UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
(Mark One)
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2019
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number | Exact name of registrants as specified in their charters | I.R.S. Employer Identification Number | ||
001-08489 | ||||
DOMINION ENERGY, INC. | 54-1229715 | |||
000-55337 | ||||
Virginia ELECTRIC AND POWER COMPANY | 54-0418825 | |||
Virginia ( | ||||
120 TREDEGAR STREET RICHMOND Virginia (Address of principal executive offices) | 23219 (Zip Code) | |||
(804) 819-2284 (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 | |||
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 Dominion Energy Gas Holdings, LLC 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 Dominion Energy Gas Holdings, LLC Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Dominion Energy, Inc. Yes Dominion Energy Gas Holdings, LLC 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(§ (§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 Dominion Energy Gas Holdings, LLC Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a“non-accelerated
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. ☒ Virginia Electric and Power Company ☐
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
Dominion Energy, Inc. Yes Dominion Energy Gas Holdings, LLC Yes ☐ No ☒
The aggregate market value of Dominion Energy, Inc. common stock held by$62.0$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 14, 2020,15, 2023, Dominion Energy had 838,000,325835,193,617 shares of common stock outstanding and Virginia Power had 274,723 shares of common stock outstanding. Dominion Energy Questar Corporation, a wholly-owned subsidiary of Dominion Energy, Inc., holds all of the membership interests of Dominion Energy Gas Holdings, LLC.
DOCUMENT INCORPORATED BY REFERENCE
Portions of Dominion Energy’s 20202023 Proxy Statement are incorporated by reference in Part III.
This combined Form, and Virginia Electric and Power Company and Dominion Energy Gas Holdings, LLC.Company. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Virginia Electric and Power Company and Dominion Energy Gas Holdings, LLC makemakes no representations as to the information relating to Dominion Energy, Inc.’s other operations.
VIRGINIA ELECTRIC AND POWER COMPANY AND DOMINION ENERGY GAS HOLDINGS, LLC MEETMEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I(1)(a) AND (b) OF FORMAREIS FILING THIS FORM
Dominion Energy, Inc., and Virginia Electric and
Item Number | Page Number | |||
3 | ||||
Part I | ||||
1. | 8 | |||
1A. | 28 | |||
1B. | 36 | |||
2. | 37 | |||
3. | 42 | |||
4. | 42 | |||
43 | ||||
Part II | ||||
5. | 44 | |||
6. | 45 | |||
7. | 46 | |||
7A. | 66 | |||
8. | 69 | |||
9. | 196 | |||
9A. | 196 | |||
9B. | 199 | |||
Part III | ||||
10. | 200 | |||
11. | 200 | |||
12. | 200 | |||
13. | 200 | |||
14. | 201 | |||
Part IV | ||||
15. | 202 | |||
16. | 209 | |||
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1. |
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1A. |
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1B. |
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2. |
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3. |
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4. |
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5. |
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6. |
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7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
| 57 |
7A. |
| 83 | |
8. |
| 86 | |
9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
| 199 |
9A. |
| 199 | |
9B. |
| 202 | |
9C. | Disclosure Regarding Foreign Jurisdictions that Prevent Inspections |
| 203 |
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10. |
| 204 | |
11. |
| 204 | |
12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
| 204 |
13. | Certain Relationships and Related Transactions, and Director Independence |
| 204 |
14. |
| 204 | |
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15. |
| 206 | |
16. |
| 211 | |
2
Glossary of Terms
The following abbreviations or acronyms used in this Form
Abbreviation or Acronym | Definition | |
2017 Tax Reform Act | An Act to Provide for Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018 (previously known as The Tax Cuts and Jobs Act) enacted on December 22, 2017 | |
2019 Equity Units | Dominion Energy’s 2019 Series A Equity Units issued in June 2019, initially in the form of 2019 Series A Corporate Units, which consisted of a stock purchase contract and a 1/10 interest in a share of the Series A Preferred Stock | |
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 | |
2023 Proxy Statement | Dominion Energy | |
ABO | Accumulated benefit obligation | |
ACE Rule | Affordable Clean Energy Rule | |
AFUDC | Allowance for funds used during construction | |
Align RNG | Align RNG, LLC, a joint venture between Dominion Energy and Smithfield Foods, Inc. | |
Altavista | Altavista biomass power station | |
AMI | Advanced Metering Infrastructure | |
AOCI | Accumulated other comprehensive income (loss) | |
ARO | Asset retirement obligation | |
Atlantic Coast Pipeline | Atlantic Coast Pipeline, LLC, a limited liability company owned by Dominion Energy and Duke | |
Atlantic Coast Pipeline Project | A previously proposed approximately | |
bcf | ||
Billion cubic feet | ||
bcfe | 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 | |
Birdseye | Birdseye Renewable Energy, LLC | |
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 | |
CAA | Clean Air Act | |
CAISO | California ISO | |
CAO | Chief Accounting Officer | |
CCR | Coal combustion residual | |
CCRO | Customer credit reinvestment offset | |
CEA | Commodity Exchange Act | |
CEO | Chief Executive Officer | |
CEP | Capital Expenditure Program, as established by House Bill 95, Ohio legislation enacted in 2011, deployed by East Ohio to recover certain costs associated with capital investment | |
CERCLA | Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as Superfund |
3
Abbreviation or Acronym | Definition | |
CFO | Chief Financial Officer | |
CH4 | Methane | |
Clearway | The legal entity, Clearway Energy, Inc. (a subsidiary of Global Infrastructure Partners), one or more of its consolidated subsidiaries, or the entirety of Clearway Energy, Inc. and its consolidated subsidiaries | |
CNG | Consolidated Natural Gas Company | |
CO | Carbon dioxide | |
Colonial Trail West | A 142 MW utility-scale solar power station located in Surry County, Virginia | |
Companies | Dominion Energy and Virginia Power, | |
Contracted | Contracted | |
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, | |
Cove Point LNG Facility | An LNG import/export and storage facility, including the Liquefaction Facility, located on the Chesapeake Bay in Lusby, Maryland | |
CPCN | ||
Certificate of Public Convenience and Necessity | ||
CVOW Commercial Project | A proposed 2.6 GW wind generation facility 27 miles off the coast of Virginia Beach, Virginia in federal waters adjacent to the CVOW Pilot Project and associated interconnection facilities in and around Virginia Beach, Virginia | |
CVOW Pilot Project | A 12 MW wind generation facility 27 miles off the coast of Virginia Beach, Virginia in federal waters | |
CWA | Clean Water Act | |
DCP | The legal entity, |
DECGS | ||||||||
Carolina Gas | ||
Services, Inc. (formerly known as Dominion Energy Carolina Gas Services, Inc. | ||
DECP Holdings | The legal entity DECP Holdings, Inc., which holds Dominion Energy’s noncontrolling interest in Cove Point | |
DEQPS | 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. | |
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, | |
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 | |
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, | |
Dominion Energy Midstream | The legal entity, Northeast Midstream Partners, LP (formerly known as Dominion Energy Midstream Partners, |
4
Abbreviation or Acronym | Definition | |
Dominion Energy Questar Pipeline | The legal entity, MountainWest Pipeline, LLC (formerly known as Dominion Energy Questar | |
Dominion Energy South Carolina | Dominion Energy South Carolina operating segment | |
Dominion Energy Virginia | Dominion Energy Virginia operating segment | |
Dominion Iroquois | The legal entity Iroquois Inc. (formerly known as Dominion Iroquois Inc.), one or more of its consolidated subsidiaries, or the entirety of Iroquois, Inc. and its consolidated subsidiaries, which held a 50% noncontrolling interest in Iroquois | |
Dominion Privatization | Dominion Utility Privatization, LLC, a joint venture between Dominion Energy and Patriot | |
DSM | Demand-side management | |
DSM Riders | Rate adjustment clauses, designated Riders C1A, C2A, C3A and C4A, associated with the recovery of costs related to certain Virginia DSM programs 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 | |
Energy Choice | Program authorized by the Ohio Commission which provides energy customers with the ability to shop for energy options from a group of suppliers certified by the Ohio Commission | |
EnergySolutions | EnergySolutions, LLC | |
EPA | U.S. Environmental Protection Agency | |
EPACT | Energy Policy Act of 2005 | |
EPS | Earnings per common share | |
ERISA | Employee Retirement Income Security Act of 1974 | |
ESA Excess Tax Benefits | Endangered Species Act Benefits of tax deductions in excess of the compensation cost recognized for stock-based compensation | |
FASB | ||
Financial Accounting Standards Board | ||
FERC | Federal Energy Regulatory Commission | |
FILOT | Fee in lieu of taxes | |
Fitch | Fitch Ratings Ltd. | |
Four Brothers | Four Brothers Solar, LLC, a limited liability company owned by Dominion Energy (through December 2021) and Four Brothers Holdings, LLC, a subsidiary of | |
Fowler Ridge | Fowler I Holdings LLC, a wind-turbine facility | |
FTRs | Financial transmission rights | |
GAAP | U.S. generally accepted accounting principles | |
Gas Distribution | Gas Distribution operating segment | |
GENCO |
South Carolina Generating Company, Inc. | ||
GHG | Greenhouse gas | |
Granite Mountain | ||
Granite Mountain Holdings, LLC, a limited liability company owned by Dominion Energy (through December 2021) and Granite Mountain Renewables, LLC, a subsidiary of | ||
Green Mountain | Green Mountain Power Corporation | |
Greensville County | A | |
5
Abbreviation or Acronym | Definition | |
GT&S Transaction | The sale by Dominion Energy to BHE of Dominion Energy Gas, DGP, DECGS, Eastern Energy Field Services, Inc. (formerly known as Dominion Energy Field Services, Inc.) and Modular LNG Holdings, Inc. (formerly known as Dominion Modular LNG Holdings, Inc.) (which holds a 50% noncontrolling interest in JAX LNG) pursuant to a purchase and sale agreement entered into on July 3, 2020, which was completed on November 1, 2020 | |
GTSA | Virginia Grid Transformation and Security Act of 2018 | |
GW | Gigawatt | |
Heating degree days | Units measuring the extent to which the average daily temperature is less than 65 degrees Fahrenheit, or 60 degrees Fahrenheit in DESC’s service territory, calculated as the difference between 65 or 60 degrees, as applicable, and the average temperature for that day | |
Hope | Hope Gas, Inc., doing business as Dominion Energy West Virginia | |
Hopewell | Polyester biomass power station | |
Idaho Commission | Idaho Public Utilities Commission | |
IRA | 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 | |
Kewaunee | ||
Kewaunee nuclear power station | ||
kV | Kilovolt | |
LIBOR | London Interbank Offered Rate | |
LIFO | Last-in-first-out | |
Liquefaction Facility | A natural gas export/liquefaction facility at the Cove Point LNG Facility | |
LNG | Liquefied natural gas | |
LTIP | Long-term incentive program | |
Massachusetts Municipal | Massachusetts Municipal Wholesale Electric Company | |
mcfe | ||
Thousand cubic feet equivalent | ||
MD&A | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
MGD | Million gallons | |
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 | |
North Anna | North Anna nuclear power station |
6
Abbreviation or Acronym | Definition | |
North Carolina Commission | North Carolina Utilities Commission | |
NO | Nitrogen oxide | |
NRC | U.S. Nuclear Regulatory Commission |
NWP 12 | ||||||||
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. | ||
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 | |
offshore wind turbine installation season | 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 | |
Patriot | Patriot Utility Privatizations, LLC, a joint venture between Foundation Infrastructure Partners, LLC and John Hancock Life Insurance Company (U.S.A.) and affiliates | |
PHMSA | Pipeline and Hazardous Materials Safety Administration | |
PIPP | Percentage of Income Payment Plan deployed by East Ohio | |
PIR | Pipeline Infrastructure Replacement program deployed by East Ohio | |
PJM | PJM Interconnection, | |
PSD | ||
Prevention of significant deterioration | ||
PSNC | Public Service Company of North Carolina, Incorporated, doing business as Dominion Energy North Carolina | |
Q-Pipe Group | Collectively, Dominion Energy Questar Pipeline, DEQPS and MountainWest Energy Holding Company, LLC (formerly known as QPC Holding Company, LLC and its subsidiary MountainWest Southern Trails Pipeline Company (formerly known as Questar Southern Trails Pipeline Company)) | |
Q-Pipe Transaction | A previously proposed sale by Dominion Energy to BHE of the Q-Pipe Group pursuant to a purchase and sale agreement entered into on October 5, 2020 and terminated on July 9, 2021 | |
Questar Gas | Questar Gas Company, doing business as Dominion Energy Utah, Dominion Energy Wyoming and Dominion Energy Idaho | |
Regulation Act | Legislation effective July 1, 2007, that amended the Virginia Electric Utility Restructuring Act and fuel factor statute, which legislation is also known as the Virginia Electric Utility Regulation Act, as amended in 2015 and 2018 | |
RGGI | Regional Greenhouse Gas Initiative | |
RICO | Racketeer Influenced and Corrupt Organizations Act | |
Rider B | A rate adjustment clause associated with the recovery of costs related to the conversion of three of Virginia Power’s coal-fired power stations to biomass | |
Rider BW | A rate adjustment clause associated with the recovery of costs related to Brunswick County | |
Rider CCR | A rate adjustment clause associated with the recovery of costs related to the removal of CCR at certain power stations | |
Rider CE | A rate adjustment clause associated with the recovery of costs related to certain renewable generation, energy storage and related transmission facilities in Virginia as well as certain small-scale distributed generation projects and related transmission facilities | |
Rider D | 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 GT | A rate adjustment clause associated with the recovery of costs associated with electric distribution grid transformation projects that the Virginia Commission has approved as authorized by the GTSA |
7
Abbreviation or Acronym | Definition | ||
Rider GV | A rate adjustment clause associated with the recovery of costs related to Greensville County | ||
Rider OSW | 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 SNA | A rate adjustment clause associated with costs relating to the preparation of the applications for subsequent license renewal to the NRC to extend the operating licenses of Surry and North Anna and related projects | ||
Rider T1 | A rate adjustment clause to recover the difference between revenues produced from transmission rates included in base rates, and the new total revenue requirement developed annually for the rate years effective September 1 | ||
Rider U | A rate adjustment clause associated with the recovery of costs of new underground distribution facilities | ||
Rider | A rate adjustment clause associated with the recovery of costs related to Woodland Solar, Scott Solar and Whitehouse Solar | ||
Rider | A rate adjustment clause associated with the recovery of costs related to Colonial Trail West and Spring Grove 1 | ||
Rider US-4 | A rate adjustment clause associated with the recovery of costs related to Sadler Solar | ||
Rider W | A rate adjustment clause associated with the recovery of costs related to Warren County | ||
ROE | |||
Return on equity | |||
ROIC | Return on invested capital | ||
RTEP | |||
Regional transmission expansion plan | |||
RTO | Regional transmission organization | ||
Sadler Solar | A 100 MW | ||
SAIDI | |||
System Average Interruption Duration Index, metric used to measure electric service reliability | |||
Santee Cooper | South Carolina Public Service Authority | ||
SBL Holdco | SBL Holdco, LLC, a wholly-owned subsidiary of DGI | ||
SCANA | The legal entity, SCANA Corporation, one or more of its consolidated subsidiaries, or the entirety of SCANA Corporation and its consolidated subsidiaries | ||
SCANA Combination | Dominion Energy’s acquisition of SCANA completed on January 1, 2019 pursuant to the terms of the agreement and plan of merger entered on January 2, 2018 between Dominion Energy and SCANA | ||
SCANA Merger Approval Order | Final order issued by the South Carolina Commission on December 21, 2018 setting forth its approval of the SCANA Combination | ||
SCDOR | |||
South Carolina Department of Revenue | |||
Scope 1 emissions | Emissions that are produced directly by an entity’s own operations | ||
Scope 2 emissions | Emissions from electricity a company consumes but does not generate from its own facilities | ||
Scope 3 emissions | Emissions generated downstream of company operations by customers and upstream by suppliers | ||
Scott Solar | A 17 MW utility-scale solar power station in Powhatan County, Virginia | ||
SEC | U.S. Securities and Exchange Commission | ||
SEEM | Southeast Energy | ||
SERC | |||
Southeast Electric Reliability Council | |||
Series A Preferred Stock | Dominion Energy’s | ||
Series B Preferred Stock | Dominion Energy’s 4.65% Series B Fixed-Rate | ||
8
Abbreviation or Acronym | Definition | |
Series C Preferred Stock | Dominion Energy’s 4.35% Series C Fixed-Rate Cumulative Redeemable Perpetual Preferred Stock, without par value, with a liquidation preference of $1,000 per share | |
SF6 | Sulfur hexafluoride | |
SO2 | Sulfur dioxide | |
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, | ||
Spring Grove 1 | A 98 MW utility-scale solar power station located in Surry County, Virginia | |
Standard & Poor’s | Standard & Poor’s Ratings Services, a division of S&P Global Inc. | |
Summer | V.C. Summer nuclear power station | |
Supply Header Project | A project previously intended for DETI to provide approximately 1,500,000 Dths of firm transportation service to various customers in connection with the Atlantic Coast Pipeline Project | |
Surry | Surry nuclear power station | |
Terra Nova Renewable Partners | The legal entity, Terra Nova Renewable Partners, LLC, a partnership comprised primarily of institutional investors advised by J.P. Morgan Asset | |
Three Cedars | Granite Mountain and Iron Springs, collectively | |
TSR | Total shareholder return | |
UEX | Uncollectible Expense Rider deployed by East Ohio | |
Ullico | The legal entity, | |
Utah Commission | Utah Public Service Commission | |
VCEA | Virginia | |
VEBA | Voluntary Employees’ Beneficiary Association | |
VIE | Variable interest entity | |
Virginia City Hybrid Energy Center | A 610 MW baseload carbon-capture compatible, clean coal powered electric generation facility in Wise County, Virginia | |
Virginia Commission | Virginia State Corporation Commission | |
Virginia Facilities | Proposed electric interconnection and transmission facilities in and around Virginia Beach, Virginia, comprising transmission facilities required to interconnect the CVOW Commercial Project reliably with the existing transmission system; including 3 miles of 230 kV offshore export circuits, 4 miles of underground 230 kV onshore export circuits, a new Harpers switching station, 14 miles of three new overhead 230 kV transmission circuits between a new Harpers switching station and the Fentress substation, rebuild eight miles of two existing 230 kV overhead lines and an expansion of the Fentress substation | |
Virginia Power | The legal entity, Virginia Electric and Power Company, one or more of its consolidated subsidiaries or operating segment, or the entirety of Virginia Electric and Power Company and its consolidated subsidiaries | |
VOC | Volatile organic compounds | |
Warren County | A | |
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 | |
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 | |
Wexpro Agreements | 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 |
9
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 | |
WP&L | Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corporation | |
WPSC | Wisconsin Public Service Corporation, a subsidiary of WEC Energy Group | |
Wrangler | Wrangler Retail Gas Holdings, LLC, a partnership between Dominion Energy (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,
Dominion Energy has commenced a comprehensive business review as discussed in Future Issues and retail energy customers and operates oneOther Matters in Item 7. MD&A. Pending the results of the nation’s largest underground natural gas storage systems, with approximately 1 trillion cubic feet of storage capacity.
Dominion Energy has transitioned to a more regulated, less volatile earnings mix as evidenced by its capital investments in regulated infrastructure, including the SCANA Combination and Dominion Energy Questar Combination, and in infrastructure with output sold under long-term purchase agreements, as well as the divestiture of interests in certain merchant generating facilities and natural gas gathering and processing investments. Dominion Energycurrently expects approximately 95%90% of
Virginia Power, and Dominion Energy Gas.
Amounts and information disclosed for Dominion Energy are inclusive of Virginia Power, and/or Dominion Energy Gas, 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, available, free of charge, including the annual report on Form
11
ACQUISITIONS AND DISPOSITIONS
The following are significant acquisitions and divestitures by the Companies duringwithin the last five years.
Gas Transmission and Storage Operations
Sales to BHE and Southwest Gas
In November 2020, Dominion Energy completed the GT&S Transaction with BHE for approximately $2.7 billion in cash proceeds and the assumption by BHE of approximately $5.3 billion of related long-term debt.
In December 2021, Dominion Energy completed the sale of the Q-Pipe Group to Southwest Gas for approximately $1.5 billion in cash proceeds and the assumption by Southwest Gas of $430 million of related long-term debt.
See Note 3 to the Consolidated Financial Statements for additional information.
Acquisition of Interest in Atlantic Coast Pipeline and Pivotal LNG, Inc.
In FebruaryMarch 2020, Dominion Energy entered into agreements withcompleted the acquisition from Southern to acquireof its 5% membership interest in Atlantic Coast Pipeline and its 100% ownership interest in Pivotal LNG, Inc., for approximately $175$184 million in aggregate, plus certain purchase price adjustments. See Note 9 to the Consolidated Financial Statements for additional information.
Hope
In January 2019, Dominion Energy and SCANA completed astock-for-stockmerger 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 InterestVirginia Power Solar Projects
In 2020 through 2022, Virginia Power entered into and completed the acquisitions of several primarily early-stage solar development projects in Wrangler
In December 2019, Dominion Energy acquired2022, Virginia Power entered into and completed the acquisitions of various solar development projects in Virginia. These projects are expected to cost a 20% noncontrolling interesttotal 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 Wrangler,Virginia. These projects are expected to cost a partnership with Interstate Gas Supply, Inc., along with $301total of approximately $1.4 billion once constructed, including initial acquisition costs, and generate approximately 697 MW combined.
In 2020, Virginia Power entered into and completed the acquisition of various solar development projects in Virginia. These projects are expected to cost a total of approximately $595 million in cash as part of itsonce constructed, including initial contribution of certain retail energy marketing operations. acquisition costs, and generate approximately 282 MW combined.
See Note 9Notes 10 and 13 to the Consolidated Financial Statements for additional information.
Acquisition of Certain Merchant Generation Facilities
In December 2018,2022, Dominion Energy entered into an agreement and completed the saleacquisition of Fairlessa nonregulated solar project in Ohio. The project is expected to cost a total of $390 million once constructed, including the initial acquisition cost, and Manchester for total consideration of $1.2 billion, subject to customary closing adjustments. See Note 10 to the Consolidated Financial Statements for additional information.
In December 2018,2020, Dominion Energy completed the sale of its 50% limited partner interest in Blue Racer for total consideration of $1.2 billion. In addition, the purchaser agreed to pay additional consideration contingent upon the achievement of certain financial performance milestones of Blue Racer from 2019 through 2021. See Note 9 to the Consolidated Financial Statements for additional information.
See Note 10 to the Consolidated Financial Statements for additional information.
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Sale of Certain Retail Energy Marketing Assets
In October 2017,2021, Dominion Energy entered into an agreementcompleted the sale of SBL Holdco, which held Dominion Energy’s remaining 67% controlling interest in certain nonregulated solar projects, to sell certain assets associated with its nonregulated retail energy marketing operationsTerra Nova Renewable Partners for total considerationcash proceeds of $143$209 million subject to customary approvals and certain adjustments. the assumption by Terra Nova Renewable Partners of $265 million of related long-term debt.
In December 2017, the first phase of the agreement closed for $79 million. In October 2018, the second phase of the agreement closed for $63 million. Pursuant to the agreement,2021, Dominion Energy entered into a commission agreement withcompleted the buyer upon the first closingsale of its remaining 50% controlling interest in December 2017, under which the buyer will pay a commission in connection with the rightFour Brothers and Three Cedars to use Dominion Energy’s brand in marketing materials and other services over aten-yearterm. Clearway for cash proceeds of $331 million.
See Note 10 to the Consolidated Financial Statements for additional information.
Equity Method Investments
Contributions to and Disposition of Tower Rental Portfolio
After an initial contribution to Wrangler in 2019, Dominion Energy completed a second contribution in November 2020 consisting of certain retail energy natural gas contracts receiving $74 million in cash and a final contribution in December 2021 of its electric transmission towers to various wireless carriers for communications antennas and other equipment. In March 2017, Virginia Power sold its rental portfolio to Vertical Bridge Towers II, LLC for $91remaining nonregulated natural gas retail energy marketing operations receiving $127 million in cash. 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 109 to the Consolidated Financial Statements for additional information.
Acquisition of Interest in Iroquois
In September 2015,February 2022, Dominion Energy Midstream acquired from NG and NJNRentered into an agreement to form Dominion Privatization, a 25.93% noncontrolling partnership interest in Iroquois. The investment was recorded at $216 million based onjoint venture with Patriot. Under the value ofagreement, during 2022 Dominion Energy Midstream’s common units at closing. The common units issued to NGcontributed its existing privatization operations in Virginia, Texas, Pennsylvania and NJNR have been reflected as noncontrolling interest inSouth Carolina, excluding contracts held by DESC, and Patriot contributed cash. Dominion Energy and Dominion Energy Gas’ Consolidated Financial Statements.
See Note 109 to the Consolidated Financial Statements for additional information on certaininformation.
HUMAN CAPITAL
One of these sales of MarcellusDominion Energy's greatest strengths is its employees and Utica acreage.
Safety is the highest priority of Dominion Energy’s five core values with the fundamental goal to send every employee home safe and sound every day. In 2022, Dominion Energy experienced an OSHA Recordable Rate of 0.52 compared to 0.46 in 2021 and 0.41 in 2020. These rates reflect Dominion Energy’s dedication to safety when compared to a 2021 BLS Industry Average OSHA Recordable Rate of 1.7 and a 2020 BLS Industry Average OSHA Recordable Rate of 1.5. As evidence of Dominion Energy’s commitment to safety, annual incentive plans for all employees, except as restricted by any collective bargaining agreements, include a safety performance measure. Furthermore, Dominion Energy has been proactive in protecting its segments which resultedworkforce during the global COVID-19 pandemic by establishing safety protocols and adapting its approach as the pandemic has evolved. Dominion Energy also facilitated telecommuting and hybrid work options for many employees and expanded paid time off and other benefits to help employees cope with disruptions caused by the pandemic.
Dominion Energy works to recruit, retain and develop the careers of talented individuals who reflect the communities it serves. To cultivate this diversified workforce, Dominion Energy focuses on workforce diversity, equity and inclusion while fostering an environment where employees can utilize their unique strengths, skills, personalities and life experiences. Dominion Energy is committed to increasing its diverse workforce representation to 40% by year-end 2026; to be adjusted as necessary based on position and market availability. During 2022, Dominion Energy increased diverse representation within its workforce from 35.5% to 37.0%, following an increase during 2021 from 34.7% to 35.5%. For the purposes of measuring diversity, Dominion Energy includes employees who identify their gender as female and/or their race/ethnicity as American Indian or Alaskan Native, Asian, Black or African American, Hispanic or Latino, Native Hawaiian or Other Pacific Islander or Two or More Races. In 2022, 2021 and 2020, the percentage of new hires that are diverse was 48.9%, 57.5% and 50.7%, respectively. Dominion Energy sponsors eight employee
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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 formationgoal to provide a consistent and progressive approach to training that engages the workforce and fosters a culture of fivelearning. To this end, Dominion Energy offers continuous learning opportunities including tuition assistance programs, professional development resources, access to a career center and a self-guided training program for independent learning as well as leadership development programs. These resources and programs are designed not only to engage and retain talented employees but also to allow Dominion Energy to meet the needs of its customers in an ever-changing industry with a skilled workforce.
CYBERSECURITY
In an effort to reduce the likelihood and severity of cyber intrusions, the Companies have a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of data and systems, including oversight by the Board of Directors as well as the finance and risk oversight board committee. The Companies are subject to mandatory cybersecurity regulatory requirements, interface regularly with a wide range of external organizations and participate in classified briefings to maintain an awareness of current cybersecurity threats and vulnerabilities. The Companies’ current security posture and regulatory compliance efforts are intended to address the evolving and changing cyber threats. See Item 1A. Risk Factors for discussion of related risks.
OPERATING SEGMENTS
Dominion Energy manages its daily operations through four primary operating segments: Dominion Energy Virginia, Gas Transmission & Storage, Gas Distribution, Dominion Energy South Carolina and Contracted Generation.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). In addition, as well as Dominion Energy’s noncontrolling interest in Dominion Privatization. Corporate and Other includes specific items attributable to Dominion Energy’s other operating segments that are not included in profit measures evaluated by executive management in assessing the operating segments’ performance or in allocating resources.
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.
Segment | Energy | Power | Energy Gas | |||||||||||
14 DOMINION ENERGY VIRGINIA Dominion Energy Virginia | ||||||||||||||
Dominion Energy Virginia’s previously announced growth capital plan includes spending approximately $16$27 billion from 20192022 through 20232026 to construct new generation capacity, including the CVOW Commercial Project, to meet its renewable generation targets and growing electricity demand within its service territory in order to maintain reliability and regulatory compliance and to upgrade or add new transmission lines, distribution lines, substations, and other facilities, as well as maintain existing and construct new generation capacity to meet growing electricity demand within its service territory in order to maintain reliability and regulatory compliance.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
Virginia Power has also created awill addressaddresses the structural limitations of Virginia Power’s distribution grid in a systematic manner in order to recognize and
Revenue provided by electric distribution and generation operations is based primarily on rates established by the Virginia and North Carolina Commissions. Approximately 84%81% of revenue comes from serving Virginia jurisdictional customers. Base rates for the Virginia jurisdiction are set using a modified138136 minutes for the three-year average ending 2019, up2022, down from the previous three-year average of 134141 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 the customer’scertain 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 rate adjustment clausesriders in Virginia. Variability in earnings from rate adjustment clausesriders 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’s electric transmission operations arePower is committed to meeting NERC standards, modernizing its infrastructure and maintaining superior system reliability.
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Competition
There is no competition for electric distribution service within Virginia Power’s service territory in Virginia and North Carolina
Virginia Power’s
Regulation
Virginia Power’s electric distribution and generation operations, including the rates it may charge to jurisdictional customers, as well as wholesale electric transmission rates, tariffs and terms of service, are subject to regulation by the Virginia and North Carolina Commissions as well as FERC, the NRC, the EPA, the DOE and the U.S. Army Corps of Engineers. See77. 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:
Electric Transmission and Distribution Projects
Virginia Power continues to invest in transmission projects that are a part of PJM’s RTEP process which focus on reliability improvements and replacement of aging infrastructure. The projects that have been authorized by PJM authorized the following material reliability projects (including Virginia Power’s estimated cost):
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Virginia Power is investing in transmission substation physical security and expects to invest an additional $125$100 million to $175$150 million through 20242026 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
Presented below is a summary of Virginia Power’s actual system output by energy source:
Source |
| 2022 |
|
| 2021 |
|
| 2020 |
|
| |||
Natural gas |
|
| 36 |
| % |
| 40 |
| % |
| 48 |
| % |
Nuclear(1) |
|
| 28 |
|
|
| 29 |
|
|
| 32 |
|
|
Purchased power, net |
|
| 23 |
|
|
| 17 |
|
|
| 7 |
|
|
Coal(2) |
|
| 8 |
|
|
| 9 |
|
|
| 9 |
|
|
Renewable and Hydro(3) |
|
| 5 |
|
|
| 5 |
|
|
| 4 |
|
|
Total |
|
| 100 |
| % |
| 100 |
| % |
| 100 |
| % |
Source | 2019 | 2018 | 2017 | |||||||||
Natural gas | 41 | % | 33 | % | 32 | % | ||||||
Nuclear (1) | 29 | 29 | 32 | |||||||||
Purchased power, net | 17 | 19 | 14 | |||||||||
Coal (2) | 8 | 13 | 17 | |||||||||
Renewable/hydro (3) | 5 | 5 | 5 | |||||||||
Oil | — | 1 | — | |||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||
Nuclear Fuel
Fossil Fuel
Virginia Power’s natural gas and oil supply is obtained from various sources including purchases from major and independent producers in theDominion Energy or 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—
Purchased Power
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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 to2019,2021, 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 expects to submitsubmitted a license extensionrenewal application for the two units at North Anna in 2020.Anna. Under this renewal application, the two units will be allowed to generate electricity through 2058 and 2060, if approved. Between the four units, Virginia Power estimates that it could spend approximately $3 billion to $4 billion over the next several yearsthrough 2035 on the relicensing process.capital improvements. The existing regulatory framework in Virginia provides rate recovery mechanisms for such costs. The most recent site-specific study completed for Surry and North Anna was performed in 2019.
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 (2019 dollars) (1) | Funds in trusts at December 31, 2019 | 2019 contributions to trusts | |||||||||||||
(dollars in millions) | ||||||||||||||||
Surry | ||||||||||||||||
Unit 1 | 2032 | $ 803 | $ 815 | $ — | ||||||||||||
Unit 2 | 2033 | 794 | 803 | — | ||||||||||||
North Anna | ||||||||||||||||
Unit 1 (2) | 2038 | 720 | 651 | — | ||||||||||||
Unit 2 (2) | 2040 | 724 | 612 | — | ||||||||||||
Total | $3,041 | $2,881 | $— | |||||||||||||
|
| 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 |
|
Virginia Power did not make any contributions to its nuclear decommissioning trust funds during 2022. |
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.
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GAS DISTRIBUTION
Gas Distribution Operating Segment of Dominion Energy West Virginia, North Carolina, Utah, southwestern Wyoming and southeastern Idaho (through East Ohio, Hope, PSNC and Questar Gas) which collectively serve approximately 3.0 million residential, commercial and industrial customers.
Gas Distribution’s previously announced growth capital plan includes spending approximately $4$5 billion from 20192022 through 20232026 to upgrade existing or add new infrastructure to meet growing energy needs and retain reliability within its service territory and maintain reliability.as well as investments in renewable natural gas infrastructure projects. Planned capital spending is driven by infrastructure needs from a growing customer base in states with expanding economies, replacing aging assets for reliability, safety and safetysustainability and meeting demands for natural gas to support the transition from more carbon intensive fuels.
Earnings for the Gas Distribution Operating Segment of Dominion Energy West Virginia, North Carolina, Utah, Wyoming and Idaho Commissions. The profitability of these businesses is dependent on their ability, through the rates they are permitted to charge, to recover costs and earn a reasonable return on their capital investments. Variability in earnings primarily results from changes in operating and maintenance expenditures, as well as changes in rates and the economy.
Competition
East Ohio has offeredoffers an Energy Choice program, under which residential customers are encouraged to residentialpurchase gas directly from retail suppliers or through a community aggregation program and commercial customers since October 2000.have it delivered by East Ohio has since taken various steps approved by the Ohio Commission toward exiting the merchant function, including restructuring its
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. SeeRegulationmoreadditional information.
Properties
For a description of existing facilities see Item 2.Properties.
Dominion Energy has the following significant projects under construction or development to better serve utility customers or expand its service offerings within its utility service territory.
East Ohio
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expenditures to $200 million by 2018 with a 3% increase per year thereafter subject to the annual cost recovery rate increase caps proposed by East Ohio. In April 2022, the Ohio Commission approved an extension of East Ohio’s PIR program for capital investments through 2026 with continuation of 3% increases of annual capital expenditures per year. See Note 13 into 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 additional information.
PSNC—The North Carolina Commission has authorized PSNC to use a tracker mechanism to recover the incurred capital investment and associated costs of complying with federal standards for pipeline integrity and safety requirements that are not in current base rates. Projected integrity management plan investment, excluding the costs associated with the project noted below, for the period 2023 to 2025 is expected to be approximately $144 million.
During 2020, construction began on 11 miles of transmission pipeline in Buncombe County, NC. After an analysis was performed under the integrity management program, the new transmission line was deemed necessary to offset the capacity losses on the existing line due to lower pressure being utilized in order to meet federal safety requirements. The project is expected to cost approximately $65 million and had approximately 10 miles placed into service in December 2021 with the remaining portion anticipated to be placed into service in 2023.
Questar Gas
In 2018, legislation became effective in Utah which is designed to spur economic growth in rural communities without natural gas service. The legislation allowsPursuant to its 2022 Utah base rate case, Questar Gas is permitted to spend up to $50approximately $85 million over the three years, and up to $125approximately $215 million over five years,in the aggregate, for expansion of distribution facilities to bring natural gas to residential and commercial customers in rural parts of Utah, subject toas approved by the Utah Commission. Additionally, as part of the 2022 Utah base rate case, the Utah Commission approval. See Note 13 to Consolidated Financial Statements for more information.
Non-Utility Renewable Natural Gas—In December 2019, Dominion Energy announced the formation of a strategic alliance with Vanguard Renewables in collaboration with the Dairy Farmers of America to capture methane from dairy farms and associated costsconvert it into pipeline quality natural gas. In August 2021, Dominion Energy announced an expansion of complying with federal standards for pipeline integritythe partnership, increasing its commitment up to $1 billion. As of December 31, 2022, 16 dairy renewable natural gas facilities were under construction in Colorado, Nevada, Idaho, Georgia, Kansas, Texas and safety requirements thatNew Mexico. These facilities are not in current base rates. Projected integrity management plant investment for the period 2020 to 2022 for which recovery is expected is approximately $95 million.
Investments
Align RNG—In November 2018, Dominion Energy announced the formation of Align RNG, an equal partnership with Smithfield Foods, Inc. Align RNG expects to invest $500 million to develop assets to capture methane from swine farms across Virginia, North Carolina, Utah and Arizona and convert it into pipeline quality natural gas. In July 2020, Align RNG placed its first project, located in Milford, UT, in service by mid-2020. Thisand the project ishas produced over 160,000 Dths of renewable natural gas. As of December 31, 2022, Align RNG had four additional projects under construction in North Carolina, Arizona and Virginia with an estimated total cost of approximately $200 million. These facilities are expected to be recovered through the pipeline integrity tracker mechanism described above.
Sources of Energy Supply
Dominion Energy’s natural gas supply is obtained from various sources including purchases from major and independent producers in theAgreement and the Wexpro II Agreement,Agreements, comprehensive agreements with the states
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of Utah and Wyoming.
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
Dominion Energy South Carolina
Dominion Energy South Carolina’s previously announced growth capital plan includes spending approximately $2 billion from 20192022 through 20232026 to upgrade existing or add new infrastructure to meet growing energy needs within its service territory and maintain reliability.
Revenue provided by DESC’s electric distribution operations is based primarily on rates established by the South Carolina Commission. Variability in earnings is driven primarily by changes in rates, weather, customer growth and other factors impacting consumption such as the economy and energy conservation, in addition to operating and maintenance expenditures.
DESC’s electric transmission operations serve its electric distribution operations as well as certain wholesale customers. Revenue provided by such electric transmission operations is based on a FERC-approved formula rate mechanism under DESC’s open access transmission tariff or based on retail rates established by the South Carolina Commission.
Revenue provided by DESC’s electric generation operations is primarily derived from the sale of electricity generated by its utility generation assets and is based on rates established by the South Carolina Commission. Variability in earnings may arise when revenues are impacted by factors not reflected in current rates, such as the impact of weather, customer demand or the timing and nature of expenses or outages.
Electric operations continue to focus on improving service and experience levels while striving to reduce costs and link investments to operational results. SAIDI performance results, excluding major events, were 82 minutes for the three-year average ending 2022, consistent with the previous three-year average of 82 minutes.
Revenue provided by DESC’s natural gas distribution operations primarily results from rates established by the South Carolina Commission. Variability in earnings results from changes in operating and maintenance expenditures, as well as changes in rates and the demand for services, the availability and prices of alternative fuels and the economy.
DESC is a member of the 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.
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,
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.
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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. Seemoreadditional 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 2019,2020, DESC began an initiative tothe upgrade of its electric and gas systems to an AMI whereby over a million smart meters will be installed throughout its service area. As of December 31, 2022, DESC has completed the installation of approximately 765,000 of the planned 1.1 million smart meters. This project is estimated to cost approximately $140 million and will be completed in mid-2024.
In January 2022, DESC committed to a plan to retire certain existing gas combustion turbine facilities, including certain units which currently do not have any net summer capability, and replace them with new gas combustion turbine units at the Williams and Parr facilities to increase reliability and reduce emissions. The replacement facilities are expected to be placed in service by 2023.
To maintain reliability, DESC expects to commence development in 2023 of a wastewater treatment facility at its Williams facility. The project will allow DESC to comply with the effluent limitation guidelines and is expected to be placed in service by the end of 2025 at an estimated cost of approximately $165 million, excluding financing costs.
Sources of Energy Supply
DESC uses a variety of fuels to power its electric generation fleet and purchases power for utility system load requirements.
Presented below is a summary of DESC’s actual system output by energy source:
Source |
| 2022 |
|
| 2021 |
|
| 2020 |
|
| |||
Natural gas |
|
| 48 |
| % |
| 49 |
| % |
| 47 |
| % |
Nuclear(1) |
|
| 23 |
|
|
| 20 |
|
|
| 20 |
|
|
Coal |
|
| 18 |
|
|
| 20 |
|
|
| 22 |
|
|
Renewable and Hydro(2) |
|
| 11 |
|
|
| 11 |
|
|
| 11 |
|
|
Total |
|
| 100 |
| % |
| 100 |
| % |
| 100 |
| % |
Source | 2019 | 2018 (1) | ||||||
Natural gas | 46 | % | 37 | % | ||||
Coal | 27 | 35 | ||||||
Nuclear (2) | 23 | 20 | ||||||
Renewable/hydro (3) | 4 | 8 | ||||||
Total | 100 | % | 100 | % | ||||
Natural gas
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 through 2020.throughout 2023 and 2024. Spot market purchases may occur when needed or when prices are believed to be favorable.
Nuclear— DESC primarily utilizes long-term contracts to support its nuclear fuel requirements. DESC, for itself and as agent for Santee Cooper, and Westinghouse are parties to a fuel alliance agreement and contracts for fuel fabrication and related services. Under these contracts, DESC supplies enriched products to Westinghouse, who in turn supplies nuclear fuel assemblies for Summer. Westinghouse is DESC’s exclusive provider of such fuel assemblies on a cost-plus basis. The fuel assemblies to be delivered under the contracts are expected to supply the nuclear fuel requirements through 2033.
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In addition, DESC has contracts covering its nuclear fuel needs for uranium, conversion services and enrichment services. These contracts have varying expiration dates through 2024. DESC believes that it will be able to renew these contracts as they expire or enter into similar contractual arrangements with other suppliers of nuclear fuel materials and services and that sufficient capacity for nuclear fuel supplies and processing exists to allow for normal operations of its nuclear generating unit. Current agreements, inventories and spot market availability are expected to support current and planned fuel supply needs. Additional fuel is purchased as required to ensure optimal fuel and inventory levels.
Seasonality
DESC’s electric distribution and transmission business earnings vary seasonally as a result of the impact of changes in temperature, the impact of storms and other catastrophic weather events and the availability of alternative sources for heating on demand by residential and commercial customers. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs, respectively. An increase in heating degree days does not produce the same increase in revenue as an increase in cooling degree days, due to seasonal pricing differentials and because alternative heating sources are more readily available.
DESC’s gas distribution and storage business earnings vary seasonally as a result of the impact of changes in temperature on demand by residential and commercial customers for gas to meet heating needs. The majority of these earnings are generated during the heating season, which is generally from November to March; however, South Carolina has certain rate mechanisms designed to reduce the impact of weather-related fluctuations.
Nuclear Decommissioning
DESC has a
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 $646 million (statedreflected in 2019 dollars), whichthe table below and is primarily based upon site-specific studies completed in 2016.2020. These cost studies are generally completed every four to five years. Santee Cooper is responsible for the remaining decommissioning costs, proportionate with its 33.3% ownership in Summer. The cost estimates assume decommissioning activities will begin shortly after cessation of operations, which will occur when the operating license expires. NRC regulations allow licensees to apply for extension of an operating license in up to 20-year increments. DESC expects to apply for an operating license renewal for Summer.
The estimated decommissioning costs, funds in trust and current license expiration dates for Summer are shown in the following table:
|
| NRC license expiration year |
| Most recent cost estimate (2022 dollars)(1) |
|
| Funds in trusts at December 31, 2022(2) |
| ||
(dollars in millions) |
|
|
|
|
|
|
|
| ||
Summer – Unit 1 |
| 2042 |
| $ | 788 |
|
| $ | 221 |
|
Also see Notes 9, 14 and 23 to the Consolidated Financial Statements for its proportionate shareadditional information about nuclear decommissioning trust investments, AROs and other aspects of thesenuclear decommissioning, activities.
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CONTRACTED ASSETS
Contracted Generation
Contracted Generation’sAssets’ previously announced growth capital plan includes spending less than $1approximately $3 billion from 20192022 through 20232026 to expand its renewable generation fleet.
ContractedGeneration Operating Segment Assets derives its earnings primarily from Dominion Energy’s merchantnonregulated generation assets, as well as fromincluding associated capacity and ancillary services.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 following approval by PURA in 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 merchantnonregulated generation fleet includes numerous renewable generation facilities, including solar generation and wind facilities in operation or development in nine states, including Virginia. The output of these facilities is primarily 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 and wind speeds due to changes in weather. See Notes 3 and 10 to the Consolidated Financial Statements for additional information regarding certain solar projects.
Competition
Contracted Generation’sAsset’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 merchantnonregulated 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 merchantnonregulated 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 its nonrenewable merchant fleetMillstone 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. See7,7. 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 theMid-Atlantic.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 and, for FERC-regulated operations, changes in rates and demand for services.
See Item 2. Properties for a description of Cove Point’s physical assets.
See Note 9 to the Consolidated Financial Statements for further information about Dominion Energy’s equity method investment in Fowler Ridge.
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 Generation’sAsset’s renewable fleet utilizes solar and wind 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 theincluded as contractual obligationsdetailed further inFuture CashPayments for Contractual Obligations Fuel and Planned Capital Expenditures
Seasonality
Sales of electricity for Contracted Generation typically vary seasonallyAssets are subject to seasonal variation as a result of the weather.
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 allowed60-yearwindow.
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.
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 (2019 dollars) (1) | Funds in trusts at December 31, 2019 | 2019 contributions to trusts | |||||||||||||
(dollars in millions) | ||||||||||||||||
Millstone | ||||||||||||||||
Unit 1 (2) | N/A | $ | 450 | $ 622 | $ — | |||||||||||
Unit 2 | 2035 | 653 | 828 | — | ||||||||||||
Unit 3 (3) | 2045 | 741 | 813 | — | ||||||||||||
Kewaunee | ||||||||||||||||
Unit 1 (4) | N/A | 573 | 834 | — | ||||||||||||
Total | $ | 2,417 | $3,097 | $ — | ||||||||||||
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.
CORPORATE AND OTHER
Corporate and Other Segment-Virginia Power and Dominion Energy Gas
Virginia Power and Dominion Energy Gas’Power’s Corporate and Other segmentssegment primarily includeincludes certain specific items attributable to theirits operating segments that are not included in profit measures evaluated by executive management in assessing the segments’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). In addition, as well as its noncontrolling interest in Dominion Privatization. Corporate and Other includes specific items attributable to Dominion Energy’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources.
Dominion Energy owns a 50% noncontrolling interest in Dominion Privatization, a partnership with Patriot, which will maintain and operate electric and gas distribution infrastructure under service concession arrangements with certain U.S. military installations in Pennsylvania, South Carolina, Texas and Virginia.
Dominion Energy owns a 53% noncontrolling interest in Atlantic Coast Pipeline. In July 2020, as a result of the continued permitting delays, growing legal uncertainties and the need to incur significant capital expenditures to maintain project timing before such uncertainties could be resolved, Dominion Energy and Duke Energy announced the cancellation of the Atlantic Coast Pipeline Project.
See Note 9 to the Consolidated Financial Statements for additional information.
REGULATION
The Companies are subject to regulation by various federal, state and local authorities, including the state commissions of Virginia, North Carolina, South Carolina, Ohio, West Virginia, Georgia, 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
27
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 rate adjustment clauses,riders, and also contains statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission. As amended, it provides for enhanced returns on capital expenditures on specific newly-proposed generation projects.
In March 2018, the GTSA reinstated base rate reviews on a triennial basis other than the first review, which will be a quadrennial review, occurring for Virginia Power in 2021 for the four successive12-monthtest periods beginning January 1, 2017 and ending December 31, 2020.
In April 2020, the 2021 review, any such rate reduction is limitedVCEA 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 $50 million.
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 arate-of-return
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 arate-of-return
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 SCANA Combination, DESC agreed notNND Project. Revenue from the capital cost rider component of retail electric rates will continue to file a generaldecline over the 20-year period as capital cost rate case with the South Carolina Commission with a requested rate effective date earlier than January 2021. Rate adjustments are permitted prior to 2021 for fuel and environmental costs, DSM costs and other rates routinely adjusted on an annual or biennial basis.
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 itthey may charge itstheir customers, are regulated by the state commissions of Ohio, Commission. Hope’s natural gas distribution services are regulated by the West Virginia Commission. DESCNorth Carolina and PSNC’s natural gas distribution services are regulated by the South Carolina, Commission and North Carolina Commission, respectively.
Gas Regulation in Utah, Wyoming and Idaho
Questar Gas is subject to regulation of rates and other aspects of its business by the Utah, Wyoming and Idaho Commissions. The Idaho Commission has contracted with the Utah Commission for rate oversight of Questar Gas’ operations in a small area of southeastern Idaho. When necessary, Questar Gas seeks general base rate increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the
Questar Gas makes routine separate filings with the Utah and Wyoming Commissions to reflect changes in the costs of purchased gas. The majorityQuestar 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 and Wyoming Commissions have alsoCommission has approved several stand-alonea standalone cost recovery mechanismsmechanism 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
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
The Ohio Commission has also approved several stand-alone cost recovery mechanisms to recover specified costs and a return for infrastructure, information technology and integrity or compliance-related projects between general base rate cases.
See Note 13 to the Consolidated Financial Statements for additional information.
Gas Regulation in North Carolina
PSNC is subject to regulation of rates and other aspects of its business by the North Carolina Commission. When necessary, PSNC seeks general base rate increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the
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 customer.
PSNC makes routine separate filings with the North Carolina Commission to reflect changes in the costs of purchased gas. PSNC’s purchased gas adjustment allows it to recover from customers all prudently incurred gas costs, including transportation costs, and 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
The North Carolina Commission has also approved a stand-alone cost recovery mechanism to recover specified capital costs and a return for pipeline integrity management infrastructure projects between general base rate cases.
See Notes 3 andNote 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
DESC’s natural gas tariffs include a purchased gas adjustment that provides for the recovery of prudently incurred gas costs, including transportation costs. DESC is authorized to adjust its purchased gas rates monthly and makes routine filings with the South Carolina Commission to provide notification of changes in these rates. Costs that are under or over recovered are deferred as regulatory assets or liabilities, respectively, and considered in subsequent purchased gas adjustments. The purchased gas adjustment filings generally cover a prospective twelve-month period. Increases or decreases in purchased gas costs can result in corresponding changes in purchased gas adjustment rates and the revenue generated by those rates. The South Carolina Commission reviews DESC’s gas purchasing policies and practices, including its administration of the purchased gas adjustment, annually.
See Notes 3 andNote 13 to the Consolidated Financial Statements for additional information.
Federal Regulations
Federal Energy Regulatory Commission
Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Virginia Power purchases and, under its market-based rate authority, sells electricity in the PJM wholesale market and sells electricity to wholesale purchasers in Virginia and North Carolina. Dominion Energy’s merchantnonregulated generators sell electricity in the PJM, CAISO andIndiana,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 approval ofapproved 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 service territories.territory. Any such sales would beare voluntary.
In January 2021, Virginia Power and DESCnotified 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 merchantnonregulated plants and utility plants without first receiving FERC authorization, (2) require the merchantnonregulated and utility plants to conduct their wholesale power sales operations separately, and (3) prohibit utilities from sharing market information with merchantnonregulated plant operating personnel. The rules are designed to prohibit utilities from giving the merchantnonregulated 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 $1.2$1.5 million per day, per violation and can also be assessed
In April 2008, FERC granted an application for Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE effective as of January 1, 2008. The formula rate is designed to recover the expected revenue requirement for each calendar year and is updated based on actual costs. The FERC-approved formula method, which is based on projected costs, allows Virginia Power to earn a current return on its growing investment in electric transmission infrastructure.
In October 2011, FERC issued an order approving the settlement of DESC’s formula rate that updates transmission rates on an annual basis, including its ROE. The formula rate is designed to recover the expected revenue requirement for the calendar year and is updated annually based on actual costs. This FERC accepted formula rate enables DESC to earn a return on its investment in electric transmission infrastructure.
In February 2021, DESC and the Natural Gas Policy Actother members of 1978, as amended. Under the Natural Gas Act,SEEM submitted the Southeast Energy Exchange Market Agreement to FERC has authority over rates, termsfor authorization. This agreement sets forth the framework and conditions of services performedrules 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 Dominionparticipating transmission service providers, including DESC. In October 2021, the Southeast Energy Questar Pipeline, DETI, DECG, Iroquois and certain services performedExchange Market Agreement became effective by Cove Point. The 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 Cove Point LNG Facility, including associated natural gas pipelines,operation and maintenance of the Liquefaction FacilityCompanies’ nuclear power stations are regulated by the NRC. Operating licenses issued by the NRC are subject to revocation, suspension or modification, and the importoperation 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 exportmaintenance of LNG are also regulated by FERC.
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 andVirginia-Nuclear Decommissioning, Dominion Energy GasSouth Carolina-Nuclear Decommissioning, and Contracted Assets-Nuclear Decommissioning above and Notes 3 and 9 to the Consolidated Financial Statements. See Note 23 to the Consolidated Financial Statements for additional information on spent nuclear fuel.
Cyber Regulations
The Companies plan and operate their facilities in compliance with approved government cyber regulatory requirements. The Companies’ employees participate on various regulatory committees, track the development and implementation of standards, and maintain proper compliance registration with NERC’s regional organizations. The Companies anticipate incurring additional compliance expenditures over the next several years because of the implementation of new cybersecurity programs such as the Transportation Security Administration’s gas sector cyber security directives. In addition, NERC continues to develop additional requirements specifically regarding supply chain standards and control centers that impact the bulk electric system. While the Companies expect to incur additional compliance costs in connection with NERC, Transportation Security Administration and other governmental agency regulations, such expenses are not expected to significantly affect results of operations.
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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 and Dominion Energy Gas have evaluated their natural gas transmission and storage properties, as required by the U.S. Department of Transportation regulations under these Acts, and have implemented a program of identification, testing and potential remediation activities. These activities are ongoing.
The Companies are subject to a number of federal and state laws and regulations, including Occupational Safety and Health Administration, and comparable state statutes, whose purpose is to protect the health and safety of workers. The Companies have an internal safety, health and security program designed to monitor and enforce compliance with worker safety requirements, which is routinely reviewed and considered for improvement. The Companies believe that they are in material compliance with all applicable laws and regulations related to worker health and safety. Notwithstanding these preventive measures, incidents may occur that are outside of the Companies’ control.
Environmental Regulations
Each of the Companies’ operating segments is subject to substantial laws, regulations and compliance costs with respect to environmental matters. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of significant penalties for noncompliance, including fines, injunctive relief and other sanctions. The cost of complying with applicable environmental laws, regulations and rules is expected to be 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, seeItem 3. Legal Proceedings and 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 CEOs 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, Environmental Matters
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, NOaddress 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 andDominion 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
32
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
Protected Species
The ESA and analogous state laws prohibit activities that can result in harm to specific species of plants and animals, as well as impacts to the habitat on which those species depend. In addition to ESA programs, the Migratory Bird Treaty Act of 1918 and Bald and Golden Eagle Protection Act establish broader prohibitions on harm to protected birds. Many of the Companies’ facilities are subject to requirements of the ESA, Migratory Bird Treaty Act of 1918 and Bald and Golden Eagle Protection Act. The ESA and Bald and Golden Eagle Protection Act require potentially lengthy coordination with the state and federal agencies to ensure potentially affected species are protected. Ultimately, the suite of species protections may restrict company activities to certain times of year, project modifications may be necessary to avoid harm, or a permit may be needed for unavoidable taking of the species. The authorizing agency may impose mitigation requirements and costs to compensate for harm of a protected species or habitat loss. These requirements and time of year restrictions can result in adverse impacts on project plans and schedules such that the Companies’ businesses may be materially affected.
Other Regulations
Other significant environmental regulations to which the Companies are subject include federal and state laws protecting graves, sacred sites, historic sites and cultural resources, including those of American Indian tribal nations and tribal communities. These can result in compliance and mitigation costs as well as potential adverse effects on project plans and schedules such that the Companies’ businesses may be materially affected.
ENVIRONMENTAL STRATEGY
Dominion Energy is committed to a safe, sustainable, reliable and affordable energy future. In February 2020, Dominion Energy set a goal to achieve net zero carbon and methane Scope 1 emissions by 2050. In February 2022, Dominion Energy expanded this commitment to cover Scope 2 emissions and material categories of Scope 3 emissions: electricity purchased to power the grid, fuel purchased for its power stations and gas distribution systems and consumption of sales gas by natural gas customers. As part of the operation and maintenance ofnet 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 Virginia Power’s nuclear power stations are regulatedcut 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 NRC. Operating licenses issued bycompletion of the NRC are subject to revocation, suspension or modification,comprehensive business review discussed in Future Issues and the operation of a nuclear unit may be suspended if the NRC determines that the public interest, health or safety so requires.
To meet its customers’ needs for safe, reliable, and affordable energy and to reach net zero emissions, in the cost of operating and maintainingnear term Dominion Energy and Virginia Power’sis seeking extension of the licenses of its zero-carbon nuclear generating units. See Note 23fleet at North Anna similar to the Consolidated Financial Statementslicense extension received for further information.
Over the long term, Dominion Energy’s ability to meet its customers’ needs for safe, reliable clean and affordable energy while fully complying with all applicable environmental laws and regulations. Additionally,achieve net zero emissions will require supportive legislative and regulatory policies, advancements in technology and broader investments across the Companies seekeconomy. 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. The Companies believeDominion Energy commits to inclusiveness during its stakeholder engagement on decisions regarding the siting and operation of energy infrastructure and strives to include all people and communities, regardless of race, color, national origin or income to ensure a diversity of views are considered in being transparent about theirits 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 including the Environmental Justice Policy adopted in 2018, and initiatives which have been disclosed in a Sustainability &and Corporate Responsibility Report as well as a Climate Report andin addition to other reports included on Dominion Energy’s dedicated Environmental, Social and Governance website. The Companies are dedicated to meeting their customers’ growing energy needs with innovative, sustainable solutions. The Companies are pursuing initiatives intended to reduce the GHG footprint of their customers and energy end-users, including a school bus electrification program in Virginia and two renewable natural gas partnerships in the agricultural sector. It is the Companies’ belief that sustainable solutions should strive to balance the interdependent goals of environmental stewardship and economic effects. The integrated strategy to meet these objectives consists of three major elements:
Clean Energy infrastructure modernization, including natural gas and electric operations; and
To achieve its net zero commitment, Dominion Energy has committedis pursuing a diverse mix of cleaner, more efficient and lower-emitting methods of generating and delivering energy, while advancing measures to cut methanecontinue dramatically reducing emissions by 65% by 2030from traditional generation and by 80% by 2040, in each case relative to 2010 emissions.delivery. Diversifying the energy portfolio enables Dominion Energy has further committed to achieve net zero carbon and methane emissionsprovide customers with cleaner options while protecting the power supply from its electric generation and natural gas infrastructure operations by 2050.
Over the past two decades, Dominion Energy has changed the Companies have made changesfuel mix it uses to generate electricity, as well as improved the generation mix and tosystems that make up its natural gas operations, which have significantly improved environmental performance. For example,
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 previously announced it expects to invest up to $21 billion from 2022 through 2035 in solar generation to achieve its target of 13.4 GW generating capacity in-service by the end of 2035. While an updated investment plan is dependent upon completion of the comprehensive business review discussed in Future Issues and Other Matters in Item 7. MD&A, it is expected to reflect a decreased investment in new nonregulated solar generation facilities. As of December 31, 2022, Dominion Energy had 2.4 GW of solar generation capacity in operation across five states and several projects under various stages of development which represented a potential generating capacity of approximately 7.8 GW. In addition, Dominion Energy previously announced it expects to invest up to $21 billion from 2022 through 2035 in offshore wind generation facilities. Dominion Energy has nearly 3,200 MWcommenced development of solar generating capacity in operation or under development in nine states, including offtake agreements for Virginia Power’s utility customers. Dominion Energy continuesthe CVOW Commercial Project, expected to add utility-scale solar capacity and currently has the fourth largest utility-owned solar fleet in the U.S. Backed by nearly $2 billion of investment from 2018 through 2020, Dominion Energy has grown its solar fleet in Virginia and North Carolina to about 2,400 MWbe placed in service in construction or under development.
Preservation of the Companies’Dominion Energy’s existing carbon-free baseload nuclear generation is also an important component of Dominion Energy’s GHG emissions reduction strategy. Accordingly,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 four nucleartwo units at SurryNorth Anna.
Dominion Energy is pursuing renewable natural gas through its investment in Align RNG, which is developing projects to capture and North Anna.
See
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
34
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 includingon the IRA.
Innovation and Energy Infrastructure Modernization
One of the pillars of Dominion Energy’s merchant solar properties.
Total CH Emissions | ||||
Dominion Energy has also implemented infrastructure improvements and improved operational practices to reduce the GHG emissions from theirfor its natural gas facilities. Dominion Energy and Dominion Energy Gas, in connection with the investment plan, areis also pursuing the construction or upgrade of regulated infrastructure in theirits natural gas businesses. The Companies haveDominion Energy has made voluntary commitments as part of the EPAEPA’s Natural Gas STAR Methane Challenge Program to continue to reduce methane emissions as part of these improvements. Dominion Energy is also a member of the EPA’s voluntary Natural Gas STAR Program. In addition, Dominion Energy is a member of the One Future Coalition, an industry group with members pledging to limit methane emissions to below 1% of gas throughput across the entire natural gas value chain.
Seeinformation, including natural gas infrastructure projects.
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. The Companies offercustomers and lower their bills. Dominion Energy offers various energy efficiency programs designed to reduce energy consumption in Virginia, North Carolina, Ohio, South Carolina, Utah and Wyoming, designed to reduce energy consumption including programs such as:
GHG Emissions
Dominion Energy continues to reducemake progress on achieving its net zero emissions commitment. Through 2021, Dominion Energy has reduced direct Scope 1 CO2 equivalent carbon and methane emissions from its electric generation and natural gas operations by 44%. Through 2021, Dominion Energy has reduced carbon emissions from electric generation by 46% since 2005 and reduced methane emissions from its natural gas infrastructure operations by 38% since 2010. For the likelihoodpurposes of these calculations and severityconsistent 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 cyber intrusions, the Companies haveQ-Pipe Group and Hope.
Dominion Energy’s 2022 emissions data is not yet available.
Corporate GHG Inventory
Dominion Energy maintains a comprehensive cybersecurity program designedCorporate GHG Inventory, which follows methodologies specified in the EPA’s Mandatory GHG Reporting Rule, 40 Code of Federal Regulations Part 98 for calculating emissions, as well as approved industry protocols. In its annual Corporate GHG Inventory, Dominion Energy voluntarily includes carbon and methane emission estimates
35
from smaller sources that are not required to protectbe included under the EPA’s mandatory GHG Reporting Program, including smaller electric generation, natural gas compressor stations and preserveother sources. Dominion Energy’s Corporate GHG Inventory also includes emissions sources it voluntarily reports to various programs in which it participates. As a result, Dominion Energy’s reported methane emissions in its Corporate GHG Inventory are higher than what is reported to the confidentiality, integrityEPA. Dominion Energy includes emissions data in its Corporate GHG Inventory based on its ownership percentage of the associated assets and availability offor the period in which the operations are owned by Dominion Energy.
Total direct Scope 1 CO2 equivalent emissions reported under Dominion Energy’s Corporate GHG Inventory were 34.9 million metric tons in 2021. Reported CO2 equivalent emissions include CO2, CH4, N2O and SF6 emissions from Dominion Energy’s electric generation operations, electric transmission and distribution operations and natural gas operations. Consistent with its ownership percentage, Dominion Energy’s 2021 emissions data and systems, including oversight byreported under its Corporate GHG Inventory includes emissions from the Board of DirectorsQ-Pipe Group (through December 2021) as well as the financialentire year of operations for Hope.
EPA Mandatory GHG Reporting Program
Dominion Energy has been reporting GHG emissions, including carbon, methane, N2O and SF6, from its natural gas infrastructure, electric generation and power delivery operations to the EPA since 2011 under the EPA mandatory GHG Reporting Program. The CompaniesEPA’s mandatory GHG Reporting Program requires annual reporting based on full equity asset ownership at the end of the calendar year. Dominion Energy’s 2021 GHG emissions reported under various subparts of the EPA’s Mandatory GHG Reporting Program as of December 31, 2021, which include the operations of Hope, are subjectas follows:
Natural Gas Operations – 2021 Emissions
Segment |
| Subpart W |
|
| Subpart C |
|
| Subparts |
|
| Subparts |
|
| Subparts |
|
| Subparts |
| ||||||
(metric tons) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Distribution |
|
| 33,482 |
|
|
|
|
|
| 33,482 |
|
|
| 2,168 |
|
|
| — |
|
|
| 839,208 |
| |
Production(1) |
|
| 13,731 |
|
|
|
|
|
| 13,731 |
|
|
| 10,028 |
|
|
| 0.02 |
|
|
| 353,311 |
| |
Transmission pipelines(1) |
|
| 573 |
|
|
|
|
|
| 573 |
|
|
| 17 |
|
|
|
|
|
| 14,340 |
| ||
Transmission compressor stations(1) |
|
| 636 |
|
|
| 4.7 |
|
|
| 641 |
|
|
| 249,628 |
|
|
| 0.47 |
|
|
| 265,788 |
|
Gathering and boosting |
|
| 3,555 |
|
|
|
|
|
| 3,555 |
|
|
| 79,542 |
|
|
| 0.16 |
|
|
| 168,472 |
| |
Storage(1) |
|
| 422 |
|
|
| 1.5 |
|
|
| 423 |
|
|
| 79,128 |
|
|
| 0.15 |
|
|
| 89,749 |
|
LNG storage |
|
| 172 |
|
|
| — |
|
|
| 172 |
|
|
| 630 |
|
|
| — |
|
|
| 4,940 |
|
Total(2)(3) |
|
| 52,571 |
|
|
| 6.2 |
|
|
| 52,577 |
|
|
| 421,141 |
|
|
| 0.80 |
|
|
| 1,735,808 |
|
36
Electric Generation Operations – 2021 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 |
|
Electric Transmission and Distribution Operations – 2021 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 |
|
ENVIRONMENTAL PROTECTION AND MONITORING EXPENDITURES
Dominion Energy incurred $251 million, $221 million and $238 million of expenses (including accretion and depreciation) during 2022, 2021 and 2020 respectively, in connection with a wide range of external organizationsenvironmental protection and participatemonitoring activities. Dominion Energy expects these expenses to be approximately $254 million and $235 million in classified briefings2023 and 2024, respectively. In addition, capital expenditures related to maintain an
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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
Regulatory, Legislative and Legal Risks
The rates of the Companies’ principal electric transmission, distribution and generation operations and gas transmission, storage and distribution operations are subject to regulatory review.
At the federal level, Dominion Energy and Virginia Power’sthe Companies’ wholesale rates for electric transmission service and various rates and charges assessed by Dominion Energy and Dominion Energy Gas’ natural gas transmission and storage businesses 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. Rates for gas transmission and storage services are adjusted in rate cases periodically and must reflect recovery of costs plus a reasonable return on investment, in accordance with cost of service ratemaking. 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.
In states other than Virginia, Dominion Energy and Virginia Power’sthe Companies’ retail electric base rates for generation and distribution services to customers are regulated on a
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.
The outcome of these legal proceedings, investigations and examinations, including settlements, is uncertain and may adversely affect Dominion Energy’s financial condition or results of operation.
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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 state subsidized resources that do not seek a FERC exemption, increasing their risk of failing to clear the capacity auction and
The Companies are subject to complex governmental regulation, including tax regulation, that could adversely affect
The 2017 Tax Reform Act couldCompanies have been and may continue to be or become subject to legal proceedings and governmental investigations and examinations. The Companies may from time to time be subject to various legal proceedings and governmental investigations and examinations. For example, Dominion Energy, following the SCANA Combination, has been subject to numerous federal and state legal proceedings and governmental investigations relating to the decision of SCANA and DESC to abandon construction at the NND Project. Dominion Energy has spent substantial amounts of time and money defending these lawsuits and proceedings and on related investigations. In addition, juries have demonstrated a material impact onwillingness to grant large awards in certain cases, including personal injury claims. Accordingly, actual costs incurred may differ materially from insured or reserved amounts and may not be recoverable, in whole or in part, by insurance or in rates from our customers. The outcome of these or future legal proceedings, investigations and examinations, including settlements, may adversely affect the Companies’ financial condition or results of operation.
Environmental Risks
Compliance with federal and/or state requirements imposing limitations on GHG emissions or efficiency improvements, as well as Dominion Energy’s commitment to achieve net zero carbon and methane emissions by 2050, may result in significant compliance costs, could result in certain of the Companies’ existing electric generation units being uneconomical to maintain or operate and may depend upon technological advancements which may be beyond the Companies’ control. Virginia has adopted the VCEA which establishes renewable energy and CO2 reduction targets for Virginia Power’s generation fleet and grid operations, cash flows,including the requirement that 100% of Virginia Power’s electricity come from zero-carbon generation by the end of 2045. The legislation mandates the development of 16.1 GW of solar or onshore wind capacity by the end of 2035, which includes specific requirements for utility-scale solar of 3.0 GW by the end of 2024, up to 15.0 GW by the end of 2035 and financial results.
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
39
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 corporate income tax rates to 21% under the provisionsimpairment of the 2017 Tax Reform Act have been recognized as regulatory liabilities and are expected to be shared with customers, generally through reductions in future ratesassets, or in the form of credits to customer bills. The 2017 Tax Reform Act includes provisions that stipulate how these excess deferred taxes may be passed back to customers for certain accelerated tax depreciation benefits. Potential reductions in future rates attributable to other, non-plant related excess deferred taxes may be determined by our regulators. The amount and timing of these reductions could be material tootherwise adversely affect the Companies’ results of operations, cash flows and/financial performance or financial condition.
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, the 2017 Tax Reform Act contains provisions that limit the interest deduction on business interest to (1) business interest income, plus (2) 30 percent of the taxpayer’s adjusted taxable income. Business interest and business interest income are defined as that allocable to a trade or business and not investment interest and income. Dominion Energy is a consolidated group with both regulated and nonregulated lines of businesses. In November 2018, the U.S. Department of Treasury issued proposed regulations defining interest as any amounts associated with the time value of money or use of funds. These proposed regulations provide guidance for purposes of the exception to the interest limitation for regulated public utilities, the application of the interest limitation to consolidated groups, such as Dominion Energy, and the interest limitation with respect
The Companies’ operations and construction activities are subject to a number of environmental laws and regulations which impose significant compliance costs on the Companies.
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 have beenmay be imposed on the natural gas sector, including rules to limit methane leakage.sector. The Companies are also subject to federal water and waste regulations, including regulations concerning cooling water intake structures, coal combustion
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
The ACE Rule, which became effective in September 2019, is targeted at reducing CO2 emissions from existing coal-fired power plants. The ACE
The EPA has issued regulations concerning the management and storage of CCRs, which Virginia has adopted. These CCR regulations require Dominion Energy and Virginia Powerthe Companies to make additional capital expenditures and increase operating and maintenance expenses. In addition, Dominion Energy and Virginia Powerthe Companies will incur expenses and other costs associated with closing, corrective action and ongoing monitoring of certain ash ponds. Dominion Energyponds and Virginia Powerlandfills. The Companies also may face litigation concerning their coal ash facilities.
Further, while Dominion Energy and Virginia Powerthe Companies operate their ash ponds and landfills in compliance with applicable state safety regulations, a release of coal ash with a significant environmental impact such as the Dan River ash basin release by a neighboring utility, 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 Dominion Energy and/or Virginia Power.
Construction Risks
The Companies’ infrastructure build and expansion plans often require regulatory approval, including environmental permits, before commencing construction and completing projects. The
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transmission lines, pipeline replacements, facility expansions or renewed licensing, conversions and Start-upadditionalother 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, Atlantic Coast PipelineDominion 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 has impacted the cost and schedule forsuch as the Atlantic Coast Pipeline Project.Project and ultimately led to its cancellation in July 2020. Even if facility construction, pipeline, expansion, electric transmission line, conversion and other infrastructure projects are completed, the total costs of the projects may be higher than anticipated and the performance of the business of the Companies following completion of the projects may not meet expectations.
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.
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 terrainenvironments 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.
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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.
A successful cyber attack through third-party or insider action on the systems that control the Companies’ electric generation, electric or gas 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 the Companies’ services. The widescale implementation of alternative generation methods could negatively impact the reliability of the Companies’ electric grid and/or result in significant costs to enhance the grid. Virginia Power has an exclusive franchise to serve retail electric customers in Virginia. However, Virginia’s Retail Access Statutes allow certain electric generation customers exceptions to this franchise. As market conditions change, Virginia Power’s customers may further pursue exceptions and Virginia Power’s exclusive franchise may erode.
Reduced energy demand or significantly slowed growth in demand due to customer adoption of energy efficient technology, conservation, distributed generation, regional economic conditions, or the impact of additional compliance obligations, unless substantially offset through regulatory cost allocations, could adversely impact the value of the Companies’ business activities.
The Companies may be materially adversely affected by negative publicity or the inability of Dominion Energy to meet its stated commitments. From time to time, political and public sentiment may result in a significant amount of adverse press coverage and other adverse public statements affecting the Companies. Any failure by Dominion Energy to realize its commitments to achieve net zero carbon and methane emissions by 2050, increase workforce diversity, enhance the customer experience or other long-term goals could lead to adverse press coverage and other adverse public statements affecting the Companies. The ability to comply with some or all of Dominion Energy’s voluntary commitments may be outside of its control. For example, Dominion Energy is dependent on the actions of third parties to meet the expanded commitment regarding Scope 2 emissions and Scope 3 emissions. If downstream customers or upstream suppliers do not sufficiently reduce their GHG emissions, Dominion Energy may not achieve its net zero emissions goal. In addition, while the Atlantic Coast Pipeline Project was cancelled in July 2020 and several of the legal proceedings and governmental investigations relating to the abandonment of the NND Project have been resolved, there is a risk that lingering negative publicity may continue. Adverse press coverage and other adverse statements, whether or not driven by political or public sentiment, may also result in investigations by regulators, legislators and law enforcement officials or in legal claims as well as adverse outcomes.
Addressing any adverse publicity, governmental scrutiny or enforcement or other legal proceedings is time consuming and expensive and, regardless of the factual basis for the assertions being made, can have a negative impact on the reputation of the Companies, on the morale and performance of their employees and on their relationships with their respective regulators, customers and commercial counterparties. It may also have a negative impact on the Companies’ ability to take timely advantage of various business and market opportunities. The direct and indirect effects of negative publicity, and the demands of responding to and addressing it, may have a material adverse effect on the Companies’ business, financial condition and results of operations.
Dominion Energy’s nonregulated generation business operates in a challenging market, which could adversely affect its results of operations and future growth. The success of Dominion Energy’s contracted generation business depends upon favorable market conditions including the ability to sell power at prices sufficient to cover its operating costs. Dominion Energy operates in active wholesale markets that expose it to price volatility for electricity and nuclear fuel as well as the credit risk of counterparties. Dominion Energy attempts to manage its price risk by entering into long-term power purchase agreements with customers as well as hedging transactions, including short-term and long-term fixed price sales and purchase contracts. The failure of Dominion Energy to maintain, renew or replace its existing long-term contracts on similar terms or with counterparties with similar credit profiles could result in a loss of revenue and/or decreased earnings and cash flows for Dominion Energy.
In these wholesale markets, the spot market price of electricity for each hour is generally determined by the cost of supplying the next unit of electricity to the market during that hour. In many cases, the next unit of electricity supplied would be provided by generating stations that consume fossil fuels, primarily natural gas. Consequently, the open market wholesale price for electricity generally reflects the cost of natural gas plus the cost to convert the fuel to electricity. Therefore, changes in the price of natural gas generally affect the open market wholesale price of electricity. To the extent Dominion Energy does not enter into long-term power purchase agreements or otherwise effectively hedge its output, these changes in market prices could adversely affect its financial results.
Dominion Energy purchases nuclear fuel primarily under long-term contracts. Dominion Energy is exposed to nuclear fuel cost volatility for the portion of its nuclear fuel obtained through short-term contracts or on the spot market, including as a result of market supply shortages. Nuclear fuel prices can be volatile and the price that can be obtained for power produced may not change at the same rate as nuclear fuel costs, thus adversely impacting Dominion Energy’s financial results. In addition, in the event that any of the contracted generation facilities experience a forced outage, Dominion Energy may not receive the level of revenue it anticipated.
Dominion Energy conducts certain operations through partnership arrangements involving third-party investors which may limit Dominion Energy’s operational flexibility or result in an adverse impact on its financial results. Certain of Dominion
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Energy’s operations are conducted through entities subject to partnership arrangements under which Dominion Energy has significant influence but does not control the operations of such entities or in which Dominion Energy’s control over such entities may be subject to certain rights of third-party investors. Accordingly, while Dominion Energy may have a certain level of control or influence over these entities, it may not have unilateral, or any, control over the day-to-day operations of these entities or over decisions that may have a material financial impact on the partnership participants, including Dominion Energy. In each case such partnership arrangements operate in accordance with their respective governance documents, and Dominion Energy is dependent upon third parties satisfying their respective obligations, including, as applicable, funding of their required share of capital expenditures. Such third-party investors have their own interests and objectives which may differ from those of Dominion Energy and, accordingly, disputes may arise amongst the owners of such partnership arrangements that may result in delays, litigation or operational impasses.
For example, Dominion Energy has a noncontrolling 50% interest in Cove Point following the sale of a 25% controlling interest to BHE in November 2020. This controlling interest allows BHE to make decisions affecting Cove Point’s ability to retain its long-term contracts. Cove Point is a party to certain contracts that allow a regulated service provider and a customer to mutually agree to sign a contract for service at a “negotiated rate” which may be above or below the FERC regulated, cost-based recourse rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs which could be produced by inflation or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue as a result of these “negotiated rate” contracts could decrease Cove Point’s earnings and cash flows. The inability to maintain or renew such contracts on favorable terms may have a material impact to Dominion Energy’s results of operations, financial position or cash flows. Dominion Energy is also dependent upon BHE for managing counterparty credit risk relating to Cove Point’s terminal services agreements for its liquefied natural gas export/liquefaction facility. While the counterparties’ obligations are supported by parental guarantees and letters of credit, there is no assurance that such credit support would be sufficient to satisfy the obligations in the event of a counterparty default. In addition, if a controversy arises under either terminal services agreement resulting in a judgment in Cove Point’s favor, Cove Point may need to seek to enforce a final U.S. court judgment in a foreign tribunal, which could involve a lengthy process. Accordingly, there is no assurance that BHE may pursue remedies in the event of default in the same manner as Dominion Energy would if it had unilateral control over such decisions.
War, acts and threats of terrorism, intentional acts and other significant events could adversely affect the Companies’ operations.
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.
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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 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 Dominion Energy and Virginia Powerthe 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.
An inability to access financial markets and, in the case of Dominion Energy, and Dominion Energy Gas, obtain cash from subsidiaries could adversely affect the execution of the Companies’ business plans.
Dominion Energy and Dominion Energy Gas areis a holding companiescompany that conductconducts all of theirits operations through their respectiveits subsidiaries. Accordingly, each entity’sDominion 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 Dominion Energy and Virginia Power’sthe Companies’ decommissioning trust funds and Dominion Energy and Dominion Energy Gas’Energy’s benefit plan assets or increase Dominion Energy and Dominion Energy Gas’Energy’s liabilities, which could then require significant additional funding.
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 Dominion Energy and Virginia Power’sthe Companies’ nuclear plants or require additional NRC-approved funding assurance.
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A decline in the market value of the assets held in trusts to satisfy future obligations under Dominion Energy and Dominion Energy Gas’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 and Dominion Energy Gas’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 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
Future impairments of goodwill or other intangible assets or long-lived assets may have a material adverse effect on the Companies’ results.
Exposure to counterparty performance may adversely affect the Companies’ financial results of operations. The Companies are exposed to credit risks of their counterparties and the risk that one or more counterparties may fail or delay the performance of their contractual obligations, including but not limited to payment for services. Some of Dominion Energy’s operations are conducted through partnership arrangements, as noted above. Counterparties could fail or delay the performance of their contractual obligations for a number of reasons, including the effect of regulations on their operations. Defaults or failure to perform by customers, suppliers, contractors, joint venture partners, financial institutions or other third parties may adversely affect the Companies’ financial results.
Public health crises and epidemics or pandemics, such as COVID-19, could adversely affect the Companies’ business, results of operations, financial condition, liquidity and/or cash flows. The effects of the continued outbreak of the COVID-19 pandemic and related government responses could include extended disruptions to supply chains and capital markets, reduced labor availability and productivity and a prolonged reduction in economic activity. The effects could also have a variety of adverse impacts on the Companies, including reduced demand for energy, particularly from commercial and industrial customers, impairment of goodwill or long-lived assets and diminished ability of the Companies to access funds from financial institutions and capital markets. There remains uncertainty regarding the extent and duration of measures to try to contain the virus, such as travel bans and restrictions, quarantines, shelter-in-place orders and shutdowns. Such restrictions may cause operational interruptions and delays in construction projects, which, in the case of renewable energy projects, could delay the expected in-service dates of these projects and financial statement impact of the investment tax credits associated with these projects. For the duration of the outbreak of COVID-19, voluntary suspension, or potential legislative or government action, such as legislation enacted in Virginia in November 2020, may limit the Companies’ ability to collect on overdue accounts or disconnect services for non-payment, which may cause a decrease in the Companies’ results of operations and cash flows.
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Item 1B. Unresolved Staff Comments
None.
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Item 2. Properties
As of December 31, 2019,2022, 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 and Dominion Energy Gas shareshares Dominion Energy’s principal executive office in Richmond, Virginia, which is owned by Dominion Energy.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.
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, 2019;2022; however, by leaving the indenture open, Virginia Power expects to retainretains the flexibility to issue mortgage bonds in the future. Certain of Dominion Energy’s merchantnonregulated 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 58,40059,700 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The grants for most of its electric lines contain471 substations.
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The following tables list Virginia Power’s generating units and capability as of December 31, 2019.
Plant | Location | Net Summer Capability (MW) | Percentage Net Summer Capability | |||||||||
Gas | ||||||||||||
Greensville County (CC) | Greensville County, VA | 1,629 | ||||||||||
Brunswick County (CC) | Brunswick County, VA | 1,376 | ||||||||||
Warren County (CC) | Warren County, VA | 1,370 | ||||||||||
Ladysmith (CT) | Ladysmith, VA | 783 | ||||||||||
Bear Garden (CC) | Buckingham County, VA | 622 | ||||||||||
Remington (CT) | Remington, VA | 622 | ||||||||||
Possum Point (CC) (1) | Dumfries, VA | 573 | ||||||||||
Chesterfield (CC) | Chester, VA | 392 | ||||||||||
Elizabeth River (CT) | Chesapeake, VA | 330 | ||||||||||
Gordonsville Energy (CC) | Gordonsville, VA | 218 | ||||||||||
Gravel Neck (CT) | Surry, VA | 170 | ||||||||||
Darbytown (CT) | Richmond, VA | 168 | ||||||||||
Rosemary (CC) | Roanoke Rapids, NC | 160 | ||||||||||
Total Gas | 8,413 | 40 | % | |||||||||
Coal | ||||||||||||
Mt. Storm | Mt. Storm, WV | 1,621 | ||||||||||
Chesterfield | Chester, VA | 1,014 | ||||||||||
Virginia City Hybrid Energy Center | Wise County, VA | 610 | ||||||||||
Clover | Clover, VA | 439 | (2) | |||||||||
Total Coal | 3,684 | 18 | ||||||||||
Nuclear | ||||||||||||
Surry | Surry, VA | 1,676 | ||||||||||
North Anna | Mineral, VA | 1,672 | (3) | |||||||||
Total Nuclear | 3,348 | 16 | ||||||||||
Oil | ||||||||||||
Yorktown | Yorktown, VA | 790 | ||||||||||
Possum Point | Dumfries, VA | 770 | ||||||||||
Gravel Neck (CT) | Surry, VA | 198 | ||||||||||
Darbytown (CT) | Richmond, VA | 168 | ||||||||||
Possum Point (CT) | Dumfries, VA | 72 | ||||||||||
Low Moor (CT) | Covington, VA | 48 | ||||||||||
Northern Neck (CT) | Lively, VA | 47 | ||||||||||
Chesapeake (CT) | Chesapeake, VA | 39 | ||||||||||
Total Oil | 2,132 | 10 | ||||||||||
Hydro | ||||||||||||
Bath County | Warm Springs, VA | 1,808 | (4) | |||||||||
Gaston | Roanoke Rapids, NC | 220 | ||||||||||
Roanoke Rapids | Roanoke Rapids, NC | 95 | ||||||||||
Other | 1 | |||||||||||
Total Hydro | 2,124 | 10 | ||||||||||
Solar | ||||||||||||
Colonial Trail West | Surry County, VA | 142 | ||||||||||
Whitehouse Solar | Louisa County, VA | 20 | ||||||||||
Woodland Solar | Isle of Wight County, VA | 19 | ||||||||||
Scott Solar | Powhatan, VA | 17 | ||||||||||
Total Solar | 198 | 1 | ||||||||||
Biomass | ||||||||||||
Altavista | Altavista, VA | 51 | ||||||||||
Polyester | Hopewell, VA | 51 | ||||||||||
Southampton | Southampton, VA | 51 | ||||||||||
Total Biomass | 153 | 1 | ||||||||||
Various | ||||||||||||
Mt. Storm (CT) | Mt. Storm, WV | 11 | — | |||||||||
20,063 | ||||||||||||
Power Purchase Agreements | 782 | 4 | ||||||||||
Total Utility Generation | 20,845 | 100 | % | |||||||||
VIRGINIA POWER UTILITY GENERATION
Plant |
| Location |
| Net Summer |
|
| Percentage |
|
| ||
Gas |
|
|
|
|
|
|
|
|
| ||
Greensville County (CC) |
| Greensville County, VA |
|
| 1,629 |
|
|
|
|
| |
Brunswick County (CC) |
| Brunswick County, VA |
|
| 1,376 |
|
|
|
|
| |
Warren County (CC) |
| Warren County, VA |
|
| 1,349 |
|
|
|
|
| |
Ladysmith (CT) |
| Ladysmith, VA |
|
| 783 |
|
|
|
|
| |
Bear Garden (CC) |
| Buckingham County, VA |
|
| 622 |
|
|
|
|
| |
Remington (CT) |
| Remington, VA |
|
| 622 |
|
|
|
|
| |
Possum Point (CC) |
| Dumfries, VA |
|
| 573 |
|
|
|
|
| |
Chesterfield (CC) |
| Chester, VA |
|
| 392 |
|
|
|
|
| |
Elizabeth River (CT) |
| Chesapeake, VA |
|
| 330 |
|
|
|
|
| |
Gordonsville Energy (CC) |
| Gordonsville, VA |
|
| 218 |
|
|
|
|
| |
Gravel Neck (CT) |
| Surry, VA |
|
| 170 |
|
|
|
|
| |
Darbytown (CT) |
| Richmond, VA |
|
| 168 |
|
|
|
|
| |
Total Gas |
|
|
|
| 8,232 |
|
|
| 41 |
| % |
Coal |
|
|
|
|
|
|
|
|
| ||
Mt. Storm |
| Mt. Storm, WV |
|
| 1,617 |
|
|
|
|
| |
Chesterfield(1) |
| Chester, VA |
|
| 1,014 |
|
|
|
|
| |
Virginia City Hybrid Energy Center |
| Wise County, VA |
|
| 610 |
|
|
|
|
| |
Clover |
| Clover, VA |
|
| 439 |
| (2) |
|
|
| |
Total Coal |
|
|
|
| 3,680 |
|
|
| 18 |
|
|
Nuclear |
|
|
|
|
|
|
|
|
| ||
Surry |
| Surry, VA |
|
| 1,676 |
|
|
|
|
| |
North Anna |
| Mineral, VA |
|
| 1,672 |
| (3) |
|
|
| |
Total Nuclear |
|
|
|
| 3,348 |
|
|
| 16 |
|
|
Hydro |
|
|
|
|
|
|
|
|
| ||
Bath County |
| Warm Springs, VA |
|
| 1,808 |
| (4) |
|
|
| |
Gaston |
| Roanoke Rapids, NC |
|
| 220 |
|
|
|
|
| |
Roanoke Rapids |
| Roanoke Rapids, NC |
|
| 95 |
|
|
|
|
| |
Other |
|
|
|
| 1 |
|
|
|
|
| |
Total Hydro |
|
|
|
| 2,124 |
|
|
| 10 |
|
|
Oil |
|
|
|
|
|
|
|
|
| ||
Yorktown(1) |
| Yorktown, VA |
|
| 790 |
|
|
|
|
| |
Gravel Neck (CT) |
| Surry, VA |
|
| 198 |
|
|
|
|
| |
Darbytown (CT) |
| Richmond, VA |
|
| 168 |
|
|
|
|
| |
Rosemary (CC) |
| Roanoke Rapids, NC |
|
| 160 |
|
|
|
|
| |
Possum Point (CT) |
| Dumfries, VA |
|
| 72 |
|
|
|
|
| |
Low Moor (CT) |
| Covington, VA |
|
| 48 |
|
|
|
|
| |
Northern Neck (CT) |
| Lively, VA |
|
| 47 |
|
|
|
|
| |
Chesapeake (CT) |
| Chesapeake, VA |
|
| 39 |
|
|
|
|
| |
Total Oil |
|
|
|
| 1,522 |
|
|
| 7 |
|
|
Solar(5) |
|
|
|
|
|
|
|
|
| ||
Colonial Trail West |
| Surry County, VA |
|
| 142 |
|
|
|
|
| |
Sadler Solar |
| Emporia, VA |
|
| 100 |
|
|
|
|
| |
Spring Grove |
| Surry County, VA |
|
| 98 |
|
|
|
|
| |
Grassfield |
| Chesapeake, VA |
|
| 20 |
|
|
|
|
| |
Whitehouse Solar |
| Louisa County, VA |
|
| 20 |
|
|
|
|
| |
Woodland Solar |
| Isle of Wight County, VA |
|
| 19 |
|
|
|
|
| |
Scott Solar |
| Powhatan, VA |
|
| 17 |
|
|
|
|
| |
Total Solar |
|
|
|
| 416 |
|
|
| 2 |
|
|
Biomass |
|
|
|
|
|
|
|
|
| ||
Altavista(6) |
| Altavista, VA |
|
| 51 |
|
|
|
|
| |
Polyester(6) |
| Hopewell, VA |
|
| 51 |
|
|
|
|
| |
Southampton(6) |
| Southampton, VA |
|
| 51 |
|
|
|
|
| |
Total Biomass |
|
|
|
| 153 |
|
|
| 1 |
|
|
Wind |
|
|
|
|
|
|
|
|
| ||
CVOW Pilot Project |
| Virginia Beach, VA |
|
| 12 |
|
|
| — |
|
|
Various |
|
|
|
|
|
|
|
|
| ||
Mt. Storm (CT) |
| Mt. Storm, WV |
|
| 11 |
|
|
| — |
|
|
|
|
|
|
| 19,498 |
|
|
|
|
| |
Power Purchase Agreements |
|
|
|
| 1,106 |
|
|
| 5 |
|
|
Total Utility Generation |
|
|
|
| 20,604 |
|
|
| 100 |
| % |
Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.
50
VIRGINIA POWER NON-JURISDICTIONAL GENERATION
Plant | Location | Net Summer | ||||||
Solar(1) | ||||||||
Fort Powhatan | Disputanta, VA | 150 | ||||||
Maplewood | Chatham, VA | 120 | ||||||
Desper | Louisa, VA | 88 | ||||||
Gutenberg | Garysburg, NC | 80 | ||||||
Butcher Creek | Chase City, VA | 80 | ||||||
Pecan | Pleasant Hill, NC | 75 | ||||||
Chestnut | Halifax County, NC | 75 | ||||||
Bedford | Chesapeake, VA | 70 | ||||||
Pumpkinseed | Emporia, VA | 60 | ||||||
Gloucester | Gloucester County, VA | 20 | ||||||
Montross | Westmoreland County, VA | 20 | ||||||
Morgans Corner | Pasquotank County, NC | 20 | ||||||
Remington | Fauquier County, VA | 20 | ||||||
Rochambeau | James City County, VA | 20 | ||||||
Oceana | Virginia Beach, VA | 18 | ||||||
Hollyfield | Manquin, VA | 17 | ||||||
Puller | Topping, VA | 15 | ||||||
Total | 948 | |||||||
(1)
GAS DISTRIBUTION
Gas Transmission & Storage
East Ohio’s integrated underground storage facilities have more than 60 bcf of working gas capacity to serve base and peak demand. PSNC owns one LNG facility that stores the liquefied equivalent of 1.0 bcf of natural gas, can regasify approximately 10% of its storage capacity per day and can liquefy less than 1% of its storage capacity per day. Questar Gas also owns one LNG facility that stores the liquified equivalent of 1.2 bcf of natural gas, can regasify approximately 12% of its storage capacity per day and can liquefy less than 1% of its storage capacity per day.
DOMINION ENERGY SOUTH CAROLINA
DESC has approximately 3,900 miles and 18,800 miles of electric transmission and distribution lines, respectively, exclusive of service level lines, in South Carolina. The grants for most of DESC’s electric lines contain rights-of-way that have been obtained from the apparent owners of real estate, but underlying property titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked. In addition, DESC owns 459 substations.
DESC’s natural gas system includes approximately 19,100 miles of distribution mains and related service facilities, which are supported by approximately 400 miles of transmission pipeline.
DESC owns two LNG facilities, one located in the states of Colorado, Georgia, Maryland, New York, Ohio, Pennsylvania,near Charleston, South Carolina, Utah, Virginia, West Virginia and Wyoming.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, 2022.
Plant |
| Location |
| Net Summer |
|
| Percentage |
|
| ||
Gas |
|
|
|
|
|
|
|
|
| ||
Jasper (CC) (1) |
| Hardeeville, SC |
|
| 903 |
|
|
|
|
| |
Columbia Energy Center (CC) (1) |
| Gaston, SC |
|
| 519 |
|
|
|
|
| |
Urquhart (CC) (1) |
| Beech Island, SC |
|
| 458 |
|
|
|
|
| |
McMeekin |
| Irmo, SC |
|
| 250 |
|
|
|
|
| |
Hagood (CT) (1) |
| Charleston, SC |
|
| 126 |
|
|
|
|
| |
Urquhart Unit 3 |
| Beech Island, SC |
|
| 95 |
|
|
|
|
| |
Urquhart (CT) (1) |
| Beech Island, SC |
|
| 87 |
|
|
|
|
| |
Parr (CT) (1)(2) |
| Jenkinsville, SC |
|
| 47 |
|
|
|
|
| |
Coit (CT) (1)(2) |
| Columbia, SC |
|
| 26 |
|
|
|
|
| |
Total Gas |
|
|
|
| 2,511 |
|
|
| 38 |
| % |
Coal |
|
|
|
|
|
|
|
|
| ||
Wateree |
| Eastover, SC |
|
| 684 |
|
|
|
|
| |
Williams |
| Goose Creek, SC |
|
| 605 |
|
|
|
|
| |
Cope (3) |
| Cope, SC |
|
| 415 |
|
|
|
|
| |
Total Coal |
|
|
|
| 1,704 |
|
|
| 26 |
|
|
Hydro |
|
|
|
|
|
|
|
|
| ||
Fairfield |
| Jenkinsville, SC |
|
| 576 |
|
|
|
|
| |
Saluda |
| Irmo, SC |
|
| 198 |
|
|
|
|
| |
Other |
| Various |
|
| 18 |
|
|
|
|
| |
Total Hydro |
|
|
|
| 792 |
|
|
| 12 |
|
|
Nuclear |
|
|
|
|
|
|
|
|
| ||
Summer |
| Jenkinsville, SC |
|
| 651 |
| (4) |
| 10 |
|
|
|
|
|
|
| 5,658 |
|
|
|
|
| |
Power Purchase Agreements |
|
|
|
| 973 |
| (5) |
| 14 |
|
|
Total Utility Generation |
|
|
|
| 6,631 |
|
|
| 100 |
| % |
Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.
CONTRACTED ASSETS
Contracted Assets includes Dominion Energy’s 50% noncontrolling interest in Cove Point’sPoint. The Cove Point LNG Facility has an operational peak regasification dailyBcfe/bcfe/day (approximately 5.75 Mtpa) should the Liquefaction Facility perform better than expected.
52
The following table lists DESC’sContracted Assets’ generating units and capability as of December 31, 2019.
Plant | Location | Net Summer Capability (MW) | Percentage Net Summer Capability | |||||||
Gas | ||||||||||
Jasper (CC) (1) | Hardeeville, SC | 852 | ||||||||
Columbia Energy Center (CC) (1) | Gaston, SC | 519 | ||||||||
Urquhart (CC) (1) | Beech Island, SC | 458 | ||||||||
McMeekin | Irmo, SC | 250 | ||||||||
Hagood (CT) (1) | Charleston, SC | 126 | ||||||||
Urquhart Unit 3 | Beech Island, SC | 95 | ||||||||
Urquhart (CT) | Beech Island, SC | 87 | ||||||||
Parr (CT) (1) | Jenkinsville, SC | 60 | ||||||||
Williams (CT) (1) | Goose Creek, SC | 40 | ||||||||
Coit (CT) (1) | Columbia, SC | 26 | ||||||||
Total Gas (2) | 2,513 | 40 | % | |||||||
Coal | ||||||||||
Wateree | Eastover, SC | 684 | ||||||||
Williams | Goose Creek, SC | 605 | ||||||||
Cope (3) | Cope, SC | 415 | ||||||||
Total Coal | 1,704 | 27 | ||||||||
Hydro | ||||||||||
Fairfield | Jenkinsville, SC | 576 | ||||||||
Saluda | Irmo, SC | 190 | ||||||||
Other | Various | 18 | ||||||||
Total Hydro | 784 | 13 | ||||||||
Nuclear | ||||||||||
Summer | Jenkinsville, SC | 650 | (4) | |||||||
Total Nuclear | 650 | 10 | ||||||||
Power Purchase Agreements | 596 | (5) | 10 | |||||||
Total Utility Generation | 6,247 | 100 | % | |||||||
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 |
| % |
(1)
Plant | Location | Net Summer Capability (MW) | Percentage Net Summer Capability | |||||||||
Nuclear | ||||||||||||
Millstone | Waterford, CT | 2,001 | (1) | |||||||||
Total Nuclear | 2,001 | 59 | % | |||||||||
Solar (2) | ||||||||||||
Escalante I, II and III | Beaver County, UT | 120 | (3) | |||||||||
Amazon Solar Farm Virginia—Southampton | Newsoms, VA | 100 | (4) | |||||||||
Amazon Solar Farm Virginia—Accomack | Oak Hall, VA | 80 | (4) | |||||||||
Innovative Solar 37 | Morven, NC | 79 | (4) | |||||||||
Wilkinson | Pantego, NC | 74 | ||||||||||
Seabrook | Beaufort County, SC | 72 | ||||||||||
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—Sappony | Stoney Creek, VA | 20 | (4) | |||||||||
Amazon Solar Farm Virginia—Scott II | Powhatan, VA | 20 | (4) | |||||||||
Cottonwood Solar | Kings and Kern Counties, CA | 16 | (5) | |||||||||
Adams East Solar | Tranquility, CA | 13 | (5) | |||||||||
Alamo Solar | San Bernardino, CA | 13 | (5) | |||||||||
CID Solar | Corcoran, CA | 13 | (5) | |||||||||
Imperial Valley Solar | Imperial, 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 | 43 | (4)(5) | |||||||||
Total Solar | 1,268 | 37 | ||||||||||
Wind | ||||||||||||
Fowler Ridge (6) | Benton County, IN | 150 | (7) | 4 | ||||||||
Total Merchant Generation | 3,419 | 100 | % | |||||||||
53
Item 3. Legal Proceedings
From time to time, the Companies are allegedparties to be in violationvarious legal, environmental or in default under orders, statutes, rules or regulations relating to the environment, compliance plans imposed upon or agreed to by the Companies, or permits issued by various local, state and/or federal agencies for the construction or operation of facilities. Administrativeother regulatory proceedings, may also be pending on these matters. In addition,including in the ordinary course of business,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 and their subsidiaries are involved in various legalreasonably believe will exceed a specified threshold. Pursuant to the SEC regulations, the Companies use a threshold of $1 million for such proceedings.
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 | |
Robert M. Blue (55) | Chair of the Board of Directors from April 2021 to present; President and CEO from | |
present; Director from November 2020 to present; Executive Vice President and Co-COO from December 2019 to | ||
Edward H. Baine (49) | President—Dominion Energy Virginia from October 2020 to present; Senior Vice | |
P. Rodney Blevins | President—Gas Distribution from January 2022 to present; President—Dominion Energy South Carolina from December 2019 to | |
Carlos M. Brown (48) | ||
Senior Vice President, Chief | ||
present; Senior Vice President, General Counsel and Chief Compliance Officer from December 2019 to | ||
Michele L. Cardiff | Senior Vice President, Controller and Chief Accounting Officer from October 2020 to present; Vice President, Controller and CAO from April 2014 to |
W. Keller Kissam (56) | President—Dominion Energy | |
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 2019. | |
Steven D. Ridge (42) | Senior Vice President and CFO from November 2022 to present; President of Questar Gas from October 2022 to November 2022; Vice President and General Manager—Western Distribution from October 2021 to September 2022; Vice President—Investor Relations of DES from April 2019 to September 2021; Director—Investor Relations of DES from October 2017 to March 2019. | |
Daniel G. Stoddard (60) | 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. | ||||||||
(1)
55
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 14, 2020,15, 2023, there were approximately 134,000122,016 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
Purchases of Equity Securities
Period |
| Total |
|
| Average |
|
| Total Number |
|
| Maximum Number (or | |||
10/1/22-10/31/22 |
|
| 74,869 |
|
| $ | 69.11 |
|
|
| — |
|
| $ 0.92 billion |
11/1/22-11/30/22 |
|
| 1,014 |
|
|
| 69.72 |
|
|
| — |
|
| 0.92 billion |
12/1/22-12/31/22 |
|
| 556 |
|
|
| 60.37 |
|
|
| — |
|
| 0.92 billion |
Total |
|
| 76,439 |
|
| $ | 69.05 |
|
|
| — |
|
| $ 0.92 billion |
Dominion Energy Purchases Of Equity Securities | ||||||||||||||||
Period | Total Number of Shares (or Units) Purchased (1) | Average Price Paid per Share (or Unit) (2) | Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs | Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased under the Plans or Programs (3) | ||||||||||||
10/1/19-10/31/19 | 31,435 | $81.22 | — | 19,629,059 shares/$ | 1.18 billion | |||||||||||
11/1/19-11/30/19 | 401 | 83.08 | — | 19,629,059 shares/$ | 1.18 billion | |||||||||||
12/1/19-12/31/19 | 2,429 | 83.11 | — | 19,629,059 shares/$ | 1.18 billion | |||||||||||
Total | 34,265 | $81.38 | — | 19,629,059 shares/$ | 1.18 billion | |||||||||||
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 20202023 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
Year Ended December 31, | 2019 (1) | 2018 (2) | 2017 (3) | 2016 (4) | 2015 | |||||||||||||||
(millions, except per share amounts) | ||||||||||||||||||||
Operating revenue | $ | 16,572 | $ | 13,366 | $ | 12,586 | $ | 11,737 | $ | 11,683 | ||||||||||
Net income attributable to Dominion Energy | 1,358 | 2,447 | 2,999 | 2,123 | 1,899 | |||||||||||||||
Net income attributable to Dominion Energy per common share-basic | 1.66 | 3.74 | 4.72 | 3.44 | 3.21 | |||||||||||||||
Net income attributable to Dominion Energy per common share-diluted | 1.62 | 3.74 | 4.72 | 3.44 | 3.20 | |||||||||||||||
Dividends declared per common share | 3.67 | 3.34 | 3.035 | 2.80 | 2.59 | |||||||||||||||
Total assets | 103,823 | 77,914 | 76,585 | 71,610 | 58,648 | |||||||||||||||
Long-term debt (5) | 33,824 | 31,144 | 30,948 | 30,231 | 23,468 | |||||||||||||||
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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 and Dominion Energy Gas’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 and Dominion Energy Gas meetmeets the conditions to file under the reduced disclosure format, and therefore havehas omitted certain sections of MD&A.
CONTENTS OF MD&A
MD&A consists of the following information:
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:
57
58
Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors.
The Companies’ forward-looking statements are based on beliefs and assumptions using information available at the time the statements are made. The Companies caution the reader not to place undue reliance on their forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, differ materially from actual results. The Companies undertake no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.
ACCOUNTING MATTERS
Critical Accounting Policies and Estimates
Dominion Energy has identified the following accounting policies, including certain inherent estimates, that as a result of the judgments, uncertainties, uniqueness and complexities of the underlying accounting standards and operations involved, could result in material changes to its financial condition or results of operations under different conditions or using different assumptions. Dominion Energy has discussed the development, selection and disclosure of each of these policies with the Audit Committee of its Board of Directors.
Accounting for Regulated Operations
The accounting for Dominion Energy’s regulated electric and gas operations differs from the accounting for nonregulated operations in that Dominion Energy is required to reflect the effect of rate regulation in its Consolidated Financial Statements. For regulated businesses subject to federal or state
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:
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 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
Dominion Energy’s AROs include a significant balance related to the future decommissioning of its merchantnonregulated and utility nuclear facilities. These nuclear decommissioning AROs are reported in Dominion Energy Virginia, Dominion Energy South Carolina and Contracted Generation.Assets. At December 31, 2019,2022 and 2021, Dominion Energy’s nuclear decommissioning AROs totaled $1.7 billion.$1.9 billion and $2.0 billion, respectively. The following discusses critical assumptions inherent in determining the fair value of AROs associated with Dominion Energy’s nuclear decommissioning obligations.
Dominion Energy obtains from third-party specialists periodic site-specific base year cost studies in order to estimate the nature, cost and timing of planned decommissioning activities for its nuclear plants. These cost studies are based on relevant information available at the time they are performed; however, estimates of future cash flows for extended periods of time are by nature highly uncertain and may vary significantly from actual results. These cash flows include estimates on timing of decommissioning, which for regulated nuclear units factors in the probability of NRC approval for license extensions. In addition, Dominion Energy’s cost estimates include cost escalation rates that are applied to the base year costs. Dominion Energy determines cost escalation rates, which represent projected cost increases over time due to both general inflation and increases in the cost of specific decommissioning activities, for each nuclear facility. The selection of these cost escalation rates is dependent on subjective factors which are considered to be critical assumptions.
Income Taxes
Judgment and the use of estimates are required in developing the provision for income taxes and reporting ofincluding the provisions of the 2017 Tax Reform Act,and associated regulations involves uncertainty since tax authorities may interpret the laws differently. In addition, the states in which the Companies operate may or may not conform to some or all the provisions in the 2017 Tax Reform Act. Ultimate resolution or clarification of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to
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-
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 is2019,2022 and 2021, Dominion Energy had established $161$138 million and $140 million, respectively, of valuation allowances.
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Accounting for Derivative Contracts and Financial Instruments at Fair Value
Dominion Energy uses derivative contracts such as physical and financial forwards, futures, swaps, options and FTRs to manage commodity, interest rate andand/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
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 wouldIn addition, in the fourth quarter of 2019, Dominion Energy performed impairment tests immediately beforeThe 2022, 2021 and after the realignment of its operating segments. The 2019, 2018 and 20172020 annual tests and any interim teststest 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
See Note 11 to the Consolidated Financial Statements for additional information.
Use of Estimates in Long-livedLong-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
61
fluctuations of prices of commodities sold and consumed and expected proceeds from dispositions. In 2022, Dominion Energy determined that its nonregulated solar generation assets within Contracted Assets were impaired. The estimates of future cash flows and selection of a discount rate are considered to be critical assumptions. A 10% decrease in projected future pre-tax cash flows would have resulted in a $69 million increase to the impairment charge recorded. A 0.25% increase in the discount rate would have resulted in a $13 million increase to the impairment charge recorded. See Notes 6 and 9Note 10 to the Consolidated Financial Statements for a discussion of impairmentsfurther information concerning the impairment related to certain of Dominion Energy’s nonregulated solar generation assets. There were no other tests performed in 2022 of long-lived assets andor equity method investments.
Held for construction along with construction delays due to judicial actions have impacted the estimated cost and schedule for the Atlantic
Dominion Energy evaluatedrecognizes the carrying amountassets 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 equity method investmentcarrying value or fair value less any costs to sell. Any loss resulting from this measurement is recognized in Atlantic Coast Pipelinethe period in which the held for an other-than-temporary impairmentsale 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 determined thatassesses the fair value of the disposal group less any costs to sell at each reporting period and until it was not impaired. Anyis no longer classified as held for sale.
The determination as to whether the sale of the disposal group is probable may include significant changes affectingjudgments from management related to the discounted cash flow estimates associated with the Atlantic Coast Pipeline Project,expectation of obtaining approvals from applicable regulatory agencies such as future unfavorable judicialstate utility regulatory commissions, FERC or the U.S. Federal Trade Commission. This analysis is generally based on orders issued by regulatory actions resulting in further constructioncommissions, past experience andin-servicedelays along discussions with an increase in construction costs, could result in an impairment charge.
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:
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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 developsnon-investmentrelated its critical assumptions, which are then compared to the forecasts of an independent investment advisor or an independent actuary, as applicable, to ensure reasonableness. An internal committee selects the final assumptions. Dominion Energy calculated its pension cost using an expected long-term rate of return on plan assets assumption that ranged from 7.00% to 8.65%8.35% for 20192022, 7.00% to 8.45% for 2021 and 8.75%7.00% to 8.60% for 2018 and 2017.2020. For 2020,2023, the expected long-term rate of return for the pension cost assumption ranged from 7.00% to 8.60%8.35% for Dominion Energy’s plans held as of December 31, 2019.2022. 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 2019, 2018 and 2017.2020. For 2020,2023, the expected long-term rate of return for other postretirement benefit cost assumption is 8.50%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 3.57%3.06% to 4.43%3.19% for pension plans and 4.05%3.04% to 4.41%5.03% for other postretirement benefit plans in 2019,2022, ranged from 3.80%2.73% to 3.81%3.29% for pension plans and 3.76%2.69% to 2.80% for other postretirement benefit plans in 20182021 and ranged from 3.31%2.77% to 4.50%3.63% for pension plans and 3.92%3.07% to 4.47%3.52% for other postretirement benefit plans in 2017.2020. Dominion Energy selected a discount rate ranging from 3.47%5.65% to 3.63%5.75% for pension plans and 3.44%5.69% to 3.52%5.70% for other postretirement benefit plans for determining its December 31, 20192022 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, 2019 ranged from 6.50% to 6.60%2022 was 6.25% and is expected to gradually decrease to 5.00% by 20252026-2027 and continue at that rate for years thereafter.
The following table illustrates the effect on cost of changing the critical actuarial assumptions previously discussed for Dominion Energy’s plans held as of December 31, 2019,above, while holding all other assumptions constant:
Increase in 2020 Net Periodic Cost | ||||||||||||
Change in Actuarial Assumptions | Pension Benefits | Other Postretirement Benefits | ||||||||||
(millions, except percentages) | ||||||||||||
Discount Rate | (0.25 | )% | 19 | 2 | ||||||||
Long-Term rate of return on plan assets | (0.25 | )% | 23 | 5 | ||||||||
Health care cost trend rate | 1 | % | N/A | 20 | ||||||||
|
|
| Increase in 2022 Net Periodic Cost |
| |||||
| Change in Actuarial Assumptions |
| Pension Benefits |
|
| Other Postretirement Benefits |
| ||
(millions, except percentages) |
|
|
|
|
|
|
| ||
Discount rate | (0.25)% |
| $ | 17 |
|
| $ | — |
|
Long-term rate of return on plan assets | (0.25)% |
|
| 27 |
|
|
| 6 |
|
Health care cost trend rate | 1% |
| N/A |
|
|
| 9 |
| |
In addition to the effects on cost, at December 31, 2019, a 0.25% decrease in the discount rate would increase Dominion Energy’s projected pension benefit obligation at December 31, 2022 by $371$215 million and its accumulated postretirement benefit obligation at December 31, 2022 by $52$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 $153$75 million.
See Note 22 to the Consolidated Financial Statements for additional information on Dominion Energy’s employee benefit plans.
New Accounting Standards
See Note 2 to the Consolidated Financial Statements for a discussion of new accounting standards.
63
RESULTS OF OPERATIONS
Dominion Energy
Presented below is a summary of Dominion Energy’s consolidated results:
Year Ended December 31, | 2019 | $ Change | 2018 | $ Change | 2017 | |||||||||||||||
(millions, except EPS) | ||||||||||||||||||||
Net Income attributable to Dominion Energy | $ | 1,358 | $(1,089) | $ | 2,447 | $(552) | $ | 2,999 | ||||||||||||
Diluted EPS | 1.62 | (2.12 | ) | 3.74 | (0.98 | ) | 4.72 | |||||||||||||
Year Ended December 31, |
| 2022 |
|
| $ Change |
|
| 2021 |
|
| $ Change |
|
| 2020 |
| |||||
(millions, except EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Net income (loss) attributable to Dominion Energy |
| $ | 994 |
|
| $ | (2,294 | ) |
| $ | 3,288 |
|
| $ | 3,689 |
|
| $ | (401 | ) |
Diluted EPS |
|
| 1.09 |
|
|
| (2.89 | ) |
|
| 3.98 |
|
|
| 4.55 |
|
|
| (0.57 | ) |
Overview
2022 VS. 2021
Net Incomeincome attributable to Dominion Energy decreased 45%70%, primarily due to charges for refunds of amounts previously collected from retail electric customers of DESC fora charge associated with the NND Project, litigation acquired in the SCANA Combination, a voluntary retirement program, the planned early retirementimpairment of certain Virginia Power electricnonregulated solar generation facilities, anda loss associated with the absencesale of gains on the sales of certain equity method investments. These decreases were partially offset by an increaseKewaunee, a decrease in net investment earnings on nuclear decommissioning trust funds, and the operations acquired in the SCANA Combination.
Analysis of Consolidated Operations
Presented below are selected amounts related to Dominion Energy’s results of operations:
Year Ended December 31, | 2019 | $ Change | 2018 | $ Change | 2017 | |||||||||||||||
(millions) | ||||||||||||||||||||
Operating revenue | $ | 16,572 | $3,206 | $ | 13,366 | $780 | $ | 12,586 | ||||||||||||
Electric fuel and other energy-related purchases | 2,938 | 124 | 2,814 | 513 | 2,301 | |||||||||||||||
Purchased electric capacity | 88 | (34 | ) | 122 | 116 | 6 | ||||||||||||||
Purchased gas | 1,536 | 891 | 645 | (56 | ) | 701 | ||||||||||||||
Net revenue | 12,010 | 2,225 | 9,785 | 207 | 9,578 | |||||||||||||||
Other operations and maintenance | 4,428 | 970 | 3,458 | 258 | 3,200 | |||||||||||||||
Depreciation, depletion and amortization | 2,655 | 655 | 2,000 | 95 | 1,905 | |||||||||||||||
Other taxes | 1,040 | 337 | 703 | 35 | 668 | |||||||||||||||
Impairment of assets and related charges | 1,535 | 1,132 | 403 | 388 | 15 | |||||||||||||||
Gains on sales of assets | (162 | ) | 218 | (380 | ) | (233 | ) | (147 | ) | |||||||||||
Other income | 986 | (35 | ) | 1,021 | 663 | 358 | ||||||||||||||
Interest and related charges | 1,773 | 280 | 1,493 | 288 | 1,205 | |||||||||||||||
Income tax expense (benefit) | 351 | (229 | ) | 580 | 610 | (30 | ) | |||||||||||||
Noncontrolling interests | 18 | (84 | ) | 102 | (19 | ) | 121 | |||||||||||||
Year Ended December 31, |
| 2022 |
|
| $ Change |
|
| 2021 |
|
| $ Change |
|
| 2020 |
| |||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Operating revenue |
| $ | 17,174 |
|
| $ | 3,210 |
|
| $ | 13,964 |
|
| $ | (208 | ) |
| $ | 14,172 |
|
Electric fuel and other energy-related purchases |
|
| 3,711 |
|
|
| 1,343 |
|
|
| 2,368 |
|
|
| 125 |
|
|
| 2,243 |
|
Purchased electric capacity |
|
| 59 |
|
|
| (11 | ) |
|
| 70 |
|
|
| 17 |
|
|
| 53 |
|
Purchased gas |
|
| 1,582 |
|
|
| 499 |
|
|
| 1,083 |
|
|
| 194 |
|
|
| 889 |
|
Other operations and maintenance |
|
| 3,984 |
|
|
| 250 |
|
|
| 3,734 |
|
|
| 49 |
|
|
| 3,685 |
|
Depreciation, depletion and amortization |
|
| 2,830 |
|
|
| 352 |
|
|
| 2,478 |
|
|
| 146 |
|
|
| 2,332 |
|
Other taxes |
|
| 923 |
|
|
| 14 |
|
|
| 909 |
|
|
| 38 |
|
|
| 871 |
|
Impairment of assets and other charges |
|
| 2,063 |
|
|
| 1,868 |
|
|
| 195 |
|
|
| (1,910 | ) |
|
| 2,105 |
|
Losses (gains) on sales of assets |
|
| 426 |
|
|
| 318 |
|
|
| 108 |
|
|
| 169 |
|
|
| (61 | ) |
Earnings from equity method investees |
|
| 299 |
|
|
| 23 |
|
|
| 276 |
|
|
| 236 |
|
|
| 40 |
|
Other income |
|
| 124 |
|
|
| (1,033 | ) |
|
| 1,157 |
|
|
| 464 |
|
|
| 693 |
|
Interest and related charges |
|
| 966 |
|
|
| (388 | ) |
|
| 1,354 |
|
|
| (23 | ) |
|
| 1,377 |
|
Income tax expense |
|
| 68 |
|
|
| (357 | ) |
|
| 425 |
|
|
| 342 |
|
|
| 83 |
|
Net income (loss) from discontinued operations including |
|
| 9 |
|
|
| (632 | ) |
|
| 641 |
|
|
| 2,519 |
|
|
| (1,878 | ) |
Noncontrolling interests |
|
| — |
|
|
| (26 | ) |
|
| 26 |
|
|
| 175 |
|
|
| (149 | ) |
An analysis of Dominion Energy’s results of operations follows:
2022 VS. 2021
Operating revenue
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These increases were partially offset by:
Electric fuel and other energy-related purchases increased 57%, primarily due to higher commodity costs for electric utilities ($1.2 billion) and an increase in the use of purchased renewable energy credits at Virginia Power ($58 million), which are offset in operating revenue and do not impact net income.
Purchased gas increased 46%, primarily due to an increase in commodity costs for gas utilities ($586 million), which are offset in operating revenue and do not impact net income, partially offset by cost saving incentives earned under the Wexpro Agreements ($27 million).
Other operations and maintenance increased 7%, primarily reflecting:
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 regulatory asset established in the settlement of the 2021 Triennial Review ($183 million), and an increase in RGGI-related amortization ($128 million), which except for the suspended period of Rider RGGI is offset in operating revenue and does not impact net income, partially offset by depreciation rates revised in the first quarter of 2022 at Virginia Power ($82 million) and a decrease from the sale of non-wholly-owned nonregulated solar facilities ($45 million).
Impairment of assets and other charges increased $1.9 billion, primarily reflecting:
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) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
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 2017 ($112 million) and the annual PJM capacity performance market effective June 2018 ($39 million), partially offset by a benefit related tonon-utilitygenerators ($57 million);
Other operations and maintenance
Depreciation and amortization increased 27%, primarily due to an increase for amortization of a regulatory asset established in the regulated electric service territory;
Impairment of assets and other charges (benefits) increased $826 million, primarily reflecting:
Other income decreased $146 million, decrease from a reductionprimarily due to net investment losses in planned outage days at certain merchant2022 compared to net investment gains in 2021 on nuclear decommissioning trust funds.
Interest and utility generation facilities.
Income tax expense decreased 52%, primarily due to the absence of capitalization of interest expense associated with the Liquefaction Facility upon completion of constructionlower pre-tax income ($111 million), higher long-term debt interest expense resulting from net debt issuances in 2018 and 2017 ($92182 million) and charges associated with the early redemption of certain debt securities ($69 million).
68
privatization operations in Virginia to Dominion Privatization ($41434 million).
SEGMENT RESULTS OF OPERATIONS
Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit or loss. In December 2019, Dominion Energy realigned its segments which resulted in the formation of five primary operating segments. 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, | 2019 | 2018 | 2017 | |||||||||||||||||||||
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 | $ 1,786 | $2.21 | $1,596 | $2.44 | $1,466 | $2.30 | ||||||||||||||||||
Gas Transmission & Storage | 934 | 1.16 | 844 | 1.29 | 552 | 0.87 | ||||||||||||||||||
Gas Distribution | 488 | 0.60 | 373 | 0.57 | 351 | 0.55 | ||||||||||||||||||
Dominion Energy South Carolina | 430 | 0.53 | — | — | — | — | ||||||||||||||||||
Contracted Generation | 276 | 0.34 | 245 | 0.37 | 253 | 0.40 | ||||||||||||||||||
Corporate and Other | (2,556 | ) | (3.22 | ) | (611 | ) | (0.93 | ) | 377 | 0.60 | ||||||||||||||
Consolidated | $ 1,358 | $ 1.62 | $ 2,447 | $3.74 | $2,999 | $4.72 | ||||||||||||||||||
Dominion Energy Virginia
Presented below are operating statistics related to Dominion Energy Virginia’s operations:
Year Ended December 31, | 2019 | % Change | 2018 | % Change | 2017 | |||||||||||||||
Electricity delivered (million MWh) | 87.7 | — | % | 87.8 | 5 | % | 83.4 | |||||||||||||
Electricity supplied (million MWh): | ||||||||||||||||||||
Utility | 88.2 | — | 88.0 | 4 | 85.0 | |||||||||||||||
Degree days (electric distribution and utility service area): | ||||||||||||||||||||
Cooling | 2,031 | 1 | 2,019 | 12 | 1,801 | |||||||||||||||
Heating | 3,259 | (10 | ) | 3,608 | 16 | 3,104 | ||||||||||||||
Average electric distribution customer accounts (thousands) | 2,626 | 1 | 2,600 | 1 | 2,574 | |||||||||||||||
Year Ended December 31, |
| 2022 |
|
| % Change |
|
| 2021 |
|
| % Change |
|
| 2020 |
| |||||
Electricity delivered (million MWh) |
|
| 90.0 |
|
|
| 6 |
| % |
| 85.2 |
|
|
| 2 |
| % |
| 83.3 |
|
Electricity supplied (million MWh): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Utility |
|
| 90.2 |
|
|
| 5 |
|
|
| 85.7 |
|
|
| (1 | ) |
|
| 87.0 |
|
Non-Jurisdictional |
|
| 1.5 |
|
|
| 50 |
|
|
| 1.0 |
|
|
| 43 |
|
|
| 0.7 |
|
Degree days (electric distribution and utility service area): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Cooling |
|
| 1,765 |
|
|
| (1 | ) |
|
| 1,783 |
|
|
| 1 |
|
|
| 1,759 |
|
Heating |
|
| 3,555 |
|
|
| 11 |
|
|
| 3,210 |
|
|
| 8 |
|
|
| 2,970 |
|
Average electric distribution customer accounts |
|
| 2,724 |
|
|
| 1 |
|
|
| 2,697 |
|
|
| 1 |
|
|
| 2,661 |
|
69
Presented below, on an
2022 VS. 2018
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Regulated electric sales: | ||||||||
Weather | $ (14 | ) | $ | (0.02 | ) | |||
Other | 9 | 0.01 | ||||||
Rate adjustment clause equity return | 84 | 0.13 | ||||||
Electric capacity | 54 | 0.08 | ||||||
Expiration of energy supply contract | 30 | 0.05 | ||||||
Renewable energy investment tax credits | (14 | ) | (0.02 | ) | ||||
Other | 41 | 0.06 | ||||||
Share dilution | — | (0.52 | ) | |||||
Change in net income contribution | $190 | $ | (0.23 | ) | ||||
|
| Increase (Decrease) |
| |||||
|
| Amount |
|
| EPS |
| ||
(millions, except EPS) |
|
|
|
|
|
| ||
Weather |
| $ | 21 |
|
| $ | 0.03 |
|
Customer usage and other factors |
|
| 25 |
|
|
| 0.03 |
|
Customer-elected rate impacts |
|
| 13 |
|
|
| 0.02 |
|
Base rate case impacts |
|
| (41 | ) |
|
| (0.05 | ) |
Rider equity return |
|
| 64 |
|
|
| 0.08 |
|
Storm damage and service restoration |
|
| (17 | ) |
|
| (0.02 | ) |
Planned outage costs |
|
| (12 | ) |
|
| (0.01 | ) |
Depreciation and amortization |
|
| 19 |
|
|
| 0.02 |
|
Renewable energy investment tax credits |
|
| 65 |
|
|
| 0.08 |
|
Salaries, wages and benefits & administrative costs |
|
| 26 |
|
|
| 0.03 |
|
Interest expense, net |
|
| (13 | ) |
|
| (0.02 | ) |
Other |
|
| (61 | ) |
|
| (0.07 | ) |
Share dilution |
|
| — |
|
|
| (0.05 | ) |
Change in net income contribution |
| $ | 89 |
|
| $ | 0.07 |
|
2021 VS. 2017
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Regulated electric sales: | ||||||||
Weather | $ 86 | $ | 0.14 | |||||
Other | 43 | 0.07 | ||||||
Rate adjustment clause equity return | 14 | 0.02 | ||||||
Depreciation and amortization | 31 | 0.05 | ||||||
Storm damage and service restoration | (19 | ) | (0.03 | ) | ||||
Planned outage costs | 12 | 0.02 | ||||||
Electric capacity | (66 | ) | (0.10 | ) | ||||
Renewable energy investment tax credits | 34 | 0.05 | ||||||
Other | (5 | ) | (0.01 | ) | ||||
Share dilution | — | (0.07 | ) | |||||
Change in net income contribution | $130 | $ | 0.14 | |||||
Year Ended December 31, | 2019 (1) | % Change | 2018 | % Change | 2017 | |||||||||||||||
Average retail energy marketing customer accounts (thousands) | 762 | 2 | % | 750 | (47 | )% | 1,405 | |||||||||||||
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Cove Point export contracts | $172 | $ 0.26 | ||||||
Assignment of shale development rights | (83 | ) | (0.12 | ) | ||||
Interest expense, net | (60 | ) | (0.09 | ) | ||||
State legislative change | (18 | ) | (0.03 | ) | ||||
Noncontrolling interest | 62 | 0.09 | ||||||
Atlantic Coast Pipeline equity earnings | 37 | 0.06 | ||||||
Other | (20 | ) | (0.03 | ) | ||||
Share dilution | — | (0.27 | ) | |||||
Change in net income contribution | $ 90 | $ (0.13 | ) | |||||
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Transmission and storage growth projects | $ 30 | $ | 0.05 | |||||
Cove Point export contracts | 259 | 0.41 | ||||||
Cove Point import contracts | (12 | ) | (0.02 | ) | ||||
DETI contract declines | (20 | ) | (0.03 | ) | ||||
Assignment of shale development rights | 27 | 0.04 | ||||||
2017 Tax Reform Act impacts | 113 | 0.18 | ||||||
Interest expense, net | (81 | ) | (0.13 | ) | ||||
State legislative change | 18 | 0.03 | ||||||
Other | (42 | ) | (0.07 | ) | ||||
Share dilution | — | (0.04 | ) | |||||
Change in net income contribution | $ 292 | $ 0.42 | ||||||
|
| Increase (Decrease) |
| |||||
|
| Amount |
|
| EPS |
| ||
(millions, except EPS) |
|
|
|
|
|
| ||
Weather |
| $ | 44 |
|
| $ | 0.05 |
|
Customer usage and other factors |
|
| (26 | ) |
|
| (0.03 | ) |
Customer-elected rate impacts |
|
| 46 |
|
|
| 0.06 |
|
Rider equity return |
|
| 41 |
|
|
| 0.05 |
|
Electric capacity |
|
| (28 | ) |
|
| (0.03 | ) |
Outages |
|
| (14 | ) |
|
| (0.02 | ) |
Depreciation and amortization |
|
| (18 | ) |
|
| (0.02 | ) |
Renewable energy investment tax credits |
|
| 7 |
|
|
| 0.01 |
|
Salaries, wages and benefits & administrative costs |
|
| (22 | ) |
|
| (0.03 | ) |
Other |
|
| (2 | ) |
|
| (0.01 | ) |
Share accretion |
|
| — |
|
|
| 0.06 |
|
Change in net income contribution |
| $ | 28 |
|
| $ | 0.09 |
|
Gas Distribution
Presented below are selected operating statistics related to Gas Distribution’s operations:
Year Ended December 31, |
| 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, | 2019 (1) | % Change | 2018 | % Change | 2017 | |||||||||||||||
Gas distribution throughput (bcf): | ||||||||||||||||||||
Sales | 192 | 47 | % | 131 | 1 | % | 130 | |||||||||||||
Transportation | 811 | 12 | 725 | 11 | 654 | |||||||||||||||
Heating degree days (gas distribution service area): | ||||||||||||||||||||
North Carolina | 2,942 | |||||||||||||||||||
Ohio and West Virginia | 5,355 | (6 | ) | 5,693 | 15 | 4,930 | ||||||||||||||
Utah, Wyoming and Idaho | 5,501 | 18 | 4,672 | (4 | ) | 4,892 | ||||||||||||||
Average gas distribution customer accounts (thousands): | ||||||||||||||||||||
Sales | 1,857 | 48 | 1,258 | 1 | 1,240 | |||||||||||||||
Transportation | 1,108 | 1 | 1,096 | 1 | 1,086 | |||||||||||||||
70
Presented below, on an
2022 VS. 2018
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Regulated gas sales: | ||||||||
Weather | $ | (3 | ) | $ | — | |||
Other | (2 | ) | — | |||||
Rate adjustment clause equity return | 16 | 0.02 | ||||||
SCANA Combination | 87 | 0.13 | ||||||
Other | 17 | 0.02 | ||||||
Share dilution | — | (0.14 | ) | |||||
Change in net income contribution | $115 | $0.03 | ||||||
|
| Increase (Decrease) |
| |||||
|
| Amount |
|
| EPS |
| ||
(millions, except EPS) |
|
|
|
|
|
| ||
Weather |
| $ | 4 |
|
| $ | — |
|
Customer usage and other factors |
|
| 36 |
|
|
| 0.04 |
|
Base rate case impacts |
|
| 29 |
|
|
| 0.04 |
|
Rider equity return |
|
| 25 |
|
|
| 0.03 |
|
Wexpro cost saving sharing incentives |
|
| 21 |
|
|
| 0.03 |
|
Sale of Hope |
|
| (11 | ) |
|
| (0.01 | ) |
Interest expense, net |
|
| (16 | ) |
|
| (0.02 | ) |
Other |
|
| 9 |
|
|
| 0.01 |
|
Share dilution |
|
| — |
|
|
| (0.01 | ) |
Change in net income contribution |
| $ | 97 |
|
| $ | 0.11 |
|
2021 VS. 2017
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Regulated gas sales: | ||||||||
Weather | $ | 7 | $ | 0.01 | ||||
Other | 2 | — | ||||||
Rate adjustment clause equity return | 9 | 0.01 | ||||||
2017 Tax Reform Act impacts | 28 | 0.04 | ||||||
Interest expense | (4 | ) | — | |||||
Other | (20 | ) | (0.02 | ) | ||||
Share dilution | — | (0.02 | ) | |||||
Change in net income contribution | $22 | $0.02 | ||||||
|
| Increase (Decrease) |
| |||||
|
| Amount |
|
| EPS |
| ||
(millions, except EPS) |
|
|
|
|
|
| ||
Weather |
| $ | — |
|
| $ | — |
|
Customer usage and other factors |
|
| 24 |
|
|
| 0.03 |
|
Base rate case impacts |
|
| 7 |
|
|
| 0.01 |
|
Rider equity return |
|
| 40 |
|
|
| 0.05 |
|
Salaries, wages and benefits & administrative costs |
|
| (8 | ) |
|
| (0.01 | ) |
Interest expense, net |
|
| 12 |
|
|
| 0.01 |
|
Other |
|
| (35 | ) |
|
| (0.04 | ) |
Share accretion |
|
| — |
|
|
| 0.02 |
|
Change in net income contribution |
| $ | 40 |
|
| $ | 0.07 |
|
Dominion Energy South Carolina
Presented below are selected operating statistics related to Dominion Energy South Carolina’s operations:
Year Ended December 31, |
| 2022 |
|
| % Change |
|
| 2021 |
|
| % Change |
|
| 2020 |
| |||||
Electricity delivered (million MWh) |
|
| 23.0 |
|
|
| 3 |
| % |
| 22.4 |
|
|
| 1 |
| % |
| 22.1 |
|
Electricity supplied (million MWh) |
|
| 24.1 |
|
|
| 3 |
|
|
| 23.5 |
|
|
| 2 |
|
|
| 23.0 |
|
Degree days (electric and gas distribution service areas): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Cooling |
|
| 767 |
|
|
| (11 | ) |
|
| 859 |
|
|
| 8 |
|
|
| 794 |
|
Heating |
|
| 1,294 |
|
|
| 1 |
|
|
| 1,280 |
|
|
| 19 |
|
|
| 1,074 |
|
Average electric distribution customer accounts |
|
| 777 |
|
|
| 1 |
|
|
| 766 |
|
|
| 2 |
|
|
| 753 |
|
Gas distribution throughput (bcf): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Sales |
|
| 68 |
|
|
| (6 | ) |
|
| 72 |
|
|
| 9 |
|
|
| 66 |
|
Average gas distribution customer accounts |
|
| 427 |
|
|
| 4 |
|
|
| 412 |
|
|
| 3 |
|
|
| 399 |
|
71
Presented below, on an
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
SCANA Combination | $430 | $0.53 | ||||||
2022 VS. 2021
|
| Increase (Decrease) |
| |||||
|
| Amount |
|
| EPS |
| ||
(millions, except EPS) |
|
|
|
|
|
| ||
Weather |
| $ | 21 |
|
| $ | 0.03 |
|
Customer usage and other factors |
|
| 38 |
|
|
| 0.05 |
|
Customer-elected rate impacts |
|
| 14 |
|
|
| 0.02 |
|
Base rate case & Natural Gas Rate Stabilization Act impacts |
|
| 22 |
|
|
| 0.03 |
|
Capital cost rider |
|
| (8 | ) |
|
| (0.01 | ) |
Gains on sales of property |
|
| 17 |
|
|
| 0.02 |
|
Depreciation and amortization |
|
| (15 | ) |
|
| (0.02 | ) |
Interest expense, net |
|
| (16 | ) |
|
| (0.02 | ) |
Other |
|
| (5 | ) |
|
| (0.02 | ) |
Share dilution |
|
| — |
|
|
| (0.01 | ) |
Change in net income contribution |
| $ | 68 |
|
| $ | 0.07 |
|
2021 VS. 2020
|
| Increase (Decrease) |
| |||||
|
| Amount |
|
| EPS |
| ||
(millions, except EPS) |
|
|
|
|
|
| ||
Weather |
| $ | (6 | ) |
| $ | (0.01 | ) |
Customer usage and other factors |
|
| 34 |
|
|
| 0.04 |
|
Customer-elected rate impacts |
|
| 10 |
|
|
| 0.01 |
|
Base rate case & Natural Gas Rate Stabilization Act impacts |
|
| 13 |
|
|
| 0.02 |
|
Capital cost rider |
|
| (6 | ) |
|
| (0.01 | ) |
Depreciation and amortization |
|
| (9 | ) |
|
| (0.01 | ) |
Interest expense, net |
|
| 7 |
|
|
| 0.01 |
|
Salaries, wages and benefits & administrative costs |
|
| (46 | ) |
|
| (0.06 | ) |
Other |
|
| 21 |
|
|
| 0.02 |
|
Share accretion |
|
| — |
|
|
| 0.02 |
|
Change in net income contribution |
| $ | 18 |
|
| $ | 0.03 |
|
Contracted Generation
Presented below are selected operating statistics related to Contracted Generation’sAsset’s operations:
Year Ended December 31, | 2019 | % Change | 2018 | % Change | 2017 | |||||||||||||||
Electricity supplied (million MWh) | 20.2 | (30 | )% | 28.8 | — | % | 28.9 | |||||||||||||
Year Ended December 31, |
| 2022 |
|
| % Change |
|
| 2021 |
|
| % Change |
|
| 2020 |
| |||||
Electricity supplied (million MWh) |
|
| 17.8 |
|
|
| (14 | ) | % |
| 20.8 |
|
|
| 8 |
| % |
| 19.3 |
|
Presented below, on anGeneration’sAsset’s net income contribution:
2022 VS. 20182021
|
| 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 | $ 42 | $ | 0.06 | |||||
Renewable energy investment tax credits | 50 | 0.08 | ||||||
Sale of certain electric generation facilities | (95 | ) | (0.14 | ) | ||||
Interest expense | 26 | 0.04 | ||||||
Other | 8 | 0.01 | ||||||
Share dilution | — | (0.08 | ) | |||||
Change in net income contribution | $ 31 | $ | (0.03 | ) | ||||
72
2021 VS. 20172020
|
| 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 |
|
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Margin | $101 | $ 0.16 | ||||||
Planned outage costs | 34 | 0.05 | ||||||
Depreciation and amortization | (9 | ) | (0.01 | ) | ||||
Renewable energy investment tax credits | (172 | ) | (0.28 | ) | ||||
2017 Tax Reform Act impacts | 45 | 0.07 | ||||||
Other | (7 | ) | (0.01 | ) | ||||
Share dilution | — | (0.01 | ) | |||||
Change in net income contribution | $ (8 | ) | $(0.03 | ) | ||||
Corporate and Other
Presented below are the Corporate and Other segment’s
Year Ended December 31, | 2019 | 2018 | 2017 | |||||||||
(millions, except EPS) | ||||||||||||
Specific items attributable to operating segments | $ | (2,039 | ) | $ | (88 | ) | $ | 861 | ||||
Specific items attributable to Corporate and Other segment | (50 | ) | (116 | ) | (151 | ) | ||||||
Total specific items | (2,089 | ) | (204 | ) | 710 | |||||||
Other corporate operations: | ||||||||||||
2017 Tax Reform Act impacts | — | (81 | ) | — | ||||||||
Interest expense, net | (430 | ) | (358 | ) | (334 | ) | ||||||
Other | (37 | ) | 32 | 1 | ||||||||
Total other corporate operations | (467 | ) | (407 | ) | (333 | ) | ||||||
Total net income (expense) | (2,556 | ) | (611 | ) | 377 | |||||||
EPS impact | $ | (3.22 | ) | $ | (0.93 | ) | $ | 0.60 | ||||
Year Ended December 31, |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
(millions, except EPS) |
|
|
|
|
|
|
|
|
| |||
Specific items attributable to operating segments |
| $ | (2,777 | ) |
| $ | (493 | ) |
| $ | (1,241 | ) |
Specific items attributable to Corporate and Other segment |
|
| 266 |
|
|
| 590 |
|
|
| (2,166 | ) |
Total specific items |
|
| (2,511 | ) |
|
| 97 |
|
|
| (3,407 | ) |
Other corporate operations: |
|
|
|
|
|
|
|
|
| |||
Interest expense, net |
|
| (329 | ) |
|
| (410 | ) |
|
| (384 | ) |
Other |
|
| 289 |
|
|
| 214 |
|
|
| 118 |
|
Total other corporate operations |
|
| (40 | ) |
|
| (196 | ) |
|
| (266 | ) |
Total net expense |
|
| (2,551 | ) |
|
| (99 | ) |
|
| (3,673 | ) |
EPS impact |
| $ | (3.22 | ) |
| $ | (0.20 | ) |
| $ | (4.51 | ) |
Corporate and Other includes specific items attributable to Dominion Energy’s primary operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources. See Note 26 to the Consolidated Financial Statements for discussion of these items in more detail. Corporate and Other also includes specific items attributable to the Corporate and Other segment. In 2019,2022, this primarily included $40a $255 million after-tax benefit for derivative mark-to-market changes. In 2021, this primarily included $641 million oftransaction 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 transition$32 million of after-tax charges for merger and integration-related costs associated with the SCANA Combination. In 2018,2020, this primarily included $51 million$2.2 billion ofearly redemptioncancellation of certain debt securitiesthe Atlantic Coast Pipeline Project, $82 million of after-tax charges for merger and $31 million ofafter-taxtransaction and transitionintegration-related costs associated with the Dominion Energy QuestarSCANA Combination, a $78 million after-tax benefit of derivative mark-to-market changes and SCANA Combination. In 2017, this primarily included $124a $69 million of tax benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate.
Year Ended December 31, | 2019 | $ Change | 2018 | $ Change | 2017 | |||||||||||||||
(millions) | ||||||||||||||||||||
Net Income | $ | 1,149 | $(133 | ) | $ | 1,282 | $(258 | ) | $ | 1,540 | ||||||||||
OUTLOOK
Dominion Energy’s 2023 net income is expected to increase on a voluntary retirement program and a contract termination with anon-utilitygenerator. These decreases were partially offset by increases relatedper share basis as compared to higher rate adjustment clause 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.
Year Ended December 31, | 2019 | $ Change | 2018 | $ Change | 2017 | |||||||||||||||
(millions) | ||||||||||||||||||||
Operating revenue | $ | 8,108 | $ 489 | $ | 7,619 | $ 63 | $ | 7,556 | ||||||||||||
Electric fuel and other energy-related purchases | 2,178 | (140 | ) | 2,318 | 409 | 1,909 | ||||||||||||||
Purchased electric capacity | 40 | (82 | ) | 122 | 116 | 6 | ||||||||||||||
Net revenue | 5,890 | 711 | 5,179 | (462 | ) | 5,641 | ||||||||||||||
Other operations and maintenance | 1,743 | 67 | 1,676 | 198 | 1,478 | |||||||||||||||
Depreciation and amortization | 1,223 | 91 | 1,132 | (9 | ) | 1,141 | ||||||||||||||
Other taxes | 328 | 28 | 300 | 10 | 290 | |||||||||||||||
Impairment of assets and other charges | 757 | 757 | — | — | — | |||||||||||||||
Other income | 98 | 76 | 22 | (54 | ) | 76 | ||||||||||||||
Interest and related charges | 524 | 13 | 511 | 17 | 494 | |||||||||||||||
Income tax expense | 264 | (36 | ) | 300 | (474 | ) | 774 | |||||||||||||
These increases are expected to lowerpre-taxincome ($256 million), the reduced corporate income tax rate ($235 million) and higher renewable energy investment tax credits ($35 million),be partially offset by the absence of benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate ($93 million).
Year Ended December 31, | 2019 | $ Change | 2018 | $ Change | 2017 | |||||||||||||||
(millions) | ||||||||||||||||||||
Net income attributable to Dominion Energy Gas | $721 | $240 | $481 | $(222) | $703 | |||||||||||||||
Year Ended December 31, | 2019 | $ Change | 2018 | $ Change | 2017 | |||||||||||||||
(millions) | ||||||||||||||||||||
Operating revenue | $ | 2,169 | $ 173 | $ | 1,996 | $ 473 | $ | 1,523 | ||||||||||||
Purchased (excess) gas | 7 | 17 | (10 | ) | (119 | ) | 109 | |||||||||||||
Other energy-related purchases | 2 | (2 | ) | 4 | — | 4 | ||||||||||||||
Net revenue | 2,160 | 158 | 2,002 | 592 | 1,410 | |||||||||||||||
Other operations and maintenance | 724 | 8 | 716 | 144 | 572 | |||||||||||||||
Depreciation and amortization | 367 | 34 | 333 | 91 | 242 | |||||||||||||||
Other taxes | 154 | 34 | 120 | 21 | 99 | |||||||||||||||
Impairment of assets and related charges | 13 | (150 | ) | 163 | 148 | 15 | ||||||||||||||
Gains on sales of assets | (2 | ) | 115 | (117 | ) | (47 | ) | (70 | ) | |||||||||||
Earnings from equity method investees | 43 | (11 | ) | 54 | 7 | 47 | ||||||||||||||
Other income | 166 | 77 | 89 | 27 | 62 | |||||||||||||||
Interest and related charges | 311 | 137 | 174 | 114 | 60 | |||||||||||||||
Income tax expense (benefit) | 101 | (23 | ) | 124 | 189 | (65 | ) | |||||||||||||
Net Income from discontinued operations | 141 | 117 | 24 | (139 | ) | 163 | ||||||||||||||
Noncontrolling interests | 121 | (54 | ) | 175 | 49 | 126 | ||||||||||||||
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.
Year Ended December 31, | 2019 | 2018 | 2017 | |||||||||
(millions) | ||||||||||||
Cash, restricted cash and equivalents at beginning of year | $ | 391 | $ | 185 | $ | 322 | ||||||
Cash flows provided by (used in): | ||||||||||||
Operating activities | 5,204 | 4,773 | 4,502 | |||||||||
Investing activities | (4,622 | ) | (2,358 | ) | (5,942 | ) | ||||||
Financing activities | (704 | ) | (2,209 | ) | 1,303 | |||||||
Net increase (decrease) in cash, restricted cash and equivalents | (122 | ) | 206 | (137 | ) | |||||||
Cash, restricted cash and equivalents at end of year | $ | 269 | $ | 391 | $ | 185 | ||||||
Year Ended December 31, |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
(millions) |
|
|
|
|
|
|
|
|
| |||
Cash, restricted cash and equivalents at beginning of year |
| $ | 408 |
|
| $ | 247 |
|
| $ | 269 |
|
Cash flows provided by (used in): |
|
|
|
|
|
|
|
|
| |||
Operating activities |
|
| 3,700 |
|
|
| 4,037 |
|
|
| 5,227 |
|
Investing activities |
|
| (6,746 | ) |
|
| (6,247 | ) |
|
| (2,916 | ) |
Financing activities |
|
| 2,979 |
|
|
| 2,371 |
|
|
| (2,333 | ) |
Net increase (decrease) in cash, restricted cash and equivalents |
|
| (67 | ) |
|
| 161 |
|
|
| (22 | ) |
Cash, restricted cash and equivalents at end of year |
| $ | 341 |
|
| $ | 408 |
|
| $ | 247 |
|
Operating Cash Flows
Net cash provided by Dominion Energy’sEnergy's operating activities increased $431decreased $337 million, inclusive of a $201 million decrease from discontinued operations. Net cash provided by continuing operations decreased $136 million, primarily due to operations acquired in the SCANA Combination, the commercial operations of the Liquefaction Facility for the entire year and higherlower deferred fuel cost recoveries ($1.1 billion), current year refund payments to Virginia electric customers associated with the settlement of the 2021 Triennial Review ($319 million) and changes in the Virginia jurisdiction,working capital ($628 million), partially offset by lower margin deposits ($862 million) and an increase in property tax payments, increased interest expense,of $1.0 billion primarily as the result of higher customer rate refunds, a contract termination payment to anon-utilitygenerator, an increase in merger and integration-related costs associated with the SCANA Combination, and a net decrease in other working capital items.
Gross Credit Exposure | Credit Collateral | Net Credit Exposure | ||||||||||
(millions) | ||||||||||||
Investment grade (1) | $87 | $— | $87 | |||||||||
No external ratings: | ||||||||||||
Internally rated—investment grade (2) | 119 | — | 119 | |||||||||
Internally rated—non-investment grade(3) | 27 | — | 27 | |||||||||
Total (4) | $233 | $— | $233 | |||||||||
Investing Cash Flows
Net cash used in Dominion Energy’s investing activities increased $2.3 billion,$499 million, primarily due to a decrease in net proceeds from the sale of certain merchant generation facilities and interests in certain equity method investments and an increase in plant construction and other property additions ($1.6 billion) and the absence of proceeds from the sale of Q-Pipe Group ($1.5 billion) and the sale of non-wholly-owned nonregulated solar facilities ($495 million), partially offset by cashthe absence of the repayment of the Q-Pipe Transaction deposit ($1.3 billion), a decrease in contributions to equity method affiliates including Atlantic Coast Pipeline ($978 million) and restricted cash acquired innet proceeds from the SCANA Combination.
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 Liquidity
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 inCredit 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.
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.
As the comprehensive business review announced in November 2022 is still in progress, Dominion Energy is uncertain as to the amount of long-term debt it anticipates issuing in 2023. Dominion Energy expects to issue long-term debt to satisfy cash needs for capital expenditures and maturing long-term debt to the extent such amounts are not satisfied from cash available from operations following the payment of dividends and any borrowings made from unused capacity of Dominion Energy’s credit facilities discussed above. The raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances.
Repayments, Repurchases and Redemptions of Long-Term Debt
Dominion Energy may from time to time 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.
The following long-term debt was repaid, repurchased or redeemed in 2022:
Month |
| Type |
| Entity |
| Principal |
| (1) | Rate |
|
| Stated Maturity | ||
|
|
|
|
|
| (millions) |
|
|
|
|
|
| ||
Debt scheduled to mature in 2022 |
|
|
| $ | 806 |
|
| various |
|
|
| |||
Early repurchases & redemptions |
|
|
|
|
|
|
|
|
|
| ||||
July |
| Senior notes |
| Dominion Energy |
|
| 5 |
|
|
| 4.250 | % |
| 2028 |
Multiple |
| Senior notes |
| Dominion Energy |
|
| 147 |
|
|
| 2.250 | % |
| 2031 |
Multiple |
| Senior notes |
| Dominion Energy |
|
| 35 |
|
|
| 3.300 | % |
| 2041 |
Multiple |
| Senior notes |
| Dominion Energy |
|
| 37 |
|
|
| 1.450 | % |
| 2026 |
Multiple |
| Senior notes |
| Dominion Energy |
|
| 9 |
|
|
| 4.700 | % |
| 2044 |
Multiple |
| Senior notes |
| Dominion Energy |
|
| 30 |
|
|
| 4.600 | % |
| 2049 |
Total repayments, repurchases and redemptions |
|
|
| $ | 1,069 |
|
|
|
|
|
| |||
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.
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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 decreased $1.5 billion, primarily dueSustainability 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 proceeds fromtotal capital ratio, pursuant to the saleterms 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 25% noncontrolling limited partnership interest in Cove Pointborrower under Dominion Energy’s joint revolving credit facility, to accelerate its repayment of any outstanding borrowings and the issuancelenders 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 for these direct stock purchase plans. During 2022, Dominion Energy issued 2.4 million of such shares and received proceeds of $179 million.
Dominion Energy also maintains sales agency agreements to effect sales under an at-the-market program. Under the sales agency agreements, Dominion Energy may, from time to time, offer and sell shares of its common stock through the sales agents or enter into one or more forward sale agreements with respect to shares of its common stock. Sales by Dominion Energy through the sales agents or by forward sellers pursuant to a forward sale agreement cannot exceed $1.0 billion in the aggregate. In November 2021, Dominion Energy entered forward sale agreements for approximately 1.1 million shares of its common stock to be settled by November 2022 at an initial forward price of $74.66 per share. Except in certain circumstances, Dominion Energy could have elected physical, cash or net settlement of the forward sale agreements. In November 2022, Dominion Energy provided notice to elect physical settlement of the forward sale agreements and in December 2022 received total proceeds of $78 million.
In addition, Dominion Energy issued shares of its common and preferred stock, as discussed in Notes 19 and 20 to the Consolidated Financial Statements, respectively, as follows:
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 partially offsetfor $1.6 billion.
Capital Expenditures
See Note 26 to the Consolidated Financial Statements for Dominion Energy’s historical capital expenditures by an increase in net debt repayments in 2019 compared to 2018 and higher common stock dividend payments.
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.
Dominion Energy’s commercial paper and lettersexposure to potential concentrations of credit outstanding, as well as capacity available underrisk results primarily from its energy marketing and price risk management activities. Presented below is a summary of Dominion Energy’s credit facility, were as follows:
Facility Limit | Outstanding Commercial Paper (1) | Outstanding Letters of Credit | Facility Capacity Available | |||||||||||||
(millions) | ||||||||||||||||
At December 31, 2019 | ||||||||||||||||
Joint revolving credit facility (2) | $ | 6,000 | $836 | $89 | $ | 5,075 | ||||||||||
Type | Issuer | Principal | Rate | Maturity | ||||||||||||
(millions) | ||||||||||||||||
Senior notes | Dominion Energy | $ | 200 | 4.250 | % | 2028 | ||||||||||
Senior notes | Dominion Energy | 400 | 4.600 | % | 2049 | |||||||||||
Senior notes | Virginia Power | 500 | 2.875 | % | 2029 | |||||||||||
Senior notes | Virginia Power | 550 | 3.300 | % | 2049 | |||||||||||
Senior notes | Dominion Energy Gas | 600 | 2.500 | % | 2024 | |||||||||||
Senior notes | Dominion Energy Gas | 600 | 3.000 | % | 2029 | |||||||||||
Senior notes | Dominion Energy Gas | 300 | 3.900 | % | 2049 | |||||||||||
Total notes issued | $ | 3,150 | ||||||||||||||
|
| 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
Fuel and restrictions on disposition of all or substantially all assets;
Dominion Energy is requiredparty to pay annual commitment feesvarious contracts for fuel and purchased power commitments related to maintainboth its credit facility. In addition, Dominion Energy’s credit agreement contains various termsregulated and conditions that could affect its ability to borrow under the facility. They include a maximum debt to total capital ratio and cross-default provisions.
Company | Maximum Allowed Ratio | Actual Ratio (1) | ||||||
Dominion Energy | 67.5 | % | 50.3% | |||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
|
| 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 |
|
Other Material Cash Requirements
In addition to the Consolidated Financial Statements for a description of potential restrictions on dividend payments by Dominion Energy, including in connection with the deferral of contract adjustment payments associated with the 2019 Equity Units, which information is incorporated herein by reference, as well as the failure to declare and pay dividends on Series A Preferred Stock or Series B Preferred Stock.
2020 | 2021- 2022 | 2023- 2024 | 2025 and thereafter | Total | ||||||||||||||||
(millions) | ||||||||||||||||||||
Long-term debt (1 ) | $ | 2,325 | $ | 4,284 | $ | 5,256 | $ | 25,253 | $ | 37,118 | ||||||||||
Interest payments ( 2 ) | 1,602 | 2,917 | 2,524 | 19,742 | 26,785 | |||||||||||||||
Leases | ||||||||||||||||||||
Operating Leases | 72 | 120 | 81 | 582 | 855 | |||||||||||||||
Finance Leases | 34 | 60 | 45 | 9 | 148 | |||||||||||||||
Purchase obligations ( :3 ) | ||||||||||||||||||||
Purchased electric capacity for utility operations | 59 | 116 | 114 | 664 | 953 | |||||||||||||||
Fuel commitments for utility operations | 1,061 | 932 | 318 | 946 | 3,257 | |||||||||||||||
Fuel commitments for nonregulated operations | 160 | 184 | 213 | 222 | 779 | |||||||||||||||
Pipeline transportation and storage | 591 | 961 | 640 | 2,459 | 4,651 | |||||||||||||||
Other ( 4 ) | 574 | 81 | 40 | — | 695 | |||||||||||||||
Other long-term liabilities( :5 ) | ||||||||||||||||||||
Other contractual obligations ( 6 ) | 29 | 44 | 14 | 56 | 143 | |||||||||||||||
Total cash payments | $ | 6,507 | $ | 9,699 | $ | 9,245 | $ | 49,933 | $ | 75,384 | ||||||||||
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.
Business Review
In November 2022, Dominion Energy announced the commencement of a business review of value-maximizing strategic business actions, alternatives to its current business mix and capital allocation and regulatory options which may assist customers to manage costs and provide greater predictability to its long-term, state-regulated utility value proposition. While the ultimate impacts cannot be estimated until the review is completed, which is expected in 2023, implementation of recommendations resulting from the business review could have a material impact on Dominion Energy's future results of operations, financial condition and/or cash flows.
Potential Virginia Legislation
The 2023 General Assembly session in Virginia has included several proposals which, if ultimately enacted into law, could have a material impact on Virginia Power’s retail base rates and other cost-recovery mechanisms. Items under consideration include the frequency of base rate reviews, eliminating CCROs, shifting recovery of certain costs currently recovered through riders into base
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.
Future Environmental Regulations
Climate Change
The federal government and several states in which the EPA has proposed to repeal. In June 2017, the Administration announced that the U.S. intends to file to withdraw from the Paris Agreement in 2019. Several states, including Virginia, subsequentlyDominion Energy operates have announced a commitment to achieving the carbon reduction goals ofgoals. In February 2021, the U.S. rejoined the Paris Agreement. ItAgreement, 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 not possible at this time to predict the timing and impact of this withdrawal, or how any legal requirements in the U.S.enacted at the federal or state level that is more restrictive than the VCEA and/or local levels pursuantDominion Energy’s commitment to the Paris Agreementachieving net zero emissions by 2050, compliance with such legislation could have a material impact the Companies’ customers to Dominion Energy’s financial condition and/or the business.
State Actions Related to Air and GHG Emissions
In August 2017, the Ozone Transport Commission released a draft model rule for control of NOPennsylvania, New York, Maryland, Virginia and Ohio, are developing or have announced plans to develop state-specific regulations to control GHG emissions, including methane.
Inflation Reduction Act
The IRA includes provisions which impose an annual fee for waste methane emissions from the EPA released proposed revisionsoil and natural gas industry beginning with emissions reported in calendar year 2024 to the Effluent Limitations Guidelines ruleextent that if adopted, could extendan entity’s emissions exceed a stated threshold, with implementation to be addressed by future rulemaking by the deadlines for compliance with certain standards at several facilities. WhileEPA. Pending the impactscompletion of this rule could be materialsuch rulemaking, Dominion Energy currently does not expect these provisions to Dominion Energy’smaterially affect its future 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.
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 certainoften referred to as end users, may elect thehas electedutilizes the end-user exception with respect to exempt its swaps from the CEA’s clearing requirements.swaps. If, as a result of changes to the rulemaking process, Dominion Energy’s derivative activities are not exempted fromEnergy 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 or the elimination of rulemaking that implements Title VII of the Dodd-Frank Act.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.
Federal Income Tax Laws
Inflation Reduction Act
The IRA imposes a 15% alternative minimum tax on GAAP net income, as adjusted for certain items, of corporations in excess of $1 billion, for tax years beginning after December 31, 2022. Entities that are subject to the alternative minimum tax may use tax credits to reduce the liability by up to 75% and will receive a tax credit carryforward with an indefinite life that can be claimed against the regular tax in future years. Pending additional guidance, the alternative minimum tax is not expected to have an effect on the assessment of the realizability of Dominion Energy’s deferred tax assets or a material impact on Dominion Energy’s future results of operations or cash flows.
82
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 Dominion Energy and Virginia Power’sthe Companies’ electric operations and Dominion Energy and Dominion Energy Gas’Energy’s natural gas procurement and marketing operations due to the exposure to market shifts in prices received and paid for electricity, natural gas and other commodities. The Companies use commodity derivative contracts to manage price risk exposures for these operations. Interest rate risk is generally related to their outstanding debt and future issuances of debt. In addition, the Companies are exposed to investment price risk through various portfolios of equity and debt securities.
The following sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10% change in commodity prices or interest rates.
Commodity Price Risk
To manage price risk, Dominion Energy and Virginia Powerthe Companies hold commodity-based derivative instruments held for Dominion Energy Gas’ operations are contracted primarily under long-term fixed reservation agreements. Accordingly, management believes that Dominion Energy Gas is not subject to material commodity price risk.
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 a decrease of $52 million and $16 million in the fair value of $50 million and $6 million of Dominion Energy’s commodity-based derivative instruments as of December 31, 20192022 and December 31, 2018,2021, respectively.
A hypothetical 10% decreaseincrease in commodity prices would have resulted in a decrease of $25 million and $6 million in the fair value of Virginia Power’s commodity-based derivative instruments would have resulted in a decrease in fair value of $54 million and $51 million as of December 31, 20192022 and December 31, 2018,2021, 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 not have resultedresult in a material change in earnings at December 31, 2019$37 million and would have resulted in a $24$6 million decrease in earnings at December 31, 2018.2022 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 in earnings at December 31, 2019 or December 31, 2018. For variable rate debt outstanding for Dominion Energy Gas, a hypothetical 10% increase in market interest rates would not have resulted in a material change in earnings at December 31, 2019$14 million and would have resulted in a $16less than $1 million decrease in earnings at December 31, 2018.
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, 2019,2022, Dominion Energy and Virginia Power and Dominion Energy Gas had $6.4 billion, $1.9$12.7 billion and $1.3$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 $135 million, $88$274 million and $17$156 million, respectively, in the fair value of Dominion Energy and Virginia Power and Dominion Energy Gas’Power’s interest rate derivatives at December 31, 2019.2022. As of December 31, 2018,2021, Dominion Energy and
83
Virginia Power and Dominion Energy Gas had $6.6 billion, $1.9$11.4 billion and $1.4$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 $142 million, $94$191 million and $17$111 million, respectively, in the fair value of Dominion Energy and Virginia Power and Dominion Energy Gas’Power’s interest rate derivatives at December 31, 2018.
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
Dominion Energy recognized net investment losses (including investment income) on nuclear decommissioning and rabbi trust investments of $888 million and net investment gains (including investment income) on nuclear decommissioning and rabbi trust investments of $1$1.1 billion for the yearyears ended December 31, 2019. Dominion Energy recognized net investment losses (including investment income) on nuclear decommissioning trust investments of $135 million for the year ended December 31, 2018.2022 and 2021, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Dominion Energy recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on debt investments of $74 million for the year ended December 31, 2019 and recorded a net decrease in unrealized gains on debt investments of $36$196 million and $64 million for the yearyears ended December 31, 2018.
Virginia Power recognized net investment losses (including investment income) on nuclear decommissioning and rabbi trust investments of $44$426 million and net investment gains (including investment income) on nuclear decommissioning and rabbi trust investments of $568 million for the yearyears ended December 31, 2018.2022 and 2021, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Virginia Power recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on debt investments of $30 million for the year ended December 31, 2019 and recorded a net decrease in unrealized gains on debt investments of $21$106 million and $31 million for the yearyears ended December 31, 2018.
Dominion Energy sponsors pension and other postretirement employee benefit plans that hold investments in trusts to fund employee benefit payments. Virginia Power and Dominion Energy Gas employees participate in these plans. Dominion Energy’s pension and other postretirement plan assets experienced aggregate actual returns (losses) of $2.1$(3.0) billion and $(605) million$1.5 billion in 20192022 and 2018,2021, respectively, versus expected returns of $848 million$1.1 billion and $806 million, respectively. Dominion Energy Gas’ pension and other postretirement plan assets for employees represented by collective bargaining units experienced aggregate actual returns (losses) of $167 million and $(129) million in 2019 and 2018, respectively, versus expected returns of $70 million and $178 million,$1.0 billion, respectively. Differences between actual and
84
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 and Dominion Energy Gas.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, 20192022 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.
85
Item 8. Financial StatementsStatements and Supplementary Data
Page Number | |||||
Dominion Energy, Inc. | |||||
| (PCAOB ID No. 34) | 87 | ||||
89 | |||||
90 | |||||
91 | |||||
93 | |||||
94 | |||||
Virginia Electric and Power Company | |||||
| (PCAOB ID No. 34) | 95 | ||||
97 | |||||
98 | |||||
99 | |||||
101 | |||||
102 | |||||
103 | |||||
86
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Dominion Energy, Inc. and subsidiaries (“("Dominion Energy”Energy") at December 31, 20192022 and 2018,2021, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2019,2022, and the related notes (collectively referred to as the “consolidated"consolidated financial statements”statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Dominion Energy at December 31, 20192022 and 2018,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2022, 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’sEnergy's internal control over financial reporting at December 31, 2019,2022, based on criteria established inControl—Control — Integrated Framework (2013)28, 2020,21, 2023, expressed an unqualified opinion on Dominion Energy’sEnergy's internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of Dominion Energy’sEnergy's management. Our responsibility is to express an opinion on Dominion Energy’sEnergy's consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Dominion Energy in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit 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
Regulatory Assets and Liabilities—Liabilities - Impact of Rate Regulation on the Consolidated Financial Statements—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 FERCthe 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; and depreciation, depletion and amortization expense,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 the determination of Virginia Power’s authorized
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:
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 28, 2020
We have served as Dominion Energy’s auditor since 1988.
88
Dominion Energy, Inc.
Consolidated Statements 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, | 2019 | 2018 | 2017 | |||||||||
(millions, except per share amounts) | ||||||||||||
Operating Revenue (1) | $ | 16,572 | $ | 13,366 | $ | 12,586 | ||||||
Operating Expenses | ||||||||||||
Electric fuel and other energy-related purchases | 2,938 | 2,814 | 2,301 | |||||||||
Purchased electric capacity | 88 | 122 | 6 | |||||||||
Purchased gas | 1,536 | 645 | 701 | |||||||||
Other operations and maintenance | 4,428 | 3,458 | 3,200 | |||||||||
Depreciation, depletion and amortization | 2,655 | 2,000 | 1,905 | |||||||||
Other taxes | 1,040 | 703 | 668 | |||||||||
Impairment of assets and related charges | 1,535 | 403 | 15 | |||||||||
Gains on sales of assets | (162 | ) | (380 | ) | (147 | ) | ||||||
Total operating expenses | 14,058 | 9,765 | 8,649 | |||||||||
Income from operations | 2,514 | 3,601 | 3,937 | |||||||||
Other income (1) | 986 | 1,021 | 358 | |||||||||
Interest and related charges | 1,773 | 1,493 | 1,205 | |||||||||
Income from operations including noncontrolling interests before income tax expense (benefit) | 1,727 | 3,129 | 3,090 | |||||||||
Income tax expense (benefit) | 351 | 580 | (30 | ) | ||||||||
Net Income Including Noncontrolling Interests | 1,376 | 2,549 | 3,120 | |||||||||
Noncontrolling Interests | 18 | 102 | 121 | |||||||||
Net Income Attributable to Dominion Energy | $ | 1,358 | $ | 2,447 | $ | 2,999 | ||||||
Earnings Per Common Share | ||||||||||||
Net income attributable to Dominion Energy—Basic | $ | 1.66 | $ | 3.74 | $ | 4.72 | ||||||
Net income attributable to Dominion Energy—Diluted | $ | 1.62 | $ | 3.74 | $ | 4.72 | ||||||
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, | 2019 | 2018 | 2017 | |||||||||
(millions) | ||||||||||||
Net Income Including Noncontrolling Interests | $ | 1,376 | $ | 2,549 | $ | 3,120 | ||||||
Other comprehensive income (loss), net of taxes: | ||||||||||||
Net deferred gains (losses) on derivatives-hedging activities, net of $35, $(10) and $(3) tax | (110 | ) | 30 | 8 | ||||||||
Changes in unrealized net gains (losses) on investment securities, net of $(14), $5 and $(121) tax | 39 | (18 | ) | 215 | ||||||||
Changes in net unrecognized pension and other postretirement benefit costs, net of $(4), $75 and $32 tax | (22 | ) | (215 | ) | (69 | ) | ||||||
Amounts reclassified to net income: | ||||||||||||
Net derivative (gains) losses-hedging activities, net of $21, $(35) and $18 tax | (62 | ) | 102 | (29 | ) | |||||||
Net realized (gains) losses on investment securities, net of $1, $(2) and $21 tax | (4 | ) | 5 | (37 | ) | |||||||
Net pension and other postretirement benefit costs, net of $(23), $(21) and $(32) tax | 66 | 78 | 50 | |||||||||
Changes in other comprehensive gains (losses) from equity method investees, net of $—, $(1) and $(2) tax | — | 1 | 3 | |||||||||
Total other comprehensive income (loss) | (93 | ) | (17 | ) | 141 | |||||||
Comprehensive income including noncontrolling interests | 1,283 | 2,532 | 3,261 | |||||||||
Comprehensive income attributable to noncontrolling interests | 18 | 103 | 122 | |||||||||
Comprehensive income attributable to Dominion Energy | $ | 1,265 | $ | 2,429 | $ | 3,139 | ||||||
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, | 2019 | 2018 | ||||||
(millions) | ||||||||
Assets | ||||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 166 | $ | 268 | ||||
Customer receivables (less allowance for doubtful accounts of $20 and $14) | 2,278 | 1,749 | ||||||
Other receivables (less allowance for doubtful accounts of $3 and $4 (1 ) | 367 | 331 | ||||||
Inventories: | ||||||||
Materials and supplies | 1,193 | 1,039 | ||||||
Fossil fuel | 412 | 287 | ||||||
Gas stored | 137 | 92 | ||||||
Prepayments | 328 | 265 | ||||||
Regulatory assets | 879 | 496 | ||||||
Other | 328 | 634 | ||||||
Total current assets | 6,088 | 5,161 | ||||||
Investments | ||||||||
Nuclear decommissioning trust funds | 6,192 | 4,938 | ||||||
Investment in equity method affiliates | 1,646 | 1,278 | ||||||
Other | 379 | 344 | ||||||
Total investments | 8,217 | 6,560 | ||||||
Property, Plant and Equipment | ||||||||
Property, plant and equipment | 97,466 | 76,578 | ||||||
Accumulated depreciation, depletion and amortization | (28,384 | ) | (22,018 | ) | ||||
Total property, plant and equipment, net | 69,082 | 54,560 | ||||||
Deferred Charges and Other Assets | ||||||||
Goodwill | 8,946 | 6,410 | ||||||
Pension and other postretirement benefit assets | 1,708 | 1,279 | ||||||
Intangible assets, net | 791 | 670 | ||||||
Regulatory assets | 7,687 | 2,676 | ||||||
Other | 1,304 | 598 | ||||||
Total deferred charges and other assets | 20,436 | 11,633 | ||||||
Total assets | $ | 103,823 | $ | 77,914 | ||||
At December 31, | 2019 | 2018 | |||||||
(millions) | |||||||||
Liabilities and Equity | |||||||||
Current Liabilities | |||||||||
Securities due within one year | $ | 3,162 | $ | 3,624 | |||||
Credit facility borrowings | — | 73 | |||||||
Short-term debt | 911 | 334 | |||||||
Accounts payable | 1,115 | 914 | |||||||
Accrued interest, payroll and taxes | 1,323 | 836 | |||||||
Regulatory liabilities | 497 | 356 | |||||||
Reserves for SCANA legal proceedings | 696 | — | |||||||
Other (1) | 2,235 | 1,510 | |||||||
Total current liabilitie s | 9,939 | 7,647 | |||||||
Long-Term Debt | |||||||||
Long-term debt | 30,313 | 26,293 | |||||||
Junior subordinated notes | 3,406 | 3,430 | |||||||
Remarketable subordinated notes | — | 1,386 | |||||||
Finance leases | 105 | 35 | |||||||
Total long-term debt | 33,824 | 31,144 | |||||||
Deferred Credits and Other Liabilities | �� | ||||||||
Deferred income taxes and investment tax credits | 6,277 | 5,116 | |||||||
Regulatory liabilities | 11,001 | 6,840 | |||||||
Asset retirement obligations | 4,866 | 2,250 | |||||||
Pension and other postretirement benefit liability | 2,366 | 2,328 | |||||||
Other (1) | 1,517 | 541 | |||||||
Total deferred credits and other liabilities | 26,027 | 17,075 | |||||||
Total liabilities | 69,790 | 55,866 | |||||||
Commitments and Contingencies (see Note 23) | |||||||||
Equity | |||||||||
Preferred stock (See Note 19) | 2,387 | — | |||||||
Common stock – no par ( 2 ) | 23,824 | 12,588 | |||||||
Retained earnings | 7,576 | 9,219 | |||||||
Accumulated other comprehensive loss | (1,793 | ) | (1,700 | ) | |||||
Total shareholders’ equity | 31,994 | 20,107 | |||||||
Noncontrolling interests | 2,039 | 1,941 | |||||||
Total equity | 34,033 | 22,048 | |||||||
Total liabilities and equity | $ | 103,823 | $ | 77,914 | |||||
At December 31, |
| 2022 |
|
| 2021 |
| ||
(millions) |
|
|
|
|
|
| ||
ASSETS |
|
|
|
|
|
| ||
Current Assets |
|
|
|
|
|
| ||
Cash and cash equivalents |
| $ | 153 |
|
| $ | 283 |
|
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 |
|
| 1,206 |
|
|
| 1,167 |
|
Fossil fuel |
|
| 358 |
|
|
| 320 |
|
Gas stored |
|
| 165 |
|
|
| 144 |
|
Derivative assets |
|
| 1,137 |
|
|
| 122 |
|
Margin deposit assets |
|
| 480 |
|
|
| 678 |
|
Prepayments |
|
| 392 |
|
|
| 328 |
|
Regulatory assets |
|
| 2,340 |
|
|
| 1,492 |
|
Other |
|
| 215 |
|
|
| 142 |
|
Current assets held for sale |
|
| 47 |
|
|
| 25 |
|
Total current assets |
|
| 9,850 |
|
|
| 7,269 |
|
Investments |
|
|
|
|
|
| ||
Nuclear decommissioning trust funds |
|
| 5,957 |
|
|
| 7,950 |
|
Investment in equity method affiliates |
|
| 3,012 |
|
|
| 2,932 |
|
Other |
|
| 390 |
|
|
| 394 |
|
Total investments |
|
| 9,359 |
|
|
| 11,276 |
|
Property, Plant and Equipment |
|
|
|
|
|
| ||
Property, plant and equipment |
|
| 91,202 |
|
|
| 86,503 |
|
Accumulated depreciation, depletion and amortization |
|
| (27,742 | ) |
|
| (26,729 | ) |
Total property, plant and equipment, net |
|
| 63,460 |
|
|
| 59,774 |
|
Deferred Charges and Other Assets |
|
|
|
|
|
| ||
Goodwill |
|
| 7,295 |
|
|
| 7,405 |
|
Pension and other postretirement benefit assets |
|
| 1,785 |
|
|
| 2,310 |
|
Intangible assets, net |
|
| 868 |
|
|
| 784 |
|
Derivative assets |
|
| 1,039 |
|
|
| 491 |
|
Regulatory assets |
|
| 9,087 |
|
|
| 8,643 |
|
Other |
|
| 1,500 |
|
|
| 1,638 |
|
Total deferred charges and other assets |
|
| 21,574 |
|
|
| 21,271 |
|
Total assets |
| $ | 104,243 |
|
| $ | 99,590 |
|
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
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 |
|
Preferred Stock | Common Stock | Dominion Energy Shareholders | ||||||||||||||||||||||||||||||||||
Shares | Amount | Shares | Amount | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Total Shareholders’ Equity | Noncontrolling Interests | Total Equity | ||||||||||||||||||||||||||||
(millions except per share amounts) | ||||||||||||||||||||||||||||||||||||
December 31, 2016 | 628 | $ | 8,550 | $ | 6,854 | $ (799 | ) | $14,605 | $ 2,235 | $ | 16,840 | |||||||||||||||||||||||||
Net income including noncontrolling interests | 2,999 | 2,999 | 121 | 3,120 | ||||||||||||||||||||||||||||||||
Contributions from NRG to Four Brothers and Three Cedars | — | 9 | 9 | |||||||||||||||||||||||||||||||||
Issuance of common stock | 17 | 1,302 | 1,302 | 1,302 | ||||||||||||||||||||||||||||||||
Sale of Dominion Energy Midstream common units—net of offering costs | — | 18 | 18 | |||||||||||||||||||||||||||||||||
Stock awards (net of change in unearned compensation) | 22 | 22 | 22 | |||||||||||||||||||||||||||||||||
Dividends ($3.035 per common share) and distributions | (1,931 | ) | (1,931 | ) | (156 | ) | (2,087 | ) | ||||||||||||||||||||||||||||
Other comprehensive income, net of tax | 140 | 140 | 1 | 141 | ||||||||||||||||||||||||||||||||
Other | (9 | ) | 14 | 5 | 5 | |||||||||||||||||||||||||||||||
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 | ||||||||||||||||||||||
Year Ended December 31, | 2019 | 2018 | 2017 | |||||||||
(millions) | ||||||||||||
Operating Activities | ||||||||||||
Net income including noncontrolling interests | $ | 1,376 | $ | 2,549 | $ | 3,120 | ||||||
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities: | ||||||||||||
Depreciation, depletion and amortization (including nuclear fuel) | 2,977 | 2,280 | 2,202 | |||||||||
Deferred income taxes and investment tax credits | 216 | 517 | (3 | ) | ||||||||
Proceeds from assignment of tower rental portfolio | — | — | 91 | |||||||||
Contribution to pension plan | (21 | ) | — | (75 | ) | |||||||
Provision for refunds and rate credits to electric utility customers | 800 | 77 | — | |||||||||
Impairment of assets and other charges | 1,333 | 395 | 15 | |||||||||
Charge related to a voluntary retirement program | 320 | — | — | |||||||||
Gains on sales of assets and equity method investments | (167 | ) | (1,006 | ) | (148 | ) | ||||||
Net (gains) losses on nuclear decommissioning trusts funds and other investments | (626 | ) | 102 | (117 | ) | |||||||
| Charges associated with equity method investments | — | — | 158 | |||||||||
| Charge (revision) for future ash pond and landfill closure costs | (113 | ) | 81 | — | ||||||||
Other adjustments | (5 | ) | 19 | 33 | ||||||||
Changes in: | ||||||||||||
Accounts receivable | (71 | ) | (110 | ) | (103 | ) | ||||||
Inventories | (90 | ) | (29 | ) | 15 | |||||||
Deferred fuel and purchased gas costs, net | 195 | (247 | ) | (71 | ) | |||||||
Prepayments | (225 | ) | (51 | ) | (62 | ) | ||||||
Accounts payable | (225 | ) | 67 | (89 | ) | |||||||
Accrued interest, payroll and taxes | (78 | ) | (12 | ) | 64 | |||||||
Customer deposits | (101 | ) | 54 | 15 | ||||||||
Margin deposit assets and liabilities | 60 | — | (10 | ) | ||||||||
Net realized and unrealized changes related to derivative activities | 43 | 181 | 44 | |||||||||
Asset retirement obligations | 41 | (35 | ) | (94 | ) | |||||||
Pension and other postretirement benefits | (148 | ) | (114 | ) | (177 | ) | ||||||
Other operating assets and liabilities | (287 | ) | 55 | (306 | ) | |||||||
Net cash provided by operating activities | 5,204 | 4,773 | 4,502 | |||||||||
Investing Activities | ||||||||||||
Plant construction and other property additions (including nuclear fuel) | (4,980 | ) | (4,254 | ) | (5,504 | ) | ||||||
Cash and restricted cash acquired in the SCANA Combination | 389 | — | — | |||||||||
Acquisition of solar development projects | (341 | ) | (151 | ) | (405 | ) | ||||||
Proceeds from sales of securities | 1,712 | 1,804 | 1,831 | |||||||||
Purchases of securities | (1,749 | ) | (1,894 | ) | (1,940 | ) | ||||||
Proceeds from sales of assets and equity method investments | 447 | 2,542 | 138 | |||||||||
Contributions to equity method affiliates | (209 | ) | (428 | ) | (370 | ) | ||||||
Distributions from equity method affiliates | 9 | 36 | 275 | |||||||||
Other | 100 | (13 | ) | 33 | ||||||||
Net cash used in investing activities | (4,622 | ) | (2,358 | ) | (5,942 | ) | ||||||
Financing Activities | ||||||||||||
Issuance (repayment) of short-term debt, net | 404 | (2,964 | ) | 143 | ||||||||
Issuance of short-term notes | 3,000 | 1,450 | — | |||||||||
Repayment and repurchase of short-term notes | (3,000 | ) | (1,450 | ) | (250 | ) | ||||||
Credit facility borrowings | — | 73 | — | |||||||||
Repayment of credit facility borrowings | (113 | ) | — | — | ||||||||
Issuance and remarketing of long-term debt | 4,374 | 6,362 | 3,880 | |||||||||
Repayment and repurchase of long-term debt (including redemption premiums) | (9,116 | ) | (5,682 | ) | (1,572 | ) | ||||||
Proceeds from sale of interest in Cove Point | 2,078 | — | — | |||||||||
Net proceeds from issuance of Dominion Energy Midstream common units | — | 4 | 18 | |||||||||
Issuance of 2019 Equity Units | 1,582 | — | — | |||||||||
Issuance of Series B Preferred Stock | 791 | — | — | |||||||||
Issuance of common stock | 2,515 | 2,461 | 1,302 | |||||||||
Common dividend payments | (2,983 | ) | (2,185 | ) | (1,931 | ) | ||||||
Other | (236 | ) | (278 | ) | (287 | ) | ||||||
Net cash provided by (used in) financing activities | (704 | ) | (2,209 | ) | 1,303 | |||||||
Increase (decrease) in cash, restricted cash and equivalents | (122 | ) | 206 | (137 | ) | |||||||
Cash, restricted cash and equivalents at beginning of period | 391 | 185 | 322 | |||||||||
Cash, restricted cash and equivalents at end of period | $ | 269 | $ | 391 | $ | 185 | ||||||
Supplemental Cash Flow Information | ||||||||||||
Cash paid during the year for: | ||||||||||||
Interest and related charges, excluding capitalized amounts | $ | 1,643 | $ | 1,362 | 1,083 | |||||||
Income taxes | 106 | 89 | 9 | |||||||||
Significant noncash investing and financing activities: (1)(2)(3)(4)(5) | ||||||||||||
Accrued capital expenditures | 555 | 307 | 343 | |||||||||
Leases (6) | 157 | — | — | |||||||||
Receivables from sales of assets and equity method investments | 5 | 159 | — | |||||||||
Guarantee provided by equity method affiliate | — | — | 30 | |||||||||
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
92
Dominion Energy, Inc.
Consolidated Statements of Independent Registered Public Accounting Firm
| 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 |
|
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
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
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”Power") at December 31, 20192022 and 2018,2021, the related consolidated statements of income, comprehensive income, common shareholder’sshareholder's equity, and cash flows, for each of the three years in the period ended December 31, 2019,2022, and the related notes (collectively referred to as the “consolidated"consolidated financial statements”statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Virginia Power at December 31, 20192022 and 2018,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2022, 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’sPower's management. Our responsibility is to express an opinion on Virginia Power’sPower'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 audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Assets and Liabilities - Impact of Rate Regulation on the Consolidated Financial Statements — Refer to Notes 2, 12 and 13 to the Consolidated Financial Statements
Critical Audit Matter Description
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 credit a portion of its earnings to customers.
When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds or other benefits through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Virginia Power evaluates whether recovery of its regulatory assets through future rates is probable as well as whether a regulatory liability due to customers is probable and makes various assumptions in its analyses. These analyses are generally based on orders issued by regulatory commissions, legislation and judicial actions; past experience; discussions with applicable regulatory authorities and legal counsel; forecasted earnings; and considerations around the likelihood of impacts from events such as unusual weather conditions, extreme weather events, and other natural disasters, and unplanned outages of facilities.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about the financial statement impacts of rate regulation. Management judgments include assessing the likelihood of (1) recovery of its regulatory assets through future rates and (2) whether a regulatory liability is due to customers. Given 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:
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 28, 2020
We have served as Virginia Power’sPower'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, | 2019 | 2018 | 2017 | |||||||||
(millions) | ||||||||||||
Operating Revenue (1) | $ | 8,108 | $ | 7,619 | $ | 7,556 | ||||||
Operating Expenses | ||||||||||||
Electric fuel and other energy-related purchases (1) | 2,178 | 2,318 | 1,909 | |||||||||
Purchased electric capacity | 40 | 122 | 6 | |||||||||
Other operations and maintenance: | ||||||||||||
Affiliated suppliers | 367 | 305 | 309 | |||||||||
Other | 1,376 | 1,371 | 1,169 | |||||||||
Depreciation and amortization | 1,223 | 1,132 | 1,141 | |||||||||
Other taxes | 328 | 300 | 290 | |||||||||
Impairment of assets and other charges | 757 | — | — | |||||||||
Total operating expenses | 6,269 | 5,548 | 4,824 | |||||||||
Income from operations | 1,839 | 2,071 | 2,732 | |||||||||
Other income | 98 | 22 | 76 | |||||||||
Interest and related charges (1) | 524 | 511 | 494 | |||||||||
Income from operations before income tax expense | 1,413 | 1,582 | 2,314 | |||||||||
Income tax expense | 264 | 300 | 774 | |||||||||
Net Income | $ | 1,149 | $ | 1,282 | $ | 1,540 | ||||||
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, | 2019 | 2018 | 2017 | |||||||||
(millions) | ||||||||||||
Net Income | $ | 1,149 | $ | 1,282 | $ | 1,540 | ||||||
Other comprehensive income (loss), net of taxes: | ||||||||||||
Net deferred gains (losses) on derivatives-hedging activities, net of $8, $(1) and $3 tax | (22 | ) | 1 | (5 | ) | |||||||
Changes in unrealized net gains (losses) on nuclear decommissioning trust funds, net of $(2), $— and $(16) tax | 5 | — | 24 | |||||||||
Amounts reclassified to net income: | ||||||||||||
Net derivative (gains) losses-hedging activities, net of $—, $— and $— tax | 1 | 1 | 1 | |||||||||
Net realized (gains) losses on nuclear decommissioning trust funds, net of $1, $— and $3 tax | (1 | ) | — | (4 | ) | |||||||
Other comprehensive income (loss) | (17 | ) | 2 | 16 | ||||||||
Comprehensive income | $ | 1,132 | $ | 1,284 | $ | 1,556 | ||||||
Year Ended December 31, |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
(millions) |
|
|
|
|
|
|
|
|
| |||
Net income |
| $ | 1,215 |
|
| $ | 1,712 |
|
| $ | 1,021 |
|
Other comprehensive income (loss), net of taxes: |
|
|
|
|
|
|
|
|
| |||
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 $(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) |
|
| 50 |
|
|
| 11 |
|
|
| (23 | ) |
Comprehensive income |
| $ | 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, | 2019 | 2018 | ||||||
(millions) | ||||||||
Assets | ||||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 17 | $ | 29 | ||||
Customer receivables (less allowance for doubtful accounts of $9 at both dates) | 1,163 | 999 | ||||||
Other receivables (less allowance for doubtful accounts of $2 and $3) | 106 | 76 | ||||||
Affiliated receivables | 27 | 101 | ||||||
Inventories (average cost method): | ||||||||
Materials and supplies | 549 | 550 | ||||||
Fossil fuel | 324 | 287 | ||||||
Prepayments | 27 | 28 | ||||||
Regulatory assets | 433 | 424 | ||||||
Other (1) | 30 | 77 | ||||||
Total current assets | 2,676 | 2,571 | ||||||
Investments | ||||||||
Nuclear decommissioning trust funds | 2,881 | 2,369 | ||||||
Other | 3 | 3 | ||||||
Total investments | 2,884 | 2,372 | ||||||
Property, Plant and Equipment | ||||||||
Property, plant and equipment | 47,038 | 44,524 | ||||||
Accumulated depreciation and amortization | (14,156 | ) | (14,003 | ) | ||||
Total property, plant and equipment, net | 32,882 | 30,521 | ||||||
Deferred Charges and Other Assets | ||||||||
Pension and other postretirement benefit assets (1) | 287 | 254 | ||||||
Intangible assets, net | 271 | 250 | ||||||
Regulatory assets | 1,863 | 737 | ||||||
Other (1) | 565 | 175 | ||||||
Total deferred charges and other assets | 2,986 | 1,416 | ||||||
Total assets | $ | 41,428 | $ | 36,880 | ||||
At December 31, | 2019 | 2018 | |||||||
(millions) | |||||||||
Liabilities And Common Shareholder’s Equity | |||||||||
Current Liabilities | |||||||||
Securities due within one year | $ | 4 | $ | 350 | |||||
Short-term debt | 243 | 314 | |||||||
Accounts payable | 334 | 339 | |||||||
Payables to affiliates | 210 | 209 | |||||||
Affiliated current borrowings | 107 | 224 | |||||||
Accrued interest, payroll and t axes | 253 | 248 | |||||||
Asset retirement obligations | 340 | 245 | |||||||
Regulatory liabilities | 167 | 299 | |||||||
Derivative liabilities (1) | 243 | 25 | |||||||
Customer deposits | 121 | 121 | |||||||
Other current liabilities | 450 | 441 | |||||||
Total current liabilities | 2,472 | 2,815 | |||||||
Long-Term Debt | |||||||||
Long-term debt | 12,325 | 11,320 | |||||||
Finance leases | 16 | 1 | |||||||
Total long-term debt | 12,341 | 11,321 | |||||||
Deferred Credits and Other Liabilities | |||||||||
Deferred income taxes and investment tax credits | 2,962 | 3,017 | |||||||
Asset retirement obligations | 3,241 | 1,200 | |||||||
Regulatory liabilities | 5,074 | 4,647 | |||||||
Pension and other postretirement benefit liability (1) | 782 | 632 | |||||||
Other (1) | 567 | 201 | |||||||
Total deferred credits and other liabilities | 12,626 | 9,697 | |||||||
Total liabilities | 27,439 | 23,833 | |||||||
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 | 7,167 | 6,208 | |||||||
Accumulated other comprehensive loss | (29 | ) | (12 | ) | |||||
Total common shareholder’s equity | 13,989 | 13,047 | |||||||
Total liabilities and shareholder’s equity | $ | 41,428 | $ | 36,880 | |||||
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 |
|
Common Stock | Other Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Total | ||||||||||||||||||||
Shares | Amount | |||||||||||||||||||||||
(millions, except for shares) | (thousands) | |||||||||||||||||||||||
December 31, 2016 | 275 | $ | 5,738 | $ | 1,113 | $ | 4,968 | $ 46 | $ | 11,865 | ||||||||||||||
Net income | 1,540 | 1,540 | ||||||||||||||||||||||
Dividends | (1,199 | ) | (1,199 | ) | ||||||||||||||||||||
Other comprehensive income, net of tax | 16 | 16 | ||||||||||||||||||||||
Other | 2 | 2 | ||||||||||||||||||||||
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 | |||||||||||||
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
100
Virginia Electric and Power Company
Year Ended December 31, | 2019 | 2018 | 2017 | |||||||||
(millions) | ||||||||||||
Operating Activities | ||||||||||||
Net income | $ | 1,149 | $ | 1,282 | $ | 1,540 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
Depreciation and amortization (including nuclear fuel) | 1,392 | 1,309 | 1,333 | |||||||||
Deferred income taxes and investment tax credits | (80 | ) | 224 | 269 | ||||||||
Proceeds from assignment of rental portfolio | — | — | 91 | |||||||||
| Charge (revision) for future ash pond and landfill closure costs | (113 | ) | 81 | — | ||||||||
Impairment of assets and other charges | 624 | — | — | |||||||||
Provision for rate credits to customers | — | 77 | — | |||||||||
Charge related to a voluntary retirement program | 116 | — | — | |||||||||
Other adjustments | (86 | ) | (21 | ) | (36 | ) | ||||||
Changes in: | ||||||||||||
Accounts receivable | (196 | ) | (60 | ) | (27 | ) | ||||||
Affiliated receivables and payables | 75 | (14 | ) | 125 | ||||||||
Inventories | (56 | ) | 13 | 3 | ||||||||
Prepayments | 1 | (1 | ) | 3 | ||||||||
Deferred fuel expenses, net | 243 | (269 | ) | (59 | ) | |||||||
Accounts payable | (31 | ) | (26 | ) | (42 | ) | ||||||
Accrued interest, payroll and taxes | 5 | (8 | ) | 17 | ||||||||
Net realized and unrealized changes related to derivative activities | 21 | 119 | 13 | |||||||||
Asset retirement obligations | 51 | (54 | ) | (88 | ) | |||||||
Other operating assets and liabilities | (331 | ) | 188 | (181 | ) | |||||||
Net cash provided by operating activities | 2,784 | 2,840 | 2,961 | |||||||||
Investing Activities | ||||||||||||
Plant construction and other property additions | (2,642 | ) | (2,228 | ) | (2,496 | ) | ||||||
Purchases of nuclear fuel | (157 | ) | (173 | ) | (192 | ) | ||||||
Acquisition of solar development projects | (182 | ) | (141 | ) | (41 | ) | ||||||
Proceeds from sales of securities | 858 | 887 | 849 | |||||||||
Purchases of securities | (905 | ) | (925 | ) | (884 | ) | ||||||
Other | (37 | ) | (63 | ) | (41 | ) | ||||||
Net cash used in investing activities | (3,065 | ) | (2,643 | ) | (2,805 | ) | ||||||
Financing Activities | ||||||||||||
Issuance (repayment) of short-term debt, net | (71 | ) | (228 | ) | 477 | |||||||
Issuance (repayment) of affiliated current borrowings, net | (117 | ) | 191 | (229 | ) | |||||||
Issuance and remarketing of long-term debt | 1,248 | 1,300 | 1,500 | |||||||||
Repayment and repurchase of long-term debt | (591 | ) | (964 | ) | (681 | ) | ||||||
Common dividend payments to parent | (190 | ) | (464 | ) | (1,199 | ) | ||||||
Other | (12 | ) | (18 | ) | (11 | ) | ||||||
Net cash provided by (used in) financing activities | 267 | (183 | ) | (143 | ) | |||||||
Increase (decrease) in cash, restricted cash and equivalents | (14 | ) | 14 | 13 | ||||||||
Cash, restricted cash and equivalents at beginning of year | 38 | 24 | 11 | |||||||||
Cash, restricted cash and equivalents at end of year | $ | 24 | $ | 38 | $ | 24 | ||||||
Supplemental Cash Flow Information | ||||||||||||
Cash paid during the year for: | ||||||||||||
Interest and related charges, excluding capitalized amounts | $ | 495 | $ | 498 | $ | 458 | ||||||
Income taxes | 272 | 128 | 362 | |||||||||
Significant noncash investing and financing activities: (1) | ||||||||||||
Accrued capital expenditures | 292 | 204 | 169 | |||||||||
Leases (2) | 55 | — | — | |||||||||
|
| Common Stock |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
|
| Shares |
|
| Amount |
|
| Other Paid-In Capital |
|
| Retained Earnings |
|
| AOCI |
|
| Total |
| ||||||
(millions, except for shares) |
| (thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
December 31, 2019 |
|
| 275 |
|
| $ | 5,738 |
|
| $ | 1,113 |
|
| $ | 7,167 |
|
| $ | (29 | ) |
| $ | 13,989 |
|
Net income |
|
|
|
|
|
|
|
|
|
|
| 1,021 |
|
|
|
|
|
| 1,021 |
| ||||
Dividends |
|
|
|
|
|
|
|
|
|
|
| (430 | ) |
|
|
|
|
| (430 | ) | ||||
Other comprehensive loss, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
| (23 | ) |
|
| (23 | ) | ||||
December 31, 2020 |
|
| 275 |
|
|
| 5,738 |
|
|
| 1,113 |
|
|
| 7,758 |
|
|
| (52 | ) |
|
| 14,557 |
|
Net income |
|
|
|
|
|
|
|
|
|
|
| 1,712 |
|
|
|
|
|
| 1,712 |
| ||||
Dividends |
|
|
|
|
|
|
|
|
|
|
| (300 | ) |
|
|
|
|
| (300 | ) | ||||
Other comprehensive income, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 11 |
|
|
| 11 |
| ||||
December 31, 2021 |
|
| 275 |
|
|
| 5,738 |
|
|
| 1,113 |
|
|
| 9,170 |
|
|
| (41 | ) |
|
| 15,980 |
|
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 subsidiaries (“Dominion Energy Gas”) at December 31, 2019 and 2018, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2019, 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 Gas at December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.
Consolidated Statements of Income
Year Ended December 31, | 2019 | 2018 | 2017 | |||||||||
(millions) | ||||||||||||
Operating Revenue (1) | $ | 2,169 | $ | 1,996 | $ | 1,523 | ||||||
Operating Expenses | ||||||||||||
Purchased (excess) gas (1) | 7 | (10 | ) | 109 | ||||||||
Other energy-related purchases | 2 | 4 | 4 | |||||||||
Other operations and maintenance: | ||||||||||||
Affiliated suppliers | 168 | 132 | 123 | |||||||||
Other (1) | 556 | 584 | 449 | |||||||||
Depreciation and amortization | 367 | 333 | 242 | |||||||||
Other taxes | 154 | 120 | 99 | |||||||||
Impairment of assets and related charges | 13 | 163 | 15 | |||||||||
Gains on sales of assets | (2 | ) | (117 | ) | (70 | ) | ||||||
Total operating expenses | 1,265 | 1,209 | 971 | |||||||||
Income from continuing operations | 904 | 787 | 552 | |||||||||
Earnings from equity method investees | 43 | 54 | 47 | |||||||||
Other income | 166 | 89 | 62 | |||||||||
Interest and related charges (1) | 311 | 174 | 60 | |||||||||
Income from continuing operations before income tax expense | 802 | 756 | 601 | |||||||||
Income tax expense (benefit) | 101 | 124 | (65 | ) | ||||||||
Net Income from Continuing Operations | 701 | 632 | 666 | |||||||||
Net Income from discontinued operations (2) | 141 | 24 | 163 | |||||||||
Net Income including noncontrolling interests | 842 | 656 | 829 | |||||||||
Noncontrolling interests | 121 | 175 | 126 | |||||||||
Net Income Attributable to Dominion Energy Gas | $ | 721 | $ | 481 | $ | 703 | ||||||
Year Ended December 31, |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
(millions) |
|
|
|
|
|
|
|
|
| |||
Operating Activities |
|
|
|
|
|
|
|
|
| |||
Net income |
| $ | 1,215 |
|
| $ | 1,712 |
|
| $ | 1,021 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
| |||
Depreciation and amortization (including nuclear fuel) |
|
| 1,892 |
|
|
| 1,521 |
|
|
| 1,421 |
|
Deferred income taxes and investment tax credits |
|
| 191 |
|
|
| 343 |
|
|
| (206 | ) |
Impairment of assets and other charges (benefits) |
|
| 493 |
|
|
| (269 | ) |
|
| 1,079 |
|
Provision for refunds to customers |
|
| — |
|
|
| 356 |
|
|
| — |
|
Other adjustments |
|
| 24 |
|
|
| 19 |
|
|
| (50 | ) |
Changes in: |
|
|
|
|
|
|
|
|
| |||
Accounts receivable |
|
| (629 | ) |
|
| (112 | ) |
|
| (266 | ) |
Affiliated receivables and payables |
|
| 165 |
|
|
| (175 | ) |
|
| 78 |
|
Inventories |
|
| (71 | ) |
|
| (10 | ) |
|
| 10 |
|
Prepayments |
|
| (7 | ) |
|
| (4 | ) |
|
| (5 | ) |
Deferred fuel expenses, net |
|
| (1,393 | ) |
|
| (652 | ) |
|
| 131 |
|
Accounts payable |
|
| 145 |
|
|
| 19 |
|
|
| 6 |
|
Accrued interest, payroll and taxes |
|
| (4 | ) |
|
| 21 |
|
|
| (4 | ) |
Margin deposit assets and liabilities |
|
| (143 | ) |
|
| (166 | ) |
|
| (1 | ) |
Net realized and unrealized changes related to derivative activities |
|
| 109 |
|
|
| — |
|
|
| (6 | ) |
Other operating assets and liabilities |
|
| (159 | ) |
|
| (106 | ) |
|
| (308 | ) |
Net cash provided by operating activities |
|
| 1,828 |
|
|
| 2,497 |
|
|
| 2,900 |
|
Investing Activities |
|
|
|
|
|
|
|
|
| |||
Plant construction and other property additions |
|
| (4,909 | ) |
|
| (3,521 | ) |
|
| (3,138 | ) |
Purchases of nuclear fuel |
|
| (201 | ) |
|
| (160 | ) |
|
| (199 | ) |
Acquisition of solar development projects |
|
| (77 | ) |
|
| (75 | ) |
|
| (35 | ) |
Proceeds from sales of securities |
|
| 1,538 |
|
|
| 1,791 |
|
|
| 884 |
|
Purchases of securities |
|
| (1,580 | ) |
|
| (1,789 | ) |
|
| (936 | ) |
Other |
|
| 34 |
|
|
| — |
|
|
| 21 |
|
Net cash used in investing activities |
|
| (5,195 | ) |
|
| (3,754 | ) |
|
| (3,403 | ) |
Financing Activities |
|
|
|
|
|
|
|
|
| |||
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 |
|
| 2,338 |
|
|
| 1,000 |
|
|
| 1,327 |
|
Repayment and repurchase of long-term debt |
|
| (438 | ) |
|
| (450 | ) |
|
| (427 | ) |
Common dividend payments to parent |
|
| — |
|
|
| (300 | ) |
|
| (430 | ) |
Other |
|
| (56 | ) |
|
| (21 | ) |
|
| (31 | ) |
Net cash provided by financing activities |
|
| 3,365 |
|
|
| 1,248 |
|
|
| 514 |
|
Increase (decrease) in cash, restricted cash and equivalents |
|
| (2 | ) |
|
| (9 | ) |
|
| 11 |
|
Cash, restricted cash and equivalents at beginning of year |
|
| 26 |
|
|
| 35 |
|
|
| 24 |
|
Cash, restricted cash and equivalents at end of year |
| $ | 24 |
|
| $ | 26 |
|
| $ | 35 |
|
See Note 2 for disclosure of supplemental cash flow information.
The accompanying notes are an integral part of Dominion Energy Gas’Virginia Power’s Consolidated Financial Statements.
102
Year Ended December 31, | 2019 | 2018 | 2017 | |||||||||
(millions) | ||||||||||||
Net Income including noncontrolling interests | $ | 842 | $ | 656 | $ | 829 | ||||||
Other comprehensive income (loss), net of taxes: | ||||||||||||
Net deferred gains (losses) on derivatives-hedging activities, net of $22, $5 and $(3) tax | (61 | ) | (16 | ) | 6 | |||||||
Changes in net unrecognized pension benefit (costs) , net of $(13), $20 and $(8) tax | 33 | (52 | ) | 20 | ||||||||
Amounts reclassified to net income: | ||||||||||||
Net derivative (gains) losses-hedging activities, net of $(2), $(7) and $2 tax | 5 | 19 | (4 | ) | ||||||||
Net pension and other postretirement benefit costs, net of $(2), $(2) and $(2) tax | 5 | 4 | 4 | |||||||||
Total other comprehensive income (loss) | (18 | ) | (45 | ) | 26 | |||||||
Comprehensive income including noncontrolling interests | 824 | 611 | 855 | |||||||||
Comprehensive income attributable to noncontrolling interests | 120 | 175 | 127 | |||||||||
Comprehensive income attributable to Dominion Energy Gas | $ | 704 | $ | 436 | $ | 728 | ||||||
At December 31, | 2019 | 2018 | ||||||
(millions) | ||||||||
Assets | ||||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 27 | $ | 99 | ||||
Customer receivables (less allowance for doubtful accounts of $2 and less than $1)(1) | 173 | 187 | ||||||
Other receivables (1) | 26 | 18 | ||||||
Affiliated receivables | 362 | 319 | ||||||
Affiliated notes receivable | — | 819 | ||||||
Inventories: | ||||||||
Materials and supplies | 120 | 95 | ||||||
Gas stored | 2 | 2 | ||||||
Prepayments | 73 | 77 | ||||||
Gas imbalances (1) | 52 | 187 | ||||||
Current assets of discontinued operations | — | 444 | ||||||
Other | 23 | 101 | ||||||
Total current assets | 858 | 2,348 | ||||||
Investments | ||||||||
Affiliated notes receivables | 3,437 | 4,317 | ||||||
Investment in equity method affiliates | 312 | 339 | ||||||
Total investments | 3,749 | 4,656 | ||||||
Property, Plant and Equipment | ||||||||
Property, plant and equipment | 15,166 | 14,700 | ||||||
Accumulated depreciation and amortization | (3,538 | ) | (3,219 | ) | ||||
Total property, plant and equipment, net | 11,628 | 11,481 | ||||||
Deferred Charges and Other Assets | ||||||||
Goodwill | 1,471 | 1,471 | ||||||
Intangible assets, net | 106 | 115 | ||||||
Pension and other postretirement benefit assets (1) | 840 | 705 | ||||||
Regulatory assets | 40 | 52 | ||||||
Other (1) | 92 | 74 | ||||||
Total deferred charges and other assets | 2,549 | 2,417 | ||||||
Noncurrent Assets of Discontinued Operations | — | 5,849 | ||||||
Total assets | $ | 18,784 | $ | 26,751 | ||||
At December 31, | 2019 | 2018 | |||||||
(millions) | |||||||||
Liabilities and Equity | |||||||||
Current Liabilities | |||||||||
Securities due within one year | $ | 700 | $ | 748 | |||||
Credit facility borrowings | — | 73 | |||||||
Short-term debt | 62 | 10 | |||||||
Accounts payable | 59 | 76 | |||||||
Payables to affiliates | 82 | 124 | |||||||
Affiliated current borrowings | 260 | 3,097 | |||||||
Accrued interest, payroll and taxe s | 128 | 116 | |||||||
Current liabilities of discontinued operations | — | 1,273 | |||||||
Other (1) | 161 | 238 | |||||||
Total current liabilities | 1,452 | 5,755 | |||||||
Long-Term Debt | |||||||||
Long-term debt | 4,821 | 7,022 | |||||||
Finance leases | 5 | — | |||||||
Total Long-Term Debt | 4,826 | 7,022 | |||||||
Deferred Credits and Other Liabilities | |||||||||
Deferred income taxes and investment tax credits | 1,288 | 1,330 | |||||||
Regulatory liabilities | 800 | 765 | |||||||
Other | 189 | 118 | |||||||
Total deferred credits and other liabilities | 2,277 | 2,213 | |||||||
Noncurrent Liabilities of Discontinued Operations | — | 2,896 | |||||||
Total liabilities | 8,555 | 17,886 | |||||||
Commitments and Contingencies (see Note 23) | |||||||||
Equity | |||||||||
Predecessor equity | — | 1,804 | |||||||
Membership interests | 9,031 | 4,566 | |||||||
Accumulated other comprehensive loss | (187 | ) | (169 | ) | |||||
Total members’ equity | 8,844 | 6,201 | |||||||
Noncontrolling interests | 1,385 | 2,664 | |||||||
Total equity | 10,229 | 8,865 | |||||||
Total liabilities and equity | $ | 18,784 | $ | 26,751 | |||||
Predecessor Equity | Membership Interests | Accumulated Other Comprehensive Income (Loss) | Total Members’ Equity | Noncontrolling Interests | Total | |||||||||||||||||||
(millions) | ||||||||||||||||||||||||
December 31, 2016 | $ 1,438 | $3,659 | $(123 | ) | $ | 4,974 | $ 2,713 | $ | 7,687 | |||||||||||||||
Net income including noncontrolling interests | 88 | 615 | 703 | 126 | 829 | |||||||||||||||||||
Sale of Dominion Energy Midstream common units—net of offering costs | — | 18 | 18 | |||||||||||||||||||||
Dividends and distributions | (19 | ) | (15 | ) | (34 | ) | (87 | ) | (121 | ) | ||||||||||||||
Distributions to noncontrolling interests | (193 | ) | (193 | ) | 193 | — | ||||||||||||||||||
Equity contributions from Dominion Energy | 44 | 44 | 7 | 51 | ||||||||||||||||||||
Other comprehensive income, net of tax | 25 | 25 | 1 | 26 | ||||||||||||||||||||
Other | 3 | 2 | 5 | 5 | ||||||||||||||||||||
December 31, 2017 | 1,361 | 4,261 | (98 | ) | 5,524 | 2,971 | 8,495 | |||||||||||||||||
Cumulative-effect of changes in accounting principles | 29 | (26 | ) | 3 | 3 | |||||||||||||||||||
Net income including noncontrolling interests | 180 | 301 | 481 | 175 | 656 | |||||||||||||||||||
Sale of Dominion Energy Midstream common units—net of offering costs | — | 4 | 4 | |||||||||||||||||||||
Remeasurement of noncontrolling interest in Dominion Energy Midstream | 375 | 375 | (375 | ) | — | |||||||||||||||||||
Dividends and distributions | (133 | ) | (25 | ) | (158 | ) | (138 | ) | (296 | ) | ||||||||||||||
Distributions to noncontrolling interests | (27 | ) | (27 | ) | 27 | |||||||||||||||||||
Equity contributions from Dominion Energy | 48 | 48 | 48 | |||||||||||||||||||||
Other comprehensive loss, net of tax | (45 | ) | (45 | ) | (45 | ) | ||||||||||||||||||
December 31, 2018 | 1,804 | 4,566 | (169 | ) | 6,201 | 2,664 | 8,865 | |||||||||||||||||
Net income including noncontrolling interests | 232 | 489 | 721 | 121 | 842 | |||||||||||||||||||
Acquisition of public interest in Dominion Energy Midstream | 1,181 | 1,181 | (1,221 | ) | (40 | ) | ||||||||||||||||||
Dividends and distributions | (457 | ) | (457 | ) | (179 | ) | (636 | ) | ||||||||||||||||
Equity contributions from Dominion Energy | 3,385 | 3,385 | 3,385 | |||||||||||||||||||||
Dominion Energy Gas Restructuring | (6,145 | ) | 3,978 | (1 | ) | (2,168 | ) | (2,168 | ) | |||||||||||||||
Other comprehensive loss, net of tax | (17 | ) | (17 | ) | (1 | ) | (18 | ) | ||||||||||||||||
Other | (2 | ) | (2 | ) | 1 | (1 | ) | |||||||||||||||||
December 31, 2019 | $ — | $9,031 | $(187 | ) | $ | 8,844 | $ 1,385 | $ | 10,229 | |||||||||||||||
Year Ended December 31, | 2019 | 2018 | 2017 | |||||||||
(millions) | ||||||||||||
Operating Activities | ||||||||||||
Net Income including noncontrolling interests | $ | 842 | $ | 656 | $ | 829 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
Depreciation and amortization | 445 | 424 | 328 | |||||||||
Deferred income taxes and investment tax credits | (3 | ) | 380 | (19 | ) | |||||||
Charge related to a voluntary retirement program | 20 | — | — | |||||||||
Gains on sales of assets | (7 | ) | (109 | ) | (70 | ) | ||||||
Impairment of assets and related charges | 13 | 385 | 15 | |||||||||
Other adjustments | 69 | 21 | 14 | |||||||||
Changes in: | ||||||||||||
Accounts receivable | 69 | (101 | ) | (4 | ) | |||||||
Affiliated receivables and payables | (51 | ) | (310 | ) | 26 | |||||||
Inventories | (50 | ) | (28 | ) | (5 | ) | ||||||
Prepayments | 59 | (23 | ) | (20 | ) | |||||||
Accounts payable | (109 | ) | 1 | (7 | ) | |||||||
Accrued interest, payroll and taxes | (52 | ) | 22 | 26 | ||||||||
Pension and other postretirement benefits | (142 | ) | (153 | ) | (143 | ) | ||||||
Other operating assets and liabilities | (37 | ) | 30 | (13 | ) | |||||||
Net cash provided by operating activities | 1,066 | 1,195 | 957 | |||||||||
Investing Activities | ||||||||||||
Plant construction and other property additions | (704 | ) | (1,109 | ) | (1,815 | ) | ||||||
Loan to Dominion Energy | (1,757 | ) | — | — | ||||||||
Loan to East Ohio | (115 | ) | — | — | ||||||||
Loan to Dominion Energy from Cove Point | — | (2,986 | ) | — | ||||||||
Repayment of loan by Dominion Energy to Cove Point | 2,986 | — | — | |||||||||
Repayment of loan to East Ohio | 115 | — | — | |||||||||
| Repayment of affiliated notes receivable, net | 647 | — | 32 | |||||||||
Proceeds from assignments of shale development rights | — | 109 | 70 | |||||||||
Other | (22 | ) | (20 | ) | (27 | ) | ||||||
Net cash provided by (used in) investing activities | 1,150 | (4,006 | ) | (1,740 | ) | |||||||
Financing Activities | ||||||||||||
Issuance (repayment) of short-term debt, net | 52 | (619 | ) | 169 | ||||||||
Issuance (repayment) of affiliated current borrowings, net | (2,837 | ) | 291 | 628 | ||||||||
Issuance of long-term debt | 1,500 | 3,750 | — | |||||||||
Issuance of affiliated long-term debt | 395 | — | — | |||||||||
Repayment of long-term debt | (3,750 | ) | (255 | ) | — | |||||||
Repayment of affiliated long-term debt | (395 | ) | — | — | ||||||||
Credit facility borrowings | — | 73 | — | |||||||||
Repayment of credit facility borrowings | (73 | ) | — | — | ||||||||
Net proceeds from sale of Dominion Energy Midstream common units | — | 4 | 18 | |||||||||
Contributions from Dominion Energy | 3,385 | 25 | 25 | |||||||||
Dividends and distributions | (636 | ) | (296 | ) | (121 | ) | ||||||
Other | (16 | ) | (21 | ) | — | |||||||
Net cash provided by (used in) financing activities | (2,375 | ) | 2,952 | 719 | ||||||||
Increase (decrease) in cash, restricted cash and cash equivalents | (159 | ) | 141 | (64 | ) | |||||||
Cash, restricted cash and equivalents at beginning of year | 198 | 57 | 121 | |||||||||
Cash, restricted cash and equivalents at end of year | $ | 39 | $ | 198 | $ | 57 | ||||||
Supplemental Cash Flow Information | ||||||||||||
Cash paid during the year for: | ||||||||||||
Interest and related charges, excluding capitalized amounts | $ | 291 | $ | 162 | $ | 55 | ||||||
Income taxes | 65 | 79 | 11 | |||||||||
Significant noncash investing and financing activities: (1)(2) | ||||||||||||
Accrued capital expenditures | 25 | 59 | 69 | |||||||||
Equity contributions from Dominion Energy | — | 23 | 26 | |||||||||
Finance leases | 6 | — | — | |||||||||
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 transportersdistributors of energy. Dominion Energy’s operations are conducted through various subsidiaries, including Virginia Power and Dominion Energy Gas.Power. Dominion Energy’s operations also include DESC, an equity investment in Atlantic Coast Pipeline and regulated gas distribution operations primarily in the eastern and Rocky Mountain regions of the U.S. Dominion Energy’s, nonregulated operations include merchantelectric generation and, retail energy marketing operations.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 acquiredthrough the GT&S Transaction completed in November 2020 and the SCANA Combination.
Dominion Energy manages its daily operations through fivefour primary operating segments: Dominion Energy Virginia, Gas Transmission & Storage, Gas Distribution, Dominion Energy South Carolina and Contracted Generation.Assets. Dominion Energy also reports a Corporate and Other segment, which includes its corporate, service company and other functions (including unallocated debt). In addition, as well as Dominion Energy’s noncontrolling interest in Dominion Privatization. Corporate and Other includes specific items attributable to Dominion Energy’s operating segments that are not included in profit measures evaluated by executive management in assessing the operating segments’ performance or in allocating resources.
Virginia Power is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into the PJM wholesale electricity markets. All of Virginia Power’s stock is owned by Dominion Energy.
Virginia Power manages its daily operations through one primary operating segment: Dominion Energy Virginia. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources.
See Note 26 for further discussion of the Companies’ operating segments.
NOTE 2. Significant Accounting Policies
General
The Companies make certain estimates and assumptions in preparing their Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues, expenses and cash flows for the periods presented. Actual results may differ from those estimates.
The Companies’ Consolidated Financial Statements include, after eliminating intercompany transactions and balances, their accounts, those of their respective majority-owned subsidiaries andAt December 31, 2019 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’s merchantEnergy nonregulated solar projects (through December 2021) and Brookfield’s 25%25% interest in Cove Point and the non-Dominion Energy held interest in Dominion Energy Midstream (through January 2019)November 2020) 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 merchant projects upon the occurrence of certain events, none of which are expected to occur in 2020. Brookfield’s25% interest in Cove Point and the public’s ownership interest in Dominion Energy Midstream (through January 2019)are reflected as noncontrolling interest in Dominion Energy Gas’ Consolidated Financial Statements.
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.plans and Virginia Power and Dominion Energy Gas participateparticipates in certain of these plans. See Note 22 for further information on these plans.
Certain amounts in the Companies’ 20182021 and 20172020 Consolidated Financial Statements and Notes have been reclassified to conform to the 20192022 presentation for comparative purposes; however, such reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows.
103
Amounts disclosed for Dominion Energy are inclusive of Virginia Power, and/or Dominion Energy Gas, where applicable.
Operating Revenue
Operating revenue is recorded on the basis of services rendered, commodities delivered, or contracts settled and includes amounts
The primary types of sales and service activities reported as operating revenue for Dominion Energy subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, are as follows:
Revenue from Contracts with Customers
Other Revenue
The primary types of sales and service activities reported as operating revenue for Virginia Power subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, are as follows:
Revenue from Contracts with Customers
Other Revenue
104
The primary types of sales and service activities reported as operating revenue for Virginia Power, prior to the adoption of revised guidance for revenue recognition from contracts with customers, were as follows:
Revenues from electric and gas sales are recognized over time, as the customers of the Companies consume gas and electricity as it is delivered. Transportation and storage contracts are primarily stand-ready service contracts that include fixed reservation and variable usage fees. LNG terminalling services are also stand-ready service contracts, primarily consisting of fixed fees, offset by service credits associated with thestart-upphase of the Liquefaction Facility. 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 and Dominion Energy Gas havehas 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 including NGLs, typically transfer control and are recognized as revenue upon delivery of the product or service. The customer is able to direct the use of, and obtain substantially all of the benefits from, the product at the time the product is delivered. The contract with the customer states the final terms of the sale, including the description, quantity and price of each product or service purchased. Payment for most sales and services varies by contract type but is typically due within a month of billing.
Operating revenue for the gas transmission and storage operations sold to BHE as part of the GT&S Transaction and sold to Southwest Gas as part of the Q-Pipe Group sale primarily consisted of FERC-regulated sales of transmission and storage services, LNG terminalling services, sales of extracted products and associated hedging activities and NGL activities, including gathering and processing and sales of production and condensate as well as services performed for Atlantic Coast Pipeline. This revenue is included in discontinued operations in Dominion EnergyEnergy’s Consolidated Statements of Income.
Transportation and Dominion Energystorage contracts associated with the operations sold to BHE as part of the GT&S Transaction and sold to Southwest Gas typically receive or retain NGLsas part of the Q-Pipe Group sale were primarily stand-ready service contracts that include fixed reservation and natural gas from customers when providing natural gas processing, transportation or storage services. Dominion Energy and Dominion Energy Gas recordvariable 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 fair valuestart-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 continuerevenue continued to recognize revenuebe recognized from the subsequent sale of the NGLs to customers upon delivery. Dominion Energy and Dominion Energy Gas typically retain natural gas under certain transportation service arrangements that are intended to facilitate performance of the service and allow for natural losses that occur. As the intent of the allowance is to enable fulfillment of the contract rather than to provide compensation for services, the fuel allowance is not included in revenue.
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. Management believes, based on credit policies and the December 31, 2019 provision forExpected credit losses that it is unlikely that a material adverse effect on financial position, results of operations or cash flows would occur as a
Electric Fuel, Purchased Energy and Purchased
Where permitted by regulatory authorities, the differences between Dominion Energy and Virginia Power’sthe Companies’ actual electric fuel and purchased energy expenses and Dominion Energy and Dominion Energy Gas’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, 2019,2022, approximately 84%86% is subject to Virginia Power’s deferred fuel accounting, while substantially all of the remaining amount is subject to recovery through similar mechanisms.
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.
105
Income Taxes
A consolidated federal income tax return is filed for Dominion Energy and its subsidiaries, including Virginia Power and Dominion Energy Gas’ subsidiaries.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 and Dominion Energy Gas participateparticipates 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
The Companies recognize positions taken, or expected to be taken, in income tax returns that are
If it is not
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 Virginia Power both recognized interest incomea $7 million benefit from the reversal of $11 million in 2017. Dominion Energy Gas’ interest was immaterial in 2017. The Companies’ penaltiespenalty expense on uncertain tax positions that were immaterial in 2019, 2018 and 2017.
At December 31, 2019,2022, Virginia Power had a net income tax-related affiliated payable of $22 million, comprised of $25 million of federal income taxes payable to, and $3 million of state income taxes receivable from, Dominion Energy. Virginia Power’s net affiliated balances are expected to be paid to Dominion Energy.
At December 31, 2021, Virginia Power had an incomepayablereceivable 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. Dominion Energy Gas also had a netThese affiliated receivable of $209 million due from Dominion Energy, representing $212 million of federal income taxes receivable and $3 million of state income taxes payable to Dominion Energy. The net affiliated receivables are expected to bebalances were received 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.
106
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 |
|
| 2021 |
| ||
(millions) |
|
|
|
|
|
| ||
Dominion Energy |
| $ | 49 |
|
| $ | 70 |
|
Virginia Power |
|
| 21 |
|
|
| 15 |
|
At December 31, | 2019 | 2018 | ||||||
(millions) | ||||||||
Dominion Energy | $ | 29 | $ | 35 | ||||
Virginia Power | 9 | 16 | ||||||
Dominion Energy Gas | 6 | 7 | ||||||
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:
|
| Cash, Restricted Cash and Equivalents at End/Beginning of Year |
| |||||||||||||
|
| December 31, 2022 |
|
| December 31, 2021 |
|
| December 31, 2020 |
|
| December 31, 2019 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Dominion Energy |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Cash and cash equivalents(1) |
| $ | 153 |
|
| $ | 283 |
|
| $ | 179 |
|
| $ | 166 |
|
Restricted cash and equivalents(2)(3) |
|
| 188 |
|
|
| 125 |
|
|
| 68 |
|
|
| 103 |
|
Cash, restricted cash and equivalents shown in the |
| $ | 341 |
|
| $ | 408 |
|
| $ | 247 |
|
| $ | 269 |
|
Virginia Power |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Cash and cash equivalents |
| $ | 22 |
|
| $ | 26 |
|
| $ | 35 |
|
| $ | 17 |
|
Restricted cash and equivalents(3) |
|
| 2 |
|
|
| — |
|
|
| — |
|
|
| 7 |
|
Cash, restricted cash and equivalents shown in the |
| $ | 24 |
|
| $ | 26 |
|
| $ | 35 |
|
| $ | 24 |
|
Cash, Restricted Cash and Equivalents at End/Beginning of Year | ||||||||||||||||
December 31, 2019 | December 31, 2018 | December 31, 2017 | December 31, 2016 | |||||||||||||
(millions) | ||||||||||||||||
Dominion Energy | ||||||||||||||||
Cash and cash equivalents | $166 | $268 | $120 | $261 | ||||||||||||
Restricted cash and equivalents (1) | 103 | 123 | 65 | 61 | ||||||||||||
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows | $269 | $391 | $185 | $322 | ||||||||||||
Virginia Power | ||||||||||||||||
Cash and cash equivalents | $ 17 | $ 29 | $ 14 | $ 11 | ||||||||||||
Restricted cash and equivalents (1) | 7 | 9 | 10 | — | ||||||||||||
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows | $ 24 | $ 38 | $ 24 | $ 11 | ||||||||||||
Dominion Energy Gas | ||||||||||||||||
Cash and cash equivalents (2) | $ 27 | $108 | $ 18 | $ 76 | ||||||||||||
Restricted cash and equivalents (1) | 12 | 90 | 39 | 45 | ||||||||||||
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows | $ 39 | $198 | $ 57 | $121 | ||||||||||||
Supplemental Cash Flow Information
The following table provides supplemental disclosure of cash flow information related to Dominion Energy:
Year Ended December 31, |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
(millions) |
|
|
|
|
|
|
|
|
| |||
Cash paid during the year for: |
|
|
|
|
|
|
|
|
| |||
Interest and related charges, excluding capitalized amounts |
| $ | 1,408 |
|
| $ | 1,340 |
|
| $ | 1,519 |
|
Income taxes |
|
| 139 |
|
|
| 160 |
|
|
| 292 |
|
Significant noncash investing and financing activities:(1)(2) |
|
|
|
|
|
|
|
|
| |||
Accrued capital expenditures |
|
| 979 |
|
|
| 637 |
|
|
| 485 |
|
Leases(3) |
|
| 144 |
|
|
| 96 |
|
|
| 173 |
|
107
The following table provides supplemental disclosure of cash flow information related to Virginia Power:
Year Ended December 31, |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
(millions) |
|
|
|
|
|
|
|
|
| |||
Cash paid (received) during the year for: |
|
|
|
|
|
|
|
|
| |||
Interest and related charges, excluding capitalized amounts |
| $ | 599 |
|
| $ | 501 |
|
| $ | 491 |
|
Income taxes |
|
| (54 | ) |
|
| 109 |
|
|
| 452 |
|
Significant noncash investing activities:(1) |
|
|
|
|
|
|
|
|
| |||
Accrued capital expenditures |
|
| 665 |
|
|
| 363 |
|
|
| 262 |
|
Leases(2) |
|
| 116 |
|
|
| 79 |
|
|
| 32 |
|
Distributions from Equity Method Investees
Dominion Energy and Dominion Energy Gas each holdholds investments that are accounted for under the equity method of accounting. Dominion Energyaccounting and Dominion Energy Gas classifyclassifies 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
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 Gas.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.
108
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.
109
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 and foreign currency exchange rate risks ofin their business operations. Dominion Energy usesThe Companies use derivative instruments such as physical and financial forwards, futures, swaps, options, foreign currency transactions and FTRs to manage the commodity, interest rate andand/or foreign currency exchange rate risks of itstheir business operations. Virginia Power uses derivative instruments such as physical
Derivative assets and financial forwards, futures, swaps, options and FTRs to manage commodity and interest rate risks. Dominion Energy Gas uses derivative instruments such as physical and financial forwards, futures and swaps to manage commodity, interest rate and foreign currency exchange rate risks.
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 $42$480 million and $95$678 million associated with cash collateral at December 31, 20192022 and 2018,2021, respectively. Dominion Energy’s margin liabilities of $2 million and less than $1 million associated with cash collateral at December 31, 2019 and 2018, respectively. Virginia PowerEnergy had margin assets of less than $1 million associated with cash collateral at December 31, 2019. Virginia Power had 0 margin assets associated with cash collateral at December 31, 2018 and 0no margin liabilities associated with cash collateral at December 31, 20192022 and 2018. Dominion Energy Gas2021. Virginia Power had 0 margin assets orof $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, 20192022 and 2018.2021. 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 other incomediscontinued 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
A majority of the Companies’ hedge strategies represents cash flow hedges of the variable price risk primarily associated with the purchase and saleuse of electricity, natural gas and NGLs. The Companies also use interest rate swaps to hedge their exposure to variable interest rates on long-term debt as well as foreign currency swaps to hedge their exposure to interest payments denominated in Euros.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
Dominion 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. See Note 6 for further information about fair value measurements and associated valuation methods for derivatives. See Note 7 for further information on derivatives.
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
In 2019, 20182022, 2021 and 2017,2020, Dominion Energy capitalized interest costs and AFUDC to property, plant and equipment of $89$112 million, $134$117 million and $236$103 million, respectively. In 2019, 20182022, 2021 and 2017,2020, Virginia Power capitalized AFUDC to property, plant and equipment of $34$66 million, $56$78 million and $37$60 million, respectively. In 2019, 2018 and 2017, Dominion Energy Gas capitalized AFUDC to property, plant and equipment of $31 million, $25 million and $34 million, respectively.
Under Virginia law, certain Virginia jurisdictional projects qualify for current recovery of AFUDC through rate adjustment clauses. AFUDC on these projects is calculated and recorded as a regulatory asset and is not capitalized to property, plant and equipment. In 2019, 20182022, 2021 and 2017,2020, Virginia Power recorded $11$34 million, $4$35 million and $22$11 million of AFUDC related to these projects, respectively.
For property subject toDominion Energy and Virginia Powerthe Companies’ electric distribution, electric transmission and generation property and Dominion EnergyEnergy’s natural gas distribution and Dominion Energy Gas natural gas transmission 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
In 2019, Virginia Power had the following charges, primarily recorded in impairment of assets and other charges in the Consolidated Statements of Income
For property that is not subject to
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, |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
(percent) |
|
|
|
|
|
|
|
|
| |||
Dominion Energy(1) |
|
|
|
|
|
|
|
|
| |||
Generation |
|
| 2.71 |
|
|
| 2.63 |
|
|
| 2.51 |
|
Transmission |
|
| 2.29 |
|
|
| 2.47 |
|
|
| 2.48 |
|
Distribution |
|
| 2.57 |
|
|
| 2.76 |
|
|
| 2.76 |
|
Storage |
|
| 1.89 |
|
|
| 1.79 |
|
|
| 1.59 |
|
General and other |
|
| 3.89 |
|
|
| 3.85 |
|
|
| 4.35 |
|
Virginia Power |
|
|
|
|
|
|
|
|
| |||
Generation |
|
| 2.84 |
|
|
| 2.69 |
|
|
| 2.52 |
|
Transmission |
|
| 2.29 |
|
|
| 2.51 |
|
|
| 2.52 |
|
Distribution |
|
| 2.76 |
|
|
| 3.18 |
|
|
| 3.19 |
|
General and other |
|
| 4.78 |
|
|
| 5.08 |
|
|
| 5.09 |
|
Year Ended December 31, | 2019 | 2018 | 2017 | |||||||||
(percent) | ||||||||||||
Dominion Energy | ||||||||||||
Generation | 2.84 | 2.71 | 2.94 | |||||||||
Transmission | 2.47 | 2.54 | 2.55 | |||||||||
Distribution | 2.80 | 2.97 | 3.00 | |||||||||
Storage | 2.40 | 2.40 | 2.48 | |||||||||
General and other | 4.04 | 4.20 | 4.38 | |||||||||
Virginia Power | ||||||||||||
Generation | 2.94 | 2.71 | 2.94 | |||||||||
Transmission | 2.54 | 2.52 | 2.54 | |||||||||
Distribution | 3.14 | 3.31 | 3.32 | |||||||||
General and other | 4.40 | 4.52 | 4.68 | |||||||||
Dominion Energy Gas (1) | ||||||||||||
Transmission | 2.43 | 2.66 | 2.67 | |||||||||
Storage | 2.53 | 2.42 | 2.51 | |||||||||
General and other | 4.59 | 4.18 | 5.08 | |||||||||
In 2020, Virginia Power expects to receive an updated depreciation studyrates for its nuclear plants in the first
In January 2022, Dominion Energy revised the estimated useful life of its non-jurisdictional and certain nonregulated solar generation facilities to 35 years. This changerevision resulted in an annual decrease inof depreciation expense of $30$16 million ($2312 million
In 2017,the first quarter of 2022, Virginia Power revised the depreciation rates for its assets to reflect the results of a new depreciation study. ThisThe change resulted in an increase in annual depreciation expense of $40 million ($25 millionafter-tax)for 2017. Additionally, Dominion Energy revised the depreciable lives for its merchant generation assets, excluding Millstone, which resulted in a decrease in annual depreciation expense in Virginia Power’s Consolidated Statements of $26Income of $60 million ($1645 millionfor 2017.
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.
Capitalized costs of development wells and leaseholds are amortized on a$1.80$1.67 and $1.89$1.92 per mcfe in 20192022 and 2018,2021, 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 | 15-35 years | |||
General and other | 5-59 years |
Nuclear fuel used in electric generation is amortized over its estimated service life on aDominion Energy and Virginia PowerThe 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
The Companies evaluate whether or not recovery of itstheir regulatory assets through future rates is probable as well as whether a regulatory liability due to customers is probable and makesmake various assumptions in itstheir analyses. These analyses are generally based on:
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
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
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.
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 and Dominion Energy Gas reportreports accretion of AROs and depreciation on asset retirement costs associated with theirits natural gas pipeline and storage well assetspipelines of its distribution business as an adjustment to the related regulatory assets or liabilities when revenue is recoverable from customers for AROs. Dominion Energy and Virginia PowerThe 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, Dominion Energy and Virginia Powerthe 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
In determining realized gains and losses for debt securities, the cost basis of the security is based on the specific identification method.
Credit Impairment
The Companies periodically review their available-for-sale debt securities to determine whether a decline in fair value should be considered credit related. If a decline in the fair value of any available-for-sale debt security is determined to be credit related, the credit-related impairment is recorded to an allowance included in nuclear decommissioning trust funds in the Companies’ Consolidated Balance Sheets at the end of the reporting period, with such allowance for credit losses subject to reversal in subsequent evaluations.
Using information obtained from their nuclear decommissioning trust fixed-income investment managers, the Companies record in earnings, or defer as applicable for certain jurisdictions subject to cost-based regulation, any unrealized loss for a debt security when the manager intends to sell the debt security or it is more-likely-than-not that the manager will have to sell the debt security before recovery of its fair value up to its cost basis. If that is not the case, but the debt security is deemed to have experienced a credit loss, the Companies record the credit loss in earnings or defer as applicable for certain jurisdictions subject to cost-based regulation, with the remaining non-credit portion of the unrealized loss recorded in AOCI. Credit losses are evaluated primarily by considering the credit ratings of the issuer, prior instances of non-performance by the issuer and other factors
Equity Securities with Readily Determinable Fair Values
Equity securities with readily determinable fair values include securities held by Dominion Energy in rabbi trusts associated with certain deferred compensation plans and securities held by Dominion Energy and Virginia Powerthe Companies in the nuclear decommissioning trusts. Dominion Energy and Virginia Power The Companies
114
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, Dominion Energy and Virginia Power 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. Dominion Energy and Virginia Power 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 Virginia Power’sthe nuclear decommissioning trusts are recordeddeferred 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 merchantnonregulated 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 investments in debt securities and 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 securityinvestment 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 $19$14 million and $12$26 million at December 31, 20192022 and December 31, 2018,2021, respectively. Based on the average price of gas purchased during 20192022 and 2018,2021, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by $60$129 million and $87$74 million, respectively. As a result of the
In 2022, Dominion Energy Gas
Goodwill
Dominion Energy Gas.
New Accounting Standards
Debt with Conversion Options and Contracts in an Entity’s Own Equity
In May 2014,August 2020, the FASB issued revised accounting guidance for revenue recognitiondebt 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 contracts with customers.the diluted EPS calculation for a contract that may be settled in stock or cash. The Companies adopted this revised accounting guidance became effective for Dominion Energy’s interim and annual reporting periods beginning January 1, 2018 using the modified retrospective method.2022. Upon the adoption, of the standard, Dominion Energy and Dominion Energy Gas recordedapplied the cumulative-effect of a change in accounting principle of $3 million to retained earnings and membership interests, respectively, and to establish a contract asset related to changes in the timing of revenue recognition for three existing contracts with customers at DETI.
115
retrospective approach which requires lessees and lessorscontinued to recognize and measure leases atapply the date of adoption. Under this approach, the Companies utilized the transition practical expedientif-converted method 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. Incalculate diluted EPS in connection with the adoption of this revised accounting guidance, Dominion Energy, Virginia Power and Dominion Energy Gas recorded $504 million, $209 million and $64 million, respectively, of offsettingright-of-useassets and liabilities for operating leases in effect at the adoption date. As a result of the Dominion Energy Gas Restructuring, $25 million of suchright-of-useassets and liabilities for operating leases recorded
NOTE 3. Acquisitions And Dispositions
Disposition of SCANA
In January 2019,July 2020, Dominion Energy issued 95.6 million sharesentered into an agreement with BHE with a total value of approximately $10 billion, comprised of approximately $4.0 billion of cash consideration (subject to customary closing adjustments) plus the assumption of long-term debt, to sell substantially all of its gas transmission and storage operations, including processing assets, as well as noncontrolling partnership interests in Iroquois, JAX LNG and White River Hub and a controlling interest in Cove Point (consisting of 100% of the general partner interest and 25% of the total limited partner interests). The agreement provides that Dominion Energy common stock, valuedretains the assets and obligations of the pension and other postretirement employee benefit plans associated with the operations included in the transaction and relating to services provided through closing. In October 2020, pursuant to a provision in the agreement with BHE, Dominion Energy elected to exclude the Q-Pipe Group and certain other affiliated entities from the transaction as approval under the Hart-Scott-Rodino Act had not been obtained by mid-September 2020. Concurrently in October 2020, Dominion Energy and BHE entered into a separate agreement under which Dominion Energy would sell the Q-Pipe Group and certain other affiliated entities to BHE for cash consideration of $1.3 billion and the assumption of related long-term debt.
In November 2020, Dominion Energy completed the GT&S Transaction and received cash proceeds of $2.7 billion. This transaction was structured as an asset sale for tax purposes. Dominion Energy retained a 50% noncontrolling interest in Cove Point that is accounted for as an equity method investment upon closing of the GT&S Transaction as Dominion Energy has the ability to exercise significant influence over, but not control, Cove Point. The retained 50% noncontrolling interest in Cove Point was recognized at $6.8its initial fair value of $2.8 billion representing 0.6690on the date of close estimated using an income approach and a market approach. The valuation is considered a Level 3 fair value measurement due to the use of significant judgment and unobservable inputs, including projected timing and amount of future cash flows and a discount rate reflecting risks inherent in the future cash flows and market prices. Upon closing the GT&S Transaction, Dominion Energy recognized a gain of $127 million (net of a share$1.4 billion write-off of goodwill and a $222 million closing adjustment paid to BHE in December 2020) and an associated tax expense of $336 million, presented in net income (loss) from discontinued operations including noncontrolling interest in Dominion Energy’s Consolidated Statements of Income.
In connection with closing of the GT&S Transaction, Dominion Energy common stockand 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 each share of SCANA common stock, in connectionup to 24 months after closing, subsequently extended through June 2023 for certain services. In addition, BHE provided certain administrative services to Dominion Energy through December 2022. Dominion Energy recorded $20 million, $21 million and $4 million associated with the transition services 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 SCANA Combination. SCANA, through its regulated subsidiaries, is primarily engagedQ-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 generation, transmissiontransaction and distributionrelating to services provided through closing.
In December 2021, Dominion Energy completed the sale of electricitythe 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 central, southernnet proceeds from the sale to repay all outstanding balances under the July 2021 term loan agreement and southwestern portionsterminated the term loan agreement. In 2022, Dominion Energy recognized a gain of South Carolina and$27 million ($20 million after-tax) in discontinued operations in its Consolidated Statements of Income associated with the distributionfinalization of natural gas in North Carolina and South Carolina. working capital adjustments.
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In addition, atconnection with the closing of the SCANA Combination, SCANA
The operations included in both the GT&S Transaction and the Q-Pipe Group are presented in discontinued operations effective July 2020. As a result, 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 discontinued operations. See Note 9 for additional information regarding Dominion Energy’s equity method investment in Cove Point.
The following table represents selected information regarding the results of operations, which were 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 |
|
GT&S Transaction includes a loss of $237 million ($178 million after-tax) recorded in 2020 associated with cash flow hedges of debt-related items that were determined to be probable of not occurring. | ||||||||
Capital expenditures and significant noncash items relating to the SCANA Merger Approval Order, DESC committeddisposal 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 |
|
In October 2020, Dominion Energy settled various derivatives related to, excludingbut not included in, the GT&S Transaction for a payment of $165 million.
117
Sale of Hope
In February 2022, Dominion Energy entered into an agreement to sell 100% of the equity interests in Hope to Ullico for $690 million of cash consideration, subject to customary closing adjustments, 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 rate recovery $2.4 billionthe West Virginia Commission. The sale was treated as a stock sale for tax purposes.
In connection with closing, Dominion Energy recognized a pre-tax gain of costs$14 million, inclusive of customary closing adjustments, (net of $110 million write-off of goodwill which was not deductible for tax purposes) in losses (gains) on sales of assets in its Consolidated Statements of Income. The transaction resulted in an after-tax loss of $84 million. Upon meeting the classification as held for sale in the first quarter of 2022 and through the second quarter of 2022, Dominion Energy had recorded charges of $90 million in deferred 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 additional information. In addition, a curtailment 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.
Sale of Kewaunee
In May 2021, Dominion Energy entered into an agreement to sell 100% of the equity interests in Dominion Energy Kewaunee, Inc. to EnergySolutions, including the transfer of all decommissioning obligations associated with Kewaunee, which ceased operations in 2013. The sale closed in June 2022 following approval from the Wisconsin Commission in May 2022 and NRC approval of a requested 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 Wisconsin regulatory conditions agreed to by Dominion Energy upon its acquisition of Kewaunee, including the return of any excess decommissioning funds to WPSC and WP&L customers following completion of all decommissioning activities.
In 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.
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 | ||
Twelve Months Ended December 31, | ||||||||
2019 (1) | 2018 (1) | |||||||
(millions, except EPS) | ||||||||
Operating Revenue | $ | 17,579 | $ | 17,505 | ||||
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 | ||||
Completed Acquisition Date | Seller | Number of Projects | Project Location | Project Name(s) | Initial Acquisition (millions) (1) | Project Cost (millions) (2) | Date of Commercial Operations | MW Capacity | ||||||||||||||||||||||||
February 2017 | Community Energy Solar, LLC | 1 | Virginia | Amazon Solar Farm Virginia—Southhampton | $ | 29 | $ | 205 | December 2017 | 100 | ||||||||||||||||||||||
March 2017 | Solar Frontier Americas Holding LLC | 1 | (3) | California | Midway II | 77 | 78 | June 2017 | 30 | |||||||||||||||||||||||
May 2017 | Cypress Creek Renewables, LLC | 1 | North Carolina | IS37 | 154 | 160 | June 2017 | 79 | ||||||||||||||||||||||||
June 2017 | Hecate Energy Virginia C&C LLC | 1 | Virginia | Clarke County | 16 | 16 | August 2017 | 10 | ||||||||||||||||||||||||
June 2017 | Strata Solar Development, LLC/Moorings Farm 2 Holdco, LLC | 2 | North Carolina | Fremont, Moorings 2 | 20 | 20 | November 2017 | 10 | ||||||||||||||||||||||||
September 2017 | Hecate Energy Virginia C&C LLC | 1 | Virginia | Cherrydale | 40 | 41 | November 2017 | 20 | ||||||||||||||||||||||||
October 2017 | Strata Solar Development, LLC | 2 | North Carolina | Clipperton, Pikeville | 20 | 21 | November 2017 | 10 | ||||||||||||||||||||||||
118
Period Ended November 6, 2019 | Year Ended December 31, 2018 | Year Ended December 31, 2017 | ||||||||||
(millions) | ||||||||||||
Operating revenue | $ | 594 | $ | 729 | $ | 728 | ||||||
Depreciation and amortization | 73 | 76 | 71 | |||||||||
Other operating expenses | 399 | 444 | 428 | |||||||||
Other income | 61 | 72 | 50 | |||||||||
Interest and related charges | 33 | 37 | 33 | |||||||||
Income tax expense | 26 | 53 | 86 | |||||||||
Net income from discontinued operations | 124 | 191 | 160 | |||||||||
Period Ended November 6, 2019 | Year Ended December 31, 2018 | Year Ended December 31, 2017 | ||||||||||
(millions) | ||||||||||||
Capital expenditures | $ | 299 | $ | 352 | $ | 348 | ||||||
Significant noncash items : | ||||||||||||
Charge related to a voluntary retirement program | 20 | — | — | |||||||||
Accrued capital expenditures | 2 | 5 | 8 | |||||||||
Period Ended November 6, 2019 | Year Ended December 31, 2018 | Year Ended December 31, 2017 | ||||||||||
(millions) | ||||||||||||
Operating revenue | $ | 125 | $ | 220 | $ | 114 | ||||||
Depreciation and amortization | 4 | 15 | 15 | |||||||||
Impairment of assets and related charges | — | 219 | — | |||||||||
Other operating expenses | 97 | 206 | 91 | |||||||||
Income tax expense (benefit) | 7 | (53 | ) | 5 | ||||||||
Net income (loss) from discontinued operations | $ | 17 | $ | (167 | ) | $ | 3 | |||||
Period Ended November 6, 2019 | Year Ended December 31, 2018 | Year Ended December 31, 2017 | ||||||||||
(millions) | ||||||||||||
Capital expenditures | $ | 11 | $ | 6 | $ | 8 | ||||||
Significant noncash items : | ||||||||||||
Impairment of assets and related charges | — | (219 | ) | — | ||||||||
NOTE 4. Operating Revenue
The Companies’ operating revenue subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, 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, | 2019 | 2018 | ||||||
(millions) | ||||||||
Dominion Energy | ||||||||
Regulated electric sales: | ||||||||
Residential | $ | 4,325 | $ | 3,413 | ||||
Commercial | 3,219 | 2,503 | ||||||
Industrial | 683 | 490 | ||||||
Government and other retail | 873 | 854 | ||||||
Wholesale | 176 | 137 | ||||||
Nonregulated electric sales | 926 | 1,294 | ||||||
Regulated gas sales: | ||||||||
Residential | 1,343 | 818 | ||||||
Commercial | 457 | 221 | ||||||
Other | 117 | 36 | ||||||
Nonregulated gas sales | 496 | 214 | ||||||
Regulated gas transportation and storage: | ||||||||
FERC-regulated | 1,057 | 1,091 | ||||||
State-regulated | 742 | 640 | ||||||
Nonregulated gas transportation and storage | 676 | 442 | ||||||
Other regulated revenues | 259 | 179 | ||||||
Other nonregulated revenues (1)(2) | 415 | 563 | ||||||
Total operating revenue from contracts with customers | 15,764 | 12,895 | ||||||
Other revenues (2)(3) | 808 | 471 | ||||||
Total operating revenue | $ | 16,572 | $ | 13,366 | ||||
Virginia Power | ||||||||
Regulated electric sales: | ||||||||
Residential | $ | 3,657 | $ | 3,413 | ||||
Commercial | 2,712 | 2,503 | ||||||
Industrial | 455 | 490 | ||||||
Government and other retail | 823 | 854 | ||||||
Wholesale | 128 | 137 | ||||||
Other regulated revenues | 190 | 132 | ||||||
Other nonregulated revenues (1)(2) | 71 | 55 | ||||||
Total operating revenue from contracts with customers | 8,036 | 7,584 | ||||||
Other revenues (1)(3) | 72 | 35 | ||||||
Total operating revenue | $ | 8,108 | $ | 7,619 | ||||
Dominion Energy Gas | ||||||||
Regulated gas sales—wholesale | $ | 9 | $ | 25 | ||||
Nonregulated gas sales (1) | 6 | 7 | ||||||
Regulated gas transportation and storage | 1,300 | 1,249 | ||||||
Nonregulated gas transportation and storage | 676 | 442 | ||||||
Management service revenue (1) | 162 | 257 | ||||||
Other regulated revenues (1 )(2 ) | 7 | 19 | ||||||
Other nonregulated revenues (1 )(2 ) | 5 | 3 | ||||||
Total operating revenue from contracts with customers | 2,165 | 2,002 | ||||||
Other revenues | 4 | (6 | ) | |||||
Total operating revenue | $ | 2,169 | $ | 1,996 | ||||
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 the Companies expectDominion Energy expects to recognize this revenue. These revenues relate to contracts containing fixed prices where the CompaniesDominion Energy will earn the associated revenue over time as they standit 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 the Companies electDominion Energy elects to recognize revenue in the amount they haveit 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, 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | Thereafter | Total | |||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||
Dominion Energy | $ | 1,569 | $ | 1,470 | $ | 1,363 | $ | 1,216 | $ | 1,104 | $ | 12,519 | $ | 19,241 | ||||||||||||||
Virginia Power | 3 | 1 | — | — | — | — | 4 | |||||||||||||||||||||
Dominion Energy Gas | 1,723 | 1,624 | 1,495 | 1,325 | 1,185 | 12,783 | 20,135 | |||||||||||||||||||||
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, 20192022 and 2018,2021, Dominion Energy’s contract liability balances were $123$150 million and $106$124 million, respectively. At December 31, 20192022 and 2018,2021, Virginia Power’s contract liability balances were $24$39 million and $22 million, respectively. At December 31, 2019 and 2018, Dominion Energy Gas’ contract liability balances were $20 million and $28$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 both the years ended December 31, 20192022 and 2018,2021, Dominion Energy recognized revenue of $94$118 million and $124 million from the beginning contract liability balance. During the years ended December 31, 20192022 and 2018,$22$33 million and $25$36 million, respectively, from the beginning contract liability balance. For years ended December 31, 2019 and 2018, Dominion Energy Gas recognized revenue of $8 million and $3 million, respectively, from the beginning contract liability balance.
119
Year Ended December 31 | 2017 | |||
(millions) | ||||
Dominion Energy | ||||
Electric sales: | ||||
Regulated | $ | 7,383 | ||
Nonregulated | 1,429 | |||
Gas sales: | ||||
Regulated | 1,067 | |||
Nonregulated | 457 | |||
Gas transportation and storage | 1,786 | |||
Other | 464 | |||
Total operating revenue | $ | 12,586 | ||
Virginia Power | ||||
Regulated electric sales | $ | 7,383 | ||
Other | 173 | |||
Total operating revenue | $ | 7,556 | ||
Dominion Energy Gas | ||||
Gas sales: | ||||
Regulated | $ | 6 | ||
Nonregulated | 6 | |||
Gas transportation and storage | 1,291 | |||
Other | 220 | |||
Total operating revenue | $ | 1,523 | ||
NOTE 5. Income Taxes
Judgment and the use of estimates are required in developing the provision for income taxes and reporting of
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 broad range15% alternative minimum tax on GAAP net income, as adjusted for certain items, of tax reform provisions affecting the Companies as discussed in Note 2. The 2017 Tax Reform Act reduced the corporate income tax rate from 35% to 21%corporations greater than $1 billion for tax years beginning after December 31, 2017. At2022. The IRA did not impact the datemeasurement of enactment,the Companies’ deferred income taxes or change the assessment of the realizability of deferred tax assetsassets. The Companies continue to monitor and liabilities were remeasured based uponevaluate the new 21% enacted tax rate expected to apply when temporary differences are realized or settled. The specific provisions related to regulated public utilitiesimpacts of the IRA, including changes in interpretations, if any, as guidance is issued and finalized.
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, generally allowdeductions for the continued deductibility ofnet interest expense changedare 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 tax depreciationcalculation of certain property acquired after September 27, 2017,adjusted taxable income is defined similarly to EBIT (earnings before interest and continued certain rate normalization requirements for accelerated depreciation benefits.
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 refundreturn to customers and were recorded as either an increase to a regulatory asset or liability. The 2017 Tax Reform Act included provisions that stipulate how these excess deferred
Continuing Operations
Details of income tax expense for continuing operations including noncontrolling interests were as follows:
|
| Dominion Energy |
|
| Virginia Power |
| ||||||||||||||||||
Year Ended December 31, |
| 2022 |
|
| 2021 |
|
| 2020 |
|
| 2022 |
|
| 2021 |
|
| 2020 |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Current: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Federal |
| $ | 7 |
|
| $ | (162 | ) |
| $ | (314 | ) |
| $ | 17 |
|
| $ | 67 |
|
| $ | 364 |
|
State |
|
| 46 |
|
|
| 45 |
|
|
| (81 | ) |
|
| (17 | ) |
|
| (13 | ) |
|
| 71 |
|
Total current expense (benefit) |
|
| 53 |
|
|
| (117 | ) |
|
| (395 | ) |
|
| — |
|
|
| 54 |
|
|
| 435 |
|
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Federal |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Taxes before operating loss |
|
| 62 |
|
|
| 151 |
|
|
| 12 |
|
|
| 212 |
|
|
| 145 |
|
|
| (226 | ) |
Tax utilization expense of operating |
|
| 36 |
|
|
| 43 |
|
|
| 44 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Investment tax credits |
|
| (129 | ) |
|
| 250 |
|
|
| 311 |
|
|
| (148 | ) |
|
| (39 | ) |
|
| (27 | ) |
State |
|
| 32 |
|
|
| (19 | ) |
|
| 72 |
|
|
| 112 |
|
|
| 118 |
|
|
| 7 |
|
Total deferred expense (benefit) |
|
| 1 |
|
|
| 425 |
|
|
| 439 |
|
|
| 176 |
|
|
| 224 |
|
|
| (246 | ) |
Investment tax credit-gross deferral |
|
| 18 |
|
|
| 121 |
|
|
| 42 |
|
|
| 18 |
|
|
| 121 |
|
|
| 42 |
|
Investment tax credit-amortization |
|
| (4 | ) |
|
| (4 | ) |
|
| (3 | ) |
|
| (3 | ) |
|
| (2 | ) |
|
| (2 | ) |
Total income tax expense |
| $ | 68 |
|
| $ | 425 |
|
| $ | 83 |
|
| $ | 191 |
|
| $ | 397 |
|
| $ | 229 |
|
Dominion Energy | Virginia Power | Dominion Energy Gas | ||||||||||||||||||||||||||||||||||
Year Ended December 31, | 2019 | 2018 | 2017 | 2019 | 2018 | 2017 | 2019 | 2018 | 2017 | |||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||||||
Current: | ||||||||||||||||||||||||||||||||||||
Federal | $ | 32 | $ | (45 | ) | $ | (1 | ) | $ | 286 | $ | 36 | $ | 432 | $ | 130 | $ | (227 | ) | $ | 75 | |||||||||||||||
State | 103 | 108 | (26 | ) | 58 | 40 | 73 | 17 | 31 | 13 | ||||||||||||||||||||||||||
Total current expense (benefit) | 135 | 63 | (27 | ) | 344 | 76 | 505 | 147 | (196 | ) | 88 | |||||||||||||||||||||||||
Deferred: | ||||||||||||||||||||||||||||||||||||
Federal | ||||||||||||||||||||||||||||||||||||
2017 Tax Reform Act impact (1) | — | 46 | (851 | ) | — | 21 | (93 | ) | — | (6 | ) | (246 | ) | |||||||||||||||||||||||
Taxes before operating loss carryforwards, investment tax credits and tax reform | 182 | 436 | 739 | (128 | ) | 199 | 319 | (36 | ) | 343 | 88 | |||||||||||||||||||||||||
Tax utilization expense (benefit) of operating loss carryforwards | 119 | 92 | 174 | — | — | 4 | — | — | — | |||||||||||||||||||||||||||
Investment tax credits | (51 | ) | (56 | ) | (200 | ) | (34 | ) | (51 | ) | (23 | ) | — | — | — | |||||||||||||||||||||
State | (93 | ) | (1 | ) | 132 | 22 | 55 | 59 | (10 | ) | (17 | ) | 5 | |||||||||||||||||||||||
Total deferred expense (benefit) | 157 | 517 | (6 | ) | (140 | ) | 224 | 266 | (46 | ) | 320 | (153 | ) | |||||||||||||||||||||||
Investment tax credit-gross deferral | 62 | 2 | 5 | 62 | 2 | 5 | — | — | — | |||||||||||||||||||||||||||
Investment tax credit-amortization | (3 | ) | (2 | ) | (2 | ) | (2 | ) | (2 | ) | (2 | ) | — | — | — | |||||||||||||||||||||
Total income tax expense (benefit) | $ | 351 | $ | 580 | $ | (30 | ) | $ | 264 | $ | 300 | $ | 774 | $ | 101 | $ | 124 | $ | (65 | ) | ||||||||||||||||
In 2021, Dominion Energy’s current and deferred income taxes are recorded atreflect a benefit from continuing operations as the new 21% rate.
In 2020, Dominion Energy’s current income taxes reflect a benefit from continuing operations as the transaction were also chargedincome 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 common shareholders’ equity.offset a portion of the federal tax gain on the sale. In total, the taxes recordedaddition, an $18 million income tax benefit is reflected in common shareholders’ equity resulting from this transaction were $215 million.
120
Discontinued Operations
Income tax expense as a result of(benefit) reflected in discontinued operations is $8 million, $188 million, and $(204) million for the reversal of deferred taxes upon the sale of its interest in Blue Raceryears ended December 31, 2022, 2021 and Fairless and Manchester. Dominion Energy’s current federal2020, respectively. 2021 income taxes primarily include the recognition of a $47$14 million benefit related to a carryback claim for specified liability losses involving prior tax years.
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, |
| 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 |
| % |
Dominion Energy | Virginia Power | Dominion Energy Gas | ||||||||||||||||||||||||||||||||||
Year Ended December 31, | 2019 | 2018 | 2017 | 2019 | 2018 | 2017 | 2019 | 2018 | 2017 | |||||||||||||||||||||||||||
U.S. statutory rate | 21.0 | % | 21.0 | % | 35.0 | % | 21.0 | % | 21.0 | % | 35.0 | % | 21.0 | % | 21.0 | % | 35.0 | % | ||||||||||||||||||
Increases (reductions) resulting from: | ||||||||||||||||||||||||||||||||||||
State taxes, net of federal benefit | 1.3 | 3.0 | 2.0 | 4.5 | 4.7 | 3.7 | 2.5 | 3.2 | 2.6 | |||||||||||||||||||||||||||
Investment tax credits | (5.7 | ) | (1.9 | ) | (6.3 | ) | (2.9 | ) | (3.5 | ) | (0.8 | ) | — | — | — | |||||||||||||||||||||
Production tax credits | (1.1 | ) | (0.7 | ) | (0.7 | ) | (0.7 | ) | (0.7 | ) | (0.4 | ) | — | — | — | |||||||||||||||||||||
Valuation allowances | 0.1 | 0.3 | 0.2 | — | — | — | (0.2 | ) | — | 0.3 | ||||||||||||||||||||||||||
Reversal of excess deferred income taxes | (2.0 | ) | (2.0 | ) | — | (3.1 | ) | (3.2 | ) | — | (0.8 | ) | (0.6 | ) | — | |||||||||||||||||||||
Federal legislative change | — | 1.5 | (27.5 | ) | — | 1.3 | (4.0 | ) | — | (0.5 | ) | (41.0 | ) | |||||||||||||||||||||||
State legislative change | — | (0.6 | ) | — | — | — | — | — | (2.0 | ) | (0.7 | ) | ||||||||||||||||||||||||
Write-off of regulatory assets | 10.9 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
Change in tax status | (2.8 | ) | — | — | — | — | — | (6.0 | ) | — | — | |||||||||||||||||||||||||
AFUDC—equity | (1.8 | ) | (0.8 | ) | (1.4 | ) | — | (0.5 | ) | (0.6 | ) | (0.5 | ) | (0.3 | ) | (0.9 | ) | |||||||||||||||||||
Employee stock ownership plan deduction | (0.7 | ) | (0.4 | ) | (0.6 | ) | — | — | — | — | — | — | ||||||||||||||||||||||||
Other, net | 1.1 | (0.9 | ) | (1.7 | ) | (0.2 | ) | (0.1 | ) | 0.6 | (3.4 | ) (1) | (4.4 | ) (1) | (6.0 | ) (1) | ||||||||||||||||||||
Effective tax rate | 20.3 | % | 18.5 | % | (1.0 | )% | 18.6 | % | 19.0 | % | 33.5 | % | 12.6 | % | 16.4 | % | (10.7 | )% | ||||||||||||||||||
As described in Note 3, Dominion Energy sold 100% |
In December 2021, unrecognized tax benefits related to several state uncertain tax positions acquired in satisfactionthe 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 this commitment. Dominion Energy’sthese uncertain tax positions decreased income tax expense by $38 million. In addition, the Companies’ effective tax rate also reflects the changes in consolidated state income taxes resulting from the SCANA Combination.
Dominion Energy’s 2020 effective tax rate reflects an income tax expensebenefit of $45 million associated with the remeasurement of thisconsolidated state deferred taxes with the classification of gas transmission and storage operations as held for sale. In addition, Dominion Energy’s effective tax asset. The application of these proposed regulations at Dominion Energy Gas had no impact onrate reflects an income tax expense asof $55 million attributable to the changesnoncontrolling interest primarily associated with the impairment of non-wholly-owned nonregulated solar facilities held in and remeasurement of, deferred tax liabilities increased regulatory liabilities by $35 million, of which $23 million is reflectedpartnerships discussed in noncurrent liabilities of discontinued operations on the Consolidated Balance Sheets. 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 Gas similar changes in estimates decreased income tax expense by $5 million and regulatory liabilities by $8 million. In Dominion Energy Gas’ discontinued operations, similar changes in estimates increased income tax expense by $8 million, which is reflected in income tax expense from continuing operations in the Consolidated Statements of Income, and regulatory liabilities $10 million, which are reflected in noncurrent liabilities of discontinued operations on the Consolidated Balance Sheets. These changes also impacted Dominion Energy. In addition, Dominion Energy and Dominion Energy Gas’ effective tax rates reflect the impacts of a state legislative change enacted in the second quarter of 2018 that was retroactive to January 1, 2018.
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 | Dominion Energy Gas | ||||||||||||||||||||||
| At December 31, | 2019 | 2018 | 2019 | 2018 | 2019 | 2018 | ||||||||||||||||||
(millions) | ||||||||||||||||||||||||
Deferred income taxes: | ||||||||||||||||||||||||
Total deferred income tax assets | $ | 3,736 | $ | 2,748 | $ | 1,207 | $ 1,054 | $ 206 | $ | 296 | ||||||||||||||
Total deferred income tax liabilities | 9,883 | 7,813 | 4,058 | 4,020 | 1,494 | 1,626 | ||||||||||||||||||
Total net deferred income tax liabilities | $ | 6,147 | $ | 5,065 | $ | 2,851 | $2,966 | $1,288 | $ | 1,330 | ||||||||||||||
Total deferred income taxes: | ||||||||||||||||||||||||
Plant and equipment, primarily depreciation method and basis differences | $ | 6,616 | $ | 4,933 | $ | 3,359 | $ | 3,367 | $ | 742 | $ | 671 | ||||||||||||
Excess deferred income taxes | (1,306 | ) | (993 | ) | (672 | ) | (678 | ) | (149 | ) | (156 | ) | ||||||||||||
Unrecovered NND Project costs | 553 | — | — | — | — | — | ||||||||||||||||||
DESC rate refund | (169 | ) | — | — | — | — | — | |||||||||||||||||
Toshiba Settlement | (219 | ) | — | — | — | — | — | |||||||||||||||||
Nuclear decommissioning | 909 | 815 | 290 | 273 | — | — | ||||||||||||||||||
Deferred state income taxes | 863 | 626 | 302 | 284 | 199 | 203 | ||||||||||||||||||
Federal benefit of deferred state income taxes | (184 | ) | (132 | ) | (63 | ) | (60 | ) | (42 | ) | (43 | ) | ||||||||||||
Deferred fuel, purchased energy and gas costs | 30 | 60 | 1 | 59 | — | (1 | ) | |||||||||||||||||
Pension benefits | 174 | 81 | (153 | ) | (132 | ) | 154 | 134 | ||||||||||||||||
Other postretirement benefits | (37 | ) | (5 | ) | 62 | 55 | (6 | ) | (3 | ) | ||||||||||||||
Loss and credit carryforwards | (1,832 | ) | (1,546 | ) | (280 | ) | (183 | ) | (1 | ) | (5 | ) | ||||||||||||
Valuation allowances | 161 | 158 | 5 | 5 | 1 | 6 | ||||||||||||||||||
Partnership basis differences | 823 | 1,135 | — | — | 423 | 570 | ||||||||||||||||||
Other | (235 | ) | (67 | ) | — | (24 | ) | (33 | ) | (46 | ) | |||||||||||||
Total net deferred income tax liabilities | $ | 6,147 | $ | 5,065 | $ | 2,851 | $2,966 | $1,288 | $ | 1,330 | ||||||||||||||
Deferred Investment Tax Credits – Regulated Operations | 130 | 51 | 111 | 51 | — | — | ||||||||||||||||||
Total Deferred Taxes and Deferred Investment Tax Credits | $ | 6,277 | $ | 5,116 | $ | 2,962 | $3,017 | $1,288 | $ | 1,330 | ||||||||||||||
At December 31, 2019,2022, Dominion Energy had the following deductible loss and credit carryforwards:
Deductible Amount | Deferred Tax Asset | Valuation Allowance | Expiration Period | |||||||||||||
(millions) | ||||||||||||||||
Federal losses | $ 1,361 | $ | 286 | $ — | 2037 | |||||||||||
Federal investment credits | — | 922 | — | 2035-2039 | ||||||||||||
Federal production credits | — | 126 | — | 2035-2039 | ||||||||||||
Other federal credits | — | 40 | — | 2035-2038 | ||||||||||||
State losses | 3,074 | 173 | (57 | ) | 2020-2038 | |||||||||||
State minimum tax credits | — | 165 | — | No expiration | ||||||||||||
State investment and other credits | — | 144 | (98 | ) | 2020-2031 | |||||||||||
Total | $4,435 | $ | 1,856 | $(155) | ||||||||||||
|
| Deductible |
|
| Deferred |
|
| Valuation |
|
| Expiration | |||
|
| Amount |
|
| Tax Asset |
|
| Allowance |
|
| Period | |||
(millions) |
|
|
|
|
|
|
|
|
|
|
| |||
Federal losses |
| $ | 794 |
|
| $ | 167 |
|
| $ | — |
|
| 2037 |
Federal investment credits |
| — |
|
|
| 874 |
|
| — |
|
| 2036-2042 | ||
Federal production and other credits |
| — |
|
|
| 84 |
|
| — |
|
| 2036-2042 | ||
State losses |
|
| 5,711 |
|
|
| 306 |
|
|
| (51 | ) |
| 2023-2042 |
State minimum tax credits |
| — |
|
|
| 271 |
|
| — |
|
| No expiration | ||
State investment and other credits |
| — |
|
|
| 128 |
|
|
| (87 | ) |
| 2023-2032 | |
Total |
| $ | 6,505 |
|
| $ | 1,830 |
|
| $ | (138 | ) |
|
|
122
At December 31, 2019,2022, 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 Amount | Deferred Tax Asset | Valuation Allowance | Expiration Period | |||||||||||||
(millions) | ||||||||||||||||
Federal investment credits | $ — | $ 213 | $ — | 2035-2039 | ||||||||||||
Federal production and other credits | — | 58 | — | 2035-2039 | ||||||||||||
State investment credits | — | 9 | (5 | ) | 2024 | |||||||||||
Total | $ — | $ 280 | $ (5 | ) | ||||||||||||
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 |
|
| |||||||||
|
| 2022 |
|
| 2021 |
|
| 2020 |
|
| |||
(millions) |
|
|
|
|
|
|
|
|
|
| |||
Beginning balance |
| $ | 128 |
|
| $ | 167 |
|
| $ | 175 |
|
|
Increases-prior period positions |
|
| 8 |
|
|
| 48 |
|
|
| 18 |
|
|
Decreases-prior period positions |
|
| (8 | ) |
|
| (59 | ) |
|
| (19 | ) |
|
Increases-current period positions |
|
| 2 |
|
|
| 2 |
|
|
| 1 |
|
|
Settlements with tax authorities |
|
| (3 | ) |
|
| (26 | ) |
|
| — |
|
|
Expiration of statutes of limitations |
|
| (10 | ) |
|
| (4 | ) |
|
| (8 | ) |
|
Ending balance |
| $ | 117 |
|
| $ | 128 |
|
| $ | 167 |
|
|
Dominion Energy | Virginia Power | Dominion Energy Gas | ||||||||||||||||||||||||||||||||||
2019 | 2018 | 2017 | 2019 | 2018 | 2017 | 2019 | 2018 | 2017 | ||||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||||||
Balance at January 1 | $ | 44 | $ | 38 | $ | 64 | $ | 2 | $ | 4 | $ | 13 | $2 | $ | 2 | $9 | ||||||||||||||||||||
Acquired unrecognized tax benefits | 129 | (1) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||
Increases-prior period positions | — | 10 | 1 | — | — | — | — | — | — | |||||||||||||||||||||||||||
Decreases-prior period positions | — | — | (9 | ) | — | — | (1 | ) | — | — | — | |||||||||||||||||||||||||
Increases-current period positions | 9 | 10 | 5 | — | — | — | — | — | — | |||||||||||||||||||||||||||
Settlements with tax authorities | (7 | ) | (6 | ) | (23 | ) | (2 | ) | (1 | ) | (8 | ) | — | — | (7 | ) | ||||||||||||||||||||
Expiration of statutes of limitations | — | (8 | ) | — | — | (1 | ) | — | — | — | — | |||||||||||||||||||||||||
Balance at December 31 | $ | 175 | $ | 44 | $ | 38 | $ | — | $ | 2 | $ | 4 | $2 | $ | 2 | $2 | ||||||||||||||||||||
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 $141$64 million, $37$72 million and $31$140 million at December 31, 2019, 20182022, 2021 and 2017,2020, respectively. In discontinued operations, these unrecognized tax benefits were $33 million at both December 31, 2022 and 2021. For Dominion Energy, the change in these unrecognized tax benefits decreased income tax expense by $7 million, $34 million and $6 million in 2022, 2021 and 2020, respectively. For Dominion Energy,discontinued operations, the change in these unrecognized tax benefits increased income tax expense by $3 million and $5$5 million in 2019 and 2018, respectively, and decreased income tax expense by $9 million in 2017. For Virginia Power, these unrecognized tax benefits were less than $1 million, $2 million, and $3 million at December 31, 2019, 2018 and 2017, respectively. For Virginia Power, the change in these unrecognized tax benefits decreased income tax expense by $2 million in 2019 and 2018, respectively, and $6 million in 2017. For Dominion Energy Gas, these unrecognized tax benefits were $2 million, at December 31, 2019, 2018 and 2017, respectively. For Dominion Energy Gas, the change in these unrecognized tax benefits decreased income tax expense by less than $1 million in 2019 and 2018, respectively, and $5 million in 2017.
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. These claims are currently subject to IRS examination. With the exception of these claims, theThe IRS has completed its audit of tax years through 2018.2019. The statute of limitations has not yet expired for tax year 2014 and years after 2015.2018. Although Dominion Energy has not received a final letter indicating no changes to its taxable income for tax year 2018,years 2021 and 2020, no material adjustments are expected. The IRS examination of tax year 20192022 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 20202023 by up to $86$39 million for Dominion Energy and less than $1 million for Dominion Energy Gas.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 $23$26 million for Dominion Energy and less than $1 million for Dominion Energy Gas.
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 | |||
Pennsylvania | 2012 | |||
Connecticut | 2019 | |||
Virginia | 2019 | |||
Utah | 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
The Companies’ own nonperformance risk on their liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). Dominion Energy applies fair value measurements to certain assets and liabilities including commodity, interest rate, and foreign currency derivative instruments, and other investments including those held in nuclear decommissioning, Dominion Energy’s rabbi, and pension and other postretirement benefit plan trusts,are made in accordance with the requirementspolicies discussed above. Virginia Power applies fair
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 and financial options. The discounted cash flow model for forwards and futures calculates
The following table presents Dominion Energy’sthe Companies' quantitative information about Level 3 fair value measurements at December 31, 2019.2022. 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) | $ 13 | Discounted cash flow | Market price (per Dth) (3) | (1) - | — | |||||||||||||||
FTRs | 6 | Discounted cash flow | Market price (per MWh) (3) | (1) - 5 | 1 | |||||||||||||||
Total assets | $ 19 | |||||||||||||||||||
Liabilities | ||||||||||||||||||||
Physical and financial forwards: | ||||||||||||||||||||
Natural gas (2) | $ 43 | Discounted cash flow | Market price (per Dth) (3) | (2) - 4 | (1 | ) | ||||||||||||||
FTRs | 5 | Discounted cash flow | Market price (per MWh) (3) | (4) - 4 | — | |||||||||||||||
Physical options: | ||||||||||||||||||||
Natural gas | 8 | Option model | Market price (per Dth) (3) | 1 - 4 | 3 | |||||||||||||||
Price volatility (4) | 24% - 66% | 37 | % | |||||||||||||||||
Total liabilities | $ 56 | |||||||||||||||||||
Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:
Significant Unobservable | Position | Change to Input | Impact on Fair | |||||||||
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
In 2021, Dominion Energy recorded a liability of $30 million, the fair value of the guarantee at inception, associated with the guarantee agreement. The fair value was estimated using a discounted cash flow method and is considered a Level 3 fair value measurement due to the use of a significant unobservable input related to the interest rate differential between the interest rate charged on the guaranteed revolving credit facility and the estimated interest rate that would have been charged had the loan not been guaranteed.
In 2021, Dominion Energy recorded a charge of $16 million ($12 million after-tax) in impairment of assets and equipmentother charges in its Consolidated Statements of Income to adjust a corporate office building down to its estimated fair value, of $190 million. This charge was recorded in impairment of assets and related charges in Dominion Energy’s ConsolidatedStatements of Income(reflected intheCorporate and Other segment). The fair value of the property, plant and equipment was estimated using both an income approach and market approach.approach, of $26 million. 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.
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 and Dominion Energy Gas’the Companies' pension and other postretirement benefit plans are presented in Note 22.
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:
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
(millions) | ||||||||||||||||
December 31, 2019 | ||||||||||||||||
Assets | ||||||||||||||||
Derivatives: | ||||||||||||||||
Commodity | $ | — | $ | 55 | $ 19 | $ | 74 | |||||||||
Interest rate | — | 11 | — | 11 | ||||||||||||
Foreign currency | — | 8 | — | 8 | ||||||||||||
Investments (1) : | ||||||||||||||||
Equity securities: | ||||||||||||||||
U.S. | 4,195 | — | — | 4,195 | ||||||||||||
Fixed income: | ||||||||||||||||
Corporate debt instruments | — | 463 | — | 463 | ||||||||||||
Government securities | 473 | 719 | — | 1,192 | ||||||||||||
Cash equivalents and other | 19 | 1 | — | 20 | ||||||||||||
Total assets | $ | 4,687 | $ | 1,257 | $ 19 | $ | 5,963 | |||||||||
Liabilities | ||||||||||||||||
Derivatives: | ||||||||||||||||
Commodity | $ | — | $ | 75 | $ 56 | $ | 131 | |||||||||
Interest rate | — | 606 | — | 606 | ||||||||||||
Foreign currency | — | 3 | — | 3 | ||||||||||||
Total liabilities | $ | — | $ | 684 | $56 | $ | 740 | |||||||||
December 31, 2018 | ||||||||||||||||
Assets | ||||||||||||||||
Derivatives: | ||||||||||||||||
Commodity | $ | — | $ | 180 | $ 70 | $ | 250 | |||||||||
Interest rate | — | 18 | — | 18 | ||||||||||||
Foreign currency | — | 26 | — | 26 | ||||||||||||
Investments (1) : | ||||||||||||||||
Equity securities: | ||||||||||||||||
U.S. | 3,277 | — | — | 3,277 | ||||||||||||
Fixed income: | ||||||||||||||||
Corporate debt instruments | — | 431 | — | 431 | ||||||||||||
Government securities | 455 | 688 | — | 1,143 | ||||||||||||
Cash equivalents and other | 11 | — | — | 11 | ||||||||||||
Total assets | $ | 3,743 | $ | 1,343 | $ 70 | $ | 5,156 | |||||||||
Liabilities | ||||||||||||||||
Derivatives: | ||||||||||||||||
Commodity | $ | — | $ | 129 | $ 6 | $ | 135 | |||||||||
Interest rate | — | 142 | — | 142 | ||||||||||||
Foreign currency | — | 2 | — | 2 | ||||||||||||
Total liabilities | $ | — | $ | 273 | $ 6 | $ | 279 | |||||||||
|
| 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 |
|
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 |
| ||||||||||||||||||
|
| 2022 |
|
| 2021 |
|
| 2020 |
|
| 2022 |
|
| 2021 |
|
| 2020 |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Beginning balance |
| $ | 222 |
|
| $ | 103 |
|
| $ | (37 | ) |
| $ | 102 |
|
| $ | 103 |
|
| $ | (37 | ) |
Total realized and unrealized gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Included in earnings: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Operating Revenue |
|
| 2 |
|
|
| (9 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Electric fuel and other energy-related purchases |
|
| 444 |
|
|
| 10 |
|
|
| (33 | ) |
|
| 382 |
|
|
| 4 |
|
|
| (33 | ) |
Discontinued operations |
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Included in regulatory assets/liabilities |
|
| 183 |
|
|
| 119 |
|
|
| 140 |
|
|
| 102 |
|
|
| (1 | ) |
|
| 140 |
|
Settlements |
|
| (455 | ) |
|
| (10 | ) |
|
| 33 |
|
|
| (393 | ) |
|
| (4 | ) |
|
| 33 |
|
Purchases |
|
| 28 |
|
|
| — |
|
|
| — |
|
|
| 28 |
|
|
| — |
|
|
| — |
|
Sales |
|
| — |
|
|
| — |
|
|
| (1 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
Transfers out of Level 3 |
|
| (2 | ) |
|
| 9 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Ending balance |
| $ | 422 |
|
| $ | 222 |
|
| $ | 103 |
|
| $ | 221 |
|
| $ | 102 |
|
| $ | 103 |
|
2019 | 2018 | 2017 | ||||||||||
(millions) | ||||||||||||
Balance at January 1, | $ | 64 | $ | 150 | $ | 139 | ||||||
Total realized and unrealized gains (losses): | ||||||||||||
Included in earnings: | ||||||||||||
Operating Revenue | (1 | ) | (2 | ) | 3 | |||||||
Electric fuel and other energy-related purchases | (22 | ) | (15 | ) | (42 | ) | ||||||
Purchased gas | 2 | — | 1 | |||||||||
Included in other comprehensive income (loss) | — | 1 | (2 | ) | ||||||||
Included in regulatory assets/liabilities | (90 | ) | (44 | ) | 42 | |||||||
Settlements | 17 | (27 | ) | 6 | ||||||||
Purchases | (10 | ) | — | — | ||||||||
Sales | 6 | — | — | |||||||||
Transfers out of Level 3 | (3 | ) | 1 | 3 | ||||||||
Balance at December 31, | $ | (37 | ) | $ | 64 | $ | 150 | |||||
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date: | ||||||||||||
Operating Revenue | $ | — | $ | — | $ | 2 | ||||||
The following table presents Virginia Power’s quantitative information about Level 3 fair value measurements at December 31, 2019. 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) | $ 13 | Discounted cash flow | Market price (per Dth) (3) | (1) - 4 | — | |||||||||||||||
FTRs | 6 | Discounted cash flow | Market price (per MWh) (3) | (1) - 5 | 1 | |||||||||||||||
Total assets | $ 19 | |||||||||||||||||||
Liabilities | ||||||||||||||||||||
Physical and financial forwards: | ||||||||||||||||||||
Natural gas (2) | $ 43 | Discounted cash flow | Market price (per Dth) (3) | (2) - 4 | (1 | ) | ||||||||||||||
FTRs | 5 | Discounted cash flow | Market price (per MWh) (3) | (4) - 4 | — | |||||||||||||||
Physical options: | ||||||||||||||||||||
Natural gas | 8 | Option model | Market price (per Dth) (3) | 1 - 4 | 3 | |||||||||||||||
Price volatility (4) | 24%—66% | 37 | % | |||||||||||||||||
Total liabilities | $ 56 | |||||||||||||||||||
Inputs | Value Measurement | |||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
(millions) | ||||||||||||||||
December 31, 2019 | ||||||||||||||||
Assets | ||||||||||||||||
Derivatives: | ||||||||||||||||
Commodity | $ | — | $ 3 | $19 | $ | 22 | ||||||||||
Interest rate | — | 2 | — | 2 | ||||||||||||
Investments (1) : | ||||||||||||||||
Equity securities: | ||||||||||||||||
U.S. | 1,920 | — | — | 1,920 | ||||||||||||
Fixed income: | ||||||||||||||||
Corporate debt instruments | — | 256 | — | 256 | ||||||||||||
Government securities | 186 | 361 | — | 547 | ||||||||||||
Cash equivalents and other | — | 1 | — | 1 | ||||||||||||
Total assets | $ | 2,106 | $623 | $19 | $ | 2,748 | ||||||||||
Liabilities | ||||||||||||||||
Derivatives: | ||||||||||||||||
Commodity | $ | — | $ 47 | $56 | $ | 103 | ||||||||||
Interest rate | — | 363 | — | 363 | ||||||||||||
Total liabilities | $ | — | $410 | $56 | $ | 466 | ||||||||||
December 31, 2018 | ||||||||||||||||
Assets | ||||||||||||||||
Derivatives: | ||||||||||||||||
Commodity | $ | — | $ 24 | $66 | $ | 90 | ||||||||||
Interest rate | — | 3 | — | 3 | ||||||||||||
Investments (1) : | ||||||||||||||||
Equity securities: | ||||||||||||||||
U.S. | 1,476 | — | — | 1,476 | ||||||||||||
Fixed income: | ||||||||||||||||
Corporate debt instruments | — | 221 | — | 221 | ||||||||||||
Government securities | 164 | 343 | — | 507 | ||||||||||||
Total assets | $ | 1,640 | $591 | $66 | $ | 2,297 | ||||||||||
Liabilities | ||||||||||||||||
Derivatives: | ||||||||||||||||
Commodity | $ | — | $ 9 | $ 6 | $ | 15 | ||||||||||
Interest rate | — | 88 | — | 88 | ||||||||||||
Total liabilities | $ | — | $ 97 | $ 6 | $ | 103 | ||||||||||
2019 | 2018 | 2017 | ||||||||||
(millions) | ||||||||||||
Balance at January 1, | $ | 60 | $ | 147 | $ | 143 | ||||||
Total realized and unrealized gains (losses): | ||||||||||||
Included in earnings: | ||||||||||||
Electric fuel and other energy-related purchases | (22 | ) | (17 | ) | (43 | ) | ||||||
Included in regulatory assets/liabilities | (88 | ) | (45 | ) | 40 | |||||||
Settlements | 13 | (25 | ) | 7 | ||||||||
Balance at December 31, | $ | (37 | ) | $ | 60 | $ | 147 | |||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
(millions) | ||||||||||||||||
December 31, 2019 | ||||||||||||||||
Assets | ||||||||||||||||
Foreign currency | $ — | $8 | $ — | $8 | ||||||||||||
Total assets | $ — | $8 | $ — | $8 | ||||||||||||
Liabilities | ||||||||||||||||
Interest rate | $ — | $83 | $ — | $83 | ||||||||||||
Foreign currency | — | 3 | — | 3 | ||||||||||||
Total liabilities | $ — | $86 | $ — | $86 | ||||||||||||
December 31, 2018 | ||||||||||||||||
Assets | ||||||||||||||||
Commodity | $ — | $3 | $ — | $3 | ||||||||||||
Interest rate | — | 2 | — | 2 | ||||||||||||
Foreign currency | — | 26 | — | 26 | ||||||||||||
Total assets | $ — | $31 | $ — | $31 | ||||||||||||
Liabilities | ||||||||||||||||
Interest rate | $ — | $17 | $ — | $17 | ||||||||||||
Foreign currency | — | 2 | — | 2 | ||||||||||||
Total liabilities | $ — | $ 19 | $ — | $ 19 | ||||||||||||
2018 | 2017 | |||||||
(millions) | ||||||||
Balance at January 1, | $(2 | ) | $(2 | ) | ||||
Total realized and unrealized gains (losses): | ||||||||
Included in other comprehensive income (loss) | 1 | (3 | ) | |||||
Transfers out of Level 3 | 1 | 3 | ||||||
Balance at December 31, | $— | $(2 | ) | |||||
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, | 2019 | 2018 | ||||||||||||||
Carrying Amount | Estimated Fair Value (1) | Carrying Amount | Estimated Fair Value (1) | |||||||||||||
(millions) | ||||||||||||||||
Dominion Energy | ||||||||||||||||
Long-term debt (2) | $ | 32,055 | $36,155 | $ | 29,952 | $31,045 | ||||||||||
Credit facility borrowings | — | — | 73 | 73 | ||||||||||||
Junior subordinated notes (3) | 4,797 | 4,953 | 3,430 | 3,358 | ||||||||||||
Remarketable subordinated notes (3) | — | — | 1,386 | 1,340 | ||||||||||||
Virginia Power | ||||||||||||||||
Long-term debt (3) | $ | 12,326 | $14,281 | $ | 11,671 | $12,400 | ||||||||||
Dominion Energy Gas | ||||||||||||||||
Long-term debt (4) | $ | 5,520 | $5,738 | $ | 7,770 | $7,803 | ||||||||||
Credit facility borrowings | — | — | 73 | 73 | ||||||||||||
|
| 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 |
|
|
|
|
|
|
| ||
(1)
| Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issuances with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value. |
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.
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, as well as letters of credit and other forms of security,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.
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:
December 31, 2019 | December 31, 2018 | |||||||||||||||||||||||||||||||
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 | $35 | $21 | $— | $14 | $175 | $12 | $— | $163 | ||||||||||||||||||||||||
Exchange | 37 | 21 | — | 16 | 68 | 68 | — | — | ||||||||||||||||||||||||
Interest rate contracts: | ||||||||||||||||||||||||||||||||
Over-the-counter | 11 | 3 | — | 8 | 18 | 1 | — | 17 | ||||||||||||||||||||||||
Foreign currency contracts: | ||||||||||||||||||||||||||||||||
Over-the-counter | 8 | 8 | — | — | 26 | 2 | — | 24 | ||||||||||||||||||||||||
Total derivatives, subject to a master netting or similar arrangement | $91 | $53 | $— | $38 | $287 | $83 | $— | $204 | ||||||||||||||||||||||||
|
| 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, 2019 | December 31, 2018 | |||||||||||||||||||||||||||||||
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 | $105 | $21 | $— | $ 84 | $ 19 | $12 | $— | $ 7 | ||||||||||||||||||||||||
Exchange | 21 | 21 | — | — | 115 | 68 | 47 | — | ||||||||||||||||||||||||
Interest rate contracts: | ||||||||||||||||||||||||||||||||
Over-the-counter | 606 | 8 | 35 | 563 | 142 | 1 | — | 141 | ||||||||||||||||||||||||
Foreign currency contracts: | ||||||||||||||||||||||||||||||||
Over-the-counter | 3 | 3 | — | — | 2 | 2 | — | — | ||||||||||||||||||||||||
Total derivatives, subject to a master netting or similar arrangement | $735 | $53 | $35 | $647 | $278 | $83 | $47 | $148 | ||||||||||||||||||||||||
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, 2019.2022. 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.
Current | Noncurrent | |||||||
Natural Gas (bcf): | ||||||||
Fixed price (1) | 79 | 34 | ||||||
Basis | 227 | 495 | ||||||
Electricity (MWh): | ||||||||
Fixed price (1) | 3,810,015 | — | ||||||
FTRs | 46,585,304 | — | ||||||
Liquids (Gal) (2) | 52,374,000 | — | ||||||
Interest rate (3) | $ | 2,450,000,000 | $ | 3,976,014,497 | ||||
Foreign currency (3) | — | € | 250,000,000 | € | ||||
|
| 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
(1)
| Includes options. |
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 SheetSheets at December 31, 2019:2022:
|
| 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 | ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Interest rate |
| $ | (249 | ) |
| $ | (33 | ) |
| 396 months |
| $ | 16 |
|
| $ | (1 | ) |
| 396 months |
Total |
| $ | (249 | ) |
| $ | (33 | ) |
|
|
| $ | 16 |
|
| $ | (1 | ) |
|
|
AOCI After-Tax | Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax | Maximum Term | ||||||||||
(millions) | ||||||||||||
Commodities: | ||||||||||||
Gas | $ | (4 | ) | $ | (4 | ) | 24 months | |||||
Electricity | 19 | 19 | 12 months | |||||||||
Other | 1 | 1 | 12 months | |||||||||
Interest rate | (426 | ) | (64 | ) | 384 months | |||||||
Foreign currency | 3 | (2 | ) | 78 months | ||||||||
Total | $ | (407 | ) | $ | (50 | ) | ||||||
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales)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, interest rates and foreign currency exchange rates.
Fair Value Hedges
For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative instrument as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings and presented in the same line item. 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, 2019, 20182022, 2021 and 2017.
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:hedges all of which related to 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 | ) |
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, 2019 | December 31, 2018 | December 31, 2019 | December 31, 2018 | |||||||||||||
(millions) | ||||||||||||||||
Long-term debt | $ | (1,154 | ) | $ | (1,631 | ) | $ | (4 | ) | $20 | ||||||
Virginia Power had no amounts recorded in its Consolidated Balance Sheets related to fair value hedges at December 31, 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, 2019 | ||||||||||||
ASSETS | ||||||||||||
Current Assets | ||||||||||||
Commodity | $ 30 | $37 | $ | 67 | ||||||||
Interest rate | 1 | — | 1 | |||||||||
Total current derivative assets (1) | 31 | 37 | 68 | |||||||||
Noncurrent Assets | ||||||||||||
Commodity | 1 | 6 | 7 | |||||||||
Interest rate | 10 | — | 10 | |||||||||
Foreign currency | 8 | — | 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 | — | 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 | ||||||||
At December 31, 2018 | ||||||||||||
ASSETS | ||||||||||||
Current Assets | ||||||||||||
Commodity | $ 55 | $154 | $ | 209 | ||||||||
Interest rate | 14 | — | 14 | |||||||||
Total current derivative assets (1) | 69 | 154 | 223 | |||||||||
Noncurrent Assets | ||||||||||||
Commodity | 6 | 35 | 41 | |||||||||
Interest rate | 4 | — | 4 | |||||||||
Foreign currency | 26 | — | 26 | |||||||||
Total noncurrent derivative assets (2) | 36 | 35 | 71 | |||||||||
Total derivative assets | $105 | $189 | $ | 294 | ||||||||
LIABILITIES | ||||||||||||
Current Liabilities | ||||||||||||
Commodity | $ 17 | $112 | $ | 129 | ||||||||
Interest rate | 26 | — | 26 | |||||||||
Foreign currency | 2 | — | 2 | |||||||||
Total current derivative liabilities (3) | 45 | 112 | 157 | |||||||||
Noncurrent Liabilities | ||||||||||||
Commodity | 5 | 1 | 6 | |||||||||
Interest rate | 116 | — | 116 | |||||||||
Total noncurrent derivative liabilities (4) | 121 | 1 | 122 | |||||||||
Total derivative liabilities | $166 | $113 | $ | 279 | ||||||||
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:
Derivatives in cash flow hedging relationships | Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion) (1) | Amount of Gain (Loss) Reclassified From AOCI to Income | Increase (Decrease) in Derivatives Subject to Regulatory Treatment (2) | |||||||||
(millions) | ||||||||||||
Year Ended December 31, 2019 | ||||||||||||
Derivative type and location of gains (losses): | ||||||||||||
Commodity: | ||||||||||||
Operating revenue | $146 | |||||||||||
Purchased gas | (3 | ) | ||||||||||
Total commodity | $125 | $143 | $ — | |||||||||
Interest rate (3) | (252 | ) | (54 | ) | (255 | ) | ||||||
Foreign currency (4) | (18 | ) | (6 | ) | — | |||||||
Total | $(145 | ) | $ 83 | $(255 | ) | |||||||
Year Ended December 31, 2018 | ||||||||||||
Derivative type and location of gains (losses): | ||||||||||||
Commodity: | ||||||||||||
Operating revenue | $(90 | ) | ||||||||||
Electric fuel and other energy-related purchases | 14 | |||||||||||
Total commodity | $ 64 | $(76 | ) | $ — | ||||||||
Interest rate (3) | (18 | ) | (48 | ) | 39 | |||||||
Foreign currency (4) | (6 | ) | (13 | ) | — | |||||||
Total | $ 40 | $(137 | ) | $ 39 | ||||||||
Year Ended December 31, 2017 | ||||||||||||
Derivative type and location of gains (losses): | ||||||||||||
Commodity: | ||||||||||||
Operating revenue | $ 81 | |||||||||||
Purchased gas | (2 | ) | ||||||||||
Total commodity | $ 1 | $ 79 | $ — | |||||||||
Interest rate (3) | (8 | ) | (52 | ) | (58 | ) | ||||||
Foreign currency (4) | 18 | 20 | — | |||||||||
Total | $ 11 | $ 47 | $ (58 | ) | ||||||||
|
| 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 | ) |
Amounts recorded in Dominion Energy’s Consolidated Statements of Income are classified in purchased gas. | ||||||||
|
| 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
Derivatives not designated as hedging instruments | Amount of Gain (Loss) Recognized in Income on Derivatives (1) | |||||||||||
Year Ended December 31, | 2019 | 2018 | 2017 | |||||||||
(millions) | ||||||||||||
Derivative type and location of gains (losses): | ||||||||||||
Commodity: | ||||||||||||
Operating revenue | $ | 45 | $ | (28 | ) | $ | 18 | |||||
Purchased gas | (28 | ) | 11 | (3 | ) | |||||||
Electric fuel and other energy-related purchases | (46 | ) | (9 | ) | (59 | ) | ||||||
Other operations & maintenance | — | — | (1 | ) | ||||||||
Interest rate | 3 | — | — | |||||||||
Total | $ | (26 | ) | $ | (26 | ) | $ | (45 | ) | |||
| Includes |
December 31, 2019 | December 31, 2018 | |||||||||||||||||||||||||||||||
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 | $19 | $18 | $— | $1 | $64 | $6 | $— | $58 | ||||||||||||||||||||||||
Interest rate contracts: | ||||||||||||||||||||||||||||||||
Over-the-counter | 2 | — | — | 2 | 3 | — | — | 3 | ||||||||||||||||||||||||
Total derivatives, subject to a master netting or similar arrangement | $21 | $18 | $— | $3 | $67 | $6 | $— | $61 | ||||||||||||||||||||||||
December 31, 2019 | December 31, 2018 | |||||||||||||||||||||||||||||||
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 | $ 59 | $18 | $— | $ 41 | $ 6 | $6 | $— | $— | ||||||||||||||||||||||||
Interest rate contracts: | ||||||||||||||||||||||||||||||||
Over-the-counter | 363 | — | — | 363 | 88 | — | — | 88 | ||||||||||||||||||||||||
Total derivatives, subject to a master netting or similar arrangement | $422 | $18 | $— | $404 | $94 | $6 | $— | $88 | ||||||||||||||||||||||||
Current | Noncurrent | |||||||
Natural Gas (bcf): | ||||||||
Fixed price (1) | 41 | 9 | ||||||
Basis | 132 | 448 | ||||||
Electricity (MWh): | ||||||||
FTRs | 46,585,304 | — | ||||||
Interest rate (2) | $ | 900,000,000 | $ | 950,000,000 | ||||
AOCI After-Tax | Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax | Maximum Term | ||||||||||
(millions) | ||||||||||||
Interest rate | $ | (34 | ) | $ | (1 | ) | 384 months | |||||
Total | $ | (34 | ) | $ | (1 | ) | ||||||
Fair Value – Derivatives under Hedge Accounting | Fair Value – Derivatives not under Hedge Accounting | Total Fair Value | ||||||||||
(millions) | ||||||||||||
At December 31, 2019 | ||||||||||||
ASSETS | ||||||||||||
Current Assets | ||||||||||||
Commodity | $ — | $ 20 | $ | 20 | ||||||||
Total current derivative assets (1) | — | 20 | 20 | |||||||||
Noncurrent Assets | ||||||||||||
Commodity | — | 2 | 2 | |||||||||
Interest rate | 2 | — | 2 | |||||||||
Total noncurrent derivative assets (2) | 2 | 2 | 4 | |||||||||
Total derivative assets | $ 2 | $ 22 | $ | 24 | ||||||||
LIABILITIES | ||||||||||||
Current Liabilities | ||||||||||||
Commodity | $ — | $ 58 | $ | 58 | ||||||||
Interest rate | 185 | — | 185 | |||||||||
Total current derivative liabilities | 185 | 58 | 243 | |||||||||
Noncurrent Liabilities | ||||||||||||
Commodity | — | 45 | 45 | |||||||||
Interest rate | 178 | — | 178 | |||||||||
Total noncurrent derivatives liabilities (3) | 178 | 45 | 223 | |||||||||
Total derivative liabilities | $363 | $103 | $ | 466 | ||||||||
At December 31, 2018 | ||||||||||||
ASSETS | ||||||||||||
Current Assets | ||||||||||||
Commodity | $ — | $ 60 | $ | 60 | ||||||||
Interest rate | 3 | — | 3 | |||||||||
Total current derivative assets (1) | 3 | 60 | 63 | |||||||||
Noncurrent Assets | ||||||||||||
Commodity | — | 30 | 30 | |||||||||
Total noncurrent derivative assets (2) | — | 30 | 30 | |||||||||
Total derivative assets | $ 3 | $ 90 | $ | 93 | ||||||||
LIABILITIES | ||||||||||||
Current Liabilities | ||||||||||||
Commodity | $ — | $ 15 | $ | 15 | ||||||||
Interest rate | 10 | — | 10 | |||||||||
Total current derivative liabilities | 10 | 15 | 25 | |||||||||
Noncurrent Liabilities | ||||||||||||
Interest rate | 78 | — | 78 | |||||||||
Total noncurrent derivative liabilities (3) | 78 | — | 78 | |||||||||
Total derivative liabilities | $ 88 | $ 15 | $ | 103 | ||||||||
Derivatives in cash flow hedging relationships | Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion) (1) | Amount of Gain (Loss) Reclassified From AOCI to Income | Increase (Decrease) in Derivatives Subject to Regulatory Treatment (2) | |||||||||
(millions) | ||||||||||||
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 | ||||||||
Year Ended December 31, 2017 | ||||||||||||
Derivative type and location of gains (losses): | ||||||||||||
Interest rate (3) | $ (8 | ) | $(1 | ) | $(58 | ) | ||||||
Total | $ (8 | ) | $(1 | ) | $(58 | ) | ||||||
Derivatives not designated as hedging instruments | Amount of Gain (Loss) Recognized in Income on Derivatives (1) | |||||||||||
Year Ended December 31, | 2019 | 2018 | 2017 | |||||||||
(millions) | ||||||||||||
Derivative type and location of gains (losses): | ||||||||||||
Commodity (2) | $ | (45 | ) | $2 | $(57) | |||||||
Total | $ | (45 | ) | $2 | $(57) | |||||||
December 31, 2019 | December 31, 2018 | |||||||||||||||||||||||||||||||
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 | Financial Instruments | Cash Collateral Received | Net Amounts | Gross Assets Presented in the Consolidated Balance Sheet | Financial Instruments | Cash Collateral Received | Net Amounts | |||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||
Commodity contracts: | ||||||||||||||||||||||||||||||||
Over-the-counter | $ — | $ — | $ — | $ — | $ 3 | $ — | $ — | $ 3 | ||||||||||||||||||||||||
Interest rate contracts: | ||||||||||||||||||||||||||||||||
Over-the-counter | — | — | — | — | 2 | — | — | 2 | ||||||||||||||||||||||||
Foreign currency contracts: | ||||||||||||||||||||||||||||||||
Over-the-counter | 8 | 8 | — | — | 26 | 2 | — | 24 | ||||||||||||||||||||||||
Total derivatives, subject to a master netting or similar arrangement | $ 8 | $ 8 | $ — | $ — | $ 31 | $ 2 | $ — | $ 29 | ||||||||||||||||||||||||
December 31, 2019 | December 31, 2018 | |||||||||||||||||||||||||||||||
Gross Amounts Not Offset in the Consolidated Balance Sheet | Gross Amounts Not Offset in the Consolidated Balance Sheet | |||||||||||||||||||||||||||||||
Gross Liabilities Presented in the Consolidated Balance Sheet | Financial Instruments | Cash Collateral Paid | Net Amounts | Gross Liabilities Presented in the Consolidated Balance Sheet | Financial Instruments | Cash Collateral Paid | Net Amounts | |||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||
Interest rate contracts: | ||||||||||||||||||||||||||||||||
Over-the-counter | $ 83 | $ 5 | $ — | $ 78 | $ 17 | $ — | $ — | $ 17 | ||||||||||||||||||||||||
Foreign currency contracts: | ||||||||||||||||||||||||||||||||
Over-the-counter | 3 | 3 | — | — | 2 | 2 | — | — | ||||||||||||||||||||||||
Total derivatives, subject to a master netting or similar arrangement | $ 86 | $ 8 | $ — | $ 78 | $ 19 | $ 2 | $ — | $ 17 | ||||||||||||||||||||||||
Current | Noncurrent | |||||||
Interest rate (1) | $ | 250,000,000 | $ | 1,050,000,000 | ||||
Foreign currency (1) | € | — | € | 250,000,000 | ||||
AOCI After-Tax | Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax | Maximum Term | ||||||||||
(millions) | ||||||||||||
Interest rate | $(84 | ) | $ 15 | 300 months | ||||||||
Foreign currency | 3 | (2 | ) | 78 months | ||||||||
Total | $(81 | ) | $ 13 | |||||||||
Fair Value – Derivatives under Hedge Accounting | Fair Value – Derivatives not under Hedge Accounting | Total Fair Value | ||||||||||
(millions) | ||||||||||||
At December 31, 2019 | ||||||||||||
ASSETS | ||||||||||||
Noncurrent Assets | ||||||||||||
Foreign currency | $ 8 | $ — | $ | 8 | ||||||||
Total noncurrent derivative assets (1) | 8 | — | 8 | |||||||||
Total derivative assets | $ 8 | $ — | $ | 8 | ||||||||
LIABILITIES | ||||||||||||
Current Liabilities | ||||||||||||
Interest rate | $30 | $ — | $ | 30 | ||||||||
Foreign currency | 3 | — | 3 | |||||||||
Total current derivative liabilities (2) | 33 | — | 33 | |||||||||
Noncurrent Liabilities | ||||||||||||
Interest rate | 53 | — | 53 | |||||||||
Total noncurrent derivative liabilities (3) | 53 | — | 53 | |||||||||
Total derivative liabilities | $86 | $ — | $ | 86 | ||||||||
At December 31, 2018 | ||||||||||||
ASSETS | ||||||||||||
Current Assets | ||||||||||||
Commodity | $ 3 | $ — | $ | 3 | ||||||||
Interest rate | 2 | — | 2 | |||||||||
Total current derivative assets (4) | 5 | — | 5 | |||||||||
Noncurrent Assets | ||||||||||||
Foreign currency | 26 | — | 26 | |||||||||
Total noncurrent derivative assets (1) | 26 | — | 26 | |||||||||
Total derivative assets | $31 | $ — | $ | 31 | ||||||||
LIABILITIES | ||||||||||||
Current Liabilities | ||||||||||||
Interest rate | $ 9 | $ — | $ | 9 | ||||||||
Foreign currency | 2 | — | 2 | |||||||||
Total current derivative liabilities (2) | 11 | — | 11 | |||||||||
Noncurrent Liabilities | ||||||||||||
Interest rate | 8 | — | 8 | |||||||||
Total noncurrent derivative liabilities (3) | 8 | — | 8 | |||||||||
Total derivative liabilities | $19 | $ — | $ | 19 | ||||||||
Derivatives in cash flow hedging relationships | Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion) (1) | Amount of Gain (Loss) Reclassified From AOCI to Income | ||||||
(millions) | ||||||||
Year Ended December 31, 2019 | ||||||||
Derivative type and location of gains (losses): | ||||||||
Commodity: | ||||||||
Net income from discontinued operations | $ 4 | |||||||
Total commodity | $ 1 | $ 4 | ||||||
Interest rate (2) | (68 | ) | (5 | ) | ||||
Foreign currency (3) | (18 | ) | (6 | ) | ||||
Total | $ (85 | ) | $ (7 | ) | ||||
Year Ended December 31, 2018 | ||||||||
Derivative type and location of gains (losses): | ||||||||
Commodity: | ||||||||
Net income from discontinued operations | $ (8 | ) | ||||||
Total commodity | $ 1 | $ (8 | ) | |||||
Interest rate (2) | (16 | ) | (5 | ) | ||||
Foreign currency (3) | (6 | ) | (13 | ) | ||||
Total | $ (21 | ) | $ (26 | ) | ||||
Year Ended December 31, 2017 | ||||||||
Derivative type and location of gains (losses): | ||||||||
Commodity: | ||||||||
Net income from discontinued operations | $ (8 | ) | ||||||
Total commodity | $ (10 | ) | $ (8 | ) | ||||
Interest rate (2) | 1 | (6 | ) | |||||
Foreign currency (3) | 18 | 20 | ||||||
Total | $ 9 | $ 6 | ||||||
Derivatives not designated as hedging instruments | Amount of Gain (Loss) Recognized in Income on Derivatives | |||||||||||
Year Ended December 31, | 2019 | 2018 | 2017 | |||||||||
(millions) | ||||||||||||
Derivative type and location of gains (losses): | ||||||||||||
Commodity | ||||||||||||
Operating revenue | $— | $(11 | ) | $— | ||||||||
Total | $— | $(11 | ) | $— | ||||||||
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 | ) |
2019 | 2018 | 2017 | ||||||||||
(millions, except EPS) | ||||||||||||
Net income attributable to Dominion Energy | $ | 1,358 | $ | 2,447 | $ | 2,999 | ||||||
Preferred stock dividends (see Note 19) | (17 | ) | — | — | ||||||||
Net income attributable to Dominion Energy – Basic | 1,341 | 2,447 | 2,999 | |||||||||
Dilutive effect of Series A Preferred Stock | (28 | ) | — | — | ||||||||
Net income attributable to Dominion Energy – Diluted | 1,313 | 2,447 | 2,999 | |||||||||
Average shares of common stock outstanding – Basic | 808.8 | 654.2 | 636.0 | |||||||||
Net effect of dilutive securities (1) | 0.1 | 0.7 | — | |||||||||
Average shares of common stock outstanding – Diluted | 808.9 | 654.9 | 636.0 | |||||||||
Earnings Per Common Share – Basic | $ | 1.66 | $ | 3.74 | $ | 4.72 | ||||||
Earnings Per Common Share – Diluted | $ | 1.62 | $ | 3.74 | $ | 4.72 | ||||||
The 2019 Equity Units, areprior to settlement in June 2022, and the Q-Pipe Transaction deposit, prior to being settled in cash in July 2021, were potentially dilutive securities. Theinstruments. See Notes 3 and 19 for additional information.
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 for the year ended December 31, 2019,from continuing operations as the dilutive stock price threshold was not met. The Series A Preferred Stock included within the 2019 Equity Units is excluded from the effect of dilutive securities within diluted EPS from continuing operations, but a fair value adjustment is reflected within net income attributable to Dominion Energy from continuing operations for the calculation of diluted EPS from continuing operations for the year ended December 31, 20192020, based upon the expectation that the conversion willwould be settled in cash rather than through the issuance of Dominion Energy common stock. The 2016As described in Note 19, effective November 2021 any settlement of the conversion up to $1,000 per share was payable in cash, and 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 were potentially dilutive securities, but wereis excluded from the calculation of diluted EPS from continuing operations, as such fair value adjustment was not dilutive during the period.
The impact of settling the deposit associated with the Q-Pipe Transaction in shares is excluded from the calculation for the years endedending December 31, 2019, 20182021 and 2017 as2020 based upon the dilutive stock price threshold was not met. Theexpectation Dominion Energy Midstream convertible preferred units were potentially dilutive securities but had no effect onwould settle in cash, which occurred in July 2021, rather than through the calculationissuance of diluted EPS for the years ended December 31, 2018 and 2017. In calculating diluted EPS in connection with theshares of Dominion Energy Midstream convertible preferred units, common stock.
134
NOTE 9. INVESTMENTS
Dominion Energy applied theif-convertedmethod.
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 $120$111 million and $111$122 million at December 31, 20192022 and 2018,2021, respectively.
135
Decommissioning Trust Securities
The 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:
|
|
| 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
Amortized Cost | Total Unrealized Gains | Total Unrealized Losses | Fair Value | |||||||||||||
(millions) | ||||||||||||||||
December 31, 2019 | ||||||||||||||||
Equity securities: (1) | ||||||||||||||||
U.S. | $ | 1,807 | $ | 2,451 | $ | (20 | ) | $ | 4,238 | |||||||
Fixed income securities: (2) | ||||||||||||||||
Corporate debt instruments | 434 | 29 | — | 463 | ||||||||||||
Government securities | 1,108 | 39 | (2 | ) | 1,145 | |||||||||||
Common/collective trust funds | 115 | 4 | — | 119 | ||||||||||||
Insurance contracts | 214 | — | — | 214 | ||||||||||||
Cash equivalents and other (3) | 13 | — | — | 13 | ||||||||||||
Total | $ | 3,691 | $ | 2,523 | $ | (22 | ) (4) | $ | 6,192 | |||||||
December 31, 2018 | ||||||||||||||||
Equity securities: (1) | ||||||||||||||||
U.S. | $1,741 | $1,640 | $(51) | $3,330 | ||||||||||||
Fixed income securities: (2) | ||||||||||||||||
Corporate debt instruments | 435 | 5 | (9) | 431 | ||||||||||||
Government securities | 1,092 | 17 | (12) | 1,097 | ||||||||||||
Common/collective trust funds | 76 | — | — | 76 | ||||||||||||
Cash equivalents and other | 4 | — | — | 4 | ||||||||||||
Total | $3,348 | $1,662 | $(72) (4) | $4,938 | ||||||||||||
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, | 2019 | 2018 | ||||||
(millions) | ||||||||
Net gains (losses) recognized during the period | $ | 919 | $ | (245 | ) | |||
Less: Net gains recognized during the period on securities sold during the period | (80 | ) | (58 | ) | ||||
Unrealized gains (losses) recognized during the period on securities still held at December 31, 2019 and 2018 (1) | $ | 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, 20192022 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 | $ | 198 | ||
Due after one year through five years | 412 | |||
Due after five years through ten years | 390 | |||
Due after ten years | 727 | |||
Total | $ | 1,727 | ||
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.
Year Ended December 31, | 2019 | 2018 | 2017 | |||||||||
(millions) | ||||||||||||
Proceeds from sales | $ | 1,712 | $ | 1,804 | $ | 1,831 | ||||||
Realized gains (1) | 195 | 140 | 166 | |||||||||
Realized losses (1) | 96 | 91 | 71 | |||||||||
|
| 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 |
|
| Includes realized gains and losses recorded to the |
Year Ended December 31, | 2019 | 2018 | 2017 | |||||||||
(millions) | ||||||||||||
Total other-than-temporary impairment losses (1) | $ | 3 | $ | 30 | $ | 44 | ||||||
Losses recorded to the nuclear decommissioning trust regulatory liability | — | — | (16 | ) | ||||||||
Losses recognized in other comprehensive income (before taxes) | (3 | ) | (30 | ) | (5 | ) | ||||||
Net impairment losses recognized in earnings | $ | — | $ | — | $ | 23 | ||||||
137
EQUITY METHOD INVESTMENTS
Amortized Cost | Total Unrealized Gains | Total Unrealized Losses | Fair Value | |||||||||||||
(millions) | ||||||||||||||||
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 | ||||||||||||
December 31, 2018 | ||||||||||||||||
Equity securities: (1) | ||||||||||||||||
U.S. | $ 858 | $751 | $(24) | $1,585 | ||||||||||||
Fixed income securities: (2) | ||||||||||||||||
Corporate debt instruments | 224 | 2 | (5) | 221 | ||||||||||||
Government securities | 504 | 7 | (5) | 506 | ||||||||||||
Common/collective trust funds | 51 | — | — | 51 | ||||||||||||
Cash equivalents and other (3) | 6 | — | — | 6 | ||||||||||||
Total | $1,643 | $760 | $(34) (4) | $2,369 | ||||||||||||
Year Ended December 31, | 2019 | 2018 | ||||||
(millions) | ||||||||
Net gains (losses) recognized during the period | $ | 423 | $ | (105 | ) | |||
Less: Net gains recognized during the period on securities sold during the period | (20 | ) | (32 | ) | ||||
Unrealized gains (losses) recognized during the period on securities still held at December 31, 2019 and 2018 (1) | $ | 403 | $ | (137 | ) | |||
Year Ended December 31, | 2019 | 2018 | 2017 | |||||||||
(millions) | ||||||||||||
Proceeds from sales | $ | 858 | $ | 887 | $ | 849 | ||||||
Realized gains (1) | 58 | 60 | 75 | |||||||||
Realized losses (1) | 22 | 27 | 30 | |||||||||
Year Ended December 31, | 2019 | 2018 | 2017 | |||||||||
(millions) | ||||||||||||
Total other-than-temporary impairment losses (1) | $ | 2 | $ | 15 | $ | 20 | ||||||
Losses recorded to the nuclear decommissioning trust regulatory liability | — | — | (16 | ) | ||||||||
Losses recognized in other comprehensive income (before taxes) | (2 | ) | (15 | ) | (2 | ) | ||||||
Net impairment losses recognized in earnings | $ | — | $ | — | $ | 2 | ||||||
Investments that Dominion Energy accountaccounts for under the equity method of accounting are as follows:
Company | Ownership% | Investment Balance | Description | |||||||||||||
As of December 31, | 2019 | 2018 | ||||||||||||||
(millions) | ||||||||||||||||
Atlantic Coast Pipeline | 48 | % | $ | 1,123 | $ | 820 | Gas transmission system | |||||||||
Iroquois | 50 | % | 276 | 302 | Gas transmission system | |||||||||||
Fowler Ridge | 50 | % | 74 | 82 | Wind-powered merchant generation facility | |||||||||||
Wrangler | 20 | % | 77 | — | Nonregulated retail energy marketing | |||||||||||
Other (1)(2) | various | 96 | 74 | |||||||||||||
Total | $ | 1,646 | $ | 1,278 | ||||||||||||
|
|
|
|
| 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 |
|
|
| |
Dominion Energy recorded equity earnings on its investments totaled $168of $299 million, $197$276 million and $14$40 million for the years ended December 31, 2022, 2021 and 2020, respectively, in 2019, 2018 and 2017, respectively, included in other income in Dominion Energy’sits Consolidated Statements of Income. In addition, Dominion Energy recorded equity losses of $7 million, $20 million and $2.3 billion for the years ended December 31, 2022, 2021 and 2020, respectively, in discontinued operations related to its investment in Atlantic Coast Pipeline. Dominion Energy received distributions from these investments of $112$355 million, $209$328 million and $419$102 million in 2019, 2018for the years ended December 31, 2022, 2021 and 2017,2020, respectively. As of December 31, 20192022 and 2018,$110$223 million and $161$244 million, respectively. At December 31, 2019,2022, these differences are comprised of $159$9 million of equity method goodwill that is not being amortized, and a net $49$215 million basis difference from Dominion Energy’s investmentsinvestment in Fowler,Cove Point, which is being amortized over the useful lives of the underlying assets in Atlantic Coast Pipeline, which is being amortized over the term of its credit facility,an unfunded commitmenta net $(1) million basis difference primarily attributable to be made to Align RNG.capitalized interest. At December 31, 2018,$146$27 million of equity method goodwill that is not being amortized, and $15$221 million related to basis differencesdifference from Dominion Energy’s investmentsinvestment in wind projects,Cove Point, which areis 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.
Cove Point
In November 2020, in conjunction with the GT&S Transaction, Dominion Energy sold 100% of its general partner interest and 25% of the total limited partner interest in Cove Point. Dominion Energy retained a 50% noncontrolling limited partnership interest in Cove Point which is accounted for as an equity method investment as Dominion Energy has the ability to exercise significant influence over, but not control, Cove Point. See Note 3 for further information regarding the GT&S Transaction.
Income before income taxes recorded for 100% of Cove Point for the years ended December 31, 2022, 2021 and 2020 was $574 million, $528 million and $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, earnings attributable to Dominion Energy are presented within earnings from equity method investees in its Consolidated Statements of Income. In 2020, earnings attributable to Dominion Energy of $40 million are presented within earnings from equity method investees in its Consolidated Statements of Income.
Dominion Energy recorded distributions from Cove Point of $344 million, $300 million and $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 for the years ended December 31, 2022, 2021 or 2020 (after the date of disposal).
All activity relating to Dominion Energy’s noncontrolling interest in Cove Point is recorded within Contracted Assets. See Note 3 for further information regarding the GT&S Transaction.
Atlantic Coast Pipeline which is being amortized over the term of its credit facility.
In September 2014, Dominion Energy, along with Duke Energy and Southern, announced the formation of Atlantic Coast Pipeline. The Atlantic Coast Pipeline partnership agreement includes provisions to allow Dominion Energy an option to purchase additional ownership interest in Atlantic Coast Pipeline to maintain a leading ownership percentage. Asfor the purpose of December 31, 2019, the members hold the following membership interests: Dominion Energy, 48%; Duke, 47%; and Southern, 5%.
138
-mile natural gas pipeline running from West Virginia through Virginia to North Carolina. Subsidiaries and affiliates of all 3 members planDominion Energy, Duke Energy and Southern had planned to be customers of the pipeline under20-year
In March 2020, Dominion Energy completed the acquisition from Southern of its 5% membership interest in Atlantic Coast Pipeline and its 100% ownership interest in Pivotal LNG, Inc., for $184 million in aggregate, subject to certain purchase price adjustments. Pivotal LNG, Inc. includes a 50% noncontrolling interest in JAX LNG. Following completion of the acquisition, Dominion Energy owns a 53% noncontrolling membership interest in Atlantic Coast Pipeline with Duke Energy owning the remaining interest.
Atlantic Coast Pipeline continues to be accounted for as an equity method investment as the power to direct the activities most significant to Atlantic Coast Pipeline is considered an equity method investment asshared with Duke Energy. As a result, Dominion Energy has the ability to exercise significant influence, but not control, over the investee. See Note 16 for more information.
The Atlantic Coast Pipeline Project ishad 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 allegesiswas permitted to proceed. Since December 2018, notable developments in these challenges includeincluded 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 ParkwayAtlantic Coast Pipeline continues to vigorously defend these challenges and is coordinating with the federal and state authorities to obtain new authorizations. Atlantic Coast Pipeline continues coordinating and working with U.S. Fish and Wildlife Service and other parties in
The project also evaluating possible legislativefaced new and administrative remediesserious challenges from uncertainty related to this issue.
In July 2020, as a result of ongoing permitting delays, growing legal uncertainties and the need to amendincur significant capital expenditures to maintain project timing before such uncertainties could be resolved, Dominion Energy and Duke Energy announced the contracted rate to share in certain delay cost increases, pending certain regulatory approvals. Project construction activities, schedules and costs are also subject to uncertainty due to permitting and/or work delays (including due to judicial or regulatory action), abnormal weather and other conditions that could result in further cost or schedule modifications, a suspensioncancellation of AFUDC forthe Atlantic Coast Pipeline and/or impairment charges potentially material toProject.
Dominion 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, and $7 million ($5 million after-tax) and $20 million ($14 million after-tax) for the years ended December 31, 2022 and 2021, respectively. In connection with Dominion Energy’s cash flows, financial position and/ordecision to sell substantially all of its gas transmission and storage operations, Dominion Energy has reflected the results of operations.
In October 2017, Dominion Energy entered into a guarantee agreement to support a portion of Atlantic Coast Pipeline’s obligation under a $3.4 billion revolving credit facility with a stated maturity date of October 2021. In July 2020, the capacity of the revolving credit facility was reduced from $3.4 billion to $1.9 billion. In February 2021, Atlantic Coast Pipeline repaid the outstanding borrowed amounts and terminated its revolving credit facility. Concurrently, Dominion Energy’s related guarantee agreement to support its portion of the Atlantic Coast Pipeline’s borrowings was also terminated. In 2020, Dominion Energy recorded a $48 million adjustment related to this guarantee agreement, reflected within equity as a cumulative effect of a change in accounting principle upon adoption of a new credit loss standard in January 2020.
Dominion Energy recorded contributions of $3 million, $965 million and $107 million during the years ended December 31, 2022, 2021 and 2020, respectively, to Atlantic Coast Pipeline.
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 million during the year ended December 31, 2020 (prior to closing of the GT&S Transaction), included in discontinued operations in Dominion Energy’s Consolidated Statements of Income.
All activity relating to Atlantic Coast Pipeline is recorded within the Corporate and Other segment.
Fowler Ridge
In September 2020, Dominion Energy sold its 50% noncontrolling partnership interest in Fowler Ridge to BP and terminated an affiliate’s long-term power, capacity and renewable energy credit contract with Fowler Ridge for a net payment by Dominion Energy of $150 million. The valuation is$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 a Level 3 fair value measurementmeasurements due to the use of judgmentsignificant judgmental and unobservable inputs, including projected timing andthe amount of future cash flows and a discount rate reflecting risks inherent in the future cash flows. As a result of the sale,flows and market prices. Dominion Energy recognized a gainloss of $546$221 million ($390165 million,incomecharges 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,
All activity relating to Fowler Ridge, & NedPower
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.
After 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$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 milliongainslosses (gains) on sales of assets, and an associated tax expense of $82$32 million, in the Consolidated StatementStatements of Income. OverIncome for the next two years, under the terms of the agreement,year ended December 31, 2021.
Subsequently in December 2021, Dominion Energy expects to contributesold 5% of its remaining nonregulated retail energy marketing operations to Wrangler. As a result of these contributions, Dominion Energy will receive additional cash consideration which will be based upon future financial performance. When these future contributions occur, Dominion Energy expects to retain a 20% noncontrolling ownership interest in Wrangler.
All activity relating to Wrangler is recorded within Gas Transmission & Storage.
Dominion Privatization
In September 2018,February 2022, Dominion Energy completedentered 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 saleagreement, Dominion Energy would contribute its existing privatization operations, excluding contracts held by DESC, and Patriot would contribute cash.
140
The initial contribution, consisting of its 25% limited partnershipprivatization operations in South Carolina, Texas and Pennsylvania, closed in March 2022 for which Dominion Energy received total consideration of $120 million, subject to customary closing adjustments, comprised of $60 million in cash proceeds and a 50% noncontrolling ownership interest in Catalyst Old River Hydroelectric Limited Partnership and received proceedsDominion Privatization with an initial fair value of $91 million. The sale resulted in$60 million, estimated 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 first quarter of 2022, Dominion Energy recorded a gain of $87$23 million ($6316 millionwhich is included presented in other incomelosses (gains) on sales of assets in Dominion Energy’s Consolidated Statement of Income.
Company | Ownership% | Investment Balance | Description | |||||||||||||
As of December 31, | 2019 | 2018 | ||||||||||||||
(millions) | ||||||||||||||||
Iroquois | 50 | % | $276 | $302 | Gas transmission system | |||||||||||
White River Hub | 50 | % | 36 | 37 | Gas transmission system | |||||||||||
Total | $312 | $339 | ||||||||||||||
At December 31, 2019 | At December 31, 2018 | |||||||
(millions) | ||||||||
Current assets | $ 79 | $ | 112 | |||||
Noncurrent assets | 586 | 588 | ||||||
Current liabilities | 37 | 165 | ||||||
Noncurrent liabilities | 334 | 193 | ||||||
Year Ended December 31, 2019 | Year Ended December 31, 2018 | Year Ended December 31, 2017 | ||||||||||
(millions) | ||||||||||||
Revenues | $180 | $194 | $194 | |||||||||
Operating income | 93 | 108 | 110 | |||||||||
Net income | 82 | 94 | 93 | |||||||||
At December 31, 2019 | At December 31, 2018 | |||||||
(millions) | ||||||||
Current assets | $ 3 | $ 3 | ||||||
Noncurrent assets | 39 | 41 | ||||||
Current liabilities | 2 | 2 | ||||||
Year Ended December 31, 2019 | Year Ended December 31, 2018 | Year Ended December 31, 2017 | ||||||||||
(millions) | ||||||||||||
Revenues | $10 | $12 | $10 | |||||||||
Operating income | 6 | 8 | 7 | |||||||||
Net income | 6 | 8 | 7 | |||||||||
The second contribution, consisting of privatization operations in Virginia, closed in December 2022 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 in its Consolidated Statements of Income.
All activity related to these services were $7 millionDominion Privatization is reflected within the Corporate and $13 million at December 31, 2019 and 2018, respectively, composed entirely of accrued unbilled revenue, included in other receivables in Dominion Energy Gas’ Consolidated Balance Sheets.Other segment.
NOTE 10. Property, PlantPROPERTY, 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, |
| 2022 |
|
| 2021 |
|
| 2022 |
|
| 2021 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Dominion Energy |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Utility: |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Generation |
| $ | 23,720 |
|
| $ | 23,378 |
|
| $ | 17,611 |
|
| $ | 17,325 |
|
Transmission |
|
| 16,857 |
|
|
| 15,430 |
|
|
| 13,034 |
|
|
| 11,760 |
|
Distribution |
|
| 30,624 |
|
|
| 28,953 |
|
|
| 14,681 |
|
|
| 13,621 |
|
Storage |
|
| 491 |
|
|
| 455 |
|
|
| — |
|
|
| — |
|
Nuclear fuel |
|
| 2,373 |
|
|
| 2,306 |
|
|
| 1,823 |
|
|
| 1,702 |
|
General and other |
|
| 4,630 |
|
|
| 4,373 |
|
|
| 1,019 |
|
|
| 912 |
|
Plant under construction |
|
| 5,678 |
|
|
| 3,898 |
|
|
| 4,685 |
|
|
| 2,865 |
|
Total utility |
|
| 84,373 |
|
|
| 78,793 |
|
|
| 52,853 |
|
|
| 48,185 |
|
Non-jurisdictional - including plant under construction |
|
| 1,834 |
|
|
| 1,694 |
|
|
| 1,834 |
|
|
| 1,694 |
|
Nonutility: |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Nonregulated generation-nuclear |
|
| 1,935 |
|
|
| 1,773 |
|
|
| — |
|
|
| — |
|
Nonregulated generation-solar |
|
| 495 |
|
|
| 2,026 |
|
|
| — |
|
|
| — |
|
Nuclear fuel |
|
| 954 |
|
|
| 1,056 |
|
|
| — |
|
|
| — |
|
Other-including plant under construction |
|
| 1,611 |
|
|
| 1,161 |
|
|
| 10 |
|
|
| 11 |
|
Total nonutility |
|
| 4,995 |
|
|
| 6,016 |
|
|
| 10 |
|
|
| 11 |
|
Total property, plant and equipment |
| $ | 91,202 |
|
| $ | 86,503 |
|
| $ | 54,697 |
|
| $ | 49,890 |
|
| At December 31, | 2019 | 2018 | ||||||
(millions) | ||||||||
Dominion Energy | ||||||||
Utility: | ||||||||
Generation | $ | 25,317 | $ | 18,896 | ||||
Transmission | 20,486 | 16,666 | ||||||
Distribution | 25,748 | 18,535 | ||||||
Storage | 3,227 | 2,906 | ||||||
Nuclear fuel | 2,296 | 1,626 | ||||||
Oil and gas | 1,792 | 1,763 | ||||||
General and other | 2,413 | 1,783 | ||||||
Plant under construction | 2,956 | 2,348 | ||||||
Total utility | 84,235 | 64,523 | ||||||
Non-jurisdictional—including plant under construction | 854 | 407 | ||||||
Nonutility: | ||||||||
Merchant generation-nuclear | 1,652 | 1,550 | ||||||
Merchant generation-other | 3,985 | 3,802 | ||||||
Nuclear fuel | 930 | 1,025 | ||||||
Gas gathering and processing | 190 | 185 | ||||||
LNG facility | 4,425 | 3,977 | ||||||
Other—including plant under construction | 1,195 | 1,109 | ||||||
Total nonutility | 12,377 | 11,648 | ||||||
Total property, plant and equipment | $ | 97,466 | $ | 76,578 | ||||
Virginia Power | ||||||||
Utility: | ||||||||
Generation | $ | 19,552 | $ | 18,896 | ||||
Transmission | 10,229 | 9,391 | ||||||
Distribution | 12,095 | 11,771 | ||||||
Nuclear fuel | 1,688 | 1,626 | ||||||
General and other | 825 | 820 | ||||||
Plant under construction | 1,784 | 1,602 | ||||||
Total utility | 46,173 | 44,106 | ||||||
Non-jurisdictional—including plant under construction | 854 | 407 | ||||||
Other | 11 | 11 | ||||||
Total property, plant and equipment | $ | 47,038 | $ | 44,524 | ||||
Dominion Energy Gas | ||||||||
Utility: | ||||||||
Transmission | $ | 7,014 | $ | 6,790 | ||||
Storage | 2,799 | 2,615 | ||||||
General and other | 219 | 210 | ||||||
Plant under construction | 574 | 732 | ||||||
Total utility | 10,606 | 10,347 | ||||||
Nonutility: | ||||||||
LNG facility | 4,425 | 3,977 | ||||||
Other—including plant under construction | 135 | 376 | ||||||
Total nonutility | 4,560 | 4,353 | ||||||
Total property, plant and equipment | $ | 15,166 | $ | 14,700 | ||||
Jointly-Owned Power Stations
The Companies proportionate share of jointly-owned power stations at December 31, 20192022 is as followsfollows:
|
| 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 | 1,058 | 2,564 | 610 | 1,267 | 1,394 | |||||||||||||||
Accumulated depreciation | (661 | ) | (1,321 | ) | (247 | ) | (449 | ) | (659 | ) | ||||||||||
Nuclear fuel | — | 793 | — | 483 | 608 | |||||||||||||||
Accumulated amortization of nuclear fuel | — | (634 | ) | — | (390 | ) | (389 | ) | ||||||||||||
Plant under construction | 7 | 143 | 5 | 87 | 77 | |||||||||||||||
141
TheDominion Energy and Virginia PowerThe 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.
Nonregulated 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 | 130 | Expected 2020 | 80 | ||||||||||||||||||
August 2018 | May 2019 | North Carolina | Chestnut | 130 | Expected 2020 | 75 | ||||||||||||||||||
June 2019 | June 2019 | Virginia | Ft. Powhatan | 270 | Expected 2021 | 150 | ||||||||||||||||||
June 2019 | August 2019 | Virginia | Belcher | 160 | Expected 2020 | 88 | ||||||||||||||||||
August 2019 | November 2019 | Virginia | Bedford | 110 | Expected 2021 | 70 | ||||||||||||||||||
October 2019 | October 2019 | Virginia | Maplewood | 190 | Expected 2022 | 120 | ||||||||||||||||||
December 2019 | January 2020 | Virginia | Rochambeau | 35 | Expected 2021 | 20 | ||||||||||||||||||
In addition, the following table presents acquisitions by Dominion Energy
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 |
|
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. 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 placing additional facilities in service by the end of 2023 with an estimated total projected cost of approximately $39 million and an aggregate generation capacity of 17 MW. Dominion Energy has claimed or expects to claim federal investment tax credits on the projects.
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 | $130 | Expected 2020 | 80 | ||||||||||||||||||
August 2019 | August 2019 | Virginia | Myrtle | 35 | Expected 2020 | 15 | ||||||||||||||||||
September 2019 | September 2019 | South Carolina | Seabrook | 103 | December 2019 | 72 | ||||||||||||||||||
November 2019 | November 2019 | North Carolina | Wilkinson | 153 | December 2019 | 74 | ||||||||||||||||||
Impairment
In the fourth quarter of Tower Rental Portfolio
142
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 equipment. In March 2017, Virginia Power soldcharges in its rental portfolioConsolidated Statements of Income (reflected in the Corporate and Other segment) for the year ended December 31, 2022 to Vertical Bridge Towers II, LLC for $91adjust the property, plant and equipment, intangible assets and right-of-use lease assets down to an estimated fair value of $665 million in cash.aggregate. The proceeds are subjectfair value was estimated using an income approach. The valuation is considered a Level 3 fair value measurement due to Virginia Power’s FERC-regulated tariff, under which it is required to return halfthe 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.
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 proceedsimpact of the VCEA and Dominion Energy’s decision to customers. Virginia Power recorded $7 millionsell substantially all of its gas transmission and $6 millionstorage operations. Based on an evaluation of Dominion Energy’s interests in operating revenue
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 includedof $19 million ($15 million after-tax) in gainslosses (gains) on sales of assets in Dominion Energy Gas’its Consolidated Statements of Income associated(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 finalizationHart-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 the contractual matters on previous conveyances, a $9$229 million ($5176 milliongain included in gainslosses (gains) on sales of assets in Dominion Energy Gas’its Consolidated Statements of Income (reflected in the Corporate and Other segment), primarily associated with the eliminationderecognition of its overriding royalty interestnoncontrolling interest. Except as specifically identified, all activity related to Four Brothers and in 2018, a $65 million ($47 millionafter-tax)gain included in gains on salesThree Cedars is recorded within Contracted Assets.
Acquisition of In November Virginia Power CCRO Utilization In 2021, Virginia Power wrote off $318 million, primarily to Sale of Utility Property In 2022, Dominion Energy assets in Dominion Energy Gas’ Consolidated Statements of Income associated with the final conveyance of acreage.2014, Dominion Energy Gas2021, Wexpro closed on an agreement with a natural gas producergathering systems operator to convey over time approximately 24,000 acres of Marcellus Shale development rights underneath one of itspurchase an existing natural gas storage fields. The agreement providedgathering system in Wyoming including pipelines, compressors and dehydration equipment for paymentstotal consideration of $41 million.Dominion Energy Gas, subject to customary adjustments,accumulated depreciation, representing the utilization of approximately $120 million over a period of four years, and an overriding royalty interestCCRO in gas produced fromaccordance with the acreage. In 2014 through 2016, Dominion Energy Gas received approximately $70 million in proceeds on the conveyance of approximately 12,000 acres and as well as a 50% interest in approximately 4,000 acres along with an overriding royalty interest, which resulted in the recognition of $70 million of gains. In July 2017,GTSA in connection with the existing agreement,settlement of the 2021 Triennial Review. See Note 13 for additional information.Gas conveyed an additional 50% interestcompleted the sales of certain utility property in approximately 2,000 acresSouth Carolina, as approved by the South Carolina Commission, for total cash consideration of Marcellus Shale development rights and received proceeds$20 million. In connection with the sales, Dominion Energy recognized a gain of $5$20 million and an overriding royalty interest
143
NOTE 11. GOODWILL AND INTANGIBLE ASSETS
Goodwill and Intangible Assets
The changes in Dominion Energy’s and Dominion Energy Gas’ 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 Transmission & Storage | Gas Distribution | Dominion Energy South Carolina | Contracted Generation | Corporate and Other | Total | ||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||
Dominion Energy | ||||||||||||||||||||||||||||
Balance at December 31, 2017 (1) | $ | 2,106 | $ | 1,561 | $ | 2,496 | $ | — | $ | 242 | $— | $ | 6,405 | |||||||||||||||
Purchase Accounting Adjustment | — | 4 | 1 | — | — | — | 5 | |||||||||||||||||||||
Balance at December 31, 2018 (1) | $ | 2,106 | $ | 1,565 | $ | 2,497 | $ | — | $ | 242 | $— | $ | 6,410 | |||||||||||||||
SCANA Combination (2) | — | 73 | 1,015 | 1,521 | — | — | 2,609 | |||||||||||||||||||||
Contribution of SEMI to Wrangler (3) | — | (73 | ) | — | — | — | — | (73 | ) | |||||||||||||||||||
Balance at December 31, 2019 (1) | $ | 2,106 | $ | 1,565 | $ | 3,512 | $ | 1,521 | $ | 242 | $— | $ | 8,946 | |||||||||||||||
Dominion Energy Gas | ||||||||||||||||||||||||||||
Balance at December 31, 2017 (1) | $ | — | $ | 1,466 | $ | — | $ | — | $ | — | $— | $ | 1,466 | |||||||||||||||
Purchase Accounting Adjustment | — | 5 | — | — | — | — | 5 | |||||||||||||||||||||
Balance at December 31, 2018 (1) | $ | — | $ | 1,471 | $ | — | $ | — | $ | — | $— | $ | 1,471 | |||||||||||||||
No events affecting goodwill | — | — | — | — | — | — | — | |||||||||||||||||||||
Balance at December 31, 2019 (1) | $ | — | $ | 1,471 | $ | — | $ | — | $ | — | $— | $ | 1,471 | |||||||||||||||
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 $106$115 million, $82$79 million and $80$69 million for 2019, 2018the years ended December 31, 2022, 2021 and 2017,2020, respectively. In 2019, in addition to intangible assets acquired in the SCANA Combination,$120$488 million of intangible assets, primarily representing RGGI allowances and software, andright-of-useassets, with an estimated weighted-average amortization period of approximately 10 years.3 years. Amortization expense for Virginia Power’s intangible assets was $30$67 million, $31 million and $28 million for 2019the years ended December 31, 2022, 2021 and $31 million for both 2018 and 2017.2020, respectively. In 2019,2022, Virginia Power acquired $52$430 million of intangible assets, primarily representing RGGI allowances and software, with an estimated weighted-average amortization period of 8 years. Dominion Energy Gas’ amortization expense for intangible assets was $11 million for both 2019 and 2018 and $9 million for 2017. In 2019, Dominion Energy Gas acquired $7 million of intangible assets, primarily representing software and2 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 |
|
2019 | 2018 | |||||||||||||||
At December 31, | Gross Carrying Amount | Accumulated Amortization | Gross Carrying Amount | Accumulated Amortization | ||||||||||||
(millions) | ||||||||||||||||
Dominion Energy | ||||||||||||||||
Software, licenses and other | $ | 1,340 | $549 | $ | 1,033 | $363 | ||||||||||
Virginia Power | ||||||||||||||||
Software, licenses and other | $ | 406 | $135 | $ | 384 | $134 | ||||||||||
Dominion Energy Gas | ||||||||||||||||
Software, licenses and other | $ | 178 | $ 72 | $ | 179 | $ 64 | ||||||||||
Annual amortization expense for these intangible assets is estimated to be as follows:
|
|
| 2023 |
|
| 2024 |
|
| 2025 |
|
| 2026 |
|
| 2027 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
| |||||
Dominion Energy |
| $ | 74 |
| $ | 67 |
| $ | 59 |
| $ | 47 |
| $ | 29 |
|
Virginia Power |
| $ | 33 |
| $ | 30 |
| $ | 26 |
| $ | 20 |
| $ | 10 |
|
2020 | 2021 | 2022 | 2023 | 2024 | ||||||||||||||||
(millions) | ||||||||||||||||||||
Dominion Energy | $ | 88 | $ | 78 | $ | 70 | $ | 56 | $ | 49 | ||||||||||
Virginia Power | $ | 25 | $ | 19 | $ | 15 | $ | 8 | $ | 6 | ||||||||||
Dominion Energy Gas | $ | 9 | $ | 8 | $ | 8 | $ | 5 | $ | 4 | ||||||||||
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 |
|
At December 31, | 2019 | 2018 | ||||||
(millions) | ||||||||
Dominion Energy | ||||||||
Regulatory assets: | ||||||||
Deferred cost of fuel used in electric generation (1) | $ | 48 | $ | 174 | ||||
Deferred project costs and DSM programs for gas utilities (2) | 21 | 17 | ||||||
Unrecovered gas costs (3) | 102 | 14 | ||||||
Deferred rate adjustment clause costs for Virginia electric utility (4)(5) | 109 | 78 | ||||||
Deferred nuclear refueling outage costs (6) | 68 | 69 | ||||||
NND Project costs (7) | 138 | — | ||||||
PJM transmission rates (8) | 121 | 45 | ||||||
Other | 272 | 99 | ||||||
Regulatory assets-current | 879 | 496 | ||||||
Deferred cost of fuel used in electric generation (1) | — | 83 | ||||||
P ension and other postretirement benefit costs(9) | 1,431 | 1,497 | ||||||
Deferred rate adjustment clause costs for Virginia electric utility (4)(5)(10) | 235 | 230 | ||||||
PJM transmission rates (8) | 85 | 192 | ||||||
Deferred project costs for gas utilities (2) | 521 | 335 | ||||||
Interest rate hedges (11) | 741 | 184 | ||||||
AROs and related funding (12) | 311 | — | ||||||
Cost of reacquired debt (13)(14) | 262 | 3 | ||||||
NND Project costs (7) | 2,503 | — | ||||||
Ash pond and landfill closure costs (15) | 1,016 | 27 | ||||||
Other | 582 | 125 | ||||||
Regulatory assets-noncurrent | 7,687 | 2,676 | ||||||
Total regulatory assets | $ | 8,566 | $ | 3,172 | ||||
Regulatory liabilities: | ||||||||
Provision for future cost of removal and AROs (16) | $ | 142 | $ | 117 | ||||
Reserve for refunds and rate credits to electric utility customers (17) | 143 | 71 | ||||||
Cost-of-service impact of 2017 Tax Reform Act(18) | 4 | 104 | ||||||
Income taxes refundable through future rates (19) | 77 | — | ||||||
Monetization of guarantee settlement (20) | 67 | — | ||||||
Other | 64 | 64 | ||||||
Regulatory liabilities-current | 497 | 356 | ||||||
Income taxes refundable through future rates (19) | 5,088 | 4,071 | ||||||
Provision for future cost of removal and AROs (16) | 2,302 | 1,409 | ||||||
Nuclear decommissioning trust (21) | 1,471 | 1,070 | ||||||
Monetization of guarantee settlement (20) | 970 | — | ||||||
Reserve for refunds and rate credits to electric utility customers (17) | 656 | — | ||||||
Overrecovered other postretirement benefit costs (22) | 189 | 120 | ||||||
Other | 325 | 170 | ||||||
Regulatory liabilities-noncurrent | 11,001 | 6,840 | ||||||
Total regulatory liabilities | $ | 11,498 | $ | 7,196 | ||||
145
Reflects deferrals under Virginia Power’s electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects. See Note 13 for additional information. | ||||||||
At December 31, | 2019 | 2018 | ||||||
(millions) | ||||||||
Virginia Power | ||||||||
Regulatory assets: | ||||||||
Deferred cost of fuel used in electric generation (1) | $ | 48 | $ | 174 | ||||
Deferred rate adjustment clause costs (2)(3) | 109 | 78 | ||||||
Deferred nuclear refueling outage costs (4) | 68 | 69 | ||||||
PJM transmission rates (5) | 121 | 45 | ||||||
Other | 87 | 58 | ||||||
Regulatory assets-current | 433 | 424 | ||||||
Deferred rate adjustment clause costs (2)(3)(6) | 235 | 230 | ||||||
PJM transmission rates (5) | 85 | 192 | ||||||
Interest rate hedges (7) | 404 | 151 | ||||||
Deferred cost of fuel used in electric generation (1) | — | 83 | ||||||
Ash pond and landfill closure costs (8) | 1,016 | 27 | ||||||
Other | 123 | 54 | ||||||
Regulatory assets-noncurrent | 1,863 | 737 | ||||||
Total regulatory assets | $ | 2,296 | $ | 1,161 | ||||
Regulatory liabilities: | ||||||||
Provision for future cost of removal (9) | $ | 103 | $ | 92 | ||||
Cost-of-service impact of 2017 Tax Reform Act(10) | — | 95 | ||||||
Reserve for rate credits to electric utility customers (11`) | — | 71 | ||||||
Income taxes refundable through future rates (12) | 54 | — | ||||||
Other | 10 | 41 | ||||||
Regulatory liabilities-current | 167 | 299 | ||||||
Income taxes refundable through future rates (12) | 2,438 | 2,579 | ||||||
Nuclear decommissioning trust (13) | 1,471 | 1,070 | ||||||
Provision for future cost of removal (9) | 1,054 | 940 | ||||||
Other | 111 | 58 | ||||||
Regulatory liabilities-noncurrent | 5,074 | 4,647 | ||||||
Total regulatory liabilities | $ | 5,241 | $ | 4,946 | ||||
At December 31, | 2019 | 2018 | ||||||
(millions) | ||||||||
Dominion Energy Gas | ||||||||
Regulatory assets: | ||||||||
Unrecovered gas costs (1) | $ | 2 | $ | 1 | ||||
Other | 6 | 7 | ||||||
Regulatory assets-current (2) | 8 | 8 | ||||||
Unrecognized pension and other postretirement benefit costs (3) | — | 15 | ||||||
Interest rate hedges (4) | 32 | 33 | ||||||
Other | 8 | 4 | ||||||
Regulatory assets-noncurrent | 40 | 52 | ||||||
Total regulatory assets | $ | 48 | $ | 60 | ||||
Regulatory liabilities: | ||||||||
Provision for future cost of removal and AROs (5) | $ | 18 | $ | 9 | ||||
Overrecovered gas costs (1) | 8 | 7 | ||||||
Other | 15 | 8 | ||||||
Regulatory liabilities-current (6) | 41 | 24 | ||||||
Income taxes refundable through future rates (7) | 560 | 530 | ||||||
Provision for future cost of removal and AROs (6) | 95 | 113 | ||||||
Overrecovered other postretirement benefit costs (8) | 133 | 106 | ||||||
Other | 12 | 16 | ||||||
Regulatory liabilities-noncurrent | 800 | 765 | ||||||
Total regulatory liabilities | $ | 841 | $ | 789 | ||||
At December 31, 2019,2022, Dominion Energy and Virginia Power and Dominion Energy Gas’ regulatory assets include $3.3 billion, $1.8$5.5 billion and $46 million,$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.
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.
146
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
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. As amended, it provides for enhanced returns on capital expenditures on specific newly-proposed generation projects.
If the Virginia Commission’s future rate decisions, including actions relating to Virginia Power’s rate adjustment clause filings, differ materially from Virginia Power’s expectations, it may adversely affect its results of operations, financial condition and cash flows.
The GTSA reinstated base rate reviews on a triennial basis, other thancommencing with the first review which will be a quadrennial review, occurring for Virginia Power in 2021 for the four successive12-monthtest periods beginning January 1, 2017 and ending December 31, 2020. This review for Virginia Power will occur one year earlier than under the Regulation Act legislation enacted in February 2015.
Virginia 2020 Legislation
In April 2020, the Governor of Virginia signed into law the VCEA, which along with related legislation forms a comprehensive framework affecting Virginia Power’s operations. The VCEA replaces Virginia’s voluntary renewable energy portfolio standard for Virginia Power with a mandatory program setting annual renewable energy portfolio standard requirements based on the percentage of total electric energy sold by Virginia Power, excluding existing nuclear generation and certain new carbon-free resources, reaching 100% by the end of 2045. The VCEA includes related requirements concerning deployment of wind, solar and energy storage resources, as well as provides for certain measures to increase net-metering, including an allocation for low-income customers, incentivizes energy efficiency programs and provides for cost recovery related to participation in a carbon trading program. While the legislation affects several portions of Virginia Power’s operations, key provisions of the GTSA remain in effect, including the triennial review structure and timing, the use of the CCRO and the $50 million cap on revenue reductions in the first triennial review proceeding. Key provisions of the VCEA and related legislation passed include the following:
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 credits totaling $200adjustment 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 reduce base ratesbe provided to reflect reductions in income tax expense resulting from the 2017 Tax Reform Act. Asjurisdictional customers as a result Virginia Power incurred a $215 million ($160 millionafter-tax)charge in connection with this legislation, includingof the 2021 Triennial Review as well as the impact on certainJuly
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 respectively,in one-time refunds to current customers’ bills.
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 May 2022, Virginia Power filed its annual fuel factor filing with the Virginia Commission to recover an estimated $2.3 billion in Virginia jurisdictional projected fuel expense for the rate year beginning July 1, 2022 and a projected $1.0 billion under-recovered balance as of June 30, 2022. Virginia Power’s proposed fuel rate represents a fuel revenue increase of $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 reduced baseproposed a change in the timing of fuel cost recovery for certain customers who elect market-based rates on an annual basis by $125 million effective July 2018, to reflect the estimated effectthat would consider those customers’ portion of the 2017 Tax Reform Act.projected under-recovered balance to have been recovered as of June 30, 2022. In March 2019,July 2022, Virginia Power, the Virginia Commission directed an annual revenue reductionstaff and another party filed a comprehensive settlement agreement with the Virginia Commission for approval. The comprehensive settlement agreement provides for the collection of $183the requested under-recovered projected fuel expense over a three-year period beginning July 1, 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 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 rates for generationthe second quarter of 2022 within impairment of assets and distribution services pursuant toother charges in its Consolidated Statement of Income (reflected in the GTSA effective April 2019.
Renewable Generation Projects – Construction
In September 2021, Virginia Power filed a petition with the Virginia Commission for approvalCPCNs to construct and operate 13 utility-scale projects totaling approximately 661 MW of the first three yearssolar generation and 70 MW of energy storage as part of itsten-yearplan for electric distribution grid transformation efforts to meet the renewable generation development requirements under the VCEA. The projects as authorized by the GTSA. During the first three years of the plan, Virginia Power proposedare expected to focus on the following seven foundational components of the overall grid transformation plan: (i) smart meters; (ii) customer information platform; (iii) reliability and resilience; (iv) telecommunications infrastructure; (v) cyber and physical security; (vi) predictive analytics; and (vii) emerging technology. The total estimated capital investment during 2019-2021 was $816 million and the proposed operations and maintenance expenses were $102 million. In January 2019, the Virginia Commission issued its final order approving capital spending for the first three years of the plan totaling $68 million on cyber and physical security and related telecommunications infrastructure (Phase IA). The Virginia Commission declined to approve the remainder 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 recordcost approximately $1.4 billion in the proceeding.
In May 2019, Virginia Power filed its annual fuel factor with the Virginia Commission to recover an estimated $1.5 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 2019 and the projected June 30, 2019 under recovered balance of $124 million. Virginia Power’s proposed fuel rate represented a fuel revenue decrease of $192 million when applied to projected kilowatt-hour sales for the period July 1, 2019 to June 30, 2020. Subsequently in May 2019, Virginia Power revised its fuel factor filing to reduce the projected June 30, 2019
In October 2022, Virginia Power filed a petition with the Virginia Commission for CPCNs to construct 2and operate eight utility-scale projects totaling approximately 474 MW of solar facilities. Colonial Trail Westgeneration and Spring Grove 116 MW of energy storage as part of its efforts to meet the renewable generation development requirements under the VCEA. The projects, as of October 2022, are estimatedexpected to cost approximately $410 million,$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 petition with the Virginia Commission requesting a determination that it is reasonable and prudent for Virginia Power to pursue a nuclear life extension program to extend the operating licenses of Surry and North Anna and to carry out projects to upgrade or replace systems and equipment necessary to continue to safely and reliably operate these nuclear power stations. The nuclear life extension program is expected to cost approximately $3.9 billion, excluding financing costs. Colonial Trail West commenced commercial operations in December 2019 and Spring Grove 1 is expected to commence commercial operations in the fourth quarter of 2020. Virginia Power also applied for approval of RiderUS-3associated with these projects with a proposed $10 million total revenue requirement for the rate year beginning June 1, 2019. In January 2019, the Virginia Commission issued a final order granting CPCNs to construct the solar facilities, subject to a20-yearperformance guarantee of the facilities at a 25% solar capacity factor when normalized for force majeure events. In April 2019,July 2022, the Virginia Commission approved RiderUS-3.
149
Riders
Significant 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 |
|
150
Electric Transmission Projects
Significant Virginia Power filed a petition requesting approval of Rider E and proposed a $114 million total revenue requirementelectric transmission projects approved or applied for the rate year beginning November 1, 2019. In August 2019, the Virginia Commission issued an order approving in part and denying in part the petition. As a result, Virginia Power recorded a $21 million ($16 millionafter-tax)charge in impairment of assets and other charges in the Consolidated Statements of Income for the three and nine months ended September 30, 2019 towrite-offcertain disallowed environmental property, plant and equipment and regulatory assets. In August 2019, the Virginia Commission granted Virginia Power’s petition for reconsideration of the disallowed amount and stayed the order issued earlier in August 2019. In October 2019, the Virginia Commission approved Virginia Power’s request to implement a total revenue requirement of $104 million on an interim basis, subject totrue-up,pending resolution of the petition for reconsideration. In November 2019, the Virginia Commission denied the petition for reconsideration and the $104 million total revenue requirement remains in effect.
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 |
|
Rider Name | Application Date | Approval Date | Rate Year Beginning | Total Revenue Requirement (millions) | Increase (Decrease) Over Previous Year (millions) | |||||||||||||||
Rider S | May 2019 | February 2020 | April 2020 | $195 | $(20 | ) | ||||||||||||||
Rider GV | May 2019 | February 2020 | April 2020 | 132 | 12 | |||||||||||||||
Rider W | May 2019 | February 2020 | April 2020 | 106 | 1 | |||||||||||||||
Rider R | May 2019 | February 2020 | April 2020 | 44 | (13 | ) | ||||||||||||||
Rider B | May 2019 | February 2020 | April 2020 | 32 | (6 | ) | ||||||||||||||
Rider US-3 | July 2019 | Pending | June 2020 | 31 | 21 | |||||||||||||||
Rider BW | October 2019 | Pending | September 2020 | 120 | 1 | |||||||||||||||
Rider US-2 | October 2019 | Pending | September 2020 | 10 | (5 | ) | ||||||||||||||
Rider E | January 2020 | Pending | November 2020 | 88 | (16 | ) | ||||||||||||||
In November 2013, the Virginia Commission issued an order granting Virginia Power a CPCN to construct approximately 7 miles of new overhead 500 kV transmission line from the existing Surry switching station in Surry County to a new Skiffes Creek switching station in James City County, and approximately 20 miles of new 230 kV transmission line in James City County, York County, and the City of Newport News from the proposed new Skiffes Creek switching station to Virginia
Description and Location of Project | Application Date | Approval Date | Type of Line | Miles of Lines | Cost Estimate (millions) | |||||||||||||||
Rebuild and operate transmission line between Lanexa and the Northern Neck in Virginia | June 2018 | February 2019 | 230 kV | 3 | $ 30 | |||||||||||||||
Build a new substation and connect three existing transmission lines thereto in Fluvanna County, Virginia | October 2018 | June 2019 | 230 kV | <1 | 30 | |||||||||||||||
Rebuild and operate the Glebe substation and relocate and operate in Arlington County, Virginia and the City of Alexandria, Virginia existing overhead line underground | March 2019 | September 2019 | 230 kV | <1 | 125 | |||||||||||||||
Rebuild and operate transmission line between Valley, Virginia and Mt. Storm, West Virginia | April 2019 | November 2019 | 500 kV | 65 | 290 | |||||||||||||||
Rebuild and operate transmission line between the Suffolk substation and the Virginia/North Carolina state line | May 2019 | November 2019 | 230 kV | 11 | 20 | |||||||||||||||
Rebuild and operate five segments between the Loudoun and Ox substations | August 2019 | Pending | 230 kV | 19 | 70 | |||||||||||||||
Build new Evergreen Mills switching station and line loops in Loudoun County, Virginia | December 2019 | Pending | 230 kV | 2 | 30 | |||||||||||||||
Build new Lockridge substation and line loop in Loudoun County, Virginia | December 2019 | Pending | 230 kV | <1 | 35 | |||||||||||||||
151
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 anon-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 thenon-fuelbase 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. is reviewingfiled a notice of appeal and exceptions to the order and assessing its options.
Virginia Power North Carolina Fuel Filing
In August 2019,2022, Virginia Power submitted its annual filing to the North Carolina Commission to adjust the fuel component of its electric rates. Virginia Power updated its filing in October 2022 to reflect the increased commodity cost of fuel and proposed a total $18$107 million decreaseincrease to the fuel component of its electric rates for the rate year beginning February 1, 2020.2023. Virginia Power also submitted an alternative to recover the increase over a two-year period. Under this approach, Virginia Power proposed a total $80 million increase to the fuel component of its electric rates implemented on a staggered timeline for the rate year beginning February 1, 2023 with remaining unrecovered balances to be recovered in the rate year beginning February 1, 2024. In January 2020,2023, the North Carolina Commission approved Virginia Power’s proposed fuel change adjustment.
PSNC Rider D
Rider D 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. In May 2022, PSNC submitted a filing with, and received approval from, the North Carolina Commission for a $56 million gas cost increase with rates effective June 2022. In September 2022, PSNC submitted a filing with, and received approval from, the North Carolina Commission for a $126 million gas cost increase with 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 gas 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 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. In July 2021, DESC, the South Carolina Office of Regulatory Staff and other parties of record filed a comprehensive settlement agreement with the South Carolina Commission for approval. The comprehensive settlement agreement 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 comprehensive settlement agreement, DESC would not file a retail electric base rate case prior to July 1, 2023, such that new rates would not be effective prior to January 1, 2024, absent unforeseen extraordinary economic or financial conditions that may include changes in corporate tax rates. In July 2021, the South Carolina Commission approved the comprehensive settlement agreement and issued its final order in August 2021.
In connection with this matter, Dominion Energy recorded charges of $249 million ($187 million after-tax) reflected within impairment of assets and other charges (benefits) (reflected in the Corporate and Other segment), including $237 million of regulatory assets associated with DESC’s purchases of its first mortgage bonds during 2019 that are no longer probable of recovery under the settlement agreement, and $18 million ($14 million after-tax) reflected within other income in its Consolidated Statements of Income for the year ended December 31, 2021.
DSM Programs
DESC has approval for a DSM rider through which it recovers expenditures related to its DSM programs.
152
In January 2019,2022, DESC filed an application with the South Carolina Commission seeking approval to recover $30$60 million of costs and net lost revenues associated with these programs, along with an incentive to invest in such programs. In April 2019,2022, the South Carolina Commission approved the request, for the rate year beginningeffective with the first billing cycle of May 2019.
In January 2020,2023, DESC filed an application with the South Carolina Commission seeking approval to recover $40$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 Rate Stabilization Act
In June 2019,2022, DESC filed with the South Carolina Commission its monitoring report for the20192022 with a total revenue requirement of $437$553 million. This represents a $7$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 forwith the rate year beginningfirst billing cycle of November 2019.2022. In October 2019,2022, the South Carolina Commission approvedissued an order approving a total revenue requirement of $436$549 million effective with the first billing cycle of November 2019.
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 April 2019, the South Carolina Commission approved DESC’s proposal to decrease the total fuel cost component of retail electric rates. DESC’s proposal included maintaining its base fuel component at the current level to produce a projected under-recovered balance of $35 million at the end of the12-monthperiod beginning with the first billing cycle of May 2019 and requested carrying costs for any base fuel under-collected balances, should they occur. DESC also proposed reducing its variable environmental component and maintaining or reducing its distributed energy resource components. Changes in rates became effective beginning with the first billing cycle of May 2019.
In February 2020,2022, DESC filed
In February 2020,August 2022, DESC filed an application with the South Carolina Commission requesting approvalseeking a mid-period adjustment to construct and operate 28 milesincrease the base fuel component of 230 kV transmission lines in Aiken County,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 approximately $30component 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 and avoided capacity cost component. The net effect is a proposed annual increase of $176 million. This matter is pending.
Electric - Other
DESC utilizes a pension costs rider approved by the South Carolina Commission which is designed to allow recovery of projected 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 May. In February 2023, DESC requested that the South Carolina Commission 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
In June 2022, the Ohio Commission approved East Ohio’s application to adjust the PIR cost recovery rates for 20182021 costs. The filing reflects gross plant investment for 20182021 of $202$225 million, cumulative gross plant investment of $1.6$2.2 billion and a revenue requirement of $190$273 million.
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 existingCEP-relateddeferrals2019 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$957 million through 2018 and a revenue requirement of $83$119 million. This matter is pending.
In November 1, 2019. In October 2019,2022, the West VirginiaOhio Commission approved PREPadjustments to CEP cost recovery rates effective November 1, 2019.
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 Commission forpre-approvalto construct an LNG storage facility with a liquefaction rate of 8.2 million cubic feet per day. In October 2019, the Utah Commission grantedpre-approvalto construct the LNG storage facility.
Utah Base Rate Case
In July 2019,May 2022, Questar Gas filed its base rate case and schedules with the Utah Commission. Questar Gas proposed a$19$71 million effective March 2020.January 2023. The base rate increase was proposed to recover the significant investment in distribution infrastructure for the benefit of Utah customers. Questar Gas presentedThe proposed rates would provide for an earned returnROE of 9.05% based upon a fully-adjusted test period,10.3% compared to itsthe currently authorized 9.85% return, and proposed a 10.5% ROE. February 2020,December 2022, the Utah Commission approved a non-fuel, base rate increase of $3$48 million for rates effective March 2020. This revenue requirement increase is based onJanuary 2023 with an approved ROE of 9.50%9.6%.
Purchased Gas
In July 2022, the 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 2022.
In November 2019, Questar Gas filed its base rate case and schedules with the Wyoming Commission. Questar Gas proposed a non-fuel, base rate increase of $4 million effective September 2020. The
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. Dominion Energy and Virginia Power’sThe Companies AROs are primarily associated with the decommissioning of their nuclear generation facilities and ash pond and landfill closures. Dominion Energy Gas’ AROs primarily include plugging and abandonment of gas and oil wells and the interim retirement of natural gas gathering, transmission, distribution and storage pipeline components.
154
The Companies have also identified, but not recognized, AROs related to the retirement of the Cove Point LNG Facility, Dominion Energy and Dominion Energy Gas’Energy’s storage wells in theirits 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 Dominion Energy and Virginia Power’sthe 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 20182021 and 20192022 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, 2017 | $ | 2,432 | ||
Obligations incurred during the period | 20 | |||
Obligations settled during the period | (159 | ) | ||
Revisions in estimated cash flows (2) | 120 | |||
Accretion | 119 | |||
AROs at December 31, 2018 (1) | $ | 2,532 | ||
Obligations incurred during the period (2) | 2,413 | |||
Obligations settled during the period | (137 | ) | ||
AROs acquired in the SCANA Combination | 577 | |||
Revisions in estimated cash flows (3) | (324 | ) | ||
Accretion | 213 | |||
AROs at December 31, 2019 (1) | $ | 5,274 | ||
Virginia Power | ||||
AROs at December 31, 2017 | $ | 1,365 | ||
Obligations incurred during the period | 14 | |||
Obligations settled during the period | (119 | ) | ||
Revisions in estimated cash flows (2) | 120 | |||
Accretion | 65 | |||
AROs at December 31, 2018 | $ | 1,445 | ||
Obligations incurred during the period ( 2 ) | 2,408 | |||
Obligations settled during the period | (81 | ) | ||
Revisions in estimated cash flows (3) | (323 | ) | ||
Accretion | 132 | |||
AROs at December 31, 2019 | $ | 3,581 | ||
Dominion Energy Gas | ||||
AROs at December 31, 2017 | $ | 85 | ||
Obligations incurred during the period | 3 | |||
Obligations settled during the period | (6 | ) | ||
Accretion | 6 | |||
AROs at December 31, 2018 ( 4 ) | $ | 88 | ||
Obligations settled during the period | (3 | ) | ||
Accretion | 4 | |||
AROs at December 31, 2019 ( 4 ) | $ | 89 | ||
Dominion Energy’s AROs at December 31, 20192022 and 2018,2021, include $1.7$1.9 billion and $1.6$2.0 billion, respectively, with $0.8$0.9 billion and $0.9$0.9 billion recorded by Virginia Power, related to the future decommissioning of their nuclear facilities. Dominion Energy and Virginia PowerThe Companies have established trusts dedicated to funding the future decommissioning activities.
In addition, AROs at December 31, 20192022 and 2021 include $2.6$2.8 billion and $2.9 billion, respectively, related to Virginia Power’s future ash pond and landfill closure costs. Regulatory mechanisms, primarily March 2019, provide for recovery of costs to be incurred. See NotesNote 12 and 23 for additional information.
155
NOTE 15. Leases
At December 31, 2019,2022 and 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 |
|
In addition to the amounts disclosed above, Dominion Energy’s Consolidated Balance SheetSheets at December 31, 2019 includes2022 and 2021 include property, plant and equipment of $183 million and accumulated depreciation of $2.8$1.2 billion, and $364 million, respectively, related to facilities subject to power purchase agreements under which Dominion Energy is the lessor.
For the yearyears ended December 31, 2019,2022, 2021 and 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
For the yearyears ended December 31, 2019,2022, 2021 and 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:
| 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 |
|
2019 | ||||
In addition to the amounts disclosed above, Dominion Energy’s Consolidated StatementStatements of Income for the yearyears ended December 31, 2019 includes $1742022, 2021 and 2020, include $16 million, $168 million and $175 million, respectively, of rental revenue, included in operating revenue and $94$34 million, $110 million and $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, 2019,2022 and 2021, the weighted average remaining lease term and weighted discount rate for the Companies’ finance and operating leases were as follows:
| 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 |
| ||||||||||
(millions) |
| Operating |
|
| Finance |
|
| Operating |
|
| Finance |
| ||||
2023 |
| $ | 44 |
|
| $ | 52 |
|
| $ | 23 |
|
| $ | 21 |
|
2024 |
|
| 36 |
|
|
| 45 |
|
|
| 19 |
|
|
| 20 |
|
2025 |
|
| 30 |
|
|
| 25 |
|
|
| 15 |
|
|
| 17 |
|
2026 |
|
| 27 |
|
|
| 20 |
|
|
| 12 |
|
|
| 14 |
|
2027 |
|
| 25 |
|
|
| 14 |
|
|
| 10 |
|
|
| 11 |
|
After 2027 |
|
| 642 |
|
|
| 15 |
|
|
| 314 |
|
|
| 13 |
|
Total undiscounted lease payments |
|
| 804 |
|
|
| 171 |
|
|
| 393 |
|
|
| 96 |
|
Present value adjustment |
|
| (251 | ) |
|
| (21 | ) |
|
| (99 | ) |
|
| (14 | ) |
Present value of lease liabilities |
| $ | 553 |
|
| $ | 150 |
|
| $ | 294 |
|
| $ | 82 |
|
Maturity of Lease Liabilities | Dominion Energy | Virginia Power | Dominion Energy Gas | |||||||||||||||||||||
Operating | Finance | Operating | Finance | Operating | Finance | |||||||||||||||||||
(millions) | ||||||||||||||||||||||||
2020 | $ | 72 | $ | 34 | $ | 34 | $ | 4 | $ | 7 | $ | 2 | ||||||||||||
2021 | 65 | 31 | 30 | 4 | 6 | 1 | ||||||||||||||||||
2022 | 55 | 29 | 24 | 4 | 5 | 1 | ||||||||||||||||||
2023 | 45 | 26 | 19 | 3 | 4 | 1 | ||||||||||||||||||
2024 | 36 | 19 | 14 | 3 | 3 | 1 | ||||||||||||||||||
After 2024 | 582 | 9 | 205 | 4 | 20 | 1 | ||||||||||||||||||
Total undiscounted lease payments | 855 | 148 | 326 | 22 | 45 | 7 | ||||||||||||||||||
Present value adjustment | (377 | ) | (14 | ) | (139 | ) | (3 | ) | (10 | ) | (1 | ) | ||||||||||||
Present value of lease liabilities | $ | 478 | $ | 134 | $ | 187 | $ | 19 | $ | 35 | $ | 6 | ||||||||||||
Corporate Office Leasing Arrangements
In July 2016,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 $365$465 million, which funded totalto fund the estimated 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.
Offshore Wind Vessel Leasing Arrangement
In December 2019,2020, Dominion Energy signed an agreement (subsequently amended in December 2022) with a lessor to constructcomplete construction of and lease a new corporate office property in Richmond, Virginia.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 thethrough completion, itnotcompletedearlier thanmid-2023.costs.costs, which totaled $334 million as of December 31, 2022. If the project is terminated under certain events of default, Dominion Energy could be required to pay up to 89.9%100% of the then funded amount. For specific full recourse events, Dominion Energy could be required to pay up to 100% of the then funded amount.
The51-monthfacilityvessel is able to be occupied.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 five years,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 up to 83% of project costs, for the difference between the outstanding project costs and sale proceeds.
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, 2019,2022, Dominion Energy owns the manager and 67% of thea 50% membership interest in certain merchant solar facilities,Cove Point, as discussed in Note 2.Notes 3 and 9. Dominion Energy has concluded that these entities are VIEsCove Point is a VIE due to the memberslimited partners lacking the characteristics of a controlling financial interest. In addition, in 2016As a result of the GT&S Transaction, effective November 1, 2020, Dominion Energy created a wholly owned subsidiary, SBL Holdco, as a holding company of its interest in the VIE merchant solar facilities and accordingly SBL Holdco is a VIE. Dominion Energy isno longer the primary beneficiary of SBL Holdco and the merchant solar facilities,Cove Point as it hasBHE retains the power to direct the activities that most significantly impact theirCove Point’s economic performanceperformance. Dominion Energy’s maximum exposure to loss is limited to its current and future investment, 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 $31 million and $267 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 merchant solar facilities.
At December 31, 2022, Dominion Energy owns a 48%53% membership interest in Atlantic Coast Pipeline. See Note 9 for more details regarding the nature of this entity. 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 among multiple unrelated parties. In February 2020, Dominion Energy entered an agreement to acquire Southern’s 5% membership interest which is expected to close by the second quarter of 2020. Following completion of the acquisition, Dominion Energy will own a 53% noncontrolling membership interest in Atlantic Coast Pipeline which is not expected to change Dominion Energy’s conclusion that it is not the primary beneficiary as the power to direct the activities most significant to Atlantic Coast Pipeline will be shared with Duke.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 its current andany future investment as well as any obligations under a guarantee provided.investment. See Note 239 for more information.
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
Virginia Power
Virginia Power had a long-term power and capacity contract with 1non-utilitygenerator 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 thenon-utilitygenerator. A $135 million ($100 millionafter-tax)charge was recorded in impairment of assets and other charges in Virginia Power’s Consolidated Statements of Income during the second quarter of 2019. Virginia Power paid $13 million, $50 million, and $86 million for electric capacity tonon-utilitygenerators and $1 million, $18 million and $24 million for electric energy tonon-utilitygenerators for the years ended December 31, 2019, 2018 and 2017, respectively.
158
Dominion Energy subsidiaries, including Virginia Power and Dominion Energy Gas.Power. Virginia Power and Dominion Energy Gas havehas no obligation to absorb more than theirits allocated sharesshare 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, 2019 | ||||||||||||||||
Joint revolving credit facility (2) | $ | 6,000 | $836 | $89 | $ | 5,075 | ||||||||||
At December 31, 2018 | ||||||||||||||||
Joint revolving credit facility (2) | $ | 6,000 | $324 | $88 | $ | 5,588 | ||||||||||
|
| 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 |
|
| The weighted-average interest rates of the outstanding commercial paper supported by Dominion Energy’s |
DESC was addedand Questar Gas’ short-term financings are supported through access as a borrowerco-borrowers to the joint revolving credit facility discussed above with Dominion Energy, Virginia Power, Dominion Energy Gas and Questar Gas. DESC’s short-term financing is supported through its access asco-borrowerto the facility.Companies. At December 31, 2019,2022, thesub-limitwas $500 million.
In March 2019. Liquidity needs for these entities may be satisfied through short-term intercompany borrowings from Dominion Energy.
In addition to the joint revolving credit facility mentioned above, Dominion Energy also has a credit facility with a maturity date in June 2020 which allows Dominion Energy to issue up to approximately $21$30 million in letters of credit.credit and was scheduled to mature in June 2022. In April 2022, Dominion Energy entered into an agreement to amend and restate this facility to 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, 2019,2022 and 2021, Dominion Energy had $21$25 million and $29 million in letters of credit outstanding under this agreement.
In September 2019,December 2021, in connection with the sale of certain non-wholly owned nonregulated solar facilities, as discussed in Note 10, SBL Holdco terminated $30 million of credit facilities and Dominion Solar Projects III, Inc. terminated $25 million of credit facilities.
In July 2021, Dominion Energy Questarentered into an approximately $1.3 billion term loan credit agreement following the termination of the Q-Pipe Transaction as discussed in Note 3 and borrowed $3.0 billion under a 364-Day Term Loan Agreement that accruedthe full amount available thereunder. The term loan was scheduled to mature in December 2021, with the ability to extend maturity at Dominion Energy’s option to June 2022 and bore interest at a variable rate. The proceeds were utilized to repay the deposit received from BHE on the Q-Pipe Transaction. In December 2021, Dominion Energy used the net proceeds from the borrowing were usedcompletion of the sale of the Q-Pipe Group to Southwest Gas to repay the principal of Cove Point’s $3.0 billionoutstanding under the term loan dueplus accrued interest.
In December 2021, DECP Holdings entered into a credit facility, which allows it to issue up to $110 million in 2021. 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 provided a guaranteehas an effective shelf registration statement with the SEC for the sale of up to support$3.0 billion of variable denomination floating rate demand notes, called Dominion Energy Questar’s obligationReliability 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 and December 31, 2021, Dominion Energy’s Consolidated Balance Sheets include $347 million and $431 million, respectively, presented within short-term 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 the364-DayTerm Loan Agreement. In November and December 2019, principal of $1.0 billion and $2.0 billion, respectively, plus accrued interest was repaid.
Virginia Power
Virginia Power’s short-term financing is supported through its access astheDominion 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 itsthe joint revolving credit facility with Dominion Energy, Dominion Energy Gas, 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, 2019 | ||||||||||||
Joint revolving credit facility (2) | $6,000 | $243 | $ 7 | |||||||||
At December 31, 2018 | ||||||||||||
Joint revolving credit facility (2) | $6,000 | $314 | $16 | |||||||||
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 its jointthis 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 |
| |
Facility Limit | Outstanding Commercial Paper (1) | Outstanding Letters of Credit | ||||||||||
(millions) | ||||||||||||
At December 31, 2019 | ||||||||||||
Joint revolving credit facility (2) | $1,500 | $62 | $— | |||||||||
At December 31, 2018 | ||||||||||||
Joint revolving credit facility (2) | $1,500 | $10 | $— | |||||||||
161
At December 31, | 2019 Weighted- average Coupon (1) | 2019 | 2018 | |||||||||
(millions, except percentages) | ||||||||||||
Dominion Energy Gas Holdings, LLC: | ||||||||||||
Unsecured senior notes: | ||||||||||||
Variable rate, due 2021 | 2.49 | % | $ | 500 | $ | 500 | ||||||
2.5% to 4.8%, due 2019 to 2049 (2) | 3.44 | % | 4,631 | 3,587 | ||||||||
Cove Point, term loan, due 2021 (3) | — | 3,000 | ||||||||||
Dominion Energy Midstream: | ||||||||||||
Term loan, variable rate, due 2019 | — | 300 | ||||||||||
Revolving credit agreement, variable rate, due 2021 (4) | — | 73 | ||||||||||
Dominion Energy Questar Pipeline, unsecured senior notes, 3.53% to 4.875%, due 2028 to 2041 | 4.23 | % | 430 | 430 | ||||||||
Dominion Energy Gas Holdings, LLC total principal | $ | 5,561 | $ | 7,890 | �� | |||||||
Securities due within one year | 2.80 | % | (699 | ) | (748 | ) | ||||||
Credit facility borrowings (4) | — | (73 | ) | |||||||||
Unamortized discount and debt issuance costs | (41 | ) | (47 | ) | ||||||||
Finance leases | 5 | — | ||||||||||
Dominion Energy Gas Holdings, LLC total long-term debt | $ | 4,826 | $ | 7,022 | ||||||||
Virginia Electric and Power Company: | ||||||||||||
Unsecured senior notes: | ||||||||||||
2.75% to 8.875%, due 2019 to 2049 | 4.27 | % | $ | 11,789 | $ | 11,090 | ||||||
Tax- exempt financings, 1.80% to 5.0%, due 2023 to 2041(5) (6) | 2.02 | % | 625 | 664 | ||||||||
Virginia Electric and Power Company total principal | $ | 12,414 | $ | 11,754 | ||||||||
Securities due within one year | 4.29 | % | (1 | ) | (350 | ) | ||||||
Unamortized discount, premium and debt issuances costs, net | (88 | ) | (83 | ) | ||||||||
Finance leases | 16 | — | ||||||||||
Virginia Electric and Power Company total long-term debt | $ | 12,341 | $ | 11,321 | ||||||||
Dominion Energy, Inc.: | ||||||||||||
Unsecured senior notes: | ||||||||||||
Variable rates, due 2019 and 2020 | 2.31 | % | $ | 300 | $ | 800 | ||||||
1.6% to 7.0%, due 2019 to 2049 (7) | 4.15 | % | 7,688 | 7,488 | ||||||||
Unsecured junior subordinated notes: | ||||||||||||
2.579% to 4.104%, due 2019 to 2024 | 3.01 | % | 2,950 | 2,100 | ||||||||
Payable to affiliated trust, 8.4%, due 2031 | 8.40 | % | 10 | 10 | ||||||||
Enhanced junior subordinated notes: | ||||||||||||
Variable rates, due 2066 (8) | 4.41 | % | 397 | 422 | ||||||||
5.25% and 5.75%, due 2054 and 2076 | 5.48 | % | 1,485 | 1,485 | ||||||||
Remarketable subordinated notes, 2.0%, due 2021 and 2024 | — | 1,400 | ||||||||||
Questar Gas, unsecured senior notes, 2.98% to 7.20%, due 2024 to 2051 | 4.25 | % | 750 | 750 | ||||||||
SCANA: | ||||||||||||
Unsecured medium term notes, 4.125% to 6.25%, due 2020 to 2022 (9)(10) | 5.06 | % | 508 | — | ||||||||
Unsecured senior notes, variable rate, due 2034 (11) | 2.61 | % | 66 | — | ||||||||
PSNC, senior debentures and notes, 4.13% to 7.45%, due 2020 to 2047 | 5.05 | % | 700 | — | ||||||||
DESC: | ||||||||||||
First mortgage bonds, 3.22% to 6.625%, due 2021 to 2065 (12) | 5.42 | % | 3,267 | — | ||||||||
Tax- exempt financings:(13) | ||||||||||||
Variable rate due 2038 | 1.65 | % | 35 | — | ||||||||
GENCO, variable rates due 2038 (14) | 1.65 | % | 33 | — | ||||||||
3.625% and 4.00%, due 2028 and 2033 | 3.90 | % | 54 | — | ||||||||
Other | 3.69 | % | 1 | — | ||||||||
Secured senior notes, 4.82%, due 2042 (15) | 4.82 | % | 345 | 362 | ||||||||
Term loans, variable rates, due 2023 and 2024 (15) | 4.24 | % | 527 | 582 | ||||||||
Tax- exempt financing, 1.7%, due 2033 | 1.70 | % | 27 | 27 | ||||||||
Dominion Energy Gas Holdings, LLC total principal (from above) | 5,561 | 7,890 | ||||||||||
Virginia Electric and Power Company total principal (from above) | 12,414 | 11,754 | ||||||||||
Dominion Energy, Inc. total principal | $ | 37,118 | $ | 35,070 | ||||||||
Fair value hedge valuation (16) | 4 | (20 | ) | |||||||||
Securities due within one year (8)(10)(11)(17) | 3.41 | % | (3,133 | ) | (3,624 | ) | ||||||
Credit facility borrowings (4) | — | (73 | ) | |||||||||
Unamortized discount, premium and debt issuance costs, net | (270 | ) | (248 | ) | ||||||||
Finance leases | 105 | 39 | ||||||||||
Dominion Energy, Inc. total long-term debt | $ | 33,824 | $ | 31,144 | ||||||||
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, 2019,2022, were as follows:
| 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 | $ | 700 |
| $ | 350 |
| $ | 350 |
| $ | 1,150 |
| $ | 1,350 |
| $ | 11,235 |
| $ | 15,135 |
|
Tax-Exempt Financings |
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 625 |
|
| 625 |
|
Total | $ | 700 |
| $ | 350 |
| $ | 350 |
| $ | 1,150 |
| $ | 1,350 |
| $ | 11,860 |
| $ | 15,760 |
|
Weighted-average Coupon |
| 2.75 | % |
| 3.45 | % |
| 3.10 | % |
| 3.08 | % |
| 3.61 | % |
| 4.10 | % |
|
| |
2020 | 2021 | 2022 | 2023 | 2024 | Thereafter | Total | ||||||||||||||||||||||
(millions, except percentages) | ||||||||||||||||||||||||||||
Dominion Energy Gas | $ | 700 | $ | 500 | $ | — | $ | 650 | $ | 1,050 | $ | 2,661 | $ | 5,561 | ||||||||||||||
Weighted-average coupon | 2.80 | % | 2.49 | % | — | 3.29 | % | 2.97 | % | 3.95 | % | |||||||||||||||||
Virginia Power | ||||||||||||||||||||||||||||
Unsecured senior notes | $ | — | $ | — | $ | 750 | $ | 700 | $ | 350 | $ | 9,989 | $ | 11,789 | ||||||||||||||
Tax- exempt financings | — | — | — | — | 625 | 625 | ||||||||||||||||||||||
Total | $ | — | $ | — | $ | 750 | $ | 700 | $ | 350 | $ | 10,614 | $ | 12,414 | ||||||||||||||
Weighted-average coupon | — | — | 3.15 | % | 2.75 | % | 3.45 | % | 4.35 | % | ||||||||||||||||||
Dominion Energy | ||||||||||||||||||||||||||||
Term loans (1 ) | $ | 35 | $ | 35 | $ | 34 | $ | 259 | $ | 164 | $ | — | $ | 527 | ||||||||||||||
First mortgage bonds | — | 33 | — | — | — | 3,234 | 3,267 | |||||||||||||||||||||
Unsecured senior notes (2)(3) | 1,275 | 1,237 | 1,659 | 2,355 | 1,745 | 19,092 | 27,363 | |||||||||||||||||||||
Secured senior notes | 15 | 17 | 19 | 16 | 17 | 261 | 345 | |||||||||||||||||||||
Tax- exempt financings | — | — | — | — | — | 774 | 774 | |||||||||||||||||||||
Unsecured junior subordinated notes payable to affiliated trusts | — | — | — | — | — | 10 | 10 | |||||||||||||||||||||
Unsecured junior subordinated notes | 1,000 | 1,250 | — | — | 700 | — | 2,950 | |||||||||||||||||||||
Enhanced junior subordinated notes (4) | — | — | — | — | — | 1,882 | 1,882 | |||||||||||||||||||||
Total | $ | 2,325 | $ | 2,572 | $ | 1,712 | $ | 2,630 | $ | 2,626 | $ | 25,253 | $ | 37,118 | ||||||||||||||
Weighted-average coupon | 3.09 | % | 3.15% | 3.10 | % | 2.95% | 3.19% | 4.62 | % | |||||||||||||||||||
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, 2019,2022, there were no events of default under these covenants.
Enhanced Junior Subordinated Notes
In October 2014, Dominion Energy issued $685$685 million of October 2014 hybrids that will bear interest at 5.75%5.75% per year until October 1, 2024. Thereafter, they will bear interest at theassuming three-month LIBOR plus 3.057%, reset quarterly.
In July 2016, Dominion Energy issued $800$800 million of 5.25%5.25% July 2016 hybrids. TheIn August 2021, Dominion Energy redeemed the remaining principal outstanding of $800 million of its July 2016 hybrids, arewhich would have otherwise matured in 2076 and were 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.
Derivative Restructuring
In July 2014,June 2020, Dominion Energy amended a portfolio of interest rate swaps with a notional value of $2.0 billion, extending the mandatory termination dates from 2020 and 2021 to December 2024. As a result of this noncash financing activity with an embedded interest rate swap, Dominion Energy recorded $326 million in other long-term debt representing the net present value of the initial fair value measurement of the new contract with an imputed interest rate of 1.19%, in its Consolidated Balance Sheets with an embedded
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 million, extending the mandatory termination dates from 2020 to December 2023. As a result of this noncash financing activity with an embedded interest rate swap, Virginia Power recorded $443 million in other long-term debt representing the net present value of the initial fair value measurement of the new contract with an imputed interest rate of 0.34%, in its Consolidated Balance Sheets with an embedded interest rate derivative that had a fair value of zero at inception. The interest rate swaps were in a hedge relationship prior to the transaction. Virginia Power de-designated the hedge relationships prior to the transaction and then designated the new interest rate swap in a hedge relationship after the transaction.
NOTE 19. PREFERRED STOCK
Dominion Energy is authorized to issue up to 20 million shares of preferred stock, which may be designated into separate classes. At December 31, 2022, Dominion Energy had issued and outstanding 1.8 million shares preferred stock, 0.8 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, 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, 2022 and 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 liquidation preference; however, none were issued and outstanding at December 31, 2022 or 2021.
2019 Corporate Units
In June 2019, Dominion Energy issued $1.0$1.6 billion of 2014 Series A 6.375%2019 Equity Units, initially in the form of Corporate Units. In August 2016, Dominion Energy issued $1.4 billion of 20162019 Series A 6.75% Equity Units, initially in the form of Corporate
Each 20142019 Series A Corporate Unit consisted of a stock purchase contract and a 1/2010, or 10%, undivided beneficial ownership interest in a RSN issued by Dominion Energy. Each 2016one share of Series A Corporate Unit consistedPreferred Stock. Beginning in June 2022, the Series A Preferred Stock was convertible at the option of the holder. Settlement of any conversion was initially payable in cash, common stock or a combination thereof, at Dominion Energy’s election. In November 2021, Dominion Energy’s Articles of Incorporation were amended to require that any conversion of its Series A Preferred Stock be settled, at Dominion Energy’s election, either entirely in cash or in cash up to the first $1,000 per share and in shares of Dominion Energy common stock, purchase contract,cash or any combination thereof for any amounts in excess of $1,000 per share. As a 1/40 interestresult of establishing a minimum amount to be settled in a 2016cash if the holders elect to convert the SeriesA-1RSN issued A Preferred Stock, $1.6 billion was reclassified from equity to mezzanine equity in 2021. The Series A Preferred Stock was redeemable in cash by Dominion Energy and a 1/40 interest in a 2016 SeriesA-2RSN issued by Dominion Energy. beginning September 2022 at the liquidation preference.
The stock purchase contracts obligated the holders to purchase shares of Dominion Energy common stock at a future settlement date prior to the relevant RSN maturity date.in June 2022. The purchase price paid under the stock purchase contracts was $50$100 per Corporate Unit and the number of shares purchased was determined under a formula based upon the average closing price of Dominion Energy common stock near the settlement date. The RSNs were pledged as collateral to secure the purchase of common stock under the related stock purchase contracts.
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
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 | ||||||||||||||||||
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 $2$37 million ($1.937546.50 per share) for each of the yearyears ended December 31, 2019.2022, 2021 and 2020. The dividend rate for the Series B Preferred Stock will be reset every five years beginning on December 15, 2024 to equal the then-current five-year U.S. Treasury rate plus a spread of 2.993%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 dis
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.
Series C Preferred Stock
In December 31, 2019 or 2018.
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
Dominion Energy maintains Dominion Energy DirectCurrently,In August 2020, Dominion Energy isbegan purchasing its common stock on the open market for these direct stock purchase plans. During 2020, Dominion Energy received cash of $159 million from the issuance of 2.1 million of such shares through Dominion Energy Direct® and employee savings plans. In January 2021, Dominion Energy began issuing new shares of common stock for these direct stock purchase plans. During 2019, Dominion Energy received cash of $309 million from the issuance of 4.0 million of such shares through Dominion Energy Direct®employee savings plans.
At-the-Market Program
In 2017, Dominion Energy issued 12.5 million shares under the related stock purchase contracts entered into as part of Dominion Energy’s 2014 Equity Units and received proceeds of $1.0 billion. See Note 18 for further information surrounding these stock purchase contracts.
In August 2020, Dominion Energy entered into sales agency agreements to which iteffect sales under a new at-the-market program. Under the sales agency agreements, Dominion Energy may, offer from time to time, upoffer and sell shares of its common stock through the sales agents or enter into one or more forward sale agreements with respect to $1.0 billion aggregate amountshares of its common stock. These agreements replaced the sales agency agreements entered intoSales by Dominion Energy in June 2017. Sales of common stock can be made by means of private negotiated transactions, as transactions
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 common stock. The underwriting agreement granted the underwriters a30-dayoption to purchase up to an additional threeissued 0.9 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) uponFILOT 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 physical settlement of 22.1 million shares.
Repurchase of Common Stock
Dominion Energy did notnot repurchase any shares in 20192022 or 2018 and does not plan to repurchase shares during 2020,2021, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which do not count against its stock repurchase authorization.
In July 2020, in contemplation of Dominion Energy entering the July 2020 agreement to sell substantially all of its gas transmission and storage operations to BHE, the Board of Directors authorized the repurchase of up to $3.0 billion of Dominion Energy’s common stock and rescinded its prior repurchase authorization approved in February 2005 and modified in June 2007. Dominion Energy completed repurchases under this authorization in December 2020. In November 2020, the Board of Directors authorized the repurchase of up to $1.0 billion of Dominion Energy’s common stock in addition to the repurchase program authorized in July 2020. This repurchase program does not include a specific timetable or price or volume targets and may be modified, suspended or terminated at any time. Shares may be purchased through open market or privately negotiated transactions or otherwise at the discretion of management subject to prevailing market conditions, applicable securities laws and other factors.
In August 2020, Dominion Energy began repurchasing shares under an open market agreement with a financial institution. During the third quarter of 2020, Dominion Energy repurchased 7.2 million shares of Dominion Energy common stock for $562 million. During the fourth quarter of 2020, Dominion Energy repurchased 3.7 million shares of Dominion Energy common stock for $295 million.
In September 2020, Dominion Energy repurchased 4.1 million shares of Dominion Energy common stock in a private transaction for $323 million.
In September 2020, Dominion Energy entered into two prepaid accelerated share repurchase agreements with separate financial institutions as counterparties. Dominion Energy made payments totaling $1.5 billion to the counterparties in exchange for an aggregate of 17.2 million shares of Dominion Energy common stock, which represented approximately 90% of $1.5 billion worth of Dominion Energy shares based on the closing price of such shares on the date the agreements were executed. In November 2020, Dominion Energy received an additional 1.4 million shares upon completion of the respective purchase periods under the terms of the agreements. The number of additional shares delivered under each agreement was based on the average of the daily volume-weighted average stock prices of Dominion Energy’s common stock during the term of the applicable purchase period, less a discount. As a result, Dominion Energy recorded a reduction to common stock of $1.5 billion.
In December 2020, Dominion Energy entered into a new prepaid accelerated share repurchase agreement with one financial institution as the counterparty. Dominion Energy paid $400 million to the counterparty in exchange for an aggregate of 5.0 million shares of Dominion Energy common stock, which represented all $400 million worth of Dominion Energy shares based on the closing price of such shares on the date the agreement was executed. In December 2020, Dominion Energy received an additional 0.3 million shares upon completion of the purchase period under the terms of the agreement. The number of additional shares was based on the average of the daily volume-weighted average stock prices of Dominion Energy’s common stock during the term of the purchase period, less a discount. As a result, Dominion Energy recorded a reduction to common stock of $400 million.
Virginia Power
In 2019, 20182022, 2021 and 2017,2020, Virginia Power did not issue any shares of its common stock to Dominion Energy.
Noncontrolling Interests
166
resulting in Dominion Energy’s remaining 50% noncontrolling interest accounted for as an equity method investment prospectively. As a result, the $1.4 billion of noncontrolling interest related to the 25% interest in Cove Point held by Brookfield was reversed. See Notes 3 and 9 for further information on the GT&S Transaction and Dominion Energy’s equity method investment in Cove Point.
Non-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.
Accumulated Other Comprehensive Income (Loss)
At December 31, | 2019 | 2018 | ||||||
(millions) | ||||||||
Dominion Energy | ||||||||
Net deferred losses on derivatives-hedging activities, net of $135 and $79 tax | $ | (407 | ) | $ | (234 | ) | ||
Net unrealized gains on nuclear decommissioning trust funds, net of $(13) and $— tax | 37 | 2 | ||||||
Net unrecognized pension and other postretirement benefit costs, net of $492 and $519 tax | (1,421 | ) | (1,465 | ) | ||||
Other comprehensive loss from equity method investees, net of $1 and $— tax | (2 | ) | (2 | ) | ||||
Total AOCI, including noncontrolling interests | $ | (1,793 | ) | $ | (1,699 | ) | ||
Less other comprehensive income attributable to noncontrolling interests | — | 1 | ||||||
Total AOCI, excluding noncontrolling interests | $ | (1,793 | ) | $ | (1,700 | ) | ||
Virginia Power | ||||||||
Net deferred losses on derivatives-hedging activities, net of $11 and $4 tax | $ | (34 | ) | $ | (13 | ) | ||
Net unrealized gains on nuclear decommissioning trust funds, net of $(1) and $— tax | 5 | 1 | ||||||
Total AOCI | $ | (29 | ) | $ | (12 | ) | ||
Dominion Energy Gas | ||||||||
Net deferred losses on derivatives-hedging activities, net of $28 and $8 tax | $ | (82 | ) | $ | (25 | ) | ||
Net unrecognized pension costs, net of $41 and $56 tax | (106 | ) | (144 | ) | ||||
Total AOCI, including noncontrolling interests | (188 | ) | (169 | ) | ||||
Less other comprehensive income (loss) attributable to noncontrolling interests | (1 | ) | — | |||||
Total AOCI, excluding noncontrolling interests | $ | (187 | ) | $ | (169 | ) | ||
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, 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 | ) | ||||||||||||
Year Ended December 31, 2018 | ||||||||||||||||||||
Beginning balance | $(302) | $747 | $(1,101) | $(3) | $(659 | ) | ||||||||||||||
Other comprehensive income before reclassifications: gains (losses) | 30 | (18 | ) | (215) | 1 | (202 | ) | |||||||||||||
Amounts reclassified from AOCI: (gains) losses (1) | 102 | 5 | 78 | — | 185 | |||||||||||||||
Net current period other comprehensive income (loss) | 132 | (13) | (137) | 1 | (17) | |||||||||||||||
Cumulative-effect of changes in accounting principle | (64) | (732) | (227) | — | (1,023 | ) | ||||||||||||||
Less other comprehensive income (loss) attributable to noncontrolling interests | 1 | — | — | — | 1 | |||||||||||||||
Ending balance | $(235) | $ 2 | $(1,465) | $(2) | $ (1,700 | ) | ||||||||||||||
reclassified from AOCI | Consolidated Statements of Income | |||||
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 | ) |
Net of $445 million, $396 million and $478 million tax at December 31, 2022 and 2021 and 2020, respectively. | ||||||||
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, 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) | |||||||
Year Ended December 31, 2018 | ||||||||||||
Beginning balance | $(12 | ) | $ | 74 | $ | 62 | ||||||
Other comprehensive income before reclassifications: gains (losses) | 1 | — | 1 | |||||||||
Amounts reclassified from AOCI: gains (losses) (1) | 1 | — | 1 | |||||||||
Net current period other comprehensive income (loss) | 2 | — | 2 | |||||||||
Cumulative-effect of changes in accounting principle | (3 | ) | (73 | ) | (76) | |||||||
Ending balance | $(13 | ) | $ | 1 | $ | (12) | ||||||
|
| 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 | ) |
reclassified from AOCI | Consolidated Statements of Income | |||||
Deferred gains and losses on derivatives- hedging activities | Unrecognized pension and other postretirement benefit costs | Total | ||||||||||
(millions) | ||||||||||||
Year Ended December 31, 2019 | ||||||||||||
Beginning balance | $(25 | ) | $(144 | ) | $ | (169) | ||||||
Other comprehensive income before reclassifications: gains (losses) | (61 | ) | 33 | (28 | ) | |||||||
Amounts reclassified from AOCI: (gains) losses (1) | 5 | 5 | 10 | |||||||||
Net current period other comprehensive income (loss) | (56 | ) | 38 | (18 | ) | |||||||
Dominion Energy Gas Restructuring | (1 | ) | — | (1 | ) | |||||||
Less other comprehensive income attributable to noncontrolling interests | (1 | ) | — | (1 | ) | |||||||
Ending balance | $(81 | ) | $(106 | ) | $ | (187 | ) | |||||
Year Ended December 31, 2018 | ||||||||||||
Beginning balance | $(23 | ) | $(75 | ) | $ | (98 | ) | |||||
Other comprehensive income before reclassifications: gains (losses) | (16 | ) | (52 | ) | (68 | ) | ||||||
Amounts reclassified from AOCI: gains (losses) (1) | 19 | 4 | 23 | |||||||||
Net current period other comprehensive income (loss) | 3 | (48 | ) | (45 | ) | |||||||
Cumulative-effect of changes in accounting principle | (5 | ) | (21 | ) | (26 | ) | ||||||
Ending balance | $(25 | ) | $(144 | ) | $(169 | ) | ||||||
reclassified from AOCI | Consolidated Statements of Income | |||||
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. Theyears.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, 2019,2022, approximately 2118 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, 2019,2022 and December 31, 2021, unrecognized compensation cost related to nonvested goal-based stock awards was immaterial.
Dominion Energy measures and recognizes compensation expense relating to share-based payment transactions over the vesting period based on the fair value of the equity or liability instruments issued. Dominion Energy’s results for the years ended December 31, 2019, 20182022, 2021 and 20172020 include $46$36 million, $48$42 million and $45$64 million,$11$7 million, $12$9 million and $16$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 keythreethree-year-year service period. The following table provides a summary of restricted stock activity for the years ended December 31, 2019, 20182022, 2021 and 2017:2020:
|
| 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, 2016 | 886 | $71.40 | ||||||
Granted | 454 | 74.24 | ||||||
Vested | (287 | ) | 68.90 | |||||
Cancelled and forfeited | (10 | ) | 72.37 | |||||
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 | ||||||
As of December 31, 2019,2022, unrecognized compensation cost related to nonvested restricted stock awards totaled $59$58 million and is expected to be recognized over a weighted-average period of 2.12.0 years. The fair value of restricted stock awards that vested was $23$31 million, $23$37 million and $21$35 million in 2019, 20182022, 2021 and 2017,2020, 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 zero and 200%200% of the targeted amount based on the level of performance metrics achieved.
In February 2019, a cash-based performance grant was made to officers. Payout of the performance grant is expected to occur by March 15,occurred in January 2022 based on the achievement of two performance metrics during 2019, 2020 and 2021: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group and ROIC with an additional payout based on Dominion Energy’s price-earnings ratio relative to that of the members of Dominion Energy’s peer compensation group. The total payout under the grant was $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 $4 million, all of which was accrued on December 31, 2022.
In February 2021, a cash-based performance grant was made to officers. Payout of the performance grant is expected to occur by March 15, 2024 based on the achievement of two performance metrics during 2021, 2022 and 2023: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group and ROIC. There 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, 2019,2022, the targeted amount of the three-year grant was $16$11 million and a liability of $5$4 million had been accrued for this award.
In February 2022, a cash-based performance grant was made to officers. Payout of the performance grant is expected to occur by March 15, 2025 based on the achievement of three performance metrics during 2022, 2023 and 2024: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group, Cumulative Operating EPS, and Non-Carbon Emitting Generation Capacity Performance. At December 31, 2022, the targeted amount of the three-year grant was $17 million and a liability of $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, 2019,2022, 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 atthe day prior to closing of the SCANA Combination plus (ii) any future earnings recorded by Virginia Power and PSNC after such date. 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 Commissionand Utah Commissions may prohibit any public service company, including East Ohio and Questar Gas, from declaring or paying a dividend to
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. There is no specific restriction
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 by DESC.
At December 31, 2019,2022, DESC’s retained earnings are belowexceed the balance established by the Federal Power Act as a reserve on earnings attributable to hydroelectric generation plants. As a result, DESC is prohibited from the payment of dividends without regulatory approval until the balance of its retained earnings increases.
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 contract adjustmentinterest payments on the 2019 Equity Unitsenhanced junior subordinated notes or a failure to pay dividends on the Series AB Preferred Stock or Series BC Preferred Stock.
NOTE 22. Employee Benefit Plans
Dominion Energy and Dominion Energy Gas—Energy—Defined Benefit Plans
Dominion Energy provides certain retirement benefits to eligible active employees, retirees and qualifying dependents. Dominion Energy Gas participates in a number of the Dominion Energy-sponsored retirement plans. 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
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, including those in which Dominion Energy Gas participates.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, including those in which Dominion Energy Gas participates.plans. The market-related value recognizes changes in fair value on a straight-line basis over a four-year period, which reduces
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 $2.1$(3.0) billion and $(605) million$1.5 billion in 20192022 and 2018,2021, respectively, versus expected returns of $848 million$1.1 billion and $806 million, respectively. Dominion Energy Gas’ pension and other postretirement plan
In March 2019, the Companies announced a voluntary retirement program to employees that meet certain age and service requirements. The voluntary retirement program will not compromise safety or the Companies’ ability to comply with applicable laws and regulations. In 2019, upon the determinations made concerning the number of employees that elected to participate in the program,2021, Dominion Energy recordedrecognized the effects of a chargecurtailment for certain pension plans resulting from an option that provided certain active employees a one-time choice to transition to an enhanced defined contribution plan in lieu of $427 million ($319 millionafter-tax)included within other operations and maintenance expense ($291 million), other taxes ($24 million) and other income ($112 million), Virginia Power recorded a charge of $198 million ($146 millionafter-tax)included within other operations and maintenance expense ($190 million) and other taxes ($8 million) and Dominion Energy Gas recorded a charge of $74 million ($58 millionafter-tax)included within other operations and maintenance expense ($39 million), other taxes ($2 million), other income ($1 million) and discontinued operations ($32 million) in the respective Consolidated Statements of Income.
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Funded Status
The following table summarizes the changes in pension plan and other postretirement benefit plan obligations and plan assets and includes a statement of the plans’ funded status for Dominion EnergyEnergy:
|
| 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, | 2019 | 2018 | 2019 | 2018 | ||||||||||||
(millions, except percentages) | ||||||||||||||||
Dominion Energy | ||||||||||||||||
Changes in benefit obligation: | ||||||||||||||||
Benefit obligation at beginning of year | $ | 8,500 | $ | 9,052 | $ | 1,363 | $ | 1,529 | ||||||||
Dominion Energy SCANA Combination (See Note 3) | 854 | — | 253 | — | ||||||||||||
Service cost | 162 | 157 | 26 | 27 | ||||||||||||
Interest cost | 394 | 337 | 68 | 56 | ||||||||||||
Benefits paid | (470 | ) | (358 | ) | (96 | ) | (87 | ) | ||||||||
Actuarial (gains) losses during the year | 1,054 | (688 | ) | 111 | (158 | ) | ||||||||||
Plan amendments | — | — | — | (4 | ) | |||||||||||
Settlements and curtailments (1) | (48 | ) | — | 44 | — | |||||||||||
Benefit obligation at end of year | $ | 10,446 | $ | 8,500 | $ | 1,769 | $ | 1,363 | ||||||||
Changes in fair value of plan assets: | ||||||||||||||||
Fair value of plan assets at beginning of year | $ | 7,197 | $ | 8,062 | $ | 1,581 | $ | 1,729 | ||||||||
Dominion Energy SCANA Combination (See Note 3) | 727 | — | — | — | ||||||||||||
Actual return (loss) on plan assets | 1,747 | (513 | ) | 349 | (92 | ) | ||||||||||
Employer contributions | 557 | 6 | 12 | 12 | ||||||||||||
Benefits paid | (470 | ) | (358 | ) | (62 | ) | (68 | ) | ||||||||
Settlements (2) | (127 | ) | — | — | — | |||||||||||
Fair value of plan assets at end of year | $ | 9,631 | $ | 7,197 | $ | 1,880 | $ | 1,581 | ||||||||
Funded status at end of year | $ | (815 | ) | $ | (1,303 | ) | $ | 111 | $ | 218 | ||||||
Amounts recognized in the Consolidated Balance Sheets at December 31: | ||||||||||||||||
Noncurrent pension and other postretirement benefit assets | $ | 1,266 | $ | 1,003 | $ | 442 | $ | 276 | ||||||||
Other current liabilities | (29 | ) | (34 | ) | (17 | ) | (2 | ) | ||||||||
Noncurrent pension and other postretirement benefit liabilities | (2,052 | ) | (2,272 | ) | (314 | ) | (56 | ) | ||||||||
Net amount recognized | $ | (815 | ) | $ | (1,303 | ) | $ | 111 | $ | 218 | ||||||
Significant assumptions used to determine benefit obligations as of December 31: | ||||||||||||||||
Discount rate | 3.47%–3.63% | 4.42%–4.43% | 3.44%–3.52% | 4.37%–4.38% | ||||||||||||
Weighted average rate of increase for compensation | 4.23% | 4.32% | n/a | n/a | ||||||||||||
Dominion Energy Gas | ||||||||||||||||
Changes in benefit obligation: | ||||||||||||||||
Benefit obligation at beginning of year | $ | 730 | $ | 773 | $ | 256 | $ | 290 | ||||||||
Dominion Energy Gas Restructuring (See Note 3) | (468 | ) | — | (135 | ) | — | ||||||||||
Service cost | 6 | 18 | 1 | 4 | ||||||||||||
Interest cost | 11 | 29 | 5 | 11 | ||||||||||||
Benefits paid | (15 | ) | (34 | ) | (8 | ) | (18 | ) | ||||||||
Actuarial (gains) losses during the year | 30 | (56 | ) | 1 | (27 | ) | ||||||||||
Plan amendments | — | — | — | (4 | ) | |||||||||||
Settlements and curtailments (1) | 1 | — | 1 | — | ||||||||||||
Benefit obligation at end of year | $ | 295 | $ | 730 | $ | 121 | $ | 256 | ||||||||
Changes in fair value of plan assets: | ||||||||||||||||
Fair value of plan assets at beginning of year | $ | 1,656 | $ | 1,803 | $ | 311 | $ | 333 | ||||||||
Dominion Energy Gas Restructuring(See Note 3) | (1,084 | ) | — | $ | (126 | ) | — | |||||||||
Actual return (loss) on plan assets | 129 | (113 | ) | 38 | (16 | ) | ||||||||||
Employer contributions | — | — | 12 | 12 | ||||||||||||
Benefits paid | (15 | ) | (34 | ) | (8 | ) | (18 | ) | ||||||||
Fair value of plan assets at end of year | $ | 686 | $ | 1,656 | $ | 227 | $ | 311 | ||||||||
Funded status at end of year | $ | 391 | $ | 926 | $ | 106 | $ | 55 | ||||||||
Amounts recognized in the Consolidated Balance Sheets at December 31: | ||||||||||||||||
Noncurrent pension and other postretirement benefit assets | $ | 391 | $ | 310 | $ | 106 | $ | 63 | ||||||||
Noncurrent assets of discontinued operations | — | 616 | — | — | ||||||||||||
Noncurrent liabilities of discontinued operations | — | — | — | (8 | ) | |||||||||||
Net amount recognized | $ | 391 | $ | 926 | $ | 106 | $ | 55 | ||||||||
Significant assumptions used to determine benefit obligations as of December 31: | ||||||||||||||||
Discount rate | 3.63 | % | 4.42 | % | 3.44 | % | 4.37 | % | ||||||||
Weighted average rate of increase for compensation | 4.64 | % | 4.55 | % | n/a | n/a | ||||||||||
Actuarial gains recognized during 2022 in Dominion Energy’s pension benefit obligations were $2.7 billion primarily 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 an increase in discount rate. Actuarial gains recognized during 2022 in Dominion Energy’s other postretirement benefit obligations were $360 million primarily driven by an increase in the discount rate. Actuarial gains recognized during 2021 in Dominion Energy’s other postretirement benefit obligations were $161 million resulting from an increase in discount rates, better than expected per capita claims experience and changes in demographic and economic assumptions based on an experience study completed in 2021.
The ABO for all of Dominion Energy’s defined benefit pension plans was $9.7$7.7 billion and $7.8$10.2 billion at December 31, 20192022 and 2018,2021, respectively. The ABO for the defined benefit pension plans covering Dominion Energy Gas employees represented by collective bargaining units was $279 million and $689 million at December 31, 2019 and 2018, 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. During 2019,In December 2021, Dominion Energy made $520 millionissued 250,000 shares of contributionsits Series C Preferred Stock to its
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Certain regulatory authorities have held that amounts recovered in utility customers’ rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, certain of Dominion Energy’s subsidiaries including Dominion Energy Gas, 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’sEnergy did not make any contributions to VEBAs all of which pertained toassociated with its other postretirement plans in 2022 and 2021. Dominion Energy Gas employees, totaled $12 million for 2019 and 2018, andis not required to make any contributions to its VEBAs associated with its other postretirement plans in 2023. Dominion Energy expectsconsiders voluntary contributions from time to contribute approximately $12 million totime, either in the Dominion Energy VEBAs in 2020, allform of which pertains to Dominion Energy Gas employees.
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 and Dominion Energy Gas (for employees represented by collective bargaining units):
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
As of December 31, | 2019 | 2018 | 2019 | 2018 | ||||||||||||
(millions) | ||||||||||||||||
Dominion Energy | ||||||||||||||||
Benefit obligation | $ | 9,552 | $ | 7,705 | $ | 341 | $ | 164 | ||||||||
Fair value of plan assets | 7,471 | 5,398 | 10 | 136 | ||||||||||||
Dominion Energy Gas | ||||||||||||||||
Benefit obligation | $ | — | $ | — | $ | — | $ | 134 | ||||||||
Fair value of plan assets | — | — | — | 126 | ||||||||||||
|
| 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 |
|
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, | 2019 | 2018 | ||||||
(millions) | ||||||||
Accumulated benefit obligation | $ | 8,852 | $ | 7,056 | ||||
Fair value of plan assets | 7,471 | 5,398 | ||||||
As of December 31, |
| 2022 |
|
| 2021 |
| ||
(millions) |
|
|
|
|
|
| ||
Accumulated benefit obligation |
| $ | 776 |
|
| $ | 127 |
|
Fair value of plan assets |
|
| 623 |
|
|
| 53 |
|
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units)Energy’s plans:
|
| Estimated Future Benefit Payments |
| |||||
|
| Pension Benefits |
|
| Other Postretirement |
| ||
(millions) |
|
|
|
|
|
| ||
2023 |
| $ | 518 |
|
| $ | 99 |
|
2024 |
|
| 527 |
|
|
| 97 |
|
2025 |
|
| 542 |
|
|
| 96 |
|
2026 |
|
| 551 |
|
|
| 94 |
|
2027 |
|
| 560 |
|
|
| 93 |
|
2028-2032 |
|
| 2,925 |
|
|
| 433 |
|
Estimated Future Benefit Payments | ||||||||
Pension Benefits | Other Postretirement Benefits | |||||||
(millions) | ||||||||
Dominion Energy | ||||||||
2020 | $ | 535 | $ | 120 | ||||
2021 | 472 | 117 | ||||||
2022 | 511 | 116 | ||||||
2023 | 519 | 114 | ||||||
2024 | 536 | 113 | ||||||
2025-2029 | 2,792 | 528 | ||||||
Dominion Energy Gas | ||||||||
2020 | $ | 15 | $ | 8 | ||||
2021 | 15 | 8 | ||||||
2022 | 15 | 8 | ||||||
2023 | 15 | 8 | ||||||
2024 | 15 | 8 | ||||||
2025-2029 | 79 | 36 | ||||||
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. As a participating employer in various pension plans sponsored by Dominion Energy, Dominion Energy Gas is subject to Dominion Energy’s investment policies for such plans. 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%35%32% fixed income, 3%3% real estateassets and 16%20% other alternative investments. U.S. equity includes investments inestate 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
For fair value measurement policies and procedures related to pension and other postretirement benefit plan assets, see Note 6.
The fair values of Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units)Energy’s pension plan assets by asset category are as follows:
At December 31, | 2019 | 2018 | ||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||
Dominion Energy | ||||||||||||||||||||||||||||||||
Cash and cash equivalents | $ | 22 | $ | 1 | $ — | $ | 23 | $ | 17 | $ | 1 | $— | $ | 18 | ||||||||||||||||||
Common and preferred stocks: | ||||||||||||||||||||||||||||||||
U.S. (1) | 2,284 | — | — | 2,284 | 1,645 | — | — | 1,645 | ||||||||||||||||||||||||
International | 1,634 | — | — | 1,634 | 1,061 | — | — | 1,061 | ||||||||||||||||||||||||
Insurance contracts | — | 360 | — | 360 | — | 318 | — | 318 | ||||||||||||||||||||||||
Corporate debt instruments | 273 | 859 | — | 1,132 | 23 | 729 | — | 752 | ||||||||||||||||||||||||
Government securities | 58 | 757 | — | 815 | 25 | 605 | — | 630 | ||||||||||||||||||||||||
Total recorded at fair value | $ | 4,271 | $ | 1,977 | $— | $ | 6,248 | $ | 2,771 | $ | 1,653 | $— | $ | 4,424 | ||||||||||||||||||
Assets recorded at NAV (2) : | ||||||||||||||||||||||||||||||||
Common/collective trust funds | 2,355 | 1,849 | ||||||||||||||||||||||||||||||
Alternative investments: | ||||||||||||||||||||||||||||||||
Real estate funds | 91 | 108 | ||||||||||||||||||||||||||||||
Private equity funds | 787 | 633 | ||||||||||||||||||||||||||||||
Debt funds | 159 | 155 | ||||||||||||||||||||||||||||||
Hedge funds | 14 | 17 | ||||||||||||||||||||||||||||||
Total recorded at NAV | $ | 3,406 | $ | 2,762 | ||||||||||||||||||||||||||||
Total investments (3) | $ | 9,654 | $ | 7,186 | ||||||||||||||||||||||||||||
Dominion Energy Gas | ||||||||||||||||||||||||||||||||
Cash and cash equivalents | $ | 1 | $ | — | $ — | $ | 1 | $ | 4 | $ | — | $— | $ | 4 | ||||||||||||||||||
Common and preferred stocks: | ||||||||||||||||||||||||||||||||
U.S. | 177 | — | — | 177 | 378 | — | — | 378 | ||||||||||||||||||||||||
International | 114 | — | — | 114 | 244 | — | — | 244 | ||||||||||||||||||||||||
Insurance contracts | — | 28 | — | 28 | — | 73 | — | 73 | ||||||||||||||||||||||||
Corporate debt instruments | 3 | 66 | — | 69 | 5 | 168 | — | 173 | ||||||||||||||||||||||||
Government securities | 2 | 59 | — | 61 | 6 | 139 | — | 145 | ||||||||||||||||||||||||
Total recorded at fair value | $ | 297 | $ | 153 | $— | $ | 450 | $ | 637 | $ | 380 | $— | $ | 1,017 | ||||||||||||||||||
Assets recorded at NAV (2) : | ||||||||||||||||||||||||||||||||
Common/collective trust funds | 157 | 425 | ||||||||||||||||||||||||||||||
Alternative investments: | ||||||||||||||||||||||||||||||||
Real estate funds | 7 | 25 | ||||||||||||||||||||||||||||||
Private equity funds | 61 | 146 | ||||||||||||||||||||||||||||||
Debt funds | 12 | 36 | ||||||||||||||||||||||||||||||
Hedge funds | 1 | 4 | ||||||||||||||||||||||||||||||
Total recorded at NAV | $ | 238 | $ | 636 | ||||||||||||||||||||||||||||
Total investments (4) | $ | 688 | $ | 1,653 | ||||||||||||||||||||||||||||
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 |
| ||||||
(1)
175
The fair values of Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units)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, | 2019 | 2018 | ||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||
Dominion Energy | ||||||||||||||||||||||||||||||||
Cash and cash equivalents | $ | 2 | $ | — | $— | $ | 2 | $ | 1 | $ | 1 | $— | $ | 2 | ||||||||||||||||||
Common and preferred stocks: | ||||||||||||||||||||||||||||||||
U.S. | 719 | — | — | 719 | 554 | — | — | 554 | ||||||||||||||||||||||||
International | 206 | — | — | 206 | 170 | — | — | 170 | ||||||||||||||||||||||||
Insurance contracts | — | 21 | — | 21 | — | 19 | — | 19 | ||||||||||||||||||||||||
Corporate debt instruments | 1 | 50 | — | 51 | 1 | 44 | — | 45 | ||||||||||||||||||||||||
Government securities | 2 | 44 | — | 46 | 2 | 37 | — | 39 | ||||||||||||||||||||||||
Total recorded at fair value | $ | 930 | $ | 115 | $— | $ | 1,045 | $ | 728 | $ | 101 | $— | $ | 829 | ||||||||||||||||||
Assets recorded at NAV (1) : | ||||||||||||||||||||||||||||||||
Common/collective trust funds | 717 | 650 | ||||||||||||||||||||||||||||||
Alternative investments: | ||||||||||||||||||||||||||||||||
Real estate funds | 8 | 10 | ||||||||||||||||||||||||||||||
Private equity funds | 100 | 80 | ||||||||||||||||||||||||||||||
Debt funds | 10 | 10 | ||||||||||||||||||||||||||||||
Hedge funds | 1 | 1 | ||||||||||||||||||||||||||||||
Total recorded at NAV | $ | 836 | $ | 751 | ||||||||||||||||||||||||||||
Total investments (2) | $ | 1,881 | $ | 1,580 | ||||||||||||||||||||||||||||
Dominion Energy Gas | ||||||||||||||||||||||||||||||||
Common and preferred stocks: | ||||||||||||||||||||||||||||||||
U.S. | $ | 86 | $ | — | $— | $ | 86 | $ | 113 | $ | — | $— | $ | 113 | ||||||||||||||||||
International | 21 | — | — | 21 | 30 | — | — | 30 | ||||||||||||||||||||||||
Total recorded at fair value | $ | 107 | $ | — | $— | $ | 107 | $ | 143 | $ | — | $— | $ | 143 | ||||||||||||||||||
Assets recorded at NAV (1) : | ||||||||||||||||||||||||||||||||
Common/collective trust funds | 105 | 148 | ||||||||||||||||||||||||||||||
Alternative investments: | ||||||||||||||||||||||||||||||||
Real estate funds | 1 | 2 | ||||||||||||||||||||||||||||||
Private equity funds | 14 | 18 | ||||||||||||||||||||||||||||||
Debt funds | — | — | ||||||||||||||||||||||||||||||
Total recorded at NAV | $ | 120 | $ | 168 | ||||||||||||||||||||||||||||
Total investments | $ | 227 | $ | 311 | ||||||||||||||||||||||||||||
The Plan’splan assets investments are determined based on the fair values of the investments and the underlying investments, which have been determined as follows:
176
Net Periodic Benefit (Credit) Cost
The service cost component of net periodic benefit (credit) cost is reflected in other operations andoperations and maintenance expense and other income respectively, in theDominion 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 and Dominion Energy Gas’ (for employees represented by collective bargaining units) 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 |
| ||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||
Year Ended December 31, | 2019 | 2018 | 2017 | 2019 | 2018 | 2017 | ||||||||||||||||||
(millions, except percentages) | ||||||||||||||||||||||||
Dominion Energy | ||||||||||||||||||||||||
Service cost | $ | 162 | $ | 157 | $ | 138 | $ | 26 | $ | 27 | $ | 26 | ||||||||||||
Interest cost | 394 | 337 | 345 | 68 | 56 | 60 | ||||||||||||||||||
Expected return on plan assets | (708 | ) | (663 | ) | (639 | ) | (140 | ) | (143 | ) | (128 | ) | ||||||||||||
Amortization of prior service (credit) cost | 1 | 1 | 1 | (52 | ) | (52 | ) | (51 | ) | |||||||||||||||
Amortization of net actuarial loss | 172 | 193 | 162 | 10 | 11 | 13 | ||||||||||||||||||
Settlements and curtailments | 72 | — | — | 42 | — | — | ||||||||||||||||||
Net periodic benefit (credit) cost | $ | 93 | $ | 25 | $ | 7 | $ | (46 | ) | $ | (101 | ) | $ | (80 | ) | |||||||||
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities: | ||||||||||||||||||||||||
Current year net actuarial (gain) loss | $ | 16 | $ | 490 | $ | 142 | $ | (98 | ) | $ | 78 | $ | 12 | |||||||||||
Prior service (credit) cost | — | — | 5 | 2 | (4 | ) | (73 | ) | ||||||||||||||||
Settlements and curtailments | 6 | — | 1 | — | — | 2 | ||||||||||||||||||
Less amounts included in net periodic benefit cost: | ||||||||||||||||||||||||
Amortization of net actuarial loss | (172 | ) | (193 | ) | (162 | ) | (10 | ) | (11 | ) | (13 | ) | ||||||||||||
Amortization of prior service credit (cost) | (1 | ) | (1 | ) | (1 | ) | 52 | 52 | 51 | |||||||||||||||
Total recognized in other comprehensive income and regulatory assets and liabilities | $ | (151 | ) | $ | 296 | $ | (15 | ) | $ | (54 | ) | $ | 115 | $ | (21 | ) | ||||||||
Significant assumptions used to determine periodic cost: | ||||||||||||||||||||||||
Discount rate | 3.57%- 4.43 | % | 3.80%-3.81 | % | 3.31%-4.50 | % | 4.05% - 4.41 | % | 3.76 | % | 3.92%-4.47 | % | ||||||||||||
Expected long-term rate of return on plan assets | 7.00%- 8.65 | % | 8.75 | % | 8.75 | % | 8.50 | % | 8.50 | % | 8.50 | % | ||||||||||||
Weighted average rate of increase for compensation | 4.20 | % | 4.09 | % | 4.09 | % | n/a | n/a | n/a | |||||||||||||||
Healthcare cost trend rate (1) | 6.50% - 6.60 | % | 7.00 | % | 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) | 2023-2025 | 2022 | 2021 | |||||||||||||||||||||
Dominion Energy Gas (2) | ||||||||||||||||||||||||
Service cost | $ | 6 | $ | 18 | $ | 15 | $ | 1 | $ | 4 | $ | 4 | ||||||||||||
Interest cost | 11 | 29 | 30 | 5 | 11 | 12 | ||||||||||||||||||
Expected return on plan assets | (54 | ) | (150 | ) | (141 | ) | (16 | ) | (28 | ) | (24 | ) | ||||||||||||
Amortization of prior service (credit) cost | — | — | — | (5 | ) | (4 | ) | (3 | ) | |||||||||||||||
Amortization of net actuarial loss | 7 | 19 | 16 | 3 | 3 | 2 | ||||||||||||||||||
Settlements and curtailments | 1 | — | — | 1 | — | — | ||||||||||||||||||
Net periodic benefit (credit) cost | $ | (29 | ) | $ | (84 | ) | $ | (80 | ) | $ | (11 | ) | $ | (14 | ) | $ | (9 | ) | ||||||
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities: | ||||||||||||||||||||||||
Current year net actuarial (gain) loss | $ | (46 | ) | $ | 207 | $ | (75 | ) | $ | (21 | ) | $ | 16 | $ | 18 | |||||||||
Prior service cost | — | — | — | — | (4 | ) | (61 | ) | ||||||||||||||||
Less amounts included in net periodic benefit cost: | ||||||||||||||||||||||||
Amortization of net actuarial loss | (7 | ) | (19 | ) | (16 | ) | (3 | ) | (3 | ) | (2 | ) | ||||||||||||
Amortization of prior service credit (cost) | — | — | — | 5 | 4 | 3 | ||||||||||||||||||
Total recognized in other comprehensive income and regulatory assets and liabilities | $ | (53 | ) | $ | 188 | $ | (91 | ) | $ | (19 | ) | $ | 13 | $ | (42 | ) | ||||||||
Significant assumptions used to determine periodic cost: | ||||||||||||||||||||||||
Discount rate | 4.10%-4.42 | % | 3.81 | % | 4.50 | % | 4.05%-4.37 | % | 3.81 | % | 4.47 | % | ||||||||||||
Expected long-term rate of return on plan assets | 8.65 | % | 8.75 | % | 8.75 | % | 8.50 | % | 8.50 | % | 8.50 | % | ||||||||||||
Weighted average rate of increase for compensation | 4.55 | % | 4.11 | % | 4.11 | % | n/a | n/a | n/a | |||||||||||||||
Healthcare cost trend rate (1) | 6.50 | % | 7.00 | % | 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 | 2022 | 2021 | |||||||||||||||||||||
| Assumptions used to determine net periodic cost for the following year. |
177
The components of AOCI and regulatory assets and liabilities for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units)Energy’s plans that have not been recognized as components of net periodic benefit (credit) cost are as follows:
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
At December 31, | 2019 | 2018 | 2019 | 2018 | ||||||||||||
(millions) | ||||||||||||||||
Dominion Energy | ||||||||||||||||
Net actuarial loss | $ | 3,327 | $ | 3,477 | $ | 241 | $ | 350 | ||||||||
Prior service (credit) cost | 5 | 7 | (339 | ) | (393 | ) | ||||||||||
Total (1) | $ | 3,332 | $ | 3,484 | $ | (98 | ) | $ | (43 | ) | ||||||
Dominion Energy Gas | ||||||||||||||||
Net actuarial loss | $ | 150 | $ | 555 | $ | 44 | $ | 89 | ||||||||
Prior service (credit) cost | — | — | (49 | ) | (52 | ) | ||||||||||
Total (2) | $ | 150 | $ | 555 | $ | (5 | ) | $ | 37 | |||||||
|
| 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 | |||||||
(millions) | ||||||||
Dominion Energy | ||||||||
Net actuarial loss | $194 | $5 | ||||||
Prior service (credit) cost | 1 | (50 | ) | |||||
Dominion Energy Gas | ||||||||
Net actuarial loss | $7 | $2 | ||||||
Prior service (credit) cost | — | (5 | ) | |||||
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 developsthose in which Dominion Energy Gas participates, 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 including those in which Dominion Energy Gas participates, by using a combination of:
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, including those in which Dominion Energy Gas participates.
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, including those in whichplans. Dominion Energy Gas participates. A one percentage point change in assumedestablishes the healthcare cost trend rates would have hadrate assumption based on analyses of various factors including the following effects for Dominion Energyspecific provisions of its medical plans, actual cost trends experienced and Dominion Energy Gas’ (for employees represented by collective bargaining units) other postretirement benefit plans:
Other Postretirement Benefits | ||||||||
One percentage point increase | One percentage point decrease | |||||||
(millions) | ||||||||
Dominion Energy | ||||||||
Effect on net periodic cost for 2020 | $20 | $(11) | ||||||
Effect on other postretirement benefit obligation at December 31, 2019 | 153 | (128) | ||||||
Dominion Energy Gas | ||||||||
Effect on net periodic cost for 2020 | $2 | $(2) | ||||||
Effect on other postretirement benefit obligation at December 31, 2019 | 14 | (12) | ||||||
Virginia Power—Participation in Defined Benefit Plans
Virginia Power employees and Dominion Energy Gas employees not represented by collective bargaining units are covered by the Dominion Energy Pension Plan described above. As a participating employers,employer, Virginia Power and Dominion Energy Gas areis subject to Dominion Energy’s funding policy, which is to contribute annually an amount that is in accordance with ERISA. During 2019,2022, 2021 and 2020, Virginia Power andmade payments to Dominion Energy Gas made no contributionsof $172 million, $151 million and $313 million, respectively, related to its participation in the Dominion Energy Pension Plan, and no contributions to this plan are currently expected in 2020.Plan. Virginia Power’s net periodic pension cost related to this plan was $152$72 million, $126$86 million and $110$118 million in 2019, 20182022, 2021 and 2017, respectively. Dominion Energy Gas’ net periodic pension
Retiree healthcare and life insurance benefits, for Virginia Power employees and for Dominion Energy Gas employees not represented by collective bargaining units, 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 $(27)$(81) million, $(51)$(72) million and $(42)$(58) million in 2019, 20182022, 2021 and 2017, respectively. Dominion Energy Gas’ net periodic benefit (credit) cost related to this plan was $(4) million, $(8) million and $(6) million for 2019, 2018 and 2017,2020, respectively. Net periodic benefit (credit) cost is reflected in other operations and
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maintenance expensesexpense in their respectiveVirginia Power’s Consolidated Statements of Income, except for
Dominion Energy holds investments in trusts to fund employee benefit payments for the pension and other postretirement benefit plans in which Virginia Power and Dominion Energy Gas’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 and Dominion Energy Gas will provide to Dominion Energy for their sharesits share of employee benefit plan contributions.
Virginia Power and Dominion Energy Gas fundfunds other postretirement benefit costs through VEBAs.
Defined Contribution Plans
Dominion Energy also sponsors defined contribution employee savings plans that cover substantially all employees. During 2019, 20182022, 2021 and 2017,2020, Dominion Energy recognized $73$75 million, $51$65 million and $45$67 million, respectively, as employer matching contributions to these plans. Dominion Energy Gas participates in these employee savings plans, both specific to Dominion Energy
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.
Ozone Standards
The EPA published final2018. 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
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expenditures required to implement additional controls could have a material impact on the Companies’ results of operations and cash flows.
ACE Rule
In July 2019, the EPA published the final rule informally referred to as the ACE Rule, as a replacement for the Clean Power Plan. The ACE Rule applies toregulated GHG emissions from existing coal-fired power plants. The final rule includes unit-specific performance standards based onplants pursuant to Section 111(d) of the degree of emission reduction levels achievable from unit efficiency improvements to be determined by the permitting agency. The ACE Rule requiresCAA 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 implement these performance standards. These state plans must be approvedthe EPA. This decision would take effect upon issuance of the court’s mandate. In March 2021, the court issued a partial mandate vacating and remanding all parts of the ACE Rule except for the portion of the ACE Rule that repealed the Clean Power Plan. In October 2021, the U.S. Supreme Court agreed to hear a challenge of the U.S. Court of Appeals for the D.C. Circuit’s decision on the ACE Rule. In June 2022, the U.S. Supreme Court reversed the D.C. Circuit’s decision on the ACE Rule and remanded the case back to the D.C. Circuit. Until the case is resolved by the D.C. Circuit and/or the EPA by January 2024. Whileissues new rulemaking, the impacts of
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 byto setexceed a significant emissions rate at of 75,000 tons per year of CO2CO2 equivalent emissions under which a source would not be required to apply BACT for its GHG emissions. Until the EPA ultimately takes final action on this rulemaking, the Companies cannot predict the impact to their results of operations, financial condition and/or cash flows.
In December 2018, the EPA proposed revised Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources. The proposed rule would amend the previous determination that the best system of emission reduction for newly constructed coal-fired steam generating units is no longer partial carbon capture and storage. Instead, the proposed revised best system of emission reduction for this source category is the most efficient demonstrated steam cycle (e.g., supercritical steam conditions for large units and subcritical steam conditions for small units) in combination with the best operating practices.
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.
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frameworks in South Carolina and Virginia provide rate recovery mechanisms that could substantially mitigate any such impacts for the regulated electric utilities.
Effluent Limitations Guidelines
In September 2015, the EPA released a final rule to revise the Effluent Limitations Guidelines for the Steam Electric Power Generating Category. The final rule establishesestablished updated standards for wastewater discharges that apply primarily at coal and oil steam generating stations. Affected facilities are required to convert from wet to dry or closed cycle coal ash management, improve existing wastewater treatment systems and/or install new wastewater treatment technologies in order to meet the new discharge limits. In April 2017, the EPA granted two separate petitions for reconsideration of the Effluent Limitations Guidelines final rule and stayed future compliance dates in the rule. Also in April 2017, the U.S. Court of Appeals for the Fifth Circuit granted the EPA’s request for a stay of the pending consolidated litigation challenging the rule while the EPA addresses the petitions for reconsideration. In September 2017, the EPA signed a rule to postpone the earliest compliance dates for certain waste streams regulations in the Effluent Limitations Guidelines final rule from November 2018 to November 2020; however, the latest date for compliance for these regulations remainswas December 2023. In October 2020, the EPA released the final rule that extends the latest dates for compliance. Individual facilities’ compliance dates will vary based on circumstances and the determination by state regulators and may range from 2021 to 2028. While the impacts of this rule could be material to Dominion Energy and Virginia Power’sthe Companies’ results of operations, financial condition and/or cash flows, the existing regulatory frameworks in South Carolina and Virginia provide rate recovery mechanisms that could substantially mitigate any such impacts for the regulated electric utilities.
Waste Management and Remediation
The operations of the Companies are subject to a variety of state and federal laws and regulations governing the management and
From time to time, Dominion Energy, Virginia Power or Dominion Energy Gasthe 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 1113 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 three sites, including for one site at Virginia Power and expects to conductcommence remediation activities primarily in 2020. As2023 depending on receipt of final permits and approvals. At December 31, 2019,2022 and 2021, Dominion Energy and Virginia Power have $34had $47 million and $16$45 million, respectively, of reserves recorded, including a chargerecorded. Dominion Energy’s reserves include charges of $16$14 million ($1211 million after-tax) that Virginia Power recorded in 2018,2020, in other operations and maintenance expense in the Consolidated Statements of Income. In addition, for one site associated with Dominion Energy, an updated work plan submitted to SCDHECAt both December 31, 2022 and 2021, Virginia Power had $25 million of reserves recorded. Virginia Power’s reserves include charges of $10 million ($7 million after-tax) recorded in September 2018,
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,
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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, 2022 and 2021 include reserves of $696$94 million and $274 million, respectively, included in other current liabilities, and insurance receivables of $111$68 million and $118 million, respectively, included within other receivablesreceivables. These balances at December 31, 2019.2022 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 years ended December 31, 2021 and 2020 include charges of $100 million ($75 million after-tax) and $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, 2019 includes2020 include charges of $641$25 million ($48025 millionafter-tax), included after-tax) within impairment of assets and other charges, included withinincome (reflected in the Corporate and Other segment.
SCANA Shareholder Litigation
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. TheIn January 2019, the defendants have filed a motion to dismiss the consolidated action. In February 2019, one action was voluntarily dismissed. In March 2020, the court denied the defendants’ motion to dismiss. In April 2020, the defendants filed a notice of appeal with the South Carolina Court of Appeals and a petition with the Supreme Court of South Carolina seeking appellate review of the denial of the motion to dismiss. In June 2020, the plaintiffs filed a motion to dismiss the appeal with the South Carolina Court of Appeals, which was granted in July 2020. In August 2020, the Supreme Court of South Carolina denied the defendants’ petition seeking appellate review. Also in August 2020, the defendants filed a petition for rehearing with the South Carolina Court of Appeals relating to the July 2020 ruling by the court, which was denied in October 2020. In November 2020, SCANA filed a petition of certiorari with the Supreme Court of South Carolina seeking appellate review of the denial of SCANA’s motion to dismiss. This case is pending.
In January 2018, a purported class action was filed against SCANA, Dominion Energy and certain former executive officers and directors of SCANA in the State Court of Common Pleas in Lexington County, South Carolina (the City of Warren Lawsuit). The plaintiff alleges, among other things, that defendants violated their fiduciary duties to shareholders by executing a merger agreement that would unfairly deprive plaintiffs of the true value of their SCANA stock, and that Dominion Energy aided and abetted these actions. Among other remedies, the plaintiff seeks to enjoin and/or rescind the merger. In February 2018, Dominion Energy removed the case to the U.S. District Court for the District of South Carolina, and filed a Motion to Dismiss in March 2018. In June 2018, the case was remanded back to the State Court of Common Pleas in Lexington County. Dominion Energy appealed the decision to remand to the U.S. Court of Appeals for the Fourth Circuit, where the appeal was consolidated with a similar appeal in the Metzler Lawsuit discussed below. In June 2019, the U.S. Court of Appeals for the Fourth Circuit reversed the order remanding the case to state court. The case is pending in the U.S. District Court for the District of South Carolina.
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. The case is pending in the U.S. District Court for the District of South Carolina.
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,
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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 plaintiffs allege,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
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 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’defendants' alleged failure and refusal to defend and indemnify the Fluor defendants in the aforementioned case. These casesAs 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 pending.
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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 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.
Governmental Proceedings and Investigations
In September and October 2017, SCANA was served with subpoenas issued by the U.S. Attorney’s Office for the District of South Carolina and the Staff of the SEC’s Division of Enforcement seeking documents related to the NND Project. In February 2020, the SEC filed a complaint against SCANA, two of its former executive officers and DESC in the U.S. District Court for the District of South Carolina alleging that the defendants violated federal securities laws by making false and misleading statements about the NND Project. In April 2020, SCANA and DESC reached an agreement in principle with the Staff of the SEC’s Division of Enforcement to settle, without admitting or denying the allegations in the complaint. In December 2020, the U.S. District Court for the District of South Carolina issued an order approving the settlement which required SCANA to pay a civil monetary penalty totaling $25 million, and SCANA and DESC to pay disgorgement and prejudgment interest totaling $112.5 million, which disgorgement and prejudgment interest amount were deemed satisfied by the settlements in the SCANA Securities Class Action and the DESC Ratepayer Case. SCANA paid the civil penalty in December 2020. The SEC civil action against two former executive officers of SCANA remains pending and is currently subject to a stay granted by the court in June 2020 at the request of the U.S. Attorney’s Office for the District of South Carolina.
In addition, the South Carolina Law Enforcement Division is conducting a criminal investigation into the handling of the NND Project by SCANA and DESC. These matters are pending. SCANA and DESC areDominion 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; however,requests. Dominion Energy cannot currently predict whetherhas 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 to what extent SCANAbring any civil action against Dominion Energy or DESC may incur a material liability.
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’sCooper'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
185
construction under the abandonment provisions of the Base Load
In September 2017, DESC, for itself and as agent for Santee Cooper, filed with the U.S. Bankruptcy Court for the Southern
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.
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 will not have any exposure on account of unpaid Westinghouse subcontractor claims, which DESC is presently disputing, Dominion Energy believes it is unlikely that it will be required to make payments on account of such claims.
Nuclear Operations
Nuclear Decommissioning—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.
Nuclear Insurance
The Price-Anderson Amendments Act of 1988 provides the public up to $14.1$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 2019,2022, the total liability protection per nuclear incident available to all participants in the Secondary Financial Protection Program decreasedincreased from $14.1$13.5 billion to $13.9$13.7 billion. This decreaseincrease does not impact Dominion Energy’s responsibility per active unit under the Price-Anderson Amendments Act of 1988. Dominion Energy and Virginia PowerThe 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., Dominion Energy and Virginia Powerthe 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 Dominion EnergyMillstone, Summer, Surry and Virginia Power’s nuclear unitsNorth Anna are as follows:
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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’sPower's maximum retrospective premium assessment for the current policy period is $81$65 million and $50$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. Dominion Energy and Virginia PowerThe 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.
Millstone, and 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, Dominion Energy and Virginia Powerthe 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’sPower's maximum retrospective premium assessment for the current policy period is $31$32 million and $10$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 Dominion Energy and Virginia Powerthe 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 Dominion Energy and Virginia Power’sthe Companies’ contracts with the DOE. Dominion Energy and Virginia PowerThe 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, 2019,2022. 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
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 for the period January 1, 2014 through December 31, 2017.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 2022, Virginia Power received payments of $15$17 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 20172020 through December 31, 2017 and $112020. In addition, Dominion Energy received payments of $7 million for resolution of claims incurred at Millstone for the period of July 1, 20172020 through June 30, 2018. In 2019, Dominion Energy received payment of $32021 and $1 million for resolution of its share of claims incurred at Summer for the period of January 1, 20182021 through December 31, 2018.
In 2018,2021, Virginia Power and Dominion Energy received payments of $16$25 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 20162019 through December 31, 2016, and $132019. In addition, Dominion Energy received payments of $9 million for resolution of claims incurred at Millstone for the period of July 1, 20162019 through June 30, 2017.
In 2017,2020, Virginia Power and Dominion Energy received payments of $22$24 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 20152018 through December 31, 2015, and $142018. In addition, Dominion Energy received payments of $11 million for resolution of claims incurred at Millstone for the period of July 1, 20152018 through June 30, 2016.
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The Companies continue to recognize receivables for certain spent nuclear fuel-related costs that they believe are probable of recovery from the DOE. Dominion Energy’s receivables for spent nuclear fuel-related costs totaled $52$56 million and $49$52 million at December 31, 20192022 and 2018,2021, respectively. Virginia Power’s receivables for spent nuclear fuel-related costs totaled $35$37 million and $30$39 million at December 31, 20192022 and 2018,2021, respectively.
The Companies will continue to manage their spent fuel until it is accepted by the DOE.
Long-Term Purchase Agreements
At December 31, 2019,2022, 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 |
|
2020 | 2021 | 2022 | 2023 | 2024 | Thereafter | Total | ||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||
Purchased electric capacity (1) | $45 | $44 | $44 | $44 | $44 | $494 | $715 | |||||||||||||||||||||
Guarantees, Surety Bonds and Letters of Credit
At December 31, 2022, Dominion Energy entered into a guarantee agreementhad issued four guarantees related to Cove Point, an equity method investment, in support a portion of Atlantic Coast Pipeline’s obligation under a $3.4 billion revolving credit facility with a
In addition, at December 31, 2019,2022, Dominion Energy had issued an additional $27$20 million of guarantees, primarily to support other equity method investees.third parties. No amounts related to the otherthese 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, 2019,2022, Dominion Energy had issued the following subsidiary guarantees:guarantees:
|
| Maximum |
| |
(millions) |
|
|
| |
Commodity transactions(1) |
| $ | 2,567 |
|
Nuclear obligations(2) |
|
| 243 |
|
Solar(3) |
|
| 304 |
|
Other(4) |
|
| 1,229 |
|
Total(5)(6) |
| $ | 4,343 |
|
(2) Guarantees primarily related to certain DGI subsidiaries regarding all aspects of running a nuclear facility. | ||||
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Additionally, at December 31, 2019,2022, Dominion Energy had purchased $163$249 million of surety bonds, including $77$172 million at Virginia Power, and $26 million at Dominion Energy Gas, and
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, 2019,2022, 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
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,
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 merchantnonregulated 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 unrealized2019,2022, Dominion Energy’s credit exposure totaled $233$281 million. Of this amount, investment grade counterparties, including those internally rated, represented 88%89%, and no single counterparty, whether investment grade or$61$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
Credit-Related Contingent Provisions
Certain of Dominion Energy Gas’ operating revenues for the years ended December 31, 2019 and 2018, respectively, with Dominion Energy Gas’ largest customer representing approximately 17% and 12% of such amounts.
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 25. Related-party Transactions
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 1920 for more information. As ofAt December 31, 2019,2022, Virginia Power’s derivative assets and liabilities with affiliates were $3$33 million and $53$31 million, respectively. As ofAt December 31, 2018,2021, Virginia Power’s derivative assets and liabilities with affiliates were $26$29 million and $10$6 million, respectively.
Virginia Power participates in certain Dominion Energy benefit plans as described in Note 22.At December 31, 20192022 and 2018,2021, Virginia Power’s amounts due to Dominion Energy associated with the Dominion Energy Pension Plan and
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, |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
(millions) |
|
|
|
|
|
|
|
|
| |||
Commodity purchases from affiliates |
| $ | 1,423 |
|
| $ | 742 |
|
| $ | 569 |
|
Services provided by affiliates(1) |
|
| 519 |
|
|
| 494 |
|
|
| 455 |
|
Services provided to affiliates |
|
| 18 |
|
|
| 18 |
|
|
| 18 |
|
Year Ended December 31, | 2019 | 2018 | 2017 | |||||||||
(millions) | ||||||||||||
Commodity purchases from affiliates | $ | 690 | $ | 930 | $ | 674 | ||||||
Services provided by affiliates (1) | 503 | 450 | 453 | |||||||||
Services provided to affiliates | 24 | 24 | 25 | |||||||||
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 $107 million$2.0 billion and $224$699 million in short-term demand note borrowings from Dominion Energy as of December 31, 20192022 and 2018,2021, respectively. The weighted-average interest rate of these borrowings was 3.22%4.68% and 2.94%0.26% at December 31, 20192022 and 2018,2021, respectively. Virginia Power had no outstanding borrowings, net of repayments under the Dominion Energy money pool for its nonregulated subsidiaries as of December 31, 20192022 and 2018.2021. 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, 2019, 20182021 and 2017.
There were no issuances of Virginia Power’s common stock to Dominion Energy in 2019, 20182022, 2021 or 2017.
In January 2023, Virginia Power entered into certain other contracts with affiliates, and related parties, including construction services, which are presented separately from contracts involving commodities or services. As of December 31, 2019 and 2018, Dominion Energy Gas did not
Year Ended December 31, | 2019 | 2018 | 2017 | |||||||||
(millions) | ||||||||||||
Sales of natural gas and transportation and storage services | $ | 249 | $ | 168 | $ | 173 | ||||||
Purchases of natural gas and transportation and storage services | 12 | — | 10 | |||||||||
Services provided by related parties (1) | 226 | 169 | 193 | |||||||||
Services provided to related parties (2) | 164 | 260 | 190 | |||||||||
At December 31, | 2019 | 2018 | ||||||
(millions) | ||||||||
Other receivables (1) | $ | 7 | $ | 13 | ||||
Imbalances receivable from affiliates | 8 | 16 | ||||||
Imbalances payable from affiliates (2) | 1 | 4 | ||||||
Other deferred charges and other assets | 12 | — | ||||||
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:
Segment | Energy | Power | Energy Gas | |||||
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 | X | X | ||||||
Gas Distribution | Regulated gas distribution and storage | 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 | Nonregulated electric generation fleet | X | ||||||
Noncontrolling interest in Cove Point | X |
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
191
In 2019,2022, Dominion Energy reported$2.6$2.6 billion in the Corporate and Other segment, with $2.0including $2.5 billion of theafter-tax net expenses for specific items with $2.8 billion of after tax-net expenses attributable to specific items related to its operating segments.
The net expenses for specific items attributable to Dominion Energy’s operating segments in 20192022 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 NND Project,impact of the following items:
192
In 2020, Dominion Energy reported after-tax net expenses of $3.7 billion in the Corporate and Other segment, including $3.4 billion of after-tax net expenses for specific items with $1.2 billion of after-tax net expenses attributable to its operating segments.
The net expenses for specific items attributable to Dominion Energy’s operating segments in 2020 primarily related to the impact of the following items:
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 Transmission & Storage | Gas Distribution | Dominion Energy South Carolina | Contracted Generation | Corporate and Other | Adjustments & Eliminations | Consolidated Total | ||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||
2019 | ||||||||||||||||||||||||||||||||
Total revenue from external customers | $8,170 | $3,074 | $2,367 | $2,948 | $1,135 | $(1,122 | ) | $ — | $16,572 | |||||||||||||||||||||||
Intersegment revenue | (13 | ) | 247 | 18 | 4 | 15 | 1,199 | (1,470 | ) | — | ||||||||||||||||||||||
Total operating revenue | 8,157 | 3,321 | 2,385 | 2,952 | 1,150 | 77 | (1,470 | ) | 16,572 | |||||||||||||||||||||||
Depreciation, depletion and amortization | 1,216 | 400 | 335 | 452 | 179 | 73 | — | 2,655 | ||||||||||||||||||||||||
Equity in earnings of equity method investees | — | 161 | 2 | (4 | ) | (1 | ) | 10 | — | 168 | ||||||||||||||||||||||
Interest income | 11 | 211 | 4 | 9 | 92 | 160 | (386 | ) | 101 | |||||||||||||||||||||||
Interest and related charges | 530 | 405 | 116 | 242 | 98 | 768 | (386 | ) | 1,773 | |||||||||||||||||||||||
Income tax expense (benefit) | 482 | 262 | 114 | 163 | 20 | (690 | ) | — | 351 | |||||||||||||||||||||||
Net income (loss) attributable to Dominion Energy | 1,786 | 934 | 488 | 430 | 276 | (2,556 | ) | — | 1,358 | |||||||||||||||||||||||
Investment in equity method investees | — | 1,517 | 32 | — | 74 | 23 | — | 1,646 | ||||||||||||||||||||||||
Capital expenditures | 3,002 | 431 | 848 | 562 | 367 | 111 | — | 5,321 | ||||||||||||||||||||||||
Total assets (billions) | 43.7 | 20.9 | 16.0 | 15.8 | 10.2 | 6.9 | (9.7 | ) | 103.8 | |||||||||||||||||||||||
2018 | ||||||||||||||||||||||||||||||||
Total revenue from external customers | $8,401 | $1,867 | $1,769 | $ — | $1,487 | $ (249 | ) | $ 91 | $13,366 | |||||||||||||||||||||||
Intersegment revenue | (552 | ) | 723 | 16 | — | 8 | 723 | (918 | ) | — | ||||||||||||||||||||||
Total operating revenue | 7,849 | 2,590 | 1,785 | — | 1,495 | 474 | (827 | ) | 13,366 | |||||||||||||||||||||||
Depreciation, depletion and amortization | 1,158 | 348 | 263 | — | 213 | 18 | — | 2,000 | ||||||||||||||||||||||||
Equity in earnings of equity method investees | — | 178 | — | — | 18 | 1 | — | 197 | ||||||||||||||||||||||||
Interest income | 10 | 143 | — | — | 80 | 122 | (271 | ) | 84 | |||||||||||||||||||||||
Interest and related charges | 516 | 262 | 79 | — | 124 | 784 | (272 | ) | 1,493 | |||||||||||||||||||||||
Income tax expense (benefit) | 380 | 236 | 95 | — | 75 | (206 | ) | — | 580 | |||||||||||||||||||||||
Net income (loss) attributable to Dominion Energy | 1,596 | 844 | 373 | — | 245 | (611 | ) | — | 2,447 | |||||||||||||||||||||||
Investment in equity method investees | — | 1,159 | — | — | 82 | 37 | — | 1,278 | ||||||||||||||||||||||||
Capital expenditures | 2,640 | 765 | 647 | — | 247 | 106 | — | 4,405 | ||||||||||||||||||||||||
Total assets (billions) | 39.1 | 22.6 | 11.8 | — | 9.0 | 8.3 | (12.9 | ) | 77.9 | |||||||||||||||||||||||
2017 | ||||||||||||||||||||||||||||||||
Total revenue from external customers | $8,254 | $1,054 | $1,778 | $ — | $1,345 | $ (27 | ) | $ 182 | $12,586 | |||||||||||||||||||||||
Intersegment revenue | (688 | ) | 946 | 17 | — | 9 | 724 | (1,008 | ) | — | ||||||||||||||||||||||
Total operating revenue | 7,566 | 2,000 | 1,795 | — | 1,354 | 697 | (826 | ) | 12,586 | |||||||||||||||||||||||
Depreciation, depletion and amortization | 1,141 | 260 | 258 | — | 200 | 46 | — | 1,905 | ||||||||||||||||||||||||
Equity in earnings of equity method investees | — | 158 | — | — | (171 | ) | (5 | ) | — | (18 | ) | |||||||||||||||||||||
Interest income | 19 | 114 | — | — | 77 | 94 | (222 | ) | 82 | |||||||||||||||||||||||
Interest and related charges | 497 | 100 | 72 | — | 110 | 648 | (222 | ) | 1,205 | |||||||||||||||||||||||
Income tax expense (benefit) | 865 | 291 | 195 | — | (160 | ) | (1,221 | ) | — | (30 | ) | |||||||||||||||||||||
Net income (loss) attributable to Dominion Energy | 1,466 | 552 | 351 | — | 253 | 377 | — | 2,999 | ||||||||||||||||||||||||
Capital expenditures | 2,726 | 1,489 | 452 | — | 979 | 263 | — | 5,909 | ||||||||||||||||||||||||
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.
Virginia Power
The Corporate and Other Segment of Virginia Power
In 2019,2022, Virginia Power reported$634$792 million in itsthe Corporate and Other segment, with $627including $773 million of theafter-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 20192022 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 voluntary retirement program;
197
The following table presents segment information pertaining to Virginia Power’s operations:
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 |
|
Year Ended December 31, | Dominion Energy Virginia | Corporate and Other | Consolidated Total | |||||||||
(millions) | ||||||||||||
2019 | ||||||||||||
Operating revenue | $8,137 | $ (29 | ) | $8,108 | ||||||||
Depreciation and amortization | 1,215 | 8 | 1,223 | |||||||||
Interest income | 11 | — | 11 | |||||||||
Interest expense (benefit) and related charges | 529 | (5 | ) | 524 | ||||||||
Income tax expense (benefit) | 481 | (217 | ) | 264 | ||||||||
Net income (loss) | 1,783 | (634 | ) | 1,149 | ||||||||
Capital expenditures | 2,981 | — | 2,981 | |||||||||
Total assets (billions) | 41.4 | — | 41.4 | |||||||||
2018 | ||||||||||||
Operating revenue | $7,835 | $(216 | ) | $7,619 | ||||||||
Depreciation and amortization | 1,157 | (25 | ) | 1,132 | ||||||||
Interest income (expense) | 10 | — | 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 | — | 2,542 | |||||||||
Total assets (billions) | 37.0 | (0.1 | ) | 36.9 | ||||||||
2017 | ||||||||||||
Operating revenue | $7,556 | $ — | $7,556 | |||||||||
Depreciation and amortization | 1,141 | — | 1,141 | |||||||||
Interest income (expense) | 19 | — | 19 | |||||||||
Interest expense (benefit) and related charges | 497 | (3 | ) | 494 | ||||||||
Income tax expense (benefit) | 868 | (94 | ) | 774 | ||||||||
Net income | 1,466 | 74 | 1,540 | |||||||||
Capital expenditures | 2,729 | — | 2,729 | |||||||||
198
Year Ended December 31, | Gas Transmission & Storage | Corporate and Other | Consolidated Total | |||||||||
(millions) | ||||||||||||
2019 | ||||||||||||
Operating revenue | $2,186 | $ (17 | ) | $2,169 | ||||||||
Depreciation and amortization | 367 | — | 367 | |||||||||
Equity in earnings of equity method investees | 43 | — | 43 | |||||||||
Interest income | 105 | — | 105 | |||||||||
Interest and related charges | 309 | 2 | 311 | |||||||||
Income tax expense (benefit) | 170 | (69 | ) | 101 | ||||||||
Net Income from discontinued operations | — | 141 | 141 | |||||||||
Net Income attributable to Dominion Energy Gas | 594 | 127 | 721 | |||||||||
Investment in equity method investees | 312 | — | 312 | |||||||||
Capital expenditures | 391 | 313 | 704 | |||||||||
Total assets (billions) | 18.8 | — | 18.8 | |||||||||
2018 | ||||||||||||
Operating revenue | $1,996 | $ — | $1,996 | |||||||||
Depreciation and amortization | 333 | — | 333 | |||||||||
Equity in earnings of equity method investees | 54 | — | 54 | |||||||||
Interest income | 26 | — | 26 | |||||||||
Interest and related charges | 173 | 1 | 174 | |||||||||
Income tax expense (benefit) | 226 | (102 | ) | 124 | ||||||||
Net Income from discontinued operations | — | 24 | 24 | |||||||||
Net Income (loss) attributable to Dominion Energy Gas | 571 | (90 | ) | 481 | ||||||||
Investment in equity method investees | 339 | — | 339 | |||||||||
Capital expenditures | 749 | 360 | 1,109 | |||||||||
Total assets (billions) | 19.9 | 6.9 | 26.8 | |||||||||
2017 | ||||||||||||
Operating revenue | $1,523 | $ — | $1,523 | |||||||||
Depreciation and amortization | 242 | — | 242 | |||||||||
Equity in earnings of equity method investees | 47 | — | 47 | |||||||||
Interest income | 4 | — | 4 | |||||||||
Interest and related charges | 60 | — | 60 | |||||||||
Income tax expense (benefit) | 189 | (254 | ) | (65 | ) | |||||||
Net Income from discontinued operations | — | 163 | 163 | |||||||||
Net Income attributable to Dominion Energy Gas | 314 | 389 | 703 | |||||||||
Capital expenditures | 1,459 | 356 | 1,815 | |||||||||
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||||||
(millions) | ||||||||||||||||
2019 | ||||||||||||||||
Operating revenue | $ | 3,858 | $ | 3,970 | $ | 4,269 | $ | 4,475 | ||||||||
Income (loss) from operations | (482 | ) | 461 | 1,314 | 1,221 | |||||||||||
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) attributable to Dominion Energy | (0.86 | ) | 0.07 | 1.19 | 1.22 | |||||||||||
Diluted EPS: | ||||||||||||||||
Net income (loss) attributable to Dominion Energy | (0.86 | ) | 0.05 | 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 | ||||||||||||
2018 | ||||||||||||||||
Operating revenue | $ | 3,466 | $ | 3,088 | $ | 3,451 | $ | 3,361 | ||||||||
Income from operations | 875 | 742 | 1,150 | 834 | ||||||||||||
Net income including noncontrolling interests | 526 | 478 | 883 | 662 | ||||||||||||
Net income attributable to Dominion Energy | 503 | 449 | 854 | 641 | ||||||||||||
Basic EPS: | ||||||||||||||||
Net income attributable to Dominion Energy | 0.77 | 0.69 | 1.31 | 0.97 | ||||||||||||
Diluted EPS: | ||||||||||||||||
Net income attributable to Dominion Energy | 0.77 | 0.69 | 1.30 | 0.97 | ||||||||||||
Dividends declared per common share | 0.835 | 0.835 | 0.835 | 0.835 | ||||||||||||
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||||||
(millions) | ||||||||||||||||
2019 | ||||||||||||||||
Operating revenue | $ | 1,965 | $ | 1,938 | $ | 2,264 | $ | 1,941 | ||||||||
Income from operations | 122 | 238 | 820 | 659 | ||||||||||||
Net income | 20 | 100 | 602 | 427 | ||||||||||||
2018 | ||||||||||||||||
Operating revenue | $ | 1,748 | $ | 1,829 | $ | 2,232 | $ | 1,810 | ||||||||
Income from operations | 364 | 533 | 756 | 418 | ||||||||||||
Net income | 184 | 339 | 520 | 239 | ||||||||||||
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||||||
(millions) | ||||||||||||||||
2019 | ||||||||||||||||
Operating revenue | $566 | $530 | $502 | $571 | ||||||||||||
Income from continuing operations | 247 | 179 | 202 | 276 | ||||||||||||
Net income from continuing operations | 172 | 123 | 130 | 276 | ||||||||||||
Net income from discontinued operations | 54 | 26 | 45 | 16 | ||||||||||||
Net income including noncontrolling interests | 226 | 149 | 175 | 292 | ||||||||||||
Net income attributable to Dominion Energy Gas | 190 | 119 | 151 | 261 | ||||||||||||
2018 | ||||||||||||||||
Operating revenue | $389 | $508 | $533 | $566 | ||||||||||||
Income from continuing operations | 167 | 90 | 302 | 228 | ||||||||||||
Net income from continuing operations | 157 | 84 | 209 | 182 | ||||||||||||
Net income (loss) from discontinued operations | 56 | 45 | 33 | (110 | ) | |||||||||||
Net income including noncontrolling interests | 213 | 129 | 242 | 72 | ||||||||||||
Net income attributable to Dominion Energy Gas | 180 | 83 | 191 | 27 | ||||||||||||
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 Overover Financial Reporting
Management of Dominion Energy understands and accepts responsibility for Dominion Energy’sEnergy'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 20192022 Annual Report to contain a management’smanagement'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, 2019,2022, 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‘sEnergy’s internal control over financial reporting as of December 31, 2019.2022. 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, 2019.
Dominion Energy’s independent registered public accounting firm is engaged to express an opinion on Dominion Energy‘sEnergy’s internal control over financial reporting, as stated in their report which is included herein.
February 28, 2020
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, 2019,2022, based on criteria established inControl—Control — Integrated Framework (2013)2019,2022, based on criteria established inControl—Control — Integrated Framework (2013)
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, 2019,2022, of Dominion Energy and our report dated February 28, 2020,21, 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’sManagement'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 28, 2020
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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’sPower'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’sPower's Audit Committee and meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss Virginia Power’sPower'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 2019Power's 2022 Annual Report to contain a management’smanagement'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, 2019,2022, 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’sPower's internal control over financial reporting as of December 31, 2019.2022. 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, 2019.
This annual report does not include an attestation report of Virginia Power’sPower's registered public accounting firm regarding internal control over financial reporting. Management’sManagement's report is not subject to attestation by Virginia Power’sPower's independent registered public accounting firm pursuant to a permanent exemption under the Dodd-Frank Act.
February 28, 2020
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Item 9B. Other Information
Explanatory Note: The following information is furnishedfiled in this Form 10-K in lieu of being furnishedfiled pursuant to Item 2.025.03 in a Form 28, 2020.
On February 11, 2020,20, 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 reduction relatesforegoing description of the amendments to additional reserves taken for SCANA legal proceedings. The revised Earnings Release Kit reflectingDominion Energy’s Bylaws is qualified in its entirety by reference to the reduction in earningsfull text of Dominion Energy’s Bylaws, a copy of which is furnished with this Form 10-Kattached hereto as Exhibit 99.
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 Energy is incorporated by reference from the Dominion Energy 2020 Proxy Statement, which will be filed on or around March 26, 2020:
The information concerning the executive officers of Dominion Energy required by this item is included in Part I of this FormOfficers.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 2020 Proxy Statement andrequired by this item is incorporated by reference:reference to the information regarding executive compensation contained under the headingsCompensation Discussion and AnalysisandTables; the information regarding Compensation Committee interlocks contained under the headingCompensation Committee InterlocksandInsider Participation; the information regarding the Compensation Committee review and discussions of Compensation Discussion and Analysis contained under the headingCompensation, Governance and Nominating Committee Report; and the information regarding director compensation contained under the headingDirectors.
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 under the headingSecurities Ownershipin the 2020 Proxy Statementthis item is incorporated by reference.
DOMINION ENERGY
The information regarding related party transactions required by this item found underis incorporated by reference to the headingInformation—CertainGovernance Policies and Practices —Certain Relationships and Related Party Transactionsinformation regarding director independence found under the heading–Director—Director Independence20202023 Proxy Statement is incorporated by reference.
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 heading20202023 Proxy Statement is incorporated by reference.
VIRGINIA POWER
The following table presents fees paid to Deloitte & Touche LLP for services related to Virginia Power and Dominion Energy Gas for the fiscal years ended December 31, 20192022 and 2018.
Type of Fees | 2019 | 2018 | ||||||
(millions) | ||||||||
Virginia Power | ||||||||
Audit fees | $2.13 | $ | 1.68 | |||||
Audit-related fees | — | — | ||||||
Tax fees | — | — | ||||||
All other fees | — | — | ||||||
Total Fees | $2.13 | $ | 1.68 | |||||
Dominion Energy Gas | ||||||||
Audit fees | $2.31 | $ | 0.97 | |||||
Audit-related fees | 0.26 | 0.26 | ||||||
Tax fees | — | — | ||||||
All other fees | — | — | ||||||
Total Fees | $2.57 | $ | 1.23 | |||||
Type of Fees |
| 2022 |
|
| 2021 |
| ||
(millions) |
|
|
|
|
|
| ||
Virginia Power |
|
|
|
|
|
| ||
Audit fees |
| $ | 2.44 |
|
| $ | 2.37 |
|
Audit-related fees |
|
| 0.08 |
|
|
| — |
|
Tax fees |
|
| — |
|
|
| 0.04 |
|
All other fees |
|
| — |
|
|
| — |
|
Total Fees |
| $ | 2.52 |
|
| $ | 2.41 |
|
Audit fees represent fees of Deloitte & Touche LLP for the audit of Virginia Power and Dominion Energy Gas’Power’s annual consolidated financial statements, the review of financial statements included in Virginia Power and Dominion Energy Gas’Power’s quarterly Form
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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 and Dominion Energy Gas’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 and Dominion Energy Gas’ BoardsPower’s Board of Directors havehas adopted the Dominion Energy Audit Committee20192022 meeting, the Dominion Energy Audit Committee approved schedules of services and fees for 20202023 inclusive of Virginia Power and Dominion Energy Gas.Power. In accordance with the
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Part IV
Item 15. Exhibits and Financial Statement Schedules
(a) Certain documents are filed as part of this Form
1. Financial Statements
See Index on page 69.
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 | X | |||||||||||||||
3.1.a | X | |||||||||||||||
3.1.b | X | |||||||||||||||
3.2.a | ||||||||||||||||
X | ||||||||||||||||
3.2.b | X | |||||||||||||||
4 | ||||||||||||||||
Dominion Energy, Inc. | 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 | X | X | |||||||||||||
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207
208
Exhibit Number | Description | Dominion Energy | Virginia Power | |||||||||||||
4.14 | ||||||||||||||||
X | ||||||||||||||||
10.1 | ||||||||||||||||
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Number 10.19* | ||||||||||||||||
X | ||||||||||||||||
10.20* | X | |||||||||||||||
10.21* | X | |||||||||||||||
10.22* | X | |||||||||||||||
10.23* | X | |||||||||||||||
10.24* | Restricted Stock Agreement for Steven D. Ridge (filed herewith). | X | ||||||||||||||
210
Exhibit Number | Description | Dominion Energy | Virginia Power | |||||||||||||
10.25* | X | |||||||||||||||
10.26* | X | |||||||||||||||
10.27* | X | |||||||||||||||
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 |
Number 101 | ||||||||||||||||
The following financial statements from Dominion Energy, Inc.’s Annual Report on Form | X | X | ||||||||||||||
104 | Cover Page Interactive Data File formatted in iXBRL (Inline eXtensible Business Reporting Language) and contained in Exhibit 101. | X | X | |||||||||||||
* Indicates management contract or compensatory plan or arrangement.
Item 16. Form
None.
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Signatures
DOMINION ENERGY
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
DOMINION ENERGY, INC. | ||||
By: | /s/ | |||
( Chief Executive Officer) | ||||
Date: February 28, 2020
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 28th21st day of February, 2020.
Signature | Title | ||
/s/ Robert M. Blue | Chair of the Board of Directors, President and Chief Executive Officer | ||
/s/ James A. Bennett James A. Bennett | Director | ||
/s/ Helen E. Dragas Helen E. Dragas | Director | ||
/s/ James O. Ellis, Jr. James O. Ellis, Jr. | Director | ||
/s/ D. Maybank Hagood | Director | ||
D. Maybank Hagood | |||
/s/ Ronald W. Jibson Ronald W. Jibson | Director | ||
/s/ Mark J. Kington Mark J. Kington | Director | ||
/s/ 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/ Steven D. Ridge | Senior Vice President and Chief Financial Officer | ||
/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/ | ||||
( Chief Executive Officer) | |||||
Date: February 28, 2020
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 28th21st day of February, 2020.
Signature | Title | |
/s/ Edward H. Baine Edward H. Baine | Director | |
/s/ Robert M. Blue Robert M. Blue | Director | |
/s/ Diane Leopold | Director | |
/s/ Steven D. Ridge Steven D. Ridge | Senior Vice President and Chief Financial Officer | |
/s/ Michele L. Cardiff Michele L. Cardiff | Senior Vice President, Controller and Chief Accounting Officer |
213