(1) | Represents shares of common stock repurchases during the fourth quarter of 2019:| | | | | | | | | | | | | | | | | | Dominion Energy Purchases Of Equity Securities | | | | | | | | | | of Publicly Announced
Plans or Programs | | | Approximate Dollar Value)
of Shares (or Units) that May Yet Be Purchased under the | | | | | | | | | | | | | | | | 19,629,059 shares/$ | | | | | | | | | | | | | | | | | 19,629,059 shares/$ | | | | | | | | | | | | | | | | | 19,629,059 shares/$ | | | | | | | | | | | | | | | | | 19,629,059 shares/$ | | |
(1) | Represents shares that were tendered by employees to satisfy tax withholding obligations on vested restricted stock. |
(2) | Represents the weighted-average price paid per share. |
(3) | The remaining repurchase authorization is pursuant to repurchase authority granted byIn November 2020, the Dominion Energy Board of Directors in February 2005, asauthorized the repurchase of up to $1.0 billion of shares of common stock. This repurchase program has no expiration date or price or volume targets and may be modified in June 2007. The aggregate authorization granted bysuspended or terminated at any time. Shares may be purchased through open market or privately negotiated transactions or otherwise at the Dominion Energy Boarddiscretion of Directors was 86 million shares (as adjustedmanagement subject to reflect a two-for-one
stock split distributed in November 2007) not to exceed $4 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 20202022 but is neither required to nor restricted, except as described in Note 21 to the Consolidated Financial Statements, from making such payments. All of Dominion Energy Gas’ membership interests are owned by Dominion Energy. Dominion Energy Gas intends to pay quarterly cash dividends in 2020 but is neither required to nor restricted, except as described in Note 21 to the Consolidated Financial Statements, from making such payments.
Item 6. Selected Financial Data[Reserved]
The following table should be read in conjunction with the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data.
Dominion Energy’s Consolidated Financial Statements include the results of operations acquired in the SCANA Combination effective January 2019.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (millions, except per share amounts) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | Net income attributable to Dominion Energy | | | | | | | | | | | | | | | | | | | | | Net income attributable to Dominion Energy per common share-basic | | | | | | | | | | | | | | | | | | | | | Net income attributable to Dominion Energy per common share-diluted | | | | | | | | | | | | | | | | | | | | | Dividends declared per common share | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(1) | Includes merger and integration-related costs associated with the SCANA Combination of $1.8 billionafter-tax
(inclusive of $756 millionafter-tax
charge for refunds of amounts previously collected for the NND Project, $480 millionafter-tax
charge for litigation acquired in the SCANA Combination and $319 millionafter-tax
charge related to a voluntary retirement program), $585 millionafter-tax
charges associated primarily with the planned early retirement of certain electric generation facilities, automated meter reading infrastructure and the termination of a contract with anon-utility
generator, partially offset by a $429 millionafter-tax
net gain related to nuclear decommissioning trust funds. |
(2) | Includes $568 millionafter-tax
gains on sales of certain merchant generation facilities and equity method investments partially offset by $164 millionafter-tax
charge related to the impairment of certain gathering and processing assets and a $160 millionafter-tax
charge associated with Virginia legislation enacted in March 2018 that requiredone-time
rate credits of certain amounts to utility customers. |
(3) | Includes $851 million of tax benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate, partially offset by $96 million ofafter-tax
charges associated with equity method investments in wind-powered generation facilities. |
(4) | Includes a $122 millionafter-tax
charge related to future ash pond and landfill closure costs at certain utility generation facilities. |
(5) | Includes finance leases. |
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations MD&A discusses Dominion Energy’s results of operations, and general financial condition and liquidity and Virginia Power and Dominion Energy Gas’Power’s results of operations.operations as of and for the year ended December 31, 2021 as compared to the year ended December 31, 2020, as applicable. For a discussion of these items for the year ended December 31, 2020 as compared to the year ended December 31, 2019, please see Part II, Item 7. MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on February 25, 2021. MD&A should be read in conjunction with Item 1. Business and the Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data. Virginia Power and Dominion Energy Gas meetmeets the conditions to file under the reduced disclosure format, and therefore havehas omitted certain sections of MD&A. Contents ofCONTENTS OF MD&A MD&A consists of the following information: • | Forward-Looking Statements |
Forward-Looking Statements• | Accounting Matters—Dominion Energy |
| • | Segment Results of Operations |
Accounting Matters—Dominion Energy• | Liquidity and Capital Resources—Dominion Energy |
• | Future Issues and Other Matters—Dominion Energy |
Dominion Energy
Results of Operations
Segment Results of Operations
Virginia Power
Results of Operations
Dominion Energy Gas
Results of Operations
Liquidity and Capital Resources—Dominion Energy
Future Issues and Other Matters—Dominion Energy
Forward-looking Statements
FORWARD-LOOKING STATEMENTS This report contains statements concerning the Companies’ expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In most cases, the reader can identify these forward-looking statements by such words as “anticipate,” “estimate,” “forecast,” “expect,” “believe,” “should,” “could,” “plan,” “may,” “continue,” “target” or other similar words. The Companies make forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to differ materially from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other factors may cause actual results to differ materially from those indicated in any forward-looking statement. These factors include but are not limited to: Unusual weather conditions and their effect on energy sales to customers and energy commodity prices;
Extreme weather events and other natural disasters, including, but not limited to, hurricanes, high winds, severe storms, earthquakes, flooding, climate changes and changes in water temperatures and availability that can cause outages and property damage to facilities;
Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations;
Risks of operating businesses in regulated industries that are subject to changing regulatory structures;
Changes to regulated electric rates collected by Dominion Energy and Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion Energy and Dominion Energy Gas;
Changes in rules for RTOs and ISOs in which Dominion Energy and Virginia Power join and/or participate, including changes in rate designs, changes in FERC’s interpretation of market rules and new and evolving capacity models;
Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants;
Risks associated with entities in which Dominion Energy and Dominion Energy Gas share ownership with third parties, including risks that result from lack of sole decision making authority, disputes that may arise between Dominion Energy and Dominion Energy Gas and third party participants and difficulties in exiting these arrangements;
Changes in future levels of domestic and international natural gas production, supply or consumption;
Fluctuations in future volumes of LNG imports or exports from the U.S. and other countries worldwide or demand for, purchases of, and prices related to natural gas or LNG;
Timing and receipt of regulatory approvals necessary for planned construction or growth projects and compliance with conditions associated with such regulatory approvals;
The inability to complete planned construction, conversion or growth projects at all, or with the outcomes or within the terms and time frames initially anticipated, including as a result of increased public involvement, intervention or litigation in such projects;
Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other substances, more extensive permitting requirements and the regulation of additional substances;
Cost of environmental compliance, including those costs related to climate change;
Changes in implementation and enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities;
Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals or related appeals;
Unplanned outages at facilities in which the Companies have an ownership interest;
The impact of operational hazards, including adverse developments with respect to pipeline and plant safety or integrity, equipment loss, malfunction or failure, operator error, and other catastrophic events;
Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities;
Changes in operating, maintenance and construction costs;
Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity;
Additional competition in industries in which the Companies operate, including in electric markets in which Dominion Energy’s merchant generation facilities operate and potential competition from the development and deployment of alternative energy sources, such as self-generation and distributed generation technologies, and availability of market alternatives to large commercial and industrial customers;
• | Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; |
• | | | | | | | | | | | | | | | Extreme weather events and other natural disasters, including, but not limited to, hurricanes, high winds, severe storms, earthquakes, flooding, climate changes and changes in water temperatures and availability that can cause outages and property damage to facilities; |
• | The impact of extraordinary external events, such as the current pandemic health event resulting from COVID-19, and their collateral consequences, including extended disruption of economic activity in our markets and global supply chains; |
• | Federal, state and local legislative and regulatory developments, including changes in or interpretations of federal and state tax laws and regulations; |
• | Risks of operating businesses in regulated industries that are subject to changing regulatory structures; |
• | Changes to regulated electric rates collected by the Companies and regulated gas distribution, transportation and storage rates collected by Dominion Energy; |
• | Changes in rules for RTOs and ISOs in which the Companies join and/or participate, including changes in rate designs, changes in FERC’s interpretation of market rules and new and evolving capacity models; |
• | Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants; |
• | Risks associated with entities in which Dominion Energy shares ownership with third parties, including risks that result from lack of sole decision making authority, disputes that may arise between Dominion Energy and third party participants and difficulties in exiting these arrangements; |
• | Changes in future levels of domestic and international natural gas production, supply or consumption; |
• | Impacts to Dominion Energy’s noncontrolling interest in Cove Point from fluctuations in future volumes of LNG imports or exports from the U.S. and other countries worldwide or demand for, purchases of, and prices related to natural gas or LNG; |
• | Timing and receipt of regulatory approvals necessary for planned construction or growth projects and compliance with conditions associated with such regulatory approvals; |
• | The inability to complete planned construction, conversion or growth projects at all, or with the outcomes or within the terms and time frames initially anticipated, including as a result of increased public involvement, intervention or litigation in such projects; |
Competition in the development, construction and ownership of certain electric transmission facilities in Dominion Energy and Virginia Power’s service territory in connection with Order 1000;• | Risks and uncertainties that may impact the Companies’ ability to develop and construct the CVOW Commercial Project within the currently proposed timeline, or at all, and consistent with current cost estimates along with the ability to recover such costs from customers; |
• | Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other substances, more extensive permitting requirements and the regulation of additional substances; |
• | Cost of environmental strategy and compliance, including those costs related to climate change; |
• | Changes in implementation and enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities; |
• | Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals or related appeals; |
Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies;• | Unplanned outages at facilities in which the Companies have an ownership interest; |
• | The impact of operational hazards, including adverse developments with respect to pipeline and plant safety or integrity, equipment loss, malfunction or failure, operator error and other catastrophic events; |
• | Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities; |
• | Changes in operating, maintenance and construction costs; |
• | Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity; |
Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, changes in supplies of natural gas delivered to Dominion Energy and Dominion Energy Gas’ pipeline systems, failure to maintain or replace customer contracts on favorable terms, changes in customer growth or usage patterns, including as a result of energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods;• | Additional competition in industries in which the Companies operate, including in electric markets in which Dominion Energy’s nonregulated generation facilities operate and potential competition from the development and deployment of alternative energy sources, such as self-generation and distributed generation technologies, and availability of market alternatives to large commercial and industrial customers; |
• | Competition in the development, construction and ownership of certain electric transmission facilities in the Companies’ service territory in connection with Order 1000; |
• | Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies; |
• | Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, changes in supplies of natural gas delivered to Dominion Energy’s pipeline system, failure to maintain or replace customer contracts on favorable terms, changes in customer growth or usage patterns, including as a result of energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods; |
• | Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures; |
Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures;• | Impacts of acquisitions, divestitures, transfers of assets to joint ventures and retirements of assets based on asset portfolio reviews; |
• | The expected timing and likelihood of completing the sales of Kewaunee and Hope, including the ability to obtain the requisite regulatory approvals and the terms and conditions of such regulatory approvals; |
• | Adverse outcomes in litigation matters or regulatory proceedings, including matters acquired in the SCANA Combination; |
• | Counterparty credit and performance risk; |
• | Fluctuations in the value of investments held in nuclear decommissioning trusts by the Companies and in benefit plan trusts by Dominion Energy; |
Impacts of acquisitions, divestitures, transfers of assets to joint ventures and retirements of assets based on asset portfolio reviews;• | Fluctuations in energy-related commodity prices and the effect these could have on Dominion Energy’s earnings and the Companies’ liquidity position and the underlying value of their assets; |
• | Fluctuations in interest rates; |
• | Fluctuations in currency exchange rates of the Euro or Danish Krone associated with the CVOW Commercial Project; |
• | Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital; |
• | Global capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms; |
• | Political and economic conditions, including inflation and deflation; |
Adverse outcomes in litigation matters or regulatory proceedings, including matters acquired in the SCANA Combination;• | Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; and |
• | Changes in financial or regulatory accounting principles or policies imposed by governing bodies. |
Counterparty credit and performance risk;
Fluctuations in the value of investments held in nuclear decommissioning trusts by Dominion Energy and Virginia Power and in benefit plan trusts by Dominion Energy and Dominion Energy Gas;
Fluctuations in energy-related commodity prices and the effect these could have on Dominion Energy’s earnings and the Companies’ liquidity position and the underlying value of their assets;
Fluctuations in interest rates or foreign currency exchange rates;
Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital;
Global capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms;
Political and economic conditions, including inflation and deflation;
Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; and
Changes in financial or regulatory accounting principles or policies imposed by governing bodies.
Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors. The Companies’ forward-looking statements are based on beliefs and assumptions using information available at the time the statements are made. The Companies caution the reader not to place undue reliance on their forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, differ materially from actual results. The Companies undertake no obligation to update any forward-looking statement to reflect developments occurring after the statement is made. ACCOUNTING MATTERS Critical Accounting Policies and Estimates Dominion Energy has identified the following accounting policies, including certain inherent estimates, that as a result of the judgments, uncertainties, uniqueness and complexities of the underlying accounting standards and operations involved, could result in material changes to its financial condition or results of operations under different conditions or using different assumptions. Dominion Energy has discussed the development, selection and disclosure of each of these policies with the Audit Committee of its Board of Directors. Accounting for Regulated Operations
ACCOUNTING FOR REGULATED OPERATIONS The accounting for Dominion Energy’s regulated electric and gas operations differs from the accounting for nonregulated operations in that Dominion Energy is required to reflect the effect of rate regulation in its Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds or other benefits through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Dominion Energy evaluates whether or not recovery of its regulatory assets through future rates is probable as well as whether a regulatory liability due to customers is probable and makes various assumptions in its analyses. These analyses are generally based on: | • | Orders issued by regulatory commissions, legislation and judicial actions; |
Orders issued by regulatory commissions, legislation and judicial actions; | • | 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. |
Past experience;
Discussions with applicable regulatory authorities and legal counsel;
Forecasted earnings; and
Considerations around the likelihood of impacts from events such as unusual weather conditions, extreme weather events and other natural disasters and unplanned outages of facilities.
If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made. A regulatory liability, if considered probable, will be recorded in the period such assessment is made or reversed into earnings if no longer probable. In connection with the evaluation of Virginia Power’s earnings for the 2021 Triennial Review, in 2020 Virginia Power established a regulatory liability for benefits expected to be provided to Virginia retail electric customers through the use of a CCRO in accordance with the GTSA. In 2021, Virginia Power made further adjustments to this regulatory liability prior to its ultimate resolution through a comprehensive settlement agreement. See Notes 12 and 13 to the Consolidated Financial Statements for additional information.
Asset Retirement Obligations
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
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
absence of quoted market prices, Dominion Energy estimates the fair value of its AROs using present value techniques, in which it makes various assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. The impact on measurements of new AROs or remeasurements of existing AROs, using different cost escalation or credit-adjusted risk free rates in the future, may be significant. When Dominion Energy revises any assumptions used to calculate the fair value of existing AROs, it adjusts the carrying amount of both the ARO liability and the related long-lived asset for assets that are in service; for assets that have ceased or are expected to cease operations, Dominion Energy adjusts the carrying amount of the ARO liability with such changes either recognized in income. income or as a regulatory asset.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, 2019,2021 and 2020, Dominion Energy’s nuclear decommissioning AROs totaled $1.7 billion.$2.0 billion and $1.9 billion, respectively. The following discusses critical assumptions inherent in determining the fair value of AROs associated with Dominion Energy’s nuclear decommissioning obligations. Dominion Energy obtains from third-party specialists periodic site-specific base year cost studies in order to estimate the nature, cost and timing of planned decommissioning activities for its nuclear plants. These cost studies are based on relevant information available at the time they are performed; however, estimates of future cash flows for extended periods of time are by nature highly uncertain and may vary significantly from actual results. These cash flows include estimates on timing of decommissioning, which for regulated nuclear units factors in the probability of NRC approval for license extensions. In addition, Dominion Energy’s cost estimates include cost escalation rates that are applied to the base year costs. Dominion Energy determines cost escalation rates, which represent projected cost increases over time due to both general inflation and increases in the cost of specific decommissioning activities, for each nuclear facility. The selection of these cost escalation rates is dependent on subjective factors which are considered to be critical assumptions. At December 31, 2021, a 0.25% increase in cost escalation rates would have resulted in an approximate $360 million increase in Dominion Energy’s nuclear decommissioning AROs.INCOME TAXES Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws including 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 tax-related assets and liabilities could be material. Given the uncertainty and judgment involved in the determination and filing of income taxes, there are standards for recognition and measurement in financial statements of positions taken or expected to be taken by an entity in its income tax returns. Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy a more-likely- than-not
more-likely-than-not recognition threshold, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. At December 31, 2019,2021 and 2020, Dominion Energy had $175$128 million and $167 million, respectively, of unrecognized tax benefits. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations. Deferred income tax assets and liabilities are recorded representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Dominion Energy evaluates quarterly the probability of realizing deferred tax assets by considering current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets. In addition, changes in tax laws or tax rates may require reconsideration of the realizability of existing deferred tax assets. Dominion Energy establishes a valuation allowance when it is more-likely-than-not that all or a portion of a deferred tax asset will not be realized. At December 31, 2019,2021 and 2020, Dominion Energy had established $161$140 million and $155 million, respectively, of valuation allowances. The 2017 Tax Reform Act included a broad range of tax reform provisions affecting the Companies, including changes in corporate tax rates and business deductions. Many of these provisions differ significantly from prior U.S. tax law, resulting in pervasive financial reporting implications for the Companies. The 2017 Tax Reform Act included significant changes to the Internal Revenue Code of 1986, including amendments which significantly change the taxation of individuals and business entities and included specific provisions related to regulated public utilities. The more significant changes that impact the Companies included in the 2017 Tax Reform Act are (i) reducing the corporate federal income tax rate from 35% to 21%; (ii) effective in 2018, limiting the deductibility of interest expense to 30% of adjusted taxable income for certain businesses with any disallowed interest allowed to be carried forward indefinitely; (iii) permitting 100% expensing (100% bonus depreciation) for certain qualified property; (iv) eliminating the deduction for qualified domestic production activities; and (v) limiting the utilization of net operating losses arising after December 31, 2017 to 80% of taxable income with an indefinite carryforward. The specific provisions related to regulated public utilities in the 2017 Tax Reform Act generally allow for the continued deductibility of interest expense, the exclusion from full expensing for tax purposes of certain property acquired and placed in service after September 27, 2017 and continued certain rate normalization requirements for accelerated depreciation benefits.
At the date of enactment, the Companies’ deferred taxes were remeasured based upon the new tax rate expected to apply when temporary differences are realized or settled. For regulated operations, many of the changes in deferred taxes represented amounts probable of collection from or refund 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 taxes may be passed back to customers for certain accelerated tax depreciation benefits. Potential refunds of other deferred taxes will be determined by the Companies’ regulators. For nonregulated operations, the changes in deferred taxes were recorded as an adjustment to deferred tax expense.
Accounting for Derivative Contracts and Financial Instruments at Fair Value
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
As of December 31, 2019, Dominion Energy reported $8.9 billion of goodwill in its Consolidated Balance Sheet. The majority of the balance relates to the SCANA Combination, as discussed in See Note 36 to the Consolidated Financial Statements thefor quantitative information on unobservable inputs utilized in Dominion Energy Questar Combination in 2016 and the acquisitionEnergy’s fair value measurements of the former CNG in 2000.
certain derivative contracts.USE OF ESTIMATES IN GOODWILL IMPAIRMENT TESTING In April of each year, Dominion Energy tests its goodwill for potential impairment, and performs additional tests more frequently if an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount. In addition, in the fourth quarter of 2019, Dominion Energy performed impairment tests immediately before and after the realignment of its operating segments. The 2019, 2018 and 20172021 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 are made as of a point in time; subsequent modifications, particularly changes in discount rates or growth rates inherent in Dominion Energy’s estimates of future cash flows, could result in a future impairment of goodwill. Although Dominion Energy has consistently applied the same methods in developing the assumptions and estimates that underlie the fair value calculations, such as estimates of future cash flows, and based those estimates on relevant information available at the time, such cash flow estimates are highly uncertain by nature and may vary significantly from actual results. If the estimates of future cash flows used in the most recent teststest had been 10% lower or if the discount rate had been 0.25% higher, the resulting fair values would have still been greater than the carrying values of each of those reporting units tested, indicating that no impairment was present. See Note 11 to the Consolidated Financial Statements for additional information. Use of Estimates in Long-lived Asset and Equity Method Investment Impairment Testing
USE OF ESTIMATES IN LONG-LIVED ASSET AND EQUITY METHOD INVESTMENT IMPAIRMENT TESTING Impairment testing for an individual or group of long-lived assets, including intangible assets with definite lives, and equity method investments is required when circumstances indicate those assets may be impaired. When a long-lived asset’s carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent that the asset’s fair value is less than its carrying amount. When an equity method investment’s carrying amount exceeds its fair value, and the decline in value is deemed to be other-than-temporary, an impairment is recognized to the extent that the fair value is less than its carrying amount. Performing an impairment test on long-lived assets and equity method investments involves judgment in areas such as identifying if circumstances indicate an impairment may exist, identifying and grouping affected assets in the case of long-lived assets, and developing the undiscounted and discounted estimated future cash flows (used to estimate fair value in the absence of a market-based value) associated with the asset, including probability weighting such cash flows to reflect expectations about possible variations in their amounts or timing, expectations about the operations of the long-lived assets and equity method investments and the selection of an appropriate discount rate. When determining whether a long-lived asset or asset group has been impaired, management groups assets at the lowest level that has identifiable cash flows. Although cash flow estimates are based on relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. For example, estimates of future cash flows would contemplate factors which may change over time, such as the expected use of the asset or underlying assets of equity method investees, including future production and sales levels, expected fluctuations of prices of commodities sold and consumed and expected proceeds from dispositions. There were no tests performed in 2021 of long-lived assets or equity method investments which could have resulted in material impairments. HELD FOR SALE CLASSIFICATION Dominion Energy recognizes the assets and liabilities of a disposal group as held for sale in the period (i) it has approved and committed to a plan to sell the disposal group, (ii) the disposal group is available for immediate sale in its present condition, (iii) an active program to locate a buyer and other actions required to sell the disposal group have been initiated, (iv) the sale of the disposal group is probable, (v) the disposal group is being actively marketed for sale at a price that is reasonable in relation to its current fair value and (vi) it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn. Dominion Energy initially measures a disposal group that is classified as held for sale at the lower of its carrying value or fair value less any costs to sell.
Any loss resulting from this measurement is recognized in the period in which the held for sale criteria are met. Conversely, gains are not recognized on the sale of a disposal group until closing. Upon designation as held for sale, Dominion Energy stops recording depreciation expense and assesses the fair value of the disposal group less any costs to sell at each reporting period and until it is no longer classified as held for sale. The determination as to whether the sale of the disposal group is probable may include significant judgments from management related to the expectation of obtaining approvals from applicable regulatory agencies such as state utility regulatory commissions, FERC or the U.S. Federal Trade Commission. This analysis is generally based on orders issued by regulatory commissions, past experience and discussions with applicable regulatory authorities and legal counsel. In May 2021, Dominion Energy entered into an agreement to sell Kewaunee, subject to termination by either party if not completed by December 2022. The consideration as to whether the sale is probable includes judgments related to the ability to obtain the approvals, in a timely manner, of the NRC and the Wisconsin Commission. Due to the uncertainty surrounding the timing of or ability to obtain approval by the Wisconsin Commission, at December 31, 2021 Dominion Energy did not conclude that the sale is probable and, as a result, the disposal group was not classified as held for sale. Dominion Energy would have recognized a loss of approximately $725 million ($570 million after-tax) if such classification had been met. This loss primarily represents the difference between the nuclear decommissioning trust and AROs at December 31, 2021. The Wisconsin Commission requires that any excess decommissioning funds be returned to WPSC and WP&L customers following completion of all decommissioning activities. See Notes 6 and 9Note 3 to the Consolidated Financial Statements for a discussion of impairments related to certain long-lived assets and equity method investments. As discussed inFuture Issues and Other Matters
, continued delays in obtaining and maintaining permits necessary for construction along with construction delays due to judicial actions have impacted the estimated cost and schedule for the Atlantic
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Coast Pipeline Project. As a result, Dominion Energy evaluated the carrying amount of its equity method investment in Atlantic Coast Pipeline for an other-than-temporary impairment and determined that it was not impaired. Any significant changes affecting the discounted cash flow estimates associated with the Atlantic Coast Pipeline Project, such as future unfavorable judicial or regulatory actions resulting in further construction andin-service
delays along with an increase in construction costs, could result in an impairment charge.additional information.EMPLOYEE BENEFIT PLANS Dominion Energy sponsors noncontributory defined benefit pension plans and other postretirement benefit plans for eligible active employees, retirees and qualifying dependents. The projected costs of providing benefits under these plans are dependent, in part, on historical information such as employee demographics, the level of contributions made to the plans and earnings on plan assets. Assumptions about the future, including the expected long-term rate of return on plan assets, discount rates applied to benefit obligations, mortality rates and the anticipated rate of increase in healthcare costs and participant compensation, also have a significant impact on employee benefit costs. The impact of changes in these factors, as well as differences between Dominion Energy’s assumptions and actual experience, is generally recognized in the Consolidated Statements of Income over the remaining average service period of plan participants, rather than immediately. The expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates and mortality rates are critical assumptions. Dominion Energy determines the expected long-term rates of return on plan assets for pension plans and other postretirement benefit plans by using a combination of: • | Expected inflation and risk-free interest rate assumptions; |
Expected inflation and risk-free interest rate assumptions;• | Historical return analysis to determine long-term historic returns as well as historic risk premiums for various asset classes; |
• | Expected future risk premiums, asset classes’ volatilities and correlations; |
• | Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major capital market assumptions; and |
Historical return analysis to determine long-term historic returns as well as historic risk premiums for various asset classes;• | Investment allocation of plan assets. The strategic target asset allocation for Dominion Energy’s pension funds is 27% U.S. equity, 18% non-U.S. equity, 32% fixed income, 3% real estate and 20% other alternative investments, such as private equity investments. |
Expected future risk premiums, asset classes’ volatilities and correlations;
Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major capital market assumptions; and
Investment allocation of plan assets. The strategic target asset allocation for Dominion Energy’s pension funds is 28% U.S. equity, 18%non-U.S.
equity, 35% fixed income, 3% real estate and 16% other alternative investments, such as private equity investments.Strategic investment policies are established for Dominion Energy’s prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include those mentioned above such as employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from the plans’ strategic allocation are a function of Dominion Energy’s assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans’ actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the targets. Future asset/liability studies will focus on strategies to further reduce pension and other postretirement plan risk, while still achieving attractive levels of returns. Dominion Energy develops non-investment related assumptions, which are then compared to the forecasts of an independent investment advisor to ensure reasonableness. An internal committee selects the final assumptions. Dominion Energy calculated its pension cost using an expected long-term rate of return on plan assets assumption that ranged from 7.00% to 8.45% for 2021, 7.00% to 8.60% for 2020 and 7.00% to 8.65% for 2019 and 8.75% for 2018 and 2017.2019. For 2020,2022, 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, 2019.2021. Dominion Energy calculated its other
postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 8.45% for 2021 and 8.50% for 2019, 20182020 and 2017.2019. For 2020,2022, 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 2.73% to 3.29% for pension plans and 2.69% to 2.80% for other postretirement benefit plans in 2021, ranged from 2.77% to 3.63% for pension plans and 3.07% to 3.52% for other postretirement benefit plans in 2020 and ranged from 3.57% to 4.43% for pension plans and 4.05% to 4.41% for other postretirement benefit plans in 2019, ranged from 3.80% to 3.81% for pension plans and 3.76% for other postretirement benefit plans in 2018 and ranged from 3.31% to 4.50% for pension plans and 3.92% to 4.47% for other postretirement benefit plans in 2017.2019. Dominion Energy selected a discount rate ranging from 3.47%3.06% to 3.63%3.19% for pension plans and 3.44%3.04% to 3.52%3.11% for other postretirement benefit plans for determining its December 31, 20192021 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%2021 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 2021 Net Periodic Cost | | | Change in Actuarial Assumptions | | Pension Benefits | | | Other Postretirement Benefits | | (millions, except percentages) | | | | | | | | | | Dominion Energy | | | | | | | | | | Discount Rate | (0.25)% | | $ | 18 | | | $ | — | | Long-term rate of return on plan assets | (0.25)% | | | 25 | | | | 5 | | Health care cost trend rate | 1% | | N/A | | | | 9 | |
| | | | | | | | | | | | | | | | | | | Increase in 2020 Net Periodic Cost | | | | Change in
Actuarial
Assumptions | | | | | | Other
Postretirement
Benefits | | (millions, except percentages) | | | | | | | | | | | | | | )% | | | | | | | | | Long-Term rate of return on plan assets | | | | )% | | | | | | | | | Health care cost trend rate | | | | % | | | | | | | | |
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, 2021 by $371$376 million and its accumulated postretirement benefit obligation at December 31, 2021 by $52$44 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated postretirement benefit obligation at December 31, 2021 by $153$121 million.
See Note 22 to the Consolidated Financial Statements for additional information on Dominion Energy’s employee benefit plans. See Note 2 to the Consolidated Financial Statements for a discussion of new accounting standards. DOMINION ENERGY Results Ofof Operations Presented below is a summary of Dominion Energy’s consolidated results: Year Ended December 31, | | 2021 | | | $ Change | | | 2020 | | | $ Change | | | 2019 | | (millions, except EPS) | | | | | | | | | | | | | | | | | | | | | Net income (loss) attributable to Dominion Energy | | $ | 3,288 | | | $ | 3,689 | | | $ | (401 | ) | | $ | (1,759 | ) | | $ | 1,358 | | Diluted EPS | | | 3.98 | | | | 4.55 | | | | (0.57 | ) | | | (2.19 | ) | | | 1.62 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net Income attributable to Dominion Energy | | $ | | | | | | | | $ | | | | | | | | $ | | | | | | | | | | | ) | | | | | | | | ) | | | | |
2021 VS. 2020 Net Incomeincome attributable to Dominion Energy decreased 45%,increased $3.7 billion, primarily due to the absence of: charges for refundsassociated with the cancellation of amounts previously collected from retail electric customersthe Atlantic Coast Pipeline Project and related portions of DESC for the NNDSupply Header Project litigation acquiredwhich are presented in the SCANA Combination, a voluntary retirement program,discontinued operations, the planned early retirementretirements of certain electric generation facilities in Virginia, Power electrican impairment of interests in certain nonregulated solar generation facilities and the absencetermination of gains ona contract in connection with the salessale of certain equity method investments. These decreases were partially offset byFowler Ridge. In addition, there was an increase in net investment earnings on nuclear decommissioning trust funds, and the operations acquireda decrease in the SCANA Combination. Net income attributable to Dominion Energy decreased 18%, primarily due to the absence of benefits in 2017 resulting from the remeasurement of deferred income taxes to the new corporate income tax rate, an impairment charge on certain gathering and processing assets, a chargecharges associated with Virginia legislation enacted in March 2018, decreased net investment earnings on nuclear decommissioning trust funds, lower renewable energy investment tax creditsPower’s 2021 Triennial Review and a charge for disallowancegain on the sale of FERC-regulated plant.the Q-Pipe Group to Southwest Gas. These decreasesincreases were
partially offset by gainscharges associated with the settlement of the South Carolina electric base rate case, increased unrealized losses on economic hedging activities and a net loss on the sales of certain merchant generation facilities and equity method investments, the commencement of commercial operations of the Liquefaction Facility and the absence of charges associated with equity method investments in wind-powered generationnon-wholly-owned nonregulated solar facilities. Analysis of Consolidated Operations Presented below are selected amounts related to Dominion Energy’s results of operations: Year Ended December 31, | | 2021 | | | $ Change | | | 2020 | | | $ Change | | | 2019 | | (millions) | | | | | | | | | | | | | | | | | | | | | Operating revenue | | $ | 13,964 | | | $ | (208 | ) | | $ | 14,172 | | | $ | (229 | ) | | $ | 14,401 | | Electric fuel and other energy-related purchases | | | 2,368 | | | | 125 | | | | 2,243 | | | | (642 | ) | | | 2,885 | | Purchased electric capacity | | | 70 | | | | 17 | | | | 53 | | | | (35 | ) | | | 88 | | Purchased gas | | | 1,083 | | | | 194 | | | | 889 | | | | (671 | ) | | | 1,560 | | Other operations and maintenance | | | 3,734 | | | | 49 | | | | 3,685 | | | | (105 | ) | | | 3,790 | | Depreciation, depletion and amortization | | | 2,478 | | | | 146 | | | | 2,332 | | | | 49 | | | | 2,283 | | Other taxes | | | 909 | | | | 38 | | | | 871 | | | | (12 | ) | | | 883 | | Impairment of assets and other charges | | | 195 | | | | (1,910 | ) | | | 2,105 | | | | 585 | | | | 1,520 | | Loss (gain) on sales of assets | | | 108 | | | | 169 | | | | (61 | ) | | | 91 | | | | (152 | ) | Earnings from equity method investees | | | 276 | | | | 236 | | | | 40 | | | | 32 | | | | 8 | | Other income | | | 1,157 | | | | 464 | | | | 693 | | | | (110 | ) | | | 803 | | Interest and related charges | | | 1,354 | | | | (23 | ) | | | 1,377 | | | | (109 | ) | | | 1,486 | | Income tax expense | | | 425 | | | | 342 | | | | 83 | | | | (126 | ) | | | 209 | | Net income (loss) from discontinued operations including noncontrolling interests | | | 641 | | | | 2,519 | | | | (1,878 | ) | | | (2,594 | ) | | | 716 | | Noncontrolling interests | | | 26 | | | | 175 | | | | (149 | ) | | | (167 | ) | | | 18 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | $ | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | Electric fuel and other energy-related purchases | | | | | | | | | | | | | | | | | | | | | Purchased electric capacity | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | Other operations and maintenance | | | | | | | | | | | | | | | | | | | | | Depreciation, depletion and amortization | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Impairment of assets and related charges | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | ) | | | | ) | | | | ) | | | | | | | | | ) | | | | | | | | | | | | | Interest and related charges | | | | | | | | | | | | | | | | | | | | | Income tax expense (benefit) | | | | | | | | ) | | | | | | | | | | | | ) | | | | | | | | | ) | | | | | | | | ) | | | | |
An analysis of Dominion Energy’s results of operations follows: Net2021 VS. 2020 Operating revenue increased 23%decreased 1%, primarily reflecting:• | A $402 million decrease associated with market prices affecting Millstone, including economic hedging impacts of net realized and unrealized losses on freestanding derivatives ($495 million); |
A $1.5 billion increase from the SCANA Combination,• | A $356 million decrease for refunds to be provided to retail electric customers in Virginia associated with the settlement of the 2021 Triennial Review; |
• | A $151 million decrease from an unbilled revenue reduction at Virginia Power; |
• | A $80 million decrease as a result of the contribution of certain nonregulated natural gas retail energy contracts to Wrangler; |
• | A $62 million decrease associated with settlements of economic hedges of certain Virginia Power regulated electric sales; and |
• | A $51 million decrease in PJM off-system sales. |
These decreases were partially offset by: • | A $390 million increase in the fuel cost component included in utility rates as a result of an increase in commodity costs associated with sales to gas utility customers ($239 million) and electric utility retail customers ($151 million); |
• | A $117 million increase from gas utility capital cost riders; |
• | A $75 million increase in sales to electric utility retail customers associated with growth; |
• | A $62 million increase in sales to electric utility customers associated with economic and other usage factors; |
• | A $52 million increase from the absence of planned outages at Millstone; |
• | A $51 million increase in sales to electric utility retail customers from an increase in heating degree days during the heating season ($71 million) partially offset by a decrease in cooling degree days during the cooling season ($20 million); |
• | A $26 million increase in sales to customers from non-jurisdictional solar generation facilities; and |
• | A $22 million increase in sales to gas utility customers associated with growth. |
Electric fuel and other energy-related purchases increased 6%, primarily due to operations acquiredhigher commodity costs for electric utilities ($2.5 billion)151 million), partially offset by a $1.0 billion charge for refunds of amounts previously collected from retail electric customers of DESC for the NND Project; A $348 million increase from Virginia Power rate adjustment clauses;
A $257 million increase from the Liquefaction Facility, including terminalling services provided to the Export Customers ($190 million), a decrease in credits associated with thestart-up
phasePJM off-system sales ($ 4451 million) , which are offset in operating revenue and regulated gas transportation contracts to serve the Export Customers ($23 million);The absence of a $215 million charge associated with Virginia legislation enacted in March 2018 that requiredone-time
rate credits of certain amounts to utility customers;A $74 million decrease in Virginia Powerdo not impact net income.Purchased electric capacityincreased 32%, primarily due to an increase in expense related to the annual PJM capacity performance market effective June 20192021 ($6324 million) and a contract termination with anon-utility
generator ($37 million), partially offset byan increase in expense related to the annual PJM capacity performance market effective June 20182020 ($2617 million); A $57 million increase due to favorable pricing at Millstone, including the effects of the Millstone 2019 power purchase agreements; and
A $40 million decrease in Virginia Power fuel costs due to the expiration of an energy supply contract.
These increases were partially offset by:
A $211 million decrease from the absence of certain merchant generation facilities sold in 2018;
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
A $99 million decrease in services performed for Atlantic Coast Pipeline; and
A $45 million decrease in sales to Virginia Power retail customers from lower heating degree days during the heating season,, partially offset by a $25 million increase from higher cooling degree days during the cooling season.
Otherdecrease in expense associated with DESC’s electric utility operations and maintenance
Purchased gasincreased 28%22%, primarily reflecting: A $735 million increase from operations acquired in the SCANA Combination;
Andue to an increase in merger and integration-relatedcommodity costs associated with the SCANA Combination ($474 million), including a charge related to a voluntary retirement program ($291 million);
A $116 million increasefor gas utilities, which are offset in certain Virginia Power transmission and generation-related expenditures. These expenses are primarily recovered through state and FERC ratesoperating revenue and do not impact net income;income.Other operations and maintenance increased 1%, primarily reflecting: • | A $117 million increase in salaries, wages and benefits, including $28 million of costs for employer-provided healthcare; |
• | A $44 million charge related to a revision in estimated recovery of spent nuclear fuel costs associated with the decommissioning of Kewaunee; and |
• | A $32 million increase in storm damage and restoration costs in Virginia Power’s service territory; partially offset by |
A $38 million increase in operating expenses from the commercial operations of the Liquefaction Facility and costs associated with regulated gas transportation contracts to serve the Export Customers.• | A $58 million decrease in merger and integration-related costs associated with the SCANA Combination; |
• | A $44 million decrease in certain Virginia Power expenditures which are primarily recovered through state- and FERC-regulated rates and do not impact net income; and |
• | A $26 million net decrease in outage costs as a result of a decrease in Millstone outage costs ($45 million) partially offset by an increase in Virginia Power outage costs ($19 million). |
These increases were partially offset by:
A $113 million benefit from the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019;
A $99 million decrease in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income;
The absence of an $81 million charge associated primarily with future ash pond and landfill closure costs in connection with the enactment of Virginia legislation in April 2018; and
A $43 million decrease from the absence of certain merchant generation facilities sold in 2018.
Depreciation, depletion and amortization 33%6%, primarily due to property, plant and equipment acquired in the SCANA Combination ($559 million), including amortization of NND Project costs ($127 million), an increase from various growth projects being placed into service ($134132 million) and an increase for amortization from the establishment of a regulatory asset associated with the 2021 Triennial Review ($61 million), includingpartially offset by a decrease due to the Liquefaction Facilityimpairment of certain nonregulated solar generation facilities in 2020 ($2820 million).Impairment of assets and other charges decreased 91%, primarily reflecting: • | The absence of a charge associated with the planned early retirements of certain electric generation facilities in Virginia ($747 million); |
• | The absence of a charge associated with certain nonregulated solar generation facilities ($665 million); |
• | A benefit from the establishment of a regulatory asset associated with the early retirements of certain coal- and oil-fired generating units associated with the settlement of the 2021 Triennial Review ($549 million); |
• | The absence of a contract termination charge in connection with the sale of Fowler Ridge ($221 million); |
• | The absence of a charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to legislation enacted in November 2020 ($127 million); and |
• | The absence of dismantling costs associated with certain Virginia Power electric generation facilities ($54 million); partially offset by |
• | Charges associated with the settlement of the South Carolina electric base rate case ($249 million); |
• | A charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to Virginia’s 2021 budget process ($77 million); |
• | A charge for corporate office lease termination ($62 million); |
• | An increase in charges for CCRO benefits provided to retail electric customers in Virginia associated with Virginia Power’s 2021 Triennial Review ($58 million); and |
• | A charge for the write-off of nonregulated retail software development assets ($20 million). |
Loss on sales of assets increased $169 million, primarily due to a net loss on the sales of non-wholly-owned nonregulated solar facilities ($211 million) partially offset by an increase in gains on the sale of nonregulated retail energy marketing assets ($23 million). Earnings from equity method investees increased $236 million, primarily due to accounting for Cove Point as an equity method investment for a full year following the closing of the GT&S Transaction in November 2020. Other income increased 67%, primarily due to an increase in net investment gains on nuclear decommissioning trust funds ($237 million), the absence of a benefitcharge for the retroactive application of depreciation rates for regulated nuclear plants to comply with Virginia Commission requirementssocial justice commitments ($31 million), partially offset by the planned early retirement of certain Virginia Power electric generation facilities and automated meter reading infrastructure ($40 million) and the sale of certain merchant electric generation facilities in 2018 ($37 million). increased 48%, primarily due to the SCANA Combination ($25880 million), an increase in property taxnon-service components of pension and other postretirement employee benefit plan credits ($77 million), the absence of charges for growth projects placed into service ($56 million) and a charge related to a voluntary retirement program ($24 million).Impairment of assets and related charges
increased $1.1 billion, primarily due to:Charges associated with litigation acquired in the SCANA Combination ($64125 million);
A $346 million charge related to the early retirement of certain Virginia Power electric generation facilities;
A $160 million charge related to Virginia Power’s planned early retirement of certain automated meter reading infrastructure;
A $135 million charge related to Virginia Power’s contract termination and an increase in AFUDC associated with anon-utility
generator;A $105 million charge for property, plant and equipment acquired in the SCANA Combination for which Dominion Energy committed to forgo recovery;
A $62 million charge related to the abandonment of a project at a Virginia Power electric generating facility; and
The abandonment of certain property, plant and equipmentrate-regulated projects ($3925 million);, partially offset by
The absence of a $219 impairment charge on certain gathering and processing assets;
The absence of a $135 million charge for disallowance of FERC-regulated plant; and
The absence of a $37 millionwrite-off
charges associated with the Eastern Market Access Project.Gains on salessettlement of assets
Interest and related chargesdecreased 57%2%, primarily due to the absence of the sale of Fairless and Manchesterborrowings in response to COVID-19 in 2020 ($21042 million) and the absence of gains related to agreements to convey shale development rights under natural gas storage fields ($115 million), partially offset by an increase in gains on sales of nonregulated retail energy marketing assets ($82 million). decreased 3%, primarily reflecting the absence of a gain on, and equity earnings from, the sale of Dominion Energy’s 50% limited partnership interest in Blue Racer ($603 million), a charge related to a voluntary retirement program ($112 million) and the absence of a gain on the sale of Dominion Energy’s 25% limited partnership interest in Catalyst Old River Hydroelectric Limited Partnership ($87 million). These decreases were partially offset by an increase in net investment earnings on nuclear decommissioning trust funds ($720 million) and an increase in equity earnings from Atlantic Coast Pipeline ($50 million).Interest and related charges
increased 19%, primarily due to debt acquired in the SCANA Combination net of debt redeemed in 2019 ($314 million), the absence of capitalization of interest expense associated with the Liquefaction Facility upon completion of construction ($46 million), partially offset by the absence of charges associated with the early redemption of certain debt securities in 2018the first quarter of 2020 ($ 6931 million) and a benefit associated with the effective settlement of uncertain tax positions ($21 million), partially offset by decreased carrying costs associated with the recovery of CEP beginning January 2021 ($29 million), charges associated with the early redemption of certain securities in the third quarter of 2021 ($23 million) and lower unrealized gains in 2021 associated with freestanding derivatives ($13 million). decreased 39% increased $342 million, primarily due to lowerhigher pre-tax income ($299365 million), lower investment tax credits ($38 million), the impactsabsence of prior year benefits including reductions in consolidated state deferred income taxes associated with gas transmission and storage operations ($45 million) and adjustments finalizing the effects of changes in tax status of certain subsidiaries in connection with the Dominion Energy Gas Restructuring ($4824 million). These increases are partially offset by a benefit associated with the effective settlement of uncertain tax positions ($38 million), higher investment tax creditsthe benefit of a state legislative change ($3921 million) and the absence of 2017 Tax Reform Act impacts ($46 million), partially offset by a charge for certain incometax-related
regulatoryprior year expense primarily associated with the impairment of nonregulated solar generating assets acquiredheld in the SCANA Combination for which Dominion Energy committed to forgo recovery ($194 million) and the absence of a state legislative change ($20 million).decreased 82%, primarily duepartnerships attributable to the acquisition of the publicnoncontrolling interest in Dominion Energy Midstream in January 2019.
($55 million).Net revenue 2%, primarily reflecting:A $500 million increase due to commencement of commercial operations of the Liquefaction Facility, including terminalling services provided to the Export Customers ($508 million) and regulated gas transportation contracts to serve the Export Customers ($58 million), partially offset by credits associated with thestart-up
phase of the Liquefaction Facility ($66 million);An increase in sales to electric utility retail customers from an increase in heating degree days during the heating season of 2018 ($71 million) and an increase in cooling degree days during the cooling season of 2018 ($69 million);
A $130 million increase due to favorable pricing at merchant generation facilities;
A $92 million increase due to growth projects placed in service, other than the Liquefaction Facility;
A $74 million increase in services performed for Atlantic Coast Pipeline; and
A $46 million increase in sales to electric utility retail customers due to customer growth.
These increases were partially offset by:
A $325 million decrease for regulated electric generation and electric and gas distribution operations as a result of the 2017 Tax Reform Act;
A $215 million charge associated with Virginia legislation enacted in March 2018 that requiresone-time
rate credits of certain amounts to utility customers;A $94 million increase in net electric capacity 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-utility
generators ($57 million);An $89 million decrease in rate adjustment clauses associated with electric utility operations, which includes the impacts of the 2017 Tax Reform Act; and
A $38 million decrease from scheduled declines in or expiration of certain DETI and Cove Point contracts.
Net revenue does not reflect an impact from a reduction in planned outage days at Millstone as there was an offsetting increase in unplanned outage days.
Other operations and maintenance
increased 8%, primarily reflecting:A $102 million increase in storm damage and service restoration costs in the regulated electric service territory;
An $81 million increase due to a charge associated primarily with future ash pond and landfill closure costs in connection with the enactment of Virginia legislation in April 2018;
A $73 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income;
A $47 million increase in operating expenses from the commercial operations of the Liquefaction Facility and costs associated with regulated gas transportation contracts to serve the Export Customers; and
A $38 million increase in salaries, wages and benefits, partially offset by
A $74 million decrease from a reduction in planned outage days at certain merchant and utility generation facilities.
Depreciation, depletion and amortization
increased 5%, primarily due to an increase from various growth projects being placed into service ($187 million), including the Liquefaction Facility ($81 million), partially offset by revised depreciation rates for regulated nuclear plants to comply with the Virginia Commission requirements ($61 million).Impairment of assets and related charges
increased $388 million,$2.5 billion, primarily due to a $219 million impairment charge on certain gathering and processing assets, a $135 million charge for disallowance of FERC-regulated plant and a $37 millionwrite-off
decrease in charges associated with the Eastern Market Access Project.Gains on salesAtlantic Coast Pipeline Project and related portions of assets
increased $233 million, primarily due to the sale of FairlessSupply Header Project ($2.1 billion) and Manchester ($210 million) and an increase in gains related to agreements to convey shale development rights under natural gas storage fields ($46 million).increased $663 million, primarily reflecting a gain on the sale of Dominion Energy’s 50% limited partnership interest in Blue RacerQ-Pipe ($ 546 million), the absence of charges associated with equity method investments in wind-powered generation facilities ($158 million), a gain on the sale of Dominion Energy’s 25% limited partnership interest in Catalyst Old River Hydroelectric Limited Partnership ($87 million) and a decrease in thenon-service
components of pension and other postretirement employee benefit credits capitalized to property, plant and equipment in 2018 ($45 million), partially offset by a decrease in net investment earnings on nuclear decommissioning trust funds ($209 million).Interest and related charges
increased 24%, primarily due to the absence of capitalization of interest expense associated with the Liquefaction Facility upon completion of construction ($111 million), higher long-term debt interest expense resulting from net debt issuances in 2018 and 2017 ($92 million) and charges associated with the early redemption of certain debt securities ($69 million).increased $610 million, primarily due to the absence of benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate ($851 million) and lower renewable energy investment tax credits ($138493 million), partially offset by the reduced corporate income tax rateabsence of operations sold in the GT&S Transaction ($ 41456 million). Noncontrolling interests increased $175 million, primarily due to the absence of impairments associated with certain nonregulated solar generation facilities ($267 million) partially offset by the closing of the GT&S Transaction in November 2020 ($106 million). Outlook Dominion Energy’s 20202022 net income is expected to increase on a per share basis as compared to 20192021 primarily from the following: The absence of charges for refunds of amounts previously collected from retail electric customers of DESC for the NND Project;
The absence of charges associated with the early retirement of certain Virginia Power electric generation facilities and automated meter reading infrastructure;
A reduction in merger and integration-related costs associated with the SCANA Combination, including charges related to a voluntary retirement program;
• | The absence of charges associated with Virginia Power’s 2021 Triennial Review; |
• | The absence of charges associated with the settlement of the South Carolina electric base rate case; |
• | The absence of a net loss on the sales of certain non-wholly-owned nonregulated solar facilities; |
• | The absence of charges associated with litigation acquired in the SCANA Combination; and |
• | Construction and operation of growth projects in electric utility and gas distribution operations. |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
A decrease in charges associated with litigation acquired in the SCANA Combination;
Construction and operation of growth projects in gas transmission and distribution;
Construction and operation of growth projects in electric utility operations;
Lower depreciation on Virginia Power’s nuclear plants associated with expected approval of license extensions from the NRC;
Reduced interest expense as a result of early redemptions of long-term debt; and
Delivery under the Millstone 2019 power purchase agreements for an entire year.
These increases are expected to be partially offset by the following: • | The absence of operations of the Q-Pipe Group sold to Southwest Gas and associated gain on sale; |
The absence of a benefit for the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019;• | The absence of a benefit from the establishment of a regulatory asset associated with the early retirements of certain coal- and oil-fired generating units associated with the 2021 Triennial Review and an increase from a full year of amortization of this regulatory asset; and |
The noncontrolling 25% limited partnership interest in Cove Point sold in December 2019;
An increase in planned outage days at Millstone; and
Share dilution.
Segment Results Of Operations
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, | | 2021 | | | 2020 | | | 2019 | | | | Net income (loss) attributable to Dominion Energy | | | Diluted EPS | | | Net income (loss) attributable to Dominion Energy | | | Diluted EPS | | | Net income (loss) attributable to Dominion Energy | | | Diluted EPS | | (millions, except EPS) | | | | | | | | | | | | | | | | | | | | | | | | | Dominion Energy Virginia | | $ | 1,919 | | | $ | 2.37 | | | $ | 1,891 | | | $ | 2.28 | | | $ | 1,786 | | | $ | 2.21 | | Gas Distribution | | | 600 | | | | 0.74 | | | | 560 | | | | 0.67 | | | | 487 | | | | 0.60 | | Dominion Energy South Carolina | | | 437 | | | | 0.54 | | | | 419 | | | | 0.51 | | | | 430 | | | | 0.53 | | Contracted Assets | | | 431 | | | | 0.53 | | | | 402 | | | | 0.48 | | | | 460 | | | | 0.57 | | Corporate and Other | | | (99 | ) | | | (0.20 | ) | | | (3,673 | ) | | | (4.51 | ) | | | (1,805 | ) | | | (2.29 | ) | Consolidated | | $ | 3,288 | | | $ | 3.98 | | | $ | (401 | ) | | $ | (0.57 | ) | | $ | 1,358 | | | $ | 1.62 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | income
(loss)
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Energy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Gas Transmission & Storage | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dominion Energy South Carolina | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Presented below are operating statistics related to Dominion Energy Virginia’s operations: Year Ended December 31, | | 2021 | | | % Change | | | 2020 | | | % Change | | | 2019 | | Electricity delivered (million MWh) | | | 85.2 | | | | 2 | | % | | 83.3 | | | | (5 | ) | % | | 87.7 | | Electricity supplied (million MWh): | | | | | | | | | | | | | | | | | | | | | Utility | | | 85.7 | | | | (1 | ) | | | 87.0 | | | | (1 | ) | | | 88.2 | | Non-Jurisdictional | | | 1.0 | | | | 43 | | | | 0.7 | | | | 75 | | | | 0.4 | | Degree days (electric distribution and utility service area): | | | | | | | | | | | | | | | | | | | | | Cooling | | | 1,783 | | | | 1 | | | | 1,759 | | | | (13 | ) | | | 2,031 | | Heating | | | 3,210 | | | | 8 | | | | 2,970 | | | | (9 | ) | | | 3,259 | | Average electric distribution customer accounts (thousands) | | | 2,697 | | | | 1 | | | | 2,661 | | | | 1 | | | | 2,626 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Electricity delivered (million MWh) | | | | | | | | % | | | | | | | | % | | | | | Electricity supplied (million MWh): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Degree days (electric distribution and utility service area): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | Average electric distribution customer accounts (thousands) | | | | | | | | | | | | | | | | | | | | |
Presented below, on an after-tax basis, are the key factors impacting Dominion Energy Virginia’s net income contribution: 2021 VS. 2020 | | Increase (Decrease) | | | | Amount | | | EPS | | (millions, except EPS) | | | | | | | | | Regulated electric sales: | | | | | | | | | Weather | | $ | 44 | | | $ | 0.05 | | Other | | | 20 | | | | 0.02 | | Rider equity return | | | 41 | | | | 0.05 | | Electric capacity | | | (28 | ) | | | (0.03 | ) | Outages | | | (14 | ) | | | (0.02 | ) | Depreciation and amortization | | | (18 | ) | | | (0.02 | ) | Renewable energy investment tax credits | | | 7 | | | | 0.01 | | Salaries, wages and benefits & administrative costs | | | (22 | ) | | | (0.03 | ) | Other | | | (2 | ) | | | — | | Share accretion | | | — | | | | 0.06 | | Change in net income contribution | | $ | 28 | | | $ | 0.09 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Regulated electric sales: | | | | | | | | | | | | | ) | | $ | | ) | | | | | | | | | | Rate adjustment clause equity return | | | | | | | | | | | | | | | | | | Expiration of energy supply contract | | | | | | | | | Renewable energy investment tax credits | | | | ) | | | | ) | | | | | | | | | | | | | | | | | | ) | Change in net income contribution | | | | | | $ | | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Regulated electric sales: | | | | | | | | | | | | | | | $ | | | | | | | | | | | | Rate adjustment clause equity return | | | | | | | | | Depreciation and amortization | | | | | | | | | Storm damage and service restoration | | | | ) | | | | ) | | | | | | | | | | | | | | ) | | | | ) | Renewable energy investment tax credits | | | | | | | | | | | | | ) | | | | ) | | | | | | | | | ) | Change in net income contribution | | | | | | $ | | |
Gas Transmission & Storage
Presented below are operating statistics related to Gas Transmission & Storage’s operations:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Average retail energy marketing customer accounts (thousands) | | | | | | | | % | | | | | | | | )% | | | | |
(1) | Includes SEMI effective January 2019 until December 2019. |
Presented below, on anafter-tax
basis, are the key factors impacting Gas Transmission & Storage’s net income contribution:| | | | | | | | | | | | | | | | | | | | | | | | | | | | Cove Point export contracts | | | | | | | | | Assignment of shale development rights | | | | ) | | | | ) | | | | | ) | | | | ) | | | | | ) | | | | ) | | | | | | | | | | Atlantic Coast Pipeline equity earnings | | | | | | | | | | | | | ) | | | | ) | | | | | | | | | ) | Change in net income contribution | | | | | | | | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | Transmission and storage growth projects | | | | | | $ | | | Cove Point export contracts | | | | | | | | | Cove Point import contracts | | | | ) | | | | ) | | | | | ) | | | | ) | Assignment of shale development rights | | | | | | | | | 2017 Tax Reform Act impacts | | | | | | | | | | | | | ) | | | | ) | | | | | | | | | | | | | | ) | | | | ) | | | | | | | | | ) | Change in net income contribution | | | | | | | | |
Presented below are selected operating statistics related to Gas Distribution’s operations: Year Ended December 31, | | 2021 | | | % Change | | | 2020 | | | % Change | | | 2019 | | Gas distribution throughput (bcf): | | | | | | | | | | | | | | | | | | | | | Sales | | | 183 | | | | 2 | | % | | 180 | | | | (6 | ) | % | | 192 | | Transportation | | | 975 | | | | 12 | | | | 868 | | | | 7 | | | | 811 | | Heating degree days (gas distribution service area): | | | | | | | | | | | | | | | | | | | | | North Carolina | | | 2,947 | | | | 8 | | | | 2,734 | | | | (7 | ) | | | 2,942 | | Ohio and West Virginia | | | 5,121 | | | | (1 | ) | | | 5,148 | | | | (4 | ) | | | 5,355 | | Utah, Wyoming, and Idaho | | | 4,874 | | | | (2 | ) | | | 4,973 | | | | (10 | ) | | | 5,501 | | Average gas distribution customer accounts (thousands): | | | | | | | | | | | | | | | | | | | | | Sales | | | 1,935 | | | | 2 | | | | 1,897 | | | | 2 | | | | 1,857 | | Transportation | | | 1,131 | | | | 1 | | | | 1,123 | | | | 1 | | | | 1,108 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Gas distribution throughput (bcf): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | % | | | | | | | | % | | | | | | | | | | | | | | | | | | | | | | | | | | Heating degree days (gas distribution service area): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | Average gas distribution customer accounts (thousands): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(1) | Includes PSNC effective January 1, 2019. |
Presented below, on an after-tax basis, are the key factors impacting Gas Distribution’s net income contribution: 20192021 VS. 20182020 | | Increase (Decrease) | | | | Amount | | | EPS | | (millions, except EPS) | | | | | | | | | Regulated gas sales: | | | | | | | | | Weather | | $ | — | | | $ | — | | Other | | | 31 | | | | 0.04 | | Rider equity return | | | 40 | | | | 0.05 | | Salaries, wages and benefits & administrative costs | | | (8 | ) | | | (0.01 | ) | Interest expense, net | | | 12 | | | | 0.01 | | Other | | | (35 | ) | | | (0.04 | ) | Share accretion | | | — | | | | 0.02 | | Change in net income contribution | | $ | 40 | | | $ | 0.07 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | ) | | $ | | | | | | | ) | | | | | Rate adjustment clause equity return | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | Change in net income contribution | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | | | | | | | | | Rate adjustment clause equity return | | | | | | | | | 2017 Tax Reform Act impacts | | | | | | | | | | | | | ) | | | | | | | | | ) | | | | ) | | | | | | | | | ) | Change in net income contribution | | | | | | | | |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Dominion Energy South Carolina Presented below are selected operating statistics related to Dominion Energy South Carolina’s operations: | | | | | | | | | | Electricity delivered (million MWh)
| | | | | Electricity supplied (million MWh)
| | | | | Degree days (electric and gas distribution service areas):
| | | | | | | | | | | | | | | Average electric distribution customer accounts (thousands)
| | | | | Gas distribution throughput (bcf):
| | | | | | | | | | Average gas distribution customer accounts (thousands)
| | | | |
Year Ended December 31, | | 2021 | | | % Change | | | 2020 | | | % Change | | | 2019 | | Electricity delivered (million MWh) | | | 22.4 | | | | 1 | | % | | 22.1 | | | | (4 | ) | % | | 23.0 | | Electricity supplied (million MWh) | | | 23.5 | | | | 2 | | | | 23.0 | | | | (5 | ) | | | 24.1 | | Degree days (electric and gas distribution service areas): | | | | | | | | | | | | | | | | | | | | | Cooling | | | 859 | | | | 8 | | | | 794 | | | | (17 | ) | | | 951 | | Heating | | | 1,280 | | | | 19 | | | | 1,074 | | | | (9 | ) | | | 1,179 | | Average electric distribution customer accounts (thousands) | | | 766 | | | | 2 | | | | 753 | | | | 2 | | | | 739 | | Gas distribution throughput (bcf): | | | | | | | | | | | | | | | | | | | | | Sales | | | 72 | | | | 9 | | | | 66 | | | | 2 | | | | 65 | | Average gas distribution customer accounts (thousands) | | | 412 | | | | 3 | | | | 399 | | | | 3 | | | | 386 | |
Presented below, on an after-tax basis, are the key factors impacting Dominion Energy South Carolina’s net income contribution: 2021 VS. 2020 | | Increase (Decrease) | | | | Amount | | | EPS | | (millions, except EPS) | | | | | | | | | Regulated electric sales: | | | | | | | | | Weather | | $ | (6 | ) | | $ | (0.01 | ) | Other | | | 48 | | | | 0.06 | | Regulated gas sales | | | 9 | | | | 0.01 | | Capital cost rider | | | (6 | ) | | | (0.01 | ) | Depreciation and amortization | | | (9 | ) | | | (0.01 | ) | Interest expense, net | | | 7 | | | | 0.01 | | Salaries, wages and benefits & administrative costs | | | (46 | ) | | | (0.06 | ) | Other | | | 21 | | | | 0.02 | | Share accretion | | | — | | | | 0.02 | | Change in net income contribution | | $ | 18 | | | $ | 0.03 | |
AssetsPresented below are selected operating statistics related to Contracted Generation’sAsset’s operations: Year Ended December 31, | | 2021 | | | % Change | | | 2020 | | | % Change | | | 2019 | | Electricity supplied (million MWh) | | | 20.8 | | | | 8 | | % | | 19.3 | | | | (4 | ) | % | | 20.2 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Electricity supplied (million MWh) | | | | | | | | )% | | | | | | | | % | | | | |
Presented below, on an after-tax basis, are the key factors impacting Contracted Generation’sAsset’s net income contribution: 2021 VS. 2020 | | Increase (Decrease) | | | | Amount | | | EPS | | (millions, except EPS) | | | | | | | | | Margin(1) | | $ | 28 | | | $ | 0.03 | | Planned outage costs | | | 33 | | | | 0.04 | | Renewable energy investment tax credits | | | (43 | ) | | | (0.05 | ) | Absence of contract associated with Fowler Ridge | | | 14 | | | | 0.02 | | Other | | | (3 | ) | | | (0.00 | ) | Share accretion | | | — | | | | 0.01 | | Change in net income contribution | | $ | 29 | | | $ | 0.05 | |
2019 VS. 2018(1) | Includes earnings associated with a 50% noncontrolling interest in Cove Point. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | Renewable energy investment tax credits | | | | | | | | | Sale of certain electric generation facilities | | | | ) | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | Change in net income contribution | | | | | | $ | | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Depreciation and amortization | | | | ) | | | | ) | Renewable energy investment tax credits | | | | ) | | | | ) | 2017 Tax Reform Act impacts | | | | | | | | | | | | | ) | | | | ) | | | | | | | | | ) | Change in net income contribution | | | | ) | | | | ) |
Presented below are the Corporate and Other segment’s after-tax results: after-taxYear Ended December 31, | | 2021 | | | 2020 | | | 2019 | | (millions, except EPS) | | | | | | | | | | | | | Specific items attributable to operating segments | | $ | (493 | ) | | $ | (1,241 | ) | | $ | (1,901 | ) | Specific items attributable to Corporate and Other segment | | | 590 | | | | (2,166 | ) | | | 384 | | Total specific items | | | 97 | | | | (3,407 | ) | | | (1,517 | ) | Other corporate operations: | | | | | | | | | | | | | Interest expense, net | | | (410 | ) | | | (384 | ) | | | (383 | ) | Other | | | 214 | | | | 118 | | | | 95 | | Total other corporate operations | | | (196 | ) | | | (266 | ) | | | (288 | ) | Total net expense | | | (99 | ) | | | (3,673 | ) | | | (1,805 | ) | EPS impact | | $ | (0.20 | ) | | $ | (4.51 | ) | | $ | (2.29 | ) |
results:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Specific items attributable to operating segments | | $ | | ) | | $ | | ) | | $ | | | Specific items attributable to Corporate and Other segment | | | | ) | | | | ) | | | | ) | | | | | ) | | | | ) | | | | | Other corporate operations: | | | | | | | | | | | | | 2017 Tax Reform Act impacts | | | | | | | | ) | | | | | | | | | ) | | | | ) | | | | ) | | | | | ) | | | | | | | | | Total other corporate operations | | | | ) | | | | ) | | | | ) | Total net income (expense) | | | | ) | | | | ) | | | | | | | $ | | ) | | $ | | ) | | $ | | |
TOTAL SPECIFIC ITEMS Corporate and Other includes specific items attributable to Dominion Energy’s primary operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources. See Note 26 to the Consolidated Financial Statements for discussion of these items in more detail. Corporate and Other also includes specific items attributable to the Corporate and Other segment. In 2021, this primarily included $641 million net income from discontinued operations, primarily associated with the Q-Pipe Group, a $64 million after-tax benefit for derivative mark-to-market changes, $62 million of after-tax charges for workplace realignment, primarily related to a corporate office lease termination and $32 million of after-tax charges for merger and integration-related costs associated with the SCANA Combination. In 2020, this primarily included $2.2 billion of after-tax loss associated with discontinued operations, including the results of operations of the entities included in the GT&S and Q-Pipe Transactions as well as charges associated with the cancellation of the Atlantic Coast Pipeline Project, $82 million of after-tax charges for merger and integration-related costs associated with the SCANA Combination, a $78 million after-tax benefit of derivative mark-to-market changes and a $69 million tax benefit associated with the GT&S Transaction. In 2019, this primarily included $40$521 million of after-tax earnings for the results of operations of the entities included in the GT&S and Q-Pipe Transactions and $135 million of after-tax transaction and transition costs associated with the SCANA Combination. In 2018, this primarily included $51 millionVIRGINIA POWER Results of after-tax
charges associated with the early redemption of certain debt securities and $31 million ofafter-tax
transaction and transition costs associated with the Dominion Energy Questar Combination and SCANA Combination. In 2017, this primarily included $124 million of tax benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate.Presented below is a summary of Virginia Power’s consolidated results: Year Ended December 31, | | 2021 | | | $ Change | | | 2020 | | | $ Change | | | 2019 | | (millions) | | | | | | | | | | | | | | | | | | | | | Net income | | $ | 1,712 | | | $ | 691 | | | $ | 1,021 | | | $ | (128 | ) | | $ | 1,149 | |
2020Net income decreased 10%increased 68%, primarily due to the absence of charges associated withrelated to the planned early retirementretirements of certain electric generation facilities and automated meter reading infrastructure, a voluntary retirement program and a contract termination with anon-utility
generator. These decreases were partially offset by increases related to higher rate adjustment clause equity returns, the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacteddecrease in March 2019 and the absence of charges associated with Virginia legislation enacted in March 2018 and April 2018.
Net income decreased 17%, primarily due to a charge associated with Virginia legislation enacted in March 2018, an increase in storm damage and service restoration costs, a charge associated primarily with future ash pond and landfill closure costs in connection with the enactment of Virginia legislation in April 2018 and an increase in net electric capacity expense, partially offset by an increase in heating and cooling degree days in the service territory.
2021 Triennial Review.Analysis of Consolidated Operations Presented below are selected amounts related to Virginia Power’s results of operations: Year Ended December 31, | | 2021 | | | $ Change | | | 2020 | | | $ Change | | | 2019 | | (millions) | | | | | | | | | | | | | | | | | | | | | Operating revenue | | $ | 7,470 | | | $ | (293 | ) | | $ | 7,763 | | | $ | (345 | ) | | $ | 8,108 | | Electric fuel and other energy-related purchases | | | 1,735 | | | | 99 | | | | 1,636 | | | | (542 | ) | | | 2,178 | | Purchased (excess) electric capacity | | | 24 | | | | 41 | | | | (17 | ) | | | (57 | ) | | | 40 | | Other operations and maintenance | | | 1,793 | | | | 7 | | | | 1,786 | | | | 43 | | | | 1,743 | | Depreciation and amortization | | | 1,364 | | | | 112 | | | | 1,252 | | | | 29 | | | | 1,223 | | Other taxes | | | 326 | | | | (1 | ) | | | 327 | | | | (1 | ) | | | 328 | | Impairment of assets and other charges (benefits) | | | (269 | ) | | | (1,362 | ) | | | 1,093 | | | | 336 | | | | 757 | | Other income | | | 146 | | | | 66 | | | | 80 | | | | (18 | ) | | | 98 | | Interest and related charges | | | 534 | | | | 18 | | | | 516 | | | | (8 | ) | | | 524 | | Income tax expense | | | 397 | | | | 168 | | | | 229 | | | | (35 | ) | | | 264 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | $ | | | | | | | | $ | | | Electric fuel and other energy-related purchases | | | | | | | | ) | | | | | | | | | | | | | Purchased electric capacity | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | Other operations and maintenance | | | | | | | | | | | | | | | | | | | | | Depreciation and amortization | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | Impairment of assets and other charges | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | Interest and related charges | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | ) | | | | |
An analysis of Virginia Power’s results of operations follows: increased 14% decreased 4%, primarily reflecting:• | A $356 million decrease for refunds to be provided to retail electric customers in Virginia associated with the settlement of the 2021 Triennial Review; |
A $348 million increase from rate adjustment clauses;• | A $151 million decrease from an unbilled revenue reduction; |
• | A $62 million decrease associated with settlements of economic hedges of certain regulated electric sales; and |
• | A $51 million decrease in PJM off-system sales; |
These decreases were partially offset by: • | A $125 million increase in the fuel cost component included in utility rates as a result of a net increase in commodity costs associated with sales to electric utility retail customers |
• | A $59 million increase in sales to retail customers from an increase in heating degree days during the heating season ($65 million) partially offset by a decrease in cooling degree days during the cooling season ($6 million); |
• | A $49 million increase in sales to electric utility retail customers associated with growth; |
• | A $35 million increase in sales to electric utility retail customers associated with economic and other usage factors; and |
The absence of• | A $26 million increase in sales to customers from non-jurisdictional solar generation facilities. |
Electric fuel and other energy-related purchases increased 6%, primarily due to higher commodity costs for electric utilities ($125 million), partially offset by a $215 million charge associated with Virginia legislation enacted in March 2018 that requiredone-time
rate credits of certain amounts to utility customers; A $74 million decrease in PJM off-system sales ($51 million), which are offset in operating revenue and do not impact net income.Purchased electric capacity increased $41 million, primarily due to an increase in expense primarily related to the annual PJM capacity performance market effective June 20192021 ($6324 million) and a contract termination with anon-utility
generator ($37 million), partially offset byan increase in expense related to the annual PJM capacity performance market effective June 20182020 ($2617 million); and A $40 million decrease in fuel costs due to the expiration of an energy supply contract; partially offset by
A $45 million decrease in sales to retail customers from lower heating degree days during the heating season, partially offset by a $25 million increase from higher cooling degree days during the cooling season.
.Other operations and maintenance 4%,$7 million, primarily reflecting:• | A $57 million increase in outside services; |
A $190 million charge related to a voluntary retirement program;• | A $32 million increase in storm damage and service restoration costs; |
• | A $20 million increase in materials and supplies; and |
• | A $19 million increase in planned outage costs; partially offset by |
• | A $44 million decrease in certain expenses which are primarily recovered through state- and FERC-regulated rates and do not impact net income; |
• | A $12 million gain on the sale of corporate office real estate; |
• | The absence of a $11 million charge associated with ash pond and landfill closure costs; |
A $116 million increase in certain transmission and generation-related expenses. These expenses were primarily• | The absence of a $11 million charge associated with credit risk on customer accounts related to COVID-19; |
• | A $10 million reduction in bad debt expense due to the forgiveness of Virginia retail electric customer accounts in arrears pursuant to Virginia’s 2021 budget process; and |
• | A $10 million decrease in environmental remediation costs. |
recovered through state and FERC rates and did not impact net income; partially offset by
A $113 million benefit from the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019;
The absence of an $81 million charge associated primarily with future ash pond and landfill closure costs in connection with the enactment of Virginia legislation in April 2018; and
A $25 million decrease in storm damage and service restoration costs.
Depreciation and amortization 8%9%, primarily due to an increase for amortization from the establishment of a regulatory asset associated with the 2021 Triennial Review ($61 million), various projects being placed into service ($92 million) and the absence of a benefit for the retroactive application of depreciation rates for regulated nuclear plants to comply with Virginia Commission requirements ($3157 million), partially offset by the absence of depreciation from certain electric generation facilities and automated meter reading infrastructure that were retired early ($4011 million).Impairment of assets and other charges increased $757 million, (benefits) decreased $1.4 billion, primarily reflecting:A $346 million charge related to the early retirement of certain electric generation facilities;
A $160 million charge related to the planned early retirement of certain automated meter reading infrastructure;
A $135 million charge related to contract termination with anon-utility
generator; andA $62 million charge related to the abandonment of a project at an electric generating facility.
increased $76 million, primarily reflecting an increase in net investment earnings on nuclear decommissioning trust funds.decreased 12%, primarily due to lower pretax income ($29 million) and the absence of 2017 Tax Reform Act impacts ($23 million), partially offset by lower investment tax credits ($14 million).decreased 8%, primarily reflecting:A $238 million decrease for regulated generation and distribution operations as a result of the 2017 Tax Reform Act;
A $215 million charge associated with Virginia legislation enacted in March 2018 that requiresone-time
rate credits of certain amounts to utility customers;A $94 million increase in net electric capacity 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-utility
generators ($57 million); andAn $89 million decrease from rate adjustment clauses, which includes the impacts of the 2017 Tax Reform Act; partially offset by
An increase in sales to retail customers from an increase in heating degree days during the heating season of 2018 ($71 million) and an increase in cooling degree days during the cooling season of 2018 ($69 million); and
A $46 million increase in sales to retail customers due to customer growth.
• | The absence of charges associated with the planned early retirements of certain electric generation facilities ($747 million); |
• | A benefit from the establishment of a regulatory asset associated with the early retirements of certain coal- and oil-fired generating units associated with the settlement of the 2021 Triennial Review ($549 million); |
• | The absence of a charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to legislation enacted in November 2020 ($127 million); and |
• | The absence of charges for dismantling costs associated with certain electric generation facilities ($54 million); partially offset by |
• | A charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to Virginia’s 2021 budget process ($77 million); and |
• | An increase in charges for CCRO benefits provided to retail electric customers in Virginia associated with the 2021 Triennial Review ($58 million). |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Other operations and maintenance
increased 13%, primarily reflecting:A $102 million increase due to storm damage and service restoration costs; and
An $81 million increase due to a charge associated primarily with future ash pond and landfill closure costs in connection with the enactment of Virginia legislation in April 2018; partially offset by
A $19 million decrease from a reduction in planned outage days at certain generation facilities.
Depreciation and amortization
was substantially consistent as a decrease due to revised depreciation rates for regulated nuclear plants to comply with the Virginia Commission requirements ($61 million) was substantially offset by various growth projects being placed into service ($56 million).decreased 71%, primarily related to lower realized gains (including investment income) on nuclear decommissioning trust funds ($23 million), the electric transmission tower rental portfolio, including the absence of the assignment of such amounts to Vertical Bridge Towers II, LLC ($18 million) and the absence of interest income associated with the settlement of state income tax refund claims ($11 million), partially offset by the absence of a charge associated with a customer settlement ($16 million).decreased 61%, primarily due to lowerpre-tax
income ($256 million), the reduced corporate income tax rate ($235 million) and higher renewable energy investment tax credits ($35 million), partially offset by the absence of benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate ($93 million).Presented below is a summary of Dominion Energy Gas’ consolidated results:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net income attributable to Dominion Energy Gas | | | | | | | | | | | | | | | | | | | | |
Net income attributable to Dominion Energy Gas increased 50%, primarily due to the absence of a charge for disallowance of FERC-regulated plant, the commercial operations of the Liquefaction Facility for the entire year, the absence of awrite-off
associated with the Eastern Market Access Project and the absence of an impairment charge on certain gathering and processing assets included in discontinued operations, partially offset by the absence of gains related to agreements to convey shale development rights under natural gas storage fields and a charge related to a voluntary retirement program.Net income attributable to Dominion Energy Gas decreased 32%, primarily due to an impairment charge on certain gathering and processing assets included in discontinued operations, a charge for disallowance of FERC-regulated plant and the absence of benefits from the 2017 Tax Reform Act, partially offset by the commencement of commercial operations of the Liquefaction Facility, regulated natural gas transmission activities from growth projects placed into service and an increase in gains from agreements to convey shale development rights underneath several natural gas storage fields.
Analysis of Consolidated Operations
Presented below are selected amounts related to Dominion Energy Gas’ results of operations:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | $ | | | | | | | | $ | | | | | | | | | | | | | | | ) | | | | ) | | | | | Other energy-related purchases | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other operations and maintenance | | | | | | | | | | | | | | | | | | | | | Depreciation and amortization | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Impairment of assets and related charges | | | | | | | | ) | | | | | | | | | | | | | | | | | ) | | | | | | | | ) | | | | ) | | | | ) | Earnings from equity method investees | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Interest and related charges | | | | | | | | | | | | | | | | | | | | | Income tax expense (benefit) | | | | | | | | ) | | | | | | | | | | | | ) | Net Income from discontinued operations | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | ) | | | | | | | | | | | | |
An analysis of Dominion Energy Gas’ results of operations follows:
increased 8%, primarily reflecting:A $257 million increase from the Liquefaction Facility, including terminalling services provided to the Export Customers ($190 million), a decrease in credits associated with thestart-up
phase ($44 million) and regulated gas transportation contracts to serve the Export Customers ($23 million); andAn $18 million increase due to DETI contract changes; partially offset by
A $99 million decrease in services performed for Atlantic Coast Pipeline; and
A $42 million increase in net fuel carrying costs as a result of depressed natural gas market conditions.
Other operations and maintenance
remained substantially consistent primarily reflecting:A $45 million increase in operating expenses from the commercial operations of the Liquefaction Facility and costs associated with regulated gas transportation contracts to serve the Export Customers;
A $39 million charge related to a voluntary retirement program; and
A $10 million increase in salaries, wages and benefits and general administrative expenses; substantially offset by
A $99 million decrease in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income.
Depreciation and amortization
increased 10%83%, primarily due to an increase from various growthin net investment gains on nuclear decommissioning trust funds ($38 million) and an increase in AFUDC associated with rate-regulated projects being placed into service, including the Liquefaction Facility.($24 million).Income tax expenseincreased 28%73%, primarily due to property taxes associated with the Liquefaction Facility. Impairment of assets and related charges
decreased 92%, primarily due to the absence of a charge for disallowance of FERC-regulated planthigher pre-tax income ($ 127192 million) and the absence of awrite-off
associated with the Eastern Market Access Project ($37 million), partially offset by the abandonment of the Sweden Valley project ($13 million).decreased 98%, primarily due to the absence of gains related to agreements to convey shale development rights under natural gas storage fields.Earnings from equity method investees
decreased 20%, primarily due to lower earnings from Iroquois.increased 87%, primarily due to interest income from Cove Point’s promissory notes receivable from Dominion Energy issued in 2018.Interest and related charges
increased 79%, primarily due to Cove Point’s term loan borrowings ($78 million), the absence of capitalization of interest expense associated with the Liquefaction Facility upon completion of construction ($46 million) and higher interest expense due to increased affiliate borrowings ($10 million).decreased 19%, primarily due to the impacts of changes in tax status of certain subsidiaries in connection with the Dominion Energy Gas Restructuring ($48 million), partially offset by reductions in noncontrolling interest associated with Dominion Energy’s purchase of Dominion Energy Midstream publicly held common units ($9 million) and the absencebenefit of a state legislative change ($ 1516 million). decreased 31%, primarily due to the acquisition of the public interest in Dominion Energy Midstream in January 2019.increased 42%, primarily reflecting:A $500 million increase due to commencement of commercial operations of the Liquefaction Facility, including terminalling services provided to the Export Customers ($508 million) and regulated gas transportation contracts to serve the Export Customers ($58 million), partially offset by credits associated with thestart-up
phase of the Liquefaction Facility ($66 million);A $74 million increase in services performed for Atlantic Coast Pipeline; and
A $57 million increase due to regulated natural gas transmission growth projects placed in service, other than the Liquefaction Facility; partially offset by
A $38 million decrease from scheduled declines in or expiration of certain DETI and Cove Point contracts.
Other operations and maintenance
increased 25%, primarily reflecting:A $73 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income;
A $47 million increase in operating expenses from the commercial operations of the Liquefaction Facility and costs associated with regulated gas transportation contracts to serve the Export Customers; and
A $13 million increase in salaries, wages and benefits and general administrative expenses.
Depreciation and amortization
increased 38%, primarily due to an increase from various growth projects being placed into service, including the Liquefaction Facility.increased 21%, primarily due to property taxes associated with the Liquefaction Facility commencing commercial operations.Impairment of assets and related charges
increased $148 million, primarily due to a charge for disallowance of FERC-regulated plant ($127 million) and awrite-off
associated with the Eastern Market Access Project ($37 million), partially offset by the absence of a charge towrite-off
the balance of a regulatory asset no longer considered probable of recovery ($15 million).increased 67% primarily due to increased gains from agreements to convey shale development rights underneath several natural gas storage fields.Earnings from equity method investees
increased 15%, primarily due to higher earnings from unsubscribed capacity as a result of an increase in heating degree days at Iroquois.increased 44%, primarily due to interest income from Cove Point’s promissory notes receivable from Dominion Energy issued in September 2018 ($20 million) and a decrease innon-service
components of pension and other postretirement employee benefit credits capitalized to property, plant and equipment in 2018 ($13 million), partially offset by AFUDC on rate-regulated projects ($7 million).Interest and related charges
increased $114 million, primarily due to the absence of capitalization of interest expense associated with the Liquefaction Facility upon completion of construction ($72 million) and Cove Point’s term loan borrowings ($36 million).increased $189 million, primarily due to the absence of benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate ($246 million), higherpre-tax
income ($37 million), the absence of a settlement with state tax authorities ($5 million), partially offset by the reduced corporate income tax rate ($90 million) and a state legislative change ($10 million).
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Liquidity And Capital Resources
LIQUIDITY AND CAPITAL RESOURCES Dominion Energy depends on both internalcash generated from operations and external sources of liquidity to provide working capital and as a bridge to long-term debt financings. Short-termDominion Energy’s material cash requirements not met by cash provided by operationsinclude capital and investment expenditures, repaying short-term and long-term debt obligations and paying dividends on its common and preferred stock. Analysis of Cash Flows Presented below are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through issuances of debt and/or equity securities. At December 31, 2019, Dominion Energy had $5.1 billion of unused capacity under its credit facility. See additional discussion below underCredit Facilities and Short-Term Debt.
A summary ofselected amounts related to Dominion Energy’s cash flows is presented below:flows:Year Ended December 31, | | 2021 | | | 2020 | | | 2019 | | (millions) | | | | | | | | | | | | | Cash, restricted cash and equivalents at beginning of year | | $ | 247 | | | $ | 269 | | | $ | 391 | | Cash flows provided by (used in): | | | | | | | | | | | | | Operating activities | | | 4,037 | | | | 5,227 | | | | 5,204 | | Investing activities | | | (6,247 | ) | | | (2,916 | ) | | | (4,622 | ) | Financing activities | | | 2,371 | | | | (2,333 | ) | | | (704 | ) | Net increase (decrease) in cash, restricted cash and equivalents | | | 161 | | | | (22 | ) | | | (122 | ) | Cash, restricted cash and equivalents at end of year | | $ | 408 | | | $ | 247 | | | $ | 269 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash, restricted cash and equivalents at beginning of year | | $ | | | | $ | | | | $ | | | | | | | | | | | | | | | | | Cash flows provided by (used in): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | | | | | ) | | | | ) | | | | | Net increase (decrease) in cash, restricted cash and equivalents | | | | ) | | | | | | | | ) | Cash, restricted cash and equivalents at end of year | | $ | | | | $ | | | | $ | | |
Net cash provided by Dominion Energy’sEnergy's operating activities decreased $1.2 billion, including a $1.4 billion decrease from discontinued operations largely due to the absence of operations sold in the GT&S Transaction. Net cash provided by continuing operations increased $431$200 million, primarily dueas the result of higher operating cash flows from electric utility and gas distribution operations driven by weather, customer growth and riders ($737 million), the absence of a cash pension plan contribution ($250 million), increased distributions from Cove Point ($230 million), absence of a contract termination payment in connection with the sale of Fowler Ridge ($221 million), decreases in severance payments primarily related to operationsa voluntary retirement program ($174 million) and a decrease in payments associated with litigation acquired in the SCANA Combination the commercial operations of the Liquefaction Facility for the entire year($143 million), lower income tax payments ($132 million) and higherchanges in working capital ($161 million). These increases were partially offset by lower deferred fuel cost recoveries in the Virginia jurisdiction, partially offset by an increase in property tax payments,($1.2 billion) and increased interest expense, higher customer rate refunds, a contract termination payment to a non-utility
generator, an increase in merger and integration-related costs associated with the SCANA Combination, and a net decrease in other working capital items.Dominion Energy believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and maintain or grow the dividend on common shares. In December 2019, Dominion Energy’s Board of Directors established an annual dividend rate for 2020 of $3.76 per share of common stock, a 2.5% increase over the 2019 rate. Dividends are subject to declaration by the Board of Directors. In January 2020, Dominion Energy’s Board of Directors declared dividends payable in March 2020 of 94 cents per share of common stock.
Dominion Energy’s operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flows, and which are discussed in Item 1A. Risk Factors.
Dominion Energy’s exposure to potential concentrations of credit risk results primarily from its energy marketing and price risk management activities. Presented below is a summary of Dominion Energy’s credit exposure as of December 31, 2019 for these activities. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealizedon-
oroff-balance
sheet exposure, taking into account contractual netting rights.| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Internally rated—investment grade (2) | | | | | | | | | | | | | Internally rated—non-investment grade (3) | | | | | | | | | | | | | | | | | | | | | | | | | |
(1) | Designations as investment grade are based upon minimum credit ratings assigned by Moody’s and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 25% of the total net credit exposure. |
(2) | The five largest counterparty exposures, combined, for this category represented approximately 51% of the total net credit exposure. |
(3) | The five largest counterparty exposures, combined, for this category represented approximately 11% of the total net credit exposure. |
(4) | Excludes Millstone 2019 power purchase agreements. |
margin deposits ($690 million).Investing Cash Flows Net cash used in Dominion Energy’s investing activities increased $2.3$3.3 billion, primarily due to a net decrease in net proceeds from the sale of certain merchant generationthe Q-Pipe Group compared to the GT&S Transaction ($2.2 billion), the repayment of the Q-Pipe Transaction deposit ($1.3 billion), an increase in contributions to equity method affiliates including Atlantic Coast Pipeline ($873 million), partially offset by the proceeds from the sale of non-wholly-owned nonregulated solar facilities and interests in certain($495 million), the absence of acquisitions of equity method investments ($178 million) and an increasea decrease in plant constructionacquisitions of solar development projects ($210 million). Financing Cash Flows Net cash provided by Dominion Energy’s financing activities was $2.4 billion for the year ended December 31, 2021, compared to net cash used by financing activities of $2.3 billion for the year ended December 31, 2020. This change is primarily due to the absence of common stock repurchases ($3.1 billion), higher net issuances of short-term debt ($1.4 billion), lower common stock dividend payments ($837 million) and other property additions,the issuance of Series C Preferred Stock ($742 million), partially offset by cashincreased repayments and restricted cash acquired in the SCANA Combination.redemptions of long-term debt ($871 million).
Financing Cash FlowsCredit Facilities and Liquidity Short-Term DebtDominion Energy reliesgenerally uses proceeds from short-term borrowings, including commercial paper, to satisfy short-term cash requirements not met through cash from operations. The levels of borrowing may vary significantly during the course of the year, depending on capital markets as significant sourcesthe timing and amount of funding for capitalcash requirements not satisfied by cash provided by itsfrom operations. As discussed in ,A description of Dominion Energy’s ability to borrow funds or issue securitiesprimary available sources of short-term liquidity follows.Joint Revolving Credit Facility Dominion Energy maintains a $6.0 billion joint revolving credit facility which provides for a discount in the pricing of certain annual fees and amounts borrowed by Dominion Energy under the return demanded by investors are affected byfacility if Dominion Energy achieves certain annual renewable electric generation and diversity and inclusion objectives. Dominion Energy’s commercial paper and letters of credit ratings. In addition, the raising of external capital is subject to certain regulatory requirements, includingoutstanding, as well as capacity available under its credit facility were as follows: | | Facility Limit | | | Outstanding Commercial Paper(1) | | | Outstanding Letters of Credit | | | Facility Capacity Available | | (millions) | | | | | | | | | | | | | | | | | At December 31, 2021 | | | | | | | | | | | | | | | | | Joint revolving credit facility(2) | | $ | 6,000 | | | $ | 1,883 | | | $ | 131 | | | $ | 3,986 | |
(1) | The weighted-average interest rate of the outstanding commercial paper supported by Dominion Energy’s credit facility was 0.31% at December 31, 2021. |
(2) | This credit facility matures in June 2026, with the potential to be extended by the borrowers to June 2028, and can be used by the borrowers under the credit facility to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit. |
Dominion Energy Reliability InvestmentSM Program Dominion Energy has an effective registration statement with the SEC for certain issuances.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, 2021, Dominion Energy’s Consolidated Balance Sheets include $431 million presented within short-term debt. The proceeds are used for general corporate purposes and to repay debt. Other Facilities In addition to the primary sources of short-term liquidity discussed above, from time to time Dominion Energy enters into separate supplementary credit facilities or term loans as discussed in Note 17 to the Consolidated Financial Statements. Long-Term Debt Issuances and Borrowings of Long-Term Debt During 2021, Dominion Energy issued or borrowed the following long-term debt. Unless otherwise noted, the proceeds were used for the repayment of existing long-term indebtedness and for general corporate purposes.
Month of Issuance | | Type | | Public / Private | | Issuer / Borrowing Entity | | Principal | | | Rate | | | Stated Maturity | | | | | | | | | (millions) | | | | | | | | March | | Senior notes | | Private | | PSNC | | $ | 150 | | | | 3.100 | % | | 2051 | April | | Senior notes | | Public | | Dominion Energy | | | 600 | | | | 1.450 | % | | 2026 | April | | Senior notes | | Public | | Dominion Energy | | | 500 | | | | 3.300 | % | | 2041 | June | | Sustainability Revolving Credit Agreement(1) | | Private | | Dominion Energy | | | 250 | | | variable | | | 2024 | August | | Sustainability Revolving Credit Agreement(1) | | Private | | Dominion Energy | | | 650 | | | variable | | | 2024 | August | | Senior notes(2) | | Public | | Dominion Energy | | | 1,000 | | | | 2.250 | % | | 2031 | August | | Senior notes | | Private | | Questar Gas | | | 125 | | | | 2.210 | % | | 2031 | August | | Senior notes | | Private | | Questar Gas | | | 125 | | | | 3.150 | % | | 2051 | November | | Senior notes | | Public | | Virginia Power | | | 500 | | | | 2.300 | % | | 2031 | November | | Senior notes | | Public | | Virginia Power | | | 500 | | | | 2.950 | % | | 2051 | November | | First mortgage bonds | | Public | | DESC | | | 400 | | | | 2.300 | % | | 2031 | December | | Term loan(3) | | Private | | DECP Holdings | | | 2,500 | | | variable | | | 2024 | Total issuances and borrowings | | | | | | $ | 7,300 | | | | | | | |
| (1) | This supplemental credit facility offers a reduced interest rate margin with respect to borrowed amounts allocated to certain environmental sustainability or social investment initiatives. Proceeds of the supplemental credit facility may also be used for general corporate purposes, but such proceeds are not eligible for a reduced interest rate margin. The proceeds from these borrowings were used to support environmental sustainability and social investment initiatives ($250 million) and for general corporate purposes ($650 million). At December 31, 2021, no amounts were outstanding under this arrangement. |
| (2) | The proceeds from this offering will be used to finance and/or refinance, in whole or in part, existing and future capital expenditures associated with the development, construction, acquisition and operation of certain solar projects. |
| (3) | The maturity date for this term loan has the potential to be extended to December 2026. |
Dominion Energy currently meets the definition of a well-known seasoned issuer under SEC rules governing the registration, communications and offering processes under the Securities Act of 1933, as amended. The rules provide for a streamlined shelf registration process to provide registrants with timely access to capital. This allows Dominion Energy to use automatic shelf registration statements to register any offering of securities, other than those for exchange offers or business combination transactions. FromDominion Energy anticipates, excluding potential opportunistic financings, issuing between approximately $3.2 billion and $4.4 billion of long-term debt during 2022, inclusive of $1.0 billion issued at Virginia Power in January 2022. The raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances. Repayment, Repurchases and Redemptions of Long-Term Debt Dominion Energy may from time to time 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 2021: Month of Redemption | | Type | | Entity | | Principal | | (1) | Rate | | | Stated Maturity | | | | | | | (millions) | | | | | | | | Debt scheduled to mature in 2021 | | | | $ | 2,109 | | (2) | various | | | | Early redemptions | | | | | | | | | | | | | August | | July 2016 hybrids(3) | | Dominion Energy | | | 800 | | | | 5.250 | % | | 2076 | November | | Senior notes | | Virginia Power | | | 450 | | | | 2.950 | % | | 2022 | November | | Sustainability Revolving Credit Agreement | | Dominion Energy | | | 650 | | | variable | | | 2024 | December | | Sustainability Revolving Credit Agreement | | Dominion Energy | | | 250 | | | variable | | | 2024 | December | | Senior notes | | Dominion Energy | | | 400 | | | | 2.750 | % | | 2022 | December | | Term loan | | Dominion Solar Projects III, Inc. | | | 177 | | | variable | | | 2024 | Total repayments, repurchases and redemptions(4) | | | | $ | 4,836 | | | | | | | |
(1) | Total amount redeemed prior to maturity includes remaining outstanding principal plus accrued interest. |
(2) | Includes repayment of $225 million associated with supplemental 364-Day revolving credit facility borrowings. |
Net
(3) | The July 2016 hybrids were listed on the NYSE under the symbol DRUA. Expenses related to the early redemption were $23 million reflected within interest and related charges in Dominion Energy’s Consolidated Statements of Income for the year ended December 31, 2021. |
(4) | Amounts exclude $265 million of long-term debt assumed by Terra Nova Renewable Partners in connection with the sale of SBL Holdco in December 2021. |
See Note 18 to the Consolidated Financial Statements for additional information regarding scheduled maturities and other cancellations of Dominion Energy’s long-term debt, including related average interest rates. Remarketing of Long-Term Debt In 2021, Dominion Energy was not required to and did not complete the remarketing of any of its long-term debt. In 2022, Dominion Energy expects to remarket approximately $165 million of its senior notes and tax-exempt bonds. Credit Ratings Dominion Energy’s credit ratings affect its liquidity, cost of borrowing under credit facilities and collateral posting requirements under commodity contracts, as well as the rates at which it is able to offer its debt securities. The credit ratings for Dominion Energy are affected by its financial profile, mix of regulated and nonregulated businesses and respective cash flows, changes in methodologies used by the rating agencies and event risk, if applicable, such as major acquisitions or dispositions. Credit ratings and outlooks as of February 21, 2022 are as follows: | | Fitch | | Moody's | | Standard & Poor's | Dominion Energy | | | | | | | Issuer | | BBB+ | | Baa2 | | BBB+ | Senior unsecured debt securities | | BBB+ | | Baa2 | | BBB | Junior subordinated notes | | BBB | | Baa3 | | BBB | Enhanced junior subordinated notes | | BBB- | | Baa3 | | BBB- | Preferred Stock | | BBB- | | Ba1 | | BBB- | Commercial paper | | F2 | | P-2 | | A-2 | Outlook | | Stable | | Stable | | Positive |
A credit rating is not a recommendation to buy, sell or hold securities and should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the applicable rating organization. Financial Covenants As part of borrowing funds and issuing both short-term and long-term debt or preferred securities, Dominion Energy must enter into enabling agreements. These agreements containcustomary covenants that, in the event of default, could result in the acceleration of principal and interest payments; restrictions on distributions related to capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments; and in some cases, the termination of credit commitments unless a waiver of such requirements is agreed to by the lenders/security holders. These provisions are customary, with each agreement specifying which covenants apply. These provisions are not necessarily unique to Dominion Energy. Dominion Energy is required to pay annual commitment fees to maintain its joint revolving credit facility. In addition, the credit agreement contains various terms and conditions that could affect Dominion Energy’s ability to borrow under the facility. They include a maximum debt to total capital ratio, which is also included in Dominion Energy’s financing activities decreased $1.5 billion, primarily dueSustainability Revolving Credit Agreement entered into in 2021, and cross-default provisions. As of December 31, 2021, 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 | % | | | 56.0 | % |
(1) | Indebtedness as defined by the agreements excludes certain junior subordinated notes reflected as long-term debt as well as AOCI reflected as equity in the Consolidated Balance Sheets. Capital is inclusive of preferred stock whether classified as equity or mezzanine equity. |
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 lenders could terminate their commitments, if any, to lend funds to that company under the credit facility. In addition, if the defaulting company is Virginia Power, Dominion Energy’s obligations to repay any outstanding borrowing under the credit facility could also be accelerated and the lenders’ commitments to Dominion Energy could terminate. Dominion Energy monitors compliance with these covenants on a regular basis in order to ensure that events of default will not occur. As of December 31, 2021, there have been no events of default under Dominion Energy’s covenants. Common Stock, Preferred Stock and Other Equity Securities Issuances of Equity Securities Dominion Energy maintains Dominion Energy Direct® and a number of employee savings plans through which contributions may be invested in Dominion Energy’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In January 2021, Dominion Energy began issuing new shares of common stock for these direct stock purchase plans. During 2021, Dominion Energy issued 2.6 million of such shares and received proceeds of $192 million. Dominion Energy also maintains sales agency agreements to effect sales under an at-the-market program. Under the sales agency agreements, Dominion Energy may, from time to time, offer and sell shares of its common stock through the sales agents or enter into one or more forward sale agreements with respect to shares of its common stock. Sales by Dominion Energy through the sales agents or by forward sellers pursuant to a forward sale agreement cannot exceed $1.0 billion in the aggregate. In November 2021, Dominion Energy entered forward sale agreements for approximately 1.1 million shares of its common stock to be settled by November 2022 at an average initial forward price of $74.66 per share. See Note 20 to the Consolidated Financial Statements for additional information. In addition, Dominion Energy issued shares of its common and preferred stock, as discussed in Notes 19 and 20 to the Consolidated Financial Statements, respectively, as follows: | • | In 2021, Dominion Energy issued 2.0 million shares of its common stock, valued at $149 million, to satisfy obligations under settlement agreements associated with litigation acquired in the SCANA Combination. |
| • | In December 2021, Dominion Energy issued 750,000 shares of Series C Preferred Stock and received cash proceeds of $742 million, net of issuance costs. Also in December 2021, Dominion Energy issued 250,000 shares of Series C Preferred Stock, valued at $250 million, to the qualified pension plans. |
Between Dominion Energy Direct® and its at-the-market program (including any related forward-sale agreements), and excluding potential opportunistic financings, Dominion Energy anticipates raising between $300 million and $500 million of capital through the issuance of common stock in 2022. In addition, Dominion Energy may issue up to $150 million of stock under settlement agreements associated with litigation acquired in the SCANA Combination as discussed in Note 23 to the Consolidated Financial Statements. As discussed in Note 19 to the Consolidated Financial Statements, in 2022, Dominion Energy will settle the stock purchase contract component of the 2019 Equity Units expected to result in proceeds of $1.6 billion and the Series B Preferred Stock, partially offset by an increase in net debt repayments in 2019 comparedissuance of up to 2018 and higher21.8 million shares, subject to a formula based on the average closing price of Dominion Energy common stock dividend payments. Credit Facilitiesupon settlement.Repurchases of Equity Securities In November 2020, the Board of Directors authorized the repurchase of up to $1.0 billion of Dominion Energy’s common stock. This repurchase program does not include a specific timetable or price or volume targets and Short-Term Debt may be modified, suspended or terminated at any time. Shares may be purchased through open market or privately negotiated transactions or otherwise at the discretion of management subject to prevailing market conditions, applicable securities laws and other factors. No purchases have been made under this authorization as of December 31, 2021.Dominion Energy uses short-term debtdoes not plan to fund workingrepurchase shares of common stock in 2022, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which does not impact the available capacity under its stock repurchase authorization.
Capital Expenditures See Note 26 to the Consolidated Financial Statements for Dominion Energy’s historical capital requirements and as a bridge to long-term debt financings. The levels of borrowing may vary significantly duringexpenditures by segment. Dominion Energy’s total planned capital expenditures for each segment over the course ofnext five years are presented in the | | 2022 | | | 2023 | | | 2024 | | | 2025 | | | 2026 | | | Total(1) | | (billions) | | | | | | | | | | | | | | | | | | | | | | | | | Dominion Energy Virginia | | $ | 5.8 | | | $ | 7.2 | | | $ | 7.5 | | | $ | 7.5 | | | $ | 5.3 | | | $ | 33.2 | | Gas Distribution | | | 1.4 | | | | 1.4 | | | | 1.2 | | | | 1.5 | | | | 1.1 | | | | 6.5 | | Dominion Energy South Carolina | | | 0.8 | | | | 0.9 | | | | 0.9 | | | | 0.8 | | | | 0.7 | | | | 4.2 | | Contracted Assets | | | 0.6 | | | | 0.9 | | | | 0.9 | | | | 0.9 | | | | 0.5 | | | | 3.8 | | Corporate and Other segment | | | 0.1 | | | | 0.1 | | | | 0.1 | | | | 0.1 | | | | 0.1 | | | | 0.4 | | Total(1) | | $ | 8.6 | | | $ | 10.3 | | | $ | 10.7 | | | $ | 10.6 | | | $ | 7.7 | | | $ | 47.9 | |
(1) | | | | | | | | | | | | | | | Totals may not foot due to rounding. |
year, depending uponDominion Energy’s planned growth expenditures are subject to approval by the timingBoard of Directors as well as potentially by regulatory bodies based on the individual project and amountare expected to include significant investments in support of its clean energy profile. See Dominion Energy Virginia, Gas Distribution, Dominion Energy South Carolina and Contracted Assets in Item 1. Business for additional discussion of various significant capital projects currently under development. The above estimates are based on a capital expenditures plan reviewed and endorsed by Dominion Energy’s Board of Directors in December 2021 and are subject to continuing review and adjustment and actual capital expenditures may vary from these estimates. Dominion Energy may also choose to postpone or cancel certain planned capital expenditures in order to mitigate the need for future debt financings and equity issuances. Dividends Dominion Energy believes that its operations provide a stable source of cash requirementsflow to contribute to planned levels of capital expenditures and maintain or grow the dividend on common shares. In December 2021, Dominion Energy’s Board of Directors established an annual dividend rate for 2022 of $2.67 per share of common stock, a 6% increase over the 2021 rate. Dividends are subject to declaration by the Board of Directors. In January 2022, Dominion Energy’s Board of Directors declared dividends payable in March 2022 of 66.75 cents per share of common stock. See Note 19 for a discussion of Dominion Energy’s outstanding preferred stock and associated dividend rates. Subsidiary Dividend Restrictions Certain of Dominion Energy’s subsidiaries may, from time to time, be subject to certain restrictions imposed by regulators or financing arrangements on their ability to pay dividends, or to advance or repay funds, to Dominion Energy. At December 31, 2021, these restrictions did not satisfied byhave a significant impact on Dominion Energy’s ability to pay dividends on its common or preferred stock or meet its other cash from operations. In addition,obligations. See Note 21 to the Consolidated Financial Statements for a description of such restrictions and any other restrictions on Dominion Energy utilizes cashEnergy’s ability to pay dividends. Collateral and letters of credit to fund collateral requirements. Credit Risk Collateral requirements are impacted by commodity prices, hedging levels, Dominion Energy’s credit ratings and the credit quality of its counterparties. In connection with commodity hedging activities, Dominion Energy is required to provide collateral to counterparties under some circumstances. Under certain collateral arrangements, Dominion Energy may satisfy these requirements by electing to either deposit cash, post letters of credit or, in some cases, utilize other forms of security. From time to time, Dominion Energy may vary the form of collateral provided to counterparties after weighing the costs and benefits of various factors associated with the different forms of collateral. These factors include short-term borrowing and short-term investment rates, the spread over these short-term rates at which Dominion Energy can issue commercial paper, balance sheet impacts, the costs and fees of alternative collateral postings with these and other counterparties and overall liquidity management objectives. Dominion Energy’s commercial paper and lettersexposure to potential concentrations of credit 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: | | | | | | | | | | | | | | | | | | | | | | | Outstanding Commercial Paper (1) | | | Outstanding
Letters of
Credit | | | Facility
Capacity
Available | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Joint revolving credit facility (2) | | $ | | | | | | | | | | | | $ | | |
(1) | The weighted-average interest rate of the outstanding commercial paper supported by Dominion Energy’s credit facility was 2.10% at December 31, 2019. |
(2) | This credit facility matures in March 2023 and can be used by the borrowers under the credit facility to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit. |
In November 2017, Dominion Energy filed an SEC shelf registration statement 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, arenon-transferable
and may be redeemed in whole or in part by Dominion Energy or at the investor’s option at any time. The balanceexposure as of December 31, 2019 was $75 million. The notes are short-term debt obligations on Dominion Energy’s Consolidated Balance Sheets. The proceeds will be used for general corporate purposes and to repay debt.In March 2019, DESC’s $700 million credit facility was terminated and DESC was added as a borrower to the joint revolving credit facility discussed above with Dominion Energy, Virginia Power, Dominion Energy Gas and Questar Gas. At December 31, 2019, thesub-limit
for DESC was $500 million.South Carolina Fuel Company, Inc.’s credit facility was terminated in February 2019. SCANA and PSNC’s credit facilities
were terminated in March 2019. Liquidity needs2021 for these entities may be satisfied through short-term company borrowings from Dominion Energy.
activities. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights.
| | Gross Credit Exposure | | | Credit Collateral | | | Net Credit Exposure | | (millions) | | | | | | | | | | | | | Investment grade(1) | | $ | 32 | | | $ | — | | | $ | 32 | | Non-Investment grade(2) | | | 6 | | | | — | | | | 6 | | No external ratings: | | | | | | | | | | | | | Internally rated—investment grade(3) | | | 98 | | | | — | | | | 98 | | Internally rated—non-investment grade(4) | | | 39 | | | | 28 | | | | 16 | | Total | | $ | 175 | | | $ | 28 | | | $ | 152 | |
In February 2019, Dominion Energy Midstream terminated its $500 million revolving credit facility subsequent to repaying the outstanding balance of $73 million, plus accrued interest.
In September 2019, Dominion Energy Questar borrowed $3.0 billion under a364-Day
Term Loan Agreement that bore interest at a variable rate. The proceeds from the borrowing were used to repay the principal of Cove Point’s $3.0 billion term loan due in 2021. Dominion Energy provided a guarantee to support Dominion Energy Questar’s obligation under the364-Day
Term Loan Agreement. In November and December 2019, principal of $1.0 billion and $2.0 billion, respectively, plus accrued interest was repaid.During 2019, Dominion Energy issued the following long-term public debt:
During 2019, Dominion Energy also issued the following long-term private debt:
In August 2019, Dominion Energy issued $1.0 billion of 2.45% senior notes that mature in 2023 through a private placement. The proceeds were used for general corporate purposes and to repay short-term debt, including commercial paper.
During 2019, Dominion Energy also remarketed the following long-term debt:
In May 2019, Virginia Power remarketed four series oftax-exempt
bonds, with an aggregate outstanding principal of $198 million to new investors. One of the bonds will bear interest at a coupon rate of 1.8% until April 2022, after which it will bear interest at a market rate to be determined at that time. Three of the bonds will bear interest at a coupon rate of 1.9% until June 2023, after which they will bear interest at a market rate to be determined at that time.In June 2019, Dominion Energy successfully remarketed its $700 million 2016 SeriesA-1
2.0% RSNs due 2021 and $700 million 2016 SeriesA-2
2.0% RSNs due 2024 pursuant to the terms of the 2016 Equity Units. In connection with the remarketing, the interest rates on the SeriesA-1
and Series A-2
notes were reset to 2.715% and 3.071%, respectively. Dominion Energy did not receive any proceeds from the remarketing.In October 2019, Dominion Energy Terminal Company remarketed its $27 million Peninsula Ports Authority of Virginia Coal
(1) | Designations as investment grade are based upon minimum credit ratings assigned by Moody’s and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 17% of the total net credit exposure. |
(2) | The five largest counterparty exposures, combined, for this category represented approximately 4% of the total net credit exposure. |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
(3) | Terminal Revenue Refunding Bonds, Series 2003 due in 2033 resulting in a resetThe five largest counterparty exposures, combined, for this category represented approximately 64% of the interest rate from 1.55% to 1.70% until October 2022.total net credit exposure. |
(4) | The five largest counterparty exposures, combined, for this category represented approximately 5% of the total net credit exposure. |
During 2019, Fuel and Other Purchase Commitments Dominion Energy repaid, repurchased or redeemed the following long-term debt beforeis party to various contracts for fuel and purchased power commitments related to both its stated maturity: In February 2019, Dominion Energy Midstream repaid its $300 million variable rate term loan agreement due inregulated and nonregulated operations. Total estimated costs for such commitments at December 2019 at the principal outstanding plus accrued interest.
In February and March 2019, DESC purchased certain of its first mortgage bonds having an aggregate purchase price of $1.2 billion pursuant to tender offers. Also in March 2019, SCANA purchased certain of its medium term notes having an aggregate purchase price of $300 million pursuant to a tender offer. Both DESC tender offers and the SCANA tender offer expired31, 2021 are presented in the first quarter of 2019.
In May 2019, Virginia Power redeemed its $40 million 5.0% Economic Development Authority of the County of Chesterfield Pollution Control Refunding Revenue Bonds, Series 2009A, due in 2023 at the principal outstanding plus accrued interest.
In May 2019, GENCO redeemed its 5.49% senior secured notes due in 2024 at the remaining principal outstanding of $33 million plus accrued interest. In June 2019, the first mortgage lientable below. These costs represent estimated minimum obligations for various purchased power and capacity agreements and actual costs may differ from amounts presented below depending on an electric generating facility that previously secured these notes was released.
In June 2019, Dominion Energyactual quantities purchased and canceled $12 million and $13 million of its June 2006 hybrids and September 2006 hybrids, respectively. All purchases were conducted in compliance with the applicable RCC.prices paid. | | | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | | 2023 | | | 2024 | | | 2025 | | | 2026 | | | Total | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | Purchased electric capacity for utility operations | | $ | 66 | | | $ | 66 | | | $ | 66 | | | $ | 65 | | | $ | 68 | | | $ | 331 | | Fuel commitments for utility operations | | | 1,169 | | | | 685 | | | | 371 | | | | 178 | | | | 166 | | | | 2,569 | | Fuel commitments for nonregulated operations | | | 104 | | | | 134 | | | | 88 | | | | 68 | | | | 59 | | | | 453 | | Pipeline transportation and storage | | | 523 | | | | 462 | | | | 365 | | | | 303 | | | | 291 | | | | 1,944 | | Total | | $ | 1,862 | | | $ | 1,347 | | | $ | 890 | | | $ | 614 | | | $ | 584 | | | $ | 5,297 | |
Other Material Cash Requirements In September 2019, DESC purchased certain of its first mortgage bonds with an outstanding principal balance of $552 million pursuant to a tender offer that expired in the third quarter of 2019. In November 2019, Dominion Energy Gas redeemed its $450 million 2014 Series A 2.50% senior notes which would have otherwise matured in December 2019.
During 2019, Dominion Energy repaid, repurchased or redeemed $9.1 billion of long-term debt, including redemption premiums.
In January 2020, SCANA provided notice to redeem its floating rate senior notes at the remaining principal outstanding of $66 million plus accrued interest in March 2020. The notes would have otherwise matured in June 2034.
In February 2020, SCANA provided notice to redeem the remaining principal outstanding of $183 million of its 4.75% medium-term notes and $155 million of its 4.125% medium-term notes plus accrued interest and make-whole premiums in March 2020. The notes would have otherwise matured in May 2021 and February 2022, respectively.
In February 2020, in addition to the June 2019 purchases describedfinancing arrangements discussed above, Dominion Energy redeemed the remaining principal outstanding of $111 million and $286 million of its June 2006 hybrids and September 2006 hybrids, respectively, both of which would have otherwise matured in 2066. All purchases were conducted in compliance with the applicable RCC.
Noncontrolling Interest in Dominion Energy Midstream
In January 2019, Dominion Energy and Dominion Energy Midstream closed on an agreement and plan of merger pursuant to which Dominion Energy acquired each outstanding common unit representing limited partner interests in Dominion Energy Midstream not already owned by Dominion Energy through the issuance of 22.5 million shares of common stock valued at $1.6 billion. Under the terms of the agreement and plan of merger, each publicly held outstanding common unit representing limited partner interests in Dominion Energy Midstream was converted into the right to receive 0.2492 shares of Dominion Energy common stock. Immediately prior to the closing, each Series A Preferred Unit representing limited partner interests in Dominion Energy Midstream was converted into common units representing limited partner interests in Dominion Energy Midstream in accordance with the terms of Dominion Energy Midstream’s partnership agreement. See Note 20 to the Consolidated Financial Statements for more information.
Issuance of Common Stock, Preferred Stock and Other 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. Currently, Dominion Energy is issuing new shares of common stock for these direct stock purchase plans.During 2019, Dominion Energy issued approximately 157 million shares of common stock, valued at $11.4 billion, for acquisitions, settlements of stock purchase contracts and through various programs including Dominion Energy Direct®
and anat-the-market
program.In January 2019, in connection with the SCANA Combination, Dominion Energy issued 95.6 million shares of Dominion Energy common stock, valued at $6.8 billion, representing 0.6690 of a share of Dominion Energy common stock for each share of SCANA common stock outstanding at closing. SCANA’s outstanding debt totaled $6.9 billion at closing. Also in January 2019, Dominion Energy issued 22.5 million shares of common stock to acquire interests in Dominion Energy Midstream as noted above.
In December 2019, Dominion Energy contributed 6.1 million shares of its common stock valued at $499 million to the qualified defined benefit pension plan. During 2020, Dominion Energy plans to issue shares for employee savings plans and direct stock purchase and dividend reinvestment plans.
During 2019, Dominion Energy received cash of $309 million from the issuance of 4.0 million of such shares through Dominion Energy Direct®
and employee savings plans.In August 2019, Dominion Energy issued 18.5 million shares under the related stock purchase contracts entered into as part of Dominion Energy’s 2016 Equity Units and received proceeds of $1.4 billion.
In 2019, Dominion Energy issued 9.9 million shares and received cash proceeds of $793 million, net of fees and commissions paid of $8 million, through itsat-the-market
program. In
December 2019, Dominion Energy completed the program. See Note 20 to the Consolidated Financial Statements for a description of theat-the-market
program.In June 2019, Dominion Energy issued $1.6 billion of 2019 Equity Units, initially in the form of 2019 Series A Corporate Units. The Corporate Units are listed on the NYSE under the symbol DCUE.
In December 2019, Dominion Energy issued 800,000 shares of Series B Preferred Stock and received proceeds of $791 million.
Repurchase of Common Stock
Dominion Energy did not repurchase any shares in 2019 and does not plan to repurchase shares during 2020, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which does not count against its stock repurchase authorization.
Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. Dominion Energy believes that its current credit ratings provide sufficient access to the capital markets. However, disruptions in the banking and capital markets not specifically related to Dominion Energy may affect its ability to access these funding sources or cause an increase in the return required by investors. 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.
Both quantitative (financial strength) and qualitative (business or operating characteristics) factors are considered by the credit rating agencies in establishing an individual company’s credit rating. Credit ratings should be evaluated independently and are subject to revision or withdrawal at any time by the assigning rating organization. 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 25, 2020 follow:
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| | | | | | | | | | | | | Junior subordinated notes
| | | | | | | | | | | | | Enhanced junior subordinated notes
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A downgrade in an individual company’s credit rating does not necessarily restrict its ability to raise short-term and long-term financing as long as its credit rating remains investment grade, but it could result in an increase in the cost of borrowing. Dominion Energy works closely with Fitch, Moody’s and Standard & Poor’s with the objective of achieving its targeted credit ratings. Dominion Energy may find it necessary to modify its
business plan to maintain or achieve appropriate credit ratings and such changes may adversely affect growth and EPS.
As part of borrowing funds and issuing debt (both short-term and long-term) or preferred securities, Dominion Energy must enter into enabling agreements. These agreements contain 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.
Some of the typical covenants include:
The timely payment of principal and interest;
Information requirements, including submitting financial reports and information about changes in Dominion Energy’s credit ratings to lenders;
Performance obligations, audits/inspections, continuation of the basic nature of business, restrictions on certain matters related to merger or consolidation and restrictions on disposition of all or substantially all assets;
Compliance with collateral minimums or requirements related to mortgage bonds; and
Limitations on liens.
Dominion Energy is required to pay annual commitment fees to maintain its credit facility. In addition, Dominion Energy’s credit agreement contains various terms 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.
As of December 31, 2019, the calculated total debt to total capital ratio, pursuant to the terms of the agreement, was as follows:
(1) | Indebtedness as defined by the bank agreements excludes certain junior subordinated notes reflected as long-term debt as well as AOCI reflected as equity in the Consolidated Balance Sheets. |
If Dominion Energy or any of its material subsidiaries fails to make payment on various debt obligations in excess of $100 million, the lenders could require the defaulting company, if it is a borrower under Dominion Energy’s credit facility, to accelerate its repayment of any outstanding borrowings and the lenders could terminate their commitments, if any, to lend funds to that company under the credit facility. In addition, if the defaulting company is Virginia Power, Dominion Energy’s obligations to repay any outstanding borrowing under the credit facility could also be accelerated and the lenders’ commitments to Dominion Energy could terminate.
Dominion Energy executed RCCs in connection with its issuance of the June 2006 hybrids and September 2006 hybrids. In February 2020, the RCCs were terminated subsequent to the redemption of the remaining principal outstanding of the June 2006 hybrids and the September 2006 hybrids. See Note 18 to the Consolidated Financial Statements for additional information.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Dominion Energy monitors these debt covenants on a regular basis in order to ensure that events of default will not occur. As of December 31, 2019, there have been no events of default under Dominion Energy’s debt covenants.
Certain agreements associated with Dominion Energy’s credit facility contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict Dominion Energy’s ability to pay dividends or receive dividends from its subsidiaries at December 31, 2019.
See Notes 19 and 21 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.
Future Cash Payments for Contractual Obligations and Planned Capital Expenditures
Dominion Energy is party to numerous contracts and arrangements obligating it to make cash payments in future years. These contracts include financing arrangements such as debt agreements and leases, as well as contracts for the purchase of goods and services and financial derivatives. Presented below is a table summarizing cash payments that may result from contracts to which Dominion Energy is a party as of December 31, 2019. For purchase obligations and otherexpects current liabilities amounts are based upon contract terms, including fixed and minimum quantities to be purchased at fixed or market-based prices. Actualpaid within the next twelve months. In addition to the items already discussed, the following represent material expected cash payments will be based upon actual quantities purchased and prices paid and will likely differ from amounts presented below. The table excludes all amounts classified as current liabilities in therequirements recorded on Dominion Energy’s Consolidated Balance Sheets other than current maturities of long-term debt, interest payable and certain derivative instruments. The majority of Dominion Energy’s current liabilities will be paid in cash in 2020. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Purchased electric capacity for utility operations | | | | | | | | | | | | | | | | | | | | | Fuel commitments for utility operations | | | | | | | | | | | | | | | | | | | | | Fuel commitments for nonregulated operations | | | | | | | | | | | | | | | | | | | | | Pipeline transportation and storage | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other long-term liabilities : | | | | | | | | | | | | | | | | | | | | | Other contractual obligations | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | |
(1) | Based on stated maturity dates rather than the earlier redemption dates that could be elected by instrument holders. |
(2)• | Includes interest payments over the terms of the debtOperating and payments on stock purchase contracts. Interest is calculated using the applicable interest rate or forward interest rate curve at December 31, 2019 and outstanding principal for each instrument with the terms ending at each instrument’s stated maturity.financing lease obligations – See Note 1815 to the Consolidated Financial Statements. Does not reflect Dominion Energy’s abilityStatements; |
| • | Regulatory liabilities – See Note 12 to defer stock purchase contract payments on the 2019 Equity Units, initially in the form of corporate units.Consolidated Financial Statements; |
(3) | Amounts exclude open purchase orders for services that are provided on demand,• | AROs – See Note 14 to the timing of which cannot be determined.Consolidated Financial Statements; |
(4) | Includes capital, operations and maintenance commitments. |
(5)• | Excludes regulatory liabilities, AROs and employeeEmployee benefit plan obligations which are not contractually fixed as to timing and amount.– See Notes 12, 14 andNote 22 to the Consolidated Financial Statements. Due to uncertainty about the timingStatements; and amounts that will ultimately be paid, $118 million of income taxes payable associated with unrecognized tax benefits are excluded. Deferred income taxes are also excluded since cash payments are based primarily on taxable income for each discrete fiscal year. |
| • | Charitable commitments – See Note 523 to the Consolidated Financial Statements. |
(6) | Includes interest rate and foreign currency swap agreements. |
Planned Capital Expenditures
Dominion Energy’s planned capital expenditures are expected to total approximately $8.2 billion, $8.1 billion, and $7.6 billion in 2020, 2021, and 2022, respectively. Dominion Energy’s planned expenditures are expected to include construction and expansion of electric generation, including renewable energy, and natural gas distribution, transmission and storage facilities, construction improvements and expansion of electric transmission and distribution assets, purchases of nuclear fuel, maintenance, and contributions to Atlantic Coast Pipeline to fund Dominion Energy’s portion of the Atlantic Coast Pipeline Project.
Dominion Energy expects to fund its capital expenditures with cash from operations and a combination of securities issuances and short-term borrowings. Planned capital expenditures include capital projects that are subject to approval by regulators and the Board of Directors.
SeeDominion Energy Virginia, Gas Transmission & Storage, Gas Distribution, Dominion Energy South Carolina
andContracted Generation -Properties
in Item 1. Business for a discussion of Dominion Energy’s expansion plans.
The above estimates are based on a capital expenditures plan reviewed and endorsed by Dominion Energy’s Board of Directors in late 2019 and are subject to continuing review and adjustment and actual capital expenditures may vary from these estimates. Dominion Energy may also choose to postpone or cancel certain planned capital expenditures in order to mitigate the need for future debt financings and equity issuances.
Use ofOff-Balance
Sheet ArrangementsIn December 2019, Dominion Energy signed an agreement with a lessor to construct and lease a new corporate office property in Richmond, Virginia. The lessor is providing equity and has obtained financing commitments from debt investors, totaling $465 million, to fund the estimated project costs. If Dominion Energy ultimately proceeds with the project through completion, it is not expected to be completed earlier than mid-2023. Dominion Energy has been appointed to act as the construction agent for the lessor, during which time Dominion Energy will request cash draws from the lessor and debt investors to fund all project costs. If the project is terminated under certain events of default, Dominion Energy could be required to pay up to 89.9% 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-month
lease term will commence once construction is substantially complete and the facility is able to be occupied. At the end of the initial lease term, Dominion Energy can (i) extend the term of the lease for an additional five years, subject to the approval of the participants, at current market terms, (ii) purchase the property for an amount equal to the project costs or, (iii) subject to certain terms and conditions, sell the property on behalf of the lessor to a third party using commercially reasonable efforts to obtain the highest cash purchase price for the property. If the project is sold and the proceeds from the sale are insufficient to repay the investors for the project costs, Dominion Energy may be required to make a payment to the lessor, up to 83% of project costs, for the difference between the project costs and sale proceeds.Dominion Energy is not considered the owner during construction for financial accounting purposes and, therefore, will not reflect the construction activity in its consolidated financial statements. Dominion Energy expects to recognize aright-of-use
asset and a corresponding finance lease liability at the commencement of the lease term. Dominion Energy will be considered the owner of the leased property for tax purposes, and as a result, will be entitled to tax deductions for depreciation and interest expense.Dominion Energy primarily enters into guarantee arrangements on behalf of its consolidated subsidiaries. These arrangements are not subject to the provisions of FASB guidance that dictate a guarantor’s accounting and disclosure requirements for guarantees, including indirect guarantees of indebtedness of othersIn addition, Dominion Energy has provided a guaranteeis party to support a portion of Atlantic Coast Pipeline’s obligation under a $3.4 billion revolving credit facility. See Note 23contracts and arrangements which may require it to themake material cash payments in future years that are not recorded on its Consolidated Financial Statements for additional information.Balance Sheets. Such obligations include: | • | Off-balance sheet leasing arrangements – See Note 15 to the Consolidated Financial Statements |
| • | Guarantees – See notes 9 and 23 to the Consolidated Financial Statements |
Future Issues And Other Matters
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.
Dominion Energy is subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.
Environmental Protection and Monitoring Expenditures
Dominion Energy incurred $260 million, $198 million and $200 million of expenses (including accretion and depreciation) during 2019, 2018 and 2017, respectively, in connection with environmental protection and monitoring activities. Dominion Energy expects these expenses to be approximately $286 million and $275 million in 2020 and 2021, respectively. In addition, capital expenditures related to environmental controls were $134 million, $104 million, and $201 million for 2019, 2018 and 2017, respectively. Dominion Energy expects these expenditures to be approximately $159 million and $132 million for 2020 and 2021, respectively.
Future Environmental Regulations In December 2015, the Paris Agreement was formally adopted under the United Nations Framework Convention on Climate Change. A key element of the initial U.S. commitment to the agreement was the implementation of the Clean Power Plan,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. cash flows.State Actions Related to Air and GHG Emissions In August 2017, the Ozone Transport Commission released a draft model rule for control of NO X emissions from natural gas pipeline compressor fuel-fire prime movers. States within the ozone transport region, including states in which Dominion Energy has natural gas operations, are expected to develop reasonably achievable control technology rules for existing sources based on the Ozone Transport Commission model rule. States outside of the Ozone Transport Commission may also consider the model rules in setting new reasonably achievable control technology standards. Several states in which Dominion Energy operates, including Pennsylvania, New York, Maryland, Virginia and Ohio, are developing or have announced plans to develop state-specific regulations to control GHG emissions, including methane.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Dominion Energy cannot currently estimate the potential financial statement impacts related to these matters, but there could be a material impact to its financial condition and/or cash flows. In November 2019, the EPA released proposed revisions to the Effluent Limitations Guidelines rule that, if adopted, could extend the deadlines for compliance with certain standards at several facilities. While the impacts of this rule could be material to Dominion Energy’s 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.
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. The Dodd-Frank Act was enacted into law in July 2010 in an effort to improve regulation of financial markets. The CEA, as amended by Title VII of the Dodd-Frank Act, requires certain over-the counter derivatives, or swaps, to be cleared through a derivatives clearing organization and, if the swap is subject to a clearing requirement, to be executed on a designated contract market or swap execution facility. Non-financial entities that use swaps to hedge or mitigate commercial risk often referred to as end users, may elect the end-user exception to the CEA’s clearing requirements. Dominion Energy has 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. The 2020 General Assembly session in Virginia has included several proposals which, if ultimately enacted into law, could have a material impact on Dominion Energy’s operations, as well as impacts on regulatory cost recovery. Items under consideration include environmental requirements such as joining RGGI or meeting mandatory renewable portfolio standards that could result in both the need to develop new renewable electric generation facilities and the closure of certain existing electric generation facilities, expanded use of distributed renewable generation resources and additional requirements related to
demand side management programs. Additionally, legislation has been proposed which may affect Dominion Energy’s plans and/or cost recovery mechanisms for offshore wind development and replacing diesel school buses with electric school buses. Due to the evolving legislative process, Dominion Energy is unable to estimate the potential financial statement impacts related to matters currently under consideration by the Virginia General Assembly, but there could be a material impact to its results of operations, financial condition and/or cash flows.
In September 2014, Dominion Energy, along with Duke and Southern, announced the formation of Atlantic Coast Pipeline. Atlantic Coast Pipeline is focused on constructing an approximately600-mile
natural gas pipeline running from West Virginia through Virginia to North Carolina. Atlantic Coast Pipeline has continued to experience delays in obtaining and/or maintaining permits necessary for construction along with construction delays due to judicial actions. In February 2020, the Supreme Court of the U.S. heard oral arguments in Atlantic Coast Pipeline’s case regarding the Appalachian Trail crossing and is expected to issue a ruling by June 2020. If a favorable ruling is not received, Atlantic Coast Pipeline is also evaluating possible legislative and administrative remedies to this issue. Given the legal challenges and ongoing discussions with customers, project construction is expected to be completed by the end of 2021, with fullin-service
in early 2022, with project costs estimated to be approximately $8 billion, excluding financing costs. Atlantic Coast Pipeline has reached agreements in principle with major customers to amend the contracted rate to share in certain delay cost increases, pending certain regulatory approvals. Project construction activities, schedules and costs are 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 cost or schedule modifications in the future, a suspension of AFUDC for Atlantic Coast Pipeline and/or impairment charges potentially material to Dominion Energy’s cash flows, financial position and/or results of operations. See Note 9 to the Consolidated Financial Statements for more information.Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna. If Virginia Power decides to build a new unit, it would require a Combined Construction Permit and Operating License from the NRC, approval of the Virginia Commission and certain environmental permits and other approvals. In June 2017, the NRC issued the Combined Construction Permit and Operating License. Virginia Power has not yet committed to building a new nuclear unit at North Anna. Federal Income Tax Laws Under existing law, the Companies utilize a financial reporting method that classifies and recognizes investment tax credits on nonregulated operations as immediate reductions to income tax expense and, therefore, immediate increases in earnings. This immediate earnings benefit provides a significant incentive for renewable energy development. Provisions in recently proposed federal legislation would allow taxpayers to elect direct payment for investment tax credits. While effective from a cash flow perspective, this option may not provide the same level of incentive due to the financial reporting potentially applicable to the proposed direct pay benefits and “refundable” tax credits, regardless of whether such an option is selected by the taxpayer. Because the investment tax credit could be received as a direct payment under this proposed legislation, Dominion Energy may be required to either report the benefit ratably over the life of the qualifying facility or over the five-year recapture period. Either of these alternatives may be required instead of maintaining our historical financial reporting method regardless of whether we elect the direct pay option. If this legislation is enacted into law, the application of these alternative accounting methodologies could have a material impact on the Companies’ future results of operations, financial condition and/or cash flows.
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
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 Companies’ exposure to foreign currency exchange rate risk is related to certain fixed price contracts entered into in 2021 in connection with the CVOW Commercial Project. The contracts include services denominated in currencies other than the U.S. dollar for approximately €2.6 billion and 5.1 billion kr. In addition, certain of the fixed price contracts, approximately €0.7 billion, contain commodity indexing provisions linked to steel. As a result, any changes in applicable exchange rates or commodity indices could result in a change to the ultimate cost of the project. Virginia Power is evaluating hedging strategies, subject to approval by the Virginia Commission, to mitigate such risk.The following sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10% change in commodity prices or interest rates. To manage price risk, Dominion Energy and Virginia Powerthe Companies hold commodity-based derivative instruments held for non-trading purposes associated with purchases and sales of electricity, natural gas and other energy-related products. 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% increase in commodity prices would have resulted in a decrease of $16 million and $3 million in the fair value of Dominion Energy’s commodity-based derivative instruments as of December 31, 2021 and 2020, respectively. A hypothetical 10% increase in commodity prices would have resulted in a decrease of $6 million in the fair value of Virginia Power’s commodity-based derivative instruments as of December 31, 2021. A hypothetical 10% decrease in commodity prices would have resulted in a decrease of $35 million in the fair value of $50 million and $6 million of Dominion Energy’sVirginia Power’s commodity-based derivative instruments as of December 31, 2019 and December 31, 2018, respectively. A hypothetical 10% decrease in commodity prices 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, 2019 and December 31, 2018, respectively.
2020.The impact of a change in energy commodity prices on the Companies’ commodity-based derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net losses from commodity-based financial derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction, such as revenue from physical sales of the commodity. 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 resulted in a material change in earnings at December 31, 2019 and would have resulted in a $24 million decrease in earnings at December 31, 2018. For variable rate debt outstanding for Virginia Power, a hypothetical 10% increase in market interest rates would not have resulted in a material change in earnings at December 31, 20192021 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 and would have resulted in a $16 million decrease in earnings at December 31, 2018. 2020.The Companies also use interest rate derivatives, including forward-starting swaps, interest rate swaps and interest rate lock agreements to manage interest rate risk. As of December 31, 2019,2021, Dominion Energy and Virginia Power and Dominion Energy Gas had $6.4 billion, $1.9$11.4 billion and $1.3$2.8 billion, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $135 million, $88$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, 2019.2021. As of December 31, 2018,2020, Dominion Energy and Virginia Power and Dominion Energy Gas had $6.6 billion, $1.9$6.9 billion and $1.4$2.1 billion, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $142 million, $94$124 million and $17$75 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. Dominion Energy Gas holds foreign currency swaps with the purpose of hedging the foreign currency exchange risk associated with Euro denominated debt. As of December 31, 2019 and December 31, 2018, Dominion Energy and Dominion Energy Gas had€
250 million in aggregate notional amounts of these foreign currency swaps outstanding. A hypothetical 10% decrease in market interest rates would not have resulted in a material decrease in fair value of Dominion Energy Gas’ foreign currency swaps at December 31, 2019 and would have resulted in a decrease of $8 million in the fair value of Dominion Energy Gas’ foreign currency swaps at December 31, 2018.2020.The impact of a change in interest rates on the Companies’ interest rate-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net gains and/or losses from interest rate derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction. Dominion Energy and Virginia PowerThe 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
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
investment managers. These trust funds primarily hold marketable securities that are reported in the Consolidated Balance Sheets at fair value. Dominion Energy recognized net investment gains (including investment income) on nuclear decommissioning and rabbi trust investments of $1$1.1 billion and $0.7 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, 2018.2021 and 2020, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Dominion Energy recorded, in AOCI and regulatory liabilities, a net decrease in unrealized gains on debt investments of $64 million and a net increase in unrealized gains on debt investments of $74$57 million for the yearyears ended December 31, 20192021 and recorded a net decrease in unrealized gains on debt investments of $36 million for the year ended December 31, 2018. 2020, respectively.Virginia Power recognized net investment gains (including investment income) on nuclear decommissioning trust investments of $481$568 million and $287 million for the yearyears ended December 31, 2019. Virginia Power recognized net investment losses (including investment income) on nuclear decommissioning trust investments of $44 million for the year ended December 31, 2018.2021 and 2020, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Virginia Power recorded, in AOCI and regulatory liabilities, a net decrease in unrealized gains on debt investments of $31 million and a net increase in unrealized gains on debt investments of $30$29 million for the yearyears ended December 31, 20192021 and recorded a net decrease in unrealized gains on debt investments of $21 million for the year ended December 31, 2018. 2020, respectively.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$1.5 billion and $(605) million$1.9 billion in 20192021 and 2018,2020, respectively, versus expected returns of $848 million$1.0 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$933 million, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans. A hypothetical 0.25% decrease in the assumed long-term rates of return on Dominion Energy’s plan assets would result in an increase in net periodic cost of $23$27 million and $19$25 million as of December 31, 20192021 and 2018,2020, respectively, for pension benefits and $5$6 million and $4$5 million as of December 31, 20192021 and 2018,2020, respectively, for other postretirement benefits. A hypothetical 0.25% decrease in the assumed long-term rates of return on Dominion Energy Gas’ plan assets, for employees represented by collective bargaining units, would result in an increase in net periodic cost of $2 million and $4 million as of December 31, 2019 and 2018, respectively, for pension benefits and $1 million as of December 31, 2018 for other postretirement benefits. This hypothetical decrease would result in an immaterial change in net periodic cost to Dominion Energy Gas for other postretirement benefits as of December 31, 2019. 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, 20192021 provision for credit losses, management believes that it is unlikely that a material adverse effect on the Companies’ financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.
Item 8. Financial Statements and Supplementary Data | | | | | | | | | | | | | | | | | | | | (PCAOB ID No. 34) | | | | 81 | | | | | 83 | | | | | 84 | | | | | 85 | | | | | 87 | | | | | 88 | | | | | | Virginia Electric and Power Company | | | | | | (PCAOB ID No. 34) | | | | 89 | | | | | 91 | | | | | 92 | | | | | 93 | | | | | 95 | | | | | 96 | | | | | | Dominion Energy Gas Holdings, LLC
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Report of Independent RegisteredPublic Accounting Firm
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, 20192021 and 2018,2020, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2019,2021, 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, 20192021 and 2018,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2021, in conformity with accounting principles generally accepted in the United States of America. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), Dominion Energy’sEnergy's internal control over financial reporting at December 31, 2019,2021, based on criteria established in Internal Control—Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2020,24, 2022, expressed an unqualified opinion on Dominion Energy’sEnergy's internal control over financial reporting. 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. MatterThe critical audit mattersmatter communicated below are mattersis a matter arising from the current-period audit of the financial statements that werewas communicated or required to be communicated to the audit committee and that (1) relaterelates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit mattersmatter below, providing a separate opinionsopinion on the critical audit mattersmatter or on the accounts or disclosures to which they relate. Investments—Equity Method Investment Impairment Evaluation—Refer to Note 9 to the Consolidated Financial Statements
Critical Audit Matter Description
The investment balance of Dominion Energy’s equity method investment in Atlantic Coast Pipeline, LLC (“Atlantic Coast Pipeline”) was $1.1 billion at December 31, 2019. The Atlantic Coast Pipeline project is 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 Federal Energy Regulatory Commission (“FERC”) order approving the Certificate of Public Convenience and Necessity. The delays in obtaining and maintaining permits necessary for construction along with construction delays due to judicial actions have impacted the cost and schedule for the Atlantic Coast Pipeline project; project construction is expected to be completed by the end of 2021, with fullin-service
in early 2022 with project costs estimated to be approximately $8 billion, excluding financing costs. Atlantic Coast Pipeline has reached agreements in principle with major customers to amend the contracted rate to share in certain delay cost increases, pending certain regulatory approvals.Dominion Energy evaluated the carrying amount of its equity method investment in Atlantic Coast Pipeline for an other-than-temporary impairment and determined that it was not impaired. The estimation of the fair value of Dominion Energy’s investment in Atlantic Coast Pipeline, contained in the other-than-temporary impairment evaluation, involved significant judgments related to the resolution of outstanding permitting issues within the project timeframe and the likelihood of obtaining amended contacts with the customers.
Auditing management’s judgments regarding the resolution of outstanding permitting issues within the project timeframe and the likelihood of obtaining amended contacts with the customers involved especially subjective and complex judgment.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to this critical audit matter included the following, among others:
We tested the effectiveness of controls over management’s impairment analysis, including determination of the judgments regarding the resolution of the outstanding permitting issues within the project timeframe and the likelihood of obtaining amended contacts with the customers.
We evaluated the reasonableness of management’s permitting, project timeframe, and customer contract assumptions by:
Assessing the reasonableness of management’s plans to resolve outstanding permitting issues and the corresponding impact on project timeframes by inquiring with legal counsel and executive management and considering other potential outcomes.
Assessing the reasonableness of the various projectedin-service
dates by inquiring with Atlantic Cost Pipeline’s project managers and engineers and comparing thein-service
dates to the project’s timeframe.Obtaining and reading correspondence between Atlantic Coast Pipeline and the third-party pipeline construction contractor regarding the feasibility of the various projectedin-service
dates assumed by management.Obtaining and reading correspondence, including draft terms, between Atlantic Coast Pipeline and major customers.
Searching for disconfirming evidence by listening to earnings calls, reading press releases, news articles and other publicly available information.
We read and analyzed the minutes of the Board of Managers of Atlantic Coast Pipeline for discussions of changes in legal, regulatory, or business factors which could impact management’s assumptions of the resolution of the outstanding permitting issues within the project timeframe and the likelihood of obtaining amended contacts with the customers.
Preferred Stock—2019 Corporate Units—Refer to Notes 8 & 19 to the Consolidated Financial Statements
Critical Audit Matter Description
In June 2019, Dominion Energy issued $1.6 billion of 2019 Equity Units, initially in the form of 2019 Series A Corporate Units (the “2019 Equity Units”). Each 2019 Series A Corporate Unit consists of a stock purchase contract and a 1/10, or 10% undivided beneficial ownership interest in one share of Series A Preferred Stock. Beginning in June 2022, the Series A Preferred Stock is convertible at the option of the holder into Dominion Energy common stock under a formula based upon the average closing price of Dominion Energy common stock prior to the conversion date. The Series A Preferred Stock is redeemable in cash by Dominion Energy beginning September 2022 at the liquidation preference. Settlement of any conversion is payable in cash, common stock, or a combination thereof, at Dominion Energy’s election.
The stock purchase contracts obligate the holders to purchase shares of Dominion Energy common stock in June 2022. The purchase price to be paid under the stock purchase contracts is $100 per Corporate Unit and the number of shares to be purchased will be determined under a formula based on the average closing price of Dominion Energy common stock near the settlement date. The Series A Preferred Stock was pledged upon issuance as collateral to secure the purchase of common stock under the related stock purchase contracts. Dominion Energy identified no items that should be recorded as derivative instruments and
recorded the present value of the stock purchase contract payments as a liability offset to common stock and has recorded the Series A Preferred Stock within equity.
Given the complexity of the 2019 Equity Units structure and the judgments involved in applying the relevant accounting standards, auditing management’s conclusions on the balance sheet classification of the 2019 Equity Units involved the need for specialized skill and knowledge.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to this critical audit matter included the following, among others:
We tested the effectiveness of controls over management’s technical accounting assessment of the balance sheet classification of the components of the 2019 Equity Units.
We read the applicable agreements and compared the key terms from the agreements to management’s analysis of the transaction.
With the assistance of professionals in our firm having expertise in accounting for debt and equity instruments, we evaluated management’s conclusions regarding the balance sheet classification of the components of the 2019 Equity Units through evaluation of the terms within the applicable agreements and considering the applicable generally accepted accounting standards.
We evaluated Dominion Energy’s disclosures related to the financial statement impacts of the transaction.
relates.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; 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 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
ROE prospectively. Under certain circumstances, Virginia Power may be required to refundcredit a portion of its earnings to customers. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds or other benefits through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Dominion Energy evaluates whether recovery of its regulatory assets through future rates is probable as well as whether a regulatory liability due to customers is probable and makes various assumptions in its analyses. These analyses are generally based on orders issued by regulatory commissions, legislation and judicial actions; past experience; discussions with applicable regulatory authorities and legal counsel; forecasted earnings; and considerations around the likelihood of impacts from events such as unusual weather conditions, extreme weather events, and other natural disasters, and unplanned outages of facilities. We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about the financial statement impacts of rate regulation. Management judgments include assessing the likelihood of (1) recovery of its regulatory assets through future rates and (2) whether a regulatory liability is due to customers. Given management’s accounting judgments are based on assumptions about the outcome of future decisions by the relevant commissions, auditing these judgments required specialized knowledge of the accounting for rate regulation and the rate setting process due to its inherent complexities. How the Critical Audit Matter Was Addressed in the Audit Our audit procedures related to the assessment of whether recovery of regulatory assets through future rates or a regulatory liability due to customers is probable included the following, among others: | • | We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) recovery of regulatory assets through future rates, and (2) whether a regulatory liability is due to customers. We also tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities; and the monitoring and evaluation of regulatory and legislative developments that may impact the assessment of whether recovery of regulatory assets through future rates or a regulatory liability due to customers is probable. |
We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) recovery of regulatory assets through future rates, and (2) whether a regulatory liability is due to customers. We also tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may impact the assessment of whether recovery of regulatory assets through future rates or a regulatory liability due to customers is probable. | • | We evaluated Dominion Energy’s disclosures related to the financial statement impacts of rate regulation. |
| • | We read and evaluated orders issued by the relevant commissions, as well as relevant regulatory statutes, interpretations, procedural memorandums, filings made by interveners, existing laws and other publicly available information to assess whether this external information was properly considered by management in concluding upon the financial statement impacts of rate regulation. |
| • | We considered the likelihood of (1) recovery of regulatory assets through future rates and (2) whether a regulatory liability is due to customers based on precedents established by the relevant commissions’ previous orders and Dominion Energy’s past experience with the relevant commissions. |
| • | For regulatory matters in process, we inspected associated documents and testimony filed with the relevant commissions for any evidence that might contradict management’s assertions. |
We evaluated Dominion Energy’s disclosures related | • | We read and analyzed the minutes of the Boards of Directors of Dominion Energy and Dominion Energy’s rate-regulated subsidiaries for discussions of changes in legal, regulatory, or business factors which could impact management’s conclusions with respect to the consolidated financial statement impacts of rate regulation. |
We read and evaluated orders issued by the relevant commissions, as well as relevant regulatory statutes, interpretations, procedural memorandums, filings made by interveners, existing laws and other publicly available information to assess whether this external information was properly considered by management in concluding upon the financial statement impacts of rate regulation.
We considered the likelihood of (1) recovery of regulatory assets through future rates and (2) whether a regulatory liability is due to customers based on precedence established by the relevant commissions’ previous orders and Dominion Energy’s past experience with the relevant commissions.
For regulatory matters in process, we inspected associated documents and testimony filed with the relevant commissions for any evidence that might contradict management’s assertions.
We read and analyzed the minutes of the Boards of Directors of Dominion Energy and Dominion Energy’s rate-regulated subsidiaries for discussions of changes in legal, regulatory, or business factors which could impact management’s conclusions with respect to the financial statement impacts of rate regulation.
/s/ Deloitte & Touche LLP 24, 2022We have served as Dominion Energy’s auditor since 1988.
Consolidated Statements of Income Year Ended December 31, | | 2021 | | | 2020 | | | 2019 | | (millions, except per share amounts) | | | | | | | | | | | | | Operating Revenue | | $ | 13,964 | | | $ | 14,172 | | | $ | 14,401 | | Operating Expenses | | | | | | | | | | | | | Electric fuel and other energy-related purchases | | | 2,368 | | | | 2,243 | | | | 2,885 | | Purchased electric capacity | | | 70 | | | | 53 | | | | 88 | | Purchased gas | | | 1,083 | | | | 889 | | | | 1,560 | | Other operations and maintenance | | | 3,734 | | | | 3,685 | | | | 3,790 | | Depreciation, depletion and amortization | | | 2,478 | | | | 2,332 | | | | 2,283 | | Other taxes | | | 909 | | | | 871 | | | | 883 | | Impairment of assets and other charges | | | 195 | | | | 2,105 | | | | 1,520 | | Losses (gains) on sales of assets | | | 108 | | | | (61 | ) | | | (152 | ) | Total operating expenses | | | 10,945 | | | | 12,117 | | | | 12,857 | | Income from operations | | | 3,019 | | | | 2,055 | | | | 1,544 | | Earnings from equity method investees | | | 276 | | | | 40 | | | | 8 | | Other income | | | 1,157 | | | | 693 | | | | 803 | | Interest and related charges | | | 1,354 | | | | 1,377 | | | | 1,486 | | Income from continuing operations including noncontrolling interests before income tax expense | | | 3,098 | | | | 1,411 | | | | 869 | | Income tax expense | | | 425 | | | | 83 | | | | 209 | | Net Income From Continuing Operations Including Noncontrolling Interests | | | 2,673 | | | | 1,328 | | | | 660 | | Net Income (Loss) From Discontinued Operations Including Noncontrolling Interests(1)(2) | | | 641 | | | | (1,878 | ) | | | 716 | | Net Income (Loss) Including Noncontrolling Interests | | | 3,314 | | | | (550 | ) | | | 1,376 | | Noncontrolling Interests | | | 26 | | | | (149 | ) | | | 18 | | Net Income (Loss) Attributable to Dominion Energy | | $ | 3,288 | | | $ | (401 | ) | | $ | 1,358 | | Amounts attributable to Dominion Energy | | | | | | | | | | | | | Net income from continuing operations | | $ | 2,647 | | | $ | 1,583 | | | $ | 653 | | Net income (loss) from discontinued operations | | | 641 | | | | (1,984 | ) | | | 705 | | Net income (loss) attributable to Dominion Energy | | $ | 3,288 | | | $ | (401 | ) | | $ | 1,358 | | EPS - Basic | | | | | | | | | | | | | Net income from continuing operations | | $ | 3.19 | | | $ | 1.83 | | | $ | 0.79 | | Net income (loss) discontinued operations | | | 0.79 | | | | (2.39 | ) | | | 0.87 | | Net income (loss) attributable to Dominion Energy | | $ | 3.98 | | | $ | (0.56 | ) | | $ | 1.66 | | EPS - Diluted | | | | | | | | | | | | | Net income from continuing operations | | $ | 3.19 | | | $ | 1.82 | | | $ | 0.75 | | Net income (loss) discontinued operations | | | 0.79 | | | | (2.39 | ) | | | 0.87 | | Net income (loss) attributable to Dominion Energy | | $ | 3.98 | | | $ | (0.57 | ) | | $ | 1.62 | |
| | | | | | | | | | | | | | | | | | | | | | | | (millions, except per share amounts) | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | | | | | | | | | | | | | Electric fuel and other energy-related purchases | | | | | | | | | | | | | Purchased electric capacity | | | | | | | | | | | | | | | | | | | | | | | | | | Other operations and maintenance | | | | | | | | | | | | | Depreciation, depletion and amortization | | | | | | | | | | | | | | | | | | | | | | | | | | Impairment of assets and related charges | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Interest and related charges | | | | | | | | | | | | | Income from operations including noncontrolling interests before income tax expense (benefit) | | | | | | | | | | | | | Income tax expense (benefit) | | | | | | | | | | | | ) | Net Income Including Noncontrolling Interests | | | | | | | | | | | | | | | | | | | | | | | | | | Net Income Attributable to Dominion Energy | | $ | | | | $ | | | | $ | | | Earnings Per Common Share | | | | | | | | | | | | | Net income attributable to Dominion Energy—Basic | | $ | | | | $ | | | | $ | | | Net income attributable to Dominion Energy—Diluted | | $ | | | | $ | | | | $ | | |
(1) | See Note 9 for amounts attributable to related parties.parties. |
(2) | Includes income tax expense (benefit) of $188 million, $(204) million and $142 million for the years ended December 31, 2021, 2020 and 2019, respectively. |
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
Consolidated Statements of Comprehensive Income Year Ended December 31, | | 2021 | | | 2020 | | | 2019 | | (millions) | | | | | | | | | | | | | Net income (loss) including noncontrolling interests | | $ | 3,314 | | | $ | (550 | ) | | $ | 1,376 | | Other comprehensive income (loss), net of taxes: | | | | | | | | | | | | | Net deferred gains (losses) on derivatives-hedging activities, net of $(6), $81 and $35 tax | | | 15 | | | | (239 | ) | | | (110 | ) | Changes in unrealized net gains (losses) on investment securities, net of $7, $(14) and $(14) tax | | | (7 | ) | | | 43 | | | | 39 | | Changes in net unrecognized pension and other postretirement benefit costs, net of $(54), $(2) and $(4) tax | | | 144 | | | | 25 | | | | (22 | ) | Amounts reclassified to net income (loss): | | | | | | | | | | | | | Net derivative (gains) losses-hedging activities, net of $(15), $(75) and $21 tax | | | 46 | | | | 227 | | | | (62 | ) | Net realized (gains) losses on investment securities, net of $5, $6 and $1 tax | | | (18 | ) | | | (18 | ) | | | (4 | ) | Net pension and other postretirement benefit costs, net of $(29), $(13) and $(23) tax | | | 82 | | | | 37 | | | | 66 | | Changes in other comprehensive income from equity method investees, net of $1, $(1) and $— tax | | | (3 | ) | | | 1 | | | | — | | Total other comprehensive income (loss) | | | 259 | | | | 76 | | | | (93 | ) | Comprehensive income (loss) including noncontrolling interests | | | 3,573 | | | | (474 | ) | | | 1,283 | | Comprehensive income (loss) attributable to noncontrolling interests | | | 26 | | | | (149 | ) | | | 18 | | Comprehensive income (loss) attributable to Dominion Energy | | $ | 3,547 | | | $ | (325 | ) | | $ | 1,265 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net Income Including Noncontrolling Interests | | $ | | | | $ | | | | $ | | | Other comprehensive income (loss), net of taxes: | | | | | | | | | | | | | Net deferred gains (losses) on derivatives-hedging activities, net of $35, $(10) and $(3) tax | | | | ) | | | | | | | | | Changes in unrealized net gains (losses) on investment securities, net of $(14), $5 and $(121) tax | | | | | | | | ) | | | | | Changes in net unrecognized pension and other postretirement benefit costs, net of $(4), $75 and $32 tax | | | | ) | | | | ) | | | | ) | Amounts reclassified to net income: | | | | | | | | | | | | | Net derivative (gains) losses-hedging activities, net of $21, $(35) and $18 tax | | | | ) | | | | | | | | ) | Net realized (gains) losses on investment securities, net of $1, $(2) and $21 tax | | | | ) | | | | | | | | ) | Net pension and other postretirement benefit costs, net of $(23), $(21) and $(32) tax | | | | | | | | | | | | | Changes in other comprehensive gains (losses) from equity method investees, net of $—, $(1) and $(2) tax | | | | | | | | | | | | | Total other comprehensive income (loss) | | | | ) | | | | ) | | | | | Comprehensive income including noncontrolling interests | | | | | | | | | | | | | Comprehensive income attributable to noncontrolling interests | | | | | | | | | | | | | Comprehensive income attributable to Dominion Energy | | $ | | | | $ | | | | $ | | |
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
Consolidated Balance Sheets At December 31, | | 2021 | | | 2020 | | (millions) | | | | | | | | | ASSETS | | | | | | | | | Current Assets | | | | | | | | | Cash and cash equivalents | | $ | 283 | | | $ | 172 | | Customer receivables (less allowance for doubtful accounts of $40 and $42) | | | 2,219 | | | | 2,295 | | Other receivables (less allowance for doubtful accounts of $4 and $3) | | | 349 | | | | 212 | | Inventories: | | | | | | | | | Materials and supplies | | | 1,167 | | | | 1,105 | | Fossil fuel | | | 320 | | | | 349 | | Gas stored | | | 144 | | | | 96 | | Margin deposit assets | | | 678 | | | | 19 | | Prepayments | | | 328 | | | | 309 | | Regulatory assets | | | 1,492 | | | | 699 | | Other | | | 264 | | | | 148 | | Current assets held for sale(1) | | | 25 | | | | 1,482 | | Total current assets | | | 7,269 | | | | 6,886 | | Investments | | | | | | | | | Nuclear decommissioning trust funds | | | 7,950 | | | | 6,900 | | Investment in equity method affiliates | | | 2,932 | | | | 2,934 | | Other | | | 394 | | | | 404 | | Total investments | | | 11,276 | | | | 10,238 | | Property, Plant and Equipment | | | | | | | | | Property, plant and equipment | | | 86,503 | | | | 82,959 | | Accumulated depreciation, depletion and amortization | | | (26,729 | ) | | | (25,111 | ) | Total property, plant and equipment, net | | | 59,774 | | | | 57,848 | | Deferred Charges and Other Assets | | | | | | | | | Goodwill | | | 7,405 | | | | 7,381 | | Pension and other postretirement benefit assets | | | 2,310 | | | | 1,704 | | Intangible assets, net | | | 784 | | | | 765 | | Regulatory assets | | | 8,643 | | | | 9,133 | | Other | | | 2,129 | | | | 1,950 | | Total deferred charges and other assets | | | 21,271 | | | | 20,933 | | Total assets | | $ | 99,590 | | | $ | 95,905 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash and cash equivalents | | $ | | | | $ | | | Customer receivables (less allowance for doubtful accounts of $20 and $14) | | | | | | | | | Other receivables (less allowance for doubtful accounts of $3 and $4 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Nuclear decommissioning trust funds | | | | | | | | | Investment in equity method affiliates | | | | | | | | | | | | | | | | | | | | | | | | | | | Property, Plant and Equipment | | | | | | | | | Property, plant and equipment | | | | | | | | | Accumulated depreciation, depletion and amortization | | | | ) | | | | ) | Total property, plant and equipment, net | | | | | | | | | Deferred Charges and Other Assets | | | | | | | | | | | | | | | | | | Pension and other postretirement benefit assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total deferred charges and other assets | | | | | | | | | | | $ | | | | $ | | |
(1) | See Note 9 for amounts attributable to related parties.parties. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Securities due within one year | | $ | | | | $ | | | Credit facility borrowings | | | | | | | | | | | | | | | | | | | | | | | | | | | Accrued interest, payroll and taxes | | | | | | | | | | | | | | | | | | Reserves for SCANA legal proceedings | | | | | | | | | | | | | | | | | | Total current liabilitie s | | | | | | | | | | | | | | | | | | | | | | | | | | | Junior subordinated notes | | | | | | | | | Remarketable subordinated notes | | | | | | | | | | | | | | | | | | | | | | | | | | | Deferred Credits and Other Liabilities | | | | �� | | | | | Deferred income taxes and investment tax credits | | | | | | | | | | | | | | | | | | Asset retirement obligations | | | | | | | | | Pension and other postretirement benefit liability | | | | | | | | | | | | | | | | | | Total deferred credits and other liabilities | | | | | | | | | | | | | | | | | | Commitments and Contingencies (see Note 23) | | | | | | | | | | | | | | | | | | | Preferred stock (See Note 19) | | | | | | | | | | | | | | | | | | | | | | | | | | | Accumulated other comprehensive loss | | | | ) | | | | ) | Total shareholders’ equity | | | | | | | | | | | | | | | | | | | | | | | | | | | Total liabilities and equity | | $ | | | | $ | | |
(1) | See Note 9 for amounts attributable to related parties. |
(2) | 1.8 billion shares authorized; 838 million shares and 681 million shares outstanding at December 31, 2019 and 2018, respectively. |
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
At December 31, | | 2021 | | | 2020 | | (millions) | | | | | | | | | LIABILITIES, MEZZANINE EQUITY AND SHAREHOLDERS' EQUITY | | | | | | | | | Current Liabilities | | | | | | | | | Securities due within one year | | $ | 841 | | | $ | 1,937 | | Supplemental 364-Day credit facility borrowings | | | — | | | | 225 | | Short-term debt | | | 2,314 | | | | 895 | | Accounts payable | | | 1,197 | | | | 944 | | Accrued interest, payroll and taxes | | | 1,169 | | | | 1,133 | | Regulatory liabilities | | | 986 | | | | 809 | | Liability to Atlantic Coast Pipeline | | | 113 | | | | 1,052 | | Q-Pipe Transaction deposit | | | — | | | | 1,290 | | Other(1) | | | 2,053 | | | | 1,933 | | Current liabilities held for sale | | | — | | | | 625 | | Total current liabilities | | | 8,673 | | | | 10,843 | | Long-Term Debt | | | | | | | | | Long-term debt | | | 35,190 | | | | 30,915 | | Junior subordinated notes | | | 1,386 | | | | 2,161 | | Other | | | 850 | | | | 881 | | Total long-term debt | | | 37,426 | | | | 33,957 | | Deferred Credits and Other Liabilities | | | | | | | | | Deferred income taxes and investment tax credits | | | 6,658 | | | | 5,953 | | Regulatory liabilities | | | 10,713 | | | | 10,187 | | Asset retirement obligations | | | 5,275 | | | | 5,404 | | Pension and other postretirement benefit liability | | | 442 | | | | 1,706 | | Other(1) | | | 1,485 | | | | 1,394 | | Total deferred credits and other liabilities | | | 24,573 | | | | 24,644 | | Total liabilities | | | 70,672 | | | | 69,444 | | Commitments and Contingencies (see Note 23) | | | | | | | | | Mezzanine Equity | | | | | | | | | Preferred stock (See Note 19) | | | 1,610 | | | | — | | Shareholders' Equity | | | | | | | | | Preferred stock (See Note 19) | | | 1,783 | | | | 2,387 | | Common stock – no par(2) | | | 21,610 | | | | 21,258 | | Retained earnings | | | 5,373 | | | | 4,189 | | Accumulated other comprehensive loss | | | (1,458 | ) | | | (1,717 | ) | Shareholders' equity | | | 27,308 | | | | 26,117 | | Noncontrolling interests | | | — | | | | 344 | | Total shareholders' equity | | | 27,308 | | | | 26,461 | | Total liabilities, mezzanine equity and shareholders' equity | | $ | 99,590 | | | $ | 95,905 | |
Consolidated Statements of Equity
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dominion Energy
Shareholders | | | | | | | | | | | | | | | | | | | | | | | | | | | | Accumulated
Other
Comprehensive
Income (Loss) | | | | | | | | | | | (millions except per share amounts) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | | | ) | | | | | | | | | | $ | | | Net income including noncontrolling interests | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Contributions from NRG to Four Brothers and Three Cedars | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Sale of Dominion Energy Midstream common units—net of offering costs | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Stock awards (net of change in unearned compensation) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dividends ($3.035 per common share) and distributions | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | ) | | | | ) | | | | ) | Other comprehensive income, net of tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | | | ) | | | | | | | | | | $ | | | Cumulative-effect of changes in accounting principles | | | | | | | | | | | | | | | | ) | | | | | | | | ) | | | | ) | | | | | | | | | Net income including noncontrolling interests | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Sale of Dominion Energy Midstream common units—net of offering costs | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Remeasurement of noncontrolling interest in Dominion Energy Midstream | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | Stock awards (net of change in unearned compensation) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dividends ($3.34 per common share) and distributions | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | ) | | | | ) | | | | ) | Other comprehensive income (loss), net of tax | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | | | | | ) | | | | | | | | | | | | | | | | | ) | | | | ) | | | | | | | | ) | | | | | | | | ) | | | | | | | | | | | | | | | $ | | | | $ | | | | | | ) | | | | | | | | | | $ | | | Net income including noncontrolling interests | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Stock purchase contract component of 2019 Equity Units | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | ) | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Acquisition of public interest in Dominion Energy Midstream | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | Sale of interest in Cove Point | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Stock awards (net of change in unearned compensation) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Preferred stock dividends (See Note 19) | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | ) | | | | | | | | ) | Common dividends ($3.67 per common share) and distributions | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | ) | | | | ) | | | | ) | Other comprehensive loss, net of tax | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | | | | | ) | | | | | | | | | | | | | | | | | ) | | | | ) | | | | | | | | ) | | | | | | | | ) | | | | | | | $ | | | | | | | | $ | | | | $ | | | | | | ) | | | | | | | | | | $ | | |
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements
Consolidated Statements of Cash Flows
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net income including noncontrolling interests | | $ | | | | $ | | | | $ | | | Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities: | | | | | | | | | | | | | Depreciation, depletion and amortization (including nuclear fuel) | | | | | | | | | | | | | Deferred income taxes and investment tax credits | | | | | | | | | | | | ) | Proceeds from assignment of tower rental portfolio | | | | | | | | | | | | | Contribution to pension plan | | | | ) | | | | | | | | ) | Provision for refunds and rate credits to electric utility customers | | | | | | | | | | | | | Impairment of assets and other charges | | | | | | | | | | | | | Charge related to a voluntary retirement program | | | | | | | | | | | | | Gains on sales of assets and equity method investments | | | | ) | | | | ) | | | | ) | Net (gains) losses on nuclear decommissioning trusts funds and other investments | | | | ) | | | | | | | | ) | | Charges associated with equity method investments | | | | | | | | | | | | | | Charge (revision) for future ash pond and landfill closure costs | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | | | | | ) | | | | ) | | | | | Deferred fuel and purchased gas costs, net | | | | | | | | ) | | | | ) | | | | | ) | | | | ) | | | | ) | | | | | ) | | | | | | | | ) | Accrued interest, payroll and taxes | | | | ) | | | | ) | | | | | | | | | ) | | | | | | | | | Margin deposit assets and liabilities | | | | | | | | | | | | ) | Net realized and unrealized changes related to derivative activities | | | | | | | | | | | | | Asset retirement obligations | | | | | | | | ) | | | | ) | Pension and other postretirement benefits | | | | ) | | | | ) | | | | ) | Other operating assets and liabilities | | | | ) | | | | | | | | ) | Net cash provided by operating activities | | | | | | | | | | | | | | | | | | | | | | | | | | Plant construction and other property additions (including nuclear fuel) | | | | ) | | | | ) | | | | ) | Cash and restricted cash acquired in the SCANA Combination | | | | | | | | | | | | | Acquisition of solar development projects | | | | ) | | | | ) | | | | ) | Proceeds from sales of securities | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | Proceeds from sales of assets and equity method investments | | | | | | | | | | | | | Contributions to equity method affiliates | | | | ) | | | | ) | | | | ) | Distributions from equity method affiliates | | | | | | | | | | | | | | | | | | | | | ) | | | | | Net cash used in investing activities | | | | ) | | | | ) | | | | ) | | | | | | | | | | | | | | Issuance (repayment) of short-term debt, net | | | | | | | | ) | | | | | Issuance of short-term notes | | | | | | | | | | | | | Repayment and repurchase of short-term notes | | | | ) | | | | ) | | | | ) | Credit facility borrowings | | | | | | | | | | | | | Repayment of credit facility borrowings | | | | | | | — | | | | — | | Issuance and remarketing of long-term debt | | | | | | | | | | | | | Repayment and repurchase of long-term debt (including redemption premiums) | | | | ) | | | | ) | | | | ) | Proceeds from sale of interest in Cove Point | | | | | | | | | | | | | Net proceeds from issuance of Dominion Energy Midstream common units | | | | | | | | | | | | | Issuance of 2019 Equity Units | | | | | | | | | | | | | Issuance of Series B Preferred Stock | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | | | | | ) | | | | ) | | | | ) | Net cash provided by (used in) financing activities | | | | ) | | | | ) | | | | | Increase (decrease) in cash, restricted cash and equivalents | | | | ) | | | | | | | | ) | Cash, restricted cash and equivalents at beginning of period | | | | | | | | | | | | | Cash, restricted cash and equivalents at end of period | | $ | | | | $ | | | | $ | | | Supplemental Cash Flow Information | | | | | | | | | | | | | Cash paid during the year for: | | | | | | | | | | | | | Interest and related charges, excluding capitalized amounts | | $ | | | | $ | | | | | | | | | | | | | | | | | | | | Significant noncash investing and financing activities: (1)(2)(3)(4)(5) | | | | | | | | | | | | | Accrued capital expenditures | | | | | | | | | | | | | | | | | | | | | | | | | | Receivables from sales of assets and equity method investments | | | | | | | | | | | | | Guarantee provided by equity method affiliate | | | | | | | | | | | | |
(1) | See Note 2 for noncash investing and financing activities related to the adoption of a new accounting standard for leasing arrangements. |
(2) | See Note 3 for noncash investing and financing activities related to the SCANA Combination. |
(3) | See Note 5 for noncash activities related to the sale of a noncontrolling interest in Cove Point. |
(4) | See Note 9 for noncash investing activities related to the acquisition of a noncontrolling interest in Wrangler. |
(5) | See Notes 18,19 and 20 for noncash financing activities related to the acquisition of the public interest in Dominion Energy Midstream, the remarketing of RSNs, the issuance of stock purchase contracts associated with the 2019 Equity Units and the contribution of stock to Dominion Energy’s qualified defined benefit pension plan.
|
| Includes $113 million of finance leases and $44 million of operating leases. |
(1) See Note 9 for amounts attributable to related parties. (2) 1.8 billion shares authorized; 810 million shares and 806 million shares outstanding at December 31, 2021 and 2020, respectively. The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
Dominion Energy, Inc. Consolidated Statements of Equity | | Preferred Stock | | | Common Stock | | | Dominion Energy Shareholders | | | | | | | | | | | | | | | | Shares | | | Amount | | | Shares | | | Amount | | | Retained Earnings | | | AOCI | | | Total Shareholders' Equity | | | Noncontrolling Interests | | | Total Equity | | (millions except per share amounts) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2018 | | | | | | | | | | | 681 | | | $ | 12,588 | | | $ | 9,219 | | | $ | (1,700 | ) | | $ | 20,107 | | | $ | 1,941 | | | $ | 22,048 | | Net income including noncontrolling interests | | | | | | | | | | | | | | | | | | | 1,358 | | | | | | | | 1,358 | | | | 18 | | | | 1,376 | | Issuance of stock | | | 2 | | | | 2,387 | | | | 39 | | | | 3,014 | | | | | | | | | | | | 5,401 | | | | | | | | 5,401 | | Stock purchase contract component of 2019 Equity Units | | | | | | | | | | | | | | | (264 | ) | | | | | | | | | | | (264 | ) | | | | | | | (264 | ) | Acquisition of SCANA | | | | | | | | | | | 96 | | | | 6,818 | | | | | | | | | | | | 6,818 | | | | | | | | 6,818 | | Acquisition of public interest in Dominion Energy Midstream | | | | | | | | | | | 22 | | | | 1,181 | | | | | | | | | | | | 1,181 | | | | (1,221 | ) | | | (40 | ) | Sale of interest in Cove Point | | | | | | | | | | | | | | | 476 | | | | | | | | | | | | 476 | | | | 1,386 | | | | 1,862 | | Stock awards (net of change in unearned compensation) | | | | | | | | | | | | | | | 24 | | | | | | | | | | | | 24 | | | | | | | | 24 | | Preferred stock dividends (See Note 19) | | | | | | | | | | | | | | | | | | | (17 | ) | | | | | | | (17 | ) | | | | | | | (17 | ) | Common dividends ($3.67 per common share) and distributions | | | | | | | | | | | | | | | | | | | (2,983 | ) | | | | | | | (2,983 | ) | | | (85 | ) | | | (3,068 | ) | Other comprehensive loss, net of tax | | | | | | | | | | | | | | | | | | | | | | | (93 | ) | | | (93 | ) | | | | | | | (93 | ) | Other | | | | | | | | | | | | | | | (13 | ) | | | (1 | ) | | | | | | | (14 | ) | | | | | | | (14 | ) | December 31, 2019 | | | 2 | | | $ | 2,387 | | | | 838 | | | $ | 23,824 | | | $ | 7,576 | | | $ | (1,793 | ) | | $ | 31,994 | | | $ | 2,039 | | | $ | 34,033 | | Cumulative-effect of changes in accounting principles | | | | | | | | | | | | | | | | | | | (48 | ) | | | | | | | (48 | ) | | | | | | | (48 | ) | Net loss including noncontrolling interests | | | | | | | | | | | | | | | | | | | (401 | ) | | | | | | | (401 | ) | | | (149 | ) | | | (550 | ) | Issuance of stock | | | | | | | | | | | 7 | | | | 481 | | | | | | | | | | | | 481 | | | | | | | | 481 | | Stock repurchases | | | | | | | | | | | (39 | ) | | | (3,080 | ) | | | | | | | | | | | (3,080 | ) | | | | | | | (3,080 | ) | Stock awards (net of change in unearned compensation) | | | | | | | | | | | | | | | 29 | | | | | | | | | | | | 29 | | | | | | | | 29 | | Preferred stock dividends (See Note 19) | | | | | | | | | | | | | | | | | | | (65 | ) | | | | | | | (65 | ) | | | | | | | (65 | ) | Common dividends ($3.45 per common share) and distributions | | | | | | | | | | | | | | | | | | | (2,873 | ) | | | | | | | (2,873 | ) | | | (164 | ) | | | (3,037 | ) | Other comprehensive income, net of tax | | | | | | | | | | | | | | | | | | | | | | | 76 | | | | 76 | | | | | | | | 76 | | GT&S Transaction closing | | | | | | | | | | | | | | | 17 | | | | | | | | | | | | 17 | | | | (1,384 | ) | | | (1,367 | ) | Other | | | | | | | | | | | | | | | (13 | ) | | | | | | | | | | | (13 | ) | | | 2 | | | | (11 | ) | December 31, 2020 | | | 2 | | | $ | 2,387 | | | | 806 | | | $ | 21,258 | | | $ | 4,189 | | | $ | (1,717 | ) | | $ | 26,117 | | | $ | 344 | | | $ | 26,461 | | Net income including noncontrolling interests | | | | | | | | | | | | | | | | | | | 3,288 | | | | | | | | 3,288 | | | | 26 | | | | 3,314 | | Issuance of stock | | | 1 | | | | 992 | | | | 4 | | | | 340 | | | | | | | | | | | | 1,332 | | | | | | | | 1,332 | | Stock awards (net of change in unearned compensation) | | | | | | | | | | | | | | | 28 | | | | | | | | | | | | 28 | | | | | | | | 28 | | Preferred stock dividends (See Note 19) | | | | | | | | | | | | | | | | | | | (68 | ) | | | | | | | (68 | ) | | | | | | | (68 | ) | Common dividends ($2.52 per common share) and distributions | | | | | | | | | | | | | | | | | | | (2,036 | ) | | | | | | | (2,036 | ) | | | (47 | ) | | | (2,083 | ) | Other comprehensive income, net of tax | | | | | | | | | | | | | | | | | | | | | | | 259 | | | | 259 | | | | | | | | 259 | | Reclassification of Series A Preferred Stock to Mezzanine Equity | | | (1 | ) | | | (1,596 | ) | | | | | | | (14 | ) | | | | | | | | | | | (1,610 | ) | | | | | | | (1,610 | ) | Sale of non-wholly-owned nonregulated solar facilities | | | | | | | | | | | | | | | | | | | | | | | | | | | — | | | | (323 | ) | | | (323 | ) | Other | | | | | | | | | | | | | | | (2 | ) | | | | | | | | | | | (2 | ) | | | | | | | (2 | ) | December 31, 2021 | | | 2 | | | $ | 1,783 | | | | 810 | | | $ | 21,610 | | | $ | 5,373 | | | $ | (1,458 | ) | | $ | 27,308 | | | $ | — | | | $ | 27,308 | |
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ReportThe accompanying notes are an integral part of Independent Registered Public Accounting FirmDominion Energy’s Consolidated Financial Statements.
Dominion Energy, Inc. Consolidated Statements of Cash Flows Year Ended December 31, | | 2021 | | | 2020 | | | 2019 | | (millions) | | | | | | | | | | | | | Operating Activities | | | | | | | | | | | | | Net income (loss) including noncontrolling interests | | $ | 3,314 | | | $ | (550 | ) | | $ | 1,376 | | Adjustments to reconcile net income (loss) including noncontrolling interests to net cash provided by operating activities: | | | | | | | | | | | | | Depreciation, depletion and amortization (including nuclear fuel) | | | 2,768 | | | | 2,836 | | | | 2,977 | | Deferred income taxes and investment tax credits | | | 487 | | | | (324 | ) | | | 216 | | Gain from sale of Q-Pipe Group and GT&S Transaction | | | (685 | ) | | | (134 | ) | | | — | | Contribution to pension plan | | | — | | | | (250 | ) | | | (21 | ) | Net loss on sale of interest in renewable generation facilities | | | 211 | | | | — | | | | — | | Provision for refunds and rate credits to electric utility customers | | | 356 | | | | — | | | | 800 | | Impairment of assets and other charges | | | 182 | | | | 2,345 | | | | 1,333 | | Loss from investment in Atlantic Coast Pipeline | | | 20 | | | | 2,405 | | | | — | | Charges related to a voluntary retirement program | | | — | | | | — | | | | 320 | | Gains on sales of assets and equity method investments | | | (97 | ) | | | (63 | ) | | | (167 | ) | Net (gains) losses on nuclear decommissioning trusts funds and other investments | | | (639 | ) | | | (412 | ) | | | (626 | ) | Charge (revision) for future ash pond and landfill closure costs | | | — | | | | 11 | | | | (113 | ) | Other adjustments | | | 294 | | | | 213 | | | | 29 | | Changes in: | | | | | | | | | | | | | Accounts receivable | | | (183 | ) | | | (292 | ) | | | (105 | ) | Inventories | | | (74 | ) | | | 39 | | | | (90 | ) | Deferred fuel and purchased gas costs, net | | | (939 | ) | | | 212 | | | | 195 | | Prepayments | | | (20 | ) | | | 7 | | | | (225 | ) | Accounts payable | | | 156 | | | | 35 | | | | (225 | ) | Accrued interest, payroll and taxes | | | 41 | | | | (53 | ) | | | (78 | ) | Customer deposits | | | (24 | ) | | | (13 | ) | | | (101 | ) | Margin deposit assets and liabilities | | | (664 | ) | | | 26 | | | | 60 | | Net realized and unrealized changes related to derivative activities | | | 435 | | | | (36 | ) | | | 43 | | Pension and other postretirement benefits | | | (314 | ) | | | (319 | ) | | | (148 | ) | Other operating assets and liabilities | | | (588 | ) | | | (456 | ) | | | (246 | ) | Net cash provided by operating activities | | | 4,037 | | | | 5,227 | | | | 5,204 | | Investing Activities | | | | | | | | | | | | | Plant construction and other property additions (including nuclear fuel) | | | (5,960 | ) | | | (6,020 | ) | | | (4,980 | ) | Cash and restricted cash acquired in the SCANA Combination | | | — | | | | — | | | | 389 | | Acquisition of solar development projects | | | (101 | ) | | | (311 | ) | | | (341 | ) | Proceeds from GT&S Transaction and sale of Q-Pipe Group | | | 1,522 | | | | 3,687 | | | | — | | Repayment of Q-Pipe Transaction deposit | | | (1,265 | ) | | | — | | | | — | | Proceeds from sale of non-wholly-owned nonregulated solar facilities | | | 495 | | | | — | | | | — | | Proceeds from sales of securities | | | 3,985 | | | | 4,278 | | | | 1,712 | | Purchases of securities | | | (3,939 | ) | | | (4,379 | ) | | | (1,749 | ) | Proceeds from sales of assets and equity method investments | | | 159 | | | | 143 | | | | 447 | | Contributions to equity method affiliates | | | (1,021 | ) | | | (148 | ) | | | (209 | ) | Acquisition of equity method investments | | | — | | | | (178 | ) | | | — | | Other | | | (122 | ) | | | 12 | | | | 109 | | Net cash used in investing activities | | | (6,247 | ) | | | (2,916 | ) | | | (4,622 | ) | Financing Activities | | | | | | | | | | | | | Issuance (repayment) of short-term debt, net | | | 1,419 | | | | (16 | ) | | | 404 | | Issuance of short-term notes | | | 1,265 | | | | 1,125 | | | | 3,000 | | Repayment and repurchase of short-term notes | | | (1,265 | ) | | | (1,125 | ) | | | (3,000 | ) | Supplemental 364-day credit facility borrowings | | | — | | | | 225 | | | | — | | Supplemental 364-day credit facility repayments | | | (225 | ) | | | — | | | | — | | Credit facility borrowings (repayments) | | | — | | | | — | | | | (113 | ) | Issuance and remarketing of long-term debt | | | 6,400 | | | | 6,577 | | | | 4,374 | | Repayment and repurchase of long-term debt (including redemption premiums) | | | (3,750 | ) | | | (2,879 | ) | | | (9,116 | ) | Proceeds from sale of interest in Cove Point | | | — | | | | — | | | | 2,078 | | Issuance of 2019 Equity Units | | | — | | | | — | | | | 1,582 | | Supplemental credit facility borrowings | | | 900 | | | | — | | | | — | | Supplemental credit facility repayments | | | (900 | ) | | | — | | | | — | | Issuance of preferred stock | | | 742 | | | | — | | | | 791 | | Issuance of common stock | | | 192 | | | | 159 | | | | 2,515 | | Repurchase of common stock | | | — | | | | (3,080 | ) | | | — | | Common dividend payments | | | (2,036 | ) | | | (2,873 | ) | | | (2,983 | ) | Other | | | (371 | ) | | | (446 | ) | | | (236 | ) | Net cash provided by (used in) financing activities | | | 2,371 | | | | (2,333 | ) | | | (704 | ) | Increase (decrease) in cash, restricted cash and equivalents | | | 161 | | | | (22 | ) | | | (122 | ) | Cash, restricted cash and equivalents at beginning of period | | | 247 | | | | 269 | | | | 391 | | Cash, restricted cash and equivalents at end of period | | $ | 408 | | | $ | 247 | | | $ | 269 | |
See Note 2 for disclosure of supplemental cash flow information. The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholder of Virginia Electric and Power Company Opinion on the Consolidated Financial Statements We have audited the accompanying consolidated balance sheets of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Energy, Inc.) and subsidiaries (“("Virginia Power”Power") at December 31, 20192021 and 2018,2020, 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, 2019,2021, 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, 20192021 and 2018,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2021, in conformity with accounting principles generally accepted in the United States of America. 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 Board of Directors and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Regulatory Assets and Liabilities - Impact of Rate Regulation on the Consolidated Financial Statements — Refer to Notes 2, 12 and 13 to the Consolidated Financial Statements Critical Audit Matter Description Virginia Power is subject to utility rate regulation by certain state public utility commissions and the Federal Energy Regulatory Commission (“FERC”) (collectively, the “relevant commissions”), which have jurisdiction with respect to the rates of electric utility companies in the territories Virginia Power serves. Management has determined Virginia Power meets the requirements under accounting principles generally accepted in the United States of America to apply the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures such as property, plant, and equipment, net; regulatory assets; regulatory liabilities; operating revenues; other operations and maintenance expense; depreciation and amortization expense; and impairment of assets and other charges, collectively, the “financial statement impacts of rate regulation”. Revenue provided by Virginia Power’s electric transmission, distribution and generation operations is based on rates approved by the relevant commissions. Further, Virginia Power’s retail base rates, terms and conditions for generation and distribution services to
customers in Virginia are reviewed by the Virginia State Corporation Commission (the “Virginia Commission”) in a proceeding that involves the determination of Virginia Power’s actual earned return on equity (“ROE”) during a historic test period and determination of Virginia Power’s authorized ROE prospectively. Under certain circumstances, Virginia Power may be required to credit a portion of its earnings to customers. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds or other benefits through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Virginia Power evaluates whether recovery of its regulatory assets through future rates is probable as well as whether a regulatory liability due to customers is probable and makes various assumptions in its analyses. These analyses are generally based on orders issued by regulatory commissions, legislation and judicial actions; past experience; discussions with applicable regulatory authorities and legal counsel; forecasted earnings; and considerations around the likelihood of impacts from events such as unusual weather conditions, extreme weather events, and other natural disasters, and unplanned outages of facilities. We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about the financial statement impacts of rate regulation. Management judgments include assessing the likelihood of (1) recovery of its regulatory assets through future rates and (2) whether a regulatory liability is due to customers. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commission, auditing these judgments required specialized knowledge of the accounting for rate regulation and the rate setting process due its inherent complexities. How the Critical Audit Matter Was Addressed in the Audit Our audit procedures related to the assessment of whether recovery of regulatory assets through future rates or a regulatory liability due to customers is probable included the following, among others: | • | We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) recovery of regulatory assets through future rates, and (2) whether a regulatory liability is due to customers. We also tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities; and the monitoring and evaluation of regulatory and legislative developments that may impact the assessment of whether recovery of regulatory assets through future rates or a regulatory liability due to customers is probable. |
| • | We evaluated Virginia Power’s disclosures related to the financial statement impacts of rate regulation. |
| • | We read and evaluated orders issued by the relevant commissions, as well as relevant regulatory statutes, interpretations, procedural memorandums, filings made by interveners, existing laws and other publicly available information to assess whether this external information was properly considered by management in concluding upon the financial statement impacts of rate regulation. |
| • | We considered the likelihood of (1) recovery of regulatory assets through future rates and (2) whether a regulatory liability is due to customers based on precedents established by the relevant commissions’ previous orders and Virginia Power’s past experience with relevant commissions. |
| • | For regulatory matters in process, we inspected associated documents and testimony filed with the relevant commissions for any evidence that might contradict management’s assertions. |
| • | We read and analyzed the minutes of the Board of Directors of Dominion Energy, Inc. and the Board of Directors of Virginia Power, for discussions of changes in legal, regulatory, or business factors which could impact management’s conclusions with respect to the financial statement impacts of rate regulation. |
/s/ Deloitte & Touche LLP 24, 2022We have served as Virginia Power’sPower's auditor since 1988.
Virginia Electric and Power Company Consolidated Statements of Income Year Ended December 31, | | 2021 | | | 2020 | | | 2019 | | (millions) | | | | | | | | | | | | | Operating Revenue(1) | | $ | 7,470 | | | $ | 7,763 | | | $ | 8,108 | | Operating Expenses | | | | | | | | | | | | | Electric fuel and other energy-related purchases(1) | | | 1,735 | | | | 1,636 | | | | 2,178 | | Purchased (excess) capacity | | | 24 | | | | (17 | ) | | | 40 | | Other operations and maintenance: | | | | | | | | | | | | | Affiliated suppliers | | | 333 | | | | 314 | | | | 367 | | Other | | | 1,460 | | | | 1,472 | | | | 1,376 | | Depreciation and amortization | | | 1,364 | | | | 1,252 | | | | 1,223 | | Other taxes | | | 326 | | | | 327 | | | | 328 | | Impairment of assets and other charges (benefits) | | | (269 | ) | | | 1,093 | | | | 757 | | Total operating expenses | | | 4,973 | | | | 6,077 | | | | 6,269 | | Income from operations | | | 2,497 | | | | 1,686 | | | | 1,839 | | Other income | | | 146 | | | | 80 | | | | 98 | | Interest and related charges(1) | | | 534 | | | | 516 | | | | 524 | | Income before income tax expense | | | 2,109 | | | | 1,250 | | | | 1,413 | | Income tax expense | | | 397 | | | | 229 | | | | 264 | | Net Income | | $ | 1,712 | | | $ | 1,021 | | | $ | 1,149 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | | | | | | | | | | | | | Electric fuel and other energy-related purchases (1) | | | | | | | | | | | | | Purchased electric capacity | | | | | | | | | | | | | Other operations and maintenance: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Depreciation and amortization | | | | | | | | | | | | | | | | | | | | | | | | | | Impairment of assets and other charges | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Interest and related charges (1) | | | | | | | | | | | | | Income from operations before income tax expense | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | |
(1) | See Note 25 for amounts attributable to affiliates. |
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company Consolidated Statements of Comprehensive Income Year Ended December 31, | | 2021 | | | 2020 | | | 2019 | | (millions) | | | | | | | | | | | | | Net income | | $ | 1,712 | | | $ | 1,021 | | | $ | 1,149 | | Other comprehensive income (loss), net of taxes: | | | | | | | | | | | | | Net deferred gains (losses) on derivatives-hedging activities, net of $(4), $9 and $8 tax | | | 13 | | | | (28 | ) | | | (22 | ) | Changes in unrealized net gains (losses) on nuclear decommissioning trust funds, net of $—, $(3) and $(2) tax | | | (2 | ) | | | 6 | | | | 5 | | Amounts reclassified to net income: | | | | | | | | | | | | | Net derivative (gains) losses-hedging activities, net of $(1), $— and $— tax | | | 2 | | | | 2 | | | | 1 | | Net realized (gains) losses on nuclear decommissioning trust funds, net of $1, $1 and $1 tax | | | (2 | ) | | | (3 | ) | | | (1 | ) | Other comprehensive income (loss) | | | 11 | | | | (23 | ) | | | (17 | ) | Comprehensive income | | $ | 1,723 | | | $ | 998 | | | $ | 1,132 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | Other comprehensive income (loss), net of taxes: | | | | | | | | | | | | | Net deferred gains (losses) on derivatives-hedging activities, net of $8, $(1) and $3 tax | | | | ) | | | | | | | | ) | Changes in unrealized net gains (losses) on nuclear decommissioning trust funds, net of $(2), $— and $(16) tax | | | | | | | | | | | | | Amounts reclassified to net income: | | | | | | | | | | | | | Net derivative (gains) losses-hedging activities, net of $—, $— and $— tax | | | | | | | | | | | | | Net realized (gains) losses on nuclear decommissioning trust funds, net of $1, $— and $3 tax | | | | ) | | | | | | | | ) | Other comprehensive income (loss) | | | | ) | | | | | | | | | | | $ | | | | $ | | | | $ | | |
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company Consolidated Balance Sheets | | 2021 | | | 2020 | | (millions) | | | | | | | | | ASSETS | | | | | | | | | Current Assets | | | | | | | | | Cash and cash equivalents | | $ | 26 | | | $ | 35 | | Customer receivables (less allowance for doubtful accounts of $28 and $23) | | | 1,172 | | | | 1,315 | | Other receivables (less allowance for doubtful accounts of $2 at both dates) | | | 112 | | | | 91 | | Affiliated receivables | | | 37 | | | | 5 | | Inventories (average cost method): | | | | | | | | | Materials and supplies | | | 610 | | | | 581 | | Fossil fuel | | | 261 | | | | 281 | | Margin deposit assets | | | 167 | | | | 1 | | Prepayments | | | 37 | | | | 32 | | Regulatory assets | | | 850 | | | | 295 | | Other(1) | | | 78 | | | | 26 | | Total current assets | | | 3,350 | | | | 2,662 | | Investments | | | | | | | | | Nuclear decommissioning trust funds | | | 3,734 | | | | 3,197 | | Other | | | 3 | | | | 3 | | Total investments | | | 3,737 | | | | 3,200 | | Property, Plant and Equipment | | | | | | | | | Property, plant and equipment | | | 49,890 | | | | 46,736 | | Accumulated depreciation and amortization | | | (15,234 | ) | | | (14,167 | ) | Total property, plant and equipment, net | | | 34,656 | | | | 32,569 | | Deferred Charges and Other Assets | | | | | | | | | Pension and other postretirement benefit assets(1) | | | 431 | | | | 354 | | Intangible assets, net | | | 395 | | | | 334 | | Regulatory assets | | | 4,130 | | | | 3,509 | | Other(1) | | | 1,233 | | | | 1,026 | | Total deferred charges and other assets | | | 6,189 | | | | 5,223 | | Total assets | | $ | 47,932 | | | $ | 43,654 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash and cash equivalents | | $ | | | | $ | | | Customer receivables (less allowance for doubtful accounts of $9 at both dates) | | | | | | | | | Other receivables (less allowance for doubtful accounts of $2 and $3) | | | | | | | | | | | | | | | | | | Inventories (average cost method): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Nuclear decommissioning trust funds | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Property, Plant and Equipment | | | | | | | | | Property, plant and equipment | | | | | | | | | Accumulated depreciation and amortization | | | | ) | | | | ) | Total property, plant and equipment, net | | | | | | | | | | | | | | | | | | | Deferred Charges and Other Assets | | | | | | | | | Pension and other postretirement benefit assets (1) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total deferred charges and other assets | | | | | | | | | | | $ | | | | $ | | |
(1) | See Note 25 for amounts attributable to affiliates. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Liabilities And Common Shareholder’s Equity | | | | | | | | | | | | | | | | | | | | | | | | | | | | Securities due within one year | | $ | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Affiliated current borrowings | | | | | | | | | Accrued interest, payroll and t axes | | | | | | | | | Asset retirement obligations | | | | | | | | | | | | | | | | | | Derivative liabilities (1) | | | | | | | | | | | | | | | | | | Other current liabilities | | | | | | | | | Total current liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Deferred Credits and Other Liabilities | | | | | | | | | Deferred income taxes and investment tax credits | | | | | | | | | Asset retirement obligations | | | | | | | | | | | | | | | | | | Pension and other postretirement benefit liability (1) | | | | | | | | | | | | | | | | | | Total deferred credits and other liabilities | | | | | | | | | | | | | | | | | | Commitments and Contingencies (see Note 23) | | | | | | | | | | Common Shareholder’s Equity | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Accumulated other comprehensive loss | | | | ) | | | | ) | Total common shareholder’s equity | | | | | | | | | Total liabilities and shareholder’s equity | | $ | | | | $ | | |
(1) | See Note 25 for amounts attributable to affiliates. |
(2) | 500,000 shares authorized; 274,723 shares outstanding at December 31, 2019 and 2018. |
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
| | 2021 | | | 2020 | | (millions) | | | | | | | | | LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | | | | | | | | Current Liabilities | | | | | | | | | Securities due within one year | | $ | 313 | | | $ | 8 | | Short-term debt | | | 745 | | | | 45 | | Accounts payable | | | 402 | | | | 332 | | Payables to affiliates | | | 121 | | | | 266 | | Affiliated current borrowings | | | 699 | | | | 380 | | Accrued interest, payroll and taxes | | | 274 | | | | 253 | | Asset retirement obligations | | | 191 | | | | 166 | | Regulatory liabilities | | | 647 | | | | 425 | | Derivative liabilities (1) | | | 134 | | | | 390 | | Other current liabilities | | | 567 | | | | 562 | | Total current liabilities | | | 4,093 | | | | 2,827 | | Long-Term Debt | | | | | | | | | Long-term debt | | | 13,453 | | | | 13,207 | | Other | | | 503 | | | | 480 | | Total long-term debt | | | 13,956 | | | | 13,687 | | Deferred Credits and Other Liabilities | | | | | | | | | Deferred income taxes and investment tax credits | | | 3,183 | | | | 2,779 | | Asset retirement obligations | | | 3,732 | | | | 3,654 | | Regulatory liabilities | | | 5,740 | | | | 5,338 | | Other (1) | | | 1,248 | | | | 812 | | Total deferred credits and other liabilities | | | 13,903 | | | | 12,583 | | Total liabilities | | | 31,952 | | | | 29,097 | | Commitments and Contingencies (see Note 23) | | | | | | | | | Common Shareholder’s Equity | | | | | | | | | Common stock – no par(2) | | | 5,738 | | | | 5,738 | | Other paid-in capital | | | 1,113 | | | | 1,113 | | Retained earnings | | | 9,170 | | | | 7,758 | | Accumulated other comprehensive loss | | | (41 | ) | | | (52 | ) | Total common shareholder’s equity | | | 15,980 | | | | 14,557 | | Total liabilities and shareholder’s equity | | $ | 47,932 | | | $ | 43,654 | |
(1) | See Note 25 for amounts attributable to affiliates. |
(2) | | | | | | | | | | | | | | | 500,000 shares authorized; 274,723 shares outstanding at December 31, 2021 and 2020. |
Virginia Electric and Power Company
Consolidated Statements of Common Shareholder’s Equity
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Accumulated
Other
Comprehensive
Income (Loss) | | | | | | | | | | (millions, except for shares) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | ) | Other comprehensive income, net of tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cumulative-effect of changes in accounting principles | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | ) | Other comprehensive income, net of tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (12 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | ) | Other comprehensive loss, net of tax | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | | | | $ | | | | $ | | | | $ | | | | | | ) | | $ | | |
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company Consolidated Statements of Cash FlowsCommon Shareholder’s Equity | | Common Stock | | | | | | | | | | | | | | | | | | | | | | | | | | | | Shares | | | Amount | | | | | Other Paid-In Capital | | | | | Retained Earnings | | | | | AOCI | | | | | Total | | (millions, except for shares) | | (thousands) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2018 | | | 275 | | | $ | 5,738 | | | | | $ | 1,113 | | | | | $ | 6,208 | | | | | $ | (12 | ) | | | | $ | 13,047 | | Net income | | | | | | | | | | | | | | | | | | | 1,149 | | | | | | | | | | | | 1,149 | | Dividends | | | | | | | | | | | | | | | | | | | (190 | ) | | | | | | | | | | | (190 | ) | Other comprehensive loss, net of tax | | | | | | | | | | | | | | | | | | | | | | | | | (17 | ) | | | | | (17 | ) | December 31, 2019 | | | 275 | | | | 5,738 | | | | | | 1,113 | | | | | | 7,167 | | | | | | (29 | ) | | | | | 13,989 | | Net income | | | | | | | | | | | | | | | | | | | 1,021 | | | | | | | | | | | | 1,021 | | Dividends | | | | | | | | | | | | | | | | | | | (430 | ) | | | | | | | | | | | (430 | ) | Other comprehensive loss, net of tax | | | | | | | | | | | | | | | | | | | | | | | | | (23 | ) | | | | | (23 | ) | December 31, 2020 | | | 275 | | | | 5,738 | | | | | | 1,113 | | | | | | 7,758 | | | | | | (52 | ) | | | | | 14,557 | | Net income | | | | | | | | | | | | | | | | | | | 1,712 | | | | | | | | | | | | 1,712 | | Dividends | | | | | | | | | | | | | | | | | | | (300 | ) | | | | | | | | | | | (300 | ) | Other comprehensive income, net of tax | | | | | | | | | | | | | | | | | | | | | | | | | 11 | | | | | | 11 | | December 31, 2021 | | | 275 | | | $ | 5,738 | | | | | $ | 1,113 | | | | | $ | 9,170 | | | | | $ | (41 | ) | | | | $ | 15,980 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | | | | Depreciation and amortization (including nuclear fuel) | | | | | | | | | | | | | Deferred income taxes and investment tax credits | | | | ) | | | | | | | | | Proceeds from assignment of rental portfolio | | | | | | | | | | | | | | Charge (revision) for future ash pond and landfill closure costs | | | | | | | | | | | | | Impairment of assets and other charges | | | | | | | | | | | | | Provision for rate credits to customers | | | | | | | | | | | | | Charge related to a voluntary retirement program | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | Affiliated receivables and payables | | | | | | | | ) | | | | | | | | | ) | | | | | | | | | | | | | | | | | ) | | | | | Deferred fuel expenses, net | | | | | | | | ) | | | | ) | | | | | ) | | | | ) | | | | ) | Accrued interest, payroll and taxes | | | | | | | | ) | | | | | Net realized and unrealized changes related to derivative activities | | | | | | | | | | | | | Asset retirement obligations | | | | | | | | ) | | | | ) | Other operating assets and liabilities | | | | ) | | | | | | | | ) | Net cash provided by operating activities | | | | | | | | | | | | | | | | | | | | | | | | | | Plant construction and other property additions | | | | ) | | | | ) | | | | ) | Purchases of nuclear fuel | | | | ) | | | | ) | | | | ) | Acquisition of solar development projects | | | | ) | | | | ) | | | | ) | Proceeds from sales of securities | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | | | | | ) | | | | ) | | | | ) | Net cash used in investing activities | | | | ) | | | | ) | | | | ) | | | | | | | | | | | | | | Issuance (repayment) of short-term debt, net | | | | ) | | | | ) | | | | | Issuance (repayment) of affiliated current borrowings, net | | | | ) | | | | | | | | ) | Issuance and remarketing of long-term debt | | | | | | | | | | | | | Repayment and repurchase of long-term debt | | | | ) | | | | ) | | | | ) | Common dividend payments to parent | | | | ) | | | | ) | | | | ) | | | | | ) | | | | ) | | | | ) | Net cash provided by (used in) financing activities | | | | | | | | ) | | | | ) | Increase (decrease) in cash, restricted cash and equivalents | | | | ) | | | | | | | | | Cash, restricted cash and equivalents at beginning of year | | | | | | | | | | | | | Cash, restricted cash and equivalents at end of year | | $ | | | | $ | | | | $ | | | Supplemental Cash Flow Information | | | | | | | | | | | | | Cash paid during the year for: | | | | | | | | | | | | | Interest and related charges, excluding capitalized amounts | | $ | | | | $ | | | | $ | | | | | | | | | | | | | | | | Significant noncash investing and financing activities: (1) | | | | | | | | | | | | | Accrued capital expenditures | | | | | | | | | | | | | | | | | | | | | | | | | |
(1) | See Note 2 for noncash investing and financing activities related to the adoption of a new accounting standard for leasing arrangements. |
| Includes $20 million of finance leases and $35 million of operating leases.
|
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
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Report of Independent Registered Public Accounting Firm
To the Board of Directors of
Dominion Energy Gas Holdings, LLC
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Dominion Energy Gas Holdings, LLC (a wholly-owned subsidiary of Dominion Energy, Inc.)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. These consolidated financial statements are the responsibility of Dominion Energy Gas’ management. Our responsibility is to express an opinion on Dominion Energy Gas’ consolidated financial statements based on our audits. We are a public accounting firm registered with the PublicPower Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Dominion Energy Gas 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. Dominion Energy Gas 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 Dominion Energy Gas’ 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.
/s/ Deloitte & Touche LLP
We have served as Dominion Energy Gas’ auditor since 2012.
Dominion Energy Gas Holdings, LLC
Consolidated Statements of IncomeCash Flows Year Ended December 31, | | 2021 | | | | | 2020 | | | | | 2019 | | (millions) | | | | | | | | | | | | | | | | | Operating Activities | | | | | | | | | | | | | | | | | Net income | | $ | 1,712 | | | | | $ | 1,021 | | | | | $ | 1,149 | | Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | | | | | | | | Depreciation and amortization (including nuclear fuel) | | | 1,521 | | | | | | 1,421 | | | | | | 1,392 | | Deferred income taxes and investment tax credits | | | 343 | | | | | | (206 | ) | | | | | (80 | ) | Charge (revision) for future ash pond and landfill closure costs | | | — | | | | | | 11 | | | | | | (113 | ) | Impairment of assets and other charges | | | (269 | ) | | | | | 1,079 | | | | | | 624 | | Charges related to a voluntary retirement program | | | — | | | | | | — | | | | | | 116 | | Provision for refunds to customers | | | 356 | | | | | | — | | | | | | — | | Other adjustments | | | 19 | | | | | | (61 | ) | | | | | (63 | ) | Changes in: | | | | | | | | | | | | | | | | | Accounts receivable | | | (112 | ) | | | | | (266 | ) | | | | | (219 | ) | Affiliated receivables and payables | | | (175 | ) | | | | | 78 | | | | | | 75 | | Inventories | | | (10 | ) | | | | | 10 | | | | | | (56 | ) | Prepayments | | | (4 | ) | | | | | (5 | ) | | | | | 1 | | Deferred fuel expenses, net | | | (652 | ) | | | | | 131 | | | | | | 243 | | Accounts payable | | | 19 | | | | | | 6 | | | | | | (31 | ) | Accrued interest, payroll and taxes | | | 21 | | | | | | (4 | ) | | | | | 5 | | Margin deposit assets and liabilities | | | (166 | ) | | | | | (1 | ) | | | | | — | | Net realized and unrealized changes related to derivative activities | | | — | | | | | | (6 | ) | | | | | 21 | | Other operating assets and liabilities | | | (106 | ) | | | | | (308 | ) | | | | | (280 | ) | Net cash provided by operating activities | | | 2,497 | | | | | | 2,900 | | | | | | 2,784 | | Investing Activities | | | | | | | | | | | | | | | | | Plant construction and other property additions | | | (3,521 | ) | | | | | (3,138 | ) | | | | | (2,642 | ) | Purchases of nuclear fuel | | | (160 | ) | | | | | (199 | ) | | | | | (157 | ) | Acquisition of solar development projects | | | (75 | ) | | | | | (35 | ) | | | | | (182 | ) | Proceeds from sales of securities | | | 1,791 | | | | | | 884 | | | | | | 858 | | Purchases of securities | | | (1,789 | ) | | | | | (936 | ) | | | | | (905 | ) | Other | | | — | | | | | | 21 | | | | | | (37 | ) | Net cash used in investing activities | | | (3,754 | ) | | | | | (3,403 | ) | | | | | (3,065 | ) | Financing Activities | | | | | | | | | | | | | | | | | Issuance (repayment) of short-term debt, net | | | 700 | | | | | | (198 | ) | | | | | (71 | ) | Issuance (repayment) of affiliated current borrowings, net | | | 319 | | | | | | 273 | | | | | | (117 | ) | Issuance and remarketing of long-term debt | | | 1,000 | | | | | | 1,327 | | | | | | 1,248 | | Repayment and repurchase of long-term debt | | | (450 | ) | | | | | (427 | ) | | | | | (591 | ) | Common dividend payments to parent | | | (300 | ) | | | | | (430 | ) | | | | | (190 | ) | Other | | | (21 | ) | | | | | (31 | ) | | | | | (12 | ) | Net cash provided by financing activities | | | 1,248 | | | | | | 514 | | | | | | 267 | | Increase (decrease) in cash, restricted cash and equivalents | | | (9 | ) | | | | | 11 | | | | | | (14 | ) | Cash, restricted cash and equivalents at beginning of year | | | 35 | | | | | | 24 | | | | | | 38 | | Cash, restricted cash and equivalents at end of year | | $ | 26 | | | | | $ | 35 | | | | | $ | 24 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | | | | | | | | | | | | | Purchased (excess) gas (1) | | | | | | | | ) | | | | | Other energy-related purchases | | | | | | | | | | | | | Other operations and maintenance: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Depreciation and amortization | | | | | | | | | | | | | | | | | | | | | | | | | | Impairment of assets and related charges | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | | | | | | | | | | | | | | Income from continuing operations | | | | | | | | | | | | | Earnings from equity method investees | | | | | | | | | | | | | | | | | | | | | | | | | | Interest and related charges (1) | | | | | | | | | | | | | Income from continuing operations before income tax expense | | | | | | | | | | | | | Income tax expense (benefit) | | | | | | | | | | | | ) | Net Income from Continuing Operations | | | | | | | | | | | | | Net Income from discontinued operations (2) | | | | | | | | | | | | | Net Income including noncontrolling interests | | | | | | | | | | | | | | | | | | | | | | | | | | Net Income Attributable to Dominion Energy Gas | | $ | | | | $ | | | | $ | | |
(1) | See Note 25 for amounts attributable to related parties. |
(2) | Includes income tax expense of $33 million, less than $1 million and $91 million in 2019, 2018 and 2017, respectively. |
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.
Dominion Energy Gas Holdings, LLC
Consolidated Statements of Comprehensive Income
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net Income including noncontrolling interests | | $ | | | | $ | | | | $ | | | Other comprehensive income (loss), net of taxes: | | | | | | | | | | | | | Net deferred gains (losses) on derivatives-hedging activities, net of $22, $5 and $(3) tax | | | | ) | | | | ) | | | | | Changes in net unrecognized pension benefit (costs) , net of $(13), $20 and $(8) tax | | | | | | | | ) | | | | | Amounts reclassified to net income: | | | | | | | | | | | | | Net derivative (gains) losses-hedging activities, net of $(2), $(7) and $2 tax | | | | | | | | | | | | ) | Net pension and other postretirement benefit costs, net of $(2), $(2) and $(2) tax | | | | | | | | | | | | | Total other comprehensive income (loss) | | | | ) | | | | ) | | | | | Comprehensive income including noncontrolling interests | | | | | | | | | | | | | Comprehensive income attributable to noncontrolling interests | | | | | | | | | | | | | Comprehensive income attributable to Dominion Energy Gas | | $ | | | | $ | | | | $ | | |
The accompanying notes are an integral part of Dominion Energy Gas’ Consolidated Financial Statements.
Dominion Energy Gas Holdings, LLC
Consolidated Balance Sheets
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash and cash equivalents | | $ | | | | $ | | | Customer receivables (less allowance for doubtful accounts of $2 and less than $1) (1) | | | | | | | | | | | | | | | | | | | | | | | | | | | Affiliated notes receivable | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Current assets of discontinued operations | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Affiliated notes receivables | | | | | | | | | Investment in equity method affiliates | | | | | | | | | | | | | | | | | | Property, Plant and Equipment | | | | | | | | | Property, plant and equipment | | | | | | | | | Accumulated depreciation and amortization | | | | ) | | | | ) | Total property, plant and equipment, net | | | | | | | | | Deferred Charges and Other Assets | | | | | | | | | | | | | | | | | | | | | | | | | | | Pension and other postretirement benefit assets (1) | | | | | | | | | | | | | | | | | | | | | | | | | | | Total deferred charges and other assets | | | | | | | | | Noncurrent Assets of Discontinued Operations | | | | | | | | | | | $ | | | | $ | | |
(1) | See Note 25 for amounts attributable to related parties. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Securities due within one year | | $ | | | | $ | | | Credit facility borrowings | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Affiliated current borrowings | | | | | | | | | Accrued interest, payroll and taxe s | | | | | | | | | Current liabilities of discontinued operations | | | | | | | | | | | | | | | | | | Total current liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Deferred Credits and Other Liabilities | | | | | | | | | Deferred income taxes and investment tax credits | | | | | | | | | | | | | | | | | | | | | | | | | | | Total deferred credits and other liabilities | | | | | | | | | Noncurrent Liabilities of Discontinued Operations | | | | | | | | | | | | | | | | | | Commitments and Contingencies (see Note 23) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Accumulated other comprehensive loss | | | | ) | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total liabilities and equity | | $ | | | | $ | | |
(1) | See Note 25 for amounts attributable to related parties. |
The accompanying notes are an integral part of Dominion Energy Gas’ Consolidated Financial Statements.
Dominion Energy Gas Holdings, LLC
Consolidated Statements of Equity
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Accumulated
Other
Comprehensive
Income (Loss) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | $ | | | | | | | | $ | | | Net income including noncontrolling interests | | | | | | | | | | | | | | | | | | | | | | | | | Sale of Dominion Energy Midstream common units—net of offering costs | | | | | | | | | | | | | | | | | | | | | | | | | Dividends and distributions | | | | ) | | | | ) | | | | | | | | ) | | | | ) | | | | ) | Distributions to noncontrolling interests | | | | ) | | | | | | | | | | | | ) | | | | | | | | | Equity contributions from Dominion Energy | | | | | | | | | | | | | | | | | | | | | | | | | Other comprehensive income, net of tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | Cumulative-effect of changes in accounting principles | | | | | | | | | | | | ) | | | | | | | | | | | | | Net income including noncontrolling interests | | | | | | | | | | | | | | | | | | | | | | | | | Sale of Dominion Energy Midstream common units—net of offering costs | | | | | | | | | | | | | | | | | | | | | | | | | Remeasurement of noncontrolling interest in Dominion Energy Midstream | | | | | | | | | | | | | | | | | | | | ) | | | | | Dividends and distributions | | | | ) | | | | ) | | | | | | | | ) | | | | ) | | | | ) | Distributions to noncontrolling interests | | | | ) | | | | | | | | | | | | ) | | | | | | | | | Equity contributions from Dominion Energy | | | | | | | | | | | | | | | | | | | | | | | | | Other comprehensive loss, net of tax | | | | | | | | | | | | ) | | | | ) | | | | | | | | ) | | | | | | | | | | | | | ) | | | | | | | | | | | | | Net income including noncontrolling interests | | | | | | | | | | | | | | | | | | | | | | | | | Acquisition of public interest in Dominion Energy Midstream | | | | | | | | | | | | | | | | | | | | ) | | | | ) | Dividends and distributions | | | | ) | | | | | | | | | | | | ) | | | | ) | | | | ) | Equity contributions from Dominion Energy | | | | | | | | | | | | | | | | | | | | | | | | | Dominion Energy Gas Restructuring | | | | ) | | | | | | | | ) | | | | ) | | | | | | | | ) | Other comprehensive loss, net of tax | | | | | | | | | | | | ) | | | | ) | | | | ) | | | | ) | | | | | | | | | ) | | | | | | | | ) | | | | | | | | ) | | | | | | | | | | | | | ) | | $ | | | | | | | | $ | | |
The accompanying notes are an integral part of Dominion Energy Gas’ Consolidated Financial Statements.
Dominion Energy Gas Holdings, LLC
Consolidated Statements of Cash Flows
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net Income including noncontrolling interests | | $ | | | | $ | | | | $ | | | Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | | | | Depreciation and amortization | | | | | | | | | | | | | Deferred income taxes and investment tax credits | | | | ) | | | | | | | | ) | Charge related to a voluntary retirement program | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | Impairment of assets and related charges | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | Affiliated receivables and payables | | | | ) | | | | ) | | | | | | | | | ) | | | | ) | | | | ) | | | | | | | | | ) | | | | ) | | | | | ) | | | | | | | | ) | Accrued interest, payroll and taxes | | | | ) | | | | | | | | | Pension and other postretirement benefits | | | | ) | | | | ) | | | | ) | Other operating assets and liabilities | | | | ) | | | | | | | | ) | Net cash provided by operating activities | | | | | | | | | | | | | | | | | | | | | | | | | | Plant construction and other property additions | | | | ) | | | | ) | | | | ) | | | | | ) | | | | | | | | | | | | | ) | | | | | | | | | Loan to Dominion Energy from Cove Point | | | | | | | | ) | | | | | Repayment of loan by Dominion Energy to Cove Point | | | | | | | | | | | | | Repayment of loan to East Ohio | | | | | | | | | | | | | | Repayment of affiliated notes receivable, net | | | | | | | | | | | | | Proceeds from assignments of shale development rights | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | Net cash provided by (used in) investing activities | | | | | | | | ) | | | | ) | | | | | | | | | | | | | | Issuance (repayment) of short-term debt, net | | | | | | | | ) | | | | | Issuance (repayment) of affiliated current borrowings, net | | | | ) | | | | | | | | | Issuance of long-term debt | | | | | | | | | | | | | Issuance of affiliated long-term debt | | | | | | | | | | | | | Repayment of long-term debt | | | | ) | | | | ) | | | | | Repayment of affiliated long-term debt | | | | ) | | | | | | | | | Credit facility borrowings | | | | | | | | | | | | | Repayment of credit facility borrowings | | | | ) | | | | | | | | | Net proceeds from sale of Dominion Energy Midstream common units | | | | | | | | | | | | | Contributions from Dominion Energy | | | | | | | | | | | | | Dividends and distributions | | | | ) | | | | ) | | | | ) | | | | | ) | | | | ) | | | | | Net cash provided by (used in) financing activities | | | | ) | | | | | | | | | Increase (decrease) in cash, restricted cash and cash equivalents | | | | ) | | | | | | | | ) | Cash, restricted cash and equivalents at beginning of year | | | | | | | | | | | | | Cash, restricted cash and equivalents at end of year | | $ | | | | $ | | | | $ | | | Supplemental Cash Flow Information | | | | | | | | | | | | | Cash paid during the year for: | | | | | | | | | | | | | Interest and related charges, excluding capitalized amounts | | $ | | | | $ | | | | $ | | | | | | | | | | | | | | | | Significant noncash investing and financing activities: (1)(2) | | | | | | | | | | | | | Accrued capital expenditures | | | | | | | | | | | | | Equity contributions from Dominion Energy | | | | | | | | | | | | | | | | | | | | | | | | | |
(1) | See Note 2 for noncash investing and financing activities related to the adoption of a new accounting standard for lease arrangements. |
| See Notes 3 and 25 for noncash investing and financing activities related to the Dominion Energy Gas Restructuring and related-party transactions.
|
The accompanying notes are an integral part of Dominion Energy Gas’ Consolidated Financial Statements.
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Combined Notes to Consolidated Financial Statements NoteNOTE 1. Nature Of Operations NATURE OF OPERATIONSDominion 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. Beginningsale of the Q-Pipe Group completed in December 2019, 2021.Dominion Energy manages its daily operations through five4 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 Wrangler. Corporate and Other includes specific items attributable to Dominion Energy’s operating segments that are not included in profit measures evaluated by executive management in assessing the operating segments’ performance or in allocating resources. In addition, Corporate and Other includes the net impact of discontinued operations consisting of Dominion Energy’s gas transmission and storage operations as discussed in Note 3 and its equity investment in Atlantic Coast Pipeline as discussed in Note 9.Virginia Power is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into the PJM wholesale electricity markets. All of Virginia Power’s stock is owned by Dominion Energy. Beginning in December 2019, Virginia Power manages its daily operations through one1 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. Dominion Energy Gas is a holding company that conducts business activities through FERC-regulated interstate natural gas transmission pipeline and underground storage systems in the eastern and Rocky Mountain regions of the U.S., as well as the Cove Point LNG Facility. In addition, Dominion Energy Gas owns a 50% noncontrolling interest in both Iroquois and White River Hub. See Note 3 for more information on the Dominion Energy Gas Restructuring. All of Dominion Energy Gas’ membership interests are held by Dominion Energy.
Beginning in December 2019, Dominion Energy Gas manages its daily operations through one primary operating segment: Gas Transmission & Storage. 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 and the effect of certain items recorded at Dominion Energy Gas as a result of Dominion Energy’s basis in the net assets contributed. In addition, Corporate and Other includes the net impact of discontinued operations, which is discussed in Note 3.
See Note 26 for further discussion of the Companies’ operating segments. NoteNOTE 2. Significant Accounting Policies SIGNIFICANT ACCOUNTING POLICIESGeneral The Companies make certain estimates and assumptions in preparing their Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues, expenses and cash flows for the periods presented. Actual results may differ from those estimates. The Companies’ Consolidated Financial Statements include, after eliminating intercompany transactions and balances, their accounts, those of their respective majority-owned subsidiaries and non-wholly-owned entities in which they have a controlling financial interest. For certain partnership structures, income is allocated based on the liquidation value of the underlying contractual arrangements. At December 31, 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% interest in certain Dominion Energy’s merchantEnergy nonregulated solar projects (through December 2021), Brookfield’s 25% interest in Cove Point (effective December 2019 until November 2020) and the non-Dominion Energy held interest in Dominion Energy Midstream (through January 2019) are reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements. 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) reflected as noncontrolling interest in Dominion Energy Gas’ Consolidated Financial Statements.The Companies report certain contracts, instruments and investments at fair value. See Note 6 for further information on fair value measurements. The Companies consider acquisitions or dispositions in which substantially all of the fair value of the gross assets acquired or disposed of is concentrated into a single identifiable asset or group of similar identifiable assets to be an acquisition or a disposition of an asset, rather than a business. See Notes 3 and 10 for further information on such transactions. Dominion Energy maintains pension and other postretirement benefit plans.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’ 20182020 and 20172019 Consolidated Financial Statements and Notes have been reclassified to conform to the 20192021 presentation for comparative purposes; however, such reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows. Effective in the second quarter of 2021, the Companies updated their Statements of Cash Flows to present net charges for allowance for credit risk and write-offs of accounts receivables within other adjustments to reconcile net income to net cash provided by operating activities from the previous presentation within changes in accounts receivable. All prior period information has been conformed to this presentation, which does not result in a change to net cash provided by operating activities.
Amounts disclosed for Dominion Energy are inclusive of Virginia Power, and/or Dominion Energy Gas, where applicable. Operating revenue is recorded on the basis of services rendered, commodities delivered, or contracts settled and includes amounts
Combined Notes to Consolidated Financial Statements, Continued
yet to be billed to customers. Dominion Energy and Virginia PowerThe Companies collect sales, consumption and consumer utility taxes and Dominion Energy Gas collects sales taxes; however, these amounts are excluded from revenue. Dominion Energy’s customer receivables at December 31, 20192021 and 20182020 included $896$779 million and $626 million,$1.1 billion, respectively, of accrued unbilled revenue based on estimated amounts of electricity and natural gas delivered but not yet billed to its utility customers. Virginia Power’s customer receivables at December 31, 20192021 and 20182020 included $512$398 million and $392$740 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity delivered but not yet billed to its customers. Dominion Energy Gas’ customer receivables at December 31, 2019 and 2018 included $104 million and $101 million, respectively, of accrued unbilled revenue based on estimated amounts of natural gas delivered but not yet billed to its customers. See Note 25 for amounts attributable to related parties. The primary types of sales and service activities reported as operating revenue for Dominion Energy subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, are as follows: Revenue from Contracts with Customers | • | Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services; |
| • | Nonregulated electric sales consist primarily of sales of electricity at market-based rates and contracted fixed rates and associated hedging activity and sales to Virginia Power customers from non-jurisdictional solar generation facilities; |
consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission | • | Regulated gas sales consist primarily of state-regulated natural gas sales and related distribution services; |
| • | Nonregulated gas sales consist primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties and associated hedging activity; |
| • | Regulated gas transportation and storage sales consist of state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers, sales of gathering services and sales of transportation services to off-system customers; |
| • | Other regulated revenue consists primarily of miscellaneous service revenue from electric and gas distribution operations and sales of excess electric capacity and other commodities; and |
| • | Other nonregulated revenue consists primarily of sales of commodities related to nonregulated extraction activities and other miscellaneous products. Other nonregulated revenue also includes sales of energy-related products and services from Dominion Energy’s retail energy marketing operations (through December 2021), service concession arrangements and revenue associated with services provided to entities presented in discontinued operations under transition services agreements. |
Nonregulated electric sales
consist primarily of sales of electricity at market-based rates and contracted fixed rates, and associated hedging activity;consist primarily of state-regulated natural gas sales and related distribution services;consist primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties and associated hedging activity;Regulated gas transportation and storage sales
consist of FERC-regulated sales of transmission and storage services and state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services;Nonregulated gas transportation and storage sales
consist primarily of LNG terminalling services;consists primarily of miscellaneous service revenue from electric and gas distribution operations and sales of excess electric capacity and other commodities; andOther nonregulated revenue
consists primarily of NGL gathering and processing, sales of NGL production and condensate, extracted products and associated hedging activity. Other nonregulated revenue also includes services performed for Atlantic Coast Pipeline, sales of energy-related products and services from Dominion Energy’s retail energy marketing operations, service concession arrangements and gas processing and handling revenue.Other Revenue | • | Other revenue consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues. |
consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues.The primary types of sales and service activities reported as operating revenue for Dominion Energy, prior to the adoption of revised guidance for revenue recognition from contracts with customers, were as follows:
consisted primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;Nonregulated electric sales
consisted primarily of sales of electricity at market-based rates and contracted fixed rates, and associated derivative activity;consisted primarily of state- and FERC-regulated natural gas sales and related distribution services and associated derivative activity;consisted primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties, gas trading and marketing revenue and associated derivative activity;Gas transportation and storage sales
consisted primarily of FERC-regulated sales of transmission and storage services. Also included were state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services; andconsisted primarily of sales of NGL production and condensate, extracted products and associated derivative activity. Other revenue also included miscellaneous service revenue from electric and gas distribution operations, sales of energy-related products and services from Dominion Energy’s retail energy marketing operations and gas processing and handling 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 consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services;consists primarily of sales of excess capacity and other commodities and miscellaneous service revenue from electric distribution operations; andOther nonregulated revenue
consists primarily of sales tonon-jurisdictional
customers from certain solar facilities, revenue from renting space on certain electric transmission poles and distribution towers and service concession arrangements.consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues.The primary types of sales and service activities reported as operating revenue for Virginia Power, prior to the adoption of revised guidance for revenue recognition from contracts with customers, were as follows:
consisted primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services; and | • | Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services; |
| • | | | | | | | | | | | | | | Nonregulated electric sales consists of sales to customers from non-jurisdictional solar generation facilities; |
| • | Other regulated revenue consists primarily of sales of excess capacity and other commodities and miscellaneous service revenue from electric distribution operations; and |
| • | Other nonregulated revenue consists primarily of revenue from renting space on certain electric transmission poles and distribution towers and service concession arrangements. |
consisted primarily of miscellaneous service revenue from electric distribution operations and miscellaneous revenue from generation operations, including sales of capacity and other commodities.The primary types of sales and service activities reported as operating revenue for Dominion Energy Gas, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, are as follows:
Revenue from Contracts with Customers
Regulated gas sales—wholesale
consist primarily of sales of natural gas to wholesale customers as permitted by FERC under DETI’s operating tariff;consist primarily of sales of gas purchased from third parties and royalty revenues;Regulated gas transportation and storage sales
consist of FERC-regulated sales of transmission and storage services;Nonregulated gas transportation and storage sales
consist primarily of LNG terminalling servicesManagement service revenue
consists primarily of services performed for Atlantic Coast Pipeline;consists primarily of miscellaneous regulated revenues; andOther nonregulated revenue
consists primarily of miscellaneous service revenue. | • | Other revenue consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues. |
consists primarily of gains and losses from derivative instruments not subject to hedge accounting.The primary types of sales and service activities reported as operating revenue for Dominion Energy Gas, prior to the adoption of revised guidance for revenue recognition from contracts with customers, were as follows: consisted primarily of sales of natural gas to wholesale customers as permitted by FERC under DETI’s operating tariff;consisted primarily of sales of natural gas production at market-based rates and contracted fixed prices and sales of gas purchased from third parties. Revenue from sales of gas production was recognized based on actual volumes of gas sold to purchasers and was reported net of royalties;Gas transportation and storage sales
consisted primarily of FERC-regulated sales of transmission and storage services; andconsisted primarily of miscellaneous service revenue, gas processing and handling revenue.O
revenue for East Ohio and DGP consists primarily of state-regulated natural gas sales and related distribution services, state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of NGL gathering and processing activities, and is included in net income from discontinued operations in Dominion Energy Gas’ Consolidated Statements of Incomethrough November 6, 2019.
Dominion Energy and Virginia PowerCompanies record refunds to customers as required by state commissions as a reduction to regulated electric sales or regulated gas sales, as applicable. Dominion Energy and Virginia Power’sThe Companies’ revenue accounted for under the
alternative revenue program guidance primarily consists of the equity return for under-recovery of certain riders. Alternative revenue programs compensate Dominion Energy and Virginia Powerthe Companies for certain projects and initiatives. Revenues arising from these programs are presented separately from revenue arising from contracts with customers in the categories above. Revenues from electric and gas sales are recognized over time, as the customers of the Companies consume gas and electricity as it is delivered. 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 the start-up
phase 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 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 for credit losses, that it is unlikely that a material adverse effect on financial position, results of operations or cash flows would occur as a
Combined Notes to Consolidated Financial Statements, Continued
result of counterparty nonperformance. Effective January 2020, expected credit losses will beare estimated and recorded based on historical experience, current conditions and reasonable and supportable forecasts that affect the collectability of financial assets held at amortized cost as well as expected credit losses on commitments with respect to financial guarantees.
Electric Fuel, Purchased Energy and Purchased Gas-Deferred Costs Where permitted by regulatory authorities, the differences between 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, 2019,2021, 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. Of the cost of fuel used in electric generation and energy purchases to serve South Carolina utility customers, at December 31, 2021, approximately 96% is subject to DESC’s deferred fuel accounting.Virtually all of East Ohio, Questar Gas, Hope, DESC and PSNC’s natural gas purchases are either subject to deferral accounting or are recovered from the customer in the same accounting period as the sale.
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. Although Dominion Energy Gas and certain of its subsidiaries are disregarded for income tax purposes, a provision for income taxes is recognized to reflect the inclusion of its business activities in the tax returns of its parent, Dominion Energy. 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. The 2017 Tax Reform Act included a broad range of tax reform provisions affecting the Companies, including changes in corporate tax rates and business deductions. The 2017 Tax Reform Act reduces the corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. Deferred tax assets and liabilities are classified as noncurrent in the Consolidated Balance Sheets and measured at the enacted tax rate expected to apply when temporary differences are realized or
settled. Thus, at the date of enactment, federal deferred taxes were remeasured based upon the new 21% tax rate. The total effect of tax rate changes on deferred tax balances was recorded as a component of the income tax provision related to continuing operations for the period in which the law is enacted, even if the assets and liabilities relate to other components of the financial statements, such as items of accumulated other comprehensive income. For Dominion Energy subsidiaries that are not rate-regulated utilities, existing deferred income tax assets or liabilities were adjusted for the reduction in the corporate income tax rate and allocated to continuing operations. Dominion Energy’s rate-regulated utility subsidiaries likewise were required to adjust deferred income tax assets and liabilities for the change in income tax rates. However, if it is probable that the effect of the change in income tax rates will be recovered or refunded in future rates, the regulated utility recorded a regulatory asset or liability instead of an increase or decrease to deferred income tax expense.
Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Accordingly, deferred taxes are recognized for the future consequences of different treatments used for the reporting of transactions in financial accounting and income tax returns. The Companies establish a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. Where the treatment of temporary differences is different for rate-regulated operations, a regulatory asset is recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities. The Companies recognize positions taken, or expected to be taken, in income tax returns that are more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in income taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities, noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities on the Consolidated Balance Sheets and current payables are included in accrued interest, payroll and taxes on the Consolidated Balance Sheets. The Companies recognize interest on underpayments and overpayments of income taxes in interest expense and other income, respectively. Penalties are also recognized in other income. Interest expense for the Companies was immaterial in 2019 and 2018.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.
effectively settled.At December 31, 2019,2021, Virginia Power had an income tax-related affiliated payablereceivable of $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 receivablesbalances are expected to be received from Dominion Energy. In addition, Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2019 included $10 million of state income taxes receivable. State income taxes receivable at Virginia Power were immaterial at December 31, 2019.
At December 31, 2018,2020, Virginia Power had an income tax-related affiliated receivablepayable of $36$19 million, comprised of $34$17 million of federal income taxes and $2 million of state income taxes due from Dominion Energy. Dominion Energy Gas also had a net affiliated receivable of $271 million due from Dominion Energy, representing $277 million of federal income taxes receivable and $6 million of state income taxes payable to Dominion Energy. Virginia Power’s net affiliated receivablesbalances were received frompaid to Dominion Energy, and Dominion Energy Gas’ affiliated receivables are expected to be received from Dominion Energy. In addition, Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2018 included $15 million of state income taxes receivable. State income taxes receivable at Virginia Power were immaterial at December 31, 2018.
Investment tax credits are recognized by nonregulated operations in the year qualifying property is placed in service. For regulated operations, investment tax credits are deferred and amortized over the service lives of the properties giving rise to the credits. Production tax credits are recognized as energy is generated and sold.
Cash, Restricted Cash and Equivalents Cash, restricted cash and equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less. Current banking arrangements generally do not require checks to be funded until they are presented for payment. The following table illustrates the checks outstanding but not yet presented for payment and recorded in accounts payable for the Companies: At December 31, | | 2021 | | | 2020 | | (millions) | | | | | | | | | Dominion Energy | | $ | 70 | | | $ | 50 | | Virginia Power | | | 15 | | | | 30 | |
Restricted Cash and Equivalents The Companies hold restricted cash and equivalent balances that primarily consist of amounts held for litigation settlements, customer deposits, federal assistance funds and future debt payments on SBL Holdco and Dominion Solar Projects III, Inc.’s term loan agreements (through December 2021), on DECP Holdings’ term loan agreement and on Eagle Solar’s senior note agreement. The following table provides a reconciliation of the total cash, restricted cash and equivalents reported within the Companies’ Consolidated Balance Sheets to the corresponding amounts reported within the Companies’ Consolidated Statements of Cash Flows for the years ended December 31, 2019, 20182021, 2020 and 2017: | | | | | | | | | | | | | | | | | | | | Cash, Restricted Cash and Equivalents at
End/Beginning of Year | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash and cash equivalents | | | | | | | | | | | | | | | | | Restricted cash and equivalents (1) | | | | | | | | | | | | | | | | | Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash and cash equivalents | | | | | | | | | | | | | | | | | Restricted cash and equivalents (1) | | | | | | | | | | | | | | | | | Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash and cash equivalents (2) | | | | | | | | | | | | | | | | | Restricted cash and equivalents (1) | | | | | | | | | | | | | | | | | Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows | | | | | | | | | | | | | | | | |
| | Cash, Restricted Cash and Equivalents at End/Beginning of Year | | | | December 31, 2021 | | | December 31, 2020 | | | December 31, 2019 | | | December 31, 2018 | | (millions) | | | | | | | | | | | | | | | | | Dominion Energy | | | | | | | | | | | | | | | | | Cash and cash equivalents(1) | | $ | 283 | | | $ | 179 | | | $ | 166 | | | $ | 268 | | Restricted cash and equivalents(2)(3) | | | 125 | | | | 68 | | | | 103 | | | | 123 | | Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows | | $ | 408 | | | $ | 247 | | | $ | 269 | | | $ | 391 | | Virginia Power | | | | | | | | | | | | | | | | | Cash and cash equivalents | | $ | 26 | | | $ | 35 | | | $ | 17 | | | $ | 29 | | Restricted cash and equivalents(3) | | | — | | | | — | | | | 7 | | | | 9 | | Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows | | $ | 26 | | | $ | 35 | | | $ | 24 | | | $ | 38 | |
(1) | (1) | At December 31, 2020, December 31, 2019 and December 31, 2018, Dominion Energy had $7 million, $31 million and $110 million of cash and cash equivalents included in current assets held for sale, respectively. NaN amounts were included in current assets held for sale at December 31, 2021. |
| (2) | At December 31, 2020, December 31, 2019 and December 31, 2018, Dominion Energy had $3 million, $12 million and $89 million of restricted cash included in current assets held for sale, respectively. NaN amounts were included in current assets held for sale at December 31, 2021. |
| (3) | Restricted cash and equivalent balances are presented within other current assets in the Companies’ Consolidated Balance Sheets. |
Supplemental Cash Flow Information The following table provides supplemental disclosure of cash flow information related to Dominion Energy: Year Ended December 31, | | 2021 | | | 2020 | | | 2019 | | Cash paid during the year for: | | | | | | | | | | | | | Interest and related charges, excluding capitalized amounts | | $ | 1,340 | | | $ | 1,519 | | | $ | 1,643 | | Income taxes | | | 160 | | | | 292 | | | | 106 | | Significant noncash investing and financing activities:(1)(2)(3)(4)(5) | | | | | | | | | | | | | Accrued capital expenditures | | | 637 | | | | 485 | | | | 555 | | Leases(6) | | | 96 | | | | 173 | | | | 157 | |
(2) | At December 31, 2018, 2017(1) | See the New Accounting Standards section below for noncash investing and 2016,financing activities related to the adoption of a new accounting standard for leasing arrangements. |
| (2) | See Note 3 for noncash investing and financing activities related to the SCANA Combination. |
| (3) | See Note 5 for noncash activities related to the sale of a noncontrolling interest in Cove Point. |
| (4) | See Note 9 for noncash investing activities related to the acquisition of a noncontrolling interest in Wrangler. |
| (5) | See Notes 18,19 and 20 for noncash financing activities related to the acquisition of the public interest in Dominion Energy Gas had $9 million, $3 millionMidstream, the remarketing of RSNs, the issuance of stock purchase contracts associated with the 2019 Equity Units, the contribution of stock to Dominion Energy’s qualified defined benefit pension plan, derivative restructuring and $14the issuance of common stock associated with the settlement of litigation. See Note 23 for non-cash investing activities related to property, plant and equipment conveyed to satisfy litigation. |
| (6) | Includes $47 million of cashfinance leases and cash equivalents included$49 million of operating leases entered in current assets2021, $46 million of discontinued operations, respectively.finance leases and $127 million of operating leases entered in 2020 and $113 million of finance leases and $44 million of operating leases entered in 2019. |
The following table provides supplemental disclosure of cash flow information related to Virginia Power: Year Ended December 31, | | 2021 | | | 2020 | | | 2019 | | Cash paid during the year for: | | | | | | | | | | | | | Interest and related charges, excluding capitalized amounts | | $ | 501 | | | $ | 491 | | | $ | 495 | | Income taxes | | | 109 | | | | 452 | | | | 272 | | Significant noncash investing activities:(1)(2) | | | | | | | | | | | | | Accrued capital expenditures | | | 363 | | | | 262 | | | | 292 | | Leases (3) | | | 79 | | | | 32 | | | | 55 | |
(1) | See the New Accounting Standards section below for noncash investing and financing activities related to the adoption of a new accounting standard for leasing arrangements. |
(2) | See Note 18 for non-cash financing activities related to derivative restructuring. |
(3) | Includes $37 million of finance leases and $42 million of operating leases entered in 2021, $32 million of finance leases entered in, 2020 and $20 million of finance leases and $35 million of operating leases entered in 2019. |
Distributions from Equity Method Investees Dominion Energy 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
Combined Notes to Consolidated Financial Statements, Continued
as either a return on investment (classified as cash flows from operating activities) or a return of an investment (classified as cash flows from investing activities) when such information is available to Dominion Energy and Dominion Energy Gas. Energy.Derivative Instruments The Companies are exposed to the impact of market fluctuations in the price of electricity, natural gas and other energy-related products they market and purchase, as well as interest rate and foreign currency exchange rate risks of in 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 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. All derivatives, except those for which an exception applies, are required to be reported in the Consolidated Balance Sheets at fair value. Derivative contracts representing unrealized gain positions and purchased options are reported as derivative assets. Derivative contracts representing unrealized losses and options sold are reported as derivative liabilities. One of the exceptions to fair value accounting, normal purchases and normal sales, may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenues resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance. See Note 6 for further information about fair value measurements and associated valuation methods for derivatives.The Companies do not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. Dominion Energy had margin assets of $42 $678million and $95$19 million associated with cash collateral at December 31, 20192021 and 2018,2020, respectively. Dominion Energy’sEnergy had margin liabilities of $2$5million associated with cash collateral at December 31, 2020 and 0 amounts outstanding at December 31, 2021. Virginia Power had margin assets of $167 million and less than $1 million associated with cash collateral at December 31, 20192021 and 2018,2020, respectively. Virginia Power 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 0 margin liabilities associated with cash collateral at December 31, 20192021 and 2018. Dominion Energy Gas had 0 margin assets or liabilities associated with cash collateral at December 31, 2019 and 2018.2020. See Note 7 for further information about derivatives. To manage price and interest rate risk, the Companies hold derivative instruments that are not designated as hedges for accounting purposes. However, to the extent the Companies do not hold offsetting positions for such derivatives, they believe these instruments
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. -AA 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. Dominion Energy entered into interest rate derivative instruments to hedge its forecasted interest payments related to planned debt issuances in 2014. These interest rate derivatives were designated by Dominion Energy as cash flow hedges prior to the formation of Dominion Energy Gas. For the purposes of the Dominion Energy Gas financial statements, the derivative balances, AOCI balance, and any income statement impact related to these interest rate derivative instruments entered into by Dominion Energy have been, and will continue to be, included in the Dominion Energy Gas’ Consolidated Financial Statements as the forecasted interest payments related to the debt issuances now occur at Dominion Energy Gas.
-DominionDominion Energy has also designated interest rate swaps as fair value hedges on certain fixed rate long-term debt to manage interest rate exposure. For fair value hedge transactions, changes in the fair value of the derivative are generally offset currently in earnings by the recognition of changes in the hedged item’s fair value. Hedge accounting is discontinued if the hedged item no longer qualifies for hedge accounting. 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
to cost-of-service rate regulation, AFUDC and overhead costs. The cost of repairs and maintenance, including minor additions and replacements, is generally charged to expense as it is incurred. In 2019, 20182021, 2020 and 2017,2019, Dominion Energy capitalized interest costs and AFUDC to property, plant and equipment of $89$117 million, $134$103 million and $236$78 million, respectively. In 2019, 20182021, 2020 and 2017,2019, Virginia Power capitalized AFUDC to property, plant and equipment of $34$78 million, $56 million and $37 million, respectively. In 2019, 2018 and 2017, Dominion Energy Gas capitalized AFUDC to property, plant and equipment of $31 million, $25$60 million and $34 million, respectively. Under Virginia law, certain Virginia jurisdictional projects qualify for current recovery of AFUDC through rate adjustment clauses. AFUDC on these projects is calculated and recorded as a regulatory asset and is not capitalized to property, plant and equipment. In 2019, 20182021, 2020 and 2017,2019, Virginia Power recorded $35 million, $11 million $4 million and $22$11 million of AFUDC related to these projects, respectively. For property subject to cost-of-service rate regulation, including Dominion 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 cost-of-service rate regulation that will be abandoned significantly before the end of its useful life, the net carrying value is reclassified from plant-in-service when it becomes probable it will be abandoned and recorded as a regulatory asset for amounts expected to be collected through future rates. In 2020 and 2019, Virginia Powerthe Companies had the following charges, primarily recorded in impairment of assets and other charges in the Consolidated Statements of Income (reflected in the Corporate and Other segment), related to early retirements: | • | In March 2020, Virginia Power committed to retire certain coal- and oil-fired generating units before the end of their useful lives based on economic and other factors, including but not limited to market power prices and the VCEA. These units will |
In January 2019, Virginia Power committed to a plan to retire certain automated metering reading infrastructure associated with its electric operations before the end of its estimated useful life and replace such equipment with more current AMI technology. As a result, Virginia Power recorded a charge of $160 million ($119 millionafter-tax).
This charge is considered a component of Virginia Power’s base rates deemed recovered under the GTSA, subject to review as discussed in Note 13. | | be retired after they meet their capacity obligations to PJM in 2023. As a result, Virginia Power recorded a charge of $751 million ($559 million after-tax). This charge is considered a component of Virginia Power’s base rates deemed recovered under the GTSA, subject to review as discussed in Note 13. In addition, see Note 13 for information on the settlement of the 2021 Triennial Review. Also in 2020, Virginia Power recorded charges of $54 million ($40 million after-tax) associated with dismantling certain of these electric generation facilities. |
| • | In January 2019, Virginia Power committed to a plan to retire certain automated metering reading infrastructure associated with its electric operations before the end of its estimated useful life and replace such equipment with more current AMI technology. As a result, Virginia Power recorded a charge of $160 million ($119 million after-tax). This charge is considered a component of Virginia Power’s base rates deemed recovered under the GTSA, subject to review as discussed in Note 13. |
| • | In March 2019, Virginia Power committed to retire certain electric generating units before the end of their useful lives and completed the retirement of certain units at 6 facilities representing 1,292 MW of electric generating capacity, which had previously been placed in cold reserve. An additional unit at Possum Point power station was retired after meeting its capacity obligation to PJM in December 2020. As a result, Virginia Power recorded a charge of $346 million ($257 million after-tax). This charge is considered a component of Virginia Power’s base rates deemed recovered under the GTSA, subject to review as discussed in Note 13. In addition, see Note 13 for information on the settlement of the 2021 Triennial Review. |
| • | In May 2019, Virginia Power abandoned a coal rail project at its Mt. Storm generating facility. As a result, Virginia Power recorded a charge of $62 million ($46 million after-tax). |
| • | In September 2019, the Companies abandoned certain property, plant and equipment before the end of its useful life. As a result, Dominion Energy recorded a charge of $26 million ($19 million after-tax) and Virginia Power recorded a charge of $17 million ($12 million after-tax). |
In March 2019, Virginia Power committed to retire certain electric generating units before the end of their useful lives and completed the retirement of certain units at 6 facilities representing 1,292 MW of electric generating capacity, which had previously been placed in cold reserve. An additional unit at Possum Point power station will be retired after it meets its capacity obligation to PJM in 2021. As a result, Virginia Power recorded a charge of $346 million ($257 millionafter-tax
). This charge is considered a component of Virginia Power’s base rates deemed recovered under the GTSA, subject to review as discussed in Note 13.In May 2019, Virginia Power abandoned a coal rail project at its Mt. Storm generating facility. As a result, Virginia Power recorded a charge of $62 million ($46 millionafter-tax).
In September 2019, Dominion Energy and Virginia Power abandoned certain property, plant and equipment before the end of its useful life. As a result, Dominion Energy recorded a charge of $26 million ($19 millionafter-tax)
and Virginia Power recorded a charge of $17 million ($12 millionafter-tax).
For property that is not subject to cost-of-service rate regulation, including nonutility property, cost of removal not associated with AROs is charged to expense as incurred. The Companies also record gains and losses upon retirement based upon the difference between the proceeds received, if any, and the property’s net book value at the retirement date. Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives. The Companies’ average composite depreciation rates on utility property, plant and equipment are as follows: Year Ended December 31, | | 2021 | | | 2020 | | | 2019 | | (percent) | | | | | | | | | | | | | Dominion Energy(1) | | | | | | | | | | | | | Generation | | | 2.63 | | | | 2.51 | | | | 2.84 | | Transmission | | | 2.47 | | | | 2.48 | | | | 2.50 | | Distribution | | | 2.76 | | | | 2.76 | | | | 2.80 | | Storage | | | 1.79 | | | | 1.59 | | | | 1.49 | | General and other | | | 3.85 | | | | 4.35 | | | | 3.99 | | Virginia Power | | | | | | | | | | | | | Generation | | | 2.69 | | | | 2.52 | | | | 2.94 | | Transmission | | | 2.51 | | | | 2.52 | | | | 2.54 | | Distribution | | | 3.18 | | | | 3.19 | | | | 3.14 | | General and other | | | 5.08 | | | | 5.09 | | | | 4.40 | |
(1) | Excludes rates for depreciation reported as discontinued operations. |
In 2020, Virginia Power expects to receive an updated depreciation studyrates for its nuclear plants in the first quarter
of 2020, which is anticipated to reflect lower depreciation rates as a result of expected approval of license extensions from the NRC.
In 2018, Virginia Power revised depreciation rates for regulated nuclear plants to comply with Virginia Commission requirements. For the year ended December 31, 2018,2020, this adjustment resulted in a decrease of $60$31 million ($ 4423 million after-tax) in depreciation expense in Virginia Power’s Consolidated StatementStatements of Income and an increase to Dominion Energy’s EPS of $0.07$0.03 per share. In January 2022, Dominion Energy revised the estimated useful life of its non-jurisdictional and certain nonregulated solar generation facilities to 35 years. This change resultedrevision is expected to result in an annual decrease inof depreciation expense of $30approximately $20 million ($2315 million after-tax). In 2017,, including approximately $8 million ($6 million after-tax) at Virginia Power, revised the depreciation rates for its assets to reflect the results of a new depreciation study. This change resulted in anand 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 of $26 million ($16 millionafter-tax)
for 2017.Energy’s EPS by approximately $0.02.Virginia Power’s non-jurisdictional property, plant and equipment is depreciated using the straight-line method over an estimated useful life of 30 years.35 years, effective January 2022.
Combined Notes to Consolidated Financial Statements, Continued
Capitalized costs of development wells and leaseholds are amortized on a field-by-field basis using the unit-of-production method and the estimated proved developed or total proved gas and oil reserves, at a rate of $1.80$1.92 and $1.89$1.97 per mcfe in 20192021 and 2018,2020, respectively. Dominion Energy’s nonutility property, plant and equipment is depreciated using the straight-line method over the following estimated useful lives: Asset | | | | EstimatedUsefulLives | Nonregulated generation-nuclear | | | 44 years | Merchant generation-nuclear
Nonregulated generation-solar | | | | | Merchant generation-other
| | | | | Nonutility gas gathering and processing
| | | | | | | | | | | | | | |
Depreciation and amortization related to Virginia Power and Dominion Energy Gas’ nonutility property, plant and equipment and exploration and production properties was immaterial for the years ended December 31, 2019, 2018 and 2017, except for Dominion Energy Gas’ nonutility LNG facility which is depreciated using the straight-line method overestimated useful life of 40 years.
Nuclear fuel used in electric generation is amortized over its estimated service life on a units-of-production basis. Dominion 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 businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds or other benefits through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. The Companies evaluate whether or not recovery of 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: | • | Orders issued by regulatory commissions, legislation and judicial actions; |
Orders issued by regulatory commissions, legislation and judicial actions; | • | 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. |
Past experience;
Discussions with applicable regulatory authorities and legal counsel;
Forecasted earnings; and
Considerations around the likelihood of impacts from events such as unusual weather conditions, extreme weather events and other natural disasters and unplanned outages of facilities.
Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made. A regulatory liability, if considered probable, will be recorded in the period such assessment is made or reversed into earnings if no longer probable. See Notes 12 and 13 to the Consolidated Financial Statements for additional informationinformation.
The Companies lease certain assets including vehicles, real estate, office equipment and other operational assets under both operating and finance leases. For the Companies’ operating leases, rent expense is recognized on a straight-line basis over the term of the lease agreement, subject to regulatory framework. Rent expense associated with operating leases, short-term leases and variable leases is primarily recorded in other operations and maintenance expense in the Companies’ Consolidated Statements of Income. Rent expense associated with finance leases results in the separate presentation of interest expense on the lease liability and amortization expense of the related right-of-use asset in the Companies’ Consolidated Statements of Income or, subject to regulatory framework, is deferred within regulatory assets in the Consolidated Balance Sheets and amortized into the Consolidated Statements of Income. Certain of the Companies’ leases include one or more options to renew, with renewal terms that can extend the lease from one to 70 years. The exercise of renewal options is solely at the Companies’ discretion and is included in the lease term if the option is reasonably certain to be exercised. A right-of-use asset and corresponding lease liability for leases with original lease terms of one year or less are not included in the Consolidated Balance Sheets, unless such leases contain renewal options that the Companies are reasonably certain will be exercised. Additionally, certain of the Companies’ leases contain escalation clauses whereby payments are adjusted for consumer price or other indices or contain fixed dollar or percentage increases. The Companies also have leases with variable payments based upon usage of, or revenues associated with, the leased assets. The determination of the discount rate utilized has a significant impact on the calculation of the present value of the lease liability included in the Companies’ Consolidated Balance Sheets. For the Companies’ fleet of leased vehicles, the discount rate is equal to the prevailing borrowing rate earned by the lessor. For the Companies’ remaining leased assets, the discount rate implicit in the lease is generally unable to be determined from a lessee perspective. As such, the Companies use internally-developed incremental borrowing rates as a discount rate in the calculation of the present value of the lease liability. The incremental borrowing rates are determined based on an analysis of the Companies’ publicly available unsecured borrowing rates, adjusted for a collateral discount, over various lengths of time that most closely correspond to the Companies’ lease maturities.
In addition, Dominion Energy acts as lessor under certain power purchase agreements in which the counterparty or counterparties purchase substantially all of the output of certain solar facilities. These leases are considered operating in nature. For such leasing arrangements, rental revenue and an associated accounts receivable are recorded when the monthly output of the solar facility is determined. Depreciation on these solar facilities is computed on a straight-line basis over an estimated useful life of 30 years. 35 years, effective January 2022.Asset Retirement Obligations The Companies recognize AROs at fair value as incurred or when sufficient information becomes available to determine a reasonable estimate of the fair value of future retirement activities to be performed, for which a legal obligation exists. These amounts are generally capitalized as costs of the related tangible long-lived assets. Since relevant market information is not available, fair value is estimated using discounted cash flow analyses. Quarterly, the Companies assess their AROs to determine if circumstances indicate that estimates of the amounts or timing of future cash flows associated with retirement activities have changed. AROs are adjusted 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. 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.
Debt and Equity Securities with Readily Determinable Fair Values Dominion Energy accounts for and classifies investments in debt securities as trading or available-for-sale securities. Virginia Power classifies investments in debt securities as available-for-sale securities.available-for-sale
securities.• | Debt securities classified as trading securities include securities held by Dominion Energy in rabbi trusts associated with certain deferred compensation plans. These securities are reported in other investments in the Consolidated Balance Sheets at fair value with net realized and unrealized gains and losses included in other income in the Consolidated Statements of Income. |
• | Debt securities classified as trading securities classified as available-for-sale securities include all other debt securities, primarily comprised of securities held in the nuclear decommissioning trusts. These investments are reported at fair value in nuclear decommissioning trust funds in the Consolidated Balance Sheets. Net realized and unrealized gains and losses (including any credit-related impairments) on investments held in nuclear decommissioning trusts are deferred to a regulatory asset or liability, as applicable, for certain jurisdictions subject to cost-based regulation. For all other available-for-sale debt securities, including those held in Dominion Energy’s nonregulated generation nuclear decommissioning trusts, net realized gains and losses (including any credit-related impairments) are included in other income and unrealized gains and losses are reported as a component of AOCI, after-tax. |
include securities held by Dominion Energy in rabbi trusts associated with certain deferred compensation plans. These securities are reported in other investments in the Consolidated Balance Sheets at fair value with net realized and unrealized gains and losses included in other income in the Consolidated Statements of Income.
Debt securities classified as available-for-sale securities
include all other debt securities, primarily comprised of securities held in the nuclear decommissioning trusts. These investments are reported at fair value in nuclear decommissioning trust funds in the Consolidated Balance Sheets. Net realized and unrealized gains and losses (including any other-than-temporary impairments) on investments held in Virginia Power’s nuclear decommissioning trusts are recorded to a regulatory liability for certain jurisdictions subject to cost-based regulation. For all otheravailable-for-sale
debt securities, including those held in Dominion Energy’s merchant generation nuclear decommissioning trusts, net realized gains and losses (including any other-than-temporary impairments) are included in other income and unrealized gains and losses are reported as a component of AOCI,after-tax.
In determining realized gains and losses for debt securities, the cost basis of the security is based on the specific identification method. Credit Impairment The Companies periodically review their available-for-sale debt securities to determine whether a decline in fair value should be considered credit related. If a decline in the fair value of any available-for-sale debt security is determined to be credit related, the credit-related impairment is recorded to an allowance included in nuclear decommissioning trust funds in the Companies’ Consolidated Balance Sheets at the end of the reporting period, with such allowance for credit losses subject to reversal in subsequent evaluations. Using information obtained from their nuclear decommissioning trust fixed-income investment managers, the Companies record in earnings, or defer as applicable for certain jurisdictions subject to cost-based regulation, any unrealized loss for a debt security when the manager intends to sell the debt security or it is more-likely-than-not that the manager will have to sell the debt security before recovery of its fair value up to its cost basis. If that is not the case, but the debt security is deemed to have experienced a credit loss, the Companies record the credit loss in earnings or defer as applicable for certain jurisdictions subject to cost-based regulation, with the remaining non-credit portion of the unrealized loss recorded in AOCI. Credit losses are evaluated primarily by considering the credit ratings of the issuer, prior instances of non-performance by the issuer and other factors Equity Securities with Readily Determinable Fair Values Equity securities with readily determinable fair values include securities held by Dominion Energy in rabbi trusts associated with certain deferred compensation plans and securities held by Dominion Energy and Virginia Powerthe Companies in the nuclear decommissioning trusts. Dominion Energy and Virginia PowerThe Companies record all equity securities with a readily determinable fair value, or for which they are permitted to estimate fair value using NAV (or its equivalent), at fair value in nuclear decommissioning trust funds and other investments in the Consolidated Balance Sheets. However, 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: Equity method investments
when the Companies have the ability to exercise significant influence, but not control, over the
Combined Notes to Consolidated Financial Statements, Continued
| Equity method investments when the Companies have the ability to exercise significant influence, but not control, over the investee. Dominion Energy and Dominion Energy Gas’Energy’s investments are included in investments in equity method affiliates in theirits Consolidated Balance Sheets.Sheets, except for the liability to Atlantic Coast Pipeline or where such investments are classified as held for sale. Dominion Energy and Dominion Energy Gas recordrecords equity method adjustments in other income and earnings from equity method investees, respectively, in theirits Consolidated Statements of Income, including theirits proportionate share of investee income or loss, gains or losses resulting from investee capital transactions, amortization of certain differences between the carrying value and the equity in the net assets of the investee at the date of investment and other adjustments required by the equity method. |
• | Cost method investments when the Companies do not have the ability to exercise significant influence over the investee. The Companies’ investments are included in other investments and nuclear decommissioning trust funds. Cost method investments |
| are reported at cost less impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for identical or similar investments of the same issuer. |
when Dominion Energy and Virginia Power do not have the ability to exercise significant influence over the investee. Dominion Energy and Virginia Power’s investments are included in other investments and nuclear decommissioning trust funds. Cost method investments are reported at cost less impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for identical or similar investments of the same issuer.Other-Than-Temporary Impairment The Companies periodically review their 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. Decommissioning Trust Investments —Special Considerations for Debt Securities
The recognition provisions of other-than-temporary impairment guidance apply only to debt securities classified asavailable-for-sale
orheld-to-maturity.
Using information obtained from their nuclear decommissioning trust fixed-income investment managers, Dominion Energy and Virginia Power record in earnings any unrealized loss for a debt security when the manager intends to sell the debt security or it ismore-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, Dominion Energy and Virginia Power record the credit loss in earnings and any remaining portion of the unrealized loss in AOCI. Credit losses are evaluated primarily by considering the credit ratings of the issuer, prior instances ofnon-performance
by the issuer and other factors.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$26 million and $12$2 million at December 31, 20192021 and December 31, 2018,2020, respectively. Based on the average price of gas purchased during 20192021 and 2018,2020, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by $60$74 million and $87$52 million, respectively. As a result of the Dominion Energy Gas Restructuring, at December 31, 2018, East Ohio’s stored gas inventory is reported in current assets of discontinued operations in the Consolidated Balance Sheets of Dominion Energy Gas.
Natural gas imbalances occur when the physical amount of natural gas delivered from, or received by, a pipeline system or storage facility differs from the contractual amount of natural gas delivered or received. Dominion Energy and Dominion Energy Gas valuevalues these imbalances due to, or from, shippers and operators at an appropriate index price at period end, subject to the terms of its tariff for regulated entities. Imbalances are primarily settled in-kind. Imbalances due to Dominion Energy and Dominion Energy Gas from other parties are reported in other current assets and gas imbalances, respectively, and imbalances that Dominion Energy and Dominion Energy Gas oweowes to other parties are reported in other current liabilities in the Consolidated Balance Sheets. Dominion Energy and Dominion Energy Gas evaluateevaluates goodwill for impairment annually as of April 1 and whenever an event occurs or circumstances change in the interim that would more- likely-than-not
more-likely-than-not reduce the fair value of a reporting unit below its carrying amount. 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, 20182022. Upon adoption, Dominion Energy will apply the guidance using thea modified retrospective method. Uponapproach and will continue to apply the adoptionif-converted method to calculate diluted EPS in connection with any potentially dilutive instruments, or components of the standard, Dominion Energy and Dominion Energy Gas recorded the cumulative-effect of a changeinstruments, that may be settled 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. As a result of adopting this revised accounting guidance, Dominion Energy records offsetting operating revenue and other energy-related purchases fornon-cash
consideration of performing processing and fractionation services related to NGLs. Such amounts at Dominion Energy were $107 million, recorded in the Consolidated Statements of Income for the year ended December 31, 2018. No such amounts were recorded during the year ended December 31, 2017. Dominion Energy and Dominion Energy Gas no longer record offsetting operating revenue and purchased gas for fuel retained to offset costs on certain transportation and storage arrangements. Such amounts at Dominion Energy were $111 million and at Dominion Energy Gas were $71 million, recorded in the Consolidated Statements of Income for the year ended December 31, 2017.In January 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of financial instruments. The guidance became effective for the Companies’ interim and annual reporting periods beginning
January 1, 2018 and the Companies adopted the standard using the modified retrospective method. Upon adoption of this guidance for equity securities held at January 1, 2018, Dominion Energy and Virginia Power recorded the cumulative-effect of a change in accounting principle to reclassify net unrealized gains from AOCI to retained earnings and to recognize equity securities previously categorized as cost method investments at fair value (using NAV) in nuclear decommissioning trust funds in the Consolidated Balance Sheets and a cumulative-effect adjustment to retained earnings. Dominion Energy and Virginia Power reclassified approximately $1.1 billion ($734 millionafter-tax)
and $119 million ($73 millionafter-tax),
respectively, of net unrealized gains from AOCI to retained earnings. Dominion Energy and Virginia Power also recorded approximately $36 million ($22 millionafter-tax)
in net unrealized gains on equity securities previously classified as cost method investments, of which $3 million was recorded to retained earnings and $33 million was recorded to regulatory liabilities for net unrealized gains subject to cost-based regulation. As a result of adopting this revised accounting guidance, Dominion Energy recorded unrealized losses on equity securities, net of regulatory deferrals, of $190 million ($142 millionafter-tax)
in other income in the Consolidated Statements of Income for the year ended December 31, 2018, resulting in an $0.22 loss per share for the year ended December 31, 2018. Virginia Power recorded unrealized losses on equity securities, net of regulatory deferrals, of $24 million ($18 millionafter-tax)
in other income in the Consolidated Statements of Income for the year ended December 31, 2018.In February 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. The update requires that a liability and corresponding right-of-use asset are recorded on the balance sheet for all leases, including those leases classified as operating leases, while also refining the definition of a lease. In addition, lessees are required to disclose key information about the amount, timing and uncertainty of cash flows arising from leasing arrangements. Lessor accounting remains largely unchanged. The guidance became effective for the Companies’ interim and annual reporting periods beginning January 1, 2019. The Companies adopted this revised accounting guidance using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. Under this approach, the Companies utilized the transition practical expedient to maintain historical presentation for periods before January 1, 2019. The Companies also applied the other practical expedients, which required no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no reassessment of existing or expired land easements that were not previously accounted for as leases. In connection with the adoption of this revised accounting guidance, Dominion Energy and Virginia Power and Dominion Energy Gas recorded $504 million $209 million and $64$209 million, respectively, of offsetting right-of-use assets and liabilities for operating leases in effect at the adoption date. As a resultUpon entering an agreement to sell substantially all of Dominion Energy’s gas transmission and storage operations in 2020, $43 million of the Dominion Energy Gas Restructuring, $25 million of suchinitially recorded right-of-use assets and liabilities for operating leases recordedat Dominion Energy Gas were considered activity associated with discontinued operations. See Note 15 for additional information.
Derecognition And Partial Sales Of Nonfinancial Assets
In February 2017, the FASB issued revised accounting guidance clarifying the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets. The guidance became effective for the Companies’ interim and annual reporting periods beginning January 1, 2018, and the Companies adopted the standard using the modified retrospective method. Upon adoption of the standard, Dominion Energy recorded the cumulative-effect of a change in accounting principle to reclassify $127 million from noncontrolling interests to common stock related to the sale of a noncontrolling interest in certain merchant solar projects completed in December 2015 and January 2016.
Net Periodic Pension And Other Postretirement Benefit Costs
In March 2017, the FASB issued revised accounting guidance for the presentation of net periodic pension and other postretirement benefit costs. This guidance became effective for the Companies beginning January 1, 2018 and requires that the service cost component of net periodic pension and other postretirement benefit costs be classified in the same line item as other compensation costs arising from services rendered by employees, while all other components of net periodic pension and other postretirement costs are classified outside of income from operations. In addition, only the service cost component remains eligible for capitalization during construction. These changes do not impact the accounting by participants in a multi-employer plan. The standard also recognizes that in the event that a regulator continues to require capitalization of all net periodic benefit costs prospectively, the difference would result in recognition of a regulatory asset or liability. For costs not capitalized for which regulators are expected to provide recovery, a regulatory asset will be established. As such, the amounts eligible for capitalization in the Consolidated Financial Statements of Virginia Power and Dominion Energy Gas, as subsidiary participants in Dominion Energy’s multi-employer plans, will differ from the amounts eligible for capitalization in the Consolidated Financial Statements of Dominion Energy, the plan administrator. These differences will result in a regulatory asset or liability recorded in the Consolidated Financial Statements of Dominion Energy.
In December 2017, the staff of the SEC issued guidance which clarifies accounting for income taxes if information is not yet available or complete and provided for up to aone-year
measurement period in which to complete the required analyses and accounting. The guidance described three scenarios associated with a company’s status of accounting for income tax reform: (1) a company is complete with its accounting for certain effects of tax reform, (2) a company is able to determine a reasonable estimate for certain effects of tax reform and records that estimate as a provisional amount, or (3) a company is not able to determine a reasonable estimate and therefore continues to apply accounting for income taxes based on the provisions of the tax laws that were in effect immediately prior to the 2017 Tax
Combined Notes to Consolidated Financial Statements, Continued
Reform Act being enacted. The Companies have accounted for the effects of the 2017 Tax Reform Act, although additional changes could occur as guidance is issued and finalized as described below. In addition, the major states in which the Companies operate have addressed conformity with some or all of the provisions of the 2017 Tax Reform Act, although some states have modified certain of these provisions.
In August 2018, the U.S. Department of Treasury issued proposed regulations addressing the availability of federal bonus depreciation for the period beginning after September 27, 2017 through December 31, 2017. The application of these changes decreased Dominion Energy’s net operating loss carryforward utilization on its 2017 tax return. The impacts of proposed and final regulations issued in 2019 on the applicability of accelerated depreciation were immaterial at the Companies, as discussed in Note 5.
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 to partnerships and partners in those partnerships. It is unclear when the guidance may be finalized, or whether that guidance could result in a disallowance of a portion of the Companies’ interest deductions in the future.
In February 2018, the FASB issued revised accounting guidance to provide clarification on the application of the 2017 Tax Reform Act for balances recorded within AOCI. The revised guidance provides for stranded amounts within AOCI from the impacts of the 2017 Tax Reform Act to be reclassified to retained earnings. The Companies adopted this guidance for interim and annual reporting periods beginning January 1, 2018 on a prospective basis. In connection with the adoption of this guidance, Dominion Energy reclassified a benefit of $289 million from AOCI to retained earnings, Virginia Power reclassified a benefit of $3 million from AOCI to retained earnings and Dominion Energy Gas reclassified a benefit of $26 million from AOCI to membership interests. The amounts reclassified reflect the reduction in the federal income tax rate, and the federal benefit of state income taxes, on the components of the Companies’ AOCI.
NoteNOTE 3. Acquisitions And Dispositions ACQUISITIONS AND DISPOSITIONSDominion Energy Disposition of Gas Transmission & Storage Operations In July 2020, Dominion Energy entered into an agreement with BHE with a total value of approximately $10 billion, comprised of approximately $4.0 billion of cash consideration (subject to customary closing adjustments) plus the assumption of long-term debt, to sell substantially all of its gas transmission and storage operations, including processing assets, as well as noncontrolling partnership interests in Iroquois, JAX LNG and White River Hub and a controlling interest in Cove Point (consisting of 100% of the general partner interest and 25% of the total limited partner interests). The agreement provides that Dominion Energy retains the assets and obligations of the pension and other postretirement employee benefit plans associated with the operations included in the transaction and relating to services provided through closing. In October 2020, pursuant to a provision in the agreement with BHE, Dominion Energy elected to exclude the Q-Pipe Group and certain other affiliated entities from the transaction as approval under the Hart-Scott-Rodino Act had not been obtained by mid-September 2020. Concurrently in October 2020, Dominion Energy and BHE entered into a separate agreement under which Dominion Energy would sell the Q-Pipe Group and certain other affiliated entities to BHE for cash consideration of $1.3 billion and the assumption of related long-term debt. In November 2020, Dominion Energy completed the GT&S Transaction and received cash proceeds of $2.7 billion. This transaction was structured as an asset sale for tax purposes. Dominion Energy retained a 50% noncontrolling interest in Cove Point that is accounted for as an equity method investment upon closing of the GT&S Transaction as Dominion Energy has the ability to exercise significant influence over, but not control, Cove Point. The retained 50% noncontrolling interest in Cove Point was recognized at its initial fair value of $2.8 billion on the date of close estimated using an income approach and a market approach. The valuation is considered a Level 3 fair value measurement due to the use of significant judgment and unobservable inputs, including projected timing and amount of future cash flows and a discount rate reflecting risks inherent in the future cash flows and market prices. Upon closing the GT&S Transaction, Dominion Energy recognized a gain of $127 million (net of a $1.4 billion write-off of goodwill and a $222 million closing adjustment paid to BHE in December 2020) and an associated tax expense of $336 million, presented in net income (loss) from discontinued operations including noncontrolling interest in Dominion Energy’s Consolidated Statements of Income. In connection with closing of the GT&S Transaction, Dominion Energy and BHE entered into a transition services agreement under which Dominion Energy will continue to provide specified administrative services to support the operations of the disposed business for up to 24 months after closing, subsequently extended through June 2023 for certain services. In addition, BHE will provide certain administrative services to Dominion Energy. Dominion Energy recorded revenue of $21 million and $4 million associated with the transition service agreement in operating revenue in the Consolidated Statements of Income for the years ended December 31, 2021 and 2020, respectively. Also in November 2020, BHE provided a $1.3 billion deposit to Dominion Energy on the Q-Pipe Transaction. In July 2021, Dominion Energy and BHE mutually agreed to terminate the Q-Pipe Transaction as a result of uncertainty associated with receiving approval under the Hart-Scott-Rodino Act. Also in July 2021, Dominion Energy entered into an approximately $1.3 billion term loan credit agreement and borrowed the full amount available thereunder. The agreement matured in December 2021 and bore interest at a variable rate. The proceeds were utilized to repay the deposit received from BHE on the Q-Pipe Transaction. Upon completion of a sale of the Q-Pipe Group, Dominion Energy was required to utilize the net proceeds to repay any outstanding balances under the term loan agreement. In October 2021, Dominion Energy entered into an agreement with Southwest Gas to sell the Q-Pipe Group. The total value of this transaction is approximately $2 billion, comprised of approximately $1.5 billion of cash consideration (subject to customary closing adjustments) plus the assumption of long-term debt. The agreement provides that Dominion Energy retains the assets and obligations of the pension and other postretirement employee benefit plans associated with the operations included in the transaction and relating to services provided through closing. In December 2021, Dominion Energy completed the sale of the Q-Pipe Group and received cash proceeds of $1.5 billion. This transaction is structured as an asset sale for tax purposes. Upon closing, Dominion Energy recognized a gain of $666 million (net of a $191 million write-off of goodwill) and an associated tax expense of $173 million, presented in net income (loss) from discontinued operations including noncontrolling interest in Dominion Energy’s Consolidated Statements of Income. Also in December 2021, Dominion Energy used the net proceeds from the sale to repay all outstanding balances under the July 2021 term loan agreement and terminated the term loan agreement.
In connection with the closing of the sale of the Q-Pipe Group, Dominion Energy and Southwest Gas entered into a transition services agreement under which Dominion Energy will continue to provide specified administrative services to support the operations of the disposed businesses for up to 12 months after closing, subject to extension. The operations included in both the GT&S Transaction and the Q-Pipe Group are presented in held-for-sale and discontinued operations effective July 2020. As a result, the previously reported amounts have been recast to reflect this presentation and depreciation and amortization ceased on the applicable assets. As Cove Point had previously been consolidated within Dominion Energy’s financial statements, balances associated with Cove Point prior to the closing of the GT&S Transaction are presented within held-for-sale and discontinued operations. See Note 9 for further information regarding Dominion Energy’s equity method investment in Cove Point. The following table represents selected information regarding the results of operations, which are reported within discontinued operations in Dominion Energy’s Consolidated Statements of Income: | | Year Ended December 31, 2021 | | | Year Ended December 31, 2020 | | | Year Ended December 31, 2019 | | | | Q-Pipe Group(1) | | | GT&S Transaction(1) | | | Q-Pipe Group | | | GT&S Transaction | | | Q-Pipe Group | | (millions) | | | | | | | | | | | | | | | | | | | | | Operating revenue | | $ | 254 | | | $ | 1,710 | | | $ | 246 | | | $ | 2,213 | | | $ | 251 | | Operating expense(2) | | | 76 | | | | 1,289 | | | | 96 | | | | 1,367 | | | | 131 | | Other income (loss)(3) | | | 28 | | | | 88 | | | | 1 | | | | 58 | | | | 4 | | Interest and related charges(4) | | | 25 | | | | 372 | | | | 20 | | | | 267 | | | | 20 | | Income before income taxes | | | 181 | | | | 137 | | | | 131 | | | | 637 | | | | 104 | | Income tax expense (benefit)(5) | | | 36 | | | | 334 | | | | (9 | ) | | | 120 | | | | 23 | | Net income (loss) including noncontrolling interests | | | 145 | | | | (197 | ) | | | 140 | | | | 517 | | | | 81 | | Noncontrolling interests | | | — | | | | 106 | | | | — | | | | 11 | | | | — | | Net income (loss) attributable to Dominion Energy | | $ | 145 | | | $ | (303 | ) | | $ | 140 | | | $ | 506 | | | $ | 81 | |
(1) | Operations associated with the Q-Pipe Group are through the December 31, 2021 closing date. Operations associated with the GT&S Transaction are through the November 1, 2020 closing date. |
(2) | GT&S Transaction includes a charge of $482 million ($359 million after-tax) recorded in the second quarter of 2020 associated with the probable abandonment of a significant portion of the Supply Header Project as well as the establishment of a $75 million ARO as a result of the cancellation of the Atlantic Coast Pipeline Project. |
(3) | Q-Pipe Group includes a $25 million benefit associated with the termination of the Q-Pipe Transaction in the third quarter of 2021. |
(4) | GT&S Transaction includes a loss of $237 million ($178 million after-tax) recorded in the third quarter of 2020 associated with cash flow hedges of debt-related items that were determined to be probable of not occurring. |
(5) | Excludes $17 million income tax benefit recorded in 2021 associated with the GT&S Transaction. |
The carrying amounts of major classes of assets and liabilities relating to the Q-Pipe Group, all of which was classified as current and reported as held for sale in Dominion Energy’s Consolidated Balance Sheets at December 31, 2020, were as follows: | | | | | | | | | | (millions) | | | | | | | | | | | Current assets(1) | | | | $ | 47 | | | | | | Equity method investments(2) | | | | | 35 | | | | | | Property, plant and equipment, net | | | | | 1,113 | | | | | | Other deferred charges and other assets, including goodwill(3) and intangible assets | | | | | 224 | | | | | | Current liabilities | | | | | 30 | | | | | | Long-term debt | | | | | 426 | | | | | | Other deferred credits and liabilities | | | | | 154 | | | | | |
(1) | Includes cash and cash equivalents of $7 million. |
(2) | Comprised of equity method investment in White River Hub. |
(3) | Includes goodwill of $191 million. |
Capital expenditures and significant noncash items relating to the disposal groups included the following: | | Year Ended December 31, 2021 | | | Year Ended December 31, 2020 | | | Year Ended December 31, 2019 | | | | Q-Pipe Group(1) | | | GT&S Transaction(1) | | | Q-Pipe Group | | | GT&S Transaction | | | Q-Pipe Group | | (millions) | | | | | | | | | | | | | | | | | | | | | Capital expenditures | | $ | 34 | | | $ | 292 | | | $ | 38 | | | $ | 386 | | | $ | 42 | | Significant noncash items | | | | | | | | | | | | | | | | | | | | | Impairment of assets and other charges | | | — | | | | 469 | | | | — | | | | 13 | | | | 1 | | Charge related to a voluntary retirement program | | | — | | | | — | | | | — | | | | 19 | | | | 3 | | Depreciation, depletion and amortization | | | — | | | | 177 | | | | 27 | | | | 322 | | | | 51 | | Accrued capital expenditures | | | — | | | | — | | | | 1 | | | | 25 | | | | 2 | |
(1) | Operations associated with the Q-Pipe Group are through the December 31, 2021 closing date. Operations associated with the GT&S Transaction are through the November 1, 2020 closing date. |
In October 2020, Dominion Energy settled various derivatives related to, but not included in, the GT&S Transaction for a payment of $165 million. Acquisition of SCANA In January 2019, Dominion Energy issued 95.6 million shares of Dominion Energy common stock, valued at $6.8 billion, representing 0.6690 of a share of Dominion Energy common stock for each share of SCANA common stock, in connection with the completion of the SCANA Combination. SCANA, through its regulated subsidiaries, is primarily engaged in the generation, transmission and distribution of electricity in the central, southern and southwestern portions of South Carolina and in the distribution of natural gas in North Carolina and South Carolina. In addition, at the closing of the SCANA Combination, SCANA marketed natural gas to retail customers in the southeast U.S. Following completion of the SCANA Combination, SCANA operates as a wholly-owned subsidiary of Dominion Energy. In addition, SCANA’s debt totaled $6.9 billion at closing. The SCANA Combination expanded Dominion Energy’s portfolio of regulated electric generation, transmission and distribution and regulated natural gas distribution infrastructure operations. Merger Approval and Conditions The SCANA Combination required approval of SCANA’s shareholders, FERC, the North Carolina Commission, the South Carolina Commission, the Georgia Public Service Commission and the NRC and clearance from the Federal Trade Commission under the Hart-Scott-Rodino Act. All such approvals were received prior to closing of the SCANA Combination.
Various parties filed petitions for rehearing or reconsideration of the SCANA Merger Approval Order. In January 2019, the South Carolina Commission issued an order (1) granting the request of various parties and finding that DESC was imprudent in its actions by not disclosing material information to the South Carolina Office of Regulatory Staff and the South Carolina Commission with regard to costs incurred subsequent to March 2015 and (2) denying the petitions for rehearing or consideration as to other issues raised in the various petitions. The deadline to appeal the SCANA Merger Approval Order and the order on rehearing expired in April 2019, and no party has sought appeal.
As a condition to the SCANA Merger Approval Order, DESC will provide refunds and restitution of $2.0 billion over 20 years with capital support from Dominion Energy. In September and October 2017, DESC received proceeds totaling $1.1 billion in full satisfaction of its share of a settlement agreement among DESC, Santee Cooper and Toshiba Corporation in connection with Westinghouse and WECTEC, both wholly-owned subsidiaries of Toshiba Corporation and responsible for the engineering and construction of the NND Project, filing for bankruptcy. The purchase price allocation below includes a previously established regulatory liability at DESC totaling $1.1 billion, of which $67 million was considered current, associated with the monetization of the bankruptcy settlement with Toshiba Corporation. In accordance with the terms of the SCANA Merger Approval Order, this regulatory liability, net of amounts that may be required to satisfy any liens against NND Project property, totaling $1.0 billion will be refunded to DESC electric service customers over a 20-year period ending in 2039. Additionally, in the first quarter of 2019, DESC recorded a reduction in operating revenue and a corresponding regulatory liability of $1.0 billion, of which $137 million was considered current, representing a refund of amounts previously collected from retail electric customers of DESC for the NND Project to be credited over an estimated 11-year period. period, effective February 2019. As a result, Dominion Energy’s Consolidated StatementStatements of Income for the year ended December 31, 2019 includes a $756 million after-tax charge which is reflected in the Corporate and Other segment.after-tax
charge.
As a condition to the SCANA Merger Approval Order, DESC committed to excluding from rate recovery $2.4 billion of costs related to the NND Project and $180 million of costs associated with the purchase of the Columbia Energy Center power station. Regulatory assets included in SCANA’s historical balance sheet at December 31, 2018 reflected these disallowances. The remaining regulatory asset associated with the NND Project of $2.8 billion, of which $138 million was considered current, will be collected over a 20-year period, including a return on investment. In January 2019, DESC filed the NND Projectcapital cost rider in accordance with the terms of the SCANA Merger Approval Order for rates effective in February 2019 for DESC’s retail electric customers. The South Carolina Commission approved this filing in January 2019. Other Terms and Conditions | • | DESC agreed not to file an application for a general rate case with the South Carolina Commission with a requested effective date earlier than January 2021. See Note 13 for information on the status of DESC’s base rate case; |
| • | PSNC agreed not to file an application for a general rate case with the North Carolina Commission any earlier than April 2021. See Note 13 for information on the status of PSNC’s general rate case; |
DESC will not file an application for a general rate case with the South Carolina Commission with a requested effective date earlier than January 2021; | • | Dominion Energy committed to increasing SCANA’s historical level of corporate contributions to charities by $1 million per year over five years beginning in 2019; |
| • | Dominion Energy will maintain DESC and PSNC’s headquarters in Cayce, South Carolina and Gastonia, North Carolina, respectively; and |
| • | Dominion Energy will seek to minimize reductions in local employment by allowing some DES employees supporting shared and common services functions and activities to be located in Cayce, South Carolina where it makes economic and practical sense to do so. |
PSNC will not file an application for a general rate case with the North Carolina Commission with a requested effective date earlier than April 2021;
Dominion Energy has committed to increasing SCANA’s historical level of corporate contributions to charities by $1 million per year over five years;
Dominion Energy will maintain DESC and PSNC’s headquarters in Cayce, South Carolina and Gastonia, North Carolina, respectively; and
Dominion Energy will seek to minimize reductions in local employment by allowing some DES employees supporting shared and common services functions and activities to be located in Cayce, South Carolina where it makes economic and practical sense to do so.
Purchase Price Allocation SCANA’s assets acquired and liabilities assumed have been measured at estimated fair value at closing and are included in the Dominion Energy South Carolina Gas Transmission & Storage and Gas Distribution operating segments.Distribution. The majority of the operations acquired are subject to the rate setting authority of FERC and the North and South Carolina Commissions and are therefore accounted for pursuant to ASC 980, . The fair values of SCANA’s assets and liabilities subject to rate-setting and cost recovery provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair values of these assets and liabilities equal their carrying values. Accordingly, neither the assets and liabilities acquired, nor the unaudited pro forma financial information, reflect any adjustments related to these amounts. The fair value of SCANA’s assets acquired and liabilities assumed that are not subject to the rate-setting provisions discussed above and the fair values of SCANA’s investments accounted for under the equity method have beenwere determined using the income approach and the market approach. The valuation of SCANA’s long-term debt is considered a Level 2 fair value measurement. All other valuations are considered Level 3 fair value measurements due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risk inherent in the future market prices. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed iswas reflected as goodwill. The goodwill reflects the value associated with enhancing Dominion Energy’s portfolio of regulated operations in the growing southeast region of the U.S. The goodwill recognized is not deductible for income tax purposes, and as such, no deferred taxes have been recorded related to goodwill.
The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at closing, which reflects certain adjustments related to income taxes, as discussed in Note 5, from the preliminary valuation recognized during the measurement period. | Amount | | (millions) | | | | | Total current assets(1) | | $ | 1,782 | | Investments(2) | | | 224 | | Property, plant and equipment(3)(4) | | | 11,006 | | Goodwill | | | 2,609 | | Regulatory assets(5) | | | 3,940 | | Other deferred charges and other assets, including intangible assets(6) | | | 430 | | Total Assets | | | 19,991 | | Total current liabilities(7) | | | 1,556 | | Long-term debt | | | 6,707 | | Deferred income taxes | | | 1,068 | | Regulatory liabilities | | | 2,706 | | Other deferred credits and other liabilities(8) | | | 1,115 | | Total Liabilities | | | 13,152 | | Total purchase price(9) | | $ | 6,839 | |
(1) | Includes $389 million of cash, restricted cash and equivalents, of which $115 million is considered restricted. |
(2) | Includes $31 million for equity method investments. The fair value adjustment on the equity method investments is considered to be equity method goodwill and is not amortized. |
(3) | Includes $105 million of certain property, plant and equipment associated with the NND Project for which Dominion Energy committed to forgo recovery in accordance with the SCANA Merger Approval Order. As a result, Dominion Energy’s Consolidated Statements of Income for the year ended December 31, 2019 include a charge of $105 million ($79 million after-tax), included in impairment of assets and other charges (reflected in the Corporate and Other segment). |
(4) | Nonregulated property, plant and equipment, excluding land, will be depreciated on a straight-line basis over the remaining useful lives of such property, primarily ranging from 5 to 78 years. |
(5) | Includes $258 million of certain income tax-related regulatory assets associated with the NND Project for which Dominion Energy committed to forgo recovery in accordance with the SCANA Merger Approval Order. See Note 5 for additional information. |
(6) | Intangible assets have an estimated weighted-average amortization period of approximately five years. |
(7) | Includes $40 million outstanding under letters of credit advances, which were repaid in January 2019, as well as $173 million outstanding commercial paper under various credit facilities. As discussed in Note 17, allAll such credit facilities were terminated in 2019. |
(8) | Includes a $379 million pension and other postretirement benefit liability. |
(9) | Includes stock-based compensation awards with a fair value of $21 million. |
Results of Operations and Unaudited Pro Forma Information The impact of the SCANA Combination on Dominion Energy’s operating revenue was an increase of $3.6 billion, $3.3 billion and $3.1 billion for the years ended December 31, 2021, 2020 and 2019, respectively, in the Consolidated Statements of Income. The impact of the SCANA Combination on Dominion Energy’s net income attributable to Dominion Energy in the Consolidated Statements of Income was an increase of $3.1 billion$287 million and $277 million for the years ended December 31, 2021 and 2020, respectively, and a decrease of $1.1 billion for the year ended December 31, 2019 respectively.
Combined Notes toin the Consolidated Financial Statements Continued
of Income.Dominion Energy incurred merger and integration-related costs of $31 million and $97 million for the years ended December 31, 2021 and 2020, respectively, all of which is recorded in other operations and maintenance expense in the Consolidated Statements of Income. Dominion Energy incurred merger and integration-related costs of $646 million in the Consolidated Statements of Income for the year ended December 31, 2019. The amount for the year ended December 31, 2019 includes $427 million for a charge related to a voluntary retirement program. See Note 22 for additional information. Of the remaining merger and integration-related costs, $210 million wasis recorded in other operations and maintenance expense and $9 million was recorded in interest and related charges in the Consolidated Statements of Income for the year ended December 31, 2019. During the year ended December 31, 2018, Dominion Energy incurred merger and integration-related costs of $27 million, recorded primarily in other operations and maintenance expense in the Consolidated Statements of Income. These costs consist of professional fees, the charitable contribution commitment described above, employee-related expenses, certain financing costs and other miscellaneous costs.
The following unaudited pro forma financial information reflects the consolidated results of operations of Dominion Energy assuming the SCANA Combination had taken place on January 1, 2018. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of the combined company. | | Twelve Months Ended | | | | December 31, 2019(1) | | (millions, except EPS) | | | | | Operating revenue | | $ | 15,408 | | Net income attributable to Dominion Energy | | | 3,266 | | Earnings Per Common Share – Basic | | $ | 4.04 | | Earnings Per Common Share – Diluted | | $ | 4.00 | |
| | | | | | | | | | | Twelve
Months Ended
December 31, | | | | | | | | | | | | | | | | | | $ | | | | $ | | | Net income attributable to Dominion Energy | | | | | | | | | Earnings Per Common Share – Basic | | $ | | | | $ | | | Earnings Per Common Share – Diluted | | $ | | | | $ | | |
(1) | Amounts include adjustments fornon-recurring costs directly related to the SCANA Combination. |
Sale of Interest Inin Cove Point In October 2019, Dominion Energy signed an agreement to sell theits 25% noncontrolling limited partnership interests in Cove Point not contributed to Dominion Energy Gas in the Dominion Energy Gas Restructuring to Brookfield. In December 2019, the sale was completed and Dominion Energy received cash consideration of $2.1 billion, subject to working capital adjustments. The sale was accounted for by Dominion Energy following the guidance for a change in a parent company’s ownership interest in a consolidated subsidiary. Because Dominion Energy controlscontrolled Cove Point both before and after the sale of the noncontrolling interest, the changeschange in Dominion Energy’s ownership interest in Cove Point was accounted for as an equity transaction and no gain or loss was recognized. AcquisitionsSale of Wholly-Owned Merchant Solar Projects HopeIn February 2022, Dominion Energy entered into an agreement to sell 100% of the equity interests in Hope to Ullico for $690 million of cash consideration, subject to customary closing adjustments. The following table presentssale will be treated as a stock sale for tax purposes and is expected to close by the end of 2022, contingent on clearance or approval under the Hart-Scott-Rodino Act and from the West Virginia Commission, and other customary closing and regulatory conditions. While Dominion Energy is still completing its evaluation, it does not expect to record a significant gain or loss associated with the sale. Dominion Energy will reclassify the assets and liabilities to be disposed of, currently reflected in Gas Distribution, as held for sale starting in the first quarter of 2022. Sale of Kewaunee In May 2021, Dominion Energy entered into an agreement to sell 100% of the equity interests in Dominion Energy Kewaunee, Inc. to EnergySolutions, including the transfer of all decommissioning obligations associated with Kewaunee, which ceased operations in 2013. The agreement provides that Dominion Energy retains the assets and obligations of the pension and other postretirement employee benefit plans. In addition, Dominion Energy may continue to withdraw funds prior to closing from the nuclear decommissioning trust to recover certain spent nuclear fuel and other permitted costs, subject to certain conditions. The sale will be treated as an asset sale for tax purposes and is subject to termination by either party if not completed acquisitionsby December 2022. Closing is contingent on approval from the Wisconsin Commission as well as the NRC for the transfer of wholly-owned merchant solar projectscontrol of applicable licenses. The purchase agreement requires that EnergySolutions be subject to the Wisconsin regulatory conditions agreed to by Dominion Energy. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Completed Acquisition
Date | | | | | | | | | | | | | | Initial Acquisition (millions) (1) | | | | | | Date of
Commercial
Operations | | | | | | | | Community Energy Solar, LLC | | | | | | | | | | | | Amazon Solar Farm Virginia—Southhampton | | | $ | | | | $ | | | | | | | | | | | | | | Solar Frontier Americas Holding LLC | | | | | (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cypress Creek Renewables, LLC | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Hecate Energy Virginia C&C LLC | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Strata Solar Development, LLC/Moorings Farm 2 Holdco, LLC | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Hecate Energy Virginia C&C LLC | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Strata Solar Development, LLC | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(1) | The purchase price was primarily allocated to property, plant and equipment. |
(2) | Includes acquisition cost. |
(3) | In April 2017, Dominion Energy discontinued efforts on the acquisition of the additional 20 MW solar project from Solar Frontier Americas Holding LLC. |
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 addition during 2016,May 2021, Dominion Energy and EnergySolutions submitted a license transfer application to the NRC. Also in May 2021, Dominion Energy submitted an application to the Wisconsin Commission for approval. In July 2021, WPSC and WP&L submitted a joint request to the Wisconsin Commission for the waiver of both of their rights of first refusal to purchase Kewaunee, such rights having been granted as the former owners of Kewaunee. At December 31, 2021, Dominion Energy determined that the assets and liabilities associated with the Kewaunee sale, included in Contracted Assets, did not meet the criteria to be classified as held for sale due to the significant uncertainty surrounding the timing of or ability to obtain necessary regulatory approvals. Dominion Energy expects to record a loss if and when it determines that criteria for the classification as held for sale have been met. If such classification had been made at December 31, 2021, Dominion Energy would have recognized a loss of approximately $725 million ($570 million after-tax). If the sale is ultimately completed, the final net loss will primarily depend on the value of the nuclear decommissioning trust and AROs at closing. Acquisition of Birdseye In May 2021, Dominion Energy acquired 100% of the equity interestsownership interest in Birdseye from BRE Holdings, LLC for total consideration of 7$46 million, consisting of $28 million in cash and $18 million, measured at fair value at closing, of consideration contingent on the achievement of certain revenue targets and future development project sales. Birdseye is primarily engaged in the development of solar energy projects in Virginia, North Carolina and South Carolina for an aggregatesoutheastern states in the U.S. with 2.5 GW of solar generation projects under development. The allocation of
the purchase price resulted in $25 million of $32development project assets, primarily reflected in other deferred charges and other assets in Dominion Energy’s Consolidated Balance Sheets, and $24 million all of goodwill, which was allocated to property, plantis not deductible for tax purposes. The goodwill reflects the value associated with enhancing Dominion Energy's development of regulated and equipment.long-term contracted solar generating and electric storage projects. The projects cost $421 million in total,fair value measurements, including initial acquisition costs, and generate 221 MW combined. One of the projects commenced commercial operations in 2016assets acquired, were determined using the income approach and are considered Level 3 fair value measurements due to the remaining projects commenced commercial operations in 2017. Long-term power purchase, interconnectionuse of significant judgmental and operationunobservable inputs, including projected timing and maintenance agreements have been executed for allamount of the projects described above. These projects arefuture cash flows. Birdseye is included in Contracted Generation. Dominion Energy has claimed federal investment tax credits on these solar projects.
Dominion Energy Gas Restructuring
The Dominion Energy Gas Restructuring is considered to be a reorganization of entities under common control. As a result, Dominion Energy Gas’ basis in DCP and DMLPHCII, which includes the general partner of Dominion Energy Midstream, a controlling 75% interest in Cove Point, DECG, Dominion Energy Questar Pipeline, a 50% noncontrolling interest in White River Hub and a 25.93% noncontrolling interest in Iroquois, is equal to Dominion Energy’s cost basis in the assets and liabilities of such entities since the applicable inception dates of common control. In November 2019, following completion of the Dominion Energy Gas Restructuring, DCP and DMLPHCII are wholly-owned subsidiaries of Dominion Energy Gas and therefore are consolidated by Dominion Energy Gas. The accompanying Consolidated Financial Statements and Notes of Dominion Energy Gas have been retrospectively adjusted to include the historical results and financial position of DCP and DMLPHCII. The 25% interest in Cove Point retained by Dominion Energy, and subsequently sold to Brookfield in December 2019, and thenon-Dominion
Energy held interest in Dominion Energy Midstream are reflected as noncontrolling interest.The Dominion Energy Gas Restructuring includes the disposition of East Ohio and DGP by Dominion Energy Gas in November 2019. This restructuring represents a strategic shift in the operations of Dominion Energy Gas as Dominion Energy Gas’ operations consists
of LNG import/export and storage and regulated gas transmission and storage operations. As a result, the accompanying Consolidated Financial Statements and Notes of Dominion Energy Gas have been retrospectively adjusted to include the historical results and financial position of East Ohio and DGP as discontinued operations until November 2019, presented within the Corporate and Other segment. As the Dominion Energy Gas Restructuring is considered to be a reorganization of entities under common control, Dominion Energy Gas has reflected the disposition as an equity transaction.The following table represents selected information regarding the results of operations of East Ohio, which are reported as discontinued operations in Dominion Energy Gas’ Consolidated Statements of Income:
| | | | | | | | | | | | | | | | Period Ended
November 6, 2019 | | | Year Ended
December 31, 2018 | | | Year Ended
December 31, 2017 | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | Depreciation and amortization | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Interest and related charges | | | | | | | | | | | | | | | | | | | | | | | | | | Net income from discontinued operations | | | | | | | | | | | | |
The carrying amounts of major classes of assets and liabilities relating to East Ohio, which are reported as discontinued operations in Dominion Energy Gas’ Consolidated Balance Sheets were as follows:
| | | | | | | | | | | | | Current assets of discontinued operations(1)
| | $ | | | | | | | | Property, plant and equipment, net
| | | | | | | | | | Other deferred charges and other assets, including goodwill and intangible assets
| | | | | Noncurrent assets of discontinued operations
| | | | | Current liabilities of discontinued operations
| | | | | | | | | | Deferred income taxes and investment tax credits
| | | | | | | | | | Other deferred credits and liabilities
| | | | | Noncurrent liabilities of discontinued operations
| | | | |
(1) | Includes cash and cash equivalents of $9 million as of December 31, 2018. |
Capital expenditures and significant noncash items relating to East Ohio included the following:
| | | | | | | | | | | | | | | | Period Ended
November 6, 2019 | | | Year Ended
December 31, 2018 | | | Year Ended
December 31, 2017 | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | Significant noncash items : | | | | | | | | | | | | | Charge related to a voluntary retirement program | | | | | | | — | | | | — | | Accrued capital expenditures | | | | | | | | | | | | |
The following table represents selected information regarding the results of operations of DGP, which are reported as discontinued operations in Dominion Energy Gas’ Consolidated Statements of Income:
| | | | | | | | | | | | | | | | Period Ended
November 6, 2019 | | | Year Ended
December 31, 2018 | | | Year Ended
December 31, 2017 | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | Depreciation and amortization | | | | | | | | | | | | | Impairment of assets and related charges | | | | | | | | | | | | | | | | | | | | | | | | | | Income tax expense (benefit) | | | | | | | | ) | | | | | Net income (loss) from discontinued operations | | $ | | | | $ | | ) | | $ | | |
Combined Notes to Consolidated Financial Statements, Continued
The carrying amounts of major classes of assets and liabilities relating to DGP, which are reported as discontinued operations in Dominion Energy Gas’ Consolidated Balance Sheets were as follows:
| | | | | | | | | | | | | Current assets of discontinued operations(1)
| | $ | | | Noncurrent assets of discontinued operations(2)
| | | | | Current liabilities of discontinued operations
| | | | | Noncurrent liabilities of discontinued operations
| | | | |
(1) | Includes cash and cash equivalents of less than $1 million. |
(2) | Primarily property, plant and equipment, net. |
Capital expenditures and significant noncash items of DGP included the following:
| | | | | | | | | | | | | | | | Period Ended
November 6, 2019 | | | Year Ended
December 31, 2018 | | | Year Ended
December 31, 2017 | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | Significant noncash items : | | | | | | | | | | | | | Impairment of assets and related charges | | | | | | | | ) | | | — | |
Assets.NoteNOTE 4. Operating Revenue OPERATING REVENUEThe Companies’ operating revenue subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, consists of the following: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Regulated electric sales: | | | | | | | | | | | $ | | | | $ | | | | | | | | | | | | | | | | | | | | | Government and other retail | | | | | | | | | | | | | | | | | | Nonregulated electric sales | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Regulated gas transportation and storage: | | | | | | | | | | | | | | | | | | | | | | | | | | | Nonregulated gas transportation and storage | | | | | | | | | | | | | | | | | | Other nonregulated revenues (1)(2) | | | | | | | | | Total operating revenue from contracts with customers | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | | | | | | | | | Regulated electric sales: | | | | | | | | | | | $ | | | | $ | | | | | | | | | | | | | | | | | | | | | Government and other retail | | | | | | | | | | | | | | | | | | | | | | | | | | | Other nonregulated revenues (1)(2) | | | | | | | | | Total operating revenue from contracts with customers | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | | | | | | | | | Regulated gas sales—wholesale | | $ | | | | $ | | | Nonregulated gas sales (1) | | | | | | | | | Regulated gas transportation and storage | | | | | | | | | Nonregulated gas transportation and storage | | | | | | | | | Management service revenue (1) | | | | | | | | | | | | | | | | | | Other nonregulated revenues | | | | | | | | | Total operating revenue from contracts with customers | | | | | | | | | | | | | | | | | ) | | | $ | | | | $ | | |
Year Ended December 31, | | 2021 | | | 2020 | | | 2019 | | (millions) | | | | | | | | | | | | | Dominion Energy | | | | | | | | | | | | | Regulated electric sales: | | | | | | | | | | | | | Residential | | $ | 4,509 | | | $ | 4,833 | | | $ | 4,325 | | Commercial | | | 3,194 | | | | 3,102 | | | | 3,219 | | Industrial | | | 748 | | | | 730 | | | | 683 | | Government and other retail | | | 921 | | | | 868 | | | | 873 | | Wholesale | | | 175 | | | | 128 | | | | 176 | | Nonregulated electric sales | | | 1,005 | | | | 823 | | | | 941 | | Regulated gas sales: | | | | | | | | | | | | | Residential | | | 1,455 | | | | 1,283 | | | | 1,343 | | Commercial | | | 527 | | | | 457 | | | | 457 | | Other | | | 135 | | | | 88 | | | | 109 | | Nonregulated gas sales | | | 96 | | | | 174 | | | | 495 | | Regulated gas transportation and storage | | | 945 | | | | 801 | | | | 742 | | Other regulated revenues | | | 265 | | | | 327 | | | | 252 | | Other nonregulated revenues(1)(2) | | | 195 | | | | 138 | | | | 130 | | Total operating revenue from contracts with customers | | | 14,170 | | | | 13,752 | | | | 13,745 | | Other revenues(3)(4) | | | (206 | ) | | | 420 | | | | 656 | | Total operating revenue | | $ | 13,964 | | | $ | 14,172 | | | $ | 14,401 | | Virginia Power | | | | | | | | | | | | | Regulated electric sales: | | | | | | | | | | | | | Residential | | $ | 3,366 | | | $ | 3,677 | | | $ | 3,657 | | Commercial | | | 2,417 | | | | 2,342 | | | | 2,712 | | Industrial | | | 367 | | | | 380 | | | | 455 | | Government and other retail | | | 862 | | | | 804 | | | | 823 | | Wholesale | | | 107 | | | | 90 | | | | 128 | | Nonregulated electric sales | | | 44 | | | | 19 | | | | 15 | | Other regulated revenues | | | 234 | | | | 299 | | | | 190 | | Other nonregulated revenues(1)(2) | | | 73 | | | | 50 | | | | 56 | | Total operating revenue from contracts with customers | | | 7,470 | | | | 7,661 | | | | 8,036 | | Other revenues(1)(3) | | | — | | | | 102 | | | | 72 | | Total operating revenue | | $ | 7,470 | | | $ | 7,763 | | | $ | 8,108 | |
(1) | See Notes 9 and 25 for amounts attributable to related parties and affiliates. |
(2) | Amounts above includeIncludes sales which are considered to be goods transferred at a point in time. Fortime of $34 million, $22 million and $37 million for the years ended December 31, 2021, 2020 and 2019, respectively, at Dominion Energy, primarily consisting of sales of commodities related to nonregulated extraction activities and 2018, such amounts included $171other miscellaneous products. Additionally, sales of renewable energy credits were $33 million, $20 million and $241$24 million for the years ended December 31, 2021, 2020 and 2019, respectively, at Dominion Energy and $5$21 million, $11 million and $10$17 million respectively, at Dominion Energy Gas, primarily consisting of NGL sales. Additionally, amounts above include sales of renewable energy credits. Forfor the years ended December 31, 2021, 2020 and 2019, and 2018, such sales were $24respectively, at Virginia Power. |
(3) | Includes alternative revenue of $56 million, $119 million and $ 17$66 million respectively, at Dominion Energy and $17$44 million, and $11 million, respectively, at Virginia Power. |
(3) | Includes alternative revenue of $66$82 million and $52 million at Virginia Power for the yearyears ended December 31, 2021, 2020 and 2019, at Dominion Energyrespectively. |
(4) | Includes revenue associated with services provided to discontinued operations of $5 million, $4 million and Virginia Power, respectively, and $15$6 million for yearthe years ended December 31, 2018 at both Dominion Energy2021, 2020 and Virginia Power.2019, respectively. |
The table below discloses the aggregate amount of the transaction price allocated to fixed-price performance obligations that are unsatisfied (or partially unsatisfied) at the end of the reporting period and when 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 contracts in place at December 31, 2019 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Revenue expected to be recognized on multi-year contracts in place at December 31, 2021 | | 2022 | | | 2023 | | | 2024 | | | 2025 | | | 2026 | | | Thereafter | | | Total | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dominion Energy(1) | | $ | 68 | | | $ | 66 | | | $ | 59 | | | $ | 51 | | | $ | 45 | | | $ | 448 | | | $ | 737 | |
(1) | Includes no amounts for Virginia Power. |
Contract assets represent an entity’s right to consideration in exchange for goods and services that the entity has transferred to a customer. At December 31, 2019 and 2018, Dominion Energy’s contract asset balances were $28 million and $42 million, respectively. Dominion Energy Gas’ contract asset balances were $40 million and $58 million at December 31, 2019 and 2018 respectively. Dominion Energy and Dominion Energy Gas’ contract assets are recorded in other deferred charges and other assets in the Consolidated Balance Sheets. 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, 20192021 and 2018,2020, Dominion Energy’s contract liability balances were $123$124 million and $106$130 million, respectively. At December 31, 20192021 and 2018,2020, Virginia Power’s contract liability balances were $24$33 million and $22 million, respectively. At December 31, 2019 and 2018, Dominion Energy Gas’ contract liability balances were $20 million and $28$36 million, respectively. The Companies’ contract liabilities are recorded in other current liabilities and other deferred credits and other liabilities in the Consolidated Balance Sheets. The Companies’Companies recognize revenue as they fulfill their obligations to provide service to their customers. During both the years ended December 31, 20192021 and 2018,2020, Dominion Energy recognized revenue of $94$124 million and $97 million from the beginning contract liability balance. During the years ended December 31, 20192021 and 2018 ,
2020, Virginia Power recognized revenue of $22$36 million and $25$24 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.The Companies’ operating revenue, prior to the adoption of revised guidance for revenue recognition from contracts with customers, consisted of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | Gas transportation and storage | | | | | | | | | | | | $ | | | | | | | | | | $ | | | | | | | | | | $ | | | | | | | | | | | | | | | $ | | | | | | | | Gas transportation and storage | | | | | | | | | | | | $ | | |
INCOME TAXESJudgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws and associated regulations involves uncertainty, since tax authorities may interpret the laws differently. The Companies are routinely audited by federal and state tax authorities. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.
Combined Notes to Consolidated Financial Statements, Continued
The Companies have accounted for the effects of the 2017 Tax Reform Act, included a broad rangealthough additional changes could occur as guidance is issued and finalized as described below. In July 2020, the U.S. Department of tax reform provisions affectingTreasury issued final regulations providing guidance about the Companies as discussed in Note 2. Thelimitation on the deduction for business interest expenses under the 2017 Tax Reform Act. Under the 2017 Tax Reform Act, reduced the corporatedeductions for net interest expense are limited to 30% of adjusted taxable income, tax rate from 35%which has, until this point, been defined similarly to 21% forEBITDA (earnings before interest, taxes, depreciation and amortization). For tax years beginning after December 31, 2017. At2021, the datecalculation of enactment, deferred tax assetsadjusted taxable income is defined similarly to EBIT (earnings before interest and liabilities were remeasured based upon the new 21% enacted tax rate expected to apply whentaxes). For consolidated groups such as Dominion Energy that have both regulated and nonregulated operations, these rules may result in a temporary differences are realized or settled. The specific provisions related to regulated public utilitiesdisallowance of a portion of Dominion Energy’s interest deductions in the 2017 Tax Reform Act generally allowfuture, although any interest disallowed has an indefinite carryforward period. In December 2020, federal legislation was enacted that, among other things, provides a two-year extension of the beginning construction deadline for, and delays the phase-down of, the solar energy investment tax credit as well as extending the deadlines and phase-down rules for certain other renewable tax credits. The legislation provides that offshore wind facilities are eligible for the continued deductibilityinvestment tax credit if construction on those facilities begins before 2026 with no phase-out. In addition, the U.S. Department of interest expense, changedTreasury and the IRS issued guidance for offshore wind that extended the continuity of construction safe harbor to 10 years, which significantly enhances the ability for these projects to qualify for renewable energy tax depreciation of certain property acquired after September 27, 2017, and continued certain rate normalization requirements for accelerated depreciation benefits. credits. As indicated in Note 2, certain of the Companies’ operations, including accounting for income taxes, are subject to regulatory accounting treatment. For regulated operations, many of the changes in deferred taxes from the 2017 Tax Reform Act represent amounts probable of collection from or 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 taxes may be passed back to customers for certain accelerated tax depreciation benefits. Potential refunds of other deferred taxes may be determined by the Companies’ regulators. See Note 13 for more information.
The Companies have accounted for the effects of the 2017 Tax Reform Act, although changes could occur as additional guidance is issuedinformation and finalized, particularly as it relates to the deductibility of interest expense in consolidated groups such as Dominion Energy. In addition, the major states in which the Companies operate have addressed conformity with some or all of the provisions of the 2017 Tax Reform Act, although some states have modified certain of these provisions. The changes in deferred taxes resulting from the 2017 Tax Reform Act, and the Companies’ interpretations of proposed regulations issued in 2018 on the applicability of accelerated depreciation, were recorded as either an increase to a regulatory liability or as an adjustment to the deferred tax provision. The impacts of proposed and final regulations issued in 2019 on the applicability of accelerated depreciation were immaterial at the Companies.current year developments.
Details of income tax expense for continuing operations including noncontrolling interests were as follows: | | Dominion Energy | | | Virginia Power | | Year Ended December 31, | | 2021 | | | 2020 | | | 2019 | | | 2021 | | | 2020 | | | 2019 | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | Current: | | | | | | | | | | | | | | | | | | | | | | | | | Federal | | $ | (162 | ) | | $ | (314 | ) | | $ | (94 | ) | | $ | 67 | | | $ | 364 | | | $ | 286 | | State | | | 45 | | | | (81 | ) | | | 58 | | | | (13 | ) | | | 71 | | | | 58 | | Total current expense (benefit) | | | (117 | ) | | | (395 | ) | | | (36 | ) | | | 54 | | | | 435 | | | | 344 | | Deferred: | | | | | | | | | | | | | | | | | | | | | | | | | Federal | | | | | | | | | | | | | | | | | | | | | | | | | Taxes before operating loss carryforwards, investment tax credits and tax reform | | | 151 | | | | 12 | | | | 168 | | | | 145 | | | | (226 | ) | | | (128 | ) | Tax utilization expense of operating loss carryforwards | | | 43 | | | | 44 | | | | 119 | | | | 0 | | | | 0 | | | | 0 | | Investment tax credits | | | 250 | | | | 311 | | | | (51 | ) | | | (39 | ) | | | (27 | ) | | | (34 | ) | State | | | (19 | ) | | | 72 | | | | (50 | ) | | | 118 | | | | 7 | | | | 22 | | Total deferred expense (benefit) | | | 425 | | | | 439 | | | | 186 | | | | 224 | | | | (246 | ) | | | (140 | ) | Investment tax credit-gross deferral | | | 121 | | | | 42 | | | | 62 | | | | 121 | | | | 42 | | | | 62 | | Investment tax credit-amortization | | | (4 | ) | | | (3 | ) | | | (3 | ) | | | (2 | ) | | | (2 | ) | | | (2 | ) | Total income tax expense | | $ | 425 | | | $ | 83 | | | $ | 209 | | | $ | 397 | | | $ | 229 | | | $ | 264 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | ) | | $ | | ) | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | ) | | $ | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | Total current expense (benefit) | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2017 Tax Reform Act impact (1) | | | | | | | | | | | | ) | | | | | | | | | | | | ) | | | | | | | | ) | | | | ) | Taxes before operating loss carryforwards, investment tax credits and tax reform | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | ) | | | | | | | | | Tax utilization expense (benefit) of operating loss carryforwards | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | | | | | | | | | | | | | | | | | ) | | | | ) | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | | Total deferred expense (benefit) | | | | | | | | | | | | ) | | | | ) | | | | | | | | | | | | ) | | | | | | | | ) | Investment tax credit-gross deferral | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Investment tax credit-amortization | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | | | | | | | | | | | | | Total income tax expense (benefit) | | $ | | | | $ | | | | $ | | ) | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | ) |
(1) | The 2017 Tax Reform Act impact for Dominion Energy Gas includes an expense of $8 million forIn 2021, Dominion Energy’s current income taxes reflect a benefit from continuing operations as the year ended December 31, 2018 and a benefit of $93 million for the year ended December 31, 2017 arising from discontinued operations. |
The 2017 Tax Reform Act reduced the statutory federal income tax rateexpense associated with the QPipe Group’s operations, including taxes on the gain, is reflected in discontinued operations. Dominion Energy’s income tax expense reflects the utilization of investment tax credit carryforwards to 21% beginning in January 2018. Accordingly,offset a portion of the federal tax gain on the sale.In 2020, Dominion Energy’s current and deferred income taxes are recorded atreflect a benefit from continuing operations as the new 21% rate. income tax expense associated with gas transmission and storage operations, including taxes on the gain, is reflected in discontinued operations. Dominion Energy’s income tax expense reflects the utilization of investment tax credit carryforwards to offset a portion of the federal tax gain on the sale. In addition, an $18 million income tax benefit is reflected in common shareholders’ equity associated with state deferred taxes on assets and liabilities retained in connection with the GT&S Transaction.In 2019, the Dominion Energy Gas Restructuring caused changes in tax status at certain of its subsidiaries. The impacts of the changes in tax status decreased deferred income tax expense from continuing operations by $48 million at Dominion Energy and Dominion Energy Gas.Energy. In addition, Dominion Energy recognized a taxable gain resulting from the sale of a 25% noncontrolling interest in Cove Point. The direct tax effects of the transactions included a provision for current income taxes ($362 million) and an offsetting benefit for deferred income taxes ($147 million) and were charged to common shareholders’ equity. The utilization of $208 million federal tax credit carryforwards offsetting a portion of the federal tax liability from the transaction were also charged to common shareholders’ equity. In total, the taxes recorded in common shareholders’ equity resulting from this transaction were $215 million. In 2018, Dominion Energy had less than $1 million of state deferred incomeDiscontinued Operations Income tax expense as a result of(benefit) reflected in discontinued operations is $188 million, $(204) million and $142 million for the reversal of deferred taxes upon the sale of its interest in Blue Raceryears ended December 31, 2021, 2020 and Fairless and Manchester. Dominion Energy’s current federal2019, 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. In 2017, the accounting for the reduction in the corporatefinalizing income tax rate decreased deferredreturns on the GT&S Transaction and the absence of a $36 million benefit on non-deductible goodwill written off in connection with the sale of the Q-Pipe Group. The 2020 income tax expense by $851 million at Dominion Energy, $93 million at Virginia Power and $246reflects a charge of $81 million for Dominion Energy Gas for the year ending December 31, 2017. The decrease in deferred income taxes at Dominion Energy primarily relates to the remeasurementwrite-off of deferred taxes on nonregulated operations and includes the effects at Virginia Power and Dominion Energy Gas. Virginia Power and Dominion Energy Gas have certaintax-related regulatory assets associated with the Atlantic Coast Pipeline Project and liabilities that have not yet been charged or returned to customers through rates, orthe absence of a $236 million benefit on which they do not earn a return, including unrecognized pension and other postretirement benefits. The remeasurement ofnon-deductible goodwill written off in connection with the deferred taxes on these regulatory balances was chargedGT&S Transaction.
to continuing operations in 2017. For ratemaking purposes, Dominion Energy Gas’ subsidiary DETI follows the cash method on pension contributions. Deferred taxes recorded on pension balances as required by GAAP are not included as a component of rates and therefore the remeasurement of these deferred taxes were charged to continuing operations in 2017.
Discontinued Operations—Dominion Energy Gas
Tax expense reported in discontinued operations for the period ended November 6, 2019 was $33 million. Tax expense reported in discontinued operations for years ended December 31, 2018 and 2017 at Dominion Energy Gas was less than $1 million and $91 million, respectively. Tax expense for discontinued operations included benefits of utilizing an immaterial amount of operating loss carryforwards in 2018 and $5 million in 2017.
For continuing operations including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to the Companies’ effective income tax rate as follows: | | Dominion Energy | | | Virginia Power | Year Ended December 31, | | 2021 | | | 2020 | | | 2019 | | | 2021 | | | 2020 | | | 2019 | | | U.S. statutory rate | | | 21.0 | | % | | 21.0 | | % | | 21.0 | | % | | 21.0 | | % | | 21.0 | | % | | 21.0 | | % | Increases (reductions) resulting from: | | | | | | | | | | | | | | | | | | | | | | | | | | State taxes, net of federal benefit | | | 2.6 | | | | 2.0 | | | | 1.5 | | | | 4.6 | | | | 4.8 | | | | 4.5 | | | Investment tax credits | | | (3.2 | ) | | | (9.6 | ) | | | (11.4 | ) | | | (3.0 | ) | | | (4.5 | ) | | | (2.9 | ) | | Production tax credits | | | (0.4 | ) | | | (0.7 | ) | | | (2.1 | ) | | | (0.6 | ) | | | (0.7 | ) | | | (0.7 | ) | | Valuation allowances | | | 0.1 | | | | 0.9 | | | | 0.5 | | | | 0 | | | | 0 | | | | 0 | | | Reversal of excess deferred income taxes | | | (3.2 | ) | | | (5.4 | ) | | | (3.2 | ) | | | (2.1 | ) | | | (2.2 | ) | | | (3.1 | ) | | State legislative change | | | (0.7 | ) | | | 0 | | | | 0 | | | | (0.7 | ) | | | 0 | | | | 0 | | | Write-off of regulatory assets | | | 0 | | | | 0 | | | | 21.7 | | | | 0 | | | | 0 | | | | 0 | | | Change in tax status | | | 0 | | | | (1.7 | ) | | | (5.5 | ) | | | 0 | | | | 0 | | | | 0 | | | AFUDC—equity | | | (0.4 | ) | | | (0.2 | ) | | | (0.2 | ) | | | (0.5 | ) | | | 0 | | | | 0 | | | Changes in state deferred taxes associated with assets held for sale | | | (0.3 | ) | | | (3.2 | ) | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | Absence of tax on noncontrolling interest | | | (0.1 | ) | | | 3.8 | | | | (0.2 | ) | | | 0 | | | | 0 | | | | 0 | | | Settlements of uncertain tax positions | | | (1.2 | ) | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | Employee stock ownership plan deduction | | | (0.3 | ) | | | (0.9 | ) | | | (1.4 | ) | | | 0 | | | | 0 | | | | 0 | | | Nondeductible goodwill | | | 0 | | | | 0 | | | | 1.8 | | | | 0 | | | | 0 | | | | 0 | | | Other, net | | | (0.2 | ) | | | (0.1 | ) | | | 1.5 | | | | 0.1 | | | | (0.1 | ) | | | (0.2 | ) | | Effective tax rate | | | 13.7 | | % | | 5.9 | | % | | 24.0 | | % | | 18.8 | | % | | 18.3 | | % | | 18.6 | | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | % | | | | % | | | | % | | | | % | | | | % | | | | % | | | | % | | | | % | | | | % | Increases (reductions) resulting from: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | State taxes, net of federal benefit | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | Reversal of excess deferred income taxes | | | | ) | | | | ) | | | | | | | | ) | | | | ) | | | | | | | | ) | | | | ) | | | | | Federal legislative change | | | | | | | | | | | | ) | | | | | | | | | | | | ) | | | | | | | | ) | | | | ) | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | ) | | | (0.7 | ) | Write-off of regulatory assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | ) | | | | ) | | | | ) | | | | | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | Employee stock ownership plan deduction | | | | ) | | | | ) | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | | | | ) | | | | | | | | | | | | ) (1) | | | | ) (1) | | | | | % | | | | % | | | | )% | | | | % | | | | % | | | | % | | | | % | | | | % | | | | )% |
(1) | Includes (3.2)%, (4.6)% and (6.7)% relating to the absence of tax on noncontrolling interest in 2019, 2018 and 2017, respectively. |
For the Companies’ rate-regulated entities, deferred taxes will reverse at the weighted average rate used to originate the deferred tax liability, which in some cases will be 35%. The Companies have recorded an estimate of excess deferred income tax amortization in 2019,2021, and changes in estimates of amounts probable of collection from or return to customers. The reversal of these excess deferred income taxes will impact the effective tax rate, and may ultimately impact rates charged to customers. See Note 13 for current year developments. In December 2021, unrecognized tax benefits related to several state uncertain tax positions acquired in the SCANA Combination were effectively settled through negotiations with the taxing authority. Management believed it was reasonably possible these unrecognized tax benefits could decrease through settlement negotiations or payments during 2021, however no income tax benefits could be recognized unless or until the positions were effectively settled. Resolution of these uncertain tax positions decreased income tax expense by $38 million. In addition, the Companies’ effective tax rates reflect the benefit of a state legislative change enacted in April 2021 for tax years beginning January 1, 2022. Dominion Energy’s effective tax rate reflects a $21 million deferred tax benefit, inclusive of a $16 million deferred tax benefit at Virginia Power. Dominion Energy’s 2020 effective tax rate reflects an income tax benefit of $45 million associated with the remeasurement of consolidated state deferred taxes with the classification of gas transmission and storage operations as held for sale. In addition, Dominion Energy’s effective tax rate reflects an income tax expense of $55 million attributable to the noncontrolling interest primarily associated with the impairment of non-wholly-owned nonregulated solar facilities held in partnerships discussed in Note 10. In connection with the SCANA Combination, Dominion Energy committed to forgo, or limit, the recovery of certain income tax-related regulatory assets associated with the NND Project. Dominion Energy’s effective tax rate reflects deferred income tax expense of $194 million in satisfaction of this commitment. Dominion Energy’s effective tax rate also reflects the changes in consolidated state income taxes resulting from the SCANA Combination.
In 2018, the Companies applied the provisions of proposed regulations addressing the availability of federal bonus depreciation for the period beginning after September 27, 2017 through December 31, 2017. The application of these changes increased Dominion Energy’s 2017 net operating loss carryforward, the benefit of which will be recognized at the 21% rate. As a result, Dominion Energy’s effective tax rate reflects a $23 million increase to deferred income tax expense associated with the remeasurement of this deferred tax asset. The application of these proposed regulations at Dominion Energy Gas had no impact on income tax expense as the changes in, and remeasurement of, deferred tax liabilities increased regulatory liabilities by $35 million, of which $23 million is reflected 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.
In 2017, the Companies’ effective tax rates reflect the net benefit of remeasurement of deferred taxes resulting from the lower corporate income tax rate promulgated by the 2017 Tax Reform Act, and the completion of audits by state tax authorities that resulted in the recognition of previously unrecognized tax benefits. At December 31, 2016, Virginia Power’s unrecognized tax benefits included state refund claims for open tax years through 2011. Management believed settlement of the claims, including interest thereon, within the next twelve months was remote. In June 2017, Virginia Power received and accepted a cash offer to settle the refund claims. As a result of the settlement, Virginia Power decreased its unrecognized tax benefits by $8 million, and recognized a $2 million tax benefit, which impacted its effective tax rate. Also in connection with this settlement, Virginia Power realized interest income of $11 million, which is reflected in other income in the Consolidated Statements of Income.
Combined Notes to Consolidated Financial Statements, Continued
The Companies’ deferred income taxes consist of the following: | | Dominion Energy | | | Virginia Power | | At December 31, | | 2021 | | | 2020 | | | 2021 | | | 2020 | | (millions) | | | | | | | | | | | | | | | | | Deferred income taxes: | | | | | | | | | | | | | | | | | Total deferred income tax assets | | $ | 3,025 | | | $ | 3,285 | | | $ | 1,373 | | | $ | 1,204 | | Total deferred income tax liabilities | | | 9,397 | | | | 9,069 | | | | 4,286 | | | | 3,832 | | Total net deferred income tax liabilities | | $ | 6,372 | | | $ | 5,784 | | | $ | 2,913 | | | $ | 2,628 | | Total deferred income taxes: | | | | | | | | | | | | | | | | | Plant and equipment, primarily depreciation method and basis differences | | $ | 6,017 | | | $ | 5,824 | | | $ | 3,327 | | | $ | 3,227 | | Excess deferred income taxes | | | (1,107 | ) | | | (1,142 | ) | | | (629 | ) | | | (656 | ) | Unrecovered NND Project costs | | | 508 | | | | 529 | | | | 0 | | | | 0 | | DESC rate refund | | | (113 | ) | | | (140 | ) | | | 0 | | | | 0 | | Toshiba Settlement | | | (189 | ) | | | (204 | ) | | | 0 | | | | 0 | | Nuclear decommissioning | | | 1,114 | | | | 991 | | | | 324 | | | | 303 | | Deferred state income taxes | | | 857 | | | | 702 | | | | 420 | | | | 305 | | Federal benefit of deferred state income taxes | | | (179 | ) | | | (147 | ) | | | (88 | ) | | | (64 | ) | Deferred fuel, purchased energy and gas costs | | | 189 | | | | (28 | ) | | | 126 | | | | (34 | ) | Pension benefits | | | 362 | | | | 239 | | | | (119 | ) | | | (105 | ) | Other postretirement benefits | | | 73 | | | | (14 | ) | | | 93 | | | | 76 | | Loss and credit carryforwards | | | (1,571 | ) | | | (1,534 | ) | | | (537 | ) | | | (354 | ) | Valuation allowances | | | 140 | | | | 155 | | | | 6 | | | | 6 | | Partnership basis differences | | | 398 | | | | 593 | | | | 0 | | | | 0 | | Other | | | (127 | ) | | | (40 | ) | | | (10 | ) | | | (76 | ) | Total net deferred income tax liabilities | | $ | 6,372 | | | $ | 5,784 | | | $ | 2,913 | | | $ | 2,628 | | Deferred Investment Tax Credits – Regulated Operations | | | 286 | | | | 169 | | | | 270 | | | | 151 | | Total Deferred Taxes and Deferred Investment Tax Credits | | $ | 6,658 | | | $ | 5,953 | | | $ | 3,183 | | | $ | 2,779 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | At December 31, | | | | | 2018 | | | | | | 2018 | | | | | | 2018 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total deferred income tax assets | | $ | | | | $ | | | | $ | | | | | | | | | | | | $ | | | Total deferred income tax liabilities | | | | | | | | | | | | | | | | | | | | | | | | | Total net deferred income tax liabilities | | $ | | | | $ | | | | $ | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total deferred income taxes: | | | | | | | | | | | | | | | | | | | | | | | | | Plant and equipment, primarily depreciation method and basis differences | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | Excess deferred income taxes | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | Unrecovered NND Project costs | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Deferred state income taxes | | | | | | | | | | | | | | | | | | | | | | | | | Federal benefit of deferred state income taxes | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | Deferred fuel, purchased energy and gas costs | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | ) | | | | ) | | | | | | | | | Other postretirement benefits | | | | ) | | | | ) | | | | | | | | | | | | ) | | | | ) | Loss and credit carryforwards | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | Partnership basis differences | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | | | | | ) | | | | ) | | | | ) | Total net deferred income tax liabilities | | $ | | | | $ | | | | $ | | | | | | | | | | | | $ | | | Deferred Investment Tax Credits – Regulated Operations | | | | | | | | | | | | | | | | | | | | | | | | | Total Deferred Taxes and Deferred Investment Tax Credits | | $ | | | | $ | | | | $ | | | | | | | | | | | | $ | | |
The most significant impact reflected for the 2017 Tax Reform Act is the adjustment of the net accumulated deferred income tax
liability for the reduction in the corporate income tax rate to 21%. In addition to amounts recognized in deferred income tax expense, the impacts of the 2017 Tax Reform Act decreased the accumulated deferred income tax liability by $3.1 billion at Dominion Energy, $1.9 billion at Virginia Power and $0.8 billion at Dominion Energy Gas at December 31, 2017, of which $0.4 billion is reflected in noncurrent liabilities of discontinued operations on the Consolidated Balance Sheets. At Dominion Energy, the December 31, 2017 balance sheet reflected the impact of the 2017 Tax Reform Act on our regulatory liabilities which increased our regulatory liabilities by $4.2 billion, and created a corresponding deferred tax asset of $1.1 billion. At Virginia Power, our regulatory liabilities increased $2.6 billion, and created a deferred tax asset of $0.7 billion. At Dominion Energy Gas, regulatory liabilities increased $1.1 billion, of which $0.5 billion is reflected in noncurrent liabilities of discontinued operations on the Consolidated Balance Sheets and created a deferred tax asset of $0.3 billion, of which $0.1 billion is reflected in noncurrent liabilities of discontinued operations on the Consolidated Balance Sheets. These adjustments had no impact on 2017 cash flows.
At December 31, 2019,2021, Dominion Energy had the following deductible loss and credit carryforwards: | | Deductible | | | Deferred | | | Valuation | | | Expiration | | | Amount | | | Tax Asset | | | Allowance | | | Period | (millions) | | | | | | | | | | | | | | | Federal losses | | $ | 965 | | | $ | 203 | | | $ | — | | | 2037 | Federal investment credits | | — | | | | 752 | | | — | | | 2036-2041 | Federal production and other credits | | — | | | | 63 | | | — | | | 2036-2041 | State losses | | | 4,583 | | | | 243 | | | | (50 | ) | | 2022-2041 | State minimum tax credits | | — | | | | 214 | | | — | | | No expiration | State investment and other credits | | — | | | | 129 | | | | (90 | ) | | 2022-2031 | Total | | $ | 5,548 | | | $ | 1,604 | | | $ | (140 | ) | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | Federal investment credits | | | | | | | | | | | | | | | | | Federal production credits | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | State minimum tax credits | | | | | | | | | | | | | | | | | State investment and other credits | | | | | | | | | | | | ) | | | | | | | | | | | $ | | | | | | | | | | |
At December 31, 2019,2021, Virginia Power had the following deductible loss and credit carryforwards: | | Deductible | | | Deferred | | | Valuation | | | Expiration | | | Amount | | | Tax Asset | | | Allowance | | | Period | (millions) | | | | | | | | | | | | | | | Federal losses | | $ | — | | | $ | — | | | $ | — | | | | Federal investment credits | | — | | | | 467 | | | — | | | 2036-2041 | Federal production and other credits | | — | | | | 62 | | | — | | | 2036-2041 | State investment and other credits | | — | | | | 8 | | | | (6 | ) | | 2024 | Total | | $ | — | | | $ | 537 | | | $ | (6 | ) | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Federal investment credits | | | | | | | | | | | | | | | | | Federal production and other credits | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | ) | | | | |
At December 31, 2019, Dominion Energy Gas had immaterial deductible loss carryforwards and less than $1 million of credit carryforwards that expire between 2032 and 2037.
A reconciliation of changes in the Companies’ unrecognized tax benefits follows: | | Dominion Energy | | | | | Virginia Power | | | | 2021 | | | 2020 | | | 2019 | | | | | 2021 | | | 2020 | | | 2019 | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance at January 1 | | $ | 167 | | | $ | 175 | | | $ | 44 | | | | | $ | — | | | $ | — | | | $ | 2 | | Acquired unrecognized tax benefits | | | — | | | | — | | | | 129 | | | (1 | ) | | — | | | | — | | | | — | | Increases-prior period positions | | | 48 | | | | 18 | | | | — | | | | | | — | | | | — | | | | — | | Decreases-prior period positions | | | (59 | ) | | | (19 | ) | | | — | | | | | | — | | | | — | | | | — | | Increases-current period positions | | | 2 | | | | 1 | | | | 9 | | | | | | — | | | | — | | | | — | | Settlements with tax authorities | | | (26 | ) | | | — | | | | (7 | ) | | | | | — | | | | — | | | | (2 | ) | Expiration of statutes of limitations | | | (4 | ) | | | (8 | ) | | | — | | | | | | — | | | | — | | | | — | | Balance at December 31 | | $ | 128 | | | $ | 167 | | | $ | 175 | | | | | $ | - | | | $ | — | | | $ | - | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | | | | | $ | | | | | | | Acquired unrecognized tax benefits | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Increases-prior period positions | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Decreases-prior period positions | | | | | | | | | | | | ) | | | | | | | | | | | | ) | | | | | | | | | | | | | Increases-current period positions | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Settlements with tax authorities | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | | | | | | | | | | | | ) | Expiration of statutes of limitations | | | | | | | | ) | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | | | | | $ | | | | | | |
(1) | Acquired unrecognized tax benefits reflect $106 million plus increases in prior period positions of $76 million and decreases in prior period positions of $53 million that were recorded through purchase accounting. |
Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations. For Dominion Energy and its subsidiaries, these unrecognized tax benefits were $141$72 million, $37$140 million and $31$141 million at December 31, 2021, 2020 and 2019, 2018 and 2017, respectively. In discontinued operations, these unrecognized tax benefits were $33 million at December 31, 2021. For Dominion Energy, the change in these unrecognized tax benefits decreased income tax expense by $34 million and $6 million in 2021 and 2020, respectively, and increased income tax expense by $3 million in 2019. For discontinued operations, the change in these unrecognized tax benefits increased income tax expense by $3 million and $5 million in 2019 and 2018, respectively,2020 and decreased income tax expense by $9less than $1 million in 2017. 2019.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.2019. 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. 2019.Dominion Energy participates in the IRS Compliance Assurance Process which provides the opportunity to resolve complex tax matters with the IRS before filing its federal income tax returns, thus achieving certainty for such tax return filing positions agreed to by the IRS. 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 2015.2017. Although Dominion Energy has not received a final letter indicating no changes to its taxable income for tax year 2018,2020, no material adjustments are expected. The IRS examination of tax year 20192021 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 20202022 by up to $86$23 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$9 million for Dominion Energy and less than $1 million for Dominion Energy Gas. Energy. Otherwise, with regard to 20192021 and prior years, Dominion Energy, Virginia Power and Dominion Energy Gasthe Companies cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2020. 2022.For each of the major states in which Dominion Energy operates, the earliest tax year remaining open for examination is as follows: | | | | Earliest | | | | | State | | | | Year | Pennsylvania(1) | | | | 2012 | Connecticut | | | | 2018 | | (2) | | | | 2018 | Utah | | | | 2018 | | | | | | | | | | 2018 |
(1) | (1) | Considered a major state for Dominion Energy Gas’entities presented in discontinued operations. |
(2) | (2) | Considered a major state for Virginia Power’s operations.operations |
The Companies are also obligated to report adjustments resulting from IRS settlements to state tax authorities. In addition, if Dominion Energy utilizes operating losses or tax credits generated in years for which the statute of limitations has expired, such amounts are generally subject to examination. NoteNOTE 6. Fair Value Measurements FAIR VALUE MEASUREMENTSFair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. However, the use of a mid-market pricing convention (the mid-point between bid and ask prices) is permitted. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of the Companies’ own nonperformance risk on their liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). Dominion Energy applies fair value measurements to certain assets and liabilities including commodity, interest rate andand/or foreign currency exchange rate derivative instruments, and other investments including those held in nuclear decommissioning, Dominion Energy’s rabbi, and pension and other postretirement benefit plan trusts, in accordance with the requirements discussed above. Virginia Power applies fair
Combined Notes to Consolidated Financial Statements, Continued
value measurements to certain assets and liabilities including commodity, and 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. Dominion Energy Gas 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 pension and other postretirement benefit plan trusts, in accordance with the requirements described above. The Companies apply credit adjustments to their derivative fair values in accordance with the requirements described above. Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, price information is sought from external sources, including industry publications, and to a lesser extent, broker quotes. When evaluating pricing information provided by Designated Contract Market settlement pricing, other pricing services, or brokers, the Companies consider the ability to transact at the quoted price, i.e. if the quotes are based on an active market or an inactive market and to the extent which pricing models are used, if pricing is not readily available. If pricing information from external sources is not available, or if the Companies believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases the unobservable inputs are developed and substantiated using historical information, available market data, third-party data and statistical analysis. Periodically, inputs to valuation models are reviewed and revised as needed, based on historical information, updated market data, market liquidity and relationships and changes in third-party sources. For options and contracts with option-like characteristics where observable pricing information is not available from external sources, Dominion Energy and Virginia Powerthe 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. Dominion Energy and Virginia PowerThe Companies use other option models under special circumstances, including but not limited to Spread Approximation Model and a Swing Option Model. For contracts with unique characteristics, the Companies may estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. For individual contracts, the use of different valuation models or assumptions could have a significant effect on the contract’s estimated fair value.
The inputs and assumptions used in measuring fair value include the following: For commodity derivative contracts: | • | Forward commodity prices |
Transaction prices | • | Credit quality of counterparties and the Companies |
Price volatility
Price correlation
Volumes
Commodity location
Interest rates
Credit quality of counterparties and the Companies
Credit enhancements
Time value
For interest rate derivative contracts: | • | Credit quality of counterparties and the Companies |
Credit quality of counterparties and the Companies
Notional value
Credit enhancements
Time value
For foreign currency exchange rate derivative contracts: | • | Foreign currency forward exchange rates |
Foreign currency forward exchange rates | • | Credit quality of counterparties and the Companies |
Interest rates
Credit quality of counterparties and the Companies
Notional value
Credit enhancements
Time value
| • | Quoted securities prices and indices |
| • | Securities trading information including volume and restrictions |
Quoted securities prices and indices | • | Credit quality of counterparties and the Companies |
Securities trading information including volume and restrictions
Maturity
Interest rates
Credit quality
The Companies also utilize the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels: | • | Level 1—Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date. Instruments categorized in Level 1 primarily consist of financial instruments such as certain exchange-traded derivatives, and exchange-listed equities, U.S. and international equity securities, mutual funds and certain Treasury securities held in nuclear decommissioning trust funds for the Companies and benefit plan trust funds and rabbi trust funds for Dominion Energy. |
Level 1—Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date. Instruments categorized in Level 1 primarily consist of financial instruments such as certain exchange-traded derivatives, and exchange-listed equities, U.S. and international equity securities, mutual funds and certain Treasury securities held in nuclear decommissioning trust funds for Dominion Energy and Virginia Power, benefit plan trust funds for Dominion Energy and Dominion Energy Gas, and rabbi trust funds for Dominion Energy.
Level 2—Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 primarily include commodity forwards and swaps, interest rate swaps, foreign currency swaps and cash and cash equivalents, corporate debt instruments, government securities and other fixed income investments held in nuclear decommissioning trust funds for Dominion Energy and Virginia Power, benefit plan trust funds for Dominion Energy and Dominion Energy Gas and rabbi trust funds for Dominion Energy.
Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Instruments categorized in Level 3 for the Companies consist of long-dated commodity derivatives, FTRs, certain natural gas and power options and other modeled commodity derivatives.
| • | | | | | | | | | | | | | | Level 2—Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 primarily include commodity forwards and swaps, interest rate swaps, foreign currency exchange rate instruments and cash and cash equivalents, corporate debt instruments, government securities and other fixed income investments held in nuclear decommissioning trust funds for the Companies and benefit plan trust funds and rabbi trust funds for Dominion Energy. |
| • | Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Instruments categorized in Level 3 for the Companies consist of long-dated commodity derivatives, FTRs, certain natural gas options and other modeled commodity derivatives. |
The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability. Alternative investments, consisting of investments in partnerships, joint ventures and other alternative investments held in nuclear decommissioning and benefit plan trust funds, are generally valued using NAV based on the proportionate share of the fair value as determined by reference to the most recent audited fair value financial statements or fair value statements provided by the investment manager adjusted for any significant events occurring between the investment manager’s and the Companies’ measurement date. Alternative investments recorded at NAV are not classified in the fair value hierarchy. Transfers out of Level 3 represent assets and liabilities that were previously classified as Level 3 for which the inputs became observable for classification in either Level 1 or Level 2. Because the activity and liquidity of commodity markets vary substantially between regions and time periods, the availability of observable inputs for substantially the full term and value of the Companies’ over-the-counter derivative contracts is subject to change. The Companies enter into certain physical and financial forwards, futures, options and swaps, which are considered Level 3 as they have one or more inputs that are not observable and are significant to the valuation. The discounted cash flow method is used to value Level 3 physical and financial forwards and futures contracts. An option model is used to value Level 3 physical and financial options. The discounted cash flow model for forwards and futures calculates mark-to-market valuations based on forward market prices, original transaction prices, volumes, risk-free rate of return, and credit spreads. The option model calculates mark-to-market valuations using variations of the Black-Scholes option model. The inputs into the models are the forward market prices, implied price volatilities, risk-free rate of return, the option expiration dates, the option strike prices, the original sales prices and volumes. For Level 3 fair value measurements, certain forward market prices and implied price volatilities are considered unobservable. The following table presents Dominion Energy’s quantitative information about Level 3 fair value measurements at December 31, 2019.2021. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Physical and financial forwards: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Market price (per Dth) (3) | | | | | | | | | | | | | | | | | | | | | Market price (per MWh) (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Physical and financial forwards: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Market price (per Dth) (3) | | | | | | | | | ) | | | | | | | | | | | | Market price (per MWh) (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Market price (per Dth) (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 37 | % | | | | | | | | | | | | | | | | | | | | | |
| | Fair Value (millions) | | | Valuation Techniques | | Unobservable Input | | | Range | | Weighted Average(1) | | Assets | | | | | | | | | | | | | | | | Physical and financial forwards: | | | | | | | | | | | | | | | | Natural gas(2) | | $ | 54 | | | Discounted cash flow | | Market price (per Dth) | (3) | | (2)-8 | | | (1 | ) | FTRs | | | 51 | | | Discounted cash flow | | Market price (per MWh) | (3) | | (2)-11 | | | 2 | | Electricity | | | 120 | | | Discounted cash flow | | Market price (per MWh) | (3) | | 28-72 | | | 43 | | Physical options: | | | | | | | | | | | | | | | | Natural gas | | | 5 | | | Option model | | Market price (per Dth) | (3) | | 3-9 | | | 6 | | | | | | | | | | Price volatility | (4) | | 19% - 27% | | | 24 | % | Total assets | | $ | 230 | | | | | | | | | | | | | Liabilities | | | | | | | | | | | | | | | | Physical and financial forwards: | | | | | | | | | | | | | | | | Natural gas(2) | | $ | 3 | | | Discounted cash flow | | Market price (per Dth) | (3) | | (2)-4 | | | (1 | ) | FTRs | | | 5 | | | Discounted cash flow | | Market price (per MWh) | (3) | | (3)-7 | | | 1 | | Total liabilities | | $ | 8 | | | | | | | | | | | | |
(1) | Averages weighted by volume. |
(3) | Represents market prices beyond defined terms for Levels 1 and 2. |
(4) | Represents volatilities unrepresented in published markets. |
Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows: | | | | | | | | | | | | | Significant Unobservable
| | | | | | | | Impact on Fair
| | | | Buy | | | | | | | | | | | | | Sell | | | | | | | | | | | | | Buy | | | | | | | | | | | | | Sell | | | | | | | | | | |
Nonrecurring Fair Value Measurements See Note 3 for information on the nonrecurring fair value measurement associated with the acquisition of Birdseye. See Note 9 for information regarding an impairment charge recognized associated with Dominion Energy’s equity method investment in Fowler Ridge. Also, see Note 9 for information regardingnonrecurring fair value measurements associated with Dominion Energy’s sale of itsretained noncontrolling interest in Blue RacerCove Point, charges related to Fowler Ridge and acquisition of itsDominion Energy’s retained noncontrolling interest in Wrangler.
Combined Notesbusinesses and assets contributed to Consolidated Financial Statements, Continued
Atlantic Coast Pipeline Guarantee Agreement
In October 2017, Dominion Energy entered into a guarantee agreement in connection with Atlantic Coast Pipeline’s obligation under a $3.4 billion revolving credit facility.Wrangler. See Note 2310 for more information about the guarantee agreementregarding an impairment charge recorded associated with Atlantic Coast Pipeline’s revolving credit facility.non-wholly-owned nonregulated solar facilities in partnerships.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 the fourth quarter of 2018, subsequent to the announcement of the sale of Dominion Energy’s interest in Blue Racer, Dominion Energy Gas conducted a review of strategic alternatives of its remaining gathering and processing assets at DGP. Based on an evaluation of DGP’s long-lived assets for recoverability under a probability weighted approach, Dominion Energy Gas determined the assets were impaired. As a result of this evaluation, Dominion Energy Gas recorded a charge of $219$20 million ($ 16515 million after-tax) in discontinued operationsimpairment of assets and other charges in its Consolidated Statements of Income (reflected in the Corporate and Other segment) to write down DGP’s property, plantoff substantially all of the long-lived assets of its nonregulated retail software development operations to their estimated fair value, using a market approach, of less than $1 million. The valuation is considered a Level 2 fair value measurement given that it is based on bids received. In 2021, Dominion Energy recorded a charge of $16 million ($12 million after-tax) in impairment of assets and 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 Consolidated Statements of Income
(reflected inthe
Corporate 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. The corporate office building is reflected in the Corporate and Other segment and presented as held for sale in Dominion Energy’s Consolidated Balance Sheets at December 31, 2021.
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’Energy’s pension and other postretirement benefit plans are presented in Note 22. The following table presents Dominion Energy’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions: | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | (millions) | | | | | | | | | | | | | | | | | December 31, 2021 | | | | | | | | | | | | | | | | | Assets | | | | | | | | | | | | | | | | | Derivatives: | | | | | | | | | | | | | | | | | Commodity | | $ | — | | | $ | 52 | | | $ | 230 | | | $ | 282 | | Interest rate | | | — | | | | 323 | | | | — | | | | 323 | | Foreign currency exchange rate | | | — | | | | 8 | | | | — | | | | 8 | | Investments(1): | | | | | | | | | | | | | | | | | Equity securities: | | | | | | | | | | | | | | | | | U.S. | | | 5,241 | | | | — | | | | — | | | | 5,241 | | Fixed income: | | | | | | | | | | | | | | | | | Corporate debt instruments | | | — | | | | 881 | | | | — | | | | 881 | | Government securities | | | 199 | | | | 1,256 | | | | — | | | | 1,455 | | Cash equivalents and other | | | (29 | ) | | | — | | | | — | | | | (29 | ) | Total assets | | $ | 5,411 | | | $ | 2,520 | | | $ | 230 | | | $ | 8,161 | | Liabilities | | | | | | | | | | | | | | | | | Derivatives: | | | | | | | | | | | | | | | | | Commodity | | $ | — | | | $ | 461 | | | $ | 8 | | | $ | 469 | | Interest rate | | | — | | | | 399 | | | | — | | | | 399 | | Total liabilities | | $ | — | | | $ | 860 | | | $ | 8 | | | $ | 868 | | December 31, 2020 | | | | | | | | | | | | | | | | | Assets | | | | | | | | | | | | | | | | | Derivatives: | | | | | | | | | | | | | | | | | Commodity | | $ | — | | | $ | 57 | | | $ | 110 | | | $ | 167 | | Interest rate | | | — | | | | 230 | | | | — | | | | 230 | | Investments(1): | | | | | | | | | | | | | | | | | Equity securities: | | | | | | | | | | | | | | | | | U.S. | | | 4,648 | | | | — | | | | — | | | | 4,648 | | Fixed income: | | | | | | | | | | | | | | | | | Corporate debt instruments | | | — | | | | 629 | | | | — | | | | 629 | | Government securities | | | 508 | | | | 730 | | | | — | | | | 1,238 | | Cash equivalents and other | | | 32 | | | | 15 | | | | — | | | | 47 | | Total assets | | $ | 5,188 | | | $ | 1,661 | | | $ | 110 | | | $ | 6,959 | | Liabilities | | | | | | | | | | | | | | | | | Derivatives: | | | | | | | | | | | | | | | | | Commodity | | $ | — | | | $ | 48 | | | $ | 7 | | | $ | 55 | | Interest rate | | | — | | | | 431 | | | | — | | | | 431 | | Total liabilities | | $ | — | | | $ | 479 | | | $ | 7 | | | $ | 486 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Corporate debt instruments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash equivalents and other | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Corporate debt instruments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash equivalents and other | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | | | | | $ | | |
(1) | Includes investments held in the nuclear decommissioning trusts and rabbi trusts. Excludes $274$366 million and $220$340 million of assets at December 31, 20192021 and 2018,2020, respectively, measured at fair value using NAV (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy. |
The following table presents the net change in Dominion Energy’s assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category: | | 2021 | | | 2020 | | | 2019 | | (millions) | | | | | | | | | | | | | Balance at January 1, | | $ | 103 | | | $ | (37 | ) | | $ | 64 | | Total realized and unrealized gains (losses): | | | | | | | | | | | | | Included in earnings: | | | | | | | | | | | | | Operating Revenue | | | (9 | ) | | | 0 | | | | (1 | ) | Electric fuel and other energy-related purchases | | | 10 | | | | (33 | ) | | | (22 | ) | Purchased gas | | | 0 | | | | 0 | | | | 2 | | Discontinued operations | | | 0 | | | | 1 | | | | 0 | | Included in regulatory assets/liabilities | | | 119 | | | | 140 | | | | (90 | ) | Settlements | | | (10 | ) | | | 33 | | | | 17 | | Purchases | | | 0 | | | | 0 | | | | (10 | ) | Sales | | | 0 | | | | (1 | ) | | | 6 | | Transfers out of Level 3 | | | 9 | | | | 0 | | | | (3 | ) | Balance at December 31, | | $ | 222 | | | $ | 103 | | | $ | (37 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | Total realized and unrealized gains (losses): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | | Electric fuel and other energy-related purchases | | | | ) | | | | ) | | | | ) | | | | | | | | | | | | | | Included in other comprehensive income (loss) | | | | | | | | | | | | ) | Included in regulatory assets/liabilities | | | | ) | | | | ) | | | | | | | | | | | | | ) | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | $ | | ) | | $ | | | | $ | | | 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: | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | |
Combined NotesThere were 0 unrealized gains and losses included in earnings in the Level 3 fair value category relating to Consolidated Financial Statements, Continued assets/liabilities still held at the reporting date for the years ended December 31, 2021, 2020 and 2019.Virginia Power The following table presents Virginia Power’s quantitative information about Level 3 fair value measurements at December 31, 2019.2021. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility. | | Fair Value (millions) | | | Valuation Techniques | | Unobservable Input | | | Range | | Weighted Average(1) | | Assets | | | | | | | | | | | | | | | | Physical and financial forwards: | | | | | | | | | | | | | | | | Natural gas(2) | | $ | 54 | | | Discounted cash flow | | Market price (per Dth) | (3) | | (2)-6 | | | (1 | ) | FTRs | | | 51 | | | Discounted cash flow | | Market price (per MWh) | (3) | | (2)-11 | | | 2 | | Physical options: | | | | | | | | | | | | | | | | Natural gas | | | 5 | | | Option model | | Market price (per Dth) | (3) | | 3-9 | | | 6 | | | | | | | | | | Price volatility | (4) | | 19% - 27% | | | 24 | % | Total assets | | $ | 110 | | | | | | | | | | | | | Liabilities | | | | | | | | | | | | | | | | Physical and financial forwards: | | | | | | | | | | | | | | | | Natural gas(2) | | $ | 3 | | | Discounted cash flow | | Market price (per Dth) | (3) | | (2)-4 | | | (1 | ) | FTRs | | | 5 | | | Discounted cash flow | | Market price (per MWh) | (3) | | (3)-7 | | | 1 | | Total liabilities | | $ | 8 | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Physical and financial forwards: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Market price (per Dth) (3) | | | | | | | | | | | | | | | | | | | | | Market price (per MWh) (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Physical and financial forwards: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Market price (per Dth) (3) | | | | | | | | | ) | | | | | | | | | | | | Market price (per MWh) (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Market price (per Dth) (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 37 | % | | | | | | | | | | | | | | | | | | | | | |
(1) | Averages weighted by volume. |
(3) | Represents market prices beyond defined terms for Levels 1 and 2. |
(4) | Represents volatilities unrepresented in published markets. |
Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows: | | | | | | | | | | | | | Significant Unobservable
| | | | | | | | Impact on Fair
| | | | Buy | | | | | | | | | | | | | Sell | | | | | | �� | | | | | | | Buy | | | | | | | | | | | | | Sell | | | | | | | | | | |
The following table presents Virginia Power’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions: | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | (millions) | | | | | | | | | | | | | | | | | December 31, 2021 | | | | | | | | | | | | | | | | | Assets | | | | | | | | | | | | | | | | | Derivatives: | | | | | | | | | | | | | | | | | Commodity | | $ | — | | | $ | 36 | | | $ | 110 | | | $ | 146 | | Interest rate | | | — | | | | 146 | | | | — | | | | 146 | | Foreign currency exchange rate | | | — | | | | 8 | | | | — | | | | 8 | | Investments(1): | | | | | | | | | | | | | | | | | Equity securities: | | | | | | | | | | | | | | | | | U.S. | | | 2,420 | | | | — | | | | — | | | | 2,420 | | Fixed income: | | | | | | | | | | | | | | | | | Corporate debt instruments | | | — | | | | 531 | | | | — | | | | 531 | | Government securities | | | 93 | | | | 506 | | | | — | | | | 599 | | Cash equivalents and other | | | (3 | ) | | | — | | | | — | | | | (3 | ) | Total assets | | $ | 2,510 | | | $ | 1,227 | | | $ | 110 | | | $ | 3,847 | | Liabilities | | | | | | | | | | | | | | | | | Derivatives: | | | | | | | | | | | | | | | | | Commodity | | $ | — | | | $ | 125 | | | $ | 8 | | | $ | 133 | | Interest rate | | | — | | | | 337 | | | | — | | | | 337 | | Total liabilities | | $ | — | | | $ | 462 | | | $ | 8 | | | $ | 470 | | December 31, 2020 | | | | | | | | | | | | | | | | | Assets | | | | | | | | | | | | | | | | | Derivatives: | | | | | | | | | | | | | | | | | Commodity | | $ | — | | | $ | 5 | | | $ | 110 | | | $ | 115 | | Interest rate | | | — | | | | 66 | | | | — | | | | 66 | | Investments(1): | | | | | | | | | | | | | | | | | Equity securities: | | | | | | | | | | | | | | | | | U.S. | | | 2,171 | | | | — | | | | — | | | | 2,171 | | Fixed income: | | | | | | | | | | | | | | | | | Corporate debt instruments | | | — | | | | 348 | | | | — | | | | 348 | | Government securities | | | 201 | | | | 309 | | | | — | | | | 510 | | Cash equivalents and other | | | 13 | | | | — | | | | — | | | | 13 | | Total assets | | $ | 2,385 | | | $ | 728 | | | $ | 110 | | | $ | 3,223 | | Liabilities | | | | | | | | | | | | | | | | | Derivatives: | | | | | | | | | | | | | | | | | Commodity | | $ | — | | | $ | 22 | | | $ | 7 | | | $ | 29 | | Interest rate | | | — | | | | 376 | | | | — | | | | 376 | | Total liabilities | | $ | — | | | $ | 398 | | | $ | 7 | | | $ | 405 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Corporate debt instruments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash equivalents and other | | | — | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Corporate debt instruments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | $ | | |
(1) | Includes investments held in the nuclear decommissioning trusts. Excludes $159$185 million and $160$167 million of assets at December 31, 20192021 and 2018,2020, respectively, measured at fair value using NAV (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy. |
The following table presents the net change in Virginia Power’s assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category: | | 2021 | | | 2020 | | | 2019 | | (millions) | | | | | | | | | | | | | Balance at January 1, | | $ | 103 | | | $ | (37 | ) | | $ | 60 | | Total realized and unrealized gains (losses): | | | | | | | | | | | | | Included in earnings: | | | | | | | | | | | | | Electric fuel and other energy-related purchases | | | 4 | | | | (33 | ) | | | (22 | ) | Included in regulatory assets/liabilities | | | (1 | ) | | | 140 | | | | (88 | ) | Settlements | | | (4 | ) | | | 33 | | | | 13 | | Balance at December 31, | | $ | 102 | | | $ | 103 | | | $ | (37 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | Total realized and unrealized gains (losses): | | | | | | | | | | | | | | | | | | | | | | | | | | Electric fuel and other energy-related purchases | | | | ) | | | | ) | | | | ) | Included in regulatory assets/liabilities | | | | ) | | | | ) | | | | | | | | | | | | | ) | | | | | | | $ | | ) | | $ | | | | $ | | |
There were no0 unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended December 31, 2019, 20182021, 2020 and 2017. The following table presents Dominion Energy Gas’ assets and liabilities for derivatives that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:
The following table presents the net change in Dominion Energy Gas’ derivative assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category. There were no changes in assets and liabilities measure at fair value on a recurring basis and included in the Level 3 fair value category during the year ended December 31, 2019.
| | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | Total realized and unrealized gains (losses): | | | | | | | | | Included in other comprehensive income (loss) | | | | | | | | ) | | | | | | | | | | | | | | | | | | ) |
Combined Notes to Consolidated Financial Statements, Continued
There were no gains and losses included in earnings in the Level 3 fair value category for the years ended December 31, 2019, 2018 and 2017. There were no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended December 31, 2019, 2018 and 2017.
Fair Value of Financial Instruments Substantially all of the Companies’ financial instruments are recorded at fair value, with the exception of the instruments described below, which are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. The carrying amount of cash, restricted cash and equivalents, customer and other receivables, affiliated receivables, short-term debt, affiliated current borrowings, payables to affiliates and accounts payable are representative of fair value because of the short-term nature of these instruments. For the Companies’ financial instruments that are not recorded at fair value, the carrying amounts and estimated fair values are as follows: December 31, | | 2021 | | | 2020 | | | | Carrying Amount | | | Estimated Fair Value(1) | | | Carrying Amount | | | Estimated Fair Value(1) | | (millions) | | | | | | | | | | | | | | | | | Dominion Energy | | | | | | | | | | | | | | | | | Long-term debt(2)(3) | | $ | 35,996 | | | $ | 40,947 | | | $ | 31,996 | | | $ | 38,773 | | Supplemental 364-Day credit facility borrowings | | | — | | | | — | | | | 225 | | | | 225 | | Junior subordinated notes(4) | | | 1,386 | | | | 1,470 | | | | 3,411 | | | | 3,633 | | Virginia Power | | | | | | | | | | | | | | | | | Long-term debt(4) | | $ | 13,753 | | | $ | 16,021 | | | $ | 13,207 | | | $ | 16,455 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | $ | | | | | | | Credit facility borrowings | | | | | | | | | | | | | | | | | Junior subordinated notes (3) | | | | | | | | | | | | | | | | | Remarketable subordinated notes (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | $ | | | | | | | Credit facility borrowings | | | | | | | | | | | | | | | | |
(1) | Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issuances with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value. |
(2) | Carrying amount includes current portions included in securities due within one year and amounts which represent the unamortized debt issuance costs and discount or premium, and foreign currency remeasurement adjustments.premium. At December 31, 20192021 and 2018,December 31, 2020, the carrying amount includes the valuation of certain fair value hedges associated with Dominion Energy’s fixed rate debt of $4$2 million and $(20)$3 million, respectively. |
(3) | Includes amounts classified as held for sale at December 31, 2020, see Note 3. |
(4) | Carrying amount includes current portions included in securities due within one year and amounts which represent the unamortized debt issuance costs, discount or premium. |
(4) | Carrying amount includes current portions included in securities due within one year and amounts which represent the unamortized debt issuance costs, discount or premium, and foreign currency remeasurement adjustments. |
NoteNOTE 7. Derivatives And Hedge Accounting Activities DERIVATIVES AND HEDGE ACCOUNTING ACTIVITIESSee Note 2 for the Companies’ accounting policies, objectives, and strategies for using derivative instruments. See Note 6 for further information about fair value measurements and associated valuation methods for derivatives. Derivative assets and liabilities are presented gross on the Companies’ Consolidated Balance Sheets. Dominion Energy’sEnergy and Virginia Power’s derivative contracts include both over-the-counter transactions and those that are executed on an exchange or other trading platform (exchange contracts) and centrally cleared. Virginia Power and Dominion Energy Gas’ derivative contracts includeover-the-counter
transactions.Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Exchange contracts utilize a financial intermediary, exchange or clearinghouse to enter, execute or clear the transactions. Certain over-the-counter and exchange contracts contain contractual rights of setoff through master netting arrangements, derivative clearing agreements and contract default provisions. In addition, the contracts are subject to conditional rights of setoff through counterparty nonperformance, insolvency or other conditions. In general, most over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral for over-the-counter and exchange contracts include cash, letters of credit, and in some cases, other forms of security, none of which are subject to restrictions. Cash collateral is used in the table below to offset derivative assets and liabilities. In February 2022, Dominion Energy entered into contracts representing offsetting positions to certain existing exchange contracts with collateral requirements as
well as new over-the-counter transactions that are not subject to collateral requirements. These contracts resulted in positions which limit the risk of increased cash collateral requirements. Certain accounts receivable and accounts payable recognized on the Companies’ Consolidated Balance Sheets, 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 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’s derivative asset and liability balances by type of financial instrument, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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) | | | | | | | | | | | | Gross Assets Presented in the Consolidated Balance Sheet (1) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Foreign currency contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total derivatives, subject to a master netting or similar arrangement | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2021 | | | December 31, 2020 | | | | Gross Amounts Not Offset in the Consolidated Balance Sheet | | | Gross Amounts Not Offset in the Consolidated Balance Sheet | | | | Gross Assets Presented in the Consolidated Balance Sheet(1) | | | Financial Instruments | | | Cash Collateral Received | | | Net Amounts | | | Gross Assets Presented in the Consolidated Balance Sheet(1) | | | Financial Instruments | | | Cash Collateral Received | | | Net Amounts | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Commodity contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | $ | 153 | | | $ | 13 | | | $ | — | | | $ | 140 | | | $ | 117 | | | $ | 9 | | | $ | — | | | $ | 108 | | Exchange | | | 9 | | | | 7 | | | | — | | | | 2 | | | | 49 | | | | 24 | | | | — | | | | 25 | | Interest rate contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | | 323 | | | | 49 | | | | — | | | | 274 | | | | 230 | | | | 13 | | | | — | | | | 217 | | Foreign currency exchange rate contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | | 8 | | | | — | | | | — | | | | 8 | | | | — | | | | — | | | | — | | | | — | | Total derivatives, subject to a master netting or similar arrangement | | $ | 493 | | | $ | 69 | | | $ | — | | | $ | 424 | | | $ | 396 | | | $ | 46 | | | $ | — | | | $ | 350 | |
(1) | Excludes $2$120 million and $7$1 million of derivative assets at December 31, 20192021 and 2018,2020, respectively, which are not subject to master netting or similar arrangements. |
| | December 31, 2021 | | | December 31, 2020 | | | | Gross Amounts Not Offset in the Consolidated Balance Sheet | | | Gross Amounts Not Offset in the Consolidated Balance Sheet | | | | Gross Liabilities Presented in the Consolidated Balance Sheet | | | Financial Instruments | | | Cash Collateral Paid | | | Net Amounts | | | Gross Liabilities Presented in the Consolidated Balance Sheet(1) | | | Financial Instruments | | | Cash Collateral Paid | | | Net Amounts | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Commodity contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | $ | 95 | | | $ | 13 | | | $ | 54 | | | $ | 28 | | | $ | 30 | | | $ | 9 | | | $ | — | | | $ | 21 | | Exchange | | | 374 | | | | 7 | | | | 367 | | | | — | | | | 24 | | | | 24 | | | | — | | | | — | | Interest rate contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | | 399 | | | | 49 | | | | 11 | | | | 339 | | | | 431 | | | | 13 | | | | 17 | | | | 401 | | Total derivatives, subject to a master netting or similar arrangement | | $ | 868 | | | $ | 69 | | | $ | 432 | | | $ | 367 | | | $ | 485 | | | $ | 46 | | | $ | 17 | | | $ | 422 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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) | | | | | | | | | | | | Gross Liabilities Presented in the Consolidated Balance Sheet (1) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Foreign currency contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total derivatives, subject to a master netting or similar arrangement | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(1) | Excludes $5 million and $1 million of derivative liabilities at December 31, 2019 and 2018, respectively,2020 which are not subject to master netting or similar arrangements. |
Combined Notes to Consolidated Financial Statements, Continued
The following table presents the volume of Dominion Energy’s derivative activity as of December 31, 2019.2021. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions. | | Current | | | Noncurrent | | Natural Gas (bcf): | | | | | | | | | Fixed price(1) | | | 34 | | | | 5 | | Basis | | | 156 | | | | 446 | | Electricity (MWh in millions): | | | | | | | | | Fixed price | | | 15 | | | | 31 | | FTRs | | | 44 | | | | — | | Interest rate(2) (in millions) | | $ | 1,537 | | | $ | 9,859 | | Foreign currency exchange rate(2) (in millions) | | 501 kr. | | | 4,581 kr. | |
(1) Includes options. (3) | Maturity is determined based on final settlement period. |
The following table presents selected information related to gains (losses)losses on cash flow hedges included in AOCI in Dominion Energy’s Consolidated Balance SheetSheets at December 31, 2019:2021: | | AOCI After-Tax | | | Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax | | | Maximum Term | (millions) | | | | | | | | | | | Interest rate | | $ | (358 | ) | | $ | (40 | ) | | 396 months | Total | | $ | (358 | ) | | $ | (40 | ) | | |
| | | | | | | | | | | | | | | | | | Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | ) | | $ | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | | | | | | | | | | ) | | | | | | | $ | | ) | | $ | | ) | | | | |
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.
For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative instrument as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings and presented in the same line item. There were 0 derivative instruments designated as fair value hedges during the twelve months ended December 31, 2021 and 2020. Gains and losses on derivatives inderivative fair value hedge relationships were immaterial for the yearsyear ended December 31, 2019, 2018 and 2017. 2019.The following table presents the amounts recorded on the balance sheetConsolidated Balance Sheets related to cumulative basis adjustments for fair value hedges:hedges all of which related to discontinued hedging relationships at both December 31, 2021 and 2020, respectively: | | Carrying Amount of the Hedged Asset (Liability) | | | Cumulative Amount of Fair Value Hedging Adjustments Included in the Carrying Amount of the Hedged Assets (Liabilities) | | | | December 31, 2021 | | | December 31, 2020 | | | December 31, 2021 | | | December 31, 2020 | | (millions) | | | | | | | | | | | | | | | | | Long-term debt | | $ | (352 | ) | | $ | (1,153 | ) | | $ | (2 | ) | | $ | (3 | ) |
| | | | | | | | | | | | | | | | | | | Carrying Amount of the Hedged Asset | | | Cumulative Amount of Fair Value Included in the Carrying Amount of the Hedged Assets (Liabilities) (2) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | ) | | $ | | ) | | $ | | ) | | | | |
(1) | Includes $(397) million and $(892) million related to discontinued hedging relationships at December 31, 2019 and December 31, 2018, respectively. |
(2) | Includes $3 million and $8 million of hedging adjustments on discontinued hedging relationships at December 31, 2019 and December 31, 2018, respectively. |
Fair Value and Gains and Losses on Derivative Instruments The following tables present the fair values of Dominion Energy’s derivatives and where they are presented in its Consolidated Balance Sheets: | | | | | | | | | | | | | | | Fair Value –
Derivatives
under
Hedge
Accounting | | | Fair Value –
Derivatives
not under
Hedge
Accounting | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | Total current derivative assets (1) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total noncurrent derivative assets (2) | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total current derivative liabilities (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total noncurrent derivative liabilities (4) | | | | | | | | | | | | | Total derivative liabilities | | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | Total current derivative assets (1) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total noncurrent derivative assets (2) | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total current derivative liabilities (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total noncurrent derivative liabilities (4) | | | | | | | | | | | | | Total derivative liabilities | | | | | | | | | | $ | | |
| | Fair Value – Derivatives under Hedge Accounting | | | Fair Value – Derivatives not under Hedge Accounting | | | Total Fair Value | | (millions) | | | | | | | | | | | | | At December 31, 2021 | | | | | | | | | | | | | ASSETS | | | | | | | | | | | | | Current Assets | | | | | | | | | | | | | Commodity | | $ | — | | | $ | 103 | | | $ | 103 | | Interest rate | | | 1 | | | | 17 | | | | 18 | | Foreign currency exchange rate | | | — | | | | 1 | | | | 1 | | Total current derivative assets(1) | | | 1 | | | | 121 | | | | 122 | | Noncurrent Assets | | | | | | | | | | | | | Commodity | | | — | | | | 179 | | | | 179 | | Interest rate | | | 145 | | | | 160 | | | | 305 | | Foreign currency exchange rate | | | — | | | | 7 | | | | 7 | | Total noncurrent derivative assets(2) | | | 145 | | | | 346 | | | | 491 | | Total derivative assets | | $ | 146 | | | $ | 467 | | | $ | 613 | | LIABILITIES | | | | | | | | | | | | | Current Liabilities | | | | | | | | | | | | | Commodity | | $ | — | | | $ | 304 | | | $ | 304 | | Interest rate | | | 42 | | | | 13 | | | | 55 | | Total current derivative liabilities(3) | | | 42 | | | | 317 | | | | 359 | | Noncurrent Liabilities | | | | | | | | | | | | | Commodity | | | — | | | | 165 | | | | 165 | | Interest rate | | | 295 | | | | 49 | | | | 344 | | Total noncurrent derivative liabilities(4) | | | 295 | | | | 214 | | | | 509 | | Total derivative liabilities | | $ | 337 | | | $ | 531 | | | $ | 868 | | At December 31, 2020 | | | | | | | | | | | | | ASSETS | | | | | | | | | | | | | Current Assets | | | | | | | | | | | | | Commodity | | $ | — | | | $ | 58 | | | $ | 58 | | Interest rate | | | — | | | | 9 | | | | 9 | | Total current derivative assets(1) | | | — | | | | 67 | | | | 67 | | Noncurrent Assets | | | | | | | | | | | | | Commodity | | | — | | | | 109 | | | | 109 | | Interest rate | | | 66 | | | | 155 | | | | 221 | | Total noncurrent derivative assets(2) | | | 66 | | | | 264 | | | | 330 | | Total derivative assets | | $ | 66 | | | $ | 331 | | | $ | 397 | | LIABILITIES | | | | | | | | | | | | | Current Liabilities | | | | | | | | | | | | | Commodity | | $ | — | | | $ | 42 | | | $ | 42 | | Interest rate | | | 363 | | | | 10 | | | | 373 | | Total current derivative liabilities(3) | | | 363 | | | | 52 | | | | 415 | | Noncurrent Liabilities | | | | | | | | | | | | | Commodity | | | — | | | | 13 | | | | 13 | | Interest rate | | | 19 | | | | 39 | | | | 58 | | Total noncurrent derivative liabilities(4) | | | 19 | | | | 52 | | | | 71 | | Total derivative liabilities | | $ | 382 | | | $ | 104 | | | $ | 486 | |
Combined Notes to Consolidated Financial Statements, Continued
(1) | CurrentAt December 31, 2021, all current derivative assets are presented in other current assets in Dominion Energy’s Consolidated Balance Sheets. At December 31, 2020, $63 million is included in other current assets and the remainder is recorded in current assets held for sale. |
(2) | NoncurrentAt December 31, 2021, all noncurrent derivative assets are presented in other deferred charges and other assets in Dominion Energy’s Consolidated Balance Sheets. At December 31, 2020, $330 million is included in other deferred charges and other assets and the remainder is recorded in noncurrent assets held for sale. |
(3) | CurrentAt December 31, 2021, all current derivative liabilities are presented in other current liabilities in Dominion Energy’s Consolidated Balance Sheets. At December 31, 2020, $412 million is included in other current liabilities and the remainder is recorded in current liabilities held for sale. |
(4) | NoncurrentAt December 31, 2021, all noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion Energy’s Consolidated Balance Sheets. At December 31, 2020, $71 million is included in other deferred credits and other liabilities and the remainder is recorded in noncurrent liabilities held for sale. |
The following tables present the gains and losses on Dominion Energy’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income: | | | | | | | | | | | | | Derivatives in cash flow hedging relationships | | Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion) (1) | | | Gain (Loss)
Reclassified
From AOCI
to Income | | | Increase (Decrease) in Derivatives Subject to Regulatory Treatment (2) | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2019 | | | | | | | | | | | | | Derivative type and location of gains (losses): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | | | | | ) | | | | ) | | | | | | | | | ) | | | | | | | | ) | Year Ended December 31, 2018 | | | | | | | | | | | | | Derivative type and location of gains (losses): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | Electric fuel and other energy-related purchases | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | (18 | ) | | | (48 | ) | | | | | | | | (6 | ) | | | (13 | ) | | | | | | | | | | | | | ) | | | | | Year Ended December 31, 2017 | | | | | | | | | | | | | Derivative type and location of gains (losses): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (2 | ) | | | | | | | | | | | | | | | | | | | | | (8 | ) | | | (52 | ) | | | (58 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | ) |
Derivatives in cash flow hedging relationships | | Amount of Gain (Loss) Recognized in AOCI on Derivatives(1) | | | Amount of Gain (Loss) Reclassified From AOCI to Income | | | Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2) | | (millions) | | | | | | | | | | | | | Year Ended December 31, 2021 | | | | | | | | | | | | | Derivative type and location of gains (losses): | | | | | | | | | | | | | Commodity(3): | | | | | | $ | (1 | ) | | | | | Interest rate(4) | | $ | 21 | | | | (60 | ) | | $ | 135 | | Total | | $ | 21 | | | $ | (61 | ) | | $ | 135 | | Year Ended December 31, 2020 | | | | | | | | | | | | | Derivative type and location of gains (losses): | | | | | | | | | | | | | Commodity: | | | | | | | | | | | | | Operating revenue | | | | | | $ | 25 | | | | | | Purchased gas | | | | | | | (4 | ) | | | | | Discontinued operations | | | | | | | 2 | | | | | | Total commodity | | $ | — | | | $ | 23 | | | $ | — | | Interest rate: | | | | | | | | | | | | | Interest and related charges | | | | | | $ | (83 | ) | | | | | Discontinued operations | | | | | | | (236 | ) | | | | | Total interest rate | | $ | (309 | ) | | $ | (319 | ) | | $ | (332 | ) | Foreign currency exchange rate(5) | | | (11 | ) | | | (6 | ) | | | — | | Total | | $ | (320 | ) | | $ | (302 | ) | | $ | (332 | ) | Year Ended December 31, 2019 | | | | | | | | | | | | | Derivative type and location of gains (losses): | | | | | | | | | | | | | Commodity: | | | | | | | | | | | | | Operating revenue | | | | | | $ | 142 | | | | | | Purchased gas | | | | | | | (3 | ) | | | | | Discontinued operations | | | | | | | 4 | | | | | | Total commodity | | $ | 125 | | | $ | 143 | | | $ | — | | Interest rate: | | | | | | | | | | | | | Interest and related charges | | | | | | $ | (49 | ) | | | | | Discontinued operations | | | | | | | (5 | ) | | | | | Total interest rate | | $ | (252 | ) | | $ | (54 | ) | | $ | (255 | ) | Foreign currency exchange rate(5) | | | (18 | ) | | | (6 | ) | | | — | | Total | | $ | (145 | ) | | $ | 83 | | | $ | (255 | ) |
(1) | Amounts deferred into AOCI have no associated effect in Dominion Energy’s Consolidated Statements of Income. |
(2) | Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion Energy’s Consolidated Statements of Income. |
(3) | Amounts recorded in Dominion Energy’s Consolidated Statements of Income are classified in purchased gas. |
(4) | Amounts recorded in Dominion Energy’s Consolidated Statements of Income are classified in interest and related charges. |
(4)(5) | Amounts recorded in Dominion Energy’s Consolidated Statements of Income are classified in other income.discontinued operations. |
Derivatives not designated as hedging instruments | | Amount of Gain (Loss) Recognized in Income on Derivatives(1) | | Year Ended December 31, | | 2021 | | | 2020 | | | 2019 | | (millions) | | | | | | | | | | | | | Derivative type and location of gains (losses): | | | | | | | | | | | | | Commodity: | | | | | | | | | | | | | Operating revenue | | $ | (487 | ) | | $ | 73 | | | $ | 41 | | Purchased gas | | | (1 | ) | | | (20 | ) | | | (22 | ) | Electric fuel and other energy-related purchases | | | 16 | | | | (104 | ) | | | (46 | ) | Discontinued operations | | | — | | | | (11 | ) | | | (2 | ) | Interest rate: | | | | | | | | | | | | | Interest and related charges | | | 97 | | | | 87 | | | | 3 | | Discontinued operations | | | — | | | | 5 | | | | — | | Foreign currency exchange rate: | | | | | | | | | | | | | Discontinued operations | | | — | | | | 12 | | | | — | | Total | | $ | (375 | ) | | $ | 42 | | | $ | (26 | ) |
| | | | | | | | | | | | | Derivatives not designated as hedging instruments | | Amount of Gain (Loss) Recognized in Income on Derivatives (1) | | | | | | | | | | | | | | | | | | | | | | Derivative type and location of gains (losses): | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | ) | | $ | | | | | | | ) | | | | | | | | ) | Electric fuel and other energy-related purchases | | | | ) | | | | ) | | | | ) | Other operations & maintenance | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | $ | | ) | | $ | | ) | | $ | | ) |
(1) | Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion Energy’s Consolidated Statements of Income. |
Balance Sheet Presentation The tables below present Virginia Power’s derivative asset and liability balances by type of financial instrument, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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) | | | | | | | | | | | | Gross Assets Presented in the Consolidated Balance Sheet (1) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total derivatives, subject to a master netting or similar arrangement | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2021 | | | December 31, 2020 | | | | Gross Amounts Not Offset in the Consolidated Balance Sheet | | | Gross Amounts Not Offset in the Consolidated Balance Sheet | | | | Gross Assets Presented in the Consolidated Balance Sheet(1) | | | Financial Instruments | | | Cash Collateral Received | | | Net Amounts | | | Gross Assets Presented in the Consolidated Balance Sheet(1) | | | Financial Instruments | | | Cash Collateral Received | | | Net Amounts | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Commodity contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | $ | 110 | | | $ | 8 | | | $ | — | | | $ | 102 | | | $ | 111 | | | $ | 6 | | | $ | 0 | | | $ | 105 | | Exchange | | | 7 | | | | 7 | | | | — | | | | — | | | | 1 | | | | 1 | | | | 0 | | | | 0 | | Interest rate contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | | 146 | | | | 20 | | | | — | | | | 126 | | | | 66 | | | | 7 | | | | 0 | | | | 59 | | Foreign currency exchange rate contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | | 8 | | | | — | | | | — | | | | 8 | | | | — | | | | 0 | | | | 0 | | | | 0 | | Total derivatives, subject to a master netting or similar arrangement | | $ | 271 | | | $ | 35 | | | $ | — | | | $ | 236 | | | $ | 178 | | | $ | 14 | | | $ | 0 | | | $ | 164 | |
(1) | Excludes $3$29 million and $26$3 million of derivative assets at December 31, 20192021 and 2018,2020, respectively, which are not subject to master netting or similar arrangements. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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) | | | | | | | | | | | | Gross Liabilities Presented in the Consolidated Balance Sheet (1) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total derivatives, subject to a master netting or similar arrangement | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2021 | | | December 31, 2020 | | | | Gross Amounts Not Offset in the Consolidated Balance Sheet | | | Gross Amounts Not Offset in the Consolidated Balance Sheet | | | | Gross Liabilities Presented in the Consolidated Balance Sheet(1) | | | Financial Instruments | | | Cash Collateral Paid | | | Net Amounts | | | Gross Liabilities Presented in the Consolidated Balance Sheet(1) | | | Financial Instruments | | | Cash Collateral Paid | | | Net Amounts | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Commodity contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | $ | 84 | | | $ | 8 | | | $ | 54 | | | $ | 22 | | | $ | 6 | | | $ | 6 | | | $ | — | | | $ | — | | Exchange | | | 43 | | | | 7 | | | | 36 | | | | — | | | | 1 | | | | 1 | | | | — | | | | — | | Interest rate contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | | 337 | | | | 20 | | | | — | | | | 317 | | | | 376 | | | | 7 | | | | — | | | | 369 | | Total derivatives, subject to a master netting or similar arrangement | | $ | 464 | | | $ | 35 | | | $ | 90 | | | $ | 339 | | | $ | 383 | | | $ | 14 | | | $ | — | | | $ | 369 | |
(1) | Excludes $44 $6million and $9$22 million of derivative liabilities at December 31, 20192021 and 2018,2020, respectively, which are not subject to master netting or similar arrangements. |
Combined Notes to Consolidated Financial Statements, Continued
The following table presents the volume of Virginia Power’s derivative activity at December 31, 2019.2021. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions. | | Current | | | Noncurrent | | Natural Gas (bcf): | | | | | | | | | Fixed price(1) | | | 24 | | | | 5 | | Basis | | | 139 | | | | 440 | | Electricity (MWh in millions): | | | | | | | | | Fixed price | | | 6 | | | | 7 | | FTRs | | | 44 | | | | — | | Interest rate(2) (in millions) | | $ | 1,000 | | | $ | 1,750 | | Foreign currency exchange rate(2) (in millions) | | 501 kr. | | | 4,581 kr. | |
(2) | Maturity is determined based on final settlement period. |
The following table presents selected information related to losses on cash flow hedges included in AOCI in Virginia Power’s Consolidated Balance SheetSheets at December 31, 2019:2021: | | AOCI After-Tax | | | Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax | | | Maximum Term | (millions) | | | | | | | | | | | Interest rate | | $ | (45 | ) | | $ | (2 | ) | | 396 months | Total | | $ | (45 | ) | | $ | (2 | ) | | |
| | | | | | | | | | | | | | | | | | Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax | | | | | | | | | | | | | | | | | $ | | ) | | $ | | ) | | | | | | | $ | | ) | | $ | | ) | | | | |
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., interest payments) in earnings, thereby achieving the realization of interest rates contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in interest rates.
Fair Value and Gains and Losses on Derivative Instruments The following tables present the fair values of Virginia Power’s derivatives and where they are presented in its Consolidated Balance Sheets: | | | | | | | | | | | | | | | Fair Value –
Derivatives
under
Hedge
Accounting | | | Fair Value –
Derivatives
not under
Hedge
Accounting | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | Total current derivative assets (1) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total noncurrent derivative assets (2) | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | Total current derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total noncurrent derivatives liabilities (3) | | | | | | | | | | | | | Total derivative liabilities | | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | Total current derivative assets (1) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total noncurrent derivative assets (2) | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | Total current derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total noncurrent derivative liabilities (3) | | | | | | | | | | | | | Total derivative liabilities | | | | | | | | | | $ | | |
| | Fair Value – Derivatives under Hedge Accounting | | | Fair Value – Derivatives not under Hedge Accounting | | | Total Fair Value | | (millions) | | | | | | | | | | | | | At December 31, 2021 | | | | | | | | | | | | | ASSETS | | | | | | | | | | | | | Current Assets | | | | | | | | | | | | | Commodity | | $ | — | | | $ | 74 | | | $ | 74 | | Interest rate | | | 1 | | | | — | | | | 1 | | Foreign currency exchange rate | | | — | | | | 1 | | | | 1 | | Total current derivative assets(1) | | | 1 | | | | 75 | | | | 76 | | Noncurrent Assets | | | | | | | | | | | | | Commodity | | | — | | | | 72 | | | | 72 | | Interest rate | | | 145 | | | | — | | | | 145 | | Foreign currency exchange rate | | | — | | | | 7 | | | | 7 | | Total noncurrent derivative assets(2) | | | 145 | | | | 79 | | | | 224 | | Total derivative assets | | $ | 146 | | | $ | 154 | | | $ | 300 | | LIABILITIES | | | | | | | | | | | | | Current Liabilities | | | | | | | | | | | | | Commodity | | $ | — | | | $ | 92 | | | $ | 92 | | Interest rate | | | 42 | | | | — | | | | 42 | | Total current derivative liabilities | | | 42 | | | | 92 | | | | 134 | | Noncurrent Liabilities | | | | | | | | | | | | | Commodity | | | — | | | | 41 | | | | 41 | | Interest rate | | | 295 | | | | — | | | | 295 | | Total noncurrent derivatives liabilities(3) | | | 295 | | | | 41 | | | | 336 | | Total derivative liabilities | | $ | 337 | | | $ | 133 | | | $ | 470 | | At December 31, 2020 | | | | | | | | | | | | | ASSETS | | | | | | | | | | | | | Current Assets | | | | | | | | | | | | | Commodity | | $ | — | | | $ | 22 | | | $ | 22 | | Total current derivative assets(1) | | | — | | | | 22 | | | | 22 | | Noncurrent Assets | | | | | | | | | | | | | Commodity | | | — | | | | 93 | | | | 93 | | Interest rate | | | 66 | | | | — | | | | 66 | | Total noncurrent derivative assets(2) | | | 66 | | | | 93 | | | | 159 | | Total derivative assets | | $ | 66 | | | $ | 115 | | | $ | 181 | | LIABILITIES | | | | | | | | | | | | | Current Liabilities | | | | | | | | | | | | | Commodity | | $ | — | | | $ | 28 | | | $ | 28 | | Interest rate | | | 362 | | | | — | | | | 362 | | Total current derivative liabilities | | | 362 | | | | 28 | | | | 390 | | Noncurrent Liabilities | | | | | | | | | | | | | Commodity | | | — | | | | 1 | | | | 1 | | Interest rate | | | 14 | | | | — | | | | 14 | | Total noncurrent derivatives liabilities(3) | | | 14 | | | | 1 | | | | 15 | | Total derivative liabilities | | $ | 376 | | | $ | 29 | | | $ | 405 | |
(1) | Current derivative assets are presented in other current assets in Virginia Power’s Consolidated Balance Sheets. |
(2) | Noncurrent derivative assets are presented in other deferred charges and other assets in Virginia Power’s Consolidated Balance Sheets. |
(3) | Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Virginia Power’s Consolidated Balance Sheets. |
The following tables present the gains and losses on Virginia Power’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income: | | | | | | | | | | | | | Derivatives in cash flow hedging
relationships | | Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion) (1) | | | Amount of
Gain (Loss)
Reclassified
From AOCI
to Income | | | Increase (Decrease) in Derivatives Subject to Regulatory Treatment (2) | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2019 | | | | | | | | | | | | | Derivative type and location of gains (losses): | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | | | | | ) | | | | ) | | | | ) | | | | | | | | | | | | | | | Year Ended December 31, 2018 | | | | | | | | | | | | | Derivative type and location of gains (losses): | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2017 | | | | | | | | | | | | | Derivative type and location of gains (losses): | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | | | | | ) | | | | ) | | | | ) |
Derivatives in cash flow hedging relationships | | Amount of Gain (Loss) Recognized in AOCI on Derivatives(1) | | | Amount of Gain (Loss) Reclassified From AOCI to Income | | | Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2) | | (millions) | | | | | | | | | | | | | Year Ended December 31, 2021 | | | | | | | | | | | | | Derivative type and location of gains (losses): | | | | | | | | | | | | | Interest rate(3) | | $ | 17 | | | $ | (3 | ) | | $ | 130 | | Total | | $ | 17 | | | $ | (3 | ) | | $ | 130 | | Year Ended December 31, 2020 | | | | | | | | | | | | | Derivative type and location of gains (losses): | | | | | | | | | | | | | Interest rate(3) | | $ | (37 | ) | | $ | (2 | ) | | $ | (338 | ) | Total | | $ | (37 | ) | | $ | (2 | ) | | $ | (338 | ) | Year Ended December 31, 2019 | | | | | | | | | | | | | Derivative type and location of gains (losses): | | | | | | | | | | | | | Interest rate(3) | | $ | (30 | ) | | $ | (1 | ) | | $ | (259 | ) | Total | | $ | (30 | ) | | $ | (1 | ) | | $ | (259 | ) |
(1) | Amounts deferred into AOCI have no associated effect in Virginia Power’s Consolidated Statements of Income. |
(2) | Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income. |
(3) | Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in interest and related charges. |
| | | | | | | | | | | | | Derivatives not designated as hedging instruments | | Amount of Gain (Loss) Recognized in Income on Derivatives (1) | | | | | | | | | | | | | | | | | | | | | | Derivative type and location of gains (losses): | | | | | | | | | | | | | | | $ | | ) | | | | | | | | | | | $ | | ) | | | | | | | | |
Derivatives not designated as hedging instruments | | Amount of Gain (Loss) Recognized in Income on Derivatives(1) | | Year Ended December 31, | | 2021 | | | 2020 | | | 2019 | | (millions) | | | | | | | | | | | | | Derivative type and location of gains (losses): | | | | | | | | | | | | | Commodity: | | | | | | | | | | | | | Operating revenue | | $ | (62 | ) | | $ | (104 | ) | | $ | (45 | ) | Electric fuel and other energy-related purchases | | | 9 | | | | — | | | | — | | Total | | $ | (53 | ) | | $ | (104 | ) | | $ | (45 | ) |
(1) | Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income. |
(2) | Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in electric fuel and other energy-related purchases. |
Combined Notes to Consolidated Financial Statements, Continued
Balance Sheet Presentation
The tables below present Dominion Energy Gas’ 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:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 | | | | | | | | | | | | Gross Assets
Presented in the
Consolidated
Balance Sheet | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Foreign currency contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total derivatives, subject to a master netting or similar arrangement | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 | | | | | | | | | | | | Gross Liabilities
Presented in the
Consolidated
Balance Sheet | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Foreign currency contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total derivatives, subject to a master netting or similar arrangement | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The following table presents the volume of Dominion Energy Gas’ derivative activity at December 31, 2019. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.
(1) | Maturity is determined based on final settlement period. |
The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2019:
| | | | | | | | | | | | | | | | | | | Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | ) | | | | | | | | | ) | | | | | | | | |
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) 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 and Gains and Losses on Derivative Instruments
The following table presents the fair values of Dominion Energy Gas’ derivatives and where they are presented in its Consolidated Balance Sheets:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | Total noncurrent derivative assets (1) | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | Total current derivative liabilities (2) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total noncurrent derivative liabilities (3) | | | | | | | | | | | | | Total derivative liabilities | | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | Total current derivative assets (4) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total noncurrent derivative assets (1) | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | Total current derivative liabilities (2) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total noncurrent derivative liabilities (3) | | | | | | | | | | | | | Total derivative liabilities | | | | | | | | | | $ | | |
(1) | Noncurrent derivative assets are presented in other deferred charges and other assets in Dominion Energy Gas’ Consolidated Balance Sheets. |
(2) | Current derivative liabilities are presented in other current liabilities in Dominion Energy Gas’ Consolidated Balance Sheets.
|
(3) | Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion Energy Gas’ Consolidated Balance Sheets. |
(4) | Current derivative assets include $2 million in other current assets, with the remainder recorded in current assets of discontinued operations in Dominion Energy Gas’ Consolidated Balance Sheets. |
Combined Notes to Consolidated Financial Statements, Continued
The following tables present the gains and losses on Dominion Energy Gas’ derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:
| | | | | | | | | | Derivatives in cash flow hedging relationships | | | | | Gain (Loss)
Reclassified
From AOCI
to Income | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2019 | | | | | | | | | | | | | | | | | | | Derivative type and location of gains (losses): | | | | | | | | | | | | | | | | | | Net income from discontinued operations | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | | ) | | | | ) | | | | | ) | | | | ) | Year Ended December 31, 2018 | | | | | | | | | Derivative type and location of gains (losses): | | | | | | | | | | | | | | | | | | Net income from discontinued operations | | | | | | | | ) | | | | | | | | | ) | | | | | ) | | | | ) | | | | (6 | ) | | | (13 | ) | | | | | ) | | | | ) | Year Ended December 31, 2017 | | | | | | | | | Derivative type and location of gains (losses): | | | | | | | | | | | | | | | | | | Net income from discontinued operations | | | | | | | | ) | | | | | ) | | | | ) | | | | | | | | | ) | | | | | | | | | | | | | | | | | | |
(1) | Amounts deferred into AOCI have no associated effect in Dominion Energy Gas’ Consolidated Statements of Income. |
(2) | Amounts recorded in Dominion Energy Gas’ Consolidated Statements of Income are classified in interest and related charges. |
(3) | Amounts recorded in Dominion Energy Gas’ Consolidated Statements of Income are classified in other income. |
| | | | | | | | | | | | | | Derivatives not designated as hedging
instruments | | Amount of Gain (Loss) Recognized in | | | | | | | | | | | | | | | | | | | | | | Derivative type and location of gains (losses): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | ) | | | | |
NoteNOTE 8. Earnings Per Share EARNINGS PER SHAREThe following table presents the calculation of Dominion Energy’s basic and diluted EPS: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net income attributable to Dominion Energy | | $ | | | | $ | | | | $ | | | Preferred stock dividends (see Note 19) | | | | ) | | | | | | | | | Net income attributable to Dominion Energy – Basic | | | | | | | | | | | | | Dilutive effect of Series A Preferred Stock | | | | ) | | | | | | | | | Net income attributable to Dominion Energy – Diluted | | | | | | | | | | | | | Average shares of common stock outstanding – Basic | | | | | | | | | | | | | Net effect of dilutive securities (1) | | | | | | | | | | | | | Average shares of common stock outstanding – Diluted | | | | | | | | | | | | | Earnings Per Common Share – Basic | | $ | | | | $ | | | | $ | | | Earnings Per Common Share – Diluted | | $ | | | | $ | | | | $ | | |
| | 2021 | | | 2020 | | | 2019 | | (millions, except EPS) | | | | | | | | | | | | | Net income attributable to Dominion Energy from continuing operations | | $ | 2,647 | | | $ | 1,583 | | | $ | 653 | | Preferred stock dividends (see Note 19) | | | (68 | ) | | | (65 | ) | | | (17 | ) | Net income attributable to Dominion Energy from continuing operations - Basic | | | 2,579 | | | | 1,518 | | | | 636 | | Dilutive effect of Series A Preferred Stock | | | — | | | | (11 | ) | | | (28 | ) | Net income attributable to Dominion Energy from continuing operations - Diluted | | | 2,579 | | | $ | 1,507 | | | $ | 608 | | Net income (loss) attributable to Dominion Energy from discontinued operations - Basic & Diluted | | | 641 | | | $ | (1,984 | ) | | $ | 705 | | | | | | | | | | | | | | | Average shares of common stock outstanding – Basic | | | 807.8 | | | | 831.0 | | | | 808.8 | | Net effect of dilutive securities(1) | | | 0.7 | | | | — | | | | 0.1 | | Average shares of common stock outstanding – Diluted | | | 808.5 | | | | 831.0 | | | | 808.9 | | | | | | | | | | | | | | | EPS from continuing operations - Basic | | $ | 3.19 | | | $ | 1.83 | | | $ | 0.79 | | EPS from discontinued operations - Basic | | | 0.79 | | | | (2.39 | ) | | | 0.87 | | EPS attributable to Dominion Energy - Basic | | $ | 3.98 | | | $ | (0.56 | ) | | $ | 1.66 | | | | | | | | | | | | | | | EPS from continuing operations - Diluted | | | 3.19 | | | $ | 1.82 | | | $ | 0.75 | | EPS from discontinued operations - Diluted | | | 0.79 | | | | (2.39 | ) | | | 0.87 | | EPS attributable to Dominion Energy - Diluted | | $ | 3.98 | | | $ | (0.57 | ) | | $ | 1.62 | |
(1) | (1) | Dilutive securitiesfor 20182021 consist primarily of stock expected to be issued to satisfy the obligation under a settlement agreement with the SCDOR (applying the if converted method) as well as forward salesales agreements effective April 2018 to December 2018.entered into in November 2021 (applying the treasury stock method). See Notes 1720 and 1923 for moreadditional information. |
The 2019 Equity Units, the Q-Pipe Transaction deposit, prior to being settled in cash in July 2021 and the 2016 Equity Units, prior to being settled via stock issuances in August 2019, are potentially dilutive securities. instruments. See Notes 3, 18 and 19 for additional information. The forward stock purchase contracts included within the 2019 Equity Units were excluded from the calculation of diluted EPS from continuing operations for the yearyears ended December 31, 2021, 2020 and 2019 as the dilutive stock price threshold was not met. The Series A Preferred Stock included within the 2019 Equity Units is excluded from the effect of dilutive securities within diluted EPS from continuing operations, but a fair value adjustment is reflected within net income attributable to Dominion Energy from continuing operations for the calculation of diluted EPS from continuing operations for the yearyears ended December 31, 2020 and 2019, based upon the expectation that the conversion will be settled in cash rather than through the issuance of Dominion Energy common stock. As described in Note 19, effective November 2021 any settlement of the conversion up to $1,000 per share is payable in cash, and any amount in excess of $1,000 per share may be settled in cash, common stock or a combination thereof. For the year ended December 31, 2021, a fair value adjustment related to the Series A Preferred Stock included within the 2019 Equity Units is excluded from the calculation of diluted EPS from continuing operations, as such fair value adjustment was not dilutive during the period. The impact of settling the deposit associated with the Q-Pipe Transaction in shares is excluded from the calculation for the years ending December 31, 2021 and 2020 based upon the expectation Dominion Energy would settle in cash, which occurred in July 2021, rather than through the issuance of shares of Dominion Energy common stock. The 2016 Equity Units were potentially dilutive securities but were excluded from the calculation of diluted EPS from continuing operations for the yearsyear ended December 31, 2019 2018 and 2017 as the dilutive stock price threshold was not met. The
NOTE 9. INVESTMENTS Dominion Energy Midstream convertible preferred units were potentially dilutive securities but had no effect on the calculation of diluted EPS for the years ended December 31, 2018 and 2017. In calculating diluted EPS in connection with the Dominion Energy Midstream convertible preferred units, Dominion Energy applied the if-converted
method.
Equity and Debt Securities Equity and fixed income securities and cash equivalents in Dominion Energy’s rabbi trusts and classified as trading totaled $120$122 million and $111$134 million at December 31, 20192021 and 2018,2020, respectively. Decommissioning Trust Securities Dominion Energy holds equity and fixed income securities, insurance contracts and cash equivalents in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Dominion Energy’s decommissioning trust funds are summarized below: | | Amortized Cost | | | Total Unrealized Gains | | | Total Unrealized Losses | | | Allowance for Credit Losses | | | Fair Value | | (millions) | | | | | | | | | | | | | | | | | | | | | December 31, 2021 | | | | | | | | | | | | | | | | | | | | | Equity securities:(1) | | | | | | | | | | | | | | | | | | | | | U.S. | | $ | 1,567 | | | $ | 3,734 | | | $ | (13 | ) | | | | | | $ | 5,288 | | Fixed income securities:(2) | | | | | | | | | | | | | | | | | | | | | Corporate debt instruments | | | 854 | | | | 32 | | | | (5 | ) | | $ | — | | | | 881 | | Government securities | | | 1,382 | | | | 43 | | | | (7 | ) | | | — | | | | 1,418 | | Common/collective trust funds | | | 168 | | | | 4 | | | | — | | | | — | | | | 172 | | Insurance contracts | | | 255 | | | | — | | | | — | | | | | | | | 255 | | Cash equivalents and other(3) | | | 9 | | | | 2 | | | | (75 | ) | | | — | | | | (64 | ) | Total | | $ | 4,235 | | | $ | 3,815 | | | $ | (100 | ) | (4) | $ | — | | | $ | 7,950 | | December 31, 2020 | | | | | | | | | | | | | | | | | | | | | Equity securities:(1) | | | | | | | | | | | | | | | | | | | | | U.S. | | $ | 1,756 | | | $ | 2,948 | | | $ | (24 | ) | | | | | | $ | 4,680 | | Fixed income securities:(2) | | | | | | | | | | | | | | | | | | | | | Corporate debt instruments | | | 572 | | | | 58 | | | | (1 | ) | | $ | — | | | | 629 | | Government securities | | | 1,119 | | | | 66 | | | | (1 | ) | | | — | | | | 1,184 | | Common/collective trust funds | | | 170 | | | | 5 | | | | — | | | | — | | | | 175 | | Insurance contracts | | | 237 | | | | — | | | | — | | | | | | | | 237 | | Cash equivalents and other(3) | | | (8 | ) | | | 4 | | | | (1 | ) | | | — | | | | (5 | ) | Total | | $ | 3,846 | | | $ | 3,081 | | | $ | (27 | ) | (4) | $ | — | | | $ | 6,900 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | ) | | $ | | | Fixed income securities: (2) | | | | | | | | | | | | | | | | | Corporate debt instruments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | Common/collective trust funds | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash equivalents and other (3) | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fixed income securities: (2) | | | | | | | | | | | | | | | | | Corporate debt instruments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Common/collective trust funds | | | | | | | | | | | | | | | | | Cash equivalents and other | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(1) | Unrealized gains and losses on equity securities are included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2. |
(2) | Unrealized gains and losses on fixed income securities are included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2. Changes in allowance for credit losses are included in other income. |
(3) | Includes pending purchases of securities of $1$35 million and $49 million at December 31, 2019.2021 and 2020, respectively. |
(4) | The fair value of securities in an unrealized loss position was $298$883 million and $833$293 million at December 31, 20192021 and 2018,2020, respectively. |
The portion of unrealized gains and losses that relates to equity securities held within Dominion Energy’s nuclear decommissioning trusts is summarized below: Year Ended December 31, | | 2021 | | | 2020 | | | 2019 | | (millions) | | | | | | | | | | | | | Net gains (losses) recognized during the period | | $ | 1,072 | | | $ | 512 | | | $ | 919 | | Less: Net gains recognized during the period on securities sold during the period | | | (346 | ) | | | (16 | ) | | | (80 | ) | Unrealized gains (losses) recognized during the period on securities still held at period end(1) | | $ | 726 | | | $ | 496 | | | $ | 839 | |
| | | | | | | | | | | | | | | | | | | | | | | Net gains (losses) recognized during the period | | $ | | | | $ | | ) | Less: Net gains recognized during the period on securities sold during the period | | | | ) | | | | ) | Unrealized gains (losses) recognized during the period on securities still held at December 31, 2019 and 2018 (1) | | $ | | | | $ | | ) |
(1) | Included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2. |
The fair value of Dominion Energy’s fixed income securities with readily determinable fair values held in nuclear decommissioning trust funds at December 31, 20192021 by contractual maturity is as follows:
| | Amount | | (millions) | | | | | Due in one year or less | | $ | 331 | | Due after one year through five years | | | 642 | | Due after five years through ten years | | | 630 | | Due after ten years | | | 868 | | Total | | $ | 2,471 | |
| | | | | | | | | | | | | | | | | | | | | $ | | | Due after one year through five years | | | | | Due after five years through ten years | | | | | | | | | | | | $ | | |
Combined Notes to Consolidated Financial Statements, Continued
Presented below is selected information regarding Dominion Energy’s equity and fixed income securities with readily determinable fair values held in nuclear decommissioning trust funds. Year Ended December 31, | | 2021 | | | 2020 | | | 2019 | | (millions) | | | | | | | | | | | | | Proceeds from sales | | $ | 3,985 | | | $ | 4,278 | | | $ | 1,712 | | Realized gains(1) | | | 441 | | | | 340 | | | | 195 | | Realized losses(1) | | | 91 | | | | 297 | | | | 96 | |
(1) | Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability as discussed in Note 2. |
Dominion Energy recorded other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total other-than-temporary impairment losses (1) | | $ | | | | $ | | | | $ | | | Losses recorded to the nuclear decommissioning trust regulatory liability | | | | | | | | | | | | ) | Losses recognized in other comprehensive income (before taxes) | | | | ) | | | | ) | | | | ) | Net impairment losses recognized in earnings | | $ | | | | $ | | | | $ | | |
(1) | Amounts include other-than-temporary impairment losses for fixed income securities of $5 million at December 31, 2017. |
Virginia Power holds equity and fixed income securities and cash equivalents in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Virginia Power’s decommissioning trust funds are summarized below: | | Amortized Cost | | | Total Unrealized Gains | | | Total Unrealized Losses | | | Allowance for Credit Losses | | | Fair Value | | (millions) | | | | | | | | | | | | | | | | | | | | | December 31, 2021 | | | | | | | | | | | | | | | | | | | | | Equity securities:(1) | | | | | | | | | | | | | | | | | | | | | U.S. | | $ | 841 | | | $ | 1,720 | | | $ | (11 | ) | | | | | | $ | 2,550 | | Fixed income securities:(2) | | | | | | | | | | | | | | | | | | | | | Corporate debt instruments | | | 517 | | | | 17 | | | | (3 | ) | | $ | — | | | | 531 | | Government securities | | | 584 | | | | 16 | | | | (2 | ) | | | — | | | | 598 | | Common/collective trust funds | | | 53 | | | | — | | | | — | | | | — | | | | 53 | | Cash equivalents and other(3) | | | 2 | | | | 0 | | | | 0 | | | | 0 | | | | 2 | | Total | | $ | 1,997 | | | $ | 1,753 | | | $ | (16 | ) | (4) | $ | 0 | | | $ | 3,734 | | December 31, 2020 | | | | | | | | | | | | | | | | | | | | | Equity securities:(1) | | | | | | | | | | | | | | | | | | | | | U.S. | | $ | 929 | | | $ | 1,371 | | | $ | (21 | ) | | | | | | $ | 2,279 | | Fixed income securities:(2) | | | | | | | | | | | | | | | | | | | | | Corporate debt instruments | | | 315 | | | | 33 | | | | — | | | $ | — | | | | 348 | | Government securities | | | 484 | | | | 25 | | | | — | | | | — | | | | 509 | | Common/collective trust funds | | | 58 | | | | — | | | | — | | | | — | | | | 58 | | Cash equivalents and other(3) | | | 3 | | | | 0 | | | | 0 | | | | 0 | | | | 3 | | Total | | $ | 1,789 | | | $ | 1,429 | | | $ | (21 | ) | (4) | $ | — | | | $ | 3,197 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fixed income securities: (2) | | | | | | | | | | | | | | | | | Corporate debt instruments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Common/collective trust funds | | | | | | | | | | | | | | | | | Cash equivalents and other | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fixed income securities: (2) | | | | | | | | | | | | | | | | | Corporate debt instruments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Common/collective trust funds | | | | | | | | | | | | | | | | | Cash equivalents and other (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(1) | Unrealized gains and losses on equity securities are included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.2 |
(2) | Unrealized gains and losses on fixed income securities are included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2. Changes in allowance for credit losses are included in other income. |
(3) | Includes pending sales of securities of $6$5 million at December 31, 2018.2021, and pending purchases of securities of $10 million at December 31, 2020. |
(4) | The fair value of securities in an unrealized loss position was $185$425 million and $404$142 million at December 31, 20192021 and 2018,2020, respectively. |
The portion of unrealized gains and losses that relates to equity securities held within Virginia Power’s nuclear decommissioning trusts is summarized below: | | | | | | | | | | | | | | | | | | | | | | | Net gains (losses) recognized during the period | | $ | | | | $ | | ) | Less: Net gains recognized during the period on securities sold during the period | | | | ) | | | | ) | Unrealized gains (losses) recognized during the period on securities still held at December 31, 2019 and 2018 (1) | | $ | | | | $ | | ) |
Year Ended December 31, | | 2021 | | | 2020 | | | 2019 | | (millions) | | | | | | | | | | | | | Net gains (losses) recognized during the period | | $ | 552 | | | $ | 224 | | | $ | 423 | | Less: Net gains recognized during the period on securities sold during the period | | | (190 | ) | | | (6 | ) | | | (20 | ) | Unrealized gains (losses) recognized during the period on securities still held at end of period (1) | | $ | 362 | | | $ | 218 | | | $ | 403 | |
(1) | Included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2. |
The fair value of Virginia Power’s fixed income securities with readily determinable fair values held in nuclear decommissioning trust funds at December 31, 2019,2021, by contractual maturity is as follows: | | Amount | | (millions) | | | | | Due in one year or less | | $ | 78 | | Due after one year through five years | | | 335 | | Due after five years through ten years | | | 361 | | Due after ten years | | | 408 | | Total | | $ | 1,182 | |
| | | | | | | | | | | | | | | | | | Due after one year through five years
| | | | | Due after five years through ten years
| | | | | | | | | | | | | | |
Presented below is selected information regarding Virginia Power’s equity and fixed income securities with readily determinable fair values held in nuclear decommissioning trust funds. Year Ended December 31, | | 2021 | | | 2020 | | | 2019 | | (millions) | | | | | | | | | | | | | Proceeds from sales | | $ | 1,791 | | | $ | 884 | | | $ | 858 | | Realized gains(1) | | | 228 | | | | 88 | | | | 58 | | Realized losses(1) | | | 35 | | | | 68 | | | | 22 | |
(1) | Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability as discussed in Note 2. |
Virginia Power recorded other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total other-than-temporary impairment losses (1) | | $ | | | | $ | | | | $ | | | Losses recorded to the nuclear decommissioning trust regulatory liability | | | | | | | | | | | | ) | Losses recognized in other comprehensive income (before taxes) | | | | ) | | | | ) | | | | ) | Net impairment losses recognized in earnings | | $ | | | | $ | | | | $ | | |
(1) | Amounts include other-than-temporary impairment losses for fixed income securities of $2 million at December 31, 2017. |
Equity Method Investments
EQUITY METHOD INVESTMENTS Investments that Dominion Energy accountaccounts for under the equity method of accounting are as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | % | | $ | | | | $ | | | | | | | | | | | % | | | | | | | | | | | | | | | | | % | | | | | | | | | | | Wind-powered merchant generation facility | | | | | | % | | | | | | | | | | | Nonregulated retail energy marketing | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | | | |
| | | | | | Investment | | | | Company | | Ownership% | | | Balance | | | Description | As of December 31, | | | | | | 2021 | | | 2020 | | | | (millions) | | | | | | | | | | | | | | | Cove Point | | | 50 | % | | $ | 2,738 | | | $ | 2,784 | | | LNG import/export and storage facility | Atlantic Coast Pipeline | | | 53 | % | | | 0 | | (3) | | — | | (3) | Gas transmission system | Wrangler | | | 15 | % | (2) | | 68 | | | | 74 | | | Nonregulated retail energy marketing | Align RNG(1) | | | 50 | % | | | 74 | | | | 25 | | | Renewable natural gas | Other | | various | | | | 52 | | | | 51 | | | | Total | | | | | | $ | 2,932 | | | $ | 2,934 | | | |
(1) | Liability of less than $1 million associated with NedPower recorded to other deferred credits and other liabilities, on the Consolidated Balance Sheets as of December 31, 2018. See additional discussion of NedPower below. |
(2) | Dominion Energy has an $80
millionEnergy’s unfunded commitment to be made to Align RNG by the end of 2022
. |
(2) | Dominion Energy’s ownership interest became 15% in December 2021, following the sale of 5% of its ownership interest. See discussion below. |
(3) | Dominion Energy’s Consolidated Balance Sheets include a liability associated with its investment in Atlantic Coast Pipeline of $113 million and $1.1 billion at December 31, 2021 and 2020, respectively. See discussion below for additional information. |
Dominion Energy recorded equity earnings on its investments totaled $168of $276 million, $197$40 million and $14$8 million in 2021, 2020 and 2019, 2018 and 2017, respectively, included in other income in Dominion Energy’sits Consolidated Statements of Income. In addition, Dominion Energy recorded equity earnings (losses) of $(20) million, $(2.3) billion and $117 million in 2021, 2020 and 2019, respectively, in discontinued operations related to its investment in Atlantic Coast Pipeline. Dominion Energy received distributions from these investments of $112$328 million, $209$102 million and $419$38 million in 2019, 20182021, 2020 and 2017,2019, respectively. As of December 31, 20192021 and 2018 ,
2020, the net difference between the carrying amount of Dominion Energy’s investments and its share of underlying equity in net assets was $110$244 million and $161$213 million, respectively. At December 31, 2019,2021, these differences are comprised of $159$27 million of equity method goodwill that is not being amortized, and a net $49$221 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,
and a net $(4) million basis difference primarily attributable to an unfunded commitment to be made to Align RNG. At December 31, 2018,
2020, these differences are comprised of $146$27 million of equity method goodwill that is not being amortized, and $15$227 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 $(41) million basis difference primarily attributable to an unfunded commitment made to Align RNG.Cove Point Prior to January 2019, Dominion Energy owned all of the common equity interest in Cove Point except for a preferred equity interest held by Dominion Energy Midstream (entitled to the first $50 million of annual cash distributions by Cove Point), in which Dominion Energy owned a controlling financial interest and consolidated. As discussed in Note 20, Dominion Energy acquired all of the outstanding partnership interests of Dominion Energy Midstream not owned by Dominion Energy in January 2019. In December 2019, Dominion Energy closed on an agreement to sell a 25% noncontrolling limited partnership interest in Cove Point. In November 2020, in conjunction with the GT&S Transaction, Dominion Energy sold 100% of its general partner interest and 25% of the total limited partner interest in Cove Point. Dominion Energy retained a 50% noncontrolling limited partnership interest in Cove Point which is accounted for as an equity method investment as Dominion Energy has the ability to exercise significant influence over, but not control, Cove Point. See Note 3 for further information regarding the sales of interests in Cove Point. Income before income taxes recorded by Cove Point for 2021, 2020 and 2019 was $528 million, $511 million and $471 million, respectively. For the periods prior to closing of the GT&S Transaction, earnings attributable to Dominion Energy are presented in discontinued operations. Subsequent to the closing of the GT&S Transaction, earnings attributable to Dominion Energy are presented within earnings from equity method investees in its Consolidated Statements of Income. In 2020, earnings attributable to Dominion Energy of $40 million are presented within earnings from equity method investees in its Consolidated Statements of Income. Dominion Energy recorded distributions from Cove Point of $300 million and $70 million in 2021 and 2020 (after the date of disposal), respectively. Dominion Energy made 0 contributions to Cove Point in 2021 or 2020 (after the date of disposal). All activity relating to Dominion Energy’s noncontrolling interest in Cove Point is recorded within Contracted Assets. See Note 3 for further information regarding the GT&S Transaction. Atlantic Coast Pipeline 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%. Atlantic Coast Pipeline is focused on constructing an approximately 600-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 under 20-year contracts. In March 2020, Dominion Energy completed the acquisition from Southern of its 5% membership interest in Atlantic Coast Pipeline and its 100% ownership interest in Pivotal LNG, Inc., for $184 million in aggregate, subject to certain purchase price adjustments. Pivotal LNG, Inc. includes a 50% noncontrolling interest in JAX LNG. Following completion of the acquisition, Dominion Energy owns a 53% noncontrolling membership interest in Atlantic Coast Pipeline with Duke Energy owning the remaining interest. Atlantic Coast Pipeline continues to be accounted for as an equity method investment as the power to direct the activities most significant to Atlantic Coast Pipeline is 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. Dominion Energy recorded contributions of $186 million, $414 million and $310 million during 2019, 2018 and 2017, respectively, to Atlantic Coast Pipeline. At December 31, 2019, Dominion Energy had $7 million of contributions payable to Atlantic Coast Pipeline included within other current liabilities in the Consolidated Balance Sheets.
Dominion Energy did not receive distributions from Atlantic Coast Pipeline during 2019 and received distributions of $36 million and $270 million during 2018 and 2017, respectively.
In October 2017, Dominion Energy entered into a guarantee agreement to support a portion of Atlantic Coast Pipeline’s obligation under its credit facility. See Note 23 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 alleges alleged non-compliance on the part of federal and state permitting authorities and adverse ecological consequences if the Atlantic Coast Pipeline Project iswas 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 U.S.the Army Corps of Engineers of Atlantic Coast Pipeline’s Huntington District 404 verification and the U.S.
Court of Appeals for the Fourth Circuit’s remand to the National Park Service of Atlantic Coast Pipeline’s Blue Ridge Parkwayright-of-way. Atlantic 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
Combined Notes to Consolidated Financial Statements, Continued
preparation for a reissuance of the biological opinion and incidental take statement. In June 2019, the Solicitor General of the U.S. and Atlantic Coast Pipeline filed petitions requesting that the Supreme Court of the U.S. hear the case regarding the Appalachian Trail crossing. In Februarycrossing and in June 2020, the Supreme Court of the U.S. heard oral argumentsruled in favor of the case and is expected to issue a ruling no later than June 2020. If a favorable ruling is not received, Atlantic Coast Pipeline, isreversing the lower court’s decision and remanding the case back to the U.S. Court of Appeals for the Fourth Circuit.The project also evaluating possible legislativefaced new and administrative remediesserious challenges from uncertainty related to this issue. GivenNWP 12, specifically, from the legal challenges described above and ongoing discussions with customers, project construction is expected to be completeddecision of the U.S. District Court for the District of Montana in April 2020 vacating an NWP 12 issued by the endArmy Corps of 2021,Engineers, including among other things gas pipelines, followed by a U.S. Court of Appeals for the Ninth Circuit ruling in May 2020 denying a stay of that decision. In July 2020, the Supreme Court of the U.S. issued an order allowing other new oil and gas pipeline projects to use the NWP 12 process pending appeal to the U.S. Court of Appeals for the Ninth Circuit; however, that did not decrease the uncertainty associated with fullin-service
an eventual ruling. The Montana district court decision was viewed as likely to prompt similar challenges in early 2022, with project costs estimatedother federal circuit courts related to be approximately $8 billion, excluding financing costs.permits issued under NWP 12, including for the Atlantic Coast Pipeline has reached agreements in principle withcustomersProject.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 potentiallyProject. Dominion Energy recorded equity method earnings (losses) of $(2.3) billion ($(1.8) billion after-tax) for the year ended December 31, 2020, as a result of the determination of the probable abandonment of the Atlantic Coast Pipeline Project in June 2020, and $(20) million ($(14) million after-tax) and $117 million ($118 million after-tax) for the year ended December 31, 2021 and 2019, respectively. In connection with Dominion Energy’s decision to sell substantially all of its gas transmission and storage operations, Dominion Energy has reflected the results of its equity method investment in Atlantic Coast Pipeline as discontinued operations in its Consolidated Statements of Income. As a result of its share of equity losses exceeding its investment Dominion Energy’s Consolidated Balance Sheets at December 31, 2021 and 2020 includes a liability of $113 million and $1.1 billion, respectively, which reflects Dominion Energy’s obligations to Atlantic Coast Pipeline related to its credit facility, through February 2021, and AROs. In October 2017, Dominion Energy entered into a guarantee agreement to support a portion of Atlantic Coast Pipeline’s obligation under a $3.4 billion revolving credit facility with a stated maturity date of October 2021. In July 2020, the capacity of the revolving credit facility was reduced from $3.4 billion to $1.9 billion. In February 2021, Atlantic Coast Pipeline repaid the outstanding borrowed amounts and terminated its revolving credit facility. Concurrently, Dominion Energy’s related guarantee agreement to support its portion of the Atlantic Coast Pipeline’s borrowings was also terminated. As of December 31, 2020, Atlantic Coast Pipeline had borrowed $1.8 billion against the revolving credit facility. Dominion Energy’s Consolidated Balance Sheets include a liability of $6 million associated with this guarantee agreement at December 31, 2020. The $1.1 billion liability at December 31, 2020 discussed above includes a $48 million adjustment related to this guarantee agreement that is reflected within equity as a cumulative effect of a change in accounting principle upon adoption of the new credit loss standard in January 2020. Dominion Energy recorded contributions of $965 million, $107 million and $186 million during 2021, 2020 and 2019, respectively, to Atlantic Coast Pipeline. Dominion Energy expects to incur additional losses from Atlantic Coast Pipeline as it completes wind-down activities. While Dominion Energy is unable to precisely estimate the amounts to be incurred by Atlantic Coast Pipeline, the portion of such amounts attributable to Dominion Energy is not expected to be material to Dominion Energy’s cash flows,results of operations, financial position and/or resultsstatement of operations. In February 2020, Dominion Energy entered into agreements with Southerncash flows.DETI provided services to acquire its 5% membership interest in Atlantic Coast Pipeline and its 100% ownership interest in Pivotal LNG, Inc., for approximately $175 million in aggregate, plus certain purchase price adjustments. Pivotal LNG, Inc. includes a 50% noncontrolling interest in JAX LNG, LLC, an LNG supplier in Florida serving the growing marine and truck LNG markets. The acquisitions are 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 will continuetotaled $49 million and $103 million in 2020 (prior to be reflected as an equity method investment asclosing of the power to direct the activities most significantGT&S Transaction) and 2019, respectively, included in discontinued operations in Dominion Energy’s Consolidated Statements of Income. All activity relating to Atlantic Coast Pipeline is shared with Duke. recorded within the Corporate and Other segment.Blue Racer In December 2018, Dominion Energy sold its 50% limited partnership interest in Blue Racer for up-front cash consideration of $1.05 billion and additional consideration of $150 million, subject to increase for interest costs effective March 2019, payable upon the purchaser’s availability of cash. TheIn the first quarter of 2019, Dominion Energy received $151 million of additional consideration, was recorded at a fair value of $150 million on the date of sale following a discounted cash flow model and is included within other receivablesincluding applicable interest, in the Consolidated Balance Sheets at December 31, 2018. The valuation is considered a Level 3 fair value measurement due to the use of judgment and unobservable inputs, including projected timing and amount of future cash flows and a discount rate reflecting risks inherent in the future cash flows. As a result of the sale, Dominion Energy recognized a gain of $546 million ($390 millionafter-tax),
included in other income in its Consolidated Statements of Income for the year ended December 31, 2018.connection with this sale. In addition, the purchaser agreed to pay additional consideration contingent upon the achievement of certain financial performance milestones of Blue Racer from 2019 through 2021. Pursuant to the purchase agreement, the aggregate will not exceed $300 million, which represents a gain contingency,and, as a result, Dominion Energy will not recognize any additional gain unless such consideration is realizable. In the first quarter of 2019, Dominion Energy received $151 million of additional consideration, including applicable interest, in connection with this sale. Blue Racer did not achieve the 2019, 2020 or 2021 financial performance milestones set forth in the sale agreement. All activity relating to Blue Racer is recorded within the Corporate and Other segment. Fowler Ridge
In September 2020, Dominion Energy sold its 50% noncontrolling partnership interest in Fowler Ridge & NedPower In the fourth quarter of 2017,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 recordedof $150 million. The $150 million payment was allocated between the contract termination and sale based on the relative fair value of each using an income approach. The fair value determinations for the payment allocations are considered Level 3 fair value measurements due to the use of significant judgmental and unobservable inputs, including the amount of future cash flows and discount rate reflecting risks inherent in the future cash flows and market prices. Dominion Energy recognized a chargeloss of $126$221 million ($ 76165 million after-tax) on the contract termination, included in impairment of assets and other incomecharges in its Consolidated Statements of Income reflecting its share of a long-lived asset impairment of property, plant and equipment recorded by NedPower, which resulted in losses in excess of Dominion Energy’s investment balance. Dominion Energy recordedfor the excess losses due to its commitment to provide further financial support for NedPower, resulting in a liability of $17 million atyear ended December 31, 2017, recorded2020, reflected in the Corporate and Other segment.All activity relating to other deferred credits and other liabilities, on the Consolidated Balance Sheets. As a result of the impairment recorded by NedPower, Dominion Energy evaluated its equity method investment in Fowler Ridge, a similar wind-powered merchant generation facility, determined its fair value was other than-temporarily impaired andunless otherwise specified, is recorded an impairment charge of $32 million ($20 millionafter-tax)
in other income in its Consolidated Statements of Income. The fair value of $81 million was estimated using a discounted cash flow method and is considered a Level 3 fair value measurement due to the use of significant unobservable inputs related to the timing and amount of future equity distributions based on the investee’s future wind generation and operating costs.within Contracted Assets.Wrangler In September 2019, Dominion Energy entered into an agreement to form Wrangler, a partnership with Interstate Gas Supply, Inc. Wrangler will operate a nonregulated natural gas retail energy marketing business with Dominion Energy contributing its nonregulated retail energy marketing operations and Interstate Gas Supply, Inc. contributing cash. At December 31, 2021 Dominion Energy has a 20%15% noncontrolling ownership interest in Wrangler, which is accounted for as an equity method investment as Dominion Energy has the ability to exercise significant influence, but not control, over the investee. The initial contribution, consisting of SEMI, closed in December 2019 for which Dominion Energy received $301 million in cash proceeds and a 20% noncontrolling ownership interest in Wrangler with initial fair value of $75 million estimated using the market approach. This valuation is considered a Level 2 fair value measurement given that it is based on the agreed-upon sales price. In connection with the transaction, Dominion Energy recorded a gain of $147 million, net of a $73 million write-off of goodwill, presented in gainslosses (gains) on sales of assets, and an associated tax expense of $82 million, in the Consolidated StatementStatements of Income. OverIncome for the next two years, under the termsyear ended December 31, 2019. The second contribution, consisting of the agreement,certain nonregulated natural gas retail energy contracts, closed in November 2020 for which Dominion Energy expectsreceived $74 million in cash proceeds and retained a 20% noncontrolling ownership interest through its ownership interest in Wrangler in the contracts valued at $13 million using the market approach. This valuation is considered a Level 2 fair value measurement given that it is based on the agreed-upon sales price. In connection with the transaction, Dominion Energy recorded a gain of $64 million presented in losses (gains) on sales of assets, and an associated tax expense of $19 million, in the Consolidated Statements of Income for the year ended December 31, 2020. The final contribution, consisting of Dominion Energy’s remaining nonregulated natural gas retail energy marketing operations, closed in December 2021 for which Dominion Energy received $127 million in cash proceeds and retained a 20% noncontrolling ownership interest in Wrangler with an initial fair value of $23 million estimated using the market approach. This valuation is considered a Level 2 fair value measurement given that it is based on the agreed-upon sales price. In connection with the transaction, Dominion Energy recorded a gain of $87 million, net of a $14 million write-off of goodwill, presented in losses (gains) on sales of assets, and an associated tax expense of $32 million, in the Consolidated Statements of Income for the year ended December 31, 2021. Subsequently in December 2021, Dominion Energy sold 5% of its noncontrolling ownership interest in Wrangler to contribute itsInterstate Gas Supply, Inc. for $33 million and recorded a gain of $10 million, presented in other income, and an associated tax expense of $3 million, in the Consolidated Statements of Income for the year ended December 31, 2021. At December 31, 2020, $63 million of assets and $15 million of liabilities associated with the remaining nonregulated retail energy marketing operations 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.
As of December 31, 2019, $41 million of assets associated with Dominion Energy’s residential contracts to be contributed to Wrangler in December 20202021 were classified as held for sale and were included in other current assets held for sale and current liabilities held for sale on theDominion Energy’s Consolidated Balance Sheet.Sheets, respectively. The related disposal group is primarily comprised of customer receivables, goodwill, inventories and inventories.
account payables.All activity relating to Wrangler is recorded within Gas Transmission & Storage. the Corporate and Other – Catalyst Old River Hydroelectric Limited Partnershipsegment.
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 will contribute its existing privatization operations, excluding contracts held by DESC, in South Carolina, Texas, Pennsylvania and Virginia and Patriot will contribute cash. The contribution of its 25% limited partnershipthe service concession arrangements currently held by Virginia Power requires approval from the Virginia and North Carolina Commissions. Dominion Energy expects to receive cash proceeds totaling $168 million, subject to customary closing adjustments, and a 50% noncontrolling ownership interest in Catalyst Old River Hydroelectric Limited PartnershipDominion Privatization following closing of the contributions expected to occur by the end of 2022, contingent on clearance or approval under the Hart-Scott-Rodino Act and received proceedsother customary closing and regulatory conditions. Dominion Energy expects to recognize gains totaling approximately $150 million ($110 million after-tax) upon closing of $91 million. The sale resulted in a gain of $87 million ($63 million after-tax),
which is included in other incomethe contributions. Dominion Energy’s 50% noncontrolling ownership interest in Dominion Energy’s Consolidated Statement of Income.Privatization will be accounted for as an equity method investment as Dominion Energy Gas Investments thathas the ability to exercise significant influence, but not control, over the investee.All activity relating to Dominion Privatization will be recorded within Dominion Energy Gas account for under the equity method of accounting are as follows:Virginia.
Dominion Energy Gas’ equity earnings on its investment totaled $43 million, $54 million and $47 million in 2019, 2018 and 2017, respectively. Dominion Energy Gas received distributions from its investment of $74 million, $64 million and $55 million in 2019, 2018 and 2017, respectively. As of December 31, 2019 and 2018, the carrying amount of Dominion Energy Gas’ investment exceeded its share of underlying equity in net assets by $146 million. The difference reflects equity method goodwill and is not being amortized.
Summarized financial information provided to Dominion Energy Gas by Iroquois for 100% of Iroquois at December 31, 2019 and 2018,
and for the years ended December 31, 2019, 2018 and 2017,
is presented below.Summarized financial information provided to Dominion Energy Gas by White River Hub for 100% of White River Hub at December 31, 2019 and 2018 and for the years ended December 31, 2019, 2018 and 2017 is presented below.
DETI provides services to Atlantic Coast Pipeline which totaled $103 million, $203 million and $129 million in 2019, 2018 and 2017, respectively, included in operating revenue in Dominion Energy and Dominion Energy Gas’ Consolidated Statements of Income. Amounts receivable related to these services were $7 million 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.
Combined Notes to Consolidated Financial Statements, Continued
NoteNOTE 10. Property, Plant EquipmentPROPERTY, PLANT AND EQUIPMENTMajor classes of property, plant and equipment and their respective balances for the Companies are as follows: At December 31, | | 2021 | | | 2020 | | (millions) | | | | | | | | | Dominion Energy | | | | | | | | | Utility: | | | | | | | | | Generation | | $ | 23,378 | | | $ | 22,697 | | Transmission | | | 15,430 | | | | 14,351 | | Distribution | | | 28,953 | | | | 27,311 | | Storage | | | 455 | | | | 436 | | Nuclear fuel | | | 2,306 | | | | 2,283 | | General and other | | | 4,373 | | | | 4,130 | | Plant under construction | | | 3,898 | | | | 3,350 | | Total utility | | | 78,793 | | | | 74,558 | | Non-jurisdictional - including plant under construction | | | 1,694 | | | | 1,225 | | Nonutility: | | | | | | | | | Nonregulated generation-nuclear | | | 1,773 | | | | 1,736 | | Nonregulated generation-solar | | | 2,026 | | | | 3,268 | | Nuclear fuel | | | 1,056 | | | | 1,012 | | Other-including plant under construction | | | 1,161 | | | | 1,160 | | Total nonutility | | | 6,016 | | | | 7,176 | | Total property, plant and equipment | | $ | 86,503 | | | $ | 82,959 | | Virginia Power | | | | | | | | | Utility: | | | | | | | | | Generation | | $ | 17,325 | | | $ | 16,769 | | Transmission | | | 11,760 | | | | 11,000 | | Distribution | | | 13,621 | | | | 12,839 | | Nuclear fuel | | | 1,702 | | | | 1,709 | | General and other | | | 912 | | | | 845 | | Plant under construction | | | 2,865 | | | | 2,338 | | Total utility | | | 48,185 | | | | 45,500 | | Non-jurisdictional - including plant under construction | | | 1,694 | | | | 1,225 | | Other | | | 11 | | | | 11 | | Total property, plant and equipment | | $ | 49,890 | | | $ | 46,736 | |
| | | | | | | | | | | At December 31, | | | | | 2018 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | 18,896 | | | | | | | | | 16,666 | | | | | | | | | 18,535 | | | | | | | | | 2,906 | | | | | | | | | 1,626 | | | | | | | | | 1,763 | | | | | | | | | 1,783 | | | | | | | | | 2,348 | | | | | | | | | 64,523 | | Non-jurisdictional—including plant under construction | | | | | | | 407 | | | | | | | | | | | Merchant generation-nuclear | | | | | | | 1,550 | | Merchant generation-other | | | | | | | 3,802 | | | | | | | | | 1,025 | | Gas gathering and processing | | | | | | | 185 | | | | | | | | | 3,977 | | Other—including plant under construction | | | | | | | 1,109 | | | | | | | | | 11,648 | | Total property, plant and equipment | | $ | | | | $ | 76,578 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | 18,896 | | | | | | | | | 9,391 | | | | | | | | | 11,771 | | | | | | | | | 1,626 | | | | | | | | | 820 | | | | | | | | | 1,602 | | | | | | | | | 44,106 | | Non-jurisdictional—including plant under construction | | | | | | | 407 | | | | | | | | | 11 | | Total property, plant and equipment | | $ | | | | $ | 44,524 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | 6,790 | | | | | | | | | 2,615 | | | | | | | | | 210 | | | | | | | | | 732 | | | | | | | | | 10,347 | | | | | | | | | | | | | | | | | | 3,977 | | Other—including plant under construction | | | | | | | 376 | | | | | | | | | 4,353 | | Total property, plant and equipment | | $ | | | | $ | 14,700 | |
Jointly-Owned Power Stations Dominion Energy and Virginia Power’sThe Companies proportionate share of jointly-owned power stations at December 31, 20192021 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 | | | 1,063 | | | | 2,532 | | | | 610 | | | | 1,353 | | | | 1,522 | | Accumulated depreciation | | | (714 | ) | | | (1,381 | ) | | | (273 | ) | | | (522 | ) | | | (699 | ) | Nuclear fuel | | | — | | | | 730 | | | | — | | | | 549 | | | | 603 | | Accumulated amortization of nuclear fuel | | | — | | | | (576 | ) | | | — | | | | (406 | ) | | | (387 | ) | Plant under construction | | | 6 | | | | 178 | | | | 1 | | | | 127 | | | | 76 | |
| | | | | | | | | | | | | | | | | | | | | | | | Bath County Pumped Storage Station (1) | | | | | | | | | | | | | | (millions, except
percentages) | | | | | | | | | | | | | | | | | | | | % | | �� | | % | | | | % | | | | % | | | | % | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | | | | | | | | | | | | | | | | | | | | | | Accumulated amortization of nuclear fuel | | | | | | | | ) | | | | | | | | ) | | | | ) | | | | | | | | | | | | | | | | | | | | | |
(1) | Units jointly owned by Virginia Power. |
(2) | Unit jointly owned by Dominion Energy. |
The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly-owned facilities in the same proportion as their respective ownership interest. Dominion 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. Sale of Certain Retail Energy Marketing Assets
In October 2017, Dominion Energy entered into an agreement to sell certain assets associated with its nonregulated retail energy marketing operations for total consideration of $143 million, subject to customary approvals and certain adjustments. In December 2017, the first phase of the agreement closed for $79 million, which resulted in the recognition of a $78 million ($48 millionafter-tax)
benefit, included in gains on sales of assets in Dominion Energy’s Consolidated Statements of Income. In October 2018, the second phase of the agreement closed for $63 million, which resulted in the recognition of a $65 million ($49 millionafter-tax)
benefit included in gains on sales of assets in Dominion Energy’s Consolidated Statements of Income. Pursuant to the agreement, Dominion Energy entered into a commission agreement with the buyer upon the first closing in December 2017 under which the buyer will pay a commission in connection with the right to use Dominion Energy’s brand in marketing materials and other services over aten-year
term.Sale of Certain Merchant Generation Facilities
In December 2018, Dominion Energy completed the sale of Fairless and Manchester for total consideration of $1.2 billion, subject to customary closing adjustments. Dominion Energy recognized a gain of $210 million ($198 millionafter-tax)
included in gains on sales of assets in Dominion Energy’s Consolidated Statements of Income. Theafter-tax
gain reflects Dominion Energy’s assessment andmore-likely-than-not
conclusion that the utilization of state tax incentives will reduce the income tax expense associated with the sale of these facilities.
Acquisition of Solar Projects The following table presents acquisitions by Virginia Power of solar projects. Virginia Power has claimed or expects to claim federal investment tax credits on the projects. Project Name | | Date Agreement Entered | | Date Agreement Closed | | Project Location | | Project Cost (millions(1)] | | | Date of Commercial Operations | | MW Capacity | | Gutenberg | | September 2017 | | June 2019 | | North Carolina | | | 142 | | | September 2019 | | | 80 | | Gloucester | | June 2018 | | February 2019 | | Virginia | | | 37 | | | April 2019 | | | 20 | | Grasshopper(2) | | August 2018 | | May 2019 | | Virginia | | | 128 | | | October 2020 | | | 80 | | Chestnut | | August 2018 | | May 2019 | | North Carolina | | | 127 | | | January 2020 | | | 75 | | Ft. Powhatan | | June 2019 | | June 2019 | | Virginia | | | 267 | | | January 2022 | | | 150 | | Belcher(3) | | June 2019 | | August 2019 | | Virginia | | | 164 | | | June 2021 | | | 88 | | Bedford | | August 2019 | | November 2019 | | Virginia | | | 106 | | | November 2021 | | | 70 | | Maplewood | | October 2019 | | October 2019 | | Virginia | | | 185 | | | Expected 2022 | | | 120 | | Rochambeau | | December 2019 | | January 2020 | | Virginia | | | 35 | | | December 2021 | | | 20 | | Pumpkinseed | | May 2020 | | May 2020 | | Virginia | | | 130 | | | Expected 2022 | | | 60 | | Bookers Mill | | February 2021 | | June 2021 | | Virginia | | | 200 | | | Expected 2023 | | | 127 | |
(1) | Includes acquisition costs. |
(2) | Referred to as Butcher Creek once placed in service. |
(3) | Referred to as Desper once placed in service. |
The following table presents acquisitions by Dominion Energy of solar projects.projects in addition to the Virginia Power solar projects presented above. Dominion Energy has claimed or expects to claim federal investment tax credits on the projects. Project Name | | Date Agreement Entered | | Date Agreement Closed | | Project Location | | Project Cost (millions)(1) | | | Date of Commercial Operations | | MW Capacity | | Greensville | | August 2019 | | August 2019 | | Virginia | | $ | 127 | | | December 2020 | | | 80 | | Myrtle | | August 2019 | | August 2019 | | Virginia | | | 32 | | | June 2020 | | | 15 | | Seabrook | | September 2019 | | September 2019 | | South Carolina | | | 103 | | | December 2019 | | | 72 | | Wilkinson | | November 2019 | | November 2019 | | North Carolina | | | 153 | | | December 2019 | | | 74 | | Blackville | | May 2020 | | May 2020 | | South Carolina | | | 12 | | | December 2020 | | | 7 | | Denmark | | May 2020 | | May 2020 | | South Carolina | | | 14 | | | December 2020 | | | 6 | | Yemassee | | May 2020 | | August 2020 | | South Carolina | | | 17 | | | January 2021 | | | 10 | | Trask | | May 2020 | | October 2020 | | South Carolina | | | 22 | | | March 2021 | | | 12 | | Hardin I | | June 2020 | | June 2020 | | Ohio | | | 240 | | | Split(2) | | | 150 | | Madison | | July 2020 | | July 2020 | | Virginia | | | 125 | | | Expected 2023 | | | 62 | | Hardin II | | August 2020 | | Expected 2022 | | Ohio | | | 295 | | | Expected 2023 | | | 150 | |
(1) | Includes acquisition costs. |
Assignment(1) Includes acquisition costs. (2)In December 2020 and January 2021, 97 MW and 53 MW of Tower Rental Portfolio Virginia Power rents spacethe project commenced commercial operations, respectively.In addition to the facilities discussed above, Dominion Energy has also entered into various agreements to install solar facilities, primarily at schools in Virginia. As of December 31, 2021, Dominion Energy had placed in service solar facilities with an aggregate generation capacity of 17 MW at a cost of $34 million and anticipates placing additional facilities in service by the end of 2022 with an estimated total projected cost of approximately $30 million and an aggregate generation capacity of 15 MW. Dominion Energy has claimed or expects to claim federal investment tax credits on certainthe projects. Acquisition of its electric transmission towers to various wireless carriers for communications antennasGathering and other equipment. Processing Assets In March 2017, Virginia Power sold its rental portfolio to Vertical Bridge Towers II, LLC for $91 million in cash. The proceeds are subject to Virginia Power’s FERC-regulated tariff, under which it is required to return half of the proceeds to customers. Virginia Power recorded $7 million and $6 million in operating revenue in 2019 and 2018, respectively,
and $11 million in other incomein
2017, with $22 million remaining to be recognized ratably through 2023.Assignments of Shale Development Rights
In December 2013, Dominion Energy Gas2020, Wexpro closed on agreements with two natural gas producers to convey over time approximately 100,000 acres of Marcellus Shale development rights underneath several of its natural gas storage fields. The agreements provided for payments to Dominion Energy Gas, subject to customary adjustments, of approximately $200 million over a period of nine years, and an overriding royalty interest in gas produced from the acreage. In 2013 through 2016, Dominion Energy Gas received approximately $116 million of cash proceeds and through amendments closed on the immediate conveyance of approximately 9,000 acres and a 32% partial interest in the 70,000 acres of Marcellus Shale development rights, which resulted in the recognition of $78 million of gains. In August 2017, DominionEnergy Gas and the natural gas producer signed an amendment to the agreement, which included the finalization of contractual matters on previous conveyances, the conveyance of Dominion Energy Gas’ remaining 68% interest in approximately 70,000 acres and the elimination of Dominion Energy Gas’ overriding
royalty interest in gas produced from all acreage. Dominion Energy Gas received total consideration of $130 million, with $65 million received in 2017 and $65 million received in September 2018 in connection with the final conveyance. As a result of this amendment, in 2017, Dominion Energy Gas recognized a $56 million ($33 millionafter-tax)
gain included in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income associated with the finalization of the contractual matters on previous conveyances, a $9 million ($5 millionafter-tax)
gain included in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income associated with the elimination of its overriding royalty interest and in 2018, a $65 million ($47 millionafter-tax)
gain included in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income associated with the final conveyance of acreage.In November 2014, Dominion Energy Gas closed 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 existing natural gas storage fields. The agreement providedgathering systems including pipelines, compressors and dehydration equipment for payments to Dominion Energy Gas, subject to customary adjustments,total consideration of approximately $120 million over a period of four years, and an overriding royalty interest in gas produced from 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, in connection with the existing agreement, Dominion Energy Gas conveyed an additional 50% interest in approximately 2,000 acres of Marcellus Shale development rights and received proceeds of $5 million and an overriding royalty interest
Combined Notes to Consolidated Financial Statements, Continued
in gas produced from the acreage. This transaction resulted in a $5 million ($3 millionafter-tax)
gain. The gains are included in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income. In January 2018, Dominion Energy Gas and the$38 million. These facilities gather natural gas producerin Colorado, Utah and Wyoming.In November 2021, Wexpro closed on an amendment to the agreement, which included the conveyance of Dominion Energy Gas’ remaining 50% interest in approximately 18,000 acres and the elimination of Dominion Energy Gas’ overriding royalty interest in gas produced from all acreage. Dominion Energy Gas received proceeds of $28 million, resulting in an approximately $28 million ($20 million after-tax)
gain recorded in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income.In March 2018, Dominion Energy Gas closed an agreement with a natural gas producergathering systems operator to convey approximately 11,000 acres of Utica and Point Pleasant 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 a paymenttotal consideration of $41 million.Non-Wholly-Owned Nonregulated Solar Facilities Sale to Terra Nova Renewable Partners In August 2021, Dominion Energy Gas,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 $16 million. 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 March 2018,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 Gas received cash proceedsrecorded a gain of $16$19 million associated with the conveyance of the acreage, resulting($15 million after-tax) in a $16 million ($12 millionafter-tax)
gain recorded in gainslosses (gains) on sales of assets in Dominion Energy Gas’its Consolidated Statements of Income.Income (reflected in the Corporate and Other segment). Except as specifically identified, all activity related to SBL Holdco is recorded within Contracted Assets.Sale to Clearway In June 2018,August 2021, Dominion Energy Gas closed an amendment toentered an agreement with a natural gas producerClearway 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 elimination ofHart-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 Gas’ overriding royalty interestrecorded a loss of $229 million ($176 million after-tax) in gas produced from approximately 9,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields previously conveyed in December 2013. In June 2018, Dominion Energy Gas received proceeds of $6 million associated with the transaction, resulting in a $6 million ($4 million after-tax)
gain recorded in gainslosses (gains) on sales of assets in Dominion Energy Gas’its Consolidated Statements of Income. AllIncome (reflected in the Corporate and Other segment), primarily associated with the derecognition of noncontrolling interest. Except as specifically identified, all activity related to shale development rightsFour Brothers and Three Cedars is recorded within Gas Transmission & Storage.Contracted Assets.Impairment In the third quarter of 2020, Dominion Energy performed a strategic review of its long-term intentions for its contracted nonregulated solar generation assets in partnerships outside of its core electric service territories in consideration of the impact of the VCEA and Dominion Energy’s decision to sell substantially all of its gas transmission and storage operations. Based on an evaluation of
Dominion Energy’s interests in these long-lived assets for recoverability under a probability weighted approach, Dominion Energy determined the assets were impaired. As a result of this evaluation, Dominion Energy recorded a charge of $665 million ($293 million after-tax attributable to Dominion Energy and $267 million attributable to noncontrolling interest) in impairment of assets and other charges in its Consolidated Statements of Income (reflected in the Corporate and Other segment) for the year ended December 31, 2020 to adjust the property, plant and equipment down to its estimated fair value of $1.4 billion. The fair value was estimated using an income approach. The valuation is considered a Level 3 fair value measurement due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risks inherent in the future cash flows and market prices. Virginia Power CCRO Utilization In 2021, Virginia Power wrote off $318 million, primarily to accumulated depreciation, representing the utilization of a CCRO in accordance with the GTSA in connection with the settlement of the 2021 Triennial Review. See Note 13 for additional information. NoteNOTE 11. GOODWILL AND INTANGIBLE ASSETS Goodwill and Intangible Assets During the fourth quarter of 2019, Dominion Energy realigned its segments which resulted in the formation of five primary operating segments and Dominion Energy Gas finalized a restructuring that was accounted for as a reorganization of entities under common control. The historical information presented herein has been recast to the current segment presentation and the current structure of Dominion Energy Gas. With respect to the segment realignment, goodwill has been reassigned to the affected reporting units and operating segments using a relative fair value allocation approach. 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, 2019(1) | | $ | 2,106 | | | $ | 3,512 | | | $ | 1,521 | | | $ | 242 | | | $ | 14 | | $ | 7,395 | | Contribution to Wrangler(2) | | | — | | | | — | | | | — | | | | — | | | | (14 | ) | | (14 | ) | Balance at December 31, 2020(1) | | $ | 2,106 | | | $ | 3,512 | | | $ | 1,521 | | | $ | 242 | | | $ | — | | $ | 7,381 | | Acquisition of Birdseye (3) | | | — | | | | — | | | | — | | | | 24 | | | | — | | | 24 | | Balance at December 31, 2021(1) | | $ | 2,106 | | | $ | 3,512 | | | $ | 1,521 | | | $ | 266 | | | $ | — | | $ | 7,405 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dominion
Energy
South
Carolina | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance at December 31, 2017 (1) | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | | | | | $ | | | Purchase Accounting Adjustment | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance at December 31, 2018 (1) | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Contribution of SEMI to Wrangler (3) | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | ) | Balance at December 31, 2019 (1) | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance at December 31, 2017 (1) | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | | | | | $ | | | Purchase Accounting Adjustment | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance at December 31, 2018 (1) | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | | | | | $ | | | No events affecting goodwill | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance at December 31, 2019 (1) | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | | | | | $ | | |
(1) | Goodwill amounts do not contain any accumulated impairment losses. |
(2) | See Note 3 for discussion of Dominion Energy’s acquisitions. |
(3) | See Note 9 for additional information. |
(1) Goodwill amounts do not contain any accumulated impairment losses. (2) See Note 9 for additional information including amounts reclassified to held for sale at December 31, 2020. (3) See Note 3 for more information. Other Intangible Assets The Companies’ other intangible assets are subject to amortization over their estimated useful lives. Dominion Energy’s amortization expense for intangible assets was $106$79 million, $82$69 million and $80$95 million for 2019, 20182021, 2020 and 2017,2019, respectively. In 2019 , in addition to intangible assets acquired in the SCANA Combination,
Dominion Energy acquired $120$311 million of intangible assets, primarily representing RGGI allowances and software, andright-of-use
assets, with an estimated weighted-average amortization period of approximately 107 years. Amortization expense for Virginia Power’s intangible assets was $31 million, $28 million and $30 million for 2021, 2020 and 2019, and $31 million for both 2018 and 2017.respectively. In 2019,2021, Virginia Power acquired $52$276 million of intangible assets, primarily representing RGGI allowances and software, with an estimated weighted-average amortization period of 87 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 andright-of-use
assets, with an estimated weighted-average amortization period of approximately 29 years.The components of intangible assets are as follows: | | 2021 | | | 2020 | | At December 31, | | Gross Carrying Amount | | | Accumulated Amortization | | | Gross Carrying Amount | | | Accumulated Amortization | | (millions) | | | | | | | | | | | | | | | | | Dominion Energy | | | | | | | | | | | | | | | | | Software, licenses and other(1) | | $ | 1,459 | | | $ | 675 | | | $ | 1,295 | | | $ | 530 | | Virginia Power | | | | | | | | | | | | | | | | | Software, licenses and other(1) | | $ | 685 | | | $ | 290 | | | $ | 482 | | | $ | 148 | |
(1) | Includes $158M of RGGI allowances purchased and consumed in 2021, with deferral to a regulatory asset. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Software, licenses and other | | $ | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Software, licenses and other | | $ | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Software, licenses and other | | $ | | | | | | | | $ | | | | | | |
Annual amortization expense for these intangible assets is estimated to be as follows:
| | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | (millions) | | | | | | | | | | | | | | | | | Dominion Energy | | $ | 72 | | $ | 58 | | $ | 50 | | $ | 42 | | $ | 28 | | Virginia Power | | $ | 29 | | $ | 23 | | $ | 20 | | $ | 16 | | $ | 9 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | |
NoteNOTE 12. Regulatory Assets And Liabilities REGULATORY ASSETS AND LIABILITIESRegulatory assets and liabilities include the following: At December 31, | | 2021 | | | 2020 | | (millions) | | | | | | | | | Dominion Energy | | | | | | | | | Regulatory assets: | | | | | | | | | Deferred cost of fuel used in electric generation(1) | | $ | 251 | | | $ | — | | Deferred project costs and DSM programs for gas utilities(2) | | | 53 | | | | 35 | | Unrecovered gas costs(3) | | | 191 | | | | 78 | | Deferred rider costs for Virginia electric utility(4) | | | 72 | | | | 98 | | Ashpond and landfill closure costs(5) | | | 193 | | | | — | | Deferred nuclear refueling outage costs(6) | | | 79 | | | | 53 | | NND Project costs(7) | | | 138 | | | | 138 | | PJM transmission rates(8) | | | 7 | | | | 71 | | Deferred early plant retirement charges(9) | | | 226 | | | | — | | Derivatives(10) | | | 112 | | | | 33 | | Other | | | 170 | | | | 193 | | Regulatory assets-current | | | 1,492 | | | | 699 | | Unrecognized pension and other postretirement benefit costs(11) | | | 548 | | | | 1,363 | | Deferred rider costs for Virginia electric utility(4) | | | 489 | | | | 311 | | Deferred project costs for gas utilities(2) | | | 675 | | | | 632 | | Interest rate hedges(12) | | | 899 | | | | 1,042 | | AROs and related funding(13) | | | 329 | | | | 331 | | Cost of reacquired debt(14) | | | 10 | | | | 245 | | NND Project costs(7) | | | 2,226 | | | | 2,364 | | Ash pond and landfill closure costs(5) | | | 2,223 | | | | 2,301 | | Deferred cost of fuel used in electric generation(1) | | | 409 | | | | — | | Deferred early plant retirement charges(9) | | | 226 | | | | — | | Other | | | 609 | | | | 544 | | Regulatory assets-noncurrent | | | 8,643 | | | | 9,133 | | Total regulatory assets | | $ | 10,135 | | | $ | 9,832 | | Regulatory liabilities: | | | | | | | | | Deferred cost of fuel used in electric generation(1) | | $ | — | | | $ | 58 | | Provision for future cost of removal and AROs(15) | | | 181 | | | | 183 | | Reserve for refunds and rate credits to electric utility customers(16) | | | 420 | | | | 128 | | Reserve for future credits to Virginia electric customers(17) | | | — | | | | 120 | | Income taxes refundable through future rates(18) | | | 153 | | | | 124 | | Monetization of guarantee settlement(19) | | | 67 | | | | 67 | | Commodity derivatives(10) | | | 55 | | | | 9 | | Other | | | 110 | | | | 120 | | Regulatory liabilities-current | | | 986 | | | | 809 | | Income taxes refundable through future rates(18) | | | 4,260 | | | | 4,376 | | Provision for future cost of removal and AROs(15) | | | 2,331 | | | | 2,150 | | Nuclear decommissioning trust(20) | | | 2,158 | | | | 1,719 | | Monetization of guarantee settlement(19) | | | 831 | | | | 903 | | Reserve for refunds and rate credits to electric utility customers(16) | | | 448 | | | | 540 | | Unrecognized pension and other postretirement benefit costs(11) | | | 200 | | | | 66 | | Overrecovered other postretirement benefit costs(21) | | | 105 | | | | 111 | | Other | | | 380 | | | | 322 | | Regulatory liabilities-noncurrent | | | 10,713 | | | | 10,187 | | Total regulatory liabilities | | $ | 11,699 | | | $ | 10,996 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Deferred cost of fuel used in electric generation (1) | | $ | | | | $ | | | Deferred project costs and DSM programs for gas utilities (2) | | | | | | | | | | | | | | | | | | Deferred rate adjustment clause costs for Virginia electric utility (4)(5) | | | | | | | | | Deferred nuclear refueling outage costs (6) | | | | | | | | | | | | | | | | | | PJM transmission rates (8) | | | | | | | | | | | | | | | | | | Regulatory assets-current | | | | | | | | | Deferred cost of fuel used in electric generation (1) | | | | | | | | | P ension and other postretirement benefit costs (9) | | | | | | | | | Deferred rate adjustment clause costs for Virginia electric utility (4)(5)(10) | | | | | | | | | PJM transmission rates (8) | | | | | | | | | Deferred project costs for gas utilities (2) | | | | | | | | | | | | | | | | | | AROs and related funding (12) | | | | | | | | | Cost of reacquired debt (13)(14) | | | | | | | | | | | | | | | | | | Ash pond and landfill closure costs (15) | | | | | | | | | | | | | | | | | | Regulatory assets-noncurrent | | | | | | | | | | | $ | | | | $ | | | | | | | | | | | | Provision for future cost of removal and AROs (16) | | $ | | | | $ | | | Reserve for refunds and rate credits to electric utility customers (17) | | | | | | | | | Cost-of-service impact of 2017 Tax Reform Act (18) | | | | | | | | | Income taxes refundable through future rates (19) | | | | | | | | | Monetization of guarantee settlement (20) | | | | | | | | | | | | | | | | | | Regulatory liabilities-current | | | | | | | | | Income taxes refundable through future rates (19) | | | | | | | | | Provision for future cost of removal and AROs (16) | | | | | | | | | Nuclear decommissioning trust (21) | | | | | | | | | Monetization of guarantee settlement (20) | | | | | | | | | Reserve for refunds and rate credits to electric utility customers (17) | | | | | | | | | Overrecovered other postretirement benefit costs (22) | | | | | | | | | | | | | | | | | | Regulatory liabilities-noncurrent | | | | | | | | | Total regulatory liabilities | | $ | | | | $ | | |
(1) | (1) | Reflects deferred fuel expenses for the Virginia, North Carolina and South Carolina jurisdictions of Dominion Energy’s electric generation operations. |
(2) | (2) | Primarily reflects amounts expected to be collected from or owed to gas customers in Dominion Energy’s service territories associated with current and prospective rider projects, including CEP, PIR and pipeline integrity management. See Note 13 for more information. |
(3) | (3) | Reflects unrecovered or overrecovered gas costs at regulated gas operations, which are recovered or refunded through filings with the applicable regulatory authority.authority. |
Combined Notes to Consolidated Financial Statements, Continued
(4) | Reflects deferrals under Virginia Power’s electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects, net of income taxes refundable from the 2017 Tax Reform Act for Virginia Power.projects. See Note 13 for more information.information. |
(5) | As a result of actions from the(5) | Primarily reflects legislation enacted in Virginia Commission in the first quarter of 2019 regarding the ratemaking treatment of excess deferred taxes from the adoption of the 2017 Tax Reform Act for all existing rate adjustment clauses,which requires any CCR asset located at certain Virginia Power recordedstations to be closed by removing the CCR to an approved landfill or through beneficial reuse. These deferred costs are expected to be collected over a $29 million ($22 millionafter-tax)
charge in operating revenue in the Consolidated Statements of Incomeperiod between 15 and 18 years commencing December 2021 through Rider CCR. Virginia Power is entitled to collect carrying costs on uncollected expenditures once expenditures have been made. See Note 13 for amounts which are probable of being returned to customers.additional information. |
(6) | (6) | Legislation enacted in Virginia in April 2014 requires Virginia Power to defer operation and maintenance costs incurred in connection with the refueling of any nuclear-powered generating plant. These deferred costs will be amortized over the refueling cycle, not to exceed 18 months. |
(7) | | Reflects expenditures by DESC associated with the NND Project, which pursuant to the SCANA Merger Approval Order, will be recovered from DESC electric service customers over a20-year period ending in 2039. See Note 3 for more information.information. |
(8) | | Reflects current portion of amounts to be recovered through retail rates in Virginia for payments Virginia Power willexpects to make to PJM over aten-year
period ending 2028through 2026 under the terms of a FERC settlement agreement in May 2018 resolving a PJM cost allocation matter. |
(9) | (9) | Reflects amounts from the early retirements of certain coal- and oil-fired generating units to be amortized through 2023 in accordance with the settlement of the 2021 Triennial Review. See Note 13 for additional information. |
| (10) | For jurisdictions subject to cost-based rate regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities as they are expected to be recovered from or refunded to customers. |
| (11) | Represents unrecognized pension and other postretirement employee benefit costs expected to be recovered or refunded through future rates generally over the expected remaining service period of plan participants by certain of Dominion Energy’sEnergy's rate-regulated subsidiaries.subsidiaries. |
(10) | During 2019, Virginia Power recorded a charge of $17 million ($13 millionafter-tax)
in impairment of assets and other charges (reflected in the Corporate and Other segment)
towrite-off
the balance of a regulatory asset for which it is no longer seeking recovery. |
(11)(12) | Reflects interest rate hedges recoverable from or refundable to customers. Certain of these instruments are settled and any related payments are being amortized into interest expense over the life of the related debt, which has a weighted-average useful life of approximately 27 years as of December 31, 2019.2021. |
(12) | | Represents deferred depreciation and accretion expense related to legal obligations associated with the future retirement of generation, transmission and distribution properties. The AROs primarily relate to DESC’s electric generating facilities, including Summer, and are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 105years. years. |
(13) | | In 2021, DESC recorded a charge of $237 million ($178 million after-tax) in impairment of assets and other charges, reflected in the reacquisitionCorporate and Other segment, to write-off the balance of debt are deferred and amortized as interest expense overa regulatory asset that is no longer probable of recovery under thewould-be
remaining life of the reacquired debt. The reacquired debt costs had a weighted-average life of approximately 26 years as of December 31, 2019. |
(14) | During 2019, DESC purchased certain of its first mortgage bonds as discussed settlement agreement approved in Note 18. As a result of these transactions, DESC incurred net costs, including write-offs of unamortized discount, premium and debt issuance costs, of $270 million. |
(15) | Primarily reflects legislation enacted in Virginia in March 2019 which requires any CCR unit located at certain Virginia Power stations to be closed by removing the CCRs to an approved landfill or through recycling for beneficial reuse. Subject to approval by the Virginia Commission, amounts are expected to be collected over a period between 15 and 18 years commencing no earlier than 2021. Virginia Power is entitled to collect carrying costs once expenditures have been made.DESC’s retail electric base rate case. See Note 2313 for additionalmore information. |
(16) | (15) | Rates charged to customers by Dominion Energy’s regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement.retirement. Reflects an increase of $66 million associated with the revision of certain gas distribution pipeline AROs in the third quarter of 2021. See Note 14 for more information. |
(17) | | Reflects amounts previously collected from retail electric customers of DESC for the NND Project to be credited over an estimated11-year period effective February 2019, in connection with the SCANA Merger Approval Order and Virginia legislation enacted in March 2018 that requiredone-time
rate credits of certain amounts to utility customers in Virginia.Order. See Notes 3 and 13 for more information. Also reflects amounts to be refunded to jurisdictional retail electric customers in Virginia associated with the settlement of the 2021 Triennial Review. See Note 13 for additional information. |
(18) | Balance refundable to customers(17) | Represents a reserve related to the decreaseexpected use of a CCRO in revenue requirements for recovery of income taxes ataccordance with the Companies’ regulated electric generation and electric and natural gas distribution operations.GTSA associated with the 2021 Triennial Review. See Notes 3 andNote 13 for additional information. |
(19) | (18) | Amounts recorded to pass the effect of reduced income taxes from the 2017 Tax Reform Act to customers in future periods, which will primarily reverse at the weighted average tax rate that was used to build the reserves over the remaining book life of the property, net of amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC equity. |
| (19) | Reflects amounts to be refunded to DESC electric service customers over a 20-year period ending in 2039 associated with the monetization of a bankruptcy settlement agreement. See Note 3 for more information. |
| (20) | Primarily reflects a regulatory liability representing amounts collected from Virginia jurisdictional customers and placed in external trusts (including income, losses and changes in fair value thereon, as applicable) for the future decommissioning of Dominion Energy’s utility nuclear generation stations, in excess of the related AROs. |
| (21) | Reflects a regulatory liability for the collection of postretirement benefit costs allowed in rates in excess of expense incurred. |
At December 31, | | 2021 | | | 2020 | | (millions) | | | | | | | | | Virginia Power | | | | | | | | | Regulatory assets: | | | | | | | | | Deferred cost of fuel used in electric generation(1) | | $ | 131 | | | $ | — | | Deferred rider costs(2) | | | 72 | | | | 98 | | Ash pond and landfill closure costs(3) | | | 193 | | | | — | | Deferred nuclear refueling outage costs(4) | | | 79 | | | | 53 | | PJM transmission rates(5) | | | 7 | | | | 71 | | Deferred early plant retirement charges(6) | | | 226 | | | | — | | Derivatives(7) | | | 105 | | | | 40 | | Other | | | 37 | | | | 33 | | Regulatory assets-current | | | 850 | | | | 295 | | Deferred rider costs(2) | | | 489 | | | | 311 | | Interest rate hedges(8) | | | 604 | | | | 733 | | Ash pond and landfill closure costs(3) | | | 2,223 | | | | 2,301 | | Deferred cost of fuel used in electric generation(1) | | | 409 | | | | — | | Deferred early plant retirement charges(6) | | | 226 | | | | — | | Other | | | 179 | | | | 164 | | Regulatory assets-noncurrent | | | 4,130 | | | | 3,509 | | Total regulatory assets | | $ | 4,980 | | | $ | 3,804 | | Regulatory liabilities: | | | | | | | | | Deferred cost of fuel used in electric generation(1) | | $ | — | | | $ | 58 | | Provision for future cost of removal(9) | | | 154 | | | | 152 | | Reserve for refunds to Virginia electric customers(10) | | | 306 | | | | — | | Reserve for future credits to Virginia electric customers(11) | | | — | | | | 120 | | Income taxes refundable through future rates(12) | | | 63 | | | | 54 | | Derivatives(7) | | | 51 | | | | 8 | | Other | | | 73 | | | | 33 | | Regulatory liabilities-current | | | 647 | | | | 425 | | Income taxes refundable through future rates(12) | | | 2,335 | | | | 2,404 | | Nuclear decommissioning trust(13) | | | 2,158 | | | | 1,719 | | Provision for future cost of removal(9) | | | 1,043 | | | | 980 | | Deferred cost of fuel used in electric generation(1) | | | — | | | | 54 | | Reserve for refunds to Virginia electric customers(10) | | | 25 | | | | — | | Other | | | 179 | | | | 181 | | Regulatory liabilities-noncurrent | | | 5,740 | | | | 5,338 | | Total regulatory liabilities | | $ | 6,387 | | | $ | 5,763 | |
| (1) | Reflects deferred fuel expenses for the Virginia and North Carolina jurisdictions of Virginia Power’s generation operations. |
| (2) | Reflects deferrals under Virginia Power’s electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects. See Note 13 for more information. |
| (3) | Primarily reflects legislation enacted in Virginia in 2019 which requires any CCR asset located at certain Virginia Power stations to be closed by removing the CCR to an approved landfill or through beneficial reuse. These deferred costs are expected to be collected over a period between 15 and 18 years commencing December 2021 through Rider CCR. Virginia Power is entitled to collect carrying costs on uncollected expenditures once expenditures have been made. See Note 13 for additional information. |
| (4) | Legislation enacted in Virginia in April 2014 requires Virginia Power to defer operation and maintenance costs incurred in connection with the refueling of any nuclear-powered generating plant. These deferred costs will be amortized over the refueling cycle, not to exceed 18 months. |
| (5) | Reflects current portion of amounts to be recovered through retail rates in Virginia for payments Virginia Power expects to make to PJM through 2026 under the terms of a FERC settlement agreement in May 2018 resolving a PJM cost allocation matter. |
| (6) | Reflects amounts from the early retirement of certain coal- and oil-fired generating units to be amortized through 2023 in accordance with the settlement of the 2021 Triennial Review. See Note 13 for more information. |
| (7) | For jurisdictions subject to cost-based rate regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities as they are expected to be recovered from or refunded to customers. |
| (8) | Reflects interest rate hedges recoverable from or refundable to customers. Certain of these instruments are settled and any related payments are being amortized into interest expense over the life of the related debt, which has a weighted-average useful life of approximately 25 years as of December 31, 2021. |
| (9) | Rates charged to customers by Virginia Power's regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement. |
| (10) | Reflects amounts to be refunded to jurisdictional retail electric customers in Virginia associated with the settlement of the 2021 Triennial Review. See Note 13 for additional information. |
| (11) | Represents a reserve related to the expected use of a CCRO in accordance with the GTSA associated with the 2021 Triennial Review. See Note 13 for additional information. |
| (12) | Amounts recorded to pass the effect of reduced income taxes from the 2017 Tax Reform Act to customers in future periods, which will reverse at the weighted average tax rate that was used to build the reserves over the remaining book life of the property, net of amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC equity.equity. |
(20) | Reflects amounts to be refunded to DESC electric service customers over a20-year
period ending in 2039 associated with the monetization of a bankruptcy settlement agreement. See Note 3 for additional information. |
(21)(13) | Primarily reflects a regulatory liability representing amounts collected from Virginia jurisdictional customers and placed in external trusts (including income, losses and changes in fair value thereon, as applicable) for the future decommissioning of Dominion Energy’s utility nuclear generation stations, in excess of the related AROs. |
(22) | Reflects a regulatory liability for the collection of postretirement benefit costs allowed in rates in excess of expense incurred. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Deferred cost of fuel used in electric generation (1) | | $ | | | | $ | | | Deferred rate adjustment clause costs (2)(3) | | | | | | | | | Deferred nuclear refueling outage costs (4) | | | | | | | | | PJM transmission rates (5) | | | | | | | | | | | | | | | | | | Regulatory assets-current | | | | | | | | | Deferred rate adjustment clause costs (2)(3)(6) | | | | | | | | | PJM transmission rates (5) | | | | | | | | | | | | | | | | | | Deferred cost of fuel used in electric generation (1) | | | | | | | | | Ash pond and landfill closure costs (8) | | | | | | | | | | | | | | | | | | Regulatory assets-noncurrent | | | | | | | | | | | $ | | | | $ | | | | | | | | | | | | Provision for future cost of removal (9) | | $ | | | | $ | | | Cost-of-service impact of 2017 Tax Reform Act (10) | | | | | | | | | Reserve for rate credits to electric utility customers (11`) | | | | | | | | | Income taxes refundable through future rates (12) | | | | | | | | | | | | | | | | | | Regulatory liabilities-current | | | | | | | | | Income taxes refundable through future rates (12) | | | | | | | | | Nuclear decommissioning trust (13) | | | | | | | | | Provision for future cost of removal (9) | | | | | | | | | | | | | | | | | | Regulatory liabilities-noncurrent | | | | | | | | | Total regulatory liabilities | | $ | | | | $ | | |
(1) | Reflects deferred fuel expenses for the Virginia and North Carolina jurisdictions of Virginia Power’s generation operations. |
(2) | Reflects deferrals under Virginia Power’s electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects, net of income taxes refundable from the 2017 Tax Reform Act for Virginia Power. See Note 13 for more information. |
(3) | As a result of actions from the Virginia Commission in the first quarter of 2019 regarding the ratemaking treatment of excess deferred taxes from the adoption of the 2017 Tax Reform Act for all existing rate adjustment clauses, Virginia Power recorded a $29 million ($22 millionafter-tax)
charge in operating revenue in the Consolidated Statements of Income for amounts which are probable of being returned to customers. |
(4) | Legislation enacted in Virginia in April 2014 requires Virginia Power to defer operation and maintenance costs incurred in connection with the refueling of any nuclear-powered generating plant. These deferred costs will be amortized over the refueling cycle, not to exceed 18 months. |
(5) | Reflects amounts to be recovered through retail rates in Virginia for payments Virginia Power will make to PJM over aten-year
period ending 2028 under the terms of a FERC settlement agreement in May 2018 resolving a PJM cost allocation matter. |
(6) | During 2019, Virginia Power recorded a charge of $17 million ($13 millionafter-tax)
in impairment of assets and other charges (reflected in the Corporate and Other segment)towrite-off
the balance of a regulatory asset for which it is no longer seeking recovery. |
(7) | Reflects interest rate hedges recoverable from or refundable to customers. Certain of these instruments are settled and any related payments are being amortized into interest expense over the life of the related debt, which has a weighted-average useful life of approximately 24 years as of December 31, 2019. |
(8) | Primarily reflects legislation enacted in Virginia in March 2019 which requires any CCR unit located at certain Virginia Power stations to be closed by removing the CCR to an approved landfill or through recycling for beneficial reuse. Subject to approval by the Virginia Commission, amounts are expected to be collected over a period between 15 and 18 years commencing no earlier than 2021. Virginia Power is entitled to collect carrying costs once expenditures have been made. See Note 23 for additional information. |
(9) | Rates charged to customers by Virginia Power’s regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement. |
(10) | Balance refundable to customers related to the decrease in revenue requirements for recovery of income taxes at regulated electric generation and distribution operations. See Note 13 for additional information. |
(11) | Charge associated with Virginia legislation enacted in March 2018 that requiredone-time
rate credits of certain amounts to utility customers. See Note 13 for additional information. |
(12) | Amounts recorded to pass the effect of reduced income taxes from the 2017 Tax Reform Act to customers in future periods, which will reverse at the weighted average tax rate that was used to build the reserves over the remaining book life of the property, net of amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC equity. |
(13) | Primarily reflects a regulatory liability representing amounts collected from Virginia jurisdictional customers and placed in external trusts (including income, losses and changes in fair value thereon) for the future decommissioning of Virginia Power’s utility nuclear generation stations, in excess of the related AROs.AROs. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | | | | | | | | | Regulatory assets-current (2) | | | | | | | | | Unrecognized pension and other postretirement benefit costs (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | Regulatory assets-noncurrent | | | | | | | | | | | $ | | | | $ | | | | | | | | | | | | Provision for future cost of removal and AROs (5) | | $ | | | | $ | | | Overrecovered gas costs (1) | | | | | | | | | | | | | | | | | | Regulatory liabilities-current (6) | | | | | | | | | Income taxes refundable through future rates (7) | | | | | | | | | Provision for future cost of removal and AROs (6) | | | | | | | | | Overrecovered other postretirement benefit costs (8) | | | | | | | | | | | | | | | | | | Regulatory liabilities-noncurrent | | | | | | | | | Total regulatory liabilities | | $ | | | | $ | | |
(1) | Reflects unrecovered or overrecovered gas costs at regulated gas operations, which are recovered or refunded through filings with the applicable regulatory authority. |
(2) | Current regulatory assets are presented in other current assets in Dominion Energy Gas’ Consolidated Balance Sheets. |
(3) | Represents unrecognized pension and other postretirement employee benefit costs expected to be recovered or refunded through future rates generally over the expected remaining service period of plan participants by certain of Dominion Energy Gas’ rate-regulated subsidiaries. |
(4) | Reflects interest rate hedges recoverable from or refundable to customers. Certain of these instruments are settled and any related payments are being amortized into interest expense over the life of the related debt, which has a weighted average useful life of approximately 30 years. |
(5) | Rates charged to customers by Dominion Energy Gas’ regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement. |
(6) | Current regulatory liabilities are presented in other current liabilities in Dominion Energy Gas’ Consolidated Balance Sheets. |
(7) | Amounts recorded to pass the effect of reduced income taxes from the 2017 Tax Reform Act to customers in future periods, which will reverse at the weighted average tax rate that was used to build the reserves over the remaining book life of the property, net of amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC equity. |
(8) | Reflects a regulatory liability for the collection of postretirement benefit costs allowed in rates in excess of expense incurred. |
At December 31, 2019,2021, Dominion Energy and Virginia Power and Dominion Energy Gas’ regulatory assets include $3.3 billion, $1.8$4.4 billion and $46 million,$3.0 billion, respectively, on which they do not expect to earn a return during the applicable recovery period. With the exception of certain items discussed above, the majority of these expenditures are expected to be recovered within the next two years. Note
NOTE 13. Regulatory Matters REGULATORY MATTERSRegulatory 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. Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Virginia Power purchases and, under its market based rate authority, sells electricity in the PJM wholesale market and to
Combined Notes to Consolidated Financial Statements, Continued
wholesale purchasers in Virginia and North Carolina. DESC sells electricity to wholesale purchasers in its balancing authority area under its electric cost based tariff and to wholesale purchasers outside of its balancing authority area under its market based rate authority. Dominion Energy’s merchant generators sell electricity in the PJM, CAISO andISO-NE
wholesale markets, and to wholesale purchasers in the states of Virginia, North Carolina, Indiana, Connecticut, Tennessee, Georgia, California, South Carolina and Utah, under Dominion Energy’s market-based sales tariffs authorized by FERC or pursuant to FERC authority to sell as a qualified facility. In addition, Virginia Power has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power’s service territory. Any such sales would be voluntary.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 investment in electric transmission infrastructure.
In March 2010, ODEC and North Carolina Electric Membership Corporation filed a complaint with FERC against Virginia Power claiming, among other issues, that the incremental costs of undergrounding certain transmission line projects were unjust, unreasonable and unduly discriminatory or preferential and should be excluded from Virginia Power’s transmission formula rate. A settlement of the other issues raised in the complaint was approved by FERC in May 2012.
In March 2014, FERC issued an order excluding from Virginia Power’s transmission rates for wholesale transmission customers located outside Virginia the incremental costs of undergrounding certain transmission line projects. FERC found it is not just and reasonable fornon-Virginia
wholesale transmission customers to be allocated the incremental costs of undergrounding the facilities because the projects are a direct result of Virginia legislation and Virginia Commission pilot programs intended to benefit the citizens of Virginia. The order is retroactively effective as of March 2010 and will cause the reallocation of the costs charged to wholesale transmission customers with loads outside Virginia to wholesale transmission customers with loads in Virginia. FERC determined that there was not sufficient evidence on the record to determine the magnitude of the underground increment and held a hearing to determine the appropriate amount of undergrounding cost to be allocated to each wholesale transmission customer in Virginia.In October 2017, FERC issued an order determining the calculation of the incremental costs of undergrounding the transmission projects and affirming that the costs are to be recovered from the wholesale transmission customers with loads located in Virginia. FERC directed Virginia Power to rebill all wholesale transmission customers retroactively to March 2010 within 30 days of when the proceeding becomes final and no longer subject to rehearing. In November 2017, Virginia Power,
North Carolina Electric Membership Corporation and the wholesale transmission customers filed petitions for rehearing. In July 2018, FERC denied the rehearing requests related to the October 2017 order determining the calculation of the undergrounding costs. Several parties have appealed FERC’s decision to the U.S. Court of Appeals for the D.C. Circuit. In December 2019, the U.S. Court of Appeals for the D.C. Circuit denied the appeal.
In January 2019, FERC issued an order denying PJM’s request to waive certain provisions of the PJM Tariff regarding the liquidation of a portfolio of FTRs owned by GreenHat who had defaulted on its financial obligations. As a result of FERC’s order, PJM is required to use the existing tariff provisions to liquidate GreenHat’s FTR portfolio and allocate the resulting costs to PJM members. In February 2019, PJM filed a request for clarification and rehearing with FERC. Also in February 2019, Virginia Power and certain other PJM members filed a request for rehearing with FERC. In June 2019, FERC established a hearing and settlement proceedings to address the issues raised in PJM’s request for clarification and rehearing. In October 2019, PJM submitted a settlement offer to FERC which was approved by FERC in December 2019. Based on the terms of the settlement, the impact to Virginia Power is expected to be immaterial.
In July 2017, FERC audit staff communicated to DETI that it had substantially completed an audit of DETI’s compliance with the accounting and reporting requirements of FERC’s Uniform System of Accounts and provided a description of matters and preliminary recommendations. In November 2017, the FERC audit staff issued its audit report which could have the potential to result in adjustments which could be material to Dominion Energy and Dominion Energy Gas’ results of operations. In December 2017, DETI provided its response to the audit report. DETI requested FERC review of contested findings and submitted its plan for compliance with the uncontested portions of the report. In connection with one uncontested issue, DETI recognized a charge of $15 million ($9 millionafter-tax)
recorded within impairment of assets and related charges in Dominion Energy and Dominion Energy Gas’ Consolidated Statements of Income(reflected in the Corporate and Other segment)
during 2017 towrite-off
the balance of a regulatory asset, originally established in 2008, that is no longer considered probable of recovery. DETI recognized a charge of $129 million ($94 millionafter-tax)
recorded primarily within impairment of assets and related charges in Dominion Energy and Dominion Energy Gas’ Consolidated Statements of Income(reflected in the Corporate and Other segment)
during 2018 for a disallowance of plant, originally established beginning in 2012, for the resolution of one matter with FERC. Pending final resolution of the audit process and a determination by FERC, management is unable to estimate the potential impact of the remaining finding and no amounts have been recognized.Subsequent to the enactment of the 2017 Tax Reform Act, the Companies’ state regulators issued orders requesting that public utilities evaluate the total tax impact on the entity’s cost of service and accrue a regulatory liability attributable to the benefits of the reduction in the corporate income tax rate. Certain of the orders requested that the public utilities submit a
response to the state regulatory commissions detailing the total tax impact on the utility’s cost of service.
The Companies began to reserve the impacts of thecost-of-service
reduction as regulatory liabilities in January 2018 and will continue until rates are reset pursuant to state regulators’ approvals. The Companies have recorded a reasonable estimate of net income taxes refundable through future rates in the jurisdictions in which they operate and are currently assessing these actions and decisions, which could have a material impact on the Companies’ results of operations, financial condition and/or cash flows.In September 2018, the Virginia Commission issued an order directing Virginia Power to submit a filing quantifying the impacts of the 2017 Tax Reform Act in advance of the April 1, 2019 implementation as required by legislation, which filing was submitted in October 2018. In January 2019, Virginia Power filed updated testimony with a proposed annual revenue reduction of approximately $171 million. Additionally, Virginia Power proposed to issue aone-time
bill credit to customers within 90 days of this effective date, totrue-up
the difference between the final revenue reduction for the period January 1, 2018 through March 31, 2019 and the $125 million interim rate reduction implemented on July 1, 2018. In March 2019, the Virginia Commission issued an order approving an annual revenue reduction of approximately $183 million effective April 2019 and ordered Virginia Power to implement theone-time
customer credit on or before July 1, 2019. In the second quarter of 2019, Virginia Power refunded to customers $132 million.In August 2018, Virginia Power filed with FERC to waive protocols and begin reflecting projected tax reform benefits of approximately $100 million through the transmission formula rate prior to the normal formula rate process. FERC granted the waiver and the amounts began being reflected in customer billings in November 2018 reflecting the adjustment effective January 1, 2018.
In October 2018, the North Carolina Commission issued an order requesting companies file to reduce base rates expeditiously. Virginia Power made its compliance filing in October 2018 and submitted an annual base rate revenue decrease of approximately $14 million effective in early 2019. Virginia Power also proposed to issue aone-time
bill credit in early 2019 for its 2018 tax savings collected provisionally from customers. In March 2019, the North Carolina Commission issued an order approving Virginia Power’s proposed annual base rate revenue decrease andone-time
bill credit. In the second quarter of 2019, Virginia Power refunded to customers $13 million.In March 2019, Questar Gas filed with the Utah and Wyoming Commissions as to the impact of excess deferred income taxes resulting from the 2017 Tax Reform Act. Questar Gas proposed to return the 2018 amortization of excess deferred income taxes to customers and to incorporate the remaining excess deferred income tax impact in its next general rate cases in each jurisdiction. In May 2019, the Utah Commission issued an order approving Questar Gas’ proposal to pass back the 2018 amortization of excess deferred income taxes over twelve months beginning in June 2019. The matter with the Wyoming Commission is pending.
In October 2018, the Ohio Commission issued an order requiring rate-regulated utilities to file an application reflecting the
impact of the 2017 Tax Reform Act on current rates by January 1, 2019. In December 2018, East Ohio filed its application proposing an approach to establishing rates and charges by and through which to return tax reform benefits to its customers. In December 2019, the Ohio Commission issued an order approving customer credits of approximately $600 million that will be shared with customers primarily over the remaining book life of the property to which the excess deferred income taxes relate. In addition, East Ohio will reduce rates approximately $19 million per year to account for the 2017 Tax Reform Act’s impact on its equity return component of rates charged to customers.
In connection with the SCANA Merger Approval Order, the South Carolina Commission approved DESC’s provision of approximately $100 million in bill credits related to the 2017 Tax Reform Act’s impact on retail electric customer rates for the period beginning January 2018 through January 2019. These credits have been included in bills rendered on and after the first billing cycle of February 2019. In addition, the South Carolina Commission approved a tax rider whereby the effects of the reduction in the corporate income tax rate resulting from the 2017 Tax Reform Act will benefit retail electric customers. This tax rider reduced base rates to retail electric customers by approximately $63 million in 2019 and is expected to reduce these rates by $67 million in 2020.
In October 2018, the South Carolina Commission issued an order approving adjustment to DESC’s natural gas rate schedules, under the terms of the Natural Gas Rate Stabilization Act, to reflect the reduction in the federal corporate tax rate arising from the 2017 Tax Reform Act. The approved natural gas rate schedules also included a tax reform rate rider to refund certain income tax amounts previously collected from customers. These lower rates, representing a $20 million decreased revenue requirement, became effective for bills rendered on and after the first billing cycle in November 2018.
In December 2018, the North Carolina Commission issued an order approving PSNC’s proposed adjustments to customer rates, representing a $13 million decreased revenue requirement, to reflect the reduction in the federal corporate tax rate arising from the 2017 Tax Reform Act. These lower rates became effective for service rendered on and after January 1, 2019. Amounts collected in customer rates during 2018 and amounts arising from excess deferred income taxes have been recorded in regulatory liabilities and must be considered in PSNC’s next general rate case proceeding or in three years, whichever is sooner. The reduction in the federal corporate tax rate and its impact on PSNC’s various rate riders will be addressed in future proceedings related to those riders.
During 2018, Dominion Energy’s FERC-regulated pipelines, including those accounted for as equity method investments, filed the Form501-G
with FERC. Dominion Energy Overthrust Pipeline, LLC, White River Hub, Dominion Energy Questar Pipeline, DETI, DECG, Cove Point and Iroquois have reached resolution through a FERC waiver or FERC terminating the501-G
proceeding, or through settlement, which did not result in a material impact to results of operations, financial condition and/or cash flows of Dominion Energy or Dominion Energy Gas.
Combined Notes to Consolidated Financial Statements, Continued
Virginia Regulation Regulation Act and Grid Transformation and Security Act of 2018 The Regulation Act enacted in 2007 instituted a cost-of-service rate model, ending Virginia’s planned transition to retail competition for electric supply service to most classes of customers. The Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, FERC-approved transmission costs, underground distribution lines, environmental compliance, conservation and energy efficiency programs, renewable energy programs and nuclear license renewals, and also contains statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission. 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. Grid Transformation and Security Act of 2018
In March 2018, theThe 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 successive 12-month
test 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.Triennial Review. In the triennial review proceedings, earnings that are more than 70 basis points above the utility’s authorized ROE that might have been refunded to customers and served as the basis for a reduction in future rates, may be reduced by Virginia Commission-
approvedCommission-approved investment amounts in qualifying solar or wind generation facilities or electric distribution grid transformation projects that Virginia Power elects to include in a customer credit reinvestment offset.CCRO. The legislation declares that electric distribution grid transformation projects are in the public interest and provides that the costs of such projects may be recovered through a rate adjustment clause if not the subject of a customer credit reinvestment offset.CCRO. Any costs that are the subject of a customer credit reinvestment offset may not beCCRO are deemed recovered in base rates forduring the service life of the projectstriennial period under review and may not be included in base rates in future triennial review proceedings. In any triennial review in which the Virginia Commission determines that the utility’s earnings are more than 70 basis points above its authorized ROE, base rates are subject to reduction prospectively and customer refunds would be due unless the total customer credit reinvestment offsetCCRO elected by the utility equals or exceeds the amount of earnings in excess of the 70 basis points. For the purposes of measuring any customer refunds or CCRO amounts utilized under the GTSA, associated income taxes are factored into the determination of such amounts. In the 2021 review,Triennial Review, any such rate reduction iswas limited to $50 million. Virginia 2020 Legislation In April 2020, the Governor of Virginia signed into law the VCEA, which along with related legislation forms a comprehensive framework affecting Virginia Power’s operations. The VCEA replaces Virginia’s voluntary renewable energy portfolio standard for
Virginia Power with a mandatory program setting annual renewable energy portfolio standard requirements based on the percentage of total electric energy sold by Virginia Power, excluding existing nuclear generation and certain new carbon-free resources, reaching 100% by the end of 2045. The VCEA includes related requirements concerning deployment of wind, solar and energy storage resources, as well as provides for certain measures to increase net-metering, including an allocation for low-income customers, incentivizes energy efficiency programs and directs Virginia to participate in a carbon trading program. While the legislation affects several portions of Virginia Power’s operations, key provisions of the GTSA remain in effect, including the triennial review structure and timing, the use of the CCRO and the $50 million cap on revenue reductions in the first triennial review proceeding. Key provisions of the VCEA and related legislation passed include the following: | • | FossilFuel Electric Generation: The legislation mandates Chesterfield Power Station Units 5 & 6 and Yorktown Power Station Unit 3 to be retired by the end of 2024, Altavista, Southampton and Hopewell to be retired by the end of 2028 and Virginia Power’s remaining fossil fuel units to be retired by the end of 2045, unless the retirement of such generating units will compromise grid reliability or security. The legislation also imposed a temporary moratorium on CPCNs for fossil fuel generation, unless the resources are needed for grid reliability. This temporary moratorium concluded in January 2022. In addition, the Virginia Commission shall determine the amortization period for recovery of any appropriate costs due to the early retirement of any electric generation facilities, which could result in the reversal of previous retirement costs deemed recovered during the review period ending 2020. As discussed in Note 2, Virginia Power had recorded charges for early retirement of certain coal- and oil-fired generating units in the first quarters of 2020 and 2019. Virginia Power also revised the depreciable lives of Altavista, Southampton and Hopewell for the mandated retirement to the end of 2028, which will not have a material impact to Virginia Power’s results of operations or cash flows given the existing regulatory framework. |
| • | Renewable Generation: The legislation provides a detailed renewable energy portfolio standard to achieve 100% zero-carbon generation by the end of 2045, excluding existing nuclear generation and certain new carbon-free resources. Components include requirements to petition the Virginia Commission for approval to construct or acquire new generating capacity to reach 16.1 GW of installed solar and onshore wind by the end of 2035, which includes specific requirements for utility-scale solar of 3.0 GW by the end of 2024, up to 15.0 GW by the end of 2035 and 1.1 GW of small-scale solar by the end of 2035. The legislation deems 2.7 GW of energy storage, including up to 800 MW for any one project which may include a pumped storage facility, by the end of 2035 to be in the public interest. The legislation also deems the construction or purchase of an offshore wind facility constructed off the Virginia coast with a capacity of up to 5.2 GW before 2035 to be in the public interest and provides certain presumptions facilitating cost recovery. The costs of such a facility constructed by the utility with a capacity between 2.5 and 3.0 GW will be presumed reasonably and prudently incurred if the Virginia Commission finds that the project meets competitive procurement requirements, the projected cost of the facility does not exceed a specified industry benchmark and the utility commences construction by the end of 2023 or has a plan for the facility to be in service by the end of 2027. Projects to meet these requirements are subject to approval by the Virginia Commission. |
| • | Energy Efficiency:The legislation includes an energy efficiency target of 5% energy savings, as measured from a 2019 baseline, through verifiable energy efficiency programs by the end of 2025 with future targets to be set by the Virginia Commission. Virginia Power has the opportunity to offset the lost revenues with margins on program spend if certain targets are achieved and can also seek recovery of the lost revenues associated with energy efficiency programs if such reductions are found to have caused Virginia Power to earn more than 50 basis points below a fair rate of return on its rates for generation and distribution services. |
| • | Carbon trading program: The legislation directs Virginia to participate in a market-based carbon trading program consistent with RGGI through 2050. In January 2022, the Governor of Virginia issued an executive order which puts directives in place to start the withdrawal of Virginia from RGGI. All costs of the carbon trading program are recoverable through an environmental rider. |
| • | Low-income customers: The legislation includes the establishment of a percentage of income payment program to be administered by the Virginia Department of Housing and Community Development and the Virginia Department of Social Services. To fund the program, Virginia Power will remit amounts collected from customers under a universal service fee established and set by the Virginia Commission. As such, this program will not affect Virginia Power’s results of operations, financial position or cash flows. In December 2020, the Virginia Commission issued a final order confirming a revenue requirement of $93 million related to this program. Implementation details and the effective date of the program will be established in future legislation prior to collection of fees from customers. |
Virginia Power is incurring and expects to incur significant costs, including capital expenditures, to comply with the legislative requirements discussed above. The legislation also includes provisions requiringallows for cost recovery under the existing or modified regulatory framework through rate adjustment clauses, rates for generation and distribution services or Virginia Power’s fuel factor, as approved by the Virginia Commission. Costs allocated to the North Carolina jurisdiction will be recovered, subject to approval by the North Carolina Commission, in accordance with the existing regulatory framework. 2021 Triennial Review In March 2021, Virginia Power to provide current customers one-time
filed its base rate credits totaling $200 millioncase and to reduceaccompanying schedules in support of the 2021 Triennial Review. In its filing, Virginia Power did not request an increase in base rates for generation and distribution services and proposed that base rates remain at their existing level. Virginia Power’s earnings test analysis, as filed, demonstrated it earned a combined ROE of 10.85% on
its generation and distribution services for the test period, before accounting for forgiven customer balances. Pursuant to Virginia legislation, forgiven customer balances were excluded from the cost of service in determining test period revenues as part of the 2021 Triennial Review. To the extent that the Virginia Commission determined total earnings for the test period to be above Virginia Power’s authorized earnings band, the forgiven balance amounts are offset against the available revenues in the determination of any customer bill credits, or utilization of a CCRO. Test period earnings may be further reduced by Virginia Commission approved investment amounts in qualifying solar or wind generation facilities or electric distribution grid transformation projects that Virginia Power elects to include as a CCRO under the GTSA. In its filing, Virginia Power elected to utilize $26 million of the CVOW Pilot Project investment as a CCRO to offset available revenues. Virginia Power had contingently elected to offset additional available revenues, if any, determined by the Virginia Commission for earnings sharing with additional Virginia Commission approved qualifying CCRO investments. The Virginia Commission also authorized an ROE for Virginia Power that is applied to Virginia Power’s riders prospectively and that was also utilized to measure base rate earnings as of January 1, 2021. Virginia Power had requested authorization of an ROE of 10.8% based on Virginia Power’s current cost of equity. Pursuant to the Regulation Act, Virginia Power’s authorized ROE shall not be set lower than the average of either (i) the returns reported for the three previous years by not less than a majority of comparable utilities in the Southeastern U.S., with certain limitations as described in the Regulation Act, or (ii) the authorized returns that are set by the applicable regulatory commissions for the same select peer group. In May 2021, Virginia Power filed supplemental testimony to reflect reductionsupdated test period earnings, including an earned ROE of 10.42%, before accounting for forgiven customer balances, and that no amount of eligible CCRO is necessary to be elected to be utilized. In 2020, Virginia Power recorded a net charge of $130 million related to the use of a CCRO in income tax expense resulting fromaccordance with the 2017 Tax Reform Act. AsGTSA, included in impairment of assets and other charges (benefits) in its Consolidated Statements of Income (reflected in the Corporate and Other segment) for benefits expected to be provided to jurisdictional customers as a result Virginia Power incurred a $215 million ($160 million after-tax)
charge in connection with this legislation, includingof the 2021 Triennial Review as well as the impact on certain non-jurisdictional customers which follow Virginia Power’s jurisdictional customer rate methodology. In July 2018 and January 2019,2021, Virginia Power credited $138recorded a benefit of $130 million ($97 million after-tax) in impairment of assets and $77 million, respectively,other charges (benefits) in its Consolidated Statements of Income (reflected in the Corporate and Other segment) to current customers’ bills.
In addition,adjust its reserve related to the use of a CCRO in accordance with the GTSA.Subsequently, in October 2021, Virginia Power, reduced base rates on an annual basis by $125 million effective July 2018, to reflect the estimated effect of the 2017 Tax Reform Act. In March 2019, the Virginia Commission directed an annual revenue reduction of $183 million in rates for generationstaff and distribution services pursuant to the GTSA effective April 2019. In July 2018, Virginia Powerother parties filed a petitioncomprehensive settlement agreement with the Virginia Commission for approvalapproval. The comprehensive settlement agreement provides for $330 million in one-time refunds to customers made up of the first$255 million over a 6-month period and $75 million over three years, a $50 million going-forward base rate reduction and an authorized ROE of itsten-year
plan for electric distribution grid transformation projects as authorized by the GTSA. During the first three years of the plan,9.35%. Additionally, Virginia Power proposedhas agreed to focus onutilize $309 million of qualifying CCRO investments in the following seven foundational componentsCVOW Pilot Project, deployment of AMI and a Customer Information Platform to offset available earnings and to amortize through 2023 the overall grid transformation plan: (i) smart meters; (ii) customer information platform; (iii) reliabilityearly retirement charges for coal- and resilience; (iv) telecommunications infrastructure; (v) cyberoil-fired generation units recorded in 2019 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.2020. In January 2019,November 2021, the Virginia Commission issuedapproved the comprehensive settlement agreement.In connection with the settlement agreement, Virginia Power recorded a $356 million ($265 million after-tax) charge for refunds to be provided to customers in operating revenues in its final order approving capital spendingConsolidated 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 three yearsquarter 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 record in the proceeding. In September 2019,2021 Virginia Power filedrecorded a revised plan which includes six components: (i) smart meters; (ii)charge of $76 million ($56 million after-tax) in impairment of assets and other charges (benefits) in its Consolidated Statements of Income for Virginia jurisdictional retail electric customer information platform; (iii) grid improvement projects; (iv) telecommunications infrastructure; (v) cyber security; and (vi) a smart charging electric vehicle infrastructure pilot program (Phase IB). For Phase IB, the total proposed capital investment during 2019 – 2021 is $503 million and the proposed operations and maintenance investment is $78 million. This matter is pending.
In March 2019,balances that were more than 30 days past due as of December 31, 2020 that Virginia Power filed an application foris required to forgive. For the Virginia Commission to determine the general ROE forpurposes of Virginia Power’snon-transmission
rate adjustment clauses and 2021 Triennial Review, these charges were excluded from Virginia Power’s cost of service for purposes of determining any test period earnings and determining any future rates. To the extent that the Virginia Commission determined total earnings for the test period were above Virginia Power’s base rateauthorized earnings band, the forgiven balance amounts were offset against the excess earnings in the determination of any customer bill credits, or utilization of a CCRO, as part of the 2021 quadrennial review for the four successive12-month
test periods beginning January 1, 2017 and ending December 31, 2020. The application supported a 10.75% ROE for these rate adjustment clauses and quadrennial review period. In November 2019, the Virginia Commission approved a 9.2% general ROE for Virginia Power.Triennial Review discussed above.Virginia Fuel Expenses In May 2019,2021, Virginia Power filed its annual fuel factor with the Virginia Commission to recover an estimated $1.5$1.4 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 20192021 and the projected$72 million of estimated net under-recovered balances through 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 to2021. In June 30, 2020. Subsequently in May 2019, Virginia Power revised its fuel factor filing to reduce the projected June 30, 2019
underrecovered balance to $107 million and a fuel revenue decrease of $254 million. In August 2019, the Virginia Commission approved Virginia Power’s fuel rate.
In February 2020, Virginia Power filed its annual fuel factor with the Virginia Commission to recover an estimated $1.2 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 2020 and a projected over-recovery of approximately $81 million for the prior year balance as of June 30, 2020. Virginia Power requested that the new fuel factor rate be implemented on an interim basis two months early, beginning on May 1, 2020. Virginia Power’s proposed fuel rate represents a fuel revenue decrease of approximately $393 million when applied to projected kilowatt-hour sales for the rate year beginning May 1, 2020. This matter is pending.
In August 2019, Virginia Power filed an application with the Virginia Commission to participate in a pilot program for electric power storage batteries, which includes three projects for deployment of battery energy storage systems. Virginia Power also requested an amended CPCN to construct and operate a battery energy storage system at Scott Solar. The projects are estimated to cost approximately $35 million.
In February 2020,2021, the Virginia Commission approved the request.annual fuel factor.GTSA Filing
In June 2021, Virginia Power filed a petition with the Virginia Commission for approval of a revised plan for electric distribution grid transformation projects as authorized by the GTSA. The plan includes 14 projects covering 6 components: (i) smart meters; (ii) customer information platform; (iii) grid improvement projects; (iv) physical and cyber security; (v) telecommunications infrastructure and (vi) customer education (Phase II). For Phase II, the total proposed capital investment during 2022 – 2023 is $667 million and the proposed operations and maintenance investment is $110 million. In January 2022, the Virginia Commission approved the petition. Renewable Generation Projects In May 2020 and July 2020, Virginia Power entered into and closed on separate agreements to acquire Grassfield Solar, Facility Projects Norge Solar and Sycamore Solar. The projects are expected to cost approximately $170 million in aggregate once constructed, including the initial acquisition cost. The facilities are expected to generate 82 MW combined and be placed into service in 2022. In July 2018,October 2020, Virginia Power filed an application with the Virginia Commission for CPCNs to construct 2 solar facilities. Colonial Trail West and Spring Grove 1 are estimated to cost approximately $410 million, 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-3
associated withoperate these projects with a proposed $10 million total revenue requirement foras part of its efforts to meet 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-year
performance guarantee of the facilities at a 25% solar capacity factor when normalized for force majeure events.renewable generation development requirements under VCEA. In April 2019,2021, the Virginia Commission approved RiderUS-3.
the application.In July 2019,September 2021, Virginia Power filed a petition with the Virginia Commission for CPCNs to construct and operate 13 utility-scale projects totaling approximately 661 MW of solar generation and 70 MW of energy storage as part of its efforts to meet the renewable generation development requirements under the VCEA. The projects are expected to cost approximately $1.4 billion in the aggregate, excluding financing costs, and be placed into service between 2022 and 2023. This matter is pending. In November 2021, Virginia Power filed an application with the Virginia Commission for a CPCN to construct Sadler Solar,requesting approval and certification of the Virginia Facilities component of the CVOW Commercial Project. The onshore Virginia Facilities have an estimated cost of approximately $1.1 billion, excluding financing costs, which is estimatedincluded within the overall cost of the CVOW Commercial Project. In addition, Virginia Power requested approval from the Virginia Commission to cost approximately $146 million, excluding financing costs. Sadler Solar is expectedenter into financial hedges with U.S. financial institutions to commence commercial operations, subject to regulatory approvalsmitigate the foreign currency exchange risk associated with certain supplier contracts associated with the project, in the fourth quarter of 2020. Virginia Power also applied for approval of Rider US-4
associated with this project with a proposed $9 million total revenue requirement for the rate year beginning June 1, 2020. In January 2020, the Virginia Commission issued a final order granting the CPCN to construct Sadler Solar, subject to a20-
year performance guarantee of the facility at a 22% solar capacity factor when normalized for force majeure events.CVOW Commercial Project. This matter regarding RiderUS-4
is pending. Below is a discussion of significant riders associated with various Virginia Power projects:
The Virginia Commission previously approved Rider T1 concerning transmission rates. In May 2019, Virginia Power
proposed a $920 million total revenue requirement consisting of $474 million for the transmission component of Virginia Power’s base rates and $446 million for Rider T1 for the rate year beginning September 1, 2019. This total revenue requirement represents a $271 million increase versus the revenues to be produced during the rate year under current rates. In July 2019, the Virginia Commission approved the filing.
The Virginia Commission previously approved Rider U in conjunction with cost recovery to move certain electric distribution facilities underground as authorized by Virginia legislation. Nuclear Life Extension Program In October 2019, the Virginia Commission approved Virginia Power’s proposed fourth phase of conversions totaling $123 million and a total $52 million revenue requirement for the rate year beginning February 1, 2020 for continuing recovery of the previously approved phase conversions and the proposed fourth phase conversions. The Virginia Commission previously approved Riders C1A, C2A and C3A in connection with cost recovery for DSM programs. In December 2019,2021, Virginia Power filed a petition to approve an additional 10 new energy efficiency programs and 1 new demand response DSM program for five years, subject to future extension, with a $186 million cost cap, and proposed a total $60 million revenue requirement for the rate year beginning September 1, 2020. This total revenue requirement represents an $11 million increase over the previous year.
In December 2018, Virginia Power filed a petition requesting approval of Rider E and proposed a $114 million total revenue requirement for the rate year beginning November 1, 2019. In August 2019, the Virginia Commission issued an order approving in partrequesting a determination that it is reasonable and denying in part the petition. As a result,prudent for Virginia Power recordedto pursue a $21 million ($16 millionafter-tax)
charge in impairmentnuclear life extension program to extend the operating licenses of assetsSurry and other charges in the Consolidated Statements of Income for the threeNorth Anna and nine months ended September 30, 2019 to write-off
certain disallowed environmental property, plant carry out projects to upgrade or replace systems and equipment necessary to continue to safely 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 requestreliably operate these nuclear power stations. The nuclear life extension program is expected to implement a total revenue requirement of $104 million on an interim basis, subject tocost approximately $3.9 billion, excluding financing costs. This matter is pending.true-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.AdditionalRiders The significant riders associated with various Virginia Power projects are as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total
Revenue
Requirement
(millions) | | | Increase
(Decrease)
Over
Previous
Year
(millions) | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | ) |
Rider Name | | Application Date | | Approval Date | | Rate Year Beginning | | Total Revenue Requirement (millions) | | Increase (Decrease) Over Previous Year (millions) | | Rider B | | June 2020 | | February 2021 | | April 2021 | | 24 | | | (8 | ) | Rider B | | June 2021 | | February 2022 | | April 2022 | | 16 | | | (8 | ) | Rider BW | | October 2020 | | July 2021 | | September 2021 | | 113 | | | 14 | | Rider BW | | October 2021 | | Pending | | September 2022 | | 145 | | | 32 | | Rider BW | | October 2021 | | Pending | | September 2023 | | 120 | | | (25 | ) | Rider CCR | | February 2021 | | October 2021 | | December 2021 | | 216 | | N/A | | Rider CE(1) | | October 2020 | | April 2021 | | June 2021 | | 10 | | N/A | | Rider CE(2) | | September 2021 | | Pending | | May 2022 | | 71 | | | 61 | | Rider E | | January 2021 | | September 2021 | | November 2021 | | 67 | | | (18 | ) | Rider E | | January 2022 | | Pending | | November 2022 | | 101 | | | 34 | | Rider GT | | August 2021 | | Pending | | June 2022 | | 56 | | N/A | | Rider GV | | June 2020 | | February 2021 | | April 2021 | | 153 | | | 21 | | Rider GV | | June 2021 | | December 2021 | | April 2022 | | 142 | | | (11 | ) | Rider GV | | June 2021 | | December 2021 | | April 2023 | | 127 | | | (15 | ) | Rider OSW | | November 2021 | | Pending | | September 2022 | | 79 | | N/A | | Rider R | | June 2020 | | February 2021 | | April 2021 | | 58 | | | 14 | | Rider R | | June 2021 | | Pending | | April 2022 | | 59 | | | 1 | | Rider R | | June 2021 | | Pending | | April 2023 | | 55 | | | (4 | ) | Rider RGGI(3) | | December 2020 | | August 2021 | | September 2021 | | 168 | | N/A | | Rider RGGI(4) | | December 2021 | | Withdrawal pending | | | | | | | | | Rider RPS | | December 2020 | | July 2021 | | August 2021 | | 13 | | N/A | | Rider RPS | | December 2021 | | Pending | | September 2022 | | 140 | | | 127 | | Rider S | | June 2020 | | February 2021 | | April 2021 | | 194 | | | (1 | ) | Rider S | | June 2021 | | February 2022 | | April 2022 | | 192 | | | (2 | ) | Rider S | | June 2021 | | February 2022 | | April 2023 | | 191 | | | (1 | ) | Rider SNA(5) | | October 2021 | | Pending | | September 2022 | | 109 | | N/A | | Rider T1(6) | | May 2021 | | August 2021 | | September 2021 | | 874 | | | (190 | ) | Rider U(7) | | June 2020 | | February 2021 | | April 2021 | | 80 | | | 28 | | Rider U(8) | | June 2021 | | Pending | | April 2022 | | 96 | | | 16 | | Rider US-2 | | October 2020 | | July 2021 | | September 2021 | | 9 | | | — | | Rider US-2 | | October 2021 | | Pending | | September 2022 | | 11 | | | 2 | | Rider US-3 | | July 2020 | | March 2021 | | June 2021 | | 38 | | | 10 | | Rider US-3 | | August 2021 | | Pending | | June 2022 | | 50 | | | 12 | | Rider US-4 | | July 2020 | | March 2021 | | June 2021 | | 10 | | | 3 | | Rider US-4 | | August 2021 | | Pending | | June 2022 | | 15 | | | 5 | | Rider W | | June 2020 | | February 2021 | | April 2021 | | 120 | | | 14 | | Rider W | | June 2021 | | February 2022 | | April 2022 | | 121 | | | 1 | | DSM Riders(9) | | December 2020 | | September 2021 | | October 2021 | | 74 | | | 14 | | DSM Riders(10) | | December 2021 | | Pending | | September 2022 | | 91 | | | 17 | |
(1) | | | | | | | | | | | | | | | Associated with Grassfield Solar, Norge Solar and Sycamore Solar. |
(2) | Associated with solar generation and energy storage projects requested for approval in September 2021, solar generation projects approved in April 2021 and certain small-scale solar projects. |
(3) | In August 2021, the Virginia Commission issued an order granting reconsideration and suspended its order approving the revenue requirement. In November 2021, the Virginia Commission lifted the suspension of the order. In February 2022, a party filed an appeal to the Supreme Court of Virginia challenging the Virginia Commission’s order. |
(4) | In January 2022, Virginia Power filed a motion to withdraw its application as a result of the announcement by the Governor of Virginia that he intends to withdraw Virginia from RGGI. Virginia Power expects to file an updated application to recover its actual and projected RGGI compliance costs informed by these developments at the appropriate time. |
(5) | Virginia Power also requested approval of cost recovery of approximately $1.2 billion through Rider SNA for the first phase of nuclear life extension program which includes investments through 2024. |
(6) | Consists of $493 million for the transmission component of Virginia Power’s base rates and $381 million for Rider T1. |
(7) | Consists of $44 million for previously approved phases and $36 million for phase five costs for Rider U. |
(8) | Consists of $61 million for previously approved phases and $35 million for phase six costs for Rider U. |
(9) | Associated with an additional 10 new energy efficiency programs and 1 new demand response DSM program for five years, subject to future extension, with a $162 million cost cap. |
(10) | Associated with an additional 9 new energy efficiency programs with a $140 million cost cap, with the ability to exceed the cost cap by no more than 15%. |
Combined Notes to Consolidated Financial Statements, Continued
Coastal Virginia Offshore Wind Project
In November 2018,Electric Transmission Projects Significant Virginia Power received approval from the Virginia Commissionelectric transmission projects approved or applied for its petition seeking a prudency determinationare as provided in the GTSA with respect to the proposed Coastal Virginia Offshore Wind Pilot project consisting of two 6follows: Description and Location of Project | | Application Date | | Approval Date | | Type of Line | | Miles of Lines | | Cost Estimate (millions) | Bristers-Ladysmith Rebuild Project in the Counties of Fauquier, Stafford, Spotsylvania and Caroline, Virginia | | May 2020 | | February 2021 | | 500 kV | | 37 | | 110 | Relocate and replace a transmission line underground between the Tysons substation and the future Spring Hill substation | | September 2020 | | June 2021 | | 230 kV | | < 1 | | 30 | Rebuild an existing transmission line and install new line adjacent thereto in the Counties of New Kent, King William, King and Queen, Essex and Richmond, Virginia | | October 2020 | | December 2021 | | 230 kV | | 41 | | 100 | Rebuild Clubhouse-Dry Bread Line and Dry Bread-Lakeview Line in Greensville County, Virginia | | November 2020 | | July 2021 | | 230 kV | | 13 | | 20 | Rebuild transmission lines and related projects in the Counties of York and James City and the City of Williamsburg, Virginia | | January 2021 | | September 2021 | | 230 kV | | 11 | | 30 | Elmont-Ladysmith rebuild and related projects in the Counties of Hanover and Caroline, Virginia | | April 2021 | | Pending | | 500 kV | | 26 | | 95 | Beaumeade-Belmont reconductor and rebuild projects in the County of Loudoun, Virginia | | May 2021 | | February 2022 | | 230 kV | | 7 | | 15 | Extension to Cloud Switching Station and Easters Switching Station in the County of Mecklenburg, Virginia | | June 2021 | | February 2022 | | 230 kV | | 15 | | 105 | Rebuild transmission lines and related projects in the City of Staunton and County of Augusta, Virginia | | November 2021 | | Pending | | 230 kV | | 21 | | 45 | Build new DTC substation and line loop in the County of Loudoun, Virginia | | December 2021 | | Pending | | 230 kV | | 1 | | 105 | Build new Aviator substation and line loop in the County of Loudoun, Virginia | | February 2022 | | Pending | | 230 kV | | 1 | | 80 |
MW wind turbine generators located approximately 27 miles off the coast of Virginia Beach, Virginia in federal waters, and for a CPCN, for the generation tie line connecting the generators to shore. This project is expected to cost approximately $300 million and to be placed into service by the end of 2020.
Electric Transmission Projects
In November 2013, the Virginia Commission issued an order granting Virginia Power a CPCN to construct approximately 7 miles of new overhead 500 kV transmission line from the existing Surry switching station in Surry County to a new Skiffes Creek switching station in James City County, and approximately 20 miles of new 230 kV transmission line in James City County, York County, and the City of Newport News from the proposed new Skiffes Creek switching station to Virginia Power’s existing Whealton substation in the City of Hampton. In February 2019, the transmission line project was placed into service. In March 2019, the U.S. Court of Appeals for the D.C. Circuit issued an order vacating the permit from the U.S. Army Corps of Engineers issued in July 2017 and ordered the U.S. Army Corps of Engineers to do a full environmental impact study of the project. In April 2019, Virginia Power and the U.S. Army Corps of Engineers filed petitions for rehearing with the U.S. Court of Appeals for the D.C. Circuit, asking that the permit from the U.S. Army Corps of Engineers remain in effect while an environmental impact study is performed. In May 2019, the U.S. Court of Appeals for the D.C. Circuit denied the request for rehearing and ordered the U.S. District Court for the D.C. Circuit to consider and issue a ruling on whether the permit should be vacated during the U.S. Army Corps of Engineers’ preparation of an environmental impact statement. In November 2019, the U.S. District Court for the D.C. Circuit issued an order allowing the permit to remain in effect while an environmental impact studystatement is performed.prepared. In November 2020, the U.S. Army Corps of Engineers issued a draft environmental impact statement noting there is no better alternative. This matter is pending.
Additional significant Virginia Power electric transmission projects approvedor
applied for are as follows:| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Rebuild and operate transmission line between Lanexa and the Northern Neck
in Virginia | | | | | | | | | | | | | | | | | | | | | Build a new substation and connect three existing
transmission lines thereto in Fluvanna County, Virginia | | | | | | | | | | | | | | | | | | | | | Rebuild and operate the Glebe
substation and relocate and operate in Arlington County, Virginia and the City
of Alexandria, Virginia existing overhead line
underground | | | | | | | | | | | | | | | | | | | | | Rebuild and operate transmission line between Valley, Virginia and
Mt. Storm, West Virginia | | | | | | | | | | | | | | | | | | | | | Rebuild and operate transmission line between the Suffolk substation and
the Virginia/North Carolina state line | | | | | | | | | | | | | | | 11 | | | | | | Rebuild and operate five segments between the Loudoun
and Ox substations | | | | | | | | | | | | | | | | | | | | | Build new Evergreen Mills switching station and line loops in Loudoun County,
Virginia | | | | | | | | | | | | | | | | | | | | | Build new Lockridge substation and line loop in Loudoun County, Virginia | | | | | | | | | | | | | | | | | | | | |
North Carolina Regulation Virginia Power North Carolina Base Rate Case In March 2019, Virginia Power filed its base rate case and schedules with the North Carolina Commission. Virginia Power proposed a non-fuel, base rate increase of $27 million effective November 1, 2019 on an interim basis subject to refund, with any permanent rates ordered by the North Carolina Commission effective January 1, 2020. The base rate increase was proposed to recover the significant investments in generation, transmission and distribution infrastructure for the benefit of North Carolina customers. Virginia Power presented an earned return of 7.52% based upon a fully-adjusted test period, compared to its authorized 9.90% return, and proposed a 10.75% ROE. In September 2019, Virginia Power revised its filing to reduce the non-fuel base rate increase to $24 million. In January 2020, the North Carolina Commission approved a 9.75% ROE and disallowed certain costs associated with coal ash remediation at Chesterfield power station. In February 2020, the North Carolina Commission issued its final order relating to base rates. In July 2020, Virginia Power filed a notice of appeal and exceptions to the Supreme Court of North Carolina, arguing that the North Carolina Commission committed reversible error on certain issues relating to the ratemaking treatment of certain coal ash remediation costs. This matter is reviewing the order and assessing its options. pending.Virginia Power North Carolina Fuel Filing In August 2019,2021, Virginia Power submitted its annual filing to the North Carolina Commission to adjust the fuel component of its electric rates. Virginia Power updated its filing in October 2021 to reflect the increased commodity cost of fuel and proposed a total $18$26 million decreaseincrease to the fuel component of its electric rates for the rate year beginning February 1, 2020.2022. In January 2020,2022, the North Carolina Commission approved Virginia Power’sthe filing. PSNC Base Rate Case In April 2021, PSNC filed its general rate case application and schedules with the North Carolina Commission. PSNC proposed fuel change adjustment.a non-fuel, base rate increase of $53 million to be effective November 1, 2021. After considering the benefits of the 2017 Tax Reform Act, the net revenue increase to customers would be approximately $42 million. The base rate increase was proposed to recover the significant investment in infrastructure to serve a growing customer base, improve safety and reliability of the transmission and distribution system and enhance energy efficiency and sustainability. The proposed rates would provide for an ROE of 10.25% compared to the currently authorized ROE of 9.7%. In October 2021, PSNC, the North Carolina Commission public staff and certain other parties of record filed a stipulation of settlement with the North Carolina Commission for approval. The stipulation of settlement provides for a non-fuel, base rate increase of $29 million effective November 1, 2021, based on an ROE of 9.60%. The net revenue increase to customers, after considering the amortization of the previously deferred benefits of the 2017 Tax Reform Act, would be $4 million in the initial rate year, $23 million for the following rate year and then $26 million beginning for the third through fifth rate years. In addition, the stipulation of settlement provides for the recovery, over four years, of $106 million of operation and maintenance costs which PSNC has incurred and deferred through June 2021 to comply with federal standards for pipeline integrity and safety. In November 2021, PSNC implemented temporary rates consistent with the stipulation of settlement. In December 2021, a revised stipulation of settlement was filed with the North Carolina Commission adjusting the net revenue increase to customers, after considering the amortization of the previously deferred benefits of the 2017 Tax Reform Act, to $6 million in the initial rate year, $25 million for the following rate year and $27 million beginning for the third through fifth rate years. In January 2022, the North Carolina Commission approved the revised stipulation of settlement without modification and issued its final order. Pipeline Integrity and Safety Program The North Carolina Commission has authorized PSNC to use a tracker mechanism to recover the incurred capital investment and associated costs of complying with federal standards for pipeline integrity and safety requirements that are not in current base rates. In August 2021, the North Carolina Commission approved PSNC’s request to increase the integrity management annual revenue requirement to $34 million, an increase of $1 million over its previous filing, effective September 2021. Rider D Rider D allows PSNC to recover from customers all prudently incurred gas costs and certain related uncollectible expenses as well as losses on negotiated gas and transportation sales. In September 2021, PSNC submitted a filing with the North Carolina Commission for a $61 million gas cost increase. The North Carolina Commission approved the filing in September 2021 with rates effective October 2021. In November 2021, PSNC submitted a filing with the North Carolina Commission for a $49 million gas cost increase and a $15 million increase in the customers deferred account. The North Carolina Commission approved the filing in December 2021 with rates effective December 2021.
South Carolina Regulation South Carolina Electric Base Rate Case In August 2020, DESC filed its retail electric base rate case and schedules with the South Carolina Commission. DESC proposed a non-fuel, base rate increase of $178 million, or 7.75%, based on an adjusted test year data, effective on or after the first billing cycle of March 2021. The base rate increase was proposed to recover the significant investment in assets and operating resources required to serve an expanding customer base, maintain the safety, reliability and efficiency of DESC’s system and meet increasingly stringent reliability, security and environmental requirements for the benefit of South Carolina customers. DESC presented an earned ROE of 5.90% based upon a fully-adjusted test period. The proposed rates would provide for an earned ROE equal to the current authorized earned ROE of 10.25% established in the previous rate case in 2012. In January 2021, the South Carolina Commission approved a proposal made by the South Carolina Office of Regulatory Staff, and agreed to by DESC and other intervenors, to stay the base rate case due to the current economic conditions and to allow the parties more time to negotiate a settlement with a final order to be issued no later than August 2021. In July 2021, DESC, the South Carolina Office of Regulatory Staff and other parties of record filed a comprehensive settlement agreement with the South Carolina Commission for approval. The comprehensive settlement agreement provides for a non-fuel, base rate increase of $62 million (resulting in a net increase of $36 million after considering an accelerated amortization of certain excess deferred income taxes) commencing with bills issued on September 1, 2021 and an authorized earned ROE of 9.50%. Additionally, DESC has agreed to commit up to $15 million to forgive retail electric customer balances that were more than 60 days past due as of May 31, 2021 and provide $15 million for energy efficiency upgrades and critical health and safety repairs to customer homes. Pursuant to the comprehensive settlement agreement, DESC would not file a retail electric base rate case prior to July 1, 2023, such that new rates would not be effective prior to January 1, 2024, absent unforeseen extraordinary economic or financial conditions that may include changes in corporate tax rates. In July 2021, the South Carolina Commission approved the comprehensive settlement agreement and issued its final order in August 2021. In connection with this matter, Dominion Energy recorded charges of $249 million ($187 million after-tax) reflected within impairment of assets and other charges (benefits) (reflected in the Corporate and Other segment), including $237 million of regulatory assets associated with DESC’s purchases of its first mortgage bonds during 2019 that are no longer probable of recovery under the settlement agreement, and $18 million ($14 million after-tax) reflected within other income in its Consolidated Statements of Income for the year ended December 31, 2021. DSM Programs DESC has approval for a DSM rider through which it recovers expenditures related to its DSM programs. programs In January 2019,2021, DESC filed an application with the South Carolina Commission seeking approval to recover $30$48 million of costs and net lost revenues associated with these programs, along with an incentive to invest in such programs. In April 2019,2021, the South Carolina Commission approved the request for the rate year beginningfiling. In connection with the first billing cycleapproval of May 2019.
the comprehensive settlement agreement in the South Carolina base rate case discussed above, the net lost revenue component of the DSM rider was adjusted resulting in a recovery of $43 million commencing with bills issued on September 1, 2021.In January 2020,2022, DESC filed an application with the South Carolina Commission seeking approval to recover $40$60 million of costs and net lost revenues associated with these programs, along with an incentive to invest in such programs. This matter is pending. Natural Gas Rate Stabilization Act RatesIn June 2019,2021, DESC filed with the South Carolina Commission its monitoring report for the 12-month period ended March 31, 20192021 with a total revenue requirement of $437$426 million. This represents a $7$9 million overall annual increase to its natural gas rates under the terms of the Natural Gas Rate Stabilization Act effective forwith the rate year beginningfirst billing cycle of November 2019.2021. In October 2019,2021, the South Carolina Commission approvedissued an order approving a total revenue requirement of $436$424 million effective with the first billing cycle of November 2019. 2021. This represents a $7 million overall annual increase to DESC’s natural gas rates.Cost of Fuel DESC’s retail electric rates include a cost of fuel component approved by the South Carolina Commission which may be adjusted periodically to reflect changes in the price of fuel purchased by DESC. In 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-month
period 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 2020,2021, DESC filed a proposal
with the South Carolina Commission a proposal to decreaseincrease the total fuel cost component of retail electric rates. DESC’s proposed decreaseadjustment would reduceincrease annual base fuel component recoveries by approximately $44$36 million and is projecteddesigned to return to customers the existing over-collected balance while recoveringrecover DESC’s current base fuel costs, net of the existing over-collected balance, over the 12-month period beginning with the first billing cycle of May 2020.2021. In addition, DESC proposed a decrease to its variable environmental component and an increase to its distributed energy resource component. In April 2021, the South Carolina Commission approved the filing.
In February 2022, DESC filed with the South Carolina Commission a proposal to increase the total fuel cost component of retail electric rates. DESC’s proposed adjustment is designed to recover DESC’s current base fuel costs, including its existing under-collected balance, over the 12-month period beginning with the first billing cycle of May 2022. DESC also proposed to apply approximately $66 million representing the net balance of funds associated with the monetization of the bankruptcy settlement with Toshiba Corporation following the satisfaction of liens against NND Project property recorded in regulatory liabilities, as a reduction to its under-collected base fuel cost balance. In addition, DESC proposed an increase to its variable environmental and distributed energy resource components. This matteravoided capacity cost component. The net effect is pending. Electric Transmission Projects
In 2020, DESC expects to begin several electric transmission projects in connection with two new nuclear plants under development by Southern. These transmission projects are required to be in place prior to these plants beginning operations to maintain reliability. DESC anticipates the projects to go into service in phases, costing approximately $75 million in aggregate. In February 2020, DESC filed an application with the South Carolina Commission requesting approval to construct and operate 28 milesa proposed annual increase of 230 kV transmission lines in Aiken County, South Carolina estimated to cost approximately $30$143 million. This matter is pending.
In 2008, East Ohio began PIR, aimed at replacing approximately 25% of its pipeline system. In September 2016, the Ohio Commission approved a stipulation filed jointly by East Ohio and the Staff of the Ohio Commission to continue the PIR program and associated cost recovery for another five-year term, calendar years 2017 through 2021, and to permit East Ohio to increase its annual capital expenditures to $200 million by 2018 and 3% per year thereafter subject to the cost recovery rate increase caps proposed by East Ohio. In December 2020, East Ohio filed an application with the Ohio Commission requesting approval to extend the PIR program for an additional five years upon expiration of the current authorization at the end of 2021. East Ohio proposed continued capital investment increases of 3% per year, with related increases in the annual rate-increase caps. In its application, East Ohio proposed that the new five-year period should include investment through December 31, 2026. This case is pending. In April 2019,2021, the Ohio Commission approved East Ohio’s application to adjust the PIR cost recovery rates for 20182020 costs. The filing reflects gross plant investment for 20182020 of $202$178 million, cumulative gross plant investment of $1.6$2.0 billion and a revenue requirement of $190$243 million. In 2011, East Ohio began CEP which enables East Ohio to defer depreciation expense, property tax expense and carrying costs at the debt rate of 6.5% on capital investments not covered by its PIR program to expand, upgrade or replace its pipeline systeminfrastructure and information technology systems as well as investments necessary to comply with the Ohio Commission or other government regulation. In May 2019,April 2021, East Ohio filed an application requesting approval to adjust the CEP cost recovery rates for an alternative rate plan to establish a CEP rider to recover existing CEP-related
deferrals2019 and to establish an ongoing recovery mechanism for future deferrals.2020 costs. The filing reflects gross plant investment for 2019 of $137 million, gross plant investment for 2020 of $99 million, cumulative gross plant investment of $723$957 million through 2018 and a revenue requirement of $83$119 million. This matter is pending. UEX Rider East Ohio has approval for a UEX Rider through which it recovers the bad debt expense of most customers not participating in the PIPP Plus Program. The UEX Rider is adjusted annually to achieve dollar for dollar recovery of East Ohio’s actual write-offs of uncollectible amounts. In July 2021, the Ohio Commission approved East Ohio’s application to adjust its UEX Rider to reflect an increased annual revenue requirement of $20 million to provide for an under-recovered accumulated bad debt expense of $7 million as of March 31, 2021, and recovery of net bad debt expense projected to total $13 million for the twelve-month period ending March 2022. West Virginia Regulation West Virginia Base Rate Case In May 2019,September 2020, Hope filed its base rate case and schedules with the West Virginia Commission. Hope proposed a non-fuel, base rate increase of $28 million. The base rate increase was proposed to recover the significant investment in distribution infrastructure and costs associated with the acquisition of over 2,000 miles of gathering assets, both for the benefit of West Virginia customers. The proposed rates would provide for an ROE of 10.25% compared to the authorized ROE of 9.45%. In July 2021, the West Virginia Commission approved a non-fuel, base rate increase of $13 million for rates effective July 2021 with an ROE of 9.54%. In August 2021, Hope filed a PREP applicationpetition for reconsideration with the West Virginia Commission requestingregarding certain return calculations included in the July 2021 approval order. This matter is pending. PREP In October 2021, the West Virginia Commission approved Hope’s request to recover PREP costs related to $29$54 million and $39$56 million of projected capital investment for 20192021 and 2020,2022, respectively. The applicationrequest also includes a true-up of PREP costs related to the 20182020 actual capital investment of $30$34 million and sets forth $10$9 million of annual PREP costs to be recovered in proposed rates effective November 1, 2019. 2021.
Utah Regulation Purchased Gas In October 2019, the West Virginia Commission approved PREP rates effective November 1, 2019. Utah And Wyoming Regulation
In April 2019, Questar Gas filed a request with the Utah Commission forpre-approval
to construct an LNG storage facility with a liquefaction rate of 8.2 million cubic feet per day. In October 2019, the Utah Commission grantedpre-approval
to construct the LNG storage facility.In July 2019, Questar Gas filed its base rate case and schedules with the Utah Commission. Questar Gas proposed anon-fuel,
base rate increase of $19 million effective March 2020. The base rate increase was proposed to recover the significant investment in distribution infrastructure for the benefit of Utah customers. Questar Gas presented an earned return of 9.05% based upon a fully-adjusted test period, compared to its authorized 9.85% return, and proposed a 10.5% ROE. In February 2020,May 2021, the Utah Commission approved Questar Gas’ request for a non-fuel, base rate$43 million gas cost increase of $3 millionwith rates effective March 2020. This revenue requirement increase is based on an approved ROE of 9.50%.
June 2021.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
Combined Notes to Consolidated Financial Statements, Continued
base rate increase was proposed to replace aging infrastructure and expand its system. Questar Gas presented an earned return of7.46%, based upon a fully-adjusted test period, compared to its authorized 9.5% return, and proposed a 10.5% ROE. This matter is pending.
In December 2019, Questar Gas filed an application withOctober 2021, the Utah Commission approved Questar Gas’ request for an $83 million gas cost increase with rates effective November 2021.In December 2021, the Utah Commission approved Questar Gas’ request for a CPCN to construct natural$29 million gas infrastructure to extend service to Eureka, Utah. The project is expected to include 11 miles of high-pressure pipeline and up to 360 service lines and to be in service in late 2021. Questar Gas also requested approval of a rural expansion rate adjustment tracker to recover the construction costs of the project. This matter is pending. In February 2019, Cove Point submitted its annual electric power cost adjustment to FERC requesting approval to recover $24 million. FERC approved the adjustment in March 2019.
In June 2015, Cove Point executed two binding precedent agreements for the approximately $150 million Eastern Market Access Project. Inincrease on an interim basis, with rates effective January 2018, Cove Point received FERC authorization to construct and operate the project facilities. In October 2018, Cove Point announced it was evaluating alternatives to a proposed Charles County, Maryland compressor station that was initially part of this project and in December 2018, after working with project customers for alternative solutions, decided not to pursue further construction at this location resulting in a revised project estimate of approximately $45 million and awrite-off
of $37 million ($28 millionafter-tax).
In May 2019, Cove Point filed an application for an amendment to vacate its FERC authorization for the Charles County, Maryland compressor station and revised its project scope. In August 2019, Cove Point received FERC authorization and the Eastern Market Access Project commenced commercial operations in September 2019.In connection with the Eastern Market Access Project, in August 2019, Cove Point filed to update its annual electric power cost adjustment requesting FERC approval to recover $25 million, representing an increase of $1 million from the adjustment approved in March 2019. FERC approved the adjustment in August 2019.
In January 2020, pursuant to the terms of a previous settlement, Cove Point filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective March 1, 2020. Cove Point proposed an annualcost-of-service
of approximately $182 million. Cove Point anticipates that FERC will suspend the changes in rates for five months following the proposed effective date, until August 1, 2020.In
September 2019, DETI submitted its annual transportation cost rate adjustment to FERC requesting approval to recover $
38 million. Also in
September 2019, DETI submitted its annual electric power cost adjustment to FERC requesting approval to recover $
10 million. In
October 2019, FERC approved these adjustments.
In December 2019, DETI filed an application to request FERC authorization to construct, operate and maintain the Tri-West project to provide 120,000 Dth per day of firm transportation service in from Pennsylvania to Ohio for delivery to Tennessee Gas Pipeline Company. The project facilities are expected to cost approximately
$25 million and be in service by the end of 2020.
In August 2018, DETI executed a binding precedent agreement with a customer for the West Loop project. The project is expected to cost approximately $95 million and provide 150,000 Dth per day of firm transportation service from Pennsylvania to Ohio for delivery to a proposed combined-cycle, naturalgas-fired
electric power generation facility to be located in Columbiana County, Ohio. In December 2018, DETI filed an application to request FERC authorization to construct, operate and maintain the project facilities, which are expected to be in service by the end of 2021. In December 2019, DETI received FERC authorization.In January 2018, DETI filed an application to request FERC authorization to construct and operate certain facilities located in Ohio and Pennsylvania for the Sweden Valley project. In June 2019, DETI withdrew its application for the project due to certain regulatory delays. As a result of the project abandonment, during the second quarter of 2019, DETI recorded a charge of $13 million ($10 millionafter-tax),
included in impairment of assets and other charges in Dominion Energy and Dominion Energy Gas’ Consolidated Statements of Income(reflected in the Corporate and Other segment)
.2022.NoteNOTE 14. Asset Retirement Obligations ASSET RETIREMENT OBLIGATIONSAROs 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. 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 20182020 and 20192021 were as follows: | | | | | | | | | | | | | | | | | | AROs at December 31, 2017 | | $ | | | Obligations incurred during the period | | | | | Obligations settled during the period | | | | ) | Revisions in estimated cash flows | | | | | | | | | | AROs at December 31, 2018 (1) | | $ | | | Obligations incurred during the period | | | | | Obligations settled during the period | | | | ) | AROs acquired in the SCANA Combination | | | | | Revisions in estimated cash flows (3) | | | | ) | | | | | | AROs at December 31, 2019 (1) | | $ | | | | | | | | AROs at December 31, 2017 | | $ | | | Obligations incurred during the period | | | | | Obligations settled during the period | | | | ) | Revisions in estimated cash flows (2) | | | | | | | | | | AROs at December 31, 2018 | | $ | | | Obligations incurred during the period | | | | | Obligations settled during the period | | | | ) | Revisions in estimated cash flows (3) | | | | ) | | | | | | AROs at December 31, 2019 | | $ | | | | | | | | AROs at December 31, 2017 | | $ | | | Obligations incurred during the period | | | | | Obligations settled during the period | | | | ) | | | | | | AROs at December 31, 2018 | | $ | | | Obligations settled during the period | | | | ) | | | | | | AROs at December 31, 2019 | | $ | | |
| Amount | | (millions) | | | | Dominion Energy | | | | AROs at December 31, 2019 | $ | 5,184 | | Obligations incurred during the period | | 67 | | Obligations settled during the period | | (114 | ) | Revisions in estimated cash flows(1) | | 228 | | Accretion | | 218 | | AROs at December 31, 2020(2) | $ | 5,583 | | Obligations incurred during the period | | 31 | | Obligations settled during the period | | (165 | ) | Revisions in estimated cash flows(3) | | (151 | ) | Accretion | | 224 | | Sale of non-wholly-owned nonregulated solar facilities | | (49 | ) | AROs at December 31, 2021(2) | $ | 5,473 | | Virginia Power | | | | AROs at December 31, 2019 | $ | 3,581 | | Obligations incurred during the period | | 48 | | Obligations settled during the period | | (85 | ) | Revisions in estimated cash flows(4) | | 139 | | Accretion | | 137 | | AROs at December 31, 2020 | $ | 3,820 | | Obligations incurred during the period | | 26 | | Obligations settled during the period | | (131 | ) | Revisions in estimated cash flows(5) | | 67 | | Accretion | | 141 | | AROs at December 31, 2021 | $ | 3,923 | |
(1) | Includes $282 million and $408 million reported in other current liabilities at December 31, 2018, and 2019, respectively. |
(2) | Reflects future ash pond and landfill closure costs at certain utility generation facilities. See Note 23 for further information. |
| Reflects revisions to future ash pond and landfill closure costs at certain utility generation facilities, as well as revisions for 20 year license extensions for regulatedasbestos abatement costs associated with certain utility facilities and from the completion of a nuclear power stations in Virginia. |
(4)(2) | Includes $74$179 million and $75$198 million reported in other deferred credits and other liabilities, with the remainder recorded in other current liabilities at December 31, 20182020 and 2019,2021, respectively. |
(3) | Reflects revisions to future ash pond and landfill closure costs at certain utility generation facilities, estimated cash flow projections associated with the recovery of spent nuclear fuel costs for its AROs associated with the decommissioning of Kewaunee and estimated cash flow projections associated with certain gas distribution pipelines. These revisions in 2021 resulted in a charge of $44 million ($35 million after-tax) within other operations and maintenance expense in the Consolidated Statements of Income as well as a $173 million decrease to property, plant and equipment, net. |
(4) | Reflects revisions to future ash pond and landfill closure costs at certain utility generation facilities and asbestos abatement costs associated with certain utility facilities. |
(5) | Reflects revisions to future ash pond and landfill closure costs at certain utility generation facilities. |
In addition, Virginia Power revised its estimated cash flows for the existing ARO related to future ash pond and landfill closure costs, which resulted in a $113 million ($84 million after-tax) benefit in other operations and maintenance expense in the Consolidated Statements of Income in 2019. Dominion Energy’s AROs at December 31, 20192021 and 2018,2020, include $1.7$2.0 billion and $1.6$1.9 billion, respectively, with $0.8$0.9 billion and $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. At December 31, 20192021 and 2018,2020, the aggregate fair value of Dominion Energy’s trusts, consisting primarily of equity and debt securities, totaled $6.2$8.0 billion and $4.9$6.9 billion, respectively. At December 31, 20192021 and 2018,2020, the aggregate fair value of Virginia Power’s trusts, consisting primarily of debt and equity securities, totaled $2.9$3.7 billion and $2.4$3.2 billion, respectively. In addition, AROs at December 31, 20192021 and 2020 include $2.6$2.9 billion and $2.8 billion, respectively, related to Virginia Power’s future ash pond and landfill closure costs. Regulatory mechanisms, primar ily
primarily associated with legislation enacted in Virginia in March 2019, provide for recovery of costs to be incurred. See NotesNote 12 and 23 for additional information.
LEASESAt December 31, 2019,2021 and 2020, the Companies had the following lease assets and liabilities recorded in the Consolidated Balance Sheets: | December 31, 2021 | | | December 31, 2020 | | (millions) | | | | | | | | Dominion Energy | | | | | | | | Lease assets: | | | | | | | | Operating lease assets(1) | $ | 506 | | | $ | 564 | | Finance lease assets(2) | | 144 | | | | 148 | | Total lease assets | $ | 650 | | | $ | 712 | | Lease liabilities: | | | | | | | | Operating lease liabilities(3) | $ | 44 | | | $ | 54 | | Finance lease liabilities(4) | | 36 | | | | 32 | | Total lease liabilities - current | | 80 | | | | 86 | | Operating lease liabilities (5) | | 464 | | | | 516 | | Finance lease liabilities(6) | | 112 | | | | 108 | | Total lease liabilities - noncurrent | | 576 | | | | 624 | | Total lease liabilities | $ | 656 | | | $ | 710 | | Virginia Power | | | | | | | | Operating lease assets(1) | $ | 256 | | | $ | 185 | | Finance lease assets(2) | | 71 | | | | 45 | | Total lease assets | $ | 327 | | | $ | 230 | | Lease liabilities: | | | | | | | | Operating lease liabilities(3) | $ | 25 | | | $ | 28 | | Finance lease liabilities(4) | | 13 | | | | 8 | | Total lease liabilities - current | | 38 | | | | 36 | | Operating lease liabilities (5) | | 227 | | | | 155 | | Finance lease liabilities(6) | | 57 | | | | 36 | | Total lease liabilities - noncurrent | | 284 | | | | 191 | | Total lease liabilities | $ | 322 | | | $ | 227 | |
(1) | | | | | | | | | | | | | | | | | | | | | | | Operating lease assets(1)
| | | | | | | | | | | | $ | | | | | | | | Operating lease liabilities(3)
| | $ | | | Finance lease liabilities(4)
| | | | | Total lease liabilities—current
| | | | | Operating lease liabilities(5)
| | | | | Finance lease liabilities
| | | | | Total lease liabilities—noncurrent
| | | | | | | $ | | | | | | | | Operating lease assets(1)
| | $ | | | | | | | | | | $ | | | | | | | | Operating lease liabilities(3)
| | $ | | | Finance lease liabilities(4)
| | | | | Total lease liabilities—current
| | | | | Operating lease liabilities(5)
| | | | | Finance lease liabilities
| | | | | Total lease liabilities—noncurrent
| | | | | | | $ | | | | | | | | Operating lease assets(1)
| | $ | | | | | | | | | | $ | | | | | | | | Operating lease liabilities(3)
| | $ | | | Finance lease liabilities(4)
| | | | | Total lease liabilities—current
| | | | | Operating lease liabilities(5)
| | | | | Finance lease liabilities
| | | | | Total lease liabilities—noncurrent
| | | | | | | $ | | |
(1) | Included in other deferred charges and other assets in the Companies’ Consolidated Balance Sheets. |
(2) | Included in property, plant and equipment in the Companies’ Consolidated Balance Sheets, net of $27 million, $4$81 million and $1$18 million of accumulated amortization at Dominion Energy and Virginia Power, and Dominion Energy Gas, respectively, at December 31, 2019.2021 and net of $50 million and $9 million of accumulated amortization at Dominion Energy and Virginia Power, respectively, at December 31, 2020. |
(3) | Included in other current liabilities in the Companies’ Consolidated Balance Sheets. |
(4) | Included in securities due within one year in the Companies’ Consolidated Balance Sheets. |
(5) | Included in other deferred credits and other liabilities in the Companies’ Consolidated Balance Sheets. |
(6) | Included in other long-term debt in the Companies’ Consolidated Balance Sheets. |
In addition to the amounts disclosed above, Dominion Energy’s Consolidated Balance SheetSheets at December 31, 20192021 and 2020 includes property, plant and equipment of $1.2 billion and $2.2 billion, respectively, and accumulated depreciation of $2.8 billion$106 million and $364$68 million, respectively, related to facilities subject to power purchase agreements under which Dominion Energy is the lessor.
Combined Notes to Consolidated Financial Statements, Continued
For the yearyears ended December 31, 2021, 2020 and 2019, total lease cost associated with the Companies’ leasing arrangements consisted of the following: | Year Ended December 31, 2021 | | | Year Ended December 31, 2020 | | | Year Ended December 31, 2019 | | | | (millions) | | | | | | | | | | | | | | Dominion Energy | | | | | | | | | | | | | | Finance lease cost: | | | | | | | | | | | | | | Amortization | $ | 40 | | | $ | 33 | | | $ | 20 | | | | Interest | | (3 | ) | | | — | | | | 4 | | | | Operating lease cost | | 66 | | | | 68 | | | | 79 | | | | Short-term lease cost | | 32 | | | | 20 | | | | 26 | | | | Variable lease cost | | 5 | | | | 8 | | | | 5 | | | | Total lease cost | $ | 140 | | | $ | 129 | | | $ | 134 | | | | Virginia Power | | | | | | | | | | | | | | Finance lease cost: | | | | | | | | | | | | | | Amortization | $ | 12 | | | $ | 7 | | | $ | 3 | | | | Interest | | 1 | | | | 1 | | | | — | | | | Operating lease cost | $ | 30 | | | $ | 36 | | | $ | 41 | | | | Short-term lease cost | | 19 | | | | 12 | | | | 13 | | | | Variable lease cost | | 1 | | | | 4 | | | | 2 | | | | Total lease cost | $ | 63 | | | $ | 60 | | | $ | 59 | | | |
For the yearyears ended December 31, 2021, 2020 and 2019, cash paid for amounts included in the measurement of the lease liabilities consisted of the following amounts, included in the Companies’ Consolidated Statements of Cash Flows: | Year Ended December 31, 2021 | | | Year Ended December 31, 2020 | | | Year Ended December 31, 2019 | | (millions) | | | | | | | | | | | | Dominion Energy | | | | | | | | | | | | Operating cash flows for finance leases | $ | (3 | ) | | $ | — | | | $ | 4 | | Operating cash flows for operating leases | | 103 | | | | 96 | | | | 111 | | Financing cash flows for finance leases | | 40 | | | | 33 | | | | 20 | | Virginia Power | | | | | | | | | | | | Operating cash flows for finance leases | $ | 1 | | | $ | 1 | | | $ | — | | Operating cash flows for operating leases | | 53 | | | | 52 | | | | 56 | | Financing cash flows for finance leases | | 12 | | | | 7 | | | | 3 | |
| | | | | | | | | | | | | | | | | | Operating cash flows for finance leases
| | $ | | | Operating cash flows for operating leases
| | | | | Financing cash flows for finance leases
| | | | | | | | | | Operating cash flows for operating leases
| | | | | | | | | | Operating cash flows for operating leases
| | | | |
In addition to the amounts disclosed above, Dominion Energy’s Consolidated StatementStatements of Income for the yearyears ended December 31, 2021, 2020 and 2019, includesinclude $168 million, $175 million and $174 million, respectively, of rental revenue, included in operating revenue and $110 million, $102 million and $94 million, respectively, of depreciation expense, included in depreciation, depletion and amortization, related to facilities subject to power purchase agreements under which Dominion Energy is the lessor. At December 31, 2019,2021 and 2020, the weighted average remaining lease term and weighted discount rate for the Companies’ finance and operating leases were as follows: | | | | | | | | | | | | | | Weighted average remaining lease term—finance leases
| | | | | Weighted average remaining lease term—operating leases
| | | | | Weighted average discount rate—finance leases
| | | | % | Weighted average discount rate—operating leases
| | | | % | | | | | | Weighted average remaining lease term—finance leases
| | | | | Weighted average remaining lease term—operating leases
| | | | | Weighted average discount rate—finance leases
| | | | % | Weighted average discount rate—operating leases
| | | | % | | | | | | Weighted average remaining lease term—finance leases
| | | | | Weighted average remaining lease term—operating leases
| | | | | Weighted average discount rate—finance leases
| | | | % | Weighted average discount rate—operating leases
| | | | % |
| December 31, 2021 | | | December 31, 2020 | | Dominion Energy | | | | | | | | Weighted average remaining lease term - finance leases | 5 years | | | 5 years | | Weighted average remaining lease term - operating leases | 27 years | | | 26 years | | Weighted average discount rate - finance leases | | 2.77 | % | | | 3.17 | % | Weighted average discount rate - operating leases | | 3.96 | % | | | 4.07 | % | Virginia Power | | | | | | | | Weighted average remaining lease term - finance leases | 6 years | | | 6 years | | Weighted average remaining lease term - operating leases | 25 years | | | 21 years | | Weighted average discount rate - finance leases | | 2.27 | % | | | 2.51 | % | Weighted average discount rate - operating leases | | 4.00 | % | | | 4.26 | % |
The Companies’ lease liabilities have the following maturities: Maturity of Lease Liabilities | | Dominion Energy | | | Virginia Power | | (millions) | | Operating | | | Finance | | | Operating | | | Finance | | 2022 | | $ | 50 | | | $ | 32 | | | $ | 27 | | | $ | 8 | | 2023 | | | 41 | | | | 39 | | | | 21 | | | | 14 | | 2024 | | | 33 | | | | 33 | | | | 17 | | | | 14 | | 2025 | | | 27 | | | | 18 | | | | 13 | | | | 13 | | 2026 | | | 24 | | | | 15 | | | | 10 | | | | 10 | | After 2026 | | | 577 | | | | 22 | | | | 240 | | | | 17 | | Total undiscounted lease payments | | | 752 | | | | 159 | | | | 328 | | | | 76 | | Present value adjustment | | | (244 | ) | | | (11 | ) | | | (76 | ) | | | (6 | ) | Present value of lease liabilities | | $ | 508 | | | $ | 148 | | | $ | 252 | | | $ | 70 | |
| | | | | | | | | | | | | | | | | | | | | | | | | Maturity of Lease Liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total undiscounted lease payments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | Present value of lease liabilities | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | |
Corporate Office Leasing Arrangements Arrangement 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. Upon commencement, the lease for the facility was classified as a finance lease. At the end of the initial lease term, In March 2021, Dominion Energy can (i) extend the term of the lease for an additional five years, subject to the approval of the participants, at current market terms, (ii) purchase the property for an amount equal to the project costs or, (iii) subject to certain terms and conditions, sell the property on behalf ofnotified the lessor of its intention to terminate the leasing arrangement effective April 2021. As a third party using commercially reasonable efforts to obtain the highest cash purchase price for the
property. If the project is sold and the proceeds from the sale are insufficient to repay the investors for the project costs, Dominion Energy may be required to make a payment to the lessor, up to 87% of project costs, for the difference between the project costs and sale proceeds. Noend-of-term
options were deemed reasonably certain of exercise at commencement date. At commencement,result, Dominion Energy recorded a right-of-use
asset charge of $62 million ($46 million after-tax) in 2021, included in impairments of assets and offsetting lease obligationother charges in its Consolidated Statements of $67 million, representingIncome, primarily for amounts required to be repaid to the present value of consideration over the five-year term at the rate implicit in the lease. Dominion Energy is considered the owner of the leased property for tax purposes, and as a result, is entitled to tax deductions for depreciation and interest expense.lessor.
Offshore Wind Vessel Leasing Arrangement In December 2019,2020, Dominion Energy signed an agreement 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 technologies as well as next generation turbines. The lessor is providing equity and has obtained financing commitments from debt investors, totaling $465$550 million, to fund the estimated project costs. If Dominion Energy ultimately proceeds with the
The project through completion, it
is not
expected to be completed earlier than
mid-2023.
by the end of 2023. Dominion Energy has been appointed to act as the construction agent for the lessor, during which time Dominion Energy will request cash draws from the lessor and debt investors to fund all project costs.costs, which totaled $293 million as of December 31, 2021. If the project is terminated under certain events of default, Dominion Energy could be required to pay up to 89.9% 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. The 51-month
initial lease term will commence once construction is substantially complete and the facilityvessel 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. Dominion Energy is not considered the owner during construction for financial accounting purposes and, therefore, will not reflect the construction activity in its consolidated financial statements. Dominion Energy expects to recognize a right-of-use asset and a corresponding finance lease liability at the commencement of the lease term. Dominion Energy will be considered the owner of the leased property for tax purposes, and as a result, will be entitled to tax deductions for depreciation and interest expense. NoteNOTE 16. Variable Interest Entities VARIABLE INTEREST ENTITIESThe 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. AtThrough December 31, 2019,2021, Dominion Energy ownsowned the manager and 67% of the membership interest in certain merchantnonregulated solar facilities, as discussed in Note 2. Dominion Energy has concluded that these entities arewere VIEs due to the members lacking the characteristics of a controlling financial interest. In addition, in 2016 Dominion Energy created a wholly owned subsidiary, SBL Holdco, as a holding company of its interest in the VIE merchantnonregulated solar facilities and accordingly SBL Holdco iswas a VIE. Prior to
its disposition in December 2021, Dominion Energy iswas the primary beneficiary of SBL Holdco and the merchantnonregulated solar facilities, as it hashad the power to direct the activities that most significantly impact their economic performance as well as the obligation to absorb losses and benefits which could be significant to them. At December 31, 2020, Dominion Energy’s securities due within one year and long-term debt include $31$32 million and $267$239 million, respectively, of debt issued by SBL Holdco net of issuance costs that iswas nonrecourse to Dominion Energy and iswas secured by SBL Holdco’s interest in certain merchantnonregulated solar facilities. At December 31, 2021, Dominion Energy owns a 48%50% membership interest in Cove Point, as discussed in Notes 3 and 9. Dominion Energy concluded that Cove Point is a VIE due to the limited partners lacking the characteristics of a controlling financial interest. As a result of the GT&S Transaction, effective November 1, 2020, Dominion Energy is no longer the primary beneficiary of Cove Point as BHE retains the power to direct the activities that most significantly impact Cove Point’s economic performance. Dominion Energy’s maximum exposure to loss is limited to its current and future investment, as well as any obligations under guarantees provided. See Note 23 for more information. At December 31, 2021, Dominion Energy owns a 53% membership interest in Atlantic Coast Pipeline. 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 previously concluded that Dominion Energy Midstream was a VIE due todetails regarding the limited partners lacking the characteristicsnature of a controlling financial interest and that it was the primary beneficiary as it had the power to direct the activities that most significantly impact the economic performance as well as to absorb losses and benefits which could be significant to Dominion Energy Midstream. In January 2019, Dominion Energy acquired all outstanding partnership interests not owned by Dominion Energy and Dominion Energy Midstream became a wholly-owned subsidiary of Dominion Energy. As a result, Dominion Energy concluded that Dominion Energy Midstream is no longer a VIE.
this entity.Dominion Energy and Virginia Power Dominion Energy and Virginia Power’sThe Companies’ nuclear decommissioning trust funds and Dominion Energy’s rabbi trusts hold investments in limited partnerships or similar type entities (see Note 9 for further details). Dominion Energy and Virginia Power concluded that these partnership investments are VIEs due to the limited partners lacking the characteristics of a controlling financial interest. Dominion Energy and Virginia Power have concluded neither is the primary beneficiary as they do not have the power to
Combined Notes to Consolidated Financial Statements, Continued
direct the activities that most significantly impact these VIEs’ economic performance. Dominion Energy and Virginia Power are obligated to provide capital contributions to the partnerships required by each partnership agreement based on their ownership percentages. Dominion Energy and Virginia Power’s maximum exposure to loss is limited to their current and future investments. Virginia Power had a long-term power and capacity contract with 1 non-utility generator with an aggregate summer generation capacity of approximately 218 MW. The contract contained certain variable pricing mechanisms in the form of partial fuel reimbursement that Virginia Power considered to be variable interests and for which Virginia Power had previously concluded if the generation facility were to be a VIE that it would not be the primary beneficiary. In May 2019, Virginia Power entered into an agreement and paid $135 million to terminate the remaining contract with the non-utility generator. A $135 million ($100 million after-tax) charge was recorded in impairment of assets and other charges in Virginia Power’s Consolidated Statements of Income (reflected in the Corporate and Other segment) during the second quarter of 2019. Virginia Power paid $13 million $50 million, and $86 million for electric capacity to non-utility generators and $1 million $18 million and $24 million for electric energy to non-utility generators for the yearsyear ended December 31, 2019, 2018 and 2017, respectively.Dominion Energy and Dominion Energy Gas
As part of the Dominion Energy Gas Restructuring, Dominion Energy contributed to Dominion Energy Gas a 75% controlling limited partner interest in Cove Point. In December 2019, Dominion Energy sold its retained 25% noncontrolling limited partner interest in Cove Point. Dominion Energy Gas concluded that Cove Point is a VIE due to the limited partners lacking the characteristics of a controlling financial interest. Dominion Energy Gas is the primary beneficiary of Cove Point as it has the power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to it.
DETI has been engaged to oversee the construction of, and to subsequently operate and maintain, the projects undertaken by Atlantic Coast Pipeline based on the overall direction and oversight of Atlantic Coast Pipeline’s members. An affiliate of DETI holds a membership interest in Atlantic Coast Pipeline, therefore DETI is considered to have a variable interest in Atlantic Coast Pipeline. The members of Atlantic Coast Pipeline hold the power to direct the construction, operations and maintenance activities of the entity. DETI has concluded 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. DETI has no obligation to absorb any losses of the VIE. See Note 25 for information about associated related party receivable balances.
Dominion Energy Gas purchased shared services from DECGS and DEQPS, affiliated VIEs, of $49 million, $45 million and $45 million for the years ended December 31, 2019, 2018 and 2017, respectively. Dominion Energy Gas’ Consolidated Balance Sheets included amounts due to DECGS and DEQPS of $15 million and $6 million at December 31, 2019 and at December 31, 2018, respectively.
Dominion EnergyGas determined that neither it nor any of its consolidated entities is the primary beneficiary of DECGS or DEQPS, as neither it nor any of its consolidated entities has both the power to direct the activities that most significantly impact their economic performance as well as the obligation to absorb losses and benefits which could be significant to them. DECGS and DEQPS provide
marketing
and operational
services to Dominion Energy and its subsidiaries as subsidiary service companies. Neither Dominion Energy Gas nor any of its consolidated entities has any obligation to absorb more than its allocated share of DECGS or DEQPS costs.2019.Virginia Power and Dominion Energy Gas Virginia Power and Dominion Energy Gas purchased shared services from DES, an affiliated VIE, of $387$380 million, $349 million and $119 million, $335 million and $106 million, and $340 million and $106$387 million for the years ended December 31, 2019, 20182021, 2020, and 2017,2019, respectively. Virginia Power and Dominion Energy Gas’Power’s Consolidated Balance Sheets included amounts due to DES of $102$20 million and $27 million, respectively, at December 31, 2019,2021, and $107$175 million and $43 million, respectively, at December 31, 2018,2020, respectively, recorded in payables to affiliates in the Consolidated Balance Sheets. Virginia Power and Dominion Energy Gas determined that neitherit is not the primary beneficiary of DES as neither has both theit does not have power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to it. DES provides accounting, legal, finance and certain administrative and technical services to all Dominion Energy subsidiaries, including Virginia Power and Dominion Energy Gas.Power. Virginia Power and Dominion Energy Gas havehas no obligation to absorb more than theirits allocated sharesshare of DES costs.
NoteNOTE 17. Short-term Debt and Credit Agreements SHORT-TERM DEBT AND CREDIT AGREEMENTSThe 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. In June 2021, Dominion Energy amended its $6.0 billion joint revolving credit facility to provide for a discount in the pricing of certain annual fees and amounts borrowed by Dominion Energy under the facility if Dominion Energy achieves certain annual renewable electric generation and diversity and inclusion objectives. In addition, the amended facility incorporates certain administrative changes with respect to the anticipated transition from LIBOR to an alternative benchmark rate. The key financial covenants are unchanged from the previous facility. Dominion Energy’s short-term financing is supported through its access to the joint revolving credit facility described below. Commercial paper and letters of credit outstanding, as well as capacity available under the credit facility were as follows: | | | | | | | | | | | | | | | | | | | | | | Outstanding Commercial Paper (1) | | | Outstanding
Letters of
Credit | | | Facility
Capacity
Available | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Joint revolving credit facility (2) | | $ | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | Joint revolving credit facility (2) | | $ | | | | | | | | | | | | $ | | |
| | Facility Limit | | | Outstanding Commercial Paper(1) | | | Outstanding Letters of Credit | | | Facility Capacity Available | | (millions) | | | | | | | | | | | | | | | | | At December 31, 2021 | | | | | | | | | | | | | | | | | Joint revolving credit facility(2) | | $ | 6,000 | | | $ | 1,883 | | | $ | 131 | | | $ | 3,986 | | At December 31, 2020 | | | | | | | | | | | | | | | | | Joint revolving credit facility(2) | | $ | 6,000 | | | $ | 627 | | | $ | 100 | | | $ | 5,273 | |
(1) | The weighted-average interest rates of the outstanding commercial paper supported by Dominion Energy’s credit facility was 2.10%0.31% and 2.93%0.29% at December 31, 20192021 and 2018,2020, respectively. |
(2) | This credit facility matures in March 2023June 2026, with the potential to be extended by the borrowers to June 2028, and can be used by the borrowers under the credit facility to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit. |
In March 2019, DESC’s $700 million credit facility was terminated
DESC and DESC was addedQuestar 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-borrower
to the facility.Companies. At December 31, 2019,2021, thesub-limit
sub-limits for DESC was $500 million. Questar Gas’ short-term financing is supported through its access asco-borrower
to the joint revolving credit facility discussed above with Dominion Energy, Virginia Power, Dominion Energy Gas and DESC. At December 31, 2019, thesub-limit
for Questar Gas waswere $500 million and $250 million.South Carolina Fuel Company, Inc.’s credit facility was terminated in February 2019. SCANAmillion, respectively.In January 2021, DESC and PSNC’s credit facilities were terminated inGENCO applied to FERC for a two-year short-term borrowing authorization. In March 2019. Liquidity needs for these entities may be satisfied through short-term intercompany borrowings from Dominion Energy. In April 2019,2021, FERC granted DESC renewed its FERC authority through April 2020March 2023 to issue short-term indebtedness (pursuant to Section 204 of the Federal Power Act) in amounts not to exceed $2.2 billion outstanding with maturity dates of one year or less. In addition, in April 2019,March 2021, FERC granted GENCO renewed its FERC authority through April 2020March 2023 to issue short-term indebtedness not to exceed $200 million outstanding with maturity dates of one year or less. In January 2020, DESC and GENCO applied to FERC for a two-year short-term borrowing authorization. The applications are pending.
In addition to the credit facilities mentioned above, SBL Holdco has $30 million of credit facilities which had an original stated maturity date of December 2017 with automaticone-year
renewals through the maturity of the SBL Holdco term loan agreement in December 2023. Dominion Solar Projects III, Inc. has $25 million of credit facilities which had an original stated maturity date of May 2018 with automaticone-year
renewals through the maturity of the Dominion Solar Projects III, Inc. term loan agreement in May 2024. At December 31, 2019, no amounts were outstanding under either of these facilities.In February 2019, Dominion Energy Midstream terminated its $500 million revolving credit facility subsequent to repaying the outstanding balance of $73 million, plus accrued interest.
In addition to the joint revolving credit facility mentioned above, Dominion Energy also has a credit facility with a maturity date in June 2020 whichallows Dominion Energy to issue up to approximately $21$30 million in letters of credit. credit and matures in June 2022.At December 31, 2019,2021 and 2020, Dominion Energy had $21$29 million and $30 million, respectively, 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. At December 31, 2020, 0 amounts were outstanding under either of these facilities. In March 2020, Dominion Energy Questar borrowed $3.0 billion underentered into a $900 million 364-Day Term LoanRevolving Credit Agreement that accruedbore interest at a variable rate. At December 31, 2020, $225 million was outstanding under the agreement. In March 2021, the agreement reached maturity and Dominion Energy repaid the outstanding borrowed amount in full. In July 2021, Dominion Energy entered into an approximately $1.3 billion term loan credit agreement following the termination of the Q-Pipe Transaction as discussed in Note 3 and borrowed the full amount available thereunder. The term loan was scheduled to mature in December 2021, with the ability to extend maturity at Dominion Energy’s option to June 2022 and bore interest at a variable rate. The proceeds were utilized to repay the deposit received from BHE on the Q-Pipe Transaction. In December 2021, Dominion Energy used the net proceeds from the borrowing were usedcompletion of the sale of the Q-Pipe Group to Southwest Gas to repay the principal outstanding under the term loan plus accrued interest.
In December 2021, DECP Holdings entered into a credit facility, which allows it to issue up to $110 million in letters of Cove Point’scredit with automatic one-year renewals through the maturity of the facility in December 2024. At December 31, 2021, $110 million in letters of credit were outstanding under this agreement with 0 amounts drawn under the letters of credit. Dominion Energy has an effective shelf registration statement with the SEC for the sale of up to $3.0 billion term loan due in 2021.of variable denomination floating rate demand notes, called Dominion Energy providedReliability 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 guarantee to supportcontinuous basis and bear interest at a floating rate per annum determined by the Dominion Energy Questar’s obligation underReliability 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 the364-Day
Term Loan Agreement. In November investor’s option at any time. At December 31, 2021 and December 2019, principal of $1.0 billion31, 2020, Dominion Energy’s Consolidated Balance Sheets include $431 million and $2.0 billion,$268 million, respectively, plus accrued interest was repaid. presented within short-term debt. The proceeds are used for general corporate purposes and to repay debt.Virginia Power Virginia Power’s short-term financing is supported through its access as co-borrower to theDominion Energy’s $6.0 billion joint revolving credit facility.facility, as amended in June 2021. The credit facility can be used for working capital, as support for the combined commercial paper programs of the borrowers under the credit facility and for other general corporate purposes. Virginia Power’s share of commercial paper and letters of credit outstanding under itsthe joint revolving credit facility with Dominion Energy, Dominion Energy Gas, Questar Gas and DESC were as follows: | | | | | | | | | | | | | | | | | | Outstanding Commercial Paper (1) | | | Outstanding
Letters of
Credit | | | | | | | | | | | | | | | | | | | | | | | | | Joint revolving credit facility (2) | | | | | | | | | | | | | | | | | | | | | | | | | | Joint revolving credit facility (2) | | | | | | | | | | | | |
| | Facility Limit | | | Outstanding Commercial Paper(1) | | | Outstanding Letters of Credit | | (millions) | | | | | | | | | | | | | At December 31, 2021 | | | | | | | | | | | | | Joint revolving credit facility(2) | | $ | 6,000 | | | $ | 745 | | | $ | 40 | | At December 31, 2020 | | | | | | | | | | | | | Joint revolving credit facility(2) | | $ | 6,000 | | | $ | 45 | | | $ | 12 | |
(1) | The weighted-average interest rates of the outstanding commercial paper supported by the credit facility was 2.10%0.26% and 2.94%0.30% at December 31, 20192021 and 2018,2020, respectively. |
(2) | The full amount of the facility is available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy, Dominion Energy Gas, Questar Gas and DESC. The sub-limit for Virginia Power is set within the facility limit but can be changed at the option of the borrowers under the credit facility multiple times per year. At December 31, 2019,2021, the sub-limit for Virginia Power was $1.5$1.75 billion. If Virginia Power has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term intercompany borrowings from Dominion Energy. This credit facility matures in March 2023 andJune 2026, with the potential to be extended by the borrowers to June 2028. The credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $2.0 billion (or the sub-limit, whichever is less) of letters of credit. |
Dominion Energy Gas’ short-term financing is supported by its access asco-borrower
to the joint revolving credit facility. The credit facility can be used for working capital, as support for the combined commercial paper programs of the borrowers under the credit facility and for other general corporate purposes.Dominion Energy Gas’ share of commercial paper and letters of credit outstanding under its joint credit facility with Dominion Energy, Virginia Power, Questar Gas and DESC were as follows:
| | | | | | | | | | | | | | | | | | Outstanding Commercial Paper (1) | | | Outstanding
Letters of
Credit | | | | | | | | | | | | | | | | | | | | | | | | | Joint revolving credit facility (2) | | | | | | | | | | | | | | | | | | | | | | | | | | Joint revolving credit facility (2) | | | | | | | | | | | | |
(1) | The weighted-average interest rates of the outstanding commercial paper supported by the credit facility was 1.98% and 2.58% at December 31, 2019 and 2018, respectively. |
(2) | A maximum of $1.5 billion of the facility is available to Dominion Energy Gas, assuming adequate capacity is available after giving effect to uses byco-borrowers
Dominion Energy, Virginia Power, Questar Gas and DESC. Thesub-limit
for Dominion Energy Gas is set within the facility limit but can be changed at the option of the borrowers under the credit facility multiple times per year. At December 31, 2019, thesub-limit
for Dominion Energy Gas was $750 million. If Dominion Energy Gas has liquidity needs in excess of itssub-limit,
thesub-limit
may be changed or such needs may be satisfied through short-term intercompany borrowings from Dominion Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or thesub-limit,
whichever is less) of letters of credit. |
Combined Notes to Consolidated Financial Statements, Continued
| | | | | | | | | | | | | | | | | | | | | | | (millions, except percentages) | | | | | | | | | | Dominion Energy Gas Holdings, LLC: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | % | | $ | | | | $ | | | 2.5% to 4.8%, due 2019 to 2049 (2) | | | | % | | | | | | | | | Cove Point, term loan, due 2021 (3) | | | | | | | | | | | | | Dominion Energy Midstream: | | | | | | | | | | | | | Term loan, variable rate, due 2019 | | | | | | | | | | | | | Revolving credit agreement, variable rate, due 2021 (4) | | | | | | | | | | | | | Dominion Energy Questar Pipeline, unsecured senior notes, 3.53% to 4.875%, due 2028 to 2041 | | | | % | | | | | | | | | Dominion Energy Gas Holdings, LLC total principal | | | | | | $ | | | | $ | | �� | Securities due within one year | | | | % | | | | ) | | | | ) | Credit facility borrowings (4) | | | | | | | | | | | (73 | ) | Unamortized discount and debt issuance costs | | | | | | | | ) | | | | ) | | | | | | | | | | | | | | Dominion Energy Gas Holdings, LLC total long-term debt | | | | | | $ | | | | $ | | | Virginia Electric and Power Company: | | | | | | | | | | | | | | | | | | | | | | | | | | 2.75% to 8.875%, due 2019 to 2049 | | | | % | | $ | | | | $ | | | Tax- exempt financings, 1.80% to 5.0%, due 2023 to 2041 | | | | % | | | | | | | | | Virginia Electric and Power Company total principal | | | | | | $ | | | | $ | | | Securities due within one year | | | | % | | | | ) | | | | ) | Unamortized discount, premium and debt issuances costs, net | | | | | | | | ) | | | | ) | | | | | | | | | | | | | | Virginia Electric and Power Company total long-term debt | | | | | | $ | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Variable rates, due 2019 and 2020 | | | | % | | $ | | | | $ | | | 1.6% to 7.0%, due 2019 to 2049 (7) | | | | % | | | | | | | | | Unsecured junior subordinated notes: | | | | | | | | | | | | | 2.579% to 4.104%, due 2019 to 2024 | | | | % | | | | | | | | | Payable to affiliated trust, 8.4%, due 2031 | | | | % | | | | | | | | | Enhanced junior subordinated notes: | | | | | | | | | | | | | Variable rates, due 2066 (8) | | | | % | | | | | | | | | 5.25% and 5.75%, due 2054 and 2076 | | | | % | | | | | | | | | Remarketable subordinated notes, 2.0%, due 2021 and 2024 | | | | | | | | | | | | | Questar Gas, unsecured senior notes, 2.98% to 7.20%, due 2024 to 2051 | | | | % | | | | | | | | | | | | | | | | | | | | | | Unsecured medium term notes, 4.125% to 6.25%, due 2020 to 2022 (9)(10) | | | | % | | | | | | | | | Unsecured senior notes, variable rate, due 2034 (11) | | | | % | | | | | | | | | PSNC, senior debentures and notes, 4.13% to 7.45%, due 2020 to 2047 | | | | % | | | | | | | | | | | | | | | | | | | | | | First mortgage bonds, 3.22% to 6.625%, due 2021 to 2065 (12) | | | | % | | | | | | | | | Tax- exempt financings: (13) | | | | | | | | | | | | | | | | | % | | | | | | | | | GENCO, variable rates due 2038 (14) | | | | % | | | | | | | | | 3.625% and 4.00%, due 2028 and 2033 | | | | % | | | | | | | | | | | | | % | | | | | | | | | Secured senior notes, 4.82%, due 2042 (15) | | | | % | | | | | | | | | Term loans, variable rates, due 2023 and 2024 (15) | | | | % | | | | | | | | | Tax- exempt financing, 1.7%, due 2033 | | | | % | | | | | | | | | Dominion Energy Gas Holdings, LLC total principal (from above) | | | | | | | | | | | | | Virginia Electric and Power Company total principal (from above) | | | | | | | | | | | | | Dominion Energy, Inc. total principal | | | | | | $ | | | | $ | | | Fair value hedge valuation (16) | | | | | | | | | | | | ) | Securities due within one year (8)(10)(11)(17) | | | | % | | | | ) | | | | ) | Credit facility borrowings (4) | | | | | | | | | | | (73 | ) | Unamortized discount, premium and debt issuance costs, net | | | | | | | | ) | | | | ) | | | | | | | | | | | | | | Dominion Energy, Inc. total long-term debt | | | | | | $ | | | | $ | | |
NOTE 18. LONG-TERM DEBT At December 31, | | 2021 Weighted- average Coupon(1) | | | 2021 | | | 2020 | | (millions, except percentages) | | | | | | | | | | | | | Virginia Electric and Power Company: | | | | | | | | | | | | | Unsecured Senior Notes: | | | | | | | | | | | | | 2.30% to 8.875%, due 2022 to 2051 | | | 4.07 | % | | $ | 13,238 | | | $ | 12,689 | | Tax-Exempt Financings(2): | | | | | | | | | | | | | 0.45% to 1.90%, due 2032 to 2041 | | | 1.14 | % | | | 625 | | | | 625 | | Virginia Electric and Power Company total principal | | | | | | $ | 13,863 | | | $ | 13,314 | | Securities due within one year | | | 3.45 | % | | | (300 | ) | | | — | | Unamortized discount, premium and debt issuances costs, net | | | | | | | (110 | ) | | | (107 | ) | Derivative restructuring | | | | | | | 446 | | | | 444 | | Finance leases | | | | | | | 57 | | | | 36 | | Virginia Electric and Power Company total long-term debt | | | | | | $ | 13,956 | | | $ | 13,687 | | Dominion Energy, Inc.: | | | | | | | | | | | | | Supplemental 364-Day credit facility, variable rate, due 2021 | | | | | | $ | — | | | $ | 225 | | Sustainability Revolving Credit Agreement, variable rate, due 2024(3) | | | | | | | — | | | | — | | Unsecured Senior Notes: | | | | | | | | | | | | | Variable rate, due 2023 | | | 0.73 | % | | | 1,000 | | | | 1,000 | | 1.45% to 7.0%, due 2021 to 2049(4) | | | 3.78 | % | | | 11,238 | | | | 9,938 | | Unsecured Junior Subordinated Notes: | | | | | | | | | | | | | 2.715% to 4.104%, due 2021 and 2024 | | | 3.07 | % | | | 700 | | | | 1,950 | | Payable to Affiliated Trust, 8.4%, due 2031 | | | 8.40 | % | | | 10 | | | | 10 | | Enhanced Junior Subordinated Notes: | | | | | | | | | | | | | 5.25% and 5.75%, due 2054 and 2076(5) | | | 5.75 | % | | | 685 | | | | 1,485 | | DECP Holdings, Term Loan, variable rate, due 2024(6) | | | 1.50 | % | | | 2,500 | | | | — | | Questar Gas, Unsecured Senior Notes, 2.21% to 7.20%, due 2024 to 2051 | | | 3.85 | % | | | 1,000 | | | | 750 | | East Ohio, Unsecured Senior Notes, 1.30% to 3.00%, due 2025 to 2050 | | | 2.25 | % | | | 1,800 | | | | 1,800 | | PSNC, Senior Debentures and Notes, 3.10% to 7.45%, due 2021 to 2051 | | | 4.34 | % | | | 800 | | | | 800 | | DESC: | | | | | | | | | | | | | First Mortgage Bonds, 2.30% to 6.625%, due 2021 to 2065 | | | 5.09 | % | | | 3,634 | | | | 3,267 | | Tax-Exempt Financings(7): | | | | | | | | | | | | | Variable rate due 2038 | | | 0.14 | % | | | 35 | | | | 35 | | 3.625% and 4.00%, due 2028 and 2033 | | | 3.90 | % | | | 54 | | | | 54 | | GENCO, variable rate due 2038 | | | 0.14 | % | | | 33 | | | | 33 | | Other | | | 3.65 | % | | | 1 | | | | 1 | | Secured Senior Notes, 4.82%, due 2042(8) | | | 4.82 | % | | | 314 | | | | 331 | | Term Loans, variable rates, due 2023 and 2024(9) | | | | | | | — | | | | 476 | | Tax-Exempt Financing, 1.7% due 2033 | | | 1.70 | % | | | 27 | | | | 27 | | Virginia Electric and Power Company total principal (from above) | | | | | | | 13,863 | | | | 13,314 | | Dominion Energy, Inc. total principal(10) | | | | | | $ | 37,694 | | | $ | 35,496 | | Fair value hedge valuation(11) | | | | | | | 2 | | | | 3 | | Securities due within one year(12) | | | 2.79 | % | | | (805 | ) | | | (1,905 | ) | Supplemental 364-Day credit facility borrowings | | | | | | | — | | | | (225 | ) | Unamortized discount, premium and debt issuance costs, net | | | | | | | (315 | ) | | | (293 | ) | Derivative restructuring | | | | | | | 738 | | | | 773 | | Finance leases | | | | | | | 112 | | | | 108 | | Dominion Energy, Inc. total long-term debt | | | | | | $ | 37,426 | | | $ | 33,957 | |
(1) | Represents weighted-average coupon rates for debt outstanding as of December 31, 2019.2021. |
(2) | Amount includes foreign currency remeasurement adjustments. |
(3) | In September 2019, Cove Point repaid its $3.0 billion term loan due in 2021. |
(4) | In February 2019, Dominion Energy Midstream repaid its $300 million variable rate term loan due in December 2019 and terminated the credit facility due in March 2021 subsequent to repaying the $73 million outstanding balance. As such, credit facility borrowings are presented within current liabilities in Dominion Energy Gas’ Consolidated Balance Sheets at December 31, 2018. |
(5) | These financings relate to certain pollution control equipment at Virginia Power’s generating facilities. |
(6)(3) | In May 2019, Virginia Power redeemed its $40This $900 million 5.0% Economic Development Authoritysupplemental credit facility, entered in June 2021, offers a reduced interest rate margin with respect to borrowed amounts allocated to certain environmental sustainability or social investment initiatives. Proceeds of the County of Chesterfield Pollution Control Refunding Revenue Bonds, Series 2009A, due in 2023 at the principal outstanding plus accrued interest.supplemental credit facility also may be used for general corporate purposes, but such proceeds are not eligible for a reduced interest rate margin. In June 2021 and August 2021, Dominion Energy borrowed $250 million and $650 million respectively. The proceeds from these borrowings were used to support environmental sustainability and social investment initiatives ($250 million) and for general corporate purposes ($650 million). In November 2021 and December 2021, Dominion Energy repaid $650 million and $250 million, respectively, borrowed under this arrangement. |
(7)(4) | Includes debt assumed by Dominion Energy from the merger of its former CNG subsidiary. |
(8)(5) | In February 2020,August 2021, Dominion Energy purchased and cancelledredeemed the remaining $111 million and $286principal outstanding of $800 million of its June 2006July 2016 hybrids, and September 2006 hybrids, respectively, both of which would have otherwise matured in 2066. As such, these borrowings are presented within securities due within one year2076. |
(6) | The term loan amortizes over a 17-year period and matures in Dominion Energy’s Consolidated Balance Sheets at December 31, 2019. |
(9) | In March 2019, SCANA purchased certain of its medium term notes having an aggregate purchase price of $300 million pursuant2024 with the potential to tender offer that expired in the first quarter of 2019. |
(10) | In February 2020, SCANA provided noticebe extended to redeem the remaining principal outstanding of $183 million of its 4.75% medium-term notes and $155 million of its 4.125% medium-term notes plus accrued interest and make-whole premiums in March 2020.December 2026. The notes would have otherwise matured in May 2021 and February 2022, respectively. As such, these borrowings are presented within securities due within one year in Dominion Energy’s Consolidated Balance Sheets at December 31, 2019. |
(11) | In January 2020, SCANA provided notice to redeem its floating rate senior notes at the remaining principal outstanding of $66 million plus accrueddebt is secured by DECP Holdings’ noncontrolling interest in March 2020. The notes would have otherwise matured in June 2034. As such, these borrowings are presented within securities due within one year in Dominion Energy’s Consolidated Balance Sheets at December 31, 2019.Cove Point. |
(12)(7) | In February, March and September 2019, DESC purchased certain of its first mortgage bonds having an aggregate purchase price of $1.8 billion pursuant to tender offers. The February and March tender offers expired in the first quarter of 2019 and the September tender offer expired in the third quarter of 2019. |
| Industrial revenue bonds totaling $68 million are secured by letters of credit that expire, subject to renewal, in the fourth quarter of 2020. |
| In May 2019, GENCO redeemed its 5.49% senior secured notes due in 2024 at the remaining principal outstanding of $33 million plus accrued interest. In June 2019, the first mortgage lien on an electric generating facility that previously secured these notes was released. |
8) | Represents debt associated with Eagle Solar, SBL Holdco and Dominion Solar Projects III, Inc.Solar. The debt is nonrecourse to Dominion Energy and is secured by Eagle Solar’s interest in certain solar facilities. |
(9) | Represents debt associated with SBL Holdco and Dominion Solar Projects III, Inc. The debt was nonrecourse to Dominion Energy and was secured by SBL Holdco’s and Dominion Solar Projects III, Inc’s interest in certain solar facilities. In connection with the sales of certain non-wholly owned nonregulated solar facilities discussed in Note 10, the outstanding debt of SBL Holdco was assumed by Terra Nova Renewable Partners and Dominion Energy utilized proceeds from Clearway to repay the outstanding balance of the Dominion Solar Projects III, Inc. term loan. |
(10) | Excludes amounts classified as held for sale at December 31, 2020. See Note 3. |
(11) | Represents the valuation of certain fair value hedges associated with Dominion Energy’s fixed rate debt. |
(12) | Includes $20At December 31, 2020, includes $22 million of estimated mandatory prepayments due within one year based on estimated cash flows in excess of debt service at SBL Holdco and Dominion Solar Projects III, Inc. |
Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2019,2021, were as follows: | | 2022 | | | 2023 | | | 2024 | | | 2025 | | | 2026 | | | Thereafter | | | Total | | (millions, except percentages) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Virginia Power | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Unsecured Senior Notes | | $ | 300 | | | $ | 700 | | | $ | 350 | | | $ | 350 | | | $ | 1,150 | | | $ | 10,388 | | | $ | 13,238 | | Tax-Exempt Financings | | | — | | | | — | | | | — | | | | — | | | | — | | | | 625 | | | | 625 | | Total | | $ | 300 | | | $ | 700 | | | $ | 350 | | | $ | 350 | | | $ | 1,150 | | | $ | 11,013 | | | $ | 13,863 | | Weighted-average Coupon | | | 3.45 | % | | | 2.75 | % | | | 3.45 | % | | | 3.10 | % | | | 3.08 | % | | | 4.16 | % | | | | | Dominion Energy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Term Loans | | $ | 151 | | | $ | 134 | | | $ | 2,215 | | | $ | — | | | $ | — | | | $ | — | | | $ | 2,500 | | First Mortgage Bonds | | | — | | | | — | | | | — | | | | — | | | | — | | | | 3,634 | | | | 3,634 | | Unsecured Senior Notes | | | 650 | | | | 2,700 | | | | 690 | | | | 2,000 | | | | 2,257 | | | | 20,779 | | | | 29,076 | | Secured Senior Notes | | | 6 | | | | 17 | | | | 31 | | | | 19 | | | | 20 | | | | 221 | | | | 314 | | Tax-Exempt Financings | | | — | | | | — | | | | — | | | | — | | | | — | | | | 775 | | | | 775 | | Unsecured Junior Subordinated Notes Payable to Affiliated Trusts | | | — | | | | — | | | | — | | | | — | | | | — | | | | 10 | | | | 10 | | Unsecured Junior Subordinated Notes | | | — | | | | — | | | | 700 | | | | — | | | | — | | | | — | | | | 700 | | Enhanced Junior Subordinated Notes | | | — | | | | — | | | | — | | | | — | | | | — | | | | 685 | | | | 685 | | Total | | $ | 807 | | | $ | 2,851 | | | $ | 3,636 | | | $ | 2,019 | | | $ | 2,277 | | | $ | 26,104 | | | $ | 37,694 | | Weighted-average Coupon | | | 2.79 | % | | | 1.89 | % | | | 2.20 | % | | | 3.01 | % | | | 2.82 | % | | | 4.26 | % | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (millions, except percentages) | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | | | | % | | | | % | | | | | | | | % | | | | % | | | | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | | | | | | | | | | | | % | | | | % | | | | % | | | | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Unsecured senior notes (2)(3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Unsecured junior subordinated notes payable | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Unsecured junior subordinated notes | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Enhanced junior subordinated notes (4) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | | | | % | | | | | | | | % | | | | | | | | | | | | % | | | | |
(1) | Excludes mandatory prepayments associated with SBL Holdco and Dominion Solar Projects III, Inc. based on cash flows in excess of debt service. At December 31, 2019, $20 million of estimated mandatory prepayments due within one year were included in securities due within one year in Dominion Energy’s Consolidated Balance Sheets. |
(2) | In January 2020, SCANA provided notice to redeem its floating rate senior notes at the remaining principal outstanding of $66 million plus accrued interest in March 2020. The notes would have otherwise matured in June 2034. |
(3) | In February 2020, SCANA provided notice to redeem the remaining principal outstanding of $183 million of its 4.75% medium-term notes and $155 million of its 4.125% medium-term notes plus accrued interest and make-whole premiums in March 2020. The notes would have otherwise matured in May 2021 and February 2022, respectively.
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(4) | In February 2020, Dominion Energy purchased and cancelled the remaining $111 million and $286 million of its June 2006 hybrids and September 2006 hybrids, respectively, both of which would have otherwise matured in 2066. As such, these borrowings are presented within current liabilities in Dominion Energy’s Consolidated Balance Sheets at December 31, 2019.
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Combined Notes to Consolidated Financial Statements, Continued
The Companies’ short-term credit facility and long-term debt agreements contain customary covenants and default provisions. As of December 31, 2019,2021, there were no events of default under these covenants. IssuancesIn November 2018January 2022, Virginia Power issued $600 million of 2.40% senior notes and December 2018, Dominion Energy redeemed the following outstanding series$400 million of 2.95% senior notes: 2011 Series A 4.45% Senior Notes due 2021, 2014 Series B 2.50% Senior Notes due 2019, 2014 Series C 3.625% Senior Notes due 2024notes that mature in 2032 and 2018 Series A Floating Rate Senior Notes due 2020 with an aggregate outstanding principal of $2.2 billion.2051, respectively. The aggregate redemption price paid was $2.2 billion and represents the principal amount outstanding, accrued and unpaid interest and the applicable make-whole premium of $34 million. Total charges of $69 million, including the make-whole premium,proceeds were recognized and recorded in interest expense in Dominion Energy’s Consolidated Statements of Income. used for general corporate purposes and/or to repay short-term debt.Enhanced Junior Subordinated Notes In June 2006 and September 2006, Dominion Energy issued $300 million of June 2006 hybrids and $500 million of September 2006 hybrids, respectively. The June 2006 hybrids and the September 2006 hybrids bore interest at the three-month LIBOR plus 2.825%, reset quarterly and at the three-month LIBOR plus 2.3%, reset quarterly, respectively. Dominion Energy executed RCCs in connection with its issuance of the June 2006 hybrids and the September 2006 hybrids. Under the terms of the RCCs, redemptions of the hybrids were subject to certain conditions. In 2019, Dominion Energy purchased and cancelled $12 million and $13 million of its June 2006 hybrids and September 2006 hybrids, respectively. In February 2020, Dominion Energy purchased and cancelledredeemed the remaining $111 million and $286 million of its June 2006 hybrids and September 2006 hybrids, respectively, both of which would have otherwise matured in 2066. All purchases were conducted in compliance with the applicable RCC, each of which was terminated in February 2020. Expenses related to the early redemption of the hybrids were $10 million reflected within interest and related charges in the Consolidated Statements of Income for the year ended December 31, 2020.In October 2014, Dominion Energy issued $685 million of October 2014 hybrids that will bear interest at 5.75% per year until October 1, 2024. Thereafter, they will bear interest at the three-month LIBOR plus 3.057%, reset quarterly. If the three-month LIBOR is terminated while the October 2014 hybrids are outstanding, they will thereafter bear interest at the last interest rate determined prior to the termination.
In July 2016, Dominion Energy issued $800 million of 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. Expenses related to the early redemption of the hybrids were $23 million reflected within interest and related charges in the Consolidated Statements of Income for the year ended December 31, 2021.Dominion Energy may defer interest payments on the hybrids on one or more occasions for up to 10 consecutive years. If the interest payments on the hybrids are deferred, Dominion Energy may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments during the deferral period. Also, during the deferral period, Dominion Energy may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the hybrids. Remarketable Subordinated Notes In July 2014, Dominion Energy issued $1.0 billion of 2014 Series A 6.375% Equity Units, initially in the form of Corporate Units. In August 2016, Dominion Energy issued $1.4 billion of 2016 Series A 6.75% Equity Units, initially in the form of Corporate
Units. The Corporate Units were listed on the NYSE under the symbols DCUC and DCUD, respectively.
Each 2014 Series A Corporate Unit consisted of a stock purchase contract and 1/20 interest in a RSN issued by Dominion Energy. Each 2016 Series A Corporate Unit consisted of a stock purchase contract, a 1/40 interest in a 2016 SeriesA-1
RSN issued by Dominion Energy and a 1/40 interest in a 2016 SeriesA-2
RSN issued by Dominion Energy. 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. The purchase price paid under the stock purchase contracts was $50 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.In May 2017, Dominion Energy successfully remarketed the $1.0 billion 2014 Series A 1.50% RSNs due 2020 pursuant to the terms of the related 2014 Equity Units. In connection with the remarketing, the interest rate on the junior subordinated notes was reset to 2.579%, payable on a semi-annual basis and Dominion Energy ceased to have the ability to redeem the notes at its option or defer interest payments.
In June 2019, Dominion Energy successfully remarketed the $700 million 2016 Series A-1 2.0% RSNs due 2021 and $700 million 2016 Series A-2 2.0% RSNs due 2024 pursuant to the terms of the related 2016 Equity Units. In connection with the remarketing, the interest rates on the Series A-1 and Series A-2 notes were reset to 2.715% and 3.071%, respectively, payable on a semi-annual basis, and Dominion Energy ceased to have the ability to redeem the notes at its option or defer interest payments. At December 31, 2019, the securities are included in junior subordinated notes in Dominion Energy’s Consolidated Balance Sheets. Dominion Energy did not receive any proceeds from the remarketings.remarketing. Remarketing proceeds belonged to the investors holding the related equity units2016 Equity Units and were temporarily used to purchase a portfolio of treasury securities. Upon maturity of eachthe portfolio, the proceeds were applied on behalf of the investors on the related stock purchase contract settlement date to pay the purchase price to Dominion Energy for issuance of 12.5 million shares of its common stock in July 2017 and 18.5 million shares of its common stock in August 2019. NoteDerivative Restructuring In June 2020, Dominion Energy amended a portfolio of interest rate swaps with a notional value of $2.0 billion, extending the mandatory termination dates from 2020 and 2021 to December 2024. As a result of this noncash financing activity with an embedded interest rate swap, Dominion Energy recorded $326 million in other long-term debt representing the net present value of the initial fair value measurement of the new contract with an imputed interest rate of 1.19%, in its Consolidated Balance Sheets with an embedded interest rate derivative that had a fair value of zero at inception. In August 2021, Dominion Energy settled certain of the outstanding interest rate swaps which would have otherwise matured in December 2024, resulting in a $39 million reduction in other long-term debt. In August 2020, Virginia Power amended a portfolio of interest rate swaps with a notional value of $900 million, extending the mandatory termination dates from 2020 to December 2023. As a result of this noncash financing activity with an embedded interest rate swap, Virginia Power recorded $443 million in other long-term debt representing the net present value of the initial fair value measurement of the new contract with an imputed interest rate of 0.34%, in its Consolidated Balance Sheets with an embedded interest rate derivative that had a fair value of zero at inception. The interest rate swaps were in a hedge relationship prior to the transaction. Virginia Power de-designated the hedge relationships prior to the transaction and then designated the new interest rate swap in a hedge relationship after the transaction. NOTE 19. Preferred Stock PREFERRED STOCKDominion Energy is authorized to issue up to 20 million shares of preferred stock,which may be designated into separate classes. At December 31, 2019,2021, Dominion Energy had issued and outstanding 3.4 million shares of preferred stock, 1.6 million, 0.8 million and 1.0 million of which were designated as the Series A Preferred Stock, the Series B Preferred Stock and the Series C Preferred Stock, respectively. At December 31, 2020, Dominion Energy had issued and outstanding 2.4 million shares preferred stock, 1.6 million and 0.8 million of which were designated as the Series A Preferred Stock and the Series B Preferred Stock, respectively. No shares of preferred stock were outstanding at December 31, 2018. DESC is authorized to issue up to 20 million shares of preferred stock. At both December 31, 2019,2021 and 2020, DESC had issued and outstanding 1,000 shares of preferred stock, all of which were held by SCANA and are eliminated in consolidation.
Virginia Power is authorized to issue up to 10 million shares of preferred stock, $100 liquidation preference; however, 0ne were issued and outstanding at December 31, 2021 or 2020. 2019 Corporate Units In June 2019, Dominion Energy issued $1.6 billion of 2019 Equity Units, initially in the form of 2019 Series A Corporate Units. The Corporate Units are listed on the NYSE under the symbol DCUE. The net proceeds were used for general corporate purposes and to repay short-term debt, including commercial paper.
Each 2019 Series A Corporate Unit consists of a stock purchase contract and a 1/10, or 10%, undivided beneficial ownership interest in one share of Series A Preferred Stock. Beginning in June 2022, the Series A Preferred Stock is convertible at the option of the holder into Dominion Energy common stock under a formula based upon the average closing price of Dominion Energy common stock prior to the conversion date. The Series A Preferred Stock is redeemable in cash by Dominion Energy beginning September 2022 at the liquidation preference. Settlement of any conversion is payable in cash, common stock or a combination thereof, at Dominion Energy’s election. In November 2021, Dominion Energy’s Articles of Incorporation were amended to require that any conversion of its Series A Preferred Stock be settled, at Dominion Energy’s election, either entirely in cash or in cash up to the first $1,000 per share and in shares of Dominion Energy common stock, cash or any combination thereof for any amounts in excess of $1,000 per share. As a result of establishing a minimum amount to be settled in cash if the holders elect to convert the Series A Preferred Stock, $1.6 billion was reclassified from equity to mezzanine equity in 2021.The stock purchase contracts obligate the holders to purchase shares of Dominion Energy common stock in June 2022. The purchase price to be paid under the stock purchase contracts is $100 per Corporate Unit and the number of shares to be purchased will be determined under a formula based upon the average closing price of Dominion Energy common stock near the settlement date. The Series A Preferred Stock was pledged upon issuance as collateral to secure the purchase of common stock under the related stock purchase contracts. Dominion Energy pays cumulative dividends on the Series A Preferred Stock and quarterly contract adjustment payments on the stock purchase contracts, at the rates described below. Dominion Energy may elect to pay such dividends and/or payments in cash, shares of Dominion Energy common stock or a combination of cash and shares of Dominion Energy common stock. Dominion Energy may defer the contract adjustment payments for one or more consecutive periods but generally not beyond the purchase contract settlement date. If payments are deferred, Dominion Energy may not make any distributions related to its capital stock, including dividends, redemptions, repurchases or liquidation payments. Also, during the deferral period, Dominion Energy may not make any payments on or redeem, repay or repurchase any debt securities that are equal in right of payment with, or subordinated to, the contract adjustment payments or make any payment on any guarantee of a security of a subsidiary if the guarantee ranks equal or junior to the contract adjustment payments. Unless all accumulated and unpaid dividends on the Series A Preferred Stock have been declared and paid, Dominion Energy may not make any distributions on any of its capital stock ranking equal or junior to the Series A Preferred Stock as to dividends or upon liquidation, as applicable, including dividends, redemptions, repurchases or liquidation payments. In such circumstances, Dominion Energy also may not make any contract adjustment payments or other similar types of payments, subject to certain exceptions. Pursuant to the terms of the 2019 Equity Units, Dominion Energy has recordedexpects to remarket shares of Series A Preferred Stock during the present valuefirst or second quarter of 2022. Following a successful remarketing, the dividend rate on the preferred stock will be reset and the conversion rate on the preferred stock may increase depending on the closing price of Dominion Energy’s common stock on the date of the stock purchase contract paymentsremarketing. Dominion Energy will not directly receive any proceeds from the remarketing as a liability offset to common stock. Stock purchase contract payments are recorded against this liability. Accretionthe remarketing will be conducted on behalf of investors that, as of the stockremarketing, continue to hold corporate units or otherwise elect to participate in the remarketing. Proceeds from the remarketing attributable to investors that continue to hold corporate units will be used to purchase contract liability is recorded as imputed interest expense. In calculating diluted EPS,a treasury portfolio that upon maturity will be used in June 2022 to pay the purchase price to Dominion Energy applies the treasuryfor issuance of its common stock method tounder the stock purchase contracts and the if-converted
method to the Series A Preferred Stock.that are a component of such corporate units. Under the terms of the stock purchase contracts, assuming no anti-dilution or other adjustments, the maximum number of shares of common stock Dominion Energy will issue in June 2022 is 21.8 million.million for consideration of $1.6 billion.Selected information about Dominion Energy’s 2019 Equity Units is presented below: Issuance Date | | Units Issued | | Total Net Proceeds(1) | | | Total Preferred Stock(2) | | | Cumulative Dividend Rate | | | Stock Purchase Contract Annual Rate | | | Stock Purchase Contract Liability(3) | | | Stock Purchase Contract Settlement Date | (millions except interest rates) | | | | | | | | | | | | | | | | | | | | | | | 6/14/2019 | | 16 | | $ | 1,582 | | | $ | 1,610 | | | | 1.75 | % | | | 5.5 | % | | $ | 250 | | | 6/1/2022 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (millions except interest rates) | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | % | | | | % | | | | | | | | |
(1) | Issuance costs of $28 million were recorded as a reduction to preferred stock ($14 million) and common stock ($14 million) in the Consolidated Balance Sheets. |
(2) | Dominion Energy recorded dividends of $15 million ($9.479 per share) for the year ended December 31, 2019. |
(3) | Payments of $38 million were made in 2019. The stock purchase contract liability was $212 million at December 31, 2019. |
(1) Issuance costs of $28 million were recorded as a reduction to preferred stock ($14 million) and common stock ($14 million).In connection with the reclassification of the Series A Preferred Stock to mezzanine equity in 2021, the issuance costs originally recognized as a reduction to preferred stock were reclassified to common stock. (2)Dominion Energy recorded dividends of $28 million ($17.50 per share), $28 million ($17.50 per share) and $15 million ($9.479 per share) for the years ended December 31, 2021, 2020 and 2019, respectively. (3) Payments of $85 million, $83 million and $38 million were made in 2021, 2020 and 2019, respectively. The stock purchase contract liability was $44 million and $129 million at December 31, 2021 and 2020, respectively. Series B Preferred Stock In December 2019, Dominion Energy issued 800,000 shares of Series B Preferred Stock for $791 million, net of $9 million of issuance costs. The preferred stock has a liquidation preference of $1,000 per share and currently pays a 4.65% dividend per share on
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 the yearyears ended December 31, 2019.2021 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 tributionsdistributions on any of its capital stock ranking equal or junior to the Series B Preferred Stock as to dividends or upon liquidation, including through dividends, redemptions, repurchases or otherwise.
Dominion Energy may, at its option, redeem the Series B Preferred Stock in whole or in part on December 15, 2024 or on any subsequent fifth anniversary of such date at a price equal to $1,000 per share plus any accumulated and unpaid dividends. Dominion Energy may also, at its option, redeem the Series B Preferred Stock in whole but not in part at a price equal to $1,020 per share plus any accumulated and unpaid dividends at any time within a certain period of time following any change in the criteria ratings agencies use to assign equity credit to securities such as the Series B Preferred Stock that has certain adverse effects on the equity credit actually received by the Series B Preferred Stock.
Combined Notes to Consolidated Financial Statements, Continued
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. Virginia Power is authorized to issue up to 10 millionSeries C Preferred Stock In December 2021, Dominion Energy issued 750,000 shares of Series C Preferred Stock for $742 million, net of $8 million of issuance costs. Also in December 2021, Dominion Energy issued 250,000 shares of Series C Preferred Stock valued at $250 million to the qualified benefit pension plans. See Note 22 for further information regarding activity surrounding pension plan contributions. The preferred stock $100has a liquidation preference; however, 0ne were issuedpreference of $1,000 per share and outstanding atcurrently pays a 4.35% dividend per share on the liquidation preference. Dividends are paid cumulatively on a semi-annual basis, commencing April 15, 2022. Dominion Energy recorded dividends of $3 million ($2.6583 per share) for the year ended December 31, 20192021. The dividend rate for the Series C Preferred Stock will be reset every five years beginning on April 15, 2027 to equal the then-current five-year U.S. Treasury rate plus a spread of 3.195%. Unless all accumulated and unpaid dividends on the Series C Preferred Stock have been declared and paid, Dominion Energy may not make any distributions on any of its capital stock ranking equal or 2018. Notejunior 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 During 2019, 20182021, 2020 and 2017,2019, Dominion Energy recorded, net of fees and commissions, $11.0 billion, $2.5 billion$340 million, $481 million and $1.3$11.0 billion from the issuance of approximately 1574 million, 367 million and 17157 million shares of common stock, respectively, for acquisitions, pension plan contributions, settlements of stock purchase contracts and litigation and through various programs including Dominion Energy Direct ® , employee savings plans and an at-the-market program. During 2019, Dominion Energy issued 95.6 million shares of common stock in connection with the acquisition of SCANA. At the time of issuance, these common stock shares were valued at $6.8 billion. See Note 3 for further information on the issuance of Dominion Energy common stock in connection with the SCANA Combination.
In January 2019, Dominion Energy and Dominion Energy Midstream closed on an agreement and plan of merger pursuant to which Dominion Energy acquired each outstanding common unit representing limited partner interests in Dominion Energy Midstream not already owned by Dominion Energy through the issuance of 22.5 million shares of common stock valued at $1.6 billion. Under the terms of the agreement and plan of merger, each publicly held outstanding common unit representing limited partner interests in Dominion Energy Midstream was converted into the right to receive 0.2492 shares of Dominion Energy common stock. Immediately prior to the closing, each Series A Preferred Unit representing limited partner interests in Dominion Energy Midstream was converted into common units representing limited partner interests in Dominion Energy Midstream in accordance with the terms of Dominion Energy Midstream’s partnership agreement. The merger was accounted for by Dominion Energy following the guidance for a change in a parent company’s ownership interest in a consolidated subsidiary. Because Dominion Energy controls Dominion Energy Midstream both before and after the merger, the changes in Dominion Energy’s ownership interest in Dominion Energy Midstream were accounted for as an equity transaction and no0 gain or loss was recognized. In connection with the merger, Dominion Energy recognized $40 million of income taxes in equity primarily attributable to establishing additional regulatory liabilities related to excess deferred income taxes and changes in state income taxes. Subsequent to this activity, as a result of the Dominion Energy Gas Restructuring, Dominion Energy Gas is considered to have acquired all of the outstanding partnership interests of Dominion Energy Midstream and Dominion Energy Midstream became a wholly-owned subsidiary of Dominion Energy Gas.
Pension Plan Contribution In December 2019, Dominion Energy contributed 6.1 million shares of its common stock valued at $499 million to the qualified defined benefit pension plans. See Note 22 for further information regarding activity surrounding pension plan contributions. and Employee Savings PlansDominion 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. Currently,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 2019,2021, Dominion Energy received cash of $309 million from the issuance of 4.0issued 2.6 million of such shares through Dominion Energy Direct®
and employee savings plans. received proceeds of $192 million.Stock Purchase Contracts In August 2019, Dominion Energy issued 18.5 million shares under the related stock purchase contracts entered into as part of Dominion Energy’s 2016 Equity Units and received proceeds of $1.4 billion. 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. Other Issuances In June 2017,July 2021, Dominion Energy filed an SEC shelf registrationissued 1.4 million shares of its common stock, valued at $104 million, to satisfy DESC’s obligation under a settlement agreement for the saleFILOT litigation discussed in Note 23. In August 2021, Dominion Energy issued 0.6 million shares of debt and equity securities including the ability to sellits common stock, through an at-the-market
program. Also,valued at $45 million, to satisfy DESC’s obligation for the initial payment under a settlement agreement with the SCDOR discussed in June 2017,Note 23.In September 2020, Dominion Energy issued 4.1 million shares of its common stock to satisfy its obligation under a settlement agreement for the Santee Cooper Ratepayer Case discussed in Note 23. These shares were immediately repurchased as discussed below. At-the-Market Program In February 2018, Dominion Energy entered into three separate sales agency agreements to effect sales under the program and pursuant to which it may offer from time to time up to $500 million aggregate amount of its common stock. Sales of common stock can be made by means of privately negotiated transactions, as transactions on the NYSE at market prices or in such other transactions as are agreed upon by Dominion Energy and the sales agents in conformance with applicable securities laws. In January 2018, Dominion Energy provided sales instructions to one of the sales agents and issued 6.6 million shares through an at-the-market issuances and received cash proceeds of $495 million, net of fees and commissions paid of $5 million. Following these issuances, Dominion Energy had no remaining ability to issue stock under the 2017 sales agency agreements and completed the program. In February 2018, Dominion Energy entered into six separate sales agency agreements to effect sales under a newat-the-market
program pursuant to which it may offer from time to time up to $1.0 billion aggregate amount of its common stock. These agreements replaced the sales agency agreements entered into by Dominion Energy in June 2017. Sales of common stock can be made by means of private negotiated transactions, as transactions
on the NYSE at market prices or in such other transactions as are agreed upon by Dominion Energy and the sales agents in conformance with applicable securities laws. In the fourth quarter of 2018, Dominion Energy provided sales instructions to two of the sales agents and issued 2.7 million shares throughat-the-market
issuances and received cash proceeds of $197 million, net of fees and commissions paid of $2 million. In the first quarter of 2019, Dominion Energy provided sales instructions to one of the sales agents and issued 2.1 million shares and received cash proceeds of $154 million, net of fees and commissions paid of $2 million. In the fourth quarter of 2019, Dominion Energy provided sales instructions to two of the sales agents and issued 7.8 million shares and received cash proceeds of $639 million, net of fees and commissions paid of $6 million. Following these issuances, Dominion Energy had no remaining ability to issue stockcapacity under the 2018 sales agency agreements and completed thethis program. In 2018,March 2020, Dominion Energy entered into separatesales agency agreements to effect sales under a $500 million at-the-market common stock program. Dominion Energy did 0t issue any shares under this program which expired in June 2020. In August 2020, Dominion Energy entered into sales agency agreements to effect sales under a new at-the-market program. Under the sales agency agreements, Dominion Energy may, from time to time, offer and sell shares of its common stock through the sales agents
or enter into one or more forward sale agreements with Goldman Sachs & Co. LLC and Credit Suisse Capital LLC, asrespect to shares of its common stock. Sales by Dominion Energy through the sales agents or by forward purchasers, and an underwritingsellers pursuant to a forward sale agreement with Credit Suisse Securities (USA) LLC and Goldman Sachs & Co. LLC, as representatives ofcannot exceed $1.0 billion in the several underwriters named therein, relating to an aggregate of 20aggregate. In November 2021, Dominion Energy entered forward sale agreements for approximately 1.1 million shares of its common stock to be settled by November 2022 at an initial forward price of $74.66 per share. Except in certain specified circumstances that would require physical share settlement, Dominion Energy common stock. The underwriting agreement granted the underwriters a30-day
option to purchase up to an additional three million sharesmay elect physical, cash or net share settlement of Dominion Energy common stock, which the underwriters exercised with respect to approximately 2.1 million shares in April 2018. Dominion Energy entered into separate forward sale agreements with the forward purchasers with respect to the additional shares. In December 2018, Dominion Energy received proceeds of $1.4 billion (after deducting underwriting discounts, but before deducting expenses, and subject to forward price adjustments under the forward sale agreements) upon theagreements. A net share settlement could require us to deliver a number of shares significantly lower than would be issued in connection with a full physical settlement of 22.1 million shares. settlement.
Repurchase of Common Stock
Dominion Energy did not0t repurchase any shares in 20192021 or 2018 and does not plan to repurchase shares during 2020,2019, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which do not count against its stock repurchase authorization. During 2020, Dominion Energy repurchased 38.9 million shares of Dominion Energy common stock for $3.1 billion through an open market agreement, a private transaction and accelerated share repurchase agreements as discussed below.In July 2020, in contemplation of Dominion Energy entering the July 2020 agreement to sell substantially all of its gas transmission and storage operations to BHE, the Board of Directors authorized the repurchase of up to $3.0 billion of Dominion Energy’s common stock and rescinded its prior repurchase authorization approved in February 2005 and modified in June 2007. Dominion Energy completed repurchases under this authorization in December 2020. In November 2020, the Board of Directors authorized the repurchase of up to $1.0 billion of Dominion Energy’s common stock in addition to the repurchase program authorized in July 2020. This repurchase program does not include a specific timetable or price or volume targets and may be modified, suspended or terminated at any time. Shares may be purchased through open market or privately negotiated transactions or otherwise at the discretion of management subject to prevailing market conditions, applicable securities laws and other factors. In August 2020, Dominion Energy began repurchasing shares under an open market agreement with a financial institution. During the third quarter of 2020, Dominion Energy repurchased 7.2 million shares of Dominion Energy common stock for $562 million. During the fourth quarter of 2020, Dominion Energy repurchased 3.7 million shares of Dominion Energy common stock for $295 million. In September 2020, Dominion Energy repurchased 4.1 million shares of Dominion Energy common stock in a private transaction for $323 million. In September 2020, Dominion Energy entered into 2 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, 20182021, 2020 and 2017,2019, Virginia Power did not issue any shares of its common stock to Dominion Energy. Noncontrolling Interests
GT&S Transaction Closing
In November 2020, as part of the GT&S Transaction, Dominion Energy sold a 25% controlling interest in Cove Point to BHE resulting in Dominion Energy’s remaining 50% noncontrolling interest accounted for as an equity method investment prospectively.
As a result, the $1.4 billion of noncontrolling interest related to the 25% interest in Cove Point held by Brookfield was reversed. See Notes 3 and 9 for further information on the GT&S Transaction and Dominion Energy’s equity method investment in Cove Point. Sale of Interest in Cove Point
In December 2019, Dominion Energy completed the sale of its 25% noncontrolling limited partnership interest in Cove Point to Brookfield in exchange for cash consideration of $2.1 billion, subject to working capital adjustments. See Note 3 for further information on the sale of this interest.
Remeasurement ofNon-Wholly-Owned Nonregulated Solar Facilities In December 2021, Dominion Energy Midstream Units In May 2018, allcompleted the sale of SBL Holdco, which held Dominion Energy’s 67% controlling interest in certain nonregulated solar projects, and the subordinated unitssale of Dominion Energy Midstream held by Dominion Energy were converted into common units on a 1:1 ratio following the payment of Dominion Energy Midstream’s distribution for the first quarter of 2018. In
June 2018, Dominion Energy, as general partner, exercised an incentive distribution right reset as definedits 50% controlling interest in Dominion Energy Midstream’s partnership agreementFour Brothers and received 27 million common units representing limited partner interests in Dominion Energy Midstream.Three Cedars. As a result of the increase in its ownership interest in Dominion Energy Midstream, Dominion Energythese sales, all balances recorded a decrease inas noncontrolling interest, and a corresponding increase in shareholders’ equity, of $375 million reflecting the change in the carrying value of the interest in the net assets of Dominion Energy Midstream held by others.interests associated with these entities were written off. See Note 10 for more information.
Accumulated Other Comprehensive Income (Loss) Presented in the table below is a summary of AOCI by component:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net deferred losses on derivatives-hedging activities, net of $135 and $79 tax | | $ | | ) | | $ | | ) | Net unrealized gains on nuclear decommissioning trust funds, net of $(13) and $— tax | | | | | | | | | Net unrecognized pension and other postretirement benefit costs, net of $492 and $519 tax | | | | ) | | | | ) | Other comprehensive loss from equity method investees, net of $1 and $— tax | | | | ) | | | | ) | Total AOCI, including noncontrolling interests | | $ | | ) | | $ | | ) | Less other comprehensive income attributable to noncontrolling interests | | | | | | | | | Total AOCI, excluding noncontrolling interests | | $ | | ) | | $ | | ) | | | | | | | | | | Net deferred losses on derivatives-hedging activities, net of $11 and $4 tax | | $ | | ) | | $ | | ) | Net unrealized gains on nuclear decommissioning trust funds, net of $(1) and $— tax | | | | | | | | | | | $ | | ) | | $ | | ) | | | | | | | | | | Net deferred losses on derivatives-hedging activities, net of $28 and $8 tax | | $ | | ) | | $ | | ) | Net unrecognized pension costs, net of $41 and $56 tax | | | | ) | | | | ) | Total AOCI, including noncontrolling interests | | | | ) | | | | ) | Less other comprehensive income (loss) attributable to noncontrolling interests | | | | ) | | | | | Total AOCI, excluding noncontrolling interests | | $ | | ) | | $ | | ) |
Combined Notes to Consolidated Financial Statements, Continued
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 | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2019 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | | Other comprehensive income before reclassifications: gains (losses) | | | | | | | | | | | | | | | | | | | | | Amounts reclassified from AOCI: (gains) losses (1) | | | | | | | | | | | | | | | | | | | | | Net current period other comprehensive income (loss) | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | ) | | | | ) | | | | ) | Year Ended December 31, 2018 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | Other comprehensive income before reclassifications: gains (losses) | | | | | | | | ) | | | | | | | | | | | | ) | Amounts reclassified from AOCI: (gains) losses (1) | | | | | | | | | | | | | | | | | | | | | Net current period other comprehensive income (loss) | | | | | | | | | | | | | | | | | | | | | Cumulative-effect of changes in accounting principle | | | | | | | | | | | | | | | | | | | | ) | Less other comprehensive income (loss) attributable to noncontrolling interests | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) |
(1) | See table below for details about these reclassifications. |
The following table presents Dominion Energy’stax) and reclassifications out of AOCI by component: | | Commodity | | | | | Interest Rate | | | | | Foreign Currency | | | | | Total Derivative-Hedging Activities(1) | | | | | Investment Securities(2) | | | | | Pension and other postretirement benefit costs(3) | | | | | Equity Method Investees(4) | | | | | Total | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2021 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Beginning balance | | $ | (1 | ) | | | | $ | (418 | ) | | | | $ | — | | | | | $ | (419 | ) | | | | $ | 62 | | | | | $ | (1,359 | ) | | | | $ | (1 | ) | | | | $ | (1,717 | ) | Other comprehensive income before reclassifications: gains (losses) | | | — | | | | | | 15 | | | | | | — | | | | | | 15 | | | | | | (7 | ) | | | | | 144 | | | | | | (3 | ) | | | | | 149 | | Amounts reclassified from AOCI: (gains) losses | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Purchased gas | | | 1 | | | | | | — | | | | | | — | | | | | | 1 | | | | | | — | | | | | | — | | | | | | — | | | | | | 1 | | Interest and related charges | | | — | | | | | | 60 | | | | | | — | | | | | | 60 | | | | | | — | | | | | | — | | | | | | — | | | | | | 60 | | Other income | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | (23 | ) | | | | | 111 | | | | | | — | | | | | | 88 | | Total | | | 1 | | | | | | 60 | | | | | | — | | | | | | 61 | | | | | | (23 | ) | | | | | 111 | | | | | | — | | | | | | 149 | | Income tax expense | | | — | | | | | | (15 | ) | | | | | — | | | | | | (15 | ) | | | | | 5 | | | | | | (29 | ) | | | | | — | | | | | | (39 | ) | Total, net of tax | | | 1 | | | | | | 45 | | | | | | — | | | | | | 46 | | | | | | (18 | ) | | | | | 82 | | | | | | — | | | | | | 110 | | Net current period other comprehensive income (loss) | | | 1 | | | | | | 60 | | | | | | — | | | | | | 61 | | | | | | (25 | ) | | | | | 226 | | | | | | (3 | ) | | | | | 259 | | Ending balance | | $ | — | | | | | $ | (358 | ) | | | | $ | — | | | | | $ | (358 | ) | | | | $ | 37 | | | | | $ | (1,133 | ) | | | | $ | (4 | ) | | | | $ | (1,458 | ) | Year Ended December 31, 2020 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Beginning balance | | $ | 16 | | | | | $ | (426 | ) | | | | $ | 3 | | | | | $ | (407 | ) | | | | $ | 37 | | | | | $ | (1,421 | ) | | | | $ | (2 | ) | | | | $ | (1,793 | ) | Other comprehensive income before reclassifications: gains (losses) | | | — | | | | | | (231 | ) | | | | | (8 | ) | | | | | (239 | ) | | | | | 43 | | | | | | 25 | | | | | | 1 | | | | | | (170 | ) | Amounts reclassified from AOCI: (gains) losses | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating revenue | | | (25 | ) | | | | | — | | | | | | — | | | | | | (25 | ) | | | | | — | | | | | | — | | | | | | — | | | | | | (25 | ) | Purchased gas | | | 4 | | | | | | — | | | | | | — | | | | | | 4 | | | | | | — | | | | | | — | | | | | | — | | | | | | 4 | | Discontinued operations | | | (2 | ) | | | | | 236 | | | | | | 6 | | | | | | 240 | | | | | | — | | | | | | — | | | | | | — | | | | | | 240 | | Interest and related charges | | | — | | | | | | 83 | | | | | | — | | | | | | 83 | | | | | | — | | | | | | — | | | | | | — | | | | | | 83 | | Other income | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | (24 | ) | | | | | 50 | | | | | | — | | | | | | 26 | | Total | | | (23 | ) | | | | | 319 | | | | | | 6 | | | | | | 302 | | | | | | (24 | ) | | | | | 50 | | | | | | — | | | | | | 328 | | Income tax expense | | | 6 | | | | | | (80 | ) | | | | | (1 | ) | | | | | (75 | ) | | | | | 6 | | | | | | (13 | ) | | | | | — | | | | | | (82 | ) | Total, net of tax | | | (17 | ) | | | | | 239 | | | | | | 5 | | | | | | 227 | | | | | | (18 | ) | | | | | 37 | | | | | | — | | | | | | 246 | | Net current period other comprehensive income (loss) | | | (17 | ) | | | | | 8 | | | | | | (3 | ) | | | | | (12 | ) | | | | | 25 | | | | | | 62 | | | | | | 1 | | | | | | 76 | | Ending balance | | $ | (1 | ) | | | | $ | (418 | ) | | | | $ | — | | | | | $ | (419 | ) | | | | $ | 62 | | | | | $ | (1,359 | ) | | | | $ | (1 | ) | | | | $ | (1,717 | ) |
(1) | | | | | | | Details about AOCI components
| | Amounts
reclassified
from AOCI
| | | Affected line item in the
Consolidated StatementsNet of
Income | | | | | | | Year Ended $119 million and $141 million tax at December 31, 2019
|
(2) | | | | | | | Deferred (gains)Net of $(10) million and losses on derivatives-hedging activities: | | | | | | | | | | | | | | | | | | | | | | | | | | | Interest and related charges
| Foreign currency contracts
| | | | | | | | | | | ) | | | | | | | | | Income$(21) million tax expense
| | | | | ) | | | Unrealized (gains) and losses on investment securities:
| | | | | | | Realized (gain) loss on sale of securities
| | | | | | | | | | | | | | | | | | | | | | | | | ) | | | Unrecognized pension and other postretirement benefit costs:
| | | | | | | Amortization of prior-service costs (credits)
| | | | | | | Amortization of actuarial losses
| | | | | | | | | | | | | | | | | | ) | | | | | | | | | | Year Endedat December 31, 2018
| | | | | | | Deferred (gains)2021 and losses on derivatives-hedging activities:
| | | | | | | | | | | | | | | | | (14 | ) | | | | | | | | | Interest and related charges
| Foreign currency contracts
| | | | | | | | | | | | | | | | | (35 | ) | | | | | | | | | | Unrealized (gains) and losses on investment securities:
| | | | | | | Realized (gain) loss on sale of securities
| | | | | | | | | | | | | | | | | (2 | ) | | | | | | | | | | Unrecognized pension and other postretirement benefit costs:
| | | | | | | Prior-service costs (credits)
| | | | ) | | | | | | | | | | | | | | | | | | | | (21 | ) | | | | | | | | | 2020, respectively. |
(3) | | | | | | | | | | | | | | | Net of $396 million and $478 million tax at December 31, 2021 and 2020, respectively. |
(4) | Net of $1 million and $— million tax at December 31, 2021 and 2020, respectively. |
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 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2019 | | | | | | | | | | | | | | | | | ) | | $ | | | | | | | Other comprehensive income before reclassifications: gains (losses) | | | | ) | | | | | | | | | Amounts reclassified from AOCI: (gains) losses (1) | | | | | | | | ) | | | | | Net current period other comprehensive income (loss) | | | | ) | | | | | | | | | | | | | ) | | $ | | | | | | | Year Ended December 31, 2018 | | | | | | | | | | | | | | | | | ) | | $ | | | | $ | | | Other comprehensive income before reclassifications: gains (losses) | | | | | | | | | | | | | Amounts reclassified from AOCI: gains (losses) (1) | | | | | | | | | | | | | Net current period other comprehensive income (loss) | | | | | | | | | | | | | Cumulative-effect of changes in accounting principle | | | | ) | | | | ) | | | | | | | | | ) | | $ | | | | $ | | |
(1) | See table below for details about these reclassifications. |
The following table presents Virginia Power’s reclassificationstax) and reclassification out of AOCI by component: | | Interest Rate | | | | | Total Derivative-Hedging Activities(1) | | | | | Investment Securities(2) | | | | | Total | | (millions) | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2021 | | | | | | | | | | | | | | | | | | | | | | | Beginning balance | | $ | (60 | ) | | | | $ | (60 | ) | | | | $ | 8 | | | | | $ | (52 | ) | Other comprehensive income before reclassifications: gains (losses) | | | 13 | | | | | | 13 | | | | | | (2 | ) | | | | | 11 | | Amounts reclassified from AOCI: (gains) losses | | | | | | | | | | | | | | | | | | | | | | | Interest and related charges | | | 3 | | | | | | 3 | | | | | | — | | | | | | 3 | | Other income | | | — | | | | | | — | | | | | | (3 | ) | | | | | (3 | ) | Total | | | 3 | | | | | | 3 | | | | | | (3 | ) | | | | | — | | Income tax expense | | | (1 | ) | | | | | (1 | ) | | | | | 1 | | | | | | — | | Total, net of tax | | | 2 | | | | | | 2 | | | | | | (2 | ) | | | | | — | | Net current period other comprehensive income (loss) | | | 15 | | | | | | 15 | | | | | | (4 | ) | | | | | 11 | | Ending balance | | $ | (45 | ) | | | | $ | (45 | ) | | | | $ | 4 | | | | | $ | (41 | ) | Year Ended December 31, 2020 | | | | | | | | | | | | | | | | | | | | | | | Beginning balance | | $ | (34 | ) | | | | $ | (34 | ) | | | | $ | 5 | | | | | $ | (29 | ) | Other comprehensive income before reclassifications: gains (losses) | | | (28 | ) | | | | | (28 | ) | | | | | 6 | | | | | | (22 | ) | Amounts reclassified from AOCI: (gains) losses | | | | | | | | | | | | | | | | | | | | | | | Interest and related charges | | | 2 | | | | | | 2 | | | | | | — | | | | | | 2 | | Other income | | | — | | | | | | — | | | | | | (4 | ) | | | | | (4 | ) | Total | | | 2 | | | | | | 2 | | | | | | (4 | ) | | | | | (2 | ) | Income tax expense | | | — | | | | | | — | | | | | | 1 | | | | | | 1 | | Total, net of tax | | | 2 | | | | | | 2 | | | | | | (3 | ) | | | | | (1 | ) | Net current period other comprehensive income (loss) | | | (26 | ) | | | | | (26 | ) | | | | | 3 | | | | | | (23 | ) | Ending balance | | $ | (60 | ) | | | | $ | (60 | ) | | | | $ | 8 | | | | | $ | (52 | ) |
(1) | | | | | | | Details about AOCI components
| | Amounts
reclassified
from AOCI
| | | Affected line item in the
Consolidated StatementsNet of
Income | | | | | | | | | | | | | | Year Ended $16 million and $21 million tax at December 31, 2019
|
(2) | | | | | | | (Gains) losses on cash flow hedges:
| | | | | | | | | | | | | InterestNet of $(2) million and related charges | | | | | | | | | | | | | | Income$(3) million tax expense
| | | | | | | | Unrealized (gains) and losses on investment securities:
| | | | | | | Realized (gain) loss on sale of securities
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Endedat December 31, 2018
| | | | | | | (Gains) losses on cash flow hedges:
| | | | | | | | | | | | | Interest2021 and related charges
| | | | | | | | | | | | | | | | | | | | | 2020, respectively. |
The following table presents Dominion Energy Gas’ changes in AOCI by component, net of tax:
| | | | | | | | | | | | | | | Deferred gains
and losses on
derivatives-
hedging
activities | | | Unrecognized
pension and
other
postretirement
benefit costs | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2019 | | | | | | | | | | | | | | | | | ) | | | | ) | | $ | | | Other comprehensive income before reclassifications: gains (losses) | | | | ) | | | | | | | | ) | Amounts reclassified from AOCI: (gains) losses (1) | | | | | | | | | | | | | Net current period other comprehensive income (loss) | | | | ) | | | | | | | | ) | Dominion Energy Gas Restructuring | | | | ) | | | | | | | | ) | Less other comprehensive income attributable to noncontrolling interests | | | | ) | | | | | | | | ) | | | | | ) | | | | ) | | $ | | ) | Year Ended December 31, 2018 | | | | | | | | | | | | | | | | | ) | | | | ) | | $ | | ) | Other comprehensive income before reclassifications: gains (losses) | | | | ) | | | | ) | | | | ) | Amounts reclassified from AOCI: gains (losses) (1) | | | | | | | | | | | | | Net current period other comprehensive income (loss) | | | | | | | | ) | | | | ) | Cumulative-effect of changes in accounting principle | | | | ) | | | | ) | | | | ) | | | | | ) | | | | ) | | | | ) |
(1) | See table below for details about these reclassifications. |
Combined Notes to Consolidated Financial Statements, Continued
The following table presents Dominion Energy Gas’ reclassifications out of AOCI by component:
| | | | | | | Details about AOCI components
| | Amounts
reclassified
from AOCI
| | | Affected line item in the
Consolidated Statements of Income
| | | | | | | | | | | | | | Year Ended December 31, 2019
| | | | | | | Deferred (gains) and losses on derivatives-hedging activities:
| | | | | | | | | | | | | Net income from discontinued operations
| | | | | | | Interest and related charges
| Foreign currency contracts
| | | | | | | | | | | | | | | | | | | | | | | | | | | | Unrecognized pension costs:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2018
| | | | | | | Deferred (gains) and losses on derivatives-hedging activities:
| | | | | | | | | | | | | Net income from discontinued operations
| | | | | | | Interest and related charges
| Foreign currency contracts
| | | | | | | | | | | | | | | | | | | | | | | | | | | | Unrecognized pension costs:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The 2014 Incentive Compensation Plan permits stock-based awards that include restricted stock, performance grants, goal-based stock, stock options and stock appreciation rights. The Non-Employee Directors Compensation Plan permits grants of restricted stock and stock options. Under provisions of these plans, employees and non-employee directors may be granted options to purchase common stock at a price not less than its fair market value at the date of grant with a maximum term of eight years. Option terms are set at the discretion of the 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, 2019,2021, approximately 2119 million shares were available for future grants under these plans. Goal-based stock awards are granted in lieu of cash-based performance grants to certain officers who have not achieved a certain targeted level of share ownership. As of December 31, 2019,2021, unrecognized compensation cost related to nonvested goal-based stock awards was immaterial. Dominion Energy measures and recognizes compensation expense relating to share-based payment transactions over the vesting period based on the fair value of the equity or liability instruments issued. Dominion Energy’s results for the years ended December 31, 2021, 2020 and 2019 2018include $42 million, $64 million and 2017 include $46 million, $48 million and $45 million, respectively, of compensation costs and $11$9 million, $12$16 million and $16$11 million, respectively of income tax benefits related to Dominion Energy’s stock-based compensation arrangements. Stock-based compensation cost is reported in other operations and maintenance expense in Dominion Energy’s Consolidated Statements of Income. Excess Tax Benefits are classified as a financing cash flow.
Restricted stock grants are made to officers under Dominion Energy’s LTIP and may also be granted to certain key non-officer employees. The fair value of Dominion Energy’s restricted stock awards is equal to the closing price of Dominion Energy’s stock on the date of grant. New shares are issued for restricted stock awards on the date of grant and generally vest over a threethree-year-year service period. The following table provides a summary of restricted stock activity for the years ended December 31, 2019, 20182021, 2020 and 2017:2019: | | Shares | | | Weighted - average Grant Date Fair Value | | | | (thousands) | | | | | | Nonvested at December 31, 2018 | | | 1,208 | | | $ | 73.03 | | Granted | | | 614 | | | | 76.49 | | Vested | | | (324 | ) | | | 71.75 | | Cancelled and forfeited | | | (96 | ) | | | 77.16 | | Nonvested at December 31, 2019 | | | 1,402 | | | $ | 74.77 | | Granted | | | 531 | | | | 81.74 | | Vested | | | (424 | ) | | | 74.39 | | Cancelled and forfeited | | | (99 | ) | | | 81.59 | | Nonvested at December 31, 2020 | | | 1,410 | | | $ | 77.41 | | Granted | | | 518 | | | | 71.78 | | Vested | | | (505 | ) | | | 73.54 | | Cancelled and forfeited | | | (113 | ) | | | 75.57 | | Nonvested at December 31, 2021 | | | 1,310 | | | $ | 76.65 | |
| | | | | | | | | | | | | | Weighted—average
Grant Date Fair
Value | | | | | | | | | Nonvested at December 31, 2016 | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | ) | | | | | Nonvested at December 31, 2017 | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | ) | | | | | Nonvested at December 31, 2018 | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | ) | | | | | Nonvested at December 31, 2019 | | | | | | | | |
As of December 31, 2019,2021, unrecognized compensation cost related to nonvested restricted stock awards totaled $59$55 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 $37 million, $35 million and $23 million $23 millionin 2021, 2020 and $21 million in 2019, 2018 and 2017, 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 zero0 and 200% of the targeted amount based on the level of performance metrics achieved.
In February 2017, two2019, a cash-based performance grants weregrant was made to officers as Dominion Energy transitioned from a performance period to a three-year performance period.officers. Payout of the performance grant occurred in January 20192022 based on the achievement of two performance metrics during 20172019, 2020 and 2018:2021: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group and ROIC with an additional partial payout based on Dominion Energy’s price-earnings ratio relative to that of the members of Dominion Energy’s peer compensation peer group. The total payout under the two-year grant was$13 million. Payout
of the three-year performance grant occurred in January 2020 based on the achievement of two performance metrics during 2017, 2018 and 2019: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group and ROIC with an additional partial payout based on Dominion Energy’s price-earnings ratio relative to that of the members of Dominion Energy’s compensation peer group.The
total of the payout under the three-year grant was $13$5.7 million, and a liabilityall of $13 million had beenwhich was accrued for the award.at December 31, 2021.In February 2018,2020, a cash-based performance grant was made to officers. Payout of the performance grant is expected to occur by March 15, 20212023 based on the achievement of two performance metrics during 2018, 20192020, 2021 and 2020:2022: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group and ROIC. There are additional opportunities to earn a portion of the award based on Dominion Energy’s absolute TSR or relative price-earnings ratio performance. At December 31, 2019,2021, the targeted amount of the three-year grant was $15$10 million and a liability of $8$6 million had been accrued for this award. In February 2019,2021, a cash-based performance grant was made to officers. Payout of the performance grant is expected to occur by March 15, 20222024 based on the achievement of two performance metrics during 2019, 20202021, 2022 and 2021:2023: TSR relative to that of companies that are members of Dominion Energy’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, 2019,2021, the targeted amount of the three-year grant was $16$13 million and a liability of $5$4 million had been accrued for this award.
NoteNOTE 21. Dividend Restrictions DIVIDEND RESTRICTIONSThe 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, 2019,2021, the Virginia Commission had not restricted the payment of dividends by Virginia Power. The North Carolina Commission, in its order approving the SCANA Combination, limited cumulative dividends payable to Dominion Energy by Virginia Power and PSNC to (i) the amount of retained earnings 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%. The Ohio Commissionand Utah Commissions may prohibit any public service company, including East Ohio and Questar Gas, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2019,2021, neither the Ohio Commission nor the Utah Commission had not restricted the payment of dividends by East Ohio. Ohio or Questar Gas, respectively.There is no specific restriction from the South Carolina Commission on the payment of dividends paid by DESC. Pursuant to the SCANA Merger Approval Order, the amount of any DESC dividends paid must be reasonable and consistent with the long-term payout ratio of the electric utility industry and gas distribution industry. There is no specific restriction on the payment of dividends by DESC. At December 31, 2019,2021, 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. The Utah Commission may prohibit any public service company, including Questar Gas, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2019, the Utah Commission had not restricted the payment of dividends by Questar Gas.
Certain agreements associated with the Companies’ credit facility contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict the Companies’ abilitypermitted to pay dividends or receive dividends from their subsidiaries at December 31, 2019.
In connection withwithout additional regulatory approval provided that such amounts would not bring the SCANA Combination, underretained earnings balance below the terms of the merger agreement, Dominion Energy could not declare, set aside or pay any dividends on, or make any other distributions (whether in cash, stock or property) in respect of, any of its capital stock, other than regular quarterly cash dividends from January 2018 through January 2019.
As part of the merger agreement with Dominion Energy Midstream from November 2018 through January 2019, Dominion Energy could not declare, set aside or pay any dividends on, or make any other distributions (whether in cash, stock or property) in respect of, any of its capital stock, other than regular quarterly cash dividends.
threshold.See Notes 18 and 19 for a description of potential restrictions on common stock dividend payments by Dominion Energy in connection with the deferral of interest payments on the enhanced junior subordinated notes, the deferral of contract adjustment payments on the 2019 Equity Units or a failure to pay dividends on the Series A Preferred Stock, or Series B Preferred Stock or Series C Preferred Stock. NoteNOTE 22. Employee Benefit Plans EMPLOYEE BENEFIT PLANSDominion 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
Combined Notes to Consolidated Financial Statements, Continued
benefits to certain retired executives under company-sponsored nonqualified employee benefit plans. The nonqualified plans are funded through contributions to grantor trusts. Dominion Energy also provides retiree healthcare and life insurance benefits with annual employee premiums based on several factors such as age, retirement date and years of service. Pension benefits for Dominion Energy Gas employees not represented by collective bargaining units are covered by the Dominion Energy Pension Plan, a defined benefit pension plan sponsored by Dominion Energy that provides benefits to multiple Dominion Energy subsidiaries. Pension benefits for Dominion Energy Gas employees represented by collective bargaining units are covered by a sepa
rate pension plan that provides benefits to employees of both DETI and Hope. Employee compensation is the basis for allocating pension costs and obligations between DETI and Hope.Retiree healthcare and life insurance benefits for Dominion Energy Gas employees not represented by collective bargaining units are covered by the Dominion Energy Retiree Health and Welfare Plan, a plan sponsored by Dominion Energy that provides certain retiree healthcare and life insurance benefits to multiple Dominion Energy subsidiaries. Retiree healthcare and life insurance benefits for Dominion Energy Gas employees represented by collective bargaining units are covered by a sepa
rate other postretirement benefit plan that provides benefits to both DETI and Hope. Employee headcount is the basis for allocating other postretirement benefit costs and obligations between DETI and Hope.Dominion Energy Gas included the separate pension and other postretirement benefit plans for East Ohio employees covered by collective bargaining units through November 2019, the effective date of the Dominion Energy Gas Restructuring. See Note 3 for more information on the Dominion Energy Gas Restructuring.
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 year-to-year volatility. Changes in fair value are measured as the difference between the expected and actual plan asset returns, including dividends, interest and realized and unrealized investment gains and losses. Since the market-related value recognizes changes in fair value over a four-year period, the future market-related value of pension plan assets will be impacted as previously unrecognized changes in fair value are recognized. Dominion Energy’s pension and other postretirement benefit plans hold investments in trusts to fund employee benefit payments. Dominion Energy’s pension and other postretirement plan assets experienced aggregate actual returns (losses) of $2.1$1.5 billion and $(605) million$1.9 billion in 20192021 and 2018,2020, respectively, versus expected returns of $848 million$1.0 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$933 million, respectively. Differences between
actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans. In the fourth quarter of 2021, Dominion Energy recognized the effects of a curtailment for certain pension plans resulting from an option that will provide certain active employees a one-time choice to transition to an enhanced defined contribution plan in lieu of accruing pension benefits for future services. The curtailment resulted in a decrease in the pension benefit obligation of $26 million and an increase to net periodic pension cost of $2 million. The effects of the curtailment are included in the measurement of Dominion Energy’s pension plans as of December 31, 2021. In the third quarter of 2020, Dominion Energy remeasured certain pension plans due to a curtailment resulting from entering an agreement to sell substantially all of its gas transmission and storage operations to BHE. The remeasurement resulted in an increase in the pension benefit obligation of $497 million and a decrease in the fair value of the pension plan assets of $87 million. The impact of the remeasurement on net periodic pension benefit cost (credit) was recognized prospectively from the remeasurement date. The remeasurement increased the net periodic benefit credit by approximately $4 million for the year ending December 31, 2020, excluding the impacts of curtailments. The discount rate used for the remeasurement was 3.11% - 3.16% with all other assumptions used for the remeasurement consistent with the measurement as of December 31, 2019. In the fourth quarter of 2020, Dominion Energy remeasured certain other postretirement benefit plans due to a curtailment and settlement resulting from Dominion Energy completing the GT&S Transaction. The remeasurement resulted in an increase in the accumulated postretirement benefit obligation of $16 million and a decrease in the fair value of the other postretirement benefit plan assets of $25 million. The impact of the remeasurement on net periodic benefit cost (credit) was recognized prospectively from the remeasurement date. The discount rate used for the remeasurement was 3.07% - 3.11%. The initial healthcare cost trend rate used for the remeasurement was 6.25% and decreased to 5.00% by 2025-2026. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2019. Voluntary Retirement Program In March 2019, the Companies announced a voluntary retirement program to employees that meet certain age and service requirements. 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, Dominion Energy recorded a charge of $427 million ($319 million after-tax) included within other operations and maintenance expense ($ 291251 million), other taxes ($ 2421 million), other income ($111 million) and other incomediscontinued operations ($ 11244 million) , and Virginia Power recorded a charge of $198 million ($146 million after-tax) included within other operations and maintenance expense ($190 million) and other taxes ($8 million) 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 thetheir respective Consolidated Statements of Income. In the second quarter of 2019, Dominion Energy and Dominion Energy Gas remeasured theirits pension and other postretirement benefit plans as a result of the voluntary retirement program. The remeasurement resulted in an increase in the pension benefit obligation of $484 million and $32 million and an increase in the fair value of the pension plan assets of $671 million and $146 million for Dominion Energy and Dominion Energy Gas, respectively.million. In addition, the remeasurement resulted in an increase in the accumulated postretirement benefit obligation of $101 million and $8 million and an increase in the fair value of the other postretirement benefit plan assets of $156 million and $29 million for Dominion Energy and Dominion Energy Gas, respectively.million. The impact of the remeasurement on net periodic benefit cost (credit) was recognized prospectively from the remeasurement date. The discount rate used for the remeasurement was 4.07%—4.10% for the Dominion Energy pension plans 4.10% for Dominion Energy Gas pension plans,and 4.05%—4.08% for the Dominion Energy other postretirement benefit plans, and 4.05% for the Dominion Energy Gas other postretirement benefit plans. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2018. In the third quarter of 2019, Dominion Energy remeasured a pension plan as a result of a settlement from the voluntary retirement program at SCANA. The settlement and related remeasurement resulted in an increase in the pension benefit obligation of $37 million and an increase in the fair value of the pension plan assets of $51 million for Dominion Energy. The impact of the remeasurement on net periodic benefit cost (credit) was recognized prospectively from the remeasurement date. The discount rate used for the remeasurement was 3.57%. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2018.
The following table summarizes the changes in pension plan and other postretirement benefit plan obligations and plan assets and includes a statement of the plans’ funded status for Dominion Energy and Dominion Energy Gas (for employees represented by collective bargaining units):Energy: | | Pension Benefits | | | Other Postretirement Benefits | | Year Ended December 31, | | 2021 | | | 2020 | | | 2021 | | | 2020 | | (millions, except percentages) | | | | | | | | | | | | | | | | | Dominion Energy | | | | | | | | | | | | | | | | | Changes in benefit obligation: | | | | | | | | | | | | | | | | | Benefit obligation at beginning of year | | $ | 11,363 | | | $ | 10,446 | | | $ | 1,746 | | | $ | 1,769 | | Service cost | | | 170 | | | | 173 | | | | 25 | | | | 28 | | Interest cost | | | 317 | | | | 351 | | | | 46 | | | | 58 | | Benefits paid | | | (488 | ) | | | (461 | ) | | | (105 | ) | | | (120 | ) | Actuarial (gains) losses during the year | | | (413 | ) | | | 992 | | | | (161 | ) | | | 33 | | Plan amendments | | | — | | | | — | | | | (14 | ) | | | (6 | ) | Settlements and curtailments(1) | | | (59 | ) | | | (138 | ) | | | — | | | | (16 | ) | Benefit obligation at end of year | | $ | 10,890 | | | $ | 11,363 | | | $ | 1,537 | | | $ | 1,746 | | Changes in fair value of plan assets: | | | | | | | | | | | | | | | | | Fair value of plan assets at beginning of year | | $ | 10,979 | | | $ | 9,631 | | | $ | 2,100 | | | $ | 1,880 | | Actual return (loss) on plan assets | | | 1,202 | | | | 1,602 | | | | 294 | | | | 300 | | Employer contributions | | | 284 | | | | 278 | | | | — | | | | 13 | | Benefits paid | | | (488 | ) | | | (461 | ) | | | (71 | ) | | | (93 | ) | Settlements(2) | | | (32 | ) | | | (71 | ) | | | — | | | | — | | Fair value of plan assets at end of year | | $ | 11,945 | | | $ | 10,979 | | | $ | 2,323 | | | $ | 2,100 | | Funded status at end of year | | $ | 1,055 | | | $ | (384 | ) | | $ | 786 | | | $ | 354 | | Amounts recognized in the Consolidated Balance Sheets at December 31: | | | | | | | | | | | | | | | | | Noncurrent pension and other postretirement benefit assets | | $ | 1,246 | | | $ | 1,054 | | | $ | 1,064 | | | $ | 650 | | Other current liabilities | | | (12 | ) | | | (14 | ) | | | (15 | ) | | | (15 | ) | Noncurrent pension and other postretirement benefit liabilities | | | (179 | ) | | | (1,424 | ) | | | (263 | ) | | | (281 | ) | Net amount recognized | | $ | 1,055 | | | $ | (384 | ) | | $ | 786 | | | $ | 354 | | Significant assumptions used to determine benefit obligations as of December 31: | | | | | | | | | | | | | | | | | Discount rate | | 3.06%-3.19% | | | 2.73%–2.95% | | | 3.04%-3.11% | | | 2.69%–2.80% | | Weighted average rate of increase for compensation | | 4.51% | | | 4.53% | | | n/a | | | n/a | | Crediting interest rate for cash balance and similar plans | | 1.81%-1.94% | | | 1.93% - 2.15% | | | n/a | | | n/a | |
| | | | | | | | | | | | | | | | | | | | | | | Other Postretirement Benefits | | | | | | | | | | | | | | | (millions, except percentages) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Changes in benefit obligation: | | | | | | | | | | | | | | | | | Benefit obligation at beginning of year | | $ | | | | $ | | | | $ | | | | $ | | | Dominion Energy SCANA Combination (See Note 3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | | | | ) | Actuarial (gains) losses during the year | | | | | | | | ) | | | | | | | | ) | | | | | | | | | | | | | | | | | ) | Settlements and curtailments (1) | | | | ) | | | | | | | | | | | | | Benefit obligation at end of year | | $ | | | | $ | | | | $ | | | | $ | | | Changes in fair value of plan assets: | | | | | | | | | | | | | | | | | Fair value of plan assets at beginning of year | | $ | | | | $ | | | | $ | | | | $ | | | Dominion Energy SCANA Combination (See Note 3) | | | | | | | | | | | | | | | | | Actual return (loss) on plan assets | | | | | | | | ) | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | | | | ) | | | | | ) | | | | | | | | | | | | | Fair value of plan assets at end of year | | $ | | | | $ | | | | $ | | | | $ | | | Funded status at end of year | | $ | | ) | | $ | | ) | | $ | | | | $ | | | Amounts recognized in the Consolidated Balance Sheets at December 31: | | | | | | | | | | | | | | | | | Noncurrent pension and other postretirement benefit assets | | $ | | | | $ | | | | $ | | | | $ | | | Other current liabilities | | | | ) | | | | ) | | | | ) | | | | ) | Noncurrent pension and other postretirement benefit liabilities | | | | ) | | | | ) | | | | ) | | | | ) | | | $ | | ) | | $ | | ) | | $ | | | | $ | | | Significant assumptions used to determine benefit obligations as of December 31: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Weighted average rate of increase for compensation | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Changes in benefit obligation: | | | | | | | | | | | | | | | | | Benefit obligation at beginning of year | | $ | | | | $ | | | | $ | | | | $ | | | Dominion Energy Gas Restructuring (See Note 3) | | | | ) | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | | | | ) | Actuarial (gains) losses during the year | | | | | | | | ) | | | | | | | | ) | | | | | | | | | | | | | | | | | ) | Settlements and curtailments (1) | | | | | | | | | | | | | | | | | Benefit obligation at end of year | | $ | | | | $ | | | | $ | | | | $ | | | Changes in fair value of plan assets: | | | | | | | | | | | | | | | | | Fair value of plan assets at beginning of year | | $ | | | | $ | | | | $ | | | | $ | | | Dominion Energy Gas Restructuring (See Note 3) | | | | ) | | | | | | $ | | ) | | | | | Actual return (loss) on plan assets | | | | | | | | ) | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | | | | ) | Fair value of plan assets at end of year | | $ | | | | $ | | | | $ | | | | $ | | | Funded status at end of year | | $ | | | | $ | | | | $ | | | | $ | | | Amounts recognized in the Consolidated Balance | | | | | | | | | | | | | | | | | Noncurrent pension and other postretirement benefit assets | | $ | | | | $ | | | | $ | | | | $ | | | Noncurrent assets of discontinued operations | | | | | | | | | | | | | | | | | Noncurrent liabilities of discontinued operations | | | | | | | | | | | | | | | | ) | | | $ | | | | $ | | | | $ | | | | $ | | | Significant assumptions used to determine benefit obligations as of December 31: | | | | | | | | | | | | | | | | | | | | | % | | | | % | | | | % | | | | % | Weighted average rate of increase for compensation | | | | % | | | | % | | | | | | | | |
(1) | 2019(1) | 2021 amounts relateinclude curtailments and settlements recognized primarily to a settlement as a result of the voluntary retirement program.employee choice program and settlements of nonqualified pension obligations. 2020 amounts include curtailment and settlements recognized as a result of the GT&S Transaction as well as settlements of qualified and nonqualified pension obligations. |
| (2) | | | | | | | | | | | | | | 2021amounts relate to settlements of nonqualified pension obligations and 2020 amounts relate primarily to settlements of qualified and nonqualified pension obligations. |
Combined NotesActuarial gains recognized during 2021 in Dominion Energy’s pension benefit obligations were $413 million primarily driven by an increase in discount rates. Actuarial losses recognized during 2020 in Dominion Energy’s pension benefit obligations include a $1.0 billion loss resulting primarily from a decrease in discount rate. Actuarial gains recognized during 2021 in Dominion Energy’s other postretirement benefit obligations were $161 million resulting from an increase in discount rates, better than expected per capita claims experience and changes in demographic and economic assumptions based on an experience study completed in 2021. Actuarial losses recognized during 2020 in Dominion Energy’s other postretirement benefit obligations include a $149 million loss resulting from a decrease in discount rates and were partially offset by an $85 million actuarial gain as a result of a completed experience study in one of Dominion Energy’s other postretirement plans and the impact of an update to Consolidated Financial Statements, Continued healthcare claims assumptions.The ABO for all of Dominion Energy’s defined benefit pension plans was $9.7$10.2 billion and $7.8$10.6 billion at December 31, 20192021 and 2018,2020, 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. In December 2021, Dominion Energy issued 250,000 shares of its Series C Preferred Stock to its qualified defined benefit pension plans, valued at $250 million. In December 2020, Dominion Energy contributed $250 million to its qualified defined benefit pension plans. During 2019, Dominion Energy made $520 million of contributions to its defined benefit pension plans, including 6.1 million shares of its common stock valued at $499 million. The shares of common and preferred stock were contributed through athough private placement,placements exempt from registration requirements, with an independent fiduciary and investment manager to a separate account within the qualified defined benefit pension plans. Dominion Energy also entered into a registration rights agreement with the independent fiduciary and investment manager pursuant to which Dominion Energy agreed to provide registrationsregistration rights on customary terms with respect to the shares.shares of
common and preferred stock. Dominion Energy Gas did 0tis not required to make any contributions to its qualified defined benefit pension plans in 2019.2022. Dominion Energy expectsconsiders voluntary contributions from time to make $29 milliontime, either in the form of the minimum required contributions in 2020, and 0 contributions are currently expected in 2020 for Dominion Energy Gas. cash or equity securities.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 not prefund other postretirement benefit costs but instead pay claims as presented. Dominion Energy did 0t make any contributions to VEBAs associated with its other postretirement plans in 2021 and 2020. Dominion Energy’s contributions to VEBAs, all of which pertained to Dominion Energy Gas employees of operations sold to BHE, totaled $12 million for 2019 and 2018, and 2019. Dominion Energy expectsis not required to contribute approximately $12 millionmake any contributions to theits VEBAs associated with its other postretirement plans in 2022. Dominion Energy VEBAsconsiders voluntary contributions from time to time, either in 2020, allthe form of which pertains to Dominion Energy Gas employees. Dominion Energy and Dominion Energy Gas do 0t expect any pensioncash or other postretirement plan assets to be returned during 2020.
equity securities.The following table provides information on the benefit obligations and fair value of plan assets for plans with a benefit obligation in excess of plan assets for Dominion Energy and Dominion Energy Gas (for employees represented by collective bargaining units):Energy: | | Pension Benefits | | | Other Postretirement Benefits | | As of December 31, | | 2021 | | | 2020 | | | 2021 | | | 2020 | | (millions) | | | | | | | | | | | | | | | | | Dominion Energy | | | | | | | | | | | | | | | | | Benefit obligation | | $ | 9,420 | | | $ | 10,697 | | | $ | 261 | | | $ | 305 | | Fair value of plan assets | | | 9,229 | | | | 9,259 | | | | 7 | | | | 9 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | Fair value of plan assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | $ | | | Fair value of plan assets | | | | | | | | | | | | | | | | |
The following table provides information on the ABO and fair value of plan assets for Dominion Energy’s pension plans with an ABO in excess of plan assets: As of December 31, | | 2021 | | | 2020 | | (millions) | | | | | | | | | Accumulated benefit obligation | | $ | 127 | | | $ | 9,970 | | Fair value of plan assets | | | 53 | | | | 9,259 | |
| | | | | | | | | | | | | | | | | | | | | | | | Accumulated benefit obligation | | $ | | | | $ | | | Fair value of plan assets | | | | | | | | |
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 Benefits | | (millions) | | | | | | | | | Dominion Energy | | | | | | | | | 2022 | | $ | 513 | | | $ | 101 | | 2023 | | | 516 | | | | 100 | | 2024 | | | 529 | | | | 99 | | 2025 | | | 541 | | | | 97 | | 2026 | | | 548 | | | | 96 | | 2027-2031 | | | 2,833 | | | | 450 | |
| | | | | | | | | | | | Estimated Future Benefit Payments | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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 strategic target asset allocations for substantially all of Dominion Energy’s pension funds are 28%27% U.S. equity, 18% non-U.S. equity, 35%32% fixed income, 3% real estate and 16%20% other alternative investments. U.S. equity includes investments in large-cap, mid-cap and small-cap companies located in the U.S. Non-U.S. equity includes investments in large-cap and small-cap companies located outside of the U.S. including both developed and emerging markets. Fixed income includes corporate debt instruments of companies from diversified industries and U.S. Treasuries. The U.S. equity, non-U.S. equity and fixed income investments are in individual securities as well as mutual funds. Real estate includes equity real estate investment trusts and investments in partnerships. Other alternative investments include partnership investments in private equity, debt and hedge funds that follow several different strategies.
Dominion Energy also utilizes common/collective trust funds as an investment vehicle for its defined benefit plans. A common/collective trust fund is a pooled fund operated by a bank or trust company for investment of the assets of various organizations and individuals in a well-diversified portfolio. Common/collective trust funds are funds of grouped assets that follow various investment strategies.
Strategic investment policies are established for Dominion Energy’s prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from the plans’ strategic allocation are a function of Dominion Energy’s assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans’ actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the target. Future asset/liability studies will focus on strategies to further reduce pension and other postretirement plan risk, while still achieving attractive levels of returns. Financial derivatives may be used to obtain or manage market exposures and to hedge assets and liabilities. For fair value measurement policies and procedures related to pension and other postretirement benefit plan assets, see Note 6. The fair values of Dominion Energy 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, | | 2021 | | | 2020 | | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dominion Energy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash and cash equivalents | | $ | 25 | | | $ | 5 | | | $ | — | | | $ | 30 | | | $ | 20 | | | $ | 1 | | | $ | — | | | $ | 21 | | Common and preferred stocks: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | U.S.(1) | | | 2,592 | | | | 244 | | | | — | | | | 2,836 | | | | 2,405 | | | | — | | | | — | | | | 2,405 | | International | | | 1,773 | | | | 19 | | | | — | | | | 1,792 | | | | 1,727 | | | | — | | | | — | | | | 1,727 | | Insurance contracts | | | — | | | | 279 | | | | — | | | | 279 | | | | — | | | | 409 | | | | — | | | | 409 | | Corporate debt instruments | | | 81 | | | | 1,439 | | | | — | | | | 1,520 | | | | 32 | | | | 1,385 | | | | — | | | | 1,417 | | Government securities | | | 39 | | | | 914 | | | | — | | | | 953 | | | | 30 | | | | 772 | | | | — | | | | 802 | | Total recorded at fair value | | $ | 4,510 | | | $ | 2,900 | | | $ | — | | | $ | 7,410 | | | $ | 4,214 | | | $ | 2,567 | | | $ | — | | | $ | 6,781 | | Assets recorded at NAV(2): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Common/collective trust funds | | | | | | | | | | | | | | | 3,010 | | | | | | | | | | | | | | | | 2,905 | | Alternative investments: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Real estate funds | | | | | | | | | | | | | | | 116 | | | | | | | | | | | | | | | | 108 | | Private equity funds | | | | | | | | | | | | | | | 1,233 | | | | | | | | | | | | | | | | 856 | | Debt funds | | | | | | | | | | | | | | | 162 | | | | | | | | | | | | | | | | 168 | | Hedge funds | | | | | | | | | | | | | | | 14 | | | | | | | | | | | | | | | | 13 | | Total recorded at NAV | | | | | | | | | | | | | | $ | 4,535 | | | | | | | | | | | | | | | $ | 4,050 | | Total investments(3) | | | | | | | | | | | | | | $ | 11,945 | | | | | | | | | | | | | | | $ | 10,831 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash and cash equivalents | | $ | | | | $ | | | | | | | | $ | | | | $ | | | | $ | | | | | | | | $ | | | Common and preferred stocks: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Corporate debt instruments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total recorded at fair value | | $ | | | | $ | | | | | | | | $ | | | | $ | | | | $ | | | | | | | | $ | | | Assets recorded at NAV (2) : | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Common/collective trust funds | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash and cash equivalents | | $ | | | | $ | | | | | | | | $ | | | | $ | | | | $ | | | | | | | | $ | | | Common and preferred stocks: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Corporate debt instruments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total recorded at fair value | | $ | | | | $ | | | | | | | | $ | | | | $ | | | | $ | | | | | | | | $ | | | Assets recorded at NAV (2) : | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Common/collective trust funds | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | $ | | |
(1) | Includes $508$258 million of Dominion Energy preferred stock and 0 Dominion Energy common stock at December 31, 2021 and $365 million of Dominion Energy common stock at December 31, 2019.2020. |
(2) | These investments that are measured at fair value using the NAV per share (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy. |
(3) | Excludes net assets related to pending sales of securities of $52$35 million, net accrued income of $24 $27million, and includes net assets related to pending purchases of securities of $99$62 million at December 31, 2019.2021. Excludes net assets related to pending sales of securities and advanced subscriptions of $12$198 million, net accrued income of $21$20 million, and includes net assets related to pending purchases of securities of $22$71 million at December 31, 2018.2020. |
(4) | Excludes net assets related to pending sales of securities of $2 million, net accrued income of $2 million, and includes net assets related to pending purchases of securities of $6 million at December 31, 2019. Excludes net assets related to pending sales of securities of $3 million, net accrued income of $5 million, and includes net assets related to pending purchases of securities of $5 million at December 31, 2018. |
Combined Notes to Consolidated Financial Statements, Continued
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, | | 2021 | | | 2020 | | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dominion Energy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash and cash equivalents | | $ | 3 | | | $ | 1 | | | $ | — | | | $ | 4 | | | $ | — | | | $ | 2 | | | $ | — | | | $ | 2 | | Common and preferred stocks: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | U.S. | | | 898 | | | | 14 | | | | — | | | | 912 | | | | 817 | | | | — | | | | — | | | | 817 | | International | | | 256 | | | | 1 | | | | — | | | | 257 | | | | 240 | | | | — | | | | — | | | | 240 | | Insurance contracts | | | — | | | | 16 | | | | — | | | | 16 | | | | — | | | | 23 | | | | — | | | | 23 | | Corporate debt instruments | | | 5 | | | | 61 | | | | — | | | | 66 | | | | 2 | | | | 60 | | | | — | | | | 62 | | Government securities | | | 2 | | | | 47 | | | | — | | | | 49 | | | | 2 | | | | 42 | | | | — | | | | 44 | | Total recorded at fair value | | $ | 1,164 | | | $ | 140 | | | $ | — | | | $ | 1,304 | | | $ | 1,061 | | | $ | 127 | | | $ | — | | | $ | 1,188 | | Assets recorded at NAV(1): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Common/collective trust funds | | | | | | | | | | | | | | | 840 | | | | | | | | | | | | | | | | 765 | | Alternative investments: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Real estate funds | | | | | | | | | | | | | | | 13 | | | | | | | | | | | | | | | | 10 | | Private equity funds | | | | | | | | | | | | | | | 152 | | | | | | | | | | | | | | | | 117 | | Debt funds | | | | | | | | | | | | | | | 9 | | | | | | | | | | | | | | | | 10 | | Hedge funds | | | | | | | | | | | | | | | 1 | | | | | | | | | | | | | | | | 1 | | Total recorded at NAV | | | | | | | | | | | | | | $ | 1,015 | | | | | | | | | | | | | | | $ | 903 | | Total investments(2) | | | | | | | | | | | | | | $ | 2,319 | | | | | | | | | | | | | | | $ | 2,091 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash and cash equivalents | | $ | | | | $ | | | | | | | | $ | | | | $ | | | | $ | | | | | | | | $ | | | Common and preferred stocks: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Corporate debt instruments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total recorded at fair value | | $ | | | | $ | | | | | | | | $ | | | | $ | | | | $ | | | | | | | | $ | | | Assets recorded at NAV (1) : | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Common/collective trust funds | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Common and preferred stocks: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | | | | | $ | | | | $ | | | | $ | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total recorded at fair value | | $ | | | | $ | | | | | | | | $ | | | | $ | | | | $ | | | | | | | | $ | | | Assets recorded at NAV (1) : | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Common/collective trust funds | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | | $ | | | | | | | | | | | | | | | | $ | | |
(1) | These investments that are measured at fair value using the NAV per share (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy. |
(2) | Excludes net assets related to pending sales of securities of $2$5 million, net accrued income of $2 million, and includes net assets related to pending purchases of securities of $5$3 million at December 31, 2019.2021. Excludes net assets related to pending sales of securities of $1$10 million, net accrued income of $2 million, and includes net assets related to pending purchases of securities of $2 million at December 31, 2018.2020. |
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: Cash and Cash Equivalents
—Investments are held primarily in short-term notes and treasury bills, which are valued at cost plus accrued interest.Common and Preferred Stocks
—Investments are valued at the closing price reported on the active market on which the individual securities are traded.—Investments in Group Annuity Contracts with John Hancock were entered into after 1992 and are stated at fair value based on the fair value of the underlying securities as provided by the managers and include investments in U.S. government securities, corporate debt instruments, state and municipal debt securities.Corporate Debt Instruments
—Investments are valued using pricing models maximizing the use of observable inputs for similar securities. This includes basing value on yields currently available on comparable securities of issuers with similar credit ratings. When quoted prices are not available for identical or similar instruments, the instrument is valued under a discounted cash flows approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks or a broker quote, if available.—Investments are valued using pricing models maximizing the use of observable inputs for similar securities.Common/Collective Trust Funds
—Common/collective trust funds invest in debt and equity securities and other instruments with characteristics similar to those of the funds’ benchmarks. The primary objectives of the funds are to seek investment returns that approximate the overall performance of their benchmark indexes. These benchmarks are major equity indices, fixed income indices, and money market indices that focus on growth, income, and liquidity strategies, as applicable. Investments in common/collective trust funds are stated at the NAV as determined by the issuer of the common/collective trust funds and are based on the fair value of the underlying investments held by the fund less its liabilities. The NAV is used as a practical expedient to estimate fair value. The common/collective trust funds do not have any unfunded commitments, and do not have any applicable liquidation periods or defined terms/periods to be held. The majority of the common/collective trust funds have limited withdrawal or redemption rights during the term of the investment.—Investments in real estate funds, private equity funds, debt funds and hedge funds are stated at fair value based on the NAV of the Plan’s proportionate share of the partnership, joint venture or other alternative investment’s fair value as determined by reference to audited financial statements or NAV statements provided by the investment manager. The NAV is used as a practical expedient to estimate fair value. | • | Cash and Cash Equivalents—Investments are held primarily in short-term notes and treasury bills, which are valued at cost plus accrued interest. |
| • | | | | | | | | | | | | | | Common and Preferred Stocks—Investments are valued at the closing price reported on the active market on which the individual securities are traded. |
| • | Insurance Contracts—Investments in Group Annuity Contracts with John Hancock were entered into after 1992 and are stated at fair value based on the fair value of the underlying securities as provided by the managers and include investments in U.S. government securities, corporate debt instruments and state and municipal debt securities. |
| • | Corporate Debt Instruments—Investments are valued using pricing models maximizing the use of observable inputs for similar securities. This includes basing value on yields currently available on comparable securities of issuers with similar credit ratings. When quoted prices are not available for identical or similar instruments, the instrument is valued under a discounted cash flows approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks or a broker quote, if available. |
| • | Government Securities—Investments are valued using pricing models maximizing the use of observable inputs for similar securities. |
| • | Common/Collective Trust Funds—Common/collective trust funds invest in debt and equity securities and other instruments with characteristics similar to those of the funds’ benchmarks. The primary objectives of the funds are to seek investment returns that approximate the overall performance of their benchmark indexes. These benchmarks are major equity indices, fixed income indices and money market indices that focus on growth, income and liquidity strategies, as applicable. Investments in common/collective trust funds are stated at the NAV as determined by the issuer of the common/collective trust funds and are based on the fair value of the underlying investments held by the fund less its liabilities. The NAV is used as a practical expedient to estimate fair value. The common/collective trust funds do not have any unfunded commitments, and do not have any applicable liquidation periods or defined terms/periods to be held. The majority of the common/collective trust funds have limited withdrawal or redemption rights during the term of the investment. |
| • | Alternative Investments—Investments in real estate funds, private equity funds, debt funds and hedge funds are stated at fair value based on the NAV of the plan’s proportionate share of the partnership, joint venture or other alternative investment’s fair value as determined by reference to audited financial statements or NAV statements provided by the investment manager. The NAV, which is used as a practical expedient to estimate fair value, is adjusted for contributions and distributions occurring between the investment manager’s and Dominion Energy’s measurement date. These valuations also involve assumptions and methods that are reviewed, evaluated, and adjusted, if necessary, by Dominion Energy. |
Combined Notes to Consolidated Financial Statements, Continued
Net Periodic Benefit (Credit) Cost The service cost component of net periodic benefit (credit) cost is reflected in other operations and maintenance expense in Dominion Energy’s Consolidated Statements of Income, except for $1 million, $13 million and $16 million for the years ended December 31, 2021, 2020 and 2019, respectively, presented in discontinued operations. The non-service cost components of net periodic benefit (credit) cost are reflected in other operations 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: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other Postretirement Benefits | | | | | | | | | | | | | | | | | | | | | (millions, except percentages) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | Expected return on plan assets | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | Amortization of prior service (credit) cost | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | Amortization of net actuarial loss | | | | | | | | | | | | | | | | | | | | | | | | | Settlements and curtailments | | | | | | | | | | | | | | | | | | | | | | | | | Net periodic benefit (credit) cost | | $ | | | | $ | | | | $ | | | | $ | | ) | | $ | | ) | | $ | | ) | Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | Current year net actuarial (gain) loss | | $ | | | | $ | | | | $ | | | | $ | | ) | | $ | | | | $ | | | Prior service (credit) cost | | | | | | | | | | | | | | | | | | | | ) | | | | ) | Settlements and curtailments | | | | | | | | | | | | | | | | | | | | | | | | | Less amounts included in net periodic benefit cost: | | | | | | | | | | | | | | | | | | | | | | | | | Amortization of net actuarial loss | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | Amortization of prior service credit (cost) | | | | ) | | | | ) | | | | ) | | | | | | | | | | | | | Total recognized in other comprehensive income and regulatory assets and liabilities | | $ | | ) | | $ | | | | $ | | ) | | $ | | ) | | $ | | | | $ | | ) | Significant assumptions used to determine periodic cost: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | % | | | | % | | | | % | | | | % | | | | % | | | | % | Expected long-term rate of return on plan assets | | | | % | | | | % | | | | % | | | | % | | | | % | | | | % | Weighted average rate of increase for compensation | | | | % | | | | % | | | | % | | | | | | | | | | | | | Healthcare cost trend rate (1) | | | | | | | | | | | | | | | | % | | | | % | | | | % | Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) (1) | | | | | | | | | | | | | | | | % | | | | % | | | | % | Year that the rate reaches the ultimate trend rate (1) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | Expected return on plan assets | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | Amortization of prior service (credit) cost | | | | | | | | | | | | | | | | ) | | | | ) | | | | ) | Amortization of net actuarial loss | | | | | | | | | | | | | | | | | | | | | | | | | Settlements and curtailments | | | | | | | | | | | | | | | | | | | | | | | | | Net periodic benefit (credit) cost | | $ | | ) | | $ | | ) | | $ | | ) | | $ | | ) | | $ | | ) | | $ | | ) | Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | Current year net actuarial (gain) loss | | $ | | ) | | $ | | | | $ | | ) | | $ | | ) | | $ | | | | $ | | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) | Less amounts included in net periodic benefit cost: | | | | | | | | | | | | | | | | | | | | | | | | | Amortization of net actuarial loss | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | | | | ) | Amortization of prior service credit (cost) | | | | | | | | | | | | | | | | | | | | | | | | | Total recognized in other comprehensive income and regulatory assets and liabilities | | $ | | ) | | $ | | | | $ | | ) | | $ | | ) | | $ | | | | $ | | ) | Significant assumptions used to determine periodic cost: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | % | | | 3.81 | % | | | 4.50 | % | | | | % | | | 3.81 | % | | | 4.47 | % | Expected long-term rate of return on plan assets | | | | % | | | | % | | | | % | | | | % | | | | % | | | | % | Weighted average rate of increase for compensation | | | | % | | | | % | | | | % | | | | | | | | | | | | | Healthcare cost trend rate (1) | | | | | | | | | | | | | | | | % | | | | % | | | | % | Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) (1) | | | | | | | | | | | | | | | | % | | | | % | | | | % | Year that the rate reaches the ultimate trend rate (1) | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | | Other Postretirement Benefits | | Year Ended December 31, | | 2021 | | | 2020 | | | 2019 | | | 2021 | | | 2020 | | | 2019 | | (millions, except percentages) | | | | | | | | | | | | | | | | | | | | | | | | | Dominion Energy | | | | | | | | | | | | | | | | | | | | | | | | | Service cost | | $ | 170 | | | $ | 173 | | | $ | 162 | | | $ | 25 | | | $ | 28 | | | $ | 26 | | Interest cost | | | 317 | | | | 351 | | | | 394 | | | | 46 | | | | 58 | | | | 68 | | Expected return on plan assets | | | (834 | ) | | | (777 | ) | | | (708 | ) | | | (173 | ) | | | (156 | ) | | | (140 | ) | Amortization of prior service (credit) cost | | | — | | | | 1 | | | | 1 | | | | (42 | ) | | | (49 | ) | | | (52 | ) | Amortization of net actuarial loss | | | 193 | | | | 206 | | | | 172 | | | | 4 | | | | 6 | | | | 10 | | Settlements, curtailments and special termination benefits | | | 10 | | | | 14 | | | | 72 | | | | — | | | | (59 | ) | | | 42 | | Net periodic benefit (credit) cost | | $ | (144 | ) | | $ | (32 | ) | | $ | 93 | | | $ | (140 | ) | | $ | (172 | ) | | $ | (46 | ) | Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | Current year net actuarial (gain) loss | | $ | (782 | ) | | $ | 166 | | | $ | 16 | | | $ | (282 | ) | | $ | (110 | ) | | $ | (98 | ) | Prior service (credit) cost | | | — | | | | — | | | | — | | | | (13 | ) | | | (6 | ) | | | 2 | | Settlements and curtailments | | | (36 | ) | | | (81 | ) | | | 6 | | | | — | | | | 59 | | | | — | | Less amounts included in net periodic benefit cost: | | | | | | | | | | | | | | | | | | | | | | | | | Amortization of net actuarial loss | | | (193 | ) | | | (206 | ) | | | (172 | ) | | | (4 | ) | | | (6 | ) | | | (10 | ) | Amortization of prior service credit (cost) | | | — | | | | (1 | ) | | | (1 | ) | | | 42 | | | | 49 | | | | 52 | | Total recognized in other comprehensive income and regulatory assets and liabilities | | $ | (1,011 | ) | | $ | (122 | ) | | $ | (151 | ) | | $ | (257 | ) | | $ | (14 | ) | | $ | (54 | ) | Significant assumptions used to determine periodic cost: | | | | | | | | | | | | | | | | | | | | | | | | | Discount rate | | 2.73%-3.29% | | | 2.77%-3.63% | | | 3.57%-4.43% | | | 2.69%-2.80% | | | 3.07%-3.52% | | | 4.05% to 4.41% | | Expected long-term rate of return on plan assets | | 7.00%-8.45% | | | 7.00%-8.60% | | | 7.00% -8.65% | | | 8.45% | | | 8.50% | | | 8.50% | | Weighted average rate of increase for compensation | | 4.53% | | | 4.23% | | | 4.20% | | | n/a | | | n/a | | | n/a | | Crediting interest rate for cash balance and similar plans | | 1.93%-2.15% | | | 2.31-2.83% | | | 2.77-3.63% | | | n/a | | | n/a | | | n/a | | Healthcare cost trend rate(1) | | | | | | | | | | | | | | 6.25% | | | 6.25% | | | 6.50% to 6.60% | | Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)(1) | | | | | | | | | | | | | | 5.00% | | | 5.00% | | | 5.00% | | Year that the rate reaches the ultimate trend rate(1) | | | | | | | | | | | | | | 2026-2027 | | | 2025-2026 | | | 2023-2025 | |
(1) | Assumptions used to determine net periodic cost for the following year. |
(2) | Amounts related to East Ohio are presented within discontinued operations. |
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: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | $ | | | Prior service (credit) cost | | | | | | | | | | | | ) | | | | ) | | | $ | | | | $ | | | | $ | | ) | | $ | | ) | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | $ | | | Prior service (credit) cost | | | | | | | | | | | | ) | | | | ) | | | $ | | | | $ | | | | $ | | ) | | $ | | |
| | Pension Benefits | | | Other Postretirement Benefits | | At December 31, | | 2021 | | | 2020 | | | 2021 | | | 2020 | | (millions) | | | | | | | | | | | | | | | | | Dominion Energy | | | | | | | | | | | | | | | | | Net actuarial loss | | $ | 2,198 | | | $ | 3,207 | | | $ | (166 | ) | | $ | 120 | | Prior service (credit) cost | | | 2 | | | | 4 | | | | (203 | ) | | | (232 | ) | Total(1) | | $ | 2,200 | | | $ | 3,211 | | | $ | (369 | ) | | $ | (112 | ) |
(1) | As of December 31, 2019,2021, of the $3.3$2.2 billion and $(98)$(369) million related to pension benefits and other postretirement benefits, $2.0$1.7 billion and $(65)$(155) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. As of December 31, 2018, 2020, |
| of the $3.5$3.2 billion and $(43)$(112) million related to pension benefits and other postretirement benefits, $2.0$1.9 billion and $(41)$(40) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. |
(2) | As of December 31, 2019, of the $150 million related to pension benefits, $147 million is included in AOCI, with the remainder included in regulatory assets and liabilities; the $(5) million related to other postretirement benefits is included entirely in regulatory assets and liabilities. As of December 31, 2018, of the $555 million related to pension benefits, $200 million is included in AOCI, with the remainder includedin
noncurrent assets of discontinued operations; of the
$37 million related to other postretirement benefits, $22 million
is includedin noncurrent assets of discontinued operations with the remainder
in regulatory assets and liabilities. |
The following table provides the components of AOCI and regulatory assets and liabilities for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans as of December 31, 2019 that are expected to be amortized as components of net periodic benefit (credit) cost in 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Prior service (credit) cost | | | | | | | | ) | | | | | | | | | | | | | | | | | | | Prior service (credit) cost | | | | | | | | ) |
The expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates and mortality are critical assumptions in determining net periodic benefit (credit) cost. Dominion Energy develops non-investment related assumptions, which are then compared to the forecasts of an independent investment advisor to ensure reasonableness. An internal committee selects the final assumptions used for Dominion Energy’s pension and other postretirement plans including those 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: | • | Expected inflation and risk-free interest rate assumptions; |
Expected inflation and risk-free interest rate assumptions; | • | Historical return analysis to determine long term historic returns as well as historic risk premiums for various asset classes; |
| • | Expected future risk premiums, asset classes’ volatilities and correlations; |
| • | Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major capital market assumptions; and |
| • | Investment allocation of plan assets. |
Historical return analysis to determine long term historic returns as well as historic risk premiums for various asset classes;
Expected future risk premiums, asset classes’ volatilities and correlations;
Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major capital market assumptions; and
Investment allocation of plan assets.
Dominion Energy determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans, including those in which Dominion Energy Gas participates. plans.Mortality rates are developed from actual and projected plan experience for postretirement benefit plans. Dominion Energy’s actuary conducts an experience study periodically as part of the process to select its best estimate of mortality. Dominion Energy considers both standard mortality tables and improvement factors as well as the plans’ actual experience when selecting a best estimate. Assumed healthcare cost trend rates have a significant effect on the amounts reported for Dominion Energy’s retiree healthcare plans, 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 | | | | | | | | | | | | | | | | | | | | | | | | | Effect on net periodic cost for 2020 | | | | | | | | | Effect on other postretirement benefit obligation at December 31, 2019 | | | | | | | | | | | | | | | | | | Effect on net periodic cost for 2020 | | | | | | | | | Effect on other postretirement benefit obligation at December 31, 2019 | | | | | | | | |
Dominion Energy Gas (Employees Not Represented by Collective Bargaining Units)projected and demographics of plan participants.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, Virginia Power and Dominion Energy Gas made no0 contributions to the Dominion Energy Pension Plan, and noPlan. During 2020, Virginia Power made a payment to Dominion Energy for $313 million related to its participation in the Dominion Energy Pension Plan. In addition, in December 2020, Dominion Energy notified Virginia Power of a required contribution of $151 million, recorded in payables to affiliates in Virginia Power’s Consolidated Balance Sheets at December 31, 2020, which was paid in 2021. While Virginia Power has not been notified by Dominion Energy of any required contributions to this plan are currently expectedbe made in 2020.2022, it anticipates that it may have to contribute approximately $175 million as a result of Dominion Energy’s contribution made in December 2021. Virginia Power’s net periodic pension cost related to this plan was $86 million, $118 million and $152 million $126 millionin 2021, 2020 and $110 million in 2019, 2018 and 2017, respectively. Dominion Energy Gas’ net periodic pension
Combined Notes to Consolidated Financial Statements, Continued
credit related to this plan was $(8) million, $(35) million and $(35) million in 2019, 2018 and 2017, respectively. Net periodic pensionbenefit (credit) cost is reflected in other operations and maintenance expense in their respectiveVirginia Power’s Consolidated Statements of Income, except for $(14) million, $(21) million and $(20) million of Dominion Energy Gas’ costs in 2019, 2018 and 2017, respectively, that are recorded in net income from discontinued operations.Income. The funded status of various Dominion Energy subsidiary groups and employee compensation are the basis for determining the share of total pension costs for participating Dominion Energy subsidiaries. See Note 25 for Virginia Power and Dominion Energy Gas amounts due to/from Dominion Energy related to this plan.
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 $(72) million, $(58) million and $(27) million $(51) millionin 2021, 2020 and $(42) million in 2019, 2018 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, respectively. Net periodic benefit (credit) cost is reflected in other operations and maintenance expensesexpense in their respectiveVirginia Power’s Consolidated Statements of Income, except for less than $(1
) million, $(2) million and $(2) million of Dominion Energy Gas’ costs in 2019, 2018 and 2017, respectively, that are recorded in net income from discontinued operations.Income. Employee headcount is the basis for determining the share of total other postretirement benefit costs for participating Dominion Energy subsidiaries. See Note 25 for Virginia Power and Dominion Energy Gas amounts due to/from Dominion Energy related to this plan.
Dominion Energy holds investments in trusts to fund employee benefit payments for the pension and other postretirement benefit plans in which Virginia Power 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.
Certain regulatory authorities have held that amounts recovered in 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, Virginia Power and Dominion Energy Gas fundfunds other postretirement benefit costs through VEBAs. During 20192021, 2020 and 2018,2019, Virginia Power and Dominion Energy Gas made 0 contributions to the VEBAs and does 0t
0t expect to contribute to the VEBAs in 2020. 2022.Defined Contribution Plans Dominion Energy also sponsors defined contribution employee savings plans that cover substantially all employees. During 2019, 20182021, 2020 and 2017,2019, Dominion Energy recognized $73$65 million, $51$67 million and $45$69 million, respectively, as employer matching contributions to these plans. Dominion Energy Gas participates in these employee savings plans, both specific to Dominion Energy Gas and that cover multiple Dominion Energy subsidiaries. During 2019, 2018 and 2017, Dominion Energy Gas recognized $4 million, $8 million and $8 million, respectively, as employer matching contributions to these plans.excluding discontinued operations. Virginia Power also participates in these employee savings plans. During 2019, 20182021, 2020 and 2017,2019, Virginia Power recognized $20 million, $20$19 million and $19$20 million, respectively, as employer matching contributions to these plans.
NoteNOTE 23. Commitments and Contingencies COMMITMENTS AND CONTINGENCIESAs 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. 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. 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.
In February 2019, the EPA published a proposed rule to reverse its previous finding that it is appropriate and necessary to regulate toxic emissions from power plants. However, the emissions standards and other requirements of the MATS rule would remain in place as the EPA is not proposing to remove coal andoil-fired
power plants from the list of sources that are regulated under MATS. Although litigation of the MATS rule and the outcome of the EPA’s rulemaking are still pending, the regulation remains in effect and Dominion Energy and Virginia Power are complying with the applicable requirements of the rule and do not expect any adverse impacts to their operations at this time.The EPA published final non-attainment designations for the October 2015 ozone standard in June 2018. States have until August 20212018 with states required to develop plans to address the new standard. UntilCertain states in which the statesCompanies operate have developed plans, and had such plans approved or partially approved by the EPA, which are not expected to have a material impact on the Companies’ results of operations or cash flows. However, until implementation plans for the standard are developed and approved for all states in which the Companies operate, the Companies are unable to predict whether or to what extent the new rules will ultimately require additional controls. The expenditures required to implement additional controls could have a material impact on the Companies’ results of operations and cash flows. In August 2012, the EPA issued an NSPS impacting new and modified facilities in the natural gas production and gathering sectors and made revisions to the NSPS for natural gas processing and transmission facilities. These rules establish equipment performance specifications and emissions standards for control of VOC emissions for natural gas production wells, tanks, pneumatic controllers, and compressors in the upstream sector. In June 2016, the EPA issued another NSPS regulation, for the oil and natural gas sector, to regulate methane and VOC emissions from new and modified facilities in transmission and storage, gathering and boosting, production and processing facilities. All projects which commenced construction after September 2015 are required to comply with this regulation. In October 2018, the EPA published a proposed rule reconsidering and amending portions of the 2016 rule, including but not limited to, the fugitive emissions requirements at well sites and compressor stations. The amended portions of the 2016 rule were effective immediately upon publication. Until the proposed rule regarding reconsideration is final, Dominion Energy and Dominion Energy Gas are implementing the 2016 regulation. Dominion Energy and Dominion Energy Gas are still evaluating whether potential impacts on results of operations, financial condition and/or cash flows related to this matter will be material.
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 approved bythe EPA. This decision would take effect upon issuance of the court’s mandate. In March 2021, the court issued a partial mandate vacating and remanding all parts of the ACE Rule except for the portion of the ACE Rule that repealed the Clean Power Plan. In October 2021, the U.S. Supreme Court agreed to hear a challenge of the U.S. Court of Appeals for the D.C. Circuit’s decision on the ACE Rule. While the EPA by January 2024. Whilehas stated its intention to replace the impacts of ACE Rule, it is unknown at this rule could be material to Dominion Energytime if or how the EPA will issue a replacement for the ACE Rule and Virginia Power’s results ofhow that replacement will affect the Companies’ 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. In August 2016, the EPA issued a draft rule proposing to reaffirm that a source’s obligation to obtain a PSD or Title V permit for GHGs is triggered only if such permitting requirements are first triggered by non-GHG, or conventional, pollutants that are regulated by the New Source Review program, and to setexceed a significant emissions rate atof 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.flows.In December 2018, the EPA proposed revised Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources. The proposed rule would amend the previous determination that the best system of emission reduction for newly constructed coal-fired steam generating units is no longer partial carbon capture and storage. Instead, the proposed revised best system of emission reduction for this source category is the most efficient demonstrated steam cycle (e.g., supercritical steam conditions for large units and subcritical steam conditions for small units) in combination with the best operating practices. In May 2019, VDEQ issuedJanuary 2021, the EPA published a final rule establishingaffirming that fossil fuel-fired electric generating units meet the requirement that a state carbon regulation program withsource category “significantly contribute” to endangering air pollution for the purposes of regulating GHG emissions from new, modified and reconstructed stationary sources. The January 2021 rule also established a 28.0 million ton initial state-wide carbon cap in 2020.threshold for the “significant contribution” threshold that would have meant that no other source category, such as oil and gas facilities, petroleum refineries, and boilers, would meet that requirement at this time. In April 2021, the U.S. Court of Appeals for the D.C. Circuit granted an unopposed motion by the EPA to vacate and remand the January 2021 rule. The cap is reduced by approximately three percent per year through 2030, resulting in an ultimate cap of 19.6 million tons. The final rule includes a provision for VDEQ to delay implementation of the rule and possible adjustmentsproposed revision to the baseline cap pending authorization fromperformance standards for coal-fired steam generating units remains pending. Until the General Assembly and Governor of Virginia. Once VDEQ is authorizedEPA ultimately takes final action on this rulemaking, the Companies cannot predict the impact to begin implementation of the rule, the impacts of this program could be material to Dominion Energy and Virginia Power’stheir results of operations, financial condition and/or cash flows; however, the existing regulatory framework in Virginia provides rate recovery mechanisms that could substantially mitigate any such impact. 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. 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.
Combined Notes to Consolidated Financial Statements, Continued
The rule establishes a national standard for impingement based on seven compliance options, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA has delegated entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of five5 mandatory facility-specific factors, including a social cost-benefit test, and six6 optional facility-specific factors. The rule governs all electric generating stations with water withdrawals above two MGD, with a heightened entrainment analysis for those facilities over 125 MGD. Dominion Energy and Virginia Power currently have 1315 and seven9 facilities, respectively, that are subject to the final regulations. Dominion Energy anticipatesis also working with the EPA and state regulatory agencies to assess the applicability of Section 316(b) to 8 hydroelectric facilities, including 3 Virginia Power facilities. The Companies anticipate that itthey may have to install impingement control technologies at certain of these stations that have once-through cooling systems. Dominion Energy and Virginia PowerThe Companies are currently evaluating the need or potential for
entrainment controls under the final rule as these decisions will be made on acase-by-case basis after a thorough review of detailed biological, technology,technological, and cost and benefit studies. DESC is conducting studies and implementing plans as required by the rule to determine appropriate intake structure modifications at certain facilities to ensure compliance with this rule. While the impacts of this rule could be material to 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. 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 two2 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. utilities.Waste Management and Remediation The operations of the Companies are subject to a variety of state and federal laws and regulations governing the management and disposal of solid and hazardous waste, and release of hazardous substances associated with current and/or historical operations. The CERCLA, as amended, and similar state laws, may impose joint, several and strict liability for cleanup on potentially responsible parties who owned, operated or arranged for disposal at facilities affected by a release of hazardous substances. In addition, many states have created programs to incentivize voluntary remediation of sites where historical releases of hazardous substances are identified and property owners or responsible parties decide to initiate cleanups. From time to time, 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 has proposed or expects to propose remediation plans associated with three2 sites, including one1 at Virginia Power, and expects to conductcommence remediation activities primarily in 2020. As2022 depending on receipt of final permits and approvals. For 1 site associated with Dominion Energy, final approval of an updated work plan was received from the Army Corps of Engineers in December 2021, resulting in an additional $11 million of reserves and corresponding regulatory assets. At December 31, 2019,2021 and 2020, Dominion Energy and Virginia Power have $34had $45 million and $16$42 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 December 31, 2021 and 2020, Virginia Power had $25 million and $26 million, respectively, of reserves recorded. Virginia Power’s reserves include charges of $10 million ($7 million after-tax) recorded in September 2018, would increase costs by approximately $8 million if approved.2020, in other operations and maintenance expense in the Consolidated Statements of Income. Dominion Energy is associated with 1312 additional sites, including two2 associated with Virginia Power, which are not under investigation by any state or federal environmental agency nor the subject of any current or proposed plans to perform remediation activities. Due to the uncertainty surrounding such sites, Dominion Energy and Virginia Powerthe Companies are unable to make an estimate of the potential financial statement impacts.
Ash Pond and Landfill Closure Costs
In April 2015, the EPA enacted a final rule regulating CCR landfills, existing ash ponds that still receive and manage CCRs, and inactive ash ponds that do not receive, but still store, CCRs. Dominion Energy currently operates inactive ash ponds, existing ash ponds and CCR landfills subject to the final rule at 11 different facilities, eight of which are at Virginia Power. This rule created a legal obligation for Dominion Energy and Virginia Power to retrofit or close all of its inactive and existing ash ponds over a
certain period of time, as well as perform required monitoring, corrective action, and post-closure care activities as necessary.
In December 2016, legislation was enacted that creates a framework forEPA-
approved state CCR permit programs. In August 2017, the EPA issued interim guidance outlining the framework for state CCR program approval. The EPA has enforcement authority until state programs are approved. The EPA and states with approved programs both will have authority to enforce CCR requirements under their respective rules and programs. In September 2017, the EPA agreed to reconsider portions of the CCR rule in response to two petitions for reconsideration. In March 2018, the EPA proposed certain changes to the CCR rule related to issues remanded as part of the pending litigation and other issues the EPA is reconsidering. Several of the proposed changes would allow states with approved CCR permit programs additional flexibilities in implementing their programs. In July 2018, the EPA promulgated the first phase of changes to the CCR rule. Until all phases of the CCR rule are promulgated, Dominion Energy and Virginia Power cannot forecast potential incremental impacts or costs related to existing coal ash sites in connection with future implementation of the 2016 CCR legislation and reconsideration of the CCR rule. In August 2018, the U.S. Court of Appeals for the D.C. Circuit issued its decision in the pending challenges of the CCR rule, vacating and remanding to the EPA three provisions of the rule. Dominion Energy and Virginia Power do not expect the scope of the U.S. Court of Appeals for the D.C. Circuit’s decision to impact their closure plans, but cannot forecast incremental impacts associated with any future changes to the CCR rule in connection with the court’s remand.In April 2017, the Governor of Virginia signed legislation into law that placed a moratorium on the VDEQ issuing solid waste permits for closure of ash ponds at Virginia Power’s Bremo, Chesapeake, Chesterfield and Possum Point power stations until May 2018. The law also required Virginia Power to conduct an assessment of closure alternatives for the ash ponds at these four stations, to include an evaluation of excavation for recycling oroff-site
disposal, surface and groundwater conditions and safety. Virginia Power completed the assessments and provided the report on December 1, 2017. In April 2018, the Governor of Virginia signed legislation into law extending the existing permit moratorium until July 2019. The legislation also required Virginia Power to solicit and compile by November 2018, information from third parties on the suitability, cost and market demand for beneficiation or recycling of coal ash from these units. The coal ash recycling business plan was submitted to the legislature in November 2018. The extended moratorium does not apply to a permit required for an impoundment where CCRs have already been removed and placed in another impoundmenton-site,
are being removed from an impoundment, or are being processed in connection with a recycling or beneficial use project. In connection with this legislation, in the second quarter of 2018, Virginia Power recorded an increase to its ARO and a related environmental liability related to future ash pond and landfill closure costs of $131 million, which resulted in an $81 million ($60 millionafter-tax)
charge recorded in other operations and maintenance expense in its Consolidated Statement of Income, a $46 million increase in property, plant and equipment associated with asset retirement costs and a $4 million increase in regulatory assets.In March 2019, the Governor of Virginia signed into law legislation which requires any CCR unit located at Virginia Power’s Bremo, Chesapeake, Chesterfield or Possum Point power stations that stop accepting CCR prior to July 2019 be closed by removing the CCR to an approved landfill or through recycling for beneficial reuse. The legislation further requires that at least 6.8 million cubic yards of CCR be beneficially reused. Costs associated with the closure of these CCR units are recoverable through a rate adjustment clause approved by the Virginia Commission with a revenue requirement that cannot exceed $225 million in any12-month
period. Associated costs that are allocated to customers outside of Virginia, and not actually recovered from such customers, are recoverable through the Virginia rate adjustment clause. In connection with this legislation, Virginia Power recorded a $2.4 billion ARO related to the cost of landfills and beneficial reuse, with an offsetting increase to property, plant and equipment of $1.3 billion for the Chesterfield power station and an increase primarily to regulatory assets for the remaining portion related to the Bremo, Chesapeake and Possum Point power stations during the first quarter of 2019. In addition, Virginia Power revised its estimated cash flows for the existing ARO related to future ash pond and landfill closure costs, which resulted in a decrease of $202 million and a corresponding $113 million ($84 millionafter-tax)
benefit in other operations and maintenance expense in the Consolidated Statement of Income in the first quarter of 2019.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.
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, and unless otherwise noted therein, Dominion Energy is unable to estimate a reasonable range of possible loss and the related financial statement impacts, but for any such matter there could be a material impact to its results of operations, financial condition and/or cash flows. For the matters for which Dominion Energy is able to reasonably estimate a probable loss, Dominion Energy’s Consolidated Balance Sheets at December 31, 2021 and 2020 include reserves of $696$274 million and $208 million, respectively, included in other current liabilities, and insurance receivables of $111$118 million and $8 million, respectively, included within other receivablesreceivables. These balances at December 31, 2019.2021 and 2020 include $85 million and $8 million, respectively, of offsetting reserves and insurance receivables related to personal injury or wrongful death cases which are currently pending. Dominion Energy’s Consolidated Statements of Income for the years ended December 31, 2021, 2020 and 2019 include charges of $100 million ($75 million after-tax), $90 million ($68 million after-tax) and $641 million ($480 million after-tax), respectively, within impairment of assets and other charges (reflected in the Corporate and Other segment. In addition, Dominion Energy’s Consolidated Statements of Income for the year ended December 31, 2019 includes2020 include charges of $641$25 million ($48025 million after-tax
), included after-tax) within impairment of assets and other charges, included withinincome (expense) (reflected in the Corporate and Other segment.
Combined Notes to Consolidated Financial Statements, Continued
segment).Ratepayer Class Actions In May 2018, a consolidated complaint against DESC, SCANA and the State of South Carolina was filed in the State Court of Common Pleas in Hampton County, South Carolina (the DESC Ratepayer Case). In September 2018, the court certified this case as a class action. The plaintiffs allege,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. The plaintiffs sought a declaratory judgment that DESC may not charge its customers for any past or continuing costs of the NND Project, sought to have SCANA and DESC’s assets frozen and all monies recovered from Toshiba Corporation and other sources be placed in a constructive trust for the benefit of ratepayers and sought specific performance of the alleged implied contract to construct the NND Project. In December 2018, the State Court of Common Pleas in Hampton County entered an order granting preliminary approval of a class action settlement. The court entered an order granting final approval of the settlement and a stay ofpre-trial
proceedings in the DESC Ratepayer Case.June 2019, which became effective in July 2019. The settlement agreement, contingent upon the closing of the SCANA Combination, provided that SCANA and DESC would establish an escrow account and proceeds from the escrow account would be distributed to the class members,plaintiffs, after payment of certain taxes, attorneys’attorneys' fees and other expenses and administrative costs. The escrow account would include (1) up to $2.0 billion, net of a credit of up to $2.0 billion in future electric bill relief, which would inure to the benefit of the escrow account in favor of class members over a period of time established by the South Carolina Commission in its order related to matters before the South Carolina Commission related to the NND Project, (2) a cash payment of $115 million and (3) the transfer of certain DESC-owned real estate or sales proceeds from the sale of such properties, which counsel for the DESC Ratepayer Class estimateplaintiffs 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. The court held a fairness hearing on the settlement in May 2019. In June 2019, the court entered an order granting final approval of the settlement, which order became effective July 2019. In July 2019, DESC transferred $117 million representing the cash payment, plus accrued interest, to the plaintiffs. In addition,Through August 2020, property, plant and equipment with a net recorded value of $54$27 million is in the process of beinghad 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 arewere substantially similar to those in the DESC Ratepayer Case. The plaintiffs seek a declaratory judgment that the defendants may not charge the purported class for reimbursement for past or future costs of the NND Project. In March 2018, the plaintiffs filed an amended complaint including as additional named defendants, including certain then current and former directors of Santee Cooper and SCANA. In June 2018, Santee Cooper filed a Notice of Petition for Original Jurisdiction with the Supreme Court of
South Carolina. In December 2018, Santee Cooper filed its answer to the plaintiffs’ fourth amended complaint and filed cross claims against DESC, which was denied. In October 2019, Santee Cooper voluntarily consented to stay its cross claims against DESC pending the outcome of the trial of the underlying case. In November 2019, DESC removed the case to the U.S. District Court for the District of South Carolina. In December 2019, the plaintiffs and Santee Cooper filed a motion to remand the case to state court. In January 2020, the case was remanded to state court. In February 2020, the parties executed a preliminary settlement term sheetagreement relating to this matter as well as the Luquire Case and the Glibowski Case described below. The proposed settlement is expected to beagreement 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 iswas $320 million. The parties are currently negotiatingmillion 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, based on the preliminary settlement term sheet that will be presented to the court for preliminary approval. This case is pending.
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 arewere similar to the Santee Cooper Ratepayer Case. In FebruaryMarch 2020, the parties executed a preliminary settlement term sheetagreement as described above relating to this matter as well as the Santee Cooper Ratepayer Case and the Glibowski Case. This case is pending. was dismissed as part of the Santee Cooper Ratepayer Case settlement described above.RICO Class Action
In January 2018, a purported class action was filed, and subsequently amended, against SCANA, DESC and certain former executive officers in the U.S. District Court for the District of South Carolina (the Glibowski Case). The plaintiff alleges,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. The DESC Ratepayer Class Action settlement described previously contemplates dismissal of claims by DESC ratepayers in this case against DESC, SCANA and their officers. In August 2019, the individual defendants filed motions to dismiss. In FebruaryMarch 2020, the parties executed a preliminary settlement term sheetagreement as described above relating to this matter as well as the Santee Cooper Ratepayer Case and the Luquire Case. This case is pending. 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.defendants (collectively the SCANA Securities Class Action). In January 2018, the U.S. District Court for the District of South Carolina consolidated these suits, and the plaintiffs filed a consolidated amended complaint in March 2018. The plaintiffs allege,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 June 2018, the defendants filed motions to dismiss. In March 2019, the U.S. District Court for the District of South Carolina granted in part and denied in part
the defendants’ motions to dismiss. In December 2019, the parties executed a settlement agreement pursuant to which SCANA willwould pay $192.5 million, up to $32.5 million of which cancould be satisfied through the issuance of shares of Dominion Energy common stock, subject to approval by the U.S. District Court for the District of South Carolina.court approval. In February 2020, the U.S. District Court for the District of South Carolina granted preliminary approval of the settlement agreement, pending a fairness hearing.
hearing, and granted final approval in July 2020. In March 2020, SCANA funded an escrow account with $160 million in cash and paid the balance of $32.5 million in cash in August 2020 to satisfy the settlement.In September 2017, a shareholder derivative action was filed against certain former executive officers and directors of SCANA in the State Court of Common Pleas in Richland County, South Carolina.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. petition was denied in June 2021. Also in June 2021, the parties reached an agreement in principle in the amount of $33 million to resolve this matter, subject to court approval. This settlement was reached in contemplation of and will be utilized to satisfy a portion of the Federal Court Merger Case and the State Court Merger Case discussed below. In November 2021, the parties executed a settlement agreement and filed with the State Court of Common Pleas in Richland County, South Carolina for approval.In January 2018, a purported class action was filed against SCANA, Dominion Energy and certain former executive officers and directors of SCANA in the State Court of Common Pleas in Lexington County, South Carolina (the City of Warren Lawsuit). The plaintiff alleges, among other things, that defendants violated their fiduciary duties to shareholders by executing a merger agreement that would unfairly deprive plaintiffs of the true value of their SCANA stock, and that Dominion Energy aided and abetted these actions. Among other remedies, the plaintiff seeks to enjoin and/or rescind the merger. In February 2018, 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, which stated substantially similar allegations to those in the City of Warren Lawsuit and the Metzler Lawsuit.Lawsuit as well as an inseparable fraud claim. In November 2019, the defendants filed a motion to dismiss. In April 2020, the U.S. District Court for the District of South Carolina denied the motion to dismiss. In May 2020, SCANA filed a motion to intervene, which was denied in August 2020. In September 2020, SCANA filed a notice of appeal with the U.S. Court of Appeals for the Fourth Circuit. In June 2021, the parties reached an agreement in principle in the amount of $63 million to resolve this matter as well as the State Court Merger Case described below, subject to court approval. This case is pending.settlement was reached in contemplation of and will be partially satisfied by the State Court Derivative Case settlement described above. In November 2021, the parties executed a settlement agreement, as described above relating to this matter as well as the State Court Derivative Case and the State Court Merger Case, and filed with the State Court of Common Pleas in Richland County, South Carolina for approval.
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 secure and obtain the best price for the sale of SCANA. Also in May 2019, the case was removed to the U.S. District Court of South Carolina by the non-South Carolina defendants. In June 2019, the plaintiffs filed a motion to remand the case to state court. In January 2020, the case was remanded to state court. This case is pending.In February 2020, the defendants filed a motion to dismiss. In June 2021, the parties reached an agreement in principle as described above relating to this matter as well as the Federal Court Merger Case and the State Court Derivative Case. In November 2021, the parties executed a settlement agreement, as described above relating to this matter as well as the State Court Derivative Case and the Federal Court Merger Case, and filed with the State Court of Common Pleas in Richland County, South Carolina for approval.Employment Class Actions and Indemnification In August 2017, a case was filed in the U.S. District Court for the District of South Carolina on behalf of persons who were formerly employed at the NND Project. In July 2018, the court certified this case as a class action. In February 2019, certain of these plaintiffs filed an additional case, which case has been dismissed and the plaintiffs have joined the case filed August 2017. The plaintiffs allege, among other things, that SCANA, DESC, Fluor Corporation and Fluor Enterprises, Inc. violated the Worker Adjustment and Retraining Notification Act in connection with the decision to stop construction at the NND Project. The plaintiffs allege that the defendants failed to provide adequate advance written notice of their terminations of employment and are seeking damages, which could be as much as $100 million for 100% of the NND Project. In January 2021, the U.S. District Court for the District of South Carolina granted summary judgment in favor of SCANA, DESC, Fluor Corporation and Fluor Enterprises, Inc. In February 2021, the plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Fourth Circuit. In November 2021, the U.S Court of Appeals for the Fourth Circuit affirmed the lower court ruling.In September 2018, a case was filed in the State Court of Common Pleas in Fairfield County, South Carolina by Fluor Enterprises, Inc. and Fluor Daniel Maintenance Services, Inc. against DESC and Santee Cooper. The plaintiffs make claims for indemnification, breach of contract and promissory estoppel arising from, among other things, the defendants’defendants' alleged failure and refusal to defend and indemnify the Fluor defendants in the aforementioned case. These cases areThis case is pending. FILOT Litigation and Related Matters In November 2017, Fairfield County filed a complaint and a motion for temporary injunction against DESC in the State Court of Common Pleas in Fairfield County, South Carolina, making allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty, breach of implied duty of good faith and fair dealing and unfair trade practices related to DESC’s termination of the FILOT agreement between DESC and Fairfield County related to the NND Project. The plaintiff sought a temporary and permanent injunction to prevent DESC from terminating the FILOT agreement. The plaintiff withdrew the motion for temporary injunction in December 2017. This case is pending. In July 2021, the parties executed a settlement agreement requiring DESC to pay $99 million, which could be satisfied in either cash or shares of Dominion Energy common stock. Also in July 2021, the State Court of Common Pleas in Fairfield County, South Carolina approved the settlement. In July 2021, Dominion Energy issued 1.4 million shares of Dominion Energy common stock to satisfy DESC’s obligation under the settlement agreement.Governmental Proceedings and Investigations In June 2018, DESC received a notice of proposed assessment of approximately $410 million, excluding interest, from the SCDOR following its audit of DESC’s sales and use tax returns for the periods September 1, 2008 through December 31, 2017. The proposed assessment, which includes 100% of the NND Project, is based on the SCDOR’s position that DESC’s sales and
Combined Notes to Consolidated Financial Statements, Continued
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 has protestedto fund the proposed assessment, which remains pending. settlement amount through a combination of cash, shares of Dominion Energy common stock or real estate with an initial payment of at least $43 million in shares of Dominion Energy common stock. In August 2021, Dominion Energy issued 0.6 million shares of its common stock to satisfy DESC’s obligation for the initial payment under the settlement agreement.In September and October 2017, SCANA was served with subpoenas issued by the U.S. Attorney’s Office for the District of South Carolina and the Staff of the SEC’s Division of Enforcement seeking documents related to the NND Project. In February 2020, the SEC filed a complaint against SCANA, two of its former executive officers and DESC in the U.S. District Court for the District of South Carolina alleging that the defendants violated federal securities laws by making false and misleading statements about the NND Project. In April 2020, SCANA and DESC reached an agreement in principle with the Staff of the SEC’s Division of Enforcement to settle, without admitting or denying the allegations in the complaint. In December 2020, the U.S. District Court for the District of South Carolina issued an order approving the settlement which required SCANA to pay a civil monetary penalty totaling $25 million, and SCANA and DESC to pay disgorgement and prejudgment interest totaling $112.5 million, which disgorgement and prejudgment interest amount were deemed satisfied by the settlements in the SCANA Securities Class Action and the DESC Ratepayer Case.
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. In December 2018, arbitration proceedings commenced between DESC and Cameco Corporationany of its current, previous, or future direct or indirect subsidiaries related to the NND Project. A former executive officer of SCANA entered a supplyplea agreement signedwith the U.S. Attorney’s Office and the South Carolina Attorney General’s Office in May 2008. This agreement providesJune 2020 and entered a guilty plea with the terms and conditions under which DESC agreed to purchase uranium hexafluoride from Cameco Corporation over a period from 2010 to 2020. Cameco Corporation alleges that DESC violated this agreement by failing to purchase the stated quantities of uranium hexafluorideU.S. District Court for the 2017District of South Carolina in July 2020. Another former executive officer of SCANA entered a plea agreement with the U.S. Attorney's Office and 2018 delivery years. DESC denies that it isthe South Carolina Attorney General's Office in breachNovember 2020 and entered guilty pleas in the U.S. District Court for the District of South Carolina and in South Carolina state court in February 2021. As a result of the agreement and believes that itpleas, Dominion Energy has reduced its purchase quantity within the terms of the agreement. This matter is pending.
terminated indemnity for these former executive officers related to these two cases.Abandoned NND Project DESC, for itself and as agent for Santee Cooper, entered into an engineering, construction and procurement contract with Westinghouse and WECTEC in 2008 for the design and construction of the NND Project, of which DESC’s ownership share is 55%. Various difficulties were encountered in connection with the project. The ability of Westinghouse and WECTEC to adhere to established budgets and construction schedules was affected by many variables, including unanticipated difficulties encountered in connection with project engineering and the construction of project components, constrained financial resources of the contractors, regulatory, legal, training and construction processes associated with securing approvals, permits and licenses and necessary amendments to them within projected time frames, the availability of labor and materials at estimated costs and the efficiency of project labor. There were also contractor and supplier performance issues, difficulties in timely meeting critical regulatory requirements, contract disputes, and changes in key contractors or subcontractors. These matters preceded the filing for bankruptcy protection by Westinghouse and WECTEC in March 2017, and were the subject of comprehensive analyses performed by SCANA and Santee Cooper. Based on the results of SCANA’s analysis, and in light of Santee Cooper’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 construction under the abandonment provisions of the Base Load Review Act or through other means. This decision by SCANA became the focus of numerous legislative, regulatory and legal proceedings. Some of these proceedings remain unresolved and are described above. In September 2017, DESC, for itself and as agent for Santee Cooper, filed with the U.S. Bankruptcy Court for the Southern District of New York Proofs of Claim for unliquidated damages against each of Westinghouse and WECTEC. These Proofs of Claim were based upon the anticipatory repudiation and material breach by Westinghouse and WECTEC of the contract, and assert against Westinghouse and WECTEC any and all claims that are based thereon or that may be related thereto. Westinghouse’s reorganization plan was confirmed by the U.S. Bankruptcy Court for the Southern District of New York and became effective in August 2018. In connection with the effectiveness of the reorganization plan, the contract associated with the NND Project was deemed rejected. DESC is contestingcontested approximately $285 million of filed liens in Fairfield County, South Carolina. Most of these asserted liens arewere claims that relate to work performed by Westinghouse subcontractors before the Westinghouse bankruptcy, although some of them arewere claims arising from work performed after the Westinghouse bankruptcy. Westinghouse has indicated that some unsecured creditors have sought or may seek amounts beyond what Westinghouse allocated when it submitted its reorganization plan to the U.S. Bankruptcy Court for the Southern District of New York. If any unsecured creditor is successful in its attempt to include its claim as part of the class of general unsecured creditors beyond the amounts in the bankruptcy reorganization plan allocated by Westinghouse, it is possible that the reorganization plan will not provide for payment in full or nearly in full to itspre-petition
trade creditors. The shortfall could be significant.DESC and Santee Cooper were responsible for amounts owed to Westinghouse for valid work performed by Westinghouse subcontractors on the NND Project after the Westinghouse bankruptcy filing until termination of the interim assessment agreement. In December 2019, DESC and Santee Cooper entered into a confidential settlement agreement with W Wind Down Co LLC resolving claims relating to the interim assessment agreement.
Further, some Westinghouse subcontractors who havethat made claims against Westinghouse in the bankruptcy proceeding also filed claims against DESC and Santee Cooper in South Carolina state court for damages. Many of these claimants have also asserted construction liens against the NND Project site. DESC also intendsIn December 2021, settlements were reached to oppose theseresolve all remaining claims and liens. With respect to claims ofmade by Westinghouse subcontractors, DESC believes there were sufficientsubcontractors. All amounts previously funded during the interim assessment agreement period to pay such validly asserted claims. With respect to the Westinghouse subcontractor claimsfor which relate to other periods, DESC understands that such claims will be paid pursuant to Westinghouse’s confirmed bankruptcy reorganization plan. DESC further understands that the amounts paid under the plan may satisfy such claims in full. Therefore, DESC believes that the Westinghouse subcontractors may be paid substantially (and potentially in full) by Westinghouse. While Dominion Energy cannot be assured that it 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.
In connection with the Appalachian Gateway project, Dominion Energy Field Services, Inc. entered into contracts for firm purchase rights with a group of small gas producers. In June 2016, the gas producers filed a complaint in the Circuit Court of Marshall County, West Virginia against Dominion Energy, DETI and Dominion Energy Field Services, Inc., among other defendants, claiming that the contracts are unenforceable and seeking compensatory and punitive damages. During the third quarter of 2016, Dominion Energy, DETI and Dominion Energy Field Services, Inc. were served with the complaint. Also in the third quarter of 2016, Dominion Energy and DETI, with the consent of the other defendants, removed the case to the U.S. District Court for the Northern District of West Virginia. In October 2016, the defendants filed a motion to dismiss and the plaintiffs filed a motion to remand. In February 2017, the U.S. District Court entered an order remanding the matter to the Circuit Court of Marshall County, West Virginia. In March 2017, Dominion Energy was voluntarily dismissed from ultimately responsible were funded utilizing, and did not exceed, the case; however, DETI and Dominion Energy Field Services, Inc. remained parties to the matter. In April 2017, the case was transferred to the Business Court Division of West Virginia. In January 2018, the court granted the motion to dismiss filed by the defendants on two counts. In 2019, all claims were settled between Dominion Energy Field Services, Inc. and the gas producers, and all claims against DETI and Dominion Energy Field Services, Inc. were dismissed with no material impact to Dominion Energy or Dominion Energy Gas’ results of operations, financial condition or cash flows.
FERC staff in the Office of Enforcement, Division of Investigations, conducted a non-public investigation of Virginia Power’s offers of combustion turbines generators into the PJM day-ahead markets from April 2010 through September 2014. FERC staff notified Virginia Power of its preliminary findings relating to Virginia Power’s alleged violation of FERC’s rules in connection with these activities. Virginia Power provided its response to FERC staff’s preliminary findings letter explaining why Virginia Power’s conduct was lawful and refuting any allegation of wrongdoing. In May 2019, FERC issued an order approving an agreement between Virginia Power and FERC staff that settled any and all potential claims relating to the types of activities that were the subjectportion of the investigation, under which Virginia Power neither admits nor deniesToshiba Settlement allocated for such balances within the alleged violations and paid $7 millionSCANA Merger Approval Order recorded in disgorgement to PJM and a $7 million penalty to the U.S. Department of the Treasury.
In March 2011, a magnitude 9.0 earthquake and subsequent tsunami caused significant damage at the Fukushima Daiichi nuclear power station in northeast Japan. These events resulted in significant nuclear safety reviews by the NRC and industry groups such as the Institute of Nuclear Power Operations. Like other U.S. nuclear operators,regulatory liabilities on Dominion Energy has gathered supporting data and participated in industry initiatives focused on the ability to respond to and mitigate the consequences of, design-basis and beyond-design-basis events at its stations.
In July 2011, an NRC task force provided initial recommendations based on its review of the Fukushima Daiichi accident and in October 2011 the NRC staff prioritized these recommendations into Tiers 1, 2 and 3. Tier 1 recommendations consisted of actions which the NRC staff determined should be started without unnecessary delay. Tier 2 and 3 items consisted of items which could not be initiated in the near term because of resource restraints, the need for further technical assessment, or were dependent on activities related to the higher priority Tier 1 issues. In December 2011, the NRC Commissioners approved the agency staff’s prioritization and recommendations, and that same month an appropriations act directed the NRC to require reevaluation of external hazards (not limited to seismic and flooding hazards) as soon as possible.
Based on the prioritized recommendations, in March 2012, the NRC issued orders and information requests requiring specific reviews and actions to all operating reactor licensees, construction permit holders and combined license holders based on the lessons learned from the Fukushima Daiichi event. The orders applicable to Dominion Energy requiring implementation of safety enhancements related to mitigation strategies for responding to extreme natural events resulting in the loss of power at plants, and enhancing spent fuel pool instrumentation have been implemented. The information requests issued by the NRC requested each reactor licensee to reevaluate the seismic and external flooding hazards at their facility usingpresent-day
methods and information, conduct walkdowns of their facility to ensure protection against these hazards in their current design basis, and to reevaluate their emergency communications systems and staffing levels. The walkdowns of each unit have been completed, audited by the NRC and found to be adequate. Reevaluation of the emergency communications systems and staffing levels was completed as part of the effort to comply with the orders. Reevaluation of the seismic hazards is complete and final with NRC acceptance received for all Dominion Energy facilities. Reevaluation of the external flooding hazards is complete for all Dominion Energy facilities. However, NRC acceptance of the external flooding hazards reevaluations for Millstone and Surry have not yet been received. NRC is expected to accept these external flooding hazards analyses in 2020. Dominion Energy and Virginia Power do not currently expect that compliance with the NRC’s information requests will materially impact their financial position, results of operations or cash flows during the implementation period. The NRC staff has resolved the Tier 2 and Tier 3 recommendations and no additional future actions on the part of Dominion Energy are anticipated with respect to these recommendations. Therefore, Dominion Energy and Virginia Power do not expect material financial impacts related to compliance with Tier 2 and Tier 3 recommendations.Energy’s Consolidated Balance Sheets.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.
Combined Notes to Consolidated Financial Statements, Continued
The 20192021 calculation for the NRC minimum financial assurance amount, aggregated for Dominion Energy and Virginia Power’s nuclear units, excluding joint owners’ assurance amounts and Millstone Unit 1 and Kewaunee, as those units are in a decommissioning state, was $2.8$3.2 billion and $1.8$1.9 billion, respectively, and has been satisfied by a combination of the funds being collected and deposited in the nuclear decommissioning trusts and the real annual rate of return growth of the funds allowed by the NRC. The 20192021 NRC minimum financial assurance amounts above were calculated using preliminary December 31, 20192021 U.S. Bureau of Labor Statistics indices. Dominion Energy believes that the amounts currently available in its decommissioning trustsfunds and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Virginia Power alsoIn addition, Dominion Energy believes that the decommissioning funds and their expected earnings will be sufficient to cover expected decommissioning costs for the Summer unit, particularly when combined with future ratepayer collections and contributions. The Companies believe the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient to cover decommissioning costs, particularly when combined with future ratepayer collections and contributions to these decommissioning trusts, if such future collections and contributions are required. This reflects a positive long-term outlook for trust fund investment returns as the decommissioning of the units will not be complete for decades. Dominion Energy and Virginia PowerThe Companies will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirement, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments recognized by the NRC. See Note 9 for additional information on nuclear decommissioning trust investments. The Price-Anderson Amendments Act of 1988 provides the public up to $14.1$13.5 billion of liability protection on a per site, per nuclear incident basis, via obligations required of owners of nuclear power plants, and allows for an inflationary provision adjustment every five years. During the secondfirst quarter of 2019,2021, the total liability protection per nuclear incident available to all participants in the Secondary Financial Protection Program decreased from $14.1$13.8 billion to $13.9$13.7 billion. This decrease doesDuring the second quarter of 2021, the total liability protection per nuclear incident available to all participants in the Secondary Financial Protection Program decreased from $13.7 billion to $13.5 billion. These decreases do not impact Dominion Energy’s responsibility per active unit under the Price-Anderson Amendments Act of 1988. Dominion Energy and Virginia PowerThe Companies have purchased $450 million of coverage from commercial insurance pools for Millstone, Summer, Surry and North Anna with the remainder provided through the mandatory industry retrospective rating plan. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., Dominion Energy and Virginia Powerthe Companies could be assessed up to $138 million for each of their licensed reactors not to exceed $21 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed. The NRC granted an exemption in March 2015 to remove Kewaunee from the Secondary Financial Protection program. This same exemption permitted Dominion Energy to reduce Kewaunee’s required level of liability coverage to $100 million. This reduction was implemented in January 2018, following the removal and storage of the spent nuclear fuel from the spent fuel pool. The current levels of nuclear property insurance coverage for Dominion Energy and Virginia Power’sthe Companies’ nuclear units are as follows: | | Coverage | | (billions) | | | | | Dominion Energy | | | | | Millstone | | $ | 1.06 | | Kewaunee | | | 0.05 | | Summer | | | 2.75 | | Virginia Power | | | | | Surry | | $ | 1.06 | | North Anna | | | 1.06 | |
(1) | Surry and North Anna share a blanket property limit of $200 million. |
Dominion Energy and Virginia Power’sThe Companies’ nuclear property insurance coverage for Millstone, Summer, Surry and North Anna meets or exceeds the NRC minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site. In March 2015, the NRC granted an exemption which allowed Kewaunee to reduce its property insurance limit to $50 million. This reduction was implemented in January
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$76 million and $50$35 million, respectively. Based on the severity of the incident, the Board of Directors of the nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. 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. Additionally, DESC maintains an excess property insurance policy with the European Mutual Association for Nuclear Insurance. The policy provides coverage to Summer for property damage and outage costs up to $415 million resulting from an event of a non-nuclear origin. The European Mutual Association for Nuclear Insurance policy permits retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, DESC's share of the retrospective premium assessment would not exceed $2 million.Millstone, 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$33 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. Under Price-Anderson, DESC (for itself and on behalf of Santee-Cooper) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Summer. Price-Anderson provides funds up to $14.0 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $450 million by American Nuclear Insurers with the remaining coverage provided by a mandatory program of
deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. Each reactor licensee is liable for up to $138 million per reactor owned for each nuclear incident occurring at any reactor in the U.S., provided that not more than $21 million of the liability per reactor would be assessed per year. DESC’s maximum assessment, based on itstwo-thirds
ownership of Summer, would be $92 million per incident, but not more than $14 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.DESC currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Summer for property damage and outage costs up to $2.75 billion resulting from an event of nuclear origin and up to $2.33 billion resulting from an event of anon-nuclear
origin. The NEIL policies in aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. The NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, DESC’s portion of the retrospective premium assessment would not exceed $24 million. DESC currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with the European Mutual Association for Nuclear Insurance. The policy provides coverage to Summer for property damage and outage costs up to $415 million resulting from an event of anon-nuclear
origin. The European Mutual Association for Nuclear Insurance policy permits retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, DESC’s portion of the retrospective premium assessment would not exceed $2 million.To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from an incident at Summer exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that DESC’s rates would not recover the cost of any purchased replacement power, DESC will retain the risk of loss as a self-insurer. DESC has no reason to anticipate a serious nuclear or other incident. However, if such an incident were to occur, it likely would have a material impact on DESC’s results of operations, cash flows and financial position.
Dominion Energy and Virginia PowerThe 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 provide for periodic payments for damages incurred through December 31, 2019,2022, and additional extensions are contemplated by the settlement agreements. A similar agreement for Summer extends until the DOE has accepted the same amount of spent fuel from the facility as if it has fully performed its contractual obligations. In June 2018, a lawsuit for Kewaunee was filed in the U.S. Court of Federal Claims for recovery of spent nuclear fuel storage costs incurred 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 January 2022, a settlement agreement was entered into for $48 million. Dominion Energy received the settlement funds in February 2022.In 2021, Virginia Power received payments of $25 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2019 through December 31, 2019. In addition, Dominion Energy received payments of $9 million for resolution of claims incurred at Millstone for the period of July 1, 2019 through June 30, 2020 and $1 million for resolution of its share of claims incurred at Summer for the period of January 1, 2020 through December 31, 2020. In 2020, Virginia Power received payments of $24 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2018 through December 31, 2018. In addition, Dominion Energy received payments of $11 million for resolution of claims incurred at Millstone for the period of July 1, 2018 through June 30, 2019 and $4 million for resolution of its share of claims incurred at Summer for the period of January 1, 2019 through December 31, 2019. In 2019, Virginia Power received payments of $15 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2017 through December 31, 2017 and2017. In addition, Dominion Energy received $11 million for resolution of claims incurred at Millstone for the period of July 1, 2017 through June 30, 2018. In 2019, Dominion Energy received payment of2018 and $3 million for resolution of its share of claims incurred at Summer for the period of January 1, 2018 through December 31, 2018. In 2018, Virginia Power and Dominion Energy received payments of $16 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2016 through December 31, 2016, and $13 million for resolution of claims incurred at Millstone for the period of July 1, 2016 through June 30, 2017.
In 2017, Virginia Power and Dominion Energy received payments of $22 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2015 through December 31, 2015, and $14 million for resolution of claims incurred at Millstone for the period of July 1, 2015 through June 30, 2016.
Dominion Energy and Virginia PowerThe Companies continue to recognize receivables for certain spent nuclear fuel-related costs that they believe are probable of recovery from the DOE. Dominion Energy’s receivables for spent nuclear fuel-related costs totaled $52 million and $49$46 million at
December 31, 20192021 and 2018,2020, respectively. Virginia Power’s receivables for spent nuclear fuel-related costs totaled $35$39 million and $30$35 million at December 31, 20192021 and 2018,2020, respectively. Dominion Energy and Virginia PowerThe Companies will continue to manage their spent fuel until it is accepted by the DOE. Long-Term Purchase Agreements At December 31, 2019,2021, Dominion Energy had the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and that a third party has used to secure financing for the facility that will provide the contracted goods or services: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Purchased electric capacity (1) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2022 | | | 2023 | | | 2024 | | | 2025 | | | 2026 | | | Thereafter | | | Total | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Purchased electric capacity(1) | | $ | 66 | | | $ | 66 | | | $ | 66 | | | $ | 65 | | | $ | 68 | | | $ | 681 | | | $ | 1,012 | |
(1) | Commitments represent estimated amounts payable for energy under power purchase contracts with qualifying facilities which expire at various dates through 2046. Energy payments are generally based on fixed dollar amounts per month and totaled $29$59 million and $52 million for the yearyears ended December 31, 2019.2021 and 2020, respectively. |
Guarantees, Surety Bonds and Letters of Credit In October 2017,Upon the closing of the GT&S Transaction, Dominion Energy entered into a guarantee agreementretained its 4 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
Combined Notes to Consolidated Financial Statements, Continued
stated maturity date of October 2021. Dominion Energy’s maximum potential loss exposure under the termsterminal services, transportation and construction. NaN of the guarantee is limitedCove Point guarantees have a cumulative maximum exposure of $1.9 billion while the other 2 guarantees have 0 maximum limit. No amounts related to 48% of the outstanding borrowings under the revolving credit facility, an equal percentage to Dominion Energy’s ownership in Atlantic Coast Pipeline. As of December 31, 2019, Atlantic Coast Pipeline has borrowed $1.8 billion against the revolving credit facility and borrowed an additional $27 million in January and February 2020. Dominion Energy’s Consolidated Balance Sheet includes a liability of $14 million and $21 million associated with this guarantee agreement at December 31, 2019 and 2018, respectively.
these guarantees have been recorded. In addition, at December 31, 2019,2021, 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, 2019,2021, Dominion Energy had issued the following subsidiary guarantees:guarantees: | | Maximum Exposure | | (millions) | | | | | Commodity transactions(1) | | $ | 2,077 | | Nuclear obligations(2) | | | 243 | | Solar(3) | | | 321 | | Other(4) | | | 1,282 | | Total(5) | | $ | 3,923 | |
(1) | | | | | | | | | | | | | Commodity transactions(1)
| | $ | | | | | | | | | | | | | | | | | | | | | | | | | $ | | |
(1) | Guarantees related to commodity commitments of certain subsidiaries. These guarantees were provided to counterparties in order to facilitate physical and financial transaction related commodities and services. |
(2) | Guarantees primarily related to certain DGI subsidiaries’subsidiaries regarding all aspects of running a nuclear facility. |
(3) | Guarantees related to Cove Point, in support of terminal services, transportation and construction. Cove Point has two guarantees that have no maximum limit and, therefore, are not included in this amount. |
(4) | Includes guarantees to facilitate the development of solar projects. Also includes guarantees entered into by DGI on behalf of certain subsidiaries to facilitate the acquisition and development of solar projects. |
(5)(4) | Guarantees related to other miscellaneous contractual obligations such as leases, environmental obligations, construction projects and insurance programs. Also includes guarantees entered into by Dominion Energy RNG Holdings, II, Inc. on behalf of a subsidiary to facilitate construction of renewable natural gas facilities. Due to the uncertainty of worker’sworkers’ compensation claims, the parental guarantee has no stated limit. |
(6)(5) | Excludes Dominion Energy’s guarantees for the new corporate office propertiesproperty and an offshore wind installation vessel discussed further withinin Note 15. |
Additionally, at December 31, 2019,2021, Dominion Energy had purchased $163$217 million of surety bonds, including $77$154 million at Virginia Power, and $26 million at Dominion Energy Gas, and authorized the issuance of letters of credit by financial institutions of $89$131 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, the Companies are obligated to indemnify the respective surety bond company for any amounts paid. 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, 2019,2021, the Companies believe any other future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on their results of operations, cash flows or financial position. NoteCharitable Commitments In 2020, Dominion Energy made unconditional promises to several charitable organizations, including to support its commitment to diversity and social justice through scholarship programs and donations to historically black colleges and universities. As a result, Dominion Energy recorded charges totaling $80 million in other income in its Consolidated Statements of Income for the year ended December 31, 2020. These commitments are to be funded at various intervals through 2028. Dominion Energy’s Consolidated Balance Sheets include $43 million and $73 million in other deferred credits and other liabilities at December 31, 2021 and 2020, respectively and $26 million in other current liabilities at December 31, 2021. NOTE 24. Credit Risk CREDIT RISKDominion Energy As a diversified energy company, Dominion Energy transacts primarily with major companies in the energy industry and with commercial and residential energy consumers. These transactions principally occur in the Northeast, mid-Atlantic, Midwest and Rocky Mountain and Southeast regions of the U.S. Dominion Energy does not believe that this geographic concentration contributes significantly to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion Energy is not exposed to a significant concentration of credit risk for receivables arising from electric and gas utility operations. Dominion Energy’s exposure to credit risk is concentrated primarily within its energy marketing and price risk management activities, as Dominion Energy transacts with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Energy marketing and price risk management activities include marketing of 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 unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of any collateral. At December 31, 2019,2021, Dominion Energy’s credit exposure totaled $233$152 million. Of this amount, investment grade counterparties, including those internally rated, represented 88%85%, and no0 single counterparty, whether investment grade or non-investment grade, exceeded $61$45 million of exposure.
Virginia Power sells electricity and provides distribution and transmission services to customers in Virginia and northeastern North Carolina. Management believes that this geographic concentration risk is mitigated by the diversity of Virginia Power’s
customer base, which includes residential, commercial and industrial customers, as well as rural electric cooperatives and municipalities. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers. Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Virginia Power’s gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2019,2021, Virginia Power’s credit exposure totaled $71$16 million. Of this amount, investment grade counterparties, including those internally rated, represented 96%47%, and no0 single counterparty exceeded $61$4 million of exposure. Dominion Energy Gas transacts mainly with major companies in the energy industry. These transactions principally occur in the eastern and Rocky Mountain regions of the U.S. Dominion Energy Gas does not believe that this geographic concentration contributes to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion Energy Gas is not exposed to a significant concentration of credit risk for receivables arising from its regulated operations. Dominion Energy Gas’ gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealizedon-
oroff-balance
sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2019, Dominion Energy Gas’ credit exposure totaled $46 million. Of this amount, investment grade counterparties, including those internally rated, represented 81%, and no single counterparty, whether investment grade ornon-investment
grade, exceeded $9 million of exposure.Upon the Liquefaction Facility commencing commercial operations in April 2018, the majority of Cove Point’s revenue and earnings are expected to be generated from annual reservation payments under certain terminalling, storage and transportation contracts with the Export Customers. If such agreements were terminated and Cove Point was unable to replace such agreements on comparable terms, there could be a material impact on results of operations, financial condition and/or cash flows.
The Export Customers comprised approximately 34% and 32% 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.
In 2019, DETI provided service to 296 customers with approximately 98% of its storage and transportation revenue being provided through firm services. The ten largest customers provided approximately 38% of the total storage and transportation revenue and the thirty largest provided approximately 72% of the total storage and transportation revenue.
Credit-Related Contingent Provisions The majorityCertain of Dominion Energy’s derivative instruments contain credit-related contingent provisions. These provisions require Dominion Energy to provide collateral upon the occurrence of specific events, primarily a credit rating downgrade. If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered, as of December 31, 20192021 and 2018,2020 Dominion Energy would have been required to post an additional $10$31 million and $1$14 million, respectively, of additional collateral to its counterparties. The collateral that would be required to be posted includes the impacts of any offsetting asset positions and any amounts already posted for derivatives, non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. Dominion Energy had posted no$66 million and $1 million of collateral at December 31, 20192021 and 2018,2020, respectively, related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash as of December 31, 20192021 and 20182020 was $10$97 million and $1$15 million, respectively, which does not include the impact of any offsetting asset positions. Certain of Virginia Power’s derivative instruments contain credit-related contingent provisions. These provisions require Virginia Power to provide collateral upon the occurrence of specific events, primarily a credit rating downgrade. If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered as of December 31, 2019,2021 and 2020, Virginia Power would have been required to post an additional $8$22 million and $2 million, respectively, of additional collateral to its counterparties. Credit-relatedThe collateral that would be required to be posted includes the impacts of any offsetting asset position and any amounts already posted for derivatives and non-derivative contracts, per contractual terms. Virginia Power had posted $54 million of collateral at December 31, 2021 related to derivatives with credit-related contingent provisions for Virginia Powerthat are in a liability position and not fully collateralized with cash. NaN such amounts were not material as ofposted at December 31, 2018. Credit-related2020. The aggregate fair value of all derivative instruments with credit-related contingent provisions for Dominion Energy Gas werethat are in a liability position and not material as offully collateralized with cash was $76 million and $2 million at December 31, 20192021 and 2018.
December 31, 2020, respectively, which does not include the impact of any offsetting asset positions.See Note 7 for further information about derivative instruments. NoteNOTE 25. Related-party Transactions RELATED-PARTY TRANSACTIONSVirginia Power and Dominion Energy Gas engageengages in related party transactions primarily with other Dominion Energy subsidiaries (affiliates). Virginia Power and Dominion Energy Gas’Power’s receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Virginia Power and Dominion Energy Gas areis included in Dominion Energy’s consolidated federal income tax return and, where applicable, combined income tax returns for Dominion Energy are filed in various states. See Note 2 for further information. Dominion Energy’s transactions with equity method investments are described in Note 9. A discussion of significant related party transactions follows. Transactions with Affiliates Virginia Power transacts with affiliates for certain quantities of natural gas and other commodities in the ordinary course of business. Virginia Power also enters into certain commodity derivative contracts with affiliates. Virginia Power uses these contracts, which are principally comprised of forward commodity purchases, to manage commodity price risks associated with purchases of natural gas. See Notes 7 and 1920 for more information. As ofAt December 31, 2019,2021, Virginia Power’s derivative assets and liabilities with affiliates were $29 million and $6 million, respectively. At December 31, 2020, Virginia Power’s derivative assets and liabilities with affiliates were $3 million and $53$22 million, respectively. As of December 31, 2018, Virginia Power’s derivative assets and liabilities with affiliates were $26 million and $10 million, respectively.
Virginia Power participates in certain Dominion Energy benefit plans as described in Note 22.At December 31, 20192021 and 2018,2020, Virginia Power’s amounts due to Dominion Energy associated with the Dominion Energy Pension Plan and
Combined Notes to Consolidated Financial Statements, Continued
reflected in noncurrent pension and other postretirement benefit liabilities in the Consolidated Balance Sheets were $782$522 million and $632$436 million, respectively. At December 31, 20192021 and 2018,2020, Virginia Power’s amounts due from Dominion Energy associated with the Dominion Energy Retiree Health and Welfare Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $287$431 million and $254$354 million, respectively. DES and other affiliates provide accounting, legal, finance and certain administrative and technical services to Virginia Power. In addition, Virginia Power provides certain services to affiliates, including charges for facilities and equipment usage. The financial statements for all years presented include costs for certain general, administrative and corporate expenses assigned by DES to Virginia Power on the basis of direct and allocated methods in accordance with Virginia Power’s services agreements with DES. Where costs incurred cannot be determined by specific identification, the costs are allocated based on the proportional level of effort devoted by DES resources that is attributable to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DES service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable. Presented below are Virginia Power’s significant transactions with DES and other affiliates: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Commodity purchases from affiliates | | $ | | | | $ | | | | $ | | | Services provided by affiliates (1) | | | | | | | | | | | | | Services provided to affiliates | | | | | | | | | | | | |
Year Ended December 31, | | 2021 | | | 2020 | | | 2019 | | (millions) | | | | | | | | | | | | | Commodity purchases from affiliates | | $ | 742 | | | $ | 569 | | | $ | 690 | | Services provided by affiliates(1) | | | 494 | | | | 455 | | | | 503 | | Services provided to affiliates | | | 18 | | | | 18 | | | | 24 | |
(1) | Includes capitalized expenditures of $133$161 million, $145$141 million and $144$133 million for the year ended December 31, 2021, 2020 and 2019, 2018 and 2017, respectively. |
Virginia Power has borrowed funds from Dominion Energy under short-term borrowing arrangements. There were $107$699 million and $224$380 million in short-term demand note borrowings from Dominion Energy as of December 31, 20192021 and 2018,2020, respectively. The weighted-average interest rate of these borrowings was 3.22%0.26% and 2.94%0.30% at December 31, 20192021 and 2018,2020, respectively. Virginia Power had no0 outstanding borrowings, net of repayments under the Dominion Energy money pool for its nonregulated subsidiaries as of December 31, 20192021 and 2018.2020. Interest charges related to Virginia Power’s borrowings from Dominion Energy were immaterial for the years ended December 31, 2019, 20182021, 2020 and 2017. 2019.There were no0 issuances of Virginia Power’s common stock to Dominion Energy in 2019, 20182021, 2020 or 2017. Transactions with Related Parties
Dominion Energy Gas transacts with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Additionally, Dominion Energy Gas provides transportation and storage services to affiliates. Dominion Energy Gas also enters 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
have any commodity derivative assets and liabilities. See Notes 7 and 20 for more information. See Note 9 for information regarding transactions with an affiliate. See Note 3 for information regarding the Dominion Energy Gas Restructuring, an affiliated transaction.
Dominion Energy Gas participates in certain Dominion Energy benefit plans as described in Note 22. At December 31, 2019 and 2018, Dominion Energy Gas’ amounts due from Dominion Energy associated with the Dominion Energy Pension Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $326 million and $319 million, respectively. Dominion Energy Gas’ amounts due from Dominion Energy associated with the Dominion Energy Retiree Health and Welfare Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $17 million and $13 million at December 31, 2019 and 2018, respectively.
DES, DECGS, DEQPS and other affiliates provide accounting, legal, finance and certain administrative and technical services to Dominion Energy Gas. Dominion Energy Gas provides certain services to related parties, including technical services.
The financial statements for all years presented include costs for certain general, administrative and corporate expenses assigned by DES, DECGS and DEQPS to Dominion Energy Gas on the basis of direct and allocated methods in accordance with Dominion Energy Gas’ services agreements with DES, DECGS and DEQPS. Where costs incurred cannot be determined by specific identification, the costs are allocated based on the proportional level of effort devoted by DES, DECGS and DEQPS 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. The costs of these services follow:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Sales of natural gas and transportation and storage services | | $ | | | | $ | | | | $ | | | Purchases of natural gas and transportation and storage services | | | | | | | | | | | | | Services provided by related parties (1) | | | | | | | | | | | | | Services provided to related parties (2) | | | | | | | | | | | | |
(1) | Includes capitalized expenditures of $19 million, $37 million and $53 million for the year ended December 31, 2019, 2018 and 2017, respectively. |
(2) | Amounts primarily attributable to Atlantic Coast Pipeline, a related party VIE. |
The following table presents affiliated and related party balances reflected in Dominion Energy Gas’ Consolidated Balance Sheets:
| | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | Imbalances receivable from affiliates | | | | | | | | | Imbalances payable from affiliates (2) | | | | | | | | | Other deferred charges and other assets | | | | | | | | |
(1) | Represents amounts due from Atlantic Coast Pipeline, a related party VIE. |
(2) | Amounts are presented in other current liabilities in Dominion Energy Gas’ Consolidated Balance Sheets. |
Affiliated receivables at December 31, 2019 and December 31, 2018 included $22 million and $7 million of accrued unbilled revenue, respectively. This revenue is based on estimated amounts of services provided but not yet billed to various affiliates.
Affiliated notes receivable from East Ohio and DGP borrowings under an IRCA with Dominion Energy Gas were $704 million at December 31, 2018. Interest income on the IRCAs was $14 million, $15 million and $5 million for the years ended December 31, 2019, 2018 and 2017, respectively.
In 2016, DMLPHCII issued a five-year $15.0 million promissory note to Dominion Energy. The interest rate is a fixed 2.75% per annum. Interest income earned on the promissory note was immaterial for the years ended December 31, 2019, 2018 and 2017.
In 2018, in connection with the closing of a $3.0 billion term loan, Cove Point loaned Dominion Energy $3.0 billion in exchange for a promissory note. The promissory note had an annual interest rate of 3.6% which was payable quarterly and was scheduled to mature in 2021. Interest income related to Dominion Energy’s borrowing was $82 million and $21 million for the years ended December 31, 2019 and December 31, 2018, respectively, presented in other income in the Consolidated Statements of Income and accrued interest was immaterial at December 31, 2018, presented in affiliated receivables in the Consolidated Balance Sheets. In September 2019, Dominion Energy repaid the promissory note to Cove Point and the proceeds were used by Cove Point to repay its $3.0 billion term loan.
In November 2019, Dominion Energy Gas issued a five-year promissory note to Dominion Energy under which it may lend up to $3.0 billion. Dominion Energy Gas’ affiliated notes receivable from Dominion Energy totaled $1.8 billion at December 31, 2019. The promissory note has a fixed annual interest rate of 2.5% payable
quarterly
. Interest income on the promissory note was $5 million for the year ended December 31, 2019.
At December 31, 2019 and 2018, Dominion Energy Gas’ affiliated notes receivable from East Ohio totaled $1.7 billion and $1.4 billion, respectively. These promissory notes have fixed annual interest rates between 3.67% to 4.90% which are payable semi-annually. Interest income on these promissory notes was $72 million for the year ended December 31, 2019 and $64 million for both the years ended December 31, 2018 and 2017.
Dominion Energy Gas’ borrowings under the IRCA with Dominion Energy totaled $251 million and $218 million as of December 31, 2019 and 2018, respectively. The weighted-average interest rate of these borrowings was 2.02% and 2.78% at December 31, 2019 and 2018, respectively. Interest charges related to Dominion Energy Gas’ total borrowings from Dominion Energy were $3 million for December 31, 2019 and less than $1 million for December 31, 2018 and 2017, respectively.
DCP had borrowings under an IRCA with Dominion Energy of $2.8 billion at December 31, 2018. The weighted-average interest rate for these borrowings was 3.43% at December 31, 2018. In October 2019, DCP repaid the outstanding balance and accrued interest utilizing funds from a capital contribution from Dominion Energy. Interest charges related to DCP’s total borrowings from Dominion Energy totaled $94 million, $96 million and $82 million for the years ended December 31, 2019, 2018 and 2017, respectively.
In addition, DCP had borrowings of $9 million and $57 million with DES as of December 31, 2019 and 2018 respectively. The weighted-average interest rate for these borrowings was 3.85% and 3.45% at December 31, 2019 and 2018, respectively. Interest related to DCP’s total borrowings from DES totaled $3 million, $1 million and less than $1 million for the years ended December 31, 2019, 2018 and 2017, respectively.
DMLPHCII had borrowings under an IRCA with Dominion Energy of $22 million December 31, 2018. The weighted-average interest rate for these borrowings was 3.43% at December 31, 2018. In October 2019, DMLPHCII repaid the outstanding balance and accrued interest utilizing funds from a capital contribution from Dominion Energy. Interest charges related to DMLPHCII’s total borrowings from Dominion Energy were less than $1 million for each of the years ended December 31, 2019, 2018 and 2017.
In the first quarter of 2019, Dominion Energy Midstream borrowed $395 million from Dominion Energy under a $400 million promissory note with Dominion Energy that was scheduled to mature in 2022. The interest rate was fixed 3.5% per annum. In October 2019, Dominion Energy Midstream repaid the outstanding balance and accrued interest utilizing funds from a capital contribution from Dominion Energy. Interest charges of $10 million were incurred for the year ended December 31, 2019.
For the periods ending December 31, 2019, 2018 and 2017, Dominion Energy Gas, including entities acquired in the Dominion Energy Gas Restructuring, distributed $603 million, $230 million and $239 million to Dominion Energy, respectively.
NoteNOTE 26. Operating Segments OPERATING SEGMENTSThe 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: | | | | | | | | | | | Description of Operations | | | | | | | | | Regulated electric distribution | | | | | | | | | Regulated electric transmission | | | | | | | | | Regulated electric generation fleet (1) | | | | | | | Gas Transmission & Storage
| | Regulated gas transmission and storage(2)
| | | | | | | | | LNG terminalling and storage
| | | | | | | | | Nonregulated retail energy marketing
| | | | | | | | | Regulated gas distribution and storage (3)
| | | | | | | Dominion Energy South Carolina | | Regulated electric distribution | | | | | | | | | Regulated electric transmission | | | | | | | | | Regulated electric generation fleet | | | | | | | | | Regulated gas distribution and storage | | | | | | | | Assets | | MerchantNonregulated electric generation fleet | | | | | | |
| | | | | | | | | | | Noncontrolling interest in Cove Point | | X | | |
Combined Notes to Consolidated Financial Statements, Continued
(1) | Includes Virginia Power’s nonjurisdictional generation operations. |
(2) | Includes gathering and processing activities. |
(3) | Includes Wexpro’s natural gas development and production operations. |
(1) Includes Virginia Power’s non-jurisdictional generation operations. (2)Includes renewable natural gas operations as well as Wexpro’s natural gas development and production operations. (3) Includes solar generation facility development operations. In addition to the operating segments above, the Companies also report a Corporate and Other segment. The Corporate and Other Segment of Dominion Energy . as well as nonregulated retail energy marketing operations (prior to December 1, 2021), including Dominion Energy’s noncontrolling interest in Wrangler. In addition, Corporate and Other includes specific items attributable to Dominion Energy’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources.resources, as well as the net impact of the gas transmission and storage operations held in discontinued operations which are discussed in Note 3.In 2019,2021, Dominion Energy reported after-tax net expenses of $2.6$99 million in the Corporate and Other segment, including $97 million of after-tax net benefit for specific items with $493 million of after tax-net expenses attributable to its operating segments.The net expenses for specific items attributable to Dominion Energy’s operating segments in 2021 primarily related to the impact of the following items: • | A $347 million ($261 million after-tax) loss related to economic hedging activities, attributable to Contracted Assets; |
• | $266 million ($199 million after-tax) of charges associated with the settlement of the South Carolina electric base rate case, attributable to Dominion Energy South Carolina; |
• | A $211 million ($161 million after-tax) net loss on the sale of non-wholly-owned nonregulated solar facilities, attributable to Contracted Assets; |
• | A $151 million ($112 million after-tax) loss from an unbilled revenue reduction at Virginia Power, attributable to Dominion Energy Virginia; |
• | A $125 million ($93 million after-tax) net charge associated with the settlement of the 2021 Triennial Review, attributable to Dominion Energy Virginia; |
• | A $77 million ($57 million after-tax) charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to Virginia’s 2021 budget process, attributable to Dominion Energy Virginia; |
• | A $70 million ($53 million after-tax) charge associated with litigation acquired in the SCANA Combination, attributable to Dominion Energy South Carolina; |
• | A $68 million ($50 million after-tax) charge associated with storm damage and service restoration in Virginia Power’s service territory, attributable to Dominion Energy Virginia; |
• | A $61 million ($45 million after-tax) charge for amortization of a regulatory asset established in connection with the settlement of the 2021 Triennial Review, attributable to Dominion Energy Virginia; and |
• | A $44 million ($35 million after-tax) charge related to a revision in estimated recovery of spent nuclear fuel costs associated with the decommissioning of Kewaunee, attributable to Contracted Assets; partially offset by |
• | A $568 million ($445 million after-tax) gain related to investments in nuclear decommissioning trust funds, attributable to: |
| • | Contracted Assets ($390 million after-tax); and |
| • | Dominion Energy Virginia ($55 million after-tax); and |
• | A $130 million ($97 million after-tax) benefit for a change in the expected CCRO to be provided to Virginia retail electric customers under the GTSA, attributable to Dominion Energy Virginia. |
In 2020, Dominion Energy reported after-tax net expenses of $3.7 billion in the Corporate and Other segment, with $2.0including $3.4 billion of theafter-tax net expenses for specific items with $1.2 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 2020 primarily related to the impact of the following items: • | A $751 million ($564 million after-tax) charge primarily related to the planned early retirement of certain Virginia Power electric generation facilities, attributable to Dominion Energy Virginia; |
• | A $405 million ($325 million after-tax) charge associated with certain nonregulated solar generation facilities, attributable to Contracted Assets; |
• | A $221 million ($171 million after-tax) charge associated with the sale of Fowler Ridge, attributable to Contracted Assets; and |
• | A $130 million ($97 million after-tax) charge for the expected CCRO to be provided to Virginia retail electric customers under the GTSA, attributable to Dominion Energy Virginia; |
• | A $127 million ($94 million after-tax) charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to legislation enacted in November 2020, attributable to Dominion Energy Virginia; and |
• | A $117 million ($93 million after-tax) of charges associated with litigation acquired in the SCANA Combination, attributable to Dominion Energy South Carolina; partially offset by |
• | A $335 million ($264 million after-tax) net gain related to investments in nuclear decommissioning trust funds attributable to: |
| • | Dominion Energy Virginia ($27 million after-tax); and |
| • | Contracted Assets ($237 million after-tax). |
In 2019, Dominion Energy reported after-tax net expenses of $1.8 billion in the Corporate and Other segment, including $1.5 billion of after-tax net expenses for specific items with $1.9 billion of after-tax net expenses attributable to its operating segments. The net expenses for specific items attributable to Dominion Energy’s operating segments in 2019 primarily related to the impact of the following items: A $1.0 billion ($756 millionafter-tax)
charge for refunds of amounts previously collected from retail electric customers of DESC for the NND Project, attributable to Dominion Energy South Carolina;$641 million ($480 millionafter-tax)
of charges associated with litigation acquired in the SCANA Combination, attributable to Dominion Energy South Carolina;$484 million ($315 millionafter-tax)
of charges for merger and integration-related costs associated with the SCANA Combination, including a $444 million ($332 millionafter-tax)
charge related to a voluntary retirement program, attributable to:Dominion Energy Virginia ($151 millionafter-tax);
Gas Distribution ($56 millionafter-tax);
Dominion Energy South Carolina ($75 millionafter-tax);
andContracted Generation ($38 millionafter-tax);
partially offset byGas Transmission & Storage ($5 millionafter-tax
benefit);A $346 million ($257 millionafter-tax)
charge related to the early retirement of certain Virginia Power electric generation facilities, attributable to Dominion Energy Virginia;A $194 million tax charge for $258 million of incometax-related
regulatory assets acquired in the SCANA Combination for which Dominion Energy committed to forgo recovery, attributable to Dominion Energy South Carolina;A $160 million ($119 millionafter-tax)
charge related to Virginia Power’s planned early retirement of certain automated meter reading infrastructure, attributable to Dominion Energy Virginia;A $135 million ($100 millionafter-tax)
charge related to Virginia Power’s contract termination with anon-utility
generator, attributable to Dominion Energy Virginia;A $114 million ($86 millionafter-tax)
charge for property, plant and equipment acquired in the SCANA Combination primarily for which Dominion Energy committed to forgo recovery, attributable to Dominion Energy South Carolina; partially offset byA $553 million ($411 millionafter-tax)
net gain related to investments in nuclear decommissioning trust funds attributable to:Dominion Energy Virginia ($49 millionafter-tax);
andContracted Generation ($362 millionafter-tax);
andA $113 million ($84 millionafter-tax)
benefit from the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019, attributable to Dominion Energy Virginia.In 2018, Dominion Energy reportedafter-tax
net expenses of $611 million in the Corporate and Other segment, with $88 million of the net expenses attributable to specific items related to its operating segments.The net expenses for specific items in 2018 primarily related to the impact of the following items:
A $219 million ($164 millionafter-tax)
charge related to the impairment of certain gathering and processing assets attributable to Gas Transmission & Storage;A $215 million ($160 millionafter-tax)
charge associated with Virginia legislation enacted in March 2018 that requiresone-time
rate credits of certain amounts to utility customers, attributable to Dominion Energy Virginia;A $170 million ($134 millionafter-tax)
net loss related to our investments in nuclear decommissioning trust funds attributable to:Dominion Energy Virginia ($14 millionafter-tax);
andContracted Generation ($120 millionafter-tax);
A $124 million ($88 millionafter-tax)
charge for disallowance of FERC-regulated plant attributable to Gas Transmission & Storage;An $81 million ($60 millionafter-tax)
charge associated primarily with the asset retirement obligations for ash ponds and landfills at certain utility generation facilities in connection with the enactment of Virginia legislation in April 2018 attributable to Dominion Energy Virginia; andA $70 million ($52 millionafter-tax)
charge associated with major storm damage and service restoration attributable to Dominion Energy Virginia; partially offset byAn $828 million ($619 millionafter-tax)
benefit associated with the sale of certain merchant generation facilities and equity method investments attributable to:Contracted Generation ($229 millionafter-tax);
andGas Transmission & Storage ($390 millionafter-tax).
In 2017, Dominion Energy reportedafter-tax
net benefits of $377 million in the Corporate and Other segment, with $861 million of the net benefits attributable to specific items related to its operating segments.The net benefits for specific items in 2017 primarily related to the impact of the following items:
A $1.0 billion tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act, primarily attributable to:
Dominion Energy Virginia ($83 million);
Gas Transmission & Storage ($302 million);
Gas Distribution ($56 million);
Contracted Generation ($569 million); partially offset by
$158 million ($96 millionafter-tax)
of charges associated with equity method investments in wind-powered generation facilities, attributable to Contracted Generation.• | A $1.0 billion ($756 million after-tax) charge for refunds of amounts previously collected from retail electric customers of DESC for the NND Project, attributable to Dominion Energy South Carolina; |
• | | | | | | | | | | | | | | | $641 million ($480 million after-tax) of charges associated with litigation acquired in the SCANA Combination, attributable to Dominion Energy South Carolina; |
• | $427 million ($320 million after-tax) of charges for merger and integration-related costs associated with the SCANA Combination, including a $394 million ($295 million after-tax) charge related to a voluntary retirement program, attributable to: |
| • | Dominion Energy Virginia ($151 million after-tax); |
| • | Gas Distribution ($56 million after-tax); |
| • | Dominion Energy South Carolina ($75 million after-tax); and |
| • | Contracted Assets ($38 million after-tax). |
• | A $346 million ($257 million after-tax) charge related to the early retirement of certain Virginia Power electric generation facilities, attributable to Dominion Energy Virginia; |
• | A $194 million tax charge for $258 million of income tax-related regulatory assets acquired in the SCANA Combination for which Dominion Energy committed to forgo recovery, attributable to Dominion Energy South Carolina; |
• | A $160 million ($119 million after-tax) charge related to Virginia Power’s planned early retirement of certain automated meter reading infrastructure, attributable to Dominion Energy Virginia; |
• | A $135 million ($100 million after-tax) charge related to Virginia Power’s contract termination with a non-utility generator, attributable to Dominion Energy Virginia; |
• | A $114 million ($86 million after-tax) charge for property, plant and equipment acquired in the SCANA Combination primarily for which Dominion Energy committed to forgo recovery, attributable to Dominion Energy South Carolina; partially offset by |
• | A $553 million ($411 million after-tax) net gain related to investments in nuclear decommissioning trust funds attributable to: |
| • | Dominion Energy Virginia ($49 million after-tax); and |
| • | Contracted Assets ($362 million after-tax); and |
• | A $113 million ($84 million after-tax) benefit from the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019, attributable to Dominion Energy Virginia. |
The following table presents segment information pertaining to Dominion Energy’s operations: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dominion
Energy
South
Carolina | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total revenue from external customers | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | Depreciation, depletion and amortization | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Equity in earnings of equity method investees | | | | | | | | | | | | | | | | ) | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | Interest and related charges | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | Income tax expense (benefit) | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | Net income (loss) attributable to Dominion Energy | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | Investment in equity method investees | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total revenue from external customers | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | Depreciation, depletion and amortization | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Equity in earnings of equity method investees | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | Interest and related charges | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | Income tax expense (benefit) | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | Net income (loss) attributable to Dominion Energy | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | Investment in equity method investees | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2,640 | | | | 765 | | | | 647 | | | | | | | | 247 | | | | 106 | | | | | | | | 4,405 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total revenue from external customers | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | Depreciation, depletion and amortization | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Equity in earnings of equity method investees | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | Interest and related charges | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | Income tax expense (benefit) | | | | | | | | | | | | | | | | | | | | ) | | | | ) | | | | | | | | ) | Net income (loss) attributable to Dominion Energy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2,726 | | | | 1,489 | | | | 452 | | | | | | | | 979 | | | | 263 | | | | | | | | 5,909 | |
Year Ended December 31, | | Dominion Energy Virginia | | | Gas Distribution | | | Dominion Energy South Carolina | | | Contracted Assets | | | Corporate and Other | | | Adjustments & Eliminations | | | Consolidated Total | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2021 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total revenue from external customers | | $ | 8,012 | | | $ | 2,660 | | | $ | 2,968 | | | $ | 1,018 | | | $ | (759 | ) | | $ | 60 | | | $ | 13,959 | | Intersegment revenue | | | (13 | ) | | | 5 | | | | 7 | | | | 67 | | | | 943 | | | | (1,004 | ) | | | 5 | | Total operating revenue | | | 7,999 | | | | 2,665 | | | | 2,975 | | | | 1,085 | | | | 184 | | | | (944 | ) | | | 13,964 | | Depreciation, depletion and amortization | | | 1,299 | | | | 380 | | | | 486 | | | | 162 | | | | 151 | | | | 0 | | | | 2,478 | | Equity in earnings of equity method investees | | | 0 | | | | 0 | | | | (3 | ) | | | 259 | | | | 20 | | | | 0 | | | | 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 | ) | | | 0 | | | | 425 | | Net income from discontinued operations | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 641 | | | | 0 | | | | 641 | | Net income (loss) attributable to Dominion Energy | | | 1,919 | | | | 600 | | | | 437 | | | | 431 | | | | (99 | ) | | | 0 | | | | 3,288 | | Investment in equity method investees(1) | | | 0 | | | | 106 | | | | 0 | | | | 2,738 | | | | 88 | | | | 0 | | | | 2,932 | | Capital expenditures | | | 3,762 | | | | 1,252 | | | | 694 | | | | 277 | | | | 76 | | | | 0 | | | | 6,061 | | Total assets (billions) | | | 50.3 | | | | 18.5 | | | | 16.4 | | | | 12.3 | | | | 7.1 | | | | (5.0 | ) | | | 99.6 | | 2020 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total revenue from external customers | | $ | 7,802 | | | $ | 2,345 | | | $ | 2,782 | | | $ | 1,020 | | | $ | 200 | | | $ | 48 | | | $ | 14,197 | | Intersegment revenue | | | (15 | ) | | | 10 | | | | 5 | | | | 51 | | | | 963 | | | | (1,039 | ) | | | (25 | ) | Total operating revenue | | | 7,787 | | | | 2,355 | | | | 2,787 | | | | 1,071 | | | | 1,163 | | | | (991 | ) | | | 14,172 | | Depreciation, depletion and amortization | | | 1,247 | | | | 344 | | | | 474 | | | | 182 | | | | 85 | | | | 0 | | | | 2,332 | | Equity in earnings of equity method investees | | | 0 | | | | 0 | | | | (1 | ) | | | 35 | | | | 6 | | | | 0 | | | | 40 | | Interest income | | | 13 | | | | 6 | | | | 12 | | | | 91 | | | | 73 | | | | (88 | ) | | | 107 | | Interest and related charges | | | 527 | | | | 76 | | | | 219 | | | | 75 | | | | 568 | | | | (88 | ) | | | 1,377 | | Income tax expense (benefit) | | | 496 | | | | 121 | | | | 107 | | | | (16 | ) | | | (625 | ) | | | 0 | | | | 83 | | Net income (loss) from discontinued operations | | | 0 | | | | 0 | | | | 0 | | | | 167 | | | | (2,045 | ) | | | 0 | | | | (1,878 | ) | Net income (loss) attributable to Dominion Energy | | | 1,891 | | | | 560 | | | | 419 | | | | 402 | | | | (3,673 | ) | | | 0 | | | | (401 | ) | Investment in equity method investees(1) | | | 0 | | | | 55 | | | | 0 | | | | 2,784 | | | | 95 | | | | 0 | | | | 2,934 | | Capital expenditures | | | 3,406 | | | | 1,151 | | | | 700 | | | | 649 | | | | 425 | | | | 0 | | | | 6,331 | | Total assets (billions) | | | 46.0 | | | | 17.1 | | | | 16.0 | | | | 13.1 | | | | 8.6 | | | | (4.9 | ) | | | 95.9 | | 2019 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total revenue from external customers | | $ | 8,170 | | | $ | 2,367 | | | $ | 2,948 | | | $ | 1,083 | | | $ | (239 | ) | | $ | 79 | | | $ | 14,408 | | Intersegment revenue | | | (13 | ) | | | 18 | | | | 4 | | | | 73 | | | | 1,071 | | | | (1,160 | ) | | | (7 | ) | Total operating revenue | | | 8,157 | | | | 2,385 | | | | 2,952 | | | | 1,156 | | | | 832 | | | | (1,081 | ) | | | 14,401 | | Depreciation, depletion and amortization | | | 1,216 | | | | 335 | | | | 452 | | | | 180 | | | | 100 | | | | 0 | | | | 2,283 | | Equity in earnings of equity method investees | | | 0 | | | | 2 | | | | (4 | ) | | | (1 | ) | | | 11 | | | | 0 | | | | 8 | | Interest income | | | 11 | | | | 4 | | | | 9 | | | | 97 | | | | 112 | | | | (136 | ) | | | 97 | | Interest and related charges | | | 530 | | | | 116 | | | | 242 | | | | 98 | | | | 636 | | | | (136 | ) | | | 1,486 | | Income tax expense (benefit) | | | 482 | | | | 114 | | | | 163 | | | | 20 | | | | (570 | ) | | | 0 | | | | 209 | | Net income from discontinued operations | | | 0 | | | | 0 | | | | 0 | | | | 183 | | | | 533 | | | | 0 | | | | 716 | | Net income (loss) attributable to Dominion Energy | | | 1,786 | | | | 487 | | | | 430 | | | | 460 | | | | (1,805 | ) | | | 0 | | | | 1,358 | | Capital expenditures | | | 3,002 | | | | 853 | | | | 562 | | | | 367 | | | | 537 | | | | 0 | | | | 5,321 | |
(1) | Excludes liability to Atlantic Coast Pipeline. |
Intersegment sales and transfers for Dominion Energy are based on contractual arrangements and may result in intersegment profit or loss that is eliminated in consolidation.
Combined Notesconsolidation, including amounts related to Consolidated Financial Statements, Continuedentities presented within discontinued operations.
The Corporate and Other Segment of Virginia Power In 2021, Virginia Power reported after-tax net expenses of $202 million in the Corporate and Other segment, including $202 million of after-tax net expenses for specific items all of which were attributable to its operating segment. The net expenses for specific items attributable to its operating segment in 2021 primarily related to the impact of the following items: • | A $151 million ($112 million after-tax) loss from an unbilled revenue reduction; |
• | A $125 million ($93 million after-tax) net charge associated with the settlement of the 2021 Triennial Review; |
• | A $77 million ($57 million after-tax) charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to Virginia’s 2021 budget process; |
• | A $68 million ($50 million after-tax) charge associated with storm damage and service restoration in its service territory; and |
• | A $61 million ($45 million after-tax) charge for amortization of a regulatory asset established in connection with the settlement of the 2021 Triennial Review; partially offset by |
• | A $130 million ($97 million after-tax) benefit for a change in the expected CCRO to be provided to Virginia retail electric customers under the GTSA. |
In 2020, Virginia Power reported after-tax net expenses of $863 million in the Corporate and Other segment, including $915 million of after-tax net expenses for specific items all of which were attributable to its operating segment. The net expenses for specific items attributable to its operating segment in 2020 primarily related to a $751 million ($559 million after-tax) charge related to the planned early retirement of certain electric generation facilities, a $130 million ($97 million after-tax) charge for the expected CCRO to be provided to Virginia retail electric customers under the GTSA and a $127 million ($94 million after-tax) charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to legislation enacted in November 2020. In 2019, Virginia Power reported after-tax net expenses of $634 million in itsthe Corporate and Other segment, withincluding $627 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 2019 primarily related to the impact of the following items: • | A $346 million ($257 million after-tax) charge related to the early retirement of certain electric generation facilities; |
A $346 million ($257 millionafter-tax)
charge related to the early retirement of certain electric generation facilities;• | A $198 million ($146 million after-tax) charge related to a voluntary retirement program; |
• | A $160 million ($119 million after-tax) charge related to the planned early retirement of certain automated meter reading infrastructure; |
• | A $135 million ($100 million after-tax) charge related to a contract termination with a non-utility generator; and |
• | A $62 million ($46 million after-tax) charge related to the abandonment of a project at an electric generating facility; partially offset by |
• | A $113 million ($84 million after-tax) benefit from the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019. |
A $198 million ($146 millionafter-tax)
charge related to a voluntary retirement program;A $160 million ($119 millionafter-tax)
charge related to the planned early retirement of certain automated meter reading infrastructure;A $135 million ($100 millionafter-tax)
charge related to a contract termination with anon-utility
generator; andA $62 million ($46 millionafter-tax)
charge related to the abandonment of a project at an electric generating facility, partially offset byA $113 million ($84 millionafter-tax)
benefit from the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019.In 2018, Virginia Power reportedafter-tax
net expenses of $312 million in its Corporate and Other segment, all of which were
attributable to its primary operating segment.The net expenses for specific items in 2018 primarily related to the impact of the following items:
A $215 million ($160 millionafter-tax)
charge associated with Virginia legislation enacted in March 2018 that requiresone-time
rate credits of certain amounts to utility customers;An $81 million ($60 millionafter-tax)
charge associated primarily with the asset retirement obligations for ash ponds and landfills at certain utility generation facilities in connection with the enactment of Virginia legislation in April 2018; andA $70 million ($52 millionafter-tax)
charge associated with major storm damage and service restoration.In 2017, Virginia Power reported anafter-tax
net benefit of $74 million in its Corporate and Other segment, all of which was attributable to its primary operating segment.The net benefit for specific items in 2017 primarily related to the impact of the following item:
A $93 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act.
The following table presents segment information pertaining to Virginia Power’s operations: Year Ended December 31, | | Dominion Energy Virginia | | | Corporate and Other | | | Consolidated Total | | (millions) | | | | | | | | | | | | | 2021 | | | | | | | | | | | | | Operating revenue | | $ | 7,976 | | | $ | (506 | ) | | $ | 7,470 | | Depreciation and amortization | | | 1,296 | | | | 68 | | | | 1,364 | | Interest income | | | 11 | | | | 0 | | | | 11 | | Interest expense (benefit) and related charges | | | 535 | | | | (1 | ) | | | 534 | | Income tax expense (benefit) | | | 467 | | | | (70 | ) | | | 397 | | Net income (loss) | | | 1,914 | | | | (202 | ) | | | 1,712 | | Capital expenditures | | | 3,756 | | | | 0 | | | | 3,756 | | Total assets (billions) | | | 47.9 | | | | 0 | | | | 47.9 | | 2020 | | | | | | | | | | | | | Operating revenue | | $ | 7,763 | | | $ | 0 | | | $ | 7,763 | | Depreciation and amortization | | | 1,245 | | | | 7 | | | | 1,252 | | Interest income | | | 11 | | | | 0 | | | | 11 | | Interest expense (benefit) and related charges | | | 524 | | | | (8 | ) | | | 516 | | Income tax expense (benefit) | | | 500 | | | | (271 | ) | | | 229 | | Net income (loss) | | | 1,884 | | | | (863 | ) | | | 1,021 | | Capital expenditures | | | 3,372 | | | | 0 | | | | 3,372 | | Total assets (billions) | | | 43.7 | | | | 0 | | | | 43.7 | | 2019 | | | | | | | | | | | | | Operating revenue | | $ | 8,137 | | | $ | (29 | ) | | $ | 8,108 | | Depreciation and amortization | | | 1,215 | | | | 8 | | | | 1,223 | | Interest income | | | 11 | | | | 0 | | | | 11 | | Interest expense (benefit) and related charges | | | 529 | | | | (5 | ) | | | 524 | | Income tax expense (benefit) | | | 481 | | | | (217 | ) | | | 264 | | Net income (loss) | | | 1,783 | | | | (634 | ) | | | 1,149 | | Capital expenditures | | | 2,981 | | | | 0 | | | | 2,981 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | Depreciation and amortization | | | | | | | | | | | | | | | | | | | | | | | | | | Interest expense (benefit) and related charges | | | | | | | | ) | | | | | Income tax expense (benefit) | | | | | | | | ) | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | Depreciation and amortization | | | | | | | | ) | | | | | Interest income (expense) | | | | | | | | | | | | | Interest expense (benefit) and related charges | | | | | | | | ) | | | | | Income tax expense (benefit) | | | | | | | | ) | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Depreciation and amortization | | | | | | | | | | | | | Interest income (expense) | | | | | | | | | | | | | Interest expense (benefit) and related charges | | | | | | | | ) | | | | | Income tax expense (benefit) | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The Corporate and Other Segment of Dominion Energy Gas
primarily includes specific items attributable to Dominion Energy Gas’ operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources and the effect of certain items recorded at Dominion Energy Gas as a result of Dominion Energy’s basis in the net assets contributed. In addition, Corporate and Other includes the net impact of discontinued operations, which are discussed in Note 3.In 2019, Dominion Energy Gas reportedan
after-tax
net benefit of $127 million in its Corporate and Other segment, with $12 million of netexpense
attributable to its operating segment.The net
expense
for specific items in 2019 primarily related to the impact of the following items:
A $48 million tax benefit resulting from changes in tax status of certain subsidiaries in connection with the Dominion Energy Gas Restructuring;
and
A $42 million ($31 millionafter-tax)
charge related to a voluntary retirement program.In 2018, Dominion Energy Gas reportedafter-tax
net expenses of $90 million in its Corporate and Other segment, with $107 million of these net expenses attributable to its operating segment.The net expense for specific items in 2018 primarily related to a $124 million ($88 millionafter-tax)
charge for disallowance of FERC-regulated plant.In 2017, Dominion Energy Gas reportedan
after-tax
net benefit of $389 million in its Corporate and Other segment, with $156 million of the netbenefit
attributable to its operating segment.The net benefit for specific items in 2017 primarily related to a $169 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act.
The following table presents segment information pertaining to Dominion Energy Gas’ operations:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | Depreciation and amortization | | | | | | | | | | | | | Equity in earnings of equity method investees | | | | | | | | | | | | | | | | | | | | | | | | | | Interest and related charges | | | | | | | | | | | | | Income tax expense (benefit) | | | | | | | | ) | | | | | Net Income from discontinued operations | | | | | | | | | | | | | Net Income attributable to Dominion Energy Gas | | | | | | | | | | | | | Investment in equity method investees | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Depreciation and amortization | | | | | | | | | | | | | Equity in earnings of equity method investees | | | | | | | | | | | | | | | | | | | | | | | | | | Interest and related charges | | | | | | | | | | | | | Income tax expense (benefit) | | | | | | | | ) | | | | | Net Income from discontinued operations | | | | | | | | | | | | | Net Income (loss) attributable to Dominion Energy Gas | | | | | | | | ) | | | | | Investment in equity method investees | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Depreciation and amortization | | | | | | | | | | | | | Equity in earnings of equity method investees | | | | | | | | | | | | | | | | | | | | | | | | | | Interest and related charges | | | | | | | | | | | | | Income tax expense (benefit) | | | | | | | | ) | | | | ) | Net Income from discontinued operations | | | | | | | | | | | | | Net Income attributable to Dominion Energy Gas | | | | | | | | | | | | | | | | | | | | | | | | | |
Combined Notes to Consolidated Financial Statements, Continued
Note 27. Quarterly Financial Data (Unaudited)
A summary of the Companies’ quarterly results of operations for the years ended December 31, 2019 and 2018 follows. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | $ | | | Income (loss) from operations | | | | ) | | | | | | | | | | | | | Net income (loss) including noncontrolling interests | | | | ) | | | | | | | | | | | | | Net income (loss) attributable to Dominion Energy | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net income (loss) attributable to Dominion Energy | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net income (loss) attributable to Dominion Energy | | | | ) | | | | | | | | | | | | | Dividends per share (Series A Preferred Stock) | | | | | | | | | | | | | | | | | Dividends per share (Series B Preferred Stock) | | | | | | | | | | | | | | | | | Dividends declared per common share | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | | | | $ | | | | $ | | | | $ | | | | | | | | | | | | | | | | | | | | Net income including noncontrolling interests | | | | | | | | | | | | | | | | | Net income attributable to Dominion Energy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net income attributable to Dominion Energy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net income attributable to Dominion Energy | | | | | | | | | | | | | | | | | Dividends declared per common share | | | | | | | | | | | | | | | | |
Dominion Energy’s 2019 results include the impact of the following significant items:
Fourth quarter results include a $244 million after-tax charge related to litigation acquired in the SCANA Combination, offset by a $150 million net gain related to nuclear decommissioning trust funds.
Second quarter results include a $316 million after-tax charge related to a voluntary retirement program, a $100 million after-tax charge related to a contract termination with a non-utility generator and a $75 million after-tax charge for litigation acquired in the SCANA Combination.
First quarter results include $1.3 billion of after-tax merger and integration-related costs related to the SCANA Combination (inclusive of a $756 million after-tax charge for refunds of amounts previously collected from retail electric customers of DESC for the NND Project, a $277 million after-tax charge for certain regulatory assets and property, plant and equipment acquired in the SCANA Combination for which Dominion Energy committed to forego recovery and $134 million after-tax charge for litigation acquired in the SCANA Combination) and a $409 million after-tax charge for the planned early retirement of certain Virginia Power electric generation facilities and automated metering reading infrastructure
, partially offset by $197 million after-tax net gain related to nuclear decommissioning trust funds and an $84 million after-tax revision to future ash ponds and landfill closure costs.Dominion Energy’s 2018 results include the impact of the following significant items:
Fourth quarter results include $536 million ofafter-tax
gains from the sale of certain merchant generation facilities and equity method investments partially offset by a $164 millionafter-tax
impairment charge for certain gathering and processing assets.Second quarter results include an $89 millionafter-tax
charge for disallowance of FERC-regulated plant.First quarter results include a $160 millionafter-tax
charge associated with Virginia legislation enacted in March 2018 that requiredone-time
rate credits of certain amounts to utility customers.Virginia Power’s quarterly results of operations were as follows:
Virginia Power’s 2019 results include the impact of the following significant item:
Second quarter results include a $144 million after-tax charge related to a voluntary retirement program, a $100 million after-tax charge related to a contract termination with a non-utility generator and a $47 million after-tax charge for the abandonment of a project at an electric generation facility.
First quarter results include a $409 millionafter-tax
chargefor the planned early retirement of certain electric generation facilities and automated metering reading infrastructure, partially offset by an $84 million after-tax revision to future ash ponds and landfill closure costs.
Virginia Power’s 2018 results include the impact of the following significant item:
First quarter results include a $160 millionafter-tax
charge associated with Virginia legislation enacted in March 2018 that requiredone-time
rate credits of certain amounts to utility customers.Dominion Energy Gas’ quarterly results of operations were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Income from continuing operations | | | | | | | | | | | | | | | | | Net income from continuing operations | | | | | | | | | | | | | | | | | Net income from discontinued operations | | | | | | | | | | | | | | | | | Net income including noncontrolling interests | | | | | | | | | | | | | | | | | Net income attributable to
Dominion Energy Gas | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Income from continuing operations | | | | | | | | | | | | | | | | | Net income from continuing operations | | | | | | | | | | | | | | | | | Net income (loss) from discontinued operations | | | | | | | | | | | | | | | | ) | Net income including noncontrolling interests | | | | | | | | | | | | | | | | | Net income attributable to Dominion Energy Gas | | | | | | | | | | | | | | | | |
Dominion Energy Gas’s 2019 results include the impact of the following significant items:
Second quarter results include a $58 million after-tax charge related to a voluntary retirement program, including $32 million in discontinued operations.
Dominion Energy Gas’s 2018 results include the impact of the following significant items:
Fourth quarter results include a $165 millionafter-tax
impairment charge for certain gathering and processing assets, included in discontinued operations.Second quarter results include an $89 millionafter-tax
charge for disallowance of FERC-regulated plant.
Combined Notes to Consolidated Financial Statements, Continued
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure Item 9A. Controls and Procedures 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 20192021 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, 2019,2021, Dominion Energy makes the following assertions: Management is responsible for establishing and maintaining effective internal control over financial reporting of Dominion Energy. There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time. Management evaluated Dominion Energy‘sEnergy’s internal control over financial reporting as of December 31, 2019.2021. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Dominion Energy maintained effective internal control over financial reporting as of December 31, 2019. 2021.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. In January 2019, Dominion Energy acquired SCANA. Dominion Energy excluded all of the acquired SCANA businesses from the scope of management’s assessment of the effectiveness of Dominion Energy’s internal control over financial reporting as of December 31, 2019. SCANA constituted 19% of Dominion Energy’s total revenues for 2019 and 17% of Dominion Energy’s total assets as of December 31, 2019.
February 28, 202024, 2022
Report of Independent Registered Public Accounting Firm
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, 2019,2021, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, Dominion Energy maintained, in all material respects, effective internal control over financial reporting at December 31, 2019,2021, based on criteria established in Internal Control—Integrated Framework (2013) issued by COSO. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements at and for the year ended December 31, 2019,2021, of Dominion Energy and our report dated February 28, 2020,24, 2022, expressed an unqualified opinion on those consolidated financial statements. As described in Management’s Annual Report on Internal Control over Financial Reporting, management excluded from its assessment the internal control over financial reporting the legacy SCANA Corporation businesses (the “SCANA businesses”), which were acquired on January 1, 2019, and which constitute 19% of total revenues and 17% of total assets of the consolidated financial statement amounts at and for the year ended December 31, 2019. Accordingly, our audit did not include the internal control over financial reporting of SCANA businesses.
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 February 28, 202024, 2022
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 2021 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, 2019,2021, Virginia Power makes the following assertions: Management is responsible for establishing and maintaining effective internal control over financial reporting of Virginia Power. There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time. Management evaluated Virginia Power’sPower's internal control over financial reporting as of December 31, 2019.2021. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Virginia Power maintained effective internal control over financial reporting as of December 31, 2019. 2021.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, 202024, 2022
Senior management of Dominion Energy Gas, including Dominion Energy Gas’ CEO and CFO, evaluated the effectiveness of Dominion Energy Gas’ disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Dominion Energy Gas’ CEO and CFO have concluded that Dominion Energy Gas’ 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 Gas’ internal control over financial reporting.
Management’s Annual Report on Internal Control over Financial Reporting
Management of Dominion Energy Gas understands and accepts responsibility for Dominion Energy Gas’ financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Dominion Energy Gas continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as it does throughout all aspects of its business.
Dominion Energy Gas 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 Dominion Energy Gas’ Audit Committee and meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss Dominion Energy Gas’ 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 Dominion Energy Gas’ 2019 Annual Report to contain a management’s report regarding the effectiveness of internal control. As a basis for the report, Dominion Energy Gas tested and evaluated the design and operating effectiveness of internal controls. Based on the assessment as of December 31, 2019, Dominion Energy Gas makes the following assertions:
Management is responsible for establishing and maintaining effective internal control over financial reporting of Dominion Energy Gas.
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 Gas’ internal control over financial reporting as of December 31, 2019. 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 Gas maintained effective internal control over financial reporting as of December 31, 2019.
This annual report does not include an attestation report of Dominion Energy Gas’ registered public accounting firm regarding internal control over financial reporting. Management’s report is not subject to attestation by Dominion Energy Gas’ independent registered public accounting firm pursuant to a permanent exemption under the Dodd-Frank Act.
Item 9B. Other Information Explanatory Note: The following information is furnished in this Form 10-K in lieu of being furnished pursuant to None. Item 2.02 in a Form 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections Not applicable. 8-K.
The date of the events reported below was February 28, 2020.On February 11, 2020, Dominion Energy issued its 4th Quarter 2019 Earnings Release Kit reporting unaudited earnings determined in accordance with GAAP for the year ended December 31, 2019. On February 28, 2020, Dominion Energy issued a revised 4th Quarter 2019 Earnings Release Kit to reflect a reduction in reported earnings for the year ended December 31, 2019. The reduction relates to additional reserves taken for SCANA legal proceedings. The revised Earnings Release Kit reflecting the reduction in earnings is furnished with this Form 10-K as Exhibit 99.
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: Information regarding the directors required by this item is found underincorporated by reference to the headingsections entitled Item 1—Election of Directors .Information regarding compliance with Section 16 of the Securities Exchange Act of 1934, as amended, required by this item is found under the headingDelinquent Section 16(a) Reports
.Information regarding the Dominion Energy Audit Committee Financial expert(s) required by this item is found under the heading, Corporate Governance—The Committees of the Board—Audit Committee .Information regarding the Dominion Energy Audit Committee required by this item is found under the headingsThe Committees of the Board—Audit Committee
and .Information regarding Dominion Energy’s Corporate Governance—Other Governance Policies and Practices—Code of Ethics and Business Conduct required by this item is found under in the heading—Code of Ethics and Business Conduct
.Dominion Energy 2022 Proxy Statement.The information concerning the executive officers of Dominion Energy required by this item is included in Part I of this Form 10-K under the caption . 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 headings Compensation Discussion and Analysis
andsections entitled Executive Compensation, Tables ; the information regarding Compensation Committee interlocks contained under the headingCompensation Committee Interlocks
; 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 headingCompensation of Non-Employee Directors. Directors and Corporate Governance—The Committees of the Board—Compensation Committee Interlocks and Insider Participation in the 2022 Proxy Statement.Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters DOMINION ENERGY The information concerning stock ownershiprequired by directors, executive officers and five percent beneficial owners contained under the heading in the 2020 Proxy Statementthis item is incorporated by reference.The information regarding equity securitiesreference to the sections entitled Security Ownership of Dominion Energy that are authorized for issuance under its equity compensation plans contained under the headingCertain Beneficial Owners and Management and Executive Compensation Tables-Equity Compensation—Equity Compensation Plans in the 20202022 Proxy Statement is incorporated by reference.Statement.Item 13. Certain Relationships and Related Transactions, and Director Independence DOMINION ENERGY The information regarding related party transactions required by this item found underis incorporated by reference to the heading sections entitled Corporate Governance—Other Information—CertainGovernance Policies and Practices —Certain Relationships and Related Party Transactions and information regarding director independence found under the headingCorporate Governance –Director—Director Independence in the 20202022 Proxy Statement is incorporated by reference.
Statement.Item 14. Principal Accountant Fees and Services DOMINION ENERGY The information concerning principal accountant fees and services contained underrequired by this item is incorporated by reference to the heading section entitled Audit-Related Matters—Auditor Fees and Pre-Approval Policy in the 20202022 Proxy Statement is incorporated by reference.Statement.
Virginia Power and Dominion Energy Gas
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, 20192021 and 2018.2020. Type of Fees | | 2021 | | | 2020 | | (millions) | | | | | | | | | Virginia Power | | | | | | | | | Audit fees | | $ | 2.37 | | | $ | 2.30 | | Audit-related fees | | | — | | | — | | Tax fees | | | 0.04 | | | — | | All other fees | | | — | | | — | | Total Fees | | $ | 2.41 | | | $ | 2.30 | |
Audit fees represent fees of Deloitte & Touche LLP for the audit of Virginia Power 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 10-Q reports, and the services that an independent auditor would customarily provide in connection with subsidiary audits, statutory requirements, regulatory filings and similar engagements for the fiscal year, such as comfort letters, attest services, consents and assistance with review of documents filed with the SEC. Audit-related fees consist of assurance and related services that are reasonably related to the performance of the audit or review of Virginia Power 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 Committee pre-approval policy for their independent auditor’s services and fees and have delegated the execution of this policy to the Dominion Energy Audit Committee. In accordance with this delegation, each year the Dominion Energy Audit Committee pre-approves a schedule that details the services to be provided for the following year and an estimated charge for such services. At its December 20192021 meeting, the Dominion Energy Audit Committee approved schedules of services and fees for 2020 2022inclusive of Virginia Power and Dominion Energy Gas.Power. In accordance with the pre-approval policy, any changes to the pre-approved schedule may be pre-approved by the Dominion Energy Audit Committee or a delegated member of the Dominion Energy Audit Committee.
Item 15. Exhibits and Financial Statement Schedules (a) Certain documents are filed as part of this Form 10-K and are incorporated by reference and found on the pages noted. 80.2. All schedules are omitted because they are not applicable, or the required information is either not material or is shown in the financial statements or the related notes. 3. Exhibits (incorporated by reference unless otherwise noted) Exhibit Number | | Description | | Dominion Energy | | | | | | | | | | | | Virginia Power | | | | | | | | | | | | | | 2.1.a | | | | Purchase and Sale Agreement, and Plandated as of MergerJuly 3, 2020, by and among Dominion Energy, Inc., Sedona Corp.Dominion Energy Questar Corporation and SCANA Corporation, dated as of January 2, 2018Berkshire Hathaway Energy Company (Exhibit 2.1, Form 8-K filed January 5, 2018,July 6, 2020, File No. 1-8489). | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2.1.b | | Purchase and Sale Agreement, dated as of October 5, 2020, by and among Dominion Energy Questar Corporation, Berkshire Hathaway Energy Corporation and Dominion Energy, Inc., as guarantor (Exhibit 2.1, Form 8-K filed October 6, 2020, File No. 1-8489). | | | | | 3.1.a | | Dominion Energy, Inc. Articles of Incorporation, as restated,amended, effective December 13, 20199, 2021 (Exhibit 3.1, Form 8-K filed December 13, 2019,9, 2021, File No.1-8489). | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 3.1.b | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 3.2.a | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dominion Energy, Inc. Bylaws, as amended and restated, effective September 26, 2019May 5, 2021 (Exhibit 3.2,3.1, Form 8-K filed October 2, 2019,May 6, 2021, File No. 1-8489). | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 3.2.b | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 4 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dominion Energy, Inc., and Virginia Electric and Power Company and Dominion Energy Gas Holdings, LLC agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of any of their total consolidated assets. | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 4.1.a | | | | | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 4.1.b | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 4.2 | | | | Indenture of Mortgage of Virginia Electric and Power Company, dated November 1, 1935, as supplemented and modified by Fifty-Eighth Supplemental Indenture (Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255); Ninety-Second Supplemental Indenture, dated as of July 1, 2012 (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2012 filed August 1, 2012, File No. 1-2255).. | | X | | | | | | | | | | |
Exhibit Number | | Description | | Dominion Energy | | | | Virginia Power | | | | | | | |
| | | | | | | | | | | | | | | | | 4.3 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Form of Senior Indenture, dated June 1, 1998, between Virginia Electric and Power Company and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed February 27, 1998, File No. 333-47119);; Form of Thirteenth Supplemental Indenture, dated as of January 1, 2006 (Exhibit 4.3, Form 8-K filed January 12, 2006, File No. 1-2255);; Form of Fourteenth Supplemental Indenture, dated May 1, 2007 (Exhibit 4.2, Form 8-K filed May 16, 2007, File No. 1-2255);; Form of Seventeenth Supplemental Indenture, dated November 1, 2007 (Exhibit 4.3, Form 8-K filed November 30, 2007, File No. 1-2255);; Form of Nineteenth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 5, 2008, File No. 1-2255);; Form of Twentieth Supplemental Indenture, dated June 1, 2009 (Exhibit 4.3, Form 8-K filed June 24, 2009, File No. 1-2255); Form of Twenty-First Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 1, 2010, File No. 1-2255);; Twenty-Second Supplemental Indenture, dated as of January 1, 2012 (Exhibit 4.3, Form 8-K filed January 12, 2012, File No. 1-2255);; Twenty-Fourth Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.4, Form 8-K filed January 8, 2013, File No. 1-2255);; Twenty-Fifth Supplemental Indenture, dated as of March 1, 2013 (Exhibit 4.3, Form 8-K filed March 14, 2013, File No. 1-2255);; Twenty-Sixth Supplemental Indenture, dated as of August 1, 2013 (Exhibit 4.3, Form 8-K filed August 15, 2013, File No. 1-2255);; Twenty-Seventh Supplemental Indenture, dated February 1, 2014 (Exhibit 4.3, Form 8-K filed February 7, 2014, File No. 1-2255);; Twenty-Eighth Supplemental Indenture, dated February 1, 2014 (Exhibit 4.4, Form 8-K filed February 7, 2014, File No. 1-2255);; Twenty-Ninth Supplemental Indenture, dated May 1, 2015 (Exhibit 4.3, Form 8-K filed May 13, 2015, File No. 1-02255);; Thirtieth Supplemental Indenture, dated May 1, 2015 (Exhibit 4.4, Form 8-K filed May 13, 2015, File No. 1-02255);; Thirty-First Supplemental Indenture, dated January 1, 2016 (Exhibit 4.3, Form 8-K filed January 14, 2016, File No. 000-55337);; Thirty-Second Supplemental Indenture, dated November 1, 2016 (Exhibit 4.3, Form 8-K filed November 16, 2016, File No. 000-55337);; Thirty-Third Supplemental Indenture, dated November 1, 2016 (Exhibit 4.4, Form 8-K filed November 16, 2016, File No. 000-55337);; Thirty-Fourth Supplemental Indenture, dated March 1, 2017 (Exhibit 4.3, Form 8-K filed March 16, 2017; File No. 000-55337).. | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 4.4 | | | | Senior Indenture, dated as of September 1, 2017, between Virginia Electric and Power Company and U.S. Bank National Association, as Trustee (Exhibit 4.1, Form 8-K filed September 13, 2017, File No.000-55337);; First Supplemental Indenture, dated as of September 1, 2017 (Exhibit 4.2, Form 8-K filed September 13, 2017, File No.000-55337);; Second Supplemental Indenture, dated as of March 1, 2018 (Exhibit 4.2, Form 8-K filed March 22, 2018, File No. 000-55337);; Third Supplemental Indenture, dated as of November 1, 2018 (Exhibit 4.2, Form 8-K filed November 28, 2018, File No. 000-55337);; Fourth Supplemental Indenture, dated as of July 1, 2019 (Exhibit 4.2, Form 8-K filed July 10, 2019, File No. 00-55337);; Fifth Supplemental Indenture, dated as of December 1, 2019 (Exhibit 4.2, Form 8-K filed December 5, 2019, File No. 000-55337);Sixth Supplemental Indenture, dated as of December 1, 2020 (Exhibit 4.2, Form 8-K filed December 15, 2020, File No. 00-55337);Seventh Supplemental Indenture, dated as of November 1, 2021 (Exhibit 4.2, Form 8-K filed November 22, 2021, File No.000-55337);Eighth Supplemental Indenture, dated as of November 1, 2021 (Exhibit 4.3, Form 8-K filed November 22, 2021, File No.000-55337);Ninth Supplemental Indenture, dated as of January 1, 2022 (Exhibit 4.3, Form 8-K filed January 13, 2022, File No.000-55337). | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 4.5 | | | | Indenture, Junior Subordinated Debentures, dated December 1, 1997, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)) as supplemented by a Form of Second Supplemental Indenture, dated January 1, 2001 (Exhibit 4.6, Form 8-K filed January 12, 2001, File No. 1-8489).. | | X | | |
Exhibit Number | | Description | | Dominion Energy | | | | Virginia Power | | | | | | | | | | | | | | | | | | 4.6 | | | | Indenture, dated April 1, 1995, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to United States Trust Company of New York) (Exhibit (4), Certificate of Notification No. 1 filed April 19, 1995, File No. 70-8107);; Securities Resolution No. 2 effective as of October 16, 1996 (Exhibit 2, Form 8-A filed October 18, 1996, File No. 1-3196 and relating to the 6 7/8% Debentures Due October 15, 2026);; Securities Resolution No. 4 effective as of December 9, 1997 (Exhibit 2, Form 8-A filed December 12, 1997, File No. 1-3196 and relating to the 6.80% Debentures Due December 15, 2027).. | | X | | | | | | | | | | |
| | | | | | | | | | | | | | | | | 4.7 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Form of Senior Indenture, dated June 1, 2000, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed December 21, 1999, File No. 333-93187);; Form of Sixteenth Supplemental Indenture, dated December 1, 2002 (Exhibit 4.3, Form 8-K filed December 13, 2002, File No. 1-8489);; Form of Twenty-First Supplemental Indenture, dated March 1, 2003 (Exhibits 4.3, Form 8-K filed March 4, 2003, File No. 1-8489);; Form of Twenty-Second Supplemental Indenture, dated July 1, 2003 (Exhibit 4.2, Form 8-K filed July 22, 2003, File No. 1-8489);; Form of Twenty-Ninth Supplemental Indenture, dated June 1, 2005 (Exhibit 4.3, Form 8-K filed June 17, 2005, File No. 1-8489);; Form of Thirty-Sixth Supplemental Indentures, dated June 1, 2008 (Exhibit 4.3, Form 8-K filed June 16, 2008, File No. 1-8489);; Form of Thirty-Ninth Supplemental Indenture, dated August 1, 2009 (Exhibit 4.3, Form 8-K filed August 12, 2009, File No. 1-8489); Forty-Third Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K, filed August 5, 2011, File No. 1-8489);; Forty-Sixth Supplemental Indenture, dated September 1, 2012 (Exhibit 4.4, Form 8-K, filed September 13, 2012, File No. 1-8489);; Forty-Seventh Supplemental Indenture, dated September 1, 2012 (Exhibit 4.5, Form 8-K, filed September 13, 2012, File No. 1-8489);; Fifty-First Supplemental Indenture, dated November 1, 2014 (Exhibit 4.5, Form 8-K, filed November 25, 2014, File No. 1-8489).. | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 4.8 | | | | Indenture, dated as of June 1, 2015, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Trustee (Exhibit 4.1, Form 8-K filed June 15, 2015, File No. 1-8489);; Second Supplemental Indenture, dated as of September 1, 2015 (Exhibit 4.2, Form 8-K filed September 24, 2015, File No. 1-8489);; Fourth Supplemental Indenture, dated as of August 1, 2016 (Exhibit 4.2, Form 8-K filed August 9, 2016, File No. 1-8489); Fifth Supplemental Indenture, dated as of August 1, 2016 (Exhibit 4.3, Form 8-K filed August 9, 2016, File No. 1-8489);; Sixth Supplemental Indenture, dated as of August 1, 2016 (Exhibit 4.4, Form 8-K filed August 9, 2016, File No. 1-8489);; Ninth Supplemental Indenture, dated as of January 1, 2017 (Exhibit 4.2, Form 8-K filed January 12, 2017, File No. 1-8489); Tenth Supplemental Indenture, dated as of January 1, 2017 (Exhibit 4.3, Form 8-K filed January 12, 2017, File No. 1-8489);; Eleventh Supplemental Indenture, dated as of March 1, 2017 (Exhibit 4.3, Form 10-Q filed May 4, 2017, File No. 1-8489);; Twelfth Supplemental Indenture, dated as of June 1, 2017 (Exhibit 4.2, Form 10-Q filed August 3, 2017, File No. 1-8489); Thirteenth Supplemental Indenture, dated December 1, 2017 (Exhibit 4.8, Form 10-K for the fiscal year ended December 31, 2017 filed February 27, 2018, File No. 1-8489);; Fourteenth Supplemental Indenture, dated May 1, 2018 (Exhibit 4.2, Form 10-Q filed August 2, 2018, File No. 1-8489); Fifteenth Supplemental Indenture, dated June 1, 2018 (Exhibit 4.2, Form 8-K, filed June 5, 2018, File No. 1-8489);; Sixteenth Supplemental Indenture, dated March 1, 2019 (Exhibit 4.2, Form 8-K filed March 13, 2019, File No. 1-8489);; Seventeenth Supplemental Indenture, dated as of August 1, 2019 (Exhibit 4.2, Form 10-Q filed November 1, 2019, File No. 1-8489);Eighteenth Supplemental Indenture, dated as of March 1, 2020 (Exhibit 4.2, Form 8-K, filed March 19, 2020, File No. 1-8489);Nineteenth Supplemental Indenture, dated as of March 1, 2020 (Exhibit 4.3, Form 8-K, filed March 19, 2020, File No. 1-8489);Twentieth Supplemental Indenture, dated as of April 1, 2020 (Exhibit 4.2, Form 8-K, filed April 3, 2020, File No. 1-8489);Twenty-First Supplemental Indenture, dated as of September 1, 2020 (Exhibit 4.2, Form 8-K, filed September 17, 2020, File No. 1-8489);Twenty-Second Supplemental Indenture, dated as of April 1, 2021 (Exhibit 4.2, Form 8-K, filed April 5, 2021, File No. 1-8489);Twenty-Third Supplemental Indenture, dated as of April 1, 2021 (Exhibit 4.3, Form 8-K, filed April 5, 2021, File No. 1-8489);Twenty-Fourth Supplemental Indenture, dated as of August 1, 2021 (Exhibit 4.2, Form 8-K filed August 12, 2021, File No. 1-8489). | | X | | |
Exhibit Number | | Description | | Dominion Energy | | | | Virginia Power | | | | | | | | | | | | | | | | | | 4.9 | | | | Junior Subordinated Indenture II, dated June 1, 2006, between Dominion Resources, Inc. and The Bank of New York Mellon (successor to JPMorgan Chase Bank, N.A.), as Trustee (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489);; First Supplemental Indenture dated as of June 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489);; Second Supplemental Indenture, dated as of September 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489);; Third Supplemental and Amending Indenture, dated as of June 1, 2009 (Exhibit 4.2, Form 8-K filed June 15, 2009, File No. 1-8489);; Sixth Supplemental Indenture, dated as of June 1, 2014 (Exhibit 4.3, Form 8-K filed July 1, 2014, File No. 1-8489); Seventh Supplemental Indenture, dated as of September 1, 2014 (Exhibit 4.3, Form 8-K filed October 3, 2013, File No. 1-8489);; Eighth Supplemental Indenture, dated March 7, 2016 (Exhibit 4.4, Form 8-K filed March 7, 2016, File No. 1-8489);; Ninth Supplemental Indenture, dated May 26, 2016 (Exhibit 4.4, Form 8-K filed May 26, 2016, File No. 1-8489); Tenth Supplemental Indenture, dated July 1, 2016 (Exhibit 4.3, Form 8-K filed July 19, 2016, File No. 1-8489);; Eleventh Supplemental Indenture, dated August 1, 2016 (Exhibit 4.3, Form 8-K filed August 15, 2016, File No. 1-8489); Twelfth Supplemental Indenture, dated August 1, 2016 (Exhibit 4.4, Form 8-K filed August 15, 2016, File No. 1-8489); Thirteenth Supplemental Indenture, dated May 18, 2017 (Exhibit 4.4, Form 8-K filed May 18, 2017, File No. 1-8489);; Fourteenth Supplemental Indenture, dated June 27, 2019 (Exhibit 4.5, Form 8-K filed June 27, 2019, File No. 1-8489);; Fifteenth Supplemental Indenture, dated June 27, 2019 (Exhibit 4.6, Form 8-K filed June 27, 2019, File No. 1-8489).. | | X | | | | | | | | | | |
| | | | | | | | | | | | | | | | | Exhibit
Number4.10 | | | Description | | Dominion
Energy
| | | Virginia
Power
| | | Dominion
Energy
Gas
| | | | | | | | | | | | | | | | | | | | 4.10 | | | Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 23, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No. 1-8489).
| | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 4.11 | | | Replacement Capital Covenant entered into by Dominion Resources, Inc. dated September 29, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No. 1-8489). | | | X | | | | | | | | | | | 4.12 | | | | | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 4.13 | | | Indenture, dated as of October 1, 2013, between Dominion Gas Holdings, LLC and Deutsche Bank Trust Company Americas, as Trustee (Exhibit 4.1, Form S-4 filed April 4, 2014, File No. 333-195066);Second Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.3, Form S-4 filed April 4, 2014, File No. 333-195066);Third Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.4, Form S-4 filed April 4, 2014, File No. 333-195066);Fourth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.2, Form 8-K filed December 8, 2014, File No. 333-195066);Fifth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.3, Form 8-K filed December 8, 2014, File No. 333-195066);Sixth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.4, Form 8-K filed December 8, 2014, File No. 333-195066);Seventh Supplemental Indenture, dated as of November 1, 2015 (Exhibit 4.2, Form 8-K filed November 17, 2015, File No. 001-37591);Eighth Supplemental Indenture, dated as of May 1, 2016 (Exhibit 4.1.a, Form 10-Q filed August 3, 2016, File No. 1-37591); Ninth Supplemental Indenture, dated as of June 1, 2016 (Exhibit 4.1.b, Form 10-Q filed August 3, 2016, File No. 1-37591); Tenth Supplemental Indenture, dated as of June 1, 2016 (Exhibit 4.1.c, Form 10-Q filed August 3, 2016, File No. 1-37591); Eleventh Supplemental Indenture, dated June 1, 2018 (Exhibit 4.2, Form 8-K filed June 19, 2018, File No. 1-37591);Twelfth Supplemental Indenture, dated November 1, 2019 (Exhibit 4.2, Form 8-K filed November 21, 2019, File No. 1-37591); Thirteenth Supplemental Indenture, dated November 1, 2019 (Exhibit 4.3, Form 8-K filed November 21, 2019, File No. 1-37591); Fourteenth Supplemental Indenture, dated November 1, 2019 (Exhibit 4.4, Form 8-K filed November 21, 2019, File No. 1-37591). | | | X | | | | X | | | | | | | | | | | | | | | | | | | | | | | | 4.14 | | | 2019 Series A Purchase Contract and Pledge Agreement, dated June 14, 2019, among the Dominion Energy, Inc., Deutsche Bank Trust Company Americas, in its capacity as the purchase contract agent, and HSBC Bank USA, National Association, in its capacity as the collateral agent, custodial agent and securities intermediary (Exhibit 3.1,4.1, Form 8-K filed June 14, 2019, File No.1-8489). | | X | X | | | | | | | | | | | | | | | | | | | | | | | | | | | 4.11 | 4.15 | | | | | X | | | | | | | | | | 4.12 | | Registration Rights Agreement, date December 16, 2019,1, 2021, by and between Dominion Energy, Inc. and Gallagher Fiduciary Advisors, LLC on behalf of the Dominion Energy, Inc. Defined Benefit Master Trust (Exhibit 4.1,4.2, Form 8-K filed December 20, 2019,9, 2021, File No. 1-8489). | | X | X | | | | | | | | | | | | | | | | | | | | | | | | | | | 4.13 | 4.16 | | | | | X | X | | | | | | | | | | | | | | | | | | | | | | | | | | | 4.14 | 4.17 | | | | | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 4.18 | | | | | X | X | | | | | | | | | | | | | | | | | | | | | | | | | | | 4.15 | 4.19 | | | | | | | | | | X | | | | | | | | | | | | | | | | | | | | | | | 10.1 | 4.20 | | | | | | | | | | | | | | X | | | | | | | | | | | | | | | | | | | | 4.21 | | | | | | | | | | | | | | X | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $6,000,000,000 FourthFifth Amended and Restated Revolving Credit Agreement, dated March 22, 2019,June 9, 2021, among Dominion Energy, Inc., Virginia Electric and Power Company, Dominion Energy Gas Holdings, LLC, Questar Gas Company, Dominion Energy South Carolina, Electric & Gas Company,Inc., JPMorgan Chase Bank, N.A., as Administrative Agent, Mizuho Bank, Ltd., Bank of America, N.A., The Bank of Nova Scotia and Wells Fargo Bank, N.A., as Syndication Agents, J.P. Morgan Securities LLC and Mizuho Bank, Ltd., as Co-Sustainability Structuring Agent, and other lenders named therein (Exhibit 10.1, Form 8-K filed March 26, 2019,June 10, 2021, File No. 1-8489). | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 10.2 | | | | Inter-Company$900,000,000 Sustainability Revolving Credit Agreement, dated October 17, 2013, betweenas of June 9, 2021, among Dominion Resources,Energy, Inc., Sumitomo Mitsui Banking Corporation, as Administrative Agent and Sustainability Coordinator, Sumitomo Mitsui Banking Corporation, The Bank of Nova Scotia and The Toronto- Dominion Gas Holdings, LLCBank, New York Branch, as Joint Lead Arrangers and Joint Bookrunners, and the other lenders named therein (Exhibit 10.2, Form S-48-K filed April 4, 2014,June 10, 2021, File No. 333-195066)1-8489)..
| | X | | |
Exhibit Number | | Description | | Dominion Energy | | | | Virginia Power | | | | | | | | 10.3 | | $1,265,341,250 364-Day Term Loan Credit Agreement, dated as of July 14, 2021, by and Dominion Energy, Inc., as Borrower, Barclays Bank PLC, as Administrative Agent, Barclays Bank PLC, as Sole Leader Arranger and Sole Bookrunner, and the other lenders from time to time parties thereto (Exhibit 10.1, Form 8-K filed July 14, 2021, File No. 1-8489). | | X | | | | | | | | | | 10.4 | | DRS Services Agreement, dated January 1, 2003, between Dominion Resources, Inc. and Dominion Resources Services, Inc. (Exhibit 10.1, Form 10-K for the fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489).. | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 10.5 | | | | DRSDES Services Agreement, dated January 1, 2012,2021, between Dominion ResourcesEnergy Services, Inc. and Virginia Electric and Power Company (Exhibit 10.2,10.3, Form 10-K for the fiscal year ended December 31, 20112020 filed February 28, 2012,25, 2021, File No. 1-8489 and File No. 1-2255)No.1-8489)..
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 10.6 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 10.7 | | | | | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 10.8* | | | | Dominion Resources, Inc. Executive Supplemental Retirement Plan, as amended and restated effective December 17, 2004 (Exhibit 10.5, Form 8-K filed December 23, 2004, File No. 1-8489), as amended September 26, 2014 (Exhibit 10.1, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014).
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company,, amended and restated July 15, 2003 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2003 filed August 11, 2003, File No. 1-8489 and File No. 1-2255)1-8489),, as amended, March 31, 2006 (Exhibit 10.1, Form 8-K filed April 4, 2006, File No. 1-8489).. | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 10.9* | | | | | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 10.10* | | | | Dominion Resources, Inc. Retirement Benefit Restoration Plan, as amended and restated effective December 17, 2004 (Exhibit 10.6, Form 8-K filed December 23, 2004, File No. 1-8489), as amended September 26, 2014 (Exhibit 10.2, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014).
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 10.11* | | | | Dominion Resources, Inc. New Executive Supplemental Retirement Plan, as amended and restated effective July 1, 2013 (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2013 filed August 6, 2013 File No. 1-8489),, as amended September 26, 2014 (Exhibit 10.3, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014),, as amended effective October 1, 2019 (Exhibit 10.1, Form 8-K filed October 2, 2019, File No. 1-8489),as amended December 11, 2020 (Exhibit 10.9, Form 10-K for the fiscal year ended December 31, 2020 filed February 25, 2021, File No.1-8489). | | X | | | | | | | | | | | | | | | | | | 10.12* | | Dominion Resources, Inc. New Retirement Benefit Restoration Plan, as amended and restated effective January 1, 2009 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489, and Exhibit 10.20, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-2255), as amended September 26, 2014 (Exhibit 10.4, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014). | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, amended as of February 27, 2004 (Exhibit 10.15, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004,, File No. 1-8489). as amended effective December 31, 2004 (Exhibit 10.1, Form 8-K filed December 23, 2004, File No. 1-8489). | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 10.13* | | | | Dominion Resources, Inc. Directors Stock Compensation Plan, as amended February 27, 2004 (Exhibit 10.16, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.2, Form 8-K filed December 23, 2004, File No. 1-8489).
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dominion Resources, Inc. Non-Employee Directors’ Compensation Plan, effective January 1, 2005, as amended and restated effective December 17, 2009 (Exhibit 10.18, Form 10-K filed for the fiscal year ended December 31, 2009 filed February 26, 2010, File No. 1-8489)15, 2021 (filed herewith).. | | X | | | | | | | | | | | | | | | | | |
Exhibit Number | | Description | | Dominion Energy | | | | | | Virginia Power | 10.14* | | | | | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 10.15* | | | | Letter agreement between Dominion Resources, Inc. and Thomas F. Farrell, II, dated February 27, 2003 (Exhibit 10.24, Form 10-K for the fiscal year ended December 31, 2002 filed March 20, 2003, File No. 1-8489), as amended December 16, 2005 (Exhibit 10.1, Form 8-K filed December 16, 2005, File No. 1-8489).
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Form of Advancement of Expenses for certain directors and officers of Dominion Resources, Inc., approved by the Dominion Resources, Inc. Board of Directors on October 24, 2008 (Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-84891-8489). and Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-2255). | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 10.16* | | | | | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 10.17* | | | | Form of Restricted Stock Award Agreement under the 2016 Long-Term Incentive Program approved January 21, 2016Letter agreement between Dominion Resources, Inc. and Thomas F. Farrell, II, dated February 27, 2003 (Exhibit 10.48,10.24, Form 10-K for the fiscal year ended December 31, 20152002 filed February 26, 2016,March 20, 2003, File No. 1-8489),as amended December 16, 2005 (Exhibit 10.1, Form 8-K filed December 16, 2005, File No. 1-8489).
| | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 10.18* | | | | | | X | | | | | | | | | | |
| | | | | | | | | | | | | | | | | 10.19* | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 10.20* | | | | Form of Restricted Stock Award Agreement under the 2018 Long-Term Incentive Program approved January 25, 2018Dominion Energy, Inc. Deferred Compensation Plan, effective July 1, 2021 (Exhibit 10.44,10.18, Form 10-K for the fiscal year ended December 31, 2017,2020, filed February 27, 2018,25, 2021, File No. 1-8489),.
| | | | | | | | | | | | | | | | | 2019 Performance Grant Plan under the 2019 Long-Term Incentive Program approved January 24, 2019as amended September 23, 2021 (Exhibit 10.42,10.1, Form 10-K for the fiscal year ended December 31, 2018,10-Q filed February 28, 2019,November 5, 2021, File No. 1-8489). | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 10.21* | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 10.22* | | | | | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 10.23* | | | | | | X | | | | | | | | | | 10.24* | | Restricted Stock Award Agreement for Diane Leopold (Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2020 filed November 6, 2020, File No. 1-8489). | | X | | | | | | | | | | 10.25* | | 2021 Performance Grant Plan under the 2021 Long-Term Incentive Program approved January 21, 2021 (Exhibit 10.26, Form 10-K for the fiscal year ended December 31, 2020 filed February 25, 2021, File No.1-8489). | | X | | | | | | | | | | 10.26* | | Form of 2021 Goal-Based Stock Award Agreement under the 2021 Long-Term Incentive Program approved January 21, 2021 (Exhibit 10.27, Form 10-K for the fiscal year ended December 31, 2020 filed February 25, 2021, File No.1-8489). | | X | | | | | | | | | | 10.27* | | Form of Restricted Stock Agreement under the 2021 Long-Term Incentive Program approved January 21, 2021 (Exhibit 10.28, Form 10-K for the fiscal year ended December 31, 2020 filed February 25, 2021, File No.1-8489). | | X | | | | | | | | | | 10.28* | | 2022 Performance Grant Plan under the 2022 Long-Term Incentive Program approved January 27, 2022 (filed herewith). | | X | | |
| | | | | | | | | | | | | | | | | 101 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | TheThe following financial statements from Dominion Energy, Inc.’s Annual Report on Form10-K for the year ended December 31, 2019,2021, filed on February 28, 2020,24, 2022, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Statements of Income, (ii) Consolidated Statements of Comprehensive Income (iii) Consolidated Balance Sheets, (iv) Consolidated Statements of Equity, (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements. The following financial statements from Virginia Electric and Power Company’s Annual Report on Form10-K for the year ended December 31, 2019,2021, filed on February 28, 2020,24, 2022, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Statements of Income, (ii) Consolidated Statements of Comprehensive Income, (iii) Consolidated Balance Sheets, (iv) Consolidated Statements of Common Shareholder’s Equity (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements. The following financial statements from Dominion Energy Gas Holdings, LLC’s Annual Report on Form10-K
for the year ended December 31, 2019, filed on February 28, 2020, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Statements of Income, (ii) Consolidated Statements of Comprehensive Income, (iii) Consolidated Balance Sheets, (iv) Consolidated Statements of Equity, (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements. | | X | | | | | | | | | | | | | | | | | | | | | | | | | | | | 104 | | | | Cover Page Interactive Data File formatted in iXBRL (Inline eXtensible Business Reporting Language) and contained in Exhibit 101. | | X | | | | | | | | | | |
* | Indicates management contract or compensatory plan or arrangement.
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*Indicates management contract or compensatory plan or arrangement. Item 16. Form 10-K Summary None. 10-K
Summary
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. | | | | | | | | | | | | | By: | | | | /s/ Thomas F. Farrell, II | | | | | (Thomas F. Farrell, II, Chairman,Robert M. Blue, President and |
24, 2022Pursuant 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 28th24th day of February, 2020. Signature | | Title | | | | | | | /s/ Thomas F. Farrell, II Robert M. Blue | | ChairmanChair of the Board of Directors, President and Chief | | | | | | /s/ James A. Bennett | | | | | | | | /s/ Helen E. Dragas | | | | | | | | /s/ James O. Ellis, Jr. | | | | | | | Director | D. Maybank Hagood | | | | | | | | | | | | | | | | | | | | /s/ Mark J. Kington | | | | | | | | /s/ Joseph M. Rigby | | | | | | | | /s/ Pamela J. Royal | | | | | | | | /s/ Robert H. Spilman, Jr. | | | | | | | | /s/ Susan N. Story | | | | | | | | /s/ Michael E. Szymanczyk | | | | | | | | /s/ James R. Chapman | | Executive Vice President, Chief Financial Officer and Treasurer | | | | | | /s/ Michele L. Cardiff | | Senior Vice President, Controller and Chief Accounting Officer |
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/ Thomas F. Farrell, II | | | | | (Thomas F. Farrell, II, Chairman of the Board of Directors and Robert M. Blue,Chief Executive Officer) |
24, 2022Pursuant 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 28th24th day of February, 2020. | | | | | | | | | /s/ Thomas F. Farrell, II
| | Chairman of the Board of Directors and Chief Executive Officer
| /s/ Edward H. Baine Edward H. Baine | | Director | | | | | /s/ Robert M. Blue | | and Chief Executive Officer | | | | | Diane Leopold Diane Leopold | | | | | | | | /s/ James R. Chapman | | Executive Vice President, Chief Financial Officer and Treasurer | | | | /s/ /s/ Michele L. Cardiff | | Senior Vice President, Controller and Chief Accounting Officer |
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 GAS HOLDINGS, LLC
| | | | | | | | | | /s/ Thomas F. Farrell, II
| | | | | (Thomas F. Farrell, II, Chairman of the Board
of Directors and Chief Executive Officer)
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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 28th day of February, 2020.
| | | | | | | | | /s/ Thomas F. Farrell, II
| | Chairman of the Board of Directors and Chief Executive Officer
| | | | | | | | | | | | Director, Executive Vice President, Chief Financial Officer and Treasurer
| | | | | | Vice President, Controller and Chief Accounting Officer
|
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