FERC Form

THIS FILING IS

Item 1:

☑ An Initial (Original) Submission

OR

☐ Resubmission No.




FERC FINANCIAL REPORT FERC FORM No. 1: Annual Report of Major Electric Utilities, Licensees and Others and Supplemental Form 3-Q: Quarterly Financial Report

These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and 18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and other sanctions as provided by law. The Federal Energy Regulatory Commission does not consider these reports to be of confidential nature

Exact Legal Name of Respondent (Company)

Dominion Energy South Carolina, Inc.

Year/Period of Report

End of:

2022

/

Q1

INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q

GENERAL INFORMATION

Purpose
FERC Form No. 1 (FERC Form 1) is an annual regulatory requirement for Major electric utilities, licensees and others (18 C.F.R. § 141.1). FERC Form No. 3-Q ( FERC Form 3-Q) is a quarterly regulatory requirement which supplements the annual financial reporting requirement (18 C.F.R. § 141.400). These reports are designed to collect financial and operational information from electric utilities, licensees and others subject to the jurisdiction of the Federal Energy Regulatory Commission. These reports are also considered to be non-confidential public use forms.
Who Must Submit
Each Major electric utility, licensee, or other, as classified in the Commission’s Uniform System of Accounts Prescribed for Public Utilities, Licensees, and Others Subject To the Provisions of The Federal Power Act (18 C.F.R. Part 101), must submit FERC Form 1 (18 C.F.R. § 141.1), and FERC Form 3-Q (18 C.F.R. § 141.400).
Note: Major means having, in each of the three previous calendar years, sales or transmission service that exceeds one of the following:
1. one million megawatt hours of total annual sales,
2. 100 megawatt hours of annual sales for resale,
3. 500 megawatt hours of annual power exchanges delivered, or
4. 500 megawatt hours of annual wheeling for others (deliveries plus losses).

What and Where to Submit

Submit FERC Form Nos. 1 and 3-Q electronically through the eCollection portal at https://eCollection.ferc.gov, and according to the specifications in the Form 1 and 3-Q taxonomies.
The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-Q filings.
Submit immediately upon publication, by either eFiling or mail, two (2) copies to the Secretary of the Commission, the latest Annual Report to Stockholders. Unless eFiling the Annual Report to Stockholders, mail the stockholders report to the Secretary of the Commission at:
Secretary
Federal Energy Regulatory Commission 888 First Street, NE
Washington, DC 20426

For the CPA Certification Statement, submit within 30 days after filing the FERC Form 1, a letter or report (not applicable to filers classified as Class C or Class D prior to January 1, 1984). The CPA Certification Statement can be either eFiled or mailed to the Secretary of the Commission at the address above.

The CPA Certification Statement should:

Attest to the conformity, in all material aspects, of the below listed (schedules and pages) with the Commission's applicable Uniform System of Accounts (including applicable notes relating thereto and the Chief Accountant's published accounting releases), and

Be signed by independent certified public accountants or an independent licensed public accountant certified or licensed by a regulatory authority of a State or other political subdivision of the U. S. (See 18 C.F.R. §§ 41.10-41.12 for specific qualifications.)

Schedules	Pages
Comparative Balance Sheet	110-113
Statement of Income	114-117
Statement of Retained Earnings	118-119
Statement of Cash Flows	120-121
Notes to Financial Statements	122-123

The following format must be used for the CPA Certification Statement unless unusual circumstances or conditions, explained in the letter or report, demand that it be varied. Insert parenthetical phrases only when exceptions are reported.
“In connection with our regular examination of the financial statements of [COMPANY NAME] for the year ended on which we have reported separately under date of [DATE], we have also reviewed schedules [NAME OF SCHEDULES] of FERC Form No. 1 for the year filed with the Federal Energy Regulatory Commission, for conformity in all material respects with the requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases. Our review for this purpose included such tests of the accounting records and such other auditing procedures as we considered necessary in the circumstances.
Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph (except as noted below) conform in all material respects with the accounting requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases.” The letter or report must state which, if any, of the pages above do not conform to the Commission’s requirements. Describe the discrepancies that exist.
Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFiling. Further instructions are found on the Commission’s website at https://www.ferc.gov/ferc-online/ferc-online/frequently-asked-questions-faqs-efilingferc-online.
Federal, State, and Local Governments and other authorized users may obtain additional blank copies of FERC Form 1 and 3-Q free of charge from https://www.ferc.gov/general-information-0/electric-industry-forms.

When to Submit
FERC Forms 1 and 3-Q must be filed by the following schedule:
1. FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR § 141.1), and
2. FERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. § 141.400).
Where to Send Comments on Public Reporting Burden.
The public reporting burden for the FERC Form 1 collection of information is estimated to average 1,168 hours per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data-needed, and completing and reviewing the collection of information. The public reporting burden for the FERC Form 3-Q collection of information is estimated to average 168 hours per response.
Send comments regarding these burden estimates or any aspect of these collections of information, including suggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426 (Attention: Information Clearance Officer); and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 (Attention: Desk Officer for the Federal Energy Regulatory Commission). No person shall be subject to any penalty if any collection of information does not display a valid control number (44 U.S.C. § 3512 (a)).

GENERAL INSTRUCTIONS

Prepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). Interpret all accounting words and phrases in accordance with the USofA.
Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages and figures per unit where cents are important. The truncating of cents is allowed except on the four basic financial statements where rounding is required.) The amounts shown on all supporting pages must agree with the amounts entered on the statements that they support. When applying thresholds to determine significance for reporting purposes, use for balance sheet accounts the balances at the end of the current reporting period, and use for statement of income accounts the current year's year to date amounts.
Complete each question fully and accurately, even if it has been answered in a previous report. Enter the word "None" where it truly and completely states the fact.
For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA," "NONE," or "Not Applicable" in column (d) on the List of Schedules, pages 2 and 3.
Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the header of each page is to be completed only for resubmissions (see VII. below).
Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must be reported as positive. Numbers having a sign that is different from the expected sign must be reported by enclosing the numbers in parentheses.
For any resubmissions, please explain the reason for the resubmission in a footnote to the data field.
Do not make references to reports of previous periods/years or to other reports in lieu of required entries, except as specifically authorized.
Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be based upon those shown by the report of the previous period/year, or an appropriate explanation given as to why the different figures were used.
Schedule specific instructions are found in the applicable taxonomy and on the applicable blank rendered form.

Definitions for statistical classifications used for completing schedules for transmission system reporting are as follows:

FNS - Firm Network Transmission Service for Self. "Firm" means service that can not be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff. "Self" means the respondent.

FNO - Firm Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff.

LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and” firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Point-to-Point Transmission Reservations" are described in Order No. 888 and the Open Access Transmission Tariff. For all transactions identified as LFP, provide in a footnote the termination date of the contract defined as the earliest date either buyer or seller can unilaterally cancel the contract.

OLF - Other Long-Term Firm Transmission Service. Report service provided under contracts which do not conform to the terms of the Open Access Transmission Tariff. "Long-Term" means one year or longer and “firm” means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. For all transactions identified as OLF, provide in a footnote the termination date of the contract defined as the earliest date either buyer or seller can unilaterally get out of the contract.

SFP - Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-point transmission reservations, where the duration of each period of reservation is less than one-year.

NF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions.

OS - Other Transmission Service. Use this classification only for those services which can not be placed in the above-mentioned classifications, such as all other service regardless of the length of the contract and service FERC Form. Describe the type of service in a footnote for each entry.

AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment.

DEFINITIONS

Commission Authorization (Comm. Auth.) -- The authorization of the Federal Energy Regulatory Commission, or any other Commission. Name the commission whose authorization was obtained and give date of the authorization.
Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whose behalf the report is made.

EXCERPTS FROM THE LAW

Federal Power Act, 16 U.S.C. § 791a-825r

Sec. 3. The words defined in this section shall have the following meanings for purposes of this Act, to with:

’Corporation' means any corporation, joint-stock company, partnership, association, business trust, organized group of persons, whether incorporated or not, or a receiver or receivers, trustee or trustees of any of the foregoing. It shall not include 'municipalities, as hereinafter defined;
'Person' means an individual or a corporation;
'Licensee, means any person, State, or municipality Licensed under the provisions of section 4 of this Act, and any assignee or successor in interest thereof;

'municipality means a city, county, irrigation district, drainage district, or other political subdivision or agency of a State competent under the Laws thereof to carry and the business of developing, transmitting, unitizing, or distributing power; ......

"project' means. a complete unit of improvement or development, consisting of a power house, all water conduits, all dams and appurtenant works and structures (including navigation structures) which are a part of said unit, and all storage, diverting, or fore bay reservoirs directly connected therewith, the primary line or lines transmitting power there from to the point of junction with the distribution system or with the interconnected primary transmission system, all miscellaneous structures used and useful in connection with said unit or any part thereof, and all water rights, rights-of-way, ditches, dams, reservoirs, Lands, or interest in Lands the use and occupancy of which are necessary or appropriate in the maintenance and operation of such unit;

"Sec. 4. The Commission is hereby authorized and empowered

'To make investigations and to collect and record data concerning the utilization of the water 'resources of any region to be developed, the water-power industry and its relation to other industries and to interstate or foreign commerce, and concerning the location, capacity, development costs, and relation to markets of power sites; ... to the extent the Commission may deem necessary or useful for the purposes of this Act."

"Sec. 304.

Every Licensee and every public utility shall file with the Commission such annual and other periodic or special* reports as the Commission may by rules and regulations or other prescribe as necessary or appropriate to assist the Commission in the proper administration of this Act. The Commission may prescribe the manner and FERC Form in which such reports shall be made, and require from such persons specific answers to all questions upon which the Commission may need information. The Commission may require that such reports shall include, among other things, full information as to assets and Liabilities, capitalization, net investment, and reduction thereof, gross receipts, interest due and paid, depreciation, and other reserves, cost of project and other facilities, cost of maintenance and operation of the project and other facilities, cost of renewals and replacement of the project works and other facilities, depreciation, generation, transmission, distribution, delivery, use, and sale of electric energy. The Commission may require any such person to make adequate provision for currently determining such costs and other facts. Such reports shall be made under oath unless the Commission otherwise specifies*.10

"Sec. 309.

The Commission shall have power to perform any and all acts, and to prescribe, issue, make, and rescind such orders, rules and regulations as it may find necessary or appropriate to carry out the provisions of this Act. Among other things, such rules and regulations may define accounting, technical, and trade terms used in this Act; and may prescribe the FERC Form or FERC Forms of all statements, declarations, applications, and reports to be filed with the Commission, the information which they shall contain, and the time within which they shall be field..."

GENERAL PENALTIES

The Commission may assess up to $1 million per day per violation of its rules and regulations. See FPA § 316(a) (2005), 16 U.S.C. § 825o(a).

FERC FORM NO.

1/3-Q

REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER

Identification

01 Exact Legal Name of Respondent

Dominion Energy South Carolina, Inc.

02 Year/ Period of Report

End of:

2022

/

Q1

03 Previous Name and Date of Change (If name changed during year)

/

04 Address of Principal Office at End of Period (Street, City, State, Zip Code)

400 Otarre Parkway, Cayce SC 29033-3751

05 Name of Contact Person

Lisa Honeycutt

06 Title of Contact Person

Accounting Manager

07 Address of Contact Person (Street, City, State, Zip Code)

220 Operation Way - MC B131, Cayce, SC 29033-3701

08 Telephone of Contact Person, Including Area Code

(803) 217-7416

09 This Report is An Original / A Resubmission

(1)

☑ An Original

(2)

☐ A Resubmission

10 Date of Report (Mo, Da, Yr)

05/24/2022

Quarterly Corporate Officer Certification

The undersigned officer certifies that:

I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material respects to the Uniform System of Accounts.

01 Name

Mark F. Lindley

02 Title

Controller

03 Signature

Mark F. Lindley

04 Date Signed (Mo, Da, Yr)

05/24/2022

Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any false, fictitious or fraudulent statements as to any matter within its jurisdiction.

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

List of Schedules
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line No.	Title of Schedule (a)	Reference Page No. (b)	Remarks (c)
	ScheduleIdentificationAbstract Identification	1
	ScheduleListOfSchedulesAbstract List of Schedules (Electric Utility)	2
1	ScheduleImportantChangesDuringTheQuarterYearAbstract Important Changes During the Quarter	108
2	ScheduleComparativeBalanceSheetAbstract Comparative Balance Sheet	110
3	ScheduleStatementOfIncomeAbstract Statement of Income for the Quarter	114
4	ScheduleRetainedEarningsAbstract Statement of Retained Earnings for the Quarter	118
5	ScheduleStatementOfCashFlowsAbstract Statement of Cash Flows	120
6	ScheduleNotesToFinancialStatementsAbstract Notes to Financial Statements	122
7	ScheduleStatementOfAccumulatedOtherComprehensiveIncomeAndHedgingActivitiesAbstract Statement of Accum Comp Income, Comp Income, and Hedging Activities	122a
8	ScheduleSummaryOfUtilityPlantAndAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep	200
9	ScheduleElectricPlantInServiceAndAccumulatedProvisionForDepreciationByFunctionAbstract Electric Plant In Service and Accum Provision For Depr by Function	208
10	ScheduleTransmissionServiceAndGenerationInterconnectionStudyCostsAbstract Transmission Service and Generation Interconnection Study Costs	231
11	ScheduleOtherRegulatoryAssetsAbstract Other Regulatory Assets	232
12	ScheduleOtherRegulatoryLiabilitiesAbstract Other Regulatory Liabilities	278
13	ScheduleElectricOperatingRevenuesAbstract Elec Operating Revenues (Individual Schedule Lines 300-301)	300
14	ScheduleRegionalTransmissionServiceRevenuesAbstract Regional Transmission Service Revenues (Account 457.1)	302	N/A
15	ScheduleElectricProductionOtherPowerTransmissionRegionalExpensesAbstract Electric Prod, Other Power Supply Exp, Trans and Distrib Exp	324
16	ScheduleElectricCustomerAccountServiceSalesAdministrativeAndGeneralExpensesAbstract Electric Customer Accts, Service, Sales, Admin and General Expenses	325
17	ScheduleTransmissionOfElectricityForOthersAbstract Transmission of Electricity for Others	328
18	ScheduleTransmissionOfElectricityByIsoOrRtoAbstract Transmission of Electricity by ISO/RTOs	331	N/A
19	ScheduleTransmissionOfElectricityByOthersAbstract Transmission of Electricity by Others	332
20	ScheduleDepreciationDepletionAndAmortizationsAbstract Deprec, Depl and Amort of Elec Plant (403,403.1,404,and 405) (except Amortization of Acquisition Adjustments)	338
21	ScheduleAmountsIncludedInIsoOrRtoSettlementAbstract Amounts Included in ISO/RTO Settlement Statements	397
22	ScheduleMonthlyPeaksAndOutputAbstract Monthly Peak Loads and Energy Output	399
23	ScheduleMonthlyTransmissionSystemPeakLoadAbstract Monthly Transmission System Peak Load	400
24	ScheduleMonthlyIsoOrRtoTransmissionSystemPeakLoadAbstract Monthly ISO/RTO Transmission System Peak Load	400a	N/A

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

IMPORTANT CHANGES DURING THE QUARTER/YEAR
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the franchise rights were acquired. If acquired without the payment of consideration, state that fact. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to Commission authorization. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto, and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts were submitted to the Commission. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give reference to such authorization. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as appropriate, and the amount of obligation or guarantee. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments. State the estimated annual effect and nature of any important wage scale changes during the year. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such proceedings culminated during the year. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer, director, security holder reported on Pages 104 or 105 of the Annual Report Form No. 1, voting trustee, associated company or known associate of any of these persons was a party or in which any such person had a material interest. (Reserved.) If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred during the reporting period. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30 percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.

1. One combination electric and gas franchise agreement was renewed during the first quarter of 2022 without payment of consideration.
2. None
3. None
4. None
5. None
6. Short-term borrowings below have been authorized by FERC (Docket No. ES21-25-000). The Company’s obligations under non-affiliated short-term borrowing arrangements on the respective Balance Sheet dates were as follows: 03/31/2022 - $52,000,000 12/31/2021 - $0 South Carolina Fuel Company, Inc. (Fuel Company) participates in an intercompany credit agreement with Dominion Energy. At January 1, 2022, Fuel Company had borrowings outstanding under this agreement totaling $241,811,245. During the first quarter of 2022, Fuel Company borrowed $702,581,969 and repaid $717,994,969 under this agreement. As of March 31, 2022, Fuel Company had borrowings outstanding under this agreement totaling $226,398,245. DESC has FERC approval to participate in an Intercompany Credit Agreement with Dominion Energy under which DESC may have short-term borrowings outstanding up to $900 million. At January 1, 2022, DESC had borrowings outstanding under this credit agreement totaling $171,671,000. In the first quarter of 2022, DESC borrowed $1,114,183,453 and repaid borrowings of $868,514,453. At March 31, 2022, DESC had borrowings outstanding under this agreement totaling $417,340,000. DESC is obligated with respect to an aggregate of $35 million of Industrial Revenue Bonds which are secured by letters of credit. These letters of credit expire, subject to renewal, in the fourth quarter of 2022. For additional information, see Notes 5, 7 and 8 to the Financial Statements.
7. None
8. None
9. See Notes 2 and 10 to the Financial Statements
10. None
12. Not Applicable
13. The following change in Company Officers occurred in the first quarter of 2022: P. Rodney Blevins resigned as President, effective December 31, 2021. Mr. Blevins was elected President – Gas Distribution of Dominion Energy, Inc., effective January 1, 2022. W. Keller Kissam, President - Electric Operations, was elected President, effective January 1, 2022. Douglas C. Lawrence was elected Vice President - Nuclear Engineering & Fleet Support, effective January 1, 2022. Mark D. Sartain, Vice President - Nuclear Engineering & Fleet Support, was elected Vice President - Nuclear Projects, effective January 1, 2022. Mr. Sartain resigned and retired from the Company, effective March 1, 2022. W. Keith Windle was elected Senior Vice President - Administrative Services, effective March 1, 2022. During the first quarter of 2022, the following change in Company Officers were announced: Darius A. Johnson was elected Vice President and Treasurer, effective April 1, 2022. James R. Chapman, Executive Vice President, Chief Financial Officer and Treasurer, was elected Executive Vice President and Chief Financial Officer, effective April 1, 2022. Keith C. Coffer Jr., Controller resigned as Controller of the Company, effective April 1, 2022. Mr. Coffer was elected Controller of Public Service Company of North Carolina, Incorporated, The East Ohio Gas Company, Questar Gas Company, Hope Gas, Inc. and various other subsidiary companies of Dominion Energy, Inc., effective April 1, 2022, none of which were the Company. Mark F. Lindley was elected Controller, effective April 1, 2022. Elizabeth L. Chester was elected Vice President - Regulatory Affairs, effective April 1, 2022. Prabir Purohit, Vice President - Finance, was elected Vice President - Strategy, effective April 1, 2022. Joseph A. Woomer was elected Vice President - New Business & Customer Solutions effective April 1, 2022.
14. Not Applicable

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line No.	Title of Account (a)	Ref. Page No. (b)	Current Year End of Quarter/Year Balance (c)	Prior Year End Balance 12/31 (d)
1	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlant Utility Plant (101-106, 114)	200	13,568,450,992	13,443,485,258
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	458,391,247	455,263,567
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		14,026,842,239	13,898,748,825
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	5,493,568,619	5,446,634,770
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		8,533,273,620	8,452,114,055
7	NuclearFuelInProcessOfRefinementConversionEnrichmentAndFabrication Nuclear Fuel in Process of Ref., Conv., Enrich., and Fab. (120.1)	202	123,736	852,246
8	NuclearFuelMaterialsAndAssembliesStockAccountMajorOnly Nuclear Fuel Materials and Assemblies-Stock Account (120.2)		142,677,977	142,677,977
9	NuclearFuelAssembliesInReactorMajorOnly Nuclear Fuel Assemblies in Reactor (120.3)		165,107,401	164,301,564
10	SpentNuclearFuelMajorOnly Spent Nuclear Fuel (120.4)		295,504,260	295,504,260
11	NuclearFuelUnderCapitalLeases Nuclear Fuel Under Capital Leases (120.6)
12	AccumulatedProvisionForAmortizationOfNuclearFuelAssemblies (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)	202	397,342,343	387,545,863
13	NuclearFuelNet Net Nuclear Fuel (Enter Total of lines 7-11 less 12)		206,071,031	215,790,184
14	UtilityPlantAndNuclearFuelNet Net Utility Plant (Enter Total of lines 6 and 13)		8,739,344,651	8,667,904,239
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)
17	OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS
18	NonutilityProperty Nonutility Property (121)		43,738,202	43,772,965
19	AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Prov. for Depr. and Amort. (122)		1,355,182	1,327,725
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224	17,395	13,124
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances	228
24	OtherInvestments Other Investments (124)		60,309	60,309
25	SinkingFunds Sinking Funds (125)
26	DepreciationFund Depreciation Fund (126)
27	AmortizationFundFederal Amortization Fund - Federal (127)
28	OtherSpecialFunds Other Special Funds (128)		311,458,890	319,197,398
29	SpecialFunds Special Funds (Non Major Only) (129)
30	DerivativeInstrumentAssetsLongTerm Long-Term Portion of Derivative Assets (175)		173,329,207	130,514,568
31	DerivativeInstrumentAssetsHedgesLongTerm Long-Term Portion of Derivative Assets - Hedges (176)
32	OtherPropertyAndInvestments TOTAL Other Property and Investments (Lines 18-21 and 23-31)		527,248,821	492,230,639
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)		(a) 30,230,861	(b) 54,128,851
36	SpecialDeposits Special Deposits (132-134)			6,807,848
37	WorkingFunds Working Fund (135)		100	100
38	TemporaryCashInvestments Temporary Cash Investments (136)
39	NotesReceivable Notes Receivable (141)
40	CustomerAccountsReceivable Customer Accounts Receivable (142)		220,756,244	220,356,466
41	OtherAccountsReceivable Other Accounts Receivable (143)		146,734,179	149,919,620
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		6,615,948	5,839,009
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)		54,394,967	(c) 24,743,156
45	FuelStock Fuel Stock (151)	227	37,476,281	42,992,386
46	FuelStockExpensesUndistributed Fuel Stock Expenses Undistributed (152)	227
47	Residuals Residuals (Elec) and Extracted Products (153)	227
48	PlantMaterialsAndOperatingSupplies Plant Materials and Operating Supplies (154)	227	179,293,841	168,976,412
49	Merchandise Merchandise (155)	227
50	OtherMaterialsAndSupplies Other Materials and Supplies (156)	227
51	NuclearMaterialsHeldForSale Nuclear Materials Held for Sale (157)	202/227
52	AllowanceInventoryAndWithheld Allowances (158.1 and 158.2)	228	623,813	624,403
53	NoncurrentPortionOfAllowances (Less) Noncurrent Portion of Allowances	228
54	StoresExpenseUndistributed Stores Expense Undistributed (163)	227	842,862	989,327
55	GasStoredCurrent Gas Stored Underground - Current (164.1)		15,006,666	16,972,985
56	LiquefiedNaturalGasStoredAndHeldForProcessing Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)		3,742,070	7,888,197
57	Prepayments Prepayments (165)		63,453,427	69,697,403
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)
60	RentsReceivable Rents Receivable (172)
61	AccruedUtilityRevenues Accrued Utility Revenues (173)		109,063,207	139,097,583
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)		1,237,765	2,782,565
63	DerivativeInstrumentAssets Derivative Instrument Assets (175)		225,299,453	148,135,913
64	DerivativeInstrumentAssetsLongTerm (Less) Long-Term Portion of Derivative Instrument Assets (175)		173,329,207	130,514,568
65	DerivativeInstrumentAssetsHedges Derivative Instrument Assets - Hedges (176)
66	DerivativeInstrumentAssetsHedgesLongTerm (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176)
67	CurrentAndAccruedAssets Total Current and Accrued Assets (Lines 34 through 66)		908,210,581	912,194,508
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		23,263,594	23,289,434
70	ExtraordinaryPropertyLosses Extraordinary Property Losses (182.1)	230a
71	UnrecoveredPlantAndRegulatoryStudyCosts Unrecovered Plant and Regulatory Study Costs (182.2)	230b	2,402,178,379	2,437,034,900
72	OtherRegulatoryAssets Other Regulatory Assets (182.3)	232	1,349,187,420	1,355,610,227
73	PreliminarySurveyAndInvestigationCharges Prelim. Survey and Investigation Charges (Electric) (183)		2,480,579	1,426,780
74	PreliminaryNaturalGasSurveyAndInvestigationChargesAndOtherPreliminarySurveyAndInvestigationCharges Preliminary Natural Gas Survey and Investigation Charges 183.1)
75	OtherPreliminarySurveyAndInvestigationCharges Other Preliminary Survey and Investigation Charges (183.2)
76	ClearingAccounts Clearing Accounts (184)		41,226
77	TemporaryFacilities Temporary Facilities (185)
78	MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186)	233	67,902,400	64,109,946
79	DeferredLossesFromDispositionOfUtilityPlant Def. Losses from Disposition of Utility Plt. (187)
80	ResearchDevelopmentAndDemonstrationExpenditures Research, Devel. and Demonstration Expend. (188)	352
81	UnamortizedLossOnReacquiredDebt Unamortized Loss on Reaquired Debt (189)		10,227,202	(d) 10,500,746
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	1,044,214,858	1,190,727,036
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		4,899,413,206	5,082,699,069
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		15,074,217,259	15,155,028,455

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: Cash

Includes $23,700,276 of Federal Customer Assistance Funds which are considered restricted cash.

(b) Concept: Cash

Includes $23,698,374 of Federal Customer Assistance Funds which are considered restricted cash.

(c) Concept: AccountsReceivableFromAssociatedCompanies

Reflects the reclassification from amounts reported in the Company's first quarter of 2021 Form 3-Q report of $206,372,242 (debit activity) from Account 146 - Accounts Receivable from Associated Companies to Account 234 - Accounts Payable to Associated Companies related to repayment of borrowings from the SCANA Utility Money Pool in the first quarter of 2021.

(d) Concept: UnamortizedLossOnReacquiredDebt

In connection with the comprehensive settlement agreement in DESC's retail electric base rate case approved by the SCPSC (Docket No. 2020-125-E), in 2021 DESC wrote off $239.5 million of unamortized losses on reacquired debt that are no longer probable of recovery under the terms of the settlement agreement.

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line No.	Title of Account (a)	Ref. Page No. (b)	Current Year End of Quarter/Year Balance (c)	Prior Year End Balance 12/31 (d)
1	ProprietaryCapitalAbstract PROPRIETARY CAPITAL
2	CommonStockIssued Common Stock Issued (201)	250	576,405,122	576,405,122
3	PreferredStockIssued Preferred Stock Issued (204)	250	100,000	100,000
4	CapitalStockSubscribed Capital Stock Subscribed (202, 205)
5	StockLiabilityForConversion Stock Liability for Conversion (203, 206)
6	PremiumOnCapitalStock Premium on Capital Stock (207)
7	OtherPaidInCapital Other Paid-In Capital (208-211)	253	3,443,427,723	3,443,427,723
8	InstallmentsReceivedOnCapitalStock Installments Received on Capital Stock (212)	252
9	DiscountOnCapitalStock (Less) Discount on Capital Stock (213)	254
10	CapitalStockExpense (Less) Capital Stock Expense (214)	254b	4,335,379	4,335,379
11	RetainedEarnings Retained Earnings (215, 215.1, 216)	118	(a) 337,673,783	(c) 335,041,820
12	UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1)	118
13	ReacquiredCapitalStock (Less) Reaquired Capital Stock (217)	250
14	NoncorporateProprietorship Noncorporate Proprietorship (Non-major only) (218)
15	AccumulatedOtherComprehensiveIncome Accumulated Other Comprehensive Income (219)	122(a)(b)	579,414	582,602
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		4,352,691,835	4,350,056,684
17	LongTermDebtAbstract LONG-TERM DEBT
18	Bonds Bonds (221)	256	3,722,814,000	3,722,814,000
19	ReacquiredBonds (Less) Reaquired Bonds (222)	256
20	AdvancesFromAssociatedCompanies Advances from Associated Companies (223)	256
21	OtherLongTermDebt Other Long-Term Debt (224)	256	1,134,821	1,142,917
22	UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225)		7,499,116	7,590,039
23	UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Debit (226)		16,706,066	16,837,163
24	LongTermDebt Total Long-Term Debt (lines 18 through 23)		3,714,741,871	3,714,709,793
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		24,236,038	26,284,208
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		4,652,568	4,473,191
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		162,611,668	166,568,695
30	AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4)
31	AccumulatedProvisionForRateRefunds Accumulated Provision for Rate Refunds (229)
32	LongTermPortionOfDerivativeInstrumentLiabilities Long-Term Portion of Derivative Instrument Liabilities		2,609,741	6,379,718
33	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges Long-Term Portion of Derivative Instrument Liabilities - Hedges
34	AssetRetirementObligations Asset Retirement Obligations (230)		595,458,470	583,340,017
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		789,568,485	787,045,829
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)		52,000,000
38	AccountsPayable Accounts Payable (232)		154,658,095	237,791,041
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)		(b) 645,395,625	(d) 414,563,708
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		58,612,845	(e) 58,543,196
41	CustomerDeposits Customer Deposits (235)		70,087,528	70,996,666
42	TaxesAccrued Taxes Accrued (236)	262	113,074,208	255,328,027
43	InterestAccrued Interest Accrued (237)		67,507,451	71,599,838
44	DividendsDeclared Dividends Declared (238)
45	MaturedLongTermDebt Matured Long-Term Debt (239)
46	MaturedInterest Matured Interest (240)
47	TaxCollectionsPayable Tax Collections Payable (241)		170,588,308	171,714,197
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		170,079,372	162,625,626
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		5,579,006	6,602,918
50	DerivativesInstrumentLiabilities Derivative Instrument Liabilities (244)		3,124,016	7,212,444
51	LongTermPortionOfDerivativeInstrumentLiabilities (Less) Long-Term Portion of Derivative Instrument Liabilities		2,609,741	6,379,718
52	DerivativeInstrumentLiabilitiesHedges Derivative Instrument Liabilities - Hedges (245)
53	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges
54	CurrentAndAccruedLiabilities Total Current and Accrued Liabilities (lines 37 through 53)		1,508,096,713	1,450,597,943
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)
57	AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255)	266	15,162,342	15,486,622
58	DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256)
59	OtherDeferredCredits Other Deferred Credits (253)	269	57,585,833	55,765,267
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	2,667,349,629	2,733,859,640
61	UnamortizedGainOnReacquiredDebt Unamortized Gain on Reaquired Debt (257)		0	(f) 0
62	AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty Accum. Deferred Income Taxes-Accel. Amort.(281)	272	10,880,300	10,577,600
63	AccumulatedDeferredIncomeTaxesOtherProperty Accum. Deferred Income Taxes-Other Property (282)		1,138,137,744	1,216,325,872
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		820,002,507	820,603,205
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		4,709,118,355	4,852,618,206
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		15,074,217,259	15,155,028,455

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: RetainedEarnings

DESC's articles of incorporation do not limit the dividends that may be paid on its common stock. However, DESC's bond indenture under which it issues First Mortgage Bonds contains provisions that could limit the payment of cash dividends on its common stock. DESC's bond indenture permits the payment of dividends on DESC's common stock only either (1) out of its surplus (as defined in the bond indenture) or (2) in case there is no surplus, out of its net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year. In addition, with respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At March 31, 2022, approximately $115.2 million were restricted by this requirement as to payment of cash dividends on common stock.

(b) Concept: NotesPayableToAssociatedCompanies

Includes borrowings outstanding, plus accrued interest, under the intercompany credit agreement with Dominion Energy as follows:


DESC	$	418,150,559
SCFC	227,245,066
Total	$	645,395,625

(c) Concept: RetainedEarnings

DESC's articles of incorporation do not limit the dividends that may be paid on its common stock. However, DESC's bond indenture under which it issues First Mortgage Bonds contains provisions that could limit the payment of cash dividends on its common stock. DESC's bond indenture permits the payment of dividends on DESC's common stock only either (1) out of its surplus (as defined in the bond indenture) or (2) in case there is no surplus, out of its net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year. In addition, with respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At December 31, 2021, approximately $115.2 million were restricted by this requirement as to payment of cash dividends on common stock.

(d) Concept: NotesPayableToAssociatedCompanies

Includes borrowings outstanding, plus accrued interest, under the intercompany credit agreement with Dominion Energy as follows:


DESC	$	172,153,675
SCFC	242,410,033
Total	$	414,563,708

(e) Concept: AccountsPayableToAssociatedCompanies

Reflects the reclassification from amounts reported in the Company's first quarter 2021 Form 3-Q report of $206,372,242 (debit activity) from Account 146 - Accounts Receivable from Associated Companies to Account 234 - Accounts Payable to Associated Companies related to repayment of borrowings from the SCANA Utility Money Pool in the first quarter of 2021.

(f) Concept: UnamortizedGainOnReacquiredDebt

In connection with the comprehensive settlement agreement in DESC's retail electric base rate case approved by the SCPSC (Docket No. 2020-125-E), in 2021 DESC wrote off $2.1 million of unamortized gains on reacquired debt that are no longer probable of being returned under the terms of the settlement agreement.

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

STATEMENT OF INCOME
Quarterly Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only. Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same three month period for the prior year. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in column (k) the quarter to date amounts for other utility function for the current year quarter. Report in column (h) the quarter to date amounts for electric utility function; in column (j) the quarter to date amounts for gas utility, and in column (l) the quarter to date amounts for other utility function for the prior year quarter. If additional columns are needed, place them in a footnote. Annual or Quarterly if applicable Do not report fourth quarter data in columns (e) and (f) Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility column in a similar manner to a utility department. Spread the amount(s) over Lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above. Use page 122 for important notes regarding the statement of income for any account thereof. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases. Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate proceeding affecting revenues received or costs incurred for power or gas purchases, and a summary of the adjustments made to balance sheet, income, and expense accounts. If any notes appearing in the report to stockholders are applicable to the Statement of Income, such notes may be included at page 122. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income, including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to this schedule.
Line No.	Title of Account (a)	(Ref.) Page No. (b)	Total Current Year to Date Balance for Quarter/Year (c)	Total Prior Year to Date Balance for Quarter/Year (d)	Current 3 Months Ended - Quarterly Only - No 4th Quarter (e)	Prior 3 Months Ended - Quarterly Only - No 4th Quarter (f)	Electric Utility Current Year to Date (in dollars) (g)	Electric Utility Previous Year to Date (in dollars) (h)	Gas Utiity Current Year to Date (in dollars) (i)	Gas Utility Previous Year to Date (in dollars) (j)	Other Utility Current Year to Date (in dollars) (k)	Other Utility Previous Year to Date (in dollars) (l)
1	UtilityOperatingIncomeAbstract UTILITY OPERATING INCOME
2	OperatingRevenues Operating Revenues (400)	300	849,413,021	742,253,998	849,413,021	742,253,998	655,694,428	578,254,856	193,718,593	163,999,142
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	432,894,339	349,532,260	432,894,339	349,532,260	(c) 310,732,752	(d) 251,573,292	(e) 122,161,587	(f) 97,958,968
5	MaintenanceExpense Maintenance Expenses (402)	320	44,692,848	37,490,162	44,692,848	37,490,162	43,019,997	35,768,522	1,672,851	1,721,640
6	DepreciationExpense Depreciation Expense (403)	336	76,803,185	73,299,826	76,803,185	73,299,826	67,202,118	64,595,192	9,601,067	8,704,634
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	2,036,536	2,336,858	2,036,536	2,336,858	1,712,205	2,064,047	324,331	272,811
9	AmortizationOfElectricPlantAcquisitionAdjustments Amort. of Utility Plant Acq. Adj. (406)	336	215,104	215,104	215,104	215,104	213,550	213,550	1,554	1,554
10	AmortizationOfPropertyLossesUnrecoveredPlantAndRegulatoryStudyCosts Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)		38,659,328	38,465,834	38,659,328	38,465,834	38,572,740	38,453,803	86,588	12,031
11	AmortizationOfConversionExpenses Amort. of Conversion Expenses (407.2)
12	RegulatoryDebits Regulatory Debits (407.3)		4,586,533	3,810,335	4,586,533	3,810,335	4,586,533	3,810,335
13	RegulatoryCredits (Less) Regulatory Credits (407.4)		243,350		243,350		243,350
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	70,734,394	65,395,485	70,734,394	65,395,485	62,629,459	57,097,113	8,104,935	8,298,372
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	17,982,020	6,002,714	17,982,020	6,002,714	10,450,404	1,680,162	7,531,616	7,682,876
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	3,437,492	375,645	3,437,492	375,645	1,720,607	1,369,991	1,716,885	1,745,636
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	44,097,172	54,854,351	44,097,172	54,854,351	39,163,893	51,606,400	4,933,279	3,247,951
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	39,970,591	35,347,787	39,970,591	35,347,787	36,708,177	32,498,943	3,262,414	2,848,844
19	InvestmentTaxCreditAdjustments Investment Tax Credit Adj. - Net (411.4)	266	324,280	316,382	324,280	316,382	310,646	302,748	13,634	13,634
20	GainsFromDispositionOfPlant (Less) Gains from Disp. of Utility Plant (411.6)
21	LossesFromDispositionOfServiceCompanyPlant Losses from Disp. of Utility Plant (411.7)
22	GainsFromDispositionOfAllowances (Less) Gains from Disposition of Allowances (411.8)
23	LossesFromDispositionOfAllowances Losses from Disposition of Allowances (411.9)
24	AccretionExpense Accretion Expense (411.10)
25	UtilityOperatingExpenses TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)		695,600,730	596,114,405	695,600,730	596,114,405	542,742,085	469,330,410	152,858,645	126,783,995
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		153,812,291	146,139,593	153,812,291	146,139,593	112,952,343	108,924,446	40,859,948	37,215,147
28	OtherIncomeAndDeductionsAbstract Other Income and Deductions
29	OtherIncomeAbstract Other Income
30	NonutilityOperatingIncomeAbstract Nonutilty Operating Income
31	RevenuesFromMerchandisingJobbingAndContractWork Revenues From Merchandising, Jobbing and Contract Work (415)		213,186	218,403	213,186	218,403
32	CostsAndExpensesOfMerchandisingJobbingAndContractWork (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)		319,944	73,460	319,944	73,460
33	RevenuesFromNonutilityOperations Revenues From Nonutility Operations (417)		3,179,015	3,604,105	3,179,015	3,604,105
34	ExpensesOfNonutilityOperations (Less) Expenses of Nonutility Operations (417.1)		2,830,810	3,167,123	2,830,810	3,167,123
35	NonoperatingRentalIncome Nonoperating Rental Income (418)		29,400	27,825	29,400	27,825
36	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1)	119	46,117	611,731	46,117	611,731
37	InterestAndDividendIncome Interest and Dividend Income (419)		1,566,727	3,037,989	1,566,727	3,037,989
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		1,034,265	1,154,867	1,034,265	1,154,867
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		696,061	480,346	696,061	480,346
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)		97,068		97,068
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		3,618,851	4,671,221	3,618,851	4,671,221
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)
44	MiscellaneousAmortization Miscellaneous Amortization (425)		8,459	8,459	8,459	8,459
45	Donations Donations (426.1)		1,178,107	210,350	1,178,107	210,350
46	LifeInsurance Life Insurance (426.2)		1,304	65,006	1,304	65,006
47	Penalties Penalties (426.3)		125	106	125	106
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		588,240	226,508	588,240	226,508
49	OtherDeductions Other Deductions (426.5)		3,380,702	(a) 60,453,890	3,380,702	(b) 60,453,890
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		5,156,937	60,964,319	5,156,937	60,964,319
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262	139,397	130,270	139,397	130,270
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262	19,949,921	1,322,069	19,949,921	1,322,069
54	IncomeTaxesOther Income Taxes-Other (409.2)	262	5,779,615	798,135	5,779,615	798,135
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272	26,813,455	2,151,726	26,813,455	2,151,726
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272	1,477,724	16,032,886	1,477,724	16,032,886
57	InvestmentTaxCreditAdjustmentsNonutilityOperations Investment Tax Credit Adj.-Net (411.5)
58	InvestmentTaxCredits (Less) Investment Tax Credits (420)
59	TaxesOnOtherIncomeAndDeductions TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)		254,408	13,226,956	254,408	13,226,956
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		1,283,678	43,066,142	1,283,678	43,066,142
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		47,649,945	45,899,270	47,649,945	45,899,270
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		350,076	267,820	350,076	267,820
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)		273,543	4,400,485	273,543	4,400,485
65	AmortizationOfPremiumOnDebtCredit (Less) Amort. of Premium on Debt-Credit (429)		90,923	85,875	90,923	85,875
66	AmortizationOfGainOnReacquiredDebtCredit (Less) Amortization of Gain on Reaquired Debt-Credit (429.1)			25,110		25,110
67	InterestOnDebtToAssociatedCompanies Interest on Debt to Assoc. Companies (430)		575,917	84,770	575,917	84,770
68	OtherInterestExpense Other Interest Expense (431)		1,883,786	2,711,954	1,883,786	2,711,954
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		745,694	565,200	745,694	565,200
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		49,896,650	52,688,114	49,896,650	52,688,114
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		102,631,963	50,385,337	102,631,963	50,385,337
72	ExtraordinaryItemsAbstract Extraordinary Items
73	ExtraordinaryIncome Extraordinary Income (434)
74	ExtraordinaryDeductions (Less) Extraordinary Deductions (435)
75	NetExtraordinaryItems Net Extraordinary Items (Total of line 73 less line 74)
76	IncomeTaxesExtraordinaryItems Income Taxes-Federal and Other (409.3)	262
77	ExtraordinaryItemsAfterTaxes Extraordinary Items After Taxes (line 75 less line 76)
78	NetIncomeLoss Net Income (Total of line 71 and 77)		102,631,963	50,385,337	102,631,963	50,385,337

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: OtherDeductions

Includes charges of $60 million related to litigation.

(b) Concept: OtherDeductions

Includes charges of $60 million related to litigation.

(c) Concept: OperationExpense

Includes depreciation charges, amortization charges, and property taxes $171,170 billed from Dominion Energy Services, Inc.

(d) Concept: OperationExpense

Includes depreciation charges, amortization charges, and property taxes $319,913 billed from Dominion Energy Services, Inc.

(e) Concept: OperationExpense

Includes depreciation charges, amortization charges, and property taxes $26,282 billed from Dominion Energy Services, Inc.

(f) Concept: OperationExpense

Includes depreciation charges, amortization charges, and property taxes $28,997 billed from Dominion Energy Services, Inc.

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

STATEMENT OF RETAINED EARNINGS
Do not report Lines 49-53 on the quarterly report. Report all changes in appropriated retained earnings, unappropriated retained earnings, and unappropriated undistributed subsidiary earnings for the year. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436-439 inclusive). Show the contra primary account affected in column (b). State the purpose and amount for each reservation or appropriation of retained earnings. List first Account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow by credit, then debit items, in that order. Show dividends for each class and series of capital stock. Show separately the State and Federal income tax effect of items shown for Account 439, Adjustments to Retained Earnings. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated. If any notes appearing in the report to stockholders are applicable to this statement, attach them at page 122.
Line No.	Item (a)	Contra Primary Account Affected (b)	Current Quarter/Year Year to Date Balance (c)	Previous Quarter/Year Year to Date Balance (d)
	UnappropriatedRetainedEarningsAbstract UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1	UnappropriatedRetainedEarnings Balance-Beginning of Period		219,879,297	161,741,656
2	ChangesAbstract Changes
3	AdjustmentsToRetainedEarningsAbstract Adjustments to Retained Earnings (Account 439)
4	AdjustmentsToRetainedEarningsCreditAbstract Adjustments to Retained Earnings Credit
4.1	AdjustmentsToRetainedEarningsCredit
4.2	AdjustmentsToRetainedEarningsCredit
9	AdjustmentsToRetainedEarningsCredit TOTAL Credits to Retained Earnings (Acct. 439)
10	AdjustmentsToRetainedEarningsDebitAbstract Adjustments to Retained Earnings Debit
10.1	AdjustmentsToRetainedEarningsDebit Reclassification from Account 219 - Accumulated
10.2	AdjustmentsToRetainedEarningsDebit Other Comprehensive Income
15	AdjustmentsToRetainedEarningsDebit TOTAL Debits to Retained Earnings (Acct. 439)
16	BalanceTransferredFromIncome Balance Transferred from Income (Account 433 less Account 418.1)		102,678,080	50,997,068
17	AppropriationsOfRetainedEarningsAbstract Appropriations of Retained Earnings (Acct. 436)
17.1	AppropriationsOfRetainedEarnings Federal Power Act Appropriation - See Note 5 to the Financial Statements	215.1
22	AppropriationsOfRetainedEarnings TOTAL Appropriations of Retained Earnings (Acct. 436)
23	DividendsDeclaredPreferredStockAbstract Dividends Declared-Preferred Stock (Account 437)
29	DividendsDeclaredPreferredStock TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30	DividendsDeclaredCommonStockAbstract Dividends Declared-Common Stock (Account 438)
30.1	DividendsDeclaredCommonStock	238	100,000,000	75,000,000
36	DividendsDeclaredCommonStock TOTAL Dividends Declared-Common Stock (Acct. 438)		100,000,000	75,000,000
37	TransfersFromUnappropriatedUndistributedSubsidiaryEarnings Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings		46,117	611,731
38	UnappropriatedRetainedEarnings Balance - End of Period (Total 1,9,15,16,22,29,36,37)		222,511,260	137,126,993
39	AppropriatedRetainedEarningsAbstract APPROPRIATED RETAINED EARNINGS (Account 215)
45	AppropriatedRetainedEarnings TOTAL Appropriated Retained Earnings (Account 215)
	AppropriatedRetainedEarningsAmortizationReserveFederalAbstract APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46	AppropriatedRetainedEarningsAmortizationReserveFederal TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)		115,162,523	115,162,523
47	AppropriatedRetainedEarningsIncludingReserveAmortization TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)		115,162,523	115,162,523
48	RetainedEarnings TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)		(a) 337,673,783	252,289,516
	UnappropriatedUndistributedSubsidiaryEarningsAbstract UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49	UnappropriatedUndistributedSubsidiaryEarnings Balance-Beginning of Year (Debit or Credit)
50	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings for Year (Credit) (Account 418.1)
51	DividendsReceived (Less) Dividends Received (Debit)
52	ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits TOTAL other Changes in unappropriated undistributed subsidiary earnings for the year
52.1	ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits Funded Equity Method Losses
53	UnappropriatedUndistributedSubsidiaryEarnings Balance-End of Year (Total lines 49 thru 52)

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: RetainedEarnings

DESC's articles of incorporation do not limit the dividends that may be paid on its common stock. However, DESC's bond indenture under which it issues First Mortgage Bonds contains provisions that could limit the payment of cash dividends on its common stock. DESC's bond indenture permits the payment of dividends on DESC's common stock only either (1) out of its surplus (as defined in the bond indenture) or (2) in case there is no surplus, out of its net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year. In addition, with respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At March 31, 2022, approximately $115.2 million were restricted by this requirement as to payment of cash dividends on common stock.

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

STATEMENT OF CASH FLOWS
Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as investments, fixed assets, intangibles, etc. Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash Equivalents at End of Period" with related amounts on the Balance Sheet. Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid. Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the dollar amount of leases capitalized with the plant cost.
Line No.	Description (See Instructions No.1 for explanation of codes) (a)	Current Year to Date Quarter/Year (b)	Previous Year to Date Quarter/Year (c)
1	NetCashFlowFromOperatingActivitiesAbstract Net Cash Flow from Operating Activities
2	NetIncomeLoss Net Income (Line 78(c) on page 117)	102,631,963	50,385,337
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	76,830,642	73,323,269
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of Utility Plant and Acquisition Adjustment	2,260,099	2,560,421
5.2	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization - DER, Muni Franchise, Unrecovered Plt. & OCI	43,492,399	41,939,756
5.3	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of Nuclear Fuel	9,796,480	10,217,460
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	68,026,053	30,158,917
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)	324,280	316,381
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	10,663,253	122,123,181
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	1,457,587	13,611,145
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory	590	66
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	172,822,666	58,497,720
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	579,836	11,863,176
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	143,964,307	64,918,189
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	1,034,265	1,154,867
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other (provide details in footnote):	(a) 28,226,889	(f) 79,301,537
18.2	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Discount / Premium on Long-Term Debt	40,174	30,503
18.3	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Carrying Cost Recovery	1,211,982	2,760,453
18.4	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription (Gain) / Loss on Disposition of Assets	1,547,296	300,000
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	614,991	180,316,104
24	CashFlowsFromInvestmentActivitiesAbstract Cash Flows from Investment Activities:
25	ConstructionAndAcquisitionOfPlantIncludingLandAbstract Construction and Acquisition of Plant (including land):
26	GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities Gross Additions to Utility Plant (less nuclear fuel)	(b) 187,543,566	(g) 162,946,995
27	GrossAdditionsToNuclearFuelInvestingActivities Gross Additions to Nuclear Fuel	637,766	26,987,807
28	GrossAdditionsToCommonUtilityPlantInvestingActivities Gross Additions to Common Utility Plant	(c) 7,760,896	(h) 23,740,678
29	GrossAdditionsToNonutilityPlantInvestingActivities Gross Additions to Nonutility Plant	(d) 58,712	(i) 3,937
30	AllowanceForOtherFundsUsedDuringConstructionInvestingActivities (Less) Allowance for Other Funds Used During Construction	1,034,265	1,154,867
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
31.1	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Other (provide details in footnote):
31.2	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Salvage Received	912,140	154,910
31.3	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Cost of Removal	12,434,409	8,320,228
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	206,488,944	220,689,868
36	AcquisitionOfOtherNoncurrentAssets Acquisition of Other Noncurrent Assets (d)
37	ProceedsFromDisposalOfNoncurrentAssets Proceeds from Disposal of Noncurrent Assets (d)
39	InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Investments in and Advances to Assoc. and Subsidiary Companies	50,388	595,058
40	ContributionsAndAdvancesFromAssociatedAndSubsidiaryCompanies Contributions and Advances from Assoc. and Subsidiary Companies
41	DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompaniesAbstract Disposition of Investments in (and Advances to)
42	DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Disposition of Investments in (and Advances to) Associated and Subsidiary Companies
44	PurchaseOfInvestmentSecurities Purchase of Investment Securities (a)
45	ProceedsFromSalesOfInvestmentSecurities Proceeds from Sales of Investment Securities (a)
46	LoansMadeOrPurchased Loans Made or Purchased
47	CollectionsOnLoans Collections on Loans
49	NetIncreaseDecreaseInReceivablesInvestingActivities Net (Increase) Decrease in Receivables
50	NetIncreaseDecreaseInInventoryInvestingActivities Net (Increase) Decrease in Inventory
51	NetIncreaseDecreaseInAllowancesHeldForSpeculationInvestingActivities Net (Increase) Decrease in Allowances Held for Speculation
52	NetIncreaseDecreaseInPayablesAndAccruedExpensesInvestingActivities Net Increase (Decrease) in Payables and Accrued Expenses
53	OtherAdjustmentsToCashFlowsFromInvestmentActivities Other (provide details in footnote):
53.1	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Proceeds-Sale of Fixed Assets & Investments	1,769,368	300,000
53.2	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Investments in Utility Money Pool
53.3	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Return of Investments from Utility Money Pool
53.4	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Other Investments	(e) 816,107	(j) 1,094,647
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	205,586,071	222,079,573
59	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
60	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
61	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b)
62	ProceedsFromIssuanceOfPreferredStockFinancingActivities Preferred Stock
63	ProceedsFromIssuanceOfCommonStockFinancingActivities Common Stock
64	OtherAdjustmentsToCashFlowsFromFinancingActivities Other (provide details in footnote):
64.1	OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription Other (provide details in footnote):
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)	52,000,000	30,000,000
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
67.1	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
67.2	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Borrowings from Utility Money Pool & Intercompany Credit Agreement	1,816,765,422	1,076,035,679
67.3	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Deferred Financing Costs / Long-Term Debt Issuance Costs	52,716
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	1,868,712,706	1,106,035,679
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)	1,130,194	1,639,561
74	PaymentsForRetirementOfPreferredStockFinancingActivities Preferred Stock
75	PaymentsForRetirementOfCommonStockFinancingActivities Common Stock
76	OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
76.1	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
76.2	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Borrowings from Utilty Money Pool & Intercompany Credit Agreement	1,586,509,422	987,632,649
76.3	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Premiums & Costs Related to Redmeptions
78	NetDecreaseInShortTermDebt Net Decrease in Short-Term Debt (c)
80	DividendsOnPreferredStock Dividends on Preferred Stock
81	DividendsOnCommonStock Dividends on Common Stock	100,000,000	75,000,000
83	CashFlowsProvidedFromUsedInFinancingActivities Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)	181,073,090	41,763,469
85	NetIncreaseDecreaseInCashAndCashEquivalentsAbstract Net Increase (Decrease) in Cash and Cash Equivalents
86	NetIncreaseDecreaseInCashAndCashEquivalents Net Increase (Decrease) in Cash and Cash Equivalents (Total of line 22, 57 and 83)	23,897,990
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	54,128,951	100
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	30,230,961	100

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities

Includes ($3,957,027) for changes in the Company's net postretirement benefit obligation, $6,243,976 for Prepayments, ($909,138) for Customer Deposits and various other Balance Sheet changes not presented as separate line items.

(b) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities

For the three months ended March 31, 2022, the Company added $0 to its Utility Plant Property Accounts (101.1 and 118) and reduced the same accounts by ($1,345,956) for leases in accordance with USoA General Instruction No. 20.

(c) Concept: GrossAdditionsToCommonUtilityPlantInvestingActivities

For the three months ended March 31, 2022, the Company added $0 to its Common Utility Plant Property Account (118) and reduced the same account by ($1,624,270) for leases in accordance with USoA General Instruction No. 20.

(d) Concept: GrossAdditionsToNonutilityPlantInvestingActivities

For the three months ended March 31, 2022, the Company added $0 to its Nonutility Plant Property Account (121) and reduced the same account by ($101,855) for leases in accordance with USoA General Instruction No. 20.

(e) Concept: OtherAdjustmentsToCashFlowsFromInvestmentActivities

Nuclear Decommissioning Trust ($ 816,107)

(f) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities

Includes ($7,629,267) for changes in the Company's net postretirement benefit obligation, $5,179,414 for Prepayments, ($891,861) for Customer Deposits, $60,000,000 related to litigation reserves, $700,000 interest rate swap collateral returned and various other Balance Sheet changes not presented as separate line items.

(g) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities

For the three months ended March 31, 2021, the Company added $0 to its Utility Plant Property Accounts (101.1 and 118) and reduced the same accounts by ($1,469,289) for leases in accordance with USoA General Instruction No. 20.

(h) Concept: GrossAdditionsToCommonUtilityPlantInvestingActivities

For the three months ended March 31, 2021, the Company added $29,299 to its Common Utility Plant Property Account (118) and reduced the same account by ($391,972) for leases in accordance with USoA General Instruction No. 20.

(i) Concept: GrossAdditionsToNonutilityPlantInvestingActivities

For the three months ended March 31, 2021, the Company added $0 to its Nonutility Plant Property Account (121) and reduced the same account by ($463,835) for leases in accordance with USoA General Instruction No. 20.

(j) Concept: OtherAdjustmentsToCashFlowsFromInvestmentActivities

Nuclear Decommissioning Trust ($1,094,647)

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

NOTES TO FINANCIAL STATEMENTS

Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement, providing a subheading for each statement except where a note is applicable to more than one statement.
Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears on cumulative preferred stock.
For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant adjustments and requirements as to disposition thereof.
Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such restrictions.
If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be omitted.
For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements; status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such matters shall be provided even though a significant change since year end may not have occurred.
Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are applicable and furnish the data required by the above instructions, such notes may be included herein.

GLOSSARY OF TERMS

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


Abbreviation or Acronym						Definition
2017 Tax Reform Act						An Act to Provide for Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018 (previously known as The Tax Cuts and Jobs Act) enacted on December 22, 2017
ACE Rule						Affordable Clean Energy Rule
AOCI						Accumulated other comprehensive income (loss)
ARO						Asset retirement obligation
BACT						Best available control technology
CAA						Clean Air Act
CCR						Coal combustion residual
CERCLA						Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as Superfund
CO2						Carbon dioxide
CUA						Capacity Use Area
CWA						Clean Water Act
DES						Dominion Energy Services, Inc.
DESC						The legal entity, Dominion Energy South Carolina, Inc., one or more of its consolidated entities or operating segment, or the entirety of Dominion Energy South Carolina, Inc. and its consolidated entities
Dominion Energy						The legal entity, Dominion Energy, Inc., one or more of its consolidated subsidiaries (other than DESC) or operating segments, or the entirety of Dominion Energy, Inc. and its consolidated subsidiaries
Dominion Energy South Carolina						Dominion Energy South Carolina operating segment
DSM						Demand-side management
ELG Rule						Effluent limitations guidelines for the steam electric power generating category
EPA						U.S. Environmental Protection Agency
FERC						Federal Energy Regulatory Commission
Fuel Company						South Carolina Fuel Company, Inc.
GAAP						U.S. generally accepted accounting principles
GENCO						South Carolina Generating Company, Inc.
GHG						Greenhouse gas
MGD						Million gallons per day
NND Project						V. C. Summer Units 2 and 3 nuclear development project under which DESC and Santee Cooper undertook to construct two Westinghouse AP1000 Advanced Passive Safety nuclear units in Jenkinsville, South Carolina
NOx						Nitrogen oxide


Order 1000						Order issued by FERC adopting requirements for electric transmission planning, cost allocation and development
PSD						Prevention of significant deterioration
Questar Gas						Questar Gas Company, a wholly-owned subsidiary of Dominion Energy
Santee Cooper						South Carolina Public Service Authority
SCANA						The legal entity, SCANA Corporation, one or more of its consolidated subsidiaries (other than DESC) or the entirety of SCANA Corporation and its consolidated subsidiaries
SCANA Combination						Dominion Energy's acquisition of SCANA completed on January 1, 2019 pursuant to the terms of the SCANA Merger Agreement
SCANA Merger Agreement						Agreement and plan of merger entered on January 2, 2018 between Dominion Energy and SCANA
SCANA Merger Approval Order						Final order issued by the South Carolina Commission on December 21, 2018 setting forth its approval of the SCANA Combination
SCDHEC						South Carolina Department of Health and Environmental Control
SCDOR						South Carolina Department of Revenue
SEC						U.S. Securities and Exchange Commission
SO2						Sulfur dioxide
South Carolina Commission						Public Service Commission of South Carolina
Summer						V. C. Summer nuclear power station
Toshiba						Toshiba Corporation, parent company of Westinghouse
Toshiba Settlement						Settlement Agreement dated as of July 27, 2017, by and among Toshiba, DESC and Santee Cooper
VIE						Variable interest entity
Virginia Power						The legal entity, Virginia Electric and Power Company, a wholly-owned subsidiary of Dominion Energy, one or more of its consolidated subsidiaries or operating segment, or the entirety of Virginia Electric and Power Company and its consolidated subsidiaries
Westinghouse						Westinghouse Electric Company LLC

The financial statements shown on pages 110 through 122 are prepared in accordance with the accounting requirements of the FERC as set forth in its applicable Uniform System of Accounts and published accounting releases, which is a comprehensive basis of accounting other than GAAP. The significant differences from the Company’s GAAP requirements are related to the classification of certain assets and liabilities to include (i) the classification of restricted cash amounts within other current assets in the GAAP financial statements, whereas these amounts are included within cash in the FERC financial statements; (ii) the classification of a portion of regulatory assets and liabilities as current assets and liabilities in the GAAP financial statements, whereas these amounts are reported as deferred debits and credits in the FERC financial statements; (iii) the current portion of long term debt is not classified as a current liability in the FERC financial statements; (iv) certain affiliated payables and receivables are presented on a gross basis in the FERC financial statements, whereas these are reported on a net basis in the GAAP financial statements; (v) accumulated deferred income taxes are reported on a gross basis in the FERC financial statements, whereas these amounts are reported on a net basis by jurisdiction in the GAAP financial statements; (vi) the removal of uncognized tax benefits for FERC reporting; (vii) accrued cost of removal is reported within accumulated provisions for depreciation in the FERC financial statements, whereas these amounts are reported within regulatory liabilities in the GAAP financial statements; (viii) debt issuance costs are reported within unamortized debt expense in the FERC financial statements, whereas these amounts are reported as a reduction to the carrying value of the debt in the GAAP financial statements; (ix) unamortized losses and gains on reacquired debt are reported within regulatory assets and liabilities in the GAAP basis financial statements and are separately presented within deferred debits and credits in the FERC financial statements; (x) the presentation of leases and the removal of regulatory assets recorded for GAAP reporting purposes related to leases; (xi) certain cloud computing arrangement costs are classified within net utility plant in the FERC financial statements whereas these amounts are included within prepayments on the GAAP basis statements; (xii) the non-service cost component of certain pension and other post employment benefits are reported within net utility plant and operation and maintenance expenses in the FERC financial statements, whereas these amounts are reported as regulatory assets and nonoperating expenses in the GAAP financial statements; and (xiii) the carrying value related to the planned retirement of certain peaking units is reported within net utility plant in the FERC financial statements until retirement, whereas these amounts are reported as regulatory assets in the GAAP financial statements . Also, certain charges associated with the abandonment of the NND Project are classified within operating income and taxes for GAAP reporting purposes, whereas these amounts are classified within nonoperating income (other deductions) for FERC reporting purposes. In addition, the accounts of GENCO are not consolidated herein, whereas they are so consolidated for GAAP reporting purposes.

The Company adopted revised GAAP accounting guidance for the recognition, measurement, presentation, and disclosure of leasing arrangements in 2019. For FERC reporting purposes, as a result of the adoption of this guidance, the Company established leased assets and liabilities for operating leases in the existing FERC balance sheet accounts for leases, in addition to the assets and liabilities the Company already maintained for its capital lease amounts which are now considered finance leases. The Company follows the accounting guidance set forth in General Instruction 20 of the Uniform System of Accounts. The operating lease assets established upon the adoption of this new accounting guidance have been excluded from rate base in the Company’s FERC jurisdictional cost of service rates.

These notes are based on the notes contained in DESC's Quarterly Report on Form 10-Q filed with the SEC and reflect certain reclassifications from the Uniform System of Accounts presentation shown on pages 110 through 122.

Management has evaluated the impact of events occurring after March 31, 2022 up to May 5, 2022, the date that DESC's GAAP financial statements were issued and has updated such evaluation for disclosure purposes through May 24, 2022. These financial statements include all necessary adjustments and disclosures resulting from these evaluations.

Dominion Energy South Carolina, Inc.

Notes to Consolidated Financial Statements

(Unaudited)

The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in DESC's Annual Report on Form 10-K for the year ended December 31, 2021.

These are interim financial statements and, due to the seasonality of DESC's business and matters that may occur during the rest of the year, the amounts reported in the Consolidated Statements of Comprehensive Income are not necessarily indicative of amounts expected for the full year. In the opinion of management, the information furnished herein reflects all adjustments which are necessary for a fair statement of the results for the interim periods reported, and such adjustments are of a normal recurring nature. In addition, the preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Certain amounts in DESC's 2021 Consolidated Financial Statements and Notes have been reclassified to conform to the 2022 presentation for comparative purposes; however, such reclassifications did not affect DESC's net income and other comprehensive income, total assets, liabilities, equity or cash flows. Effective in the second quarter of 2021, DESC updated its 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.

DESC is a wholly-owned subsidiary of SCANA, which is a wholly-owned subsidiary of Dominion Energy.

The financial statements and notes contained herein have not been audited.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Consolidation and Variable Interest Entities

DESC has determined that it has a controlling financial interest in Fuel Company (which is considered to be aVIE) and, accordingly, DESC's Consolidated Financial Statements include, after eliminating intercompany balances and transactions, the accounts of DESC and Fuel Company. See Note 2 to the Consolidated Financial Statements included in DESC’s Annual Report on Form 10-K for the year ended December 31, 2021 for a description of Fuel Company.

DESC purchases shared services from DES, an affiliated VIE that provides accounting, legal, finance and certain administrative and technical services to all Dominion Energy subsidiaries, including DESC. DESC has determined that it is not the primary beneficiary of DES as it does not have either the power to direct the activities that most significantly impact its economic performance or an obligation to absorb losses and benefits which could be significant to it. See Note 12 for amounts attributable to affiliates.

Significant Accounting Policies

There have been no significant changes from Note 2 to the Consolidated Financial Statements in DESC's Annual Report on Form 10-K for the year ended December 31, 2021.

2. RATE AND OTHER REGULATORY MATTERS

Regulatory Matters Involving Potential Loss Contingencies

As a result of issues generated in the ordinary course of business, DESC is 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 DESC to estimate a range of possible loss. For regulatory matters that DESC 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 DESC is able to estimate a range of possible loss. For regulatory matters for which DESC is 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 DESC’s 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 DESC’s financial position, liquidity or results of operations.

Other Regulatory Matters

Other than the following matters, there have been no significant developments regarding the pending regulatory matters disclosed in Note 3 to the Consolidated Financial Statements in DESC's Annual Report on Form 10-K for the year ended December 31, 2021.

Electric – 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 2022, the South Carolina Commission approved DESC’s request to increase the total fuel cost component of retail electric rates, effective with the first billing cycle of May 2022. The South Carolina Commission also approved DESC’s request to apply approximately $66 million representing the net balance of funds associated with the monetization of the bankruptcy settlement with Toshiba following the satisfaction of liens against NND Project property previously recorded in regulatory liabilities, as a reduction to its under-collected base fuel cost balance, along with a requested increase to DESC’s variable environmental and avoided capacity cost component. The net effect is an annual increase of $143 million.

Electric – Other

DESC has approval for a DSM rider through which it recovers expenditures related to its DSM programs. In January 2022, DESC filed an application with the South Carolina Commission seeking approval to recover $60 million of costs and net lost revenues associated with these programs, along with an incentive to invest in such programs. In April 2022, the South Carolina Commission approved the request, effective with the first billing cycle of May 2022.

DESC utilizes a pension costs rider approved by the South Carolina Commission which is designed to allow recovery of projected pension costs, including under-collected balances or net of over-collected balances, as applicable. The rider is typically reviewed for adjustment every 12 months with any resulting increase or decrease going into effect beginning with the first billing cycle in May. In April 2022, the South Carolina Commission approved DESC’s requested adjustment to this rider to decrease annual revenue by $12 million.

Regulatory Assets and Regulatory Liabilities

Rate-regulated utilities recognize in their financial statements certain revenues and expenses in different periods than do other enterprises. As a result, DESC has recorded regulatory assets and regulatory liabilities which are summarized in the following table. Except for NND Project costs and certain other unrecovered costs referenced herein, substantially all regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.


	March 31,		December 31,
(millions)	2022		2021
Regulatory assets:
NND Project costs(1)	$	138	$	138
Deferred employee benefit plan costs(2)		4		8
Other unrecovered plant(3)		16		16


DSM programs(4)		22		23
AROs(5)		1		1
Cost of fuel and purchased gas under-collections(6)		121		126
Other		46		47
Regulatory assets - current		348		359
NND Project costs(1)		2,191		2,226
AROs(5)		326		294
Deferred employee benefit plan costs(2)		110		106
Deferred losses on interest rate derivatives(7)		279		284
Other unrecovered plant(3)		63		57
DSM programs(4)		44		45
Environmental remediation costs(8)		37		30
Deferred storm damage costs(9)		38		38
Deferred transmission operating costs(10)		77		77
Other(11)		133		128
Regulatory assets - noncurrent		3,298		3,294
Total regulatory assets	$	3,646	$	3,653
Regulatory liabilities:
Monetization of guaranty settlement(12)	$	67	$	67
Income taxes refundable through future rates(13)		39		40
Reserve for refunds to electric utility customers(14)		109		113
Cost of fuel and purchased gas over-collections(6)		4		—
Derivatives(15)		52		18
Other		8		5
Regulatory liabilities - current		279		243
Monetization of guaranty settlement(12)		753		831
Income taxes refundable through future rates(13)		865		872
Asset removal costs(16)		554		553
Deferred gains on interest rate derivatives(7)		66		67
Reserve for refunds to electric utility customers(14)		394		425
Derivatives(15)		173		131
Other		9		9
Regulatory liabilities - noncurrent		2,814		2,888
Total regulatory liabilities	$	3,093	$	3,131


(1)			Reflects expenditures associated with the NND Project, which pursuant to the SCANA Merger Approval Order, will be recovered from electric service customers over a 20-year period ending in 2039. See Note 12 to the Consolidated Financial Statements in DESC’s Annual Report on Form 10-K for the year ended December 31, 2021 for additional information.
(2)			Employee benefit plan costs have historically been recovered as they have been recorded under GAAP. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific South Carolina Commission regulatory orders. DESC expects to recover deferred pension costs through utility rates over periods through 2044. DESC expects to recover other deferred benefit costs through utility rates, primarily over average service periods of participating employees up to 11 years.
(3)			Represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. DESC is amortizing these amounts through cost of service rates following depreciation amounts that were designed to recover the retired units’ cost over their previous estimated remaining useful lives, which has been estimated to be through 2025. Based on current projections of remaining decommissioning costs, projected recovery is expected to extend to 2029 . In addition, amounts include unrecovered costs of existing meters and equipment retired from service prior to being fully depreciated as part of the Advance Metering Infrastructure project, which are being recovered through rates through 2028. This amount also includes certain inventory and preliminary survey and investigation charges being amortized over five years related to the transition or conversion from coal to gas fired generation at certain facilities. In addition, reflects an increase of approximately $7 million related to the abandonment of certain peaking gas generation facilities, such amounts having been reclassified from property, plant and equipment to noncurrent other unrecovered plant. Unamortized amounts are included in rate base and are earning a current return


(4)			Represents deferred costs associated with electric demand reduction programs, and such deferred costs are currently being recovered over three years through an approved rate rider.


(5)			Represents deferred depreciation and accretion expense related to legal obligations associated with the future retirement of generation, transmission and distribution properties. The AROs primarily relate to DESC’s electric generating facilities, including Summer, and are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 105 years.
(6)			Represents amounts under- or over-collected from customers pursuant to the cost of fuel and purchased gas components approved by the South Carolina Commission. Reflects a $66 million reduction recorded in the first quarter of 2022 from the application of a portion of the monetization of guarantee settlement previously reflected as regulatory liabilities associated with the approval of DESC’s cost of fuel proceedings. See above for additional information.
(7)			Represents (i) the changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments made or received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt through 2043.The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense through 2065.
(8)			Reflects amounts associated with the assessment and clean-up of sites currently or formerly owned by DESC. Such remediation costs are expected to be recovered over periods of up to 27 years. See Note 10 for additional information.
(9)			Represents storm restoration costs which DESC expects to recover through customer rates over approximately 10 years pursuant to the settlement agreement approved in DESC’s retail electric base rate case. Unamortized amounts are included in rate base and are earning a current return.
(10)			(10)
(11)			Various other regulatory assets are expected to be recovered through rates over varying periods through 2047.
(12)			Represents proceeds related to the monetization of the Toshiba Settlement. In accordance with the SCANA Merger Approval Order, this balance, net of amounts that may be required to satisfy liens, will be refunded to electric customers over a 20-year period ending in 2039. See Note 12 to the Consolidated Financial Statements in DESC’s Annual Report on Form 10-K for the year ended December 31, 2021 for additional information.
(13)			Includes (i) excess deferred income taxes arising from the remeasurement of deferred income taxes in connection with the enactment of the 2017 Tax Reform Act (certain of which are protected under normalization rules and will be amortized over the remaining lives of related property, and certain of which will be amortized to the benefit of customers over prescribed periods as instructed by regulators) and (ii) deferred income taxes arising from investment tax credits, offset by (iii) deferred income taxes that arise from utility operations that have not been included in customer rates (a portion of which relate to depreciation and are expected to be recovered over the remaining lives of the related property which may range up to 85 years). See Note 7 to the Consolidated Financial Statements in DESC’s Annual Report on Form 10-K for the year ended December 31, 2021 for additional information.
(14)			Reflects amounts previously collected from retail electric customers of DESC for the NND Project to be credited to customers over an estimated 11-year period effective February 2019 in connection with the SCANA Merger Approval Order. See Note 12 to the Consolidated Financial Statements in DESC’s Annual Report on Form 10-K for the year ended December 31, 2021.
(15)			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.
(16)			Represents estimated net collections through depreciation rates of amounts to be expended for the removal of assets in the future.

Regulatory assets have been recorded based on the probability of their recovery. All regulatory assets represent incurred costs that may be deferred under GAAP for regulated operations. The South Carolina Commission or FERC has reviewed and approved through specific orders certain of the items shown as regulatory assets. In addition, regulatory assets include, but are not limited to, certain costs which have not been specifically approved for recovery by one of these regulatory agencies. While such costs are not currently being recovered, management believes they would be allowable under existing rate-making concepts embodied in rate orders or applicable state law and expects to recover these costs through rates in future periods.

3. REVENUE RECOGNITION

DESC has disaggregated operating revenues by customer class as follows:


	Three Months Ended				Three Months Ended
	March 31, 2022				March 31, 2021
(millions)	Electric		Gas		Electric		Gas
Customer class:
Residential	$	300	$	109	$	275	$	98
Commercial		201		48		175		39
Industrial		108		31		88		22
Other		38		6		33		5
Revenues from contracts with customers		647		194		571		164
Other revenues		8		—		8		1
Total Operating Revenues	$	655	$	194	$	579	$	165

Contract liabilities represent the obligation to transfer goods or services to a customer for which consideration has already been received from the customer. DESC had contract liability balances of $8 million at both March 31, 2022 and December 31, 2021. During the three months ended March 31, 2022 and 2021, DESC recognized revenue of $4 million and $3 million, respectively, from the beginning contract liability balances as DESC fulfilled its obligations to provide service to its customers. Contract liabilities are recorded in customer deposits and customer prepayments in the Consolidated Balance Sheets.

Balances and activity related to contract costs deferred as regulatory assets were as follows:


	Regulatory Assets
(millions)	March 31, 2022			December 31, 2021
Beginning balance	$	11		$	12
Amortization		(1	)		(1	)
Ending balance	$	10		$	11

4. EQUITY

For all periods presented, DESC's authorized shares of common stock, no par value, were 50 million, of which 40.3 million were issued and outstanding, and DESC's authorized shares of preferred stock, no par value, were 20 million, of which 1,000 shares were issued and outstanding. All outstanding shares of common and preferred stock are held by SCANA.

In May 2022, Dominion Energy issued $72 million of shares of Dominion Energy common stock to partially satisfy DESC’s remaining obligation under a settlement agreement with the SCDOR discussed in Note 10. In connection with this transaction, DESC will record an equity contribution from Dominion Energy in the second quarter of 2022.

There have been no material changes to the dividend restrictions affecting DESC described in Note 5 to the Consolidated Financial Statements in DESC’s Annual Report on Form 10-K for the year ended December 31, 2021.

5. LONG-TERM AND SHORT-TERM DEBT

DESC’s short-term financing is supported through its access as co-borrower to Dominion Energy’s $6.0 billion joint revolving credit facility, which can be used for working capital, as support for the combined commercial paper programs of DESC, Dominion Energy, Virginia Power and Questar Gas, and for other general corporate purposes. Other than the items discussed below, there have been no significant changes from Note 6 to the Consolidated Financial Statements in DESC's Annual Report on Form 10-K for the year ended December 31, 2021.

At March 31, 2022, DESC's share of commercial paper and letters of credit outstanding under its joint credit facility with Dominion Energy, was as follows:


(millions)	Facility Limit		Outstanding Commercial Paper		Outstanding Letters of Credit
Joint revolving credit facility(1)	$	1,000	$	52	$	—


(1)			A maximum of $1.0 billion of the facility is available to DESC, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power and Questar Gas. A sub-limit for DESC is set within the facility limit but can be changed at the option of the co-borrowers multiple times per year. At March 31, 2022, the sub-limit for DESC was $500 million. If DESC 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 DESC's parent or from Dominion Energy. This credit facility matures in June 2026, with the potential to be extended by the borrowers to June 2028. The credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.0 billion (or the sub-limit, whichever is less) of letters of credit.

DESC is obligated with respect to an aggregate of $68 million of industrial revenue bonds which are secured by letters of credit. These letters of credit expire, subject to renewal, in the fourth quarter of 2022.

DESC has FERC approval to enter into an inter-company credit agreement with Dominion Energy under which DESC may have short-term borrowings outstanding up to $900 million. At March 31, 2022 and December 31, 2021, DESC had borrowings outstanding under this credit agreement totaling $646 million and $415 million, respectively, which are recorded in affiliated and related party payables in DESC’s Consolidated Balance Sheets. For both the three months ended March 31, 2022 and 2021, DESC recorded interest charges of $2 million.

Fuel Company participated in a SCANA utility money pool until January 2021, when that utility money pool was closed. Money pool borrowings and investments bore interest at short-term market rates. For the three-months ended March 31, 2021, DESC recorded both interest income and interest expense from money pool transactions of less than $1 million.

6. INCOME TAXES

DESC’s effective tax rate is 19.5% for both the three months ended March 31, 2022 and 2021.

As of March 31, 2022, there have been no material changes in DESC’s unrecognized tax benefits. See Note 7 to the Consolidated Financial Statements in DESC's Annual Report on Form 10-K for the year ended December 31, 2021 for a discussion of these unrecognized tax benefits.

7. DERIVATIVE FINANCIAL INSTRUMENTS

DESC’s accounting policies, objectives, and strategies for using derivative instruments are discussed in Note 2 in the Consolidated Financial Statements in DESC’s Annual Report on Form 10-K for the year ended December 31, 2021. See Note 8 for further information about fair value measurements and associated valuation methods for derivatives.

Derivative assets and liabilities are presented gross on the Consolidated Balance Sheets. DESC’s derivative contracts include over-the-counter transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Certain over-the-counter contracts contain contractual rights of setoff through master netting arrangements 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 are subject to collateral requirements. Types of collateral for over-the-counter contracts include cash, letters of credit and, in some cases, other forms of security, none of which are subject to restrictions. Cash collateral, as presented in the table below, is used to offset derivative assets and liabilities.

Certain of DESC’s derivative instruments contain credit-related contingent provisions. These provisions require DESC to provide collateral upon the occurrence of specific events, primarily a credit rating downgrade. If the credit-related contingent features underlying the instruments that are in a liability position and not fully collateralized with cash were fully triggered as of March 31, 2022 and December 31, 2021, DESC would have been required to post $3 million and $7 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.. No collateral was posted at DESC at both March 31, 2022 and December 31, 2021 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 March 31, 2022 and December 31, 2021 was $3 million and $7 million, respectively, which does not include the impact of any offsetting asset positions.

The table below presents derivative balances by type of financial instrument, if the gross amounts recognized in the Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid. DESC’s commodity derivative assets are not subject to a master netting agreement or similar arrangement.


	March 31, 2022								December 31, 2021
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
(millions)	Gross Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Gross Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
Interest rate contracts:
Over-the-counter	$	3	$	—	$	—	$	3	$	7	$	—	$	1	$	7
Total derivatives	$	3	$	—	$	—	$	3	$	7	$	—	$	1	$	7


(1)			There were no derivative liabilities that are not subject to master netting or similar arrangements at March 31, 2022 or December 31, 2021.

Volumes

The following table presents the volume of derivative activity at March 31, 2022. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions.


	Current		Noncurrent
Electricity (MWh in millions):
Fixed price		2		22
Interest rate(1) (in millions)	$	—	$	35

(1) Maturity is determined based on final settlement period.

Fair Value and Gains and Losses on Derivative Instruments

The following tables present the fair values of derivatives and where they are presented in the Consolidated Balance Sheets:


(millions)	Fair Value - Derivatives not under Hedge Accounting
At March 31, 2022
ASSETS
Current Assets
Commodity	$	52
Total current derivative assets(1)		52
Noncurrent Assets
Commodity		173
Total noncurrent derivative assets(2)		173
Total derivative assets	$	225
LIABILITIES
Noncurrent Liabilities
Interest rate		3
Total noncurrent derivative liabilities(4)		3
Total derivative liabilities	$	3
At December 31, 2021
ASSETS
Current Assets
Commodity	$	18
Total current derivative assets(1)		18
Noncurrent Assets
Commodity		130
Total noncurrent derivative assets(2)		130
Total derivative assets	$	148
LIABILITIES
Current Liabilities
Interest rate	$	1
Total current derivative liabilities(3)		1
Noncurrent Liabilities
Interest rate		6
Total noncurrent derivative liabilities(4)		6
Total derivative liabilities	$	7


(1)			Current derivative assets are presented in other current assets in DESC’s Consolidated Balance Sheets.
(2)			Noncurrent derivative assets are presented in other deferred debits and other assets in DESC’s Consolidated Balance Sheets.
(3)			Current derivative liabilities are presented in other current liabilities in DESC’s Consolidated Balance Sheets.
(4)			Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in DESC’s Consolidated Balance Sheets.

The following tables present the gains and losses on derivatives, as well as where the associated activity is presented in the Consolidated Balance Sheets and Statements of Comprehensive Income:

Derivatives in Cash Flow Hedging Relationships


(millions)	Increase (Decrease) in Derivatives Subject to Regulatory Treatment(1)
Three Months Ended March 31, 2022
Derivative type and location of gains (losses):
Interest rate	$	—
Total	$	—
Three Months Ended March 31, 2021
Derivative type and location of gains (losses):
Interest rate	$	2
Total	$	2


(1)			Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/ liabilities have no associated effect in the Consolidated Statements of Comprehensive Income.

Derivatives Not Designated as Hedging Instrument


(millions)	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Three Months Ended March 31,	2022		2021
Derivative type and location of gains (losses):
Commodity contracts:
Purchased power	$	3	$	—
Interest rate contracts:
Interest charges		(1)		—
Total	$	2	$	—


(1)			Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in the Consolidated Statements of Comprehensive Income.

8. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

DESC’s fair value measurements are made in accordance with the policies discussed in Note 9 to the Consolidated Financial Statements in DESC’s Annual Report on Form 10-K for the year ended December

31, 2021. See Note 7 in this report for further information about DESC’s derivatives and hedge accounting activities. DESC applies fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments.

The following table presents DESC’s quantitative information about Level 3 fair value measurements at March 31, 2022. The range and weighted average are presented in dollars for market price inputs.

Fair Value

(millions)

Valuation Techniques

Unobservable Input

Range

Weighted

Average(1)

Assets

Physical forwards:

Electricity

$

225

Discounted cash flow

Market price (per MWh)

(2)

30-87

47

Total assets

$

225

(1) Averages weighted by volume.

(2) Represents market prices beyond defined terms for Levels 1 and 2.

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

Significant Unobservable

Inputs

Position

Change to Input

Impact on Fair Value

Measurement

Market price

Buy

Increase (decrease)

Gain (loss)

Market price

Sell

Increase (decrease)

Loss (gain)

Recurring Fair Value Measurements

The following table presents DESC’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:


(millions)	Level 1		Level 2		Level 3		Total
At March 31, 2022
Assets
Commodity	$	—	$	—	$	225	$	225
Total assets	$	—	$	—	$	225	$	225
Liabilities
Interest rate	$	—	$	3	$	—	$	3
Total liabilities	$	—	$	3	$	—	$	3
At December 31, 2021
Assets
Commodity	$	—	$	—	$	148	$	148
Total assets	$	—	$	—	$	148	$	148
Liabilities


Interest rate	$	—	$	7	$	—	$	7
Total liabilities	$	—	$	7	$	—	$	7

The following table presents the net change in DESC's assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category. There were no net changes in assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category for the three months ended March 31, 2021.




	Three Months Ended
	March 31,
	2022
(millions)
Beginning balance	$	148
Total realized and unrealized gains (losses):
Included in earnings:
Purchased power		3
Included in regulatory assets/liabilities		77
Settlements		(3	)
Ending balance	$	225

There are no unrealized gains and losses included in earnings in the Level 3 fair value category related to assets/liabilities still held at the

reporting date for the three months ended March 31, 2022.

Fair Value of Financial Instruments

Substantially all of DESC’s 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 financial instruments classified within current assets and current liabilities are representative of fair value because of the short-term nature of these instruments. For financial instruments that are not recorded at fair value, the carrying amounts and estimated fair values are as follows:


		March 31, 2022				December 31, 2021
(millions)		Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(1)
Long-term debt(2)		$	3,691	$	4,198	$	3,691	$	4,798

(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.

9. EMPLOYEE BENEFIT PLANS

Components of net periodic benefit cost recorded by DESC were as follows:


(millions)	Pension Benefits						Other Postretirement Benefits
Three Months Ended March 31,	2022			2021			2022		2021
Service cost	$	2		$	3		$	—	$	1
Interest cost		5			5			2		1
Expected return on assets		(12	)		(12	)		—		—
Amortization of actuarial losses		—			2			—		—
Net periodic benefit cost (credit)	$	(5	)	$	(2	)	$	2	$	2

During the three months ended March 31, 2022, DESC made no contributions to its pension trust and does not expect to make any such contributions in 2022. DESC recovers current pension costs through either a rate rider that may be adjusted annually for retail electric operations or through cost of service rates for gas operations.

10. COMMITMENTS AND CONTINGENCIES

As a result of issues generated in the ordinary course of business, DESC is involved in legal proceedings before various courts and is 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 DESC to estimate a range of possible loss. For such matters that DESC 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 DESC is able to estimate a range of possible loss. For legal proceedings and governmental examinations for which DESC is 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. DESC maintains 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 DESC’s 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 DESC’s financial position, liquidity or results of operations.

Environmental Matters

DESC 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.

From a regulatory perspective, DESC continually monitors and evaluates its current and projected emission levels and strives to comply with all state and federal regulations regarding those emissions. DESC participates in the SO2 and NOX emission allowance programs with respect to coal plant emissions and also has constructed additional pollution control equipment at its coal-fired electric generating plants. These actions are expected to address many of the rules and regulations discussed herein.

Air

The CAA, as amended, is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation's air quality. At a minimum, states are required to establish regulatory programs to meet applicable requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Many of DESC’s facilities are subject to the CAA’s permitting and other requirements.

ACE Rule

In July 2019, the EPA published the final rule informally referred to as the ACE Rule, as a replacement for the Clean Power Plan. The ACE Rule regulated GHG emissions from existing coal-fired power plants

pursuant to Section 111(d) of the CAA and required states to develop plans by July 2022 establishing unit-specific performance standards for existing coal-fired power plants. In January 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE Rule and remanded it to the EPA. This decision would take effect upon issuance of the court’s mandate. In March 2021, the court issued a partial mandate vacating and remanding all parts of the ACE Rule except for the portion of the ACE Rule that repealed the Clean Power Plan. In October 2021, the U.S. Supreme Court agreed to hear a challenge of the U.S. Court of Appeals for the D.C. Circuit’s decision on the ACE Rule. While the EPA has stated its intention to replace the ACE Rule, it is unknown at this time if or how the EPA will issue a replacement for the ACE Rule and how that replacement will affect DESC’s operations, financial condition and/or cash flows.

Carbon Regulations

In August 2016, the EPA issued a draft rule proposing to reaffirm that a source’s obligation to obtain a PSD or Title V permit for GHGs is triggered only if such permitting requirements are first triggered by non-GHG, or conventional, pollutants that are regulated by the New Source Review program, and exceed a significant emissions rate of 75,000 tons per year of CO2 equivalent emissions. Until the EPA ultimately takes final action on this rulemaking, DESC cannot predict the impact to its results of operations, financial condition and/or cash flows.

In December 2018, the EPA proposed revised Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources. The proposed rule would amend the previous determination that the best system of emission reduction for newly constructed coal-fired steam generating units is no longer partial carbon capture and storage. Instead, the proposed revised best system of emission reduction for this source category is the most efficient demonstrated steam cycle (e.g., supercritical steam conditions for large units and subcritical steam conditions for small units) in combination with best operating practices. In January 2021, the EPA published a final rule affirming that fossil fuel-fired electric generating units meet the requirement that a source category “significantly contribute” to endangering air pollution for the purposes of regulating GHG emissions from new, modified and reconstructed stationary sources. The January 2021 rule also established a threshold for the “significant contribution” threshold that would have meant that no other source category, such as oil and gas facilities, petroleum refineries, and boilers, would meet that requirement at this time. In April 2021, the U.S. Court of Appeals for the D.C. Circuit granted an unopposed motion by the EPA to vacate and remand the January 2021 rule. The proposed revision to the performance standards for coal-fired steam generating units remains pending. Until the EPA ultimately takes final action on this rulemaking, DESC cannot predict the impact to its results of operations, financial condition and/or cash flows.

Water

The CWA, as amended, is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. DESC must comply with applicable aspects of the CWA programs at its operating facilities.

Regulation 316(b)

In October 2014, the final regulations under Section 316(b) of the CWA that govern existing facilities and new units at existing facilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold became effective. The rule establishes a national standard for impingement based on seven compliance options, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA has delegated entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of five mandatory facility-specific factors, including a social cost-benefit test, and six optional facility-specific factors. The rule governs all electric generating stations with water withdrawals above two MGD, with a heightened entrainment analysis for those facilities over 125 MGD. DESC has four facilities that are subject to the final

regulations. DESC is also working with the EPA and state regulatory agencies to assess the applicability of Section 316(b) to five hydroelectric facilities. DESC anticipates that it may have to install impingement control technologies at certain of these stations that have once-through cooling systems. DESC is currently evaluating the need or potential for entrainment controls under the final rule as these decisions will be made on a case-by-case basis after a thorough review of detailed biological, technological, and cost benefit studies. DESC is conducting studies and implementing plans as required by the rule to determine appropriate intake structure modifications at certain facilities to ensure compliance with this rule. While the impacts of this rule could be material to DESC’s results of operations, financial condition and/or cash flows, the existing regulatory framework in South Carolina provides rate recovery mechanisms that could substantially mitigate any such impacts for DESC.

Effluent Limitations Guidelines

In September 2015, the EPA released a final rule to revise the ELG Rule. The final rule established updated standards for wastewater discharges that apply primarily at coal and oil steam generating stations. Affected facilities are required to convert from wet to dry or closed cycle coal ash management, improve existing wastewater treatment systems and/or install new wastewater treatment technologies in order to meet the new discharge limits. In April 2017, the EPA granted two separate petitions for reconsideration of the final ELG 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 final ELG Rule from November 2018 to November 2020; however, the latest date for compliance for these regulations was December 2023. In October 2020, the EPA released the final rule that extends the latest dates for compliance. Individual facilities’ compliance dates will vary based on circumstances and the determination by state regulators and may range from 2021 to 2028. While the impacts of this rule could be material to DESC’s results of operations, financial condition and/or cash flows, as DESC expects that wastewater treatment technology retrofits and modifications to the bottom ash handling systems at the Wateree generating station will be required, the existing regulatory framework in South Carolina provides rate recovery mechanisms that could substantially mitigate any such impacts for DESC.

Capacity Use Area

In November 2019, a new CUA was established in the counties surrounding the Cope Generating Station (Western Capacity Use Area) under the South Carolina Groundwater Use and Reporting Regulation. Under the regulation any groundwater well in a CUA that withdraws above three million gallons per month must be permitted. The Cope Generating Station is located within this new Western Capacity Use Area. Cope has been using four deep groundwater wells for cooling water and other house loads since 1996. Prior to designation of the new Western Capacity Use Area, the wells at Cope Station were only required to be registered not permitted. As a result of this designation, Cope will need to restore the surface water equipment to operable status to reduce reliance on groundwater wells. This includes completion of 316(b) requirements, (including SCDHEC BACT determination and modification of the station national pollutant discharge elimination system permit) and extensive inspection, repair and/or replacement of the associated surface water withdrawal equipment which has been idle since 1996. While the impacts of this rule change are material to DESC’s results of operations, financial condition and/or cash flows, the existing regulatory framework in South Carolina provides rate recovery mechanisms that could substantially mitigate any such impacts for DESC.

Waste Management and Remediation

The operations of DESC 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, DESC 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, DESC 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. DESC also may identify, evaluate and remediate other potentially impacted sites under voluntary state programs. Remediation costs may be subject to reimbursement under DESC’s insurance policies, rate recovery mechanisms, or both. Except as described below, DESC does not believe these matters will have a material effect on results of operations, financial condition and/or cash flows.

DESC has four decommissioned manufactured gas plant sites in South Carolina that are in various states of investigation, remediation and monitoring under work plans approved by, or under review by, the SCDHEC or the EPA. DESC anticipates that activities at these sites will continue through 2025 at an estimated cost of $26 million. DESC expects to recover costs arising from the remediation work at all four sites through rate recovery mechanisms and as of March 31, 2022, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $38 million and are included in regulatory assets.

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. DESC currently has inactive and existing CCR ponds and CCR landfills subject to the final rule at 2different facilities. This rule created a legal obligation for DESC 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 for EPA- 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 flexibility in implementing their programs. In July 2018, the EPA promulgated the first phase of changes to 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. Until this matter is resolved and all phases of the CCR rule are promulgated, DESC is unable to precisely estimate potential incremental impacts or costs related to existing coal ash sites in connection with future implementation of the final CCR rule. While such amounts may be material to DESC’s results of operations, financial condition and/or cash flows, the existing regulatory framework in South Carolina provides rate recovery mechanisms that could substantially mitigate any such impacts.

Claims and Litigation

The following describes certain legal proceedings involving DESC relating primarily to events occurring before closing of the SCANA Combination. In addition, certain legal matters which have been resolved are discussed in Note 12 to the Consolidated Financial Statements in DESC’s Annual Report on Form 10-K for the year ended December 31, 2021. 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, DESC 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 DESC is able to reasonably estimate a probable loss, the Consolidated Balance Sheets at March 31, 2022 and December 31, 2021 include reserves of $194 million and $211 million, respectively, and insurance receivables of $85 million at both dates, included within other receivables. These balances at March 31, 2022 and December 31, 2021 include $70 million and $85 million, respectively, of offsetting reserves and insurance receivables related to personal injury or wrongful death cases which are currently pending. During the three months ended March 31, 2022, no charges were included in DESC’s Consolidated Statements of Comprehensive Income. During the three months ended March 31, 2021, DESC’s Consolidated Statements of Comprehensive Income includes charges of $60 million ($45 million after-tax), included within impairment of assets and other charges.

SCANA Shareholder Litigation

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 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 September 2019, the U.S. District Court for the District of South Carolina granted the plaintiffs’ motion to consolidate the Metzler Lawsuit with another lawsuit regarding the SCANA Merger Agreement to which DESC is not a party. 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 initial lawsuits 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 to settle this case, along with a related case to which DESC was not a party, subject to court approval, with no financial impact to DESC.

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 March 2022, the deadline to file an appeal to the Supreme Court of the United States expired.

In September 2018, a case was filed in the State Court of Common Pleas in Fairfield County, South Carolina by Fluor Enterprises, Inc. and Fluor Daniel Maintenance Services, Inc. against DESC and Santee Cooper. The plaintiffs make claims for indemnification, breach of contract and promissory estoppel arising from, among other things, the defendants' alleged failure and refusal to defend and indemnify the Fluor defendants in the aforementioned case. As a result of the ruling in favor of the defendants in the aforementioned case, any potential loss by DESC would be limited to an inconsequential amount.

Governmental Proceedings and Investigations

In June 2018, DESC received a notice of proposed assessment of approximately $410 million, excluding interest, from the SCDOR following its audit of DESC’s sales and use tax returns for the periods September 1, 2008 through December 31, 2017. The proposed assessment, which includes 100% of the NND Project, is based on the SCDOR’s position that DESC’s sales and use tax exemption for the NND Project does not apply because the facility will not become operational. In December 2020, the parties reached an agreement in principle in the amount of $165 million to resolve this matter. In June 2021, the parties executed a settlement agreement which allows DESC to fund the settlement amount through a combination of cash, shares of Dominion Energy common stock or real estate with an initial payment of at least $43 million in shares of Dominion Energy common stock. In August 2021, Dominion Energy issued 0.6 million shares of its common stock to satisfy DESC’s obligation for the initial payment under the settlement agreement. In May 2022, Dominion Energy issued an additional 0.9 million shares of its common stock to partially satisfy DESC’s remaining obligation under the settlement agreement.

11. OPERATING SEGMENTS

The Corporate and Other segment includes specific items attributable to its operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources.

In the three months ended March 31, 2022 and 2021, DESC reported an immaterial amount of specific items in the Corporate and Other segment.


(millions)	External Revenue		Comprehensive Income (Loss) Available (Attributable) to Common Shareholder
Three Months Ended March 31, 2022
Dominion Energy South Carolina	$	849	$	104
Corporate and Other		—		(1	)
Consolidated total	$	849	$	103

Three Months Ended March 31, 2021
Dominion Energy South Carolina	$	744	$	97
Corporate and Other		—		(46	)
Consolidated total	$	744	$	51

12. AFFILIATED AND RELATED PARTY TRANSACTIONS

DES, on behalf of itself and its parent company, provide the following services to DESC, which are rendered at direct or allocated cost: information systems, telecommunications, customer support, marketing and sales, human resources, corporate compliance, purchasing, financial, risk management, public affairs, legal, investor relations, gas supply and capacity management, strategic planning, general administrative and retirement benefits. In addition, DES processes and pays invoices for DESC and is reimbursed. Costs for these services include amounts capitalized. Amounts expensed are primarily recorded in other operations and maintenance - affiliated suppliers and other income, net in the Consolidated Statements of Comprehensive Income.

DESC transacts with affiliates for certain quantities of electricity in the ordinary course of business. DESC also enters into certain commodity derivative contracts with affiliates. DESC uses these contracts, which are principally comprised of forward commodity purchases, to manage commodity price risks associated with purchases of electricity. See Note 7 for additional information.


	Three Months Ended March 31,
(millions)	2022		2021
Direct and allocated costs from DES(1)	$	57	$	54
Operating Revenues - Electric from sales to affiliate		1		1
Operating Expenses - Other taxes from affiliate		3		3
Purchases of electricity from solar affiliates		2		2


(1)			Includes capitalized expenditures of $10 million and $2 million for the three months ended March 31, 2022 and 2021, respectively.


(millions)	March 31, 2022		December 31, 2021
Payable to DES	$	23	$	29
Receivable from Public Service Company of North Carolina, Incorporated		5		60
Payable to solar affiliates		1		1
Receivable from nuclear affiliates		1		1
Payable to Dominion Energy		2		1
Derivative assets with affiliates(1)		45		28

(1) Includes amounts recorded in other current assets of $11 million and $4 million as of March 31, 2022 and December 31, 2021, respectively, and amounts recorded in other deferred debits and other assets of $34 million and $24 million as of March 31, 2022 and December 31, 2021, respectively.

Borrowings from an affiliate are described in Note 5.

13. OTHER INCOME, NET

Components of other income, net are as follows:


	Three Months Ended March 31,
(millions)	2022		2021
Revenues from contracts with customers	$	—	$	—
Other income		2		3
Other expense		1		2
Allowance for equity funds used during construction		1		1
Other income, net	$	4	$	6

Non-service cost components of pension and other postretirement benefits are included in other income.

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote. Report data on a year-to-date basis.
Line No.	Item (a)	Unrealized Gains and Losses on Available-For-Sale Securities (b)	Minimum Pension Liability Adjustment (net amount) (c)	Foreign Currency Hedges (d)	Other Adjustments (e)	Other Cash Flow Hedges Interest Rate Swaps (f)	Other Cash Flow Hedges [Specify] (g)	Totals for each category of items recorded in Account 219 (h)	Net Income (Carried Forward from Page 116, Line 78) (i)	Total Comprehensive Income (j)
1	Balance of Account 219 at Beginning of Preceding Year				(a) 1,652,649			(e) 1,652,649
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income				(b) 336,413			336,413
3	Preceding Quarter/Year to Date Changes in Fair Value
4	Total (lines 2 and 3)				336,413			336,413	50,385,337	50,048,924
5	Balance of Account 219 at End of Preceding Quarter/Year				1,989,062			1,989,062
6	Balance of Account 219 at Beginning of Current Year				582,602			582,602
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income				(c) 3,188			3,188
8	Current Quarter/Year to Date Changes in Fair Value
9	Total (lines 7 and 8)				3,188			3,188	102,631,963	102,635,151
10	Balance of Account 219 at End of Current Quarter/Year				(d) 579,414			579,414

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: AccumulatedOtherComprehensiveIncomeLossOtherAdjustmentsToComprehensiveIncomeLossBalance

Lines 1-5 present information for the period 1/1/21 - 3/31/2021.

Lines 6-10 present information for the period 1/1/22 - 3/31/2022.

(b) Concept: AccumulatedOtherComprehensiveIncomeLossOtherAdjustmentsToComprehensiveIncomeLossReclassificationsToNetIncomeLoss

Reflects reclassification adjustments of amounts recognized in AOCI (net losses and prior service costs, as applicable) pursuant to accounting requirements for deferred employee

benefit plan costs. These adjustments result from the amortization of those amounts as components of net periodic benefit costs in 2021.

(c) Concept: AccumulatedOtherComprehensiveIncomeLossOtherAdjustmentsToComprehensiveIncomeLossReclassificationsToNetIncomeLoss

Reflects reclassification adjustments of amounts recognized in AOCI (net losses and prior service costs, as applicable) pursuant to accounting requirements for deferred employee benefit plan costs. These adjustments result from the amortization of those amounts as components of net periodic benefit costs in 2022.

(d) Concept: AccumulatedOtherComprehensiveIncomeLossOtherAdjustmentsToComprehensiveIncomeLossBalance

Other Comprehensive Income related to deferred employee benefit plan costs.

(e) Concept: AccumulatedOtherComprehensiveIncomeLoss

Lines 1-5 present information for the period 1/1/21 - 3/31/2021.

Lines 6-10 present information for the period 1/1/22 - 3/31/2022.

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in column (h) common function.
Line No.	Classification (a)	Total Company For the Current Year/Quarter Ended (b)	Electric (c)	Gas (d)	Other (Specify) (e)	Other (Specify) (f)	Other (Specify) (g)	Common (h)
1	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlantInServiceAbstract In Service
3	UtilityPlantInServiceClassified Plant in Service (Classified)	12,873,814,188	11,109,133,184	1,415,694,322				348,986,682
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	28,781,586	15,126,666	784,189				12,870,731
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified	625,078,292	386,658,096	186,451,311				51,968,885
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	13,527,674,066	11,510,917,946	1,602,929,822				413,826,298
9	UtilityPlantLeasedToOthers Leased to Others
10	UtilityPlantHeldForFutureUse Held for Future Use	9,179,850	9,179,850
11	ConstructionWorkInProgress Construction Work in Progress	458,391,247	410,964,967	39,622,466				7,803,814
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments	31,597,076	31,360,826	236,250
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	14,026,842,239	11,962,423,589	1,642,788,538				421,630,112
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	5,493,568,619	4,768,803,459	536,625,638				188,139,522
15	UtilityPlantNet Net Utility Plant (13 less 14)	8,533,273,620	7,193,620,130	1,106,162,900				233,490,590
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	5,274,691,862	4,680,602,431	522,311,057				71,778,374
19	AmortizationAndDepletionOfProducingNaturalGasLandAndLandRightsutilityPlantInService Amortization and Depletion of Producing Natural Gas Land and Land Rights
20	AmortizationOfUndergroundStorageLandAndLandRightsutilityPlantInService Amortization of Underground Storage Land and Land Rights
21	AmortizationOfOtherUtilityPlantUtilityPlantInService Amortization of Other Utility Plant	207,572,114	77,043,005	14,167,961				116,361,148
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	5,482,263,976	4,757,645,436	536,479,018				188,139,522
23	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthersAbstract Leased to Others
24	DepreciationUtilityPlantLeasedToOthers Depreciation
25	AmortizationAndDepletionUtilityPlantLeasedToOthers Amortization and Depletion
26	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthers Total Leased to Others (24 & 25)
27	DepreciationAndAmortizationUtilityPlantHeldForFutureUseAbstract Held for Future Use
28	DepreciationUtilityPlantHeldForFutureUse Depreciation
29	AmortizationUtilityPlantHeldForFutureUse Amortization
30	DepreciationAndAmortizationUtilityPlantHeldForFutureUse Total Held for Future Use (28 & 29)
31	AbandonmentOfLeases Abandonment of Leases (Natural Gas)
32	AmortizationOfPlantAcquisitionAdjustment Amortization of Plant Acquisition Adjustment	11,304,643	11,158,023	146,620
33	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Total Accum Prov (equals 14) (22,26,30,31,32)	5,493,568,619	4,768,803,459	536,625,638				188,139,522

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

Electric Plant In Service and Accum Provision For Depr by Function
Report below the original cost of plant in service by function. In addition to Account 101, include Account 102, and Account 106. Report in column (b) the original cost of plant in service and in column(c) the accumulated provision for depreciation and amortization by function.
Line No.	Item (a)	Plant in Service Balance at End of Quarter (b)	Accumulated Depreciation And Amortization Balance at End of Quarter (c)
1	Intangible Plant	99,241,406	77,043,005
2	Steam Production Plant	2,144,993,321	1,088,404,494
3	Nuclear Production Plant	1,456,985,708	688,547,939
4	Hydraulic Production - Conventional	443,920,954	307,269,519
5	Hydraulic Production - Pumped Storage	234,205,181	81,884,843
6	Other Production	986,125,815	645,869,255
7	Transmission	2,057,519,941	525,434,751
8	Distribution	3,840,946,811	1,258,692,115
9	Regional Transmission and Market Operation
10	General	246,978,809	84,499,515
11	TOTAL (Total of lines 1 through 10)	11,510,917,946	4,757,645,436

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

Transmission Service and Generation Interconnection Study Costs
Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and generator interconnection studies. List each study separately. In column (a) provide the name of the study. In column (b) report the cost incurred to perform the study at the end of period. In column (c) report the account charged with the cost of the study. In column (d) report the amounts received for reimbursement of the study costs at end of period. In column (e) report the account credited with the reimbursement received for performing the study.
Line No.	DescriptionOfStudyPerformed Description (a)	StudyCostsIncurred Costs Incurred During Period (b)	StudyCostsAccountCharged Account Charged (c)	StudyCostsReimbursements Reimbursements Received During the Period (d)	StudyCostsAccountReimbursed Account Credited With Reimbursement (e)
1	Transmission Studies
2	(a) See Footnote			0.00
20	Total	0		0
21	Generation Studies
22	20220324001 System Impact Study			90,000	253
23	20220128001 System Impact Study			10,000	253
24	20220118001 System Impact Study			20,000	253
25	20220225001 System Impact Study	723	408.1/561.7/926	12,000	253
26	20171018009 Feasibility Study	2,402	408.1/561.7/926
27	20211206001 System Impact Study			85,000	253
28	20220202001 System Impact Study			10,000	253
29	20220112001 System Impact Study			85,000	253
30	20211221001 System Impact Study			85,000	253
31	20220228001 System Impact Study			10,000	253
32	20220323001 System Impact Study			12,000	253
33	20220316001 System Impact Study			20,000	253
34	20211005001 System Impact Study	2,233	408.1/561.7/926
35	20171018011 Feasibility Study	3,048	408.1/561.7/926
39	Total	8,406		(b) 439,000
40	Grand Total	8,406		439,000

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: DescriptionOfStudyPerformed

No Transmission Studies for reporting period.

(b) Concept: StudyCostsReimbursements

Column (d) represents deposits received to perform study.

An analysis is performed of actual billable costs and if necessary an additional billing is rendered to the study purchaser. Any reimbursements received are transferred from account 253 - Other Deferred Credits and credited to expense as the actual charges are incurred. If reimbursements exceed billable costs, the Company refunds the excess reimbursement, with interest if applicable, to the study purchaser.

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

OTHER REGULATORY ASSETS (Account 182.3)
Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. For Regulatory Assets being amortized, show period of amortization.
				CREDITS
Line No.	DescriptionAndPurposeOfOtherRegulatoryAssets Description and Purpose of Other Regulatory Assets (a)	OtherRegulatoryAssets Balance at Beginning of Current Quarter/Year (b)	IncreaseDecreaseInOtherRegulatoryAssets Debits (c)	OtherRegulatoryAssetsWrittenOffAccountCharged Written off During Quarter/Year Account Charged (d)	OtherRegulatoryAssetsWrittenOffRecovered Written off During the Period Amount (e)	OtherRegulatoryAssets Balance at end of Current Quarter/Year (f)
1	Accumulated Deferred Income Taxes	30,180,577	343,836	282	138,386	30,386,027
2	(a) Gas Water Heater Rebate Program (12/2016-11/2026)	6,751,184	399,400	912/143	752,804	6,397,780
3	(b) MGP Environmental Remediation	31,328,924	7,300,041	735	357,207	38,271,758
4	(c) Deferred ARO Accretion & Depreciation Costs	318,297,957	9,255,597	108/119	271,184	327,282,370
5	(d) Interest Rate Derivatives	290,025,614	4,392,051	427/244	9,677,523	284,740,142
6	Deferred Employee Benefit Plan Costs-Gas (ASC 715)	9,708,434	20,077	(ac) see footnote	48,163	9,680,348
7	Deferred Employee Benefit Plan Costs-Elec (ASC 715)	54,576,467	108,860	(ad) see footnote	264,526	54,420,801
8	(e) Deferred VCS Coolant Reconfig Costs (7/2010-7/2042)	3,771,071		530	45,954	3,725,117
9	(f) Deferred Capacity Charges (9/2021-8/2024)	1,897,343		555	177,876	1,719,467
10	(g) Electric Demand Side Management	67,963,267	10,360,826	254/908	12,301,716	66,022,377
11	Gas Demand Side Management		102,447	(ae) see footnote	317	102,130
12	(h) Def Pollution Cntrl Costs-Williams (7/2010-2/2045)	6,530,309		555	70,665	6,459,644
13	(i) Economic Development Grants (1/2012-5/2032)	7,902,421		921	243,353	7,659,068
14	(j) Major Maintenance Accrual and Interest	11,900,973	50,295	(af) see footnote	2,325,704	9,625,564
15	(k) Deferred Pension Cost-Gas (11/2013-1/2027)	5,219,073	85,792	926	343,169	4,961,696
16	(l) Deferred Pension Cost-Electric (1/2013-12/2042)	44,762,424	165,653	926	662,611	44,265,466
17	(m) Deferred Pollution Control Costs - Wateree (1/2013-9/2040)	19,846,256		407.3	265,485	19,580,771
18	(n) Research and Development Grant (1/2013-12/2047)	2,600,000		930.2	25,000	2,575,000
19	(o) Amount Undercollected-Gas Cost Adjustment	6,479,347	31,564,806	(ag) see footnote	38,044,153
20	(p) Amount Undercollected-Elec Fuel Adjustment Clause	115,620,396	70,210,876	(ah) see footnote	71,433,442	114,397,830
21	(q) Gas WNA Cap - Winter 2019/2020 and Winter 2020/2021 (11/2020-10/2022)	768,869		480/481	230,661	538,208
22	(r) Fukushima Compliance Costs (9/2021-8/2031)	4,350,000		524	112,500	4,237,500
23	(s) Cyber Compliance Costs (9/2021-12/2031)	8,422,861		407.3/524	212,155	8,210,706
24	(t) CIPv5 Compliance Costs (9/2021-6/2032)	24,510,784		407.3/566	586,613	23,924,171
25	(u) Gas Pipeline Integrity Costs	9,680,296	793,251	887	796,145	9,677,402
26	(v) Net Operating Loss Excess Deferred Tax Assets	127,428,794		190/410.2	7,597,853	119,830,941
27	(w) Deferred Transmission Operating Costs (9/2021-10/2063)	79,238,907		407.3	475,173	78,763,734
28	(x) Deferred Storm Damage Costs	42,288,557	1,616,126	571/593	1,097,492	42,807,191
29	(y) Undercollected Distributed Energy Resources and Net Metering Costs	6,928,378	7,853,997	(ai) see footnote	8,152,641	6,629,734
30	(z) Deferred AMI Operating Costs (9/2021-5/2078)	4,802,004		407.3	21,289	4,780,715
31	Deferred Costs Pursuant to SC Act 62	1,155,712	503,168			1,658,880
32	(aa) 2020 Rate Case Incremental Exp (9/2021-7/2037)	2,796,792		928	45,012	2,751,780
33	Canady's Ash Pond Closure Costs	3,631,786			521,948	3,109,838
34	Wholesale Fuel Undercollection	4,244,450	2,315,952	419/447	2,293	6,558,109
35	(ab) Amt. Overcollected - Vegetation Mgmt Accrual		5,759,878	254	2,324,723	3,435,155
44	TOTAL	1,355,610,227	153,202,929		159,625,736	1,349,187,420

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 89-245-G

SCPSC Docket No. 2008-155-G

(b) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2005-113-G

(c) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2003-84-E

(d) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Activity associated with this item includes the deferral of losses or gains on certain interest rate derivatives and the amortization of settlement amounts over the life of the related debt issuances.

(e) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2009-489-E

(f) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2008-230-E

SCPSC Docket No. 2020-125-E

(g) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Amortization of deferred balance is a function of customer usage per a Rate Rider mechanism approved by the SCPSC in Docket Nos. 2016-40-E, 2018-42-E, 2019-57-E, 2020-41-E, 2021-34-E and 2022-52-E.

(h) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2009-489-E

(i) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2009-497-E

SCPSC Docket No. 2011-264-E

SCPSC Docket No. 2012-246-E

(j) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2009-489-E

SCPSC Docket No. 2012-218-E

SCPSC Docket No. 2017-210-E

SCPSC Docket No. 2019-159-E

SCPSC Docket No. 2020-125-E

(k) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2009-35-G

SCPSC Docket No. 2013-6-G

(l) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2009-489-E

SCPSC Docket No. 2012-218-E

(m) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2008-393-E

SCPSC Docket No. 2012-218-E

(n) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2011-513-E

SCPSC Docket No. 2012-218-E

(o) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2021-5-G

(p) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2021-2-E

(q) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2020-6-G

SCPSC Docket No. 2021-6-G

(r) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2012-277-E

SCPSC Docket No. 2020-125-E

(s) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2015-372-E

SCPSC Docket No. 2020-125-E

(t) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2014-416-E

SCPSC Docket No. 2020-125-E

(u) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2018-6-G

In the docket referenced above, the SCPSC authorized amortization in a levelized annual amount of $3,182,300 beginning in November 2018.

(v) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2017-381-A

(w) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2017-370-E

SCPSC Docket No. 2020-125-E

(x) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2012-218-E

SCPSC Docket No. 2020-125-E

Pursuant to the comprehensive settlement agreement approved by the SCPSC in DESC's retail electric base rate case (Docket No. 2020-125-E), annual amortization of $4,389,969 began September 2021. The SCPSC's order also authorized additional incremental storm cost deferrals to this account. Therefore, the actual period over which the balance will be amortized will change as additional qualifying deferrals are incurred and recognized.

(y) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2018-2-E

SCPSC Docket No. 2019-2-E

SCPSC Docket No. 2020-2-E

SCPSC Docket No. 2021-2-E

(z) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2019-241-EG

SCPSC Docket No. 2020-125-E

(aa) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

SCPSC Docket No. 2020-125-E

(ab) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Pursuant to the Comprehensive Settlement Agreement approved by the SCPSC in DESC's Retail Electric Base Rate Case (Docket No. 2020-125-E), the SCPSC approved a Vegetation Management accrual under which DESC is allowed to recover $27,679,292 annually. Amounts under/(over) collected are deferred as a regulatory asset or regulatory liability, as applicable.

(ac) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

107 / 143 / 182.2 / 182.3 / 183 / 186 / 253 / 926

(ad) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

107 / 143 / 182.2 / 182.3 / 183 / 186 / 253 / 926

(ae) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

107 / 143 / 182.2 / 183 / 184 / 186 / 253 / 926

(af) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

513 / 553 / 555

(ag) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

431 / 480 / 481 / 173

(ah) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

173 / 254 / 449

(ai) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

232 / 407.3 / 440 / 442

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

OTHER REGULATORY LIABILITIES (Account 254)
Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. For Regulatory Liabilities being amortized, show period of amortization.
			DEBITS
Line No.	Description and Purpose of Other Regulatory Liabilities (a)	Balance at Beginning of Current Quarter/Year (b)	Account Credited (c)	Amount (d)	Credits (e)	Balance at End of Current Quarter/Year (f)
1	Accumulated Deferred Income Tax Credits	5,148,451				5,148,451
2	(a) Nuclear Refueling Accrual		524/528	1,455,940	4,021,857	2,565,917
3	NOX Emission Allowance Proceeds	1,042				1,042
4	(b) Interest Rate Derivatives (3/2009-6/2043)	69,155,346	427	1,172,419	599,627	68,582,554
5	(c) Solar PPAs MTM Gains	148,135,913	175	148,135,913	225,299,453	225,299,453
6	(d) Demand Side Management Carrying Costs	814,642	182.3	268,836	123,162	668,968
7	SO2 Emission Allowance Proceeds	1,183				1,183
8	(e) Overcollected Electric Pension Expense	1,742,064			2,020,575	3,762,639
9	(f) Monetization-Toshiba Settlement (2/2019-1/2039)	897,672,003	(v) see footnote	78,126,705		819,545,298
10	(g) Excess Deferred Tax Liabilities - Electric	867,018,468	(w) see footnote	16,651,749	6,318,412	856,685,131
11	(h) Excess Deferred Tax Liabilities - Gas	77,419,135	410	382,525		77,036,610
12	(i) Amortization Excess Deferred Tax Liabilities - Gas (11/2021-10/2022)	30,262	481	8,974	168	21,456
13	(j) Customer Refunds Merger Approval Order - Electric	537,808,000	(x) see footnote	32,491,000		505,317,000
14	(k) Customer Refunds Merger Approval Order - Gas (11/2021-10/2022)	3,349	(y) see footnote	998		2,351
15	(l) WEC Reimbursement Proceeds	4,557,263	182.3	4,585,758	28,495
16	(m) Deferred Gain on Sale of Turbine Generator and Associated Equipment (9/2021-8/2023)	812,500	407.4	121,875		690,625
17	(n) Revenue Subject to Refund - Tax Reform Electric Residual Balance (9/2021-9/2024)	1,311,014	407.4	121,475		1,189,539
18	(o) Amortized Excess Deferred Tax Liabilities from GENCO (9/2021-6/2026)	6,011,244	555	338,091		5,673,153
19	Renewable Energy Credits	3,268,602	174	202,626		3,065,976
20	(p) Decommissioning Asset Ret. Obligation	22,888,469	182.3	20,327,833		2,560,636
21	(q) Amt. Overcollected - Gas Cost Adjustment		(z) see footnote	64,762,874	69,051,444	4,288,570
22	(r) Environmental Remediation Costs	133,956	592/573	12,954	60,000	181,002
23	(s) Amt. Overcollected - Vegetation Mgmt Accrual	27,743	182.3	2,324,722	2,296,979
24	(t) Unprotected Plant EDIT Decrement Rider	89,898,991	411	5,981,061		83,917,930
25	(u) Hardeeville Retirement				1,144,145	1,144,145
41	TOTAL	2,733,859,640		377,474,328	310,964,317	2,667,349,629

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

SCPSC Docket No. 2012-218-E

SCPSC Docket No. 2020-172-E

SCPSC Docket No. 2020-125-E

(b) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Activity is associated with the amortization of settlement amounts over the life of the related debt issuances.

(c) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Represents the mark to market gains associated with embedded derivatives of Solar PPAs that contain minimum production guarantees and not probable of physical settlement.

(d) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

SCPSC Docket No. 2013-50-E

SCPSC Docket No. 2013-208-E

SCPSC Docket No. 2014-44-E

SCPSC Docket No. 2015-45-E

SCPSC Docket No. 2016-40-E

SCPSC Docket No. 2017-35-E

SCPSC Docket No. 2018-42-E

SCPSC Docket No. 2019-57-E

SCPSC Docket No. 2020-41-E

SCPSC Docket No. 2021-34-E

SCPSC Docket No. 2022-52-E

(e) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

SCPSC Docket No. 2012-218-E

SCPSC Docket No. 2021-46-E

In the dockets referenced above, the SCPSC authorized the recovery of current pension expense related to retail electric operations through a rate rider mechanism. Any differences between actual pension expense and amounts recovered through the rider are deferred as a regulatory asset (under-recovered) or regulatory liability (over-recovered) as appropriate.

(f) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Represents net proceeds received under or arising from the monetization of the Settlement Agreement dated as of July 27, 2017 with Toshiba Corporation. By Order No. 2018-804 issued in Docket No. 2017-370-E, the SCPSC ordered $1.032 billion to be credited to customers over twenty years beginning in February 2019.

In March 2022 per SCPSC Docket No. 2022-2-E, DESC applied approximately $61.3 million of this regulatory liability as a reduction to its retail electric undercollected base fuel cost balance.

(g) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The FERC jurisdictional transmission portion of these amounts was included in a compliance filing for Order No. 864 in FERC Docket No. ER20-1836. This matter is pending.

SCPSC Docket No. 2017-381-A

Amounts related to plant-related temporary differences are being amortized using the average rate assumption method (ARAM). Under ARAM, the excess deferred tax liabilities will reverse at the weighted average rate at which the deferred taxes were built over the remaining book life of the property to which those deferred taxes relate. These reversal periods average fifty years.

For non-plant related excess deferred tax liabilities, the balances will reverse over 5 years, or in the case of Nuclear Project-related excess deferred tax liabilities, twenty years.

(h) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amounts related to plant-related temporary differences are being amortized using the average rate assumption method (ARAM). Under ARAM, the excess deferred tax liabilities will reverse at the weighted average rate at which the deferred taxes were built over the remaining book life of the property to which those deferred taxes relate. These reversal periods average fifty years.

For non-plant related excess deferred tax liabilities, the balances will reverse over 5 years.

(i) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

SCPSC Docket No. 2021-6-G

Pursuant to SCPSC Docket No. 2019-6-G, this amount was amortized through October 2020. Pursuant to SCPSC Docket No. 2021-6-G, amortization of the remaining balance will commence in November 2021 for approximately one year.

(j) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

SCPSC Docket No. 2017-370-E

(k) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

SCPSC Docket No. 2017-370-E

SCPSC Docket No. 2021-6-G

By Order No. 2018-804, issued in Docket No. 2017-370-E, the SCPSC ordered the refund of $2.45 million of previous collections from gas customers. The refund was to be provided over three years (2019-2021) in annual tranches in the first quarter of each year. The third and final refund was provided in the first quarter of 2021. Since the refund was a volumetric calculation, a residual balance remains to be refunded. In SCPSC Docket No. 2021-6-G, the SCPSC authorized amortization over approximately one year beginning in November 2021.

(l) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

DESC received an initial payment of $2,930,425 in April 2019 and a subsequent payment of $1,472,581 in July 2019 representing its 55% share of proceeds received from W Wind Down Company LLC (Company established to administer Westinghouse Electric Company LLC's bankruptcy obligations) per the terms of the Interim Assessment Agreement and with the approval of the Bankruptcy Court. This amount, plus accrued carrying cost of $182,752, has been recorded as a regulatory liability.

In March 2022 per SCPSC 2022-2-E, DESC applied these proceeds as a reduction to its retail electric undercollected base fuel cost balance.

(m) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

SCPSC Docket No. 2020-125-E

Deferred gain related to sale of an electric power generator, a 13.8/115kV generator step-up transformer and associated equipment to Kapstone Charleston Kraft, LLC. The FERC authorized the clearing of the gain from Account 102 - Electric Plant Purchased or Sold to Account 254 - Other Regulatory Liabilities via a letter order dated July 2, 2019 issued in Docket No. AC19-145-000.

(n) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

SCPSC Docket No. 2020-125-E

By Order No. 2018-804 issued in Docket No. 2017-370-E, the SCPSC ordered the refund of amounts collected from customers and reserved for refund related to the change in the corporate federal tax rate. The Company provided the refund in accordance with the order in February 2019. However, since the refund was a volumetric calculation, a residual balance is being refunded pursuant to the SCPSC Docket above.

(o) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

SCPSC Docket No. 2020-125-E

By order dated April 28, 2020, the FERC authorized modifications to South Carolina Generating Company, Inc.'s (GENCO) formula rate to provide for the pass through of GENCO's amortized Excess Deferred Tax Liabilities to DESC.

(p) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

SCPSC Docket No. 2003-84-E

(q) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

SCPSC Docket No. 2021-5-G

Per SCPSC Docket No. 2005-5-G, commodity and demand components of purchased gas cost are recovered separately. Balances for these components as of March 31, 2022 are as follows:


Commodity	$	18,386,864
Demand	$	(22,675,434)
Total	$	(4,288,570)

(r) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

SCPSC Docket No. 2012-218-E

(s) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Pursuant to the Comprehensive Settlement Agreement approved by the SCPSC in DESC's Retail Electric Base Rate Case (Docket No. 2020-125-E), the SCPSC approved a Vegetation Management accrual under which DESC is allowed to recover $27,679,292 annually. Amounts under/(over) collected are deferred as a regulatory asset or regulatory liability, as applicable.

(t) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The FERC jurisdictional transmission portion of these amounts was included in a compliance filing for Order No. 864 in FERC Docket No. ER20-1836. This matter is pending.

SCPSC Docket No. 2020-125-E

In connection with the comprehensive settlement agreement approved by the SCPSC (Docket No. 2020-125-E) in DESC's retail electric base rate case, unprotected plant-related excess deferred tax liabilities will be returned to retail customers through a volumetric decrement rate rider which began in September 2021. Amortization will be matched with the rider decrements, with certain portions of the amortization affecting the Open Access Transmission Tariff (OATT) formula rate.

(u) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

In March 2022 in SCPSC Docket No. 2022-107-E, DESC petitioned for an accounting order seeking, among other things, authorization to reclassify its net credit balance carrying value related to the retirement of its Hardeeville simple cycle combustion turbine to a regulatory liability account. This matter is pending.

(v) Concept: OtherRegulatoryLiabilitiesDescriptionOfCreditedAccountNumberForDebitAdjustment

131 / 182.3 / 440 / 442 / 444 / 445

(w) Concept: OtherRegulatoryLiabilitiesDescriptionOfCreditedAccountNumberForDebitAdjustment

190 / 254 / 282 / 283

(x) Concept: OtherRegulatoryLiabilitiesDescriptionOfCreditedAccountNumberForDebitAdjustment

440 / 442 / 444 / 445

(y) Concept: OtherRegulatoryLiabilitiesDescriptionOfCreditedAccountNumberForDebitAdjustment

142 / 480/ / 481

(z) Concept: OtherRegulatoryLiabilitiesDescriptionOfCreditedAccountNumberForDebitAdjustment

173/ 431 / 480 / 481

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

Electric Operating Revenues
The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH related to unbilled revenues need not be reported separately as required in the annual version of these pages. Report below operating revenues for each prescribed account, and manufactured gas revenues in total. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added for billing purposes, one customer should be counted for each group of meters added. The average number of customers means the average of twelve figures at the close of each month. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification in a footnote.) See page 108, Important Changes During Period, for important new territory added and important rate increase or decreases. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts. Include unmetered sales. Provide details of such Sales in a footnote.
Line No.	Title of Account (a)	Operating Revenues Year to Date Quarterly/Annual (b)	Operating Revenues Previous year (no Quarterly) (c)	MEGAWATT HOURS SOLD Year to Date Quarterly/Annual (d)	MEGAWATT HOURS SOLD Amount Previous year (no Quarterly) (e)	AVG.NO. CUSTOMERS PER MONTH Current Year (no Quarterly) (f)	AVG.NO. CUSTOMERS PER MONTH Previous Year (no Quarterly) (g)
1	SalesOfElectricityHeadingAbstract Sales of Electricity
2	ResidentialSalesAbstract (440) Residential Sales	299,932,281		1,968,482
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)	200,957,364		1,598,627
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)	108,613,103		1,308,778	0
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting	4,998,286		22,784
7	OtherSalesToPublicAuthoritiesAbstract (445) Other Sales to Public Authorities	11,713,592		112,229
8	SalesToRailroadsAndRailwaysAbstract (446) Sales to Railroads and Railways
9	InterdepartmentalSalesAbstract (448) Interdepartmental Sales
10	SalesToUltimateConsumersAbstract TOTAL Sales to Ultimate Consumers	(a) 626,214,626	0	(d) 5,010,900	0
11	SalesForResaleAbstract (447) Sales for Resale	12,252,261		205,860
12	SalesOfElectricityAbstract TOTAL Sales of Electricity	638,466,887		5,216,760
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds	638,466,887		5,216,760
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts	1,898,057
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	(b) 926,524	0
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power	107,804
19	RentFromElectricProperty (454) Rent from Electric Property	8,243,611
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	(c) 2,503,779	0
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	3,547,766
23	RegionalTransmissionServiceRevenues (457.1) Regional Control Service Revenues
24	MiscellaneousRevenue (457.2) Miscellaneous Revenues
25	OtherMiscellaneousOperatingRevenues Other Miscellaneous Operating Revenues
26	OtherOperatingRevenues TOTAL Other Operating Revenues	17,227,541
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	655,694,428
Line12, column (b) includes $ of unbilled revenues.
Line12, column (d) includes MWH relating to unbilled revenues

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: SalesToUltimateConsumers

Includes the following amounts under/(over)-collected pursuant to the respondent's fuel adjustment clause:


Residential	$	28,069,759
Commercial	20,643,661
Industrial	14,457,530
Street Lighting	82,148
Other Public Authorities	1,459,289
	$	64,712,387

Includes Unmetered Sales Revenue as follows:


Residential	$	4,651,368
Commercial	7,073,139
Industrial	166,714
Street Lighting	3,531,944
Other Public Authorities	23,677
	$	15,446,842

(b) Concept: MiscellaneousServiceRevenues

Includes $728,250 of transmission maintenance fee revenue.

Includes $267,534 of returned check fees.

Also includes debit activity related to Lighting contract cancellation fee reversals.

(c) Concept: OtherElectricRevenue

Includes $899,744 associated with municipal Franchise Fees pursuant to SCPSC Docket No. 2008-2-E.

Includes $1,443,810 of timber sales revenue.

(d) Concept: MegawattHoursSoldSalesToUltimateConsumers

Includes Unmetered MWH Sales as follows:


Residential			18,955
Commercial			34,410
Industrial			1,174
Street Lighting			15,822
Other Public Authorities			175
			70,536

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

REGIONAL TRANSMISSION SERVICE REVENUES (Account 457.1)
The respondent shall report below the revenue collected for each service (i.e., control area administration, market administration, etc.) performed pursuant to a Commission approved tariff. All amounts separately billed must be detailed below.
Line No.	Description of Service (a)	Balance at End of Quarter 1 (b)	Balance at End of Quarter 2 (c)	Balance at End of Quarter 3 (d)	Balance at End of Year (e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46	TOTAL

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

ELECTRIC PRODUCTION, OTHER POWER SUPPLY EXPENSES, TRANSMISSION AND DISTRIBUTION EXPENSES

Report Electric production, other power supply expenses, transmission, regional market, and distribution expenses through the reporting period.
Line No.	Account (a)	Year to Date Quarter (b)
1	PowerProductionExpensesAbstract 1. POWER PRODUCTION AND OTHER SUPPLY EXPENSES
2	SteamPowerGenerationOperationsExpense Steam Power Generation - Operation (500-509)	46,203,907
3	SteamPowerGenerationMaintenanceExpense Steam Power Generation – Maintenance (510-515)	7,879,765
4	PowerProductionExpensesSteamPower Total Power Production Expenses - Steam Power	54,083,672
5	NuclearPowerGenerationOperationsExpense Nuclear Power Generation – Operation (517-525)	25,737,832
6	NuclearPowerGenerationMaintenanceExpense Nuclear Power Generation – Maintenance (528-532)	9,925,592
7	PowerProductionExpensesNuclearPower Total Power Production Expenses - Nuclear Power	35,663,424
8	HydraulicPowerGenerationOperationsExpense Hydraulic Power Generation – Operation (535-540.1)	1,178,474
9	HydraulicPowerGenerationMaintenanceExpense Hydraulic Power Generation – Maintenance (541-545.1)	736,700
10	PowerProductionExpensesHydraulicPower Total Power Production Expenses - Hydraulic Power	1,915,174
11	RentsOtherPowerGeneration Other Power Generation – Operation (546-550.1)	102,728,973
12	MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration Other Power Generation – Maintenance (551-554.1)	4,493,305
13	MaintenanceOfMiscellaneousOtherPowerGenerationPlant Total Power Production Expenses - Other Power	107,222,278
14	OtherPowerSuplyExpensesAbstract Other Power Supply Expenses
15	PurchasedPower (555) Purchased Power	72,526,666
15.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations
16	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching	770,426
17	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses
18	OtherPowerSupplyExpense Total Other Power Supply Expenses (line 15-17)	73,297,092
19	PowerProductionExpenses Total Power Production Expenses (Total of lines 4, 7, 10, 13 and 18)	272,181,640
20	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
21	TransmissionExpensesOperationAbstract Transmission Operation Expenses
22	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	524,885
24	LoadDispatchReliability (561.1) Load Dispatch-Reliability	369,117
25	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	333,900
26	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling	68,008
27	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services
28	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development
29	TransmissionServiceStudies (561.6) Transmission Service Studies
30	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies	10,061
31	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services
32	StationExpensesTransmissionExpense (562) Station Expenses	657,299
32.1	OperationOfEnergyStorageEquipmentTransmissionExpense (562.1) Operation of Energy Storage Equipment
33	OverheadLineExpense (563) Overhead Lines Expenses	54,501
34	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses	119,712
35	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	25,775
36	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	1,829,806
37	RentsTransmissionElectricExpense (567) Rents	193,964
38	OperationSuppliesAndExpensesTransmissionExpense (567.1) Operation Supplies and Expenses (Non-Major)
39	TransmissionOperationExpense TOTAL Transmission Operation Expenses (Lines 22 - 38)	3,927,482
40	TransmissionMaintenanceAbstract Transmission Maintenance Expenses
41	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering
42	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	258
43	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware
44	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software
45	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment	8,861
46	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant
47	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	680,501
47.1	MaintenanceOfEnergyStorageEquipmentTransmission (570.1) Maintenance of Energy Storage Equipment
48	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	1,906,490
49	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines
50	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant	20,864
51	MaintenanceOfTransmissionPlant (574) Maintenance of Transmission Plant
52	TransmissionMaintenanceExpenseElectric TOTAL Transmission Maintenance Expenses (Lines 41 – 51)	2,616,974
53	TransmissionExpenses Total Transmission Expenses (Lines 39 and 52)	6,544,456
54	RegionalMarketExpensesAbstract 3. REGIONAL MARKET EXPENSES
55	RegionalMarketExpensesOperationAbstract Regional Market Operation Expenses
56	OperationSupervision (575.1) Operation Supervision
57	DayAheadAndRealTimeMarketAdministration (575.2) Day-Ahead and Real-Time Market Facilitation
58	TransmissionRightsMarketAdministration (575.3) Transmission Rights Market Facilitation
59	CapacityMarketAdministration (575.4) Capacity Market Facilitation
60	AncillaryServicesMarketAdministration (575.5) Ancillary Services Market Facilitation
61	MarketMonitoringAndCompliance (575.6) Market Monitoring and Compliance
62	MarketFacilitationMonitoringAndComplianceServices (575.7) Market Facilitation, Monitoring and Compliance Services
63	RegionalMarketOperationExpense Regional Market Operation Expenses (Lines 55 - 62)
64	RegionalMarketExpensesMaintenanceAbstract Regional Market Maintenance Expenses
65	MaintenanceOfStructuresAndImprovementsRegionalMarketExpenses (576.1) Maintenance of Structures and Improvements
66	MaintenanceOfComputerHardware (576.2) Maintenance of Computer Hardware
67	MaintenanceOfComputerSoftware (576.3) Maintenance of Computer Software
68	MaintenanceOfCommunicationEquipmentRegionalMarketExpenses (576.4) Maintenance of Communication Equipment
69	MaintenanceOfMiscellaneousMarketOperationPlant (576.5) Maintenance of Miscellaneous Market Operation Plant
70	RegionalMarketMaintenanceExpense Regional Market Maintenance Expenses (Lines 65-69)
71	RegionalMarketExpenses TOTAL Regional Control and Market Operation Expenses (Lines 63,70)
72	DistributionExpensesAbstract 4. DISTRIBUTION EXPENSES
73	DistributionOperationExpensesElectric Distribution Operation Expenses (580-589)	4,294,017
74	DistributionMaintenanceExpenseElectric Distribution Maintenance Expenses (590-598)	12,946,639
75	DistributionExpenses Total Distribution Expenses (Lines 73 and 74)	17,240,656

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

Electric Customer Accts, Service, Sales, Admin and General Expenses
Report the amount of expenses for customer accounts, service, sales, and administrative and general expenses year to date.
Line No.	Account (a)	Year to Date Quarter (b)
-	CustomerAccountsExpensesOperationsAbstract Operation
1	CustomerAccountExpenses (901-905) Customer Accounts Expenses	8,157,535
2	CustomerServiceAndInformationExpenses (907-910) Customer Service and Information Expenses	7,454,616
3	SalesExpenses (911-917) Sales Expenses	375,942
4	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
5	AdministrativeAndGeneralExpensesOperationAbstract Operation
6	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	21,493,121
7	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	6,047,900
8	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit	7,732,061
9	OutsideServicesEmployed (923) Outside Services Employed	3,195,521
10	PropertyInsurance (924) Property Insurance	1,736,651
11	InjuriesAndDamages (925) Injuries and Damages	1,053,722
12	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	8,780,616
13	FranchiseRequirements (927) Franchise Requirements
14	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	2,476,455
15	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.	2,905,336
16	GeneralAdvertisingExpenses (930.1) General Advertising Expenses	218,553
17	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	595,860
18	RentsAdministrativeAndGeneralExpense (931) Rents	2,415,880
19	AdministrativeAndGeneralOperationExpense TOTAL Operation (Total of lines 6 thru 18)	37,376,882
20	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
21	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	4,421,022
22	AdministrativeAndGeneralExpenses TOTAL Administrative and General Expenses (Total of lines 19 and 21)	41,797,904

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")

Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to. Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c).
In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes.
In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (d), is provided.
Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column (g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the contract.
Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
Report in column (i) and (j) the total megawatthours received and delivered.
In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (0) in column (n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report purposes only on Page 401, Lines 16 and 17, respectively.
Footnote entries and provide explanations following all required data.

TRANSFER OF ENERGY

REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS

Line No.

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

(m)

(n)

1

Macquarie Energy LLC

Georgia Power Company

South Carolina Public Service Authority

SFP

S7,S1,S2

SOCO

SC

67

(h)

1,525

(o)

1,495

7,464

(y)

441

7,905

2

South Carolina Public Service Authority

Central Electric Power Co-op

FNO

(b)

Attach H

205

(i)

83,944

(p)

81,499

934,568

(v)

8,845

(z)

27,894

(af)

971,307

3

Southeastern Power Administration

(a)

See Footnote

FNO

(c)

Attach H

60

(j)

12,521

(q)

12,115

287,961

(aa)

18,309

(ag)

306,270

4

City of Orangeburg

Dominion Energy South Carolina, Inc.

City of Orangeburg

FNO

(d)

Attach H

375

(k)

190,311

(r)

184,768

1,745,167

(ab)

127,740

(ah)

1,872,907

5

Town of Winnsboro

Dominion Energy South Carolina, Inc.

Town of Winnsboro

FNO

(e)

Attach H

28

(l)

14,203

(s)

13,924

136,231

(ac)

9,973

(ai)

146,204

6

Central Electric Power Co-op

South Carolina Public Service Authority

Central Electric Power Co-op

FNO

(f)

Attach H

42

(m)

15,420

(t)

15,118

190,872

(w)

2,778

(ad)

5,698

(aj)

199,348

7

McCormick Commission of Public Works

Duke Energy Carolinas, LLC

McCormick Commission of Public Works

FNO

(g)

Attach H

11

(n)

5,097

(u)

4,997

54,497

(x)

14,668

(ae)

3,996

(ak)

43,825

35

TOTAL

788

323,021

313,916

3,356,760

3,045

194,051

3,547,766

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName

South Carolina Public Service Authority, Little River Electric Cooperative, McCormick CPW, City of Orangeburg and Town of Winnsboro.

(b) Concept: RateScheduleTariffNumber

Also includes Rate Schedules S1, S2 and S4 of Tariff.

(c) Concept: RateScheduleTariffNumber

Also includes Rate Schedules S1, S2, S5 and S6 of Tariff.

(d) Concept: RateScheduleTariffNumber

Also includes Rate Schedules S1, S2, S3, S5 and S6 of Tariff.

(e) Concept: RateScheduleTariffNumber

Also includes Rate Schedules S1, S2, S3, S5 and S6 of Tariff.

(f) Concept: RateScheduleTariffNumber

Also includes Rate Schedules S1, S2 and S4 of Tariff.

(g) Concept: RateScheduleTariffNumber

Also includes Rate Schedules S1, S2, S3, S4, S5 and S6 of Tariff.

(h) Concept: TransmissionOfElectricityForOthersEnergyReceived

Actual energy flows in MWH are listed rather than transmission reservation quantities.

(i) Concept: TransmissionOfElectricityForOthersEnergyReceived

Actual energy flows in MWH are listed rather than transmission reservation quantities.

(j) Concept: TransmissionOfElectricityForOthersEnergyReceived

Actual energy flows in MWH are listed rather than transmission reservation quantities.

(k) Concept: TransmissionOfElectricityForOthersEnergyReceived

Actual energy flows in MWH are listed rather than transmission reservation quantities.

(l) Concept: TransmissionOfElectricityForOthersEnergyReceived

Actual energy flows in MWH are listed rather than transmission reservation quantities.

(m) Concept: TransmissionOfElectricityForOthersEnergyReceived

Actual energy flows in MWH are listed rather than transmission reservation quantities.

(n) Concept: TransmissionOfElectricityForOthersEnergyReceived

Actual energy flows in MWH are listed rather than transmission reservation quantities.

(o) Concept: TransmissionOfElectricityForOthersEnergyDelivered

Actual energy flows in MWH are listed rather than transmission reservation quantities.

(p) Concept: TransmissionOfElectricityForOthersEnergyDelivered

Actual energy flows in MWH are listed rather than transmission reservation quantities.

(q) Concept: TransmissionOfElectricityForOthersEnergyDelivered

Actual energy flows in MWH are listed rather than transmission reservation quantities.

(r) Concept: TransmissionOfElectricityForOthersEnergyDelivered

Actual energy flows in MWH are listed rather than transmission reservation quantities.

(s) Concept: TransmissionOfElectricityForOthersEnergyDelivered

Actual energy flows in MWH are listed rather than transmission reservation quantities.

(t) Concept: TransmissionOfElectricityForOthersEnergyDelivered

Actual energy flows in MWH are listed rather than transmission reservation quantities.

(u) Concept: TransmissionOfElectricityForOthersEnergyDelivered

Actual energy flows in MWH are listed rather than transmission reservation quantities.

(v) Concept: EnergyChargesRevenueTransmissionOfElectricityForOthers

Charges for Ancillary Service 4 (Energy Imbalance). The reported amount does not include energy imbalance penalties which are allocated to non-offending transmission customers.

(w) Concept: EnergyChargesRevenueTransmissionOfElectricityForOthers

Charges for Ancillary Service 4 (Energy Imbalance). The reported amount does not include energy imbalance penalties which are allocated to non-offending transmission customers.

(x) Concept: EnergyChargesRevenueTransmissionOfElectricityForOthers

Charges for Ancillary Service 4 (Energy Imbalance). The reported amount does not include energy imbalance penalties which are allocated to non-offending transmission customers.

(y) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Sum of Ancillary Service 1 and 2 charges.

(z) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Sum of Ancillary Service 1 and 2 charges.

(aa) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Sum of Ancillary Service 1, 2, 5 and 6 charges.

(ab) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Sum of Ancillary Services 1, 2, 3, 5 and 6 charges.

(ac) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Sum of Ancillary Services 1, 2, 3, 5 and 6 charges.

(ad) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Sum of Ancillary Service 1 and 2 charges.

(ae) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Sum of Ancillary Services 1, 2, 3, 5 and 6 charges.

(af) Concept: RevenuesFromTransmissionOfElectricityForOthers

Network transmission revenue.

(ag) Concept: RevenuesFromTransmissionOfElectricityForOthers

Network transmission revenue.

(ah) Concept: RevenuesFromTransmissionOfElectricityForOthers

Network transmission revenue.

(ai) Concept: RevenuesFromTransmissionOfElectricityForOthers

Network transmission revenue.

(aj) Concept: RevenuesFromTransmissionOfElectricityForOthers

Network transmission revenue.

(ak) Concept: RevenuesFromTransmissionOfElectricityForOthers

Network transmission revenue.

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

TRANSMISSION OF ELECTRICITY BY ISO/RTOs
Report in Column (a) the Transmission Owner receiving revenue for the transmission of electricity by the ISO/RTO. Use a separate line of data for each distinct type of transmission service involving the entities listed in Column (a). In Column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO – Firm Network Service for Others, FNS – Firm Network Transmission Service for Self, LFP – Long-Term Firm Point-to-Point Transmission Service, OLF – Other Long-Term Firm Transmission Service, SFP – Short-Term Firm Point-to-Point Transmission Reservation, NF – Non-Firm Transmission Service, OS – Other Transmission Service and AD- Out-of-Period Adjustments. Use this code for any accounting adjustments or “true-ups” for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes. In column (c) identify the FERC Rate Schedule or tariff Number, on separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (b) was provided. In column (d) report the revenue amounts as shown on bills or vouchers. Report in column (e) the total revenues distributed to the entity listed in column (a).
Line No.	Payment Received by (Transmission Owner Name) (a)	Statistical Classification (b)	FERC Rate Schedule or Tariff Number (c)	Total Revenue by Rate Schedule or Tariff (d)	Total Revenue (e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
40	TOTAL

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. Enter ""TOTAL"" in column (a) as the last line. Footnote entries and provide explanations following all required data.
			TRANSFER OF ENERGY		EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Line No.	NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	TransmissionOfElectricityByOthersEnergyReceived MegaWatt Hours Received (c)	TransmissionOfElectricityByOthersEnergyDelivered MegaWatt Hours Delivered (d)	DemandChargesTransmissionOfElectricityByOthers Demand Charges ($) (e)	EnergyChargesTransmissionOfElectricityByOthers Energy Charges ($) (f)	OtherChargesTransmissionOfElectricityByOthers Other Charges ($) (g)	ChargesForTransmissionOfElectricityByOthers Total Cost of Transmission ($) (h)
1	Duke Energy Carolinas	FNS	1,319	1,383	4,394	19,452	(a) 3,684	11,374
2	Duke Energy Carolinas	NF	97	97	239		(b) 38	277
3	PJM Settlement, Inc.	NF					(c) 163	163
4	Central Electric Power Cooperative, Inc.	OS					(d) 27,666	27,666
5	Santee Cooper	SFP	1,925	1,869	10,693		(e) 1,645	12,338
6	Adjustments						(f) 26,043	26,043
	TOTAL		3,341	3,349	6,538	19,452	215	25,775

FOOTNOTE DATA

(a) Concept: OtherChargesTransmissionOfElectricityByOthers


Scheduling, System Control and Dispatch	$	(209)
Reactive Supply and Voltage Control	(452)
Regulation and Frequency Response	(86)
Operating Reserve - Spinning	(184)
Operating Reserve - Supplement	(184)
Other - Direct Assignment Charges	(2,569)
Total	$	(3,684)

(b) Concept: OtherChargesTransmissionOfElectricityByOthers


Scheduling, System Control and Dispatch	$	11
Reactive Supply and Voltage Control	27
Total	$	38

(c) Concept: OtherChargesTransmissionOfElectricityByOthers


Reactive Supply and Voltage Control	$	2
Operating Reserve - Spinning	(1)
Other - Load Response Charge Allocation	1
Other - PJM Settlement, Inc. Miscellaneous Fees	161
Total	$	163

(d) Concept: OtherChargesTransmissionOfElectricityByOthers


Other - Sewee/Commonwealth Transmission Facility Charges	$	27,666
Total	$	27,666

(e) Concept: OtherChargesTransmissionOfElectricityByOthers


Scheduling, System Control and Dispatch	$	449
Reactive Supply and Voltage Control	1,196
Total	$	1,645

(f) Concept: OtherChargesTransmissionOfElectricityByOthers


Duke Energy Carolinas, LLC loss related to January 2022 Purchase Wheeling transaction	$	140
Excess amount accrued in Q4 2021 related to PJM. Adjusted in January 2022.	$	(1,719)
Excess amount accrued in Q4 2021 related to Duke Energy Progress. Adjusted in January 2022.	$	(24,464)
Total	$	(26,043)

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

Deprec, Depl and Amort of Elec Plant (403,403.1,404,and 405) (except Amortization of Acquisition Adjustments)
Report the year to date amounts of depreciation expense, asset retirement cost depreciation, depletion and amortization, except amortization of acquisition adjustments for the accounts indicated and classified according to the plant functional groups described.
Line No.	FunctionalClassificationAxis Functional Classification (a)	DepreciationExpenseExcludingAmortizationOfAcquisitionAdjustments Depreciation Expense (Account 403) (b)	DepreciationExpenseForAssetRetirementCostsExcludingAmortizationgOfAcquisitionAdjustments Depreciation Expense for Asset Retirement Costs (Account 403.1) (c)	AmortizationOfLimitedTermPlantOrProperty Amortization of Limited Term Electric Plant (Account 404) (d)	AmortizationOfOtherElectricPlant Amortization of Other Electric Plant (Acc 405) (e)	DepreciationAndAmortization Total (f)
1	Intangible Plant			975,132		975,132
2	Steam Production Plant	15,716,995				15,716,995
3	Nuclear Production Plant	6,588,661				6,588,661
4	Hydraulic Production Plant-Conventional	686,470				686,470
5	Hydraulic Production Plant-Pumped Storage	666,866				666,866
6	Other Production Plant	5,752,582				5,752,582
7	Transmission Plant	12,035,274				12,035,274
8	Distribution Plant	23,294,760				23,294,760
9	General Plant	993,144				993,144
10	Common Plant-Electric	1,467,366		737,073		2,204,439
11	TOTAL	67,202,118		1,712,205		68,914,323

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for Resale, for items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market for purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determining whether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively.
Line No.	Description of Item(s) (a)	Balance at End of Quarter 1 (b)	Balance at End of Quarter 2 (c)	Balance at End of Quarter 3 (d)	Balance at End of Year (e)
1	Energy
2	Net Purchases (Account 555)
2.1	Net Purchases (Account 555.1)
3	Net Sales (Account 447)
4	Transmission Rights
5	Ancillary Services	1
6	Other Items (list separately)
7	Load Response Charge Allocation	1
8	PJM Settlement, Inc. Miscellaneous Fees	161
46	TOTAL	163

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

Monthly Peak Loads and Energy Output
Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required information for each non- integrated system. Report in column (b) by month the system’s output in Megawatt hours for each month. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
Line No.	MonthAxis Month (a)	Total Monthly Energy (MWH) (b)	Monthly Non-Requirements Sales for Resale & Associated Losses (c)	MonthlyPeakLoad Monthly Peak Megawatts (See Instr. 4) (d)	DayOfMonthlyPeak Monthly Peak Day of Month (e)	HourOfMonthlyPeak Monthly Peak Hour (f)
	NAME OF SYSTEM: 0
1	January	2,139,766		4,255	23	(a) 8
2	February	1,689,269		4,022	9	8
3	March	1,697,259	7,573	3,524	14	8
4	Total for Quarter 1	5,526,294	7,573
5	April
6	May
7	June
8	Total for Quarter 2
9	July
10	August
11	September
12	Total for Quarter 3
41	Total

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: HourOfMonthlyPeak

All Times are in Hour Ending (HE) format.

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

MONTHLY TRANSMISSION SYSTEM PEAK LOAD
Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. Report on Column (b) by month the transmission system's peak load. Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the definition of each statistical classification.
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Firm Network Service for Self (e)	Firm Network Service for Others (f)	Long-Term Firm Point-to-point Reservations (g)	Other Long-Term Firm Service (h)	Short-Term Firm Point-to-point Reservation (i)	Other Service (j)
	NAME OF SYSTEM: 0
1	January	3,755	27	(a) 8	(b) 3,442	246			67
2	February	3,749	9	8	3,498	251
3	March	3,401	14	8	3,177	224
4	Total for Quarter 1				10,117	721			67
5	April
6	May
7	June
8	Total for Quarter 2
9	July
10	August
11	September
12	Total for Quarter 3
13	October
14	November
15	December
16	Total for Quarter 4
17	Total				10,117	721			67

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

FOOTNOTE DATA

(a) Concept: HourOfMonthlyPeakExcludingIsoAndRto

All times are shown in Hour Ending (HE) format.

(b) Concept: FirmNetworkServiceForSelf

For all values shown in column (e):

The Company utilizes grandfathered service for its retail customers and has not executed a network integration transmission service agreement under the Open Access Transmission Tariff.

Name of Respondent:

Dominion Energy South Carolina, Inc.

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

05/24/2022

Year/Period of Report

End of:

2022

/

Q1

Monthly ISO/RTO Transmission System Peak Load
Report the monthly peak load on the respondent's transmission system. If the Respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. Report on Column (b) by month the transmission system's peak load. Report on Column (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). Report on Columns (e) through (i) by month the system’s transmission usage by classification. Amounts reported as Through and Out Service in Column (g) are to be excluded from those amounts reported in Columns (e) and (f). Amounts reported in Column (j) for Total Usage is the sum of Columns (h) and (i).
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Import into ISO/RTO (e)	Exports from ISO/RTO (f)	Through and Out Service (g)	Network Service Usage (h)	Point-to-Point Service Usage (i)	Total Usage (j)
	NAME OF SYSTEM: 0
1	January
2	February
3	March
4	Total for Quarter 1				0	0	0	0	0	0
5	April
6	May
7	June
8	Total for Quarter 2				0	0	0	0	0	0
9	July
10	August
11	September
12	Total for Quarter 3				0	0	0	0	0	0
13	October
14	November
15	December
16	Total for Quarter 4				0	0	0	0	0	0
17	Total Year to Date/Year				0	0	0	0	0	0

FERC FINANCIAL REPORT FERC FORM No. 1: Annual Report of Major Electric Utilities, Licensees and Others and Supplemental Form 3-Q: Quarterly Financial Report

INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q

GENERAL INFORMATION

Purpose

Who Must Submit

What and Where to Submit

When to Submit

Where to Send Comments on Public Reporting Burden.

GENERAL INSTRUCTIONS

EXCERPTS FROM THE LAW

GENERAL PENALTIES

FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report