FERC Form

THIS FILING IS

Item 1:

☐ An Initial (Original) Submission

☑ 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)

Duke Energy Carolinas, LLC

Year/Period of Report

End of:

2022

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.

REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER

IDENTIFICATION

01 Exact Legal Name of Respondent

Duke Energy Carolinas, LLC

02 Year/ Period of Report

End of:

2022

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)

526 S. Church Street, Charlotte, NC 28202

05 Name of Contact Person

Erin Kelley

06 Title of Contact Person

Manager Accounting I

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

526 S. Church Street, Charlotte, NC 28202

08 Telephone of Contact Person, Including Area Code

(980) 373-6928

09 This Report is An Original / A Resubmission

(1)

☐ An Original

(2)

☑ A Resubmission

10 Date of Report (Mo, Da, Yr)

04/14/2023

Annual 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

Cynthia S. Lee

02 Title

VP, CAO, and Controller

03 Signature

Cynthia S. Lee

04 Date Signed (Mo, Da, Yr)

04/14/2023

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:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

LIST OF SCHEDULES (Electric Utility)
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	2
1	ScheduleGeneralInformationAbstract General Information	101
2	ScheduleControlOverRespondentAbstract Control Over Respondent	102
3	ScheduleCorporationsControlledByRespondentAbstract Corporations Controlled by Respondent	103
4	ScheduleOfficersAbstract Officers	104
5	ScheduleDirectorsAbstract Directors	105
6	ScheduleInformationOnFormulaRatesAbstract Information on Formula Rates	106
7	ScheduleImportantChangesDuringTheQuarterYearAbstract Important Changes During the Year	108
8	ScheduleComparativeBalanceSheetAbstract Comparative Balance Sheet	110
9	ScheduleStatementOfIncomeAbstract Statement of Income for the Year	114
10	ScheduleRetainedEarningsAbstract Statement of Retained Earnings for the Year	118
12	ScheduleStatementOfCashFlowsAbstract Statement of Cash Flows	120
12	ScheduleNotesToFinancialStatementsAbstract Notes to Financial Statements	122
13	ScheduleStatementOfAccumulatedOtherComprehensiveIncomeAndHedgingActivitiesAbstract Statement of Accum Other Comp Income, Comp Income, and Hedging Activities	122a
14	ScheduleSummaryOfUtilityPlantAndAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep	200
15	ScheduleNuclearFuelMaterialsAbstract Nuclear Fuel Materials	202
16	ScheduleElectricPlantInServiceAbstract Electric Plant in Service	204
17	ScheduleElectricPropertyLeasedToOthersAbstract Electric Plant Leased to Others	213	N/A
18	ScheduleElectricPlantHeldForFutureUseAbstract Electric Plant Held for Future Use	214
19	ScheduleConstructionWorkInProgressElectricAbstract Construction Work in Progress-Electric	216
20	ScheduleAccumulatedProvisionForDepreciationOfElectricUtilityPlantAbstract Accumulated Provision for Depreciation of Electric Utility Plant	219
21	ScheduleInvestmentsInSubsidiaryCompaniesAbstract Investment of Subsidiary Companies	224
22	ScheduleMaterialsAndSuppliesAbstract Materials and Supplies	227
23	ScheduleAllowanceInventoryAbstract Allowances	228
24	ScheduleExtraordinaryPropertyLossesAbstract Extraordinary Property Losses	230a	N/A
25	ScheduleUnrecoveredPlantAndRegulatoryStudyCostsAbstract Unrecovered Plant and Regulatory Study Costs	230b
26	ScheduleTransmissionServiceAndGenerationInterconnectionStudyCostsAbstract Transmission Service and Generation Interconnection Study Costs	231
27	ScheduleOtherRegulatoryAssetsAbstract Other Regulatory Assets	232
28	ScheduleMiscellaneousDeferredDebitsAbstract Miscellaneous Deferred Debits	233
29	ScheduleAccumulatedDeferredIncomeTaxesAbstract Accumulated Deferred Income Taxes	234
30	ScheduleCapitalStockAbstract Capital Stock	250	N/A
31	ScheduleOtherPaidInCapitalAbstract Other Paid-in Capital	253
32	ScheduleCapitalStockExpenseAbstract Capital Stock Expense	254b	N/A
33	ScheduleLongTermDebtAbstract Long-Term Debt	256
34	ScheduleReconciliationOfReportedNetIncomeWithTaxableIncomeForFederalIncomeTaxesAbstract Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax	261
35	ScheduleTaxesAccruedPrepaidAndChargedDuringYearDistributionOfTaxesChargedAbstract Taxes Accrued, Prepaid and Charged During the Year	262
36	ScheduleAccumulatedDeferredInvestmentTaxCreditsAbstract Accumulated Deferred Investment Tax Credits	266
37	ScheduleOtherDeferredCreditsAbstract Other Deferred Credits	269
38	ScheduleAccumulatedDeferredIncomeTaxesAcceleratedAmortizationPropertyAbstract Accumulated Deferred Income Taxes-Accelerated Amortization Property	272	N/A
39	ScheduleAccumulatedDeferredIncomeTaxesOtherPropertyAbstract Accumulated Deferred Income Taxes-Other Property	274
40	ScheduleAccumulatedDeferredIncomeTaxesOtherAbstract Accumulated Deferred Income Taxes-Other	276
41	ScheduleOtherRegulatoryLiabilitiesAbstract Other Regulatory Liabilities	278
42	ScheduleElectricOperatingRevenuesAbstract Electric Operating Revenues	300
43	ScheduleRegionalTransmissionServiceRevenuesAbstract Regional Transmission Service Revenues (Account 457.1)	302	N/A
44	ScheduleSalesOfElectricityByRateSchedulesAbstract Sales of Electricity by Rate Schedules	304
45	ScheduleSalesForResaleAbstract Sales for Resale	310
46	ScheduleElectricOperationsAndMaintenanceExpensesAbstract Electric Operation and Maintenance Expenses	320
47	SchedulePurchasedPowerAbstract Purchased Power	326
48	ScheduleTransmissionOfElectricityForOthersAbstract Transmission of Electricity for Others	328	Resubmission 2 (filed 9/20/2023): Duke Energy Carolinas, LLC (DEC) discovered that the Billing Demand (MW) in column h was overstated by 875 MW.
49	ScheduleTransmissionOfElectricityByIsoOrRtoAbstract Transmission of Electricity by ISO/RTOs	331	N/A
50	ScheduleTransmissionOfElectricityByOthersAbstract Transmission of Electricity by Others	332
51	ScheduleMiscellaneousGeneralExpensesAbstract Miscellaneous General Expenses-Electric	335
52	ScheduleDepreciationDepletionAndAmortizationAbstract Depreciation and Amortization of Electric Plant (Account 403, 404, 405)	336
53	ScheduleRegulatoryCommissionExpensesAbstract Regulatory Commission Expenses	350
54	ScheduleResearchDevelopmentOrDemonstrationExpendituresAbstract Research, Development and Demonstration Activities	352
55	ScheduleDistributionOfSalariesAndWagesAbstract Distribution of Salaries and Wages	354
56	ScheduleCommonUtilityPlantAndExpensesAbstract Common Utility Plant and Expenses	356	N/A
57	ScheduleAmountsIncludedInIsoOrRtoSettlementAbstract Amounts included in ISO/RTO Settlement Statements	397
58	SchedulePurchasesSalesOfAncillaryServicesAbstract Purchase and Sale of Ancillary Services	398
59	ScheduleMonthlyTransmissionSystemPeakLoadAbstract Monthly Transmission System Peak Load	400	Resubmission 2 (filed 9/20/2023): Changes on Page 328-330 impacted values presented on this page, specifically related to columns e and g.
60	ScheduleMonthlyIsoOrRtoTransmissionSystemPeakLoadAbstract Monthly ISO/RTO Transmission System Peak Load	400a	N/A
61	ScheduleElectricEnergyAccountAbstract Electric Energy Account	401a
62	ScheduleMonthlyPeakAndOutputAbstract Monthly Peaks and Output	401b	Resubmission 1 (filed 5/10/2023) - Duke Energy Carolinas, LLC (DEC) discovered that New River (previously part of Blue Ridge prior to 2022) was included in the calculation of the Production peaks reported on page 401b of the FERC Form 1 filed April 14, 2023. New River is not served by DEC and this resubmitted filing is to remove that load.
63	ScheduleSteamElectricGeneratingPlantStatisticsAbstract Steam Electric Generating Plant Statistics	402	Resubmission 2 (filed 9/20/2023): Duke Energy Carolinas, LLC (DEC) discovered the Plant O&M amounts on lines 22-35 for the following steam plants: Allen, Belews Creek, Buck, Catawba, Cliffside, Dan River Steam, Lee Steam, Marshall, and Riverbend Steam were incorrect due to an upload issue into the software used to file the FERC Form 1.
64	ScheduleHydroelectricGeneratingPlantStatisticsAbstract Hydroelectric Generating Plant Statistics	406
65	SchedulePumpedStorageGeneratingPlantStatisticsAbstract Pumped Storage Generating Plant Statistics	408
66	ScheduleGeneratingPlantStatisticsAbstract Generating Plant Statistics Pages	410
0	ScheduleEnergyStorageOperationsLargePlantsAbstract Energy Storage Operations (Large Plants)	414
67	ScheduleTransmissionLineStatisticsAbstract Transmission Line Statistics Pages	422
68	ScheduleTransmissionLinesAddedAbstract Transmission Lines Added During Year	424
69	ScheduleSubstationsAbstract Substations	426
70	ScheduleTransactionsWithAssociatedAffiliatedCompaniesAbstract Transactions with Associated (Affiliated) Companies	429
71	FootnoteDataAbstract Footnote Data	450
	StockholdersReportsAbstract Stockholders' Reports (check appropriate box)
	Stockholders' Reports Check appropriate box: ☐ Two copies will be submitted ☐ No annual report to stockholders is prepared

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

GENERAL INFORMATION
1. Provide name and title of officer having custody of the general corporate books of account and address of office where the general corporate books are kept, and address of office where any other corporate books of account are kept, if different from that where the general corporate books are kept. Cynthia S. Lee Vice President, Chief Accounting Officer and Controller 526 S. Church Street, Charlotte, NC 28202
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation. If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type of organization and the date organized. State of Incorporation: NC Date of Incorporation: 1963-11-27 Incorporated Under Special Law:
3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or trusteeship was created, and (d) date when possession by receiver or trustee ceased. (a) Name of Receiver or Trustee Holding Property of the Respondent: (b) Date Receiver took Possession of Respondent Property: (c) Authority by which the Receivership or Trusteeship was created: (d) Date when possession by receiver or trustee ceased:
4. State the classes or utility and other services furnished by respondent during the year in each State in which the respondent operated. Per the 2022 10-K:Duke Energy Carolinas is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. Duke Energy Carolinas’ service area covers approximately 24,000 square miles and supplies electric service to 2.8 million residential, commercial and industrial customers. For information about Duke Energy Carolinas’ generating facilities, see Item 2, “Properties.” Duke Energy Carolinas is subject to the regulatory provisions of the NCUC, PSCSC, NRC and FERC.Substantially all of Duke Energy Carolinas' operations are regulated and qualify for regulatory accounting. Duke Energy Carolinas operates one reportable business segment, Electric Utilities and Infrastructure. For additional information regarding this business segment, including financial information, see Note 3 to the Consolidated Financial Statements, “Business Segments.”
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not the principal accountant for your previous year's certified financial statements? (1) ☐ Yes (2) ☑ No

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

CONTROL OVER RESPONDENT
1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held control over the respondent at the end of the year, state name of controlling corporation or organization, manner in which control was held, and extent of control. If control was in a holding company organization, show the chain of ownership or control to the main parent company or organization. If control was held by a trustee(s), state name of trustee(s), name of beneficiary or beneficiaries for whom trust was maintained, and purpose of the trust.

Manner/Extent of Control: Membership interest in respondent, Duke Energy Carolinas, LLC, is 100% owned by Duke Energy Corporation. Chain of Ownership/Control to Main Parent company: 100% of the membership interest in respondent, Duke Energy Carolinas, LLC, is owned and controlled by Duke Energy Corporation, which is the publicly held parent company. See also 2022 Duke Energy Corporation Form 10-K filed with the SEC in February, 2023.

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

CORPORATIONS CONTROLLED BY RESPONDENT
Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming any intermediaries involved. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests. Definitions See the Uniform System of Accounts for a definition of control. Direct control is that which is exercised without interposition of an intermediary. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line No.	NameOfCompanyControlledByRespondent Name of Company Controlled (a)	CompanyControlledByRespondentKindOfBusinessDescription Kind of Business (b)	VotingStockOwnedByRespondentPercentage Percent Voting Stock Owned (c)	FootnoteReferences Footnote Ref. (d)
1	Advance SC LLC	Non-Profit	100
2	Caldwell Power Company	Refer to Column (d)	100	(a) A
3	Catawba Manufacturing and Electric Power Co.	Refer to Column (d)	100	(b) A
4	Claiborne Energy Services, Inc	Uranium Enrichment	100
5	Duke Energy Carolinas NC Storm Funding LLC	Storm Securitization Recovery	100
6	Duke Energy Receivables Finance Co., LLC	Receivables Finance	100
7	Eastover Land Company	Real Estate	100
8	Eastover Mining Company	Mining Company	100
9	Greenville Gas & Electric Light & Power Co	Refer to Column (d)	100	(c) A
10	MCP, LLC	Holding Company	100
11	Sandy River Timber, LLC	Real Estate	100
12	Southern Power Company	Refer to Column (d)	100	(d) A
13	TBP Properties, LLC	Real Estate	100
14	TRES Timber, LLC	Real Estate	100
15	Wateree Power Company	Refer to Column (d)	100	(e) A
16	Western Carolina Power Co	Refer to Column (d)	100	(f) A

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: FootnoteReferences

The purpose of this entity is to generate, transmit, and distribute electric power and preserve property rights

(b) Concept: FootnoteReferences

The purpose of this entity is to generate, transmit, and distribute electric power and preserve property rights

(d) Concept: FootnoteReferences

The purpose of this entity is to generate, transmit, and distribute electric power and preserve property rights

(e) Concept: FootnoteReferences

The purpose of this entity is to generate, transmit, and distribute electric power and preserve property rights

(f) Concept: FootnoteReferences

The purpose of this entity is to generate, transmit, and distribute electric power and preserve property rights

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

OFFICERS
Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function (such as sales, administration or finance), and any other person who performs similar policy making functions. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous incumbent, and the date the change in incumbency was made.
Line No.	OfficerTitle Title (a)	OfficerName Name of Officer (b)	OfficerSalary Salary for Year (c)	DateOfficerIncumbencyStarted Date Started in Period (d)	DateOfficerIncumbencyEnded Date Ended in Period (e)
1	Chief Executive Officer	Lynn J. Good	1,500,000	2022-01-01	2022-12-31
2	Executive Vice President and Chief Financial Officer	Steven K. Young	802,824	2022-01-01	2022-08-31
3	Executive Vice President, Chief Commercial Officer	Steven K. Young	802,824	2022-09-01	2022-12-31
4	Executive Vice President and Chief Operating Officer	Dhiaa M. Jamil	903,611	2022-01-01	2022-12-31
5	Senior Vice President and Chief Human Resources Officer	Ron Reising	498,818	2022-01-01	2022-12-31
6	Executive Vice President	Julia S. Janson	777,026	2022-01-01	2022-12-31
7	State President, NC	Stephen De May	455,540	2022-01-01	2022-12-31
8	State President, SC	Michael P. Callahan	327,625	2022-01-01	2022-12-31
9	Senior Vice President, Corporate Development and Treasurer	Karl W. Newlin	539,556	2022-01-01	2022-12-31
10	Vice President, Chief Accounting Officer and Controller	Cynthia S. Lee	319,815	2022-01-01	2022-12-31
11	Executive Vice President, Customer Experience Solutions, and Services	Harry K. Sideris	607,257	2022-01-01	2022-12-31
12	Executive Vice President, Chief Commercial Officer	Brian D. Savoy	579,630	2022-01-01	2022-08-31
13	Executive Vice President and Chief Financial Officer	Brian D. Savoy	626,000	2022-09-01	2022-12-31
14	Executive Vice President, Chief Legal Officer and Secetary	Kodwo Ghartey-Tagoe	673,002	2022-01-01	2022-12-31
15	Senior Vice President, External Affairs and Communications	Louis Renjel	483,750	2022-01-01	2022-12-31
16	Senior Vice President	R. Alexander Glenn	510,625	2022-01-01	2022-12-31

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

DIRECTORS
Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), name and abbreviated titles of the directors who are officers of the respondent. Provide the principle place of business in column (b), designate members of the Executive Committee in column (c), and the Chairman of the Executive Committee in column (d).
Line No.	NameAndTitleOfDirector Name (and Title) of Director (a)	PrincipalBusinessAddress Principal Business Address (b)	MemberOfTheExecutiveCommittee Member of the Executive Committee (c)	ChairmanOfTheExecutiveCommittee Chairman of the Executive Committee (d)
1	Lynn Good, Chief Excutive Officer	526 S Church St, Charlotte NC 28202	true	true
2	Dhiaa Jamil, Executive Vice President and Chief Operating Officer	526 S Church St, Charlotte NC 28202	true	false
3	Julia S. Janson, Executive Vice President	526 S Church St, Charlotte NC 28202	true	false

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

INFORMATION ON FORMULA RATES
Does the respondent have formula rates?		☑ Yes ☐ No
Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No) accepting the rate(s) or changes in the accepted rate.
Line No.	RateScheduleTariffNumber FERC Rate Schedule or Tariff Number (a)	ProceedingDocketNumber FERC Proceeding (b)
1	508	ER22-1481-000
2	Joint Open Access Transmission Tariff (Sec 4)	ER22-1166-000
3	Joint Open Access Transmission Tariff (Sec 4)	ER23-213-000
4	Joint Open Access Transmission Tariff (10.A-2)	ER22-306-002
5	Joint Open Access Transmission Tariff (Sec. 1, 14, 15, schedule 9, Att.X, x-1)	ER23-388-000
6	Joint Open Access Transmission Tariff (10.A-1, 10.A-2, 12-A)	ER22-2844-000
7	Joint Open Access Transmission Tariff (Sec. 4, Attachment Y)	ER22-2352-000
8	Joint Open Access Transmission Tariff (Attachments J and K)	ER22-2007-000
9	588	ER22-2011-000

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

INFORMATION ON FORMULA RATES - FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent file with the Commission annual (or more frequent) filings containing the inputs to the formula rate(s)?			☑ Yes ☐ No
If yes, provide a listing of such filings as contained on the Commission's eLibrary website.
Line No.	AccessionNumber Accession No. (a)	DocumentDate Document Date / Filed Date (b)	DocketNumber Docket No. (c)	DescriptionOfFiling Description (d)	RateScheduleTariffNumber Formula Rate FERC Rate Schedule Number or Tariff Number (e)
1	20220516-5284	05/16/2022	ER11-3585	Informational Filing 2022 Annual Update
2				for the OATT Formula Transmission	Tariff Volume No. 4, Open Access
3				Rate of Duke Energy Carolinas, LLC	Transmission Tariff, 9.0.0
4				under ER11-3585

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

INFORMATION ON FORMULA RATES - Formula Rate Variances
If a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from amounts reported in the Form 1. The footnote should provide a narrative description explaining how the "rate" (or billing) was derived if different from the reported amount in the Form 1. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.
Line No.	PageNumberOfFormulaRateVariances Page No(s). (a)	ScheduleOfFormulaRateVariances Schedule (b)	ColumnOfFormulaRateVariances Column (c)	LineNumberOfFormulaRateVariances Line No. (d)
1	117	Interest on Long Term Debt	c	62-67
2	207	Electric Plant in Service	g	58
3	219	Accumulated Provision for Depreciation of Electric Utility Plant (Account 108)	b	25
4	227	Materials and Supplies - Transmission	c	5
5	263	Taxes Accrued, Prepaid, and Charged during year	i	102,332
6	275	Accumulated Deferred Income Taxes - Other Property	k	9
7	321	Electric Operation and Maintenance Expense	b	112
8	323	Electric Operation and Maintenance Expense	b	197
9	336	Depreciation and Amortization of Electric Plant	f	7
10	354	Distribution of Salaries and Wages	b	27
11	355	Distribution of Salaries and Wages	b	65
12	114	Statement of Income	g	14
13	117	Interest on Long Term Debt	c	67
14	200	Summary of Utility Plant and Accumulated Provisions for Depreciation, Amortization and Depletion	c	21
15	204-205	Electric Plant in Service	g	5
16	205	Electric Plant in Service	g	46
17	207	Electric Plant in Service	g	99
18	219	Accumulated Provision for Depreciation of Electric Utility Plant (Account 108)	c	242,528
19	263	Taxes Accrued, Prepaid, and Charged during year	l	11,12,1
20	275	Accumulated Deferred Income Taxes - Other Property	k	2
21	311	Sales for Resale	k	Subtotal non-RQ
22	320	Electric Operation and Maintenance Expense	b	5,12
23	321	Electric Operation and Maintenance Expense	b	63,80,112
24	323	Electric Operation and Maintenance Expense	b	185,197
25	336	Depreciation and Amortization of Electric Plant	f	1,2,3,4,6,7,10
26	354	Distribution of Salaries and Wages	b	20,24

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

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. Listed below are the newly added franchise agreements obtained in 2022: City of Archdale, NC - March 2022, acquired without the payment of consideration

2. None

3. None

4. None

5. None

6. See Notes to Financial Statements, Note 5, "Debt and Credit Facilities"

7. None

8. None

9. See Notes to Financial Statements, Note 3, "Regulatory Matters" and Note 4,"Commitments and Contingencies"

10. None

12. None

13. There are no changes to major security holders and voting powers of Duke Energy Carolinas, LLC that occurred during 2022. The changes in officer and director appointments and resignations for Duke Energy Carolinas, LLC that occurred during 2022 are as follows:


Appointments Effective January 2022
Jessica Brooks Bishop			Vice President, Customer Care
Larry E. Hatcher			Senior Vice President, Customer Experience and Services
Martin Strasburger			Vice President and Chief Information Security Officer
Appointments Effective February 2022
Edward R. Pigott			Site Vice President, McGuire
Thomas D. Ray			Senior Vice President, Nuclear Operations - NC
Cassandra M. Springer			Assistant Secretary
Appointments Effective April 2022
Randy C. Herrin			Vice President, Carolinas Regulated Renewables and Lake Services
Appointments Effective May 2022
Retha Hunsicker			Vice President, Customer Experience Design and Solutions
Appointments Effective September 2022
Brian D. Savoy			Executive Vice President and Chief Financial Officer
Steven K. Young			Executive Vice President and Chief Commercial Officer
Appointments Effective November 2022
Julie K. Turner			Vice President, Carolinas Generation

Appointments Effective December 2022


Jay R. Alvaro			Vice President, Employee and Labor Relations
Cameron D. McDonald			Vice President, Talent Acquisition and Talent Management
Sharene J. Pierce			Vice President and Chief Diversity and Inclusion Officer
Martin Strasburger			Vice President, Chief Security and Information Security Officer
Resignations Effective January 2022
Keith G. Butler			Senior Vice President and Chief Security Officer
Joni Y. Davis			Vice President, Chief of Staff and Chief Diversity and Inclusion Officer
Larry E. Hatcher			Senior Vice President, Customer Services
Mia S. Haynes			Vice President, Customer Care
Barbara A. Higgins			Senior Vice President and Chief Customer Officer
Resignations Effective February 2022
Dennis P. Gilbert, Jr.			Vice President and Chief Information Security Officer
Thomas D. Ray			Site Vice President, McGuire
Benjamin C. Waldrep			Senior Vice President, Nuclear Operations - NC
Resignations Effective May 2022
Melody Birmingham			Senior Vice President and Chief Administrative Officer
Retha Hunsicker			Vice President, Customer Connect Solutions
Resignations Effective June 2022
Robert P. Vary			Senior Vice President, Sales and Relationship Management
Peter E. Toomey			Senior Vice President, Strategic Regulatory Initiatives
Resignations Effective September 2022
Brian D. Savoy			Executive Vice President, Chief Strategy and Commercial Officer
Nancy M. Wright			Assistant Secretary
Steven K. Young			Executive Vice President and Chief Financial Officer
Resignations Effective October 2022
Forest (Buddy) W. Rogers, Jr.			Senior Vice President, Transmission Maintenance and Construction
Resignations Effective November 2022
Julie K. Turner			Vice President, Carolinas Coal Generation
Resignations Effective December 2022
Stephen G. De May			President, North Carolina
Tanya M. Hamilton			Senior Vice President, Nuclear Corporate
Cameron D. McDonald			Vice President, Chief Diversity and Inclusion Officer, Talent Agility and Acquisition
James M. Mosley			Vice President, Carolinas Natural Gas Generation
Janet Rhoton			Vice President, Human Resources, Executive Development & Engagement
L. Stanford Sherrill, Jr.			Vice President, Human Resources and Employee & Labor Relations
Martin Strasburger			Vice President and Chief Information Security Officer

14. N/A

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

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	50,189,611,446	48,083,730,849
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	2,668,054,514	2,074,674,520
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		52,857,665,960	50,158,405,369
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	18,826,671,097	18,092,066,058
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		34,030,994,863	32,066,339,311
7	NuclearFuelInProcessOfRefinementConversionEnrichmentAndFabrication Nuclear Fuel in Process of Ref., Conv., Enrich., and Fab. (120.1)	202	318,507,751	323,922,465
8	NuclearFuelMaterialsAndAssembliesStockAccountMajorOnly Nuclear Fuel Materials and Assemblies-Stock Account (120.2)		1	1
9	NuclearFuelAssembliesInReactorMajorOnly Nuclear Fuel Assemblies in Reactor (120.3)		1,038,700,375	1,072,507,768
10	SpentNuclearFuelMajorOnly Spent Nuclear Fuel (120.4)		371,747,433	466,390,240
11	NuclearFuelUnderCapitalLeases Nuclear Fuel Under Capital Leases (120.6)
12	AccumulatedProvisionForAmortizationOfNuclearFuelAssemblies (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)	202	940,022,796	1,070,439,997
13	NuclearFuelNet Net Nuclear Fuel (Enter Total of lines 7-11 less 12)		788,932,764	792,380,477
14	UtilityPlantAndNuclearFuelNet Net Utility Plant (Enter Total of lines 6 and 13)		34,819,927,627	32,858,719,788
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)		1,012,650	1,012,652
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)
17	OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS
18	NonutilityProperty Nonutility Property (121)		147,023,257	142,257,197
19	AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Prov. for Depr. and Amort. (122)		56,182,620	51,806,699
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224	13,114,590	13,114,590
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances	228
24	OtherInvestments Other Investments (124)		96,239	95,984
25	SinkingFunds Sinking Funds (125)
26	DepreciationFund Depreciation Fund (126)
27	AmortizationFundFederal Amortization Fund - Federal (127)
28	OtherSpecialFunds Other Special Funds (128)		5,043,375,183	6,221,233,397
29	SpecialFunds Special Funds (Non Major Only) (129)
30	DerivativeInstrumentAssetsLongTerm Long-Term Portion of Derivative Assets (175)
31	DerivativeInstrumentAssetsHedgesLongTerm Long-Term Portion of Derivative Assets - Hedges (176)		65,859,985	48,154,229
32	OtherPropertyAndInvestments TOTAL Other Property and Investments (Lines 18-21 and 23-31)		5,213,286,634	6,373,048,698
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)		43,421,767	7,123,317
36	SpecialDeposits Special Deposits (132-134)
37	WorkingFunds Working Fund (135)		300,000	300,000
38	TemporaryCashInvestments Temporary Cash Investments (136)
39	NotesReceivable Notes Receivable (141)
40	CustomerAccountsReceivable Customer Accounts Receivable (142)		737,908,627	651,279,578
41	OtherAccountsReceivable Other Accounts Receivable (143)		175,471,927	192,204,348
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		68,311,242	41,521,659
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)		1,186,050	1,186,050
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)		397,764,794	198,841,223
45	FuelStock Fuel Stock (151)	227	290,008,826	237,479,722
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	825,717,767	742,724,654
49	Merchandise Merchandise (155)	227
50	OtherMaterialsAndSupplies Other Materials and Supplies (156)	227	197,323	73,366
51	NuclearMaterialsHeldForSale Nuclear Materials Held for Sale (157)	202/227
52	AllowanceInventoryAndWithheld Allowances (158.1 and 158.2)	228	84,906,259	73,571,212
53	NoncurrentPortionOfAllowances (Less) Noncurrent Portion of Allowances	228
54	StoresExpenseUndistributed Stores Expense Undistributed (163)	227	(a) 48,743,849	(b) 46,246,014
55	GasStoredCurrent Gas Stored Underground - Current (164.1)
56	LiquefiedNaturalGasStoredAndHeldForProcessing Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)
57	Prepayments Prepayments (165)		25,342,955	31,159,798
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)		232,765	529,304
60	RentsReceivable Rents Receivable (172)		408,938	356,340
61	AccruedUtilityRevenues Accrued Utility Revenues (173)		367,597,749	273,671,078
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)		493	8,633,432
63	DerivativeInstrumentAssets Derivative Instrument Assets (175)		94,202,917
64	DerivativeInstrumentAssetsLongTerm (Less) Long-Term Portion of Derivative Instrument Assets (175)
65	DerivativeInstrumentAssetsHedges Derivative Instrument Assets - Hedges (176)		164,406,696	131,569,284
66	DerivativeInstrumentAssetsHedgesLongTerm (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176)		65,859,985	48,154,229
67	CurrentAndAccruedAssets Total Current and Accrued Assets (Lines 34 through 66)		3,123,253,829	2,507,126,100
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		69,730,347	66,290,421
70	ExtraordinaryPropertyLosses Extraordinary Property Losses (182.1)	230a
71	UnrecoveredPlantAndRegulatoryStudyCosts Unrecovered Plant and Regulatory Study Costs (182.2)	230b	268,117,137	302,153,769
72	OtherRegulatoryAssets Other Regulatory Assets (182.3)	232	5,006,761,329	3,225,787,621
73	PreliminarySurveyAndInvestigationCharges Prelim. Survey and Investigation Charges (Electric) (183)		13,753,411	13,210,991
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)		923,512	896,038
77	TemporaryFacilities Temporary Facilities (185)
78	MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186)	233	879,175,548	748,143,187
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)		35,716,829	41,138,005
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	3,308,699,145	3,461,784,968
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		9,582,877,258	7,859,405,000
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		52,740,357,998	49,599,312,238

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: StoresExpenseUndistributed

Stores Expense: Production 36,491,693 Transmission 3,063,265 Distribution 9,188,891

(b) Concept: StoresExpenseUndistributed

Stores Expense: Production 36,964,965 Transmission 2,658,880 Distribution 6,622,169

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

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
3	PreferredStockIssued Preferred Stock Issued (204)	250
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	3,725,067,850	3,725,067,850
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
11	RetainedEarnings Retained Earnings (215, 215.1, 216)	118	11,720,717,946	10,169,724,576
12	UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1)	118	4,810,163	4,810,163
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)	6,039,907	6,455,552
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		15,444,556,052	13,893,147,037
17	LongTermDebtAbstract LONG-TERM DEBT
18	Bonds Bonds (221)	256	12,455,842,052	11,656,738,919
19	ReacquiredBonds (Less) Reaquired Bonds (222)	256
20	AdvancesFromAssociatedCompanies Advances from Associated Companies (223)	256	300,000,000	300,000,000
21	OtherLongTermDebt Other Long-Term Debt (224)	256	1,084,301,533	860,271,405
22	UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225)		2,856,225	2,963,512
23	UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Debit (226)		24,144,973	23,669,305
24	LongTermDebt Total Long-Term Debt (lines 18 through 23)		13,818,854,837	12,796,304,531
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		360,380,457	361,697,908
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)		142,310,173	139,718,367
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		458,976,681	503,719,459
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		28,619,500	37,929,750
30	AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4)		848,802	807,716
31	AccumulatedProvisionForRateRefunds Accumulated Provision for Rate Refunds (229)		5,528,308	5,178,059
32	LongTermPortionOfDerivativeInstrumentLiabilities Long-Term Portion of Derivative Instrument Liabilities
33	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges Long-Term Portion of Derivative Instrument Liabilities - Hedges		2,953,999	1,444,109
34	AssetRetirementObligations Asset Retirement Obligations (230)		5,381,903,202	5,301,158,092
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		6,381,521,122	6,351,653,460
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)
38	AccountsPayable Accounts Payable (232)		1,429,054,204	958,467,951
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)		1,232,747,000	226,415,000
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		232,981,910	306,555,280
41	CustomerDeposits Customer Deposits (235)		83,740,140	68,369,287
42	TaxesAccrued Taxes Accrued (236)	262	195,466,860	253,086,975
43	InterestAccrued Interest Accrued (237)		119,779,499	124,260,511
44	DividendsDeclared Dividends Declared (238)
45	MaturedLongTermDebt Matured Long-Term Debt (239)
46	MaturedInterest Matured Interest (240)
47	TaxCollectionsPayable Tax Collections Payable (241)		22,336,147	16,535,914
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		432,107,476	508,975,825
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		20,616,573	27,575,734
50	DerivativesInstrumentLiabilities Derivative Instrument Liabilities (244)			8,633,432
51	LongTermPortionOfDerivativeInstrumentLiabilities (Less) Long-Term Portion of Derivative Instrument Liabilities
52	DerivativeInstrumentLiabilitiesHedges Derivative Instrument Liabilities - Hedges (245)		84,193,024	13,192,701
53	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges		2,953,999	1,444,109
54	CurrentAndAccruedLiabilities Total Current and Accrued Liabilities (lines 37 through 53)		3,850,068,834	2,510,624,501
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)
57	AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255)	266	300,444,062	287,006,804
58	DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256)
59	OtherDeferredCredits Other Deferred Credits (253)	269	780,840,758	882,014,410
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	4,703,606,464	5,783,960,664
61	UnamortizedGainOnReacquiredDebt Unamortized Gain on Reaquired Debt (257)
62	AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty Accum. Deferred Income Taxes-Accel. Amort.(281)	272
63	AccumulatedDeferredIncomeTaxesOtherProperty Accum. Deferred Income Taxes-Other Property (282)		4,970,188,323	4,764,247,775
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		2,490,277,546	2,330,353,056
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		13,245,357,153	14,047,582,709
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		52,740,357,998	49,599,312,238

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

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	7,811,181,562	7,100,634,161			7,811,181,562	7,100,634,161
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	3,204,402,812	2,796,367,900			3,204,402,812	2,796,367,900
5	MaintenanceExpense Maintenance Expenses (402)	320	578,153,854	517,128,775			578,153,854	517,128,775
6	DepreciationExpense Depreciation Expense (403)	336	1,208,559,422	1,173,115,743			1,208,559,422	1,173,115,743
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336		4,435,886				4,435,886
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	73,900,912	71,285,843			73,900,912	71,285,843
9	AmortizationOfElectricPlantAcquisitionAdjustments Amort. of Utility Plant Acq. Adj. (406)	336
10	AmortizationOfPropertyLossesUnrecoveredPlantAndRegulatoryStudyCosts Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)		45,421,830	45,427,295			45,421,830	45,427,295
11	AmortizationOfConversionExpenses Amort. of Conversion Expenses (407.2)
12	RegulatoryDebits Regulatory Debits (407.3)		222,382,427	240,590,871			222,382,427	240,590,871
13	RegulatoryCredits (Less) Regulatory Credits (407.4)		21,882,642	28,532,715			21,882,642	28,532,715
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	341,809,886	320,409,756			341,809,886	320,409,756
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	73,073,642	252,908,008			73,073,642	252,908,008
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	10,529,360	27,717,829			10,529,360	27,717,829
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	1,571,126,341	1,606,673,593			1,571,126,341	1,606,673,593
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	1,364,699,218	1,810,725,377			1,364,699,218	1,810,725,377
19	InvestmentTaxCreditAdjustments Investment Tax Credit Adj. - Net (411.4)	266	4,151,613	3,959,622			4,151,613	3,959,622
20	GainsFromDispositionOfPlant (Less) Gains from Disp. of Utility Plant (411.6)		17,060	1,162			17,060	1,162
21	LossesFromDispositionOfServiceCompanyPlant Losses from Disp. of Utility Plant (411.7)			699,120				699,120
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)		112,171	1,440,319			112,171	1,440,319
25	UtilityOperatingExpenses TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)		5,771,516,120	5,214,982,062			5,771,516,120	5,214,982,062
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		2,039,665,442	1,885,652,099			2,039,665,442	1,885,652,099
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)
32	CostsAndExpensesOfMerchandisingJobbingAndContractWork (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)		175,857	11,733
33	RevenuesFromNonutilityOperations Revenues From Nonutility Operations (417)		46,490,179	43,055,272
34	ExpensesOfNonutilityOperations (Less) Expenses of Nonutility Operations (417.1)		17,939,650	20,106,907
35	NonoperatingRentalIncome Nonoperating Rental Income (418)		4,372,710	4,093,218
36	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1)	119
37	InterestAndDividendIncome Interest and Dividend Income (419)		2,218,827	3,671,900
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		97,598,412	65,129,106
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		35,914,121	121,318,078
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)		4,512,976	2,129,676
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		164,246,298	211,092,174
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)		575,041	423,888
44	MiscellaneousAmortization Miscellaneous Amortization (425)		1,551	3,001
45	Donations Donations (426.1)		7,578,702	7,227,333
46	LifeInsurance Life Insurance (426.2)		200,492	211,481
47	Penalties Penalties (426.3)		52,586	521,500
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		7,107,129	7,728,674
49	OtherDeductions Other Deductions (426.5)		32,070,049	230,840,389
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		47,181,464	245,685,528
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262	1,722,114	651,756
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262	1,791,200	11,460,948
54	IncomeTaxesOther Income Taxes-Other (409.2)	262	2,482,398	4,337,427
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272	17,536,174	11,010,016
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272	9,715,491	16,657,024
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)		5,407,371	22,097,139
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		111,657,463	12,496,215
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		509,512,662	479,560,490
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		8,190,645	8,004,083
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)		5,421,175	6,403,404
65	AmortizationOfPremiumOnDebtCredit (Less) Amort. of Premium on Debt-Credit (429)		107,287	107,287
66	AmortizationOfGainOnReacquiredDebtCredit (Less) Amortization of Gain on Reaquired Debt-Credit (429.1)
67	InterestOnDebtToAssociatedCompanies Interest on Debt to Assoc. Companies (430)		14,995,561	998,262
68	OtherInterestExpense Other Interest Expense (431)		62,394,810	70,418,382
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		50,078,031	28,714,347
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		550,329,535	536,562,987
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		1,600,993,370	1,336,592,897
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)		1,600,993,370	1,336,592,897

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

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		10,007,159,843	9,280,215,805
2	ChangesAbstract Changes
3	AdjustmentsToRetainedEarningsAbstract Adjustments to Retained Earnings (Account 439)
4	AdjustmentsToRetainedEarningsCreditAbstract Adjustments to Retained Earnings Credit
4.1	AdjustmentsToRetainedEarningsCredit Current Expected Credit Losses (CECL) adjustments	283
4.2	AdjustmentsToRetainedEarningsCredit Current Expected Credit Losses (CECL) adjustments	190
4.3	AdjustmentsToRetainedEarningsCredit
4.4	AdjustmentsToRetainedEarningsCredit
9	AdjustmentsToRetainedEarningsCredit TOTAL Credits to Retained Earnings (Acct. 439)
10	AdjustmentsToRetainedEarningsDebitAbstract Adjustments to Retained Earnings Debit
10.1	AdjustmentsToRetainedEarningsDebit
10.2	AdjustmentsToRetainedEarningsDebit
10.3	AdjustmentsToRetainedEarningsDebit Current Expected Credit Losses (CECL) adjustments	186
10.4	AdjustmentsToRetainedEarningsDebit Current Expected Credit Losses (CECL) adjustments	144
15	AdjustmentsToRetainedEarningsDebit TOTAL Debits to Retained Earnings (Acct. 439)
16	BalanceTransferredFromIncome Balance Transferred from Income (Account 433 less Account 418.1)		1,600,993,370	1,336,592,897
17	AppropriationsOfRetainedEarningsAbstract Appropriations of Retained Earnings (Acct. 436)
17.1	AppropriationsOfRetainedEarnings Appropriations of Retained Earnings		29,037,489	14,535,288
22	AppropriationsOfRetainedEarnings TOTAL Appropriations of Retained Earnings (Acct. 436)		29,037,489	14,535,288
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 Cash Distribution to Parent		50,000,000	600,000,000
36	DividendsDeclaredCommonStock TOTAL Dividends Declared-Common Stock (Acct. 438)		50,000,000	600,000,000
37	TransfersFromUnappropriatedUndistributedSubsidiaryEarnings Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings			4,886,429
38	UnappropriatedRetainedEarnings Balance - End of Period (Total 1,9,15,16,22,29,36,37)		11,529,115,724	10,007,159,843
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)		191,602,222	162,564,733
47	AppropriatedRetainedEarningsIncludingReserveAmortization TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)		191,602,222	162,564,733
48	RetainedEarnings TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)		11,720,717,946	10,169,724,576
	UnappropriatedUndistributedSubsidiaryEarningsAbstract UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49	UnappropriatedUndistributedSubsidiaryEarnings Balance-Beginning of Year (Debit or Credit)		4,810,163	9,696,592
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 Transfers from Unappropriated Retained Earnings (Account 216)			4,886,429
53	UnappropriatedUndistributedSubsidiaryEarnings Balance-End of Year (Total lines 49 thru 52)		4,810,163	4,810,163

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

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)	1,600,993,370	1,336,592,897
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	1,208,671,593	1,178,991,948
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization (Primarily Nuclear Fuel)	577,428,898	602,650,056
5.2	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Impairment Charges	25,735,889	227,029,431
5.3	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Net (Increase) Decrease in MTM and Hedging Transactions	43,871,907	127,693
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	214,247,806	209,698,792
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)	4,151,613	3,959,622
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	349,640,564	273,574,569
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	137,390,507	16,305,073
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory	11,335,047	8,386,678
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	231,552,071	263,134,322
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	1,224,776,755	9,595,167
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	201,737,934	11,096,059
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	97,598,412	65,129,106
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies		4,886,429
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription SC Coal Ash Insurance Proceeds	2,026,508	30,658,006
18.2	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Federal and State Tax on Real Estate Impairments	664,266	6,805,139
18.3	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Church & College St. Impairments		2,299,671
18.4	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Tower Lease Revenue	613,371	2,871,039
18.5	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Deferred Lighting Revenue	1,544,879	2,134,867
18.6	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Claims and expenses related to injuries and damages	14,959,402	29,138,362
18.7	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other Post-Retirement Benefit Costs	9,731,122	21,729,041
18.8	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription COVID-19 Deferrals	76,145,667	19,508,225
18.9	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Deferral of Storm Costs	72,156,624	26,483,976
18.10	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Storm Securitization Proceeds	1,703,961	232,865,020
18.11	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Environmental Reserve	602,219	1,162,892
18.12	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Insurance proceeds for asbestos claims	16,455,563	16,963,901
18.13	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Miscellaneous Prepaid Expenses	1,010,184	5,912,960
18.14	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Nuclear Insurance Property Reserve	2,591,805	11,144,749
18.15	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Pension Contributions and Accruals	201,168,874	68,844,302
18.16	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Reclass of Prior Year Subsidiary Earnings		4,886,429
18.17	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Shareholder Contributions		4,000,000
18.18	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other	20,973,504	744,229
18.19	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Contributions to Qualified Pension Plans	15,487,883
18.20	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Payments for asset retirement obligations	199,686,527	182,393,174
18.21	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Provision for Rate Refunds	73,571,240	46,317,619
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	1,531,263,579	2,911,777,351
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)	3,155,306,874	2,499,256,857
27	GrossAdditionsToNuclearFuelInvestingActivities Gross Additions to Nuclear Fuel	246,662,951	258,599,871
28	GrossAdditionsToCommonUtilityPlantInvestingActivities Gross Additions to Common Utility Plant
29	GrossAdditionsToNonutilityPlantInvestingActivities Gross Additions to Nonutility Plant
30	AllowanceForOtherFundsUsedDuringConstructionInvestingActivities (Less) Allowance for Other Funds Used During Construction	97,598,412	65,129,106
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	3,304,371,413	2,692,727,622
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
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)	2,632,611,254	3,425,375,596
45	ProceedsFromSalesOfInvestmentSecurities Proceeds from Sales of Investment Securities (a)	2,632,611,254	3,425,375,596
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 Notes Receivable from Affiliate Companies		1,186,050
53.2	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Cost of removal of utility plant, net of salvage value	230,064,200	147,361,147
53.3	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Proceeds from Sales of Hydro Plants
53.4	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Other investing	74,349,790
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	3,460,085,823	2,841,274,819
59	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
60	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
61	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b)	1,449,632,991	1,422,198,756
62	ProceedsFromIssuanceOfPreferredStockFinancingActivities Preferred Stock
63	ProceedsFromIssuanceOfCommonStockFinancingActivities Common Stock
64	OtherAdjustmentsToCashFlowsFromFinancingActivities Other (provide details in footnote):
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
67.1	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Issuance Costs	8,745,334	8,354,867
67.2	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Unamortized Debt Expenses associated with Master Credit Facilities	1,021,405	916,344
67.3	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other Financing
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	1,439,866,252	1,412,927,545
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)	431,077,558	617,286,830
74	PaymentsForRetirementOfPreferredStockFinancingActivities Preferred Stock
75	PaymentsForRetirementOfCommonStockFinancingActivities Common Stock
76	OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
76.1	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Net Increase (Decrease) in Intercompany Notes	1,006,332,000	279,546,000
76.2	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Cash Distribution to Parent	50,000,000	600,000,000
78	NetDecreaseInShortTermDebt Net Decrease in Short-Term Debt (c)
80	DividendsOnPreferredStock Dividends on Preferred Stock
81	DividendsOnCommonStock Dividends on Common Stock
83	CashFlowsProvidedFromUsedInFinancingActivities Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)	1,965,120,694	83,905,285
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)	(a) 36,298,450	(e) 13,402,753
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	(b)(c) 7,423,317	(f) 20,826,070
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	(d) 43,721,767	(g)(h) 7,423,317

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: NetIncreaseDecreaseInCashAndCashEquivalents

Accrued Capital Expenditures 474,964,852Supplemental Disclosures:Cash Paid for Interest, Net of Amount Capitalized 546,121,915Cash Paid for Income Taxes, Net (59,167,927)

(b) Concept: CashAndCashEquivalents

Cash and working funds (131 & 135) 7,423,317Special deposits (132 - 134) 0Temporary cash investments 0Total 7,423,317

(d) Concept: CashAndCashEquivalents

Cash and working funds (131 & 135) 43,721,767Special deposits (132 - 134) 0Temporary cash investments 0Total 43,721,767

(e) Concept: NetIncreaseDecreaseInCashAndCashEquivalents

Accrued Capital Expenditures 364,994,059Supplemental Disclosures:Cash Paid for Interest, Net of Amount Capitalized 480,892,567Cash Paid for Income Taxes, Net 321,298,013

(f) Concept: CashAndCashEquivalents

Cash and working funds (131 & 135) (13,402,753)Special deposits (132 - 134) 0Temporary cash investments 0Total (13,402,753)

(g) Concept: CashAndCashEquivalents

Cash and working funds (131 & 135) 7,423,317Special deposits (132 - 134) 0Temporary cash investments 0Total 7,423,317

(h) Concept: CashAndCashEquivalents

Cash and working funds (131 & 135) 7,423,317Special deposits (132 - 134) 0Temporary cash investments 0Total 7,423,317

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

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.

This Federal Energy Regulatory Commission (FERC) Form 1 has been prepared in conformity with the 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 Generally Accepted Accounting Principles in the United States of America (GAAP). The following areas represent the significant differences between the Uniform System of Accounts and GAAP:

•GAAP requires that public business enterprises report certain information about operating segments in complete sets of financial statements of the enterprise and certain information about their products and services, which are not required for FERC reporting purposes.

•GAAP requires that majority-owned subsidiaries be consolidated for financial reporting purposes. FERC requires that majority-owned subsidiaries be separately reported as Investment in Subsidiary Companies, unless an appropriate waiver has been granted by the FERC.

•FERC requires that income or losses of an unusual nature and infrequent occurrence, which would significantly distort the current year's income, be recorded as extraordinary income or deductions, respectively.

•GAAP requires that removal and nuclear decommissioning costs for property that does not have an associated legal retirement obligation be presented as a regulatory liability on the Balance Sheet. These costs are presented as accumulated depreciation on the Balance Sheet for FERC reporting purposes.

•GAAP requires the regulatory assets and liabilities resulting from the implementation of ASC 740-10 (formerly SFAS No. 109) be presented as a net amount on the balance sheet. For FERC reporting purposes, these assets and liabilities are presented separately and are included in the Other Regulatory Asset and Other Regulatory Liability line items.

•GAAP requires that the current portion of regulatory assets and regulatory liabilities be reported as current assets and current liabilities, respectively, on the Balance Sheet. FERC requires that the current portion of regulatory assets and liabilities be reported as Regulatory Assets within Deferred Debits and Regulatory Liabilities within Deferred Credits, respectively.

•GAAP requires that the current portion of long-term debt and preferred stock be reported as a current liability on the Balance Sheet. FERC requires that the current portion of long-term debt and preferred stock be reported as Long-term Debt and Proprietary Capital.

•GAAP requires that any deferred costs associated with a specific debt issuance be presented as a reduction to debt on the Balance Sheet. FERC requires any Unamortized Debt Expense to be separately stated as a Deferred Debit on the Balance Sheet.

•GAAP requires that certain account balances within financial statement line items which are not in the natural position for that line item (e.g. an account within Accounts Receivable with a credit balance) be reclassed to the appropriate side of the Balance Sheet. FERC does not require certain accounts which are not in a natural position for their respective line item to be reclassed, as long as the line item in total is in its natural position.

•GAAP requires that the current portion of the provision for injuries and damages be reported as a current liability on the Balance Sheet. GAAP also requires that the current portion of the expected insurance proceeds receivable related to the provision for injuries and damages be reported as a current asset on the Balance Sheet. FERC requires that the current portion of the provision for injuries and damages be reported as 'Accumulated Provision for Injuries and Damages' and that the current portion of the related insurance receivable be reported as 'Deferred Debits'.

•GAAP requires that regulated assets that are abandoned or retired early, including the cost of the asset and its associated accumulated depreciation, be reclassified to a separate regulatory asset on the Balance Sheet. For FERC reporting purposes, those assets which have been abandoned but are still operating are maintained in their original balance sheet accounts.

•GAAP requires that the current portion of Asset Retirement Obligations be reported as current liabilities on the Balance Sheet. For FERC reporting purposes, these liabilities are not reported separately and are reflected as Asset Retirement Obligations within the Other Noncurrent Liabilities section of the Balance Sheet.

•GAAP requires service cost related to pensions and Post-Retirement Benefits Other Than Pensions (PBOP) to be reported with other compensation costs arising from services rendered by employees during the period and included in a subtotal of income from operations on the income statement. Non-service cost components are presented separately outside the subtotal of income from operations on the income statement. For FERC reporting purposes, costs related to pensions and PBOP is included in the Net Utility Operating Income of the income statement.

The Combined Notes To Consolidated Financial Statements below are as published in the fourth quarter ended December 31, 2022 Form 10-K (includes Duke Energy Carolinas, LLC, Duke Energy Progress, LLC, Duke Energy Florida, LLC, Duke Energy Ohio, Inc., Duke Energy Indiana, LLC and Piedmont Natural Gas Company, Inc.) filed on February 27, 2023. See "Index to the Combined Notes to Consolidated Financial Statements" for a listing of applicable notes for Duke Energy Carolinas, LLC.

Management has evaluated the impact of events occurring after December 31, 2022 up to February 27, 2023 (March 24, 2023 for DE Kentucky), the date that the Company’s U.S. GAAP financial statements were issued and has updated such evaluation for disclosure purposes through April 14, 2023. These financial statements include all necessary adjustments and disclosures resulting from these evaluations.

Index to Combined Notes To Consolidated Financial Statements

The notes to the consolidated financial statements are a combined presentation. The following table indicates the registrants to which the notes apply.

Applicable Notes

Registrant

Duke Energy

•

Duke Energy Carolinas

•

Progress Energy

•

Duke Energy Progress

•

Duke Energy Florida

•

Duke Energy Ohio

•

Duke Energy Indiana

•

Piedmont

•

Tables within the notes may not sum across due to (i) Progress Energy's consolidation of Duke Energy Progress, Duke Energy Florida and other subsidiaries that are not registrants and (ii) subsidiaries that are not registrants but included in the consolidated Duke Energy balances.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations and Basis of Consolidation

Duke Energy is an energy company headquartered in Charlotte, North Carolina, subject to regulation by the FERC and other regulatory agencies listed below. Duke Energy operates in the U.S. primarily through its direct and indirect subsidiaries. Certain Duke Energy subsidiaries are also subsidiary registrants, including Duke Energy Carolinas; Progress Energy; Duke Energy Progress; Duke Energy Florida; Duke Energy Ohio; Duke Energy Indiana and Piedmont. When discussing Duke Energy’s consolidated financial information, it necessarily includes the results of its separate Subsidiary Registrants, which along with Duke Energy, are collectively referred to as the Duke Energy Registrants.

The information in these combined notes relates to each of the Duke Energy Registrants as noted in the Index to Combined Notes to Consolidated Financial Statements. However, none of the Subsidiary Registrants make any representation as to information related solely to Duke Energy or the Subsidiary Registrants of Duke Energy other than itself.

These Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of the Duke Energy Registrants and subsidiaries or VIEs where the respective Duke Energy Registrants have control. See Note 18 for additional information on VIEs. These Consolidated Financial Statements also reflect the Duke Energy Registrants’ proportionate share of certain jointly owned generation and transmission facilities. See Note 9 for additional information on joint ownership. Substantially all of the Subsidiary Registrants' operations qualify for regulatory accounting.

Duke Energy Carolinas is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. Duke Energy Carolinas is subject to the regulatory provisions of the NCUC, PSCSC, NRC and FERC.

Progress Energy is a public utility holding company, which conducts operations through its wholly owned subsidiaries, Duke Energy Progress and Duke Energy Florida. Progress Energy is subject to regulation by FERC and other regulatory agencies listed below.

Duke Energy Progress is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. Duke Energy Progress is subject to the regulatory provisions of the NCUC, PSCSC, NRC and FERC.

Duke Energy Florida is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of Florida. Duke Energy Florida is subject to the regulatory provisions of the FPSC, NRC and FERC.

Duke Energy Ohio is a regulated public utility primarily engaged in the transmission and distribution of electricity in portions of Ohio and Kentucky, the generation and sale of electricity in portions of Kentucky and the transportation and sale of natural gas in portions of Ohio and Kentucky. Duke Energy Ohio conducts competitive auctions for retail electricity supply in Ohio whereby the energy price is recovered from retail customers and recorded in Operating Revenues on the Consolidated Statements of Operations and Comprehensive Income. Operations in Kentucky are conducted through its wholly owned subsidiary, Duke Energy Kentucky. References herein to Duke Energy Ohio collectively include Duke Energy Ohio and its subsidiaries, unless otherwise noted. Duke Energy Ohio is subject to the regulatory provisions of the PUCO, KPSC and FERC.

Duke Energy Indiana is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of Indiana. Duke Energy Indiana is subject to the regulatory provisions of the IURC and FERC.

Piedmont is a regulated public utility primarily engaged in the distribution of natural gas in portions of North Carolina, South Carolina and Tennessee. Piedmont is subject to the regulatory provisions of the NCUC, PSCSC, TPUC and FERC.

Certain prior year amounts have been reclassified to conform to the current year presentation.

Other Current Assets and Liabilities

The following table provides a description of amounts included in Other within Current Assets or Current Liabilities that exceed 5% of total Current Assets or Current Liabilities on the Duke Energy Registrants' Consolidated Balance Sheets at either December 31, 2022, or 2021.


		December 31,
(in millions)	Location	2022		2021
Duke Energy
Accrued compensation	Current Liabilities	$	778	$	915

Duke Energy Carolinas
Accrued compensation	Current Liabilities	$	247	$	277

Duke Energy Progress
Customer deposits	Current Liabilities	$	106	$	144
Other accrued liabilities	Current Liabilities	124		163
Duke Energy Florida
Customer deposits	Current Liabilities	$	200	$	200
Other accrued liabilities	Current Liabilities	61		89
Duke Energy Ohio
Gas Storage	Current Assets	$	57	$	25
Collateral liabilities	Current Liabilities	53		57
Duke Energy Indiana
Mark-to-market transactions	Current Assets	$	110	$	23

Discontinued Operations

Duke Energy has elected to present cash flows of discontinued operations combined with cash flows of continuing operations. Unless otherwise noted, the notes to these consolidated financial statements exclude amounts related to discontinued operations for all periods presented. For the years ended December 31, 2022, 2021 and 2020, the Loss From Discontinued Operations, net of tax on Duke Energy's Consolidated Statements of Operations includes amounts related to noncontrolling interests. A portion of Noncontrolling interests on Duke Energy's Consolidated Balance Sheets relates to discontinued operations for the periods presented. See Note 2 for discussion of discontinued operations related to the Commercial Renewables Disposal Groups.

Noncontrolling Interest

Duke Energy maintains a controlling financial interest in certain less than wholly owned regulated and nonregulated subsidiaries. As a result, Duke Energy consolidates these subsidiaries and presents the third-party investors' portion of Duke Energy's net income (loss), net assets and comprehensive income (loss) as noncontrolling interest. Noncontrolling interest is included as a component of equity on the Consolidated Balance Sheet. Operating agreements of Duke Energy's subsidiaries with noncontrolling interest allocate profit and loss based on their pro rata shares of the ownership interest in the respective subsidiary. Therefore, Duke Energy allocates net income or loss and other comprehensive income or loss of these subsidiaries to the owners based on their pro rata shares.

Significant Accounting Policies

Use of Estimates

In preparing financial statements that conform to GAAP, the Duke Energy Registrants must make estimates and assumptions that affect the reported amounts of assets and liabilities, the reported amounts of revenues and expenses and the disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates.

Regulatory Accounting

The majority of the Duke Energy Registrants’ operations are subject to price regulation for the sale of electricity and natural gas by state utility commissions or FERC. When prices are set on the basis of specific costs of the regulated operations and an effective franchise is in place such that sufficient natural gas or electric services can be sold to recover those costs, the Duke Energy Registrants apply regulatory accounting. Regulatory accounting changes the timing of the recognition of costs or revenues relative to a company that does not apply regulatory accounting. As a result, regulatory assets and regulatory liabilities are recognized on the Consolidated Balance Sheets. Regulatory assets and liabilities are amortized consistent with the treatment of the related cost in the ratemaking process. Regulatory assets are reviewed for recoverability each reporting period. If a regulatory asset is no longer deemed probable of recovery, the deferred cost is charged to earnings. See Note 4 for further information.

Regulatory accounting rules also require recognition of a disallowance (also called "impairment") loss if it becomes probable that part of the cost of a plant under construction (or a recently completed plant or an abandoned plant) will be disallowed for ratemaking purposes and a reasonable estimate of the amount of the disallowance can be made. For example, if a cost cap is set for a plant still under construction, the amount of the disallowance is a result of a judgment as to the ultimate cost of the plant. These disallowances can require judgments on allowed future rate recovery.

When it becomes probable that regulated generation, transmission or distribution assets will be abandoned, the cost of the asset is removed from plant in service. The value that may be retained as a regulatory asset on the balance sheet for the abandoned property is dependent upon amounts that may be recovered through regulated rates, including any return. As such, an impairment charge could be partially or fully offset by the establishment of a regulatory asset if rate recovery is probable. The impairment charge for a disallowance of costs for regulated plants under construction, recently completed or abandoned is based on discounted cash flows.

The Duke Energy Registrants utilize cost-tracking mechanisms, commonly referred to as fuel adjustment clauses or PGA clauses. These clauses allow for the recovery of fuel and fuel-related costs, portions of purchased power, natural gas costs and hedging costs through surcharges on customer rates. The difference between the costs incurred and the surcharge revenues is recorded either as an adjustment to Operating Revenues, Operating Expenses – Fuel used in electric generation or Operating Expenses – Cost of natural gas on the Consolidated Statements of Operations, with an off-setting impact on regulatory assets or liabilities.

Cash, Cash Equivalents and Restricted Cash

All highly liquid investments with maturities of three months or less at the date of acquisition are considered cash equivalents. Duke Energy, Progress Energy and Duke Energy Florida have restricted cash balances related primarily to collateral assets, escrow deposits and VIEs. Duke Energy Carolinas and Duke Energy Progress have restricted cash balances related to VIEs from storm recovery bonds issued. See Note 18 for additional information. Restricted cash amounts are included in Other within Current Assets and Other Noncurrent Assets on the Consolidated Balance Sheets. The following table presents the components of cash, cash equivalents and restricted cash included in the Consolidated Balance Sheets.


	December 31, 2022
			Duke				Duke		Duke
	Duke		Energy		Progress		Energy		Energy
	Energy		Carolinas		Energy		Progress		Florida
Current Assets
Cash and cash equivalents	$	409	$	44	$	108	$	49	$	45
Other	173		8		74		28		41
Other Noncurrent Assets
Other	11		1		2		2		—
Total cash, cash equivalents and restricted cash	$	593	$	53	$	184	$	79	$	86


	December 31, 2021
			Duke				Duke		Duke
	Duke		Energy		Progress		Energy		Energy
	Energy		Carolinas		Energy		Progress		Florida
Current Assets
Cash and cash equivalents	$	341	$	7	$	70	$	35	$	23
Other	170		—		39		—		39
Other Noncurrent Assets
Other	6		1		4		4		—
Total cash, cash equivalents and restricted cash	$	517	$	8	$	113	$	39	$	62

Inventory

Inventory related to regulated operations is valued at historical cost. Inventory related to nonregulated operations is valued at the lower of cost or market. Inventory is charged to expense or capitalized to property, plant and equipment when issued, primarily using the average cost method. Excess or obsolete inventory is written down to the lower of cost or net realizable value. Once inventory has been written down, it creates a new cost basis for the inventory that is not subsequently written up. Provisions for inventory write-offs were not material at December 31, 2022, and 2021, respectively. The components of inventory are presented in the tables below.


	December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Materials and supplies	$	2,604	$	876	$	1,232	$	819	$	413	$	105	$	342	$	12
Coal	620		253		190		99		91		34		144		—
Natural gas, oil and other	360		35		157		88		69		5		3		160
Total inventory	$	3,584	$	1,164	$	1,579	$	1,006	$	573	$	144	$	489	$	172


	December 31, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Materials and supplies	$	2,309	$	793	$	1,067	$	729	$	338	$	80	$	311	$	14
Coal	486		195		167		94		73		19		105		—
Natural gas, oil and other	316		38		164		98		66		17		2		95
Total inventory	$	3,111	$	1,026	$	1,398	$	921	$	477	$	116	$	418	$	109

Investments in Debt and Equity Securities

The Duke Energy Registrants classify investments in equity securities as FV-NI and investments in debt securities as AFS. Both categories are recorded at fair value on the Consolidated Balance Sheets. Realized and unrealized gains and losses on securities classified as FV-NI are reported through net income. Unrealized gains and losses for debt securities classified as AFS are included in AOCI until realized, unless it is determined the carrying value of an investment has a credit loss. For certain investments of regulated operations, such as substantially all of the NDTF, realized and unrealized gains and losses (including any credit losses) on debt securities are recorded as a regulatory asset or liability. The credit loss portion of debt securities of nonregulated operations are included in earnings. Investments in debt and equity securities are classified as either current or noncurrent based on management’s intent and ability to sell these securities, taking into consideration current market liquidity. See Note 16 for further information.

Goodwill

Duke Energy, Progress Energy, Duke Energy Ohio and Piedmont perform annual goodwill impairment tests as of August 31 each year at the reporting unit level, which is determined to be a business segment or one level below. Duke Energy, Progress Energy, Duke Energy Ohio and Piedmont update these tests between annual tests if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 12 for further information.

Intangible Assets

Intangible assets are included in Other in Other Noncurrent Assets on the Consolidated Balance Sheets. Generally, intangible assets are amortized using an amortization method that reflects the pattern in which the economic benefits of the intangible asset are consumed or on a straight-line basis if that pattern is not readily determinable. Amortization of intangibles is reflected in Depreciation and amortization on the Consolidated Statements of Operations. Intangible assets are subject to impairment testing and if impaired, the carrying value is accordingly reduced.

RECs are used to measure compliance with renewable energy standards and are held primarily for consumption. See Note 12 for further information.

Long-Lived Asset Impairments

The Duke Energy Registrants evaluate long-lived assets that are held and used, excluding goodwill, for impairment when circumstances indicate the carrying value of those assets may not be recoverable. An impairment exists when a long-lived asset’s carrying value exceeds the estimated undiscounted cash flows expected to result from the use and eventual disposition of the asset. The estimated cash flows may be based on alternative expected outcomes that are probability weighted. If the carrying value of the long-lived asset is not recoverable based on these estimated future undiscounted cash flows, the carrying value of the asset is written down to its then current estimated fair value and an impairment charge is recognized.

The Duke Energy Registrants assess fair value of long-lived assets that are held and used using various methods, including recent comparable third-party sales, internally developed discounted cash flow analysis and analysis from outside advisors. Triggering events to reassess cash flows may include, but are not limited to, significant changes in commodity prices, the condition of an asset or management’s interest in selling the asset.

Property, Plant and Equipment

Property, plant and equipment are stated at the lower of depreciated historical cost net of any disallowances or fair value, if impaired. The Duke Energy Registrants capitalize all construction-related direct labor and material costs, as well as indirect construction costs such as general engineering, taxes and financing costs. See “Allowance for Funds Used During Construction and Interest Capitalized” section below for information on capitalized financing costs. Costs of renewals and betterments that extend the useful life of property, plant and equipment are also capitalized. The cost of repairs, replacements and major maintenance projects, which do not extend the useful life or increase the expected output of the asset, are expensed as incurred. Depreciation is generally computed over the estimated useful life of the asset using the composite straight-line method. Depreciation studies are conducted periodically to update composite rates and are approved by state utility commissions and/or the FERC when required. The composite weighted average depreciation rates, excluding nuclear fuel, are included in the table that follows.


	Years Ended December 31,
	2022		2021		2020
Duke Energy	3.0	%	2.9	%	3.0	%
Duke Energy Carolinas	2.7	%	2.7	%	2.8	%
Progress Energy	3.2	%	3.1	%	3.2	%
Duke Energy Progress	3.0	%	3.0	%	3.1	%
Duke Energy Florida	3.5	%	3.3	%	3.3	%
Duke Energy Ohio	2.9	%	2.9	%	2.9	%
Duke Energy Indiana	3.6	%	3.6	%	3.5	%
Piedmont	2.1	%	2.1	%	2.3	%

In general, when the Duke Energy Registrants retire regulated property, plant and equipment, the original cost plus the cost of retirement, less salvage value and any depreciation already recognized, is charged to accumulated depreciation. However, when it becomes probable the asset will be retired substantially in advance of its original expected useful life or is abandoned, the cost of the asset and the corresponding accumulated depreciation is recognized as a separate asset. If the asset is still in operation, the net amount is classified as Facilities to be retired, net on the Consolidated Balance Sheets. If the asset is no longer operating, the net amount is classified in Regulatory assets on the Consolidated Balance Sheets if deemed recoverable (see discussion of long-lived asset impairments above). The carrying value of the asset is based on historical cost if the Duke Energy Registrants are allowed to recover the remaining net book value and a return equal to at least the incremental borrowing rate. If not, an impairment is recognized to the extent the net book value of the asset exceeds the present value of future revenues discounted at the incremental borrowing rate.

When the Duke Energy Registrants sell entire regulated operating units, or retire or sell nonregulated properties, the original cost and accumulated depreciation and amortization balances are removed from Property, Plant and Equipment on the Consolidated Balance Sheets. Any gain or loss is recorded in earnings, unless otherwise required by the applicable regulatory body. See Note 11 for additional information.

Other Noncurrent Assets

Duke Energy, through a nonregulated subsidiary, was the winner of the Carolina Long Bay offshore wind auction in May 2022 and recorded an

asset of $150 million related to the contract in Other within Other noncurrent assets. In November 2022, Duke Energy committed to a plan to sell the Commercial Renewables business segment, excluding the offshore wind contract for Carolina Long Bay, which was moved to the Electric Utilities and Infrastructure (EU&I) segment. See Notes 2 and 3 for further information.

Leases

Duke Energy determines if an arrangement is a lease at contract inception based on whether the arrangement involves the use of a physically distinct identified asset and whether Duke Energy has the right to obtain substantially all of the economic benefits from the use of the asset throughout the period as well as the right to direct the use of the asset. As a policy election, Duke Energy does not evaluate arrangements with initial contract terms of less than one year as leases.

Operating leases are included in Operating lease ROU assets, net, Other current liabilities and Operating lease liabilities on the Consolidated Balance Sheets. Finance leases are included in Property, plant and equipment, Current maturities of long-term debt and Long-Term Debt on the Consolidated Balance Sheets.

For lessee and lessor arrangements, Duke Energy has elected a policy to not separate lease and non-lease components for all asset classes. For lessor arrangements, lease and non-lease components are only combined under one arrangement and accounted for under the lease accounting framework if the non-lease components are not the predominant component of the arrangement and the lease component would be classified as an operating lease.

Nuclear Fuel

Nuclear fuel is classified as Property, Plant and Equipment on the Consolidated Balance Sheets.

Nuclear fuel in the front-end fuel processing phase is considered work in progress and not amortized until placed in service. Amortization of nuclear fuel is included within Fuel used in electric generation and purchased power on the Consolidated Statements of Operations. Amortization is recorded using the units-of-production method.

Allowance for Funds Used During Construction and Interest Capitalized

For regulated operations, the debt and equity costs of financing the construction of property, plant and equipment are reflected as AFUDC and capitalized as a component of the cost of property, plant and equipment. AFUDC equity is reported on the Consolidated Statements of Operations as non-cash income in Other income and expenses, net. AFUDC debt is reported as a non-cash offset to Interest Expense. After construction is completed, the Duke Energy Registrants are permitted to recover these costs through their inclusion in rate base and the corresponding subsequent depreciation or amortization of those regulated assets.

AFUDC equity, a permanent difference for income taxes, reduces the ETR when capitalized and increases the ETR when depreciated or amortized. See Note 24 for additional information.

Asset Retirement Obligations

AROs are recognized for legal obligations associated with the retirement of property, plant and equipment. Substantially all AROs are related to regulated operations. When recording an ARO, the present value of the projected liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The liability is accreted over time. For operating plants, the present value of the liability is added to the cost of the associated asset and depreciated over the remaining life of the asset. For retired plants, the present value of the liability is recorded as a regulatory asset unless determined not to be probable of recovery.

The present value of the initial obligation and subsequent updates are based on discounted cash flows, which include estimates regarding timing of future cash flows, selection of discount rates and cost escalation rates, among other factors. These estimates are subject to change. Depreciation expense is adjusted prospectively for any changes to the carrying amount of the associated asset. The Duke Energy Registrants receive amounts to fund the cost of the ARO for regulated operations through a combination of regulated revenues and earnings on the NDTF. As a result, amounts recovered in regulated revenues, earnings on the NDTF, accretion expense and depreciation of the associated asset are netted and deferred as a regulatory asset or liability.

Accounts Payable

During 2020, Duke Energy established a supply chain finance program (the “program”) with a global financial institution. The program is voluntary and allows Duke Energy suppliers, at their sole discretion, to sell their receivables from Duke Energy to the financial institution at a rate that leverages Duke Energy’s credit rating and, which may result in favorable terms compared to the rate available to the supplier on their own credit rating. Suppliers participating in the program, determine at their sole discretion which invoices they will sell to the financial institution. Suppliers’ decisions on which invoices are sold do not impact Duke Energy’s payment terms, which are based on commercial terms negotiated between Duke Energy and the supplier regardless of program participation. The commercial terms negotiated between Duke Energy and its suppliers are consistent regardless of whether the supplier elects to participate in the program. Duke Energy does not issue any guarantees with respect to the program and does not participate in negotiations between suppliers and the financial institution. Duke Energy does not have an economic interest in the supplier’s decision to participate in the program and receives no interest, fees or other benefit from the financial institution based on supplier participation in the program.

The following table presents the outstanding accounts payable balance sold to the financial institution by our suppliers and the supplier invoices sold to the financial institution under the program included within Net cash provided by operating activities on the Consolidated Statements of Cash Flows as of December 31, 2022, and December 31, 2021.


	December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Outstanding Accounts Payable Balance Sold	$	87	$	6	$	19	$	8	$	11	$	5	$	—	$	57
Suppliers Invoices Settled Through The Program	301		29		85		26		59		38		2		147


	December 30, 2021
					Duke		Duke
	Duke		Progress		Energy		Energy
(in millions)	Energy		Energy		Florida		Ohio		Piedmont
Outstanding Accounts Payable Balance Sold	$	19	$	9	$	9	$	6	$	4
Suppliers Invoices Settled Through The Program	122		10		10		12		100

Revenue Recognition

Duke Energy recognizes revenue as customers obtain control of promised goods and services in an amount that reflects consideration expected in exchange for those goods or services. Generally, the delivery of electricity and natural gas results in the transfer of control to customers at the time the commodity is delivered and the amount of revenue recognized is equal to the amount billed to each customer, including estimated volumes delivered when billings have not yet occurred. See Note 19 for further information.

Derivatives and Hedging

Derivative and non-derivative instruments may be used in connection with commodity price and interest rate activities, including swaps, futures, forwards and options. All derivative instruments, except those that qualify for the NPNS exception, are recorded on the Consolidated Balance Sheets at fair value. Qualifying derivative instruments may be designated as either cash flow hedges or fair value hedges. Other derivative instruments (undesignated contracts) either have not been designated or do not qualify as hedges. The effective portion of the change in the fair value of cash flow hedges is recorded in AOCI. The effective portion of the change in the fair value of a fair value hedge is offset in net income by changes in the hedged item. For activity subject to regulatory accounting, gains and losses on derivative contracts are reflected as regulatory assets or liabilities and not as other comprehensive income or current period income. As a result, changes in fair value of these derivatives have no immediate earnings impact.

Formal documentation, including transaction type and risk management strategy, is maintained for all contracts accounted for as a hedge. At inception and at least every three months thereafter, the hedge contract is assessed to see if it is highly effective in offsetting changes in cash flows or fair values of hedged items.

See Note 15 for further information.

Captive Insurance Reserves

Duke Energy has captive insurance subsidiaries that provide coverage, on an indemnity basis, to the Subsidiary Registrants as well as certain third parties, on a limited basis, for financial losses, primarily related to property, workers’ compensation and general liability. Liabilities include provisions for estimated losses incurred but not reported (IBNR), as well as estimated provisions for known claims. IBNR reserve estimates are primarily based upon historical loss experience, industry data and other actuarial assumptions. Reserve estimates are adjusted in future periods as actual losses differ from experience.

Duke Energy, through its captive insurance entities, also has reinsurance coverage with third parties for certain losses above a per occurrence and/or aggregate retention. Receivables for reinsurance coverage are recognized when realization is deemed probable.

Preferred Stock

Preferred stock is reviewed to determine the appropriate balance sheet classification and embedded features, such as call options, are evaluated to determine if they should be bifurcated and accounted for separately. Costs directly related to the issuance of preferred stock are recorded as a reduction of the proceeds received. The liability for the dividend is recognized when declared. The accumulated dividends on the cumulative preferred stock is recognized to net income available to Duke Energy Corporation in the EPS calculation. See Note 20 for further information.

Loss Contingencies and Environmental Liabilities

Contingent losses are recorded when it is probable a loss has occurred and the loss can be reasonably estimated. When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, the minimum amount in the range is recorded. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Environmental liabilities are recorded on an undiscounted basis when environmental remediation or other liabilities become probable and can be reasonably estimated. Environmental expenditures related to past operations that do not generate current or future revenues are expensed. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Certain environmental expenditures receive regulatory accounting treatment and are recorded as regulatory assets.

See Notes 4 and 5 for further information.

Severance and Special Termination Benefits

Duke Energy maintains severance plans for the general employee population under which, in general, the longer a terminated employee worked prior to termination the greater the amount of severance benefits provided. A liability for involuntary severance is recorded once an involuntary severance plan is committed to by management if involuntary severances are probable and can be reasonably estimated. For involuntary severance benefits incremental to its ongoing severance plan benefits, the fair value of the obligation is expensed at the communication date if there are no future service requirements or over the required future service period. Duke Energy also offers special termination benefits under voluntary severance programs. Special termination benefits are recorded immediately upon employee acceptance absent a significant retention period. Otherwise, the cost is recorded over the remaining service period. Employee acceptance of voluntary severance benefits is determined by management based on the facts and circumstances of the benefits being offered. See Note 21 for further information.

Guarantees

If necessary, liabilities are recognized at the time of issuance or material modification of a guarantee for the estimated fair value of the obligation it assumes. Fair value is estimated using a probability weighted approach. The obligation is reduced over the term of the guarantee or related contract in a systematic and rational method as risk is reduced. Duke Energy recognizes a liability for the best estimate of its loss due to the nonperformance of the guaranteed party. This liability is recognized at the inception of a guarantee and is updated periodically. See Note 8 for further information.

Income Taxes

Duke Energy and its subsidiaries file a consolidated federal income tax return and other state and foreign jurisdictional returns. The Subsidiary Registrants are parties to a tax-sharing agreement with Duke Energy. Income taxes recorded represent amounts the Subsidiary Registrants would incur as separate C-Corporations. Deferred income taxes have been provided for temporary differences between GAAP and tax bases of assets and liabilities because the differences create taxable or tax-deductible amounts for future periods. ITCs associated with regulated operations are deferred and amortized as a reduction of income tax expense over the estimated useful lives of the related properties.

Accumulated deferred income taxes are valued using the enacted tax rate expected to apply to taxable income in the periods in which the deferred tax asset or liability is expected to be settled or realized. In the event of a change in tax rates, deferred tax assets and liabilities are remeasured as of the enactment date of the new rate. To the extent that the change in the value of the deferred tax represents an obligation to customers, the impact of the remeasurement is deferred to a regulatory liability. Remaining impacts are recorded in income from continuing operations. Duke Energy's results of operations could be impacted if the estimate of the tax effect of reversing temporary differences is not reflective of actual outcomes, is modified to reflect new developments or interpretations of the tax law, revised to incorporate new accounting principles, or changes in the expected timing or manner of a reversal.

Tax-related interest and penalties are recorded in Interest Expense and Other Income and Expenses, net in the Consolidated Statements of Operations.

See Note 24 for further information.

Excise Taxes

Certain excise taxes levied by state or local governments are required to be paid even if not collected from the customer. These taxes are recognized on a gross basis. Taxes for which Duke Energy operates merely as a collection agent for the state and local government are accounted for on a net basis. Excise taxes accounted for on a gross basis within both Operating Revenues and Property and other taxes in the Consolidated Statements of Operations were as follows.


	Years Ended December 31,
(in millions)	2022		2021		2020
Duke Energy	$	449	$	420	$	415
Duke Energy Carolinas	47		44		43
Progress Energy	290		250		249
Duke Energy Progress	25		22		26
Duke Energy Florida	265		228		223
Duke Energy Ohio	104		102		96
Duke Energy Indiana	7		23		25
Piedmont	1		1		2

Dividend Restrictions and Unappropriated Retained Earnings

Duke Energy does not have any current legal, regulatory or other restrictions on paying common stock dividends to shareholders. However, if Duke Energy were to defer dividend payments on the preferred stock, the declaration of common stock dividends would be prohibited. See Note 20 for more information. Additionally, as further described in Note 4, Duke Energy Carolinas, Duke Energy Progress, Duke Energy Ohio, Duke Energy Indiana and Piedmont have restrictions on paying dividends or otherwise advancing funds to Duke Energy due to conditions established by regulators in conjunction with merger transaction approvals. At December 31, 2022, and 2021, an insignificant amount of Duke Energy’s consolidated Retained earnings balance represents undistributed earnings of equity method investments.

New Accounting Standards

The following accounting standard was adopted by the Duke Energy Registrants in 2021.

Leases with Variable Lease Payments. In July 2021, the FASB issued new accounting guidance requiring lessors to classify a lease with variable lease payments that do not depend on a reference index or rate as an operating lease if both of the following are met: (1) the lease would have to be classified as a sales-type or direct financing lease under prior guidance, and (2) the lessor would have recognized a day-one loss. Duke Energy elected to adopt the guidance immediately upon issuance of the new standard and will be applying the new standard prospectively to new lease arrangements meeting the criteria. Duke Energy did not have any lease arrangements that this new accounting guidance materially impacted.

The following accounting standard was adopted by the Duke Energy Registrants in 2020.

Current Expected Credit Losses. In June 2016, the FASB issued new accounting guidance for credit losses. Duke Energy adopted the new accounting guidance for credit losses effective January 1, 2020, using the modified retrospective method of adoption, which does not require restatement of prior year results. Duke Energy did not adopt any practical expedients.

Duke Energy recognizes allowances for credit losses based on management's estimate of losses expected to be incurred over the lives of certain assets or guarantees. Management monitors credit quality, changes in expected credit losses and the appropriateness of the allowance for credit losses on a forward-looking basis. Management reviews the risk of loss periodically as part of the existing assessment of collectability of receivables.

Duke Energy reviews the credit quality of its counterparties as part of its regular risk management process and requires credit enhancements, such as deposits or letters of credit, as appropriate and as allowed by regulators.

Duke Energy recorded cumulative effects of changes in accounting principles related to the adoption of the new credit loss standard for allowances and credit losses of trade and other receivables, insurance receivables and financial guarantees. These amounts are included in the Consolidated Balance Sheets in Receivables, Receivables of VIEs, Other Noncurrent Assets and Other Noncurrent Liabilities. See Notes 8 and 19 for more information.

Duke Energy recorded an adjustment for the cumulative effect of a change in accounting principle due to the adoption of this standard on January 1, 2020, as shown in the table below:


	January 1, 2020
			Duke				Duke		Duke
	Duke		Energy		Progress		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Piedmont
Total pretax impact to Retained Earnings	$	120	$	16	$	2	$	1	$	1	$	1

2. DISPOSITIONS

The following table summarizes the Loss from Discontinued Operations, net of tax recorded on Duke Energy's Consolidated Statements of Operations:


	Years Ended December 31,
(in millions)	2022	2021	2020
Commercial Renewables Disposal Groups	$(1,349)	$(151)	$(14)
Other(a)	26	7	7
Loss from Discontinued Operations, net of tax	$(1,323)	$(144)	$(7)

(a) Amount represents an income tax benefit resulting from tax adjustments for previously sold businesses not related to the Commercial Renewables Disposal Groups.

Sale of Commercial Renewables Segment

In August 2022, Duke Energy announced a strategic review of its commercial renewables business. Since 2007, Duke Energy has built a portfolio of commercial wind, solar and battery projects across the U.S., and established a development pipeline. Duke Energy has developed a strategy to focus on renewables, grid and other investment opportunities within its regulated operations. In November 2022, Duke Energy committed to a plan to sell the Commercial Renewables business segment, excluding the offshore wind contract for Carolina Long Bay, which was moved to the Electric Utilities and Infrastructure (EU&I) segment. Duke Energy is actively marketing the business as two separate disposal groups, the utility-scale solar and wind group and the distributed generation group (collectively, Commercial Renewables Disposal Groups). The sales processes for both Disposal Groups are ongoing and Duke Energy expects to dispose of these groups in the second half of 2023.

Assets Held For Sale and Discontinued Operations

The Commercial Renewables Disposal Groups were classified as held for sale and as discontinued operations in the fourth quarter of 2022. No adjustments were made to the historical activity within the Consolidated Statements of Comprehensive Income, Consolidated Statements of Cash Flows or the Consolidated Statements of Changes in Equity. Unless otherwise noted, the notes to these consolidated financial statements exclude amounts related to discontinued operations for all periods presented.

The following table presents the carrying values of the major classes of Assets held for sale and Liabilities associated with assets held for sale included in Duke Energy's Consolidated Balance Sheets.


	December 31,
(in millions)	2022	2021
Current Assets Held for Sale
Cash and cash equivalents	$10	$3
Receivables, net	107	87
Inventory	88	86
Other	57	56
Total current assets held for sale	262	232
Noncurrent Assets Held for Sale
Property, Plant and Equipment
Cost	6,444	7,323
Accumulated depreciation and amortization	(1,651)	(1,452)
Net property, plant and equipment	4,793	5,871
Operating lease right-of-use assets, net	140	130
Investments in equity method unconsolidated affiliates	522	513
Other	179	181
Total other noncurrent assets held for sale	841	824
Total Assets Held for Sale	$5,896	$6,927
Current Liabilities Associated with Assets Held for Sale
Accounts payable	$122	$98
Taxes accrued	17	18

Other	120	51
Total current liabilities associated with assets held for sale	259	167
Noncurrent Liabilities Associated with Assets Held for Sale


Operating lease liabilities	150	134
Asset retirement obligations	190	175
Other	399	303
Total other noncurrent liabilities associated with assets held for sale	739	612
Total Liabilities Associated with Assets Held for Sale	$998	$779

As of December 31, 2022, the noncontrolling interest balance is $1.6 billion.

The following table presents the results of the Commercial Renewables Disposal Groups, which are included in Loss from Discontinued Operations, net of tax in Duke Energy's Consolidated Statements of Operations.


	Years Ended December 31,
(in millions)	2022	2021	2020
Operating revenues	$465	$476	$502


Operation, maintenance and other	337	343	292
Depreciation and amortization(a)	201	227	200
Property and other taxes	36	34	26


Other income and expenses, net	2	(27)	1
Interest expense	10	72	66
Loss on disposal	1,748	—	—
Loss before income taxes	(1,865)	(227)	(81)
Income tax benefit	(516)	(76)	(67)
Loss from discontinued operations	$(1,349)	$(151)	$(14)
Add: Net loss attributable to noncontrolling interest included in discontinued operations	108	344	296
Net income from discontinued operations attributable to Duke Energy Corporation	$(1,241)	$193	$282

(a) Upon meeting the criteria for assets held for sale, beginning in November 2022 depreciation and amortization expense were ceased.

The Commercial Renewables Disposal Groups' held for sale assets included pretax impairments of approximately $1.7 billion for the year ended December 31, 2022. The impairment was recorded to write-down the carrying amount of the property, plant and equipment assets to the estimated fair value of the business, based on the expected selling price less estimated cost to sell. These losses were included in Loss from Discontinued Operations, net of tax in Duke Energy's Consolidated Statements of Operations and Comprehensive Income. The fair value was primarily determined from the income approach using discounted cash flows but also considered market information obtained through the bidding process. The discounted cash flow model utilized Level 2 and Level 3 inputs. The fair value hierarchy levels are further discussed in Note 17. The impairment will be updated, if necessary, based on the final sales price, after any adjustments at closing for working capital and capital expenditures.

Duke Energy has elected not to separately disclose discontinued operations on Duke Energy's Consolidated Statements of Cash Flows. The following table summarizes Duke Energy's cash flows from discontinued operations related to the Commercial Renewables Disposal Groups.


	Years Ended December 31,
(in millions)	2022	2021	2020
Cash flows provided by (used in):
Operating activities	$213	$62	$466
Investing activities	(802)	(542)	(1,102)

Other Sale Related Matters

Several Duke Energy renewables project companies, located in the Electric Reliability Council of Texas (ERCOT) market, were named in several lawsuits arising out of Texas Storm Uri, which occurred in February 2021. The legal actions related to these lawsuits will remain with Duke Energy and any future activity related to the matters will be presented in discontinued operations. See Note 5 for more information.

The Commercial Renewables Disposal Groups' debt and related interest rate swaps have not been classified as held for sale as they are not currently expected transfer to the buyer, but would be required to be extinguished as a result of the disposition. As of December 31, 2022, the balance of long-term debt including current maturities is $1.5 billion. If the debt and related interest rate swaps do not transfer to the buyer and are terminated early, the expected total loss on extinguishment is approximately $100 million, of which approximately $55 million is expected to be attributable to Duke Energy. The loss would be recorded in discontinued operations when the debt and swaps are terminated. Hedge accounting was discontinued on the related interest rate swaps when the Commercial Renewables Disposal Groups were classified as held for sale as the forecasted transactions being hedged are no longer probable. As a result, a gain of $72 million was recorded in Loss from Discontinued Operations, net of tax in Duke Energy's Consolidated Statements of Operations as of December 31, 2022, of which $54 million is attributable to Duke Energy.

Interest expense and debt issuance costs directly associated with the Commercial Renewables Disposal Groups was allocated to discontinued operations. No interest from corporate level debt was allocated to discontinued operations.

The Commercial Renewables Disposal Groups have entered into negotiations to modify or terminate certain PPAs under which the Commercial Renewables Disposal Groups sell power and RECs from renewable projects to offtakers. Duke Energy expects to pay offtakers approximately $95 million to modify the agreements. Charges related to the modifications will be reflected within Loss From Discontinued Operations in Duke Energy's Consolidated Statements of Operations.

Sale of Minority Interest in Duke Energy Indiana Holdco, LLC

On January 28, 2021, Duke Energy executed an agreement providing for an investment by an affiliate of GIC in Duke Energy Indiana in exchange for a 19.9% minority interest issued by Duke Energy Indiana Holdco, LLC, the holding company for Duke Energy Indiana. The transaction was completed following two closings for an aggregate purchase price of approximately $2.05 billion. The first closing, which occurred on September 8, 2021, resulted in Duke Energy Indiana Holdco, LLC issuing 11.05% of its membership interests in exchange for approximately $1.03 billion or 50% of the purchase price. The difference between the cash consideration received, net of transaction costs of approximately $27 million, and the carrying value of the noncontrolling interest is $545 million and was recorded as an increase to equity. The second closing was completed in December 2022 and resulted in Duke Energy Indiana Holdco, LLC issuing an additional 8.85% of its membership interests in exchange for approximately $1.03 billion. The difference between the cash consideration received, net of transaction costs of approximately $6 million, and the carrying value of the noncontrolling interest is $492 million and was recorded as an increase to equity. Duke Energy retained indirect control of these assets, and, therefore, no gain or loss was recognized on the Consolidated Statements of Operations for either transaction.

3. BUSINESS SEGMENTS

Reportable segments are determined based on information used by the chief operating decision-maker in deciding how to allocate resources and evaluate the performance of the business. Duke Energy evaluates segment performance based on segment income. Segment income is defined as income from continuing operations net of income attributable to noncontrolling interests and preferred stock dividends. Segment income, as discussed below, includes intercompany revenues and expenses that are eliminated on the Consolidated Financial Statements. Certain governance costs are allocated to each segment. In addition, direct interest expense and income taxes are included in segment income.

Products and services are sold between affiliate companies and reportable segments of Duke Energy at cost. Segment assets as presented in the tables that follow exclude all intercompany assets.

Duke Energy

Due to Duke Energy's commitment in the fourth quarter of 2022 to sell the Commercial Renewables business segment, Duke Energy's segment structure now includes the following two segments: EU&I and GU&I. Prior period information has been recast to conform to the current segment structure. See Note 2 for further information on the Commercial Renewables Disposal Groups.

The EU&I segment includes Duke Energy's regulated electric utilities in the Carolinas, Florida and the Midwest. The regulated electric utilities conduct operations through the Subsidiary Registrants that are substantially all regulated and, accordingly, qualify for regulatory accounting treatment. EU&I also includes Duke Energy's electric transmission infrastructure investments and the offshore wind contract for Carolina Long Bay. Refer to Note 2 for further information.

The GU&I segment includes Piedmont, Duke Energy's natural gas local distribution companies in Ohio and Kentucky, and Duke Energy's natural gas storage, midstream pipeline, and renewable natural gas investments. GU&I's operations are substantially all regulated and, accordingly, qualify for regulatory accounting treatment.

The remainder of Duke Energy’s operations is presented as Other, which is primarily comprised of interest expense on holding company debt, unallocated corporate costs and Duke Energy’s wholly owned captive insurance company, Bison. Other also includes Duke Energy's interest in NMC. See Note 13 for additional information on the investment in NMC.

Business segment information is presented in the following tables. Segment assets presented exclude intercompany assets.


	Year Ended December 31, 2022
	Electric		Gas		Total
	Utilities and		Utilities and		Reportable
(in millions)	Infrastructure		Infrastructure		Segments		Other		Eliminations		Total
Unaffiliated Revenues	$	25,990	$	2,748	$	28,738	$	30	$	—	$	28,768
Intersegment Revenues	34		92		126		92		(218)		—
Total Revenues	$	26,024	$	2,840	$	28,864	$	122	$	(218)	$	28,768
Interest Expense	$	1,565	$	182	$	1,747	$	778	$	(86)	$	2,439
Depreciation and amortization	4,550		327		4,877		236		(27)		5,086
Equity in earnings of unconsolidated affiliates	7		20		27		86		—		113
Income tax expense (benefit)	536		8		544		(244)		—		300
Segment income (loss)(a)(b)	3,929		468		4,397		(737)		(1)		3,659
Less noncontrolling interest											95
Add back preferred stock dividend											106
Discontinued operations											(1,215)
Net income											$	2,455
Capital investments expenditures and acquisitions(c)	$	8,985	$	1,295	$	10,280	$	1,139	$	—	$	11,419
Segment assets(d)	152,104		16,411		168,515		9,571		—		178,086

(a) EU&I includes $386 million recorded within Impairment of assets and other charges, $46 million within Regulated electric revenues and $34 million within Noncontrolling Interests related to the Duke Energy Indiana court rulings on coal ash on the Consolidated Statements of Operations. See Note 4 for additional information.

(b) Other includes $72 million recorded within Impairment of assets and other charges, $71 million within Operations, maintenance and other and a $7 million gain within Gains on sales of other assets related to costs attributable to business transformation, including long-term real estate strategy changes and workforce realignment on the Consolidated Statements of Operations; it also includes $25 million recorded within Operations, maintenance and other related to litigation on the Consolidated Statements of Operations.

(c) Other includes capital investments expenditures and acquisitions related to the Commercial Renewables Disposal Groups.

(d) Other includes Assets Held for Sale balances related to the Commercial Renewables Disposal Groups. Refer to Note 2 for further information.


	Year Ended December 31, 2021
	Electric		Gas		Total
	Utilities and		Utilities and		Reportable
(in millions)	Infrastructure		Infrastructure		Segments		Other		Eliminations		Total
Unaffiliated Revenues	$	22,570	$	2,022	$	24,592	$	29	$	—	$	24,621
Intersegment Revenues	33		90		123		84		(207)		—
Total Revenues	$	22,603	$	2,112	$	24,715	$	113	$	(207)	$	24,621
Interest Expense	$	1,432	$	142	$	1,574	$	643	$	(10)	$	2,207
Depreciation and amortization	4,251		303		4,554		236		(28)		4,762
Equity in earnings of unconsolidated affiliates	7		8		15		47		—		62
Income tax expense (benefit)	494		55		549		(281)		—		268
Segment income (loss)(a)(b)(c)	3,850		396		4,246		(641)		(3)		3,602
Less noncontrolling interest											329
Add back preferred stock dividend											106
Discontinued operations											200
Net income											$	3,579
Capital investments expenditures and acquisitions(d)	$	7,653	$	1,271	$	8,924	$	828	$	—	$	9,752
Segment assets(e)	143,841		15,179		159,020		10,567		—		169,587

(a) EU&I includes $160 million of expense recorded within Impairment of assets and other charges, $77 million of income within Other Income and expenses, $5 million of expense within Operations, maintenance and other, $13 million of income within regulated operating revenues, $3 million of expense within interest expense and $6 million of expense within Depreciation and amortization on the Duke Energy Carolinas' Consolidated Statement of Operations related to the South Carolina Supreme Court decision on coal ash and insurance proceeds; it also includes $42 million of expense recorded within Impairment of assets and other charges, $34 million of income within Other Income and expenses, $7 million of expense within Operations, maintenance, and other, $15 million of income within Regulated electric operating revenues, $5 million of expense within interest expense and $1 million of expense within Depreciation and amortization on the Duke Energy Progress' Consolidated Statement of Operations. See Notes 4 and 5 for more information.

(b) GU&I includes $20 million, recorded within Equity in earnings (losses) of unconsolidated affiliates on the Consolidated Statements of Operations, related to natural gas pipeline investments. See Note 4 for additional information.

(c) Other includes $133 million recorded within Impairment of assets and other charges, $42 million within Operations, maintenance and other, and $17 million within Depreciation and amortization on the Consolidated Statements of Operations, related to the workplace and workforce realignment. See Note 11 for additional information.

(d) Other includes capital investments expenditures and acquisitions related to the Commercial Renewables Disposal Groups.

(e) Other includes Assets Held for Sale balances related to the Commercial Renewables Disposal Groups. Refer to Note 2 for further information.


	Year Ended December 31, 2020
	Electric		Gas		Total
	Utilities and		Utilities and		Reportable
(in millions)	Infrastructure		Infrastructure		Segments		Other		Eliminations		Total
Unaffiliated Revenues	$	21,687	$	1,653	$	23,340	$	26	$	—	$	23,366
Intersegment Revenues	33		95		128		73		(201)		—
Total Revenues	$	21,720	$	1,748	$	23,468	$	99	$	(201)	$	23,366
Interest Expense	$	1,320	$	135	$	1,455	$	657	$	(15)	$	2,097
Depreciation and amortization	4,068		258		4,326		207		(29)		4,504
Equity in (losses) earnings of unconsolidated affiliates	(1)		(2,017)		(2,018)		13		—		(2,005)
Income tax expense (benefit)	340		(349)		(9)		(160)		—		(169)
Segment income (loss)(a)(b)(c)	2,669		(1,266)		1,403		(418)		(4)		981
Less noncontrolling interest											295
Add back preferred stock dividend											107
Discontinued operations											289
Net income											$	1,082
Capital investments expenditures and acquisitions(d)	$	7,629	$	1,309	$	8,938	$	1,483	$	—	$	10,421
Segment assets(e)	138,225		13,849		152,074		10,314		—		162,388

(a) EU&I includes $948 million of Impairment of assets and other charges and a reversal of $152 million included in Regulated electric operating revenue related to the CCR Settlement Agreement filed with the NCUC. Additionally, EU&I includes $19 million of Impairment of assets and other charges related to the Clemson University Combined Heat and Power Plant, $5 million of Impairment charges related to the natural gas pipeline assets and $16 million of shareholder contributions within Operations, maintenance and other related to Duke Energy Carolinas' and Duke Energy Progress' 2019 North Carolina rate cases. See Note 4 for additional information.

(b) GU&I includes $2.1 billion recorded within Equity in (losses) earnings of unconsolidated affiliates and $7 million of Impairment of assets and other charges related to natural gas pipeline investments. See Notes 4 and 13 for additional information.

(c) Other includes a $98 million reversal of 2018 severance costs due to a partial settlement in the Duke Energy Carolinas' 2019 North Carolina rate case. See Note 21 for additional information.

(d) Other includes capital investments expenditures and acquisitions related to the Commercial Renewables Disposal Groups.

(e) Other includes Assets Held for Sale balances related to the Commercial Renewables Disposal Groups. Refer to Note 2 for further information.

Geographical Information

Substantially all assets and revenues from continuing operations are within the U.S.

Major Customers

For the year ended December 31, 2022, revenues from one customer of Duke Energy Progress are $684 million. Duke Energy Progress has one reportable segment, Electric Utilities and Infrastructure. No other Subsidiary Registrant has an individual customer representing more than 10% of its revenues for the year ended December 31, 2022.

Products and Services

The following table summarizes revenues of the reportable segments by type.


	Retail		Wholesale		Retail				Total
(in millions)	Electric		Electric		Natural Gas		Other		Revenues
2022
Electric Utilities and Infrastructure	$	22,036	$	2,882	$	—	$	1,106	$	26,024
Gas Utilities and Infrastructure	—		—		2,535		305		2,840

Total Reportable Segments	$	22,036	$	2,882	$	2,535	$	1,411	$	28,864
2021
Electric Utilities and Infrastructure	$	19,410	$	2,216	$	—	$	977	$	22,603
Gas Utilities and Infrastructure	—		—		2,025		87		2,112

Total Reportable Segments	$	19,410	$	2,216	$	2,025	$	1,064	$	24,715
2020
Electric Utilities and Infrastructure	$	18,898	$	1,878	$	—	$	944	$	21,720
Gas Utilities and Infrastructure	—		—		1,691		57		1,748

Total Reportable Segments	$	18,898	$	1,878	$	1,691	$	1,001	$	23,468

Duke Energy Ohio

Duke Energy Ohio has two reportable segments, EU&I and GU&I.

EU&I transmits and distributes electricity in portions of Ohio and generates, distributes and sells electricity in portions of Northern Kentucky. GU&I transports and sells natural gas in portions of Ohio and Northern Kentucky. Both reportable segments conduct operations primarily through Duke Energy Ohio and its wholly owned subsidiary, Duke Energy Kentucky. The remainder of Duke Energy Ohio's operations is presented as Other.

All Duke Energy Ohio assets and revenues from continuing operations are within the U.S.


	Year Ended December 31, 2022
	Electric		Gas		Total
	Utilities and		Utilities and		Reportable
(in millions)	Infrastructure		Infrastructure		Segments		Other		Eliminations		Total


Total revenues	$	1,798	$	716	$	2,514	$	—	$	—	$	2,514
Interest expense	$	86	$	43	$	129	$	—	$	—	$	129
Depreciation and amortization	221		103		324		—		—		324
Income tax expense (benefit)	24		(43)		(19)		(2)		—		(21)
Segment income (loss)/Net income	189		121		310		(8)		—		302


Capital expenditures	$	488	$	362	$	850	$	—	$	—	$	850
Segment assets	7,504		4,164		11,668		14		(176)		11,506


	Year Ended December 31, 2021
	Electric		Gas		Total
	Utilities and		Utilities and		Reportable
(in millions)	Infrastructure		Infrastructure		Segments		Other		Eliminations		Total


Total revenues	$	1,493	$	544	$	2,037	$	—	$	—	$	2,037
Interest expense	$	87	$	24	$	111	$	—	$	—	$	111
Depreciation and amortization	217		90		307		—		—		307
Income tax expense (benefit)	15		19		34		(4)		—		30
Segment income (loss)/Net Income	141		78		219		(15)		—		204


Capital expenditures	$	486	$	362	$	848	$	—	$	—	$	848
Segment assets	6,882		3,892		10,774		29		(29)		10,774


	Year Ended December 31, 2020
	Electric		Gas		Total
	Utilities and		Utilities and		Reportable
(in millions)	Infrastructure		Infrastructure		Segments		Other		Eliminations		Total


Total revenues	$	1,405	$	453	$	1,858	$	—	$	—	$	1,858
Interest expense	$	85	$	17	$	102	$	—	$	—	$	102
Depreciation and amortization	200		78		278		—		—		278
Income tax expense (benefit)	19		26		45		(2)		—		43
Segment income (loss)	162		96		258		(6)		—		252


Capital expenditures	$	548	$	286	$	834	$	—	$	—	$	834
Segment assets	6,615		3,380		9,995		32		(2)		10,025

4. REGULATORY MATTERS

REGULATORY ASSETS AND LIABILITIES

The Duke Energy Registrants record regulatory assets and liabilities that result from the ratemaking process. See Note 1 for further information.

The following tables present the regulatory assets and liabilities recorded on the Consolidated Balance Sheets of Duke Energy and Progress Energy. See separate tables below for balances by individual registrant.


	Duke Energy				Progress Energy
	December 31,				December 31,
(in millions)	2022		2021		2022		2021
Regulatory Assets
AROs – coal ash	$	3,205	$	3,408	$	1,429	$	1,399
AROs – nuclear and other	945		684		884		620
Deferred fuel and purchased power	3,866		1,253		2,060		718
Accrued pension and OPEB	2,336		2,017		759		725
Storm cost securitized balance, net	940		991		720		759
Nuclear asset securitized balance, net	881		937		881		937
Debt fair value adjustment	829		884		—		—
Storm cost deferrals	666		213		559		189
Hedge costs deferrals	378		348		128		137
Post-in-service carrying costs (PISCC) and deferred operating expenses	342		356		42		47
Retired generation facilities	316		357		243		265
Deferred asset – Lee and Harris COLA	288		317		21		21
Advanced metering infrastructure (AMI)	283		311		111		130
Customer connect project	271		242		136		124
Costs of removal regulatory asset	221		107		221		107
Vacation accrual	222		221		43		42
Incremental COVID-19 expenses	210		87		78		28
CEP deferral	190		161		—		—
Demand side management (DSM)/Energy efficiency (EE)	189		235		188		230
Derivatives – natural gas supply contracts	168		139		—		—
NCEMPA deferrals	157		165		157		165
Nuclear deferral	154		120		64		42
Deferred pipeline integrity costs	121		108		—		—
COR settlement	120		123		32		32
Deferred coal ash handling system costs	92		90		25		23
Qualifying facility contract buyouts	81		94		81		94
Amounts due from customers	57		85		—		—
Propane caverns	26		—		—		—
Deferred severance charges	21		54		7		18
Manufactured gas plant (MGP)	—		104		—		—




Other	555		426		110		87
Total regulatory assets	18,130		14,637		8,979		6,939
Less: current portion	3,485		2,150		1,833		1,030
Total noncurrent regulatory assets	$	14,645	$	12,487	$	7,146	$	5,909
Regulatory Liabilities
Net regulatory liability related to income taxes	$	6,462	$	7,199	$	2,192	$	2,394
Costs of removal	5,151		6,150		2,269		2,955
AROs – nuclear and other	1,038		2,053		—		—
Hedge cost deferrals	683		364		252		155
Accrued pension and OPEB	211		213		—		—
DOE Settlement	154		—		154		—
Provision for rate refunds	78		274		28		87

Amounts to be refunded to customers	45		—		—		—
Other	1,226		1,110		434		453
Total regulatory liabilities	15,048		17,363		5,329		6,044
Less: current portion	1,466		1,211		576		478
Total noncurrent regulatory liabilities	$	13,582	$	16,152	$	4,753	$	5,566

Descriptions of regulatory assets and liabilities summarized in the tables above and below follow. See tables below for recovery and amortization periods at the separate registrants.

AROs – coal ash. Represents deferred depreciation and accretion related to the legal obligation to close ash basins. The costs are deferred until recovery treatment has been determined. See Notes 1 and 10 for additional information.

AROs – nuclear and other. Represents regulatory assets or liabilities, including deferred depreciation and accretion, related to legal obligations associated with the future retirement of property, plant and equipment, excluding amounts related to coal ash. The AROs relate primarily to decommissioning nuclear power facilities. The amounts also include certain deferred gains and losses on NDTF investments. See Notes 1 and 10 for additional information.

Deferred fuel and purchased power. Represents certain energy-related costs that are recoverable or refundable as approved by the applicable regulatory body.

Accrued pension and OPEB. Accrued pension and OPEB represent regulatory assets and liabilities related to each of the Duke Energy Registrants’ respective shares of unrecognized actuarial gains and losses and unrecognized prior service cost and credit attributable to Duke Energy’s pension plans and OPEB plans. The regulatory asset or liability is amortized with the recognition of actuarial gains and losses and prior service cost and credit to net periodic benefit costs for pension and OPEB plans. The accrued pension and OPEB regulatory assets are expected to be recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail.

Storm cost securitized balance, net. Represents the North Carolina portion of storm restoration expenditures related to Hurricane Florence, Hurricane Michael, Hurricane Dorian and Winter Storm Diego (2018 and 2019 events).

Nuclear asset securitized balance, net. Represents the balance associated with Crystal River Unit 3 retirement approved for recovery by the FPSC on September 15, 2015, and the upfront financing costs securitized in 2016 with issuance of the associated bonds. The regulatory asset balance is net of the AFUDC equity portion.

Debt fair value adjustment. Purchase accounting adjustments recorded to state the carrying value of Progress Energy and Piedmont at fair value in connection with the 2012 and 2016 mergers, respectively. Amount is amortized over the life of the related debt.

Storm cost deferrals. Represents deferred incremental costs incurred related to major weather-related events.

Hedge costs deferrals. Amounts relate to unrealized gains and losses on derivatives recorded as a regulatory asset or liability, respectively, until the contracts are settled.

Post-in-service carrying costs (PISCC) and deferred operating expenses. Represents deferred depreciation and operating expenses as well as carrying costs on the portion of capital expenditures placed in service but not yet reflected in retail rates as plant in service.

Retired generation facilities. Represents amounts to be recovered for facilities that have been retired and are probable of recovery.

Deferred asset – Lee and Harris COLA. Represents deferred costs incurred for the canceled Lee and Harris nuclear projects.

AMI. Represents deferred costs related to the installation of AMI meters and remaining net book value of non-AMI meters to be replaced at Duke Energy Carolinas, net book value of existing meters at Duke Energy Florida, Duke Energy Progress and Duke Energy Ohio and future recovery of net book value of electromechanical meters that have been replaced with AMI meters at Duke Energy Indiana.

Customer connect project. Represents incremental operating expenses and carrying costs on deferred amounts related to the deployment of the new customer information system.

Vacation accrual. Represents vacation entitlement, which is generally recovered in the following year.

Incremental COVID-19 expenses. Represents incremental costs related to ensuring continuity and quality of service in a safe manner during the COVID-19 pandemic.

CEP deferral. Represents deferred depreciation, PISCC and deferred property tax for Duke Energy Ohio Gas capital assets for the Capital Expenditure Program (CEP).

DSM/EE. Deferred costs related to various DSM and EE programs recoverable through various mechanisms.

Derivatives – natural gas supply contracts. Represents costs for certain long-dated, fixed quantity forward natural gas supply contracts, which are recoverable through PGA clauses.

NCEMPA deferrals. Represents retail allocated cost deferrals and returns associated with the additional ownership interest in assets acquired from NCEMPA in 2015.

Nuclear deferral. Includes amounts related to levelizing nuclear plant outage costs, which allows for the recognition of nuclear outage expenses over the refueling cycle rather than when the outage occurs, resulting in the deferral of operations and maintenance costs associated with refueling.

Deferred pipeline integrity costs. Represents pipeline integrity management costs in compliance with federal regulations.

COR settlement. Represents approved COR settlements that are being amortized over the average remaining lives, at the time of approval, of the associated assets.

Deferred coal ash handling system costs. Represents deferred depreciation and returns associated with capital assets related to converting the ash handling system from wet to dry.

Qualifying facility contract buyouts. Represents termination payments for regulatory recovery through the capacity clause.

Amounts due from customers. Relates primarily to margin decoupling and IMR recovery mechanisms.

Costs of removal regulatory asset. Represents the excess of spend over funds received from customers to cover the future removal of property, plant and equipment from retired or abandoned sites as property is retired, net of certain deferred gains on NDTF investments.

Propane Caverns. Represents amounts for costs related to propane inventory, the net book value of remaining assets and decommissioning costs at Duke Energy Ohio.

MGP. Represents remediation costs incurred at former MGP sites and the deferral of costs to be incurred at Duke Energy Ohio's East End and West End sites.

Net regulatory liability related to income taxes. Amounts for all registrants include regulatory liabilities related primarily to impacts from the Tax Act. See Note 24 for additional information. Amounts have no immediate impact on rate base as regulatory assets are offset by deferred tax liabilities.

Costs of removal. Represents funds received from customers to cover the future removal of property, plant and equipment from retired or abandoned sites as property is retired. Also includes certain deferred gains on NDTF investments.

DOE Settlement. Represents litigation settlement funds received resulting from the DOE’s failure to accept spent nuclear fuel and other radioactive waste from the Crystal River Unit 3 during 2014-2018 as required under the Nuclear Waste Policy Act.

Provision for rate refunds. Represents estimated amounts due to customers based on recording interim rates subject to refund.

RESTRICTIONS ON THE ABILITY OF CERTAIN SUBSIDIARIES TO MAKE DIVIDENDS, ADVANCES AND LOANS TO DUKE ENERGY

As a condition to the approval of merger transactions, the NCUC, PSCSC, PUCO, KPSC and IURC imposed conditions on the ability of Duke Energy Carolinas, Duke Energy Progress, Duke Energy Ohio, Duke Energy Kentucky, Duke Energy Indiana and Piedmont to transfer funds to Duke Energy through loans or advances, as well as restricted amounts available to pay dividends to Duke Energy. Certain subsidiaries may transfer funds to the Parent by obtaining approval of the respective state regulatory commissions. These conditions imposed restrictions on the ability of the public utility subsidiaries to pay cash dividends as discussed below.

Duke Energy Progress and Duke Energy Florida also have restrictions imposed by their first mortgage bond indentures, which in certain circumstances, limit their ability to make cash dividends or distributions on common stock. Amounts restricted as a result of these provisions were not material at December 31, 2022.

Additionally, certain other subsidiaries of Duke Energy have restrictions on their ability to dividend, loan or advance funds to Duke Energy due to specific legal or regulatory restrictions, including, but not limited to, minimum working capital and tangible net worth requirements.

The restrictions discussed below were not a material amount of Duke Energy's and Progress Energy's net assets at December 31, 2022.

Duke Energy Carolinas

Duke Energy Carolinas must limit cumulative distributions subsequent to mergers to (i) the amount of retained earnings on the day prior to the closing of the mergers, plus (ii) any future earnings recorded.

Duke Energy Progress

Duke Energy Progress must limit cumulative distributions subsequent to the mergers between Duke Energy and Progress Energy and Duke Energy and Piedmont to (i) the amount of retained earnings on the day prior to the closing of the respective mergers, plus (ii) any future earnings recorded.

Duke Energy Ohio

Duke Energy Ohio will not declare and pay dividends out of capital or unearned surplus without the prior authorization of the PUCO. Duke Energy Ohio received FERC and PUCO approval to pay dividends from its equity accounts that are reflective of the amount that it would have in its retained earnings account had push-down accounting for the Cinergy merger not been applied to Duke Energy Ohio’s balance sheet. The conditions include a commitment from Duke Energy Ohio that equity, adjusted to remove the impacts of push-down accounting, will not fall below 30% of total capital.

Duke Energy Kentucky is required to pay dividends solely out of retained earnings and to maintain a minimum of 35% equity in its capital structure.

Duke Energy Indiana

Duke Energy Indiana must limit cumulative distributions subsequent to the merger between Duke Energy and Cinergy to (i) the amount of retained earnings on the day prior to the closing of the merger, plus (ii) any future earnings recorded. In addition, Duke Energy Indiana will not declare and pay dividends out of capital or unearned surplus without prior authorization of the IURC.

Piedmont

Piedmont must limit cumulative distributions subsequent to the acquisition of Piedmont by Duke Energy to (i) the amount of retained earnings on the day prior to the closing of the merger, plus (ii) any future earnings recorded.

RATE-RELATED INFORMATION

The NCUC, PSCSC, FPSC, IURC, PUCO, TPUC and KPSC approve rates for retail electric and natural gas services within their states. The FERC approves rates for electric sales to wholesale customers served under cost-based rates (excluding Ohio and Indiana), as well as sales of transmission service. The FERC also regulates certification and siting of new interstate natural gas pipeline projects.

Duke Energy Carolinas and Duke Energy Progress

Hurricane Ian

In late September and early October 2022, Hurricane Ian inflicted severe damage to the Duke Energy Carolinas and Duke Energy Progress territories in North Carolina and South Carolina. Approximately 950,000 customers were impacted. Total estimated operation and maintenance expenses incurred for restoration efforts for the year ended December 31, 2022, were approximately $100 million, with an additional $9 million in capital investments. Approximately $83 million of the operation and maintenance expenses are deferred in Regulatory assets within Other Noncurrent Assets on the Consolidated Balance Sheets as of December 31, 2022 ($40 million and $43 million for Duke Energy Carolinas and Duke Energy Progress, respectively). Duke Energy Carolinas and Duke Energy Progress have regulatory tools to recover storm costs including deferral and securitization. These estimates could change as Duke Energy Carolinas and Duke Energy Progress receive additional information on actual costs.

Carbon Plan Proceeding

On October 13, 2021, North Carolina enacted legislation (Energy Solutions for North Carolina or HB 951) that established a framework overseen by the NCUC to advance North Carolina CO2 emission reductions from electric generating facilities in the state through the use of least cost planning while providing for continued reliability and affordable rates for customers. Among other things, HB 951 directed that the NCUC approve an initial carbon plan (Carbon Plan) by December 31, 2022, taking all reasonable steps to achieve a 70% reduction in CO2 emissions from public utilities’ electric generating facilities in the state by 2030 (from 2005 levels) and achieve carbon neutrality from electric generating facilities by 2050 while maintaining affordability and reliability for customers. On May 16, 2022, Duke Energy Carolinas and Duke Energy Progress filed their proposed Carolinas Carbon Plan (Proposed Plan) with the NCUC.

The NCUC issued an order on December 30, 2022, adopting the first Carbon Plan. The order recognizes the value of an “all-of-the-above” approach to achieving CO2 emission reductions and established a set of near-term procurement and development activities needed to continue progress towards the targeted CO2 reductions, along with the schedule for the future biennial updates to the Carbon Plan. The approved near-term action plan includes procurement and development of solar, storage and hydrogen-capable natural gas generation at levels consistent with the Proposed Plan, along with upgrading key transmission facilities to strengthen the grid, improve resilience for customers and interconnect new solar generation and stakeholder engagement activities for onshore wind generation (in all cases, subject to any further applicable regulatory processes). The order also approved early development activities for long lead-time resources, including new nuclear, pumped-hydro storage and offshore wind transmission development. The NCUC affirmed the utility ownership structure required in HB 951; all new generation facilities or other resources selected by the NCUC to achieve the CO2 emission reductions shall be owned and recovered on a cost-of-service basis by the utilities, with a carveout for 45% of solar and solar plus storage generation to be procured through long-term purchase power agreements with third parties. The order approves continued utilization of the remaining coal-fired generation assets, ensuring that appropriate replacement generating units and associated transmission infrastructure are in service before existing generating units are retired and providing an orderly transition out of coal generation by 2035.

Storm Cost Securitization Legislation

On June 15, 2022, the South Carolina General Assembly unanimously adopted S. 1077 (Act 227) in both the House and Senate and the bill was signed into law on June 17, 2022. The legislation enables the PSCSC to permit the issuance of bonds for the payment of storm costs and the creation of a storm charge for repayment.

On August 5, 2022, Duke Energy Progress filed a petition with the PSCSC for review and approval of deferred storm costs to be securitized of approximately $223 million. The evidentiary hearing is scheduled to begin on or after March 1, 2023. On February 7, 2023, a stipulation was reached with all parties in the proceeding regarding certain items identified through the Office of Regulatory Staff (ORS) audit of storm costs. The final amount for securitization will depend on the outcome of the hearing. Duke Energy Progress cannot predict the outcome of this matter.

Duke Energy Carolinas

Regulatory Assets and Liabilities

The following tables present the regulatory assets and liabilities recorded on Duke Energy Carolinas' Consolidated Balance Sheets.


	December 31,				Earns/Pays	Recovery/Refund
(in millions)	2022		2021		a Return	Period Ends
Regulatory Assets(a)
AROs – coal ash	$	1,391	$	1,227	(g)	(b)

Deferred fuel and purchased power(i)	1,614		339		(e)	2024
Accrued pension and OPEB(c)	614		365		Yes	(h)
Storm cost securitized balance, net	220		232			2041


Storm cost deferrals	93		22		Yes	(b)
Hedge costs deferrals(c)	228		171		Yes	(b)
PISCC and deferred operating expenses(c)	30		31		Yes	(b)
Retired generation facilities(c)	39		54		Yes	(b)
Deferred asset – Lee COLA	267		296			(b)
AMI	139		140		Yes	(b)
Customer connect project	62		66		Yes	(b)

Vacation accrual	84		83			2023
Incremental COVID-19 expenses	127		51		Yes	(b)




Nuclear deferral	90		78			2024

COR settlement	88		91		Yes	(b)
Deferred coal ash handling system costs	67		67		Yes	(b)









Other	235		166			(b)
Total regulatory assets	5,388		3,479
Less: current portion	1,095		544
Total noncurrent regulatory assets	$	4,293	$	2,935
Regulatory Liabilities(a)
Net regulatory liability related to income taxes(d)	$	2,475	$	2,785		(b)
Costs of removal(c)	1,769		2,009		Yes	(f)
AROs – nuclear and other	1,038		2,053			(b)
Hedge cost deferrals	350		209			(b)
Accrued pension and OPEB(c)	44		44		Yes	(h)

Provision for rate refunds	50		124		Yes	(b)


Other	587		461			(b)
Total regulatory liabilities	6,313		7,685
Less: current portion	530		487
Total noncurrent regulatory liabilities	$	5,783	$	7,198

(a) Regulatory assets and liabilities are excluded from rate base unless otherwise noted.

(b) The expected recovery or refund period varies or has not been determined.

(d) Includes regulatory liabilities related to the change in the federal tax rate as a result of the Tax Act and the change in the North Carolina tax rate, both discussed in Note 24. Portions are included in rate base.

(e) Pays interest on over-recovered costs in North Carolina. Includes certain purchased power costs in North Carolina and South Carolina and costs of distributed energy in South Carolina.

(f) Recovered over the life of the associated assets.

(g) Earns a debt and equity return on coal ash expenditures for North Carolina and South Carolina retail customers as permitted by various regulatory orders.

(h) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail.

(i) Duke Energy Carolinas submitted a fuel filing to the NCUC in May 2022 for recovery of $327 million, which included deferrals through January 2022. This amount is expected to be recovered through August 2023. The next filing will be made in the first quarter of 2023. Duke Energy Carolinas submitted a fuel filing to the PSCSC in July 2022 for recovery of $79 million, which included deferrals through May 2022. The amount is expected to be recovered through September 2023. The next filing will be made in the third quarter of 2023.

2023 North Carolina Rate Case

On January 19, 2023, Duke Energy Carolinas filed a PBR application with the NCUC to request an increase in base rate retail revenues. The PBR Application includes an MYRP to recover projected capital investments during the three year MYRP period. In addition to the MYRP, the PBR Application includes an Earnings Sharing Mechanism, Residential Decoupling Mechanism and Performance Incentive Mechanisms as required by HB 951. If approved, the overall retail revenue increase would be $501 million in Year 1, $172 million in Year 2 and $150 million in Year 3, for a combined total of $823 million or 15.7% by early 2026. The rate increase is driven primarily by major transmission and distribution investments since the last rate case and projected in the MYRP, as well as investments in energy storage and solar assets included in the MYRP consistent with the Carbon Plan. Duke Energy Carolinas plans to implement temporary rates, subject to refund, on September 1, 2023, and has requested permanent rates be effective by January 1, 2024. Duke Energy Carolinas cannot predict the outcome of this matter.

Oconee Nuclear Station Subsequent License Renewal

On June 7, 2021, Duke Energy Carolinas filed a subsequent license renewal (SLR) application for the Oconee Nuclear Station (ONS) with the U.S. Nuclear Regulatory Commission (NRC) to renew ONS’s operating license for an additional 20 years. The SLR would extend operations of the facility from 60 to 80 years. The current licenses for units 1 and 2 expire in 2033 and the license for unit 3 expires in 2034. By a Federal Register Notice dated July 28, 2021, the NRC provided a 60-day comment period for persons whose interest may be affected by the issuance of a subsequent renewed license for ONS to file a request for a hearing and a petition for leave to intervene. On September 27, 2021, Beyond Nuclear and Sierra Club (Petitioners) filed a Hearing Request and Petition to Intervene (Hearing Request) and a Petition for Waiver. The Hearing Request proposed three contentions and claimed that Duke Energy Carolinas did not satisfy the National Environmental Policy Act (NEPA) of 1969, as amended, or the NRC’s NEPA-implementing regulations. Following Duke Energy Carolinas' answer and the Petitioners' reply, on February 11, 2022, the Atomic Safety and Licensing Board (ASLB) issued its decision on the Hearing Request and found that the Petitioners failed to establish that the proposed contentions are litigable. The ASLB also denied the Petitioners' Petition for Waiver and terminated the proceeding.

On February 24, 2022, the NRC issued a decision in the SLR appeal related to Florida Power and Light's Turkey Point nuclear generating station in Florida. The NRC ruled that the NRC’s license renewal Generic Environmental Impact Statement (GEIS) does not apply to SLR because the GEIS does not address SLR. The decision overturned a 2020 NRC decision that found the GEIS applies to SLR. Although Turkey Point is not owned or operated by a Duke Energy Registrant, the NRC’s order applies to all SLR applicants, including ONS. The NRC order also indicated no subsequent renewed licenses will be issued until the NRC staff has completed an adequate NEPA review for each application. On April 5, 2022, the NRC approved a 24-month rulemaking plan that will enable the NRC staff to complete an adequate NEPA review. Although an SLR applicant may wait until the rulemaking is completed, the NRC also noted that an applicant may submit a supplement to its environmental report providing information on environmental impacts during the SLR period prior to the rulemaking being completed. On November 7, 2022, Duke Energy Carolinas submitted a supplement to its environmental report addressing environmental impacts during the SLR period. On December 19, 2022, the NRC published a notice in the Federal Register that the NRC will conduct a limited scoping process to gather additional information necessary to prepare an environmental impact statement (EIS) to evaluate the environmental impacts at ONS during the SLR period. The NRC received comments from the EPA and the Petitioners and these comments identify eighteen potential impacts that should be considered by the NRC in the EIS, which include, but are not limited to, climate change and flooding, environmental justice, severe accidents, and external events. Currently, the NRC expects to publish a draft EIS in October 2023.

On December 19, 2022, the NRC issued the Safety Evaluation Report (SER) for the safety portion of the SLR application. The NRC determined Duke Energy Carolinas met the requirements of the applicable regulations and identified actions that have been taken or will be taken to manage the effects of aging and address time-limited analyses. Duke Energy Carolinas and the NRC met with the Advisory Committee on Reactor Safeguards (ACRS) on February 2, 2023, to discuss issues regarding the SER and SLR application, after which the ACRS will issue a report discussing the result of its review.

Although the NRC’s GEIS applicability decision will delay completion of the SLR proceeding, Duke Energy Carolinas does not believe it changes the probability that the ONS subsequent renewed licenses will ultimately be issued, although Duke Energy Carolinas cannot guarantee the outcome of the license application process.

Duke Energy Carolinas and Duke Energy Progress intend to seek renewal of operating licenses and 20-year license extensions for all of their nuclear stations. New depreciation rates were implemented for all of the nuclear facilities during the second quarter of 2021. Duke Energy Carolinas and Duke Energy Progress cannot predict the outcome of these additional relicensing proceedings.

Duke Energy Progress

Regulatory Assets and Liabilities

The following tables present the regulatory assets and liabilities recorded on Duke Energy Progress' Consolidated Balance Sheets.


	December 31,				Earns/Pays	Recovery/Refund
(in millions)	2022		2021		a Return	Period Ends
Regulatory Assets(a)
AROs – coal ash	$	1,418	$	1,389	(g)	(b)
AROs – nuclear and other	869		613			(c)
Deferred fuel and purchased power(l)	705		303		(e)	2024
Accrued pension and OPEB(d)	417		351		Yes	(j)
Storm cost securitized balance, net	720		759			2041


Storm cost deferrals	234		170		Yes	(b)
Hedge costs deferrals	55		60			(b)
PISCC and deferred operating expenses	42		47		Yes	2054
Retired generation facilities	149		171		Yes	(b)
Deferred asset - Harris COLA	21		21			(b)
AMI	81		92		Yes	(b)
Customer connect project	54		57		Yes	(b)

Vacation accrual	43		42			2023
Incremental COVID-19 expenses	78		28		Yes	(b)

DSM/EE(d)	180		218		(h)	(h)

NCEMPA deferrals	157		165		(f)	2042
Nuclear deferral	64		42			2024

COR settlement	32		32		Yes	(b)
Deferred coal ash handling system costs	25		23		Yes	(b)









Other	70		68			(b)
Total regulatory assets	5,414		4,651
Less: current portion	690		533
Total noncurrent regulatory assets	$	4,724	$	4,118
Regulatory Liabilities(a)
Net regulatory liability related to income taxes(k)	$	1,559	$	1,695		(b)
Costs of removal(d)	2,269		2,955		Yes	(i)

Hedge cost deferrals	252		155			(b)


Provision for rate refunds	28		87		Yes	(b)


Other	344		357			(b)
Total regulatory liabilities	4,452		5,249
Less: current portion	332		381
Total noncurrent regulatory liabilities	$	4,120	$	4,868

(a) Regulatory assets and liabilities are excluded from rate base unless otherwise noted.

(b) The expected recovery or refund period varies or has not been determined.

(d) Included in rate base.

(e) Pays interest on over-recovered costs in North Carolina. Includes certain purchased power costs in North Carolina and South Carolina and costs of distributed energy in South Carolina.

(f) South Carolina retail allocated costs are earning a return.

(g) Earns a debt and equity return on coal ash expenditures for North Carolina and South Carolina retail customers as permitted by various regulatory orders.

(h) Includes incentives on DSM/EE investments and is recovered through an annual rider mechanism.

(i) Recovered over the life of the associated assets.

(j) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail.

(k) Includes regulatory liabilities related to the change in the federal tax rate as a result of the Tax Act and the change in the North Carolina tax rate, both discussed in Note 24. Portions are included in rate base.

(l) Duke Energy Progress submitted a fuel filing to the NCUC in August 2022 for recovery of $251 million, which included deferrals through June 2022. This amount is expected to be recovered through November 2023. The next filing will be made in the second quarter of 2023. Duke Energy Progress submitted a fuel filing to the PSCSC in April 2022 for recovery of $44 million, which included deferrals through February 2022. This amount is expected to be recovered through June 2023. The next filing will be made in the second quarter of 2023.

2022 North Carolina Rate Case

On October 6, 2022, Duke Energy Progress filed a PBR application with the NCUC to request an increase in base rate retail revenues. The rate request before the NCUC includes an MYRP to recover projected capital investments during the three year MYRP period. In addition to the MYRP, the PBR Application includes an Earnings Sharing Mechanism, Residential Decoupling Mechanism and Performance Incentive Mechanisms as required by HB 951. If approved, the overall retail revenue increase would be $326 million in Year 1, $151 million in Year 2 and $138 million in Year 3, for a combined total of $615 million or 16% by late 2025. The rate increase is driven primarily by major transmission and distribution investments since the last rate case and projected in the MYRP, as well as investments in energy storage and solar assets included in the MYRP consistent with the Carbon Plan. Duke Energy Progress plans to implement temporary rates, subject to refund, on June 1, 2023, and has requested permanent rates be effective by October 1, 2023. The evidentiary hearing has been scheduled to begin on May 1, 2023. Duke Energy Progress cannot predict the outcome of this matter.

2022 South Carolina Rate Case

On September 1, 2022, Duke Energy Progress filed an application with the PSCSC to request an increase in base rate retail revenues. On January 12, 2023, Duke Energy Progress and the ORS, as well as other consumer, environmental, and industrial intervening parties, filed a comprehensive Agreement and Stipulation of Settlement resolving all issues in the base rate proceeding. The major components of the stipulation include:

•A $52 million annual customer rate increase prior to the reduction from the accelerated return to customers of federal unprotected Property, Plant and Equipment related EDIT. After extending the remaining EDIT giveback to customers to 33 months, the net annual retail rate increase is approximately $36 million.

•ROE of 9.6% based upon a capital structure of 52.43% equity and 47.57% debt.

•Continuation of deferral treatment of coal ash basin closure costs. Supports an amortization period for remaining coal ash closure costs in this rate case of seven years. Duke Energy Progress agreed not to seek recovery of approximately $50 million of deferred coal ash expenditures related to retired sites in this rate case (South Carolina retail allocation).

•Accepts the 2021 Depreciation Study as proposed in this case, as adjusted for certain recommendations from ORS and includes accelerated retirement dates for certain coal units as originally proposed.

•Establishment of a storm reserve to help offset the costs of major storms.

The PSCSC held a hearing on January 17, 2023, to consider evidence supporting the stipulation and unanimously voted to approve the comprehensive agreement on February 9, 2023. The PSCSC voted to allow Duke Energy Progress to implement new customer rates by April 1, 2023. A final written order is due from the PSCSC by March 1, 2023.

FERC Return on Equity Complaint

On October 16, 2020, North Carolina Electric Membership Corporation (NCEMC) filed a complaint at the FERC against Duke Energy Progress pursuant to Section 206 of the Federal Power Act (FPA), alleging that the 11% stated ROE component in the demand formula rate in the Power Supply and Coordination Agreement between NCEMC and Duke Energy Progress is unjust and unreasonable. On June 16, 2022, Duke Energy Progress submitted to the FERC an Offer of Settlement and Settlement Agreement (Settlement Agreement) between NCEMC and Duke Energy Progress. The Settlement Agreement provides for an ROE of 10%, effective January 1, 2022, among other contract modifications. On November 7, 2022, the FERC approved the Settlement Agreement.

Duke Energy Florida

Regulatory Assets and Liabilities

The following tables present the regulatory assets and liabilities recorded on Duke Energy Florida's Consolidated Balance Sheets.


	December 31,				Earns/Pays	Recovery/Refund
(in millions)	2022		2021		a Return	Period Ends
Regulatory Assets(a)
AROs – coal ash	$	11	$	10		(b)
AROs – nuclear and other	15		7			(b)
Deferred fuel and purchased power(h)	1,355		415		(f)	2024
Accrued pension and OPEB(c)	342		374		Yes	(g)

Nuclear asset securitized balance, net	881		937			2036

Storm cost deferrals(c)	325		19		(f)	(b)
Hedge costs deferrals(c)	73		77		Yes	2038

Retired generation facilities(c)	94		94		Yes	2044

AMI(c)	30		38		Yes	2032
Customer connect project(c)	82		67		Yes	2037
Costs of removal regulatory asset(c)	221		107		(d)	(b)










Qualifying facility contract buyouts(c)	81		94		Yes	2034








Other	55		49		(d)	(b)
Total regulatory assets	3,565		2,288
Less: current portion	1,143		497
Total noncurrent regulatory assets	$	2,422	$	1,791

Net regulatory liability related to income taxes(c)	$	633	$	699		(b)




DOE Settlement	154		—



Other	90		97		(d)	(b)
Total regulatory liabilities	877		796
Less: current portion	244		98
Total noncurrent regulatory liabilities	$	633	$	698

(a) Regulatory assets and liabilities are excluded from rate base unless otherwise noted.

(b) The expected recovery or refund period varies or has not been determined.

(d) Certain costs earn/pay a return.

(e) Earns a debt return/interest once collections begin.

(f) Earns commercial paper rate.

(g) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail.

(h) Duke Energy Florida submitted a fuel filing to the FPSC in January 2023 for recovery of $795 million, which included the 2022 actual under-recovery of $1.2 billion, offset by projected declining fuel costs in 2023 due to lower natural gas prices. The expected recovery period is April 2023 through March 2024.

2021 Settlement Agreement

On January 14, 2021, Duke Energy Florida filed a Settlement Agreement (the “2021 Settlement”) with the FPSC. The parties to the 2021 Settlement include Duke Energy Florida, the Office of Public Counsel (OPC), the Florida Industrial Power Users Group, White Springs Agricultural Chemicals, Inc. d/b/a PCS Phosphate and NUCOR Steel Florida, Inc. (collectively, the “Parties”).

Pursuant to the 2021 Settlement, the Parties agreed to a base rate stay-out provision that expires year-end 2024; however, Duke Energy Florida is allowed an increase to its base rates of an incremental $67 million in 2022, $49 million in 2023 and $79 million in 2024, subject to adjustment in the event of tax reform during the years 2021, 2022 and 2023. The Parties also agreed to an ROE band of 8.85% to 10.85% with a midpoint of 9.85% based on a capital structure of 53% equity and 47% debt. The ROE band can be increased by 25 basis points if the average 30-year U.S. Treasury rate increases 50 basis points or more over a six-month period in which case the midpoint ROE would rise from 9.85% to 10.10%. On July 25, 2022, this provision was triggered. Duke Energy Florida filed a petition with the FPSC on August 12, 2022, to increase the ROE effective August 2022 with a base rate increase effective January 1, 2023. The FPSC approved this request on October 4, 2022. The 2021 Settlement Agreement also provided that Duke Energy Florida will be able to retain the $173 million retail portion of the expected DOE award from its lawsuit to recover spent nuclear fuel to mitigate customer rates over the term of the 2021 Settlement. In return, Duke Energy Florida is permitted to recognize the $173 million into earnings through the approved settlement period. The full amount of the $173 million is expected to be recognized between the years of 2023 and 2024, while also remaining within the approved ROE band. Duke Energy Florida settled the DOE lawsuit and received payment of approximately $180 million on June 15, 2022, of which the retail portion was approximately $154 million. The 2021 Settlement authorizes Duke Energy Florida to collect the difference between $173 million and the $154 million retail portion of the amount received through the capacity cost recovery clause.

The 2021 Settlement also contained a provision to recover or flow-back the effects of tax law changes. As a result of the IRA enacted on August 16, 2022, Duke Energy Florida is eligible for PTCs associated with solar facilities placed in service beginning in January 2022. Duke Energy Florida filed a petition with the FPSC on October 17, 2022, to reduce base rates effective January 1, 2023, by $56 million to flow back the expected 2023 PTCs and to flow back the expected 2022 PTCs via an adjustment to the capacity cost recovery clause. On December 14, 2022, the FPSC issued an order approving Duke Energy Florida’s petition. See Note 24 for additional information on the IRA.

In addition to these terms, the 2021 Settlement contained provisions related to the accelerated depreciation of Crystal River Units 4-5, the approval of approximately $1 billion in future investments in new cost-effective solar power, the implementation of a new Electric Vehicle Charging Station Program and the deferral and recovery of costs in connection with the implementation of Duke Energy Florida’s Vision Florida program, which explores various emerging non-carbon emitting generation technology, distributed technologies and resiliency projects, among other things. The 2021 Settlement also resolved remaining unrecovered storm costs for Hurricane Michael and Hurricane Dorian.

The FPSC approved the 2021 Settlement on May 4, 2021, issuing an order on June 4, 2021. Revised customer rates became effective January 1, 2022, with subsequent base rate increases effective January 1, 2023, and January 1, 2024.

Clean Energy Connection

On July 1, 2020, Duke Energy Florida petitioned the FPSC for approval of a voluntary solar program. The program consists of 10 new solar generating facilities with combined capacity of approximately 750 MW. The program allows participants to support cost-effective solar development in Florida by paying a subscription fee based on per kilowatt subscriptions and receiving a credit on their bill based on the actual generation associated with their portion of the solar portfolio. The estimated cost of the 10 new solar generation facilities is approximately $1 billion and the projects are expected to be completed by the end of 2024. This investment will be included in base rates offset by the revenue from the subscription fees and the credits will be included for recovery in the fuel cost recovery clause. The FPSC approved the program in January 2021.

On February 24, 2021, the League of United Latin American Citizens (LULAC) filed a notice of appeal of the FPSC’s order approving the Clean Energy Connection to the Supreme Court of Florida. The Supreme Court of Florida heard the oral argument on February 9, 2022. On May 27, 2022, the Supreme Court of Florida issued an order remanding the case back to the FPSC so that the FPSC can amend its order to better address some of the arguments raised by LULAC. On September 23, 2022, the FPSC issued a revised order and submitted it on September 26, 2022, to the Supreme Court of Florida. The Supreme Court of Florida requested that the parties file supplemental briefs regarding the revised order, which were filed February 6, 2023. The FPSC approval order remains in effect pending the outcome of the appeal. Duke Energy Florida cannot predict the outcome of this matter.

Storm Protection Plan

On April 11, 2022, Duke Energy Florida filed a Storm Protection Plan for approval with the FPSC. The plan, which covers investments for the 2023-2032 time frame, reflects approximately $7 billion of capital investment in transmission and distribution meant to strengthen its infrastructure, reduce outage times associated with extreme weather events, reduce restoration costs and improve overall service reliability. The evidentiary hearing began on August 2, 2022. On October 4, 2022, the FPSC voted to approve Duke Energy Florida's plan with one modification to remove the transmission loop radially fed program, representing a reduction of approximately $80 million over the 10-year period starting in 2025. On December 9, 2022, the Office of Public Counsel filed a notice of appeal of this order to the Florida Supreme Court. Duke Energy Florida cannot predict the outcome of this matter.

Hurricane Ian

On September 28, 2022, much of Duke Energy Florida’s service territory was impacted by Hurricane Ian, which caused significant damage resulting in more than 1.1 million outages. Duke Energy Florida's December 31, 2022 Consolidated Balance Sheets include an estimate of approximately $353 million related to deferred Hurricane Ian storm costs, consistent with the FPSC's storm rule, in Regulatory assets within Other Noncurrent Assets. After depleting any existing storm reserves, which were approximately $107 million before Hurricane Ian, Duke Energy Florida is permitted to petition the FPSC for recovery of additional incremental operation and maintenance costs resulting from the storm and to replenish the retail customer storm reserve to approximately $132 million. Duke Energy Florida filed its petition for cost recovery of various storms, including Hurricane Ian, and replenishment of the storm reserve on January 23, 2023, seeking recovery of $442 million, for recovery over 12 months beginning with the first billing cycle in April 2023. Duke Energy Florida cannot predict the outcome of this matter.

Duke Energy Ohio

Regulatory Assets and Liabilities

The following tables present the regulatory assets and liabilities recorded on Duke Energy Ohio's Consolidated Balance Sheets.


	December 31,				Earns/Pays	Recovery/Refund
(in millions)	2022		2021		a Return	Period Ends
Regulatory Assets(a)
AROs – coal ash	$	—	$	33	Yes	(b)

Deferred fuel and purchased power	54		38			2023
Accrued pension and OPEB	129		133			(e)



Storm cost deferrals	14		2			2023
Hedge costs deferrals	2		5			(b)
PISCC and deferred operating expenses(c)	15		16		Yes	2083


AMI	18		24			(b)
Customer connect project	54		41			(b)



CEP deferral	190		161		Yes	(b)




Deferred pipeline integrity costs	28		24		Yes	(b)




Propane caverns	26		—			(b)

Manufactured gas plant (MGP)	—		104			(b)




Other	154		126			(b)
Total regulatory assets	684		707
Less: current portion	103		72
Total noncurrent regulatory assets	$	581	$	635
Regulatory Liabilities(a)
Net regulatory liability related to income taxes	$	496	$	602		(b)
Costs of removal	9		39			(d)


Accrued pension and OPEB	21		21			(e)

Provision for rate refunds	—		61


Other	107		78			(b)
Total regulatory liabilities	633		801
Less: current portion	99		62
Total noncurrent regulatory liabilities	$	534	$	739

(a) Regulatory assets and liabilities are excluded from rate base unless otherwise noted.

(b) The expected recovery or refund period varies or has not been determined.

(d) Recovery over the life of the associated assets.

(e) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail.

Duke Energy Ohio Electric Base Rate Case

Duke Energy Ohio filed with the PUCO an electric distribution base rate case application on October 1, 2021, with supporting testimony filed on October 15, 2021, requesting an increase in electric distribution base rates of approximately $55 million and an ROE of 10.3%. This is an approximate 3.3% average increase in the customer's total bill across all customer classes. The drivers for this case are capital invested since Duke Energy Ohio's last electric distribution base rate case in 2017. Duke Energy Ohio is also seeking to adjust the caps on its Distribution Capital Investment Rider (DCI Rider). The Staff of the PUCO (Staff) report was issued on May 19, 2022, recommending an increase in electric distribution base rates of $2 million to $15 million with an ROE range of 8.84% to 9.85%. On September 19, 2022, Duke Energy Ohio filed a Stipulation and Recommendation with the PUCO, which includes an increase in overall electric distribution base rates of approximately $23 million and an ROE of 9.5%. The stipulation is among all but one party to the proceeding. The PUCO issued an order on December 14, 2022, approving the Stipulation without material modification. Rates went into effect on January 3, 2023. The Ohio Consumers' Counsel (OCC) filed an application for rehearing on January 13, 2023. On February 8, 2023, the Commission granted the OCC's application for rehearing for further consideration. Duke Energy Ohio cannot predict the outcome of this matter.

Energy Efficiency Cost Recovery

In response to changes in Ohio law that eliminated Ohio's energy efficiency mandates, the PUCO issued an order on February 26, 2020, directing utilities to wind down their demand-side management programs by September 30, 2020, and to terminate the programs by December 31, 2020. Duke Energy Ohio took the following actions:

•On March 27, 2020, Duke Energy Ohio filed an application for rehearing seeking clarification on the final true up and reconciliation process after 2020. On November 18, 2020, the PUCO issued an order replacing the cost cap previously imposed upon Duke Energy Ohio with a cap on shared savings recovery. On December 18, 2020, Duke Energy Ohio filed an additional application for rehearing challenging, among other things, the imposition of the cap on shared savings. On January 13, 2021, the application for rehearing was granted for further consideration.

•On October 9, 2020, Duke Energy Ohio filed an application to implement a voluntary energy efficiency program portfolio to commence on January 1, 2021. The application proposed a mechanism for recovery of program costs and a benefit associated with avoided transmission and distribution costs. This application remains under review.

•On November 18, 2020, the PUCO issued an order directing all utilities to set their energy efficiency riders to zero effective January 1, 2021, and to file a separate application for final reconciliation of all energy efficiency costs prior to December 31, 2020. Effective January 1, 2021, Duke Energy Ohio suspended its energy efficiency programs.

•On June 14, 2021, the PUCO requested each utility to file by July 15, 2021, a proposal to reestablish low-income programs through December 31, 2021. Duke Energy Ohio filed its application on July 14, 2021.

•On February 23, 2022, the PUCO issued its Fifth Entry on Rehearing that 1) affirmed its reduction in Duke Energy Ohio's shared savings cap; 2) denied rehearing/clarification regarding lost distribution revenues and shared savings recovery for periods after December 31, 2020; and 3) directed Duke Energy Ohio to submit an updated application with exhibits.

•On March 25, 2022, Duke Energy Ohio filed its Amended Application consistent with the PUCO's order.

Duke Energy Ohio cannot predict the outcome of this matter.

Duke Energy Ohio Natural Gas Base Rate Case

Duke Energy Ohio filed with the PUCO a natural gas base rate case application on June 30, 2022, with supporting testimony filed on July 14, 2022, requesting an increase in natural gas base rates of approximately $49 million and an ROE of 10.3%. This is an approximate 5.6% average increase in the customer's total bill across all customer classes. The drivers for this case are capital invested since Duke Energy Ohio's last natural gas base rate case in 2012. Duke Energy Ohio is also seeking to adjust the caps on its Capital Expenditure Program Rider (CEP Rider). The Staff of the PUCO (Staff) report was issued on December 21, 2022, recommending an increase in natural gas base rates of $24 million to $36 million, with an equity ratio of 52% and an ROE range of 9.03% to 10.04%. A procedural schedule was issued on December 22, 2022, scheduling the evidentiary hearing to commence on March 28, 2023. Duke Energy Ohio cannot predict the outcome of this matter.

Natural Gas Pipeline Extension

Duke Energy Ohio installed a new natural gas pipeline (the Central Corridor Project) in its Ohio service territory to increase system reliability and enable the retirement of older infrastructure. Construction of the pipeline extension was completed and placed in service on March 14, 2022, with a total cost of approximately $170 million (excluding overheads and AFUDC).

MGP Cost Recovery

In an order issued in 2013, the PUCO approved Duke Energy Ohio's deferral and recovery of costs related to environmental remediation at two sites (East End and West End) that housed former MGP operations. Duke Energy Ohio made annual applications with the PUCO to recover its incremental remediation costs consistent with the PUCO’s directive in Duke Energy Ohio’s 2012 natural gas base rate case.

A Stipulation and Recommendation was filed jointly by Duke Energy Ohio, the Staff, the Office of the Ohio Consumers' Counsel and the Ohio Energy Group on August 31, 2021, which was approved without modification by the PUCO on April 20, 2022. The Stipulation and Recommendation resolved all open issues regarding MGP remediation costs incurred between 2013 and 2019, Duke Energy Ohio’s request for additional deferral authority beyond 2019 and the pending issues related to the Tax Act described below as it related to Duke Energy Ohio’s natural gas operations. As a result of the approval of the Stipulation and Recommendation, Duke Energy Ohio recognized pretax charges of approximately $15 million to Operating revenues, regulated natural gas and $58 million to Operation, maintenance and other and a tax benefit of $72 million to Income Tax (Benefit) Expense in the Consolidated Statements of Operations for the year ended December 31, 2022. The Stipulation and Recommendation further acknowledged Duke Energy Ohio’s ability to file a request for additional deferral authority in the future related to environmental remediation of any MGP impacts in the Ohio River, if necessary, subject to specific conditions. On June 15, 2022, the PUCO granted the rehearing requests of Interstate Gas Supply, Inc. (IGS) and The Retail Energy Supply Association (RESA), which were filed on May 20, 2022, for further consideration. Duke Energy Ohio cannot predict the outcome of this matter.

Tax Act – Ohio

On December 21, 2018, Duke Energy Ohio filed an application to change its base rate tariffs and establish a new rider to implement the benefits of the Tax Act for natural gas customers. The new rider would flow through to customers the benefit of the reduction in the statutory federal tax rate from 35% to 21% since January 1, 2018, all future benefits of the lower tax rates and a full refund of deferred income taxes collected at the higher tax rates in prior years. Deferred income taxes subject to normalization rules would be refunded consistent with federal law and deferred income taxes not subject to normalization rules will be refunded over a 10-year period. An evidentiary hearing occurred on August 7, 2019. The Stipulation and Recommendation filed on August 31, 2021, and approved on April 20, 2022, disclosed in the MGP Cost Recovery matter above, resolves the outstanding issues in this proceeding by providing customers a one-time bill credit for the reduction in the statutory federal tax rate from 35% to 21% since January 1, 2018, through June 1, 2022, and reducing base rates going forward. Deferred income taxes subject to normalization rules will be refunded consistent with federal law through a new rider. Deferred income taxes not subject to normalization rules were written off. The commission granted the rehearing requests of IGS and RESA for further consideration. Duke Energy Ohio cannot predict the outcome of this matter.

Midwest Propane Caverns

Duke Energy Ohio used propane stored in caverns to meet peak demand during winter for several decades. Once the Central Corridor Project was complete and placed in service, the propane peaking facilities were no longer necessary and were retired. On October 7, 2021, Duke Energy Ohio requested deferral treatment of the property, plant and equipment as well as costs related to propane inventory and decommissioning costs. On January 6, 2022, the Staff issued a report recommending deferral authority for costs related to propane inventory and decommissioning costs, but not for the net book value of the remaining plant assets. As a result of the Staff's report, Duke Energy Ohio recorded a $19 million charge to Impairment of assets and other charges on the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2021. A Stipulation and Recommendation was filed jointly by Duke Energy Ohio and the Staff on April 27, 2022, recommending, among other things, approval of deferral treatment of a portion of the net book value of the property, plant and equipment prior to the 2021 impairment at the time of the next natural gas base rate case, excluding operations and maintenance savings, decommissioning costs not to exceed $7 million and costs related to propane inventory. The Stipulation and Recommendation states that Duke Energy Ohio will seek recovery of the deferral through its next natural gas base rate case proceeding with a proposed amortization period of at least 10 years and include an independent engineering study analyzing the necessity and prudency of the incremental investments made at the facilities since March 31, 2012. Duke Energy Ohio will not seek a return on the deferred amounts. An evidentiary hearing was held on September 8, 2022. On October 5, 2022, the PUCO issued an order approving the Stipulation and Recommendation as filed. As a result of the order, Duke Energy Ohio recorded a reversal of $12 million to Impairment of assets and other charges on the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2022.

Duke Energy Kentucky Electric Base Rate Case

On December 1, 2022, Duke Energy Kentucky filed a rate case with the KPSC requesting an annualized increase in electric base rates of approximately $75 million and an ROE of 10.35%. This is an overall increase in rates of approximately 17.8%. The request for rate increase is driven by capital investments to strengthen the electricity generation and delivery systems along with adjusted depreciation rates for the East Bend and Woodsdale generation stations to support the energy transition. Duke Energy Kentucky is also requesting new programs and tariff updates, including a voluntary community-based renewable subscription program and two EV charging programs. A procedural schedule was issued on December 19, 2022, scheduling the evidentiary hearing for May 9, 2023. New rates are anticipated to go into effect around July 15, 2023. Duke Energy Kentucky cannot predict the outcome of this matter.

Duke Energy Indiana

Regulatory Assets and Liabilities

The following tables present the regulatory assets and liabilities recorded on Duke Energy Indiana's Consolidated Balance Sheets.


	December 31,				Earns/Pays	Recovery/Refund
(in millions)	2022		2021		a Return	Period Ends
Regulatory Assets(a)
AROs – coal ash	$	385	$	749	Yes	(b)

Deferred fuel and purchased power	138		158			2023
Accrued pension and OPEB	214		222			(e)




Hedge costs deferrals	20		35			(b)
PISCC and deferred operating expenses(c)	255		262		Yes	(b)
Retired generation facilities(c)	34		38		Yes	2030

AMI	15		17			2031
Customer connect project	19		11			(b)




















Other	44		63			(b)
Total regulatory assets	1,124		1,555
Less: current portion	249		277
Total noncurrent regulatory assets	$	875	$	1,278
Regulatory Liabilities(a)
Net regulatory liability related to income taxes	$	840	$	908		(b)
Costs of removal	531		575			(d)

Hedge cost deferrals	81		—			(b)
Accrued pension and OPEB	104		113			(e)




Other	85		96			(b)
Total regulatory liabilities	1,641		1,692
Less: current portion	187		127
Total noncurrent regulatory liabilities	$	1,454	$	1,565

(a) Regulatory assets and liabilities are excluded from rate base unless otherwise noted.

(b) The expected recovery or refund period varies or has not been determined.

(d) Refunded over the life of the associated assets.

(e) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail.

2019 Indiana Rate Case

On July 2, 2019, Duke Energy Indiana filed a general rate case with the IURC for a rate increase for retail customers of approximately $395 million. The rebuttal case, filed on December 4, 2019, updated the requested revenue requirement to result in a 15.6% or $396 million average retail rate increase, including the impacts of the utility receipts tax. On June 29, 2020, the IURC issued an order in the rate case approving a revenue increase of $146 million before certain adjustments and ratemaking refinements. The order approved Duke Energy Indiana's requested forecasted rate base of $10.2 billion as of December 31, 2020, including the Edwardsport Integrated Gasification Combined Cycle (IGCC) Plant. The IURC reduced Duke Energy Indiana's request by slightly more than $200 million, when accounting for the utility receipts tax and other adjustments. Approximately 50% of the reduction was due to a prospective change in depreciation and use of regulatory asset for the end-of-life inventory at retired generating plants, approximately 20% was due to the approved ROE of 9.7% versus the requested ROE of 10.4% and approximately 20% was related to miscellaneous earnings neutral adjustments. Step one rates were estimated to be approximately 75% of the total and became effective on July 30, 2020. Step two rates estimated to be the remaining 25% of the total rate increase were approved on July 28, 2021, and implemented in August 2021.

Several groups appealed the IURC order to the Indiana Court of Appeals. The Indiana Court of Appeals affirmed the IURC decision on May 13, 2021. However, upon appeal by the Indiana Office of Utility Consumer Counselor (OUCC) and the Duke Industrial Group on March 10, 2022, the Indiana Supreme Court found that the IURC erred in allowing Duke Energy Indiana to recover coal ash costs incurred before the IURC’s rate case order in June 2020. The Indiana Supreme Court found that allowing Duke Energy Indiana to recover coal ash costs incurred between rate cases that exceeded the amount built into base rates violated the prohibition against retroactive ratemaking. The IURC’s order has been remanded to the IURC for additional proceedings consistent with the Indiana Supreme Court’s opinion. As a result of the court's opinion, Duke Energy Indiana recognized pretax charges of approximately $211 million to Impairment of assets and other charges and $46 million to Operating revenues in the Consolidated Statements of Operations for the year ended December 31, 2022. Duke Energy Indiana filed a request for rehearing with the Supreme Court on April 11, 2022, which the court denied on May 26, 2022. Duke Energy Indiana filed its testimony in the remand proceeding on August 18, 2022. An evidentiary hearing is scheduled to begin March 3, 2023. Duke Energy Indiana cannot predict the outcome of this matter.

2020 Indiana Coal Ash Recovery Case

In Duke Energy Indiana’s 2019 rate case, the IURC also opened a subdocket for post-2018 coal ash related expenditures. Duke Energy Indiana filed testimony on April 15, 2020, in the coal ash subdocket requesting recovery for the post-2018 coal ash basin closure costs for plans that have been approved by the Indiana Department of Environmental Management (IDEM) as well as continuing deferral, with carrying costs, on the balance. An evidentiary hearing was held on September 14, 2020. Briefing was completed by mid-September 2021. On November 3, 2021, the IURC issued an order allowing recovery for post-2018 coal ash basin closure costs for the plans that have been approved by IDEM, as well as continuing deferral, with carrying costs, on the balance. The OUCC and the Duke Industrial Group appealed. The Indiana Court of Appeals issued its opinion on February 21, 2023, reversing the IURC's order to the extent that it allowed Duke Energy Indiana to recover federally mandated costs incurred prior to the IURC's November 3, 2021 order. In addition, the court found that any costs incurred pre-petition to determine federally mandated compliance options were not specifically authorized by the statute and should also be disallowed. Duke Energy Indiana is assessing its appellate options and must file a petition to transfer to the Indiana Supreme Court by April 7, 2023. As a result of the court's opinion, Duke Energy Indiana recognized a pretax charge of approximately $175 million to Impairment of assets and other charges for the year ended December 31, 2022. Duke Energy Indiana cannot predict the outcome of this matter.

TDSIC 2.0

On November 23, 2021, Duke Energy Indiana filed for approval of the Transmission, Distribution, Storage Improvement Charge 2.0 investment plan for 2023-2028 (TDSIC 2.0). On June 15, 2022, the IURC approved, without modification, TDSIC 2.0, which includes approximately $2 billion in transmission and distribution investments selected to improve customer reliability, harden and improve resiliency of the grid, enable expansion of renewable and distributed energy projects and encourage economic development. In addition, the IURC set up a subdocket to consider the targeted economic development project, which the IURC approved on March 2, 2022. On July 15, 2022, the OUCC filed a notice of appeal to the Indiana Court of Appeals in Duke Energy Indiana’s TDSIC 2.0 proceeding. An appellant brief was filed on October 28, 2022, and Duke Energy Indiana filed its responsive brief on December 28, 2022. Duke Energy Indiana cannot predict the outcome of this matter.

Piedmont

Regulatory Assets and Liabilities

The following tables present the regulatory assets and liabilities recorded on Piedmont's Consolidated Balance Sheets.


	December 31,				Earns/Pays	Recovery/Refund
(in millions)	2022		2021		a Return	Period Ends
Regulatory Assets(a)

AROs – nuclear and other	$	27	$	22		(d)

Accrued pension and OPEB(c)	119		82			(g)











Vacation accrual	12		12			2023



Derivatives – natural gas supply contracts(f)	168		139


Deferred pipeline integrity costs(c)	93		84			2025



Amounts due from customers	57		85		(e)	(b)







Other	35		33			(b)
Total regulatory assets	511		457
Less: current portion	119		141
Total noncurrent regulatory assets	$	392	$	316
Regulatory Liabilities(a)
Net regulatory liability related to income taxes	$	459	$	510		(b)
Costs of removal(c)	573		572			(d)







Other	66		32		(e)	(b)
Total regulatory liabilities	1,098		1,114
Less: current portion	74		56
Total noncurrent regulatory liabilities	$	1,024	$	1,058

(a) Regulatory assets and liabilities are excluded from rate base unless otherwise noted.

(b) The expected recovery or refund period varies or has not been determined.

(d) Recovery over the life of the associated assets.

(e) Certain costs earn/pay a return.

(f) Balance will fluctuate with changes in the market. Current contracts extend into 2031.

(g) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail.

2022 South Carolina Rate Case

On April 1, 2022, Piedmont filed an application with the PSCSC for a rate increase for retail customers of approximately $7 million, which represents an approximate 3.4% increase in retail revenues. An evidentiary hearing was held on August 15, 2022. On September 15, 2022, the PSCSC delivered its decision, which included an ROE of 9.3% and a capital structure of 52.2% equity and 47.8% debt and issued its final order on October 6, 2022. Revised customer rates became effective in October 2022 and resulted in a rate decrease for retail customers of approximately $1 million.

Tennessee Annual Review Mechanism

On October 10, 2022, the TPUC approved Piedmont’s petition to adopt an Annual Review Mechanism (ARM) as allowed by Tennessee law. Under the ARM, Piedmont will adjust rates annually to achieve its allowed 9.80% ROE over the upcoming year and to true up any variance between its allowed ROE and actual ROE from the prior calendar year. The initial year subject to the true up is 2022, and the initial rate adjustments request will be filed in May 2023 for rates effective October 1, 2023.

OTHER REGULATORY MATTERS

Atlantic Coast Pipeline, LLC

Atlantic Coast Pipeline (ACP pipeline) was planned to be an approximately 600-mile interstate natural gas pipeline running from West Virginia to North Carolina. Duke Energy indirectly owns a 47% interest, which is accounted for as an equity method investment through its Gas Utilities and Infrastructure segment.

As a result of the uncertainty created by various legal rulings, the potential impact on the cost and schedule for the project, the ongoing legal challenges and the risk of additional legal challenges and delays through the construction period and Dominion’s decision to sell substantially all of its gas transmission and storage segment assets, Duke Energy's Board of Directors and management decided that it was not prudent to continue to invest in the project. On July 5, 2020, Duke Energy and Dominion announced the cancellation of the ACP pipeline project.

As part of the pretax charges to earnings of approximately $2.1 billion recorded for the year ended December 31, 2020, within Equity in earnings (losses) of unconsolidated affiliates on the Duke Energy Consolidated Statements of Operations, Duke Energy established liabilities related to the cancellation of the ACP pipeline project. In February 2021, Duke Energy paid approximately $855 million to fund ACP's outstanding debt, relieving Duke Energy of its guarantee. At December 31, 2022, there is $59 million and $47 million within Other Current Liabilities and Other Noncurrent Liabilities, respectively, in the Gas Utilities and Infrastructure segment. The liabilities represent Duke Energy's obligation of approximately $106 million to satisfy remaining ARO requirements to restore construction sites.

See Notes 8 and 13 for additional information regarding this transaction.

Potential Coal Plant Retirements

The Subsidiary Registrants periodically file IRPs with their state regulatory commissions. The IRPs provide a view of forecasted energy needs over a long term (10 to 20 years) and options being considered to meet those needs. IRPs filed by the Subsidiary Registrants included planning assumptions to potentially retire certain coal-fired generating facilities in North Carolina and Indiana earlier than their current estimated useful lives. The NCUC concluded in its Carbon Plan order that the projected retirements dates presented by Duke Energy Carolinas and Duke Energy Progress in their Carbon Plan for coal-fired generating facilities were reasonable for planning purposes and further directed that appropriate steps be taken to optimally retire the coal fleet according to such schedule. Duke Energy continues to evaluate the potential need to retire these coal-fired generating facilities earlier than the current estimated useful lives and plans to seek regulatory recovery for amounts that would not be otherwise recovered when any of these assets are retired.

The table below contains the net carrying value of generating facilities planned for retirement or included in recent IRPs or Carbon Plan as evaluated for potential retirement. Dollar amounts in the table below are included in Net property, plant and equipment on the Consolidated Balance Sheets as of December 31, 2022, and exclude capitalized asset retirement costs.








		Remaining Net
	Capacity	Book Value
	(in MW)	(in millions)
Duke Energy Carolinas
Allen Steam Station Unit 1(a)	167	$	10
Allen Steam Station Unit 5(b)	259	233
Cliffside Unit 5(b)	546	344
Marshall Units 1-2(b)	760	428
Duke Energy Progress
Mayo Unit 1(b)	713	639
Roxboro Units 3-4(b)	1,409	425
Duke Energy Florida
Crystal River Units 4-5(c)	1,442	1,549
Duke Energy Indiana
Gibson Units 1-5(d)	2,845	2,043
Cayuga Units 1-2(d)	1,005	622
Total Duke Energy	9,146	$	6,293

(a) As part of the 2015 resolution of a lawsuit involving alleged New Source Review violations, Duke Energy Carolinas must retire Allen Steam Station Unit 1 by December 31, 2024.

(b) These units were included in the IRP filed by Duke Energy Carolinas and Duke Energy Progress in South Carolina on September 1, 2020, and in the Carbon Plan adopted by the NCUC in December 2022. The long-term energy options considered could result in retirement of these units earlier than their current estimated useful lives.

(c) On January 14, 2021, Duke Energy Florida filed the 2021 Settlement agreement with the FPSC, which proposed depreciation rates reflecting retirement dates for Duke Energy Florida's last two coal-fired generating facilities, Crystal River Units 4-5, eight years ahead of schedule in 2034 rather than in 2042. The FPSC approved the 2021 Settlement on May 4, 2021. The remaining net book value reflected in the table above excludes $200 million of accelerated deprecation collected from retail customers pursuant to Duke Energy Florida's 2017 Settlement.

(d) The rate case filed July 2, 2019, included proposed depreciation rates reflecting retirement dates from 2026 to 2038. The depreciation rates reflecting these updated retirement dates were approved by the IURC as part of the rate case order issued on June 29, 2020.

5. COMMITMENTS AND CONTINGENCIES

INSURANCE

General Insurance

The Duke Energy Registrants have insurance and reinsurance coverage either directly or through indemnification from Duke Energy’s captive insurance company, Bison, and its affiliates, consistent with companies engaged in similar commercial operations with similar type properties. The Duke Energy Registrants’ coverage includes (i) commercial general liability coverage for liabilities arising to third parties for bodily injury and property damage; (ii) workers’ compensation; (iii) automobile liability coverage; and (iv) property coverage for all real and personal property damage. Real and personal property damage coverage excludes electric transmission and distribution lines, but includes damages arising from boiler and machinery breakdowns, earthquakes, flood damage and extra expense, but not outage or replacement power coverage. All coverage is subject to certain deductibles or retentions, sublimits, exclusions, terms and conditions common for companies with similar types of operations. The Duke Energy Registrants self-insure their electric transmission and distribution lines against loss due to storm damage and other natural disasters. As discussed further in Note 4, Duke Energy Florida maintains a storm damage reserve and has a regulatory mechanism to recover the cost of named storms on an expedited basis.

The cost of the Duke Energy Registrants’ coverage can fluctuate from year to year reflecting claims history and conditions of the insurance and reinsurance markets.

In the event of a loss, terms and amounts of insurance and reinsurance available might not be adequate to cover claims and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered by other sources, could have a material effect on the Duke Energy Registrants’ results of operations, cash flows or financial position. Each company is responsible to the extent losses may be excluded or exceed limits of the coverage available.

Nuclear Insurance

Duke Energy Carolinas owns and operates McGuire and Oconee and operates and has a partial ownership interest in Catawba. McGuire and Catawba each have two reactors. Oconee has three reactors. The other joint owners of Catawba reimburse Duke Energy Carolinas for certain expenses associated with nuclear insurance per the Catawba joint owner agreements.

Duke Energy Progress owns and operates Robinson, Brunswick and Harris. Robinson and Harris each have one reactor. Brunswick has two reactors.

Duke Energy Florida owns Crystal River Unit 3, which permanently ceased operation in 2013 and achieved a SAFSTOR condition in July 2019. On October 1, 2020, Crystal River Unit 3 changed decommissioning strategies from SAFSTOR to DECON.

In the event of a loss, terms and amounts of insurance available might not be adequate to cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered by other sources, could have a material effect on Duke Energy Carolinas’, Duke Energy Progress’ and Duke Energy Florida’s results of operations, cash flows or financial position. Each company is responsible to the extent losses may be excluded or exceed limits of the coverage available.

Nuclear Liability Coverage

The Price-Anderson Act requires owners of nuclear reactors to provide for public nuclear liability protection per nuclear incident up to a maximum total financial protection liability. The maximum total financial protection liability, which is approximately $13.7 billion, is subject to change every five years for inflation and for the number of licensed reactors. Total nuclear liability coverage consists of a combination of private primary nuclear liability insurance coverage and a mandatory industry risk-sharing program to provide for excess nuclear liability coverage above the maximum reasonably available private primary coverage. The U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims.

Primary Liability Insurance

Duke Energy Carolinas and Duke Energy Progress have purchased the maximum reasonably available private primary nuclear liability insurance as required by law, which is $450 million per station. Duke Energy Florida has purchased $100 million primary nuclear liability insurance for Crystal River in compliance with the law.

Excess Liability Program

This program provides $13.2 billion of coverage per incident through the Price-Anderson Act’s mandatory industrywide excess secondary financial protection program of risk pooling. This amount is the product of potential cumulative retrospective premium assessments of $138 million times the current 96 licensed commercial nuclear reactors in the U.S. Under this program, operating unit licensees could be assessed retrospective premiums to compensate for public nuclear liability damages in the event of a nuclear incident at any licensed facility in the U.S. Retrospective premiums may be assessed at a rate not to exceed $20.5 million per year per licensed reactor for each incident. The assessment may be subject to state premium taxes.

Nuclear Property and Accidental Outage Coverage

Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida are members of Nuclear Electric Insurance Limited (NEIL), an industry mutual insurance company, which provides property damage, nuclear accident decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. Additionally, NEIL provides accidental outage coverage for losses in the event of a major accidental outage at an insured nuclear station.

Pursuant to regulations of the NRC, each company’s property damage insurance policies provide that all proceeds from such insurance be applied, first, to place the plant in a safe and stable condition after a qualifying accident and second, to decontaminate the plant before any proceeds can be used for decommissioning, plant repair or restoration.

Losses resulting from acts of terrorism are covered as common occurrences, such that if terrorist acts occur against one or more commercial nuclear power plants insured by NEIL within a 12-month period, they would be treated as one event and the owners of the plants where the act occurred would share one full limit of liability. The full limit of liability is currently $3.2 billion. NEIL sublimits the total aggregate for all of their policies for non-nuclear terrorist events to approximately $1.8 billion.

Each nuclear facility has accident property damage, nuclear accident decontamination and premature decommissioning liability insurance from NEIL with limits of $1.5 billion, except for Crystal River Unit 3. Crystal River Unit 3’s limit is $50 million and is on an actual cash value basis. All nuclear facilities except for Catawba and Crystal River Unit 3 also share an additional $1.25 billion nuclear accident insurance limit above their dedicated underlying limit. This shared additional excess limit is not subject to reinstatement in the event of a loss. Catawba has a dedicated $1.25 billion of additional nuclear accident insurance limit above its dedicated underlying limit. Catawba and Oconee also have an additional $750 million of non-nuclear accident property damage limit. All coverages are subject to sublimits and significant deductibles.

NEIL’s Accidental Outage policy provides some coverage, similar to business interruption, for losses in the event of a major accident property damage outage of a nuclear unit. Coverage is provided on a weekly limit basis after a significant waiting period deductible and at 100% of the applicable weekly limits for 52 weeks and 80% of the applicable weekly limits for up to the next 110 weeks. Coverage is provided until these applicable weekly periods are met, where the accidental outage policy limit will not exceed $490 million for Catawba, McGuire, Harris, Brunswick, Oconee and Robinson. NEIL sublimits the accidental outage recovery up to the first 104 weeks of coverage not to exceed $328 million from non-nuclear accidental property damage. Coverage amounts decrease in the event more than one unit at a station is out of service due to a common accident. All coverages are subject to sublimits and significant deductibles.

Potential Retroactive Premium Assessments

In the event of NEIL losses, NEIL’s board of directors may assess member companies' retroactive premiums of amounts up to 10 times their annual premiums for up to six years after a loss. NEIL has never exercised this assessment. The maximum aggregate annual retrospective premium obligations for Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida are $151 million, $93 million and $1 million, respectively. Duke Energy Carolinas' maximum assessment amount includes 100% of potential obligations to NEIL for jointly owned reactors. Duke Energy Carolinas would seek reimbursement from the joint owners for their portion of these assessment amounts.

ENVIRONMENTAL

The Duke Energy Registrants are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal, coal ash and other environmental matters. These regulations can be changed from time to time, imposing new obligations on the Duke Energy Registrants. The following environmental matters impact all of the Duke Energy Registrants.

Remediation Activities

In addition to AROs recorded as a result of various environmental regulations, discussed in Note 10, the Duke Energy Registrants are responsible for environmental remediation at various sites. These include certain properties that are part of ongoing operations and sites formerly owned or used by Duke Energy entities. These sites are in various stages of investigation, remediation and monitoring. Managed in conjunction with relevant federal, state and local agencies, remediation activities vary based upon site conditions and location, remediation requirements, complexity and sharing of responsibility. If remediation activities involve joint and several liability provisions, strict liability, or cost recovery or contribution actions, the Duke Energy Registrants could potentially be held responsible for environmental impacts caused by other potentially responsible parties and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. Liabilities are recorded when losses become probable and are reasonably estimable. The total costs that may be incurred cannot be estimated because the extent of environmental impact, allocation among potentially responsible parties, remediation alternatives and/or regulatory decisions have not yet been determined at all sites. Additional costs associated with remediation activities are likely to be incurred in the future and could be significant. Costs are typically expensed as Operation, maintenance and other in the Consolidated Statements of Operations unless regulatory recovery of the costs is deemed probable.

The following table contains information regarding reserves for probable and estimable costs related to the various environmental sites. These reserves are recorded in Other within Other Noncurrent Liabilities on the Consolidated Balance Sheets.


(in millions)	December 31, 2022		December 31, 2021
Reserves for Environmental Remediation
Duke Energy	$	84	$	88
Duke Energy Carolinas	22		19
Progress Energy	19		23
Duke Energy Progress	8		11
Duke Energy Florida	11		11
Duke Energy Ohio	33		34
Duke Energy Indiana	3		4
Piedmont	7		9

Additional losses in excess of recorded reserves that could be incurred for the stages of investigation, remediation and monitoring for environmental sites that have been evaluated at this time are not material.

LITIGATION

Duke Energy

Michael Johnson et al. v. Duke Energy Corporation et al.

On September 23, 2020, plaintiff Michael Johnson, a former Duke Energy employee and participant in the Duke Energy Retirement Savings Plan (Plan) brought suit on his own behalf and on behalf of other participants and beneficiaries similarly situated against Duke Energy Corporation, the Duke Energy Benefits Committee, and other unnamed individual defendants. The complaint, which was subsequently amended to add a current participant as a plaintiff on November 23, 2020, alleges that the defendants breached their fiduciary duties with respect to certain fees associated with the Plan in violation of the Employee Retirement Income Security Act of 1974 and seeks certification of a class of all individuals who were participants or beneficiaries of the Plan at any time on or after September 23, 2014. The defendants filed a motion to dismiss the plaintiffs’ amended complaint on December 18, 2020. On January 31, 2022, the court denied the defendants' motion to dismiss. On February 28, 2022, Duke Energy responded to the amended complaint. Discovery commenced and the parties exchanged preliminary disclosures. After review of these disclosures, the plaintiffs agreed to voluntarily dismiss the suit and the parties subsequently filed a joint stipulation of voluntary dismissal with prejudice on April 29, 2022, ending this litigation.

Texas Storm Uri Tort Litigation

Duke Energy Corporation and several Duke Energy renewables project companies in the ERCOT market were named in more than thirty lawsuits arising out of Texas Storm Uri, which occurred in February 2021. Duke Energy Corporation was dismissed from the suits, leaving two suits in which individual wind and solar projects are named. These lawsuits seek recovery for property damages, personal injury and wrongful death allegedly caused by the power outages that plaintiffs claim were the collective failure of generators, transmission and distribution utilities ("TDUs"), retail energy providers, natural gas providers, co-ops and municipalities that generate power and ERCOT, all of which were originally sued by all plaintiffs. The cases were consolidated into a Texas state court multidistrict litigation (MDL) proceeding for discovery and pre-trial motions. Five cases were designated for motions to dismiss and all other cases were stayed. On January 28, 2023, the Court denied the generators' and TDUs' motions to dismiss the negligence claims but dismissed the tortious interference and conspiracy claims. The motions to dismiss ERCOT and the natural gas defendants were also granted. The generator and TDU defendants filed a petition for mandamus in each of the five cases seeking to overturn the denials on February 10, 2023. If the Texas Court of Appeals accepts the appeals, it will set a briefing schedule. The remaining cases that are part of the MDL are currently stayed, except that plaintiffs have been given leave to amend their pleadings. Plaintiffs began amending existing lawsuits and filing new lawsuits on behalf of hundreds of plaintiffs against hundreds of defendants, including in some cases, by again naming Duke Energy Corporation and naming, for the first time, Duke Energy Renewables, LLC. Plaintiffs have also re-named ERCOT as a defendant. As new cases are served, they are being brought into the MDL and are subject to the stay in the MDL proceeding. Duke Energy cannot predict the outcomes of these matters. See Note 2 for more information related to the sale of the Commercial Renewables Disposal Groups.

Duke Energy Carolinas

Ruben Villano, et al. v. Duke Energy Carolinas, LLC

On June 16, 2021, a group of nine individuals went over a low head dam adjacent to the Dan River Steam Station in Eden, North Carolina, while water tubing. Emergency personnel rescued four people and five others were confirmed deceased. On August 11, 2021, Duke Energy Carolinas was served with the complaint filed in Durham County Superior Court on behalf of four survivors, which was later amended to include all the decedents along with the survivors. The lawsuit alleges that Duke Energy Carolinas knew that the river was used for recreational purposes and that Duke Energy did not adequately warn about the dam and that Duke Energy Carolinas created a dangerous and hidden hazard on the Dan River in building and maintaining the low head dam. Discovery has commenced and is scheduled to be completed on or before August 23, 2023. The parties are preparing for mediation, which is scheduled for March 22, 2023. Dispositive motions are due to be filed by September 6, 2023, and the case is scheduled to be trial-ready by October 2, 2023. Duke Energy Carolinas cannot predict the outcome of this matter.

NTE Carolinas II, LLC Litigation

In November 2017, Duke Energy Carolinas entered into a standard FERC large generator interconnection agreement (LGIA) with NTE Carolinas II, LLC (NTE), a company that proposed to build a combined-cycle natural gas plant in Rockingham County, North Carolina. On September 6, 2019, Duke Energy Carolinas filed a lawsuit in Mecklenburg County Superior Court against NTE for breach of contract, alleging that NTE's failure to pay benchmark payments for Duke Energy Carolinas' transmission system upgrades required under the interconnection agreement constituted a termination of the interconnection agreement. Duke Energy Carolinas sought a monetary judgment against NTE because NTE failed to make multiple milestone payments. The lawsuit was moved to federal court in North Carolina. NTE filed a motion to dismiss Duke Energy Carolinas’ complaint and brought counterclaims alleging anti-competitive conduct and violations of state and federal statutes. Duke Energy Carolinas filed a motion to dismiss NTE's counterclaims. Both NTE's and Duke Energy Carolinas' motions to dismiss were subsequently denied by the court.

On May 21, 2020, in response to an NTE petition challenging Duke Energy Carolinas' termination of the LGIA, FERC issued a ruling that 1) it has exclusive jurisdiction to determine whether a transmission provider may terminate a LGIA; 2) FERC approval is required to terminate a conforming LGIA if objected to by the interconnection customer; and 3) Duke Energy may not announce the termination of a conforming LGIA unless FERC has approved the termination. FERC's Office of Enforcement also initiated an investigation of Duke Energy Carolinas into matters pertaining to the LGIA. Duke Energy Carolinas is cooperating with the Office of Enforcement but cannot predict the outcome of this investigation.

Following completion of discovery, Duke Energy Carolinas filed a motion for summary judgment seeking a ruling in its favor as to some of its affirmative claims against NTE and to all of NTE’s counterclaims. On June 24, 2022, the court issued an order partially granting Duke Energy Carolinas' motion by dismissing NTE's counterclaims that Duke Energy Carolinas engaged in anti-competitive behavior in violation of state and federal statutes. On October 12, 2022, the parties executed a settlement agreement with respect to the remaining breach of contract claims in the litigation and a Stipulation of Dismissal was filed with the court on October 13, 2022. On November 11, 2022, NTE filed its Notice of Appeal to the U.S. Court of Appeals for the Fourth Circuit as to the District Court's summary judgment ruling in Duke Energy Carolinas' favor on NTE's antitrust and unfair competition claims. Briefing on NTE's appeal will be completed on May 3, 2023. Duke Energy Carolinas cannot predict the outcome of this matter.

Asbestos-related Injuries and Damages Claims

Duke Energy Carolinas has experienced numerous claims for indemnification and medical cost reimbursement related to asbestos exposure. These claims relate to damages for bodily injuries alleged to have arisen from exposure to or use of asbestos in connection with construction and maintenance activities conducted on its electric generation plants prior to 1985.

Duke Energy Carolinas has recognized asbestos-related reserves of $457 million and $501 million at December 31, 2022, and 2021, respectively. These reserves are classified in Other within Other Noncurrent Liabilities and Other within Current Liabilities on the Consolidated Balance Sheets. The change in the reserves is a result of a third-party study completed in 2021 as well as settlements made throughout the year. These reserves are based upon Duke Energy Carolinas' best estimate for current and future asbestos claims through 2042 and are recorded on an undiscounted basis. In light of the uncertainties inherent in a longer-term forecast, management does not believe they can reasonably estimate the indemnity and medical costs that might be incurred after 2042 related to such potential claims. It is possible Duke Energy Carolinas may incur asbestos liabilities in excess of the recorded reserves.

Duke Energy Carolinas has third-party insurance to cover certain losses related to asbestos-related injuries and damages above an aggregate self-insured retention. Receivables for insurance recoveries were $595 million and $644 million at December 31, 2022, and 2021, respectively. These amounts are classified in Other within Other Noncurrent Assets and Receivables within Current Assets on the Consolidated Balance Sheets. Any future payments up to the policy limit will be reimbursed by the third-party insurance carrier. Duke Energy Carolinas is not aware of any uncertainties regarding the legal sufficiency of insurance claims. Duke Energy Carolinas believes the insurance recovery asset is probable of recovery as the insurance carrier continues to have a strong financial strength rating.

The reserve for credit losses for insurance receivables for the asbestos-related injuries and damages is $12 million for Duke Energy and Duke Energy Carolinas as of December 31, 2022, and December 31, 2021. The insurance receivable is evaluated based on the risk of default and the historical losses, current conditions and expected conditions around collectability. Management evaluates the risk of default annually based on payment history, credit rating and changes in the risk of default from credit agencies.

Duke Energy Progress and Duke Energy Florida

Spent Nuclear Fuel Matters

On June 18, 2018, Duke Energy Progress and Duke Energy Florida sued the U.S. in the U.S. Court of Federal Claims for damages incurred for the period 2014 through 2018. The lawsuit claimed the DOE breached a contract in failing to accept spent nuclear fuel under the Nuclear Waste Policy Act of 1982 and asserted damages for the cost of on-site storage in the amount of $100 million and $200 million for Duke Energy Progress and Duke Energy Florida, respectively.

On March 30, 2022, the DOE and Duke Energy Progress executed a settlement agreement, pursuant to which Duke Energy Progress would receive damages for costs incurred between 2014 and 2018 and would be able to submit future costs on a defined schedule. In April 2022, Duke Energy Progress received $87 million in proceeds that related to damages incurred in 2014 through 2018.

On May 2, 2022, the DOE and Duke Energy Florida executed a settlement agreement, pursuant to which Duke Energy Florida would receive damages for costs incurred between 2014 and 2018 and would be able to submit costs incurred in 2019 and 2020 pursuant to an audit process. In June 2022, Duke Energy Florida received $180 million in proceeds that related to damages incurred in 2014 through 2018.

Duke Energy Indiana

Coal Ash Basin Closure Plan Appeal

On January 27, 2020, Hoosier Environmental Council (HEC) filed a Petition for Administrative Review with the Indiana Office of Environmental Adjudication challenging the Indiana Department of Environmental Management’s (IDEM's) December 10, 2019 partial approval of Duke Energy Indiana’s ash pond closure plan at Duke Energy's Gallagher power station. After hearing oral arguments in early April 2021 on Duke Energy Indiana's and HEC's competing Motions for Summary Judgment, on May 4, 2021, the administrative court rejected all of HEC’s claims and issued a ruling in favor of Duke Energy Indiana. On June 3, 2021, HEC filed an appeal in Superior Court to seek judicial review of the order. Briefing on the appeal was completed on December 13, 2021.

On January 11, 2022, Duke Energy Indiana received a compliance obligation letter from the EPA notifying the company that the two basins at issue in the litigation are subject to requirements of the CCR Rule. The letter does not provide a deadline for compliance. Duke Energy Indiana is proceeding with surface impoundment closure at its Indiana sites consistent with EPA’s guidance, the federal CCR rule, and Indiana law, as applicable.

On April 21, 2022, HEC filed a motion requesting that the court hold a hearing within 45 days and also take judicial notice of the EPA's January 11, 2022 letter. On April 22, 2022, Duke Energy Indiana sent IDEM a letter withdrawing the closure plans for the Gallagher North Ash Pond and Primary Pond Ash Fill. After acknowledgment by IDEM of withdrawal of these closure plans, Duke Energy Indiana filed a Motion to Dismiss the litigation as moot on April 28, 2022, which IDEM supported, and the court granted the Motion to Dismiss on July 8, 2022.

Coal Ash Insurance Coverage Litigation

In June 2022, Duke Energy Indiana filed a civil action in Indiana Superior Court against various insurance companies seeking declaratory relief with respect to insurance coverage for coal combustion residuals-related expenses and liabilities covered by third-party liability insurance policies. The insurance policies cover the 1969-1972 and 1984-1985 periods and provide third-party liability insurance for claims and suits alleging property damage, bodily injury and personal injury (or a combination thereof). A trial date has not yet been set. Duke Energy Indiana cannot predict the outcome of this matter.

Other Litigation and Legal Proceedings

The Duke Energy Registrants are involved in other legal, tax and regulatory proceedings arising in the ordinary course of business, some of which involve significant amounts. The Duke Energy Registrants believe the final disposition of these proceedings will not have a material effect on their results of operations, cash flows or financial position for the years presented. Reserves are classified on the Consolidated Balance Sheets in Other within Other Noncurrent Liabilities and Other within Current Liabilities.

OTHER COMMITMENTS AND CONTINGENCIES

General

As part of their normal business, the Duke Energy Registrants are party to various financial guarantees, performance guarantees and other contractual commitments to extend guarantees of credit and other assistance to various subsidiaries, investees and other third parties. These guarantees involve elements of performance and credit risk, which are not fully recognized on the Consolidated Balance Sheets and have uncapped maximum potential payments. However, the Duke Energy Registrants do not believe these guarantees will have a material effect on their results of operations, cash flows or financial position. See Note 8 for more information.

Purchase Obligations

Purchased Power

Duke Energy Progress, Duke Energy Florida and Duke Energy Ohio have ongoing purchased power contracts, including renewable energy contracts, with other utilities, wholesale marketers, co-generators and qualified facilities. These purchased power contracts generally provide for capacity and energy payments. In addition, Duke Energy Progress and Duke Energy Florida have various contracts to secure transmission rights.

The following table presents executory purchased power contracts with terms exceeding one year, excluding contracts classified as leases.


		Minimum Purchase Amount at December 31, 2022
	Contract
(in millions)	Expiration	2023		2024		2025		2026		2027		Thereafter		Total
Duke Energy Progress(a)	2028-2032	$	22	$	21	$	22	$	18	$	19	$	27	$	129
Duke Energy Florida(b)	2024-2025	300		267		91		—		—		—		658
Duke Energy Ohio(c)	2024	55		36		—		—		—		—		91

(a) Contracts represent between 18% and 100% of net plant output.

(b) Contracts represent 100% of net plant output.

Gas Supply and Capacity Contracts

Duke Energy Ohio and Piedmont routinely enter into long-term natural gas supply commodity and capacity commitments and other agreements that commit future cash flows to acquire services needed in their businesses. These commitments include pipeline and storage capacity contracts and natural gas supply contracts to provide service to customers. Costs arising from the natural gas supply commodity and capacity commitments, while significant, are pass-through costs to customers and are generally fully recoverable through the fuel adjustment or PGA procedures and prudence reviews in North Carolina and South Carolina and under the Tennessee Incentive Plan in Tennessee. In the Midwest, these costs are recovered via the Gas Cost Recovery Rate in Ohio or the Gas Cost Adjustment Clause in Kentucky. The time periods for fixed payments under pipeline and storage capacity contracts are up to 20 years. The time periods for fixed payments under natural gas supply contracts are up to four years. The time period for the natural gas supply purchase commitments is up to nine years.

Certain storage and pipeline capacity contracts require the payment of demand charges that are based on rates approved by the FERC in order to maintain rights to access the natural gas storage or pipeline capacity on a firm basis during the contract term. The demand charges that are incurred in each period are recognized in the Consolidated Statements of Operations and Comprehensive Income as part of natural gas purchases and are included in Cost of natural gas.

The following table presents future unconditional purchase obligations under natural gas supply and capacity contracts as of December 31, 2022.


(in millions)	2023		2024		2025		2026		2027		Thereafter		Total
Duke Energy Ohio	$	85	$	101	$	85	$	56	$	52	$	616	$	995
Piedmont	319		313		267		213		203		587		1,902

6. LEASES

As part of its operations, Duke Energy leases certain aircraft, space on communication towers, industrial equipment, fleet vehicles, fuel transportation (barges and railcars), land and office space under various terms and expiration dates. Additionally, Duke Energy Carolinas, Duke Energy Progress and Duke Energy Indiana have finance leases related to firm natural gas pipeline transportation capacity. Duke Energy Progress and Duke Energy Florida have entered into certain PPAs, which are classified as finance and operating leases.

Duke Energy has certain lease agreements, which include variable lease payments that are based on the usage of an asset. These variable lease payments are not included in the measurement of the ROU assets or operating lease liabilities on the Consolidated Financial Statements.

Certain Duke Energy lease agreements include options for renewal and early termination. The intent to renew a lease varies depending on the lease type and asset. Renewal options that are reasonably certain to be exercised are included in the lease measurements. The decision to terminate a lease early is dependent on various economic factors. No termination options have been included in any of the lease measurements.

Duke Energy Carolinas entered into a sale-leaseback arrangement in December 2019, to construct and occupy an office tower. The lease agreement was evaluated as a sale-leaseback of real estate and it was determined that the transaction did not qualify for sale-leaseback accounting. As a result, the transaction is being accounted for as a financing. For this transaction, Duke Energy Carolinas will continue to record the real estate on the Consolidated Balance Sheets within Property, Plant and Equipment as if it were the legal owner and will continue to recognize depreciation expense over the estimated useful life. In addition, the failed sale-leaseback obligation is reported within Long-Term Debt on the Consolidated Balance Sheets, with the monthly lease payments commencing after the construction phase being split between interest expense and principal pay down of the debt.

Piedmont has certain agreements with Duke Energy Carolinas for the construction and transportation of natural gas pipelines to supply its natural gas plant needs. Piedmont accounts for these pipeline lateral contracts as sales-type leases since the present value of the sum of the lease payments equals the fair value of the assets. These pipeline lateral assets owned by Piedmont had a current net investment basis of $2 million as of December 31, 2022, and 2021, and a long-term net investment basis of $201 million and $203 million as of December 31, 2022, and 2021, respectively. These assets are classified in Other, within Current Assets and Other Noncurrent Assets, respectively, on Piedmont's Consolidated Balance Sheets. Duke Energy Carolinas accounts for the contracts as finance leases. The activity for these contracts is eliminated in consolidation at Duke Energy.

The following tables present the components of lease expense.


	Year Ended December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Operating lease expense(a)	$	229	$	39	$	153	$	83	$	70	$	10	$	19	$	6
Short-term lease expense(a)	4		—		1		—		1		—		2		—
Variable lease expense(a)	61		(1)		60		37		23		—		—		1
Finance lease expense
Amortization of leased assets(b)	151		6		61		41		20		—		—		—
Interest on lease liabilities(c)	50		32		49		45		4		—		1		—
Total finance lease expense	201		38		110		86		24		—		1		—
Total lease expense	$	495	$	76	$	324	$	206	$	118	$	10	$	22	$	7


	Year Ended December 31, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Operating lease expense(a)	$245		$43		$155		$83		$72		$11		$18		$7
Short-term lease expense(a)	5		—		2		1		1		—		2		—
Variable lease expense(a)	41		17		22		10		12		—		—		1
Finance lease expense
Amortization of leased assets(b)	219		5		37		18		19		—		1		—
Interest on lease liabilities(c)	55		33		48		42		6		—		—		—
Total finance lease expense	274		38		85		60		25		—		1		—
Total lease expense	$	565	$	98	$	264	$	154	$	110	$	11	$	21	$	8

(a) Included in Operations, maintenance and other or, for barges and railcars, Fuel used in electric generation and purchased power on the Consolidated Statements of Operations.

(b) Included in Depreciation and amortization on the Consolidated Statements of Operations.

The following table presents operating lease maturities and a reconciliation of the undiscounted cash flows to operating lease liabilities.


	December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
2023	$	225	$	23	$	118	$	64	$	54	$	2	$	6	$	4
2024	207		21		110		56		54		2		5		4
2025	175		14		96		42		54		2		5		4
2026	161		13		99		45		54		2		4		—
2027	134		9		73		46		27		2		4		—
Thereafter	322		37		253		209		44		15		45		1
Total operating lease payments	1,224		117		749		462		287		25		69		13
Less: present value discount	(169)		(20)		(107)		(76)		(31)		(7)		(18)		—
Total operating lease liabilities(a)	$	1,055	$	97	$	642	$	386	$	256	$	18	$	51	$	13

(a) Certain operating lease payments include renewal options that are reasonably certain to be exercised.

The following table presents finance lease maturities and a reconciliation of the undiscounted cash flows to finance lease liabilities.


	December 31, 2022
			Duke				Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Indiana
2023	$	198	$	38	$	103	$	78	$	25	$	1
2024	143		38		88		79		9		1
2025	76		38		85		80		5		1
2026	77		38		86		81		5		1
2027	74		38		82		81		1		1
Thereafter	584		427		555		555		—		23
Total finance lease payments	1,152		617		999		954		45		28
Less: amounts representing interest	(388)		(333)		(371)		(367)		(4)		(19)
Total finance lease liabilities	$	764	$	284	$	628	$	587	$	41	$	9

The following tables contain additional information related to leases.


		December 31, 2022
				Duke				Duke		Duke		Duke		Duke
		Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Classification	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Assets
Operating	Operating lease ROU assets, net	$	1,042	$	78	$	628	$	370	$	258	$	18	$	49	$	4
Finance	Net property, plant and equipment	810		284		674		590		84		—		6		—
Total lease assets		$	1,852	$	362	$	1,302	$	960	$	342	$	18	$	55	$	4
Liabilities
Current
Operating	Other current liabilities	$	179	$	14	$	96	$	51	$	45	$	1	$	4	$	—
Finance	Current maturities of long-term debt	153		7		57		35		22		—		—		—
Noncurrent
Operating	Operating lease liabilities	876		83		546		335		211		17		47		13
Finance	Long-Term Debt	611		277		571		552		19		—		9		—
Total lease liabilities		$	1,819	$	381	$	1,270	$	973	$	297	$	18	$	60	$	13


		December 31, 2021
				Duke				Duke		Duke		Duke		Duke
		Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Classification	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Assets
Operating	Operating lease ROU assets, net	$	1,136	$	92	$	691	$	389	$	302	$	19	$	53	$	16
Finance	Net property, plant and equipment	950		302		729		627		102		—		7		—
Total lease assets		$	2,086	$	394	$	1,420	$	1,016	$	404	$	19	$	60	$	16
Liabilities
Current
Operating	Other current liabilities	$	184	$	22	$	94	$	50	$	44	$	1	$	4	$	5
Finance	Current maturities of long-term debt	151		6		61		41		20		—		—		—
Noncurrent
Operating	Operating lease liabilities	940		78		606		350		256		18		50		14
Finance	Long-Term Debt	764		283		629		588		41		—		10		—
Total lease liabilities		$	2,039	$	389	$	1,390	$	1,029	$	361	$	19	$	64	$	19


	Year Ended December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Cash paid for amounts included in the measurement of lease liabilities(a)
Operating cash flows from operating leases	$	230	$	24	$	118	$	63	$	55	$	2	$	6	$	4
Operating cash flows from finance leases	50		32		49		45		4		—		1		—
Financing cash flows from finance leases	151		6		61		41		20		—		—		—


Lease assets obtained in exchange for new lease liabilities (non-cash)
Operating(b)	$	111	$	10	$	—	$	—	$	—	$	—	$	—	$	—


	Year Ended December 31, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Cash paid for amounts included in the measurement of lease liabilities(a)
Operating cash flows from operating leases	$	245	$	25	$	117	$	62	$	55	$	2	$	6	$	5
Operating cash flows from finance leases	55		33		48		42		6		—		—		—
Financing cash flows from finance leases	219		5		37		18		19		—		1		—


Lease assets obtained in exchange for new lease liabilities (non-cash)
Operating(b)	$	182	$	4	$	99	$	99	$	—	$	—	$	—	$	—
Finance	322		—		322		322		—		—		—		—

(a) No amounts were classified as investing cash flows from operating leases.

(b) Does not include ROU assets recorded as a result of the adoption of the new lease standard.


	December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Weighted average remaining lease term (years)
Operating leases	8		10		8		9		6		15		15		1
Finance leases	10		17		12		12		12		—		23		—
Weighted average discount rate(a)
Operating leases	3.4	%	3.8	%	3.6	%	3.5	%	3.8	%	4.2	%	4.0	%	3.3	%
Finance leases	7.7	%	11.5	%	9.1	%	9.1	%	8.0	%	—	%	11.9	%	—	%


	December 31, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Weighted average remaining lease term (years)
Operating leases	8		9		8		10		7		16		16		4
Finance leases	10		18		13		13		11		—		24		—
Weighted average discount rate(a)
Operating leases	3.5	%	3.5	%	3.6	%	3.4	%	3.8	%	4.2	%	4.1	%	3.6	%
Finance leases	7.3	%	11.6	%	9.0	%	9.0	%	8.2	%	—	%	11.9	%	—	%

(a) The discount rate is calculated using the rate implicit in a lease if it is readily determinable. Generally, the rate used by the lessor is not provided to Duke Energy and in these cases the incremental borrowing rate is used. Duke Energy will typically use its fully collateralized incremental borrowing rate as of the commencement date to calculate and record the lease. The incremental borrowing rate is influenced by the lessee’s credit rating and lease term and as such may differ for individual leases, embedded leases or portfolios of leased assets.


(in millions)	2023		2024		2025		2026		2027		Thereafter		Total
Duke Energy Ohio	$	85	$	101	$	85	$	56	$	52	$	616	$	995
Piedmont	319		313		267		213		203		587		1,902

7. DEBT AND CREDIT FACILITIES

Summary of Debt and Related Terms

The following tables summarize outstanding debt and includes debt attributable to the Commercial Renewables Disposal Groups. See Note 2 for further details.


	December 31, 2022
	Weighted
	Average				Duke				Duke		Duke		Duke		Duke
	Interest		Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Rate		Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Unsecured debt, maturing 2023-2082	4.20	%	$	29,585	$	1,150	$	2,600	$	—	$	950	$	1,330	$	697	$	3,390
Secured debt, maturing 2023-2052	4.11	%	5,632		1,317		2,383		1,155		1,228		—		—		—
First mortgage bonds, maturing 2023-2052(a)	3.89	%	32,645		11,306		16,350		8,776		7,576		1,850		3,138		—
Finance leases, maturing 2023-2051(b)	7.90	%	764		284		628		587		41		—		9		—

Tax-exempt bonds, maturing 2027-2046(c)	3.84	%	1,331		—		500		500		—		77		352		—
Notes payable and commercial paper(d)	4.50	%	4,582		—		—		—		—		—		—		—
Money pool/intercompany borrowings			—		1,533		993		389		605		522		585		514
Fair value hedge carrying value adjustment			(5)		—		—		—		—		—		—		—
Unamortized debt discount and premium, net(e)			1,016		(21)		(40)		(23)		(16)		(25)		(17)		(9)
Unamortized debt issuance costs(f)			(383)		(70)		(132)		(59)		(70)		(12)		(22)		(18)
Total debt	4.09	%	$	75,167	$	15,499	$	23,282	$	11,325	$	10,314	$	3,742	$	4,742	$	3,877
Short-term notes payable and commercial paper			(3,952)		—		—		—		—		—		—		—
Short-term money pool/intercompany borrowings			—		(1,233)		(843)		(238)		(605)		(497)		(435)		(514)
Current maturities of long-term debt(g)			(4,154)		(1,018)		(697)		(369)		(328)		(475)		(303)		(45)
Total long-term debt(g)			$	67,061	$	13,248	$	21,742	$	10,718	$	9,381	$	2,770	$	4,004	$	3,318

(a)Substantially all electric utility property is mortgaged under mortgage bond indentures.

(b)Duke Energy includes $164 million of finance lease purchase accounting adjustments related to Duke Energy Florida related to PPAs that are not accounted for as finance leases in their respective financial statements because of grandfathering provisions in GAAP.

(c)Substantially all tax-exempt bonds are secured by first mortgage bonds, letters of credit or the Master Credit Facility.

(d)Includes $625 million classified as Long-Term Debt on the Consolidated Balance Sheets due to the existence of long-term credit facilities that backstop these commercial paper balances, along with Duke Energy’s ability and intent to refinance these balances on a long-term basis. The weighted average days to maturity for Duke Energy's commercial paper program was 15 days.

(e)Duke Energy includes $1,057 million and $85 million in purchase accounting adjustments related to Progress Energy and Piedmont, respectively.

(f)Duke Energy includes $27 million in purchase accounting adjustments primarily related to the merger with Progress Energy.

(g)Refer to Note 18 for additional information on amounts from consolidated VIEs.


	December 31, 2021
	Weighted
	Average				Duke				Duke		Duke		Duke		Duke
	Interest		Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Rate		Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Unsecured debt, maturing 2022-2082	3.71	%	$	24,564	$	1,150	$	2,250	$	—	$	150	$	1,330	$	700	$	2,990
Secured debt, maturing 2022-2052	2.50	%	5,584		1,094		2,397		1,120		1,278		—		—		—
First mortgage bonds, maturing 2022-2051(a)	3.87	%	31,026		10,507		15,450		8,375		7,075		1,850		3,219		—
Finance leases, maturing 2022-2051(b)	5.81	%	915		289		690		629		61		—		10		—

Tax-exempt bonds, maturing 2027-2041(c)	0.65	%	360		—		48		48		—		27		285		—
Notes payable and commercial paper(d)	0.35	%	3,929		—		—		—		—		—		—		—
Money pool/intercompany borrowings			—		526		2,959		322		199		128		150		518
Fair value hedge carrying value adjustment			4		4		—		—		—		—		—		—
Unamortized debt discount and premium, net(e)			1,119		(21)		(34)		(19)		(14)		(27)		(18)		(6)
Unamortized debt issuance costs(f)			(362)		(67)		(128)		(54)		(68)		(13)		(23)		(16)
Total debt	3.50	%	$	67,139	$	13,482	$	23,632	$	10,421	$	8,681	$	3,295	$	4,323	$	3,486
Short-term notes payable and commercial paper			(3,304)		—		—		—		—		—		—		—
Short-term money pool/intercompany borrowings			—		(226)		(2,809)		(172)		(199)		(103)		—		(518)
Current maturities of long-term debt(g)			(3,387)		(362)		(1,082)		(556)		(76)		—		(84)		—
Total long-term debt(g)			$	60,448	$	12,894	$	19,741	$	9,693	$	8,406	$	3,192	$	4,239	$	2,968

(a) Substantially all electric utility property is mortgaged under mortgage bond indentures.

(b) Duke Energy includes $256 million of finance lease purchase accounting adjustments related to Duke Energy Florida related to PPAs that are not accounted for as finance leases in their respective financial statements because of grandfathering provisions in GAAP.

(c) Substantially all tax-exempt bonds are secured by first mortgage bonds, letters of credit or the Master Credit Facility.

(d) Includes $625 million that was classified as Long-Term Debt on the Consolidated Balance Sheets due to the existence of long-term credit facilities that backstop these commercial paper balances, along with Duke Energy’s ability and intent to refinance these balances on a long-term basis. The weighted average days to maturity for Duke Energy's commercial paper programs was 15 days.

(e) Duke Energy includes $1,121 million and $100 million in purchase accounting adjustments related to Progress Energy and Piedmont, respectively.

(f) Duke Energy includes $29 million in purchase accounting adjustments primarily related to the merger with Progress Energy.

(g) Refer to Note 18 for additional information on amounts from consolidated VIEs.

Current Maturities of Long-Term Debt

The following table shows the significant components of Current maturities of Long-Term Debt on the Consolidated Balance Sheets. The Duke Energy Registrants currently anticipate satisfying these obligations with cash on hand and proceeds from additional borrowings.


(in millions)	Maturity Date	Interest Rate		December 31, 2022
Unsecured Debt
Duke Energy (Parent)	April 2023	2.875	%	$	350
Duke Energy (Parent)(a)	June 2023	3.469	%	500
Duke Energy (Parent)	October 2023	3.950	%	400
Duke Energy Ohio(a)	October 2023	4.272	%	150
Duke Energy Indiana(a)	October 2023	4.118	%	300



First Mortgage Bonds
Duke Energy Carolinas	March 2023	2.500	%	500
Duke Energy Carolinas	March 2023	3.050	%	500
Duke Energy Progress	September 2023	3.375	%	300
Duke Energy Ohio	September 2023	3.800	%	300

Other(b)				854
Current maturities of long-term debt				$	4,154

(a) Debt has a floating interest rate.

(b) Includes finance lease obligations, amortizing debt, tax-exempt bonds with mandatory put options and small bullet maturities.

Maturities and Call Options

The following table shows the annual maturities of long-term debt for the next five years and thereafter. Amounts presented exclude short-term notes payable, commercial paper and money pool borrowings and debt issuance costs for the Subsidiary Registrants.


	December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy(a)		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
2023	$	4,154	$	1,018	$	697	$	369	$	328	$	475	$	303	$	45
2024	3,216		19		939		72		867		—		4		40
2025	4,322		491		1,040		975		65		245		4		205
2026	2,682		621		345		279		66		45		4		40
2027	3,203		323		947		233		714		102		177		300
Thereafter	52,999		11,884		18,642		9,238		7,753		2,415		3,853		2,760
Total long-term debt, including current maturities	$	70,576	$	14,356	$	22,610	$	11,166	$	9,793	$	3,282	$	4,345	$	3,390

(a) Excludes $1,169 million in purchase accounting adjustments related to the Progress Energy merger and the Piedmont acquisition.

The Duke Energy Registrants have the ability under certain debt facilities to call and repay the obligation prior to its scheduled maturity. Therefore, the actual timing of future cash repayments could be materially different than as presented above.

Short-Term Obligations Classified as Long-Term Debt

Tax-exempt bonds that may be put to the Duke Energy Registrants at the option of the holder and certain commercial paper issuances and money pool borrowings are classified as Long-Term Debt on the Consolidated Balance Sheets. These tax-exempt bonds, commercial paper issuances and money pool borrowings, which are short-term obligations by nature, are classified as long-term due to Duke Energy’s intent and ability to utilize such borrowings as long-term financing. As Duke Energy’s Master Credit Facility and other bilateral letter of credit agreements have non-cancelable terms in excess of one year as of the balance sheet date, Duke Energy has the ability to refinance these short-term obligations on a long-term basis. The following tables show short-term obligations classified as long-term debt.


	December 31, 2022 and 2021
			Duke		Duke		Duke		Duke
	Duke		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Progress		Ohio		Indiana
Tax-exempt bonds	$	312	$	—	$	—	$	27	$	285
Commercial paper(a)	625		300		150		25		150

Total	$	937	$	300	$	150	$	52	$	435

(a) Progress Energy amounts are equal to Duke Energy Progress amounts.

Summary of Significant Debt Issuances

In January 2023, Duke Energy Carolinas issued $1.8 billion of first mortgage bonds. The issuance was split between a $900 million,10-year tranche at 4.95% and a $900 million, 30-year tranche at 5.35%. The net proceeds will be used to refinance $1 billion of Duke Energy Carolinas bonds maturing in March 2023, to pay down short-term debt and for general company purposes.

The following tables summarize significant debt issuances (in millions).


				Year Ended December 31, 2022
						Duke		Duke		Duke		Duke
	Maturity	Interest		Duke		Energy		Energy		Energy		Energy
Issuance Date	Date	Rate		Energy		(Parent)		Carolinas		Progress		Florida		Piedmont
Unsecured Debt
May 2022(a)	May 2052	5.050	%	$	400	$	—	$	—	$	—	$	—	$	400
June 2022(b)	June 2028	4.750	%	645		645		—		—		—		—
June 2022(b)	June 2034	5.306	%	537		537		—		—		—		—
August 2022(c)	March 2028	4.300	%	900		900		—		—		—		—
August 2022(c)	August 2032	4.500	%	1,150		1,150		—		—		—		—
August 2022(c)	August 2052	5.000	%	1,150		1,150		—		—				—
December 2022(d)	December 2025	5.000	%	500		500		—		—		—		—
December 2022(d)	December 2027	5.000	%	500		500		—		—		—		—


First Mortgage Bonds
March 2022(e)	March 2032	2.850	%	500		—		500		—		—		—
March 2022(e)	March 2052	3.550	%	650		—		650		—		—		—
March 2022(e)	April 2032	3.400	%	500		—		—		500		—		—
March 2022(e)	April 2052	4.000	%	400		—		—		400		—		—
November 2022(f)	November 2052	5.950	%	500		—		—		—		500		—
Tax-exempt Bonds
June 2022(g)	September 2030	4.000	%	168		168		—		—		—		—
June 2022(g)	November 2039	4.250	%	234		234		—		—		—		—
September 2022(h)	October 2046	3.300	%	200		—		—		200				—
September 2022(i)	October 2046	3.700	%	210		—		—		210				—
September 2022(i)	October 2046	4.000	%	42		—		—		42				—

Total issuances				$	9,186	$	5,784	$	1,150	$	1,352	$	500	$	400

(a)Debt issued to repay a portion of outstanding intercompany short-term debt and for general corporate purposes.

(b)Duke Energy (Parent) issued 600 million euros aggregate principal amount of 3.10% senior notes due June 2028 and 500 million euros aggregate principal amount of 3.85% senior notes due June 2034. Debt issued to repay a $500 million debt maturity, pay down short-term debt and for general corporate purposes. Duke Energy's obligations under its euro-denominated fixed-rate notes were effectively converted to fixed-rate U.S. dollars at issuance through cross-currency swaps, mitigating foreign currency exchange risk associated with the interest and principal payments. See Note 15 for additional information.

(c)Debt issued to repay a portion of short-term debt and for general corporate purposes.

(d)Proceeds will be used to repay a portion of commercial paper and for general corporate purposes.

(e)Debt issued to finance or refinance, in whole or in part, existing or new eligible projects under the sustainable financing framework.

(f)Debt issued to repay a portion of outstanding intercompany short-term debt and for general company purposes.

(g)Debt issued to refund the Ohio Air Quality Development Revenue Refunding bonds, previously held in treasury, which were used to finance or refinance portions of certain solid waste disposal facilities. The mandatory purchase date of these bonds is June 1, 2027.

(h)Debt issued to provide funds to refund the prior bonds, which were used to finance or refinance portions of certain air and water pollution control equipment and solid waste disposal equipment. The mandatory purchase date of these bonds is October 1, 2026.

(i)Debt issued to provide funds to refund the prior bonds, which were used to finance or refinance portions of certain air and water pollution control equipment and solid waste disposal equipment. The mandatory purchase date of these bonds is October 1, 2030.


				Year Ended December 31, 2021
						Duke		Duke		Duke		Duke
	Maturity	Interest		Duke		Energy		Energy		Energy		Energy
Issuance Date	Date	Rate		Energy		(Parent)		Carolinas		Progress		Florida		Piedmont
Unsecured Debt
March 2021a)	March 2031	2.500	%	$	350	$	—	$	—	$	—	$	—	$	350
June 2021(b)(c)	June 2023	0.299	%	500		500		—		—		—		—
June 2021(c)	June 2031	2.550	%	1,000		1,000		—		—		—		—
June 2021(c)	June 2041	3.300	%	750		750		—		—		—		—
June 2021(c)	June 2051	3.500	%	750		750		—		—		—		—
September 2021(d)	January 2082	3.250	%	500		500		—		—		—		—
Secured Debt
November 2021(e)	July 2031	1.679	%	100		—		100		—		—		—
November 2021(e)	July 2041	2.617	%	137		—		137		—		—		—
November 2021(e)	July 2028	1.295	%	221		—		—		221		—		—
November 2021(e)	July 2037	2.387	%	352		—		—		352		—		—
November 2021(e)	July 2041	2.799	%	197		—		—		197		—		—
First Mortgage Bonds
April 2021(f)	April 2031	2.550	%	550		—		550		—		—		—
April 2021(f)	April 2051	3.450	%	450		—		450		—		—		—
August 2021(g)	August 2031	2.000	%	650		—		—		650		—		—
August 2021(g)	August 2051	2.900	%	450		—		—		450		—		—
December 2021(h)	December 2031	2.400	%	650		—		—		—		650		—
December 2021(h)	December 2051	3.000	%	500		—		—		—		500		—
Total issuances				$	8,107	$	3,500	$	1,237	$	1,870	$	1,150	$	350

(a)Debt issued to repay at maturity $160 million senior unsecured notes due June 2021, pay down short-term debt and for general corporate purposes.

(b)Debt has a floating interest rate.

(c)Debt issued to repay $1.75 billion of Duke Energy (Parent) debt maturities, to repay a portion of short-term debt and for general corporate purposes.

(d)Debt issued to repay in October 2021 $500 million of Duke Energy (Parent) unsecured notes. The interest rate resets every five years.

(e)Debt issued to finance the North Carolina portion of storm restoration expenditures related to Hurricane Florence, Hurricane Michael, Hurricane Dorian and Winter Storm Diego.

(f)Debt issued to repay at maturity $500 million first mortgage bonds due June 2021, pay down short-term debt and for general company purposes.

(g)Debt issued to repay at maturity a total of $600 million first mortgage bonds due September 2021, pay down short-term debt and for general company purposes.

(h)Proceeds were used to finance or refinance, in whole or in part, existing or new eligible projects under the sustainable financing framework.

AVAILABLE CREDIT FACILITIES

Master Credit Facility

In March 2022, Duke Energy amended its existing Master Credit Facility to increase the amount of the facility from $8 billion to $9 billion and to extend the termination date to March 2027. The Duke Energy Registrants, excluding Progress Energy, have borrowing capacity under the Master Credit Facility up to a specified sublimit for each borrower. Duke Energy has the unilateral ability at any time to increase or decrease the borrowing sublimits of each borrower, subject to a maximum sublimit for each borrower. The amount available under the Master Credit Facility has been reduced to backstop issuances of commercial paper, certain letters of credit and variable-rate demand tax-exempt bonds that may be put to the Duke Energy Registrants at the option of the holder.

The table below includes the current borrowing sublimits and available capacity under these credit facilities.


	December 31, 2022
			Duke		Duke		Duke		Duke		Duke		Duke
	Duke		Energy		Energy		Energy		Energy		Energy		Energy
(in millions)	Energy		(Parent)		Carolinas		Progress		Florida		Ohio		Indiana		Piedmont
Facility size(a)	$	9,000	$	2,375	$	1,925	$	800	$	1,150	$	900	$	1,050	$	800
Reduction to backstop issuances
Commercial paper(b)	(3,685)		463		(1,533)		(389)		(605)		(522)		(585)		(514)
Outstanding letters of credit	(40)		(27)		(4)		(2)		(7)		—		—		—
Tax-exempt bonds	(81)		—		—		—		—		—		(81)		—

Available capacity	$	5,194	$	2,811	$	388	$	409	$	538	$	378	$	384	$	286

(a) Represents the sublimit of each borrower.

(b) Duke Energy issued $625 million of commercial paper and loaned the proceeds through the money pool to Duke Energy Carolinas, Duke Energy Progress, Duke Energy Ohio and Duke Energy Indiana. The balances are classified as Long-Term Debt Payable to Affiliated Companies in the Consolidated Balance Sheets.

Duke Energy (Parent) Term Loan Facility

On March 9, 2022, Duke Energy (Parent) entered into a Term Loan Credit Agreement (Credit Agreement) with commitments totaling $1.4 billion maturing on March 9, 2024. The maturity date of the Credit Agreement may be extended for up to two years by request of Duke Energy (Parent), upon satisfaction of certain conditions contained in the Credit Agreement. Borrowings under the facility were used to repay amounts drawn under the Three-Year Revolving Credit Facility and for general corporate purposes, including repayment of a portion of Duke Energy's outstanding commercial paper. In December 2022, Duke Energy (Parent) repaid $400 million of the term loan. The balance is classified as Long-Term Debt on Duke Energy's Consolidated Balance Sheets. The Three-Year Revolving Credit Facility was terminated in March 2022.

Duke Energy Florida Term Loan Facility

In October 2022, Duke Energy Florida entered into a term loan facility with commitments totaling $800 million expiring in April 2024. The term loan was fully drawn at the time of closing In October and borrowings were used for storm costs, under-collected fuel and general company purposes. The balance is classified as Long-Term Debt on Duke Energy Florida's Consolidated Balance Sheet.

Other Debt Matters

In September 2022, Duke Energy filed a Form S-3 with the SEC. Under this Form S-3, which is uncapped, the Duke Energy Registrants, excluding Progress Energy, may issue debt and other securities, including preferred stock, in the future at amounts, prices and with terms to be determined at the time of future offerings. The registration statement was filed to replace a similar prior filing upon expiration of its three-year term and also allows for the issuance of common and preferred stock by Duke Energy.

Also in September 2022, to replace another similar prior filing, Duke Energy filed an effective Form S-3 with the SEC to sell up to $4 billion of variable denomination floating-rate demand notes, called PremierNotes. The Form S-3 states that no more than $2 billion of the notes will be outstanding at any particular time. The notes are offered on a continuous basis and bear interest at a floating rate per annum determined by the Duke Energy PremierNotes Committee, or its designee, on a weekly basis. The interest rate payable on notes held by an investor may vary based on the principal amount of the investment. The notes have no stated maturity date, are non-transferable and may be redeemed in whole or in part by Duke Energy or at the investor’s option at any time. The balance as of December 31, 2022, and 2021, was $897 million and $1,066 million, respectively. The notes are short-term debt obligations of Duke Energy and are reflected as Notes payable and commercial paper on Duke Energy’s Consolidated Balance Sheets.

Money Pool and Intercompany Credit Agreements

The Subsidiary Registrants, excluding Progress Energy, are eligible to receive support for their short-term borrowing needs through participation with Duke Energy and certain of its subsidiaries in a money pool arrangement. Under this arrangement, those companies with short-term funds may provide short-term loans to affiliates participating in this arrangement. The money pool is structured such that the Subsidiary Registrants, excluding Progress Energy, separately manage their cash needs and working capital requirements. Accordingly, there is no net settlement of receivables and payables between money pool participants. Duke Energy (Parent), may loan funds to its participating subsidiaries, but may not borrow funds through the money pool. Accordingly, as the money pool activity is between Duke Energy and its subsidiaries, all money pool balances are eliminated within Duke Energy’s Consolidated Balance Sheets.

Money pool receivable balances are reflected within Notes receivable from affiliated companies on the Subsidiary Registrants’ Consolidated Balance Sheets. Money pool payable balances are reflected within either Notes payable to affiliated companies or Long-Term Debt Payable to Affiliated Companies on the Subsidiary Registrants’ Consolidated Balance Sheets.

In March 2022, Progress Energy closed a revolving credit agreement with Duke Energy (Parent), which allowed up to $2.5 billion in intercompany borrowings.

Restrictive Debt Covenants

The Duke Energy Registrants’ debt and credit agreements contain various financial and other covenants. Duke Energy's Master Credit Facility contains a covenant requiring the debt-to-total capitalization ratio not to exceed 65% for each borrower, excluding Piedmont, and 70% for Piedmont. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of December 31, 2022, Duke Energy presented approximately $131 million of long-term debt as current on the Consolidated Balance Sheet as a result of a technical default due to the bankruptcy filing of a Duke Energy customer. The Duke Energy Registrants were in compliance with all other covenants related to their debt agreements as of December 31, 2022. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the debt or credit agreements contain material adverse change clauses.

Other Loans

As of December 31, 2022, and 2021, Duke Energy had loans outstanding of $852 million, including $33 million at Duke Energy Progress and $819 million, including $34 million at Duke Energy Progress, respectively, against the cash surrender value of life insurance policies it owns on the lives of its executives. The amounts outstanding were carried as a reduction of the related cash surrender value that is included in Other within Other Noncurrent Assets on the Consolidated Balance Sheets.

8. GUARANTEES AND INDEMNIFICATIONS

Duke Energy has various financial and performance guarantees and indemnifications with non-consolidated entities, which are issued in the normal course of business. As discussed below, these contracts include performance guarantees, standby letters of credit, debt guarantees and indemnifications and include guarantees and indemnifications related to Commercial Renewables Disposal Groups. Duke Energy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. At December 31, 2022, Duke Energy does not believe conditions are likely for significant performance under these guarantees. To the extent liabilities are incurred as a result of the activities covered by the guarantees, such liabilities are included on the accompanying Consolidated Balance Sheets.

On January 2, 2007, Duke Energy completed the spin-off of its previously wholly owned natural gas businesses to shareholders. Guarantees issued by Duke Energy or its affiliates, or assigned to Duke Energy prior to the spin-off, remained with Duke Energy subsequent to the spin-off. Guarantees issued by Spectra Energy Capital, LLC (Spectra Capital) or its affiliates prior to the spin-off remained with Spectra Capital subsequent to the spin-off, except for guarantees that were later assigned to Duke Energy. Duke Energy has indemnified Spectra Capital against any losses incurred under certain of the guarantee obligations that remain with Spectra Capital. At December 31, 2022, the maximum potential amount of future payments associated with these guarantees were $40 million, the majority of which expire by 2028.

In October 2017, ACP executed a $3.4 billion revolving credit facility with a stated maturity date of October 2021. Duke Energy entered into a guarantee agreement to support its share of the ACP revolving credit facility. In July 2020, ACP reduced the size of the credit facility to $1.9 billion. Duke Energy's maximum exposure to loss under the terms of the guarantee was $860 million as of December 31, 2020. This amount represented 47% of the outstanding borrowings under the credit facility and was recognized within Other Current Liabilities on the Consolidated Balance Sheets at December 31, 2020, of which $95 million was previously recognized due the adoption of new guidance for credit losses effective January 1, 2020. In February 2021, Duke Energy paid approximately $855 million to fund ACP's outstanding debt, relieving Duke Energy of its guarantee. See Notes 4 and 13 for more information.

In addition to the Spectra Capital and ACP revolving credit facility guarantees above, Duke Energy has issued performance guarantees to customers and other third parties that guarantee the payment and performance of other parties, including certain non-wholly owned entities, as well as guarantees of debt of certain non-consolidated entities. If such entities were to default on payments or performance, Duke Energy would be required under the guarantees to make payments on the obligations of these entities. The maximum potential amount of future payments required under these guarantees as of December 31, 2022, was $33 million of which all expire between 2024 and 2030, with the remaining performance guarantees having no contractual expiration. Additionally, certain guarantees have uncapped maximum potential payments; however, Duke Energy does not believe these guarantees will have a material effect on its results of operations, cash flows or financial position.

Duke Energy uses bank-issued standby letters of credit to secure the performance of wholly owned and non-wholly owned entities to a third party or customer. Under these arrangements, Duke Energy has payment obligations to the issuing bank that are triggered by a draw by the third party or customer due to the failure of the wholly owned or non-wholly owned entity to perform according to the terms of its underlying contract. At December 31, 2022, Duke Energy had issued a total of $667 million in letters of credit, which expire between 2023 and 2028. The unused amount under these letters of credit was $35 million.

Duke Energy recognized $2 million and $3 million as of December 31, 2022, and 2021, respectively, primarily in Other within Other Noncurrent Liabilities on the Consolidated Balance Sheets, for the guarantees discussed above. As current estimates change, additional losses related to guarantees and indemnifications to third parties, which could be material, may be recorded by the Duke Energy Registrants in the future.

9. JOINT OWNERSHIP OF GENERATING AND TRANSMISSION FACILITIES

The Duke Energy Registrants maintain ownership interests in certain jointly owned generating and transmission facilities. The Duke Energy Registrants are entitled to a share of the generating capacity and output of each unit equal to their respective ownership interests. The Duke Energy Registrants pay their ownership share of additional construction costs, fuel inventory purchases and operating expenses. The Duke Energy Registrants share of revenues and operating costs of the jointly owned facilities is included within the corresponding line in the Consolidated Statements of Operations. Each participant in the jointly owned facilities must provide its own financing.

The following table presents the Duke Energy Registrants' interest of jointly owned plant or facilities and amounts included on the Consolidated Balance Sheets. All facilities are operated by the Duke Energy Registrants and are included in the Electric Utilities and Infrastructure segment.


	December 31, 2022
							Construction
	Ownership		Property, Plant		Accumulated		Work in
(in millions except for ownership interest)	Interest		and Equipment		Depreciation		Progress
Duke Energy Carolinas
Catawba (units 1 and 2)(a)	19.25	%	$	1,047	$	546	$	32
W.S. Lee CC(b)	87.27	%	613		86		48
Duke Energy Indiana
Gibson (unit 5)(c)	50.05	%	450		241		2
Vermillion(d)	62.50	%	182		113		1
Transmission and local facilities(c)	Various		6,718		1,510		157

(a) Jointly owned with North Carolina Municipal Power Agency Number 1, NCEMC and PMPA.

(b) Jointly owned with NCEMC.

(d) Jointly owned with WVPA.

10. ASSET RETIREMENT OBLIGATIONS

Duke Energy records an ARO when it has a legal obligation to incur retirement costs associated with the retirement of a long-lived asset and the obligation can be reasonably estimated. Certain assets of the Duke Energy Registrants have an indeterminate life, such as transmission and distribution facilities, and thus the fair value of the retirement obligation is not reasonably estimable. A liability for these AROs will be recorded when a fair value is determinable.

The Duke Energy Registrants’ regulated operations accrue costs of removal for property that does not have an associated legal retirement obligation based on regulatory orders from state commissions. These costs of removal are recorded as a regulatory liability in accordance with regulatory accounting treatment. The Duke Energy Registrants do not accrue the estimated cost of removal for any nonregulated assets. See Note 4 for the estimated cost of removal for assets without an associated legal retirement obligation, which are included in Regulatory liabilities on the Consolidated Balance Sheets.

The following table presents the AROs recorded on the Consolidated Balance Sheets.


	December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Decommissioning of nuclear power facilities(a)	$	7,261	$	3,009	$	4,217	$	3,948	$	270	$	—	$	—	$	—
Closure of ash impoundments	5,176		2,309		1,862		1,833		29		95		911		—
Other	291		64		102		42		59		59		40		26
Total asset retirement obligation	$	12,728	$	5,382	$	6,181	$	5,823	$	358	$	154	$	951	$	26
Less: Current portion	773		261		289		288		1		17		207		—
Total noncurrent asset retirement obligation	$	11,955	$	5,121	$	5,892	$	5,535	$	357	$	137	$	744	$	26

(a) Duke Energy amount includes purchase accounting adjustments related to the merger with Progress Energy.

Nuclear Decommissioning Liability

AROs related to nuclear decommissioning are based on site-specific cost studies. The NCUC, PSCSC and FPSC require updated cost estimates for decommissioning nuclear plants every five years.

The following table summarizes information about the most recent site-specific nuclear decommissioning cost studies. Decommissioning costs are stated in 2018 or 2019 dollars, depending on the year of the cost study, and include costs to decommission plant components not subject to radioactive contamination.


	Annual Funding		Decommissioning
(in millions)	Requirement(a)		Costs(a)		Year of Cost Study
Duke Energy	$	10	$	9,105	2018 or 2019
Duke Energy Carolinas(b)(c)	—		4,365		2018
Duke Energy Progress(d)	10		4,181		2019
Duke Energy Florida(e)	—		559		N/A

(a) Amount represents annual funding requirement for the current fiscal year. Amounts for Progress Energy equal the sum of Duke Energy Progress and Duke Energy Florida.

(b) Decommissioning costs for Duke Energy Carolinas reflects its ownership interest in jointly owned reactors. Other joint owners are responsible for decommissioning costs related to their interest in the reactors.

(c) Duke Energy Carolinas' site-specific nuclear decommissioning cost study completed in 2018 was filed with the NCUC and PSCSC in 2019. A new funding study was also completed and filed with the NCUC and PSCSC in 2019.

(d) Duke Energy Progress' site-specific nuclear decommissioning cost study completed in 2019 was filed with the NCUC and PSCSC in March 2020. Duke Energy Progress also completed a funding study, which was filed with the NCUC and PSCSC in July 2020. In October 2021, Duke Energy Progress filed the 2019 nuclear decommissioning cost study with the FERC, as well as a revised rate schedule for decommissioning expense to be collected from wholesale customers. The FERC accepted the filing, as filed on December 9, 2021.

(e) During 2019, Duke Energy Florida reached an agreement to transfer decommissioning work for Crystal River Unit 3 to a third party and decommissioning costs are based on the agreement with this third party rather than a cost study. Regulatory approval was received from the NRC and the FPSC in April 2020 and August 2020, respectively.

Nuclear Decommissioning Trust Funds

Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida each maintain NDTFs that are intended to pay for the decommissioning costs of their respective nuclear power plants. The NDTF investments are managed and invested in accordance with applicable requirements of various regulatory bodies including the NRC, FERC, NCUC, PSCSC, FPSC and the IRS.

Use of the NDTF investments is restricted to nuclear decommissioning activities including license termination, spent fuel and site restoration. The license termination and spent fuel obligations relate to contaminated decommissioning and are recorded as AROs. The site restoration obligation relates to non-contaminated decommissioning and is recorded to cost of removal within Regulatory liabilities on the Consolidated Balance Sheets.

The following table presents the fair value of NDTF assets legally restricted for purposes of settling AROs associated with nuclear decommissioning. Duke Energy Florida entered into an agreement with a third party to decommission Crystal River Unit 3 and was granted an exemption from the NRC, which allows for use of the NDTF for all aspects of nuclear decommissioning. The entire balance of Duke Energy Florida's NDTF may be applied toward license termination, spent fuel and site restoration costs incurred to decommission Crystal River Unit 3 and is excluded from the table below. See Note 17 for additional information related to the fair value of the Duke Energy Registrants' NDTFs.


	December 31,
(in millions)	2022		2021
Duke Energy	$	7,466	$	8,933
Duke Energy Carolinas	4,208		5,068
Duke Energy Progress	3,258		3,865

Nuclear Operating Licenses

As described in Note 4, Duke Energy Carolinas and Duke Energy Progress intend to seek renewal of operating licenses and 20-year license extensions for all of their nuclear stations. The following table includes the current expiration of nuclear operating licenses.


Unit			Year of Expiration
Duke Energy Carolinas
Catawba Units 1 and 2			2043

McGuire Unit 1			2041
McGuire Unit 2			2043
Oconee Units 1 and 2			2033

Oconee Unit 3			2034
Duke Energy Progress
Brunswick Unit 1			2036
Brunswick Unit 2			2034
Harris			2046
Robinson			2030

The NRC has acknowledged permanent cessation of operation and permanent removal of fuel from the reactor vessel at Crystal River Unit 3. Therefore, the license no longer authorizes operation of the reactor. During 2019, Duke Energy Florida entered into an agreement for the accelerated decommissioning of Crystal River Unit 3. Regulatory approval was received from the NRC and the FPSC in April 2020 and August 2020, respectively. See Note 4 for more information.

Closure of Ash Impoundments

The Duke Energy Registrants are subject to state and federal regulations covering the closure of coal ash impoundments, including the EPA CCR rule and the Coal Ash Act, and other agreements. AROs recorded on the Duke Energy Registrants' Consolidated Balance Sheets include the legal obligation for closure of coal ash basins and the disposal of related ash as a result of these regulations and agreements.

The ARO amount recorded on the Consolidated Balance Sheets is based upon estimated closure costs for impacted ash impoundments. The amount recorded represents the discounted cash flows for estimated closure costs based upon specific closure plans. Actual costs to be incurred will be dependent upon factors that vary from site to site. The most significant factors are the method and time frame of closure at the individual sites. Closure methods considered include removing the water from ash basins, consolidating material as necessary and capping the ash with a synthetic barrier, excavating and relocating the ash to a lined structural fill or lined landfill or recycling the ash for concrete or some other beneficial use. The ultimate method and timetable for closure will be in compliance with standards set by federal and state regulations and other agreements. The ARO amount will be adjusted as additional information is gained through the closure and post-closure process, including acceptance and approval of compliance approaches, which may change management assumptions, and may result in a material change to the balance. See ARO Liability Rollforward section below for information on revisions made to the coal ash liability during 2022 and 2021.

Asset retirement costs associated with the AROs for operating plants and retired plants are included in Net property, plant and equipment and Regulatory assets, respectively, on the Consolidated Balance Sheets. See Note 4 for additional information on Regulatory assets related to AROs and Note 5 for additional information on commitments and contingencies.

Cost recovery for future expenditures will be pursued through the normal ratemaking process with federal and state utility commissions, which permit recovery of necessary and prudently incurred costs associated with Duke Energy’s regulated operations. See Note 4 for additional information on recovery of coal ash costs.

ARO Liability Rollforward

The following tables present changes in the liability associated with AROs.


			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Balance at December 31, 2020	$	12,854	$	5,350	$	6,149	$	5,635	$	514	$	111	$	1,176	$	20

Accretion expense(a)	504		242		229		212		17		4		35		1
Liabilities settled(b)	(613)		(210)		(324)		(214)		(110)		(3)		(77)		—
Liabilities incurred in the current year	14		8		6		—		6		—		—		—
Revisions in estimates of cash flows(c)	(159)		(89)		52		42		10		24		(147)		1
Balance at December 31, 2021	12,600		5,301		6,112		5,675		437		136		987		22

Accretion expense(a)	501		242		229		215		14		6		30		1
Liabilities settled(b)	(680)		(234)		(334)		(228)		(106)		(13)		(98)		—
Liabilities incurred in the current year	22		—		18		—		18		—		5		—
Revisions in estimates of cash flows(c)	285		73		156		161		(5)		25		27		3
Balance at December 31, 2022	$	12,728	$	5,382	$	6,181	$	5,823	$	358	$	154	$	951	$	26

(a) Substantially all accretion expense for the years ended December 31, 2022, and 2021, relates to Duke Energy’s regulated operations and has been deferred in accordance with regulatory accounting treatment.

(b) Amounts primarily relate to ash impoundment closures and nuclear decommissioning.

(c) The amounts recorded represent the discounted cash flows for estimated closure costs as evaluated on a site-by-site basis. The increases in 2022 primarily relate to higher unit costs associated with basin closure and routine maintenance. The decreases in 2021 primarily relate to revised basin closure cost estimates, partially offset by increases related to new closure plan approvals, post closure maintenance and beneficiation costs.

11. PROPERTY, PLANT AND EQUIPMENT

The following tables summarize the property, plant and equipment for Duke Energy and its subsidiary registrants.


	December 31, 2022
	Average
	Remaining			Duke				Duke		Duke		Duke		Duke
	Useful Life	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	(Years)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Land		$	2,232	$	565	$	993	$	496	$	497	$	230	$	124	$	295
Plant – Regulated
Electric generation, distribution and transmission	39	126,016		46,640		55,872		33,336		22,536		6,900		16,604		—
Natural gas transmission and distribution	56	13,174		—		—		—		—		3,773		—		9,401
Other buildings and improvements	40	2,537		973		647		341		306		398		336		183
Plant – Nonregulated

Other buildings and improvements	10	369		—		—		—		—		—		—		—
Nuclear fuel		3,081		1,723		1,358		1,358		—		—		—		—
Equipment	13	2,959		710		936		567		369		441		356		125
Construction in process		7,381		2,671		3,073		1,317		1,756		375		381		478
Other	15	6,090		1,368		1,943		1,460		476		380		320		387
Total property, plant and equipment(a)		163,839		54,650		64,822		38,875		25,940		12,497		18,121		10,869
Total accumulated depreciation – regulated(b)(c)		(50,544)		(18,669)		(20,584)		(14,201)		(6,377)		(3,250)		(6,021)		(2,081)
Total accumulated depreciation – nonregulated(d)		(1,556)		—		—		—		—		—		—		—
Facilities to be retired, net		9		—		—		—		—		—		—		9
Total net property, plant and equipment		$	111,748	$	35,981	$	44,238	$	24,674	$	19,563	$	9,247	$	12,100	$	8,797

(a) Includes finance leases of $816 million, $335 million, $674 million, $590 million, $84 million and $10 million at Duke Energy, Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida and Duke Energy Indiana, respectively, primarily within Plant – Regulated. The Progress Energy, Duke Energy Progress and Duke Energy Florida amounts are net of $233 million, $81 million and $152 million, respectively, of accumulated amortization of finance leases.

(b) Includes $1,683 million, $934 million, $749 million and $749 million of accumulated amortization of nuclear fuel at Duke Energy, Duke Energy Carolinas, Progress Energy and Duke Energy Progress, respectively.

(c) Includes accumulated amortization of finance leases of $7 million, $51 million and $4 million at Duke Energy, Duke Energy Carolinas and Duke Energy Indiana, respectively.

(d) Includes accumulated amortization of finance leases of ($1 million) at Duke Energy.


	December 31, 2021
	Average
	Remaining			Duke				Duke		Duke		Duke		Duke
	Useful Life	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	(Years)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Land		$	2,145	$	543	$	957	$	482	$	475	$	219	$	122	$	279
Plant – Regulated
Electric generation, distribution and transmission	40	120,855		44,910		53,447		32,417		21,030		6,573		15,925		—
Natural gas transmission and distribution	54	12,079		—		—		—		—		3,347		—		8,732
Other buildings and improvements	37	1,921		550		514		228		286		381		321		155
Plant – Nonregulated

Other buildings and improvements	11	401		—		—		—		—		—		—		—
Nuclear fuel		3,181		1,856		1,325		1,325		—		—		—		—
Equipment	13	2,659		614		791		497		294		403		262		122
Construction in process		5,979		2,078		2,297		954		1,343		515		460		262
Other	14	5,276		1,323		1,563		1,115		437		287		253		368
Total property, plant and equipment(a)		154,496		51,874		60,894		37,018		23,865		11,725		17,343		9,918
Total accumulated depreciation – regulated(b)(c)		(47,611)		(17,854)		(19,214)		(13,387)		(5,819)		(3,106)		(5,583)		(1,899)
Total accumulated depreciation – nonregulated(d)		(1,493)		—		—		—		—		—		—		—
Facilities to be retired, net		144		102		26		26		—		6		—		11
Total net property, plant and equipment		$	105,536	$	34,122	$	41,706	$	23,657	$	18,046	$	8,625	$	11,760	$	8,030

(a) Includes finance leases of $958 million, $335 million, $729 million, $627 million, $102 million, and $10 million at Duke Energy, Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida and Duke Energy Indiana, respectively, primarily within Plant – Regulated. The Progress Energy, Duke Energy Progress and Duke Energy Florida amounts are net of $178 million, $45 million and $133 million, respectively, of accumulated amortization of finance leases.

(b) Includes $1,799 million, $1,064 million, $735 million and $735 million of accumulated amortization of nuclear fuel at Duke Energy, Duke Energy Carolinas, Progress Energy and Duke Energy Progress, respectively.

(c) Includes accumulated amortization of finance leases of $9 million, $33 million, and $3 million at Duke Energy, Duke Energy Carolinas and Duke Energy Indiana, respectively.

(d) Includes accumulated amortization of finance leases of ($1 million) at Duke Energy.

Duke Energy continues to execute on its business transformation strategy, including the evaluation of in-office work policies considering the experience with the COVID-19 pandemic and also workforce realignment of roles and responsibilities. In May 2021, Duke Energy management approved the sale of certain properties and entered into an agreement to exit certain leased space on December 31, 2021. The sale of the properties is subject to abandonment accounting and resulted in an impairment charge. Additionally, the exit of the leased space resulted in the impairment of related furniture, fixtures and equipment. During the year ended December 31, 2021, Duke Energy recorded a pretax charge to earnings of $192 million on the Consolidated Statements of Operations, which includes $133 million within Impairment of assets and other charges, $42 million within Operations, maintenance and other and $17 million within Depreciation and amortization.

The following table presents capitalized interest, which includes the debt component of AFUDC.


	Years Ended December 31,
(in millions)	2022		2021		2020
Duke Energy	$	118	$	66	$	96
Duke Energy Carolinas	50		29		28
Progress Energy	26		20		17
Duke Energy Progress	19		14		12
Duke Energy Florida	7		6		5
Duke Energy Ohio	14		20		26
Duke Energy Indiana(a)	3		(17)		10
Piedmont	4		9		8

(a) In 2021, Duke Energy Indiana is primarily compromised of ($24 million) of PISCC amortization, which is partially offset by $7 million of the debt component of AFUDC.

12. GOODWILL AND INTANGIBLE ASSETS

GOODWILL

Duke Energy

Duke Energy's Goodwill balance of $19.3 billion is allocated $17.4 billion to EU&I and $1.9 billion to GU&I on Duke Energy's Consolidated Balance Sheets at December 31, 2022, and 2021. There are no accumulated impairment charges.

Duke Energy Ohio

Duke Energy Ohio's Goodwill balance of $920 million, allocated $596 million to EU&I and $324 million to GU&I, is presented net of accumulated impairment charges of $216 million on the Consolidated Balance Sheets at December 31, 2022, and 2021.

Progress Energy

Progress Energy's Goodwill is included in the EU&I segment and there are no accumulated impairment charges.

Piedmont

Piedmont's Goodwill is included in the GU&I segment and there are no accumulated impairment charges.

Goodwill Impairment Testing

Duke Energy, Progress Energy, Duke Energy Ohio and Piedmont are required to perform an annual goodwill impairment test as of the same date each year and, accordingly, perform their annual impairment testing of goodwill as of August 31. Duke Energy, Progress Energy, Duke Energy Ohio and Piedmont update their test between annual tests if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. As the fair value for Duke Energy, Progress Energy, Duke Energy Ohio and Piedmont exceeded their respective carrying values at the date of the annual impairment analysis, no goodwill impairment charges were recorded in 2022.

INTANGIBLE ASSETS

The following tables show the carrying amount and accumulated amortization of intangible assets included in Other within Other Noncurrent Assets on the Consolidated Balance Sheets of the Duke Energy Registrants at December 31, 2022, and 2021.


	December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Emission allowances	$	8	$	—	$	5	$	2	$	3	$	—	$	2	$	—
Renewable energy certificates	210		84		124		124		—		2		—		—


Other	55		—		4		1		3		—		—		22
Total gross carrying amounts	273		84		133		127		6		2		2		22


Accumulated amortization – other	(8)		—		(1)		—		(1)		—		—		(2)
Total accumulated amortization	(8)		—		(1)		—		(1)		—		—		(2)
Total intangible assets, net	$	265	$	84	$	132	$	127	$	5	$	2	$	2	$	20


	December 31, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Emission allowances	$	8	$	—	$	5	$	2	$	3	$	—	$	2	$	—
Renewable energy certificates	204		73		131		131		—		—		—		—
Natural gas, coal and power contracts	24		—		—		—		—		—		24		—

Other	28		—		—		—		—		—		—		—
Total gross carrying amounts	264		73		136		133		3		—		26		—
Accumulated amortization – natural gas, coal and power contracts	(24)		—		—		—		—		—		(24)		—

Accumulated amortization – other	(4)		—		—		—		—		—		—		—
Total accumulated amortization	(28)		—		—		—		—		—		(24)		—
Total intangible assets, net	$	236	$	73	$	136	$	133	$	3	$	—	$	2	$	—

Amortization Expense

Amortization expense amounts for other intangible assets are immaterial for the years ended December 31, 2022, 2021 and 2020, and are expected to be immaterial for the next five years as of December 31, 2022.

13. INVESTMENTS IN UNCONSOLIDATED AFFILIATES

EQUITY METHOD INVESTMENTS

Investments in affiliates that are not controlled by Duke Energy, but over which it has significant influence, are accounted for using the equity method.

The following table presents Duke Energy’s investments in unconsolidated affiliates accounted for under the equity method, as well as the respective equity in earnings, by segment, for periods presented in this filing.


	Years Ended December 31,
	2022				2021				2020
			Equity in				Equity in		Equity in
			earnings				earnings		earnings
(in millions)	Investments		(losses)		Investments		(losses)		(losses)
Electric Utilities and Infrastructure	$	99	$	7	$	104	$	7	$	(1)
Gas Utilities and Infrastructure	240		21		231		8		(2,017)

Other	116		85		122		47		13
Total	$	455	$	113	$	457	$	62	$	(2,005)

During the years ended December 31, 2022, 2021 and 2020, Duke Energy received distributions from equity investments of $111 million, $56 million and $34 million, respectively, which are included in Other assets within Cash Flows from Operating Activities on the Consolidated Statements of Cash Flows. During the years ended December 31, 2022, 2021 and 2020, Duke Energy received distributions from equity investments of $6 million, $14 million and $23 million, respectively, which are included in Return of investment capital within Cash Flows from Investing Activities on the Consolidated Statements of Cash Flows.

During the years ended December 31, 2022, 2021 and 2020, Piedmont received distributions from equity investments of $31 million, $8 million and $2 million, respectively, which are included in Other assets within Cash Flows from Operating Activities. During the years ended December 31, 2021, and 2020, Piedmont received distributions from equity investments of $2 million and $2 million, respectively, which are included within Cash Flows from Investing Activities on the Consolidated Statements of Cash Flows. Amounts received during the year ended December 31, 2022, included in Cash Flows from Investing Activities on the Consolidated Statements of Cash Flows were immaterial.

Significant investments in affiliates accounted for under the equity method are discussed below.

Electric Utilities and Infrastructure

Duke Energy owns 50% interests in both DATC and Pioneer, which build, own and operate electric transmission facilities in North America.

Gas Utilities and Infrastructure

Pipeline Investments

Piedmont owns a 21.49% investment in Cardinal, an intrastate pipeline located in North Carolina.

Duke Energy owns a 7.5% interest in Sabal Trail, a 517-mile interstate natural gas pipeline, which provides natural gas to Duke Energy Florida and Florida Power and Light.

Duke Energy owns a 47% interest in the ACP pipeline. In 2020, Duke Energy determined it would no longer continue its investment in the construction of the ACP pipeline. See Notes 4 and 8 for further information.

Storage Facilities

Piedmont owns a 45% interest in Pine Needle, an interstate LNG storage facility located in North Carolina, and a 50% interest in Hardy Storage, an underground interstate natural gas storage facility located in West Virginia.

Renewable Natural Gas Investments

Duke Energy owns a 29.68% investment in SustainRNG, a developer of renewable natural gas projects, a 70% interest in Sustain T&W, SustainRNG's renewable natural gas project located in Georgia, and a 70% interest in Sustain Liberty, SustainRNG's renewable natural gas project located in North Carolina.

Other

Duke Energy has a 17.5% indirect economic ownership interest and a 25% board representation and voting rights interest in NMC, which owns and operates a methanol and MTBE business in Jubail, Saudi Arabia.

Significant Subsidiaries

For the year ended December 31, 2020, Duke Energy's investment in ACP met the requirements of S-X Rule 4-08(g) to provide summarized financial information. The following table provides summary information for ACP as required under S-X Rule 1-02(bb) for the period of significance in Duke Energy's consolidated statements of operations. For the years ended December 31, 2022, and 2021, there were no investments that met the significance requirements.











	Year Ended
	December 31, 2020
Net revenues	$	—
Operating loss	(4,612)

Net loss	(4,512)

Net loss attributable to Duke Energy	$	(2,121)

14. RELATED PARTY TRANSACTIONS

The Subsidiary Registrants engage in related party transactions in accordance with the applicable state and federal commission regulations. Refer to the Consolidated Balance Sheets of the Subsidiary Registrants for balances due to or due from related parties. Material amounts related to transactions with related parties included in the Consolidated Statements of Operations and Comprehensive Income are presented in the following table.


	Years Ended December 31,
(in millions)	2022		2021		2020
Duke Energy Carolinas
Corporate governance and shared service expenses(a)	$	838	$	894	$	753
Indemnification coverages(b)	28		24		20
Joint Dispatch Agreement (JDA) revenue(c)	109		41		25
JDA expense(c)	600		207		114
Intercompany natural gas purchases(d)	12		11		15
Progress Energy
Corporate governance and shared service expenses(a)	$	818	$	856	$	715
Indemnification coverages(b)	43		41		36
JDA revenue(c)	600		207		114
JDA expense(c)	109		41		25
Intercompany natural gas purchases(d)	76		75		75
Duke Energy Progress
Corporate governance and shared service expenses(a)	$	469	$	504	$	420
Indemnification coverages(b)	20		19		17
JDA revenue(c)	600		207		114
JDA expense(c)	109		41		25
Intercompany natural gas purchases(d)	76		75		75
Duke Energy Florida
Corporate governance and shared service expenses(a)	$	349	$	352	$	295
Indemnification coverages(b)	23		22		19
Duke Energy Ohio
Corporate governance and shared service expenses(a)	$	334	$	329	$	326
Indemnification coverages(b)	5		4		4
Duke Energy Indiana
Corporate governance and shared service expenses(a)	$	447	$	409	$	401
Indemnification coverages(b)	8		8		8
Piedmont
Corporate governance and shared service expenses(a)	$	155	$	139	$	140
Indemnification coverages(b)	3		3		3
Intercompany natural gas sales(d)	88		86		90
Natural gas storage and transportation costs(e)	23		22		23

(a)The Subsidiary Registrants are charged their proportionate share of corporate governance and other shared services costs, primarily related to human resources, employee benefits, information technology, legal and accounting fees, as well as other third-party costs. These amounts are primarily recorded in Operation, maintenance and other on the Consolidated Statements of Operations and Comprehensive Income.

(b)The Subsidiary Registrants incur expenses related to certain indemnification coverages through Bison, Duke Energy’s wholly owned captive insurance subsidiary. These expenses are recorded in Operation, maintenance and other on the Consolidated Statements of Operations and Comprehensive Income.

(c)Duke Energy Carolinas and Duke Energy Progress participate in a JDA, which allows the collective dispatch of power plants between the service territories to reduce customer rates. Revenues from the sale of power and expenses from the purchase of power pursuant to the JDA are recorded in Operating Revenues and Fuel used in electric generation and purchased power, respectively, on the Consolidated Statements of Operations and Comprehensive Income.

(d)Piedmont provides long-term natural gas delivery service to certain Duke Energy Carolinas and Duke Energy Progress natural gas-fired generation facilities. Piedmont records the sales in Operating Revenues, and Duke Energy Carolinas and Duke Energy Progress record the related purchases as a component of Fuel used in electric generation and purchased power on their respective Consolidated Statements of Operations and Comprehensive Income. These intercompany revenues and expenses are eliminated in consolidation.

(e)Piedmont has related party transactions as a customer of its equity method investments in Pine Needle, Hardy Storage, and Cardinal natural gas storage and transportation facilities. These expenses are included in Cost of natural gas on Piedmont's Consolidated Statements of Operations and Comprehensive Income.

In addition to the amounts presented above, the Subsidiary Registrants have other affiliate transactions, including rental of office space, participation in a money pool arrangement, other operational transactions and their proportionate share of certain charged expenses. See Note 7 for more information regarding money pool. These transactions of the Subsidiary Registrants are incurred in the ordinary course of business and are eliminated in consolidation.

As discussed in Note 18, certain trade receivables have been sold by Duke Energy Ohio and Duke Energy Indiana to CRC, an affiliate formed by a subsidiary of Duke Energy. The proceeds obtained from the sales of receivables are largely cash but do include a subordinated note from CRC for a portion of the purchase price.

Intercompany Income Taxes

Duke Energy and the Subsidiary Registrants file a consolidated federal income tax return and other state and jurisdictional returns. The Subsidiary Registrants have a tax sharing agreement with Duke Energy for the allocation of consolidated tax liabilities and benefits. Income taxes recorded represent amounts the Subsidiary Registrants would incur as separate C-Corporations. The following table includes the balance of intercompany income tax receivables and payables for the Subsidiary Registrants.


	Duke				Duke		Duke		Duke		Duke
	Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
December 31, 2022
Intercompany income tax receivable	$	—	$	95	$	36	$	17	$	—	$	—	$	—
Intercompany income tax payable	37		—		—		—		17		18		38

December 31, 2021
Intercompany income tax receivable	$	—	$	—	$	—	$	40	$	19	$	—	$	—
Intercompany income tax payable	62		—		84		—		—		10		27

15. DERIVATIVES AND HEDGING

The Duke Energy Registrants use commodity, interest rate and foreign currency contracts to manage commodity price risk, interest rate risk and foreign currency exchange rate risk. The primary use of commodity derivatives is to hedge the generation portfolio against changes in the prices of electricity and natural gas. Piedmont enters into natural gas supply contracts to provide diversification, reliability and natural gas cost benefits to its customers. Interest rate derivatives are used to manage interest rate risk associated with borrowings. Foreign currency derivatives are used to manage risk related to foreign currency exchange rates on certain issuances of debt. Derivatives related to interest rate risk for the Commercial Renewables Disposal Groups are included in the following disclosures. See Note 2 for further information.

All derivative instruments not identified as NPNS are recorded at fair value as assets or liabilities on the Consolidated Balance Sheets. Cash collateral related to derivative instruments executed under master netting arrangements is offset against the collateralized derivatives on the Consolidated Balance Sheets. The cash impacts of settled derivatives are recorded as operating activities on the Consolidated Statements of Cash Flows.

INTEREST RATE RISK

The Duke Energy Registrants are exposed to changes in interest rates as a result of their issuance or anticipated issuance of variable-rate and fixed-rate debt and commercial paper. Interest rate risk is managed by limiting variable-rate exposures to a percentage of total debt and by monitoring changes in interest rates. To manage risk associated with changes in interest rates, the Duke Energy Registrants may enter into interest rate swaps, U.S. Treasury lock agreements and other financial contracts. In anticipation of certain fixed-rate debt issuances, a series of forward-starting interest rate swaps or Treasury locks may be executed to lock in components of current market interest rates. These instruments are later terminated prior to or upon the issuance of the corresponding debt.

Cash Flow Hedges

For a derivative designated as hedging the exposure to variable cash flows of a future transaction, referred to as a cash flow hedge, the effective portion of the derivative's gain or loss is initially reported as a component of other comprehensive income and subsequently reclassified into earnings once the future transaction impacts earnings. Amounts for interest rate contracts are reclassified to earnings as interest expense over the term of the related debt. See Note 2 for information on the de-designation of interest rate swaps and related gain reclassified out of AOCI for the year ended December 31, 2022, related to the Commercial Renewables Disposal Groups. Gains and losses reclassified out of AOCI for the years ended December 31, 2021, and 2020, were not material. Duke Energy's interest rate derivatives designated as hedges include forward-starting interest rate swaps not accounted for under regulatory accounting.

Undesignated Contracts

Undesignated contracts primarily include contracts not designated as a hedge because they are accounted for under regulatory accounting or contracts that do not qualify for hedge accounting.

Duke Energy’s interest rate swaps for its regulated operations employ regulatory accounting. With regulatory accounting, the mark-to-market gains or losses on the swaps are deferred as regulatory liabilities or regulatory assets, respectively. Regulatory assets and liabilities are amortized consistent with the treatment of the related costs in the ratemaking process. The accrual of interest on the swaps is recorded as Interest Expense on the Duke Energy Registrant's Consolidated Statements of Operations and Comprehensive Income.

The following tables show notional amounts of outstanding derivatives related to interest rate risk.


	December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Indiana		Ohio
Cash flow hedges	$	500	$	—	$	—	$	—	$	—	$	—	$	—
Undesignated contracts	2,979		1,250		800		500		300		300		27
Total notional amount	$	3,479	$	1,250	$	800	$	500	$	300	$	300	$	27


	December 31, 2021
			Duke				Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Indiana		Ohio
Cash flow hedges	$	2,415	$	—	$	—	$	—	$	—	$	—
Undesignated contracts	1,177		350		500		500		300		27
Total notional amount	$	3,592	$	350	$	500	$	500	$	300	$	27

COMMODITY PRICE RISK

The Duke Energy Registrants are exposed to the impact of changes in the prices of electricity purchased and sold in bulk power markets and natural gas purchases, including Piedmont's natural gas supply contracts. Exposure to commodity price risk is influenced by a number of factors including the term of contracts, the liquidity of markets and delivery locations. To manage risk associated with commodity prices, the Duke Energy Registrants may enter into long-term power purchase or sales contracts and long-term natural gas supply agreements.

Undesignated Contracts

For the Subsidiary Registrants, bulk power electricity and natural gas purchases flow through fuel adjustment clauses, formula-based contracts or other cost sharing mechanisms. Differences between the costs included in rates and the incurred costs, including undesignated derivative contracts, are largely deferred as regulatory assets or regulatory liabilities. Piedmont policies allow for the use of financial instruments to hedge commodity price risks. The strategy and objective of these hedging programs are to use the financial instruments to reduce natural gas cost volatility for customers.

Volumes

The tables below include volumes of outstanding commodity derivatives. Amounts disclosed represent the absolute value of notional volumes of commodity contracts excluding NPNS. The Duke Energy Registrants have netted contractual amounts where offsetting purchase and sale contracts exist with identical delivery locations and times of delivery. Where all commodity positions are perfectly offset, no quantities are shown.


	December 31, 2022
		Duke		Duke	Duke	Duke
	Duke	Energy	Progress	Energy	Energy	Energy
	Energy	Carolinas	Energy	Progress	Ohio	Indiana	Piedmont
Electricity (GWh)	14,086	—	—	—	1,820	12,266	—
Natural gas (millions of Dth)	909	307	292	292	—	11	299


	December 31, 2021
		Duke		Duke	Duke	Duke
	Duke	Energy	Progress	Energy	Energy	Energy
	Energy	Carolinas	Energy	Progress	Ohio	Indiana	Piedmont
Electricity (GWh)	12,369	—	—	—	1,681	10,688	—
Natural gas (millions of Dth)	823	264	215	215	—	8	336

FOREIGN CURRENCY RISK

Duke Energy may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars.

Fair Value Hedges

Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives’ fair value gains or losses and hedged items’ fair value gains or losses are both recorded directly to earnings on the same income statement line item, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Duke Energy has elected to exclude the cross-currency basis spread from the assessment of effectiveness in the fair value hedges of its foreign currency risk and record any difference between the change in the fair value of the excluded components and the amounts recognized in earnings as a component of other comprehensive income or loss.

The following table shows Duke Energy's outstanding derivatives related to foreign currency risk. There were no fair value hedges in 2021.


	December 31, 2022
					Receive					Fair Value
	Pay Notional				Notional		Receive		Hedge	Gain (Loss)(a)
	(in millions)		Pay Rate		(in millions)		Rate		Maturity Date	(in millions)
Fair value hedges
	$	645	4.75	%	600	euros	3.10	%	June 2028	$	(3)
	537		5.31	%	500	euros	3.85	%	June 2034	(2)
Total notional amount	$	1,182			1,100	euros				$	(5)

(a) Amounts are recorded in Other Income and expenses, net on the Consolidated Statement of Operations, which offsets an equal translation adjustment of the foreign denominated debt. See the Consolidated Statements of Comprehensive Income for amounts excluded from the assessment of effectiveness for which the difference between changes in fair value and periodic amortization is recorded.

LOCATION AND FAIR VALUE OF DERIVATIVE ASSETS AND LIABILITIES RECOGNIZED IN THE CONSOLIDATED BALANCE SHEETS

The following tables show the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the Consolidated Balance Sheets, the fair values presented below are shown gross and cash collateral on the derivatives has not been netted against the fair values shown.


Derivative Assets	December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Commodity Contracts



Not Designated as Hedging Instruments
Current	$	265	$	132	$	99	$	99	$	—	$	5	$	29	$	—
Noncurrent	213		104		108		108		—		—		—		—
Total Derivative Assets – Commodity Contracts	$	478	$	236	$	207	$	207	$	—	$	5	$	29	$	—
Interest Rate Contracts
Designated as Hedging Instruments
Current	$	101	$	—	$	—	$	—	$	—	$	—	$	—	$	—

Not Designated as Hedging Instruments
Current	$	228	$	94	$	41	$	23	$	17	$	—	$	81	$	—
Noncurrent	29		—		—		—		—		—		—		—
Total Derivative Assets – Interest Rate Contracts	$	358	$	94	$	41	$	23	$	17	$	—	$	81	$	—








Total Derivative Assets	$	836	$	330	$	248	$	230	$	17	$	5	$	110	$	—


Derivative Liabilities	December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Commodity Contracts



Not Designated as Hedging Instruments
Current	$	175	$	96	$	36	$	18	$	19	$	—	$	16	$	27
Noncurrent	202		31		30		30		—		—		—		141
Total Derivative Liabilities – Commodity Contracts	$	377	$	127	$	66	$	48	$	19	$	—	$	16	$	168
Interest Rate Contracts



Not Designated as Hedging Instruments

Noncurrent	2		—		—		—		—		2		—		—
Total Derivative Liabilities – Interest Rate Contracts	$	2	$	—	$	—	$	—	$	—	$	2	$	—	$	—
Foreign Currency Contracts
Designated as Hedging Instruments
Current	$	18	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Noncurrent	40		—		—		—		—		—		—		—



Total Derivative Liabilities – Foreign Currency Contracts	$	58	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Total Derivative Liabilities	$	437	$	127	$	66	$	48	$	19	$	2	$	16	$	168


Derivative Assets	December 31, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Commodity Contracts



Not Designated as Hedging Instruments
Current	$	199	$	99	$	72	$	72	$	—	$	2	$	23	$	3
Noncurrent	113		63		50		50		—		—		—		—
Total Derivative Assets – Commodity Contracts	$	312	$	162	$	122	$	122	$	—	$	2	$	23	$	3
Interest Rate Contracts
Designated as Hedging Instruments
Current	$	3	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Noncurrent	3		—		—		—		—		—		—		—
Not Designated as Hedging Instruments
Current	$	2	$	—	$	2	$	2	$	—	$	—	$	—	$	—

Total Derivative Assets – Interest Rate Contracts	$	8	$	—	$	2	$	2	$	—	$	—	$	—	$	—




Total Derivative Assets	$	320	$	162	$	124	$	124	$	—	$	2	$	23	$	3


Derivative Liabilities	December 31, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont




Not Designated as Hedging Instruments
Current	$	72	$	18	$	19	$	5	$	14	$	—	$	13	$	21
Noncurrent	132		9		5		5		—		—		—		118
Total Derivative Liabilities – Commodity Contracts	$	204	$	27	$	24	$	10	$	14	$	—	$	13	$	139
Interest Rate Contracts
Designated as Hedging Instruments
Current	$	75	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Noncurrent	21		—		—		—		—		—		—		—
Not Designated as Hedging Instruments
Current	10		8		—		—		—		1		—		—
Noncurrent	18		—		—		—		—		4		14		—
Total Derivative Liabilities – Interest Rate Contracts	$	124	$	8	$	—	$	—	$	—	$	5	$	14	$	—




Total Derivative Liabilities	$	328	$	35	$	24	$	10	$	14	$	5	$	27	$	139

OFFSETTING ASSETS AND LIABILITIES

The following tables present the line items on the Consolidated Balance Sheets where derivatives are reported. Substantially all of Duke Energy's outstanding derivative contracts are subject to enforceable master netting arrangements. The gross amounts offset in the tables below show the effect of these netting arrangements on financial position and include collateral posted to offset the net position. The amounts shown are calculated by counterparty. Accounts receivable or accounts payable may also be available to offset exposures in the event of bankruptcy. These amounts are not included in the tables below.


Derivative Assets	December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Current
Gross amounts recognized	$	594	$	226	$	140	$	122	$	17	$	5	$	110	$	—
Gross amounts offset	(64)		(33)		(30)		(30)		—		—		—		—
Net amounts presented in Current Assets: Other	$	530	$	193	$	110	$	92	$	17	$	5	$	110	$	—
Noncurrent
Gross amounts recognized	$	242	$	104	$	108	$	108	$	—	$	—	$	—	$	—
Gross amounts offset	(97)		(40)		(57)		(57)		—		—		—		—
Net amounts presented in Other Noncurrent Assets: Other	$	145	$	64	$	51	$	51	$	—	$	—	$	—	$	—


Derivative Liabilities	December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Current
Gross amounts recognized	$	193	$	96	$	36	$	18	$	19	$	—	$	16	$	27
Gross amounts offset	(49)		(15)		(18)		(18)		—		—		(16)		—
Net amounts presented in Current Liabilities: Other	$	144	$	81	$	18	$	—	$	19	$	—	$	—	$	27
Noncurrent
Gross amounts recognized	$	244	$	31	$	30	$	30	$	—	$	2	$	—	$	141
Gross amounts offset	(59)		(29)		(30)		(30)		—		—		—		—
Net amounts presented in Other Noncurrent Liabilities: Other	$	185	$	2	$	—	$	—	$	—	$	2	$	—	$	141


Derivative Assets	December 31, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Current
Gross amounts recognized	$	204	$	99	$	74	$	74	$	—	$	2	$	23	$	3
Gross amounts offset	(25)		(16)		(9)		(9)		—		—		—		—
Net amounts presented in Current Assets: Other	$	179	$	83	$	65	$	65	$	—	$	2	$	23	$	3
Noncurrent
Gross amounts recognized	$	116	$	63	$	50	$	50	$	—	$	—	$	—	$	—
Gross amounts offset	(23)		(15)		(8)		(8)		—		—		—		—
Net amounts presented in Other Noncurrent Assets: Other	$	93	$	48	$	42	$	42	$	—	$	—	$	—	$	—


Derivative Liabilities	December 31, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Current
Gross amounts recognized	$	157	$	26	$	19	$	5	$	14	$	1	$	13	$	21
Gross amounts offset	(11)		(6)		(5)		(5)		—		—		—		—
Net amounts presented in Current Liabilities: Other	$	146	$	20	$	14	$	—	$	14	$	1	$	13	$	21
Noncurrent
Gross amounts recognized	$	171	$	9	$	5	$	5	$	—	$	4	$	14	$	118
Gross amounts offset	(12)		(8)		(5)		(5)		—		—		—		—
Net amounts presented in Other Noncurrent Liabilities: Other	$	159	$	1	$	—	$	—	$	—	$	4	$	14	$	118

OBJECTIVE CREDIT CONTINGENT FEATURES

Certain derivative contracts contain objective credit contingent features. These features include the requirement to post cash collateral or letters of credit if specific events occur, such as a credit rating downgrade below investment grade. The following tables show information with respect to derivative contracts that are in a net liability position and contain objective credit risk-related payment provisions.


	December 31, 2022
			Duke				Duke		Duke
	Duke		Energy		Progress		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida
Aggregate fair value of derivatives in a net liability position	$	141	$	86	$	55	$	48	$	7
Fair value of collateral already posted	—		—		—		—		—
Additional cash collateral or letters of credit in the event credit risk-related contingent features were triggered	141		86		55		48		7


	December 31, 2021
			Duke				Duke		Duke
	Duke		Energy		Progress		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida
Aggregate fair value of derivatives in a net liability position	$	32	$	18	$	14	$	10	$	4
Fair value of collateral already posted	—		—		—		—		—
Additional cash collateral or letters of credit in the event credit risk-related contingent features were triggered	32		18		14		10		4

The Duke Energy Registrants have elected to offset cash collateral and fair values of derivatives. For amounts to be netted, the derivative and cash collateral must be executed with the same counterparty under the same master netting arrangement.

16. INVESTMENTS IN DEBT AND EQUITY SECURITIES

Duke Energy’s investments in debt and equity securities are primarily comprised of investments held in (i) the NDTF at Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida, (ii) the grantor trusts at Duke Energy Progress, Duke Energy Florida and Duke Energy Indiana related to OPEB plans and (iii) Bison. The Duke Energy Registrants classify investments in debt securities as AFS and investments in equity securities as FV-NI.

For investments in debt securities classified as AFS, the unrealized gains and losses are included in other comprehensive income until realized, at which time they are reported through net income. For investments in equity securities classified as FV-NI, both realized and unrealized gains and losses are reported through net income. Substantially all of Duke Energy’s investments in debt and equity securities qualify for regulatory accounting, and accordingly, all associated realized and unrealized gains and losses on these investments are deferred as a regulatory asset or liability.

Duke Energy classifies the majority of investments in debt and equity securities as long term, unless otherwise noted.

Investment Trusts

The investments within the Investment Trusts are managed by independent investment managers with discretion to buy, sell and invest pursuant to the objectives set forth by the investment manager agreements and trust agreements. The Duke Energy Registrants have limited oversight of the day-to-day management of these investments. As a result, the ability to hold investments in unrealized loss positions is outside the control of the Duke Energy Registrants. Accordingly, all unrealized losses associated with debt securities within the Investment Trusts are recognized immediately and deferred to regulatory accounts where appropriate.

Other AFS Securities

Unrealized gains and losses on all other AFS securities are included in other comprehensive income until realized, unless it is determined the carrying value of an investment has a credit loss. The Duke Energy Registrants analyze all investment holdings each reporting period to determine whether a decline in fair value is related to a credit loss. If a credit loss exists, the unrealized credit loss is included in earnings. There were no material credit losses as of December 31, 2022, and 2021.

Other Investments amounts are recorded in Other within Other Noncurrent Assets on the Consolidated Balance Sheets.

DUKE ENERGY

The following table presents the estimated fair value of investments in debt and equity securities; equity investments are classified as FV-NI and debt investments are classified as AFS.


	December 31, 2022						December 31, 2021
	Gross		Gross				Gross		Gross
	Unrealized		Unrealized				Unrealized		Unrealized
	Holding		Holding		Estimated		Holding		Holding		Estimated
(in millions)	Gains		Losses		Fair Value		Gains		Losses		Fair Value
NDTF
Cash and cash equivalents	$	—	$	—	$	215	$	—	$	—	$	160
Equity securities	3,658		105		5,871		4,905		43		7,350
Corporate debt securities	1		85		641		39		6		829
Municipal bonds	—		39		330		14		1		314
U.S. government bonds	2		112		1,423		31		12		1,568
Other debt securities	—		18		156		3		1		180
Total NDTF Investments	$	3,661	$	359	$	8,636	$	4,992	$	63	$	10,401
Other Investments
Cash and cash equivalents	$	—	$	—	$	22	$	—	$	—	$	36
Equity securities	21		16		128		36		—		156
Corporate debt securities	—		12		84		2		1		119
Municipal bonds	—		3		78		3		1		80
U.S. government bonds	—		2		62		—		—		56
Other debt securities	—		3		41		—		1		45
Total Other Investments	$	21	$	36	$	415	$	41	$	3	$	492
Total Investments	$	3,682	$	395	$	9,051	$	5,033	$	66	$	10,893

Realized gains and losses, which were determined on a specific identification basis, from sales of FV-NI and AFS securities for the years ended December 31, 2022, 2021 and 2020, were as follows.


	Years Ended December 31,
(in millions)	2022		2021		2020
FV-NI:
Realized gains	$	201	$	724	$	366
Realized losses	316		141		174
AFS:
Realized gains	28		56		96
Realized losses	151		54		51

DUKE ENERGY CAROLINAS

The following table presents the estimated fair value of investments in debt and equity securities; equity investments are classified as FV-NI and debt investments are classified as AFS.


	December 31, 2022						December 31, 2021
	Gross		Gross				Gross		Gross
	Unrealized		Unrealized				Unrealized		Unrealized
	Holding		Holding		Estimated		Holding		Holding		Estimated
(in millions)	Gains		Losses		Fair Value		Gains		Losses		Fair Value
NDTF
Cash and cash equivalents	$	—	$	—	$	117	$	—	$	—	$	53
Equity securities	2,147		51		3,367		2,887		19		4,265
Corporate debt securities	1		62		401		24		4		506
Municipal bonds	—		10		64		2		—		48
U.S. government bonds	1		51		685		16		3		712
Other debt securities	—		18		148		3		1		175
Total NDTF Investments	$	2,149	$	192	$	4,782	$	2,932	$	27	$	5,759

Realized gains and losses, which were determined on a specific identification basis, from sales of FV-NI and AFS securities for the years ended December 31, 2022, 2021 and 2020, were as follows.


	Years Ended December 31,
(in millions)	2022		2021		2020
FV-NI:
Realized gains	$	124	$	440	$	64
Realized losses	177		96		99
AFS:
Realized gains	22		38		60
Realized losses	86		37		37

PROGRESS ENERGY

The following table presents the estimated fair value of investments in debt and equity securities; equity investments are classified as FV-NI and debt investments are classified as AFS.


	December 31, 2022						December 31, 2021
	Gross		Gross				Gross		Gross
	Unrealized		Unrealized				Unrealized		Unrealized
	Holding		Holding		Estimated		Holding		Holding		Estimated
(in millions)	Gains		Losses		Fair Value		Gains		Losses		Fair Value
NDTF
Cash and cash equivalents	$	—	$	—	$	98	$	—	$	—	$	107
Equity securities	1,511		54		2,504		2,018		24		3,085
Corporate debt securities	—		23		240		15		2		323
Municipal bonds	—		29		266		12		1		266
U.S. government bonds	1		61		738		15		9		856
Other debt securities	—		—		8		—		—		5
Total NDTF Investments	$	1,512	$	167	$	3,854	$	2,060	$	36	$	4,642
Other Investments
Cash and cash equivalents	$	—	$	—	$	11	$	—	$	—	$	20
Municipal bonds	—		—		25		2		—		26
Total Other Investments	$	—	$	—	$	36	$	2	$	—	$	46
Total Investments	$	1,512	$	167	$	3,890	$	2,062	$	36	$	4,688

Realized gains and losses, which were determined on a specific identification basis, from sales of FV-NI and AFS securities for the years ended December 31, 2022, 2021 and 2020, were as follows.


	Years Ended December 31,
(in millions)	2022		2021		2020
FV-NI:
Realized gains	$	77	$	284	$	302
Realized losses	139		45		75
AFS:
Realized gains	6		16		24
Realized losses	48		14		13

DUKE ENERGY PROGRESS

The following table presents the estimated fair value of investments in debt and equity securities; equity investments are classified as FV-NI and debt investments are classified as AFS.


	December 31, 2022						December 31, 2021
	Gross		Gross				Gross		Gross
	Unrealized		Unrealized				Unrealized		Unrealized
	Holding		Holding		Estimated		Holding		Holding		Estimated
(in millions)	Gains		Losses		Fair Value		Gains		Losses		Fair Value
NDTF
Cash and cash equivalents	$	—	$	—	$	56	$	—	$	—	$	94
Equity securities	1,431		54		2,411		1,915		23		2,970
Corporate debt securities	—		22		230		15		2		282
Municipal bonds	—		29		266		12		1		266
U.S. government bonds	1		37		460		15		3		472
Other debt securities	—		—		7		—		—		5
Total NDTF Investments	$	1,432	$	142	$	3,430	$	1,957	$	29	$	4,089
Other Investments
Cash and cash equivalents	$	—	$	—	$	9	$	—	$	—	$	16
Total Other Investments	$	—	$	—	$	9	$	—	$	—	$	16
Total Investments	$	1,432	$	142	$	3,439	$	1,957	$	29	$	4,105

Realized gains and losses, which were determined on a specific identification basis, from sales of FV-NI and AFS securities for the years ended December 31, 2022, 2021 and 2020, were as follows.


	Years Ended December 31,
(in millions)	2022		2021		2020
FV-NI:
Realized gains	$	76	$	283	$	52
Realized losses	136		44		59
AFS:
Realized gains	6		15		24
Realized losses	44		13		13

DUKE ENERGY FLORIDA

The following table presents the estimated fair value of investments in debt and equity securities; equity investments are classified as FV-NI and debt investments are classified as AFS.


	December 31, 2022						December 31, 2021
	Gross		Gross				Gross		Gross
	Unrealized		Unrealized				Unrealized		Unrealized
	Holding		Holding		Estimated		Holding		Holding		Estimated
(in millions)	Gains		Losses		Fair Value		Gains		Losses		Fair Value
NDTF
Cash and cash equivalents	$	—	$	—	$	42	$	—	$	—	$	13
Equity securities	80		—		93		103		1		115
Corporate debt securities	—		1		10		—		—		41

U.S. government bonds	—		24		278		—		6		384
Other debt securities	—		—		1		—		—		—
Total NDTF Investments(a)	$	80	$	25	$	424	$	103	$	7	$	553
Other Investments
Cash and cash equivalents	$	—	$	—	$	1	$	—	$	—	$	3
Municipal bonds	—		—		25		2		—		26
Total Other Investments	$	—	$	—	$	26	$	2	$	—	$	29
Total Investments	$	80	$	25	$	450	$	105	$	7	$	582

(a) During the years ended December 31, 2022, and 2021, Duke Energy Florida continued to receive reimbursements from the NDTF for costs related to ongoing decommissioning activity of the Crystal River Unit 3.

Realized gains and losses, which were determined on a specific identification basis, from sales of FV-NI and AFS securities for the years ended December 31, 2022, 2021 and 2020, were as follows.


	Years Ended December 31,
(in millions)	2022		2021		2020
FV-NI:
Realized gains	$	1	$	1	$	250
Realized losses	3		1		16
AFS:
Realized gains	—		1		—
Realized losses	4		1		—

DUKE ENERGY INDIANA

The following table presents the estimated fair value of investments in debt and equity securities; equity investments are measured at FV-NI and debt investments are classified as AFS.


	December 31, 2022						December 31, 2021
	Gross		Gross				Gross		Gross
	Unrealized		Unrealized				Unrealized		Unrealized
	Holding		Holding		Estimated		Holding		Holding		Estimated
(in millions)	Gains		Losses		Fair Value		Gains		Losses		Fair Value
Investments
Cash and cash equivalents	$	—	$	—	$	1	$	—	$	—	$	—
Equity securities	2		16		79		6		—		97
Corporate debt securities	—		1		8		—		—		6
Municipal bonds	—		3		45		1		1		46
U.S. government bonds	—		—		7		—		—		12


Total Investments	$	2	$	20	$	140	$	7	$	1	$	161

Realized gains and losses, which were determined on a specific identification basis, from sales of FV-NI and AFS securities for the years ended December 31, 2022, 2021 and 2020, were immaterial.

DEBT SECURITY MATURITIES

The table below summarizes the maturity date for debt securities.


	December 31, 2022
			Duke				Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Indiana
Due in one year or less	$	137	$	7	$	89	$	24	$	65	$	8
Due after one through five years	807		287		443		244		199		22
Due after five through 10 years	469		230		193		178		15		6
Due after 10 years	1,402		774		552		517		35		24
Total	$	2,815	$	1,298	$	1,277	$	963	$	314	$	60

17. FAIR VALUE MEASUREMENTS

Fair value is the exchange price to sell an asset or transfer a liability in an orderly transaction between market participants at the measurement date. The fair value definition focuses on an exit price versus the acquisition cost. Fair value measurements use market data or assumptions market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs may be readily observable, corroborated by market data, or generally unobservable. Valuation techniques maximize the use of observable inputs and minimize the use of unobservable inputs. A midmarket pricing convention (the midpoint price between bid and ask prices) is permitted for use as a practical expedient.

Fair value measurements are classified in three levels based on the fair value hierarchy as defined by GAAP. Certain investments are not categorized within the fair value hierarchy. These investments are measured at fair value using the net asset value per share practical expedient. The net asset value is derived based on the investment cost, less any impairment, plus or minus changes resulting from observable price changes for an identical or similar investment of the same issuer.

Fair value accounting guidance permits entities to elect to measure certain financial instruments that are not required to be accounted for at fair value, such as equity method investments or the company’s own debt, at fair value. The Duke Energy Registrants have not elected to record any of these items at fair value.

Valuation methods of the primary fair value measurements disclosed below are as follows.

Investments in equity securities

The majority of investments in equity securities are valued using Level 1 measurements. Investments in equity securities are typically valued at the closing price in the principal active market as of the last business day of the quarter. Principal active markets for equity prices include published exchanges such as the NYSE and Nasdaq Stock Market. Foreign equity prices are translated from their trading currency using the currency exchange rate in effect at the close of the principal active market. There was no after-hours market activity that was required to be reflected in the reported fair value measurements.

Investments in debt securities

Most investments in debt securities are valued using Level 2 measurements because the valuations use interest rate curves and credit spreads applied to the terms of the debt instrument (maturity and coupon interest rate) and consider the counterparty credit rating. If the market for a particular fixed-income security is relatively inactive or illiquid, the measurement is Level 3.

Commodity derivatives

Commodity derivatives with clearinghouses are classified as Level 1. Commodity derivatives with observable forward curves are classified as Level 2. If forward price curves are not observable for the full term of the contract and the unobservable period had more than an insignificant impact on the valuation, the commodity derivative is classified as Level 3. In isolation, increases (decreases) in natural gas forward prices result in favorable (unfavorable) fair value adjustments for natural gas purchase contracts; and increases (decreases) in electricity forward prices result in unfavorable (favorable) fair value adjustments for electricity sales contracts. Duke Energy regularly evaluates and validates pricing inputs used to estimate the fair value of natural gas commodity contracts by a market participant price verification procedure. This procedure provides a comparison of internal forward commodity curves to market participant generated curves.

Interest rate derivatives

Most over-the-counter interest rate contract derivatives are valued using financial models that utilize observable inputs for similar instruments and are classified as Level 2. Inputs include forward interest rate curves, notional amounts, interest rates and credit quality of the counterparties. Derivatives related to interest rate risk for the Commercial Renewables Disposal Groups are included in the following disclosures. See Note 2 for further information.

Other fair value considerations

See Note 2 for further information on the valuation of the Commercial Renewables Disposal Groups. See Note 12 for a discussion of the valuation of goodwill and intangible assets.

DUKE ENERGY

The following tables provide recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets. Derivative amounts in the tables below for all Duke Energy Registrants exclude cash collateral, which is disclosed in Note 15. See Note 16 for additional information related to investments by major security type for the Duke Energy Registrants.


	December 31, 2022
(in millions)	Total Fair Value		Level 1		Level 2		Level 3		Not Categorized
NDTF cash and cash equivalents	$	215	$	215	$	—	$	—	$	—
NDTF equity securities	5,871		5,829		—		—		42
NDTF debt securities	2,550		780		1,770		—		—
Other equity securities	128		128		—		—		—
Other debt securities	265		55		210		—		—
Other cash and cash equivalents	22		22		—		—		—
Derivative assets	836		1		801		34		—
Total assets	9,887		7,030		2,781		34		42

Derivative liabilities	(437)		(16)		(421)		—		—
Net assets (liabilities)	$	9,450	$	7,014	$	2,360	$	34	$	42


	December 31, 2021
(in millions)	Total Fair Value		Level 1		Level 2		Level 3		Not Categorized
NDTF cash and cash equivalents	$	160	$	160	$	—	$	—	$	—
NDTF equity securities	7,350		7,300		—		—		50
NDTF debt securities	2,891		967		1,924		—		—
Other equity securities	156		156		—		—		—
Other debt securities	300		45		255		—		—
Other cash and cash equivalents	36		36		—		—		—
Derivative assets	320		3		293		24		—
Total assets	11,213		8,667		2,472		24		50

Derivative liabilities	(327)		(13)		(314)		—		—
Net assets (liabilities)	$	10,886	$	8,654	$	2,158	$	24	$	50

The following table provides reconciliations of beginning and ending balances of assets and liabilities measured at fair value using Level 3 measurements.


	Derivatives (net)
	Years Ended December 31,

(in millions)	2022		2021
Balance at beginning of period	$	24	$	8



Purchases, sales, issuances and settlements:
Purchases	78		21


Settlements	(36)		(20)

Total gains (losses) included on the Consolidated Balance Sheet	(32)		15
Balance at end of period	$	34	$	24

DUKE ENERGY CAROLINAS

The following tables provide recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets.


	December 31, 2022
(in millions)	Total Fair Value		Level 1		Level 2		Not Categorized
NDTF cash and cash equivalents	$	117	$	117	$	—	$	—
NDTF equity securities	3,367		3,325		—		42
NDTF debt securities	1,298		323		975		—

Derivative assets	330		—		330		—
Total assets	5,112		3,765		1,305		42
Derivative liabilities	(127)		—		(127)		—
Net assets	$	4,985	$	3,765	$	1,178	$	42


	December 31, 2021
(in millions)	Total Fair Value		Level 1		Level 2		Not Categorized
NDTF cash and cash equivalents	$	53	$	53	$	—	$	—
NDTF equity securities	4,265		4,215		—		50
NDTF debt securities	1,441		339		1,102		—

Derivative assets	162		—		162		—
Total assets	5,921		4,607		1,264		50
Derivative liabilities	(35)		—		(35)		—
Net assets	$	5,886	$	4,607	$	1,229	$	50

PROGRESS ENERGY

The following table provides recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets.


	December 31, 2022						December 31, 2021
(in millions)	Total Fair Value		Level 1		Level 2			Total Fair Value		Level 1		Level 2
NDTF cash and cash equivalents	$	98	$	98	$	—		$	107	$	107	$	—
NDTF equity securities	2,504		2,504		—			3,085		3,085		—
NDTF debt securities	1,252		457		795			1,450		628		822
Other debt securities	25		—		25			26		—		26
Other cash and cash equivalents	11		11		—			20		20		—
Derivative assets	248		—		248			124		—		124
Total assets	4,138		3,070		1,068			4,812		3,840		972

Derivative liabilities	(66)		—		(66)			(24)		—		(24)
Net assets	$	4,072	$	3,070	$	1,002		$	4,788	$	3,840	$	948

DUKE ENERGY PROGRESS

The following table provides recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets.


	December 31, 2022						December 31, 2021
(in millions)	Total Fair Value		Level 1		Level 2			Total Fair Value		Level 1		Level 2
NDTF cash and cash equivalents	$	56	$	56	$	—		$	94	$	94	$	—
NDTF equity securities	2,411		2,411		—			2,970		2,970		—
NDTF debt securities	963		225		738			1,025		289		736

Other cash and cash equivalents	9		9		—			16		16		—
Derivative assets	230		—		230			124		—		124
Total assets	3,669		2,701		968			4,229		3,369		860
Derivative liabilities	(48)		—		(48)			(10)		—		(10)
Net assets	$	3,621	$	2,701	$	920		$	4,219	$	3,369	$	850

DUKE ENERGY FLORIDA

The following table provides recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets.


	December 31, 2022						December 31, 2021
(in millions)	Total Fair Value		Level 1		Level 2		Total Fair Value		Level 1		Level 2
NDTF cash and cash equivalents	$	42	$	42	$	—	$	13	$	13	$	—
NDTF equity securities	93		93		—		115		115		—
NDTF debt securities	289		232		57		425		339		86
Other debt securities	25		—		25		26		—		26
Other cash and cash equivalents	1		1		—		3		3		—
Derivative assets	17		—		17		—		—		—
Total assets	467		368		99		582		470		112

Derivative liabilities	(19)		—		(19)		(14)		—		(14)
Net assets	$	448	$	368	$	80	$	568	$	470	$	98

DUKE ENERGY OHIO

The recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets were not material at December 31, 2022, and 2021.

DUKE ENERGY INDIANA

The following table provides recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets.


	December 31, 2022								December 31, 2021
(in millions)	Total Fair Value		Level 1		Level 2		Level 3		Total Fair Value		Level 1		Level 2		Level 3
Other equity securities	$	79	$	79	$	—	$	—	$	97	$	97	$	—	$	—
Other debt securities	60		—		60		—		64		—		64		—
Other cash equivalents	1		1		—		—		—		—		—		—
Derivative assets	110		—		81		29		23		1		—		22
Total assets	250		80		141		29		184		98		64		22
Derivative liabilities	(16)		(16)		—		—		(27)		(13)		(14)		—
Net assets	$	234	$	64	$	141	$	29	$	157	$	85	$	50	$	22

The following table provides a reconciliation of beginning and ending balances of assets and liabilities measured at fair value using Level 3 measurements.


	Derivatives (net)
	Years Ended December 31,
(in millions)	2022		2021
Balance at beginning of period	$	22	$	6


Purchases, sales, issuances and settlements:
Purchases	74		18


Settlements	(32)		(16)

Total (losses) gains included on the Consolidated Balance Sheet	(35)		14
Balance at end of period	$	29	$	22

PIEDMONT

The following table provides recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets.


	December 31, 2022						December 31, 2021
(in millions)	Total Fair Value		Level 1		Level 2			Total Fair Value		Level 1		Level 2


Derivative assets	$	—	$	—	$	—		$	3	$	3	$	—

Derivative liabilities	(168)		—		(168)			(139)		—		(139)
Net (liabilities) assets	$	(168)	$	—	$	(168)		$	(136)	$	3	$	(139)

QUANTITATIVE INFORMATION ABOUT UNOBSERVABLE INPUTS

The following tables include quantitative information about the Duke Energy Registrants' derivatives classified as Level 3.

December 31, 2022

Weighted

Fair Value

Average

Investment Type

(in millions)

Valuation Technique

Unobservable Input

Range

Duke Energy Ohio

FTRs

RTO auction pricing

FTR price – per MWh

0.89

–

6.25

3.35

Duke Energy Indiana

FTRs

RTO auction pricing

FTR price – per MWh

0.09

–

21.79

2.74

Duke Energy

Total Level 3 derivatives

December 31, 2021

Weighted

Fair Value

Average

Investment Type

(in millions)

Valuation Technique

Unobservable Input

Range

Duke Energy Ohio

FTRs

RTO auction pricing

FTR price – per MWh

0.06

–

1.79

0.96

Duke Energy Indiana

FTRs

RTO auction pricing

FTR price – per MWh

(1.18)

–

13.11

2.68

Duke Energy

Total Level 3 derivatives

OTHER FAIR VALUE DISCLOSURES

The fair value and book value of long-term debt, including current maturities, is summarized in the following table. The following disclosures include debt attributable to the Commercial Renewables Disposal Groups. See Note 2 for further details. Estimates determined are not necessarily indicative of amounts that could have been settled in current markets. Fair value of long-term debt uses Level 2 measurements.


	December 31, 2022				December 31, 2021
(in millions)	Book Value		Fair Value		Book Value		Fair Value
Duke Energy(a)	$	71,215	$	63,454	$	63,835	$	69,683
Duke Energy Carolinas	14,266		12,943		13,275		15,101
Progress Energy	22,439		20,467		20,823		23,751
Duke Energy Progress	11,087		9,689		10,249		11,252
Duke Energy Florida	9,709		8,991		8,482		9,772
Duke Energy Ohio	3,245		2,927		3,193		3,570
Duke Energy Indiana	4,307		3,913		4,323		5,067
Piedmont	3,363		2,940		2,968		3,278

(a) Book value of long-term debt includes $1.17 billion as of December 31, 2022, and $1.25 billion as of December 31, 2021, of unamortized debt discount and premium, net in purchase accounting adjustments related to the mergers with Progress Energy and Piedmont that are excluded from fair value of long-term debt.

At both December 31, 2022, and December 31, 2021, fair value of cash and cash equivalents, accounts and notes receivable, accounts payable, notes payable and commercial paper, and nonrecourse notes payable of VIEs are not materially different from their carrying amounts because of the short-term nature of these instruments and/or because the stated rates approximate market rates.

18. VARIABLE INTEREST ENTITIES

A VIE is an entity that is evaluated for consolidation using more than a simple analysis of voting control. The analysis to determine whether an entity is a VIE considers contracts with an entity, credit support for an entity, the adequacy of the equity investment of an entity and the relationship of voting power to the amount of equity invested in an entity. This analysis is performed either upon the creation of a legal entity or upon the occurrence of an event requiring reevaluation, such as a significant change in an entity’s assets or activities. A qualitative analysis of control determines the party that consolidates a VIE. This assessment is based on (i) what party has the power to direct the activities of the VIE that most significantly impact its economic performance and (ii) what party has rights to receive benefits or is obligated to absorb losses that could potentially be significant to the VIE. The analysis of the party that consolidates a VIE is a continual reassessment.

CONSOLIDATED VIEs

The obligations of the consolidated VIEs discussed in the following paragraphs are nonrecourse to the Duke Energy Registrants. The registrants have no requirement to provide liquidity to, purchase assets of or guarantee performance of these VIEs unless noted in the following paragraphs.

No financial support was provided to any of the consolidated VIEs during the years ended December 31, 2022, 2021 and 2020, or is expected to be provided in the future, that was not previously contractually required.

Receivables Financing – DERF/DEPR/DEFR

DERF, DEPR and DEFR are bankruptcy remote, special purpose subsidiaries of Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida, respectively. DERF, DEPR and DEFR are wholly owned LLCs with separate legal existence from their parent companies, and their assets are not generally available to creditors of their parent companies. On a revolving basis, DERF, DEPR and DEFR buy certain accounts receivable arising from the sale of electricity and related services from their parent companies.

DERF, DEPR and DEFR borrow amounts under credit facilities to buy these receivables. Borrowing availability from the credit facilities is limited to the amount of qualified receivables purchased, which generally exclude receivables past due more than a predetermined number of days and reserves for expected past-due balances. The sole source of funds to satisfy the related debt obligations is cash collections from the receivables. Amounts borrowed under the credit facilities are reflected on the Consolidated Balance Sheets as Long-Term Debt.

The most significant activity that impacts the economic performance of DERF, DEPR and DEFR are the decisions made to manage delinquent receivables. Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida are considered the primary beneficiaries and consolidate DERF, DEPR and DEFR, respectively, as they make those decisions.

Receivables Financing – CRC

CRC is a bankruptcy remote, special purpose entity indirectly owned by Duke Energy. On a revolving basis, CRC buys certain accounts receivable arising from the sale of electricity, natural gas and related services from Duke Energy Ohio and Duke Energy Indiana. CRC borrows amounts under a credit facility to buy the receivables from Duke Energy Ohio and Duke Energy Indiana. Borrowing availability from the credit facility is limited to the amount of qualified receivables sold to CRC, which generally exclude receivables past due more than a predetermined number of days and reserves for expected past-due balances. The sole source of funds to satisfy the related debt obligation is cash collections from the receivables. Amounts borrowed under the credit facility are reflected on Duke Energy's Consolidated Balance Sheets as Long-Term Debt.

The proceeds Duke Energy Ohio and Duke Energy Indiana receive from the sale of receivables to CRC are approximately 75% cash and 25% in the form of a subordinated note from CRC. The subordinated note is a retained interest in the receivables sold. Depending on collection experience, additional equity infusions to CRC may be required by Duke Energy to maintain a minimum equity balance of $3 million.

CRC is considered a VIE because (i) equity capitalization is insufficient to support its operations, (ii) power to direct the activities that most significantly impact the economic performance of the entity is not held by the equity holder and (iii) deficiencies in net worth of CRC are funded by Duke Energy. The most significant activities that impact the economic performance of CRC are decisions made to manage delinquent receivables. Duke Energy is considered the primary beneficiary and consolidates CRC as it makes these decisions. Neither Duke Energy Ohio nor Duke Energy Indiana consolidate CRC.

Receivables Financing – Credit Facilities

The following table summarizes the amounts and expiration dates of the credit facilities and associated restricted receivables described above.


	Duke Energy
			Duke Energy		Duke Energy		Duke Energy
			Carolinas		Progress		Florida
(in millions)	CRC		DERF		DEPR		DEFR
Expiration date	February 2025		January 2025		April 2025		April 2023
Credit facility amount	$	350	$	500	$	400	$	250
Amounts borrowed at December 31, 2022	350		471		400		250
Amounts borrowed at December 31, 2021	350		475		350		250
Restricted Receivables at December 31, 2022	917		928		793		490
Restricted Receivables at December 31, 2021	587		844		574		427

Nuclear Asset-Recovery Bonds – Duke Energy Florida Project Finance, LLC (DEFPF)

DEFPF is a bankruptcy remote, wholly owned special purpose subsidiary of Duke Energy Florida. DEFPF was formed in 2016 for the sole purpose of issuing nuclear asset-recovery bonds to finance Duke Energy Florida's unrecovered regulatory asset related to Crystal River Unit 3.

In 2016, DEFPF issued senior secured bonds and used the proceeds to acquire nuclear asset-recovery property from Duke Energy Florida. The nuclear asset-recovery property acquired includes the right to impose, bill, collect and adjust a non-bypassable nuclear asset-recovery charge from all Duke Energy Florida retail customers until the bonds are paid in full and all financing costs have been recovered. The nuclear asset-recovery bonds are secured by the nuclear asset-recovery property and cash collections from the nuclear asset-recovery charges are the sole source of funds to satisfy the debt obligation. The bondholders have no recourse to Duke Energy Florida.

DEFPF is considered a VIE primarily because the equity capitalization is insufficient to support its operations. Duke Energy Florida has the power to direct the significant activities of the VIE as described above and therefore Duke Energy Florida is considered the primary beneficiary and consolidates DEFPF.

The following table summarizes the impact of DEFPF on Duke Energy Florida's Consolidated Balance Sheets.


	December 31,
(in millions)	2022		2021
Receivables of VIEs	$	6	$	5
Regulatory Assets: Current	55		54
Current Assets: Other	41		39
Other Noncurrent Assets: Regulatory assets	826		883
Current Liabilities: Other	9		9
Current maturities of long-term debt	56		56
Long-Term Debt	890		946

Storm Recovery Bonds – Duke Energy Carolinas NC Storm Funding and Duke Energy Progress NC Storm Funding

Duke Energy Carolinas NC Storm Funding, LLC. (DECNCSF) and Duke Energy Progress NC Storm Funding, LLC. (DEPNCSF) are bankruptcy remote, wholly owned special purpose subsidiaries of Duke Energy Carolinas and Duke Energy Progress, respectively. These entities were formed in 2021 for the sole purpose of issuing storm recovery bonds to finance certain of Duke Energy Carolinas’ and Duke Energy Progress’ unrecovered regulatory assets related to storm costs.

In November 2021, DECNCSF and DEPNCSF issued $237 million and $770 million of senior secured bonds, respectively and used the proceeds to acquire storm recovery property from Duke Energy Carolinas and Duke Energy Progress. The storm recovery property was created by state legislation and NCUC financing orders for the purpose of financing storm costs incurred in 2018 and 2019. The storm recovery property acquired includes the right to impose, bill, collect and adjust a non-bypassable charge from all Duke Energy Carolinas’ and Duke Energy Progress’ retail customers until the bonds are paid in full and all financing costs have been recovered. The storm recovery bonds are secured by the storm recovery property and cash collections from the storm recovery charges are the sole source of funds to satisfy the debt obligation. The bondholders have no recourse to Duke Energy Carolinas or Duke Energy Progress. For additional information, see Notes 4 and 7.

DECNCSF and DEPNCSF are considered VIEs primarily because the equity capitalization is insufficient to support their operations. Duke Energy Carolinas and Duke Energy Progress have the power to direct the significant activities of the VIEs as described above and therefore Duke Energy Carolinas and Duke Energy Progress are considered the primary beneficiaries and consolidate DECNCSF and DEPNCSF, respectively.

The following table summarizes the impact of these VIEs on Duke Energy Carolinas’ and Duke Energy Progress’ Consolidated Balance Sheets.


	Duke Energy Carolinas				Duke Energy Progress
	December 31,				December 31,
(in millions)	2022		2021		2022		2021
Regulatory Assets: Current	$	12	$	12	$	39	$	39
Current Assets: Other	8		—		29		—
Other Noncurrent Assets: Regulatory assets	208		220		681		720
Other Noncurrent Assets: Other	1		1		2		4

Current maturities of long-term debt	10		5		34		15
Current Liabilities: Other	3		1		8		2
Long-Term Debt	219		228		714		747

NON-CONSOLIDATED VIEs

The following tables summarize the impact of non-consolidated VIEs on the Consolidated Balance Sheets.


	December 31, 2022
	Duke Energy		Duke	Duke
	Natural Gas				Energy		Energy
(in millions)	Investments				Ohio		Indiana
Receivables from affiliated companies	$	—			$	198	$	317

Investments in equity method unconsolidated affiliates	43				—		—
Other noncurrent assets	45				—		—
Total assets	$	88			$	198	$	317

Other current liabilities	59				—		—

Other noncurrent liabilities	47				—		—
Total liabilities	$	106			$	—	$	—
Net (liabilities) assets	$	(18)			$	198	$	317


	December 31, 2021
	Duke Energy		Duke	Duke
	Natural Gas				Energy		Energy
(in millions)	Investments				Ohio		Indiana
Receivables from affiliated companies	$	—			$	79	$	97

Investments in equity method unconsolidated affiliates	15				—		—
Other noncurrent assets	61				—		—
Total assets	$	76			$	79	$	97

Other current liabilities	47				—		—

Other noncurrent liabilities	54				—		—
Total liabilities	$	101			$	—	$	—
Net (liabilities) assets	$	(25)			$	79	$	97

The Duke Energy Registrants are not aware of any situations where the maximum exposure to loss significantly exceeds the carrying values shown above.

Natural Gas Investments

Duke Energy has investments in various joint ventures including pipeline and renewable natural gas projects. These entities are considered VIEs due to having insufficient equity to finance their own activities without subordinated financial support. Duke Energy does not have the power to direct the activities that most significantly impact the economic performance, the obligation to absorb losses or the right to receive benefits of these VIEs and therefore does not consolidate these entities.

Duke Energy has a 47% ownership interest in ACP. In 2020, Duke Energy determined that it would no longer invest in the construction of the ACP pipeline. In February 2021, Duke Energy paid approximately $855 million to fund ACP's outstanding debt, relieving Duke Energy of its guarantee. See Notes 4, 8 and 13 for further information regarding this transaction.

CRC

See discussion under Consolidated VIEs for additional information related to CRC.

Amounts included in Receivables from affiliated companies in the above table for Duke Energy Ohio and Duke Energy Indiana reflect their retained interest in receivables sold to CRC. These subordinated notes held by Duke Energy Ohio and Duke Energy Indiana are stated at fair value. Carrying values of retained interests are determined by allocating carrying value of the receivables between assets sold and interests retained based on relative fair value. The allocated bases of the subordinated notes are not materially different than their face value because (i) the receivables generally turnover in less than two months, (ii) credit losses are reasonably predictable due to the broad customer base and lack of significant concentration and (iii) the equity in CRC is subordinate to all retained interests and thus would absorb losses first. The hypothetical effect on fair value of the retained interests assuming both a 10% and a 20% unfavorable variation in credit losses or discount rates is not material due to the short turnover of receivables and historically low credit loss history. Interest accrues to Duke Energy Ohio and Duke Energy Indiana on the retained interests using the acceptable yield method. This method generally approximates the stated rate on the notes since the allocated basis and the face value are nearly equivalent. An impairment charge is recorded against the carrying value of both retained interests and purchased beneficial interest whenever it is determined that an other-than-temporary impairment has occurred.

Key assumptions used in estimating fair value are detailed in the following table.


	Duke Energy Ohio				Duke Energy Indiana
	2022		2021		2022		2021
Anticipated credit loss ratio	0.5	%	0.5	%	0.3	%	0.3	%
Discount rate	2.7	%	1.1	%	2.7	%	1.1	%
Receivable turnover rate	13.5	%	13.5	%	11.3	%	11.3	%

The following table shows the gross and net receivables sold.


	Duke Energy Ohio				Duke Energy Indiana
	December 31,				December 31,
(in millions)	2022		2021		2022		2021
Receivables sold	$	423	$	269	$	508	$	328
Less: Retained interests	198		79		317		97
Net receivables sold	$	225	$	190	$	191	$	231

The following table shows sales and cash flows related to receivables sold.


	Duke Energy Ohio						Duke Energy Indiana
	Years Ended December 31,						Years Ended December 31,
(in millions)	2022		2021		2020		2022		2021		2020
Sales
Receivables sold	$	2,562	$	2,023	$	1,905	$	3,744	$	2,909	$	2,631
Loss recognized on sale	18		10		10		26		13		12
Cash flows
Cash proceeds from receivables sold	2,424		2,018		1,875		3,498		2,909		2,586
Collection fees received	1		1		1		2		1		1
Return received on retained interests	10		4		4		15		6		5

Cash flows from sales of receivables are reflected within Cash Flows From Operating Activities and Cash Flows from Investing Activities on Duke Energy Ohio’s and Duke Energy Indiana’s Consolidated Statements of Cash Flows.

Collection fees received in connection with servicing transferred accounts receivable are included in Operation, maintenance and other on Duke Energy Ohio’s and Duke Energy Indiana’s Consolidated Statements of Operations and Comprehensive Income. The loss recognized on sales of receivables is calculated monthly by multiplying receivables sold during the month by the required discount. The required discount is derived monthly utilizing a three-year weighted average formula that considers charge-off history, late charge history and turnover history on the sold receivables, as well as a component for the time value of money. The discount rate, or component for the time value of money, is the prior month-end Daily Simple SOFR plus a fixed rate of 1%.

19. REVENUE

Duke Energy recognizes revenue consistent with amounts billed under tariff offerings or at contractually agreed upon rates based on actual physical delivery of electric or natural gas service, including estimated volumes delivered when billings have not yet occurred. As such, the majority of Duke Energy’s revenues have fixed pricing based on the contractual terms of the published tariffs, with variability in expected cash flows attributable to the customer’s volumetric demand and ultimate quantities of energy or natural gas supplied and used during the billing period. The stand-alone selling price of related sales are designed to support recovery of prudently incurred costs and an appropriate return on invested assets and are primarily governed by published tariff rates or contractual agreements approved by relevant regulatory bodies. As described in Note 1, certain excise taxes and franchise fees levied by state or local governments are required to be paid even if not collected from the customer. These taxes are recognized on a gross basis as part of revenues. Duke Energy elects to account for all other taxes net of revenues.

Performance obligations are satisfied over time as energy or natural gas is delivered and consumed with billings generally occurring monthly and related payments due within 30 days, depending on regulatory requirements. In no event does the timing between payment and delivery of the goods and services exceed one year. Using this output method for revenue recognition provides a faithful depiction of the transfer of electric and natural gas service as customers obtain control of the commodity and benefit from its use at delivery. Additionally, Duke Energy has an enforceable right to consideration for energy or natural gas delivered at any discrete point in time and will recognize revenue at an amount that reflects the consideration to which Duke Energy is entitled for the energy or natural gas delivered.

As described above, the majority of Duke Energy’s tariff revenues are at-will and, as such, related contracts with customers have an expected duration of one year or less and will not have future performance obligations for disclosure. Additionally, other long-term revenue streams, including wholesale contracts, generally provide services that are part of a single performance obligation, the delivery of electricity or natural gas. As such, other than material fixed consideration under long-term contracts, related disclosures for future performance obligations are also not applicable.

Duke Energy earns substantially all of its revenues through its reportable segments, EU&I and GU&I.

Electric Utilities and Infrastructure

EU&I earns the majority of its revenues through retail and wholesale electric service through the generation, transmission, distribution and sale of electricity. Duke Energy generally provides retail and wholesale electric service customers with their full electric load requirements or with supplemental load requirements when the customer has other sources of electricity.

Retail electric service is generally marketed throughout Duke Energy's electric service territory through standard service offers. The standard service offers are through tariffs determined by regulators in Duke Energy's regulated service territory. Each tariff, which is assigned to customers based on customer class, has multiple components such as an energy charge, a demand charge, a basic facilities charge and applicable riders. Duke Energy considers each of these components to be aggregated into a single performance obligation for providing electric service, or in the case of distribution only customers in Duke Energy Ohio, for delivering electricity. Electricity is considered a single performance obligation satisfied over time consistent with the series guidance and is provided and consumed over the billing period, generally one month. Retail electric service is typically provided to at-will customers who can cancel service at any time, without a substantive penalty. Additionally, Duke Energy adheres to applicable regulatory requirements in each jurisdiction to ensure the collectability of amounts billed and appropriate mitigating procedures are followed when necessary. As such, revenue from contracts with customers for such contracts is equivalent to the electricity supplied and billed in that period (including unbilled estimates).

Wholesale electric service is generally provided under long-term contracts using cost-based pricing. FERC regulates costs that may be recovered from customers and the amount of return companies are permitted to earn. Wholesale contracts include both energy and demand charges. For full requirements contracts, Duke Energy considers both charges as a single performance obligation for providing integrated electric service. For contracts where energy and demand charges are considered separate performance obligations, energy and demand are each a distinct performance obligation under the series guidance and are satisfied as energy is delivered and stand-ready service is provided on a monthly basis. This service represents consumption over the billing period and revenue is recognized consistent with billings and unbilled estimates, which generally occur monthly. Contractual amounts owed are typically trued up annually based upon incurred costs in accordance with FERC published filings and the specific customer’s actual peak demand. Estimates of variable consideration related to potential additional billings or refunds owed are updated quarterly.

The majority of wholesale revenues are full requirements contracts where the customers purchase the substantial majority of their energy needs and do not have a fixed quantity of contractually required energy or capacity. As such, related forecasted revenues are considered optional purchases. Supplemental requirements contracts that include contracted blocks of energy and capacity at contractually fixed prices have the following estimated remaining performance obligations:


	Remaining Performance Obligations
(in millions)	2023		2024		2025		2026		2027		Thereafter		Total

Progress Energy	$	61	$	66	$	7	$	7	$	7	$	36	$	184
Duke Energy Progress	8		8		—		—		—		—		16
Duke Energy Florida	53		58		7		7		7		36		168
Duke Energy Indiana	11		16		17		15		7		5		71

Revenues for block sales are recognized monthly as energy is delivered and stand-ready service is provided, consistent with invoiced amounts and unbilled estimates.

Gas Utilities and Infrastructure

GU&I earns its revenue through retail and wholesale natural gas service through the transportation, distribution and sale of natural gas. Duke Energy generally provides retail and wholesale natural gas service customers with all natural gas load requirements. Additionally, while natural gas can be stored, substantially all natural gas provided by Duke Energy is consumed by customers simultaneously with receipt of delivery.

Retail natural gas service is marketed throughout Duke Energy's natural gas service territory using published tariff rates. The tariff rates are established by regulators in Duke Energy's service territories. Each tariff, which is assigned to customers based on customer class, have multiple components, such as a commodity charge, demand charge, customer or monthly charge and transportation costs. Duke Energy considers each of these components to be aggregated into a single performance obligation for providing natural gas service. For contracts where Duke Energy provides all of the customer’s natural gas needs, the delivery of natural gas is considered a single performance obligation satisfied over time, and revenue is recognized monthly based on billings and unbilled estimates as service is provided and the commodity is consumed over the billing period. Additionally, natural gas service is typically at-will and customers can cancel service at any time, without a substantive penalty. Duke Energy also adheres to applicable regulatory requirements to ensure the collectability of amounts billed and receivable and appropriate mitigating procedures are followed when necessary.

Certain long-term individually negotiated contracts exist to provide natural gas service. These contracts are regulated and approved by state commissions. The negotiated contracts have multiple components, including a natural gas and a demand charge, similar to retail natural gas contracts. Duke Energy considers each of these components to be a single performance obligation for providing natural gas service. This service represents consumption over the billing period, generally one month.

Fixed capacity payments under long-term contracts for the GU&I segment include minimum margin contracts and supply arrangements with municipalities and power generation facilities. Revenues for related sales are recognized monthly as natural gas is delivered and stand-ready service is provided, consistent with invoiced amounts and unbilled estimates. Estimated remaining performance obligations are as follows:


	Remaining Performance Obligations
(in millions)	2023		2024		2025		2026		2027		Thereafter		Total
Piedmont	$	68	$	62	$	61	$	51	$	49	$	241	$	532

Other

The remainder of Duke Energy’s operations is presented as Other, which does not include material revenues from contracts with customers.

Disaggregated Revenues

For the EU&I and GU&I segments, revenue by customer class is most meaningful to Duke Energy as each respective customer class collectively represents unique customer expectations of service, generally has different energy and demand requirements, and operates under tailored, regulatory approved pricing structures. Additionally, each customer class is impacted differently by weather and a variety of economic factors including the level of population growth, economic investment, employment levels, and regulatory activities in each of Duke Energy’s jurisdictions. As such, analyzing revenues disaggregated by customer class allows Duke Energy to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. Disaggregated revenues are presented as follows:


	Year Ended December 31, 2022
			Duke				Duke		Duke		Duke		Duke
(in millions)	Duke		Energy		Progress		Energy		Energy		Energy		Energy
By market or type of customer	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Electric Utilities and Infrastructure
Residential	$	11,377	$	3,275	$	5,812	$	2,378	$	3,434	$	862	$	1,430	$	—
General	7,356		2,396		3,396		1,480		1,916		517		1,049		—
Industrial	3,504		1,251		1,095		770		325		202		956		—
Wholesale	2,856		561		1,785		1,346		439		127		383		—
Other revenues	795		372		994		768		226		61		19		—
Total Electric Utilities and Infrastructure revenue from contracts with customers	$	25,888	$	7,855	$	13,082	$	6,742	$	6,340	$	1,769	$	3,837	$	—

Gas Utilities and Infrastructure
Residential	$	1,462	$	—	$	—	$	—	$	—	$	488	$	—	$	974
Commercial	765		—		—		—		—		180		—		585
Industrial	170		—		—		—		—		24		—		144
Power Generation	—		—		—		—		—		—		—		94
Other revenues	360		—		—		—		—		25		—		271
Total Gas Utilities and Infrastructure revenue from contracts with customers	$	2,757	$	—	$	—	$	—	$	—	$	717	$	—	$	2,068

Other
Revenue from contracts with customers	$	30	$	—	$	—	$	—	$	—	$	—	$	—	$	—

Total revenue from contracts with customers	$	28,675	$	7,855	$	13,082	$	6,742	$	6,340	$	2,486	$	3,837	$	2,068

Other revenue sources(a)	$	93	$	2	$	43	$	11	$	13	$	28	$	85	$	56
Total revenues	$	28,768	$	7,857	$	13,125	$	6,753	$	6,353	$	2,514	$	3,922	$	2,124

(a) Other revenue sources include revenues from leases, derivatives and alternative revenue programs that are not considered revenues from contracts with customers. Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over or under collection of related revenues.


	Year Ended December 31, 2021
			Duke				Duke		Duke		Duke		Duke
(in millions)	Duke		Energy		Progress		Energy		Energy		Energy		Energy
By market or type of customer	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Electric Utilities and Infrastructure
Residential	$	10,097	$	3,054	$	5,084	$	2,156	$	2,928	$	767	$	1,188	$	—
General	6,375		2,210		2,883		1,378		1,505		440		825		—
Industrial	2,924		1,145		894		634		260		135		750		—
Wholesale	2,199		472		1,385		1,164		221		56		285		—
Other revenues	879		264		716		387		329		83		86		—
Total Electric Utilities and Infrastructure revenue from contracts with customers	$	22,474	$	7,145	$	10,962	$	5,719	$	5,243	$	1,481	$	3,134	$	—

Gas Utilities and Infrastructure
Residential	$	1,131	$	—	$	—	$	—	$	—	$	354	$	—	$	777
Commercial	561		—		—		—		—		143		—		418
Industrial	158		—		—		—		—		20		—		137
Power Generation	—		—		—		—		—		—		—		92
Other revenues	133		—		—		—		—		28		—		45
Total Gas Utilities and Infrastructure revenue from contracts with customers	$	1,983	$	—	$	—	$	—	$	—	$	545	$	—	$	1,469




Other
Revenue from contracts with customers	$	29	$	—	$	—	$	—	$	—	$	—	$	—	$	—

Total revenue from contracts with customers	$	24,486	$	7,145	$	10,962	$	5,719	$	5,243	$	2,026	$	3,134	$	1,469

Other revenue sources(a)	$	135	$	(43)	$	95	$	61	$	16	$	11	$	40	$	100
Total revenues	$	24,621	$	7,102	$	11,057	$	5,780	$	5,259	$	2,037	$	3,174	$	1,569


	Year Ended December 31, 2020
			Duke				Duke		Duke		Duke		Duke
(in millions)	Duke		Energy		Progress		Energy		Energy		Energy		Energy
By market or type of customer	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Electric Utilities and Infrastructure
Residential	$	9,806	$	2,997	$	5,017	$	2,059	$	2,958	$	726	$	1,064	$	—
General	6,194		2,233		2,779		1,312		1,467		442		740		—
Industrial	2,859		1,137		901		649		252		137		683		—
Wholesale	1,864		380		1,228		1,034		194		32		224		—
Other revenues	914		281		596		294		302		82		72		—
Total Electric Utilities and Infrastructure revenue from contracts with customers	$	21,637	$	7,028	$	10,521	$	5,348	$	5,173	$	1,419	$	2,783	$	—

Gas Utilities and Infrastructure
Residential	$	930	$	—	$	—	$	—	$	—	$	300	$	—	$	630
Commercial	446		—		—		—		—		117		—		329
Industrial	127		—		—		—		—		17		—		110
Power Generation	—		—		—		—		—		—		—		34
Other revenues	87		—		—		—		—		17		—		70
Total Gas Utilities and Infrastructure revenue from contracts with customers	$	1,590	$	—	$	—	$	—	$	—	$	451	$	—	$	1,173




Other
Revenue from contracts with customers	$	26	$	—	$	—	$	—	$	—	$	—	$	—	$	—

Total revenue from contracts with customers	$	23,253	$	7,028	$	10,521	$	5,348	$	5,173	$	1,870	$	2,783	$	1,173

Other revenue sources(a)	$	113	$	(13)	$	106	$	74	$	15	$	(12)	$	12	$	124
Total revenues	$	23,366	$	7,015	$	10,627	$	5,422	$	5,188	$	1,858	$	2,795	$	1,297

As described in Note 1, Duke Energy adopted the new guidance for credit losses effective January 1, 2020, using the modified retrospective method of adoption, which does not require restatement of prior year reported results. The following table presents the reserve for credit losses for trade and other receivables based on adoption of the new standard.



			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Balance at December 31, 2019	$	76	$	10	$	16	$	8	$	7	$	4	$	3	$	6
Cumulative Change in Accounting Principle	5		1		2		1		1		—		—		1
Write-Offs	(58)		(13)		(23)		(8)		(14)		—		—		(6)
Credit Loss Expense	75		13		29		9		20		—		—		11
Other Adjustments	48		12		13		13		—		—		—		—
Balance at December 31, 2020	$	146	$	23	$	37	$	23	$	14	$	4	$	3	$	12
Write-Offs	(58)		(21)		(25)		(12)		(13)		—		—		(9)
Credit Loss Expense	53		27		25		11		14		—		—		7
Other Adjustments	(20)		13		(1)		(1)		1		—		—		5
Balance at December 31, 2021	$	121	$	42	$	36	$	21	$	16	$	4	$	3	$	15
Write-Offs	(158)		(73)		(70)		(36)		(34)		—		—		(12)
Credit Loss Expense	160		40		72		17		55		2		1		11
Other Adjustments	93		59		43		42		(1)		—		—		—
Balance at December 31, 2022	$	216	$	68	$	81	$	44	$	36	$	6	$	4	$	14

Trade and other receivables are evaluated based on an estimate of the risk of loss over the life of the receivable and current and historical conditions using supportable assumptions. Management evaluates the risk of loss for trade and other receivables by comparing the historical write-off amounts to total revenue over a specified period. Historical loss rates are adjusted due to the impact of current conditions, as well as forecasted conditions over a reasonable time period. The calculated write-off rate can be applied to the receivable balance for which an established reserve does not already exist. Management reviews the assumptions and risk of loss periodically for trade and other receivables.

The aging of trade receivables is presented in the table below.


	December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Unbilled Receivables(a)(b)	$	1,457	$	486	$	355	$	232	$	123	$	20	$	28	$	160
Current	2,347		577		1,059		637		417		15		52		265
1-30 days past due	261		96		60		15		45		5		17		15
31-60 days past due	123		23		61		49		12		6		2		3
61-90 days past due	74		25		18		9		9		3		11		2
91+ days past due	209		70		74		27		47		26		6		4
Deferred Payment Arrangements(c)	160		57		62		35		27		4		—		1
Trade and Other Receivables	$	4,631	$	1,334	$	1,689	$	1,004	$	680	$	79	$	116	$	450


	December 31, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Unbilled Receivables(a)(b)	$	922	$	316	$	266	$	193	$	73	$	4	$	27	$	106
Current	1,941		592		716		405		311		42		50		202
1-30 days past due	288		77		128		44		82		4		5		12
31-60 days past due	98		30		49		21		28		1		10		2
61-90 days past due	118		32		48		28		20		23		5		4
91+ days past due	161		84		37		9		28		24		6		3
Deferred Payment Arrangements(c)	115		55		45		22		23		2		—		4
Trade and Other Receivables	$	3,643	$	1,186	$	1,289	$	722	$	565	$	100	$	103	$	333

(a) Unbilled revenues are recognized by applying customer billing rates to the estimated volumes of energy or natural gas delivered but not yet billed and are included within Receivables and Receivables of VIEs on the Consolidated Balance Sheets.

(b) Duke Energy Ohio and Duke Energy Indiana sell, on a revolving basis, nearly all of their retail accounts receivable, including receivables for unbilled revenues, to an affiliate, CRC, and account for the transfers of receivables as sales. Accordingly, the receivables sold are not reflected on the Consolidated Balance Sheets of Duke Energy Ohio and Duke Energy Indiana. See Note 18 for further information. These receivables for unbilled revenues are $148 million and $260 million for Duke Energy Ohio and Duke Energy Indiana, respectively, as of December 31, 2022, and $82 million and $121 million for Duke Energy Ohio and Duke Energy Indiana, respectively, as of December 31, 2021.

(c) Due to ongoing financial hardships impacting customers, Duke Energy has permitted customers to defer payment of past-due amounts through installment payment plans.

20. STOCKHOLDERS' EQUITY

Basic EPS is computed by dividing net income available to Duke Energy common stockholders, as adjusted for distributed and undistributed earnings allocated to participating securities and accumulated preferred dividends, by the weighted average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income available to Duke Energy common stockholders, as adjusted for distributed and undistributed earnings allocated to participating securities and accumulated preferred dividends, by the diluted weighted average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock, such as equity forward sale agreements, were exercised or settled. Duke Energy’s participating securities are RSUs that are entitled to dividends declared on Duke Energy common stock during the RSUs vesting periods. Dividends declared on preferred stock are recorded on the Consolidated Statements of Operations as a reduction of net income to arrive at net income available to Duke Energy common stockholders. Dividends accumulated on preferred stock are an adjustment to net income used in the calculation of basic and diluted EPS.

The following table presents Duke Energy’s basic and diluted EPS calculations, the weighted average number of common shares outstanding and common and preferred share dividends declared.


	Years Ended December 31,
(in millions, except per share amounts)	2022		2021		2020
Net Income available to Duke Energy common stockholders	$	2,444	$	3,802	$	1,270
Less: (Loss) Income from discontinued operations attributable to Duke Energy common stockholders	(1,215)		200		289
Accumulated preferred stock dividends adjustment	—		—		1
Less: Impact of participating securities	2		3		2
Income from continuing operations available to Duke Energy common stockholders	$	3,657	$	3,599	$	980

Loss from discontinued operations, net of tax	$	(1,323)	$	(144)	$	(7)
Add: Loss attributable to NCI	108		344		296
(Loss) Income from discontinued operations attributable to Duke Energy common stockholders	$	(1,215)	$	200	$	289
Weighted average common shares outstanding – basic	770		769		737

Equity forwards	—		—		1
Weighted average common shares outstanding – diluted	770		769		738
EPS from continuing operations available to Duke Energy common stockholders
Basic and Diluted	$	4.74	$	4.68	$	1.33

(Loss) Earnings Per Share from discontinued operations attributable to Duke Energy common stockholders
Basic and Diluted	$	(1.57)	$	0.26	$	0.39
Potentially dilutive items excluded from the calculation(a)	2		2		2
Dividends declared per common share	$	3.98	$	3.90	$	3.82
Dividends declared on Series A preferred stock per depositary share(b)	$	1.437	$	1.437	$	1.437
Dividends declared on Series B preferred stock per share(c)	$	48.750	$	48.750	$	49.292

(a) Performance stock awards were not included in the dilutive securities calculation because the performance measures related to the awards had not been met.

(b) 5.75% Series A Cumulative Redeemable Perpetual Preferred Stock dividends are payable quarterly in arrears on the 16th day of March, June, September and December. The preferred stock has a $25 liquidation preference per depositary share.

(c) 4.875% Series B Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock dividends are payable semiannually in arrears on the 16th day of March and September. The preferred stock has a $1,000 liquidation preference per share. On September 16, 2024, the First Call Date, and any fifth anniversary of the First Call Date, the dividend rate will reset based on the then current five-year U.S. Treasury rate plus a spread of 3.388%.

Common Stock

In November 2022, Duke Energy filed a prospectus supplement and executed an EDA under which it may sell up to $1.5 billion of its common stock through a new ATM offering program, including an equity forward sales component. Under the terms of the EDA, Duke Energy may issue and sell shares of common stock through September 2025.

Preferred Stock

The Series A Preferred Stock has no maturity or mandatory redemption date, is not redeemable at the option of the holders and includes separate call options. The first call option allows Duke Energy to call the Series A Preferred Stock at a redemption price of $25.50 per depositary share prior to June 15, 2024, in whole but not in part, at any time within 120 days after a ratings event where a rating agency amends, clarifies or changes the criteria it uses to assign equity credit for securities such as the preferred stock. The second call option allows Duke Energy to call the preferred stock, in whole or in part, at any time, on or after June 15, 2024, at a redemption price of $25 per depositary share. Duke Energy is also required to redeem all accumulated and unpaid dividends if either call option is exercised.

The Series B Preferred Stock has no maturity or mandatory redemption date, is not redeemable at the option of the holders and includes separate call options. The first call option allows Duke Energy to call the Series B Preferred Stock at a redemption price of $1,020 per share, in whole but not in part, at any time within 120 days after a ratings event. The second call option allows Duke Energy to call the preferred stock, in whole or in part, on the First Call Date or any subsequent Reset Date at a redemption price in cash equal to $1,000 per share. Duke Energy is also required to redeem all accumulated and unpaid dividends if either call option is exercised.

Dividends issued on its Series A and Series B Preferred Stock are subject to approval by the Board of Directors. However, the deferral of dividend payments on the preferred stock prohibits the declaration of common stock dividends.

The Series A and Series B Preferred Stock rank, with respect to dividends and distributions upon liquidation or dissolution:

•senior to Common Stock and to each other class or series of capital stock established after the original issue date of the Series A and Series B Preferred Stock that is expressly made subordinated to the Series A and Series B Preferred Stock;

•on a parity with any class or series of capital stock established after the original issue date of the Series A and Series B Preferred Stock that is not expressly made senior or subordinated to the Series A or Series B Preferred Stock;

•junior to any class or series of capital stock established after the original issue date of the Series A and Series B Preferred Stock that is expressly made senior to the Series A or Series B Preferred Stock;

•junior to all existing and future indebtedness (including indebtedness outstanding under Duke Energy's credit facilities, unsecured senior notes, junior subordinated debentures and commercial paper) and other liabilities with respect to assets available to satisfy claims against Duke Energy; and

•structurally subordinated to existing and future indebtedness and other liabilities of Duke Energy's subsidiaries and future preferred stock of subsidiaries.

Holders of Series A and Series B Preferred Stock have no voting rights with respect to matters that generally require the approval of voting stockholders. The limited voting rights of holders of Series A and Series B Preferred Stock include the right to vote as a single class, respectively, on certain matters that may affect the preference or special rights of the preferred stock, except in the instance that Duke Energy elects to defer the payment of dividends for a total of six quarterly full dividend periods for Series A Preferred Stock or three semiannual full dividend periods for Series B Preferred Stock. If dividends are deferred for a cumulative total of six quarterly full dividend periods for Series A Preferred Stock or three semiannual full dividend periods for Series B Preferred Stock, whether or not for consecutive dividend periods, holders of the respective preferred stock have the right to elect two additional Board members to the Board of Directors.

21. SEVERANCE

During 2022, Duke Energy identified opportunities to eliminate work and create sustainable savings through a workload reduction initiative with a focus on process improvement through digital technology, governance simplification and elimination of low-value work. As a result, Duke Energy extended involuntary severance benefits to certain employees in specific areas as a part of this initiative.

During 2021, Duke Energy reviewed its operations and identified opportunities for improvement to better serve its customers. This operational review included workforce realignment to ensure the company is staffed with the right skill sets and number of teammates to execute the long-term vision for Duke Energy. As such, Duke Energy extended involuntary severance benefits to certain employees in specific areas as a part of these workforce realignment efforts.

During 2020, as a result of partial settlements between Duke Energy Carolinas, Duke Energy Progress and the Public Staff, Duke Energy Carolinas and Duke Energy Progress deferred as Regulatory assets on the Consolidated Balance Sheets, approximately $65 million and $33 million, respectively, of previously recorded severance charges within Operation, maintenance and other on the Consolidated Statements of Operations. These severance charges were previously recorded during 2018, as Duke Energy reviewed its operations and identified opportunities for improvement to better serve its customers. This operational review included the company's workforce strategy and staffing levels to ensure the company was staffed with the right skill sets and number of teammates to execute the long-term vision for Duke Energy. As such, Duke Energy extended voluntary and involuntary severance benefits to certain employees in specific areas as a part of workforce planning and digital transformation efforts.

The following table presents the direct and allocated severance and related charges accrued for approximately 233 employees in 2022, 290 employees in 2021 and 30 employees in 2020, by the Duke Energy Registrants within Operation, maintenance and other on the Consolidated Statements of Operations.


			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Year Ended December 31, 2022(a)(b)	$	65	$	40	$	20	$	17	$	3	$	1	$	2	$	2
Year Ended December 31, 2021(c)(d)	69		33		26		20		6		2		3		2
Year Ended December 31, 2020(e)(f)	(85)		(58)		(28)		(31)		3		—		—		—

(a) Includes amortization of deferred severance charges of approximately $33 million, $22 million, $11 million and $11 million for Duke Energy, Duke Energy Carolinas, Progress Energy and Duke Energy Progress, respectively.

(b) Includes adjustments associated with 2021 severance charges of approximately $(19) million, $(6) million, $(8) million, $(4) million, $(4) million, $(1) million, $(2) million and $(1) million for Duke Energy, Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio, Duke Energy Indiana and Piedmont, respectively.

(c) Includes amortization of deferred severance charges of approximately $33 million, $22 million, $11 million and $11 million for Duke Energy, Duke Energy Carolinas, Progress Energy and Duke Energy Progress, respectively.

(d) Includes adjustments associated with 2018 severance charges of approximately $(3) million, $(2) million and $(1) million for Duke Energy, Duke Energy Carolinas and Duke Energy Indiana, respectively.

(e) Includes unamortized deferred severance charges of approximately $(86) million, $(57) million, $(29) million and $(29) million for Duke Energy, Duke Energy Carolinas, Progress Energy and Duke Energy Progress, respectively.

(f) Includes adjustments associated with 2018 severance charges of approximately $(6) million, $(2) million, $(3) million and $(2) million for Duke Energy, Duke Energy Carolinas, Progress Energy and Duke Energy Progress, respectively.

The table below presents the severance liability for past and ongoing severance plans including the plans described above.


			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Balance at December 31, 2020	$	11	$	2	$	3	$	1	$	2	$	—	$	1	$	—
Provision/Adjustments	36		1		1		1		—		—		—		—
Cash Reductions	(8)		(1)		(2)		(1)		(1)		—		(1)		—
Balance at December 31, 2021	$	39	$	2	$	2	$	1	$	1	$	—	$	—	$	—
Provision/Adjustments	33		14		4		3		1		—		—		1
Cash Reductions	(8)		(1)		—		—		—		—		—		—
Balance at December 31, 2022	$	64	$	15	$	6	$	4	$	2	$	—	$	—	$	1

22. STOCK-BASED COMPENSATION

The Duke Energy Corporation 2015 Long-Term Incentive Plan (the 2015 Plan) provides for the grant of stock-based compensation awards to employees and outside directors. The 2015 Plan reserved 10 million shares of common stock for issuance. Duke Energy has historically issued new shares upon exercising or vesting of share-based awards. However, Duke Energy may use a combination of new share issuances and open market repurchases for share-based awards that are exercised or vest in the future. Duke Energy has not determined with certainty the amount of such new share issuances or open market repurchases.

The following table summarizes the total expense recognized by the Duke Energy Registrants, net of tax, for stock-based compensation.


	Years Ended December 31,
(in millions)	2022		2021		2020
Duke Energy	$	74	$	64	$	61
Duke Energy Carolinas	27		23		22
Progress Energy	27		24		23
Duke Energy Progress	17		15		15
Duke Energy Florida	10		9		9
Duke Energy Ohio	5		5		4
Duke Energy Indiana	7		6		6
Piedmont	4		3		3

Duke Energy's pretax stock-based compensation costs, the tax benefit associated with stock-based compensation expense and stock-based compensation costs capitalized are included in the following table.


	Years Ended December 31,
(in millions)	2022		2021		2020
RSU awards	$	58	$	49	$	46
Performance awards	42		39		38

Pretax stock-based compensation cost	$	100	$	88	$	84
Stock-based compensation costs capitalized	5		5		5
Stock-based compensation expense	$	95	$	83	$	79
Tax benefit associated with stock-based compensation expense	$	21	$	19	$	18

RESTRICTED STOCK UNIT AWARDS

RSU awards generally vest over periods from immediate to three years. Fair value amounts are based on the market price of Duke Energy's common stock on the grant date. The following table includes information related to RSU awards.


	Years Ended December 31,
	2022		2021		2020
Shares granted (in thousands)	654		673		498
Fair value (in millions)	$	64	$	59	$	50

The following table summarizes information about RSU awards outstanding.


		Weighted Average
	Shares	Grant Date Fair Value
	(in thousands)	(per share)
Outstanding at December 31, 2021	1,043	$	92
Granted	654	98
Vested	(527)	93
Forfeited	(73)	94
Outstanding at December 31, 2022	1,097	95
RSU awards expected to vest	1,056	95

The total grant date fair value of shares vested during the years ended December 31, 2022, 2021 and 2020, was $49 million, $45 million and $43 million, respectively. At December 31, 2022, Duke Energy had $34 million of unrecognized compensation cost, which is expected to be recognized over a weighted average period of 23 months.

PERFORMANCE AWARDS

Stock-based performance awards generally vest after three years to the extent performance targets are met. The actual number of shares issued will range from zero to 200% of target shares, depending on the level of performance achieved.

Performance awards contain performance conditions and a market condition. The performance conditions are based on Duke Energy's cumulative adjusted EPS and total incident case rate (total incident case rate is one of our key employee safety metrics). The market condition is based on TSR of Duke Energy relative to a predefined peer group.

Relative TSR is valued using a path-dependent model that incorporates expected relative TSR into the fair value determination of Duke Energy’s performance-based share awards. The model uses three-year historical volatilities and correlations for all companies in the predefined peer group, including Duke Energy, to simulate Duke Energy’s relative TSR as of the end of the performance period. For each simulation, Duke Energy’s relative TSR associated with the simulated stock price at the end of the performance period plus expected dividends within the period results in a value per share for the award portfolio. The average of these simulations is the expected portfolio value per share. Actual life to date results of Duke Energy’s relative TSR for each grant are incorporated within the model. For performance awards granted in 2022, the model used a risk-free interest rate of 1.78%, which reflects the yield on three-year Treasury bonds as of the grant date, and an expected volatility of 26.8% based on Duke Energy's historical volatility over three years using daily stock prices.

The following table includes information related to stock-based performance awards.


	Years Ended December 31,
	2022		2021		2020
Shares granted assuming target performance (in thousands)	408		380		319
Fair value (in millions)	$	40	$	33	$	34

The following table summarizes information about stock-based performance awards outstanding and assumes payout at the target level.


		Weighted Average
	Shares	Grant Date Fair Value
	(in thousands)	(per share)
Outstanding at December 31, 2021	952	$	93
Granted	408	99


Vested	(297)	86
Forfeited	(30)	96
Outstanding at December 31, 2022	1,033	97
Stock-based performance awards expected to vest	1,006	97

The total grant date fair value of shares vested during the years ended December 31, 2022, and 2021, was $25 million and $25 million, respectively. At December 31, 2022, Duke Energy had $22 million of unrecognized compensation cost, which is expected to be recognized over a weighted average period of 22 months.

23. EMPLOYEE BENEFIT PLANS

DEFINED BENEFIT RETIREMENT PLANS

Duke Energy and certain subsidiaries maintain, and the Subsidiary Registrants participate in, qualified, non-contributory defined benefit retirement plans, which consist of the Duke Energy Retirement Cash Balance Plan (RCBP), which is an active plan, and the Duke Energy Legacy Pension Plan (DELPP), which is an inactive plan. These plans cover most employees using a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit consisting of pay credits based upon a percentage of current eligible earnings, age or age and years of service and interest credits. Certain employees are eligible for benefits that use a final average earnings formula. Under these final average earnings formulas, a plan participant accumulates a retirement benefit equal to the sum of percentages of their (i) highest three-, four-, or five-year average earnings, (ii) highest three-, four-, or five-year average earnings in excess of covered compensation per year of participation (maximum of 35 years) or (iii) highest three-year average earnings times years of participation in excess of 35 years. Duke Energy also maintains, and the Subsidiary Registrants participate in, non-qualified, non-contributory defined benefit retirement plans that cover certain executives. The qualified and non-qualified, non-contributory defined benefit plans are closed to new participants.

Duke Energy uses a December 31 measurement date for its defined benefit retirement plan assets and obligations. Actuarial losses experienced by the defined benefit retirement plans in remeasuring plan assets on December 31, 2022, were primarily attributable to actual investment performance that was less than expected investment performance. Actuarial gains experienced by the defined benefit retirement plans in remeasuring plan obligations as of December 31, 2022, were primarily attributable to the increase in the discount rate used to measure plan obligations. Actuarial losses experienced by the defined benefit retirement plans in remeasuring plan assets as of December 31, 2021, were primarily attributable to actual investment performance that was less than expected investment performance. Actuarial gains experienced by the defined benefit retirement plans in remeasuring plan obligations as of December 31, 2021, were primarily attributable to the increase in the discount rate used to measure plan obligations.

As a result of the application of settlement accounting due to total lump-sum benefit payments exceeding the settlement threshold (defined as the sum of service cost and interest cost on projected benefit obligation components of net periodic benefit costs) for one of its qualified pension plans, Duke Energy recognized settlement charges of $117 million, of which $95 million was recorded to Regulatory Assets within Other Noncurrent Assets on the Condensed Consolidated Balance Sheets and $22 million was recorded to Other Income and Expenses, net, within the Condensed Consolidated Statement of Operations as of December 31, 2022.

Settlement charges recognized by the Subsidiary Registrants as of December 31, 2022, which represent amounts allocated by Duke Energy for employees of the Subsidiary Registrants and allocated charges for their proportionate share of settlement charges for employees of Duke Energy's shared services affiliate, and recorded to Regulatory Assets within Other Noncurrent Assets on the Condensed Consolidated Balance Sheets were $35 million for Duke Energy Carolinas, $23 million for Progress Energy, $16 million for Duke Energy Progress, $7 million for Duke Energy Florida, $8 million for Duke Energy Indiana and $29 million for Piedmont. Settlement charges recognized by the Subsidiary Registrants as of December 31, 2022, recorded to Other Income and Expenses, net, within the Condensed Consolidated Statement of Operations were $3 million for Duke Energy Carolinas, $5 million for Progress Energy, $5 million for Duke Energy Progress, $1 million for Duke Energy Florida, $5 million for Duke Energy Ohio and $6 million for Piedmont.

The settlement charges reflect the recognition of a pro-rata portion of previously unrecognized actuarial losses, equal to the percentage of reduction in the projected benefit obligation resulting from total lump-sum benefit payments as of December 31, 2022. Settlement charges recognized as a regulatory asset within Other Noncurrent Assets on the Consolidated Balance Sheets are amortized over the average remaining service period for participants in the plan. Amortization of settlement charges is disclosed in the tables below as a component of net periodic pension costs.

Effective December 31, 2022, Duke Energy Florida changed its method for calculating the market related value of plan assets (MRVA) from the fair value method to a method that recognizes changes in fair value of its plan assets over a five-year period. This represents a change in regulatory treatment that will serve to mitigate the impact of market volatility on retail customer rates, resulting in the timing of net periodic pension cost recognition that is more consistent with treatment of the related cost in the ratemaking process. The three-year retrospective impact of this method change of $24 million was recognized by Duke Energy, Progress Energy and Duke Energy Florida, respectively, and was recorded to Other Income and Expenses, net, within the Condensed Consolidated Statement of Operations and has been disclosed in the tables below as a component of net periodic pension costs.

Net periodic benefit costs disclosed in the tables below represent the cost of the respective benefit plan for the periods presented prior to capitalization of amounts reflected as Net property, plant and equipment, on the Consolidated Balance Sheets. Only the service cost component of net periodic benefit costs is eligible to be capitalized. The remaining non-capitalized portions of net periodic benefit costs are classified as either: (1) service cost, which is recorded in Operations, maintenance and other on the Consolidated Statements of Operations; or as (2) components of non-service cost, which is recorded in Other income and expenses, net on the Consolidated Statements of Operations. Amounts presented in the tables below for the Subsidiary Registrants represent the amounts of pension and other post-retirement benefit cost allocated by Duke Energy for employees of the Subsidiary Registrants. Additionally, the Consolidated Statements of Operations of the Subsidiary Registrants also include allocated net periodic benefit costs for their proportionate share of pension and post-retirement benefit cost for employees of Duke Energy’s shared services affiliate that provide support to the Subsidiary Registrants. However, in the tables below, these amounts are only presented within the Duke Energy column (except for amortization of settlement charges). These allocated amounts are included in the governance and shared service costs discussed in Note 14.

Duke Energy’s policy is to fund amounts on an actuarial basis to provide assets sufficient to meet benefit payments to be paid to plan participants. The following table includes information related to the Duke Energy Registrants’ contributions to its qualified defined benefit pension plans. There were no contributions made in the years ended December 31, 2021 and 2020.


			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont




Contributions Made:
2022	$	58	$	15	$	13	$	8	$	5	$	3	$	5	$	2

QUALIFIED PENSION PLANS

Components of Net Periodic Pension Costs


	Year Ended December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Service cost	$	152	$	48	$	43	$	25	$	17	$	4	$	9	$	5
Interest cost on projected benefit obligation	249		59		77		35		41		13		20		8
Expected return on plan assets	(558)		(152)		(183)		(88)		(94)		(23)		(37)		(24)
Amortization of actuarial loss	81		16		23		12		12		4		9		5
Amortization of prior service credit	(18)		(3)		—		—		—		—		(2)		(7)
Amortization of settlement charges(c)	32		9		8		7		1		5		1		7
MRVA method change	24		—		24		—		24		—		—		—
Net periodic pension costs(a)(b)	$	(38)	$	(23)	$	(8)	$	(9)	$	1	$	3	$	—	$	(6)


	Year Ended December 31, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Service cost	$	176	$	56	$	50	$	29	$	21	$	5	$	10	$	6
Interest cost on projected benefit obligation	220		51		70		30		39		13		18		7
Expected return on plan assets	(558)		(141)		(187)		(84)		(102)		(28)		(40)		(20)
Amortization of actuarial loss	133		29		38		18		20		7		13		10
Amortization of prior service credit	(29)		(8)		(2)		(1)		(1)		(1)		(2)		(9)
Amortization of settlement charges	9		5		2		2		1		—		—		1
Net periodic pension costs(a)(b)	$	(49)	$	(8)	$	(29)	$	(6)	$	(22)	$	(4)	$	(1)	$	(5)


	Year Ended December 31, 2020
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Service cost	$	165	$	51	$	48	$	27	$	21	$	5	$	9	$	6
Interest cost on projected benefit obligation	269		62		85		38		46		15		22		9
Expected return on plan assets	(572)		(145)		(190)		(87)		(101)		(28)		(42)		(21)
Amortization of actuarial loss	128		28		41		18		23		6		12		9
Amortization of prior service credit	(32)		(8)		(3)		(2)		(1)		—		(2)		(9)
Amortization of settlement charges(c)	18		9		7		6		1		—		1		1
Net periodic pension costs(a)(b)	$	(24)	$	(3)	$	(12)	$	—	$	(11)	$	(2)	$	—	$	(5)

(a) Duke Energy amounts exclude $3 million, $3 million and $4 million for the years ended December 2022, 2021 and 2020, respectively, of regulatory asset amortization resulting from purchase accounting adjustments associated with Duke Energy's merger with Cinergy in April 2006.

(b) Duke Energy Ohio amounts exclude $1 million, $1 million and $2 million for the years ended December 2022, 2021 and 2020, respectively, of regulatory asset amortization resulting from purchase accounting adjustments associated with Duke Energy's merger with Cinergy in April 2006.

Amounts Recognized in Accumulated Other Comprehensive Income and Regulatory Assets


	Year Ended December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Regulatory assets, net increase (decrease)	$	367	$	221	$	107	$	101	$	5	$	(1)	$	(12)	$	9
Accumulated other comprehensive loss (income)
Deferred income tax expense	$	(7)	$	—	$	(1)	$	—	$	—	$	—	$	—	$	—
Amortization of prior year service credit	—		—		—		—		—		—		—		—
Amortization of prior year actuarial losses	37		—		2		—		—		—		—		—
Net amount recognized in accumulated other comprehensive income	$	30	$	—	$	1	$	—	$	—	$	—	$	—	$	—


	Year Ended December 31, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Regulatory assets, net decrease	$	(261)	$	(57)	$	(128)	$	(31)	$	(97)	$	(17)	$	(19)	$	(5)
Accumulated other comprehensive loss (income)
Deferred income tax expense	$	1	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Amortization of prior year service credit	1		—		—		—		—		—		—		—
Amortization of prior year actuarial losses	(8)		—		(1)		—		—		—		—		—
Net amount recognized in accumulated other comprehensive income	$	(6)	$	—	$	(1)	$	—	$	—	$	—	$	—	$	—

Reconciliation of Funded Status to Net Amount Recognized


	Year Ended December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Change in Projected Benefit Obligation
Obligation at prior measurement date	$	8,207	$	1,903	$	2,560	$	1,153	$	1,392	$	450	$	680	$	273

Service cost	145		47		40		24		16		4		8		5
Interest cost	249		59		77		35		41		13		20		8
Actuarial gain	(1,490)		(301)		(513)		(197)		(312)		(84)		(143)		(47)
Benefits paid	(753)		(159)		(184)		(101)		(82)		(50)		(66)		(69)

Transfers	—		5		(5)		(5)		—		—		—		—
Obligation at measurement date	$	6,358	$	1,554	$	1,975	$	909	$	1,055	$	333	$	499	$	170
Accumulated Benefit Obligation at measurement date	$	6,324	$	1,556	$	1,959	$	910	$	1,038	$	327	$	495	$	170
Change in Fair Value of Plan Assets
Plan assets at prior measurement date	$	9,235	$	2,365	$	3,053	$	1,421	$	1,610	$	438	$	669	$	334

Employer contributions	58		15		13		8		5		3		5		2
Actual return on plan assets	(1,547)		(411)		(506)		(240)		(262)		(68)		(107)		(64)
Benefits paid	(753)		(159)		(184)		(101)		(82)		(50)		(66)		(69)

Transfers	—		5		(5)		(5)		—		—		—		—

Plan assets at measurement date	$	6,993	$	1,815	$	2,371	$	1,083	$	1,271	$	323	$	501	$	203
Funded status of plan	$	635	$	261	$	396	$	174	$	216	$	(10)	$	2	$	33


	Year Ended December 31, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Change in Projected Benefit Obligation
Obligation at prior measurement date	$	8,634	$	1,988	$	2,715	$	1,193	$	1,507	$	502	$	715	$	293

Service cost	168		54		48		28		20		5		9		6
Interest cost	220		51		70		30		39		13		18		7
Actuarial gain	(200)		(42)		(108)		(18)		(89)		(10)		(10)		(5)
Benefits paid	(615)		(148)		(161)		(80)		(81)		(50)		(52)		(28)

Transfers	—		—		(4)		—		(4)		(10)		—		—
Obligation at measurement date	$	8,207	$	1,903	$	2,560	$	1,153	$	1,392	$	450	$	680	$	273
Accumulated Benefit Obligation at measurement date	$	8,144	$	1,904	$	2,529	$	1,154	$	1,361	$	439	$	672	$	274
Change in Fair Value of Plan Assets
Plan assets at prior measurement date	$	9,337	$	2,381	$	3,049	$	1,422	$	1,605	$	472	$	684	$	343


Actual return on plan assets	513		132		169		79		90		26		37		19
Benefits paid	(615)		(148)		(161)		(80)		(81)		(50)		(52)		(28)

Transfers	—		—		(4)		—		(4)		(10)		—		—

Plan assets at measurement date	$	9,235	$	2,365	$	3,053	$	1,421	$	1,610	$	438	$	669	$	334
Funded status of plan	$	1,028	$	462	$	493	$	268	$	218	$	(12)	$	(11)	$	61

Amounts Recognized in the Consolidated Balance Sheets


	December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Prefunded pension(a)	$	885	$	261	$	396	$	174	$	216	$	62	$	90	$	33
Noncurrent pension liability(b)	$	250	$	—	$	—	$	—	$	—	$	72	$	88	$	—
Net asset (liability) recognized	$	635	$	261	$	396	$	174	$	216	$	(10)	$	2	$	33
Regulatory assets	$	2,016	$	545	$	670	$	353	$	316	$	92	$	178	$	84
Accumulated other comprehensive (income) loss
Deferred income tax benefit	$	(27)	$	—	$	(1)	$	—	$	—	$	—	$	—	$	—
Prior service credit	(1)		—		—		—		—		—		—		—
Net actuarial loss	129		—		3		—		—		—		—		—
Net amounts recognized in accumulated other comprehensive loss	$	101	$	—	$	2	$	—	$	—	$	—	$	—	$	—


	December 31, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Prefunded pension(a)	$	1,071	$	462	$	494	$	268	$	219	$	74	$	100	$	61
Noncurrent pension liability(b)	$	43	$	—	$	1	$	—	$	1	$	86	$	111	$	—
Net asset (liability) recognized	$	1,028	$	462	$	493	$	268	$	218	$	(12)	$	(11)	$	61
Regulatory assets	$	1,649	$	324	$	563	$	252	$	311	$	93	$	190	$	75
Accumulated other comprehensive (income) loss
Deferred income tax benefit	$	(20)	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Prior service credit	(1)		—		—		—		—		—		—		—
Net actuarial loss	92		—		1		—		—		—		—		—
Net amounts recognized in accumulated other comprehensive loss	$	71	$	—	$	1	$	—	$	—	$	—	$	—	$	—

(a) Included in Other within Other Noncurrent Assets on the Consolidated Balance Sheets.

(b) Included in Accrued pension and other post-retirement benefit costs on the Consolidated Balance Sheets.

Information for Plans with Accumulated Benefit Obligation in Excess of Plan Assets


	December 31, 2022
			Duke		Duke
	Duke		Energy		Energy
(in millions)	Energy		Ohio		Indiana
Projected benefit obligation	$	3,323	$	103	$	198
Accumulated benefit obligation	3,288		99		193
Fair value of plan assets	3,073		31		110


	December 31, 2021
	Duke		Duke
	Energy		Energy
(in millions)	Ohio		Indiana
Projected benefit obligation	$	153	$	284
Accumulated benefit obligation	143		275
Fair value of plan assets	67		173

Assumptions Used for Pension Benefits Accounting

The discount rate used to determine the current year pension obligation and following year’s pension expense is based on a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high-quality corporate bonds that generate sufficient cash flow to provide for projected benefit payments of the plan. The selected bond portfolio is derived from a universe of non-callable corporate bonds rated Aa quality or higher. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan’s projected benefit payments discounted at this rate with the market value of the bonds selected.

The average remaining service period for participants in active plans and life expectancy of participants in inactive plans is 13 years for Duke Energy and Duke Energy Progress, 15 years for Duke Energy Florida and Duke Energy Ohio, 14 years for Progress Energy and Duke Energy Indiana, 12 years for Duke Energy Carolinas and nine years for Piedmont.

The following tables present the assumptions or range of assumptions used for pension benefit accounting.


	December 31,
	2022				2021				2020
Benefit Obligations
Discount rate				5.60%				2.90%				2.60%
Interest crediting rate				4.35%				4.00%				4.00%
Salary increase	3.50	%	–	4.00%	3.50	%	–	4.00%	3.50	%	–	4.00%
Net Periodic Benefit Cost
Discount rate	2.90	%	–	5.70%				2.60%				3.30%
Interest crediting rate				4.00%				4.00%				4.00%
Salary increase	3.50	%	–	4.00%	3.50	%	–	4.00%	3.50	%	–	4.00%
Expected long-term rate of return on plan assets				6.50%				6.50%				6.85%

Expected Benefit Payments


			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Years ending December 31,
2023	$	661	$	186	$	183	$	99	$	83	$	32	$	45	$	19
2024	635		176		180		95		84		31		45		18
2025	629		174		183		97		85		31		44		16
2026	607		164		180		91		87		30		44		16
2027	592		156		177		89		87		29		43		15
2028-2032	2,581		628		804		372		427		135		205		71

NON-QUALIFIED PENSION PLANS

The accumulated benefit obligation, which equals the projected benefit obligation for non-qualified pension plans, was $232 million for Duke Energy, $10 million for Duke Energy Carolinas, $78 million for Progress Energy, $24 million for Duke Energy Progress, $32 million for Duke Energy Florida, $3 million for Duke Energy Ohio, $2 million for Duke Energy Indiana and $3 million for Piedmont as of December 31, 2022.

Employer contributions, which equal benefits paid for non-qualified pension plans, were $24 million for Duke Energy, $1 million for Duke Energy Carolinas, $10 million for Progress Energy, $3 million for Duke Energy Progress and $4 million for Duke Energy Florida for the year ended December 31, 2022. Employer contributions were not material for Duke Energy Ohio, Duke Energy Indiana or Piedmont for the year ended December 31, 2022.

Net periodic pension costs for non-qualified pension plans were not material for the years ended December 31, 2022, 2021 or 2020.

OTHER POST-RETIREMENT BENEFIT PLANS

Duke Energy provides, and the Subsidiary Registrants participate in, some health care and life insurance benefits for retired employees on a contributory and non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans. The health care benefits include medical, dental, vision and prescription drug coverage and are subject to certain limitations, such as deductibles and copayments.

Duke Energy did not make any pre-funding contributions to its other post-retirement benefit plans during the years ended December 31, 2022, 2021 or 2020.

Components of Net Periodic Other Post-Retirement Benefit Costs


	Year Ended December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Service cost	$	3	$	1	$	—	$	—	$	—	$	—	$	—	$	—
Interest cost on accumulated post-retirement benefit obligation	17		4		7		4		3		1		1		1
Expected return on plan assets	(10)		(6)		—		—		—		—		—		(2)
Amortization of actuarial loss	2		—		1		1		1		—		—		—
Amortization of prior service credit	(8)		(3)		(2)		(1)		(1)		—		—		(2)

Net periodic post-retirement benefit costs (a)(b)	$	4	$	(4)	$	6	$	4	$	3	$	1	$	1	$	(3)


	Year Ended December 31, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Service cost	$	4	$	1	$	1	$	—	$	—	$	—	$	1	$	—
Interest cost on accumulated post-retirement benefit obligation	18		4		7		4		3		1		1		1
Expected return on plan assets	(11)		(7)		—		—		—		—		—		(2)
Amortization of actuarial loss	2		—		1		—		1		—		4		—
Amortization of prior service credit	(13)		(4)		(2)		(1)		(1)		(1)		(1)		(2)

Net periodic post-retirement benefit costs(a)(b)	$	—	$	(6)	$	7	$	3	$	3	$	—	$	5	$	(3)


	Year Ended December 31, 2020
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Service cost	$	4	$	1	$	1	$	—	$	—	$	—	$	1	$	—
Interest cost on accumulated post-retirement benefit obligation	23		5		10		5		4		1		2		1
Expected return on plan assets	(13)		(8)		—		—		—		—		—		(2)
Amortization of actuarial loss	2		—		1		—		1		—		4		—
Amortization of prior service credit	(14)		(4)		(3)		(1)		(2)		(1)		(1)		(2)

Net periodic post-retirement benefit costs(a)(b)	$	2	$	(6)	$	9	$	4	$	3	$	—	$	6	$	(3)

(a) Duke Energy amounts exclude $4 million, $5 million and $6 million for the years ended December 2022, 2021 and 2020, respectively, of regulatory asset amortization resulting from purchase accounting adjustments associated with Duke Energy's merger with Cinergy in April 2006.

(b) Duke Energy Ohio amounts exclude $1 million, $1 million and $1 million for the years ended December 2022, 2021 and 2020, respectively, of regulatory asset amortization resulting from purchase accounting adjustments associated with Duke Energy's merger with Cinergy in April 2006.

Amounts Recognized in Accumulated Other Comprehensive Income and Regulatory Assets and Liabilities


	Year Ended December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Regulatory assets, net (decrease) increase	$	(79)	$	—	$	(80)	$	(45)	$	(36)	$	—	$	(3)	$	—
Regulatory liabilities, net increase (decrease)	$	27	$	—	$	—	$	—	$	—	$	—	$	19	$	(5)
Accumulated other comprehensive (income) loss


Amortization of prior year actuarial gain	$	1	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Net amount recognized in accumulated other comprehensive income	$	1	$	—	$	—	$	—	$	—	$	—	$	—	$	—


	Year Ended December 31, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Regulatory assets, net (decrease) increase	$	(15)	$	—	$	(18)	$	(9)	$	(9)	$	4	$	(4)	$	—
Regulatory liabilities, net increase	$	23	$	12	$	—	$	—	$	—	$	4	$	1	$	2
Accumulated other comprehensive (income) loss


Amortization of prior year actuarial gain	$	(1)	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Net amount recognized in accumulated other comprehensive income	$	(1)	$	—	$	—	$	—	$	—	$	—	$	—	$	—

Reconciliation of Funded Status to Accrued Other Post-Retirement Benefit Costs


	Year Ended December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Change in Projected Benefit Obligation
Accumulated post-retirement benefit obligation at prior measurement date	$	625	$	149	$	263	$	147	$	112	$	25	$	54	$	27

Service cost	3		1		—		—		—		—		—		—
Interest cost	17		4		7		4		3		1		1		1
Plan participants' contributions	11		2		4		2		2		1		1		—
Actuarial gains	(80)		(17)		(43)		(27)		(16)		(3)		(1)		(5)
Plan amendments	(71)		(11)		(37)		(18)		(19)		—		(17)		—

Benefits paid	(68)		(16)		(26)		(13)		(13)		(4)		(8)		(2)
Accumulated post-retirement benefit obligation at measurement date	$	437	$	112	$	168	$	95	$	69	$	20	$	30	$	21
Change in Fair Value of Plan Assets
Plan assets at prior measurement date	$	211	$	135	$	(1)	$	(2)	$	(2)	$	9	$	6	$	39

Actual return on plan assets	(31)		(19)		—		—		—		(2)		—		(7)
Benefits paid	(68)		(16)		(26)		(13)		(13)		(4)		(8)		(2)

Employer contributions	39		3		23		11		11		3		4		1
Plan participants' contributions	11		2		4		2		2		1		1		—
Plan assets at measurement date	$	162	$	105	$	—	$	(2)	$	(2)	$	7	$	3	$	31
Funded status of plan	$	(275)	$	(7)	$	(168)	$	(97)	$	(71)	$	(13)	$	(27)	$	10


	Year Ended December 31, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Change in Projected Benefit Obligation
Accumulated post-retirement benefit obligation at prior measurement date	$	709	$	174	$	299	$	166	$	130	$	27	$	61	$	30

Service cost	4		1		1		—		—		—		1		—
Interest cost	18		4		7		4		3		1		1		1
Plan participants' contributions	14		3		5		3		2		1		2		—
Actuarial gains	(47)		(14)		(20)		(10)		(10)		(1)		(2)		(2)

Benefits paid	(73)		(19)		(29)		(16)		(13)		(3)		(9)		(2)
Accumulated post-retirement benefit obligation at measurement date	$	625	$	149	$	263	$	147	$	112	$	25	$	54	$	27
Change in Fair Value of Plan Assets
Plan assets at prior measurement date	$	237	$	139	$	(1)	$	(2)	$	(1)	$	9	$	7	$	37

Actual return on plan assets	15		9		—		—		—		1		—		3
Benefits paid	(73)		(19)		(29)		(16)		(13)		(3)		(9)		(2)

Employer contributions	18		3		24		13		10		1		6		1
Plan participants' contributions	14		3		5		3		2		1		2		—
Plan assets at measurement date	$	211	$	135	$	(1)	$	(2)	$	(2)	$	9	$	6	$	39
Funded status of plan	$	(414)	$	(14)	$	(264)	$	(149)	$	(114)	$	(16)	$	(48)	$	12

Amounts Recognized in the Consolidated Balance Sheets


	December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Prefunded post-retirement benefit	$	—	$	—	$	—	$	—	$	—	$	1	$	—	$	10
Current post-retirement liability(a)	9		—		5		3		2		2		—		—
Noncurrent post-retirement liability(b)	266		7		163		94		69		12		27		—
Net liability (asset) recognized	$	275	$	7	$	168	$	97	$	71	$	13	$	27	$	(10)
Regulatory assets	$	50	$	—	$	46	$	34	$	11	$	4	$	25	$	—
Regulatory liabilities	$	189	$	44	$	—	$	—	$	—	$	21	$	82	$	—
Accumulated other comprehensive (income) loss
Deferred income tax expense	$	3	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Prior service credit	(1)		—		—		—		—		—		—		—
Net actuarial gain	(13)		—		—		—		—		—		—		—
Net amounts recognized in accumulated other comprehensive income	$	(11)	$	—	$	—	$	—	$	—	$	—	$	—	$	—


	December 31, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Prefunded post-retirement benefit	$	12	$	—	$	—	$	—	$	—	$	1	$	—	$	12
Current post-retirement liability(a)	9		—		5		3		2		1		—		—
Noncurrent post-retirement liability(b)	417		14		259		146		112		16		48		—
Net liability (asset) recognized	$	414	$	14	$	264	$	149	$	114	$	16	$	48	$	(12)
Regulatory assets	$	129	$	—	$	126	$	79	$	47	$	4	$	28	$	—
Regulatory liabilities	$	162	$	44	$	—	$	—	$	—	$	21	$	63	$	5
Accumulated other comprehensive (income) loss
Deferred income tax expense	$	3	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Prior service credit	(1)		—		—		—		—		—		—		—
Net actuarial gain	(14)		—		—		—		—		—		—		—
Net amounts recognized in accumulated other comprehensive income	$	(12)	$	—	$	—	$	—	$	—	$	—	$	—	$	—

(a) Included in Other within Current Liabilities on the Consolidated Balance Sheets.

(b) Included in Accrued pension and other post-retirement benefit costs on the Consolidated Balance Sheets.

Assumptions Used for Other Post-Retirement Benefits Accounting

The discount rate used to determine the current year other post-retirement benefits obligation and following year’s other post-retirement benefits expense is based on a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high-quality corporate bonds that generate sufficient cash flow to provide for projected benefit payments of the plan. The selected bond portfolio is derived from a universe of non-callable corporate bonds rated Aa quality or higher. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan’s projected benefit payments discounted at this rate with the market value of the bonds selected.

The average remaining service period of active covered employees is seven years for Duke Energy and Duke Energy Florida, six years for Duke Energy Carolinas, Duke Energy Ohio, Duke Energy Indiana and Piedmont and five years for Progress Energy and Duke Energy Progress.

The following tables present the assumptions used for other post-retirement benefits accounting.


	December 31,
	2022		2021		2020
Benefit Obligations
Discount rate	5.60	%	2.90	%	2.60	%
Net Periodic Benefit Cost
Discount rate	2.90	%	2.60	%	3.30	%
Expected long-term rate of return on plan assets	6.50	%	6.50	%	6.85	%

Assumed Health Care Cost Trend Rate


	December 31,
	2022		2021
Health care cost trend rate assumed for next year	6.50	%	6.25	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.75	%	4.75	%
Year that rate reaches ultimate trend	2030-2032		2028

Expected Benefit Payments


			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Years ending December 31,
2023	$	68	$	16	$	25	$	14	$	11	$	3	$	7	$	2
2024	49		13		18		10		7		3		4		2
2025	45		12		16		9		7		2		3		2
2026	41		11		15		9		6		2		3		2
2027	38		10		14		8		6		2		3		2
2028-2032	158		41		61		36		25		8		9		9

PLAN ASSETS

Description and Allocations

Duke Energy Corporation Master Retirement Trust

Assets for both the qualified pension and other post-retirement benefits are maintained in the Duke Energy Corporation Master Retirement Trust. Approximately 98% of the Duke Energy Corporation Master Retirement Trust assets were allocated to qualified pension plans and approximately 2% were allocated to other post-retirement plans (comprised of 401(h) accounts), as of December 31, 2022, and 2021. The investment objective of the Duke Energy Corporation Master Retirement Trust is to invest in a diverse portfolio of assets that is expected to generate positive surplus return over time (i.e., asset growth greater than liability growth) subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants.

As of December 31, 2022, Duke Energy assumes qualified pension and other post-retirement plan assets will generate a long-term rate of return of 8.25% for the RCBP pension and RCBP 401(h) account assets and 6.5% for the DELPP pension and DELPP 401(h) account assets. The expected long-term rate of return was developed using a weighted average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers, where applicable. The asset allocation targets were set after considering the investment objective and the risk profile. Equity securities are held for their higher expected returns. Debt securities are primarily held to hedge the qualified pension plan. Return seeking debt securities, hedge funds and other global securities are held for diversification. Investments within asset classes are diversified to achieve broad market participation and reduce the impact of individual managers or investments.

Effective January 1, 2023, the target asset allocation for the RCBP assets is 35% liability hedging and 65% return-seeking assets and the target asset allocation for the DELPP assets is 80% liability hedging assets and 20% return-seeking assets. Duke Energy periodically reviews its asset allocation targets, and over time, as the funded status of the benefit plans increase, the level of asset risk relative to plan liabilities may be reduced to better manage Duke Energy's benefit plan liabilities and reduce funded status volatility.

The Duke Energy Corporation Master Retirement Trust is authorized to engage in the lending of certain plan assets. Securities lending is an investment management enhancement that utilizes certain existing securities of the Duke Energy Corporation Master Retirement Trust to earn additional income. Securities lending involves the loaning of securities to approved parties. In return for the loaned securities, the Duke Energy Corporation Master Retirement Trust receives collateral in the form of cash and securities as a safeguard against possible default of any borrower on the return of the loan under terms that permit the Duke Energy Corporation Master Retirement Trust to sell the securities. The Duke Energy Corporation Master Retirement Trust mitigates credit risk associated with securities lending arrangements by monitoring the fair value of the securities loaned, with additional collateral obtained or refunded as necessary. The fair value of securities on loan was approximately $390 million and $542 million at December 31, 2022, and 2021, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned at December 31, 2022, and 2021, respectively. Securities lending income earned by the Duke Energy Corporation Master Retirement Trust was immaterial for the years ended December 31, 2022, 2021 and 2020, respectively.

Qualified pension and other post-retirement benefits for the Subsidiary Registrants are derived from the Duke Energy Corporation Master Retirement Trust, as such, each are allocated their proportionate share of the assets discussed below.

The following table includes the target asset allocations by asset class at December 31, 2022, and the actual asset allocations for the RCBP assets.


			Actual Allocation at
	Target		December 31,

	Allocation		2022		2021


Global equity securities	45	%	49	%	24	%
Global private equity securities	2	%	2	%	1	%
Debt securities	35	%	30	%	62	%
Return seeking debt securities	7	%	7	%	4	%
Hedge funds	4	%	6	%	3	%
Real estate and cash	7	%	6	%	6	%

Total	100	%	100	%	100	%

The following table includes the target asset allocations by asset class at December 31, 2022, and the actual asset allocations for the DELPP assets.


			Actual Allocation at
	Target		December 31,

	Allocation		2022		2021


Global equity securities	14	%	14	%	24	%
Global private equity securities	1	%	—	%	1	%
Debt securities	80	%	80	%	62	%
Return seeking debt securities	2	%	2	%	4	%
Hedge funds	1	%	2	%	3	%
Real estate and cash	2	%	2	%	6	%

Total	100	%	100	%	100	%

Other post-retirement assets

Duke Energy's other post-retirement assets are comprised of Voluntary Employees' Beneficiary Association (VEBA) trusts and 401(h) accounts held within the Duke Energy Corporation Master Retirement Trust. Duke Energy's investment objective is to achieve sufficient returns, subject to a prudent level of portfolio risk, for the purpose of promoting the security of plan benefits for participants.

The following table presents target and actual asset allocations for the VEBA trusts at December 31, 2022.


			Actual Allocation at
	Target		December 31,
	Allocation		2022		2021
U.S. equity securities	30	%	12	%	19	%
Non-U.S. equity securities	5	%	5	%	5	%
Real estate	1	%	3	%	3	%
Debt securities	45	%	11	%	18	%
Cash	19	%	69	%	55	%
Total	100	%	100	%	100	%

Fair Value Measurements

Duke Energy classifies recurring and non-recurring fair value measurements based on the fair value hierarchy as discussed in Note 17.

Valuation methods of the primary fair value measurements disclosed below are as follows:

Investments in equity securities

Investments in equity securities are typically valued at the closing price in the principal active market as of the last business day of the reporting period. Principal active markets for equity prices include published exchanges such as NASDAQ and NYSE. Foreign equity prices are translated from their trading currency using the currency exchange rate in effect at the close of the principal active market. Prices have not been adjusted to reflect after-hours market activity. The majority of investments in equity securities are valued using Level 1 measurements. When the price of an institutional commingled fund is unpublished, it is not categorized in the fair value hierarchy, even though the funds are readily available at the fair value.

Investments in corporate debt securities and U.S. government securities

Most debt investments are valued based on a calculation using interest rate curves and credit spreads applied to the terms of the debt instrument (maturity and coupon interest rate) and consider the counterparty credit rating. Most debt valuations are Level 2 measurements. If the market for a particular fixed-income security is relatively inactive or illiquid, the measurement is Level 3. U.S. Treasury debt is typically Level 2.

Investments in short-term investment funds

Investments in short-term investment funds are valued at the net asset value of units held at year end and are readily redeemable at the measurement date. Investments in short-term investment funds with published prices are valued as Level 1. Investments in short-term investment funds with unpublished prices are valued as Level 2.

Duke Energy Corporation Master Retirement Trust

The following tables provide the fair value measurement amounts for the Duke Energy Corporation Master Retirement Trust qualified pension and other post-retirement assets.


	December 31, 2022
	Total Fair								Not
(in millions)	Value		Level 1		Level 2		Level 3		Categorized(b)
Equity securities	$	2,234	$	2,014	$	194	$	—	$	26
Corporate debt securities	2,944		—		2,944		—		—
Short-term investment funds	193		1		192		—		—
Partnership interests	62		—		—		62		—
Hedge funds	209		—		—		—		209

U.S. government securities	1,254		—		1,254		—		—

Governments bonds – foreign	112		—		112		—		—
Cash	45		45		—		—		—
Government and commercial mortgage backed securities	6		—		6		—		—
Net pending transactions and other investments	14		5		9		—		—
Total assets(a)	$	7,073	$	2,065	$	4,711	$	62	$	235

(a) Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio, Duke Energy Indiana and Piedmont were allocated approximately 27%, 33%, 15%, 18%, 5%, 7% and 3%, respectively, of the Duke Energy Corporation Master Retirement Trust at December 31, 2022. Accordingly, all amounts included in the table above are allocable to the Subsidiary Registrants using these percentages.

(b) Certain investments that are measured at fair value using the net asset value per share practical expedient have not been categorized in the fair value hierarchy.


	December 31, 2021
	Total Fair								Not
(in millions)	Value		Level 1		Level 2		Level 3		Categorized(b)
Equity securities	$	2,575	$	2,547	$	—	$	—	$	28
Corporate debt securities	4,189		—		4,189		—		—
Short-term investment funds	382		272		110		—		—
Partnership interests	95		—		—		95		—
Hedge funds	216		—		—		—		216

U.S. government securities	1,618		—		1,618		—		—

Governments bonds – foreign	78		—		78		—		—
Cash	144		144		—		—		—
Government and commercial mortgage backed securities	2		—		2		—		—
Net pending transactions and other investments	53		12		41		—		—
Total assets(a)	$	9,352	$	2,975	$	6,038	$	95	$	244

(a) Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio, Duke Energy Indiana and Piedmont were allocated approximately 26%, 32%, 15%, 17%, 5%, 7% and 4%, respectively, of the Duke Energy Corporation Master Retirement Trust at December 31, 2021. Accordingly, all amounts included in the table above are allocable to the Subsidiary Registrants using these percentages.

(b) Certain investments that are measured at fair value using the net asset value per share practical expedient have not been categorized in the fair value hierarchy.

The following table provides a reconciliation of beginning and ending balances of Duke Energy Corporation Master Retirement Trust qualified pension and other post-retirement assets at fair value on a recurring basis where the determination of fair value includes significant unobservable inputs (Level 3).


(in millions)	2022		2021
Balance at January 1	$	95	$	—



Sales	(18)		—
Total gains and other, net	(8)		—
Transfer of Level 3 assets from other classifications	(7)		95
Balance at December 31	$	62	$	95

Other post-retirement assets

The following tables provide the fair value measurement amounts for VEBA trust assets.


	December 31, 2022
	Total Fair
(in millions)	Value		Level 2
Cash and cash equivalents	$	11	$	11
Real estate	2		2
Equity securities	12		12
Debt securities	8		8
Total assets	$	33	$	33


	December 31, 2021
	Total Fair
(in millions)	Value		Level 2
Cash and cash equivalents	$	14	$	14
Real estate	2		2
Equity securities	18		18
Debt securities	11		11
Total assets	$	45	$	45

EMPLOYEE SAVINGS PLANS

Retirement Savings Plan

Duke Energy Corporation sponsors, and the Subsidiary Registrants participate in, employee savings plans that cover substantially all U.S. employees. Most employees participate in a matching contribution formula where Duke Energy provides a matching contribution generally equal to 100% of employee before-tax and Roth 401(k) contributions of up to 6% of eligible pay per pay period. Dividends on Duke Energy shares held by the savings plans are charged to retained earnings when declared and shares held in the plans are considered outstanding in the calculation of basic and diluted EPS.

For new and rehired employees who are not eligible to participate in Duke Energy’s defined benefit plans, an additional employer contribution of 4% of eligible pay per pay period, which is subject to a three-year vesting schedule, is provided to the employee’s savings plan account. Certain Piedmont employees whose participation in a prior Piedmont defined benefit plan (that was frozen as of December 31, 2017) are eligible for employer transition credit contributions of 3% to 5% of eligible pay per period, for each pay period during the three-year period ending December 31, 2020.

The following table includes pretax employer matching contributions made by Duke Energy and expensed by the Subsidiary Registrants.


			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Years ended December 31,
2022	$	246	$	76	$	65	$	43	$	22	$	6	$	12	$	13
2021	229		70		60		39		21		5		12		11
2020	213		67		57		38		19		5		11		13

24. INCOME TAXES

Inflation Reduction Act

On August 16, 2022, the IRA was signed into law. Among other provisions, the IRA implemented a new 15% corporate alternative minimum tax based on GAAP net income, with certain adjustments as defined by the IRA, and clean energy-related provisions. The IRA's clean energy provisions include, among other provisions, the extension and modification of existing investment and PTCs for projects placed in service through 2024 and introduces new technology-neutral clean energy related credits beginning in 2025. In addition, the IRA created a new, zero-emission nuclear power PTC and a clean hydrogen PTC.

Duke Energy has preliminarily reviewed the provisions of the IRA and has determined there were no material impacts on the results of operations, financial position, or cash flows in the periods presented for the Duke Energy Registrants as a result of the IRA being signed into law. Based on the preliminary review of the IRA provisions, future annual cash flow impacts related to the energy credits could be material to the Duke Energy Registrants. However, the majority of Duke Energy's operations are regulated and the FERC and state utility commissions will determine the regulatory treatment. We anticipate the Subsidiary Registrants will defer and expect to pass along the net financial impact associated with the IRA to customers over time. See Note 4 for further details on the IRA as it relates to Duke Energy Florida. Duke Energy will continue to assess the IRA as new information and anticipated guidance from the U.S. Department of the Treasury becomes available.

North Carolina's 2021 Appropriations Act

On November 18, 2021, North Carolina Senate Bill 105 (SB 105) was signed into law. Starting with tax year 2025, SB 105 begins phasing out the North Carolina corporate income tax rate over five years, from a statutory rate of 2.5% to zero. Duke Energy recorded a net reduction of approximately $490 million to its North Carolina deferred tax liability in the fourth quarter of 2021. The majority of this deferred tax liability reduction was offset by recording a regulatory liability pending NCUC determination of the disposition of the amounts related to Duke Energy Carolinas, Duke Energy Progress and Piedmont. In addition, Duke Energy recorded a net reduction of North Carolina consolidating deferred tax assets of approximately $25 million to deferred state income tax expense in the fourth quarter of 2021. North Carolina SB 105 did not have a significant impact on the financial position, results of operation, or cash flows of Duke Energy, Duke Energy Carolinas, Progress Energy, Duke Energy Progress or Piedmont.

Consolidated Appropriations Act

On December 27, 2020, the Consolidated Appropriations Act (CAA) was signed into law. In addition to the CAA providing funding for government operations, it also provided tax provisions to assist with COVID-19 relief, including extending certain expiring tax provisions. The company has reviewed the provisions of the CAA and has determined that there are no material impacts on the financial statements as a result of the CAA being signed into law.

CARES Act

On March 27, 2020, the CARES Act was enacted. The CARES Act was an emergency economic stimulus package in response to the COVID-19 pandemic. Among other provisions, the CARES Act accelerated the remaining AMT credit refund allowances resulting in taxpayers being able to immediately claim a refund in full for any AMT credit carryforwards and provided for the deferral of certain 2020 payroll taxes. In the third quarter of 2020, Duke Energy received $572 million related to these AMT credit carryforwards and $19 million of interest income. In addition, the company deferred approximately $117 million of payroll taxes, of which, 50% were paid by December 31, 2021, with the remaining 50% payable by December 31, 2022. The other provisions within the CARES Act did not materially impact Duke Energy's income tax accounting.

Income Tax Expense

Components of Income Tax Expense

Tax benefit from discontinued operations, in the following tables, includes income tax benefits related to the Commercial Renewables Disposal Groups. See Note 2 for further details.


	Year Ended December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Current income taxes
Federal	$	1	$	(71)	$	(13)	$	37	$	(37)	$	(2)	$	38	$	32
State	(8)		(13)		(3)		—		(23)		1		2		2
Foreign	4		—		—		—		—		—		—		—
Total current income taxes	(3)		(84)		(16)		37		(60)		(1)		40		34
Deferred income taxes
Federal	328		230		310		118		201		(22)		(63)		12
State	(14)		(16)		59		7		84		3		—		(7)

Total deferred income taxes(a)	314		214		369		125		285		(19)		(63)		5
ITC amortization	(11)		(4)		(5)		(4)		—		(1)		(1)		—
Income tax expense from continuing operations	300		126		348		158		225		(21)		(24)		39
Tax benefit from discontinued operations	(503)		—		—		—		—		—		—		—
Total income tax (benefit) expense included in Consolidated Statements of Operations	$	(203)	$	126	$	348	$	158	$	225	$	(21)	$	(24)	$	39

(a) Total deferred income taxes includes the generation of NOL carryforwards and tax credit carryforwards of $550 million at Duke Energy, $97 million at Duke Energy Carolinas, $128 million at Progress Energy, $9 million at Duke Energy Progress, $111 million at Duke Energy Florida, $7 million at Duke Energy Ohio, $13 million at Duke Energy Indiana, and $12 million at Piedmont.


	Year Ended December 31, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Current income taxes
Federal	$	(2)	$	241	$	(15)	$	113	$	(75)	$	(8)	$	65	$	23
State	1		23		(4)		8		(17)		(2)		7		3
Foreign	2		—		—		—		—		—		—		—
Total current income taxes	1		264		(19)		121		(92)		(10)		72		26
Deferred income taxes
Federal	275		(130)		203		(16)		202		35		19		17
State	—		(79)		47		(26)		77		5		16		(13)

Total deferred income taxes(a)	275		(209)		250		(42)		279		40		35		4
ITC amortization	(8)		(4)		(4)		(4)		—		—		—		—
Income tax expense from continuing operations	268		51		227		75		187		30		107		30
Tax benefit from discontinued operations	(76)		—		—		—		—		—		—		—
Total income tax expense included in Consolidated Statements of Operations	$	192	$	51	$	227	$	75	$	187	$	30	$	107	$	30

(a) Total deferred income taxes includes the generation of NOL carryforwards and tax credit carryforwards of $32 million at Duke Energy Carolinas, $8 million at Duke Energy Indiana, and $3 million at Piedmont. In addition, total deferred income taxes includes utilization of NOL carryforwards and tax credit carryforwards of $250 million at Duke Energy, $95 million at Progress Energy, $14 million at Duke Energy Progress, $64 million at Duke Energy Florida, and $2 million at Duke Energy Ohio.


	Year Ended December 31, 2020
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Current income taxes
Federal	$	(281)	$	314	$	280	$	181	$	148	$	10	$	48	$	(27)
State	(3)		35		29		17		24		1		7		(8)
Foreign	1		—		—		—		—		—		—		—
Total current income taxes	(283)		349		309		198		172		11		55		(35)
Deferred income taxes
Federal	222		(171)		(167)		(180)		1		30		12		60
State	(98)		(86)		(24)		(49)		25		2		17		(7)

Total deferred income taxes(a)	124		(257)		(191)		(229)		26		32		29		53
ITC amortization	(10)		(4)		(5)		(5)		—		—		—		—
Income tax (benefit) expense from continuing operations	(169)		88		113		(36)		198		43		84		18
Tax benefit from discontinued operations	(65)		—		—		—		—		—		—		—
Total income tax (benefit) expense included in Consolidated Statements of Operations	$	(234)	$	88	$	113	$	(36)	$	198	$	43	$	84	$	18

(a) Total deferred income taxes includes the generation of NOL carryforwards and tax credit carryforwards of $20 million at Duke Energy Carolinas, $3 million at Duke Energy Progress, $8 million at Duke Energy Indiana, and $11 million at Piedmont. In addition, total deferred income taxes includes utilization of NOL carryforwards and tax credit carryforwards of $39 million at Progress Energy, $30 million at Duke Energy Florida and $189 million at Duke Energy.

Duke Energy Income from Continuing Operations before Income Taxes


	Years Ended December 31,
(in millions)	2022		2021		2020
Domestic	$	3,991	$	3,947	$	907
Foreign	87		44		13
Income from continuing operations before income taxes	$	4,078	$	3,991	$	920

Statutory Rate Reconciliation

The following tables present a reconciliation of income tax expense at the U.S. federal statutory tax rate to the actual tax expense from continuing operations.


	Year Ended December 31, 2022
				Duke						Duke			Duke			Duke			Duke
	Duke			Energy			Progress			Energy			Energy			Energy			Energy
(in millions)	Energy			Carolinas			Energy			Progress			Florida			Ohio			Indiana			Piedmont
Income tax expense, computed at the statutory rate of 21%	$	856		$	362		$	457		$	245		$	238		$	59		$	24		$	76
State income tax, net of federal income tax effect	(17)			(23)			44			6			48			3			2			(4)
Amortization of excess deferred income tax	(481)			(195)			(133)			(74)			(59)			(79)			(48)			(23)
AFUDC equity income	(41)			(20)			(14)			(11)			(3)			(1)			(2)			(2)
AFUDC equity depreciation	36			18			12			6			6			1			4			—


Other tax credits	(43)			(12)			(16)			(9)			(7)			(2)			(3)			(8)

Other items, net	(10)			(4)			(2)			(5)			2			(2)			(1)			—
Income tax expense from continuing operations	$	300		$	126		$	348		$	158		$	225		$	(21)		$	(24)		$	39
Effective tax rate	7.4		%	7.3		%	16.0		%	13.6		%	19.8		%	(7.5)		%	(21.2)		%	10.8		%


	Year Ended December 31, 2021
				Duke						Duke			Duke			Duke			Duke
	Duke			Energy			Progress			Energy			Energy			Energy			Energy
(in millions)	Energy			Carolinas			Energy			Progress			Florida			Ohio			Indiana			Piedmont
Income tax expense, computed at the statutory rate of 21%	$	838		$	291		$	384		$	224		$	194		$	49		$	123		$	71
State income tax, net of federal income tax effect	1			(44)			34			(14)			47			2			18			(8)
Amortization of excess deferred income tax	(438)			(184)			(174)			(120)			(54)			(22)			(34)			(25)
AFUDC equity income	(34)			(14)			(11)			(7)			(3)			(2)			(4)			(4)
AFUDC equity depreciation	35			18			10			5			5			2			5			—


Other tax credits	(30)			(12)			(11)			(8)			(3)			(1)			(2)			(4)
Valuation allowance(a)	(85)			—			—			—			—			—			—			—


Other items, net	(19)			(4)			(5)			(5)			1			2			1			—
Income tax expense from continuing operations	$	268		$	51		$	227		$	75		$	187		$	30		$	107		$	30
Effective tax rate	6.7		%	3.7		%	12.4		%	7.0		%	20.2		%	12.8		%	18.2		%	8.8		%

(a) In the fourth quarter of 2021, the company recognized a federal capital gain in the amount of $426 million. As a result, a valuation allowance of $85 million related to a federal capital loss carryforward was released. This valuation allowance was originally recorded as a result of the 2019 sale of minority interest of certain renewable assets within the Commercial Renewables Disposal Groups.


	Year Ended December 31, 2020
				Duke						Duke			Duke			Duke			Duke
	Duke			Energy			Progress			Energy			Energy			Energy			Energy
(in millions)	Energy			Carolinas			Energy			Progress			Florida			Ohio			Indiana			Piedmont
Income tax expense, computed at the statutory rate of 21%	$	193		$	219		$	243		$	80		$	204		$	62		$	103		$	61
State income tax, net of federal income tax effect	(80)			(40)			4			(25)			39			2			19			(12)
Amortization of excess deferred income tax	(276)			(82)			(118)			(68)			(49)			(20)			(36)			(21)
AFUDC equity income	(48)			(13)			(9)			(6)			(3)			(2)			(4)			(10)
AFUDC equity depreciation	103			19			10			5			5			1			4			—


Other tax credits	(37)			(13)			(16)			(14)			(2)			(1)			(3)			(2)
Tax true up	(12)			(3)			1			(5)			5			—			(1)			1
Other items, net	(12)			1			(2)			(3)			(1)			1			2			1
Income tax (benefit) expense from continuing operations	$	(169)		$	88		$	113		$	(36)		$	198		$	43		$	84		$	18
Effective tax rate	(18.4)		%	8.4		%	9.7		%	(9.5)		%	20.4		%	14.6		%	17.1		%	6.2		%

Valuation allowances have been established for certain state NOL carryforwards and state income tax credits that reduce deferred tax assets to an amount that will be realized on a more-likely-than-not basis. The net change in the total valuation allowance is included in state income tax, net of federal income tax effect, in the above tables.

DEFERRED TAXES

Net Deferred Income Tax Liability Components

The following tables include deferred income tax assets and liabilities related to the Commercial Renewables Disposal Groups. See Note 2 for further details.


	December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Deferred credits and other liabilities	$	348	$	170	$	117	$	33	$	83	$	12	$	23	$	24
Lease obligations	405		89		263		197		65		4		15		3
Pension, post-retirement and other employee benefits	192		(1)		12		18		(10)		9		10		(2)
Progress Energy merger purchase accounting adjustments(a)	301		—		—		—		—		—		—		—
Tax credits and NOL carryforwards	4,426		444		618		167		412		20		208		37
Regulatory liabilities and deferred credits	—		—		—		—		—		3		61		—
Investments and other assets	—		—		—		—		—		3		—		—
Other	106		18		22		12		10		5		2		9
Valuation allowance	(519)		—		—		—		—		—		—		—
Total deferred income tax assets	5,259		720		1,032		427		560		56		319		71
Investments and other assets	(1,671)		(983)		(521)		(432)		(102)		—		(12)		(28)
Accelerated depreciation rates	(11,478)		(3,410)		(4,358)		(1,844)		(2,576)		(1,192)		(1,606)		(892)
Regulatory assets and deferred debits, net	(2,074)		(480)		(1,300)		(628)		(671)		—		—		(21)

Total deferred income tax liabilities	(15,223)		(4,873)		(6,179)		(2,904)		(3,349)		(1,192)		(1,618)		(941)
Net deferred income tax liabilities	$	(9,964)	$	(4,153)	$	(5,147)	$	(2,477)	$	(2,789)	$	(1,136)	$	(1,299)	$	(870)

(a) Primarily related to lease obligations and debt fair value adjustments.

The following table presents the expiration of tax credits and NOL carryforwards.


	December 31, 2022
(in millions)	Amount		Expiration Year
General Business Credits	$	2,473	2027	—	2042
Federal NOL carryforwards(a) (e)	306		2024	—	Indefinite
Charitable contribution carryforwards	18		2024	—	2027
State carryforwards and credits(b) (e)	394		2023	—	Indefinite
Foreign NOL carryforwards(c)	12		2027	—	2037
Foreign Tax Credits(d)	1,223		2024	—	2028
Total tax credits and NOL carryforwards	$	4,426

(a) A valuation allowance of $4 million has been recorded on the Federal NOL carryforwards, as presented in the Net Deferred Income Tax Liability Components table.

(b) A valuation allowance of $109 million has been recorded on the state NOL and attribute carryforwards, as presented in the Net Deferred Income Tax Liability Components table.

(c) A valuation allowance of $12 million has been recorded on the foreign NOL carryforwards, as presented in the Net Deferred Income Tax Liability Components table.

(d) A valuation allowance of $391 million has been recorded on the foreign tax credits, as presented in the Net Deferred Income Tax Liability Components table.

(e) Indefinite carryforward for Federal NOLs, and NOLs for states that have adopted the Tax Act's NOL provisions, generated in tax years beginning after December 31, 2017.


	December 31, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Deferred credits and other liabilities	$	347	$	121	$	101	$	60	$	40	$	19	$	7	$	18
Lease obligations	346		91		197		121		76		4		16		4
Pension, post-retirement and other employee benefits	207		(36)		30		17		7		11		20		(8)
Progress Energy merger purchase accounting adjustments(a)	340		—		—		—		—		—		—		—
Tax credits and NOL carryforwards	3,784		349		497		160		306		13		195		29
Regulatory liabilities and deferred credits	—		11		—		—		—		16		—		6
Investments and other assets	—		—		—		—		—		5		6		—
Other	85		12		12		7		4		7		2		8
Valuation allowance	(518)		—		—		—		—		—		—		—
Total deferred income tax assets	4,591		548		837		365		433		75		246		57
Investments and other assets	(2,428)		(1,205)		(742)		(610)		(135)		—		—		(39)
Accelerated depreciation rates	(10,391)		(2,977)		(3,891)		(1,546)		(2,382)		(1,125)		(1,496)		(833)
Regulatory assets and deferred debits, net	(1,151)		—		(768)		(417)		(350)		—		(53)		—

Total deferred income tax liabilities	(13,970)		(4,182)		(5,401)		(2,573)		(2,867)		(1,125)		(1,549)		(872)
Net deferred income tax liabilities	$	(9,379)	$	(3,634)	$	(4,564)	$	(2,208)	$	(2,434)	$	(1,050)	$	(1,303)	$	(815)

(a) Primarily related to lease obligations and debt fair value adjustments.

UNRECOGNIZED TAX BENEFITS

The following tables present changes to unrecognized tax benefits.


	Year Ended December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Unrecognized tax benefits – January 1	$	51	$	13	$	15	$	10	$	4	$	1	$	2	$	4



Gross decreases – tax positions in prior periods	—		—		—		—		—		—		—		—
Gross increases – current period tax positions	14		4		4		3		1		—		—		5



Total changes	14		4		4		3		1		—		—		5
Unrecognized tax benefits – December 31	$	65	$	17	$	19	$	13	$	5	$	1	$	2	$	9


	Year Ended December 31, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Unrecognized tax benefits – January 1	$	125	$	10	$	10	$	6	$	3	$	1	$	1	$	1


Gross decreases – tax positions in prior periods(a)	(86)		—		—		—		—		—		—		—

Gross increases – current period tax positions	12		3		5		4		1		—		1		3



Total changes	(74)		3		5		4		1		—		1		3
Unrecognized tax benefits – December 31	$	51	$	13	$	15	$	10	$	4	$	1	$	2	$	4

(a) In the fourth quarter of 2021, the company recognized a federal capital gain in the amount of $426 million. As a result of the capital gain, a previously recorded unrecognized tax benefit related to the character of a taxable loss has been reversed. See note (a) under the Statutory Rate Reconciliation table for more details.


	Year Ended December 31, 2020
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Unrecognized tax benefits – January 1	$	126	$	8	$	9	$	6	$	3	$	1	$	1	$	4


Gross decreases – tax positions in prior periods	(2)		—		—		—		—		—		—		—

Gross increases – current period tax positions	4		2		1		—		—		—		—		—


Reduction due to lapse of statute of limitations	(3)		—		—		—		—		—		—		(3)
Total changes	(1)		2		1		—		—		—		—		(3)
Unrecognized tax benefits – December 31	$	125	$	10	$	10	$	6	$	3	$	1	$	1	$	1

The following table includes additional information regarding the Duke Energy Registrants' unrecognized tax benefits at December 31, 2022. None of Duke Energy Registrants anticipates a material increase or decrease in unrecognized tax benefits within the next 12 months.


	December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Amount that if recognized, would affect the effective tax rate or regulatory liability(a)	$	59	$	17	$	18	$	13	$	5	$	1	$	2	$	8

(a) The Duke Energy Registrants are unable to estimate the specific amounts that would affect the ETR versus the regulatory liability.

Duke Energy and its subsidiaries are no longer subject to federal, state, local or non-U.S. income tax examinations by tax authorities for years before 2016, aside from certain state tax attributes carried forward for utilization in future years.

25. OTHER INCOME AND EXPENSES, NET

The components of Other income and expenses, net on the Consolidated Statements of Operations are as follows.


	Year Ended December 31, 2022
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Interest income	$	27	$	2	$	24	$	4	$	20	$	11	$	15	$	19
AFUDC equity	197		98		68		52		16		7		13		11
Post in-service equity returns	34		14		18		18		—		1		1		—
Nonoperating income, other	134		107		71		40		38		—		7		16
Other income and expense, net	$	392	$	221	$	181	$	114	$	74	$	19	$	36	$	46


	Year Ended December 31, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Interest income	$	13	$	4	$	8	$	6	$	2	$	4	$	6	$	19
AFUDC equity	171		65		51		34		16		7		27		20
Post in-service equity returns	39		21		16		16		—		1		1		—
Nonoperating income, other	413		180		140		87		53		6		8		16
Other income and expense, net	$	636	$	270	$	215	$	143	$	71	$	18	$	42	$	55


	Year Ended December 31, 2020
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Interest income	$	30	$	4	$	8	$	2	$	6	$	4	$	6	$	17
AFUDC equity	154		62		42		29		12		7		23		19
Post in-service equity returns	27		17		8		8		—		1		1		—
Nonoperating income, other	240		94		71		36		35		4		7		15
Other income and expense, net	$	451	$	177	$	129	$	75	$	53	$	16	$	37	$	51

26. SUBSEQUENT EVENTS

For information on subsequent events related to dispositions, regulatory matters, commitments and contingencies, and debt and credit facilities see Notes 2, 4, 5 and 7, respectively.

27. QUARTERLY FINANCIAL DATA (UNAUDITED)

DUKE ENERGY

Quarterly EPS amounts may not sum to the full-year total due to changes in the weighted average number of common shares outstanding and rounding.


	First		Second		Third		Fourth
(in millions, except per share data)	Quarter		Quarter		Quarter		Quarter		Total
2022
Operating revenues	$	7,011	$	6,564	$	7,842	$	7,351	$	28,768
Operating income	1,314		1,448		2,056		1,194		6,012
Income from continuing operations	835		898		1,410		635		3,778
(Loss) Income from discontinued operations, net of tax	(15)		(18)		3		(1,293)		(1,323)
Net income (loss)	820		880		1,413		(658)		2,455
Net income (loss) available to Duke Energy Corporation common stockholders	818		893		1,383		(650)		2,444
Earnings per share:
Income from continuing operations available to Duke Energy Corporation common stockholders
Basic and diluted	$	1.06	$	1.11	$	1.78	$	0.80	$	4.74

Income (Loss) from discontinued operations attributable to Duke Energy Corporation common stockholders
Basic and diluted	$	0.02	$	0.03	$	0.03	$	(1.66)	$	(1.57)

Net income (loss) available to Duke Energy Corporation common stockholders
Basic and diluted	$	1.08	$	1.14	$	1.81	$	(0.86)	$	3.17

2021
Operating revenues	$	6,032	$	5,638	$	6,834	$	6,117	$	24,621
Operating income	1,466		1,198		1,726		1,110		5,500
Income from continuing operations	967		723		1,333		700		3,723
Loss from discontinued operations, net of tax	(26)		(25)		(57)		(36)		(144)
Net income	941		698		1,276		664		3,579
Net income available to Duke Energy Corporation common stockholders	953		751		1,366		732		3,802
Earnings per share:
Income from continuing operations available to Duke Energy Corporation common stockholders
Basic and diluted	$	1.22	$	0.90	$	1.69	$	0.86	$	4.68

Income from discontinued operations attributable to Duke Energy Corporation common stockholders
Basic and diluted	$	0.03	$	0.06	$	0.10	$	0.07	$	0.26

Net income available to Duke Energy Corporation common stockholders
Basic and diluted	$	1.25	$	0.96	$	1.79	$	0.93	$	4.94

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

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	1				6,871,197		6,871,198
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income					415,646		415,646
3	Preceding Quarter/Year to Date Changes in Fair Value
4	Total (lines 2 and 3)					415,646		415,646	1,336,592,897	1,337,008,543
5	Balance of Account 219 at End of Preceding Quarter/Year	1				6,455,551		6,455,552
6	Balance of Account 219 at Beginning of Current Year	1				6,455,551		6,455,552
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income					415,645		415,645
8	Current Quarter/Year to Date Changes in Fair Value
9	Total (lines 7 and 8)					415,645		415,645	1,600,993,370	1,601,409,015
10	Balance of Account 219 at End of Current Quarter/Year	1				6,039,906		6,039,907

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

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)	45,669,223,712	45,669,223,712
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	412,802,602	(a) 412,802,602
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified	4,042,182,258	4,042,182,258
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	50,124,208,572	50,124,208,572
9	UtilityPlantLeasedToOthers Leased to Others
10	UtilityPlantHeldForFutureUse Held for Future Use	65,118,768	65,118,768
11	ConstructionWorkInProgress Construction Work in Progress	2,668,054,514	2,668,054,514
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments	284,106	284,106
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	52,857,665,960	52,857,665,960
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	18,826,671,097	18,826,671,097
15	UtilityPlantNet Net Utility Plant (13 less 14)	34,030,994,863	34,030,994,863
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	18,039,325,093	18,039,325,093
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	787,061,898	787,061,898
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	18,826,386,991	18,826,386,991
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	284,106	284,106
33	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Total Accum Prov (equals 14) (22,26,30,31,32)	18,826,671,097	18,826,671,097

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: UtilityPlantInServicePropertyUnderCapitalLeases

Property Under Capital Leases includes both Capital Leases of $334,662,879 and Net Operating Leases of $78,139,723.

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)
Report below the costs incurred for nuclear fuel materials in process of fabrication, on hand, in reactor, and in cooling; owned by the respondent. If the nuclear fuel stock is obtained under leasing arrangements, attach a statement showing the amount of nuclear fuel leased, the quantity used and quantity on hand, and the costs incurred under such leasing arrangements.
Line No.	Description of item (a)	Balance Beginning of Year (b)	Changes during Year Additions (c)	Changes during Year Amortization (d)	Changes during Year Other Reductions (Explain in a footnote) (e)	Balance End of Year (f)
1	Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1)
2	Fabrication	9,315,659	42,392,509		(a) 45,418,579	6,289,588
3	Nuclear Materials	254,998,052	185,735,361		(b) 190,613,729	250,119,684
4	Allowance for Funds Used during Construction	59,608,755	16,039,346		(c) 13,549,621	62,098,479
5	(Other Overhead Construction Costs, provide details in footnote)
6	SUBTOTAL (Total 2 thru 5)	323,922,465				318,507,751
7	Nuclear Fuel Materials and Assemblies
8	In Stock (120.2)	1	249,581,930		(d) 249,581,930	1
9	In Reactor (120.3)	1,072,507,768	249,581,930		(e) 283,389,322	1,038,700,375
10	SUBTOTAL (Total 8 & 9)	1,072,507,769				1,038,700,376
11	Spent Nuclear Fuel (120.4)	466,390,240	283,389,322		(f) 378,032,129	371,747,433
12	Nuclear Fuel Under Capital Leases (120.6)
13	(Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5)	1,070,439,997		247,614,928	(g) 378,032,129	940,022,796
14	TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13)	792,380,477				788,932,764
15	Estimated Net Salvage Value of Nuclear Materials in Line 9
16	Estimated Net Salvage Value of Nuclear Materials in Line 11
17	Est Net Salvage Value of Nuclear Materials in Chemical Processing
18	Nuclear Materials held for Sale (157)
19	Uranium
20	Plutonium
21	Other (Provide details in footnote)
22	TOTAL Nuclear Materials held for Sale (Total 19, 20, and 21)

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: FabricationCostsNuclearFuelInProcessOfRefinementConversionEnrichmentAndFabricationOtherReductions

Transfer of Nuclear Materials and Assemblies to stock

(b) Concept: NuclearMaterialsNuclearFuelInProcessOfRefinementConversionEnrichmentAndFabricationOtherReductions

Transfer of Nuclear Materials and Assemblies to stock

(c) Concept: AllowanceForFundsConstructionNuclearFuelInProcessOfRefinementConversionEnrichmentAndFabricationOtherReductions

Transfer of Nuclear Materials and Assemblies to stock

(d) Concept: NuclearFuelMaterialsAndAssembliesInStockOtherReductions

Transfer to Reactor

(e) Concept: NuclearFuelAssembliesInReactorOtherReductions

Reflects Nuclear Fuel Assemblies transferred to the Spent Fuel Pool

(f) Concept: SpentNuclearFuelOtherReductions

Reflects Nuclear Fuel Assemblies retired from the Reactor

(g) Concept: AccumulatedProvisionForAmortizationOfNuclearFuelAssembliesOtherReductions

Reflects Nuclear Fuel Assemblies retired from the Reactor

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
Report below the original cost of electric plant in service according to the prescribed accounts. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and reductions in column (e) adjustments. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included in column (c) are entries for reversals of tentative distributions of the prior year reported in column (b). Likewise, if the respondent has a significant amount of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d) distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of respondent’s plant actually in service at end of year. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary account classifications. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing subaccount classification of such plant conforming to the requirement of these pages. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase, and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date.
Line No.	Account (a)	Balance Beginning of Year (b)	Additions (c)	Retirements (d)	Adjustments (e)	Transfers (f)	Balance at End of Year (g)
1	1. INTANGIBLE PLANT
2	(301) Organization
3	(302) Franchise and Consents	227,565,131	7,659,445				235,224,576
4	(303) Miscellaneous Intangible Plant	978,611,836	60,852,890	31,485,365		7,415,842	1,015,395,203
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)	1,206,176,967	68,512,335	31,485,365		7,415,842	1,250,619,779
6	2. PRODUCTION PLANT
7	A. Steam Production Plant
8	(310) Land and Land Rights	32,194,574		9,160			32,185,414
9	(311) Structures and Improvements	1,410,084,090	11,041,067	11,358,723		30,748,115	1,379,018,319
10	(312) Boiler Plant Equipment	5,775,239,106	38,861,443	63,616,446			5,750,484,103
11	(313) Engines and Engine-Driven Generators
12	(314) Turbogenerator Units	890,118,768	14,896,598	12,163,031			892,852,335
13	(315) Accessory Electric Equipment	393,965,945	1,469,326	16,752,190			378,683,081
14	(316) Misc. Power Plant Equipment	375,370,265	5,282,670	6,553,229		13,826,917	360,272,789
15	(317) Asset Retirement Costs for Steam Production	2,065,695,354	88,472,332	49,140,580			2,105,027,106
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)	10,942,668,102	160,023,436	159,593,359		44,575,032	10,898,523,147
17	B. Nuclear Production Plant
18	(320) Land and Land Rights	3,041,443					3,041,443
19	(321) Structures and Improvements	1,992,636,568	56,737,661	15,740,341			2,033,633,888
20	(322) Reactor Plant Equipment	4,069,735,577	35,829,390	16,959,899			4,088,605,068
21	(323) Turbogenerator Units	1,120,173,028	14,549,221	2,758,922			1,131,963,327
22	(324) Accessory Electric Equipment	1,311,042,851	10,856,310	5,137,323			1,316,761,838
23	(325) Misc. Power Plant Equipment	637,024,852	25,749,305	1,540,718			661,233,439
24	(326) Asset Retirement Costs for Nuclear Production	251,515,770					251,515,770
25	TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)	8,882,138,549	143,721,887	42,137,203			8,983,723,233
26	C. Hydraulic Production Plant
27	(330) Land and Land Rights	52,744,940	334,273	1,378			53,077,835
28	(331) Structures and Improvements	455,598,319	14,258,509	254,046			469,602,782
29	(332) Reservoirs, Dams, and Waterways	991,983,575	105,998,170	10,677,203			1,087,304,542
30	(333) Water Wheels, Turbines, and Generators	824,435,989	27,269,004	4,522,609			856,227,602
31	(334) Accessory Electric Equipment	156,450,199	2,896,084	478,953			159,825,236
32	(335) Misc. Power Plant Equipment	57,055,255	2,667,308	441,428			60,163,991
33	(336) Roads, Railroads, and Bridges	22,815,544					22,815,544
34	(337) Asset Retirement Costs for Hydraulic Production			2,223,577	2,223,577
35	TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)	2,561,083,821	153,423,348	3,266,060	2,223,577		2,709,017,532
36	D. Other Production Plant
37	(340) Land and Land Rights	9,262,315					9,262,315
38	(341) Structures and Improvements	525,936,999	7,541,709	178,074		30,748,115	564,048,749
39	(342) Fuel Holders, Products, and Accessories	185,404,444	946,064	746,264			185,604,244
40	(343) Prime Movers	1,185,073,886	55,026,755	44,223,397			1,195,877,244
41	(344) Generators	1,282,049,177	20,970,633	9,851			1,261,088,395
42	(345) Accessory Electric Equipment	213,702,205	24,142,769	194,550			237,650,424
43	(346) Misc. Power Plant Equipment	45,420,501	3,366,843	117,621		13,826,917	62,496,640
44	(347) Asset Retirement Costs for Other Production	22,158,763					22,158,763
44.1	(348) Energy Storage Equipment - Production
45	TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)	3,469,008,290	70,053,507	45,450,055		44,575,032	3,538,186,774
46	TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)	25,854,898,762	527,222,178	250,446,677	2,223,577		26,129,450,686
47	3. Transmission Plant
48	(350) Land and Land Rights	203,915,814	8,926,070	4,148		6,020,535	206,825,497
48.1	(351) Energy Storage Equipment - Transmission
49	(352) Structures and Improvements	186,704,696	9,563,796	607,421		5,843,889	170,689,590
50	(353) Station Equipment	2,302,082,150	225,954,856	14,042,334		36,644,959	2,477,349,713
51	(354) Towers and Fixtures	651,436,521	2,892,062	58,120			648,486,339
52	(355) Poles and Fixtures	662,651,783	40,295,652	5,071,387			697,876,048
53	(356) Overhead Conductors and Devices	944,794,878	160,260,886	10,741,920		1,570,339	1,095,884,183
54	(357) Underground Conduit	154,590	436,293	2,890			587,993
55	(358) Underground Conductors and Devices	12,171,600	111,446	151,130		1,570,339	10,338,685
56	(359) Roads and Trails	42,238	13,953	31,321			24,870
57	(359.1) Asset Retirement Costs for Transmission Plant
58	TOTAL Transmission Plant (Enter Total of lines 48 thru 57)	4,963,954,270	423,320,406	30,702,375		48,509,383	5,308,062,918
59	4. Distribution Plant
60	(360) Land and Land Rights	83,626,440	9,369,690	156,693		6,020,535	99,173,358
61	(361) Structures and Improvements	178,576,484	6,479,001	328,080		5,612,236	190,339,641
62	(362) Station Equipment	1,705,258,389	182,504,448	29,473,580		37,023,467	1,895,312,724
63	(363) Energy Storage Equipment – Distribution
64	(364) Poles, Towers, and Fixtures	1,846,979,711	50,791,715	15,035,494			1,882,735,932
65	(365) Overhead Conductors and Devices	2,678,576,713	309,367,077	38,426,337		373,864	2,949,143,589
66	(366) Underground Conduit	269,930,640	30,973,692	157,822			300,746,510
67	(367) Underground Conductors and Devices	2,592,327,369	280,003,353	11,098,834			2,861,231,888
68	(368) Line Transformers	1,842,342,544	292,704,527	10,565,431		4,645	2,124,476,995
69	(369) Services	1,273,824,826	143,295,369	1,071,883			1,129,457,574
70	(370) Meters	588,755,090	73,476,471	10,545,508		1,792,645	653,478,698
71	(371) Installations on Customer Premises	1,063,691,889	25,863,930	14,748,612			1,074,807,207
72	(372) Leased Property on Customer Premises
73	(373) Street Lighting and Signal Systems	357,015,453	94,626,752	6,806,941			444,835,264
74	(374) Asset Retirement Costs for Distribution Plant
75	TOTAL Distribution Plant (Enter Total of lines 60 thru 74)	14,480,905,548	1,212,865,287	138,101,829		50,070,374	15,605,739,380
76	5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77	(380) Land and Land Rights
78	(381) Structures and Improvements
79	(382) Computer Hardware
80	(383) Computer Software
81	(384) Communication Equipment
82	(385) Miscellaneous Regional Transmission and Market Operation Plant
83	(386) Asset Retirement Costs for Regional Transmission and Market Oper
84	TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
85	6. General Plant
86	(389) Land and Land Rights	62,872,816	200,027	4,223,860			58,448,929
87	(390) Structures and Improvements	733,020,622	419,550,200	180,040,155		231,653	972,762,320
88	(391) Office Furniture and Equipment	176,130,657	47,364,564	16,705,463			206,789,758
89	(392) Transportation Equipment	15,532,601	1,045,559	459,273			16,118,887
90	(393) Stores Equipment	16,082,426	757,896	5,052			15,319,478
91	(394) Tools, Shop and Garage Equipment	128,793,458	9,813,592	4,058,400		1,792,645	132,756,005
92	(395) Laboratory Equipment	2,813,356	137,590	235,575			2,715,371
93	(396) Power Operated Equipment	19,040,122	325,450	495,139			18,219,533
94	(397) Communication Equipment	255,016,900	66,177,076	7,311,541			313,882,435
95	(398) Miscellaneous Equipment	15,146,584	1,180,860	212,740			16,114,704
96	SUBTOTAL (Enter Total of lines 86 thru 95)	1,424,449,542	543,986,068	213,747,198		1,560,992	1,753,127,420
97	(399) Other Tangible Property
98	(399.1) Asset Retirement Costs for General Plant	931,335					931,335
99	TOTAL General Plant (Enter Total of lines 96, 97, and 98)	1,423,518,207	543,986,068	213,747,198		1,560,992	1,752,196,085
100	TOTAL (Accounts 101 and 106)	47,929,453,754	2,775,906,274	664,483,444	2,223,577	7,415,841	50,046,068,848
101	(102) Electric Plant Purchased (See Instr. 8)
102	(Less) (102) Electric Plant Sold (See Instr. 8)
103	(103) Experimental Plant Unclassified
104	TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)	47,929,453,754	2,775,906,274	664,483,444	2,223,577	7,415,841	50,046,068,848

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

ELECTRIC PLANT LEASED TO OTHERS (Account 104)
Line No.	LesseeName Name of Lessee (a)	IndicationOfAssociatedCompany * (Designation of Associated Company) (b)	LeaseDescription Description of Property Leased (c)	CommissionAuthorization Commission Authorization (d)	ExpirationDateOfLease Expiration Date of Lease (e)	ElectricPlantLeasedToOthers Balance at End of Year (f)
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	TOTAL

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held for future use. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.
Line No.	ElectricPlantHeldForFutureUseDescription Description and Location of Property (a)	ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate Date Originally Included in This Account (b)	ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate Date Expected to be used in Utility Service (c)	ElectricPlantHeldForFutureUse Balance at End of Year (d)
1	Land and Rights:
2	LEE NUCELAR PLANT COMMON LAND - CHEROKEE,SC	06/01/2018	12/31/2030	40,939,833
3	LIBERTY SITE RIGHT OF WAY - GUILFORD, NC	09/01/2022	12/31/2026	2,626,066
4	RICHBURG RETAIL SUBSTATION LAND - CHESTER, SC	10/01/2018	12/31/2026	1,524,740
5	PATTERSON AVENUE RETAIL SUBSTATION LAND - CLEVELAND, NC	01/01/2017	12/31/2025	1,335,969
6	FURR ROAD RETAIL SUBSTATION LAND - MECKLENBURG, NC	10/01/2011	12/31/2023	1,227,200
7	N ALEXANDER ST RETAIL SUBSTATION LAND - MECKLENBURG, NC	03/01/2012	12/31/2026	959,967
8	LAKE NORMAN 525KV RIGHT OF WAY - MECKLENBURG, NC	01/01/1980	12/31/2024	937,983
9	FERNCLIFF RETAIL 115/23 KV SUBSTATION LAND - DAVIE, NC	12/01/2018	12/31/2030	886,508
10	DEATH VALLEY RETAIL SUBSTATION RIGHT OF WAY - PICKENS, SC	09/01/2020	12/31/2023	835,301
11	BELMEADE RETAIL SUBSTATION LAND - MECKLENBURG, NC	11/01/2012	12/31/2025	804,674
12	WRENN RETAIL SUBSTATION LAND - ANDERSON, SC	06/01/2020	12/31/2024	798,078
13	PATTERSON AVE RETAIL TRANS LINE RIGHT OF WAY - CLEVELAND, NC	01/01/2021	12/31/2026	711,195
14	STOKESDALE RETAIL TRANS LINE RIGHT OF WAY - GUILFORD, NC	06/01/2021	12/31/2025	642,140
15	BRANSON MILL RD RETAIL SUBSTATION LAND - RANDOLPH, NC	11/01/2013	12/31/2026	542,992
16	SHOFFNER RETAIL SUBSTATION LAND - GUILFORD, NC	12/01/2009	12/31/2026	512,693
17	KERWIN CIRCLE RETAIL SUBSTATION LAND - FORSYTH, NC	06/04/2009	12/31/2023	512,463
18	WALNUT COVE RIGHT OF WAY - STOKES, NC	03/01/2020	12/31/2024	503,275
19	DORMAN RD RETAIL SUBSTATION LAND - MECKLENBURG, NC	06/01/2012	12/31/2026	459,800
20	TARRANT RD SWITCHING STATION LAND - GUILFORD, NC	10/01/2018	12/31/2024	453,572
21	HARRISON BRIDGE RETAIL 100KV TAP RIGHT OF WAY - GREENVILLE, SC	12/01/2021	12/31/2025	446,162
22	CALICO RD RETAIL SUBSTATION LAND - CALDWELL, NC	01/01/2012	12/31/2024	427,771
23	CANTERBURRY RETAIL LAND - GREENVILLE, SC	04/01/2018	12/31/2023	415,864
24	KANOY RETAIL SUBSTATION RIGHT OF WAY - DAVIDSON, NC	07/01/2010	12/31/2026	405,935
25	VOSS CREEK RETAIL SUBSTATION LAND & RIGHT OF WAY - STOKES, NC	05/01/2018	12/31/2024	398,240
26	REVOLUTION MILL RETAIL SUBSTATION LAND - GUILFORD, NC	10/01/2011	12/31/2026	381,535
27	GALENOR/LENOIR 203-100KV RIGHT OF WAY - CALDWELL, NC	11/01/2020	12/31/2040	378,537
28	EDGEFIELD RETAIL SUBSTATION LAND - GUILFORD, NC	02/01/2012	12/31/2025	370,486
29	ROEBUCK RETAIL LAND - SPARTANBURG, SC	02/01/2012	12/31/2027	364,453
30	HIGHWAY 24 RETAIL SUBSTATION LAND - ANDERSON, SC	12/02/2008	12/31/2028	325,328
31	RICHBURG RETAIL STATION RIGHT OF WAY - CHESTER, SC	10/01/2019	12/31/2026	317,351
32	LONG ISLAND ROAD RETAIL LAND - CATAWBA, NC	05/31/2009	12/31/2025	308,738
33	SKYLAND RETAIL SUBSTATION LAND - FORSYTH, NC	01/01/1990	12/31/2025	303,819
34	KEOWEE PLT PICKENS INSURABLE LAND - PICKENS, SC	10/01/2016	12/31/2030	284,915
35	LITTLE MOUNTAIN ROAD RETAIL LAND - GASTON, NC	12/11/2008	12/31/2027	282,811
36	N ALEXANDER ST RIGHT OF WAY - MECKLENBURG, NC	06/01/2020	12/31/2024	266,626
37	Other Land and Land Rights < $250K Each (41 Items)			2,224,812
38
21	Other Property:
22	Other Property < $250K Each (2 Items)			936
47	TOTAL			65,118,768

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Report below descriptions and balances at end of year of projects in process of construction (107). Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see Account 107 of the Uniform System of Accounts). Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line No.	ConstructionWorkInProgressProjectDescription Description of Project (a)	ConstructionWorkInProgress Construction work in progress - Electric (Account 107) (b)
1	DISTRIBUTION PLANT
2	0
3	DISTRIBUTION OVERHEAD/UNDERGROUND LINE IMPROVEMENTS - NORTH CAROLINA	90,810,651
4	DISTRIBUTION OVERHEAD/UNDERGROUND LINE IMPROVEMENTS - SOUTH CAROLINA	30,647,610
5	SMARTGRID FEEDER CAPACITY	16,919,071
6	KENILWTH RET - 1209	11,737,041
7	DEC IVVC CIRCUIT CONDITIONING VOLT	11,701,972
8	OUTDOOR LIGHTING MV REPLACEMENT	9,333,349
9	SG-R&I EQUIP DTUG REL IMPRV DEC	8,056,166
10	IVVC 2022 CENTRAL ZONE	7,832,011
11	COMMONWLTH R - 1205	7,749,453
12	PWRUP FAIRPLAINS RET TRANSFORMER RE	7,561,744
13	SMARTGRID TARGETED OVERHEAD/UNDERGROUND CONVERSION	7,482,842
14	SUBOPT - TEGA CAY RET - 2409	7,127,409
15	LONGVIEW TIE (8) 230KV BRK REPL	7,113,907
16	SMARTGRID SELF-HEALING TEAMS	7,113,804
17	SUBOPT - MONROE RD RET - 1207	6,515,823
18	HUDSON ST RET - SUBSTA EXPANSION	5,880,914
19	SUBOPT - PROVOL RET - 2411	5,818,194
20	DISTRIBUTION LINE RELOCATIONS/MODIFICATIONS - NORTH CAROLINA	5,795,335
21	NPL DISTRIBUTION LINES-NC	5,681,811
22	IVVC 2022 TRIAD ZONE	5,430,793
23	RICHBURG RET - NEW SUBSTATION	5,289,298
24	IVVC 2022 UPSTATE ZONE	4,719,998
25	SUBOPT-EDDY ROAD 1203	4,706,493
26	SUBOPT - HIGHTOWER - 1213	4,651,561
27	SUBOPT - CRUMP RD - 1207	4,624,479
28	2022 CAP FAILURES PH	4,612,723
29	SUBOPT - LAKE LURE RET - 1201	4,496,082
30	SUBOPT - SPRINGFIELD - 2411	4,381,336
31	DISTRIBUTION LIGHTING INSTALLATION - NORTH CAROLINA	4,257,109
32	SUBOPT-ROBBINSVILLE 1201	4,256,796
33	SUBOPT-BRUSHY CREEK - 1211	4,226,673
34	SUBOPT - HIGHTOWER - 1211	4,151,782
35	SUBOPT-FOREST LAKE 2402	4,109,838
36	SUBOPT - BRUSHY CREEK - 1206	4,098,854
37	ELI LILLY EXTRA FACILITIES	4,043,479
38	NESTLE PURINA - CUSTOMER SUBSTATION	3,963,498
39	WILGROVE RET - 2412	3,937,677
40	SUBOPT - MCALPNE CK R - 2414	3,870,099
41	SUBOPT - MERRITT DR RET 2405	3,629,306
42	SUBOPT - ASHEVILLE HWY RET - 1208	3,481,748
43	WILGROVE RET - 2411	3,430,915
44	DISTRIBUTION OVERHEAD/UNDERGROUND LINE IMPROVEMENTS - NP&L NORTH CAROLINA	3,427,072
45	SUBOPT-HENSLEY ROAD - 0401	3,417,983
46	MATTHEWS RET - 2409	3,386,031
47	SUBOPT - CODDLE CREEK - 1202	3,371,347
48	SUBOPT - NEW HOPE - 1212	3,356,456
49	CARMEL RD RT - 1209	3,323,444
50	SUBOPT-GILBRTH ST R - 2409	3,297,464
51	SUBOPT-DAVIDSON RIVER RET 1204	3,279,494
52	WILKES TIE 230 EXPANSION	3,226,049
53	SUBOPT - DUNBAR - 1205	3,215,351
54	CARMEL RD RT - 1208	3,197,984
55	SUBOPT - SPARTAN HEIGHTS RET - 1203	3,162,904
56	SUBOPT-NANTAHALA PLANT 3403	3,124,188
57	SUBOPT - BUTNER - 2403	3,097,401
58	SUBOPT - TAYLORSVILLE - 1201	3,067,898
59	SUBOPT - ROBERTA RD R - 1203	3,005,181
60	CHARLOTTE AUTOMATION AND INTEGRATION	2,992,220
61	SUBOPT-DANIELS RET 1208	2,968,181
62	GROOMETOWN - 2403	2,921,512
63	SUBOPT - HUDSON STRT - 1209	2,914,401
64	E & J GALLO WINERY - NEW CUSTOMER	2,868,115
65	DEC FUSE REPLACEMENT	2,730,887
66	SUBOPT - POPE ROAD - 2408	2,679,842
67	N CHARLOTTE RET - TRF BANK UPGRADE	2,666,372
68	IVVC 2022 TRIANGLE ZONE	2,621,176
69	SUBOPT - LANDRUM - 1203	2,568,424
70	SMARTGRID CABLE	2,529,557
71	SUBOPT - LEWISVILLE RETAIL 1209	2,526,313
72	SUBOPT - DUNBAR - 1209	2,481,781
73	SUBOPT - BELHAVEN RET - 1203	2,408,651
74	SUBOPT - GREENBRIAR SW STA - 1210	2,407,658
75	SUBOPT - RANKIN AVE - 1209	2,402,665
76	SUBOPT-TABERNACLE - 1208	2,380,997
77	DUKE DISTRIBUTION LINES-SC	2,360,283
78	SUBOPT - HUDSON STRT - 1212	2,287,627
79	SUBOPT - TAYLORSVILLE - 1204	2,284,848
80	LOCUST RET - TRF ADDITION	2,282,311
81	SUBOPT - BOILING SPGS - 1206	2,254,482
82	REIDSVILLE RET REPL 100KV BRK	2,192,232
83	SUBOPT - RANKIN AVE - 1210	2,178,305
84	IVVC 2022 MOUNTAIN ZONE	2,146,897
85	SUBOPT-BLANTYRE RET 1201	2,113,037
86	SUBOPT - DURHAM MAIN - 1203	2,100,072
87	SUBOPT - LEWISVILLE RETAIL 1206	2,091,694
88	SUBOPT - HUDSON STRT - 1210	2,063,205
89	SUBOPT - KNOLLWOOD - 1212	2,052,997
90	SUBOPT - RANKIN AVE - 1206	2,051,205
91	SUBOPT-LAKE LURE RET 1202	2,035,186
92	SUBOPT-PIPER GLEN RET 2413	2,031,989
93	DEC CAPITAL FAILURES PLACEHOLDER	2,011,667
94	SUBOPT - JOHNS CREEK - 1215	2,011,235
95	SUBOPT - ASHEVILLE HWY RET - 1207	1,996,447
96	SUBOPT - COFFEY CREEK RET - 2408	1,970,493
97	NEWRY - 1201	1,947,714
98	SUBOPT - SWPSONVLE RET 1203	1,930,177
99	SUBOPT-MOORESBORO RET 1202	1,917,092
100	SUBOPT - ROBERTA RD R - 1202	1,908,908
101	SIX MILE RET - 1206	1,908,576
102	SUBOPT - INDIAN LD RT - 1201	1,878,677
103	SUBOPT-FISHER 2401	1,871,534
104	SUBOPT-CAMPOBELLO 1201	1,838,974
105	SUBOPT - HUDSON STRT - 1211	1,838,398
106	SUBOPT-BOUNTY LAND 1201	1,834,730
107	SUBOPT - LAUREL CREEK - 1209	1,829,909
108	FARMINGTON	1,826,442
109	SUBOPT - JOHNS CREEK - 1209	1,824,348
110	SUBOPT - CAMP CROFT - 1207	1,818,199
111	GREENBRIAR SW STA - 1201	1,808,145
112	AURIGA POLYMERS SWITCH	1,806,412
113	HWY 801 - LAND ACQUISITION	1,800,754
114	SUBOPT-HICKRY GV RT 1207	1,784,083
115	PEBBLECREEK - 1206	1,763,082
116	SUBOPT-JENKINS BRANCH 1202	1,762,981
117	SUBOPT - BELHAVEN RET - 1204	1,760,933
118	SUBOPT - HINSHAW BANK - 1208	1,759,037
119	FAIRNTOSH RET RLBTYUPG	1,757,369
120	SUBOPT-MOCKSVILLE RET 2401	1,754,983
121	SUBOPT-SWAIMTOWN 1201	1,754,325
122	SUBOPT - WALLACE RD RET - 2403	1,751,405
123	SUBOPT-PEELER 1201	1,742,124
124	SUBOPT - POPE ROAD - 2401	1,725,454
125	MATTHEWS RET - 2407	1,717,809
126	SUBOPT - EASY ST. - 1202	1,693,522
127	SUBOPT-OAK RIDGE - 1208	1,684,310
128	SUBOPT-EASTGATE RET 1209	1,649,971
129	SPEEDWAY 2411 RECONDUCTOR	1,642,343
130	SUBOPT - FISHER - 2404	1,632,585
131	SUBOPT - BOILING SPGS - 1205	1,610,587
132	SUBOPT - HUDSON STRT - 1203	1,604,019
133	PWRUP - PORTABLE REGULATORS	1,602,909
134	SUBOPT - COFFEYCRK - 2406	1,602,385
135	SUBOPT - WILGROVE RET - 2405	1,595,702
136	SUBOPT-DUNCAN RET	1,594,195
137	SUBOPT-EBENEZER RET 1201	1,589,073
138	OAKVALE - 1206	1,578,158
139	SUBOPT-LELIA RET 1204	1,568,193
140	SUBOPT-THRIFT RET 1205	1,559,853
141	LONG DURATION OUTAGES	1,531,515
142	SUBOPT - TEGA CAY - FORT MILL - 240	1,530,056
143	FOUR SESNS R - 2406	1,520,008
144	IVVC 2021 TRIAD ZONE	1,519,214
145	SUBOPT - HILLSBOROUGH - 1202	1,494,785
146	MOORESVILLE RLBTY UPG	1,493,321
147	MORNING STAR TIE - 2403	1,490,538
148	SUBOPT - MOORE - 1201	1,486,352
149	SUBOPT - COMMONWEALTH RET - 1208	1,484,874
150	SUBOPT - DUNBAR - 1207	1,467,876
151	KNOLLWOOD - 1208	1,467,318
152	SUBOPT - NEW HOPE - 1211	1,459,331
153	SUBOPT - MCADENVILLE JCT TIE - 1204	1,447,452
154	SUBOPT - SOUTH SYLVA RET - 1205	1,433,816
155	SWPSONVLE RT - 1202	1,423,183
156	SUBOPT - WHITEHALL - 1203	1,415,806
157	SUBOPT - JENKINS BRANCH - 1203	1,411,987
158	SUBOPT - MCALPNE CK R - 2410	1,408,588
159	SUBOPT-GILBRTH ST R - 1201	1,388,830
160	WILGROVE RET - 2406	1,385,102
161	SUBOPT - KNOLLWOOD - 1211	1,369,070
162	SUBOPT-WOODLAWN RET 1210	1,350,521
163	SUBOPT-PEACE HAVEN RD RET 1205	1,350,395
164	SUBOPT - MAR-DON RET - 1205	1,341,266
165	SUBOPT - SCUFFLETOWN RET - 1202	1,335,055
166	MOORE - 1202	1,331,976
167	SUBOPT - ASHCRAFT AVE RET - 2407	1,322,196
168	SUBOPT-LANGSTON CRK 1207	1,303,207
169	SUBOPT - DOCHENO - 1202	1,301,294
170	SUBOPT-SPRINGFIELD 2412	1,296,899
171	SUBOPT - HUDSON STRT - 1205	1,293,937
172	SUBOPT - MOCKSVILLE RET - 2403	1,272,698
173	LANDRUM - 1202	1,271,201
174	SUBOPT - TEGA CAY - FORT MILL - 240	1,270,394
175	SUBOPT - LELIA RET - 1201	1,264,630
176	SUBOPT - BOILING SPGS - 1210	1,261,175
177	SUBOPT - GROOMETOWN - 1210	1,246,120
178	SUBOPT - EAST FRANKLIN - 1204	1,240,394
179	SUBOPT - LUMBER LANE RET - 1208	1,230,069
180	SUBOPT - BARRIER RD RET - 1201	1,229,387
181	SUBOPT - LEWISVILLE RETAIL 1212	1,228,641
182	HICKRY GV RT - 1205	1,227,004
183	ERWIN FARMS RET - TRF ADDITION	1,217,397
184	SUBOPT-AUGUSTA ROAD - 1203	1,212,195
185	DISTRIBUTION LIGHTING	1,209,731
186	SUBOPT-DOCHENO 1202	1,200,163
187	SUBOPT - EASLEY - 1202	1,194,926
188	SUBOPT - HILLSBOROUGH - 1201	1,192,908
189	LITTLE RK RT - 1212	1,189,157
190	BALLANTYNE RET - LAND ACQUISITION	1,187,481
191	VERDAE - 1203	1,182,736
192	SUBOPT - MARDON RET - 1208	1,182,370
193	SUBOPT - LELIA RET - 1202	1,176,163
194	SUBOPT - CREST STREET - 1203	1,173,681
195	SUBOPT - GREENBRIAR SW STA - 1212	1,165,976
196	SUBOPT - LANDRUM - 1204	1,156,506
197	SUBOPT - BRUSHY CREEK - 1212	1,149,692
198	SUBOPT - DURHAM MAIN - 1216	1,144,916
199	SUBOPT - MCADENVILLE JCT TIE - 1203	1,141,905
200	HICKRY GV RT - 1213	1,136,386
201	SUBOPT - BELMONT RET - 1203	1,134,107
202	HIGHTOWER - 1206	1,128,640
203	SUBOPT - POPE ROAD - 2403	1,120,439
204	SUBOPT - DOCHENO - 1202	1,119,067
205	SUBOPT - KIMESVLE RET - 1203	1,117,269
206	SUBOPT - CAMP CROFT - 1212	1,107,146
207	SUBOPT - ASHEVILLE HWY RET - 1205	1,104,843
208	SUBOPT-SWAIMTOWN 1207	1,104,761
209	SUBOPT-OLD FORT RET 1203	1,089,113
210	SUBOPT - WADSWORTH - 1208	1,085,422
211	SUBOPT - ROPER MOUNTN - 1204	1,077,372
212	SUBOPT-UTOPIA 1204	1,077,037
213	SUBOPT - RANKIN - 1204	1,064,143
214	SUBOPT - KNOLLWOOD - 1213	1,064,083
215	BUXTON ST RET - LOW SIDE REBUILD	1,060,544
216	GILBRTH ST R - 1202	1,054,964
217	SUBOPT - MCALPNE CK R - 2407	1,049,745
218	SUBOPT - MERRITT DR RET 2412	1,045,142
219	SUBOPT-GILBRTH ST R - 2410	1,044,695
220	SMARTGRID DETERIORATED CONDUCTOR	1,031,338
221	SUBOPT - MONROE RD RT - 1212	1,022,721
222	SUBOPT - ROARING RV R - 1201	1,020,803
223	SUBOPT - HINSHAW BANK - 1209	1,014,168
224	PWRUP CENTRAL REGION VANQUISH FENCE	1,006,591
225	SUBOPT - DURHAM MAIN - 1205	1,001,936
226	PROJECTS LESS THAN $1 MILLION	256,524,518
227	GENERAL PLANT
228	CHARLOTTE METRO - CONSTRUCT NEW OFFICE TOWER	184,820,854
229	REAL ESTATE SERVICES - GENERAL PLANT WORK	44,609,753
230	GENERAL ACCRUAL FOR DUKE POWER	13,629,038
231	TOWERS, SHELTERS & POWER SUPPLIES	13,521,768
232	DEC LMR PROJECT 5 DEC	11,718,029
233	FUNDING PROJECT 2022 TELECOM DVV	11,386,346
234	REAL ESTATE SERVICES - MISCELLANEOUS CAROLINAS WEST GENERAL PLANT PROJECTS	8,533,061
235	GRIDWAN CORE ROUTER UPFIT	7,449,071
236	STRATEGIC COMMUNICATION	7,412,968
237	IT DEMAND WORK FUNDING PROJECT	6,986,543
238	RES CAROLINA EAST CAPITAL PROJECTS	6,521,816
239	DEC OPTICAL EOL SYSTEMS	5,172,824
240	DEC MICROWAVE	4,870,436
241	DEE CONSOLES PROJECT	4,855,700
242	GENERIC CAPITAL COSTS	4,586,249
243	FUNDING PROJECT 2022 TELECOM MRTP	3,870,308
244	REAL ESTATE SERVICES - GENERAL PLANT WORK	3,671,414
245	SMARTGRID DEE DISTRIBUTED MANAGEMENT SYSTEM ADMS	3,343,952
246	CUSTOMER PLATFORM PROJECT	3,269,174
247	DEC MISSION CRITICAL VOICE COMMUN	2,569,958
248	CW C&M TOOLS PURCHASES	2,083,620
249	IT DEMAND WORK FUNDING PROJECT	2,054,796
250	EQUIPMENT PURCHASES FOR NC	1,955,012
251	GRID SOLUTIONS PROJECT 1 CORES	1,845,858
252	OPGW - LOOKOUT TIE TO STAMEY TIE	1,555,390
253	WEBFG PROJECT	1,482,793
254	LINCOLNTON TIE TO RIVERBEND	1,379,167
255	VEHICLE PURCHASES FOR SC	1,359,115
256	PRYSMIAN GROUP REG	1,300,892
257	DEE MOBILE CONNECT PRE SCALE	1,052,641
258	VEHICLE PURCHASES FOR NC	1,036,102
259	PROJECTS LESS THAN $1 MILLION	11,456,854
260	INTANGIBLE PLANT
261	SMARTGRID DEE DISTRIBUTED MANAGEMENT SYSTEM ADMS	46,909,970
262	SMARTGRID SECURE ACCESS AND DEVICE MANAGEMENT	5,992,268
263	OCONEE CORE MONITORING SOFTWARE AND SERVERS	5,483,000
264	IT DEMAND WORK FUNDING PROJECT	5,307,773
265	CATAWBA WATEREE RELICENSING	5,253,347
266	IT DEMAND WORK FUNDING PROJECT	5,251,212
267	DEE DER DISPATCH DESIGN AND DEVELOP	3,657,356
268	CUSTOMER CONNECT	3,577,581
269	DEC CLOSED LOOP FISR FS DEPLOY	2,636,121
270	FERC BA RELICENSING	2,538,306
271	DEE GRID HOSTING CAPACITY	2,296,503
272	IT DEMAND WORK FUNDING PROJECT	2,152,157
273	MODERN ARCHITECTURE IMPLEMENTATION	1,626,035
274	DEC DMS UPGRADE	1,602,180
275	REAL ESTATE SERVICES - MISCELLANEOUS CAROLINAS WEST GENERAL PLANT PROJECTS	1,213,164
276	DEC SCADA UPGRADE	1,209,280
277	20003 DE CAROLINAS FOSSIL IT	1,134,693
278	PROJECTS LESS THAN $1 MILLION	10,086,568
279	PRODUCTION PLANT
280	CEDAR CLIFF POWER HOUSE DAM INFLOW DESIGN FLOOD SPILLWAY & GATE HOUSE	112,147,979
281	OCONEE MAIN STREAM ISOLATION VALVES	84,839,113
282	LINCOLN NEW COMBUSTION TURBINE UNIT	69,263,795
283	LOOKOUT SHOALS PLANT - SEISMIC NET PROJECT	50,475,450
284	OCONEE SUPPLEMENTAL LICENSE REQUEST	42,746,378
285	BA U3 MW UPRATE	28,474,263
286	WSL U11 HGPI TEMPLATE LTSA	15,554,577
287	WSL U12 HGPI TEMPLATE LTSA	14,990,797
288	MARSHALL STEAM PLANT SCR INSTALLATION	13,536,829
289	MNS U2 REACTOR VESSEL HEAD PEENING	12,269,523
290	OCONEE SSF ELECTRICAL GENERATOR	11,663,427
291	FERC WY ALLISON CREEK ACCESS AREA	10,203,894
292	BA U4 MW UPRATE	10,043,594
293	ONS PHASE 10 DRY STORAGE OVERPACKS	9,555,675
294	ONP-CCW CROSSOVER VALVE U2	9,280,540
295	FERC BW BLACK BEAR ACCESS AREA	9,099,720
296	OCONEE UNIT 1 SSF INSTRUMENTATION AND TORNADO LAR	8,432,608
297	MNS U1 REACTOR VESSEL HEAD PEENING	8,419,129
298	CT U11 FORCED OUTAGE INS.CLAIM	8,019,897
299	OCONEE CYBER SECURITY MITIGATION SECURITY SYSTEMS	7,580,687
300	PSCS VIDEO HARDWARE/SOFTWARE REPLAC	7,262,372
301	ONP-IPB U1 ISOLATED PHASE BUS	7,097,225
302	MCGUIRE UNIT 2 MAIN POWER RELAYING	7,010,117
303	ONP-ALLOY 600 COMPLEX NOZZLES U1	6,969,395
304	FERC WA FLOOD MANAGEMENT	6,746,195
305	MI U1 REPLACE TURBINE RUNNER	6,486,298
306	MOUNTAIN ISLAND DAM SEISMIC	5,941,366
307	NGO ONS BAFFLE BOLTS	5,648,283
308	CCP CLIFF-500 LOW HEAD DAM STAB.	5,310,494
309	FERC WY SOUTH POINT ACCESS AREA	5,193,647
310	MNS ISFSI PHASE 5 MAGNASTOR PADS	4,971,774
311	CNS RVCH PEENING U2	4,926,090
312	ONP-BLOCKHOUSE U1/2 AND CT-4(OBDN)	4,904,170
313	ONS INSTALL INCOREDETRS O3R31-O1R32	4,628,139
314	OCONEE PLANT INSURABLE - MSIV ALT SSF INSTRUMENTATION U2	4,525,991
315	STATION ROOF REPLACEMENTS	4,381,725
316	BAD CREEK UNIT 1 UPRATE	4,154,284
317	CS06 REPLACE AIR PREHEATER BASKETS	4,065,984
318	MNS U1 A GENERATOR CIRCUIT BREAKER	3,833,637
319	FERC FC FLOODGATE LIFE EXTEN PH II	3,589,159
320	ONS REPL 1A2 RCP MOTOR	3,504,617
321	MNS PHASE 5 DRY STORAGE OVERPACKS	3,350,130
322	CATAWBA LICENSE RENEWAL	3,269,643
323	MNS CAPITAL SPARE EXCITER	3,247,637
324	FLOATING FALSE GATE	3,174,373
325	MCGUIRE UNIT 1 & UNIT 2 POLAR CRANE METER & CONTROLS	3,140,541
326	ONS 2022 MAINT UMBRELLA PROJECT	2,915,749
327	U1 POLAR CRANE MTR & CONTROLS UPGRD	2,891,645
328	FP FOR SPAR 336593022	2,884,341
329	OCONEE UNIT 2 MEASUREMENT UNCERTAINTY RECAPTURE RATE	2,686,002
330	HCAD TUNNEL WASHDOWN FIXED SYSTEM	2,600,719
331	FERC FIRST LK HICKORY SWIM & WITTEN	2,569,085
332	BELEWS CREEK GMA 2022	2,564,263
333	2B SSPS CIRCUIT BOARD REPLACEMENT	2,475,145
334	CNS 1B MSU TRANSFORMER REPLACEMENT	2,475,130
335	CF ELEVATOR REPLACEMENT	2,462,883
336	RH U3 TRASH RACKS STOP LOGS SYSTEM	2,395,289
337	FERC RH CONLEY CREEK ACCESS AREA	2,379,362
338	ONS REPL U3 RCP SEAL (2022)	2,356,501
339	MCGUIRE UNIT 1 GENERATOR STATOR REFURBISHMENT	2,329,311
340	PAVE ADM EAST&WEST PARKING LOTS	2,316,753
341	FERC WA COLONELS CREEK ACCESS AREA	2,244,160
342	ONP-MCCB OUTAGE U1	2,194,765
343	NIT EOL SERVER REPLACEMENT - DEC	2,182,573
344	ENERGY SERVICES DEC REG FP	2,155,970
345	1A RN MOTOR	2,144,504
346	MNS REPL U2 TURBINE BUILDING ROOF	2,093,865
347	ONP-STATOR COOLANT RECTIFIER U1	2,011,328
348	20004 DE CAROLINAS CT IT	2,010,690
349	ONP AUX BLDG ELEVATOR U1/2	1,996,902
350	JO INSTALL AHU 1-5 CHILLERS WC SYS	1,894,050
351	ONS TEMPORARY CHILLER PURCHASE	1,890,732
352	ONS SIEM ONS BREAKOUT	1,869,578
353	ONS REPL U1 RCP SEAL (2022)	1,859,776
354	ONP-HELB CC HVAC U1-U2	1,839,801
355	ONS KEOWEE HYDRO STATION ROOF SEC 1	1,831,937
356	ONS PAVING SOUTH U3 AREA 11	1,823,680
357	MS3 APH BASKET REPL	1,819,670
358	WSL U10 FORCED OUTAGE	1,791,848
359	NGO FIXED RP EQUIP	1,722,455
360	ONS REPL U1A HPI PUMP & MOTOR	1,709,529
361	ONS UPGRADE SUPPLEMENTAL SFP PIPING	1,703,740
362	OPTIM CT CI UNIT 3	1,681,498
363	HEAT RATE OPTIMIZATION TOOL - DEC	1,656,667
364	1A2 KC MOTOR	1,615,397
365	CNS RVCH PEENING U1	1,611,366
366	EXTERIOR LIFE EXTENSION	1,606,101
367	U1 LPSW PIPING TO A RCPS	1,561,467
368	ONS LIGHT REPLACEMENT-SITE	1,557,673
369	ONP-MCCB OUTAGE U3	1,539,091
370	CNS INTELLEGENT MONITORING PH II	1,538,469
371	ONS AXIAL POWER SHAPING RODS (APSR)	1,532,194
372	OPTIM CT CI UNIT 4	1,521,740
373	2A RN MOTOR	1,504,656
374	CS06 CATALYST REPLACEMENT	1,499,778
375	WA REPLACE 9070 TO 3I CONTROLS	1,476,415
376	REPL U2 CONDENSATE POLISHER SYS	1,465,190
377	ONS REPL AHU 3-7 AND 3-8	1,452,223
378	BE PENSTOCK ISOLATION VALVE	1,420,599
379	MAIN POWER RELAY ZONE A&B UNIT 1	1,416,082
380	ONS REPL METAL EXP JOINTS O1R32	1,406,241
381	OCONEE UNIT 1 MEASUREMENT UNCERTAINTY RECAPTURE RATE	1,405,236
382	REPLACE AIR COMPRESSOR #3	1,358,036
383	WC POND PIPE REPLACEMENT	1,356,725
384	ONS KEOWEE OIL DETECTION	1,275,481
385	FERC OX SPILLWAY PIERS BULKHEAD	1,258,821
386	REPLACE AIR COMPRESSOR #8	1,255,800
387	ONS RCP MOTOR REFURB (2022)	1,242,071
388	ONS U1 WATER BOX COATING LINERS	1,207,712
389	ONS MTF/OUTFALL MAIN STORM DRN REPL	1,204,763
390	TORQUE TUBE REPLACEMENT	1,195,917
391	OCONEE UNIT 3 MEASUREMENT UNCERTAINTY RECAPTURE RATE	1,115,436
392	CNS HP TURBINE DIAPHRAGMS U2	1,106,420
393	END OF LIFE HARDWARE REPLAC	1,105,013
394	MS1 BOOSTER FAN ROTOR REPL	1,097,454
395	CNS 1A MSU TRANSFORMER REPLACEMENT	1,078,494
396	CNS 2A MSU TRANSFORMER REPLACEMENT	1,077,502
397	MNS U2 A GENERATOR CIRCUIT BREAKER	1,075,148
398	NGO PMMD SERVER INFRASTRUCTURE UPGR	1,059,468
399	REPLACE AIR COMPRESSOR #2	1,022,361
400	MNS PENSEAL EQUIPMENT PURCHASE	1,011,572
401	DCS EVERGREEN	1,008,917
402	PROJECTS LESS THAN $1 MILLION	107,214,032
403	TRANSMISSION PLANT
404	ALLEN STEAM STA	41,789,706
405	WILKES TIE 230 EXPANSION	31,510,248
406	SILAS LINES REBUILD'	14,334,711
407	MONROE MN P&C UPGRADE	13,324,338
408	WINDMERE NEW 100KV LINE	10,584,822
409	DURHAM MAIN SPCC AND RELIABILITY UP	10,082,521
410	STONEWALL TAP 44 KV LINE REBUILD	9,823,179
411	WEBSTER TIE RELIABILITY UPGRADE	9,409,044
412	SHELBY TIE RLBTY UPG	9,221,778
413	WYLIE SERIES 100 KV BJB	9,073,519
414	BELFAST 44 KV LINE REBUILD	8,690,198
415	500KV PARKWOOD LINE RELOCATION	8,387,968
416	WICK #2 44 KV LINE REBUILD	8,015,620
417	PACOLET TIE RLBTY UPG	7,098,333
418	MCDOWELL TIE RLBTY UPG	6,685,831
419	OCONEE 230KV SWYD NEW RELAY CONTROL	6,194,376
420	TOYOTA BATTERY MANUFACTURING NEW C	6,035,349
421	2022 CAP FAILURES PH	5,507,812
422	CABIN CREEK 44KV LINE RUTLEDGE RBLD	5,080,184
423	ROCKFORD LINE REBUILD CHATHAM MFG	4,913,416
424	EMERGENCY NEWPORT AUTOTRANSFORMER 1	4,563,492
425	GLEN RAVEN MN RLBTY UPG	4,466,447
426	MOUNTAIN ISLAND HYDRO - TRANSMISSIO	4,060,651
427	PARKWOOD TIE ADD REDUND	3,977,774
428	NEALS CREEK TAP 44 KV LINE REBUILD	3,898,916
429	ANDERSON TIE RLBTY UPG	3,805,630
430	REEDY RIVER TIE P+C REPL	3,584,658
431	EMERGENT CLIFFSIDE UNIT 5 SWYD FAIL	3,201,903
432	PICKENS TIE RLBTY UPG	2,977,782
433	DACIAN AVE RET (STA1511) REPLACE	2,808,343
434	HANKINS LINE RBLD STR 104	2,764,105
435	RIVERBEND STEAM STA RELAY MIS OP	2,665,002
436	CLIFFSIDE SS 1-4 SYD RLBTY UPG	2,664,678
437	6-WIRE WATEREE LINE	2,611,353
438	LIBERTY MEGA-SITE NEW ROW	2,260,265
439	PUTMAN RETAIL - CIRCUIT SWITCHER AD	2,199,950
440	QUEBEC 44 KV T-LINE REBUILD CONTAIN	2,164,163
441	RURAL HALL TO MITCHELL RIVER	1,809,755
442	ROCKY CREEK #1 44KV LINE RBLD	1,768,966
443	APEX SOLAR PV INTERCONNECTION	1,703,111
444	PWRUP LAKE TOWNSEND RETAIL TAP GOAB	1,596,591
445	REAL ESTATE SERVICES - GENERAL PLANT WORK	1,531,859
446	DEC EMERGENT 2020	1,509,135
447	EMERGENCY PROJECT - PARKWOOD TIE (S	1,485,061
448	CENTRAL/BROAD RIVER DELIVERY #20 FL	1,448,670
449	SRP10XX CATHODIC PROTECT SOUTH 2022	1,276,368
450	CAROLINA WEST CBM PROGRAM 2021 - CE	1,260,527
451	DEC CAPITAL FAILURES PLACEHOLDER	1,189,833
452	OCONEE 230KV SWYD LOAD CNTRS REPL	1,102,445
453	HENDERSONVILLE TIE RLBTY UPG	1,070,549
454	SRP1084 CATHODIC PROTECT CENT 2026	1,029,584
455	PROJECTS LESS THAN $1 MILLION	41,021,250
43	Total	2,668,054,514

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
Explain in a footnote any important adjustments during year. Explain in a footnote any difference between the amount for book cost of plant retired, Line 12, column (c), and that reported for electric plant in service, page 204, column (d), excluding retirements of non-depreciable property. The provisions of Account 108 in the Uniform System of Accounts require that retirements of depreciable plant be recorded when such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional classifications. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Line No.	Item (a)	Total (c + d + e) (b)	Electric Plant in Service (c)	Electric Plant Held for Future Use (d)	Electric Plant Leased To Others (e)
Section A. Balances and Changes During Year
1	AccumulatedProvisionForDepreciationOfElectricUtilityPlant Balance Beginning of Year	17,347,320,041	17,347,320,041
2	Depreciation Provisions for Year, Charged to
3	DepreciationExpenseExcludingAdjustments (403) Depreciation Expense	1,208,559,422	1,208,559,422
4	DepreciationExpenseForAssetRetirementCosts (403.1) Depreciation Expense for Asset Retirement Costs
5	ExpensesOfElectricPlantLeasedToOthers (413) Exp. of Elec. Plt. Leas. to Others
6	TransportationExpensesClearing Transportation Expenses-Clearing	1,071,189	1,071,189
7	OtherClearingAccounts Other Clearing Accounts
8	OtherAccounts Other Accounts (Specify, details in footnote):
9.1	Amortization of Buck and Bridgewater	85,452	85,452
9.2	Amortization of Cliffside	320,952	320,952
9.3	Amortization of Dan River	95,040	95,040
9.4	Amortization of Deferred ABSAT (T1) Depreciation and Return	3,615,579	3,615,579
9.5	Amortization of Deferred AMI Depreciation and Return (SC)	798,542	798,542
9.6	Amortization of Deferred Carolinas West Control Center Costs (SC)	48,040	48,040
9.7	Amortization of Deferred Depreciation (2018 Depreciation Study) (SC)	1,053,012	1,053,012
9.8	Amortization of Deferred Grid Improvement Costs	144,615	144,615
9.9	Amortization of Deferred Lee CC Equity Return (NC)	306,492	306,492
9.10	Amortization of Deferred Lee CC Equity Return (SC)	471,377	471,377
9.11	Amortization of McGuire and Oconee	75,108	75,108
9.12	Amortization of Partially Disallowed Transmission Expansion Projects (TEP)	639,657	639,657
9.13	Amortization of Rotable Fleet Spare Regulatory Asset and Liability	2,321,941	2,321,941
9.14	Amortization of WWII Regulatory Assets	75,975	75,975
9.15	Deferral of ABSAT Depreciation (NC)	1,111,712	1,111,712
9.16	Deferral of ABSAT Depreciation (SC)	3,305,472	3,305,472
9.17	Deferral of AMI Depreciation Expense (SC)	868,642	868,642
9.18	Deferral of Depreciation Expense (2020 Storm)	117,943	117,943
9.19	Deferral of Depreciation Expense (2022 Storm) (NC)	39,963	39,963
9.20	Deferral of Grid Depreciation	14,845,879	14,845,879
9.21	Deferral of Solar Depreciation	1,060,406	1,060,406
9.22	ARO Depr Expense Deferred	269,734,763	269,734,763
10	DepreciationProvision TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)	1,491,942,923	1,491,942,923
11	Net Charges for Plant Retired:
12	BookCostOfRetiredPlant Book Cost of Plant Retired	632,998,080	(a) 632,998,080
13	CostOfRemovalOfPlant Cost of Removal	263,621,385	263,621,385
14	SalvageValueOfRetiredPlant Salvage (Credit)	104,763,728	104,763,728
15	NetChargesForRetiredPlant TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)	791,855,737	791,855,737
16	OtherAdjustmentsToAccumulatedDepreciation Other Debit or Cr. Items (Describe, details in footnote):
17.1	Storm Securitization NBV to Regulatory Asset	373,312	373,312
17.2	Non-AMI Meter Reserve Adjustment	8,264,511	8,264,511
17.3	Rotable Fleet Spare Transfers	1,413,370	1,413,370
17.4	ARO Transfers	14,549,402	14,549,402
17.5	Misc. Gain (Loss)	10,561	10,561
18	BookCostOfAssetRetirementCosts Book Cost or Asset Retirement Costs Retired
19	AccumulatedProvisionForDepreciationOfElectricUtilityPlant Balance End of Year (Enter Totals of lines 1, 10, 15, 16, and 18)	18,039,325,093	18,039,325,093
Section B. Balances at End of Year According to Functional Classification
20	AccumulatedDepreciationSteamProduction Steam Production	4,692,219,340	4,692,219,340
21	AccumulatedDepreciationNuclearProduction Nuclear Production	4,076,608,869	4,076,608,869
22	AccumulatedDepreciationHydraulicProductionConventional Hydraulic Production-Conventional	374,222,042	374,222,042
23	AccumulatedDepreciationHydraulicProductionPumpedStorage Hydraulic Production-Pumped Storage	622,356,643	622,356,643
24	AccumulatedDepreciationOtherProduction Other Production	1,274,962,793	1,274,962,793
25	AccumulatedDepreciationTransmission Transmission	1,507,834,720	1,507,834,720
26	AccumulatedDepreciationDistribution Distribution	5,127,810,720	5,127,810,720
27	AccumulatedDepreciationRegionalTransmissionAndMarketOperation Regional Transmission and Market Operation
28	AccumulatedDepreciationGeneral General	363,309,966	363,309,966
29	AccumulatedProvisionForDepreciationOfElectricUtilityPlant TOTAL (Enter Total of lines 20 thru 28)	18,039,325,093	18,039,325,093

FOOTNOTE DATA

(a) Concept: BookCostOfRetiredPlant

Intangible Plant Retirements of $31,485,364 not reported on FERC Page 219.

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
Report below investments in Account 123.1, Investments in Subsidiary Companies. Provide a subheading for each company and list thereunder the information called for below. Sub-TOTAL by company and give a TOTAL in columns (e), (f), (g) and (h). (a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity, and interest rate. (b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity date, and specifying whether note is a renewal. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for Account 418.1. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee and purpose of the pledge. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission, date of authorization, and case or docket number. Report column (f) interest and dividend revenues from investments, including such revenues from securities disposed of during the year. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or the other amount at which carried in the books of account if different from cost) and the selling price thereof, not including interest adjustment includible in column (f). Report on Line 42, column (a) the TOTAL cost of Account 123.1.
Line No.	DescriptionOfInvestmentsInSubsidiaryCompanies Description of Investment (a)	DateOfAcquisitionInvestmentsInSubsidiaryCompanies Date Acquired (b)	DateOfMaturityInvestmentsInSubsidiaryCompanies Date of Maturity (c)	InvestmentInSubsidiaryCompanies Amount of Investment at Beginning of Year (d)	EquityInEarningsOfSubsidiaryCompanies Equity in Subsidiary Earnings of Year (e)	InterestAndDividendRevenueFromInvestments Revenues for Year (f)	InvestmentInSubsidiaryCompanies Amount of Investment at End of Year (g)	InvestmentGainLossOnDisplosal Gain or Loss from Investment Disposed of (h)
1	The Eastover Companies Equity Contribution	06/30/1970		4,759,873			4,759,873
2	Claiborne Energy Services, Inc. Equity Contribution	03/01/1990		8,354,717			8,354,717
3	DEC NC Storm Recovery Funding Equity Contribution	08/11/2021
42	Total Cost of Account 123.1 $		Total	13,114,590			13,114,590

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

MATERIALS AND SUPPLIES
For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a); estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense clearing, if applicable.
Line No.	Account (a)	Balance Beginning of Year (b)	Balance End of Year (c)	Department or Departments which Use Material (d)
1	Fuel Stock (Account 151)	237,479,722	290,008,826	Electric
2	Fuel Stock Expenses Undistributed (Account 152)
3	Residuals and Extracted Products (Account 153)
4	Plant Materials and Operating Supplies (Account 154)
5	Assigned to - Construction (Estimated)	(a) 641,458,344	(b) 622,519,526	Electric
6	Assigned to - Operations and Maintenance
7	Production Plant (Estimated)	73,570,835	170,042,767	Electric
8	Transmission Plant (Estimated)	7,445,158	7,992,420	Electric
9	Distribution Plant (Estimated)	20,250,317	25,163,054	Electric
10	Regional Transmission and Market Operation Plant (Estimated)
11	Assigned to - Other (provide details in footnote)
12	TOTAL Account 154 (Enter Total of lines 5 thru 11)	742,724,654	825,717,767
13	Merchandise (Account 155)
14	Other Materials and Supplies (Account 156)	73,366	197,323	Electric
15	Nuclear Materials Held for Sale (Account 157) (Not applic to Gas Util)
16	Stores Expense Undistributed (Account 163)	(c) 46,246,014	(d) 48,743,849	Electric
17
18
19
20	TOTAL Materials and Supplies	1,026,377,024	1,164,273,119

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: PlantMaterialsAndOperatingSuppliesConstruction

Assigned to Construction: Production 497,602,019 Transmission 41,212,654 Distribution 102,643,671

(b) Concept: PlantMaterialsAndOperatingSuppliesConstruction

Assigned to Construction: Production 407,756,282 Transmission 53,694,768 Distribution 161,068,476

Stores Expense: Production 36,964,965 Transmission 2,658,880 Distribution 6,622,169

(d) Concept: StoresExpenseUndistributed

Stores Expense: Production 36,491,693 Transmission 3,063,265 Distribution 9,188,891

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

Allowances (Accounts 158.1 and 158.2)
Report below the particulars (details) called for concerning allowances. Report all acquisitions of allowances at cost. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k). Report on Line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40. Report on Line 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances. Report on Lines 8-14 the names of vendors/transferors of allowances acquired and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
		Current Year		Year One		Year Two		Year Three		Future Years		Totals
Line No.	SO2 Allowances Inventory (Account 158.1) (a)	No. (b)	Amt. (c)	No. (d)	Amt. (e)	No. (f)	Amt. (g)	No. (h)	Amt. (i)	No. (j)	Amt. (k)	No. (l)	Amt. (m)
1	Balance-Beginning of Year	(a) 1,097,352	415,945	107,370		105,402		79,275		2,133,620		3,523,019	415,945
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)
5	Returned by EPA
6
7
8	Purchases/Transfers:
9
10
11
12
13
14
15	Total
16
17	Relinquished During Year:
18	Charges to Account 509	3,106	743									3,106	743
19	Other:
20	Allowances Used
20.1	Allowances Used
21	Cost of Sales/Transfers:
22
23
24
25
26
27
28	Total	3,106	743									3,106	743
29	Balance-End of Year	(b) 1,094,246	415,202	107,370		105,402		79,275		2,133,620		3,519,913	415,202
30
31	Sales:
32	Net Sales Proceeds(Assoc. Co.)
33	Net Sales Proceeds (Other)
34	Gains
35	Losses
	Allowances Withheld (Acct 158.2)
36	Balance-Beginning of Year	4,130		4,130		4,130		4,130		111,510		128,030
37	Add: Withheld by EPA									4,130		4,130
38	Deduct: Returned by EPA
39	Cost of Sales	4,130										4,130
40	Balance-End of Year			4,130		4,130		4,130		115,640		128,030
41
42	Sales
43	Net Sales Proceeds (Assoc. Co.)
44	Net Sales Proceeds (Other)
45	Gains
46	Losses

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: AllowanceInventoryNumber

Beginning balance includes allowances for Cross State Air Pollution Rule and the Acid Rain Program.

(b) Concept: AllowanceInventoryNumber

Ending balance includes allowances for Cross State Air Pollution Rule and the Acid Rain Program.

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

Allowances (Accounts 158.1 and 158.2)
Report below the particulars (details) called for concerning allowances. Report all acquisitions of allowances at cost. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k). Report on Line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40. Report on Line 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances. Report on Lines 8-14 the names of vendors/transferors of allowances acquired and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
		Current Year		Year One		Year Two		Year Three		Future Years		Totals
Line No.	NOx Allowances Inventory (Account 158.1) (a)	No. (b)	Amt. (c)	No. (d)	Amt. (e)	No. (f)	Amt. (g)	No. (h)	Amt. (i)	No. (j)	Amt. (k)	No. (l)	Amt. (m)
1	Balance-Beginning of Year	19,233		18,894		18,401						56,528
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)
5	Returned by EPA
6
7
8	Purchases/Transfers:
9
10
11
12
13
14
15	Total
16
17	Relinquished During Year:
18	Charges to Account 509
19	Other:
20	Allowances Used
20.1	Allowances Used
21	Cost of Sales/Transfers:
22
23
24
25
26
27
28	Total
29	Balance-End of Year	(a)(b) 19,233		18,894		18,401						56,528
30
31	Sales:
32	Net Sales Proceeds(Assoc. Co.)
33	Net Sales Proceeds (Other)
34	Gains
35	Losses
	Allowances Withheld (Acct 158.2)
36	Balance-Beginning of Year
37	Add: Withheld by EPA
38	Deduct: Returned by EPA
39	Cost of Sales
40	Balance-End of Year
41
42	Sales
43	Net Sales Proceeds (Assoc. Co.)
44	Net Sales Proceeds (Other)
45	Gains
46	Losses

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: AllowanceInventoryNumber

Does not include renewable energy credits represented in account 0158120.

(b) Concept: AllowanceInventoryNumber

Does not include renewable energy credits consumption expense represented in account 0509213.

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

EXTRAORDINARY PROPERTY LOSSES (Account 182.1)
				WRITTEN OFF DURING YEAR
Line No.	DescriptionOfExtraordinaryPropertyLoss Description of Extraordinary Loss [Include in the description the date of Commission Authorization to use Acc 182.1 and period of amortization (mo, yr to mo, yr).] (a)	ExtraordinaryPropertyLossesNotYetRecognized Total Amount of Loss (b)	ExtraordinaryPropertyLossesRecognized Losses Recognized During Year (c)	ExtraordinaryPropertyLossesWrittenOffAccountCharged Account Charged (d)	ExtraordinaryPropertyLossesWrittenOff Amount (e)	ExtraordinaryPropertyLosses Balance at End of Year (f)
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
20	TOTAL

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)
				WRITTEN OFF DURING YEAR
Line No.	DescriptionOfUnrecoveredPlantAndRegulatoryStudyCosts Description of Unrecovered Plant and Regulatory Study Costs [Include in the description of costs, the date of COmmission Authorization to use Acc 182.2 and period of amortization (mo, yr to mo, yr)] (a)	UnrecoveredPlantAndRegulatoryStudyCostsNotYetRecognized Total Amount of Charges (b)	UnrecoveredPlantAndRegulatoryStudyCostsRecognized Costs Recognized During Year (c)	UnrecoveredPlantAndRegulatoryStudyCostsWrittenOffAccountCharged Account Charged (d)	UnrecoveredPlantAndRegulatoryStudyCostsWrittenOff Amount (e)	UnrecoveredPlantAndRegulatoryStudyCosts Balance at End of Year (f)
21	Lee Nuclear COLA - Wholesale	11,368,379		407	1,165,988	10,202,391
22	Auth - 10/22/2019
23	Amort Period - 10/19 to 09/31
24	Lee Nuclear COLA - NC Retail	207,244,235		407/421	20,810,369	186,433,866
25	Amort Period - 08/18 to 07/30
26	Lee Nuclear COLA - SC Retail	77,249,356		407/421	7,026,837	70,222,519
27	Amort Period - 06/19 to 03/31
28	Buck/Riverbend Early Retired Plnt	6,291,799		407	5,033,438	1,258,361
29	Auth - 7/25/2019
30	Amort Period - 10/15 to 03/23
49	TOTAL	302,153,769			34,036,632	268,117,137

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

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	State Studies 1	21,067.00	561600
3	Lochart Power - FAC	2,850.00
4	Woodleaf - FEA	2,046.00
5	Joanna Solar - FEA	1,280.00
6	Jonesville - SIS	8,670.00
7	Stony Knoll - SIS Solar	8,648.00
8	Oasis - SIS	1,735.00
9	Blue Ridge - SIS	1,020.00
10	Central EMC - SIS	46,038.00
11	NCEMC Davidson - FEA	3,284.00
12	Energy United - SIS	924.00
13	New River Light & Power - SIS	441.00
14	Buck - SIS	3,854.00
15	Bradely Solar - SIS	2,341.00
16	Oakboro - SIS	72.00
17	Princeton Solar - FEA	171.00
18	Broad River - SIS	8,741.00
19	NTE - SIS & WCU - SIS, Sugar, Dutchman, & Delancey Solar SIS	10,151.00
20	Reimbursements Transmission				561601
20	Total	12,491		0
21	Generation Studies
22	State Studies	137,714.61	561700
23	Broad River - FAC	102,471.00
24	Fresh Air Energy !!	19,470.00
25	Dutchman Creek Solar	4,491.00
26	Sugar Solar	587,854.00
27	Duel Solar	3,000.00
28	Turkey Creek Solar	3,000.00
29	Duke Energy Renewables Solar	6,000.00
30	Quaker Creek Farm Solar	18,132.00
31	Dogwood Farm Solar	3,000.00
32	Broad River Solar	25,306.00
33	Blackburn Solar	3,040.00
34	Delancey Solar	6,545.00
35	EDF Union Two	3,000.00
36	Okra Holding - SIS	21,675.00
37	Fairforest Solar	4,000.00
38	Mistflower - FEA	3,000.00
39	Nextera Solar	4,000.00
40	High Rock Solar	3,000.00
41	NCEMC - FEA	746.00
42	Silverstreet Solar - FEA	3,000.00
43	Pacolet Solar - FEA	3,000.00
44	Woodleaf	6,820.00
45	Hodgges Solar	5,617.00
46	Various Projects	1,239,043.39
47	Reimbursements Generation	1,985,601.00			561701
39	Total	229,832
40	Grand Total	217,341

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

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	Regulatory Asset Related to Income Taxes (Various)	431,501,703	30,362,472	282/283	25,099,697	436,764,478
2	Vacation Accrual NCUC Docket No. E-7, Sub 774	83,419,378	373,019			83,792,397
3	Closed Def Int Hedge - Asset - PSCSC Docket No. 2013-59-E	149,462,074		427	3,868,793	145,593,281
4	Retail portion - IRS Section 124 Asset Depreciation	1,547,369		403	75,975	1,471,394
5	Energy Efficiency Cost Recovery-NCUC Docket No. E-7, Sub 1050	32,890,263	66,263,450	421/456	33,373,187
6	Energy Efficiency Cost Recovery-PSCSC Docket No. 2011-420-E	4,786,082	19,354,345	421/456	14,568,263
7	Renewable Energy and Energy Portfolio-NCUC Docket No. E-7, Sub 1052-Standard Cost Deferral	9,313,327	1,641,061	407	3,834,706	7,119,682
8	Pension Non-Qualified-NCUC Docket No. E-100, Sub 112	3,829,018		253/926	1,501,703	2,327,315
9	Pension Qualified-NCUC Docket No. E-100, Sub 112	324,305,163	275,920,702	128/186/228/926	54,808,772	545,417,093
10	Interest Rate Swap-PSCSC Docket No. 2013-59-E			131
11	Natural Gas Hedging - MTM-NCUC Docket No. E-7, Sub 862-NCUC Docket No. E-7, Sub 1006-NCUC Docket No. E-7, Sub 1033	13,192,701	69,443,301			82,636,002
12	Buck and Bridgewater Deferred Costs-25 Year Amortization-NCUC Docket No. E-7, Sub 999-PSCSC Docket No. 2012-57-E	4,445,908		403/407/408/421/431/510/546	216,516	4,229,392
13	Dan River & Cliffside 6 Deferred Costs-Dan River - 4 year Amortization - NC /Dan River - 39 Year Amortization - SC /Cliffside 6 - 4 year Amortization - NC/Cliffside 6 - 35 Year Amortization - SC -NCUC Docket No. E-7, Sub 1029 -PSCSC Docket No. 2013-99-E	23,247,006		403/407/408/421/431/510	541,560	22,705,446
14	McGuire and Oconee Deferred Costs-McGuire - 4 Year Amortization - NC/McGuire - 43 Year Amortization - SC/Oconee - 28 Year Amortization - SC -NCUC Docket No. E-7, Sub 1029 -PSCSC Docket No. 2013-99-E	3,473,294		403/407/421/431	102,336	3,370,958
15	Nuclear Deferral-18-24 Months Amortization-NCUC Docket No. E-7, Sub 1026	73,035,629	63,262,677	517/519/520/523/524/528/529/530/531/532/921	53,743,286	82,555,020
16	Nuclear Deferral-18-24 Months Amortization-PSCSC Docket No. 2013-59-E	5,134,456	20,786,227	517/519/520/523/524/528/529/530/531/532/921	18,801,881	7,118,802
17	Billing System Deferral-NCUC Docket No. E-7, Sub 1026	656,028				656,028
18	Credit Card Program-PSCSC Docket No. 2018-319-E, Order No. 2019-323	1,175,021	11,438			1,163,583
19	Deferred Severance Costs-NCUC Docket No. E-7, Sub 1214	35,675,119		920	21,684,889	13,990,230
20	NC Rate Case CostsNCUC Docket No. E-7, Sub 909-NCUC Docket No. E-7, Sub 989-NCUC Docket No. E-7, Sub 1146	7,543,647		928	1,783,160	5,760,487
21	SC Rate Case Costs-PSCSC Docket No. 2009-226-E-PSCSC Docket No. 2011-271-E, Order No. 2012-77-PSCSC Docket No. 2018-319-E, Order No. 2019-323	1,723,170		928	298,873	1,424,297
22	Coal Ash Basin - ARO Deferral-NC Coal Ash Management Act of 2014-Consent Agreement with SCDHEC	819,346,891	329,523,712	182/403/407/411/426	232,732,350	916,138,253
23	Coal Ash Remediation Costs-NCUC Docket No. E-7, Sub 1146-PSCSC Docket No. 2016-196-E, Order No. 2016-490-PSCSC Docket No. 2018-319-E, Order No. 2019-323	54,201,584	210,203,752	182/407/426/501	10,197,145	274,602,481
24	Deferred Fuel-NCUC Docket No. E-7, Sub 1033	259,278,899	1,087,411,735	557	108,938,688	1,237,751,946
25	Deferred Fuel-PSCSC Docket No. 2014-3-E	79,889,621	296,567,114			376,456,735
26	NCUC Regulatory Fee-NCUC Docket No. M-100, Sub 142	1,515,014		928	555,412	959,602
27	SC Distributed Energy Resource Program-PSCSC Docket No. 2015-3-E	4,838,286	17,550	407	371,744	4,448,992
28	Rotable Fleet Spare-NCUC Docket No. E-7, Sub 986A-PSCSC Docket No. 2015-293-E	6,175,134	3,693,517	254/403	2,811,954	7,056,697
29	Advanced Metering Infrastructure-PSCSC Docket No. 2016-240-E	140,684,514	9,960,728	403/407/421/431	11,913,731	138,731,511
30	Coal Ash Spend-NCUC Docket No. E-7, Sub 1146-PSCSC Docket No. 2018-319-E, OrderNo. 2019-323	353,028,886		407/421	153,068,746	199,960,140
31	Customer Connect-NCUC Docket No. E-7, Sub 1146	59,143,171		407/421	4,150,398	54,992,773
32	Customer Connect-PSCSC Docket No. 2018-207-E, OrderNo. 2018-552	7,142,654		407/421	442,975	6,699,679
33	Lee Combined Cycle Deferrals-NCUC Docket No. E-7, Sub 1146	5,464,387		403/407/408/421/431	757,344	4,707,043
34	Lee Combined Cycle Deferrals-PSCSC Docket No. 2018-207-E, Order No. 2018-552	14,498,964		403/407/408/421	1,784,113	12,714,851
35	Ash Basin Strategic Action Team (ABSAT)-NCUC Docket No. E-7, Sub 1146	50,813,529	2,339,451	403/407/421/431	7,530,356	45,622,624
36	Ash Basin Strategic Action Team (ABSAT)-PSCSC Docket No. 2016-196-E, Order No. 2016-490	16,261,428	6,155,018	403/407/421/431	1,112,167	21,304,279
37	Carolinas West Primary District Control Center-PSCSC Docket No. 2018-207-E, Order No. 2018-552	3,034,082		403/407/421	113,444	2,920,638
38	NC Solar Rebate Program-NCUC Docket No. E-7, Sub 1166	16,938,660	4,391,400	407	1,063,498	20,266,562
39	CPRE Rider-NCUC Docket No. E-7, Sub 1170	128,697	1,282,984	407	525,102	886,579
40	NC Coal Inventory Rider-NCUC Docket No. E-7, Sub 1146	37,667		431/456	37,667
41	Cost of Removal Settlement-NCUC Docket No. E-7, Sub 1146	51,018,781		407	2,042,112	48,976,669
42	Cost of Removal Settlement-PSCSC Docket No. 2018-319-E, OrderNo. 2019-323	40,309,442		407	1,313,725	38,995,717
43	Grid Deferral (NC&SC)-NCUC Docket No. E-7, Sub 1214	16,006,575	25,519,238			41,525,813
44	Grid Deferral (NC&SC)-PSCSC Docket No. 2018-206-E, Order No. 2018-519	32,253,531	23,616,473	403/407/408/421	918,525	54,951,479
45	Depreciation Deferral-PSCSC Docket No. 2018-319-E, OrderNo. 2019-323	1,205,063		403/407	1,205,063
46	Hydro Loss Recovery-NCUC Docket No. E-7, Sub 1181	21,021,853		407	1,138,493	19,883,360
47	Hydro Loss Recovery-PSCSC Docket No. 2018-281-E, OrderNo. 2019-474	8,366,677				8,366,677
48	SC HB3659 Implementation-South Carolina-2019-H3659	1,912,790	399,323			2,312,113
49	Storm Reg Asset - Upfront Cost - NCUC Docket E-7, Sub 1243	363,282		232	363,282
50	NC NBV Retired Plant - NCUC Docket E-7, Sub 1214	47,284,520		407	9,407,929	37,876,591
51	Storm Securitization Return - NCUC Docket E-7, Sub 1243	21,380,627	21,380,627
52	Storm Contra Equity LT - NCUC Docket E-7 Sub 1243		20,174,168	421	822,496	19,351,672
53	Storm Contra Equity ST - NCUC Docket E-7 Sub 1243 - Amortization of Storm Securitization Equity Return		1,100,569			1,100,569
54	Other Deferred Costs		7,881			7,881
44	TOTAL	3,225,787,621	2,548,556,482		767,582,774	5,006,761,329

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

MISCELLANEOUS DEFFERED DEBITS (Account 186)
Report below the particulars (details) called for concerning miscellaneous deferred debits. For any deferred debit being amortized, show period of amortization in column (a) Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by classes.
				CREDITS
Line No.	Description of Miscellaneous Deferred Debits (a)	Balance at Beginning of Year (b)	Debits (c)	Credits Account Charged (d)	Credits Amount (e)	Balance at End of Year (f)
1	Demand Side Management Costs	1,190,194	803,177		543,130	930,147
2	Storm Costs	12,015,996	75,252,000	182	3,095,376	84,172,620
3	Renewables	2,976,266	665,915		1,123,387	3,433,738
4	I&D Insurance Receivable, net	631,731,357	255,658	131, 228	49,203,926	582,783,089
5	Pension Settlement Charges - Amort Per. 6/30/2019-9/30/2029	36,911,157	35,127,748	926	5,740,113	66,298,792
6	Equity Return on BPM Sharing	615,265	1,439		70,226	546,478
7	Combustion Turbine Generator	2,386,893	167,083		2,553,976
8	Pooled Inventory	4,534,508				4,534,508
9	Natural Gas Pipeline Upgrade - Amort Per. 11/2017-11/2025	417,290		547	106,542	310,748
10	Incremental Covid -19 Expenses	50,843,480	76,145,667	431, 903, 904, 923		126,989,147
11	ORS Avoided Cost Consultant	157,201				157,201
12	Other Minor Items	1,026,657	12,129,368		11,491,588	1,664,437
47	Miscellaneous Work in Progress	1,604,210				2,075,326
48	Deferred Regulatroy Comm. Expenses (See pages 350 - 351)	10,065,633	5,658,146		1,716,692	14,007,087
49	TOTAL	748,143,187				879,175,548

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

ACCUMULATED DEFERRED INCOME TAXES (Account 190)
Report the information called for below concerning the respondent’s accounting for deferred income taxes. At Other (Specify), include deferrals relating to other income and deductions.
Line No.	DescriptionOfAccumulatedDeferredIncomeTax Description and Location (a)	AccumulatedDeferredIncomeTaxes Balance at Beginning of Year (b)	AccumulatedDeferredIncomeTaxes Balance at End of Year (c)
1	Electric
7	Other	3,461,784,968	3,308,699,145
8	TOTAL Electric (Enter Total of lines 2 thru 7)	3,461,784,968	3,308,699,145
9	Gas
15	Other
16	TOTAL Gas (Enter Total of lines 10 thru 15)
17.1	Other (Specify)
17	Other (Specify)
18	TOTAL (Acct 190) (Total of lines 8, 16 and 17)	3,461,784,968	3,308,699,145

Notes

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

CAPITAL STOCKS (Account 201 and 204)
Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year. Give details concerning shares of any class and series of stock authorized to be issued by a regulatory commission which have not yet been issued. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or noncumulative. State in a footnote if any capital stock that has been nominally issued is nominally outstanding at end of year. Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which is pledged, stating name of pledgee and purpose of pledge.
Line No.	Class and Series of Stock and Name of Stock Series (a)	Number of Shares Authorized by Charter (b)	Par or Stated Value per Share (c)	Call Price at End of Year (d)	Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Shares (e)	Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Amount (f)	Held by Respondent As Reacquired Stock (Acct 217) Shares (g)	Held by Respondent As Reacquired Stock (Acct 217) Cost (h)	Held by Respondent In Sinking and Other Funds Shares (i)	Held by Respondent In Sinking and Other Funds Amount (j)
1	Common Stock (Account 201)
2
3
4
5	Total
6	Preferred Stock (Account 204)
7
8
9
10	Total
1	Capital Stock (Accounts 201 and 204) - Data Conversion
2
3
4
5	Total

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

2023-04-14

Year/Period of Report

End of:

2022

Other Paid-in Capital
1. Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a subheading for each account and show a total for the account, as well as a total of all accounts for reconciliation with the balance sheet, page 112. Explain changes made in any account during the year and give the accounting entries effecting such change. Donations Received from Stockholders (Account 208) - State amount and briefly explain the origin and purpose of each donation. Reduction in Par or Stated Value of Capital Stock (Account 209) - State amount and briefly explain the capital changes that gave rise to amounts reported under this caption including identification with the class and series of stock to which related. Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210) - Report balance at beginning of year, credits, debits, and balance at end of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related. Miscellaneous Paid-In Capital (Account 211) - Classify amounts included in this account according to captions that, together with brief explanations, disclose the general nature of the transactions that gave rise to the reported amounts.
Line No.	Item (a)	Amount (b)
1	DonationsReceivedFromStockholdersAbstract Donations Received from Stockholders (Account 208)
2	DonationsReceivedFromStockholders Beginning Balance Amount
3.1	IncreasesDecreasesFromSalesOfDonationsReceivedFromStockholders Increases (Decreases) from Sales of Donations Received from Stockholders
4	DonationsReceivedFromStockholders Ending Balance Amount
5	ReductionInParOrStatedValueOfCapitalStockAbstract Reduction in Par or Stated Value of Capital Stock (Account 209)
6	ReductionInParOrStatedValueOfCapitalStock Beginning Balance Amount
7.1	IncreasesDecreasesDueToReductionsInParOrStatedValueOfCapitalStock Increases (Decreases) Due to Reductions in Par or Stated Value of Capital Stock
8	ReductionInParOrStatedValueOfCapitalStock Ending Balance Amount
9	GainOrResaleOrCancellationOfReacquiredCapitalStockAbstract Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210)
10	GainOnResaleOrCancellationOfReacquiredCapitalStock Beginning Balance Amount
11.1	IncreasesDecreasesFromGainOrResaleOrCancellationOfReacquiredCapitalStock Increases (Decreases) from Gain or Resale or Cancellation of Reacquired Capital Stock
12	GainOnResaleOrCancellationOfReacquiredCapitalStock Ending Balance Amount
13	MiscellaneousPaidInCapitalAbstract Miscellaneous Paid-In Capital (Account 211)
14	MiscellaneousPaidInCapital Beginning Balance Amount	3,725,067,850
15.1	IncreasesDecreasesDueToMiscellaneousPaidInCapital Increases (Decreases) Due to Miscellaneous Paid-In Capital
16	MiscellaneousPaidInCapital Ending Balance Amount	3,725,067,850
17	OtherPaidInCapitalAbstract Historical Data - Other Paid in Capital
18	OtherPaidInCapitalDetail Beginning Balance Amount
19.1	IncreasesDecreasesInOtherPaidInCapital Increases (Decreases) in Other Paid-In Capital
20	OtherPaidInCapitalDetail Ending Balance Amount
40	OtherPaidInCapital Total	3,725,067,850

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

CAPITAL STOCK EXPENSE (Account 214)
Report the balance at end of the year of discount on capital stock for each class and series of capital stock. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars (details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Line No.	NameOfClassAndSeriesOfStock Class and Series of Stock (a)	CapitalStockExpense Balance at End of Year (b)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22	TOTAL

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

LONG-TERM DEBT (Account 221, 222, 223 and 224)
Report by Balance Sheet Account the details concerning long-term debt included in Accounts 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other Long-Term Debt. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds, and in column (b) include the related account number. For Advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate demand notes as such. Include in column (a) names of associated companies from which advances were received, and in column (b) include the related account number. For receivers' certificates, show in column (a) the name of the court and date of court order under which such certificates were issued, and in column (b) include the related account number. In a supplemental statement, give explanatory details for Accounts 223 and 224 of net changes during the year. With respect to long-term advances, show for each company: (a)principal advanced during year (b) interest added to principal amount, and (c) principal repaid during year. Give Commission authorization numbers and dates. If the respondent has pledged any of its long-term debt securities, give particulars (details) in a footnote, including name of the pledgee and purpose of the pledge. If the respondent has any long-term securities that have been nominally issued and are nominally outstanding at end of year, describe such securities in a footnote. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest expense in column (m). Explain in a footnote any difference between the total of column (m) and the total Account 427, Interest on Long-Term Debt and Account 430, Interest on Debt to Associated Companies. Give details concerning any long-term debt authorized by a regulatory commission but not yet issued.
Line No.	ClassAndSeriesOfObligationCouponRateDescription Class and Series of Obligation, Coupon Rate (For new issue, give commission Authorization numbers and dates) (a)	RelatedAccountNumber Related Account Number (b)	Principal Amount of Debt Issued (c)	LongTermDebtIssuanceExpensePremiumOrDiscount Total Expense, Premium or Discount (d)	LongTermDebtIssuanceExpenses Total Expense (e)	LongTermDebtPremium Total Premium (f)	LongTermDebtDiscount Total Discount (g)	NominalDateOfIssue Nominal Date of Issue (h)	DateOfMaturity Date of Maturity (i)	AmortizationPeriodStartDate AMORTIZATION PERIOD Date From (j)	AmortizationPeriodEndDate AMORTIZATION PERIOD Date To (k)	Outstanding (Total amount outstanding without reduction for amounts held by respondent) (l)	Interest for Year Amount (m)
1	Bonds (Account 221)
2	Series A 6% Snr Notes	221380	300,000,000		284,550		3,696,000	12/04/1998	12/01/2028	12/01/1998	12/01/2028	300,000,000	18,000,000
3	8.95% Series	221160	15,994,025		2,752			07/01/1991	07/01/2027	07/01/1991	07/01/2027	5,842,052	603,133
4	3.75% First Mortgage Bonds	221856	500,000,000		3,295,451		4,170,000	03/12/2015	06/01/2045	03/01/2015	06/01/2045	500,000,000	18,750,000
5	6.45% Senior Unsecured Notes	221240	350,000,000		871,004		2,161,255	10/08/2002	10/15/2032	10/01/2002	10/01/2032	350,000,000	22,575,000
6	2.5% First Mortgage Bonds	221857	500,000,000				195,000	03/11/2016	03/15/2023	03/01/2016	03/01/2023	500,000,000	12,500,000
7	3.875% First Mortgage Bonds	221858	500,000,000		3,195,974		1,765,000	03/11/2016	03/15/2046	03/01/2016	03/01/2046	500,000,000	19,375,000
8	6.1% Senior Unsecured Notes	221801	500,000,000		1,834,924		65,000	06/05/2007	06/01/2037	06/01/2007	06/01/2037	500,000,000	30,500,000
9	2.95% First Mortgage Bonds	221859	600,000,000		1,248,494		1,452,000	11/17/2016	12/01/2026	12/01/2016	12/01/2026	600,000,000	17,700,000
10	6.00% First Mortgage Bonds	221803	500,000,000		2,059,304		350,000	01/10/2008	01/15/2038	01/01/2008	01/01/2038	500,000,000	30,000,000
11	6.05% First Mortgage Bonds	221005	600,000,000		2,389,744		1,650,000	04/14/2008	04/15/2038	04/01/2008	04/01/2038	600,000,000	36,300,000
12	5.3% First Mortgage Bonds	221285	750,000,000		3,388,340		3,202,500	11/16/2009	02/15/2040	11/01/2009	02/01/2040	750,000,000	39,750,000
13	4.25% First Mortgage Bonds	221284	650,000,000		3,341,992		1,098,500	12/08/2011	12/15/2041	12/01/2011	12/01/2041	650,000,000	27,625,000
14	4.00% First Mortgage Bonds	221062	650,000,000		3,655,571		5,174,000	09/21/2012	09/30/2042	09/01/2012	09/01/2042	650,000,000	26,000,000
15	3.70% First Mortgage Bonds	221094	550,000,000		3,894,494		803,000	11/14/2017	12/01/2047	11/01/2017	12/01/2047	550,000,000	20,350,000
16	3.05% First Mortgage Bonds	221096	500,000,000				585,000	03/01/2018	03/15/2023	03/01/2018	03/01/2023	500,000,000	15,250,000
17	3.95% First Mortgage Bonds	221097	500,000,000		3,543,514		2,365,000	03/01/2018	03/15/2048	03/01/2018	03/01/2048	500,000,000	19,750,000
18	3.35% First Mortgage Bonds	221287	350,000,000				129,500	11/08/2018	05/15/2022	11/01/2018	05/01/2022		5,862,500
19	3.95% First Mortgage Bonds	221288	650,000,000		2,004,528		2,398,500	11/08/2018	11/15/2028	11/01/2018	11/01/2028	650,000,000	25,675,000
20	2.45% First Mortgage Bonds	221289	450,000,000		1,605,134		553,500	08/15/2019	08/15/2029	08/01/2019	08/01/2029	450,000,000	11,025,000
21	3.20% First Mortgage Bonds	221291	750,000,000		5,650,143	3,176,000	938,000	08/15/2019	08/15/2049	08/01/2019	08/01/2049	750,000,000	24,000,000
22	2.45% First Mortgage Bonds	221281	500,000,000		1,929,508		1,600,000	01/06/2020	02/01/2030	01/01/2020	02/01/2030	500,000,000	12,250,000
23	2.55% First Mortgage Bonds	221282	550,000,000		2,446,972		632,500	04/01/2021	04/15/2031	04/01/2021	04/15/2031	550,000,000	14,025,000
24	3.45% First Mortgage Bonds	221283	450,000,000		3,554,847		1,678,500	04/01/2021	04/15/2051	04/01/2021	04/15/2051	450,000,000	15,525,000
25	2.85% First Mortgage Bonds	221081	500,000,000		2,587,393		305,000	03/04/2022	03/15/2032	03/04/2022	03/15/2032	500,000,000	7,125,000
26	3.55% First Mortgage Bonds	221,082	650,000,000		5,326,966		2,034,500	03/04/2022	03/15/2052	03/04/2022	03/15/2052	650,000,000	11,537,500
27	Subtotal		12,815,994,025		58,111,599	3,176,000	39,002,255					12,455,842,052	482,053,133
28	Reacquired Bonds (Account 222)
29
30
31
32	Subtotal
33	Advances from Associated Companies (Account 223)
34	Duke Energy Corporation - 4.6058%	233006	300,000,000					10/01/2008	03/01/2025			300,000,000	14,995,561
35	Subtotal		300,000,000									300,000,000	14,995,561
36	Other Long Term Debt (Account 224)
37	Charlotte Metro Tower	224853	85,000,000		7,610,359			12/23/2019	12/01/2052	01/01/2020	12/01/2052	613,197,824	23,000,209
38	Other Long Term Debt (DERF)	224560	500,000,000		4,341,415			01/24/2022	01/24/2025	01/24/2022	01/24/2025	471,103,709	12,356,590
39	Subtotal		585,000,000		11,951,774							1,084,301,533	35,356,799
33	TOTAL		13,700,994,025									13,840,143,585	532,405,493

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
Line No.	Particulars (Details) (a)	Amount (b)
1	Net Income for the Year (Page 117)	1,600,993,370
2	Reconciling Items for the Year
3
4	Taxable Income Not Reported on Books
5	Subtotal
9	Deductions Recorded on Books Not Deducted for Return
10	Subtotal
14	Income Recorded on Books Not Included in Return
15	Subtotal
19	Deductions on Return Not Charged Against Book Income
20	See Below For Detailed List
21	AFUDC Equity Income	97,598,412
22	AFUDC Interest	50,078,031
23	Bad Debts	26,789,582
24	Benefits Accruals	131,244,198
25	Book Depreciation	1,064,702,340
26	Capitalized Hardware/Software	4,628,567
27	Capitalized Property Taxes	3,424,085
28	Cares Act Reserve	17,955,594
29	Charitable Contribution Carryovers/ Accruals	830,455
30	Charlotte Metro Tower Financing Arrangement	231,611,064
31	Coal Ash Spend, Net of Capitalized Portion	64,135,474
32	Contributions in Aid of Construction	74,760,719
33	COR Settlement	3,355,837
34	Cost of Coal Consumed	4,852,742
35	Cost of Removal	154,373,288
36	Deferred Compensation	448,456
37	Deferred Fuel	1,275,169,545
38	Deferred Revenue	414,214
39	Demand Side Management	85,357,748
40	Dividends Received Exclusion	1,090,000
41	End of Life Nuclear Fuel Cost Reserve	12,987,519
42	Environmental Reserves	595,249
43	Equipment/T&D Repairs	539,581,742
44	Extra Facility Lighting	1,467,915
45	Greensboro Transit Principal Payments	896,867
46	Impairment of Plant Assets	16,717,703
47	Other Impairment	14,092,484
48	Injuries & Damages Accrual	3,801,090
49	Investment Tax Credit Amortization	4,151,613
50	Lawsuiut Contingency	4,139,385
51	Lease Adjustments	23,023,483
52	Lobbying	2,700,000
53	Loss on Reacquired Debt	5,421,175
54	Meals & Entertainment	4,342,768
55	MGP Sites	4,171,473
56	Net Operating Loss	267,676,748
57	Non-Cash Overhead Basis Adjustment	38,872,973
58	Nuclear Decommissioning Contributions/Earnings	26,000,203
59	Nuclear Fuel Book Burned	247,614,928
60	Nuclear Insurance Reserve	2,591,805
61	Other	811,550
62	Plant License Renewal	5,208,288
63	Prepaid Expenses	2,217,077
64	Provision for Current Federal Income Taxes	71,282,442
65	Provision for Current State Income Taxes	5,686,038
66	Provision for Deferred Income Taxes	214,247,804
67	Rate Refunds	13,394,864
68	Regulatory Asset - ABSAT	148,054
69	Regulatory Asset - AMI/Non-AMI Meters	1,953,003
70	Regulatory Asset - COVID-19 Deferral	97,526,294
71	Regulatory Asset - Customer Connect	4,593,372
72	Regulatory Asset - CWDC Deferred Costs	113,444
73	Regulatory Asset - Depreciation Deferral	1,205,063
74	Regulatory Asset - Early Retired Plant	14,441,368
75	Regulatory Asset - Energy Efficiency	37,676,344
76	Regulatory Asset - FAS 158	247,088,417
77	Regulatory Asset - Grid Deferred Costs	48,217,186
78	Regulatory Asset - Hydro Impairment	1,138,494
79	Regulatory Asset - Lee CC Deferred Costs	2,541,456
80	Regulatory Asset - Nuclear COLA	29,003,194
81	Regulatory Asset - Nuclear Levelization	11,503,737
82	Regulatory Asset - Other Deferred Costs	852,531
83	Regulatory Asset - Rate Case Expenses	1,859,420
84	Regulatory Asset - Severance Non-Rate Base	21,684,889
85	Regulatory Asset - SC Solar Bill	399,324
86	Regulatory Asset - NC Solar Rebate Program	3,327,902
87	Regulatory Asset - Storm Securitization	33,162,359
88	Regulatory Asset/Liability - CPRE Rider	4,688,484
89	Regulatory Asset/Liability - Rotable Spare Parts	2,321,941
90	Regulatory Fee - North Carolina	555,412
91	Renewable Energy Liability	15,293,538
92	REPs Incremental Costs	1,331,144
93	Return on Solar Assets	159,379
94	Returns on Federal Excess Deferred Income Taxes	16,783,801
95	Returns on State Excess Deferred Income Taxes	3,844,386
96	SC Distributive Energy Resource Program	389,294
97	SC Storm Reserve Fund	20,416,841
98	Section 263A Adjustment	149,000,000
99	Severance Reserve	12,496,366
100	Storm Cost Deferrals	72,156,624
101	Surplus Materials Write-Off	6,240,081
102	Tax Depreciation	1,262,700,000
103	Tax Gain/Loss	158,780,000
104	Tax Interest Capitalized	49,550,738
105	Transportation Benefits	1,393,000
106	Subtotal	1,747,573,017
27	Federal Tax Net Income	146,579,647
28	Show Computation of Tax:
29	21% of $(146,579,647)	30,781,726
30	Prior Year Federal Tax Adjustments - Prior Year Tax True-Ups	40,500,716
31	Total Federal Income Tax	(a) 71,282,442

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: ComputationOfTax

INSTRUCTION 2 Allocations of consolidated tax liability are based on the percentage method of allocation under Treasury Regulation Section 1.1.502-33(d)(3), with a fixed percentage of 100 percent, in conjunction with the income method under Treasury Regulation Section 1.1552-1(a)(1). For members of the affiliated group, see corporations controlled by respondent, page 103.

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

TAXES ACCRUED, PREPAID AND CHARGES DURING YEAR
Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual, or estimated amounts of such taxes are known, show the amounts in a footnote and designate whether estimated or actual amounts. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.) Enter the amounts in both columns (g) and (h). The balancing of this page is not affected by the inclusion of these taxes. Include in column (g) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued, (b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than accrued and prepaid tax accounts. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained. If any tax (exclude Federal and State income taxes) covers more than one year, show the required information separately for each tax year, identifying the year in column (d). Enter all adjustments of the accrued and prepaid tax accounts in column (i) and explain each adjustment in a foot- note. Designate debit adjustments by parentheses. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending transmittal of such taxes to the taxing authority. Report in columns (l) through (o) how the taxes were distributed. Report in column (o) only the amounts charged to Accounts 408.1 and 409.1 pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 409.1 pertaining to other utility departments and amounts charged to Accounts 408.2 and 409.2. Also shown in column (o) the taxes charged to utility plant or other balance sheet accounts. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
					BALANCE AT BEGINNING OF YEAR					BALANCE AT END OF YEAR		DISTRIBUTION OF TAXES CHARGED
Line No.	DescriptionOfTaxesAccruedPrepaidAndCharged Kind of Tax (See Instruction 5) (a)	TypeOfTax Type of Tax (b)	TaxJurisdiction State (c)	TaxYear Tax Year (d)	TaxesAccrued Taxes Accrued (Account 236) (e)	PrepaidTaxes Prepaid Taxes (Include in Account 165) (f)	TaxesCharged Taxes Charged During Year (g)	TaxesPaid Taxes Paid During Year (h)	TaxAdjustments Adjustments (i)	TaxesAccrued Taxes Accrued (Account 236) (j)	PrepaidTaxes Prepaid Taxes (Included in Account 165) (k)	TaxesAccruedPrepaidAndCharged Electric (Account 408.1, 409.1) (l)	IncomeTaxesExtraordinaryItems Extraordinary Items (Account 409.3) (m)	AdjustmentsToRetainedEarnings Adjustment to Ret. Earnings (Account 439) (n)	TaxesIncurredOther Other (o)
1	Social Security Tax	Federal Tax	Federal	2022	22,760,042		67,191,491	93,775,382		3,823,849		38,826,105			28,365,386
2	Highway Use	Federal Tax	Federal	2022
3	Subtotal Federal Tax				22,760,042		67,191,491	93,775,382		3,823,849		38,826,105			28,365,386
4	SC Kilowatt Hour	State Tax	SC	2022	627,404		9,818,926	9,543,469		902,861		9,818,926
5	Subtotal State Tax				627,404		9,818,926	9,543,469		902,861		9,818,926
6	NC Property Tax	Property Tax	NC	2022	201,613	3,382,066	115,091,420	114,801,557	(a) 263,055	159,701	3,313,346	116,022,299			930,879
7	SC Property Tax	Property Tax	SC	2022	149,622,690		139,365,093	141,699,789		147,287,994		138,993,663			371,430
8	Subtotal Property Tax				149,824,303	3,382,066	254,456,513	256,501,346	263,055	147,447,695	3,313,346	255,015,962			559,449
9	Fed Unemployment Tax	Unemployment Tax	Federal	2022	8,675		397,189	396,170		9,694		514,761			117,572
10	Other Unemployment Tax	Unemployment Tax	Other	2022	2,928		15,350	47,468		29,190		16,177			827
11	NC Unemployment Tax	Unemployment Tax	NC	2022	2,192		102,721	101,559		3,354		111,817			9,096
12	SC Unemployment Tax	Unemployment Tax	SC	2022	1,837		142,710	142,789		1,758		143,486			776
13	Subtotal Unemployment Tax				15,632		657,970	687,986		14,384		786,241			128,271
14	NC Sales and Use Tax	Sales And Use Tax	NC	2022	1,970,988		33,838,475	34,202,037		1,607,426		389,100			34,227,575
15	SC Sales and Use Tax	Sales And Use Tax	SC	2022	980,649		11,740,742	13,612,390		890,999		78,589			11,662,153
16	Other Sales and Use Tax	Sales And Use Tax	Other	2022			1,582	1,582				74,746			73,164
17	Subtotal Sales And Use Tax				2,951,637		45,577,635	47,812,845		716,427		385,257			45,962,892
18	Fed Income Tax	Income Tax	Federal	2022	59,040,688		71,282,442	42,421,825		30,180,071		73,073,642			1,791,200
19	NC Income Tax	Income Tax	NC	2022	1,240,180		6,335,212	9,546,346		4,451,314		6,445,698			110,488
20	SC Income Tax	Income Tax	SC	2022	5,487,442		6,676,546	7,199,755		6,010,651		4,083,662			2,592,882
21	Subtotal Income Tax				65,768,310		84,294,200	59,167,926		40,642,036		83,603,002			691,194
22	SC Franchise Tax	Franchise Tax	SC	2022	2,597,772		9,522,720	9,831,510		2,906,562		9,522,720
23	NC Franchise Tax	Franchise Tax	NC	2022	13,823,064		27,624,785	28,859,577		12,588,272		28,130,559			505,774
24	Subtotal Franchise Tax				11,225,292		37,147,505	38,691,087		9,681,710		37,653,279			505,774
25	NC Miscellaneous Tax	Miscellaneous Other Tax	NC	2022	13,792		94,621	94,612		13,783		94,630
26	SC Miscellaneous Tax	Miscellaneous Other Tax	SC	2022	0
27	Subtotal Miscellaneous Other Tax				13,792		94,621	94,612		13,783		94,630
28	SC Muncipal License Tax	Other State Tax	SC	2022	71,853					71,853
29	Subtotal Other State Tax				71,853					71,853
40	TOTAL				253,086,975	3,382,066	330,650,461	387,938,801	263,055	195,466,860	3,313,346	258,206,884			72,443,590

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: TaxAdjustments

Offset to account 419

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g). Include in column (i) the average period over which the tax credits are amortized.
			Deferred for Year		Allocations to Current Year's Income
Line No.	Account Subdivisions (a)	Balance at Beginning of Year (b)	Account No. (c)	Amount (d)	Account No. (e)	Amount (f)	Adjustments (g)	Balance at End of Year (h)	Average Period of Allocation to Income (i)	ADJUSTMENT EXPLANATION (j)
1	Electric Utility
2	3%
3	4%	1,167,617			411.4	128,590		1,039,027
4	7%
5	8%	7,592,175			411.4	435,327		7,156,848
6	10%	41,057,337			411.4	2,187,078		38,870,259
7	15%	125,000,000						125,000,000
8	30%	110,941,225	190	16,270,060	411.4	1,400,618	1,318,811	127,129,478		To adjust the amount of additional investment tax credit accrued in the 2021 tax provision related to the Gaston and Maiden Creek solar projects to equal the amount claimed on the 2021 Federal Tax Return that was filed during 2022.
8	TOTAL Electric (Enter Total of lines 2 thru 7)	285,758,354		16,270,060		4,151,613	1,318,811	299,195,612
9	Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
10	10%	1,248,450						1,248,450
11										`
47	OTHER TOTAL	1,248,450						1,248,450
48	GRAND TOTAL	287,006,804		16,270,060		4,151,613	1,318,811	300,444,062

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

OTHER DEFERRED CREDITS (Account 253)
Report below the particulars (details) called for concerning other deferred credits. For any deferred credit being amortized, show the period of amortization. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
			DEBITS
Line No.	Description and Other Deferred Credits (a)	Balance at Beginning of Year (b)	Contra Account (c)	Amount (d)	Credits (e)	Balance at End of Year (f)
1	Decommissioning Costs	691,988,212	128	374,286,923	256,609,792	574,311,081
2	Prepaid Extra Facilities Lighting	20,275,024	454	3,571,434	5,039,348	21,742,938
3	Shareholder Contributions	4,000,000	107, 131, 146	4,000,000
4	Catawba - Wateree relicensing	6,066,449	146	42,302	332,521	6,356,668
5	Environmental Reserves	15,966,900	108	1,846,603	6,025,046	20,145,343
6	JEA Option Agreement	7,500,000				7,500,000
7	Deferred Debt Return - Solar	7,459,153	403, 408, 550	40,846	215,646	7,633,953
8	SC Coal Insurance Proceeds	30,658,006	421, 431, 923	886,020	2,912,528	32,684,514
9	NC State Excess Deferred Income Taxes - SC Retail	51,314,774			1,640,956	52,955,730
10	NC State Excess Deferred Income Taxes Gross Up - SC Retail	15,632,312			499,893	16,132,205
11	Executive Cash Balance Plan	10,752,576		2,453,465	471,733	8,770,844
12	Other	20,401,004		10,664,594	22,871,072	32,607,482
47	TOTAL	882,014,410		397,792,187	296,618,535	780,840,758

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)

Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to amortizable property.
For other (Specify),include deferrals relating to other income and deductions.
Use footnotes as required.

CHANGES DURING YEAR

ADJUSTMENTS

Debits

Credits

Line No.

Account

(a)

Balance at Beginning of Year

(b)

Amounts Debited to Account 410.1

(c)

Amounts Credited to Account 411.1

(d)

Amounts Debited to Account 410.2

(e)

Amounts Credited to Account 411.2

(f)

Account Credited

(g)

Amount

(h)

Account Debited

(i)

Amount

(j)

Balance at End of Year

(k)

Accelerated Amortization (Account 281)

Electric

Defense Facilities

Pollution Control Facilities

Other

5.1

Other (provide details in footnote):

TOTAL Electric (Enter Total of lines 3 thru 7)

Gas

Defense Facilities

Pollution Control Facilities

Other

12.1

Other (provide details in footnote):

TOTAL Gas (Enter Total of lines 10 thru 14)

Other

16.1

Other

16.2

Other

TOTAL (Acct 281) (Total of 8, 15 and 16)

Classification of TOTAL

Federal Income Tax

State Income Tax

Local Income Tax

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282)
Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to property not subject to accelerated amortization. For other (Specify),include deferrals relating to other income and deductions. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Account 282
2	Electric	4,764,247,775	666,832,521	468,875,048	16,230,524	5,511,855		(a) 10,291,571		(b) 7,555,977	4,970,188,323
3	Gas
4	Other (Specify)
5	Total (Total of lines 2 thru 4)	4,764,247,775	666,832,521	468,875,048	16,230,524	5,511,855		10,291,571		7,555,977	4,970,188,323
6
7
8
9	TOTAL Account 282 (Total of Lines 5 thru 8)	4,764,247,775	666,832,521	468,875,048	16,230,524	5,511,855		10,291,571		7,555,977	4,970,188,323
10	Classification of TOTAL
11	Federal Income Tax	4,469,424,781	563,147,988	398,853,637	14,174,345	4,427,557		2,735,734		5,169,175	4,651,370,829
12	State Income Tax	294,822,994	103,684,533	70,021,411	2,056,179	1,084,298		13,027,305		2,386,802	318,817,494
13	Local Income Tax

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxLiabilitiesOtherPropertyAdjustmentsDebitedToAccount

Offset to account 253 1,579,026Offset to account 254 8,712,545Total 10,291,571

(b) Concept: AccumulatedDeferredIncomeTaxLiabilitiesOtherPropertyAdjustmentsCreditedToAccount

Offset to account 182 4,038,825Offset to account 254 2,495,717Offset to account 146 1,021,435Total 7,555,977

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283)
Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts recorded in Account 283. For other (Specify),include deferrals relating to other income and deductions. Provide in the space below explanations for Page 276. Include amounts relating to insignificant items listed under Other. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Account 283
2	Electric
3	Electric	2,409,305,919	507,154,172	358,646,289	11,822	125,535	254	15,076		(a) 67,407,467	2,490,277,546
4		60,800,253								(b) 60,800,253
5		18,152,610								(c) 18,152,610
9	TOTAL Electric (Total of lines 3 thru 8)	2,330,353,056	507,154,172	358,646,289	11,822	125,535		15,076		11,545,396	2,490,277,546
10	Gas
11
12
13
14
15
16
17	TOTAL Gas (Total of lines 11 thru 16)
18	TOTAL Other
19	TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)	2,330,353,056	507,154,172	358,646,289	11,822	125,535		15,076		11,545,396	2,490,277,546
20	Classification of TOTAL
21	Federal Income Tax	2,126,913,188	440,408,498	310,892,575	11,822	60,420		13,156		886,954	2,255,480,403
22	State Income Tax	203,439,868	66,745,674	47,753,714		65,115		1,920		12,432,350	234,797,143
23	Local Income Tax
NOTES

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxLiabilitiesOtherAdjustmentsCreditedToAccount

Offset to account 182 1,223,950Offset to account 254 7,631,263Offset to account 253 2,361,656 Offset to account 146 328,527 Transfer of balance from line 4 (60,800,253)Transfer of balance from line 5 (18,152,610)Total (67,407,467)

(b) Concept: AccumulatedDeferredIncomeTaxLiabilitiesOtherAdjustmentsCreditedToAccount

Transfer of balance to line 3

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

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	Regulatory Liability Related to Income Taxes - Amortization period follows the book depreciable asset lives	83,413,156	190/282/410/411	1,053,219	5,049,130	87,409,067
2	NC State Excess Deferred Income Taxes - NC Retail - NCUC Docket No. E-7, Sub 1146:- Amortization from August 2018 - July 2022NCUC Docket No. E-7, Sub 1214:- Amortization from June 2021 - May 2023	55,521,222	190/410/411	48,209,413		7,311,809
3	ARO Regulatory Liability- NCUC Docket No E-7 Sub 723- PSCSC Docket No. 2003-84-E	1,592,466,043	128/182	2,238,527,447	1,223,273,555	577,212,151
4	I&D Regulatory Liability- NCUC Docket No E-7, Sub 1026- PSCSC Docket 2013-59-E	27,686,252	228	1,496,161		26,190,091
5	TCJA Federal Excess Deferred Income Taxes - Wholesale - Production Amortization: Beginning January 2018Contract Nos: ER20-1715-000, 1716-000, 2077-000, 2200-000,2716-000, 2398-000, ER21-688-000Transmission Amortization: Beginning June 2020Contract No. ER20-1837-000-Unprotected PPE: 20 years-Unprotected Non-PPE: 5 years-Protected PPE: ARAM, 25-50 years	195,179,555	411	10,784,626		184,394,929
6	NC REC Liability-NCUC Docket No. E-7, Sub 1052	70,190,508	407	25,531,973	41,687,230	86,345,765
7	Mark to Market Fuel	154,027,047			47,042,325	201,069,372
8	SC Storm Reserve Fund-PSCSC Docket No.2013-59-E	9,988,304	407	25,809,646	5,392,805	30,405,145
9	Deferred Fuel-PSCSC Docket No. 2014-3-E	129,382	182	129,382
10	OPEB Liability-FERC Docket No. AI07-1-000	43,508,439	926	2,445,864	2,834,697	43,897,272
11	Reg Liability-NQ - FAS 106 - Medical-FERC Docket No. AI07-1-000	7,061	926	3,096	30,518	20,361
12	NDTF Liability- NCUC Docket No E-7 Sub 723-PSCSC Docket No 2003-84-E	460,505,258				460,505,258
13	End of Life Reserves-NCUC Docket No. E-7, Sub 1026	136,889,964	182	37,676,344	136,281,658	235,495,278
14	Coal Ash Wholesale Settlement Refund	1,597,367				1,597,367
15	TCJA Federal Excess Deferred Income Taxes - NC Retail - NCUC Docket No. E-7, Sub 1214:-Protected PPE: ARAM, 25-50 years, Beginning August 2020-Unprotected: Amortization from June 2021 - May 2026	1,458,620,317	411	164,505,077		1,294,115,240
16	TCJA Federal Excess Deferred Income Taxes - Gross Up	627,565,734	190	62,670,310	3,881,137	568,776,561
17	TCJA Federal Excess Deferred Income Taxes - SC Retail - PSCSC Docket No. 2018-319-EOrder Nos.: 2019-323, 2020-347, 2021-328, 2022-338-Protected PPE: ARAM, 25-50 years, Beginning June 2019-Unprotected PPE: 20 years, Beginning June 2019-Unprotected Non-PPE: 5 years, Beginning June 2019	495,233,688	411	30,432,450		464,801,238
18	NC State Excess Deferred Income Taxes - SC Retail - PSCSC Docket No. 2018-319-EOrder Nos.: 2019-323, 2020-347, 2021-328, 2022-338-Amortization from June 2019 - May 2024	42,151,212	190/410/411	17,348,800		24,802,412
19	Interest Rate Swap Reg Liability	54,623,250	175	163,028,289	202,607,955	94,202,916
20	Levelized NC State SEDIT Rider - NC Retail - NCUC Docket No. E-7, Sub 1146:- Amortization from August 2018 - July 2022NCUC Docket No. E-7, Sub 1214:- Amortization from June 2021 - May 2023	4,190,847	407	5,455,765	1,611,379	346,461
21	Job Retention Rider-NCUC Docket No. E-7, Subs 1146 & 1152-Amortization from June 2020 - May 2021	818			818
22	Rotable Fleet Spare-Docket No. E-7, Sub 986A-Amortization ends July 2022	490,013	182/403	490,013
23	Levelized NC FEDIT Rider - NC Retail - NCUC Docket No. E-7, Sub 1214:- Amortization from June 2021 - May 2026	14,604,737	407	30,255,685	47,039,486	31,388,538
24	NC State Excess Deferred Income Taxes (2.5%-0%) - NC Retail	150,416,152			8,890,597	159,306,749
25	NC State Excess Deferred Income Taxes (2.5%-0%) - Wholesale	21,414,651			2,467,188	18,947,463
26	NC State Excess Deferred Income Taxes (2.5%-0%) - Gross Up	52,345,796			1,956,800	54,302,596
27	NC NBV Retired Plant - NCUC Docket E-7, Sub 1214	47,284,520				47,284,520
28	CPRE (ST) - NCUC Docket E-7, Sub 1262	3,888,035	407	1,900,584	7,346,950	9,334,401
29	Storm Securitization Service/Admin - LT - NCUC Docket E-7, Sub 1243	13,702	186/431	151	135,619	149,170
30	Closed Def Int Hedge-Asset - NCUC Docket E-7, Sub 1026, PSCSC Docket 2013-59-E				54,433,851	54,433,851
31	Storm Reg Liability - Upfront Costs - NCUC Docket E-7, Sub 1243				370,773	370,773
41	TOTAL	5,783,960,664		2,867,754,295	1,787,400,095	4,703,606,464

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

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	3,227,110,506	3,030,038,042	30,153,490	28,953,191	2,378,411	2,350,215
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)	2,320,198,467	2,150,753,617	29,843,638	28,487,261	395,996	392,440
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)	1,237,261,240	1,135,298,521	20,993,344	20,663,400	6,066	5,963
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting	46,253,125	43,210,988	286,547	287,062	11,238	16,202
7	OtherSalesToPublicAuthoritiesAbstract (445) Other Sales to Public Authorities
8	SalesToRailroadsAndRailwaysAbstract (446) Sales to Railroads and Railways
9	InterdepartmentalSalesAbstract (448) Interdepartmental Sales		44
10	SalesToUltimateConsumersAbstract TOTAL Sales to Ultimate Consumers	6,830,823,338	6,359,301,212	81,277,019	78,390,914	2,791,711	2,764,820
11	SalesForResaleAbstract (447) Sales for Resale	695,809,121	530,223,666	9,637,002	9,405,970		19
12	SalesOfElectricityAbstract TOTAL Sales of Electricity	7,526,632,459	6,889,524,878	90,914,021	87,796,884	2,791,711	2,764,839
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds	70,141,424	47,416,972
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds	7,596,773,883	6,936,941,850	90,914,021	87,796,884	2,791,711	2,764,839
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts	6,387,401	4,401,734
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	6,911,139	4,488,914
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power
19	RentFromElectricProperty (454) Rent from Electric Property	113,277,874	109,743,089
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	30,167,034	65,265,587
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	117,998,299	110,324,161
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	214,407,679	163,692,311
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	7,811,181,562	7,100,634,161
Line12, column (b) includes $ 93,926,671 of unbilled revenues.
Line12, column (d) includes 1,262,788 MWH relating to unbilled revenues

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

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:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	RS-Residential Service	16,150,619	1,795,197,033	1,327,250	12,168	0.1112
2	RS-CPP-Residential Service, Critical Peak Pricing (Pilot)	14	1,507	4	3,500	0.1076
3	RS-TC-Residential Service, Time of Use with Critical Peak Pricing	3,472	371,806	306	11,334	0.1071
4	RS-TOU-CPP-Residential Service, Time of Use Critical Peak Pricing (Pilot)	1,451	213,440	196	7,409	0.1471
5	RS-TOUD-DPP-Residential Service, Time of Use Demand Daily Peak Pricing (Pilot)		4
6	RE-Residential Service, Electric Water Heating and Space Conditioning	12,855,997	1,301,422,631	1,005,642	12,784	0.1012
7	RE-CPP-Residential Service, Electric Water Heating and Space Conditioning, Critical Peak Pricing (Pilot)	16	1,470	3	4,800	0.0919
8	RE-TC-Residential Service for All-Electric Customers, Time of Use with Critical Peak Pricing	4,484	439,405	355	12,634	0.0980
9	RE-TOU-CPP-Residential Service, Electric Water Heating and Space Conditioning, Time of Use Critical Peak Pricing (Pilot)
10	RE-TOUD-DPP-Residential Service, Electric Water Heating and Space Conditioning, Time of Use Demand Daily Peak Pricing (Pilot)	1	89		6,000	0.0890
11	ES-Residential Service, Energy Star	211,777	21,928,747	16,240	13,041	0.1035
12	RT-Residential Service, Time-of-Use	50,743	4,552,474	2,247	22,584	0.0897
13	WC-Residential Service, Water Heating, Controlled/Submetered
14	OL-General Service, Outdoor Lighting Service	101,217	36,223,765	226,482	447	0.3579
15	Duplicate Customers			200,314
41	TOTAL Billed Residential Sales	29,379,791	3,160,352,363	2,378,411	12,353	0.1076
42	TOTAL Unbilled Rev. (See Instr. 6)	773,699	66,758,143			0.0863
43	TOTAL	30,153,490	3,227,110,506	2,378,411	12,353	0.1070

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
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	TOTAL Billed Small or Commercial
42	TOTAL Unbilled Rev. Small or Commercial (See Instr. 6)
43	TOTAL Small or Commercial	29,843,638	2,320,198,467	395,996

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
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	TOTAL Billed Large (or Ind.) Sales
42	TOTAL Unbilled Rev. Large (or Ind.) (See Instr. 6)
43	TOTAL Large (or Ind.)	20,993,344	1,237,261,240	6,066

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	SGS-Small General Service	5,821,176	670,366,475	329,281	17,678	0.1152
2	SGS-CPP-Small General Service, Critical Peak Pricing (Pilot)	1	301		3,000	0.3010
3	SGS-TC-Small General Service, Time of Use with Critical Peak Pricing	809	106,593	73	11,108	0.1318
4	SGS-TOU-CPP-Small General Service, Time of Use Critical Peak Pricing (Pilot)	14	1,410		33,600	0.1007
5	SGS-TOUD-DPP-Small General Service, Time of Use Demand Daily Peak Pricing (Pilot)
6	BC-General Service, Building Construction Service	31,581	5,070,179	12,330	2,561	0.1605
7	LGS-Large General Service	6,168,864	496,071,999	10,946	563,555	0.0804
8	TS-Traffic Signal Service	12,692	3,055,310	7,562	1,678	0.2407
9	I-Industrial Service	3,502,337	258,783,749	4,696	745,747	0.0739
10	OPT-E-Optional Power Service, Time of Use, Energy-Only (Pilot)	12,427	766,756	17	723,903	0.0617
11	OPT-V-Optional Power Service, Time of Use with Voltage Differential	34,422,026	1,998,389,327	22,368	1,538,930	0.0581
12	HP-Hourly Pricing for Incremental Load
13	PG-Parallel Generation	3,605	705,044	7	554,615	0.1956
14	S-Unmetered Sign (Nantahala)	37	2,883	4	9,061	0.0779
15	OL-General Service, Outdoor Lighting Service	376,260	97,860,834	76,928	4,891	0.2601
16	Duplicate Customers			62,150
41	TOTAL Billed Commercial and Industrial Sales	50,351,829	3,531,180,860	402,062	125,234	0.0701
42	TOTAL Unbilled Rev. (See Instr. 6)	485,153	26,278,847			0.0542
43	TOTAL	50,836,982	3,557,459,707	402,062	125,234	0.0700

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	FL-General Service, Floodlighting Service	0	0	0	0
2	OL-General Service, Outdoor Lighting Service	2,012	511,144	263	7,655	0.2540
3	GL-Government Lighting Service	0	0	0	0
4	PL-General Service, Street and Public Lighting Service	280,513	44,787,673	10,879	24,961	0.1597
5	NL-Nonstandard Lighting Service	86	64,627	96	896	0.7515
6	Duplicate Customers
41	TOTAL Billed Public Street and Highway Lighting	282,611	45,363,444	11,238	25,148	0.1605
42	TOTAL Unbilled Rev. (See Instr. 6)	3,936	889,681			0.2260
43	TOTAL	286,547	46,253,125	11,238	25,148	0.1614

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	Interdepartmental - Account 448
41	TOTAL Billed Interdepartmental Sales
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
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	TOTAL Billed Provision For Rate Refunds
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL		70,141,424

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
41	TOTAL Billed - All Accounts	80,014,231	6,736,896,667	2,791,711	162,734	0.0842
42	TOTAL Unbilled Rev. (See Instr. 6) - All Accounts	1,262,788	93,926,671			0.0744
43	TOTAL - All Accounts	81,277,019	6,830,823,338	2,791,711	162,734	0.0840

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

SALES FOR RESALE (Account 447)
Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the Purchased Power schedule (Page 326). Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the purchaser. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or setter can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less than five years. SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one year or less. LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years. OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote. AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (g) through (k). In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. Report in column (g) the megawatt hours shown on bills rendered to the purchaser. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k) the total charge shown on bills rendered to the purchaser. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,line 24. Footnote entries as required and provide explanations following all required data.
					ACTUAL DEMAND (MW)			REVENUE
Line No.	Name of Company or Public Authority (Footnote Affiliations) (a)	Statistical Classification (b)	FERC Rate Schedule or Tariff Number (c)	Average Monthly Billing Demand (MW) (d)	Average Monthly NCP Demand (e)	Average Monthly CP Demand (f)	Megawatt Hours Sold (g)	Demand Charges ($) (h)	Energy Charges ($) (i)	Other Charges ($) (j)	Total ($) (h+i+j) (k)
1	Blue Ridge Electric Membership Corporation	RQ	315	174	218	184	1,204,823	31,888,567	45,581,288		77,469,855
2	Blue Ridge Electric Membership Corporation	AD	315					1,211,744	527,192		1,738,936
3	Central Electric Power Cooperative, Inc.	RQ	336	802	858	855	4,245,179	147,421,228	153,632,891		301,054,119
4	Central Electric Power Cooperative, Inc.	AD	336				638	4,151,528	1,524,238		5,675,766
5	City of Concord	AD	327
6	City of Kings Mountain	AD	331
7	City of Greenwood, SC	AD	334
8	Haywood Electric Membership Corporation	RQ	335	25	29	25	148,312	4,279,636	5,372,844		9,652,480
9	Haywood Electric Membership Corporation	AD	335				4,720	437,952	159,042		596,995
10	Lockhart Power Company	RQ	332	35	60	30	496,746	5,003,246	17,986,302		22,989,548
11	Lockhart Power Company	AD	332					962,584	120,449		1,083,033
12	North Carolina Electric Membership Corporation	RQ	326	60	60	60	391,093	12,312,415	14,160,804		26,473,218
13	North Carolina Electric Membership Corporation	AD	326				0	604,160	145,646		749,806
14	North Carolina Municipal Power Agency 1	OS	318				6,341	1,050,000	714,061		1,764,061
15	North Carolina Municipal Power Agency 1	AD	318
16	Piedmont Electric Membership Corporation	RQ	316	87	86	83	415,409	14,537,123	15,041,245		29,578,367
17	Piedmont Electric Membership Corporation	AD	316					689,426	150,012		839,437
18	Piedmont Municipal Power Agency	RQ	340
19	Piedmont Municipal Power Agency	AD	340
20	Rutherford Electric Membership Corporation	RQ	317	207	215	215	982,924	37,481,535	36,994,587		74,476,123
21	Rutherford Electric Membership Corporation	AD	317					1,620,868	346,675		1,967,543
22	Town of Dallas	RQ	328	13	13	12	71,533	2,080,741	2,671,781		4,752,521
23	Town of Dallas	AD	328					60,830	25,768		86,598
24	Town of Due West	RQ	329	2	2	2	13,674	353,816	495,122		848,938
25	Town of Due West	AD	329					16,563	4,851		21,413
26	Town of Forest City	RQ	330	15	18	14	103,920	2,405,807	3,880,718		6,286,525
27	Town of Forest City	AD	330					130,680	37,554		168,233
28	Town of Highlands	RQ	337	9	9	9	54,614	1,860,313	2,081,804		3,942,117
29	Town of Highlands	AD	337					49,006	19,500		68,506
30	Town of Prosperity	RQ	333
31	Town of Prosperity	AD	333					62,983			62,983
32	Western Carolina University	RQ	338
33	Western Carolina University	AD	338					87,179.36	19,094		106,274
34	Broad River Energy, LLC	OS	4				4,565			591,158	591,158
35	Cargill-Alliant, LLC	OS	4				233			2	2
36	Macquarie Energy, LLC	OS	4				3,457
37	North Carolina Municipal Power Agency 1	OS	4				5,260			95,055	95,055
38	Piedmont Municipal Power Agency	OS	4				10,585			603,242	603,242
39	Southern Power Company - Rowan Plant	OS	4				6,308			1,409,633	1,409,633
40	Southern Power Company - Cleveland Plant	OS	4				6,560			1,014,171	1,014,171
41	North Carolina Electric Membership Corporation	OS	273				320,419		26,219,788		26,219,788
42	Associated Electric Cooperative, Inc.	OS	5				41		2,552		2,552
43	Carolina Power Partners	OS	6				150		8,800		8,800
44	Central Electric Power Cooperative, Inc.	OS	6	115			3,450	5,267,000.00	271,111		5,538,111
45	Central Electric Power Cooperative, Inc.	AD	6
46	Dominion Energy South Carolina, Inc.	OS	5				1,382		209,983		209,983
47	Dominion Energy South Carolina, Inc.	OS	294				3,020		522,805		522,805
48	Macquarie Energy, LLC	OS	5				20,545		1,459,360		1,459,360
49	PJM Settlement, Inc.	OS	5				200		16,952		16,952
50	PJM Settlement, Inc.	AD	5
51	Southern Company Services, Inc.	OS	5				1,409		112,627		112,627
52	South Carolina Electric & Gas Company	OS	5							4	4
53	South Carolina Public Service Authority	OS	5							4	4
54	South Carolina Public Service Authority	OS	293				4,767		417,282		417,282
55	Tennessee Valley Authority	OS	5				90		5,926		5,926
56	Tennessee Valley Authority	OS	306				8,648		1,924,600		1,924,600
57	The Energy Authority, Inc.	OS	5				1,474		83,368		83,368
58	Brookfield Energy Marketing LP	OS	4
59	Brookfield Renewable	OS	4							15,525	15,525
60	Carolina Power Partners	OS	4							604,923	604,923
61	City of Kings Mountain	OS	4							1,971	1,971
62	City of Concord	OS	4							12,924	12,924
63	City of Greenwood, SC	OS	4							3,542	3,542
64	City of Seneca, South Carolina	OS	4							2,429	2,429
65	Eagle Energy Partners	OS	4							1,809	1,809
66	Energy United Electric Membership Corporation	OS	4							4,138	4,138
67	Exelon Generation Co., LLC	OS	4							22,293	22,293
68	Lockhart Power Company	OS	4							61	61
69	Macquarie Energy	OS	4							29,375	29,375
70	Mercuria Energy American	OS	4							2,620	2,620
71	Morgan Stanley Capital Group Inc.	OS	4							7,839	7,839
72	North Carolina Electric Membership Corporation	OS	4							106,981	106,981
73	New River Power & Light	OS	4							2,784	2,784
74	Rainbow Energy	OS	4							1,838	1,838
75	South Carolina Electric & Gas Company	OS	4							96	96
76	South Carolina Public Service Authority	OS	4							1,453	1,453
77	Southern Wholesale	OS	4							20,027	20,027
78	Tennessee Valley Authority	OS	4							1	1
79	The Energy Authority, Inc.	OS	4							14,880	14,880
80	Westar Energy, Inc.	OS	4
81	Western Carolina University	OS	4							639	639
82	Duke Energy Progress, Inc.	LF	341				1,104,079	17,512.11	108,895,192		108,912,704
83	Duke Energy Progress, Inc.	AD	341						2,823		2,823
84	Duke Energy Progress, Inc.	OS	10				1,150		106,271		106,271
85	Intra-company SEEM Transmission									24,769	24,769
15	Subtotal - RQ						8,128,227	259,624,426	297,899,386		557,523,812
16	Subtotal-Non-RQ						1,508,775	3,750,990	137,887,833	4,148,465	138,285,309
17	Total						9,637,002	255,873,436	435,787,220	4,148,465	695,809,121

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line No.	Account (a)	Amount for Current Year (b)	Amount for Previous Year (c) (c)
1	PowerProductionExpensesAbstract 1. POWER PRODUCTION EXPENSES
2	SteamPowerGenerationAbstract A. Steam Power Generation
3	SteamPowerGenerationOperationAbstract Operation
4	OperationSupervisionAndEngineeringSteamPowerGeneration (500) Operation Supervision and Engineering	10,909,633.00	10,740,984
5	FuelSteamPowerGeneration (501) Fuel	279,478,829.00	442,607,622
6	SteamExpensesSteamPowerGeneration (502) Steam Expenses	44,991,017.00	42,564,723
7	SteamFromOtherSources (503) Steam from Other Sources
8	SteamTransferredCredit (Less) (504) Steam Transferred-Cr.
9	ElectricExpensesSteamPowerGeneration (505) Electric Expenses	6,603,307.00	6,291,489
10	MiscellaneousSteamPowerExpenses (506) Miscellaneous Steam Power Expenses	10,670,348.00	9,836,774
11	RentsSteamPowerGeneration (507) Rents
12	Allowances (509) Allowances	22,255,128.00	28,905,745
13	SteamPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 4 thru 12)	374,908,262	540,947,337
14	SteamPowerGenerationMaintenanceAbstract Maintenance
15	MaintenanceSupervisionAndEngineeringSteamPowerGeneration (510) Maintenance Supervision and Engineering	12,209,835.00	11,438,707
16	MaintenanceOfStructuresSteamPowerGeneration (511) Maintenance of Structures	14,653,117.00	15,242,880
17	MaintenanceOfBoilerPlantSteamPowerGeneration (512) Maintenance of Boiler Plant	23,775,577.00	30,683,997
18	MaintenanceOfElectricPlantSteamPowerGeneration (513) Maintenance of Electric Plant	14,142,375.00	11,917,580
19	MaintenanceOfMiscellaneousSteamPlant (514) Maintenance of Miscellaneous Steam Plant	4,335,722.00	3,357,160
20	SteamPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 15 thru 19)	69,116,626	72,640,324
21	PowerProductionExpensesSteamPower TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)	444,024,888	613,587,661
22	NuclearPowerGenerationAbstract B. Nuclear Power Generation
23	NuclearPowerGenerationOperationAbstract Operation
24	OperationSupervisionAndEngineeringNuclearPowerGeneration (517) Operation Supervision and Engineering	37,910,788.00	38,069,607
25	NuclearFuelExpense (518) Fuel	250,765,424.00	261,462,415
26	CoolantsAndWater (519) Coolants and Water	7,715,936.00	7,505,800
27	SteamExpensesNuclearPowerGeneration (520) Steam Expenses	40,987,125.00	38,058,467
28	SteamFromOtherSourcesNuclearPowerGeneration (521) Steam from Other Sources
29	SteamTransferredCreditNuclearPowerGeneration (Less) (522) Steam Transferred-Cr.
30	ElectricExpensesNuclearPowerGeneration (523) Electric Expenses	21,293,052.00	21,039,593
31	MiscellaneousNuclearPowerExpenses (524) Miscellaneous Nuclear Power Expenses	153,717,895.00	164,981,901
32	RentsNuclearPowerGeneration (525) Rents
33	NuclearPowerGenerationOperationsExpense TOTAL Operation (Enter Total of lines 24 thru 32)	512,390,220	531,117,783
34	NuclearPowerGenerationMaintenanceAbstract Maintenance
35	MaintenanceSupervisionAndEngineeringNuclearPowerGeneration (528) Maintenance Supervision and Engineering	45,632,433.00	47,919,645
36	MaintenanceOfStructuresNuclearPowerGeneration (529) Maintenance of Structures	6,298,248.00	7,155,071
37	MaintenanceOfReactorPlantEquipmentNuclearPowerGeneration (530) Maintenance of Reactor Plant Equipment	65,197,739.00	64,589,158
38	MaintenanceOfElectricPlantNuclearPowerGeneration (531) Maintenance of Electric Plant	38,198,078.00	36,780,883
39	MaintenanceOfMiscellaneousNuclearPlant (532) Maintenance of Miscellaneous Nuclear Plant	42,873,148.00	41,273,719
40	NuclearPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 35 thru 39)	198,199,646	197,718,476
41	PowerProductionExpensesNuclearPower TOTAL Power Production Expenses-Nuclear. Power (Enter Total of lines 33 & 40)	710,589,866	728,836,259
42	HydraulicPowerGenerationAbstract C. Hydraulic Power Generation
43	HydraulicPowerGenerationOperationAbstract Operation
44	OperationSupervisionAndEngineeringHydraulicPowerGeneration (535) Operation Supervision and Engineering	7,718,771.00	7,828,085
45	WaterForPower (536) Water for Power
46	HydraulicExpenses (537) Hydraulic Expenses	1,481,203.00	1,272,408
47	ElectricExpensesHydraulicPowerGeneration (538) Electric Expenses	5,781,205.00	5,374,592
48	MiscellaneousHydraulicPowerGenerationExpenses (539) Miscellaneous Hydraulic Power Generation Expenses	10,442,947.00	9,430,035
49	RentsHydraulicPowerGeneration (540) Rents
50	HydraulicPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 44 thru 49)	22,461,720	21,360,304
51	HydraulicPowerGenerationContinuedAbstract C. Hydraulic Power Generation (Continued)
52	HydraulicPowerGenerationMaintenanceAbstract Maintenance
53	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration (541) Mainentance Supervision and Engineering	2,635,779.00	2,581,470
54	MaintenanceOfStructuresHydraulicPowerGeneration (542) Maintenance of Structures	482,348.00	670,833
55	MaintenanceOfReservoirsDamsAndWaterways (543) Maintenance of Reservoirs, Dams, and Waterways	2,339,336.00	3,528,982
56	MaintenanceOfElectricPlantHydraulicPowerGeneration (544) Maintenance of Electric Plant	5,396,900.00	5,021,121
57	MaintenanceOfMiscellaneousHydraulicPlant (545) Maintenance of Miscellaneous Hydraulic Plant	4,823,588.00	3,225,723
58	HydraulicPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 53 thru 57)	15,677,951	15,028,129
59	PowerProductionExpensesHydraulicPower TOTAL Power Production Expenses-Hydraulic Power (Total of Lines 50 & 58)	38,139,671	36,388,433
60	OtherPowerGenerationAbstract D. Other Power Generation
61	OtherPowerGenerationOperationAbstract Operation
62	OperationSupervisionAndEngineeringOtherPowerGeneration (546) Operation Supervision and Engineering	6,131,457.00	5,865,266
63	Fuel (547) Fuel	1,742,469,543.00	781,911,186
64	GenerationExpenses (548) Generation Expenses	6,716,230.00	5,925,214
64.1	OperationOfEnergyStorageEquipment (548.1) Operation of Energy Storage Equipment	9,485,908.00	9,244,747
65	MiscellaneousOtherPowerGenerationExpenses (549) Miscellaneous Other Power Generation Expenses	33,284.00	68,373
66	RentsOtherPowerGeneration (550) Rents
67	OtherPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 62 thru 67)	1,764,836,422	803,014,786
68	OtherPowerGenerationMaintenanceAbstract Maintenance
69	MaintenanceSupervisionAndEngineeringOtherPowerGeneration (551) Maintenance Supervision and Engineering	5,318,218.00	5,221,418
70	MaintenanceOfStructures (552) Maintenance of Structures	5,788,550.00	6,428,872
71	MaintenanceOfGeneratingAndElectricPlant (553) Maintenance of Generating and Electric Plant	18,850,301.00	9,227,948
71.1	MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration (553.1) Maintenance of Energy Storage Equipment	5,927,581.00	5,916,014
72	MaintenanceOfMiscellaneousOtherPowerGenerationPlant (554) Maintenance of Miscellaneous Other Power Generation Plant
73	OtherPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 69 thru 72)	35,884,650	26,794,252
74	PowerProductionExpensesOtherPower TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)	1,800,721,072	829,809,038
75	OtherPowerSuplyExpensesAbstract E. Other Power Supply Expenses
76	PurchasedPower (555) Purchased Power	1,003,902,989.00	414,254,099
76.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations
77	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching	45,580.00	16,539
78	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	1,152,221,411.00	205,220,606
79	OtherPowerSupplyExpense TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)	148,272,842	209,050,032
80	PowerProductionExpenses TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74 & 79)	2,845,202,655	2,417,671,423
81	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
82	TransmissionExpensesOperationAbstract Operation
83	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	18,031	18,921
85	LoadDispatchReliability (561.1) Load Dispatch-Reliability	1,723,714	1,489,407
86	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	8,852,354	8,825,339
87	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling	352,744	364,119
88	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services
89	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development	157,261	266,364
90	TransmissionServiceStudies (561.6) Transmission Service Studies	12,491	572
91	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies	229,832	1,554
92	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services
93	StationExpensesTransmissionExpense (562) Station Expenses	3,105,361	2,842,461
93.1	OperationOfEnergyStorageEquipmentTransmissionExpense (562.1) Operation of Energy Storage Equipment
94	OverheadLineExpense (563) Overhead Lines Expenses	1,578,726	804,165
95	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses	0
96	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	5,054,288	3,313,375
97	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	9,023,777	9,903,096
98	RentsTransmissionElectricExpense (567) Rents	173,658	161,672
99	TransmissionOperationExpense TOTAL Operation (Enter Total of Lines 83 thru 98)	30,257,255	27,991,045
100	TransmissionMaintenanceAbstract Maintenance
101	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering
102	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	685,725	504,747
103	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware	191,613	74,394
104	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software	2,570,207	3,036,301
105	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment
106	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	8,460,223	8,417,582
107.1	MaintenanceOfEnergyStorageEquipmentTransmission (570.1) Maintenance of Energy Storage Equipment
108	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	14,688,192	14,980,824
109	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines	51,226	57,262
110	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant		393
111	TransmissionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 101 thru 110)	26,544,734	26,956,979
112	TransmissionExpenses TOTAL Transmission Expenses (Total of Lines 99 and 111)	56,801,989	54,948,024
113	RegionalMarketExpensesAbstract 3. REGIONAL MARKET EXPENSES
114	RegionalMarketExpensesOperationAbstract Operation
115	OperationSupervision (575.1) Operation Supervision
116	DayAheadAndRealTimeMarketAdministration (575.2) Day-Ahead and Real-Time Market Facilitation
117	TransmissionRightsMarketAdministration (575.3) Transmission Rights Market Facilitation
118	CapacityMarketAdministration (575.4) Capacity Market Facilitation
119	AncillaryServicesMarketAdministration (575.5) Ancillary Services Market Facilitation
120	MarketMonitoringAndCompliance (575.6) Market Monitoring and Compliance
121	MarketFacilitationMonitoringAndComplianceServices (575.7) Market Facilitation, Monitoring and Compliance Services
122	RentsRegionalMarketExpenses (575.8) Rents
123	RegionalMarketOperationExpense Total Operation (Lines 115 thru 122)
124	RegionalMarketExpensesMaintenanceAbstract Maintenance
125	MaintenanceOfStructuresAndImprovementsRegionalMarketExpenses (576.1) Maintenance of Structures and Improvements
126	MaintenanceOfComputerHardware (576.2) Maintenance of Computer Hardware
127	MaintenanceOfComputerSoftware (576.3) Maintenance of Computer Software
128	MaintenanceOfCommunicationEquipmentRegionalMarketExpenses (576.4) Maintenance of Communication Equipment
129	MaintenanceOfMiscellaneousMarketOperationPlant (576.5) Maintenance of Miscellaneous Market Operation Plant
130	RegionalMarketMaintenanceExpense Total Maintenance (Lines 125 thru 129)
131	RegionalMarketExpenses TOTAL Regional Transmission and Market Operation Expenses (Enter Total of Lines 123 and 130)
132	DistributionExpensesAbstract 4. DISTRIBUTION EXPENSES
133	DistributionExpensesOperationAbstract Operation
134	OperationSupervisionAndEngineeringDistributionExpense (580) Operation Supervision and Engineering	1,943,595.00	1,369,497
135	LoadDispatching (581) Load Dispatching	4,696,338.00	6,340,945
136	StationExpensesDistribution (582) Station Expenses	1,891,788.00	2,330,680
137	OverheadLineExpenses (583) Overhead Line Expenses	2,078,002.00	1,240,518
138	UndergroundLineExpenses (584) Underground Line Expenses	11,421,383.00	12,205,086
138.1	OperationOfEnergyStorageEquipmentDistribution (584.1) Operation of Energy Storage Equipment	12,509.00	17,412
139	StreetLightingAndSignalSystemExpenses (585) Street Lighting and Signal System Expenses	10,447,467.00	10,252,838
140	MeterExpenses (586) Meter Expenses	10,339,662.00	9,833,201
141	CustomerInstallationsExpenses (587) Customer Installations Expenses	31,231,950.00	42,979,815
142	MiscellaneousDistributionExpenses (588) Miscellaneous Expenses	147,550.00	40,233
143	RentsDistributionExpense (589) Rents
144	DistributionOperationExpensesElectric TOTAL Operation (Enter Total of Lines 134 thru 143)	74,210,244	86,610,225
145	DistributionExpensesMaintenanceAbstract Maintenance
146	MaintenanceSupervisionAndEngineering (590) Maintenance Supervision and Engineering	2,328,808.00	1,864,702
147	MaintenanceOfStructuresDistributionExpense (591) Maintenance of Structures		607
148	MaintenanceOfStationEquipment (592) Maintenance of Station Equipment	3,699,527.00	4,119,875
148.1	MaintenanceOfEnergyStorageEquipment (592.2) Maintenance of Energy Storage Equipment
149	MaintenanceOfOverheadLines (593) Maintenance of Overhead Lines	199,127,648.00	142,374,880
150	MaintenanceOfUndergroundLines (594) Maintenance of Underground Lines	9,888,115.00	10,473,233
151	MaintenanceOfLineTransformers (595) Maintenance of Line Transformers	1,462,696.00	2,497,401
152	MaintenanceOfStreetLightingAndSignalSystems (596) Maintenance of Street Lighting and Signal Systems	11,406,734.00	12,064,849
153	MaintenanceOfMeters (597) Maintenance of Meters	2,899,434.00	2,166,269
154	MaintenanceOfMiscellaneousDistributionPlant (598) Maintenance of Miscellaneous Distribution Plant	160,373.00	1,016,422
155	DistributionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 146 thru 154)	230,973,335	176,578,238
156	DistributionExpenses TOTAL Distribution Expenses (Total of Lines 144 and 155)	305,183,579	263,188,463
157	CustomerAccountsExpensesAbstract 5. CUSTOMER ACCOUNTS EXPENSES
158	CustomerAccountsExpensesOperationsAbstract Operation
159	SupervisionCustomerAccountExpenses (901) Supervision	59,756.00	264,274
160	MeterReadingExpenses (902) Meter Reading Expenses	1,595,086.00	1,151,033
161	CustomerRecordsAndCollectionExpenses (903) Customer Records and Collection Expenses	91,601,346.00	92,798,934
162	UncollectibleAccounts (904) Uncollectible Accounts	34,706,095.00	24,812,044
163	MiscellaneousCustomerAccountsExpenses (905) Miscellaneous Customer Accounts Expenses	28,244.00	316,249
164	CustomerAccountExpenses TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)	127,990,527	119,342,534
165	CustomerServiceAndInformationalExpensesAbstract 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166	CustomerServiceAndInformationalExpensesOperationAbstract Operation
167	SupervisionCustomerServiceAndInformationExpenses (907) Supervision
168	CustomerAssistanceExpenses (908) Customer Assistance Expenses	172.00	520
169	InformationalAndInstructionalAdvertisingExpenses (909) Informational and Instructional Expenses	232,234.00	269,563
170	MiscellaneousCustomerServiceAndInformationalExpenses (910) Miscellaneous Customer Service and Informational Expenses	15,607,879.00	14,148,039
171	CustomerServiceAndInformationExpenses TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)	15,840,285	14,418,122
172	SalesExpenseAbstract 7. SALES EXPENSES
173	SalesExpenseOperationAbstract Operation
174	SupervisionSalesExpense (911) Supervision	106.00	2,005
175	DemonstratingAndSellingExpenses (912) Demonstrating and Selling Expenses	16,721,229.00	17,000,912
176	AdvertisingExpenses (913) Advertising Expenses	175,290.00	347,428
177	MiscellaneousSalesExpenses (916) Miscellaneous Sales Expenses	200,575.00	287,978
178	SalesExpenses TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)	17,097,200	17,638,323
179	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
180	AdministrativeAndGeneralExpensesOperationAbstract Operation
181	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	167,806,750.00	195,035,407
182	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	93,293,539.00	94,314,905
183	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit	28,582,669.00	35,689,398
184	OutsideServicesEmployed (923) Outside Services Employed	58,595,223.00	63,656,112
185	PropertyInsurance (924) Property Insurance	15,417,510.00	5,002,254
186	InjuriesAndDamages (925) Injuries and Damages	30,671,930.00	21,571,197
187	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	51,716,610.00	79,751,982
188	FranchiseRequirements (927) Franchise Requirements
189	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	16,905,233.00	15,704,752
190	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.	31,709,480.00	30,821,868
191	GeneralAdvertisingExpenses (930.1) General Advertising Expenses	6,135,350.00	6,055,556
192	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	10,074,116.00	24,998,896
193	RentsAdministrativeAndGeneralExpense (931) Rents	42,507,639.00	45,299,914
194	AdministrativeAndGeneralOperationExpense TOTAL Operation (Enter Total of Lines 181 thru 193)	412,683,519	424,877,409
195	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
196	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	1,756,912.00	1,412,377
197	AdministrativeAndGeneralExpenses TOTAL Administrative & General Expenses (Total of Lines 194 and 196)	414,440,431	426,289,786
198	OperationsAndMaintenanceExpensesElectric TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 156, 164, 171, 178, and 197)	3,782,556,666	3,313,496,675

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

PURCHASED POWER (Account 555)
Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years. SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less. LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years. EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges. OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each adjustment. AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. Report in column (g) the megawatthours shown on bills rendered to the respondent, excluding purchases for energy storage. Report in column (h) the megawatthours shown on bills rendered to the respondent for energy storage purchases. Report in columns (i) and (j) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. Report demand charges in column (k), energy charges in column (l), and the total of any other types of charges, including out-of-period adjustments, in column (m). Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (n) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (m) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. The data in columns (g) through (n) must be totaled on the last line of the schedule. The total amount in columns (g) and (h) must be reported as Purchases on Page 401, line 10. The total amount in column (i) must be reported as Exchange Received on Page 401, line 12. The total amount in column (j) must be reported as Exchange Delivered on Page 401, line 13. Footnote entries as required and provide explanations following all required data.
					Actual Demand (MW)				POWER EXCHANGES		COST/SETTLEMENT OF POWER
Line No.	NameOfCompanyOrPublicAuthorityProvidingPurchasedPower Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	RateScheduleTariffNumber Ferc Rate Schedule or Tariff Number (c)	AverageMonthlyBillingDemand Average Monthly Billing Demand (MW) (d)	AverageMonthlyNonCoincidentPeakDemand Average Monthly NCP Demand (e)	AverageMonthlyCoincidentPeakDemand Average Monthly CP Demand (f)	MegawattHoursPurchasedOtherThanStorage MegaWatt Hours Purchased (Excluding for Energy Storage) (g)	MegawattHoursPurchasedForEnergyStorage MegaWatt Hours Purchased for Energy Storage (h)	EnergyReceivedThroughPowerExchanges MegaWatt Hours Received (i)	EnergyDeliveredThroughPowerExchanges MegaWatt Hours Delivered (j)	DemandChargesOfPurchasedPower Demand Charges ($) (k)	EnergyChargesOfPurchasedPower Energy Charges ($) (l)	OtherChargesOfPurchasedPower Other Charges ($) (m)	SettlementOfPower Total (k+l+m) of Settlement ($) (n)
1	1001 Ebenezer Church Solar, LLC	LU	1				9,176					589,359		589,359
2	1008 Matthews Solar, LLC	LU	1				9,187					595,378		595,378
3	1045 Tomlin Mill Solar, LLC	LU	1				8,773					564,778		564,778
4	1047 LITTLE MOUNTAIN SOLAR, LLC	LU	1				4,975					318,611		318,611
5	1051 Lucky Solar LLC	LU	1				5,711					370,357		370,357
6	231 DIXON 74 SOLAR I, LLC	LU	1				4,018					268,774		268,774
7	232 LONG BRANCH 29 SOLAR I LLC	LU	1				2,433					162,707		162,707
8	233 Randolph 74 Solar I, LLC	LU	1				1,136					91,052		91,052
9	ACE SOLAR CENTER, LLC SOLTAGE, LLC	LU	1				2,083					145,043		145,043
10	ACTIVE CONCEPTS LLC	LU	1				90					2,385		2,385
11	Adams Solar LLC - SC	LU	1				4,413					263,185		263,185
12	AKS REAL ESTATE HOLDINGS LLC	LU	1				3					127		127
13	ALAMANCE HYDRO, LLC	LU	1				77					4,592		4,592
14	AMETHYST SOLAR , LLC	LU	1				5,969					396,353		396,353
15	Anderson Solar Farm, LLC	LU	1				4,566					271,161		271,161
16	ANGEL SOLAR , LLC	LU	1				8,801					590,806		590,806
17	APPLE DATA CENTER PV2	IU	1				37,764					2,251,066		2,251,066
18	APPLE INC CLAREMONT PV3	LU	1				34,222					2,044,144		2,044,144
19	APPLE ONE, LLC	LU	1				9,927					662,918		662,918
20	APPLE PV1	LU	1				37,349					2,698,134		2,698,134
21	Aquenergy - Piedmont Hydro	LU	1				58					1,839		1,839
22	Aquenergy - Ware Shoals Hydro	LU	1				2,459					79,858		79,858
23	ARARAT ROCK SOLAR, LLC	LU	1				5,776					445,307		445,307
24	ARNDT FARM LLC	LU	1				9,349					719,749		719,749
25	ASHLEY SOLAR	LU	1				7,477					499,765		499,765
26	ATOOD SOLAR II, LLC	LU	1				4,284					255,068		255,068
27	AUDREY SOLAR , LLC	LU	1				4,942					328,384		328,384
28	AUGUSTA SOLAR, LLC	LU	1				4,142					247,758		247,758
29	AUTEN ROAD FARM,LLC	LU	1				10,111					673,337		673,337
30	AVALON HYDROPOWER, LLC	LU	1				4,169					235,171		235,171
31	AYRSHIRE HOLDINGS LLC	LU	1				33,024					2,027,918		2,027,918
32	BAKATSIAS SOLAR FARM, LLC	LU	1				7,896					510,114		510,114
33	BANK OF AMERICA	LU	1				10					656		656
34	BATTLEGROUND SOLAR I, LLC	LU	1				5,818					381,246		381,246
35	BEACON SOLAR ONE, LLC	LU	1				398					11,846		11,846
36	BEACON SOLAR TWO, LLC	LU	1				1,357					41,317		41,317
37	BEETLE SOLAR, LLC	LU	1				6,786					449,059		449,059
38	BELWOOD FARM, LLC	LU	1				6,955					527,209		527,209
39	BERNHARDT FURNITURE COMPANY	LU	1				1,621					109,006		109,006
40	BETH SOLAR LLC	LU	1				7,932					525,987		525,987
41	BG STEWART SOLAR FARM, LLC	LU	1				8,879					623,173		623,173
42	BIG BOY SOLAR,LLC	LU	1				4,813					320,038		320,038
43	BIOMERIEUX, INC	LU	1				132					4,869		4,869
44	BLACKSBURG ENVIRONMENTAL AND ENERGY, LLC	IU	1				158					9,397		9,397
45	BLUE BRIGHT VENTURES, LLC	LU	1				120					8,031		8,031
46	Bluebird Solar LLC	LU	1				6,985					353,041		353,041
47	BOYD LEON HYDER	LU	1				7					180		180
48	BRANCH,JAMES DAVID DR	LU	1				11					313		313
49	BRIAN M ATTIS	LU	1				3					76		76
50	BRIARWOOD SOLAR, LLC	LU	1				3,658					220,202		220,202
51	Broad River Solar,LLC	LU	1				105,440					3,725,497		3,725,497
52	BUDDY SOLAR, LLC	LU	1				6,271					419,715		419,715
53	CAROL JEAN SOLAR,LLC	LU	1				7,328					472,275		472,275
54	Carolina Lilly Solar, LLC	LU	1				8,318					538,788		538,788
55	CARRBORO COMMUNITY SOLAR LLC	LU	1				4					114		114
56	Catawba County - Blackburn Landfill	LU	1				7,150					380,767		380,767
57	CATAWBA GREEN STEP SOLAR, LLC	LU	1				777					50,169		50,169
58	CATAWBA SOLAR, LLC	LU	1				3,611					239,940		239,940
59	CHAPEL HILL TIRE CO	LU	1				20					532		532
60	CHAPEL HILL TIRE COMPANY, INC.	LU	1				7					172		172
61	CHARLIE SOLAR, LLC	LU	1				6,526					380,865		380,865
62	CHARLOTTE SOLAR, LLC	LU	1				8,988					593,027		593,027
63	CHEROKEE FALLS HYDRO	LU	1				4,208					137,333		137,333
64	CISCO SYSTEMS INC	IU	1				103					3,808		3,808
65	CITY OF CHARLOTTE	IU	1				5,919					264,767		264,767
66	City of Winston Salem	LU	1				4,248					192,800		192,800
67	CLEAN ENERGY,LLC	LU	1				13,566					635,188		635,188
68	CLEAR SOLAR I, LLC	LU	1				6,788					436,788		436,788
69	Cliffside Mills LLC	LU	1				889					50,336		50,336
70	CLINE SOLAR, LLC	LU	1				8,253					553,058		553,058
71	COC SURRY LFG,LLC	LU	1				6,208					417,968		417,968
72	COMMONWEALTH BRANDS INC	LU	1				239					8,755		8,755
73	CONCORD ENERGY LLC	LU	1				60,989					4,188,403		4,188,403
74	CONGOLINA SOLAR, LLC	LU	1				1,152					75,439		75,439
75	Converse Energy - Clifton Dam #3 Hydro	LU	1				3,647					204,553		204,553
76	COUNTY HOME SOLAR CENTER LLC	LU	1				3,499					232,308		232,308
77	CROWN SOLAR CENTER, LLC	LU	1				6,045					316,524		316,524
78	CT WILSON PROPERTIES, LLC	LU	1				44					2,825		2,825
79	Cube Yadkin Generation LLC	IU	1				2,640					137,728		137,728
80	DANIEL FARM, LLC	LU	1				9,276					613,377		613,377
81	DANIELLE SEAMAN	LU	1				5					167		167
82	DAVID H NEWMAN	LU	1				1					24		24
83	DAVIDSON GAS PRODUCERS, LLC	LU	1				12,404					847,591		847,591
84	DDM MORTGAGE CORPORATION	LU	1				98					4,065		4,065
85	DELTA PRODUCTS CORP.	LU	1				29					1,088		1,088
86	Depcom AGA Tag Solar III, LLC	LU	1				3,955					244,399		244,399
87	DEPCOM POWER//ATOOD SOLAR III	LU	1				3,640					230,026		230,026
88	DIANE E JAMES	LU	1				6					209		209
89	DIBRELL FARM, LLC	LU	1				9,378					722,363		722,363
90	DIXON DAIRY ROAD, LLC	LU	1				6,810					520,100		520,100
91	DRAGSTRIP FARM	LU	1				9,319					619,628		619,628
92	DURHAM LANDFILL ELECTRICITY LLC	LU	1				12,768					715,004		715,004
93	DURHAM SOLAR , LLC	LU	1				5,919					397,025		397,025
94	EARNHARDT-CHILDRESS RACING TECHNOLOGIES,LLC	LU	1				57					1,575		1,575
95	ELLIANA SOLAR, LLC	LU	1				9,531					684,274		684,274
96	ESA Albemarle NC, LLC	LU	1				4,467					289,471		289,471
97	ESTES EXPRESS LINES, INC	LU	1				803					53,491		53,491
98	FACILE SOLAR, LLC	LU	1				3,459					232,358		232,358
99	FISHER SOLAR FARM, LLC	LU	1				9,600					639,954		639,954
100	FLASH SOLAR , LLC	LU	1				8,482					564,065		564,065
101	FLS OWNER II, LLC	LU	1				5					123		123
102	FOOTHILLS WINEWORX INC	LU	1				35					1,259		1,259
103	FREEMONT SOLAR CENTER, LLC	LU	1				8,574					567,609		567,609
104	Freightliner Corp	IU	1				0					7		7
105	FREIRICH FOODS, LLC	LU	1				101					3,592		3,592
106	FRESH AIR ENERGY XV, LLC	LU	1				6,087					410,396		410,396
107	FRESH AIR ENERGY XX, LLC	LU	1				9,766					630,733		630,733
108	FRESH AIR ENERGY XXIX, LLC	LU	1				5,259					352,513		352,513
109	Fresh Air Energy XXXII, LLC - High Shoals	LU	1				17,906					1,074,801		1,074,801
110	GAMBLE SOLAR, LLC	LU	1				6,587					423,787		423,787
111	GAS RECOVERY SYSTEMS, LLC	LU	1				4,265					286,445		286,445
112	GASTON COUNTY	LU	1				22,422					681,304		681,304
113	GASTONIA SOLAR CENTER, LLC	LU	1				7,588					482,295		482,295
114	GENERAL ELECTRIC COMPANY	LU	1				395					23,070		23,070
115	GERMANTOWN SOLAR, LLC	LU	1				2,974					209,303		209,303
116	GO STORE IT ROPER LLC	IU	1				40					2,116		2,116
117	GOLD MINE SOLAR, LLC	LU	1				3,300					197,410		197,410
118	GREEN ENERGY TRANS, LLC	LU	1				61					2,151		2,151
119	GREENVILLE COUNTY SCHOOLS	LU	1				26					693		693
120	GREENVILLE GAS PRODUCERS, LLC	LU	1				8,480					413,246		413,246
121	Haw River Hydro Co - Saxapahaw Hydro	LU	1				4,033					289,673		289,673
122	HAYES SOLAR, LLC	LU	1				6,611					426,486		426,486
123	HAYNES FARM, LLC	LU	1				8,502					649,170		649,170
124	Hecate Energy West Newberry, LLC	LU	1				6,484					348,523		348,523
125	HELIOS 4 MT, LLC - Ventura Solar	LU	1				9,884					636,328		636,328
126	HELIOS 4 MT, LLC - Zuma Solar	LU	1				6,484					421,963		421,963
127	HMS Holdings Limited Partnership	LU	1				72					1,956		1,956
128	HOFFMAN & HOFFMAN	LU	1				139					5,079		5,079
129	HOWELL MIDLAND FARM, LLC	LU	1				9,339					620,886		620,886
130	HUSKY SOLAR LLC	LU	1				8,813					591,534		591,534
131	HUTCHINSON FARM,LLC	LU	1				9,922					664,115		664,115
132	INDUSTRIAL CENTERS, LLC	LU	1				96					6,155		6,155
133	INNOVATIVE SOLAR 14, LLC	LU	1				3,377					257,308		257,308
134	INNOVATIVE SOLAR 15, LLC	LU	1				3,325					255,860		255,860
135	INNOVATIVE SOLAR 16, LLC	LU	1				3,100					206,202		206,202
136	INNOVATIVE SOLAR 18, LLC	LU	1				3,928					261,078		261,078
137	INNOVATIVE SOLAR 23, LLC	LU	1				3,720					247,331		247,331
138	INNOVATIVE SOLAR 26, LLC	LU	1				3,550					233,248		233,248
139	IRVINE RIVER COMPANY	LU	1				3,663					270,330		270,330
140	ITRON INC	LU	1				67					1,858		1,858
141	JACOB SOLAR LLC	LU	1				8,875					628,199		628,199
142	Jafasa Farms Greenhouse	LU	1				6					156		156
143	JEFFERY LYNN PARDUE	LU	1				5					119		119
144	JSD Pinson PV-1, LLC	LU	1				12,488					502,161		502,161
145	JUBA ALUMINUM PRODUCTS COMPANY INC	LU	1				11					292		292
146	JUDITH LOBERG	LU	1				168					7,005		7,005
147	LAFAYETTE SOLAR I, LLC	LU	1				3,490					233,865		233,865
148	LAMAR BAILES	LU	1				6					157		157
149	LAURA J BALLANCE	LU	1				7					191		191
150	LAWRENCE ELECTRIC	LU	1				2					66		66
151	LENOVO (UNITED STATES) INC - Lenovo RTP 2	LU	1				1,384					49,683		49,683
152	LENOVO (UNITED STATES) INC - Lenovo Whitsett 2	LU	1				1,678					58,590		58,590
153	LEON'S BEAUTY SCHOOL, INC	LU	1				41					1,471		1,471
154	Lick Creek Solar, LLC	IU	1				42,580					1,457,087		1,457,087
155	Limelight Solar I, LLC	LU	1				1,733					115,946		115,946
156	LIMELIGHT SOLAR II, LLC	LU	1				3,069					193,299		193,299
157	LIMELIGHT SOLAR III, LLC	LU	1				7,122					450,353		450,353
158	LINCOLN SOLAR LLC	LU	1				9,033					574,656		574,656
159	LOCKHART - LOWER PACOLET HYDRO	LU	1				3,628					253,612		253,612
160	LOCKHART - UPPER PACOLET HYDRO	LU	1				4,486					313,595		313,595
161	LOCKHART BIOENERGY, LLC	LU	1				14,320					773,265		773,265
162	Lockhart Buzzards Roost	LU	1				7					255		255
163	LOCKHART Minimum Flow	LU	1				4,566					319,164		319,164
164	LOTUS SOLAR LLC	LU	1				6,920					455,574		455,574
165	LUX SOLAR I LLC	LU	1				4,006					265,198		265,198
166	MARIPOSA SOLAR CENTER LLC	LU	1				9,037					600,787		600,787
167	MARKET FARM, LLC	LU	1				8,886					599,558		599,558
168	MARSHVILLE FARM ,LLC	LU	1				8,316					637,388		637,388
169	MARTIN TRUEX JR. LLC	LU	1				49					1,785		1,785
170	MAYBERRY SOLAR LLC	LU	1				1,530					116,781		116,781
171	Mayo Hydropower LLC - Mayo Hydro	LU	1				3,212					233,692		233,692
172	MCBRIDE PLACE ENERGY, LLC	LU	1				141,531					8,310,881		8,310,881
173	MEADOWBROOK SOLAR, LLC	LU	1				9,769					653,913		653,913
174	MIDTOWN SHOPS, LLC	LU	1				20					1,343		1,343
175	Midway Green Solar, LLC (Lockhart)	LU	1				16,378					936,779		936,779
176	Mill Shoals Hydro - High Shoals Hydro	LU	1				2,201					160,771		160,771
177	MILLIKAN FARM, LLC	LU	1				9,654					643,640		643,640
178	MILO SOLAR, LLC	LU	1				5,509					363,866		363,866
179	MINNESOTA MINING & MFG CO	IU	1				9					497		497
180	MINNIE SOLAR , LLC	LU	1				5,551					370,075		370,075
181	MISENHEIMER FARM, LLC	LU	1				9,180					614,535		614,535
182	MOCKSVILLE FARM,LLC	LU	1				9,423					717,873		717,873
183	Mohea Solar Center, LLC	LU	1				7,318					394,470		394,470
184	MONROE MOORE FARM,LLC	LU	1				9,594					638,770		638,770
185	MOORE SOLAR #2, LLC	LU	1				9,065					605,332		605,332
186	MOORE SOLAR FARM,LLC	LU	1				8,269					638,127		638,127
187	NARENCO	LU	1				514					14,753		14,753
188	NC SOLAR DOCKS LLC	LU	1				15					960		960
189	NEISLER STREET SOLAR I LLC	LU	1				3,553					238,983		238,983
190	NEWTON-CONOVER CITY SCHOOLS	LU	1				154					5,469		5,469
191	NICK SOLAR,LLC	LU	1				8,905					687,978		687,978
192	Northbrook Carolina - Boyds Mill Hydro	IU	1				3,366					112,374		112,374
193	Northbrook Carolina - Holliday's Bridge Hydro	IU	1				10,446					374,942		374,942
194	Northbrook Carolina - Saluda Hydro	IU	1				6,441					233,894		233,894
195	Northbrook Carolina - Turner Shoals Hydro	IU	1				11,325					569,405		569,405
196	NORTHBROOK CAROLINA (Bryson)	LU	1				4,356					144,999		144,999
197	NORTHBROOK CAROLINA (Franklin)	LU	1				5,370					181,429		181,429
198	NORTHBROOK CAROLINA (Gaston Shoals)	LU	1				18,314					606,185		606,185
199	NORTHBROOK HYDRO II (Mission Dam)	LU	1				8,572					289,175		289,175
200	NORTHBROOK TUXEDO	LU	1				17,678					596,285		596,285
201	NYPRO,INC	LU	1				222					8,223		8,223
202	OAKDALE HOLDING LLC	LU	1				23					607		607
203	Oakwood Solar Farm, LLC	LU	1				10,986					710,229		710,229
204	OLD CAROLEEN SOLAR FARM, LLC	LU	1				3,958					255,008		255,008
205	OLD DOMINION FREIGHT LINE INC	LU	1				1,768					65,050		65,050
206	OLD PAGELAND-MONROE ROAD SOLAR FARM LLC	LU	1				9,523					669,255		669,255
207	ORBIT ENERGY CHARLOTTE,LLC	LU	1				5,072					335,849		335,849
208	ORGAN CHURCH SOLAR, LLC	LU	1				11,196					723,014		723,014
209	OWEN SOLAR , LLC	LU	1				6,369					422,632		422,632
210	PAUL M NEUBAUER	LU	1				3					78		78
211	Pelzer Hydro Co - Lower Pelzer Hydro	LU	1				5,677					172,810		172,810
212	Pelzer Hydro Co - Upper Pelzer Hydro	LU	1				4,009					123,090		123,090
213	PELZER SOLAR I, LLC	LU	1				1,956					135,900		135,900
214	Pickens Mill Hydro LLC	LU	1				521					29,641		29,641
215	PIEDMONT COMPANY, INC	LU	1				84					3,426		3,426
216	PILOT MOUNTAIN SOLAR, LLC	LU	1				10,778					697,373		697,373
217	PUBLIC LIBRARY OF CHARLOTTE	LU	1				42					1,520		1,520
218	R B SOLAR LLC	LU	1				6,286					402,003		402,003
219	RAJENDRA MOREY	LU	1				5					128		128
220	Ray Wilson Solar, LLC	LU	1				8,593					554,487		554,487
221	RAYLEN VINEYARDS INC	LU	1				516					34,995		34,995
222	REBECCA G LASKODY	LU	1				4					94		94
223	REDMON SOLAR FARM, LLC	LU	1				4,091					272,811		272,811
224	REI 2 LLC	LU	1				13,744					611,443		611,443
225	RENEWABLE WATER RESOURCES	LU	1				1,950					115,467		115,467
226	ROCKWELL SOLAR, LLC	LU	1				5,734					382,511		382,511
227	RONNIE B POWERS	LU	1				621					25,945		25,945
228	ROPER FARM, LLC	LU	1				9,906					659,920		659,920
229	ROUSCH & YATES RACING ENGINES, LLC	LU	1				103					2,780		2,780
230	RPSC Solar 3, LLC - Berry Rd	LU	1				3,632					218,538		218,538
231	RPSC SOLAR 5, LLC	LU	1				3,789					224,815		224,815
232	RPSC SOLAR 7, LLC	LU	1				3,479					221,215		221,215
233	Ruff Solar, LLC	LU	1				47,077					2,266,973		2,266,973
234	RUTHERFORD FARM, LLC	LU	1				140,888					8,717,847		8,717,847
235	SAIA MOTOR FREIGHT LINE, LLC	LU	1				122					8,189		8,189
236	SALEM ENERGY SYSTEMS, LLC	LU	1				25,794					1,413,478		1,413,478
237	SALISBURY SOLAR, LLC	LU	1				8,106					523,454		523,454
238	SANDAN FARM	LU	1				32					1,184		1,184
239	Saw Solar, LLC	LU	1				2,701					153,345		153,345
240	SAWTELL SOLAR, LLC	LU	1				5,468					347,743		347,743
241	SHELBY RANDOLPH ROAD SOLAR I , LLC	LU	1				3,749					249,883		249,883
242	SHOE SHOW, INC	LU	1				3,012					113,497		113,497
243	SID SOLAR I, LLC	LU	1				8,731					584,861		584,861
244	SIGMON CATAWBA FARM,LLC	LU	1				9,160					610,182		610,182
245	SONNE TWO,LLC	LU	1				9,587					631,575		631,575
246	SOPHIE SOLAR, LLC	LU	1				8,027					533,869		533,869
247	SOUTH WINSTON FARM, LLC	LU	1				8,474					604,450		604,450
248	South Yadkin Power, Inc.	LU	1				1,134					79,946		79,946
249	SOUTHWICK SOLAR FARM, LLC	LU	1				5,892					380,502		380,502
250	SPARTANBURG WATER SYSTEM	LU	1				427					25,451		25,451
251	Speedway Solar NC, LLC	LU	1				43,816					1,932,210		1,932,210
252	SPENCER FARM, LLC	LU	1				9,705					652,727		652,727
253	SPENCER MOUNTAIN HYDROPOWER, LLC	LU	1				1,326					80,252		80,252
254	STANLEY CHAMBERLAIN	LU	1				8					222		222
255	Star Solar, LLC	LU	1				8,100					527,305		527,305
256	STATESVILLE SOLAR, LLC	LU	1				9,829					695,375		695,375
257	STIKELEATHER FARM, LLC	LU	1				9,587					641,755		641,755
258	Stony Knoll Solar, LLC	LU	1				32,518					1,304,889		1,304,889
259	STOUT FARM LLC	LU	1				8,915					586,785		586,785
260	Sugar Solar LLC	LU	1				104,989					3,959,246		3,959,246
261	SUN CAPITAL,INC	LU	1				25					910		910
262	SUN EDISON LLC	LU	1				7,901					535,678		535,678
263	SV LIM HOLDINGS LLC	LU	1				116					3,646		3,646
264	TENCARVA MACHINERY COMPANY	LU	1				253					9,267		9,267
265	TerraForm LLC; DBA: SunE B9 Holdings, LLC	LU	1				10,190					690,859		690,859
266	THE CITY OF CHARLOTTE	LU	1				372					25,819		25,819
267	THE NORTHWESTERN MUTUAL LIFE INSURANCE	LU	1				2					48		48
268	TIBURON HOLDINGS LLC	LU	1				9,521					629,504		629,504
269	Town Of Lake Lure - Lake Lure Hydro	LU	1				2,325					145,985		145,985
270	TRINITY SOLAR, LLC	LU	1				9,599					619,322		619,322
271	TRIPPLE STATE FARM, LLC	LU	1				10,349					669,972		669,972
272	TWC ADMINISTRATION LLC	LU	1				1,096					72,024		72,024
273	TWO LINES FARM, LLC	LU	1				9,409					726,325		726,325
274	UNIFI MANUFACTURING, INC	LU	1				1,053					70,569		70,569
275	UNITED SEWING MACHINE SALES, LLC	LU	1				45					2,567		2,567
276	UNITED THERAPEUTICS CORPORATION	LU	1				4,755					308,738		308,738
277	VETRORESINA LLC	LU	1				357					21,274		21,274
278	VIDYA SAGAR SETHI	LU	1				5					128		128
279	VIOLET SOLAR, LLC	LU	1				6,540					421,597		421,597
280	VOLT SOLAR, LLC	LU	1				1,332					86,418		86,418
281	W B MOORE CO OF CHAR	LU	1				31					1,136		1,136
282	WACO FARM, LLC	LU	1				9,239					709,639		709,639
283	WALLACE & GRAHAM PA	LU	1				207					7,606		7,606
284	WALTER C. MCGERVEY	LU	1				2					37		37
285	Warbler Holdings, LLC	LU	1				7,852					507,284		507,284
286	WEST SALISBURY FARM, LLC	LU	1				8,811					603,313		603,313
287	WHITE CROSS FARM, LLC	LU	1				8,453					647,037		647,037
288	WHITE CROSS SOLAR LLC	LU	1				3,816					255,304		255,304
289	White Street Renewables Solar, LLC	LU	1				6,745					434,767		434,767
290	WHITE STREET RENEWABLES, LLC	LU	1				10,650					590,157		590,157
291	WHITT SOLAR, LLC	LU	1				3,935					224,892		224,892
292	WILLIAM P MILLER	LU	1				3					77		77
293	WM RENEWABLE ENERGY,LLC	LU	1				10,848					687,333		687,333
294	Woodfields Solar, LLC	LU	1				3,455					210,558		210,558
295	WRIGHT OF THOMASVILLE INC	LU	1				94					3,456		3,456
296	YADKIN 601 FARM,LLC	LU	1				5,882					393,276		393,276
297	Yadkin Solar Farm, LLC	LU	1				8,149					526,807		526,807
298	YADKINVILLE SOLAR, LLC	LU	1				6,739					450,051		450,051
299	YORK ROAD SOLAR I , LLC	LU	1				3,401					225,407		225,407
300	YUZE HOLDINGS LLC	IU	1				28					778		778
301	Adams Solar LLC - SC	AD	1				381					20,878		20,878
302	Broad River Solar,LLC	AD	1				871					35,786		35,786
303	Catawba County - Blackburn Landfill	AD	1				578					15,200		15,200
304	COMMONWEALTH BRANDS INC	AD	1				6					141		141
305	CROWN SOLAR CENTER, LLC	AD	1				793					50,483		50,483
306	Cube Yadkin Generation LLC	AD	1				900					47,070		47,070
307	DANIELLE SEAMAN	AD	1				0					20		20
308	DIANE E JAMES	AD	1				0					4		4
309	FOOTHILLS WINEWORX INC	AD	1				1					26		26
310	GREENVILLE COUNTY SCHOOLS	AD	1				3					75		75
311	HELIOS 4 MT, LLC - Zuma Solar	AD	1				343					20,430		20,430
312	HOFFMAN & HOFFMAN	AD	1				3					81		81
313	ITRON INC	AD	1				7					189		189
314	Lick Creek Solar, LLC	AD	1				2
315	MARTIN TRUEX JR. LLC	AD	1				1					29		29
316	MOORE SOLAR FARM,LLC	AD	1				854					78,044		78,044
317	NEWTON-CONOVER CITY SCHOOLS	AD	1				5					107		107
318	Northbrook Carolina - Boyds Mill Hydro	AD	1				161					6,916		6,916
319	Northbrook Carolina - Saluda Hydro	AD	1				346					14,925		14,925
320	Northbrook Carolina - Turner Shoals Hydro	AD	1				599					26,040		26,040
321	NORTHBROOK CAROLINA (Bryson)	AD	1				124					3,963		3,963
322	OLD DOMINION FREIGHT LINE INC	AD	1				50					1,191		1,191
323	PUBLIC LIBRARY OF CHARLOTTE	AD	1				1					25		25
324	SHOE SHOW, INC	AD	1				287					9,041		9,041
325	Speedway Solar NC, LLC	AD	1				1,157					55,619		55,619
326	UNIFI MANUFACTURING, INC	AD	1				188					10,876		10,876
327	Warbler Holdings, LLC	AD	1				1,511					99,674		99,674
328	Woodfields Solar, LLC	AD	1				30					1,706		1,706
329	WRIGHT OF THOMASVILLE INC	AD	1				2					59		59
330	Residential Solar Credit	LU					5,321					143,677		143,677
331	Southeastern Power Administration	OS	124									16,551		16,551
332	NC CPRE Liquidated Damages	LU	1									0	5,397,400	5,397,400
333	Small Customer Generator Credits	OS										8,267		8,267
334	North Carolina Municipal Power Agency	EX	271						3,560,028	3,528,612	733,805	1,993,339		1,259,534
335	Piedmont Municipal Power Agency	EX	314						1,186,676	1,176,207	244,603	542,284		786,887
336	North Carolina Electric Member Corporation	EX	273				17,142		2,919,602	2,903,362	601,799	1,377,429		775,630
337	North Carolina Municipal Power Agency	OS	271				6,298			6,298		210,238		210,238
338	North Carolina Electric Member Corporation	OS	273				5,165			5,165		172,417		172,417
339	Piedmont Municipal Power Agency	OS	313				2,099			2,099		70,079		70,079
340	Associated Electric Cooperative, Inc.	OS	2				3,384					163,916		163,916
341	Blue Ridge Electric Membership Corporation	RQ	315				293,671				5,824,442	6,201,919		12,026,361
342	Blue Ridge Electric Membership Corporation	AD	315				0				105,082	102,682		207,764
343	Carolina Power & Light Company	OS	2				177					30,606		30,606
344	Carolina Power Partners, LLC	OS	2				182,475					15,080,072		15,080,072
345	Cherokee County Cogeneration Partners, LLC	OS	2				0				215,310	6,207,998		6,423,308
346	Cherokee County Cogeneration Partners, LLC	AD	2				0				0	22,574		22,574
347	Constellation Energy Generation, LLC	OS	2				6,659					489,570		489,570
348	Cube Yadkin Generation, LLC	OS	2				2,810					221,550		221,550
349	DE Progress	OS	341				7,369,876				400,501	599,157,888		599,558,389
350	DE Progress	AD	341								0	4,891		4,891
351	Dominion Energy South Carolina, Inc.	OS	2				288					13,472		13,472
352	Haywood Electric Membership Corporation	RQ	335				45,523				978,976	1,194,327		2,173,303
353	Haywood Electric Membership Corporation	AD	335				335				0	11,126		11,126
354	Haywood Electric Membership Corporation (Economic)	RQ	335				6,939				242,809	715,153		957,962
355	Haywood Electric Membership Corporation (Economic)	AD	335				23				0	343		343
356	LGE/KU	OS	2				14,077					785,194		785,194
357	Macquarie Energy LLC	OS	2				1,060,471					147,064,943		147,064,943
358	Morgan Stanley Capital Group, Inc.	OS	2				1,100					72,600		72,600
359	NC Electric Member Corporation	RQ	326				0				39,805	0		39,805
360	NCEMC	OS	2				67,097					10,241,913		10,241,913
361	North Carolina Municipal Power Agency Number 1	OS	2				259,234					21,057,410		21,057,410
362	North Carolina Municipal Power Agency Number 1	RQ	318				465,009				0	37,141,682		37,141,682
363	Piedmont Electric Membership Corporation	RQ	316				140,160				2,779,845	2,943,070		5,722,915
364	Piedmont Electric Membership Corporation	AD	316				0				46,450	49,633		96,083
365	Piedmont Municipal Power Agency	RQ	340				102,863				0	5,268,497		5,268,497
366	PJM Settlements, Inc.	OS	2				192,441					14,064,245		14,064,245
367	PJM Settlements, Inc.	AD	2				0				0	56		56
368	Southern Company Services, Inc.	OS	2				9,748					557,481		557,481
369	Tennessee Valley Authority	OS	2				84,497					5,408,020		5,408,020
370	The Energy Authority	OS	2				424					16,905		16,905
371	Town of Dallas, North Carolina	RQ	328				0				0	0
372	Town of Forest City, North Carolina	RQ	330				0				244,999	0		244,999
373	Broad River Energy Center	EX	3				4,626					492,053		492,053
374	JURISCODE - TBDEP & TBSE.	EX	3									2,697,005		2,697,005
375	Macquarie Energy LLC	EX	3				3,793					95,972		95,972
376	NCMPA	EX	3				21,587		1,005			2,663,742		2,663,742
377	Piedmont Municipal Pwr Agency	EX	3				5,020		3,549			200,069		200,069
378	Southern Co - Cleveland Plant	EX	3				10,957					1,098,169		1,098,169
379	Southern Pwr Co - Rowan Plant	EX	3				23,728					1,961,156		1,961,156
380	City of Concord	EX	3						5,168			1,908,262		1,908,262
381	City of Kings Mountain	EX	3						2,116			519,370		519,370
382	City of Seneca	EX	3						979			90,827		90,827
383	Energy United EMC	EX	3						9,602			1,074,619		1,074,619
384	Greenwood Comm of Pblc Works	EX	3						4,807			1,050,717		1,050,717
385	NC Electric Membership Corp	EX	3						15,343			630,493		630,493
386	SCE&G Company	EX	3						426			55,046		55,046
387	Brookfield Renewable	OS	890									9,237		9,237
388	JURISCODE - TBDEP & TBSE.	OS	890									9,381		9,381
389	Eagle Energy Partners	OS	890									1,319		1,319
390	Exelon Power Team	OS	890									14,978		14,978
391	Lockhart Power Company	OS	890									17		17
392	Macquarie Energy LLC	OS	890									21,551		21,551
393	Mercuria Energy American	OS	890									1,222		1,222
394	Morgan Stanley Capital Grp INC	OS	890									7,764		7,764
395	Rainbow Energy Marketing	OS	890									1,093		1,093
396	SC Public Service Authority	OS	890									1,362		1,362
397	Southern Wholesale	OS	890									15,687		15,687
398	The Energy Authority	OS	890									17,048		17,048
399	New River Power & Light	OS	890									1,207,895		1,207,895
400	SCANA Energy Marketing	OS	890									1		1
401	Western Carolina University	OS	890									368,809		368,809
402	Operating Regulating	EX	5						146,462	149,983		0
15	TOTAL						12,655,282	0	7,792,946	7,744,602	8,867,392	1,000,432,997	5,397,400	1,003,902,989

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

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.	PaymentByCompanyOrPublicAuthority Payment By (Company of Public Authority) (Footnote Affiliation) (a)	TransmissionEnergyReceivedFromCompanyOrPublicAuthorityName Energy Received From (Company of Public Authority) (Footnote Affiliation) (b)	TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName Energy Delivered To (Company of Public Authority) (Footnote Affiliation) (c)	StatisticalClassificationCode Statistical Classification (d)	RateScheduleTariffNumber Ferc Rate Schedule of Tariff Number (e)	TransmissionPointOfReceipt Point of Receipt (Substation or Other Designation) (f)	TransmissionPointOfDelivery Point of Delivery (Substation or Other Designation) (g)	BillingDemand Billing Demand (MW) (h)	TransmissionOfElectricityForOthersEnergyReceived Megawatt Hours Received (i)	TransmissionOfElectricityForOthersEnergyDelivered Megawatt Hours Delivered (j)	Demand Charges ($) (k)	Energy Charges ($) (l)	Other Charges ($) (m)	RevenuesFromTransmissionOfElectricityForOthers Total Revenues ($) (k+l+m) (n)
1	Brookfield Energy Marketing LP	Various	Various	LFP	Various	Various	Various	200	0	0	4,185,825	0	0	4,185,825
2	Brookfield Energy Marketing LP	Various	Various	LFP	Various	Various	Various	99	0	0	2,071,984	0	0	2,071,984
3	Brookfield Energy Marketing LP	Various	Various	SFP	Various	Various	Various	0	0	0	0	0	4,950,364	4,950,364
4	Brookfield Renewable Trading and Marketing LP	Various	Various	OS	Various	Various	Various	0	0	0	0	0	2,564	2,564
5	Brookfield Renewable Trading and Marketing LP	Various	Various	SFP	Various	Various	Various	0	0	0	0	14,174	5,490,151	5,504,325
6	Carolina Power & Light	Various	Various	LFP	Various	Various	Various	600	0	0	0	0	0	0
7	Carolina Power & Light	Various	Various	LFP	Various	Various	Various	200	0	0	0	0	0	0
8	Carolina Power & Light	Various	Various	LFP	Various	Various	Various	225	0	0	0	0	0	0
9	Carolina Power & Light	Various	Various	LFP	Various	Various	Various	51	0	0	0	0	0	0
10	Carolina Power & Light	Various	Various	LFP	Various	Various	Various	195	0	0	0	0	0	0
11	Carolina Power & Light	Various	Various	LFP	Various	Various	Various	40	0	0	0	0	0	0
12	Carolina Power & Light	Various	Various	LFP	Various	Various	Various	875	0	0	0	0	0	0
13	Carolina Power & Light	Various	Various	LFP	Various	Various	Various	10	0	0	0	0	0	0
14	Carolina Power & Light	Various	Various	OS	Various	Various	Various	0	0	0	0	0	179,300	179,300
15	Carolina Power & Light	Various	Various	SFP	Various	Various	Various	0	0	0	0	0	0	0
16	Carolina Power Partners, LLC	Various	Various	LFP	Various	Various	Various	87	0	0	0	0	0	0
17	Carolina Power Partners, LLC	Various	Various	LFP	Various	Various	Various	5	0	0	104,646	0	0	104,646
18	Carolina Power Partners, LLC	Various	Various	OS	Various	Various	Various	0	0	0	0	0	635,128	635,128
19	Carolina Power Partners, LLC	Various	Various	SFP	Various	Various	Various	0	0	0	0	0	950,591	950,591
20	Constellation Energy Generation, LLC	Various	Various	OS	Various	Various	Various	0	0	0	0	303	405,210	405,513
21	Constellation Energy Generation, LLC	Various	Various	SFP	Various	Various	Various	0	0	0	0	0	3,401,842	3,401,842
22	EDF Trading North America	Various	Various	OS	Various	Various	Various	0	0	0	0	0	257,054	257,054
23	EDF Trading North America	Various	Various	SFP	Various	Various	Various	0	0	0	0	0	131,254	131,254
24	Endure Energy LLC	Various	Various	OS	Various	Various	Various	0	0	0	0	0	141	141
25	Exelon Power Team	Various	Various	OS	Various	Various	Various	0	0	0	0	0	54,425	54,425
26	Exelon Power Team	Various	Various	SFP	Various	Various	Various	0	0	0	0	0	603,944	603,944
27	Florida Power Corp	Various	Various	OS	Various	Various	Various	0	0	0	0	0	144,918	144,918
28	Macquarie Energy LLC	Various	Various	OS	Various	Various	Various	0	0	0	0	377,474	920,743	1,298,217
29	Macquarie Energy LLC	Various	Various	SFP	Various	Various	Various	0	0	0	0	2,893,044	5,870,399	8,763,443
30	Mercuria Energy America, LLC	Various	Various	OS	Various	Various	Various	0	0	0	0	0	381,260	381,260
31	Mercuria Energy America, LLC	Various	Various	SFP	Various	Various	Various	0	0	0	0	0	93,742	93,742
32	Morgan Stanley Capital Group Inc	Various	Various	OS	Various	Various	Various	0	0	0	0	0	1,126,609	1,126,609
33	Morgan Stanley Capital Group Inc	Various	Various	SFP	Various	Various	Various	0	0	0	0	0	1,195,601	1,195,601
34	NC Electric Membership Corporation	Various	Various	LFP	Various	Various	Various	150	0	0	2,092,913	0	0	2,092,913
35	NC Electric Membership Corporation	Various	Various	LFP	Various	Various	Various	102	0	0	0	0	0	0
36	NC Electric Membership Corporation	Various	Various	LFP	Various	Various	Various	100	0	0	0	0	0	0
37	NC Electric Membership Corporation	Various	Various	LFP	Various	Various	Various	55	0	0	0	0	0	0
38	NC Electric Membership Corporation	Various	Various	OS	Various	Various	Various	0	0	0	0	217	401,211	401,428
39	NC Electric Membership Corporation	Various	Various	SFP	Various	Various	Various	0	0	0	0	0	72,867	72,867
40	NCMPA	Various	Various	OS	Various	Various	Various	0	0	0	0	0	1,342,098	1,342,098
41	NCMPA	Various	Various	SFP	Various	Various	Various	0	0	0	0	0	271,912	271,912
42	New River Light and Power Company	Various	Various	SFP	Various	Various	Various	0	0	0	0		0	0
43	Ontario Power Generation Energy Trading, Inc.	Various	Various	OS	Various	Various	Various	0	0	0	0	0	121	121
44	Rainbow Energy Marketing	Various	Various	OS	Various	Various	Various	0	0	0	0	0	159,369	159,369
45	Rainbow Energy Marketing	Various	Various	SFP	Various	Various	Various	0	0	0	0	0	127,292	127,292
46	South Carolina Electric & Gas Company	Various	Various	OS	Various	Various	Various	0	0	0	0	140	277	417
47	South Carolina Public Service Authority - P2P	Various	Various	LFP	Various	Various	Various	23	0	0	0	0	0	0
48	South Carolina Public Service Authority - P2P	Various	Various	OS	Various	Various	Various	0	0	0	0	0	245,367	245,367
49	South Carolina Public Service Authority - P2P	Various	Various	SFP	Various	Various	Various	0	0	0	0	0	153,897	153,897
50	Southern Wholesale	Various	Various	OS	Various	Various	Various	0	0	0	0	0	5,485,346	5,485,346
51	Tennessee Valley Authority	Various	Various	OS	Various	Various	Various	0	0	0	0	0	16,307	16,307
52	Tennessee Valley Authority	Various	Various	SFP	Various	Various	Various	0	0	0	0	0	20,785	20,785
53	The Energy Authority	Various	Various	OS	Various	Various	Various	0	0	0	0	0	1,263,900	1,263,900
54	The Energy Authority	Various	Various	SFP	Various	Various	Various	0	0	0	0	0	4,136,570	4,136,570
55	Westar Energy	Various	Various	OS	Various	Various	Various	0	0	0	0	0	12,303	12,303
56	Point to Point MWH(s) for all entries above							0	17,752,402	17,645,514	0	0	0	0
57	SEEM Transactions	Various	Various	FNO	Various	Various	Various	0	0	0	0	0	16,076	16,076
58	Blue Ridge Electric Membership Corporation	Various	Various	FNO	Various	Various	Various	0	1,201,484	1,201,484	3,309,505	0	869,840	4,179,345
59	Cargill-Alliant, LLC	Various	Various	FNO	Various	Various	Various	0	0	0	0	0	0	0
60	Central Electric Power Cooperative, Inc.	Various	Various	FNO	Various	Various	Various	0	4,216,690	4,216,690	13,536,861	0	3,229,349	16,766,210
61	City of Concord	Various	Various	FNO	Various	Various	Various	0	968,603	968,603	2,741,437	0	676,648	3,418,085
62	City of Kings Mountain	Various	Various	FNO	Various	Various	Various	0	154,375	154,375	434,978	0	103,998	538,976
63	City of Seneca	Various	Various	FNO	Various	Various	Various	0	155,404	155,404	464,871	0	61,543	526,414
64	EnergyUnited Electric Membership Corporation	Various	Various	FNO	Various	Various	Various	0	2,931,198	2,931,198	9,251,246	0	1,224,125	10,475,371
65	Greenwood Commissioners of Public Works	Various	Various	FNO	Various	Various	Various	0	306,356	306,356	863,870	0	206,535	1,070,405
66	Haywood Electric Membership Corporation	Various	Various	FNO	Various	Various	Various	0	148,288	148,288	389,081	0	102,450	491,531
67	Lockhart Power Company	Various	Various	FNO	Various	Various	Various	0	392,508	392,508	1,051,205	0	245,537	1,296,742
68	Macquarie Energy LLC	Various	Various	FNO	Various	Various	Various	0	0	0	0	0	0	0
69	NC Electric Membership Corporation	Various	Various	FNO	Various	Various	Various	0	2,215,040	2,215,040	6,667,565	0	74,583	6,592,982
70	NCMPA	Various	Various	FNO	Various	Various	Various	0	5,403,639	5,403,639	13,934,046	0	1,060,973	14,995,019
71	New River Light and Power Company	Various	Various	FNO	Various	Various	Various	0	227,907	227,907	565,515	0	151,760	717,275
72	Piedmont Electric Membership Corporation	Various	Various	FNO	Various	Various	Various	0	414,514	414,514	1,371,214	0	327,696	1,698,910
73	Piedmont Municipal Power Agency	Various	Various	FNO	Various	Various	Various	0	2,488,243	2,488,243	6,959,053	0	660,240	7,619,293
74	Rutherford Electric Membership Corporation	Various	Various	FNO	Various	Various	Various	0	1,416,242	1,416,242	4,586,690	0	1,095,984	5,682,674
75	SCE&G COMPANY	Various	Various	FNO	Various	Various	Various	0	5,872	5,872	19,445	0	4,641	24,086
76	Southern Power Company - Rowan Plant	Various	Various	FNO	Various	Various	Various	0	0	0	0	0	343,759	343,759
77	Town of Dallas	Various	Various	FNO	Various	Various	Various	0	72,459	72,459	178,886	0	42,648	221,534
78	Town of Due West	Various	Various	FNO	Various	Various	Various	0	13,890	13,890	33,889	0	8,077	41,966
79	Town of Forest City	Various	Various	FNO	Various	Various	Various	0	105,733	105,733	260,481	0	62,320	322,801
80	Town of Highlands	Various	Various	FNO	Various	Various	Various	0	54,498	54,498	139,532	0	33,310	172,842
81	US Department of Energy	Various	Various	FNO	Various	Various	Various	0	4,231	5,685	74,040	0	16,551	90,591
82	Western Carolina University	Various	Various	FNO	Various	Various	Various	0	53,124	53,124	158,040	0	37,263	195,303
83	(a) Revenue Accrual							0	0	0	798,627	0	0	798,627
84														0
35	TOTAL							3,017	40,702,700	40,597,266	74,648,191	3,285,352	40,064,756	117,998,299

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: PaymentByCompanyOrPublicAuthority

Accrue for Mutually Agreed Upon Items (798,627)

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

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:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

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	NCMPA	OS			27,140			27,140.00
2	NCEMC	OS			43,784			43,784.00
3	Energy United	OS			112,930			112,930.00
4	Carolina Power & Light	SFP				505,550	81,999	587,549.00
5	Central	OS			159,914			159,914.00
6	Carolina Power & Light	NF				4,113,404	9,567	4,122,971.00
	TOTAL

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line No.	Description (a)	Amount (b)
1	IndustryAssociationDues Industry Association Dues	1,382,845
2	NuclearPowerResearchExpenses Nuclear Power Research Expenses
3	OtherExperimentalAndGeneralResearchExpenses Other Experimental and General Research Expenses	2,914,248
4	PublicationAndDistributionExpensesForSecuritiesToStockholders Pub and Dist Info to Stkhldrs...expn servicing outstanding Securities	218,541
5	OtherMiscellaneousGeneralExpenses Oth Expn greater than or equal to 5,000 show purpose, recipient, amount. Group if less than $5,000
6	Service Company Allocation	32,284,012
7	Consultants and Contract Services	1,965,905
8	Postage and Freight	186,803
9	Allocated Labor	110,826
10	Other Contracts	5,524,519
11	Direct Purchase Allocations	521,823
12	Allocated Incentives	15,430
13	Travel Expenses	24,589
14	IT Software Maintenance	16,829
15	Restricted Stock Units	10,895
16	Baseload Contract Labor	14,093
17	Executive Short Term Incentives	6,601
18	Miscellaneous	3,739,641
19	Dues and Subscriptions to various organizations:
20	Agribusiness Henderson County	500
21	Alamance County Area CoC	1,100
22	Anderson Area CoC	2,306
23	Archdale - Trinity CoC	940
24	Belmont CoC	1,845
25	Cabarrus Regional CoC	3,400
26	Caldwell County CoC	3,000
27	Charlotte Regional Business Alliance	80,000
28	Cherokee County CoC	3,000
29	Chester County CoC	3,000
30	Clemson Area CoC	870
31	Cleveland County CoC	1,744
32	E4 Carolinas	10,000
33	Eden CoC	1,670
34	Electric Power Research Institute	95,182
35	Franklin Area CoC	500
36	Gaston Business Association	10,000
37	Greater Durham CoC	9,300
38	Greater Easley CoC	970
39	Greater Clover CoC	600
40	Greater Winston Salem	11,465
41	Greensboro CoC	12,934
42	Greenville CoC	30,175
43	Henderson County CoC	1,174
44	Henderson County Partners	1,300
45	Hillsborough Orange County CoC	1,200
46	Jackson County CoC	500
47	King CoC	575
48	Lake Norman CoC	1,200
49	Lancaster Breakfast Club Rotary	627
50	Lincolnton-Lincoln County CoC	707
51	Mauldin CoC	650
52	McDowell CoC	685
53	Mooresville-South Iredell	551
54	Mount Airy CoC	1,170
55	North Carolina Econoci Developers Assoc	590
56	Palmetto Agribusiness Council	2,500
57	Randleman CoC	1,120
58	Reidsville CoC	1,170
59	Rotary Club Of Greenwood	1,050
60	Rowan County CoC	3,448
61	Smoky Mountain Host Of North Carolina	1,000
62	South Carolina CoC	11,625
63	South Carolina Manufacturers Alliance	17,000
64	Southeastern Electric Exchange	29,549
65	Stanly County CoC	1,190
66	Thomasville Area CoC	1,826
67	Union County CoC	4,000
68	Wilkes CoC	1,828
69	York County Regional CoC	3,400
70	Chamber of Commerce (13)	3,840
71	Miscellaneous Dues and Subscriptions	203,173
72	Transferred Employees Homes	3,579,162
73	Leased Circuit Charges	2,649
74	Director's Fees and Expenses	1,391,348
46	MiscellaneousGeneralExpenses TOTAL	10,074,116.00

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

Depreciation and Amortization of Electric Plant (Account 403, 404, 405)
Report in section A for the year the amounts for: (b) Depreciation Expense (Account 403); (c) Depreciation Expense for Asset Retirement Costs (Account 403.1); (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric Plant (Account 405). Report in Section B the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to compute charges and whether any changes have been made in the basis or rates used from the preceding report year. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes to columns (c) through (g) from the complete report of the preceding year. Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount, account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant included in any sub-account used. In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the method of averaging used. For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification listed in column (a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type of mortality curve selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at the bottom of section C the amounts and nature of the provisions and the plant items to which related.
	A. Summary of Depreciation and Amortization Charges
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			73,780,561		73,780,561
2	Steam Production Plant	345,645,055				345,645,055
3	Nuclear Production Plant	197,914,400				197,914,400
4	Hydraulic Production Plant-Conventional	30,000,270				30,000,270
5	Hydraulic Production Plant-Pumped Storage	20,931,061				20,931,061
6	Other Production Plant	114,196,065				114,196,065
7	Transmission Plant	122,431,187				122,431,187
8	Distribution Plant	319,117,945				319,117,945
9	Regional Transmission and Market Operation
10	General Plant	58,323,439		120,351		58,443,790
11	Common Plant-Electric
12	TOTAL	1,208,559,422		73,900,912		1,282,460,334

B. Basis for Amortization Charges
Limited term electric depreciable plant base is $474,864,349, which is the cost of capitalized software and generating plant relicensing. Intangible plant is amortized over 3, 5, 10 and 15 years. The generating plant relicensing is amortized over the remaining life of the license.

	C. Factors Used in Estimating Depreciation Charges
Line No.	AccountNumberFactorsUsedInEstimatingDepreciationCharges Account No. (a)	DepreciablePlantBase Depreciable Plant Base (in Thousands) (b)	UtilityPlantEstimatedAverageServiceLife Estimated Avg. Service Life (c)	UtilityPlantNetSalvageValuePercentage Net Salvage (Percent) (d)	UtilityPlantAppliedDepreciationRate Applied Depr. Rates (Percent) (e)	MortalityCurveType Mortality Curve Type (f)	UtilityPlantWeightedAverageRemainingLife Average Remaining Life (g)
12	(a) N/A

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: AccountNumberFactorsUsedInEstimatingDepreciationCharges

This section is not required because 2022 does not meet the 5 year reporting cycle requirement, and the Company did not implement a change in approved depreciation rates during the year.

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

REGULATORY COMMISSION EXPENSES
Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts deferred in previous years. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization. List in columns (f), (g), and (h), expenses incurred during the year which were charged currently to income, plant, or other accounts. Minor items (less than $25,000) may be grouped.
						EXPENSES INCURRED DURING YEAR				AMORTIZED DURING YEAR
						CURRENTLY CHARGED TO
Line No.	RegulatoryCommissionDescription Description (Furnish name of regulatory commission or body the docket or case number and a description of the case) (a)	RegulatoryExpensesAssessedByRegulatoryCommission Assessed by Regulatory Commission (b)	RegulatoryExpensesOfUtility Expenses of Utility (c)	RegulatoryCommissionExpensesAmount Total Expenses for Current Year (d)	OtherRegulatoryAssetsRegulatoryCommissionExpenses Deferred in Account 182.3 at Beginning of Year (e)	NameOfDepartmentRegulatoryCommissionExpensesCharged Department (f)	AccountNumberRegulatoryCommissionExpensesCharged Account No. (g)	RegulatoryComissionExpensesIncurredAndCharged Amount (h)	RegulatoryCommissionExpensesDeferredToOtherRegulatoryAssets Deferred to Account 182.3 (i)	DeferredRegulatoryCommissionExpensesAmortizedInContraAccount Contra Account (j)	DeferredRegulatoryCommissionExpensesAmortized Amount (k)	OtherRegulatoryAssetsRegulatoryCommissionExpenses Deferred in Account 182.3 End of Year (l)
1	North Carolina Utilities Commission:
2	NCUC Regulatory Fee	6,804,319		6,804,319		Electric	928	6,804,319
3	Docket E-7, Sub 989 (2011 Rate Case Expenses)									928
4	Docket E-7, Sub 1029 (2013 Rate Case Expenses)									928
5	Docket E-7, Sub 1146 (2017 Rate Case Expenses)		982,162	982,162	4,623,874	Electric	186			928	982,162	3,641,712
6	Docket M-100, Sub 142 (Deferral) / Docket E-7, Sub 1146 (Amort)		555,412	555,412	1,515,013					928	555,412	959,601
7	Docket E-7, Sub 1214 (2018 Rate Case Expenses)		801,000	801,000	2,919,774					928	801,000	2,118,774
8	The Public Service Commission Of South Carolina:
9	SCPSC Regulatory Fee	3,759,634		3,759,634			928	3,759,634
10	Docket 2009-226-E (2009 Rate Case Expenses)		10,133	10,133	130,239	Electric				928	10,133	120,106
11	Docket 2011-271-E (2011 Rate Case Expenses)		15,945	15,945	307,428					928	15,945	291,483
12	Docket 2013-59-E (2013 Rate Case Expenses)		5,000	5,000	638,331					928	5,000	633,331
13	Docket 2018-319-E (2018 Rate Case Expenses)		267,795	267,795	647,172					928	267,795	379,377
14	Federal Energy Regulatory Commission:
15	FERC Regulatory Fee	3,421,593		3,421,593		Electric	928	3,421,593
16	Misc. Legal Expenses:
17	Transmission	104,488		104,488		Electric	928	104,488
18	Distribution	51,638		51,638				51,638
19	Production	33,406		33,406				33,406
20	Other	92,708		92,708				92,708
46	TOTAL	14,267,786	2,637,447	16,905,233	10,781,831			14,267,786			2,637,447	8,144,384

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D and D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(Identify recipient regardless of affiliation.) For any R, D and D work carried with others, show separately the respondent's cost for the year and cost chargeable to others (See definition of research, development, and demonstration in Uniform System of Accounts). Indicate in column (a) the applicable classification, as shown below: Classifications: Electric R, D and D Performed Internally: Generation hydroelectric Recreation fish and wildlife Other hydroelectric Fossil-fuel steam Internal combustion or gas turbine Nuclear Unconventional generation Siting and heat rejection Transmission Overhead Underground Distribution Regional Transmission and Market Operation Environment (other than equipment) Other (Classify and include items in excess of $50,000.) Total Cost Incurred Electric, R, D and D Performed Externally: Research Support to the electrical Research Council or the Electric Power Research Institute Research Support to Edison Electric Institute Research Support to Nuclear Power Groups Research Support to Others (Classify) Total Cost Incurred Include in column (c) all R, D and D items performed internally and in column (d) those items performed outside the company costing $50,000 or more, briefly describing the specific area of R, D and D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.). Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D and D activity. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year, listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e). Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research, Development, and Demonstration Expenditures, Outstanding at the end of the year. If costs have not been segregated for R, D and D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by ""Est."" Report separately research and related testing facilities operated by the respondent.
					AMOUNTS CHARGED IN CURRENT YEAR
Line No.	ResearchDevelopmentAndDemonstrationClassification Classification (a)	ResearchDevelopmentAndDemonstrationDescription Description (b)	ResearchDevelopmentAndDemonstrationCostsIncurredInternally Costs Incurred Internally Current Year (c)	ResearchDevelopmentAndDemonstrationCostsIncurredExternally Costs Incurred Externally Current Year (d)	AccountNumberForResearchDevelopmentAndDemonstrationCosts Amounts Charged In Current Year: Account (e)	ResearchDevelopmentAndDemonstrationCosts Amounts Charged In Current Year: Amount (f)	ResearchDevelopmentAndDemonstrationExpenditures Unamortized Accumulation (g)
1	A. Electric R, D&D Performed Internally:
2	Distribution	Research & Development Administration Costs	9,581		930.7	9,581
3	TOTAL ELECTRIC R, D&D PERFORMED INTERNALLY		9,581			9,581
4	B. Electric R, D&D Performed Externally:
5	Research Support to:
6	Electric Power Research Institute	Electric Power Research Institute Membership		8,106,007	Various	8,106,007
7		Coal Combustion Product Land and Groundwater Management		439,643	511-506	439,643
8		Other (Less than $50K each)		577,148	Various	577,148
9	Research Support to Others	Alternate Energy (Advanced Energy Research)		2,106,638	930.8	2,106,638
10		Centre for Energy Advancement through Tech Innov		121,100	930.7	121,100
11		Georgie Tech Membership		192,746	930.7	192,746
12		University of North Carolina at Charlotte CAPER Membership		125,487	930.7	125,487
13		Other (Less than $50K each)		78,765	930.7	78,765
14	TOTAL ELECTRIC R, D&D PERFORMED EXTERNALLY			11,747,534		11,747,534

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

DISTRIBUTION OF SALARIES AND WAGES
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation giving substantially correct results may be used.
Line No.	Classification (a)	Direct Payroll Distribution (b)	Allocation of Payroll Charged for Clearing Accounts (c)	Total (d)
1	SalariesAndWagesElectricAbstract Electric
2	SalariesAndWagesElectricOperationAbstract Operation
3	SalariesAndWagesElectricOperationProduction Production	298,451,890
4	SalariesAndWagesElectricOperationTransmission Transmission	13,746,653
5	SalariesAndWagesElectricOperationRegionalMarket Regional Market
6	SalariesAndWagesElectricOperationDistribution Distribution	27,028,358
7	SalariesAndWagesElectricOperationCustomerAccounts Customer Accounts	32,788,762
8	SalariesAndWagesElectricOperationCustomerServiceAndInformational Customer Service and Informational	9,218,985
9	SalariesAndWagesElectricOperationSales Sales	10,368,370
10	SalariesAndWagesElectricOperationAdministrativeAndGeneral Administrative and General	164,175,097
11	SalariesAndWagesElectricOperation TOTAL Operation (Enter Total of lines 3 thru 10)	555,778,115
12	SalariesAndWagesElectricMaintenanceAbstract Maintenance
13	SalariesAndWagesElectricMaintenanceProduction Production	178,605,693
14	SalariesAndWagesElectricMaintenanceTransmission Transmission	8,172,159
15	SalariesAndWagesElectricMaintenanceRegionalMarket Regional Market
16	SalariesAndWagesElectricMaintenanceDistribution Distribution	34,442,715
17	SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral Administrative and General	258,454
18	SalariesAndWagesElectricMaintenance TOTAL Maintenance (Total of lines 13 thru 17)	221,479,021
19	SalariesAndWagesElectricOperationAndMaintenanceAbstract Total Operation and Maintenance
20	SalariesAndWagesElectricProduction Production (Enter Total of lines 3 and 13)	477,057,583
21	SalariesAndWagesElectricTransmission Transmission (Enter Total of lines 4 and 14)	21,918,812
22	SalariesAndWagesElectricRegionalMarket Regional Market (Enter Total of Lines 5 and 15)
23	SalariesAndWagesElectricDistribution Distribution (Enter Total of lines 6 and 16)	61,471,073
24	SalariesAndWagesElectricCustomerAccounts Customer Accounts (Transcribe from line 7)	32,788,762
25	SalariesAndWagesElectricCustomerServiceAndInformational Customer Service and Informational (Transcribe from line 8)	9,218,985
26	SalariesAndWagesElectricSales Sales (Transcribe from line 9)	10,368,370
27	SalariesAndWagesElectricAdministrativeAndGeneral Administrative and General (Enter Total of lines 10 and 17)	164,433,551
28	SalariesAndWagesElectricOperationAndMaintenance TOTAL Oper. and Maint. (Total of lines 20 thru 27)	777,257,136	400,254	777,657,390
29	SalariesAndWagesGasAbstract Gas
30	SalariesAndWagesGasOperationAbstract Operation
31	SalariesAndWagesGasOperationProductionManufacturedGas Production - Manufactured Gas
32	SalariesAndWagesGasOperationProductionNaturalGas Production-Nat. Gas (Including Expl. And Dev.)
33	SalariesAndWagesGasOperationOtherGasSupply Other Gas Supply
34	SalariesAndWagesGasOperationStorageLiquifiedNaturalGasTerminalingAndProcessing Storage, LNG Terminaling and Processing
35	SalariesAndWagesGasOperationTransmission Transmission
36	SalariesAndWagesGasOperationDistribution Distribution
37	SalariesAndWagesGasCustomerAccounts Customer Accounts
38	SalariesAndWagesGasCustomerServiceAndInformational Customer Service and Informational
39	SalariesAndWagesGasSales Sales
40	SalariesAndWagesGasOperationAdministrativeAndGeneral Administrative and General
41	SalariesAndWagesGasOperation TOTAL Operation (Enter Total of lines 31 thru 40)
42	SalariesAndWagesGasMaintenanceAbstract Maintenance
43	SalariesAndWagesGasMaintenanceProductionManufacturedGas Production - Manufactured Gas
44	SalariesAndWagesGasMaintenanceProductionNaturalGas Production-Natural Gas (Including Exploration and Development)
45	SalariesAndWagesGasMaintenanceOtherGasSupply Other Gas Supply
46	SalariesAndWagesGasMaintenanceStorageLngTerminalingAndProcessing Storage, LNG Terminaling and Processing
47	SalariesAndWagesGasMaintenanceTransmission Transmission
48	SalariesAndWagesGasMaintenanceDistribution Distribution
49	SalariesAndWagesGasMaintenanceAdministrativeAndGeneral Administrative and General
50	SalariesAndWagesGasMaintenance TOTAL Maint. (Enter Total of lines 43 thru 49)
51	SalariesAndWagesGasOperationAndMaintenanceAbstract Total Operation and Maintenance
52	SalariesAndWagesGasProductionManufacturedGas Production-Manufactured Gas (Enter Total of lines 31 and 43)
53	SalariesAndWagesGasProductionNaturalGas Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,
54	SalariesAndWagesGasOtherGasSupply Other Gas Supply (Enter Total of lines 33 and 45)
55	SalariesAndWagesGasStorageLngTerminalingAndProcessing Storage, LNG Terminaling and Processing (Total of lines 31 thru
56	SalariesAndWagesGasTransmission Transmission (Lines 35 and 47)
57	SalariesAndWagesGasDistribution Distribution (Lines 36 and 48)
58	SalariesAndWagesGasCustomerAccounts Customer Accounts (Line 37)
59	SalariesAndWagesGasCustomerServiceAndInformational Customer Service and Informational (Line 38)
60	SalariesAndWagesGasSales Sales (Line 39)
61	SalariesAndWagesGasAdministrativeAndGeneral Administrative and General (Lines 40 and 49)
62	SalariesAndWagesGasOperationAndMaintenance TOTAL Operation and Maint. (Total of lines 52 thru 61)
63	SalariesAndWagesOtherUtilityDepartmentsAbstract Other Utility Departments
64	SalariesAndWagesOtherUtilityDepartmentsOperationAndMaintenance Operation and Maintenance
65	SalariesAndWagesOperationsAndMaintenance TOTAL All Utility Dept. (Total of lines 28, 62, and 64)	777,257,136	400,254	777,657,390
66	SalariesAndWagesUtilityPlantAbstract Utility Plant
67	SalariesAndWagesUtilityPlantConstructionAbstract Construction (By Utility Departments)
68	SalariesAndWagesUtilityPlantConstructionElectricPlant Electric Plant	312,746,460	28,555,194	341,301,654
69	SalariesAndWagesUtilityPlantConstructionGasPlant Gas Plant
70	SalariesAndWagesUtilityPlantConstructionOther Other (provide details in footnote):
71	SalariesAndWagesUtilityPlantConstruction TOTAL Construction (Total of lines 68 thru 70)	312,746,460	28,555,194	341,301,654
72	SalariesAndWagesPlantRemovalAbstract Plant Removal (By Utility Departments)
73	SalariesAndWagesPlantRemovalElectricPlant Electric Plant	45,040,244		45,040,244
74	SalariesAndWagesPlantRemovalGasPlant Gas Plant
75	SalariesAndWagesPlantRemovalOther Other (provide details in footnote):
76	SalariesAndWagesPlantRemoval TOTAL Plant Removal (Total of lines 73 thru 75)	45,040,244		45,040,244
77	SalariesAndWagesOtherAccountsAbstract Other Accounts (Specify, provide details in footnote):
78	SalariesAndWagesOtherAccountsDescription Other Accounts (Specify, provide details in footnote):
79	SalariesAndWagesOtherAccountsDescription Non-Regulated Products & Services	3,880,246		3,880,246
80	SalariesAndWagesOtherAccountsDescription Other Work in Progress	5,077,540		5,077,540
81	SalariesAndWagesOtherAccountsDescription Other Accounts	5,150,308		5,150,308
82	SalariesAndWagesOtherAccountsDescription
83	SalariesAndWagesOtherAccountsDescription
84	SalariesAndWagesOtherAccountsDescription
85	SalariesAndWagesOtherAccountsDescription
86	SalariesAndWagesOtherAccountsDescription
87	SalariesAndWagesOtherAccountsDescription
88	SalariesAndWagesOtherAccountsDescription
89	SalariesAndWagesOtherAccountsDescription
90	SalariesAndWagesOtherAccountsDescription
91	SalariesAndWagesOtherAccountsDescription
92	SalariesAndWagesOtherAccountsDescription
93	SalariesAndWagesOtherAccountsDescription
94	SalariesAndWagesOtherAccountsDescription
95	SalariesAndWagesOtherAccounts TOTAL Other Accounts	14,108,094		14,108,094
96	SalariesAndWagesGeneralExpense TOTAL SALARIES AND WAGES	1,149,151,934	28,955,448	1,178,107,382

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

COMMON UTILITY PLANT AND EXPENSES
Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by accounts as provided by Electric Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated provisions, and amounts allocated to utility departments using the common utility plant to which such accumulated provisions relate, including explanation of basis of allocation and factors used. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such expenses are related. Explain the basis of allocation used and give the factors of allocation. Give date of approval by the Commission for use of the common utility plant classification and reference to the order of the Commission or other authorization.

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

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)	2,738,894	7,394,277	13,558,029	14,064,189
2.1	Net Purchases (Account 555.1)
3	Net Sales (Account 447)			79	16,952
4	Transmission Rights
5	Ancillary Services
6	Other Items (list separately)
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	2,738,894	7,394,277	13,557,950	14,081,141

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

PURCHASES AND SALES OF ANCILLARY SERVICES
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the respondents Open Access Transmission Tariff. In columns for usage, report usage-related billing determinant and the unit of measure. On Line 1 columns (b), (c), (d), and (e) report the amount of ancillary services purchased and sold during the year. On Line 2 columns (b), (c), (d), and (e) report the amount of reactive supply and voltage control services purchased and sold during the year. On Line 3 columns (b), (c), (d), and (e) report the amount of regulation and frequency response services purchased and sold during the year. On Line 4 columns (b), (c), (d), and (e) report the amount of energy imbalance services purchased and sold during the year. On Lines 5 and 6, columns (b), (c), (d), and (e) report the amount of operating reserve spinning and supplement services purchased and sold during the period. On Line 7 columns (b), (c), (d), and (e) report the total amount of all other types ancillary services purchased or sold during the year. Include in a footnote and specify the amount for each type of other ancillary service provided.
		Amount Purchased for the Year			Amount Sold for the Year
		Usage - Related Billing Determinant			Usage - Related Billing Determinant
Line No.	Type of Ancillary Service (a)	Number of Units (b)	Unit of Measure (c)	Dollar (d)	Number of Units (e)	Unit of Measure (f)	Dollars (g)
1	Scheduling, System Control and Dispatch			70,660			2,529,012
2	Reactive Supply and Voltage	44,030	MWH	59,973	11,859,011	MWH	8,926,027
3	Regulation and Frequency Response						607,378
4	Energy Imbalance	14,881,221	MWH	2,954,691	14,901,043	MWH	7,909,940
5	Operating Reserve - Spinning						1,519,351
6	Operating Reserve - Supplement						1,519,351
7	Other	262153	MWH	9,356,882	37,169	MWH	4,126,849
8	Total (Lines 1 thru 7)	15,187,404		12,442,205	26,797,223		27,137,908

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

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: Duke Energy Carolinas
1	January	22,605	27	8	14,620	4,170	3,032		783
2	February	21,665	9	8	14,288	3,995	3,032		350
3	March	20,445	13	9	12,525	3,886	3,037		997
4	Total for Quarter 1				41,433	12,051	9,101	0	2,130	0
5	April	18,679	25	19	11,797	3,258	3,037		587
6	May	22,618	31	18	14,771	4,263	3,037		547
7	June	25,219	15	17	15,945	5,013	3,037		1,224
8	Total for Quarter 2				42,513	12,534	9,111	0	2,358	0
9	July	24,764	28	16	14,606	4,741	3,037		2,380
10	August	24,273	2	17	14,096	4,709	3,037		2,431
11	September	22,163	6	17	14,205	4,090	3,037		831
12	Total for Quarter 3				42,907	13,540	9,111	0	5,642	0
13	October	18,218	20	8	11,188	3,108	3,037		885
14	November	21,290	21	8	13,276	3,892	3,037		1,085
15	December	24,813	24	7	14,840	5,260	3,037		1,676
16	Total for Quarter 4				39,304	12,260	9,111	0	3,646	0
17	Total				166,157	50,385	36,434	0	13,776	0

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

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: Enter System
1	January
2	February
3	March
4	Total for Quarter 1
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 Year to Date/Year

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

2023-04-14

Year/Period of Report

End of:

2022

ELECTRIC ENERGY ACCOUNT
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
Line No.	Item (a)	MegaWatt Hours (b)	Line No.	Item (a)	MegaWatt Hours (b)
1	SOURCES OF ENERGY		21	DISPOSITION OF ENERGY
2	Generation (Excluding Station Use):		22	Sales to Ultimate Consumers (Including Interdepartmental Sales)	81,277,019
3	Steam	21,669,914	23	Requirements Sales for Resale (See instruction 4, page 311.)	8,128,227
4	Nuclear	44,225,032	24	Non-Requirements Sales for Resale (See instruction 4, page 311.)	1,508,775
5	Hydro-Conventional	1,696,649	25	Energy Furnished Without Charge
6	Hydro-Pumped Storage	3,172,953	26	Energy Used by the Company (Electric Dept Only, Excluding Station Use)	73,791
7	Other	15,849,674	27	Total Energy Losses	4,564,541
8	Less Energy for Pumping	3,870,929	27.1	Total Energy Stored
9	Net Generation (Enter Total of lines 3 through 8)	82,743,293	28	TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL LINE 20 UNDER SOURCES	95,552,353
10	Purchases (other than for Energy Storage)	12,655,282
10.1	Purchases for Energy Storage	0
11	Power Exchanges:
12	Received	7,792,946
13	Delivered	7,744,602
14	Net Exchanges (Line 12 minus line 13)	48,344
15	Transmission For Other (Wheeling)
16	Received	40,702,700
17	Delivered	40,597,266
18	Net Transmission for Other (Line 16 minus line 17)	105,434
19	Transmission By Others Losses
20	TOTAL (Enter Total of Lines 9, 10, 10.1, 14, 18 and 19)	95,552,353

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

MONTHLY PEAKS AND 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)	EnergyActivity Total Monthly Energy (b)	NonRequiredSalesForResaleEnergy Monthly Non-Requirement Sales for Resale & Associated Losses (c)	MonthlyPeakLoad Monthly Peak - Megawatts (d)	DayOfMonthlyPeak Monthly Peak - Day of Month (e)	HourOfMonthlyPeak Monthly Peak - Hour (f)
	NAME OF SYSTEM: Duke Energy Carolinas
29	January	9,046,106	186,210	16,146	27	8
30	February	7,267,421	73,626	15,285	9	8
31	March	7,021,303	45,964	14,150	13	9
32	April	6,627,311	147,666	12,579	25	18
33	May	7,626,115	105,862	15,806	31	18
34	June	8,654,894	57,664	17,963	15	17
35	July	9,507,577	80,158	17,742	28	16
36	August	9,022,029	53,169	17,228	3	17
37	September	7,867,744	146,284	15,508	6	17
38	October	7,074,620	333,974	12,384	20	8
39	November	7,172,203	72,091	15,022	21	8
40	December	8,818,087	206,107	17,829	24	7
41	Total	95,705,410	1,508,775

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

Steam Electric Generating Plant Statistics

1. Report data for plant in Service only.
2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants.
3. Indicate by a footnote any plant leased or operated as a joint facility.
4. If net peak demand for 60 minutes is not available, give data which is available, specifying period.
5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant.
6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.
7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.
8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
9. Items under Cost of Plant are based on USofA accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses.
10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants.
11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.
12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant.

Line No.	Item (a)	Plant Name: Allen	Plant Name: Belews Creek	Plant Name: Buck	Plant Name: Buck CC	Plant Name: Buck CT	Plant Name: Buzzard Roost	Plant Name: Catawba	Plant Name: Clemson CHP	Plant Name: Cliffside	Plant Name: Dan River	Plant Name: Dan River CC	Plant Name: Dan River Steam	Plant Name: Lee	Plant Name: Lee CC	Plant Name: Lee Steam	Plant Name: Lincoln	Plant Name: Marshall	Plant Name: McGuire	Plant Name: Millcreek	Plant Name: Oconee	Plant Name: Riverbend	Plant Name: Riverbend Steam	Plant Name: Rockingham
1	PlantKind Kind of Plant (Internal Comb, Gas Turb, Nuclear)	Steam	Steam	Steam	Combined Cycle	Combustion Turbine	Combustion Turbine	Nuclear	Combined Heat/Power	Steam	Combustion Turbine	Combined Cycle	Steam	Combustion Turbine	Combined Cycle	Steam	Combustion Turbine	Steam	Nuclear	Combustion Turbine	Nuclear	Combustion Turbine	Steam	Combustion Turbine
2	PlantConstructionType Type of Constr (Conventional, Outdoor, Boiler, etc)	Conventional	Conventional	Conventional	Conventional	Conventional	Conventional	Conventional		Conventional	Conventional	Conventional	Conventional	Conventional	Conventional	Conventional	Conventional	Conventional	Conventional	Conventional	Conventional	Conventional	Conventional	Conventional
3	YearPlantOriginallyConstructed Year Originally Constructed	1957	1974	1953	2011	1970	1971	1985	2019	1972	1968	2012	1949	2006	2018	1958	1995	1956	1981	2002	1973	1969	1952	2000
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed	1961	1975	1953	2011	1970	1971	1986	2019	2012	1969	2012	1955	2007	2018	1958	1996	1970	1984	2003	1974	1969	1954	2000
5	InstalledCapacityOfPlant Total Installed Cap (Max Gen Name Plate Ratings-MW)	435	2,491	370	698	104		2,410		1,531	98	698	290	108	739	163	1,754	2,119	2,441	799	2,667	135	466	978
6	NetPeakDemandOnPlant Net Peak Demand on Plant - MW (60 minutes)	343	2,276		724			458		1,393		711		97	813	409	1,544	2,066	2,393	759	2,635			899
7	PlantHoursConnectedToLoad Plant Hours Connected to Load	1,241	8,042		8,144			8,760		6,756		6,882		814	6,912	562	151	8,734	8,760	494	8,760			3,124
8	NetContinuousPlantCapability Net Continuous Plant Capability (Megawatts)
9	NetContinuousPlantCapabilityNotLimitedByCondenserWater When Not Limited by Condenser Water	426	2,220		718			458		1,395		718		96	809	173	1,507	2,078	2,386	756	2,618			895
10	NetContinuousPlantCapabilityLimitedByCondenserWater When Limited by Condenser Water	421	2,220		668			445		1,388		662		84	786		1,161	2,078	2,316	563	2,554			825
11	PlantAverageNumberOfEmployees Average Number of Employees	77	147		34			754	7	109		37		36	2		10	161	866	7	920			11
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh	209,389,000	9,244,086,000		4,866,838,000			3,649,593,000	91,218,000	5,011,651,000		4,110,015,000		55,847,000	4,654,253,000	1,130,000	48,745,000	7,205,918,000	19,450,310,000	129,049,000	21,125,129,000			1,439,160,200
13	CostOfLandAndLandRightsSteamProduction Cost of Plant: Land and Land Rights	583,297	21,251,487	648,626				779,551		3,338,075		119,364			59,537	162,649	3,021,923	5,829,127	754,812	5,063,537	1,504,454			967,095
14	CostOfStructuresAndImprovementsSteamProduction Structures and Improvements	161,363,429	484,700,405		155,719,117			253,827,114	8,605,539	419,626,489		149,221,972		1,389,212	142,149,002	3,425,342	28,822,641	309,900,831	722,501,804	29,986,169	1,057,304,926			3,444,305
15	CostOfEquipmentSteamProduction Equipment Costs	733,782,451	2,105,842,402		559,189,800			648,854,881	21,487,334	2,709,726,406		538,457,977		62,320,836	463,647,649		385,573,682	1,829,939,475	2,823,347,400	226,062,952	3,721,159,228			345,056,515
16	AssetRetirementCostsSteamProduction Asset Retirement Costs	603,040,740	483,926,740					18,734,779		357,700,068								660,359,557	192,959,611		77,290,937
17	CostOfPlant Total cost (total 13 thru 20)	1,498,769,917	3,095,721,034	648,626	714,908,917			922,196,325	30,092,873	3,490,391,038		687,799,313		63,710,048	605,856,188	3,587,991	417,418,246	2,806,028,990	3,353,644,405	261,112,658	4,702,677,671		0	349,467,915
18	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 17/5) Including	3,445.4481	1,242.7624	1.7530	1,024.2248	0.0000		382.6541		2,279.8113	0.0000	985.3858	0.0000	589.9079	819.8325	22.0122	237.9808	1,324.2232	1,373.8814	327	1,763.2837	0.0000	0	357.3292
19	OperationSupervisionAndEngineeringExpense Production Expenses: Oper, Supv, & Engr	1,175,957	3,119,247	6,261	453,080	46,624		3,910,145	231,321	3,182,845		3,321,169	4,995	343,549	596,449	77,643	239,031	3,334,799	19,199,715	114,715	14,800,928		7,886	213,952
20	FuelSteamPowerGeneration Fuel	(a) 12,292,882	(b) 537,026,322	(c) 315,079	(d) 237,963,312			(e) 21,559,773	8,690,213	(f) 310,208,440		(g) 211,214,353	(h) 35	4,950,696	(i) 178,240,276	(j) 31,013	(k) 8,175,641	(l) 381,746,854	107,243,715	17,247,679	121,961,936		(m) 57	109,468,438
21	CoolantsAndWater Coolants and Water (Nuclear Plants Only)							928,113											3,684,115		3,103,708
22	SteamExpensesSteamPowerGeneration Steam Expenses	2,355,225	19,193,862	3,077				3,924,959		10,867,509			27,609			22,855		12,520,881	17,318,506		19,743,660
23	SteamFromOtherSources Steam From Other Sources
24	SteamTransferredCredit Steam Transferred (Cr)
25	ElectricExpensesSteamPowerGeneration Electric Expenses	522,126	1,441,234		4,638,559	14,382		529,542	898,649	1,973,224		1,171,900		238,952	3,808,285	3,323	1,857,860	2,663,399	2,503,963	1,348,427	18,259,548			1,808,564
26	MiscellaneousSteamPowerExpenses Misc Steam (or Nuclear) Power Expenses	916,779	3,455,668	128,578				13,157,090		2,688,642			56,451			184,187		3,212,832	63,572,948		76,987,857		27,212
27	RentsSteamPowerGeneration Rents
28	Allowances Allowances	2	251							99								391					1
29	MaintenanceSupervisionAndEngineeringSteamPowerGeneration Maintenance Supervision and Engineering	1,630,722	3,968,669	56,338	1,009,439	711		3,559,705	177,134	2,795,071		1,256,828	8,322	253,416	1,391,602	97,917	647,384	3,639,423	17,976,584	325,416	24,096,143		13,373	495,569
30	MaintenanceOfStructuresSteamPowerGeneration Maintenance of Structures	1,169,556	5,769,622	72,514	2,030,257	38		631,993	140,072	3,710,257		1,368,907	32,080	225,293	1,706,113	160,699	22,913	3,702,790	2,615,827	224,360	3,050,427		35,600	243,444
31	MaintenanceOfBoilerPlantSteamPowerGeneration Maintenance of Boiler (or reactor) Plant	1,853,157	7,368,210	2,700				5,765,555		5,420,335			2,116			2,581		9,123,078	30,584,926		28,847,258		3,400
32	MaintenanceOfElectricPlantSteamPowerGeneration Maintenance of Electric Plant	284,919	2,097,881	355	1,545,569	4,095		2,771,788	577,549	4,152,574		8,237,030	278	789,226	9,293,457	18,785	716,261	7,586,812	16,700,299	1,623,700	18,725,990		771	2,467,624
33	MaintenanceOfMiscellaneousSteamPlant Maintenance of Misc Steam (or Nuclear) Plant	183,518	2,353,852	922				3,711,937		610,673			1,207			5,525		1,192,838	15,992,641		23,168,570		1,162
34	PowerProductionExpensesSteamPower Total Production Expenses	22,384,843	585,794,818	585,824	247,640,216	64,427		60,450,600	10,714,937	345,609,669		226,570,187	130,679	6,294,300	195,036,182	604,528	11,659,091	428,724,097	297,393,238	20,884,297	352,746,025		89,462	114,697,590
35	ExpensesPerNetKilowattHour Expenses per Net kWh	0.1069	0.0634		0.0509			0.0166	0.1175	0.0690		0.0551		0.1127	0.0419	0.5350	0.2392	0.0595	0.0153	0.1618	0.0167			0.0797

35	FuelKindAxis Plant Name	Allen	Allen	Belews Creek	Belews Creek	Belews Creek	Buck CC	Catawba	Catawba	Clemson CHP	Cliffside	Cliffside	Cliffside	Dan River CC	Lee	Lee	Lee CC	Lee Steam	Lincoln	Lincoln	Marshall	Marshall	Marshall	McGuire	McGuire	Millcreek	Millcreek	Oconee	Oconee	Rockingham	Rockingham
36	FuelKind Fuel Kind	Coal	Oil	Coal	Gas	Oil	Gas	Nuclear	Uranium	Gas	Coal	Gas	Oil	Gas	Gas	Oil	Gas	Gas	Gas	Oil	Coal	Gas	Oil	Nuclear	Uranium	Gas	Oil	Nuclear	Uranium	Gas	Oil
37	FuelUnit Fuel Unit	T	bbl	T	Mcf	bbl	Mcf	MMBTU	g	Mcf	T	Mcf	bbl	Mcf	Mcf	bbl	Mcf	Mcf	Mcf	bbl	T	Mcf	bbl	MMBTU	g	Mcf	bbl	MMBTU	g	Mcf	bbl
38	QuantityOfFuelBurned Quantity (Units) of Fuel Burned	138,866.000	9,457.000	1,224,955.000	58,618,543.000		33,696,453.000	190,667,891.000	3,001,366.000	1,116,433.000	491,602.000	35,562,096.000	10,017.000	28,163,705.000	536,945.000	5,278.000	(n) 28,003,218.000	277.000	404,232.000	49,279.000	1,312,079.000	38,013,721.000	352.000	194,586,633.000	3,069,057.000	1,197,931.000	77,157.000	213,728,237.000	3,113,695.000	15,217,412.000	36,308.000
39	FuelBurnedAverageHeatContent Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)	11,919.000	137,910.000	12,546.000	1,033.000		1,032.000			1,028.000	12,425.000	1,029.000	137,698.000	1,034.000	1,027.000	137,740.000	(o) 1,028.000	1,025.000	1,031.000	138,111.000	12,721.000	1,030.000	137,335.000			1,028.000	137,787.000			1,032.000	137,204.000
40	AverageCostOfFuelPerUnitAsDelivered Avg Cost of Fuel/unit, as Delvd f.o.b. during year	89.390	168.310	90.770	7.337	146.040	7.060			7.783	109.390	7.474	149.820	7.497	8.257	136.570	(p) 6.362	6.343	9.019		107.590	6.961				7.317	130.590			6.943	139.700
41	AverageCostOfFuelPerUnitBurned Average Cost of Fuel per Unit Burned	(q) 76.110	159.590	(r) 83.980	7.337		7.060		37.324	7.783	(s) 83.270	7.474	124.855	7.497	8.257	95.714	(t) 6.362	6.343	9.019	88.023	(u) 88.810	6.961	83.195		34.944	7.317	108.804		39.170	6.943	101.941
42	AverageCostOfFuelBurnedPerMillionBritishThermalUnit Average Cost of Fuel Burned per Million BTU	3.193	27.551	3.347	7.100		6.844	0.588		7.573	3.351	7.261	21.589	7.253	8.042	16.545	(v) 6.188	6.191	8.751	15.175	3.491	6.759	14.440	0.551		7.120	18.801	0.571		6.725	17.690
43	AverageCostOfFuelBurnedPerKilowattHourNetGeneration Average Cost of Fuel Burned per kWh Net Gen	(w) 0.058	(x) 0.058	(y) 0.058	(z) 0.058		0.049	0.006	0.006	0.095	(aa) 0.061	(ab) 0.061	(ac) 0.061	0.052	(ad) 0.088	(ae) 0.088	(af) 0.044	0.004	(ag) 0.164	(ah) 0.164	(ai) 0.053	(aj) 0.053	(ak) 0.053	0.006	0.006	(al) 0.133	(am) 0.133	0.006	0.006	(an) 0.076	(ao) 0.076
44	AverageBritishThermalUnitPerKilowattHourNetGeneration Average BTU per kWh Net Generation	(ap) 16,071.000	(aq) 16,071.000	9,878.000	9,878.000		7,142.000	10,055.000	10,055.000	12,579.000	(ar) 9,753.000	(as) 9,753.000	(at) 9,753.000	7,083.000	(au) 10,419.000	(av) 10,419.000	(aw) 7,088.000	717.000	(ax) 14,411.000	(ay) 14,411.000	(az) 10,066.000	(ba) 10,066.000	(bb) 10,066.000	10,004.000	10,004.000	(bc) 12,999.000	(bd) 12,999.000	10,117.000	10,117.000	(be) 11,062.000	(bf) 11,062.000

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: FuelSteamPowerGeneration

Allen Steam Total fuel costs include Fuel Handling and Sale of Fly Ash.

(b) Concept: FuelSteamPowerGeneration

Belews Creek Steam Total fuel costs include Fuel Handling and Sale of Fly Ash. Belews Creek Steam Plant Units 1 and 2 have been converted to operate using either natural gas or coal . The fuel consumed reflects the dual fuel capacity.

Buck Steam Total fuel costs reflect Sale of Fly Ash. Buck Steam Accounts 0501007, 0501008, and 0501009 for Coal Ash Beneficial Reuse in the amount of ($1,628,028) are excluded.

(d) Concept: FuelSteamPowerGeneration

Buck Combined Cycle Total fuel costs include Biogas account 0547106, 0547107 and 0547108 in the amount of $149,005.

(e) Concept: FuelSteamPowerGeneration

Represents respondent's 19.246% ownership of Catawba units 1 and 2

(f) Concept: FuelSteamPowerGeneration

Cliffside Steam Total fuel costs include Fuel Handling, Coal Sampling, and Sale of Fly Ash. Cliffside Steam Plant Units 5 & 6 have been converted to operate using either natural gas, coal or fuel oil. The fuel consumed reflects the dual fuel capacity.

(g) Concept: FuelSteamPowerGeneration

Dan River Combined Cycle Total fuel costs include Biogas accounts 0547106, 0547107 and 0547108 in the amount of $901,398.

(h) Concept: FuelSteamPowerGeneration

Dan River Steam Total fuel costs reflect Sale of Fly Ash.

(i) Concept: FuelSteamPowerGeneration

Lee Combined Cycle Total fuel costs represents respondent’s ownership share.

(j) Concept: FuelSteamPowerGeneration

Lee Unit 3 Steam Plant has been converted to operate using natural gas. The fuel consumed now relates to natural gas. Lee Steam Total fuel costs include Fuel Handling and Sale of Fly Ash.

(k) Concept: FuelSteamPowerGeneration

Lincoln Combustion Turbine total fuel costs exclude $6,005,110 for Lincoln Unit 17pre-commercial generation.

(l) Concept: FuelSteamPowerGeneration

Marshall Steam Total fuel costs include Fuel Handling and Sale of Fly Ash. Marshall Steam Plant Unit 1-4 have been converted to operate using either natural gas, coal or fuel oil. The fuel consumed reflects the dual fuel capacity.

(m) Concept: FuelSteamPowerGeneration

Riverbend Steam Total fuel costs reflect Sale of Fly Ash.

(n) Concept: QuantityOfFuelBurned

Lee Combined Cycle calculated using respondent’s ownership share.

(o) Concept: FuelBurnedAverageHeatContent

Lee Combined Cycle calculated using respondent’s ownership share.

(p) Concept: AverageCostOfFuelPerUnitAsDelivered

Lee Combined Cycle calculated using respondent’s ownership share.

(q) Concept: AverageCostOfFuelPerUnitBurned

Allen Steam Average Cost of Fuel per Unit Burned does not include cost for Fuel Handling and Sale of Fly Ash.

(r) Concept: AverageCostOfFuelPerUnitBurned

Belews Creek Steam Average Cost of Fuel per Unit Burned does not include cost for Fuel Handling and Sale of Fly Ash.

(s) Concept: AverageCostOfFuelPerUnitBurned

Cliffside Steam Average Cost of Fuel per Unit Burned does not include cost for Fuel Handling, Coal Sampling and Sale of Fly Ash.

(t) Concept: AverageCostOfFuelPerUnitBurned

Lee Combined Cycle calculated using respondent’s ownership share.

(u) Concept: AverageCostOfFuelPerUnitBurned

Marshall Steam Average Cost of Fuel per Unit Burned does not include cost for Fuel Handling and Sale of Fly Ash.

(v) Concept: AverageCostOfFuelBurnedPerMillionBritishThermalUnit

Lee Combined Cycle calculated using respondent’s ownership share.

(w) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(x) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(y) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(z) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(aa) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(ab) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(ac) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(ad) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(ae) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(af) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Lee Combined Cycle calculated using respondent’s ownership share.

(ag) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(ah) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(ai) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(aj) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(ak) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(al) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(am) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(an) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(ao) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(ap) Concept: AverageBritishThermalUnitPerKilowattHourNetGeneration

Conventional steam heat rates include BTU's of both generation and light-off fuels.

(aq) Concept: AverageBritishThermalUnitPerKilowattHourNetGeneration

Conventional steam heat rates include BTU's of both generation and light-off fuels.

(ar) Concept: AverageBritishThermalUnitPerKilowattHourNetGeneration

Conventional steam heat rates include BTU's of both generation and light-off fuels.

(as) Concept: AverageBritishThermalUnitPerKilowattHourNetGeneration

Conventional steam heat rates include BTU's of both generation and light-off fuels.

(at) Concept: AverageBritishThermalUnitPerKilowattHourNetGeneration

Conventional steam heat rates include BTU's of both generation and light-off fuels.

(au) Concept: AverageBritishThermalUnitPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(av) Concept: AverageBritishThermalUnitPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(aw) Concept: AverageBritishThermalUnitPerKilowattHourNetGeneration

Lee Combined Cycle calculated using respondent’s ownership share.

(ax) Concept: AverageBritishThermalUnitPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(ay) Concept: AverageBritishThermalUnitPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(az) Concept: AverageBritishThermalUnitPerKilowattHourNetGeneration

Conventional steam heat rates include BTU's of both generation and light-off fuels.

(ba) Concept: AverageBritishThermalUnitPerKilowattHourNetGeneration

Conventional steam heat rates include BTU's of both generation and light-off fuels.

(bb) Concept: AverageBritishThermalUnitPerKilowattHourNetGeneration

Conventional steam heat rates include BTU's of both generation and light-off fuels.

(bc) Concept: AverageBritishThermalUnitPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(bd) Concept: AverageBritishThermalUnitPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(be) Concept: AverageBritishThermalUnitPerKilowattHourNetGeneration

Calculated on all fuels basis only.

(bf) Concept: AverageBritishThermalUnitPerKilowattHourNetGeneration

Calculated on all fuels basis only.

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

Hydroelectric Generating Plant Statistics

Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings).
If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. If licensed project, give project number.
If net peak demand for 60 minutes is not available, give that which is available specifying period.
If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each plant.
The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.

Line No.	Item (a)	FERC Licensed Project No. 2232 Plant Name: Bridgewater	FERC Licensed Project No. 2232 Plant Name: Cedar Creek	FERC Licensed Project No. 2232 Plant Name: Cowans Ford	FERC Licensed Project No. 2232 Plant Name: Dearborn	FERC Licensed Project No. 2232 Plant Name: Fishing Creek	FERC Licensed Project No. 2232 Plant Name: Great Falls	FERC Licensed Project No. 2232 Plant Name: Lookout Shoals	FERC Licensed Project No. 2232 Plant Name: Mountain Island	FERC Licensed Project No. 2232 Plant Name: Oxford	FERC Licensed Project No. 2232 Plant Name: Rhodhiss	FERC Licensed Project No. 2232 Plant Name: Rocky Creek	FERC Licensed Project No. 2232 Plant Name: Wateree	FERC Licensed Project No. 2232 Plant Name: Wylie	FERC Licensed Project No. 2331 Plant Name: Ninety-Nine Islands	FERC Licensed Project No. 2503 Plant Name: Keowee	FERC Licensed Project No. 2686 Plant Name: Thorpe	FERC Licensed Project No. 2692 Plant Name: Nantahala	FERC Licensed Project No. 2698 Plant Name: Tennessee Creek
1	PlantKind Kind of Plant (Run-of-River or Storage)	Storage	Run-of-River	Storage	Run-of-River	Storage	Run-of-River	Run-of-River	Storage	Storage	Storage	Run-Of-River	Storage	Storage	Run-of-River	Storage	Storage	Storage	Storage
2	PlantConstructionType Plant Construction type (Conventional or Outdoor)	Conventional	Conventional	Outdoor	Conventional	Conventional	Conventional	Conventional	Conventional	Outdoor	Conventional	Conventional	Conventional	Conventional	Conventional	Outdoor	Conventional	Conventional	Conventional
3	YearPlantOriginallyConstructed Year Originally Constructed	2011	1926	1963	1923	1916	1907	1915	1923	1928	1925	1909	1919	1925	1910	1971	1941	1942	1955
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed	2011	1926	1967	1923	1916	1907	1915	1923	1928	1925	1909	1919	1925	1910	1971	1941	1942	1955
5	InstalledCapacityOfPlant Total installed cap (Gen name plate Rating in MW)	28	45	350	45	42	24	26	60	36	26		77	51	18	158
6	NetPeakDemandOnPlant Net Peak Demand on Plant-Megawatts (60 minutes)	31	49	300	40	53		31	61	41	34		72	60	15	152
7	PlantHoursConnectedToLoad Plant Hours Connect to Load	8,433	8,723	1,692	8,757	8,759		8,740	7,462	6,176	5,916		8,760	8,019	7,974	487
8	NetPlantCapabilityAbstract Net Plant Capability (in megawatts)
9	NetPlantCapabilityUnderMostFavorableOperatingConditions (a) Under Most Favorable Oper Conditions	32	45	390	47	56		28	65	44	34		81	66	20	160
10	NetPlantCapabilityUnderMostAdverseOperatingConditions (b) Under the Most Adverse Oper Conditions	28	43	325	42	49		28	58	40	33		74	60	10	152
11	PlantAverageNumberOfEmployees Average Number of Employees	2	2	25	2	3	4	1		2	2		2	7	3		5	5
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh	49,084,000	133,317,000	144,365,000	109,359,000	140,518,000	161,000	95,084,000	103,670,000	98,990,000	60,790,000		188,443,000	122,202,000	45,348,000	56,500,000	73,093,000	191,423,000	35,088,000
13	CostOfPlantAbstract Cost of Plant
14	CostOfLandAndLandRightsHydroelectricProduction Land and Land Rights	1,715,798	34,920	12,390,682	428,669	373,568	27,613	550,590	800,211	1,512,589	525,914		630,071	2,701,971	151,343	21,905,557	1,402,331	469,013	475,718
15	CostOfStructuresAndImprovementsHydroelectricProduction Structures and Improvements	66,232,987	4,034,838	20,120,896	2,131,193	6,400,446	5,548,208	2,871,615	4,264,762	4,525,864	6,105,596	61,939	18,968,587	12,325,600	2,050,256	32,788,215	4,445,001	2,895,035	355,878
16	CostOfReservoirsDamsAndWaterwaysHydroelectricProduction Reservoirs, Dams, and Waterways	200,767,399	12,017,600	38,788,728	67,237,832	30,744,047	2,869,198	5,580,443	14,584,121	36,203,844	19,361,678		15,019,296	38,546,880	13,028,343	17,981,009	6,624,518	18,262,780	12,026,066
17	EquipmentCostsHydroelectricProduction Equipment Costs	35,585,238	21,563,506	83,485,704	16,241,802	29,804,533	6,613,499	13,392,572	30,074,247	23,135,031	20,243,433		43,037,810	34,873,213	13,113,810	192,638,324	4,311,347	8,819,320	14,512,852
18	CostOfRoadsRailroadsAndBridgesHydroelectricProduction Roads, Railroads, and Bridges			2,240,416	633,636												46,024	239,971	72,590
19	AssetRetirementCostsHydroelectricProduction Asset Retirement Costs
20	CostOfPlant Total cost (total 13 thru 20)	304,301,422	37,650,864	157,026,426	86,673,132	67,322,594	15,058,518	22,395,220	49,723,341	65,377,328	46,236,621	61,939	77,655,764	88,447,664	28,343,752	265,313,105	16,829,221	30,686,119	27,443,104
21	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 20 / 5)	10,867.9079	836.6859	448.6469	1,926.0696	1,602.9189	627.4383	861.3546	828.7224	1,816.0369	1,778.3316		1,008.5164	1,734.2679	1,574.6529	1,679.1969
22	ProductionExpensesAbstract Production Expenses
23	OperationSupervisionAndEngineeringExpense Operation Supervision and Engineering	287,600	155,240	1,861,542	126,237	155,242	68,390	161,161	6,179	218,441	202,240	2,671	417,662	380,262	195,264	251,886	235,483	302,755	58,205
24	WaterForPower Water for Power
25	HydraulicExpenses Hydraulic Expenses	200,693	6,408	838,559	6,410	6,023	1,757	31,398	11,010	103,326	48,015	6,795	38,680	212,917	9,903	324,175	67,167	25,645
26	ElectricExpensesHydraulicPowerGeneration Electric Expenses	143,743	238,118	448,311	235,266	133,935	16,122	159,282	113,265	1,611	142,044		297,875	141,722	135,662	1,300,266	15,544	64,590	12,221
27	MiscellaneousHydraulicPowerGenerationExpenses Misc Hydraulic Power Generation Expenses	148,171	196,081	1,487,189	179,384	157,274	247,406	164,467	257,621	165,222	154,106	7,112	249,747	305,890	59	412,440	190,380	258,560	46,040
28	RentsHydraulicPowerGeneration Rents
29	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration Maintenance Supervision and Engineering	28,044	45,599	401,602	63,909	41,596	11,807	26,150	97,847	37,323	27,082		75,853	66,502	12,133	48,190	71,862	121,323	3,637
30	MaintenanceOfStructuresHydraulicPowerGeneration Maintenance of Structures	102	13,618	21,441	2,230	116,631	695	205	1,179	823	3,178	182	2,361	1,888	2,301	13,880	14,817	37,697	3,953
31	MaintenanceOfReservoirsDamsAndWaterways Maintenance of Reservoirs, Dams, and Waterways	108,279	47,664	162,502	26,948	14,224	6,518	44,199	60,460	64,640	66,322	485	60,679	80,206	86,077	402,014	68,188	363,705	42,183
32	MaintenanceOfElectricPlantHydraulicPowerGeneration Maintenance of Electric Plant	131,154	115,799	520,153	83,447	75,036	33,900	287,833	231,213	117,150	173,039	1,391	114,851	207,993	164,761	138,787	240,181	262,901	47,367
33	MaintenanceOfMiscellaneousHydraulicPlant Maintenance of Misc Hydraulic Plant	109,166	33,991	259,822	2,880	39,069	32,414	87,126	42,556	200,946	35,365	4,250	272,742	196,322	90,957	338,075	195,069	223,198	77,583
34	PowerProductionExpensesHydraulicPower Total Production Expenses (total 23 thru 33)	755,566	852,518	4,324,003	720,951	739,030	419,009	961,821	799,310	702,830	755,361	22,886	1,530,450	1,167,868	697,117	2,581,363	1,098,691	1,660,374	291,189
35	ExpensesPerNetKilowattHour Expenses per net kWh	0.0154	0.0064	0.0300	0.0066	0.0053	2.6025	0.0101	0.0077	0.0071	0.0124		0.0081	0.0096	0.0154	0.0457	0.0150	0.0087	0.0083

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

Pumped Storage Generating Plant Statistics
Large plants and pumped storage plants of 10,000 Kw or more of installed capacity (name plate ratings). If any plant is leased, operating under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. Give project number. If net peak demand for 60 minutes is not available, give that which is available, specifying period. If a group of employees attends more than one generating plant, report on Line 8 the approximate average number of employees assignable to each plant. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power System Control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses." Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes. Include on Line 36 the cost of energy used in pumping into the storage reservoir. When this item cannot be accurately computed leave Lines 36, 37 and 38 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of energy from each station or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses per net MWH as reported herein for each source described. Group together stations and other resources which individually provide less than 10 percent of total pumping energy. If contracts are made with others to purchase power for pumping, give the supplier contract number, and date of contract.
Line No.	Item (a)	FERC Licensed Project No. 0 Plant Name: 0	FERC Licensed Project No. 2503 Plant Name: Jocassee	FERC Licensed Project No. 2740 Plant Name: Bad Creek Outdoor
1	PlantConstructionType Type of Plant Construction (Conventional or Outdoor)		Conventional	Outdoor
2	YearPlantOriginallyConstructed Year Originally Constructed		1973	1991
3	YearLastUnitOfPlantInstalled Year Last Unit was Installed		1975	1991
4	InstalledCapacityOfPlant Total installed cap (Gen name plate Rating in MW)		774	1,488
5	NetPeakDemandOnPlant Net Peak Demaind on Plant-Megawatts (60 minutes)		787	1,186
6	PlantHoursConnectedToLoad Plant Hours Connect to Load While Generating		3,027	2,822
7	NetContinuousPlantCapability Net Plant Capability (in megawatts)		780	1,520
8	PlantAverageNumberOfEmployees Average Number of Employees		19	45
9	NetGenerationExcludingPlantUse Generation, Exclusive of Plant Use - kWh		1,302,149	1,844,335
10	EnergyUsedForPumping Energy Used for Pumping		1,544,408	2,300,052
11	NetOutputForLoad Net Output for Load (line 9 - line 10) - Kwh		2,846,557	4,144,387
12	CostOfPlantAbstract Cost of Plant
13	CostOfLandAndLandRightsPumpedStoragePlant Land and Land Rights		5,273,013	1,223,028
14	CostOfStructuresAndImprovementsPumpedStoragePlant Structures and Improvements		35,005,969	233,791,023
15	CostOfReservoirsDamsAndWaterwaysPumpedStoragePlant Reservoirs, Dams, and Waterways		65,257,342	455,745,492
16	CostOfWaterWheelsTurbinesAndGeneratorsPumpedStoragePlant Water Wheels, Turbines, and Generators		72,503,882	287,637,388
17	CostOfAccessoryElectricEquipmentPumpedStoragePlant Accessory Electric Equipment		17,805,661	58,864,589
18	CostOfMiscellaneousPowerPlantEquipmentPumpedStoragePlant Miscellaneous Powerplant Equipment		4,527,557	30,462,544
19	CostOfRoadsRailroadsAndBridgesPumpedStoragePlant Roads, Railroads, and Bridges		415,508	18,888,978
20	AssetRetirementCostsPumpedStoragePlant Asset Retirement Costs
21	CostOfPlant Total cost (total 13 thru 20)		200,788,932	1,086,613,042
22	CostPerKilowattOfInstalledCapacity Cost per KW of installed cap (line 21 / 4)		259.4172	730.2507
23	ProductionExpensesAbstract Production Expenses
24	OperationSupervisionAndEngineeringExpense Operation Supervision and Engineering		904,771	1,558,225
25	WaterForPower Water for Power
26	PumpedStorageExpenses Pumped Storage Expenses		47,412	5,597
27	ElectricExpensesPumpedStoragePlant Electric Expenses		576,748	1,566,043
28	MiscellaneousPumpedStoragePowerGenerationExpenses Misc Pumped Storage Power generation Expenses		2,722,036	2,866,338
29	RentsPumpedStoragePlant Rents
30	MaintenanceSupervisionAndEngineeringPumpedStoragePlant Maintenance Supervision and Engineering		598,921	844,351
31	MaintenanceOfStructuresPumpedStoragePlant Maintenance of Structures		179,290	60,529
32	MaintenanceOfReservoirsDamsAndWaterwaysPumpedStoragePlant Maintenance of Reservoirs, Dams, and Waterways		182,750	339,277
33	MaintenanceOfElectricPlantPumpedStoragePlant Maintenance of Electric Plant		1,438,307	919,562
34	MaintenanceOfMiscellaneousPumpedStoragePlant Maintenance of Misc Pumped Storage Plant		442,067	1,959,427
35	PowerProductionExpenseBeforePumpingExpenses Production Exp Before Pumping Exp (24 thru 34)		7,092,302	10,119,349
36	PumpingExpenses Pumping Expenses
37	PowerProductionExpensesPumpedStoragePlant Total Production Exp (total 35 and 36)		7,092,302	10,119,349
38	ExpensesPerNetKilowattHour Expenses per kWh (line 37 / 9)		5.4466	5.4867
39	ExpensesPerNetKilowattHourGenerationAndPumping Expenses per KWh of Generation and Pumping (line 37/(line 9 + line 10))	0	29	22

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

GENERATING PLANT STATISTICS (Small Plants)
Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped storage plants of less than 10,000 Kw installed capacity (name plate rating). Designate any plant leased from others, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project, give project number in footnote. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11, Page 402. If net peak demand for 60 minutes is not available, give the which is available, specifying period. If any plant is equipped with combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
									Production Expenses
Line No.	PlantName Name of Plant (a)	YearPlantOriginallyConstructed Year Orig. Const. (b)	InstalledCapacityOfPlant Installed Capacity Name Plate Rating (MW) (c)	NetPeakDemandOnPlant Net Peak Demand MW (60 min) (d)	NetGenerationExcludingPlantUse Net Generation Excluding Plant Use (e)	CostOfPlant Cost of Plant (f)	PlantCostPerMw Plant Cost (Incl Asset Retire. Costs) Per MW (g)	OperatingExpensesExcludingFuel Operation Exc'l. Fuel (h)	FuelProductionExpenses Fuel Production Expenses (i)	MaintenanceProductionExpenses Maintenance Production Expenses (j)	FuelKind Kind of Fuel (k)	FuelCostPerMmbtus Fuel Costs (in cents (per Million Btu) (l)	GenerationType Generation Type (m)
1	HYDRO PLANTS:
2	Bear Creek - Project 2698	1954	9.50		24,218	16,055,700	1,690,074	84,111		117,683			Hydro
3	Cedar Cliff - Project 2698	1952	12.80		16,590	10,731,087	838,366	57,639		94,147			Hydro
4	Queen's Creek - Project 2694	1949	1.44		3,089	1,320,122	916,752	52,028		108,717			Hydro
5	Tuckaseegee - Project 2686	1950	2.50		5,639	5,501,357	2,200,543	246,100		87,258			Hydro

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

ENERGY STORAGE OPERATIONS (Large Plants)
Large Plants are plants of 10,000 Kw or more. In columns (a) (b) and (c) report the name of the energy storage project, functional classification (Production, Transmission, Distribution), and location. In column (d), report Megawatt hours (MWH) purchased, generated, or received in exchange transactions for storage. In columns (e), (f) and (g) report MWHs delivered to the grid to support production, transmission and distribution. The amount reported in column (d) should include MWHs delivered/provided to a generator’s own load requirements or used for the provision of ancillary services. In columns (h), (i), and (j) report MWHs lost during conversion, storage and discharge of energy. In column (k) report the MWHs sold. In column (l), report revenues from energy storage operations. In a footnote, disclose the revenue accounts and revenue amounts related to the income generating activity. In column (m), report the cost of power purchased for storage operations and reported in Account 555.1, Power Purchased for Storage Operations. If power was purchased from an affiliated seller specify how the cost of the power was determined. In columns (n) and (o), report fuel costs for storage operations associated with self-generated power included in Account 501 and other costs associated with self-generated power. In columns (q), (r) and (s) report the total project plant costs including but not exclusive of land and land rights, structures and improvements, energy storage equipment, turbines, compressors, generators, switching and conversion equipment, lines and equipment whose primary purpose is to integrate or tie energy storage assets into the power grid, and any other costs associated with the energy storage project included in the property accounts listed.
Line No.	Name of the Energy Storage Project (a)	Functional Classification (b)	Location of the Project (c)	MWHs (d)	MWHs delivered to the grid to support Production (e)	MWHs delivered to the grid to support Transmission (f)	MWHs delivered to the grid to support Distribution (g)	MWHs Lost During Conversion, Storage and Discharge of Energy Production (h)	MWHs Lost During Conversion, Storage and Discharge of Energy Transmission (i)	MWHs Lost During Conversion, Storage and Discharge of Energy Distribution (j)	MWHs Sold (k)	Revenues from Energy Storage Operations (l)	Power Purchased for Storage Operations (555.1) (Dollars) (m)	Fuel Costs from associated fuel accounts for Storage Operations Associated with Self- Generated Power (Dollars) (n)	Other Costs Associated with Self-Generated Power (Dollars) (o)	Project Costs included in (p)	Production (Dollars) (q)	Transmission (Dollars) (r)	Distribution (Dollars) (s)
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

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

TRANSMISSION LINE STATISTICS
Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage. If required by a State commission to report individual lines for all voltages, do so but do not group totals for each voltage under 132 kilovolts. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report substation costs and expenses on this page. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder of the line. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with respect to such structures are included in the expenses reported for the line designated. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g). Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company, give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is an associated company. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how determined. Specify whether lessee is an associated company. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
	DESIGNATION		VOLTAGE (KV) - (Indicate where other than 60 cycle, 3 phase)			LENGTH (Pole miles) - (In the case of underground lines report circuit miles)				COST OF LINE (Include in column (j) Land, Land rights, and clearing right-of-way)			EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line No.	TransmissionLineStartPoint From	TransmissionLineEndPoint To	OperatingVoltageOfTransmissionLine Operating	DesignedVoltageOfTransmissionLine Designated	SupportingStructureOfTransmissionLineType Type of Supporting Structure	LengthForStandAloneTransmissionLines On Structure of Line Designated	LengthForTransmissionLinesAggregatedWithOtherStructures On Structures of Another Line	NumberOfTransmissionCircuits Number of Circuits	SizeOfConductorAndMaterial Size of Conductor and Material	CostOfLandAndLandRightsTransmissionLines Land	ConstructionAndOtherCostsTransmissionLines Construction Costs	OverallCostOfTransmissionLine Total Costs	OperatingExpensesOfTransmissionLine Operation Expenses	MaintenanceExpensesOfTransmissionLine Maintenance Expenses	RentExpensesOfTransmissionLine Rents	OverallExpensesOfTransmissionLine Total Expenses
	(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)	(l)	(m)	(n)	(o)	(p)
1	Antioch Tie	Appalachian Power	525.00	525.00	3	27.89		1	2515 ACSR
2	Cliffside Tie	Cliffisde SW	525.00	525.00	2	0.77		1	2515 ACSR
3	Cliffside Tie	Cliffisde SW	525.00	525.00	3	0.37			2515 ACSR
4	Cliffside Tie	McGuire SW	525.00	525.00	2	0.51		1	2515 ACSR
5	Cliffside Tie	McGuire SW	525.00	525.00	3	48.71			2515 ACSR
6	Jocassee Tie	Bad Creek Hydro	525.00	525.00	3	9.27		1	2515 ACSR
7	Jocassee Tie	Cliffside Tie	525.00	525.00	3	70.57		1	2515 ACSR
8	McGuire SW	Antioch Tie	525.00	525.00	3	54.83		1	2515 ACSR
9	McGuire SW	Woodleaf Switching	525.00	525.00	3	29.96		1	2515 ACSR
10	Newport Tie	McGuire Switching	525.00	525.00	2	2.44		1	2515 ACSR
11	Newport Tie	McGuire Switching	525.00	525.00	3	30.00			2515 ACSR
12	Newport Tie	Progress Energy Rockingham	525.00	525.00	3	48.33		1	2515 ACSR
13	Oconee Nuclear	Newport Tie	525.00	525.00	3	107.47		1	2515 ACSR
14	Oconee Nuclear	South Hall	525.00	525.00	3	22.46		1	2515 ACSR
15	Oconee Nuclear	Jocassee Tie	525.00	525.00	3	20.89		1	2515 ACSR
16	Pleasant Garden Tie	Parkwood Tie	525.00	525.00	3	49.29		1	2515 ACSR
17	Woodleaf Switching	Pleasant Garden Tie	525.00	525.00	3	52.75		1	2515 ACSR
18	Total Cost 525 KV Lines									20,656,136	137,751,483	158,407,619
19	Allen Steam	Catawba Nuclear	230.00	230.00	3	10.91	10.91	2	2156 ACSR
20	Allen Steam	Riverbend Steam	230.00	230.00	3	12.58	12.57	2	2156 ACSR
21	Allen Steam	Winecoff Tie	230.00	230.00	3	32.18	32.16	2	954 ACSR
22	Allen Steam	Woodlawn Tie	230.00	230.00	1	0.37		2	2156 ACSR
23	Allen Steam	Woodlawn Tie	230.00	230.00	3	8.24	8.23		2156 ACSR
24	Anderson Tie	Hodges Tie	230.00	230.00	3	26.06	25.30	2	954 ACSR
25	Antioch Tie	Wilkes Tie	230.00	230.00	3	4.27	4.26	2	954 ACSR
26	Beckerdite Tie	Belews Creek Steam	230.00	230.00	3	24.68	24.67	2	2156 ACSR
27	Beckerdite Tie	Pleasant Garden Tie	230.00	230.00	3	28.22	28.22	2	954 ACSR
28	Belews Creek Steam	Ernest Switching Station	230.00	230.00	3	13.61	13.61	2	1272 ACSR
29	Belews Creek Steam	North Greensboro Tie	230.00	230.00	3	21.58	21.59	2	2156 ACSR
30	Belews Creek Steam	Pleasant Garden Tie	230.00	230.00	3	38.76	38.76	2	2156 ACSR
31	Belews Creek Steam	Rural Hall Tie	230.00	230.00	3	18.28	18.29	2	2156 ACSR
32	Bobwhite Switching	North Greensboro Tie	230.00	230.00	3	3.87	3.86	2	2156 ACSR
33	Buck Tie	Beckerdite Tie	230.00	230.00	3	23.75	23.74	2	954 ACSR
34	Bush River Tie	SCE&G (Parr)	230.00	230.00	3	17.74		1	954 ACSR
35	Catawba Nuclear	Newport Tie (Newport)	230.00	230.00	3	5.18	5.18	2	1272 ACSR
36	Catawba Nuclear	Newport Tie (Allison Creek)	230.00	230.00	3	5.20	5.20	2	1272 ACSR
37	Catawba Nuclear	Pacolet Tie	230.00	230.00	3	41.01	41.00	2	954 ACSR
38	Catawba Nuclear	Peacock Tie	230.00	230.00	1	0.50		2	1272 ACSR
39	Catawba Nuclear	Peacock Tie	230.00	230.00	3	14.78	14.45		1272 ACSR
40	Catawba Nuclear	Ripp Switching Station	230.00	230.00	3	24.32	24.32	2	1272 ACSR
41	Central Tie	Anderson Tie	230.00	230.00	3	23.21	23.22	2	954 ACSR
42	Cliffside Steam	Pacolet Tie	230.00	230.00	3	23.19	23.18	2	954 ACSR
43	Cliffside Steam	Shelby Tie	230.00	230.00	3	14.09	14.08	2	954 ACSR
44	Cowans Ford Hydro	McGuire Switching	230.00	230.00	3	1.68	1.67	2	795 ACSR
45	Dixon School Rd Switching	Ripp Switching Station	230.00	230.00	3	5.29	5.29	2	795 ACSR
46	East Durham Tie	Parkwood Tie	230.00	230.00	3	19.32	19.31	2	1272 ACSR
47	Eno Tap Bent	East Durham Tie	230.00	230.00	3	15.77	15.77	2	1272 ACSR
48	Eno Tap Bent	Progress Energy (Roxboro)	230.00	230.00	3	13.86	13.86	2	1272 ACSR
49	Ernest Switching Station	Sadler Tie	230.00	230.00	3	12.56	12.55	2	1272 ACSR
50	Harrisburg Tie	Oakboro Tie	230.00	230.00	3	21.39	21.39	2	954 ACSR
51	Hartwell Hydro	Anderson Tie	230.00	230.00	3	11.12	11.14	2	954 ACSR
52	Jocassee Switching	Shiloh Switching	230.00	230.00	3	22.33	22.34	2	2156 ACSR
53	Jocassee Switching	Tuckasegee Tie	230.00	230.00	3	26.69	26.68	2	1272 ACSR
54	Lakewood Tie	Riverbend Steam	230.00	230.00	3	10.64	10.65	2	954 ACSR
55	Lincoln CT	Orchard Tie	230.00	230.00	3	19.75	19.73	2	795 ACSR
56	Longview Tie	McDowell Tie	230.00	230.00	3	31.69	31.69	2	954 ACSR
57	Marshall Steam	Beckerdite Tie	230.00	230.00	3	52.48	52.46	2	954 ACSR
58	Marshall Steam	Longview Tie	230.00	230.00	3	28.91	28.91	2	1272 ACSR
59	Marshall Steam	McGuire Switching	230.00	230.00	3	13.84	13.84	2	1272 ACSR
60	Marshall Steam	Stamey Tie	230.00	230.00	3	13.55	13.54	2	954 ACSR
61	Marshall Steam	Winecoff Tie	230.00	230.00	3	24.29	24.29	2	1272 ACSR
62	McGuire Startup Tap		230.00	230.00	3	0.04		1	795 ACSR
63	McGuire Switching	Harrisburg Tie C	230.00	230.00	3	19.09	19.07	2	1272 ACSR
64	McGuire Switching	Harrisburg Tie M	230.00	230.00	3	17.12	17.12	2	1272 ACSR
65	Mitchell River Tie	Antioch Tie	230.00	230.00	3	16.82	16.81	2	954 ACSR
66	Mitchell River Tie	Rural Hall Tie	230.00	230.00	3	26.61	26.61	2	954 ACSR
67	Morningstar Tie	Oakboro Tie	230.00	230.00	3	32.50		1	954 ACSR
68	North Greenville Tie	Central Tie	230.00	230.00	1	3.26		2	954 ACSR
69	North Greenville Tie	Central Tie	230.00	230.00	3	22.91	26.15		954 ACSR
70	North Greenville Tie	Shiloh Switching	230.00	230.00	3	8.99	8.99	2	954 ACSR
71	Newport Tie	Morningstar Tie	230.00	230.00	3	33.47	0.03	1	954 ACSR
72	Newport Tie	SCE&G (Parr)	230.00	230.00	3	45.63		1	954 ACSR
73	Oakboro Tie	Progress Energy Rockingham	230.00	230.00	3	5.14	5.14	2	954 ACSR
74	Oconee Nuclear	Central Tie "Calhoun"	230.00	230.00	3	8.78	8.78	2	1272 ACSR
75	Oconee Nuclear	Central Tie "Oconee"	230.00	230.00	3	8.80	8.80	2	1272 ACSR
76	Oconee Nuclear	Jocassee Switching	230.00	230.00	3	12.36	12.35	2	2156 ACSR
77	Oconee Nuclear	North Greenville Tie	230.00	230.00	1	1.27		2	1272 ACSR
78	Oconee Nuclear	North Greenville Tie	230.00	230.00	3	27.83	29.11		1272 ACSR
79	Orchard Tie	Longview Tie	230.00	230.00	3	12.70	12.70	2	795 ACSR
80	Pacolet Tie	Tiger Tie	230.00	230.00	3	27.85	27.87	2	954 ACSR
81	Peach Valley Tie	Tiger Tie	230.00	230.00	3	15.59	15.60	2	795 ACSR
82	Pisgah Tie	Progress Energy Skyland Stm	230.00	230.00	3	14.48	14.48	2	954 ACSR
83	Pleasant Garden Tie	Eno Tie	230.00	230.00	3	42.52	42.52	2	954 ACSR
84	Ripp Switching	Riverview Switching	230.00	230.00	3	9.72	9.71	2	795 ACSR
85	Ripp Switching	Shelby Tie	230.00	230.00	3	9.96	9.97	2	954 ACSR
86	Riverbend Steam	Dixon School Rd Switching	230.00	230.00	3	24.76	24.76	2	795 ACSR
87	Riverbend Steam	Lincoln CT	230.00	230.00	3	11.59	11.49	2	795 ACSR
88	Riverbend Steam	McGuire Switching	230.00	230.00	3	5.62	5.63	2	1533 ACSS
89	Riverview Switching	Peach Valley Tie	230.00	230.00	3	19.17	19.14	2	795 ACSR
90	Shady Grove Tap	Shady Grove Tie	230.00	230.00	3	7.79	7.79	2	2515 ACSR
91	Shiloh Switching	Pisgah Tie	230.00	230.00	3	21.96	21.95	2	1158 ACSS
92	Shiloh Switching	Tiger Tie	230.00	230.00	3	21.31	21.32	2	1272 ACSR
93	Stamey Tie	Mitchell River Tie	230.00	230.00	3	36.16	36.16	2	954 ACSR
94	Tiger Tie	North Greenville Tie	230.00	230.00	3	18.30	18.30	2	954 ACSR
95	Winecoff Tie	Buck Tie	230.00	230.00	3	24.09	24.09	2	954 ACSR
96	Total Cost 230 KV Lines									42,410,125	348,533,384	390,943,510
97	Fontana (TVA)	Nantahala Hydro	161.00	161.00	3	18.47		1	795 ACSR
98	Nantahala Hydro	Webster Tie	161.00	161.00	1	0.11	25.51	1	795 ACSR
99	Nantahala Hydro	Marble Tie	161.00	161.00	3	16.80	16.80	2	795 ACSR
100	Nantahala Hydro	Robbinsville Substation	161.00	161.00	3	0.03	8.11	1	795 ACSR
101	Santeetlah Hydro	Robbinsville Substation	161.00	161.00	3	0.44	10.24	1	795 ACSR
102	Tuckasegee Tie	Thorpe Hydro	161.00	161.00	2	1.77		1	397.5 ACSR
103	Tuckasegee Tie	Thorpe Hydro	161.00	161.00	3	1.38			397.5 ACSR
104	Tuckasegee Tie	Webster Tie	161.00	161.00	3		10.36	1	795 ACSR
105	Tuckasegee Tie	Wests Mill Tie	161.00	161.00	3	22.96		1	795 ACSR
106	Webster Tie	Lake Emory Tie	161.00	161.00	1	12.71		1	636 ACSR
107	Wests Mill Tie	Lake Emory Tie	161.00	161.00	2	6.72		1	795 ACSR
108	Wests Mill Tie	Nantahala Hydro	161.00	161.00	3	12.98		1	795 ACSR
109	Wests Mill Tie	Swain Tie	161.00	161.00	1	2.41		1	954 ACSR
110	Wests Mill Tie	Swain Tie	161.00	161.00	3	9.87			954 ACSR
111	Total Cost 161 KV Lines									3,736,539	120,403,819	124,140,358
112	Dan River Steam	Appalachian Power (Fieldale)	138.00	138.00	2	5.39		1	397.5 ACSR
113	Dan River Steam	Appalachian Power (Fieldale)	138.00	138.00	3	1.12			397.5 ACSR
114	Total Cost 138 KV Lines								.
115	All 115 KV Lines		115.00	115.00		55.26	11.32	5
116	Total Cost 115 KV Lines
117	All 100 KV Lines		100.00	100.00		3,573.53	3,019.56	1,157
118	Total Cost 100 KV Lines									90,926,708	1,199,801,224	1,290,727,932
119	All 66 KV Lines		66.00	66.00		105.78	14.89	28
120	Total Cost 66 KV Lines									5,793,848	43,215,153	49,009,002
121	All 44 KV Lines		44.00	44.00		2,309.02	443.81	1,224
122	Total Cost 44 KV Lines									30,246,389	609,546,121	639,792,511
123	All 33 KV Lines		33.00	33.00		4.06	1.17	4
124	Total Cost 33 KV Lines
125	All 24 KV Lines		24.00	24.00		53.81	9.73	38
126	Total Cost 24 KV Lines
127	All 13 KV Lines		13.00	13.00		0.08	0.18	7
128	Total Costs 13 KV Lines
129	All 12 KV Lines		12.00	12.00		23.05	6.78	44
130	Total Costs 12 KV Lines
131	Total Cost 12-33 KV Lines									754,618	9,891,790	10,646,408
36	TOTAL												1,578,726	14,636,966		16,215,692

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

TRANSMISSION LINES ADDED DURING YEAR
Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report minor revisions of lines. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m). If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase, indicate such other characteristic.
	LINE DESIGNATION			SUPPORTING STRUCTURE		CIRCUITS PER STRUCTURE		CONDUCTORS				LINE COST
Line No.	TransmissionLineStartPoint From	TransmissionLineEndPoint To	LengthOfTransmissionLineAdded Line Length in Miles	SupportingStructureOfTransmissionLineType Type	AverageNumberOfSupportingStructuresOfTransmissionLinePerMiles Average Number per Miles	NumberOfTransmissionCircuitsPerStructurePresent Present	NumberOfTransmissionCircuitsPerStructureUltimate Ultimate	ConductorSize Size	ConductorSpecification Specification	ConductorConfigurationAndSpacing Configuration and Spacing	OperatingVoltageOfTransmissionLine Voltage KV (Operating)	CostOfLandAndLandRightsTransmissionLinesAdded Land and Land Rights	CostOfPolesTowersAndFixturesTransmissionLinesAdded Poles, Towers and Fixtures	CostOfConductorsAndDevicesTransmissionLinesAdded Conductors and Devices	Asset Retire. Costs	CostOfTransmissionLinesAdded Total	SupportingStructureConstructionType Construction
	(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)	(l)	(m)	(n)	(o)	(p)	(q)
1	Arlington Ret Tap		2.79	1		2	2	954 ACSR			100		5,184,293	4,400,645		9,584,938
2	Horseshoe T	Progress Energy (Skyland Stm)	0.35	2		1	1	1272 ACSR			100		1,346,909			1,346,909
3	Mcadenville Jct	Stonewater T	0.29	3		2	2	1272 ACSR			100		827,013	721,215	115,828	1,664,056
4	Stonewater T	Lakewood T R	0.26	3		2	2	1272 ACSR			100		846,472	735,936	28,495	1,610,903
5	Stonewater T	Lakewood T L	0.24	3		2	2	336 ACSR			100		758,565	721,071	222,204	1,701,840
6	Simmental Solar Tap		0.15	1		1	1	556 ACSR			100		208,637			208,637
7	Mooresville T	Brawley School Ret	0.11	3		1	1	954 AAC			100		1,035,193			1,035,193
8	Sunset Ret	Conley Sw Sta	0.09	1		1	1	795 ACSR			100		92,021	92,021	333	184,375
9	Lick Creek Solar Tap		0.07	2		1	1	556 ACSR			100			530,401		530,401
10	Egger Wood Products LLC		0.06	1		1	1	556 ACSR			100		326,560			326,560
11	Stanly Solar Tap		0.06	1		1	1	954 ACSR			100		202,354	160,926	9,640	372,920
12	Union EMC Del 22 Tap		0.04	1		1	1	795 ACSS			100		802,169			802,169
13	Ram W-100/44 BT Hillsboro 1		0.03	2		1	1	336 ACSR			100					0
14	N Stanley Ret Tap		0.07	3		2	2	477 ACSR			100			467,800	91,603	559,403
15	Mooresville T	Cherokee Mooresville Pl S1	0.14	3		2	2	477 ACSR			100		441,902			441,902
16	Plantation P/L (Huntersville) Tap		0.33								100			224	31,104	31,328
17	Hendersonville T	Horseshoe T	5.69	1		2	2	556 ACSR			44					0
18	Mebane T	Mebane Ret	0.47	1		1	1	4/0 ACSR			44		53,940	13,485	5,901	73,326
19	Riverbend STM	Mtn Island Hyd	0.21	3		2	2	556 ACSR			44		548,470		73,934	622,404
20	Riverbend STM	Cowans Ford Hyd	0.20	1		1	1	477 ACSR			44		420,890	276,670	114,747	812,307
21	Seneca Tie	BASF Corp	0.12	1		1	1	556 ACSR			44					0
22	Riverbend STM	Four Walls Assoc Pl	0.05	3		2	2	447 ACSR			44		433,191	269,024	89,722	791,937
23	Pinson Solar Tap		0.04	1		1	1	556 ACSR			44		707,759			707,759
24	Pinnacle T	Mitchell R T	0.02	1		1	1	336 ACSR			44		230		363	593
25	Riverbend STM	Lucia No 2	0.04	1		1	1	477 ACSR			44		405,344	278,450	111,308	795,102
26	Edneyville Ret Tap		0.08	1		1	2	556 ACSR			44					0
27	Lions Mountain Tie	Haywood EMC Del 1	0.08	1		1	1	1/0 ACSR			44					0
28	Riverbend STM	Mcadenville Jct	0.10	1		1	1				44					0
29	Riverbend STM	Wildcat T	0.13	1		1	1	556 ACSR			44					0
30	Greenlight Enterprise Upper Pl Tap		0.14								44					0
31	Hampton Capital Turnersbrg T&D Tap		0.33								44					0
32	One World Tech Inc Pickens		0.43	1		1	1	1/0 ACSR			44					0
33	Old C&NW		0.51								44		3,064		117,413	120,477
34	James Clarkson Tap		0.58								44					0
35	Stowe M (Eagle Yarn M) Tap		0.87								44					0
36	Belton T	Blair M	0.89	1		1	1	336 ACSR			44					0
37	Peeler Ret	E Spartanburg Tie	11.96	1		1	1				33		20,959		2,284,144	2,305,103
38	Spencer Mtn Line		0.63	1		2	2				12			106,652	19,478	126,130
44	TOTAL		6.03		0.00	42.00	43.00						14,665,935	8,774,520	3,316,217	26,756,672

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

SUBSTATIONS
Report below the information called for concerning substations of the respondent as of the end of the year. Substations which serve only one industrial or street railway customer should not be listed below. Substations with capacities of Less than 10 MVA except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f). Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
		Character of Substation		VOLTAGE (In MVa)						Conversion Apparatus and Special Equipment
Line No.	SubstationNameAndLocation Name and Location of Substation (a)	SubstationCharacterDescription Transmission or Distribution (b)	SubstationCharacterAttendedOrUnattended Attended or Unattended (b-1)	PrimaryVoltageLevel Primary Voltage (In MVa) (c)	SecondaryVoltageLevel Secondary Voltage (In MVa) (d)	TertiaryVoltageLevel Tertiary Voltage (In MVa) (e)	SubstationInServiceCapacity Capacity of Substation (In Service) (In MVa) (f)	NumberOfTransformersInService Number of Transformers In Service (g)	Number of Spare Transformers (h)	ConversionApparatusAndSpecialEquipmentType Type of Equipment (i)	NumberOfConversionApparatusAndSpecialEquipmentUnits Number of Units (j)	CapacityOfConversionApparatusAndSpecialEquipment Total Capacity (In MVa) (k)
1	ABBOTTS CREEK TIE LEXINGTON NC	Transmission	Unattended	24.00	0.20	0	0	1	0
2	ABBOTTS CREEK TIE LEXINGTON NC	Transmission	Unattended	100.00	44.00	0	72	3	0
3	ACREROCK TIE DALLAS NC	Transmission	Unattended	44.00	6.90	2	9	3	1
4	ACREROCK TIE DALLAS NC	Transmission	Unattended	100.00	44.00	0	40	2	0
5	ADVANCE RET ADVANCE NC	Distribution	Unattended	100.00	13.00	0	40	2
6	ALBEMARLE CITY DEL 2 ALBEMARLE NC	Distribution	Unattended	100.00	24.00	0	12	1
7	ALBEMARLE CITY DEL 2 ALBEMARLE NC	Distribution	Unattended	100.00	24.00	13	12	1
8	ALBEMARLE SW STA ALBEMARLE NC	Distribution	Unattended	100.00	13.00	7	70	6	1
9	ALLEN STEAM PL BELMONT NC	Transmission	Unattended	100.00	13.00	0	300	1
10	ALLEN STEAM PL BELMONT NC	Transmission	Unattended	100.00	15.00	15	336	0	1
11	ALLEN STEAM PL BELMONT NC	Transmission	Unattended	100.00	24.00	0	370	2
12	ALLEN STEAM PL BELMONT NC	Transmission	Unattended	230.00	13.00	0	650	3
13	ALLEN STEAM PL BELMONT NC	Transmission	Unattended	230.00	100.00	13	185	1
14	ALLEN STEAM PL BELMONT NC	Transmission	Unattended	230.00	100.00	44	300	1
15	ANDERSON TIE STARR SC	Transmission	Unattended	230.00	44.00	0	75	1
16	ANDERSON TIE STARR SC	Transmission	Unattended	230.00	100.00	44	1344	3
17	ANTIOCH TIE WILKESBORO NC	Transmission	Unattended	22.90	0.40	0	2	2
18	ANTIOCH TIE WILKESBORO NC	Transmission	Unattended	525.00	230.00	23	3360	6	1
19	APALACHE RET GREER SC	Distribution	Unattended	44.00	13.00	0	28	2
20	ARROWOOD RET CHARLOTTE NC	Distribution	Unattended	100.00	24.00	0	60	3
21	ASHCRAFT AVE RET MONROE NC	Distribution	Unattended	100.00	24.00	0	20	1
22	ASHE ST SW STA DURHAM NC	Transmission	Unattended	100.00	13.00	0	40	2
23	ASHEVILLE HWY RET HENDERSONVILLE NC	Distribution	Unattended	100.00	13.00	0	60	3
24	AUGUSTA RD RET GREENVILLE SC	Distribution	Unattended	100.00	13.00	0	40	2
25	AUNT HILL RET NC	Transmission	Unattended	100.00	12.50	0	22	1
26	AVONDALE RET AVONDALE NC	Distribution	Unattended	44.00	6.90	2	20	7	1
27	BAD CREEK HYDRO BAD CREEK SC	Transmission	Unattended	100.00	4.10	0	13	1
28	BAD CREEK HYDRO BAD CREEK SC	Transmission	Unattended	500.00	24.00	24	0	0	1
29	BAD CREEK HYDRO BAD CREEK SC	Transmission	Unattended	525.00	24.00	0	0	3
30	BAINBRIDGE RET GREENVILLE SC	Distribution	Unattended	100.00	13.00	0	40	2
31	BALL PARK RET KANNAPOLIS NC	Distribution	Unattended	44.00	2.40	0	8	3	1
32	BALL PARK RET KANNAPOLIS NC	Distribution	Unattended	44.00	6.90	2	8	3	1
33	BALSAM RET HENDERSONVILLE NC	Distribution	Unattended	44.00	13.00	0	14	1
34	BALSAM RET HENDERSONVILLE NC	Distribution	Unattended	44.00	13.00	7	12	3
35	BANCROFT RET CHARLOTTE NC	Distribution	Unattended	100.00	13.00	0	40	2
36	BANKS ST RET FORT MILL SC	Distribution	Unattended	100.00	13.00	0	12	1
37	BANNERTOWN TIE MT AIRY NC	Transmission	Unattended	100.00	13.00	0	36	3
38	BAPTIST HOSP T&D WINSTON-SALEM NC	Distribution	Unattended	100.00	13.00	0	40	2
39	BARBEE CHAPEL RD RET DURHAM NC	Distribution	Unattended	100.00	24.00	0	20	1
40	BARRIER RD RET RIMER NC	Distribution	Unattended	100.00	13.00		23	1
41	BEATTIES FORD RET CHARLOTTE NC	Distribution	Unattended	100	13	0	13	1
42	BEATTIES FORD RET CHARLOTTE NC	Distribution	Unattended	100	24	0	20	1
43	BEAVER DAM RET MARSHVILLE NC	Distribution	Unattended	100	24	0	79	3
44	BECKERDITE SVC WINSTON-SALEM NC	Transmission	Unattended	16	0	0	161	1
45	BECKERDITE SVC WINSTON-SALEM NC	Transmission	Unattended	100	24	0	240	3	1
46	BECKERDITE TIE WINSTON-SALEM NC	Transmission	Unattended	44	0	0	1	2
47	BECKERDITE TIE WINSTON-SALEM NC	Transmission	Unattended	100	13	7	16	3	1
48	BECKERDITE TIE WINSTON-SALEM NC	Transmission	Unattended	230	100	13	400	2
49	BECKERDITE TIE WINSTON-SALEM NC	Transmission	Unattended	230	100	44	570	2
50	BEECH ST RET HENDERSONVILLE NC	Distribution	Unattended	44	2	0	12	3	1
51	BELEWS CREEK STEAM STA UNIT 1 BELEWS CREEK NC	Transmission	Unattended	7	1	0	16	7	1
52	BELEWS CREEK STEAM STA UNIT 1 BELEWS CREEK NC	Transmission	Unattended	7	7	0	2	1
53	BELEWS CREEK STEAM STA UNIT 1 BELEWS CREEK NC	Transmission	Unattended	13	7	7	80	1
54	BELEWS CREEK STEAM STA UNIT 1 BELEWS CREEK NC	Transmission	Unattended	230	7	7	78	1
55	BELEWS CREEK STEAM STA UNIT 1 BELEWS CREEK NC	Transmission	Unattended	230	13	0	1500	2
56	BELEWS CREEK STEAM STA UNIT 2 BELEWS CREEK NC	Transmission	Unattended	7	1	0	17	8
57	BELEWS CREEK STEAM STA UNIT 2 BELEWS CREEK NC	Transmission	Unattended	13	7	7	78	1
58	BELEWS CREEK STEAM STA UNIT 2 BELEWS CREEK NC	Transmission	Unattended	230	7	7	78	1
59	BELEWS CREEK STEAM STA UNIT 2 BELEWS CREEK NC	Transmission	Unattended	230	13	0	750	1
60	BELEWS CREEK STEAM STA UNIT 2 BELEWS CREEK NC	Transmission	Unattended	230	24	0	760	1
61	BELEWS CREEK SW STA BELEWS CREEK NC	Transmission	Unattended	7	0	0	1	1
62	BELEWS CREEK SW STA BELEWS CREEK NC	Transmission	Unattended	230	18	0	760	0	1
63	BELLHAVEN RET CHARLOTTE NC	Distribution	Unattended	100	13	0	40	2
64	BELMONT TIE BELMONT NC	Transmission	Unattended	24	0	0	0	1
65	BELMONT TIE BELMONT NC	Transmission	Unattended	44	13	0	20	2
66	BELMONT TIE BELMONT NC	Transmission	Unattended	100	44	0	60	2
67	BELTON RET BELTON SC	Distribution	Unattended	24	2	0	1	0	1
68	BELTON RET BELTON SC	Distribution	Unattended	24	2	1	3	3
69	BELTON RET BELTON SC	Distribution	Unattended	44	7	2	23	9	2
70	BELTON TIE BELTON SC	Transmission	Unattended	24	0	0	0	1
71	BELTON TIE BELTON SC	Transmission	Unattended	100	44	0	90	3
72	BEREA RD RET GREENVILLE SC	Distribution	Unattended	100	13	0	44	2
73	BESSEMER CITY RET BESSEMER CITY NC	Distribution	Unattended	44	2	0	9	3
74	BESSEMER CITY RET BESSEMER CITY NC	Distribution	Unattended	44	7	2	11	3	2
75	BETHEL RET CLOVER SC	Distribution	Unattended	44	7	2	11	6	1
76	BETHLEHEM SS HICKORY NC	Distribution	Unattended	44	13	0	20	2
77	BETHWARE RET KINGS MOUNTAIN NC	Distribution	Unattended	100	13	0	12	1
78	BIG WILLOW RET HENDERSONVILLE NC	Distribution	Unattended	44	13	0	10	1
79	BINGHAM RET HILLSBOROUGH NC	Distribution	Unattended	100	13	0	44	2
80	BLACK CREEK RET CHESTER SC	Transmission	Unattended	100	13	0	37	2
81	BLACK CREEK RET CHESTER SC	Transmission	Unattended	100	24	0	0	0
82	BLACKSBURG RET BLACKSBURG SC	Distribution	Unattended	44	7	0	11	3	1
83	BLACKSBURG RET BLACKSBURG SC	Distribution	Unattended	44	13	0	10	1
84	BLACKSBURG TIE BLACKSBURG SC	Transmission	Unattended	24	0	0	0	1
85	BLACKSBURG TIE BLACKSBURG SC	Transmission	Unattended	100	44	0	60	2
86	BLAKLEY RET LAURENS SC	Distribution	Unattended	44	13	0	10	1
87	BLANTON RET SHELBY NC	Distribution	Unattended	44	13	0	20	2
88	BLANTYRE RET HORSE SHOE NC	Distribution	Unattended	100	13	0	35	2
89	BLUE RIDGE E C DEL 11 EASLEY SC	Distribution	Unattended	100	13	0	12	1
90	BLUE RIDGE E C DEL 12 WESTMINSTER SC	Distribution	Unattended	100	7	0	12	3	1
91	BLUE RIDGE E C DEL 14 PICKENS SC	Distribution	Unattended	100	7	2	12	3	1
92	BOB JONES UNIV DIST GREENVILLE SC	Distribution	Unattended	13	2	0	6	3
93	BOB JONES UNIV DIST GREENVILLE SC	Distribution	Unattended	13	4	0	5	0	1
94	BOILING SPRINGS RET BOILING SPRINGS SC	Distribution	Unattended	100	13	0	74	2
95	BOND PARK RET SPARTANBURG SC	Distribution	Unattended	44	13	0	10	1
96	BOND PARK RET SPARTANBURG SC	Distribution	Unattended	44	13	4	10	1
97	BOND PARK RET SPARTANBURG SC	Distribution	Unattended	44	24	13	10	1
98	BONSET AMERICA GREENSBORO NC	Transmission	Unattended	100	24	0	22	1
99	BOUNTY LAND SS SENECA SC	Distribution	Unattended	44	7	2	5	1	1
100	BOUNTY LAND SS SENECA SC	Distribution	Unattended	44	13	0	10	1
101	BOUNTY LAND SS SENECA SC	Distribution	Unattended	44	13	7	2	1
102	BOUNTY LAND SS SENECA SC	Distribution	Unattended	44	24	13	2	1
103	BRANCH RD RET WALHALLA SC	Distribution	Unattended	44	7	2	6	3
104	BRANCH RD RET WALHALLA SC	Distribution	Unattended	44	13	0	11	1
105	BRANTLEY RD RET KANNAPOLIS NC	Distribution	Unattended	100	13	0	24	2
106	BRASSFIELD RET DURHAM NC	Distribution	Unattended	230	24	0	90	2	1
107	BRAWLEY SCHOOL RET MOORESVILLE NC	Distribution	Unattended	100	13	0	71	2
108	BRAWLEY SCHOOL RET MOORESVILLE NC	Distribution	Unattended	100	24	0	76	2
109	BRENTWOOD RET SIMPSONVILLE SC	Transmission	Unattended	100	13	0	111	3
110	BREVARD RET BREVARD NC	Distribution	Unattended	44	2	0	3	3
111	BREVARD RET BREVARD NC	Distribution	Unattended	44	7	2	15	6	2
112	BRIAR CREEK RET CHARLOTTE NC	Distribution	Unattended	100	12	0	0	1
113	BRIAR CREEK RET CHARLOTTE NC	Distribution	Unattended	100	13	0	37	1
114	BRIDGEPORT RET MORGANTON NC	Distribution	Unattended	44	13	0	20	2
115	BRIDGEWATER HYDRO PL MORGANTON NC	Transmission	Unattended	7	1	0	0	3
116	BRIDGEWATER HYDRO PL MORGANTON NC	Transmission	Unattended	100	7	0	30	2
117	BRIDGEWATER HYDRO PL MORGANTON NC	Transmission	Unattended	100	44	0	12	1
118	BROOK ST RET NORTH WILKESBORO NC	Distribution	Unattended	100	13	0	40	2
119	BROOKWOOD RET WINSTON-SALEM NC	Distribution	Unattended	100	13	0	24	2
120	BROUGHTON RET MORGANTON NC	Distribution	Unattended	44	13	0	4	2
121	BROWNS FORD RET NORTH WILKESBORO NC	Transmission	Unattended	100	13	0	44	2
122	BRUSHY CREEK RET GREENVILLE SC	Distribution	Unattended	100	13	0	40	2
123	BUCK STEAM STA YARD SPENCER NC	Transmission	Unattended	4	0	0	8	4
124	BUCK STEAM STA YARD SPENCER NC	Transmission	Unattended	13	1	0	15	13
125	BUCK STEAM STA YARD SPENCER NC	Transmission	Unattended	13	4	0	10	2
126	BUCK STEAM STA YARD SPENCER NC	Transmission	Unattended	24	1	0	2	2
127	BUCK STEAM STA YARD SPENCER NC	Transmission	Unattended	24	4	0	34	2
128	BUCK STEAM STA YARD SPENCER NC	Transmission	Unattended	100	13	0	0	0
129	BUCK TIE SPENCER NC	Transmission	Unattended	13	0	0	2	2
130	BUCK TIE SPENCER NC	Transmission	Unattended	100	14	0	5	1
131	BUCK TIE SPENCER NC	Transmission	Unattended	230	100	13	400	1
132	BUCK TIE SPENCER NC	Transmission	Unattended	230	100	44	448	1
133	BUCKEYE RET CHARLOTTE NC	Distribution	Unattended	100	24	0	74	2
134	BURLINGTON MN BURLINGTON NC	Distribution	Unattended	24	2	0	8	3	1
135	BURLINGTON MN BURLINGTON NC	Distribution	Unattended	100	24	0	40	2
136	BUSH RIVER TIE NEWBERRY SC	Transmission	Unattended	24	0	0	0	1
137	BUSH RIVER TIE NEWBERRY SC	Transmission	Unattended	44	0	0	10	1
138	BUSH RIVER TIE NEWBERRY SC	Transmission	Unattended	44	2	0	3	3
139	BUSH RIVER TIE NEWBERRY SC	Transmission	Unattended	100	13	7	1	1
140	BUSH RIVER TIE NEWBERRY SC	Transmission	Unattended	100	100	0	30	1
141	BUSH RIVER TIE NEWBERRY SC	Transmission	Unattended	100	100	4	30	1
142	BUSH RIVER TIE NEWBERRY SC	Transmission	Unattended	100	100	13	60	1
143	BUSH RIVER TIE NEWBERRY SC	Transmission	Unattended	230	100	44	200	1
144	BUSTER BOYD RET CHARLOTTE NC	Distribution	Unattended	100	24	0	37	1
145	BUTNER RET DURHAM NC	Transmission	Unattended	100	24	0	130	3
146	BUXTON ST RET WINSTON-SALEM NC	Distribution	Unattended	24	2	0	3	3
147	BUXTON ST RET WINSTON-SALEM NC	Distribution	Unattended	24	7	2	0	0	1
148	BUXTON ST RET WINSTON-SALEM NC	Distribution	Unattended	100	13	0	75	2
149	BUXTON ST RET WINSTON-SALEM NC	Distribution	Unattended	100	24	0	75	2
150	BUZZARD ROOST COMB TURBINE CHAPPELLS SC	Transmission	Unattended	100	13	0	140	1
151	BUZZARD ROOST COMB TURBINE CHAPPELLS SC	Transmission	Unattended	100	13	13	200	1
152	BYRUM CREEK RET ANDERSON SC	Distribution	Unattended	100	13	0	12	1
153	CAIRO RET NORTH WILKESBORO NC	Distribution	Unattended	100	13	0	12	1
154	CAMERON AVE SS CHAPEL HILL NC	Transmission	Unattended	100	13	0	40	2
155	CAMP CREEK RD RET WHITTIER NC	Distribution	Unattended	69	13	0	34	1	1
156	CAMP CROFT RET SPARTANBURG SC	Distribution	Unattended	100	13	0	24	2
157	CAMPOBELLO TIE CAMPOBELLO SC	Transmission	Unattended	24	0	0	0	1
158	CAMPOBELLO TIE CAMPOBELLO SC	Transmission	Unattended	44	13	0	10	1
159	CAMPOBELLO TIE CAMPOBELLO SC	Transmission	Unattended	100	44	0	90	3
160	CAMPTON RET INMAN SC	Distribution	Unattended	100	13	0	24	2
161	CANE CREEK TIE TAYLORS SC	Transmission	Unattended	44	0	0	0	0	1
162	CANE CREEK TIE TAYLORS SC	Transmission	Unattended	100	44	0	15	3
163	CANE CREEK TIE TAYLORS SC	Transmission	Unattended	100	44	24	15	3
164	CANE CREEK TIE TAYLORS SC	Transmission	Unattended	100	44	44	0	0	1
165	CANOE CREEK RET MORGANTON NC	Distribution	Unattended	44	7	0	3	3
166	CANOE CREEK RET MORGANTON NC	Distribution	Unattended	44	13	7	12	3	1
167	CARMEL RD RET CHARLOTTE NC	Transmission	Unattended	100	13	0	108	3
168	CARSON RET MARION NC	Distribution	Unattended	44	13	0	20	2
169	CARVER ST RET CLOVER SC	Distribution	Unattended	44	7	2	21	6	1
170	CASHIERS RET CASHIERS NC	Distribution	Unattended	69	13	0	28	2
171	CATAWBA NUC STA UNIT 1 ROCK HILL SC	Transmission	Unattended	4	1	0	18	9
172	CATAWBA NUC STA UNIT 1 ROCK HILL SC	Transmission	Unattended	7	0	0	2	2
173	CATAWBA NUC STA UNIT 1 ROCK HILL SC	Transmission	Unattended	7	1	0	30	15
174	CATAWBA NUC STA UNIT 1 ROCK HILL SC	Transmission	Unattended	7	4	0	24	3
175	CATAWBA NUC STA UNIT 1 ROCK HILL SC	Transmission	Unattended	13	1	0	12	4
176	CATAWBA NUC STA UNIT 1 ROCK HILL SC	Transmission	Unattended	24	7	7	168	4
177	CATAWBA NUC STA UNIT 1 ROCK HILL SC	Transmission	Unattended	24	13	0	24	1
178	CATAWBA NUC STA UNIT 1 ROCK HILL SC	Transmission	Unattended	230	24	0	1500	2
179	CATAWBA NUC STA UNIT 2 ROCK HILL SC	Transmission	Unattended	4	1	0	16	8
180	CATAWBA NUC STA UNIT 2 ROCK HILL SC	Transmission	Unattended	7	0	0	4	0	2
181	CATAWBA NUC STA UNIT 2 ROCK HILL SC	Transmission	Unattended	7	1	0	24	12
182	CATAWBA NUC STA UNIT 2 ROCK HILL SC	Transmission	Unattended	7	4	0	24	3
183	CATAWBA NUC STA UNIT 2 ROCK HILL SC	Transmission	Unattended	13	1	0	9	3
184	CATAWBA NUC STA UNIT 2 ROCK HILL SC	Transmission	Unattended	24	7	7	168	4
185	CATAWBA NUC STA UNIT 2 ROCK HILL SC	Transmission	Unattended	24	13	0	24	1
186	CATAWBA NUC STA UNIT 2 ROCK HILL SC	Transmission	Unattended	230	24	0	1500	2
187	CATAWBA RET CATAWBA NC	Distribution	Unattended	44	13	0	28	2
188	CATFISH RET HICKORY NC	Distribution	Unattended	44	13	0	20	2
189	CATHEY RD RET ANDERSON SC	Transmission	Unattended	100	13	0	22	1
190	CENTRAL TIE CENTRAL SC	Transmission	Unattended	44	0	0	39	2
191	CENTRAL TIE CENTRAL SC	Transmission	Unattended	44	7	2	3	3
192	CENTRAL TIE CENTRAL SC	Transmission	Unattended	230	100	44	1344	4
193	CHAMBERS RET MORGANTON NC	Distribution	Unattended	44	7	0	0	0
194	CHAMBERS RET MORGANTON NC	Distribution	Unattended	44	7	2	28	2
195	CHEROKEE RESERVATION RET CHEROKEE NC	Distribution	Unattended	66	13	0	30	3
196	CHERRYVILLE MAIN CHERRYVILLE NC	Distribution	Unattended	44	13	0	20	2
197	CHERRYVILLE RET CHERRYVILLE NC	Distribution	Unattended	44	13	0	10	1
198	CHERRYVILLE TIE CHERRYVILLE NC	Transmission	Unattended	44	0	0	0	1
199	CHERRYVILLE TIE CHERRYVILLE NC	Transmission	Unattended	100	44	0	90	3
200	CHESNEE RET CHESNEE SC	Distribution	Unattended	44	13	0	20	2
201	CHESNEE TIE CHESNEE SC	Transmission	Unattended	100	44	0	24	2
202	CHESTER MAIN CHESTER SC	Distribution	Unattended	24	7	2	4	3	1
203	CHESTER MAIN CHESTER SC	Distribution	Unattended	100	13	7	24	3	2
204	CHESTER MAIN CHESTER SC	Distribution	Unattended	100	44	13	12	3
205	CHINA GROVE MAIN CHINA GROVE NC	Transmission	Unattended	24	0	0	0	1
206	CHINA GROVE MAIN CHINA GROVE NC	Transmission	Unattended	100	44	0	36	3
207	CHINA GROVE RET CHINA GROVE NC	Distribution	Unattended	44	2	0	3	3
208	CHINA GROVE RET CHINA GROVE NC	Distribution	Unattended	100	13	0	20	1
209	CHRISTOPHER RD RET SHELBY NC	Distribution	Unattended	100	13	0	12	1
210	CLAREMONT RET CLAREMONT NC	Distribution	Unattended	100	13	0	24	2
211	CLARK HILL TIE GREENWOOD SC	Transmission	Unattended	24	0	0	0	0
212	CLARK HILL TIE GREENWOOD SC	Transmission	Unattended	100	44	0	165	3
213	CLARK HILL TIE GREENWOOD SC	Transmission	Unattended	100	100	0	125	1
214	CLEGHORN SS RUTHERFORDTON NC	Distribution	Unattended	44	13	0	10	1
215	CLEMMONS RET CLEMMONS NC	Distribution	Unattended	100	13	0	24	2
216	CLEVELAND RET CLEVELAND NC	Distribution	Unattended	100	13	7	21	3	1
217	CLIFFSIDE STEAM STA 1-4 SW YD CLIFFSIDE NC	Transmission	Unattended	4	0	0	0	2
218	CLIFFSIDE STEAM STA 1-4 SW YD CLIFFSIDE NC	Transmission	Unattended	44	1	2	2	2
219	CLIFFSIDE STEAM STA 1-4 SW YD CLIFFSIDE NC	Transmission	Unattended	44	13	0	14	1
220	CLIFFSIDE STEAM STA 5 SW YD CLIFFSIDE NC	Transmission	Unattended	4	0	0	6	3
221	CLIFFSIDE STEAM STA 5 SW YD CLIFFSIDE NC	Transmission	Unattended	4	1	0	18	10
222	CLIFFSIDE STEAM STA 5 SW YD CLIFFSIDE NC	Transmission	Unattended	24	4	0	43	1
223	CLIFFSIDE STEAM STA 5 SW YD CLIFFSIDE NC	Transmission	Unattended	230	4	0	56	2
224	CLIFFSIDE STEAM STA 5 SW YD CLIFFSIDE NC	Transmission	Unattended	230	24	0	773	1
225	CLIFFSIDE STEAM STA 5 SW YD CLIFFSIDE NC	Transmission	Unattended	230	100	44	784	2
226	CLIMAX RET CLIMAX NC	Distribution	Unattended	44	13	0	28	2
227	CLINTON CITY CLINTON SC	Distribution	Unattended	100	24	13	30	2
228	CLINTON TIE CLINTON SC	Transmission	Unattended	24	0	0	0	1
229	CLINTON TIE CLINTON SC	Transmission	Unattended	100	44	24	16	3	1
230	CLOVER TIE CLOVER SC	Transmission	Unattended	24	0	0	0	1
231	CLOVER TIE CLOVER SC	Transmission	Unattended	100	44	0	60	2
232	CODDLE CREEK RET MOORESVILLE NC	Distribution	Unattended	44	13	0	88	2
233	COFFEY CREEK RET CHARLOTTE NC	Distribution	Unattended	100	24	0	60	2
234	COLFAX RET COLFAX NC	Distribution	Unattended	100	24	0	60	2
235	COLUMBUS RET COLUMBUS NC	Distribution	Unattended	44	13	0	11	1
236	COLUMBUS RET COLUMBUS NC	Distribution	Unattended	44	13	7	8	3	1
237	COMMONWEALTH RET CHARLOTTE NC	Distribution	Unattended	100	13	0	40	2
238	COMMSCOPE SHERRILLS FORD T&D SHERRILLS FORD NC	Distribution	Unattended	44	13	0	16	2
239	CONCORD CITY DEL 1 CONCORD NC	Distribution	Unattended	24	0	0	0	1
240	CONCORD CITY DEL 1 CONCORD NC	Distribution	Unattended	100	44	0	90	2
241	CONCORD MAIN CONCORD NC	Transmission	Unattended	100	13	0	25	2
242	CONCORD MAIN CONCORD NC	Transmission	Unattended	100	44	0	60	2
243	CONWAY RET GREENVILLE SC	Distribution	Unattended	100	13	0	40	2
244	CORINTH RET ELLENBORO NC	Distribution	Unattended	44	13	0	14	1
245	CORONACA RET CORONACA SC	Distribution	Unattended	44	13	0	10	2
246	CORONACA TIE CORONACA SC	Transmission	Unattended	24	0	0	0	1
247	CORONACA TIE CORONACA SC	Transmission	Unattended	100	44	0	70	3
248	COTTONWOOD RET CORNELIUS NC	Distribution	Unattended	100	13	0	22	1	1
249	COUNTRYSIDE RD RET KINGS MOUNTAIN NC	Distribution	Unattended	100	24	0	74	2
250	COWANS FORD HYDRO STANLEY NC	Transmission	Unattended	13	1	0	2	2
251	COWANS FORD HYDRO STANLEY NC	Transmission	Unattended	44	1	0	1	1
252	COWANS FORD HYDRO STANLEY NC	Transmission	Unattended	230	13	13	276	2
253	COWPENS RET COWPENS SC	Distribution	Unattended	44	7	2	12	3	1
254	COWPENS RET COWPENS SC	Distribution	Unattended	44	13	0	10	1
255	CREST ST RET DURHAM NC	Distribution	Unattended	100	7	0	28	6	1
256	CRETO TIE NINETY SIX SC	Transmission	Unattended	100	44	0	30	1
257	CRUMP RD RET HUDSON NC	Distribution	Unattended	100	13	0	24	2
258	CULLOWHEE RET CULLOWHEE NC	Distribution	Unattended	66	13	0	15	2
259	CYCLE RET ELKIN NC	Distribution	Unattended	44	13	0	28	2
260	CYPRESS TIE ABBEVILLE SC	Transmission	Unattended	24	0	0	0	1
261	CYPRESS TIE ABBEVILLE SC	Transmission	Unattended	100	44	0	60	2
262	DACIAN AVE RET DURHAM NC	Distribution	Unattended	100	24	0	40	2
263	DALLAS CITY DEL 2 DALLAS NC	Distribution	Unattended	44	13	0	14	2
264	DAN RIVER STEAM STA EDEN NC	Transmission	Unattended	2	1	0	0	0
265	DAN RIVER STEAM STA EDEN NC	Transmission	Unattended	138	100	14	127	4
266	DAN VALLEY RET STONEVILLE NC	Distribution	Unattended	100	13	0	24	2
267	DANBURY RET DANBURY NC	Distribution	Unattended	44	24	13	10	1
268	DANIELS RET GREENVILLE SC	Distribution	Unattended	100	13	0	40	2
269	DAVIDSON RET DAVIDSON NC	Distribution	Unattended	44	7	2	21	6	1
270	DAVIDSON RET DAVIDSON NC	Distribution	Unattended	44	13	0	10	1
271	DAVIDSON RIVER RET PISGAH FOREST NC	Transmission	Unattended	100	13	0	12	1
272	DAVIS RET WILLIAMSTON SC	Distribution	Unattended	100	13	0	12	1
273	DEARBORN HYDRO GREAT FALLS SC	Transmission	Unattended	44	7	0	16	2
274	DEARBORN HYDRO GREAT FALLS SC	Transmission	Unattended	100	66	0	25	1
275	DEATH VALLEY RET SC	Transmission	Unattended	100	13	0	44	2
276	DEERFIELD RET MOORESVILLE NC	Distribution	Unattended	100	13	0	37	1
277	DENNY RD RET GREENSBORO NC	Distribution	Unattended	100	24	0	62	3
278	DENTON RET DENTON NC	Transmission	Unattended	100	13	0	22	1
279	DEPOT ST RET FRANKLIN NC	Distribution	Unattended	66	0	0	10	1
280	DEPOT ST RET FRANKLIN NC	Distribution	Unattended	69	13	0	10	1
281	DERITA RET CHARLOTTE NC	Transmission	Unattended	100	24	0	111	3
282	DILWORTH DIST CHARLOTTE NC	Distribution	Unattended	24	2	1	8	3	1
283	DILWORTH DIST CHARLOTTE NC	Distribution	Unattended	24	7	2	8	3	1
284	DIXIE TIE GASTONIA NC	Transmission	Unattended	100	0	0	0	1
285	DIXIE TIE GASTONIA NC	Transmission	Unattended	100	44	0	40	2
286	DIXON RET ANDERSON SC	Distribution	Unattended	100	13	0	12	1
287	DOBSON RET DOBSON NC	Distribution	Unattended	44	12	0	0	2
288	DOCHENO RET HONEA PATH SC	Distribution	Unattended	44	13	0	28	2
289	DRAKA COMTEQ T&D CLAREMONT NC	Distribution	Unattended	100	24	13	15	1
290	DUKE UNIV MN DURHAM NC	Distribution	Unattended	100	44	0	168	3
291	DUKE UNIV STA 1 DURHAM NC	Distribution	Unattended	44	13	0	24	2
292	DUKE UNIV STA 2 DURHAM NC	Distribution	Unattended	44	13	0	36	3
293	DUKE UNIV STA 3 DURHAM NC	Distribution	Unattended	44	13	0	22	1	1
294	DUKE UNIV STA 4 DURHAM NC	Distribution	Unattended	44	13	0	26	2
295	DUNBAR RET MOORESVILLE NC	Distribution	Unattended	100	13	0	40	2
296	DUNCAN RET DUNCAN SC	Distribution	Unattended	44	13	0	20	2
297	DURHAM MN DURHAM NC	Distribution	Unattended	100	13	0	99	3
298	E BRYSON RET BRYSON CITY NC	Distribution	Unattended	66	13	0	10	1
299	E CHESTER RET CHESTER SC	Distribution	Unattended	100	13	0	24	2
300	E DURHAM TIE DURHAM NC	Transmission	Unattended	44	0	0	1	1
301	E DURHAM TIE DURHAM NC	Transmission	Unattended	230	100	44	700	2
302	E FRANKLIN RET FRANKLIN NC	Distribution	Unattended	66	13	0	20	2
303	E GANTT RET CONESTEE SC	Distribution	Unattended	44	13	0	20	2
304	E MAIDEN RET MAIDEN NC	Distribution	Unattended	44	7	0	3	0	1
305	E MAIDEN RET MAIDEN NC	Distribution	Unattended	44	7	2	9	3
306	E MAIDEN RET MAIDEN NC	Distribution	Unattended	44	13	0	10	1
307	E SPARTANBURG TIE SPARTANBURG SC	Transmission	Unattended	44	7	2	0	3
308	E SPARTANBURG TIE SPARTANBURG SC	Transmission	Unattended	100	7	2	9	3	1
309	E SPARTANBURG TIE SPARTANBURG SC	Transmission	Unattended	100	44	0	36	3
310	E SYLVA RET SYLVA NC	Distribution	Unattended	66	13	0	20	2
311	E THOMASVILLE RET THOMASVILLE NC	Distribution	Unattended	100	13	0	40	2
312	EASLEY CITY DEL 3 EASLEY SC	Distribution	Unattended	100	24	13	10	1
313	EASLEY CITY DEL 3 EASLEY SC	Distribution	Unattended	100	44	24	10	1
314	EASLEY CITY DEL 4 EASLEY SC	Distribution	Unattended	100	13	0	12	1
315	EASLEY MN EASLEY SC	Transmission	Unattended	100	13	0	62	3
316	EASLEY MN EASLEY SC	Transmission	Unattended	100	44	0	66	2
317	EASTATOE RET PICKENS SC	Distribution	Unattended	100	13	0	12	1
318	EASTFIELD RD RET CONCORD NC	Distribution	Unattended	100	13	0	12	1
319	EASTFIELD RD RET CONCORD NC	Distribution	Unattended	100	24	0	20	1
320	EASTGATE RET CHAPEL HILL NC	Distribution	Unattended	100	13	0	40	2
321	EASTOVER RET GREENVILLE SC	Transmission	Unattended	100	13	0	102	3
322	EASY ST RET CONCORD NC	Distribution	Unattended	44	13	0	12	1
323	EBENEZER RET TRAVELERS REST SC	Distribution	Unattended	100	13	0	20	1
324	EBERT RD RET WINSTON-SALEM NC	Transmission	Unattended	100	13	0	37	1
325	EFLAND RET EFLAND NC	Distribution	Unattended	44	13	0	16	2
326	ELIZABETH AVE RET CHARLOTTE NC	Distribution	Unattended	24	4	0	10	1
327	ELIZABETH AVE RET CHARLOTTE NC	Distribution	Unattended	24	4	2	11	1
328	ELIZABETH AVE RET CHARLOTTE NC	Distribution	Unattended	100	13	0	111	3
329	ELIZABETH AVE RET CHARLOTTE NC	Distribution	Unattended	100	24	0	103	3
330	ELK VALLEY RET ELKIN NC	Distribution	Unattended	100	13	0	24	2
331	ELKIN RET ELKIN NC	Distribution	Unattended	44	2	0	3	3
332	ELKIN RET ELKIN NC	Distribution	Unattended	44	2	1	1	0	1
333	ELKIN RET ELKIN NC	Distribution	Unattended	44	7	2	8	3	1
334	ELLERBEE RET CHAPEL HILL NC	Distribution	Unattended	100	13	0	12	1
335	ELLIOTT RET SHELBY NC	Distribution	Unattended	100	13	0	25	2
336	ELLIS RD RET DURHAM NC	Transmission	Unattended	100	24	0	112	2
337	ELLISBORO RET REIDSVILLE NC	Distribution	Unattended	100	13	0	37	1
338	ELMWOOD RET ELMWOOD NC	Distribution	Unattended	100	24	0	12	1
339	EMERALD RD RET GREENWOOD SC	Distribution	Unattended	100	13	0	12	1
340	ENERGYUNITED EMC DEL 11 TAYLORSVILLE NC	Distribution	Unattended	100	24	13	16	3	1
341	ENO RET DURHAM NC	Distribution	Unattended	44	24	0	28	2
342	ENO TIE DURHAM NC	Transmission	Unattended	13	0	0	1	1
343	ENO TIE DURHAM NC	Transmission	Unattended	230	100	13	200	1
344	ENO TIE DURHAM NC	Transmission	Unattended	230	100	44	1000	4
345	ENOCHVILLE RET KANNAPOLIS NC	Distribution	Unattended	100	13	0	24	2
346	ENOLA RET SPARTANBURG SC	Distribution	Unattended	100	13	0	30	2
347	FAIR GROVE RET THOMASVILLE NC	Distribution	Unattended	100	13	0	12	1
348	FAIRFAX RD RET GREENSBORO NC	Distribution	Unattended	100	24	0	90	3
349	FAIRNTOSH RET DURHAM NC	Distribution	Unattended	100	24	0	40	2
350	FAIRPLAINS RET NORTH WILKESBORO NC	Distribution	Unattended	100	13	0	24	2
351	FAIRVIEW TIE FOREST CITY NC	Transmission	Unattended	100	44	0	90	3
352	FAITH RET SALISBURY NC	Distribution	Unattended	100	13	0	24	2
353	FALL CREEK RET JONESVILLE NC	Distribution	Unattended	44	7	0	4	2	1
354	FALL CREEK RET JONESVILLE NC	Distribution	Unattended	44	7	2	14	4
355	FANTS GROVE RET PENDLETON SC	Distribution	Unattended	44	13	0	14	1
356	FANTS GROVE RET PENDLETON SC	Distribution	Unattended	44	24	0	22	2
357	FIDDLERS CREEK RET WINSTON-SALEM NC	Distribution	Unattended	100	12	0	37	1
358	FIDDLERS CREEK RET WINSTON-SALEM NC	Distribution	Unattended	100	13	0	37	1
359	FINGERVILLE RET FINGERVILLE SC	Distribution	Unattended	100	13	0	12	1
360	FIRST ST RET HICKORY NC	Distribution	Unattended	44	7	2	8	3	1
361	FIRST ST RET HICKORY NC	Distribution	Unattended	44	13	4	20	2
362	FISHER SS CHARLOTTE NC	Distribution	Unattended	24	4	0	0	2
363	FISHER SS CHARLOTTE NC	Distribution	Unattended	100	24	0	40	2
364	FISHING CREEK HYDRO GREAT FALLS SC	Transmission	Unattended	100	7	0	47	2
365	FITESA SIMPSONVILLE T&D FOUNTAIN INN SC	Distribution	Unattended	100	24	0	22	1
366	FLAT ROCK RET ANDERSON SC	Distribution	Unattended	44	13	0	26	3
367	FLAY RET LINCOLNTON NC	Distribution	Unattended	44	7	2	12	3	1
368	FLORIDA AVE RET GREENWOOD SC	Distribution	Unattended	44	7	2	6	3
369	FLORIDA AVE RET GREENWOOD SC	Distribution	Unattended	44	13	0	10	1
370	FOREST CITY DEL 2 FOREST CITY NC	Distribution	Unattended	44	7	2	18	6	1
371	FOREST CITY DEL 3 FOREST CITY NC	Distribution	Unattended	44	13	0	20	2
372	FOREST HILL RET GREENWOOD SC	Distribution	Unattended	44	13	0	16	2
373	FOREST LAKE RET FORT MILL SC	Distribution	Unattended	44	24	0	28	2
374	FOUR SEASONS RET CHARLOTTE NC	Distribution	Unattended	100	24	0	40	2
375	FRIEDEN RET GIBSONVILLE NC	Distribution	Unattended	100	24	0	40	2
376	FRIENDSHIP RET GREENSBORO NC	Distribution	Unattended	100	24	0	60	2
377	FRONTIER SPINNING M PL 3 MAYODAN NC	Distribution	Unattended	44	0	0	66	6
378	FURR RD RET HUNTERSVILLE NC	Distribution	Unattended	44	13	0	10	1
379	GAFFNEY CITY DEL 1A & 1B GAFFNEY SC	Transmission	Unattended	100	24	0	74	2
380	GAFFNEY TIE GAFFNEY SC	Transmission	Unattended	44	0	0	0	2
381	GAFFNEY TIE GAFFNEY SC	Transmission	Unattended	100	24	0	42	6	1
382	GARRETT RD RET DURHAM NC	Distribution	Unattended	100	24	0	60	2
383	GASTONIA CITY DEL 10 GASTONIA NC	Distribution	Unattended	0	0	0	0	1
384	GASTONIA CITY DEL 10 GASTONIA NC	Distribution	Unattended	100	13	0	24	2
385	GASTONIA CITY DEL 11 GASTONIA NC	Distribution	Unattended	100	13	0	24	2
386	GASTONIA CITY DEL 12 GASTONIA NC	Distribution	Unattended	100	13	0	20	1
387	GASTONIA CITY DEL 12 GASTONIA NC	Transmission	Unattended	100	13	0	22	1
388	GASTONIA CITY DEL 2 GASTONIA NC	Distribution	Unattended	44	7	0	3	1
389	GASTONIA CITY DEL 2 GASTONIA NC	Distribution	Unattended	44	7	2	9	2	1
390	GASTONIA CITY DEL 6 GASTONIA NC	Distribution	Unattended	100	13	0	25	2
391	GASTONIA CITY DEL 7 GASTONIA NC	Distribution	Unattended	44	7	2	8	3	1
392	GASTONIA CITY DEL 7 GASTONIA NC	Distribution	Unattended	44	13	7	9	3
393	GASTONIA CITY DEL 9 GASTONIA NC	Distribution	Unattended	100	13	0	24	2
394	GATEWAY RET WHITTIER NC	Distribution	Unattended	66	13	0	14	1	1
395	GATEWOOD RET GATEWOOD NC	Distribution	Unattended	44	13	0	10	1
396	GENELEE RET DURHAM NC	Transmission	Unattended	100	24	0	74	2
397	GENESTU DR RET CHAPEL HILL NC	Transmission	Unattended	100	13	0	0	1
398	GILBREATH RET GRAHAM NC	Distribution	Unattended	24	13	0	20	2
399	GILBREATH RET GRAHAM NC	Distribution	Unattended	100	24	0	40	2
400	GLEN ALPINE RET GLEN ALPINE NC	Distribution	Unattended	44	7	0	6	3
401	GLEN ALPINE RET GLEN ALPINE NC	Distribution	Unattended	44	13	0	5	1
402	GLEN RAVEN MN GLEN RAVEN NC	Transmission	Unattended	100	24	0	66	3
403	GLENOLA RET GLENOLA NC	Distribution	Unattended	100	13	0	24	2
404	GLENWAY SS STATESVILLE NC	Distribution	Unattended	100	24	0	12	1
405	GLENWOOD RET MARION NC	Transmission	Unattended	100	12	0	0	44	2
406	GOODWILL CHURCH RD RET BELEWS CREEK NC	Distribution	Unattended	100	13	0	13	1
407	GRAHAM ST RET CHARLOTTE NC	Distribution	Unattended	13	2	0	5	3	1
408	GRAHAM ST RET CHARLOTTE NC	Distribution	Unattended	100	13	0	42	2
409	GRAHAM ST RET CHARLOTTE NC	Distribution	Unattended	100	24	0	90	3
410	GRANITE FALLS CITY DEL 2 GRANITE FALLS NC	Distribution	Unattended	44	13	0	14	1
411	GRASSY POND RET GRASSY POND SC	Distribution	Unattended	44	13	0	28	2
412	GREAT FALLS HYDRO STA GREAT FALLS SC	Transmission	Unattended	44	2	0	48	4
413	GREAT FALLS SW STA GREAT FALLS SC	Transmission	Unattended	100	44	0	40	2
414	GREEN POND RET ANDERSON SC	Distribution	Unattended	44	13	0	28	2
415	GREEN ST RET DURHAM NC	Distribution	Unattended	100	13	0	24	2
416	GREENBRIAR SW STA SIMPSONVILLE SC	Distribution	Unattended	100	13	0	111	2
417	GREENSBORO MN GREENSBORO NC	Transmission	Unattended	100	7	2	18	4	1
418	GREENSBORO MN GREENSBORO NC	Transmission	Unattended	100	24	0	173	5
419	GREENVILLE MN GREENVILLE SC	Transmission	Unattended	24	0	0	0	1
420	GREENVILLE MN GREENVILLE SC	Transmission	Unattended	100	13	0	40	2
421	GREENVILLE MN GREENVILLE SC	Transmission	Unattended	100	44	0	36	9
422	GREENVILLE MN GREENVILLE SC	Transmission	Unattended	100	44	24	4	0	1
423	GREENWOOD CITY DEL 1 GREENWOOD SC	Distribution	Unattended	44	13	0	20	2
424	GREENWOOD CITY DEL 3 GREENWOOD SC	Distribution	Unattended	44	13	0	10	1
425	GREENWOOD CITY DEL 4 GREENWOOD SC	Distribution	Unattended	44	13	0	15	2
426	GREENWOOD CITY DEL 5 GREENWOOD SC	Distribution	Unattended	44	13	0	10	1
427	GREENWOOD TIE GREENWOOD SC	Transmission	Unattended	24	0	0	0	1
428	GREENWOOD TIE GREENWOOD SC	Transmission	Unattended	100	44	0	36	3
429	GREER CITY STA 2 GREER SC	Distribution	Unattended	100	13	4	26	2
430	GREER RET GREER SC	Transmission	Unattended	100	13	0	37	1
431	GREY RET CHAPEL HILL NC	Distribution	Unattended	100	13	0	24	2
432	GRIFFITH RD RET WINSTON-SALEM NC	Distribution	Unattended	100	13	0	40	2
433	GROOMTOWN RET GREENSBORO NC	Transmission	Unattended	100	13	0	22	1
434	GROOMTOWN RET GREENSBORO NC	Transmission	Unattended	100	24	0	44	2
435	GTP GREENVILLE INC GREENVILLE SC	Distribution	Unattended	44	2	0	12	3	1
436	GUTHRIE RET WINSTON-SALEM NC	Distribution	Unattended	100	13	0	24	2
437	HAMPTON AVE RET SPARTANBURG SC	Distribution	Unattended	44	2	0	4	3	1
438	HAMPTON AVE RET SPARTANBURG SC	Distribution	Unattended	100	13	0	24	2
439	HARRISBURG TIE CHARLOTTE NC	Transmission	Unattended	44	0	0	8	1
440	HARRISBURG TIE CHARLOTTE NC	Transmission	Unattended	44	1	0	3	3
441	HARRISBURG TIE CHARLOTTE NC	Transmission	Unattended	44	2	1	0	3
442	HARRISBURG TIE CHARLOTTE NC	Transmission	Unattended	230	100	44	940	4
443	HARTFORD AVE RET BESSEMER CITY NC	Distribution	Unattended	44	11	0	8	1
444	HARTFORD AVE RET BESSEMER CITY NC	Distribution	Unattended	44	14	0	10	1
445	HAW RIVER RET HAW RIVER NC	Distribution	Unattended	13	2	1	7	3	1
446	HAW RIVER RET HAW RIVER NC	Distribution	Unattended	44	13	0	10	1
447	HAWTHORNE RD RET WINSTON-SALEM NC	Distribution	Unattended	100	13	0	60	3
448	HAWTHORNE RD RET WINSTON-SALEM NC	Distribution	Unattended	100	24	0	24	2
449	HAYS RET HAYS NC	Distribution	Unattended	44	13	0	10	1
450	HEATH RET RANDLEMAN NC	Transmission	Unattended	100	13	0	74	2
451	HEATH RET RANDLEMAN NC	Transmission	Unattended	100	24	0	37	1
452	HENDERSONVILLE TIE EAST FLAT ROCK NC	Transmission	Unattended	24	0	0	0	1
453	HENDERSONVILLE TIE EAST FLAT ROCK NC	Transmission	Unattended	100	44	0	60	2
454	HENSLEY RD RET FORT MILL SC	Distribution	Unattended	13	2	0	4	3	1
455	HENSLEY RD RET FORT MILL SC	Distribution	Unattended	44	7	0	15	6	1
456	HERMAN RD RET CONOVER NC	Distribution	Unattended	100	12	0	66	3
457	HICKORY GROVE RET CHARLOTTE NC	Distribution	Unattended	100	13	0	60	3
458	HICKORY TIE HICKORY NC	Transmission	Unattended	100	44	0	139	3
459	HIDDENITE RET HIDDENITE NC	Distribution	Unattended	44	7	0	6	3
460	HIDDENITE RET HIDDENITE NC	Distribution	Unattended	44	7	2	0	1	1
461	HIDDENITE RET HIDDENITE NC	Distribution	Unattended	44	13	0	14	1
462	HIGH SHOALS RET HIGH SHOALS NC	Distribution	Unattended	13	2	0	3	3
463	HIGH SHOALS RET HIGH SHOALS NC	Distribution	Unattended	44	13	0	5	1
464	HIGH SHOALS RET HIGH SHOALS NC	Distribution	Unattended	44	13	13	5	1
465	HIGHLANDS RET HIGHLANDS NC	Distribution	Unattended	66	13	0	20	2
466	HIGHTOWER RET TAYLORS SC	Transmission	Unattended	100	13	0	74	2
467	HILL ST RET CHARLOTTE NC	Transmission	Unattended	100	24	0	168	3
468	HILLBROOK RET SPARTANBURG SC	Distribution	Unattended	100	13	0	40	2
469	HILLSBOROUGH RET HILLSBOROUGH NC	Distribution	Unattended	44	7	0	10	2
470	HILLSBOROUGH RET HILLSBOROUGH NC	Distribution	Unattended	44	7	2	20	4
471	HILLTOP TIE KINGS MOUNTAIN NC	Transmission	Unattended	24	0	0	0	1
472	HILLTOP TIE KINGS MOUNTAIN NC	Transmission	Unattended	100	44	0	72	4
473	HINSHAW RET WINSTON-SALEM NC	Transmission	Unattended	100	13	0	111	3
474	HITACHI METALS LTD CHINA GROVE NC	Distribution	Unattended	44	13	0	10	1
475	HOLCOMBE RD RET PIEDMONT SC	Distribution	Unattended	100	13	0	20	1
476	HOLLY HILL RET THOMASVILLE NC	Distribution	Unattended	100	13	0	40	2
477	HOMESTEAD RET CHAPEL HILL NC	Distribution	Unattended	100	13	0	24	2
478	HOPE VALLEY RET DURHAM NC	Distribution	Unattended	100	13	0	40	2
479	HOPEDALE DIST HOPEDALE NC	Distribution	Unattended	24	7	0	3	0	1
480	HOPEDALE DIST HOPEDALE NC	Distribution	Unattended	24	7	2	9	3
481	HORSESHOE TIE HENDERSONVILLE NC	Transmission	Unattended	24	0	0	0	3
482	HORSESHOE TIE HENDERSONVILLE NC	Transmission	Unattended	100	44	0	168	3
483	HORSESHOE TIE HENDERSONVILLE NC	Transmission	Unattended	100	100	13	100	1
484	HORTON RD RET DURHAM NC	Distribution	Unattended	100	13	0	40	2
485	HUDLOW RET RUTHERFORDTON NC	Distribution	Unattended	100	13	0	12	1
486	HUDSON ST RET GREENVILLE SC	Distribution	Unattended	100	13	0	60	3
487	HUNTERSVILLE CITY HUNTERSVILLE NC	Distribution	Unattended	44	13	0	20	2
488	HURRICANE CREEK RET ANDERSON SC	Distribution	Unattended	100	13	0	12	1
489	IBM CHARLOTTE PL SS CHARLOTTE NC	Transmission	Unattended	100	13	0	40	2
490	IBM CHARLOTTE PL SS CHARLOTTE NC	Transmission	Unattended	100	24	0	57	2
491	ICARD RET ICARD NC	Distribution	Unattended	44	7	0	15	6	1
492	IMPERIAL RET DURHAM NC	Transmission	Unattended	100	24	0	168	3
493	INDEPENDENCE HILL RET NC	Transmission	Unattended	100	25	0	37	1
494	INDIAN LAND RET FORT MILL SC	Distribution	Unattended	100	13	0	12	1
495	INDIAN LAND RET FORT MILL SC	Distribution	Unattended	100	24	0	20	1
496	INMAN TIE INMAN SC	Transmission	Unattended	100	44	0	36	3
497	ISLAND FORD RD RET STATESVILLE NC	Distribution	Unattended	100	13	0	12	1
498	JAMES ST RET CHAPEL HILL NC	Distribution	Unattended	100	13	0	12	1
499	JAMES ST RET CHAPEL HILL NC	Distribution	Unattended	100	13	7	12	1
500	JENKINS BRANCH RET BRYSON CITY NC	Distribution	Unattended	66	13	0	20	2
501	JESSUPTOWN RET GREENSBORO NC	Transmission	Unattended	100	24	0	168	3
502	JOCASSEE HYDRO JOCASSEE SC	Transmission	Unattended	4	1	0	0	2
503	JOCASSEE HYDRO JOCASSEE SC	Transmission	Unattended	13	0	0	4	4
504	JOCASSEE HYDRO JOCASSEE SC	Transmission	Unattended	13	1	0	3	1
505	JOCASSEE HYDRO JOCASSEE SC	Transmission	Unattended	44	1	1	4	3	1
506	JOCASSEE HYDRO JOCASSEE SC	Transmission	Unattended	230	13	0	672	4
507	JOCASSEE TIE JOCASSEE SC	Transmission	Unattended	230	13	13	192	0	1
508	JOCASSEE TIE JOCASSEE SC	Transmission	Unattended	500	230	24	1500	3
509	JOHNS CREEK RET GREENWOOD SC	Distribution	Unattended	100	13	0	24	2
510	JULIAN RD RET SALISBURY NC	Distribution	Unattended	100	13	0	12	1
511	KANUGA RET HENDERSONVILLE NC	Distribution	Unattended	44	13	0	20	2
512	KENILWORTH RET CHARLOTTE NC	Transmission	Unattended	100	13	0	111	3
513	KENILWORTH RET CHARLOTTE NC	Transmission	Unattended					2
514	KEOWEE HYDRO NEWRY SC	Transmission	Unattended	4	1	0	1	1
515	KEOWEE HYDRO NEWRY SC	Transmission	Unattended	13	0	0	3	2	1
516	KEOWEE HYDRO NEWRY SC	Transmission	Unattended	13	1	0	2	2
517	KEOWEE HYDRO NEWRY SC	Transmission	Unattended	230	13	13	205	1
518	KERNERSVILLE RET KERNERSVILLE NC	Distribution	Unattended	100	13	7	16	2	2
519	KERNERSVILLE RET KERNERSVILLE NC	Distribution	Unattended	100	24	13	4	1
520	KERNERSVILLE RET KERNERSVILLE NC	Distribution	Unattended	100	44	13	12	3
521	KERSHAW RET KERSHAW SC	Distribution	Unattended	44	7	2	10	3	1
522	KERSHAW RET KERSHAW SC	Distribution	Unattended	46	44	0	12	3	1
523	KEY ST RET PILOT MOUNTAIN NC	Distribution	Unattended	44	13	0	26	2
524	KILDARE RET GREENSBORO NC	Distribution	Unattended	100	24	0	60	2
525	KIMESVILLE RET KIMESVILLE NC	Distribution	Unattended	44	13	0	25	2
526	KINCAID RD RET HUDSON NC	Distribution	Unattended	100	13	0	24	2
527	KING RET KING NC	Distribution	Unattended	100	13	0	40	2
528	KINGS MTN CITY DEL 2 KINGS MOUNTAIN NC	Distribution	Unattended	44	7	2	12	3	1
529	KINGS MTN MAIN KINGS MOUNTAIN NC	Distribution	Unattended	44	13	0	20	2
530	KINGSGATE RET GREENVILLE SC	Distribution	Unattended	100	13	0	20	1
531	KIT CREEK RET DURHAM NC	Distribution	Unattended	100	24	0	22	1
532	KIVETT DR RET HIGH POINT NC	Transmission	Unattended	100	13	0	33	3	1
533	KIVETT DR RET HIGH POINT NC	Transmission	Unattended	24	13	13	8	3	1
534	KNIGHTS RET ROCK HILL SC	Distribution	Unattended	100	24	0	74	2
535	KNOLLWOOD RET SPARTANBURG SC	Distribution	Unattended	100	13	0	40	2
536	KUDZU RET CHARLOTTE NC	Transmission	Unattended	100	13	0	37	1
537	KUDZU RET CHARLOTTE NC	Transmission	Unattended	100	24	0	20	1
538	LAKE EMORY TIE FRANKLIN NC	Transmission	Unattended	44	2	0	3	3
539	LAKE EMORY TIE FRANKLIN NC	Transmission	Unattended	44	2	1	6	3
540	LAKE EMORY TIE FRANKLIN NC	Transmission	Unattended	66	2	0	1	0	1
541	LAKE EMORY TIE FRANKLIN NC	Transmission	Unattended	161	66	0	90	3
542	LAKE LATHAM RET MEBANE NC	Transmission	Unattended	100	25	0	37	1
543	LAKE LURE RET LAKE LURE NC	Distribution	Unattended	44	7	2	12	3	1
544	LAKE LURE RET LAKE LURE NC	Distribution	Unattended	44	13	0	14	1
545	LAKE TOWNSEND RET GREENSBORO NC	Distribution	Unattended	100	24	0	42	2
546	LAKEWOOD RET CHARLOTTE NC	Transmission	Unattended	44	4	0	11	2
547	LAKEWOOD RET CHARLOTTE NC	Transmission	Unattended	100	7	0	0	0	1
548	LAKEWOOD RET CHARLOTTE NC	Transmission	Unattended	100	13	7	40	6
549	LAKEWOOD TIE CHARLOTTE NC	Transmission	Unattended	44	0	0	40	3
550	LAKEWOOD TIE CHARLOTTE NC	Transmission	Unattended	230	100	44	800	2
551	LANCASTER MN LANCASTER SC	Transmission	Unattended	24	0	0	0	1
552	LANCASTER MN LANCASTER SC	Transmission	Unattended	100	44	0	16	3	1
553	LANCASTER MN LANCASTER SC	Transmission	Unattended	100	44	24	16	3	1
554	LANCASTER RET LANCASTER SC	Distribution	Unattended	100	2	0	4	3	1
555	LANCASTER RET LANCASTER SC	Distribution	Unattended	100	13	0	24	2
556	LANDIS CITY DEL 1&2 LANDIS NC	Distribution	Unattended	44	2	0	12	3	1
557	LANDIS CITY DEL 1&2 LANDIS NC	Distribution	Unattended	44	13	0	10	1
558	LANDO RET LANDO SC	Distribution	Unattended	44	13	0	20	2
559	LANDRUM RET LANDRUM SC	Distribution	Unattended	44	7	0	9	3
560	LANDRUM RET LANDRUM SC	Distribution	Unattended	44	13	0	10	1
561	LANGSTON CREEK RET GREENVILLE SC	Distribution	Unattended	100	13	0	24	2
562	LANGTREE RET MOORESVILLE NC	Distribution	Unattended	100	13	0	45	2
563	LAUREL CREEK RET GREENVILLE SC	Distribution	Unattended	100	13	0	40	2
564	LAURENS CITY CAROLINE STA LAURENS SC	Distribution	Unattended	100	13	0	24	2
565	LAURENS E C DEL 25 MAULDIN MAULDIN SC	Distribution	Unattended	100	13	0	15	1
566	LAURENS E C DEL 25 MAULDIN MAULDIN SC	Distribution	Unattended	100	13	4	20	1
567	LAURENS E C DEL 26 WALNUT GROVE SC	Distribution	Unattended	100	13	0	12	1
568	LAURENS TIE LAURENS SC	Transmission	Unattended	44	13	7	12	3	1
569	LAURENS TIE LAURENS SC	Transmission	Unattended	100	24	0	42	6	1
570	LAWNDALE RET LAWNDALE NC	Distribution	Unattended	44	13	0	10	1
571	LAWSONS FORK TIE SPARTANBURG SC	Transmission	Unattended	100	44	0	40	2
572	LAYCOCK RD RET NC	Transmission	Unattended	100	0	0		3
573	LEAFCREST RET CHARLOTTE NC	Transmission	Unattended	100	13	0	37	1
574	LEE STEAM STA COMB TURB PELZER SC	Transmission	Unattended	100	13	0	64	2
575	LELIA RET WELLFORD SC	Distribution	Unattended	100	13	0	42	2
576	LESLIE RET LESLIE SC	Distribution	Unattended	44	7	0	3	0	1
577	LESLIE RET LESLIE SC	Distribution	Unattended	44	7	2	6	3
578	LESLIE RET LESLIE SC	Distribution	Unattended	44	13	0	10	1
579	LEWISVILLE RET LEWISVILLE NC	Distribution	Unattended	100	13	0	40	2
580	LEXINGTON CITY DEL 1 LEXINGTON NC	Distribution	Unattended	24	0	0	0	1
581	LEXINGTON CITY DEL 1 LEXINGTON NC	Distribution	Unattended	100	44	0	60	2
582	LEXINGTON MN LEXINGTON NC	Distribution	Unattended	100	13	7	16	3	1
583	LEXINGTON MN LEXINGTON NC	Distribution	Unattended	100	24	0	40	2
584	LIBERTY RET NEW LIBERTY SC	Distribution	Unattended	100	13	0	24	2
585	LINCOLN COMBUSTION TURB YARD LOWESVILLE NC	Transmission	Unattended	230	13	0	1072	8
586	LINCOLNTON CITY LINCOLNTON NC	Distribution	Unattended	100	13	7	16	3	1
587	LINCOLNTON TIE LINCOLNTON NC	Transmission	Unattended	100	13	0	40	2
588	LINCOLNTON TIE LINCOLNTON NC	Transmission	Unattended	100	44	0	60	2
589	LINDE LLC MIDLAND NC	Transmission	Unattended	100	13	0	30	1
590	LINDEN ST SW STA HIGH POINT NC	Distribution	Unattended	100	0	0	0	2
591	LINDEN ST SW STA HIGH POINT NC	Distribution	Unattended	100	13	7	7	3	1
592	LINDEN ST SW STA HIGH POINT NC	Distribution	Unattended	100	24	0	75	2
593	LINWOOD SS LEXINGTON NC	Distribution	Unattended	100	44	24	12	1
594	LIONS MOUNTAIN TIE CALVERT NC	Transmission	Unattended	0	5	0	0	0	1
595	LIONS MOUNTAIN TIE CALVERT NC	Transmission	Unattended	44	4	2	5	1
596	LIONS MOUNTAIN TIE CALVERT NC	Transmission	Unattended	100	44	0	40	2
597	LITTLE ROCK RET CHARLOTTE NC	Distribution	Unattended	100	13	0	40	2
598	LITTLE ROCK RET CHARLOTTE NC	Distribution	Unattended	100	24	0	22	1
599	LOCKHART POWER CO DEL 1 PACOLET SC	Distribution	Unattended	33	0	0	7	1
600	LOCKHART POWER CO DEL 1 PACOLET SC	Distribution	Unattended	100	44	33	24	2
601	LOCUST RET LOCUST NC	Distribution	Unattended	100	13	0	12	1
602	LONG FERRY RET SALISBURY NC	Distribution	Unattended	100	13	0	24	2
603	LONGVIEW RET LONG VIEW NC	Distribution	Unattended	44	13	0	20	2
604	LONGVIEW TIE LONG VIEW NC	Transmission	Unattended	44	0	0	0	2
605	LONGVIEW TIE LONG VIEW NC	Transmission	Unattended	44	7	2	0	0
606	LONGVIEW TIE LONG VIEW NC	Transmission	Unattended	230	100	44	1568	4
607	LOOKOUT HYDRO STATESVILLE NC	Transmission	Unattended	100	7	0	40	2
608	LOOKOUT TIE STATESVILLE NC	Transmission	Unattended	24	0	0	0	1
609	LOOKOUT TIE STATESVILLE NC	Transmission	Unattended	100	44	0	80	3
610	LUMBER LANE RET MOUNT HOLLY NC	Distribution	Unattended	100	13	0	12	1
611	LUNSFORD RD RET KING NC	Distribution	Unattended	100	13	0	12	1
612	MACEDONIA RET TAYLORSVILLE NC	Distribution	Unattended	100	13	0	12	1
613	MADISON RET MADISON NC	Distribution	Unattended	100	13	0	25	2
614	MADISON TIE MADISON NC	Transmission	Unattended	100	44	0	90	3
615	MAIDEN CITY DEL 2 MAIDEN NC	Distribution	Unattended	44	13	0	20	2
616	MAJOLICA RD RET SALISBURY NC	Distribution	Unattended	100	13	0	12	1
617	MALLARD CREEK RET CHARLOTTE NC	Distribution	Unattended	100	13	0	40	2
618	MANCHESTER RET KANNAPOLIS NC	Distribution	Unattended	100	13	0	13	1
619	MARBLE TIE MARBLE NC	Transmission	Unattended	35	13	0	7	1
620	MARBLE TIE MARBLE NC	Transmission	Unattended	161	35	0	84	3
621	MAR-DON DR RET WINSTON-SALEM NC	Distribution	Unattended	100	13	0	20	1
622	MAR-DON DR RET WINSTON-SALEM NC	Distribution	Unattended	100	24	0	12	1
623	MARIETTA TIE MARIETTA SC	Transmission	Unattended	24	0	0	0	1
624	MARIETTA TIE MARIETTA SC	Transmission	Unattended	100	44	0	54	2
625	MARION MN MARION NC	Distribution	Unattended	44	7	2	4	3	1
626	MARION MN MARION NC	Distribution	Unattended	100	13	7	16	3	1
627	MARKET POINT RET GREENVILLE SC	Distribution	Unattended	100	13	0	20	1
628	MARSHALL RET TERRELL NC	Distribution	Unattended	44	13	0	11	1
629	MARSHALL STEAM STA YARD TERRELL NC	Transmission	Unattended	0	0	0	0	2
630	MARSHALL STEAM STA YARD TERRELL NC	Transmission	Unattended	4	1	0	2	2
631	MARSHALL STEAM STA YARD TERRELL NC	Transmission	Unattended	230	24	0	2350	4
632	MASCOT RET INMAN SC	Distribution	Unattended	44	13	0	28	2
633	MASONIC DR DIST GREENSBORO NC	Distribution	Unattended	13	2	0	6	1	1
634	MATTHEWS RET CHARLOTTE NC	Transmission	Unattended	100	24	0	168	3
635	MCADENVILLE JCT TIE MCADENVILLE NC	Transmission	Unattended	24	0	0	0	1
636	MCADENVILLE JCT TIE MCADENVILLE NC	Transmission	Unattended	44	13	0	28	2
637	MCADENVILLE JCT TIE MCADENVILLE NC	Transmission	Unattended	100	44	0	168	3
638	MCALPINE CREEK RET CHARLOTTE NC	Distribution	Unattended	100	24	0	60	3
639	MCDOWELL TIE MARION NC	Transmission	Unattended	44	2	1	0	3
640	MCDOWELL TIE MARION NC	Transmission	Unattended	44	24	0	3	3
641	MCDOWELL TIE MARION NC	Transmission	Unattended	100	44	0	30	1
642	MCDOWELL TIE MARION NC	Transmission	Unattended	230	100	44	150	1
643	MCGUIRE RET HUNTERSVILLE NC	Distribution	Unattended	44	7	2	12	3	1
644	MCGUIRE SWITCHING STA HUNTERSVILLE NC	Transmission	Unattended	4	0	0	1	4
645	MCGUIRE SWITCHING STA HUNTERSVILLE NC	Transmission	Unattended	7	4	0	2	1
646	MCGUIRE SWITCHING STA HUNTERSVILLE NC	Transmission	Unattended	25	4	0	0	1
647	MCGUIRE SWITCHING STA HUNTERSVILLE NC	Transmission	Unattended	500	0	0	0	0	1
648	MCGUIRE SWITCHING STA HUNTERSVILLE NC	Transmission	Unattended	525	230	23	1560	3	1
649	MEADOW GREEN RET EDEN NC	Distribution	Unattended	100	13	0	40	2
650	MEBANE RET MEBANE NC	Distribution	Unattended	44	2	0	4	3	1
651	MEBANE RET MEBANE NC	Distribution	Unattended	44	7	2	4	3	1
652	MEBANE RET MEBANE NC	Distribution	Unattended	44	13	0	5	1
653	MEBANE TIE MEBANE NC	Transmission	Unattended	24	0	0	0	1
654	MEBANE TIE MEBANE NC	Transmission	Unattended	100	44	0	48	4
655	MERRITT DR RET GREENSBORO NC	Distribution	Unattended	100	24	0	60	2
656	MIDWAY SS UNION SC	Transmission	Unattended	100	33	0	60	2
657	MILLER HILL RET LENOIR NC	Transmission	Unattended	0	240	0	0	2
658	MILLER HILL RET LENOIR NC	Transmission	Unattended	100	13	0	62	3
659	MILLER HILL TIE LENOIR NC	Transmission	Unattended	100	44	0	80	4
660	MILLERS CREEK RET NORTH WILKESBORO NC	Distribution	Unattended	100	13	0	24	2
661	MILLIS RET HIGH POINT NC	Distribution	Unattended	100	24	0	24	2
662	MILLS RIVER RET HENDERSONVILLE NC	Transmission	Unattended	100	24	0	12	1
663	MILLS RIVER RET HENDERSONVILLE NC	Transmission	Unattended	115	7	13	18	3
664	MILLS RIVER RET HENDERSONVILLE NC	Transmission	Unattended	115	24	0	39	3	1
665	MILLS RIVER RET HENDERSONVILLE NC	Transmission	Unattended	121	7	13	0	0	1
666	MINE SHAFT RET CHARLOTTE NC	Distribution	Unattended	100	24	0	60	2
667	MINI RANCH RET WAXHAW NC	Distribution	Unattended	100	24	0	20	1
668	MITCHELL RIVER TIE ELKIN NC	Transmission	Unattended	44	0	0	18	3
669	MITCHELL RIVER TIE ELKIN NC	Transmission	Unattended	230	100	44	769	3
670	MOCKSVILLE MN MOCKSVILLE NC	Transmission	Unattended	100	7	2	12	2	1
671	MOCKSVILLE MN MOCKSVILLE NC	Transmission	Unattended	100	24	0	44	2
672	MOCKSVILLE MN MOCKSVILLE NC	Transmission	Unattended	100	44	0	72	3
673	MONROE MN MONROE NC	Transmission	Unattended	44	7	2	6	3
674	MONROE MN MONROE NC	Transmission	Unattended	100	13	7	16	3	1
675	MONROE MN MONROE NC	Transmission	Unattended	100	44	0	40	2
676	MONROE RD RET CHARLOTTE NC	Distribution	Unattended	100	13	0	60	3
677	MONROETON RET MONROETON NC	Distribution	Unattended	44	13	0	14	1
678	MONTCLAIRE RET CHARLOTTE NC	Distribution	Unattended	100	24	0	60	2
679	MONTICELLO RET GREENSBORO NC	Distribution	Unattended	44	13	0	10	1
680	MONTROYAL RD RET RURAL HALL NC	Distribution	Unattended	100	13	0	20	1
681	MOONVILLE RET GREENVILLE SC	Distribution	Unattended	100	13	0	40	2
682	MOORE RET MOORE SC	Distribution	Unattended	44	13	0	10	1
683	MOORESBORO RET MOORESBORO NC	Distribution	Unattended	44	13	0	20	2
684	MOORESVILLE TIE MOORESVILLE NC	Transmission	Unattended	24	0	0	0	1
685	MOORESVILLE TIE MOORESVILLE NC	Transmission	Unattended	100	44	0	48	4
686	MORGANTON CITY DEL 3 MORGANTON NC	Distribution	Unattended	44	13	0	28	2
687	MORGANTON CITY DEL 4 MATS MORGANTON NC	Distribution	Unattended	100	13	0	10	1
688	MORGANTON TIE MORGANTON NC	Transmission	Unattended	0	0	0	0	1
689	MORGANTON TIE MORGANTON NC	Transmission	Unattended	100	24	13	30	3
690	MORGANTON TIE MORGANTON NC	Transmission	Unattended	100	44	0	52	3
691	MORNING STAR TIE MATTHEWS NC	Transmission	Unattended	44	0	0	1	1
692	MORNING STAR TIE MATTHEWS NC	Transmission	Unattended	100	24	0	112	2
693	MORNING STAR TIE MATTHEWS NC	Transmission	Unattended	230	100	44	500	3
694	MOTLEY TIE EDEN NC	Transmission	Unattended	24	0	0	0	1
695	MOTLEY TIE EDEN NC	Transmission	Unattended	100	44	0	32	2
696	MT AIRY RET MT AIRY NC	Transmission	Unattended	100	7	2	12	3	1
697	MT AIRY RET MT AIRY NC	Transmission	Unattended	100	13	7	45	3	1
698	MT HOPE CHURCH RD RET GREENSBORO NC	Distribution	Unattended	100	7	2	15	3	1
699	MT OLIVE RET CONOVER NC	Distribution	Unattended	44	13	0	20	2
700	MT PLEASANT RET MOUNT PLEASANT NC	Distribution	Unattended	44	7	2	5	5	1
701	MT PLEASANT RET MOUNT PLEASANT NC	Distribution	Unattended	44	13	0	0	1
702	MT TABOR RET WINSTON-SALEM NC	Distribution	Unattended	100	13	0	40	2
703	MTN VIEW RET HICKORY NC	Distribution	Unattended	100	13	0	32	2
704	MUD CREEK RD RET BOILING SPRINGS SC	Distribution	Unattended	100	13	0	27	2
705	MULBERRY CREEK RET WARE SHOALS SC	Distribution	Unattended	100	7	0	12	3	1
706	MULBERRY CREEK RET WARE SHOALS SC	Distribution	Unattended	100	7	2	8	3	1
707	MURDOCK RD RET TROUTMAN NC	Distribution	Unattended	44	13	0	20	2
708	N CHARLOTTE RET CHARLOTTE NC	Distribution	Unattended	100	7	2	32	7	1
709	N CHARLOTTE RET CHARLOTTE NC	Distribution	Unattended	100	13	7	18	2	1
710	N FRANKLIN RET FRANKLIN NC	Distribution	Unattended	66	13	0	10	1
711	N GORDONTON RET THOMASVILLE NC	Distribution	Unattended	100	13	0	12	1
712	N GREENSBORO TIE GREENSBORO NC	Transmission	Unattended	100	44	0	20	1
713	N GREENSBORO TIE GREENSBORO NC	Transmission	Unattended	230	100	13	896	2
714	N GREENSBORO TIE GREENSBORO NC	Transmission	Unattended	230	100	44	896	2
715	N GREENVILLE TIE GREENVILLE SC	Transmission	Unattended	44	0	0	38	2
716	N GREENVILLE TIE GREENVILLE SC	Transmission	Unattended	44	2	1	0	3
717	N GREENVILLE TIE GREENVILLE SC	Transmission	Unattended	230	100	44	800	4
718	N GREENWOOD RET GREENWOOD SC	Distribution	Unattended	44	13	0	16	2
719	N HICKORY RET HICKORY NC	Transmission	Unattended	100	13	0	74	2
720	N STANLEY RET STANLEY NC	Distribution	Unattended	100	13	0	12	1
721	N STANLEY RET STANLEY NC	Distribution	Unattended	100	13	4	12	1
722	N WINSTON RET WINSTON-SALEM NC	Transmission	Unattended	100	13	0	111	3
723	NANTAHALA HYDRO TOPTON NC	Transmission	Unattended	13	0	0	0	2
724	NANTAHALA HYDRO TOPTON NC	Transmission	Unattended	35	13	0	0	1
725	NANTAHALA HYDRO TOPTON NC	Transmission	Unattended	161	13	0	54	2
726	NANTAHALA HYDRO TOPTON NC	Transmission	Unattended	161	35	0	15	1
727	NAPLES RET NAPLES NC	Distribution	Unattended	44	13	0	28	2
728	NEALS CREEK RET ANDERSON SC	Distribution	Unattended	44	13	0	20	2
729	NEBO RET MARION NC	Distribution	Unattended	100	13	0	12	1
730	NELSON RET DURHAM NC	Distribution	Unattended	100	24	0	24	2
731	NEW CUT RD RET INMAN SC	Distribution	Unattended	100	13	0	22	1
732	NEW HOPE RET GASTONIA NC	Distribution	Unattended	100	13	0	42	2
733	NEWBERRY MN NEWBERRY SC	Transmission	Unattended	100	24	0	60	2
734	NEWELL RET CHARLOTTE NC	Distribution	Unattended	100	24	0	60	2
735	NEWPORT RET NEWPORT SC	Distribution	Unattended	44	13	0	28	2
736	NEWPORT TIE NEWPORT SC	Transmission	Unattended	230	100	44	1344	3
737	NEWPORT TIE NEWPORT SC	Transmission	Unattended	500	230	24	1119	3	1
738	NEWTON CITY DEL 2 NEWTON NC	Distribution	Unattended	100	13	7	18	3
739	NEWTON TIE NEWTON NC	Transmission	Unattended	24	0	0	0	1
740	NEWTON TIE NEWTON NC	Transmission	Unattended	100	24	0	42	6	1
741	NINETY-NINE ISLANDS HYDRO BLACKSBURG SC	Transmission	Unattended	24	0	0	0	3
742	NINETY-NINE ISLANDS HYDRO BLACKSBURG SC	Transmission	Unattended	44	2	0	30	6	4
743	NIX RD RET HENDERSONVILLE NC	Distribution	Unattended	100	13	0	20	1
744	NORRIS RET CATEECHEE SC	Distribution	Unattended	44	13	0	14	2
745	NORTH DENVER RET DENVER NC	Transmission	Unattended	100	13	0	20	1
746	NORTH LAKES RET HICKORY NC	Distribution	Unattended	100	13	0	12	1
747	NORTH LINCOLN RET LINCOLNTON NC	Distribution	Unattended	44	13	0	10	1
748	NORTH ST RET ANDERSON SC	Distribution	Unattended	44	13	0	10	1
749	OAK GROVE RET SHELBY NC	Distribution	Unattended	44	13	0	20	2
750	OAK RIDGE RET KERNERSVILLE NC	Distribution	Unattended	100	13	0	40	2
751	OAKBORO RET OAKBORO NC	Distribution	Unattended	100	13	7	16	3	1
752	OAKBORO TIE OAKBORO NC	Transmission	Unattended	44	0	0	10	2
753	OAKBORO TIE OAKBORO NC	Transmission	Unattended	230	100	44	1072	4
754	OAKLAND RD RET SPINDALE NC	Distribution	Unattended	100	13	0	24	2
755	OAKVALE TIE GREENVILLE SC	Transmission	Unattended	100	13	0	42	2
756	OAKVALE TIE GREENVILLE SC	Transmission	Unattended	100	24	0	15	3
757	OAKVALE TIE GREENVILLE SC	Transmission	Unattended	100	44	0	12	4
758	OAKVALE TIE GREENVILLE SC	Transmission	Unattended	100	44	24	4	0	1
759	OAKWOOD ST RET MEBANE NC	Transmission	Unattended	100	13	0	74	2	1
760	OCONEE 230KV SWITCHYARD NEWRY SC	Transmission	Unattended	4	0	0	0	2
761	OCONEE 230KV SWITCHYARD NEWRY SC	Transmission	Unattended	24	4	0	0	0
762	OCONEE 230KV SWITCHYARD NEWRY SC	Transmission	Unattended	230	4	0	16	1
763	OCONEE 230KV SWITCHYARD NEWRY SC	Transmission	Unattended	525	240	0	240	1
764	OCONEE 525KV SWITCHYARD NEWRY SC	Transmission	Unattended	4	0	0	0	2
765	OCONEE 525KV SWITCHYARD NEWRY SC	Transmission	Unattended	500	230	24	1120	2	2
766	OCONEE NUCLEAR STA UNIT 1 NEWRY SC	Transmission	Unattended	4	1	0	22	11	2
767	OCONEE NUCLEAR STA UNIT 1 NEWRY SC	Transmission	Unattended	24	7	4	45	1
768	OCONEE NUCLEAR STA UNIT 1 NEWRY SC	Transmission	Unattended	230	7	4	82	1	1
769	OCONEE NUCLEAR STA UNIT 1 NEWRY SC	Transmission	Unattended	230	24	0	1000	1
770	OCONEE NUCLEAR STA UNIT 2 NEWRY SC	Transmission	Unattended	4	1	0	11	8	1
771	OCONEE NUCLEAR STA UNIT 2 NEWRY SC	Transmission	Unattended	24	7	4	67	1
772	OCONEE NUCLEAR STA UNIT 2 NEWRY SC	Transmission	Unattended	230	7	4	67	1
773	OCONEE NUCLEAR STA UNIT 2 NEWRY SC	Transmission	Unattended	230	24	0	1120	1
774	OCONEE NUCLEAR STA UNIT 3 NEWRY SC	Transmission	Unattended	4	1	0	14	9
775	OCONEE NUCLEAR STA UNIT 3 NEWRY SC	Transmission	Unattended	13	4	0	27	1	1
776	OCONEE NUCLEAR STA UNIT 3 NEWRY SC	Transmission	Unattended	24	7	4	45	1
777	OCONEE NUCLEAR STA UNIT 3 NEWRY SC	Transmission	Unattended	100	4	4	12	1
778	OCONEE NUCLEAR STA UNIT 3 NEWRY SC	Transmission	Unattended	230	7	4	45	1
779	OCONEE NUCLEAR STA UNIT 3 NEWRY SC	Transmission	Unattended	500	24	0	1492	3	1
780	OCONEE SITE 100KV NEWRY SC	Transmission	Unattended	100	24	0	74	2
781	OGBURN DIST STOKESDALE NC	Distribution	Unattended	24	13	7	18	3
782	OGBURN DIST STOKESDALE NC	Distribution	Unattended	44	24	7	0	0	1
783	OLD FORT RET OLD FORT NC	Distribution	Unattended	44	7	2	8	3	1
784	OLD FORT RET OLD FORT NC	Distribution	Unattended	44	13	0	11	1
785	ONEAL RET GREER SC	Distribution	Unattended	100	13	0	74	2
786	OSSIPEE DIST OSSIPEE NC	Distribution	Unattended	24	7	0	3	3
787	OSSIPEE DIST OSSIPEE NC	Distribution	Unattended	24	7	2	8	3	1
788	OTTO RET OTTO NC	Distribution	Unattended	69	13	0	10	1
789	OXFORD HYDRO CONOVER NC	Transmission	Unattended	100	7	0	30	2
790	OXFORD RD RET DURHAM NC	Distribution	Unattended	100	13	0	24	2
791	OYAMA RET HICKORY NC	Distribution	Unattended	100	13	0	40	2
792	PACOLET RET PACOLET SC	Distribution	Unattended	44	7	0	12	3	1
793	PACOLET TIE PACOLET SC	Transmission	Unattended	230	100	13	200	1	1
794	PACOLET TIE PACOLET SC	Transmission	Unattended	230	100	44	200	1
795	PANORAMA RET GREENWOOD SC	Distribution	Unattended	44	13	0	5	1
796	PARADISE RET FOREST CITY NC	Distribution	Unattended	44	13	0	14	2
797	PARK RD RET CHARLOTTE NC	Transmission	Unattended	100	13	0	111	3
798	PARK RD RET CHARLOTTE NC	Transmission	Unattended	100	24	0	37	1
799	PARKWAY SS GROVER NC	Distribution	Unattended	100	13	0	22	2
800	PARKWOOD RET DURHAM NC	Transmission	Unattended	100	24	0	37	1
801	PARKWOOD TIE DURHAM NC	Transmission	Unattended	13	0	0	1	1
802	PARKWOOD TIE DURHAM NC	Transmission	Unattended	44	0	0	2	1
803	PARKWOOD TIE DURHAM NC	Transmission	Unattended	230	100	44	1120	3
804	PARKWOOD TIE DURHAM NC	Transmission	Unattended	500	230	13	1680	6	1
805	PATTERSON SPRINGS RET SHELBY NC	Distribution	Unattended	100	13	0	40	2
806	PEACE HAVEN RD RET CLEMMONS NC	Transmission	Unattended	100	13	0	74	2
807	PEACH VALLEY TIE SPARTANBURG SC	Transmission	Unattended	44	0	0	59	3
808	PEACH VALLEY TIE SPARTANBURG SC	Transmission	Unattended	230	100	44	800	3
809	PEACOCK TIE GASTONIA NC	Transmission	Unattended	44	0	0	38	3
810	PEACOCK TIE GASTONIA NC	Transmission	Unattended	100	13	0	19	1
811	PEACOCK TIE GASTONIA NC	Transmission	Unattended	230	100	44	896	2
812	PEARMAN SS ANDERSON SC	Distribution	Unattended	100	13	0	24	2
813	PEBBLE CREEK RET GREENVILLE SC	Distribution	Unattended	100	13	0	75	2
814	PEELER RET GAFFNEY SC	Distribution	Unattended	44	13	0	10	2
815	PELHAM RET TAYLORS SC	Distribution	Unattended	100	24	0	40	2	1
816	PELZER RET PELZER SC	Distribution	Unattended	44	13	0	10	1
817	PENDLETON RET PENDLETON SC	Distribution	Unattended	44	2	0	3	3
818	PENDLETON RET PENDLETON SC	Distribution	Unattended	44	7	2	1	0	1
819	PENDLETON RET PENDLETON SC	Distribution	Unattended	44	13	0	10	1
820	PERTH RD RET TROUTMAN NC	Transmission	Unattended	44	13	0	14	1
821	PERTH RD RET TROUTMAN NC	Transmission	Unattended	44	24	0	14	1
822	PETERS CREEK RET SPARTANBURG SC	Distribution	Unattended	44	13	0	28	2
823	PFAFFTOWN RET WINSTON-SALEM NC	Distribution	Unattended	100	13	0	20	1
824	PICKENS RET PICKENS SC	Distribution	Unattended	44	7	2	15	6	1
825	PICKENS TIE PICKENS SC	Transmission	Unattended	100	44	0	36	3
826	PIEDMONT RET PIEDMONT SC	Distribution	Unattended	13	2	0	0	1
827	PIEDMONT RET PIEDMONT SC	Distribution	Unattended	44	7	2	14	5	1
828	PIEDMONT RET PIEDMONT SC	Distribution	Unattended	44	13	7	3	1
829	PIERCETOWN SS ANDERSON SC	Distribution	Unattended	100	13	0	24	2
830	PINCH GUT CREEK RET NEWTON NC	Distribution	Unattended	100	13	0	12	1
831	PINEWOOD RET SPARTANBURG SC	Transmission	Unattended	100	13	0	74	2
832	PINK HARRILL TIE CAROLEEN NC	Transmission	Unattended	100	44	0	40	2
833	PINNACLE TIE PINNACLE NC	Transmission	Unattended	24	0	0	0	1
834	PINNACLE TIE PINNACLE NC	Transmission	Unattended	100	44	0	28	6	1
835	PIONEER AVE RET CHARLOTTE NC	Transmission	Unattended	100	24	0	74	2
836	PIPER GLEN RET CHARLOTTE NC	Transmission	Unattended	100	24	0	168	3
837	PISGAH TIE PISGAH FOREST NC	Transmission	Unattended	44	0	0	29	3
838	PISGAH TIE PISGAH FOREST NC	Transmission	Unattended	100	44	0	50	1
839	PISGAH TIE PISGAH FOREST NC	Transmission	Unattended	100	100	13	0	0
840	PISGAH TIE PISGAH FOREST NC	Transmission	Unattended	115	100	0	336	2	1
841	PISGAH TIE PISGAH FOREST NC	Transmission	Unattended	230	100	44	400	2
842	PITTS SCHOOL RET CONCORD NC	Distribution	Unattended	100	13	0	20	1
843	PLAINVIEW RET ANDERSON SC	Transmission	Unattended	100	13	0	74	2
844	PLATO LEE RET SHELBY NC	Distribution	Unattended	100	12	0	0	1
845	PLEASANT GARDEN RET PLEASANT GARDEN NC	Transmission	Unattended	24	0	0	1	1
846	PLEASANT GARDEN TIE PLEASANT GARDEN NC	Transmission	Unattended	230	100	44	1120	4
847	PLEASANT GARDEN TIE PLEASANT GARDEN NC	Transmission	Unattended	500	230	24	1680	3	1
848	PLEASANT GARDEN TIE PLEASANT GARDEN NC	Transmission	Unattended	500	500	0	0	0	1
849	POPE RD RET DURHAM NC	Distribution	Unattended	100	24	0	60	2
850	POPLAR TENT RET CONCORD NC	Transmission	Unattended	100	13	0	74	2
851	PORTER RANCH RET VAN WYCK SC	Distribution	Unattended	44	2	0	0	1
852	PORTER RANCH RET VAN WYCK SC	Distribution	Unattended	44	7	2	3	3
853	PORTER RANCH RET VAN WYCK SC	Distribution	Unattended	44	13	0	4	1
854	POWDERSVILLE RET POWDERSVILLE SC	Distribution	Unattended	44	13	0	18	2
855	PROCTER & GAMBLE GBORO PL T&D GREENSBORO NC	Distribution	Unattended	44	13	0	10	1
856	PROPST RET HICKORY NC	Distribution	Unattended	44	13	0	11	2
857	PROVOL RET CHARLOTTE NC	Transmission	Unattended	100	24	0	168	3
858	PUTMAN RET FOUNTAIN INN SC	Distribution	Unattended	100	13	0	40	2
859	PUTMAN RET FOUNTAIN INN SC	Distribution	Unattended	100	24	0	40	2
860	RAGSDALE RET JAMESTOWN NC	Distribution	Unattended	100	24	0	40	2
861	RANDLEMAN RD RET RANDLEMAN NC	Transmission	Unattended	100	13	0	42	2
862	RANDOLPH AVE RET GREENSBORO NC	Transmission	Unattended	100	24	0	168	3
863	RANKIN AVE RET MOUNT HOLLY NC	Distribution	Unattended	100	13	0	40	2
864	REAMES RD RET CHARLOTTE NC	Distribution	Unattended	100	24	0	60	3
865	RED RAIDER RET BELMONT NC	Distribution	Unattended	100	13	0	12	1
866	RED ROSE RET LANCASTER SC	Distribution	Unattended	100	13	0	27	2
867	REEDY RIVER TIE FOUNTAIN INN SC	Transmission	Unattended	100	24	0	16	4
868	REEDY RIVER TIE FOUNTAIN INN SC	Transmission	Unattended	100	44	24	12	2	1
869	REIDSVILLE RET REIDSVILLE NC	Distribution	Unattended	100	13	0	40	2
870	REIDSVILLE RET REIDSVILLE NC	Distribution	Unattended	100	13	4	24	2
871	REMOUNT RD RET CHARLOTTE NC	Distribution	Unattended	100	13	0	40	2
872	RESEARCH TRIANGLE RET DURHAM NC	Distribution	Unattended	100	24	0	90	3
873	RHODHISS HYDRO PL RHODHISS NC	Transmission	Unattended	46	7	0	45	3
874	RHODHISS TIE RHODHISS NC	Transmission	Unattended	44	0	0	0	1
875	RHODHISS TIE RHODHISS NC	Transmission	Unattended	100	44	0	60	2
876	RICH MOUNTAIN RET BREVARD NC	Distribution	Unattended	100	13	0	25	2
877	RICHFIELD RET RICHFIELD NC	Distribution	Unattended	100	13	7	16	3	1
878	RIDGEVIEW RET EDEN NC	Distribution	Unattended	100	13	0	40	2
879	RITTERS LAKE RD RET GREENSBORO NC	Transmission	Unattended	100	25	0	0	1
880	RIVER HILLS RET CLOVER SC	Distribution	Unattended	100	24	0	24	2
881	RIVERBEND STEAM STA MOUNT HOLLY NC	Transmission	Unattended	230	100	44	896	2
882	RIVERSTONE RET FOREST CITY NC	Transmission	Unattended	100	13	0	22	1
883	ROBBINSVILLE RET ROBBINSVILLE NC	Distribution	Unattended	13	0	0	2	4
884	ROBBINSVILLE RET ROBBINSVILLE NC	Distribution	Unattended	13	35	0	10	1
885	ROBBINSVILLE RET ROBBINSVILLE NC	Distribution	Unattended	161	13	0	52	3	1
886	ROBERTA RD RET CONCORD NC	Distribution	Unattended	44	13	0	20	2
887	ROCHESTER TIE NEWRY SC	Transmission	Unattended	100	44	0	34	1
888	ROCK HILL CITY DEL 4 ROCK HILL SC	Distribution	Unattended	100	24	13	24	2
889	ROCK HILL MN ROCK HILL SC	Distribution	Unattended	100	13	7	28	3	1
890	ROCKETT RET CONOVER NC	Distribution	Unattended	100	13	0	24	2
891	ROCKWELL RET ROCKWELL NC	Distribution	Unattended	100	13	0	40	2
892	ROCKY CREEK HYDRO GREAT FALLS SC	Transmission	Unattended	2	0	0	2	2
893	ROCKY CREEK HYDRO GREAT FALLS SC	Transmission	Unattended	44	4	0	32	4
894	ROPER MTN RET GREENVILLE SC	Distribution	Unattended	100	13	0	40	2
895	ROSE HILL RET GAFFNEY SC	Distribution	Unattended	100	13	7	16	3	1
896	ROSMAN SS ROSMAN NC	Distribution	Unattended	44	7	2	4	1	1
897	ROSMAN SS ROSMAN NC	Distribution	Unattended	44	12	7	4	1
898	ROSMAN SS ROSMAN NC	Distribution	Unattended	44	13	0	0	1
899	ROSMAN SS ROSMAN NC	Distribution	Unattended	44	13	7	8	3
900	ROUGHEDGE TIE ROUGHEDGE NC	Transmission	Unattended	44	13	0	0	1
901	ROUGHEDGE TIE ROUGHEDGE NC	Transmission	Unattended	100	44	0	30	6	1
902	ROYAL RET CHARLOTTE NC	Distribution	Unattended	100	24	0	40	2
903	ROZZELLES RET CHARLOTTE NC	Transmission	Unattended	100	13	0	74	2
904	RUDD RET GREENSBORO NC	Distribution	Unattended	100	24	0	42	2
905	RUFF SOLAR ELLENBORO NC	Transmission	Unattended	44	0	0		0
906	RUFFIN RET RUFFIN NC	Distribution	Unattended	44	7	0	11	4	1
907	RUFFIN RET RUFFIN NC	Distribution	Unattended	44	13	0	14	1
908	RURAL HALL RET RURAL HALL NC	Distribution	Unattended	44	13	0	20	2
909	RURAL HALL TIE RURAL HALL NC	Transmission	Unattended	44	0	0	30	2
910	RURAL HALL TIE RURAL HALL NC	Transmission	Unattended	230	100	44	1248	3
911	RUTHERFORD COLLEGE RET RUTHERFORD COLLEGE NC	Distribution	Unattended	44	13	0	10	1
912	RUTHERFORD COLLEGE RET RUTHERFORD COLLEGE NC	Distribution	Unattended	44	24	13	10	1
913	RUTLEDGE TIE MT AIRY NC	Transmission	Unattended	100	44	0	60	2
914	S CULLOWHEE RET CULLOWHEE NC	Distribution	Unattended	66	13	0	15	2
915	S FRANKLIN RET FRANKLIN NC	Distribution	Unattended	66	13	0	16	2
916	S GASTONIA RET GASTONIA NC	Distribution	Unattended	44	13	0	25	2
917	S HICKORY RET HICKORY NC	Transmission	Unattended	100	13	0	74	2
918	S SHELBY SS SHELBY NC	Distribution	Unattended	44	13	0	14	1
919	S SYLVA RET SYLVA NC	Distribution	Unattended	67	13	0	28	1
920	SADLER TIE REIDSVILLE NC	Transmission	Unattended	44	0	0	20	2
921	SADLER TIE REIDSVILLE NC	Transmission	Unattended	230	100	44	896	2
922	SALISBURY MN SALISBURY NC	Transmission	Unattended	24	0	0	0	1
923	SALISBURY MN SALISBURY NC	Transmission	Unattended	100	7	2	12	3	1
924	SALISBURY MN SALISBURY NC	Transmission	Unattended	100	13	0	40	2
925	SALISBURY MN SALISBURY NC	Transmission	Unattended	100	44	0	9	3
926	SALISBURY MN SALISBURY NC	Transmission	Unattended	100	44	24	28	6	1
927	SALUDA RET SALUDA NC	Distribution	Unattended	44	7	0	6	2	1
928	SALUDA RET SALUDA NC	Distribution	Unattended	44	7	2	5	4
929	SANDS RD RET REIDSVILLE NC	Distribution	Unattended	100	24	0	12	1
930	SANDY SPRINGS RET PENDLETON SC	Distribution	Unattended	44	7	2	6	3
931	SANDY SPRINGS RET PENDLETON SC	Distribution	Unattended	44	13	7	8	3	1
932	SANDY SPRINGS TIE SANDY SPRINGS SC	Transmission	Unattended	24	0	0	0	1
933	SANDY SPRINGS TIE SANDY SPRINGS SC	Transmission	Unattended	100	44	0	68	2
934	SAPPHIRE RET CASHIERS NC	Distribution	Unattended	66	13	0	10	1
935	SAWMILLS RET SAWMILLS NC	Distribution	Unattended	44	13	0	20	2
936	SAXAPAHAW RET SAXAPAHAW NC	Distribution	Unattended	44	13	0	20	2
937	SCUFFLETOWN RET SIMPSONVILLE SC	Distribution	Unattended	100	13	0	20	1
938	SEDGE GARDEN RET KERNERSVILLE NC	Distribution	Unattended	100	13	0	74	2
939	SEDGE GARDEN RET KERNERSVILLE NC	Distribution	Unattended	100	24	0	37	1
940	SENECA CITY DEL 1 SENECA SC	Distribution	Unattended	100	13	0	22	1
941	SENECA CITY DEL 2 SENECA SC	Distribution	Unattended	100	13	0	12	1
942	SENECA TIE SENECA SC	Transmission	Unattended	100	44	0	68	2
943	SEVENTH ST RET BURLINGTON NC	Distribution	Unattended	24	2	0	2	0	1
944	SEVENTH ST RET BURLINGTON NC	Distribution	Unattended	24	7	2	6	3
945	SEVENTH ST RET BURLINGTON NC	Distribution	Unattended	100	24	0	40	2
946	SEWARD RET WINSTON-SALEM NC	Distribution	Unattended	100	24	0	40	2
947	SHADY GROVE TIE GREENVILLE SC	Transmission	Unattended	44	0	0	40	3
948	SHADY GROVE TIE GREENVILLE SC	Transmission	Unattended	230	100	44	600	2
949	SHARON GROVE SS HICKORY GROVE SC	Distribution	Unattended	44	7	2	11	6	1
950	SHARON RET CHARLOTTE NC	Distribution	Unattended	100	24	0	40	2
951	SHATTALON SW STA WINSTON-SALEM NC	Transmission	Unattended	100	13	0	74	2
952	SHELBY CITY DEL 8 SHELBY NC	Distribution	Unattended	44	13	0	20	2
953	SHELBY MN SHELBY NC	Distribution	Unattended	44	2	0	12	3	1
954	SHELBY TIE SHELBY NC	Transmission	Unattended	44	0	0	20	2
955	SHELBY TIE SHELBY NC	Transmission	Unattended	44	2	1	3	3
956	SHELBY TIE SHELBY NC	Transmission	Unattended	230	100	44	700	3
957	SHERRILLS FORD SS SHERRILLS FORD NC	Distribution	Unattended	44	13	0	28	2
958	SHOPTON RET CHARLOTTE NC	Distribution	Unattended	100	24	0	37	1
959	SHORTOFF RET HIGHLANDS NC	Distribution	Unattended	66	13	0	10	1
960	SIX MILE RET SIX MILE SC	Distribution	Unattended	44	13	0	10	1
961	SMITHTOWN RET SMITHTOWN NC	Distribution	Unattended	44	13	0	10	1
962	SOUTHBOUND RET WINSTON-SALEM NC	Distribution	Unattended	100	13	0	20	1
963	SOUTHBOUND RET WINSTON-SALEM NC	Distribution	Unattended	100	24	0	40	2
964	SOUTHPORT RD RET SPARTANBURG SC	Transmission	Unattended	100	13	0	20	1
965	SPARTAN GREEN RET DUNCAN SC	Distribution	Unattended	100	24	0	40	2
966	SPARTAN HEIGHTS RET HENDERSONVILLE NC	Distribution	Unattended	44	13	0	20	2
967	SPEEDWAY RET HARRISBURG NC	Transmission	Unattended	13	0	0	0	1
968	SPEEDWAY RET HARRISBURG NC	Transmission	Unattended	100	13	7	27	3	1
969	SPEEDWAY RET HARRISBURG NC	Transmission	Unattended	100	24	0	37	1
970	SPRINGFIELD RET CHARLOTTE NC	Distribution	Unattended	100	24	0	40	2
971	SPRINGS IND SS FORT LAWN SC	Distribution	Unattended	13	0	0	0	1
972	SPRINGS IND SS FORT LAWN SC	Distribution	Unattended	100	24	13	12	1
973	ST MARKS RET BURLINGTON NC	Transmission	Unattended	100	24	0	93	2
974	ST STEPHENS RET HICKORY NC	Distribution	Unattended	100	13	0	24	2
975	STALLINGS RD RET DURHAM NC	Transmission	Unattended	100	13	0	37	1
976	STALLINGS RD RET DURHAM NC	Transmission	Unattended	100	24	0	22	1
977	STAMEY TIE STATESVILLE NC	Transmission	Unattended	13	0	0	2	2
978	STAMEY TIE STATESVILLE NC	Transmission	Unattended	230	100	13	670	2
979	STAMEY TIE STATESVILLE NC	Transmission	Unattended	230	100	44	400	1
980	STARMOUNT FOREST DIST GREENSBORO NC	Distribution	Unattended	24	7	2	12	3	1
981	STARTOWN RET NEWTON NC	Distribution	Unattended	44	13	0	28	2
982	STATESVILLE CITY DEL 2 STATESVILLE NC	Distribution	Unattended	100	24	0	20	1
983	STATESVILLE CITY DEL 2 STATESVILLE NC	Distribution	Unattended	100	24	13	12	1
984	STATESVILLE CITY DEL 3 STATESVILLE NC	Distribution	Unattended	100	24	0	20	1
985	STATESVILLE RD RET SALISBURY NC	Distribution	Unattended	100	13	0	40	2
986	STATESVILLE TIE STATESVILLE NC	Transmission	Unattended	100	13	7	28	6	1
987	STATESVILLE TIE STATESVILLE NC	Transmission	Unattended	100	44	0	52	3
988	STEELE CREEK RET CHARLOTTE NC	Transmission	Unattended	100	24	0	112	2
989	STOUTS RET STOUTS NC	Distribution	Unattended	100	24	0	60	3
990	STUART W CRAMER RET CRAMERTON NC	Transmission	Unattended	100	12	0	22	1
991	SUGAR HILL TIE MARION NC	Transmission	Unattended	24	0	0	0	1
992	SUGAR HILL TIE MARION NC	Transmission	Unattended	100	44	0	60	2
993	SUMMERFIELD RET SUMMERFIELD NC	Distribution	Unattended	100	24	0	42	2
994	SUMMEY ST RET CLEMSON SC	Transmission	Unattended	100	13	0	66	3
995	SUMNER RET SALISBURY NC	Distribution	Unattended	100	13	0	42	2
996	SUN CITY YORK SC	Distribution	Unattended	100	24	0	37	1
997	SUNSET RET CHARLOTTE NC	Distribution	Unattended	100	13	0	40	2
998	SWAIMTOWN RET WINSTON-SALEM NC	Distribution	Unattended	100	13	0	40	2
999	SWAIN TIE BRYSON CITY NC	Transmission	Unattended	69	13	0	5	2
1000	SWAIN TIE BRYSON CITY NC	Transmission	Unattended	161	66	0	55	2
1001	SWAIN TIE BRYSON CITY NC	Transmission	Unattended	170	66	0	45	1
1002	SWEETWATER RET HICKORY NC	Distribution	Unattended	100	13	0	24	2
1003	SWEPSONVILLE TIE SWEPSONVILLE NC	Transmission	Unattended	24	0	0	0	1
1004	SWEPSONVILLE TIE SWEPSONVILLE NC	Transmission	Unattended	44	13	0	21	2
1005	SWEPSONVILLE TIE SWEPSONVILLE NC	Transmission	Unattended	100	44	0	40	2
1006	TABERNACLE CHURCH RET GREENSBORO NC	Distribution	Unattended	44	13	0	10	1
1007	TABLE ROCK TIE MORGANTON NC	Transmission	Unattended	24	0	0	0	1
1008	TABLE ROCK TIE MORGANTON NC	Transmission	Unattended	44	0	0	9	1
1009	TABLE ROCK TIE MORGANTON NC	Transmission	Unattended	100	44	0	10	1
1010	TABLE ROCK TIE MORGANTON NC	Transmission	Unattended	100	44	33	20	2
1011	TANNER RET RUTHERFORDTON NC	Distribution	Unattended	100	7	2	16	3	1
1012	TARRANT RD RET GREENSBORO NC	Transmission	Unattended	100	24	0	112	2
1013	TAYLORSVILLE TIE TAYLORSVILLE NC	Transmission	Unattended	24	0	0	0	1
1014	TAYLORSVILLE TIE TAYLORSVILLE NC	Transmission	Unattended	100	13	7	16	3	1
1015	TAYLORSVILLE TIE TAYLORSVILLE NC	Transmission	Unattended	100	44	0	40	2
1016	TECHNOLOGY RET CHARLOTTE NC	Distribution	Unattended	100	24	0	44	2
1017	TEGA CAY RET FORT MILL SC	Distribution	Unattended	100	24	0	12	1
1018	TEGA CAY RET FORT MILL SC	Distribution	Unattended	100	24	13	12	1
1019	TENNESSEE CREEK HYDRO TUCKASEGEE NC	Distribution	Unattended	66	4	0	13	1
1020	THIRD AVE RET HICKORY NC	Distribution	Unattended	100	13	0	40	2
1021	THOMASVILLE MN THOMASVILLE NC	Distribution	Unattended	100	7	2	28	6	2
1022	THORPE HYDRO TUCKASEGEE NC	Transmission	Unattended	7	0	0	0	1
1023	THORPE HYDRO TUCKASEGEE NC	Transmission	Unattended	66	4	0	3	3
1024	THORPE HYDRO TUCKASEGEE NC	Transmission	Unattended	66	13	0	5	1
1025	THORPE HYDRO TUCKASEGEE NC	Transmission	Unattended	161	7	0	36	3	1
1026	THORPE HYDRO TUCKASEGEE NC	Transmission	Unattended	161	66	0	80	2
1027	THRIFT RET CHARLOTTE NC	Distribution	Unattended	100	13	0	40	2
1028	TIGER TIE DUNCAN SC	Transmission	Unattended	230	100	44	900	3
1029	TIGERVILLE RET TIGERVILLE SC	Distribution	Unattended	44	7	2	17	6	1
1030	TNS M GREEN PL STA 3 GREER SC	Distribution	Unattended	100	13	0	0	0
1031	TOAST RET TOAST NC	Distribution	Unattended	100	13	0	24	2
1032	TOXAWAY TIE ANDERSON SC	Transmission	Unattended	44	2	0	4	3	1
1033	TOXAWAY TIE ANDERSON SC	Transmission	Unattended	100	13	0	52	3
1034	TOXAWAY TIE ANDERSON SC	Transmission	Unattended	100	44	24	76	2
1035	TRADESVILLE RET TRADESVILLE SC	Distribution	Unattended	44	7	0	6	2	1
1036	TRADESVILLE RET TRADESVILLE SC	Distribution	Unattended	44	7	2	4	1
1037	TRAVELERS REST RET TRAVELERS REST SC	Distribution	Unattended	44	7	2	12	6
1038	TREMONT RET LENOIR NC	Distribution	Unattended	44	13	0	20	2
1039	TREYBURN RET DURHAM NC	Distribution	Unattended	100	24	0	40	2
1040	TRIAD PARK RET KERNERSVILLE NC	Transmission	Unattended	100	13	0	40	2
1041	TRIANGLE RET LOWESVILLE NC	Transmission	Unattended	100	13	4	37	1
1042	TRIANGLE RET LOWESVILLE NC	Transmission	Unattended	100	24	0	37	1
1043	TRIBBLE ST RET ANDERSON SC	Distribution	Unattended	44	2	1	4	1	1
1044	TRIBBLE ST RET ANDERSON SC	Distribution	Unattended	44	7	2	9	5	1
1045	TRINITY RIDGE RET LAURENS SC	Distribution	Unattended	44	7	2	6	3	1
1046	TRINITY RIDGE RET LAURENS SC	Distribution	Unattended	44	13	0	14	1
1047	TRINITY RIDGE RET LAURENS SC	Distribution	Unattended	44	13	7	6	3	1
1048	TRIPLETT RET MOORESVILLE NC	Distribution	Unattended	100	13	0	37	1
1049	TRIPLETT RET MOORESVILLE NC	Distribution	Unattended	100	13	7	37	1
1050	TRIPLETT RET MOORESVILLE NC	Distribution	Unattended	100	24	0	0	1
1051	TROLLINGWOOD RET HAW RIVER NC	Transmission	Unattended	100	24	0	70	2
1052	TROUTMAN RET TROUTMAN NC	Distribution	Unattended	44	7	2	12	3	1
1053	TROUTMAN RET TROUTMAN NC	Distribution	Unattended	44	13	7	9	3
1054	TRYON RET TRYON NC	Distribution	Unattended	44	7	2	6	3	1
1055	TRYON RET TRYON NC	Distribution	Unattended	44	13	0	28	2
1056	TUCKASEGEE TIE TUCKASEGEE NC	Transmission	Unattended	13	0	0	2	2
1057	TUCKASEGEE TIE TUCKASEGEE NC	Transmission	Unattended	230	161	13	500	2
1058	TUCKERS CREEK RET BREVARD NC	Distribution	Unattended	44	13	0	20	2
1059	TUMBLING SHOALS SS LAURENS SC	Distribution	Unattended	44	7	0	0	2
1060	TUMBLING SHOALS SS LAURENS SC	Distribution	Unattended	44	7	2	8	2
1061	TURNER SHOALS SW STA MILL SPRINGS NC	Transmission	Unattended	2	0	0	0	2
1062	TURNER SHOALS SW STA MILL SPRINGS NC	Transmission	Unattended	24	0	0	0	1
1063	TURNER SHOALS SW STA MILL SPRINGS NC	Transmission	Unattended	44	0	0	10	1
1064	TURNER SHOALS SW STA MILL SPRINGS NC	Transmission	Unattended	44	2	1	6	3
1065	TURNERSBURG RET TURNERSBURG NC	Distribution	Unattended	44	7	0	9	3
1066	TURNERSBURG RET TURNERSBURG NC	Distribution	Unattended	44	24	7	3	0	1
1067	TYSINGER RD RET MIDWAY NC	Distribution	Unattended	100	13	0	12	1
1068	UNA RET SPARTANBURG SC	Distribution	Unattended	100	13	0	40	2
1069	UNC-CH DEL 1 CAMERON CHAPEL HILL NC	Distribution	Unattended	100	13	0	68	2
1070	UNC-CH DEL 2 SOUTH CHAPEL HILL NC	Distribution	Unattended	100	13	0	30	1
1071	UNIFI MADISON T&D MADISON NC	Distribution	Unattended	100	24	0	30	1
1072	UNIFI YADKINVILLE T&D STA 1 YADKINVILLE NC	Distribution	Unattended	100	13	0	24	2
1073	UNIFI YADKINVILLE T&D STA 2 YADKINVILLE NC	Distribution	Unattended	100	24	0	40	2
1074	UNIV OF N C CHARLOTTE STA 2 CHARLOTTE NC	Distribution	Unattended	100	44	0	22	1
1075	UPWARD RD RET HENDERSONVILLE NC	Transmission	Unattended	100	13	0	44	2
1076	URQUHART STEAM STA AUGUSTA GA	Transmission	Unattended	100	13	0	65	1
1077	VALDESE RET VALDESE NC	Distribution	Unattended	44	2	1	15	3
1078	VALDESE RET VALDESE NC	Distribution	Unattended	44	13	0	20	2
1079	VALDESE TIE VALDESE NC	Transmission	Unattended	100	24	0	24	3	1
1080	VALDESE TIE VALDESE NC	Transmission	Unattended	100	44	0	20	1
1081	VALMEAD RET LENOIR NC	Distribution	Unattended	44	13	0	10	1
1082	VALMEAD RET LENOIR NC	Distribution	Unattended	44	13	7	16	3	1
1083	VAN WYCK RET VAN WYCK SC	Distribution	Unattended	44	7	0	4	3	1
1084	VAN WYCK RET VAN WYCK SC	Distribution	Unattended	44	7	2	3	3
1085	VAN WYCK RET VAN WYCK SC	Distribution	Unattended	44	13	7	9	3	1
1086	VAN WYCK TIE VAN WYCK SC	Distribution	Unattended	24	0	0	0	1
1087	VAN WYCK TIE VAN WYCK SC	Distribution	Unattended	100	44	0	32	2
1088	VANDALIA RET GREENSBORO NC	Distribution	Unattended	24	7	2	8	3	1
1089	VANDALIA RET GREENSBORO NC	Distribution	Unattended	100	24	0	60	3
1090	VERDAE RET GREENVILLE SC	Distribution	Unattended	100	13	0	22	1
1091	VERDAE RET GREENVILLE SC	Distribution	Unattended	100	24	0	37	1
1092	VETERANS ADMINISTRATION HOSP SALISBURY NC	Distribution	Unattended	44	13	7	9	3
1093	VICTOR HILL RET DUNCAN SC	Transmission	Unattended	100	13	0	74	2
1094	VICTOR HILL RET DUNCAN SC	Transmission	Unattended	100	24	0	37	1
1095	VICTOR HILL SPARTANBURG SC	Distribution	Unattended	100	13	0	74	2
1096	VICTOR HILL SPARTANBURG SC	Distribution	Unattended	100	24	0	37	1
1097	W FRANKLIN RET FRANKLIN NC	Distribution	Unattended	66	13	0	15	2
1098	W GASTONIA RET GASTONIA NC	Distribution	Unattended	100	13	0	24	2
1099	W HICKORY RET HICKORY NC	Distribution	Unattended	44	13	0	12	3	1
1100	W NORWOOD RET NORWOOD NC	Distribution	Unattended	24	7	2	8	3	1
1101	W NORWOOD RET NORWOOD NC	Distribution	Unattended	100	24	0	24	2
1102	W SPARTANBURG TIE SPARTANBURG SC	Transmission	Unattended	100	44	0	24	4
1103	WADDELL RD RET GREENVILLE SC	Transmission	Unattended	12	12	0	0	1
1104	WADDELL RD RET GREENVILLE SC	Transmission	Unattended	100	13	0	111	3
1105	WADSWORTH RET SPARTANBURG SC	Distribution	Unattended	100	13	0	40	2
1106	WALDEN RET SPARTANBURG SC	Distribution	Unattended	100	24	0	12	1
1107	WALHALLA TIE WALHALLA SC	Transmission	Unattended	44	0	0	0	1
1108	WALHALLA TIE WALHALLA SC	Transmission	Unattended	100	44	0	36	3
1109	WALKER TIE HARMONY SC	Transmission	Unattended	24	0	0	0	2
1110	WALKER TIE HARMONY SC	Transmission	Unattended	100	44	0	40	2
1111	WALKERTOWN RET WALKERTOWN NC	Transmission	Unattended	100	13	0	44	2
1112	WALLACE RD RET MIDLAND NC	Distribution	Unattended	100	24	0	20	1
1113	WALNUT COVE TIE WALNUT COVE NC	Transmission	Unattended	44	13	7	0	0	1
1114	WALNUT COVE TIE WALNUT COVE NC	Transmission	Unattended	44	24	0	14	1
1115	WALNUT COVE TIE WALNUT COVE NC	Transmission	Unattended	100	44	0	93	2
1116	WARE PLACE RET PELZER SC	Distribution	Unattended	44	7	0	3	1
1117	WARE PLACE RET PELZER SC	Distribution	Unattended	44	7	2	2	1	1
1118	WARE PLACE RET PELZER SC	Distribution	Unattended	44	7	13	10	1
1119	WASHBURN RET BOSTIC NC	Distribution	Unattended	44	13	0	14	1
1120	WASHBURN RET BOSTIC NC	Distribution	Unattended	44	13	4	12	4
1121	WATEREE HYDRO LUGOFF SC	Transmission	Unattended	7	1	0	0	3
1122	WATEREE HYDRO LUGOFF SC	Transmission	Unattended	100	7	0	50	5
1123	WATERTOWER RET KANNAPOLIS NC	Distribution	Unattended	13	2	0	2	0	1
1124	WATERTOWER RET KANNAPOLIS NC	Distribution	Unattended	13	2	1	3	3
1125	WATERTOWER RET KANNAPOLIS NC	Distribution	Unattended	44	13	0	20	2
1126	WAYNICK RD RET REIDSVILLE NC	Distribution	Unattended	100	13	0	12	1
1127	WEAVER RET DURHAM NC	Distribution	Unattended	100	24	0	20	1
1128	WEBBS CHAPEL RET DENVER NC	Distribution	Unattended	44	13	0	20	2
1129	WEBSTER TIE WEBSTER NC	Transmission	Unattended	66	13	0	28	2
1130	WEBSTER TIE WEBSTER NC	Transmission	Unattended	69	13	0	14	1
1131	WEBSTER TIE WEBSTER NC	Transmission	Unattended	161	66	0	150	2
1132	WENTWORTH RET WENTWORTH NC	Distribution	Unattended	100	13	0	25	2
1133	WESTMINSTER MN WESTMINSTER SC	Distribution	Unattended	44	7	2	0	3	1
1134	WESTMINSTER MN WESTMINSTER SC	Distribution	Unattended	100	44	0	36	3
1135	WHITE CROSS RET WHITE CROSS NC	Distribution	Unattended	44	13	13	14	1
1136	WHITE PLAINS RET MT AIRY NC	Distribution	Unattended	100	13	0	12	1
1137	WHITEHALL RET ANDERSON SC	Distribution	Unattended	100	13	0	40	2
1138	WHITMIRE RET WHITMIRE SC	Distribution	Unattended	100	7	2	20	3	1
1139	WHITSETT RET BURLINGTON NC	Transmission	Unattended	100	24	0	74	2
1140	WILDCAT TIE CORNELIUS NC	Transmission	Unattended	100	44	0	60	3
1141	WILGROVE RET CHARLOTTE NC	Distribution	Unattended	100	24	0	60	2
1142	WILKES TIE NORTH WILKESBORO NC	Transmission	Unattended	24	0	0	0	1
1143	WILKES TIE NORTH WILKESBORO NC	Transmission	Unattended	100	44	0	40	2
1144	WILLARD RD RET WINSTON-SALEM NC	Distribution	Unattended	100	24	0	20	1
1145	WILLIAMSBURG RET REIDSVILLE NC	Distribution	Unattended	100	13	0	12	1
1146	WILLIAMSBURG TIE WILLIAMSBURG NC	Transmission	Unattended	100	24	0	16	3	1
1147	WILLIAMSTON RET WILLIAMSTON SC	Distribution	Unattended	44	7	2	20	6	2
1148	WILLOW CREEK RET HIGH POINT NC	Distribution	Unattended	100	13	0	24	2
1149	WINECOFF RET CONCORD NC	Distribution	Unattended	44	13	0	12	1
1150	WINECOFF TIE CONCORD NC	Transmission	Unattended	44	0	0	11	3
1151	WINECOFF TIE CONCORD NC	Transmission	Unattended	230	100	44	1320	4
1152	WINSTON TIE WINSTON-SALEM NC	Transmission	Unattended	100	13	0	20	1
1153	WINTHROP UNIV DEL 3 ROCK HILL SC	Distribution	Unattended	24	13	0	11	1
1154	WITHERS RET CHARLOTTE NC	Distribution	Unattended	100	24	0	40	2
1155	WOODLAWN TIE CHARLOTTE NC	Transmission	Unattended	44	0	0	59	3
1156	WOODLAWN TIE CHARLOTTE NC	Transmission	Unattended	100	13	0	111	3
1157	WOODLAWN TIE CHARLOTTE NC	Transmission	Unattended	230	100	44	1120	3
1158	WOODRUFF RET WOODRUFF SC	Distribution	Unattended	44	13	0	16	2
1159	WOODRUFF TIE WOODRUFF SC	Transmission	Unattended	24	0	0	50	1
1160	WOODRUFF TIE WOODRUFF SC	Transmission	Unattended	100	44	0	70	3
1161	WRENN RET PIEDMONT SC	Distribution	Unattended	100	13	0	40	2
1162	WYLIE HYDRO PL FORT MILL SC	Transmission	Unattended	44	7	0	60	4
1163	WYLIE SW STA FORT MILL SC	Transmission	Unattended	100	44	0	24	2
1164	WYNDWARD POINT RET NEWRY SC	Transmission	Unattended	100	24	0	74	2
1165	YADKINVILLE RET YADKINVILLE NC	Transmission	Unattended	100	7	2	24	3	1
1166	YORK E C DEL 6 TIRZAH SC	Distribution	Unattended	44	13	0	15	2
1167	YORK RET YORK SC	Distribution	Unattended	13	2	1	3	3
1168	YORK RET YORK SC	Distribution	Unattended	100	13	0	24	2
1169	YORK RET YORK SC	Distribution	Unattended	100	24	13	12	1
1170	ZF TRANSMISSIONS GVILLE LLC GRAY COURT SC	Transmission	Unattended	100	13	0	22	1
1171	ZION CHURCH RD RET HICKORY NC	Distribution	Unattended	100	13	7	12	1
1172	EDDY RD RET NINETY SIX SC	Distribution	Unattended	44	12	0	28	2
1173	KERWIN CIRCLE RET KERNERSVILLE NC	Transmission	Unattended	100	12	0	22	1	0
1174	MCLEANSVILLE RET NC	Transmission	Unattended	100	25	0	37	1	0
1175	MICHELIN N AMER SANDY SPRINGS SANDY SPRINGS SC	Transmission	Unattended	100	4	0	67	3	0
1176	MICHELIN N AMERICA SPTBG SPARTANBURG SC	Transmission	Unattended	100	4	0	22	1	0
1177	TOTAL Transmission Substations						78155	1203	74	—
1178	TOTAL Distribution Substations						14940	1296	125	—
1179	TOTAL Generation Substations									—
1180	TOTAL						93095	2499	199	0	0	0

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not attempt to include or aggregate amounts in a nonspecific category such as "general". Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.
Line No.	Description of the Good or Service (a)	Name of Associated/Affiliated Company (b)	Account(s) Charged or Credited (c)	Amount Charged or Credited (d)
1	Non-power Goods or Services Provided by Affiliated
2	(a) Services Provided by Duke Energy Business Services	Duke Energy Business Services, LLC	Various	1,193,952,754
3	Customer and Market Services	Duke Energy Progress, LLC	Various	8,417,141
4	Generation Services	Duke Energy Progress, LLC	Various	32,660,274
5	Other Goods and Services	Duke Energy Progress, LLC	Various	15,503,305
6	Transmission and Distribution Services	Duke Energy Progress, LLC	Various	33,751,097
7	Customer and Market Services	Duke Energy Florida, LLC	Various	2,997,015
8	Generation Services	Duke Energy Florida, LLC	Various	1,181,260
9	Other Goods and Services	Duke Energy Florida, LLC	Various	796,942
10	Transmission and Distribution Services	Duke Energy Florida, LLC	Various	809,566
11	Customer and Market Services	Duke Energy Indiana, LLC	Various	153,254
12	Generation Services	Duke Energy Indiana, LLC	Various	201,129
13	Other Goods and Services	Duke Energy Indiana, LLC	Various	339,529
14	Transmission and Distribution Services	Duke Energy Indiana, LLC	Various	734,928
15	Customer and Market Services	Duke Energy Ohio, Inc.	Various	57,539
16	Gas Distribution Services	Duke Energy Ohio, Inc.	Various	2,710
17	Other Goods and Services	Duke Energy Ohio, Inc.	Various	6,313
18	Transmission and Distribution Services	Duke Energy Ohio, Inc.	Various	840,360
19	Gas Distribution Services	Piedmont Natural Gas Company, Inc.	Various	4,101,139
20	Other Goods and Services	Bison	Various	9,152,052
21	Generation Services	Duke Energy Kentucky	Various	329,547
22	Other Goods and Services	Duke Energy Kentucky	Various	27
23	Transmission and Distribution Services	Duke Energy Kentucky	Various	25,505
19
20	Non-power Goods or Services Provided for Affiliated
21	Services Provided to Duke Energy Business Services	Duke Energy Business Services, LLC	Various	1,413,748
22	Customer and Market Services	Duke Energy Progress, LLC	Various	55,194,599
23	Generation Services	Duke Energy Progress, LLC	Various	298,743,756
24	Other Goods and Services	Duke Energy Progress, LLC	Various	74,995,945
25	Transmission and Distribution Services	Duke Energy Progress, LLC	Various	53,603,805
26	Customer and Market Services	Duke Energy Florida, LLC	Various	41,709,771
27	Generation Services	Duke Energy Florida, LLC	Various	8,807,404
28	Other Goods and Services	Duke Energy Florida, LLC	Various	29,213,009
29	Transmission and Distribution Services	Duke Energy Florida, LLC	Various	23,221,928
30	Customer and Market Services	Duke Energy Indiana, LLC	Various	28,957,804
31	Generation Services	Duke Energy Indiana, LLC	Various	9,707,802
32	Other Goods and Services	Duke Energy Indiana, LLC	Various	10,124,241
33	Transmission and Distribution Services	Duke Energy Indiana, LLC	Various	21,340,075
34	Customer and Market Services	Duke Energy Kentucky, Inc.	Various	6,378,534
35	Generation Services	Duke Energy Kentucky, Inc.	Various	1,336,742
36	Other Goods and Services	Duke Energy Kentucky, Inc.	Various	1,962,880
37	Transmission and Distribution Services	Duke Energy Kentucky, Inc.	Various	2,248,291
38	Customer and Market Services	Duke Energy Ohio, Inc.	Various	16,440,570
39	Generation Services	Duke Energy Ohio, Inc.	Various	196,297
40	Other Goods and Services	Duke Energy Ohio, Inc.	Various	1,220,818
41	Transmission and Distribution Services	Duke Energy Ohio, Inc.	Various	10,583,369
42	Customer and Market Services	Piedmont Natural Gas Company, Inc.	Various	10,278,921
43	Generation Services	Piedmont Natural Gas Company, Inc.	Various	228,807
44	Other Goods and Services	Piedmont Natural Gas Company, Inc.	Various	1,025,061
45	Transmission and Distribution Services	Piedmont Natural Gas Company, Inc.	Various	3,989,585
46	Customer and Market Services	Cinergy Solutions	Various	6,633,031
47	Generation Services	Cinergy Solutions	Various	25,155
48	Other Goods and Services	Cinergy Solutions	Various	263,399
49	Transmission and Distribution Services	Cinergy Solutions	Various	382,338
50	Customer and Market Services	Duke Energy Corporation	Various	3,000
51	Generation Services	Duke Energy Corporation	Various	131,602
52	Other Goods and Services	Duke Energy Corporation	Various	1,838,230
53	Transmission and Distribution Services	Duke Energy Corporation	Various	1,149
54	Customer and Market Services	Duke Energy One, Inc.	Various	319,250
55	Generation Services	Duke Energy One, Inc.	Various	1,167
56	Other Goods and Services	Duke Energy One, Inc.	Various	1,018
57	Customer and Market Services	DukeEnergy Renewables Wind,LLC	Various	19
58	Generation Services	DukeEnergy Renewables Wind,LLC	Various	155,705
59	Other Goods and Services	DukeEnergy Renewables Wind,LLC	Various
60	Transmission and Distribution Services	DukeEnergy Renewables Wind,LLC	Various	389,485
42

Name of Respondent:

Duke Energy Carolinas, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/14/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: DescriptionOfNonPowerGoodOrService


Schedule Page: 429 Line No.: 2 Column: a
When an employee of the Service Company performs services for a Client Company, costs will be directly assigned or distributed or allocated. For allocated services, the allocation method will be on a basis reasonably related to the service performed. The Service Company Utility Service Agreement prescribes 23 Service Company functions and approximately 20 allocation methods.
Functions and Allocation Methods:
Information Systems
Number of Central Processing Unit Seconds Ratio/Millions of Instructions per Second
Number of Personal Computer Workstations Ratio
Number of Information Systems Servers Ratio
Number of Employees Ratio
Meters
Number of Customers Ratio
Transportation
Number of Employees Ratio
Three Factor Formula
Electric System Maintenance
Circuit Miles of Electric Transmission Lines Ratio
Circuit Miles of Electric Distribution Lines Ratio
Marketing and Customer Relations and Grid Solutions
Number of Customers Ratio
Electric Transmission & Distribution Engineering & Construction
Electric Transmission Plant's Construction - Expenditures Ratio
Electric Distribution Plant's Construction - Expenditures Ratio
Power Engineering & Construction
Electric Production Plant's Construction - Expenditures Ratio
Human Resources
Number of Employees Ratio
Supply Chain
Procurement Spending Ratio
Inventory Ratio
Facilities
Square Footage Ratio
Accounting
Three Factor Formula
Generating Unit MW Capability Ratio
Power Planning and Operations
Electric Peak Load Ratio
Weighted Avg of the Circuit Miles of Electric Distribution Lines Ratio and the Electric
Peak Load Ratio
Sales Ratio
Weighted Avg of the Circuit Miles of Electric Transmission Lines Ratio and the Electric
Peak Load Ratio
Generating Unit MW Capability Ratio


Public Affairs
Three Factor Formula
Weighted Avg of Number of Customers Ratio and Number of Employees Ratio
Legal
Three Factor Formula
Rates
Sales Ratio
Finance
Three Factor Formula
Rights of Way
Circuit Miles of Electric Transmission Lines Ratio
Circuit Miles of Electric Distribution Lines Ratio
Electric Peak Load Ratio
Internal Auditing
Three Factor Formula
Environmental, Health and Safety
Three Factor Formula
Sales Ratio
Fuels
Sales Ratio
Investor Relations
Three Factor Formula
Planning
Three Factor Formula
Executive
Three Factor Formula

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

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Who Must Submit

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