FERC Form

THIS FILING IS

Item 1:

☐ An Initial (Original) Submission

OR

☑ Resubmission No.




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

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

Exact Legal Name of Respondent (Company)

Duke Energy Florida, LLC

Year/Period of Report

End of:

2021

/

Q4

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

GENERAL INFORMATION

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

What and Where to Submit

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

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

The CPA Certification Statement should:

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

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

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

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

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

GENERAL INSTRUCTIONS

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

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

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

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

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

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

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

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

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

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

DEFINITIONS

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

EXCERPTS FROM THE LAW

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

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

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

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

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

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

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

"Sec. 304.

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

"Sec. 309.

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

GENERAL PENALTIES

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

FERC FORM NO.

1

REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER

IDENTIFICATION

01 Exact Legal Name of Respondent

Duke Energy Florida, LLC

02 Year/ Period of Report

End of:

2021

/

Q4

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

Michael Dirr

06 Title of Contact Person

Manager of Accounting II

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

(704) 382-9032

09 This Report is An Original / A Resubmission

(1)

☐ An Original

(2)

☑ A Resubmission

10 Date of Report (Mo, Da, Yr)

04/29/2022

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)

04/29/2022

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

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	Rev 4/29/2022 Revised filing corrects XBRL tagging for footnotes
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	Rev 4/29/2022 Revised filing corrects XBRL tagging for footnotes
23	ScheduleAllowanceInventoryAbstract Allowances	228	Rev 4/29/2022 Revised fiing deletes extra row
24	ScheduleExtraordinaryPropertyLossesAbstract Extraordinary Property Losses	230a
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
31	ScheduleOtherPaidInCapitalAbstract Other Paid-in Capital	253
32	ScheduleCapitalStockExpenseAbstract Capital Stock Expense	254b
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
39	ScheduleAccumulatedDeferredIncomeTaxesOtherPropertyAbstract Accumulated Deferred Income Taxes-Other Property	274
40	ScheduleAccumulatedDeferredIncomeTaxesOtherAbstract Accumulated Deferred Income Taxes-Other	276	Rev 4/29/2022 Revised filing adds beginning and ending balances
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	Rev 4/29/2022 Revised filing corrects XBRL tagging for footnotes
48	ScheduleTransmissionOfElectricityForOthersAbstract Transmission of Electricity for Others	328
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	Rev 4/29/2022 Revised filing corrects XBRL tagging for footnotes
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
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
63	ScheduleSteamElectricGeneratingPlantStatisticsAbstract Steam Electric Generating Plant Statistics	402
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 Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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: FL Date of Incorporation: 1899-07-18 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. Electric service in the state of Florida
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 Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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.

Duke Energy Florida, LLC is a wholly-owned subsidiary of Duke Energy Corporation, a North Carolina Corporation.

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	Duke Energy Florida Receivables, LLC	Receivables Finance	100
2	Duke Energy Florida Solar Solutions, LLC	Solar Power Development	100
3	Duke Energy Project Finance, LLC	Nuclear Asset Recovery	100

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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 Good	1,390,500	2021-01-01	2021-12-31
2	Executive Vice President and Chief Financial Officer	Steven Keith Young	775,675	2021-01-01	2021-12-31
3	Executive Vice President and Chief Operating Officer	Dhiaa Jamil	873,055	2021-01-01	2021-12-31
4	Executive Vice President, Chief Human Resources Officer	Ron Reising	475,065	2021-01-01	2021-12-31
5	Executive Vice President, Energy Solutions and President, Midwest/Florida Regions and Natural Gas Business (1/1/21 - 4/30/21)	Douglas Esamann	708,750	2021-01-01	2021-04-30
6	Executive Vice President, Energy Solutions and President, Midwest/Florida Regions and Natural Gas Business (4/30/21 - 12/31/21)	VACANT		2021-04-30	2021-12-31
7	EVP and CEO, Duke Energy Carolinas	Julie Janson	750,750	2021-01-01	2021-12-31
8	State President, Florida (1/1/21 - 3/15/21)	Catherine Stempien	399,500	2021-01-01	2021-03-15
9	State President, Florida (3/16/21 - 12/31/21)	Melissa Seixas	260,000	2021-03-16	2021-12-31
10	Senior Vice President, Corporate Development and Treasurer	Karl Newlin	523,841	2021-01-01	2021-12-31
11	Senior Vice President, Chief Accounting Officer, Tax and Controller (1/1/21 - 5/15/21)	Dwight L. Jacobs	354,003	2021-01-01	2021-05-15
12	Senior Vice President, Chief Accounting Officer, Tax and Controller (5/16/21 - 12/31/21)	Cynthia Lee	300,000	2021-05-16	2021-12-31
13	Executive Vice President, Customer Experience, Solutions, & Services	Harry Sideris	535,500	2021-01-01	2021-12-31
14	Executive Vice President, Chief Strategy & Commercial Officer	Brian Savoy	536,694	2021-01-01	2021-12-31
15	Executive Vice President and Chief Legal Officer	Kodwo Ghartey-Tagoe	605,000	2021-01-01	2021-12-31
16	Senior Vice President & Chief Administrative Officer (5/1/21 - 12/31/21)	Melody Birmingham	450,000	2021-05-01	2021-12-31
17	Senior Vice President, External Affairs & Communications (5/1/21 - 12/31/21)	Louis Renjel	450,000	2021-05-01	2021-12-31
18	SVP and CEO, Duke Energy Florida and Midwest (5/1/21 - 12/31/21)	Alex Glenn	475,000	2021-05-01	2021-12-31

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	false
2	Dhiaa Jamil, Executive Vice President and Chief Operating Officer	526 S Church St, Charlotte NC 28202	false
3	Julia S. Janson, Executive Vice President	526 S Church St, Charlotte NC 28202	false
4	Kodwo Ghartey-Tagoe; Executive Vice President, Chief Legal Officer and Secretary	526 S Church St, Charlotte NC 28202	false
5	R. Alexander Glenn, Senior Vice President	526 S Church St, Charlotte NC 28202	false

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	Joint Open Access Transmission Tariff (Network Demand Ministerial Changes)	ER21-2900
2	Rate Schedule No. 226	ER21-1561
3	Rate Schedule No. 81	ER21-2099
4	Joint Open Access Transmission Tariff (Schedule 10-B)	ER21-1940
5	Joint Open Access Transmission Tariff (Schedule 10-A.3)	ER21-2002
6	Joint Open Access Transmission Tariff (Att. X )	ER21-1115-004
7	Joint Open Access Transmission Tariff (Att. J)	ER21-1579
8	Joint Open Access Transmission Tariff (Sec. 1, 14, 15, 28, 42, schedule 9, Att. x-1)	ER21-1115-001
9	Joint Open Access Transmission Tariff (OATT)	ER21-1484

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	20210517-5137	05/17/2021	ER09-1166	2021 Annual Update for the OATT Formula Transmission Rate of Duke Energy Florida, LLC	Tariff Volume No. 4, Open Access Transmission Tariff

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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
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

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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.

Listed below are the franchise renewals completed in the fourth quarter of 2021:

•Kenneth City 12/8/2021

Listed below are the franchise renewals completed in the third quarter of 2021:

•Micanopy 7/13/2021

•St. Pete Beach 8/10/2021

•Ocoee 9/7/2021

•Deltona 9/20/2021

Listed below are the franchise renewals completed in the second quarter of 2021:

•Monticello 4/6/2021

•South Pasadena 6/8/2021

Listed below are the franchise renewals completed during the first quarter of 2021:

• Belleair Bluffs 1/11/2021

• Gulfport 1/20/2021

• Indian Rocks Beach 2/23/2021

• Belleview 3/2/2021

Duke Energy Florida remits a franchise fee to municipalities collected from customers based on 6% of the retail revenues for specific revenue classes within these cities having the franchise agreements and based on the provisions of the negotiated agreement.

High Springs Solar, LLC was merged into Duke Energy Florida, LLC on October 1, 2021 (which was the single member of the LLC) for DEF to take direct ownership of the underlying assets of the special purpose entity for regulatory accounting purposes. High Springs Solar, LLC was a special purpose entity engaged in the development of a future solar generation facility that was acquired from High Springs Solar Member, LLC by Duke Energy Florida, LLC in April 2021. Upon completion of the development work for the subject project, and prior to the commencement of construction of the facility.

There were no mergers completed during the third quarter of 2021.

Duke Energy Florida, LLC acquired High Springs Solar, LLC from Southeast Solar, LLC on April 21, 2021. High Springs Solar, LLC is a special purpose entity holding development assets (real property interests, environmental permits and studies, zoning permits and related assets) related to a possible future renewable energy facility in High Springs, FL. No Commission authorization was required for the transaction.2021.

There were no mergers completed during the first quarter of 2021.

There are no purchases or sales of operating units or systems to report during the first, second, third, or fourth quarters of 2021.

There were no important leasehold transactions completed during the first, second, third, or fourth quarters of 2021.

There was no state territory added or relinquished and no customers added or lost during the third or fourth quarter of 2021.

During the second quarter Duke Energy Florida (DEF) relinquished 6 residential customers via the territorial agreements with Sumter Electric Cooperative (3 customers) under Commission Order No. PSC-2020-0279-CO-EU and with Tri-County Electric Cooperative (3 customers) under Commission Order No. PSC- -2021-0085-CO-EU. The predicted annual revenue loss to DEF resulting from the relinquishment is approximately $22,000.

During the first quarter of 2021 Duke Energy Florida (DEF) acquired twenty-five customers (18 residential, 7 commercial) via the territorial agreement with Clay Electric Cooperative under Commission Order No. 16-0145-CO-EU. As the customers have been transferred as of March 2021, the predicted revenue gain to DEF resulting from the acquisition is approximately $55,000.

See Notes to Financial Statements, Note 5, "Commitments and Contingencies" and Note 6,"Debits and Credit Facilities".

None

During the fourth quarter of 2021, there were no large scale wage changes for Duke Energy Florida.

During the third quarter of 2021, there were no large scale wage changes for Duke Energy Florida.

During the second quarter of 2021, there were no large scale wage changes for Duke Energy Florida.

During the first quarter of 2021, there was an average merit increase applied to wage rates of exempt and non-exempt Duke Energy Florida employees totaling $2,803,696 annually

See Notes to Financial Statements, Note 4, “Regulatory Matters” and Note 5, “Commitments and Contingencies.”

None

13. The changes in officers and directors for Duke Energy Florida, LLC that occurred during the fourth quarter of 2021 are as follows:


Appointments Effective 11/1/2021
McDonald, Cameron D.			Vice President, Chief Diversity and Inclusion Officer, Talent Agility and Acquisition


Resignations Effective 11/1/2021
McDonald, Cameron D.			Vice President, Human Resources, Transformation & Employee Development

The changes in officers and directors for Duke Energy Florida, LLC that occurred during the third quarter 2021 are as follows:


Resignations Effective 8/1/2021
Esamann, Douglas F .			Advisor to the Chair, President and Chief Executive Officer

The changes in officers and directors for Duke Energy Florida, LLC that occurred during the second quarter 2021 are as follows:


Appointments Effective 6/16/2021
Anderson, Reginald D.			Vice President, Florida Generation and Engineer (under First Mortgage Bond Indenture)
Appointments Effective 6/1/2021
Gibby, Shawn K.			Vice President, Nuclear Engineering
Appointments Effective 5/16/2021
Jacobs, Dwight L.			Senior Vice President, Supply Chain and Chief Procurement Officer
Lee, Cynthia S.			Vice President, Chief Accounting Officer and Controller
Appointments Effective 5/1/2021
Bednarcik, Jessica L.			Senior Vice President, Environmental, Health and Safety and Coal Combustion Products
Birmingham, Melody			Senior Vice President and Chief Administrative Officer
Daji, Swati V.			Senior Vice President, Enterprise Strategy and Planning
Denton, Diane V.			Vice President, Integrated Planning, Florida and Midwest
Draovitch, Paul			Senior Vice President, Chief Regulated and Renewable Energy Officer and Engineer (under First Mortgage Bond Indenture)
Esamann, Douglas F.			Advisor to the Chair, President and Chief Executive Officer
Fallon, Christopher M.			Senior Vice President and President, Duke Energy Sustainable Solutions
Giaimo, Nicholas J.			Vice President, Financial Planning and Analysis
Glenn, R. Alexander			Senior Vice President
Janson, Julia S.			Executive Vice President
Renjel, Louis E.			Senior Vice President, External Affairs and Communications
Repko, Regis T.			Senior Vice President, Generation and Transmission Strategy
Savoy, Brian D.			Executive Vice President, Chief Strategy and Commercial Officer
Sideris, Harry K.			Executive Vice President, Customer Experience, Solutions, and Services
Resignations Effective 6/16/2021
Swartz, Jeffrey R.			Vice President, Florida Generation
Resignations Effective 5/16/2021
Jacobs, Dwight L.			Senior Vice President, Chief Accounting Officer, Tax and Controller
Resignations Effective 5/1/2021
Birmingham, Melody			Senior Vice President, Supply Chain and Chief Procurement Officer
Currens Jr., William E.			Senior Vice President, Financial Planning and Analysis
Daji, Swati V.			Senior Vice President, Customer Solutions and Strategies


Draovitch, Paul			Senior Vice President, Environmental, Health and Safety and Project Management and Controls
Esamann, Douglas F			Executive Vice President, Energy Solutions and President, Midwest/Florida Regions and Natural Gas Business
Fallon, Christopher M.			President, Duke Energy Renewables and Senior Vice President, Delivery & Operations
Grant, Eric S.			Regional Senior Vice President, Customer Delivery – Carolinas
Immel, Stephen J.			Vice President, Fleet Transition Strategy
Janson, Julia S.			Executive Vice President, External Affairs and President, Carolinas Region
Renjel, Louis E.			Senior Vice President, Federal Government and Corporate Affairs
Repko, Regis T.			Senior Vice President, Chief Regulated & Renewable Energy Officer and Engineer (under First Mortgage Bond Indenture)
Savoy, Brian D.			Senior Vice President, Chief Transformation and Administrative Officer
Sideris, Harry K.			Senior Vice President, Customer Experience and Services
Resignations Effective 4/16/2021
Snider, Steven M.			Vice President, Nuclear Engineering
Resignations Effective 4/1/2021
Boyce, Cari P.			Senior Vice President, Enterprise Strategy and Planning

The changes in officers and directors for Duke Energy Florida, LLC that occurred during the first quarter 2021 are as follows:


Appointments Effective 2/16/2021
Seixas, Melissa L.			President, Duke Energy Florida
Appointments Effective 2/1/2021
Bauer, Christopher R			Assistant Treasurer
Jordan, Kenna C			Assistant Secretary
Repko, Regis T			Senior Vice President, Chief Regulated & Renewable Energy Officer
Resignations Effective 2/16/2021
Stempien, Catherine S.			President, Duke Energy Florida
Resignations Effective 2/1/2021
Repko, Regis T.			Senior Vice President and Chief Fossil/Hydro Officer
Sullivan, III John L.			Assistant Treasurer

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	22,807,120,307	21,147,417,291
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	1,342,670,129	1,303,817,349
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		24,149,790,436	22,451,234,640
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	5,860,668,965	5,753,625,944
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		18,289,121,471	16,697,608,696
7	NuclearFuelInProcessOfRefinementConversionEnrichmentAndFabrication Nuclear Fuel in Process of Ref., Conv., Enrich., and Fab. (120.1)	202
8	NuclearFuelMaterialsAndAssembliesStockAccountMajorOnly Nuclear Fuel Materials and Assemblies-Stock Account (120.2)
9	NuclearFuelAssembliesInReactorMajorOnly Nuclear Fuel Assemblies in Reactor (120.3)
10	SpentNuclearFuelMajorOnly Spent Nuclear Fuel (120.4)
11	NuclearFuelUnderCapitalLeases Nuclear Fuel Under Capital Leases (120.6)
12	AccumulatedProvisionForAmortizationOfNuclearFuelAssemblies (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)	202
13	NuclearFuelNet Net Nuclear Fuel (Enter Total of lines 7-11 less 12)
14	UtilityPlantAndNuclearFuelNet Net Utility Plant (Enter Total of lines 6 and 13)		18,289,121,471	16,697,608,696
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)
17	OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS
18	NonutilityProperty Nonutility Property (121)		22,767,805	23,647,531
19	AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Prov. for Depr. and Amort. (122)		9,954,169	9,226,937
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224	16,472,514	16,560,306
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances	228
24	OtherInvestments Other Investments (124)		764,923	580,759
25	SinkingFunds Sinking Funds (125)
26	DepreciationFund Depreciation Fund (126)
27	AmortizationFundFederal Amortization Fund - Federal (127)
28	OtherSpecialFunds Other Special Funds (128)		851,374,259	857,683,146
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)
32	OtherPropertyAndInvestments TOTAL Other Property and Investments (Lines 18-21 and 23-31)		881,425,332	889,244,805
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)		22,991,564	10,810,269
36	SpecialDeposits Special Deposits (132-134)
37	WorkingFunds Working Fund (135)
38	TemporaryCashInvestments Temporary Cash Investments (136)
39	NotesReceivable Notes Receivable (141)
40	CustomerAccountsReceivable Customer Accounts Receivable (142)		461,953,418	368,467,447
41	OtherAccountsReceivable Other Accounts Receivable (143)		25,532,838	21,569,614
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		15,323,283	14,285,937
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)		14,333,768	799,669
45	FuelStock Fuel Stock (151)	227	143,244,000	141,296,152
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	317,936,298	308,065,816
49	Merchandise Merchandise (155)	227
50	OtherMaterialsAndSupplies Other Materials and Supplies (156)	227	94,692	31,582
51	NuclearMaterialsHeldForSale Nuclear Materials Held for Sale (157)	202/227
52	AllowanceInventoryAndWithheld Allowances (158.1 and 158.2)	228	3,212,783	3,221,471
53	NoncurrentPortionOfAllowances (Less) Noncurrent Portion of Allowances	228
54	StoresExpenseUndistributed Stores Expense Undistributed (163)	227	(a) 15,226,648	(b) 14,889,786
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)		66,354,195	70,819,237
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)
60	RentsReceivable Rents Receivable (172)		182,131	117,309
61	AccruedUtilityRevenues Accrued Utility Revenues (173)		72,613,906	115,635,471
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)
63	DerivativeInstrumentAssets Derivative Instrument Assets (175)
64	DerivativeInstrumentAssetsLongTerm (Less) Long-Term Portion of Derivative Instrument Assets (175)
65	DerivativeInstrumentAssetsHedges Derivative Instrument Assets - Hedges (176)
66	DerivativeInstrumentAssetsHedgesLongTerm (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176)
67	CurrentAndAccruedAssets Total Current and Accrued Assets (Lines 34 through 66)		1,128,352,958	1,041,437,886
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		58,671,894	51,811,671
70	ExtraordinaryPropertyLosses Extraordinary Property Losses (182.1)	230a	1,438,625	1,503,780
71	UnrecoveredPlantAndRegulatoryStudyCosts Unrecovered Plant and Regulatory Study Costs (182.2)	230b
72	OtherRegulatoryAssets Other Regulatory Assets (182.3)	232	1,643,152,117	1,405,140,808
73	PreliminarySurveyAndInvestigationCharges Prelim. Survey and Investigation Charges (Electric) (183)		3,538,464	1,508,784
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)		24,161	10,956
77	TemporaryFacilities Temporary Facilities (185)			139,361
78	MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186)	233	201,516,024	177,597,976
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)		5,935,257	7,124,278
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	902,270,724	884,610,287
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		2,816,498,944	2,529,425,989
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		23,115,398,705	21,157,717,376

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: StoresExpenseUndistributed

Stores Expense Undistributed (For internal use only)Production 8,795,193Transmission 2,548,363Distribution 3,546,230

(b) Concept: StoresExpenseUndistributed

Stores Expense Undistributed (For internal use only)Production 7,873,616Transmission 2,854,044Distribution 4,498,988

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	1,766,035,361	1,766,035,361
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	6,525,138,987	5,788,163,916
12	UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1)	118	226,117	393,712
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)	3,562,837	4,328,464
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		8,294,963,302	7,558,921,453
17	LongTermDebtAbstract LONG-TERM DEBT
18	Bonds Bonds (221)	256	7,075,000,000	6,425,000,000
19	ReacquiredBonds (Less) Reaquired Bonds (222)	256
20	AdvancesFromAssociatedCompanies Advances from Associated Companies (223)	256
21	OtherLongTermDebt Other Long-Term Debt (224)	256	400,000,000	400,000,000
22	UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225)
23	UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Debit (226)		13,603,552	10,498,283
24	LongTermDebt Total Long-Term Debt (lines 18 through 23)		7,461,396,448	6,814,501,717
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		297,526,862	361,905,822
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)		64,577,461	83,047,650
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		27,245,203	27,189,526
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		131,060,739	199,572,304
30	AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4)		30,226,613	32,473,482
31	AccumulatedProvisionForRateRefunds Accumulated Provision for Rate Refunds (229)
32	LongTermPortionOfDerivativeInstrumentLiabilities Long-Term Portion of Derivative Instrument Liabilities
33	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges Long-Term Portion of Derivative Instrument Liabilities - Hedges
34	AssetRetirementObligations Asset Retirement Obligations (230)		436,646,246	514,190,627
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		987,283,124	1,052,284,111
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)
38	AccountsPayable Accounts Payable (232)		623,066,965	463,282,517
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)		198,554,000	195,522,000
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		198,186,365	75,105,759
41	CustomerDeposits Customer Deposits (235)		192,453,415	202,800,377
42	TaxesAccrued Taxes Accrued (236)	262	11,699,675	78,811,420
43	InterestAccrued Interest Accrued (237)		69,515,328	69,834,828
44	DividendsDeclared Dividends Declared (238)
45	MaturedLongTermDebt Matured Long-Term Debt (239)
46	MaturedInterest Matured Interest (240)
47	TaxCollectionsPayable Tax Collections Payable (241)		19,592,493	18,059,405
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		120,871,963	109,335,702
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		64,378,961	61,361,504
50	DerivativesInstrumentLiabilities Derivative Instrument Liabilities (244)
51	LongTermPortionOfDerivativeInstrumentLiabilities (Less) Long-Term Portion of Derivative Instrument Liabilities
52	DerivativeInstrumentLiabilitiesHedges Derivative Instrument Liabilities - Hedges (245)		14,139,393
53	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges
54	CurrentAndAccruedLiabilities Total Current and Accrued Liabilities (lines 37 through 53)		1,489,059,208	1,274,113,512
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)		16,544,868	15,663,321
57	AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255)	266	235,766,505	145,829,017
58	DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256)
59	OtherDeferredCredits Other Deferred Credits (253)	269	76,460,034	28,124,358
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	1,215,750,420	1,194,101,751
61	UnamortizedGainOnReacquiredDebt Unamortized Gain on Reaquired Debt (257)
62	AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty Accum. Deferred Income Taxes-Accel. Amort.(281)	272	1	1
63	AccumulatedDeferredIncomeTaxesOtherProperty Accum. Deferred Income Taxes-Other Property (282)		2,513,054,454	2,275,359,130
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		825,120,341	798,819,005
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		4,882,696,623	4,457,896,583
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		23,115,398,705	21,157,717,376

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	5,111,847,480	5,043,412,116			5,111,847,480	5,043,412,116
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	2,961,149,778	2,512,804,944			2,961,149,778	2,512,804,944
5	MaintenanceExpense Maintenance Expenses (402)	320	243,465,082	235,987,064			243,465,082	235,987,064
6	DepreciationExpense Depreciation Expense (403)	336	586,910,249	541,592,905			586,910,249	541,592,905
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336		406,979				406,979
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	35,290,199	31,459,524			35,290,199	31,459,524
9	AmortizationOfElectricPlantAcquisitionAdjustments Amort. of Utility Plant Acq. Adj. (406)	336	91,646	91,646			91,646	91,646
10	AmortizationOfPropertyLossesUnrecoveredPlantAndRegulatoryStudyCosts Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
11	AmortizationOfConversionExpenses Amort. of Conversion Expenses (407.2)
12	RegulatoryDebits Regulatory Debits (407.3)		283,483,878	120,139,077			283,483,878	120,139,077
13	RegulatoryCredits (Less) Regulatory Credits (407.4)			47				47
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	382,654,888	379,380,745			382,654,888	379,380,745
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	80,120,902	141,019,355			80,120,902	141,019,355
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	17,699,495	22,239,255			17,699,495	22,239,255
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	814,956,863	685,444,578			814,956,863	685,444,578
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	531,970,318	664,634,030			531,970,318	664,634,030
19	InvestmentTaxCreditAdjustments Investment Tax Credit Adj. - Net (411.4)	266
20	GainsFromDispositionOfPlant (Less) Gains from Disp. of Utility Plant (411.6)		754,121	512,418			754,121	512,418
21	LossesFromDispositionOfServiceCompanyPlant Losses from Disp. of Utility Plant (411.7)		3	2,076			3	2,076
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)		1,228,487	1,649,303			1,228,487	1,649,303
25	UtilityOperatingExpenses TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)		4,111,718,481	4,006,256,998			4,111,718,481	4,006,256,998
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		1,000,128,999	1,037,155,118			1,000,128,999	1,037,155,118
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)		3,258,216	2,322,663
32	CostsAndExpensesOfMerchandisingJobbingAndContractWork (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)		652
33	RevenuesFromNonutilityOperations Revenues From Nonutility Operations (417)		56,753,264	57,152,452
34	ExpensesOfNonutilityOperations (Less) Expenses of Nonutility Operations (417.1)		25,300,998	26,366,018
35	NonoperatingRentalIncome Nonoperating Rental Income (418)		727,731	503,111
36	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1)	119	167,595	144,002
37	InterestAndDividendIncome Interest and Dividend Income (419)		2,135,577	4,132,409
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		16,139,829	12,077,036
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		6,022,435	592,219
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)		734,082	303,694
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		58,846,427	49,567,342
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)		892,448	84,678
44	MiscellaneousAmortization Miscellaneous Amortization (425)		788,692	1,159,611
45	Donations Donations (426.1)		5,152,449	2,413,159
46	LifeInsurance Life Insurance (426.2)		2,579,593	4,183,836
47	Penalties Penalties (426.3)		500,000	647
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		3,388,454	4,624,462
49	OtherDeductions Other Deductions (426.5)		20,595,063	21,973
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		28,737,513	4,120,694
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262	236,148	1,356,906
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262	4,869,851	6,908,250
54	IncomeTaxesOther Income Taxes-Other (409.2)	262	827,658	1,534,951
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272	1,663,813	6,299,867
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272	5,235,072	347,835
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)		2,362,398	15,752,139
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		27,746,516	29,694,509
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		282,138,524	285,378,590
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		6,217,336	5,880,503
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)		1,189,021	1,189,021
65	AmortizationOfPremiumOnDebtCredit (Less) Amort. of Premium on Debt-Credit (429)
66	AmortizationOfGainOnReacquiredDebtCredit (Less) Amortization of Gain on Reaquired Debt-Credit (429.1)
67	InterestOnDebtToAssociatedCompanies Interest on Debt to Assoc. Companies (430)		521,464	1,783,207
68	OtherInterestExpense Other Interest Expense (431)		6,250,033	6,578,988
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		6,317,136	4,797,336
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		289,999,242	296,012,973
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		737,876,273	770,836,654
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)		737,876,273	770,836,654

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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		5,788,163,916	5,017,733,461
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		186,790
4.3	AdjustmentsToRetainedEarningsCredit
4.4	AdjustmentsToRetainedEarningsCredit
4.5	AdjustmentsToRetainedEarningsCredit
9	AdjustmentsToRetainedEarningsCredit TOTAL Credits to Retained Earnings (Acct. 439)			186,790
10	AdjustmentsToRetainedEarningsDebitAbstract Adjustments to Retained Earnings Debit
10.1	AdjustmentsToRetainedEarningsDebit
10.2	AdjustmentsToRetainedEarningsDebit
10.3	AdjustmentsToRetainedEarningsDebit Interco JE to move RE in account 0216000 from BU50220 to 50229		1,068,797
10.4	AdjustmentsToRetainedEarningsDebit Current Expected Credit Losses (CECL) adjustments	186		736,991
10.5	AdjustmentsToRetainedEarningsDebit Current Expected Credit Losses (CECL) adjustments	144
15	AdjustmentsToRetainedEarningsDebit TOTAL Debits to Retained Earnings (Acct. 439)		1,068,797	736,991
16	BalanceTransferredFromIncome Balance Transferred from Income (Account 433 less Account 418.1)		738,043,868	770,980,656
17	AppropriationsOfRetainedEarningsAbstract Appropriations of Retained Earnings (Acct. 436)
22	AppropriationsOfRetainedEarnings TOTAL Appropriations of Retained Earnings (Acct. 436)
23	DividendsDeclaredPreferredStockAbstract Dividends Declared-Preferred Stock (Account 437)
29	DividendsDeclaredPreferredStock TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30	DividendsDeclaredCommonStockAbstract Dividends Declared-Common Stock (Account 438)
30.1	DividendsDeclaredCommonStock Cash Dividend to Parent
36	DividendsDeclaredCommonStock TOTAL Dividends Declared-Common Stock (Acct. 438)
37	TransfersFromUnappropriatedUndistributedSubsidiaryEarnings Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
38	UnappropriatedRetainedEarnings Balance - End of Period (Total 1,9,15,16,22,29,36,37)		6,525,138,987	5,788,163,916
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)
47	AppropriatedRetainedEarningsIncludingReserveAmortization TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
48	RetainedEarnings TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)		6,525,138,987	5,788,163,916
	UnappropriatedUndistributedSubsidiaryEarningsAbstract UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49	UnappropriatedUndistributedSubsidiaryEarnings Balance-Beginning of Year (Debit or Credit)		393,712	537,714
50	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings for Year (Credit) (Account 418.1)		167,595	144,002
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)
53	UnappropriatedUndistributedSubsidiaryEarnings Balance-End of Year (Total lines 49 thru 52)		226,117	393,712

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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)	737,876,273	770,836,654
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	586,910,249	541,185,926
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amort and Accretion of Limited & Electric Plant, Load Mgmt & Debt	39,778,630	36,357,068
5.2	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Contributions to Qualified Pensions
5.3	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription NET (Increase) Decrease in MTM and Hedging Transactions	3,413,747	9,393,621
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	279,415,286	26,762,580
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	110,025,751	36,814,316
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	9,195,247	25,695,036
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory	8,688	6,011
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	82,653,592	33,593,077
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	284,541,063	44,373,603
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	44,522,478	56,756,771
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	16,139,829	12,077,036
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies	167,595	144,002
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other (provide details in footnotes)
18.2	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Storm Collections	59,928,939	299,399,681
18.3	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Storm Cost Payments	11,091,919	9,315,327
18.4	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Post Retirement Expenses	55,760,050	50,387,183
18.5	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription LTSA Agreements	20,423,902	42,244,128
18.6	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Asset Retirement Obligations - Settlements	101,256,510	79,948,969
18.7	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription PPE Terminal, Citrus Settlement, Cap Lse, Bayside & Crystal River Impairmnt	6,848,960	16,984,252
18.8	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription State Tax Rate Change-Savings		2,793,306
18.9	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Customer Connect	36,655,043	9,745,340
18.10	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription EVCS Deferral		3,442,821
18.11	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Right-of-use Asset Amortization	11,161,800	27,702,267
18.12	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Franchise Fee & Utility Tax Audit	8,652,776
18.13	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription CARES Act - Employee Retention Credit	2,041,725
18.14	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Storm Reserve	88,889,351
18.15	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Lease/Rent Adjustments	8,262,062
18.16	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Deferred Credit	22,324,331
18.17	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other	5,515,677	1,510,899
18.18	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Gain/Loss on Sale of Assets	595,753	729,358
18.19	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Impairment of Assets	57,099	3,855,591
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	1,333,109,433	1,607,724,601
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)	(a) 1,906,465,860	(d) 1,894,667,683
27	GrossAdditionsToNuclearFuelInvestingActivities Gross Additions to Nuclear Fuel
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	16,139,829	12,077,036
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
31.1	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Other (provide details in footnote):
31.2	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Gross Additions Accrued Property
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	1,922,605,689	1,906,744,719
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		172,715,000
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)	301,695,557	4,442,938,166
45	ProceedsFromSalesOfInvestmentSecurities Proceeds from Sales of Investment Securities (a)	407,603,314	4,494,502,374
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 Disposal Cost of Removal (Net of Salvage)
53.2	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Cost of Removal net of salvage
53.3	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Other (provide details in footnote):
53.4	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Cost of Removal (Net of Salvage)	135,222,904	103,478,384
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	1,951,920,836	1,785,943,895
59	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
60	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
61	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b)	1,147,356,717	494,577,315
62	ProceedsFromIssuanceOfPreferredStockFinancingActivities Preferred Stock
63	ProceedsFromIssuanceOfCommonStockFinancingActivities Common Stock
64	OtherAdjustmentsToCashFlowsFromFinancingActivities Other (provide details in footnote):
64.1	OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription Other (provide details in footnote):
64.2	OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription Increase (Decrease) in InterCompany Money Pool	3,032,000	195,522,000
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
67.1	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	1,150,388,717	690,099,315
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)	500,000,000	499,999,999
74	PaymentsForRetirementOfPreferredStockFinancingActivities Preferred Stock
75	PaymentsForRetirementOfCommonStockFinancingActivities Common Stock
76	OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
76.1	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
76.2	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Other Financing due to bond issuance	434,875	549,309
76.3	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Capital lease payments	18,961,144	17,544,247
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)	630,992,698	172,005,760
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)	12,181,295	6,213,534
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	(b) 10,810,269	(e) 17,023,803
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	(c) 22,991,564	(f) 10,810,269

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities

Significant non-cash transactions:Accrued property additions: $337,480,865

(b) Concept: CashAndCashEquivalents

Includes $0 of temporary cash investments Supplemental Disclosures: Cash Paid for Interest, net of amount capitalized $321 million

(c) Concept: CashAndCashEquivalents

Includes $0 of temporary cash investments Supplemental Disclosures: Cash Paid for Interest, net of amount capitalized $308 million

(d) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities

Significant non-cash transactions:Accrued property additions: $213,645,861

(e) Concept: CashAndCashEquivalents

Includes $0 of temporary cash investments

(f) Concept: CashAndCashEquivalents

Includes $0 of temporary cash investments Supplemental Disclosures: Cash Paid for Interest, net of amount capitalized $321 million

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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, 2021 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 24, 2022. See "Index to the Combined Notes to Consolidated Financial Statements" for a listing of applicable notes for Duke Energy Carolinas, LLC.

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

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

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 17 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 8 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, 2021, or 2020.


		December 31,
(in millions)	Location	2021		2020
Duke Energy
Accrued compensation	Current Liabilities	$	915	$	662
Other accrued liabilities	Current Liabilities	649		1,455
Duke Energy Carolinas
Accrued compensation	Current Liabilities	$	277	$	213

Duke Energy Progress
Customer deposits	Current Liabilities	$	144	$	144
Other accrued liabilities	Current Liabilities	163		132
Duke Energy Florida
Customer deposits	Current Liabilities	$	200	$	203
Other accrued liabilities	Current Liabilities	89		81
Duke Energy Ohio
Gas Storage	Current Assets	$	25	$	21
Collateral liabilities	Current Liabilities	57		41

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, 2021, 2020 and 2019, the Income (Loss) From Discontinued Operations, net of tax on Duke Energy's Consolidated Statements of Operations is entirely attributable to controlling interest.

Noncontrolling Interest

Duke Energy maintains a controlling financial interest in certain less than wholly owned 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.

Several operating agreements of Duke Energy's subsidiaries with noncontrolling interest are subject to allocations of tax attributes and cash flows in accordance with contractual agreements that vary throughout the lives of the subsidiaries. Therefore, Duke Energy and the other investors' (the owners) interests in the subsidiaries are not fixed, and the subsidiaries apply the HLBV method in allocating income or loss and other comprehensive income or loss (all measured on a pretax basis) to the owners. The HLBV method measures the amounts that each owner would hypothetically claim at each balance sheet reporting date, including tax benefits realized by the owners, most of which is over the IRS recapture period, upon a hypothetical liquidation of the subsidiary at the net book value of its underlying assets. The change in the amount that each owner would hypothetically receive at the reporting date compared to the amount it would have received on the previous reporting date represents the amount of income or loss allocated to each owner for the reporting period.

Other 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.

In 2019, Duke Energy completed a sale of minority interest in a portion of certain renewable assets within the Commercial Renewables Segment for pretax proceeds to Duke Energy of $415 million. The portion of Duke Energy's commercial renewables energy portfolio sold includes 49% of 37 operating wind, solar and battery storage assets and 33% of 11 operating solar assets across the U.S. Duke Energy retained control of these assets, and, therefore, no gain or loss was recognized on the Consolidated Statements of Operations. The difference between the consideration received and the carrying value of the noncontrolling interest claim on net assets was $466 million, net of tax benefit of $8 million, and was recorded to equity.

The following table presents allocated losses to noncontrolling interest for the years ended December 31, 2021, 2020 and 2019.


	December 31,
(in millions)	2021	2020	2019




Noncontrolling Interest Allocation of Income
Allocated losses to noncontrolling tax equity members utilizing the HLBV method	$298	$271	$165
Allocated losses to noncontrolling members based on pro rata shares of ownership	31	24	12
Total Noncontrolling Interest Allocated Losses	$329	$295	$177

2021 Sale of Minority Interest in Duke Energy Indiana

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 will be completed following two closings for an aggregate purchase price of approximately $2 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 $1,025 million or 50% of the purchase price. Duke Energy retained indirect control of these assets, and, therefore, no gain or loss was recognized on the Consolidated Statements of Operations. 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. Under the terms of the agreement, Duke Energy has the discretion to determine the timing of the second closing, but it will occur no later than January 2023. At the second closing, Duke Energy will issue and sell additional membership interests such that GIC will own 19.9% of the membership interests for the remaining 50% of the purchase price.

Acquisitions

The Duke Energy Registrants consolidate assets and liabilities from acquisitions as of the purchase date and include earnings from acquisitions in consolidated earnings after the purchase date.

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 3 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 in 2021. See Note 17 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, 2021
			Duke				Duke		Duke
	Duke		Energy		Progress		Energy		Energy
	Energy		Carolinas		Energy		Progress		Florida
Current Assets
Cash and cash equivalents	$	343	$	7	$	70	$	35	$	23
Other	170		—		39		—		39
Other Noncurrent Assets
Other	7		1		4		4		—
Total cash, cash equivalents and restricted cash	$	520	$	8	$	113	$	39	$	62


	December 31, 2020
			Duke				Duke		Duke
	Duke		Energy		Progress		Energy		Energy
	Energy		Carolinas		Energy		Progress		Florida
Current Assets
Cash and cash equivalents	$	259	$	21	$	59	$	39	$	11
Other	194		—		39		—		39
Other Noncurrent Assets
Other	103		—		102		—		—
Total cash, cash equivalents and restricted cash	$	556	$	21	$	200	$	39	$	50

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, 2021, and 2020, respectively. The components of inventory are presented in the tables below.


	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	$	2,397	$	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	$	3,199	$	1,026	$	1,398	$	921	$	477	$	116	$	418	$	109


	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
Materials and supplies	$	2,312	$	785	$	999	$	673	$	325	$	78	$	307	$	12
Coal	561		186		193		131		63		16		165		—
Natural gas, oil and other	294		39		183		107		76		16		1		56
Total inventory	$	3,167	$	1,010	$	1,375	$	911	$	464	$	110	$	473	$	68

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 15 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 11 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 11 for further information.

Long-Lived Asset Impairments

The Duke Energy Registrants evaluate long-lived assets, 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 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.

Equity Method Investment Impairments

Investments in affiliates that are not controlled by Duke Energy, but over which it has significant influence, are accounted for using the equity method. Equity method investments are assessed for impairment whenever events or changes in circumstances indicate that the carrying amount of the investment may not be recoverable. If the decline in value is considered to be other than temporary, the investment is written down to its estimated fair value, which establishes a new cost basis in the investment.

Impairment assessments use a discounted cash flow income approach and include consideration of the severity and duration of any decline in the fair value of the investments. The estimated cash flows may be based on alternative expected outcomes that are probability weighted. Key inputs that involve estimates and significant management judgment include cash flow projections, selection of a discount rate, probability weighting of potential outcomes, and whether any decline in value is considered temporary.

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,
	2021		2020		2019
Duke Energy	2.9	%	3.0	%	3.1	%
Duke Energy Carolinas	2.7	%	2.8	%	2.8	%
Progress Energy	3.1	%	3.2	%	3.1	%
Duke Energy Progress	3.0	%	3.1	%	3.1	%
Duke Energy Florida	3.3	%	3.3	%	3.1	%
Duke Energy Ohio	2.9	%	2.9	%	2.6	%
Duke Energy Indiana	3.6	%	3.5	%	3.3	%
Piedmont	2.1	%	2.3	%	2.4	%

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 10 for additional 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 23 for additional information.

For nonregulated operations, interest is capitalized during the construction phase with an offsetting non-cash credit to Interest Expense on the Consolidated Statements of Operations.

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, 2021, and December 31, 2020.


	December 31, 2021										December 30, 2020
					Duke		Duke						Duke
	Duke		Progress		Energy		Energy				Duke		Energy
(in millions)	Energy		Energy		Florida		Ohio		Piedmont		Energy		Ohio		Piedmont
Outstanding Accounts Payable Balance Sold	$	19	$	9	$	9	$	6	$	4	$	15	$	1	$	14
Suppliers Invoices Settled Through The Program	122		10		10		12		100		45		9		36

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 18 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 14 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.

Unamortized Debt Premium, Discount and Expense

Premiums, discounts and expenses incurred with the issuance of outstanding long-term debt are amortized over the term of the debt issue. The gain or loss on extinguishment associated with refinancing higher-cost debt obligations in the regulated operations is amortized over the remaining life of the original instrument. Amortization expense is recorded as Interest Expense in the Consolidated Statements of Operations and is reflected as Depreciation, amortization and accretion within Net cash provided by operating activities on the Consolidated Statements of Cash Flows.

Premiums, discounts and expenses are presented as an adjustment to the carrying value of the debt amount and included in Long-Term Debt on the Consolidated Balance Sheets presented.

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 19 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 3 and 4 for further information.

Pension and Other Post-Retirement Benefit Plans

Duke Energy maintains qualified, non-qualified and other post-retirement benefit plans. Eligible employees of the Subsidiary Registrants participate in the respective qualified, non-qualified and other post-retirement benefit plans and the Subsidiary Registrants are allocated their proportionate share of benefit costs. See Note 22 for further information, including significant accounting policies associated with these plans.

Severance and Special Termination Benefits

Duke Energy has severance plans under which in general, the longer a terminated employee worked prior to termination the greater the amount of severance benefits. 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 20 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 7 for further information.

Stock-Based Compensation

Stock-based compensation represents costs related to stock-based awards granted to employees and Board of Directors members. Duke Energy recognizes stock-based compensation based upon the estimated fair value of awards, net of estimated forfeitures at the date of issuance. The recognition period for these costs begins at either the applicable service inception date or grant date and continues throughout the requisite service period. Compensation cost is recognized as expense or capitalized as a component of property, plant and equipment. See Note 21 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. For ITCs associated with nonregulated operations see “Accounting for Renewable Energy Tax Credits.”

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 23 for further information.

Accounting for Renewable Energy Tax Credits

When Duke Energy receives ITCs on wind or solar facilities associated with its nonregulated operations, it reduces the basis of the property recorded on the Consolidated Balance Sheets by the amount of the ITC and, therefore, the ITC benefit is ultimately recognized in the statement of operations through reduced depreciation expense. Additionally, certain tax credits and government grants result in an initial tax depreciable base in excess of the book carrying value by an amount equal to one half of the ITC. Deferred tax benefits are recorded as a reduction to income tax expense in the period that the basis difference is created.

Duke Energy receives PTCs on wind facilities that are recognized as electricity is produced and records related amounts as a reduction of income tax expense.

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)	2021		2020		2019
Duke Energy	$	420	$	415	$	421
Duke Energy Carolinas	44		43		39
Progress Energy	250		249		256
Duke Energy Progress	22		26		21
Duke Energy Florida	228		223		235
Duke Energy Ohio	102		96		101
Duke Energy Indiana	23		25		23
Piedmont	1		2		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 19 for more information. Additionally, as further described in Note 3, 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, 2021, and 2020, an insignificant amount of Duke Energy’s consolidated Retained earnings balance represents undistributed earnings of equity method investments.

New Accounting Standards

The following new 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 new accounting standard was adopted by 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 7 and 18 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

The following new accounting standard has been issued but not yet adopted by the Duke Energy Registrants as of December 31, 2021.

Reference Rate Reform. In March 2020, the FASB issued new accounting guidance for reference rate reform. This guidance is elective and provides expedients to facilitate financial reporting for the anticipated transition away from the London Inter-bank Offered Rate (LIBOR) and other interbank reference rates starting in 2021 with all rates expected to be fully phased out in 2023. The optional expedients are effective for modification of existing contracts or new arrangements executed between March 12, 2020, through December 31, 2022.

Duke Energy has variable-rate debt and manages interest rate risk by entering into financial contracts including interest rate swaps that are generally indexed to LIBOR. Impacted financial arrangements extending beyond the phase out of the applicable LIBOR rate may require contractual amendment or termination to fully adapt to a post-LIBOR environment. Duke Energy is assessing these financial arrangements and is evaluating the use of optional expedients outlined in the new accounting guidance. Alternative index provisions are also being assessed and incorporated into new financial arrangements that extend beyond the phase out of the applicable LIBOR rate. The full outcome of the transition away from LIBOR cannot be determined at this time, but is not expected to have a material impact on the financial statements.

2. 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

Duke Energy's segment structure includes the following segments: Electric Utilities and Infrastructure, Gas Utilities and Infrastructure and Commercial Renewables.

The Electric Utilities and Infrastructure 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. Electric Utilities and Infrastructure also includes Duke Energy's electric transmission infrastructure investments.

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

The Commercial Renewables segment is primarily comprised of nonregulated utility-scale wind and solar generation assets located throughout the U.S.

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 12 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, 2021
	Electric		Gas				Total
	Utilities and		Utilities and		Commercial		Reportable
(in millions)	Infrastructure		Infrastructure		Renewables		Segments		Other		Eliminations		Total
Unaffiliated Revenues	$	22,570	$	2,022	$	476	$	25,068	$	29	$	—	$	25,097
Intersegment Revenues	33		90		—		123		82		(205)		—
Total Revenues	$	22,603	$	2,112	$	476	$	25,191	$	111	$	(205)	$	25,097
Interest Expense	$	1,432	$	142	$	72	$	1,646	$	643	$	(9)	$	2,280
Depreciation and amortization	4,251		303		225		4,779		237		(26)		4,990
Equity in earnings (losses) of unconsolidated affiliates	7		8		(34)		(19)		47		—		28
Income tax expense (benefit)	494		55		(78)		471		(279)		—		192
Segment income (loss)(a)(b)(c)(d)	3,850		396		201		4,447		(652)		—		3,795
Less noncontrolling interest													329
Add back preferred stock dividend													106
Income from discontinued operations, net of tax													7
Net income													$	3,579
Capital investments expenditures and acquisitions	$	7,653	$	1,271	$	543	$	9,467	$	285	$	—	$	9,752
Segment assets	143,841		15,179		6,977		165,997		3,590		—		169,587

(a) Electric Utilities and Infrastructure 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 3 and 4 for more information.

(b) Gas Utilities and Infrastructure 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 3 for additional information.

(c) Commercial Renewables includes a $35 million loss related to Texas Storm Uri of which ($8 million) is recorded within Nonregulated electric and other revenues, $2 million within Operations, maintenance and other, $29 million within Equity in earnings (losses) of unconsolidated affiliates and $12 million within Loss Attributable to Noncontrolling Interests on the Consolidated Statements of Operations. See Note 4 for additional information.

(d) 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 workplace realignment. See Note 10 for additional information.


	Year Ended December 31, 2020
	Electric		Gas				Total
	Utilities and		Utilities and		Commercial		Reportable
(in millions)	Infrastructure		Infrastructure		Renewables		Segments		Other		Eliminations		Total
Unaffiliated Revenues	$	21,687	$	1,653	$	502	$	23,842	$	26	$	—	$	23,868
Intersegment Revenues	33		95		—		128		71		(199)		—
Total Revenues	$	21,720	$	1,748	$	502	$	23,970	$	97	$	(199)	$	23,868
Interest Expense	$	1,320	$	135	$	66	$	1,521	$	657	$	(16)	$	2,162
Depreciation and amortization	4,068		258		199		4,525		209		(29)		4,705
Equity in earnings (losses) of unconsolidated affiliates	(1)		(2,017)		—		(2,018)		13		—		(2,005)
Income tax expense (benefit)	340		(349)		(65)		(74)		(162)		—		(236)
Segment income (loss)(a)(b)(c)	2,669		(1,266)		286		1,689		(426)		—		1,263
Less noncontrolling interest													295
Add back preferred stock dividend													107
Income from discontinued operations, net of tax													7
Net income													$	1,082
Capital investments expenditures and acquisitions	$	7,629	$	1,309	$	1,219	$	10,157	$	264	$	—	$	10,421
Segment assets	138,225		13,849		6,716		158,790		3,598		—		162,388

(a) Electric Utilities and Infrastructure 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, Electric Utilities and Infrastructure 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 3 for additional information.

(b) Gas Utilities and Infrastructure 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 3 and 12 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 20 for additional information.


	Year Ended December 31, 2019
	Electric		Gas				Total
	Utilities and		Utilities and		Commercial		Reportable
(in millions)	Infrastructure		Infrastructure		Renewables		Segments		Other		Eliminations		Total
Unaffiliated Revenues	$	22,798	$	1,770	$	487	$	25,055	$	24	$	—	$	25,079
Intersegment Revenues	33		96		—		129		71		(200)		—
Total Revenues	$	22,831	$	1,866	$	487	$	25,184	$	95	$	(200)	$	25,079
Interest Expense	$	1,345	$	117	$	95	$	1,557	$	705	$	(58)	$	2,204
Depreciation and amortization	3,951		256		168		4,375		178		(5)		4,548
Equity in earnings (losses) of unconsolidated affiliates	9		114		(4)		119		43		—		162
Income tax expense (benefit)	785		22		(115)		692		(173)		—		519
Segment income (loss)(a)(b)	3,536		432		198		4,166		(452)		—		3,714
Less noncontrolling interest													177
Add back preferred stock dividend													41
Loss from discontinued operations, net of tax													(7)
Net income													$	3,571
Capital investments expenditures and acquisitions	$	8,263	$	1,539	$	1,423	$	11,225	$	221	$	—	$	11,446
Segment assets	135,561		13,921		6,020		155,502		3,148		188		158,838

(a) Electric Utilities and Infrastructure includes a $27 million reduction of a prior year impairment at Citrus County CC related to the plant's cost cap.

(b) Gas Utilities and Infrastructure includes an after-tax impairment charge of $19 million for the remaining investment in Constitution. See Note 12 for additional information.

Geographical Information

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

Major Customers

For the year ended December 31, 2021, revenues from one customer of Duke Energy Progress are $586 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.

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
2021
Electric Utilities and Infrastructure	$	19,410	$	2,216	$	—	$	977	$	22,603
Gas Utilities and Infrastructure	—		—		2,025		87		2,112
Commercial Renewables	—		411		—		65		476
Total Reportable Segments	$	19,410	$	2,627	$	2,025	$	1,129	$	25,191
2020
Electric Utilities and Infrastructure	$	18,898	$	1,878	$	—	$	944	$	21,720
Gas Utilities and Infrastructure	—		—		1,691		57		1,748
Commercial Renewables	—		434		—		68		502
Total Reportable Segments	$	18,898	$	2,312	$	1,691	$	1,069	$	23,970
2019
Electric Utilities and Infrastructure	$	19,745	$	2,231	$	—	$	855	$	22,831
Gas Utilities and Infrastructure	—		—		1,782		84		1,866
Commercial Renewables	—		389		—		98		487
Total Reportable Segments	$	19,745	$	2,620	$	1,782	$	1,037	$	25,184

Duke Energy Ohio

Duke Energy Ohio has two reportable segments, Electric Utilities and Infrastructure and Gas Utilities and Infrastructure.

Electric Utilities and Infrastructure transmits and distributes electricity in portions of Ohio and generates, distributes and sells electricity in portions of Northern Kentucky. Gas Utilities and Infrastructure 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, 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)/Net Income	162		96		258		(6)		—		252


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


	Year Ended December 31, 2019
	Electric		Gas		Total
	Utilities and		Utilities and		Reportable
(in millions)	Infrastructure		Infrastructure		Segments		Other		Eliminations		Total


Total revenues	$	1,456	$	484	$	1,940	$	—	$	—	$	1,940
Interest expense	$	80	$	29	$	109	$	—	$	—	$	109
Depreciation and amortization	182		83		265		—		—		265
Income tax expense (benefit)	20		21		41		(1)		—		40
Segment income (loss)	159		85		244		(5)		—		239
Loss from discontinued operations, net of tax											(1)
Net income											$	238
Capital expenditures	$	680	$	272	$	952	$	—	$	—	$	952
Segment assets	6,188		3,116		9,304		34		—		9,338

3. 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)	2021		2020		2021		2020
Regulatory Assets
AROs – coal ash	$	3,408	$	3,408	$	1,399	$	1,357
AROs – nuclear and other	684		754		620		685
Accrued pension and OPEB	2,017		2,317		725		875
Deferred fuel and purchased power	1,253		213		718		162
Storm cost securitized balance, net	991		—		759		—
Nuclear asset securitized balance, net	937		991		937		991
Debt fair value adjustment	884		950		—		—
Retired generation facilities	357		417		265		363
Post-in-service carrying costs (PISCC) and deferred operating expenses	356		397		47		51
Hedge costs deferrals	348		351		137		148
Deferred asset – Lee and Harris COLA	317		356		21		32
Advanced metering infrastructure (AMI)	311		311		130		102
Customer connect project	242		136		124		55
Demand side management (DSM)/Energy efficiency (EE)	235		242		230		241
Vacation accrual	221		221		42		42
Storm cost deferrals	213		1,102		189		893
NCEMPA deferrals	165		124		165		124
CEP deferral	161		117		—		—
Derivatives – natural gas supply contracts	139		122		—		—
COR settlement	123		128		32		33
Nuclear deferral	120		123		42		35
Deferred pipeline integrity costs	108		92		—		—
Costs of removal regulatory asset	107		—		107		—
Manufactured gas plant (MGP)	104		104		—		—
Qualifying facility contract buyouts	94		107		94		107
ABSAT, coal ash basin closure	90		98		23		27
Incremental COVID-19 expenses	87		76		28		23
Amounts due from customers	85		110		—		—
Deferred severance charges	54		86		18		29




Other	426		609		87		158
Total regulatory assets	14,637		14,062		6,939		6,533
Less: current portion	2,150		1,641		1,030		758
Total noncurrent regulatory assets	$	12,487	$	12,421	$	5,909	$	5,775
Regulatory Liabilities
Net regulatory liability related to income taxes	$	7,199	$	7,368	$	2,394	$	2,411
Costs of removal	6,150		5,883		2,955		2,666
AROs – nuclear and other	2,053		1,512		—		—
Provision for rate refunds	274		344		87		123
Hedge cost deferrals	271		24		117		8
Accrued pension and OPEB	213		177		—		—


Other	1,203		1,098		491		483
Total regulatory liabilities	17,363		16,406		6,044		5,691
Less: current portion	1,211		1,377		478		640
Total noncurrent regulatory liabilities	$	16,152	$	15,029	$	5,566	$	5,051

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 9 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 9 for additional information.

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 22 for additional detail.

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

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.

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

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.

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.

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.

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

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

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

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

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

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

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

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.

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.

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.

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

ABSAT, coal ash basin closure. Represents deferred depreciation and returns associated with Ash Basin Strategic Action Team (ABSAT) capital assets related to converting the ash handling system from wet to dry.

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

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

Deferred severance charges. Represents costs incurred for employees separation from Duke Energy.

Net regulatory liability related to income taxes. Amounts for all registrants include regulatory liabilities related primarily to impacts from the Tax Act. See Note 23 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.

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

Amounts to be refunded to customers. Represents required rate reductions to retail customers by the applicable regulatory body.

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, 2021.

Duke Energy Indiana has certain dividend restrictions as a result of the minority interest investment agreement entered in January 2021 with GIC. Duke Energy Indiana will declare dividends before the second closing, which is required to be completed no later than January 2023, in accordance with the agreement. See additional information in Note 1.

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, 2021.

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

2021 Coal Ash Settlement

On January 22, 2021, Duke Energy Carolinas and Duke Energy Progress entered into the Coal Combustion Residuals Settlement Agreement (the “CCR Settlement Agreement”) with the North Carolina Public Staff (Public Staff), the North Carolina Attorney General’s Office and the Sierra Club (collectively, the "Settling Parties"), which was filed with the NCUC on January 25, 2021. The CCR Settlement Agreement resolves all coal ash prudence and cost recovery issues in connection with 2019 rate cases filed by Duke Energy Carolinas and Duke Energy Progress with the NCUC, as well as the equitable sharing issue on remand from the 2017 Duke Energy Carolinas and Duke Energy Progress North Carolina rate cases as a result of the December 11, 2020 North Carolina Supreme Court opinion. The settlement also provides clarity on coal ash cost recovery in North Carolina for Duke Energy Carolinas and Duke Energy Progress through January 2030 and February 2030 (the "Term"), respectively.

Duke Energy Carolinas and Duke Energy Progress agreed not to seek recovery of approximately $1 billion of systemwide deferred coal ash expenditures, but will retain the ability to earn a debt and equity return during the amortization period, which shall be five years under the 2019 North Carolina rate cases and will be set by the NCUC in future rate case proceedings. The equity return and the amortization period on deferred coal ash costs under the 2017 Duke Energy Carolinas and Duke Energy Progress North Carolina rate cases will remain unaffected. The equity return on deferred coal ash costs under the 2019 North Carolina rate cases and future rate cases in North Carolina will be set at 150 basis points lower than the authorized return on equity (ROE) then in effect, with a capital structure composed of 48% debt and 52% equity. Duke Energy Carolinas and Duke Energy Progress retain the ability to earn a full WACC return during the deferral period, which is the period from when costs are incurred until they are recovered in rates.

The Settling Parties agreed that execution by Duke Energy Carolinas and Duke Energy Progress of a settlement agreement between themselves and the NCDEQ dated December 31, 2019, (the “DEQ Settlement”) and the coal ash management plans included therein or subsequently approved by DEQ are reasonable and prudent. The Settling Parties retain the right to challenge the reasonableness and prudence of actions taken by Duke Energy Carolinas and Duke Energy Progress and costs incurred to implement the scope of work agreed upon in the DEQ Settlement, after February 1, 2020, and March 1, 2020, for Duke Energy Carolinas and Duke Energy Progress, respectively. The Settling Parties further agreed to waive rights through the Term to challenge the reasonableness or prudence of Duke Energy Carolinas’ and Duke Energy Progress’ historical coal ash management practices, and to waive the right to assert any arguments that future coal ash costs, including financing costs, shall be shared between either company and customers through equitable sharing or any other rate base or return adjustment that shares the revenue requirement burden of coal ash costs not otherwise disallowed due to imprudence.

The Settling Parties agreed to a sharing arrangement for future coal ash insurance litigation proceeds between Duke Energy Carolinas and Duke Energy Progress and North Carolina customers. For more information, see Note 4 "Commitments and Contingencies."

As a result of the CCR Settlement Agreement, Duke Energy Carolinas and Duke Energy Progress recorded a pretax charge of approximately $454 million and $494 million, respectively, in the fourth quarter of 2020 to Impairment of assets and other charges and a reversal of approximately $50 million and $102 million, respectively, to Regulated electric operating revenues on the respective Consolidated Statements of Operations.

The Coal Ash Settlement was approved without modification in the NCUC Orders in the 2019 rate cases on March 31, 2021, and April 16, 2021, for Duke Energy Carolinas and Duke Energy Progress, respectively. The NCUC issued an Order on Remand Accepting CCR Settlement and Affirming Previous Orders Settling Rates and Imposing Penalties in the 2017 rate cases on June 25, 2021.

Carbon Plan

The NCUC is required by North Carolina House Bill 951 (HB 951) to adopt an initial Carbon Plan on or before December 31, 2022. The NCUC has directed Duke Energy Carolinas and Duke Energy Progress to file a proposed Carbon Plan on or before May 16, 2022. Duke Energy Carolinas and Duke Energy Progress cannot predict the outcome of this matter.

Performance-Based Regulation Rules

On February 10, 2022, the NCUC adopted rules to govern the application and review process for the Performance-Based Regulation (PBR) authorized under HB 951. The PBR rules are constructive and consistent with the policy objectives of HB 951.

2020 North Carolina Storm Securitization Filings

On October 26, 2020, Duke Energy Carolinas and Duke Energy Progress filed a joint petition with the NCUC, as agreed to in partial settlements reached in the 2019 North Carolina Rate Cases for Duke Energy Carolinas and Duke Energy Progress, seeking authorization for the financing of the costs of each utility's storm recovery activities required as a result of Hurricane Florence, Hurricane Michael, Hurricane Dorian and Winter Storm Diego. Specifically, Duke Energy Carolinas and Duke Energy Progress requested that the NCUC find that their storm recovery costs and related financing costs are appropriately financed by debt secured by storm recovery property, and that the commission issue financing orders by which each utility may accomplish such financing using a securitization structure. On January 27, 2021, Duke Energy Carolinas, Duke Energy Progress and the Public Staff filed an Agreement and Stipulation of Partial Settlement, subject to review and approval of the NCUC, resolving certain accounting issues, including agreement to support an 18- to 20-year bond period. In the NCUC Orders in the 2019 rate cases issued on March 31, 2021, and April 16, 2021, for Duke Energy Carolinas and Duke Energy Progress, respectively, the reasonableness and prudence of the deferred storm costs was approved. On May 20, 2021, the NCUC issued financing orders authorizing the companies to issue storm recovery bonds, subject to the terms of the financing orders, and approving the Agreement and Stipulation of Partial Settlement in its entirety. The storm recovery bonds were issued by Duke Energy Carolinas and Duke Energy Progress on November 24, 2021.

COVID-19 Filings

North Carolina

Duke Energy Carolinas and Duke Energy Progress filed a joint petition on August 7, 2020, with the NCUC for deferral treatment of incremental costs and the cost of waived customer fees due to the COVID-19 pandemic. On December 29, 2021, the NCUC approved Duke Energy Carolinas' and Duke Energy Progress' joint petition to defer estimated incremental pandemic-related costs, without prejudice, to the NCUC's future determination of the appropriate ratemaking treatment ultimately to be accorded such costs in future rate case proceedings.

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)	2021		2020		a Return	Period Ends
Regulatory Assets(a)
AROs – coal ash	$	1,227	$	1,414	(h)	(b)

Accrued pension and OPEB(c)	365		427		Yes	(i)
Deferred fuel and purchased power	339		42		(e)	2023
Storm cost securitized balance, net	232		—			2041


Retired generation facilities(c)	54		11		Yes	2023
PISCC(c)	31		32		Yes	(b)
Hedge costs deferrals(c)	171		174		Yes	(b)
Deferred asset – Lee COLA	296		324			(b)
AMI	140		154		Yes	(b)
Customer connect project	66		50		Yes	(b)

Vacation accrual	83		84			2022
Storm cost deferrals	22		205		Yes	(b)



COR settlement	91		95		Yes	(b)
Nuclear deferral	78		88			2023




ABSAT, coal ash basin closure	67		71		Yes	(b)
Incremental COVID-19 expenses	51		31		Yes	(b)

Deferred severance charges	36		57			2023




Other	130		210			(b)
Total regulatory assets	3,479		3,469
Less: current portion	544		473
Total noncurrent regulatory assets	$	2,935	$	2,996
Regulatory Liabilities(a)
Net regulatory liability related to income taxes(d)	$	2,785	$	2,874		(b)
Costs of removal(c)	2,009		1,975		Yes	(f)
AROs – nuclear and other	2,053		1,512			(b)
Provision for rate refunds(c)	124		170		Yes
Hedge cost deferrals	154		16			(b)
Accrued pension and OPEB(c)	44		32		Yes	(i)


Other	516		429			(b)
Total regulatory liabilities	7,685		7,008
Less: current portion	487		473
Total noncurrent regulatory liabilities	$	7,198	$	6,535

(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.

(c) Included in rate base.

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

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

(i) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 22 for additional detail.

2017 North Carolina Rate Case

On August 25, 2017, Duke Energy Carolinas filed an application with the NCUC for a rate increase for retail customers of approximately $647 million. On February 28, 2018, Duke Energy Carolinas and the Public Staff filed an Agreement and Stipulation of Partial Settlement resolving certain portions of the proceeding. Terms of the settlement included an ROE of 9.9% and a capital structure of 52% equity and 48% debt. On June 22, 2018, the NCUC issued an order approving the Stipulation of Partial Settlement and requiring a revenue reduction.

The North Carolina Attorney General and other parties separately filed Notices of Appeal to the North Carolina Supreme Court. The North Carolina Supreme Court consolidated the Duke Energy Carolinas and Duke Energy Progress appeals. On December 11, 2020, the North Carolina Supreme Court issued an opinion, which affirmed, in part, and reversed and remanded, in part, the NCUC’s decisions. In the Opinion, the court upheld the NCUC's decision to include coal ash costs in the cost of service, as well as the NCUC’s discretion to allow a return on the unamortized balance of coal ash costs. The court also remanded to the NCUC a single issue to consider the assessment of support for the Public Staff’s equitable sharing argument. On January 22, 2021, Duke Energy Carolinas and Duke Energy Progress entered into the CCR Settlement Agreement with the Settling Parties, which was filed with the NCUC on January 25, 2021, and approved by the NCUC on March 31, 2021. The NCUC issued an Order on Remand Accepting CCR Settlement and Affirming Previous Orders Setting Rates and Imposing Penalties on June 25, 2021.

2019 North Carolina Rate Case

On September 30, 2019, Duke Energy Carolinas filed an application with the NCUC for a net rate increase for retail customers of approximately $291 million, which represented an approximate 6% increase in annual base revenues. The gross rate case revenue increase request was $445 million, which was offset by an EDIT rider of $154 million to return to customers North Carolina and federal EDIT resulting from recent reductions in corporate tax rates. The request for a rate increase was driven by major capital investments subsequent to the previous base rate case, coal ash pond closure costs, accelerated coal plant depreciation and deferred 2018 storm costs. Duke Energy Carolinas requested rates be effective no later than August 1, 2020.

On March 25, 2020, Duke Energy Carolinas and the Public Staff filed an Agreement and Stipulation of Partial Settlement, subject to review and approval of the NCUC, resolving certain issues in the base rate proceeding. On July 24, 2020, Duke Energy Carolinas filed its request for approval of its notice to customers required to implement temporary rates. On July 27, 2020, Duke Energy Carolinas filed a joint motion with Duke Energy Progress and the Public Staff notifying the commission that the parties reached a joint partial settlement with the Public Staff. Also, on July 27, 2020, Duke Energy Carolinas filed a letter stating that it intended to update its temporary rates calculation to reflect the terms of the partial settlement. On July 31, 2020, Duke Energy Carolinas and the Public Staff filed a Second Agreement and Stipulation of Partial Settlement (Second Partial Settlement), subject to review and approval of the NCUC, resolving certain remaining issues in the base rate proceeding. The remaining items litigated at hearing included recovery of deferred coal ash compliance costs that are subject to asset retirement obligation accounting, implementation of new depreciation rates and the amortization period of the loss on the hydro station sale.

On August 4, 2020, Duke Energy Carolinas filed an amended motion for approval of its amended notice to customers, seeking to exercise its statutory right to implement temporary rates subject to refund on or after August 24, 2020. The revenue requirement to be recovered, subject to refund, through the temporary rates was based on and consistent with the base rate component of the Second Partial Settlement and excluded the items to be litigated noted above. The NCUC approved the August 4, 2020 amended temporary rates motion on August 6, 2020, and temporary rates went into effect on August 24, 2020.

The Duke Energy Carolinas evidentiary hearing concluded on September 18, 2020, and post-hearing filings were made with the NCUC from all parties by November 4, 2020. On January 22, 2021, Duke Energy Carolinas and Duke Energy Progress entered into the CCR Settlement Agreement with the Settling Parties, which was filed with the NCUC on January 25, 2021.

On March 31, 2021, the NCUC issued an order approving the March 25, 2020, and July 31, 2020, partial settlements. The order includes approval of 1) an ROE of 9.6% based upon a capital structure of 52% equity and 48% debt; 2) deferral treatment of approximately $800 million of grid improvement projects with a return; 3) a flow back period of five years for unprotected federal EDIT; and 4) the reasonableness and prudence of $213 million of deferred storm costs, which were removed from the rate case and for which Duke Energy Carolinas filed a petition seeking securitization in October 2020. Additionally, the order approved without modification the CCR Settlement Agreement.

The order denied Duke Energy Carolinas' proposal to shorten the remaining depreciable lives of certain Duke Energy Carolinas coal-fired generating units, indicating the NCUC has not had the chance to fully examine the issue within the context of an integrated resource planning (IRP) proceeding, and upon retirement the remaining net book value of these units should be placed in a regulatory asset account to be amortized over an appropriate period to be determined in a future rate case.

On May 21, 2021, the NCUC issued an Order Approving Rate Schedules, which resulted in a net increase of approximately $33 million. Revised customer rates became effective on June 1, 2021.

2018 South Carolina Rate Case

On November 8, 2018, Duke Energy Carolinas filed an application with the PSCSC for a rate increase for retail customers of approximately $168 million.

After hearings in March 2019, the PSCSC issued an order on May 21, 2019, which included an ROE of 9.5% and a capital structure of 53% equity and 47% debt. The order also included the following material components:

•Approval of cancellation of the Lee Nuclear Project, with Duke Energy Carolinas maintaining the combined operating license;

•Approval of recovery of $125 million (South Carolina retail portion) of Lee Nuclear Project development costs (including AFUDC through December 2017) over a 12-year period, but denial of a return on the deferred balance of costs;

•Approval of recovery of $96 million of coal ash costs over a five-year period with a return at Duke Energy Carolinas' WACC;

•Denial of recovery of $115 million of certain coal ash costs deemed to be related to the Coal Ash Act and incremental to the federal CCR rule;

•Approval of a $66 million decrease to base rates to reflect the change in ongoing tax expense, primarily the reduction in the federal income tax rate from 35% to 21%;

•Approval of a $45 million decrease through the EDIT Rider to return EDIT resulting from the federal tax rate change and deferred revenues since January 2018 related to the change, to be returned in accordance with the Average Rate Assumption Method (ARAM) for protected EDIT, over a 20-year period for unprotected EDIT associated with Property, Plant and Equipment, over a five-year period for unprotected EDIT not associated with Property, Plant and Equipment and over a five-year period for the deferred revenues; and

•Approval of a $17 million decrease through the EDIT Rider related to reductions in the North Carolina state income tax rate from 6.9% to 2.5% to be returned over a five-year period.

As a result of the order, revised customer rates were effective June 1, 2019. On May 31, 2019, Duke Energy Carolinas filed a Petition for Rehearing or Reconsideration of that order contending substantial rights of Duke Energy Carolinas were prejudiced by unlawful, arbitrary and capricious rulings by the PSCSC on certain issues presented in the proceeding. On June 19, 2019, the PSCSC issued a directive denying Duke Energy Carolinas' request to rehear or reconsider the commission's rulings on certain issues presented in the proceeding including coal ash remediation and disposal costs, ROE and the recovery of a return on deferred operation and maintenance expenses. An order detailing the commission's decision in the directive was issued on October 18, 2019. Duke Energy Carolinas filed a notice of appeal on November 15, 2019, with the Supreme Court of South Carolina. On November 20, 2019, the South Carolina Energy Users Committee filed a Notice of Appeal with the Supreme Court of South Carolina. Initial briefs were filed on April 21, 2020, which included the South Carolina Energy User's Committee brief arguing that the PSCSC erred in allowing Duke Energy Carolinas' recovery of costs related to the Lee Nuclear Station. Response briefs were filed on July 6, 2020, and reply briefs were filed on August 11, 2020. Oral arguments were heard before the Supreme Court of South Carolina on May 26, 2021.

On October 27, 2021, the Supreme Court of South Carolina affirmed the PSCSC's May 2019 order to:

•Disallow cost recovery on certain CCR compliance costs the PSCSC deemed to be incremental to the federal CCR rules;

•Disallow recovery of certain coal ash insurance litigation expenses;

•Disallow a return on certain deferred expenses; and

•Allow recovery of Lee Nuclear Project preconstruction costs.

The Supreme Court of South Carolinas' decision notes the prior determination made by the PSCSC that Duke Energy could submit coal ash costs for recovery that were not initially approved in the rate case order if such costs can be attributed to the CCR rules. As a result of the court's opinion, Duke Energy Carolinas recognized a pretax charge of approximately $160 million to Impairment of assets and other charges, and a $31 million increase in Other income and expenses, net in the Consolidated Statements of Operations for the year ended December 31, 2021, principally related to coal ash remediation at retired coal ash basin sites. On November 29, 2021, Duke Energy Carolinas filed a petition for rehearing on several grounds, including the Supreme Court of South Carolinas’ decision on coal ash cost recovery and certain deferred expenses. On February 1, 2022, the Supreme Court of South Carolina denied the petition for rehearing.

Oconee Nuclear Station Subsequent License Renewal

On June 7, 2021, Duke Energy Carolinas filed a subsequent license renewal 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 subsequent license renewal would extend operations of the facility from 60 to 80 years. The current license 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 purporting to challenge Duke Energy Carolinas’ environmental report (ER). In general, the proposed contentions claimed that the ER did not consider certain information regarding the environmental aspects of severe accidents caused by a hypothetical failure of the Jocassee Dam, and therefore did not satisfy the National Environmental Policy Act (NEPA) of 1969, as amended, or the NRC’s NEPA-implementing regulations. Duke Energy Carolinas filed its answer to the proposed contentions on October 22, 2021, and the Petitioners filed their reply to Duke Energy Carolinas’ answer on November 5, 2021. 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.

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 this matter.

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)	2021		2020		a Return	Period Ends
Regulatory Assets(a)
AROs – coal ash	$	1,389	$	1,347	(h)	(b)
AROs – nuclear and other	613		683			(c)
Accrued pension and OPEB	351		393			(k)
Deferred fuel and purchased power	303		158		(f)	2023
Storm cost securitized balance, net	759		—			2041


Retired generation facilities	171		189		Yes	(b)
PISCC and deferred operating expenses	47		51		Yes	2054
Hedge costs deferrals	60		89			(b)
Deferred asset – Harris COLA	21		32			(b)
AMI	92		57		Yes	(b)
Customer connect project	57		25		Yes	(b)
DSM/EE(e)	218		224		(i)	(i)
Vacation accrual	42		42			2022
Storm cost deferrals(d)	170		785		Yes	(b)
NCEMPA deferrals	165		124		(g)	2042


COR settlement	32		33		Yes	(b)
Nuclear deferral	42		35			2023




ABSAT, coal ash basin closure	23		27		Yes	(b)
Incremental COVID-19 expenses	28		23		Yes	(b)

Deferred severance charges	18		29			2023




Other	50		122			(b)
Total regulatory assets	4,651		4,468
Less: current portion	533		492
Total noncurrent regulatory assets	$	4,118	$	3,976
Regulatory Liabilities(a)
Net regulatory liability related to income taxes(l)	$	1,695	$	1,662		(b)
Costs of removal	2,955		2,666		Yes	(j)

Provision for rate refunds	87		123		Yes
Hedge cost deferrals	117		8			(b)



Other	395		465			(b)
Total regulatory liabilities	5,249		4,924
Less: current portion	381		530
Total noncurrent regulatory liabilities	$	4,868	$	4,394

(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.

(c) Recovery period for costs related to nuclear facilities runs through the decommissioning period of each unit.

(d) South Carolina storm costs are included in rate base.

(e) Included in rate base.

(f) 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.

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

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

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

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

(k) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 22 for additional detail.

(l) 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 23. Portions are included in rate base.

2017 North Carolina Rate Case

On June 1, 2017, Duke Energy Progress filed an application with the NCUC for a rate increase for retail customers of approximately $477 million, which was subsequently adjusted to $420 million. On November 22, 2017, Duke Energy Progress and the Public Staff filed an Agreement and Stipulation of Partial Settlement resolving certain portions of the proceeding. Terms of the settlement included an ROE of 9.9% and a capital structure of 52% equity and 48% debt. On February 23, 2018, the NCUC issued an order approving the stipulation. The Public Staff, the North Carolina Attorney General and the Sierra Club filed notices of appeal to the North Carolina Supreme Court.

The North Carolina Supreme Court consolidated the Duke Energy Carolinas and Duke Energy Progress appeals. On December 11, 2020, the North Carolina Supreme Court issued an opinion, which affirmed, in part, and reversed and remanded, in part, the NCUC’s decisions. In the Opinion, the court upheld the NCUC's decision to include coal ash costs in the cost of service, as well as the NCUC’s discretion to allow a return on the unamortized balance of coal ash costs. The court also remanded to the NCUC a single issue to consider the assessment of support for the Public Staff’s equitable sharing argument. On January 22, 2021, Duke Energy Progress and Duke Energy Carolinas entered into the CCR Settlement Agreement with the Settling Parties, which was filed with the NCUC on January 25, 2021, and approved by the NCUC on April 16, 2021. The NCUC issued an Order on Remand Accepting CCR Settlement and Affirming Previous Orders Setting Rates and Imposing Penalties on June 25, 2021.

2019 North Carolina Rate Case

On October 30, 2019, Duke Energy Progress filed an application with the NCUC for a net rate increase for retail customers of approximately $464 million, which represented an approximate 12.3% increase in annual base revenues. The gross rate case revenue increase request was $586 million, which was offset by riders of $122 million, primarily an EDIT rider of $120 million to return to customers North Carolina and federal EDIT resulting from recent reductions in corporate tax rates. The request for a rate increase was driven by major capital investments subsequent to the previous base rate case, coal ash pond closure costs, accelerated coal plant depreciation and deferred 2018 storm costs. Duke Energy Progress sought to defer and recover incremental Hurricane Dorian storm costs in this proceeding and requested rates be effective no later than September 1, 2020. As a result of the COVID-19 pandemic, on March 24, 2020, the NCUC suspended the procedural schedule and postponed the previously scheduled evidentiary hearing on this matter indefinitely.

On June 2, 2020, Duke Energy Progress and the Public Staff filed an Agreement and Stipulation of Partial Settlement, subject to review and approval of the NCUC, resolving certain issues in the base rate proceeding. On July 27, 2020, Duke Energy Progress filed a joint motion with Duke Energy Carolinas and the Public Staff notifying the commission that the parties reached a joint partial settlement with the Public Staff. On July 31, 2020, Duke Energy Progress and the Public Staff filed a Second Agreement and Stipulation of Partial Settlement, subject to review and approval of the NCUC, resolving certain remaining issues in the base rate proceeding. The remaining items litigated at hearing included recovery of deferred coal ash compliance costs that are subject to asset retirement obligation accounting and implementation of new depreciation rates.

On August 7, 2020, Duke Energy Progress filed a motion for approval of notice required to implement temporary rates, seeking to exercise its statutory right to implement temporary rates subject to refund on or after September 1, 2020. The revenue requirement to be recovered subject to refund through the temporary rates was based on and consistent with the terms of the base rate component of the settlement agreements with the Public Staff and excluded items to be litigated noted above. In addition, Duke Energy Progress also sought authorization to place a temporary decrement EDIT Rider into effect, concurrent with the temporary base rate change. The NCUC approved the August 7, 2020 temporary rates motion on August 11, 2020, and temporary rates went into effect on September 1, 2020.

On January 22, 2021, Duke Energy Progress and Duke Energy Carolinas entered into the CCR Settlement Agreement with the Settling Parties, which was filed with the NCUC on January 25, 2021.

On April 16, 2021, the NCUC issued an order approving the June 2, 2020, and July 31, 2020, partial settlements. The order includes approval of 1) an ROE of 9.6% based upon a capital structure of 52% equity and 48% debt; 2) deferral treatment of approximately $400 million of grid improvement projects with a return; 3) a flow back period of five years for unprotected federal EDIT; and 4) the reasonableness and prudence of approximately $714 million of deferred storm costs, which were removed from the rate case and for which Duke Energy Progress filed a petition seeking securitization in October 2020. Additionally, the order approved without modification the CCR Settlement Agreement.

The order denied Duke Energy Progress' proposal to shorten the remaining depreciable lives of certain Duke Energy Progress coal-fired generating units, indicating the NCUC has not had the chance to fully examine the issue within the context of an IRP proceeding, and upon retirement the remaining net book value of these units should be placed in a regulatory asset account to be amortized over an appropriate period to be determined in a future rate case.

On May 21, 2021, the NCUC issued an Order Approving Rate Schedules, which resulted in a net increase of approximately $178 million. Revised customer rates became effective on June 1, 2021.

2018 South Carolina Rate Case

On November 8, 2018, Duke Energy Progress filed an application with the PSCSC for a rate increase for retail customers of approximately $59 million.

After hearings in April 2019, the PSCSC issued an order on May 21, 2019, which included an ROE of 9.5% and a capital structure of 53% equity and 47% debt. The order also included the following material components:

•Approval of recovery of $4 million of coal ash costs over a five-year period with a return at Duke Energy Progress' WACC;

•Denial of recovery of $65 million of certain coal ash costs deemed to be related to the Coal Ash Act and incremental to the federal CCR rule;

•Approval of a $17 million decrease to base rates to reflect the change in ongoing tax expense, primarily the reduction in the federal income tax rate from 35% to 21%;

•Approval of a $12 million decrease through the EDIT Tax Savings Rider resulting from the federal tax rate change and deferred revenues since January 2018 related to the change, to be returned in accordance with ARAM for protected EDIT, over a 20-year period for unprotected EDIT associated with Property, Plant and Equipment, over a five-year period for unprotected EDIT not associated with Property, Plant and Equipment and over a three-year period for the deferred revenues; and

•Approval of a $12 million increase due to the expiration of EDIT related to reductions in the North Carolina state income tax rate from 6.9% to 2.5%.

As a result of the order, revised customer rates were effective June 1, 2019. On May 31, 2019, Duke Energy Progress filed a Petition for Rehearing or Reconsideration of that order contending substantial rights of Duke Energy Progress were prejudiced by unlawful, arbitrary and capricious rulings by the PSCSC on certain issues presented in the proceeding. On June 19, 2019, the PSCSC issued a directive denying Duke Energy Progress' request to rehear or reconsider the commission's rulings on certain issues presented in the proceeding including coal ash remediation and disposal costs, ROE and the recovery of a return on deferred operation and maintenance expenses, but allowing additional litigation-related costs. As a result of the directive allowing litigation-related costs, customer rates were revised effective July 1, 2019. An order detailing the commission's decision in the directive was issued on October 18, 2019. In November 2019, Duke Energy Progress appealed the decision to the Supreme Court of South Carolina.

On October 27, 2021, the Supreme Court of South Carolina affirmed the PSCSC's May 2019 order to:

•Disallow cost recovery on certain CCR compliance costs the PSCSC deemed to be incremental to the federal CCR rules;

•Disallow recovery of certain coal ash insurance litigation expenses; and

•Disallow a return on certain deferred expenses.

The Supreme Court of South Carolinas' decision notes the prior determination made by the PSCSC that Duke Energy could submit coal ash costs for recovery that were not initially approved in the rate case order if such costs can be attributed to the CCR rules. As a result of the court's opinion, Duke Energy Progress recognized a pretax charge of approximately $42 million to Impairment of assets and other charges, and a $6 million increase in Other income and expenses, net, in the Consolidated Statements of Operations for the year ended December 31, 2021, principally related to coal ash remediation at retired coal ash basin sites. On November 29, 2021, Duke Energy Progress filed a petition for rehearing on several grounds, including the Supreme Court of South Carolinas’ decision on coal ash cost recovery and certain deferred expenses. On February 1, 2022, the Supreme Court of South Carolina denied the petition for rehearing.

FERC Return on Equity Complaints

On October 11, 2019, North Carolina Eastern Municipal Power Agency (NCEMPA) 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 contained in the demand formula rate in the Full Requirements Power Purchase Agreement (FRPPA) between NCEMPA and Duke Energy Progress is unjust and unreasonable. On July 16, 2020, the FERC set this matter for hearing and settlement judge procedures and established a refund effective date of October 11, 2019. In its order setting the matter for settlement, the FERC allowed for the consideration of variations to the base transmission-related ROE methodology developed in its Order No. 569-A, through the introduction of “specific facts and circumstances” involving issues specific to the case. The parties reached a settlement in principle at a settlement conference on January 7, 2021, and filed a settlement package on March 10, 2021. The FERC Trial Staff filed comments in support of the settlement. On April 19, 2021, the Settlement Judge certified the settlement to the FERC as an uncontested settlement. The FERC approved the settlement on May 25, 2021, and Duke Energy Progress filed compliance documents on June 10, 2021. The FERC accepted the compliance filing on October 8, 2021.

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 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. Under FPA Section 206, the earliest refund effective date that the FERC can establish is the date of the filing of the complaint. Duke Energy Progress responded to the complaint on November 20, 2020, seeking dismissal, demonstrating that the 11% ROE is just and reasonable for the service provided. The parties filed responsive pleadings and are awaiting an order from the FERC. Duke Energy Progress cannot predict the outcome of this matter.

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)	2021		2020		a Return	Period Ends
Regulatory Assets(a)
AROs – coal ash	$	10	$	10		(b)
AROs – nuclear and other	7		2			(b)
Accrued pension and OPEB(c)	374		482		Yes	(g)
Deferred fuel and purchased power	415		4		(f)	2022

Nuclear asset securitized balance, net	937		991			2036

Retired generation facilities(c)	94		174		Yes	2044

Hedge costs deferrals(c)	77		59		Yes	2038

AMI(c)	38		45		Yes	2032
Customer connect project	67		30			2037
DSM/EE(c)	12		17		Yes	2025

Storm cost deferrals(c)	19		108		(e)	(b)






Costs of removal regulatory asset(c)	107		—		(d)	(b)

Qualifying facility contract buyouts(c)	94		107		Yes	2034








Other	37		35		(d)	(b)
Total regulatory assets	2,288		2,064
Less: current portion	497		265
Total noncurrent regulatory assets	$	1,791	$	1,799
Regulatory Liabilities(a)
Net regulatory liability related to income taxes(c)	$	699	$	749		(b)







Other	97		19		(d)	(b)
Total regulatory liabilities	796		768
Less: current portion	98		110
Total noncurrent regulatory liabilities	$	698	$	658

(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.

(c) Included in rate base.

(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 22 for additional detail.

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%. Duke Energy Florida will also be able to retain the retail portion of the DOE award of approximately $173 million for spent nuclear fuel, which is expected to be received in 2022, in order to mitigate customer rates over the term of the 2021 Settlement. In return, Duke Energy Florida will be able to recognize the $173 million into earnings from 2022 through 2024.

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.

Storm Restoration Cost Recovery

Duke Energy Florida filed a petition with the FPSC on April 30, 2019, to recover $223 million of estimated retail incremental storm restoration costs for Hurricane Michael, consistent with the provisions in the 2017 Settlement, and the FPSC approved the petition on June 11, 2019. The FPSC also approved allowing Duke Energy Florida to use the tax savings resulting from the Tax Act to recover these storm costs in lieu of implementing a storm surcharge. Approved storm costs were fully recovered by year-end 2021. On November 22, 2019, Duke Energy Florida filed a petition for approval of actual retail recoverable storm restoration costs related to Hurricane Michael in the amount of $191 million plus interest. On May 19, 2020, Duke Energy Florida filed a supplemental true up reducing the actual retail recoverable storm restoration costs related to Hurricane Michael by approximately $3 million, resulting in a total request to recover $188 million actual retail recoverable storm restoration costs, plus interest. Approximately $80 million of these costs are included in Regulatory assets within Current Assets and Other Noncurrent Assets on the Consolidated Balance Sheets as of December 31, 2020.

Duke Energy Florida filed a petition with the FPSC on December 19, 2019, to recover $169 million of estimated retail incremental storm restoration costs for Hurricane Dorian, consistent with the provisions in the 2017 Settlement and the FPSC approved the petition on February 24, 2020. The final actual amount of $145 million was filed on September 30, 2020. The 2021 Settlement resolved all matters regarding storm cost recovery relating to Hurricane Michael and Hurricane Dorian.

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 over the next three years, and this investment will be included in base rates offset by the revenue from the subscription fees. 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. LULAC's initial brief was filed on May 26, 2021, and Appellees' response briefs were filed on July 26, 2021. LULAC's reply brief was filed on September 24, 2021, and its request for oral argument was filed on September 28, 2021. The Supreme Court of Florida heard the oral argument on February 9, 2022. The FPSC approval order remains in effect pending the outcome of the appeal. 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)	2021		2020		a Return	Period Ends
Regulatory Assets(a)
AROs – coal ash	$	33	$	22	Yes	(b)

Accrued pension and OPEB	133		149			(g)
Deferred fuel and purchased power	38		—			2022




PISCC and deferred operating expenses(c)	16		16		Yes	2083
Hedge costs deferrals	5		7			(b)

AMI	24		36			(b)
Customer connect project	41		26			(b)
DSM/EE	5		1		(f)	(e)
Vacation accrual	6		6			2022
Storm cost deferrals	2		4			2023

CEP deferral	161		117		Yes	(b)



Deferred pipeline integrity costs	24		21		Yes	(b)

MGP	104		104			(b)









Other	115		140			(b)
Total regulatory assets	707		649
Less: current portion	72		39
Total noncurrent regulatory assets	$	635	$	610
Regulatory Liabilities(a)
Net regulatory liability related to income taxes	$	602	$	628		(b)
Costs of removal	39		68			(d)

Provision for rate refunds	61		45			(b)

Accrued pension and OPEB	21		17			(g)


Other	78		55			(b)
Total regulatory liabilities	801		813
Less: current portion	62		65
Total noncurrent regulatory liabilities	$	739	$	748

(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.

(c) Included in rate base.

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

(e) Recovered via a rider mechanism.

(f) Includes incentives on DSM/EE investments.

(g) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 22 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 (DCI) Rider. Duke Energy Ohio anticipates the PUCO will rule on the request by the summer of 2022. Duke Energy Ohio cannot predict the outcome of this matter.

Ohio House Bill 6 and House Bill 128

On July 23, 2019, House Bill 6 was signed into law and became effective January 1, 2020. Among other things, the bill allowed for funding through a rider mechanism referred to as the Clean Air Fund (CAF) Rider, of two nuclear generating facilities located in Northern Ohio owned by Energy Harbor (f/k/a FirstEnergy Solutions) and certain renewable resources, repeal of energy efficiency mandates and recovery of prudently incurred costs, net of any revenues, for Ohio investor-owned utilities that are participants under the OVEC power agreement. The OVEC recovery is through a non-bypassable rider that replaced any existing recovery mechanism approved by the PUCO and will remain in place through 2030. As such, Duke Energy Ohio created the Legacy Generation Rider that replaced the Price Stabilization Rider effective January 1, 2020. The amounts recoverable from customers are subject to an annual cap, with incremental costs that exceed such cap eligible for deferral and recovery, subject to review. See Note 17 for additional discussion of Duke Energy Ohio's ownership interest in OVEC. House Bill 128 (HB 128) was signed into law on March 31, 2021, and became effective June 30, 2021. The bill removes nuclear plant funding included in HB 6, eliminates the CAF Rider and establishes the Solar Generation Fund Rider to recover the renewable investments originally included in HB 6. HB 128 does not impact OVEC cost recovery or any transmission or distribution rider.

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. The 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 issued an entry for each utility to file by July 15, 2021, a proposal to reestablish low-income programs through December 31, 2021. Duke Energy Oho filed its application on July 14, 2021.

Duke Energy Ohio cannot predict the outcome of this matter.

Natural Gas Pipeline Extension

Duke Energy Ohio is installing 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. Duke Energy Ohio currently estimates the pipeline development costs and construction activities will range from $185 million to $195 million in direct costs (excluding overheads and AFUDC) and that construction of the pipeline extension will be completed in February 2022. An evidentiary hearing on Duke Energy Ohio's application for a Certificate of Environmental Compatibility and Public Need concluded on April 11, 2019. On November 21, 2019, the Ohio Power Siting Board (OPSB) approved Duke Energy Ohio's application subject to 41 conditions on construction. Applications for rehearing were filed by several stakeholders on December 23, 2019, arguing that the OPSB approval was incorrect. On February 20, 2020, the OPSB denied the rehearing requests. On April 15, 2020, those stakeholders filed a notice of appeal at the Supreme Court of Ohio of the OPSB’s decision approving Duke Energy Ohio’s Central Corridor Project application. The Supreme Court of Ohio affirmed the OPSB order on September 22, 2021.

On September 22, 2020, Duke Energy Ohio filed an application with the OPSB for approval to amend the certificated pipeline route due to changes in the route negotiated with property owners and municipalities. On January 21, 2021, the OPSB approved the amended filing with recommended conditions that reaffirm previous conditions and provide guidance regarding local permitting and construction supervision.

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 has collected approximately $55 million in environmental remediation costs incurred between 2008 through 2012 through Rider MGP, which is currently suspended. Duke Energy Ohio has 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. To date, the PUCO has not ruled on Duke Energy Ohio’s annual applications for the calendar years 2013 through 2019. On September 28, 2018, the Staff of the PUCO (Staff) issued a report recommending a disallowance of approximately $12 million of the $26 million in MGP remediation costs incurred between 2013 through 2017 that the Staff believes are not eligible for recovery. The Staff interprets the PUCO’s 2013 order granting Duke Energy Ohio recovery of MGP remediation as limiting the recovery to work directly on the East End and West End sites. On October 30, 2018, Duke Energy Ohio filed reply comments objecting to the Staff’s recommendations and explaining, among other things, the obligation Duke Energy Ohio has under Ohio law to remediate all areas impacted by the former MGPs and not just physical property that housed the former plants and equipment. On March 29, 2019, Duke Energy Ohio filed its annual application to recover incremental remediation expense for the calendar year 2018 seeking recovery of approximately $20 million in remediation costs. On July 12, 2019, the Staff recommended a disallowance of approximately $11 million for work that the Staff believes occurred in areas not authorized for recovery. Additionally, the Staff recommended that any discussion pertaining to Duke Energy Ohio's recovery of ongoing MGP costs should be directly tied to or netted against insurance proceeds collected by Duke Energy Ohio. An evidentiary hearing concluded on November 21, 2019. Initial briefs were filed on January 17, 2020, and reply briefs were filed on February 14, 2020.

On March 31, 2020, Duke Energy Ohio filed its annual application to recover incremental MGP remediation expense seeking recovery of approximately $39 million in remediation costs incurred during 2019. On July 23, 2020, the Staff recommended a disallowance of approximately $4 million for work the Staff believes occurred in areas not authorized for recovery. Additionally, the Staff recommended insurance proceeds, net of litigation costs and attorney fees, should be paid to customers and not be held by Duke Energy Ohio until all investigation and remediation is complete. Duke Energy Ohio filed comments in response to the Staff's report on August 21, 2020, and intervenor comments were filed on November 9, 2020.

The 2013 PUCO order also contained conditional deadlines for completing the MGP environmental remediation and the deferral of related remediation costs. Subsequent to the order, the deadline was extended to December 31, 2019. On May 10, 2019, Duke Energy Ohio filed an application requesting a continuation of its existing deferral authority for MGP remediation that must occur after December 31, 2019. On July 12, 2019, the Staff recommended the commission deny the deferral authority request. On September 13, 2019, intervenor comments were filed opposing Duke Energy Ohio's request for continuation of existing deferral authority and on October 2, 2019, Duke Energy Ohio filed reply comments.

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 is subject to review and approval by the PUCO. If approved, the Stipulation and Recommendation would, among other things, resolve 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 as it relates to Duke Energy Ohio’s natural gas operations. These impacts are not expected to have a material impact on Duke Energy Ohio's financial statements. The Stipulation and Recommendation further acknowledges 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 October 15, 2021, the PUCO granted motions to intervene filed in September 2021 by Interstate Gas Supply, Inc. and Retail Energy Supply Association on a limited basis. An evidentiary hearing was held on November 18, 2021, and briefing was concluded on December 23, 2021. 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. Duke Energy Ohio requested commission approval to implement the tariff changes and rider effective April 1, 2019. The new rider will 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 will be refunded consistent with federal law and deferred income taxes not subject to normalization rules will be refunded over a 10-year period. The PUCO established a procedural schedule and testimony was filed on July 31, 2019. An evidentiary hearing occurred on August 7, 2019. Initial briefs were filed on September 11, 2019. Reply briefs were filed on September 25, 2019. The Stipulation and Recommendation filed on August 31, 2021, disclosed in the MGP Cost Recovery matter above, also resolves the outstanding issues in this proceeding. On October 15, 2021, the PUCO granted motions to intervene filed in September 2021 by Interstate Gas Supply, Inc. and Retail Energy Supply Association on a limited basis. An evidentiary hearing was held on November 18, 2021, and briefing was concluded on December 23, 2021. Duke Energy Ohio cannot predict the outcome of this matter.

Duke Energy Kentucky Natural Gas Base Rate Case

On June 1, 2021, Duke Energy Kentucky filed an application with the KPSC requesting an increase in natural gas base rates of approximately $15 million, an approximate 13% average increase across all customer classes. The drivers for this case are capital invested since Duke Energy Kentucky's last natural gas base rate case in 2018. Duke Energy Kentucky also sought implementation of a rider in order to recover from or pay to customers the financial impact of governmental directives and mandates, including changes in federal or state tax rates and regulations issued by the Pipeline and Hazardous Materials Safety Administration (PHMSA). On October 8, 2021, Duke Energy Kentucky filed a Stipulation and Recommendation jointly with the Kentucky Attorney General, subject to review and approval by the KPSC, which if approved, would resolve the case. The Stipulation and Recommendation included a $9 million increase in base revenues, an ROE of 9.375% for natural gas base rates and 9.3% for natural gas riders, a rider for PHMSA-required capital investments with an annual 5% rate increase cap and a four-year natural gas base rate case stay out. The evidentiary hearing was held on October 18, 2021. On December 28, 2021, the KPSC approved the Stipulation and Recommendation with minor modifications, authorizing a $9 million increase. Rates were effective January 4, 2022.

Midwest Propane Caverns

Duke Energy Ohio uses propane stored in caverns to meet peak demand during winter. Once the Central Corridor Project is complete, the propane peaking facilities will no longer be necessary and will be 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 but not for the net book value of the remaining 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 in the fourth quarter of 2021. There is approximately $6 million and $27 million in Net, property, plant and equipment on the Consolidated Balance Sheets as of December 31, 2021, and December 31, 2020, respectively, related to the propane caverns. The PUCO established a procedural schedule for the submission of comments by March 7, 2022. Duke Energy Ohio cannot predict the outcome of this matter.

Regional Transmission Organization Realignment

Duke Energy Ohio, including Duke Energy Kentucky, transferred control of its transmission assets from MISO to PJM, effective December 31, 2011. The PUCO approved a settlement related to Duke Energy Ohio’s recovery of certain costs of the RTO realignment via a non-bypassable rider. Duke Energy Ohio is allowed to recover all MISO Transmission Expansion Planning (MTEP) costs directly or indirectly charged to Ohio customers. The KPSC also approved a request to effect the RTO realignment, subject to a commitment not to seek double recovery in a future rate case of the transmission expansion fees that may be charged by MISO and PJM in the same period or overlapping periods.

The following table provides a reconciliation of the beginning and ending balance of Duke Energy Ohio’s recorded liability for its exit obligation and share of MTEP costs recorded in Other within Current Liabilities and Other Noncurrent Liabilities on the Consolidated Balance Sheets. The retail portions of MTEP costs billed by MISO are recovered by Duke Energy Ohio through a non-bypassable rider. As of December 31, 2021, and 2020, $33 million and $37 million, respectively, are recorded in Regulatory assets on Duke Energy Ohio's Consolidated Balance Sheets.


			Provisions/		Cash
(in millions)	December 31, 2020		Adjustments		Reductions		December 31, 2021
Duke Energy Ohio	$	50	$	—	$	(4)	$	46

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)	2021		2020		a Return	Period Ends
Regulatory Assets(a)
AROs – coal ash	$	749	$	615	Yes	(b)

Accrued pension and OPEB	222		245			(e)
Deferred fuel and purchased power	158		9			2022



Retired generation facilities(c)	38		43		Yes	2030
PISCC and deferred operating expenses(c)	262		298		Yes	(b)
Hedge costs deferrals	35		22			(b)

AMI	17		19			2031
Customer connect project	11		5			(b)

Vacation accrual	13		12			2022


















Other	50		60			(b)
Total regulatory assets	1,555		1,328
Less: current portion	277		125
Total noncurrent regulatory assets	$	1,278	$	1,203
Regulatory Liabilities(a)
Net regulatory liability related to income taxes	$	908	$	956		(b)
Costs of removal	575		599			(d)



Accrued pension and OPEB	113		100			(e)


Other	96		83			(b)
Total regulatory liabilities	1,692		1,738
Less: current portion	127		111
Total noncurrent regulatory liabilities	$	1,565	$	1,627

(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.

(c) Included in rate base.

(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 22 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. Hearings concluded on February 7, 2020. 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% is 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 are estimated to be the remaining 25% of the total rate increase. Step two rates were approved on July 28, 2021, and implemented in August 2021. Step two rates are based on a return on equity of 9.7% and actual December 31, 2020 capital structure with a 54% equity component. Step two rates will be reconciled to January 1, 2021. Several groups appealed the IURC order to the Indiana Court of Appeals. Appellate briefs were filed on October 14, 2020, focusing on three issues: wholesale sales allocations, coal ash basin cost recovery and the Edwardsport IGCC operating and maintenance expense level approved. The appeal was fully briefed in January 2021, and an oral argument was held on April 8, 2021. The Indiana Court of Appeals affirmed the IURC decision on May 13, 2021. The Indiana Office of Utility Consumer Counselor (OUCC) and the Duke Industrial Group filed a joint petition to transfer the rate case appeal to the Indiana Supreme Court on June 28, 2021. Response briefs were filed July 19, 2021. The Indiana Supreme Court granted the petition to transfer on September 16, 2021, and oral arguments were heard on November 16, 2021. 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 approved coal ash basin closure costs expended through 2018 including financing costs as a regulatory asset and included in rate base. 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 filed a notice of appeal to the Indiana Court of Appeals on December 3, 2021. 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)	2021		2020		a Return	Period Ends
Regulatory Assets(a)

AROs – nuclear and other	$	22	$	20		(d)
Accrued pension and OPEB(c)	82		88			(g)











Vacation accrual	12		12			2022



Derivatives – natural gas supply contracts(f)	139		122


Deferred pipeline integrity costs(c)	84		71			2025





Amounts due from customers	85		110		(e)	(b)





Other	33		32			(b)
Total regulatory assets	457		455
Less: current portion	141		153
Total noncurrent regulatory assets	$	316	$	302
Regulatory Liabilities(a)
Net regulatory liability related to income taxes	$	510	$	499		(b)
Costs of removal(c)	572		575			(d)

Provision for rate refunds	2		6

Accrued pension and OPEB(c)	5		3			(g)


Other	25		49		(e)	(b)
Total regulatory liabilities	1,114		1,132
Less: current portion	56		88
Total noncurrent regulatory liabilities	$	1,058	$	1,044

(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.

(c) Included in rate base.

(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 22 for additional detail.

2020 Tennessee Rate Case

On July 2, 2020, Piedmont filed an application with the TPUC, its first general rate case in Tennessee in nine years, for a rate increase for retail customers of approximately $30 million, which represents an approximate 15% increase in annual revenues. The rate increase is driven by significant infrastructure upgrade investments since Piedmont's previous rate case. Approximately half of the plant additions being added to rate base are categories of capital investment not covered under the IMR mechanism, which was approved in 2013. Piedmont amended its requested increase to approximately $26 million in December 2020. As authorized under Tennessee law, Piedmont implemented interim rates on January 2, 2021, at the level requested in its adjusted request. A settlement reached with the Tennessee Consumer Advocate in mid-January was approved by the TPUC on February 16, 2021. The settlement results in an increase of revenues of approximately $16 million and an ROE of 9.8%. Revised customer rates became effective on January 2, 2021. Piedmont refunded customers the difference between bills previously rendered under interim rates and such bills if rendered under approved rates, plus interest in April 2021.

2021 North Carolina Rate Case

On March 22, 2021, Piedmont filed an application with the NCUC for a rate increase for retail customers of approximately $109 million, which represents an approximate 10% increase in retail revenues. The rate increase is driven by customer growth and significant infrastructure upgrade investments (plant additions) since the last general rate case. Approximately 70% of the plant additions being rolled into rate base are categories of plant investment not covered under the IMR mechanism, which was originally approved as part of the 2013 North Carolina Rate Case. On July 28, 2021, Piedmont amended its requested increase to approximately $97 million.

On September 7, 2021, Piedmont and the Public Staff, the Carolina Utility Customers Association, Inc. and the Carolina Industrial Group for Fair Utility Rates IV filed a Stipulation of Partial Settlement (Stipulation), which is subject to review and approval by the NCUC, resolving most issues between these parties. Major components of the Stipulation include:

•A return on equity of 9.6% and a capital structure of 51.6% equity and 48.4% debt;

•Continuation of the IMR mechanism and margin decoupling; and

•A base rate increase of approximately $67 million, subject to completion of the Robeson County LNG facility and the Pender Onslow County expansion project.

An evidentiary hearing to review the Stipulation and other issues concluded on September 9, 2021. On October 12, 2021, Piedmont notified the NCUC of its intent to implement the stipulated rates effective November 1, 2021, on a temporary basis and subject to refund. On October 18, 2021, Piedmont and the Public Staff filed supplemental testimony attesting to the completion of the Robeson County LNG facility and the Pender Onslow County expansion project and to the propriety of including the capital investment for these two projects in this proceeding. On January 6, 2022, the NCUC issued an order approving the Stipulation. No refunds need to be rendered to customers arising from Piedmont's implementation of interim rates.

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 in June 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, 2021, there is $47 million and $53 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 $100 million to satisfy remaining ARO requirements to restore construction sites.

See Notes 7 and 12 for additional information regarding this transaction.

Potential Coal Plant Retirements

The Subsidiary Registrants periodically file integrated resource plans (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. 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 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, 2021, 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	$	12
Allen Steam Station Unit 5(b)	259	277
Cliffside Unit 5(b)	546	365
Duke Energy Progress
Mayo Unit 1(b)	713	631
Roxboro Units 3-4(b)	1,409	457
Duke Energy Florida
Crystal River Units 4-5(c)	1,442	1,650
Duke Energy Indiana(d)
Gibson Units 1-5(e)	2,845	1,829
Cayuga Units 1-2(e)	1,005	696
Total Duke Energy	8,386	$	5,917

(a) As part of the 2015 resolution of a lawsuit involving alleged New Source Review violations, Duke Energy Carolinas must retire Allen Steam Station Units 1 through 3 by December 31, 2024. The long-term energy options considered in the IRP could result in retirement of these units earlier than their current estimated useful lives. Unit 3 with a capacity of 270 MW and a net book value of $26 million at December 31, 2020, was retired in March 2021, and unit 2 with a capacity of 167 MW and a net book value of $44 million at December 31, 2020, was retired in December 2021.

(b) These units were included in the IRP filed by Duke Energy Carolinas and Duke Energy Progress in North Carolina and South Carolina on September 1, 2020. The long-term energy options considered in the IRP could result in retirement of these units earlier than their current estimated useful lives. In 2019, Duke Energy Carolinas and Duke Energy Progress filed North Carolina rate cases that included depreciation studies that accelerate end-of-life dates for these plants. The NCUC issued orders in the 2019 rate cases of Duke Energy Carolinas and Duke Energy Progress on March 31, 2021, and April 16, 2021, respectively, in which the proposals to shorten the remaining depreciable lives of these units were denied, while indicating the IRP proceeding was the appropriate proceeding for the review of generating plant retirements. Allen Unit 4 with a capacity of 267 MW and a net book value of $170 million at December 31, 2020, was retired in December 2021.

(c) On January 14, 2021, Duke Energy Florida filed the 2021 Settlement 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.

(d) Gallagher Units 2 and 4 with a total capacity of 280 MW and a total net book value of $102 million at December 31, 2020, were retired on June 1, 2021.

(e) 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.

4. 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 3, 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 $13.5 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 in compliance with the law.

Excess Liability Program

This program provides $13.1 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 95 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, $434 million for McGuire, $364 million for Harris, $336 million for Brunswick, $322 million for Oconee and $280 million for 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 $140 million, $88 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 laws regarding air and water quality, hazardous and solid waste disposal, coal ash and other environmental matters. These laws 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 the ARO recorded as a result of various environmental regulations, discussed in Note 9, 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 tables contain 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, 2021		December 31, 2020
Reserves for Environmental Remediation
Duke Energy	$	88	$	75
Duke Energy Carolinas	19		19
Progress Energy	23		19
Duke Energy Progress	11		6
Duke Energy Florida	11		12
Duke Energy Ohio	34		22
Duke Energy Indiana	4		6
Piedmont	9		10

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. Duke Energy will be filing its answer to the amended complaint, following which discovery will commence. Duke Energy cannot predict the outcome of this matter.

Texas Storm Uri Tort Litigation

Several Duke Energy renewables project companies, located in the Electric Reliability Council of Texas (ERCOT) market, were named in lawsuits arising out of Texas Storm Uri in mid-February 2021. Several additional suits, where Duke Energy Corporation had been named, were dismissed The current lawsuits seek recovery for property damages, personal injury and for wrongful death allegedly caused by the power outages, which the plaintiffs claim was the result of collective failures of generators, transmission and distribution operators, retail energy providers and others including ERCOT. The cases have been consolidated into a Texas state court multidistrict litigation (MDL) proceeding for discovery purposes. With the exception of a few bellwether cases which are still being decided, all the lawsuits in the MDL will be stayed until motions to dismiss are filed and considered by the court in mid-2022. The bellwether cases will include those in which the Duke Energy entities are named. Duke Energy cannot predict the outcomes of these matters.

Duke Energy Carolinas and Duke Energy Progress

Coal Ash Insurance Coverage Litigation

In March 2017, Duke Energy Carolinas and Duke Energy Progress filed a civil action in the North Carolina Business Court against various insurance providers. The lawsuit sought payment for coal ash related liabilities covered by third-party liability insurance policies. The insurance policies were issued between 1971 and 1986 and provide third-party liability insurance for property damage. The civil action sought damages for breach of contract and indemnification for costs arising from the Coal Ash Act and the EPA CCR rule at 15 coal-fired plants in North Carolina and South Carolina.

Duke Energy Carolinas and Duke Energy Progress have now resolved claims against all of the insurers sued in this litigation and have dismissed their claims against all of the insurers. Duke Energy Carolinas and Duke Energy Progress have received approximately $418 million of coal ash insurance litigation proceeds from settlements with insurer-defendants and the proceeds will be distributed in accordance with the terms of the CCR settlement agreement.

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, except for one minor. 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. On September 30, 2021, Duke Energy Carolinas filed its motion to dismiss and motion for transfer of venue from Durham County to Rockingham County, both of which were denied on November 15, 2021. On November 15, 2021, Duke Energy Carolinas was also served with Plaintiffs Second Amended Complaint, which added the final minor plaintiff and consolidated all the actions into one lawsuit. Duke Energy Carolinas has filed its Answer and Affirmative Defenses to the Second Amended Complaint. Discovery has now commenced. 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 is seeking 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.

On May 21, 2020, in response to a NTE petition challenging Duke Energy Carolinas' termination of the LGIA, FERC issued a ruling that 1) FERC 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 and cannot predict the outcome of this investigation.

On August 17, 2020, the court denied both NTE’s and Duke Energy Carolinas’ motions to dismiss. In October 2021, NTE filed a Second Amended Counterclaim and Complaint, and in January 2022, NTE filed a Third Amended Counterclaim and Complaint. Duke Energy Carolinas has responded to these pleadings. On December 6, 2021, Duke Energy Carolinas filed an Amended Complaint. Discovery is scheduled to end by April 2022, after which the parties will file dispositive motions for the court's consideration. The case is scheduled to be trial ready by August 1, 2022. 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 $501 million and $572 million at December 31, 2021, and 2020, 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 2041 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 2041 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 $644 million and $704 million at December 31, 2021, and 2020, 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.

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 reserve for credit losses for insurance receivables for the asbestos-related injuries and damages based on adoption of the new standard is $12 million and $15 million for Duke Energy and Duke Energy Carolinas as of December 31, 2021, and December 31, 2020, respectively. 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 Department of Energy 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. The Department of Energy filed a motion for partial summary judgment relating to approximately $60 million of Duke Energy Florida’s claimed damages. A hearing on the motion was held on February 9, 2022. Trial is scheduled for April 2022. Duke Energy Progress and Duke Energy Florida cannot predict the outcome of this matter.

Duke Energy Florida

Power Purchase Dispute Arbitration

Duke Energy Florida, on behalf of its customers, entered into a PPA for the purchase of firm capacity and energy from a qualifying facility under the Public Utilities Regulatory Policies Act of 1978. Duke Energy Florida determined the qualifying facility did not perform in accordance with the PPA, and Duke Energy Florida terminated the PPA. The qualifying facility counterparty filed a confidential American Arbitration Association (AAA) arbitration demand, challenging the termination of the PPA and seeking damages.

The final arbitration hearing occurred during the week of December 7, 2020. An interim arbitral award was issued in March 2021, upholding Duke Energy Florida's positions on all issues and awarding the company termination costs. In May 2021, the final arbitral award was issued awarding Duke Energy Florida its claimed fees and costs. On August 18, 2021, Duke Energy Florida filed a motion in Florida state court to confirm the arbitral award. On December 13, 2021, the court entered a final judgment confirming the arbitration award.

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 Gallagher. 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. On June 25, 2021, Duke Energy Indiana filed its response to the Petition to Review. On August 30, 2021, HEC served Duke Energy Indiana with its Brief in Support of Petition for Judicial Review. On October 29, 2021, Duke Energy Indiana and IDEM filed their response briefs. On December 13, 2021, HEC filed and served its Reply Brief.

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 evaluating the EPA letter, its potential impacts on the litigation and the extent to which this letter could apply to CCR surface impoundments at its other Indiana sites.

Following the January 11, 2022 EPA notice of compliance letter, the parties filed a joint motion to stay the litigation for 45 days, which was approved by the court. As a result, the oral argument scheduled for February 1, 2022, was postponed until the end of the 45-day stay. 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. See Note 7 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, 2021
	Contract
(in millions)	Expiration	2022		2023		2024		2025		2026		Thereafter		Total
Duke Energy Progress(a)	2028-2032	$	22	$	22	$	21	$	22	$	18	$	45	$	150
Duke Energy Florida(b)	2023-2025	354		374		262		91		—		—		1,081
Duke Energy Ohio(c)(d)	2023	53		34		—		—		—		—		87

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

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

(c) Contracts represent 15% of net plant output.

(d) Excludes PPA with OVEC. See Note 17 for additional information.

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 14 years. The time periods for fixed payments under natural gas supply contracts are up to five years. The time period for the natural gas supply purchase commitments is up to 10 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, 2021.


(in millions)	2022		2023		2024		2025		2026		Thereafter		Total
Duke Energy Ohio	$	62	$	37	$	25	$	16	$	13	$	47	$	200
Piedmont	324		272		225		134		122		503		1,580

5. 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.

Duke Energy operates various renewable energy projects and sells the generated output to utilities, electric cooperatives, municipalities and commercial and industrial customers through long-term PPAs. In certain situations, these PPAs and the associated renewable energy projects qualify as operating leases. Rental income from these leases is accounted for as Nonregulated electric and other revenues in the Consolidated Statements of Operations. There are no minimum lease payments as all payments are contingent based on actual electricity generated by the renewable energy projects. Contingent lease payments were $259 million, $275 million and $264 million for the years ended December 31, 2021, 2020, and 2019, respectively. Renewable energy projects owned by Duke Energy and accounted for as operating leases had a cost basis of $3,339 million and $3,335 million and accumulated depreciation of $966 million and $848 million at December 31, 2021, and 2020, respectively. These assets are principally classified as nonregulated electric generation and transmission assets.

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, 2021, and 2020, and a long-term net investment basis of $203 million and $205 million as of December 31, 2021, and 2020, 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, 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)	$	250	$	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	$	570	$	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.

(c) Included in Interest Expense on the Consolidated Statements of Operations.


	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
Operating lease expense(a)	$283		$53		$162		$72		$90		$11		$19		$7
Short-term lease expense(a)	4		—		2		1		1		—		1		—
Variable lease expense(a)	30		13		13		5		8		—		1		1
Finance lease expense
Amortization of leased assets(b)	119		8		24		6		18		—		1		—
Interest on lease liabilities(c)	61		30		44		37		7		—		—		—
Total finance lease expense	180		38		68		43		25		—		1		—
Total lease expense	$	497	$	104	$	245	$	121	$	124	$	11	$	22	$	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.

(c) Included in Interest Expense 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, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
2022	$	225	$	24	$	118	$	63	$	55	$	2	$	6	$	5
2023	212		21		118		64		54		2		6		5
2024	185		14		110		56		54		2		4		5
2025	156		10		96		42		54		2		4		5
2026	136		10		92		38		54		2		4		—
Thereafter	594		42		290		220		70		16		50		—
Total operating lease payments	1,508		121		824		483		341		26		74		20
Less: present value discount	(247)		(21)		(124)		(83)		(41)		(7)		(20)		(1)
Total operating lease liabilities(a)	$	1,261	$	100	$	700	$	400	$	300	$	19	$	54	$	19

(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, 2021
			Duke				Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Indiana
2022	$	201	$	38	$	111	$	86	$	25	$	1
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
Thereafter	658		464		637		636		1		24
Total finance lease payments	1,353		654		1,110		1,040		70		29
Less: amounts representing interest	(438)		(365)		(420)		(411)		(9)		(19)
Total finance lease liabilities	$	915	$	289	$	690	$	629	$	61	$	10

The following tables contain additional information related to leases.


		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	$	1,266	$	92	$	691	$	389	$	302	$	19	$	53	$	16
Finance	Net property, plant and equipment	950		302		729		627		102		—		7		—
Total lease assets		$	2,216	$	394	$	1,420	$	1,016	$	404	$	19	$	60	$	16
Liabilities
Current
Operating	Other current liabilities	$	187	$	22	$	94	$	50	$	44	$	1	$	4	$	5
Finance	Current maturities of long-term debt	151		6		61		41		20		—		—		—
Noncurrent
Operating	Operating lease liabilities	1,074		78		606		350		256		18		50		14
Finance	Long-Term Debt	764		283		629		588		41		—		10		—
Total lease liabilities		$	2,176	$	389	$	1,390	$	1,029	$	361	$	19	$	64	$	19


		December 31, 2020
				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	$	1,524	$	110	$	690	$	346	$	344	$	20	$	55	$	20
Finance	Net property, plant and equipment	797		312		416		297		119		—		7		—
Total lease assets		$	2,321	$	422	$	1,106	$	643	$	463	$	20	$	62	$	20
Liabilities
Current
Operating	Other current liabilities	$	177	$	20	$	73	$	31	$	42	$	1	$	3	$	4
Finance	Current maturities of long-term debt	129		5		26		7		19		—		—		—
Noncurrent
Operating	Operating lease liabilities	1,340		97		623		323		300		20		53		19
Finance	Long-Term Debt	716		289		351		289		62		—		10		—
Total lease liabilities		$	2,362	$	411	$	1,073	$	650	$	423	$	21	$	66	$	23


	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 for the year ended December 31, 2021.

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


	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
Cash paid for amounts included in the measurement of lease liabilities(a)
Operating cash flows from operating leases	$	271	$	31	$	124	$	52	$	72	$	2	$	6	$	5
Operating cash flows from finance leases	61		30		44		37		7		—		—		—
Financing cash flows from finance leases	119		8		24		6		18		—		1		—


Lease assets obtained in exchange for new lease liabilities (non-cash)
Operating(b)	$	116	$	17	$	—	$	—	$	—	$	—	$	1	$	—
Finance	125		125		—		—		—		—		—		—

(a) No amounts were classified as investing cash flows from operating leases for the year ended December 31, 2020.

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


	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	9		9		8		10		7		16		16		4
Finance leases	10		18		13		13		11		—		24		—
Weighted average discount rate(a)
Operating leases	3.6	%	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.


	December 31, 2020
			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	10		9		10		12		8		17		18		5
Finance leases	13		19		15		17		11		—		25		—
Weighted average discount rate(a)
Operating leases	3.8	%	3.4	%	3.8	%	3.9	%	3.8	%	4.2	%	4.2	%	3.6	%
Finance leases	8.4	%	11.6	%	11.9	%	12.4	%	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.

6. DEBT AND CREDIT FACILITIES

Summary of Debt and Related Terms

The following tables summarize outstanding debt.


	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 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 $1,121 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 17 for additional information on amounts from consolidated VIEs.


	December 31, 2020
	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 2021-2078	3.71	%	$	23,669	$	1,150	$	3,150	$	700	$	350	$	1,180	$	403	$	2,800
Secured debt, maturing 2021-2052	2.67	%	4,270		543		1,584		252		1,332		—		—		—
First mortgage bonds, maturing 2021-2050(a)	4.00	%	29,177		10,008		14,100		7,875		6,225		1,850		3,219		—
Finance leases, maturing 2022-2051(b)	6.96	%	845		294		377		296		81		—		10		—

Tax-exempt bonds, maturing 2027-2041(c)	0.75	%	477		—		48		48		—		77		352		—
Notes payable and commercial paper(d)	0.51	%	3,407		—		—		—		—		—		—		—
Money pool/intercompany borrowings			—		806		3,119		445		196		194		281		530
Fair value hedge carrying value adjustment			4		4		—		—		—		—		—		—
Unamortized debt discount and premium, net(e)			1,217		(20)		(31)		(19)		(11)		(29)		(18)		(5)
Unamortized debt issuance costs(f)			(330)		(62)		(113)		(44)		(62)		(14)		(25)		(15)
Total debt	3.62	%	$	62,736	$	12,723	$	22,234	$	9,553	$	8,111	$	3,258	$	4,222	$	3,310
Short-term notes payable and commercial paper			(2,873)		—		—		—		—		—		—		—
Short-term money pool/intercompany borrowings			—		(506)		(2,969)		(295)		(196)		(169)		(131)		(530)
Current maturities of long-term debt(g)			(4,238)		(506)		(1,426)		(603)		(823)		(50)		(70)		(160)
Total long-term debt(g)			$	55,625	$	11,711	$	17,839	$	8,655	$	7,092	$	3,039	$	4,021	$	2,620

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

(b) Duke Energy includes $24 million and $341 million of finance lease purchase accounting adjustments related to Duke Energy Progress and Duke Energy Florida, respectively, 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 23 days.

(e) Duke Energy includes $1,196 million and $117 million in purchase accounting adjustments related to Progress Energy and Piedmont, respectively.

(f) Duke Energy includes $33 million in purchase accounting adjustments primarily related to the merger with Progress Energy.

(g) Refer to Note 17 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, 2021
Unsecured Debt(a)
Duke Energy (Parent)	March 2022	3.227	%	300
Duke Energy (Parent)(b)	March 2022	0.851	%	300
Progress Energy	April 2022	3.150	%	450
Duke Energy (Parent)	August 2022	3.050	%	500
Duke Energy (Parent)	August 2022	2.400	%	500



First Mortgage Bonds
Duke Energy Indiana	January 2022	8.850	%	53
Duke Energy Carolinas	May 2022	3.350	%	350
Duke Energy Progress	May 2022	2.800	%	500
Other(c)				434
Current maturities of long-term debt				$	3,387

(a) In December 2021, Duke Energy Progress early retired $700 million of unsecured debt with an original maturity date of February 2022.

(b) Debt has a floating interest rate.

(c) Includes finance lease obligations, amortizing debt 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, 2021
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy(a)		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
2022	$	3,387	$	362	$	1,082	$	556	$	76	$	—	$	84	$	—
2023	4,725		1,018		1,046		719		327		475		303		45
2024	1,917		19		138		72		66		—		4		40
2025	3,078		496		639		575		64		245		4		205
2026	3,125		921		310		229		81		70		154		40
Thereafter	46,844		10,528		17,766		8,168		7,949		2,442		3,814		2,660
Total long-term debt, including current maturities	$	63,076	$	13,344	$	20,981	$	10,319	$	8,563	$	3,232	$	4,363	$	2,990

(a) Excludes $1,250 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, 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


	December 31, 2020
			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

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


				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 will be used to finance or refinance, in whole or in part, existing or new eligible projects under the sustainable financing framework.


				Year Ended December 31, 2020
						Duke		Duke		Duke		Duke		Duke		Duke
	Maturity	Interest		Duke		Energy		Energy		Energy		Energy		Energy		Energy
Issuance Date	Date	Rate		Energy		(Parent)		Carolinas		Progress		Florida		Ohio		Indiana		Piedmont
Unsecured Debt
May 2020(a)	June 2030	2.450	%	$	500	$	500	$	—	$	—	$	—	$	—	$	—	$	—
May 2020(b)	June 2050	3.350	%	400		—		—		—		—		—		—		400
August 2020(c)(d)	February 2022	0.400	%	700		—		—		700		—		—		—		—
September 2020(e)	September 2025	0.900	%	650		650		—		—		—		—		—		—
September 2020(e)	June 2030	2.450	%	350		350		—		—		—		—		—		—



First Mortgage Bonds
January 2020(f)	February 2030	2.450	%	500		—		500		—		—		—		—		—
January 2020(f)	August 2049	3.200	%	400		—		400		—		—		—		—		—
March 2020(g)	April 2050	2.750	%	550		—		—		—		—		—		550		—
May 2020(b)	June 2030	2.125	%	400		—		—		—		—		400		—		—
June 2020(b)	June 2030	1.750	%	500		—		—		—		500		—		—		—
August 2020(h)	August 2050	2.500	%	600		—		—		600		—		—		—		—
Total issuances				$	5,550	$	1,500	$	900	$	1,300	$	500	$	400	$	550	$	400

(a)Debt issued to repay $500 million borrowing made under Duke Energy (Parent) revolving credit facility in March 2020, and for general corporate purposes.

(b)Debt issued to repay short-term debt and for general corporate purposes.

(c)Debt issued to repay $700 million term loan due December 2020.

(d)Debt issuance has a floating interest rate.

(e)Debt issued to repay a portion of outstanding commercial paper, to repay a portion of Duke Energy (Parent)'s outstanding $1.7 billion term loan due March 2021 and for general corporate purposes.

(f)Debt issued to repay at maturity $450 million first mortgage bonds due June 2020 and for general corporate purposes.

(g)Debt issued to repay at maturity $500 million first mortgage bonds due July 2020 and to pay down short-term debt.

(h)Debt issued to repay at maturity $300 million first mortgage bonds due September 2020 and for general corporate purposes.

AVAILABLE CREDIT FACILITIES

Master Credit Facility

In March 2021, Duke Energy amended its existing $8 billion Master Credit Facility to extend the termination date to March 2026. 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, 2021
			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)	$	8,000	$	2,650	$	1,225	$	1,150	$	900	$	775	$	600	$	700
Reduction to backstop issuances
Commercial paper(b)	(2,863)		(1,128)		(506)		(307)		(181)		(119)		(150)		(472)
Outstanding letters of credit	(38)		(25)		(4)		(2)		(7)		—		—		—
Tax-exempt bonds	(81)		—		—		—		—		—		(81)		—

Available capacity	$	5,018	$	1,497	$	715	$	841	$	712	$	656	$	369	$	228

(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.

Three-Year Revolving Credit Facility

Duke Energy (Parent) has a $1 billion revolving credit facility. In March 2021, Duke Energy extended the termination date of the facility from May 2022 to May 2024. Borrowings under this facility will be used for general corporate purposes. As of December 31, 2021, $500 million has been drawn under this facility. This balance is classified as Long-term debt on Duke Energy's Consolidated Balance Sheets. Any undrawn commitments can be drawn, and borrowings can be prepaid, at any time throughout the term of the facility. During the first quarter of 2020, an additional $500 million was drawn under this facility to manage liquidity impacts from COVID-19. The additional $500 million was paid down during the second quarter of 2020. The terms and conditions of the facility are generally consistent with those governing Duke Energy's Master Credit Facility.

Duke Energy Ohio Term Loan Facility

In October 2021, Duke Energy Ohio entered into a two-year term loan facility with commitments totaling $100 million. Borrowings under the facility will be used to pay down short-term debt and for general corporate purposes. The term loan was fully drawn at the time of closing in October. The balance is classified as Long-Term Debt on Duke Energy Ohio’s Consolidated Balance Sheets.

Duke Energy Indiana Term Loan Facility

In October 2021, Duke Energy Indiana entered into a two-year term loan facility with commitments totaling $300 million. Borrowings under the facility will be used to pay down short-term debt and for general corporate purposes. The term loan was fully drawn at the time of closing in October. The balance is classified as Long-Term Debt on Duke Energy Indiana’s Consolidated Balance Sheets.

Duke Energy Kentucky Term Loan Facility

In October 2021, Duke Energy Kentucky entered into a two-year term loan facility with commitments totaling $50 million. Borrowings under the facility will be used to pay down short-term debt and for general corporate purposes. The term loan was fully drawn at the time of closing in October. The balance is classified as Long-Term Debt on Duke Energy Ohio’s Consolidated Balance Sheets.

Other Debt Matters

In September 2019, 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.

Duke Energy has an effective Form S-3 with the SEC to sell up to $3 billion of variable denomination floating-rate demand notes, called PremierNotes. The Form S-3 states that no more than $1.5 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, 2021, and 2020, was $1,066 million and $1,168 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 wholly owned 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.

Progress Energy has a revolving credit agreement with Duke Energy (Parent) which allows up to $2.5 billion in intercompany borrowings. The balance is reflected within Notes payable to affiliated companies on the Progress Energy Consolidated Balance Sheets.

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, 2021, each of the Duke Energy Registrants was in compliance with all covenants related to their debt agreements. 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, 2021, and 2020, Duke Energy had loans outstanding of $819 million, including $34 million at Duke Energy Progress and $817 million, including $35 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.

7. 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. 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, 2021, 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, 2021, the maximum potential amount of future payments associated with these guarantees were $48 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 3 and 12 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, 2021, was $53 million of which all expire between 2022 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, 2021, Duke Energy had issued a total of $586 million in letters of credit, which expire between 2022 and 2023. The unused amount under these letters of credit was $54 million.

Duke Energy recognized $3 million and $11 million as of December 31, 2021, and 2020, 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.

8. 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, 2021
							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	%	$	1,044	$	525	$	20
W.S. Lee CC(b)	87.27	%	632		67		3
Duke Energy Indiana
Gibson (unit 5)(c)	50.05	%	440		221		3
Vermillion(d)	62.50	%	175		108		5
Transmission and local facilities(c)	Various		6,164		1,477		190

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

(b) Jointly owned with NCEMC.

(c) Jointly owned with WVPA and IMPA.

(d) Jointly owned with WVPA.

9. 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 3 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, 2021
			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)	$	7,046	$	2,847	$	4,156	$	3,792	$	364	$	—	$	—	$	—
Closure of ash impoundments	5,293		2,390		1,872		1,839		33		82		949		—
Other	437		64		84		44		40		54		38		22
Total asset retirement obligation	$	12,776	$	5,301	$	6,112	$	5,675	$	437	$	136	$	987	$	22
Less: Current portion	647		249		275		274		1		13		110		—
Total noncurrent asset retirement obligation	$	12,129	$	5,052	$	5,837	$	5,401	$	436	$	123	$	877	$	22

(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	$	15	$	9,105	2018 or 2019
Duke Energy Carolinas(b)(c)	—		4,365		2018
Duke Energy Progress(d)	15		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 16 for additional information related to the fair value of the Duke Energy Registrants' NDTFs.


	December 31,
(in millions)	2021		2020
Duke Energy	$	8,933	$	7,726
Duke Energy Carolinas	5,068		4,381
Duke Energy Progress	3,865		3,345

Nuclear Operating Licenses

As described in Note 3, 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 3 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 2021 and 2020.

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 3 for additional information on Regulatory assets related to AROs and Note 4 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 3 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, 2019	$	13,318	$	5,734	$	6,471	$	5,893	$	578	$	80	$	832	$	17

Accretion expense(a)	542		258		246		225		21		4		33		1
Liabilities settled(b)	(724)		(198)		(451)		(358)		(93)		(2)		(74)		—
Liabilities incurred in the current year	22		—		5		—		5		—		—		—
Revisions in estimates of cash flows(c)	(154)		(444)		(122)		(125)		3		29		385		2
Balance at December 31, 2020	13,004		5,350		6,149		5,635		514		111		1,176		20

Accretion expense(a)	512		242		229		212		17		4		35		1
Liabilities settled(b)	(613)		(210)		(324)		(214)		(110)		(3)		(77)		—
Liabilities incurred in the current year	32		8		6		—		6		—		—		—
Revisions in estimates of cash flows(c)	(159)		(89)		52		42		10		24		(147)		1
Balance at December 31, 2021	$	12,776	$	5,301	$	6,112	$	5,675	$	437	$	136	$	987	$	22

(a) Substantially all accretion expense for the years ended December 31, 2021, and 2020, 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) Primarily relates to decreases due to revised basin closure cost estimates, partially offset by increases related to new closure plan approvals, post closure maintenance and beneficiation costs. Duke Energy Indiana estimates also include the impacts of closure estimates for certain ash impoundments due to the impact of Hoosier Environmental Council’s petition filed with the court challenging the Indiana Department of Environmental Management’s partial approval of Duke Energy Indiana’s ash pond closure plan. See Note 4 for more information on Hoosier Environmental Council's petition. The amounts recorded represent the discounted cash flows for estimated closure costs based upon the probability weightings of the potential closure methods as evaluated on a site-by-site basis.

10. PROPERTY, PLANT AND EQUIPMENT

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


	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		$	2,162	$	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
Electric generation, distribution and transmission	28	7,104		—		—		—		—		—		—		—
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		6,168		2,078		2,297		954		1,343		515		460		262
Other	14	5,289		1,323		1,563		1,115		437		287		253		368
Total property, plant and equipment(a)(e)		161,819		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)(e)		(2,944)		—		—		—		—		—		—		—
Facilities to be retired, net		144		102		26		26		—		6		—		11
Total net property, plant and equipment		$	111,408	$	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.

(e) Includes gross property, plant and equipment cost of consolidated VIEs of $7,339 million and accumulated depreciation of consolidated VIEs of $1,474 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 12 months 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.

In 2021, Duke Energy continued to monitor recoverability of its renewable merchant plants located in the Electric Reliability Council of Texas West market and in the PJM West market due to fluctuating market pricing and long-term forecasted energy prices. The assets were not impaired as of December 31, 2021, because the carrying value of approximately $200 million continues to approximate the aggregate estimated future undiscounted cash flows. A continued decline in energy market pricing or other factors unfavorably impacting the economics would likely result in a future impairment. Duke Energy retained 51% ownership interest in these facilities following the 2019 transaction to sell a minority interest in certain renewable assets. See Note 1 for further information.


	December 31, 2020
	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		$	2,046	$	536	$	908	$	463	$	445	$	171	$	118	$	279
Plant – Regulated
Electric generation, distribution and transmission	39	117,107		44,059		50,785		31,375		19,410		6,255		16,008		—
Natural gas transmission and distribution	54	10,799		—		—		—		—		3,136		—		7,663
Other buildings and improvements	36	2,038		740		459		197		262		374		300		165
Plant – Nonregulated
Electric generation, distribution and transmission	27	5,444		—		—		—		—		—		—		—
Other buildings and improvements	10	519		—		—		—		—		—		—		—
Nuclear fuel		3,284		1,837		1,447		1,447		—		—		—		—
Equipment	15	2,608		620		759		498		261		385		238		122
Construction in process		6,645		1,645		2,013		709		1,304		407		409		581
Other	14	5,090		1,203		1,521		1,070		441		294		309		324
Total property, plant and equipment(a)(e)		155,580		50,640		57,892		35,759		22,123		11,022		17,382		9,134
Total accumulated depreciation – regulated(b)(c)		(46,216)		(17,453)		(18,368)		(12,801)		(5,560)		(3,013)		(5,661)		(1,749)
Total accumulated depreciation – nonregulated(d)(e)		(2,611)		—		—		—		—		—		—		—
Facilities to be retired, net		29		—		29		29		—		—		—		—
Total net property, plant and equipment		$	106,782	$	33,187	$	39,553	$	22,987	$	16,563	$	8,009	$	11,721	$	7,385

(a) Includes finance leases of $832 million, $335 million, $416 million, $297 million, $119 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 $141 million, $24 million and $117 million, respectively, of accumulated amortization of finance leases.

(b) Includes $1,832 million, $1,010 million, $822 million and $822 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 $12 million, $23 million, and $3 million at Duke Energy, Duke Energy Carolinas and Duke Energy Indiana, respectively.

(d) Includes accumulated amortization of finance leases of $23 million at Duke Energy.

(e) Includes gross property, plant and equipment cost of consolidated VIEs of $6,394 million and accumulated depreciation of consolidated VIEs of $1,242 million at Duke Energy.

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


	Years Ended December 31,
(in millions)	2021		2020		2019
Duke Energy	$	72	$	112	$	159
Duke Energy Carolinas	29		28		30
Progress Energy	20		17		31
Duke Energy Progress	14		12		28
Duke Energy Florida	6		5		3
Duke Energy Ohio	20		26		22
Duke Energy Indiana(a)	(17)		10		26
Piedmont	9		8		26

(a) 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.

11. GOODWILL AND INTANGIBLE ASSETS

GOODWILL

Duke Energy

The following table presents goodwill by reportable segment for Duke Energy included on Duke Energy's Consolidated Balance Sheets at December 31, 2021, and 2020.


	Electric Utilities		Gas Utilities		Commercial
(in millions)	and Infrastructure		and Infrastructure		Renewables		Total
Goodwill Balance at December 31, 2020	$	17,379	$	1,924	$	122	$	19,425
Accumulated impairment charges	—		—		(122)		(122)
Goodwill balance at December 31, 2020, adjusted for accumulated impairment charges	$	17,379	$	1,924	$	—	$	19,303

Goodwill Balance at December 31, 2021	$	17,379	$	1,924	$	122	$	19,425
Accumulated impairment charges	—		—		(122)		(122)
Goodwill balance at December 31, 2021, adjusted for accumulated impairment charges	$	17,379	$	1,924	$	—	$	19,303

Duke Energy Ohio

Duke Energy Ohio's Goodwill balance of $920 million, allocated $596 million to Electric Utilities and Infrastructure and $324 million to Gas Utilities and Infrastructure, is presented net of accumulated impairment charges of $216 million on the Consolidated Balance Sheets at December 31, 2021, and 2020.

Progress Energy

Progress Energy's Goodwill is included in the Electric Utilities and Infrastructure segment and there are no accumulated impairment charges.

Piedmont

Piedmont's Goodwill is included in the Gas Utilities and Infrastructure 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 2021.

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, 2021, and 2020.


	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		—
Renewable operating and development projects	106		—		—		—		—		—		—		—
Other	28		—		—		—		—		—		—		—
Total gross carrying amounts	370		73		136		133		3		—		26		—
Accumulated amortization – natural gas, coal and power contracts	(24)		—		—		—		—		—		(24)		—
Accumulated amortization – renewable operating and development projects	(38)		—		—		—		—		—		—		—
Accumulated amortization – other	(4)		—		—		—		—		—		—		—
Total accumulated amortization	(66)		—		—		—		—		—		(24)		—
Total intangible assets, net	$	304	$	73	$	136	$	133	$	3	$	—	$	2	$	—


	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
Emission allowances	$	8	$	—	$	5	$	2	$	3	$	—	$	2	$	—
Renewable energy certificates	196		65		130		130		—		1		—		—
Natural gas, coal and power contracts	24		—		—		—		—		—		24		—
Renewable operating and development projects	107		—		—		—		—		—		—		—
Other	20		—		—		—		—		—		—		—
Total gross carrying amounts	355		65		135		132		3		1		26		—
Accumulated amortization – natural gas, coal and power contracts	(23)		—		—		—		—		—		(23)		—
Accumulated amortization – renewable operating and development projects	(34)		—		—		—		—		—		—		—
Accumulated amortization – other	(3)		—		—		—		—		—		—		—
Total accumulated amortization	(60)		—		—		—		—		—		(23)		—
Total intangible assets, net	$	295	$	65	$	135	$	132	$	3	$	1	$	3	$	—

Amortization Expense

Amortization expense amounts for natural gas, coal and power contracts, renewable operating projects and other intangible assets are immaterial for the years ended December 31, 2021, 2020 and 2019, and are expected to be immaterial for the next five years as of December 31, 2021.

12. 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,
	2021				2020				2019
			Equity in				Equity in		Equity in
			earnings				earnings		earnings
(in millions)	Investments		(losses)		Investments		(losses)		(losses)
Electric Utilities and Infrastructure	$	104	$	7	$	105	$	(1)	$	9
Gas Utilities and Infrastructure	231		8		215		(2,017)		114
Commercial Renewables	513		(34)		534		—		(4)
Other	122		47		107		13		43
Total	$	970	$	28	$	961	$	(2,005)	$	162

During the years ended December 31, 2021, 2020 and 2019, Duke Energy received distributions from equity investments of $80 million, $37 million and $55 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, 2021, 2020 and 2019, Duke Energy received distributions from equity investments of $44 million, $133 million and $11 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, 2021, 2020 and 2019, Piedmont received distributions from equity investments of $8 million, $2 million and $1 million, respectively, which are included in Other assets within Cash Flows from Operating Activities and $2 million, $2 million and $4 million, respectively, which are included within Cash Flows from Investing Activities on the Consolidated Statements of Cash Flows.

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 recorded OTTIs of $25 million within Equity in earnings (losses) of unconsolidated affiliates on Duke Energy's Consolidated Statements of Operations for the year ended December 31, 2019, to completely impair its 24% ownership interest in Constitution.

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 3 and 7 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, and a 70% interest in Sustain T&W, SustainRNG's renewable natural gas project located in Georgia.

Commercial Renewables

DS Cornerstone, LLC, which owns wind farm projects in the U.S. was part of a sale of minority interest in a certain portion of renewable assets in 2019. See Note 1 for more information on the sale. Prior to the sale, Duke Energy had a 50% interest in DS Cornerstone, LLC. Subsequent to the sale, Duke Energy has a 26% interest in the investment.

In 2020, Duke Energy completed its acquisition of 70 distributed fuel cell projects from Bloom Energy Corporation, which approximates 43 MW of capacity serving commercial and industrial customers across the U.S. Duke Energy is not the primary beneficiary of the distributed fuel cell portfolio and does not consolidate these assets.

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 and comparative prior year periods in Duke Energy's consolidated balance sheets and consolidated statements of operations. For the year ended December 31, 2021, there were no investments that met the significance requirements.


(in millions)			December 31, 2020

Current assets			$43
Noncurrent assets			93
Current liabilities			1,965
Noncurrent liabilities			167

Membership interests			(1,996)

	Years Ended December 31,
	2020		2019
Net revenues	$	—	$	—
Operating loss	(4,612)		(5)

Net (loss) income	(4,512)		246

Net (loss) income attributable to Duke Energy	$	(2,121)	$	116

13. 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)	2021		2020		2019
Duke Energy Carolinas
Corporate governance and shared service expenses(a)	$	894	$	753	$	841
Indemnification coverages(b)	24		20		20
Joint Dispatch Agreement (JDA) revenue(c)	41		25		60
JDA expense(c)	207		114		186
Intercompany natural gas purchases(d)	11		15		15
Progress Energy
Corporate governance and shared service expenses(a)	$	856	$	715	$	778
Indemnification coverages(b)	41		36		37
JDA revenue(c)	207		114		186
JDA expense(c)	41		25		60
Intercompany natural gas purchases(d)	75		75		76
Duke Energy Progress
Corporate governance and shared service expenses(a)	$	504	$	420	$	462
Indemnification coverages(b)	19		17		15
JDA revenue(c)	207		114		186
JDA expense(c)	41		25		60
Intercompany natural gas purchases(d)	75		75		76
Duke Energy Florida
Corporate governance and shared service expenses(a)	$	352	$	295	$	316
Indemnification coverages(b)	22		19		22
Duke Energy Ohio
Corporate governance and shared service expenses(a)	$	329	$	326	$	354
Indemnification coverages(b)	4		4		4
Duke Energy Indiana
Corporate governance and shared service expenses(a)	$	409	$	401	$	412
Indemnification coverages(b)	8		8		7
Piedmont
Corporate governance and shared service expenses(a)	$	139	$	140	$	138
Indemnification coverages(b)	3		3		3
Intercompany natural gas sales(d)	86		90		91
Natural gas storage and transportation costs(e)	22		23		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 6 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 17, 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, 2021
Intercompany income tax receivable	$	—	$	—	$	—	$	40	$	19	$	—	$	—
Intercompany income tax payable	62		—		84		—		—		10		27

December 31, 2020
Intercompany income tax receivable	$	—	$	—	$	—	$	—	$	—	$	9	$	10
Intercompany income tax payable	31		33		46		35		2		—		—

14. DERIVATIVES AND HEDGING

The Duke Energy Registrants use commodity and interest rate contracts to manage commodity price risk and interest 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.

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. Gains and losses reclassified out of AOCI for the years ended December 31, 2021, 2020 and 2019, were not material. Duke Energy's interest rate derivatives designated as hedges include interest rate swaps used to hedge existing debt within the Commercial Renewables segment and 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, 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(a)	$	3,592	$	350	$	500	$	500	$	300	$	27


	December 31, 2020
			Duke				Duke		Duke
	Duke		Energy		Progress		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Ohio
Cash flow hedges	$	632	$	—	$	—	$	—	$	—
Undesignated contracts	1,177		400		750		750		27
Total notional amount(a)	$	1,809	$	400	$	750	$	750	$	27

(a) Duke Energy includes amounts related to consolidated VIEs of $665 million in cash flow hedges as of December 31, 2021, and $632 million in cash flow hedges as of December 31, 2020.

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.

Cash Flow Hedges

For derivatives designated as hedging the exposure to variable cash flows of a future transaction, referred to as a cash flow hedge, 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. Gains and losses reclassified out of accumulated other comprehensive income (loss) for the year ended December 31, 2021, 2020 and 2019, were not material. Duke Energy’s commodity derivatives designated as hedges include long-term electricity sales in the Commercial Renewables segment.

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, 2021
		Duke		Duke	Duke	Duke
	Duke	Energy	Progress	Energy	Energy	Energy
	Energy	Carolinas	Energy	Progress	Ohio	Indiana	Piedmont
Electricity (GWh)(a)	22,344	—	—	—	1,681	10,688	—
Natural gas (millions of Dth)	823	264	215	215	—	8	336


	December 31, 2020
		Duke		Duke	Duke	Duke
	Duke	Energy	Progress	Energy	Energy	Energy
	Energy	Carolinas	Energy	Progress	Ohio	Indiana	Piedmont
Electricity (GWh)(a)	35,409	—	—	—	2,559	10,802	—
Natural gas (millions of Dth)	678	145	158	158	—	2	373

(a) Duke Energy includes 9,975 GWh and 22,048 GWh related to cash flow hedges as of December 31, 2021, and 2020, respectively.

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, 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
Commodity Contracts
Designated as Hedging Instruments
Current	$	27	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Noncurrent	117		—		—		—		—		—		—		—
Not Designated as Hedging Instruments
Current	$	72	$	18	$	19	$	5	$	14	$	—	$	13	$	21
Noncurrent	132		9		5		5		—		—		—		118
Total Derivative Liabilities – Commodity Contracts	$	348	$	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	$	472	$	35	$	24	$	10	$	14	$	5	$	27	$	139


Derivative Assets	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
Commodity Contracts



Not Designated as Hedging Instruments
Current	$	30	$	14	$	9	$	9	$	—	$	1	$	6	$	1
Noncurrent	13		6		6		6		—		—		—		—
Total Derivative Assets – Commodity Contracts	$	43	$	20	$	15	$	15	$	—	$	1	$	6	$	1
Interest Rate Contracts



Not Designated as Hedging Instruments
Current	$	18	$	—	$	18	$	18	$	—	$	—	$	—	$	—

Total Derivative Assets – Interest Rate Contracts	$	18	$	—	$	18	$	18	$	—	$	—	$	—	$	—




Total Derivative Assets	$	61	$	20	$	33	$	33	$	—	$	1	$	6	$	1


Derivative Liabilities	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
Commodity Contracts
Designated as Hedging Instruments
Current	$	14	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Noncurrent	70		—		—		—		—		—		—		—
Not Designated as Hedging Instruments
Current	$	30	$	13	$	2	$	2	$	—	$	—	$	1	$	15
Noncurrent	137		3		27		12		—		—		—		107
Total Derivative Liabilities – Commodity Contracts	$	251	$	16	$	29	$	14	$	—	$	—	$	1	$	122
Interest Rate Contracts
Designated as Hedging Instruments
Current	$	15	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Noncurrent	48		—		—		—		—		—		—		—
Not Designated as Hedging Instruments
Current	5		4		—		—		—		1		—		—
Noncurrent	5		—		—		—		—		5		—		—
Total Derivative Liabilities – Interest Rate Contracts	$	73	$	4	$	—	$	—	$	—	$	6	$	—	$	—




Total Derivative Liabilities	$	324	$	20	$	29	$	14	$	—	$	6	$	1	$	122

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, 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	$	184	$	26	$	19	$	5	$	14	$	1	$	13	$	21
Gross amounts offset	(11)		(6)		(5)		(5)		—		—		—		—
Net amounts presented in Current Liabilities: Other	$	173	$	20	$	14	$	—	$	14	$	1	$	13	$	21
Noncurrent
Gross amounts recognized	$	288	$	9	$	5	$	5	$	—	$	4	$	14	$	118
Gross amounts offset	(12)		(8)		(5)		(5)		—		—		—		—
Net amounts presented in Other Noncurrent Liabilities: Other	$	276	$	1	$	—	$	—	$	—	$	4	$	14	$	118


Derivative Assets	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
Gross amounts recognized	$	48	$	14	$	27	$	27	$	—	$	1	$	6	$	1
Gross amounts offset	(3)		(2)		(2)		(2)		—		—		—		—
Net amounts presented in Current Assets: Other	$	45	$	12	$	25	$	25	$	—	$	1	$	6	$	1
Noncurrent
Gross amounts recognized	$	13	$	6	$	6	$	6	$	—	$	—	$	—	$	—
Gross amounts offset	(5)		(1)		(4)		(4)		—		—		—		—
Net amounts presented in Other Noncurrent Assets: Other	$	8	$	5	$	2	$	2	$	—	$	—	$	—	$	—


Derivative Liabilities	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
Gross amounts recognized	$	64	$	17	$	2	$	2	$	—	$	1	$	1	$	15
Gross amounts offset	(3)		(2)		(2)		(2)		—		—		—		—
Net amounts presented in Current Liabilities: Other	$	61	$	15	$	—	$	—	$	—	$	1	$	1	$	15
Noncurrent
Gross amounts recognized	$	260	$	3	$	27	$	12	$	—	$	5	$	—	$	107
Gross amounts offset	(5)		(1)		(4)		(4)		—		—		—		—
Net amounts presented in Other Noncurrent Liabilities: Other	$	255	$	2	$	23	$	8	$	—	$	5	$	—	$	107

15. 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, 2021, and 2020.

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, 2021						December 31, 2020
	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	$	—	$	—	$	160	$	—	$	—	$	177
Equity securities	4,905		43		7,350		4,138		54		6,235
Corporate debt securities	39		6		829		76		1		806
Municipal bonds	14		1		314		22		—		370
U.S. government bonds	31		12		1,568		51		—		1,361
Other debt securities	3		1		180		8		—		180
Total NDTF Investments	$	4,992	$	63	$	10,401	$	4,295	$	55	$	9,129
Other Investments
Cash and cash equivalents	$	—	$	—	$	36	$	—	$	—	$	127
Equity securities	36		—		156		79		—		146
Corporate debt securities	2		1		119		8		—		110
Municipal bonds	3		1		80		5		—		86
U.S. government bonds	—		—		56		—		—		42
Other debt securities	—		1		45		—		—		47
Total Other Investments	$	41	$	3	$	492	$	92	$	—	$	558
Total Investments	$	5,033	$	66	$	10,893	$	4,387	$	55	$	9,687

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, 2021, 2020 and 2019, were as follows.


	Years Ended December 31,
(in millions)	2021		2020		2019
FV-NI:
Realized gains	$	724	$	366	$	172
Realized losses	141		174		151
AFS:
Realized gains	56		96		94
Realized losses	54		51		67

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, 2021						December 31, 2020
	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	$	—	$	—	$	53	$	—	$	—	$	30
Equity securities	2,887		19		4,265		2,442		23		3,685
Corporate debt securities	24		4		506		49		1		510
Municipal bonds	2		—		48		6		—		91
U.S. government bonds	16		3		712		25		—		475
Other debt securities	3		1		175		7		—		174
Total NDTF Investments	$	2,932	$	27	$	5,759	$	2,529	$	24	$	4,965

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, 2021, 2020 and 2019, were as follows.


	Years Ended December 31,
(in millions)	2021		2020		2019
FV-NI:
Realized gains	$	440	$	64	$	113
Realized losses	96		99		107
AFS:
Realized gains	38		60		55
Realized losses	37		37		38

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, 2021						December 31, 2020
	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	$	—	$	—	$	107	$	—	$	—	$	147
Equity securities	2,018		24		3,085		1,696		31		2,550
Corporate debt securities	15		2		323		27		—		296
Municipal bonds	12		1		266		16		—		279
U.S. government bonds	15		9		856		26		—		886
Other debt securities	—		—		5		1		—		6
Total NDTF Investments	$	2,060	$	36	$	4,642	$	1,766	$	31	$	4,164
Other Investments
Cash and cash equivalents	$	—	$	—	$	20	$	—	$	—	$	106
Municipal bonds	2		—		26		3		—		26
Total Other Investments	$	2	$	—	$	46	$	3	$	—	$	132
Total Investments	$	2,062	$	36	$	4,688	$	1,769	$	31	$	4,296

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, 2021, 2020 and 2019, were as follows.


	Years Ended December 31,
(in millions)	2021		2020		2019
FV-NI:
Realized gains	$	284	$	302	$	59
Realized losses	45		75		44
AFS:
Realized gains	16		24		36
Realized losses	14		13		29

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, 2021						December 31, 2020
	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	$	—	$	—	$	94	$	—	$	—	$	76
Equity securities	1,915		23		2,970		1,617		31		2,459
Corporate debt securities	15		2		282		27		—		296
Municipal bonds	12		1		266		16		—		279
U.S. government bonds	15		3		472		26		—		412
Other debt securities	—		—		5		1		—		6
Total NDTF Investments	$	1,957	$	29	$	4,089	$	1,687	$	31	$	3,528
Other Investments
Cash and cash equivalents	$	—	$	—	$	16	$	—	$	—	$	1
Total Other Investments	$	—	$	—	$	16	$	—	$	—	$	1
Total Investments	$	1,957	$	29	$	4,105	$	1,687	$	31	$	3,529

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, 2021, 2020 and 2019, were as follows.


	Years Ended December 31,
(in millions)	2021		2020		2019
FV-NI:
Realized gains	$	283	$	52	$	38
Realized losses	44		59		33
AFS:
Realized gains	15		24		7
Realized losses	13		13		5

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, 2021						December 31, 2020
	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	$	—	$	—	$	13	$	—	$	—	$	71
Equity securities	103		1		115		79		—		91
Corporate debt securities	—		—		41		—		—		—

U.S. government bonds	—		6		384		—		—		474

Total NDTF Investments(a)	$	103	$	7	$	553	$	79	$	—	$	636
Other Investments
Cash and cash equivalents	$	—	$	—	$	3	$	—	$	—	$	1
Municipal bonds	2		—		26		3		—		26
Total Other Investments	$	2	$	—	$	29	$	3	$	—	$	27
Total Investments	$	105	$	7	$	582	$	82	$	—	$	663

(a) During the years ended December 31, 2021, and 2020, 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, 2021, 2020 and 2019, were as follows.


	Years Ended December 31,
(in millions)	2021		2020		2019
FV-NI:
Realized gains	$	1	$	250	$	21
Realized losses	1		16		11
AFS:
Realized gains	1		—		29
Realized losses	1		—		24

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, 2021						December 31, 2020
	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	6		—		97		58		—		97
Corporate debt securities	—		—		6		—		—		3
Municipal bonds	1		1		46		1		—		38
U.S. government bonds	—		—		12		—		—		4


Total Investments	$	7	$	1	$	161	$	59	$	—	$	143

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, 2021, 2020 and 2019, were immaterial.

DEBT SECURITY MATURITIES

The table below summarizes the maturity date for debt securities.


	December 31, 2021
			Duke				Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Indiana
Due in one year or less	$	159	$	3	$	138	$	31	$	107	$	7
Due after one through five years	957		337		546		256		290		25
Due after five through 10 years	550		226		248		231		17		10
Due after 10 years	1,525		875		544		507		37		22
Total	$	3,191	$	1,441	$	1,476	$	1,025	$	451	$	64

16. 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.

Other fair value considerations

See Note 11 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 14. See Note 15 for additional information related to investments by major security type for the Duke Energy Registrants.


	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	(472)		(13)		(314)		(145)		—
Net assets (liabilities)	$	10,741	$	8,654	$	2,158	$	(121)	$	50


	December 31, 2020
(in millions)	Total Fair Value		Level 1		Level 2		Level 3		Not Categorized
NDTF cash and cash equivalents	$	177	$	177	$	—	$	—	$	—
NDTF equity securities	6,235		6,189		—		—		46
NDTF debt securities	2,717		874		1,843		—		—
Other equity securities	146		146		—		—		—
Other debt securities	285		37		248		—		—
Other cash and cash equivalents	127		127		—		—		—
Derivative assets	61		1		53		7		—
Total assets	9,748		7,551		2,144		7		46

Derivative liabilities	(324)		—		(240)		(84)		—
Net assets (liabilities)	$	9,424	$	7,551	$	1,904	$	(77)	$	46

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)	2021		2020
Balance at beginning of period	$	(77)	$	(102)

Total pretax realized or unrealized losses included in comprehensive income	(75)		(84)

Purchases, sales, issuances and settlements:
Purchases	21		14


Settlements	(5)		(19)
Net transfers Out of Level 3(a)	—		117
Total gains (losses) included on the Consolidated Balance Sheet	15		(3)
Balance at end of period	$	(121)	$	(77)

(a) Transferred from Level 3 to Level 2 because observable market data became available.

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, 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


	December 31, 2020
(in millions)	Total Fair Value		Level 1		Level 2		Not Categorized
NDTF cash and cash equivalents	$	30	$	30	$	—	$	—
NDTF equity securities	3,685		3,639		—		46
NDTF debt securities	1,250		192		1,058		—

Derivative assets	20		—		20		—
Total assets	4,985		3,861		1,078		46
Derivative liabilities	(20)		—		(20)		—
Net assets	$	4,965	$	3,861	$	1,058	$	46

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, 2021						December 31, 2020
(in millions)	Total Fair Value		Level 1		Level 2			Total Fair Value		Level 1		Level 2
NDTF cash and cash equivalents	$	107	$	107	$	—		$	147	$	147	$	—
NDTF equity securities	3,085		3,085		—			2,550		2,550		—
NDTF debt securities	1,450		628		822			1,467		682		785
Other debt securities	26		—		26			26		—		26
Other cash and cash equivalents	20		20		—			106		106
Derivative assets	124		—		124			33		—		33
Total assets	4,812		3,840		972			4,329		3,485		844

Derivative liabilities	(24)		—		(24)			(29)		—		(29)
Net assets	$	4,788	$	3,840	$	948		$	4,300	$	3,485	$	815

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, 2021						December 31, 2020
(in millions)	Total Fair Value		Level 1		Level 2			Total Fair Value		Level 1		Level 2
NDTF cash and cash equivalents	$	94	$	94	$	—		$	76	$	76	$	—
NDTF equity securities	2,970		2,970		—			2,459		2,459		—
NDTF debt securities	1,025		289		736			993		237		756

Other cash and cash equivalents	16		16		—			1		1		—
Derivative assets	124		—		124			33		—		33
Total assets	4,229		3,369		860			3,562		2,773		789
Derivative liabilities	(10)		—		(10)			(14)		—		(14)
Net assets	$	4,219	$	3,369	$	850		$	3,548	$	2,773	$	775

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, 2021						December 31, 2020
(in millions)	Total Fair Value		Level 1		Level 2		Total Fair Value		Level 1		Level 2
NDTF cash and cash equivalents	$	13	$	13	$	—	$	71	$	71	$	—
NDTF equity securities	115		115		—		91		91		—
NDTF debt securities	425		339		86		474		445		29
Other debt securities	26		—		26		26		—		26
Other cash and cash equivalents	3		3		—		1		1		—

Total assets	582		470		112		663		608		55

Derivative liabilities	(14)		—		(14)		—		—		—
Net assets	$	568	$	470	$	98	$	663	$	608	$	55

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, 2021, and 2020.

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, 2021								December 31, 2020
(in millions)	Total Fair Value		Level 1		Level 2		Level 3		Total Fair Value		Level 1		Level 2		Level 3
Other equity securities	$	97	$	97	$	—	$	—	$	97	$	97	$	—	$	—
Other debt securities	64		—		64		—		45		—		45		—
Other cash equivalents	—		—		—		—		1		1		—		—
Derivative assets	23		1		—		22		6		—		—		6
Total assets	184		98		64		22		149		98		45		6
Derivative liabilities	(27)		(13)		(14)		—		(1)		(1)		—		—
Net assets	$	157	$	85	$	50	$	22	$	148	$	97	$	45	$	6

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)	2021		2020
Balance at beginning of period	$	6	$	11


Purchases, sales, issuances and settlements:
Purchases	18		10


Settlements	(16)		(13)

Total gains (losses) included on the Consolidated Balance Sheet	14		(2)
Balance at end of period	$	22	$	6

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, 2021						December 31, 2020
(in millions)	Total Fair Value		Level 1		Level 2			Total Fair Value		Level 1		Level 2


Derivative assets	$	3	$	3	$	—		$	1	$	1	$	—

Derivative liabilities	(139)		—		(139)			(122)		—		(122)
Net (liabilities) assets	$	(136)	$	3	$	(139)		$	(121)	$	1	$	(122)

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)
	Year Ended December 31,
(in millions)		2020
Balance at beginning of period		$	(117)







Net transfers Out of Level 3(a)		117

Balance at end of period		$	—

(a) Transferred from Level 3 to Level 2 because observable market data became available.

QUANTITATIVE INFORMATION ABOUT UNOBSERVABLE INPUTS

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

December 31, 2021

Weighted

Fair Value

Average

Investment Type

(in millions)

Valuation Technique

Unobservable Input

Range

Duke Energy

Electricity contracts

$

(145)

RTO forward pricing

Forward electricity curves – price per MWh

$

19.04

–

$

139.11

$37.57

Duke Energy Ohio

FTRs

2

RTO auction pricing

FTR price – per MWh

0.06

–

1.79

0.96

Duke Energy Indiana

FTRs

22

RTO auction pricing

FTR price – per MWh

(1.18)

–

13.11

2.68

Duke Energy

Total Level 3 derivatives

$

(121)


	December 31, 2020
										Weighted
	Fair Value									Average
Investment Type	(in millions)		Valuation Technique	Unobservable Input	Range					Range
Duke Energy
Electricity contracts	$	(84)	Discounted cash flow	Forward electricity curves – price per MWh	$	14.68	–	$	151.84	$	28.84
Duke Energy Ohio
FTRs	1		RTO auction pricing	FTR price – per MWh	0.25		–	1.68		0.79
Duke Energy Indiana
FTRs	6		RTO auction pricing	FTR price – per MWh	(2.40)		–	7.41		1.05


Duke Energy
Total Level 3 derivatives	$	(77)

OTHER FAIR VALUE DISCLOSURES

The fair value and book value of long-term debt, including current maturities, is summarized in the following table. 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, 2021				December 31, 2020
(in millions)	Book Value		Fair Value		Book Value		Fair Value
Duke Energy(a)	$	63,835	$	69,683	$	59,863	$	69,292
Duke Energy Carolinas	13,275		15,101		12,218		14,917
Progress Energy	20,823		23,751		19,264		23,470
Duke Energy Progress	10,249		11,252		9,258		10,862
Duke Energy Florida	8,482		9,772		7,915		9,756
Duke Energy Ohio	3,193		3,570		3,089		3,650
Duke Energy Indiana	4,323		5,067		4,091		5,204
Piedmont	2,968		3,278		2,780		3,306

(a) Book value of long-term debt includes $1.25 billion as of December 31, 2021, and $1.3 billion as of December 31, 2020, 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, 2021, and December 31, 2020, 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.

17. 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, 2021, 2020 and 2019, 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 2023		January 2025		April 2023		April 2023
Credit facility amount	$	350	$	475	$	350	$	250
Amounts borrowed at December 31, 2021	350		475		350		250
Amounts borrowed at December 31, 2020	350		364		250		250
Restricted Receivables at December 31, 2021	587		844		574		427
Restricted Receivables at December 31, 2020	547		696		500		397

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)	2021		2020
Receivables of VIEs	$	5	$	4
Regulatory Assets: Current	54		53
Current Assets: Other	39		39
Other Noncurrent Assets: Regulatory assets	883		937
Current Liabilities: Other	9		10
Current maturities of long-term debt	56		55
Long-Term Debt	946		1,002

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 3 and 6.

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.


	December 31, 2021
	Duke Energy		Duke Energy
(in millions)	Carolinas		Progress
Regulatory Assets: Current	$	12	$	39
Other Noncurrent Assets: Regulatory assets	220		720
Other Noncurrent Assets: Other	1		4
Interest Accrued	1		2
Current maturities of long-term debt	5		15
Long-Term Debt	228		747

Commercial Renewables

Certain of Duke Energy’s renewable energy facilities are VIEs due to Duke Energy issuing guarantees for debt service and operations and maintenance reserves in support of debt financings. Assets are restricted and cannot be pledged as collateral or sold to third parties without prior approval of debt holders. Additionally, Duke Energy has VIEs associated with tax equity arrangements entered into with third-party investors in order to finance the cost of renewable assets eligible for tax credits. The activities that most significantly impacted the economic performance of these renewable energy facilities were decisions associated with siting, negotiating PPAs and EPC agreements, and decisions associated with ongoing operations and maintenance-related activities. Duke Energy is considered the primary beneficiary and consolidates the entities as it is responsible for all of these decisions.

The table below presents material balances reported on Duke Energy's Consolidated Balance Sheets related to Commercial Renewables VIEs.


	December 31,
(in millions)	2021		2020
Current Assets: Other	$	215	$	257
Property, Plant and Equipment: Cost	7,339		6,394
Accumulated depreciation and amortization	(1,474)		(1,242)
Other Noncurrent Assets: Other	62		67
Current maturities of long-term debt	167		167
Long-Term Debt	1,475		1,569

Other Noncurrent Liabilities: AROs	173		148
Other Noncurrent Liabilities: Other	319		316

NON-CONSOLIDATED VIEs

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


	December 31, 2021
	Duke Energy				Duke		Duke
	Pipeline		Commercial				Energy		Energy
(in millions)	Investments		Renewables		Total		Ohio		Indiana
Receivables from affiliated companies	$	—	$	—	$	—	$	79	$	97

Investments in equity method unconsolidated affiliates	15		508		523		—		—
Other noncurrent assets	61		—		61		—		—
Total assets	$	76	$	508	$	584	$	79	$	97

Other current liabilities	47		4		51		—		—

Other noncurrent liabilities	54		3		57		—		—
Total liabilities	$	101	$	7	$	108	$	—	$	—
Net (liabilities) assets	$	(25)	$	501	$	476	$	79	$	97


	December 31, 2020
	Duke Energy				Duke		Duke
	Pipeline		Commercial				Energy		Energy
(in millions)	Investments		Renewables		Total		Ohio		Indiana
Receivables from affiliated companies	$	—	$	—	$	—	$	83	$	110

Investments in equity method unconsolidated affiliates	—		530		530		—		—
Other noncurrent assets	31		—		31		—		—
Total assets	$	31	$	530	$	561	$	83	$	110

Other current liabilities	928		5		933		—		—

Other noncurrent liabilities	8		10		18		—		—
Total liabilities	$	936	$	15	$	951	$	—	$	—
Net (liabilities) assets	$	(905)	$	515	$	(390)	$	83	$	110

The Duke Energy Registrants are not aware of any situations where the maximum exposure to loss significantly exceeds the carrying values shown above except for certain renewable energy project entities guarantees for debt services and operations and maintenance, as discussed below.

Pipeline Investments

Duke Energy has investments in various joint ventures to construct and operate pipeline 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 3, 7 and 12 for further information regarding this transaction.

Commercial Renewables

Duke Energy has investments in various renewable energy project entities. Duke Energy has a 50% ownership in a VIE, which owns a portfolio of wind projects. This entity is a VIE as a result of Duke Energy issuing guarantees for debt service and operations and maintenance reserves in support of debt financings. Duke Energy does not consolidate this VIE because power to direct and control key activities is shared jointly by Duke Energy and the other owner. Duke Energy also has equity ownership in an entity, which owns a portfolio of fuel cell projects. Duke Energy does not consolidate the fuel cell portfolio as it does not have the power to direct the activities that most significantly impact the economic performance of the entity.

OVEC

Duke Energy Ohio’s 9% ownership interest in OVEC is considered a non-consolidated VIE due to OVEC having insufficient equity to finance its activities without subordinated financial support. The activities that most significantly impact OVEC's economic performance include fuel strategy and supply activities and decisions associated with ongoing operations and maintenance-related activities. Duke Energy Ohio does not have the unilateral power to direct these activities, and therefore, does not consolidate OVEC.

As a counterparty to an Inter-Company Power Agreement (ICPA), Duke Energy Ohio has a contractual arrangement to receive entitlements to capacity and energy from OVEC’s power plants through June 2040 commensurate with its power participation ratio, which is equivalent to Duke Energy Ohio's ownership interest. Costs, including fuel, operating expenses, fixed costs, debt amortization and interest expense, are allocated to counterparties to the ICPA based on their power participation ratio. The value of the ICPA is subject to variability due to fluctuation in power prices and changes in OVEC's cost of business. See Note 3 for additional information.

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 OTTI has occurred.

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


	Duke Energy Ohio				Duke Energy Indiana
	2021		2020		2021		2020
Anticipated credit loss ratio	0.5	%	0.5	%	0.3	%	0.3	%
Discount rate	1.1	%	1.6	%	1.1	%	1.6	%
Receivable turnover rate	13.5	%	13.4	%	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)	2021		2020		2021		2020
Receivables sold	$	269	$	270	$	328	$	344
Less: Retained interests	79		83		97		110
Net receivables sold	$	190	$	187	$	231	$	234

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)	2021		2020		2019		2021		2020		2019
Sales
Receivables sold	$	2,023	$	1,905	$	1,979	$	2,909	$	2,631	$	2,837
Loss recognized on sale	10		10		14		13		12		17
Cash flows
Cash proceeds from receivables sold	2,018		1,875		1,993		2,909		2,586		2,860
Collection fees received	1		1		1		1		1		1
Return received on retained interests	4		4		6		6		5		9

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 LIBOR plus a fixed rate of 1%.

18. 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, Electric Utilities and Infrastructure, Gas Utilities and Infrastructure and Commercial Renewables.

Electric Utilities and Infrastructure

Electric Utilities and Infrastructure 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)	2022		2023		2024		2025		2026		Thereafter		Total

Progress Energy	$	109	$	53	$	45	$	7	$	7	$	43	$	264
Duke Energy Progress	8		8		8		—		—		—		24
Duke Energy Florida	101		45		37		7		7		43		240
Duke Energy Indiana	1		9		14		14		14		12		64

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

Gas Utilities and Infrastructure 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 Gas Utilities and Infrastructure 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)	2022		2023		2024		2025		2026		Thereafter		Total
Piedmont	$	71	$	64	$	61	$	60	$	50	$	286	$	592

Commercial Renewables

Commercial Renewables earns the majority of its revenues through long-term PPAs and generally sells all of its wind and solar facility output, electricity and RECs to customers. The majority of these PPAs have historically been accounted for as leases. For PPAs that are not accounted for as leases, the delivery of electricity and the delivery of RECs are considered separate performance obligations.

The delivery of electricity is a performance obligation satisfied over time and represents generation and consumption of the electricity over the billing period, generally one month. The delivery of RECs is a performance obligation satisfied at a point in time and represents delivery of each REC generated by the wind or solar facility. The majority of self-generated RECs are bundled with energy in Duke Energy’s contracts and, as such, related revenues are recognized as energy is generated and delivered as that pattern is consistent with Duke Energy’s performance. Commercial Renewables recognizes revenue based on the energy generated and billed for the period, generally one month, at contractual rates (including unbilled estimates) according to the invoice practical expedient. Amounts are typically due within 30 days of invoice.

Commercial Renewables also earns revenues from installation of distributed solar generation resources, which is primarily composed of EPC projects to deliver functioning solar power systems, generally completed within two to 12 months from commencement of construction. The installation of distributed solar generation resources is a performance obligation that is satisfied over time. Revenue from fixed-price EPC contracts is recognized using the input method as work is performed based on the estimated ratio of incurred costs to estimated total costs.

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 Electric and Gas Utility and Infrastructure 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. For the Commercial Renewables segment, the majority of revenues from contracts with customers are from selling all of the unit-contingent output at contractually defined pricing under long-term PPAs with consistent expectations regarding the timing and certainty of cash flows. Disaggregated revenues are presented as follows:


	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

Commercial Renewables
Revenue from contracts with customers	$	217	$	—	$	—	$	—	$	—	$	—	$	—	$	—

Other
Revenue from contracts with customers	$	29	$	—	$	—	$	—	$	—	$	—	$	—	$	—

Total revenue from contracts with customers	$	24,703	$	7,145	$	10,962	$	5,719	$	5,243	$	2,026	$	3,134	$	1,469

Other revenue sources(a)	$	394	$	(43)	$	95	$	61	$	16	$	11	$	40	$	100
Total revenues	$	25,097	$	7,102	$	11,057	$	5,780	$	5,259	$	2,037	$	3,174	$	1,569

(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, 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

Commercial Renewables
Revenue from contracts with customers	$	227	$	—	$	—	$	—	$	—	$	—	$	—	$	—

Other
Revenue from contracts with customers	$	26	$	—	$	—	$	—	$	—	$	—	$	—	$	—

Total revenue from contracts with customers	$	23,480	$	7,028	$	10,521	$	5,348	$	5,173	$	1,870	$	2,783	$	1,173

Other revenue sources(a)	$	388	$	(13)	$	106	$	74	$	15	$	(12)	$	12	$	124
Total revenues	$	23,868	$	7,015	$	10,627	$	5,422	$	5,188	$	1,858	$	2,795	$	1,297

(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, 2019
			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	$	9,863	$	3,044	$	4,998	$	2,144	$	2,854	$	733	$	1,087	$	—
General	6,431		2,244		2,935		1,368		1,567		451		802		—
Industrial	3,071		1,215		934		675		259		147		774		—
Wholesale	2,212		462		1,468		1,281		187		46		235		—
Other revenues	770		276		548		317		231		80		89		—
Total Electric Utilities and Infrastructure revenue from contracts with customers	$	22,347	$	7,241	$	10,883	$	5,785	$	5,098	$	1,457	$	2,987	$	—

Gas Utilities and Infrastructure
Residential	$	976	$	—	$	—	$	—	$	—	$	315	$	—	$	661
Commercial	508		—		—		—		—		130		—		378
Industrial	141		—		—		—		—		19		—		122
Power Generation	—		—		—		—		—		—		—		51
Other revenues	129		—		—		—		—		19		—		110
Total Gas Utilities and Infrastructure revenue from contracts with customers	$	1,754	$	—	$	—	$	—	$	—	$	483	$	—	$	1,322

Commercial Renewables
Revenue from contracts with customers	$	223	$	—	$	—	$	—	$	—	$	—	$	—	$	—

Other
Revenue from contracts with customers	$	24	$	—	$	—	$	—	$	—	$	—	$	—	$	—

Total revenue from contracts with customers	$	24,348	$	7,241	$	10,883	$	5,785	$	5,098	$	1,940	$	2,987	$	1,322

Other revenue sources(a)	$	731	$	154	$	319	$	172	$	133	$	—	$	17	$	59
Total revenues	$	25,079	$	7,395	$	11,202	$	5,957	$	5,231	$	1,940	$	3,004	$	1,381

(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.

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.


	Years Ended December 31, 2020 and 2021
			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	54		27		25		11		14		—		—		7
Other Adjustments	(20)		13		(1)		(1)		1		—		—		5
Balance at December 31, 2021	$	122	$	42	$	36	$	21	$	16	$	4	$	3	$	15

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. Duke Energy considers receivables greater than 30 days outstanding past due.


	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)	$	964	$	316	$	266	$	193	$	73	$	4	$	27	$	106
0-30 days	2,104		595		800		405		393		42		51		202
30-60 days	212		77		72		44		28		4		13		12
60-90 days	88		37		41		21		20		1		1		2
90+ days	249		106		65		37		28		47		11		7
Deferred Payment Arrangements(c)	115		55		45		22		23		2		—		4
Trade and Other Receivables	$	3,732	$	1,186	$	1,289	$	722	$	565	$	100	$	103	$	333


	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
Unbilled Receivables(a)(b)	$	969	$	328	$	283	$	167	$	116	$	2	$	16	$	86
0-30 days	1,789		445		707		398		307		60		26		149
30-60 days	185		80		54		25		29		8		3		8
60-90 days	22		1		10		4		6		2		1		3
90+ days	119		16		32		9		23		30		12		9
Deferred Payment Arrangements(c)	215		96		80		52		28		—		—		7
Trade and Other Receivables	$	3,299	$	966	$	1,166	$	655	$	509	$	102	$	58	$	262

(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 17 for further information. These receivables for unbilled revenues are $82 million and $121 million for Duke Energy Ohio and Duke Energy Indiana, respectively, as of December 31, 2021, and $87 million and $134 million for Duke Energy Ohio and Duke Energy Indiana, respectively, as of December 31, 2020.

(c) Due to certain customer financial hardships created by the COVID-19 pandemic and resulting stay-at-home orders, Duke Energy permitted customers to defer payment of past-due amounts through an installment payment plan over a period of several months.

19. 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)	2021		2020		2019
Net Income available to Duke Energy common stockholders	$	3,802	$	1,377	$	—
Less: Income (Loss) from discontinued operations	7		7		(7)
Accumulated preferred stock dividends adjustment	—		1		(15)
Less: Impact of participating securities	4		2		5
Income from continuing operations available to Duke Energy common stockholders	$	3,791	$	1,369	$	(13)
Weighted average common shares outstanding – basic	769		737		729

Equity forwards	—		1		—
Weighted average common shares outstanding – diluted	769		738		729
EPS from continuing operations available to Duke Energy common stockholders
Basic and Diluted	$	4.93	$	1.71	$	5.07

Potentially dilutive items excluded from the calculation(a)	2		2		2
Dividends declared per common share	$	3.90	$	3.82	$	3.75
Dividends declared on Series A preferred stock per depositary share	$	1.437	$	1.437	$	1.03
Dividends declared on Series B preferred stock per share	$	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.

Common Stock

In November 2019, Duke Energy filed a prospectus supplement and executed an Equity Distribution Agreement (EDA) under which it may sell up to $1.5 billion of its common stock through a new at-the-market (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 2022.

Separately, in November 2019, Duke Energy marketed an equity offering of 28.75 million shares of common stock through an Underwriting Agreement. In connection with the offering, Duke Energy entered into equity forward sales agreements with an initial forward price of $85.99 per share. In March 2020, Duke Energy marketed approximately 940,000 shares of common stock through an equity forward transaction under the ATM with an initial forward price of $89.76 per share. In May 2020, Duke Energy marketed approximately 903,000 shares of common stock through an equity forward transaction under the ATM with an initial forward price of $82.44 per share. In August 2020, Duke Energy marketed approximately 936,000 shares of common stock through an equity forward transaction under the ATM with an initial forward price of $79.52 per share.

In December 2020, Duke Energy physically settled the equity forwards by delivering 32 million shares of common stock in exchange for net cash proceeds of approximately $2.6 billion.

Preferred Stock

On March 29, 2019, Duke Energy completed the issuance of 40 million depositary shares, each representing 1/1,000th share of its Series A Cumulative Redeemable Perpetual Preferred Stock, at a price of $25 per depositary share. The transaction resulted in net proceeds of $973 million after issuance costs with proceeds used for general corporate purposes and to reduce short-term debt. The preferred stock has a $25 liquidation preference per depositary share and earns dividends on a cumulative basis at a rate of 5.75% per annum. Dividends are payable quarterly in arrears on the 16th day of March, June, September and December, and began on June 16, 2019.

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.

On September 12, 2019, Duke Energy completed the issuance of 1 million shares of its Series B Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, at a price of $1,000 per share. The transaction resulted in net proceeds of $989 million after issuance costs with proceeds being used to pay down short-term debt, repay at maturity $500 million senior notes due September 2019, and for general corporate purposes. The preferred stock has a $1,000 liquidation preference per share and earns dividends on a cumulative basis at an initial rate of 4.875% per annum. Dividends are payable semiannually in arrears on the 16th day of March and September, and began on March 16, 2020. On September 16, 2024, the First Call Date, and any fifth anniversary of the First Call Date (each a Reset Date), the dividend rate will reset based on the then current five-year U.S. Treasury rate plus a spread of 3.388%.

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.

20. SEVERANCE

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 290 employees in 2021, 30 employees in 2020 and 140 employees in 2019, 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, 2021(a)(b)	$	69	$	33	$	26	$	20	$	6	$	2	$	3	$	2
Year Ended December 31, 2020(c)(d)	(85)		(58)		(28)		(31)		3		—		—		—
Year Ended December 31, 2019	16		8		6		3		3		—		1		1

(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 2018 severance charges of approximately $(3) million, $(2) million and $(1) million for Duke Energy, Duke Energy Carolinas and Duke Energy Indiana, respectively.

(c) 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.

(d) 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	$	—	$	—	$	—

21. 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 reserves 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)	2021		2020		2019
Duke Energy	$	64	$	61	$	65
Duke Energy Carolinas	23		22		24
Progress Energy	24		23		24
Duke Energy Progress	15		15		15
Duke Energy Florida	9		9		9
Duke Energy Ohio	5		4		5
Duke Energy Indiana	6		6		6
Piedmont	3		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)	2021		2020		2019
RSU awards	$	49	$	46	$	44
Performance awards	39		38		45

Pretax stock-based compensation cost	$	88	$	84	$	89
Stock-based compensation costs capitalized	5		5		5
Stock-based compensation expense	$	83	$	79	$	84
Tax benefit associated with stock-based compensation expense	$	19	$	18	$	19

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,
	2021		2020		2019
Shares granted (in thousands)	673		498		571
Fair value (in millions)	$	59	$	50	$	51

The following table summarizes information about RSU awards outstanding.


		Weighted Average
	Shares	Grant Date Fair Value
	(in thousands)	(per share)
Outstanding at December 31, 2020	939	$	93
Granted	673	88
Vested	(502)	89
Forfeited	(67)	92
Outstanding at December 31, 2021	1,043	92
RSU awards expected to vest	996	92

The total grant date fair value of shares vested during the years ended December 31, 2021, 2020 and 2019, was $45 million, $43 million and $49 million, respectively. At December 31, 2021, Duke Energy had $35 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 if 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 2021, the model used a risk-free interest rate of 0.24%, which reflects the yield on three-year Treasury bonds as of the grant date, and an expected volatility of 26.9% 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,
	2021		2020		2019
Shares granted assuming target performance (in thousands)	380		319		320
Fair value (in millions)	$	33	$	34	$	27

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, 2020	962	$	87
Granted	380	88


Vested	(346)	73
Forfeited	(44)	92
Outstanding at December 31, 2021	952	93
Stock-based performance awards expected to vest	927	93

The total grant date fair value of shares vested during the years ended December 31, 2021, and 2020, was $25 million and $36 million, respectively. At December 31, 2021, Duke Energy had $20 million of unrecognized compensation cost, which is expected to be recognized over a weighted average period of 22 months.

22. 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. The Duke Energy 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 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. Actuarial gains experienced by the defined benefit retirement plans in remeasuring plan assets as of December 31, 2020, were attributable to actual investment performance that exceeded expected investment performance. Actuarial losses experienced by the defined benefit retirement plans in remeasuring plan obligations as of December 31, 2020, were primarily attributable to the decrease in the discount rate used to measure plan obligations.

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 13.

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. Duke Energy does not anticipate making any contributions in 2022. The following table includes information related to the Duke Energy Registrants’ contributions to its qualified defined benefit pension plans.


			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont




Contributions Made:
2021	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
2020	—		—		—		—		—		—		—		—
2019	77		7		57		4		53		2		2		1

QUALIFIED PENSION PLANS

Components of Net Periodic Pension Costs


	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	18		9		7		6		1		—		1		1

Net periodic pension costs(a)(b)	$	(24)	$	(3)	$	(12)	$	—	$	(11)	$	(2)	$	—	$	(5)


	Year Ended December 31, 2019
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Service cost	$	158	$	49	$	46	$	26	$	20	$	4	$	9	$	5
Interest cost on projected benefit obligation	317		75		100		45		54		18		26		10
Expected return on plan assets	(567)		(147)		(178)		(88)		(89)		(28)		(43)		(22)
Amortization of actuarial loss	108		24		39		15		24		4		8		8
Amortization of prior service credit	(32)		(8)		(3)		(2)		(1)		—		(2)		(9)
Amortization of settlement charge	6		2		1		1		—		2		—		—

Net periodic pension costs(a)(b)	$	(10)	$	(5)	$	5	$	(3)	$	8	$	—	$	(2)	$	(8)

(a) Duke Energy amounts exclude $3 million, $4 million and $4 million for the years ended December 2021, 2020 and 2019, 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, $2 million and $2 million for the years ended December 2021, 2020 and 2019, 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, 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)	$	—	$	—	$	—	$	—	$	—


	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
Regulatory assets, net (decrease) increase	$	(62)	$	(39)	$	(26)	$	(30)	$	4	$	(2)	$	5	$	(1)
Accumulated other comprehensive loss (income)
Deferred income tax expense	$	2	$	—	$	1	$	—	$	1	$	—	$	—	$	—

Amortization of prior year service credit	1		—		—		—		—		—		—		—
Amortization of prior year actuarial losses	(11)		—		(1)		—		(3)		—		—		—


Net amount recognized in accumulated other comprehensive income	$	(8)	$	—	$	—	$	—	$	(2)	$	—	$	—	$	—

Reconciliation of Funded Status to Net Amount Recognized


	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


	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
Change in Projected Benefit Obligation
Obligation at prior measurement date	$	8,321	$	1,923	$	2,608	$	1,170	$	1,424	$	481	$	693	$	292

Service cost	157		49		46		26		20		4		8		5
Interest cost	269		62		85		38		46		15		22		9
Actuarial loss	433		83		144		50		93		21		46		14
Benefits paid	(541)		(137)		(160)		(83)		(76)		(34)		(49)		(27)
Benefits paid – settlements	(5)		—		—		—		—		—		(5)		—
Transfers	—		8		(8)		(8)		—		15		—		—
Obligation at measurement date	$	8,634	$	1,988	$	2,715	$	1,193	$	1,507	$	502	$	715	$	293
Accumulated Benefit Obligation at measurement date	$	8,577	$	1,989	$	2,684	$	1,194	$	1,476	$	493	$	709	$	294
Change in Fair Value of Plan Assets
Plan assets at prior measurement date	$	8,910	$	2,263	$	2,898	$	1,364	$	1,515	$	443	$	667	$	335


Actual return on plan assets	973		247		319		149		166		48		71		35
Benefits paid	(541)		(137)		(160)		(83)		(76)		(34)		(49)		(27)
Benefits paid – settlements	(5)		—		—		—		—		—		(5)		—
Transfers	—		8		(8)		(8)		—		15		—		—

Plan assets at measurement date	$	9,337	$	2,381	$	3,049	$	1,422	$	1,605	$	472	$	684	$	343
Funded status of plan	$	703	$	393	$	334	$	229	$	98	$	(30)	$	(31)	$	50

Amounts Recognized in the Consolidated Balance Sheets


	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	$	—	$	—	$	—	$	—	$	—


	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
Prefunded pension(a)	$	780	$	393	$	379	$	229	$	143	$	58	$	79	$	50
Noncurrent pension liability(b)	$	77	$	—	$	45	$	—	$	45	$	88	$	110	$	—
Net asset (liability) recognized	$	703	$	393	$	334	$	229	$	98	$	(30)	$	(31)	$	50
Regulatory assets	$	1,910	$	381	$	691	$	283	$	408	$	110	$	209	$	80
Accumulated other comprehensive (income) loss
Deferred income tax benefit	$	(21)	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Prior service credit	(2)		—		—		—		—		—		—		—
Net actuarial loss	100		—		2		—		—		—		—		—
Net amounts recognized in accumulated other comprehensive loss	$	77	$	—	$	2	$	—	$	—	$	—	$	—	$	—

(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, 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


	December 31, 2020
					Duke		Duke		Duke
	Duke		Progress		Energy		Energy		Energy
(in millions)	Energy		Energy		Florida		Ohio		Indiana
Projected benefit obligation	$	4,914	$	828	$	828	$	184	$	293
Accumulated benefit obligation	4,856		796		796		176		285
Fair value of plan assets	4,837		783		783		96		183

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 14 years for Duke Energy, Duke Energy Progress and Duke Energy Ohio, 15 years for Progress Energy and Duke Energy Florida, 13 years for Duke Energy Carolinas and Duke Energy Indiana and nine years for Piedmont.

The following tables present the assumptions or range of assumptions used for pension benefit accounting.


	December 31,
	2021				2020				2019
Benefit Obligations
Discount rate				2.90%				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%
Net Periodic Benefit Cost
Discount rate				2.60%				3.30%				4.30%
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%				6.85%				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,
2022	$	652	$	174	$	177	$	95	$	81	$	37	$	48	$	27
2023	653		173		180		97		82		36		48		24
2024	645		171		181		96		84		35		47		23
2025	632		168		180		94		85		34		47		20
2026	605		155		176		90		86		33		45		21
2027-2031	2,705		655		818		389		426		149		218		85

NON-QUALIFIED PENSION PLANS

The accumulated benefit obligation, which equals the projected benefit obligation for non-qualified pension plans, was $300 million for Duke Energy, $12 million for Duke Energy Carolinas, $104 million for Progress Energy, $31 million for Duke Energy Progress, $41 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, 2021.

Employer contributions, which equal benefits paid for non-qualified pension plans, were $24 million for Duke Energy, $1 million for Duke Energy Carolinas, $8 million for Progress Energy, $3 million for Duke Energy Progress and $3 million for Duke Energy Florida for the year ended December 31, 2021. Employer contributions were not material for Duke Energy Ohio, Duke Energy Indiana or Piedmont for the year ended December 31, 2021.

Net periodic pension costs for non-qualified pension plans were not material for the years ended December 31, 2021, 2020 or 2019.

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, 2021, 2020 or 2019.

Components of Net Periodic Other Post-Retirement Benefit Costs


	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)


	Year Ended December 31, 2019
			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	$	—	$	1	$	—
Interest cost on accumulated post-retirement benefit obligation	30		7		12		7		5		1		3		1
Expected return on plan assets	(12)		(7)		—		—		—		—		—		(1)
Amortization of actuarial loss	4		2		1		—		1		—		4		—
Amortization of prior service credit	(19)		(5)		(8)		(1)		(7)		(1)		(1)		(2)

Net periodic post-retirement benefit costs(a)(b)	$	7	$	(2)	$	6	$	6	$	—	$	—	$	7	$	(2)

(a) Duke Energy amounts exclude $5 million, $6 million and $6 million for the years ended December 2021, 2020 and 2019, 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 2021, 2020 and 2019, 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, 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)	$	—	$	—	$	—	$	—	$	—	$	—	$	—


	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
Regulatory assets, net increase (decrease)	$	9	$	—	$	9	$	6	$	3	$	—	$	(4)	$	—
Regulatory liabilities, net decrease	$	(10)	$	(7)	$	—	$	—	$	—	$	—	$	(1)	$	—
Accumulated other comprehensive (income) loss

Amortization of prior year service credit	$	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, 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


	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
Change in Projected Benefit Obligation
Accumulated post-retirement benefit obligation at prior measurement date	$	723	$	175	$	303	$	168	$	135	$	29	$	64	$	30

Service cost	4		1		1		—		—		—		1		—
Interest cost	23		5		10		5		4		1		2		1
Plan participants' contributions	15		3		5		3		2		1		2		—
Actuarial losses	19		8		8		5		2		—		1		1

Benefits paid	(75)		(18)		(28)		(15)		(13)		(4)		(9)		(2)
Accumulated post-retirement benefit obligation at measurement date	$	709	$	174	$	299	$	166	$	130	$	27	$	61	$	30
Change in Fair Value of Plan Assets
Plan assets at prior measurement date	$	220	$	130	$	(1)	$	(1)	$	—	$	9	$	5	$	34

Actual return on plan assets	24		14		—		—		—		—		1		4
Benefits paid	(75)		(18)		(28)		(15)		(13)		(4)		(9)		(2)

Employer contributions	53		10		23		11		10		3		8		1
Plan participants' contributions	15		3		5		3		2		1		2		—
Plan assets at measurement date	$	237	$	139	$	(1)	$	(2)	$	(1)	$	9	$	7	$	37
Funded status of plan	$	(472)	$	(35)	$	(300)	$	(168)	$	(131)	$	(18)	$	(54)	$	7

Amounts Recognized in the Consolidated Balance Sheets


	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)	$	—	$	—	$	—	$	—	$	—	$	—	$	—


	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
Prefunded post-retirement benefit	$	8	$	—	$	—	$	—	$	—	$	1	$	—	$	7
Current post-retirement liability(a)	9		—		6		4		2		2		—		—
Noncurrent post-retirement liability(b)	471		35		294		164		129		17		54		—
Net liability (asset) recognized	$	472	$	35	$	300	$	168	$	131	$	18	$	54	$	(7)
Regulatory assets	$	144	$	—	$	144	$	88	$	56	$	—	$	32	$	—
Regulatory liabilities	$	139	$	32	$	—	$	—	$	—	$	17	$	62	$	3
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)	$	—	$	—	$	—	$	—	$	—	$	—	$	—

(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 four years for Duke Energy, seven years for Duke Energy Florida, six years for Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Indiana and Piedmont and five years for Duke Energy Ohio.

The following tables present the assumptions used for other post-retirement benefits accounting.


	December 31,
	2021		2020		2019
Benefit Obligations
Discount rate	2.90	%	2.60	%	3.30	%
Net Periodic Benefit Cost
Discount rate	2.60	%	3.30	%	4.30	%
Expected long-term rate of return on plan assets	6.50	%	6.85	%	6.85	%

Assumed Health Care Cost Trend Rate


	December 31,
	2021		2020
Health care cost trend rate assumed for next year	6.25	%	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	2028		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,
2022	$	70	$	17	$	26	$	15	$	12	$	3	$	7	$	2
2023	62		15		25		14		11		3		6		2
2024	58		14		23		13		11		3		6		2
2025	54		13		22		12		10		2		5		2
2026	50		12		21		12		9		2		5		2
2027-2031	207		50		87		49		38		8		19		10

PLAN ASSETS

Description and Allocations

Duke Energy Master Retirement Trust

Assets for both the qualified pension and other post-retirement benefits are maintained in the Duke Energy Master Retirement Trust. Approximately 98% of the Duke Energy 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, 2021, and 2020. The investment objective of the Duke Energy 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, 2021, Duke Energy assumes pension and other post-retirement plan assets will generate a long-term rate of return of 6.5%. 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, 2022, the target asset allocation for the Duke Energy Retirement Master Trust is 60% liability hedging assets and 40% 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 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 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 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 Master Retirement Trust to sell the securities. The Duke Energy 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 $542 million and $482 million at December 31, 2021, and 2020, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned at December 31, 2021, and 2020, respectively. Securities lending income earned by the Duke Energy Master Retirement Trust was immaterial for the years ended December 31, 2021, 2020 and 2019, respectively.

Qualified pension and other post-retirement benefits for the Subsidiary Registrants are derived from the Duke Energy 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, 2021, and the actual asset allocations for the Duke Energy Master Retirement Trust.


			Actual Allocation at
	Target		December 31,

	Allocation		2021		2020


Global equity securities	27	%	24	%	30	%
Global private equity securities	1	%	1	%	1	%
Debt securities	62	%	62	%	55	%
Return seeking debt securities	4	%	4	%	5	%
Hedge funds	2	%	3	%	3	%
Real estate and cash	4	%	6	%	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 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, 2021.


			Actual Allocation at
	Target		December 31,
	Allocation		2021		2020
U.S. equity securities	30	%	19	%	36	%
Non-U.S. equity securities	5	%	5	%	6	%
Real estate	2	%	3	%	2	%
Debt securities	45	%	18	%	42	%
Cash	18	%	55	%	14	%
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 16.

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 Master Retirement Trust

The following tables provide the fair value measurement amounts for the Duke Energy Master Retirement Trust qualified pension and other post-retirement assets.


	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 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.


	December 31, 2020
	Total Fair								Not
(in millions)	Value		Level 1		Level 2		Level 3		Categorized(b)
Equity securities	$	3,202	$	3,162	$	—	$	—	$	40
Corporate debt securities	4,162		—		4,162		—		—
Short-term investment funds	397		247		150		—		—
Partnership interests	97		—		—		—		97
Hedge funds	198		—		—		—		198

U.S. government securities	1,164		—		1,164		—		—

Governments bonds – foreign	73		—		73		—		—
Cash	98		98		—		—		—

Net pending transactions and other investments	88		34		54		—		—
Total assets(a)	$	9,479	$	3,541	$	5,603	$	—	$	335

(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 Master Retirement Trust at December 31, 2020. 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 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)	2021		2020
Balance at January 1	$	—	$	11



Sales	—		(12)
Total gains and other, net	—		1
Transfer of Level 3 assets from other classifications	95		—
Balance at December 31	$	95	$	—

Other post-retirement assets

The following tables provide the fair value measurement amounts for VEBA trust assets.


	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


	December 31, 2020
	Total Fair
(in millions)	Value		Level 2
Cash and cash equivalents	$	5	$	5
Real estate	1		1
Equity securities	23		23
Debt securities	19		19
Total assets	$	48	$	48

EMPLOYEE SAVINGS PLANS

Retirement Savings Plan

Duke Energy or its affiliates sponsor, 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,
2021	$	229	$	70	$	60	$	39	$	21	$	5	$	12	$	11
2020	213		67		57		38		19		5		11		13
2019	214		66		58		38		20		5		11		13

23. INCOME TAXES

North Carolina's 2021 Appropriations Act

On November 18, 2021, North Carolina Senate Bill 105 (SB 105) was signed into law by Governor Roy Cooper. 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 is an emergency economic stimulus package in response to the COVID-19 pandemic. Among other provisions, the CARES Act accelerates the remaining AMT credit refund allowances resulting in taxpayers being able to immediately claim a refund in full for any AMT credit carryforwards and 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 do not materially impact Duke Energy's income tax accounting.

Income Tax Expense

Components of Income Tax Expense


	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	2		23		(4)		8		(17)		(2)		7		3
Foreign	2		—		—		—		—		—		—		—
Total current income taxes	2		264		(19)		121		(92)		(10)		72		26
Deferred income taxes
Federal	199		(130)		203		(16)		202		35		19		17
State	(1)		(79)		47		(26)		77		5		16		(13)

Total deferred income taxes(a)	198		(209)		250		(42)		279		40		35		4
ITC amortization	(8)		(4)		(4)		(4)		—		—		—		—


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 $150 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	(9)		35		29		17		24		1		7		(8)
Foreign	1		—		—		—		—		—		—		—
Total current income taxes	(289)		349		309		198		172		11		55		(35)
Deferred income taxes
Federal	155		(171)		(167)		(180)		1		30		12		60
State	(92)		(86)		(24)		(49)		25		2		17		(7)

Total deferred income taxes(a)	63		(257)		(191)		(229)		26		32		29		53
ITC amortization	(10)		(4)		(5)		(5)		—		—		—		—
Income tax (benefit) expense from continuing operations	(236)		88		113		(36)		198		43		84		18
Tax expense from discontinued operations	2		—		—		—		—		—		—		—
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 $79 million at Duke Energy.


	Year Ended December 31, 2019
			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	$	(299)	$	164	$	(173)	$	(36)	$	(43)	$	(41)	$	(23)	$	(92)
State	10		13		(7)		(3)		18		(1)		1		(1)
Foreign	2		—		—		—		—		—		—		—
Total current income taxes	(287)		177		(180)		(39)		(25)		(42)		(22)		(93)
Deferred income taxes
Federal	855		175		422		220		153		77		128		133
State	(38)		(37)		17		(18)		27		5		28		3

Total deferred income taxes(a)	817		138		439		202		180		82		156		136
ITC amortization	(11)		(4)		(6)		(6)		—		—		—		—
Income tax expense from continuing operations	519		311		253		157		155		40		134		43
Tax benefit from discontinued operations	(2)		—		—		—		—		—		—		—
Total income tax expense included in Consolidated Statements of Operations	$	517	$	311	$	253	$	157	$	155	$	40	$	134	$	43

(a) Total deferred income taxes includes the generation of tax credit carryforwards of $8 million at Duke Energy Carolinas. In addition, total deferred income taxes includes utilization of NOL carryforwards and tax credit carryforwards of $243 million at Progress Energy, $35 million at Duke Energy Progress, $152 million at Duke Energy Florida, $25 million at Duke Energy Ohio, $60 million at Duke Energy Indiana, $90 million at Piedmont and $775 million at Duke Energy.

Duke Energy Income from Continuing Operations before Income Taxes


	Years Ended December 31,
(in millions)	2021		2020		2019
Domestic	$	3,720	$	826	$	4,053
Foreign	44		13		44
Income from continuing operations before income taxes	$	3,764	$	839	$	4,097

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, 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%	$	790		$	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			—
Noncontrolling Interests	72			—			—			—			—			—			—			—
Renewable energy PTCs	(100)			—			—			—			—			—			—			—
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	$	192		$	51		$	227		$	75		$	187		$	30		$	107		$	30
Effective tax rate	5.1		%	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 segment.


	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%	$	176		$	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			—
Noncontrolling Interests	62			—			—			—			—			—			—			—
Renewable energy PTCs	(110)			—			—			—			—			—			—			—
Other tax credits	(37)			(13)			(16)			(14)			(2)			(1)			(3)			(2)
Tax true up	(12)			(3)			1			(5)			5			—			(1)			1


Other items, net	(14)			1			(2)			(3)			(1)			1			2			1
Income tax (benefit) expense from continuing operations	$	(236)		$	88		$	113		$	(36)		$	198		$	43		$	84		$	18
Effective tax rate	(28.1)		%	8.4		%	9.7		%	(9.5)		%	20.4		%	14.6		%	17.1		%	6.2		%


	Year Ended December 31, 2019
				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%	$	860		$	360		$	332		$	202		$	178		$	59		$	120		$	51
State income tax, net of federal income tax effect	(22)			(19)			8			(17)			35			3			22			2
Amortization of excess deferred income tax	(121)			(29)			(64)			(10)			(54)			(12)			(6)			(10)
AFUDC equity income	(52)			(9)			(14)			(13)			(1)			(3)			(3)			—
AFUDC equity depreciation	34			19			10			5			5			1			4			—
Renewable energy PTCs	(120)			—			—			—			—			—			—			—
Other tax credits	(23)			(11)			(9)			(7)			(2)			(1)			(1)			(1)
Tax true up	(64)			(9)			(8)			(3)			(5)			(7)			(1)			—
Other items, net	27			9			(2)			—			(1)			—			(1)			1
Income tax expense from continuing operations	$	519		$	311		$	253		$	157		$	155		$	40		$	134		$	43
Effective tax rate	12.7		%	18.1		%	16.0		%	16.3		%	18.3		%	14.3		%	23.5		%	17.6		%

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


	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.

The following table presents the expiration of tax credits and NOL carryforwards.


	December 31, 2021
(in millions)	Amount		Expiration Year
General Business Credits	$	2,312	2024	—	2041
Federal NOL carryforwards(a)	4		2024	—	2026
State carryforwards and credits(b) (e)	328		2022	—	Indefinite
Foreign NOL carryforwards(c)	12		2027	—	2037
Foreign Tax Credits(d)	1,128		2024	—	2027
Total tax credits and NOL carryforwards	$	3,784

(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 $112 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 $390 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, 2020
			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	$	286	$	85	$	87	$	67	$	18	$	21	$	7	$	38
Lease obligations	515		96		208		120		87		5		16		5
Pension, post-retirement and other employee benefits	236		(30)		68		24		38		16		26		(5)
Progress Energy merger purchase accounting adjustments(a)	441		—		—		—		—		—		—		—
Tax credits and NOL carryforwards	3,909		285		508		179		282		16		183		29
Regulatory liabilities and deferred credits	—		11		—		—		—		18		—		—
Investments and other assets	—		—		—		—		—		7				—
Other	93		8		14		9		4		7		1		8
Valuation allowance	(586)		—		—		—		—		—		—		—
Total deferred income tax assets	4,894		455		885		399		429		90		233		75
Investments and other assets	(2,267)		(1,127)		(669)		(507)		(164)		—		(14)		(48)
Accelerated depreciation rates	(10,729)		(3,170)		(3,868)		(1,778)		(2,124)		(1,071)		(1,433)		(844)
Regulatory assets and deferred debits, net	(1,142)		—		(744)		(412)		(332)		—		(14)		(4)

Total deferred income tax liabilities	(14,138)		(4,297)		(5,281)		(2,697)		(2,620)		(1,071)		(1,461)		(896)
Net deferred income tax liabilities	$	(9,244)	$	(3,842)	$	(4,396)	$	(2,298)	$	(2,191)	$	(981)	$	(1,228)	$	(821)

(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, 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


	Year Ended December 31, 2019
			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	$	24	$	6	$	9	$	6	$	3	$	1	$	1	$	4

Unrecognized tax benefits increases	105		2		1		1		—		—		—		—
Gross decreases – tax positions in prior periods	(3)		—		(1)		(1)		—		—		—		—





Total changes	102		2		—		—		—		—		—		—
Unrecognized tax benefits – December 31	$	126	$	8	$	9	$	6	$	3	$	1	$	1	$	4

The following table includes additional information regarding the Duke Energy Registrants' unrecognized tax benefits at December 31, 2021. Duke Energy Registrants do not anticipate a material increase or decrease in unrecognized tax benefits within the next 12 months.


	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
Amount that if recognized, would affect the effective tax rate or regulatory liability(a)	$	47	$	13	$	14	$	10	$	4	$	1	$	2	$	4

(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.

24. 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, 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	$	16	$	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	417		180		140		87		53		6		8		16
Other income and expense, net	$	643	$	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	$	32	$	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	$	453	$	177	$	129	$	75	$	53	$	16	$	37	$	51


	Year Ended December 31, 2019
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana		Piedmont
Interest income	$	31	$	1	$	11	$	—	$	11	$	10	$	10	$	1
AFUDC equity	139		42		66		60		6		13		18		—
Post in-service equity returns	29		20		7		7		—		1		—		—
Nonoperating income, other	231		88		57		33		31		—		13		19
Other income and expense, net	$	430	$	151	$	141	$	100	$	48	$	24	$	41	$	20

25. SUBSEQUENT EVENTS

For information on subsequent events related to regulatory matters and commitments and contingencies, see Notes 3 and 4, respectively.

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	5,742,901	362,027					5,380,874
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income
3	Preceding Quarter/Year to Date Changes in Fair Value	72,806	979,604					1,052,410
4	Total (lines 2 and 3)	72,806	979,604					1,052,410	770,836,654	769,784,244
5	Balance of Account 219 at End of Preceding Quarter/Year	5,670,095	1,341,631					4,328,464
6	Balance of Account 219 at Beginning of Current Year	5,670,095	1,341,631					4,328,464
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income
8	Current Quarter/Year to Date Changes in Fair Value	354,332	411,295					765,627
9	Total (lines 7 and 8)	354,332	411,295					765,627	737,876,273	737,110,646
10	Balance of Account 219 at End of Current Quarter/Year	5,315,763	1,752,926					3,562,837

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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)	18,633,082,384	18,630,551,144		(b) 2,531,240
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	(a) 404,021,328	404,021,328
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified	3,612,562,802	3,612,562,802
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	22,649,666,514	22,647,135,274		2,531,240
9	UtilityPlantLeasedToOthers Leased to Others
10	UtilityPlantHeldForFutureUse Held for Future Use	137,128,357	137,128,357
11	ConstructionWorkInProgress Construction Work in Progress	1,342,670,129	1,342,670,129
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments	20,325,435	20,325,435
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	24,149,790,436	24,147,259,196		2,531,240
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	5,860,668,965	5,858,222,578		2,446,387
15	UtilityPlantNet Net Utility Plant (13 less 14)	18,289,121,471	18,289,036,618		84,853
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	5,677,758,162	5,677,758,162
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	176,539,527	174,093,140		2,446,387
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	5,854,297,689	5,851,851,302		2,446,387
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	6,371,276	6,371,276
33	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Total Accum Prov (equals 14) (22,26,30,31,32)	5,860,668,965	5,858,222,578		2,446,387

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: UtilityPlantInServicePropertyUnderCapitalLeases

University of Florida Cogen Asset

(b) Concept: UtilityPlantInServiceClassified

Property Under Capital Leases includes Capital and Operating Leases. Net Capital leases $102,280,770 and Net Operating Leases $301,740,558

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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
3	Nuclear Materials
4	Allowance for Funds Used during Construction
5	(Other Overhead Construction Costs, provide details in footnote)
6	SUBTOTAL (Total 2 thru 5)
7	Nuclear Fuel Materials and Assemblies
8	In Stock (120.2)
9	In Reactor (120.3)
10	SUBTOTAL (Total 8 & 9)
11	Spent Nuclear Fuel (120.4)
12	Nuclear Fuel Under Capital Leases (120.6)
13	(Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5)
14	TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13)
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 Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	8,450,028					8,450,028
4	(303) Miscellaneous Intangible Plant	342,661,166	97,827,439	105,979,121		2,415,584	336,925,068
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)	351,111,194	97,827,439	105,979,121		2,415,584	345,375,096
6	2. PRODUCTION PLANT
7	A. Steam Production Plant
8	(310) Land and Land Rights	3,551,805					3,551,805
9	(311) Structures and Improvements	507,803,815	6,923,357	824,336			513,902,836
10	(312) Boiler Plant Equipment	1,968,090,208	6,281,926	4,212,689			1,970,159,445
11	(313) Engines and Engine-Driven Generators
12	(314) Turbogenerator Units	505,215,067	5,017,709	1,079,597			509,153,179
13	(315) Accessory Electric Equipment	225,576,648	3,400,761	1,860,118			227,117,291
14	(316) Misc. Power Plant Equipment	49,953,462	2,147,096	586,269			51,514,289
15	(317) Asset Retirement Costs for Steam Production	21,006,765	10,023,995				31,030,760
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)	3,281,197,770	33,794,844	8,563,009			3,306,429,605
17	B. Nuclear Production Plant
18	(320) Land and Land Rights
19	(321) Structures and Improvements
20	(322) Reactor Plant Equipment
21	(323) Turbogenerator Units
22	(324) Accessory Electric Equipment
23	(325) Misc. Power Plant Equipment
24	(326) Asset Retirement Costs for Nuclear Production
25	TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26	C. Hydraulic Production Plant
27	(330) Land and Land Rights
28	(331) Structures and Improvements
29	(332) Reservoirs, Dams, and Waterways
30	(333) Water Wheels, Turbines, and Generators
31	(334) Accessory Electric Equipment
32	(335) Misc. Power Plant Equipment
33	(336) Roads, Railroads, and Bridges
34	(337) Asset Retirement Costs for Hydraulic Production
35	TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)
36	D. Other Production Plant
37	(340) Land and Land Rights	39,719,458	839,521				38,879,937
38	(341) Structures and Improvements	451,520,951	40,265,349	2,030,848			489,755,452
39	(342) Fuel Holders, Products, and Accessories	374,045,524	24,409,182	900,955			397,553,751
40	(343) Prime Movers	2,872,426,780	122,242,231	46,365,653			2,948,303,358
41	(344) Generators	797,445,516	207,312,740	10,729,519			994,028,737
42	(345) Accessory Electric Equipment	429,109,483	69,519,826	1,227,378			497,401,931
43	(346) Misc. Power Plant Equipment	79,067,827	4,925,283	174,446			73,968,098
44	(347) Asset Retirement Costs for Other Production	16,263,428	6,043,831				22,307,259
44.1	(348) Energy Storage Equipment - Production
45	TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)	5,059,598,967	464,028,355	61,428,799			5,462,198,523
46	TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)	8,340,796,737	497,823,199	69,991,808			8,768,628,128
47	3. Transmission Plant
48	(350) Land and Land Rights	132,717,563	28,111,269	641		322,289	161,150,480
48.1	(351) Energy Storage Equipment - Transmission
49	(352) Structures and Improvements	38,324,617	54,513,530	779,141		1,551,038	93,610,044
50	(353) Station Equipment	1,506,279,925	336,664,972	54,833,737		71,442,747	1,859,553,907
51	(354) Towers and Fixtures	79,630,744	1,716,618	98,681			81,248,681
52	(355) Poles and Fixtures	1,446,459,503	290,235,030	12,125,725		13,407,618	1,737,976,426
53	(356) Overhead Conductors and Devices	734,008,121	85,369,386	8,785,017		2,960,132	813,552,622
54	(357) Underground Conduit	41,950,833	337,929	608,486			41,680,276
55	(358) Underground Conductors and Devices	87,807,931	3,349,497				84,458,434
56	(359) Roads and Trails	49,871,006					49,871,006
57	(359.1) Asset Retirement Costs for Transmission Plant
58	TOTAL Transmission Plant (Enter Total of lines 48 thru 57)	4,117,050,243	793,599,237	77,231,428		89,683,824	4,923,101,876
59	4. Distribution Plant
60	(360) Land and Land Rights	112,661,235	4,347,848	235,036		322,289	116,451,758
61	(361) Structures and Improvements	39,808,548	4,823,296	24,833		1,516,168	33,493,917
62	(362) Station Equipment	1,248,284,609	125,815,637	14,823,256		70,105,427	1,289,171,563
63	(363) Energy Storage Equipment – Distribution
64	(364) Poles, Towers, and Fixtures	893,756,062	13,586,927	4,688,252		612,459	874,868,424
65	(365) Overhead Conductors and Devices	1,039,471,536	121,465,283	19,508,073		11,510,898	1,129,917,848
66	(366) Underground Conduit	366,146,985	48,690,340	897,687			413,939,638
67	(367) Underground Conductors and Devices	1,078,256,609	184,836,773	12,120,881		1,506,595	1,249,465,906
68	(368) Line Transformers	917,997,181	42,736,868	13,096,516		3,937,720	943,699,813
69	(369) Services	553,111,903	52,077,005	23,383,265		15,063	581,790,580
70	(370) Meters	328,922,441	15,559,479	4,847,043		137,187	339,497,690
71	(371) Installations on Customer Premises	19,545,660	861,133	3,861,679		115,805	16,429,309
72	(372) Leased Property on Customer Premises
73	(373) Street Lighting and Signal Systems	527,271,291	55,503,634	14,241,980			568,532,945
74	(374) Asset Retirement Costs for Distribution Plant
75	TOTAL Distribution Plant (Enter Total of lines 60 thru 74)	7,125,234,060	633,483,777	111,678,835		89,779,611	7,557,259,391
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	19,467,979	2,016,813	183			17,450,983
87	(390) Structures and Improvements	253,639,626	23,664,988	1,607,843		34,869	278,877,588
88	(391) Office Furniture and Equipment	66,321,408	20,963,679	3,048,924			84,236,163
89	(392) Transportation Equipment	66,728,275	79,075				66,807,350
90	(393) Stores Equipment	5,078,774	262,455	581,650			4,234,669
91	(394) Tools, Shop and Garage Equipment	67,433,223	8,351,715	2,434,448			73,350,490
92	(395) Laboratory Equipment
93	(396) Power Operated Equipment	14,039,137	2,171,247				16,210,384
94	(397) Communication Equipment	88,874,844	17,303,111	9,486,316			96,691,639
95	(398) Miscellaneous Equipment	8,114,632	1,590,117	919,453		130,655	8,915,951
96	SUBTOTAL (Enter Total of lines 86 thru 95)	589,697,898	71,844,664	14,863,131		95,786	646,775,217
97	(399) Other Tangible Property
98	(399.1) Asset Retirement Costs for General Plant	1,974,238					1,974,238
99	TOTAL General Plant (Enter Total of lines 96, 97, and 98)	591,672,136	71,844,664	14,863,131		95,786	648,749,455
100	TOTAL (Accounts 101 and 106)	20,525,864,370	2,094,578,316	379,744,323		2,415,583	22,243,113,946
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)	20,525,864,370	2,094,578,316	379,744,323		2,415,583	22,243,113,946

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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 Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	Elec - Distribution Plant
3	CENTRAL FLORIDA SOUTH SUBSTATION	06/01/2012	01/31/2022	6,421,115
4	ZEPHYRHILLS NORTH SUBSTATION - PASCO, FL	11/01/2015	12/31/2025	2,087,816
5	JASPER SOUTH SUBSTATION - HAMILTON COUNTY	04/01/2018	01/31/2022	474,490
6	BELCHER ROAD SUBSTATION	05/01/1996	12/31/2024	267,012
7	Elec - General Plant
8	(a) LYBASSEE PROPERTY - LEVY, FL	12/01/2007	12/31/2033	27,667,950
9	WILDWOOD TRANSMISSION TRAINING CENTER	04/01/2021	12/31/2027	2,016,804
10	WILDWOOD TRANSMISSION MOBILE STORAGE - SUMTER, FL	06/01/2019	12/31/2026	1,445,507
11	(b) Elec - Nuclear Production Plant
12	(c) LEVY GENERATION LAND - LEVY, FL	01/01/2013	12/31/2033	66,404,373
13	LEVY BARGE SLIP EASEMENT - LEVY, FL	05/01/2021	12/31/2033	395,833
14	Elec - Other Production Plant
15	HIGGINS LAND - PINELLAS, FL	12/01/2019	12/31/2025	1,359,138
16	TURNER PEAKING COMMON - VOLUSIA, FL	06/01/2016	12/31/2023	824,781
17	SUWANNEE LAND - SUWANNEE, FL	12/01/2009	12/31/2022	701,045
18	Elec - Steam Production Plant
19	CRYSTAL RIVER LAND - CITRUS, FL	06/01/2019	12/31/2026	2,522,029
20	Elec - Transmission Plant
21	LEVY TRANSMISSION LAND - LEVY, FL	01/01/2013	12/31/2033	16,273,381
22	HIGH SPRINGS - JASPER - FLORIDA STATE LINE	03/01/1996	12/31/2033	2,584,486
23	PERRY - FLORIDA STATE LINE	12/01/1992	12/31/2033	1,808,764
24	PERRY - CROSS CITY - DUNNELLON	06/01/1987	12/31/2033	1,046,211
25	SUWANNEE TRANSMISSION LAND - HAMILTON, FL	11/01/2015	12/31/2029	978,408
26	PERRY CONTROL HOUSE - TAYLOR, FL	07/01/1990	12/31/2033	752,861
27	Other Land and Land Rights <$250K Each (11 Items)			1,096,354
21	Other Property:
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			137,128,357

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: ElectricPlantHeldForFutureUseDescription

Per DEF's Stipulation and Settlement Agreement that was approved by the Florida Public Service Commission dated January 20, 2012, Order No. PSC-12-0104-FOF-EI, DEF was allowed to transfer the land investments previously included in the Nuclear Cost Recovery Clause to base rate FERC account 105 "Plant Held for Future Use" effective 1/1/2013.

(b) Concept: ElectricPlantHeldForFutureUseDescription

Per DEF's Stipulation and Settlement Agreement that was approved by the Florida Public Service Commission dated January 20, 2012, Order No. PSC-12-0104-FOF-EI, DEF was allowed to transfer the land investments previously included in the Nuclear Cost Recovery Clause to base rate FERC account 105 "Plant Held for Future Use" effective 1/1/2013.

(c) Concept: ElectricPlantHeldForFutureUseDescription

Per DEF's Stipulation and Settlement Agreement that was approved by the Florida Public Service Commission dated January 20, 2012, Order No. PSC-12-0104-FOF-EI, DEF was allowed to transfer the land investments previously included in the Nuclear Cost Recovery Clause to base rate FERC account 105 "Plant Held for Future Use" effective 1/1/2013.

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	DEF TARGETED OVERHEAD/UNDERGROUND CONVERSION	29,481,070
3	DISTRIBUTION OVERHEAD/UNDERGROUND LINE IMPROVEMENTS	24,656,914
4	SMART GRIND DEF SEGMENTATION AND AUTOMATION	15,441,491
5	DEF CAPE SAN BLAS BATTERY ENERGY STORAGE SYSTEM	13,416,447
6	DEF TRENTON BATTERY ENERGY STORAGE SYSTEM	13,006,290
7	DEF JOHN HOPKINS MICROGRID	11,908,286
8	SAND LAKE BANK 3 ADDITION	10,483,670
9	GAINESVILLE SUBSTATION EXPANSION	9,449,475
10	DEF SUBSTATION UPGRADES	9,221,071
11	DEF MICANOPY BATTERY ENERGY STORAGE SYSTEM	9,111,767
12	DEF FUSE REPLACEMENT	7,233,870
13	DEF JENNINGS BATTERY ENERGY STORAGE SYSTEM	7,036,844
14	DEF FEEDER CAPACITY	6,638,680
15	DEF STRATEGIC COMMUNICATION	5,412,172
16	2017 REDUNDANCY PROTECTION PROGRAM	4,680,446
17	SG-RELIABILITY DET CONDUCTOR DEF	4,642,318
18	2016 NETWORK - UNDERGROUND CABLE	3,653,848
19	WILLISTON - NEW STUBSTATION	3,330,193
20	MORGAN ROAD TO NEW RIVER - NEW SUBSTATION	2,788,703
21	NORTHRIDGE TO WEST DAVENPORT NEW LINES	2,758,352
22	BAYBORO NEW SUBSTATION	2,527,662
23	STORM PROTECTION PLAN FH EAST CLEARWATER	2,389,619
24	TRMP GP (BUCKEYE) FOLEY SUBSTATION	2,382,123
25	TRMP WINTER SPRINGS TO SANFORD/POINSETT	2,330,705
26	DEPARTMENT OF TRANSPORTATION RELOCATION - I-4 ULTIMATE ROADWAY	2,208,771
27	BITHLO TO UNIVERSITY OF CENTRAL FLORIDA (FTR) 69KV REBUILD	2,131,476
28	2018 LG DENHAM C155 LINE EXTENSION	2,083,504
29	DISTRIBUTION RELOCATION/MODIFICATIONS	2,033,081
30	NON ROUTINE MISCELLANEOUS SUBSTATION - DISTRIBUTION	1,899,303
31	STORM PROTECTION PLAN FH PORT RICHEY WEST	1,896,322
32	STORM PROTECTION PLAN FH DELTONA	1,872,262
33	STORM PROTECTION PLAN FH PASADENA	1,828,144
34	40TH STREET TO 16TH STREET (BFE-2)	1,800,624
35	BU 50226 DISTRIBUTION SUBSTATIONS (HB) FUNDING PROJECT FOR ENABLE	1,774,127
36	STORM PROTECTION PLAN FH TARPON	1,733,786
37	SUBOPT - PORT RICHEY W C208	1,704,332
38	STORM PROTECTION PLAN FH DELAND W0808 298 POLES	1,665,445
39	52ND ST. RECONDUCTOR FUNDING PROJEC	1,661,393
40	2020 SC - OAKHURST JTBD BREAKER FEEDER	1,525,357
41	2021 SC - TAYLOR J2901 BREAKER INSTALLATION	1,405,321
42	STORM PROTECTION PLAN FH DELAND W0806 134 POLES	1,334,828
43	LAKE BRYAN TO VINELAND LINES	1,333,145
44	STORM PROTECTION PLAN FH MAITLAND W0087 73 POLES	1,296,854
45	TRMP LAKE LUNTZ - NEW 25MVAR 69 KV	1,260,743
46	2020 SC - LAND O' LAKES BANK UPGRADE	1,174,836
47	APALACHICOLA CAPACITY INCREASE MO-L	1,174,440
48	LAKE WALESBUILD (6) POSITION 69KV R	1,124,132
49	STORM PROTECTION PLAN FH WINTER GARDEN K203 170 POLES	1,114,338
50	SUBOPT - FIFTY-FIRST STREET X101	1,013,900
51	PROJECTS LESS THAN $1 MILLION	34,502,922
52	GENERAL PLANT
53	DEF LAND MOBILE RADIO PROJECT 3	28,924,833
54	REAL ESTATE FUNDING PROJECT	16,471,307
55	2021 MATTING PURCHASE	15,608,675
56	MICROWAVE PROJECTS FLORIDA	11,582,074
57	DEF STRATEGIC COMMUNICATION	9,886,456
58	DEF SUBSTATION STORM SURVIVABILITY	6,639,492
59	FACILITIES SERVICES CAPITAL PROJECTS	5,957,176
60	CUSTOMER CONNECT	5,520,333
61	FLORIDA LABOR ACCRUAL	5,520,279
62	GRID/BUSINESS WAN NETWORK CORE ROUTER	4,961,822
63	FUNDING PROJECT 2021 TELECOM MRTP	4,727,940
64	FLEET VEHICLES FLORIDA	4,670,334
65	TOOLS & EQUIPMENT BLANKET CONSTRUCTION	3,869,187
66	GENERIC CAPITAL COST	3,330,396
67	DEF TOWERS, SHELTERS & POWER SUPPLIES	3,320,258
68	SMARTGRID DEE DISTRIBUTED MANAGEMENT SYSTEM ADMS	3,224,526
69	DEF 2019-2020 MICROWAVE UPGRADES	3,138,646
70	FUNDING PROJECT 2021 TELECOM DVV	2,344,468
71	ENERGY SERVICES DEF REG FP	1,918,615
72	DEE LMR CONSOLES	1,802,739
73	DEF GRIDWAN	1,650,611
74	DEF OPTICAL ELECTRONICS	1,454,227
75	WEBFG REPLACEMENT	1,266,590
76	SMART GRIND DEF SEGMENTATION AND AUTOMATION	1,251,676
77	PROJECTS LESS THAN $1 MILLION	3,817,568
78	INTANGIBLE PLANT
79	SMARTGRID DEE DISTRIBUTED MANAGEMENT SYSTEM ADMS	20,016,060
80	IT DEMAND WORK FUNDING PROJECT	16,504,365
81	DEE ADVANCED DISTRIBUTIION PLANNING TOOL	3,964,835
82	SMART GRID DEE SECURE ACCESS AND DEVICE MAN	2,496,566
83	ARCOS SYSTEM OUTAGE PROJECT	1,606,344
84	DEE GRID DATA QUALITY GDQ	1,035,252
85	PROJECTS LESS THAN $1 MILLION	6,510,783
86	PRODUCTION PLANT
87	BAY TRAIL SOLAR	93,854,399
88	SANDY CREEK SOLAR	83,936,377
89	CHARLIE CREEK SOLAR	77,546,540
90	FORT GREEN SOLAR	67,706,577
91	LAKE PLACID BATTERY STORAGE	21,508,189
92	HIGH SPRINGS SOLAR	15,213,181
93	CRYSTAL RIVER 316B-CITRUS COUNTY COMPONENT	12,963,644
94	HARDEETOWN SOLAR	9,966,067
95	TEMPLATE OSP2 HGP	8,276,973
96	BAY RANCH SOLAR	7,361,502
97	HILDRETH SOLAR	6,124,846
98	NEW WAREHOUSE / OFFICE BUILDING	5,177,799
99	CT2 OPERATIONAL FLEXIBILITY	5,144,157
100	CR5 COOLING TOWER BEAM REPL	2,434,620
101	CR4 SCR CATALYST REPLACE - 2 LAYERS	2,281,901
102	P01-06 CONTROLS UPGRADE	2,257,280
103	OSP2 CT2 ROTOR REPLACEMENT	2,099,992
104	4C GEN STATOR REPL AND ROTOR REWIND	1,774,559
105	2021 BTC4 MISC CAPITAL BLANKET	1,742,829
106	CITRUS PB2 DUCTBANK/6.9KV CABLES	1,680,432
107	IC10 GE RLE/RTR OVRHL	1,595,422
108	BRR- WATER TREATMENT SYSTEM	1,461,195
109	2021 ANC MISC CAPITAL BLANKET	1,360,698
110	CITRUS 2021 MISC. CAPITAL BLANKET	1,344,086
111	TEMPLATE PB1 STG VALVE OUTAGE 2022	1,312,818
112	CRYSTAL RIVER CASCADE ROOM TRANSFER POINTS	1,272,413
113	SUWANEE CT MISC BLANKET - 2021	1,249,830
114	SUWANEE P2B FREE TURBINE	1,061,211
115	PROJECTS LESS THAN $1 MILLION	24,468,216
116	TRANSMISSION PLANT
117	OSPREY TO HAINES CITY EAST - NEW 23	62,489,104
118	KATHLEEN TO OSPREY - NEW 230KV LINE	29,414,869
119	WILLISTON - NEW STUBSTATION	27,881,150
120	KEYSTONE - NEW SUBSTATION	26,443,673
121	MORGAN ROAD TO NEW RIVER - NEW SUBSTATION	24,395,619
122	OSPREY PLANT TRANSMISSION LINES	21,477,750
123	RIO PINAR TO ECON WINTER PARK LINES	18,932,158
124	FORT WHITE TO PERRY 69KV 2ND CIRCUIT	15,619,548
125	CRYSTAL RIVER TO BRONSON LINES	12,507,081
126	NEW RIVER TO WIRE ROAD LINES	11,844,295
127	BARTOW TO NORTHEAST - ADD 230KV CABLE	11,151,770
128	BROOKSVILLE TRANSFORMER	10,988,719
129	CRYSTAL RIVER TO BRONSON 230KV LINE	6,712,053
130	Q282 - SOLAR INTERCONNECTION - LADY	6,541,844
131	Q253 SOLAR INTERCONNECTION - SINGLE	5,531,651
132	POWERLINE TO HOLDER - NEW 230KV LINE	4,637,625
133	EUSTOS TO DONA VISTA LINES	4,188,400
134	DBB - BRONSON - NEW SECOND 230/69 K	4,154,921
135	3160 - DIXIE TP-COLEMAN 69 KV REBUILD	3,818,641
136	VANDOLAH TO WHIDDEN 230KV BIFURCATI	3,372,152
137	LAKE TALQUIN TO BRICKYARD DOUBLE CIRCUIT CAPABLE STRUCTURE	3,146,863
138	OAK CITY TAP TO HAVANA LINES	2,875,517
139	2021 STORM PROTECTION PLAN STRUCTURE HARDENNING WOOD POLES GROUP 2D, CF-3	2,778,867
140	2021 STORM PROTECTION PLAN STRUCTURE HARDENNING WOOD POLES GROUP 2F, CF-2	2,644,686
141	PIEDMONT TO WEKIVA LINES	2,507,245
142	TRANSMISSION BREAKER RELIABILITY PROGRAM	2,328,255
143	TRMP WINTER SPRINGS TO SANFORD/POINSETT	2,180,366
144	GAINESVILLE SUBSTATION EXPANSION	2,170,198
145	LAKE WALES - WEST LAKE WALES REPLACEMENT	1,863,409
146	TRANSMISION LINES (GG) FP FOR ENABLE	1,780,755
147	FLWHOL SECO DALLAS SUBSTATION LOOPING	1,754,585
148	2021 STORM PROTECTION PLAN STRUCTURE HARDENNING WOOD POLES GROUP O, CF-3	1,711,739
149	DELTONA SUBSTATION 115KV BREAKER AD	1,614,056
150	BAYBORO NEW SUBSTATION	1,590,297
151	MARTIN WEST REPLACE T-OIL BREAKERS	1,499,846
152	BROOKRIDGE - INSTALL NEW 500/230 KV	1,452,542
153	INTERCESSION'S RELAY UPGRADES	1,442,415
154	WINDERMERE - ADD 2 NEW 75 MVA 230KV	1,422,835
155	STORM PROTECTION PLAN HOLOPAW WEST LAKE WALES (WLXF)	1,404,055
156	40TH STREET TO 16TH STREET (BFE-2)	1,393,697
157	BITHLO TO LOCKWOOD - NEW LINES	1,324,345
158	2021 STORM PROTECTION PLAN STRUCTURE HARDENING WOOD POLES GROUP N	1,318,907
159	2021 STORM PROTECTION PLAN STRUCTURE HARDENING WOOD POLES GROUP 5	1,257,491
160	BAYVIEW TO EAST CLEARWATER (HD-5)	1,172,506
161	ANCLOTE TO TARPON SPRINGS NEW 230KV	1,105,120
162	DELAND WEST - DONA VISTA - NEW 230KV	1,093,734
163	STORM PROTECTION PLAN BRONSON NEWBERRY 230KV (CF-2)	1,084,942
164	2021 STORM PROTECTION PLAN STRUCTURE HARDENING WOOD POLES GROUP 1	1,071,244
165	PROJECTS LESS THAN $1 MILLION	33,869,001
43	Total	1,342,670,129

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	5,500,492,618	5,500,492,618
2	Depreciation Provisions for Year, Charged to
3	DepreciationExpenseExcludingAdjustments (403) Depreciation Expense	586,910,249	586,910,249
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	3,457,382	3,457,382
7	OtherClearingAccounts Other Clearing Accounts
8	OtherAccounts Other Accounts (Specify, details in footnote):
9.1	Other Accounts (Specify, details in footnote):
9.2	Hurricane Michael Depreciation Expense Deferral	992,469	992,469
9.3	Demand-Side Management Depreciation - Northpoint	42,290	42,290
9.4	ARO Depreciation Expense	1,398,456	1,398,456
10	DepreciationProvision TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)	592,800,846	592,800,846
11	Net Charges for Plant Retired:
12	BookCostOfRetiredPlant Book Cost of Plant Retired	274,421,833	(a) 274,421,833
13	CostOfRemovalOfPlant Cost of Removal	170,190,069	170,190,069
14	SalvageValueOfRetiredPlant Salvage (Credit)	28,012,194	28,012,194
15	NetChargesForRetiredPlant TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)	416,599,708	416,599,708
16	OtherAdjustmentsToAccumulatedDepreciation Other Debit or Cr. Items (Describe, details in footnote):
17.1	Other Debit or Cr. Items (Describe, details in footnote):
17.2	Land and Land Rights Gain (Loss)	182,715	182,715
17.3	Reserve moved to regulatory asset	1,342,537	1,342,537
17.4	Meter reserve adjustment	2,507,420	2,507,420
17.5	Crystal River 1 & 2 NBV reserve adjustment	2,065,712	2,065,712
17.6	Generator installed on customer premise - Gain (Loss)	1,795,746	1,795,746
17.7	To move ash landfill COR to ash reserve	131,107	131,107
17.8	Final Dismantlement Nuclear Decommission	1,452,539	1,452,539
17.9	Retire old non-AMI Meters	28,012	28,012
17.10	Reserve transferred from Intangible Plant	1,066,665	1,066,665
17.11	Reserve to other utility	64,190	64,190
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)	5,677,758,162	5,677,758,162
Section B. Balances at End of Year According to Functional Classification
20	AccumulatedDepreciationSteamProduction Steam Production	1,416,848,362	1,416,848,362
21	AccumulatedDepreciationNuclearProduction Nuclear Production	51,866,526	51,866,526
22	AccumulatedDepreciationHydraulicProductionConventional Hydraulic Production-Conventional
23	AccumulatedDepreciationHydraulicProductionPumpedStorage Hydraulic Production-Pumped Storage
24	AccumulatedDepreciationOtherProduction Other Production	1,257,881,421	1,257,881,421
25	AccumulatedDepreciationTransmission Transmission	770,295,651	770,295,651
26	AccumulatedDepreciationDistribution Distribution	1,995,966,156	1,995,966,156
27	AccumulatedDepreciationRegionalTransmissionAndMarketOperation Regional Transmission and Market Operation
28	AccumulatedDepreciationGeneral General	184,900,046	184,900,046
29	AccumulatedProvisionForDepreciationOfElectricUtilityPlant TOTAL (Enter Total of lines 20 thru 28)	5,677,758,162	5,677,758,162

FOOTNOTE DATA

(a) Concept: BookCostOfRetiredPlant

Balance does not tie to Retirements reported on FERC Page 204-207 due to Intangible Retirements of $105,979,121, Future Use Retirements of ($667,927), and Lease Asset Activity of $11,295.

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	DE Florida Solar Solutions, LLC	02/25/2015
2	Equity Contribution
3	Undistributed Earnings			393,710	167,412		226,298
4	Investment Advance from Parent			8,522,856		80,421	8,603,277
5	DE Florida Project Finance, LLC	01/05/2016
6	Equity Contribution			6,471,449	183		6,471,266
7	Undistributed Earnings
8	Investment Advance from Parent			1,172,291		618	1,171,673
42	Total Cost of Account 123.1 $		Total	16,560,306	167,595	79,803	16,472,514

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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)	141,296,152	143,244,000	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) 236,171,836	(b) 233,278,275	Electric
6	Assigned to - Operations and Maintenance
7	Production Plant (Estimated)	69,310,145	67,392,118	Generation
8	Transmission Plant (Estimated)	993,743	6,796,525	Transmission
9	Distribution Plant (Estimated)	1,590,092	10,469,380	Distribution
10	Regional Transmission and Market Operation Plant (Estimated)
11	Assigned to - Other (provide details in footnote)			Other
12	TOTAL Account 154 (Enter Total of lines 5 thru 11)	308,065,816	317,936,298
13	Merchandise (Account 155)
14	Other Materials and Supplies (Account 156)	31,582	94,692	Customer Service
15	Nuclear Materials Held for Sale (Account 157) (Not applic to Gas Util)
16	Stores Expense Undistributed (Account 163)	(c) 14,889,786	(d) 15,226,648	Electric
17
18
19
20	TOTAL Materials and Supplies	464,283,336	476,501,638

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: PlantMaterialsAndOperatingSuppliesConstruction

Assigned to Construction (For internal use only) Production 117,100,835Transmission 49,787,758Distribution 69,283,243

(b) Concept: PlantMaterialsAndOperatingSuppliesConstruction

Assigned to Construction (For internal use only) Production 115,313,918Transmission 45,787,295Distribution 72,177,062

(c) Concept: StoresExpenseUndistributed

Stores Expense Undistributed (For internal use only)Production 7,873,616Transmission 2,854,044Distribution 4,498,988

(d) Concept: StoresExpenseUndistributed

Stores Expense Undistributed (For internal use only)Production 8,795,193Transmission 2,548,363Distribution 3,546,230

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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) 1,096,508	3,221,471	119,141		119,141		119,141		3,216,807		4,670,738	3,221,471
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)									119,141		119,141
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	3,664	8,687									3,664	8,687
19	Other:
20	Allowances Used
20.1	Allowances Used
21	Cost of Sales/Transfers:
22
23
24
25
26
27
28	Total	3,664	8,687									3,664	8,687
29	Balance-End of Year	(b) 1,092,844	3,212,783	119,141		119,141		119,141		3,216,807		4,667,074	3,212,783
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	3,443		3,443		3,443		3,443		89,518		103,290
37	Add: Withheld by EPA									3,443		3,443
38	Deduct: Returned by EPA
39	Cost of Sales	3,443										3,443
40	Balance-End of Year			3,443		3,443		3,443		92,961		103,290
41
42	Sales
43	Net Sales Proceeds (Assoc. Co.)
44	Net Sales Proceeds (Other)
45	Gains
46	Losses

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: AllowanceInventoryNumber

Balance includes allowances for Cross State Air Pollution Rule and the Acid RainProgram

(b) Concept: AllowanceInventoryNumber

Balance includes allowances for Cross State Air Pollution Rule and the Acid RainProgram

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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
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
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 Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	Storm Extraordinary Property Loss
2	Wholesale (FERC Letter dated
3	1/7/2005. Docket No. AC05-12-111
4	amortization expenses consistent
5	with recovery in rates.)	1,503,780		407371	65,155	1,438,625
20	TOTAL	1,503,780			65,155	1,438,625

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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
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	TOTAL

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	Affected System Study EcoPlexus	2,474	561.6
3	St. Cloud East - Holopaw 230 kV lin	74	561.6
4	Transmission Affected System Study	36,664	561.6
5	NO VALUE			42,099	561.601
20	Total	39,212		42,099
21	Generation Studies
22	NO VALUE			1,218,488	561.701
23	3R Solar Farm Facility Study	149	561.7
24	Affected Facilities Study for SAVIO	3,572	561.7
25	Alachua County FAC Study FERC	11,190	561.7
26	Alachua Solar	3,702	561.7
27	Alira Energy - Levy Solar 1	21,993	561.7
28	Apalachicola Solar Facility Study	30,899	561.7
29	Apalachicola Solar, LLC	668	561.7
30	Aster Holdings Facility Study	3,146	561.7
31	Atwater Solar SIS	6,000	561.7	103,002	561.701
32	Bay County Solar FAC Study FERC	10,754	561.7
33	Birdseye Aster Holdings	557	561.7
34	Birdseyee Charolais Holdings	27,388	561.7
35	Canoe Creek FERC System Impact	2,000	561.7
36	Canoe Creek I FERC Facilities	21,854	561.7
37	CE Gainesville Solar SIS FERC	52,235	561.7
38	Charolais Holdings Facility Study	1,139	561.7
39	Dairies Solar	2,157	561.7
40	DEF - Panama City SIS FERC	29,458	561.7
41	DEF Bartow BESS FERC Feasibility	10,268	561.7
42	DEF Bartow BESS FERC SIS	54,831	561.7
43	DEF Bay County SIS FERC	28,278	561.7
44	DEF Blue Springs 230 FERC SIS	47,005	561.7
45	DEF Charlie Creek Solar	828	561.7
46	DEF Charlie Creek System Impact	520	561.7
47	DEF Gulf Country SIS FERC	27,616	561.7
48	DEF Gulf County Solar Facility FERC	9,037	561.7
49	DEF Lake Placid Storage Facility	1,038	561.7
50	DEF Rattler Solar	547	561.7
51	DEF St Marks Solar FERC Facilities	16,905	561.7
52	DEF St Marks Solar FERC SIS	50,001	561.7
53	DEF Wahoo Solar Transmission SIS	637	561.7
54	DEF Winquepin Solar FAC FERC	37,233	561.7
55	DEF Winquepin Solar SIS FERC	26,894	561.7
56	DEF, LLC - Longleaf 230 kV	52,807	561.7
57	DEF, LLC - Longleaf 69 kV	54,182	561.7
58	Duke Energy Florida Alachua Solar	547	561.7
59	Echo River Solar Facilities FERC	14,101	561.7
60	Echo River Solar Feasibility FERC	138	561.7
61	Echo River Solar SIS FERC	58,304	561.7
62	EcoPark Hamel Facilities Study FERC	31,640	561.7
63	EcoPlexus Drifton PV2	280	561.7
64	Ecoplexus Ft. White PV1	8,214	561.7
65	Ecoplexus Perry PV1 Solar	280	561.7
66	Figure 8 Solar	607	561.7
67	Figure 8 Solar Facility Study	9,014	561.7
68	First Solar Columbia 2	22,041	561.7
69	First Solar Columbia 3	1,040	561.7
70	First Solar Development - Mae Meado	668	561.7
71	First Solar Development - Zolfo Spr	668	561.7
72	Florida Renewable Partners - Bass F	1,953	561.7
73	Florida Renewable Partners - Gallow	1,958	561.7
74	Florida Renewable Partners - Loncal	3,015	561.7
75	Florida Renewable Partners - Poinse	2,765	561.7
76	Florida Renewable Partners-Galloway	607	561.7
77	FLRP Johnson Farms 1	4,634	561.7
78	Ft. White PV1	888	561.7
79	Gilchrist County Solar 3 Fac FERC	18,913	561.7
80	Gilchrist County Solar FAC FERC	66,102	561.7
81	Gilchrist SIS FERC	50,242	561.7
82	Gwin Solar Farm - Fac Study FERC	9,965	561.7
83	Gwinn Solar Farm System Impact FERC	784	561.7
84	Hardee Dydo Solar	24,740	561.7
85	Hardee Dydo Solar Facility Study	73	561.7
86	High Springs Solar	582	561.7
87	Highlands Solar South Facility Stdy	57	561.7
88	Invenergy - Terrace Top Solar	4,850	561.7
89	Invenergy Duette Solar	130	561.7
90	Invenergy Terrace Top	1,159	561.7
91	Levy Solar 1 Facility Study FERC	254	561.7
92	Leyland Holdings Facility Study	6,919	561.7
93	Lincoln Clean Energy Waukeenah	949	561.7
94	Mae Meadows Facility Study FERC	9,650	561.7
95	McAlpin Solar Center Facility Study	11,691	561.7
96	McAlpin Solar CTR 230 kV FERC SIS	1,342	561.7
97	Micco Solar System Impact Study	49,981	561.7
98	Newberry Solar	607	561.7
99	Newberry Solar Facility Study	7,630	561.7
100	NextEra Swift Creek	607	561.7
101	Oleander	804	561.7
102	Oxford PV1 Solar Facility Study	2,367	561.7
103	Panama City Solar Fac Study FERC	6,467	561.7
104	Pattern Energy Crystal River South	21,041	561.7
105	Perry PV 1 Solar Facility Study	375	561.7
106	Pleasant Solar BESS	24,477	561.7
107	Rattler Solar DER Facility Study	3,720	561.7
108	RCID Bell Ridge Transmission SIS	665	561.7
109	Red Toad 3Rs Ranch Solar	453	561.7
110	Reimbursement for City of Mount Dor	318	561.7
111	rsted Onshore North America LLC	11,536	561.7
112	Solar FL 2018 LLC Dunnellon Farms	28,023	561.7
113	Southeast Solar & Power - High Spri	7,985	561.7
114	SR26 Solar Farm Facility Study	19,284	561.7
115	Strata Solar Patchwork Solar	6,014	561.7
116	Tide Bay Solar Facilities Stdy FERC	1,920	561.7
117	Tide Bay Solar Reedy Creek Tran SYS	562	561.7
118	Trans. Impact Study Bay County Sol	94	561.7
119	Trans. Impact Study Panama City Sol	94	561.7
120	Transitional Serial Construction DE	54,341	561.7
121	Transitional Serial Study DET Overh	83,845	561.7
122	Transmission SIS for Alachua Poinse	1,118	561.7
123	Transmission System Impact Study fo	1,830	561.7
124	Transmission System Impact Study Gu	94	561.7
125	Twin Rivers Solar Facility Study	396	561.7
126	Whistling Duck FMPA ARP	279	561.7
127	Whistling Duck I FERC Facilities	55,641	561.7
128	Whistling Duck II FERC Facilities	33,110	561.7
129	Whistling Duck Mt Dora 2MW Transmis	279	561.7
130	Whistling Duck Winter Park Transmis	279	561.7
131	Zolfo Springs Facility Study FERC	9,712	561.7
39	Total	1,455,200		1,321,490
40	Grand Total	1,494,412		1,363,589

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	Income Taxes, Order No PSC-2010-0131-FOF-EI	163,868,604	16,957,334	282, 283	6,718,313	174,107,625
2	Deferred Pension Costs, Amortized over the service life of the employee; Order No. PSC-2021-0202-AS-EI	481,555,695	207,830,493	Var	315,711,776	373,674,412
3	Asset Retirement Obligation, Amortized over Various Periods; Docket Nos. 201000-461-EI & 20090145-EI	11,850,428	28,283,906	Var	22,830,624	17,303,710
4	Interest Rate Hedges, Amortized over Various Periods; Docket No. 20120303-EI	58,759,882	8,210,695	182.3, 427	3,663,229	63,307,348
5	Fuel Recovery Clause, Amortized through 2022; Order No. PSC-2021-0442-FOF-EI	4,407,712	476,054,016	Var	51,121,137	429,340,591
6	Capacity Recovery Clause, Amortized through 2021; Docket No. 20200001-EI		22,613,567	254	22,613,567
7	Load Management, Amortized through 2025; Order No. PSC-2021-0427-FOF-EG	56,348,466	18,366,574	Var	27,092,460	47,622,580
8	Environmental; Amortized over various periods; Docket No. 20200007-EI	143,828		Var	157,359	13,531
9	Cost of Removal, Docket No. 20130308-EI	460,648,796		N/A		460,648,796
10	CR3 Regulatory Asset; Amortized through 2036; Docket No. 20130308-EI	40,331,286	2,602,018	421		37,729,267
11	Deferred Depreciation - 2010 Rate Cases; Docket No. 20090145-EI	17,521,839		N/A		17,521,839
12	Crystal River South Retirement; Amortized through 2021; Docket Nos: 20170183-EI	80,472,612	665,652	108, 407.3	80,592,741	545,523
13	Qualifying Facility Contract Buyout; Amortized through 2034; Docket No. 20170274-EQ	107,450,232		407	13,069,032	94,381,200
14	Deferred Depreciation - Retail Recovery; Docket No. 20170272-EI	1,331,613	992,469	403		2,324,082
15	Storm Protection Plan (SPP) Recovery; Amortized over various periods; Docket No. 20210010-EI	1,112,387	772,775	Var	1,767,953	117,209
44	TOTAL	1,405,140,808	783,349,499		545,338,191	1,643,152,117

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	Vision Florida Def O&M		564,213	0186020		564,213
2	EVCS Deferral	7,960,294	1,646,048	0186036	306,670	9,299,672
3	DEF CR3 Dry Cask Storage	96,346,403		0186102		96,346,403
4	DEF DCS Contra Equity	2,448,982		0186109		2,448,982
5	DEF CR3 NCR-Reg Asst Base Rate			0186101	37,749	37,749
6	Other	256	886,562	Various	886,270	36
7	Cust Connect Def O&M	30,088,532	36,655,043	0186111		66,743,575
8	Misc. Wip-Fp Dist. Wids	3,473,635	175,535,867	0186120	178,444,363	565,139
9	Def Project/Acq Exp	2,905,965		0186201	518,392	2,387,573
10	Oth Deferred Charges-Operation	1,581,463	836,645	0186290	2,418,108
11	Deferred Rate Expenses	783,471	154,444	0186195	3,094	934,821
12	Deferred Storm Expenses	21,448,274	65,450,904	0186295	69,913,341	16,985,837
13	SECI-Lakeland Intercon Upgrade	4,548,915		0186400	710,064	3,838,851
14	Worker's Comp	14,915,994		0186605	3,166,819	11,749,175
15	Straight Line Lease Defer DR	5,520,208	58,586,279	0186882	58,479,550	5,413,479
16	Other Long-term Assets	1,514,476	251,985	0186984	1,765,522	940
47	Miscellaneous Work in Progress
48	Deferred Regulatroy Comm. Expenses (See pages 350 - 351)
49	TOTAL	177,597,976				201,516,024

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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
2		884,610,287	902,270,724
7	Other
8	TOTAL Electric (Enter Total of lines 2 thru 7)	884,610,287	902,270,724
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)	884,610,287	902,270,724

Notes

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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 Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

2022-04-29

Year/Period of Report

End of:

2021

/

Q4

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	1,766,035,361
15.1	IncreasesDecreasesDueToMiscellaneousPaidInCapital Increases (Decreases) Due to Miscellaneous Paid-In Capital
16	MiscellaneousPaidInCapital Ending Balance Amount	1,766,035,361
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	1,766,035,361

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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 Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	First Mortgage Bonds - 5.9%		225,000,000			3,013,280	571,500	02/01/2003	03/01/2033	02/01/2003	03/01/2033	225,000,000	13,275,000
3	First Mortgage Bonds - 4.55%							03/25/2010	04/01/2020	03/25/2010	04/01/2020
4	First Mortgage Bonds - 5.65%		350,000,000			4,691,511	1,459,500	03/25/2010	04/01/2040	03/25/2010	04/01/2040	350,000,000	19,775,000
5	First Mortgage Bonds - 3.10%		300,000,000			3,467,458	612,000	08/18/2011	08/15/2021	08/18/2011	08/15/2021		5,786,667
6	First Mortgage Bonds - 3.85%		400,000,000			4,864,188	1,268,000	11/20/2012	11/15/2042	11/20/2012	11/15/2042	400,000,000	15,399,996
7	First Mortgage Bond - 3.40%		600,000,000			7,316,807	3,372,000	09/09/2016	10/01/2046	09/09/2016	10/01/2046	600,000,000	20,400,000
8	First Mortgage Bond - 4.20%		400,000,000			4,824,680	556,000	06/21/2018	07/15/2048	06/21/2018	07/15/2048	400,000,000	16,800,000
9	First Mortgage Bonds - 1.85%							01/06/2017	01/15/2020	01/06/2017	01/15/2020
10	First Mortgage Bond - 3.20%		650,000,000				390,000	01/06/2017	01/15/2027	01/06/2017	01/15/2027	650,000,000	20,799,996
11	First Mortgage Bond - 3.80%		600,000,000			5,437,020	1,110,000	06/21/2018	07/15/2028	06/21/2018	07/15/2028	600,000,000	22,800,000
12	First Mortgage Bond - 1.75%		500,000,000			4,686,102	685,000	06/15/2020	06/15/2030	06/15/2020	06/15/2030	500,000,000	8,750,004
13	Long-Term Debt Fixed - 2.5%		700,000,000			6,267,562	371,000	11/26/2019	12/01/2029	11/26/2019	12/01/2029	700,000,000	17,499,996
14	Fist Mortgage Bonds - 6.35%		500,000,000			6,708,137	660,000	09/18/2007	09/15/2037	09/18/2007	09/15/2037	500,000,000	31,750,000
15	First Mortgage Bonds - 2.40%		650,000,000		2,925,000			12/02/2021	12/15/2031	12/02/2021	12/15/2031	650,000,000	1,256,667
16	First Mortgage Bonds - 3.00%		500,000,000		3,750,000			12/02/2021	12/15/2051	12/02/2021	12/15/2051	500,000,000	1,208,333
17	Long Term Debt - Floating Rate							11/26/2019	11/26/2021	11/26/2019	11/26/2021		757,634
18	First Mortgage Bonds - 6.40%		1,000,000,000			13,136,457	4,220,000	06/18/2008	06/15/2038	06/18/2008	06/15/2038	1,000,000,000	64,000,000
19	Subtotal		7,375,000,000		6,675,000	64,413,202	15,275,000					7,075,000,000	260,259,293
20	Reacquired Bonds (Account 222)
21
22
23
24	Subtotal
25	Advances from Associated Companies (Account 223)
26
27
28
29	Subtotal
30	Other Long Term Debt (Account 224)
31	Florida Long Term Note - 6.75%		150,000,000			5,528,498	436,500	02/13/1998	02/01/2028	02/13/1998	02/01/2028	150,000,000	10,125,000
32	DEF Receivables Suntrust 125M (Floating Rate)		112,500,000			638,078		03/13/2014	04/30/2023	03/13/2014	04/30/2023	125,000,000	1,186,747
33	DEF Receivables RBC 125M (Floating Rate)		112,500,000			638,078		03/13/2014	04/30/2023	03/13/2014	04/30/2023	125,000,000	1,256,556
34	Treasury Lock Amortization												9,310,928
35	Subtotal		375,000,000			6,804,654	436,500					400,000,000	21,879,231
33	TOTAL		7,750,000,000									7,475,000,000	282,138,524

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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)	737,876,273
2	Reconciling Items for the Year
3
4	Taxable Income Not Reported on Books
5	State Income Tax Addback	15,464,211
6	Taxable Income Not Reported on Books - Subtotal	15,464,211
9	Deductions Recorded on Books Not Deducted for Return
10	Federal and State Income Tax Deducted for Books	187,292,399
11	Other Deductions on Books Not Deducted for Tax	1,448,867,025
12	Subtotal -Deductions Recorded on Books Not Deducted for Return	1,636,159,424
14	Income Recorded on Books Not Included in Return
15	Income Recorded on Books Not Included in Return - Subtotal
19	Deductions on Return Not Charged Against Book Income
20	Deductions on Return Not Charged Against Book Income	2,422,815,867
21	Deductions on Return Not Charged Against Book Income - Subtotal	2,422,815,867
27	Federal Tax Net Income	33,315,959
28	Show Computation of Tax:
29	Federal Tax Net Income as above	33,315,959
30	Tax at 21% for Electirc, Water, Non-Utility, and Gas	6,996,351
31	Less NOLS	62,525,689
32	Add True-up Entries	5,705,267
33	Add: Other Benefits	23,744
34	Tax of Respondent	75,251,051

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	FICA	Federal Tax	Federal	2021	14,784,859		14,466,790	22,956,541	331,209	6,626,317		14,466,790
2	Subtotal Federal Tax				14,784,859		14,466,790	22,956,541	331,209	6,626,317		14,466,790
3	Utility Receipts Taxes	State Tax	Florida	2021	16,940,190		107,953,027	111,935,907	3,240,401	9,716,909		107,953,027
4	Regulatory Assessment	State Tax	Florida	2021	1,786,553			3,417,924	3,309,508	1,678,137
5	Subtotal State Tax				18,726,743		107,953,027	115,353,831	69,107	11,395,047		107,953,027
6	Property Tax	Property Tax	State	2021	0		146,724,320	144,946,738	1,766,567	11,015		146,488,172			236,148
7	Subtotal Property Tax				0		146,724,320	144,946,738	1,766,567	11,015		146,488,172			236,148
8	Fed Unemployment Taxes	Unemployment Tax	Federal	2021	630		115,274	900,896	1,012,300	4,500		115,274
9	State Unemployment Taxes	Unemployment Tax	FL	2021	1,531		77,923	79,943		490		77,923
10	Subtotal Unemployment Tax				2,161		193,197	820,952	1,012,300	4,010		193,197
11	Sales and Use Taxes	Sales And Use Tax	Florida	2021	1,443,079		23,271,062	24,727,237		13,096		807,996			24,079,058
12	Subtotal Sales And Use Tax				1,443,079		23,271,062	24,727,237		13,096		807,996			24,079,058
13	Fed Income Taxes	Income Tax	Federal	2021	30,980,986		75,251,051	12,367,235		31,902,830		80,120,902			4,869,851
14	State Income Taxes	Income Tax	FL	2021	4,281,906		16,871,837	4,022,761	4	8,567,165		17,699,495			827,658
15	Subtotal Income Tax				35,262,892		92,122,888	16,389,997	4	40,469,995		97,820,397			5,697,509
16	Highway and Fuel Taxes	Fuel Tax	Federal	2021	0		25	25				25
17	Subtotal Fuel Tax				0		25	25				25
18	Franchise Tax	Franchise Tax	Florida	2021	8,591,686		114,361,672	112,172,346	33,985	10,747,027		114,361,672
19	Subtotal Franchise Tax				8,591,686		114,361,672	112,172,346	33,985	10,747,027		114,361,672
40	TOTAL				78,811,420		314,847,206	402,945,770	2,412,532	11,699,675		284,834,491			30,012,715

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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%
4	7%
5	10%
6	30%	145,829,017	190	62,585,488				208,414,505
7	26%		190	27,352,000				27,352,000
8	TOTAL Electric (Enter Total of lines 2 thru 7)	145,829,017		89,937,488				235,766,505
9	Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
10										`
11	10%
12	Adjustments
47	OTHER TOTAL
48	GRAND TOTAL	145,829,017		89,937,488				235,766,505

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	Environmental Reserve - MGP	10,568,681	Var	455,869	98,816	10,211,628
2	Cable Company Deposits ( Pole att)	231,293	431		2,140	233,433
3	Franchise Settlements (Apopka, Perry, and Alamonte Springs)	611,000	Var	209,000		402,000
4	PEP's Lease Incentive - AV Lease	125,535	242, 431, 931	21,459		104,076
5	PEP's Lease Incentive - Furniture	966,661	242, 431, 931	165,242		801,419
6	PEP's Lease Incentive - Other	338,286	242, 431, 931	57,827		280,459
7	JN Investments LLC - Five Guys	5,300	Var			5,300
8	Accounts Payable accruals	204,000	Var			204,000
9	Altitude Communication - Pole Attachment Agreement	2,000	Var			2,000
10	Performance Guarantee Deposits	1,189,648	Var	2,941,624	11,805,510	10,053,534
11	IGCC Settlement Accrual	3,128,208	Var	2,492,531	24,771,862	25,407,539
12	FL Subdivision Infrastructure UG	143,190	Var	143,190	500,188	500,188
13	Deferred Revenue	1,069,280	Var	177,730	242,065	1,133,615
14	Other	11,670	154, 566, 598	4,732	79,743	86,681
15	SmartGrid
16	LT Service Agreement - Hines	2,059,439	146, 165	2,059,439	1,864,889	1,864,889
17	LT Service Agreement - Bartow	3,315,742	165	9,224,076	21,672,928	15,764,594
18	Deferred Revenue /Extended Payment Plan Weather Protect
19	CATV Pole Rent		143, 146, 454	5,152,371	5,152,371
20	Citrus County LTSA Def Liab	4,562,425	165	4,562,425	3,874,831	3,874,831
21	SCHM Exec Cash Bal Plan		Var	1,019,284	6,824,365	5,805,081
22	Deferred Prepaid EF-Lighting		Var	47,416	180,183	132,767
47	TOTAL	28,124,358		28,734,215	77,069,891	76,460,034

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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)
1	Accelerated Amortization (Account 281)
2	Electric
3	Defense Facilities
4	Pollution Control Facilities	1									1
5	Other
5.1	Other (provide details in footnote):
8	TOTAL Electric (Enter Total of lines 3 thru 7)	1									1
9	Gas
10	Defense Facilities
11	Pollution Control Facilities
12	Other
12.1	Other (provide details in footnote):
15	TOTAL Gas (Enter Total of lines 10 thru 14)
16	Other
16.1	Other
16.2	Other
17	TOTAL (Acct 281) (Total of 8, 15 and 16)	1									1
18	Classification of TOTAL
19	Federal Income Tax	1									1
20	State Income Tax
21	Local Income Tax

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	2,275,359,130	441,780,276	213,306,588	1,601,078	5,117,659			182, 254, 146	12,738,217	2,513,054,454
3	Gas
4	Other (Specify)
5	Total (Total of lines 2 thru 4)	2,275,359,130	441,780,276	213,306,588	1,601,078	5,117,659				12,738,217	2,513,054,454
6
7
8
9	TOTAL Account 282 (Total of Lines 5 thru 8)	2,275,359,130	441,780,276	213,306,588	1,601,078	5,117,659				12,738,217	2,513,054,454
10	Classification of TOTAL
11	Federal Income Tax	1,822,187,889	335,374,750	168,865,740	1,253,636	4,007,100				11,829,949	1,997,773,384
12	State Income Tax	453,171,241	106,405,526	44,440,848	347,442	1,110,559				908,268	515,281,070
13	Local Income Tax

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	798,819,005	144,176,205	119,146,920	62,735					1,209,316	825,120,341
9	TOTAL Electric (Total of lines 3 thru 8)	798,819,005	144,176,205	119,146,920	62,735					1,209,316	825,120,341
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)	798,819,005	144,176,205	119,146,920	62,735					1,209,316	825,120,341
20	Classification of TOTAL
21	Federal Income Tax	625,467,634	112,889,199	93,291,404	49,121					929,672	646,044,222
22	State Income Tax	173,351,371	31,287,006	25,855,516	13,614					279,644	179,076,119
23	Local Income Tax
NOTES

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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 Iiability Income Tax; Recovered over plant lives; Order No. PSC-2010-0131-FOF-EI	50,762,120	282	163,291	31,772,542	82,371,371
2	Deferred Environmental Cost Recovery; Amortized over 12 months; Docket No. 2021-0426-FOF-EI	6,562,324	407.3, 421	4,738,524	389,170	2,212,970
3	Deferred Property Gains/Losses; Amortized over 5 years; Order No. PSC-2010-0131-FOF-EI	512,230	421	343,457	1,795,746	1,964,519
4	OPEB Regulatory Liability - Amortized over the service life of the employee; Order No. PSC-2010-0131-FOF-EI	525,244	182		525,244
5	NDT - Qual - Unreal Gains; Order No. PSC-2012-0225-PAA-EI	88,951,509	Various	4,770,096	20,061,110	104,242,523
6	Regulatory Liability Cost of Removal; Order No. PSC-2013-0598-FOF-EI	5,838,851	108		131,107	5,969,958
7	Deferred Capacity; Amortized over 12 months; Order No. PSC-2021-0442-FOF-EI	6,070,044	Various	33,455,474	32,950,218	5,564,789
8	Accumulated Deferred Income Tax - Amortized over various periods; Order No. PSC-2017-0451-AS-EU	862,054,542	Various	71,751,607		790,302,935
9	Accelerated Depreciation; Amortized through 2021 - Order No. PSC-2017-0451-AS-EU	150,000,000	407.3		50,000,000	200,000,000
10	Deferred Energy Conservation; Amortized over 12 months; Order No. PSC-2021-0427-FOF-EG	2,295,780	431, 908	1,004,005	17,905,810	19,197,585
11	Deferred Fuel Settlements; Amortized through 2022; Docket No. 20210001-EI	21,579,594	Various	184,376,441	163,313,631	516,784
12	Reg Liability - MTM LT Fuel; Amortized over various periods		176	10,444,357	10,444,357
13	Storm Protection Plan (SPP) Recovery; Amortized over various periods; Docket No. 20210010-EI		407.3, 421		3,406,987	3,406,987
41	TOTAL	1,194,101,751		311,047,252	332,695,922	1,215,750,420

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	(a) 2,901,902,571	2,895,724,788	21,194,790	21,458,693	1,720,307	1,655,304
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)	1,183,844,981	1,134,061,827	11,841,210	11,521,828	192,614	179,666
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)	256,560,586	247,131,449	3,417,754	3,147,394	2,154	1,999
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting	(b) 2,493,044	1,548,904	24,343	22,864	3,035	1,494
7	OtherSalesToPublicAuthoritiesAbstract (445) Other Sales to Public Authorities	(c) 301,846,269	285,459,692	3,203,700	3,079,434	24,902	25,338
8	SalesToRailroadsAndRailwaysAbstract (446) Sales to Railroads and Railways
9	InterdepartmentalSalesAbstract (448) Interdepartmental Sales
10	SalesToUltimateConsumersAbstract TOTAL Sales to Ultimate Consumers	4,646,647,451	4,563,926,660	39,681,797	39,230,213	1,943,012	1,863,801
11	SalesForResaleAbstract (447) Sales for Resale	221,448,452	193,785,637	3,702,432	3,019,323	13	13
12	SalesOfElectricityAbstract TOTAL Sales of Electricity	(d) 4,868,095,903	(g) 4,757,712,297	(j) 43,384,229	(k) 42,249,536	1,943,025	1,863,814
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds	4,868,095,903	4,757,712,297	43,384,229	42,249,536	1,943,025	1,863,814
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts	16,027,553	10,564,029
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	(e) 21,775,853	(h) 18,446,040
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power
19	RentFromElectricProperty (454) Rent from Electric Property	110,334,253	108,479,183
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	(f) 43,380,235	(i) 23,483,909
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	138,994,153	124,726,658
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	243,751,577	285,699,819
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	5,111,847,480	5,043,412,116
Line12, column (b) includes $ of unbilled revenues.
Line12, column (d) includes MWH relating to unbilled revenues

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: ResidentialSales

Due to a a classification error, DEF's original submission listed incorrect data on Page 304 under Column c. This did not impact the total reported. Incorrect amount has been restated and corrected.

(b) Concept: PublicStreetAndHighwayLighting

Due to a a classification error, DEF's original submission listed incorrect data on Page 304 under Column c. This did not impact the total reported. Incorrect amount has been restated and corrected.

(c) Concept: OtherSalesToPublicAuthorities

Due to a a classification error, DEF's original submission listed incorrect data on Page 304 under Column c. This did not impact the total reported. Incorrect amount has been restated and corrected.

(d) Concept: SalesOfElectricity

Unbilled revenues are not included in Line No. 12, but rather in Line No. 21, and are ($41,782,825) and $20,924,930 for 2021 and 2020, respectively, with related MWH's of (730,595) and 240,833, respectively.

(e) Concept: MiscellaneousServiceRevenues

Rates Billing and Payment 22,548,099General Office Collection and Other (772,246)

(f) Concept: OtherElectricRevenue

Other Variable Revenue - Reg 325,748Retail Unbilled Revenue (41,782,825)Municipal County Tax Collection 307,229Sales and Use Tax Collection Fees 10,297Shared Solar 25,619Other Variable Revenue 1,712Generation Performance Incentive Factor (2,268,016)

(g) Concept: SalesOfElectricity

Unbilled revenues are not included in Line No. 12, but rather in Line No. 21, and are ($41,782,825) and $20,924,930 for 2021 and 2020, respectively, with related MWH's of (730,595) and 240,833, respectively.

(h) Concept: MiscellaneousServiceRevenues

Rates Billing and Payment 18,513,176General Office Collection and Other (67,136)

(i) Concept: OtherElectricRevenue

Other Variable Revenue - Reg 387,060Retail Unbilled Revenue 20,924,930Municipal County Tax Collection 294,717Sales and Use Tax Collection Fees (293,753)Shared Solar 14,940Transmission Study Revenue 340,000Generation Performance Incentive Factor 1,816,015

(j) Concept: MegawattHoursSoldSalesOfElectricity

Unbilled revenues are not included in Line No. 12, but rather in Line No. 21, and are ($41,782,825) and $20,924,930 for 2021 and 2020, respectively, with related MWH's of (730,595) and 240,833, respectively.

(k) Concept: MegawattHoursSoldSalesOfElectricity

Unbilled revenues are not included in Line No. 12, but rather in Line No. 21, and are ($41,782,825) and $20,924,930 for 2021 and 2020, respectively, with related MWH's of (730,595) and 240,833, respectively.

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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 Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	FLER_RS-1	15,406,812	2,166,624,138	1,233,526	149,881	0.1406
2	FLEO_LS1U	24,373	3,027,693	26,230	11,150	0.1242
3	FLER_RST1	518	68,890	26	238,167	0.1330
4	FLER_RSL1	5,522,018	742,286,487	420,919	157,427	0.1344
5	FLER_RSS1	154,791	22,746,250	26,973	68,866	0.1469
6	FLER_RSSL1	86,278	12,015,128	12,630	81,974	0.1393
7	FLER_RST1A		41	3	1,746
8	Asset Securitization Charge		(a) 44,866,056
41	TOTAL Billed Residential Sales	21,194,790	2,901,902,571	1,720,307	709,211	0.1369
42	TOTAL Unbilled Rev. (See Instr. 6)	(b) 0	(c) 0
43	TOTAL	21,194,790	(d) 2,901,902,571	1,720,307	709,211	0.1369

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: ResidentialSalesBilled

Due to a a classification error, DEF's original submission listed incorrect data on Page 304 under Column c. This did not impact the total reported. Incorrect amount has been restated and corrected.

(b) Concept: MegawattHoursSoldResidentialSalesUnbilled

Unbilled MWH and Revenues are (463,451) & ($33,075,397), respectively

(c) Concept: ResidentialSalesUnbilled

Unbilled MWH and Revenues are (463,451) & ($33,075,397), respectively

(d) Concept: ResidentialSales

Due to a a classification error, DEF's original submission listed incorrect data on Page 304 under Column c. This did not impact the total reported. Incorrect amount has been restated and corrected.

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	11,841,210	1,183,844,981	192,614

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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.)	3,417,754	256,560,586	2,154

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	FLEC_C2PA	2	22,406	3	8,667	11.2030
2	FLEC_C2SA			1
3	FLEC_CS1P			1
4	FLEC_GS2	195,362	17,008,811	11,500	203,851	0.0871
5	FLEC_GS2UM	203	50,624	322	7,542	0.2494
6	FLEC_GSDT	34	4,999	1	410,741	0.1470
7	FLEC_GST1T	2,475	211,794	1	28,354,857	0.0856
8	FLEC_GT1PA		17
9	FLEC_GT1TA		1,270
10	FLEC_SS1TA		277
11	FLEC_TS1	8	2,990	61	1,644	0.3738
12	FLER_RS-1	15	2,434	26	6,780	0.1623
13	FLEC_SS2P	65,521	4,211,570	2	378,918,486	0.0643
14	FLEC_SS2T	2,265	164,076	1	26,212,942	0.0724
15	FLEC_SS3P	82,980	5,639,383	2	507,272,807	0.0680
16	FLEC_IS1P	103,537	7,861,150	22	56,646,590	0.0759
17	FLEC_IST1T	319,886	15,667,373	5	767,725,629	0.0490
18	FLEC_CST1P	41,344	2,873,368	1	669,771,855	0.0695
19	FLEC_CG095		67,988	2
20	FLEC_CG096		3,263	2
21	FLEC_IS2S	2,161	170,088	2	14,819,044	0.0787
22	FLEC_IST2T	835,674	39,630,300	7	1,425,044,020	0.0474
23	FLEC_CST2P	3,604	171,806		129,737,249	0.0477
24	FLEC_CG296		2,271	1
25	FLEC_IS2PA		12,618
26	FLEC_IT2PA		28,945
27	FLEC_SS1PA		29,203
28	FLEC_GSDP	39,465	4,274,741	62	16,784,218	0.1083
29	FLEO_LS1U	143,615	16,005,122	15,592	233,729	0.1114
30	FLEC_IST1P	343,164	23,097,535	57	142,741,474	0.0673
31	FLEC_SS1P	21,266	2,143,435	3	149,823,939	0.1008
32	FLEC_SS1T	4,559	541,275	3	27,981,097	0.1187
33	FLEC_IST1S	10,158	688,731	4	54,452,309	0.0678
34	FLEC_GSDTP	1,057,272	91,711,477	179	161,389,971	0.0867
35	FLEC_IS1S	4,997	410,609	4	21,376,424	0.0822
36	FLEC_GST1S	74,533	9,115,007	975	3,313,040	0.1223
37	FLEC_GST1P	755	89,363	4	3,236,936	0.1184
38	FLEC_GSDTS	6,489,127	602,417,914	12,918	27,990,952	0.0928
39	FLEC_GS1S	1,769,097	253,255,654	122,035	1,131,813	0.1432
40	FLEC_GS1P	10,701	1,468,361	60	4,202,198	0.1372
41	FLEC_GS1UM	217	48,359	191	46,571	0.2229
42	FLEC_GSDS	2,814,811	318,093,673	30,566	4,809,407	0.1130
43	FLEC_IST2P	439,645	23,898,970	30	362,939,272	0.0544
44	FLEC_IST2S	324,375	19,634,801	64	174,274,599	0.0605
45	FLEC_IS2P	55,667	3,796,074	7	212,166,775	0.0682
46	FLEC_GT1SA		6,423	1	4,991
47	FLEC_GSDSA	11	53,516	35	4,446	4.8651
48	FLEC_GSDPA		4,959
49	FLEC_GDTSA	458	102,366	14	384,048	0.2235
50	FLEC_GDTPA		100,602	1
51	FLEC_IT2SA		11,584
52	Asset Securitization Charge		(a) 24,404,008
41	TOTAL Billed Commercial and Industrial Sales	15,258,964	1,440,405,567	194,768	5,374,430,913	0.0944
42	TOTAL Unbilled Rev. (See Instr. 6)	(b) 0	(c) 0
43	TOTAL	15,258,964	(d) 1,440,405,567	194,768	5,374,430,913	0.0944

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: CommercialAndIndustrialSalesBilled

Due to a a classification error, DEF's original submission listed incorrect data on Page 304 under Column c. This did not impact the total reported. Incorrect amount has been restated and corrected.

(b) Concept: MegawattHoursSoldCommercialAndIndustrialSalesUnbilled

Unbilled MWH and Revenues are (207,978) & ($7,274,168), respectively

(c) Concept: CommercialAndIndustrialSalesUnbilled

Unbilled MWH and Revenues are (207,978) & ($7,274,168), respectively

(d) Concept: CommercialAndIndustrialSales

Due to a a classification error, DEF's original submission listed incorrect data on Page 304 under Column c. This did not impact the total reported. Incorrect amount has been restated and corrected.

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	FLEO_LS1M	2,816	201,383	242	139,741	0.0715
2	FLEO_LS1U	17,684	2,143,569	1,264	167,822	0.1212
3	FLEC_GS2	1,472	186,233	1,292	13,680	0.1265
4	FLEC_GSDTS	48	5,267	2	346,784	0.1097
5	FLEC_GS1S	131	18,658	3	524,092	0.1424
6	FLEC_GS1UM	2	334	3	6,408	0.1670
7	FLEC_GS2UM	252	27,763	217	13,980	0.1102
8	FLEC_GSDS	89	11,071	2	534,231	0.1244
9	FLEO_LS1U1	1,849	126,338	10	2,234,243	0.0683
10	FLEC_GSDSA		32
11	Asset Securitization Charge		(a) 227,604
41	TOTAL Billed Public Street and Highway Lighting	24,343	2,493,044	3,035	3,980,981	0.1024
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL	24,343	(b) 2,493,044	3,035	3,980,981	0.1024

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: PublicStreetAndHighwayLightingBilled

Due to a a classification error, DEF's original submission listed incorrect data on Page 304 under Column c. This did not impact the total reported. Incorrect amount has been restated and corrected.

(b) Concept: PublicStreetAndHighwayLighting

Due to a a classification error, DEF's original submission listed incorrect data on Page 304 under Column c. This did not impact the total reported. Incorrect amount has been restated and corrected.

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	FLEC_CST1P	16,098	1,039,090	2	98,225,761	0.0645
2	FLEC_GDTPA		20,956
3	FLEC_GDTSA	4	82,731	1	47,020	20.6828
4	FLEC_GS1P	991	165,313	13	907,691	0.1668
5	FLEC_GS1S	334,238	45,917,323	12,917	310,520	0.1374
6	FLEC_GS1UM	188	50,846	232	9,690	0.2705
7	FLEC_GS2	10,975	1,268,165	1,364	96,521	0.1156
8	FLEC_GS2UM	2,107	216,941	319	79,307	0.1030
9	FLEC_GSDP	31,026	3,420,269	17	21,986,723	0.1102
10	FLEC_GSDPA		2,542
11	FLEC_GSDS	443,593	51,277,702	1,789	2,975,136	0.1156
12	FLEC_GSDSA		35,479	1	3,391
13	FLEC_GSDTP	561,288	47,176,171	71	95,044,107	0.0840
14	FLEC_GSDTS	1,052,284	106,339,704	2,240	5,637,979	0.1011
15	FLEC_GSDTT	399,515	28,563,077	1	4,794,175,592	0.0715
16	FLEC_GST1S	58,679	6,683,315	431	1,632,606	0.1139
17	FLEC_GT1SA		11,584
18	FLEC_IS1P	20,147	1,543,666	11	22,112,403	0.0766
19	FLEC_IS1S	8,502	674,866	10	10,482,155	0.0794
20	FLEC_IS2PA		4,165
21	FLEC_IS2S	6,441	579,936	4	20,888,636	0.0900
22	FLEC_IST1P	23,694	1,516,892	4	71,082,509	0.0640
23	FLEC_IST2P	39,866	2,125,323	3	159,464,063	0.0533
24	FLEC_IST2S	6,966	396,454	3	33,435,342	0.0569
25	FLEC_SS1P	41,850	3,378,355	2	251,099,464	0.0807
26	FLEC_SS1T	2,593	486,950	2	13,149,106	0.1878
27	FLEC_TS1		6		36
28	FLEO_LS1M	20,014	1,376,434	831	288,997	0.0688
29	FLEO_LS1U	120,696	14,839,373	4,553	318,118	0.1229
30	FLEO_LS1U1	1,944	133,395	81	288,087	0.0686
31	FLER_RS-1	1	99		22,500	0.0990
32	Asset Securitization Charge		(a) 17,480,853
41	TOTAL Billed Other Sales to Public Authorities	3,203,700	301,846,269	24,902	5,603,763,460	0.0942
42	TOTAL Unbilled Rev. (See Instr. 6)	(b) 0	(c) 0
43	TOTAL	3,203,700	(d) 301,846,269	24,902	5,603,763,460	0.0942

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: OtherSalesToPublicAuthoritiesBilled

Due to a a classification error, DEF's original submission listed incorrect data on Page 304 under Column c. This did not impact the total reported. Incorrect amount has been restated and corrected.

(b) Concept: MegawattHoursSoldOtherSalesToPublicAuthoritiesUnbilled

Unbilled MWH and Revenues are (59,165) & ($1,433,260), respectively

(c) Concept: OtherSalesToPublicAuthoritiesUnbilled

Unbilled MWH and Revenues are (59,165) & ($1,433,260), respectively

(d) Concept: OtherSalesToPublicAuthorities

Due to a a classification error, DEF's original submission listed incorrect data on Page 304 under Column c. This did not impact the total reported. Incorrect amount has been restated and corrected.

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	39,681,797	4,646,647,451	1,943,012	10,982,884,565	0.1171
42	TOTAL Unbilled Rev. (See Instr. 6) - All Accounts
43	TOTAL - All Accounts	39,681,797	4,646,647,451	1,943,012	10,982,884,565	0.1171

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	Exelon Generation Company, LLC	OS	9				17,658		685,540		685,540
2	Florida Municipal Power Agency	OS	9				7,680		320,779		320,779
3	Macquarie Energy LLC	SF	10				30,082		1,318,448		1,318,448
4	Morgan Stanley Capital Group Inc.	OS	177				7,456		368,665		368,665
5	Orlando Utilities Commission	OS	86				2,875		125,024		125,024
6	PJM Settlements, Inc	OS	24				19,636		1,012,904		1,012,904
7	Rainbow Energy Marketing Corporation	OS	9				696		31,145		31,145
8	Reedy Creek Improvement District	OS	9				82,500		2,279,126		2,279,126
9	Southern Company Services, Inc.	OS	9				16,663		798,293		798,293
10	Tallahassee (City of)	OS	9, 22				943		51,411		51,411
11	Tampa Electric Company	SF	9, 10				2,725		322,352		322,352
12	Tennessee Valley Authority	OS	8, 6				100		7,500		7,500
13	The Energy Authority	SF	4				211,748		5,951,561		5,951,561
14	(a) CITY OF CHATTAHOOCHEE, FL (ADJ)	RQ	126						1,733		1,733
15	CITY OF CHATTAHOOCHEE, FL	RQ	126
16	CITY OF HOMESTEAD (ADJ)	RQ	9
17	CITY OF HOMESTEAD	RQ	9
18	(b) CITY OF MOUNT DORA, FL (ADJ)	RQ	219						5,194		5,194
19	CITY OF MOUNT DORA, FL	RQ	219
20	(c) CITY OF WILLISTON, FL (ADJ)	RQ	220						2,135		2,135
21	CITY OF WILLISTON, FL	RQ	220
22	NEW SMYRNA BEACH (ADJ)	RQ	218
23	NEW SMYRNA BEACH	RQ	218
24	REEDY CREEK IMPROVEMENT DISTRICT (ADJ)	RQ	9
25	REEDY CREEK IMPROVEMENT DISTRICT	RQ	9	98	108	91	412,844	8,827,500	14,248,790		23,076,290
26	(d) SEMINOLE ELECTRIC COOPERATIVE, INC. (ADJ)	RQ	194						42,624		42,624
27	SEMINOLE ELECTRIC COOPERATIVE, INC.	RQ	194	219	206	160	269,524	5,583,250	12,419,798		18,003,048
28	SEMINOLE ELECTRIC COOPERATIVE, INC. (ADJ)	RQ	210
29	SEMINOLE ELECTRIC COOPERATIVE, INC.	RQ	210
30	SEMINOLE ELECTRIC COOPERATIVE, INC. (ADJ)	RQ	213
31	SEMINOLE ELECTRIC COOPERATIVE, INC.	RQ	213	500	500	494	1,445,404	70,645,000	46,413,240		117,058,240
32	(e) SOUTHEASTERN POWER ADMINISTRATION (ADJ)	RQ	65				1,032	20,900	66,819		45,919
33	SOUTHEASTERN POWER ADMINISTRATION	RQ	65	9	9	5	12,229	299,479	506,497		805,976
34	(f) TALQUIN/TRI COUNTY (ADJ)	RQ	1				17	116	518	264	898
35	TALQUIN/TRI COUNTY	RQ	1				157	1,187	5,234	2,904	9,325
36	(g) TAMPA ELECTRIC COMPANY (ADJ)	RQ	9						169,805		169,805
37	TAMPA ELECTRIC COMPANY	RQ	9		300	213	1,162,527		48,871,447		48,871,447
38	Covanta								260,155		260,155
15	Subtotal - RQ						3,301,670	85,377,432	122,534,948	3,168	207,915,548
16	Subtotal-Non-RQ						400,762		13,532,904		13,532,904
17	Total						3,702,432	85,377,432	136,067,852	3,168	221,448,452

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: NameOfCompanyOrPublicAuthorityReceivingElectricityPurchasedForResale

These sales are Out of Period adjustments related to requirements services. The sales were classified as RQ to ensure the Page 311 total column g, for RQ and non-RQ tie to Page 401 line 23 and 24 column b, respectively.

(b) Concept: NameOfCompanyOrPublicAuthorityReceivingElectricityPurchasedForResale

These sales are Out of Period adjustments related to requirements services. The sales were classified as RQ to ensure the Page 311 total column g, for RQ and non-RQ tie to Page 401 line 23 and 24 column b, respectively.

(c) Concept: NameOfCompanyOrPublicAuthorityReceivingElectricityPurchasedForResale

These sales are Out of Period adjustments related to requirements services. The sales were classified as RQ to ensure the Page 311 total column g, for RQ and non-RQ tie to Page 401 line 23 and 24 column b, respectively.

(d) Concept: NameOfCompanyOrPublicAuthorityReceivingElectricityPurchasedForResale

These sales are Out of Period adjustments related to requirements services. The sales were classified as RQ to ensure the Page 311 total column g, for RQ and non-RQ tie to Page 401 line 23 and 24 column b, respectively.

(e) Concept: NameOfCompanyOrPublicAuthorityReceivingElectricityPurchasedForResale

These sales are Out of Period adjustments related to requirements services. The sales were classified as RQ to ensure the Page 311 total column g, for RQ and non-RQ tie to Page 401 line 23 and 24 column b, respectively.

(f) Concept: NameOfCompanyOrPublicAuthorityReceivingElectricityPurchasedForResale

These sales are Out of Period adjustments related to requirements services. The sales were classified as RQ to ensure the Page 311 total column g, for RQ and non-RQ tie to Page 401 line 23 and 24 column b, respectively.

(g) Concept: NameOfCompanyOrPublicAuthorityReceivingElectricityPurchasedForResale

These sales are Out of Period adjustments related to requirements services. The sales were classified as RQ to ensure the Page 311 total column g, for RQ and non-RQ tie to Page 401 line 23 and 24 column b, respectively.

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	4,898,928	6,116,493
5	FuelSteamPowerGeneration (501) Fuel	301,933,469	232,930,049
6	SteamExpensesSteamPowerGeneration (502) Steam Expenses	7,104,005	3,994,481
7	SteamFromOtherSources (503) Steam from Other Sources
8	SteamTransferredCredit (Less) (504) Steam Transferred-Cr.
9	ElectricExpensesSteamPowerGeneration (505) Electric Expenses	69,568	67,478
10	MiscellaneousSteamPowerExpenses (506) Miscellaneous Steam Power Expenses	4,349,355	5,535,323
11	RentsSteamPowerGeneration (507) Rents
12	Allowances (509) Allowances	8,687	6,011
13	SteamPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 4 thru 12)	318,364,012	248,649,835
14	SteamPowerGenerationMaintenanceAbstract Maintenance
15	MaintenanceSupervisionAndEngineeringSteamPowerGeneration (510) Maintenance Supervision and Engineering	7,909,862	5,271,665
16	MaintenanceOfStructuresSteamPowerGeneration (511) Maintenance of Structures	22,875,516	22,188,450
17	MaintenanceOfBoilerPlantSteamPowerGeneration (512) Maintenance of Boiler Plant	11,229,317	11,394,108
18	MaintenanceOfElectricPlantSteamPowerGeneration (513) Maintenance of Electric Plant	4,506,899	6,405,093
19	MaintenanceOfMiscellaneousSteamPlant (514) Maintenance of Miscellaneous Steam Plant	3,591,149	5,398,978
20	SteamPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 15 thru 19)	50,112,743	50,658,294
21	PowerProductionExpensesSteamPower TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)	368,476,755	299,308,129
22	NuclearPowerGenerationAbstract B. Nuclear Power Generation
23	NuclearPowerGenerationOperationAbstract Operation
24	OperationSupervisionAndEngineeringNuclearPowerGeneration (517) Operation Supervision and Engineering
25	NuclearFuelExpense (518) Fuel
26	CoolantsAndWater (519) Coolants and Water
27	SteamExpensesNuclearPowerGeneration (520) Steam Expenses
28	SteamFromOtherSourcesNuclearPowerGeneration (521) Steam from Other Sources
29	SteamTransferredCreditNuclearPowerGeneration (Less) (522) Steam Transferred-Cr.
30	ElectricExpensesNuclearPowerGeneration (523) Electric Expenses
31	MiscellaneousNuclearPowerExpenses (524) Miscellaneous Nuclear Power Expenses	5,762,353	3,347,534
32	RentsNuclearPowerGeneration (525) Rents
33	NuclearPowerGenerationOperationsExpense TOTAL Operation (Enter Total of lines 24 thru 32)	5,762,353	3,347,534
34	NuclearPowerGenerationMaintenanceAbstract Maintenance
35	MaintenanceSupervisionAndEngineeringNuclearPowerGeneration (528) Maintenance Supervision and Engineering	35	2,750
36	MaintenanceOfStructuresNuclearPowerGeneration (529) Maintenance of Structures	195
37	MaintenanceOfReactorPlantEquipmentNuclearPowerGeneration (530) Maintenance of Reactor Plant Equipment
38	MaintenanceOfElectricPlantNuclearPowerGeneration (531) Maintenance of Electric Plant
39	MaintenanceOfMiscellaneousNuclearPlant (532) Maintenance of Miscellaneous Nuclear Plant
40	NuclearPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 35 thru 39)	160	2,750
41	PowerProductionExpensesNuclearPower TOTAL Power Production Expenses-Nuclear. Power (Enter Total of lines 33 & 40)	5,762,193	3,344,784
42	HydraulicPowerGenerationAbstract C. Hydraulic Power Generation
43	HydraulicPowerGenerationOperationAbstract Operation
44	OperationSupervisionAndEngineeringHydraulicPowerGeneration (535) Operation Supervision and Engineering
45	WaterForPower (536) Water for Power
46	HydraulicExpenses (537) Hydraulic Expenses
47	ElectricExpensesHydraulicPowerGeneration (538) Electric Expenses
48	MiscellaneousHydraulicPowerGenerationExpenses (539) Miscellaneous Hydraulic Power Generation Expenses
49	RentsHydraulicPowerGeneration (540) Rents
50	HydraulicPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 44 thru 49)
51	HydraulicPowerGenerationContinuedAbstract C. Hydraulic Power Generation (Continued)
52	HydraulicPowerGenerationMaintenanceAbstract Maintenance
53	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration (541) Mainentance Supervision and Engineering
54	MaintenanceOfStructuresHydraulicPowerGeneration (542) Maintenance of Structures
55	MaintenanceOfReservoirsDamsAndWaterways (543) Maintenance of Reservoirs, Dams, and Waterways
56	MaintenanceOfElectricPlantHydraulicPowerGeneration (544) Maintenance of Electric Plant
57	MaintenanceOfMiscellaneousHydraulicPlant (545) Maintenance of Miscellaneous Hydraulic Plant
58	HydraulicPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 53 thru 57)
59	PowerProductionExpensesHydraulicPower TOTAL Power Production Expenses-Hydraulic Power (Total of Lines 50 & 58)
60	OtherPowerGenerationAbstract D. Other Power Generation
61	OtherPowerGenerationOperationAbstract Operation
62	OperationSupervisionAndEngineeringOtherPowerGeneration (546) Operation Supervision and Engineering	10,979,583	11,689,052
63	Fuel (547) Fuel	1,266,976,697	860,892,640
64	GenerationExpenses (548) Generation Expenses	3,978,297	3,293,606
64.1	OperationOfEnergyStorageEquipment (548.1) Operation of Energy Storage Equipment
65	MiscellaneousOtherPowerGenerationExpenses (549) Miscellaneous Other Power Generation Expenses	18,736,169	18,373,686
66	RentsOtherPowerGeneration (550) Rents
67	OtherPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 62 thru 67)	1,300,670,746	894,248,984
68	OtherPowerGenerationMaintenanceAbstract Maintenance
69	MaintenanceSupervisionAndEngineeringOtherPowerGeneration (551) Maintenance Supervision and Engineering	8,819,433	8,285,145
70	MaintenanceOfStructures (552) Maintenance of Structures	5,985,414	5,814,331
71	MaintenanceOfGeneratingAndElectricPlant (553) Maintenance of Generating and Electric Plant	22,350,757	20,956,999
71.1	MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration (553.1) Maintenance of Energy Storage Equipment
72	MaintenanceOfMiscellaneousOtherPowerGenerationPlant (554) Maintenance of Miscellaneous Other Power Generation Plant	40,054,390	38,218,006
73	OtherPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 69 thru 72)	77,209,994	73,274,481
74	PowerProductionExpensesOtherPower TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)	1,377,880,740	967,523,465
75	OtherPowerSuplyExpensesAbstract E. Other Power Supply Expenses
76	PurchasedPower (555) Purchased Power	670,909,301	596,039,865
76.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations	0
77	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching	2,090,845	2,164,255
78	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	3,014,465	415,186
79	OtherPowerSupplyExpense TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)	669,985,681	597,788,934
80	PowerProductionExpenses TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74 & 79)	2,410,580,983	1,861,275,744
81	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
82	TransmissionExpensesOperationAbstract Operation
83	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	45,131	52,734
85	LoadDispatchReliability (561.1) Load Dispatch-Reliability	5,213,655	5,217,642
86	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	3,323,324	3,292,527
87	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling	1,262,387	1,284,904
88	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services
89	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development	237,554	215,329
90	TransmissionServiceStudies (561.6) Transmission Service Studies	2,886
91	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies	133,709
92	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services
93	StationExpensesTransmissionExpense (562) Station Expenses	1,295,697	1,115,424
93.1	OperationOfEnergyStorageEquipmentTransmissionExpense (562.1) Operation of Energy Storage Equipment
94	OverheadLineExpense (563) Overhead Lines Expenses	515,184	887,019
95	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses
96	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	7,289,210	7,035,405
97	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	5,111,064	5,027,010
98	RentsTransmissionElectricExpense (567) Rents	1,277,838	4,839
99	TransmissionOperationExpense TOTAL Operation (Enter Total of Lines 83 thru 98)	25,701,867	24,132,833
100	TransmissionMaintenanceAbstract Maintenance
101	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering	4,538	18,151
102	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	784,696	782,881
103	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware
104	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software	1,877,119	1,791,665
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	3,648,144	4,963,698
107.1	MaintenanceOfEnergyStorageEquipmentTransmission (570.1) Maintenance of Energy Storage Equipment
108	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	11,886,777	6,397,450
109	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines	603,932
110	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant	117,470	105,029
111	TransmissionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 101 thru 110)	18,687,736	13,848,816
112	TransmissionExpenses TOTAL Transmission Expenses (Total of Lines 99 and 111)	44,389,603	37,981,649
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	1,515,893	1,331,000
135	LoadDispatching (581) Load Dispatching	5,262,797	5,493,465
136	StationExpensesDistribution (582) Station Expenses	392,431	279,634
137	OverheadLineExpenses (583) Overhead Line Expenses	6,955,587	5,641,379
138	UndergroundLineExpenses (584) Underground Line Expenses	3,564,799	3,296,221
138.1	OperationOfEnergyStorageEquipmentDistribution (584.1) Operation of Energy Storage Equipment
139	StreetLightingAndSignalSystemExpenses (585) Street Lighting and Signal System Expenses
140	MeterExpenses (586) Meter Expenses	7,023,410	7,976,435
141	CustomerInstallationsExpenses (587) Customer Installations Expenses	3,430,174	3,329,465
142	MiscellaneousDistributionExpenses (588) Miscellaneous Expenses	23,211,093	22,733,419
143	RentsDistributionExpense (589) Rents	1,041,642	410,483
144	DistributionOperationExpensesElectric TOTAL Operation (Enter Total of Lines 134 thru 143)	52,397,826	50,491,501
145	DistributionExpensesMaintenanceAbstract Maintenance
146	MaintenanceSupervisionAndEngineering (590) Maintenance Supervision and Engineering	846,117	918,236
147	MaintenanceOfStructuresDistributionExpense (591) Maintenance of Structures
148	MaintenanceOfStationEquipment (592) Maintenance of Station Equipment	2,831,971	2,129,081
148.1	MaintenanceOfEnergyStorageEquipment (592.2) Maintenance of Energy Storage Equipment
149	MaintenanceOfOverheadLines (593) Maintenance of Overhead Lines	72,636,380	74,089,126
150	MaintenanceOfUndergroundLines (594) Maintenance of Underground Lines	6,824,087	7,805,170
151	MaintenanceOfLineTransformers (595) Maintenance of Line Transformers	1,708,084	2,234,430
152	MaintenanceOfStreetLightingAndSignalSystems (596) Maintenance of Street Lighting and Signal Systems	9,113,138	8,301,383
153	MaintenanceOfMeters (597) Maintenance of Meters	1,961,234	1,721,169
154	MaintenanceOfMiscellaneousDistributionPlant (598) Maintenance of Miscellaneous Distribution Plant	1,016,535	949,926
155	DistributionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 146 thru 154)	96,937,546	98,148,521
156	DistributionExpenses TOTAL Distribution Expenses (Total of Lines 144 and 155)	149,335,372	148,640,022
157	CustomerAccountsExpensesAbstract 5. CUSTOMER ACCOUNTS EXPENSES
158	CustomerAccountsExpensesOperationsAbstract Operation
159	SupervisionCustomerAccountExpenses (901) Supervision	418,268	324,414
160	MeterReadingExpenses (902) Meter Reading Expenses	1,872,128	4,961,380
161	CustomerRecordsAndCollectionExpenses (903) Customer Records and Collection Expenses	43,891,017	46,357,825
162	UncollectibleAccounts (904) Uncollectible Accounts	13,520,969	18,779,151
163	MiscellaneousCustomerAccountsExpenses (905) Miscellaneous Customer Accounts Expenses	15,509	28,185
164	CustomerAccountExpenses TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)	59,717,891	70,450,955
165	CustomerServiceAndInformationalExpensesAbstract 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166	CustomerServiceAndInformationalExpensesOperationAbstract Operation
167	SupervisionCustomerServiceAndInformationExpenses (907) Supervision
168	CustomerAssistanceExpenses (908) Customer Assistance Expenses	117,986,874	115,380,899
169	InformationalAndInstructionalAdvertisingExpenses (909) Informational and Instructional Expenses	443,489	1,106,917
170	MiscellaneousCustomerServiceAndInformationalExpenses (910) Miscellaneous Customer Service and Informational Expenses	1,211,100	1,022,754
171	CustomerServiceAndInformationExpenses TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)	119,641,463	117,510,570
172	SalesExpenseAbstract 7. SALES EXPENSES
173	SalesExpenseOperationAbstract Operation
174	SupervisionSalesExpense (911) Supervision
175	DemonstratingAndSellingExpenses (912) Demonstrating and Selling Expenses	10,817,201	9,804,174
176	AdvertisingExpenses (913) Advertising Expenses	121,611	78,610
177	MiscellaneousSalesExpenses (916) Miscellaneous Sales Expenses	293,511	217,868
178	SalesExpenses TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)	11,232,323	10,100,652
179	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
180	AdministrativeAndGeneralExpensesOperationAbstract Operation
181	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	89,708,129	57,295,546
182	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	50,615,841	44,889,570
183	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit	42
184	OutsideServicesEmployed (923) Outside Services Employed	38,218,182	33,059,929
185	PropertyInsurance (924) Property Insurance	187,828,563	323,582,362
186	InjuriesAndDamages (925) Injuries and Damages	14,418,290	7,914,617
187	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	13,582,939	21,243,687
188	FranchiseRequirements (927) Franchise Requirements
189	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	4,992,759	4,834,912
190	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.	1,315,238	1,761,700
191	GeneralAdvertisingExpenses (930.1) General Advertising Expenses	2,375,570	1,659,875
192	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	13,308,440	13,812,316
193	RentsAdministrativeAndGeneralExpense (931) Rents	22,083,769	23,871,732
194	AdministrativeAndGeneralOperationExpense TOTAL Operation (Enter Total of Lines 181 thru 193)	409,200,322	502,778,214
195	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
196	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	516,903	54,202
197	AdministrativeAndGeneralExpenses TOTAL Administrative & General Expenses (Total of Lines 194 and 196)	409,717,225	502,832,416
198	OperationsAndMaintenanceExpensesElectric TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 156, 164, 171, 178, and 197)	3,204,614,860	2,748,792,008

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	Purchased Power:
2	Citrus World	OS	(a) COG - Note 1				45					1,232		1,232
3	Lake County	OS	(b) COG - Note 1				4,707					170,625		170,625
4	Lee County	OS	(c) COG - Note 1				6,946					331,149		331,149
5	Metro-Dade County	OS	(d) COG - Note 1				4,146					193,671		193,671
6	Orange Cogen	OS	(e) COG - Note 1				376,107				74,172,395	14,962,865		89,135,260
7	Orlando Cogen Limited	OS	(f) COG - Note 1				1,020,608				74,711,198	55,376,994		130,088,192
8	Pasco County Resource Recovery	OS	(g) COG - Note 1				164,726				27,412,320	4,758,201		32,170,521
9	PCS Phoshate	OS	(h) COG - Note 1				672					29,449		29,449
10	Pinellas County Resource Recovery	OS	(i) COG - Note 1				427,622				65,253,240	11,902,942		77,156,182
11	Polk Power Partners LP	OS	(j) COG - Note 1				407,908				101,978,672	13,159,225		115,137,897
12	Shady Hill Power Company	OS	6				307,145				22,173,300	22,956,065		45,129,365
13	Vandolah Power Company	OS	67				1,158,629				40,496,977	79,753,217		120,250,194
14	Southern Company Services	OS	111				169,235				18,172,295	7,336,350		25,508,645
15	Southeastern Power Adminiistration	OS	65				49,725					1,789,337		1,789,337
16	Carolina Power and Light	OS	(k) Note 1									549		549
17	Dominion Energy South Carolina, Inc.						400					16,200		16,200
18	Duke Eectric Transmission	OS	(l) Note 1									70,029		70,029
19	EDF Trading North America, LLC	OS	10				158					6,320		6,320
20	Exelon Generation Company, LLC	OS	8,10				105,195					5,783,972		5,783,972
21	Florida Power & Light Company	OS	102				258,140				543,437	13,997,121		14,540,558
22	Jacksonville Electric Authority	OS	91									79,488		79,488
23	Macquarie Energy LLC	OS					47,603					2,542,341		2,542,341
24	Morgan Stanley Capital Group Inc.	OS	177				13,306					742,844		742,844
25	Orlando Utilities Commission	OS	85				29,174					1,950,171		1,950,171
26	PJM Settlements	OS	24							0		15,749		15,749
27	Rainbow Energy Marketing Corporation	OS					35,878					1,676,252		1,676,252
28	Seminole Electric Cooperative, Inc.	OS										3,517		3,517
29	South Carolina Public Service Authority											296		296
30	Southern Company Services, Inc.	OS					64,536					3,439,629		3,439,629
31	Tallahassee (City of)	OS	122				1,389				27,439	21,283		6,156
32	Tampa Electric Company	OS	80				24,070					1,387,544		1,387,544
33	Tennessee Valley Authority Transmission											25,246		25,246
34	The Energy Authority	OS	71				6,943					683,560		683,560
35	Tyr Energy, LLC						1,676					86,560		86,560
36	City of Alachua	EX										21,448		21,448
37	City of Chattahoochee	EX										42		42
38	City of Homestead	EX
39	City of Mount Dora	EX										226,547		226,547
40	City of Wauchula	EX										12,023		12,023
41	City of Winter Park	EX										35,040		35,040
42	Florida Municipal Power Agency	EX										8,223		8,223
43	Florida Power and Light EMT	EX
44	Macquarie Energy LLC	EX
45	Quincy	EX										118,801		118,801
46	Reedy Creek Improvement Distri	EX										129,369		129,369
47	Seminole Electric Coop Inc.	EX										296,419		296,419
48	Tampa Electric Company	EX										2		2
49	The City of Bartow	EX										2,414		2,414
50	The City of Williston	EX										39,198		39,198
51	The Energy Authority	EX										83		83
52	Inadvertent Interchange (Net)	OS					416
53	Net Metering Customer True Up	AD										161,397		161,397
15	TOTAL						4,687,105	0	0	0	424,886,395	246,022,905	0	670,909,301

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: RateScheduleTariffNumber

This is a QF Cogeneration Facility.

(b) Concept: RateScheduleTariffNumber

This is a QF Cogeneration Facility.

(c) Concept: RateScheduleTariffNumber

This is a QF Cogeneration Facility.

(d) Concept: RateScheduleTariffNumber

This is a QF Cogeneration Facility.

(e) Concept: RateScheduleTariffNumber

This is a QF Cogeneration Facility.

(f) Concept: RateScheduleTariffNumber

This is a QF Cogeneration Facility.

(g) Concept: RateScheduleTariffNumber

This is a QF Cogeneration Facility.

(h) Concept: RateScheduleTariffNumber

This is a QF Cogeneration Facility.

(i) Concept: RateScheduleTariffNumber

This is a QF Cogeneration Facility.

(j) Concept: RateScheduleTariffNumber

This is a QF Cogeneration Facility.

(k) Concept: RateScheduleTariffNumber

Carolina Power and Light is an affiliate of Duke Energy Corporation.

(l) Concept: RateScheduleTariffNumber

Carolina Power and Light is an affiliate of Duke Energy Corporation.

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	City of Alachua	Various	Various	FNO		Various	Various	0	15,418	15,236	104,852		25,030	129,882
2	City of Alachua	Various	Various	OS		Various	Various	0	0	0			2,190	2,190
3	The City of Bartow	Various	Various	FNO	T6/136	Various	Various	0	293,820	290,165	1,904,337		199,930	2,104,267
4	The City of Bartow	Various	Various	OS	T6/136	Various	Various	0	0	0			22,740	22,740
5	The City of Bartow	Various	Various	AD		Various	Various	0	0	0			64,508	64,508
6	Florida Municipal Power Agency	Various	Various	FNO	T6/148	Various	Various	0	2,041,164	2,014,895	13,592,699		1,426,433	15,019,132
7	Florida Municipal Power Agency	Various	Various	OS	T6/148	Various	Various	0	0	0			246,088	246,088
8	Florida Municipal Power Agency	Various	Various	NF		Various	Various	0	0	0			1,923	1,923
9	Florida Municpal Power Agency	Various	Various	AD		Various	Various	0	0	0			436,427	436,427
10	Quincy	Various	Various	FNO	T6/137	Various	Various	0	146,643	144,813	528,844		127,960	656,804
11	Quincy	Various	Various	OS	T6/137	Various	Various	0	0	0			9,900	9,900
12	Quincy	Various	Various	AD		Various	Various	0	0	0			21,817	21,817
13	Florida Power and Light EMT	Various	Various	NF	T6/7C	Various	Various	0	0	0			2,667	2,667
14	Florida Power and Light EMT	Various	Various	AD		Various	Various	0	0	0			3	3
15	City of Homestead	Various	Various	AD		Various	Various	0	0	0			6,357	6,357
16	City of Lakeland	Various	Various	NF		Various	Various	0	0	0			3,865	3,865
17	City of Mount Dora	Various	Various	FNO	T6/133	Various	Various	0	95,106	93,926	694,467		167,920	862,387
18	City of Mount Dora	Various	Various	OS		Various	Various	0	0	0			6,900	6,900
19	City of Mount Dora	Various	Various	AD		Various	Various	0	0	0			19,355	19,355
20	City of New Smyrna Beach	Various	Various	AD		Various	Various	0	0	0			2,430	2,430
21	Orlando Utilities Comm	Various	Various	NF		Various	Various	0	0	0			10	10
22	Reedy Creek Improvement Dist.	Various	Various	NF		Various	Various	0	1,006,961	994,462			20,148	20,148
23	Reedy Creek Improvement Dist.	Various	Various	FNO	T6/147	Various	Various	0	0	0	5,526,972		1,335,005	6,861,977
24	Reedy Creek Improvement Dist.	Various	Various	OS		Various	Various	0	0	0			37,980	37,980
25	Reedy Creek Improvement Dist.	Various	Various	AD		Various	Various	0	0	0			35,549	35,549
26	Seminole Electric Coop Inc.	Various	Various	NF	T6/24	Various	Various	0	0	0			35,850	35,850
27	Seminole Electric Coop Inc.	Various	Various	FNO	T6/143	Various	Various	0	11,966,456	11,816,853	85,412,014		12,679,307	98,091,321
28	Seminole Electric Coop Inc.	Various	Various	OS		Various	Various	0	0	0			871,317	871,317
29	Seminole Electric Coop Inc.	Various	Various	AD		Various	Various	0	0	0			2,778,070	2,778,070
30	City of Tallahassee	Various	Various	NF		Various	Various	0	0	0			4,155	4,155
31	City of Tallahassee	Various	Various	AD		Various	Various	0	0	0			1,176	1,176
32	Tampa Electric Company	Various	Various	NF	T6/160C	Various	Various	0	0	0			26,427	26,427
33	Tampa Electric Company	Various	Various	AD		Various	Various	0	0	0			680	680
34	Rainbow Energy Marketing	Various	Various	NF		Various	Various	0	0	0			1,176	1,176
35	The Energy Authority	Various	Various	LFP	T6/140	Various	Various	4	0	0	145,832		15,304	161,136
36	The Energy Authority	Various	Various	NF	T6/68C	Various	Various	0	0	0			62,168	62,168
37	The Energy Authority	Various	Various	OS		Various	Various	0	0	0			75,564	75,564
38	The Energy Authority	Various	Various	AD		Various	Various	0	0	0			4,624	4,624
39	Macquarie Energy LLC	Various	Various	SFP		Various	Various	0	0	0			82,892	82,892
40	City of Chattahoochee	Various	Various	FNO		Various	Various	0	36,181	35,730	136,481		33,022	169,503
41	City of Chattahoochee	Various	Various	OS		Various	Various	0	0	0			3,840	3,840
42	City of Chattahoochee	Various	Various	AD		Various	Various	0	0	0			6,848	6,848
43	City of Wauchula	Various	Various	FNO	T6/150	Various	Various	0	63,124	62,339	407,816		98,644	506,460
44	City of Wauchula	Various	Various	OS		Various	Various	0	0	0			5,340	5,340
45	City of Wauchula	Various	Various	AD		Various	Various	0	0	0			12,002	12,002
46	The City of Williston	Various	Various	FNO	T6/125	Various	Various	0	36,122	35,311	242,507		58,706	301,213
47	The City of Williston	Various	Various	OS		Various	Various	0	0	0			3,300	3,300
48	The City of Williston	Various	Various	AD		Various	Various	0	0	0			7,288	7,288
49	City of Winter Park	Various	Various	FNO	T6/124	Various	Various	0	357,772	353,314	2,347,774		246,295	2,594,069
50	City of Winter Park	Various	Various	OS		Various	Various	0	0	0			8,400	8,400
51	City of Winter Park	Various	Various	AD		Various	Various	0	0	0			63,520	63,520
52	DEF Tax Accrual	Various	Various	AD		Various	Various	0	0	0			5,389,796	5,389,796
53	Southeastern Power Admin	Various	Various	OS		Various	Various	0	215,697	201,586			361,160	361,160
54	The Energy Authority - CXL	Various	Various	NF		Various	Various	0	0	0			45,755	45,755
55	Reedy Creek - CXL	Various	Various	NF		Various	Various	0	0	0			13,759	13,759
56	Tallahassee - CXL	Various	Various	NF		Various	Various	0	0	0			1,731	1,731
57	Florida Municpal Power - CXL	Various	Various	NF		Various	Various	0	0	0			2,386	2,386
58	Orlando Utilities Com	Various	Various	NF		Various	Various	0	0	0			4,801	4,801
59	Marcquarie Energy - CXL	Various	Various	NF		Various	Various	0	0	0			129,303	129,303
60	Morgan Stanley Capital - CXL	Various	Various	NF		Various	Various	0	0	0			37,607	37,607
61	Pa-NJ-Maryland Int (PJM) - CXL	Various	Various	NF		Various	Various	0	0	0			294,125	294,125
62	Tampa Electric Company - CXL	Various	Various	NF		Various	Various	0	0	0			16,166	16,166
63	Southern Company - CXL	Various	Various	NF		Various	Various	0	0	0			163,834	163,834
64	Exelon Generation Company LLC - CXL	Various	Various	NF		Various	Various	0	0	0			88,213	88,213
65	TAV - CXL	Various	Various	NF		Various	Various	0	0	0			1,900	1,900
66	Rainbow Energy Market - CXL	Various	Various	NF		Various	Various		0	0			3,655	3,655
67	Other from CXL	Various	Various	NF		Various	Various	0	0	0			6,243	6,243
68	P2P	Various	Various	NF		Various	Various	0	39,690	39,690
35	TOTAL							4	16,314,154	16,098,320	111,044,595	0	27,949,558	138,994,153

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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 Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	Tampa Electric Company	NF		0	7,289,210			7,289,210
	TOTAL		0	0	7,289,210	0	0	7,289,210

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line No.	Description (a)	Amount (b)
1	IndustryAssociationDues Industry Association Dues	613,477
2	NuclearPowerResearchExpenses Nuclear Power Research Expenses
3	OtherExperimentalAndGeneralResearchExpenses Other Experimental and General Research Expenses	55,731
4	PublicationAndDistributionExpensesForSecuritiesToStockholders Pub and Dist Info to Stkhldrs...expn servicing outstanding Securities	163,090
5	OtherMiscellaneousGeneralExpenses Oth Expn greater than or equal to 5,000 show purpose, recipient, amount. Group if less than $5,000
6	Dues to Various Organizations	456,646
7	Director's Fees and Expenses	665,556
8	Employees Moving Expenses	149,602
9	Employee Expenses	13,540,360
10	Miscellaneous Expenses	743,652
11	Service Company Allocations	29,696,554
46	MiscellaneousGeneralExpenses TOTAL	13,308,440

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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			35,290,199		35,290,199
2	Steam Production Plant	72,859,098				72,859,098
3	Nuclear Production Plant
4	Hydraulic Production Plant-Conventional
5	Hydraulic Production Plant-Pumped Storage
6	Other Production Plant	155,951,794				155,951,794
7	Transmission Plant	100,314,523				100,314,523
8	Distribution Plant	209,729,527				209,729,527
9	Regional Transmission and Market Operation
10	General Plant	48,055,306				48,055,306
11	Common Plant-Electric
12	TOTAL	586,910,249		35,290,199		622,200,448

B. Basis for Amortization Charges
Limited term electric depreciable plant base is $172,092,318 which is the cost of capitalized software. This includes amortized assets, which have been fully amortized but not yet retired. Intangible plant is amortized over 3, 5, 10 and 15 years.

	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	311 - Anclote Units 1 And 2	45,113	90 years	2	2	R2	7 years
13	311 - Crystal River Units 4 And 5	468,877	90 years	2	1	R2	12 years
14	312 - Anclote Units 1 And 2	225,856	55 years	13	2	R1	7 years
15	312 - Crystal River Units 4 And 5	1,735,885	55 years	13	2	R1	12 years
16	312.9 - Crystal River Units 4 And 5	1,713	7 years	15	20		5 years
17	314 - Anclote Units 1 And 2	159,797	50 years	3	3	R1	7 years
18	314 - Crystal River Units 4 And 5	287,042	50 years	3	1	R1	12 years
19	315 - Anclote Units 1 And 2	38,968	70 years	3	2	R1.5	7 years
20	315 - Crystal River Units 4 And 5	175,533	70 years	3	1	R1.5	12 years
21	316 - Anclote Units 1 And 2	9,617	45 years	6	2	R1	7 years
22	316 - Crystal River Units 4 And 5	38,357	45 years	6	2	R1	12 years
23	316 - System - Other	748	5 years		17		5 years
24	316.91 - Anclote Units 1 And 2	131	5 years		20		5 years
25	316.91 - Crystal River Units 4 And 5	1,067	5 years		20		5 years
26	316.92 - Anclote Units 1 And 2	128	7 years		14		7 years
27	316.92 - Crystal River Units 4 And 5	370	7 years		14		7 years
28	341 - Bartow Units 1 and 3	2,452	85 years		2	R1.5	12 years
29	341 - Bartow Units 2 and 4	91,093	85 years		3	R1.5	5 years
30	341 - Bayboro Units 1 Through 4	1,979	85 years		1	R1.5	2 years
31	341 - Citrus Units 1 and 2	112,439	85 years		3	R1.5	35 years
32	341 - Debary Units 2 Through 6	6,259	85 years		3	R1.5	5 years
33	341 - Debary Units 7 Through 10	5,376	85 years		3	R1.5	15 years
34	341 - Hines Energy Complex Unit 1	62,922	85 years		3	R1.5	17 years
35	341 - Hines Energy Complex Unit 2	19,051	85 years		3	R1.5	21 years
36	341 - Hines Energy Complex Unit 3	11,038	85 years		3	R1.5	23 years
37	341 - Hines Energy Complex Unit 4	13,434	85 years		3	R1.5	24 years
38	341 - Intercession City Unit 11	2,120	85 years		4	R1.5	20 years
39	341 - Intercession City Units 1 Through 6	4,507	85 years		3	R1.5	12 years
40	341 - Intercession City Units 12 Through 14	1,385	85 years		3	R1.5	22 years
41	341 - Intercession City Units 7 Through 10	9,930	85 years		3	R1.5	16 years
42	341 - Osprey Energy Center	71,246	85 years		2	R1.5	22 years
43	341 - Suwannee River Units 1 Through 3	4,628	85 years		1	R1.5	12 years
44	341 - Tiger Bay Cogeneration	11,401	85 years		2	R1.5	13 years
45	341 - University of Florida Cogeneration	6,786	85 years		2	R1.5	6 years
46	341.66 - Columbia Solar	2,521	30 years		3		29 years
47	341.66 - Debary Solar	2,382	30 years		3		29 years
48	341.66 - Hamilton Solar	2,570	30 years		3		27 years
49	341.66 - Lake Placid Solar	2,591	30 years		3		28 years
50	341.66 - New Solar 2020	12,065	30 years		3		29 years
51	341.66 - New Solar 2021	29,906	30 years		3		29 years
52	341.66 - Osceola Solar	86	30 years		3		25 years
53	341.66 - Perry Solar	347	30 years		3		25 years
54	341.66 - Suwannee Solar	60	30 years		3		26 years
55	341.66 - Trenton Solar	6,242	30 years		3		28 years
56	341-346 - University of Florida Cogeneration	2,531	50 years		3	R1.5	39 years
57	342 - Bartow Units 1 and 3	3,454	50 years	6	3	R1	12 years
58	342 - Bartow Units 2 and 4	41,867	50 years	6	3	R1	5 years
59	342 - Bayboro Units 1 Through 4	1,919	50 years	6	3	R1	2 years
60	342 - Citrus Units 1 and 2	227,134	50 years		3	R1	31 years
61	342 - Debary Units 2 Through 6	10,313	50 years	6	3	R1	5 years
62	342 - Debary Units 7 Through 10	6,456	50 years	6	4	R1	14 years
63	342 - Hines Energy Complex Unit 1	18,031	50 years	6	3	R1	16 years
64	342 - Hines Energy Complex Unit 2	12,566	50 years	6	3	R1	19 years
65	342 - Hines Energy Complex Unit 3	14,713	50 years	6	3	R1	21 years
66	342 - Hines Energy Complex Unit 4	7,493	50 years	6	3	R1	22 years
67	342 - Intercession City Unit 11	2,017	50 years	6	4	R1	18 years
68	342 - Intercession City Units 1 Through 6	5,406	50 years	6	7	R1	12 years
69	342 - Intercession City Units 12 Through 14	5,197	50 years	6	3	R1	21 years
70	342 - Intercession City Units 7 Through 10	7,820	50 years	6	3	R1	15 years
71	342 - Osprey Energy Center	13,820	50 years		2	R1	20 years
72	342 - Suwannee River Units 1 Through 3	6,336	50 years	6	3	R1	12 years
73	342 - Tiger Bay Cogeneration	5,566	50 years	6	2	R1	13 years
74	342 - University of Florida Cogeneration	6,486	50 years	6	2	R1	6 years
75	343 - Bartow Units 1 and 3	22,926	40 years	5	2	R0.5	11 years
76	343 - Bartow Units 2 and 4	502,334	40 years	5	3	R0.5	5 years
77	343 - Bayboro Units 1 Through 4	17,751	40 years	5	2	R0.5	2 years
78	343 - Citrus Units 1 and 2	920,777	40 years		3	R0.5	29 years
79	343 - Debary Units 2 Through 6	26,366	40 years	5	3	R0.5	5 years
80	343 - Debary Units 7 Through 10	71,843	40 years	5	4	R0.5	13 years
81	343 - Hines Energy Complex Unit 1	317,287	40 years	5	3	R0.5	16 years
82	343 - Hines Energy Complex Unit 2	177,642	40 years	5	3	R0.5	18 years
83	343 - Hines Energy Complex Unit 3	158,480	40 years	5	3	R0.5	20 years
84	343 - Hines Energy Complex Unit 4	191,399	40 years	5	3	R0.5	21 years
85	343 - Intercession City Unit 11	25,109	40 years	5	5	R0.5	17 years
86	343 - Intercession City Units 1 Through 6	30,025	40 years	5	3	R0.5	11 years
87	343 - Intercession City Units 12 Through 14	67,827	40 years	5	3	R0.5	19 years
88	343 - Intercession City Units 7 Through 10	77,039	40 years	5	3	R0.5	14 years
89	343 - Osprey Energy Center	225,527	40 years		2	R0.5	19 years
90	343 - Suwannee River Units 1 Through 3	28,568	40 years	5	1	R0.5	11 years
91	343 - Tiger Bay Cogeneration	53,940	40 years	5	1	R0.5	12 years
92	343 - University of Florida Cogeneration	31,066	40 years	5	3	R0.5	6 years
93	344 - Bartow Units 1 and 3	6,920	65 years	1	2	R1	12 years
94	344 - Bartow Units 2 and 4	47,295	65 years	1	3	R1	5 years
95	344 - Bayboro Units 1 Through 4	3,896	65 years	1	1	R1	2 years
96	344 - Citrus Units 1 and 2	16,619	65 years		3	R1	33 years
97	344 - Debary Units 2 Through 6	7,869	65 years	1	2	R1	5 years
98	344 - Debary Units 7 Through 10	18,542	65 years	1	3	R1	15 years
99	344 - Hines Energy Complex Unit 1	44,923	65 years	1	3	R1	16 years
100	344 - Hines Energy Complex Unit 2	36,551	65 years	1	3	R1	20 years
101	344 - Hines Energy Complex Unit 3	53,393	65 years	1	3	R1	22 years
102	344 - Hines Energy Complex Unit 4	45,541	65 years	1	3	R1	23 years
103	344 - Intercession City Unit 11	4,168	65 years	1	4	R1	19 years
104	344 - Intercession City Units 1 Through 6	4,772	65 years	1	3	R1	12 years
105	344 - Intercession City Units 12 Through 14	17,042	65 years	1	3	R1	22 years
106	344 - Intercession City Units 7 Through 10	17,557	65 years	1	3	R1	16 years
107	344 - Osprey Energy Center	31,419	65 years		2	R1	21 years
108	344 - Suwannee River Units 1 Through 3	7,201	65 years	1	1	R1	12 years
109	344 - Tiger Bay Cogeneration	10,677	65 years	1	2	R1	13 years
110	344 - University of Florida Cogeneration	5,965	65 years	1	2	R1	6 years
111	344.66 - Columbia Solar	93,017	30 years		3		29 years
112	344.66 - Debary Solar	74,034	30 years		3		29 years
113	344.66 - Hamilton Solar	96,866	30 years		3		27 years
114	344.66 - Lake Placid Solar	45,158	30 years		3		28 years
115	344.66 - New Solar 2020	40,449	30 years		3		29 years
116	344.66 - New Solar 2021	134,830	30 years		3		29 years
117	344.66 - Osceola Solar	6,439	30 years		3		25 years
118	344.66 - Perry Solar	9,271	30 years		3		25 years
119	344.66 - St Pete Pier Solar	1,452	30 years		3		28 years
120	344.66 - Suwannee Solar	14,111	30 years		3		26 years
121	344.66 - Trenton Solar	75,345	30 years		3		28 years
122	345 - Bartow Units 1 and 3	3,892	60 years	4	2	S0	12 years
123	345 - Bartow Units 2 and 4	39,231	60 years	4	3	S0	5 years
124	345 - Bayboro Units 1 Through 4	1,461	60 years	4	2	S0	2 years
125	345 - Citrus Units 1 and 2	119,487	60 years		3	S0	32 years
126	345 - Debary Units 2 Through 6	7,033	60 years	4	3	S0	5 years
127	345 - Debary Units 7 Through 10	6,317	60 years	4	3	S0	14 years
128	345 - Hines Energy Complex Unit 1	46,317	60 years	4	3	S0	17 years
129	345 - Hines Energy Complex Unit 2	18,922	60 years	4	3	S0	20 years
130	345 - Hines Energy Complex Unit 3	22,824	60 years	4	3	S0	21 years
131	345 - Hines Energy Complex Unit 4	25,727	60 years	4	3	S0	23 years
132	345 - Intercession City Unit 11	4,762	60 years	4	4	S0	18 years
133	345 - Intercession City Units 1 Through 6	6,011	60 years	4	3	S0	12 years
134	345 - Intercession City Units 12 Through 14	9,135	60 years	4	3	S0	21 years
135	345 - Intercession City Units 7 Through 10	6,947	60 years	4	3	S0	15 years
136	345 - Osprey Energy Center	40,852	60 years		2	S0	20 years
137	345 - Suwannee River Units 1 Through 3	6,348	60 years	4	2	S0	12 years
138	345 - Tiger Bay Cogeneration	8,890	60 years	4	2	S0	13 years
139	345 - University of Florida Cogeneration	6,191	60 years	4	2	S0	6 years
140	345.66 - Columbia Solar	9,509	30 years		3		29 years
141	345.66 - Debary Solar	10,721	30 years		3		29 years
142	345.66 - Hamilton Solar	10,184	30 years		3		27 years
143	345.66 - Lake Placid Solar	11,231	30 years		3		28 years
144	345.66 - New Solar 2020	31,523	30 years		3		29 years
145	345.66 - New Solar 2021	28,302	30 years		3		29 years
146	345.66 - Osceola Solar	1,088	30 years		3		25 years
147	345.66 - Perry Solar	1,486	30 years		3		25 years
148	345.66 - St Pete Pier Solar	94	30 years		3		28 years
149	345.66 - Suwannee Solar	2,544	30 years		3		26 years
150	345.66 - Trenton Solar	15,834	30 years		3		28 years
151	346 - Bartow Units 1 and 3	217	35 years	6		R1.5	11 years
152	346 - Bartow Units 2 and 4	22,256	35 years	6	3	R1.5	5 years
153	346 - Bayboro Units 1 Through 4	585	35 years	6	1	R1.5	2 years
154	346 - Citrus Units 1 and 2	5,656	35 years		3	R1.5	28 years
155	346 - Debary Units 2 Through 6	1,378	35 years	6	3	R1.5	5 years
156	346 - Debary Units 7 Through 10	1,049	35 years	6	4	R1.5	13 years
157	346 - Hines Common	16	35 years		20	R1.5	5 years
158	346 - Hines Energy Complex Unit 1	10,278	35 years	6	3	R1.5	15 years
159	346 - Hines Energy Complex Unit 2	2,957	35 years	6	3	R1.5	17 years
160	346 - Hines Energy Complex Unit 3	2,284	35 years	6	3	R1.5	19 years
161	346 - Hines Energy Complex Unit 4	8,195	35 years	6	3	R1.5	20 years
162	346 - Intercession City Unit 11	257	35 years	6	4	R1.5	17 years
163	346 - Intercession City Units 1 Through 6	1,876	35 years	6	6	R1.5	11 years
164	346 - Intercession City Units 12 Through 14	158	35 years	6	3	R1.5	20 years
165	346 - Intercession City Units 7 Through 10	1,019	35 years	6	2	R1.5	14 years
166	346 - Osprey Energy Center	8,749	35 years		2	R1.5	19 years
167	346 - Suwannee River Units 1 Through 3	2,063	35 years	6	3	R1.5	12 years
168	346 - System - Other	614	97 years	6	2		97 years
169	346 - Tiger Bay Cogeneration	1,731	35 years	6	1	R1.5	12 years
170	346 - University of Florida Cogeneration	35	35 years		20	R1.5	6 years
171	346.66 - Columbia Solar	11	30 years		3		29 years
172	346.66 - Hamilton Solar	42	30 years		3		27 years
173	346.66 - Perry Solar	15	30 years		3		24 years
174	346.66 - Trenton Solar	17	30 years		3		28 years
175	346.9 - Bayboro Units 1 Through 4	20	5 years		20		5 years
176	346.9 - Debary Units 2 Through 6	20	5 years		20		5 years
177	346.9 - Debary Units 7 Through 10	1	5 years		20		5 years
178	346.9 - Intercession City Units 1 Through 6	1	5 years		20		5 years
179	346.9 - Intercession City Units 12 Through 14	44	5 years		20		5 years
180	346.9 - University of Florida Cogeneration	1,500	62 years	6	2		62 years
181	352 - Structures and Improvements	76,562	75 years	15	1	R0.5	72 years
182	353 - Station Equipment	1,647,701	53 years		2	R0.5	47 years
183	353 - Station Equipment Citrus Units 1 And 2	12,858	53 years		3	R0.5	47 years
184	353.01 - Station Equipment - Step Up Transformers	110,570	53 years		2	R0.5	44 years
185	353.91 - Station Equipment - Energy Control	53,246	17 years		1	L2	10 years
186	354 - Towers and Fixtures	81,249	65 years	25	1	R3	25 years
187	355 - Poles and Fixtures	1,696,824	38 years	25	3	R2	30 years
188	356 - Overhead Conductors and Devices	810,822	55 years	30	2	R1.5	44 years
189	357 - Underground Conduit	41,680	55 years		1	R3	36 years
190	358 - Underground Conductors and Devices	84,458	50 years	3	2	R3	39 years
191	359 - Roads and Trails	49,870	90 years		1	R3	86 years
192	361 - Structures and Improvements	33,495	75 years	5	1	R2	55 years
193	362 - Station Equipment	1,274,856	60 years	15	2	R0.5	54 years
194	364 - Poles, Towers and Fixtures	889,719	32 years	15	4	R4	19 years
195	365 - Overhead Conductors and Devices	1,122,881	36 years	10	3	R0.5	29 years
196	366 - Underground Conduit	411,213	67 years		2	R2.5	53 years
197	367 - Underground Conductors and Devices	1,244,302	35 years	6	3	R2	25 years
198	368 - Line Transformers	948,242	31 years	4	3	R2	20 years
199	369.01 - Services - Underground	73,916	43 years	25	4	R0.5	31 years
200	369.02 - Services - Overhead	462,542	34 years	4	2	R3	19 years
201	370 - Meters	25,728	18 years	8	6	R0.5	12 years
202	370.02 - Meters - AMI	313,549	15 years		7	S2.5	13 years
203	371 - Installations on Customers' Premises	16,668	25 years		4	R2	18 years
204	373 - Street Lighting and Signal Systems	565,521	25 years		3	S0	18 years
205	390 - Structures and Improvements	278,611	35 years	15	4	R0.5	29 years
206	391 - Office Furniture and Equipment	81,331	7 years		14		7 years
207	392.1 - Passenger Cars	2,644	9 years		9	R3	2 years
208	392.2 - Light Trucks	17,944	9 years		9	S3	2 years
209	392.3 - Heavy Trucks	8,711	12 years		5	S2	5 years
210	392.4 - Special Trucks	18,665	15 years		5	L2.5	6 years
211	392.5 - Trailers	18,926	22 years		2	S0	15 years
212	393 - Stores Equipment	4,608	7 years		14		7 years
213	394 - Tools, Shop and Garage Equipment	68,666	7 years		14		7 years
214	396 - Power Operated Equipment	15,754	18 years		6	L1.5	14 years
215	397 - Communication Equipment	94,759	7 years		14		7 years
216	398 - Miscellaneous Equipment	8,708	7 years		14		7 years
217	398.91 - Miscellaneous Equipment - Energy Control	208	5 years		20		5 years
218	(a) Footnote

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: AccountNumberFactorsUsedInEstimatingDepreciationCharges

Depreciable Plant Base represents balances as of December 31, 2021, and excludes plant related to non-utility, asset retirement obligations, plant held for future use, capital and operating leases, land and intangibles.

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	FERC Fee for Fiscal Year 2021	1,685,377		1,685,377			928000	1,685,377
2	Regulatory Assessment Fee owed to the FPSC	3,307,382		3,307,382			928000	3,307,382
46	TOTAL	4,992,759		4,992,759				4,992,759

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	55,731		930.7	55,731
3	TOTAL ELECTRIC R, D&D PERFORMED INTERNALLY		55,731			55,731
4	B. Electric R, D&D Performed Externally:
5	Electric Power Research Institute	Electric Power Research Institute Membership		1,067,542	Various	1,067,542
6		Other (Less than $50K each)		32,746	Various	32,746
7	TOTAL ELECTRIC R, D&D PERFORMED EXTERNALLY			1,100,288		1,100,288

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	21,031,894
4	SalariesAndWagesElectricOperationTransmission Transmission	9,025,056
5	SalariesAndWagesElectricOperationRegionalMarket Regional Market
6	SalariesAndWagesElectricOperationDistribution Distribution	23,225,573
7	SalariesAndWagesElectricOperationCustomerAccounts Customer Accounts	26,087,317
8	SalariesAndWagesElectricOperationCustomerServiceAndInformational Customer Service and Informational	5,324,792
9	SalariesAndWagesElectricOperationSales Sales	6,460,551
10	SalariesAndWagesElectricOperationAdministrativeAndGeneral Administrative and General	92,014,724
11	SalariesAndWagesElectricOperation TOTAL Operation (Enter Total of lines 3 thru 10)	183,169,907
12	SalariesAndWagesElectricMaintenanceAbstract Maintenance
13	SalariesAndWagesElectricMaintenanceProduction Production	63,900,766
14	SalariesAndWagesElectricMaintenanceTransmission Transmission	3,978,240
15	SalariesAndWagesElectricMaintenanceRegionalMarket Regional Market
16	SalariesAndWagesElectricMaintenanceDistribution Distribution	22,354,015
17	SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral Administrative and General	759
18	SalariesAndWagesElectricMaintenance TOTAL Maintenance (Total of lines 13 thru 17)	90,233,780
19	SalariesAndWagesElectricOperationAndMaintenanceAbstract Total Operation and Maintenance
20	SalariesAndWagesElectricProduction Production (Enter Total of lines 3 and 13)	84,932,660
21	SalariesAndWagesElectricTransmission Transmission (Enter Total of lines 4 and 14)	13,003,296
22	SalariesAndWagesElectricRegionalMarket Regional Market (Enter Total of Lines 5 and 15)
23	SalariesAndWagesElectricDistribution Distribution (Enter Total of lines 6 and 16)	45,579,588
24	SalariesAndWagesElectricCustomerAccounts Customer Accounts (Transcribe from line 7)	26,087,317
25	SalariesAndWagesElectricCustomerServiceAndInformational Customer Service and Informational (Transcribe from line 8)	5,324,792
26	SalariesAndWagesElectricSales Sales (Transcribe from line 9)	6,460,551
27	SalariesAndWagesElectricAdministrativeAndGeneral Administrative and General (Enter Total of lines 10 and 17)	92,015,483
28	SalariesAndWagesElectricOperationAndMaintenance TOTAL Oper. and Maint. (Total of lines 20 thru 27)	273,403,687	614,084	274,017,771
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)	273,403,687	614,084	274,017,771
66	SalariesAndWagesUtilityPlantAbstract Utility Plant
67	SalariesAndWagesUtilityPlantConstructionAbstract Construction (By Utility Departments)
68	SalariesAndWagesUtilityPlantConstructionElectricPlant Electric Plant	203,603,070	13,072,089
69	SalariesAndWagesUtilityPlantConstructionGasPlant Gas Plant
70	SalariesAndWagesUtilityPlantConstructionOther Other (provide details in footnote):
71	SalariesAndWagesUtilityPlantConstruction TOTAL Construction (Total of lines 68 thru 70)	203,603,070	13,072,089	216,675,159
72	SalariesAndWagesPlantRemovalAbstract Plant Removal (By Utility Departments)
73	SalariesAndWagesPlantRemovalElectricPlant Electric Plant	23,852,187
74	SalariesAndWagesPlantRemovalGasPlant Gas Plant
75	SalariesAndWagesPlantRemovalOther Other (provide details in footnote):
76	SalariesAndWagesPlantRemoval TOTAL Plant Removal (Total of lines 73 thru 75)	23,852,187		23,852,187
77	SalariesAndWagesOtherAccountsAbstract Other Accounts (Specify, provide details in footnote):
78	SalariesAndWagesOtherAccountsDescription Other Accounts (Specify, provide details in footnote):
79	SalariesAndWagesOtherAccountsDescription Stores Expense Undistributed	13,686,173	13,686,173
80	SalariesAndWagesOtherAccountsDescription Clearing Accounts	1,646		1,646
81	SalariesAndWagesOtherAccountsDescription Misc Deferred Debits	2,361,622		2,361,622
82	SalariesAndWagesOtherAccountsDescription All Other Accounts	(a) 7,954,739		7,954,739
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	24,004,180	13,686,173	10,318,007
96	SalariesAndWagesGeneralExpense TOTAL SALARIES AND WAGES	524,863,124		524,863,124

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: SalariesAndWagesOtherAccounts

All other accounts include $7,071,935 related to non-utility operations and $882,804 related to civic and political activities

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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.
DEF has no Common Utility Plant and Expenses to report for the year ending 2020

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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)				15,749
2.1	Net Purchases (Account 555.1)
3	Net Sales (Account 447)				1,012,904
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				1,028,653

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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				36,493	MW	3,863,549
2	Reactive Supply and Voltage				30,503	MW	6,496,003
3	Regulation and Frequency Response				30,588	MW	5,440,051
4	Energy Imbalance			2,132,361			1,520,846
5	Operating Reserve - Spinning				2,512	MW	147,000
6	Operating Reserve - Supplement				2,512	MW	451,650
7	Other
8	Total (Lines 1 thru 7)			2,132,361	102,608		17,919,099

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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 Florida
1	January	9,494	19	8	6,451	3,003	4	36
2	February	11,035	4	8	7,598	3,397	4	36
3	March	9,624	31	17	6,959	2,625	4	36
4	Total for Quarter 1				21,008	9,025	12	108	0	0
5	April	10,031	29	18	7,249	2,742	4	36
6	May	11,320	5	18	8,111	3,169	4	36
7	June	11,320	11	18	8,310	2,970	4	36
8	Total for Quarter 2				23,670	8,881	12	108	0	0
9	July	11,784	22	17	8,504	3,240	4	36
10	August	12,098	19	17	8,634	3,424	4	36
11	September	11,066	13	17	7,953	3,073	4	36
12	Total for Quarter 3				25,091	9,737	12	108	0	0
13	October	10,950	7	17	7,957	2,953	4	36
14	November	7,647	3	17	5,569	2,038	4	36
15	December	7,758	19	16	5,570	2,148	4	36
16	Total for Quarter 4				19,096	7,139	12	108	0	0
17	Total				88,865	34,782	48	432	0	0

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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 Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

2022-04-29

Year/Period of Report

End of:

2021

/

Q4

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)	39,681,797
3	Steam	7,154,366	23	Requirements Sales for Resale (See instruction 4, page 311.)	3,301,670
4	Nuclear		24	Non-Requirements Sales for Resale (See instruction 4, page 311.)	400,762
5	Hydro-Conventional		25	Energy Furnished Without Charge
6	Hydro-Pumped Storage		26	Energy Used by the Company (Electric Dept Only, Excluding Station Use)	160,615
7	Other	33,408,344	27	Total Energy Losses	1,920,805
8	Less Energy for Pumping		27.1	Total Energy Stored
9	Net Generation (Enter Total of lines 3 through 8)	40,562,710	28	TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL LINE 20 UNDER SOURCES	45,465,649
10	Purchases (other than for Energy Storage)	4,687,105
10.1	Purchases for Energy Storage	0
11	Power Exchanges:
12	Received	0
13	Delivered	0
14	Net Exchanges (Line 12 minus line 13)	0
15	Transmission For Other (Wheeling)
16	Received	16,314,154
17	Delivered	16,098,320
18	Net Transmission for Other (Line 16 minus line 17)	215,834
19	Transmission By Others Losses
20	TOTAL (Enter Total of Lines 9, 10, 10.1, 14, 18 and 19)	45,465,649

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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 Florida
29	January	3,289,287	20,955	7,053	19	8
30	February	2,867,108	10,254	8,359	4	8
31	March	3,192,687	28,341	7,566	31	17
32	April	3,264,600	20,020	7,872	29	18
33	May	4,058,936	24,815	8,736	5	18
34	June	4,403,050	27,210	9,107	11	18
35	July	4,752,583	46,070	9,453	22	17
36	August	4,897,677	33,115	9,682	19	17
37	September	4,317,346	8,815	8,771	13	17
38	October	4,095,199	34,588	8,702	7	17
39	November	2,989,274	58,736	6,199	3	17
40	December	3,337,902	87,843	6,056	19	16
41	Total	45,465,649	400,762

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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: Anclote	Plant Name: Avon Park	Plant Name: Bartow	Plant Name: Bartow Ct	Plant Name: Bayboro	Plant Name: Citrus County	Plant Name: Crystal River North	Plant Name: Debary	Plant Name: Hines	Plant Name: Intercession City	Plant Name: Osprey	Plant Name: Suwannee	Plant Name: Tiger Bay	Plant Name: University Of Florida
1	PlantKind Kind of Plant (Internal Comb, Gas Turb, Nuclear)	Steam		combined cycle	combustion turbine	combustion turbine	combined cycle	Steam	combustion turbine	combined cycle	combustion turbine	combined cycle	combustion turbine	combined cycle	combined cycle
2	PlantConstructionType Type of Constr (Conventional, Outdoor, Boiler, etc)	Conventional		conventional	conventional	conventional	conventional	conventional	conventional	conventional	conventional	conventional	conventional	conventional	conventional
3	YearPlantOriginallyConstructed Year Originally Constructed	1974		2009	1972	1973	2018	1982	1975	1999	1974	2004	1980	1997	1994
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed	1978		2009	1972	1973	2018	1984	1992	2007	2000	2004	1980	1997	1994
5	InstalledCapacityOfPlant Total Installed Cap (Max Gen Name Plate Ratings-MW)	1,112.00		1,254.00	222.00	227.00	1,970.60	1,478.00	748.00	2,267.00	1,197.00	644.00	197.70	278.00	54.00
6	NetPeakDemandOnPlant Net Peak Demand on Plant - MW (60 minutes)	1,041		1,171	180	134	1,877	1,533	459	2,145	837	576	143	226	53
7	PlantHoursConnectedToLoad Plant Hours Connected to Load	7,821		8,751	604	91	8,760	7,939	1,498	8,760	2,008	6,085	1,015	6,086	7,313
8	NetContinuousPlantCapability Net Continuous Plant Capability (Megawatts)	0		0	0	0	0	0	0	0	0	0	0	0	0
9	NetContinuousPlantCapabilityNotLimitedByCondenserWater When Not Limited by Condenser Water	1,035		1,259	209	226	1,884	1,430	661	2,169	1,173	567	194	224	50
10	NetContinuousPlantCapabilityLimitedByCondenserWater When Limited by Condenser Water	1,013		1,112	168	171	1,610	1,410	524	2,061	931	543	145	193	44
11	PlantAverageNumberOfEmployees Average Number of Employees	56		59	0	0	45	270	13	88	27	31	17	1	13
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh	2,112,063,000		5,244,463,000	33,344,000	5,300,000	11,115,050,000	5,042,303,000	158,621,000	11,517,629,000	367,493,070	2,420,414,000	61,214,700	1,192,323,000	350,960,500
13	CostOfLandAndLandRightsSteamProduction Cost of Plant: Land and Land Rights	1,909,092		1,811,514	0	1,597,635	20,344,325	1,642,673	2,055,281	11,396,422	746,305	906,395	22,059	0	0
14	CostOfStructuresAndImprovementsSteamProduction Structures and Improvements	45,098,860		90,773,913	2,451,635	1,979,426	112,487,299	468,788,489	11,635,074	106,608,998	17,941,396	71,243,546	4,627,883	11,417,158	6,785,836
15	CostOfEquipmentSteamProduction Equipment Costs	433,922,466		655,122,182	37,384,166	25,631,074	1,290,012,670	2,318,028,359	158,211,218	1,217,026,146	294,187,078	320,366,808	50,515,722	80,878,047	51,227,730
16	AssetRetirementCostsSteamProduction Asset Retirement Costs	1,048,789			0	0	0		0	0	0	0	0	0	0
17	CostOfPlant Total cost (total 13 thru 20)	481,979,207	0	747,707,609	39,835,801	29,208,135	1,422,844,294	2,788,459,521	171,901,573	1,335,031,566	312,874,779	392,516,749	55,165,664	92,295,205	58,013,566
18	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 17/5) Including	433.4345		596.2581	179.4405	128.6702	722.0361	1,886.6438	229.8149	588.8979	261.3824	609.4981	279.0372	331.9971	1,074.3253
19	OperationSupervisionAndEngineeringExpense Production Expenses: Oper, Supv, & Engr	2,100,982	39,926	2,500,513	0	127,267	5,920,076	2,379,009	621,624	11,195,718	2,168,989	1,586,331	128,451	976,834	1,359,583
20	FuelSteamPowerGeneration Fuel	129,121,636		197,583,635	4,646,106	1,035,029	444,015,847	172,811,833	16,534,366	425,316,530	26,338,043	82,833,586	5,054,490	45,588,768	18,030,297
21	CoolantsAndWater Coolants and Water (Nuclear Plants Only)	0	0	0	0	0	0	0	0	0	0	0	0	0	0
22	SteamExpensesSteamPowerGeneration Steam Expenses	33,164	0	33,203	0	0		4,303,077	0	0	0	0	0	0	0
23	SteamFromOtherSources Steam From Other Sources	0	0	0	0	0	0	0	0	0	0	0	0	0	0
24	SteamTransferredCredit Steam Transferred (Cr)	0	0	0	0	0	0	0	0	0	0	0	0	0	0
25	ElectricExpensesSteamPowerGeneration Electric Expenses		0		0	0		66,365	0	0	0	0	0	0	0
26	MiscellaneousSteamPowerExpenses Misc Steam (or Nuclear) Power Expenses	3,832,514	50,608	2,717,439	0	191,264	3,349,926	8,123,275	971,061	4,514,717	1,271,478	1,532,792	334,473	300,123	469,231
27	RentsSteamPowerGeneration Rents	0	0	0	0	0	0	0	0	0	0	0	0	0	0
28	Allowances Allowances	22	0	47	0	0	0	13,275	11	77	4	15		7	4
29	MaintenanceSupervisionAndEngineeringSteamPowerGeneration Maintenance Supervision and Engineering	3,785,646	13,658	1,679,557	0	27,018	3,673,181	3,861,379	697,438	362,061	590,563	81,582	225,961	33,603	332,085
30	MaintenanceOfStructuresSteamPowerGeneration Maintenance of Structures	4,710,884	441	1,470,290	0	34,782	1,013,704	17,745,743	327,865	1,566,286	472,168	353,146	126,132	145,826	165,476
31	MaintenanceOfBoilerPlantSteamPowerGeneration Maintenance of Boiler (or reactor) Plant	1,210,612	0		0	0		9,773,048	0	0	0	0	0	0	0
32	MaintenanceOfElectricPlantSteamPowerGeneration Maintenance of Electric Plant	1,722,539	101	1,833,122	0	75,749	747,685	2,689,892	208,332	14,790,679	629,999	1,885,177	86,617	796,323	1,124,069
33	MaintenanceOfMiscellaneousSteamPlant Maintenance of Misc Steam (or Nuclear) Plant	476,991	47,229	7,905,437	0	392,878	5,573,577	2,785,642	2,799,665	11,653,507	1,763,107	4,598,876	877,568	428,419	1,324,904
34	PowerProductionExpensesSteamPower Total Production Expenses	146,994,990	151,963	215,723,243	4,646,106	1,883,987	464,293,996	224,552,538	22,160,362	469,399,575	33,234,351	92,871,505	6,833,692	48,269,903	22,805,649
35	ExpensesPerNetKilowattHour Expenses per Net kWh	0.0696		0.0411	0.1393	0.3555	0.0418	0.0445	0.1397	0.0408	0.0904	0.0384	0.1116	0.0405	0.0650

35	FuelKindAxis Plant Name	Anclote	Bartow	Bartow Ct	Bartow Ct	Bayboro	Citrus County	Crystal River North	Crystal River North	Debary	Debary	Hines	Hines	Intercession City	Intercession City	Osprey	Suwannee	Suwannee	Tiger Bay	University Of Florida
36	FuelKind Fuel Kind	GAS	GAS	GAS	OIL	OIL	GAS	COAL	OIL	GAS	OIL	GAS	OIL	GAS	OIL	GAS	GAS	OIL	GAS	GAS
37	FuelUnit Fuel Unit	Mcf	Mcf	Mcf	bbl	bbl	Mcf	T	bbl	Mcf	bbl	Mcf	bbl	Mcf	bbl	Mcf	Mcf	bbl	Mcf	Mcf
38	QuantityOfFuelBurned Quantity (Units) of Fuel Burned	23,249,956	39,750,393	359,566	25,496	7,981	73,460,121	2,389,754	48,974	1,817,277	60,632	81,706,111		4,507,762	42,465	17,218,555	813,110	5,490	9,020,757	3,425,060
39	FuelBurnedAverageHeatContent Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)	1,025,931	1,020,619	1,025,395	5,711,876	5,710,563	1,028,395	22,556,283	5,730,040	1,027,535	5,767,680	1,022,903		1,027,472	5,711,975	1,023,640	1,026,615	5,816,940	1,022,340	1,026,664
40	AverageCostOfFuelPerUnitAsDelivered Avg Cost of Fuel/unit, as Delvd f.o.b. during year	5.554	4.971	5.121	0.000	0.000	6.044	80.600	146.767	5.289	0.000	5.205		4.822	0.000	4.811	5.5950	0.0000	5.054	5.264
41	AverageCostOfFuelPerUnitBurned Average Cost of Fuel per Unit Burned	5.554	4.971	5.121	111.146	132.168	6.044	68.444	134.929	5.289	115.358	5.205		4.822	99.324	4.811	5.5950	92.9190	5.054	5.264
42	AverageCostOfFuelBurnedPerMillionBritishThermalUnit Average Cost of Fuel Burned per Million BTU	5.413	4.870	4.994	19.459	23.145	5.877	3.034	23.548	5.147	20.001	5.089		4.693	17.389	4.700	5.4500	15.9740	4.943	5.128
43	AverageCostOfFuelBurnedPerKilowattHourNetGeneration Average Cost of Fuel Burned per kWh Net Gen	0.061	0.038	0.077	0.300	0.199	0.040	0.032		0.072	0.280	0.037		0.062	0.218	0.034	0.0770	0.2250	0.038	0.051
44	AverageBritishThermalUnitPerKilowattHourNetGeneration Average BTU per kWh Net Generation	11,293.628	7,735.781	15,424.878	15,424.864	8,599.245	6,796.735	10,690.347		13,976.845	13,976.840	7,256.476		13,305.084	12,512.309	7,282.062	14,160.4540	14,097.7820	7,734.717	10,019.321

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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. 0 Plant Name: 0
1	PlantKind Kind of Plant (Run-of-River or Storage)
2	PlantConstructionType Plant Construction type (Conventional or Outdoor)
3	YearPlantOriginallyConstructed Year Originally Constructed
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed
5	InstalledCapacityOfPlant Total installed cap (Gen name plate Rating in MW)
6	NetPeakDemandOnPlant Net Peak Demand on Plant-Megawatts (60 minutes)
7	PlantHoursConnectedToLoad Plant Hours Connect to Load
8	NetPlantCapabilityAbstract Net Plant Capability (in megawatts)
9	NetPlantCapabilityUnderMostFavorableOperatingConditions (a) Under Most Favorable Oper Conditions
10	NetPlantCapabilityUnderMostAdverseOperatingConditions (b) Under the Most Adverse Oper Conditions
11	PlantAverageNumberOfEmployees Average Number of Employees
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh
13	CostOfPlantAbstract Cost of Plant
14	CostOfLandAndLandRightsHydroelectricProduction Land and Land Rights
15	CostOfStructuresAndImprovementsHydroelectricProduction Structures and Improvements
16	CostOfReservoirsDamsAndWaterwaysHydroelectricProduction Reservoirs, Dams, and Waterways
17	EquipmentCostsHydroelectricProduction Equipment Costs
18	CostOfRoadsRailroadsAndBridgesHydroelectricProduction Roads, Railroads, and Bridges
19	AssetRetirementCostsHydroelectricProduction Asset Retirement Costs
20	CostOfPlant Total cost (total 13 thru 20)
21	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 20 / 5)
22	ProductionExpensesAbstract Production Expenses
23	OperationSupervisionAndEngineeringExpense Operation Supervision and Engineering
24	WaterForPower Water for Power
25	HydraulicExpenses Hydraulic Expenses
26	ElectricExpensesHydraulicPowerGeneration Electric Expenses
27	MiscellaneousHydraulicPowerGenerationExpenses Misc Hydraulic Power Generation Expenses
28	RentsHydraulicPowerGeneration Rents
29	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration Maintenance Supervision and Engineering
30	MaintenanceOfStructuresHydraulicPowerGeneration Maintenance of Structures
31	MaintenanceOfReservoirsDamsAndWaterways Maintenance of Reservoirs, Dams, and Waterways
32	MaintenanceOfElectricPlantHydraulicPowerGeneration Maintenance of Electric Plant
33	MaintenanceOfMiscellaneousHydraulicPlant Maintenance of Misc Hydraulic Plant
34	PowerProductionExpensesHydraulicPower Total Production Expenses (total 23 thru 33)
35	ExpensesPerNetKilowattHour Expenses per net kWh

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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
1	PlantConstructionType Type of Plant Construction (Conventional or Outdoor)
2	YearPlantOriginallyConstructed Year Originally Constructed
3	YearLastUnitOfPlantInstalled Year Last Unit was Installed
4	InstalledCapacityOfPlant Total installed cap (Gen name plate Rating in MW)
5	NetPeakDemandOnPlant Net Peak Demaind on Plant-Megawatts (60 minutes)
6	PlantHoursConnectedToLoad Plant Hours Connect to Load While Generating
7	NetContinuousPlantCapability Net Plant Capability (in megawatts)
8	PlantAverageNumberOfEmployees Average Number of Employees
9	NetGenerationExcludingPlantUse Generation, Exclusive of Plant Use - kWh
10	EnergyUsedForPumping Energy Used for Pumping
11	NetOutputForLoad Net Output for Load (line 9 - line 10) - Kwh
12	CostOfPlantAbstract Cost of Plant
13	CostOfLandAndLandRightsPumpedStoragePlant Land and Land Rights
14	CostOfStructuresAndImprovementsPumpedStoragePlant Structures and Improvements
15	CostOfReservoirsDamsAndWaterwaysPumpedStoragePlant Reservoirs, Dams, and Waterways
16	CostOfWaterWheelsTurbinesAndGeneratorsPumpedStoragePlant Water Wheels, Turbines, and Generators
17	CostOfAccessoryElectricEquipmentPumpedStoragePlant Accessory Electric Equipment
18	CostOfMiscellaneousPowerPlantEquipmentPumpedStoragePlant Miscellaneous Powerplant Equipment
19	CostOfRoadsRailroadsAndBridgesPumpedStoragePlant Roads, Railroads, and Bridges
20	AssetRetirementCostsPumpedStoragePlant Asset Retirement Costs
21	CostOfPlant Total cost (total 13 thru 20)
22	CostPerKilowattOfInstalledCapacity Cost per KW of installed cap (line 21 / 4)
23	ProductionExpensesAbstract Production Expenses
24	OperationSupervisionAndEngineeringExpense Operation Supervision and Engineering
25	WaterForPower Water for Power
26	PumpedStorageExpenses Pumped Storage Expenses
27	ElectricExpensesPumpedStoragePlant Electric Expenses
28	MiscellaneousPumpedStoragePowerGenerationExpenses Misc Pumped Storage Power generation Expenses
29	RentsPumpedStoragePlant Rents
30	MaintenanceSupervisionAndEngineeringPumpedStoragePlant Maintenance Supervision and Engineering
31	MaintenanceOfStructuresPumpedStoragePlant Maintenance of Structures
32	MaintenanceOfReservoirsDamsAndWaterwaysPumpedStoragePlant Maintenance of Reservoirs, Dams, and Waterways
33	MaintenanceOfElectricPlantPumpedStoragePlant Maintenance of Electric Plant
34	MaintenanceOfMiscellaneousPumpedStoragePlant Maintenance of Misc Pumped Storage Plant
35	PowerProductionExpenseBeforePumpingExpenses Production Exp Before Pumping Exp (24 thru 34)
36	PumpingExpenses Pumping Expenses
37	PowerProductionExpensesPumpedStoragePlant Total Production Exp (total 35 and 36)
38	ExpensesPerNetKilowattHour Expenses per kWh (line 37 / 9)
39	ExpensesPerNetKilowattHourGenerationAndPumping Expenses per KWh of Generation and Pumping (line 37/(line 9 + line 10))	0

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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
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

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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 Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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													515,184	12,490,709		13,005,893
2	500KV LINES
3	CENTRAL FLORIDA	KATHLEEN	500.00	500.00	ST	44.22		1	2156 KCM ACSR
4	CRYSTAL RIVER SUB	BROOKRIDGE	500.00	500.00	ST	34.47		1	2335 KCM ACSR
5	CRYSTAL RIVER SUB	BROOKRIDGE			SP	0.62			1590 KCM ACSR
6	BROOKRIDGE	LAKE TARPON	500.00	500.00	ST	37.63		1	2335 KCM ACSR
7	CRYSTAL RIVER	CENTRAL FLORIDA	500.00	500.00	ST	51.51		1	2335 KCM ACSR
8	CRYSTAL RIVER	CENTRAL FLORIDA			SP	0.19			1590 KCM ACSR
9	Tot. 500KV Lines									2,304,818	58,456,902	60,761,719
10	230 KV LINES
11	BARTOW PLANT	NORTHEAST #3	230.00	230.00	HPOF	3.91		1	2500 KCM CU
12	BARTOW PLANT	NORTHEAST #5	230.00	230.00	HPOF	3.98		1	2500 KCM CU
13	BARTOW PLANT	NORTHEAST #6	230.00	230.00	XLPE	3.86		1	5000 KCMIL CU
14	CENTRAL FLORIDA	BUSHNELL EAST	230.00	230.00	SP	8.27		1	1622 ACSS/TW
15	AVON PARK	FORT MEADE	230	230	ST	4.30		1	1081 KCM ACSR
16	AVON PARK	FORT MEADE			CP	2.01			954 KCM ACSR
17	AVON PARK	FORT MEADE			WH	20.15			954 KCM ACSR
18	AVON PARK	FORT MEADE			WP	0.94			954 KCM ACSR
19	AVON PARK	FORT MEADE			SP		1.22		954 KCM ACSR
20	AVON PARK	FISHEATING CREEK	230.00	230.00	SP	9.06		1	1590 KCM ACSR
21	AVON PARK	FISHEATING CREEK			CP	17.05			1590 KCM ACSR
22	AVON PARK	FISHEATING CREEK			WH	3.29			1590 KCM ACSR
23	ANCLOTE PLANT	LARGO	230.00	230.00	SH	15.29		1	1590 KCM ACSR
24	ANCLOTE PLANT	LARGO			SP	8.54			1590 KCM ACSR
25	ANCLOTE PLANT	EAST CLEARWATER	230.00	230.00	SH		15.30	1	1590 KCM ACSR
26	ANCLOTE PLANT	SEVEN SPRINGS	230.00	230.00	SP	7.71		1	2335 KCM ACAR
27	ALTAMONTE	WOODSMERE	230.00	230.00	WP	0.09		1	1590 KCM ACSR
28	ALTAMONTE	WOODSMERE			ST		0.56		1590 KCM ACSR
29	ALTAMONTE	WOODSMERE			WH	10.98			1590 KCM ACSR
30	ALTAMONTE	WOODSMERE			SP	1.09			1590 KCM ACSR
31	BARCOLA	CITY OF LAKELAND TIE	230.00	230.00	WH	18.68		1	1590 KCM ACSR
32	BARTOW PLANT	NORTHEAST #1	230.00	230.00	SP	1.53		1	1590 KCM ACSR
33	BARTOW PLANT	NORTHEAST #7	230.00	230.00	XLPE	3.83		1	5000 KCMIL CU
34	BARTOW PLANT	NORTHEAST #8	230.00	230.00	XLPE	3.89		1	5000 KCMIL CU
35	BARTOW PLANT	NORTHEAST #9	230.00	230.00	XLPE	4.00		1	5000 KCMIL CU
36	BARCOLA	PEBBLEDALE	230.00	230.00	CP	3.86		1	1622 KCM ACSS/TW
37	BROOKRIDGE	BROOKRIDGE	230.00	230.00	WP	0.21		1	1590 KCM ACSR
38	CRYSTAL RIVER	CURLEW	230.00	230.00	ST	77.13	75.92	2	1590 KCM ACSR
39	CRYSTAL RIVER	CURLEW			CP	0.34		1	1590 KCM ACSR
40	CRYSTAL RIVER	CENTRAL FLORIDA	230.00	230.00	ST	50.09	36.50	2	1590 KCM ACSR
41	CRYSTAL RIVER	FT. WHITE	230.00	230.00	WH	73.17		1	954 KCM ACSR
42	CRYSTAL RIVER	FT. WHITE	230.00	230.00	CP	0.28			2627 KCM ACSS/TW
43	CENTRAL FLORIDA	SILVER SPRINGS	230.00	230.00	ST	27.28		2	1590 KCM ACSR
44	CENTRAL FLORIDA	SILVER SPRINGS			CP	0.33		1	1590 KCM ACSR
45	CENTRAL FLORIDA	SORRENTO	230.00	230.00	CP	14.64		1	1590 KCM ACSR
46	CENTRAL FLORIDA	SORRENTO			SP	14.95			1590 KCM ACSR
47	CENTRAL FLORIDA	WINDERMERE	230.00	230.00	ST	45.20	43.36	2	1590 KCM ACSR
48	CRAWFORDVILLE	PERRY	230.00	230.00	ST	11.72		1	954 KCM ACSR
49	CRAWFORDVILLE	PERRY			CP	2.05	1.35	1	954 KCM ACSR
50	CRAWFORDVILLE	PERRY			WH	40.61			954 KCM ACSR
51	CRAWFORDVILLE	PORT ST. JOE	230	230	WH	58.78		1	954 KCM ACSR
52	CRAWFORDVILLE	PORT ST. JOE			SP	2.65			954 KCM ACSR
53	CRAWFORDVILLE	PORT ST. JOE			SH	0.65			954 KCM ACSR
54	CRYSTAL RIVER EAST	SEVEN SPRINGS	230.00	230.00	ST		2.90	1	1590 KCM ACSR
55	DEBARY	ALTAMONTE	230.00	230.00	SP	3.40	8.66	1	1590 KCM ACSR
56	DEBARY	ALTAMONTE			WP	0.06		1	1590 KCM ACSR
57	DEBARY	ALTAMONTE			WH	3.23			1590 KCM ACSR
58	DEBARY	ALTAMONTE			ST	0.49	3.23		1590 KCM ACSR
59	DEBARY	ALTAMONTE			CP	0.05	0.30		1590 KCM ACSR
60	DEBARY	DELAND WEST	230.00	230.00	WH	7.15		1	1590 KCM ACSR
61	DEBARY	DELAND WEST			WP	1.94			1590 KCM ACSR
62	DEBARY	DELAND WEST			CP	1.13			1590 KCM ACSR
63	DEBARY	NORTH LONGWOOD	230.00	230.00	WH	1.32		1	954 KCM ACSR
64	DEBARY	NORTH LONGWOOD			CH		2.49		954 KCM ACSR
65	DEBARY	NORTH LONGWOOD			ST	3.36			1590 KCM ACSR
66	DEBARY	NORTH LONGWOOD			CP	0.42			1431 KCM ACSR
67	DEBARY	NORTH LONGWOOD			SP	9.21			1590 KCM ACSR
68	DEARMAN	SILVER SPRINGS NORTH	230.00	230.00	CP	4.27		1	954 KCM ACSR
69	DEARMAN	SILVER SPRINGS NORTH			ST		1.21		954 KCM ACSR
70	DEBARY	WINTER SPRINGS	230.00	230.00	WH	3.23		1	1590 KCM ACSR
71	DEBARY	WINTER SPRINGS			SP	16.98			1590 KCM ACSR
72	DEBARY	WINTER SPRINGS			ST	0.58			1590 KCM ACSR
73	FORT WHITE	SILVER SPRINGS	230.00	230.00	CP	2.46		1	2627 KCM ACSS/TW
74	FORT WHITE	SILVER SPRINGS			CH	61.84			795 KCM ACSR
75	FORT WHITE	SILVER SPRINGS			CH	12.02			954 KCM ACSR
76	40TH ST	PASADENA FSP	230.00	230.00	CP	0.19		1	1590 KCM ACSR
77	40TH ST	PASADENA FSP			SP	4.02			1590 KCM ACSR
78	FORT MEADE	VANDOLAH	230.00	230.00	WH	16.03		1	954 KCM ACSR
79	FORT MEADE	VANDOLAH			CP	6.15			2627 KCM ACSS/TW
80	FORT MEADE	VANDOLAH			CP	1.79			954 KCM ACSR
81	FORT MEADE	WEST LAKE WALES	230.00	230.00	SP	19.90		1	2627 KCM ACSS/TW
82	HINES ENERGY	FORT MEADE	230.00	230.00	SP	6.41		1	954 KCM ACSR
83	HINES ENERGY	BARCOLA	230.00	230.00	SP	3.09		1	954 KCM ACSR
84	HINES ENERGY	BARCOLA (2ND CIRCUIT)	230.00	230.00	SP		3.09	1	954 KCM ACSR
85	HINES ENERGY	TIGER BAY	230	230	SP	0.60	3.51		954 KCM ACSR
86	HINES PLANT	HINES	230	230	SP	0.97			954 KCM ACSR
87	HINES	WEST LAKE WALES	230	230	SP	20.57		1	1622 KCM ACSS/TW
88	OLD SUB NORTH	NEW SUB NORTH	230.00	230.00	SP	0.22		1	2335 KCM ACAR
89	INTERCESSION CITY	LAKE BRYAN	230.00	230.00	SP	7.84	2.31	1	1622KCM ACSS TW
90	KATHLEEN	WEST LAKELAND	230.00	230.00	WH	14.50		1	1590 KCM ACSR
91	KATHLEEN	WEST LAKELAND			CP	1.31			1590 KCM ACSR
92	KATHLEEN	ZEPHYRHILLS NORTH	230.00	230.00	WH	0.83		1	1590 KCM ACSR
93	KATHLEEN	ZEPHYRHILLS NORTH			CP	8.71			1590 KCM ACSR
94	KATHLEEN	ZEPHYRHILLS NORTH			WP	1.35			1590 KCM ACSR
95	LARGO	PASADENA	230.00	230.00	ST	0.16	1.21	1	1590 KCM ACSR
96	LARGO	PASADENA			SP	13.46			1590 KCM ACSR
97	LAKE TARPON	CURLEW	230.00	230.00	ST	4.32		1	1590 KCM ACSR
98	LAKE TARPON	HIGGINS	230.00	230.00	CP	2.57		1	1590 KCM ACSR
99	LAKE TARPON	HIGGINS			SP	2.22			1590 KCM ACSR
100	LAKE TARPON	LARGO	230.00	230.00	SP	14.49		1	1590 KCM ACSR
101	LAKE TARPON	LARGO			CP	2.90			1590 KCM ACSR
102	LAKE TARPON	SEVEN SPRINGS	230.00	230.00	ST	2.90	8.90	1	1590 KCM ACSR
103	LAKE TARPON	TECO EXIST	230.00	230.00	ST	0.68		1	1590 KCM ACSR
104	LAKE TARPON	TECO EXIST			SP	0.81			1590 KCM ACSR
105	NORTHEAST	CURLEW	230.00	230.00	ST	16.95	12.78	2	1590 KCM ACSR
106	NORTHEAST	40TH ST.	230.00	230.00	SP	8.41			1590 KCA ACSR
107	NORTH LONGWOOD	PIEDMONT	230.00	230.00	SP	2.70	2.54	1	2627 KCM ACSS/TW
108	NORTH LONGWOOD	PIEDMONT			SP	1.76	0.87		1026 KCM ACCC/TW
109	NORTH LONGWOOD	PIEDMONT			WH	3.15			954 KCM ACSR
110	NORTH LONGWOOD	FP&L CO TIE (SANFORD)	230.00	230.00	SP	6.10		1	2627 KCM ACSS/TW
111	NORTH LONGWOOD	FP&L CO TIE (SANFORD)			SP	0.71			1026 KCM ACCC/TW
112	NORTH LONGWOOD	RIO PINAR	230.00	230.00	SP	1.62	2.88	1	1590 KCM ACSR
113	NORTH LONGWOOD	RIO PINAR			CP	0.17			954 KCM ACSR
114	NORTH LONGWOOD	RIO PINAR			AT	10.91			954 KCM ACSR
115	NEWBERRY	WILCOX	230.00	230.00	SP	19.33		1	1590 KCM ACSR
116	NORTHEAST PINELLAS	RESOURCE RECOVERY FL	230.00	230.00	CP	1.90		1	954 KCM ACSR
117	PIEDMONT	SORRENTO	230.00	230.00	SP	3.18		1	1590 KCM ACSR
118	PIEDMONT	SORRENTO			CP	7.15			1590 KCM ACSR
119	PIEDMONT	SORRENTO			WH	4.80			1590 KCM ACSR
120	PIEDMONT	WOODSMERE	230.00	230.00	WH	6.72		1	954 KCM ACSR
121	PORT ST. JOE	GULF POWER	230	230	ST	1.58		1	795 KCM ACSR
122	PORT ST. JOE	GULF POWER			SP	32.58			954 KCM ACSS/TW
123	RIO PINAR	OUC TIE	230	230	CP	2.96		1	1622 KCM ACSS/TW
124	SILVER SPRINGS	DELAND WEST	230.00	230.00	SL	39.93		1	1590 KCM ACSR
125	SILVER SPRINGS	DELAND WEST			ST		4.73	1	1590 KCM ACSR
126	SILVER SPRINGS	DELAND WEST			SH	0.92			1590 KCM ACSR
127	SILVER SPRINGS	DELAND WEST			SP	1.57			1590 KCM ACSR
128	SUWANNEE RIVER PLANT	FORT WHITE	230.00	230.00	ST	38.05		1	954 KCM ACSR
129	SUWANNEE RIVER PLANT	FORT WHITE	230.00	230.00	CP	0.14			2627 KCM ACSS/TW
130	SKY LAKE	OUC TIE	230.00	230.00	CP	2.40		1	954 KCM ACSR
131	SKY LAKE	OUC TIE			WP	2.22			954 KCM ACSR
132	SUWANNEE	PERRY	230.00	230.00	ST	28.68		1	795 KCM ACSR
133	SUWANNEE PEAKERS	SUWANNEE	230.00	230.00	SP	0.51		1	795 KCM ACSR
134	SUWANNEE	GEORGIA GPC TIE	230.00	230.00	ST	18.35		1	954 KCM ACSR
135	TIGER BAY	FORT MEADE 2	230.00	230.00	SP	0.60	1.43	1	954 KCM ACSR
136	ULMERTON	LARGO	230.00	230.00	ST	5.05		1	1590 KCM ACSR
137	VANDOLAH	SEMINOLE	230.00	230.00	SP	0.03		1	954 KCM ACSS/TW
138	VANDOLAH	WHIDDEN	230.00	230.00	SP	14.40		1	1622 KCM ACSS/TW
139	WINDERMERE	INTERCESSION CITY	230.00	230.00	SP	11.23	8.67	1	1622 KCM ACSS/TW
140	WINDERMERE	WOODSMERE	230.00	230.00	WH	4.68		1	1590 KCM ACSR
141	WINDERMERE	WOODSMERE			ST	1.82			1590 KCM ACSR
142	WEST LAKE WALES	FP&L TIE	230.00	230.00	AT	40.31		1	954 KCM ACSR
143	WEST LAKE WALES	FP&L TIE			SH	18.17		1	795 KCM ACSS/TW
144	WEST LAKE WALES	TECO TIE	230.00	230.00	AT	2.29		1	954 KCM ACSR
145	WINDERMERE	OUC TIE	230.00	230.00	WH	1.31		1	954 KCM ACSR
146	INTERCESSION CITY	GIFFORD	230.00	230.00	SP	12.35		4	2627 KCM ACCS/TW
147	HOLOPAW	RELIANT ENERGY 1	230.00	230.00	SP	0.03		1	954 KCM ACSR
148	HOLOPAW	RELIANT ENERGY 2	230.00	230.00	SP	0.05		1	954 KCM ACSR
149	RIO PINAR	OUC (STANTON) 2nd	230.00	230.00	CP	2.72		1	1272 KCM ACSS/TW
150	KATHLEEN	KATHLEEN	230.00	230.00	CP	0.14		1	2627 KCM ACSS/TW
151	LAKE BRYAN	WINDERMERE	230.00	230.00	SP	9.76		2	1622 KCM ACSS/TW
152	STANTON PLANT (OUC)	BITHLO TIE	230.00	230.00	SP	5.42		1	1622 KCM ACSS/TW
153	NORTHEAST	NORTHEAST (SUBST BUS)	230.00	230.00	SP	0.16		1	1590 KCM ACSR
154	NORTHEAST	32nd (DISSTON)	230.00	230.00	SP	2.71	3.12	1	954 KCM ACSR
155	DUNDEE	WEST LK WALES (DWL1)	230	230	SP	9.79		1	2627 KCM ACSS/TW
156	HINES	WEST LK WALES CIR 2	230	230	SP	0.76	20.26	1	1622 KCM ACCS/TW
157	AVALON	GIFFORD	230	230	SP	7.20		1	2627 KCM ACSS/TW
158	INTERCESSION CITY	DUNDEE (ICD1)	230.00	230.00	SP	20.29		1	2627 KCM ACSS/TW/HS
159	KATHLEEN	ZEPHYRHILLS NORTH #2	230.00	230.00	CP	12.66		1	1622 KCM ACSS/TW
160	DUNDEE	WEST LK WALES (DWL2)	230.00	230.00	SP	0.63	9.10	1	2627 KCM ACSS/TW
161	INTERCESSION CITY	DUNDEE 2nd CIR (ICD2)	230.00	230.00	SP	2.72	18.44	1	2627 KCM ACSS/TW
162	SANFORD (FP&L)	BITHLO	230.00	230.00	CP	0.01		1	954 KCM ACSR
163	HOLDER	HOLDER STRING BUS	230.00	230.00	CP	0.07		1	2627 KCM ACSS/TW
164	AVON PARK	FORT MEADE #2	230.00	230.00	SP	0.05	3.14	1	2627 KCM ACSS/TW
165	AVON PARK	FORT MEADE #2			ST	18.52	7.29	1	1622 KCM ACSS/TW
166	CENTRAL FLORIDA	CENTRAL FLORIDA	230.00	230.00	SP	0.28		1	2627 KCM ACSS/TW
167	HUDSON	SHADEY HILLS	230.00	230.00	CH	0.18		1	795 KCM ACSS/TW
168	BITHLO	FP&L POINSETT	230.00	230.00	SP	0.01		1	1431 KCM ACSR/AW
169	TIGER BAY	GENERAL PEAT	230.00	230.00	SP	0.20		1	954 KCM ACSR
170	TIGER BAY	GENERAL PEAT			CP	0.10		1	954 KCM ACSR
171	TIGER BAY	GENERAL PEAT #2	230.00	230.00	SP	0.18		1	954 KCM ACSR
172	TIGER BAY	GENERAL PEAT #2			CP	0.10		1	954 KCM ACSR
173	VANDOLAH	FP&L CHARLOTTE	230.00	230.00	SP	0.03		1	954 KCM ACSS/TW
174	VANDOLAH	VANDOLAH	230.00	230.00	SP	0.09		1	954 KCM ACSS/TW
175	VANDOLAH	SEMINOLE #2	230.00	230.00	SP	0.03		1	954 KCM ACSS/TW
176	WOODSMERE	OUC TIE	230.00	230.00	ST		0.92	2	954 KCM ACSR
177	INTERCESSION CITY	CANE ISLAND (KUA)	230.00	230.00	SP	0.01		1	1590 KCM ACSR
178	Tot. 230KV Lines									103,228,015	1,009,896,090	1,113,124,106
179	OTHER TRANS. LINES	69KV				2,084.27	181.34			61,782,253	1,200,993,973	1,262,776,226
180	OTHER TRANS. LINES	115KV				799.37	231.73			11,196,084	486,473,482	497,669,566
36	TOTAL					4,393		126		178,511,170	2,755,820,447	2,934,331,617	515,184	12,490,709	0	13,005,893

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	Bushnell East	Sumterville	6.08	SP	10.00	2	2	1272	KCM ACSS/TW	Vertical	69		3,269,029	1,684,045		4,953,074
2	SUWANNEE	GEORGIA GPC TIE	0.33	SP	3.00	1	1	2,627	KCM ACSS/TW	Vertical	230		3,596,741	722		3,596,019
3	DLL 25 1	DLL 25 3	0.04	SP	3.00	1	1	795	KCM AAC	Vertical	69		163,779	20,242		184,021
4	FORT WHITE	SILVER SPRINGS	0.30	SP	2.00	1	1	2627	KCM ACSS/TW	Vertical	230		3,429,559	10,765	88,756	3,529,080
5	Radiant	Sanat Fe Solar Generation	0.11	SP	1.00	1	1	795	KCM ACSR	Vertical	230
6	Central Florida	Bushnell East	9.05	SP	11.00	2	2	1622	KCM ACSS/TW	Vertical	230		21,863,745	2,702,262	2,311,904	26,877,911
7	RW 428	RW 430	0.04	SP	1	1	1	4/0	KCM ACSR	Vertical	69		138,345	17,047	69,214	224,606
8	Zephyrhills North	ZNCS 2	0.03	SP	2	1	1	954	KCM ACSR	Vertical	69		182,598	94,066		276,664
9	CRYSTAL RIVER	CENTRAL FLORIDA	1.95	SP	5	1	1	1590	KCM ACSR	Vertical	230		6,736,739	841,117	227,248	7,350,608
10	CENTRAL FLORIDA	WINDERMERE	0.59	CP		1	1	1590	KCM ACSR	Vertical	230		2,095,866	266,258	80,121	2,442,245
11	GH 282 1/2	Legacy Park	0.03	SP	2	1	1	1272	KCM ACSS/TW	Vertical	69		1,032,617		32,034	1,064,651
12	CRYSTAL RIVER	CURLEW	2.38	SP	7	1	1	1590	KCM ACSR	Vertical	230		5,117,213	662,882	125,980	5,906,075
13	Morgan Road	Morgan Road	0.09	CP	2	1	1	1272	KCM ACSS/TW	Vertical	69		420,701	126,969		547,670
14	LB T1	LB T4	0.12	SP	4	1	1	1272	KCM ACSS/TW	Vertical	69		282,495	49,352	22,548	354,395
15	New River	Cabbage Hill TECO	2.85	SP	10	2	2	1272	KCM ACSS/TW	Vertical	69		20,296,222	2,703,279	682,997	23,682,498
16	Denham	Morgan Road	0.62	SP	4	1	1	1272	KCM ACSS/TW	Vertical	69		3,192,865	394,624	137,048	3,724,537
17	Dry Prairie	Duette Solar Generation	0.09	SP	1	1	1	795	KCM ACSR	Vertical	230		843,866			843,866
18	MS 29	Racehorse	0.09	SP	1	1	1	795	KCM AAC	Vertical	69		200,849	24,824		225,673
19	Ochlockonee	Ochlockonee	0.05	SP	2	1	1	795	KCM AAC	Vertical	69		173,351	22,781	2,958	199,090
20	Morgan Road	New River	7.50	SP	8	2	2	1622	KCM ACSS/TW	Vertical	230		16,378,869	2,024,355	855,133	19,258,357
21	Morgan Road	New River	5.00	SP	8	2	2	1622	KCM ACSS/TW	Vertical	230		4,678,270	578,213		5,256,483
22	New River	Wire Road	12.49	SP	8	2	2	1622	KCM ACSS/TW	Vertical	230		30,037,758	3,712,533		33,750,291
23	Wire Road	Zephyrhills North	0.02	CP	3	1	1	1622	KCM ACSS/TW	Vertical	230		2,350,968	160,940	307,734	2,819,642
24	Wire Road	Zephyrhills North CKT 2	0.09	CP	2	1	1	1622	KCM ACSS/TW	Vertical	230		1,088,237	66,288		1,154,525
25	HTL2 1.5	HTL2 106	10.27	SP	9	2	2	1272	KCM ACSS/TW	Vertical	115		298,212	29,748		327,960
26	WHX 6 1	WHX 6 2	0.04	SP	2	1	1	1272	KCM ACSS/TW	Vertical	115		1,073,468		17,462	1,090,930
27	WHX 6 1 1	Trulieve Tap Cap Bank	0.01	SP	1	1	1	795	KCM AAC	Vertical	115
44	TOTAL		60.26		112	34	34						128,942,362	16,191,868	4,506,641	149,640,871

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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	THIRTY SECOND STREET 115KV COASTAL FLORIDA REGION	Distribution	UNATTENDED	115	13	0	48	2	0		0	0
2	FORTIETH STREET 230KV COASTAL FLORIDA REGION	Distribution	UNATTENDED	115	13	0	60	2	0		0	0
3	FORTIETH STREET 230KV COASTAL FLORIDA REGION	Distribution	UNATTENDED	230	115	0	250	1	0		0	0
4	FIFTY-FIRST STREET 230KV COASTAL FLORIDA REGION	Distribution	UNATTENDED	115	13	0	80	2	0		0	0
5	FIFTY-FIRST STREET 230KV COASTAL FLORIDA REGION	Distribution	UNATTENDED	230	115	0	300	1	0		0	0
6	ALDERMAN - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	90	3	0		0	0
7	ANCLOTE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	13	0	100	2	0		0	0
8	BAYBORO - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	12	0	90	2	0		0	0
9	BAYVIEW - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	100	2	0		0	0
10	BAYWAY - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	40	1	0		0	0
11	BELLEAIR - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	80	2	0		0	0
12	BROOKER CREEK - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	74	2	0		0	0
13	BROOKSVILLE ROCK - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	2	0	11	3	1		0	0
14	BROOKSVILLE ROCK - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	4	0	9	3	1		0	0
15	CAMPS SECTION 7 MINE-SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	4	0	21	2	0		0	0
16	CENTRAL PLAZA - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	60	2	0		0	0
17	CLEARWATER - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	120	4	0		0	0
18	CROSS BAYOU - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	150	3	0		0	0
19	CROSSROADS - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	80	2	0		0	0
20	CURLEW - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	110	3	0		0	0
21	DENHAM - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	90	3	0		0	0
22	DISSTON - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	300	1	0		0	0
23	DISSTON - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	80	2	0		0	0
24	DISSTON - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	115	0	300	1	0		0	0
25	DUNEDIN - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	3	0		0	0
26	EAST CLEARWATER - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	69	0	200	1	0		0	0
27	EAST CLEARWATER - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	115	0	200	1	0		0	0
28	EAST CLEARWATER - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	250	1	0		0	0
29	EAST CLEARWATER - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	150	3	0		0	0
30	ELFERS - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	100	2	0		0	0
31	FLORAL CITY - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	13	3	0		0	0
32	FLORA-MAR - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	100	2	0		0	0
33	FLORIDA ROCK - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	4	0	5	3	1		0	0
34	FLORIDA ROCK - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	2	0	5	3	1		0	0
35	G.E. PINELLAS - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	40	2	0		0	0
36	GATEWAY - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	90	3	0		0	0
37	GIFFORD 230KV CENTRAL FLORIDA REGION	Distribution	UNATTENDED	230	69	0	336	1	0		0	0
38	GIFFORD 230KV CENTRAL FLORIDA REGION	Distribution	UNATTENDED	69	13	0	34	1	0		0	0
39	HAMMOCK - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	4	0	20	1	0		0	0
40	HAMMOCK - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	4	0	11	1	0		0	0
41	HERNANDO AIRPORT - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	12	0	30	1	0		0	0
42	HIGHLANDS - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	80	2	0		0	0
43	KENNETH CITY - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	60	2	0		0	0
44	LAND-O-LAKES - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
45	LARGO - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	896	3	0		0	0
46	LARGO - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	100	2	0		0	0
47	MAXIMO - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	150	3	0		0	0
48	NEW PORT RICHEY - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	60	2	0		0	0
49	NORTHEAST - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	115	0	600	2	0		0	0
50	NORTHEAST - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	100	2	0		0	0
51	OAKHURST - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	90	3	0		0	0
52	OLDSMAR 115KV COASTAL FLORIDA REGION	Distribution	UNATTENDED	115	0	0	15	4	1		0	0
53	PALM HARBOR - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED`	230	69	0	250	1	0		0	0
54	PALM HARBOR - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
55	PASADENA - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	115	0	300	1	0		0	0
56	PASADENA - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	80	2	0		0	0
57	PILSBURY - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	100	2	0		0	0
58	PINELLAS WELL FIELD - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	4	0	8	1	0		0	0
59	PORT RICHEY WEST 115KV COASTAL FLORIDA REGION	Distribution	UNATTENDED	115	13	0	101	3	0		0	0
60	SAFETY HARBOR - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	80	2	0		0	0
61	SEMINOLE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	250	1	0		0	0
62	SEMINOLE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	100	2	0		0	0
63	SEVEN SPRINGS - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	90	3	0		0	0
64	SEVEN SPRINGS - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	115	0	750	3	0		0	0
65	SIXTEENTH ST. - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	90	2	0		0	0
66	STARKEY ROAD - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	80	2	0		0	0
67	TARPON SPRINGS - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	69	0	150	1	0		0	0
68	TARPON SPRINGS - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	100	2	0		0	0
69	TAYLOR AVE. - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	80	2	0		0	0
70	TRI-CITY - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	60	2	0		0	0
71	TRILBY - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	9	3	1		0	0
72	UCF -CENTRAL FLORIDA REGION	Distribution	UNATTENDED	69	13	0	100	2	0		0	0
73	UCF -NORTH - CENTRAL FLORIDA REGION	Distribution	UNATTENDED	69	13	0	90	3	0		0	0
74	ULMERTON WEST - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	80	2	0		0	0
75	VINOY - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	100	2	0		0	0
76	WALSINGHAM - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	100	2	0		0	0
77	ZEPHYRHILLS - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	80	2	1		0	0
78	ZEPHYRHILLS NORTH - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	336	1	0		0	0
79	ZEPHYRHILLS NORTH - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	67	2	0		0	0
80	ZEPHYRHILLS NORTH - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	115	0	336	1	0		0	0
81	ALACHUA - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	10	3	0		0	0
82	APALACHICOLA - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	13	3	1		0	0
83	ARCHER - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	336	1	0		0	0
84	ARCHER - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	36	4	1		0	0
85	BEACON HILL - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
86	BEVILLES CORNER - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	20	1	0		0	0
87	CARRABELLE - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	13	3	1		0	0
88	CARRABELLE BEACH - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	12	0	12	3	1		0	0
89	CROSS CITY - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	12	0	67	2	0		0	0
90	DONA VISTA 230 KV - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	672	2	0		0	0
91	EAST POINT - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	14	3	1		0	0
92	FOLEY - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	40	2	0		0	0
93	FORT WHITE - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	112	1	0		0	0
94	FORT WHITE - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	69	0	224	1	0		0	0
95	FORT WHITE - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	14	3	1		0	0
96	G.E. ALACHUA - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	20	1	0		0	0
97	GAINESVILLE - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	25	0	30	1	0		0	0
98	GEORGIA PACIFIC - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	13	3	1		0	0
99	HIGH SPRINGS - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	23	4	1		0	0
100	HULL ROAD - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	19	2	0		0	0
101	INDIAN PASS - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	17	4	0		0	0
102	JASPER SOUTH NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	69	0	100	1	0		0	0
103	JASPER SOUTH NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	60	2	0		0	0
104	JENNINGS - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	6	3	1		0	0
105	LURAVILLE - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	12	0	11	3	1		0	0
106	MADISON - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	40	2	0		0	0
107	MONTICELLO - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	40	2	0		0	0
108	MONASTERY - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	30	1	0		0	0
109	NEWBERRY - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	112	1	0		0	0
110	NEWBERRY - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	14	3	1		0	0
111	O'BRIEN - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	5	3	1		0	0
112	OCCIDENTAL #1 - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	4	0	50	1	0		0	0
113	OCCIDENTAL #1 - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	7	0	50	1	0		0	0
114	OCCIDENTAL #2 - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	4	0	40	2	0		0	0
115	OCCIDENTAL #3 - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	4	0	13	1	0		0	0
116	OCCIDENTAL SWIFT CREEK #1 115KV NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	4	0	22	1	0		0	0
117	OCCIDENTAL SWIFT CREEK #1 115KV NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	34	1	0		0	0
118	OCCIDENTAL SWIFT CREEK #1 115KV NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	25	0	28	1	0		0	0
119	OCCIDENTAL SWIFT CREEK #2 115KV NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	25	0	28	1	0		0	0
120	OCCIDENTAL SWIFT CREEK #2 115KV NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	12	0	34	1	0		0	0
121	OCHLOCKONEE - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	29	4	1		0	0
122	PERRY - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	250	2	0		0	0
123	PERRY - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	230	115	0	300	1	0		0	0
124	PERRY - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	40	2	0		0	0
125	PERRY NORTH - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	20	1	0		0	0
126	PORT ST JOE INDUSTRIAL 69KV NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	30	1	0		0	0
127	PORT ST. JOE - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	336	2	0		0	0
128	PORT ST. JOE - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	30	1	0		0	0
129	RIVER JUNCTION - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	21	3	1		0	0
130	SOPCHOPPY - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	9	1	0		0	0
131	ST. GEORGE ISLAND - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	20	1	0		0	0
132	SUTTERS CREEK - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	21	2	0		0	0
133	SUWANNEE DISTRIBUTION NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	60	2	1		0	0
134	TRENTON - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	12	3	1		0	0
135	UNIVERSITY OF FLORIDA - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	23	0	90	3	0		0	0
136	WHITE SPRINGS - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	21	4	1		0	0
137	WILLISTON - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	21	2	0		0	0
138	ADAMS - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	20	1	0		0	0
139	ALAFAYA - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
140	ALTAMONTE SPRINGS - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	100	2	0		0	0
141	APOPKA SOUTH - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	101	3	0		0	0
142	BAY RIDGE - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	56	2	0		0	0
143	BELLEVIEW - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	100	2	0		0	0
144	BEVERLY HILLS - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	60	2	0		0	0
145	CASSADAGA - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	60	2	0		0	0
146	CASSELBERRY - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	110	3	0		0	0
147	CIRCLE SQUARE - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
148	CITRUS HILL - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	50	2	0		0	0
149	CLARCONA - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	90	3	0		0	0
150	CLERMONT 69KV CENTRAL FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
151	COLEMAN - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	29	2	0		0	0
152	CRYSTAL RIVER NORTH - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	49	4	1		0	0
153	CRYSTAL RIVER SOUTH - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	9	3	1		0	0
154	DELAND - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	100	2	0		0	0
155	PINE RIDGE - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	30	1	0		0	0
156	DELAND EAST - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	90	3	0		0	0
157	DELTONA - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	69	0	75	1	0		0	0
158	DELTONA - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	130	3	0		0	0
159	DELTONA EAST - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	60	2	0		0	0
160	DOUGLAS AVENUE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
161	DUNNELLON TOWN - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	40	2	0		0	0
162	EAGLENEST - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	21	2	0		0	0
163	EATONVILLE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	90	3	0		0	0
164	ECON - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	13	0	100	2	0		0	0
165	EUSTIS - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
166	EUSTIS SOUTH - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	63	2	0		0	0
167	FERN PARK - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	30	1	0		0	0
168	FLORIDA GAS TRANSMISSION - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	230	13	0	50	1	0		0	0
169	GROVELAND - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	40	2	0		0	0
170	HOLDER - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	230	115	0	250	1	0		0	0
171	HOLDER - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	550	2	0		0	0
172	HOLDER - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	40	2	0		0	0
173	HOMOSASSA - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	20	1	0		0	0
174	HOWEY - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	13	3	1		0	0
175	INGLIS MINING - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	25	0	10	3	0		0	0
176	INGLIS - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	69	0	100	1	0		0	0
177	INGLIS - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	9	1	0		0	0
178	INVERNESS - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	69	7	300	1	2		0	0
179	INVERNESS - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
180	KELLER ROAD - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
181	KELLY PARK - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	30	1	0		0	0
182	LADY LAKE - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	40	2	0		0	0
183	LAKE ALOMA - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	50	2	0		0	0
184	LAKE EMMA - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	13	0	100	2	0		0	0
185	LAKE HELEN - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	55	2	0		0	0
186	LAKE WEIR - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	34	2	0		0	0
187	LAND O LAKES 69KV COASTAL FLORIDA REGION	Distribution	UNATTENDED	69	13	0	100	2	0		0	0
188	LEBANON - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	12	0	13	3	1		0	0
189	LIBSON - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	40	2	0		0	0
190	LOCKHART - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	13	0	100	2	0		0	0
191	LOCKWOOD - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
192	LONGWOOD - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	70	3	0		0	0
193	MAITLAND 69KV CENTRAL FLORIDA REGION	Distribution	UNATTENDED	69	13	0	101	3	0		0	0
194	MARICAMP - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	40	2	0		0	0
195	MARTIN - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	20	1	0		0	0
196	MCINTOSH - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	22	2	0		0	0
197	MINNEOLA - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	50	2	0		0	0
198	MONTVERDE - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	100	2	0		0	0
199	MOUNT DORA - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	40	2	0		0	0
200	MYRTLE LAKE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	13	0	100	2	0		0	0
201	NORTH LONGWOOD - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	250	1	0		0	0
202	NORTH LONGWOOD - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	13	0	100	2	0		0	0
203	OCOEE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	90	3	0		0	0
204	OKAHUMPKA - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	56	2	0		0	0
205	ORANGE BLOSSOM - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
206	ORANGE CITY - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	115	0	600	2	0		0	0
207	ORANGE CITY - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	60	2	0		0	0
208	OVIEDO - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	90	3	0		0	0
209	PIEDMONT - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	150	1	0		0	0
210	PIEDMONT - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
211	RAINBOW SPRINGS - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	21	2	0		0	0
212	REDDICK - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	29	2	0		0	0
213	SANTOS - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
214	SILVER SPRINGS - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	250	1	0		0	0
215	SILVER SPRINGS - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	20	1	0		0	0
216	SILVER SPRINGS SHORES - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	40	2	0		0	0
217	ST MARKS WEST - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
218	TROPIC TERRACE - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	40	2	0		0	0
219	TURNER PLANT - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	72	2	0		0	0
220	TURNER PLANT - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	69	0	172	2	0		0	0
221	TURNER PLANT - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	189	2	0		0	0
222	TWIN COUNTY RANCH - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	40	2	0		0	0
223	UMATILLA - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	40	2	0		0	0
224	WEIRSDALE - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	21	2	0		0	0
225	WEKIVA - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	13	0	60	2	0		0	0
226	WEST CHAPMAN - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
227	WILDWOOD CITY - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	34	2	0		0	0
228	WINTER GARDEN - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	100	2	0		0	0
229	WINTER GARDEN CITRUS - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	12	0	10	3	1		0	0
230	WINTER PARK - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
231	WINTER PARK EAST - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	550	2	0		0	0
232	WINTER PARK EAST - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	13	0	100	2	0		0	0
233	WINTER SPRINGS - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	250	1	0		0	0
234	WINTER SPRINGS - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	90	3	0		0	0
235	WOODSMERE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	616	1	0		0	0
236	WOODSMERE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	56	2	0		0	0
237	ZELLWOOD - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	22	2	0		0	0
238	ZUBER - NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	50	2	0		0	0
239	ARBUCKLE CREEK - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	9	1	0		0	0
240	AVON PARK NORTH - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	40	2	0		0	0
241	BABSON PARK - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	20	1	0		0	0
242	BARNUM CITY - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
243	BAY HILL 69KV CENTRAL FLORIDA REGION	Distribution	UNATTENDED	69	13	0	90	3	0		0	0
244	BITHLO - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	100	2	0		0	0
245	BITHLO - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	30	1	0		0	0
246	BOGGY MARSH - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	100	2	0		0	0
247	BONNET CREEK - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
248	CABBAGE ISLAND - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
249	CANOE CREEK - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	13	0	30	1	0		0	0
250	CELEBRATION - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
251	CENTRAL PARK 69KV CENTRAL FLORIDA REGION	Distribution	UNATTENDED	69	13	0	90	3	0		0	0
252	CHAMPIONS GATE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	70	2	0		0	0
253	CITRUSVILLE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	20	1	0		0	0
254	COLONIAL - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	30	1	0		0	0
255	CONWAY - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	40	2	0		0	0
256	COUNTRY OAKS - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	40	2	0		0	0
257	CROOKED LAKE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	34	1	0		0	0
258	CROWN POINT - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	30	1	0		0	0
259	CURRY FORD - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	13	0	100	2	0		0	0
260	CYPRESSWOOD - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	40	2	0		0	0
261	DAVENPORT - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	20	1	0		0	0
262	DELEON SPRINGS - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	13	0	30	1	0		0	0
263	DESOTO CITY - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	21	2	0		0	0
264	DINNER LAKE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	98	2	0		0	0
265	DUNDEE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	34	1	0		0	0
266	DUNDEE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	250	1	0		0	0
267	EAST LAKE WALES - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	40	2	0		0	0
268	EAST ORANGE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	120	3	1		0	0
269	FISHEATING CREEK - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	150	1	0		0	0
270	FISHEATING CREEK - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	11	1	0		0	0
271	FLORIDA GAS TRANSMISSION EAST 69KV CENTRAL FLORIDA R	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
272	FORT MEADE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	200	1	0		0	0
273	FORT MEADE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	10	1	0		0	0
274	FOUR CORNERS - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	90	3	0		0	0
275	FROSTPROOF - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	50	2	0		0	0
276	HAINES CITY - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	80	2	0		0	0
277	HEMPLE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	110	3	0		0	0
278	HOLOPAW - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	25	0	28	6	0		0	0
279	HORSE CREEK #2 - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	4	0	9	1	0		0	0
280	HUNTERS CREEK - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	110	3	0		0	0
281	INTERNATIONAL DRIVE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	13	0	100	2	0		0	0
282	ISLEWORTH 69KV CENTRAL FLORIDA REGION	Distribution	UNATTENDED	69	13	0	101	3	0		0	0
283	LAKE BRYAN - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	500	2	0		0	0
284	LAKE BRYAN - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	90	3	0		0	0
285	LAKE LUNTZ - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	100	2	0		0	0
286	LAKE MARION - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	45	2	0		0	0
287	LAKE OF THE HILLS - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	20	1	0		0	0
288	LAKE PLACID - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	40	2	0		0	0
289	LAKE PLACID NORTH - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	20	2	0		0	0
290	LAKE WALES - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
291	LAKE WILSON - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	40	2	0		0	0
292	LAKEWOOD - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	55	2	0		0	0
293	LEISURE LAKES - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	11	1	0		0	0
294	LITTLE PAYNE CREEK#1 - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	25	0	13	1	0		0	0
295	MAGNOLIA RANCH - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
296	MARLEY ROAD 69KV CENTRAL FLORIDA REGION	Distribution	UNATTENDED	69	13	0	30	1	0		0	0
297	MEADOW WOODS EAST - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	88	2	0		0	0
298	MEADOWS WOODS SOUTH - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	300	1	0		0	0
299	MEADOWS WOODS SOUTH - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	90	3	0		0	0
300	MIDWAY - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	30	1	0		0	0
301	MULBERRY - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	4	0	5	3	1		0	0
302	NARCOOSEE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	90	3	0		0	0
303	NORALYN #1 - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	9	3	1		0	0
304	ODESSA - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
305	ORANGEWOOD - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	100	2	0		0	0
306	PARKWAY - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	20	1	0		0	0
307	PEMBROKE 69KV CENTRAL FLORIDA REGION	Distribution	UNATTENDED	69	13	0	5	3	1		0	0
308	PINECASTLE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	67	4	0		0	0
309	PLYMOUTH SOUTH 69KV CENTRAL FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
310	POINCIANA - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	100	2	0		0	0
311	POINCIANA NORTH - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	30	1	0		0	0
312	REEDY LAKE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	40	2	0		0	0
313	RIO PINAR - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	560	2	0		0	0
314	RIO PINAR - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	112	2	0		0	0
315	SAND LAKE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	101	2	0		0	0
316	SAND MOUNTAIN - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	9	3	0		0	0
317	SEBRING EAST - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	20	1	0		0	0
318	SHINGLE CREEK - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	100	2	0		0	0
319	SOUTH BARTOW - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	11	1	0		0	0
320	SOUTH FORT MEADE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	4	0	45	2	0		0	0
321	SOUTH FORT MEADE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	24	0	24	1	0		0	0
322	SOUTHERN OAKS NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	67	2	0		0	0
323	SUNFLOWER - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	100	2	0		0	0
324	SUN'N LAKES - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
325	TAFT - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	90	2	2		0	0
326	TAUNTON RD - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	20	1	0		0	0
327	TAVARES EAST 69KV NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	30	1	0		0	0
328	VINELAND - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	150	3	0		0	0
329	WAUCHULA - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	21	2	0		0	0
330	WEST DAVENPORT - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	60	2	0		0	0
331	WESTRIDGE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	70	2	0		0	0
332	WEWAHOOTEE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	13	4	0	9	3	1		0	0
333	WEWAHOOTEE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	13	3	1		0	0
334	WHIDDEN CREEK #1 - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	4	0	12	1	0		0	0
335	WINDERMERE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	230	69	0	250	1	0		0	0
336	WINDERMERE - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	40	2	0		0	0
337	WORLD GATEWAY - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	50	1	0		0	0
338	NORTHRIDGE 69KV CENTRAL FLORIDA REGION	Distribution	UNATTENDED	69	13	0	50	1	0		0	0
339	TAFT INDUSTRIAL 69KV CENTRAL FLORIDA REGION	Distribution	UNATTENDED	69	4	0	22	1	0		0	0
340	WOLF LAKE 69KV CENTRAL FLORIDA REGION	Distribution	UNATTENDED	69	13	0	30	1	0		0	0
341	STATION BUSHNELL (SEC) 69KV NORTHERN FLORIDA REGION	Distribution	UNATTENDED	69	13	0	34	1	0		0	0
342	BAYBORO SOUTH - SOUTHERN FLORIDA REGION	Distribution	UNATTENDED	115	14	0	280	2	0		0	0
343	BROOKRIDGE - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	500	230	14	750	3	0		0	0
344	BROOKRIDGE - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	230	115	0	560	2	0		0	0
345	BROOKSVILLE 115KV COASTAL FLORIDA REGION	Transmission	UNATTENDED	115	13	0	67	2	0		0	0
346	BROOKSVILLE 115KV COASTAL FLORIDA REGION	Transmission	UNATTENDED	115	69	0	280	2	0		0	0
347	CRAWFORDVILLE - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	230	69	0	112	1	0		0	0
348	CRAWFORDVILLE - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	69	13	0	36	4	1		0	0
349	GRIFFIN 230KV CENTRAL FLORIDA REGION	Transmission	UNATTENDED	230	115	0	250	1	0		0	0
350	HUDSON - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	230	115	0	750	3	0		0	0
351	HUDSON - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	115	13	7	250	2	0		0	0
352	LAKE TARPON 500KV COASTAL FLORIDA REGION	Transmission	UNATTENDED	500	230	0	1870	6	0		0	0
353	LAKE TARPON 115KV COASTAL FLORIDA REGION	Transmission	UNATTENDED	115	12	0	14	4	0		0	0
354	NEW RIVER - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	115	69	0	280	1	0		0	0
355	BRONSON - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	230	69	0	150	1	0		0	0
356	DRIFTON - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	115	69	0	175	2	0		0	0
357	GINNIE - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	230	69	0	250	1	0		0	0
358	GUMBAY - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	230	69	0	75	1	0		0	0
359	IDYLWILD - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	138	69	0	168	1	1		0	0
360	QUINCY - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	115	69	0	200	1	0		0	0
361	SKY LAKE - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	230	69	0	300	1	0		0	0
362	SKY LAKE - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	69	13	0	90	3	0		0	0
363	SPRING LAKE 230KV CENTRAL FLORIDA REGION	Transmission	UNATTENDED	69	13	0	101	3	0		0	0
364	SPRING LAKE 230KV CENTRAL FLORIDA REGION	Transmission	UNATTENDED	230	69	0	672	2	0		0	0
365	SUWANNEE TRANSMISSION 230KV NORTHERN FLORIDA REGION	Transmission	UNATTENDED	230	115	0	600	2	0		0	0
366	TALLAHASSEE - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	115	69	0	200	2	0		0	0
367	TANGERINE 115KV COASTAL FLORIDA REGION	Transmission	UNATTENDED	115	13	0	34	1	0		0	0
368	WILCOX - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	230	69	0	300	1	0		0	0
369	LIBERTY - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	115	69	0	150	1	0		0	0
370	ANDERSEN - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	230	69	0	132	2	0		0	0
371	BARBERVILLE - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	115	69	0	150	1	0		0	0
372	BARBERVILLE - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	69	13	0	40	2	0		0	0
373	CAMP LAKE - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	230	69	0	672	2	0		0	0
374	CENTRAL FLORIDA - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	500	230	0	746	6	2		0	0
375	CENTRAL FLORIDA - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	230	69	0	616	2	2		0	0
376	CENTRAL FLORIDA - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	69	13	0	2	2	0		0	0
377	CLERMONT EAST - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	230	69	0	250	1	0		0	0
378	CRYSTAL RIVER EAST - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	230	116	0	250	1	0		0	0
379	DALLAS - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	230	69	0	616	2	0		0	0
380	DELAND WEST - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	230	69	0	200	1	0		0	0
381	DELAND WEST - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	115	69	0	200	1	0		0	0
382	HAINES CREEK - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	230	69	0	250	1	0		0	0
383	LECANTO - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	230	115	0	300	1	0		0	0
384	MARTIN WEST - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	230	69	0	200	1	0		0	0
385	ROSS PRAIRIE - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	230	69	0	550	2	0		0	0
386	ROSS PRAIRIE - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	69	13	0	20	1	0		0	0
387	SORRENTO - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	230	69	0	250	1	0		0	0
388	AVON PARK PLANT 230KV CENTRAL FLORIDA REGION	Transmission	UNATTENDED	230	69	0	616	2	0		0	0
389	AVON PARK PLANT 230KV CENTRAL FLORIDA REGION	Transmission	UNATTENDED	69	13	0	670	5	0		0	0
390	AVALON 230KV CENTRAL FLORIDA REGION	Transmission	UNATTENDED	230	69	0	280	1	0		0	0
391	AVALON 230KV CENTRAL FLORIDA REGION	Transmission	UNATTENDED	69	13	0	34	1	0		0	0
392	BARCOLA - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	230	69	0	150	1	0		0	0
393	DRY PRAIRIE CENTRAL FLORIDA REGION	Transmission	UNATTENDED	230	69	0	672	2	0		0	0
394	HAINES CITY EAST - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	230	69	0	300	1	0		0	0
395	HIGGINS PLANT 230KV COASTAL FLORIDA REGION	Transmission	UNATTENDED	230	115	0	250	1	1		0	0
396	INGLIS 115 KV - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	115	69	0	224	1	0		0	0
397	INGLIS 115 KV - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	69	13	0	11	1	0		0	0
398	INTERCESSION CITY - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	13	0	0	19	14	0		0	0
399	INTERCESSION CITY - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	13	4	0	7	7	0		0	0
400	INTERCESSION CITY - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	69	13	0	337	4	0		0	0
401	INTERCESSION CITY - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	230	13	0	1120	8	0		0	0
402	INTERCESSION CITY - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	230	69	0	560	2	0		0	0
403	KATHLEEN - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	500	230	14	1120	3	2		0	0
404	NORTH BARTOW - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	230	69	0	150	1	0		0	0
405	PARKER BRANCH CENTRAL FLORIDA REGION	Transmission	UNATTENDED	115	69	0	112	1	0		0	0
406	SOUTH POLK - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	230	115	0	300	2	0		0	0
407	WAUKEENAH 115KV NORTHERN FLORIDA REGION	Transmission	UNATTENDED	115	12	0	22	2	0		0	0
408	ST MARKS EAST NORTHERN FLORIDA REGION	Transmission	UNATTENDED	230	69	0	300	1	0		0	0
409	CITRUS CENTER 230KV CENTRAL FLORIDA REGION	Transmission	UNATTENDED	230	69	0	672	2	0		0	0
410	LOUGHMAN 69KV CENTRAL FLORIDA REGION	Transmission	UNATTENDED	69	13	0	30	1	0		0	0
411	ULMERTON 230KV COASTAL FLORIDA REGION	Transmission	UNATTENDED	230	115	0	616	2	0		0	0
412	ULMERTON 230KV COASTAL FLORIDA REGION	Transmission	UNATTENDED	115	13	0	112	2	0		0	0
413	WELCH ROAD 230KV CENTRAL FLORIDA REGION	Transmission	UNATTENDED	230	13	0	112	2	0		0	0
414	WEST LAKE WALES 230KV CENTRAL FLORIDA REGION	Transmission	UNATTENDED	230	69	0	280	1	0		0	0
415	WEST LAKE WALES 230KV CENTRAL FLORIDA REGION	Transmission	UNATTENDED	69	13	0	34	1	0			0
416	LAKE BRANCH 115KV CENTRAL FLORIDA REGION	Transmission	UNATTENDED	115	24	0	80	2	0			0
417	VANDOLAH - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	230	69	0	400	2	0			0
418	BROOKER CREEK - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	115	13	0	80	2	0		0	0
419	BROOKSVILLE WEST - COASTAL FLORIDA REGION	Transmission	UNATTENDED	230	115	0	600	2	0		0	0
420	HANCOCK ROAD - CENTRAL FLORIDA REGION	Transmission	UNATTENDED	230	69	0	300	1	0		0	0
421	HAVANA - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	115	69	0	112	1	0		0	0
422	HIGHBANKS - CENTRAL FLORIDA REGION	Transmission	UNATTENDED	115	13	0	30	1	0		0	0
423	INVERNESS - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	115	69	0	360	4	0		0	0
424	MORGAN ROAD - COASTAL FLORIDA REGION	Transmission	UNATTENDED	230	69	0	400	3	0		0	0
425	MONASTERY - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	115	13	0	60	2	0		0	0
426	NEW RIVER - SOUTHERN FLORIDA REGION	Transmission	UNATTENDED	230	115	0	550	2	0		0	0
427	PARKER BRANCH - CENTRAL FLORIDA REGION	Transmission	UNATTENDED	115	69	0	100	1	0		0	0
428	POWER LINE - NORTHERN FLORIDA REGION	Transmission	UNATTENDED	230	115	0	600	2	0		0	0
429	TOTAL Transmission Substations						26910	181	9	—
430	TOTAL Distribution Substations						31068	675	39	—
431	TOTAL Generation Substations									—
432	TOTAL						57978	856	48	0	0	0

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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 Service	Duke Energy Business Services, LLC	Various	521,127,775
3	Customer & Market services	Duke Energy Carolinas, LLC	Various	26,960,347
4	Generation services	Duke Energy Carolinas, LLC	Various	1,166,530
5	Other goods and services	Duke Energy Carolinas, LLC	Various	18,018,151
6	Transmission and Distribution services	Duke Energy Carolinas, LLC	Various	20,815,681
7	Customer & Market services	Duke Energy Progress, LLC	Various	2,379,533
8	Generation services	Duke Energy Progress, LLC	Various	2,720,301
9	Other goods and services	Duke Energy Progress, LLC	Various	2,884,186
10	Transmission and Distribution services	Duke Energy Progress, LLC	Various	3,595,220
11	Customer & Market services	Duke Energy Indiana, Inc.	Various	103,334
12	Generation services	Duke Energy Indiana, Inc.	Various	116,350
13	Other goods and services	Duke Energy Indiana, Inc.	Various	74,276
14	Transmission and Distribution services	Duke Energy Indiana, Inc.	Various	638,655
15	Gas Distribution Services	Piedmont Natural Gas	Various	332,118
19
20	Non-power Goods or Services Provided for Affiliated
21	Services provided to DE Business Services, LLC	Duke Energy Business Services LLC	Various	2,718,347
22	Customer & Market services	Duke Energy Carolinas, LLC	Various	2,331,817
23	Generation services	Duke Energy Carolinas, LLC	Various	969,296
24	Other goods and services	Duke Energy Carolinas, LLC	Various	225,910
25	Transmission and Distribution services	Duke Energy Carolinas, LLC	Various	2,394,638
26	Customer & Market services	Duke Energy Progress, LLC	Various	1,435,458
27	Generation services	Duke Energy Progress, LLC	Various	1,993,324
28	Other goods and services	Duke Energy Progress, LLC	Various	68,859
29	Transmission and Distribution services	Duke Energy Progress, LLC	Various	2,593,784
30	Customer & Market services	Duke Energy Indiana, Inc.	Various	413,052
31	Generation services	Duke Energy Indiana, Inc.	Various	299,321
32	Other goods and services	Duke Energy Indiana, Inc.	Various	62,187
33	Transmission and Distribution services	Duke Energy Indiana, Inc.	Various	467,857
34	Customer & Market services	Duke Energy Kentucky, Inc.	Various	88,670
35	Generation services	Duke Energy Kentucky, Inc.	Various	70,279
36	Other goods and services	Duke Energy Kentucky, Inc.	Various	162,652
37	Transmission and Distribution services	Duke Energy Kentucky, Inc.	Various	19,356
38	Customer & Market services	Duke Energy Ohio, Inc.	Various	139,637
39	Generation services	Duke Energy Ohio, Inc.	Various	79,623
40	Other goods and services	Duke Energy Ohio, Inc.	Various	15,185
41	Transmission and Distribution services	Duke Energy Ohio, Inc.	Various	410,289
42	Customer & Market services	Cinergy Solutions	Various	5,776,346
43	Generation services	Cinergy Solutions	Various	7,301
44	Other goods and services	Cinergy Solutions	Various	8,519
45	Transmission and Distribution services	Cinergy Solutions	Various	24,495
42

Name of Respondent:

Duke Energy Florida, LLC

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

04/29/2022

Year/Period of Report

End of:

2021

/

Q4

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 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

GENERAL INFORMATION

Purpose

Who Must Submit

What and Where to Submit

When to Submit

Where to Send Comments on Public Reporting Burden.

GENERAL INSTRUCTIONS

EXCERPTS FROM THE LAW

GENERAL PENALTIES

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