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)

Kentucky Power Company

Year/Period of Report

End of:

2022

/

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

Kentucky Power Company

02 Year/ Period of Report

End of:

2022

/

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)

1 Riverside Plaza, Columbus, OH 43215-2373

05 Name of Contact Person

Jason M. Johnson

06 Title of Contact Person

Accountant

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

1 Riverside Plaza, Columbus, OH 43215-2373

08 Telephone of Contact Person, Including Area Code

614- 716-1000

09 This Report is An Original / A Resubmission

(1)

☑ An Original

(2)

☐ A Resubmission

10 Date of Report (Mo, Da, Yr)

04/12/2023

Annual Corporate Officer Certification

The undersigned officer certifies that:

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

01 Name

Jeffrey W Hoersdig

02 Title

Assistant Controller

03 Signature

Jeffrey W Hoersdig

04 Date Signed (Mo, Da, Yr)

04/12/2023

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

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	116-NA
9	ScheduleStatementOfIncomeAbstract Statement of Income for the Year	114
10	ScheduleRetainedEarningsAbstract Statement of Retained Earnings for the Year	118
12	ScheduleStatementOfCashFlowsAbstract Statement of Cash Flows	120
12	ScheduleNotesToFinancialStatementsAbstract Notes to Financial Statements	122
13	ScheduleStatementOfAccumulatedOtherComprehensiveIncomeAndHedgingActivitiesAbstract Statement of Accum Other Comp Income, Comp Income, and Hedging Activities	122a
14	ScheduleSummaryOfUtilityPlantAndAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep	200
15	ScheduleNuclearFuelMaterialsAbstract Nuclear Fuel Materials	202
16	ScheduleElectricPlantInServiceAbstract Electric Plant in Service	204
17	ScheduleElectricPropertyLeasedToOthersAbstract Electric Plant Leased to Others	213
18	ScheduleElectricPlantHeldForFutureUseAbstract Electric Plant Held for Future Use	214
19	ScheduleConstructionWorkInProgressElectricAbstract Construction Work in Progress-Electric	216
20	ScheduleAccumulatedProvisionForDepreciationOfElectricUtilityPlantAbstract Accumulated Provision for Depreciation of Electric Utility Plant	219
21	ScheduleInvestmentsInSubsidiaryCompaniesAbstract Investment of Subsidiary Companies	224
22	ScheduleMaterialsAndSuppliesAbstract Materials and Supplies	227
23	ScheduleAllowanceInventoryAbstract Allowances	228
24	ScheduleExtraordinaryPropertyLossesAbstract Extraordinary Property Losses	230a
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
41	ScheduleOtherRegulatoryLiabilitiesAbstract Other Regulatory Liabilities	278
42	ScheduleElectricOperatingRevenuesAbstract Electric Operating Revenues	300
43	ScheduleRegionalTransmissionServiceRevenuesAbstract Regional Transmission Service Revenues (Account 457.1)	302	NA
44	ScheduleSalesOfElectricityByRateSchedulesAbstract Sales of Electricity by Rate Schedules	304
45	ScheduleSalesForResaleAbstract Sales for Resale	310
46	ScheduleElectricOperationsAndMaintenanceExpensesAbstract Electric Operation and Maintenance Expenses	320
47	SchedulePurchasedPowerAbstract Purchased Power	326
48	ScheduleTransmissionOfElectricityForOthersAbstract Transmission of Electricity for Others	328
49	ScheduleTransmissionOfElectricityByIsoOrRtoAbstract Transmission of Electricity by ISO/RTOs	331	NA
50	ScheduleTransmissionOfElectricityByOthersAbstract Transmission of Electricity by Others	332
51	ScheduleMiscellaneousGeneralExpensesAbstract Miscellaneous General Expenses-Electric	335
52	ScheduleDepreciationDepletionAndAmortizationAbstract Depreciation and Amortization of Electric Plant (Account 403, 404, 405)	336
53	ScheduleRegulatoryCommissionExpensesAbstract Regulatory Commission Expenses	350
54	ScheduleResearchDevelopmentOrDemonstrationExpendituresAbstract Research, Development and Demonstration Activities	352
55	ScheduleDistributionOfSalariesAndWagesAbstract Distribution of Salaries and Wages	354
56	ScheduleCommonUtilityPlantAndExpensesAbstract Common Utility Plant and Expenses	356
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	NA
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:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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. Jeffrey W. Hoersdig, Assistant Controller 1 Riverside Plaza Columbus, OH 43215-2373
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. Kentucky - July 21,1919 State of Incorporation: Date of Incorporation: 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 - Kentucky
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:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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.

American Electric Power Company, Inc. - Ownership of 100% of Respondent's Common Stock

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
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Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	(a) Footnote

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: OfficerTitle


Schedule Page: 104 Line No.: 1 Column: a

The following table provides summary information concerning compensation earned by our Chief Executive Officer, our two Chief Financial Officers during 2022, the three other most highly compensated executive officers and one additional former executive officer whose compensation would have been among the three other most highly compensated executive officers if she had been an executive officer at year end. We refer collectively to this group as the named executive officers.


Name and Principal Position	Year	Salary ($)(1)	Bonus ($)	Stock Awards ($)(2)	Non-Equity Incentive Plan Compensation ($)(3)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)(4)	All Other Compensation ($)(5)	Total ($)
Nicholas K. Akins
Chair of the Board and Chief Executive Officer	2022	1,510,000		10,824,690	3,620,000	204,063	216,755	16,375,508


Julia A. Sloat
Executive Vice President and Chief Financial Officer	2022	779,769		3,948,384	1,010,000		77,810	5,815,963


Ann P. Kelly
Executive Vice President and Chief Financial Officer	2022	61,923		393,121	55,750		9,974	520,768


David M. Feinberg
Executive Vice President, General Counsel and Secretary	2022	714,000		1,623,710	805,000		63,163	3,205,873


Charles E. Zebula
Executive Vice President - Portfolio Optimization	2022	593,000		1,407,162	705,000		67,856	2,773,018


Paul Chodak, III
Executive Vice President - Generation	2022	551,500	—	1,407,162	622,890	—	63,366	2,644,918


Lisa M. Barton
Former Exec. Vice President and Chief Operations Officer	2022	686,054	—	2,597,880	—	15,083	154,503	3,453,520

(1) Amounts in the salary column are composed of executive salaries earned for the year shown, which include 260 days of pay for 2022 , which is the number of workdays and holidays in a standard year.

(2) The amounts reported in this column reflect the aggregate grant date fair value calculated in accordance with FASB ASC Topic 718 of the performance shares, restricted stock units (RSUs) and unrestricted shares granted under our Long-Term Incentive Plan. See Note 15 to the Consolidated Financial Statements included in our Form 10-K for the year ended December 31, 2022 for a discussion of the relevant assumptions used in calculating these amounts. The number of shares realized and the value of the performance shares, if any, will depend on the Company’s performance during a 3-year performance period. The potential payout can range from 0 percent to 200 percent of the target number of performance shares, plus any dividend equivalents. The value of the performance shares will be based on three measures: a Board approved cumulative operating earnings per share measure (Cumulative EPS 50%), a total shareholder return relative to peer companies (Relative TSR 40%) and a carbon free capacity mix (Carbon Free Capacity 10%). The grant date fair value of the 2022 performance shares that are based on Cumulative EPS was computed in accordance with FASB ASC Topic 718 and was measured based on the closing price of AEP’s common stock on the grant date. The maximum amount payable for the 2022 performance shares that are based on Cumulative EPS measured on the grant date was $7,500,054 for Mr. Akins; $1,350,018 for Ms. Sloat; $109,965 for Ms. Kelly, $1,125,029 for Mr. Feinberg; $974,951

for Mr. Zebula; $974,951 for Mr. Chodak and $1,799,996 for Ms. Barton. The maximum amount payable for the 2022 performance shares that are based on Carbon Free Capacity is equal to $1,500,011 for Mr. Akins; $270,004 for Ms. Sloat; $21,993 for Ms. Kelly; $225,006 for Mr. Feinberg; $194,990 for Mr. Zebula, $194,990 for Mr. Chodak and $359,999 for Ms. Barton. The grant date fair value of the 2022 performance shares that are based on Relative TSR is calculated using a Monte-Carlo model as of the date of grant, in accordance with FASB ASC Topic 718. Because the performance shares that are based on Relative TSR are subject to market conditions as defined under FASB ASC Topic 718, they did not have a maximum value on the grant date that differed from the grant date fair values presented in the table. Instead, the maximum value is factored into the calculation of the grant date fair value. The values realized from the 2020 performance shares are included in the Option Exercises and Stock Vested for 2022 table.

(3) The amounts shown in this column reflect annual incentive compensation paid for the year shown.

(4) The amounts shown in this column are attributable to the increase in the actuarial values of each of the named executive officer’s combined benefits under AEP’s qualified and non-qualified defined benefit pension plans determined using interest rate and mortality assumptions consistent with those used in the Company’s financial statements. Negative values of ($41,465), ($131,041) ($245,983) and ($27,352) for Ms. Sloat and Messrs. Feinberg, Zebula and Chodak, respectfully, were replaced with $0 for the purposes of the Summary Compensation Table. See the Pension Benefits for 2022 table and related footnotes for additional information. See Note 8 to the Consolidated Financial Statements included in our Form 10-K for the year ended December 31, 2022 for a discussion of the relevant assumptions. None of the named executive officers received preferential or above-market earnings on deferred compensation.

(5) Amounts shown in the All Other Compensation column for 2022 include: (a) Company matching contributions to the Company’s Retirement Savings Plan, (b) Company matching contributions to the Company’s Supplemental Retirement Savings Plan, (c) perquisites, (d) vacation payout, and (e) severance benefits. The 2022 values for these items are listed in the following table:


Type	Nicholas K. Akins		Julia A. Sloat		Ann P. Kelly		David M. Feinberg		Charles E. Zebula		Paul Chodak, III		Lisa M. Barton
Retirement Savings Plan Match	13,725		13,725		1,212		13,725		13,725		13,725		13,725
Supplemental Retirement Savings Plan Match	182,475		49,829				49,438		41,746		35,516		57,890
Relocation					8,762
Perquisites	20,555		14,256						12,385		14,125		14,125
Vacation Payout	—		—		—		—		—				68,763
Severance	—		—		—		—		—
Total	$	216,755	$	77,810	$	9,974	$	63,163	$	67,856	$	63,366	$	154,503

(6) Ms. Sloat's compensation is provided only for the years in which she was an executive officer of the Company.

Perquisites provided in 2022 included: financial counseling and tax preparation services and, for Mr. Akins, director’s group travel accident insurance premium. Executive officers may also have the occasional personal use of event tickets when such tickets are not being used for business purposes, however, there is no associated incremental cost. From time-to-time executive officers may receive customary gifts from third parties that sponsor events (subject to our policies on conflicts of interest).

Provided Ms. Barton complies with the terms of her Executive Severance, Noncompetition and Release of All Claims Agreement, she will receive $1,520,700 in cash severance benefits and up to $15,650 in outplacement services in 2023 in connection with her 2022 separation from AEP employment.

Mr. Akins has entered into an Aircraft Time Sharing Agreement that allows him to use our corporate aircraft for personal use for a limited number of hours each year. The Aircraft Time Sharing Agreement requires Mr. Akins to reimburse the Company for the cost of his personal use of corporate aircraft in accordance with limits set forth in Federal Aviation Administration regulations. Mr. Akins reimbursed the Company all incremental costs incurred in connection with personal flights under the Aircraft Timesharing Agreement including fuel, oil, hangar costs, crew travel expenses, catering, landing fees and other incremental airport fees. Accordingly, no value is shown for these amounts in the Summary Compensation Table. If the aircraft flies empty before picking up or after dropping off Mr. Akins at a destination on a personal flight, the cost of the empty flight is included in the incremental cost for which Mr. Akins reimburses the Company. Since AEP aircraft are used predominantly for business purposes, we do not include fixed costs that do not change in amount based on usage, such as depreciation and pilot salaries.

Due to her promotion to CEO, in February 2023 the Company entered into a TSA with Ms. Sloat on substantively the same terms as Mr. Akins' TSA.

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	Nicholas K. Akins, Chairman of the Board and Chief Executive Officer	Columbus, Ohio	false	false
2	Julia A. Sloat, Vice President and Chief Financial Officer	Columbus, Ohio	false	false
3	Christian T. Beam, Executive Vice President, Energy Services	Columbus, Ohio	false	false
4	Paul Chodak, Vice President	Columbus, Ohio	false	false
5	David M. Feinberg, Vice President and Secretary	Columbus, Ohio	false	false
6	Ann P. Kelly, Vice President and Chief Financial Officer	Columbus, Ohio	false	false
7	Brett D.Mattison, President and Chief Operating Officer	Columbus, Ohio	false	false
8	Therace M. Risch, Vice President	Columbus, Ohio	false	false
9	Toby L. Thomas, Vice President	Columbus, Ohio	false	false
10	Peggy I.Simmons,Executive Vice President, Utilities	Columbus, Ohio	false	false
11	Rajagopalan.Sundararajan,Executive Vice President, External Affairs	Columbus, Ohio	false	false
12	Phillip R.Ulrich,Vice President	Columbus, Ohio	false	false
13	Lisa M. Barton, Vice President	Columbus, Ohio	false	false
14	Charles R. Patton	Columbus, Ohio	false	false

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	PJM Interconnection LLC - Attachment H-14	ER17-405

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	20221208-5094	12/08/2022	ER17-405	AEP PJM OATT Proj Transmission	PJM OATT Attachment H-14
2	20221101-5174	11/01/2022	ER17-405	AEP PJM OATT Proj Transmission	PJM OATT Attachment H-14
3	20220527-5370	05/27/2022	ER17-405	AEP PJM OATT Proj Transmission	PJM OATT Attachment H-14

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	204-207	Electric Plant in Service	g	49
2	214	Electric Plant Held for Future Use	d	46
3	216	Construction Work in Progress	b	1
4	219	Accumulated Depreciation	b	21
5	310-311	Sales for Resale	k	1
6	320	Electric Operations & Maintenance Expense	b	5
7	320	Electric Operations & Maintenance Expense	b	25
8	320	Electric Operations & Maintenance Expense	b	31
9	321	Electric Operations & Maintenance Expense	b	93
10	323	Electric Operations & Maintenance Expense	b	185
11	336	Depreciation Expense	b	7
12	354	Distribution of Wages and Salaries	b	28

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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.

None
None
None
None
None
Kentucky Power Term Loan Extension $125M KY State Commission Authority: Case No. 2019-00072 Issued: 3/6/2020 Maturity: 9/6/2022 Kentucky credit Agreement $150M, State Authority: Cause No 2021-00131 (1st $75M), Cause No 2022-00205 (2nd $75M) Issued: 7/22/2022 , Maturity: 12/31/2023. Kentucky Second amendment to the March 6,2020 credit Agreement $125M has been extended to December 31, 2023, State Authority: Cause No 2022-00205 Issue:9/06/2022, Maturity: 12/31/2023
None
8. 449 Employees represented by IBEW978 granted a 2% wage increase 1/2/2022 120 employees represented by UMUA 492 granted a 2% wage increase 1/2/2022 79 employees represented by IBEW978 granted a 4% wage increase 4/1/2022 126 employees represented by UWUA 492 granted a 3% wage increase 6/1/2022
Please refer to the Notes to Financial Statements pages 122-123
None
Not Used
Rajagopalan Sundararajan elected as Director Effective on 07/02/2022 David M. Feinberg elected as Vice President Effective on 08/25/2022 Peggy I. Simmons elected as Director Effective on 09/22/2022 Christian T. Beam elected as Director Effective on 09/22/2022 Philip R. Ulrich elected as Director Effective on 09/22/2022 and Vice President Effective on 09/14/2022 Lisa M. Barton Resigned as a Director on 09/20/2022 Charles R. Patton Resigned as a Director on 07/02/2022 Timothy C. Kerns Resigned as a Vice president- Generation Assets on 09/03/2022 Joel H Jansen elected as Vice President effective on 10/28/2022 Ann P Kelly elected as Vice President & Chief Financial Officer effective on 11/30/2022 and Director effective 12/14/2022 Nicholas K Akins resigned as Director, Chairman of the Board and Chief Executive Officer effective on 12/31/2022 Lisa M Barton resigned as Vice President effective on 11/01/2022 Julia A Sloat resigned as Vice President and Chief Financial Officer effective on 11/29/2022 Brett D Mattison resigned President and Vice President effective on 12/312022
Proprietary capital ratio exceeds 30%

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	3,267,854,352	3,147,348,972
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	138,936,649	95,340,895
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		3,406,791,001	3,242,689,868
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	1,230,384,120	1,159,640,985
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		2,176,406,881	2,083,048,883
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)		2,176,406,881	2,083,048,883
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)
17	OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS
18	NonutilityProperty Nonutility Property (121)		571,711	6,554,403
19	AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Prov. for Depr. and Amort. (122)		235,580	151,941
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances	228	8,378,701	8,458,403
24	OtherInvestments Other Investments (124)		751,735	1,804,869
25	SinkingFunds Sinking Funds (125)
26	DepreciationFund Depreciation Fund (126)
27	AmortizationFundFederal Amortization Fund - Federal (127)
28	OtherSpecialFunds Other Special Funds (128)
29	SpecialFunds Special Funds (Non Major Only) (129)		20,531,281	60,332,681
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)		29,997,848	76,998,414
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)		2,683,920	763,386
36	SpecialDeposits Special Deposits (132-134)		1,000,594	14,266,645
37	WorkingFunds Working Fund (135)
38	TemporaryCashInvestments Temporary Cash Investments (136)
39	NotesReceivable Notes Receivable (141)
40	CustomerAccountsReceivable Customer Accounts Receivable (142)		62,174,770	15,642,267
41	OtherAccountsReceivable Other Accounts Receivable (143)		71,556	56,847
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		1,012,937	3,389
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)		10,817,819	24,535,392
45	FuelStock Fuel Stock (151)	227	21,071,010	9,489,812
46	FuelStockExpensesUndistributed Fuel Stock Expenses Undistributed (152)	227	922,553	599,696
47	Residuals Residuals (Elec) and Extracted Products (153)	227
48	PlantMaterialsAndOperatingSupplies Plant Materials and Operating Supplies (154)	227	26,061,672	20,420,653
49	Merchandise Merchandise (155)	227
50	OtherMaterialsAndSupplies Other Materials and Supplies (156)	227
51	NuclearMaterialsHeldForSale Nuclear Materials Held for Sale (157)	202/227
52	AllowanceInventoryAndWithheld Allowances (158.1 and 158.2)	228	8,498,981	8,552,442
53	NoncurrentPortionOfAllowances (Less) Noncurrent Portion of Allowances	228	8,378,701	8,458,403
54	StoresExpenseUndistributed Stores Expense Undistributed (163)	227
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)		1,476,784	1,995,946
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)
60	RentsReceivable Rents Receivable (172)		2,624,119	2,619,316
61	AccruedUtilityRevenues Accrued Utility Revenues (173)		35,002,399	16,646,864
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)
63	DerivativeInstrumentAssets Derivative Instrument Assets (175)		8,463,111	5,986,480
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)		171,477,650	113,113,955
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		1,552,472	1,895,122
70	ExtraordinaryPropertyLosses Extraordinary Property Losses (182.1)	230a
71	UnrecoveredPlantAndRegulatoryStudyCosts Unrecovered Plant and Regulatory Study Costs (182.2)	230b
72	OtherRegulatoryAssets Other Regulatory Assets (182.3)	232	663,934,948	613,089,054
73	PreliminarySurveyAndInvestigationCharges Prelim. Survey and Investigation Charges (Electric) (183)		1,072,515	1,335,712
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)			1,634
77	TemporaryFacilities Temporary Facilities (185)
78	MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186)	233	25,566,595	22,792,880
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)		333,703	367,354
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	86,163,415	94,062,449
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		778,623,648	733,544,206
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		3,156,506,027	3,006,705,458

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	50,450,000	50,450,000
3	PreferredStockIssued Preferred Stock Issued (204)	250	0
4	CapitalStockSubscribed Capital Stock Subscribed (202, 205)		0
5	StockLiabilityForConversion Stock Liability for Conversion (203, 206)		0
6	PremiumOnCapitalStock Premium on Capital Stock (207)		0
7	OtherPaidInCapital Other Paid-In Capital (208-211)	253	526,286,962	526,135,279
8	InstallmentsReceivedOnCapitalStock Installments Received on Capital Stock (212)	252	0
9	DiscountOnCapitalStock (Less) Discount on Capital Stock (213)	254	0
10	CapitalStockExpense (Less) Capital Stock Expense (214)	254b	0
11	RetainedEarnings Retained Earnings (215, 215.1, 216)	118	343,572,384	296,020,207
12	UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1)	118	0
13	ReacquiredCapitalStock (Less) Reaquired Capital Stock (217)	250	0
14	NoncorporateProprietorship Noncorporate Proprietorship (Non-major only) (218)		0
15	AccumulatedOtherComprehensiveIncome Accumulated Other Comprehensive Income (219)	122(a)(b)	0	1,749,841
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		920,309,346	874,355,328
17	LongTermDebtAbstract LONG-TERM DEBT
18	Bonds Bonds (221)	256	0
19	ReacquiredBonds (Less) Reaquired Bonds (222)	256	0
20	AdvancesFromAssociatedCompanies Advances from Associated Companies (223)	256	0
21	OtherLongTermDebt Other Long-Term Debt (224)	256	1,180,000,000	1,105,000,000
22	UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225)		0
23	UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Debit (226)		0
24	LongTermDebt Total Long-Term Debt (lines 18 through 23)		1,180,000,000	1,105,000,000
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		738,735	10,678,099
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)		0
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		1,273,572	2,096,019
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		6,699,141	3,818,077
30	AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4)		0
31	AccumulatedProvisionForRateRefunds Accumulated Provision for Rate Refunds (229)		1,253,690
32	LongTermPortionOfDerivativeInstrumentLiabilities Long-Term Portion of Derivative Instrument Liabilities		14,009	405
33	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges Long-Term Portion of Derivative Instrument Liabilities - Hedges		0
34	AssetRetirementObligations Asset Retirement Obligations (230)		18,476,771	17,696,994
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		28,427,900	34,289,595
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)		0
38	AccountsPayable Accounts Payable (232)		56,969,094	52,836,888
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)		94,427,543	47,895,489
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		51,075,869	42,223,069
41	CustomerDeposits Customer Deposits (235)		38,784,350	32,431,608
42	TaxesAccrued Taxes Accrued (236)	262	39,507,718	44,350,258
43	InterestAccrued Interest Accrued (237)		8,542,879	5,685,082
44	DividendsDeclared Dividends Declared (238)		0
45	MaturedLongTermDebt Matured Long-Term Debt (239)		0
46	MaturedInterest Matured Interest (240)		0
47	TaxCollectionsPayable Tax Collections Payable (241)		3,006,212	2,710,271
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		13,331,338	16,479,391
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		208,177	2,964,248
50	DerivativesInstrumentLiabilities Derivative Instrument Liabilities (244)		14,009	51,471
51	LongTermPortionOfDerivativeInstrumentLiabilities (Less) Long-Term Portion of Derivative Instrument Liabilities		14,009	405
52	DerivativeInstrumentLiabilitiesHedges Derivative Instrument Liabilities - Hedges (245)		0
53	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges		0
54	CurrentAndAccruedLiabilities Total Current and Accrued Liabilities (lines 37 through 53)		305,853,180	247,627,370
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)		113,413	162,588
57	AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255)	266	0
58	DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256)		0
59	OtherDeferredCredits Other Deferred Credits (253)	269	8,118,911	2,559,807
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	171,302,791	211,496,606
61	UnamortizedGainOnReacquiredDebt Unamortized Gain on Reaquired Debt (257)		0
62	AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty Accum. Deferred Income Taxes-Accel. Amort.(281)	272	26,863,317	28,546,787
63	AccumulatedDeferredIncomeTaxesOtherProperty Accum. Deferred Income Taxes-Other Property (282)		277,184,560	279,944,834
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		238,332,611	222,722,543
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		721,915,603	745,433,165
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		3,156,506,029	3,006,705,458

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	802,124,211	659,547,828			802,124,211	659,547,828
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	523,739,319	391,618,340			523,739,319	391,618,340
5	MaintenanceExpense Maintenance Expenses (402)	320	64,824,174	64,352,871			64,824,174	64,352,871
6	DepreciationExpense Depreciation Expense (403)	336	98,662,438	93,483,264			98,662,438	93,483,264
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336	58,339	155,861			58,339	155,861
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	9,687,647	8,819,731			9,687,647	8,819,731
9	AmortizationOfElectricPlantAcquisitionAdjustments Amort. of Utility Plant Acq. Adj. (406)	336	38,616	38,616			38,616	38,616
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)		14,937,125	12,707,045			14,937,125	12,707,045
13	RegulatoryCredits (Less) Regulatory Credits (407.4)
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	26,866,441	26,544,078			26,866,441	26,544,078
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	1,370,088	1,639,190			1,370,088	1,639,190
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	979,112	337,063			979,112	337,063
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	85,054,577	59,974,621			85,054,577	59,974,621
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	116,425,649	83,905,161			116,425,649	83,905,161
19	InvestmentTaxCreditAdjustments Investment Tax Credit Adj. - Net (411.4)	266
20	GainsFromDispositionOfPlant (Less) Gains from Disp. of Utility Plant (411.6)		641,658	9,877			641,658	9,877
21	LossesFromDispositionOfServiceCompanyPlant Losses from Disp. of Utility Plant (411.7)
22	GainsFromDispositionOfAllowances (Less) Gains from Disposition of Allowances (411.8)		712,800	8			712,800	8
23	LossesFromDispositionOfAllowances Losses from Disposition of Allowances (411.9)
24	AccretionExpense Accretion Expense (411.10)		554,516	613,105			554,516	613,105
25	UtilityOperatingExpenses TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)		708,992,286	573,090,359			708,992,285	573,090,359
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		93,131,925	86,457,469			93,131,926	86,457,469
28	OtherIncomeAndDeductionsAbstract Other Income and Deductions
29	OtherIncomeAbstract Other Income
30	NonutilityOperatingIncomeAbstract Nonutilty Operating Income
31	RevenuesFromMerchandisingJobbingAndContractWork Revenues From Merchandising, Jobbing and Contract Work (415)
32	CostsAndExpensesOfMerchandisingJobbingAndContractWork (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)
33	RevenuesFromNonutilityOperations Revenues From Nonutility Operations (417)		325,104	308,103
34	ExpensesOfNonutilityOperations (Less) Expenses of Nonutility Operations (417.1)			19
35	NonoperatingRentalIncome Nonoperating Rental Income (418)		5,670	16,187
36	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1)	119
37	InterestAndDividendIncome Interest and Dividend Income (419)		134,088	19,109
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		1,192,269	1,821,825
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		25,384	58,006
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)		17,512	515,942
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		1,688,688	2,739,153
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)		35,070	2,682
44	MiscellaneousAmortization Miscellaneous Amortization (425)
45	Donations Donations (426.1)		3,725,687	2,945,972
46	LifeInsurance Life Insurance (426.2)
47	Penalties Penalties (426.3)		470	105,164
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		248,160	308,201
49	OtherDeductions Other Deductions (426.5)		144,029	2,515,193
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		4,153,415	5,666,884
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262	52,108	98,390
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262	1,296,517	1,331,171
54	IncomeTaxesOther Income Taxes-Other (409.2)	262	287,972	337,063
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272	1,376,225	638,797
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272	1,798,738	1,216,770
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)		1,954,894	2,147,817
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		509,834	779,914
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		44,211,238	36,669,034
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		473,752	480,846
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)		33,651	33,651
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)		1,984,932	165,604
68	OtherInterestExpense Other Interest Expense (431)		1,562	885,096
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		1,635,221	936,297
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		45,069,914	35,527,742
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		47,552,177	50,149,813
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	0
77	ExtraordinaryItemsAfterTaxes Extraordinary Items After Taxes (line 75 less line 76)
78	NetIncomeLoss Net Income (Total of line 71 and 77)		47,552,177	50,149,813

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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		296,020,207	245,870,395
2	ChangesAbstract Changes
3	AdjustmentsToRetainedEarningsAbstract Adjustments to Retained Earnings (Account 439)
4	AdjustmentsToRetainedEarningsCreditAbstract Adjustments to Retained Earnings Credit
4.1	AdjustmentsToRetainedEarningsCredit Adj to Retained Earnings
9	AdjustmentsToRetainedEarningsCredit TOTAL Credits to Retained Earnings (Acct. 439)
10	AdjustmentsToRetainedEarningsDebitAbstract Adjustments to Retained Earnings Debit
15	AdjustmentsToRetainedEarningsDebit TOTAL Debits to Retained Earnings (Acct. 439)
16	BalanceTransferredFromIncome Balance Transferred from Income (Account 433 less Account 418.1)		47,552,177	50,149,812
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 Common stock
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)		343,572,384	296,020,207
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)		343,572,384	296,020,207
	UnappropriatedUndistributedSubsidiaryEarningsAbstract UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49	UnappropriatedUndistributedSubsidiaryEarnings Balance-Beginning of Year (Debit or Credit)
50	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings for Year (Credit) (Account 418.1)
51	DividendsReceived (Less) Dividends Received (Debit)
52	ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits TOTAL other Changes in unappropriated undistributed subsidiary earnings for the year
53	UnappropriatedUndistributedSubsidiaryEarnings Balance-End of Year (Total lines 49 thru 52)		0

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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)	47,552,177	50,149,813
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	108,447,039	102,497,472
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of Regulatory Debits and Credits (Net)	14,937,125	12,707,045
5.2	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Mark-to-Market of Risk Management Contracts	2,542,112	2,991,726
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	31,793,585	24,508,514
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	31,824,893	9,804,910
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	17,545,074	11,702,745
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory	53,461	68,067
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	20,788,725	20,093,759
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	27,956,526	56,480,696
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	3,093,625	3,847,436
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	1,192,269	1,821,825
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other (provide details in footnote):	(a) 9,588,235	30,419,418
18.2	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Customer deposits	6,352,742	1,657,710
18.3	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Over/Under Recovered Fuel, Net	15,025,292	8,529,459
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	82,933,377	68,167,499
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)	212,537,581	167,164,664
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	1,192,269	1,821,825
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
31.1	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Other (provide details in footnote):
31.2	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Acquired Assets	70,501	206,212
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	211,274,811	165,549,051
36	AcquisitionOfOtherNoncurrentAssets Acquisition of Other Noncurrent Assets (d)
37	ProceedsFromDisposalOfNoncurrentAssets Proceeds from Disposal of Noncurrent Assets (d)	(b) 8,003,560	1,075,489
39	InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Investments in and Advances to Assoc. and Subsidiary Companies
40	ContributionsAndAdvancesFromAssociatedAndSubsidiaryCompanies Contributions and Advances from Assoc. and Subsidiary Companies
41	DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompaniesAbstract Disposition of Investments in (and Advances to)
42	DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Disposition of Investments in (and Advances to) Associated and Subsidiary Companies
44	PurchaseOfInvestmentSecurities Purchase of Investment Securities (a)
45	ProceedsFromSalesOfInvestmentSecurities Proceeds from Sales of Investment Securities (a)
46	LoansMadeOrPurchased Loans Made or Purchased
47	CollectionsOnLoans Collections on Loans
49	NetIncreaseDecreaseInReceivablesInvestingActivities Net (Increase) Decrease in Receivables
50	NetIncreaseDecreaseInInventoryInvestingActivities Net (Increase) Decrease in Inventory
51	NetIncreaseDecreaseInAllowancesHeldForSpeculationInvestingActivities Net (Increase) Decrease in Allowances Held for Speculation
52	NetIncreaseDecreaseInPayablesAndAccruedExpensesInvestingActivities Net Increase (Decrease) in Payables and Accrued Expenses
53	OtherAdjustmentsToCashFlowsFromInvestmentActivities Other (provide details in footnote):
53.1	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Other (Provide details in footnote):	618,271	3,221,405
53.2	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription (Increase) Decrease in Other Special Deposits	80,875	74,930
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	202,572,105	161,327,087
59	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
60	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
61	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b)	150,000,000	150,000,000
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 Long Term Issuances Costs	131,102	26,355
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
67.1	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Proceed on Capital leaseback	6,627	168,008
67.2	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Notes Payable to Associated Companies	46,532,054
67.3	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Capital Contributions from Parent	151,683
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	196,559,262	150,141,653
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)	75,000,000	40,000,000
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 Notes Payable to Associated Companies - Retired		17,751,304
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)	121,559,262	92,390,349
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)	1,920,534	769,239
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	763,386	1,532,625
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	2,683,920	763,386

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities


	2022 Cash Flow Incr / (Decr)		2021 Cash Flow Incr / (Decr)
Utility Plant, Net	$	(20,556,831)	$	(13,107,143)

Property and Investments, Net	$	7,119,464	$	182,324

Margin Deposits	13,185,176		(14,043,098)

Prepayments	(3,646,485)		(1,225,157)

Accrued Utility Revenues, Net	(18,355,535)		2,270,665

Unamortized Debt Expense	473,752		480,846

Other Deferred Debits, Net	(2,552,359)		(293,644)

Other Comprehensive Income, Net	(1,670,953)		—

Accumulated Provisions - Misc	(455,071)		(10,435)

Current and Accrued Liabilities, Net	(4,054,428)		(875,480)

Other Deferred Credits, Net	4,694,288		(3,798,296)

Special Funds	35,407,217		—
Total	$	9,588,235	$	(30,419,418)

(b) Concept: ProceedsFromDisposalOfNoncurrentAssets


	2022 Cash Flow Incr / (Decr)		2021 Cash Flow Incr / (Decr)
Sale of meters between various operating companies	$	15,635	$	22,701
Sale of transformers between various operating companies	112,100		408,442
Sale of 1.18+/- acres located at 332 South May Trail, Pikeville, Kentucky - to third party	—		530,000
Land Sale Proceeds - Dumont / Lakeville Site, Dumont UHV Test Facility - to third party	6,686,087		114,346
Sale of Kentucky Portion of Posey Coal Lands	1,058,960		$	—
Caterpillar D8T Crawler Tractor	130,778		$	—

Total	$	8,003,560	$	1,075,489

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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.

INDEX OF NOTES TO FINANCIAL STATEMENTS


			Glossary of Terms for Notes
1.			Organization and Summary of Significant Accounting Policies
2.			New Accounting Standards
3.			Comprehensive Income
4.			Rate Matters
5.			Effects of Regulation
6.			Commitments, Guarantees and Contingencies
7.			Benefit Plans
8.			Derivatives and Hedging
9.			Fair Value Measurements
10.			Income Taxes
11.			Leases
12.			Financing Activities
13.			Related Party Transactions
14.			Property, Plant and Equipment
15.			Revenue from Contracts with Customers

GLOSSARY OF TERMS FOR NOTES

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.


Term						Meaning

AEGCo						AEP Generating Company, an AEP electric utility subsidiary.
AEP						American Electric Power Company, Inc., an investor-owned electric public utility holding company which includes American Electric Power Company, Inc. (Parent) and majority-owned subsidiaries and affiliates.
AEP Credit						AEP Credit, Inc., a subsidiary of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP East Companies						APCo, I&M, KGPCo, KPCo, OPCo and WPCo.
AEP System						American Electric Power System, an electric system, owned and operated by AEP subsidiaries.
AEPSC						American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEPTCo						AEP Transmission Company, LLC, a wholly-owned subsidiary of AEP Transmission Holdco, is an intermediate holding company that owns the State Transcos.
AFUDC						Allowance for Equity Funds Used During Construction.
AOCI						Accumulated Other Comprehensive Income.
APCo						Appalachian Power Company, an AEP electric utility subsidiary.
CCR						Coal Combustion Residual.
COVID-19						Coronavirus 2019, a highly infectious respiratory disease. In March 2020, the World Health Organization declared COVID-19 a worldwide pandemic.
CWIP						Construction Work in Progress.
ELG						Effluent Limitation Guidelines.
EIS						Energy Insurance Services, Inc., a nonaffiliated captive insurance company.
Excess ADIT						Excess accumulated deferred income taxes.
FAC						Fuel Adjustment Clause.
FASB						Financial Accounting Standards Board.
Federal EPA						United States Environmental Protection Agency.
FERC						Federal Energy Regulatory Commission.
FTR						Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP						Accounting Principles Generally Accepted in the United States of America.
I&M						Indiana Michigan Power Company, an AEP electric utility subsidiary.
IRS						Internal Revenue Service.
ITC						Investment Tax Credit.
KGPCo						Kingsport Power Company, an AEP electric utility subsidiary.
KPCo						Kentucky Power Company, an AEP electric utility subsidiary.
KPSC						Kentucky Public Service Commission.
KTCo						AEP Kentucky Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.
Liberty						Liberty Utilities Co., a subsidiary of Algonquin Power & Utilities Corporation.
MTM						Mark-to-Market.
MW						Megawatt.
MWh						Megawatt-hour.
NOx						Nitrogen oxide.


OATT						Open Access Transmission Tariff.
OPCo						Ohio Power Company, an AEP electric utility subsidiary.
OPEB						Other Postretirement Benefits.
OTC						Over-the-counter.
Parent						American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
PCA						Power Coordination Agreement among APCo, I&M, KPCo and WPCo.
PJM						Pennsylvania – New Jersey – Maryland regional transmission organization.
PSO						Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO						Public Utilities Commission of Ohio.
Risk Management Contracts						Trading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant						A generation plant, jointly-owned by AEGCo and I&M, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana.

RTO						Regional Transmission Organization, responsible for moving electricity over large interstate areas.
SIA						System Integration Agreement, effective June 15, 2000, as amended, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP.
SWEPCo						Southwestern Electric Power Company, an AEP electric utility subsidiary.
TA						Transmission Agreement, effective November 2010, among APCo, I&M, KGPCo, KPCo, OPCo and WPCo with AEPSC as agent.
Tax Reform						On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018.
UPA						Unit Power Agreement.
Utility Money Pool						Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
WPCo						Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC						West Virginia Public Service Commission.

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION

As a public utility, KPCo engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to approximately 163,000 retail customers in its service territory in eastern Kentucky. KPCo also sells power at wholesale to municipalities.

In December 2022, the UPA between AEGCo, an affiliated company, and KPCo ended upon the termination of the Rockport Plant, Unit 2 lease. The UPA allowed KPCo to purchase 30% of AEGCo’s 50% capacity of Rockport Plant, Unit 2. Following the end of the lease, KPCo reached an agreement with I&M, an affiliated company, to purchase capacity from Rockport Plant, Unit 2 through May 2024 at a rate equal to PJM’s RPM clearing price.

To minimize the credit requirements and operating constraints when operating within PJM, participating AEP companies, including KPCo, agreed to a netting of certain payment obligations incurred by the participating AEP companies against certain balances due to such AEP companies and to hold PJM harmless from actions that any one or more AEP companies may take with respect to PJM.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Rates and Service Regulation

KPCo’s rates are regulated by the FERC and the KPSC. The FERC also regulates KPCo’s affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over certain issuances and acquisitions of securities of public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The KPSC also regulates certain intercompany transactions under its affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system.

The FERC regulates wholesale power markets, wholesale power transactions and wholesale transmission operations and rates. KPCo’s wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when KPCo negotiates and files a cost-based contract with the FERC or the FERC determines that KPCo has “market power” in the region where the transaction occurs. KPCo has entered into wholesale power supply contracts with various municipalities that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued-up to actual costs annually.

The KPSC regulates all of the distribution operations and rates and retail transmission rates on a cost basis. The KPSC also regulates retail generation/power supply operations and rates.

In addition, the FERC regulates the SIA and the TA, which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. The FERC also regulates the PCA. See Note 13 - Related Party Transactions for additional information.

Basis of Accounting

KPCo’s accounting is subject to the requirements of the KPSC and the FERC. The financial statements have been prepared in accordance with the Uniform System of Accounts prescribed by the FERC. The principal differences from GAAP include:



·			The classification of deferred fuel as noncurrent rather than current.

·			The requirement to report deferred tax assets and liabilities separately rather than as a single amount.
·			The classification of accrued taxes as a single amount rather than as assets and liabilities.
·			The exclusion of current maturities of long-term debt from current liabilities.
·			The classification of accrued non-ARO asset removal costs as accumulated depreciation rather than regulatory liabilities.
·			The classification of finance lease payments as operating activities instead of financing activities.
·			The classification of gains/losses from disposition of allowances as utility operating expenses rather than as operating revenues.
·			The classification of PJM hourly activity for physical transactions as purchases and sales instead of net sales.



·			The classification of regulatory assets and liabilities related to the accounting guidance for “Accounting for Income Taxes” as separate assets and liabilities rather than as a single amount.
·			The presentation of finance leased assets and their associated accumulated amortization as a single amount instead of as separate amounts.
·			The classification of factored accounts receivable expense as a nonoperating expense instead of as an operating expense.

·			The classification of certain nonoperating revenues as miscellaneous nonoperating income instead of as operating revenue.
·			The classification of certain nonoperating expenses as miscellaneous nonoperating expense instead of as operating expense.
·			The separate classification of income tax expense for operating and nonoperating activities instead of as a single income tax expense.


·			The classification of unamortized loss on reacquired debt in deferred debits rather than in regulatory assets.

·			The classification of certain other assets and liabilities as current instead of noncurrent.
·			The classification of certain other assets and liabilities as noncurrent instead of current.
·			The classification of debt issuance costs as noncurrent assets instead of noncurrent liabilities.
·			The classification of rents receivable as rents receivable instead of customer accounts receivable.
·			The classification of Non-Service Cost Components of Net Periodic Benefit Cost as Operating Expense instead of Other Income (Expense).
·			The classification of operating lease assets as Utility Plant rather than as a noncurrent asset.
·			The presentation of obligations under finance and operating leases as a single amount in Obligations Under Capital Leases rather than as separate items.
·			The classification of certain expenses in operating income rather than operating expenses.


·			The classification of interest on regulated finance leases as operating expense instead of Other Income (Expense).
·			The classification of cloud computing implementation costs as Utility Plant rather than as a noncurrent asset.

Accounting for the Effects of Cost-Based Regulation

As a rate-regulated electric public utility company, KPCo’s financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” KPCo records regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.

Use of Estimates

The preparation of these financial statements requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include but are not limited to inventory valuation, allowance for doubtful accounts, long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.

Cash and Cash Equivalents

Cash and Cash Equivalents include Cash, Working Fund and Temporary Cash Investments on the balance sheets with original maturities of three months or less.

Supplementary Information


		2022			2021
For the Years Ended December 31,		(in thousands)
Cash was Paid (Received) for:
	Interest (Net of Capitalized Amounts)	$	41,497		$	37,378
	Income Taxes (Net of Refunds)			2,489			(4,123)
Noncash Acquisitions Under Finance Leases				131			331
As of December 31,
Construction Expenditures Included in Current and Accrued Liabilities				18,898			28,280

AEP System Tax Allocation

KPCo joins in the filing of a consolidated federal income tax return with its affiliates in the AEP System. Historically, the allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocated the benefit of current tax loss of the parent company (Parent Company Loss Benefit) to the AEP System subsidiaries through a reduction of current tax expense. In the first quarter of 2022, AEP and subsidiaries changed accounting for the Parent Company Loss Benefit from a reduction of current tax expense to an allocation through equity. The impact of this change was immaterial to KPCo’s financial statements. The consolidated net operating losses of the AEP System is allocated to each company in the consolidated group with taxable loss. With the exception of the allocation of the consolidated AEP System net operating losses, the loss of the Parent and tax credits, the method of allocation reflects a separate return result for each company in the consolidated group.

Inventory

Fossil fuel inventories and materials and supplies inventories are carried at average cost.

Accounts Receivable

Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities.

Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, KPCo accrues and recognizes, as Accrued Utility Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing.

Allowance for Uncollectible Accounts

Prior to the first quarter of 2022, KPCo sold, without recourse, certain of its customer accounts receivable and accrued unbilled revenue balances to AEP Credit under an affiliated receivables sales arrangement. Under the arrangement, KPCo was charged a fee for each sale based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience from previous purchases of KPCo’s customer accounts receivable. As a result, no allowance for uncollectible accounts was recognized within KPCo’s financial statements for customer accounts receivable sold to AEP Credit, and any bad debt stemming from these receivables would be recognized by AEP Credit. KPCo terminated selling accounts receivable to AEP Credit in the first quarter of 2022, based on the pending sale to Liberty. As a result of the termination, in the first quarter of 2022, KPCo recorded an allowance for uncollectible accounts on its balance sheet for those receivables no longer sold to AEP Credit. KPCo’s bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable.

Concentrations of Credit Risk and Significant Customers

KPCo had a significant customer which accounts for the following percentages of Total Revenues for the years ended December 31 and Accounts Receivable – Customers as of December 31:


Significant Customer of KPCo:
Marathon Petroleum Company	2022		2021
Percentage of Total Revenues	14	%	12	%
Percentage of Accounts Receivable – Customers	14	%	45	%

Management monitors credit levels and the financial condition of KPCo’s customers on a continuous basis to minimize credit risk. The KPSC allows recovery in rates for a reasonable level of bad debt costs. Management believes adequate provision for credit loss has been made in the accompanying financial statements.

Property, Plant and Equipment

Electric utility property, plant and equipment are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review.

The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses.

Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in-service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed or is not probable, the cost of that asset shall be written down to its then current estimated fair value, with the change charged to expense, and the asset is removed from plant-in-service or CWIP.

The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.

Allowance for Funds Used During Construction

AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant.

Asset Retirement Obligations (ARO)

KPCo records ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities. AROs are computed as the present value of the estimated costs associated with the future retirement of an asset and are recorded in the period in which the liability is incurred. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be decommissioned, inflation, and discount rate, which may change significantly over time. The estimated costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. KPCo has identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since KPCo plans to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected.

Valuation of Nonderivative Financial Instruments

The book values of Cash, Special Deposits, Notes Payable to Associated Companies and accounts receivable and accounts payable approximate fair value because of the short-term maturity of these instruments.

Fair Value Measurements of Assets and Liabilities

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.

For commercial activities, exchange-traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange-traded derivatives where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be

corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket-based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility.

AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes.

Assets in the benefits trusts are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and equity securities. They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Investments classified as Other are valued using Net Asset Value as a practical expedient. Items classified as Other are primarily cash equivalent funds, common collective trusts, commingled funds, structured products, private equity, real estate, infrastructure and alternative credit investments. These investments do not have a readily determinable fair value or they contain redemption restrictions which may include the right to suspend redemptions under certain circumstances. Redemption restrictions may also prevent certain investments from being redeemed at the reporting date for the underlying value.

Deferred Fuel Costs

The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Operation Expenses when the fuel is burned or the allowance or consumable is utilized. Fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as regulatory assets. These deferrals are amortized when refunded or when billed to customers

in later months with the KPSC’s review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the KPSC. On a routine basis, the KPSC reviews and/or audits KPCo’s fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. Changes in fuel costs, including purchased power, are reflected in rates in a timely manner through the FAC. A portion of margins from off-system sales are given to customers through the FAC.

Revenue Recognition

Regulatory Accounting

KPCo’s financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses or alternative revenues recognized in accordance with the guidance for “Regulated Operations”) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching revenue with its passage to customers in cost-based regulated rates.

When regulatory assets are probable of recovery through regulated rates, KPCo records them as assets on its balance sheets. Regulatory assets are reviewed for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, KPCo derecognizes that regulatory asset as a charge against income.

Electricity Supply and Delivery Activities

KPCo recognizes revenues from customers for retail and wholesale electricity sales and electricity transmission and distribution delivery services. KPCo recognizes such revenues on the statements of income as the performance obligations of delivering energy to customers are satisfied. Recognized revenues include unbilled as well as-billed amounts. Wholesale transmission revenue is based on a FERC-approved formula rate filing made for each calendar year using estimated costs. Revenues initially recognized per the annual rate filing are compared to actual costs, resulting in the subsequent recognition of an over or under-recovered amount, with interest, that is refunded or recovered, respectively, in a future year’s rates. The annual true-up meets the definition of alternative revenues in accordance with the accounting guidance for “Regulated Operations”. An estimated annual true-up is recorded by KPCo in the fourth quarter of each calendar year and a final annual true-up is recognized by KPCo in the second quarter of each calendar year following the filing of the annual FERC report. Any portion of the true-up applicable to an affiliated company is recorded as Accounts Receivable from Associated Companies or Accounts Payable to Associated Companies on the balance sheets. Any portion of the true-ups applicable to third-parties is recorded as regulatory assets or regulatory liabilities on the balance sheets. See Note 15 - Revenue from Contracts with Customers for additional information.

Gross versus Net Presentation of Certain Electricity Supply and Delivery Activities

The power produced at KPCo’s generation plants is sold to PJM. KPCo also purchases power from PJM to supply power to its customers. Generally, these power sales and purchases are reported on a net basis in revenues on the statements of income.

Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Operation Expenses on the statements of income. Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s facts and circumstances. Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Operation Expenses on the statements of income. All other non-trading derivative purchases are recorded net in revenues.

In general, KPCo records expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting. KPCo defers the unrealized MTM amounts as regulatory assets (for losses) and regulatory liabilities (for gains).

Energy Marketing and Risk Management Activities

KPCo engages in power marketing as a major power producer and participant in electricity markets. KPCo also engages in power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity risk management activities focused on markets where the AEP System owns assets and on adjacent markets. These activities include the purchase-and-sale of energy under forward contracts at fixed and variable prices. These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options. Certain energy marketing and risk management transactions are with RTOs.

KPCo recognizes revenues from marketing and risk management transactions that are not derivatives as the performance obligation of delivering the commodity is satisfied. Expenses from marketing and risk management transactions that are not derivatives are also recognized upon delivery of the commodity.

KPCo uses MTM accounting for marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or elected normal under the normal purchase normal sale election. Unrealized MTM gains and losses are included on KPCo’s balance sheets as Derivative Instrument Assets and Liabilities, as appropriate, and on KPCo’s statements of income in Operating Revenues. Realized gains and losses on marketing and risk management transactions are included in revenues or expenses based on the transaction’s facts and circumstances. However, in regulated jurisdictions subject to cost-based regulation, unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).

Certain qualifying marketing and risk management derivative transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge). In the event KPCo designates a cash flow hedge, the cash flow hedge’s gain or loss is initially recorded as a component of AOCI. When the forecasted transaction is realized and affects net income, KPCo subsequently reclassifies the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on the statements of income. See “Accounting for Cash Flow Hedging Strategies” section of Note 8.

Maintenance

Maintenance costs are expensed as incurred. If it becomes probable that KPCo will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues.

Income Taxes

KPCo uses the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled.

When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost-of-service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense.

KPCo accounts for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” KPCo classifies interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classifies penalties as Penalties on the statements of income.

Excise Taxes

As an agent for some state and local governments, KPCo collects from customers certain excise taxes levied by those state or local governments on customers. KPCo does not recognize these taxes as revenue or expense.

Debt

Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt is refinanced, the reacquisition costs are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates.

Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations.

Pension and OPEB Plans

KPCo participates in an AEP sponsored qualified pension plan and two unfunded non-qualified pension plans. Substantially all of KPCo’s employees are covered by the qualified plan or both the qualified and non-qualified

pension plans. KPCo also participates in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees. KPCo accounts for its participation in the AEP sponsored pension and OPEB plans using multiple-employer accounting. See Note 7 - Benefit Plans for additional information including significant accounting policies associated with the plans.

Investments Held in Trust for Future Liabilities

AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits. All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations. The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance.

Benefit Plans

All benefit plan assets are invested in accordance with each plan’s investment policy. The investment policy outlines the investment objectives, strategies and target asset allocations by plan.

The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns. Strategies used include:

•Maintaining a long-term investment horizon.

•Diversifying assets to help control volatility of returns at acceptable levels.

•Managing fees, transaction costs and tax liabilities to maximize investment earnings.

•Using active management of investments where appropriate risk/return opportunities exist.

•Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks.

•Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification.

The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities. The current target asset allocations are as follows:


Pension Plan Assets	Target
Equity	30	%
Fixed Income	54	%
Other Investments	15	%
Cash and Cash Equivalents	1	%

OPEB Plans Assets	Target
Equity	59	%
Fixed Income	40	%
Cash and Cash Equivalents	1	%

The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies or certain commingled funds). However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law.

For equity investments, the concentration limits are generally as follows:

•No security in excess of 5% of all equities.

•Cash equivalents must be less than 10% of an investment manager’s equity portfolio.

•No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager’s equity portfolio.

•No securities may be bought or sold on margin or other use of leverage.

For fixed income investments, each investment manager’s portfolio is compared to investment grade, diversified long and intermediate benchmark indices.

A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation. Real estate properties are illiquid, difficult to value and not actively traded. The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties. To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification. Real estate holdings include core, value-added and opportunistic classifications.

A portion of the pension assets is invested in private equity. Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance. Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded. The pension plan uses limited partnerships to invest across the private equity investment spectrum. The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection

expertise. The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investments.

AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses. AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral. All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested. The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security. The securities lending program’s objective is to provide modest incremental income with a limited increase in risk. As of December 31, 2022 and 2021, the fair value of securities on loan as part of the program was $83 million and $137 million, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned as of December 31, 2022 and 2021.

Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts. The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust. Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid. Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities. With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds. A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges. The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities.

Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal. The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities. The cash funds are valued each business day and provide daily liquidity.

Comprehensive Income (Loss)

Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).

Disposition of KPCo and KTCo

In October 2021, AEP entered into a Stock Purchase Agreement (SPA) to sell KPCo and KTCo to Liberty Utilities Co., a subsidiary of Algonquin Power & Utilities Corp. (Liberty), for approximately a $2.85 billion enterprise value. In May 2022, the KPSC approved the transfer of KPCo to Liberty subject to certain conditions contingent upon the closing of the sale. AEP has received clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR) and the Committee on Foreign Investment in the United States during 2022.

Clearance under the HSR expired in January 2023. AEP and Liberty refiled a joint application seeking HSR clearance in February 2023. The sale is also contingent upon FERC approval under Section 203 of the Federal Power Act. The parties to the SPA have certain termination rights if the closing of the sale does not occur by April 26, 2023.

Transfer of Ownership

FERC Proceedings

In December 2021, Liberty, KPCo and KTCo (the applicants) requested FERC approval of the sale under Section 203 of the Federal Power Act. In February 2022, several intervenors in the case filed protests related to whether the sale will negatively impact the wholesale transmission rates of applicants. In April 2022, the FERC issued a deficiency letter stating that the Section 203 application is deficient and that additional information is required to process it. In May 2022, Liberty, KPCo and KTCo supplemented the application. In December 2022, the FERC issued an order denying, without prejudice, authorization of the proposed sale stating the applicants failed to demonstrate the proposed transaction will not have an adverse effect on rates.

In January 2023, AEP, AEPTCo, and Liberty entered into an amendment to the SPA that specified the applicants will submit a new filing for approval under Section 203 of the Federal Power Act. The new filing was submitted to the FERC on February 14, 2023. The applicants requested expedited treatment of the new filing, including an accelerated comment period. In response, the FERC granted a shortened 45 day comment period. The applicants believe the new Section 203 application addresses the concerns raised in the FERC’s December 2022 order. The application contains several additional commitments by Liberty to mitigate potential adverse impacts on FERC jurisdictional rates over the next five years, including: a) maintaining the current return on equity; b) maintaining the current cost cap on equity; c) financing future investments at the current credit rating; and d) capping certain operating and administrative costs. The sale remains subject to FERC approval. The statute requires an order from the FERC within 180 days of the February 14, 2023 filing date in accordance with Section 203 of the Federal Power Act.

KPSC Proceedings

In May 2022, the KPSC approved the transfer of KPCo to Liberty subject to conditions contingent upon the closing of the sale, including establishment of regulatory liabilities to subsidize retail customer transmission and distribution expenses, a fuel adjustment clause bill credit, and a three-year Big Sandy decommissioning rider rate holiday during which KPCo’s carrying charge is reduced by 50%.

Mitchell Plant Operations and Maintenance Agreement and Ownership Agreement

KPCo and WPCo each own a 50% undivided interest in the 1,560 MW coal-fired Mitchell Plant. As of December 31, 2022 and 2021, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $577 million and $586 million, respectively. The SPA includes a condition precedent to closing requiring the issuance of regulatory orders approving new Mitchell Plant agreements.

The KPSC and WVPSC issued orders proposing materially different modifications to the Mitchell Plant agreements filed by AEP such that the new agreements could not be executed by the parties. In lieu of new agreements, in July 2022, KPCo and WPCo confirmed with the KPSC and WVPSC, respectively, that they will continue operating under the existing Mitchell Agreement, utilizing the Mitchell Agreement Operating Committee’s authority under that agreement to issue appropriate resolutions so the parties can operate in accordance with each state commission’s directives related to CCR and ELG investment. In September 2022, pursuant to resolutions under the existing Mitchell Plant agreement, WPCo replaced KPCo as the Operator of Mitchell Plant.

Summary

Management believes it is probable that FERC authorization under Section 203 of the Federal Power Act will be received and closing will occur after receipt of the order with Liberty acquiring the assets and assuming the liabilities of KPCo and KTCo, excluding pension and other post-retirement benefit plan assets and liabilities. AEP expects to provide customary transition services to Liberty for a period of time after closing of the transaction.

In June 2022, KPCo entered into agreements to purchase assets under lease, terminating remaining lease obligations prior to the original maturity date. As a result of the early terminations, current obligations under operating and finance leases of $1.9 million and $583 thousand, respectively, and noncurrent obligations under operating and finance leases of $7.2 million and $1.4 million, respectively, were relieved from KPCo’s balance sheet in the second quarter of 2022.

Subsequent Events

Management has evaluated the impact of events occurring after December 31, 2022 through February 23, 2023, the date that KPCo’s 2022 Annual Report was available to be issued, and has updated such evaluation for disclosure purposes through April 12, 2023. These financial statements include all necessary adjustments and disclosures resulting from these evaluations.

2. NEW ACCOUNTING STANDARDS

During the FASB’s standard-setting process and upon issuance of final standards, management reviews the new accounting literature to determine its relevance, if any, to KPCo’s business. There are no new standards expected to have a material impact on KPCo’s financial statements.

3. COMPREHENSIVE INCOME

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the years ended December 31, 2022 and 2021. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 - Benefit Plans for additional details.


		Pension and OPEB
		Amortization		Changes
		of Deferred		in Funded
For the Year Ended December 31, 2022		Costs		Status		Total
	(in thousands)
Balance in AOCI as of December 31, 2021		$	2,890	$	(1,141)	$	1,749
Change in Fair Value Recognized in AOCI, Net of Tax		—		—		—
Amount of (Gain) Loss Reclassified from AOCI
Amortization of Prior Service Cost (Credit)		(119)		—		(119)
Amortization of Actuarial (Gains) Losses		19		—		19
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(100)		—		(100)
Income Tax (Expense) Benefit		(21)		—		(21)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(79)		—		(79)
Pension and OPEB Adjustment Related to Plant Transfers		—		(2,114)		(2,114)
Income Tax (Expense) Benefit		—		(444)		(444)
Pension and OPEB Adjustment Related to Plant Transfers, Net of Income Tax (Expense) Benefit		—		(1,670)		(1,670)
Net Current Period Other Comprehensive Income (Loss)		(79)		(1,670)		(1,749)
Balance in AOCI as of December 31, 2022		$	2,811	$	(2,811)	$	—


		Pension and OPEB
		Amortization		Changes
		of Deferred		in Funded
For the Year Ended December 31, 2021		Costs		Status		Total
	(in thousands)
Balance in AOCI as of December 31, 2020		$	3,027	$	(2,149)	$	878
Change in Fair Value Recognized in AOCI, Net of Tax		—		1,008		1,008
Amount of (Gain) Loss Reclassified from AOCI
Amortization of Prior Service Cost (Credit)		(235)		—		(235)
Amortization of Actuarial (Gains) Losses		62		—		62
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(173)		—		(173)
Income Tax (Expense) Benefit		(36)		—		(36)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(137)		—		(137)
Net Current Period Other Comprehensive Income (Loss)		(137)		1,008		871
Balance in AOCI as of December 31, 2021		$	2,890	$	(1,141)	$	1,749

4. RATE MATTERS

KPCo is involved in rate and regulatory proceedings at the FERC and the KPSC. Rate matters can have a material impact on net income, cash flows and possibly financial condition. KPCo’s recent significant rate orders and pending rate filings are addressed in this note.

CCR/ELG Compliance Plan Filings

KPCo and WPCo each own a 50% interest in the Mitchell Plant. As of December 31, 2022, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $577 million. In December 2020 and February 2021, WPCo and KPCo filed requests with the WVPSC and KPSC, respectively, to obtain the regulatory approvals necessary to implement CCR and ELG compliance plans and seek recovery of the estimated $132 million investment for the Mitchell Plant that would allow the plant to continue operating beyond 2028. Within those requests, WPCo and KPCo also filed a $25 million alternative to implement only the CCR-related investments with the WVPSC and KPSC, respectively, which would allow the Mitchell Plant to continue operating only through 2028.

In July 2021, the KPSC issued an order approving the CCR only alternative and rejecting the full CCR and ELG compliance plan. In May 2022, the KPSC approved recovery of the Kentucky jurisdictional share of ELG costs incurred at the Mitchell Plant prior to July 15, 2021.

In August 2021, the WVPSC approved the full CCR and ELG compliance plan for the WPCo share of the Mitchell Plant. In September 2021, WPCo submitted a filing with the WVPSC to reopen the CCR/ELG case that was approved by the WVPSC in August 2021. Due to the rejection by the KPSC of the KPCo share of the ELG investments, WPCo requested the WVPSC consider approving the construction and recovery of all ELG costs at the plant. In October 2021, the WVPSC affirmed its August 2021 order approving the construction of CCR/ELG investments and directed WPCo to proceed with CCR/ELG compliance plans that would allow the plant to continue operating beyond 2028. The WVPSC also ordered that WPCo will be given the opportunity to recover, from its customers, the ELG and new capital and operating costs arising solely from the WVPSC's directive to operate the plant beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred. The WVPSC’s order further states that unless KPCo pays for its share of costs for ELG improvements and costs necessary to continue operations beyond 2028, the benefit of the capacity and energy made possible by those improvements and operating Mitchell Plant beyond 2028 should benefit only West Virginia jurisdictional customers who have shared in paying for those costs.

Storm-Related Costs

In June 2022, KPCo’s service territory was impacted by strong winds from severe storms resulting in system damages and power outages. In July 2022, KPCo’s service territory was impacted again by severe storms, which caused flash flooding, resulting in additional system damages and power outages. In August 2022, KPCo filed an application with the KPSC requesting deferral authority for $18 million of incremental operation and maintenance costs related to these storms. In September 2022, the KPSC issued an order granting deferral authority. KPCo

intends to seek recovery of the deferral in a future base rate case. If any of these incremental storm costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Deferred Purchased Power Expenses

In September 2022, the KPSC initiated a proceeding to investigate the appropriate amortization period and recovery mechanism for the deferral of Kentucky Deferred Purchased Power Expenses related to the Rockport Plant Unit Power Agreement, as well as KPCo’s ability to use the level of non-fuel, non-environmental Rockport UPA expense included in base rates to earn its authorized ROE in 2023 since the KPCo UPA ended in December 2022. KPCo requested the KPSC approve the terms related to each of the foregoing items as reflected in the settlement agreement in the 2017 Kentucky Base Rate Case, including recovery of the Kentucky Deferred Purchased Power Expenses over five years through a rider beginning in December 2022. In December 2022, the KPSC approved KPCo’s request and recovery began through a rider, including recovery of an estimated allowed cost (Rockport Offset) of $22.8 million in accordance with the terms of the settlement agreement in the 2017 Kentucky Base Rate Case permitting KPCo to use the level of non-fuel, non-environmental Rockport UPA expense included in base rates to earn its authorized ROE in 2023. This estimated Rockport Offset is subject to true-up based on KPCo’s actual 2023 financial results and KPSC review in the first quarter of 2024. The actual Rockport Offset cannot exceed $40.8 million. If the actual Rockport Offset is not recoverable, it could reduce future net income and cash flows and impact financial condition.

5. EFFECTS OF REGULATION

Regulatory Assets and Liabilities

Regulatory assets and liabilities are comprised of the following items:


			December 31,				Remaining
Regulatory Assets:			2022		2021		Recovery Period
			(in thousands)
Regulatory assets pending final regulatory approval:

	Regulatory Assets Currently Earning a Return
		Kentucky Deferred Purchased Power Expenses	$	—	$	47,528
Total Regulatory Assets Currently Earning a Return			—		47,528
	Regulatory Assets Currently Not Earning a Return
		Storm Related Costs (a)	74,430		56,506
		Income Tax Assets	32,843		—
		Other Regulatory Assets Pending Final Regulatory Approval	1,699		893
Total Regulatory Assets Currently Not Earning a Return			108,972		57,399

Total Regulatory Assets Pending Final Regulatory Approval			108,972		104,927

Regulatory assets approved for recovery:

	Regulatory Assets Currently Earning a Return
		Plant Retirement Costs	178,502		193,229		18 years
		Plant Retirement Costs - Asset Retirement Obligation Costs	110,010		109,577		18 years
		Kentucky Deferred Purchased Power Expenses	52,970		—		5 years
		Plant Retirement Costs - Materials and Supplies	3,016		3,016		18 years
		Other Regulatory Assets Approved for Recovery	931		928		various
Total Regulatory Assets Currently Earning a Return			345,429		306,750
	Regulatory Assets Currently Not Earning a Return
		Income Tax Assets	103,999		128,784		(b)
		Fuel and Purchased Power Rider	38,164		28,727		2 years
		Pension and OPEB Funded Status	23,704		12,236		12 years
		Under-recovered Fuel Costs	23,241		8,216		1 year
		Plant Retirement Costs - Asset Retirement Obligation Costs	5,295		4,721		18 years
		Environmental Costs	5,139		5,920		2 years
		Postemployment Benefits	4,416		3,410		3 years
		Storm Related Costs	100		2,167		1 year
		Other Regulatory Assets Approved for Recovery	5,476		7,231		various
Total Regulatory Assets Currently Not Earning a Return			209,534		201,412

Total Regulatory Assets Approved for Recovery			554,963		508,162

Total FERC Account 182.3 Regulatory Assets			$	663,935	$	613,089

(a)KPCo will seek recovery of these costs during the next base rate case.

(b)Recovered over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets.


			December 31,				Remaining
Regulatory Liabilities:			2022		2021		Refund Period
			(in thousands)
Regulatory liabilities pending final regulatory determination:

	Regulatory Liabilities Currently Not Paying a Return
		Other Regulatory Liabilities Pending Final Regulatory Determination	$	2,098	$	2,098
Total Regulatory Liabilities Pending Final Regulatory Determination			2,098		2,098

Regulatory liabilities approved for payment:

	Regulatory Liabilities Currently Paying a Return
		Income Tax Liabilities (a)	158,732		201,997		(b)
Total Regulatory Liabilities Currently Paying a Return			158,732		201,997
	Regulatory Liabilities Currently Not Paying a Return
		Unrealized Gain on Forward Commitments	3,982		3,199		2 years
		Off-system Sales Margin Sharing	3,417		—		1 year
		PJM Transmission Enhancement Refund	2,031		2,644		3 years
		Other Regulatory Liabilities Approved for Payment	1,043		1,559		various
Total Regulatory Liabilities Currently Not Paying a Return			10,473		7,402

Total Regulatory Liabilities Approved for Payment			169,205		209,399

Total FERC Account 254 Regulatory Liabilities			$	171,303	$	211,497

(a)Predominately pays a return due to the inclusion of Excess ADIT in rate base.

(b)Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $40.7 million and $81.4 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 6 years.

6. COMMITMENTS, GUARANTEES AND CONTINGENCIES

KPCo is subject to certain claims and legal actions arising in its ordinary course of business. In addition, KPCo’s business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against KPCo cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates.

For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements.

COMMITMENTS

KPCo has substantial commitments to support its business. KPCo purchases fuel, energy and capacity contracts as part of its normal course of business. Certain contracts contain penalty provisions for early termination.

In accordance with the accounting guidance for “Commitments”, the following table summarizes KPCo’s actual contractual commitments as of December 31, 2022:


		Less Than									After
Contractual Commitments		1 Year			2-3 Years			4-5 Years			5 Years			Total
		(in thousands)
Fuel Purchase Contracts (a)		$	5,993		$	12,002		$	11,985		$	20,474		$	50,454
Energy and Capacity Purchase Contracts				—			1,577			—			—			1,577
Total		$	5,993		$	13,579		$	11,985		$	20,474		$	52,031

(a)	Represents contractual commitments to purchase coal, natural gas and other consumables as fuel for electric generation along with related transportation of the fuel.

GUARANTEES

Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third-parties unless specified below.

Indemnifications and Other Guarantees

Contracts

KPCo enters into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally,

these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of December 31, 2022, there were no material liabilities recorded for any indemnifications.

AEPSC conducts power purchase-and-sale activity on behalf of APCo, I&M, KPCo and WPCo, who are jointly and severally liable for activity conducted on their behalf.

CONTINGENCIES

Insurance and Potential Losses

KPCo maintains insurance coverage normal and customary for an electric utility, subject to various deductibles. KPCo also maintains property and casualty insurance that may cover certain physical damage or third-party injuries caused by cyber security incidents. Insurance coverage includes all risks of physical loss or damage to assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. The insurance programs also generally provide coverage against loss arising from certain claims made by third-parties and are in excess of KPCo’s retentions. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers.

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cyber security incident. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition.

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation

By-products from the generation of electricity include materials such as ash, slag and sludge. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and non-hazardous materials. KPCo currently incurs costs to dispose of these substances safely.

Superfund addresses clean-up of hazardous substances that are released to the environment. The Federal EPA administers the clean-up programs. Several states enacted similar laws. As of December 31, 2022, there is one site for which KPCo has received an information request which could lead to a Potentially Responsible Party designation. In the instance where KPCo has been named a defendant, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. Liability has been resolved for a number of sites with no significant effect on net income.

Management evaluates the potential liability for each site separately, but several general statements can be made about potential future liability. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often non-hazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named for

each site and several of the parties are financially sound enterprises. As of December 31, 2022, management’s estimates do not anticipate material clean-up costs for the identified site.

Claims Challenging Transition of American Electric Power System Retirement Plan to Cash Balance Formula

Four participants in The American Electric Power System Retirement Plan (the Plan) filed a class action complaint in December 2021 in the U.S. District Court for the Southern District of Ohio against AEPSC and the Plan. When the Plan’s benefit formula was changed in the year 2000, AEP provided a special provision for employees hired before January 1, 2001, allowing them to continue benefit accruals under the then benefit formula for a full 10 years alongside of the new cash balance benefit formula then being implemented. Employees who were hired on or after January 1, 2001 accrued benefits only under the new cash balance benefit formula. The plaintiffs assert a number of claims on behalf of themselves and the purported class, including that: (a) the Plan violates the requirements under the Employee Retirement Income Security Act (ERISA) intended to preclude back-loading the accrual of benefits to the end of a participant’s career, (b) the Plan violates the age discrimination prohibitions of ERISA and the Age Discrimination in Employment Act and (c) AEP failed to provide required notice regarding the changes to the Plan. Among other relief, the Complaint seeks reformation of the Plan to provide additional benefits and the recovery of plan benefits for former employees under such reformed plan. The plaintiffs previously had submitted claims for additional plan benefits to AEP, which were denied. On February 15, 2022, AEPSC and the Plan filed a motion to dismiss the complaint for failure to state a claim. On August 16, 2022, the district court granted the motion to dismiss the complaint without prejudice. The plaintiffs filed a motion for leave to file an amended complaint, which the Court denied on December 1, 2022. The plaintiffs did not file an appeal by the deadline of January 3, 2023.

7. BENEFIT PLANS

For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Fair Value Measurements of Assets and Liabilities” and “Investments Held in Trust for Future Liabilities” sections of Note 1.

KPCo participates in an AEP sponsored qualified pension plan and two unfunded non-qualified pension plans. Substantially all of KPCo’s employees are covered by the qualified plan or both the qualified and non-qualified pension plans. KPCo also participates in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees.

KPCo recognizes its funded status associated with defined benefit pension and OPEB plans on its balance sheets. Disclosures about the plans are required by the “Compensation - Retirement Benefits” accounting guidance. KPCo recognizes an asset for a plan’s overfunded status or a liability for a plan’s underfunded status and recognizes, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. KPCo records a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for rate-making purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.

Actuarial Assumptions for Benefit Obligations

The weighted-average assumptions used in the measurement of benefit obligations are shown in the following table:


	Pension Plans						OPEB
	December 31,
Assumptions	2022			2021			2022		2021
Discount Rate	5.50	%		2.90	%		5.50	%	2.90	%
Interest Crediting Rate	4.25	%		4.00	%		NA		NA
Rate of Compensation Increase	5.10	%	(a)	4.90	%	(a)	NA		NA

(a)Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.

NA Not applicable.

A duration-based method is used to determine the discount rate for the plans. A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.

For 2022, the rate of compensation increase assumed varies with the age of the employee, ranging from 3% per year to 11.5% per year, with an average increase of 5.1%.

Actuarial Assumptions for Net Periodic Benefit Costs

The weighted-average assumptions used in the measurement of benefit costs are shown in the following table:


	Pension Plans						OPEB
	Year Ended December 31,
Assumptions	2022			2021			2022		2021
Discount Rate	2.90	%		2.50	%		2.90	%	2.55	%
Interest Crediting Rate	4.00	%		4.00	%		NA		NA
Expected Return on Plan Assets	5.25	%		4.75	%		5.50	%	4.75	%
Rate of Compensation Increase	4.90	%	(a)	4.90	%	(a)	NA		NA

(a)Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.

NA Not applicable.

The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation, third-party forecasts and current prospects for economic growth.

The health care trend rate assumptions used for OPEB plans measurement purposes are shown below:


	December 31,
Health Care Trend Rates	2022		2021
Initial	7.50	%	6.25	%
Ultimate	4.50	%	4.50	%
Year Ultimate Reached	2029		2029

Significant Concentrations of Risk within Plan Assets

In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets. The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits. The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment. The plans are monitored to control security diversification and ensure compliance with the investment policy. As of December 31, 2022, the assets were invested in compliance with all investment limits. See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details.

Benefit Plan Obligations, Plan Assets and Funded Status

For the year ended December 31, 2022, the pension plans had an actuarial gain primarily due to an increase in the discount rate and was partially offset by increases in the assumed lump sum conversion rate and cash balance account interest crediting rate. For the year ended December 31, 2022, the OPEB plans had an actuarial gain primarily due to an increase in the discount rate and updated per capita cost assumptions. The OPEB plans gains were partially offset by a projected reduction in the Employer Group Waiver Program catastrophic reinsurance offset provided to AEP, resulting from the Inflation Reduction Act as well as an increase in the health care cost trend assumption. For the year ended December 31, 2021, the pension plans had an actuarial gain primarily due to an increase in the discount rate, partially offset by less favorable demographic experience than expected, resulting from the updated census information as of January 1, 2021. For the year ended December 31, 2021, the OPEB plans had an actuarial gain primarily due to an increase in the discount rate and an update of the projected reimbursements from the Employer Group Waiver Program under Medicare Part D. The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets, funded status and the presentation on the balance sheets. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively.


	Pension Plans				OPEB
	2022		2021		2022		2021
Change in Benefit Obligation	(in thousands)
Benefit Obligation as of January 1,	$	184,199	$	198,433	$	36,932	$	45,058
Service Cost	2,739		3,477		172		283
Interest Cost	4,480		4,840		953		1,096
Actuarial Gain	(36,034)		(9,831)		(3,106)		(5,851)
Plan Amendments	—		—		—		(216)
Transfers	(57,450)		—		(7,548)		—
Benefit Payments	(11,079)		(12,720)		(5,520)		(5,156)
Participant Contributions	—		—		1,713		1,708
Medicare Subsidy	—		—		9		10
Benefit Obligation as of December 31,	$	86,855	$	184,199	$	23,605	$	36,932

Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1,	$	203,932	$	208,552	$	77,433	$	75,920
Actual Gain (Loss) on Plan Assets	(31,289)		8,095		(13,714)		4,960
Transfers	(78,502)		—		—		—
Company Contributions	—		5		(15,776)		1
Participant Contributions	—		—		1,713		1,708
Benefit Payments	(11,079)		(12,720)		(5,520)		(5,156)
Fair Value of Plan Assets as of December 31,	$	83,062	$	203,932	$	44,136	$	77,433

Funded (Underfunded) Status as of December 31,	$	(3,793)	$	19,733	$	20,531	$	40,501

Amounts Recognized on the Balance Sheets


	Pension Plans				OPEB
	December 31,
	2022		2021		2022		2021
	(in thousands)
Employee Benefits and Pension Assets – Prepaid Benefit Costs	$	—	$	19,832	$	20,531	$	40,501
Other Current Liabilities – Accrued Short-term Benefit Liability	(4)		(3)		—		—
Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability	(3,789)		(96)		—		—
Funded (Underfunded) Status	$	(3,793)	$	19,733	$	20,531	$	40,501

Amounts Included in Regulatory Assets, Deferred Income Taxes and AOCI

The following tables show the components of the plans included in Other Regulatory Assets, Accumulated Deferred Income Taxes and AOCI:


	Pension Plans				OPEB
	December 31,
	2022		2021		2022		2021
Components	(in thousands)
Net Actuarial (Gain) Loss	$	16,985	$	22,630	$	9,355	$	(6,622)
Prior Service Credit	—		—		(2,637)		(5,987)

Recorded as
Regulatory Assets	$	16,986	$	21,923	$	6,718	$	(9,687)
Deferred Income Taxes	(1)		148		—		(614)
Net of Tax AOCI	—		559		—		(2,308)


	Pension Plans				OPEB
	2022		2021		2022		2021
Components	(in thousands)
Actuarial (Gain) Loss During the Year	$	3,370	$	(9,345)	$	14,492	$	(7,332)
Amortization of Actuarial Loss	(1,867)		(3,523)		—		—
Prior Service Credit	—		—		—		(216)
Amortization of Prior Service Credit	—		—		2,375		2,499
Transfers - Prior Service Cost	—		—		975		—
Transfers - (Gain)/loss	(7,148)		—		1,485		—
Change for the Year Ended December 31,	$	(5,645)	$	(12,868)	$	19,327	$	(5,049)

Determination of Pension Expense

The determination of pension expense or income is based on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return.

Pension and OPEB Assets

The fair value tables within Pension and OPEB Assets present the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to KPCo using the percentages below:


Pension Plan				OPEB
December 31,
2022		2021		2022		2021
2.0	%	3.8	%	2.8	%	3.8	%

The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2022:


Asset Class	Level 1		Level 2		Level 3		Other		Total		Year End Allocation
	(in millions)
Equities (a):
Domestic	$	347.6	$	—	$	—	$	—	$	347.6	8.4	%
International	398.4		—		—		—		398.4		9.7	%
Common Collective Trusts (b)	—		—		—		379.9		379.9		9.2	%
Subtotal – Equities	746.0		—		—		379.9		1,125.9		27.3	%

Fixed Income (a):
United States Government and Agency Securities	(0.6)		1,071.4		—		—		1,070.8		26.0	%
Corporate Debt	—		891.7		—		—		891.7		21.6	%
Foreign Debt	—		140.2		—		—		140.2		3.4	%
State and Local Government	—		37.0		—		—		37.0		0.9	%
Other – Asset Backed	—		0.8		—		—		0.8		—	%
Subtotal – Fixed Income	(0.6)		2,141.1		—		—		2,140.5		51.9	%

Infrastructure (b)	—		—		—		109.2		109.2		2.6	%
Real Estate (b)	—		—		—		276.9		276.9		6.7	%
Alternative Investments (b)	—		—		—		319.7		319.7		7.8	%
Cash and Cash Equivalents (b)	—		64.9		—		58.3		123.2		3.0	%
Other – Pending Transactions and Accrued Income (c)	—		—		—		29.3		29.3		0.7	%

Total	$	745.4	$	2,206.0	$	—	$	1,173.3	$	4,124.7	100.0	%

(a)Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information.

(b)Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share.

(c)Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2022:


Asset Class	Level 1		Level 2		Level 3		Other		Total		Year End Allocation
	(in millions)
Equities:
Domestic	$	414.1	$	—	$	—	$	—	$	414.1	26.7	%
International	265.0		—		—		—		265.0		17.1	%
Common Collective Trusts (a)	—		—		—		169.1		169.1		10.9	%
Subtotal – Equities	679.1		—		—		169.1		848.2		54.7	%

Fixed Income:
Common Collective Trust Debt (a)	—		—		—		120.3		120.3		7.8	%
United States Government and Agency Securities	0.1		155.8		—		—		155.9		10.1	%
Corporate Debt	—		141.5		—		—		141.5		9.1	%
Foreign Debt	—		21.0		—		—		21.0		1.4	%
State and Local Government	62.9		7.8		—		—		70.7		4.6	%
Subtotal – Fixed Income	63.0		326.1		—		120.3		509.4		33.0	%

Trust Owned Life Insurance:
International Equities	—		46.7		—		—		46.7		3.0	%
United States Bonds	—		110.3		—		—		110.3		7.1	%
Subtotal – Trust Owned Life Insurance	—		157.0		—		—		157.0		10.1	%

Cash and Cash Equivalents (a)	23.2		—		—		6.7		29.9		1.9	%
Other – Pending Transactions and Accrued Income (b)	—		—		—		4.8		4.8		0.3	%

Total	$	765.3	$	483.1	$	—	$	300.9	$	1,549.3	100.0	%

(a)Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share.

(b)Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2021:


Asset Class	Level 1		Level 2		Level 3		Other		Total		Year End Allocation
	(in millions)
Equities (a):
Domestic	$	388.9	$	—	$	—	$	—	$	388.9	7.2	%
International	465.7		—		—		—		465.7		8.7	%
Common Collective Trusts (b)	—		—		—		463.9		463.9		8.7	%
Subtotal – Equities	854.6		—		—		463.9		1,318.5		24.6	%

Fixed Income (a):
United States Government and Agency Securities	0.1		1,557.6		—		—		1,557.7		29.1	%
Corporate Debt	—		1,295.9		—		—		1,295.9		24.2	%
Foreign Debt	—		259.4		—		—		259.4		4.8	%
State and Local Government	—		57.1		—		—		57.1		1.1	%
Other – Asset Backed	—		1.3		—		—		1.3		—	%
Subtotal – Fixed Income	0.1		3,171.3		—		—		3,171.4		59.2	%

Infrastructure (b)	—		—		—		92.1		92.1		1.7	%
Real Estate (b)	—		—		—		232.6		232.6		4.4	%
Alternative Investments (b)	—		—		—		448.8		448.8		8.4	%
Cash and Cash Equivalents (b)	—		64.3		—		53.4		117.7		2.2	%
Other – Pending Transactions and Accrued Income (c)	—		—		—		(28.2)		(28.2)		(0.5)	%

Total	$	854.7	$	3,235.6	$	—	$	1,262.6	$	5,352.9	100.0	%

(a)Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information.

(b)Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share.

(c)Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2021:


Asset Class	Level 1		Level 2		Level 3		Other		Total		Year End Allocation
	(in millions)
Equities:
Domestic	$	474.0	$	—	$	—	$	—	$	474.0	23.2	%
International	296.3		—		—		—		296.3		14.5	%
Common Collective Trusts (a)	—		—		—		265.0		265.0		13.0	%
Subtotal – Equities	770.3		—		—		265.0		1,035.3		50.7	%

Fixed Income:
Common Collective Trust – Debt (a)	—		—		—		167.7		167.7		8.2	%
United States Government and Agency Securities	—		222.4		—		—		222.4		10.9	%
Corporate Debt	—		233.2		—		—		233.2		11.4	%
Foreign Debt	—		39.8		—		—		39.8		2.0	%
State and Local Government	91.9		13.6		—		—		105.5		5.1	%
Subtotal – Fixed Income	91.9		509.0		—		167.7		768.6		37.6	%

Trust Owned Life Insurance:
International Equities	—		23.4		—		—		23.4		1.1	%
United States Bonds	—		171.3		—		—		171.3		8.4	%
Subtotal – Trust Owned Life Insurance	—		194.7		—		—		194.7		9.5	%

Cash and Cash Equivalents (a)	33.0		—		—		6.7		39.7		1.9	%
Other – Pending Transactions and Accrued Income (b)	—		—		—		6.0		6.0		0.3	%

Total	$	895.2	$	703.7	$	—	$	445.4	$	2,044.3	100.0	%

(a)Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share.

(b)Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

Accumulated Benefit Obligation

The accumulated benefit obligation for the pension plans is as follows:


	December 31,
	2022		2021
	(in thousands)
Qualified Pension Plan	$	84,724	$	177,132
Nonqualified Pension Plan	49		34
Total Accumulated Benefit Obligation	$	84,773	$	177,166

Obligations in Excess of Fair Values

The tables below show the underfunded pension plans that had obligations in excess of plan assets.

Projected Benefit Obligation


	Underfunded Pension Plans
	December 31,
	2022		2021
	(in thousands)
Projected Benefit Obligation	$	86,855	$	98
Fair Value of Plan Assets	83,062		—
Underfunded Projected Benefit Obligation	$	(3,793)	$	(98)

Accumulated Benefit Obligation


	Underfunded Pension Plans
	December 31,
	2022		2021
	(in thousands)
Accumulated Benefit Obligation	$	84,773	$	34
Fair Value of Plan Assets	83,062		—
Underfunded Accumulated Benefit Obligation	$	(1,711)	$	(34)

Estimated Future Benefit Payments and Contributions

KPCo expects contributions and payments for the Pension and OPEB plans of $4 thousand and $53 thousand, respectively, during 2023. The estimated contributions to the pension trust are at least the minimum amount required by the Employee Retirement Income Security Act and additional discretionary contributions may also be made to maintain the funded status of the plan.

The table below reflects the total benefits expected to be paid from the plan or from KPCo’s assets. The payments include the participants’ contributions to the plan for their share of the cost. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results. The estimated payments for pension benefits and OPEB are as follows:


	Estimated Payments
	Pension Plans		OPEB
	(in thousands)
2023	$	7,342	$	3,690
2024	7,781		3,534
2025	7,766		3,708
2026	7,554		3,692
2027	7,874		3,586
Years 2028 to 2032, in Total	36,110		16,525

Components of Net Periodic Benefit Cost

The following table provides the components of net periodic benefit cost (credit):


	Pension Plans				OPEB
	Years Ended December 31,
	2022		2021		2022		2021
	(in thousands)
Service Cost	$	2,739	$	3,477	$	172	$	283
Interest Cost	4,480		4,840		953		1,096
Expected Return on Plan Assets	(8,116)		(8,583)		(3,885)		(3,479)
Amortization of Prior Service Credit	—		—		(2,375)		(2,499)
Amortization of Net Actuarial Loss	1,867		3,523		—		—
Net Periodic Benefit Cost (Credit)	970		3,257		(5,135)		(4,599)
Capitalized Portion	(1,287)		(1,582)		(81)		(129)
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	(317)	$	1,675	$	(5,216)	$	(4,728)

American Electric Power System Retirement Savings Plan

KPCo participates in an AEP sponsored defined contribution retirement savings plan, the American Electric Power System Retirement Savings Plan, for substantially all employees. This qualified plan offers participants an opportunity to contribute a portion of their pay, includes features under Section 401(k) of the Internal Revenue Code and provides for matching contributions. The matching contributions to the plan are 100% of the first 1% of eligible employee contributions and 70% of the next 5% of contributions. The cost for matching contributions totaled $2.0 million in 2022 and $2.3 million in 2021.

8. DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

AEPSC is agent for and transacts on behalf of KPCo.

KPCo is exposed to certain market risks as a major power producer and participant in the electricity, natural gas, coal and emission allowance markets. These risks include commodity price risk, interest rate risk and credit risk. These risks represent the risk of loss that may impact KPCo due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks.

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Risk Management Strategies

The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, KPCo primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

KPCo utilizes power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. KPCo utilizes interest rate derivative contracts in order to manage the interest rate exposure associated with its commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. KPCo may also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with the established risk management policies as approved by the Finance Committee of the Board of Directors.

The following table represents the gross notional volume of KPCo’s outstanding derivative contracts:

December 31,

Unit of

Primary Risk Exposure

2022

2021

Measure

(in thousands)

Commodity:

Power

3,450

6,927

MWhs

Heating Oil and Gasoline

—

305

Gallons

Cash Flow Hedging Strategies

KPCo utilizes cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. KPCo does not hedge all commodity price risk.

KPCo may utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. KPCo may also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. KPCo does not hedge all interest rate exposure.

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON KPCo’s FINANCIAL STATEMENTS

The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes and assumptions. In order to determine the relevant fair values of the derivative instruments, KPCo applies valuation adjustments for discounting, liquidity and credit quality.

Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts.

According to the accounting guidance for “Derivatives and Hedging,” KPCo reflects the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, KPCo is required to post or receive cash collateral based on third-party contractual agreements and risk profiles. The amount of cash collateral from third-parties netted against short-term and long-term risk management assets and the amount of cash collateral paid to third-parties netted against short-term and long-term risk management liabilities were immaterial for KPCo as of December 31, 2022 and 2021.

The following tables represent the gross fair value of KPCo’s derivative activity on the balance sheets:


	December 31, 2022
	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts –		in the Statement of		Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)		Financial Position (c)
	(in thousands)
Derivative Instrument Assets	$	8,744	$	(281)	$	8,463
Long-term Portion of Derivative Instrument Assets	137		(137)		—

Derivative Instrument Liabilities	281		(281)		—
Long-term Portion of Derivative Instrument Liabilities	137		(137)		—


	December 31, 2021
	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts –		in the Statement of		Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)		Financial Position (c)
	(in thousands)
Derivative Instrument Assets	$	7,534	$	(1,548)	$	5,986
Long-term Portion of Derivative Instrument Assets	46		(46)		—

Derivative Instrument Liabilities	1,504		(1,453)		51
Long-term Portion of Derivative Instrument Liabilities	46		(46)		—

(a) Derivative instruments within this category are disclosed as gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”

(b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”

(c) All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position.

The table below presents KPCo’s activity of derivative risk management contracts:

Amount of Gain (Loss) Recognized on

Risk Management Contracts


	Years Ended December 31,
Location of Gain (Loss)	2022		2021
	(in thousands)
Operating Revenues	$	8	$	(12)
Operation Expenses	376		208
Maintenance Expenses	263		116
Other Regulatory Assets (a)	(25)		(1,077)
Other Regulatory Liabilities (a)	16,998		11,192
Total Gain on Risk Management Contracts	$	17,620	$	10,427

(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment.

Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis.

The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge.

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on KPCo’s statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on KPCo’s statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same line item on the statements of income as that of the associated risk being hedged. However, unrealized and some realized gains and losses for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains), in accordance with the accounting guidance for “Regulated Operations.”

Accounting for Cash Flow Hedging Strategies

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), KPCo initially reports the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income on the balance sheets until the period the hedged item affects Net Income.

Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Operating Revenues or Operation Expenses on KPCo’s statements of income, or in Other Regulatory Assets or Other Regulatory Liabilities on KPCo’s balance sheets, depending on the specific nature of the risk being hedged. During the years ended 2022 and 2021, KPCo did not apply cash flow hedging to outstanding power derivatives.

KPCo reclassifies gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income on its balance sheets into Interest on Long-Term Debt on its statements of income in those periods in which hedged interest payments occur. During the years ended 2022 and 2021, KPCo did not apply cash flow hedging to outstanding interest rate derivatives.

There was no impact of cash flow hedges included in Accumulated Other Comprehensive Income on KPCo’s balance sheets as of December 31, 2022 and 2021.

The actual amounts that KPCo reclassifies from Accumulated Other Comprehensive Income to Net Income can differ due to market price changes. As of December 31, 2022, KPCo is not hedging (with contracts subject to the

accounting guidance for “Derivatives and Hedging”) its exposure to variability in future cash flows related to forecasted transactions.

Credit Risk

Management mitigates credit risk in KPCo’s wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit, surety bonds and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including failure or inability to post collateral when required.

Collateral Triggering Events

Credit Downgrade Triggers

A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. KPCo has not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. As of December 31, 2022 and 2021, KPCo did not have derivative contracts with collateral triggering events in a net liability position.

Cross-Acceleration Triggers

Certain interest rate derivative contracts contain cross-acceleration provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-acceleration provisions could be triggered if there was a non-performance event by KPCo under any of their outstanding debt of at least $50 million and the lender on that debt has accelerated the entire repayment obligation. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-acceleration provisions in contracts. KPCo had no derivative contracts with cross-acceleration provisions in a net liability position as of December 31, 2022 and 2021, respectively. There was no cash collateral posted as of December 31, 2022 and 2021. If a cross-acceleration provision would have been triggered, settlement at fair value would have been required. KPCo had no derivative contracts with cross-acceleration provisions outstanding as of December 31, 2022 and 2021.

Cross-Default Triggers

In addition, a majority of KPCo’s non-exchange-traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third-party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. KPCo’s derivative contracts with cross-default provisions outstanding as of December 31, 2022 and 2021 were not material. There was no cash collateral posted as of December 31, 2022 and 2021, respectively. If a cross-default provision would have been triggered, settlement at fair value would have been required.

9. FAIR VALUE MEASUREMENTS

Fair Value Measurements of Long-term Debt

The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.

The book values and fair values of KPCo’s Long-term Debt are summarized in the following table:


	December 31,
	2022				2021
	Book Value		Fair Value		Book Value		Fair Value
	(in thousands)
Long-term Debt	$	1,180,000	$	1,148,769	$	1,105,000	$	1,224,664

Fair Value Measurements of Financial Assets and Liabilities

For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1.

The following tables set forth, by level within the fair value hierarchy, KPCo’s financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.


Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2022

	Level 1		Level 2		Level 3		Other		Total
Assets:	(in thousands)

Derivative Instrument Assets
Risk Management Commodity Contracts (a) (b)	$	—	$	137	$	8,607	$	(281)	$	8,463

Liabilities:

Derivative Instrument Liabilities
Risk Management Commodity Contracts (a) (b)	$	—	$	137	$	144	$	(281)	$	—


Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2021

	Level 1		Level 2		Level 3		Other		Total
Assets:	(in thousands)

Derivative Instrument Assets
Risk Management Commodity Contracts (a) (b)	$	—	$	1,096	$	6,439	$	(1,549)	$	5,986

Liabilities:

Derivative Instrument Liabilities
Risk Management Commodity Contracts (a) (b)	$	—	$	937	$	568	$	(1,454)	$	51

(a)Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.”

(b)Substantially comprised of power contracts.

The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:


	Net Risk Management
Year Ended December 31, 2022	Assets (Liabilities)
	(in thousands)
Balance as of December 31, 2021	$	5,871
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)	2,801
Settlements	(8,672)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)	8,463
Balance as of December 31, 2022	$	8,463


	Net Risk Management
Year Ended December 31, 2021	Assets (Liabilities)
	(in thousands)
Balance as of December 31, 2020	$	3,025
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)	1,858
Settlements	(4,950)
Transfers out of Level 3 (c)	8
Changes in Fair Value Allocated to Regulated Jurisdictions (d)	5,930
Balance as of December 31, 2021	$	5,871

(a)Included in revenues on KPCo’s statements of income.

(b)Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.

(c)Transfers are recognized based on their value at the beginning if the period that the transfer occurred.

(d)Relates to the net gains (losses) of those contracts that are not reflected on KPCo’s statements of income. These changes in fair value are recorded as regulatory liabilities for net gains and as regulatory assets for net losses.

The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of December 31, 2022 and 2021:

Significant Unobservable Inputs

December 31, 2022

Significant

Input/Range

Fair Value

Valuation

Unobservable

Weighted

Assets

Liabilities

Technique

Input (a)

Low

High

Average (b)

(in thousands)

FTRs

$

8,607

$

144

Discounted Cash Flow

Forward Market Price

$

(3.10)

$

18.79

$

2.48


Significant Unobservable Inputs
December 31, 2021

						Significant	Input/Range
	Fair Value				Valuation	Unobservable					Weighted
	Assets		Liabilities		Technique	Input (a)	Low		High		Average (b)
	(in thousands)
Energy Contracts	$	—	$	51	Discounted Cash Flow	Forward Market Price	$	32.20	$	56.54	$	44.77
FTRs	6,439		517		Discounted Cash Flow	Forward Market Price	(1.44)		22.19		1.74
Total	$	6,439	$	568

(a) Represents market prices in dollars per MWh.

(b) The weighted-average is the product of the forward market price of the underlying commodity and volume weighted by term.

The following table provides the measurement uncertainty of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs as of December 31, 2022 and 2021:

Uncertainty of Fair Value Measurements

Impact on Fair Value

Significant Unobservable Input

Position

Change in Input

Measurement

Forward Market Price

Buy

Increase (Decrease)

Higher (Lower)

Forward Market Price

Sell

Increase (Decrease)

Lower (Higher)

10. INCOME TAXES

Income Tax Benefit

The details of KPCo’s Income Tax Benefit are as follows:


	Years Ended December 31,
	2022			2021
	(in thousands)
Charged (Credited) to Operating Expenses, Net:
Current	$	2,349		$	(1,302)
Deferred			(31,371)			(23,931)
Total			(29,022)			(25,233)

Charged (Credited) to Non-Operating Income, Net:
Current			(1,583)			(1,668)
Deferred			(423)			(578)
Total			(2,006)			(2,246)

Income Tax Benefit	$	(31,028)		$	(27,479)

The following is a reconciliation between the federal income taxes computed by multiplying pretax income by the federal statutory tax rate and the income taxes reported:


	Years Ended December 31,
	2022				2021
	(in thousands)
Net Income	$	47,552			$	50,150
Income Tax Benefit			(31,028)				(27,479)
Pretax Income	$	16,524			$	22,671

Income Taxes on Pretax Income at Statutory Rate (21%)	$	3,470			$	4,761
Increase (Decrease) in Income Taxes Resulting from the Following Items:
Depreciation			1,475				1,891
Removal Costs			(2,660)				(2,154)
State and Local Income Taxes, Net			(594)				(2,871)
Tax Reform Excess ADIT Reversal			(32,452)				(31,174)
Federal Return to Provision Adjustment			(38)				(952)
Tax Adjustments (a)			—				3,098
AFUDC			(242)				—
Other			13				(78)
Income Tax Benefit	$	(31,028)			$	(27,479)

Effective Income Tax Rate			(187.8)	%			(121.2)	%

(a)Represents the correction of an out of period adjustment related to Deferred Income Taxes and Income Tax Benefit. Management concluded the misstatement and subsequent correction was not material to prior or current period financial statement.

Net Deferred Tax Liability

The following table shows elements of KPCo’s net deferred tax liability and significant temporary differences:


	December 31,
	2022			2021
	(in thousands)
Deferred Tax Assets	$	86,163		$	94,062
Deferred Tax Liabilities			(542,380)			(531,214)
Net Deferred Tax Liabilities	$	(456,217)		$	(437,152)

Property Related Temporary Differences	$	(304,463)		$	(310,721)
Amounts Due to Customers for Future Income Taxes			39,613			51,754
Deferred State Income Taxes			(96,837)			(92,617)
Net Operating Loss Carryforward			11,671			17,475
Regulatory Assets			(109,919)			(101,155)
All Other, Net			3,718			(1,888)
Net Deferred Tax Liabilities	$	(456,217)		$	(437,152)

Federal and State Income Tax Audit Status

The statute of limitations for the IRS to examine KPCo and other AEP subsidiaries originally filed federal return has expired for tax years 2016 and earlier. KPCo has agreed to extend the statute of limitations on the 2017 and 2018 tax returns to December 31, 2023, to allow time for the current IRS audit to be completed including a refund claim approval by the Congressional Joint Committee on Taxation. The statute of limitations for the 2019 return is set to naturally expire in 2023 as well.

The current IRS audit and associated refund claim evolved from a net operating loss carryback to 2015 that originated in the 2017 return. KPCo and other AEP subsidiaries have received and agreed to two IRS proposed adjustments on the 2017 tax return, which were immaterial. The exam is nearly complete, and KPCo and other AEP subsidiaries are currently working with the IRS to submit the refund claim to the Congressional Joint Committee on Taxation for resolution and final approval.

KPCo and other AEP subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns, and KPCo and other AEP subsidiaries are currently under examination in several state and local jurisdictions. Generally, the statutes of limitations have expired for tax years prior to 2017. In addition, management is monitoring and continues to evaluate the potential impact of federal legislation and corresponding state conformity.

State Tax Legislation

In April 2021, West Virginia enacted House Bill (HB) 2026. HB 2026 changes the state income tax apportionment formula from a ratio that includes property, payroll and sales to a single sales factor apportionment regime effective for tax years beginning on or after January 1, 2022. HB 2026 also eliminates the “throw out” rule related to sales of tangible personal property for sales factor apportionment calculation purposes and introduces a market-based sourcing for sales of services and intangible property.

11. LEASES

KPCo leases property, plant and equipment including, but not limited to, fleet, information technology and real estate leases. These leases require payments of non-lease components, including related property taxes, operating and maintenance costs. KPCo does not separate non-lease components from associated lease components. Many of these leases have purchase or renewal options. Leases not renewed are often replaced by other leases. Options to renew or purchase a lease are included in the measurement of lease assets and liabilities if it is reasonably certain that KPCo will exercise the option.

Lease obligations are measured using the discount rate implicit in the lease when that rate is readily determinable. KPCo has visibility into the rate implicit in the lease when assets are leased from selected financial institutions under master leasing agreements. When the implicit rate is not readily determinable, KPCo measures its lease obligation using its estimated secured incremental borrowing rate. Incremental borrowing rates are comprised of an underlying risk-free rate and a secured credit spread relative to the lessee on a matched maturity basis.

Operating and Finance lease rental costs are generally charged to Operation Expenses and Maintenance Expenses in accordance with rate-making treatment for regulated operations. Lease costs associated with capital projects are included in Utility Plant on the balance sheets. For regulated operations with finance leases, a finance lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Finance leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs were as follows:


	Years Ended December 31,
Lease Rental Costs	2022		2021
	(in thousands)
Operating Lease Cost	$	14,058	$	3,100
Finance Lease Cost:
Amortization of Finance Leases	2,735		920
Interest on Finance Leases	63		125
Total Lease Rental Costs (a)	$	16,856	$	4,145

(a)Excludes variable and short-term lease costs, which were immaterial.

Supplemental information related to leases are shown in the tables below.


Lease Type	Weighted-Average Remaining Lease Term (years):		Weighted-Average Discount Rate
	December 31,
	2022	2021	2022		2021

Operating Leases	5.92	6.05	2.95	%	3.33	%
Finance Leases	4.73	4.68	4.41	%	4.00	%


	Years Ended December 31,
	2022		2021
	(in thousands)
Cash Paid for Amounts Included in the Measurement of Lease Liabilities
Operating Cash Flows Used for Operating Leases	$	14,050	$	3,089
Operating Cash Flows Used for Finance Leases	63		125
Financing Cash Flows Used for Finance Leases	2,735		920

Non-cash Acquisitions Under Operating Leases	$	422	$	1,261

The following tables show the property, plant and equipment under finance leases and noncurrent assets under operating leases and related obligations recorded on KPCo’s balance sheets. Unless shown as a separate line on the balance sheets due to materiality, net operating lease assets are included in Deferred Charges and Other Noncurrent Assets, current finance lease obligations are included in Other Current Liabilities and long-term finance lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets. Lease obligations are not recognized on the balance sheets for lease agreements with a lease term of less than twelve months.


	December 31,
	2022		2021
	(in thousands)
Property, Plant and Equipment Under Finance Leases
Utility Plant (a)	$	369	$	2,855

Obligations Under Finance Leases
Noncurrent	288		2,064
Current	81		791
Total Obligations Under Finance Leases	$	369	$	2,855

(a) Includes $305 thousand and $2.6 million of accumulated provision for depreciation and amortization for the years ended December 31, 2022 and 2021, respectively.


	December 31,
	2022		2021
	(in thousands)
Property, Plant and Equipment Under Operating Leases
Utility Plant (a)	$	535	$	10,755

Obligations Under Operating Leases
Noncurrent	450		8,614
Current	128		2,173
Total Obligations Under Operating Leases	$	578	$	10,787

(a) Includes $146 thousand and $4.5 million of accumulated provision for depreciation and amortization for the years ended December 31, 2022 and 2021, respectively.

Future minimum lease payments consisted of the following as of December 31, 2022:


Future Minimum Lease Payments	Finance Leases		Operating Leases
	(in thousands)
2023	$	95	$	154
2024	88		136
2025	85		81
2026	71		64
2027	54		46
After 2027	18		198
Total Future Minimum Lease Payments	411		679
Less: Imputed Interest	42		101
Estimated Present Value of Future Minimum Lease Payments	$	369	$	578

Lessor Activity

KPCo’s lessor activity was immaterial as of and for the twelve months ended December 31, 2022 and December 31, 2021, respectively.

12. FINANCING ACTIVITIES

Long-term Debt

The following table details long-term debt outstanding:


		Weighted-Average	Interest Rate Ranges as of		Outstanding as of
		Interest Rate as of	December 31,		December 31,
Type of Debt	Maturity	December 31, 2022	2022	2021	2022		2021
					(in thousands)
Senior Unsecured Notes	2024-2047	4.54%	3.13%-8.13%	3.13%-8.13%	$	690,000	$	690,000
Pollution Control Bonds	2023 (a)	2.35%	2.35%	2.35%	65,000		65,000
Other Long-term Debt	2022-2023	5.26%	5.03%-5.55%	0.76%-1.61%	425,000		350,000
Total Long-term Debt					$	1,180,000	$	1,105,000

(a) KPCo’s Pollution Control Bond is subject to redemption earlier than the maturity date.

As of December 31, 2022, outstanding long-term debt was payable as follows:


											After
	2023		2024		2025		2026		2027		2027		Total
	(in thousands)
Principal Amount	$	490,000	$	65,000	$	—	$	200,000	$	40,000	$	385,000	$	1,180,000
Total Long-term Debt Outstanding													$	1,180,000

Dividend Restrictions

KPCo pays dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of KPCo to transfer funds to Parent in the form of dividends.

All of the dividends declared by KPCo are subject to a Federal Power Act requirement that prohibits the payment of dividends out of capital accounts in certain circumstances; payment of dividends is generally allowed out of retained earnings.

KPCo has credit agreements that contain a covenant that limit its debt to capitalization ratio to 67.5%. As of December 31, 2022, KPCo did not exceed its debt to capitalization limit. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements.

The most restrictive dividend limitation for KPCo is through the Federal Power Act. As of December 31, 2022, the maximum amount of restricted net assets of KPCo that may not be distributed to Parent in the form of a loan, advance or dividend was $613.2 million.

The Federal Power Act restriction does not limit the ability of KPCo to pay dividends out of retained earnings. The credit agreement covenant restrictions can limit the ability of KPCo to pay dividends out of retained earnings. As of December 31, 2022, the amount of any such restrictions was $36.5 million.

Corporate Borrowing Program – AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding borrowings from the Utility Money Pool as of December 31, 2022 and 2021 are included in Notes Payable to Associated Companies on KPCo’s balance sheets. KPCo’s Utility Money Pool activity and corresponding authorized borrowing limits are described in the following table:


	Maximum		Maximum		Average		Average		Borrowings		Authorized
	Borrowings		Loans		Borrowings		Loans		from the Utility		Short-Term
Years Ended	from the Utility		to the Utility		from the Utility		to the Utility		Money Pool as of		Borrowing
December 31,	Money Pool		Money Pool		Money Pool		Money Pool		December 31,		Limit
	(in thousands)
2022	$	161,643	$	28,393	$	82,006	$	23,343	$	94,428	$	180,000
2021	121,608		43,730		46,522		22,427		47,895		180,000

Maximum, minimum and average interest rates for funds either borrowed from or loaned to the Utility Money Pool are summarized in the following table:


	Maximum		Minimum		Maximum		Minimum		Average		Average
	Interest Rate		Interest Rate		Interest Rate		Interest Rate		Interest Rate		Interest Rate
	for Funds		for Funds		for Funds		for Funds		for Funds		for Funds
	Borrowed		Borrowed		Loaned		Loaned		Borrowed		Loaned
Years Ended	from the Utility		from the Utility		to the Utility		to the Utility		from the Utility		to the Utility
December 31,	Money Pool		Money Pool		Money Pool		Money Pool		Money Pool		Money Pool
2022	5.28	%	0.10	%	2.15	%	2.15	%	2.23	%	2.15	%
2021	0.48	%	0.02	%	0.34	%	0.03	%	0.31	%	0.33	%

Interest expense and interest income related to the Utility Money Pool are included in Interest on Debt to Associated Companies and Interest and Dividend Income, respectively, on KPCo’s statements of income. For amounts borrowed from and advances to the Utility Money Pool, KPCo incurred the following amounts of interest expense and earned the following amounts of interest income:


	Years Ended December 31,
	2022		2021
	(in thousands)
Interest Expense	$	1,985	$	166
Interest Income	102				6

Securitized Accounts Receivables – AEP Credit

Under an affiliated receivables sales arrangement, KPCo sold, without recourse, certain of its customer accounts receivable and accrued utility revenue balances to AEP Credit. KPCo was charged a fee for each sale that is based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience from previous purchases of KPCo’s customer accounts receivable. The costs of customer accounts receivable sold are reported in Other Deductions on KPCo’s statements of income. In January 2022, due to the pending sale to Liberty, KPCo

ceased selling accounts receivable to AEP Credit. As a result, in the first quarter of 2022, KPCo began recording an allowance for uncollectible accounts on its balance sheet for those receivables no longer sold to AEP Credit.

KPCo’s amounts of accounts receivable and accrued unbilled revenues under the sale of receivables agreement were $0 and $53.3 million as of December 31, 2022 and 2021, respectively.

The fees paid by KPCo to AEP Credit for customer accounts receivable sold were $63 thousand and $1.9 million for the years ended December 31, 2022 and 2021, respectively. In 2021, due to the successful collection of accounts receivable balances during the COVID-19 pandemic, the allowance for doubtful accounts was reduced, resulting in the issuance of credits to offset the higher fees previously paid and to lower subsequent fees paid. In 2022, as a result of KPCo’s discontinued sale of receivables with AEP Credit, KPCo was issued a net credit upon final settlement of the allowance for doubtful accounts balance as collections of accounts receivable were higher than originally estimated.

KPCo’s proceeds on the sale of receivables to AEP Credit were $66 million and $595 million for the years ended December 31, 2022 and 2021, respectively.

13. RELATED PARTY TRANSACTIONS

For other related party transactions, also see “AEP System Tax Allocation” section of Note 1 in addition to “Corporate Borrowing Program – AEP System” and “Securitized Accounts Receivables – AEP Credit” sections of Note 12.

Power Coordination Agreement

Effective January 1, 2014, the FERC approved the PCA. Under the PCA, APCo, I&M, KPCo and WPCo are individually responsible for planning their respective capacity obligations. The PCA allows, but does not obligate, APCo, I&M, KPCo and WPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities.

AEPSC conducts power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on behalf of APCo, I&M, KPCo, PSO, SWEPCo and WPCo. Certain power and natural gas risk management activities for APCo, I&M, KPCo and WPCo are allocated based on the four member companies’ respective equity positions.

System Integration Agreement

Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and natural gas risk management activities based upon the location of such activity. Margins resulting from trading and marketing activities originating in PJM generally accrue to the benefit of APCo, I&M, KPCo and WPCo. Margins resulting from other transactions are allocated among APCo, I&M, KPCo, PSO, SWEPCo and WPCo based upon the equity positions of these companies.

Affiliated Revenues and Purchases

The table below shows the revenues derived from auction sales to affiliates, net transmission agreement sales and other revenues as follows:


	Years Ended December 31,
Related Party Revenues	2022		2021
	(in thousands)
Transmission Agreement Sales	$	17,701	$	8,991
Other Revenues	1,550		1,551
Total Affiliated Revenues	$	19,251	$	10,542

The table below shows the purchased power expenses incurred for purchases from affiliates as follows:


	Years Ended December 31,
Related Party Purchases	2022		2021
	(in thousands)
Direct Purchases from AEGCo (a)	$	93,137	$	93,365
Total Affiliated Purchases	$	93,137	$	93,365

(a)Refer to the “Unit Power Agreements” section below for further information regarding this amount.

PJM Transmission Service Charges

The AEP East Companies are parties to the TA, which defines how transmission costs through PJM OATT are allocated among the AEP East Companies on a 12-month average coincident peak basis. Additional costs for transmission services provided by AEPTCo and other transmission affiliates are billed to KPCo through the PJM OATT.

KPCo’s net charges recorded as a result of the TA for the years ended December 31, 2022 and 2021 were $64.9 million and $57.1 million, respectively, and were recorded in Operation Expenses on KPCo’s statements of income.

Unit Power Agreements

UPA between AEGCo and I&M

A UPA between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) net of amounts received by AEGCo from any other sources, sufficient to enable AEGCo to pay all of its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC. The I&M Power Agreement will continue in effect until the debt obligations of AEGCo secured by the Rockport Plant have been satisfied and discharged (currently expected to be December 2028).

In April 2021, AEGCo and I&M executed an agreement to purchase 100% of the interests in Rockport Plant, Unit 2 effective at the end of the lease term on December 7, 2022. Beginning December 8, 2022, AEGCo and I&M applied the joint plant accounting model to their respective 50% undivided interests in the jointly owned Rockport Plant, Unit 2 as well as any future investments made prior to the current estimated retirement date of December 2028.

Prior to the termination of the lease, I&M assigned 30% of the power to KPCo. See the “UPA between AEGCo and KPCo” section below for additional information. Beginning December 8, 2022, AEGCo billed 100% of its share of the Rockport Plant to I&M and ceased billing to KPCo. KPCo reached an agreement with I&M, from the end of the lease through May 2024, to buy capacity from Rockport Plant, Unit 2 through the PCA at a rate equal to PJM’s RPM clearing price.

UPA between AEGCo and KPCo

On December 7, 2022, the UPA between AEGCo and KPCo ended upon the termination of the Rockport Plant, Unit 2 lease. Previously, pursuant to an assignment between I&M and KPCo and a UPA between AEGCo and KPCo, AEGCo sold KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo paid AEGCo in consideration for the right to receive such power, the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. As a result of the end of the UPA between AEGCo and KPCo, a prorated bill was recorded from AEGCo to KPCo to reflect costs incurred for the first seven days of December 2022.

I&M Barging, Urea Transloading and Other Services

I&M provides barging, urea transloading and other transportation services to affiliates. Urea is a chemical used to control NOx emissions at certain generation plants in the AEP System. KPCo recorded expenses of $2 million and $3.1 million in 2022 and 2021, respectively, for urea transloading provided by I&M. These expenses were recorded as Operation Expenses. This agreement with KPCo terminated with the transfer of the Mitchell Plant in August 2022.

Central Machine Shop

APCo operates a facility which repairs and rebuilds specialized components for the generation plants across the AEP System. APCo defers the cost of performing these services on the balance sheet and then transfers the cost to the affiliate for reimbursement. KPCo recorded its assigned portion of these billings as capital or maintenance expenses depending on the nature of the services received. These billings are recoverable from customers. KPCo’s billed amounts were $1 million and $973 thousand for the years ended December 31, 2022 and 2021, respectively.

Sales and Purchases of Property

KPCo had affiliated sales and purchases of electric property individually amounting to $100 thousand or more, sales and purchases of meters and transformers and sales and purchases of transmission property. There were no gains or losses recorded on the transactions. The table below shows the sales and purchases, recorded at net book value, as follows:


	Years Ended December 31,
	2022		2021
	(in thousands)
Sales	$	1,187	$	431
Purchases	631		3,995

Charitable Contributions to AEP Foundation

The American Electric Power Foundation is funded by American Electric Power and its utility operating units. The Foundation provides a permanent, ongoing resource for charitable initiatives and multi-year commitments in the communities served by AEP and initiatives outside of AEP’s 11-state service area. In 2022, KPCo made a $2.8 million charitable contribution to the AEP Foundation recorded in Operation Expenses on the statements of income. In 2021, there were no charitable contributions made to the AEP Foundation.

Intercompany Billings

KPCo performs certain utility services for other AEP subsidiaries when necessary or practical. The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable basis of proration for services that benefit multiple companies. The billings for services are made at cost and include no compensation for the use of equity capital.

14. PROPERTY, PLANT AND EQUIPMENT

Depreciation

KPCo provides for depreciation of Utility Plant on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. The following table provides total regulated annual composite depreciation rates and depreciable lives for KPCo. Nonregulated depreciation rate ranges and depreciable life ranges are not applicable or not meaningful for 2022 and 2021.


Year	Steam		Transmission		Distribution		General
	(in percentages)
2022	3.0	%	2.7	%	3.4	%	8.2	%
2021	3.0	%	2.6	%	3.4	%	9.5	%

The composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to accumulated depreciation on the balance sheets. Actual removal costs incurred are charged to accumulated depreciation.

Asset Retirement Obligations (ARO)

The following is a reconciliation of the 2022 and 2021 aggregate carrying amounts of ARO for KPCo:


												Revisions in
	ARO as of			Accretion			Liabilities		Liabilities			Cash Flow			ARO as of
Year	January 1,			Expense			Incurred		Settled (a)			Estimates (a)			December 31,
	(in thousands)
2022	$	17,697		$	803		$	—	$	(1,162)		$	1,139		$	18,477
2021			24,565			968		—			(3,227)			(4,609)			17,697

(a) Primarily related to ash pond closure and asbestos abatement.

Jointly-owned Electric Facilities

KPCo, jointly with WPCo, owns Unit 1 and Unit 2 of the Mitchell Generating Station. KPCo and WPCo each have a 50% ownership of Unit 1 and Unit 2 of the Mitchell Generating Station. Using its own financing, each participating company is obligated to pay its share of the costs in the same proportion as its ownership interest. KPCo’s proportionate share of the operating costs associated with this facility is included in its statements of income and the investment and accumulated depreciation are reflected in its balance sheets under Utility Plant as follows:


	Fuel Type	Percent of Ownership		Utility Plant in Service		Construction Work in Progress		Accumulated Depreciation


				(in thousands)
KPCo’s Share as of December 31, 2022
Mitchell Generating Station, Units 1 and 2 (a)	Coal	50.0	%	$	1,052,996	$	23,231	$	518,178

KPCo’s Share as of December 31, 2021
Mitchell Generating Station, Units 1 and 2 (a)	Coal	50.0	%	$	1,049,434	$	12,040	$	493,124

(a)In September 2022, pursuant to resolutions under the existing Mitchell Plant agreement, WPCo replaced KPCo as the operator of Mitchell Plant. See Note 1 - Organization and Summary of Significant Accounting Policies for additional information.

15. REVENUE FROM CONTRACTS WITH CUSTOMERS

Disaggregated Revenues from Contracts with Customers

The table below represents KPCo’s revenues from contracts with customers, net of respective provisions for refund, by type of revenue:


	Years Ended December 31,
	2022		2021
	(in thousands)
Retail Revenues:
Residential Revenues	$	317,814	$	282,900
Commercial Revenues	197,505		160,183
Industrial Revenues	185,174		142,217
Other Retail Revenues	2,193		2,029
Total Retail Revenues	702,686		587,329

Wholesale Revenues:
Generation Revenues	59,641		43,070
Transmission Revenues (a)	35,522		22,052
Total Wholesale Revenues	95,163		65,122

Other Revenues from Contracts with Customers (b)	10,483		8,277

Total Revenues from Contracts with Customers	808,332		660,728

Other Revenues:
Alternative Revenue Programs (c)	(6,216)		(1,180)
Other Revenues	8		—
Total Other Revenues	(6,208)		(1,180)

Total Revenues	$	802,124	$	659,548

(a)Amounts included affiliated and nonaffiliated revenues. The affiliated revenues were

$19 million and $9 million for years ended December 31, 2022 and 2021, respectively.

(b)Amounts included affiliated and nonaffiliated revenues.

(c)Alternative revenue programs in certain jurisdictions include regulatory mechanisms

that periodically adjust for over/under collection of related revenues.

Performance Obligations

KPCo has performance obligations as part of its normal course of business. A performance obligation is a promise to transfer a distinct good or service, or a series of distinct goods or services that are substantially the same and have the same pattern of transfer to a customer. The invoice practical expedient within the accounting guidance for “Revenue from Contracts with Customers” allows for the recognition of revenue from performance obligations in the amount of consideration to which there is a right to invoice the customer and when the amount for which there is a right to invoice corresponds directly to the value transferred to the customer.

The purpose of the invoice practical expedient is to depict an entity’s measure of progress toward completion of the performance obligation within a contract and can only be applied to performance obligations that are satisfied over time and when the invoice is representative of services provided to date. KPCo elected to apply the invoice

practical expedient to recognize revenue for performance obligations satisfied over time as the invoices from the respective revenue streams are representative of services or goods provided to date to the customer. Performance obligations for KPCo are summarized as follows:

Retail Revenues

KPCo has performance obligations to generate, transmit and distribute electricity for sale to rate-regulated retail customers. The performance obligation to deliver electricity is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Revenues are variable as they are subject to the customer’s usage requirements.

Rate-regulated retail customers typically have the right to discontinue receiving service at will, therefore these contracts between KPCo and their customers for rate-regulated services are generally limited to the services requested and received to date for such arrangements. Retail customers are generally billed on a monthly basis, and payment is typically due within 15 to 20 days after the issuance of the invoice.

Wholesale Revenues - Generation

KPCo has performance obligations to sell electricity to wholesale customers from generation assets in PJM. The performance obligation to deliver electricity from generation assets is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Wholesale generation revenues are variable as they are subject to the customer’s usage requirements.

KPCo also has performance obligations to stand ready in order to promote grid reliability. Stand ready services are sold into PJM’s Reliability Pricing Model (RPM) capacity market. RPM entails a base auction and at least three incremental auctions for a specific PJM delivery year, with the incremental auctions spanning three years. The performance obligation to stand ready is satisfied over time and the consideration for which is variable until the occurrence of the final incremental auction, at which point the performance obligation becomes fixed.

Payments from the RTO for stand ready services are typically received within one week from the issuance of the invoice, which is typically issued weekly. Gross margin resulting from generation sales are primarily subject to margin sharing agreements with customers, where the revenues are reflected gross in the disaggregated revenues table above.

Wholesale Revenues - Transmission

KPCo has performance obligations to transmit electricity to wholesale customers through assets owned and operated by KPCo and other AEP subsidiaries. The performance obligation to provide transmission services in PJM is partially fixed for a period of one year or less. Payments from the RTO for transmission services are typically received within one week from the issuance of the invoice, which is issued weekly for PJM.

KPCo collects revenues through transmission formula rates. The FERC-approved rates establish the annual transmission revenue requirement (ATRR) and transmission service rates for transmission owners. The formula rates establish rates for a one year period and also include a true-up calculation for the prior year’s billings, allowing for over/under-recovery of the transmission owner’s ATRR. The annual true-ups meet the definition of

alternative revenues in accordance with the accounting guidance for “Regulated Operations,” and are therefore presented as such in the disaggregated revenues table above.

The AEP East Companies are parties to the TA, which defines how transmission costs are allocated among the AEP East Companies on a 12-month average coincident peak basis. AEPTCo is a load serving entity within PJM providing transmission services to affiliates in accordance with the OATT and TA. Affiliate revenues as a result of the TA are reflected as Transmission Revenues in the disaggregated revenues table above.

Fixed Performance Obligations

The following table represents KPCo’s remaining fixed performance obligations satisfied over time as of December 31, 2022. Fixed performance obligations primarily include electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market. KPCo elected to apply the exemption to not disclose the value of unsatisfied performance obligations for contracts with an original expected term of one year or less. Due to the annual establishment of revenue requirements, transmission revenues are excluded from the table below. The amounts shown in the table below include affiliated and nonaffiliated revenues.


2023		2024-2025		2026-2027		After 2027		Total
(in thousands)
$	1,256	$	2,512	$	2,512	$	1,256	$	7,536

Contract Assets and Liabilities

Contract assets are recognized when KPCo has a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. KPCo did not have material contract assets as of December 31, 2022 and 2021, respectively.

When KPCo receives consideration, or such consideration is unconditionally due from a customer prior to transferring goods or services to the customer under the terms of a sales contract, they recognize a contract liability on the balance sheet in the amount of that consideration. Revenue for such consideration is subsequently recognized in the period or periods in which the remaining performance obligations in the contract are satisfied. KPCo’s contract liabilities typically arise from advanced payments of services provided primarily with respect to joint use agreements for utility poles. KPCo did not have material contract liabilities as of December 31, 2022 and 2021, respectively.

Accounts Receivable from Contracts with Customers

Accounts receivable from contracts with customers are presented on KPCo’s balance sheets in Customer Accounts Receivable. KPCo’s balances for receivables from contracts that are not recognized in accordance with the accounting guidance for “Revenue from Contracts with Customers” included in Customer Accounts Receivable were not material as of December 31, 2022 and 2021, respectively. See “Securitized Accounts Receivable - AEP Credit” section of Note 12 for additional information.

The amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable from Associated Companies on KPCo’s balance sheets were $9.1 million and $9.1 million, respectively, as of December 31, 2022 and December 31, 2021.

Contract Costs

Contract costs to obtain or fulfill a contract are accounted for under the guidance for “Other Assets and Deferred Costs” and presented as a single asset and neither bifurcated nor reclassified between current assets and deferred debits on KPCo’s balance sheets. Contract costs to acquire a contract are amortized in a manner consistent with the transfer of goods or services to the customer in Operation Expenses on KPCo’s statements of income. KPCo did not have material contract costs as of December 31, 2022 and 2021, respectively.

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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				878,395			878,395
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income				871,447			871,447
3	Preceding Quarter/Year to Date Changes in Fair Value
4	Total (lines 2 and 3)				871,447			871,447	50,149,813	51,021,260
5	Balance of Account 219 at End of Preceding Quarter/Year				1,749,842			1,749,842
6	Balance of Account 219 at Beginning of Current Year				1,749,842			1,749,842
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income				1,749,842			1,749,842
8	Current Quarter/Year to Date Changes in Fair Value
9	Total (lines 7 and 8)				1,749,842			1,749,842	47,552,177	45,802,335
10	Balance of Account 219 at End of Current Quarter/Year

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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)	3,122,313,718	3,122,313,718
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	903,614	903,614
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified	143,835,349.00	143,835,349.00
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	3,267,052,681	3,267,052,681
9	UtilityPlantLeasedToOthers Leased to Others
10	UtilityPlantHeldForFutureUse Held for Future Use	801,671	801,671
11	ConstructionWorkInProgress Construction Work in Progress	138,936,649	138,936,649
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	3,406,791,001	3,406,791,001
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	1,230,384,120	1,230,384,120
15	UtilityPlantNet Net Utility Plant (13 less 14)	2,176,406,881	2,176,406,881
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	1,201,250,028	1,201,250,028
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	29,134,092	29,134,092
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	1,230,384,120	1,230,384,120
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
33	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Total Accum Prov (equals 14) (22,26,30,31,32)	1,230,384,120	1,230,384,120

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	52,919					52,919
4	(303) Miscellaneous Intangible Plant	59,076,584	9,889,734	6,677,081		1,530	62,290,767
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)	59,129,503	9,889,734	6,677,081		1,530	62,343,686
6	2. PRODUCTION PLANT
7	A. Steam Production Plant
8	(310) Land and Land Rights	4,833,439					4,833,439
9	(311) Structures and Improvements	80,993,728	912,475	75,489			81,830,714
10	(312) Boiler Plant Equipment	969,566,381	7,341,770	4,168,978			972,739,173
11	(313) Engines and Engine-Driven Generators
12	(314) Turbogenerator Units	118,674,732	30,952	2,309			118,703,375
13	(315) Accessory Electric Equipment	31,687,839	978,600	157,562			32,508,877
14	(316) Misc. Power Plant Equipment	13,698,891	481,683	23,984			14,156,590
15	(317) Asset Retirement Costs for Steam Production	10,932,714	303,705				11,236,419
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)	1,230,387,724	10,049,185	4,428,322			1,236,008,587
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
38	(341) Structures and Improvements
39	(342) Fuel Holders, Products, and Accessories
40	(343) Prime Movers
41	(344) Generators
42	(345) Accessory Electric Equipment
43	(346) Misc. Power Plant Equipment
44	(347) Asset Retirement Costs for Other Production
44.1	(348) Energy Storage Equipment - Production
45	TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)
46	TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)	1,230,387,724	10,049,185	4,428,322			1,236,008,587
47	3. Transmission Plant
48	(350) Land and Land Rights	38,518,796	817,201	1,307			39,334,690
48.1	(351) Energy Storage Equipment - Transmission
49	(352) Structures and Improvements	13,478,383	1,876,966	1,778		494,646	14,858,925
50	(353) Station Equipment	254,254,673	22,093,991	1,355,823			274,992,841
51	(354) Towers and Fixtures	100,689,807	832,296	96,178			101,425,925
52	(355) Poles and Fixtures	187,594,785	10,632,818	623,594			197,604,009
53	(356) Overhead Conductors and Devices	164,915,210	3,826,022	338,306			168,402,926
54	(357) Underground Conduit	524,848	4,312,660				4,837,508
55	(358) Underground Conductors and Devices	382,339	868				381,471
56	(359) Roads and Trails
57	(359.1) Asset Retirement Costs for Transmission Plant
58	TOTAL Transmission Plant (Enter Total of lines 48 thru 57)	760,358,841	44,391,086	2,416,986		494,646	801,838,295
59	4. Distribution Plant
60	(360) Land and Land Rights	9,130,683	31,358				9,162,041
61	(361) Structures and Improvements	9,304,328	70,347				9,374,675
62	(362) Station Equipment	141,097,946	4,191,270	1,278,195			144,011,021
63	(363) Energy Storage Equipment – Distribution
64	(364) Poles, Towers, and Fixtures	264,443,940	22,225,811	2,166,659			284,503,092
65	(365) Overhead Conductors and Devices	300,863,515	11,040,426	2,063,298			309,840,643
66	(366) Underground Conduit	8,173,222	1,518,878	9,074			9,683,026
67	(367) Underground Conductors and Devices	12,380,723	410,693	37,853			12,753,563
68	(368) Line Transformers	151,393,145	8,298,545	2,080,275			157,611,415
69	(369) Services	70,671,893	3,552,702	476,972			73,747,623
70	(370) Meters	25,354,737	425,509	389,556			25,390,690
71	(371) Installations on Customer Premises	19,362,643	2,803,672	2,388,467			19,777,848
72	(372) Leased Property on Customer Premises
73	(373) Street Lighting and Signal Systems	4,673,548	406,817	136,728			4,943,637
74	(374) Asset Retirement Costs for Distribution Plant
75	TOTAL Distribution Plant (Enter Total of lines 60 thru 74)	1,016,850,323	54,976,028	11,027,077			1,060,799,274
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	1,729,399					1,729,399
87	(390) Structures and Improvements	27,759,147	232,913	118,398			27,873,662
88	(391) Office Furniture and Equipment	2,639,387	618,144			33,891	3,223,640
89	(392) Transportation Equipment	14,768	20,563,297			74,063	20,652,128
90	(393) Stores Equipment	301,190	7,268	4,331			304,127
91	(394) Tools, Shop and Garage Equipment	6,484,964	539,061	21,422		17	7,002,586
92	(395) Laboratory Equipment	227,981	6,407	23,978			210,410
93	(396) Power Operated Equipment	5,931	1,663,906			27,412	1,642,425
94	(397) Communication Equipment	25,006,278	15,073,260	151,093		14,273	39,914,172
95	(398) Miscellaneous Equipment	2,128,225	130,016	305,030		494,646	2,447,857
96	SUBTOTAL (Enter Total of lines 86 thru 95)	66,297,270	38,834,272	624,252		493,116	105,000,406
97	(399) Other Tangible Property
98	(399.1) Asset Retirement Costs for General Plant	158,819					158,819
99	TOTAL General Plant (Enter Total of lines 96, 97, and 98)	66,456,089	38,834,272	624,252		493,116	105,159,225
100	TOTAL (Accounts 101 and 106)	3,133,182,480	158,140,305	25,173,718			3,266,149,067
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)	3,133,182,480	158,140,305	25,173,718			3,266,149,067

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	Ramey Substation (4205)	10/01/2009	12/31/2023	556,145.00
3	Items under $250,000			245,526
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			801,671

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	Ashland-Lynchburg MW Upgrade	1,162,381
2	Ed-Ci-Kepco-D Ast Imp	3,407,503
3	Hazard Station Rehab	7,698,112
4	KPCo - D Work	4,007,380
5	KPCo - T BlnktProj Under $3M	2,291,575
6	KPCo D Work 1	1,074,435
7	KPCo D Work 2	4,272,287
8	KPCo T Work 1	3,592,336
9	KPCo T Work 2	18,938,898
10	KPCo T Work 3	8,220,577
11	KPCo T Work 4	1,811,683
12	KPCo T Work 5	1,901,412
13	KPCo-D Baseline Work	11,139,086
14	KY D Work	1,248,712
15	KY Next Generation Radio Sys	1,116,561
16	KY T Work	1,613,817
17	KYPCo Distr Pre Eng Parent	3,808,012
18	KYPCo Trans Pre Eng Parent	4,263,720
19	Leon-Morehead 69 kV Rehab	4,413,029
20	Leslie Station Rehab	2,969,774
21	ML PCC U0 ELG Compliance - 117	10,010,727
22	ML PCC U0 Lime Conversion 117	1,243,002
23	ML PCC U2 Cooling Twr Cmp 117	2,830,874
24	ML S U2 Air Htr Bskt Rplc Lbty	2,091,455
25	ML V U2 Cat Layer 4 Rplc Lbty	1,284,802
26	NGUCS Weddington & Leatherwood	1,007,104
27	ROW Capital Widening & Removal	6,539,181
28	T/KP/Capital Blanket - KYPCo	2,188,783
29	T/KP/Wooten-Pineville-KP Work	2,013,840
30	WS-CI-KEPCo-G PPB	5,689,730
31	Other Minor Projects Which is under 5% or $1,000,000	15,085,861
43	Total	138,936,649

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	1,134,142,286	1,134,142,286
2	Depreciation Provisions for Year, Charged to
3	DepreciationExpenseExcludingAdjustments (403) Depreciation Expense	98,662,438	98,662,438
4	DepreciationExpenseForAssetRetirementCosts (403.1) Depreciation Expense for Asset Retirement Costs	58,339	58,339
5	ExpensesOfElectricPlantLeasedToOthers (413) Exp. of Elec. Plt. Leas. to Others
6	TransportationExpensesClearing Transportation Expenses-Clearing
7	OtherClearingAccounts Other Clearing Accounts
8	OtherAccounts Other Accounts (Specify, details in footnote):
9.1	Other Accounts (Specify, details in footnote):	312,561	(a) 312,561
10	DepreciationProvision TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)	98,408,216	98,408,216
11	Net Charges for Plant Retired:
12	BookCostOfRetiredPlant Book Cost of Plant Retired	24,479,329	18,496,638	5,982,691
13	CostOfRemovalOfPlant Cost of Removal	13,033,697	(b) 12,825,447	208,250
14	SalvageValueOfRetiredPlant Salvage (Credit)	6,756,788	(c) 565,847	6,190,941
15	NetChargesForRetiredPlant TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)	30,756,238	30,756,238
16	OtherAdjustmentsToAccumulatedDepreciation Other Debit or Cr. Items (Describe, details in footnote):
17.1	Other Debit or Cr. Items (Describe, details in footnote):	544,236	(d) 544,236
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)	1,201,250,028	1,201,250,028
Section B. Balances at End of Year According to Functional Classification
20	AccumulatedDepreciationSteamProduction Steam Production	586,303,746	586,303,746
21	AccumulatedDepreciationNuclearProduction Nuclear Production
22	AccumulatedDepreciationHydraulicProductionConventional Hydraulic Production-Conventional
23	AccumulatedDepreciationHydraulicProductionPumpedStorage Hydraulic Production-Pumped Storage
24	AccumulatedDepreciationOtherProduction Other Production
25	AccumulatedDepreciationTransmission Transmission	266,086,765	266,086,765
26	AccumulatedDepreciationDistribution Distribution	324,534,110	324,534,110
27	AccumulatedDepreciationRegionalTransmissionAndMarketOperation Regional Transmission and Market Operation
28	AccumulatedDepreciationGeneral General	24,325,407	24,325,407
29	AccumulatedProvisionForDepreciationOfElectricUtilityPlant TOTAL (Enter Total of lines 20 thru 28)	1,201,250,028	1,201,250,028

FOOTNOTE DATA

(a) Concept: OtherAccounts


Big Sandy Ash Pond deferred depreciation expense(ref: Case No. 2012-00578)			$455,556
Environmental costs recovered per KPSC Order Case No. 2014-00396			$(780,572)
Asbestos ARO depreciation expense in account 1080013			$12,455
Total			$(312,561)

(b) Concept: CostOfRemovalOfPlant

Includes $463,257 of removal cost in retirement work in progress (RWIP).

(c) Concept: SalvageValueOfRetiredPlant

Includes ($841,776) of salvage in retirement work in progress (RWIP).

(d) Concept: OtherAdjustmentsToAccumulatedDepreciation


ARO Reserve in acct 1080013			$(544,102)
Adjust gain/loss for Big Sandy U0 retirement			$(134)
TOTAL			$(544,236)

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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
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	Total Cost of Account 123.1 $		Total

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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)	9,489,812	21,071,010	Electric
2	Fuel Stock Expenses Undistributed (Account 152)	599,696	922,553	Electric
3	Residuals and Extracted Products (Account 153)
4	Plant Materials and Operating Supplies (Account 154)
5	Assigned to - Construction (Estimated)	10,002,298	11,680,011	Electric
6	Assigned to - Operations and Maintenance
7	Production Plant (Estimated)	9,932,874	14,031,691	Electric
8	Transmission Plant (Estimated)	2,428	12,852	Electric
9	Distribution Plant (Estimated)	427,729	313,881	Electric
10	Regional Transmission and Market Operation Plant (Estimated)
11	Assigned to - Other (provide details in footnote)	(a) 55,324	(b) 23,237	Electric
12	TOTAL Account 154 (Enter Total of lines 5 thru 11)	20,420,653	26,061,672
13	Merchandise (Account 155)
14	Other Materials and Supplies (Account 156)
15	Nuclear Materials Held for Sale (Account 157) (Not applic to Gas Util)
16	Stores Expense Undistributed (Account 163)
17
18
19
20	TOTAL Materials and Supplies	30,510,161	48,055,235

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: PlantMaterialsAndOperatingSuppliesOther

Assigned to - Other includes customer account, administrative and general expenses.

(b) Concept: PlantMaterialsAndOperatingSuppliesOther

Assigned to - Other includes Customer Account, Administrative and General Expenses.

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	298,260	8,552,442	63,996		65,460		54,080		1,389,246		1,871,042	8,552,442
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)	1,394								54,271		55,665
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	2,690	53,461									2,690	53,461
19	Other:
20	Allowances Used
20.1	Allowances Used
21	Cost of Sales/Transfers:
22	Consent Decree Surrenders
23
24
25
26
27
28	Total
29	Balance-End of Year	296,964	8,498,981	63,996		65,460		54,080		1,443,517		1,924,017	8,498,981
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	362		362		362		362		24,244		25,692
37	Add: Withheld by EPA									723		723
38	Deduct: Returned by EPA
39	Cost of Sales	362								361		723
40	Balance-End of Year			362		362		362		24,606		25,692
41
42	Sales
43	Net Sales Proceeds (Assoc. Co.)
44	Net Sales Proceeds (Other)
45	Gains
46	Losses

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	46,371		6,735		7,198						60,304
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)	850										850
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	1,561										1,561
19	Other:
20	Allowances Used
20.1	Allowances Used
21	Cost of Sales/Transfers:
22	Wolverine Power Supply Cooperative, Inc.
23
24
25
26
27
28	Total
29	Balance-End of Year	45,660		6,735		7,198						59,593
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:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
20	TOTAL

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	AF1-130	6,039	186	7,261	186
3	AF1-162	2,426	186	2,541	186
4	AG1-066	188	186
5	AG2-184	37	186	74	186
6	AG2-567	52	186	104	186
7	AG2-678	53	186	106	186
8	AG2-679	75	186	149	186
9	AG2-681	66	186	132	186
10	AG2-682	64	186	128	186
11	AG2-685	76	186	150	186
12	PJM - #AF2-018	591	186
20	Total
21	Generation Studies
22	None
39	Total
40	Grand Total

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	Deferred Storm Expenses - Kentucky PSC Case No. 2017-00179 - Amortz period: January 2018 - December 2023	2,166,553		593	2,066,559	99,994
2	KY Deferred Interest on 7.32% Note Case No. 2020-00174	487,582		427	487,582
3	SFAS 109 Deferred FIT	38,753,917	17,621,958	282/283	14,236,101	42,139,774
4	Unrecovered Fuel Cost	8,216,170	50,196,421	501	35,171,129	23,241,462
5	SFAS 109 Deferred SIT	90,029,737	10,756,715	282/283	6,083,995	94,702,457
6	KY Steam Maint O/U	472,239		512	232,064	240,175
7	Post In-Service AFUDC Hanging Rock/Jefferson 765 KV LineAmortz period: Dec 1984 - Nov 2032	364,968		182/406	33,408	331,560
8	PJM Greenhat Default Deferral	205,840		561	101,153	104,687
9	Depreciation Expense - Hanging Rock/Jefferson 765 KV LineAmortz period: Dec 1984 - Nov 2032	56,857		182/406	5,208	51,649
10	Unrecovered Plant - Big Sandy Kentucky PSC Case No. 2014-00396	256,509,062				256,509,062
11	IGCC Pre-Construction Costs Kentucky PSC Case No. 2014-00396	985,128		506	53,250	931,878
12	CCS FEED Study Costs Kentucky PSC Case No. 2014-00396	645,916		506	34,914	611,002
13	SFAS 112 Post Employment Benefit	3,409,554	1,092,139	228	85,867	4,415,826
14	Spent AROs - Big Sandy Coal Kentucky PSC Case No. 2014-00396	109,576,758	433,087			110,009,845
15	SFAS 158 Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans	12,236,398	35,321,452	165/182/228	23,854,227	23,703,623
16	Big Sandy Recovery Over/Under Kentucky PSC Case No. 2014-00396	38,377,806		407	14,575,979	52,953,785
17	Big Sandy Retirement Rider Unit 2 O&M Kentucky PSC Case No. 2014-00396	928,225	3,203			931,428
18	Unrealized Loss on Forward Commitments		455,054	175/182/244/456	538,933	83,879
19	Deferred Depreciation - Environmental Kentucky PSC Case No. 2014-00396	5,919,771	5,748,897	403	6,529,469	5,139,199
20	Netting of Trading Activities related toUnrealized Gains/Losses on Forward Commitmentsbetween Regulated Assets/Liabilities		272,144	254	188,265	83,879
21	BS1OR Under Recovery Kentucky PSC Case No. 2014-00396	722,291	702,350	182/407	1,063,495	361,146
22	NERC Compliance and Cybersecurity Costs Kentucky PSC Case No. 2014-00396	1,224,091	920,696	182/404/431	205,443	1,939,344
23	Capacity Charge Tariff Kentucky PSC Case No. 2014-00396, TFS 2016-00430	406,426	197,233	254/440/442/444	603,659
24	SFAS 106 Medicare SubsidyAmortz period: Jan 2013 - Dec 2024	649,859		926	216,620	433,239
25	Rate Cases Expenses	228,431	2,332	928	112,254	118,509
26	OSS Margin Sharing Kentucky PSC Case No. 2017-00179	372,015	1,790,311	440/442/444/561	2,162,326
27	Under-Recovery of PJM True-UpAmortz period: Jan 2022-Dec 2022	330,235		456/447	330,235
28	Rockport Capacity Deferral Kentucky PSC Case No. 2017-00179	47,527,845	7,358,399	182/431	1,916,551	52,969,693
29	PJM RTEP Costs Deferral
30	Cost of Removal-Big Sandy CoalKentucky PSC Case No. 2014-00396	24,901,951	66,184	108	217,085	25,052,852
31	KY Under-recovered PPA Rider	28,727,095	13,859,963	566	4,423,488	38,163,570
32	2020 KY Storm Deferral	56,505,847				56,505,847
33	NBV - AROs Retired PlantsKentucky PSC Case No. 2014-00396	4,720,791	1,007,870	182	433,087	5,295,574
34	2022 PJM Transmission True-up		13,564			13,564
35	PJM 2020 Transmission DeferralAmortization period: Jan 2022-Dec 2022	973,425		565	973,425
36	M&S - Retiring PlantsKentucky PSC Case No. 2014-00396	3,015,785				3,015,785
37	2021 PJM Transmission True-up		1,073,198			1,073,198
38	KY ELG Deferral		1,446,998	107/506	482,333	964,665
39	2022 KY Major Storm Deferral		18,106,036	560/566/570/592	182,206	17,923,830
44	TOTAL	613,089,054	168,446,204		117,600,310	663,934,948

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	Deferred Property Tax	20,777,988	22,406,269	107/408	19,511,749	23,672,508
2	Agency Fees - Factored A/R	1,042,779	1,371,292	142/184	2,414,070
3	Unamortized Credit Line Fees	353,209	78,982	431	134,502	297,689
4	Amortized thru March 2027
5	Deferred Lease Assets	86,775	246,210	107/143/184	332,985
6	Estimated Barging Bills
7	Miscellaneous Items	6,978				6,978
8	Allowance	7,146	10,050	253/411/232	17,196
9	Trnsrce OU Acctg for Def Asset	53,858	61,401	565	85,798	29,461
10	2021 PJM Transmission True-up		1,272,009			1,272,009
11	2022 PJM Transmission True-up		71,168			71,168
47	Miscellaneous Work in Progress	478,103				230,738
48	Deferred Regulatroy Comm. Expenses (See pages 350 - 351)
49	TOTAL	22,792,880				25,566,595

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	Provision Revenue Refunds	28,026	291,903
3	Accrued BK ARO Cost	3,716,369	3,880,122
4	Int Exp Capd for Tax	5,756,007	6,664,287
5	Accrued Book Pension	8,489,702	2,659,439
6	NOL State Deferred Tax Asset	13,098,501	14,789,648
7	Other	9,189,875	2,731,394
8	TOTAL Electric (Enter Total of lines 2 thru 7)	23,243,024	25,697,915
9	Gas
15	Other
16	TOTAL Gas (Enter Total of lines 10 thru 15)
17.1	Other (Specify)	(a) 70,819,425	60,465,500
17	Other (Specify)
18	TOTAL (Acct 190) (Total of lines 8, 16 and 17)	94,062,449	86,163,415

Notes

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxes



Line 17 Other - Detail	Balance at	Balance at
	Beginning of Year	End of Year


Acc Def Income Taxes - Federal - Hdg-CF-Int Rate	-	-
Non Utility Items - 190.2	628,222	968,606
SFAS 109-Regulatory Assets - 190.3, 190.4 & 190.6	70,656,351	59,496,894
SFAS 133	-	-
Accu Def Income Taxes Pension-OCI	(465,148)	-

Total	$ 70,819,425	60,465,500



Line 18
Reconciliation of details applicable to Account 190, Line 18, Columns (b) and (c) :

Balance at Beginning of Year		94,062,449

(Less) Amounts Debited to:
(a) Account 410.1		(17,985,113)
(b) Account 410.2		(1,376,225)
(c) 1823/254/219/129/427		(21,029,635)

(Plus) Amounts Credited to:
(a) Account 411.1		20,483,349
(b) Account 411.2		1,673,266
(c) 1823/254/219/129/427		10,335,326

Balance at End of Year		86,163,417

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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		2,000,000	50.00		1,009,000	50,450,000
6	Total	2,000,000			1,009,000	50,450,000
7	Preferred Stock (Account 204)
8
9
10
11	Total					0
1	Capital Stock (Accounts 201 and 204) - Data Conversion
2
3
4
5	Total

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

2023-04-12

Year/Period of Report

End of:

2022

/

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	523,324,094
3.1	IncreasesDecreasesFromSalesOfDonationsReceivedFromStockholders Increases (Decreases) from Sales of Donations Received from Stockholders
4	DonationsReceivedFromStockholders Ending Balance Amount	523,324,094
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	2,811,185
15.1	IncreasesDecreasesDueToMiscellaneousPaidInCapital Increases (Decreases) Due to Miscellaneous Paid-In Capital	151,683
16	MiscellaneousPaidInCapital Ending Balance Amount	2,962,868
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	526,286,962

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	0

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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
3
4
5	Subtotal											0
6	Reacquired Bonds (Account 222)
7
8
9
10	Subtotal											0
11	Advances from Associated Companies (Account 223)
12
13
14
15	Subtotal											0
16	Other Long Term Debt (Account 224)
17	(a) Senior Unsecured Notes - 5.625%, Series D		75,000,000					06/13/2003	12/01/2032	06/13/2003	12/01/2032	75,000,000	4,218,750
18	Senior Unsecured Notes - 8.030%, State Commission Authority Case # 2008-00442		30,000,000					06/18/2009	06/18/2029	06/18/2009	06/18/2029	30,000,000	2,409,000
19	Senior Unsecured Notes - 8.130%, State Commission Authority Case # 2008-00442		60,000,000					06/18/2009	06/18/2039	06/18/2009	06/18/2039	60,000,000	4,878,000
20	Senior Unsecured Notes - 4.180%, Series A State Commission Authority Case# 2014-00210		120,000,000					09/30/2014	09/30/2026	09/30/2014	09/30/2026	120,000,000	5,016,000
21	Senior Unsecured Notes - 4.33%, Series B State Commission Authority Case# 2014-00210		80,000,000					12/30/2014	12/30/2026	12/30/2014	12/30/2026	80,000,000	3,464,000
22	(b) West Virginia Economic Development Authority Mitchell Project Series 2014A State Commission Authority Case# 2013-00410		65,000,000					06/26/2014	04/01/2036	06/26/2014	06/19/2023	65,000,000	1,527,500
23	Local Bank Term Loan, State Commission Authority Case# 2014-00210		75,000,000					11/05/2014	10/26/2022	11/05/2014	10/26/2022		1,103,667
24	(c) Local Bank Term LoanState Commission Authority: 2021-00131 (1st 75 million)State Commission Authority: 2022-00205 (2nd 75 million)		150,000,000					07/22/2022	12/31/2023	07/22/2022	12/31/2023	150,000,000	2,643,829
25	Senior Unsecured Notes - 3.13%, Series F		65,000,000					09/12/2017	09/12/2024	09/12/2017	09/12/2024	65,000,000	2,034,500
26	Senior Unsecured Notes - 3.35%, Series G		40,000,000					09/12/2017	09/12/2027	09/12/2017	09/12/2027	40,000,000	1,827,582
27	Senior Unsecured Notes - 3.45%, Series H		165,000,000					09/12/2017	09/12/2029	09/12/2017	09/12/2029	165,000,000	5,692,500
28	Senior Unsecured Notes - 4.12%, Series I		55,000,000					09/12/2017	09/12/2047	09/12/2017	09/12/2047	55,000,000	2,266,000
29	(d) Local Bank Term Loan, State Commission Authority Case# 2019-00072, Maturity Extended to 12/31/2023		125,000,000					03/06/2020	12/31/2023	03/06/2020	12/31/2023	125,000,000	3,061,743
30	(e) Term Loan - KY State Commission Authority: Case No. 2021-00131		150,000,000					06/17/2021	06/17/2023	06/17/2021	06/17/2023	150,000,000	4,068,167
31	Subtotal		1,255,000,000									1,180,000,000	44,211,238
33	TOTAL		1,255,000,000									1,180,000,000	44,211,238

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: ClassAndSeriesOfObligationCouponRateDescription

The $75 million multiple draw term loan was issued on November 5, 2014. The interest rate is variable and the maturity date is November 5, 2018. Note was reissued October 26, 2018 with a new maturity date of 10/26/2022 and called off on 08/17/2022 before maturity date

(b) Concept: ClassAndSeriesOfObligationCouponRateDescription

Issuance: West Virginia Economic Development Authority, Mitchell Project Series 2014A

Principal Amount: $65,000,000

Date of Issuance: 06/26/2014

Date of Maturity: 04/01/2036

Puttable Date: Bonds were subject to mandatory tender for purchase on 06/26/2017. Issuance expense of 675,501 was fully amortized as of 06/19/2017.

These bonds were re-marketed 06/19/2017:

Issuance: West Virginia Economic Development Authority, Mitchell Project Series 2014A

Principal Amount: $65,000,000

Date of Issuance: 06/19/2017

Date of Maturity: 04/01/2036

Puttable Date: Bonds are subject to mandatory tender for purchase on 6/19/2020. Issuance expense of 146,250 to be amortized through 06/19/2020.

Issuance: West Virginia Economic Development Authority, Mitchell Project Series 2014A

Principal Amount: $65,000,000

Date of Issuance: 06/19/2020

Date of Maturity: 04/01/2036

Puttable Date: Bonds are subject to mandatory tender for purchase on 6/19/2023. Issuance expense of 330,220 to be amortized through 06/19/2023.

(c) Concept: ClassAndSeriesOfObligationCouponRateDescription

The $75 million multiple draw term loan was issued on November 5, 2014. The interest rate is variable and the maturity date is November 5, 2018. Note was reissued October 26, 2018 with a new maturity date of 10/26/2022 and called off on 08/17/2022 before maturity date

(d) Concept: ClassAndSeriesOfObligationCouponRateDescription

The $125 million multiple draw term loan was issued on March 6, 2020. The interest rate is variable and the maturity date is extended from March 6, 2022 to September 6 2022 and then from September 6 2022 extended up to December 31, 2023

(e) Concept: ClassAndSeriesOfObligationCouponRateDescription

The $150 million multiple draw term loan was issued on June 17, 2021. The interest rate is variable and the maturity date is June 17, 2023.

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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)	47,552,177
2	Reconciling Items for the Year
3
4	Taxable Income Not Reported on Books
5
6
7
8
9	Deductions Recorded on Books Not Deducted for Return
10
11
12
13
14	Income Recorded on Books Not Included in Return
15
16
17
18
19	Deductions on Return Not Charged Against Book Income
20
21
22
23
24
25
26
27	Federal Tax Net Income	(a) 16,433,499
28	Show Computation of Tax:
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: FederalTaxNetIncome


FOOTNOTE DATA

Schedule Page: 261 Line No.: 28 Column: b			in $ 000's

Net Income for the Year per Page 117			47,552

Federal Income Taxes			(30,274)

State Income Taxes			(755)

			—

Pre-Tax Book Income`			16,523

Excess Tax vs Book Depreciation			35,141

AFUDC and Other Capitalization Differences			16

Book Unit of Property Adjustment			(27,631)

Removal Cost			(12,515)

Pollution Control Equipment			7,784

Property Tax			—

Provision for Revenue Refunds			1259

Deferred Fuel			(15,025)

Self Insurance / Worker's Comp			-1327

Accrued Book Pension Expense			27,830

Deferred Storm Damage			2,067

Misc Book Accruals, Reserves & Deferrals			(22,150)

Non Deduct expenses			206

Total Tax Accruals			6

Capitalized Software			4,197

Reg-Asset unrecovered plant			—

Mark-to-Market			—

Emission Allowances			54

Others			—


FOOTNOTE DATA


Taxable Income before State Taxes			16,434

Deductions for Fed/Other States			432

			16,002

State & Local Current Tax			—

Federal Taxable Income			16,002

FIT on Current Year Taxable Income (21%)			3,360


NOL Reclass			2,549

Tax Credit CFWD			210

ALT Min Tax

ETR Adjustment
R&D Credit - Current			31

Estimated Tax Currently Payable (b)			2,790
Current Tax (a) - (b)			570

Adjustments of Prior Year's Accruals			(497)

Tax Expense for R/C of Net Operating Loss (Prior Yr)

Estimated Current Federal Income Taxes			73

Foot Notes:

(a) Represents the allocation of the estimated current year net operating tax loss of American Electric Power Company, Inc.

(b) The Company joins in the filing of a consolidated Federal income tax return with its affiliated companies in the AEP system. The allocation of the AEP System's consolidated Federal income tax to the System companies allocates the benefit of current tax losses to the System companies giving rise to them in determining their current tax expense. The tax loss of the System parent company, American Electric Power Company, Inc., is allocated to its subsidiaries with taxable income. With the exception of the loss of the parent company, the method of allocation approximates a separate return result for each company in the consolidating group.

INSTRUCTION 2.

* The tax computation above represents an estimate of the Company's allocated portion of the System consolidated Federal income tax. The computation of actual 2021 System. Federal income taxes will not be available until the consolidated Federal income tax return is completed and filed by October 2022. The actual allocation of the System consolidated Federal income tax to the members of the consolidated group will not be available until after the consolidated federal income tax return is filed

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	Federal Tax	Federal Tax			2,419,570	0	73,572	2,792,565		299,423		1,370,088			1,296,517
2	Subtotal Federal Tax				2,419,570	0	73,572	2,792,565	0	299,423	0	1,370,088	0	0	1,296,517
3	State Tax	State Tax	IL	2016	1	0				1
4	State Tax	State Tax	IL	2017	66,879	0				66,879
5	State Tax	State Tax	IL	2018	4,158	0				4,158
6	State Tax	State Tax	IL	2019	41,360	0				41,360
7	State Tax	State Tax	IL	2020	7,650	0	0			7,650
8	State Tax	State Tax	IL	2021	49,034	0	0	55,715		104,749
9	State Tax	State Tax	IL	2022	0					0		216			216
10	State Tax	State Tax	KY	2015	0	0	0			0
11	State Tax	State Tax	KY	2017	1,172,523	0	0			1,172,523
12	State Tax	State Tax	KY	2018	36,254	0	0			36,254
13	State Tax	State Tax	KY	2019	863,107	0	0			863,107
14	State Tax	State Tax	KY	2020	1,486,489	0				1,486,489
15	State Tax	State Tax	KY	2021	46,543	0		299,508		346,051
16	State Tax	State Tax	KY	2022	0		259,648			259,648		581,564			321,916
17	State Tax	State Tax	MI	2017	2,683	0	0			2,683
18	State Tax	State Tax	MI	2018	2,685	0	0			2,685
19	State Tax	State Tax	MI	2019	1,096	0	0			1,096
20	State Tax	State Tax	MI	2020	1,310	0	0			1,310
21	State Tax	State Tax	MI	2021	0	0	0	217		217
22	State Tax	State Tax	MULTI	2019	49,346	0	0			49,346
23	State Tax	State Tax	MULTI	2021				296,567		296,567
24	State Tax	State Tax	WV	2017	324,201	0	0			324,201
25	State Tax	State Tax	WV	2018	361,995	0	0			361,995
26	State Tax	State Tax	WV	2019	566,200	0	0			566,200
27	State Tax	State Tax	WV	2020	260,820	0				260,820
28	State Tax	State Tax	WV	2021	66,163	0		277,011		343,174
29	State Tax	State Tax	WV	2022			431,492			431,492		397,672			33,821
30	State Tax	State Tax	CA	2020	92	0				92
31	State Tax	State Tax	CA	2021	92	0				92
32	State Tax	State Tax	CA	2022			0			0		92			92
33	Subtotal State Tax				842,593	0	691,140	263,566	0	415,019	0	979,112	0	0	287,971
34	Local Tax	Local Tax		2019	49,346	0				49,346
35	Local Tax	Local Tax		2021	0	0				0
36	Local Tax	Local Tax		2022	0	0				0
37	Subtotal Local Tax				49,346	0	0	0	0	49,346	0	0	0	0	0
38	Subtotal Other Tax				0	0	0	0	0	0	0	0	0	0	0
39	Property Tax	Property Tax	KY	2019	2,199,410			397,434		1,801,976
40	Property Tax	Property Tax	KY	2020	16,530,117	0		15,060,008		1,470,109
41	Property Tax	Property Tax	KY	2021	17,053,555	0		5,358,521		11,695,034		15,319,300			15,319,300
42	Property Tax	Property Tax	KY	2022	0	0	19,986,600	152,449		19,834,151		547,210			19,439,390
43	Property Tax	Property Tax	IN	2021			2,655	2,655							2,655
44	Property Tax	Property Tax	WV	2020	1,411,612	0	0	1,411,612		0		1,650,854			1,650,854
45	Property Tax	Property Tax	WV	2021	2,852,700	0	32,220	1,461,386		1,423,534		1,466,174			1,433,954
46	Property Tax	Property Tax	WV	2022		0	2,887,268			2,887,268					2,887,268
47	Subtotal Property Tax				40,047,394	0	22,903,433	23,838,755	0	39,112,072	0	18,983,538	0	0	3,919,895
48	Subtotal Real Estate Tax				0	0	0	0	0	0	0	0	0	0	0
49	UNEMPLOYMENT 2022	Unemployment Tax			5,786	0	21,253	22,024		5,015		12,720			8,533
50	STATE UNEMPLOYMENT 2022	Unemployment Tax	KY		6,424	0	6,447	10,476		2,395		3,517			2,931
51	STATE UNEMPLOYMENT 2022	Unemployment Tax	OH		0	0	0			0
52	STATE UNEMPLOYMENT 2022	Unemployment Tax	VA		0	0	0			0
53	STATE UNEMPLOYMENT 2022	Unemployment Tax	WV		6,757	0	20,788	27,544		1		11,934			8,854
54	Subtotal Unemployment Tax				18,967	0	48,488	60,044	0	7,411	0	28,171	0	0	20,318
55	Sales and Use	Sales And Use Tax	KY	2017	492,200	0	492,200			0		492,200
56	Sales and Use	Sales And Use Tax	KY	2018			3,543,016	3,543,016	0	0		317,582			3,225,434
57	Sales and Use	Sales And Use Tax	KY	2021	83,542	899,256	988,571	172,857	0	0		5,426			983,145
58	Sales and Use	Sales And Use Tax	KY	2022			1,255,757	2,010,885		162,299	917,427	59,791			1,195,966
59	Sales and Use	Sales And Use Tax	OH	2021	118	0	118			0		0			118
60	Sales and Use	Sales And Use Tax	OH	2022		0				0		139			139
61	Sales and Use	Sales And Use Tax	WV	2020	8,074	0		8,074		0
62	Sales and Use	Sales And Use Tax	WV	2021			0	0			0	0			0
63	Sales and Use	Sales And Use Tax	WV	2022			68,805	65,566		3,239		1,239			70,044
64	Subtotal Sales And Use Tax				583,934	899,256	5,363,831	5,800,398	0	165,538	917,427	110,779	0	0	5,474,610
65	Subtotal Income Tax				0	0	0	0	0	0	0	0	0	0	0
66	Excise Tax	Excise Tax		2021	0	0	585	585		0		585
67	Excise Tax	Excise Tax		2022	0	0	4,712	4,712		0		4,712
68	Subtotal Excise Tax				0	0	5,297	5,297	0	0	0	5,297	0	0	0
69	Subtotal Fuel Tax				0	0	0	0	0		0	0	0	0	0
70	FICA	Federal Insurance Tax			1,405,613	0	3,280,404	4,465,086	92	220,839		1,684,721
71	Subtotal Federal Insurance Tax				1,405,613	0	3,280,404	4,465,086	92	220,839	0	1,684,721	0	0	0
72	Franchise Tax	Franchise Tax	KY	2017	225,823	0				225,823
73	Franchise Tax	Franchise Tax	KY	2018	174,650	0				174,650
74	Franchise Tax	Franchise Tax	KY	2019	243,115	0				243,115
75	Franchise Tax	Franchise Tax	KY	2020	48,643	0				48,643
76	Subtotal Franchise Tax				240,585	0	0	0	0	240,585	0	0	0	0	0
77	Subtotal Miscellaneous Other Tax				0	0	0	0	0		0	0	0	0	0
78	Subtotal Other Federal Tax				0	0	0	0	0	0	0	0	0	0	0
79	Other State Tax	Other State Tax	KY	2019			4,859	4,859				4,859
80	Other State Tax	Other State Tax	KY	2020		0	1,736	1,736		0		1,736
81	Other State Tax	Other State Tax	KY	2021	1,487	0	4,234	5,721		0		1,411			2,823
82	Other State Tax	Other State Tax	OH	2021	4,200	0	4,671	471		0		4,671
83	Other State Tax	Other State Tax	OH	2022		0	2,092	2,092		0		2,092
84	Other State Tax	Other State Tax	WV	2020		0	22,147	22,147		0		22,147
85	Other State Tax	Other State Tax	WV	2021	520,817	0	10,279	510,538		0		10,279
86	Other State Tax	Other State Tax	WV	2022			6,296,423	5,772,421		524,002		6,296,423
87	Utility GR LIC- EDP	Other State Tax	KY	2022			19,259	17,654		1,605		19,259
88	Subtotal Other State Tax				526,504	0	6,278,316	6,279,213	0	525,607	0	6,275,493	0	0	2,823
89	Subtotal Other Property Tax				0	0	0	0	0	0	0	0	0	0	0
90	Subtotal Other Use Tax				0	0	0	0	0		0	0	0	0	0
91	Subtotal Other Advalorem Tax				0	0	0	0	0		0	0	0	0	0
92	Other License and Fees Tax	Other License And Fees Tax	KY	2019	124	0			1	125
93	Other License and Fees Tax	Other License And Fees Tax	KY	2020	200	0				200
94	Other License and Fees Tax	Other License And Fees Tax	WV	2019	46	0				46
95	Other License and Fees Tax	Other License And Fees Tax	WV	2022				175		175
96	Subtotal Other License And Fees Tax				370	0	0	175	1	546	0	0	0	0	0
97	Subtotal Payroll Tax				0	0	0	0	0	0	0	0	0	0	0
98	Subtotal Advalorem Tax				0	0	0	0	0	0	0	0	0	0	0
99	Subtotal Other Allocated Tax				0	0	0	0	0	0	0	0	0	0	0
100	Subtotal Severance Tax				0	0	0	0	0	0	0	0	0	0	0
101	Subtotal Penalty Tax				0	0	0	0	0	0	0	0	0	0	0
102	Other Taxes and Fees	Other Taxes and Fees	KY	2020		0
103	Other Taxes and Fees	Other Taxes and Fees	KY	2021		0				0
104	Subtotal Other Taxes And Fees				0	0				0	0	0	0	0	0
40	TOTAL				44,350,258	899,256	38,644,481	43,505,099	93	39,507,718	917,427	29,215,641	0	0	7,833,158

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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%		411.1		411.4
8	TOTAL Electric (Enter Total of lines 2 thru 7)
9	Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
10										`
47	OTHER TOTAL
48	GRAND TOTAL							0

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	TV Pole Attachments	147,516	142/186/143/454	876,660	880,107	150,963
2	Customer Advance Receipts	1,833,564	142/232	1,833,564	1,988,189	1,988,189
3	Deferred Gain: Fiber Optic Agrmts-In Kind SvcAmortize through June 2026	72,379	124	18,045		54,334
4	ABD - Deferred Revenues	104,509	456	104,509
5	Deferred Revenue Fiber Optic Lines-Sold-Defd Rev Amortize through January 2025	2,739	451	888		1,851
6	2021 PJM Transmission True-up				467,866	467,866
7	2022 PJM Transmission True-up				4,892,524	4,892,524
8	IPP - System Upgrade Credits
9	Miscellaneous	794	131/142/146/186/232/235	4,818	5,360	1,336
10	Contribution Aid of Construction	185,561	107/108	185,561	197,300	197,300
11	Deferred Revenue	66,207	142/143/186	66,207	240,778	240,778
12	Deferred Rev-Bonus Lease	51,227	421	22,768		28,459
13	NERC Penalties	95,310				95,310
47	TOTAL	2,559,807		3,113,020	8,672,124	8,118,911

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	45,613,662	406	2,289,169							43,324,899
5	Other
5.1	Other (provide details in footnote):
8	TOTAL Electric (Enter Total of lines 3 thru 7)	45,613,662	406	2,289,169							43,324,899
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	(a) OTHER	17,066,875					254	406	254	605,699	16,461,582
17	TOTAL (Acct 281) (Total of 8, 15 and 16)	28,546,787	406	2,289,169				406		605,699	26,863,317
18	Classification of TOTAL
19	Federal Income Tax	28,546,787	406	2,289,169				406		605,699	26,863,317
20	State Income Tax
21	Local Income Tax

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: DescriptionOfAcceleratedAmortizationPropertyOtherUtilityOther

232,561,566


Description Page 272-273 Line 16	Balance at Beginning of The year	Debit Adjust.	Credit Adjust.	Balance End of Year
SFAS 109	(17,066,875)		605699	(16,461,176)
Total Line 16	(17,066,875)		605699	(16,461,176)

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	359,773,864	42,269,919	67,434,131					190		334,609,652
3	Gas
4	Other (Specify)
5	Total (Total of lines 2 thru 4)	359,773,864	42,269,919	67,434,131							334,609,652
6	Others	(a) 79,829,030					1823/254	9,876,651	1823/254	32,280,589	57,425,092
9	TOTAL Account 282 (Total of Lines 5 thru 8)	279,944,834	42,269,919	67,434,131				9,876,651		32,280,589	277,184,560
10	Classification of TOTAL
11	Federal Income Tax	279,944,834	42,269,919	67,434,131				9,876,651		32,280,589	277,184,560
12	State Income Tax
13	Local Income Tax

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesOtherProperty


Line 6 Footnote
	Beg Bal	Debits	Credits	End Bal
Non-Utility	0	0	0	0
SFAS 109	(79,829,030)	9,876,651	32,280,589	(57,425,091)
Total Other - Line 6	(79,829,030)	9,876,651	32,280,589	(57,425,091)

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	Deferred Fuel Costs	1,725,395	6,255,405	3,100,093							4,880,707
4	Mark-to-Market	65,070,611	267,167	3,116,470							62,221,308
5	Capitalized Software - Book	6,861,391	122,863	559,076							6,425,178
6	Emission Allowances	1,824,604	7,496	47,311							1,784,789
7	Reg Asset - SFAS 112	716,007	211,317								927,324
8	Other	52,185,740	17,935,297	19,396,050		125,472		1			50,599,514
9	TOTAL Electric (Total of lines 3 thru 8)	128,383,748	24,799,545	26,219,000		125,472		1			126,838,820
10	Gas
11
12
13
14
15
16
17	TOTAL Gas (Total of lines 11 thru 16)
18	TOTAL Other	(a) 94,338,795					1823/254	10,796,251	1823/254	27,951,247	111,493,791
19	TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)	222,722,543	24,799,545	26,219,000		125,472		10,796,252		27,951,247	238,332,611
20	Classification of TOTAL
21	Federal Income Tax	130,105,461	24,799,545	25,766,288		125,472		4,712,257		17,194,532	141,495,521
22	State Income Tax	92,617,082		452,712				6,083,995		10,756,715	96,837,090
23	Local Income Tax
NOTES

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesOther


Line 18 Other - Detail	Balance at Beginning of Year		Balance at End of Year
Non-Utility	—		—
SFAS 109	94,338,795		111,493,790
SFAS 133	0		0
Total	$	94,338,795	$	111,493,790

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	Home Energy Assistance Program	1,136,440	142/235/237/450/451/460	1,871,080	963,829	229,189
2	SFAS 109 Deferred FIT	201,997,111	190/282/283	53,488,497	10,222,986	158,731,600
3	Kentucky Reliability	383,347	593	1,704,023	1,690,639	369,963
4	Over Recovered Fuel Cost
5	PJM Trans Enhancement Reg Liability	2,643,689	142	612,304		2,031,385
6	KY- DSM Over Recovery	39,316	182/456	89,241	66,328	16,403
7	Netting of Trading Activities related toUnrealized Gains/Losses on Forward Commitmentsbetween Regulated Assets/Liabilities		182	188,266	272,144	83,878
8	Capacity Charge Tariff OverRec				427,163	427,163
9	OSS Margin Sharing		182/440/442/444	3,624,540	7,041,868	3,417,328
10	Unrealized Gain on Forward Commitments	3,198,943	175/182/244	6,386,405	7,085,584	3,898,122
11	Steam Maintenance Levelized Reg LiabilityKY Case No. 2017-00179	2,097,760				2,097,760
41	TOTAL	211,496,606		67,964,356	27,770,541	171,302,791

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	315,954,846	281,787,992	1,968,490	1,979,060	132,619	133,805
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)	196,025,387	159,833,921	1,344,936	1,144,445	30,207	30,222
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)	183,905,898	142,303,180	2,068,484	1,960,411	1,049	1,079
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting	2,193,290	2,032,165	9,388	9,393	309	310
7	OtherSalesToPublicAuthoritiesAbstract (445) Other Sales to Public Authorities
8	SalesToRailroadsAndRailwaysAbstract (446) Sales to Railroads and Railways
9	InterdepartmentalSalesAbstract (448) Interdepartmental Sales
10	SalesToUltimateConsumersAbstract TOTAL Sales to Ultimate Consumers	(a) 698,079,422	(d) 585,957,258	5,391,298	5,093,309	164,184	165,416
11	SalesForResaleAbstract (447) Sales for Resale	59,734,355	43,087,990	610,474	887,455	10	12
12	SalesOfElectricityAbstract TOTAL Sales of Electricity	757,813,776	629,045,248	6,001,772	5,980,764	164,194	165,428
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds	5,999,074
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds	751,814,702	629,045,248	6,001,772	5,980,764	164,194	165,428
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts	1,835,674	1,311,974
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	(b) 159,667	256,524
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power
19	RentFromElectricProperty (454) Rent from Electric Property	7,093,909	5,841,043
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	(c) 1,394,280	838,181
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	39,825,979	22,254,859
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	50,309,509	30,502,581
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	802,124,211	659,547,829
Line12, column (b) includes $ 4,673,974 of unbilled revenues.
Line12, column (d) includes 32,817 MWH relating to unbilled revenues

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: SalesToUltimateConsumers

Detail of Unmetered Sales - 2022


	Revenue	MWH	Average No. of Customers

Residential	6,565,847	23,460	38,929
Commercial	3,374,691	14,459	6,962
Industrial	163,877	752	207
Public Street Lighting	38,491	108	35
Total	10,142,906	38,779	46,133

(b) Concept: MiscellaneousServiceRevenues

Customer Service Revenue including connects, reconnects, disconnects, temporary services and other charges billed to customers.

(c) Concept: OtherElectricRevenue


Description	2022 YTD	2021 YTD
Oth Elect Rev - Demand Side Management Program	270,151	284,168
All Other (Under $250,000)	1,124,129	554,013
	1,394,280	838,181

(d) Concept: SalesToUltimateConsumers

Detail of Unmetered Sales - 2021


	Revenue	MWH	Average No. of Customers

Residential	6,448,479	25,476	38,700
Commercial	3,154,653	14,776	6,835
Industrial	150,723	760	208
Public Street Lighting	36,520	108	35
Total	9,790,375	41,120	45,778

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	Estimated
2	General Service R	31	6,102	4	7,750	0.1968
3	Outdoor Lighting R	23,460	6,565,847			0.2799
4	Residential Load Management‐Time‐of‐Day R	2,928	446,459	149	19,651	0.1525
5	Residential Service R	1,931,059	308,825,958	132,462	14,578	0.1599
6	Residential Service Time‐of‐Day R	92	14,188	4	23,000	0.1542
7	Unrecovered R
8	Kentucky Rider R		1,859,638
41	TOTAL Billed Residential Sales	1,957,570	313,998,916	132,619	14,761	0.1604
42	TOTAL Unbilled Rev. (See Instr. 6)	10,920	1,955,930			0.1791
43	TOTAL	1,968,490	315,954,846	132,619	14,843	0.1605

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	Unrecovered C
2	Kentucky Rider C		1,479,149
3	Estimated C	11	380
4	General Service C	595,619	105,363,952	29,685	20,065	0.1769
5	Industrial General Service C	314,830	27,774,958	25	12,593,200	0.0882
6	Large General Service C	395,902	57,939,821	483	819,673	0.1463
7	Large General Service Time‐of‐Day C	4,961	632,766	4	1,240,250	0.1275
8	Municipal WaterworksC	1,805	255,678	9	200,556	0.1416
9	Outdoor Lighting C	14,459	3,374,690			0.2334
10	Residential Service C	9	1,512	1	9,000	0.1680
41	TOTAL Billed Small or Commercial	1,327,574	193,863,848	30,207	43,949	0.1460
42	TOTAL Unbilled Rev. Small or Commercial (See Instr. 6)	17,362	2,161,539			0.1245
43	TOTAL Small or Commercial	1,344,936	196,025,387	30,207	44,524	0.1458

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	Contract Service – Interruptible Power I	231,478	16,824,767	8	28,934,750	0.0727
2	Estimated I	1,905	2,318,448			1.2170
3	General Service I	25,341	4,367,978	910	27,847	0.1724
4	Industrial General Service I	1,711,654	146,448,194	35	48,904,400	0.0856
5	Large General Service I	89,706	14,095,976	94	954,319	0.1571
6	Large General Service Time‐of‐Day I	3,135	402,252	2	1,567,500	0.1283
7	Outdoor Lighting I	752	163,877			0.2179
8	Unrecovered I
9	Kentucky Rider I		1,267,723
41	TOTAL Billed Large (or Ind.) Sales	2,063,971	183,353,769	1,049	1,967,561	0.0888
42	TOTAL Unbilled Rev. Large (or Ind.) (See Instr. 6)	4,513	552,129			0.1223
43	TOTAL Large (or Ind.)	2,068,484	183,905,898	1,049	1,971,863	0.0889

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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 Commercial and Industrial Sales
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	Estimated
2	General Service	822	221,507	255	3,224	0.2695
3	Outdoor Lighting	108	38,492			0.3564
4	Street Lighting	8,436	1,928,885	54	156,222	0.2286
5	Unrecovered
6	Kentucky Rider		29
41	TOTAL Billed Public Street and Highway Lighting	9,366	2,188,913	309	30,311	0.2337
42	TOTAL Unbilled Rev. (See Instr. 6)	22	4,377			0.1990
43	TOTAL	9,388	2,193,290	309	30,382	0.2336

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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 Provision For Rate Refunds
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL		5,999,074

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	5,358,481	693,405,446	164,184	2,056,581
42	TOTAL Unbilled Rev. (See Instr. 6) - All Accounts	32,817	4,673,975
43	TOTAL - All Accounts	5,391,298	(a) 698,079,421	164,184	2,056,581

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: RevenueFromSalesOfElectricityByRateSchedulesIncludingUnbilledRevenue


FUEL CLAUSE
Account	DESCR	Total
4400 RES	Estimated	-
	General Service	898
	Outdoor Lighting	566,630
	Residential Load Management‐Time‐of‐Day	65,951
	Residential Service	44,323,354
	Residential Service Time‐of‐Day	2,128
	Unbilled	572,343
	Unrecovered	-
4400 RES Total		45,531,305
4420 COM	Estimated	356
	General Service	14,066,827
	Industrial General Service	8,198,064
	Large General Service	9,415,826
	Large General Service Time‐of‐Day	119,153
	Municipal Waterworks	42,634
	Outdoor Lighting	352,272
	Residential Service	212
	Unbilled	729,575
	Unrecovered	-
4420 COM Total		32,924,920
4420 IND	Contract Service – Interruptible Power	2,261,351
	Estimated	1,951,171
	General Service	587,592
	Industrial General Service	39,033,663
	Large General Service	2,123,564
	Large General Service Time‐of‐Day	65,337
	Outdoor Lighting	18,223
	Unbilled	210,287
	Unrecovered	-
4420 IND Total		46,251,188
4440 PUB	Estimated	-
	General Service	19,737
	Outdoor Lighting	2,636
	Street Lighting	203,812
	Unbilled	910
	Unrecovered	-
4440 PUB Total		227,095
Grand Total		124,934,507

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	AMEREX POWER, LTD	OS	(b) NOTE 1				0		17		17
2	CITIGROUP ENERGY INC.	OS	NOTE 1				0		1,540		1,540
3	CITY OF OLIVE HILL	RQ	KPCO 52				22,042	866,335	1,767,379		2,633,714
4	CITY OF VANCEBURG	RQ	KPCO 51				56,405	2,037,942	4,216,740		6,254,682
5	FIRSTENERGY TRADING SERVICES	OS	NOTE 1				3,134		129,342		(e) 129,342
6	(a) OHIO POWER COMPANY (AUCTION)	OS	(c) NOTE 1				13		374		374
7	PJM INTERCONNECTION	OS	NOTE 1				528,907	3,326,281	49,224,538		52,550,819
8	PJM INTERCONNECTION	RQ	VARIOUS				0			(d) 1,859,683	1,859,683
9	PPL ELECTRIC UTILITIES CORP	OS	NOTE 1				1		42		42
10	WELLS FARGO SECURITIES, LLC	OS	NOTE 1				0		27,454		27,454
15	Subtotal - RQ						78,447	2,904,277	5,984,119	1,859,683	7,028,713
16	Subtotal-Non-RQ						532,027	3,326,281	49,379,361		52,705,642
17	Total						610,474	6,230,558	55,363,480	1,859,683	59,734,355

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: NameOfCompanyOrPublicAuthorityReceivingElectricityPurchasedForResale

An affiliated company

(b) Concept: RateScheduleTariffNumber

FERC Electric Tariff, First Revised Volume No. 5.

(c) Concept: RateScheduleTariffNumber

The PUCO (Public Utilities Commission Ohio) ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning June 2015. APCo, KPCo, I&M and WPCo participated in the auction process and were awarded tranches of OPCo's SSO load.

(d) Concept: OtherChargesRevenueSalesForResale

Amount represents transmission services and related charges

(e) Concept: RevenueFromSalesOfElectricityForResale

Margins for Off System Sales (OSS) reported in KPCO's generation formula rates are included in the total revenue amount. The margins are specifically identified in the ledger as a subset of the accounts that make up these OSS revenues.

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	5,724,888	5,350,713
5	FuelSteamPowerGeneration (501) Fuel	(a) 76,868,710	80,123,189
6	SteamExpensesSteamPowerGeneration (502) Steam Expenses	5,696,813	7,022,880
7	SteamFromOtherSources (503) Steam from Other Sources
8	SteamTransferredCredit (Less) (504) Steam Transferred-Cr.
9	ElectricExpensesSteamPowerGeneration (505) Electric Expenses	182,056	309,758
10	MiscellaneousSteamPowerExpenses (506) Miscellaneous Steam Power Expenses	4,837,943	4,402,732
11	RentsSteamPowerGeneration (507) Rents
12	Allowances (509) Allowances	53,406	68,067
13	SteamPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 4 thru 12)	93,363,816	97,277,339
14	SteamPowerGenerationMaintenanceAbstract Maintenance
15	MaintenanceSupervisionAndEngineeringSteamPowerGeneration (510) Maintenance Supervision and Engineering	1,629,467	1,593,289
16	MaintenanceOfStructuresSteamPowerGeneration (511) Maintenance of Structures	1,949,430	1,693,654
17	MaintenanceOfBoilerPlantSteamPowerGeneration (512) Maintenance of Boiler Plant	13,117,248	11,091,565
18	MaintenanceOfElectricPlantSteamPowerGeneration (513) Maintenance of Electric Plant	4,573,439	3,849,593
19	MaintenanceOfMiscellaneousSteamPlant (514) Maintenance of Miscellaneous Steam Plant	1,027,688	1,431,603
20	SteamPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 15 thru 19)	22,297,272	19,659,705
21	PowerProductionExpensesSteamPower TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)	115,661,088	116,937,044
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
32	RentsNuclearPowerGeneration (525) Rents
33	NuclearPowerGenerationOperationsExpense TOTAL Operation (Enter Total of lines 24 thru 32)
34	NuclearPowerGenerationMaintenanceAbstract Maintenance
35	MaintenanceSupervisionAndEngineeringNuclearPowerGeneration (528) Maintenance Supervision and Engineering
36	MaintenanceOfStructuresNuclearPowerGeneration (529) Maintenance of Structures
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)
41	PowerProductionExpensesNuclearPower TOTAL Power Production Expenses-Nuclear. Power (Enter Total of lines 33 & 40)
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
63	Fuel (547) Fuel
64	GenerationExpenses (548) Generation Expenses
64.1	OperationOfEnergyStorageEquipment (548.1) Operation of Energy Storage Equipment
65	MiscellaneousOtherPowerGenerationExpenses (549) Miscellaneous Other Power Generation Expenses
66	RentsOtherPowerGeneration (550) Rents	86	7
67	OtherPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 62 thru 67)	86	7
68	OtherPowerGenerationMaintenanceAbstract Maintenance
69	MaintenanceSupervisionAndEngineeringOtherPowerGeneration (551) Maintenance Supervision and Engineering
70	MaintenanceOfStructures (552) Maintenance of Structures
71	MaintenanceOfGeneratingAndElectricPlant (553) Maintenance of Generating and Electric Plant
71.1	MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration (553.1) Maintenance of Energy Storage Equipment
72	MaintenanceOfMiscellaneousOtherPowerGenerationPlant (554) Maintenance of Miscellaneous Other Power Generation Plant
73	OtherPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 69 thru 72)
74	PowerProductionExpensesOtherPower TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)	86	7
75	OtherPowerSuplyExpensesAbstract E. Other Power Supply Expenses
76	PurchasedPower (555) Purchased Power	319,873,795	188,731,639
76.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations	0
77	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching	267,090	345,020
78	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	775,363	554,118
79	OtherPowerSupplyExpense TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)	320,916,247	189,630,777
80	PowerProductionExpenses TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74 & 79)	436,577,250	306,567,827
81	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
82	TransmissionExpensesOperationAbstract Operation
83	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	3,116,508	2,675,797
85	LoadDispatchReliability (561.1) Load Dispatch-Reliability
86	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	312,922	309,116
87	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling
88	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services	1,344,678	886,000
89	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development	79,870	126,575
90	TransmissionServiceStudies (561.6) Transmission Service Studies
91	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies
92	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services	352,579	329,196
93	StationExpensesTransmissionExpense (562) Station Expenses	(b) 322,663	191,474
93.1	OperationOfEnergyStorageEquipmentTransmissionExpense (562.1) Operation of Energy Storage Equipment
94	OverheadLineExpense (563) Overhead Lines Expenses	23,984	18,881
95	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses	64,754	1
96	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	67,554,811	60,477,934
97	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	884,015	4,912,907
98	RentsTransmissionElectricExpense (567) Rents	277	350
99	TransmissionOperationExpense TOTAL Operation (Enter Total of Lines 83 thru 98)	74,057,060	69,928,229
100	TransmissionMaintenanceAbstract Maintenance
101	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering	1,519	2,784
102	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	9,614	9,622
103	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware	4,753	5,801
104	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software	132,099	96,782
105	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment	1,709	1,712
106	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	554,346	503,786
107.1	MaintenanceOfEnergyStorageEquipmentTransmission (570.1) Maintenance of Energy Storage Equipment
108	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	5,442,768	6,524,013
109	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines	512	439
110	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant	6,278	18,380
111	TransmissionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 101 thru 110)	6,153,598	7,163,319
112	TransmissionExpenses TOTAL Transmission Expenses (Total of Lines 99 and 111)	80,210,658	77,091,548
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	1,025,103	1,119,915
122	RentsRegionalMarketExpenses (575.8) Rents
123	RegionalMarketOperationExpense Total Operation (Lines 115 thru 122)	1,025,103	1,119,915
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)	1,025,103	1,119,915
132	DistributionExpensesAbstract 4. DISTRIBUTION EXPENSES
133	DistributionExpensesOperationAbstract Operation
134	OperationSupervisionAndEngineeringDistributionExpense (580) Operation Supervision and Engineering	805,659	829,970
135	LoadDispatching (581) Load Dispatching	1,964	3,410
136	StationExpensesDistribution (582) Station Expenses	388,479	259,294
137	OverheadLineExpenses (583) Overhead Line Expenses	351,141	397,079
138	UndergroundLineExpenses (584) Underground Line Expenses	238,861	152,750
138.1	OperationOfEnergyStorageEquipmentDistribution (584.1) Operation of Energy Storage Equipment
139	StreetLightingAndSignalSystemExpenses (585) Street Lighting and Signal System Expenses	46,816	78,060
140	MeterExpenses (586) Meter Expenses	1,229,732	1,151,401
141	CustomerInstallationsExpenses (587) Customer Installations Expenses	200,910	193,715
142	MiscellaneousDistributionExpenses (588) Miscellaneous Expenses	3,192,387	2,424,122
143	RentsDistributionExpense (589) Rents	933,528	242,074
144	DistributionOperationExpensesElectric TOTAL Operation (Enter Total of Lines 134 thru 143)	7,389,477	5,731,876
145	DistributionExpensesMaintenanceAbstract Maintenance
146	MaintenanceSupervisionAndEngineering (590) Maintenance Supervision and Engineering	5,110	26,434
147	MaintenanceOfStructuresDistributionExpense (591) Maintenance of Structures	20,773	8,122
148	MaintenanceOfStationEquipment (592) Maintenance of Station Equipment	337,440	683,774
148.1	MaintenanceOfEnergyStorageEquipment (592.2) Maintenance of Energy Storage Equipment
149	MaintenanceOfOverheadLines (593) Maintenance of Overhead Lines	33,194,092	33,683,296
150	MaintenanceOfUndergroundLines (594) Maintenance of Underground Lines	48,395	19,443
151	MaintenanceOfLineTransformers (595) Maintenance of Line Transformers	23,586	52,827
152	MaintenanceOfStreetLightingAndSignalSystems (596) Maintenance of Street Lighting and Signal Systems	20,854	8,742
153	MaintenanceOfMeters (597) Maintenance of Meters	33,477	50,515
154	MaintenanceOfMiscellaneousDistributionPlant (598) Maintenance of Miscellaneous Distribution Plant	25,517	20,541
155	DistributionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 146 thru 154)	33,709,244	34,536,210
156	DistributionExpenses TOTAL Distribution Expenses (Total of Lines 144 and 155)	41,098,721	40,268,086
157	CustomerAccountsExpensesAbstract 5. CUSTOMER ACCOUNTS EXPENSES
158	CustomerAccountsExpensesOperationsAbstract Operation
159	SupervisionCustomerAccountExpenses (901) Supervision	17,398	22,750
160	MeterReadingExpenses (902) Meter Reading Expenses	453,585	554,574
161	CustomerRecordsAndCollectionExpenses (903) Customer Records and Collection Expenses	5,184,728	5,557,980
162	UncollectibleAccounts (904) Uncollectible Accounts	3,299,981	36,810
163	MiscellaneousCustomerAccountsExpenses (905) Miscellaneous Customer Accounts Expenses	17,532	26,769
164	CustomerAccountExpenses TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)	8,973,225	6,125,263
165	CustomerServiceAndInformationalExpensesAbstract 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166	CustomerServiceAndInformationalExpensesOperationAbstract Operation
167	SupervisionCustomerServiceAndInformationExpenses (907) Supervision	164,653	43,142
168	CustomerAssistanceExpenses (908) Customer Assistance Expenses	1,309,985	1,351,901
169	InformationalAndInstructionalAdvertisingExpenses (909) Informational and Instructional Expenses	31,067	94,779
170	MiscellaneousCustomerServiceAndInformationalExpenses (910) Miscellaneous Customer Service and Informational Expenses	32,119	36,307
171	CustomerServiceAndInformationExpenses TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)	1,537,824	1,526,129
172	SalesExpenseAbstract 7. SALES EXPENSES
173	SalesExpenseOperationAbstract Operation
174	SupervisionSalesExpense (911) Supervision
175	DemonstratingAndSellingExpenses (912) Demonstrating and Selling Expenses	48,529	40,621
176	AdvertisingExpenses (913) Advertising Expenses		10,703
177	MiscellaneousSalesExpenses (916) Miscellaneous Sales Expenses
178	SalesExpenses TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)	48,529	51,323
179	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
180	AdministrativeAndGeneralExpensesOperationAbstract Operation
181	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	10,604,895	10,584,485
182	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	743,867	510,863
183	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit	927,681	1,108,389
184	OutsideServicesEmployed (923) Outside Services Employed	4,206,731	2,602,573
185	PropertyInsurance (924) Property Insurance	(c) 960,402	879,125
186	InjuriesAndDamages (925) Injuries and Damages	1,517,535	2,117,373
187	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	2,135,543	1,132,660
188	FranchiseRequirements (927) Franchise Requirements	139,548	139,814
189	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	2,390,590	1,919,336
190	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.
191	GeneralAdvertisingExpenses (930.1) General Advertising Expenses	295,365	226,697
192	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	1,424,413	966,171
193	RentsAdministrativeAndGeneralExpense (931) Rents	243,073	256,777
194	AdministrativeAndGeneralOperationExpense TOTAL Operation (Enter Total of Lines 181 thru 193)	16,428,125	20,227,484
195	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
196	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	2,664,059	2,993,639
197	AdministrativeAndGeneralExpenses TOTAL Administrative & General Expenses (Total of Lines 194 and 196)	19,092,184	23,221,123
198	OperationsAndMaintenanceExpensesElectric TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 156, 164, 171, 178, and 197)	588,563,493	455,971,214

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: FuelSteamPowerGeneration

The portion of account 501 that is excluded from the fuel costs in KPCo's generation formula rate is identified by a query of the general ledger.

(b) Concept: StationExpensesTransmissionExpense

Generation Step-Up Units' (GSUs) O&M expenses included in KPCo's generation formula rate are the ratio of GSU balances to all investment for plant accounts 352 & 353 multiplied by the balance in O&M accounts 562,569 & 570.

(c) Concept: PropertyInsurance

The insurance expenses for generation included in KPCo's generation formula rate are identified by a query of the general ledger.

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	(a) AEP GENERATING COMPANY	RQ	AEG 2				735,451				64,008,478	28,929,635		92,938,113
2	PJM INTERCONNECTION	OS					3,436,567					240,291,526		240,291,526
3	(b) ROCKPORT PURCHASE POWER	OS									13,355,845			13,355,845
15	TOTAL						4,172,018	0	0	0	50,652,633	269,221,161		319,873,794

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: NameOfCompanyOrPublicAuthorityProvidingPurchasedPower

Affiliated Company

(b) Concept: NameOfCompanyOrPublicAuthorityProvidingPurchasedPower

Per KPSC Order Case No. 2017-00179, KPCO defers a portion of the non-fuel, non-environmental lease expenses incurred for Rockport Unit 2.

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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.

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

(m)

(n)

1

PJM Network Integ Trans Rev Whlsle

Various

FNO

(a)

PJM OATT

Various

2,692,690

2

PJM Network Integ Trans Serv

Various

FNO

PJM OATT

Various

10,913,063

3

PJM Trans Enhancement Rev

Various

FNO

PJM OATT

Various

1,867,294

4

PJM Trans Enhancement Rev Whlsle

Various

FNO

PJM OATT

Various

59,931

5

PJM Trans Enhancement Rev - Affil

Various

FNO

PJM OATT

Various

438,960

6

PJM Network Integ Rev - Affil

Various

FNO

PJM OATT

Various

21,961,161

7

PJM Point to Point Trans Service

Various

LFP

PJM OATT

Various

1,795,364

8

PJM Trans Owner Admin Revenue

Various

OLF

PJM OATT

Various

16,972

9

PJM Trans Owner Serv Rev Whlsle

Various

OLF

PJM OATT

Various

10,490

10

PJM Power Factor Credits Rev Whlsle

Various

OS

PJM OATT

Various

(b)

7,651

11

PJM Trans Owner Serv - Affil

Various

OLF

PJM OATT

Various

62,425

12

East Kentucky Power Cooperative

Various

OLF

PJM OATT

Various

(c)

54,902

35

TOTAL

0

39,728,463

34,963

62,553

39,825,979

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: RateScheduleTariffNumber

Effective October 1, 2004, the administration of the transmission tariff was turned over to PJM. PJM does not provide any detail except for the total revenue by the major classes listed. OATT (Open Access Transmission Tariff) 3rd revised Volume No. 6

(b) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Per Proforma ILDSA (Interconnection and Local Delivery Service Agreement) AEP Tariff 3rd Revised Volume No. 6

(c) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Compensation should be at a rate of one and one-half (1.5) mils per kilowatt-hour for energy delivered pursuant to Appendix IV of PJM Service Agreement No. 1530, the Interconnection Agreement between AEPSC and East Kentucky Power Cooperative.

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	Concurrent Energy	LFP					(a) 132,102	132,102
2	East KY Power Coop
3	PJM - Enhancements	OS					(b) 6,935,416	6,935,416
4	PJM - NITS	OS					(c) 60,368,472	60,368,472
5	PJM - Trans Owner	OS					(d) 118,821	118,821
	TOTAL		0	0	0	0	67,554,811	67,554,811

FOOTNOTE DATA

(a) Concept: OtherChargesTransmissionOfElectricityByOthers

Concurrent Energy Charges from East Kentucky Power.

(b) Concept: OtherChargesTransmissionOfElectricityByOthers

Transmission Enhancement Charges and Credits (PJM OATT Schedule 12)

(c) Concept: OtherChargesTransmissionOfElectricityByOthers

Network Integration Transmission Service Charges - NITS (PJM OATT Schedule H)

(d) Concept: OtherChargesTransmissionOfElectricityByOthers

Transmission Owner Service (PJM OATT Tariff Sixth Revised Volume No. 1)

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line No.	Description (a)	Amount (b)
1	IndustryAssociationDues Industry Association Dues	127,636
2	NuclearPowerResearchExpenses Nuclear Power Research Expenses
3	OtherExperimentalAndGeneralResearchExpenses Other Experimental and General Research Expenses	416
4	PublicationAndDistributionExpensesForSecuritiesToStockholders Pub and Dist Info to Stkhldrs...expn servicing outstanding Securities
5	OtherMiscellaneousGeneralExpenses Oth Expn greater than or equal to 5,000 show purpose, recipient, amount. Group if less than $5,000
6	Asociated Business Development	1,015,533
7	AEP Service Corporation Billings	151,822
8	Intercompany Allocations	50,380
9	Corporate Money Pool Allocations	85,157
10	Corporate and Fiscal	82,726
11	Miscellaneous	11,503
46	MiscellaneousGeneralExpenses TOTAL	1,424,413

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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			9,687,647		9,687,647
2	Steam Production Plant	36,713,390	58,339			36,771,729
3	Nuclear Production Plant
4	Hydraulic Production Plant-Conventional
5	Hydraulic Production Plant-Pumped Storage
6	Other Production Plant
7	Transmission Plant	21,547,903				21,547,903
8	Distribution Plant	36,408,097				36,408,097
9	Regional Transmission and Market Operation
10	General Plant	3,993,048				3,993,048
11	Common Plant-Electric
12	TOTAL	98,662,438	58,339	9,687,647		108,408,424

B. Basis for Amortization Charges
Section A Line 1 Column D represents amortization of capitalized software development costs over a 5 year life and costs associated with the Oracle strategic partnership which are over a 10 year life.

	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	STEAM -- COAL/LIGNITE
13	311 - Big Sandy	24.389
14	311 - Mitchell	57.416
15	312 - Big Sandy	77.749
16	312 - Mitchell	884.212
17	312 - Mitchell SCR	9.156
18	314 - Big Sandy	63.139
19	314 - Mitchell	55.565
20	315 - Big Sandy	6.359
21	315 - Mitchell	26.141
22	316 - Big Sandy	4.553
23	316 - Mitchell	9.434
24	TOTAL COAL/LIGNITE	1,218.113
25	TRANSMISSION
26	350.1	34.757
27	352	14.768
28	352 - Big Sandy	0.01
29	352 - Mitchell	0.072
30	353	252.457
31	353 - Big Sandy	0.603
32	353 - Mitchell	12.303
33	353.16	6.122
34	354	101.3
35	355	196.501
36	356	163.568
37	356.16	4.579
38	357	0.511
39	358	0.106
40	358.16	0.275
41	TOTAL TRANSMISSION	787.932
42	DISTRIBUTION
43	360.1	5.789
44	361	9.375
45	362	140.394
46	362.16	3.549
47	364	283.193
48	365	308.087
49	366	9.694
50	367	12.744
51	368	157.102
52	369	73.541
53	370	25.397
54	371	19.811
55	373	4.951
56	TOTAL DISTRIBUTION	303.24
57	GENERAL PLANT
58	389.1	0.036
59	390	27.86
60	391	2.734
61	391.11	0.491
62	392	19.899
63	393	0.305
64	394	6.977
65	395	0.21
66	396	1.269
67	397	37.898
68	397.16	1.504
69	398	2.448
70	TOTAL GENERAL	101.631
71	DEPRECIABLE SUM	(a) 407.605
72	TOTAL DISTRIBUTION	1,053.627
73	TOTAL GENERAL	101.631
74	DEPRECIABLE SUM	(b) 3,161.303

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: DepreciablePlantBase

The depreciable plant base is the November 30, 2022 total company depreciable plant.

(b) Concept: DepreciablePlantBase

The depreciable plant base is the November 30, 2022 total company depreciable plant.

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	2016 - Kentucky Power Rate Case
2	KPSC - Case No. 2016-00180
3	2019 Kentucky IRP Plan		1,051,490	1,051,490		Electric	928	1,051,490
4	Minor Items < $25,000		80,934	80,934		Electric	928	80,934
5	2020 - Kentucky Power Base Case		172,084	172,084	228,431	Electric	928	59,830	2,332	928	112,254	118,509
6	KPSC - Case No. 2020-00174
7	Kentucky PSC Investigation		38,485	38,485		Electric	928	38,485
8	Kentucky AMI Program Filing		373	373		Electric	928	373
9	Kentucky Solar Filing		11,563	11,563		Electric	928	11,563
10	State Commission Fees		982,320	982,320		Electric	928	982,320
11	22 KYP Case Rockport Deferral		17,472	17,472		Electric	928	17,472
12	AEPSC KY Power Ebon Case		8,016	8,016		Electric	928	8,016
13	23 KYP Base Rate Case Filing		27,853	27,853		Electric	928	27,853
46	TOTAL		2,390,590	2,390,590	228,431			2,278,336	2,332		112,254	118,509

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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(1)b: Generation: Fossil-Fuel Steam	Generation Asset Management	43,572		506	43,572
2		1 items under $50,000	507		506	507
3	A(1)e: Generation: Unconventional	1 item under $50,000
4	A(2): Transmission	1 item under $50,000	2,796		566	2,796
5	A(3): Distribution	1 items under $50,000	4,239		588	4,239
6	A(5): Environment (other than equipment)	1 items under $50,000	97		506	97
7	A(6): Other	2 items under $50,000	11,265		506,566,588	11,265
8	A(6)a: Alternate Energy	1 item under $50,000
9	A(6)f: Other (Metering)	1 item under $50,000	578		588	578
10	A(6)g: Other (program management)	1 item under $50,000	1,139		566,588	1,139
11	B: Electric R&D External	6 items under $50,000		21,020	506,566,588	21,020
12	B(1): R&D support to the Research Council	EPRI Annual Portfolio		114,820	506	114,820
13	or the Electric Power Research	Transmission EPRI Portfolio		77,433	566	77,433
14		EPRI Environmental Science		153,731	506	153,731
15	Institute	28 items under $50,000		137,586	506,566,588	137,586
16	B(4): Research Support to Others	1 items under $50,000		7,679	506	7,679

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	7,180,820
4	SalariesAndWagesElectricOperationTransmission Transmission	3,342
5	SalariesAndWagesElectricOperationRegionalMarket Regional Market
6	SalariesAndWagesElectricOperationDistribution Distribution	3,041,210
7	SalariesAndWagesElectricOperationCustomerAccounts Customer Accounts	999,859
8	SalariesAndWagesElectricOperationCustomerServiceAndInformational Customer Service and Informational	180,454
9	SalariesAndWagesElectricOperationSales Sales
10	SalariesAndWagesElectricOperationAdministrativeAndGeneral Administrative and General	2,382,997
11	SalariesAndWagesElectricOperation TOTAL Operation (Enter Total of lines 3 thru 10)	13,788,682
12	SalariesAndWagesElectricMaintenanceAbstract Maintenance
13	SalariesAndWagesElectricMaintenanceProduction Production	4,693,041
14	SalariesAndWagesElectricMaintenanceTransmission Transmission	526
15	SalariesAndWagesElectricMaintenanceRegionalMarket Regional Market
16	SalariesAndWagesElectricMaintenanceDistribution Distribution	5,585,982
17	SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral Administrative and General	377,789
18	SalariesAndWagesElectricMaintenance TOTAL Maintenance (Total of lines 13 thru 17)	10,657,338
19	SalariesAndWagesElectricOperationAndMaintenanceAbstract Total Operation and Maintenance
20	SalariesAndWagesElectricProduction Production (Enter Total of lines 3 and 13)	11,873,861
21	SalariesAndWagesElectricTransmission Transmission (Enter Total of lines 4 and 14)	3,868
22	SalariesAndWagesElectricRegionalMarket Regional Market (Enter Total of Lines 5 and 15)
23	SalariesAndWagesElectricDistribution Distribution (Enter Total of lines 6 and 16)	8,627,192
24	SalariesAndWagesElectricCustomerAccounts Customer Accounts (Transcribe from line 7)	999,859
25	SalariesAndWagesElectricCustomerServiceAndInformational Customer Service and Informational (Transcribe from line 8)	180,454
26	SalariesAndWagesElectricSales Sales (Transcribe from line 9)
27	SalariesAndWagesElectricAdministrativeAndGeneral Administrative and General (Enter Total of lines 10 and 17)	2,760,786
28	SalariesAndWagesElectricOperationAndMaintenance TOTAL Oper. and Maint. (Total of lines 20 thru 27)	24,446,020	1,612,638	26,058,658
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)	24,446,020	1,612,638	26,058,658
66	SalariesAndWagesUtilityPlantAbstract Utility Plant
67	SalariesAndWagesUtilityPlantConstructionAbstract Construction (By Utility Departments)
68	SalariesAndWagesUtilityPlantConstructionElectricPlant Electric Plant	13,066,718	861,977	13,928,695
69	SalariesAndWagesUtilityPlantConstructionGasPlant Gas Plant
70	SalariesAndWagesUtilityPlantConstructionOther Other (provide details in footnote):
71	SalariesAndWagesUtilityPlantConstruction TOTAL Construction (Total of lines 68 thru 70)	13,066,718	861,977	13,928,695
72	SalariesAndWagesPlantRemovalAbstract Plant Removal (By Utility Departments)
73	SalariesAndWagesPlantRemovalElectricPlant Electric Plant	2,764,909	182,394	2,947,303
74	SalariesAndWagesPlantRemovalGasPlant Gas Plant
75	SalariesAndWagesPlantRemovalOther Other (provide details in footnote):
76	SalariesAndWagesPlantRemoval TOTAL Plant Removal (Total of lines 73 thru 75)	2,764,909	182,394	2,947,303
77	SalariesAndWagesOtherAccountsAbstract Other Accounts (Specify, provide details in footnote):
78	SalariesAndWagesOtherAccountsDescription Other Accounts (Specify, provide details in footnote):
79	SalariesAndWagesOtherAccountsDescription 152 - Fuel Stock Undistributed	1,881,790		1,881,790
80	SalariesAndWagesOtherAccountsDescription 154 - Materials and Supplies
81	SalariesAndWagesOtherAccountsDescription 163 - Stores Expense Undistributed	1,363,331	1,363,331
82	SalariesAndWagesOtherAccountsDescription 165 - Other Prepayments
83	SalariesAndWagesOtherAccountsDescription 182 - Other Regulatory Assets
84	SalariesAndWagesOtherAccountsDescription 183 - Prelim Survey	5,756	5,756
85	SalariesAndWagesOtherAccountsDescription 184 - Clearing Accounts	1,299,434	1,299,434
86	SalariesAndWagesOtherAccountsDescription 185 - ODD Temporary Facilities	56,676		56,676
87	SalariesAndWagesOtherAccountsDescription 186 - Misc Deferred Debits	6,843		6,843
88	SalariesAndWagesOtherAccountsDescription 402 - Maintenance Exp
89	SalariesAndWagesOtherAccountsDescription 407 - Regulatory Debits
90	SalariesAndWagesOtherAccountsDescription 417 - Misc Exp
91	SalariesAndWagesOtherAccountsDescription 418 - Nonoperating Rental Income
92	SalariesAndWagesOtherAccountsDescription 421 - Misc Nonoperating Income
93	SalariesAndWagesOtherAccountsDescription 426 - Political Activities	17,057		17,057
94	SalariesAndWagesOtherAccountsDescription 451 - Misc Service Rev - Nonaffil
95	SalariesAndWagesOtherAccountsDescription 456 - Other Electric Revenue
95	SalariesAndWagesOtherAccounts TOTAL Other Accounts	4,619,375	2,657,009	1,962,366
96	SalariesAndWagesGeneralExpense TOTAL SALARIES AND WAGES	44,897,022		44,897,022

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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.

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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)				228,800,522
2.1	Net Purchases (Account 555.1)
3	Net Sales (Account 447)				46,241,300
4	Transmission Rights				16,501,636
5	Ancillary Services				304,493
6	Other Items (list separately)
7	Congestion				14,358,376
8	Operating Reserves				1,158,677
9	Transmission Purchase Expense				1,859,688
10	Transmission Losses				10,289,116
11	Meter Corrections				705,219
12	Inadvertent				197,490
13	Capacity Credits				3,326,281
46	TOTAL				189,798,946

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	(a) 0
2	Reactive Supply and Voltage
3	Regulation and Frequency Response
4	Energy Imbalance
5	Operating Reserve - Spinning
6	Operating Reserve - Supplement
7	Other
8	Total (Lines 1 thru 7)

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: AncillaryServicesPurchasedNumberOfUnits

The final grandfathered contracts (under the AEP OATT) expired 12/31/2010. Currently, services are provided under the SPP and PJM OATTs.

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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: 0
1	January	(a) 0
2	February
3	March
4	Total for Quarter 1				0	0	0	0	0	0
5	April
6	May
7	June
8	Total for Quarter 2				0	0	0	0	0	0
9	July
10	August
11	September
12	Total for Quarter 3				0	0	0	0	0	0
13	October
14	November
15	December
16	Total for Quarter 4				0	0	0	0	0	0
17	Total				0	0	0	0	0	0

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: MonthlyPeakLoadExcludingIsoAndRto

Kentucky Power Company's transmission service is administered through an RTO/ISO and requested information is not available on an individual operating company basis.

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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: 0
1	January
2	February
3	March
4	Total for Quarter 1				0	0	0	0	0	0
5	April
6	May
7	June
8	Total for Quarter 2				0	0	0	0	0	0
9	July
10	August
11	September
12	Total for Quarter 3				0	0	0	0	0	0
13	October
14	November
15	December
16	Total for Quarter 4				0	0	0	0	0	0
17	Total Year to Date/Year				0	0	0	0	0	0

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

2023-04-12

Year/Period of Report

End of:

2022

/

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)	5,391,298
3	Steam	2,261,055	23	Requirements Sales for Resale (See instruction 4, page 311.)	78,447
4	Nuclear		24	Non-Requirements Sales for Resale (See instruction 4, page 311.)	532,027
5	Hydro-Conventional		25	Energy Furnished Without Charge
6	Hydro-Pumped Storage		26	Energy Used by the Company (Electric Dept Only, Excluding Station Use)
7	Other		27	Total Energy Losses	431,301
8	Less Energy for Pumping		27.1	Total Energy Stored
9	Net Generation (Enter Total of lines 3 through 8)	2,261,055	28	TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL LINE 20 UNDER SOURCES	6,433,073
10	Purchases (other than for Energy Storage)	4,172,018
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
17	Delivered
18	Net Transmission for Other (Line 16 minus line 17)	0
19	Transmission By Others Losses
20	TOTAL (Enter Total of Lines 9, 10, 10.1, 14, 18 and 19)	6,433,073

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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: 0
29	January	708,096	85,603	1,187	27	8
30	February	532,951	27,024	1,081	15	8
31	March	490,452	13,892	1,049	13	9
32	April	488,510	72,352	812	20	8
33	May	487,711	45,149	897	31	16
34	June	538,730	56,192	996	16	16
35	July	619,177	106,445	939	12	16
36	August	586,454	83,781	935	9	15
37	September	442,298	7,365	880	21	17
38	October	443,853	8,784	863	20	9
39	November	492,648	18,354	1,037	21	8
40	December	602,193	29,381	1,359	23	21
41	Total	6,433,073	554,322

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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: 0	Plant Name: Big Sandy	Plant Name: Mitchell- Total	Plant Name: (a) Mitchell-KEPCo Share
1	PlantKind Kind of Plant (Internal Comb, Gas Turb, Nuclear)		STEAM	STEAM	STEAM
2	PlantConstructionType Type of Constr (Conventional, Outdoor, Boiler, etc)		CONVENTIONAL	OUTDOOR BOILER	OUTDOOR BOILER
3	YearPlantOriginallyConstructed Year Originally Constructed		1963	1971	1971
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed		2016	1971	1971
5	InstalledCapacityOfPlant Total Installed Cap (Max Gen Name Plate Ratings-MW)		280.50	1,633.00	817.00
6	NetPeakDemandOnPlant Net Peak Demand on Plant - MW (60 minutes)		296	1,574	787
7	PlantHoursConnectedToLoad Plant Hours Connected to Load		3,213	958	958
8	NetContinuousPlantCapability Net Continuous Plant Capability (Megawatts)		0		0
9	NetContinuousPlantCapabilityNotLimitedByCondenserWater When Not Limited by Condenser Water		295	1,560	780
10	NetContinuousPlantCapabilityLimitedByCondenserWater When Limited by Condenser Water		295	1,560	780
11	PlantAverageNumberOfEmployees Average Number of Employees		25	309	154
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh		509,961,000	3,502,186,000	1,751,093,000
13	CostOfLandAndLandRightsSteamProduction Cost of Plant: Land and Land Rights		1,734,844	6,197,188	3,098,594
14	CostOfStructuresAndImprovementsSteamProduction Structures and Improvements		24,414,231	114,658,466	57,416,483
15	CostOfEquipmentSteamProduction Equipment Costs		152,066,033	1,975,214,424	986,041,982
16	AssetRetirementCostsSteamProduction Asset Retirement Costs		6,618,088	11,057,543	4,618,331
17	CostOfPlant Total cost (total 13 thru 20)		184,833,196	2,107,127,621	1,051,175,390
18	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 17/5) Including		658.9419	1,290.3415	1,286.6284
19	OperationSupervisionAndEngineeringExpense Production Expenses: Oper, Supv, & Engr		2,544,916	5,647,624	3,179,971
20	FuelSteamPowerGeneration Fuel		35,169,943	113,322,640	56,724,059
21	CoolantsAndWater Coolants and Water (Nuclear Plants Only)		0		0
22	SteamExpensesSteamPowerGeneration Steam Expenses		162	11,393,278	5,696,651
23	SteamFromOtherSources Steam From Other Sources		0		0
24	SteamTransferredCredit Steam Transferred (Cr)		0		0
25	ElectricExpensesSteamPowerGeneration Electric Expenses		1	364,109	182,056
26	MiscellaneousSteamPowerExpenses Misc Steam (or Nuclear) Power Expenses		1,633,265	6,054,364	3,204,678
27	RentsSteamPowerGeneration Rents		0		0
28	Allowances Allowances		4,592	45,600	48,814
29	MaintenanceSupervisionAndEngineeringSteamPowerGeneration Maintenance Supervision and Engineering		381,489	2,485,553	1,247,979
30	MaintenanceOfStructuresSteamPowerGeneration Maintenance of Structures		1,247,275	1,404,041	702,155
31	MaintenanceOfBoilerPlantSteamPowerGeneration Maintenance of Boiler (or reactor) Plant		2,357,333	21,350,029	10,759,915
32	MaintenanceOfElectricPlantSteamPowerGeneration Maintenance of Electric Plant		2,055,817	5,035,310	2,517,622
33	MaintenanceOfMiscellaneousSteamPlant Maintenance of Misc Steam (or Nuclear) Plant		314,569	1,427,781	713,119
34	PowerProductionExpensesSteamPower Total Production Expenses	0	45,709,362	168,530,329	84,977,019
35	ExpensesPerNetKilowattHour Expenses per Net kWh		0.0896	0.0481	0.0485

35	FuelKindAxis Plant Name	Big Sandy	Mitchell- Total	Mitchell- Total	Mitchell-KEPCo Share	Mitchell-KEPCo Share
36	FuelKind Fuel Kind	Gas	Coal	Oil	Coal	Oil
37	FuelUnit Fuel Unit	Mcf	t	Boe	t	Boe
38	QuantityOfFuelBurned Quantity (Units) of Fuel Burned	4,296,269	1,523,492	62,205	761,746	32,294
39	FuelBurnedAverageHeatContent Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)	1,211,000	12,444	125,839	12,444	125,839
40	AverageCostOfFuelPerUnitAsDelivered Avg Cost of Fuel/unit, as Delvd f.o.b. during year	6.762	64.492	152.075	64.492	152.075
41	AverageCostOfFuelPerUnitBurned Average Cost of Fuel per Unit Burned	14.057	59.643	142.292	59.643	137.042
42	AverageCostOfFuelBurnedPerMillionBritishThermalUnit Average Cost of Fuel Burned per Million BTU	11.608	2.396	26.923	2.396	25.929
43	AverageCostOfFuelBurnedPerKilowattHourNetGeneration Average Cost of Fuel Burned per kWh Net Gen	0.118	0.026	0.000	0.026	0.000
44	AverageBritishThermalUnitPerKilowattHourNetGeneration Average BTU per kWh Net Generation	10,358	10,913.000	0.000	10,913	0.000

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: PlantName

Plant Name: Mitchell - This plant is owned jointly by Respondent and Wheeling Power Company, also a subsidiary of American Electric Power, Inc.

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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)	0
6	PlantHoursConnectedToLoad Plant Hours Connect to Load While Generating	0
7	NetContinuousPlantCapability Net Plant Capability (in megawatts)	0
8	PlantAverageNumberOfEmployees Average Number of Employees
9	NetGenerationExcludingPlantUse Generation, Exclusive of Plant Use - kWh	0
10	EnergyUsedForPumping Energy Used for Pumping
11	NetOutputForLoad Net Output for Load (line 9 - line 10) - Kwh	0
12	CostOfPlantAbstract Cost of Plant
13	CostOfLandAndLandRightsPumpedStoragePlant Land and Land Rights
14	CostOfStructuresAndImprovementsPumpedStoragePlant Structures and Improvements	0
15	CostOfReservoirsDamsAndWaterwaysPumpedStoragePlant Reservoirs, Dams, and Waterways	0
16	CostOfWaterWheelsTurbinesAndGeneratorsPumpedStoragePlant Water Wheels, Turbines, and Generators	0
17	CostOfAccessoryElectricEquipmentPumpedStoragePlant Accessory Electric Equipment	0
18	CostOfMiscellaneousPowerPlantEquipmentPumpedStoragePlant Miscellaneous Powerplant Equipment	0
19	CostOfRoadsRailroadsAndBridgesPumpedStoragePlant Roads, Railroads, and Bridges	0
20	AssetRetirementCostsPumpedStoragePlant Asset Retirement Costs	0
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	0
25	WaterForPower Water for Power	0
26	PumpedStorageExpenses Pumped Storage Expenses	0
27	ElectricExpensesPumpedStoragePlant Electric Expenses	0
28	MiscellaneousPumpedStoragePowerGenerationExpenses Misc Pumped Storage Power generation Expenses	0
29	RentsPumpedStoragePlant Rents	0
30	MaintenanceSupervisionAndEngineeringPumpedStoragePlant Maintenance Supervision and Engineering	0
31	MaintenanceOfStructuresPumpedStoragePlant Maintenance of Structures	0
32	MaintenanceOfReservoirsDamsAndWaterwaysPumpedStoragePlant Maintenance of Reservoirs, Dams, and Waterways	0
33	MaintenanceOfElectricPlantPumpedStoragePlant Maintenance of Electric Plant	0
34	MaintenanceOfMiscellaneousPumpedStoragePlant Maintenance of Misc Pumped Storage Plant	0
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:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	0700 BIG SANDY, KY	AMOS WV	765.00	765.00	3	0.13	0	1	954 MCMA
2	0701 BIG SANDY, KY	SARGENTS, OH	765.00	765.00	3	24.20	0	1	954 MCMA
3	0701 BIG SANDY, KY	SARGENTS, OH	765.00	765.00	3	4.79	0	1
4	0702 BIG SANDY, KY	BROADFORD, VA	765.00	765.00	3	12.65	0	1	4-954 KCM ACSR
5	0702 BIG SANDY, KY	BROADFORD, VA	765.00	765.00	3	3.04	0	1
6	0702 BIG SANDY, KY	BROADFORD, VA	765.00	765.00	3	58.26	0	1
7	0703 HANGING ROCK, OH	JEFFERSON, IN	765.00	765.00	3	154.74	0	1	1351.5 KCM ACSR
8	0300 BIG SANDY, KY	TRI-STATE, WV	345.00	345.00	3	8.36	0	1	954 KCM ACSR
9	0600 HAZARD, KY	PINEVILLE, KY	161.00	161.00	1	0.33	0	1	500 KCM CU
10	0600 HAZARD, KY	PINEVILLE, KY	161.00	161.00	2	37.08	0	1	500 KCM CU
11	0600 HAZARD, KY	PINEVILLE, KY	161.00	161.00	3	0.06	0	1	795 KCM ACSR
12	0600 HAZARD, KY	PINEVILLE, KY	161.00	161.00	2	0.96	0	2	795 KCM ACSR
13	0135 WOOTEN	ARNOLD DELVINTA (LGE)	161.00	161.00	1	1.09	0	1	795 KCM ACSR
14	0136 WOOTEN EXTENSION		161.00	161.00	1	0.04	0	1	795 KCM ACSR
15	0143 HAZARD	WOOTON	161.00	161.00	1	0.60	0	1	795 KCM ACSR
16	0143 HAZARD	WOOTON	161.00	161.00	1	0.98	0	2	795 KCM ACSR
17	0143 HAZARD	WOOTON	161.00	161.00	3	0.26	0	2	795 KCM ACSR
18	0143 HAZARD	WOOTON	161.00	161.00	3	1.16	0	1	795 KCM ACSR
19	0143 HAZARD	WOOTON	161.00	161.00	2	3.58	0	1	795 KCM ACSR
20	0100 BIG SANDY, KY	BELLEFONTE	138.00	138.00	3	12.08	0	1	2-556.5 KCM ACSR
21	0100 BIG SANDY, KY	BELLEFONTE	138.00	138.00	3	14.77	0	2	795 KCM ACSR
22	0100 BIG SANDY, KY	BELLEFONTE	138.00	138.00	0	0.00	0	0	2-556.5 KCM ACSR
23	0100 BIG SANDY, KY	BELLEFONTE	138.00	138.00	3	0.32	0	1	1272 ACSS
24	0101 BIG SANDY, KY	W HUNTINGTON, WV	138.00	138.00	3	0.33	0	1	1033.5 KCM ACSR
25	0102 BELLEFONTE, KY	N PROCTORVILLE, OH	138.00	138.00	3	0.81	0	2	795 KCM ACSR
26	0103 HAZARD, KY	BEAVER CREEK, KY	138.00	138.00	3	5.91	0	1	397.5 MCMCU
27	0103 HAZARD, KY	BEAVER CREEK, KY	138.00	138.00	3	23.25	0	1
28	0105 CLINCH RIVER, VA	BEAVER CREEK, KY	138.00	138.00	3	2.30	0	1	636 MCMA
29	0105 CLINCH RIVER, VA	BEAVER CREEK, KY	138.00	138.00	1	16.09	17	1
30	0107 LOGAN, WV	SPRIGG, KY	138.00	138.00	3	0.48	0	2	397 MCMA
31	0110 BEAVER CREEK, KY	BIG SANDY, KY	138.00	138.00	2	1.48	0	1	954KCM ACSR
32	0110 BEAVER CREEK, KY	BIG SANDY, KY	138.00	138.00	2	3.31	0	1	795KCM ACSR
33	0110 BEAVER CREEK, KY	BIG SANDY, KY	138.00	138.00	3	30.88	0	1	636KCM ACSR
34	0110 BEAVER CREEK, KY	BIG SANDY, KY	138.00	138.00	2	22.86	0	1	636KCM ACSR
35	0110 BEAVER CREEK, KY	BIG SANDY, KY	138.00	138.00	1	0.01	0	1	636KCM ACSR
36	0111 TRI STATE, WV	BELLEFONTE, KY	138.00	138.00	3	0.71	14	1	795 MCMA
37	0111 TRI STATE, WV	BELLEFONTE, KY	138.00	138.00	1	0.38	0	1
38	0113 CHADWICK	KY ELECTRIC STEEL	138.00	138.00	1	8.09	0	1	795 MCMA
39	0115 CHADWICK	COALTON	138.00	138.00	1	0.98	0	1	795 MCMA
40	0133 CHADWICK EXTENSION		138.00	138.00		1.06	0	1	795KCM ACSR
41	0117 MILBROOK PARK, OH	FULLERTON	138.00	138.00	1	5.08	2	1	556.5 MCM
42	0116 BEAVER CREEK	SPICEWOOD	138.00	138.00	1	25.83	0	1	795 MCMA
43	0116 BEAVER CREEK	SPICEWOOD	138.00	138.00	3	0.63	0	0	1590 KCM
44	0120 HATFIELD	SPRIGG	138.00	138.00	1	5.88	0	1	1033 MCM
45	0121 HATFIELD	INEZ	138.00	138.00	1	14.67	0	1	1033.5 VAR
46	0122 INEZ	LOVELY	138.00	138.00	1	6.86	0	1	1033.5 VAR
47	0126 INEZ	MARTIKI	138.00	138.00	1	0.30	0	1	336.4 KCM ACSR
48	0127 BIG SANDY	INEZ	138.00	138.00	3	25.08	0	1	795 MCMA
49	0106 DORTON	FLEMING	138.00	138.00	1	6.81	0	1	795 MCMA
50	0106 DORTON	FLEMING	138.00	138.00	3	0.83	0	0	795 MCMA
51	0108 BEAVER CREEK	SPRIGG #1	138.00	138.00	1	32.60	0	1	397 MCMA
52	0124 BIG SANDY	SOUTH NEAL	138.00	138.00	1	0.01	0	1	1033.5 VAR
53	0109 BEAVER CREEK	SPRIGG #3	138.00	138.00		0.00	0	0
54	0125 BELLEFONTE	AK STEEL OXYGEN PLANT	138.00	138.00	3	0.22	0	2	795 ACSR
55	0130 JOHNS CREEK	SPRIGG	138.00	138.00	3	13.00	0	0	1033 MCM
56	0131 BAKER	BIG SANDY EXT.	138.00	138.00	3	1.00	0	1	1351 KCM
57	0131 BAKER	BIG SANDY EXT.	138.00	138.00	1	0.05	0	2	2 - 1351KCM ACSR
58	0128 INEZ	JOHNS CREEK	138.00	138.00	3	17.00	0	0	2-556.5 MCM
59	0129 BEAVER CREEK	JOHNS CREEK	138.00	138.00	3	22.25	0	2	1033.5KCM ACSR
60	0132 GRANGSTON LOOP		138.00	138.00	3	0.84	0	2	556.5 KCM ACSR
61	0137 HAYS BRANCH	MORGAN FORK	138.00	138.00	3	8.30	0	1	795 ACSR
62	0138 SOFT SHELL	BEAVER CREEK	138.00	138.00	3	1.40	0	2	1590 ACSR
63	0138 SOFT SHELL	SPICEWOOD	138.00	138.00	3	1.40	0	2	1590 ACSR
64	0139 MORGAN FORK	BETSY LANE	138.00	138.00	3	0.10	0	1	795 ACSR
65	0139 MORGAN FORK	BEAVER CREEK	138.00	138.00	3	0.10	0	1	795 ACSR
66	0140 BONNYMAN	SOFT SHELL	138.00	138.00	3	0.88	0	2	1590 KCM ACSS
67	0140 BONNYMAN	SOFT SHELL	138.00	138.00	1	19.15	0	1	1590 KCM ACSS
68	0154 Racoon Extension		138.00	138.00	1	0.20	0	2	1033.5KCM ACSR
69	0119 BETSY LAYNE	ALLEN	46.00	138.00	1	5.89	0	1	795KCM ACSR
70	0119 BETSY LAYNE	ALLEN	46.00	138.00	3	0.22	0	2	1033.5KCM ACSR
71	0119 BETSY LAYNE	ALLEN	46.00	138.00	1	0.33	0	2	1033.5KCM ACSR
72	0142 STANVILLE EXTENSION		138.00	138.00	1	0.42	0	1	1033.5KCM ACSR
73	LINES < 132KV		69.00	69.00		593.74	6	0
74	Line cost and expense are	not available by individual								37,164,523	467,145,280	504,309,803	88,738	5,443,280		5,532,018
75	transmission line	Total shown in Column j - p
36	TOTAL					1,269.48	39.00	82		37,164,523.00	467,145,280.00	504,309,803.00	88,738.00	5,443,280.00	0.00	5,532,018.00

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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.

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

(m)

(n)

(o)

(p)

(q)

1

Nothing to Report

44

TOTAL

0

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	ALLEN (KP) - KY	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	13.20
2	ALLEN (KP) - KY	Distribution		46.00	12.00		6.25	1			0	0.00
3	ASHLAND - KY	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	16.20
4	ASHLAND - KY	Distribution		69.00	12.00		22.40	1			0	0.00
5	BAKER 765KV - KY	Transmission		69.00	12.00		10.50	0	1		0	0.00
6	BAKER 765KV - KY	Transmission		69.00	12.00		2.50	0	1		0	0.00
7	BAKER 765KV - KY	Transmission		69.00	4.00		3.00	0	1		0	0.00
8	BAKER 765KV - KY	Transmission		765.00	345.00	34.50	1500.00	3			0	0.00
9	BARRENSHE - KY	Distribution		69.00	12.00		25.00	1			0	0.00
10	BEAVER CREEK - KY	Transmission		138.00	0.00	0.00	0.00			Air Core Reactor	3
11	BEAVER CREEK - KY	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	124.80
12	BEAVER CREEK - KY	Transmission		138.00	0.00	0.00	0.00			Reactor	3
13	BEAVER CREEK - KY	Transmission		138.00	69.00	46.00	90.00	1			0	0.00
14	BEAVER CREEK - KY	Transmission		138.00	34.50		30.00	1			0	0.00
15	BEAVER CREEK - KY	Transmission		138.00	70.50	46.00	90.00	1			0	0.00
16	BECKHAM - KY	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	43.20
17	BECKHAM - KY	Distribution		138.00	34.50		30.00	1			0	0.00
18	BEEFHIDE - KY	Distribution		138.00	34.50		20.00	1			0	0.00
19	BELFRY - KY	Distribution		46.00	12.00		10.50	1			0	0.00
20	BELHAVEN - KY	Distribution		138.00	13.09		20.00	1			0	0.00
21	BELLEFONTE 138KV - KY	Transmission		138.00	69.00	34.50	308.00	2			0	0.00
22	BELLEFONTE 138KV - KY	Transmission		138.00	35.00		45.00	1			0	0.00
23	BELLEFONTE 138KV - KY	Transmission		138.00	13.09		22.40	1			0	0.00
24	BELLEFONTE 69KV - KY	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.40
25	BIG SANDY 138KV - KY	Transmission		138.00	13.09		20.00	1			0	0.00
26	BIG SANDY 138KV - KY	Transmission		138.00	34.50		20.00	1			0	0.00
27	BIG SANDY 138KV - KY	Transmission		138.00	69.50	13.20	128.80	1			0	0.00
28	BLUE GRASS - KY	Distribution		69.00	12.00		10.50	1			0	0.00
29	BONNYMAN - KY	Transmission		69.00	34.50		30.00	1			0	0.00
30	BONNYMAN - KY	Transmission		138.00	70.50	13.00	130.00	1			0	0.00
31	BULAN - KY	Distribution		69.00	12.00		9.38	1			0	0.00
32	BURDINE - KY	Distribution		46.00	12.00		7.50	1			0	0.00
33	BURTON - KY	Distribution		46.00	12.00		6.25	1			0	0.00
34	BUSSEYVILLE - KY	Distribution		138.00	34.50		55.00	2			0	0.00
35	CEDAR CREEK - KY	Transmission		138.00	34.50		25.00	0	1		0	0.00
36	CEDAR CREEK - KY	Transmission		69.00	12.00		6.25	0	1		0	0.00
37	CEDAR CREEK - KY	Transmission		138.00	69.00	46.00	90.00	1			0	0.00
38	CHADWICK - KY	Transmission		138.00	69.00	34.50	200.00	1			0	0.00
39	CHAVIES - KY	Distribution		69.00	12.00		3.75	1			0	0.00
40	CHAVIES - KY	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	9.60
41	COALTON - KY	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.40
42	COALTON - KY	Distribution		69.00	12.00		25.00	1			0	0.00
43	COLEMAN - KY	Distribution		69.00	12.00		3.75	1			0	0.00
44	COLEMAN - KY	Distribution		69.00	34.50		20.00	1			0	0.00
45	COLLIER - KY	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	9.60
46	COLLIER - KY	Distribution		69.00	34.00		25.00	1			0	0.00
47	COMBS - KY	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	13.20
48	COMBS - KY	Distribution		69.00	12.00		7.50	1			0	0.00
49	DAISY - KY	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	13.20
50	DAISY - KY	Distribution		69.00	12.00		4.70	1			0	0.00
51	DEWEY - KY	Transmission		138.00	69.00	12.00	90.00	1			0	0.00
52	DEWEY - KY	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	27.00
53	DEWEY - KY	Transmission		138.00	34.50		25.00	1			0	0.00
54	DORTON - KY	Transmission		138.00	70.50	46.00	144.00	2			0	0.00
55	DRAFFIN - KY	Distribution		46.00	12.00		10.50	1			0	0.00
56	EAST PRESTONSBURG - KY	Distribution		46.00	12.00		20.00	1			0	0.00
57	ELWOOD (KP) - KY	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	14.40
58	ELWOOD (KP) - KY	Distribution		46.00	34.50	6.50	25.00	1			0	0.00
59	ENGLE - KY	Distribution		69.00	34.50		20.00	1			0	0.00
60	FALCON - KY	Distribution		69.00	12.00		20.00	1			0	0.00
61	FALCON - KY	Distribution		69.00	46.00		20.00	1			0	0.00
62	FEDS CREEK - KY	Distribution		69.00	12.00		22.34	1			0	0.00
63	FISHTRAP - KY	Distribution		69.00	12.00		3.75	1			0	0.00
64	FLEMING - KY	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.40
65	FLEMING - KY	Transmission		138.00	69.00	46.00	130.00	1			0	0.00
66	FLEMING - KY	Transmission		69.00	12.00		20.00	1			0	0.00
67	FORDS BRANCH - KY	Distribution		46.00	34.50	12.00	30.00	1			0	0.00
68	FORDS BRANCH STEPDOWN - KY	Distribution		34.50	12.00		3.75	1			0	0.00
69	FORTY SEVENTH STREET - KY	Distribution		69.00	13.09		12.00	1			0	0.00
70	GARRETT (KP) - KY	Transmission		46.00	12.00		10.50	1			0	0.00
71	GRAHN - KY	Distribution		69.00	12.00		3.13	1			0	0.00
72	GRAYS BRANCH - KY	Distribution		69.00	12.00		5.00	1			0	0.00
73	GRAYSON - KY	Distribution		69.00	12.00		20.00	1			0	0.00
74	HADDIX - KY	Distribution		69.00	34.50		25.00	1			0	0.00
75	HADDIX - KY	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	5.40
76	HATFIELD (KP) - KY	Transmission		138.00	69.00	46.00	60.00	1			0	0.00
77	HAYWARD - KY	Distribution		69.00	13.09		9.38	1			0	0.00
78	HAZARD - KY	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	24.30
79	HAZARD - KY	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	32.40
80	HAZARD - KY	Transmission		161.00	138.00	11.00	135.00	3			0	0.00
81	HAZARD - KY	Transmission		138.00	69.00	12.00	180.00	2			0	0.00
82	HAZARD - KY	Transmission		34.50	12.00		9.38	1			0	0.00
83	HAZARD - KY	Transmission		138.00	36.20		30.00	1			0	0.00
84	HENRY CLAY - KY	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	9.60
85	HENRY CLAY - KY	Distribution		46.00	34.50		30.00	1			0	0.00
86	HIGHLAND (KP) - KY	Distribution		69.00	13.09		25.00	1			0	0.00
87	HIGHLAND (KP) - KY	Distribution		69.00	0.00	0.00	0.00			STATCAP	1
88	HITCHINS - KY	Distribution		69.00	13.09		25.00	1			0	0.00
89	HOODS CREEK - KY	Distribution		69.00	12.00		10.50	1			0	0.00
90	HOWARD COLLINS - KY	Distribution		69.00	12.00		30.50	2			0	0.00
91	INDEX - KY	Distribution		69.00	12.00		9.40	1			0	0.00
92	INEZ - KY	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	9.60
93	INEZ - KY	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	105.60
94	INEZ - KY	Transmission		138.00	69.00	13.09	50.00	1			0	0.00
95	JACKSON - KY	Distribution		69.00	12.00		14.50	2			0	0.00
96	JACKSON - KY	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	9.60
97	JEFF - KY	Distribution		69.00	36.20		30.00	1			0	0.00
98	JENKINS - KY	Distribution		69.00	12.00		10.50	1			0	0.00
99	JOHNS CREEK - KY	Transmission		138.00	70.50	36.20	54.00	1			0	0.00
100	JOHNS CREEK - KY	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	52.80
101	JOHNS CREEK - KY	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	9.60
102	KENWOOD - KY	Distribution		46.00	12.00		20.00	1			0	0.00
103	KENWOOD - KY	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	7.20
104	KEYSER - KY	Distribution		69.00	12.00		20.00	1			0	0.00
105	KIMPER - KY	Distribution		69.00	12.00		9.38	1			0	0.00
106	LESLIE - KY	Transmission		69.00	34.50		30.00	1			0	0.00
107	LESLIE - KY	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.40
108	LESLIE - KY	Transmission		161.00	69.00	12.00	90.00	1			0	0.00
109	LOVELY - KY	Distribution		138.00	34.00		30.00	1			0	0.00
110	MANSBACH - KY	Distribution		69.00	4.00		9.38	1			0	0.00
111	MAYKING - KY	Distribution		69.00	12.00		20.00	1			0	0.00
112	MAYO TRAIL - KY	Distribution		69.00	0.00	69.00	25.00	1			0	0.00
113	MCKINNEY - KY	Distribution		34.50	12.00		6.67	1			0	0.00
114	MCKINNEY - KY	Distribution		46.00	34.00		20.00	1			0	0.00
115	MIDDLE CREEK - KY	Distribution		46.00	12.00		3.75	1			0	0.00
116	MORGAN FORK - KY	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	43.20
117	NEW CAMP - KY	Distribution		69.00	12.00		20.00	1			0	0.00
118	OLIVE HILL - KY	Distribution		69.00	12.00		7.50	1			0	0.00
119	OLIVE HILL - KY	Distribution		69.00	4.00		5.00	1			0	0.00
120	PRESTONSBURG - KY	Distribution		46.00	13.09		10.00	1			0	0.00
121	PRESTONSBURG - KY	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	9,600.00
122	PRINCESS - KY	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	21.60
123	RACELAND - KY	Distribution		69.00	2.40		7.50	1			0	0.00
124	REEDY COAL - KY	Distribution		69.00	34.00		20.00	1			0	0.00
125	RUSSELL - KY	Distribution		69.00	12.00		22.40	1			0	0.00
126	RUSSELL FORK - KY	Distribution		69.00	12.00		3.75	1			0	0.00
127	SALISBURY (KP) - KY	Distribution		46.00	13.09		20.00	1			0	0.00
128	SECOND FORK - KY	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.40
129	SECOND FORK - KY	Distribution		69.00	12.00		7.50	1			0	0.00
130	SHAMROCK - KY	Distribution		69.00	34.50		10.50	1			0	0.00
131	SIDNEY - KY	Distribution		69.00	12.00		20.00	1			0	0.00
132	SILOAM - KY	Distribution		69.00	12.00		4.68	1			0	0.00
133	SLEMP - KY	Distribution		69.00	34.00		20.00	1			0	0.00
134	SLEMP - KY	Distribution		69.00	34.50		10.50	1			0	0.00
135	SOFT SHELL - KY	Distribution		138.00	34.50		30.00	1			0	0.00
136	SOUTH PIKEVILLE - KY	Distribution		69.00	13.09		25.00	1			0	0.00
137	SOUTH SHORE - KY	Distribution		69.00	13.09		7.50	1			0	0.00
138	SPRING FORK - KY	Distribution		46.00	7.20		0.83	1			0	0.00
139	STINNETT - KY	Distribution		161.00	34.50	7.20	22.40	1			0	0.00
140	STINNETT - KY	Distribution		161.00	34.00	7.20	14.93	1			0	0.00
141	STINNETT - KY	Distribution		161.00	34.50	7.20	22.40	0	1		0	0.00
142	STONE - KY	Transmission		138.00	70,500.00	46.00	90.00	1			0	0.00
143	TENTH STREET - KY	Distribution		69.00	13.09		25.00	1			0	0.00
144	THELMA - KY	Transmission		138.00	69.00	46.00	70.00	1			0	0.00
145	THELMA - KY	Transmission		138.00	69.00	12.00	90.00	1			0	0.00
146	THELMA - KY	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	32.40
147	THELMA - KY	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	7.20
148	TOM WATKINS - KY	Distribution		69.00	12.00		10.50	1			0	0.00
149	TOPMOST - KY	Distribution		138.00	13.09		20.00	1			0	0.00
150	VICCO - KY	Distribution		138.00	34.50		30.00	1			0	0.00
151	WEEKSBURY - KY	Distribution		69.00	12.00		6.25	1			0	0.00
152	WEST PAINTSVILLE - KY	Distribution		69.00	12.00		25.00	1			0	0.00
153	WHITESBURG - KY	Distribution		69.00	12.00		35.50	2			0	0.00
154	WHITESBURG - KY	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	13.20
155	WORTHINGTON - KY	Distribution		69.00	12.00		1.50	1			0	0.00
156	WURTLAND - KY	Distribution		69.00	12.00		20	1			0	0
157	TotalTransmissionSubstationMember											10,340
158	Total											10,340

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

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	Administrative and General Expenses - Maintenance	AEPSC	935	1,485,323
3	Distribution Expenses - Maintenance	OPCO	592,593,595	1,026,502
4	Transmission Expenses - Maintenance	AEPSC	568-573	1,341,761
5	Administrative and General Expenses - Maintenance	APCO	935	263,657
6	Distribution Expenses - Operation	AEPSC	580-583,584,586-588	1,109,418
7	Transmission Expenses - Operation	AEPSC	560-563,564,920,923	4,157,525
8	Administrative and General Expenses - Operation	AEPSC	920-928,930.1,930.2,931	3,827,415
9	Transmission Expenses - Operation	I&M	560,563,565,566	2,017,372
10	Audit Services	AEPSC	920,923	282,338
11	Fuel & Storeroom Services	AEPSC	152,163	2,692,700
12	Treasury & Risk	AEPSC	920,923	597,520
13	Barging	I&M	151	2,009,631
14	Information Technology	AEPSC	920,923	2,157,812
15	Urea	APCO	154	818,932
16	Central Machine Shop	APCo	107,108,506,511-514,570,592	1,012,304
17	Infrastructure Ops & Support	AEPSC	920,923	330,464
18	Urea	WPCO	154	1,381,108
19	Bus Ops & Perf Assurance	AEPSC	920,923	388,956
20	Civil & Political Activities and Other Svcs	AEPSC	426	786,566
21	Legal GC/Administration	AEPSC	920,923	1,988,672
22	Construction Services	AEPSC	107,108	30,691,324
23	Materials and Supplies	OPCo	107,184,513,564,569-570,592,935	1,111,360
24	Construction Services	APCO	107,108	591,918
25	O&M Services for Jointly Owned Facility - Mitchell	WPCo	107,108,143,154,186,408,421,426.1,426.3,426.4,426.5,500-502,505,506,510-514,557,920-928,930.1,930.2,931,935	29,954,990
26	Construction Services	OPCo	107,108	459,751
27	Other Power Supply Expenses	AEPSC	556,557	1,124,134
28	Corp Safety & Health	AEPSC	920,923	558,909
29	Physical & Cyber Security	AEPSC	920,923	325,058
30	Corporate Accounting	AEPSC	920,923	1,022,510
31	Real Estate & Workplace Svcs	AEPSC	920,923	628,038
32	Corporate Communications	AEPSC	920,923	306,314
33	Regulatory Services	AEPSC	920,923	369,298
34	Corporate Human Resources	AEPSC	920,923	1,048,286
35	Research and Other Services	AEPSC	183,186,188	699,436
36	Corporate Planning & Budgeting	AEPSC	920,923	489,403
37	Steam Power Generation - Maintenance	AEPSC	510-514	1,094,040
38	Customer Accounts Expenses	AEPSC	901-903,905	3,576,574
39	Steam Power Generation - Operation	AEPSC	500-502,506	4,513,394
40	Distribution Expenses - Maintenance	AEPSC	590-598	889,370
41	Tax Services	AEPSC	920,923	329,866
42	Distribution Expenses - Maintenance	I&M	592,593	510,453
43	Taxes Other Than Income taxes	WPCO	4,081	775,568
19
20	Non-power Goods or Services Provided for Affiliated
21	Building and Property Leases	AEPSC	4540	961,628
22	Fleet and Vehicle Charges	AEP Texas	(a) See Foonote	943,108
23	Materials and Supplies	APCo	154	315,895
24	O&M Services for Jointly Owned Facility - Mitchell	WPCo	107,108,154,186,401,408,421,426,500,501,502,505,506,510-514,557,920-923,925,926,928,930,931,935	42,624,515
25	Research and Other Services	WPCo	183,184,186	618,935
26	Steam Power Generation - Maintenance	WPCo	510-514	536,394
27	Steam Power Generation - Operation	WPCO	501-502,505,506	796,708
28	Administrative and General Expenses - Operation	American Electric Power Company	920,921,923,926-928,931	1,867,973
29	Construction Services	WPCo	107,108	403,048
30	Fuel & Storeroom Services	WPCo	151,152,154	4,528,927
31	Taxes Other Than Income taxes	WPCo	4081	1,046,305
32	Urea	APCo	154	758,851
33	Urea	WPCO	154	419,327
34	Use of Jointly Owned Facility	KYTCo	454	574,646
42

Name of Respondent:

Kentucky Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: AccountsChargedOrCreditedTransactionsWithAssociatedAffiliatedCompanies

Cost related to AEP's fleet vehicles are allocated in the same manner as the labor of each department utilizing the vehicles. To the extent a department provides service to another affiliate company, an applicable share of their fleet costs are also assigned to that affiliate company.

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