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)

Wheeling 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

Wheeling 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, Ohio 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)

AEP Service Corporation,1 Riverside Plaza, Columbus, Ohio 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:

Wheeling 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
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
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
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
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:

Wheeling 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 AEP Service Corporation,1 Riverside Plaza, Columbus, Ohio 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. 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 - West Virginia
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:

Wheeling 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 the Common Stock

Name of Respondent:

Wheeling 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
20
21
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23
24
25
26
27

Name of Respondent:

Wheeling 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:

Wheeling 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

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:

Wheeling 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, President and Chief Operating Officer	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	Therace M. Risch, Vice President	Columbus, Ohio	false	false
8	Peggy I.Simmons, Executive Vice President, Utilities	Columbus, Ohio	false	false
9	Toby L. Thomas, Vice President	Columbus, Ohio	false	false
10	Rajagopalan.Sundararajan,Executive Vice President, External Affairs	Columbus, Ohio	false	false
11	Aaron D.Walker, President, Chief Operating Officer and Vice President - Distribution Region Operations	Charleston,WV	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, Vice President	Columbus, Ohio	false	false

Name of Respondent:

Wheeling 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:

Wheeling 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:

Wheeling 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:

Wheeling 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

$165M Wheeling Power Company Term Loan, State Authority: N/A, FERC Authority: ES20-32-000 Issued: 5/11/2022, Maturity: 5/11/2024

Remarketed $65M WVEDA Series 2013A Pollution Control Bond Wheeling Power Company VA State:State Commission Authority: N/A, TN State Commission Authority: N/A, SEC Registration Statement:N/A, Issued: 4/1/2022, Mandatory Tender: 6/18/2027, Maturity: 6/1/2037

$165M -Term Loan, Increased $100M from $165M to $265M, State Authority: N/A

FERC Authority: ES22-52-000, Issued: 12/16/2022 ,Maturity: 5/11/2024

None

Effective Date

Status

Business Unit

Operating Company, Location

Union Local #

Contract

Or

Wages

Total Personnel Represented

Settlement Amount %

1/1/2022

Completed

Wheeling Power

UWUA 264

Wages

35

2% GWI

44563

Complete

Mitchell Plant

UWUA 492

Wages

120

2% GWI

9/13/2022

Ratified

Wheeling Power Co, operated by APCo

UWUA 264

Contract and Wages

37

3.0% + adders for certain journey level positions

Please refer to the Notes to Financial Statements pages 122-123

None

Not Used

Rajagopalan Sundararajan elected as Director effective 07/02/2022

David M. Feinberg elected as Vice President effective 08/25/2022

Timothy C. Kerns elected as Vice President – Generation Assets effective 09/03/2022

Aaron D. Walker elected as Director, President and Chief Operating Officer effective 09/22/2022

Peggy I. Simmons elected as Director effective 09/22/2022

Phillip R. Ulrich elected as Director effective 09/22/2022 and as Vice President effective

09/14/2022

Lisa M. Barton resigned as Director effective 09/20/2022

Charles R. Patton resigned as Director effective 07/02/2022

Christian T. Beam resigned as President and Chief Operating Officer effective 09/21/2022

Aaron D. Walker resigned as Vice President - Distribution Region Operations effective 09/21/2022

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 as effective on 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

Proprietary capital ratio exceeds 30%

Name of Respondent:

Wheeling 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	1,515,097,358	1,479,536,796
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	90,474,262	17,221,104
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		1,605,571,620	1,496,757,900
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	625,467,890	594,905,788
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		980,103,730	901,852,112
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)		980,103,730	901,852,112
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)
17	OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS
18	NonutilityProperty Nonutility Property (121)		16,001	16,001
19	AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Prov. for Depr. and Amort. (122)		810	810
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances	228	23,853	23,990
24	OtherInvestments Other Investments (124)		17,439	18,887
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)		29,756,825	8,131,029
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)		29,814,928	8,190,716
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)		222,499	74,814
36	SpecialDeposits Special Deposits (132-134)		917,743	12,739,600
37	WorkingFunds Working Fund (135)
38	TemporaryCashInvestments Temporary Cash Investments (136)
39	NotesReceivable Notes Receivable (141)
40	CustomerAccountsReceivable Customer Accounts Receivable (142)		32,709,073	26,327,868
41	OtherAccountsReceivable Other Accounts Receivable (143)		5,414
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		131,007	159,243
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)		26,132,944	3,383,473
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	12,260,390	11,688,331
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	24,614	24,950
53	NoncurrentPortionOfAllowances (Less) Noncurrent Portion of Allowances	228	23,853	23,990
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)		919,194	897,379
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)
60	RentsReceivable Rents Receivable (172)		17,096	18,226
61	AccruedUtilityRevenues Accrued Utility Revenues (173)		9,832,439	8,195,719
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)
63	DerivativeInstrumentAssets Derivative Instrument Assets (175)		8,819,585	5,327,037
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)		113,699,693	78,583,673
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		758,582	499,175
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	324,197,161	174,735,271
73	PreliminarySurveyAndInvestigationCharges Prelim. Survey and Investigation Charges (Electric) (183)		553,501	3
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)
77	TemporaryFacilities Temporary Facilities (185)
78	MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186)	233	11,420,384	9,555,706
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)
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	42,711,133	34,283,833
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		379,640,761	219,073,989
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		1,503,259,112	1,207,700,489

Name of Respondent:

Wheeling 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	2,428,460	2,428,460
3	PreferredStockIssued Preferred Stock Issued (204)	250
4	CapitalStockSubscribed Capital Stock Subscribed (202, 205)
5	StockLiabilityForConversion Stock Liability for Conversion (203, 206)
6	PremiumOnCapitalStock Premium on Capital Stock (207)
7	OtherPaidInCapital Other Paid-In Capital (208-211)	253	360,592,845	320,592,845
8	InstallmentsReceivedOnCapitalStock Installments Received on Capital Stock (212)	252
9	DiscountOnCapitalStock (Less) Discount on Capital Stock (213)	254
10	CapitalStockExpense (Less) Capital Stock Expense (214)	254b
11	RetainedEarnings Retained Earnings (215, 215.1, 216)	118	121,654,844	87,049,114
12	UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1)	118
13	ReacquiredCapitalStock (Less) Reaquired Capital Stock (217)	250
14	NoncorporateProprietorship Noncorporate Proprietorship (Non-major only) (218)
15	AccumulatedOtherComprehensiveIncome Accumulated Other Comprehensive Income (219)	122(a)(b)	338,214	971,746
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		485,014,363	411,042,165
17	LongTermDebtAbstract LONG-TERM DEBT
18	Bonds Bonds (221)	256
19	ReacquiredBonds (Less) Reaquired Bonds (222)	256
20	AdvancesFromAssociatedCompanies Advances from Associated Companies (223)	256
21	OtherLongTermDebt Other Long-Term Debt (224)	256	502,000,000	350,000,000
22	UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225)
23	UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Debit (226)
24	LongTermDebt Total Long-Term Debt (lines 18 through 23)		502,000,000	350,000,000
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		3,020,937	3,311,384
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		113,862	361,967
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		732,173	178,576
30	AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4)
31	AccumulatedProvisionForRateRefunds Accumulated Provision for Rate Refunds (229)		1,872,862
32	LongTermPortionOfDerivativeInstrumentLiabilities Long-Term Portion of Derivative Instrument Liabilities		6,586	203
33	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges Long-Term Portion of Derivative Instrument Liabilities - Hedges
34	AssetRetirementObligations Asset Retirement Obligations (230)		8,420,062	8,185,254
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		14,153,309	12,037,384
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)
38	AccountsPayable Accounts Payable (232)		65,097,313	7,851,299
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)		7,060,457	55,730,134
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		25,423,129	33,065,969
41	CustomerDeposits Customer Deposits (235)		8,034,191	7,919,855
42	TaxesAccrued Taxes Accrued (236)	262	7,258,149	4,950,144
43	InterestAccrued Interest Accrued (237)		2,407,092	1,334,669
44	DividendsDeclared Dividends Declared (238)
45	MaturedLongTermDebt Matured Long-Term Debt (239)
46	MaturedInterest Matured Interest (240)
47	TaxCollectionsPayable Tax Collections Payable (241)		97,982	94,181
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		7,884,311	1,622,832
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		689,633	731,099
50	DerivativesInstrumentLiabilities Derivative Instrument Liabilities (244)		12,861	25,784
51	LongTermPortionOfDerivativeInstrumentLiabilities (Less) Long-Term Portion of Derivative Instrument Liabilities		6,586	203
52	DerivativeInstrumentLiabilitiesHedges Derivative Instrument Liabilities - Hedges (245)
53	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges
54	CurrentAndAccruedLiabilities Total Current and Accrued Liabilities (lines 37 through 53)		123,945,982	113,325,763
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)
57	AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255)	266
58	DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256)
59	OtherDeferredCredits Other Deferred Credits (253)	269	3,673,945	1,074,146
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	85,360,434	82,903,376
61	UnamortizedGainOnReacquiredDebt Unamortized Gain on Reaquired Debt (257)
62	AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty Accum. Deferred Income Taxes-Accel. Amort.(281)	272	26,088,659	27,703,586
63	AccumulatedDeferredIncomeTaxesOtherProperty Accum. Deferred Income Taxes-Other Property (282)		120,955,819	114,317,337
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		142,066,601	95,296,733
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		378,145,458	321,295,178
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		1,503,259,112	1,207,700,489

Name of Respondent:

Wheeling 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	407,222,479	349,336,194			407,222,479	349,336,194
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	250,291,323	201,566,300			250,291,323	201,566,300
5	MaintenanceExpense Maintenance Expenses (402)	320	33,051,564	27,701,695			33,051,564	27,701,695
6	DepreciationExpense Depreciation Expense (403)	336	42,496,387	42,356,837			42,496,387	42,356,837
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336	198,454	199,491			198,454	199,491
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	1,312,588	1,163,993			1,312,588	1,163,993
9	AmortizationOfElectricPlantAcquisitionAdjustments Amort. of Utility Plant Acq. Adj. (406)	336
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)		769,236	769,236			769,236	769,236
13	RegulatoryCredits (Less) Regulatory Credits (407.4)
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	21,102,949	19,395,761			21,102,949	19,395,761
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	28,824,214	1,459,067			28,824,214	1,459,067
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	135,505	123,931			135,505	123,931
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	59,743,418	26,038,468			59,743,418	26,038,468
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	24,252,560	19,288,406			24,252,560	19,288,406
19	InvestmentTaxCreditAdjustments Investment Tax Credit Adj. - Net (411.4)	266
20	GainsFromDispositionOfPlant (Less) Gains from Disp. of Utility Plant (411.6)		1,448	1,274			1,448	1,274
21	LossesFromDispositionOfServiceCompanyPlant Losses from Disp. of Utility Plant (411.7)			3,771				3,771
22	GainsFromDispositionOfAllowances (Less) Gains from Disposition of Allowances (411.8)		244,000				244,000
23	LossesFromDispositionOfAllowances Losses from Disposition of Allowances (411.9)
24	AccretionExpense Accretion Expense (411.10)		419,869	410,401			419,869	410,401
25	UtilityOperatingExpenses TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)		356,199,072	298,733,275			356,199,071	298,733,275
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		51,023,407	50,602,919			51,023,408	50,602,919
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)
34	ExpensesOfNonutilityOperations (Less) Expenses of Nonutility Operations (417.1)			6
35	NonoperatingRentalIncome Nonoperating Rental Income (418)
36	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1)	119
37	InterestAndDividendIncome Interest and Dividend Income (419)		102,963	1,268
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		39,024	793
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		23,563	23,543
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		165,550	24,012
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)
44	MiscellaneousAmortization Miscellaneous Amortization (425)
45	Donations Donations (426.1)		1,024,007	3,126
46	LifeInsurance Life Insurance (426.2)
47	Penalties Penalties (426.3)		178	12,041
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		58,649	31,261
49	OtherDeductions Other Deductions (426.5)		496,626	79,054
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		1,579,460	101,400
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262	35,885	82,629
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262	462,891	117,431
54	IncomeTaxesOther Income Taxes-Other (409.2)	262	135,319	57,513
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272	2,183,099	175,130
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272	8,555,469	504,486
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)		6,934,696	421,671
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		5,520,786	344,283
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		14,176,991	12,360,800
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		219,964	315,559
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)
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)		1,675,871	109,940
68	OtherInterestExpense Other Interest Expense (431)		263,794	218,665
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		573,157	2,994
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		15,763,463	13,001,970
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		40,780,730	37,945,232
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)		40,780,730	37,945,232

Name of Respondent:

Wheeling 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		87,049,114	89,103,882
2	ChangesAbstract Changes
3	AdjustmentsToRetainedEarningsAbstract Adjustments to Retained Earnings (Account 439)
4	AdjustmentsToRetainedEarningsCreditAbstract Adjustments to Retained Earnings Credit
4.1	AdjustmentsToRetainedEarningsCredit Adoption of ASC 326 - Adjustment in the allowance for other A/R
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)		40,780,730	37,945,232
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		6,175,000	40,000,000
36	DividendsDeclaredCommonStock TOTAL Dividends Declared-Common Stock (Acct. 438)		6,175,000	40,000,000
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)		121,654,844	87,049,114
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)		121,654,844	87,049,114
	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)

Name of Respondent:

Wheeling 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)	40,780,730	37,945,232
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	44,007,429	43,720,321
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of Regulatory Debits and Credits (Net)	769,236	769,236
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	29,118,487	6,420,706
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	29,163,195	1,294,632
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	12,476,114	12,318,630
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory	336	374
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	17,284,071	13,379,212
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	299,174	2,802,287
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	4,464,534	9,499,196
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	39,024	793
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other (provide details in footnote):	(a) 24,200,723	13,995,009
18.2	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Over/Under Recovered Fuel (Net)	129,412,978	54,261,593
18.3	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Market to market Risk Management Contracts
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	59,166,385	54,289,443
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)	80,182,878	31,983,006
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	39,024	793
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
31.1	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Other (provide details in footnote):
31.2	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Acquired Assets	15,311	54,817
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	80,159,165	32,038,616
36	AcquisitionOfOtherNoncurrentAssets Acquisition of Other Noncurrent Assets (d)
37	ProceedsFromDisposalOfNoncurrentAssets Proceeds from Disposal of Noncurrent Assets (d)	(b) 216,142	423,621
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 Contribution in Aid of construction proceeds	2,528,588	263,999
53.2	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription (Increase) Decrease in other Special Deposits	2,902	12,531
53.3	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Notes Receivable from Associated Companies
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	77,411,533	31,338,465
59	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
60	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
61	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b)	330,000,000
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	449,370
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
67.1	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Proceeds from Aquired Assets - Subject to Capital Lease	19,651	82,435
67.2	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Notes Payable to Associated Companies		16,851,513
67.3	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Capital Contributions from Parent	40,000,000
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	369,570,281	16,933,948
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)	178,000,000
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 Associates Companies	48,669,677
78	NetDecreaseInShortTermDebt Net Decrease in Short-Term Debt (c)
80	DividendsOnPreferredStock Dividends on Preferred Stock
81	DividendsOnCommonStock Dividends on Common Stock	6,175,000	40,000,000
83	CashFlowsProvidedFromUsedInFinancingActivities Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)	136,725,604	23,066,052
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)	147,686	115,074
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	74,814	189,888
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	222,500	74,814

Name of Respondent:

Wheeling 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		2021
	Cash Flow Incr / (Decr)		Cash Flow Incr / (Decr)
Utility Plant, Net	$	(5,696,358)	$	(3,236,204)
Property and Investments, Net	$	1,448	$	1,273
Special Funds	$	(31,959,208)	$	—
Margin Deposits	$	11,818,955	$	(12,706,324)
Mark-to-Market of Risk Management Contracts	$	(3,531,192)	$	(3,740,752)
Prepayments	$	(1,026,917)	$	(358,488)
Accrued Utility Revenues, Net	$	(1,636,721)	$	754,585
Miscellaneous Current and Accr Assets	$	—	$	—
Unamortized Debt Expense	$	189,964	$	315,559
Other Deferred Debits, Net	$	(2,398,515)	$	238,437
Proprietary Capital, Net	$	—	$	—
Other Comprehensive Income, Net	$	2,475,836	$	—
Unamortized Discount/Premium on Long-Term Debt	$	—	$	—
Accumulated Provisions - Misc	$	2,062,714	$	(82,920)
Current and Accrued Liabilities, Net	$	4,489,248	$	1,441,995
Other Deferred Credits, Net	$	1,010,023	$	3,377,830
Total	$	(24,200,723)	$	(13,995,009)

(b) Concept: ProceedsFromDisposalOfNoncurrentAssets


	2022		2021
	Cash Flow Incr / (Decr)		Cash Flow Incr / (Decr)
Sale of Meters	$	182,368	$	31,827
Sale of Transformers	$	33,712	$	70,145
Transco Transfer of Assets			$	321,649
Adjust Sale of Meters (FEB)	$	62	$	—
Total	$	216,142	$	423,621

Name of Respondent:

Wheeling 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

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


Term						Meaning

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 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.
AFUDC						Allowance for Funds Used During Construction.
AOCI						Accumulated Other Comprehensive Income.
APCo						Appalachian Power Company, an AEP electric utility subsidiary.
ARO						Asset Retirement Obligation.
CCR						Coal Combustion Residual.
CWIP						Construction Work in Progress.
COVID-19						Coronavirus 2019, a highly infectious respiratory disease. In March 2020, the World Health Organization declared COVID-19 a worldwide pandemic.
EIS						Energy Insurance Services, Inc., a nonaffiliated captive insurance company.
ELG						Effluent Limitation Guidelines.
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.
MTM						Mark-to-Market.
MW						Megawatt.
MWh						Megawatthour.
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.
PTC						Production Tax Credit.
Risk Management Contracts						Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
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.

SPP						Southwest Power Pool regional transmission organization.
SWEPCo						Southwestern Electric Power Company, an AEP electric utility subsidiary.
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.
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						Public Service Commission of West Virginia.

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION

WPCo is a wholly-owned subsidiary of AEP. WPCo is engaged in the generation and purchase of electric power and the subsequent sale, transmission and distribution of that power to approximately 41,000 retail customers in its service territory in northern West Virginia. As a member of the AEP System, WPCo’s facilities are operated in conjunction with the facilities of certain other AEP affiliated utilities as an integrated utility system.

To minimize the credit requirements and operating constraints when operating within PJM, participating AEP companies, including WPCo, 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.

Power Coordination Agreement

Under the FERC approved 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 and WPCo. Power and natural gas risk management activities are allocated based on the member companies’ respective equity positions. Risk management activities primarily include power and natural gas physical transactions, financially-settled swaps and exchange-traded futures. AEPSC settles the majority of the physical forward contracts by entering into offsetting contracts. WPCo shared in the revenues and expenses associated with these risk management activities with the member companies.

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, while trading and marketing activities originating in SPP generally accrue to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among APCo, I&M, KPCo, PSO, SWEPCo and WPCo based upon the common shareholder’s equity of these companies.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Rates and Service Regulation

WPCo’s rates are regulated by the FERC and the WVPSC. The FERC also regulates WPCo’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. The WVPSC 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. WPCo’s wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when WPCo negotiates and files a cost-based contract with the FERC or the FERC determines that WPCo has “market power” in the region where the transaction occurs.

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

In West Virginia, APCo and WPCo provide retail electric services at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis.

Certain transmission lines are owned by WPCo and leased to OPCo. An interconnection agreement exists between OPCo and WPCo which allows WPCo’s wholesale transmission rates to be based on the FERC’s OATT rates that are cost-based.

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

Basis of Accounting

WPCo’s accounting is subject to the requirements of the WVPSC 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 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 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, WPCo’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,” WPCo 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,
Cash was Paid (Received) for:
	Interest (Net of Capitalized Amounts)	$	14,308	$	12,564
	Income Taxes (Net of Refunds)	(33,207)		4,863
Noncash Acquisitions Under Finance Leases		206		152
As of December 31,
Construction Expenditures Included in Current and Accrued Liabilities		39,057		1,579

AEP System Tax Allocation Agreement

WPCo 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 WPCo’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.

Special Deposits

Special Deposits include funds held by trustees primarily for margin deposits for risk management activities.

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, WPCo 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

WPCo calculates bad debt reserves based on a rolling two-year average write-off in proportion to gross accounts receivable. For miscellaneous accounts receivable, bad debt expense is recorded based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable, unless specifically identified. In addition to these processes, management contemplates available current information, as well as any reasonable and supportable forecast information, to determine if allowances for uncollectible accounts should be further adjusted in accordance with the accounting guidance for Credit Losses. Management’s assessments contemplate expected losses over the life of the accounts receivable.

Concentrations of Credit Risk and Significant Customers

Two of WPCo’s industrial customers who produce shale gas account for the following percentages of Operating Revenues for the years ended December 31 and Customer Accounts Receivable as of December 31:


Percentage of Operating Revenues	2022		2021
Customer One Who Produces Shale Gas	13	%	14	%
Customer Two Who Produces Shale Gas	9	%	11	%

Percentage of Customer Accounts Receivable	2022		2021
Customer One Who Produces Shale Gas	15	%	16	%
Customer Two Who Produces Shale Gas	11	%	11	%

Management monitors credit levels and the financial condition of WPCo’s customers on a continuous basis to minimize credit risk. Management believes adequate provision for credit loss has been made in the accompanying financial statements.

Property, Plant and Equipment

Regulated

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. Removal costs accrued are charged to accumulated depreciation. 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

For regulated operations, 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

WPCo 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. WPCo 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 WPCo plans to use its facilities indefinitely. The retirement obligation would only be recognized if and when WPCo abandons or ceases the use of specific easements, which is not expected.

Valuation of Nonderivative Financial Instruments

The book values of Cash, Special Deposits, Working Fund, Notes Receivable from Associated Companies, Notes Payable to Associated Companies, 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.

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. In regulated jurisdictions with an active FAC, 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 WVPSC’s review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the WVPSC. On a routine basis, the WVPSC reviews and/or audits WPCo’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

WPCo’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, WPCo records them as assets on its balance sheets. WPCo reviews the 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, WPCo derecognizes that regulatory asset as a charge against income.

Electricity Supply and Delivery Activities

WPCo recognizes revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services. WPCo 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 WPCo in the fourth quarter of each calendar year and a final annual true-up is recognized by WPCo 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 from 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.

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, WPCo 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. WPCo defers the unrealized MTM amounts as regulatory assets (for losses) and regulatory liabilities (for gains).

Energy Marketing and Risk Management Activities

WPCo engages in power marketing as a major power producer and participant in electricity markets. WPCo also engages in power, capacity, 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 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.

WPCo 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.

WPCo 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 the balance sheets as Derivative Instrument Assets or Liabilities, as appropriate, and on the statements of income in Operating Revenues. The realized gains and losses on marketing and risk management transactions are included in revenues or expense 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 WPCo 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, WPCo 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, or defers the gain or loss as a regulatory asset or liability on the balance sheet, depending on the nature of the risk being hedged.

Maintenance

Maintenance costs are expensed as incurred. If it becomes probable that WPCo 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

WPCo 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.

WPCo accounts for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” WPCo 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. WPCo’s uncertain tax positions were immaterial to the financial statements.

Excise Taxes

As an agent for some state and local governments, WPCo collects from customers certain excise taxes levied by those state or local governments on customers. WPCo 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

WPCo participates in an AEP sponsored qualified pension plan and an unfunded nonqualified plan. Substantially all of WPCo’s employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. WPCo also participates in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees. WPCo is allocated a proportionate share of benefit costs and accounts for its participation in these plans as multiple-employer plans. 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 $83.3 million and $136.7 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).

Special Deposits

In December 2021, Special Deposits increased by approximately $13 million primarily due to an increase in deposits paid to PJM driven by a significant increase in the forward price of electricity. The Special Deposits were returned from PJM in February 2022.

Subsequent Events

Management reviewed subsequent events through March 24, 2023, the date that WPCo’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 WPCo’s business. There are no new standards expected to have a material impact on WPCo’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.


Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Year Ended December 31, 2022

	Pension and OPEB
	Amortization		Changes
	of Deferred		in Funded
	Costs		Status		Total
	(in thousands)
Balance in AOCI as of December 31, 2021	$	(294)	$	1,266	$	972
Change in Fair Value Recognized in AOCI	—		(2,818)		(2,818)
Amount of (Gain) Loss Reclassified from AOCI
Amortization of Prior Service Cost (Credit)	(369)		—		(369)
Reclassifications from AOCI, before Income Tax (Expense) Benefit	(369)		—		(369)
Income Tax (Expense) Benefit	(77)		—		(77)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	(292)		—		(292)
Pension and OPEB Adjustment Related to Plant Transfers	—		3,134		3,134
Income Tax (Expense) Benefit	—		658		658
Pension and OPEB Adjustment Related to Plant Transfers, Net of	—		2,476		2,476
Income Tax (Expense) Benefit
Net Current Period Other Comprehensive Income (Loss)	(292)		(342)		(634)
Balance in AOCI as of December 31, 2022	$	(586)	$	924	$	338


Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Year Ended December 31, 2021

	Pension and OPEB
	Amortization		Changes
	of Deferred		in Funded
	Costs		Status		Total
	(in thousands)
Balance in AOCI as of December 31, 2020	$	(82)	$	535	$	453
Change in Fair Value Recognized in AOCI	—		731		731
Amount of (Gain) Loss Reclassified from AOCI
Amortization of Prior Service Cost (Credit)	(269)		—		(269)
Reclassifications from AOCI, before Income Tax (Expense) Benefit	(269)		—		(269)
Income Tax (Expense) Benefit	(57)		—		(57)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	(212)		—		(212)
Net Current Period Other Comprehensive Income (Loss)	(212)		731		519
Balance in AOCI as of December 31, 2021	$	(294)	$	1,266	$	972

4. RATE MATTERS

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

Mitchell Plant Operating and Ownership Agreements with KPCo

In October 2021, AEP entered into a Stock Purchase Agreement (SPA) to sell KPCo to a nonaffiliated third-party. The SPA is contingent upon the issuance by the KPSC, WVPSC and FERC orders regarding a new proposed Mitchell Plant Operations and Maintenance Agreement and Mitchell Plant Ownership Agreement between KPCo and WPCo.

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.

2021 and 2022 ENEC (Expanded Net Energy Cost) Filings

In April 2021, APCo and WPCo (the Companies) requested a $73 million annual increase in ENEC rates based on a cumulative combined $55 million ENEC under-recovery as of February 28, 2021 and a combined $18 million increase in projected ENEC costs for the period September 2021 through August 2022. In September 2021, the WVPSC issued an order approving a $7 million overall increase in ENEC rates, including an approval for recovery of the Companies’ cumulative $55 million ENEC under-recovery balance and a $48 million reduction in projected costs for the period September 2021 through August 2022. Subsequently, the Companies submitted a request for reconsideration of this order, identifying flaws in the WVPSC’s calculation of forecasted future year fuel expense and purchased power costs.

In March 2022, the WVPSC issued an order granting the Companies’ request for reconsideration, in part, and approving $31 million in projected costs for the period September 2021 through August 2022. The order also reopened the 2021 ENEC case to require the Companies to explain the significant growth in the reported under-recovery of ENEC costs and to provide various other information including revised projected costs for the period March 2022 through August 2022. Also, in March 2022, the Companies filed testimony providing the information requested in the WVPSC’s order and requested a $155 million annual increase in ENEC rates effective May 1, 2022. In May 2022, the WVPSC issued an order approving a $93 million overall increase to ENEC rates to recover projected annual ENEC costs. However, the WVPSC stated that actual and projected ENEC costs are still subject to a prudency review.

In April 2022, the Companies submitted their 2022 annual ENEC filing with the WVPSC requesting a $297 million annual increase in ENEC revenues, inclusive of the previously requested $155 million increase, effective September 1, 2022.

In September 2022, following an agreed upon delay in the proceedings of the Companies’ 2022 ENEC case, certain intervenors submitted testimony recommending disallowances of at least $83 million to the Companies’ historical period ENEC under-recovery balance along with proposals to either securitize the Companies’ remaining ENEC balance or defer recovery of this balance beyond the traditional one-year period. West Virginia Staff recommended a $13 million increase in ENEC rates pending the outcome of the ENEC prudency review. In February 2023, the WVPSC issued an order stating that the commission will not grant additional rate increases for

fuel costs until the WVPSC staff completes its prudency review. As of December 31, 2022, the Companies’ cumulative ENEC under-recovery was $519.5 million ($231.1 million related to WPCo). If any deferred ENEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

5. EFFECTS OF REGULATION

Regulatory assets and liabilities are comprised of the following items:


			December 31,				Remaining
			2022		2021		Recovery Period
Regulatory Assets:			(in thousands)






Regulatory assets pending final regulatory approval:

	Regulatory Assets Currently Not Earning a Return

		Income Tax Assets	$	8,686	$	—
		Storm-Related Costs	1,112		—
		COVID-19	32		31
	Total Regulatory Assets Pending Final Regulatory Approval		9,830		31

Regulatory assets approved for recovery:

	Regulatory Assets Currently Earning a Return
		Mitchell Plant Transfer	13,910		14,679		18 years

Total Regulatory Assets Currently Earning a Return			13,910		14,679
	Regulatory Assets Currently Not Earning a Return
		Under-recovered Fuel Costs	231,053		101,640		1 year
		Income Tax Assets	57,982		54,447		(a)
		Pension Funded Status	10,770		2,683		12 years
		COVID-19	—		485
		Other Regulatory Assets Approved for Recovery	652		770		various
Total Regulatory Assets Currently Not Earning a Return			300,457		160,025

Total Regulatory Assets Approved for Recovery			314,367		174,704

Total FERC Account 182.3 Regulatory Assets			$	324,197	$	174,735

(a)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
			2022		2021		Refund Period
			(in thousands)
Regulatory Liabilities:


Regulatory liabilities pending final regulatory determination:
	Regulatory Liabilities Currently Paying (Earning) a Return
		Income Tax Liabilities (a)(b)	$	(13,675)	$	77
Total Regulatory Liabilities Pending Final Regulatory Determination			(13,675)		77

Regulatory liabilities approved for payment:

	Regulatory Liabilities Currently Paying a Return
		Income Tax Liabilities (a)	71,741		60,185		(c)
Total Regulatory Liabilities Currently Paying a Return			71,741		60,185
	Regulatory Liabilities Currently Not Paying a Return
		Vegetation Management Program	13,115		10,502		2 years
		Peak Demand Reduction/Energy Efficiency	7,993		6,928		2 years
		Unrealized Gain on Forward Commitments	4,932		3,557		2 years
		PJM Transmission Enhancement Refund	1,072		1,490		3 years
		Environmental Compliance Surcharge	—		164
		Other Regulatory Liabilities Approved for Payment	182		—		various
Total Regulatory Liabilities Currently Not Paying a Return			27,294		22,641

Total Regulatory Liabilities Approved for Payment			99,035		82,826

Total FERC 254 Account Regulatory Liabilities			$	85,360	$	82,903

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

(b)Represents an income tax related regulatory asset, which is presented within net regulatory liabilities on the balance sheet.

(c)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 was $366 thousand for the year ended December 31, 2022 and is to be refunded over 6 years.

6. COMMITMENTS, GUARANTEES AND CONTINGENCIES

WPCo is subject to certain claims and legal actions arising in its ordinary course of business. In addition, WPCo’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 WPCo 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

WPCo has substantial commitments to support its business. WPCo purchases fuel 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 WPCo’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)		$	232,325	$	144,375	$	16,875	$	—	$	393,575

(a)	Represents contractual commitments to purchase coal 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

WPCo 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.

Lease Obligations

WPCo leases certain equipment under master lease agreements. See “Master Lease Agreements” section of Note 11 for additional information.

CONTINGENCIES

Insurance and Potential Losses

WPCo maintains insurance coverage normal and customary for an electric utility, subject to various deductibles. WPCo 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 WPCo’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. WPCo currently incurs costs to dispose of these substances safely.

Superfund addresses clean-up of hazardous substances that have been released to the environment. The Federal EPA administers the clean-up programs. Several states have enacted similar laws. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. As of December 31, 2022, there were no sites for which WPCo has received an information request which could lead to a Potentially Responsible Party designation.

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.

WPCo participates in an AEP sponsored qualified pension plan and an unfunded nonqualified pension plan which covers substantially all of WPCo’s employees. WPCo also participates in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees.

WPCo recognizes the 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. WPCo 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. WPCo records a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking 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 Plan						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	4.70	%	(a)	4.80	%	(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 the average increase shown in the table above.

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 Plan						OPEB
	Years 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	5.05	%	(a)	4.80	%	(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 Plan				OPEB
	2022		2021		2022		2021
Change in Benefit Obligation	(in thousands)
Benefit Obligation as of January 1,	$	14,527	$	15,988	$	3,887	$	4,547
Service Cost	727		334		54		27
Interest Cost	1,056		385		202		115
Actuarial (Gain) Loss	(4,803)		(889)		457		(406)
Plan Amendments	—		—		—		(22)
Transfers (a)	54,848		—		7,548		—
Benefit Payments	(2,222)		(1,291)		(1,177)		(551)
Participant Contributions	—		—		363		176
Medicare Subsidy	—		—		1		1
Benefit Obligation as of December 31,	$	64,133	$	14,527	$	11,335	$	3,887

Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1,	$	18,395	$	19,020	$	8,150	$	7,662
Actual Gain (Loss) on Plan Assets	(5,213)		666		(1,920)		863
Transfers (a)	73,064		—		—		—
Company Contributions	—		—		15,777		—
Participant Contributions	—		—		363		176
Benefit Payments	(2,222)		(1,291)		(1,177)		(551)
Fair Value of Plan Assets as of December 31,	$	84,024	$	18,395	$	21,193	$	8,150

Funded Status as of December 31,	$	19,891	$	3,868	$	9,858	$	4,263

(a) In September 2022, pursuant to resolutions under the existing Mitchell Plant agreement, WPCo replaced KPCo as the operator of Mitchell Plant and all Mitchell Plant employees were transferred to WPCo. See Note 4 - Rate Matters for additional information.

Amounts Recognized on the Balance Sheets


	Pension Plan				OPEB
	December 31,
	2022		2021		2022		2021
	(in thousands)
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs	$	19,898	$	3,868	$	9,858	$	4,263
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability	(7)		—		—		—
Funded Status	$	19,891	$	3,868	$	9,858	$	4,263

Amounts Included in Regulatory Assets, Deferred Income Taxes and AOCI

The following table shows the components of the plans included in Regulatory Assets, Deferred Income Taxes and AOCI:


	Pension Plan				OPEB
	December 31,
	2022		2021		2022		2021
Components	(in thousands)
Net Actuarial (Gain) Loss	$	10,770	$	2,683	$	691	$	(615)
Prior Service Credit	—		—		(1,118)		(615)

Recorded as
Regulatory Assets	$	10,770	$	2,683	$	—	$	—
Deferred Income Taxes	—		—		(89)		(258)
Net of Tax AOCI	—		—		(338)		(972)

Components of the change in amounts included in Regulatory Assets, Deferred Income Taxes and AOCI were as follows:


	Pension Plan				OPEB
	2022		2021		2022		2021
Components	(in thousands)
Actuarial (Gain) Loss During the Year	$	2,669	$	(775)	$	3,198	$	(904)
Amortization of Actuarial Loss	(437)		(281)		—		—
Prior Service Credit	—		—		—		(22)
Amortization of Prior Service Credit	—		—		402		269
Transfers - Prior Service Cost	—		—		(905)		—
Transfers - (Gain)/loss	5,855		—		(1,892)		—
Change for the Year Ended December 31,	$	8,087	$	(1,056)	$	803	$	(657)

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 presenting the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to WPCo using the percentages in the table below:


Pension Plan				OPEB
December 31,
2022		2021		2022		2021
2.0	%	0.3	%	1.4	%	0.4	%

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

As of December 31, 2022 and 2021, the accumulated benefit obligation for the qualified pension plan was $61.7 million and $14 million, respectively.

Estimated Future Benefit Payments and Contributions

The table below reflects the total benefits expected to be paid from the plan’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 Plan		OPEB
	(in thousands)
2023	$	5,413	$	1,596
2024	5,256		1,622
2025	5,113		1,737
2026	5,463		1,705
2027	5,742		1,746
Years 2028 to 2032, in Total	26,303		8,533

Components of Net Periodic Benefit Cost

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


	Pension Plan				OPEB
	Years Ended December 31,
	2022		2021		2022		2021
	(in thousands)
Service Cost	$	727	$	334	$	54	$	27
Interest Cost	1,056		385		202		115
Expected Return on Plan Assets	(2,260)		(780)		(820)		(366)
Amortization of Prior Service Credit	—		—		(402)		(269)
Amortization of Net Actuarial Loss	437		281		—		—
Net Periodic Benefit Cost (Credit)	(40)		220		(966)		(493)
Capitalized Portion	(333)		(173)		(25)		(14)
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	(373)	$	47	$	(991)	$	(507)

American Electric Power System Retirement Savings Plan

WPCo 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 was $408 thousand and $193 thousand in 2022 and 2021, respectively.

8. DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

AEPSC is agent for and transacts on behalf of WPCo.

WPCo is exposed to certain market risks as a major power producer and participant in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risk, which may be subject to capacity risk, interest rate risk and credit risk. These risks represent the risk of loss that may impact WPCo 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, WPCo 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.

WPCo utilizes power, capacity, natural gas and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. 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 WPCo’s outstanding derivative contracts:

Notional Volume of Derivative Instruments

Volume

December 31,

Unit of

Primary Risk Exposure

2022

2021

Measure

(in thousands)

Commodity:

Power

2,238

4,175

MWhs

Heating Oil and Gasoline

29

30

Gallons

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON WPCo’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 other assumptions. In order to determine the relevant fair values of the derivative instruments, WPCo 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 WPCo’s risk management contracts.

According to the accounting guidance for “Derivatives and Hedging,” WPCo 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, WPCo is required to post or receive cash collateral based on third party contractual agreements and risk profiles. The netted cash collateral received from third parties against short-term and long-term risk management assets was immaterial for WPCo as of December 31, 2022 and 2021. WPCo had an immaterial cash collateral paid to third parties against short-term and long-term risk management liabilities as of December 31, 2022 and 2021.

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


Fair Value of Derivative Instruments
December 31, 2022

	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts		in the Statement of		Presented in the Statement
Balance Sheet Location	Commodity (a)		Financial Position (b)		of Financial Position (c)
	(in thousands)
Derivative Instrument Assets	$	8,922	$	(102)	$	8,820
Long-term Portion of Derivative Instrument Assets	64		(64)		—


Derivative Instrument Liabilities	102		(102)		—
Long-term Portion of Derivative Instrument Liabilities	64		(64)		—


December 31, 2021

	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts		in the Statement of		Presented in the Statement
Balance Sheet Location	Commodity (a)		Financial Position (b)		of Financial Position (c)
	(in thousands)
Derivative Instrument Assets	$	5,856	$	(529)	$	5,327
Long-term Portion of Derivative Instrument Assets	23		(23)		—


Derivative Instrument Liabilities	546		(520)		26
Long-term Portion of Derivative Instrument Liabilities	23		(23)		—

(a) Derivative instruments within this category are reported 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) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.

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


	Years Ended December 31,
Location of Gain (Loss)	2022		2021
	(in thousands)
Operation Expenses	$	9	$	7
Maintenance Expenses	34		22
Regulatory Assets (a)	(8)		(390)
Regulatory Liabilities (a)	12,059		7,117
Total Gain on Risk Management Contracts	$	12,094	$	6,756

(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

Certain qualifying derivative instruments may be 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 WPCo’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 WPCo’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.”

Credit Risk

Management mitigates credit risk in WPCo’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 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 a 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. WPCo 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, WPCo 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 WPCo 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. WPCo 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, respectively. If a cross-acceleration provision would have been triggered, settlement at fair value would have been required. WPCo had no derivative contracts with cross-acceleration provisions outstanding as of December 31, 2022 and 2021.

Cross-Default Triggers

In addition, a majority of WPCo’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. The following table represents: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount that the exposure has been reduced by cash collateral posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering contractual netting arrangements:


	December 31,
	2022	2021
	(in thousands)
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements	$ —	$ 44
Additional Settlement Liability if Cross Default Provision is Triggered	—	26

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 WPCo’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	$	502,000	$	491,049	$	350,000	$	369,260

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, WPCo’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)	$	—	$	65	$	8,857	$	(102)	$	8,820

Liabilities:

Derivative Instrument Liabilities
Risk Management Commodity Contracts (a)	$	—	$	64	$	38	$	(102)	$	—


December 31, 2021

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

Derivative Instrument Assets
Risk Management Commodity Contracts (a)	$	—	$	510	$	5,347	$	(530)	$	5,327

Liabilities:

Derivative Instrument Liabilities
Risk Management Commodity Contracts (a)	$	—	$	452	$	95	$	(521)	$	26

(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.”

The following tables set forth a reconciliation of changes in the fair value of net trading derivatives and other investments 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	$	5,252
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a)(b)	665
Settlements	(5,917)
Transfers out of Level 3 (c)	—
Changes in Fair Value Allocated to Regulated Jurisdictions (d)	8,819
Balance as of December 31, 2022	$	8,819


	Net Risk Management
Year Ended December 31, 2021	Assets (Liabilities)
	(in thousands)
Balance as of December 31, 2020	$	1,597
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a)(b)	756
Settlements	(2,387)
Transfers out of Level 3 (c)	56
Changes in Fair Value Allocated to Regulated Jurisdictions (d)	5,230
Balance as of December 31, 2021	$	5,252

(a)Included in revenues on WPCo’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 fair value at the beginning of the period that the transfer occurred.

(d)Relates to the net gains (losses) of those contracts that are not reflected on WPCo’s statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable.

The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions:


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	$	8,857	$	38	Discounted Cash Flow	Forward Market Price	$	(2.82)	$	18.79	$	3.97
Total	$	8,857	$	38


December 31, 2021

						Significant	Input/Range
	Fair Value				Valuation	Unobservable					Weighted
	Assets		Liabilities		Technique	Input (a)	Low		High		Average (b)
	(in thousands)
Energy Contracts	$	—	$	26	Discounted Cash Flow	Forward Market Price	$	32.20	$	56.54	$	44.77
FTRs	5,347		69		Discounted Cash Flow	Forward Market Price	(0.30)		10.53		2.58
Total	$	5,347	$	95

(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 the 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 Expense (Benefit)

The details of WPCo’s Income Tax Expense (Benefit) as reported are as follows:


		Years Ended December 31,
		2022		2021
		(in thousands)
Charged (Credited) to Operating Expenses, Net:
	Current	$	(28,689)	$	(1,583)
	Deferred	35,491		6,750
Total		6,802		5,167

Charged (Credited) to Nonoperating Income, Net:
	Current	(598)		(175)
	Deferred	(6,372)		(329)
Total		(6,970)		(504)

Income Tax Expense (Benefit)		$	(168)	$	4,663

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

Net Income	$	40,780		$	37,945
Income Tax Expense (Benefit)		(168)			4,663
Pretax Income	$	40,612		$	42,608

Income Taxes on Pretax Income at Statutory Rate (21%)	$	8,529		$	8,948
Increase (Decrease) in Income Taxes Resulting from the Following Items:
Reversal of Origination Flow-Through		54			1,007
State and Local Income Taxes, Net		(5,145)			149
Removal Costs		(1,152)			(659)


AFUDC		(8)			—
Tax Reform Excess ADIT Reversal		(1,542)			(4,798)
Federal Return to Provision Adjustment		(911)			14
Other		7			2
Income Tax Expense (Benefit)	$	(168)		$	4,663

Effective Income Tax Rate	(0.4)		%	10.9		%

Net Deferred Tax Liability

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


	December 31,
	2022		2021
	(in thousands)
Deferred Tax Assets	$	42,711	$	34,284
Deferred Tax Liabilities	(289,111)		(237,318)
Net Deferred Tax Liabilities	$	(246,400)	$	(203,034)

Property Related Temporary Differences	$	(144,420)	$	(139,715)
Amounts Due to Customers for Future Income Taxes	14,316		14,967
Deferred State Income Taxes	(67,378)		(56,065)
Net Operating Loss Carryforward	6,605		1,351
Regulatory Assets	(52,467)		(25,127)
All Other, Net	(3,056)		1,555
Net Deferred Tax Liabilities	$	(246,400)	$	(203,034)

Federal and State Income Tax Audit Status

The statute of limitations for the IRS to examine WPCo and other AEP subsidiaries originally filed federal return has expired for tax years 2016 and earlier. WPCo and other AEP subsidiaries have 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. WPCo 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 WPCo 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.

WPCo and other AEP subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns, and WPCo 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.

Net Income Tax Operating Loss Carryforward

WPCo had $0 and $5.6 million of federal net income tax operating loss carryforward as of December 31, 2022 and 2021, respectively. As a result, WPCo recognized $0 and $1.2 million of deferred income tax benefit in 2022 and 2021, respectively. WPCo had $124.4 million and $3.1 million of West Virginia state net income tax operating loss carryforward in 2022 and 2021, respectively. As a result, WPCo recognized deferred state income tax benefits of $8.3 million and $204 thousand in 2022 and 2021, respectively. The state net operating losses do not expire and can be carried forward indefinitely until utilized. Management anticipates future taxable income will be sufficient to realize the state net income tax operating loss tax benefits.

Federal Tax Legislation

Inflation Reduction Act

In August 2022, President Biden signed H.R. 5376 into law, commonly known as the Inflation Reduction Act of 2022 or (IRA). Most notably this budget reconciliation legislation creates a 15% minimum tax on adjusted financial statement income (Corporate Alternative Minimum Tax or CAMT), extends and increases the value of PTCs and ITCs, adds a nuclear and clean hydrogen PTC, an energy storage ITC and allows the sale or transfer of tax credits to third parties for cash. This legislation has no material impact on the current period financial statements. As further significant guidance from Treasury and the IRS is expected on the tax provisions in the IRA, WPCo will continue to monitor any issued guidance and evaluate the impact on future net income, cash flows and financial condition.

In November 2022, the IRS released Notice 2022-61 addressing the Prevailing Wage and Apprenticeship Requirements (PWAR) tied to full value PTCs and ITCs for projects that begin construction on or after January 29, 2023. AEP’s future renewable energy projects that begin construction after this date will be required to, and expect to, satisfy the PWAR to receive full value ITCs and PTCs.

In December 2022, the IRS released Notice 2023-7 addressing time sensitive issues related to the CAMT. The notice provided initial guidance that WPCo can begin to rely on in 2023 and also stated that additional guidance is expected, of which WPCo will continue to monitor and assess. Notably, the interim guidance in Notice 2023-7 confirmed the CAMT depreciation adjustment includes tax depreciation that is capitalized to inventory under §263A and recovered as part of cost of goods sold, providing significant relief to WPCo’s potential CAMT exposure.

The enactment of the IRA will have future cash flow and income tax reporting considerations. WPCo and other AEP subsidiaries expect to be applicable corporations beginning in 2023 and expect to have CAMT cash tax payments beginning in 2024. CAMT cash taxes are expected to be offset by regulatory recovery, the utilization of tax credits and additionally the cash inflow generated by the sale of tax credits. The sale of tax credits will be presented in the operating section of the statements of cash flows consistent with the presentation of cash taxes paid. WPCo will present the gain or loss on sale of tax credits through income tax expense. Management believes this presentation provides consistency in financial statement reporting as it matches the originating income tax benefit of the tax credits.

State Tax Legislation

In April 2021, West Virginia enacted House Bill (HB) 2026. HB 2026 changed 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

WPCo 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. WPCo 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 WPCo will exercise the option.

Lease obligations are measured using the discount rate implicit in the lease when that rate is readily determinable. WPCo 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, WPCo 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. The components of rental costs were as follows:


	Years Ended December 31,
Lease Rental Costs	2022		2021
	(in thousands)
Operating Lease Cost	$	586	$	644
Finance Lease Cost:
Amortization of Right-of-Use Assets	299		340
Interest on Lease Liabilities	36		43
Total Lease Rental Costs (a)	$	921	$	1,027

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

Supplemental information related to leases is 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	6.05	6.87	3.47	%	3.34	%
Finance Leases	5.35	4.69	4.58	%	4.04	%


	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	$	586	$	644
Operating Cash Flows Used for Finance Leases	335		383


Non-cash Acquisitions Under Operating Leases	$	245	$	134

The following tables show the property, plant and equipment under finance leases and noncurrent assets under operating leases and related obligations recorded on WPCo’s balance sheets.


	December 31,
	2022		2021
	(in thousands)
Property, Plant and Equipment Under Finance Leases
Utility Plant (a)	$	832	$	927





Obligations Under Finance Leases
Noncurrent	$	633	$	663
Current	199		264
Total Obligations Under Finance Leases	$	832	$	927

(a) Includes $735 thousand and $1.3 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)	$	2,881	$	3,117

Obligations Under Operating Leases
Noncurrent	$	2,388	$	2,649
Current	491		467
Total Obligations Under Operating Leases	$	2,879	$	3,116

(a) Includes $1.4 million and $948 thousand 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	$	231	$	606
2024	186		553
2025	155		535
2026	136		491
2027	114		415
After 2027	124		626
Total Future Minimum Lease Payments	946		3,226
Less: Imputed Interest	114		347
Estimated Present Value of Future Minimum Lease Payments	$	832	$	2,879

Master Lease Agreements

WPCo leases certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, WPCo is committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the amount guaranteed. As of December 31, 2022, the maximum potential loss for these lease agreements was $371 thousand assuming the fair value of the equipment is zero at the end of the lease term.

12. FINANCING ACTIVITIES

Long-term Debt

The following details long-term debt outstanding:


		Weighted
		Average
		Interest Rate
		as of			Outstanding as of
		December 31,	Interest Rate as of December 31,		December 31,
Type of Debt	Maturity	2022	2022	2021	2022		2021
					(in thousands)
Senior Unsecured Notes	2022-2035	3.85%	3.70%-4.20%	3.36%-4.20%	$	172,000	$	285,000
Pollution Control Bonds (a)	2022-2027 (b)	3.00%	3.00%	3.00%	65,000		65,000
Other Long-term Debt	2024	5.60%	5.51%-5.75%	—%	265,000		—
Total Long-term Debt Outstanding					$	502,000	$	350,000

(a) For WPCo’s pollution control bonds, the interest rate is subject to periodic adjustment and may be purchased on demand at periodic interest adjustment dates. Insurance policies support certain series.

(b) WPCo’s pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on WPCo’s balance sheets.

Long-term debt outstanding as of December 31, 2022 is payable as follows:


											After
	2023		2024		2025		2026		2027		2027		Total
	(in thousands)
Principal Amount	$	—	$	265,000	$	122,000	$	—	$	65,000	$	50,000	$	502,000

Dividend Restrictions

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

All of the dividends declared by WPCo 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.

WPCo has credit agreements that contain a covenant that limit its debt to capitalization ratio to 67.5%. As of December 31, 2022, WPCo 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 WPCo is through the Federal Power Act. As of December 31, 2022, the maximum amount of restricted net assets of WPCo that may not be distributed to Parent in the form of a loan, advance or dividend was $363.3 million.

The Federal Power Act restriction does not limit the ability of WPCo to pay dividends out of retained earnings. The credit agreement covenant restrictions can limit the ability of WPCo to pay dividends out of retained earnings. As of December 31, 2022, there were no restrictions on WPCo’s ability to pay dividends out of retained earnings.

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 amount of outstanding borrowings from the Utility Money Pool as of December 31, 2022 and 2021 are included in Notes Payable to Associated Companies on WPCo’s balance sheets. WPCo’s Utility Money Pool activity and corresponding authorized borrowing limits are described in the following table:


	Maximum				Average
	Borrowings		Maximum		Borrowings		Average		Borrowings from		Authorized
	from the		Loans		from the		Loans		from the Utility		Short-Term
Years Ended	Utility		to the Utility		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	$	147,261	$	86,660	$	71,080	$	68,468	$	7,060	$	150,000
2021	66,669		—		39,136		—		55,730		100,000

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	%	4.89	%	1.16	%	2.40	%	1.25	%
2021	0.48	%	0.02	%	—	%	—	%	0.26	%	—	%

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 WPCo’s statements of income. For amounts borrowed from and advances to the Utility Money Pool, WPCo 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		$	1,676		$	110
Interest Income		100			62

13. RELATED PARTY TRANSACTIONS

For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 1 and “Corporate Borrowing Program - AEP System” section of Note 12.

Power Coordination Agreement

Effective January 1, 2014, the FERC approved a PCA among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. See “Organization” section of Note 1.

Risk Management 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 and WPCo. Certain power and natural gas risk management activities for APCo, I&M, KPCo and WPCo are allocated based on the member companies’ respective equity positions. See “Organization” section of Note 1.

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 while trading and marketing activities originating in SPP generally accrue to the benefit of PSO and SWEPCo. 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 following table shows revenues derived from sales to affiliates and transmission agreement sales:


	Years Ended December 31,
Related Party Revenues	2022	2021
	(in thousands)
Transmission Revenues	$ 3,516	$ 3,190
Other Revenues	54	613
Total Affiliated Revenues	$ 3,570	$ 3,803

The above summarized related party revenues are reported in Operating Revenues on WPCo’s statements of income.

Transmission Agreement (TA)

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.

WPCo’s net charges recorded as a result of the TA for the years ended December 31, 2022 and 2021 were $70 million and $55.7 million, respectively, and recorded in Operation Expenses on WPCo’s statements of income.

Transmission Lines Leased to OPCo

Certain transmission lines are owned by WPCo and leased to OPCo. An interconnection agreement exists between OPCo and WPCo which allows WPCo’s wholesale transmission rates to be based on the FERC’s OATT rates. WPCo recorded revenues of $2.7 million for each years ending December 31, 2022 and 2021. These revenues were recorded in Sales to AEP Affiliates on WPCo’s statements of income.

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. WPCo recorded expenses of $4.7 million and $3.2 million for the years ended December 31, 2022 and 2021, respectively, for urea transloading provided by I&M. These expenses were recorded as Operation Expenses.

Sales and Purchases of Property

WPCo had affiliated sales and purchases of meters and transformers. There were no gains or losses recorded on the transactions. The table below shows the sales and purchases at net book value:


	Years Ended December 31,
	2022		2021
	(in thousands)
Sales	$	216	$	424
Purchases	9,260		341

The amounts above are recorded in Utility Property on the balance sheets.

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, WPCo contributed $1 million to the AEP Foundation which was recorded in Donations on the statements of income. In 2021, there were no charitable contributions made to the AEP Foundation.

Intercompany Billings

WPCo 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.

AEPSC

AEPSC provides certain managerial and professional services to AEP’s subsidiaries. The costs of the services are

based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEPSC and its billings are subject to regulation by the FERC. WPCo’s total billings from AEPSC for the years ended December 31, 2022 and 2021 were $21.1 million and $6.1 million, respectively.

14. PROPERTY, PLANT AND EQUIPMENT

Depreciation

WPCo 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 annual composite depreciation rates by functional class for WPCo. The higher composite depreciation rate in the other class of property compared to the rate of transmission and distribution is due to capitalized software, which has a relatively shorter expected useful life compared to the transmission and distribution functional property classes.



Functional Class of Property	2022	2021

Generation	2.8%	2.9%
Transmission	2.1%	2.1%
Distribution	3.6%	3.6%
Other	8.4%	8.5%

The composite depreciation rate generally includes a component for removal costs, which is credited to accumulated depreciation. Actual removal costs incurred are charged to accumulated depreciation.

Asset Retirement Obligations

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


										Revisions in
	ARO as of			Accretion			Liabilities			Cash Flow			ARO as of
Year	January 1,			Expense			Settled			Estimates			December 31,
	(in thousands)
2022		$	8,185		$	420		$	(489)		$	304		$	8,420
2021		7,976			410			(152)			(49)			8,185

Jointly-owned Electric Facilities

WPCo has a 50% ownership share of Units 1 and 2 at the Mitchell Generating Station. In addition to WPCo, the Mitchell Generating Station is jointly-owned by KPCo. Using its own financing, each participating company is obligated to pay its share of the costs in the same proportion as its ownership interest. WPCo’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:


						Construction
		Fuel	Percent of	Utility Plant		Work in		Accumulated
		Type	Ownership	in Service		Progress		Depreciation
				(in thousands)
WPCo's Share as of December 31, 2022
Mitchell Generating Station, Units 1 and 2 (a)		Coal	50%	$	1,055,952	$	76,558	$	507,916

WPCo's Share as of December 31, 2021
Mitchell Generating Station, Units 1 and 2 (a)		Coal	50%	$	1,046,939	$	11,793	$	482,890

(a)	In September 2022, pursuant to resolutions under the existing Mitchell Plant agreement, WPCo replaced KPCo as the operator of Mitchell Plant. See Note 4 - Rate Matters for additional information.

15. REVENUE FROM CONTRACTS WITH CUSTOMERS

Disaggregated Revenues from Contracts with Customers

The table below represents WPCo’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	$	61,513	$	57,101
Commercial Revenues	42,110		38,786
Industrial Revenues (a)	260,605		223,197
Other Retail Revenues	828		770
Total Retail Revenues	365,056		319,854

Wholesale Revenues:
Generation Revenues	31,429		20,595
Transmission Revenues (a)	5,908		5,895
Total Wholesale Revenues	37,337		26,490

Other Revenues from Contracts with Customers (a)	4,759		2,702

Total Revenues from Contracts with Customers	407,152		349,046

Other Revenues:
Alternative Revenues	70		290
Total Other Revenues	70		290

Total Revenues	$	407,222	$	349,336

(a) Amounts include affiliated and nonaffiliated revenues.

Performance Obligations

WPCo 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. WPCo 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 WPCo are summarized as follows:

Retail Revenues

WPCo 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 WPCo 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

WPCo 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.

WPCo 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

WPCo has performance obligations to transmit electricity to wholesale customers through assets owned and operated by WPCo 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.

WPCo 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 Transmission Agreement (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 WPCo’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. WPCo 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 below include affiliated and nonaffiliated revenues.


2023		2024-2025		2026-2027		After 2027		Total
(in thousands)
$	748	$	1,495	$	1,495	$	748	$	4,486

Contract Assets and Liabilities

Contract assets are recognized when WPCo 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. WPCo did not have material contract assets as of December 31, 2022 and 2021.

When WPCo 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. WPCo’s contract liabilities typically arise from advanced payments of services provided primarily with respect to joint use agreements for utility poles. WPCo did not have material contract liabilities as of December 31, 2022 and 2021.

Accounts Receivable from Contracts with Customers

Accounts receivable from contracts with customers are presented on WPCo’s balance sheets within the Customer Accounts Receivable line item. WPCo’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.

The amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable from Associated Companies on WPCo’s balance sheets were $2.5 million and $2.5 million, respectively, as of December 31, 2022 and 2021.

Contract Costs

Contract costs to obtain or fulfill a contract were accounted for under the guidance for “Other Assets and Deferred Costs” and presented as a single asset and neither bifurcated nor reclassified between current and noncurrent assets on WPCo’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 WPCo’s statements of income. WPCo did not have material contract costs as of December 31, 2022 and 2021.

Name of Respondent:

Wheeling 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				453,223			453,223
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income				212,559			212,559
3	Preceding Quarter/Year to Date Changes in Fair Value				731,082			731,082
4	Total (lines 2 and 3)				518,523			518,523	37,945,232	38,463,755
5	Balance of Account 219 at End of Preceding Quarter/Year				971,746			971,746
6	Balance of Account 219 at Beginning of Current Year				971,746			971,746
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income				291,518			291,518
8	Current Quarter/Year to Date Changes in Fair Value				342,014			342,014
9	Total (lines 7 and 8)				633,532			633,532	40,780,730	40,147,198
10	Balance of Account 219 at End of Current Quarter/Year				338,214			338,214

Name of Respondent:

Wheeling 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)	1,488,450,590	1,488,450,590
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	3,712,214	3,712,214
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified	22,934,554	22,934,554
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	1,515,097,358	1,515,097,358
9	UtilityPlantLeasedToOthers Leased to Others
10	UtilityPlantHeldForFutureUse Held for Future Use
11	ConstructionWorkInProgress Construction Work in Progress	90,474,262	90,474,262
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	1,605,571,620	1,605,571,620
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	625,467,890	625,467,890
15	UtilityPlantNet Net Utility Plant (13 less 14)	980,103,730	980,103,730
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	622,127,282	622,127,282
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	3,340,608	3,340,608
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	625,467,890	625,467,890
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)	625,467,890	625,467,890

Name of Respondent:

Wheeling 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:

Wheeling 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
4	(303) Miscellaneous Intangible Plant	7,000,008	2,872,564	850,340			9,022,232
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)	7,000,008	2,872,564	850,340			9,022,232
6	2. PRODUCTION PLANT
7	A. Steam Production Plant
8	(310) Land and Land Rights	3,098,594					3,098,594
9	(311) Structures and Improvements	57,072,149	203,899	34,065			57,241,983
10	(312) Boiler Plant Equipment	890,163,159	12,369,221	4,083,666			898,448,714
11	(313) Engines and Engine-Driven Generators
12	(314) Turbogenerator Units	55,502,783		2,309			55,500,474
13	(315) Accessory Electric Equipment	25,780,112	79,039	13,963			25,845,188
14	(316) Misc. Power Plant Equipment	9,186,846	204,013	12,793			9,378,066
15	(317) Asset Retirement Costs for Steam Production	6,135,507	303,705				6,439,212
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)	1,046,939,150	13,159,877	4,146,796			1,055,952,231
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)	1,046,939,150	13,159,877	4,146,796			1,055,952,231
47	3. Transmission Plant
48	(350) Land and Land Rights	6,410,214	2,399				6,407,815
48.1	(351) Energy Storage Equipment - Transmission
49	(352) Structures and Improvements	3,229,520	44,865	2,018		162,334	3,110,033
50	(353) Station Equipment	71,512,692	2,296,513	595,804			73,213,401
51	(354) Towers and Fixtures	5,285,670					5,285,670
52	(355) Poles and Fixtures	52,167,494	3,533	6,923			52,157,038
53	(356) Overhead Conductors and Devices	26,756,934	143,140				26,900,074
54	(357) Underground Conduit	10,982					10,982
55	(358) Underground Conductors and Devices	76,937					76,937
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)	165,450,443	2,478,586	604,745		162,334	167,161,950
59	4. Distribution Plant
60	(360) Land and Land Rights	2,200,696	129,788				2,330,484
61	(361) Structures and Improvements	2,240,587	271,098	16,634			2,495,051
62	(362) Station Equipment	36,771,636	938,515	90,282			37,619,869
63	(363) Energy Storage Equipment – Distribution
64	(364) Poles, Towers, and Fixtures	48,999,575	2,964,641	173,100			51,791,116
65	(365) Overhead Conductors and Devices	44,127,129	5,744,232	294,563			49,576,798
66	(366) Underground Conduit	21,669,905	1,690,632	3,300			23,357,237
67	(367) Underground Conductors and Devices	31,951,638	966,375	116,592			32,801,421
68	(368) Line Transformers	30,020,029	1,013,741	377,960			30,655,810
69	(369) Services	17,186,211	585,349	40,365			17,731,195
70	(370) Meters	5,771,296	11,269,069	1,640,911			15,399,454
71	(371) Installations on Customer Premises	1,912,160	80,980	40,900			1,952,240
72	(372) Leased Property on Customer Premises
73	(373) Street Lighting and Signal Systems	1,656,784	73,583	56,706			1,673,661
74	(374) Asset Retirement Costs for Distribution Plant
75	TOTAL Distribution Plant (Enter Total of lines 60 thru 74)	244,507,646	25,728,003	2,851,313			267,384,336
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	393,400					393,400
87	(390) Structures and Improvements	3,191,933					3,191,933
88	(391) Office Furniture and Equipment	40,668					40,668
89	(392) Transportation Equipment
90	(393) Stores Equipment	57,448					57,448
91	(394) Tools, Shop and Garage Equipment	822,911	19,735				842,646
92	(395) Laboratory Equipment	25,285	6,404				31,689
93	(396) Power Operated Equipment
94	(397) Communication Equipment	6,759,161	73,097				6,832,258
95	(398) Miscellaneous Equipment	153,322	7,402			162,334	323,058
96	SUBTOTAL (Enter Total of lines 86 thru 95)	11,444,128	106,638			162,334	11,713,100
97	(399) Other Tangible Property
98	(399.1) Asset Retirement Costs for General Plant	151,295					151,295
99	TOTAL General Plant (Enter Total of lines 96, 97, and 98)	11,595,423	106,638			162,334	11,864,395
100	TOTAL (Accounts 101 and 106)	1,475,492,670	44,345,668	8,453,194			1,511,385,144
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)	1,475,492,670	44,345,668	8,453,194			1,511,385,144

Name of Respondent:

Wheeling 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:

Wheeling 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
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
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

Name of Respondent:

Wheeling 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	Ed-Ci-Wpco-D Ast Imp	1,185,794
2	Forestry WP D Base R W	1,523,460
3	ML PCC U0 ELG Compliance	44,650,616
4	ML PCC U0 Lime Conversion	3,055,992
5	ML PCC U2 Cooling Tower Comp	5,552,435
6	ML S U1 Air Heater Basket Rplc	1,302,876
7	ML S U2 Air Heater Basket Rplc	5,133,969
8	ML V U2 Catalyst Layer 4 Rplc	2,032,902
9	Wheeling Power Co Trans CI	4,635,495
10	Wheeling Power Co-Gen Prod Pwr	14,800,379
11	Wheeling Power-T Baseline	2,135,458
12	WPCo Trans Pre Eng Parent	1,491,191
13	Other Minor Projects under $1,000,000	5,956,077
43	Total	90,474,262

Name of Respondent:

Wheeling 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	592,027,428	592,027,428
2	Depreciation Provisions for Year, Charged to
3	DepreciationExpenseExcludingAdjustments (403) Depreciation Expense	42,967,749	42,967,749
4	DepreciationExpenseForAssetRetirementCosts (403.1) Depreciation Expense for Asset Retirement Costs	198,454	198,454
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):
10	DepreciationProvision TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)	43,166,203	43,166,203
11	Net Charges for Plant Retired:
12	BookCostOfRetiredPlant Book Cost of Plant Retired	7,602,854	7,602,854
13	CostOfRemovalOfPlant Cost of Removal	5,837,055	(a) 5,837,055
14	SalvageValueOfRetiredPlant Salvage (Credit)	373,559	(b) 373,559
15	NetChargesForRetiredPlant TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)	13,066,350	13,066,350
16	OtherAdjustmentsToAccumulatedDepreciation Other Debit or Cr. Items (Describe, details in footnote):
17.1	Other Debit or Cr. Items (Describe, details in footnote):
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)	622,127,281	622,127,281
Section B. Balances at End of Year According to Functional Classification
20	AccumulatedDepreciationSteamProduction Steam Production	504,045,723	504,045,723
21	AccumulatedDepreciationNuclearProduction Nuclear Production
22	AccumulatedDepreciationHydraulicProductionConventional Hydraulic Production-Conventional
23	AccumulatedDepreciationHydraulicProductionPumpedStorage Hydraulic Production-Pumped Storage
24	AccumulatedDepreciationOtherProduction Other Production
25	AccumulatedDepreciationTransmission Transmission	37,009,075	37,009,075
26	AccumulatedDepreciationDistribution Distribution	77,094,548	77,094,548
27	AccumulatedDepreciationRegionalTransmissionAndMarketOperation Regional Transmission and Market Operation
28	AccumulatedDepreciationGeneral General	3,977,935	3,977,935
29	AccumulatedProvisionForDepreciationOfElectricUtilityPlant TOTAL (Enter Total of lines 20 thru 28)	622,127,281	622,127,281

FOOTNOTE DATA

(a) Concept: CostOfRemovalOfPlant

Includes $2,671,868 of removal cost in retirement work in progress (RWIP).

(b) Concept: SalvageValueOfRetiredPlant

Includes ($282,240) of salvage in retirement work in progress (RWIP).

Name of Respondent:

Wheeling 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:

Wheeling 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)	631,985	836,278	Electric
6	Assigned to - Operations and Maintenance
7	Production Plant (Estimated)	10,949,219	11,316,492	Electric
8	Transmission Plant (Estimated)	1,612	3,902	Electric
9	Distribution Plant (Estimated)	104,003	103,132	Electric
10	Regional Transmission and Market Operation Plant (Estimated)
11	Assigned to - Other (provide details in footnote)	(a) 1,512	(b) 586	Electric
12	TOTAL Account 154 (Enter Total of lines 5 thru 11)	11,688,331	12,260,390
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	21,777,839	34,253,953

Name of Respondent:

Wheeling 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:

Wheeling 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	99,680	24,950	23,126		23,127		19,325		521,785		687,043	24,950
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)	882.00								19,325		20,207
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	1,752	336									1,752	336
19	Other:
20	Allowances Used
20.1	Allowances Used
21	Cost of Sales/Transfers:
22	Consent Decree Surrenders			17,344								17,344
23
24
25
26
27
28	Total			17,344								17,344
29	Balance-End of Year	98,810	24,614	5,782		23,127		19,325		541,110		688,154	24,614
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:

Wheeling 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	10,802		2,716		2,716						16,234
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)	541										541
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	833										833
19	Other:
20	Allowances Used
20.1	Allowances Used
21	Cost of Sales/Transfers:
22	Mississippi Power Company
23	Wolverine Power Supply Cooperative, Inc.
24
25
26
27
28	Total
29	Balance-End of Year	10,510		2,716		2,716						15,942
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:

Wheeling 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:

Wheeling 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:

Wheeling 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	None
20	Total
21	Generation Studies
22	None
39	Total
40	Grand Total

Name of Respondent:

Wheeling 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	SFAS 109 DEFERRED FIT	11,638,019	8,391,600	282/283	5,852,249	14,177,370
2	SFAS 109 DEFERRED SIT	42,809,357	10,564,606	283	883,565	52,490,398
3	Unrealized Loss on Forward Commitments		1,338,849	175/244/254/456	1,363,883	25,034
4	Netting of Trading Activities related to UnrealizedGains/Losses of Forward Commitments betweenRegulated Assets/Liabilities		74,462	254	49,428	25,034
5	Unrecovered Fuel Cost - WV	101,640,093	136,845,920	501	7,432,942	231,053,071
6	SFAS 158 Employers' Accounting for DefinedBenefit and other postretirement plans	2,683,337	10,770,217	129	2,683,337	10,770,217
7	SFAS 106 Medicare Subsidy- Amortization Period: 01/2013 - 12/2024	116,213		926	38,737	77,476
8	Mitchell transfer adjustment- WV PSC case #14-0564-E_PC- Amortization Period: 02/2015 - 12/2040	14,679,451		407	769,236	13,910,215
9	Deferred Storm Expense		1,849,838	593	738,074	1,111,764
10	Beneficial Electrification Prg		10,251			10,251
11	WV Deferred Rate Case expenses- WVPSC case #18-0646-E-42T- Amortization Period: 03/2019 - 02/2022	6,909		928	6,909
12	PJM 2020 Annual Transmission RequirementAmortization Period 01/2022 - 12/2022	25,724		456/565	25,724
13	PJM 2022 Annual Transmission RequirementAmortization Period 01/2023 - 12/2023		96,794			96,794
14	Covid-19 Deferred Expense	516,008	780	921	484,984	31,804
15	SFAS 112 Postemployment Benef	426,735	71,100	146/228/242	713,288	215,453
16	WV MRBC Surcharge Under Recov	193,425	423,362	403	263,989	352,798
17	WV ECS Under Recovery		330,456			330,456
44	TOTAL	174,735,271	170,768,235		21,306,345	324,197,161

Name of Respondent:

Wheeling 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	Allowance
2	Deferred Expenses	1,054				1,054
3	Deferred Property Taxes	9,281,631	6,928,437	107/236/408	6,429,329	9,780,739
4	Property Taxes - Capital Leases	11,002	25,200	408	23,602	12,600
5	Unamortized Credit Line Fees Amortization through March 2027	196,227	43,879	431	74,724	165,382
6	Def. Lease Assets - Non Taxable	4,339		142/143	4,339
7	Trnsrce OU Acctg for Def Asset	33,730	43,060	565	56,671	20,119
8	2021 PJM Transmission True-up		868,632			868,632
9	2022 PJM Transmission True-up		567,196			567,196
47	Miscellaneous Work in Progress	5,764				4,662
48	Deferred Regulatroy Comm. Expenses (See pages 350 - 351)	21,959			21,959
49	TOTAL	9,555,706				11,420,384

Name of Respondent:

Wheeling 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	DSIT ENTRY - NORMALIZED	543,400	451,249
3	ACCUM DITC-STATE-A/C 2550002-MJE	986,433	986,433
4	ACCRD BOOK ARO EXPENSE - SFAS 143	1,718,903	1,768,213
5	NOL-STATE C/F-DEF STATE TAX ASSET-L/T	1,174,739	1,307,761
6	ADSITC STATE C/F-DEF STATE TAX ASSET-L/T	1,151,450	1,670,043
7	Other	4,469,205	2,747,738
8	TOTAL Electric (Enter Total of lines 2 thru 7)	10,044,130	8,931,437
9	Gas
15	Other
16	TOTAL Gas (Enter Total of lines 10 thru 15)
17.1	Other (Specify)	24,239,703	33,779,696
17	Other (Specify)
18	TOTAL (Acct 190) (Total of lines 8, 16 and 17)	34,283,833	42,711,133

Notes

Name of Respondent:

Wheeling 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	Authorized and Outstanding	150,000			150,000	2,428,460
6	Total	150,000			150,000	2,428,460
7	Preferred Stock (Account 204)
8
9
10
11	Total
1	Capital Stock (Accounts 201 and 204) - Data Conversion
2
3
4
5	Total

Name of Respondent:

Wheeling 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	320,592,845
3.1	IncreasesDecreasesFromSalesOfDonationsReceivedFromStockholders Increases (Decreases) from Sales of Donations Received from Stockholders	40,000,000
4	DonationsReceivedFromStockholders Ending Balance Amount	360,592,845
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
15.1	IncreasesDecreasesDueToMiscellaneousPaidInCapital Increases (Decreases) Due to Miscellaneous Paid-In Capital
16	MiscellaneousPaidInCapital Ending Balance Amount
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	360,592,845

Name of Respondent:

Wheeling 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

Name of Respondent:

Wheeling 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
6	Reacquired Bonds (Account 222)
7
8
9
10	Subtotal
11	Advances from Associated Companies (Account 223)
12
13
14
15	Subtotal
16	Other Long Term Debt (Account 224)
17	Pollution Control Bonds WVEDA Mitchell Series 2013A		65,000,000		999,877			07/01/2014	06/01/2037	04/11/2018	04/01/2022	65,000,000	1,950,000
18	Senior Unsecured Notes:									04/01/2022	06/01/2027
19	3.36% Unsecured Senior Notes Series A Due 06/2022, FERC Authority: Docket No. ES14-47-000		113,000,000		639,635			06/01/2015	06/01/2022	06/01/2015	06/01/2022		1,582,000
20	3.37% Unsecured Senior Notes Series B Due 06/2025, FERC Authority: Docket No. ES14-47-000		122,000,000		690,613			06/01/2015	06/01/2025	06/01/2015	06/01/2025	122,000,000	4,514,000
21	4.20% Unsecured Senior Notes Series C Due 06/2035, FERC Authority: Docket No. ES14-47-000		50,000,000		282,956			06/01/2015	06/01/2035	06/01/2015	06/01/2035	50,000,000	2,100,000
22	Truist Credit facility		265,000,000		48,285			05/11/2022	05/11/2024	05/11/2022	05/11/2024	265,000,000	4,030,991
23	Subtotal		615,000,000		2,661,366							502,000,000	14,176,991
33	TOTAL		615,000,000									502,000,000	14,176,991

Name of Respondent:

Wheeling 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)	40,780,730
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) 135,335,285
28	Show Computation of Tax:
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44

Name of Respondent:

Wheeling 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


		In (000's)

Net Income for the year per Page 117		40,781
Federal Income Taxes		6,345
State Income Taxes		(6,513)
Pretax Book Income		40,613

Increase (Decrease) in Taxable Income resulting from:
Allowance for Funds Used During Construction and Other Differences Between Items Capitalized for Books and Expensed for Tax		21
Excess Tax Vs Book Depreciation		10,889
Repair Allowance		(36,022)
Removal Costs		(5,487)
Deferred Fuel Costs		(129,413)
SFAS 106 - Post Retirement Benefit Expense Accrued/Funded (Net)		(6,117)
Tax Accruals and Deferrals		500
Regulatory Adj- Mitchell Plant		198
Defd Rev Bonus Lease LT		(23)
Accrued Incentive Compensation		2,019
Uncollectible Accounts		(28)
Accrued Book ARO Expense - SFAS 143		235
Pollution Control Equipment		6,929
Other (Net)		(19,649)
Federal Taxable Income before State Income Taxes		(135,335)
Less: State Income Taxes		—
Federal Tax Net Income - Estimated Current Year Taxable Income		(135,335)
(Separate Return Basis)

Computation of Tax *
Federal Income Tax on Current Year Taxable Income (Separate Return Basis) at the Statutory Rate of 21%		(28,420)
Tax Credits		(6)
NOL-Reclass To/From Defd Tax Ass		(527)
R & D Credit Current		(2)
SEC ALLOC - Parent Savings		—
Estimated Tax Currently Payable	(a)	(28,955)
Adjustments of Prior Year's Accruals (Net)	(b)	(332)
Estimated Current Federal Income Taxes (Net)		(29,287)


FOOTNOTE DATA

(a) Represents the allocation of the estimated current year net operating tax income 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:

Wheeling 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			7,579,362	0	30,116,212	34,137,679		3,557,895	0	28,824,214			1,291,998
2					0	0				0	0
3	Subtotal Federal Tax				7,579,362	0	30,116,212	34,137,679	0	3,557,895	0	28,824,214	0	0	1,291,998
4	Subtotal State Tax				0	0	0	0	0	0	0	0	0	0	0
5	Local Tax	Local Tax		2019	744	0				744	0
6	Local Tax	Local Tax	WV	2021	595,735	0		595,735		0	0
7	Local Tax	Local Tax	WV	2022	0	0	2,645,243	2,032,855		612,388	0	2,645,242			1
8	Subtotal Local Tax				596,479	0	2,645,243	2,628,590	0	613,132	0	2,645,242	0	0	1
9	Subtotal Other Tax				0	0	0	0	0	0	0	0	0	0	0
10	Property Tax	Property Tax	WV	2020	3,240,207	0		3,240,207		0	0	2,958,539			2,958,539
11	Property Tax	Property Tax	WV	2021	6,139,947	0	45,390	3,110,974		3,074,363	0	2,997,823			2,952,433
12	Property Tax	Property Tax	WV	2022	0	0	6,856,710	557		6,856,153	0				6,856,710
13	Subtotal Property Tax				9,380,154	0	6,902,100	6,351,738	0	9,930,516	0	5,956,362	0	0	945,738
14	Real & Personal Prop	Real Estate Tax	WV	2021	22,000	0	3,009	25,009		0		14,011			11,002
15	Real & Personal Prop	Real Estate Tax	WV	2022		0	25,200			25,200		12,600			12,600
16	Subtotal Real Estate Tax				22,000	0	28,209	25,009	0	25,200	0	26,611	0	0	1,598
17	UNEMPLOYMENT 2022	Unemployment Tax			462	0	12,405	9,701	0	3,166	0	11,113			1,292
18	STATE UNEMPLOYMENT 2022	Unemployment Tax	OH		0		20	20	0	0		16			4
19	STATE UNEMPLOYMENT 2022	Unemployment Tax	WV		1,346	0	36,075	31,117	0	6,304	0	31,757			4,318
20	Subtotal Unemployment Tax				1,808	0	48,500	40,838	0	9,470	0	42,886	0	0	5,614
21	Sales and Use Tax	Sales And Use Tax	WV	2021	642		120	522		0	0				120
22	Sales and Use Tax	Sales And Use Tax	WV	2022	0	0	189,592	59,243		130,349					189,592
23	Subtotal Sales And Use Tax				642	0	189,472	59,765	0	130,349	0	0	0	0	189,472
24	State Tax	Income Tax	IL	2017	39,662	0				39,662	0
25	State Tax	Income Tax	IL	2018	32,993	0				32,993	0
26	State Tax	Income Tax	IL	2019	421	0				421	0
27	State Tax	Income Tax	IL	2020	2,491	0				2,491	0
28	State Tax	Income Tax	IL	2021	9,911	0		1,173		8,738	0
29	State Tax	Income Tax	IL	2022						0		14,131			14,131
30	State Tax	Income Tax	KY	2020	2,186	0				2,186	0
31	State Tax	Income Tax	KY	2021	1,122	0		1,657		2,779	0
32	State Tax	Income Tax	KY	2022			186			186		311			125
33	State Tax	Income Tax	MI	2017	381	0				381	0
34	State Tax	Income Tax	MI	2018	608	0				608	0
35	State Tax	Income Tax	MI	2019	73	0				73	0
36	State Tax	Income Tax	MI	2020	83	0				83	0
37	State Tax	Income Tax	MI	2021				72		72
38	State Tax	Income Tax	MULTI	2019	744	0				744	0
39	State Tax	Income Tax	WV	2017	2,016,350	0				2,016,350	0
40	State Tax	Income Tax	WV	2018	852,428	0				852,428	0
41	State Tax	Income Tax	WV	2019	982,751	0				982,751	0
42	State Tax	Income Tax	WV	2020	848,695	0				848,695	0
43	State Tax	Income Tax	WV	2021	132,720	0		2,862,647		2,995,367	0
44	State Tax	Income Tax	WV	2022						0		121,065			121,065
45	Subtotal Income Tax				2,864,211	0	186	2,865,549	0	1,152	0	135,507	0	0	135,321
46	Subtotal Excise Tax				0	0	0	0	0		0	0	0	0	0
47	Subtotal Fuel Tax				0	0	0	0	0		0	0	0	0	0
48	Subtotal Federal Insurance Tax				0	0	0	0	0		0	0	0	0	0
49	Franchise Tax	Franchise Tax	KY	2019	233	0				233	0
50	Franchise Tax	Franchise Tax	KY	2020	175	0				175	0
51	Franchise Tax	Franchise Tax	OK	2021	0	0				0	0
52	Subtotal Franchise Tax				408	0	0	0	0	408	0	0	0	0	0
53	Subtotal Miscellaneous Other Tax				0	0	0	0	0	0	0	0	0	0	0
54	Subtotal Other Federal Tax				0	0	0	0	0	0	0	0	0	0	0
55	Other State Tax	Other State Tax	OH	2021	0	0				0	0
56	Other State Tax	Other State Tax	OH	2022	0	0				0	0
57	Other State Tax	Other State Tax	WV	2018	1,224,202	0				1,224,202	0
58	Other State Tax	Other State Tax	WV	2019		0	6,019	6,019		0	0	6,019
59	Other State Tax	Other State Tax	WV	2020	535,305		172,252	707,557		0		172,252
60	Other State Tax	Other State Tax	WV	2021	0	0	11,290,386	10,255,895		1,034,491	0	11,435,964			145,578
61	Subtotal Other State Tax				688,897	0	11,456,619	10,957,433	0	189,711	0	11,602,197	0	0	145,578
62	Subtotal Other Property Tax				0	0	0	0	0	0	0	0	0	0	0
63	OCC & PUCO FEES	Other Use Tax	OH	2020	0	0				0		82,344			82,344
64	OCC & PUCO FEES	Other Use Tax	OH	2021						0		42,808			42,808
65	Ohio CAT Tax	Other Use Tax	OH	2021			236	236		0		236
66	Ohio CAT Tax	Other Use Tax	OH	2022	0	0	742	742		0		742
67	Subtotal Other Use Tax				0	0	506	506	0	0	0	40,042	0	0	39,536
68	Subtotal Other Advalorem Tax				0	0	0	0	0	0	0	0	0	0	0
69	Other License and Fees Tax	Other License And Fees Tax	WV	2019	26	0				26	0
70	Muni License and Fees Tax	Other License And Fees Tax	WV	2022	0	0		15		15	0
71	Subtotal Other License And Fees Tax				26	0	0	15	0	41	0	0	0	0	0
72	FICA 2022	Payroll Tax			35,474	0	896,106	834,951	90,244	186,873	0	829,143			66,963
73	2360104 FICA	Payroll Tax			0	0	0	0	0	0	0	0			0
74	2360105 FICA CARES ACT	Payroll Tax			90,253	0	0	0	90,253	0	0	0			0
75	Subtotal Payroll Tax				125,727	0	896,106	834,951	9	186,873	0	829,143	0	0	66,963
76	Subtotal Advalorem Tax				0	0	0	0	0	0	0	0	0	0	0
77	Subtotal Other Allocated Tax				0	0	0	0	0	0	0	0	0	0	0
78	Subtotal Severance Tax				0	0	0	0	0	0	0	0	0	0	0
79	Subtotal Penalty Tax				0	0	0	0	0	0	0	0	0	0	0
80	Other Taxes and Fees	Other Taxes and Fees	WV	2020		0				0	0	82,344			82,344
81	Other Taxes and Fees	Other Taxes and Fees	WV	2021	227,000	455,025	341,525	113,500		0	0	0			341,525
82	Other Taxes and Fees	Other Taxes and Fees	WV	2022			649,923	958,526		111,000	419,603	42,808			607,115
83	Subtotal Other Taxes And Fees				227,000	455,025	991,448	1,072,026	0	111,000	419,603	39,536	0	0	1,030,984
40	TOTAL				4,950,144	455,025	6,957,823	9,301,259	9	7,258,149	419,603	7,585,760	0	0	627,937

Name of Respondent:

Wheeling 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%				411
3	4%				411
4	7%				411
5	10%		411		411
6	State DITC		411		411
7	30				411
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

Name of Respondent:

Wheeling 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	Customer Advance Receipts	655,167	142	655,167	751,239	751,239
2	Advance Rental Billings - TV Pole Attachments	148,303	454/172/589/905	911,105	923,360	160,558
3	Deferred Gain Re: Fiber Optic Leases, Amortize through Aug 2025	6,384	124	1,448		4,936
4	Contr in Aid of Constr Advance	54,316	107/108	54,316	2,177,443	2,177,443
5	Other Deferred Credit	4,111			95,436	99,547
6	Federal Mitigation Deferral - NSR	111,797	242	111,797
7	Deferred Rev - Bonus Lease, Amortize through Mar 2024	22,768				22,768
8	2022 PJM Transmission True-up				408,921	408,921
9	Security Deposit	20,000				20,000
10	Asbestos
11	Deferred Rev - Bonus Lease-LT, Amortize through March 2023	28,459	421	22,767		5,692
12	QUAL OF SVC PENALTIES - LT	22,841				22,841
47	TOTAL	1,074,146		1,756,600	4,356,399	3,673,945

Name of Respondent:

Wheeling 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	46,200,830		2,252,501							43,948,329
5	Other
5.1	Other (provide details in footnote):
8	TOTAL Electric (Enter Total of lines 3 thru 7)	46,200,830		2,252,501							43,948,329
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) Others - SFAS 109	18,497,244					254		254	637,574	17,859,670
17	TOTAL (Acct 281) (Total of 8, 15 and 16)	27,703,586		2,252,501						637,574	26,088,659
18	Classification of TOTAL
19	Federal Income Tax	27,703,586		2,252,501						637,574	26,088,659
20	State Income Tax
21	Local Income Tax

Name of Respondent:

Wheeling 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


Description Page 272-273 Line 16	Balance at Beginning of The year	Amounts Debited to Account 410.2	Amounts Credits to Account 411.2	Debit Adjust.	Credit Adjust.	Balance End of Year
SFAS 109	(18,497,244)			—	637,574	(17,859,670)
Total Line 16	(18,497,244)	—	—	—	637,574	(17,859,670)

Name of Respondent:

Wheeling 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	134,234,372	14,577,509	11,056,987					190		137,754,894
3	Gas
4	Other (Specify)
5	Total (Total of lines 2 thru 4)	134,234,372	14,577,509	11,056,987							137,754,894
6	(a) Other	19,917,035					1823/254	2,365,700	1823/254	5,483,660	16,799,075
9	TOTAL Account 282 (Total of Lines 5 thru 8)	114,317,337	14,577,509	11,056,987				2,365,700		5,483,660	120,955,819
10	Classification of TOTAL
11	Federal Income Tax	114,317,337	14,577,509	11,056,987				2,365,700		5,483,660	120,955,819
12	State Income Tax
13	Local Income Tax

Name of Respondent:

Wheeling 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: DescriptionOfNonUtilityAccountDetails


Line 6 Footnote

	Beg Bal	Debits	Credits	End Bal
SFAS 109	(19,917,035)	2,365,700	5,483,660	(16,799,075)
Total Other - Line 6	(19,917,035)	2,365,700	5,483,660	(16,799,075)

Name of Respondent:

Wheeling 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	DSIT ENTRY - NORMALIZED	4,697,299									4,697,299
4	Reg Asset Big Sandy	3,082,683		161,540							2,921,143
5	REG ASSET-SFAS 158 - PENSIONS	21,344,419	27,176,725								48,521,144
6	REG ASSET-NE U4 UNDEPRECIATED BALANCE	2,285,951	153,865								2,132,086
7	REG ASSET-ADVANCED METERING SYSTEM	2,587,619		438,813							2,148,806
8	Others	9,269,367	12,336,959	5,898,719							15,707,607
9	TOTAL Electric (Total of lines 3 thru 8)	38,695,436	39,667,549	6,499,072							71,863,913
10	Gas
11
12
13
14
15
16
17	TOTAL Gas (Total of lines 11 thru 16)
18	TOTAL Other	(a) 56,601,297			1,733,098	174,269	1823/254	2,513,356	1823/254	14,555,918	70,202,688
19	TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)	95,296,733	39,667,549	6,499,072	1,733,098	174,269		2,513,356		14,555,918	142,066,601
20	Classification of TOTAL
21	Federal Income Tax	39,231,704	36,236,809	4,699,842	1,733,098	174,269		1,629,790		3,991,312	74,689,022
22	State Income Tax	56,065,029	3,430,740	1,799,230				883,566		10,564,606	67,377,579
23	Local Income Tax
NOTES

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesOther

Non-Utility

Name of Respondent:

Wheeling 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	SFAS 109 Deferred Federal income Tax	60,184,526	182	3,072,653	877,001	57,988,874
2	SFAS 109 Deferred State income Tax	77,097				77,097
3	DSM Over Recovery - WV EEDRWV Public Service CommissionCase No. 10-0261-E-G1	6,928,498	908/182	536,734	1,601,149	7,992,913
4	Unrealized Gain on Forward Commitments	3,556,868	175/182/244	5,970,301	7,320,493	4,907,060
5	Netting of Trading Activities related toUnrealized Gains/Losses on Forward		175/244/254	49,428	74,462	25,034
6	WV Vegetation Management ProgramWV Public Service CommissionRate Order: WV PSC Case 14-1152-E-42T	10,502,527	593	821,975	3,434,680	13,115,232
7	WV BRSP Rider Over-Recovery				25,415	25,415
8	PJM trans enhancement settlement for refund	1,489,581	142	418,102		1,071,479
9	WV ECS Over Recovery	164,279	182/405	285,504	121,225
10	Broadband Over-Rec - APCo WVa				157,330	157,330
41	TOTAL	82,903,376		11,154,697	13,611,755	85,360,434

Name of Respondent:

Wheeling 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	61,828,106	57,101,172	387,427	398,799	34,707	34,889
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)	42,325,659	38,785,579	377,028	387,267	6,288	6,249
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)	261,941,434	223,197,399	4,053,870	3,868,412	426	410
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting	832,385	770,160	5,606	5,564	137	137
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) 366,927,584	(b) 319,854,309	4,823,931	4,660,041	41,558	41,685
11	SalesForResaleAbstract (447) Sales for Resale	31,428,516	20,594,986	291,266	403,446	5	10
12	SalesOfElectricityAbstract TOTAL Sales of Electricity	398,356,099	340,449,295	5,115,198	5,063,487	41,563	41,695
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds	2,578,313
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds	395,777,786	340,449,295	5,115,198	5,063,487	41,563	41,695
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts	160,897	141,064
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	39,234	15,085
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power
19	RentFromElectricProperty (454) Rent from Electric Property	4,101,990	2,363,422
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	459,421	182,830
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	6,683,150	6,184,498
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	11,444,692	8,886,899
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	407,222,479	349,336,194
Line12, column (b) includes $ 1,636,721 of unbilled revenues.
Line12, column (d) includes 12,232 MWH relating to unbilled revenues

Name of Respondent:

Wheeling 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

Details of Unmetered Sales included in Total Sales to Ultimate Customers


Rate Schedule	Revenue	MWH Sold	Avg No of Customers
4400 RESIDENTIAL	208,393	1,007	1,489
4420 COMMERCIAL	349,729	2,455	946
4420 INDUSTRIAL	56,492	411	50
4440 PUBLIC STREET & HIGHWAY LIGHT	5,535	23	10
Total	620,149	3,896	2,495

(b) Concept: SalesToUltimateConsumers

Details of Unmetered Sales included in Total Sales to Ultimate Customers


Rate Schedule	Revenue	MWH Sold	Avg No of Customers
4400 RESIDENTIAL	200,970	1,036	1,506
4420 COMMERCIAL	325,382	2,469	944
4420 INDUSTRIAL	52,416	412	52
4440 PUBLIC STREET & HIGHWAY LIGHT	5,267	23	10
Total	584,035	3,940	2,512

Name of Respondent:

Wheeling 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:

Wheeling 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			0
2	GS	2	489			0.2445
3	OLS	1,007	208,392			0.2069
4	RS	378,264	60,224,277	34,137	11,081	0.1592
5	RSE	7,490	1,148,532	567	13,210	0.1533
6	RS-TOD	48	5,621	3	16,000	0.1171
41	TOTAL Billed Residential Sales	386,811	61,587,311	34,707	11,145	0.1592
42	TOTAL Unbilled Rev. (See Instr. 6)	616	240,795			0.3909
43	TOTAL	387,427	61,828,106	34,707	11,163	0.1596

Name of Respondent:

Wheeling 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	2,270	167,710			0.0739
2	GS	281,854	32,316,108	1,979	142,422	0.1147
3	GS-TOD	823	97,567	19	43,316	0.1186
4	LCP	59,260	4,973,955	5	11,852,000	0.0839
5	MGS	521	51,878	16	32,563	0.0996
6	OLS	2,455	349,729	0		0.1425
7	RS		28	0
8	SGS	18,913	2,827,686	4,100	4,613	0.1495
9	SS	6,370	775,344	19	335,263	0.1217
10	SWS	4,041	597,294	150	26,940	0.1478
41	TOTAL Billed Small or Commercial	376,507	42,157,299	6,288	59,877	0.1120
42	TOTAL Unbilled Rev. Small or Commercial (See Instr. 6)	521	168,360			0.3231
43	TOTAL Small or Commercial	377,028	42,325,659	6,288	59,960	0.1123

Name of Respondent:

Wheeling 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	20,379	1,452,925			0.0713
2	GS	54,009	5,908,417	180		0.1094
3	GS-TOD	90	11,252	2		0.1250
4	LCP	3,508,102	218,376,327	24	146,170,917	0.0622
5	OLS	411	56,492			0.1375
6	REFUND		1,872,862
7	SGS	941	136,103	219		0.1446
8	SEG		26,203
9	SPECIAL	458,840	34,588,526	1	458,840,000	0.0754
10	Provision for Refund		2,083,179
41	TOTAL Billed Large (or Ind.) Sales	4,042,772	260,714,156	426	9,490,075
42	TOTAL Unbilled Rev. Large (or Ind.) (See Instr. 6)	11,098	1,227,278			0.1106
43	TOTAL Large (or Ind.)	4,053,870	261,941,434	426	9,516,127	0.0646

Name of Respondent:

Wheeling 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:

Wheeling 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	GS	1,176	131,393	15	78,400	0.1117
3	OLS	22	5,535			0.2516
4	SGS	516	74,217	110	4,691	0.1438
5	SL	3,895	620,952	12	324,583	0.1594
41	TOTAL Billed Public Street and Highway Lighting	5,609	832,097	137	40,942	0.1484
42	TOTAL Unbilled Rev. (See Instr. 6)	3	288			0.0960
43	TOTAL	5,606	832,385	137	40,920	0.1485

Name of Respondent:

Wheeling 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		2,578,313

Name of Respondent:

Wheeling 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	4,811,699	365,290,863	41,558	115,783
42	TOTAL Unbilled Rev. (See Instr. 6) - All Accounts	12,232	1,636,721
43	TOTAL - All Accounts	4,823,931	366,927,584	41,558	115,783

Name of Respondent:

Wheeling 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		9		9
2	CITIGROUP ENERGY INC.	OS	NOTE 1				0		772		772
3	FIRSTENERGY TRADING SERVICES	OS	NOTE 1				1,570		64,814		64,814
4	(a) OHIO POWER COMPANY (AUCTION)	OS	(c) NOTE 1				7		215		215
5	PJM INTERCONNECTION	OS	NOTE 1				289,703	2,301,104	29,020,415		31,321,518
6	PPL ELECTRIC UTILITIES CORP	OS	NOTE 1				0		21		21
7	WELLS FARGO SECURITIES, LLC	OS	NOTE 1				0		43,200		43,200
15	Subtotal - RQ
16	Subtotal-Non-RQ						291,266	2,301,104	29,127,412		31,428,516
17	Total						291,266	2,301,104	29,127,412		31,428,516

Name of Respondent:

Wheeling 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.

Name of Respondent:

Wheeling 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	2,467,653	1,984,550
5	FuelSteamPowerGeneration (501) Fuel	72,814,397	8,966,693
6	SteamExpensesSteamPowerGeneration (502) Steam Expenses	5,696,627	6,914,626
7	SteamFromOtherSources (503) Steam from Other Sources
8	SteamTransferredCredit (Less) (504) Steam Transferred-Cr.
9	ElectricExpensesSteamPowerGeneration (505) Electric Expenses	182,054	308,748
10	MiscellaneousSteamPowerExpenses (506) Miscellaneous Steam Power Expenses	2,849,686	2,121,733
11	RentsSteamPowerGeneration (507) Rents
12	Allowances (509) Allowances	3,213	374
13	SteamPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 4 thru 12)	61,621,590	20,296,725
14	SteamPowerGenerationMaintenanceAbstract Maintenance
15	MaintenanceSupervisionAndEngineeringSteamPowerGeneration (510) Maintenance Supervision and Engineering	1,237,575	1,229,616
16	MaintenanceOfStructuresSteamPowerGeneration (511) Maintenance of Structures	701,885	929,048
17	MaintenanceOfBoilerPlantSteamPowerGeneration (512) Maintenance of Boiler Plant	10,590,115	8,310,320
18	MaintenanceOfElectricPlantSteamPowerGeneration (513) Maintenance of Electric Plant	2,517,688	2,632,353
19	MaintenanceOfMiscellaneousSteamPlant (514) Maintenance of Miscellaneous Steam Plant	714,662	815,248
20	SteamPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 15 thru 19)	15,761,925	13,916,585
21	PowerProductionExpensesSteamPower TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)	45,859,666	34,213,309
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	7	1
67	OtherPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 62 thru 67)	7	1
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)	7	1
75	OtherPowerSuplyExpensesAbstract E. Other Power Supply Expenses
76	PurchasedPower (555) Purchased Power	223,231,299	106,122,196
76.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations	0
77	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching	117,578
78	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	569,829	389,770
79	OtherPowerSupplyExpense TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)	223,918,706	106,511,966
80	PowerProductionExpenses TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74 & 79)	178,059,033	140,725,276
81	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
82	TransmissionExpensesOperationAbstract Operation
83	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	405,582	435,152
85	LoadDispatchReliability (561.1) Load Dispatch-Reliability
86	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	23,129	23,971
87	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling
88	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services	1,055,951	952,102
89	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development	15,216	24,867
90	TransmissionServiceStudies (561.6) Transmission Service Studies
91	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies
92	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services	300,351	274,873
93	StationExpensesTransmissionExpense (562) Station Expenses	131,345	12,546
93.1	OperationOfEnergyStorageEquipmentTransmissionExpense (562.1) Operation of Energy Storage Equipment
94	OverheadLineExpense (563) Overhead Lines Expenses	3,336	2,840
95	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses
96	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	72,326,309	58,066,836
97	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	110,756	113,278
98	RentsTransmissionElectricExpense (567) Rents
99	TransmissionOperationExpense TOTAL Operation (Enter Total of Lines 83 thru 98)	74,371,975	59,906,464
100	TransmissionMaintenanceAbstract Maintenance
101	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering	198	445
102	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	446	1,196
103	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware	1,066	(a) 1,386
104	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software	27,953	20,605
105	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment	2,705	878
106	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	106,825	156,763
107.1	MaintenanceOfEnergyStorageEquipmentTransmission (570.1) Maintenance of Energy Storage Equipment
108	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	539,569	784,173
109	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines		4
110	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant	226	143
111	TransmissionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 101 thru 110)	678,988	965,585
112	TransmissionExpenses TOTAL Transmission Expenses (Total of Lines 99 and 111)	75,050,963	60,872,050
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	813,529	893,857
122	RentsRegionalMarketExpenses (575.8) Rents
123	RegionalMarketOperationExpense Total Operation (Lines 115 thru 122)	813,529	893,857
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)	813,529	893,857
132	DistributionExpensesAbstract 4. DISTRIBUTION EXPENSES
133	DistributionExpensesOperationAbstract Operation
134	OperationSupervisionAndEngineeringDistributionExpense (580) Operation Supervision and Engineering	191,950	240,944
135	LoadDispatching (581) Load Dispatching
136	StationExpensesDistribution (582) Station Expenses	72,693	119,365
137	OverheadLineExpenses (583) Overhead Line Expenses	201,076	10,059
138	UndergroundLineExpenses (584) Underground Line Expenses	79,125	72,892
138.1	OperationOfEnergyStorageEquipmentDistribution (584.1) Operation of Energy Storage Equipment
139	StreetLightingAndSignalSystemExpenses (585) Street Lighting and Signal System Expenses		54,522
140	MeterExpenses (586) Meter Expenses	28,348	124,997
141	CustomerInstallationsExpenses (587) Customer Installations Expenses	54,183	44,229
142	MiscellaneousDistributionExpenses (588) Miscellaneous Expenses	896,889	725,104
143	RentsDistributionExpense (589) Rents	345,817	97,564
144	DistributionOperationExpensesElectric TOTAL Operation (Enter Total of Lines 134 thru 143)	1,813,385	1,469,559
145	DistributionExpensesMaintenanceAbstract Maintenance
146	MaintenanceSupervisionAndEngineering (590) Maintenance Supervision and Engineering	1,445	1,005
147	MaintenanceOfStructuresDistributionExpense (591) Maintenance of Structures	4,688	4,760
148	MaintenanceOfStationEquipment (592) Maintenance of Station Equipment	232,553	141,464
148.1	MaintenanceOfEnergyStorageEquipment (592.2) Maintenance of Energy Storage Equipment
149	MaintenanceOfOverheadLines (593) Maintenance of Overhead Lines	14,634,664	11,662,580
150	MaintenanceOfUndergroundLines (594) Maintenance of Underground Lines	261,477	271,906
151	MaintenanceOfLineTransformers (595) Maintenance of Line Transformers	9,208	30,485
152	MaintenanceOfStreetLightingAndSignalSystems (596) Maintenance of Street Lighting and Signal Systems	47,817	37,813
153	MaintenanceOfMeters (597) Maintenance of Meters	9,467	18,268
154	MaintenanceOfMiscellaneousDistributionPlant (598) Maintenance of Miscellaneous Distribution Plant	160,826	154,319
155	DistributionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 146 thru 154)	15,362,145	12,322,599
156	DistributionExpenses TOTAL Distribution Expenses (Total of Lines 144 and 155)	17,175,530	13,792,158
157	CustomerAccountsExpensesAbstract 5. CUSTOMER ACCOUNTS EXPENSES
158	CustomerAccountsExpensesOperationsAbstract Operation
159	SupervisionCustomerAccountExpenses (901) Supervision	4,304	4,245
160	MeterReadingExpenses (902) Meter Reading Expenses	119,159	184,596
161	CustomerRecordsAndCollectionExpenses (903) Customer Records and Collection Expenses	973,671	914,678
162	UncollectibleAccounts (904) Uncollectible Accounts	348,250	382,400
163	MiscellaneousCustomerAccountsExpenses (905) Miscellaneous Customer Accounts Expenses	5,264	5,726
164	CustomerAccountExpenses TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)	1,450,648	1,491,645
165	CustomerServiceAndInformationalExpensesAbstract 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166	CustomerServiceAndInformationalExpensesOperationAbstract Operation
167	SupervisionCustomerServiceAndInformationExpenses (907) Supervision	6,266	9,340
168	CustomerAssistanceExpenses (908) Customer Assistance Expenses	1,350,796	1,991,901
169	InformationalAndInstructionalAdvertisingExpenses (909) Informational and Instructional Expenses
170	MiscellaneousCustomerServiceAndInformationalExpenses (910) Miscellaneous Customer Service and Informational Expenses	3,783	2,314
171	CustomerServiceAndInformationExpenses TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)	1,360,846	2,003,555
172	SalesExpenseAbstract 7. SALES EXPENSES
173	SalesExpenseOperationAbstract Operation
174	SupervisionSalesExpense (911) Supervision
175	DemonstratingAndSellingExpenses (912) Demonstrating and Selling Expenses	4,130	5,513
176	AdvertisingExpenses (913) Advertising Expenses
177	MiscellaneousSalesExpenses (916) Miscellaneous Sales Expenses
178	SalesExpenses TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)	4,130	5,513
179	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
180	AdministrativeAndGeneralExpensesOperationAbstract Operation
181	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	3,545,436	3,738,971
182	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	666,546	398,872
183	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit	304,613	242,218
184	OutsideServicesEmployed (923) Outside Services Employed	1,905,214	1,275,562
185	PropertyInsurance (924) Property Insurance	397,353	475,103
186	InjuriesAndDamages (925) Injuries and Damages	326,564	507,649
187	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	193,085	1,369,656
188	FranchiseRequirements (927) Franchise Requirements
189	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	1,039,735	1,196,567
190	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.
191	GeneralAdvertisingExpenses (930.1) General Advertising Expenses	2,962	3,120
192	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	313,450	183,634
193	RentsAdministrativeAndGeneralExpense (931) Rents	93,972	80,097
194	AdministrativeAndGeneralOperationExpense TOTAL Operation (Enter Total of Lines 181 thru 193)	8,179,704	8,987,013
195	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
196	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	1,248,507	496,925
197	AdministrativeAndGeneralExpenses TOTAL Administrative & General Expenses (Total of Lines 194 and 196)	9,428,211	9,483,938
198	OperationsAndMaintenanceExpensesElectric TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 156, 164, 171, 178, and 197)	283,342,889	229,267,992

Name of Respondent:

Wheeling 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: MaintenanceOfComputerHardwareTransmission

Allocated maintenance expense for joint use computer hardware, computer software and communication equipment are determined by using various factors, which include number of remote terminal units, number of radios, number of employees, and other factors assigned to each function. This note applies to both current and prior year.

Name of Respondent:

Wheeling 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.

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

(m)

(n)

1

(a)

EAGLE NATRIUM LLC

OS

10,941

441,366

2

PJM INTERCONNECTION

OS

3,487,174

222,789,933

15

TOTAL

3,498,115

0

223,231,299

Name of Respondent:

Wheeling 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

Non-FERC jurisdictional seller.

Name of Respondent:

Wheeling 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

Ohio Power Company

(a)

See Footnote

LFP

18

See Footnote

(c)

2,738,353

2

PJM Network Integ Trans Rev Whlse

Various

FNO

(b)

PJM OATT

Various

339,595

3

PJM Network Integ Trans Serv

Various

FNO

PJM OATT

Various

1,376,434

4

PJM Trans Enhancement Rev

Various

FNO

PJM OATT

Various

238,535

5

PJM Trans Enhancement Rev Whlsle

Various

FNO

PJM OATT

Various

7,656

6

PJM Network Integ Rev - Affil

Various

FNS

PJM OATT

Various

704,118

7

PJM Point to Point Trans Service

Various

LFP

PJM OATT

Various

1,225,527

8

PJM Trans Owner Admin Revenue

Various

OLF

PJM OATT

Various

13,099

9

PJM Trans Owner Serv - Affiliated

Various

OLF

PJM OATT

Various

74,114

10

PJM Trans Owner Serv Rev Whlsle

Various

OLF

PJM OATT

Various

8,083

35

TOTAL

0

3,891,865

52,932

2,738,353

6,683,150

Name of Respondent:

Wheeling 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: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName

Transmission of Electricity for Others (Account 456.1) Energy Delivered To: Ohio Power Company (Affiliated)

Transmission facilities provided and basis of settlement are pursuant to Transmission Facilities Agreement dated March 1, 1963 (modifications dated September 1, 1965; March 17, 1967; March 20, 1982), designated as Wheeling Power Company Rate Schedule F.E.R.C. #4 and agreement dated December 7, 1966 (modification dated March 20, 1982), designated as rate schedule F.E.R.C. #6.

Charges are not based on quantity of energy transmitted. Points of Origin and Termination:

1. Ohio state line near Brilliant, Ohio--Weirton, West Virginia.

2. Kammer Plant (Captina, West Virginia--Fort Martin)(Point near Pennsylvania state line).

3. Ohio state line near Brilliant, Ohio (point near Pennsylvania state line).

4. Kammer Plant (Captina, West Virginia--Ohio state line near Hannibal, Ohio).

5. Ohio state line near East Liverpool, Ohio--Arroyo Station (point near Pennsylvania state line).

(b) 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

(c) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Amount represents charges for leased lines.

Name of Respondent:

Wheeling 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:

Wheeling 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	PJM - Enhancements	OS					(a) 5,339,928	5,339,928
2	PJM - NITS	OS					(b) 66,885,408	66,885,408
3	PJM - Trans Owner	OS					(c) 100,973	100,973
	TOTAL		0	0	0	0	72,326,309	72,326,309

FOOTNOTE DATA

(a) Concept: OtherChargesTransmissionOfElectricityByOthers

Transmission Enhancement Charges and credits (PJM OATT Schedule 12).

(b) Concept: OtherChargesTransmissionOfElectricityByOthers

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

(c) Concept: OtherChargesTransmissionOfElectricityByOthers

Transmission Owner Charges and Credits (PJM OATT Tariff Sixth Revised Volume No. 1)

Name of Respondent:

Wheeling 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	49,459
2	NuclearPowerResearchExpenses Nuclear Power Research Expenses
3	OtherExperimentalAndGeneralResearchExpenses Other Experimental and General Research Expenses	121
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	Associated Business Development	126,958
7	Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000	27,965
8	Service Corporation and Affiliated Billings	74,879
9	Corporate and Fiscal	34,068
46	MiscellaneousGeneralExpenses TOTAL	313,450

Name of Respondent:

Wheeling 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			1,312,588		1,312,588
2	Steam Production Plant	29,216,377	190,034			29,406,411
3	Nuclear Production Plant
4	Hydraulic Production Plant-Conventional
5	Hydraulic Production Plant-Pumped Storage
6	Other Production Plant
7	Transmission Plant	3,400,294				3,400,294
8	Distribution Plant	9,459,212				9,459,212
9	Regional Transmission and Market Operation
10	General Plant	420,504	8,420			428,924
11	Common Plant-Electric
12	TOTAL	42,496,387	198,454	1,312,588		44,007,429

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 - Mitchell	57.239
14	312 - Mitchell	882.625
15	312 - Mitchell SCR	9.11
16	314 - Mitchell	55.5
17	315 - Mitchell	25.842
18	316 - Mitchell	9.352
19	TOTAL COAL/LIGNITE	1,039.668
20	TRANSMISSION
21	352	3.038
22	352 - Mitchell GSU	0.072
23	353	60.009
24	353 - Mitchell GSU	12.267
25	353.16	0.774
26	354	5.286
27	355	52.172
28	356	26.862
29	356.16	0.029
30	357	0.011
31	358	0.077
32	TOTAL TRANSMISSION	160.597
33	DISTRIBUTION
34	361	2.495
35	362	36.499
36	362.16	0.787
37	364	51.62
38	365	50.083
39	366	23.07
40	367	32.577
41	368	30.625
42	369	17.666
43	370	10.832
44	370.16	2.156
45	371	1.934
46	373	1.657
47	TOTAL DISTRIBUTION	262.001
48	GENERAL PLANT
49	390	3.192
50	391	0.041
51	393	0.058
52	394	0.843
53	395	0.031
54	397	6.832
55	398	0.323
56	TOTAL GENERAL PLANT	11.32
57	DEPRECIABLE SUM	(a) 1,473.586

Name of Respondent:

Wheeling 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.

Name of Respondent:

Wheeling 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	Rate Case Expense		6,909	6,909	6,909	Electric	928			928	6,909
2	Misc Exp - Items less than $25,000		41,377	41,377		Electric	928	41,377
3	State Commission Fees		991,448	991,448		Electric	928	991,448
46	TOTAL		1,039,734	1,039,734	6,909			1,032,825			6,909

Name of Respondent:

Wheeling 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	PERFORMED INTERNALLY
2	A(1)e Unconventional Generation
3	A(2) Transmission	1 ITEMS UNDER $50,000	411		566	411
4	A(3) Distribution	1 ITEM UNDER $50,000	1,025		588	1,025
5	A(6) Other	2 ITEMS UNDER $50,000	1,540		566/588	1,540
6	A(6)f Metering	1 ITEM UNDER $50,000	139		588	139
7	A(6)g Research - General	1 ITEM UNDER $50,000	275		566/588	275
8	A(7) TOTAL COST INCURRED INTERNALLY		3,391			3,391
9	PERFORMED EXTERNALLY
10	B Memberships	5 ITEMS UNDER $50,000		4,234	566/588	4,234
11	B(1) Research Support to Elec. Research	10 ITEMS UNDER $50,000		30,415	566/588	30,415
12	Council & Elec. Power Research Inst.
13	B(4) Substation Equipment Management	1 ITEM UNDER $50,000
14	B(5)TOTAL COST INCURRED EXTERNALLY			34,649		34,649

Name of Respondent:

Wheeling 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	5,044,805
4	SalariesAndWagesElectricOperationTransmission Transmission
5	SalariesAndWagesElectricOperationRegionalMarket Regional Market
6	SalariesAndWagesElectricOperationDistribution Distribution	212,524
7	SalariesAndWagesElectricOperationCustomerAccounts Customer Accounts	201,633
8	SalariesAndWagesElectricOperationCustomerServiceAndInformational Customer Service and Informational
9	SalariesAndWagesElectricOperationSales Sales
10	SalariesAndWagesElectricOperationAdministrativeAndGeneral Administrative and General	96,035
11	SalariesAndWagesElectricOperation TOTAL Operation (Enter Total of lines 3 thru 10)	5,362,927
12	SalariesAndWagesElectricMaintenanceAbstract Maintenance
13	SalariesAndWagesElectricMaintenanceProduction Production	3,771,233
14	SalariesAndWagesElectricMaintenanceTransmission Transmission	1,444
15	SalariesAndWagesElectricMaintenanceRegionalMarket Regional Market
16	SalariesAndWagesElectricMaintenanceDistribution Distribution	1,502,192
17	SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral Administrative and General	1,302
18	SalariesAndWagesElectricMaintenance TOTAL Maintenance (Total of lines 13 thru 17)	5,276,171
19	SalariesAndWagesElectricOperationAndMaintenanceAbstract Total Operation and Maintenance
20	SalariesAndWagesElectricProduction Production (Enter Total of lines 3 and 13)	8,816,038
21	SalariesAndWagesElectricTransmission Transmission (Enter Total of lines 4 and 14)	1,444
22	SalariesAndWagesElectricRegionalMarket Regional Market (Enter Total of Lines 5 and 15)
23	SalariesAndWagesElectricDistribution Distribution (Enter Total of lines 6 and 16)	1,714,716
24	SalariesAndWagesElectricCustomerAccounts Customer Accounts (Transcribe from line 7)	201,633
25	SalariesAndWagesElectricCustomerServiceAndInformational Customer Service and Informational (Transcribe from line 8)
26	SalariesAndWagesElectricSales Sales (Transcribe from line 9)
27	SalariesAndWagesElectricAdministrativeAndGeneral Administrative and General (Enter Total of lines 10 and 17)	94,733
28	SalariesAndWagesElectricOperationAndMaintenance TOTAL Oper. and Maint. (Total of lines 20 thru 27)	10,639,098	311,982	10,951,080
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)	10,639,098	311,982	10,951,080
66	SalariesAndWagesUtilityPlantAbstract Utility Plant
67	SalariesAndWagesUtilityPlantConstructionAbstract Construction (By Utility Departments)
68	SalariesAndWagesUtilityPlantConstructionElectricPlant Electric Plant	2,237,272	65,606	2,302,878
69	SalariesAndWagesUtilityPlantConstructionGasPlant Gas Plant
70	SalariesAndWagesUtilityPlantConstructionOther Other (provide details in footnote):
71	SalariesAndWagesUtilityPlantConstruction TOTAL Construction (Total of lines 68 thru 70)	2,237,272	65,606	2,302,878
72	SalariesAndWagesPlantRemovalAbstract Plant Removal (By Utility Departments)
73	SalariesAndWagesPlantRemovalElectricPlant Electric Plant	476,440	13,971	490,411
74	SalariesAndWagesPlantRemovalGasPlant Gas Plant
75	SalariesAndWagesPlantRemovalOther Other (provide details in footnote):
76	SalariesAndWagesPlantRemoval TOTAL Plant Removal (Total of lines 73 thru 75)	476,440	13,971	490,411
77	SalariesAndWagesOtherAccountsAbstract Other Accounts (Specify, provide details in footnote):
78	SalariesAndWagesOtherAccountsDescription Other Accounts (Specify, provide details in footnote):
79	SalariesAndWagesOtherAccountsDescription 152 - Fuel Stock Undistributed	1,121,875		1,121,875
80	SalariesAndWagesOtherAccountsDescription 154 - Materials and Supplies
81	SalariesAndWagesOtherAccountsDescription 163 - Stores Expense Undistributed	182,731	182,731
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	203,072	203,072
86	SalariesAndWagesOtherAccountsDescription 185 - ODD Temporary Facilities	2,249		2,249
87	SalariesAndWagesOtherAccountsDescription 186 - Misc Deferred Debits	922		922
88	SalariesAndWagesOtherAccountsDescription 188 - Research & Development
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	4,230		4,230
94	SalariesAndWagesOtherAccountsDescription 451 - Misc Service Rev - Nonaffil
95	SalariesAndWagesOtherAccountsDescription 456 - Other Electric Revenue
95	SalariesAndWagesOtherAccounts TOTAL Other Accounts	1,518,991	391,559	1,127,432
96	SalariesAndWagesGeneralExpense TOTAL SALARIES AND WAGES	14,871,801		14,871,801

Name of Respondent:

Wheeling 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:

Wheeling 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)				217,120,348
2.1	Net Purchases (Account 555.1)
3	Net Sales (Account 447)				28,118,901
4	Transmission Rights				10,117,735
5	Ancillary Services				1,473,729
6	Other Items (list separately)
7	Congestion				12,858,891
8	Operating Reserves				851,063
9	Transmission Purchase Expense
10	Transmission Losses				202,082
11	Meter Corrections				2,381
12	Inadvertent				93,415
13	Capacity Credits				2,301,104
46	TOTAL				191,468,413

Name of Respondent:

Wheeling 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
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:

Wheeling 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:

Wheeling 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

Wheeling 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:

Wheeling 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:

Wheeling 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)	4,823,931
3	Steam	1,751,093	23	Requirements Sales for Resale (See instruction 4, page 311.)
4	Nuclear		24	Non-Requirements Sales for Resale (See instruction 4, page 311.)	291,266
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	134,011
8	Less Energy for Pumping		27.1	Total Energy Stored
9	Net Generation (Enter Total of lines 3 through 8)	1,751,093	28	TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL LINE 20 UNDER SOURCES	5,249,208
10	Purchases (other than for Energy Storage)	3,498,115
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)	5,249,208

Name of Respondent:

Wheeling 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	438,280	34,638	602	26	13
30	February	373,798	9,189	607	1	8
31	March	421,828	5,975	635	3	20
32	April	412,387	14,061	641	5	8
33	May	447,487	9,011	690	21	17
34	June	456,906	29,080	736	30	17
35	July	489,879	29,822	728	20	19
36	August	448,624	32,795	692	4	15
37	September	428,736	18,366	645	9	16
38	October	429,285	22,293	622	3	9
39	November	425,417	29,122	636	9	22
40	December	476,581	59,712	624	19	21
41	Total	5,249,208	294,064

Name of Respondent:

Wheeling 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: MITCHELL -TOTAL	Plant Name: MITCHELL-WPCO Share
1	PlantKind Kind of Plant (Internal Comb, Gas Turb, Nuclear)		STEAM	(a) STEAM
2	PlantConstructionType Type of Constr (Conventional, Outdoor, Boiler, etc)		OUTDOOR BOILER	OUTDOOR BOILER
3	YearPlantOriginallyConstructed Year Originally Constructed		1971	1971
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed		1971	1971
5	InstalledCapacityOfPlant Total Installed Cap (Max Gen Name Plate Ratings-MW)		1,633	816
6	NetPeakDemandOnPlant Net Peak Demand on Plant - MW (60 minutes)		1,574	787
7	PlantHoursConnectedToLoad Plant Hours Connected to Load		958	958
8	NetContinuousPlantCapability Net Continuous Plant Capability (Megawatts)		0	0
9	NetContinuousPlantCapabilityNotLimitedByCondenserWater When Not Limited by Condenser Water		1,560	780
10	NetContinuousPlantCapabilityLimitedByCondenserWater When Limited by Condenser Water		1,560	780
11	PlantAverageNumberOfEmployees Average Number of Employees		309	154
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh		3,502,186,000	1,751,093,000
13	CostOfLandAndLandRightsSteamProduction Cost of Plant: Land and Land Rights		6,197,188	3,098,594
14	CostOfStructuresAndImprovementsSteamProduction Structures and Improvements		114,658,466	57,241,983
15	CostOfEquipmentSteamProduction Equipment Costs		1,975,214,424	989,172,442
16	AssetRetirementCostsSteamProduction Asset Retirement Costs		11,057,543	6,439,212
17	CostOfPlant Total cost (total 13 thru 20)		2,107,127,621	1,055,952,231
18	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 17/5) Including		1,290.3415	1,294.0591
19	OperationSupervisionAndEngineeringExpense Production Expenses: Oper, Supv, & Engr		5,647,624	2,467,653
20	FuelSteamPowerGeneration Fuel		113,322,640	56,598,581
21	CoolantsAndWater Coolants and Water (Nuclear Plants Only)		0	0
22	SteamExpensesSteamPowerGeneration Steam Expenses		11,393,278	5,696,627
23	SteamFromOtherSources Steam From Other Sources		0	0
24	SteamTransferredCredit Steam Transferred (Cr)		0	0
25	ElectricExpensesSteamPowerGeneration Electric Expenses		364,109	182,054
26	MiscellaneousSteamPowerExpenses Misc Steam (or Nuclear) Power Expenses		6,054,364	2,849,686
27	RentsSteamPowerGeneration Rents		0	0
28	Allowances Allowances		45,600	3,213
29	MaintenanceSupervisionAndEngineeringSteamPowerGeneration Maintenance Supervision and Engineering		2,485,553	1,237,575
30	MaintenanceOfStructuresSteamPowerGeneration Maintenance of Structures		1,404,041	701,885
31	MaintenanceOfBoilerPlantSteamPowerGeneration Maintenance of Boiler (or reactor) Plant		21,350,029	10,590,115
32	MaintenanceOfElectricPlantSteamPowerGeneration Maintenance of Electric Plant		5,035,310	2,517,688
33	MaintenanceOfMiscellaneousSteamPlant Maintenance of Misc Steam (or Nuclear) Plant		1,427,781	714,662
34	PowerProductionExpensesSteamPower Total Production Expenses	0	168,530,329	83,553,313
35	ExpensesPerNetKilowattHour Expenses per Net kWh	0	0.0481	0.0477

35	FuelKindAxis Plant Name	MITCHELL -TOTAL	MITCHELL -TOTAL	MITCHELL-WPCO Share	MITCHELL-WPCO Share
36	FuelKind Fuel Kind	Coal	Oil	Coal	Oil
37	FuelUnit Fuel Unit	Mcf	bbl	Mcf	bbl
38	QuantityOfFuelBurned Quantity (Units) of Fuel Burned	1,523,492	62,205	761,746	32,294
39	FuelBurnedAverageHeatContent Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)	12,444	125,839	12,462	126,024
40	AverageCostOfFuelPerUnitAsDelivered Avg Cost of Fuel/unit, as Delvd f.o.b. during year	64.492	152.075	61.193	152.075
41	AverageCostOfFuelPerUnitBurned Average Cost of Fuel per Unit Burned	59.643	142.292	56.270	79.553
42	AverageCostOfFuelBurnedPerMillionBritishThermalUnit Average Cost of Fuel Burned per Million BTU	2.396	26.923	2.258	15.030
43	AverageCostOfFuelBurnedPerKilowattHourNetGeneration Average Cost of Fuel Burned per kWh Net Gen	0.026	0.000	0.024	0.000
44	AverageBritishThermalUnitPerKilowattHourNetGeneration Average BTU per kWh Net Generation	10,913	0	10,913	0.000

Name of Respondent:

Wheeling 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: PlantKind

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

Name of Respondent:

Wheeling 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:

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

Wheeling 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:

Wheeling 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:

Wheeling 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	0444 KAMMER	FT MARTIN	500.00	500.00	3	14.43	0.00	0	954 ACSR
2	0437 TIDD	COLLIER	345.00	345.00	3	7.01	0.00	2	954 ACSR
3	0437 TIDD	COLLIER	345.00	345.00	1	0.38	0.00	0	954 ACSR
4	0445 TIDD	WYLIE RIDGE	345.00	345.00	3	1.36	7.07	0	954 ACSR
5	0416 TIDD	NATRIUM	138.00	138.00	3	40.04	0.00	1	556 ACSR
6	0416 TIDD	NATRIUM	138.00	138.00	1	0.37	0.00	0	556 ACSR
7	0417 TIDD	NATRIUM	0.00	0.00		0.00	0.00	0
8	0019 NATRIUM	MONONGAHELA	138.00	138.00	1	0.01	0.00	1	795 ACSR
9	0019 NATRIUM	MONONGAHELA	138.00	138.00	2	3.24	0.00	1	336 ACSR
10	0019 NATRIUM	MONONGAHELA	138.00	138.00	3	0.53	0.00	1	336 ACSR
11	0023 TIDD	GEORGE WASHINGTON	138.00	138.00	2	0.22	0.00	2	556 ACSR
12	0023 TIDD	GEORGE WASHINGTON	138.00	138.00	3	4.28	0.00	2	556 ACSR
13	0024 SUMMERFIELD	NATRIUM	138.00	138.00	3	2.09	0.00	0	556 ACSR
14	0031 KAMMER	TIDD/NATRIUM	138.00	138.00	3	2.75	0.00	2	556 ACSR
15	0031 KAMMER	TIDD/NATRIUM	138.00	138.00	1	0.08	0.00	2	1590 ACSR
16	0431 KAMMER	ORMET #1	138.00	138.00		0.00	0.00	0
17	0432 KAMMER	ORMET #1	138.00	138.00	3	9.91	0.00	0	1033 ACSR
18	0433 KAMMER	ORMET #2	138.00	138.00	3	10.06	0.00	0	1033 ACSR
19	0434 KAMMER	ORMET #2	138.00	138.00		0.00	0.00	0
20	0435 KAMMER	ORMET #2	138.00	138.00		0.00	0.00	0
21	0034 KAMMER	GEORGE WASHINGTON	138.00	138.00	3	6.40	0.00	1	636 ACSR
22	0034 KAMMER	GEORGE WASHINGTON	138.00	138.00	1	0.12	0.00	1	636 ACSR
23	0034 KAMMER	GEORGE WASHINGTON	138.00	138.00	1	0.09	0.00	1	1590 ACSR
24	0034 KAMMER	GEORGE WASHINGTON	138.00	138.00	1	0.20	0.00	1	2156 ACSR
25	0436 TIDD-NATRIUM	BRUES 138KV TAP	138.00	138.00		0.00	0.00	0
26	0439 ARROYO	EAST LIVERPOOL	138.00	138.00	1	2.68	0.00	1	556 ACSR
27	0439 ARROYO	EAST LIVERPOOL	138.00	138.00	1	4.85	0.00	0	556 ACSR
28	0440 TIDD	WEIRTON	138.00	138.00	1	2.38	0.43	0	556 ACSR
29	0047 TIDD/NATRIUM	WEST LIBERTY	138.00	138.00	1	0.23	0.00	1	4/0 ACSR
30	0047 TIDD/NATRIUM	WEST LIBERTY	138.00	138.00	2	0.66	0.00	1	4/0 ACSR
31	0049 BRUES	WEST BELLAIRE	138.00	138.00	1	0.20	0.00	2	556 ACSR
32	0049 BRUES	WEST BELLAIRE	138.00	138.00	3	0.33	0.00	2	556 ACSR
33	0054 TIDD	VALLEY GROVE	138.00	138.00	1	0.06	0.00	1	556 ACSR
34	0054 TIDD	VALLEY GROVE	138.00	138.00	2	0.39	0.00	1	556 ACSR
35	0059 TIDD/NATRIUM	GRAVE CREEK	138.00	138.00	1	0.54	0.00	1	556 ACSR
36	1051 FT HENRY TAP		138.00	138.00	1	0.08	0.00	1	556 ACSR
37	0061 BATTLE RUN TAP	BATTLE RUN STATION	138.00	138.00	1	0.07	0.00	1	556 ACSR
38	0061 BATTLE RUN TAP	BATTLE RUN STATION	138.00	138.00	2	0.10	0.00	1	556 ACSR
39	0062 SAND HILL	WARTON HILL	138.00	138.00	1	6.93	0.00	2	795 ACSR
40	0062 SAND HILL	WARTON HILL	138.00	138.00	1	0.07	0.00	1	795 ACSR
41	0065 NATRIUM	SIMS RUN	138.00	138.00	1	0.51	0.00	1	795 ACSR
42	0066 WAYMAN	GOSNEY HILL	138.00	138.00	2	7.57	0.00	1	795 ACSR
43	0067 NATRIUM	PPG	138.00	138.00	2	0.08	0.00	1	556 ACSR
44	0068 ASTON LOOP	ASTON LOOP	138.00	138.00	1	1.00	0.00	2	795 ACSR
45	0068 ASTON LOOP	ASTON LOOP	138.00	138.00	2	0.34	0.00	2	795 ACSR
46	0069 CRICKET EXTENSION		138.00	138.00	1	0.07	0.00	1	795 ACSR
47	0070 DIXON EXTENSION		138.00	138.00	1	0.26	0.00	1	556 ACSR
48	0071 NAVOO RIDGE	SASQUATCH	138.00	138.00	1	1.29	0.00	2	477 ACSR
49	LINES <132KV		69.00	69.00	1,2,3	52.57	5.05	0
50	Line cost and expense are	not available by individual
51	transmission line	Total shown in Column j-p								5,587,184	84,391,371	89,978,555	3,336	539,569		542,905
36	TOTAL					187	13	45		5,587,184	84,391,371	89,978,555	3,336	539,569		542,905

Name of Respondent:

Wheeling 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:

Wheeling 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	BENWOOD - WV	Distribution		69.00	4.00		9.38	1			0	0.00
2	BETHLEHEM - WV	Distribution		138.00	13.09		20.00	1			0	0.00
3	BIG GRAVE CREEK - WV	Distribution		138.00	36.20		25.00	1			0	0.00
4	BRUES - WV	Transmission		138.00	70.50	13.09	90.00	1			0	0.00
5	BRUES - WV	Transmission		69.00	4.00		10.00	1			0	0.00
6	BRUES - WV	Transmission		69.00	12.00		20.00	1			0	0.00
7	BRUES - WV	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	19.80
8	BRUES - WV	Transmission		138.00	69.00	12.00	130.00	1			0	0.00
9	COLUMBIAN - WV	Distribution		69.00	13.09		7.00	1			0	0.00
10	CONNER RUN - WV	Distribution		69.00	13.09		20.00	1			0	0.00
11	COUNTY LINE (WP) - WV	Distribution		138.00	36.20		25.00	1			0	0.00
12	COUNTY LINE (WP) - WV	Distribution		138.00	13.09		22.40	1			0	0.00
13	CRESAP - WV	Distribution		69.00	12.00		3.75	1			0	0.00
14	FORT HENRY - WV	Distribution		138.00	13.09		20.00	1			0	0.00
15	FULTON (WP) - WV	Distribution		69.00	13.09		22.40	1			0	0.00
16	GARDEN - WV	Distribution		69.00	12.00		35.40	3			0	0.00
17	GEORGE WASHINGTON - WV	Transmission		138.00	69.00	12.00	128.80	1			0	0.00
18	GEORGE WASHINGTON - WV	Transmission		138.00	70.50	13.09	130.00	1			0	0.00
19	GEORGE WASHINGTON - WV	Transmission		69.00	13.09		3.12	1			0	0.00
20	GLENDALE HEIGHTS - WV	Distribution		69.00	13.09		8.40	1			0	0.00
21	KAMMER 69KV - WV	Transmission		138.00	70.50	36.20	130.00	0	1		0	0.00
22	LOCKWOOD - WV	Distribution		69.00	13.09		17.50	1			0	0.00
23	MOUNDSVILLE - WV	Distribution		69.00	13.09		40.00	2			0	0.00
24	NATRIUM - WV	Transmission		69.00	12.00		1.00	0	1		0	0.00
25	NATRIUM - WV	Transmission		138.00	69.00	34.50	50.00	1			0	0.00
26	NATRIUM - WV	Transmission		69.00	12.00		2.50	1			0	0.00
27	NATRIUM - WV	Transmission		138.00	70.50	13.09	90.00	1			0	0.00
28	NATRIUM - WV	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	28.80
29	SAND HILL SWITCH - WV	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	57.60
30	SHORT CREEK - WV	Distribution		69.00	13.09		7.50	1			0	0.00
31	TABLE ROCK - WV	Distribution		69.00	13.09		9.38	1			0	0.00
32	VALLEY GROVE - WV	Distribution		138.00	13.09		10.50	1			0	0.00
33	WARWOOD - WV	Distribution		69.00	12.47		9.38	1			0	0.00
34	WARWOOD - WV	Distribution		69.00	13.09		6.25	1			0	0.00
35	WEST LIBERTY - WV	Distribution		138.00	13.09		8.40	1			0	0.00
36	TotalTransmissionSubstationMember											106
37	Total											106

Name of Respondent:

Wheeling 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	353,575
3	Administrative and General Expenses - Operation	AEPSC	920-928,930-931	640,800
4	Barging	(a) I&M	151	4,677,253
5	Civil & Political Activities and Other Svcs	AEPSC	426	387,872
6	Construction Services	AEPSC	107,108	10,263,286
7	Construction Services	APCo	107,108	970,065
8	Construction Services	KPCo	107,108	403,048
9	Corporate Accounting	AEPSC	920,923	326,323
10	Corporate Human Resources	AEPSC	920,923	280,345
11	Customer Accounts Expenses	AEPSC	901-903,905	663,248
12	Distribution Expenses - Maintenance	APCo	593-594,597	1,129,884
13	Distribution Expenses - Operation	AEPSC	580-584,586-588	399,418
14	Fuel & Storeroom Services	AEPSC	152,163	804,258
15	Fuel & Storeroom Services	KPCO	151-152,154	4,528,927
16	Information Technology	AEPSC	920,923	571,246
17	Legal GC/Administration	AEPSC	920,923	835,568
18	O&M Services for Jointly Owned Facility - Mitchell	KPCO	107,108,154,186,408,421,426,500-502,505,506,510-514.557,920-923,925,926,928,930.2,931,935	42,624,515
19	Other Power Supply Expenses	AEPSC	556-557	559,337
20	Research and Other Services	AEPSC	183,186,188	279,990
21	Research and Other Services	KPCO	183,184,186	618,935
22	Steam Power Generation - Maintenance	AEPSC	510-514	476,423
23	Steam Power Generation - Maintenance	KPCO	510-514	536,394
24	Steam Power Generation - Operation	AEPSC	500-502,506	1,938,400
25	Steam Power Generation - Operation	KPCO	500-502,505,506	796,708
26	Taxes Other Than Income taxes	KPCO	408	1,046,305
27	Transmission Expenses - Operation	AEPSC	560,561.2,561.5,562,563,566,920,923	554,447
28	Urea	KPCO	154	419,327
19
20	Non-power Goods or Services Provided for Affiliated
21	Facility rent	WVTCo	454	383,356
22	Leased Transmission Lines	OPCo	456	2,738,353
23	O&M Services for Jointly Owned Facility - Mitchell	KPCo	107,108,143,154,186,408,421,426,500-514,557,920-930,931,935	29,954,990
24	Taxes Other Than Income taxes	KPCO	408	775,568
25	Urea	KPCO	154	1,381,108
42

Name of Respondent:

Wheeling 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: NameOfAssociatedAffiliatedCompany

Certain managerial and professional services provided by AEPSC are allocated among multiple affiliates. The costs of the services are billed on a direct-charge basis, whenever possible. Costs incurred to perform services that benefit more than one company are allocated to the benefiting companies using one of 80 FERC accepted allocation factors. The allocation factors used to bill for services performed by AEPSC are based upon formulae that consider factors such as number of customers, number of employees, number of transmission pole miles, number of invoices and other factors. The data upon which these formulae are based is updated monthly, quarterly, semi-annually or annually, depending on the particular factor and its volatility. The billings for services are made at cost and include no compensation for a return on investment.

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