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)

Indiana Michigan 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

Indiana Michigan Power Company

02 Year/ Period of Report

End of:

2022

/

Q4

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

/

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

1 Riverside Plaza, Columbus, OH 43215-2373

05 Name of Contact Person

Jason M. Johnson

06 Title of Contact Person

Accountant

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

1 Riverside Plaza, Columbus, OH 43215-2373

08 Telephone of Contact Person, Including Area Code

614-716-1000

09 This Report is An Original / A Resubmission

(1)

☑ An Original

(2)

☐ A Resubmission

10 Date of Report (Mo, Da, Yr)

04/12/2023

Annual Corporate Officer Certification

The undersigned officer certifies that:

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

01 Name

Jeffrey W. Hoersdig

02 Title

Assistant Controller

03 Signature

Jeffrey W. Hoersdig

04 Date Signed (Mo, Da, Yr)

04/12/2023

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

Name of Respondent:

Indiana Michigan 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	NA
44	ScheduleSalesOfElectricityByRateSchedulesAbstract Sales of Electricity by Rate Schedules	304
45	ScheduleSalesForResaleAbstract Sales for Resale	310
46	ScheduleElectricOperationsAndMaintenanceExpensesAbstract Electric Operation and Maintenance Expenses	320
47	SchedulePurchasedPowerAbstract Purchased Power	326
48	ScheduleTransmissionOfElectricityForOthersAbstract Transmission of Electricity for Others	328
49	ScheduleTransmissionOfElectricityByIsoOrRtoAbstract Transmission of Electricity by ISO/RTOs	331	NA
50	ScheduleTransmissionOfElectricityByOthersAbstract Transmission of Electricity by Others	332
51	ScheduleMiscellaneousGeneralExpensesAbstract Miscellaneous General Expenses-Electric	335
52	ScheduleDepreciationDepletionAndAmortizationAbstract Depreciation and Amortization of Electric Plant (Account 403, 404, 405)	336
53	ScheduleRegulatoryCommissionExpensesAbstract Regulatory Commission Expenses	350
54	ScheduleResearchDevelopmentOrDemonstrationExpendituresAbstract Research, Development and Demonstration Activities	352
55	ScheduleDistributionOfSalariesAndWagesAbstract Distribution of Salaries and Wages	354
56	ScheduleCommonUtilityPlantAndExpensesAbstract Common Utility Plant and Expenses	356
57	ScheduleAmountsIncludedInIsoOrRtoSettlementAbstract Amounts included in ISO/RTO Settlement Statements	397
58	SchedulePurchasesSalesOfAncillaryServicesAbstract Purchase and Sale of Ancillary Services	398
59	ScheduleMonthlyTransmissionSystemPeakLoadAbstract Monthly Transmission System Peak Load	400
60	ScheduleMonthlyIsoOrRtoTransmissionSystemPeakLoadAbstract Monthly ISO/RTO Transmission System Peak Load	400a	NA
61	ScheduleElectricEnergyAccountAbstract Electric Energy Account	401a
62	ScheduleMonthlyPeakAndOutputAbstract Monthly Peaks and Output	401b
63	ScheduleSteamElectricGeneratingPlantStatisticsAbstract Steam Electric Generating Plant Statistics	402
64	ScheduleHydroelectricGeneratingPlantStatisticsAbstract Hydroelectric Generating Plant Statistics	406
65	SchedulePumpedStorageGeneratingPlantStatisticsAbstract Pumped Storage Generating Plant Statistics	408
66	ScheduleGeneratingPlantStatisticsAbstract Generating Plant Statistics Pages	410
0	ScheduleEnergyStorageOperationsLargePlantsAbstract Energy Storage Operations (Large Plants)	414
67	ScheduleTransmissionLineStatisticsAbstract Transmission Line Statistics Pages	422
68	ScheduleTransmissionLinesAddedAbstract Transmission Lines Added During Year	424
69	ScheduleSubstationsAbstract Substations	426
70	ScheduleTransactionsWithAssociatedAffiliatedCompaniesAbstract Transactions with Associated (Affiliated) Companies	429
71	FootnoteDataAbstract Footnote Data	450
	StockholdersReportsAbstract Stockholders' Reports (check appropriate box)
	Stockholders' Reports Check appropriate box: ☐ Two copies will be submitted ☐ No annual report to stockholders is prepared

Name of Respondent:

Indiana Michigan 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 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 - IndianaElectric - Michigan
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:

Indiana Michigan Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

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

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

Name of Respondent:

Indiana Michigan 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	Price River Coal Company, Inc.	Coal Company - Inactive	100
2	Blackhawk Coal Company, Inc.	Coal Company - Inactive	100

Name of Respondent:

Indiana Michigan 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:

Indiana Michigan Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: OfficerTitle


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

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


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


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


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


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


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


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


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

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

(2) The amounts reported in this column reflect the aggregate grant date fair value calculated in accordance with FASB ASC Topic 718 of the performance shares, restricted stock units (RSUs) and unrestricted shares granted under our Long-Term Incentive Plan. See Note 15 to the Consolidated Financial Statements included in our Form 10-K for the year ended December 31, 2022 for a discussion of the relevant assumptions used in calculating these amounts. The number of shares realized and the value of the performance shares, if any, will depend on the Company’s performance during a 3-year performance period. The potential payout can range from 0 percent to 200 percent of the target number of performance shares, plus any dividend equivalents. The value of the performance shares will be based on three measures: a Board approved cumulative operating earnings per share measure (Cumulative EPS 50%), a total shareholder return relative to peer companies (Relative TSR 40%) and a carbon free capacity mix (Carbon Free Capacity 10%). The grant date fair value of the 2022 performance shares that are based on Cumulative EPS was computed in accordance with FASB ASC Topic 718 and was measured based on the closing price of AEP’s common stock on the grant date. The maximum amount payable for the 2022 performance shares that are based on Cumulative EPS measured on the grant date was $7,500,054 for Mr. Akins; $1,350,018 for Ms. Sloat; $109,965 for Ms. Kelly, $1,125,029 for Mr. Feinberg; $974,951 for Mr. Zebula; $974,951 for Mr. Chodak and $1,799,996 for Ms. Barton. The maximum amount payable for the 2022 performance shares that are based on Carbon Free Capacity is equal to $1,500,011 for Mr. Akins; $270,004 for Ms. Sloat; $21,993 for Ms. Kelly; $225,006 for Mr. Feinberg; $194,990 for Mr. Zebula, $194,990 for Mr. Chodak and $359,999 for Ms. Barton. The grant date fair value of the 2022 performance shares that are based on Relative TSR is

calculated using a Monte-Carlo model as of the date of grant, in accordance with FASB ASC Topic 718. Because the performance shares that are based on Relative TSR are subject to market conditions as defined under FASB ASC Topic 718, they did not have a maximum value on the grant date that differed from the grant date fair values presented in the table. Instead, the maximum value is factored into the calculation of the grant date fair value. The values realized from the 2020 performance shares are included in the Option Exercises and Stock Vested for 2022 table.

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

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

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


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

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

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

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

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

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

Name of Respondent:

Indiana Michigan 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, Chairman of the Executive Committee and Chief Executive Officer	Columbus, Ohio	true	true
2	Julia A. Sloat, Vice President and Chief Financial Officer	Columbus, Ohio	true	false
3	Lisa M .Barton - Vice President	Columbus, Ohio	true	false
4	Steven F.Baker - Chief Operating Officer and President	Fort Wayne, Indiana	true	false
5	Katherine K.Davis - Vice President - External Affairs and Customer Experience	Fort Wayne, Indiana	false	false
6	Nicholas M.Elkins - Director Customer and Business Services	Fort Wayne, Indiana	false	false
7	David S. Isaacson - Vice President - Distribution Region Operations	Fort Wayne, Indiana	false	false
8	Andrew J. Williamson - Director Regulatory Services	Fort Wayne, Indiana	false	false
9	Ann P. Kelly, Vice President and Chief Financial Officer	Columbus, Ohio	true	false
10	Peggy I.Simmons, Executive Vice President,Utilities	Columbus, Ohio	true	false
11	Toby L. Thomas, President and Chief Operating Officer	Fort Wayne, Indiana	false	false

Name of Respondent:

Indiana Michigan 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:

Indiana Michigan 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:

Indiana Michigan 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:

Indiana Michigan 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.


Date Acquired Or Extended	Community	Period of Franchise & Termination	Consideration
8/8/2022	The Hagar Township, Berrian County, MI	Ten (10) years expiring August 08, 2032	$83.25 - Publication of affidavit fees
11/5/2022	Porter Township, Van Buren County, MI	Thirty (30) years expiring November 05, 2052	None

None

Purchase of 50% share of Rockport Plant Unit 2 from a group of Equity Participants in December 2022.

Orders include: FERC Case EC21-97-000, IURC Case No. 45546, MPSC Case No. U-21189. Final journal

entries have not yet been submitted to the Commission.

None

$72.8M Indiana Michigan power company Nuclear fuel Lease( state authority: cause No.45417 Issued: 5/23/2022, Maturity: 11/23/2026 )$69.9M Indian Michigan Power Company Nuclear Fuel Lease(State Authority: Cause No. 45417, FERC Authority: N/A, Issued: 11/7/2022, Maturity: 5/7/2027

None

67 Cook Nuclear Plant Maintenance employees represented by IBEW #1392 were provided with a 2% wage effective Jan 1,2022

13 Cook Nuclear Plant Stores employees represented by IBEW #1392 were provided with a 2% wage effective Jan 1, 2022

51 Cook Nuclear Plant RPEC employees represented by IBEW #1392 were provided with a 2% wage effective Jan 1 ,2022

70 Cook Nuclear Plant NON Licensed Operators employees represented by IBEW #1392 were provided with a 2% Wage effective Jan 1 ,2022

16 Cook Nuclear Planners employees represented by IBEW # 1392 were provided with a 3% wage effective Jan 1,2022

85 River Transportation employees represented by IBEW # 14811 were provided with a 2% Wage effective Jan 1,2022

20 Three Rivers employees represented by IBEW #876 were provided with a 2% wage effective Jan 1,2022

86 Fort Wayne employees represented by IBEW #1392 were provided with a 2% wage effective Jan 1, 2022

75 Munice employees represented by IBEW #1392 were provided with a 2% wage effective Jan 1,2022

21 Trans Line employees represented by IBEW #1392 were provided with a 2% wage effective Jan 1, 2022

4 Southern Maintenance group represented by IBEW #1392 were provided with a 2% wage effective Jan 1, 2022

142 South Bend employees represented by IBEW #1392 were provided with 2% wage effective Jan 1,2022

70 Cook Nuclear Plant Maintenance employees represented by IBEW #1392 were provided with a 3.0% Contract effective April 1, 2022.

13 Cook Nuclear Plant Stores employees represented by IBEW #1392 were provided with a 3.0% Contract effective April 1, 2022.

52 Cook Nuclear Plant RPEC employees represented by IBEW #1392 were provided with a 3.0% contract effective April 1, 2022.

68 Cook Nuclear Plant NON Licensed Operators employees represented by IBEW #1392 were provided with a 3.0% Contract effective April 1, 2022.

60 River Transportation employees represented by USW # 14811 were provided with a 3.0% contract effective April 1, 2022.

15 Three Rivers employees represented by IBEW #876 were provided a 4.5% Contract - D, T Journeyman level only effective April 1, 2022

94 Fort Wayne employees represented by IBEW #1392 were provided with provided a 4.5% Contract - D, T Journeyman level only effective April 1 ,2022

79 Munice employees represented by IBEW #1392 were provided with a 4.5% Contract - D, T Journeyman level only effective April 1 ,2022

24 Trans Line employees represented by IBEW #1392 were provided with a 4.5% Contract - D, T Journeyman level only effective April 1 ,2022

4 Southern Maintenance group represented by IBEW #1392 were provided with a 4.5% Contract- D, T Journeyman level only effective April 1 ,2022

142 Michiana employees represented by IBEW #1392 were provided with a 4.5% Contract - D, T Journeyman level only effective April 1 ,2022

142 Michiana employees represented by IBEW #1392 were provided with a 3.5% wage effective on November 1, 2022

93 Fort Wayne employees represented by IBEW #1392 were provided with a 3.5% wage effective on November 1, 2022

79 Munice employees represented by IBEW #1392 were provided with a 3.5% wage effective on November 1,2022

24 Trans Line employees represented by IBEW #1392 were provided with a 3.5% wage effective on November 1,2022

3 South Maintenance Group employees represented by IBEW #1392 were provided with a 3.5% wage effective on November 1,2022

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

None

Not Used

elly J. Ferneau elected as Site Vice president for Donald C.cook plant effective on 7/2/2022

Shane Q. Lies elected as vice president effective on 7/2/2022

David M. Feinberg elected as Vice President effective on 8/25/2022

Peggy Simmons I elected as Director effective on 9/22/2022

Phillip R. Ulrich elected as Vice President effective on 9/14/2022

Lisa M. Barton resigned as Director effective on 9/22/2022

Joel P. Gebbie resigned as Vice President effective on 7/2/2022

Shane Q. Lies resigned as Site Vice president for Donald C.cook plant effective on 7/2/2022

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 elected as Director effective on 12/14/2022

Nicholas K Akins, retired as Director, Chairman of the Board, Chairman of the Executive Committee and Chief Executive Officer effective on 12/312022

Lisa M Barton, retired as Vice President effective on 11/01/2022

Julia A Sloat, retired as Vice President and Chief Financial Officer effective on 11/29/2022 (elected Chariman of the Board and Chief Executive Officer 1/1/2023)

Proprietary capital ratio exceeds 30%

Name of Respondent:

Indiana Michigan 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	11,026,604,026	10,717,411,486
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	256,648,504	303,725,635
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		11,283,252,530	11,021,137,120
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	4,076,922,613	3,820,179,577
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		7,206,329,917	7,200,957,543
7	NuclearFuelInProcessOfRefinementConversionEnrichmentAndFabrication Nuclear Fuel in Process of Ref., Conv., Enrich., and Fab. (120.1)	202	38,893	41,389,512
8	NuclearFuelMaterialsAndAssembliesStockAccountMajorOnly Nuclear Fuel Materials and Assemblies-Stock Account (120.2)
9	NuclearFuelAssembliesInReactorMajorOnly Nuclear Fuel Assemblies in Reactor (120.3)		1,645,219	1,072,702
10	SpentNuclearFuelMajorOnly Spent Nuclear Fuel (120.4)		629,554,317	605,712,062
11	NuclearFuelUnderCapitalLeases Nuclear Fuel Under Capital Leases (120.6)		179,143,988	118,624,550
12	AccumulatedProvisionForAmortizationOfNuclearFuelAssemblies (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)	202	629,431,130	605,718,624
13	NuclearFuelNet Net Nuclear Fuel (Enter Total of lines 7-11 less 12)		180,873,501	161,080,202
14	UtilityPlantAndNuclearFuelNet Net Utility Plant (Enter Total of lines 6 and 13)		7,387,203,418	7,362,037,745
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)		1,521,080	1,718,313
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)
17	OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS
18	NonutilityProperty Nonutility Property (121)		670,402,649	71,135,454
19	AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Prov. for Depr. and Amort. (122)		577,465,961	36,244,202
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224	22,907,857	22,647,944
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances	228	25,258,945	25,304,843
24	OtherInvestments Other Investments (124)		12,408,146	11,890,852
25	SinkingFunds Sinking Funds (125)
26	DepreciationFund Depreciation Fund (126)
27	AmortizationFundFederal Amortization Fund - Federal (127)
28	OtherSpecialFunds Other Special Funds (128)		3,341,237,453	3,867,016,020
29	SpecialFunds Special Funds (Non Major Only) (129)		157,046,464	201,474,750
30	DerivativeInstrumentAssetsLongTerm Long-Term Portion of Derivative Assets (175)		215,221
31	DerivativeInstrumentAssetsHedgesLongTerm Long-Term Portion of Derivative Assets - Hedges (176)
32	OtherPropertyAndInvestments TOTAL Other Property and Investments (Lines 18-21 and 23-31)		3,652,010,774	4,163,225,662
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)		4,170,737	1,277,594
36	SpecialDeposits Special Deposits (132-134)		1,369,186	18,873,630
37	WorkingFunds Working Fund (135)			6
38	TemporaryCashInvestments Temporary Cash Investments (136)
39	NotesReceivable Notes Receivable (141)
40	CustomerAccountsReceivable Customer Accounts Receivable (142)		100,302,527	46,461,981
41	OtherAccountsReceivable Other Accounts Receivable (143)		4,692,021	2,485,873
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		2,568	127,329
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)		100,641,806	75,154,170
45	FuelStock Fuel Stock (151)	227	44,879,566	53,538,758
46	FuelStockExpensesUndistributed Fuel Stock Expenses Undistributed (152)	227	1,646,495	3,254,610
47	Residuals Residuals (Elec) and Extracted Products (153)	227
48	PlantMaterialsAndOperatingSupplies Plant Materials and Operating Supplies (154)	227	186,279,221	173,368,683
49	Merchandise Merchandise (155)	227
50	OtherMaterialsAndSupplies Other Materials and Supplies (156)	227	1,667,521	1,510,191
51	NuclearMaterialsHeldForSale Nuclear Materials Held for Sale (157)	202/227
52	AllowanceInventoryAndWithheld Allowances (158.1 and 158.2)	228	25,388,469	25,601,412
53	NoncurrentPortionOfAllowances (Less) Noncurrent Portion of Allowances	228	25,258,945	25,304,843
54	StoresExpenseUndistributed Stores Expense Undistributed (163)	227	1
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)		12,484,353	11,602,570
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)
60	RentsReceivable Rents Receivable (172)		355,807	134,315
61	AccruedUtilityRevenues Accrued Utility Revenues (173)		557,253
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)		24,043,675	28,079,025
63	DerivativeInstrumentAssets Derivative Instrument Assets (175)		15,383,659	3,336,696
64	DerivativeInstrumentAssetsLongTerm (Less) Long-Term Portion of Derivative Instrument Assets (175)		215,221
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)		498,385,563	419,247,343
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		18,575,692	20,079,273
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	696,583,826	556,269,932
73	PreliminarySurveyAndInvestigationCharges Prelim. Survey and Investigation Charges (Electric) (183)		4,914,241	760,085
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	78,311,371	63,408,711
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)		12,874,071	13,985,122
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	933,493,719	1,071,500,514
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		1,744,752,921	1,726,003,638
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		13,280,831,596	13,668,796,076

Name of Respondent:

Indiana Michigan 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	56,583,866	56,583,866
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)		4,234,635	4,234,635
7	OtherPaidInCapital Other Paid-In Capital (208-211)	253	984,636,599	976,661,803
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	127	127
11	RetainedEarnings Retained Earnings (215, 215.1, 216)	118	1,965,690,158	1,751,256,768
12	UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1)	118	2,416,144	2,703,331
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)	287,989	1,252,146
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		3,008,440,997	2,784,781,469
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	3,105,662,741	3,103,597,081
22	UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225)
23	UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Debit (226)		10,119,645	10,705,374
24	LongTermDebt Total Long-Term Debt (lines 18 through 23)		3,095,543,097	3,092,891,708
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		170,107,704	137,728,579
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		298,465	705,208
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		8,369,172	12,397,558
30	AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4)		412,141	958,887
31	AccumulatedProvisionForRateRefunds Accumulated Provision for Rate Refunds (229)		11,810,518	5,388,015
32	LongTermPortionOfDerivativeInstrumentLiabilities Long-Term Portion of Derivative Instrument Liabilities		15,970	1,352
33	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges Long-Term Portion of Derivative Instrument Liabilities - Hedges
34	AssetRetirementObligations Asset Retirement Obligations (230)		2,028,056,023	1,946,288,955
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		2,219,069,994	2,103,468,553
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)
38	AccountsPayable Accounts Payable (232)		173,426,216	174,399,996
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)		249,940,964	93,331,295
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		121,494,974	94,897,889
41	CustomerDeposits Customer Deposits (235)		48,606,762	45,161,586
42	TaxesAccrued Taxes Accrued (236)	262	102,988,689	94,367,286
43	InterestAccrued Interest Accrued (237)		36,865,840	37,016,432
44	DividendsDeclared Dividends Declared (238)
45	MaturedLongTermDebt Matured Long-Term Debt (239)
46	MaturedInterest Matured Interest (240)
47	TaxCollectionsPayable Tax Collections Payable (241)		7,068,953	6,566,423
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		81,039,240	107,846,206
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		107,995,874	207,477,213
50	DerivativesInstrumentLiabilities Derivative Instrument Liabilities (244)		31,881	5,024,580
51	LongTermPortionOfDerivativeInstrumentLiabilities (Less) Long-Term Portion of Derivative Instrument Liabilities		15,970	1,352
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)		929,379,661	866,087,554
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)
57	AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255)	266	17,350,699	22,384,341
58	DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256)
59	OtherDeferredCredits Other Deferred Credits (253)	269	25,439,687	19,133,074
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	1,894,919,119	2,607,697,815
61	UnamortizedGainOnReacquiredDebt Unamortized Gain on Reaquired Debt (257)		1,284	2,996
62	AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty Accum. Deferred Income Taxes-Accel. Amort.(281)	272	14,753,180	16,760,085
63	AccumulatedDeferredIncomeTaxesOtherProperty Accum. Deferred Income Taxes-Other Property (282)		1,162,093,451	1,128,530,876
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		913,840,427	1,027,057,608
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		4,028,397,847	4,821,566,794
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		13,280,831,596	13,668,796,078

Name of Respondent:

Indiana Michigan 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	2,683,980,655	2,319,200,338			2,683,980,655	2,319,200,338
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	1,480,052,301	1,181,641,968			1,480,052,301	1,181,641,968
5	MaintenanceExpense Maintenance Expenses (402)	320	226,936,639	209,973,572			226,936,639	209,973,572
6	DepreciationExpense Depreciation Expense (403)	336	398,405,567	387,053,997			398,405,567	387,053,997
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336	4,284,998	316,287			4,284,998	316,287
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	61,848,393	53,039,201			61,848,393	53,039,201
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)		449,814	467,537			449,814	467,537
13	RegulatoryCredits (Less) Regulatory Credits (407.4)		8,137,422	50,563			8,137,422	50,563
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	94,533,065	105,580,982			94,533,065	105,580,982
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	44,547,867	31,398,638			44,547,867	31,398,638
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	10,483,396	85,737			10,483,396	85,737
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	462,278,975	551,359,387			462,278,975	551,359,387
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	509,576,487	587,546,681			509,576,487	587,546,681
19	InvestmentTaxCreditAdjustments Investment Tax Credit Adj. - Net (411.4)	266	5,033,642	1,123,636			5,033,642	1,123,636
20	GainsFromDispositionOfPlant (Less) Gains from Disp. of Utility Plant (411.6)		631,371	522,709			631,371	522,709
21	LossesFromDispositionOfServiceCompanyPlant Losses from Disp. of Utility Plant (411.7)			798				798
22	GainsFromDispositionOfAllowances (Less) Gains from Disposition of Allowances (411.8)		4,299,350	30			4,299,350	30
23	LossesFromDispositionOfAllowances Losses from Disposition of Allowances (411.9)			1,017				1,017
24	AccretionExpense Accretion Expense (411.10)		2,435,359	5,155,842			2,435,359	5,155,842
25	UtilityOperatingExpenses TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)		2,257,678,474	1,938,375,694			2,257,678,474	1,938,375,694
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		426,302,181	380,824,644			426,302,181	380,824,644
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)		117,131,577	57,532,386
34	ExpensesOfNonutilityOperations (Less) Expenses of Nonutility Operations (417.1)		79,594,358	53,578,744
35	NonoperatingRentalIncome Nonoperating Rental Income (418)		341,431	414,570
36	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1)	119	287,187	2,781,813
37	InterestAndDividendIncome Interest and Dividend Income (419)		658,051	913,279
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		9,770,373	12,799,539
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		1,524,240	1,669,643
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)		177,798	776,070
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		47,247,819	19,969,270
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)		765,742	287,432
44	MiscellaneousAmortization Miscellaneous Amortization (425)
45	Donations Donations (426.1)		12,282,743	1,284,752
46	LifeInsurance Life Insurance (426.2)
47	Penalties Penalties (426.3)		2,334	410,373
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		1,450,863	1,013,367
49	OtherDeductions Other Deductions (426.5)		10,338,882	9,727,797
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		24,840,565	11,902,974
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262	2,575,617	2,526,953
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262	776,181	4,021,660
54	IncomeTaxesOther Income Taxes-Other (409.2)	262	278,704	349,587
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272	13,616,289	23,134,476
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272	11,873,866	26,215,630
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)		3,820,563	4,925,448
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		18,586,691	12,991,744
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		116,690,752	112,879,508
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		2,130,308	2,116,800
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)		1,318,003	1,472,631
65	AmortizationOfPremiumOnDebtCredit (Less) Amort. of Premium on Debt-Credit (429)
66	AmortizationOfGainOnReacquiredDebtCredit (Less) Amortization of Gain on Reaquired Debt-Credit (429.1)		1,712	1,712
67	InterestOnDebtToAssociatedCompanies Interest on Debt to Assoc. Companies (430)		2,893,111	211,532
68	OtherInterestExpense Other Interest Expense (431)		2,883,904	2,428,058
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		5,746,073	5,134,072
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		120,168,294	113,972,745
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		324,720,578	279,843,643
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)		324,720,578	279,843,643

Name of Respondent:

Indiana Michigan 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		1,746,436,904	1,719,594,527
2	ChangesAbstract Changes
3	AdjustmentsToRetainedEarningsAbstract Adjustments to Retained Earnings (Account 439)
4	AdjustmentsToRetainedEarningsCreditAbstract Adjustments to Retained Earnings Credit
4.1	AdjustmentsToRetainedEarningsCredit (a) Adoption of ASC 326 as of January 1, 2020.
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)		324,433,390	277,061,833
17	AppropriationsOfRetainedEarningsAbstract Appropriations of Retained Earnings (Acct. 436)
17.1	AppropriationsOfRetainedEarnings Reclassification of Appropriated Retained Earnings-Amort Reserve Federal		180,020	219,456
22	AppropriationsOfRetainedEarnings TOTAL Appropriations of Retained Earnings (Acct. 436)		180,020	219,456
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 Dividends Declared-Common Stock		110,000,000	250,000,000
36	DividendsDeclaredCommonStock TOTAL Dividends Declared-Common Stock (Acct. 438)		110,000,000	250,000,000
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)		1,960,690,274	1,746,436,904
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)		4,999,884	4,819,864
47	AppropriatedRetainedEarningsIncludingReserveAmortization TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)		4,999,884	4,819,864
48	RetainedEarnings TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)		1,965,690,158	1,751,256,768
	UnappropriatedUndistributedSubsidiaryEarningsAbstract UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49	UnappropriatedUndistributedSubsidiaryEarnings Balance-Beginning of Year (Debit or Credit)		2,703,331	5,485,144
50	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings for Year (Credit) (Account 418.1)		287,187	2,781,813
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)		2,416,144	2,703,331

Name of Respondent:

Indiana Michigan 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: AdjustmentsToRetainedEarningsCreditDescription

To recognize the adjustment in the allowance for other receivables upon the adoption of ASC 326 as of January 1, 2020. Recorded Q1 2020.

Name of Respondent:

Indiana Michigan 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)	324,720,578	279,843,643
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	464,538,958	439,776,912
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of Regulatory Debits & Credits	8,587,236	518,100
5.2	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of Nuclear Fuel	86,277,041	86,673,746
5.3	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Accretion of Asset Retirement Obligation	2,435,359	5,155,842
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	45,555,089	39,268,448
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)	5,033,642	1,123,636
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	81,880,582	22,620,016
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	2,800,561	29,939,895
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory	212,944	162,682
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	45,782,938	42,137,754
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	51,380,477	27,105,892
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	20,028,794	87,235,709
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	9,770,373	12,799,539
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies	287,187	2,781,812
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other (provide details in footnote):	(a) 138,407,868	49,395,217
18.2	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Mark-to-Market of Risk Management Contracts	17,103,425	5,136,033
18.3	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Over/Under Recovered Fuel	42,017,658
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	501,114,926	649,261,610
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)	569,260,339	514,038,334
27	GrossAdditionsToNuclearFuelInvestingActivities Gross Additions to Nuclear Fuel	102,715,455	105,663,130
28	GrossAdditionsToCommonUtilityPlantInvestingActivities Gross Additions to Common Utility Plant
29	GrossAdditionsToNonutilityPlantInvestingActivities Gross Additions to Nonutility Plant	311,352	265,957
30	AllowanceForOtherFundsUsedDuringConstructionInvestingActivities (Less) Allowance for Other Funds Used During Construction	9,770,373	12,799,539
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
31.1	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Other (provide details in footnote):
31.2	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Acquired Assets	12,647,866	920,927
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	675,164,640	608,088,809
36	AcquisitionOfOtherNoncurrentAssets Acquisition of Other Noncurrent Assets (d)
37	ProceedsFromDisposalOfNoncurrentAssets Proceeds from Disposal of Noncurrent Assets (d)	(b) 17,763,935	8,579,838
39	InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Investments in and Advances to Assoc. and Subsidiary Companies
40	ContributionsAndAdvancesFromAssociatedAndSubsidiaryCompanies Contributions and Advances from Assoc. and Subsidiary Companies
41	DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompaniesAbstract Disposition of Investments in (and Advances to)
42	DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Disposition of Investments in (and Advances to) Associated and Subsidiary Companies
44	PurchaseOfInvestmentSecurities Purchase of Investment Securities (a)	2,765,375,937	1,928,182,789
45	ProceedsFromSalesOfInvestmentSecurities Proceeds from Sales of Investment Securities (a)	2,713,633,868	1,886,361,394
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 Sale of Barges
53.2	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Other (provide details in footnote):	(c) 5,183,404	6,647,517
53.3	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription (increase) Decrease in Other Special Deposits	10,250,728	10,307,523
53.4	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Note Receivable from Associated Companies
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	693,708,643	644,990,372
59	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
60	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
61	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b)		490,000,000
62	ProceedsFromIssuanceOfPreferredStockFinancingActivities Preferred Stock
63	ProceedsFromIssuanceOfCommonStockFinancingActivities Common Stock
64	OtherAdjustmentsToCashFlowsFromFinancingActivities Other (provide details in footnote):
64.1	OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription Capital Contribution From Parent	7,974,796
64.2	OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription Long Term Issuance Costs	35,142	8,169,519
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
67.1	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Proceeds from Acquired Assets	459,856	704,426
67.2	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Notes Payable to Associated Companies	156,609,669
67.3	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Proceeds on Nuclear Fuel Leaseback	142,700,000	64,900,000
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	307,709,179	547,434,907
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)	2,222,323	294,076,636
74	PaymentsForRetirementOfPreferredStockFinancingActivities Preferred Stock
75	PaymentsForRetirementOfCommonStockFinancingActivities Common Stock
76	OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
76.1	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
76.2	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Notes Payable to Associated Companies - Retired		9,690,446
78	NetDecreaseInShortTermDebt Net Decrease in Short-Term Debt (c)
80	DividendsOnPreferredStock Dividends on Preferred Stock
81	DividendsOnCommonStock Dividends on Common Stock	110,000,000	250,000,000
83	CashFlowsProvidedFromUsedInFinancingActivities Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)	195,486,856	6,332,175
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)	2,893,139	2,060,936
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	1,277,599	3,338,535
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	4,170,738	1,277,599

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities


	2022 Cash Flow Incr / (Decr)		2021 Cash Flow Incr / (Decr)
Utility Plant, Net	$	(178,608,788)	$	(116,606,963)
Property and Investments, Net	3,292,403		9,290,321
Margin Deposits	7,253,715		(6,768,281)
Prepayments	(12,299,418)		(3,133,360)
Accrued Utility Revenues, Net	(557,253)		—
Miscellaneous Current and Accr Assets	2,054,876		(9,864,651)
Unamortized Debt Expense	1,538,724		1,212,846
Other Deferred Debits, Net	(14,369,170)		(4,376,921)
Proprietary Capital, Net
Other Comprehensive Income, Net	1,602,302		1,602,302
Unamortized Discount/Premium on Long-Term Debt	585,729		556,554
Accumulated Provisions - Misc	8,188,758		3,048,905
Current and Accrued Liabilities, Net	(33,318,900)		6,375,827
Other Deferred Credits, Net	76,229,153		69,268,204
Total	$	(138,407,869)	$	(49,395,217)

(b) Concept: ProceedsFromDisposalOfNoncurrentAssets


	2022 Cash Flow Incr / (Decr)		2021 Cash Flow Incr / (Decr)
Sale of transformers between various operating companies	$	2,389,877	$	911,559
Sale of meters between various operating companies	512,125		114,872
Transco Transfer of Assets	1,513,614		5,939,061
Land Sale Dumont / Lakeville Site, Dumont UHV Test Facility	147,595		114,346
Sale of Rotor LP-2 serial number 1-389000-406-404			650,000
Sale of 2001 Caterpillar Material			200,000
Sale of Rotor LP-1 serial number 1-309000-406-32			650,000
Sale of two 176 foot 345kV DC Tangent Emergency Restoration Structures from I&M-T Sorenson 345/138/132.2 Station to ETT Edith Clarke-Riley 345kV Line.	308,564
Sale of IP Rotor	887,160
Sales of Marine Vessel	12,005,000
Total	$	17,763,935	$	8,579,838

(c) Concept: OtherAdjustmentsToCashFlowsFromInvestmentActivities


	2022 Cash Flow Incr / (Decr)		2021 Cash Flow Incr / (Decr)
DOE Settlement	$	—	$	2,552,839
CIAC Proceeds	1,536,317		1,964,789
Insurance Receivable	3,156,980		2,129,889
DOE Proceeds	196,086		—
Other investing	294,021		—
Total	$	5,183,404	$	6,647,517

Name of Respondent:

Indiana Michigan 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.Business Segments

9.Derivatives and Hedging

10.Fair Value Measurements

11.Income Taxes

12.Leases

13.Financing Activities

14.Related Party Transactions

15.Property, Plant and Equipment

16.Revenue from Contracts with Customers

17.FERC Order NO. 784-A

GLOSSARY OF TERMS FOR NOTES

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


Term						Meaning

AEGCo						AEP Generating Company, an AEP electric utility subsidiary.
AEP						American Electric Power Company, Inc., an investor-owned electric public utility holding company which includes American Electric Power Company, Inc. (Parent) and majority-owned consolidated subsidiaries and consolidated affiliates.
AEP Credit						AEP Credit, Inc., a consolidated VIE of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP East Companies						APCo, I&M, KGPCo, KPCo, OPCo and WPCo.
AEP System						American Electric Power System, an electric system, owned and operated by AEP subsidiaries.
AEP Wind Holdings, LLC						Acquired in April 2019 as Sempra Renewables LLC, develops, owns and operates, or holds interests in, wind generation facilities in the United States.
AEPSC						American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEPTCo						AEP Transmission Company, LLC, a wholly-owned subsidiary of AEP Transmission Holdco, is an intermediate holding company that owns the State Transcos.
AFUDC						Allowance for Equity Funds Used During Construction.
ALJ						Administrative Law Judge.
AOCI						Accumulated Other Comprehensive Income.
APCo						Appalachian Power Company, an AEP electric utility subsidiary.
ARO						Asset Retirement Obligations.
Cook Plant						Donald C. Cook Nuclear Plant, a two-unit, 2,296 MW nuclear plant owned by I&M.
COVID-19						Coronavirus 2019, a highly infectious respiratory disease. In March 2020, the World Health Organization declared COVID-19 a worldwide pandemic.
CWIP						Construction Work in Progress.
DCC Fuel						DCC Fuel XI, DCC Fuel XII, DCC Fuel XIII, DCC Fuel XIV, DCC Fuel XV, DCC Fuel XVI, DCC Fuel XVII and DCC Fuel XVIII consolidated VIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
DOE						U. S. Department of Energy.
EIS						Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated VIE of AEP.
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.
IRA						On August 16, 2022 President Biden signed into law legislation commonly referred to as the “Inflation Reduction Act” (IRA).


Term						Meaning
IRS						Internal Revenue Service.
ITC						Investment Tax Credit.
IURC						Indiana Utility Regulatory Commission.
KGPCo						Kingsport Power Company, an AEP electric utility subsidiary.
KPCo						Kentucky Power Company, an AEP electric utility subsidiary.
KWh						Kilowatt-hour.
MPSC						Michigan Public Service Commission.
MTM						Mark-to-Market.
MW						Megawatt.
MWh						Megawatt-hour.
NOL						Net operating losses.
NOx						Nitrogen oxide.
NRC						Nuclear Regulatory Commission.
NSR						New Source Review.
OATT						Open Access Transmission Tariff.
OPCo						Ohio Power Company, an AEP electric utility subsidiary.
OPEB						Other Postretirement Benefits.
OTC						Over-the-counter.
OVEC						Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
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.
PFD						Proposal for Decision.
PJM						Pennsylvania – New Jersey – Maryland regional transmission organization.
PPA						Purchase Power and Sale Agreement.
PSO						Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PTC						Production Tax Credit.
Risk Management Contracts						Trading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant						A generation plant, jointly-owned by AEGCo and I&M, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana.
RPM						Reliability Pricing Model.
RTO						Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sempra Renewables LLC						Sempra Renewables LLC, acquired in April 2019 (subsequently renamed as AEP Wind Holdings LLC), consists of 724 MWs of wind generation and battery assets in the United States.
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.
SNF						Spent Nuclear Fuel.
SWEPCo						Southwestern Electric Power Company, an AEP electric utility subsidiary.
TA						Transmission Agreement, effective November 2010, among APCo, I&M, KGPCo, KPCo, OPCo and WPCo with AEPSC as agent.
Tax Reform						On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018.


Term						Meaning
UPA						Unit Power Agreement.
Utility Money Pool						Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
VIE						Variable Interest Entity.
WPCo						Wheeling Power Company, an AEP electric utility subsidiary.

1.

ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION

As a public utility, I&M engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to approximately 609,000 retail customers in its service territory in northern and eastern Indiana and southwestern Michigan. I&M sells power at wholesale to municipalities and electric cooperatives. I&M’s River Transportation Division provides barging services to affiliates and nonaffiliated companies. The revenues from barging represent the majority of other revenues.

In December 2022, the Rockport Plant, Unit 2 lease ended and I&M and AEGCo acquired 100% of the interests in the Rockport Plant. AEGCo’s 50% ownership share of Rockport Plant, Unit 2 is being billed to I&M under a FERC-approved UPA. I&M’s purchased power from AEGCo and I&M’s 50% ownership share of Rockport Plant, Unit 2 electricity generated represents a merchant resource for I&M until Rockport Plant, Unit 2 is retired in 2028.

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

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Rates and Service Regulation

I&M’s rates are regulated by the FERC, the IURC and the MPSC. The FERC also regulates I&M’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 the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. The state regulatory commissions also regulate certain intercompany transactions under various orders and 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 and wholesale power transactions. I&M’s wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that I&M has “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued-up to actual costs annually.

The IURC and the MPSC regulate all of the retail distribution operations and rates of I&M’s retail public utility subsidiaries on a cost basis. They also regulate the retail generation/power supply operations and rates.

The FERC also regulates I&M’s wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. Retail transmission

rates are based on formula rates included in the PJM OATT that are cost-based and are unbundled in Michigan for I&M.

In addition, the FERC regulates the SIA and TA, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. The FERC also regulates the PCA. See Note 14 - Related Party Transactions for additional information.

Basis of Accounting

I&M’s accounting is subject to the requirements of the IURC, the MPSC 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:


·			Accounting for subsidiaries on an equity basis.
·			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 tax assets related to the accounting guidance for “Uncertainty in Income Taxes” as a reduction to current liabilities rather than a tax benefit.
·			The classification of noncurrent tax liabilities related to the accounting guidance for “Uncertainty in Income Taxes” as a current liability rather than a noncurrent liability.
·			The classification of regulatory assets and liabilities related to the accounting guidance for “Accounting for Income Taxes” as separate assets and liabilities rather than as a single amount.
·			The presentation of finance leased assets and their associated accumulated amortization as a single amount instead of as separate amounts.
·			The classification of factored accounts receivable expense as a nonoperating expense instead of as an operating expense.
·			The presentation of over/under fuel recovery in revenue rather than as a component of operating expense.
·			The classification of certain nonoperating revenues as miscellaneous nonoperating income instead of as operating revenue.
·			The classification of certain nonoperating expenses as miscellaneous nonoperating expense instead of as operating expense.
·			The separate classification of income tax expense for operating and nonoperating activities instead of as a single income tax expense.
·			The classification of DCC Fuel as a finance lease rather than consolidating in accordance with the accounting guidance for "Variable Interest Entities."
·			The classification of coal procurement sales as a reduction of fuel expense rather than as revenue.
·			The classification of unamortized loss on reacquired debt in deferred debits rather than in regulatory assets.


·			The classification of unamortized gain on reacquired debt in deferred credits rather than in regulatory liabilities.
·			The classification of accumulated deferred investment tax credits in deferred credits rather than in regulatory liabilities and deferred investment tax credits.
·			The classification of plant impairment in utility plant adjustments rather than in property, plant and equipment - electric generation.
·			The classification of plant impairment in utility plant adjustments rather than in property, plant and equipment - accumulated depreciation and amortization.
·			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 unrecovered plant costs as accumulated depreciation instead of regulatory assets.
·			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 classification of operating lease assets as Other Property and Investments rather than as noncurrent assets.
·			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.
·			The classification of cloud computing implementation costs as Other Property and Investments rather than as a noncurrent asset.
·			The classification of the amortization of certain finance leases as depreciation and amortization rather than as operating expenses.
·			The classification of certain plant balances as nonutility property rather than as utility property.
·			The presentation of certain property balances on a net basis in gross property rather than a split between gross property and accumulated depreciation.

Accounting for the Effects of Cost-Based Regulation

I&M’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,” regulatory assets (deferred expenses) 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 income with its passage to customers in cost-based regulated rates.

Use of Estimates

The preparation of these financial statements requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not

limited to, inventory valuation, allowance for doubtful accounts, long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.

Cash and Cash Equivalents

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

Supplementary Information


		2022			2021
For the Years Ended December 31,		(in millions)
Cash was Paid for:
	Interest (Net of Capitalized Amounts)		$	116.7		$	109.5
	Income Taxes (Net of Refunds)		11.2			29.3
Noncash Acquisitions Under Finance Leases			144.9			197.2
As of December 31,
Construction Expenditures Included in Current and Accrued Liabilities			71.9			87.8

AEP System Tax Allocation

I&M and other AEP subsidiaries join in the filing of a consolidated federal income tax return. 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 I&M and other AEP subsidiaries through a reduction of current tax expense. In the first quarter of 2022, I&M and other AEP 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 I&M’s financial statements. The consolidated NOL 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 NOL, 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 over time as the performance obligations of delivering energy to customers are satisfied. To the extent that deliveries have occurred but a bill has not been issued, I&M accrues and recognizes, as Accrued Utility Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing.

AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables they acquire from affiliated utility subsidiaries. See “Securitized Accounts Receivable – AEP Credit” section of Note 13 for additional information.

Allowance for Uncollectible Accounts

Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from I&M. The assessment is performed by I&M which inherently contemplates any differences in geographical risk characteristics for the allowance. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. 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

I&M does not have any significant customers that comprise 10% or more of its operating revenues for the years ended December 31, 2022 and 2021, respectively.

I&M monitors credit levels and the financial condition of its customers on a continuous basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying financial statements.

Renewable Energy Credits

In regulated jurisdictions, I&M records renewable energy credits (RECs) at cost. I&M follows the inventory model for these RECs. RECs expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. RECs with expected consumption beyond one year are included in Deferred Charges and Other

Noncurrent Assets on the balance sheets. The purchases and sales of RECs are reported in the Operating Activities section of the statements of cash flows. RECs that are consumed to meet applicable state renewable portfolio standards are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of RECs affects the determination of deferred fuel and REC costs and the amortization of regulatory assets for certain jurisdictions.

Property, Plant and Equipment

Electric utility property, plant and equipment for rate-regulated operations 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.

Nuclear fuel, including nuclear fuel in the fabrication phase, is included in Net Nuclear Fuel on the balance sheets.

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.

Investment in Subsidiary Companies

I&M has two wholly-owned subsidiaries, Blackhawk Coal Company and Price River Coal Company that were formerly engaged in coal-mining operations. Blackhawk Coal Company currently leases and subleases portions of its Utah coal rights and land to nonaffiliated companies. Price River Coal Company which owns no land or mineral rights is inactive. Investment in the net assets of the two wholly-owned subsidiaries is carried at cost plus equity in their undistributed earnings since acquisition.

Allowance for Funds Used During Construction

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

Asset Retirement Obligations

I&M records ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal, the retirement of certain ash disposal facilities and the decommissioning of the Cook Plant. 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. I&M 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 I&M plans to use their facilities indefinitely. The retirement obligation would only be recognized if and when I&M 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. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility.

AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear 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 and nuclear 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 purchased electricity, 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. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily using the units-of-production method. 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 incorporated into the development of future fuel rates billed to or refunded to customers. The amount of an over-recovery or under-recovery can also be affected by actions of the IURC and the MPSC. On a routine basis, the IURC and the MPSC review and/or audit I&M’s, OPCo’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. I&M shares the majority of its Off-system Sales margins to customers either through an active FAC or other rate mechanisms. Where the FAC or Off-system Sales sharing mechanism is capped, frozen, non-existent or not applicable to merchant operations, changes in fuel costs or sharing of off-system sales impact earnings.

Revenue Recognition

Regulatory Accounting

I&M’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, assets are recorded on the balance sheets. Regulatory assets are reviewed for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is derecognized as a charge against income.

Retail and Wholesale Supply and Delivery of Electricity

I&M recognizes revenues from customers for retail and wholesale electricity sales and electricity transmission and distribution delivery services. I&M recognizes such revenues on the statements of income as the performance obligations of delivering energy to customers are satisfied. Recognized revenues include both billed and unbilled amounts.

Wholesale transmission revenue is based on FERC-approved formula rate filings 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. These annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for “Regulated Operations”. An estimated annual true-up is recorded by I&M in the fourth quarter of each calendar year and a final annual true-up is recognized by I&M in the second quarter of each calendar year following the filing of annual FERC reports. Any portion of the true-ups applicable to an affiliated company is recorded as Accounts Receivable from Associated Companies or Accounts Payable to

Associated Companies on the balance sheets. Any portion of the true-ups applicable to third-parties is recorded as regulatory assets or regulatory liabilities on the balance sheets. See Note 16 - Revenue from Contracts with Customers for additional information.

Gross versus Net Presentation of Certain Electricity Supply and Delivery Activities

Most of the power produced at the generation plants is sold to PJM. I&M also purchases power from PJM to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM, on an hourly net basis, used to serve retail load are recorded gross as Operation Expenses on the statements of income.

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

In general, I&M records expenses when purchased electricity is received and when expenses are incurred. I&M defers unrealized MTM amounts as regulatory assets (for losses) and regulatory liabilities (for gains).

Energy Marketing and Risk Management Activities

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

I&M 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.

I&M 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. I&M includes realized gains and losses on marketing and risk management transactions in revenue or expense based on the transaction’s facts and circumstances. The 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 derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge). In the event I&M 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, I&M 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 their statements of income. See “Accounting for Cash Flow Hedging Strategies” section of Note 10 for additional information.

Levelization of Nuclear Refueling Outage Costs

In accordance with regulatory orders, I&M defers incremental operation and maintenance costs associated with periodic refueling outages at its Cook Plant and amortizes the costs over approximately 18 months, beginning with the month following the start of each unit’s refueling outage and lasting until the end of the month in which the same unit’s next scheduled refueling outage begins.

Maintenance

I&M expenses maintenance costs as incurred. If it becomes probable that I&M will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with its recovery in cost-based regulated revenues. I&M defers costs above the level included in base rates and amortizes those deferrals commensurate with recovery through rate riders.

Income Taxes and Investment Tax Credits

I&M 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 required by a regulator to be 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.

I&M applies the deferral methodology for the recognition of ITCs. Deferred ITCs are amortized to income tax expense over the life of the asset that generated the credit. Amortization of deferred ITCs begins when the asset is placed in-service, except where regulatory commissions reflect ITCs in the rate-making process, then amortization begins when the utility is able to utilize the ITC on a stand-alone basis.

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

Excise Taxes

As an agent for some state and local governments, I&M collects from customers certain excise taxes levied by those state or local governments on customers. I&M does not record 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 associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting 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

I&M participates in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans. Substantially all of I&M’s employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. I&M also participates in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees. I&M is allocated a proportionate share of benefit costs and account for their 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, nuclear decommissioning and SNF disposal. All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations. The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance.

Benefit Plans

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

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

•Maintaining a long-term investment horizon.

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

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

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

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

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

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


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

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

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

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

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

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

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

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

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

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

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

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

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

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

Nuclear Trust Funds

Nuclear decommissioning and SNF trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and SNF disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include:

•Acceptable investments (rated investment grade or above when purchased).

•Maximum percentage invested in a specific type of investment.

•Prohibition of investment in obligations of AEP, I&M or their affiliates.

•Withdrawals permitted only for payment of decommissioning costs and trust expenses.

I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by an external investment manager that must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.

I&M records securities held in these trust funds in Other Special Funds on its balance sheets. I&M records these securities at fair value. I&M classifies debt securities in the trust funds as available-for-sale due to their long-term purpose.

Other-than-temporary impairments for investments in debt securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains, unrealized losses and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. See the “Nuclear Contingencies” section of Note 6 for additional discussion of nuclear matters. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 10 for disclosure of the fair value of assets within the trusts.

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.

Subsequent Events

Management has evaluated the impact of events occurring after December 31, 2022 through February 23, 2023, the date that AEP’s Form 10-K was 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 I&M’s business. There are no new standards expected to have a material impact on I&M’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 information.




			Pension and OPEB
			Amortization		Changes in
	Cash Flow Hedge –		of Deferred		Funded
For the Year Ended December 31, 2022	Interest Rate		Costs		Status		Total
	(in millions)
Balance in AOCI as of December 31, 2021	$	(6.7)	$	4.7	$	0.7	$	(1.3)
Change in Fair Value Recognized in AOCI, Net of Tax	—		—		(0.3)		(0.3)
Amount of (Gain) Loss Reclassified from AOCI
Interest on Long-Term Debt (a)	2.0		—		—		2.0
Amortization of Prior Service Cost (Credit)	—		(0.8)		—		(0.8)
Amortization of Actuarial (Gains) Losses	—		0.4		—		0.4
Reclassifications from AOCI, before Income Tax (Expense) Benefit	2.0		(0.4)		—		1.6
Income Tax (Expense) Benefit	0.4		(0.1)		—		0.3
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	1.6		(0.3)		—		1.3
Net Current Period Other Comprehensive Income (Loss)	1.6		(0.3)		(0.3)		1.0
Balance in AOCI as of December 31, 2022	$	(5.1)	$	4.4	$	0.4	$	(0.3)


			Pension and OPEB
			Amortization		Changes in
	Cash Flow Hedge –		of Deferred		Funded
For the Year Ended December 31, 2021	Interest Rate		Costs		Status		Total
	(in millions)
Balance in AOCI as of December 31, 2020	$	(8.3)	$	4.8	$	(3.5)	$	(7.0)
Change in Fair Value Recognized in AOCI, Net of Tax	—		—		4.2		4.2
Amount of (Gain) Loss Reclassified from AOCI
Interest on Long-Term Debt (a)	2.0		—		—		2.0
Amortization of Prior Service Cost (Credit)	—		(0.8)		—		(0.8)
Amortization of Actuarial (Gains) Losses	—		0.7		—		0.7
Reclassifications from AOCI, before Income Tax (Expense) Benefit	2.0		(0.1)		—		1.9
Income Tax (Expense) Benefit	0.4		—		—		0.4
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	1.6		(0.1)		—		1.5
Net Current Period Other Comprehensive Income (Loss)	1.6		(0.1)		4.2		5.7
Balance in AOCI as of December 31, 2021	$	(6.7)	$	4.7	$	0.7	$	(1.3)

(1)Amounts reclassified to the referenced line item on the statements of income.

4. RATE MATTERS

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

Michigan Power Supply Cost Recovery (PSCR) Reconciliation

In April 2022, an ALJ issued a PFD for I&M’s PSCR reconciliation for the 12-month period ending December 31, 2020, recommending the MPSC disallow approximately $8 million of purchased power costs that I&M incurred under the Inter-Company Power Agreement with OVEC and the Unit Power Agreement with AEGCo. In February 2023, the MPSC issued an order resulting in a $1 million disallowance of 2020 OVEC costs.

Indiana Earnings Test Filings

I&M is required by Indiana law to submit an earnings test evaluation for the most recent one-year and five-year periods as part of I&M’s semi-annual Indiana FAC filings. These earnings test evaluations require I&M to include a credit in the FAC factor computation for periods in which I&M earned above its authorized return for both the one-year and five-year periods. The credit is determined as 50% of the lower of the one-year or five-year earnings above the authorized level. In August 2022, I&M submitted its FAC filing and earnings test evaluation for the period ended May 2022, which calculated a credit due to customers of $14 million. In October 2022, the IURC approved the FAC filing and earnings test evaluation, with the credit to customers starting in November 2022 through the FAC. As of December 31, 2022, I&M’s financial statements adequately reflect the estimated impact of I&M’s upcoming Indiana earnings test filings. If it is determined that I&M’s over-earnings exceed what has been recorded, it could reduce future net income and cash flows and impact financial condition.

2022 Michigan Integrated Resource Plan (IRP) Filing

In February 2022, I&M filed a request with the MPSC for approval of its 2022 IRP. Included in that filing were requests for approval and deferral of costs associated with resources commencing construction within three years of the Commission’s order in the filing. These resources include the new generation resources expected to be in-service by 2028 and demand-side resources, including load management programs and conservation voltage reduction investments. I&M is also requesting the MPSC approval of I&M’s Rockport Plant, Unit 2 transition plan consistent with that approved by the IURC, including certain cost recovery related to remaining net book value of leasehold improvements made during the term of the Rockport Unit 2 lease and future use of Rockport Plant, Unit 2 as a capacity resource. In addition, I&M has made requests for approval of a financial incentive on certain power purchase agreements and load management programs. As of December 31, 2022, I&M’s total net book value for these Rockport Plant, Unit 2 leasehold improvements was approximately $17 million on a Michigan jurisdictional basis.

In November 2022, I&M filed a settlement agreement, which included a Rockport Plant, Unit 2 transition plan. Under this plan, I&M Michigan ratepayers will receive a jurisdictional share of post-lease revenues in excess of costs from Rockport Plant, Unit 2’s operations as a merchant facility. In addition, I&M will continue to recover

the remaining net book value of Rockport Plant, Unit 2 leasehold improvements through 2028, including a pretax return. In February 2023, the MPSC issued an order approving the settlement agreement without modification.

Request to Update AEGCo Depreciation Rates

In October 2022, AEP, on behalf of AEGCo, submitted proposed revisions to AEGCo’s depreciation rates for its 50% ownership interest in Rockport Plant, Unit 1 and Unit 2, reflected in AEGCo’s unit power agreement with I&M. The proposed depreciation rates for these assets reflect an estimated 2028 retirement date for the Rockport Plant. AEGCo’s previous FERC-approved depreciation rates for Rockport Plant, Unit 1 were based upon a December 31, 2028 estimated retirement date while AEGCo’s previous FERC-approved depreciation rates for Rockport Plant, Unit 2 leasehold improvements were based upon a December 31, 2022 estimated retirement date in conjunction with the termination of the Rockport Plant, Unit 2 lease.

In December 2022, the FERC issued an order approving the proposed AEGCo Rockport depreciation rates effective January 1, 2023, subject to further review and a potential refund. The FERC established a separate proceeding to review: (a) AEGCo’s acquisition value for the Rockport Plant, Unit 2 base generating asset (original cost and accumulated depreciation), (b) the appropriateness of including future capital additions as stated components in proposed depreciation rates, in light of the UPA’s formula rate mechanism, (c) the appropriateness of applying two different depreciation rates to a single asset common to both units and (d) the accounting and regulatory treatment of Rockport Plant, Unit 2 costs of removal and related AROs. It is expected that the FERC will issue an order on this review in the second half of 2023. This FERC review and subsequent order on these issues could reduce future net income and cash flows and impact financial conditions.

5. EFFECTS OF REGULATION


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

Regulatory assets pending final regulatory approval:

Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval	$	0.1	$	0.1
Total Regulatory Assets Currently Earning a Return	0.1		0.1
Regulatory Assets Currently Not Earning a Return
Income Tax Assets	87.7		—
Storm-Related Costs - Indiana	21.6		—
Other Regulatory Assets Pending Final Regulatory Approval	2.0		3.6
Total Regulatory Assets Currently Not Earning a Return	111.3		3.6

Total Regulatory Assets Pending Final Regulatory Approval	111.4		3.7

Regulatory assets approved for recovery:

Regulatory Assets Currently Earning a Return
Rockport Plant Dry Sorbent Injection System and Selective Catalytic Reduction	25.6		30.1		6 years
Cook Plant Uprate Project	25.3		27.7		11 years
Deferred Cook Plant Life Cycle Management Project Costs - Michigan, FERC	12.1		13.1		12 years
Cook Plant Turbine - Indiana	9.0		9.6		16 years
Under-recovered Fuel Costs - Michigan	9.0		6.4		1 year
Cook Plant Study Costs	8.7		9.4		13 years
Other Regulatory Assets Approved for Recovery	11.9		6.0		various
Total Regulatory Assets Currently Earning a Return	101.6		102.3
Regulatory Assets Currently Not Earning a Return
Income Tax Assets	293.1		360.4		(a)
Cook Plant Nuclear Refueling Outage Levelization	81.2		32.0		3 years
Under-recovered Fuel Costs - Indiana	38.1		—		1 year
Pension and OPEB Funded Status	26.9		—		12 years
Peak Demand Energy Efficiency	10.3		2.8		2 years
Postemployment Benefits	7.7		9.0		3 years
Storm-Related Costs - Indiana	3.4		12.6		2 years
PJM Costs and Off-system Sales Margin Sharing - Indiana	—		15.1
Other Regulatory Assets Approved for Recovery	22.9		18.4		various
Total Regulatory Assets Currently Not Earning a Return	483.6		450.3

Total Regulatory Assets Approved for Recovery	585.2		552.6

Total FERC Account 182.3 Regulatory Assets	$	696.6	$	556.3

(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 Refund Period
Regulatory Liabilities:	2022		2021
	(in millions)

Regulatory liabilities approved for payment:

Regulatory Liabilities Currently Paying a Return
Income Tax Liabilities (a)	$	461.7	$	543.0	(b)
Renewable Energy Surcharge - Michigan	23.2		14.9		2 years
Other Regulatory Liabilities Approved for Payment	3.0		7.0		various
Total Regulatory Liabilities Currently Paying a Return	487.9		564.9
Regulatory Liabilities Currently Not Paying a Return
Excess Nuclear Decommissioning Funding	1,318.5		1,939.7		(c)
Spent Nuclear Fuel	45.8		49.5		(c)
PJM Costs and Off-system Sales Margin Sharing - Indiana	34.2		—		2 years
Pension OPEB Funded Status	—		27.6
Rockport Plant, Unit 2 Selective Catalytic Reduction	—		10.6
Over-recovered Fuel Costs - Indiana	—		1.5
Other Regulatory Liabilities Approved for Payment	8.5		13.9		various
Total Regulatory Liabilities Currently Not Paying a Return	1,407.0		2,042.8

Total Regulatory Liabilities Approved for Payment	1,894.9		2,607.7

Total FERC 254 Account Regulatory Liabilities	$	1,894.9	$	2,607.7

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

(b) Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $42 million and $90 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 6 years.

(c) Relieved when plant is decommissioned.

6. COMMITMENTS, GUARANTEES AND CONTINGENCIES

I&M is subject to certain claims and legal actions arising in the ordinary course of business. In addition, I&M’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 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

I&M has substantial commitments for fuel, energy and capacity contracts as part of the normal course of business. Certain contracts contain penalty provisions for early termination.

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


Contractual Commitments	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Fuel Purchase Contracts (a)	$	200.9	$	235.2	$	53.3	$	222.4	$	711.8
Energy and Capacity Purchase Contracts	140.9		290.0		273.8		276.8		981.5
Total	$	341.8	$	525.2	$	327.1	$	499.2	$	1,693.3

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

GUARANTEES

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

Indemnifications and Other Guarantees

Contracts

I&M 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

I&M leases equipment under master lease agreements. See “Master Lease Agreements” section of Note 12 for additional information.

ENVIRONMENTAL CONTINGENCIES

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, sludge, low-level radioactive waste and SNF. 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. I&M currently incurs costs to dispose of these substances safely.

Superfund addresses clean-up of hazardous substances that are released to the environment. The Federal EPA administers the clean-up programs. Several states enacted similar laws. There are four sites for which I&M received information requests which could lead to Potentially Responsible Party (PRP) designation. I&M has also been named potentially liable at two sites under state law. In those instances where a PRP or defendant has been named, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. Liability has been resolved for a number of sites with no significant effect on net income.

Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often non-hazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. As of December 31, 2022, management’s estimates do not anticipate material clean-up costs for identified Superfund sites.

NUCLEAR CONTINGENCIES

I&M owns and operates the two-unit 2,296 MW Cook Plant under licenses granted by the NRC. I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. Management is currently evaluating applying for license extensions for both units. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.

Decommissioning and Low-Level Waste Accumulation Disposal

The costs to decommission a nuclear plant are affected by NRC regulations and the SNF disposal program. Decommissioning costs are accrued over the service life of Cook Plant. The most recent decommissioning cost study was performed in 2021. According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste was $2.2 billion in 2021 non-discounted dollars, with additional ongoing costs of $7 million per year for post decommissioning storage of SNF and an eventual cost of $33 million for the subsequent decommissioning of the SNF storage facility, also in 2021 non-discounted dollars. I&M recovers estimated decommissioning costs for the Cook Plant in its rates. The amounts recovered in rates were $2 million and $4 million for the years ended December 31, 2022 and 2021, respectively. Decommissioning costs recovered from customers are deposited in external trusts.

As of December 31, 2022 and 2021, the total decommissioning trust fund balances were $3 billion and $3.5 billion, respectively. The decrease in the trust fund balance was driven by unfavorable investment performance in 2022. Trust fund earnings increase the fund assets and may decrease the amount remaining to be recovered from customers. Trust fund losses decrease the fund assets and may increase the amount remaining to be recovered from customers. The decommissioning costs (including unrealized gains and losses, interest and trust funds expenses) increase or decrease the recorded liability.

I&M continues to work with regulators and customers to establish rates designed to collect the estimated costs of decommissioning the Cook Plant. However, future net income and cash flows would be reduced and financial condition could be impacted if the cost of SNF disposal and decommissioning increases and cannot be recovered.

Spent Nuclear Fuel Disposal

The federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one-mill per KWh for fuel consumed after April 6, 1983 at the Cook Plant was collected from customers and remitted to the DOE through May 14, 2014. In May 2014, pursuant to court order from the U.S Court of Appeals for the District of Columbia Circuit, the DOE adjusted the fee to $0. As of December 31, 2022 and 2021, fees and related interest of $286 million and $281 million, respectively, for fuel consumed prior to April 7, 1983 were recorded as Long-term Debt and funds collected from customers along with related earnings totaling $330 million and $329 million, respectively, to pay the fee, were recorded as part of Other Special Funds

on the balance sheets. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program.

In 2011, I&M signed a settlement agreement with the federal government which permits I&M to make annual filings to recover certain SNF storage costs incurred as a result of the government’s delay in accepting SNF for permanent storage. Under the settlement agreement, I&M received $3 million and $14 million in 2022 and 2021, respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2022. The proceeds reduced costs for dry cask storage. As of December 31, 2022 and 2021, I&M deferred $21 million and $3 million, respectively, in Miscellaneous Current and Accrued Assets and $3 million and $21 million, respectively, in Miscellaneous Deferred Debits on the balance sheets for dry cask storage and related operation and maintenance costs for recovery under this agreement. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 10 for additional information.

Nuclear Insurance

I&M carries nuclear property insurance of $2.7 billion to cover a nuclear incident at Cook Plant including coverage for decontamination and stabilization, as well as premature decommissioning caused by a nuclear incident. Insurance coverage for a nonnuclear property incident at Cook Plant is $500 million. Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage. I&M utilizes industry mutual insurers for the placement of this insurance coverage. Coverage from these industry mutual insurance programs require a contingent financial obligation of up to $41 million for I&M, which is assessable if the insurer’s financial resources would be inadequate to pay for industry losses.

The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public nuclear liability arising from a nuclear incident of $13.7 billion and applies to any incident at a licensed reactor in the U.S. Commercially available insurance, which must be carried for each licensed reactor, provides $450 million of primary coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $275 million per nuclear incident on Cook Plant’s reactors payable in annual installments of $41 million. The number of incidents for which payments could be required is not limited.

In the event of an incident of a catastrophic nature, I&M is covered for public nuclear liability for the first $450 million through commercially available insurance. The next level of liability coverage of up to $13.2 billion would be covered by claim premium assessments made under the Price-Anderson Act. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds, I&M would seek recovery of those amounts from customers through a rate increase. If recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition.

OPERATIONAL CONTINGENCIES

Insurance and Potential Losses

I&M maintains insurance coverage normal and customary for electric utilities, subject to various deductibles. I&M 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 nonnuclear 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 retentions absorbed by I&M. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers. See “Nuclear Contingencies” section above for additional information.

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 or damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant. 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.

Rockport Plant Litigation

In 2013, the Wilmington Trust Company filed suit in the U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it would be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering, refueling or retirement of the unit. The plaintiffs sought a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs.

After the litigation proceeded at the district court and appellate court, in April 2021, I&M and AEGCo reached an agreement to acquire 100% of the interests in Rockport Plant, Unit 2 for $116 million from certain financial institutions that own the unit through trusts established by Wilmington Trust, the nonaffiliated owner trustee of the ownership interests in the unit. The transaction closed at the expiration of the Rockport Plant, Unit 2 lease in December 2022 and also resulted in a final settlement of, and release of claims in, the lease litigation.

Subsequent to the end of the Rockport Plant, Unit 2 lease in December 2022, AEGCo’s 50% ownership share of Rockport Plant, Unit 2 is being billed to I&M under a FERC-approved UPA. I&M’s purchased power from AEGCo and I&M’s 50% ownership share of Rockport Plant, Unit 2 electricity generated represent a merchant resource for I&M until Rockport Plant, Unit 2 is retired in 2028. A 2021 IURC order approved a settlement agreement addressing the future use of Rockport Plant, Unit 2 as a short-term capacity resource through the June 2023 - May 2024 PJM planning year. The MPSC issued an order in February 2023 approving the settlement agreement on I&M’s 2022 Integrated Resource Plan (IRP) filing, which included certain cost recovery for the remaining net book value of leasehold improvements made during the term of the Rockport Plant, Unit 2 lease

and future use of Rockport Plant, Unit 2 as a capacity resource. If I&M cannot recover its future investment and expenses related to the merchant share of Rockport Plant Unit 2, it could reduce future net income and cash flows and impact financial condition.

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.

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

I&M recognizes the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. I&M recognizes an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, 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. I&M records a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for rate-making purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.

Actuarial Assumptions for Benefit Obligations

The weighted-average assumptions used in the measurement of I&M’s benefit obligations are shown in the following table:


	Pension Plans				OPEB
	December 31,
Assumption	2022		2021		2022	2021
Discount Rate	5.50 %		2.90 %		5.50 %	2.90 %
Interest Crediting Rate	4.25 %		4.00 %		NA	NA
Rate of Compensation Increase	5.00 %	(a)	5.00 %	(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 Plans						OPEB
	Year Ended December 31,
Assumption	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	5.00	%	(a)	5.00	%	(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. Management monitors the plans 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, Funded Status and Amounts Recognized on the Balance Sheets

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


	Pension Plans				OPEB
	2022		2021		2022		2021
Change in Benefit Obligation	(in millions)
Benefit Obligation as of January 1,	$	612.1	$	653.3	$	118.6	$	141.4
Service Cost	16.2		17.5		0.9		1.3
Interest Cost	17.0		16.2		3.4		3.5
Actuarial Gain	(138.0)		(29.5)		(8.7)		(16.8)
Plan Amendments	—		—		—		(0.7)
Benefit Payments	(40.5)		(45.4)		(18.3)		(15.3)
Participant Contributions	—		—		6.0		5.2
Benefit Obligation as of December 31,	$	466.8	$	612.1	$	101.9	$	118.6

Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1,	$	681.5	$	698.1	$	248.7	$	238.2
Actual Gain (Loss) on Plan Assets	(107.4)		28.8		(45.9)		20.6
Company Contributions	0.1		—		—		—
Participant Contributions	—		—		6.0		5.2
Benefit Payments	(40.5)		(45.4)		(18.3)		(15.3)
Fair Value of Plan Assets as of December 31,	$	533.7	$	681.5	$	190.5	$	248.7

Funded Status as of December 31,	$	66.9	$	69.4	$	88.6	$	130.1


	Pension Plans				OPEB
	December 31,
	2022		2021		2022		2021
	(in millions)
Special Funds – Prepaid Benefit Costs	$	68.5	$	71.4	$	88.6	$	130.1
Miscellaneous Current and Accrued Liabilities – Short-term Benefit Liability	(0.1)		(0.1)		—		—
Accumulated Provision for Pensions and Benefits – Long-term Benefit Liability	(1.5)		(1.9)		—		—
Funded Status	$	66.9	$	69.4	$	88.6	$	130.1

Amounts Included in Regulatory Assets, Deferred Income Taxes and AOCI

The following tables show the components of the plans included in regulatory assets, Accumulated Deferred Income Taxes, and income tax expense and the items attributable to the change in these components:


	Pension Plans				OPEB
	December 31,
	2022		2021		2022		2021
Components	(in millions)
Net Actuarial (Gain) Loss	$	(6.9)	$	(1.6)	$	40.2	$	(10.7)
Prior Service Credit	—		—		(12.4)		(22.1)

Recorded as
Regulatory Assets/Liabilities (a)	$	4.8	$	3.1	$	22.1	$	(30.7)
Deferred Income Taxes	(2.4)		(1.0)		1.2		(0.4)
Net of Tax AOCI	(9.3)		(3.7)		4.5		(1.7)

(a) Recorded as a Regulatory Asset as of December 31, 2022 and recorded as a Regulatory Liability as of December 31, 2021.


	Pension Plans				OPEB
	2022		2021		2022		2021
Components	(in millions)
Actuarial (Gain) Loss During the Year	$	1.8	$	(29.4)	$	50.9	$	(26.3)
Amortization of Actuarial Loss	(7.1)		(11.7)		—		—
Prior Service Credit	—		—		—		(0.7)
Amortization of Prior Service Credit	—		—		9.7		9.6
Change for the Year Ended December 31,	$	(5.3)	$	(41.1)	$	60.6	$	(17.4)

Determination of Pension Expense

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

Pension and OPEB Assets

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


Pension Plan				OPEB
December 31,
2022		2021		2022		2021
12.9	%	12.7	%	12.3	%	12.2	%

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


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

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

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

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

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

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

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

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


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

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

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

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

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

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

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

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


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

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

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

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

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

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

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

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


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

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

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

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

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

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

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

Accumulated Benefit Obligation

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


	December 31,
Accumulated Benefit Obligation	2022		2021
	(in millions)
Qualified Pension Plan	$	443.8	$	575.2
Nonqualified Pension Plans	1.2		1.2
Total	$	445.0	$	576.4

Obligations in Excess of Fair Values

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

Projected Benefit Obligation


	December 31,
	2022		2021
	(in millions)
Projected Benefit Obligation	$	1.6	$	1.9
Fair Value of Plan Assets	—		—
Underfunded Projected Benefit Obligation	$	(1.6)	$	(1.9)

Accumulated Benefit Obligation


	December 31,
	2022		2021
	(in millions)
Accumulated Benefit Obligation	$	1.2	$	1.2
Fair Value of Plan Assets	—		—
Underfunded Accumulated Benefit Obligation	$	(1.2)	$	(1.2)

Estimated Future Benefit Payments and Contributions

I&M expects contributions and payments for the pension plans to be immaterial during 2023. For the pension plans, this amount includes the payment of unfunded nonqualified benefits plus contributions to the qualified trust fund of at least the minimum amount required by the Employee Retirement Income Security Act. For the qualified pension plan, I&M may also make additional discretionary contributions to maintain the funded status of the plan.

The table below reflects the total benefits expected to be paid from the plan or from I&M’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 the pension benefits and OPEB are as follows:


	Estimated Payments
	Pension Plans		OPEB
	(in millions)
2023	$	38.1	$	14.9
2024	39.8		15.0
2025	40.7		16.1
2026	40.4		16.3
2027	41.0		16.1
Years 2028 to 2032, in Total	196.4		75.1

Components of Net Periodic Benefit Cost

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


	Pension Plans				OPEB
	Years Ended December 31,
	2022		2021		2022		2021
	(in millions)
Service Cost	$	16.2	$	17.5	$	0.9	$	1.3
Interest Cost	17.0		16.2		3.4		3.5
Expected Return on Plan Assets	(32.4)		(28.9)		(13.7)		(11.1)
Amortization of Prior Service Credit	—		—		(9.7)		(9.6)
Amortization of Net Actuarial Loss	7.1		11.7		—		—
Net Periodic Benefit Cost (Credit)	7.9		16.5		(19.1)		(15.9)
Capitalized Portion	(4.6)		(4.9)		(0.3)		(0.4)
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	3.3	$	11.6	$	(19.4)	$	(16.3)

American Electric Power System Retirement Savings Plan

I&M 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 company 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 to the retirement savings plans for the years ended December 31, 2022 and 2021 were $11 million and $11 million, respectively.

8. BUSINESS SEGMENTS

I&M has one reportable segment, an electricity generation, transmission and distribution business. I&M’s other activities are insignificant.

9. DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

AEPSC is agent for and transacts on behalf of I&M.

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

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

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


Notional Volume of Derivative Instruments

Primary Risk Exposure	2022	2021	Unit of Measure
	(in millions)
Commodity:
Power	4.2	13.6	MWhs
Heating Oil and Gasoline	0.7	0.7	Gallons

Cash Flow Hedging Strategies

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

I&M utilizes a variety of interest rate derivative transactions in order to manage interest rate risk exposure. I&M also utilizes interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. I&M does not hedge all interest rate exposure.

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE 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, I&M applies valuation adjustments for discounting, liquidity and credit quality.

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

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

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


	December 31, 2022
	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts -		in the Statement of		Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)		Financial Position (c)
	(in millions)
Derivative Instrument Assets	$	16.5	$	(1.1)	$	15.4
Long-Term Portion of Derivative Instrument Assets	0.5		(0.3)		0.2

Derivative Instrument Liabilities	1.2		(1.2)		—
Long-Term Portion of Derivative Instrument Liabilities	0.3		(0.3)		—


	December 31, 2021
	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts -		in the Statement of		Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)		Financial Position (c)
	(in millions)
Derivative Instrument Assets	$	11.3	$	(8.0)	$	3.3
Long-Term Portion of Derivative Instrument Assets	0.2		(0.2)		—

Derivative Instrument Liabilities	15.0		(10.0)		5.0
Long-Term Portion of Derivative Instrument Liabilities	0.2		(0.2)		—

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

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

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

The table below presents the activity of derivative risk management contracts:


Amount of Gain (Loss) Recognized on Risk Management Contracts

	Years Ended December 31,
Location of Gain (Loss)	2022		2021
	(in millions)
Operating Revenues	$	10.6	$	(0.1)
Operation Expenses	0.6		0.3
Maintenance Expenses	0.6		0.3
Other Regulatory Assets (a)	(0.8)		(14.8)
Other Regulatory Liabilities (a)	8.6		(3.9)
Total Gain (Loss) on Risk Management Contracts (b)	$	19.6	$	(18.2)

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

(b) Increase in amounts for the year ended December 31, 2022 are primarily due to increases in commodity prices for power and natural gas and an increase in value of FTRs.

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

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

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

Accounting for Cash Flow Hedging Strategies

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

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

I&M reclassifies gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income on the balance sheets into Interest on Long-term Debt on the statements of income in those periods in which hedged interest payments occur. During the years ended 2022 and 2021, I&M did not have outstanding interest rate derivatives.

For details on effective cash flow hedges included in Accumulated Other Comprehensive Income on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 - Comprehensive Income.

Cash flow hedges included in Accumulated Other Comprehensive Income on the balance sheets were:

Impact of Cash Flow Hedges on the Balance Sheets

December 31, 2022

December 31, 2021

Interest Rate

Expected to be

Reclassified to

Net Income During

AOCI Gain (Loss)

the Next

AOCI Gain (Loss)

the Next

Net of Tax

Twelve Months

Net of Tax

Twelve Months

(in millions)

$

(5.1)

$

(0.6)

$

(6.7)

$

(1.6)

The actual amounts reclassified from Accumulated Other Comprehensive Income to Net Income can differ from the estimate above due to market price changes.

Credit Risk

Management mitigates credit risk in 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.

Credit-Risk-Related Contingent Features

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. I&M has not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. I&M had no derivative contracts with collateral triggering events in a net liability position as of December 31, 2022 and 2021.

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 I&M 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. I&M had no derivative contracts with cross-acceleration provisions outstanding as of December 31, 2022 and 2021.

Cross-Default Triggers

In addition, a majority of I&M’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. Amounts for I&M were immaterial for years ended December 31, 2022 and 2021.

10. 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 Long-term Debt are summarized in the following table:


December 31,
2022				2021
Book Value		Fair Value		Book Value		Fair Value
(in millions)
$	3,095.5	$	2,749.4	$	3,092.9	$	3,625.8

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

Securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF are recorded at fair value. See “Nuclear Trust Funds” section of Note 1 for additional information.

The following is a summary of nuclear trust fund investments:


	December 31,
	2022						2021
			Gross		Other-Than-				Gross		Other-Than-
	Fair		Unrealized		Temporary		Fair		Unrealized		Temporary
	Value		Gains		Impairments		Value		Gains		Impairments
	(in millions)
Cash and Cash Equivalents	$	21.2	$	—	$	—	$	84.7	$	—	$	—
Fixed Income Securities:
United States Government	1,123.8		(3.1)		(18.8)		1,156.4		66.3		(7.9)
Corporate Debt	61.6		(7.0)		(9.6)		76.7		6.7		(2.1)
State and Local Government	3.3		0.1		(0.1)		7.3		0.4		(0.1)
Subtotal Fixed Income Securities	1,188.7		(10.0)		(28.5)		1,240.4		73.4		(10.1)
Equity Securities - Domestic (a)	2,131.3		1,477.3		—		2,541.9		1,901.3		—
Other Special Funds	$	3,341.2	$	1,467.3	$	(28.5)	$	3,867.0	$	1,974.7	$	(10.1)

(a) Amount reported as Gross Unrealized Gains includes unrealized gains of $1.5 billion and $1.9 billion and unrealized losses of $6 million and $4 million as of December 31, 2022 and 2021, respectively.

The following table provides the securities activity within the decommissioning and SNF trusts:


	Years Ended December 31,
	2022		2021
	(in millions)
Proceeds from Investment Sales	$	2,713.6	$	1,886.4
Purchases of Investments	2,765.4		1,928.2
Gross Realized Gains on Investment Sales	52.4		103.2
Gross Realized Losses on Investment Sales	42.6		16.5

The base cost of fixed income securities was $1.2 billion and $1.2 billion as of December 31, 2022 and 2021, respectively. The base cost of equity securities was $654 million and $641 million as of December 31, 2022 and 2021, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2022 was as follows:


	Fair Value of Fixed
	Income Securities
	(in millions)
Within 1 year	$	365.2
After 1 year through 5 years	425.4
After 5 years through 10 years	203.0
After 10 years	195.1
Total	$	1,188.7

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, I&M’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.


	December 31, 2022
	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)

Derivative Instrument Assets
Risk Management Commodity Contracts (b) (d)	$	—	$	11.3	$	5.3	$	(1.2)	$	15.4

Other Special Funds
Cash and Cash Equivalents (c)	11.3		—		—		9.9		21.2
Fixed Income Securities:
United States Government	—		1,123.8		—		—		1,123.8
Corporate Debt	—		61.6		—		—		61.6
State and Local Government	—		3.3		—		—		3.3
Subtotal Fixed Income Securities	—		1,188.7		—		—		1,188.7
Equity Securities - Domestic (a)	2,131.3		—		—		—		2,131.3
Total Other Special Funds	2,142.6		1,188.7		—		9.9		3,341.2

Total Assets	$	2,142.6	$	1,200.0	$	5.3	$	8.7	$	3,356.6

Liabilities:

Derivative Instrument Liabilities
Risk Management Commodity Contracts (b) (d)	$	—	$	0.6	$	0.7	$	(1.3)	$	—


	December 31, 2021
	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)

Derivative Instrument Assets
Risk Management Commodity Contracts (b) (d)	$	—	$	3.8	$	7.6	$	(8.1)	$	3.3

Other Special Funds
Cash and Cash Equivalents (c)	77.7		—		—		7.0		84.7
Fixed Income Securities:
United States Government	—		1,156.4		—		—		1,156.4
Corporate Debt	—		76.7		—		—		76.7
State and Local Government	—		7.3		—		—		7.3
Subtotal Fixed Income Securities	—		1,240.4		—		—		1,240.4
Equity Securities - Domestic (a)	2,541.9		—		—		—		2,541.9
Total Other Special Funds	2,619.6		1,240.4		—		7.0		3,867.0

Total Assets	$	2,619.6	$	1,244.2	$	7.6	$	(1.1)	$	3,870.3

Liabilities:

Derivative Instrument Liabilities
Risk Management Commodity Contracts (b) (d)	$	—	$	6.7	$	8.3	$	(10.0)	$	5.0

(a) Amounts represent publicly-traded equity securities and equity-based mutual funds.

(b) 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.”

(c) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.

(d) Substantially comprised of power contracts.

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


	Derivative Instrument
Year Ended December 31, 2022	Assets (Liabilities)
	(in millions)
Balance as of December 31, 2021	$	(0.7)
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)	3.7
Settlements	(3.0)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)	4.6
Balance as of December 31, 2022	$	4.6


	Derivative Instrument
Year Ended December 31, 2021	Assets (Liabilities)
	(in millions)
Balance as of December 31, 2020	$	2.1
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)	(0.1)
Settlements	(2.2)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)	(0.5)
Balance as of December 31, 2021	$	(0.7)

(a) Included in revenues on the 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) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These changes in fair value are recorded as regulatory liabilities for net gains and as regulatory assets for net losses or accounts payable.

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

December 31, 2022

Significant

Input/Range

Fair Value

Valuation

Unobservable

Weighted

Assets

Liabilities

Technique

Input (a)

Low

High

Average (b)

(in millions)

FTRs

$

5.3

$

0.7

Discounted Cash Flow

Forward Market Price

$

0.16

$

18.79

$

1.23


December 31, 2021
						Significant	Input/Range
	Fair Value				Valuation	Unobservable					Weighted
	Assets		Liabilities		Technique	Input (a)	Low		High		Average (b)
	(in millions)
Energy Contracts	$	—	$	0.2	Discounted Cash Flow	Forward Market Price	$	32.20	$	56.54	$	44.77
FTRs	7.6		8.1		Discounted Cash Flow	Forward Market Price	$	(5.45)	$	17.78	$	(0.12)
Total	$	7.6	$	8.3

(a) Represents market prices in dollars per MWh.

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

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

Uncertainty of Fair Value Measurements

Significant Unobservable Input

Position

Change in Input

Impact on Fair Value

Measurement

Forward Market Price

Buy

Increase (Decrease)

Higher (Lower)

Forward Market Price

Sell

Increase (Decrease)

Lower (Higher)

11. INCOME TAXES

Income Tax Expense (Benefit)

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


		Years Ended December 31,
		2022			2021
		(in millions)
Charged (Credited) to Operating Expenses, Net:
	Current	$	55.0		$	31.3
	Deferred			(52.3)			(35.0)
Total				2.7			(3.7)

Charged (Credited) to Nonoperating Income, Net:
	Current			(0.5)			(4.4)
	Deferred			1.7			(3.1)
Total				1.2			(7.5)
Total Income Tax Expense (Benefit)		$	3.9		$	(11.2)

The following is a reconciliation of the difference between the amounts of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported:


	Years Ended December 31,
	2022			2021
	(in millions)
Net Income	$	324.7		$	279.8
Income Tax Expense (Benefit)	3.9			(11.2)
Pretax Income	$	328.6		$	268.6

Income Taxes on Pretax Income at Statutory Rate (21%)	$	69.0		$	56.4
Increase (Decrease) in Income Taxes Resulting from the Following Items:
Reversal of Origination Flow-Through			2.9			3.5
Investment Tax Credit Amortization			(3.1)			(6.4)
State and Local Income Taxes, Net			9.6			(0.8)
Removal Costs			(12.4)			(9.7)
AFUDC			(2.0)			(2.7)
Parent Company Loss Benefit			—			(2.8)
Tax Reform Excess ADIT Reversal			(54.0)			(46.3)
Federal Return-to-Provision			(6.3)			(0.6)
Other			0.2			(1.8)
Income Tax Expense (Benefit)	$	3.9		$	(11.2)

Effective Income Tax Rate	1.2%			(4.2)%

Net Deferred Tax Liability

The following table shows elements of I&M’s net deferred tax assets (liabilities) and significant temporary differences:


	December 31,
	2022		2021
	(in millions)
Deferred Tax Assets	$	933.5	$	1,071.5
Deferred Tax Liabilities	(2,090.7)		(2,172.3)
Net Deferred Tax Liabilities	$	(1,157.2)	$	(1,100.8)

Property Related Temporary Differences	$	(398.0)	$	(305.8)
Amounts Due to Customers for Future Federal Income Taxes	114.3		135.5
Deferred State Income Taxes	(227.0)		(221.9)
Accrued Nuclear Decommissioning	(632.7)		(743.2)
Regulatory Assets	(29.5)		(23.6)
Operating Lease Liability	13.6		13.5
All Other, Net	2.1		44.7
Net Deferred Tax Liabilities	$	(1,157.2)	$	(1,100.8)

Tax Credit Carryforward

As of December 31, 2022, I&M has federal tax credit carryforwards in the amount of $11 million. If these credits are not utilized, federal general business tax credits will expire in the years 2036 through 2041. I&M anticipates future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused.

Federal and State Income Tax Audit Status

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

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

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

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 (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, I&M 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. I&M’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 I&M can begin to rely on in 2023 and also stated that additional guidance is expected, of which I&M 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 I&M’s potential CAMT exposure.

The enactment of the IRA will have future cash flow and income tax reporting considerations. I&M 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. I&M 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 changes the state income tax apportionment formula from a ratio that includes property, payroll and sales to a single sales factor apportionment regime effective for tax years beginning on or after January 1, 2022. HB 2026 also eliminates the “throw out” rule related to sales of tangible personal property for sales factor apportionment calculation purposes and introduces a market-based sourcing for sales of services and intangible property. During 2021, AEP recorded

$23 million in Income Tax Expense as a result of remeasuring West Virginia deferred taxes under the new apportionment methodology.

12. LEASES

I&M 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. I&M 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 I&M will exercise the option.

Lease obligations are measured using the discount rate implicit in the lease when that rate is readily determinable. AEP 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, I&M 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 Expense and Maintenance Expense 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,
	2022		2021
	(in millions)
Operating Lease Cost	$	29.5	$	90.2
Finance Lease Cost:
Amortization of Right-of-Use Assets	159.8		98.1
Interest on Lease Liabilities	6.2		4.4
Total Lease Rental Costs (a)	$	195.5	$	192.7

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

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


	December 31,
	2022		2021
	(in millions)
Weighted-Average Remaining Lease Term (years):
Operating Leases	5.79		5.87
Finance Leases	4.76		2.10
Weighted-Average Discount Rate:
Operating Leases	3.62	%	3.46	%
Finance Leases	8.99	%	3.02	%


	Years Ended December 31,
	2022		2021
	(in millions)
Cash paid for amounts included in the measurement of lease liabilities:
Operating Cash Flows from Operating Leases	$	29.7	$	92.9
Operating Cash Flows from Finance Leases	218.1		100.6

Non-cash Acquisitions Under Operating Leases	$	19.1	$	2.6

The following tables show property, plant and equipment under finance leases, operating leases and related obligations recorded on I&M’s balance sheets:


	December 31,
	2022		2021
	(in millions)
Property, Plant and Equipment Under Finance Leases:
Utility Plant (a)	$	33.7	$	160.6
Nuclear Fuel Under Finance Leases (b)	179.1		118.6
Net Property, Plant and Equipment Under Finance Leases	$	212.8	$	279.2

Obligations Under Finance Leases:
Noncurrent	$	121.2	$	88.9
Current	92.0		192.0
Total Obligations Under Finance Leases	$	213.2	$	280.9

(a) Includes $35 million and $38 million of accumulated provision for depreciation and amortization for the years ended December 31, 2022 and 2021, respectively.

(b) Includes $221 million and $264 million of accumulated provision for depreciation and amortization for the years ended December 31, 2022 and 2021, respectively.


	December 31,
	2022		2021
	(in millions)
Property, Plant and Equipment Under Operating Leases:
Utility Plant (a)	$	39.3	$	42.1
Nonutility Plant	33.2		43.2
Accumulated Provision for Depreciation and Amortization - Nonutility Plant	(8.2)		(21.9)
Net Property, Plant and Equipment Under Operating Leases	$	64.3	$	63.4

Obligations Under Operating Leases:
Noncurrent	$	48.9	$	48.9
Current	16.0		15.5
Total Obligations Under Operating Leases	$	64.9	$	64.4

(a) Includes $25 million and $18 million of accumulated provision for depreciation and amortization for the years ended December 31, 2022 and 2021, respectively.

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


	Finance Leases		Operating Leases
	(in millions)
2023	$	104.8	$	18.8
2024	69.0		17.7
2025	37.5		9.2
2026	12.7		8.3
2027	5.1		7.5
After 2027	7.6		9.8
Total Future Minimum Lease Payments	236.7		71.3
Less: Imputed Interest	23.5		6.4
Estimated Present Value of Future Minimum Lease Payments	$	213.2	$	64.9

Master Lease Agreements

I&M leases certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of 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, I&M 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, 2021, the maximum potential loss by I&M for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was $4 million.

Lessor Activity

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

Nuclear Fuel Lease

In November 2017, I&M entered into a sale-and-leaseback transaction for $70 million with DCC Fuel XI LLC (DCC XI). DCC XI is a single-lessee leasing arrangement with one asset and was formed for the sole purpose of acquiring, owning and leasing nuclear fuel to I&M. The lease had a variable rate and was a finance lease with a term of 52 months. I&M made payments on the lease monthly. I&M made the final payment in March 2022.

In May 2018, I&M entered into a sale-and-leaseback transaction for $56 million with DCC Fuel XII LLC (DCC XII). DCC XII is a single-lessee leasing arrangement with one asset and was formed for the sole purpose of acquiring, owning and leasing nuclear fuel to I&M. The lease had a variable rate and was a finance lease with a term of 52 months. I&M made payments on the lease monthly. I&M made the final payment in September 2022.

In May 2019, I&M entered into a sale-and-leaseback transaction for $63 million with DCC Fuel XIII LLC (DCC XIII). DCC XIII is a single-lessee leasing arrangement with one asset and was formed for the sole purpose of acquiring, owning and leasing nuclear fuel to I&M. The lease has a variable rate and is a finance lease with a term of 54 months. I&M makes payments on the lease monthly. Payments began in June 2019.

In November 2019, I&M entered into a sale-and-leaseback transaction for $61 million with DCC Fuel XIV LLC (DCC XIV). DCC XIV is a single-lessee leasing arrangement with one asset and was formed for the sole purpose of acquiring, owning and leasing nuclear fuel to I&M. The lease has a variable rate and is a finance lease with a term of 54 months. I&M makes payments on the lease monthly. Payments began in December 2019.

In October 2020, I&M entered into a sale-and-leaseback transaction for $70 million with DCC Fuel XV LLC (DCC XV). DCC XV is a single-lessee leasing arrangement with one asset and was formed for the sole purpose of acquiring, owning and leasing nuclear fuel to I&M. The lease has a variable rate and is a finance lease with a term of 54 months. I&M makes payments on the lease monthly. Payments began in November 2020.

In May 2021, I&M entered into a sale-and-leaseback transaction for $65 million with DCC Fuel XVI LLC (DCC XVI). DCC XVI is a single-lessee leasing arrangement with one asset and was formed for the sole purpose of acquiring, owning and leasing nuclear fuel to I&M. The lease has a fixed 0.93% rate and is a finance lease with a term of 54 months. I&M makes payments on the lease monthly. Payments began in June 2021.

In May 2022, I&M entered into a sale-and-leaseback transaction for $73 million with DCC Fuel XVII LLC (DCC XVII). DCC XVII is a single-lessee leasing arrangement with one asset and was formed for the sole purpose of acquiring, owning and leasing nuclear fuel to I&M. The lease has a fixed 3.44% rate and is a finance lease with a term of 54 months. I&M makes payments on the lease monthly. Payments began in June 2022.

In November 2022, I&M entered into a sale-and-leaseback transaction for $70 million with DCC Fuel XVIII LLC (DCC XVIII). DCC XVIII is a single-lessee leasing arrangement with one asset and was formed for the sole purpose of acquiring, owning and leasing nuclear fuel to I&M. The lease has a fixed 5.93% rate and is a finance lease with a term of 54 months. I&M makes payments on the lease monthly. Payments began in December 2022.

13. FINANCING ACTIVITIES

Long-term Debt

The following table details long-term debt outstanding:


		Weighted-Average	Interest Rate Ranges as of		Outstanding as of
		Interest Rate as of	December 31,		December 31,
Company	Maturity	December 31, 2022	2022	2021	2022		2021


I&M
Senior Unsecured Notes	2023-2051	4.19%	3.20%-6.05%	3.20%-6.05%	$	2,625.0	$	2,625.0
Pollution Control Bonds (a)	2025 (b)	2.49%	0.75%-3.05%	0.75%-3.05%	190.0		190.0
Spent Nuclear Fuel Obligation (c)					285.6		281.3
Other Long-term Debt	2025	6.00%	6.00%	6.00%	5.0		7.3
Unamortized Discount, Net					(10.1)		(10.7)
Total Long-term Debt Outstanding					$	3,095.5	$	3,092.9

(a) For certain series of Pollution Control Bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets.

(b) Certain Pollution Control Bonds are subject to redemption earlier than the maturity date.

(c) Spent Nuclear Fuel Obligation consists of a liability along with accrued interest for disposal of SNF. See “Spent Nuclear Fuel Disposal” section of Note 6 for additional information.

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


	(in millions)
2023	$	252.2
2024	2.5
2025	190.3
2026	—
2027	—
After 2027	2,660.6
Principal Amount	3,105.6
Unamortized Discount, Net	(10.1)
Total Long-term Debt	$	3,095.5

Dividend Restrictions

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

All of the dividends declared by I&M 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. The Federal Power Act also creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to I&M.

I&M has credit agreements that contain covenants that limit their debt to capitalization ratio to 67.5%. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements.

The most restrictive dividend limitation for I&M is through the credit agreements. As of December 31, 2022, the maximum amount of restricted net assets of I&M that may not be distributed to the Parent in the form of a loan, advance or dividend was $1.7 billion.

The Federal Power Act restriction limits the ability of I&M to pay dividends out of retained earnings because of their ownership in hydroelectric generation. Additionally, the credit agreement covenant restrictions can limit the ability of I&M to pay dividends out of retained earnings. As of December 31, 2022, the amount of any such restrictions was $688 million.

Corporate Borrowing Program – AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of its agreement filed with the FERC. The amounts of borrowings from the Utility Money Pool as of December 31, 2022 and 2021 are included in Notes Payable to Associated Companies on the balance sheets. I&M’s 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 to the		from the		Loans to the		the Utility Money		Short-term
Years ended	Utility		Utility		Utility		Utility		Pool as of		Borrowing
December 31,	Money Pool		Money Pool		Money Pool		Money Pool		December 31,		Limit
	(in millions)
2022	$	318.6	$	—	$	105.2	$	—	$	249.9	$	500.0
2021	166.5		354.8		110.4		96.2		93.3		500.0

The 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 Rates		Interest Rates		Interest Rates		Interest Rates		Interest Rates		Interest Rates
	for Funds		for Funds		for Funds		for Funds		for Funds		for Funds
	Borrowed from		Borrowed from		Loaned to		Loaned to		Borrowed from		Loaned to
Years ended	the Utility		the Utility		the Utility		the Utility		the Utility		the Utility
December 31,	Money Pool		Money Pool		Money Pool		Money Pool		Money Pool		Money Pool
	(in millions)
2022	5.28	%	0.10	%	—	%	—	%	2.57	%	—	%
2021	0.48	%	0.04	%	0.39	%	0.02	%	0.33	%	0.23	%

Interest expense and interest income related to the Utility Money Pool financing relationship are included in Interest on Debt to Associated Companies and Interest and Dividend Income, respectively, on the statements of income. The interest expense related to the corporate borrowing programs was $3 million and $200 thousand for the years ended December 31, 2022 and 2021, respectively, and interest income related to the corporate borrowing programs was immaterial for the years ended December 31, 2022 and 2021.

Securitized Accounts Receivables – AEP Credit

Under this sale of receivables arrangement, I&M sells, without recourse, certain of its customer accounts receivable and accrued utility revenue balances to AEP Credit and is charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for I&M’s receivables. The costs of customer accounts receivable sold are reported in Other Deductions on I&M’s statements of income. I&M manages and services its customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for I&M and retains the remainder.

The amount of accounts receivable and accrued utility revenues under the sale of receivables agreement as of December 31, 2022 and 2021 were $167 million and $157 million, respectively.

The fees paid to AEP Credit for customer accounts receivable sold were $10 million and $7 million for the years ended December 31, 2022 and 2021, respectively. In 2021, due to the successful collection of accounts receivable balances during the COVID-19 pandemic, the allowance for doubtful accounts was reduced, resulting in the issuance of credits to offset the higher fees previously paid by I&M and to lower subsequent fees paid.

The proceeds on the sale of receivables to AEP Credit were $2 billion and $1.9 billion for the years ended December 31, 2022 and 2021, respectively.

14. RELATED PARTY TRANSACTIONS

For other related party transactions, also see “AEP System Tax Allocation” section of Note 1 in addition to “Corporate Borrowing Program – AEP System” and “Securitized Accounts Receivables – AEP Credit” sections of Note 13.

Power Coordination Agreement

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

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

System Integration Agreement

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

Affiliated Revenues and Purchases

The following table shows the revenues derived from direct sales to affiliates, auction sales to affiliates, net transmission agreement sales and other revenues for the years ended December 31, 2022 and 2021:


	Years Ended December 31,
Related Party Revenues	2022 (a)		2021 (a)
	(in millions)
Transmission Revenues	$	7.7	$	(2.5)
Other Revenues	7.6		6.3

(a) I&M’s affiliated revenues exclude capacity sales to KPCo from Rockport Plant, Unit 2 and barging, urea transloading and other transportation services to affiliates. See sections “Unit Power Agreements” and “I&M Barging, Urea Transloading and Other Services” below for additional information.

The following table shows the purchased power expenses incurred for purchases from affiliates for the years December 31, 2022 and 2021:


	Years Ended December 31,
Related Party Purchases	2022		2021
	(in millions)
Direct Purchases from AEGCo	$	241.8	$	217.9

PJM Transmission Service Charges

The AEP East Companies are parties to the TA, which defines how transmission costs through the PJM OATT are allocated among the AEP East Companies on a 12-month average coincident peak basis. Additional costs for transmission services provided by AEPTCo and other transmission affiliates are billed to AEP East Companies through the PJM OATT. I&M’s net charges for the years ended December 31, 2022 and 2021 related to the TA were $221 million and $187 million, respectively. The charges were recorded in Operation Expenses on the statements of income.

Joint License Agreement

AEPTCo entered into a 50-year joint license agreement with I&M allowing either party to occupy the granting party’s facilities or real property. After the expiration of the agreement, the term shall automatically renew for successive one-year terms unless either party provides notice. The joint license billing provides compensation to the granting party for the cost of carrying assets, including depreciation expense, property taxes, interest expense, return on equity and income taxes. For the years ended December 31, 2022 and 2021, I&M billed AEPTCo $6 million and $5 million, respectively.

Unit Power Agreements

UPA between AEGCo and I&M

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

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

Prior to the termination of the Rockport Plant, Unit 2 lease, I&M assigned 30% of the power to KPCo. See the “UPA between AEGCo and KPCo” section below for additional information. Beginning December 8, 2022, AEGCo billed 100% of its share of the Rockport Plant to I&M and ceased billing to KPCo. KPCo reached an agreement with I&M, from the end of the lease through May 2024, to buy capacity from Rockport Plant, Unit 2 through the PCA at a rate equal to PJM’s RPM clearing price. I&M’s capacity sales to KPCo were $199 thousand for the year ended December 31, 2022.

UPA between AEGCo and KPCo

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

Cook Coal Terminal

Cook Coal Terminal, which is owned by AEGCo, performs coal transloading and storage services at cost for I&M. The coal transloading costs were $9 million and $11 million for the years ended December 31, 2022 and 2021, respectively. I&M recorded the cost of transloading services in Fuel Stock on the balance sheets.

Cook Coal Terminal also performs railcar maintenance services at cost for I&M. AEGCo billed I&M $609 thousand and $343 thousand for the years ended December 31, 2022 and 2021, respectively, for railcar maintenance services. I&M recorded the cost of the railcar maintenance services in Fuel Stock on the balance sheets.

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. I&M recorded revenues from barging, transloading and other services of $54 million and $54 million for the years ended December 31, 2022 and 2021, respectively, in Revenues from Nonutility Operations on the statements of income.

Sales and Purchases of Property

I&M had affiliated sales and purchases of electric property amounting to $100 thousand or more, sales and purchases of meters and transformers, and sales and purchases of transmission property. There were no gains or

losses recorded on the transactions. The following table shows the sales and purchases, recorded in Utility Plant on the balance sheets at net book value:


	Years Ended December 31,
	2022		2021
	(in millions)
Sales	$	5.3	$	7.0
Purchases	2.0		0.6

AEP Wind Holdings LLC PPAs

Prior to its acquisition, two of the 50% owned joint venture wind farms in the AEP Wind Holdings, LLC portfolio had existing PPAs with I&M, OPCo and SWEPCo. Fowler Ridge 2 has PPAs with I&M and OPCo for a portion of its energy production. The I&M portion totaled $12 million and $10 million for the years ended December 31, 2022 and 2021, respectively.

Intercompany Billings

I&M performs certain utility services for each other 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 I&M. The costs of the services are based on a direct charge or on a prorated basis and billed to I&M at AEPSC’s cost. AEPSC and its billings are subject to regulation by the FERC. I&M’s total billings from AEPSC were $192 million and $201 million for the years ended December 31, 2022 and 2021, respectively.

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, I&M made an $11 million charitable contribution to the AEP Foundation recorded in Donations on the statements of income. In 2021, there were no charitable contributions made to the AEP Foundation..

15. PROPERTY, PLANT AND EQUIPMENT

Depreciation

I&M provides for depreciation of Utility Plant, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. The following table provides total regulated annual composite depreciation rates by functional class:


Year	Nuclear		Steam		Other Generation		Hydro		Transmission		Distribution		General
	(in percentages)
2022	3.8	%	8.7	%	4.8	%	3.5	%	2.5	%	3.1	%	10.1	%
2021	3.5	%	8.7	%	4.2	%	2.5	%	2.4	%	3.4	%	9.0	%

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

Asset Retirement Obligations

As of December 31, 2022 and 2021, I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $2 billion and $1.93 billion, respectively. These liabilities are reflected in Asset Retirement Obligations on I&M’s balance sheets. As of December 31, 2022 and 2021, the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $3.01 billion and $3.54 billion, respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s balance sheets. In December 2021, I&M recorded a $58 million revision for Cook Plant as a result of the latest decommissioning cost study. The ARO liability was updated and changes from the previous study were driven primarily by general increases in the projected cost of labor and materials.

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


Year	ARO at January 1,		Accretion Expense		Liabilities Incurred		Liabilities Settled		Revisions in Cash Flow Estimates		ARO at December 31,
	(in millions)
2022	$	1,946.3	$	71.5	$	3.2	$	(0.6)	$	7.7	$	2,028.1
2021	1,813.8		72.9		0.3		(0.1)		59.4		1,946.3

Jointly-owned Electric Facilities

I&M has electric facilities that are jointly-owned with affiliated companies. Using its own financing, I&M is obligated to pay its share of the costs of these jointly-owned facilities in the same proportion as its ownership interest. I&M’s proportionate share of the operating costs associated with these facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Utility Plant as follows:


				Share as of December 31, 2022
	Fuel Type	Percent of Ownership		Utility Plant in Service		Construction Work in Progress		Accumulated Depreciation
				(in millions)

Rockport Generating Plant (a)(b)(c)	Coal	50.0	%	$	1,357.4	$	9.2	$	905.1


				Share as of December 31, 2021
	Fuel Type	Percent of Ownership		Utility Plant in Service		Construction Work in Progress		Accumulated Depreciation
				(in millions)

Rockport Generating Plant (a)(b)(c)	Coal	50.0	%	$	1,247.2	$	13.9	$	794.5

(a) Operated by I&M.

(b) Amounts include I&M's 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 was subject to a finance lease with a nonaffiliated company. In December 2022, the lease expired at which point I&M and AEGCo acquired 100% of the interests in Unit 2. See the "Rockport Plant Litigation" section of Note 6 for additional information.

(c) AEGCo owns 50%.

16. REVENUE FROM CONTRACTS WITH CUSTOMERS

Disaggregated Revenues from Contracts with Customers

The table below represents revenues from contracts with customers, net of respective provisions for refund, by type of revenue for I&M.


	Years Ended December 31,
	2022		2021
	(in millions)
Retail Revenues:
Residential Revenues	$	862.7	$	812.1
Commercial Revenues	562.0		512.6
Industrial Revenues	622.8		565.3
Other Retail Revenues	5.0		5.2
Total Retail Revenues	$	2,052.5	$	1,895.2

Wholesale Revenues:
Generation Revenues	540.7		348.8
Transmission Revenues (a)	36.8		33.7
Total Wholesale Revenues	577.5		382.5

Other Revenues from Contracts with Customers (a)	43.9		45.4

Total Revenues from Contracts with Customers	2,673.9		2,323.1

Other Revenues:
Alternative Revenues	10.0		(4.0)
Other Revenues	0.1		0.1
Total Other Revenues	10.1		(3.9)

Total Operating Revenues	$	2,684.0	$	2,319.2

(a) Amounts include affiliated and nonaffiliated revenues.

Performance Obligations

I&M 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. I&M 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 I&M are summarized as follows:

Retail Revenues

I&M 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 I&M 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

I&M 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.

I&M also has performance obligations to stand ready in order to promote grid reliability. Stand ready services are sold into PJM’s 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 and vary by state, where the revenues are reflected gross in the disaggregated revenues table above.

Wholesale Revenues - Transmission

I&M has performance obligations to transmit electricity to wholesale customers through assets owned and operated. 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.

I&M collects revenues through transmission formula rates. The FERC-approved rates establish the annual transmission revenue requirement (ATRR) and transmission service rates for transmission owners. The formula rates establish rates for a one year period and also include a true-up calculation for the prior year’s billings, allowing for over/under-recovery of the transmission owner’s ATRR. The annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for “Regulated Operations,” and are therefore presented as such in the disaggregated revenues table above.

The AEP East Companies are parties to the TA, which defines how transmission costs are allocated among the AEP East Companies on a 12-month average coincident peak basis. Affiliate revenues as a result of the TA is reflected as Transmission Revenues in the disaggregated revenues table above.

Fixed Performance Obligations

The following table represents the 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. I&M 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. I&M amounts shown in the table below include affiliated and nonaffiliated revenues.


2023		2024-2025		2026-2027		After 2027		Total
(in millions)
$	4.6	$	9.2	$	9.2	$	4.5	$	27.5

Contract Assets and Liabilities

Contract assets are recognized when I&M 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. I&M did not have any material contract assets as of December 31, 2022 and 2021.

When I&M 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 sheets 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. I&M’s contract liabilities typically arise from services provided under joint use agreements for utility poles. I&M did not have any 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 I&M’s balance sheets within the Customer Accounts Receivable line item. I&M’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. See “Securitized Accounts Receivable - AEP Credit” section of Note 13 for additional information.

The amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable from Associated Companies on I&M’s balance sheets were $75 million and $61 million, as of December 31, 2022 and 2021.

Contract Costs

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

17. FERC ORDER NO. 784-A

On July 18, 2013, the FERC issued Order No. 784 that revised certain aspects of the accounting and reporting requirements under the Uniform System of Accounts related to energy storage accounts. Due to software limitations, the newly adopted and revised schedules in the FERC forms that would contain the energy storage accounts are not available to filers of the forms for use as of the effective date. Utilities with energy storage assets must use the existing schedules in the FERC Forms to report energy storage assets pending availability of the new and revised schedules. FERC directed filers to submit the requested energy storage information as part of pages 122-123.

The following table presents I&M’s energy storage operations for small plants for the years ended December 31, 2022 and 2021, as required by FERC Order No. 784:


						Operation			Maintenance
Project	Functional	Project	Project Costs			Expenses			Expenses
Name	Classification	Location	Account	Amount		Account	Amount		Account	Amount (a)
			(dollars in millions)
Year Ended December 31, 2022
East Busco Station	Distribution	Churubusco, IN	363	$	5.6	562	$	—	592	$	—

Year Ended December 31, 2021
East Busco Station	Distribution	Churubusco, IN	363	$	5.6	562	$	—	592	$	—

(a) This amount would have been recorded in Account 592.2 in accordance with FERC Order No. 784.

Name of Respondent:

Indiana Michigan 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				1,236,357	8,175,099		6,938,742
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income				129,510	1,602,300		1,472,790
3	Preceding Quarter/Year to Date Changes in Fair Value				4,213,806			4,213,806
4	Total (lines 2 and 3)				4,084,296	1,602,300		5,686,596	279,843,643	285,530,239
5	Balance of Account 219 at End of Preceding Quarter/Year				5,320,653	6,572,799		1,252,146
6	Balance of Account 219 at Beginning of Current Year				5,320,653	6,572,799		1,252,146
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income				352,288	1,602,303		1,250,015
8	Current Quarter/Year to Date Changes in Fair Value				285,858			285,858
9	Total (lines 7 and 8)				638,146	1,602,303		964,157	324,720,578	325,684,735
10	Balance of Account 219 at End of Current Quarter/Year				4,682,507	4,970,496		287,989

Name of Respondent:

Indiana Michigan 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)	10,291,642,113	10,291,642,113
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	72,925,316	72,925,316
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified	660,716,303	660,716,303
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	11,025,283,732	11,025,283,732
9	UtilityPlantLeasedToOthers Leased to Others
10	UtilityPlantHeldForFutureUse Held for Future Use	1,320,294	1,320,294
11	ConstructionWorkInProgress Construction Work in Progress	256,648,504	256,648,504
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	11,283,252,530	11,283,252,530
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	4,076,922,613	4,076,922,613
15	UtilityPlantNet Net Utility Plant (13 less 14)	7,206,329,917	7,206,329,917
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	3,835,651,190	3,835,651,190
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	241,266,392	241,266,392
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	4,076,917,582	4,076,917,582
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	5,031	5,031
29	AmortizationUtilityPlantHeldForFutureUse Amortization
30	DepreciationAndAmortizationUtilityPlantHeldForFutureUse Total Held for Future Use (28 & 29)	5,031	5,031
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)	4,076,922,613	4,076,922,613

Name of Respondent:

Indiana Michigan 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	37,327,824	99,692,291		(c) 140,877,643	3,857,528
4	Allowance for Funds Used during Construction	4,061,688	3,025,014		(d) 3,268,067	3,818,635
5	(Other Overhead Construction Costs, provide details in footnote)
6	SUBTOTAL (Total 2 thru 5)	41,389,512				38,893
7	Nuclear Fuel Materials and Assemblies
8	In Stock (120.2)
9	In Reactor (120.3)	1,072,702	143,272,517		(e) 142,700,000	1,645,219
10	SUBTOTAL (Total 8 & 9)	1,072,702				1,645,219
11	Spent Nuclear Fuel (120.4)	(a) 605,712,062	(b) 125,873,193		(f) 102,030,938	(h) 629,554,317
12	Nuclear Fuel Under Capital Leases (120.6)	118,624,550	142,700,000	82,180,562		179,143,988
13	(Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5)	605,718,624		125,743,444	(g) 102,030,938	629,431,130
14	TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13)	161,080,202				180,873,501
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:

Indiana Michigan 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: SpentNuclearFuel

Includes 2021 costs in connection with nuclear leases:

Finance charges - $1,408,148

(b) Concept: SpentNuclearFuelAdditions

Reclassification of $142,700,000 of nuclear fuel from owned to leased due to sale/leaseback with third party

(c) Concept: NuclearMaterialsNuclearFuelInProcessOfRefinementConversionEnrichmentAndFabricationOtherReductions

Placed nuclear fuel into reactor

(d) Concept: AllowanceForFundsConstructionNuclearFuelInProcessOfRefinementConversionEnrichmentAndFabricationOtherReductions

Placed nuclear fuel into reactor

(e) Concept: NuclearFuelAssembliesInReactorOtherReductions

Reclassification of nuclear fuel from owned to leased due to sale/leaseback with third party - $142,700,000

(f) Concept: SpentNuclearFuelOtherReductions

Retirement of spent fuel

(g) Concept: AccumulatedProvisionForAmortizationOfNuclearFuelAssembliesOtherReductions

Retirement of spent fuel

(h) Concept: SpentNuclearFuel

Includes 2022 costs in connection with nuclear leases:

Finance charges - $3,353,036

Name of Respondent:

Indiana Michigan 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	117,425					117,425
3	(302) Franchise and Consents	19,866,098					19,866,098
4	(303) Miscellaneous Intangible Plant	343,210,155	37,458,040	33,371,831			347,296,364
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)	363,193,678	37,458,040	33,371,831			367,279,887
6	2. PRODUCTION PLANT
7	A. Steam Production Plant
8	(310) Land and Land Rights	7,414,505				7,239	7,407,266
9	(311) Structures and Improvements	109,411,888	347,557	140,995		7,239	109,625,689
10	(312) Boiler Plant Equipment	909,386,529	11,904,715	3,452,581			917,838,663
11	(313) Engines and Engine-Driven Generators
12	(314) Turbogenerator Units	122,572,881	4,486,319	5,227,658			121,831,542
13	(315) Accessory Electric Equipment	63,090,216	309,203	80,091			63,319,328
14	(316) Misc. Power Plant Equipment	24,789,472	635,111	31,690			25,392,893
15	(317) Asset Retirement Costs for Steam Production	11,249,431	7,669,372				18,918,803
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)	1,247,914,922	25,352,277	8,933,015			1,264,334,184
17	B. Nuclear Production Plant
18	(320) Land and Land Rights	1,879,588				1	1,879,589
19	(321) Structures and Improvements	456,149,624	12,469,258	6,800,178			461,818,704
20	(322) Reactor Plant Equipment	1,740,051,084	82,173,831	31,939,141			1,790,285,774
21	(323) Turbogenerator Units	707,677,758	15,806,056	5,939,311			717,544,503
22	(324) Accessory Electric Equipment	319,892,647	33,931,245	4,115,921			349,707,971
23	(325) Misc. Power Plant Equipment	272,794,097	35,089,780	15,711,642			292,172,235
24	(326) Asset Retirement Costs for Nuclear Production	496,814,452					496,814,452
25	TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)	3,995,259,250	179,470,170	64,506,193		1	4,110,223,228
26	C. Hydraulic Production Plant
27	(330) Land and Land Rights	706,302					706,302
28	(331) Structures and Improvements	6,026,864	11,461				6,038,325
29	(332) Reservoirs, Dams, and Waterways	25,764,521	14,425	6,850			25,772,096
30	(333) Water Wheels, Turbines, and Generators	16,386,498	235,784	5,409			16,616,873
31	(334) Accessory Electric Equipment	5,700,261	36,351	13,636			5,722,976
32	(335) Misc. Power Plant Equipment	2,834,929	7,690				2,842,619
33	(336) Roads, Railroads, and Bridges	853					853
34	(337) Asset Retirement Costs for Hydraulic Production	318,520					318,520
35	TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)	57,738,748	305,711	25,895			58,018,564
36	D. Other Production Plant
37	(340) Land and Land Rights	5,311,684					5,311,684
38	(341) Structures and Improvements	734,924					734,924
39	(342) Fuel Holders, Products, and Accessories
40	(343) Prime Movers
41	(344) Generators	62,961,954	314,483				62,647,471
42	(345) Accessory Electric Equipment	4,973,370	143,024				5,116,394
43	(346) Misc. Power Plant Equipment	789,416	7,528				796,944
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)	74,771,348	163,931				74,607,417
46	TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)	5,375,684,268	204,964,227	73,465,103		1	5,507,183,393
47	3. Transmission Plant
48	(350) Land and Land Rights	79,542,097	1,372,869	451,720		336,484	80,126,762
48.1	(351) Energy Storage Equipment - Transmission
49	(352) Structures and Improvements	77,357,371	5,058,369	249,328		848,919	81,317,493
50	(353) Station Equipment	850,071,368	25,608,740	6,055,496		1,315	869,625,927
51	(354) Towers and Fixtures	229,540,284	2,554,890	633,655			231,461,519
52	(355) Poles and Fixtures	232,219,324	17,278,960	3,210,403		4,354	246,283,527
53	(356) Overhead Conductors and Devices	307,467,780	10,825,468	2,803,686		4,354	315,493,916
54	(357) Underground Conduit	2,241,687	7,059,663				9,301,350
55	(358) Underground Conductors and Devices	4,407,311	3,878,045	3,606			8,281,750
56	(359) Roads and Trails	91,159					91,159
57	(359.1) Asset Retirement Costs for Transmission Plant
58	TOTAL Transmission Plant (Enter Total of lines 48 thru 57)	1,782,938,381	73,637,004	13,407,894		1,184,088	1,841,983,403
59	4. Distribution Plant
60	(360) Land and Land Rights	30,440,807	1,618,961	13,907		64,156	32,110,017
61	(361) Structures and Improvements	44,621,267	10,845,663	295,994			55,170,936
62	(362) Station Equipment	510,361,137	33,839,711	6,886,849		1,315	537,312,684
63	(363) Energy Storage Equipment – Distribution	5,606,730					5,606,730
64	(364) Poles, Towers, and Fixtures	362,246,592	31,183,419	3,774,784			389,655,227
65	(365) Overhead Conductors and Devices	588,305,398	58,236,849	6,778,233			639,764,014
66	(366) Underground Conduit	170,033,068	15,225,112	354,233			184,903,947
67	(367) Underground Conductors and Devices	304,863,444	18,825,172	1,910,020			321,778,596
68	(368) Line Transformers	384,484,407	29,675,706	6,545,032			407,615,081
69	(369) Services	210,179,636	13,241,198	1,064,895			222,355,939
70	(370) Meters	134,087,429	48,666,468	20,801,996			161,951,901
71	(371) Installations on Customer Premises	29,903,959	2,073,158	705,524			31,271,593
72	(372) Leased Property on Customer Premises
73	(373) Street Lighting and Signal Systems	24,773,229	8,095,795	822,322			32,046,702
74	(374) Asset Retirement Costs for Distribution Plant		2,968,296				2,968,296
75	TOTAL Distribution Plant (Enter Total of lines 60 thru 74)	2,799,907,103	274,495,508	49,953,789		62,841	3,024,511,663
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	12,233,039	2,276,531	26,255			14,483,315
87	(390) Structures and Improvements	72,039,966	11,356,360	1,654,371		32,158	81,774,113
88	(391) Office Furniture and Equipment	5,806,195	1,184	103,997			5,703,382
89	(392) Transportation Equipment	68,000	4,626				72,626
90	(393) Stores Equipment	1,025,759	366,119	20,231			1,371,647
91	(394) Tools, Shop and Garage Equipment	18,801,170	1,588,402	1,204,396			19,185,176
92	(395) Laboratory Equipment	240,988	114,874	6,262			349,600
93	(396) Power Operated Equipment	543,715					543,715
94	(397) Communication Equipment	68,577,550	5,036,897	104,849			73,509,598
95	(398) Miscellaneous Equipment	11,131,517	820,023			1,147,002	13,098,542
96	SUBTOTAL (Enter Total of lines 86 thru 95)	190,467,899	21,565,016	3,120,361		1,179,160	210,091,714
97	(399) Other Tangible Property
98	(399.1) Asset Retirement Costs for General Plant	1,033,595	274,761				1,308,356
99	TOTAL General Plant (Enter Total of lines 96, 97, and 98)	191,501,494	21,839,777	3,120,361		1,179,160	211,400,070
100	TOTAL (Accounts 101 and 106)	10,513,224,924	612,394,556	173,318,978		57,914	10,952,358,416
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)	10,513,224,924	612,394,556	173,318,978		57,914	10,952,358,416

Name of Respondent:

Indiana Michigan 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:

Indiana Michigan 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	Rockport Generating Plant Unit 1 (0111)	11/01/1984		1,034,109.00
3	Items under $250,000			280,262.00
21	Other Property:
22	Items under $250,000			5,923.00
47	TOTAL			1,320,294

Name of Respondent:

Indiana Michigan 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	ADMS Imp DSN DNEX-IM D	1,909,655
2	Ameriplex - Land purchase	1,266,256
3	Blaine Street T#5 Replacement	6,284,715
4	Business LAN Expansion	9,421,176
5	CIS-Common Deployment-IM D	2,947,088
6	Corp Prgrm Billing - I&M Trans	1,438,866
7	D/IM/Capital Blanket - IMPCo	2,564,770
8	Distributino CI	1,352,423
9	Ed-Ci-Impco-D Ast Imp	14,368,221
10	Ed-Ci-Impco-D Cust Serv	3,104,327
11	FW AMI VVO Circuits / Stations	6,165,007
12	GLBU 120 OpCo CI	2,026,419
13	GLBU 170 OperCo CI	3,599,738
14	I&M - Distribution	1,595,610
15	I&M IN Major Eq/Spare -Trans	1,213,317
16	I&M IN Major Eq/Spares- Distr	5,685,188
17	I&M D Supplemental Work	2,677,116
18	I&M Distribution (170) CI	2,504,153
19	I&M Failure - Distribution CI	1,325,707
20	I&M Failure Distribution	1,186,946
21	I&M Grid Modernization CTS IN	1,471,079
22	I&M Grid Modernization DACR IN	2,088,212
23	I&M Grid Modernization RCS IN	1,222,741
24	I&M OPCo D Supplemental	1,499,407
25	I&M T-OPCO	5,862,110
26	I&M Transmission Supplemental	1,576,993
27	I&M Transmission Work	6,695,597
28	I&M-D Service Restoration Blkt	1,470,073
29	I&M-T-BlnktProj Under $3M	8,052,376
30	IM Distr Work	3,664,744
31	IM Trans Work	9,918,110
32	IM/Crystal 12kV CB addition	1,099,962
33	IM/IN Ameriplex new station	2,157,747
34	IMPCo Trans Pre Eng Parent 1	3,652,156
35	IMPCo Trans Pre Eng Parent 2	2,948,056
36	IMPCO-D Telecom	2,502,780
37	MI AMI VVO Circuits / Stations	1,916,536
38	Michigan Roadside Relocate	2,721,785
39	OPCo CI 1	1,382,901
40	OPCo CI 2	6,565,016
41	OPCo D CI 1	1,085,636
42	OPCo D CI 2	1,595,885
43	OPCo D CI 3	1,707,207
44	OPCo T CI 1	1,628,188
45	OPCo T CI 2	2,515,479
46	OPCo T Supplemental CI	1,896,258
47	REP IN 3PH OH Rebuild	1,600,309
48	REP IN Circuit Ties	1,069,865
49	REP IN Cutouts, LAs	1,260,447
50	REP IN UG Cable Replacement	1,175,405
51	RK U0 CCR Compliance	2,908,515
52	RKP05CIIM Horiz RH ReplaceU1	2,993,948
53	RP-CI-IMPCo-G NMIB	7,030,625
54	RV Capital Station Opco	1,828,055
55	South Bend SC (New)	10,460,049
56	SPILLWAY CUT OFF WALL	3,429,936
57	SS-CI-IMPCo-D GEN PLT	6,360,077
58	Supplemental - Opco Work	2,051,881
59	Supplemental OPCo T work	1,135,500
60	T/IM/Capital Blanket - IMPCo	2,215,963
61	T/IM/Jefferson-Dumont Spacers	2,517,819
62	T/IM/Transmission Line Rebuild	4,307,517
63	Three M Station Rebuild	2,192,909
64	WS-CI-IMPCo-G PPB	5,690,691
65	Other Minor Projects Under $1,000,000	44,885,261
43	Total	256,648,504

Name of Respondent:

Indiana Michigan 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	3,606,230,505	3,606,225,578	4,927
2	Depreciation Provisions for Year, Charged to
3	DepreciationExpenseExcludingAdjustments (403) Depreciation Expense	398,416,876	398,416,772	104
4	DepreciationExpenseForAssetRetirementCosts (403.1) Depreciation Expense for Asset Retirement Costs	4,284,998	4,284,998
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):	22,361,589	(a) 22,361,589
10	DepreciationProvision TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)	425,063,463	425,063,359	104
11	Net Charges for Plant Retired:
12	BookCostOfRetiredPlant Book Cost of Plant Retired	138,248,303	138,248,303
13	CostOfRemovalOfPlant Cost of Removal	66,904,257	(b) 66,904,257
14	SalvageValueOfRetiredPlant Salvage (Credit)	13,275,248	(c) 13,275,248
15	NetChargesForRetiredPlant TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)	191,877,312	191,877,312
16	OtherAdjustmentsToAccumulatedDepreciation Other Debit or Cr. Items (Describe, details in footnote):
17.1	Other Debit or Cr. Items (Describe, details in footnote):	3,760,435	(d) 3,760,435
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)	3,835,656,221	3,835,651,190	5,031
Section B. Balances at End of Year According to Functional Classification
20	AccumulatedDepreciationSteamProduction Steam Production	674,884,547	674,884,547
21	AccumulatedDepreciationNuclearProduction Nuclear Production	1,810,247,602	1,810,247,602
22	AccumulatedDepreciationHydraulicProductionConventional Hydraulic Production-Conventional	37,179,694	37,179,694
23	AccumulatedDepreciationHydraulicProductionPumpedStorage Hydraulic Production-Pumped Storage
24	AccumulatedDepreciationOtherProduction Other Production	13,597,994	13,597,994
25	AccumulatedDepreciationTransmission Transmission	476,952,039	476,947,008	5,031
26	AccumulatedDepreciationDistribution Distribution	779,464,365	779,464,365
27	AccumulatedDepreciationRegionalTransmissionAndMarketOperation Regional Transmission and Market Operation
28	AccumulatedDepreciationGeneral General	43,329,980	43,329,980
29	AccumulatedProvisionForDepreciationOfElectricUtilityPlant TOTAL (Enter Total of lines 20 thru 28)	3,835,656,221	3,835,651,190	5,031

FOOTNOTE DATA

(a) Concept: OtherAccounts


Amortization of the Cook ARO			$ 23,611,555
Revised items due to IURC Final Order in I&M's Base Case Cause No. 44967			$ (442,916)
Amortize Indiana jurisdiction LCM deferred balances for carrying charges, depreciation, and property tax over a six year period as approved by the IURC in Cause No. 44182 LCM1 and amortize over recovery of all costs from Jul17-Jun18			$ (746,885)
Over/under recovery of the payments to the Michigan Energy Optimization Program administrator and associated carrying charges			$20,192
Amortization per MPSC Order in I&M Base Case No. U-18370			$ (167,049)
Record over/under recovery of the I&M South Bend Solar Project			$ (234,186)
ARO depr exp 1080013			$ 320,878
Total			$ 22,361,589

(b) Concept: CostOfRemovalOfPlant

Includes $25,686,791 of removal cost in retirement work in progress (RWIP).

(c) Concept: SalvageValueOfRetiredPlant

Includes ($6,613,531) of salvage in retirement work in progress (RWIP).

(d) Concept: OtherAdjustmentsToAccumulatedDepreciation


To amortize the deferred incremental depreciation expense for the MI portion of Rockport Unit 2 through December 2028 as a result of the pending purchase of Rockport Unit 2, aligning both the GAAP and regulatory depreciable lives through Dec. 2028.			$ (3,207,394)
Defer ARO Deprec & Accretion Exp			$ (553,041)
TOTAL			$ (3,760,435)

Name of Respondent:

Indiana Michigan 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	Blackhawk Coal Company, Inc.	09/01/1980
2	Common Stock			25,324,000		1	25,324,001
3	Cash Capital Contribution
4	Equity in Earnings			2,703,331	287,187		2,416,144
5	Investment in Subsidiary AOCI
6	Subtotal
7	Price River Coal Company, Inc.	12/01/1965
8	Common Stock - Price River			27,275		27,275
42	Total Cost of Account 123.1 $		Total	22,647,944	287,187	27,274	22,907,857

Name of Respondent:

Indiana Michigan 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)	53,538,758	44,879,566	Electric
2	Fuel Stock Expenses Undistributed (Account 152)	3,254,610	1,646,495	Electric
3	Residuals and Extracted Products (Account 153)
4	Plant Materials and Operating Supplies (Account 154)
5	Assigned to - Construction (Estimated)	94,708,498	105,669,615	Electric
6	Assigned to - Operations and Maintenance
7	Production Plant (Estimated)	76,089,960	78,882,130	Electric
8	Transmission Plant (Estimated)	1,124,908	275,977	Electric
9	Distribution Plant (Estimated)	849,125	860,872	Electric
10	Regional Transmission and Market Operation Plant (Estimated)
11	Assigned to - Other (provide details in footnote)	(a) 596,193	(b) 590,627	Electric
12	TOTAL Account 154 (Enter Total of lines 5 thru 11)	173,368,683	186,279,221
13	Merchandise (Account 155)
14	Other Materials and Supplies (Account 156)	1,510,191	1,667,521	River Transport
15	Nuclear Materials Held for Sale (Account 157) (Not applic to Gas Util)
16	Stores Expense Undistributed (Account 163)		1
17
18
19
20	TOTAL Materials and Supplies	231,672,242	234,472,803

Name of Respondent:

Indiana Michigan 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:

Indiana Michigan 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	536,379	25,599,004	107,267		115,572		80,899		2,109,557		2,949,674	25,599,004
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)	812								81,376		82,188
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	6,534	212,944									6,534	212,944
19	Other:
20	Allowances Used
20.1	Allowances Used
21	Cost of Sales/Transfers:
22	Consent Decree Surrenders			74,766								74,766
23
24
25
26
27
28	Total			74,766								74,766
29	Balance-End of Year	530,657	25,386,061	32,501		115,572		80,899		2,190,933		2,950,562	25,386,061
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	357		357		357		357		56,556		57,984
37	Add: Withheld by EPA									714		714
38	Deduct: Returned by EPA
39	Cost of Sales	357								357		714
40	Balance-End of Year			357		357		357		56,913		57,984
41
42	Sales
43	Net Sales Proceeds (Assoc. Co.)
44	Net Sales Proceeds (Other)
45	Gains
46	Losses

Name of Respondent:

Indiana Michigan 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	82,836	2,408	16,711		19,337						118,884	2,408
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)	484										484
5	Returned by EPA
6
7
8	Purchases/Transfers:
9
10
11
12
13
14
15	Total
16
17	Relinquished During Year:
18	Charges to Account 509	2,126										2,126
19	Other:
20	Allowances Used
20.1	Allowances Used
21	Cost of Sales/Transfers:
22	Wolverine Power Supply Cooperative, Inc.
23	Surrenders
24	Consent Decree Surrenders
25	Unknown
26	Other
27
28	Total
29	Balance-End of Year	81,194	2,408	16,711		19,337						117,242	2,408
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:

Indiana Michigan 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:

Indiana Michigan 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:

Indiana Michigan 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	AC2-080	777	186
3	AE1-113	10,297	186	10,297	186
4	AF1-071	249	186	249	186
5	AF1-084	2,451	186	2,092	186
6	AF1-091	20,147	186	17,639	186
7	AF1-092	1,336	186	1,202	186
8	AF1-141	3,585	186	1,935	186
9	AF1-148	9,826	186	9,826	186
10	AF1-161	2,754	186	168	186
11	AF1-176	579	186	608	186
12	AF1-202	10,917	186	9,134	186
13	AF1-204	1,811	186	1,965	186
14	AF1-207	697	186	697	186
15	AF1-215	25,555	186	25,384	186
16	AF1-223	290	186	290	186
17	AF1-268	642	186	719	186
18	AF1-322	492	186	521	186
19	AF2-008	1,055	186
20	AF2-083	3,176	186
21	AF2-094	168	186	455	186
22	AF2-125	725	186
23	AF2-132	620	186	1,640	186
24	AF2-133	158	186	1,172	186
25	AF2-134			314	186
26	AF2-162	3,333	186	3,333	186
27	AF2-173	13,389	186	12,814	186
28	AF2-204	9,422	186	9,422	186
29	AF2-205	536	186	537	186
30	AF2-224	896	186	1,229	186
31	AF2-370	149	186	150	186
32	AG1-109	182	186
33	AG1-222	5	186
34	AG1-224	171	186
35	AG1-232	244	186
36	AG1-302	544	186	640	186
37	AG1-324	207	186
38	AG1-365	140	186
39	AG1-367	943	186	1,110	186
40	AG1-368	148	186
41	AG1-424	206	186
42	AG1-433	1,119	186	1,317	186
43	AG1-436	168	186
44	AG1-447	168	186
45	AG1-448	997	186	1,173	186
46	AG1-453	211	186
47	AG1-454	167	186
48	AG2-072	745	186	1,343	186
49	AG2-083	51	186	100	186
50	AG2-084	196	186	385	186
51	AG2-085	84	186	164	186
52	AG2-116	92	186	181	186
53	AG2-117	95	186	187	186
54	AG2-126	98	186	193	186
55	AG2-130	91	186	179	186
56	AG2-131	82	186	161	186
57	AG2-132	99	186	194	186
58	AG2-162	97	186	192	186
59	AG2-163	95	186	187	186
60	AG2-165	18	186	32	186
61	AG2-173	20	186	36	186
62	AG2-191	21	186	38	186
63	AG2-192	17	186	31	186
64	AG2-242	2,544	186
65	AG2-519	56	186	111	186
66	AG2-577	53	186	103	186
67	AH1-013	9	186	16	186
68	J793	1,049	186	2,410	186
69	PJM - # AE1-170	18,235	186	8,663	186
70	PJM - # AE2-325	3,334	186	3,486	186
71	PJM - #AB1-087	25,702	186	27,368	186
72	PJM - #AB1-088	17,771	186	17,771	186
73	PJM - #AC2-090	2,149	186	1,943	186
74	PJM - #AC2-157	78,235	186	76,930	186
75	PJM - #AD1-043	369	186	552	186
76	PJM - #AD1-128	3,042	186	2,672	186
77	PJM - #AD2-020	2,777	186	3,522	186
78	PJM - #AD2-071	2,369	186	2,395	186
79	PJM - #AD2-138	8,310	186
80	PJM - #AE1-207	2,064	186	1,320	186
81	PJM - #AE1-208	2,120	186	2,459	186
82	PJM - #AE1-209	39,732	186	41,929	186
83	PJM - #AE1-210	3,347	186	2,808	186
84	PJM - #AE2-089	6,635	186	6,708	186
85	PJM - #AE2-130	47,536	186	44,663	186
86	PJM - #AE2-154	1,467	186	1,581	186
87	PJM - #AE2-169	138	186	138	186
88	PJM - #AE2-172	1,601	186	1,601	186
89	PJM - #AE2-219	3,792	186	2,761	186
90	PJM - #AE2-234	4,001	186	3,442	186
91	PJM - #AE2-236	8,547	186	6,531	186
92	PJM - #AE2-261	6	186
93	PJM - #AE2-276	708	186	765	186
94	PJM - #AE2-297	113	186
95	PJM - #AE2-323	3,176	186	3,223	186
96	PJM - #AE2-341	7	186
97	PJM - #AF1-088	151	186	177	186
98	PJM - #AF1-118	13,765	186	13,765	186
99	PJM - #AF1-119	10,691	186	10,270	186
100	PJM - #AF1-158	2,701	186	2,330	186
101	PJM - #AF1-221	282	186	282	186
102	PJM - #AF2-389	641	186	725	186
103	PJM - #AF2-396	1,238	186	1,432	186
104	PJM #AF1-046	4,353	186	3,333	186
20	Total
21	Generation Studies
22	St. Joseph Solar Study AD2-079			307,266	107
39	Total
40	Grand Total

Name of Respondent:

Indiana Michigan 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 112 Post Employment Benefits	9,016,533	406,483	228/242	1,690,842	7,732,174
2	Cook Plant Water Study Cost	9,390,891		524	713,793	8,677,098
3	Cook Plant Refueling Levelization	31,999,435	117,012,971	519, 520, 523, 524, 528, 529, 530, 531, 532	67,794,127	81,218,279
4	COVID-19 Deferred Bad Debt Expense	1,705,705	29,476	426	695,778	1,039,403
5	Unamortized Loss on Reacquired DebtAmort 1/1995 - 12/2022	206,952		428	206,952
6	Michigan Home Energy Management and Work Energy Manament Programs	593,154	148,588	908	7,043	734,699
7	Deferred Storm Expense	12,568,307	16,627,898	593	4,203,314	24,992,891
8	Unrealized Loss on Forward CommitmentsRegulated Assets/Liabilities	7,173,530	3,858,542	175, 182, 244, 456	11,352,304	320,232
9	Cook Life Cycle Management - Indiana Portion Per IIURC Cause Order #44182	768,769	404,636	403	1,151,521	21,884
10	Netting of Trading Activities Related to UnrealizedGains/Losses on Forward Commitments BetweenRegulatory Assets and Liabilities		377,713	254	57,481	320,232
11	Indiana Plugged In Rebate Deferral	33,679	43,223	182/431	1,776	75,126
12	Michigan Plugged In Rebate Deferral	7,149	19,961	182/431	374	26,736
13	Michigan Dry Cask Storage Deferral	981	735	182/431	1,432	284
14	SFAS 158 Employer Accounting		55,108,101	129/165/190/219/228/242	28,165,416	26,942,685
15	Nuclear Decommissioning Study Expense	185,400		923	78,905	106,495
16	Indiana Rate Case expensesPer IURC Cause Order #44075	1,283,861	1,537,589	928	1,685,179	1,136,271
17	IN PJM Exp and OSS Margin	18,144,149	5,211,553	254/555	23,355,702
18	Cook Uprate Project	27,738,719		524	2,417,536	25,321,183
19	Michigan Rate Case Expenses	102,654	693,800	928	102,654	693,800
20	Michigan Electric Vehicle Supply Equipment Per MPSC Case U-16496	8,051		912	8,051
21	DSM Energy Optimization Program - Michigan	124,798	311,656	182/431/908	19,643	416,811
22	Deferred Depreciation Rockport Unit 2	22,451,763		108	3,207,395	19,244,368
23	Michigan Under Recovered Fuel Interest	7,870	208,071	182/419	16,780	199,161
24	SFAS 109 Deferred FIT	138,835,125	48,434,022	190 ,236 ,254 ,255 ,282 ,283,409 ,410 ,411	32,856,138	154,413,009
25	Unrecovered Fuel Costs - Indiana		76,904,980	254/440/442/444	38,833,669	38,071,311
26	SFAS 109 Deferred SIT	221,569,986	23,475,857	283	18,639,022	226,406,821
27	IN Tax Rider Under Recovery		7,291,242			7,291,242
28	City of Fort Wayne SettlementAmortization 3/13 - 4/25Per IURC Cause Order #44075	3,065,693		182/588	914,591	2,151,102
29	Cook Unit 2 Baffle Bolts Amort 3/2013 - 2/2038 Per IURC Cause Order #44075	4,848,969		530	299,936	4,549,033
30	SFAS 106 Medicare Subsidy Amort 1/2013 - 12/2024	3,060,404		926	1,020,134	2,040,270
31	River Transportation Selling Price Variance	771,083	14,059,624	417	9,601,524	5,229,183
32	Cook Life Cycle Management Program - Michigan Per MPSC Case U-17026	13,086,748	459,678	182/408/421	1,472,991	12,073,435
33	Unrecovered Fuel Costs - Michigan	6,378,101	14,848,726	440/442/444	12,421,824	8,805,003
34	Rockport DSI Project - Indiana 20% Non Federal Mandate Rider Per IURC Cause Order #44331	7,630,055	152,604	182/403/500/421/502	1,436,756	6,345,903
35	Cook Turbine Replacement CC _IndianaPer IURC Cause Order #44075	9,640,577	314,629	182/421	915,919	9,039,287
36	SNF Incremental Costs	11,836		520	9,693	2,143
37	Indiana Environmental Compliance Rider		6,607,313			6,607,313
38	Indiana DSM program Per IURC Cause order #43287 Per IURC Cause order #44182	2,826,866	8,016,681	908	557,212	10,286,335
39	2022 PJM Transmission True-up	1,032,139	4,693,088	456/447	1,032,139	4,693,088
44	TOTAL	556,269,932	407,259,440		266,945,546	696,583,826

Name of Respondent:

Indiana Michigan 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	Property Taxes	53,114,057	74,677,052	107/146/186/408	74,550,406	53,240,703
2	Property Taxes - Capital Leases	63,924	62,738	408	63,924	62,738
3	Agency Fees, Factored Accts Rec	3,060,339	42,065,699	142/173/184/ 426	41,788,911	3,337,127
4	River Transport Division	2,449,671	75,875,349	106/121/122/142/143/144/152/156/163/165/182/232/236/242/408/417/421/426/430	72,055,151	6,269,869
5	Estimated Barging Bills
6	Unamortized Credit Line Fees	981,136	595,995	142/143/431	674,567	902,564
7	Defd Non-taxable Leased Assets	242,776	320,695	142/143/184	499,603	63,868
8	Minor Items	3,580		186	11	3,569
9	Transource OU Acctg for Def Asset	167,932	200,534	146/565	273,055	95,411
10	Long Term Assoc		15,257,769	253	7,907,647	7,350,122
11	Unidentified Cash Receipts		97,611	131/146/253	4,153	93,458
12	Railroad Cars Subleased		40,658	151/236/408	38,259	2,399
13	Deferred Expenses		3,652,555			3,652,555
47	Miscellaneous Work in Progress	3,325,296				3,236,988
48	Deferred Regulatroy Comm. Expenses (See pages 350 - 351)
49	TOTAL	63,408,711				78,311,371

Name of Respondent:

Indiana Michigan 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	ACCRD BOOK ARO EXPENSE - SFAS 143	472,270,665	425,891,765
3	Reg Liability - SFAS 143 - ARO	407,340,905	276,893,330
4	CAPITALIZED INTEREST	34,918,282	38,767,504
5	BOOK OPERATING LEASE - LIAB	13,537,357	13,636,399
6	SI-AMORT INT PRE 4 7 83 DISP	28,824,843	30,407,746
7	Other	76,119,559	24,037,408
8	TOTAL Electric (Enter Total of lines 2 thru 7)	880,772,493	761,559,336
9	Gas
15	Other
16	TOTAL Gas (Enter Total of lines 10 thru 15)
17.1	Other (Specify)	190,728,021	(a) 171,934,383
17	Other (Specify)
18	TOTAL (Acct 190) (Total of lines 8, 16 and 17)	1,071,500,514	933,493,719

Notes

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxes


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

Acc Def Income Taxes - Federal - Hdg-CF-Int Rate		1,747,198		1,321,271
Non Utility Items - 190.2		7,010,942		6,338,637
SFAS 109-Regulatory Assets - 190.3 & 190.4		183,384,231		165,519,192
SFAS 133		—		—
Accu Def Income Taxes Pension-OCI		(1,414,350)		(1,244,717)

Total		$	188,980,823	$	170,613,112

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

Balance at Beginning of Year				$	1,071,500,514

(Less) Amounts Debited to:
	(a) Account 410.1			(223,647,879)
	(b) Account 410.2			(10,298,646)
	(c) 1823/254/219/129/427			(43,120,422)

(Plus) Amounts Credited to:
	(a) Account 411.1			105,378,411
	(b) Account 411.2			8,682,628
	(c) 1823/254/219/129/427			24,999,114

Balance at End of Year				$	933,493,719

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

CAPITAL STOCKS (Account 201 and 204)
Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year. Give details concerning shares of any class and series of stock authorized to be issued by a regulatory commission which have not yet been issued. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or noncumulative. State in a footnote if any capital stock that has been nominally issued is nominally outstanding at end of year. Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which is pledged, stating name of pledgee and purpose of pledge.
Line No.	Class and Series of Stock and Name of Stock Series (a)	Number of Shares Authorized by Charter (b)	Par or Stated Value per Share (c)	Call Price at End of Year (d)	Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Shares (e)	Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Amount (f)	Held by Respondent As Reacquired Stock (Acct 217) Shares (g)	Held by Respondent As Reacquired Stock (Acct 217) Cost (h)	Held by Respondent In Sinking and Other Funds Shares (i)	Held by Respondent In Sinking and Other Funds Amount (j)
1	Common Stock (Account 201)
2		2,500,000			1,400,000	56,583,866
5	Total	2,500,000			1,400,000	56,583,866
6	Preferred Stock (Account 204)
7
8
9
10	Total
1	Capital Stock (Accounts 201 and 204) - Data Conversion
2
3
4
5	Total

Name of Respondent:

Indiana Michigan 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	972,666,991
3.1	IncreasesDecreasesFromSalesOfDonationsReceivedFromStockholders Increases (Decreases) from Sales of Donations Received from Stockholders
4	DonationsReceivedFromStockholders Ending Balance Amount	972,666,991
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	120,554
11.1	IncreasesDecreasesFromGainOrResaleOrCancellationOfReacquiredCapitalStock Increases (Decreases) from Gain or Resale or Cancellation of Reacquired Capital Stock
12	GainOnResaleOrCancellationOfReacquiredCapitalStock Ending Balance Amount	120,554
13	MiscellaneousPaidInCapitalAbstract Miscellaneous Paid-In Capital (Account 211)
14	MiscellaneousPaidInCapital Beginning Balance Amount	3,874,258
15.1	IncreasesDecreasesDueToMiscellaneousPaidInCapital Increases (Decreases) Due to Miscellaneous Paid-In Capital	7,974,796
16	MiscellaneousPaidInCapital Ending Balance Amount	11,849,054
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	984,636,599

Name of Respondent:

Indiana Michigan 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	127

Name of Respondent:

Indiana Michigan 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	None
3	Subtotal
4	Reacquired Bonds (Account 222)
5
6
7
8	Subtotal
9	Advances from Associated Companies (Account 223)
10	None
11	Subtotal
12	Other Long Term Debt (Account 224)
13	Spent Nuclear Fuel Disposal Costs Prior To April 7, 1983 - Basic Fee Assessment & Interest		281,294,864									285,582,850
14	Series 2002 A - 2.75% Fixed Rate		50,000,000		296,785			08/01/1985	06/01/2025	08/01/1985	06/01/2025	50,000,000	1,375,000
15							325,000
16							136,351
17					444,593			06/01/2007	06/01/2025	06/01/2007	06/01/2025
18					386,217			12/01/2017	06/01/2025	12/01/2017	06/01/2025
19					74,250					06/01/2019	05/31/2020
20					74,250					06/01/2020	05/31/2021
21					74,250					06/01/2021	05/31/2022
22	(a) Series 2009 A - 3.05% Fixed Rate		50,000,000		353,976			03/26/2009	(g) 06/01/2025	04/01/2009	05/31/2014	50,000,000	1,525,000
23					249,468					06/01/2014	05/31/2018
24					354,263			06/01/2018	06/01/2025	06/01/2018	06/01/2025
25	(b) Series 2009 B - 3.05% Fixed Rate		50,000,000		353,976			03/26/2009	06/01/2025	04/01/2009	05/31/2014	50,000,000	1,525,000
26					249,469					06/01/2014	05/30/2018
27					354,262			06/01/2018	06/01/2025	06/01/2018	06/01/2025
28	Series D -0.750% Fixed Rate		40,000,000		632,137			06/01/2021	04/01/2025	06/01/2021	04/01/2025	40,000,000	300,000
29					40,998					06/01/2021	04/01/2025
30	Series L - 3.75% Fixed Rate		300,000,000		3,139,683		2,088,000	06/29/2017	07/01/2047	06/29/2017	07/01/2047	300,000,000	11,250,000
31	Series K - 4.55% Fixed Rate		400,000,000		4,036,755		1,372,000	03/03/2016	03/15/2046	03/03/2016	03/15/2046	400,000,000	18,200,000
32	Series H - 6.05% Fixed Rate		400,000,000		3,815,383		2,272,000	11/14/2006	03/15/2037	11/14/2006	03/15/2037	400,000,000	24,200,000
33	Amortization of Cash Flow Hedges on 6.05% SUN									11/14/2006	02/28/2037		421,763
34	Series J - 3.20% Fixed Rate		250,000,000		1,969,707		402,500	03/18/2013	03/15/2023	03/18/2013	03/15/2023	250,000,000	8,000,000
35	(c) Series O-3.250% Fixed Rate		450,000,000		4,825,845		3,501,000	04/29/2021	05/01/2051	04/29/2021	05/01/2051	450,000,000	14,625,000
36	(d) Fort Wayne Settlement		7,302,217					03/01/2010	02/28/2025	03/01/2010	02/28/2025	5,079,891
37	Amortization of Interest Rate Swap on 3.20% SUN									03/18/2013	03/15/2023		1,606,489
38	(e) Series M - 3.85% Fixed Rate		350,000,000		2,865,394		1,102,500	05/02/2018	05/15/2028	05/02/2018	05/15/2028	350,000,000	13,475,000
39	(f) Series N - 4.25% Fixed Rate Per IURC Authority Cause #45057		475,000,000		4,926,878		2,717,000	08/08/2018	08/15/2048	08/08/2018	08/15/2048	475,000,000	20,187,500
28	Subtotal		3,103,597,081		29,518,539		13,916,351					3,105,662,741	116,690,752
33	TOTAL		3,103,597,081									3,105,662,741	116,690,752

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: ClassAndSeriesOfObligationCouponRateDescription

The $50 million 6.25% City of Rockport Series 2009B PCRB was issued 3/26/2009 with a maturity date of 6/1/2025 and a mandatory tender date of 6/2/2014. On the 6/2/2014 put date, the PCRB was converted to 1.75% with a mandatory tender date of 6/1/2018. On the 6/1/2018 put date, the PCRB was converted to 3.05% with a maturity date of 6/1/2025. Issuance expenses totaling $354,262 will be amortized through 6/1/2025.

(b) Concept: ClassAndSeriesOfObligationCouponRateDescription

The $40 million City of Rockport Series D,PCRB was issued on June , 2021. The interest rate is variable with the maturity date of April 1, 2025..The $40M million was reissued on December 14 ,2021 and the interest rate converted to 0.75% with the maturity date of April 1,2025

(c) Concept: ClassAndSeriesOfObligationCouponRateDescription

The $450M 3.25% fixed rate Series O Senior Unsecured Note was issued on 04/29/2021 with a maturity date of 5/1/2051.Issuance expense and discount expense will be amortized through May 2051.

(d) Concept: ClassAndSeriesOfObligationCouponRateDescription

On August 10, 2011, the Indiana Utility Regulatory Commission issued a Final Order in Cause No. 43980 approving an agreement between Indiana Michigan Power Company and the City of Fort Wayne, Indiana to settle all disputes and other matters between them relating to the 1974 Lease Agreement pursuant to which I&M leased certain electric property from the city. The agreement required I&M to purchase the leased property and settle certain claims asserted by the City of Fort Wayne. Pursuant to the agreement, I&M paid the city $5 million within thirty days of the effective date of the final order. Further, the agreement provided that I&M pay the city a total of $34.2 million, including interest, over 15 years (March 2010 to February 2025), and that the City of Fort Wayne recognize I&M as the exclusive electricity provider in the Fort Wayne area. Interest on this liability is recorded in account 431.

(e) Concept: ClassAndSeriesOfObligationCouponRateDescription

The $350M 3.85% fixed rate Series M Senior Unsecured Note was issued 5/2/2018 with a maturity date of 5/15/2028. Issuance expense and discount expense will be amortized through May 2028.

(f) Concept: ClassAndSeriesOfObligationCouponRateDescription

The $475M 4.25% fixed rate Series N Senior Unsecured Note was issued 8/8/2018 with a maturity date of 8/15/2048. Issuance expense and discount expense will be amortized through August 2048.


Schedule Page: 256 Line No.: 18.2 Column: a

The $200M variable term loan was issued 5/9/2018 with a maturity date of 05/09/2021. Issuance expense and discount expense will be amortized through May 2021.

(g) Concept: DateOfMaturity

Subject to mandatory tender for purchase (puttable) on 6/1/2018.

Name of Respondent:

Indiana Michigan 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)	324,720,578
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) 130,692,475
28	Show Computation of Tax:
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: FederalTaxNetIncome

FOOTNOTE DATA


Schedule Page: 261 Line No.: 28 Column: b A
Description			Amount('000)
Net Income for the Year per Page 117			$324,721
Federal Income Taxes			$(8,039)
State Income Taxes			$11,984
Pre-Tax Book Income			$328,666

Increase (Decrease) in Taxable Income resuliting from:

Excess tax vs book depreciation			$(25,332)
Afudc / interest capitalized			$(6,353)
Percent repair allowance			$(124,140)
Removal costs			$(59,255)
Accelerated amortization			$5,586
Mine Development			$—
Revenue refunds			$11,405
Deferred fuel costs			$(2,427)
Equity in earnings of subsidiaries			$(287)
Book accruals			$(18,455)
Book deferrals			$(37,855)
OPEB - Others miscellaneous			$22,155
Other miscellaneous			$(14,723)
Permanent Schedule M's			$1,528
Tax accruals			$26
Tax deferrals			$18,038
Tax vs book gain / loss			$(3,458)
Nuclear fuel adjustments			$82,924
Nuclear fuel disposal costs			$(4,288)
Nuclear decommissioning costs			$—
Book deferred nuclear costs			$(49,219)
Emission Allowances			$213
Asset Retirement Obligation			$5,943
Taxable Income before State Taxes			$130,692

State & Local Current Tax			$2,175

Federal Taxable Income			$128,517
Computation of Tax:
FIT on Current Year Taxable Income			$26,989
Tax Credits			$(10,030)
Solar Investment Tax Credits			$—
NOL Reclass			$—
R&D Credit			$—

Estimated Tax Currently Payable (b)			$16,959

Adjustments of Prior Year's Accruals			$26,813
Tax Expense for R/C of Net Operating Loss (Prior Yr)

Estimated Current Federal Income Taxes			$43,772

Represents the allocation of estimated current year net operating tax income of American Electric Power Company, Inc.


FOOTNOTE DATA

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 2022 System Federal income taxes will not be available until the consolidated Federal Income tax return is filed by October 2023.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:

Indiana Michigan 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	State Tax	State Tax	IL	2016	0	0				0
2	State Tax	State Tax	IL	2017	198,385	0				198,385	0
3	State Tax	State Tax	IL	2018	375,107	0				375,107	0
4	State Tax	State Tax	IL	2019	667,976	0				667,976	0
5	State Tax	State Tax	IL	2020	508,605	0				508,605	0
6	State Tax	State Tax	IL	2021	48,973	0		516,509		565,482
7	State Tax	State Tax	IL	2022		0	126,194			126,194	0	123,394			2,800
8	State Tax	State Tax	IN	2015	30,176	0				30,176	0
9	State Tax	State Tax	IN	2017	4,389,858	0				4,389,858	0
10	State Tax	State Tax	IN	2018	7,980,470	0				7,980,470	0
11	State Tax	State Tax	IN	2019	2,361,490	0				2,361,490	0
12	State Tax	State Tax	IN	2020	8,250,230	0				8,250,230	0
13	State Tax	State Tax	IN	2021	22,984	0		7,231,964		7,254,948	0
14	State Tax	State Tax	IN	2022		0	8,095,413	1,826,000		6,269,413	0	7,874,158			221,255
15	State Tax	State Tax	KY	2017	147,238	0				147,238	0
16	State Tax	State Tax	KY	2018	87,492	0				87,492	0
17	State Tax	State Tax	KY	2019	36,699	0				36,699	0
18	State Tax	State Tax	KY	2020	99,872	0				99,872	0
19	State Tax	State Tax	KY	2021	32,616	0		9,731		22,885	0
20	State Tax	State Tax	KY	2022		0	98,438			98,438	0	104,390			5,952
21	State Tax	State Tax	MI	2017	1,008,265	0				1,008,265	0
22	State Tax	State Tax	MI	2018	1,961,572	0				1,961,572	0
23	State Tax	State Tax	MI	2019	1,708,540	0				1,708,540	0
24	State Tax	State Tax	MI	2020	2,689,462	0				2,689,462	0
25	State Tax	State Tax	MI	2021	29,327	0		2,435,360		2,464,687	0
26	State Tax	State Tax	MI	2022		0	2,097,481			2,097,481	0	2,042,788			54,693
27	State Tax	State Tax	MO	2017	1,164	0				1,164	0
28	State Tax	State Tax	MO	2018	255	0				255	0
29	State Tax	State Tax	MO	2019	342	0				342	0
30	State Tax	State Tax	MO	2020	161	0				161	0
31	State Tax	State Tax	MO	2021	3	0				3	0
32	State Tax	State Tax	MO	2022		0	12,057			12,057	0	12,056			1
33	State Tax	State Tax	MULTI	2015	1,561,261	0				1,561,261	0
34	State Tax	State Tax	MULTI	2019	7,946,458	0				7,946,458	0
35	State Tax	State Tax	MULTI	2021	0	0		1,135		1,135	0
36	State Tax	State Tax	NOL	2011	25	0	25			0	0				25
37	State Tax	State Tax	UT	2020	148,134	0				148,134	0
38	State Tax	State Tax	UT	2021		0		148,135		148,135	0
39	State Tax	State Tax	WV	2017	1,337,464	0				1,337,464	0
40	State Tax	State Tax	WV	2018	257,890	0				257,890	0
41	State Tax	State Tax	WV	2019	58,958	0				58,958	0
42	State Tax	State Tax	WV	2020	89,021	0				89,021	0
43	State Tax	State Tax	WV	2021	53,885	0		1,928,653		1,874,768	0
44	State Tax	State Tax	WV	2022		0	332,518			332,518	0	326,611			5,907
45	State Tax	State Tax	FIN48		126	0				126	0
46	Subtotal State Tax				5,874,624	0	10,762,126	14,075,755	0	2,560,995	0	10,483,397	0	0	278,729
47	Total Local Tax				34,489	0	0	100	0	34,589	0	0	0	0	0
48	Real Prop Leased	Real Estate Tax	IN	2022	0	0	234,793	234,793		0					234,793
49	Real Prop Leased	Real Estate Tax	MI	2020	81,633	0	47,570	34,063		0		47,570
50	Real Prop Leased	Real Estate Tax	MI	2021		0	212,382	208,113		4,269		212,382
51	Subtotal Real Estate Tax				81,633	0	0	0	0	0	0	0	0	0	0
52	Total Real & Personal Property Tax				92,602,305	0	73,514,816	72,362,712	0	93,754,409	0	70,919,255	0	0	2,595,561
53					0	0				0	0	0			0
54	Total Unemployment Tax				86,892	0	593,774	600,631	0	80,035	0	379,300	0	0	214,474
55	Subtotal Other Tax				0	0	0	0	0	0	0	0	0	0	0
56	Total Income Tax				0	0	0	0	0	0	0	0	0	0	0
57	Excise Tax	Federal Tax		2021	169,246	0	1,299	170,545		0	0				1,299
58	Excise Tax	Federal Tax		2022		0	799,242	517,770		281,472	0	10,738			788,504
59	Subtotal Excise Tax				169,246	0	800,541	688,315	0	281,472	0	10,738	0	0	789,803
60	Total Fuel Tax				0	721,023	2,672,021	2,635,651	0	0	684,653	0	0	0	2,672,021
61	Special Fuel Tax	Fuel Tax	WV	2021	33,027	0	1	33,028		0					1
62	Special Fuel Tax	Fuel Tax	WV	2022		0	124,128	98,242		25,886					124,128
63	Subtotal Federal Insurance Tax				33,027	0	124,129	131,270	0	25,886	0	0	0	0	124,129
64	Total Franchise Tax				51,773	0	0	0	0	51,773	0	0	0	0	0
65	Federal Income	Federal Tax			12,194,146	0	41,818,899	26,230,355		3,394,398		44,547,867			2,728,967
66	Subtotal Miscellaneous Other Tax				12,194,146	0	41,818,899	26,230,355	0	3,394,398	0	44,547,867	0	0	2,728,967
67	Total Other Federal Tax				0	0	0	0	0	0	0	0	0	0	0
68	Other State Tax	Other State Tax
69	Subtotal Other State Tax				0	0	0	0	0	0	0	0	0	0	0
70	Total Util Receipts Tax				0	0	11,252,511	11,305,029	0	52,518	0	11,252,511	0	0	0
71	Use Tax	Sales And Use Tax	IN	2002	0	0				0
72	Use Tax	Sales And Use Tax	IN	2020	200		200			0					200
73	Use Tax	Sales And Use Tax	IN	2021	629,063		14,575	614,488		0		59			14,634
74	Use Tax	Sales And Use Tax	IN	2022			5,404,343	4,707,021		697,322		2,702			5,401,641
75	Use Tax	Sales And Use Tax	MI	2020	0					0
76	Use Tax	Sales And Use Tax	MI	2021	32,509	724,405	51,330	640,566		0		12,499			38,831
77	Use Tax	Sales And Use Tax	MI	2022			1,282,671	1,887,151		101,965	706,445	20,451			1,262,220
78	Use Tax	Sales And Use Tax	WV	2002	0					0
79	Use Tax	Sales And Use Tax	WV	2018	0					0
80	Use Tax	Sales And Use Tax	WV	2021	4,006			4,006		0
81	Use Tax	Sales And Use Tax	WV	2022		0	43,014	41,562		1,452					43,014
82	Subtotal Other Use Tax				665,778	724,405	6,766,583	6,613,662	0	800,739	706,445	35,711	0	0	6,730,872
83	Total Ohio CAT Tax				13,500	0	5,040	8,460	0	0	0	5,040	0	0	0
84	State License Registration	Other License And Fees Tax	MI	2019	25	0				25	0
85	State License Registration	Other License And Fees Tax	MI	2020	25	0				25	0
86	State License Registration	Other License And Fees Tax	wv	2019	26	0				26	0
87	Subtotal Other License And Fees Tax				76	0	0	0	0	76	0	0	0	0	0
88	Total Payroll Tax				7,017,219	0	18,371,670	23,262,734	4,259	2,121,896	0	11,540,986	0	0	6,830,684
89	Subtotal Advalorem Tax				0	0	0	0	0	0	0	0	0		0
90	Total Public Serv Comm				0	0	17,500	17,500	0	0	0	0	0	0	17,500
91	Subtotal Severance Tax				0	0	0	0	0	0	0	0	0	0	0
92	Total Penalty Tax				0	0	0	0	0	0	0	0	0	0	0
93	Subtotal Other Taxes And Fees				0	0	0	0	0	0	0		0	0	0
40	TOTAL				94,367,286	1,445,428	167,089,135	158,409,143	4,259	102,988,689	1,391,098	149,329,537	0	0	17,759,599

Name of Respondent:

Indiana Michigan 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%	1,792,757			411.4	1,792,757
3	4%				411.4
4	7%	189,822			411.4	31,761		158,061
5	10%	4,940,211	411.1		411.4	1,840,931		3,099,280	29 Years
6	State DITC		411.1		411.4
7	30	15,461,551			411.4	1,368,193		14,093,358
8	TOTAL Electric (Enter Total of lines 2 thru 7)	22,384,341				5,033,642		17,350,699
9	Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
10										`
47	OTHER TOTAL
48	GRAND TOTAL	22,384,341						17,350,699

Name of Respondent:

Indiana Michigan 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	Pole Attachment Rentals	709,012	143/163/184/186/421/451/454/456/593	2,363,272	2,427,000	772,740
2	IPP-System Upgrade Credits	3,955,595			150,678	4,106,273
3	Defd Gain-Fiber Optics Agrmt In Kind Service-Amrtz thru 2025	2,112,471	124	541,666		1,570,805
4	Deferred Revenues-Verizon Amortized thru March 2023	59,304	451	47,441		11,863
5	Deferred Revenues-KDL Amortized thru Dec 2022	4,878	451	4,878
6	Customer Advance Receipts	9,956,570	142	9,956,570	10,682,874	10,682,874
7	Federal Mitigation Deferral (NSR)	1,052,907	242	1,052,907
8	Deferred Revenue	373,270	142/143/186	373,270	2,971,366	2,971,366
9	Contract Settlement Reserves	237,679	506/566	237,680	317,467	317,466
10	Asbestos Accrual
11	Minor Items	423,024	107/108/142/184/186/232/234/235/242	516,967	412,544	318,601
12	QUAL OF SVC PENALTIES - LT	248,335				248,335
13	Neig Help Neig-Cust Donations	29	588	29
14	Rockport U2 Contingency Accrual
15	Long Term Assoc AP		186	2,585,590	7,024,954	4,439,364
47	TOTAL	19,133,074		17,680,270	23,986,883	25,439,687

Name of Respondent:

Indiana Michigan 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	26,785,474		5,003,526							21,781,948
5	Other
5.1	Other (provide details in footnote):
8	TOTAL Electric (Enter Total of lines 3 thru 7)	26,785,474		5,003,526							21,781,948
9	Gas
10	Defense Facilities
11	Pollution Control Facilities
12	Other
12.1	Other (provide details in footnote):
15	TOTAL Gas (Enter Total of lines 10 thru 14)
16	Other
16.1	Other - SFAS 109	(a) 10,025,389					254		254	2,996,621	7,028,768
17	TOTAL (Acct 281) (Total of 8, 15 and 16)	16,760,085		5,003,526						2,996,621	14,753,180
18	Classification of TOTAL
19	Federal Income Tax	16,760,085		5,003,526						2,996,621	14,753,180
20	State Income Tax
21	Local Income Tax

Name of Respondent:

Indiana Michigan 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: AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty

Footnote 272


Line 16 Other - Detail	Balance at Beginning of Year	Balance at End of Year
SFAS 109	(10,025,389)	(7,028,768)
Total Line 16	(10,025,389)	(7,028,768)

Name of Respondent:

Indiana Michigan 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	1,421,322,470	123,433,177	173,535,423			190		283		1,371,220,224
3	Gas
4	Other (Specify)
5	Total (Total of lines 2 thru 4)	1,421,322,470	123,433,177	173,535,423							1,371,220,224
6	Others	(a) 292,791,594	3,269,970	2,324,618			1823/254/190	28,395,246	1823/254	111,114,715	209,126,773
9	TOTAL Account 282 (Total of Lines 5 thru 8)	1,128,530,876	126,703,147	175,860,041				28,395,246		111,114,715	1,162,093,451
10	Classification of TOTAL
11	Federal Income Tax	1,128,530,876	126,703,147	175,860,041				28,395,246		111,114,715	1,162,093,451
12	State Income Tax
13	Local Income Tax

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesOtherProperty

Page 274 Footnote


	Balance at Beginning of Year	Balance at End of Year
Non-Utility	13,670,011	5,625,804
SFAS 109	(306,461,605)	(214,752,577)
Total Other - Line 6	(292,791,594)	(209,126,773)

Name of Respondent:

Indiana Michigan 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	NUC DECOM TRUST - SFAS 143 - ARO - BK	742,982,660	43,587,108	154,180,014							632,389,754
4	U1-BK DEFD NUC REFUEL COSTS	6,719,880	19,685,001	9,349,044							17,055,837
5	UNIT 2 NUC FUEL TAX VS BOOK DEPR	140,350,038									140,350,038
6	UNIT 1 NUC FUEL TAX VS BOOK DEPR	134,484,324									134,484,324
7	CAPITALIZED SOFTWARE COST-BOOK	34,572,100	2,293,906	6,993,671							29,872,335
8	Other	341,515,158	46,361,934	52,811,780	200,957	531,784					348,295,831
9	TOTAL Electric (Total of lines 3 thru 8)	717,593,844	111,927,949	223,334,509	200,957	531,784					605,856,457
10	Gas
11
12
13
14
15
16
17	TOTAL Gas (Total of lines 11 thru 16)
18	TOTAL Other	(a) 309,463,764			3,116,686	2,659,454	1823/254/1903	43,613,249	1823/254	41,676,223	307,983,970
19	TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)	1,027,057,608	111,927,949	223,334,509	3,317,643	3,191,238		43,613,249		41,676,223	913,840,427
20	Classification of TOTAL
21	Federal Income Tax	805,487,620	111,927,949	223,334,509	3,317,643	3,191,238		24,974,227		18,200,368	687,433,606
22	State Income Tax	221,569,987						18,639,022		23,475,856	226,406,821
23	Local Income Tax
NOTES

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesOther

FOOTNOTE DATA


Schedule Page: 261 Line No.: 28 Column: b A
Description			Amount('000)
Net Income for the Year per Page 117			$324,721
Federal Income Taxes			$(8,039)
State Income Taxes			$11,984
Pre-Tax Book Income			$328,666

Increase (Decrease) in Taxable Income resuliting from:

Excess tax vs book depreciation			$(25,332)
Afudc / interest capitalized			$(6,353)
Percent repair allowance			$(124,140)
Removal costs			$(59,255)
Accelerated amortization			$5,586
Mine Development			$—
Revenue refunds			$11,405
Deferred fuel costs			$(2,427)
Equity in earnings of subsidiaries			$(287)
Book accruals			$(18,455)
Book deferrals			$(37,855)
OPEB - Others miscellaneous			$22,155
Other miscellaneous			$(14,723)
Permanent Schedule M's			$1,528
Tax accruals			$26
Tax deferrals			$18,038
Tax vs book gain / loss			$(3,458)
Nuclear fuel adjustments			$82,924
Nuclear fuel disposal costs			$(4,288)
Nuclear decommissioning costs			$—
Book deferred nuclear costs			$(49,219)
Emission Allowances			$213
Asset Retirement Obligation			$5,943
Taxable Income before State Taxes			$130,692

State & Local Current Tax			$2,175

Federal Taxable Income			$128,517
Computation of Tax:
FIT on Current Year Taxable Income			$26,989
Tax Credits			$(10,030)
Solar Investment Tax Credits			$—
NOL Reclass			$—
R&D Credit			$—

Estimated Tax Currently Payable (b)			$16,959

Adjustments of Prior Year's Accruals			$26,813
Tax Expense for R/C of Net Operating Loss (Prior Yr)

Estimated Current Federal Income Taxes			$43,772

Represents the allocation of estimated current year net operating tax income of American Electric Power Company, Inc.


FOOTNOTE DATA

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 2022 System Federal income taxes will not be available until the consolidated Federal Income tax return is filed by October 2023.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:

Indiana Michigan 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	Unrealized Gain on Forward Commitments	223,482	175,182,244	3,214,216	3,288,996	298,262
2	Deferred Gain on Rockport Unit 2	3,457,637	507	3,457,637
3	Netting of Trading Activities Related to Unrealized Gains/Losses on Forward Commitments Between Regulated Assets/Liabilities		182	57,481	377,713	320,232
4	Indiana Environmental Compliance Rider	10,628,548	502	10,630,203	1,655
5	Indiana Solar Rider	165,566	403	253,344	487,530	399,752
6	Asset Retirement Oblig-Excess Provision SFAS 143	1,939,718,592	228	3,316,028,230	2,694,849,304	1,318,539,666
7	SNF Trust Funds - Pre 4/83	49,461,889	128,228,254	11,073,899	7,449,469	45,837,459
8	Gains on Foreign Currency DerivativesAmortz 1/2009 - 12/2023	22,618	403	11,309		11,309
9	SFAS 109 Deferred FIT	542,912,350	190 /282 /283	126,478,471	45,249,086	461,682,965
10	PJM Exp and OSS Margin Sharing Total		555	4,933,202	39,139,389	34,206,187
11	Over Recovered Fuel Costs - Indiana	1,519,445	182	1,519,445
12	Michigan Renewable Energy Surcharge	14,948,337	555	519,007	8,789,886	23,219,216
13	PJM Trans Enhancement	7,916,630	142	1,982,998		5,933,632
14	Indiana Resource Adequecy Rider	1,721,396	555	1,721,396	1,571,356	1,571,356
15	SFAS 158 - Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans	27,591,791	129/165/190/219	50,992,287	23,400,496
16	DSM Energy Optimization Program - Michigan	6,959,720	908	4,212,657	152,020	2,899,083
17	Michigan Credit C Rider	449,814	407	618,743	168,929
41	TOTAL	2,607,697,815		3,537,704,525	2,824,925,829	1,894,919,119

Name of Respondent:

Indiana Michigan 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	872,376,472	818,024,187	5,507,591	5,463,352	528,350	525,758
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)	568,225,756	516,316,915	4,739,785	4,599,874	72,655	72,042
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)	629,632,357	569,363,439	7,492,111	7,372,784	4,832	4,850
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting	5,163,649	5,339,682	55,614	58,034	1,897	1,899
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) 2,075,398,234	(e) 1,909,044,222	17,795,101	17,494,044	607,734	604,549
11	SalesForResaleAbstract (447) Sales for Resale	540,875,798	347,504,428	7,919,389	7,336,358	9	15
12	SalesOfElectricityAbstract TOTAL Sales of Electricity	2,616,274,032	2,256,548,651	25,714,490	24,830,402	607,743	604,564
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds	27,927,976	13,845,000
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds	2,588,346,056	2,242,703,651	25,714,490	24,830,402	607,743	604,564
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts	5,622,051	4,885,318
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	(b) 1,917,149	3,925,715
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power
19	RentFromElectricProperty (454) Rent from Electric Property	13,035,615	12,379,321
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	(c) 23,546,840	24,350,329
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	(d) 51,512,944	30,956,004
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	95,634,599	76,496,688
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	2,683,980,655	2,319,200,338
Line12, column (b) includes $ 14,879,723 of unbilled revenues.
Line12, column (d) includes 102,658 MWH relating to unbilled revenues

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: SalesToUltimateConsumers

Detail of unmetered Sales:


	Revenue	MWH	Average No.of Customers

Residential	2,518,952.00	13,347.00	18,407.00
Commercial	4,305,671.00	29,075.00	10,556.00
Industrial	830,601.00	6,112.00	1,304.00
Public Street Lighting	62,221.00	422.00	123.00
Total	7,717,445.00	48,956.00	30,390.00

(b) Concept: MiscellaneousServiceRevenues

Customer service revenue, including connects, reconnects, disconnects, temporary services and other charges billed to customers.

(c) Concept: OtherElectricRevenue


	2022	2021

Associated Business Development	3,742,525.00	2,964,052.00
DSM Revenues	—	—
Other -Nonaffiliated	137,598.00	10,050.00
Misc Revenues<$250,000	—	—
Sales of Renew.Energy Credits	19,666,717.00	21,376,227.00
	23,546,840.00	24,350,329.00

(d) Concept: RevenuesFromTransmissionOfElectricityOfOthers

PJM Revenues

(e) Concept: SalesToUltimateConsumers

Detail of unmetered Sales:


	Revenue	MWH	Average No. of Custom

Residential	2,687,995.00	13,542.00	18,567.00
Commercial	4,489,583.00	29,080.00	10,497.00
Industrial	898,670.00	6,312.00	1,327.00
Public Street Lighting	64,206.00	413.00	122.00
Total	8,140,454.00	49,347.00	30,513.00

Total Sales to Ultimate Consumers include $4,589,277 of operating revenues for distribution service provided to Open Access Customers. Megawatt hours delivered to Open Access Customers were $275,926 and are included in the reported Megawatt hours sold on pg. 301 (d).

Name of Respondent:

Indiana Michigan 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:

Indiana Michigan 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	Medium General Service	17	2,607	1	17,000	0.1534
2	Residential Service	5,298,007	830,905,024	514,879	10,290	0.1568
3	Residential Service TOD	84,948	12,143,195	5,409	15,705	0.1429
4	Residential Service Flat	14,123	2,310,810	1,447	9,760	0.1636
5	Residential Service PEV	1,125	48,376	174	6,466	0.0430
6	Res Off-Peak Energy Stor	23,048	3,044,406	1,203	19,159	0.1321
7	Res Svc Opt Senior Citizen	29,919	3,756,225	5,237	5,713	0.1255
8	Outdoor Lighting (Indiana)	13,347	2,518,952			0.1887
9	Rider
10	MI Credit		70,133
11	Misc Revenue Adjustment
12	Refund
13	Unrecovered Fuel		10,208,295
14	Outdoor Lighting (Indiana) -OAD	1	88			0.0880
41	TOTAL Billed Residential Sales	5,464,535	864,867,845	528,350	10,343	0.1583
42	TOTAL Unbilled Rev. (See Instr. 6)	43,056	7,508,627			0.1744
43	TOTAL	5,507,591	872,376,472	528,350	10,424	0.1584

Name of Respondent:

Indiana Michigan 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	Residential Service	2	287			0.1435
2	Electric Heating General	4,531	658,865	119	38,076	0.1454
3	Electric Heating Schools	5,475	645,926	13	421,154	0.1180
4	Energy Conserv Lighting	6,705	1,083,921	9	745,000	0.1617
5	GS PEV	8	102	2	4,000	0.0128
6	Industrial Services	751,153	67,696,774	60	12,519,217	0.0901
7	Irrigation Service	10,126	1,993,406	629	16,099	0.1969
8	Large General Service	2,005,587	214,000,649	3,836	522,833	0.1067
9	Large General Service OAD	5,721	172,736	2	2,860,500	0.0302
10	Large General Service OAD Self Supply	9,204	123,289	3	3,068,000	0.0134
11	Large General Service TOD	76,144	8,529,276	512	148,719	0.1120
12	Large Power	68,966	5,930,272	3	22,988,667	0.0860
13	Large Power OAD	10,714	339,407	1	10,714,000	0.0317
14	Large Power OAD Self Supply	22,726	330,153	1	22,726,000	0.0145
15	Medium General Service	1,412,257	215,953,427	62,982	22,423	0.1529
16	Medium General Service Flat	546	89,562	39	14,000	0.1640
17	Medium General Service OAD	1,632	77,927	10	163,200	0.0477
18	Medium General Service OAD Self Supply	1,541	35,111	8	192,625	0.0228
19	Medium General Service TOD	77,079	9,602,540	2,124	36,290	0.1246
20	Municipal and School Service	46,309	6,156,298	421	109,998	0.1329
21	Outdoor lightning	29,075	4,305,670	0		0.1481
22	Outdoor Lighting OAD	2	263	0		0.1315
23	Small General Service	3,542	530,830	558	6,348	0.1499
24	Small General Service TOD	576	90,996	65	8,862	0.1580
25	Street Light Customer Owned Metered	5,610	266,304	563	9,964	0.0475
26	Street Light Service	81	24,363	4	20,250	0.3008
27	Estimated	11,515	628,866			0.0546
28	Rider
29	MI Credit
30	Misc Revenue Adjustment
31	Refund
32	Unrecovered Fuel		11,751,286
33	Water and Sewage Service	158,753	13,917,512	691	229,744	0.0877
41	TOTAL Billed Small or Commercial	4,702,550	563,678,082	72,655	64,724	0.1199
42	TOTAL Unbilled Rev. Small or Commercial (See Instr. 6)	37,235	4,547,674			0.1221
43	TOTAL Small or Commercial	4,739,785	568,225,756	72,655	65,237	0.1199

Name of Respondent:

Indiana Michigan 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	Electric Heating General	394	56,116	7	56,286	0.1424
2	Medium General Service	393,421	64,550,216	3,466	113,509	0.1641
3	Medium General Service - TOD	3,289	417,989	53	62,057	0.1271
4	Medium General Service OAD	7,199	414,402	11	654,455	0.0576
5	Medium General Service Flat	276	71,040	2	138,000	0.2574
6	Large General Service	1,109,781	124,249,634	1,078	1,029,481	0.1120
7	Large General Service - TOD	2,585	322,463	9	287,222	0.1247
8	Large General Service OAD	82	5,395	1	82,000	0.0658
9	Large Power	369,705	33,533,782	20	18,485,250	0.0907
10	Large Power OAD	101,633	2,448,930	3	33,877,667	0.0241
11	Industrial Service	5,144,737	367,001,459	167	30,806,808	0.0713
12	Water & Sewage Service	4,077	372,835	7	582,429	0.0914
13	Outdoor Lighting	6,112	830,601			0.1359
14	Energy Conserv Lighting	36	4,710	1	36,000	0.1308
15	Estimated Revenue	202,954	11,764,923	1	202,954,000	0.0580
16	Large General Service OAD Self Supply	76	3,681	1	76,000	0.0484
17	Large Power OAD Self Supply	123,289	853,731	3	41,096,333	0.0069
18	Medium General Service OAD Self Supply	124	6,070	2	62,000	0.0490
19	Rider
20	MI Credit
21	Misc Revenue Adjustment
22	Refund
23	Unrecovered Fuel		19,905,167
24	Outdoor Lighting OAD	4	375			0.0938
25	Small General Service	24	3,343	2	12,000	0.1393
41	TOTAL Billed Large (or Ind.) Sales	7,469,798	626,816,862	4,832	1,545,902	0.0839
42	TOTAL Unbilled Rev. Large (or Ind.) (See Instr. 6)	22,313	2,815,495			0.1262
43	TOTAL Large (or Ind.)	7,492,111	629,632,357	4,832	1,550,520	0.0840

Name of Respondent:

Indiana Michigan 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:

Indiana Michigan 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	Small General Service	148	27,344	69	2,145	0.1848
2	Medium General Service TOD	172	30,943	40	4,300	0.1799
3	Ft Wayne Street Lighting	21,108	613,819	1	21,108,000	0.0291
4	Energy Conservation Lighting	17,882	2,576,102	206	86,806	0.1441
5	Street Light - Customer Owned	5,699	265,059	403	14,141	0.0465
6	Street Lighting Service	7,096	701,018	80	88,700	0.0988
7	Municipal & School Service	254	43,360	33	7,697	0.1707
8	Outdoor Lighting	422	62,221			0.1474
9	Medium General Service	2,780	695,539	1,065	2,610	0.2502
10	Indiana Riders
11	MI Credit
12	Misc Revenue Adjustment
13	Refund
14	Unrecovered Fuel		140,316
41	TOTAL Billed Public Street and Highway Lighting	55,561	5,155,721	1,897	29,289	0.0928
42	TOTAL Unbilled Rev. (See Instr. 6)	53	7,928			0.1496
43	TOTAL	55,614	5,163,649	1,897	29,317	0.0928

Name of Respondent:

Indiana Michigan 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		27,927,976

Name of Respondent:

Indiana Michigan 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	17,692,444	2,060,518,510	607,734	29,112	0.1165
42	TOTAL Unbilled Rev. (See Instr. 6) - All Accounts	102,657	14,879,724			0.1449
43	TOTAL - All Accounts	17,795,101	2,075,398,234	607,734	29,112	0.1166

Name of Respondent:

Indiana Michigan 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	ADJUSTMENT	OS	SEE FOOTNOTE				0		570		570
2	AMEREX POWER, LTD	OS	(b) NOTE 1				0		54		54
3	CITIGROUP ENERGY INC.	OS	NOTE 1				0		5,143		5,143
4	CITY OF AUBURN	RQ	NOTE 1				420,654	25,017,837	17,808,461		42,826,298
5	CITY OF DOWAGIAC, MI	RQ	NOTE 1				58,485	3,438,992	2,628,773		6,067,765
6	EVOLUTION MARKETS FUTURES, LLC	OS	NOTE 1				0		1,564		1,564
7	FIRSTENERGY TRADING SERVICES	OS	NOTE 1				10,462		431,937		431,937
8	INDIANA MUNICIPAL POWER AGENCY	RQ	NOTE 1				1,603,277	73,582,668	57,717,232		131,299,900
9	(a) OHIO POWER COMPANY (AUCTION)	OS	(c) NOTE 1				42		1,202		1,202
10	PJM INTERCONNECTION	OS	NOTE 1				4,999,233	6,020,279	331,002,064		337,022,342
11	PJM INTERCONNECTION	RQ	VARIOUS				0			(d) 51,530,749	51,530,749
12	PPL ELECTRIC UTILITIES CORP	OS	NOTE 1				3		141		141
13	RBC CAPITAL MARKET, LLC	OS	NOTE 1				0		4,171		4,171
14	WABASH VALLEY POWER ASSN INC.	RQ	NOTE 1				827,322	47,376,584	34,808,459		82,185,043
15	WELLS FARGO SECURITIES, LLC	OS	NOTE 1				0		7,415,035		7,415,035
15	Subtotal - RQ						2,909,739	149,416,081	112,962,926	51,530,749	210,848,258
16	Subtotal-Non-RQ						5,009,650	6,020,279	324,007,261		330,027,539
17	Total						7,919,389	155,436,360	436,970,186	51,530,749	540,875,798

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: NameOfCompanyOrPublicAuthorityReceivingElectricityPurchasedForResale

An affiliated company.

(b) Concept: RateScheduleTariffNumber

FERC Electric Tariff, First Revised Volume No. 5.

(c) Concept: RateScheduleTariffNumber

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

(d) Concept: OtherChargesRevenueSalesForResale

PJM transmission expenses related to wholesale customers.

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line No.	Account (a)	Amount for Current Year (b)	Amount for Previous Year (c) (c)
1	PowerProductionExpensesAbstract 1. POWER PRODUCTION EXPENSES
2	SteamPowerGenerationAbstract A. Steam Power Generation
3	SteamPowerGenerationOperationAbstract Operation
4	OperationSupervisionAndEngineeringSteamPowerGeneration (500) Operation Supervision and Engineering	5,350,344	4,706,248
5	FuelSteamPowerGeneration (501) Fuel	(a) 104,980,675	83,441,345
6	SteamExpensesSteamPowerGeneration (502) Steam Expenses	2,823,092	13,397,833
7	SteamFromOtherSources (503) Steam from Other Sources
8	SteamTransferredCredit (Less) (504) Steam Transferred-Cr.
9	ElectricExpensesSteamPowerGeneration (505) Electric Expenses	1,797,808	1,378,594
10	MiscellaneousSteamPowerExpenses (506) Miscellaneous Steam Power Expenses	2,531,788	3,059,605
11	RentsSteamPowerGeneration (507) Rents	68,904,440	68,652,193
12	Allowances (509) Allowances	190,327	161,666
13	SteamPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 4 thru 12)	186,578,473	174,797,483
14	SteamPowerGenerationMaintenanceAbstract Maintenance
15	MaintenanceSupervisionAndEngineeringSteamPowerGeneration (510) Maintenance Supervision and Engineering	1,804,441	2,304,616
16	MaintenanceOfStructuresSteamPowerGeneration (511) Maintenance of Structures	844,677	753,015
17	MaintenanceOfBoilerPlantSteamPowerGeneration (512) Maintenance of Boiler Plant	6,382,407	7,782,312
18	MaintenanceOfElectricPlantSteamPowerGeneration (513) Maintenance of Electric Plant	2,866,105	2,949,190
19	MaintenanceOfMiscellaneousSteamPlant (514) Maintenance of Miscellaneous Steam Plant	854,511	1,135,393
20	SteamPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 15 thru 19)	12,752,140	14,924,525
21	PowerProductionExpensesSteamPower TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)	199,330,613	189,722,008
22	NuclearPowerGenerationAbstract B. Nuclear Power Generation
23	NuclearPowerGenerationOperationAbstract Operation
24	OperationSupervisionAndEngineeringNuclearPowerGeneration (517) Operation Supervision and Engineering	(b) 12,222,139	18,443,254
25	NuclearFuelExpense (518) Fuel	86,277,041	87,999,744
26	CoolantsAndWater (519) Coolants and Water	4,784,937	6,989,349
27	SteamExpensesNuclearPowerGeneration (520) Steam Expenses	12,622,438	14,959,293
28	SteamFromOtherSourcesNuclearPowerGeneration (521) Steam from Other Sources
29	SteamTransferredCreditNuclearPowerGeneration (Less) (522) Steam Transferred-Cr.
30	ElectricExpensesNuclearPowerGeneration (523) Electric Expenses	4,748,217	5,868,035
31	MiscellaneousNuclearPowerExpenses (524) Miscellaneous Nuclear Power Expenses	(c) 75,919,581	69,106,183
32	RentsNuclearPowerGeneration (525) Rents
33	NuclearPowerGenerationOperationsExpense TOTAL Operation (Enter Total of lines 24 thru 32)	196,574,353	203,365,857
34	NuclearPowerGenerationMaintenanceAbstract Maintenance
35	MaintenanceSupervisionAndEngineeringNuclearPowerGeneration (528) Maintenance Supervision and Engineering	3,183,294	5,806,989
36	MaintenanceOfStructuresNuclearPowerGeneration (529) Maintenance of Structures	4,025,143	5,982,218
37	MaintenanceOfReactorPlantEquipmentNuclearPowerGeneration (530) Maintenance of Reactor Plant Equipment	92,579,730	65,392,064
38	MaintenanceOfElectricPlantNuclearPowerGeneration (531) Maintenance of Electric Plant	15,339,706	17,075,346
39	MaintenanceOfMiscellaneousNuclearPlant (532) Maintenance of Miscellaneous Nuclear Plant	17,398,562	16,886,003
40	NuclearPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 35 thru 39)	132,526,435	111,142,620
41	PowerProductionExpensesNuclearPower TOTAL Power Production Expenses-Nuclear. Power (Enter Total of lines 33 & 40)	329,100,788	314,508,478
42	HydraulicPowerGenerationAbstract C. Hydraulic Power Generation
43	HydraulicPowerGenerationOperationAbstract Operation
44	OperationSupervisionAndEngineeringHydraulicPowerGeneration (535) Operation Supervision and Engineering	424,373	220,338
45	WaterForPower (536) Water for Power
46	HydraulicExpenses (537) Hydraulic Expenses	138,025	74,927
47	ElectricExpensesHydraulicPowerGeneration (538) Electric Expenses	52,927	66,129
48	MiscellaneousHydraulicPowerGenerationExpenses (539) Miscellaneous Hydraulic Power Generation Expenses	1,048,792	1,036,000
49	RentsHydraulicPowerGeneration (540) Rents	21	148
50	HydraulicPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 44 thru 49)	1,664,138	1,397,542
51	HydraulicPowerGenerationContinuedAbstract C. Hydraulic Power Generation (Continued)
52	HydraulicPowerGenerationMaintenanceAbstract Maintenance
53	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration (541) Mainentance Supervision and Engineering	151,765	156,290
54	MaintenanceOfStructuresHydraulicPowerGeneration (542) Maintenance of Structures	937,663	981,805
55	MaintenanceOfReservoirsDamsAndWaterways (543) Maintenance of Reservoirs, Dams, and Waterways	649,891	123,885
56	MaintenanceOfElectricPlantHydraulicPowerGeneration (544) Maintenance of Electric Plant	224,758	174,757
57	MaintenanceOfMiscellaneousHydraulicPlant (545) Maintenance of Miscellaneous Hydraulic Plant	47,417	79,747
58	HydraulicPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 53 thru 57)	2,011,494	1,516,483
59	PowerProductionExpensesHydraulicPower TOTAL Power Production Expenses-Hydraulic Power (Total of Lines 50 & 58)	3,675,632	2,914,025
60	OtherPowerGenerationAbstract D. Other Power Generation
61	OtherPowerGenerationOperationAbstract Operation
62	OperationSupervisionAndEngineeringOtherPowerGeneration (546) Operation Supervision and Engineering	2,622	56,288
63	Fuel (547) Fuel
64	GenerationExpenses (548) Generation Expenses	5,372	9,992
64.1	OperationOfEnergyStorageEquipment (548.1) Operation of Energy Storage Equipment
65	MiscellaneousOtherPowerGenerationExpenses (549) Miscellaneous Other Power Generation Expenses	708,476	3,303,995
66	RentsOtherPowerGeneration (550) Rents	38	20
67	OtherPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 62 thru 67)	705,764	3,370,295
68	OtherPowerGenerationMaintenanceAbstract Maintenance
69	MaintenanceSupervisionAndEngineeringOtherPowerGeneration (551) Maintenance Supervision and Engineering	35	4,436
70	MaintenanceOfStructures (552) Maintenance of Structures
71	MaintenanceOfGeneratingAndElectricPlant (553) Maintenance of Generating and Electric Plant	82	32
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)	47	4,468
74	PowerProductionExpensesOtherPower TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)	705,811	3,374,763
75	OtherPowerSuplyExpensesAbstract E. Other Power Supply Expenses
76	PurchasedPower (555) Purchased Power	700,037,070	425,317,314
76.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations	0
77	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching	1,343,263	1,310,915
78	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	3,252,637	3,785,672
79	OtherPowerSupplyExpense TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)	704,632,971	430,413,901
80	PowerProductionExpenses TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74 & 79)	1,237,445,815	940,933,175
81	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
82	TransmissionExpensesOperationAbstract Operation
83	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	7,602,380	6,626,598
85	LoadDispatchReliability (561.1) Load Dispatch-Reliability
86	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	199,189	220,980
87	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling
88	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services	4,667,162	4,380,265
89	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development	174,620	303,852
90	TransmissionServiceStudies (561.6) Transmission Service Studies
91	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies
92	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services	1,326,518	1,275,988
93	StationExpensesTransmissionExpense (562) Station Expenses	(d) 579,819	534,639
93.1	OperationOfEnergyStorageEquipmentTransmissionExpense (562.1) Operation of Energy Storage Equipment
94	OverheadLineExpense (563) Overhead Lines Expenses	440,838	374,532
95	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses	4,276	3,244
96	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	228,618,743	194,809,250
97	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	2,115,573	3,361,124
98	RentsTransmissionElectricExpense (567) Rents	632,646	1,026,071
99	TransmissionOperationExpense TOTAL Operation (Enter Total of Lines 83 thru 98)	246,361,764	212,916,543
100	TransmissionMaintenanceAbstract Maintenance
101	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering	73,888	29,383
102	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	29,558	238,965
103	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware	(e) 11,815	15,270
104	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software	508,218	444,405
105	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment	55,255	70,960
106	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	1,569,678	2,872,340
107.1	MaintenanceOfEnergyStorageEquipmentTransmission (570.1) Maintenance of Energy Storage Equipment
108	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	9,462,828	16,362,132
109	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines	72,523	8,669
110	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant	17,578	21,519
111	TransmissionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 101 thru 110)	11,801,340	20,063,643
112	TransmissionExpenses TOTAL Transmission Expenses (Total of Lines 99 and 111)	258,163,103	232,980,186
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	4,361,546	4,830,186
122	RentsRegionalMarketExpenses (575.8) Rents
123	RegionalMarketOperationExpense Total Operation (Lines 115 thru 122)	4,361,546	4,830,186
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)	4,361,546	4,830,186
132	DistributionExpensesAbstract 4. DISTRIBUTION EXPENSES
133	DistributionExpensesOperationAbstract Operation
134	OperationSupervisionAndEngineeringDistributionExpense (580) Operation Supervision and Engineering	2,774,673	2,914,527
135	LoadDispatching (581) Load Dispatching	314,897	368,317
136	StationExpensesDistribution (582) Station Expenses	1,731,458	1,122,761
137	OverheadLineExpenses (583) Overhead Line Expenses	1,709,069	1,845,869
138	UndergroundLineExpenses (584) Underground Line Expenses	4,528,651	4,084,291
138.1	OperationOfEnergyStorageEquipmentDistribution (584.1) Operation of Energy Storage Equipment
139	StreetLightingAndSignalSystemExpenses (585) Street Lighting and Signal System Expenses	162,478	185,720
140	MeterExpenses (586) Meter Expenses	1,299,275	2,340,412
141	CustomerInstallationsExpenses (587) Customer Installations Expenses	411,040	248,067
142	MiscellaneousDistributionExpenses (588) Miscellaneous Expenses	14,410,723	10,626,921
143	RentsDistributionExpense (589) Rents	1,345,964	2,077,482
144	DistributionOperationExpensesElectric TOTAL Operation (Enter Total of Lines 134 thru 143)	28,688,228	25,814,366
145	DistributionExpensesMaintenanceAbstract Maintenance
146	MaintenanceSupervisionAndEngineering (590) Maintenance Supervision and Engineering	66,897	66,102
147	MaintenanceOfStructuresDistributionExpense (591) Maintenance of Structures	82,245	64,315
148	MaintenanceOfStationEquipment (592) Maintenance of Station Equipment	(f) 1,291,895	1,955,271
148.1	MaintenanceOfEnergyStorageEquipment (592.2) Maintenance of Energy Storage Equipment
149	MaintenanceOfOverheadLines (593) Maintenance of Overhead Lines	52,656,226	45,667,608
150	MaintenanceOfUndergroundLines (594) Maintenance of Underground Lines	1,482,024	1,961,672
151	MaintenanceOfLineTransformers (595) Maintenance of Line Transformers	339,024	268,535
152	MaintenanceOfStreetLightingAndSignalSystems (596) Maintenance of Street Lighting and Signal Systems	220,363	513,305
153	MaintenanceOfMeters (597) Maintenance of Meters	60,357	100,291
154	MaintenanceOfMiscellaneousDistributionPlant (598) Maintenance of Miscellaneous Distribution Plant	409,576	253,771
155	DistributionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 146 thru 154)	56,608,607	50,850,870
156	DistributionExpenses TOTAL Distribution Expenses (Total of Lines 144 and 155)	85,296,835	76,665,236
157	CustomerAccountsExpensesAbstract 5. CUSTOMER ACCOUNTS EXPENSES
158	CustomerAccountsExpensesOperationsAbstract Operation
159	SupervisionCustomerAccountExpenses (901) Supervision	753,260	865,460
160	MeterReadingExpenses (902) Meter Reading Expenses	1,066,546	969,647
161	CustomerRecordsAndCollectionExpenses (903) Customer Records and Collection Expenses	14,512,471	14,950,761
162	UncollectibleAccounts (904) Uncollectible Accounts	77,586	106,136
163	MiscellaneousCustomerAccountsExpenses (905) Miscellaneous Customer Accounts Expenses	47,163	79,628
164	CustomerAccountExpenses TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)	16,301,854	16,759,359
165	CustomerServiceAndInformationalExpensesAbstract 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166	CustomerServiceAndInformationalExpensesOperationAbstract Operation
167	SupervisionCustomerServiceAndInformationExpenses (907) Supervision	1,030,457	1,044,496
168	CustomerAssistanceExpenses (908) Customer Assistance Expenses	6,006,322	5,662,724
169	InformationalAndInstructionalAdvertisingExpenses (909) Informational and Instructional Expenses
170	MiscellaneousCustomerServiceAndInformationalExpenses (910) Miscellaneous Customer Service and Informational Expenses	49,601	77,580
171	CustomerServiceAndInformationExpenses TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)	7,086,379	6,784,801
172	SalesExpenseAbstract 7. SALES EXPENSES
173	SalesExpenseOperationAbstract Operation
174	SupervisionSalesExpense (911) Supervision
175	DemonstratingAndSellingExpenses (912) Demonstrating and Selling Expenses	182,086	256,658
176	AdvertisingExpenses (913) Advertising Expenses	412,478	265,759
177	MiscellaneousSalesExpenses (916) Miscellaneous Sales Expenses
178	SalesExpenses TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)	594,564	522,418
179	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
180	AdministrativeAndGeneralExpensesOperationAbstract Operation
181	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	42,279,429	42,503,580
182	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	3,843,628	3,510,368
183	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit	5,223,954	4,707,801
184	OutsideServicesEmployed (923) Outside Services Employed	13,172,983	7,706,437
185	PropertyInsurance (924) Property Insurance	(g) 7,253,258	6,038,182
186	InjuriesAndDamages (925) Injuries and Damages	5,276,819	10,459,369
187	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	8,278,261	18,528,510
188	FranchiseRequirements (927) Franchise Requirements
189	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	18,754,857	20,994,470
190	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.	1,318,983	1,082,547
191	GeneralAdvertisingExpenses (930.1) General Advertising Expenses	204,699	230,754
192	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	5,432,218	5,443,944
193	RentsAdministrativeAndGeneralExpense (931) Rents	3,055,547	3,120,314
194	AdministrativeAndGeneralOperationExpense TOTAL Operation (Enter Total of Lines 181 thru 193)	86,502,247	100,669,217
195	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
196	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	11,236,575	11,470,966
197	AdministrativeAndGeneralExpenses TOTAL Administrative & General Expenses (Total of Lines 194 and 196)	97,738,822	112,140,183
198	OperationsAndMaintenanceExpensesElectric TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 156, 164, 171, 178, and 197)	1,706,988,919	1,391,615,543

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: FuelSteamPowerGeneration

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

(b) Concept: OperationSupervisionAndEngineeringNuclearPowerGeneration

The portion of account 518 that is exclude from the nuclear fuel costs in I&M's generation formula rate is identified by a query of the general ledger

(c) Concept: MiscellaneousNuclearPowerExpenses

The portion of account 524 representing ARO expense that are excluded from non-fuel generation formula rate is identified by a query of the general ledger.The nuclear decommissioning expense allowed in the formula is an amount approved by the Indiana utility Regulatory Commission

(d) Concept: StationExpensesTransmissionExpense

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

(e) Concept: MaintenanceOfComputerHardwareTransmission

Allocated maintenance expenses 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.

(f) Concept: MaintenanceOfStationEquipment

Account 592.2 contains $452.82 for maintenance of energy storage equipment.

(g) Concept: PropertyInsurance

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

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

PURCHASED POWER (Account 555)
Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years. SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less. LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years. EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges. OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each adjustment. AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. Report in column (g) the megawatthours shown on bills rendered to the respondent, excluding purchases for energy storage. Report in column (h) the megawatthours shown on bills rendered to the respondent for energy storage purchases. Report in columns (i) and (j) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. Report demand charges in column (k), energy charges in column (l), and the total of any other types of charges, including out-of-period adjustments, in column (m). Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (n) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (m) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. The data in columns (g) through (n) must be totaled on the last line of the schedule. The total amount in columns (g) and (h) must be reported as Purchases on Page 401, line 10. The total amount in column (i) must be reported as Exchange Received on Page 401, line 12. The total amount in column (j) must be reported as Exchange Delivered on Page 401, line 13. Footnote entries as required and provide explanations following all required data.
					Actual Demand (MW)				POWER EXCHANGES		COST/SETTLEMENT OF POWER
Line No.	NameOfCompanyOrPublicAuthorityProvidingPurchasedPower Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	RateScheduleTariffNumber Ferc Rate Schedule or Tariff Number (c)	AverageMonthlyBillingDemand Average Monthly Billing Demand (MW) (d)	AverageMonthlyNonCoincidentPeakDemand Average Monthly NCP Demand (e)	AverageMonthlyCoincidentPeakDemand Average Monthly CP Demand (f)	MegawattHoursPurchasedOtherThanStorage MegaWatt Hours Purchased (Excluding for Energy Storage) (g)	MegawattHoursPurchasedForEnergyStorage MegaWatt Hours Purchased for Energy Storage (h)	EnergyReceivedThroughPowerExchanges MegaWatt Hours Received (i)	EnergyDeliveredThroughPowerExchanges MegaWatt Hours Delivered (j)	DemandChargesOfPurchasedPower Demand Charges ($) (k)	EnergyChargesOfPurchasedPower Energy Charges ($) (l)	OtherChargesOfPurchasedPower Other Charges ($) (m)	SettlementOfPower Total (k+l+m) of Settlement ($) (n)
1	(a) AEP GENERATING COMPANY	RQ					1,970,151				151,496,780	77,557,168		229,053,948
2	CITY OF WINCHESTER, IN	OS					0					44,086		44,086
3	FOWLER RIDGE II WIND FARM LLC	OS					117,511					11,805,898		11,805,898
4	FOWLER RIDGE WIND FARM LLC	OS					198,788					14,759,543		14,759,543
5	FRENCH PAPER	OS					48					2,538		2,538
6	FT. WAYNE ELECTRIC JATC	OS					0					2		2
7	HEADWATERS WIND FARM LLC	OS					683,886					31,511,269		31,511,269
8	ICE TRADE VAULT LLC	OS					0
9	OVEC POWER SCHEDULING	OS					867,245				30,528,689	29,162,563		59,691,252
10	(b) OVER/UNDER PJM EXP TRACKER	OS					0					49,315,159		49,315,159
11	(c) OVER/UNDER RESOURCE ADEQUACY	OS					1,117				150,040	150,374		334
12	PJM INTERCONNECTION	OS					3,274,346				439,748	274,239,319		274,679,067
13	WILDCAT WIND FARM	OS					352,606					29,169,387		29,169,387
14	WILLIAM E RICHTER	OS					0					4,587		4,587
15	TOTAL						7,465,698	0	0	0	182,315,177	517,721,893		700,037,070

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: NameOfCompanyOrPublicAuthorityProvidingPurchasedPower

Affiliated Company

(b) Concept: NameOfCompanyOrPublicAuthorityProvidingPurchasedPower

Per the IURC's Order in Cause No. 45235, I&M tracks the recovery of certain costs and revenues related to I&M’s membership in PJM compared to the level in base rates.

(c) Concept: NameOfCompanyOrPublicAuthorityProvidingPurchasedPower

Over-/Under-recovery accounting to track incremental changes in the Company's purchased power costs, per the IURC's Order in Cause No. 45235.

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

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

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

TRANSFER OF ENERGY

REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS

Line No.

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

(m)

(n)

1

PJM Network Integ Trans Rev Whlsle

Various

FNO

(a)

PJM OATT

Various

5,903,563

2

PJM Network Integ Trans Serv

Various

FNO

PJM OATT

Various

24,330,070

3

PJM Trans Enhancement Rev

Various

FNO

PJM OATT

Various

3,966,508

4

PJM Trans Enhancement Rev Whlsle

Various

FNO

PJM OATT

Various

127,304

5

PJM Network Integ Rev - Affil

Various

FNO

PJM OATT

Various

9,924,968

6

PJM Point to Point Trans Service

Various

LFP

PJM OATT

Various

5,707,117

7

PJM Trans Owner Admin Revenue

Various

OLF

PJM OATT

Various

47,927

8

PJM Trans Owner Serv Rev Whlsle

Various

OLF

PJM OATT

Various

29,756

9

PJM Power Factor Credits Rev Whlsle

Various

OS

PJM OATT

Various

(b)

21,427

10

PJM Trans Distribution & Metering

Various

OS

PJM OATT

Various

(c)

818,476

11

PJM Power Factor Credits Rev Nonaffiliated

Various

OS

PJM OATT

Various

(d)

480,173

12

PJM Trans Owner Admin Rev - Affil

Various

OLF

PJM OATT

Various

311,021

35

TOTAL

0

49,959,530

233,338

1,320,076

51,512,944

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: RateScheduleTariffNumber

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

(b) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

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

(c) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

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

(d) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

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

Name of Respondent:

Indiana Michigan 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:

Indiana Michigan 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) 22,452,974	22,452,974
2	PJM NITS	OS					(b) 205,780,043	205,780,043
3	PJM-Trans Owner Serv	OS					(c) 385,726	385,726
	TOTAL		0	0	0	0	228,618,743	228,618,743

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

Name of Respondent:

Indiana Michigan 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	3,193,492
2	NuclearPowerResearchExpenses Nuclear Power Research Expenses
3	OtherExperimentalAndGeneralResearchExpenses Other Experimental and General Research Expenses	1,285
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	1,238,203
7	American Electric Power Service Corp Billings	1,016,765
8	Corporate Money Pool Allocations	109,963
9	Corporate Legal and Financing	84,748
10	Corporate Contributions and Memberships	81,473
11	Intercompany Billings	287,952
12	Minor iItems	5,759
46	MiscellaneousGeneralExpenses TOTAL	5,432,218

Name of Respondent:

Indiana Michigan 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			49,516,732		49,516,732
2	Steam Production Plant	96,365,162	711,594	12,071,722		109,148,478
3	Nuclear Production Plant	154,368,140	562,014			154,930,154
4	Hydraulic Production Plant-Conventional	1,982,978	13,511			1,996,489
5	Hydraulic Production Plant-Pumped Storage
6	Other Production Plant	3,314,462				3,314,462
7	Transmission Plant	46,071,134				46,071,134
8	Distribution Plant	89,094,325	2,968,296			92,062,621
9	Regional Transmission and Market Operation
10	General Plant	7,209,366	29,583	259,939		7,498,888
11	Common Plant-Electric
12	TOTAL	398,405,567	4,284,998	61,848,393		464,538,958

B. Basis for Amortization Charges
Section A, Line 1, Column D represents amortization of franchises over the life of the franchise, amorization of capitalized software development cost over a 5 year life and the amortization of costs associated with the Oracle strategic partnership over a 10 year life. Section A, Line 2, Column D represents amortization of Rockport Unit 2 Leasehold Improvements over the life of Rockport Unit 2 Lease. Section A, Line 10, Column D represents amortization of leasehold improvements over the lives of the related assets.

	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
13	311 - Rockport U1	98.807	44 years	2	9.05
14	311 - Rockport U2	4.569	39 years	2	1.55
15	311 - Rkpt DSI U1	2.905	44 years	2	8.69
16	311 - Rkpt DSI U2	0.787	39 years	2	2.39
17	312 - Rockport ACI	11.833	44 years	2	9.42
18	312 - Rockport U1	425.686	44 years	2	9.63
19	312 - Rockport U2	26.229	39 years	2	1.62
20	312 - Rockport U1 -SCR	134.682	44 years	2	10.09
21	312 - Rockport U2 -SCR	112.388	39 years	2	3.65
22	312 - Rkpt DSI U1	51.74	44 years	2	9.5
23	312 - Rkpt DSI U1 - Pre	24.807	44 years	2	9.63
24	312 - Rkpt DSI U2	54.116	39 years	2	2.41
25	314 - Rockport U1	105.793	44 years	2	9.66
26	314 - Rockport U2	0.867	39 years	2	1.64
27	315 - Rockport U1	59.153	44 years	2	8.98
28	315 - Rockport U2	2.088	39 years	2	1.58
29	316 - Rockport U1	17.992	44 years	2	9.52
30	316 - Rockport U1-SCR	0.008	44 years	2	10.17
31	316 - Rockport U2	6.845	39 years	2	1.54
32	TOTAL STEAM	1,141.295
33	NUCLEAR
34	321 - Cook U1	85.994	59 years	1	3.51
35	321 - Cook U2	373.956	59 years	2	3.51
36	322 - Cook U1	770.339	59 years	3	4.71
37	322 - Cook U2	1,017.668	59 years	3	4.18
38	323 - Cook U1	304.544	59 years	3	5.34
39	323 - Cook U2	411.59	59 years	4	5.02
40	324 - Cook U1	144.481	59 years		4.21
41	324 - Cook U2	204.864	59 years		4.07
42	325 - Cook U1	34.577	59 years		4.65
43	325 - Cook U2	251.271	59 years		4.09
44	TOTAL NUCLEAR	3,599.284
45	HYDRO
46	331 - Berrien Springs	1.982	128 years	4	3.7
47	331 - Buchanan	0.61	117 years	4	3.77
48	331 - Constantine	0.35	132 years	17	2.45
49	331 - Crew Service Center	0.417	0 years	5	1.45
50	331 - Elkhart	1.049	117 years	2	4.95
51	331 - Mottville	0.766	110 years	4	4.11
52	331 - Twin Branch	0.865	132 years	5	4.02
53	332 - Berrien Springs	5.409	128 years	4	3.03
54	332 - Buchanan	4.759	117 years	4	2.9
55	332 - Constantine	1.229	132 years	17	2.35
56	332 - Elkhart	7.085	117 years	2	5.47
57	332 - Mottville	2.188	110 years	4	3.5
58	332 - Twin Branch	5.102	132 years	5	3.36
59	333 - Berrien Springs	7.178	128 years	4	3.43
60	333 - Buchanan	1.536	117 years	4	2.82
61	333 - Constantine	0.737	132 years	17	2.29
62	333 - Elkhart	0.562	117 years	2	4.16
63	333 - Mottville	0.605	110 years	4	3.26
64	333 - Twin Branch	5.998	132 years	5	3.64
65	334 - Berrien Springs	1.215	128 years	4	3.26
66	334 - Buchanan	1.024	117 years	4	3.08
67	334 - Constantine	0.499	132 years	17	2.96
68	334 - Elkhart	0.494	117 years	2	4.23
69	334 - Mottville	0.75	110 years	4	3.99
70	334 - Twin Branch	1.741	132 years	5	3.54
71	335 - Berrien Springs	0.804	128 years	4	3.64
72	335 - Buchanan	0.288	117 years	4	3.77
73	335 - Constantine	0.353	132 years	17	3.04
74	335 - Crew Service Center	0.127	0 years	5	1.43
75	335 - Elkhart	0.224	117 years	2	6.33
76	335 - Mottville	0.387	110 years	4	4.99
77	335 - Twin Branch	0.66	132 years	5	4.47
78	336 - Mottville	0.001	110 years	4	2.48
79	TOTAL HYDRO	67.868
80	OTHER GENERATION
81	341 - Olive Solar	0.377	20 years	3	5.32
82	341 - Watervliet Solar	0.358	20 years	3	5.31
83	344 - Deer Creek Solar	5.668	20 years	3	5.35
84	344 - Olive Solar	11.185	20 years	3	5.32
85	344 - South Bend Solar	27.732	0 years		3.4
86	344 - Twin Branch Solar	6.955	20 years	4	5.36
87	344 - Watervliet Solar	11.107	20 years	3	5.31
88	345 - Deer Creek Solar	0.721	20 years	3	6.21
89	345 - Olive Solar	0.269	20 years	3	5.32
90	345 - South Bend Solar	4.121	0 years		3.4
91	346 - Deer Creek Solar	0.011	20 years	3	6.82
92	346 - Olive Solar	0.215	20 years	3	5.32
93	346 - South Bend Solar	0.217	0 years		3.4
94	346 - Watervliet Solar	0.354	20 years	3	5.32
95	TOTAL OTHER	17.015
96	TRANSMISSION
97	350 (Rights)	63.713	65 years		1.72	R5
98	352	80.186	65 years	10	1.75	L1.5
99	353	855.581	44 years	10	2.6	L1
100	353.16	13.714	44 years	10	2.6	L1
101	354	231.336	66 years	39	2.73	R5
102	355	243.823	50 years	64	3.33	L0.5
103	356	313.407	67 years	35	2.32	R4
104	356.16	0.563	67 years	35	2.32	R4
105	357	9.021	55 years		2.24	R5
106	358	8.132	60 years	13	2.01	L1.5
107	359	0.091	65 years		1.75	R5
108	TOTAL TRANSMISSION	1,819.567
109	DISTRIBUTION
110	360 (Rights) - IN	12.733	65 years		1.44	R5
111	360 (Rights) - MI	6.349	65 years		1.53	R5
112	361 - IN	43.011	65 years	25	1.96	R1.5
113	361 - MI	6.394	71 years	12	1.56	R2
114	362 - IN	412.641	46 years	12	2.56	L0.5
115	362 - MI	107.403	49 years	6	2.24	L0
116	362.16 - IN	6.608	46 years	12	2.56	L0.5
117	362.16 - MI	1.328	49 years	6	2.24	L0
118	363 - IN	5.607	15 years		9.09	SQ
119	364 - IN	293.492	48 years	87	3.56	L0
120	364 - MI	96.841	35 years	81	5.02	L0
121	365 - IN	476.938	48 years	16	2.26	L0
122	365 - MI	156.347	35 years	13	3.38	L0
123	366 - IN	165.881	71 years		1.37	R2
124	366 - MI	16.099	56 years		1.75	R2
125	367 - IN	278.397	60 years		1.65	R1
126	367 - MI	40.847	52 years		1.71	R1
127	368 - IN	346.487	35 years	8	2.43	R0.5
128	368 - MI	58.749	21 years	6	5.41	R0.5
129	369 - IN	184.629	50 years	24	2.25	R0.5
130	369 - MI	36.585	40 years	22	3.05	R0.5
131	370 - IN	63.916	15 years	20	10.08	SQ
132	370 - MI	14.091	15 years	22	11.01	SQ
133	370 - AMI	81.966	0 years		10
134	371 - IN	22.483	17 years	23	4.9	L0
135	371 - MI	8.629	14 years	23	7.82	L0
136	373 - IN	24.082	22 years	18	3.75	R0.5
137	373 - MI	5.592	19 years	14	5.37	R0.5
138	TOTAL DISTRIBUTION	1,182.552
139	GENERAL PLANT
140	390	76.889	45 years	5	2.42	L1
141	391	5.703	22 years	3	5.3	SQ
142	392	0.068	0 years	5	4.65	L0
143	393	1.349	14 years		7.89	SQ
144	394	19.064	16 years		7.65	SQ
145	395	0.35	20 years	1	6.18	SQ
146	396	0.544	25 years		6.03	SQ
147	397	70.764	27 years	1	4.13	SQ
148	397.16	2.204	27 years	1	4.13	SQ
149	398	13.098	30 years	8	3.64	SQ
150	TOTAL GENERAL PLANT	190.033
151	DEPRECIABLE SUM	(a) 1,410.498

Name of Respondent:

Indiana Michigan 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:

Indiana Michigan 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	Nuclear Regulatory Commission - Inspection and Licensing Fees	1,728,377		1,728,377			928	1,728,377
2	Nuclear Regulatory Commission - Annual Fees	11,678,112		11,678,112			928	11,678,112
3	Hydro License Fee		40,830	40,830			928	40,830
4	Indiana Rate Case		746,429	746,429	1,283,861		928	347,555	946,394	928	1,093,984	1,136,271
5	Michigan Rate Case		160,535	160,535	102,653		928	57,882	693,800	928	102,653	693,800
6	Integrated Resource Plan Filing		1,570,240	1,570,240			928	1,570,240
7	State Commission Fees	2,689,556		2,689,556			928	2,689,556
8	Minor Items < $25,000		140,778	140,778			928	140,778
46	TOTAL	16,096,045	2,658,812	18,754,857	1,386,514			17,558,220	1,640,194		1,196,637	1,830,071

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D and D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(Identify recipient regardless of affiliation.) For any R, D and D work carried with others, show separately the respondent's cost for the year and cost chargeable to others (See definition of research, development, and demonstration in Uniform System of Accounts). Indicate in column (a) the applicable classification, as shown below: Classifications: Electric R, D and D Performed Internally: Generation hydroelectric Recreation fish and wildlife Other hydroelectric Fossil-fuel steam Internal combustion or gas turbine Nuclear Unconventional generation Siting and heat rejection Transmission Overhead Underground Distribution Regional Transmission and Market Operation Environment (other than equipment) Other (Classify and include items in excess of $50,000.) Total Cost Incurred Electric, R, D and D Performed Externally: Research Support to the electrical Research Council or the Electric Power Research Institute Research Support to Edison Electric Institute Research Support to Nuclear Power Groups Research Support to Others (Classify) Total Cost Incurred Include in column (c) all R, D and D items performed internally and in column (d) those items performed outside the company costing $50,000 or more, briefly describing the specific area of R, D and D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.). Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D and D activity. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year, listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e). Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research, Development, and Demonstration Expenditures, Outstanding at the end of the year. If costs have not been segregated for R, D and D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by ""Est."" Report separately research and related testing facilities operated by the respondent.
					AMOUNTS CHARGED IN CURRENT YEAR
Line No.	ResearchDevelopmentAndDemonstrationClassification Classification (a)	ResearchDevelopmentAndDemonstrationDescription Description (b)	ResearchDevelopmentAndDemonstrationCostsIncurredInternally Costs Incurred Internally Current Year (c)	ResearchDevelopmentAndDemonstrationCostsIncurredExternally Costs Incurred Externally Current Year (d)	AccountNumberForResearchDevelopmentAndDemonstrationCosts Amounts Charged In Current Year: Account (e)	ResearchDevelopmentAndDemonstrationCosts Amounts Charged In Current Year: Amount (f)	ResearchDevelopmentAndDemonstrationExpenditures Unamortized Accumulation (g)
1	A(1)b: Generation: Fossil Fuel Steam	Generation Program Management	238,266		506,524	10,286
2		2 items < $50,000	11,013		506	238,993
3	A(1)e: Generation: Unconventional	1 item <$50,000	169		506	169
4	A(2): Transmission	1 item <$50,000	7,598		566	7,598
5	A(3): Distribution	1 item <$50,000	12,360		588	12,360
6	A(5): Environment (other than equipment)	2 items <$50,000	15,973		506	15,973
7	A(6): Other	2 items <$50,000	35,396		506,524,566,588	35,396
8	A(6)a:
9	A(6)f: Other: Metering	1 item <$50,000	1,682		588	1,682
10	A(6)g: Research-General	1 item <$50,000	3,159		566,588	3,159
11	A(7) TOTAL COSTS INCURRED INTERNALLY		325,616			325,616
12	B: Electric R&D External	5 items <$50,000		63,276	506,524,566,588	63,276
13	B(1): Research Support to Electric Research	EPRI Research Portfolio		523,156	506,566,588	523,156
14		EPRI Nuclear Annual Research		1,391,415	524	1,391,415
15		IT - EPRI Annual Research Port		111,823	506,524,566,588	111,823
16		EPRI Environmental Science		228,703	506	228,703
17		Low Carbon Resource Initiative		137,810	506,524,566,588	137,810
18		25 items <$50,000		45,266	506,524,566,588	45,266
19	(B4): Steam Power	1 item <$50,000		7,546	506	7,546
20	B(5) TOTAL COSTS INCURRED EXTERNALLY			2,508,995		2,508,995

Name of Respondent:

Indiana Michigan 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	76,135,842
4	SalariesAndWagesElectricOperationTransmission Transmission	2,232,831
5	SalariesAndWagesElectricOperationRegionalMarket Regional Market
6	SalariesAndWagesElectricOperationDistribution Distribution	8,093,432
7	SalariesAndWagesElectricOperationCustomerAccounts Customer Accounts	2,212,261
8	SalariesAndWagesElectricOperationCustomerServiceAndInformational Customer Service and Informational	3,433,470
9	SalariesAndWagesElectricOperationSales Sales
10	SalariesAndWagesElectricOperationAdministrativeAndGeneral Administrative and General	1,685,844
11	SalariesAndWagesElectricOperation TOTAL Operation (Enter Total of lines 3 thru 10)	93,793,680
12	SalariesAndWagesElectricMaintenanceAbstract Maintenance
13	SalariesAndWagesElectricMaintenanceProduction Production	59,721,721
14	SalariesAndWagesElectricMaintenanceTransmission Transmission	2,090,025
15	SalariesAndWagesElectricMaintenanceRegionalMarket Regional Market
16	SalariesAndWagesElectricMaintenanceDistribution Distribution	11,115,056
17	SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral Administrative and General	1,681,174
18	SalariesAndWagesElectricMaintenance TOTAL Maintenance (Total of lines 13 thru 17)	74,607,976
19	SalariesAndWagesElectricOperationAndMaintenanceAbstract Total Operation and Maintenance
20	SalariesAndWagesElectricProduction Production (Enter Total of lines 3 and 13)	135,857,563
21	SalariesAndWagesElectricTransmission Transmission (Enter Total of lines 4 and 14)	4,322,856
22	SalariesAndWagesElectricRegionalMarket Regional Market (Enter Total of Lines 5 and 15)
23	SalariesAndWagesElectricDistribution Distribution (Enter Total of lines 6 and 16)	19,208,488
24	SalariesAndWagesElectricCustomerAccounts Customer Accounts (Transcribe from line 7)	2,212,261
25	SalariesAndWagesElectricCustomerServiceAndInformational Customer Service and Informational (Transcribe from line 8)	3,433,470
26	SalariesAndWagesElectricSales Sales (Transcribe from line 9)
27	SalariesAndWagesElectricAdministrativeAndGeneral Administrative and General (Enter Total of lines 10 and 17)	3,367,018
28	SalariesAndWagesElectricOperationAndMaintenance TOTAL Oper. and Maint. (Total of lines 20 thru 27)	168,401,656	8,009,778	176,411,434
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)	168,401,656	8,009,778	176,411,434
66	SalariesAndWagesUtilityPlantAbstract Utility Plant
67	SalariesAndWagesUtilityPlantConstructionAbstract Construction (By Utility Departments)
68	SalariesAndWagesUtilityPlantConstructionElectricPlant Electric Plant	56,601,904	2,692,186	59,294,090
69	SalariesAndWagesUtilityPlantConstructionGasPlant Gas Plant
70	SalariesAndWagesUtilityPlantConstructionOther Other (provide details in footnote):
71	SalariesAndWagesUtilityPlantConstruction TOTAL Construction (Total of lines 68 thru 70)	56,601,904	2,692,186	59,294,090
72	SalariesAndWagesPlantRemovalAbstract Plant Removal (By Utility Departments)
73	SalariesAndWagesPlantRemovalElectricPlant Electric Plant	9,858,855	468,922	10,327,777
74	SalariesAndWagesPlantRemovalGasPlant Gas Plant
75	SalariesAndWagesPlantRemovalOther Other (provide details in footnote):
76	SalariesAndWagesPlantRemoval TOTAL Plant Removal (Total of lines 73 thru 75)	9,858,855	468,922	10,327,777
77	SalariesAndWagesOtherAccountsAbstract Other Accounts (Specify, provide details in footnote):
78	SalariesAndWagesOtherAccountsDescription Other Accounts (Specify, provide details in footnote):
79	SalariesAndWagesOtherAccountsDescription 120 - Nuclr Fuel in Proc of Refinmnt	378,878		378,878
80	SalariesAndWagesOtherAccountsDescription 121 - Nonutility Property - WIP	12,432		12,432
81	SalariesAndWagesOtherAccountsDescription 152 - Fuel Stock Undistributed	2,508,769		2,508,769
82	SalariesAndWagesOtherAccountsDescription 154 - Materials and Supplies	17,643		17,643
83	SalariesAndWagesOtherAccountsDescription 163 - Stores Expense Undistributed	8,248,756	8,248,756
84	SalariesAndWagesOtherAccountsDescription 183 - Prelim Survey	73,413	73,413
85	SalariesAndWagesOtherAccountsDescription 184 - Clearing Accounts	2,848,717	2,848,717
86	SalariesAndWagesOtherAccountsDescription 185 - ODD Temporary Facilities	158,388		158,388
87	SalariesAndWagesOtherAccountsDescription 186 - Misc Deferred Debits	554,685		554,685
88	SalariesAndWagesOtherAccountsDescription 228 - RAD Waste Accrual	25,798		25,798
89	SalariesAndWagesOtherAccountsDescription 242 - Misc Current & Accrued Liab	29		29
90	SalariesAndWagesOtherAccountsDescription 254 - Ohio Reliability
91	SalariesAndWagesOtherAccountsDescription 401 - Operation Expense - Nonassociated
92	SalariesAndWagesOtherAccountsDescription 402 - Maintenance Exp
93	SalariesAndWagesOtherAccountsDescription 407 - Regulatory Debits
94	SalariesAndWagesOtherAccountsDescription 417 - Misc Exp	8,547,025		8,547,025
95	SalariesAndWagesOtherAccountsDescription 426 - Political Activities	190,267		190,267
95	SalariesAndWagesOtherAccounts TOTAL Other Accounts	23,564,800	11,170,886	12,393,914
96	SalariesAndWagesGeneralExpense TOTAL SALARIES AND WAGES	258,427,215		258,427,215

Name of Respondent:

Indiana Michigan 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:

Indiana Michigan 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)				210,839,384
2.1	Net Purchases (Account 555.1)
3	Net Sales (Account 447)				350,147,472
4	Transmission Rights				7,860,244
5	Ancillary Services				16,666,384
6	Other Items (list separately)
7	Congestion				41,416,704
8	Operating Reserves				4,202,771
9	Transmission Purchase Expense				51,532,730
10	Transmission Losses				28,637,215
11	Meter Correction				398,237
12	Inadvertent				563,524
13	Capacity Credits				6,020,279
46	TOTAL				10,898,094

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

PURCHASES AND SALES OF ANCILLARY SERVICES
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the respondents Open Access Transmission Tariff. In columns for usage, report usage-related billing determinant and the unit of measure. On Line 1 columns (b), (c), (d), and (e) report the amount of ancillary services purchased and sold during the year. On Line 2 columns (b), (c), (d), and (e) report the amount of reactive supply and voltage control services purchased and sold during the year. On Line 3 columns (b), (c), (d), and (e) report the amount of regulation and frequency response services purchased and sold during the year. On Line 4 columns (b), (c), (d), and (e) report the amount of energy imbalance services purchased and sold during the year. On Lines 5 and 6, columns (b), (c), (d), and (e) report the amount of operating reserve spinning and supplement services purchased and sold during the period. On Line 7 columns (b), (c), (d), and (e) report the total amount of all other types ancillary services purchased or sold during the year. Include in a footnote and specify the amount for each type of other ancillary service provided.
		Amount Purchased for the Year			Amount Sold for the Year
		Usage - Related Billing Determinant			Usage - Related Billing Determinant
Line No.	Type of Ancillary Service (a)	Number of Units (b)	Unit of Measure (c)	Dollar (d)	Number of Units (e)	Unit of Measure (f)	Dollars (g)
1	Scheduling, System Control and Dispatch	(a) 0
2	Reactive Supply and Voltage
3	Regulation and Frequency Response
4	Energy Imbalance
5	Operating Reserve - Spinning
6	Operating Reserve - Supplement
7	Other
8	Total (Lines 1 thru 7)

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

FOOTNOTE DATA

(a) Concept: AncillaryServicesPurchasedNumberOfUnits

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

Name of Respondent:

Indiana Michigan 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:

Indiana Michigan 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

Indiana Michigan 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:

Indiana Michigan 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:

Indiana Michigan 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)	17,795,101
3	Steam	2,960,925	23	Requirements Sales for Resale (See instruction 4, page 311.)	2,909,739
4	Nuclear	16,623,325	24	Non-Requirements Sales for Resale (See instruction 4, page 311.)	5,009,650
5	Hydro-Conventional	90,053	25	Energy Furnished Without Charge	46
6	Hydro-Pumped Storage		26	Energy Used by the Company (Electric Dept Only, Excluding Station Use)
7	Other	43,715	27	Total Energy Losses	1,469,180
8	Less Energy for Pumping		27.1	Total Energy Stored
9	Net Generation (Enter Total of lines 3 through 8)	19,718,018	28	TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL LINE 20 UNDER SOURCES	27,183,716
10	Purchases (other than for Energy Storage)	7,465,698
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)	27,183,716

Name of Respondent:

Indiana Michigan 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	2,711,508	706,226	(a)(b) 3,355	26	9
30	February	2,345,213	568,099	3,204	8	9
31	March	2,013,981	235,823	3,001	28	8
32	April	1,821,235	164,707	2,786	1	10
33	May	1,891,917	153,818	3,477	31	17
34	June	2,403,560	530,733	3,850	21	18
35	July	2,719,171	710,352	3,821	20	15
36	August	2,462,049	461,997	3,758	29	15
37	September	1,897,643	151,360	3,479	1	16
38	October	1,694,026	29,106	2,787	18	14
39	November	2,149,178	422,992	3,063	21	8
40	December	3,074,235	1,002,985	3,200	23	18
41	Total	27,183,716	5,138,198

Name of Respondent:

Indiana Michigan 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: MonthlyPeakLoad

Indiana Jurisdictional Split of Peak Volumes

Month Day Hour Volume

Jan 26 0900 2,895

Feb 08 0900 2,766

Mar 28 0800 2,583

Apr 01 1000 2,401

May 31 1700 2,937

Jun 21 1800 3,210

Jul 20 1500 3,218

Aug 29 1500 3,166

Sep 01 1600 2,910

Oct 18 1400 2,383

Nov 21 0800 2,637

Dec 23 1800 2,726

Michigan Jurisdictional Split of Peak Volumes

Month Day Hour Volume

Jan 26 0900 461

Feb 08 0900 439

Mar 28 0800 418

Apr 01 1000 385

May 31 1700 540

Jun 21 1800 640

Jul 20 1500 604

Aug 29 1500 591

Sep 01 1600 569

Oct 18 1400 404

Nov 21 0800 426

Dec 23 1800 474

(b) Concept: MonthlyPeakLoad

Jurisdictional Split of Peak Volumes Month Day Hour Volume

Name of Respondent:

Indiana Michigan 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: Donald C Cook Plant	Plant Name: ROCKPORT TOTAL I&M	Plant Name: ROCKPORT TOTAL PLANT	Plant Name: ROCKPORT UNIT 1 I&M	Plant Name: ROCKPORT UNIT 2 I&M
1	PlantKind Kind of Plant (Internal Comb, Gas Turb, Nuclear)	Nuclear	Steam	(a) Steam	Steam	Steam
2	PlantConstructionType Type of Constr (Conventional, Outdoor, Boiler, etc)	Conventional	Conventional	Conventional	Conventional	Conventional
3	YearPlantOriginallyConstructed Year Originally Constructed	1975	1984	1984	1984	1989
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed	1978	1989	1989	1984	1989
5	InstalledCapacityOfPlant Total Installed Cap (Max Gen Name Plate Ratings-MW)	2,285	1,310	2,620	660	650
6	NetPeakDemandOnPlant Net Peak Demand on Plant - MW (60 minutes)	2,310	1,306	2,612	594	1,079
7	PlantHoursConnectedToLoad Plant Hours Connected to Load	8,760	5,770	5,770	3,360	4,563
8	NetContinuousPlantCapability Net Continuous Plant Capability (Megawatts)	0	0	0	0	0
9	NetContinuousPlantCapabilityNotLimitedByCondenserWater When Not Limited by Condenser Water	2,288	1,310	2,620	660	650
10	NetContinuousPlantCapabilityLimitedByCondenserWater When Limited by Condenser Water	2,154	1,309	2,619	659	650
11	PlantAverageNumberOfEmployees Average Number of Employees	1,000	0	170	0	0
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh	16,623,325,000	2,960,925,000	5,921,850,000	1,250,366,000	1,710,559,000
13	CostOfLandAndLandRightsSteamProduction Cost of Plant: Land and Land Rights	1,879,588	6,538,036	13,046,747	6,470,266	67,770
14	CostOfStructuresAndImprovementsSteamProduction Structures and Improvements	461,818,705	107,686,012	286,035,368	99,644,712	8,041,300
15	CostOfEquipmentSteamProduction Equipment Costs	3,149,710,483	1,128,305,213	2,788,154,447	814,247,842	314,057,371
16	AssetRetirementCostsSteamProduction Asset Retirement Costs	496,814,452	18,918,804	37,814,336	9,459,402	9,459,402
17	CostOfPlant Total cost (total 13 thru 20)	4,110,223,228	1,261,448,065	3,125,050,898	929,822,222	331,625,843
18	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 17/5) Including	1,798.7848	962.9375	1,192.7675	1,408.8215	510.1936
19	OperationSupervisionAndEngineeringExpense Production Expenses: Oper, Supv, & Engr	12,222,139	4,133,694	8,367,142	2,128,705	2,004,989
20	FuelSteamPowerGeneration Fuel	86,277,041	114,667,136	230,907,819	51,738,636	62,928,500
21	CoolantsAndWater Coolants and Water (Nuclear Plants Only)	4,784,937
22	SteamExpensesSteamPowerGeneration Steam Expenses	12,622,438	21,410,767	41,998,987	9,899,307	11,511,460
23	SteamFromOtherSources Steam From Other Sources
24	SteamTransferredCredit Steam Transferred (Cr)
25	ElectricExpensesSteamPowerGeneration Electric Expenses	4,748,217	1,797,808	2,914,895	894,312	903,496
26	MiscellaneousSteamPowerExpenses Misc Steam (or Nuclear) Power Expenses	75,919,581	2,482,670	5,991,351	1,225,017	1,257,653
27	RentsSteamPowerGeneration Rents		68,889,566	136,003,146		68,889,566
28	Allowances Allowances		212,489	212,489	84,083	128,406
29	MaintenanceSupervisionAndEngineeringSteamPowerGeneration Maintenance Supervision and Engineering	3,183,294	1,865,133	3,720,691	929,203	935,930
30	MaintenanceOfStructuresSteamPowerGeneration Maintenance of Structures	4,025,143	836,438	1,669,859	583,530	252,908
31	MaintenanceOfBoilerPlantSteamPowerGeneration Maintenance of Boiler (or reactor) Plant	92,579,730	6,562,638	13,224,125	2,669,483	3,893,155
32	MaintenanceOfElectricPlantSteamPowerGeneration Maintenance of Electric Plant	15,339,706	2,886,862	5,598,654	1,605,643	1,281,219
33	MaintenanceOfMiscellaneousSteamPlant Maintenance of Misc Steam (or Nuclear) Plant	17,398,562	875,991	1,749,440	531,098	344,893
34	PowerProductionExpensesSteamPower Total Production Expenses	329,100,788	226,621,192	452,358,598	72,289,017	154,332,175
35	ExpensesPerNetKilowattHour Expenses per Net kWh	0.0198	0.0765	0.0764	0.0578	0.0902

35	FuelKindAxis Plant Name	Donald C Cook Plant	ROCKPORT TOTAL I&M	ROCKPORT TOTAL I&M	ROCKPORT TOTAL PLANT	ROCKPORT TOTAL PLANT
36	FuelKind Fuel Kind	Nuclear	Coal	Oil	Coal	Oil
37	FuelUnit Fuel Unit		t	bbl	t	bbl
38	QuantityOfFuelBurned Quantity (Units) of Fuel Burned		1,849,822	20,316	3,699,644	40,632
39	FuelBurnedAverageHeatContent Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)		8,502	137,342	8,502	137,342
40	AverageCostOfFuelPerUnitAsDelivered Avg Cost of Fuel/unit, as Delvd f.o.b. during year		62.770	155.144	62.770	155.144
41	AverageCostOfFuelPerUnitBurned Average Cost of Fuel per Unit Burned		57.222	133.165	57.222	133.164
42	AverageCostOfFuelBurnedPerMillionBritishThermalUnit Average Cost of Fuel Burned per Million BTU	0.493	3.365	23	3.365	23.085
43	AverageCostOfFuelBurnedPerKilowattHourNetGeneration Average Cost of Fuel Burned per kWh Net Gen	0.005	0.036		0.036
44	AverageBritishThermalUnitPerKilowattHourNetGeneration Average BTU per kWh Net Generation	10,517	9,882		9,882

Name of Respondent:

Indiana Michigan 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

The Rockport Plant is a two unit coal fired generating facility. Unit 1 is jointly owned and Unit 2 is jointly leased by the Respondent and AEP Generating Company thru December 7th 2022. Unit 2 was jointly purchased with AEP Generating Company beginning December 8th, 2022. Column (b) represents Respondent's 50% share of Unit 1 and column (c) represents Respondent's 50% share of Unit 2. Column (d) represents Respondent's total share of Rockport Plant and column (e) represents Total Rockport owned and leased by Respondent and AEP Generating Company.

Name of Respondent:

Indiana Michigan 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:

Indiana Michigan Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

/

Q4

Pumped Storage Generating Plant Statistics
Large plants and pumped storage plants of 10,000 Kw or more of installed capacity (name plate ratings). If any plant is leased, operating under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. Give project number. If net peak demand for 60 minutes is not available, give that which is available, specifying period. If a group of employees attends more than one generating plant, report on Line 8 the approximate average number of employees assignable to each plant. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power System Control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses." Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes. Include on Line 36 the cost of energy used in pumping into the storage reservoir. When this item cannot be accurately computed leave Lines 36, 37 and 38 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of energy from each station or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses per net MWH as reported herein for each source described. Group together stations and other resources which individually provide less than 10 percent of total pumping energy. If contracts are made with others to purchase power for pumping, give the supplier contract number, and date of contract.
Line No.	Item (a)	FERC Licensed Project No. 0 Plant Name: 0
1	PlantConstructionType Type of Plant Construction (Conventional or Outdoor)
2	YearPlantOriginallyConstructed Year Originally Constructed
3	YearLastUnitOfPlantInstalled Year Last Unit was Installed
4	InstalledCapacityOfPlant Total installed cap (Gen name plate Rating in MW)
5	NetPeakDemandOnPlant Net Peak Demaind on Plant-Megawatts (60 minutes)	0
6	PlantHoursConnectedToLoad Plant Hours Connect to Load While Generating	0
7	NetContinuousPlantCapability Net Plant Capability (in megawatts)	0
8	PlantAverageNumberOfEmployees Average Number of Employees
9	NetGenerationExcludingPlantUse Generation, Exclusive of Plant Use - kWh	0
10	EnergyUsedForPumping Energy Used for Pumping
11	NetOutputForLoad Net Output for Load (line 9 - line 10) - Kwh	0
12	CostOfPlantAbstract Cost of Plant
13	CostOfLandAndLandRightsPumpedStoragePlant Land and Land Rights
14	CostOfStructuresAndImprovementsPumpedStoragePlant Structures and Improvements	0
15	CostOfReservoirsDamsAndWaterwaysPumpedStoragePlant Reservoirs, Dams, and Waterways	0
16	CostOfWaterWheelsTurbinesAndGeneratorsPumpedStoragePlant Water Wheels, Turbines, and Generators	0
17	CostOfAccessoryElectricEquipmentPumpedStoragePlant Accessory Electric Equipment	0
18	CostOfMiscellaneousPowerPlantEquipmentPumpedStoragePlant Miscellaneous Powerplant Equipment	0
19	CostOfRoadsRailroadsAndBridgesPumpedStoragePlant Roads, Railroads, and Bridges	0
20	AssetRetirementCostsPumpedStoragePlant Asset Retirement Costs	0
21	CostOfPlant Total cost (total 13 thru 20)
22	CostPerKilowattOfInstalledCapacity Cost per KW of installed cap (line 21 / 4)
23	ProductionExpensesAbstract Production Expenses
24	OperationSupervisionAndEngineeringExpense Operation Supervision and Engineering	0
25	WaterForPower Water for Power	0
26	PumpedStorageExpenses Pumped Storage Expenses	0
27	ElectricExpensesPumpedStoragePlant Electric Expenses	0
28	MiscellaneousPumpedStoragePowerGenerationExpenses Misc Pumped Storage Power generation Expenses	0
29	RentsPumpedStoragePlant Rents	0
30	MaintenanceSupervisionAndEngineeringPumpedStoragePlant Maintenance Supervision and Engineering	0
31	MaintenanceOfStructuresPumpedStoragePlant Maintenance of Structures	0
32	MaintenanceOfReservoirsDamsAndWaterwaysPumpedStoragePlant Maintenance of Reservoirs, Dams, and Waterways	0
33	MaintenanceOfElectricPlantPumpedStoragePlant Maintenance of Electric Plant	0
34	MaintenanceOfMiscellaneousPumpedStoragePlant Maintenance of Misc Pumped Storage Plant	0
35	PowerProductionExpenseBeforePumpingExpenses Production Exp Before Pumping Exp (24 thru 34)
36	PumpingExpenses Pumping Expenses
37	PowerProductionExpensesPumpedStoragePlant Total Production Exp (total 35 and 36)
38	ExpensesPerNetKilowattHour Expenses per kWh (line 37 / 9)
39	ExpensesPerNetKilowattHourGenerationAndPumping Expenses per KWh of Generation and Pumping (line 37/(line 9 + line 10))	0

Name of Respondent:

Indiana Michigan 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	Hydro electric
2	Berrien Springs	1908	7.20	5.5	25,123	16,768,129	2,328,907	422,537		385,268
3	Buchanan	1919	4.10	2.7	15,842	8,283,194	2,020,291	275,668		167,136
4	Constantine	1921	1.20	0.8	4,800	3,285,052	2,737,543	133,055		49,899
5	Elkhart	1913	3.44	3.2	13,347	9,863,405	2,867,269	234,998		338,422
6	Mottville	1923	1.68	1.3	6,752	4,785,484	2,848,502	190,059		369,115
7	Twin Branch	1904	4.80	3.5	24,189	14,488,884	3,018,518	407,821		701,654
8	Solar electric
9	Deer Creek	2015	2.50	2.5	3,146	6,411,700	2,564,680	57,048		3
10	Olive	2016	5.00	5.5	7,522	12,062,064	2,412,413	83,446		7
11	St. Joseph	2020	20.00	15.9	24,276	37,205,711	1,860,286	681,701		27
12	Twin Branch Solar	2016	2.60	2.7	3,751	6,958,803	2,676,463	217,642		4
13	Watervliet	2016	4.60	4.6	5,020	11,969,137	2,601,986	101,207		6

Name of Respondent:

Indiana Michigan 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:

Indiana Michigan 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	STATE OF INDIANA	STATE OF INDIANA
2	6128 DUMONT	JEFFERSON	765.00	765.00	3	202.50	0	1	4-954 KCM
3	6136 DUMONT	WILTON CENTER	765.00	765.00	3	63.00	0	1	4-954 KCM
4	6141 DUMONT	MARYSVILLE	765.00	765.00	3	99.38	0	1	4-954 KCM
5	6215 D.C. COOK	DUMONT	765.00	765.00	3	20.00	0	1	4-954 KCM
6	6223 ROCKPORT	JEFFERSON	765.00	765.00	3	111.00	0	1	4-1351 KCM
7	6224 ROCKPORT	SULLIVAN	765.00	765.00	3	97.00	0	1	4-1351 KCM
8	6226 JEFFERSON	WEST	765.00	765.00		0.00	0	0
9	6236 HANGING ROCK	JEFFERSON	765.00	765.00	3	1.00	0	1	4-1351 KCM
10	0675 TANNERS CREEK	SORENSON	345.00	345.00	3	135.58	0	2	1275 KCM
11	0675 TANNERS CREEK	SORENSON	345.00	345.00	1	0.42	0	2	1414 KCM
12	0676 SORENSON	EAST LIMA	345.00	345.00	3	29.68	0	1	1275 KCM
13	0676 SORENSON	EAST LIMA	345.00	345.00	1	0.27	0	1	2-954 KCM
14	0677 BREED	DEQUINE EAST	345.00	345.00	3	46.44	0	2	1414 KCM
15	0677 BREED	DEQUINE EAST	345.00	345.00	3	45.13	0	1	1414 KCM
16	0677 BREED	DEQUINE EAST	345.00	345.00	3	0.65	0	2	2-954 KCM
17	0677 BREED	DEQUINE EAST	345.00	345.00	1	0.18	0	2	1414 KCM
18	0677 BREED	DEQUINE EAST	345.00	345.00	1	3.77	0	2	2303 KCM
19	0677 BREED	DEQUINE EAST	345.00	345.00	1	0.08	0	2	2-2303 KCM
20	0678 DEQUINE	OLIVE	345.00	345.00	3	13.31	0	2	2303 KCM
21	0678 DEQUINE	OLIVE	345.00	345.00	3	54.19	0	2	1,414KCM
22	0678 DEQUINE	OLIVE	345.00	345.00	1	0.50	0	2	2156 KCM
23	0678 DEQUINE	OLIVE	345.00	345.00	1	0.14	0	2	2,303 KCM
24	0678 DEQUINE	OLIVE	345.00	345.00	1	0.45	0	2	2-954 KCM
25	0679 SORENSON	OLIVE	345.00	345.00	3	77.90	0	1	1272 KCM
26	0679 SORENSON	OLIVE	345.00	345.00	1	0.10	0	1	1272 KCM
27	0680 OLIVE	GOODINGS GROVE	345.00	345.00	3	41.00	0	2	1414 KCM
28	0683 DESOTO	JCT TOWER (MAR. CO)	345.00	345.00	3	53.00	6	1	2-954 KCM
29	0684 TANNERS CREEK	JUNCTION TOWER	345.00	345.00	3	79.98	0	1	2-954 KCM
30	0684 TANNERS CREEK	JUNCTION TOWER	345.00	345.00	2	0.02	0	1	2-954 KCM
31	0685 HANNA	JUNCTION TOWER	345.00	345.00	3	5.63	0	0	2-954 KCM
32	0687 TANNERS CREEK	MIAMI FORT	345.00	345.00	3	0.28	0	2	2-954 KCM
33	0688 EUGENE	SIDNEY	345.00	345.00	1	0.20	0	1	1414 KCM
34	0689 SORENSON-OLIVE	TWIN BRANCH	345.00	345.00	3	11.00	0	2	1563 KCM
35	0690 BREED	CIPSCO	345.00	345.00	3	0.94	0	1	2-1024 KCM
36	0690 BREED	CIPSCO	345.00	345.00	3	0.02	0	1	2-1351.5 KCM
37	0691 BREED	PETERSBURG	345.00	345.00	3	0.70	0	1	2-954 KCM
38	0691 BREED	PETERSBURG	345.00	345.00	1	0.15	0	1	2-1351.5 KCM
39	0731 Varner	South Butler	345.00	345.00	1	0.60	0	1	2-954 KCM
40	0734 Dunton Lake Extension		345.00	345.00	3	0.25	0	2	2-954 KCM
41	6118 ROBISON PARK	SORENSON-EAST LIMA	345.00	345.00	3	22.66	0	2	1414 KCM
42	6118 ROBISON PARK	SORENSON-EAST LIMA	345.00	345.00	1	0.34	0	1	1414 KCM
43	6119 COOK	OLIVE	345.00	345.00	3	4.00	0	2	2-954 KCM
44	6122 DUMONT	OLIVE	345.00	345.00	3	14.52	0	2	2-954 KCM
45	6122 DUMONT	OLIVE	345.00	345.00	1	0.60	0	1	2-954 KCM
46	6123 DUMONT	TWIN BRANCH	345.00	345.00	3	17.00	0	2	2-954 KCM
47	6125 ROBISON PARK	EAST	345.00	345.00		0.00	0	0
48	6133 DUMONT	BABCOCK	345.00	345.00	3	9.00	0	1	2-954 KCM
49	6145 TWIN BRANCH	COOK-ROB PARK JCT	345.00	345.00	3	6.00	0	2	2-954 KCM
50	6147 COOK	ROBISON PARK	345.00	345.00	3	67.41	0	2	2-954 KCM
51	6147 COOK	ROBISON PARK	345.00	345.00	1	0.41	0	0	2-954 KCM
52	6148 JACKSON ROAD	SORENSON-OLIVE	345.00	345.00	3	4.00	0	2	2303 KCM
53	6213 COOK-ROB-PARK JCT	ARGENTA	345.00	345.00	3	2.00	0	2	2-954 KCM
54	6237 JACKSON ROAD	WEST	345.00	345.00		0.00	0	0
55	6240 TWIN BRANCH	SUBSTATION CORRIDOR	345.00	345.00		0.00	0	0
56	6256 BREED	SULLIVAN	345.00	345.00	3	0.48	0	2	1351.5 KCM
57	6256 BREED	SULLIVAN	345.00	345.00	3	0.75	0	1	1351.5 KCM
58	6256 BREED	SULLIVAN	345.00	345.00	1	0.29	0	1	1351.5 KCM
59	6259 COLLINGWOOD	SOUTH BUTLER	345.00	345.00	1	14.65	0	1	2-954 KCM
60	6232 Arnold Hogan	Kenmore	34.00	138.00	1	1.26	0	2	795 KCM
61	0604 TWIN BRANCH	ROBISON PARK	138.00	138.00	3	8.50	0	2	397.5 KCM
62	0604 TWIN BRANCH	ROBISON PARK	138.00	138.00	1	0.28	0	2	1233.6 KCM
63	0605 SOUTH BEND	MICHIGAN CITY	138.00	138.00	3	0.00	0	1	397.5 KCM
64	0606 ROBISON PARK	HAVILAND	138.00	138.00	3	12.01	0	2	397.5 KCM
65	0606 ROBISON PARK	HAVILAND	138.00	138.00	1	0.05	0	0	1233.6 KCM
66	0607 ROBISON PARK	DEER CREEK	138.00	138.00	1	0.12	0	2	1590 KCM
67	0607 ROBISON PARK	DEER CREEK	69.00	138.00	1	0.00	1	1	1033.5 KCM
68	0608 DEER CREEK	KOKOMO	138.00	138.00	3	1.56	0	1	336.4 KCM
69	0608 DEER CREEK	KOKOMO	138.00	138.00	3	5.96	0	1	636 KCM
70	0608 DEER CREEK	KOKOMO	138.00	138.00	1	0.17	0	1	336.4 KCM
71	0609 CONCORD TAP		138.00	138.00	3	4.00	0	2	397.5 KCM
72	0613 TWIN BRANCH	JACKSON ROAD	138.00	138.00	3	8.00	0	2	447 KCM
73	0614 LINCOLN TAP		138.00	138.00	3	4.00	0	2	397.5 KCM
74	0615 TWIN BRANCH	ROBISON PARK	138.00	138.00	3	65.83	0	1	477 KCM
75	0616 DEER CREEK	DELAWARE	138.00	138.00	3	2.40	0	2	397.5 KCM
76	0618 DELAWARE	COLLEGE CORNER	138.00	138.00	3	48.81	0	2	397.5 KCM
77	0618 DELAWARE	COLLEGE CORNER	138.00	138.00	4	0.84	0	2	2,000KCM
78	0618 DELAWARE	COLLEGE CORNER	138.00	138.00	2	0.11	0	2	397.5 KCM
79	0618 DELAWARE	COLLEGE CORNER	138.00	138.00	1	0.65	0	2	397.5 KCM
80	0618 DELAWARE	COLLEGE CORNER	138.00	138.00	1	0.20	0	2	556.5 KCM
81	0618 DELAWARE	COLLEGE CORNER	138.00	138.00	2	1.02	0	1	795 KCM
82	0619 MADISON	NEW CASTLE	138.00	138.00	3	6.00	1	1	795 KCM
83	0620 TANNERS CREEK	MADISON	138.00	138.00	3	82.00	0	2	636 KCM
84	0622 JACKSON ROAD	OLIVE	138.00	138.00	3	16.29	1	1	556.5 KCM
85	0622 JACKSON ROAD	OLIVE	138.00	138.00	1	0.47	0	1	556.5 KCM
86	0623 MADISON	PENDLETON	138.00	138.00	2	5.00	0	1	477 KCM
87	0624 DRAGOON TAP		138.00	138.00	3	2.00	0	1	795 KCM
88	0625 TANNERS CREEK	COLLEGE CORNER	138.00	138.00	3	51.90	0	2	636 KCM
89	0625 TANNERS CREEK	COLLEGE CORNER	138.00	138.00	1	0.37	0	2	636 KCM
90	0626 COLLEGE CORNER	RANDOLPH	138.00	138.00	2	34.58	0	1	556.5 KCM
91	0626 COLLEGE CORNER	RANDOLPH	138.00	138.00	1	1.07	0	1	556.5 KCM
92	0626 COLLEGE CORNER	RANDOLPH	138.00	138.00	2	3.34	0	0	556.5 KCM
93	0627 RANDOLPH	JAY	138.00	138.00	2	23.69	0	1	556.5 KCM
94	0627 RANDOLPH	JAY	138.00	138.00	1	0.32	0	0	556.5 KCM
95	0628 MCKINLEY TAP		138.00	138.00	3	0.85	0	2	300 KCM CU
96	0628 MCKINLEY TAP		138.00	138.00	1	0.15	0	2	300 KCM CU
97	0629 JAY	LINCOLN	138.00	138.00	2	9.71	0	1	556.5 KCM
98	0629 JAY	LINCOLN	138.00	138.00	3	3.11	0	1	1033.5 KCM
99	0630 NEW CARLISLE	MAPLE	138.00	138.00	2	1.00	0	1	397.5 KCM
100	6104 SORENSON	TWIN BRANCH	138.00	138.00	3	61.17	0	1	447 KCM
101	6104 SORENSON	TWIN BRANCH	138.00	138.00	1	0.31	0	1	556.5 KCM
102	6104 SORENSON	TWIN BRANCH	138.00	138.00	1	3.32	0	1	556.5 KCM
103	0632 SORENSON	DEVILS HOLLOW	138.00	138.00	3	0.00	0	0	556.5 KCM
104	0634 DEER CREEK	MULLIN	138.00	138.00	2	15.70	0	1	556.5 KCM
105	0635 PENDLETON	MULLIN	138.00	138.00	2	14.10	0	1	556.5 KCM
106	0635 PENDLETON	MULLIN	138.00	138.00	3	0.40	0	1	556.5 KCM
107	0635 PENDLETON	MULLIN	138.00	138.00	1	0.72	0	1	556.5 KCM
108	0636 DEER CREEK	FISHER BODY	138.00	138.00	3	5.04	0	2	397.5 KCM
109	0637 TWIN BRANCH	EAST ELKHART	138.00	138.00	3	17.00	1	2	556.5 KCM
110	0638 GRANT	FISHER BODY	138.00	138.00	3	0.00	1	1	397.5 KCM
111	0639 ROBISON PARK	AUBURN	138.00	138.00	1	0.00	0	1	556.5 KCM
112	0641 DESOTO	MEDFORD	138.00	138.00	1	0.15	0	2	795 KCM
113	0641 DESOTO	MEDFORD	138.00	138.00	3	6.86	0	2	556.5 KCM
114	0642 OLIVE	HICKORY CREEK	138.00	138.00	3	2.99	2	1	556.5 KCM
115	0645 COREY TAP		138.00	138.00	2	4.00	0	1	477 KCM
116	0646 OLIVE	NEW CARLISLE	138.00	138.00	3	2.00	0	1	556.5 KCM
117	0647 OLIVE	SOUTH BEND	138.00	138.00	3	15.97	0	2	397.5 KCM
118	0648 MEDFORD TAP		138.00	138.00	1	0.13	0	2	556.5 KCM
119	0648 MEDFORD TAP		138.00	138.00	3	7.94	0	2	556.5 KCM
120	0723 SPY RUN STATION		138.00	138.00	4	0.00	0	1	3.5IN OD
121	0730 Varner	Wilmington	138.00	138.00	1	0.83	0	1	795 KCM
122	0742 Deptmer Sw	Harber (REMC)	69.00	138.00	1	0.06	0	1	795 KCM
123	6101 WESTINGHOUSE TAP		138.00	138.00	3	2.00	0	2	556.5 KCM
124	6102 MILAN TAP		138.00	138.00	3	6.00	0	2	397.5 KCM
125	6103 MILAN	GOODRICH	138.00	138.00	3	1.00	0	2	397.5 KCM
126	6105 DESOTO	JAY	138.00	138.00	2	10.31	0	1	2-556.5 KCM
127	6105 DESOTO	JAY	138.00	138.00	3	2.25	0	1	2-556.5 KCM
128	6106 DESOTO	DEER CREEK-DELAWARE	138.00	138.00	3	7.21	0	2	636 KCM
129	6106 DESOTO	DEER CREEK-DELAWARE	138.00	138.00	1	1.20	0	0	636 KCM
130	6107 DARDEN TAP		138.00	138.00	2	0.94	0	1	336.4 KCM
131	6109 ROBISON PARK	RICHLAND	138.00	138.00	2	13.76	0	1	636 KCM
132	6109 ROBISON PARK	RICHLAND	138.00	138.00	1	0.05	0	0	1233.6 KCM
133	6109 ROBISON PARK	RICHLAND	138.00	138.00	3	4.49	0	0	636 KCM
134	6110 WESTINGHOUSE	23RD STREET	138.00	138.00	3	0.00	0	2	556.5 KCM
135	6111 KANKAKEE	WEST SIDE	138.00	138.00	1	2.00	0	1	636 KCM
136	6113 INDUSTRIAL PARK		138.00	138.00	3	3.00	0	2	745 KCM
137	6114 OLIVE	MICHIGAN CITY	138.00	138.00	3	1.94	1	1	636 KCM
138	6115 HUMMEL CREEK	VAN BUREN	138.00	138.00	3	6.00	0	2	795 KCM
139	6130 HUMMEL CREEK	TOWER 70, GREENTOWN	138.00	138.00		0.00	0	0
140	6116 SOUTH ELWOOD TAP		138.00	138.00	1	3.07	0	1	556.5 KCM
141	6117 PENDLETON	FALL CREEK	138.00	138.00	3	10.70	0	2	795 KCM
142	6117 PENDLETON	FALL CREEK	138.00	138.00	1	0.07	0	2	795 KCM
143	6121 ROBISON PARK	LINCOLN	138.00	138.00	3	7.84	0	1	795 KCM
144	6121 ROBISON PARK	LINCOLN	138.00	138.00	1	0.02	0	0	1233.6 KCM
145	6126 CONCORD	EAST ELKHART	138.00	138.00	3	11.00	0	1	795 KCM
146	6129 GREENTOWN-GRANT	HUMMEL CREEK	138.00	138.00	3	21.00	0	1	795 KCM
147	6131 INDUSTRIAL PARK	MC KINLEY	138.00	138.00	1	5.00	0	1	795 KCM
148	6132 CROSS STREET TAP	JUNCTION TOWER #88	138.00	138.00	1	4.00	0	1	795 KCM
149	6134 LINCOLN	ANTHONY	138.00	138.00	1	3.00	0	1	795 KCM
150	6135 WAYNEDALE TAP		138.00	138.00	3	0.00	0	2	795 KCM
151	6138 JACKSON ROAD	SOUTH SIDE	138.00	138.00	1	2.00	0	1	795 KCM
152	6142 ALBION	KENDALLVILLE	138.00	138.00	3	10.00	0	1	795 KCM
153	6150 SOUTHSIDE	SOUTH BEND	138.00	138.00	1	6.07	0	1	795 KCM
154	6219 DELCO BATTERY TAP		138.00	138.00	1	1.00	0	2	795 KCM AA
155	6220 FALL CREEK	MADISON-NEW CASTLE	138.00	138.00	3	1.10	0	2	795 KCM
156	6220 FALL CREEK	MADISON-NEW CASTLE	138.00	138.00	1	0.15	0	2	795 KCM
157	6225 INDUSTRIAL PARK	SPY RUN	138.00	138.00	1	4.00	0	1	1033 KCM
158	6266 WALLEN		138.00	138.00	1	0.22	0	1	1033.5 KCM
159	6234 CABOT TAP/CR 4	EAST ELKHART	138.00	138.00	1	0.13	0	1	556.5 KCM
160	6238 SORENSON	MCKINLEYTOWER	138.00	138.00	3	2.82	0	2	795 KCM
161	6238 SORENSON	MCKINLEYTOWER	138.00	138.00	1	0.26	0	2	795 KCM
162	6241 KENDALLVILLE TAP	CITY OF AUBURN #5	138.00	138.00	1	14.00	0	1	795 KCM
163	6241 KENDALLVILLE TAP	CITY OF AUBURN #5	138.00	138.00	2	14.00	0	1	795 KCM
164	6242 AUBURN	CITY OF AUBURN #5	138.00	138.00	1	2.00	0	1	795 KCM
165	6245 LAPORTE JCT	LIQUID CARBONICS	138.00	138.00	1	4.76	0	1	795 KCM
166	6245 LAPORTE JCT	LIQUID CARBONICS	138.00	138.00	1	0.23	0	0	1033.5 KCM
167	6246 LAPORTE JCT	AIRCO	138.00	138.00	1	0.72	0	1	795 KCM
168	6248 ELCONA TAP	CONC-DUN-E-ELK	138.00	138.00	1	2.00	0	1	795 KCM
169	6249 ALLEN	LINCOLN	138.00	138.00	3	4.90	0	2	1033 KCM
170	6249 ALLEN	LINCOLN	138.00	138.00	1	0.09	0	2	1233.6 KCM
171	6250 ALLEN	ADAMS/HILLCREST	138.00	138.00	3	4.92	0	2	1033 KCM
172	6250 ALLEN	ADAMS/HILLCREST	138.00	138.00	1	0.07	0	2	1233.6 KCM
173	6251 OLIVE	EDISON	138.00	138.00	3	1.00	0	2	795 KCM
174	6253 TRIER RD TAP		138.00	138.00	1	0.00	0	1	795 KCM
175	6258 KENZIE CREEK	TWIN BRANCH	138.00	138.00	3	0.00	0	2	1033 KCM
176	6260 WILMINGTON TAP		138.00	138.00	1	0.20	9	1	2-954 KCM
177	6229 DUNLAP NORTH TAP		34.00	138.00	1	2.00	0	2	795 KCM
178	6140 INDIANA-PURDUE		34.00	138.00	1	0.00	0	2	1033 KCM
179	6217 HILLCREST	KINNERK	69.00	138.00	1	3.92	0	1	795 KCM
180	6217 HILLCREST	KINNERK	69.00	138.00	2	0.03	0	1	795 KCM
181	6252 KENDALLVILLE	BIXLER	138.00	138.00	1	2.91	0	1	795 KCM
182	6254 ALLEN/LINCOLN	ALLEN/HILLCREST	138.00	138.00		0.00	0	0
183	6265 CONCORD	WOLF	138.00	138.00	1	0.77	0	1	336.4 KCM
184	6271 INDALEX TAP/CR 4	EAST ELKHART	138.00	138.00	1	1.09	0	1	556.5 KCM
185	6267 STUDEBAKER	WEST SIDE	138.00	138.00	1	2.57	0	1	954 KCM
186	6270 JONES CREEK	HOGAN	138.00	138.00		5.47	0	1	795 KCM
187	6273 DAWKINS SWITCH	HERBERT MONROE (WVPA)	138.00	138.00	1	0.50	0	1	4/0
188	LINES<132 KV	SYSTEM	69.00	0.00	Various	582.62	72	1	VARIOUS
189	STATE OF MICHIGAN	STATE OF MICHIGAN	0.00	0.00		0.00	0	0
190	6216 D.C. COOK	DUMONT	765.00	765.00	3	16.00	0	1	4-954 KCM
191	6120 COOK	PALISADES	345.00	345.00	3	41.78	0	2	2-954 KCM
192	6120 COOK	PALISADES	345.00	345.00	1	0.23	0	0	2-954 KCM
193	6120 COOK	PALISADES	345.00	345.00	1	0.21	0	0	2-1158.4 KCM
194	6143 D.C. COOK	OLIVE-PALISADES	345.00	345.00	3	5.00	0	2	2-954 KCM
195	6144 TWIN BRANCH	COOK-ROB PARK JCT	345.00	345.00	3	0.00	0	2	2-954 KCM
196	6151 COOK	OLIVE	345.00	345.00		0.00	0	0
197	6152 COOK	ROBISON PARK	345.00	345.00		0.00	0	0
198	6146 D.C. COOK	ROBISON PARK	345.00	345.00	3	36.80	0	2	2-954 KCM
199	6146 D.C. COOK	ROBISON PARK	345.00	345.00	3	0.09	0	0	954 KCM
200	6214 COOK-ROB PARK	ARGENTA	345.00	345.00	3	28.78	0	2	2-954 KCM
201	6214 COOK-ROB PARK	ARGENTA	345.00	345.00	1	0.22	0	2	2-954 KCM
202	6221 D.C. COOK	OLIVE-PALISADES	345.00	345.00	3	5.00	0	2	2-954 KCM
203	6263 BARODA TAP		138.00	138.00		0.00	0	0
204	0601 TWIN BRANCH	RIVERSIDE	138.00	138.00	3	5.80	0	2	397.5KCM & 1033.5
205	0601 TWIN BRANCH	RIVERSIDE	138.00	138.00	1	0.10	0	2	397.5KCM & 1033.5
206	0610 AUTO SPECIALTIES		138.00	138.00		0.00	0	0
207	0621 TWIN BRANCH - R	HICKORY CREEK	138.00	138.00	3	5.00	0	2	397.5 KCM
208	0643 OLIVE	HICKORY CREEK	138.00	138.00	3	23.10	2	1	556.5 KCM
209	0644 RIVERSIDE	HARTFORD	138.00	138.00	2	14.22	0	1	397.5 KCM
210	0644 RIVERSIDE	HARTFORD	138.00	138.00	3	2.11	0	0	397.5 KCM
211	0649 COREY TAP		138.00	138.00	2	12.12	0	1	477 KCM
212	0649 COREY TAP		138.00	138.00	1	0.13	0	1	477 KCM
213	6150 SOUTHSIDE	SOUTH BEND	138.00	138.00	1	6.23	0	1	795 KCM
214	6108 RIVERSIDE	OLIVE-HICKORY CREEK	138.00	138.00	1	6.00	0	1	636 KCM
215	6124 BENTON HARBOR	RIVERSIDE-HARTFORD	138.00	138.00	3	1.00	0	2	795 KCM
216	6137 EDGEWATER TAP		138.00	138.00	1	0.76	0	1	556.5 KCM
217	6149 HARTFORD	COREY	138.00	138.00	1	18.97	0	1	795 KCM
218	6149 HARTFORD	COREY	138.00	138.00		0.00	2	1	795 KCM
219	6149 HARTFORD	COREY	138.00	138.00	2	12.88	0	1	795 KCM
220	6149 HARTFORD	COREY	138.00	138.00		0.00	1	1	1033.5 KCM
221	6149 HARTFORD	COREY	138.00	138.00	1	1.34	0	1	1033.5 KCM
222	6149 HARTFORD	COREY	138.00	138.00	1	0.53	0	2	1033.5 KCM
223	6218 MOTTVILLE TAP		138.00	138.00	1	1.00	0	1	795 KCM
224	6219 DELCO BATTERY TAP		138.00	138.00	1	0.50	0	2	795 KCM
225	6219 DELCO BATTERY TAP		138.00	138.00	1	0.15	0	1	795 KCM
226	6255 KENZIE CREEK	VALLEY	138.00	138.00	1	20.00	0	1	1033 KCM
227	6257 KENZIE CREEK	T B/R'SIDE/HICK CR	138.00	138.00	3	0.00	0	0	795 KCM
228	6261 FLATBUSH TAP		138.00	138.00		1.00	0	1
229	6262 WEST ST TAP		138.00	138.00		1.00	0	2
230	6700 GM HYDRAMATIC		138.00	138.00	3	2.00	0	2	795 KCM
231	6227 NICKERSON	TOWER #13A	138.00	138.00		0.00	0	0
232	6268 SAUK TRAIL		138.00	138.00	1	1.60	0	0	1033.5KCM 45/7ACR
233	LESS THAN 132 KV LINES		69.00	0.00	Various	375.90	12	0	VARIOUS
234	Line cost and expense are	not available by individual								75,355,623	803,779,061	879,134,684	445,114	9,535,351		9,980,465
235	transmission line.	Total shown in column j-p
36	TOTAL					3,381	112	291		75,355,623	803,779,061	879,134,684	445,114	9,535,351	0	9,980,465

Name of Respondent:

Indiana Michigan 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:

Indiana Michigan 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	ADAMS (IM) - IN	Transmission		138.00	13.00		12.50	1			0	0.00
2	ADAMS (IM) - IN	Transmission		138.00	69.00	34.00	115.00	1			0	0.00
3	ALBANY (IM) - IN	Distribution		34.50	13.00		9.38	1			0	0.00
4	ALBION - IN	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.40
5	ALBION - IN	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	52.79
6	ALBION - IN	Transmission		69.00	12.00		8.40	1			0	0.00
7	ALBION - IN	Transmission		138.00	69.00	12.00	90.00	1			0	0.00
8	ALLEN (IM) - IN	Transmission		345.00	137.50	13.80	450.00	1			0	0.00
9	AM GENERAL #1 - IN	Distribution		34.50	4.00		7.17	2			0	0.00
10	ANACONDA - IN	Distribution		34.50	4.00		3.75	1			0	0.00
11	ANCHOR HOCKING (IM) - IN	Distribution		69.00	2.40		13.75	2			0	0.00
12	ANCHOR HOCKING (IM) - IN	Distribution		69.00	13.09		20.00	1			0	0.00
13	ANTHONY - IN	Transmission		34.50	12.00		29.38	2			0	0.00
14	ANTHONY - IN	Transmission		138.00	34.00		112.00	1			0	0.00
15	ANTIVILLE - IN	Distribution		69.00	12.00		3.65	1			0	0.00
16	ARMSTRONG CORK - IN	Distribution		69.00	4.00		19.88	2			0	0.00
17	ARNOLD HOGAN - IN	Transmission		34.50	0.00	0.00	0.00			STATCAP	1	14.40
18	ARNOLD HOGAN - IN	Transmission		138.00	13.09		22.40	1			0	0.00
19	AUBURN - IN	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	105.59
20	AUBURN - IN	Transmission		138.00	70.50	36.20	130.00	1			0	0.00
21	BARLEY - IN	Distribution		34.50	13.00		2.00	1			0	0.00
22	BEECH ROAD - IN	Distribution		138.00	13.09		20.00	1			0	0.00
23	BERNE - IN	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	16.20
24	BERNE - IN	Distribution		69.00	12.00		20.00	1			0	0.00
25	BIG RUN - IN	Transmission		69.00	0.48		2.50	1			0	0.00
26	BIXLER - IN	Distribution		138.00	13.09		20.00	1			0	0.00
27	BLAINE STREET - IN	Distribution		34.50	13.00		29.38	2			0	0.00
28	BLUFF POINT - IN	Transmission		69.00	13.00		5.60	1			0	0.00
29	BLUFF POINT - IN	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	16.20
30	BLUFFTON (IM) - IN	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	16.20
31	BOSMAN - IN	Distribution		34.50	13.00		9.38	1			0	0.00
32	BUTLER (IM) - IN	Distribution		69.00	13.00		20.00	1			0	0.00
33	BUTLER (IM) - IN	Distribution		69.00	0.00	0.00	0.00			STATCAP	2	30.00
34	CALVERT - IN	Distribution		138.00	13.09		20.00	1			0	0.00
35	CAPITAL AVENUE - IN	Transmission		138.00	13.09		12.00	1			0	0.00
36	CARROLL - IN	Distribution		34.50	13.00		1.50	3			0	0.00
37	CHARLES - IN	Distribution		34.50	13.00		1.60	1			0	0.00
38	CHURUBUSCO - IN	Distribution		34.50	0.00	0.00	0.00			STATCAP	1	4.80
39	CHURUBUSCO - IN	Distribution		34.50	13.00		10.50	1			0	0.00
40	CLEVELAND - IN	Distribution		138.00	13.09		20.00	1			0	0.00
41	Clipper - IN	Distribution		69.00	13.09		6.25	1			0	0.00
42	COLFAX - IN	Distribution		34.50	12.00		22.40	1			0	0.00
43	COLONY BAY - IN	Distribution		69.00	12.00		20.00	1			0	0.00
44	COLONY BAY - IN	Distribution		69.00	13.00		22.40	1			0	0.00
45	COLUMBIA (IM) - IN	Transmission		138.00	69.00	34.00	50.00	1			0	0.00
46	CONANT - IN	Distribution		34.50	12.00		22.40	1			0	0.00
47	CONCORD - IN	Transmission		138.00	70.50	36.20	130.00	1			0	0.00
48	CONCORD - IN	Transmission		138.00	13.09		22.40	1			0	0.00
49	CONCORD - IN	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	52.79
50	COUNTRYSIDE - IN	Distribution		138.00	12.47		20.00	1			0	0.00
51	COUNTY LINE (IM) - IN	Distribution		138.00	13.09		20.00	1			0	0.00
52	COUNTY ROAD 4 - IN	Distribution		138.00	13.09		20.00	1			0	0.00
53	CROSS STREET - IN	Distribution		138.00	13.09		20.00	1			0	0.00
54	DALEVILLE - IN	Distribution		138.00	13.09		20.00	1			0	0.00
55	DARDEN ROAD - IN	Distribution		138.00	13.09		42.40	2			0	0.00
56	DECATUR (FTW) - IN	Transmission		69.00	4.00		5.00	1			0	0.00
57	DECATUR (FTW) - IN	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	13.19
58	DECATUR (FTW) - IN	Transmission		69.00	13.00		20.00	1			0	0.00
59	DEER CREEK - IN	Transmission		138.00	13.09		20.00	1			0	0.00
60	DEER CREEK - IN	Transmission		34.50	13.09		3.75	1			0	0.00
61	DEER CREEK - IN	Transmission		138.00	69.00	34.00	90.00	1			0	0.00
62	DEER CREEK - IN	Transmission		138.00	34.50		75.00	1			0	0.00
63	DEER CREEK - IN	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	57.60
64	DEER CREEK - IN	Transmission		34.50	0.00	0.00	0.00			STATCAP	2	29.70
65	DELAWARE (IM) - IN	Transmission		138.00	34.00		125.00	2			0	0.00
66	DELAWARE (IM) - IN	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	52.79
67	DELAWARE (IM) - IN	Transmission		34.50	0.00	0.00	0.00			STATCAP	1	4.80
68	DESOTO - IN	Transmission		345.00	138.00	34.50	675.00	1			0	0.00
69	DIEBOLD ROAD - IN	Distribution		69.00	13.00		20.00	1			0	0.00
70	DOOVILLE - IN	Distribution		138.00	13.09		12.00	1			0	0.00
71	DRAGOON - IN	Transmission		138.00	69.00	34.00	84.00	1			0	0.00
72	DREWRYS - IN	Distribution		34.50	12.00		7.50	1			0	0.00
73	DREWRYS - IN	Distribution		34.50	13.09		7.50	1			0	0.00
74	DUMONT - IN	Transmission		765.00						REACTOR	2	200.00
75	DUNLAP - IN	Transmission		138.00	13.09		20.00	1			0	0.00
76	EAST ELKHART - IN	Transmission		345.00	137.50	13.80	450.00	1			0	0.00
77	EAST SIDE (IM) - IN	Distribution		138.00	13.09		37.40	2			0	0.00
78	EGE - IN	Distribution		138.00	34.50	13.00	7.50	1			0	0.00
79	ELCONA - IN	Distribution		138.00	13.09		22.40	1			0	0.00
80	ELKHART HYDRO STAT - IN	Transmission		34.50	0.00	0.00	0.00			STATCAP	1	13.50
81	ELKHART HYDRO STAT - IN	Transmission		34.50	13.00		7.50	1			0	0.00
82	ELLISON ROAD - IN	Transmission		138.00	13.09		20.00	1			0	0.00
83	ELMRIDGE - IN	Distribution		34.50	13.00		9.38	1			0	0.00
84	ELWOOD (IM) - IN	Distribution		34.50	13.00		18.75	2			0	0.00
85	ELWOOD (IM) - IN	Distribution		34.50	0.00	0.00	0.00			STATCAP	1	5.40
86	FAIRMOUNT - IN	Distribution		34.50	7.20		10.50	1			0	0.00
87	FARMLAND - IN	Distribution		69.00	13.09		20.00	1			0	0.00
88	FERGUSON - IN	Distribution		69.00	13.00		20.00	1			0	0.00
89	FISHER BODY - IN	Distribution		138.00	13.80		100.00	2			0	0.00
90	FULTON (IM) - IN	Distribution		34.50	13.00		20.00	1			0	0.00
91	GAS CITY - IN	Distribution		34.50	0.00	0.00	0.00			STATCAP	1	9.60
92	GAS CITY - IN	Distribution		34.50	13.00		20.00	1			0	0.00
93	GASTON - IN	Distribution		138.00	13.09		20.00	1			0	0.00
94	GATEWAY (IM) - IN	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	13.19
95	GATEWAY (IM) - IN	Transmission		69.00	34.00		20.00	1			0	0.00
96	GERMAN - IN	Distribution		138.00	13.09		47.40	2			0	0.00
97	GLENBROOK - IN	Distribution		34.50	13.00		40.00	2			0	0.00
98	GRABILL - IN	Distribution		138.00	13.09		20.00	1			0	0.00
99	GRANGER - IN	Distribution		138.00	12.47		20.00	1			0	0.00
100	GRANGER - IN	Distribution		138.00	13.09		20.00	1			0	0.00
101	GRANT - IN	Transmission		138.00	34.50		30.00	1			0	0.00
102	GRANT - IN	Transmission		138.00	13.09		20.00	1			0	0.00
103	GREENLEAF - IN	Distribution		34.50	13.09		20.00	1			0	0.00
104	HACIENDA - IN	Distribution		138.00	13.09		45.00	2			0	0.00
105	HADLEY - IN	Distribution		69.00	13.00		40.00	2			0	0.00
106	HAMILTON - IN	Distribution		69.00	13.00		21.00	2			0	0.00
107	HAMILTON - IN	Distribution		69.00	12.00		21.00	2			0	0.00
108	HARLAN - IN	Distribution		69.00	13.09		12.50	1			0	0.00
109	HARPER - IN	Distribution		138.00	13.09		20.00	1			0	0.00
110	HARTFORD CITY - IN	Transmission		69.00	34.00		20.00	1			0	0.00
111	HARTFORD CITY - IN	Transmission		69.00	13.00		20.00	1			0	0.00
112	HARVEST PARK - IN	Distribution		34.50	13.00		20.00	1			0	0.00
113	HAYMOND - IN	Distribution		34.50	13.00		24.00	2			0	0.00
114	HILLCREST - IN	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	52.79
115	HILLCREST - IN	Transmission		138.00	13.09		22.40	1			0	0.00
116	HUMMEL CREEK - IN	Transmission		138.00	69.00	34.00	75.00	1			0	0.00
117	HUMMEL CREEK - IN	Transmission		138.00	13.09		20.00	1			0	0.00
118	ILLINOIS ROAD - IN	Transmission		138.00	69.00	13.00	84.00	1			0	0.00
119	ILLINOIS ROAD - IN	Transmission		138.00	13.09		20.00	1			0	0.00
120	INDUSTRIAL PARK - IN	Transmission		138.00	13.09		22.40	1			0	0.00
121	INDUSTRIAL PARK - IN	Transmission		138.00	69.00	34.00	75.00	1			0	0.00
122	INDUSTRIAL PARK - IN	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	50.40
123	INDUSTRIAL PARK - IN	Transmission		34.50	13.00		22.40	1			0	0.00
124	IRELAND ROAD - IN	Distribution		138.00	13.09		20.00	1			0	0.00
125	IU PURDUE - IN	Distribution		13.80	4.00		5.00	1			0	0.00
126	JACKSON ROAD - IN	Transmission		138.00	13.09		32.00	2			0	0.00
127	JAY (IM) - IN	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	57.60
128	JAY (IM) - IN	Transmission		138.00	13.09		9.38	1			0	0.00
129	JAY (IM) - IN	Transmission		138.00	69.00	34.00	115.00	1			0	0.00
130	JEFFERSON (IM) - IN	Transmission		765.00						REACTOR	4	400.00
131	JOBES - IN	Distribution		34.50	4.00		9.38	1			0	0.00
132	JONES CREEK - IN	Distribution		138.00	12.47		20.00	1			0	0.00
133	KANKAKEE - IN	Transmission		138.00	13.09		22.40	1			0	0.00
134	KANKAKEE - IN	Transmission		138.00	70.50	36.20	130.00	1			0	0.00
135	KENDALLVILLE - IN	Transmission		69.00	12.00		10.50	1			0	0.00
136	KENDALLVILLE - IN	Transmission		69.00	13.00		7.50	1			0	0.00
137	KENDALLVILLE - IN	Transmission		138.00	69.00	13.00	75.00	1			0	0.00
138	KENDALLVILLE - IN	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	43.20
139	KINGSLAND - IN	Distribution		69.00	13.00		4.69	1			0	0.00
140	KLINE - IN	Transmission		138.00	34.00		100.00	1			0	0.00
141	LANTERN PARK - IN	Distribution		138.00	13.09		20.00	1			0	0.00
142	LAWRENCEBURG (AEG) - IN	Generation		4.16				2			0	0.00
143	LIGONIER - IN	Distribution		138.00	13.09		29.38	2			0	0.00
144	LINCOLN - IN	Transmission		138.00	13.09		20.00	1			0	0.00
145	LINCOLN - IN	Transmission		138.00	36.20		75.00	1			0	0.00
146	LINCOLN - IN	Transmission		138.00	70.50	36.20	200.00	1			0	0.00
147	LINWOOD (IM) - IN	Distribution		138.00	13.09		10.50	1			0	0.00
148	LOBDELL - IN	Distribution		69.00	0.48		2.80	1			0	0.00
149	LYDICK - IN	Distribution		34.50	13.09		20.00	1			0	0.00
150	LYNN - IN	Distribution		69.00	13.00		7.00	1			0	0.00
151	MADISON (IM) - IN	Transmission		138.00	35.00		60.00	1			0	0.00
152	MADISON (IM) - IN	Transmission		34.50	13.09		5.00	1			0	0.00
153	MAGLEY - IN	Transmission		138.00	69.00	13.00	90.00	1			0	0.00
154	MAGLEY - IN	Transmission		69.00	13.00		9.38	1			0	0.00
155	MARION ETHANOL - IN	Distribution		34.50	4.00		10.50	1			0	0.00
156	MARION PLANT - IN	Distribution		34.50	13.00		22.40	1			0	0.00
157	MARION PLANT - IN	Distribution		34.50	4.00		6.00	1			0	0.00
158	MARION PLANT - IN	Distribution		34.50	0.00	0.00	0.00			STATCAP	1	8.75
159	MAYFIELD - IN	Distribution		138.00	13.09		20.00	1			0	0.00
160	MCCLURE - IN	Distribution		34.50	4.00		7.50	1			0	0.00
161	MCGALLIARD ROAD - IN	Distribution		34.50	13.09		25.00	1			0	0.00
162	MCKINLEY - IN	Transmission		138.00	13.09		40.00	2			0	0.00
163	MCKINLEY - IN	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	21.60
164	MCKINLEY - IN	Transmission		138.00	34.00		112.00	1			0	0.00
165	MCKINLEY - IN	Transmission		138.00	70.50	36.20	130.00	1			0	0.00
166	MCKINLEY - IN	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	86.40
167	MEADOW LAKE SW - IN	Transmission		345.00	0.00	0.00	0.00			STATCAP	2
168	MEADOWBROOK - IN	Transmission		138.00	35.00		100.00	1			0	0.00
169	MIER - IN	Distribution		138.00	13.09		10.50	1			0	0.00
170	MILLER AVENUE - IN	Distribution		34.50	4.00		8.00	1			0	0.00
171	MISSISSINEWA - IN	Distribution		138.00	13.09		12.00	1			0	0.00
172	MOCK AVENUE - IN	Distribution		34.50	4.00		3.75	1			0	0.00
173	MODOC - IN	Transmission		69.00	13.00		5.00	1			0	0.00
174	MODOC - IN	Transmission		138.00	69.00	13.00	60.00	1			0	0.00
175	MONROE (IM) - IN	Distribution		69.00	13.00		7.50	1			0	0.00
176	MURRAY - IN	Distribution		69.00	13.00		5.00	1			0	0.00
177	NEW CARLISLE - IN	Transmission		138.00	34.50		30.00	1			0	0.00
178	NORTH KENDALLVILLE - IN	Distribution		69.00	12.00		22.40	1			0	0.00
179	NORTHLAND - IN	Distribution		138.00	13.09		32.00	2			0	0.00
180	OLIVE - IN	Transmission		345.00	138.00	34.50	675.00	1			0	0.00
181	OLIVE - IN	Transmission		138.00	13.09		9.38	1			0	0.00
182	OSOLO - IN	Transmission		138.00	13.09		20.00	1			0	0.00
183	OSSIAN - IN	Distribution		69.00	13.00		20.00	1			0	0.00
184	PARKWAY - IN	Distribution		34.50	13.00		4.69	1			0	0.00
185	PARNELL - IN	Distribution		34.50	13.00		20.00	1			0	0.00
186	PARNELL - IN	Distribution		34.50	13.09		20.00	1			0	0.00
187	PEACOCK - IN	Distribution		34.50	13.00		4.70	1			0	0.00
188	PENDLETON - IN	Transmission		138.00	35.00		75.00	1			0	0.00
189	PENNVILLE - IN	Distribution		138.00	34.00	13.00	7.50	1			0	0.00
190	PHILIPS - IN	Distribution		69.00	0.48		2.50	1			0	0.00
191	PINE ROAD - IN	Distribution		138.00	13.09		20.00	1			0	0.00
192	PIPE CREEK - IN	Distribution		138.00	12.00		20.00	1			0	0.00
193	PLEASANT - IN	Distribution		69.00	13.00		5.00	1			0	0.00
194	PLEASANT - IN	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	13.19
195	PORTLAND (IM) - IN	Distribution		69.00	13.00		16.80	2			0	0.00
196	PRICE - IN	Distribution		69.00	13.09		20.00	1			0	0.00
197	RANDOLPH - IN	Transmission		34.50	12.00		3.75	1			0	0.00
198	RANDOLPH - IN	Transmission		138.00	69.00	13.00	56.00	1			0	0.00
199	RANDOLPH - IN	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	13.50
200	RANDOLPH - IN	Transmission		138.00	13.09		22.40	1			0	0.00
201	REED - IN	Distribution		138.00	13.09		22.40	1			0	0.00
202	RENNER STREET - IN	Distribution		69.00	0.48		2.50	0	1		0	0.00
203	ROBISON PARK - IN	Transmission		138.00	13.09		20.00	1			0	0.00
204	ROBISON PARK - IN	Transmission		138.00	13.09		25.00	1			0	0.00
205	ROBISON PARK - IN	Transmission		138.00	70.50	36.20	90.00	1			0	0.00
206	ROCKPORT - IN	Transmission		34.50	13.00		1.50	2			0	0.00
207	ROSE HILL - IN	Distribution		138.00	13.00		7.50	1			0	0.00
208	ROYERTON - IN	Distribution		138.00	13.09		10.50	1			0	0.00
209	SATURN - IN	Transmission		138.00	13.09		12.50	1			0	0.00
210	SELMA PARKER - IN	Transmission		138.00	13.09		20.00	1			0	0.00
211	SHARON ROAD - IN	Distribution		34.50	13.00		2.50	3			0	0.00
212	SORENSON - IN	Transmission		345.00	138.00	34.00	675.00	1			0	0.00
213	SORENSON - IN	Transmission		765.00	345.00	34.50		0	1		0	0.00
214	SORENSON - IN	Transmission		138.00	13.09		9.38	1			0	0.00
215	SORENSON - IN	Transmission		345.00	138.00	34.50	675.00	1			0	0.00
216	SOUTH BEND - IN	Transmission		138.00	13.09		20.00	1			0	0.00
217	SOUTH BEND - IN	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	52.79
218	SOUTH BEND - IN	Transmission		138.00	69.00	34.00	130.00	1			0	0.00
219	SOUTH BERNE - IN	Distribution		69.00	12.00		12.00	1			0	0.00
220	SOUTH DECATUR - IN	Distribution		69.00	13.00		20.00	1			0	0.00
221	SOUTH DECATUR - IN	Distribution		69.00	13.09		20.00	1			0	0.00
222	SOUTH ELWOOD - IN	Transmission		138.00	13.09		20.00	1			0	0.00
223	SOUTH ELWOOD - IN	Transmission		138.00	34.00		30.00	1			0	0.00
224	SOUTH SIDE (MARION) - IN	Distribution		34.50	13.09		20.00	1			0	0.00
225	SOUTH SIDE (SOUTH BEND) - IN	Distribution		138.00	13.09		20.00	1			0	0.00
226	SOUTH SUMMITVILLE - IN	Transmission		34.50	13.09		20.00	1			0	0.00
227	SOYA - IN	Distribution		34.50	4.00		10.50	1			0	0.00
228	SPRING STREET - IN	Distribution		34.50	13.00		7.50	1			0	0.00
229	SPRING STREET - IN	Distribution		34.50	12.00		12.00	1			0	0.00
230	SPY RUN 34 - IN	Distribution		34.50	12.00		20.00	1			0	0.00
231	SPY RUN SF6 - IN	Transmission		138.00	13.09		22.40	1			0	0.00
232	SPY RUN SF6 - IN	Transmission		138.00	34.00		200.00	2			0	0.00
233	ST MARYS COLLEGE - IN	Distribution		34.50	4.33		8.00	1			0	0.00
234	ST. JOE - IN	Distribution		69.00	13.09		20.00	1			0	0.00
235	STATE STREET - IN	Distribution		138.00	13.09		25.00	1			0	0.00
236	STUDEBAKER - IN	Distribution		138.00	13.80		36.00	2			0	0.00
237	STUDEBAKER - IN	Distribution		138.00	13.09		20.00	1			0	0.00
238	SULLIVAN (IM) - IN	Transmission		765.00						REACTOR	1	50.00
239	SUMMIT - IN	Distribution		138.00	13.09		40.00	2			0	0.00
240	SWANSON - IN	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.40
241	SWANSON - IN	Distribution		69.00	34.00		45.00	2			0	0.00
242	THOMAS ROAD - IN	Distribution		69.00	13.09		20.00	1			0	0.00
243	THREE M - IN	Distribution		69.00	4.00		12.50	1			0	0.00
244	THREE RIVERS (FTW) - IN	Distribution		34.50	13.00		10.00	2			0	0.00
245	TILLMAN - IN	Transmission		138.00	36.20		18.00	1			0	0.00
246	TILLMAN - IN	Transmission		138.00	13.09		10.00	1			0	0.00
247	TORRINGTON - IN	Distribution		34.50	4.00		9.07	1			0	0.00
248	TRIER - IN	Distribution		138.00	13.09		20.00	1			0	0.00
249	TRI-LAKES - IN	Distribution		69.00	13.00		3.75	1			0	0.00
250	TWENTY FIRST STREET - IN	Distribution		34.50	13.00		18.75	2			0	0.00
251	TWENTY THIRD STREET (IM) - IN	Transmission		138.00	69.00	34.00	213.00	2			0	0.00
252	TWENTY THIRD STREET (IM) - IN	Transmission		34.50	0.00	0.00	0.00			STATCAP	2	28.80
253	TWIN BRANCH 138KV - IN	Transmission		138.00	13.09		20.00	1			0	0.00
254	TWIN BRANCH 345KV - IN	Transmission		345.00	137.50	13.20	450.00	1			0	0.00
255	TWIN BRANCH 345KV - IN	Transmission		345.00	138.00	34.50	675.00	1			0	0.00
256	TWIN BRANCH 34KV - IN	Transmission		34.50	13.00		2.67	1			0	0.00
257	UP RIVER DAM - IN	Distribution		13.80	4.00		1.50	3			0	0.00
258	UP RIVER DAM - IN	Distribution		34.50	4.00		1.50	3			0	0.00
259	UPLAND - IN	Distribution		69.00	13.20		20.00	1			0	0.00
260	UTICA (IM) - IN	Distribution		34.50	13.09		42.40	2			0	0.00
261	VAN BUREN - IN	Transmission		138.00	69.00	13.00	56.00	1			0	0.00
262	WABASH AVENUE - IN	Distribution		69.00	13.09		20.00	1			0	0.00
263	WALLEN - IN	Transmission		138.00	69.00	34.00	90.00	1			0	0.00
264	WALLEN - IN	Transmission		138.00	13.09		45.00	2			0	0.00
265	WARREN - IN	Distribution		69.00	12.00		7.00	1			0	0.00
266	WATER POLLUTION - IN	Distribution		34.50	4.00		7.00	1			0	0.00
267	WAYNE TRACE - IN	Distribution		138.00	13.09		22.40	1			0	0.00
268	WAYNEDALE - IN	Distribution		138.00	13.09		22.40	1			0	0.00
269	WAYNEDALE - IN	Distribution		138.00	12.47		20.00	1			0	0.00
270	WEST END - IN	Distribution		34.50	4.00		7.50	1			0	0.00
271	WEST END - IN	Distribution		34.50	13.00		8.75	2			0	0.00
272	WEST SIDE - IN	Transmission		138.00	13.09		42.40	2			0	0.00
273	WEST SIDE - IN	Transmission		138.00	69.00	34.00	84.00	1			0	0.00
274	WHITLEY SW - IN	Transmission		34.50	0.00	0.00	0.00			STATCAP	1	4.80
275	WINCHESTER (IM) - IN	Transmission		69.00	0.00	0.00	0.00			STATCAP	2	21.60
276	WINCHESTER (IM) - IN	Transmission		69.00	13.00		26.25	2			0	0.00
277	WOLF LAKE - IN	Distribution		69.00	13.00	0.00	7.50	1			0	0.00
278	WOODS ROAD - IN	Distribution		138.00	12.00		10.00	1			0	0.00
279	ALMENA - MI	Transmission		69.00	34.50		30.00	1			0	0.00
280	ALMENA - MI	Transmission		69.00	12.00		7.00	1			0	0.00
281	BANGOR - MI	Distribution		69.00	12.00		6.25	1			0	0.00
282	BARODA - MI	Distribution		138.00	13.09		20.00	1			0	0.00
283	BENTON HARBOR - MI	Transmission		345.00	137.50	13.80	3600.00	8			0	0.00
284	BENTON HARBOR - MI	Transmission		345.00	137.50	13.14	224.00	0	1		0	0.00
285	BENTON HARBOR WATERWORKS - MI	Distribution		34.50	2.40		0.67	0	1		0	0.00
286	BENTON HARBOR WATERWORKS - MI	Distribution		34.50	13.00		1.00	3			0	0.00
287	BERRIEN SP HYDR STAT - MI	Transmission		34.50	12.00		5.00	1			0	0.00
288	BERRIEN SP HYDR STAT - MI	Transmission		34.50	13.00		5.00	1			0	0.00
289	BERRIEN SP HYDR STAT - MI	Transmission		34.50	0.00	0.00	0.00			STATCAP	1	9.60
290	BRIDGMAN - MI	Distribution		69.00	12.00		18.90	2			0	0.00
291	BRIDGMAN - MI	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.40
292	BUCHANAN HYDRO STA - MI	Transmission		69.00	34.00		20.00	1			0	0.00
293	BUCHANAN HYDRO STA - MI	Transmission		69.00	12.00		7.50	1			0	0.00
294	BUCHANAN SOUTH - MI	Distribution		69.00	12.00		22.40	1			0	0.00
295	CAMERON - MI	Distribution		69.00	34.00		7.50	1			0	0.00
296	COLBY - MI	Transmission		138.00	69.00	34.50	75.00	1			0	0.00
297	COLBY - MI	Transmission		69.00	34.50		20.00	1			0	0.00
298	COLBY - MI	Transmission		138.00	13.09		8.40	1			0	0.00
299	COLBY - MI	Transmission		34.50	0.00	0.00	0.00			STATCAP	1	12.00
300	COREY - MI	Transmission		138.00	69.00	34.50	130.00	1			0	0.00
301	COREY - MI	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.40
302	COVERT - MI	Distribution		69.00	13.00		9.38	1			0	0.00
303	CRYSTAL - MI	Distribution		138.00	13.09		22.40	1			0	0.00
304	DC COOK 69/12 - MI	Transmission		69.00	0.00	0.00	0.00			STATCAP	1
305	DC COOK 69/12 - MI	Transmission		69.00	13.00		1.50	1			0	0.00
306	EAST WATERVLIET - MI	Distribution		138.00	13.09		20.00	1			0	0.00
307	EAU CLAIRE - MI	Distribution		34.50	13.00		4.25	1			0	0.00
308	FLORENCE ROAD - MI	Distribution		69.00	12.00		20.00	1			0	0.00
309	FLORENCE ROAD - MI	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	9.60
310	HAGAR - MI	Distribution		69.00	12.00		10.50	1			0	0.00
311	HARTFORD - MI	Transmission		138.00	70.50	36.20	54.00	1			0	0.00
312	HICKORY CREEK - MI	Transmission		138.00	69.00	34.50	75.00	1			0	0.00
313	INDIAN LAKE - MI	Distribution		34.50	13.00		1.60	1			0	0.00
314	KENZIE CREEK - MI	Transmission		345.00	137.50	13.80	450.00	1			0	0.00
315	LAKE STREET - MI	Transmission		69.00	34.00		40.00	1			0	0.00
316	LAKE STREET - MI	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.40
317	LAKESIDE (MBH) - MI	Distribution		69.00	13.09		9.38	1			0	0.00
318	LAKESIDE (MBH) - MI	Distribution		69.00	12.00		9.38	1			0	0.00
319	LANGLEY (IM) - MI	Distribution		34.50	138.00	13.80		1			0	0.00
320	MAIN STREET - MI	Transmission		138.00	34.00		30.00	1			0	0.00
321	MAIN STREET - MI	Transmission		138.00	13.09		22.40	1			0	0.00
322	MOORE PARK - MI	Transmission		138.00	13.09		20.00	1			0	0.00
323	MOORE PARK - MI	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	16.20
324	MOORE PARK - MI	Transmission		138.00	69.00	34.50	90.00	1			0	0.00
325	MURCH - MI	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	13.20
326	MURCH - MI	Distribution		69.00	12.00		20.00	1			0	0.00
327	NEW BUFFALO - MI	Distribution		69.00	12.00		30.50	2			0	0.00
328	NILES - MI	Transmission		69.00	13.09		20.00	1			0	0.00
329	NILES - MI	Transmission		69.00	34.00		44.80	1			0	0.00
330	NILES - MI	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.39
331	PEARL STREET - MI	Distribution		34.50	12.00		16.88	2			0	0.00
332	PIGEON RIVER - MI	Distribution		69.00	12.00		20.00	1			0	0.00
333	POKAGON(MBH) - MI	Transmission		138.00	69.00	13.00	115.00	1			0	0.00
334	POKAGON(MBH) - MI	Transmission		69.00	13.00		5.00	1			0	0.00
335	POKAGON(MBH) - MI	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.39
336	RICKERMAN ROAD - MI	Distribution		138.00	13.09		7.50	1			0	0.00
337	RIVERSIDE (IM) - MI	Transmission		138.00	0.00	0.00	0			STATCAP	1	53
338	RIVERSIDE (IM) - MI	Transmission		138.00	13.09		20	1			0	0
339	RIVERSIDE (IM) - MI	Transmission		138.00	69.00	34.00	134	2			0	0
340	SAUK TRAIL - MI	Distribution		138.00	13.09		20	1			0	0
341	SCOTTDALE - MI	Distribution		34.50	13.09		9	1			0	0
342	SISTER LAKES - MI	Distribution		34.50	12.00		15	2			0	0
343	SODUS - MI	Distribution		138.00	13.09		11	1			0	0
344	STEVENSVILLE - MI	Distribution		69.00	13.00		8	1			0	0
345	STEVENSVILLE - MI	Distribution		69.00	13.09		13	1			0	0
346	STONE LAKE - MI	Distribution		69.00	13.00		7	1			0	0
347	STONE LAKE - MI	Distribution		69.00	12.00		9	1			0	0
348	STUBEY ROAD - MI	Distribution		69.00	12.00		11	1			0	0
349	STUBEY ROAD - MI	Distribution		69.00	0.00	0.00	0			STATCAP	1	14
350	THREE OAKS - MI	Distribution		69.00	12.00		6	1			0	0
351	THREE RIVERS (MBH) - MI	Distribution		69.00	12.00		22	1			0	0
352	VALLEY - MI	Transmission		138.00	69.00	34.00	75	1			0	0
353	VICKSBURG - MI	Distribution		69.00	12.00		9	1			0	0
354	VICKSBURG - MI	Distribution		69.00	13.09		20	1			0	0
355	WEST STREET - MI	Distribution		138.00	13.09		20	1			0	0
356	WHEELER STREET - MI	Distribution		69.00	13.00		8	1			0	0
357	WOLVERINE - MI	Distribution		69.00	13.00	2.40	5	1			0	0
358	TotalTransmissionSubstationMember											1,843
359	Total											1,843

Name of Respondent:

Indiana Michigan 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	(a) AEPSC	935	5,180,026
3	Customer Service and Informational Expenses	AEPSC	907/908/910	310,587
4	Nuclear Power Generation - Operation	AEPSC	517/520/524	1,216,713
5	Administrative and General Expenses - Operation	AEPSC	920-931	11,713,633
6	Distribution Expenses - Maintenance	OPCo	593/594/595/596/598	287,318
7	Operations & Performance Transformation	AEPSC	920/923	532,657
8	AEPSC Support Svcs	AEPSC	4171	1,338,924
9	Distribution Expenses - Operation	AEPSC	580-588	3,947,669
10	Other Power Generation - Operation	AEPSC	546-550	488,269
11	Audit Services	AEPSC	920/923	1,282,347
12	Economic & Business Development	AEPSC	920/923	543,071
13	Other Power Supply Expenses	AEPSC	556/557	3,932,063
14	Building and Property Leases	IMTCo	567/589	609,451
15	Environmental Services	AEPSC	920/923	407,573
16	Other Property and Investments	AEPSC	121/122	321,223
17	Bus Ops & Perf Assurance	AEPSC	920/923	1,243,898
18	Expenses of Nonutility Operations	APCo	417	5,015,372
19	Physical & Cyber Security	AEPSC	920/923	1,441,008
20	Central Machine Shop	APCo	107,108,163,501,506,512,513,524,531,532,544	2,704,159
21	Factored Customer A/R Bad Debts	AEP Credit	4265	3,725,441
22	Rail Car Lease	SWEPCO	186	650,372
23	Civil & Political Activities and Other Svcs	AEPSC	4261-4265	1,524,195
24	Factored Customer A/R Expense	AEP Credit	4265	5,358,066
25	Rail Car Maintenance	AEGCo	151	609,299
26	Coal Transloading	AEGCo	151	9,183,542
27	Real Estate & Workplace Svcs	AEPSC	920/923	2,501,738
28	Construction Services	AEPSC	107/108/120	76,639,815
29	Fuel & Storeroom Services	AEP Service Corporation	152/163	6,261,778
30	Regulatory Services	AEPSC	920/923	1,920,844
31	Construction Services	IMTCo	107/108	635,862
32	Grid Solutions	AEPSC	920/923	614,797
33	Research and Other Services	AEPSC	183/186/188	3,952,509
34	Construction Services	OPCo	107/108	382,101
35	Hydraulic Power Generation - Operation	AEPSC	535-539	1,231,506
36	Steam Power Generation - Maintenance	AEPSC	510-514	763,868
37	Corp Safety & Health	AEPSC	920/923	1,407,504
38	Information Technology	AEPSC	920/923	11,756,820
39	Steam Power Generation - Operation	AEPSC	500-506	8,321,869
40	Corporate Accounting	AEPSC	920/923	2,687,539
41	Infrastructure Ops & Support	AEPSC	920/923	1,602,869
42	Strategy & Transformation	AEPSC	920/923	363,595
43	Corporate Communications	AEPSC	920/923	1,196,989
44	Legal GC/Administration	AEPSC	920/923	3,409,623
45	Tax Services	AEPSC	920/923	1,198,024
46	Corporate Human Resources	AEPSC	920/923	4,990,716
47	Materials and Supplies	OHTCo	107/108/186/569/570/571/592	365,310
48	Transmission Expenses - Maintenance	AEPSC	568-573	522,782
49	Corporate Planning & Budgeting	AEPSC	920/923	1,621,596
50	Materials and Supplies	OPCo	107/108/163/184/569/570/571/573/592/595/930/935	3,317,129
51	Transmission Expenses - Operation	AEPSC	560/561/561/562/563/566/920/923	8,757,415
52	Customer Accounts Expenses	AEPSC	901-905	9,318,215
53	Nuclear Power Generation - Maintenance	AEPSC	528/530/531/532	3,059,049
54	Treasury & Risk	AEPSC	920/923	2,035,708
55	Customer Operations and Support	AEPSC	920/923	445,781
19
20	Non-power Goods or Services Provided for Affiliated
21	Barging	AEGCo	4170	11,280,171
22	Use of Jointly Owned Facility	IMTCo	454	6,103,665
23	Barging	APCo	4170	36,148,413
24	Barging	KPCo	4170	2,009,631
25	Barging	WPCo	4170	4,677,253
26	Building and Property Leases	AEPSC	4540	1,425,147
27	Construction Services	IMTCo	107/108/116	8,788,993
28	Construction Services	OPCo	107/108	619,454
29	Distribution Expenses - Maintenance	APCo	593/594/596/597	402,383
30	Distribution Expenses - Maintenance	KPCo	592/593	510,453
31	Distribution Expenses - Maintenance	OPCo	592-596	267,568
32	Fleet and Vehicle Charges	AEP Service Corporation	188	745,153
33	Fleet and Vehicle Charges	AEPSC	188	376,260
34	Fuel Carbon Activation	AEGCo	154, 502	2,689,396
35	Fuel Consumed - Ammonia	AEGCo	154, 502	1,126,119
36	Fuel Consumed Handling	AEGCo	152, 501	6,985,566
37	Materials and Supplies	(b) APCo	154	366,757
38	Materials and Supplies	OPCo	154	507,228
39	Rail Car Lease	PSO	151	265,794
40	Rail Car Lease	SWEPCo	151	1,345,761
41	Rockport Joint Books	AEGCo	500/935	46,279,474
42	Sodium Bicarbonate Activation	AEGCo	154, 502	12,157,482
43	Transmission Expenses - Maintenance	IMTCo	568/569/570/571/573	1,963,005
42

Name of Respondent:

Indiana Michigan 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 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 service are made at cost and include no compensation for a return on investment.

(b) Concept: NameOfAssociatedAffiliatedCompany

The Rockport Plant is owned 50% by I&M and 50% by AEG. I&M is the operator of the plant and most charges originate on I&M's general ledger. A joint books process then allocates 50% of those charges to AEG.

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

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

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