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:

2021

/

Q4

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

GENERAL INFORMATION

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

What and Where to Submit

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

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

The CPA Certification Statement should:

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

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

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

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

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

GENERAL INSTRUCTIONS

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

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

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

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

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

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

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

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

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

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

DEFINITIONS

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

EXCERPTS FROM THE LAW

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

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

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

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

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

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

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

"Sec. 304.

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

"Sec. 309.

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

GENERAL PENALTIES

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

FERC FORM NO.

1

REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER

IDENTIFICATION

01 Exact Legal Name of Respondent

Indiana Michigan Power Company

02 Year/ Period of Report

End of:

2021

/

Q4

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

/

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

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)

05/19/2022

Annual Corporate Officer Certification

The undersigned officer certifies that:

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

01 Name

Jeffrey W. Hoersdig

02 Title

Assistant Controller

03 Signature

Jeffrey W. Hoersdig

04 Date Signed (Mo, Da, Yr)

05/19/2022

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

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

LIST OF SCHEDULES (Electric Utility)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line No.	Title of Schedule (a)	Reference Page No. (b)	Remarks (c)
	ScheduleIdentificationAbstract Identification	1
	ScheduleListOfSchedulesAbstract List of Schedules	2
1	ScheduleGeneralInformationAbstract General Information	101
2	ScheduleControlOverRespondentAbstract Control Over Respondent	102
3	ScheduleCorporationsControlledByRespondentAbstract Corporations Controlled by Respondent	103
4	ScheduleOfficersAbstract Officers	104
5	ScheduleDirectorsAbstract Directors	105
6	ScheduleInformationOnFormulaRatesAbstract Information on Formula Rates	106
7	ScheduleImportantChangesDuringTheQuarterYearAbstract Important Changes During the Year	108
8	ScheduleComparativeBalanceSheetAbstract Comparative Balance Sheet	110
9	ScheduleStatementOfIncomeAbstract Statement of Income for the Year	114
10	ScheduleRetainedEarningsAbstract Statement of Retained Earnings for the Year	118
12	ScheduleStatementOfCashFlowsAbstract Statement of Cash Flows	120
12	ScheduleNotesToFinancialStatementsAbstract Notes to Financial Statements	122
13	ScheduleStatementOfAccumulatedOtherComprehensiveIncomeAndHedgingActivitiesAbstract Statement of Accum Other Comp Income, Comp Income, and Hedging Activities	122a
14	ScheduleSummaryOfUtilityPlantAndAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep	200
15	ScheduleNuclearFuelMaterialsAbstract Nuclear Fuel Materials	202
16	ScheduleElectricPlantInServiceAbstract Electric Plant in Service	204
17	ScheduleElectricPropertyLeasedToOthersAbstract Electric Plant Leased to Others	213
18	ScheduleElectricPlantHeldForFutureUseAbstract Electric Plant Held for Future Use	214
19	ScheduleConstructionWorkInProgressElectricAbstract Construction Work in Progress-Electric	216
20	ScheduleAccumulatedProvisionForDepreciationOfElectricUtilityPlantAbstract Accumulated Provision for Depreciation of Electric Utility Plant	219
21	ScheduleInvestmentsInSubsidiaryCompaniesAbstract Investment of Subsidiary Companies	224
22	ScheduleMaterialsAndSuppliesAbstract Materials and Supplies	227
23	ScheduleAllowanceInventoryAbstract Allowances	228
24	ScheduleExtraordinaryPropertyLossesAbstract Extraordinary Property Losses	230a
25	ScheduleUnrecoveredPlantAndRegulatoryStudyCostsAbstract Unrecovered Plant and Regulatory Study Costs	230b
26	ScheduleTransmissionServiceAndGenerationInterconnectionStudyCostsAbstract Transmission Service and Generation Interconnection Study Costs	231
27	ScheduleOtherRegulatoryAssetsAbstract Other Regulatory Assets	232
28	ScheduleMiscellaneousDeferredDebitsAbstract Miscellaneous Deferred Debits	233
29	ScheduleAccumulatedDeferredIncomeTaxesAbstract Accumulated Deferred Income Taxes	234
30	ScheduleCapitalStockAbstract Capital Stock	250
31	ScheduleOtherPaidInCapitalAbstract Other Paid-in Capital	253
32	ScheduleCapitalStockExpenseAbstract Capital Stock Expense	254b
33	ScheduleLongTermDebtAbstract Long-Term Debt	256
34	ScheduleReconciliationOfReportedNetIncomeWithTaxableIncomeForFederalIncomeTaxesAbstract Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax	261
35	ScheduleTaxesAccruedPrepaidAndChargedDuringYearDistributionOfTaxesChargedAbstract Taxes Accrued, Prepaid and Charged During the Year	262
36	ScheduleAccumulatedDeferredInvestmentTaxCreditsAbstract Accumulated Deferred Investment Tax Credits	266
37	ScheduleOtherDeferredCreditsAbstract Other Deferred Credits	269
38	ScheduleAccumulatedDeferredIncomeTaxesAcceleratedAmortizationPropertyAbstract Accumulated Deferred Income Taxes-Accelerated Amortization Property	272
39	ScheduleAccumulatedDeferredIncomeTaxesOtherPropertyAbstract Accumulated Deferred Income Taxes-Other Property	274
40	ScheduleAccumulatedDeferredIncomeTaxesOtherAbstract Accumulated Deferred Income Taxes-Other	276
41	ScheduleOtherRegulatoryLiabilitiesAbstract Other Regulatory Liabilities	278
42	ScheduleElectricOperatingRevenuesAbstract Electric Operating Revenues	300
43	ScheduleRegionalTransmissionServiceRevenuesAbstract Regional Transmission Service Revenues (Account 457.1)	302
44	ScheduleSalesOfElectricityByRateSchedulesAbstract Sales of Electricity by Rate Schedules	304
45	ScheduleSalesForResaleAbstract Sales for Resale	310
46	ScheduleElectricOperationsAndMaintenanceExpensesAbstract Electric Operation and Maintenance Expenses	320
47	SchedulePurchasedPowerAbstract Purchased Power	326
48	ScheduleTransmissionOfElectricityForOthersAbstract Transmission of Electricity for Others	328
49	ScheduleTransmissionOfElectricityByIsoOrRtoAbstract Transmission of Electricity by ISO/RTOs	331
50	ScheduleTransmissionOfElectricityByOthersAbstract Transmission of Electricity by Others	332
51	ScheduleMiscellaneousGeneralExpensesAbstract Miscellaneous General Expenses-Electric	335
52	ScheduleDepreciationDepletionAndAmortizationAbstract Depreciation and Amortization of Electric Plant (Account 403, 404, 405)	336
53	ScheduleRegulatoryCommissionExpensesAbstract Regulatory Commission Expenses	350
54	ScheduleResearchDevelopmentOrDemonstrationExpendituresAbstract Research, Development and Demonstration Activities	352
55	ScheduleDistributionOfSalariesAndWagesAbstract Distribution of Salaries and Wages	354
56	ScheduleCommonUtilityPlantAndExpensesAbstract Common Utility Plant and Expenses	356
57	ScheduleAmountsIncludedInIsoOrRtoSettlementAbstract Amounts included in ISO/RTO Settlement Statements	397
58	SchedulePurchasesSalesOfAncillaryServicesAbstract Purchase and Sale of Ancillary Services	398
59	ScheduleMonthlyTransmissionSystemPeakLoadAbstract Monthly Transmission System Peak Load	400
60	ScheduleMonthlyIsoOrRtoTransmissionSystemPeakLoadAbstract Monthly ISO/RTO Transmission System Peak Load	400a
61	ScheduleElectricEnergyAccountAbstract Electric Energy Account	401a
62	ScheduleMonthlyPeakAndOutputAbstract Monthly Peaks and Output	401b
63	ScheduleSteamElectricGeneratingPlantStatisticsAbstract Steam Electric Generating Plant Statistics	402
64	ScheduleHydroelectricGeneratingPlantStatisticsAbstract Hydroelectric Generating Plant Statistics	406
65	SchedulePumpedStorageGeneratingPlantStatisticsAbstract Pumped Storage Generating Plant Statistics	408
66	ScheduleGeneratingPlantStatisticsAbstract Generating Plant Statistics Pages	410
0	ScheduleEnergyStorageOperationsLargePlantsAbstract Energy Storage Operations (Large Plants)	414
67	ScheduleTransmissionLineStatisticsAbstract Transmission Line Statistics Pages	422
68	ScheduleTransmissionLinesAddedAbstract Transmission Lines Added During Year	424
69	ScheduleSubstationsAbstract Substations	426
70	ScheduleTransactionsWithAssociatedAffiliatedCompaniesAbstract Transactions with Associated (Affiliated) Companies	429
71	FootnoteDataAbstract Footnote Data	450
	StockholdersReportsAbstract Stockholders' Reports (check appropriate box)
	Stockholders' Reports Check appropriate box: ☐ Two copies will be submitted ☐ No annual report to stockholders is prepared

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

GENERAL INFORMATION
1. Provide name and title of officer having custody of the general corporate books of account and address of office where the general corporate books are kept, and address of office where any other corporate books of account are kept, if different from that where the general corporate books are kept. 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: IN Date of Incorporation: 1925-02-21 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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

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

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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

CORPORATIONS CONTROLLED BY RESPONDENT
Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming any intermediaries involved. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests. Definitions See the Uniform System of Accounts for a definition of control. Direct control is that which is exercised without interposition of an intermediary. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line No.	NameOfCompanyControlledByRespondent Name of Company Controlled (a)	CompanyControlledByRespondentKindOfBusinessDescription Kind of Business (b)	VotingStockOwnedByRespondentPercentage Percent Voting Stock Owned (c)	FootnoteReferences Footnote Ref. (d)
1	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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

OFFICERS
Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function (such as sales, administration or finance), and any other person who performs similar policy making functions. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous incumbent, and the date the change in incumbency was made.
Line No.	OfficerTitle Title (a)	OfficerName Name of Officer (b)	OfficerSalary Salary for Year (c)	DateOfficerIncumbencyStarted Date Started in Period (d)	DateOfficerIncumbencyEnded Date Ended in Period (e)
1	(a) Footnote

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: OfficerTitle

The following table provides summary information concerning compensation earned by our Chief Executive Officer, our Chief Financial Officer and the three other most highly compensated executive officers, to whom we refer collectively 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	2021	1,515,808		9,976,149	2,850,000	461,732	247,526	15,051,215


Julia A. Sloat
Executive Vice President and Chief Financial Officer	2021	602,308		1,628,789	637,350	76,622	58,042	3,003,111


Lisa M. Barton
Executive Vice President and Chief Operating Officer	2021	803,077		2,443,104	890,000	165,173	88,143	4,389,497


David M. Feinberg
Executive Vice President, General Counsel and Secretary	2021	696,669		1,527,000	690,000	93,625	98,652	3,105,946


Charles E. Zebula
Executive Vice President - Portfolio Optimization	2021	579,219		1,323,341	640,000	42,921	71,745	2,657,226


Brian X. Tierney
Former Executive Vice President - Strategy	2021	410,000	—	2,675,947	—	—	732,507	3,818,454


Mark C. McCullough
Former Executive Vice President - Energy Delivery	2021	322,327	—	1,823,341	—	—	1,115,159	3,260,827

(1) Amounts in the salary column are composed of executive salaries earned for the year shown, which include 261 days of pay for 2021. This is one day more than the standard 260 calendar work days and holidays in a 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, 2021 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 2021 performance shares will be based on three measures: a Board approved cumulative operating earnings per share measure (Cumulative EPS 50%), a total shareholder return measure (Relative TSR 40%) and a carbon free capacity mix (Carbon Free Capacity 10%). The grant date fair value of the 2021 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 2021 performance shares that are based on Cumulative EPS measured on the grant date was $7,350,035 for Mr. Akins; $1,200,060 for Ms. Sloat; $1,800,012 for Ms. Barton; $1,125,066 for Mr. Feinberg; $975,000 for Mr. Zebula; $1,500,036 for Mr. Tierney; and $975,000 for Mr. McCullough. The maximum amount payable for the 2021 performance shares that are based on Carbon Free Capacity is equal to $1,470,007 for Mr. Akins; $240,012 for Ms. Sloat; $360,002 for Ms. Barton; $225,013 for Mr. Feinberg; $195,000 for Mr. Zebula; $300,007 for Mr. Tierney; and $195,000 for Mr. McCullough. The grant date fair value of the 2021 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 2019 performance shares are included in the Option Exercises and Stock Vested for 2021 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 ($404,033) and ($269,258) for Messrs. Tierney and McCullough, respectfully, were replaced with $0 for the purposes of the Summary Compensation Table. These negative values were caused by their severance from the company during 2021, which resulted in the removal of projected benefits that would have been attributable to eligible earnings for future years under these plans. See the Pension Benefits for 2021 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, 2021 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 2021 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 2021 values for these items are listed in the following table:


Type	Nicholas K. Akins		Julia A. Sloat		Lisa M. Barton		David M. Feinberg		Charles E. Zebula		Brian X. Tierney		Mark C. McCullough
Retirement Savings Plan Match	$ 13,05		$ 13,05		$ 13,05		$ 13,05		$ 13,05		$ 13,05		$ 13,05
Supplemental Retirement Savings Plan Match	212,400		31,272		61,373		56,295		46,665		53,097		35,468
Perquisites	22,076		13,720		13,720		29,307		12,030		6,360		6,804
Vacation Payout	—		—		—		—		—		41,000		60,837
Severance	—		—		—		—		—		619,000		999,000
Total	$	247,526	$	58,042	$	88,143	$	98,652	$	71,745	$	732,507	$	1,115,159

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

Perquisites provided in 2021 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).

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.

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

DIRECTORS
Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), name and abbreviated titles of the directors who are officers of the respondent. Provide the principle place of business in column (b), designate members of the Executive Committee in column (c), and the Chairman of the Executive Committee in column (d).
Line No.	NameAndTitleOfDirector Name (and Title) of Director (a)	PrincipalBusinessAddress Principal Business Address (b)	MemberOfTheExecutiveCommittee Member of the Executive Committee (c)	ChairmanOfTheExecutiveCommittee Chairman of the Executive Committee (d)
1	Nicholas K. Akins - Chief Executive Officer, Chairman of the Executive Committee and Chief Executive Officer	Columbus, Ohio	true	true
2	Toby L. Thomas - President and Chief Operating Officer	Fort Wayne, Indiana	false	false
3	Steven F.Baker - Chief Operating Officer and President	Fort Wayne, Indiana	true	false
4	Katherine K.Davis - Vice President - External Affairs and Customer Experience	Fort Wayne, Indiana	false	false
5	Nicholas M.Elkins - Director Customer and Business Services	Fort Wayne, Indiana	false	false
6	David S. Isaacson - Vice President - Distribution Region Operations	Fort Wayne, Indiana	false	false
7	Julia A. Sloat - Vice President and Chief Financial Officer	Columbus, Ohio	true	false
8	Lisa M .Barton - Vice President	Columbus, Ohio	true	false
9	Andrew J. Williamson - Director Regulatory Services	Fort Wayne, Indiana	false	false

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

INFORMATION ON FORMULA RATES
Does the respondent have formula rates?		☑ Yes ☐ No
Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No) accepting the rate(s) or changes in the accepted rate.
Line No.	RateScheduleTariffNumber FERC Rate Schedule or Tariff Number (a)	ProceedingDocketNumber FERC Proceeding (b)
1	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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

INFORMATION ON FORMULA RATES - FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent file with the Commission annual (or more frequent) filings containing the inputs to the formula rate(s)?			☑ Yes ☐ No
If yes, provide a listing of such filings as contained on the Commission's eLibrary website.
Line No.	AccessionNumber Accession No. (a)	DocumentDate Document Date / Filed Date (b)	DocketNumber Docket No. (c)	DescriptionOfFiling Description (d)	RateScheduleTariffNumber Formula Rate FERC Rate Schedule Number or Tariff Number (e)
1	20211221-5274	12/21/2021	ER17-405	AEP PJM OATT Proj Transmission	PJM OATT Attachment H-14
2	20211101-5315	11/01/2021	ER17-405	AEP PJM OATT Proj Transmission	PJM OATT Attachment H-14
3	20210525-5243	05/25/2021	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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

INFORMATION ON FORMULA RATES - Formula Rate Variances
If a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from amounts reported in the Form 1. The footnote should provide a narrative description explaining how the "rate" (or billing) was derived if different from the reported amount in the Form 1. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.
Line No.	PageNumberOfFormulaRateVariances Page No(s). (a)	ScheduleOfFormulaRateVariances Schedule (b)	ColumnOfFormulaRateVariances Column (c)	LineNumberOfFormulaRateVariances Line No. (d)
1	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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR

Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.

Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the franchise rights were acquired. If acquired without the payment of consideration, state that fact.
Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to Commission authorization.
Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto, and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts were submitted to the Commission.
Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give reference to such authorization.
Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as appropriate, and the amount of obligation or guarantee.
Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
State the estimated annual effect and nature of any important wage scale changes during the year.
State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such proceedings culminated during the year.
Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer, director, security holder reported on Pages 104 or 105 of the Annual Report Form No. 1, voting trustee, associated company or known associate of any of these persons was a party or in which any such person had a material interest.
(Reserved.)
If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred during the reporting period.
In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30 percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.


Date Acquired Or Extended	Community	Period of Franchise & Termination	Consideration
Automatic Renewal in March 2021	Benton Charter Township-Berrien Co-Michigan	Thirty (30) years expiring March 02, 2051	None
Automatic Renewal in January 2021	Village of Galien-Berrien Co-Michigan	Thirty (30) years expiring November 09, 2050	None
Automatic Renewal in March 2021	City of Buchanan-Berrien Co-Michigan	Thirty (30) years expiring March 22, 2051	None
June 19, 2021	Milton Township-Cass County-Michigan	Ten (10) years expiring June 19, 2031	None

$450M Indiana Michigan Power Company Senior Unsecured Notes (State Authority Cause No. 45418.Issued -4/29/2021, Maturity 5/1/2051)

$64.9M-Nuclear Fuel Lease (State Authority: Cause No. 45417, Issued 5/18/2021, Maturity 11/18/2025)

Remarketed $40M City of Rockport, Series D Pollution Control Bond IN State Commission Authority: N/A SEC Registration Statement: N/A

Issued: 12/14/2021

Maturity: 4/1/2025

75 Cook Nuclear Plant Maintenance employees represented by IBEW #1392 were provided with a 2.5% wage effective April 1,2021

14 Cook Nuclear Plant Stores employees represented by IBEW #1392 were provided with a 2.5% wage effective April 1, 2021

56 Cook Nuclear Plant RPEC employees represented by IBEW #1392 were provided with a 2.5% wage effective April 1, 2021

64 Cook Nuclear Plant Non Licensed Operators employees represented by IBEW #1392 were provided with a 2.5% wage effective April 1, 2021

18 Cook Nuclear Planners employees represented by IBEW #1392 were provided with a Merit Pay Plan -CBA Extension effective April 1, 2021

80 River Transportation employees represented by IBEW #14811 were provided with a 2.5% wage effective April 1,2021

87 Fort Wayne employees represented by IBEW #1392 were provided with a 2.5% wage effective November 11,2021

75 Muncie employees represented by IBEW #1392 were provided with a 2.5% wage effective November 11,2021

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

Sloat, Julia A elected as Director & Chief Financial Officer effective 1/1/2021

Sherwood, Julie A elected as Treasurer effective 1/1/2021

Lucas, David A elected as Vice President - Regulatory & Finance effective 1/1/2021

Davis, Katherine elected as Vice President - External Affairs effective 3/15/2021

Mueller, Daniel E elected as Assistant Vice President – Tax effective 3/24/2021

Moore, Scott P elected Vice President effective 5/19/2021

Smith, Wade A resigned as Vice president on 5/1/2021

Lewis, Marc E resigned as VP - External & Regulatory Affairs on 6/30/2021

Tierney, Brian X resigned as Director on 5/1/2021

Lewis, Marc E resigned as Director on 6/30/2021

McCullough, Mark C resigned as Director on 5/01/2021

Davis, Katherine K elected as Director effective 7/01/2021

Baker, Steven F elected as Director, Chief Operating officer and president effective

7/31/2021

Risch, Therace M elected as Vice President effective on 7/03/2021

Zebula, Charles E elected as Vice President effective on 7/03/2021

Baker, Steven F elected as President on 7/31/2021

Thomas, Toby L resigned as Chief Operating Officer, President and Director on

7/30/2021

McCullough, Mark C resigned as Vice President on 7/30/2021

Tierney, Brian X resigned as Vice President on 7/01/2021

Thomas, Toby L elected as Director effective 10/02/2021

Williamson, Andrew J elected as Director effective 10/02/2021

Lucas, David A resigned as Director on 10/22/2021

Feinberg, David M resigned as Director on 10/22/2021

Proprietary capital ratio exceeds 30%

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line No.	Title of Account (a)	Ref. Page No. (b)	Current Year End of Quarter/Year Balance (c)	Prior Year End Balance 12/31 (d)
1	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlant Utility Plant (101-106, 114)	200	10,717,411,486	10,189,260,941
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	303,725,635	362,634,813
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		11,021,137,120	10,551,895,754
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	3,820,179,577	3,472,869,418
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		7,200,957,543	7,079,026,336
7	NuclearFuelInProcessOfRefinementConversionEnrichmentAndFabrication Nuclear Fuel in Process of Ref., Conv., Enrich., and Fab. (120.1)	202	41,389,512	34,631,005
8	NuclearFuelMaterialsAndAssembliesStockAccountMajorOnly Nuclear Fuel Materials and Assemblies-Stock Account (120.2)
9	NuclearFuelAssembliesInReactorMajorOnly Nuclear Fuel Assemblies in Reactor (120.3)		1,072,702	1,460,144
10	SpentNuclearFuelMajorOnly Spent Nuclear Fuel (120.4)		605,712,062	628,146,562
11	NuclearFuelUnderCapitalLeases Nuclear Fuel Under Capital Leases (120.6)		118,624,550	138,923,597
12	AccumulatedProvisionForAmortizationOfNuclearFuelAssemblies (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)	202	605,718,624	629,038,752
13	NuclearFuelNet Net Nuclear Fuel (Enter Total of lines 7-11 less 12)		161,080,202	174,122,556
14	UtilityPlantAndNuclearFuelNet Net Utility Plant (Enter Total of lines 6 and 13)		7,362,037,745	7,253,148,891
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)		1,718,313
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)
17	OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS
18	NonutilityProperty Nonutility Property (121)		71,135,454	74,900,755
19	AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Prov. for Depr. and Amort. (122)		36,244,202	31,828,828
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224	22,647,944	19,866,131
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances	228	25,304,843	25,591,061
24	OtherInvestments Other Investments (124)		11,890,852	12,298,339
25	SinkingFunds Sinking Funds (125)
26	DepreciationFund Depreciation Fund (126)
27	AmortizationFundFederal Amortization Fund - Federal (127)
28	OtherSpecialFunds Other Special Funds (128)		3,867,016,020	3,306,650,990
29	SpecialFunds Special Funds (Non Major Only) (129)		201,474,750	143,372,607
30	DerivativeInstrumentAssetsLongTerm Long-Term Portion of Derivative Assets (175)			75,597
31	DerivativeInstrumentAssetsHedgesLongTerm Long-Term Portion of Derivative Assets - Hedges (176)
32	OtherPropertyAndInvestments TOTAL Other Property and Investments (Lines 18-21 and 23-31)		4,163,225,662	3,550,926,652
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)		1,277,594	3,338,136
36	SpecialDeposits Special Deposits (132-134)		18,873,630	1,797,825
37	WorkingFunds Working Fund (135)		6	399
38	TemporaryCashInvestments Temporary Cash Investments (136)
39	NotesReceivable Notes Receivable (141)
40	CustomerAccountsReceivable Customer Accounts Receivable (142)		46,461,981	51,844,520
41	OtherAccountsReceivable Other Accounts Receivable (143)		2,485,873	2,014,763
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		127,329	290,728
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)		75,154,170	47,848,863
45	FuelStock Fuel Stock (151)	227	53,538,758	81,606,797
46	FuelStockExpensesUndistributed Fuel Stock Expenses Undistributed (152)	227	3,254,610	4,411,863
47	Residuals Residuals (Elec) and Extracted Products (153)	227
48	PlantMaterialsAndOperatingSupplies Plant Materials and Operating Supplies (154)	227	173,368,683	174,114,298
49	Merchandise Merchandise (155)	227
50	OtherMaterialsAndSupplies Other Materials and Supplies (156)	227	1,510,191	1,479,180
51	NuclearMaterialsHeldForSale Nuclear Materials Held for Sale (157)	202/227
52	AllowanceInventoryAndWithheld Allowances (158.1 and 158.2)	228	25,601,412	25,764,095
53	NoncurrentPortionOfAllowances (Less) Noncurrent Portion of Allowances	228	25,304,843	25,591,061
54	StoresExpenseUndistributed Stores Expense Undistributed (163)	227
55	GasStoredCurrent Gas Stored Underground - Current (164.1)
56	LiquefiedNaturalGasStoredAndHeldForProcessing Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)
57	Prepayments Prepayments (165)		11,602,570	8,148,974
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)
60	RentsReceivable Rents Receivable (172)		134,315	92,578
61	AccruedUtilityRevenues Accrued Utility Revenues (173)
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)		28,079,025	15,569,895
63	DerivativeInstrumentAssets Derivative Instrument Assets (175)		3,336,696	3,641,421
64	DerivativeInstrumentAssetsLongTerm (Less) Long-Term Portion of Derivative Instrument Assets (175)			75,597
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)		419,247,343	395,716,222
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		20,079,273	16,623,601
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	556,269,932	525,144,404
73	PreliminarySurveyAndInvestigationCharges Prelim. Survey and Investigation Charges (Electric) (183)		760,085	1,516,005
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	63,408,711	56,981,316
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)		13,985,122	15,250,800
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	1,071,500,514	989,791,390
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		1,726,003,638	1,605,307,515
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		13,668,796,076	12,805,099,281

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line No.	Title of Account (a)	Ref. Page No. (b)	Current Year End of Quarter/Year Balance (c)	Prior Year End Balance 12/31 (d)
1	ProprietaryCapitalAbstract PROPRIETARY CAPITAL
2	CommonStockIssued Common Stock Issued (201)	250	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	976,661,803	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
11	RetainedEarnings Retained Earnings (215, 215.1, 216)	118	1,751,256,768	1,724,194,935
12	UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1)	118	2,703,331	5,485,144
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)	1,252,146	6,938,742
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		2,784,781,469	2,749,251,353
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	3,103,597,081	2,907,531,008
22	UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225)
23	UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Debit (226)		10,705,374	7,760,927
24	LongTermDebt Total Long-Term Debt (lines 18 through 23)		3,092,891,708	2,899,770,080
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		137,728,579	242,042,430
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		705,208	327,289
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		12,397,558	10,901,908
30	AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4)		958,887	719,588
31	AccumulatedProvisionForRateRefunds Accumulated Provision for Rate Refunds (229)		5,388,015	2,207,805
32	LongTermPortionOfDerivativeInstrumentLiabilities Long-Term Portion of Derivative Instrument Liabilities		1,352	61,181
33	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges Long-Term Portion of Derivative Instrument Liabilities - Hedges
34	AssetRetirementObligations Asset Retirement Obligations (230)		1,946,288,955	1,813,824,019
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		2,103,468,553	2,070,084,221
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)
38	AccountsPayable Accounts Payable (232)		174,399,996	153,242,637
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)		93,331,295	103,021,741
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		94,897,889	80,530,918
41	CustomerDeposits Customer Deposits (235)		45,161,586	41,698,455
42	TaxesAccrued Taxes Accrued (236)	262	94,367,286	95,913,751
43	InterestAccrued Interest Accrued (237)		37,016,432	35,634,798
44	DividendsDeclared Dividends Declared (238)
45	MaturedLongTermDebt Matured Long-Term Debt (239)
46	MaturedInterest Matured Interest (240)
47	TaxCollectionsPayable Tax Collections Payable (241)		6,566,423	6,392,308
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		107,846,206	95,207,627
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		207,477,213	160,085,058
50	DerivativesInstrumentLiabilities Derivative Instrument Liabilities (244)		5,024,580	193,272
51	LongTermPortionOfDerivativeInstrumentLiabilities (Less) Long-Term Portion of Derivative Instrument Liabilities		1,352	61,181
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)		866,087,554	771,859,385
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)
57	AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255)	266	22,384,341	21,260,705
58	DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256)
59	OtherDeferredCredits Other Deferred Credits (253)	269	19,133,074	26,661,688
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	2,607,697,815	2,210,119,708
61	UnamortizedGainOnReacquiredDebt Unamortized Gain on Reaquired Debt (257)		2,996	4,708
62	AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty Accum. Deferred Income Taxes-Accel. Amort.(281)	272	16,760,085	17,013,726
63	AccumulatedDeferredIncomeTaxesOtherProperty Accum. Deferred Income Taxes-Other Property (282)		1,128,530,876	1,128,807,583
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		1,027,057,608	910,266,123
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		4,821,566,794	4,314,134,241
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		13,668,796,078	12,805,099,280

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

STATEMENT OF INCOME
Quarterly Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only. Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same three month period for the prior year. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in column (k) the quarter to date amounts for other utility function for the current year quarter. Report in column (h) the quarter to date amounts for electric utility function; in column (j) the quarter to date amounts for gas utility, and in column (l) the quarter to date amounts for other utility function for the prior year quarter. If additional columns are needed, place them in a footnote. Annual or Quarterly if applicable Do not report fourth quarter data in columns (e) and (f) Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility column in a similar manner to a utility department. Spread the amount(s) over Lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above. Use page 122 for important notes regarding the statement of income for any account thereof. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases. Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate proceeding affecting revenues received or costs incurred for power or gas purchases, and a summary of the adjustments made to balance sheet, income, and expense accounts. If any notes appearing in the report to stockholders are applicable to the Statement of Income, such notes may be included at page 122. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income, including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to this schedule.
Line No.	Title of Account (a)	(Ref.) Page No. (b)	Total Current Year to Date Balance for Quarter/Year (c)	Total Prior Year to Date Balance for Quarter/Year (d)	Current 3 Months Ended - Quarterly Only - No 4th Quarter (e)	Prior 3 Months Ended - Quarterly Only - No 4th Quarter (f)	Electric Utility Current Year to Date (in dollars) (g)	Electric Utility Previous Year to Date (in dollars) (h)	Gas Utiity Current Year to Date (in dollars) (i)	Gas Utility Previous Year to Date (in dollars) (j)	Other Utility Current Year to Date (in dollars) (k)	Other Utility Previous Year to Date (in dollars) (l)
1	UtilityOperatingIncomeAbstract UTILITY OPERATING INCOME
2	OperatingRevenues Operating Revenues (400)	300	2,319,200,338	2,181,062,221			2,319,200,338	2,181,062,221
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	1,181,641,968	1,080,430,039			1,181,641,968	1,080,430,039
5	MaintenanceExpense Maintenance Expenses (402)	320	209,973,572	193,171,626			209,973,572	193,171,626
6	DepreciationExpense Depreciation Expense (403)	336	387,053,997	366,155,550			387,053,997	366,155,550
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336	316,287	793,970			316,287	793,970
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	53,039,201	46,940,601			53,039,201	46,940,601
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)		467,537	382,074			467,537	382,074
13	RegulatoryCredits (Less) Regulatory Credits (407.4)		50,563	1,772,588			50,563	1,772,588
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	105,580,982	103,748,280			105,580,982	103,748,280
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	31,398,638	14,828,901			31,398,638	14,828,901
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	85,737	720,789			85,737	720,789
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	551,359,387	1,065,202,874			551,359,387	1,065,202,874
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	587,546,681	1,080,983,127			587,546,681	1,080,983,127
19	InvestmentTaxCreditAdjustments Investment Tax Credit Adj. - Net (411.4)	266	1,123,636	4,485,265			1,123,636	4,485,265
20	GainsFromDispositionOfPlant (Less) Gains from Disp. of Utility Plant (411.6)		522,709	418,996			522,709	418,996
21	LossesFromDispositionOfServiceCompanyPlant Losses from Disp. of Utility Plant (411.7)		798				798
22	GainsFromDispositionOfAllowances (Less) Gains from Disposition of Allowances (411.8)		30	132,344			30	132,344
23	LossesFromDispositionOfAllowances Losses from Disposition of Allowances (411.9)		1,017				1,017
24	AccretionExpense Accretion Expense (411.10)		5,155,842	4,979,808			5,155,842	4,979,808
25	UtilityOperatingExpenses TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)		1,938,375,694	1,788,798,044			1,938,375,694	1,788,798,044
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		380,824,644	392,264,177			380,824,644	392,264,177
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)		57,532,386	62,644,197
34	ExpensesOfNonutilityOperations (Less) Expenses of Nonutility Operations (417.1)		53,578,744	56,195,805
35	NonoperatingRentalIncome Nonoperating Rental Income (418)		414,570	516,674
36	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1)	119	2,781,813	173,085
37	InterestAndDividendIncome Interest and Dividend Income (419)		913,279	879,794
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		12,799,539	11,537,425
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		1,669,643	2,133,166
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)		776,070	2,245,145
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		19,969,270	19,667,350
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)		287,432	2,958
44	MiscellaneousAmortization Miscellaneous Amortization (425)
45	Donations Donations (426.1)		1,284,752	1,456,688
46	LifeInsurance Life Insurance (426.2)
47	Penalties Penalties (426.3)		410,373	117,442
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		1,013,367	743,651
49	OtherDeductions Other Deductions (426.5)		9,727,797	15,549,993
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		11,902,974	17,870,733
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262	2,526,953	3,171,861
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262	4,021,660	3,570,350
54	IncomeTaxesOther Income Taxes-Other (409.2)	262	349,587	1,164,940
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272	23,134,476	98,224,220
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272	26,215,630	98,617,646
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)		4,925,448	373,024
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		12,991,744	1,423,593
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		112,879,508	106,512,897
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		2,116,800	2,094,492
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)		1,472,631	1,503,556
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)		211,532	1,352,437
68	OtherInterestExpense Other Interest Expense (431)		2,428,058	3,116,760
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		5,134,072	5,670,945
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		113,972,745	108,907,486
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		279,843,643	284,780,284
72	ExtraordinaryItemsAbstract Extraordinary Items
73	ExtraordinaryIncome Extraordinary Income (434)
74	ExtraordinaryDeductions (Less) Extraordinary Deductions (435)
75	NetExtraordinaryItems Net Extraordinary Items (Total of line 73 less line 74)
76	IncomeTaxesExtraordinaryItems Income Taxes-Federal and Other (409.3)	262
77	ExtraordinaryItemsAfterTaxes Extraordinary Items After Taxes (line 75 less line 76)
78	NetIncomeLoss Net Income (Total of line 71 and 77)		279,843,643	284,780,284

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

STATEMENT OF RETAINED EARNINGS
Do not report Lines 49-53 on the quarterly report. Report all changes in appropriated retained earnings, unappropriated retained earnings, and unappropriated undistributed subsidiary earnings for the year. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436-439 inclusive). Show the contra primary account affected in column (b). State the purpose and amount for each reservation or appropriation of retained earnings. List first Account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow by credit, then debit items, in that order. Show dividends for each class and series of capital stock. Show separately the State and Federal income tax effect of items shown for Account 439, Adjustments to Retained Earnings. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated. If any notes appearing in the report to stockholders are applicable to this statement, attach them at page 122.
Line No.	Item (a)	Contra Primary Account Affected (b)	Current Quarter/Year Year to Date Balance (c)	Previous Quarter/Year Year to Date Balance (d)
	UnappropriatedRetainedEarningsAbstract UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1	UnappropriatedRetainedEarnings Balance-Beginning of Period		1,719,594,527	1,519,717,008
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.			447,275
9	AdjustmentsToRetainedEarningsCredit TOTAL Credits to Retained Earnings (Acct. 439)			447,275
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)		277,061,833	284,607,199
17	AppropriationsOfRetainedEarningsAbstract Appropriations of Retained Earnings (Acct. 436)
17.1	AppropriationsOfRetainedEarnings Reclassification of Appropriated Retained Earnings-Amort Reserve Federal		219,456	176,955
22	AppropriationsOfRetainedEarnings TOTAL Appropriations of Retained Earnings (Acct. 436)		219,456	176,955
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		250,000,000	85,000,000
36	DividendsDeclaredCommonStock TOTAL Dividends Declared-Common Stock (Acct. 438)		250,000,000	85,000,000
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)		1,746,436,904	1,719,594,527
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)		4,819,864	4,600,408
47	AppropriatedRetainedEarningsIncludingReserveAmortization TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)		4,819,864	4,600,408
48	RetainedEarnings TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)		1,751,256,768	1,724,194,935
	UnappropriatedUndistributedSubsidiaryEarningsAbstract UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49	UnappropriatedUndistributedSubsidiaryEarnings Balance-Beginning of Year (Debit or Credit)		5,485,144	5,658,229
50	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings for Year (Credit) (Account 418.1)		2,781,813	173,085
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)		2,703,331	5,485,144

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

STATEMENT OF CASH FLOWS
Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as investments, fixed assets, intangibles, etc. Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash Equivalents at End of Period" with related amounts on the Balance Sheet. Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid. Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the dollar amount of leases capitalized with the plant cost.
Line No.	Description (See Instructions No.1 for explanation of codes) (a)	Current Year to Date Quarter/Year (b)	Previous Year to Date Quarter/Year (c)
1	NetCashFlowFromOperatingActivitiesAbstract Net Cash Flow from Operating Activities
2	NetIncomeLoss Net Income (Line 78(c) on page 117)	279,843,643	284,780,284
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	439,776,912	413,890,121
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of Regulatory Debits & Credits	518,100	2,154,662
5.2	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of Nuclear Fuel	86,673,746	89,664,255
5.3	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Accretion of Asset Retirement Obligations	5,155,842	4,979,808
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	39,268,448	16,173,680
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)	1,123,636	4,485,265
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	22,620,016	12,560,106
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	29,939,895	35,061,101
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory	162,682	389,097
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	42,137,754	30,778,238
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	27,105,892	27,584,757
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	87,235,709	19,204,501
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	12,799,539	11,537,425
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies	2,781,812	173,085
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other (provide details in footnote):	(a) 49,395,217	33,670,497
18.2	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Mark-to-Market of Risk Management Contracts	5,136,033	5,913,160
18.3	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Pension Contributions to Qualified Plan Trust		6,431,000
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	649,261,610	680,092,133
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)	514,038,334	559,078,264
27	GrossAdditionsToNuclearFuelInvestingActivities Gross Additions to Nuclear Fuel	105,663,130	68,538,335
28	GrossAdditionsToCommonUtilityPlantInvestingActivities Gross Additions to Common Utility Plant
29	GrossAdditionsToNonutilityPlantInvestingActivities Gross Additions to Nonutility Plant	265,957	135,057
30	AllowanceForOtherFundsUsedDuringConstructionInvestingActivities (Less) Allowance for Other Funds Used During Construction	12,799,539	11,537,425
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
31.1	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Other (provide details in footnote):
31.2	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Acquired Assets	920,927	6,867,333
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	608,088,809	623,081,564
36	AcquisitionOfOtherNoncurrentAssets Acquisition of Other Noncurrent Assets (d)
37	ProceedsFromDisposalOfNoncurrentAssets Proceeds from Disposal of Noncurrent Assets (d)	(b) 8,579,838	1,504,903
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)	1,928,182,789	1,637,211,231
45	ProceedsFromSalesOfInvestmentSecurities Proceeds from Sales of Investment Securities (a)	1,886,361,394	1,593,380,024
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		25,488
52	NetIncreaseDecreaseInPayablesAndAccruedExpensesInvestingActivities Net Increase (Decrease) in Payables and Accrued Expenses
53	OtherAdjustmentsToCashFlowsFromInvestmentActivities Other (provide details in footnote):
53.1	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Sale of Barges		6,384,000
53.2	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Other (provide details in footnote):	(c) 6,647,517	8,449,067
53.3	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription (increase) Decrease in Other Special Deposits	10,307,523	8,337
53.4	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Note Receivable from Associated Companies
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	644,990,372	650,557,650
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 Notes Payable to Associated companies
64.2	OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription Long Term Issuance Costs	8,169,519
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
67.1	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Proceeds on Capital Leaseback	704,426	475,818
67.2	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Proceeds from Nuclear Sale Leaseback	64,900,000	69,500,000
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	547,434,907	69,975,818
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)	294,076,636	1,778,926
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	11,426,318
78	NetDecreaseInShortTermDebt Net Decrease in Short-Term Debt (c)
80	DividendsOnPreferredStock Dividends on Preferred Stock
81	DividendsOnCommonStock Dividends on Common Stock	250,000,000	85,000,000
83	CashFlowsProvidedFromUsedInFinancingActivities Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)	6,332,175	28,229,426
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)	2,060,936	1,305,057
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	3,338,535	2,033,478
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	1,277,599	3,338,535

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities


	2021 Cash Flow Incr / (Decr)		2020 Cash Flow Incr / (Decr)
Utility Plant, Net	$	(116,606,963)	$	(128,682,338)
Property and Investments, Net	9,290,321		16,737,965
Margin Deposits	(6,768,281)		2,431,303
Prepayments	(3,133,360)		(1,147,215)
Accrued Utility Revenues, Net	—		2,534,824
Miscellaneous Current and Accr Assets	(9,864,651)		10,079,309
Unamortized Debt Expense	1,212,846		1,622,951
Other Deferred Debits, Net	(4,376,921)		(1,320,342)
Proprietary Capital, Net			447,275
Other Comprehensive Income, Net	1,602,302		1,602,302
Unamortized Discount/Premium on Long-Term Debt	556,554		469,029
Accumulated Provisions - Misc	3,048,905		792,375
Current and Accrued Liabilities, Net	6,375,827		(10,493,451)
Other Deferred Credits, Net	69,268,204		71,255,516
Total	$	(49,395,217)	$	(33,670,497)

(b) Concept: ProceedsFromDisposalOfNoncurrentAssets


	2021 Cash Flow Incr / (Decr)		2020 Cash Flow Incr / (Decr)
Sale of transformers between various operating companies	$	911,559	$	891,705
Sale of meters between various operating companies	114,872		213,450
Transco Transfer of Assets	5,939,061		399,748
Land Sale Proceeds via incoming wire from Meridian Title - Dumont / Lakeville Site, Dumont UHV Test Facility	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		—
Total	$	8,579,838	$	1,504,903

(c) Concept: OtherAdjustmentsToCashFlowsFromInvestmentActivities


	2021 Cash Flow Incr / (Decr)		2020 Cash Flow Incr / (Decr)
DOE Settlement	$	2,552,839	$	2,248,759
CIAC Proceeds	1,964,789		6,019,175
Insurance Receivable	2,129,889		181,134
Total	$	6,647,517	$	8,449,067

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

NOTES TO FINANCIAL STATEMENTS

Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement, providing a subheading for each statement except where a note is applicable to more than one statement.
Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears on cumulative preferred stock.
For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant adjustments and requirements as to disposition thereof.
Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such restrictions.
If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be omitted.
For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements; status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such matters shall be provided even though a significant change since year end may not have occurred.
Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are applicable and furnish the data required by the above instructions, such notes may be included herein.

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.
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.
AMI						Advanced Metering Infrastructure.
AOCI						Accumulated Other Comprehensive Income.
APCo						Appalachian Power Company, an AEP electric utility subsidiary.
ARAM						Average Rate Assumption Method, an IRS approved method used to calculate the reversal of Excess ADIT for rate-making purposes.
ARO						Asset Retirement Obligations.
CARES Act						Coronavirus Aid, Relief, and Economic Security Act signed into law in March 2020.
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 IX , DCC Fuel X, DCC Fuel XI, DCC Fuel XII, DCC Fuel XIII, DCC Fuel XIV, DCC Fuel XV, and DCC Fuel XVI 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.
ESP						Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.
Excess ADIT						Excess accumulated deferred income taxes.
FAC						Fuel Adjustment Clause.
FASB						Financial Accounting Standards Board.
Federal EPA						United States Environmental Protection Agency.
FERC						Federal Energy Regulatory Commission.
FTR						Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP						Accounting Principles Generally Accepted in the United States of America.
I&M						Indiana Michigan Power Company, an AEP electric utility subsidiary.


IRS						Internal Revenue Service.
ITC						Investment Tax Credit.
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.
Parent						American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
PCA						Power Coordination Agreement among APCo, I&M, KPCo and WPCo.
PJM						Pennsylvania – New Jersey – Maryland regional transmission organization.
PPA						Purchase Power and Sale Agreement.
PSO						Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PTC						Production Tax Credits.
PUCO						Public Utilities Commission of Ohio.
Risk Management Contracts						Trading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant						A generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana. AEGCo and I&M jointly-own Unit 1. In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.
ROE						Return on Equity.
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.
SPP						Southwest Power Pool regional transmission organization.
SSO						Standard service offer.
SWEPCo						Southwestern Electric Power Company, an AEP electric utility subsidiary.
TA						Transmission Agreement, effective November 2010, among APCo, I&M, KGPCo, KPCo, OPCo and WPCo with AEPSC as agent.


Tax Reform						On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018.
UPA						Unit Power Agreement.
Utility Money Pool						Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
WPCo						Wheeling Power Company, an AEP electric utility subsidiary.

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 607,000 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.

AEGCo holds a 50% interest in each of the Rockport Plant units and is entitled to 50% of the capacity and associated energy from each unit. Under unit power agreements approved by the FERC, I&M and KPCo purchase approximately 920 MWs and 390 MWs, respectively, of the output from AEGCo’s 50% share of the Rockport Plant.

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 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 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 deferred FICA taxes as taxes accrued rather than as a noncurrent liability.

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


		2021			2020
For the Years Ended December 31,		(in millions)
Cash was Paid for:
	Interest (Net of Capitalized Amounts)	$	109.5		$	105.5
	Income Taxes (Net of Refunds)			29.3			42.0
Noncash Acquisitions Under Finance Leases				197.2			72.5
As of December 31,
Construction Expenditures Included in Current and Accrued Liabilities				87.8			62.8
Acquisition of Nuclear Fuel Included in Current and Accrued Liabilities				—			33.4
Expected Reimbursement for Capital Cost of SNF Dry Cask Storage				1.7			2.6

Special Deposits

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

Inventory

Fossil fuel 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, 2021 and 2020, 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 removed from plant-in-service or CWIP and charged to expense. 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.

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 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 amortized when refunded or when billed to customers in later months with the IURC’s and the MPSC’s reviews and approvals. 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 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 mechanism in Indiana and Michigan. Where the FAC or Off-system Sales sharing mechanism is capped, frozen or non-existent, 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”, and are 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 activities 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 I&M balance sheets as Derivative Instrument Assets or Liabilities, as appropriate, and on the statements of income in Operating Revenues. Realized gains and losses on marketing and risk management transactions are included in revenues or expenses based on the transaction’s facts and circumstances. However, in regulated jurisdictions subject to cost-based regulation, unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).

Certain qualifying marketing and risk management 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 cash tax benefit is recognized.

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 an unfunded nonqualified pension plan. Substantially all 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	25	%
Fixed Income	59	%
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, 2021 and 2020, the fair value of securities on loan as part of the program was $137 million and $177 million, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned as of December 31, 2021 and 2020.

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, 2021 through February 24, 2022, the date that AEP’s Form 10-K was issued, and has updated such evaluation for disclosure purposes through April 14, 2022. 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, 2021 and 2020. 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, 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	—		—		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)


			Pension and OPEB
			Amortization		Changes in
	Cash Flow Hedge –		of Deferred		Funded
For the Year Ended December 31, 2020	Interest Rate		Costs		Status		Total
	(in millions)
Balance in AOCI as of December 31, 2019	$	(9.9)	$	4.9	$	(6.6)	$	(11.6)
Change in Fair Value Recognized in AOCI	—		—		3.1		3.1
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)		3.1		4.6
Balance in AOCI as of December 31, 2020	$	(8.3)	$	4.8	$	(3.5)	$	(7.0)

(a)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, 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.

2021 Indiana Base Rate Case

In July 2021, I&M filed a request with the IURC for a $104 million annual increase in Indiana rates, inclusive of base rates and riders, based upon a proposed 10% ROE. I&M proposed a phased-in annual increase in rates of $73 million effective in May 2022 with the remaining $31 million annual increase in rates to be effective January 2023. The proposed annual increase includes $7 million related to an annual increase in depreciation expense, driven by increased depreciation rates and proposed investments. The request also includes a new AMI rider for proposed meter projects.

In November 2021, I&M and intervenors filed an unopposed joint settlement agreement with the IURC. After adjustments to remove the impact of Rockport Plant, Unit 2, the agreement includes a $61 million annual revenue increase based on a 9.7% ROE. The primary differences between I&M’s requested annual rate increase and the agreed upon settlement increase are primarily due to: (a) changes to the capital structure of I&M, (b) decreased depreciation rates and (c) certain changes to I&M’s proposed rate base. Rockport Plant, Unit 2 costs will be recovered through riders until the lease expiration in December 2022. Adjustments to remove Rockport Plant, Unit 2 costs from base rates are consistent with the IURC’s order approving I&M’s proposed purchase of Rockport Plant, Unit 2. See “Rockport Plant Litigation” section of Note 6 for additional information. In February 2022, the IURC issued an order approving the joint settlement agreement with no modifications. The IURC’s order resulted in a phased-in increase in Indiana rates with a $3 million annual increase effective February 2022 and the remaining $58 million annual increase effective in January 2023.

5. EFFECTS OF REGULATION


	I&M
	December 31,				Remaining Recovery Period
Regulatory Assets:	2021		2020
	(in millions)


Regulatory assets pending final regulatory approval:

Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval	$	0.1	$	0.5
Total Regulatory Assets Currently Earning a Return	0.1		0.5
Regulatory Assets Currently Not Earning a Return
COVID-19	1.7		3.8
Other Regulatory Assets Pending Final Regulatory Approval	1.9		—
Total Regulatory Assets Currently Not Earning a Return (a)	3.6		3.8

Total Regulatory Assets Pending Final Regulatory Approval	3.7		4.3

Regulatory assets approved for recovery:

Regulatory Assets Currently Earning a Return
Rockport Plant Dry Sorbent Injection System and Selective Catalytic Reduction	30.1		19.1		7 years
Cook Plant Uprate Project	27.7		30.2		12 years
Deferred Cook Plant Life Cycle Management Project Costs	13.1		14.1		13 years
Cook Plant Turbine	9.6		11.1		17 years
Cook Plant Study Costs - Indiana	9.4		10.1		14 years
Under-recovered Fuel Costs	6.4		5.4		1 year
Other Regulatory Assets Approved for Recovery	6.0		7.0		various
Total Regulatory Assets Currently Earning a Return	102.3		97.0
Regulatory Assets Currently Not Earning a Return
Income Taxes Subject to Flow Through	360.4		337.0		20 years
Cook Plant Nuclear Refueling Outage Levelization	32.0		39.5		3 years
PJM Costs and Off-system Sales Margin Sharing - Indiana	15.1		—		2 years
Storm-Related Costs - Indiana	12.6		0.3		2 years
Postemployment Benefits	9.0		5.0		3 years
Unrealized Loss on Forward Commitments	7.2		—		3 years
Pension and OPEB Funded Status	—		25.7
Other Regulatory Assets Approved for Recovery	14.0		16.3		various
Total Regulatory Assets Currently Not Earning a Return	450.3		423.8

Total Regulatory Assets Approved for Recovery	552.6		520.8

Total FERC Account 182.3 Regulatory Assets	$	556.3	$	525.1

(a)In February 2022, the IURC issued an order approving Indiana jurisdictional COVID-19 costs and certain other regulatory assets totaling $3 million. See “2021 Indiana Base Rate Case” section of Note 4 for additional information.


	I&M
	December 31,				Remaining Refund Period
Regulatory Liabilities:	2021		2020
	(in millions)


Regulatory liabilities approved for payment:

Regulatory Liabilities Currently Paying a Return
Other Regulatory Liabilities Approved for Payment	$	21.9	$	17.4	various
Total Regulatory Liabilities Currently Paying a Return	21.9		17.4
Regulatory Liabilities Currently Not Paying a Return
Excess Nuclear Decommissioning Funding	1,939.7		1,476.6		(a)
Spent Nuclear Fuel	49.5		43.1		(a)
Pension OPEB Funded Status	27.6		—		12 years
Rockport Plant, Unit 2 Selective Catalytic Reduction	10.6		8.9		2 years
PJM Transmission Enhancement Refund	7.9		9.9		4 years
Over-recovered Fuel Costs, Indiana	1.5		20.8		1 year
PJM Costs and Off-system Sales Margin Sharing - Indiana	—		13.3
Other Regulatory Liabilities Approved for Payment	6.0		28.3		various
Total Regulatory Liabilities Currently Not Paying a Return	2,042.8		1,600.9
Income Tax Related Regulatory Liabilities (b)
Excess ADIT Associated with Certain Depreciable Property	433.6		450.6		(c)
Excess ADIT that is Not Subject to Rate Normalization Requirements	90.2		136.2		3 years
Income Taxes Subject to Flow Through	19.2		5.0		20 years
Total Income Tax Related Regulatory Liabilities	543.0		591.8

Total Regulatory Liabilities Approved for Payment	2,607.7		2,210.1

Total FERC 254 Account Regulatory Liabilities	$	2,607.7	$	2,210.1

(a)Relieved when plant is decommissioned.

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

(c)Refunded using ARAM.

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, 2021:


Contractual Commitments	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Fuel Purchase Contracts (a)	$	147.7	$	245.7	$	149.1	$	283.3	$	825.8
Energy and Capacity Purchase Contracts	167.2		212.6		203.3		305.9		889.0
Total	$	314.9	$	458.3	$	352.4	$	589.2	$	1,714.8

(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, 2021, 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 three 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 three 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, 2021, 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. 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 $4 million and $4 million for the years ended December 31, 2021 and 2020, respectively. Decommissioning costs recovered from customers are deposited in external trusts.

As of December 31, 2021 and 2020, the total decommissioning trust fund balances were $3.5 billion and $3 billion, respectively. Trust fund earnings increase the fund assets and decrease 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 recover the remaining 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 continues to increase 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, 2021 and 2020, fees and related interest of $281 million and $281 million, respectively, for fuel consumed prior to April 7, 1983 were recorded as Other Long-Term Debt and funds collected from customers along with related earnings totaling $329 million and $324 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 $14 million and $24 million in 2021 and 2020, 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, 2021 and 2020, I&M deferred $3 million and $14 million, respectively, in Miscellaneous Current and Accrued Assets and $21 million and $1 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 $42 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 $13.5 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 $13.1 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, with closing to occur as of the end of the Rockport Plant, Unit 2 lease in December 2022. The agreement is subject to customary closing conditions, including regulatory approvals and as of the closing will result in a final settlement of, and release of claims in, the lease litigation. As a result, in May

2021, at the parties’ request, the district court entered a stipulation and order dismissing the case without prejudice to plaintiffs asserting their claims in a re-filed action or a new action. The required regulatory approvals at the IURC and FERC have been obtained that would allow the closing to occur as of the end of the lease in December 2022. The IURC order approved a settlement agreement addressing the future use of Rockport Plant, Unit 2 as a capacity and energy resource and associated adjustments to I&M’s Indiana retail rates, along with certain other matters. Management believes its financial statements appropriately reflect the resolution of the litigation. See Note 12 - Leases for additional information.

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. AEP will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

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 an unfunded nonqualified pension plan. Substantially all 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 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 benefit obligations are shown in the following table:


	Pension Plans						OPEB
	December 31,
Assumption	2021			2020			2021		2020
Discount Rate	2.90	%		2.50	%		2.90	%	2.55	%
Interest Crediting Rate	4.00	%		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 2021, 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	2021			2020			2021		2020
Discount Rate	2.50	%		3.25	%		2.55	%	3.30	%
Interest Crediting Rate	4.00	%		4.00	%		NA		NA
Expected Return on Plan Assets	4.75	%		5.75	%		4.75	%	5.50	%
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	2021		2020
Initial	6.25	%	6.50	%
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, 2021, 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, 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. For the year ended December 31, 2020, the pension plans had an actuarial loss primarily due to a decrease in the discount rate, partially offset by a decrease in the assumed rate used to convert account balances to annuities. For the year ended December 31, 2020, the OPEB plans had an actuarial loss primarily due to a decrease in the discount rate and an update to the health care trend assumption, partially offset by updated projected per capita claims costs due to rate negotiations for Medicare advantage premium rates.

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
	2021		2020		2021		2020
Change in Benefit Obligation	(in millions)
Benefit Obligation as of January 1,	$	653.3	$	616.1	$	141.4	$	142.9
Service Cost	17.5		15.4		1.3		1.4
Interest Cost	16.2		19.7		3.5		4.7
Actuarial (Gain) Loss	(29.5)		44.3		(16.8)		5.1
Plan Amendments	—		—		(0.7)		(1.6)
Benefit Payments	(45.4)		(42.2)		(15.3)		(15.9)
Participant Contributions	—		—		5.2		4.8
Benefit Obligation as of December 31,	$	612.1	$	653.3	$	118.6	$	141.4

Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1,	$	698.1	$	630.5	$	238.2	$	216.3
Actual Gain on Plan Assets	28.8		103.3		20.6		33.0
Company Contributions	—		6.5		—		—
Participant Contributions	—		—		5.2		4.8
Benefit Payments	(45.4)		(42.2)		(15.3)		(15.9)
Fair Value of Plan Assets as of December 31,	$	681.5	$	698.1	$	248.7	$	238.2

Funded Status as of December 31,	$	69.4	$	44.8	$	130.1	$	96.8


	Pension Plans				OPEB
	December 31,
	2021		2020		2021		2020
	(in millions)
Special Funds – Prepaid Benefit Costs	$	71.4	$	46.5	$	130.1	$	96.8
Miscellaneous Current and Accrued Liabilities – Short-term Benefit Liability	(0.1)		—		—		—
Accumulated Provision for Pensions and Benefits – Long-term Benefit Liability	(1.9)		(1.7)		—		—
Funded Status	$	69.4	$	44.8	$	130.1	$	96.8

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, AOCI and income tax expense and the items attributable to the change in these components:


	Pension Plans				OPEB
	December 31,
	2021		2020		2021		2020
Components	(in millions)
Net Actuarial (Gain) Loss	$	(1.6)	$	39.5	$	(10.7)	$	15.6
Prior Service Credit	—		—		(22.1)		(31.0)

Recorded as
Regulatory Assets/Liabilities (a)	$	3.1	$	40.3	$	(30.7)	$	(14.6)
Deferred Income Taxes	(1.0)		(0.1)		(0.4)		(0.2)
Net of Tax AOCI	(3.7)		(0.7)		(1.7)		(0.6)

(a)Recorded as a Regulatory Liability as of December 31, 2021 and recorded as a Regulatory Asset as of December 31, 2020.


	Pension Plans				OPEB
	2021		2020		2021		2020
Components	(in millions)
Actuarial Gain During the Year	$	(29.4)	$	(25.7)	$	(26.3)	$	(16.4)
Amortization of Actuarial Loss	(11.7)		(10.8)		—		(0.7)
Prior Service Credit	—		—		(0.7)		(1.5)
Amortization of Prior Service Credit	—		—		9.6		9.5
Change for the Year Ended December 31,	$	(41.1)	$	(36.5)	$	(17.4)	$	(9.1)

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,
2021		2020		2021		2020
12.7	%	12.6	%	12.2	%	12.2	%

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 (c)	—		—		—		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 (c)	—		—		—		92.1		92.1		1.7	%
Real Estate (c)	—		—		—		232.6		232.6		4.4	%
Alternative Investments (c)	—		—		—		448.8		448.8		8.4	%
Cash and Cash Equivalents (c)	—		64.3		—		53.4		117.7		2.2	%
Other – Pending Transactions and Accrued Income (b)	—		—		—		(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 primarily represent accrued interest, dividend receivables and transactions pending settlement.

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

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 (b)	—		—		—		265.0		265.0		13.0	%
Subtotal – Equities	770.3		—		—		265.0		1,035.3		50.7	%

Fixed Income:
Common Collective Trust – Debt (b)	—		—		—		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 (b)	33.0		—		—		6.7		39.7		1.9	%
Other – Pending Transactions and Accrued Income (a)	—		—		—		6.0		6.0		0.3	%

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

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

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

The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2020:


Asset Class	Level 1		Level 2		Level 3		Other		Total		Year End Allocation
	(in millions)
Equities (a):
Domestic	$	542.3	$	—	$	—	$	—	$	542.3	9.7	%
International	676.3		—		—		—		676.3		12.2	%
Common Collective Trusts (c)	—		—		—		650.0		650.0		11.7	%
Subtotal – Equities	1,218.6		—		—		650.0		1,868.6		33.6	%

Fixed Income (a):
United States Government and Agency Securities	(1.4)		1,134.1		—		—		1,132.7		20.4	%
Corporate Debt	—		1,425.0		—		—		1,425.0		25.6	%
Foreign Debt	—		214.0		—		—		214.0		3.9	%
State and Local Government	—		56.0		—		—		56.0		1.0	%
Other – Asset Backed	—		0.8		—		—		0.8		—	%
Subtotal – Fixed Income	(1.4)		2,829.9		—		—		2,828.5		50.9	%

Infrastructure (c)	—		—		—		91.1		91.1		1.6	%
Real Estate (c)	—		—		—		231.6		231.6		4.2	%
Alternative Investments (c)	—		—		—		431.8		431.8		7.8	%
Cash and Cash Equivalents (c)	—		49.3		—		58.2		107.5		1.9	%
Other – Pending Transactions and Accrued Income (b)	—		—		—		(2.5)		(2.5)		—	%

Total	$	1,217.2	$	2,879.2	$	—	$	1,460.2	$	5,556.6	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 primarily represent accrued interest, dividend receivables and transactions pending settlement.

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

The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2020:


Asset Class	Level 1		Level 2		Level 3		Other		Total		Year End Allocation
	(in millions)
Equities:
Domestic	$	399.9	$	—	$	—	$	—	$	399.9	20.6	%
International	290.7		—		—		—		290.7		14.9	%
Common Collective Trusts (b)	—		—		—		264.7		264.7		13.6	%
Subtotal – Equities	690.6		—		—		264.7		955.3		49.1	%

Fixed Income:
Common Collective Trust – Debt (b)	—		—		—		186.4		186.4		9.6	%
United States Government and Agency Securities	(0.2)		199.7		—		—		199.5		10.2	%
Corporate Debt	—		248.7		—		—		248.7		12.8	%
Foreign Debt	—		34.9		—		—		34.9		1.8	%
State and Local Government	73.9		13.1		—		—		87.0		4.5	%
Subtotal – Fixed Income	73.7		496.4		—		186.4		756.5		38.9	%

Trust Owned Life Insurance:
International Equities	—		64.8		—		—		64.8		3.3	%
United States Bonds	—		135.9		—		—		135.9		7.0	%
Subtotal – Trust Owned Life Insurance	—		200.7		—		—		200.7		10.3	%

Cash and Cash Equivalents (b)	26.3		—		—		5.7		32.0		1.6	%
Other – Pending Transactions and Accrued Income (a)	—		—		—		2.2		2.2		0.1	%

Total	$	790.6	$	697.1	$	—	$	459.0	$	1,946.7	100.0	%

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

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

Accumulated Benefit Obligation

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


	December 31,
Accumulated Benefit Obligation	2021		2020
	(in millions)
Qualified Pension Plan	$	575.2	$	615.8
Nonqualified Pension Plans	1.2		0.8
Total	$	576.4	$	616.6

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,
	2021		2020
	(in millions)
Projected Benefit Obligation	$	1.9	$	1.7
Fair Value of Plan Assets	—		—
Underfunded Projected Benefit Obligation	$	(1.9)	$	(1.7)

Accumulated Benefit Obligation


	December 31,
	2021		2020
	(in millions)
Accumulated Benefit Obligation	$	1.2	$	0.8
Fair Value of Plan Assets	—		—
Underfunded Accumulated Benefit Obligation	$	(1.2)	$	(0.8)

Estimated Future Benefit Payments and Contributions

I&M expects contributions and payments for the pension plans of $1 million during 2022. 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)
2022	$	41.3	$	15.2
2023	40.9		14.1
2024	42.1		14.7
2025	42.0		14.5
2026	42.2		14.4
Years 2027 to 2031, in Total	201.8		66.8

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,
	2021		2020		2021		2020
	(in millions)
Service Cost	$	17.5	$	15.4	$	1.3	$	1.4
Interest Cost	16.2		19.7		3.5		4.7
Expected Return on Plan Assets	(28.9)		(33.3)		(11.1)		(11.7)
Amortization of Prior Service Credit	—		—		(9.6)		(9.5)
Amortization of Net Actuarial Loss	11.7		10.8		—		0.7
Net Periodic Benefit Cost (Credit)	16.5		12.6		(15.9)		(14.4)
Capitalized Portion	(4.9)		(4.3)		(0.4)		(0.4)
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	11.6	$	8.3	$	(16.3)	$	(14.8)

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, 2021 and 2020 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 a 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

Volume

December 31,

Primary Risk Exposure

2021

2020

Unit of Measure

(in millions)

Commodity:

Power

13.6

19.7

MWhs

Heating Oil and Gasoline

0.7

0.6

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, 2021 and 2020.

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


	December 31, 2021
	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts -		in the Statement of		Presented in the Statement
Balance Sheet Location	Commodity (a)		Financial Position (b)		of Financial Position (c)
	(in 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)		—


	December 31, 2020
	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts -		in the Statement of		Presented in the Statement
Balance Sheet Location	Commodity (a)		Financial Position (b)		of Financial Position (c)
	(in millions)
Derivative Instrument Assets	$	17.7	$	(14.0)	$	3.7
Long-Term Portion of Derivative Instrument Assets	0.5		(0.4)		0.1

Derivative Instrument Liabilities	12.5		(12.3)		0.2
Long-Term Portion of Derivative Instrument Liabilities	0.4		(0.3)		0.1

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

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

(c)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)	2021		2020
	(in millions)
Operating Revenues	$	(0.1)	$	0.1
Operation Expenses	0.3		(0.1)
Maintenance Expenses	0.3		(0.3)
Other Regulatory Assets (a)	(14.8)		(0.1)
Other Regulatory Liabilities (a)	(3.9)		12.4
Total Gain (Loss) on Risk Management Contracts	$	(18.2)	$	12.0

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

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

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

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on 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 2021 and 2020, 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 2021 and 2020, I&M did not apply cash flow hedging to 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, 2021

December 31, 2020

Interest Rate

Expected to be

Reclassed to

Net Income During

AOCI Loss

the Next

AOCI Loss

the Next

Net of Tax

Twelve Months

Net of Tax

Twelve Months

(in millions)

$

(6.7)

$

(1.6)

$

(8.3)

$

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

Collateral Triggering Events

Credit Downgrade Triggers

A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. 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, 2021 and 2020.

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, 2021 and 2020.

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,
2021				2020
Book Value		Fair Value		Book Value		Fair Value
(in millions)
$	3,092.9	$	3,625.8	$	2,899.8	$	3,628.6

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,
	2021						2020
			Gross		Other-Than-				Gross		Other-Than-
	Fair		Unrealized		Temporary		Fair		Unrealized		Temporary
	Value		Gains		Impairments		Value		Gains		Impairments
	(in millions)
Cash and Cash Equivalents	$	84.7	$	—	$	—	$	25.8	$	—	$	—
Fixed Income Securities:
United States Government	1,156.4		66.3		(7.9)		1,025.6		98.5		(7.1)
Corporate Debt	76.7		6.7		(2.1)		86.3		9.6		(1.7)
State and Local Government	7.3		0.4		(0.1)		114.3		0.9		(0.4)
Subtotal Fixed Income Securities	1,240.4		73.4		(10.1)		1,226.2		109.0		(9.2)
Equity Securities - Domestic (a)	2,541.9		1,901.3		—		2,054.7		1,400.8		—
Other Special Funds	$	3,867.0	$	1,974.7	$	(10.1)	$	3,306.7	$	1,509.8	$	(9.2)

(a)Amount reported as Gross Unrealized Gains includes unrealized gains of $1.9 billion and $1.4 billion and unrealized losses of $4 million and $9 million as of December 31, 2021 and 2020, respectively.

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


	Years Ended December 31,
	2021		2020
	(in millions)
Proceeds from Investment Sales	$	1,886.4	$	1,593.4
Purchases of Investments	1,928.2		1,637.2
Gross Realized Gains on Investment Sales	103.2		26.4
Gross Realized Losses on Investment Sales	16.5		26.1

The base cost of fixed income securities was $1.2 billion and $1.1 billion as of December 31, 2021 and 2020, respectively. The base cost of equity securities was $641 million and $654 million as of December 31, 2021 and 2020, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2021 was as follows:


	Fair Value of Fixed
	Income Securities
	(in millions)
Within 1 year	$	302.4
After 1 year through 5 years	431.2
After 5 years through 10 years	227.7
After 10 years	279.1
Total	$	1,240.4

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, 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


	December 31, 2020
	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)

Derivative Instrument Assets
Risk Management Commodity Contracts (b) (d)	$	—	$	15.1	$	2.5	$	(13.9)	$	3.7

Other Special Funds
Cash and Cash Equivalents (c)	16.8		—		—		9.0		25.8
Fixed Income Securities:
United States Government	—		1,025.6		—		—		1,025.6
Corporate Debt	—		86.3		—		—		86.3
State and Local Government	—		114.3		—		—		114.3
Subtotal Fixed Income Securities	—		1,226.2		—		—		1,226.2
Equity Securities - Domestic (a)	2,054.7		—		—		—		2,054.7
Total Other Special Funds	2,071.5		1,226.2		—		9.0		3,306.7

Total Assets	$	2,071.5	$	1,241.3	$	2.5	$	(4.9)	$	3,310.4

Liabilities:

Derivative Instrument Liabilities
Risk Management Commodity Contracts (b) (d)	$	—	$	12.0	$	0.4	$	(12.2)	$	0.2

(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, 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)
Transfers out of Level 3 (c)	—
Changes in Fair Value Allocated to Regulated Jurisdictions (d)	(0.5)
Balance as of December 31, 2021	$	(0.7)

	Derivative Instrument
Year Ended December 31, 2020	Assets (Liabilities)
	(in millions)
Balance as of December 31, 2019	$	5.8
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)	2.5
Settlements	(8.6)
Transfers out of Level 3 (c)	0.4
Changes in Fair Value Allocated to Regulated Jurisdictions (d)	2.0
Balance as of December 31, 2020	$	2.1

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

(d)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, 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


December 31, 2020
				Significant	Input/Range
	Fair Value		Valuation	Unobservable					Weighted
	Assets	Liabilities	Technique	Input (a)	Low		High		Average (b)
	(in millions)
Energy Contracts	$ 0.6	$ 0.3	Discounted Cash Flow	Forward Market Price	$	10.84	$	41.09	$	25.08
FTRs	1.9	0.1	Discounted Cash Flow	Forward Market Price	(1.96)		3.69		0.33
Total	$ 2.5	$ 0.4

(a)Represents market prices in dollars per MWh.

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

The following table provides the measurement uncertainty of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs as of December 31, 2021 and 2020:

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 Benefit as reported are as follows:


		Years Ended December 31,
		2021			2020
		(in millions)
Charged (Credited) to Operating Expenses, Net:
	Current	$	31.3		$	15.6
	Deferred			(35.0)			(20.3)
Total				(3.7)			(4.7)

Charged (Credited) to Nonoperating Income, Net:
	Current			(4.4)			(2.4)
	Deferred			(3.1)			(0.4)
Total				(7.5)			(2.8)
Total Income Benefit		$	(11.2)		$	(7.5)

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,
	2021			2020
	(in millions)
Net Income	$	279.8		$	284.8
Income Tax Expense		(11.2)			(7.5)
Pretax Income	$	268.6		$	277.3

Income Taxes on Pretax Income at Statutory Rate (21%)	$	56.4		$	58.2
Increase (Decrease) in Income Taxes Resulting from the Following Items:
Reversal of Origination Flow-Through		3.5			1.6
Investment Tax Credit Amortization		(6.4)			(4.5)
State and Local Income Taxes, Net		(0.8)			1.5
Removal Costs		(9.7)			(10.5)
AFUDC		(2.7)			(2.4)
Parent Company Loss Benefit		(2.8)			(6.4)
Tax Reform Excess ADIT Reversal		(46.3)			(46.8)
Other		(2.4)			1.8
Income Tax Expense	$	(11.2)		$	(7.5)

Effective Income Tax Rate	(4.2)		%	(2.7)		%

Net Deferred Tax Liability

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


	December 31,
	2021		2020
	(in millions)
Deferred Tax Assets	$	1,071.5	$	989.8
Deferred Tax Liabilities	(2,172.3)		(2,056.1)
Net Deferred Tax Liabilities	$	(1,100.8)	$	(1,066.3)

Property Related Temporary Differences	$	(305.8)	$	(411.2)
Amounts Due to Customers for Future Federal Income Taxes	135.5		147.9
Deferred State Income Taxes	(221.9)		(211.1)
Accrued Nuclear Decommissioning	(743.2)		(626.4)
Regulatory Assets	(23.6)		(16.5)
Operating Lease Liability	13.5		46.6
All Other, Net	44.7		4.4
Net Deferred Tax Liabilities	$	(1,100.8)	$	(1,066.3)

Tax Credit Carryforward

As of December 31, 2021, I&M has federal tax credit carryforwards in the amount of $16.9 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.

AEP System Tax Allocation Agreement

I&M and other AEP subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax loss of the parent company (Parent Company Loss Benefit) to the AEP System subsidiaries with taxable income reducing their current tax expense proportionately. The consolidated NOL of the AEP System is allocated to each company in the consolidated group with taxable losses. 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.

Net Income Tax Operating Loss Carryforward

As of December 31, 2021, I&M has West Virginia net income tax operating loss carryforward of $6.3 million. As a result, I&M recognized deferred state income tax benefits. Management anticipates future taxable income will be sufficient to realize the state net income tax operating loss tax benefits before the state carryforward expires.

Uncertain Tax Positions

The amount and activity of unrecognized tax benefits for I&M was immaterial as of and for the twelve months ended December 31, 2021 and 2020. Management believes that there will be no significant net increase or decrease in unrecognized benefits within 12 months of the reporting date.

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. In the third quarter of 2019, I&M and other AEP subsidiaries elected to amend the 2014 through 2017 federal returns. In the first quarter of 2020, the IRS notified I&M and other AEP subsidiaries that it was beginning an examination of these amended returns, including the net operating loss carryback to 2015 that originated in the 2017 return. As of December 31, 2021, the IRS has not issued any proposed adjustments and the IRS is limited in their proposed adjustments to the amount I&M and other AEP subsidiaries claimed on the amended returns. I&M has agreed to extend the statute of limitations on the 2017 tax return to December 31, 2022 to allow time for the audit to be completed and the Congressional Joint Committee on Taxation to approve the associated refund claim.

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 I&M and other AEP subsidiaries are currently under examination in several state and local jurisdictions. The Registrants are no longer subject to state or local examinations by tax authorities for years before 2012. In addition, management is monitoring and continues to evaluate the potential impact of federal legislation and corresponding state conformity.

State Tax Legislation

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

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


	Years Ended December 31,
	2021		2020
	(in millions)
Operating Lease Cost	$	90.2	$	101.5
Finance Lease Cost:
Amortization of Right-of-Use Assets	98.1		93.9
Interest on Lease Liabilities	4.4		5.2
Total Lease Rental Costs (a)	$	192.7	$	200.6

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

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


	December 31,
	2021		2020
Weighted-Average Remaining Lease Term (years):
Operating Leases	5.87		3.50
Finance Leases	2.10		5.79
Weighted-Average Discount Rate:
Operating Leases	3.46	%	3.42	%
Finance Leases	3.02	%	8.29	%


	Year Ended December 31,
	2021		2020
	(in millions)
Cash paid for amounts included in the measurement of lease liabilities:
Operating Cash Flows from Operating Leases	$	92.9	$	102.2
Operating Cash Flows from Finance Leases	100.6		103.2

Non-cash Acquisitions Under Operating Leases	$	2.6	$	18.1

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,
	2021		2020
	(in millions)
Property, Plant and Equipment Under Finance Leases
Utility Plant (a)	$	160.6	$	41.7
Nuclear Fuel Under Finance Leases (b)	118.6		138.9
Net Property, Plant and Equipment Under Finance Leases	$	279.2	$	180.6

Obligations Under Finance Leases
Noncurrent	$	88.9	$	106.1
Current	192.0		74.5
Total Obligations Under Finance Leases	$	280.9	$	180.6

(a) Includes $38 million and $27 million of accumulated provision for depreciation and amortization for

the years ended December 31, 2021 and 2020, respectively.

(b) Includes $264 million and $266 million of accumulated provision for depreciation and amortization

for the years ended December 31, 2021 and 2020, respectively.


	December 31,
	2021		2020
	(in millions)
Property, Plant and Equipment Under Operating Leases
Utility Plant (a)	$	42.1	$	188.9
Nonutility Plant	43.2		47.5
Accumulated Provision for Depreciation and Amortization - Nonutility Plant	(21.9)		(18.3)
Net Property, Plant and Equipment Under Operating Leases	$	63.4	$	218.1

Obligations Under Operating Leases
Noncurrent	$	48.9	$	135.9
Current	15.5		85.6
Total Obligations Under Operating Leases	$	64.4	$	221.5

(a) Includes $18 million and $143 million of accumulated provision for depreciation and amortization for

the years ended December 31, 2021 and 2020, respectively.

Future minimum lease payments consisted of the following as of December 31, 2021:


	Finance Leases		Operating Leases
	(in millions)
2022	$	199.5	$	17.6
2023	46.5		11.7
2024	25.9		10.4
2025	11.4		9.3
2026	3.5		7.3
After 2026	10.1		15.0
Total Future Minimum Lease Payments	296.9		71.3
Less: Imputed Interest	16.0		6.9
Estimated Present Value of Future Minimum Lease Payments	$	280.9	$	64.4

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.

Rockport Lease

AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2. The trusts were capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors.

The trusts own undivided interests in Rockport Plant, Unit 2 and leases equal portions to AEGCo and I&M. 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 in December 2022. In December 2021, AEGCo and I&M satisfied the necessary regulatory approvals to complete the acquisition. Upon receipt of the regulatory approvals, the addition of the lessee forward purchase obligation resulted in the modified lease changing classification from operating to finance for AEGCo and I&M. I&M’s future minimum lease payments as of December 31, 2021, inclusive of the purchase obligation, were as follows:


Future Minimum Lease Payments
	(in millions)
2022	$	124.4
Total Future Minimum Lease Payments	$	124.4

The lease modification also created variable interests in the trusts that own the undivided interests in Rockport Plant, Unit 2 for I&M and AEGCo. Neither I&M nor AEGCo are the primary beneficiaries of the trusts because AEGCo nor I&M has the power to direct the most significant activities of the trusts. AEP and I&M’s maximum

exposure to loss associated with the trusts is equal to the total future minimum lease payments, inclusive of the purchase obligation, as shown in the table above.

Lessor Activity

I&M’s lessor activity was immaterial as of and for the twelve months ended December 31, 2021 and December 31, 2020, respectively.

Nuclear Fuel Lease

In December 2016, I&M entered into a sale-and-leaseback transaction for $87 million with DCC Fuel X LLC (DCC X). DCC X 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 52 months. I&M makes payments on the lease monthly. I&M made the final payment in April 2021.

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 has a variable rate and is a finance lease with a term of 52 months. I&M makes payments on the lease monthly. Payments began in December 2017.

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 has a variable rate and is a finance lease with a term of 52 months. I&M makes payments on the lease monthly. Payments began in June 2018.

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 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 2021.

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, 2021	2021	2020	2021		2020
Senior Unsecured Notes	2023-2051	4.19%	3.20%-6.05%	3.20%-6.05%	$	2,625.0	$	2,175.0
Pollution Control Bonds (a)	2021-2025 (b)	2.49%	0.75%-3.05%	0.18%-3.05%	190.0		242.0
Spent Nuclear Fuel Obligation (c)					281.3		281.2
Other Long-term Debt	2021-2025	6.00%	6.00%	1.28%-6.00%	7.3		209.4
Unamortized Discount, Net					(10.7)		(7.8)
Total Long-term Debt Outstanding					$	3,092.9	$	2,899.8

(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, 2021, long-term debt was payable as follows:


	(in millions)
2022	$	2.0
2023	252.4
2024	2.5
2025	190.4
2026	—
After 2026	2,656.3
Principal Amount	3,103.6
Unamortized Discount, Net	(10.7)
Total Long-term Debt	$	3,092.9

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 restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. However, the Federal Power Act creates a reserve on retained 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, 2021, 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, 2021, the amount of any such restrictions was $649 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 outstanding borrowings from the Utility Money Pool as of December 31, 2021 and 2020 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)
2021	$	166.5	$	354.8	$	110.4	$	96.2	$	93.3	$	500.0
2020	218.6		—		114.5		—		103.0		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

Interest Rates

Interest Rate

for Funds

Borrowed from

Loaned to the

Borrowed from

Loaned to the

Years ended

the Utility

Utility Money

the Utility

Utility Money

December 31,

Money Pool

Pool

Money Pool

Pool

(in millions)

2021

0.48%

0.04%

0.39%

0.02%

0.33%

0.23%

2020

2.70%

0.27%

—%

1.08%

—%

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 and interest income related to the corporate borrowing programs were immaterial for the years ended December 31, 2021 and 2020.

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 revenues 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.

AEP Credit has a receivables securitization agreement that provides a commitment of $750 million from bank conduits to purchase receivables and was amended in September 2021 to include a $125 million and a $625 million facility, which expire in September 2023 and 2024, respectively.

The amount of accounts receivable and accrued utility revenues under the sale of receivables agreement as of December 31, 2021 and 2020 were $157 million and $171 million, respectively.

The fees paid to AEP Credit for customer accounts receivable sold were $7 million and $8 million for the years ended December 31, 2021 and 2020, respectively. In 2020, an increase in allowance for doubtful accounts was recognized in response to the anticipated impact of COVID-19 on the collectability of accounts receivable, which caused an increase in fees paid by I&M. In 2021, due to higher than expected collections of accounts receivables, allowance for doubtful accounts was adjusted resulting in the issuance of credits to offset the higher fees previously paid and to lower subsequent fees paid.

The proceeds on the sale of receivables to AEP Credit were $1.9 billion and $1.9 billion for the years ended December 31, 2021 and 2020, respectively.

14. RELATED PARTY TRANSACTIONS

For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 11 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 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, 2021 and 2020:


		Years Ended December 31,
Related Party Revenues		2021		2020
		(in millions)
Auction Sales to OPCo (a)		$	—	$	3.1
Transmission Revenues		(2.5)		2.9
Other Revenues		6.3		4.5
(a)	Refer to the Ohio Auctions section below for further information regarding these amounts.

The following table shows the purchased power expenses incurred for purchases from affiliates for the years ended December 31, 2021 and 2020:


	Years Ended December 31,
Related Party Purchases	2021		2020
	(in millions)
Direct Purchases from AEGCo	$	217.9	$	172.8

PJM and SPP 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, 2021 and 2020 related to the TA were $187 million and $146 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, 2021 and 2020, AEPTCo billed I&M $5 million and $3 million, respectively.

Ohio Auctions

In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015. Certain affiliated entities, including I&M, participate in the auction process and have been awarded tranches of OPCo’s SSO load. Refer to the Affiliated Revenues and Purchases section above for amounts related to these transactions.

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. Subsequently, I&M assigns 30% of the power to KPCo. See the “UPA between AEGCo and KPCo” section below. 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 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).

UPA between AEGCo and KPCo

Pursuant to an assignment between I&M and KPCo and a UPA between AEGCo and KPCo, AEGCo sells KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo pays to 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. The KPCo UPA ends in 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 $11 million and $12 million for the years ended December 31, 2021 and 2020, 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 $343 thousand and $1 million for the years ended December 31, 2021 and 2020, 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 $61 million for the years ended December 31, 2021 and 2020, respectively, in Revenues from Nonutility Operations on the statements of income.

Central Machine Shop

APCo operates a facility which repairs and rebuilds specialized components for the generation plants across the AEP System. I&M recorded billings from APCo of $2 million and $3 million as capital or maintenance expenses depending on the nature of the services received for the years ended December 31, 2021 and 2020, respectively. These billings are recoverable from customers.

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,
	2021		2020
	(in millions)
Sales	$	7.0	$	1.5
Purchases	0.6		3.4

Sempra Renewables LLC PPAs

In April 2019, AEP acquired Sempra Renewables LLC and its ownership interests in 724 MWs of wind generation. The operating wind generation portfolio includes seven wind farms. Prior to the acquisition, two wind farms had existing PPAs with I&M, OPCo and SWEPCo. One of the joint venture wind farms has PPAs with I&M and OPCo for a portion of its energy production. The I&M portion totaled $10 million and $11 million, respectively, for the years ended December 31, 2021 and 2020.

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 $201 million and $210 million for the years ended December 31, 2021 and 2020, 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. Charitable contributions to the AEP Foundation were recorded in Donations on the statements of income. In 2021 and 2020, 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)
2021	3.5	8.7	4,2	2.5	2.4	3.4	9.0
2020	3.4	8.7	5.2	2.5	2.3	3.4	10.2

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

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. 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 its 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.

As of December 31, 2021 and 2020, I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $1.93 billion and $1.80 billion, respectively. These liabilities are reflected in Asset Retirement Obligations on I&M’s balance sheets. As of December 31, 2021 and 2020, the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $3.54 billion and $2.98 billion, respectively. These assets are included in Other Special Funds 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 2021 and 2020 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)
2021	$	1,813.8	$	72.9	$	0.3	$	(0.1)	$	59.4	$	1,946.3
2020	1,748.6		70.2		0.1		(0.2)		(4.9)		1,813.8

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, 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


			Share as of December 31, 2020
	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%	$	1,228.5	$	19.6	$	677.3

(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 is subject to a finance lease with a nonaffiliated company. See the “Rockport Lease” section of Note 12 for additional information.

(c)AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2.

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,
	2021		2020
	(in millions)
Retail Revenues:
Residential Revenues	$	812.1	$	790.3
Commercial Revenues	512.6		496.6
Industrial Revenues	565.3		541.6
Other Retail Revenues	5.2		6.6
Total Retail Revenues	1,895.2		1,835.1

Wholesale Revenues:
Generation Revenues	348.8		290.1
Transmission Revenues (a)	33.7		29.0
Total Wholesale Revenues	382.5		319.1

Other Revenues from Contracts with Customers (a)	45.4		21.2

Total Revenues from Contracts with Customers	2,323.1		2,175.4

Other Revenues:
Alternative Revenues	(4.0)		5.8
Other Revenues	0.1		(0.1)
Total Other Revenues	(3.9)		5.7

Total Operating Revenues	$	2,319.2	$	2,181.1

(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 encompasses a time frame greater

than a year, where the performance obligation within each RTO 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 are 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, 2021. Fixed performance obligations primarily include wholesale transmission services, electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market. The amounts shown in the table below include affiliated and nonaffiliated revenues.


2022		2023-2024		2025-2026		After 2026		Total
(in millions)
$	37.7	$	8.8	$	8.8	$	4.5	$	59.8

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, 2021 and 2020.

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, 2021 and 2020.

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, 2021 and 2020. 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 $61 million and $35 million, as of December 31, 2021 and 2020.

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, 2021 and 2020.

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, 2021 and 2020, 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, 2021
East Busco Station	Distribution	Churubusco, IN	363	$	5.6	562	$	—	592	$	—

Year Ended December 31, 2020
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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote. Report data on a year-to-date basis.
Line No.	Item (a)	Unrealized Gains and Losses on Available-For-Sale Securities (b)	Minimum Pension Liability Adjustment (net amount) (c)	Foreign Currency Hedges (d)	Other Adjustments (e)	Other Cash Flow Hedges Interest Rate Swaps (f)	Other Cash Flow Hedges [Specify] (g)	Totals for each category of items recorded in Account 219 (h)	Net Income (Carried Forward from Page 116, Line 78) (i)	Total Comprehensive Income (j)
1	Balance of Account 219 at Beginning of Preceding Year				1,809,499	9,777,400		11,586,899
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income				96,959	1,602,301		1,505,342
3	Preceding Quarter/Year to Date Changes in Fair Value				3,142,815			3,142,815
4	Total (lines 2 and 3)				3,045,856	1,602,301		4,648,157	284,780,284	289,428,441
5	Balance of Account 219 at End of Preceding Quarter/Year				1,236,357	8,175,099		6,938,742
6	Balance of Account 219 at Beginning of Current Year				1,236,357	8,175,099		6,938,742
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income				129,510	1,602,300		1,472,790
8	Current Quarter/Year to Date Changes in Fair Value				4,213,806			4,213,806
9	Total (lines 7 and 8)				4,084,296	1,602,300		5,686,596	279,843,643	285,530,239
10	Balance of Account 219 at End of Current Quarter/Year				5,320,653	6,572,799		1,252,146

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in column (h) common function.
Line No.	Classification (a)	Total Company For the Current Year/Quarter Ended (b)	Electric (c)	Gas (d)	Other (Specify) (e)	Other (Specify) (f)	Other (Specify) (g)	Common (h)
1	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlantInServiceAbstract In Service
3	UtilityPlantInServiceClassified Plant in Service (Classified)	9,830,460,917	9,830,460,917
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	202,741,633	202,741,633
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified	682,764,007	682,764,007
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	10,715,966,558	10,715,966,558
9	UtilityPlantLeasedToOthers Leased to Others
10	UtilityPlantHeldForFutureUse Held for Future Use	1,444,928	1,444,928
11	ConstructionWorkInProgress Construction Work in Progress	303,725,635	303,725,635
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	11,021,137,120	11,021,137,120
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	3,820,179,577	3,820,179,577
15	UtilityPlantNet Net Utility Plant (13 less 14)	7,200,957,543	7,200,957,543
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	3,606,225,578	3,606,225,578
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	213,949,072	213,949,072
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	3,820,174,650	3,820,174,650
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	4,927	4,927
29	AmortizationUtilityPlantHeldForFutureUse Amortization
30	DepreciationAndAmortizationUtilityPlantHeldForFutureUse Total Held for Future Use (28 & 29)	4,927	4,927
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)	3,820,179,577	3,820,179,577

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)
Report below the costs incurred for nuclear fuel materials in process of fabrication, on hand, in reactor, and in cooling; owned by the respondent. If the nuclear fuel stock is obtained under leasing arrangements, attach a statement showing the amount of nuclear fuel leased, the quantity used and quantity on hand, and the costs incurred under such leasing arrangements.
Line No.	Description of item (a)	Balance Beginning of Year (b)	Changes during Year Additions (c)	Changes during Year Amortization (d)	Changes during Year Other Reductions (Explain in a footnote) (e)	Balance End of Year (f)
1	Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1)
2	Fabrication
3	Nuclear Materials	30,959,357	70,596,870		(c) 64,228,403	37,327,824
4	Allowance for Funds Used during Construction	3,671,648	1,626,376		(d) 1,236,336	4,061,688
5	(Other Overhead Construction Costs, provide details in footnote)
6	SUBTOTAL (Total 2 thru 5)	34,631,005				41,389,512
7	Nuclear Fuel Materials and Assemblies
8	In Stock (120.2)
9	In Reactor (120.3)	1,460,144	64,512,558		(e) 64,900,000	1,072,702
10	SUBTOTAL (Total 8 & 9)	1,460,144				1,072,702
11	Spent Nuclear Fuel (120.4)	(a) 628,146,562	(b) 87,652,180		(f) 110,086,680	(h) 605,712,062
12	Nuclear Fuel Under Capital Leases (120.6)	138,923,597	64,900,000	85,199,047		118,624,550
13	(Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5)	629,038,752		86,766,552	(g) 110,086,680	605,718,624
14	TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13)	174,122,556				161,080,202
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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: SpentNuclearFuel

Includes 2020 costs in connection with nuclear leases:

Finance charges - $2,140,710

(b) Concept: SpentNuclearFuelAdditions

Reclassification of $64,900,000 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 - $64,900,000

(f) Concept: SpentNuclearFuelOtherReductions

Retirement of spent fuel

(g) Concept: AccumulatedProvisionForAmortizationOfNuclearFuelAssembliesOtherReductions

Retirement of spent fuel

(h) Concept: SpentNuclearFuel

Includes 2021 costs in connection with nuclear leases:

Finance charges - $1,408,148

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
Report below the original cost of electric plant in service according to the prescribed accounts. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and reductions in column (e) adjustments. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included in column (c) are entries for reversals of tentative distributions of the prior year reported in column (b). Likewise, if the respondent has a significant amount of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d) distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of respondent’s plant actually in service at end of year. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary account classifications. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing subaccount classification of such plant conforming to the requirement of these pages. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase, and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date.
Line No.	Account (a)	Balance Beginning of Year (b)	Additions (c)	Retirements (d)	Adjustments (e)	Transfers (f)	Balance at End of Year (g)
1	1. INTANGIBLE PLANT
2	(301) Organization	117,425					117,425
3	(302) Franchise and Consents	19,866,098					19,866,098
4	(303) Miscellaneous Intangible Plant	234,944,681	122,708,740	14,443,267			343,210,155
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)	254,928,204	122,708,740	14,443,267			363,193,678
6	2. PRODUCTION PLANT
7	A. Steam Production Plant
8	(310) Land and Land Rights	7,414,505					7,414,505
9	(311) Structures and Improvements	108,186,508	1,225,379				109,411,888
10	(312) Boiler Plant Equipment	892,331,178	17,423,178	367,827			909,386,529
11	(313) Engines and Engine-Driven Generators
12	(314) Turbogenerator Units	123,826,111	89,258	1,163,972			122,572,881
13	(315) Accessory Electric Equipment	63,038,644	55,015	3,442			63,090,216
14	(316) Misc. Power Plant Equipment	24,753,030	36,442				24,789,472
15	(317) Asset Retirement Costs for Steam Production	9,654,655	1,594,776				11,249,431
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)	1,229,204,631	20,245,532	1,535,240			1,247,914,922
17	B. Nuclear Production Plant
18	(320) Land and Land Rights	1,879,588					1,879,588
19	(321) Structures and Improvements	437,052,785	22,606,340	3,509,501			456,149,624
20	(322) Reactor Plant Equipment	1,737,315,152	5,757,508	3,021,576			1,740,051,084
21	(323) Turbogenerator Units	705,743,309	5,128,801	3,194,352			707,677,758
22	(324) Accessory Electric Equipment	319,102,431	2,516,680	1,726,464			319,892,647
23	(325) Misc. Power Plant Equipment	266,659,419	7,981,506	1,846,827			272,794,098
24	(326) Asset Retirement Costs for Nuclear Production	439,029,648	57,784,803				496,814,452
25	TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)	3,906,782,332	101,775,638	13,298,721			3,995,259,250
26	C. Hydraulic Production Plant
27	(330) Land and Land Rights	706,302					706,302
28	(331) Structures and Improvements	4,640,716	1,386,148				6,026,864
29	(332) Reservoirs, Dams, and Waterways	25,764,521					25,764,521
30	(333) Water Wheels, Turbines, and Generators	16,386,498					16,386,498
31	(334) Accessory Electric Equipment	5,700,261					5,700,261
32	(335) Misc. Power Plant Equipment	2,779,066	55,863				2,834,929
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)	56,296,737	1,442,011				57,738,748
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	34,915,732	28,046,222				62,961,954
42	(345) Accessory Electric Equipment	989,564	3,983,806				4,973,370
43	(346) Misc. Power Plant Equipment	570,074	219,342				789,416
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)	42,521,977	32,249,370				74,771,347
46	TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)	5,234,805,677	155,712,551	14,833,961			5,375,684,267
47	3. Transmission Plant
48	(350) Land and Land Rights	77,440,458	2,573,448	471,810			79,542,097
48.1	(351) Energy Storage Equipment - Transmission
49	(352) Structures and Improvements	52,265,232	25,828,651	736,511			77,357,371
50	(353) Station Equipment	826,495,898	31,970,823	8,395,353			850,071,368
51	(354) Towers and Fixtures	230,452,983	581,472	1,494,172			229,540,284
52	(355) Poles and Fixtures	208,136,265	32,177,603	8,094,544			232,219,325
53	(356) Overhead Conductors and Devices	294,558,395	15,803,205	2,893,820			307,467,780
54	(357) Underground Conduit	2,241,687					2,241,687
55	(358) Underground Conductors and Devices	4,522,363	44	115,096			4,407,311
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)	1,696,204,441	108,935,246	22,201,306			1,782,938,381
59	4. Distribution Plant
60	(360) Land and Land Rights	27,454,914	2,986,815	923			30,440,807
61	(361) Structures and Improvements	37,201,504	7,771,399	351,636			44,621,267
62	(362) Station Equipment	475,804,667	40,670,174	6,113,704			510,361,137
63	(363) Energy Storage Equipment – Distribution	5,606,730					5,606,730
64	(364) Poles, Towers, and Fixtures	332,615,577	33,292,640	3,661,625			362,246,592
65	(365) Overhead Conductors and Devices	539,255,018	54,059,101	5,008,721			588,305,398
66	(366) Underground Conduit	157,456,290	13,000,711	423,932			170,033,068
67	(367) Underground Conductors and Devices	293,561,890	13,506,148	2,204,593			304,863,444
68	(368) Line Transformers	370,584,963	22,710,752	8,811,309			384,484,406
69	(369) Services	199,608,826	11,609,442	1,038,631			210,179,636
70	(370) Meters	102,447,783	31,728,110	88,464			134,087,429
71	(371) Installations on Customer Premises	28,779,448	1,760,375	635,864			29,903,959
72	(372) Leased Property on Customer Premises
73	(373) Street Lighting and Signal Systems	23,995,677	2,016,878	1,239,326			24,773,229
74	(374) Asset Retirement Costs for Distribution Plant
75	TOTAL Distribution Plant (Enter Total of lines 60 thru 74)	2,594,373,287	235,112,545	29,578,729			2,799,907,103
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	4,736,320	7,496,720				12,233,040
87	(390) Structures and Improvements	69,653,008	3,158,355	771,397			72,039,966
88	(391) Office Furniture and Equipment	5,869,860		63,665			5,806,195
89	(392) Transportation Equipment		68,000				68,000
90	(393) Stores Equipment	996,539	29,220				1,025,759
91	(394) Tools, Shop and Garage Equipment	16,780,302	2,182,374	161,506			18,801,170
92	(395) Laboratory Equipment	240,988					240,988
93	(396) Power Operated Equipment	543,715					543,715
94	(397) Communication Equipment	66,494,678	2,856,327	773,455			68,577,550
95	(398) Miscellaneous Equipment	10,826,054	310,123	4,660			11,131,517
96	SUBTOTAL (Enter Total of lines 86 thru 95)	176,141,463	16,101,118	1,774,683			190,467,899
97	(399) Other Tangible Property
98	(399.1) Asset Retirement Costs for General Plant	742,981	301,055	10,441			1,033,595
99	TOTAL General Plant (Enter Total of lines 96, 97, and 98)	176,884,444	16,402,173	1,785,124			191,501,494
100	TOTAL (Accounts 101 and 106)	9,957,196,053	638,871,255	82,842,385			10,513,224,923
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)	9,957,196,053	638,871,255	82,842,385			10,513,224,923

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

ELECTRIC PLANT LEASED TO OTHERS (Account 104)
Line No.	LesseeName Name of Lessee (a)	IndicationOfAssociatedCompany * (Designation of Associated Company) (b)	LeaseDescription Description of Property Leased (c)	CommissionAuthorization Commission Authorization (d)	ExpirationDateOfLease Expiration Date of Lease (e)	ElectricPlantLeasedToOthers Balance at End of Year (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47	TOTAL

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held for future use. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.
Line No.	ElectricPlantHeldForFutureUseDescription Description and Location of Property (a)	ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate Date Originally Included in This Account (b)	ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate Date Expected to be used in Utility Service (c)	ElectricPlantHeldForFutureUse Balance at End of Year (d)
1	Land and Rights:
2	Rockport Generating Plant Unit 1 (0111)	11/01/1984		1,034,109.36
3	items under $250,000			404,895.78
4
21	Other Property:
22	Items Under $250,000			5,923.00
47	TOTAL			1,444,928

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Report below descriptions and balances at end of year of projects in process of construction (107). Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see Account 107 of the Uniform System of Accounts). Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line No.	ConstructionWorkInProgressProjectDescription Description of Project (a)	ConstructionWorkInProgress Construction work in progress - Electric (Account 107) (b)
1	Ameriplex - Land purchase	1,266,256
2	Rockport Catalyst Replacement	1,504,302
3	Blaine Street T#5 Replacement	4,974,686
4	RP-CI-IMPCo-G NMIB	9,542,235
5	Business LAN Expansion	3,686,034
6	South Bend SC (New)	5,214,600
7	Cook Network Redesign	11,860,907
8	SS-CI-IMPCo-D GEN PLT	6,000,047
9	Cook Nuclear Security Upgrades	6,146,950
10	Supplemental OPCo D work	4,572,319
11	Dist Station Renew-Refu I&M IN	1,729,089
12	Supplemental OPCo T work	2,138,684
13	Ed-Ci-Impco-D Ast Imp	11,646,369
14	T/IM/Capital Blanket - IMPCo	2,769,373
15	Ed-Ci-Impco-D Cust Serv	1,520,483
16	T/IM/Jefferson-Dumont Spacers	1,298,216
17	Fukushima-Seismic Hazard Eval	17,015,884
18	Trans Line Renew-RefurbI&M	1,192,394
19	FW AMI VVO Circuits / Stations	1,856,984
20	Trans station Renew-Refurb I&M	5,446,244
21	GLBU 120 IM T CI	2,440,504
22	Transformer #7 Replacement	1,186,746
23	GLBU 170 IM D CI (T Funded)	1,821,788
24	U1 MSR Digital Controls	6,842,433
25	I&M - Trans Supplemental	2,128,026
26	U2 MSR Digital Controls	8,522,133
27	I&M Failure Distribution	1,143,495
28	Unit 1 Spec 200	19,547,182
29	I&M Grid Modernization DACR IN	1,496,672
30	Unit 2 Spec 200	17,711,249
31	I&M OPCo D Supplemental	2,763,668
32	WS-CI-IMPCo-G PPB	8,170,607
33	I&M OPCO-T Baseline#1	4,058,049
34	Other Minor Projects Which is under 5% or $1,000,000	48,762,285
35	I&M T OPCo Supplemental	4,565,285
36	I&M T-OPCO	1,180,322
37	I&M Transmission Work	6,580,031
38	I&M-D Service Restoration Blkt	1,097,680
39	I&M-T-BlnktProj Under $3M	4,486,504
40	IM Distr Work	3,342,838
41	IM Distribution Work T Funded	1,161,578
42	IM Trans Work	3,311,036
43	IM/IN Dean Station Dist	5,452,261
44	IM/IN Elwood Rebuild Distrib	2,662,482
45	IM/IN Jay Station Distribution	1,219,573
46	IMIN Public Efficient Strlght	2,420,602
47	IMPCo Trans Pre Eng Parent	6,588,140
48	IMPCO-D Telecom	2,540,814
49	Michigan Roadside Relocate	1,130,994
50	OPCo T CI	2,053,873
51	OPCo T Supplemental CI	12,354,658
52	Purchase of Muncie SC	6,821,475
53	RK U0 CCR Compliance	1,919,368
54	RKP05CIIM Horiz RH ReplaceU1	2,985,956
55	Rob Park - E. Elkhart 345kV	1,873,273
43	Total	303,725,635

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
Explain in a footnote any important adjustments during year. Explain in a footnote any difference between the amount for book cost of plant retired, Line 12, column (c), and that reported for electric plant in service, page 204, column (d), excluding retirements of non-depreciable property. The provisions of Account 108 in the Uniform System of Accounts require that retirements of depreciable plant be recorded when such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional classifications. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Line No.	Item (a)	Total (c + d + e) (b)	Electric Plant in Service (c)	Electric Plant Held for Future Use (d)	Electric Plant Leased To Others (e)
Section A. Balances and Changes During Year
1	AccumulatedProvisionForDepreciationOfElectricUtilityPlant Balance Beginning of Year	3,292,122,973	3,292,118,150	4,823
2	Depreciation Provisions for Year, Charged to
3	DepreciationExpenseExcludingAdjustments (403) Depreciation Expense	386,648,297	386,648,193	104
4	DepreciationExpenseForAssetRetirementCosts (403.1) Depreciation Expense for Asset Retirement Costs	316,287	316,287
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):	20,491,182	(a) 20,491,182
10	DepreciationProvision TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)	406,823,192	406,823,088	104
11	Net Charges for Plant Retired:
12	BookCostOfRetiredPlant Book Cost of Plant Retired	67,126,529	67,126,529
13	CostOfRemovalOfPlant Cost of Removal	51,535,260	(b) 51,535,260
14	SalvageValueOfRetiredPlant Salvage (Credit)	10,653,559	(c) 10,653,559
15	NetChargesForRetiredPlant TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)	108,008,230	108,008,230
16	OtherAdjustmentsToAccumulatedDepreciation Other Debit or Cr. Items (Describe, details in footnote):
17.1	Other Debit or Cr. Items (Describe, details in footnote):	15,292,570	(d) 15,292,570
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)	3,606,230,505	3,606,225,578	4,927
Section B. Balances at End of Year According to Functional Classification
20	AccumulatedDepreciationSteamProduction Steam Production	590,837,933	590,837,933
21	AccumulatedDepreciationNuclearProduction Nuclear Production	1,704,119,033	1,704,119,033
22	AccumulatedDepreciationHydraulicProductionConventional Hydraulic Production-Conventional	35,407,357	35,407,357
23	AccumulatedDepreciationHydraulicProductionPumpedStorage Hydraulic Production-Pumped Storage
24	AccumulatedDepreciationOtherProduction Other Production	10,517,717	10,517,717
25	AccumulatedDepreciationTransmission Transmission	462,348,721	462,343,794	4,927
26	AccumulatedDepreciationDistribution Distribution	762,943,085	762,943,085
27	AccumulatedDepreciationRegionalTransmissionAndMarketOperation Regional Transmission and Market Operation
28	AccumulatedDepreciationGeneral General	40,056,658	40,056,658
29	AccumulatedProvisionForDepreciationOfElectricUtilityPlant TOTAL (Enter Total of lines 20 thru 28)	3,606,230,505	3,606,225,578	4,927

FOOTNOTE DATA

(a) Concept: OtherAccounts


Amortization of the Cook ARO			20,616,078.68
Revised items due to IURC Final Order in I&M's Base Case Cause No. 44967			(442,916.04)
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			973,955.70
Record over/under for the Clean Coal Technology Rider to collect Rockport SCR 2 costs from customers. CC deferrals begin in Oct18 and revenues begin being collected Dec18. Indiana Cause 44871.			(507,710.47)
Amortization per MPSC Order in I&M Base Case No. U-18370			(185,667.78)
Record over/under recovery of the I&M South Bend Solar Project			(165,565.90)
ARO depr exp 1080013			203,007.72
Total			20,491,181.91

(b) Concept: CostOfRemovalOfPlant

Includes $12,240,090.00 of removal cost in retirement work in progress (RWIP).

(c) Concept: SalvageValueOfRetiredPlant

Includes ($5,482,656.97) of salvage in retirement work in progress (RWIP).

(d) Concept: OtherAdjustmentsToAccumulatedDepreciation


Reclassify the gain of closure of ARO liability and loss on retirement of ARO asset for the Hartford City SC to 1080013			23,201.95
Transfers between accounts			3,417,822.20
To defer the incremental depreciation expense for Rockport Unit 2 using 2022 retirement date instead of 2028 for the period April 26, 2018 through December 2022 as approved by the MPSC in Case No. U-18370.			12,280,322.29
Defer ARO Deprec & Accretion Exp			(428,776.00)
TOTAL			15,292,570.44

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
Report below investments in Account 123.1, Investments in Subsidiary Companies. Provide a subheading for each company and list thereunder the information called for below. Sub-TOTAL by company and give a TOTAL in columns (e), (f), (g) and (h). (a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity, and interest rate. (b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity date, and specifying whether note is a renewal. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for Account 418.1. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee and purpose of the pledge. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission, date of authorization, and case or docket number. Report column (f) interest and dividend revenues from investments, including such revenues from securities disposed of during the year. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or the other amount at which carried in the books of account if different from cost) and the selling price thereof, not including interest adjustment includible in column (f). Report on Line 42, column (a) the TOTAL cost of Account 123.1.
Line No.	DescriptionOfInvestmentsInSubsidiaryCompanies Description of Investment (a)	DateOfAcquisitionInvestmentsInSubsidiaryCompanies Date Acquired (b)	DateOfMaturityInvestmentsInSubsidiaryCompanies Date of Maturity (c)	InvestmentInSubsidiaryCompanies Amount of Investment at Beginning of Year (d)	EquityInEarningsOfSubsidiaryCompanies Equity in Subsidiary Earnings of Year (e)	InterestAndDividendRevenueFromInvestments Revenues for Year (f)	InvestmentInSubsidiaryCompanies Amount of Investment at End of Year (g)	InvestmentGainLossOnDisplosal Gain or Loss from Investment Disposed of (h)
1	Blackhawk Coal Company, Inc.	09/01/1980
2	Common Stock			25,324,000			25,324,000
3	Cash Capital Contribution
4	Equity in Earnings			5,485,144	2,781,813		2,703,331
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	19,866,131	2,781,813		22,647,944

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

MATERIALS AND SUPPLIES
For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a); estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense clearing, if applicable.
Line No.	Account (a)	Balance Beginning of Year (b)	Balance End of Year (c)	Department or Departments which Use Material (d)
1	Fuel Stock (Account 151)	81,606,797	53,538,758	Electric
2	Fuel Stock Expenses Undistributed (Account 152)	4,411,863	3,254,610	Electric
3	Residuals and Extracted Products (Account 153)
4	Plant Materials and Operating Supplies (Account 154)
5	Assigned to - Construction (Estimated)	86,400,575	94,708,498	Electric
6	Assigned to - Operations and Maintenance
7	Production Plant (Estimated)	85,806,538	76,089,960	Electric
8	Transmission Plant (Estimated)	468,764	1,124,908	Electric
9	Distribution Plant (Estimated)	946,505	849,125	Electric
10	Regional Transmission and Market Operation Plant (Estimated)
11	Assigned to - Other (provide details in footnote)	(a) 491,916	(b) 596,193	Electric
12	TOTAL Account 154 (Enter Total of lines 5 thru 11)	174,114,298	173,368,683
13	Merchandise (Account 155)
14	Other Materials and Supplies (Account 156)	1,479,180	1,510,191	River Transport
15	Nuclear Materials Held for Sale (Account 157) (Not applic to Gas Util)
16	Stores Expense Undistributed (Account 163)
17
18
19
20	TOTAL Materials and Supplies	261,612,138	231,672,242

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

Allowances (Accounts 158.1 and 158.2)
Report below the particulars (details) called for concerning allowances. Report all acquisitions of allowances at cost. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k). Report on Line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40. Report on Line 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances. Report on Lines 8-14 the names of vendors/transferors of allowances acquired and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
		Current Year		Year One		Year Two		Year Three		Future Years		Totals
Line No.	SO2 Allowances Inventory (Account 158.1) (a)	No. (b)	Amt. (c)	No. (d)	Amt. (e)	No. (f)	Amt. (g)	No. (h)	Amt. (i)	No. (j)	Amt. (k)	No. (l)	Amt. (m)
1	Balance-Beginning of Year	514,711	25,760,670	107,267		107,267		115,572		2,109,080		2,953,897	25,760,670
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)	1,948								81,376		83,324
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	4,784	161,666									4,784	161,666
19	Other:
20	Allowances Used
20.1	Allowances Used
21	Cost of Sales/Transfers:
22	Consent Decree Surrenders	15,942		66,821								82,763
23	Fathom Energy LLC
24
25
26
27
28	Total	15,942		66,821								82,763
29	Balance-End of Year	495,933	25,599,004	40,446		107,267		115,572		2,190,456		2,949,674	25,599,004
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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

Allowances (Accounts 158.1 and 158.2)
Report below the particulars (details) called for concerning allowances. Report all acquisitions of allowances at cost. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k). Report on Line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40. Report on Line 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances. Report on Lines 8-14 the names of vendors/transferors of allowances acquired and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
		Current Year		Year One		Year Two		Year Three		Future Years		Totals
Line No.	NOx Allowances Inventory (Account 158.1) (a)	No. (b)	Amt. (c)	No. (d)	Amt. (e)	No. (f)	Amt. (g)	No. (h)	Amt. (i)	No. (j)	Amt. (k)	No. (l)	Amt. (m)
1	Balance-Beginning of Year	70,987	3,425	19,934		19,934		22,560				133,415	3,425
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)	1,722		3,223		3,223		3,223				11,391
5	Returned by EPA
6
7
8	Purchases/Transfers:
9
10
11
12
13
14
15	Total
16
17	Relinquished During Year:
18	Charges to Account 509	1,580										1,580
19	Other:
20	Allowances Used
20.1	Allowances Used
21	Cost of Sales/Transfers:
22	Wolverine Power Supply Cooperative, Inc.	1,560	1,017									1,560	1,017
23	Surrenders
24	Consent Decree Surrenders
25	Unknown
26	Other
27
28	Total	1,560	1,017									1,560	1,017
29	Balance-End of Year	66,125	2,408	16,711		16,711		19,337				118,884	2,408
30
31	Sales:
32	Net Sales Proceeds(Assoc. Co.)
33	Net Sales Proceeds (Other)		1,017										1,017
34	Gains
35	Losses		1,017										1,017
	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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

EXTRAORDINARY PROPERTY LOSSES (Account 182.1)
				WRITTEN OFF DURING YEAR
Line No.	DescriptionOfExtraordinaryPropertyLoss Description of Extraordinary Loss [Include in the description the date of Commission Authorization to use Acc 182.1 and period of amortization (mo, yr to mo, yr).] (a)	ExtraordinaryPropertyLossesNotYetRecognized Total Amount of Loss (b)	ExtraordinaryPropertyLossesRecognized Losses Recognized During Year (c)	ExtraordinaryPropertyLossesWrittenOffAccountCharged Account Charged (d)	ExtraordinaryPropertyLossesWrittenOff Amount (e)	ExtraordinaryPropertyLosses Balance at End of Year (f)
1
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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)
				WRITTEN OFF DURING YEAR
Line No.	DescriptionOfUnrecoveredPlantAndRegulatoryStudyCosts Description of Unrecovered Plant and Regulatory Study Costs [Include in the description of costs, the date of COmmission Authorization to use Acc 182.2 and period of amortization (mo, yr to mo, yr)] (a)	UnrecoveredPlantAndRegulatoryStudyCostsNotYetRecognized Total Amount of Charges (b)	UnrecoveredPlantAndRegulatoryStudyCostsRecognized Costs Recognized During Year (c)	UnrecoveredPlantAndRegulatoryStudyCostsWrittenOffAccountCharged Account Charged (d)	UnrecoveredPlantAndRegulatoryStudyCostsWrittenOff Amount (e)	UnrecoveredPlantAndRegulatoryStudyCosts Balance at End of Year (f)
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49	TOTAL

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

Transmission Service and Generation Interconnection Study Costs
Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and generator interconnection studies. List each study separately. In column (a) provide the name of the study. In column (b) report the cost incurred to perform the study at the end of period. In column (c) report the account charged with the cost of the study. In column (d) report the amounts received for reimbursement of the study costs at end of period. In column (e) report the account credited with the reimbursement received for performing the study.
Line No.	DescriptionOfStudyPerformed Description (a)	StudyCostsIncurred Costs Incurred During Period (b)	StudyCostsAccountCharged Account Charged (c)	StudyCostsReimbursements Reimbursements Received During the Period (d)	StudyCostsAccountReimbursed Account Credited With Reimbursement (e)
1	Transmission Studies
2	AC2-080	2,291	186	1,654	186
3	AE1-113	308	186	308	186
4	AE1-163	6	186	13	186
5	AF1-071	2,528	186	2,528	186
6	AF1-084	9,499	186	9,499	186
7	AF1-091	2,407	186	2,407	186
8	AF1-092	12,815	186	13,022	186
9	AF1-141	11,775	186	11,775	186
10	AF1-148	1,465	186	1,790	186
11	AF1-161	6,727	186	9,312	186
12	AF1-176	17,088	186	17,060	186
13	AF1-202	8,785	186	8,500	186
14	AF1-204	10,438	186	10,284	186
15	AF1-207	6,103	186	6,103	186
16	AF1-215	11,594	186	11,370	186
17	AF1-223	538	186	538	186
18	AF1-268	4,592	186	4,515	186
19	AF1-322	9,535	186	9,506	186
20	AF2-008	4,573	186	5,807	186
21	AF2-083	7,342	186	4,514	186
22	AF2-094	2,645	186	2,357	186
23	AF2-125	3,951	186
24	AF2-132	13,680	186	12,659	186
25	AF2-133	15,374	186	14,360	186
26	AF2-134	921	186	607	186
27	AF2-162	2,007	186	2,007	186
28	AF2-173	1,711	186	1,600	186
29	AF2-177	3,713	186	3,713	186
30	AF2-188	1,994	186	1,994	186
31	AF2-189	1,217	186	1,217	186
32	AF2-191	2,072	186	2,125	186
33	AF2-204	1,353	186	1,353	186
34	AF2-205	6,704	186	6,739	186
35	AF2-224	6,946	186	6,614	186
36	AF2-359	987	186	1,005	186
37	AF2-370	839	186	839	186
38	AG1-109	2,422	186	2,240	186
39	AG1-222	1,048	186	1,259	186
40	AG1-224	1,067	186	1,905	186
41	AG1-225	2,271	186	1,780	186
42	AG1-226	2,062		2,471	186
43	AG1-232	4,229	186	4,383	186
44	AG1-237	1,387	186	1,956	186
45	AG1-238	1,025	186	1,235	186
46	AG1-297	2,750	186	3,232	186
47	AG1-302	3,029	186	3,499	186
48	AG1-324	3,815	186	3,944	186
49	AG1-349	906	186	1,169	186
50	AG1-365	3,532	186	3,901	186
51	AG1-366	1,221	186	1,559	186
52	AG1-367	3,578	186	3,721	186
53	AG1-368	3,014	186	2,972	186
54	AG1-375	2,512	186	2,242	186
55	AG1-376	834	186	1,079	186
56	AG1-414	834	186	1,079	186
57	AG1-417	1,249	186	1,656	186
58	AG1-418	1,499	186	2,022	186
59	AG1-424	3,154	186	3,154	186
60	AG1-433	4,473	186	4,635	186
61	AG1-436	3,347	186	3,558	186
62	AG1-447	3,326	186	3,499	186
63	AG1-448	3,666	186	3,818	186
64	AG1-453	3,776	186	3,996	186
65	AG1-454	3,682	186	4,016	186
66	AG1-522	2,162	186	2,621	186
67	AG1-523	1,577	186	1,963	186
68	AG1-524	1,686	186	2,129	186
69	AG1-525	841	186	1,194	186
70	AG1-555	2,220	186	2,659	186
71	AG2-014	403	186	589	186
72	AG2-029	867	186	1,271	186
73	AG2-072	3,275	186	2,616	186
74	AG2-083	1,470	186	1,420	186
75	AG2-084	2,159	186	1,970	186
76	AG2-085	1,482	186	1,401	186
77	AG2-116	2,001	186	1,912	186
78	AG2-117	1,507	186	1,415	186
79	AG2-126	1,738	186	1,644	186
80	AG2-130	1,968	186	1,880	186
81	AG2-131	1,575	186	1,495	186
82	AG2-132	2,237	186	2,142	186
83	AG2-138	127	186	121	186
84	AG2-162	1,634	186	1,540	186
85	AG2-163	1,343	186	1,251	186
86	AG2-164	390	186	384	186
87	AG2-165	1,209	186	1,188	186
88	AG2-170	384	186
89	AG2-173	1,119	186	1,096	186
90	AG2-191	1,314	186	1,289	186
91	AG2-192	1,110	186	1,090	186
92	AG2-222	781	186	773	186
93	AG2-242	127	186	121	186
94	AG2-519	859	186	804	186
95	AG2-577	732	186	681	186
96	AG2-683	544	186	1,096	186
97	AH1-013	328	186	312	186
98	J793	23,975	186	22,614	186
99	PJM - # AD2-080	15	186
100	PJM - # AE1-039	27	186
101	PJM - # AE1-170	1,080	186	1,266	186
102	PJM - # AE2-240	415	186	610	186
103	PJM - # AE2-325	14,472	186	17,768	186
104	PJM - # AF1-046	178	186
105	PJM - # AG1-109	794	186	1,080	186
106	PJM - #A21-008	8	186
107	PJM - #AB1-087	14,022	186	19,147	186
108	PJM - #AB1-088	6,050	186	11,593	186
109	PJM - #AC1-174/175	717	186	189	186
110	PJM - #AC2-090	6,003	186	6,142	186
111	PJM - #AC2-157	11,251	186	13,499	186
112	PJM - #AD1-043	4,753	186	7,920	186
113	PJM - #AD1-128	20,328	186	21,895	186
114	PJM - #AD2-020	2,680	186	2,256	186
115	PJM - #AD2-071	7,547	186	18,145	186
116	PJM - #AD2-138	6,644	186	4,961	186
117	PJM - #AE1-207	3,528	186	7,033	186
118	PJM - #AE1-208	3,424	186	5,618	186
119	PJM - #AE1-209	114,593	186	114,956	186
120	PJM - #AE1-210	900	186	817	186
121	PJM - #AE2-045	212	186
122	PJM - #AE2-089	7,664	186	10,716	186
123	PJM - #AE2-090	43	186
124	PJM - #AE2-107	8	186
125	PJM - #AE2-130	4,401	186	4,759	186
126	PJM - #AE2-138	10	186
127	PJM - #AE2-154	2,144	186	1,975	186
128	PJM - #AE2-169	942	186	970	186
129	PJM - #AE2-171	290	186	352	186
130	PJM - #AE2-172	877	186	888	186
131	PJM - #AE2-219	3,327	186	12,432	186
132	PJM - #AE2-234	5,516	186	6,348	186
133	PJM - #AE2-236	13,252	186	13,357	186
134	PJM - #AE2-276	839	186	1,074	186
135	PJM - #AE2-297	384	186	4,819	186
136	PJM - #AE2-323	3,436	186	4,611	186
137	PJM - #AF1-071	83	186
138	PJM - #AF1-080	272	186
139	PJM - #AF1-084	62	186
140	PJM - #AF1-088	919	186	935	186
141	PJM - #AF1-091	84	186
142	PJM - #AF1-092	314	186
143	PJM - #AF1-118	9,406	186	9,940	186
144	PJM - #AF1-119	6,116	186	6,287	186
145	PJM - #AF1-141	31	186
146	PJM - #AF1-148	11	186
147	PJM - #AF1-158	13,326	186	13,396	186
148	PJM - #AF1-161	152	186
149	PJM - #AF1-175	32	186
150	PJM - #AF1-176	110	186
151	PJM - #AF1-202	45	186
152	PJM - #AF1-204	139	186
153	PJM - #AF1-207	100	186
154	PJM - #AF1-215	31	186
155	PJM - #AF1-221	13,464	186	13,775	186
156	PJM - #AF1-223	180	186
157	PJM - #AF1-268	137	186
158	PJM - #AF1-298	90	186
159	PJM - #AF1-313	91	186
160	PJM - #AF2-068	3,375	186	3,759	186
161	PJM - #AF2-078	1,498	186	1,750	186
162	PJM - #AF2-083	229	186
163	PJM - #AF2-094	2,950	186	3,007	186
164	PJM - #AF2-125	963	186	1,380	186
165	PJM - #AF2-132	980	186	1,154	186
166	PJM - #AF2-133	979	186	1,152	186
167	PJM - #AF2-134	683	186	830	186
168	PJM - #AF2-162	514	186	684	186
169	PJM - #AF2-173	2,108	186	2,715	186
170	PJM - #AF2-177	2,328	186	2,903	186
171	PJM - #AF2-188	522	186
172	PJM - #AF2-189	256	186
173	PJM - #AF2-190	516	186
174	PJM - #AF2-191	270	186
175	PJM - #AF2-204	1,247	186	1,562	186
176	PJM - #AF2-205	463	186
177	PJM - #AF2-211	2,713	186	3,280	186
178	PJM - #AF2-224	82	186
179	PJM - #AF2-332	75	186
180	PJM - #AF2-335	1,725	186	2,111	186
181	PJM - #AF2-353	338	186
182	PJM - #AF2-359	217	186
183	PJM - #AF2-370	1,152	186	1,443	186
184	PJM - #AF2-388	2,500	186	2,999	186
185	PJM - #AF2-389	3,754	186	3,992	186
186	PJM - #AF2-396	1,901	186	2,020	186
187	PJM - #AF2-407	3,419	186	3,908	186
188	PJM - #AF2-408	1,737	186	2,188	186
189	PJM - #AG1-017	2,480	186	3,585	186
190	PJM - #AG1-047	3,655	186	4,794	186
191	PJM - #AG1-049	1,404	186	1,774	186
192	PJM - AF1-030	38	186
193	PJM - AF1-156	10	186
194	PJM - AF1-200	36	186	67	186
195	PJM - AF1-314	44	186	82	186
196	PJM - AF1-316	9	186
197	PJM #AF1-046	1,463	186	1,463	186
198	PJM-AD2-079			16,965	186
20	Total
21	Generation Studies
39	Total
40	Grand Total

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

OTHER REGULATORY ASSETS (Account 182.3)
Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. For Regulatory Assets being amortized, show period of amortization.
				CREDITS
Line No.	DescriptionAndPurposeOfOtherRegulatoryAssets Description and Purpose of Other Regulatory Assets (a)	OtherRegulatoryAssets Balance at Beginning of Current Quarter/Year (b)	IncreaseDecreaseInOtherRegulatoryAssets Debits (c)	OtherRegulatoryAssetsWrittenOffAccountCharged Written off During Quarter/Year Account Charged (d)	OtherRegulatoryAssetsWrittenOffRecovered Written off During the Period Amount (e)	OtherRegulatoryAssets Balance at end of Current Quarter/Year (f)
1	SFAS 112 Post Employment Benefits	4,981,895	4,090,480	228, 242	55,842	9,016,533
2	Cook Plant Water Study Cost	10,104,683		524	713,792	9,390,891
3	Cook Plant Refueling Levelization	39,451,231	43,466,662	517, 519, 520, 523, 524, 528, 529, 530, 531, 532	50,918,458	31,999,435
4	COVID-19 Deferred Bad Debt Expense	3,751,613	821,949	426	2,867,857	1,705,705
5	Unamortized Loss on Reacquired DebtAmort 1/1995 - 12/2022	413,906		428	206,954	206,952
6	Michigan Home Energy Managment and Work Energy Manament Programs	509,496	83,658			593,154
7	Deferred Storm Expense	298,079	14,751,271	254, 593	2,481,043	12,568,307
8	Unrealized Loss on Forward CommitmentsRegulated Assets/Liabilities	5,718,663	38,560,339	175, 182, 244, 456	31,764,308	1,077,368
9	Cook Life Cycle Management - Indiana Portion Per IIURC Cause Order #44182		1,706,481	403	937,712	768,769
10	Netting of Trading Activities Related to UnrealizedGains/Losses on Forward Commitments BetweenRegulatory Assets and Liabilities	5,718,663	1,730,511	254	1,353,012	6,096,162
11	Indiana Plugged In Rebate Deferral	5,044	28,958	182 ,431	323	33,679
12	Michigan Plugged In Rebate Deferral	1,505	5,732	182 ,431	88	7,149
13	Michigan Dry Cask Storage Deferral	444	834	182 ,431	297	981
14	PJM RTEP Costs Deferral	260,992		242	260,992
15	Nuclear Decommissioning Study Expense		185,400			185,400
16	Indiana Rate Case expensesPer IURC Cause Order #44075	1,141,809	1,018,636	928	876,584	1,283,861
17	IN PJM Exp and OSS Margin		18,144,149			18,144,149
18	Cook Uprate Project	30,156,255		524	2,417,536	27,738,719
19	Michigan Rate Case Expenses	521,041		928	418,387	102,654
20	Michigan Electric Vehicle Supply Equipment Per MPSC Case U-16496	62,267		912	54,216	8,051
21	SFAS 158 Employer Accounting for DefinedBenefit Pension & Other Postretirement Plans	25,658,507	38,984,585	165,219,190,219,228,000.00	64,643,092
22	Under Recovery of PJM True-Up Amortization Period: 01/2021-12/2021	2,020,022	1,032,139	182 ,234 ,242 ,447, 565	3,052,161
23	GreenHat Default Contingency	6,115		232, 566	6,115
24	DSM Energy Optimization Program - Michigan	18,619	6,680,084	403, 421, 908	6,573,905	124,798
25	Deferred Depreciation Rockport Unit 2	10,171,440	12,547,606	108	267,283	22,451,763
26	Michigan Under Recovered Fuel Interest	111,900	193,553	419 ,440 ,442 ,444	73,783	7,870
27	SFAS 109 Deferred FIT	126,662,216	41,040,464	190 ,236 ,254 ,255 ,282 ,283,409 ,410 ,411	28,867,555	138,835,125
28	SFAS 109 Deferred SIT	210,333,221	32,510,699	283	21,273,934	221,569,986
29	City of Fort Wayne SettlementAmortization 3/13 - 4/25Per IURC Cause Order #44075	3,980,284		182 ,588	914,591	3,065,693
30	Cook Unit 2 Baffle Bolts Amort 3/2013 - 2/2038 Per IURC Cause Order #44075	5,148,905		530	299,936	4,848,969
31	SFAS 106 Medicare Subsidy Amort 1/2013 - 12/2024	4,080,539		926	1,020,135	3,060,404
32	River Transportation Selling Price Variance	5,734,117	5,524,914	417	10,487,948	771,083
33	Cook Life Cycle Management Program - Michigan Per MPSC Case U-17026	14,100,061	459,678	182,403,408 ,421	1,472,991	13,086,748
34	Unrecovered Fuel Costs - Michigan	5,497,363	4,662,371	419,440,442,444.00	3,781,633	6,378,101
35	Rockport DSI Project - Indiana 20% Non Federal Mandate Rider Per IURC Cause Order #44331	8,914,208	152,604	403	1,436,757	7,630,055
36	Cook Turbine Replacement CC _IndianaPer IURC Cause Order #44075	10,241,866	314,630	182 ,421	915,919	9,640,577
37	SNF Incremental Costs	11,836				11,836
38	Cook Turbine Replacement _MichiganPer MPSC Cause U-16801	846,030	231,664	403	1,077,694
39	Michigan Credit C Rider	170,695		146	170,695
40	Indiana DSM program Per IURC Cause order #43287 Per IURC Cause order #44182		8,499,994	908	5,673,128	2,826,866
41	FERC Formula Rates Under Recovery		1,032,139			1,032,139
44	TOTAL	525,144,404	278,462,184		247,336,656	556,269,932

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

MISCELLANEOUS DEFFERED DEBITS (Account 186)
Report below the particulars (details) called for concerning miscellaneous deferred debits. For any deferred debit being amortized, show period of amortization in column (a) Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by classes.
				CREDITS
Line No.	Description of Miscellaneous Deferred Debits (a)	Balance at Beginning of Year (b)	Debits (c)	Credits Account Charged (d)	Credits Amount (e)	Balance at End of Year (f)
1	Property Taxes	51,938,697	74,050,970	107, 186, 408, 417	72,875,610	53,114,057
2	Property Taxes - Capital Leases	62,343	1,394,114	408	1,392,533	63,924
3	Agency Fees, Factored Accts Rec	3,409,262	39,426,144	142, 173, 184, 426	39,775,067	3,060,339
4	River Transport Division	824,381	42,220,067	106, 121, 122, 142, 143, 144, 152, 156, 163, 165, 182, 232, 236, 242, 408, 417, 421, 426, 430	40,594,777	2,449,671
5	Estimated Barging Bills
6	Unamortized Credit Line Fees	345,468	1,059,457	431	423,789	981,136
7	Defd Non-taxable Leased Assets	77,455	915,927	146, 242, 184, 143, 232	750,606	242,776
8	Minor Items	4,660		232, 234, 253	1,080	3,580
9	Transource OU Acctg for Def Asset		256,947	146, 565	89,015	167,932
47	Miscellaneous Work in Progress	319,050				3,325,296
48	Deferred Regulatroy Comm. Expenses (See pages 350 - 351)
49	TOTAL	56,981,316				63,408,711

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

ACCUMULATED DEFERRED INCOME TAXES (Account 190)
Report the information called for below concerning the respondent’s accounting for deferred income taxes. At Other (Specify), include deferrals relating to other income and deductions.
Line No.	DescriptionOfAccumulatedDeferredIncomeTax Description and Location (a)	AccumulatedDeferredIncomeTaxes Balance at Beginning of Year (b)	AccumulatedDeferredIncomeTaxes Balance at End of Year (c)
1	Electric
2	ACCRD BOOK ARO EXPENSE - SFAS 143	381,923,357	473,109,090
3	Reg Liability - SFAS 143 - ARO	310,092,825	407,340,905
4	EXCESS ADFIT 282 - PROTECTED.	147,920,786	132,041,368
5	BOOK OPERATING LEASE - LIAB	20,020,747	13,537,357
6	SI-AMORT INT PRE 4 7 83 DISP	28,466,507	28,824,843
7	Other	113,706,206	174,081,070
8	TOTAL Electric (Enter Total of lines 2 thru 7)	774,718,016	880,772,493
9	Gas
15	Other
16	TOTAL Gas (Enter Total of lines 10 thru 15)
17.1	Other (Specify)	215,073,374	190,728,021
17	Other (Specify)
18	TOTAL (Acct 190) (Total of lines 8, 16 and 17)	989,791,390	1,071,500,514

Notes

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

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

2022-05-19

Year/Period of Report

End of:

2021

/

Q4

Other Paid-in Capital
1. Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a subheading for each account and show a total for the account, as well as a total of all accounts for reconciliation with the balance sheet, page 112. Explain changes made in any account during the year and give the accounting entries effecting such change. Donations Received from Stockholders (Account 208) - State amount and briefly explain the origin and purpose of each donation. Reduction in Par or Stated Value of Capital Stock (Account 209) - State amount and briefly explain the capital changes that gave rise to amounts reported under this caption including identification with the class and series of stock to which related. Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210) - Report balance at beginning of year, credits, debits, and balance at end of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related. Miscellaneous Paid-In Capital (Account 211) - Classify amounts included in this account according to captions that, together with brief explanations, disclose the general nature of the transactions that gave rise to the reported amounts.
Line No.	Item (a)	Amount (b)
1	DonationsReceivedFromStockholdersAbstract Donations Received from Stockholders (Account 208)
2	DonationsReceivedFromStockholders Beginning Balance Amount	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	0
7.1	IncreasesDecreasesDueToReductionsInParOrStatedValueOfCapitalStock Increases (Decreases) Due to Reductions in Par or Stated Value of Capital Stock
8	ReductionInParOrStatedValueOfCapitalStock Ending Balance Amount	0
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
16	MiscellaneousPaidInCapital Ending Balance Amount	3,874,258
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	976,661,803

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

CAPITAL STOCK EXPENSE (Account 214)
Report the balance at end of the year of discount on capital stock for each class and series of capital stock. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars (details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Line No.	NameOfClassAndSeriesOfStock Class and Series of Stock (a)	CapitalStockExpense Balance at End of Year (b)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22	TOTAL	127

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

LONG-TERM DEBT (Account 221, 222, 223 and 224)
Report by Balance Sheet Account the details concerning long-term debt included in Accounts 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other Long-Term Debt. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds, and in column (b) include the related account number. For Advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate demand notes as such. Include in column (a) names of associated companies from which advances were received, and in column (b) include the related account number. For receivers' certificates, show in column (a) the name of the court and date of court order under which such certificates were issued, and in column (b) include the related account number. In a supplemental statement, give explanatory details for Accounts 223 and 224 of net changes during the year. With respect to long-term advances, show for each company: (a)principal advanced during year (b) interest added to principal amount, and (c) principal repaid during year. Give Commission authorization numbers and dates. If the respondent has pledged any of its long-term debt securities, give particulars (details) in a footnote, including name of the pledgee and purpose of the pledge. If the respondent has any long-term securities that have been nominally issued and are nominally outstanding at end of year, describe such securities in a footnote. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest expense in column (m). Explain in a footnote any difference between the total of column (m) and the total Account 427, Interest on Long-Term Debt and Account 430, Interest on Debt to Associated Companies. Give details concerning any long-term debt authorized by a regulatory commission but not yet issued.
Line No.	ClassAndSeriesOfObligationCouponRateDescription Class and Series of Obligation, Coupon Rate (For new issue, give commission Authorization numbers and dates) (a)	RelatedAccountNumber Related Account Number (b)	Principal Amount of Debt Issued (c)	LongTermDebtIssuanceExpensePremiumOrDiscount Total Expense, Premium or Discount (d)	LongTermDebtIssuanceExpenses Total Expense (e)	LongTermDebtPremium Total Premium (f)	LongTermDebtDiscount Total Discount (g)	NominalDateOfIssue Nominal Date of Issue (h)	DateOfMaturity Date of Maturity (i)	AmortizationPeriodStartDate AMORTIZATION PERIOD Date From (j)	AmortizationPeriodEndDate AMORTIZATION PERIOD Date To (k)	Outstanding (Total amount outstanding without reduction for amounts held by respondent) (l)	Interest for Year Amount (m)
1	Bonds (Account 221)
2	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
14	Pollution Control Revenue Bonds Lawrenceburg, IN
15	Series H - Variable Rate		52,000,000		331,889			05/20/2008	11/01/2021	05/20/2008	11/01/2021		56,055
16					277,847			03/09/2017	11/01/2021	03/09/2017	11/01/2021
17	Rockport, IN
18	Series D - 2.05% Fixed Rate		40,000,000		1,157,720			04/25/2008	04/01/2025	04/25/2008	04/01/2025		341,667
19					391,775			05/16/2017	04/01/2025	05/16/2017	06/01/2021
20	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
21					325,000		325,000
22					136,351		136,351
23					444,593			06/01/2007	06/01/2025	06/01/2007	06/01/2025
24					386,217			12/01/2017	06/01/2025	12/01/2017	06/01/2025
25					74,250					06/01/2016	05/31/2017
26					74,250					06/01/2017	05/31/2018
27					74,250					06/01/2018	05/31/2019
28					74,250					06/01/2019	05/31/2020
29					74,250					06/01/2020	05/31/2021
30	(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
31					249,468					06/01/2014	05/31/2018
32					354,263			06/01/2018	06/01/2025	06/01/2018	06/01/2025
33	(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
34					249,469					06/01/2014	05/30/2018
35					354,262			06/01/2018	06/01/2025	06/01/2018	06/01/2025
36	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	14,167
37	Senior Unsecured Notes
38	Series L - 3.75% Fixed Rate		300,000,000		3,139,683		2,088,000	06/09/2017	07/01/2047	06/29/2017	07/01/2047	300,000,000	11,250,000
39	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
40	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
41	Amortization of Cash Flow Hedges on 6.05% SUN									11/14/2006	02/28/2037		421,741
42	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
43	(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	9,831,250
44	(d) Fort Wayne Settlement		26,802,388					03/01/2010	02/28/2025	03/01/2010	02/28/2025	7,302,217
45	Multiple Draw Term Loan		200,000,000		612,944			05/14/2015	05/14/2018	06/01/2015	05/14/2018		870,639
46	Variable Rate				510,628			05/09/2018	05/09/2021	05/09/2018	05/09/2021
47	Amortization of Interest Rate Swap on 3.20% SUN									03/18/2013	03/15/2023		1,606,489
48	(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
49	(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
35	Subtotal		3,133,802,388		33,370,195		13,916,351					3,103,597,081	112,879,508
33	TOTAL		3,133,802,388									3,103,597,081	112,879,508

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

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.

(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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
Line No.	Particulars (Details) (a)	Amount (b)
1	Net Income for the Year (Page 117)	279,843,643
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	161,456,356
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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

TAXES ACCRUED, PREPAID AND CHARGES DURING YEAR
Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual, or estimated amounts of such taxes are known, show the amounts in a footnote and designate whether estimated or actual amounts. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.) Enter the amounts in both columns (g) and (h). The balancing of this page is not affected by the inclusion of these taxes. Include in column (g) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued, (b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than accrued and prepaid tax accounts. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained. If any tax (exclude Federal and State income taxes) covers more than one year, show the required information separately for each tax year, identifying the year in column (d). Enter all adjustments of the accrued and prepaid tax accounts in column (i) and explain each adjustment in a foot- note. Designate debit adjustments by parentheses. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending transmittal of such taxes to the taxing authority. Report in columns (l) through (o) how the taxes were distributed. Report in column (o) only the amounts charged to Accounts 408.1 and 409.1 pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 409.1 pertaining to other utility departments and amounts charged to Accounts 408.2 and 409.2. Also shown in column (o) the taxes charged to utility plant or other balance sheet accounts. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
					BALANCE AT BEGINNING OF YEAR					BALANCE AT END OF YEAR		DISTRIBUTION OF TAXES CHARGED
Line No.	DescriptionOfTaxesAccruedPrepaidAndCharged Kind of Tax (See Instruction 5) (a)	TypeOfTax Type of Tax (b)	TaxJurisdiction State (c)	TaxYear Tax Year (d)	TaxesAccrued Taxes Accrued (Account 236) (e)	PrepaidTaxes Prepaid Taxes (Include in Account 165) (f)	TaxesCharged Taxes Charged During Year (g)	TaxesPaid Taxes Paid During Year (h)	TaxAdjustments Adjustments (i)	TaxesAccrued Taxes Accrued (Account 236) (j)	PrepaidTaxes Prepaid Taxes (Included in Account 165) (k)	TaxesAccruedPrepaidAndCharged Electric (Account 408.1, 409.1) (l)	IncomeTaxesExtraordinaryItems Extraordinary Items (Account 409.3) (m)	AdjustmentsToRetainedEarnings Adjustment to Ret. Earnings (Account 439) (n)	TaxesIncurredOther Other (o)
1	Excise Tax	Federal Tax		2020	171,856		3,000	174,856		0	0				3,000
2	Excise Tax	Federal Tax		2021	0	0	606,404	437,158		169,246	0	11,738			594,666
3	Local Tax	Federal Tax		2019	30,028	0				30,028	0
4	Federal Tax	Federal Tax			10,243,274		27,376,977	29,327,851		12,194,148	0	31,398,635			4,021,658
5	Subtotal Federal Tax				10,101,446	0	27,986,381	29,939,865		12,054,930	0	31,410,373			3,423,992
6	State Tax	State Tax	IL
7	State Tax	State Tax	IL	2017	198,385	0				198,385	0
8	State Tax	State Tax	IL	2018	375,107	0				375,107	0
9	State Tax	State Tax	IL	2019	667,976	0				667,976	0
10	State Tax	State Tax	IL	2020	505,308	0	3,297			508,605	0				3,297
11	State Tax	State Tax	IL		0	0	48,973			48,973	0	49,040			67
12	State Tax	State Tax	IN	2015	30,176	0				30,176	0
13	State Tax	State Tax	IN	2017	4,389,858	0				4,389,858	0
14	State Tax	State Tax	IN	2018	7,980,470	0				7,980,470	0
15	State Tax	State Tax	IN	2019	2,361,490	0				2,361,490	0
16	State Tax	State Tax	IN	2020	7,963,408	0	286,822			8,250,230	0				286,822
17	State Tax	State Tax	IN	2021	0	0	22,984			22,984	0	27,946			4,962
18	State Tax	State Tax	KY	2017	147,238	0				147,238	0
19	State Tax	State Tax	KY	2018	87,492	0				87,492	0
20	State Tax	State Tax	KY	2019	36,699	0				36,699	0
21	State Tax	State Tax	KY	2020	104,868	0	4,996			99,872	0				4,996
22	State Tax	State Tax	KY	2021	0	0	32,616			32,616	0	32,685			69
23	State Tax	State Tax	MI	2017	1,008,265	0				1,008,265	0
24	State Tax	State Tax	MI	2018	1,961,572	0				1,961,572	0
25	State Tax	State Tax	MI	2019	1,708,540	0				1,708,540	0
26	State Tax	State Tax	MI	2020	2,627,000	0	62,462			2,689,462	0				62,462
27	State Tax	State Tax	MI	2021	0	0	29,327			29,327	0	30,490			1,163
28	State Tax	State Tax	MO	2017	1,164	0				1,164	0
29	State Tax	State Tax	MO	2018	255	0				255	0
30	State Tax	State Tax	MO	2019	342	0				342	0
31	State Tax	State Tax	MO	2020	716	0	877			161	0				877
32	State Tax	State Tax	MO	2021	0	0	3			3	0	3
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	NOL	2011	0	0	25			25	0				25
36	State Tax	State Tax	UT	2020	145,741	0	2,393			148,134	0				2,393
37	State Tax	State Tax	UT	2021	0	0				0	0	2,884			2,884
38	State Tax	State Tax	WV	2017	1,337,464	0				1,337,464	0
39	State Tax	State Tax	WV	2018	257,890	0				257,890	0
40	State Tax	State Tax	WV	2019	58,958	0				58,958	0
41	State Tax	State Tax	WV	2020	78,903	0	10,118			89,021	0				10,118
42	State Tax	State Tax	WV	2021	0	0	53,885			53,885	0	57,305			3,420
43	State Tax	State Tax	FIN48		126	0				126	0
44	Subtotal State Tax				6,309,094	0	434,470			5,874,624	0	85,737			348,733
45	Local Tax	Local Tax	MI	2008	1,279	0				1,279	0
46	Local Tax	Local Tax	MI	2013	18	0				18	0
47	Local Tax	Local Tax	MULTI	2008	1,279	0				1,279	0
48	Local Tax	Local Tax	MULTI	2013	18	0				18	0
49	Local Tax	Local Tax	MULTI	2017	1,261	0				1,261	0
50	Local Tax	Local Tax	OH	2018	1,200	0				1,200	0
51	Local Tax	Local Tax	OH	2020	0	0		2,000		2,000	0
52	Subtotal Local Tax				2,461	0		2,000		4,461	0
53	Property Tax	Property Tax	AR	2020	0	0	6,536	6,536		0	0				6,536
54	Property Tax	Property Tax	CO	2020	0	0	6,349	6,349		0	0				6,349
55	Property Tax	Property Tax	IL	2020	0	0	793	793		0	0	793
56	Property Tax	Property Tax	IN	2019	0	0	556	556		0	0	556
57	Property Tax	Property Tax	IN	2020	19,737,000	0	1,725,127	21,462,127		0	0	1,709,038			16,089
58	Property Tax	Property Tax	IN	2021	0	0	22,410,018	261,818		22,148,200	0	21,599,800			810,218
59	Property Tax	Property Tax	KY	2018	24,174	0	24,174			0	0				24,174
60	Property Tax	Property Tax	KY	2019	707,000	0	75,196	631,804		0	0				75,196
61	Property Tax	Property Tax	KY	2020	625,000	0				625,000	0
62	Property Tax	Property Tax	KY	2021	0	0	528,037	37		528,000	0				528,037
63	Property Tax	Property Tax	LA	2021	0	0	1,598	1,598		0	0				1,598
64	Property Tax	Property Tax	MI	2019	15,713,363	0	2,187,240	13,526,121		2	0	2,187,240
65	Property Tax	Property Tax	MI	2020	51,271,039	0	206,000	34,911,184		16,565,855	0	50,575,619			50,369,619
66	Property Tax	Property Tax	MI	2021	0	0	52,571,980			52,571,980	0				52,571,980
67	Property Tax	Property Tax	MO	2021	0	0	30,010	18,982		11,028	0				30,010
68	Property Tax	Property Tax	NE	2019	0	0	1,682	1,682		0	0				1,682
69	Property Tax	Property Tax	TN	2021	0	0	521	521		0	0				299
70	Property Tax	Property Tax	WV	2019	63,444	0	10,407	73,851		0	0				10,407
71	Property Tax	Property Tax	WV	2020	210,000	0	29,030	104,776		76,194	0	3,571			32,601
72	Property Tax	Property Tax	WV	2021	0	0	156,000			156,000	0				156,000
73	Property Tax	Property Tax	WY	2020	0	0	4,700	3,020		1,680	0				4,700
74	Property Tax	Property Tax	AL	2021	0	0	19	19		0	0				19
75	Subtotal Property Tax				88,351,020	0	75,343,581	71,010,662		92,683,939	0	71,701,025			3,642,334
76	UNEMPLOYMENT 2021	Unemployment Tax			19,539	0	106,283	101,505		24,317	0	67,802			38,481
77	STATE UNEMPLOYMENT 2021	Unemployment Tax	IN		3,695	0	48,887	46,650		5,932	0	34,587			14,300
78	STATE UNEMPLOYMENT 2021	Unemployment Tax	MO		0	0				0	0
79	STATE UNEMPLOYMENT 2021	Unemployment Tax	MI		72,521	0	225,183	241,062		56,642	0	180,254			44,929
80	STATE UNEMPLOYMENT 2021	Unemployment Tax	OH		0	0				0	0
81	STATE UNEMPLOYMENT 2021	Unemployment Tax	VA		0	0				0	0
82	STATE UNEMPLOYMENT 2021	Unemployment Tax	WV		1	0	25,670	25,670		1	0	4,976			30,646
83	Subtotal Unemployment Tax				95,756	0	406,023	414,887		86,892	0	277,667			128,356
84	Sales & Use Tax	Sales And Use Tax	IN
85	Sales & Use Tax	Sales And Use Tax	IN	2020	414,272	474,999	950,175	889,248		200	0				950,175
86	Sales & Use Tax	Sales And Use Tax	IN	2021	0	0	6,095,973	5,944,718		629,063	477,808	132			6,096,105
87	Sales & Use Tax	Sales And Use Tax	MI	2020	59,824	945,834	557,224	328,787		1	0	5,952			551,272
88	Sales & Use Tax	Sales And Use Tax	MI	2021	0	0	1,171,237	2,106,348		32,509	967,620	48,028			1,123,209
89	Sales & Use Tax	Sales And Use Tax	WV		0	0				0	0
90	Sales & Use Tax	Sales And Use Tax	WV	2020	3,535	0		3,535		0	0
91	Sales & Use Tax	Sales And Use Tax	WV	2021	0	0	31,859	27,853		4,006	0				31,859
92	Subtotal Sales And Use Tax				477,631	1,420,833	8,806,468	8,642,915		665,779	1,445,428	53,848			8,752,620
93	Excise Tax	Excise Tax	WV	2020	55,322	0		55,322		0
94	Excise Tax	Excise Tax	WV	2021	0	0	175,636	142,609		33,027					175,636
95	Subtotal Excise Tax				55,322	0	175,636	197,931		33,027					175,636
96	Franchise Tax	Franchise Tax	KY	2017	9,767	0				9,767	0
97	Franchise Tax	Franchise Tax	KY	2018	26,789	0				26,789	0
98	Franchise Tax	Franchise Tax	KY	2019	5,500	0				5,500	0
99	Franchise Tax	Franchise Tax	KY	2020	5,500	0	3,683			1,817	0	3,683
100	Franchise Tax	Franchise Tax	WV	2019	7,900	0				7,900	0
101	Subtotal Franchise Tax				55,456	0	3,683			51,773	0	3,683
102	Other State Tax	Other State Tax	IN	2020	0	0				0	0	191,745			191,745
103	Other State Tax	Other State Tax	IN	2021	0	0	21,564,222	21,564,222		0	0	21,755,967			191,745
104	Other State Tax	Other State Tax	OH	2020	15,000	0	16,696	1,696		0	0	16,696
105	Other State Tax	Other State Tax	OH	2021	0	0	20,617	7,117		13,500	0	20,617
106	Subtotal Other State Tax				15,000	0	21,568,143	21,569,643		13,500	0	21,568,143
107	Other License and Fees Tax	Other License And Fees Tax	MI	2020	50	0				50	0
108	Other License and Fees Tax	Other License And Fees Tax	WV	2019	26	0				26	0
109	Subtotal Other License And Fees Tax				76	0				76	0
110	FICA 2021	Payroll Tax			3,165,651	0	18,673,477	22,313,881	3,247,568	2,772,815	0	11,972,247			6,701,230
111	2360104 FICA	Payroll Tax			3,746,402	0			3,746,402	0	0
112	2360105 FICA CARES ACT	Payroll Tax			3,746,402	0			498,002	4,244,404	0
113	Subtotal Payroll Tax				10,658,455	0	18,673,477	22,313,881	832	7,017,219	0	11,972,247			6,701,230
114	Other Taxes & Fees	Other Taxes and Fees	IN
115	Other Taxes & Fees	Other Taxes and Fees	MI
116	Other Taxes & Fees	Other Taxes and Fees	MI	2021	0	0	18,600	18,600		0	0				18,600
117	Subtotal Other Taxes And Fees				0	0	18,600	18,600		0	0				18,600
40	TOTAL				95,913,751	1,420,833	152,540,156	154,110,384	832	94,367,286	1,445,428	136,893,883			15,646,051

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g). Include in column (i) the average period over which the tax credits are amortized.
			Deferred for Year		Allocations to Current Year's Income
Line No.	Account Subdivisions (a)	Balance at Beginning of Year (b)	Account No. (c)	Amount (d)	Account No. (e)	Amount (f)	Adjustments (g)	Balance at End of Year (h)	Average Period of Allocation to Income (i)	ADJUSTMENT EXPLANATION (j)
1	Electric Utility
2	3%	3,715,412			411.4	1,922,655		1,792,757
3	4%				411.4
4	7%	221,583			411.4	31,761		189,822
5	10%	6,941,476	411.1		411.4	2,001,265		4,940,211	29 Years
6	State DITC		411.1		411.4
7	30	10,382,234			411.4	5,079,317		15,461,551
8	TOTAL Electric (Enter Total of lines 2 thru 7)	21,260,705				1,123,636		22,384,341
9	Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
10										`
47	OTHER TOTAL
48	GRAND TOTAL	21,260,705						22,384,341

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

OTHER DEFERRED CREDITS (Account 253)
Report below the particulars (details) called for concerning other deferred credits. For any deferred credit being amortized, show the period of amortization. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
			DEBITS
Line No.	Description and Other Deferred Credits (a)	Balance at Beginning of Year (b)	Contra Account (c)	Amount (d)	Credits (e)	Balance at End of Year (f)
1	Pole Attachment Rentals	672,041	(a) Footnote	2,084,055	2,121,026	709,012
2	IPP-System Upgrade Credits	3,829,608			125,987	3,955,595
3	Defd Gain-Fiber Optics Agrmt In Kind Service-Amrtz thru 2025	2,588,871	124	476,400		2,112,471
4	Deferred Revenues-Verizon Amortized thru March 2023	106,742	451	47,438		59,304
5	Deferred Revenues-KDL Amortized thru Dec 2022	14,226	451	9,348		4,878
6	Customer Advance Receipts	7,668,054	142	7,668,053	9,956,569	9,956,570
7	Federal Mitigation Deferral (NSR)	1,052,907				1,052,907
8	Deferred Revenue	108,160	(b) Footnote	108,160	373,270	373,270
9	Contract Settlement Reserves	878,757	(c) Footnote	1,331,134	690,056	237,679
10	Asbestos Accrual
11	Minor Items	1,708,067	(d) Footnote	1,831,721	546,678	423,024
12	QUAL OF SVC PENALTIES - LT	784,226	242, 426	535,891		248,335
13	Neig Help Neig-Cust Donations	29				29
14	Rockport U2 Contingency Accrual	7,250,000	242	7,250,000
47	TOTAL	26,661,688		21,342,200	13,813,586	19,133,074

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: DecreaseInOtherDeferredCreditsContraAccount
143,163,184,186, 421,451,454,456,593
(b) Concept: DecreaseInOtherDeferredCreditsContraAccount
186,142,143
(c) Concept: DecreaseInOtherDeferredCreditsContraAccount
146,184,186,232,234,236,242,421
(d) Concept: DecreaseInOtherDeferredCreditsContraAccount
107,108,142,184,186,232,234,235,242

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)
Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to amortizable property. For other (Specify),include deferrals relating to other income and deductions. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Accelerated Amortization (Account 281)
2	Electric
3	Defense Facilities
4	Pollution Control Facilities	27,807,933	52,905	1,075,364							26,785,474
5	Other
5.1	Other (provide details in footnote):
8	TOTAL Electric (Enter Total of lines 3 thru 7)	27,807,933	52,905	1,075,364							26,785,474
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	10,794,207					254	52,905	254	821,723	10,025,389
17	TOTAL (Acct 281) (Total of 8, 15 and 16)	17,013,726	52,905	1,075,364				52,905		821,723	16,760,085
18	Classification of TOTAL
19	Federal Income Tax	17,013,726	52,905	1,075,364				52,905		821,723	16,760,085
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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282)
Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to property not subject to accelerated amortization. For other (Specify),include deferrals relating to other income and deductions. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Account 282
2	Electric	1,457,705,120	226,667,480	175,190,918			190	87,859,212	283		1,421,322,470
3	Gas
4	Other (Specify)
5	Total (Total of lines 2 thru 4)	1,457,705,120	226,667,480	175,190,918				87,859,212			1,421,322,470
6	Others	328,897,537	420,009	9,409,568			1823/254/190	31,177,274	1823/254	76,272,776	292,791,594
9	TOTAL Account 282 (Total of Lines 5 thru 8)	1,128,807,583	227,087,489	184,600,486				119,036,486		76,272,776	1,128,530,876
10	Classification of TOTAL
11	Federal Income Tax	1,128,807,583	227,087,489	184,600,486				119,036,486		76,272,776	1,128,530,876
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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283)
Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts recorded in Account 283. For other (Specify),include deferrals relating to other income and deductions. Provide in the space below explanations for Page 276. Include amounts relating to insignificant items listed under Other. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Account 283
2	Electric
3	NUC DECOM TRUST - SFAS 143 - A	626,382,351	139,791,884	23,191,575							742,982,660
4	U1-BK DEFD NUC REFUEL COSTS	8,284,757	6,600,877	8,165,754							6,719,880
5	UNIT 2 NUC FUEL TAX VS BOOK DE	140,350,038									140,350,038
6	UNIT 1 NUC FUEL TAX VS BOOK DE	134,484,324									134,484,324
7	CAPITALIZED SOFTWARE COST-BOOK	28,324,672	6,374,568	127,140							34,572,100
8	Other	326,909,116	63,518,696	77,699,967	266,540	691,311					341,515,158
9	TOTAL Electric (Total of lines 3 thru 8)	610,917,026	216,286,025	109,184,436	266,540	691,311					717,593,844
10	Gas
11
12
13
14
15
16
17	TOTAL Gas (Total of lines 11 thru 16)
18	TOTAL Other	299,349,097	66,845		1,546,202	2,560,829	1823/254/1903	39,751,626	1823/254	50,814,075	309,463,764
19	TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)	910,266,123	216,352,870	109,184,436	1,812,742	3,252,140		39,751,626		50,814,075	1,027,057,608
20	Classification of TOTAL
21	Federal Income Tax	699,932,902	212,954,740	95,002,415	1,812,743	3,252,139		29,261,586		18,303,375	805,487,620
22	State Income Tax	210,333,221						21,273,934		32,510,700	221,569,987
23	Local Income Tax
NOTES

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

OTHER REGULATORY LIABILITIES (Account 254)
Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. For Regulatory Liabilities being amortized, show period of amortization.
			DEBITS
Line No.	Description and Purpose of Other Regulatory Liabilities (a)	Balance at Beginning of Current Quarter/Year (b)	Account Credited (c)	Amount (d)	Credits (e)	Balance at End of Current Quarter/Year (f)
1	Unrealized Gain on Forward Commitments	1,611,222	175,182,244	5,488,216	1,226,758	5,872,680
2	Deferred Gain on Rockport Unit 2	7,164,353	145,507	3,706,716		3,457,637
3	Netting of Trading Activities Related to Unrealized Gains/Losses on Forward Commitments Between Regulated Assets/Liabilities	5,718,663	182	1,353,012	1,730,511	6,096,162
4	Indiana Environmental Compliance Rider	8,942,905	403 ,502	2,714,388	4,400,031	10,628,548
5	Indiana Solar Rider		403	21,185	186,751	165,566
6	Asset Retirement Oblig-Excess Provision SFAS 143	1,476,632,497	228	177,086,452	640,172,547	1,939,718,592
7	SNF Trust Funds - Pre 4/83	43,149,154	254,128,224	33,659,422	39,972,157	49,461,889
8	Gains on Foreign Currency DerivativesAmortz 1/2009 - 12/2023	33,927	403	11,309		22,618
9	SFAS 109 Deferred FIT	591,811,485	190, 282, 283	81,010,398	32,111,263	542,912,350
10	Cook Life Cycle Management - Indiana Per IURC Cause No. 44182	205,187	403	236,441	31,254
11	Over Recovered Fuel Costs - Indiana	20,756,554	182	20,756,554	1,519,445	1,519,445
12	Michigan Renewable Energy Surcharge	11,230,423	555	240,543	3,958,457	14,948,337
13	PJM Trans Enhancement	9,876,624	142	1,959,994		7,916,630
14	Indiana Resource Adequecy Rider	7,453,472	555	6,817,512	1,085,436	1,721,396
15	Expense and OSS Margin Sharing	13,289,058	555	19,263,378	5,974,320
16	SFAS 158 - Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans		129 ,165 ,190 ,219 ,228 ,242	23,400,496	50,992,287	27,591,791
17	DSM Energy Optimization Program - Michigan	5,975,675	908	6,649,625	7,633,670	6,959,720
18	MI Credit C Rider	82,457	407	119,902	487,259	449,814
19	Indiana Demand Side Management	9,408,496	908	19,096,519	9,688,023
41	TOTAL	2,210,119,708		403,592,062	801,170,169	2,607,697,815

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

Electric Operating Revenues
The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH related to unbilled revenues need not be reported separately as required in the annual version of these pages. Report below operating revenues for each prescribed account, and manufactured gas revenues in total. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added for billing purposes, one customer should be counted for each group of meters added. The average number of customers means the average of twelve figures at the close of each month. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification in a footnote.) See page 108, Important Changes During Period, for important new territory added and important rate increase or decreases. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts. Include unmetered sales. Provide details of such Sales in a footnote.
Line No.	Title of Account (a)	Operating Revenues Year to Date Quarterly/Annual (b)	Operating Revenues Previous year (no Quarterly) (c)	MEGAWATT HOURS SOLD Year to Date Quarterly/Annual (d)	MEGAWATT HOURS SOLD Amount Previous year (no Quarterly) (e)	AVG.NO. CUSTOMERS PER MONTH Current Year (no Quarterly) (f)	AVG.NO. CUSTOMERS PER MONTH Previous Year (no Quarterly) (g)
1	SalesOfElectricityHeadingAbstract Sales of Electricity
2	ResidentialSalesAbstract (440) Residential Sales	818,024,187	790,286,976	5,463,352	5,464,243	525,758	522,602
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)	516,316,915	496,638,746	4,599,874	4,475,154	72,042	71,527
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)	569,363,439	541,706,887	7,372,784	7,225,063	4,850	4,904
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting	5,339,682	6,545,284	58,034	66,647	1,899	1,913
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) 1,909,044,222	(e) 1,835,177,893	17,494,044	17,231,107	604,549	600,946
11	SalesForResaleAbstract (447) Sales for Resale	347,504,428	294,669,357	7,336,358	7,783,192	15	30
12	SalesOfElectricityAbstract TOTAL Sales of Electricity	2,256,548,651	2,129,847,250	24,830,402	25,014,299	604,564	600,976
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds	13,845,000	201,953
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds	2,242,703,651	2,129,645,297	24,830,402	25,014,299	604,564	600,976
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts	4,885,318	3,392,345
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	(b) 3,925,715	2,459,759
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power
19	RentFromElectricProperty (454) Rent from Electric Property	12,379,321	10,111,783
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	(c) 24,350,329	2,078,079
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	(d) 30,956,004	33,374,959
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	76,496,688	51,416,924
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	2,319,200,338	2,181,062,221
Line12, column (b) includes $ 15,368,364 of unbilled revenues.
Line12, column (d) includes 134,195 MWH relating to unbilled revenues

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: SalesToUltimateConsumers

Detail of unmetered Sales:


	Revenue	MWH	Average No.of Customers

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

(b) Concept: MiscellaneousServiceRevenues

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

(c) Concept: OtherElectricRevenue


	2021	2020

Associated Business Development	2,964,052.00	2,054,684.00
DSM Revenues	—	—
Other -Nonaffiliated	10,050.00	23,100.00
Misc Revenues<$250,000	—	295.00
Sales of Renew.Energy Credits	21,376,227.00	—
	24,350,329.00	2,078,079.00

(d) Concept: RevenuesFromTransmissionOfElectricityOfOthers

PJM Revenues

(e) Concept: SalesToUltimateConsumers

Detail of unmetered Sales:


	Revenue	MWH	Average No. of Custom

Residential	2,662,863.00	13,676.00	18,685.00
Commercial	4,465,603.00	29,217.00	10,476.00
Industrial	907,317.00	6,411.00	1,343.00
Public Street Lighting	63,603.00	410.00	123.00
Total	8,099,386.00	49,714.00	30,627.00

Total Sales to Ultimate Consumers include $7,670,807.78 of operating revenues for distribution service provided to Open Access Customers. Megawatt hours delivered to Open Access Customers were 286,367 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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

REGIONAL TRANSMISSION SERVICE REVENUES (Account 457.1)
The respondent shall report below the revenue collected for each service (i.e., control area administration, market administration, etc.) performed pursuant to a Commission approved tariff. All amounts separately billed must be detailed below.
Line No.	Description of Service (a)	Balance at End of Quarter 1 (b)	Balance at End of Quarter 2 (c)	Balance at End of Quarter 3 (d)	Balance at End of Year (e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46	TOTAL

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	Residential Service	5,366,392	797,116,437	515,366	10,413	0.1485
2	Residential Service TOD	90,416	12,596,129	5,711	15,832	0.1393
3	Residential Service Flat	10,233	1,638,758	1,035	9,887	0.1601
4	Residential Service PEV	664	51,522	73	9,096	0.0776
5	Res Off-Peak Energy Stor	23,584	2,941,591	1,213	19,443	0.1247
6	Res Svc Opt Senior Citizen	13,398	1,697,877	2,360	5,677	0.1267
7	Outdoor Lighting (Indiana)	13,542	2,687,995			0.1985
8	Rider
9	MI Credit		39,938
10	Misc Revenue Adjustment		837,788
11	Refund		453,038
12	Unrecovered Fuel		6,636,350
13	Outdoor Lighting (Indiana) -OAD	1	89			0.0890
41	TOTAL Billed Residential Sales	5,518,230	825,711,560	525,758	10,496	0.1496
42	TOTAL Unbilled Rev. (See Instr. 6)	54,878	7,687,373			0.1401
43	TOTAL	5,463,352	818,024,187	525,758	10,391	0.1497

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	Residential Service	3	567			0.1890
2	Energy Conserv Lighting Svc	6,010	1,076,345	9	667,778	0.1791
3	Electric Heating General	4,415	616,623	123	35,894	0.1397
4	Electric Heating Schools	5,270	611,345	13	405,375	0.1160
5	Irrigation Service	9,156	1,684,775	629	14,557	0.1840
6	Small General Service	2,796	436,839	543	5,149	0.1562
7	Small General Service TOD	681	101,147	73	9,325	0.1486
8	Medium General Service	1,364,789	200,790,783	62,507	21,834	0.1471
9	Medium General Service Flat	430	75,741	40	10,761	0.1760
10	Medium General Service TOD	66,923	7,956,727	1,961	34,127	0.1189
11	Medium General Service OAD	2,703	130,197	16	168,916	0.0482
12	Large General Service	1,994,354	199,387,351	3,843	518,957	0.1000
13	Large General Service TOD	78,378	7,873,016	529	148,163	0.1004
14	Large General Service OAD	14,944	490,538	5	2,988,858	0.0328
15	Large Power	74,904	6,286,347	4	18,726,100	0.0839
16	Large Power OAD	30,713	939,292	1	30,712,500	0.0306
17	Industrial Service	726,869	61,908,905	66	11,013,167	0.0852
18	Street Lighting Service	75	24,748	4	18,800	0.3291
19	Water & Sewage Service	159,015	12,948,508	690	230,456	0.0814
20	Municipal & School Service	46,526	5,950,441	426	109,215	0.1279
21	Street Light - Cust Owned - Meter	5,504	269,852	560	9,829	0.0490
22	Outdoor Lighting	29,080	4,489,583			0.1544
23	Estimated Revenue	18,116	1,161,153			0.0641
24	GS PEV	1	5			0.0050
25	Outdoor Lighting OAD	1	212			0.2099
26	Rider
27	MI Credit
28	Misc Revenue Adjustment		455,144
29	Refund		253,650
30	Unrecovered Fuel		5,323,410
41	TOTAL Billed Small or Commercial	4,641,654	520,735,934	72,042	64,430	0.1122
42	TOTAL Unbilled Rev. Small or Commercial (See Instr. 6)	41,780	4,419,019			0.1058
43	TOTAL Small or Commercial	4,599,874	516,316,915	72,042	63,850	0.1122

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	Electric Heating General	414	55,829	7	59,197	0.1347
2	Medium General Service	395,236	56,975,039	3,481	113,541	0.1442
3	Medium General Service - TOD	2,075	251,716	49	42,419	0.1213
4	Medium General Service OAD	7,631	450,686	13	583,382	0.0591
5	Medium General Service Flat	313	59,060	2	156,720	0.1884
6	Large General Service	1,123,501	117,130,864	1,085	1,035,800	0.1043
7	Large General Service - TOD	2,769	333,160	11	253,561	0.1203
8	Large General Service OAD	158	13,929	1	158,400	0.0879
9	Large Power	288,133	27,669,775	20	14,589,015	0.0960
10	Large Power OAD	221,672	5,451,778	6	38,022,642	0.0246
11	Industrial Service	5,346,124	353,516,792	167	32,108,855	0.0661
12	Water & Sewage Service	5,013	422,285	8	626,643	0.0842
13	Outdoor Lighting	6,312	898,670			0.1424
14	Energy Conserv Lighting	36	5,066	1	36,430	0.1390
15	Estimated Revenue	10,791	1,208,873			0.1120
16	Rider
17	MI Credit
18	Misc Revenue Adjustment		142,481
19	Refund		181,727
20	Unrecovered Fuel		8,208,537
21	Outdoor Lighting OAD	4	381			0.1005
41	TOTAL Billed Large (or Ind.) Sales	7,410,184	572,613,194	4,850	1,527,977	0.0773
42	TOTAL Unbilled Rev. Large (or Ind.) (See Instr. 6)	37,400	3,249,754			0.0869
43	TOTAL Large (or Ind.)	7,372,784	569,363,439	4,850	1,520,265	0.0772

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41	TOTAL Billed 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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	Small General Service	148	26,430	69	2,142	0.1788
2	Medium General Service TOD	168	27,296	41	4,158	0.1621
3	Ft Wayne Street Lighting	21,887	636,691	1	21,887,340	0.0291
4	Energy Conservation Lighting	18,502	2,811,240	202	91,481	0.1519
5	Street Light - Customer Owned	6,771	310,559	407	16,645	0.0459
6	Street Lighting Service	7,187	736,515	80	89,742	0.1025
7	Municipal & School Service	247	41,465	33	7,432	0.1678
8	Outdoor Lighting	413	64,206			0.1553
9	Medium General Service	2,848	633,523	1,066	2,671	0.2224
10	Indiana Riders
11	MI Credit
12	Misc Revenue Adjustment		6,144
13	Refund		350
14	Unrecovered Fuel		58,182
41	TOTAL Billed Public Street and Highway Lighting	58,171	5,351,900	1,899	30,633	0.0920
42	TOTAL Unbilled Rev. (See Instr. 6)	137	12,218			0.0892
43	TOTAL	58,034	5,339,682	1,899	30,560	0.0920

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41	TOTAL Billed Provision For Rate Refunds
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL		13,845,000

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
41	TOTAL Billed - All Accounts	17,628,240	1,924,412,587	604,549	29,159	0.1092
42	TOTAL Unbilled Rev. (See Instr. 6) - All Accounts	134,195	15,368,364			0.1145
43	TOTAL - All Accounts	17,494,044	1,909,044,223	604,549	29,159	0.1091

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

SALES FOR RESALE (Account 447)
Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the Purchased Power schedule (Page 326). Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the purchaser. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or setter can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less than five years. SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one year or less. LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years. OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote. AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (g) through (k). In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. Report in column (g) the megawatt hours shown on bills rendered to the purchaser. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k) the total charge shown on bills rendered to the purchaser. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,line 24. Footnote entries as required and provide explanations following all required data.
					ACTUAL DEMAND (MW)			REVENUE
Line No.	Name of Company or Public Authority (Footnote Affiliations) (a)	Statistical Classification (b)	FERC Rate Schedule or Tariff Number (c)	Average Monthly Billing Demand (MW) (d)	Average Monthly NCP Demand (e)	Average Monthly CP Demand (f)	Megawatt Hours Sold (g)	Demand Charges ($) (h)	Energy Charges ($) (i)	Other Charges ($) (j)	Total ($) (h+i+j) (k)
1	ALLEGHENY ELECTRIC COOPERATIVE	OS	NOTE 1				8,114		334,871		334,871
2	AMEREX POWER, LTD	OS	(a) NOTE 1				0		877		877
3	B.P. ENERGY COMPANY	OS	NOTE 1				21,619		501,015		501,015
4	CITIGROUP ENERGY INC.	OS	NOTE 1				0		154,000		154,000
5	CITY OF AUBURN	RQ	NOTE 1				429,786	24,691,423	12,761,018		37,452,441
6	CITY OF BLUFFTON	RQ	NOTE 1				0	585,088	93,699		491,389
7	CITY OF DOWAGIAC, MI	RQ	NOTE 1				56,758	3,855,095	1,960,757		5,815,853
8	CITY OF MISHAWAKA	RQ	NOTE 1				0	1,539,318	242,326		1,296,992
9	CITY OF NILES	RQ	NOTE 1				0	335,382	53,005		282,377
10	CITY OF SOUTH HAVEN	RQ	NOTE 1				0	411,307	16,301		395,007
11	CITY OF STURGIS	RQ	NOTE 1				0	628,668	86,179		542,489
12	DUQUESNE LIGHT COMPANY	OS	NOTE 1				8,228		332,618		332,618
13	EVOLUTION MARKETS FUTURES, LLC	OS	NOTE 1				0		4,132		4,132
14	FIRSTENERGY TRADING SERVICES	OS	NOTE 1				46,362		1,872,086		1,872,086
15	ICAP ENERGY LLC	OS	NOTE 1				0		1,647		1,647
16	INDIANA MUNICIPAL POWER AGENCY	RQ	NOTE 1				1,638,499	79,865,216	42,089,080		121,954,295
17	IVG ENERGY, LTD	OS	NOTE 1				0		3,191		3,191
18	OHIO POWER COMPANY (AUCTION)	OS	NOTE 1				24		665		665
19	PJM INTERCONNECTION	OS	NOTE 1				4,317,110	5,888,676	148,041,985		153,930,660
20	PJM INTERCONNECTION	RQ	VARIOUS				0			44,869,863	44,869,863
21	PPL ELECTRIC UTILITIES CORP	OS	NOTE 1				65,145		2,834,434		2,834,434
22	RBC CAPITAL MARKET, LLC	OS	NOTE 1				0		679		679
23	TOWN OF AVILA	RQ	NOTE 1				0	76,801	13,887		62,915
24	TOWN OF NEW CARLISLE	RQ	NOTE 1				0	28,825	6,824		22,002
25	TOWN OF WARREN	RQ	NOTE 1				0	45,537	10,327		(b) 35,210
26	TRIDENT BROKERAGE SERVICES, LLC	OS	NOTE 1				0		108		108
27	TULLETT PREBON AMERICAS CORP.	OS	NOTE 1				0		131		131
28	VILLAGE OF PAW PAW	RQ	NOTE 1				0	117,913	25,015		92,897
29	WABASH VALLEY POWER ASSN INC.	RQ	NOTE 1				787,952	45,597,541	25,048,027		70,645,567
30	WELLS FARGO SECURITIES, LLC	OS	NOTE 1				0		5,354,695		5,354,695
15	Subtotal - RQ						2,912,995	157,778,114	81,311,319	44,869,863	194,219,570
16	Subtotal-Non-RQ						4,423,364	5,888,676	147,396,183		153,284,858
17	Total						7,336,358	163,666,790	228,707,502	44,869,863	347,504,428

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: RateScheduleTariffNumber

FERC Electric Tariff, First Revised Volume No. 5.

(b) Concept: RevenueFromSalesOfElectricityForResale

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

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line No.	Account (a)	Amount for Current Year (b)	Amount for Previous Year (c) (c)
1	PowerProductionExpensesAbstract 1. POWER PRODUCTION EXPENSES
2	SteamPowerGenerationAbstract A. Steam Power Generation
3	SteamPowerGenerationOperationAbstract Operation
4	OperationSupervisionAndEngineeringSteamPowerGeneration (500) Operation Supervision and Engineering	4,706,248	4,496,332
5	FuelSteamPowerGeneration (501) Fuel	(a) 83,441,345	57,632,497
6	SteamExpensesSteamPowerGeneration (502) Steam Expenses	13,397,833	9,759,416
7	SteamFromOtherSources (503) Steam from Other Sources
8	SteamTransferredCredit (Less) (504) Steam Transferred-Cr.
9	ElectricExpensesSteamPowerGeneration (505) Electric Expenses	1,378,594	1,389,914
10	MiscellaneousSteamPowerExpenses (506) Miscellaneous Steam Power Expenses	3,059,605	5,890,317
11	RentsSteamPowerGeneration (507) Rents	68,652,193	69,239,217
12	Allowances (509) Allowances	161,666	385,556
13	SteamPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 4 thru 12)	174,797,483	148,793,249
14	SteamPowerGenerationMaintenanceAbstract Maintenance
15	MaintenanceSupervisionAndEngineeringSteamPowerGeneration (510) Maintenance Supervision and Engineering	2,304,616	2,426,190
16	MaintenanceOfStructuresSteamPowerGeneration (511) Maintenance of Structures	753,015	911,572
17	MaintenanceOfBoilerPlantSteamPowerGeneration (512) Maintenance of Boiler Plant	7,782,312	4,843,760
18	MaintenanceOfElectricPlantSteamPowerGeneration (513) Maintenance of Electric Plant	2,949,190	2,419,763
19	MaintenanceOfMiscellaneousSteamPlant (514) Maintenance of Miscellaneous Steam Plant	1,135,393	840,347
20	SteamPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 15 thru 19)	14,924,525	11,441,632
21	PowerProductionExpensesSteamPower TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)	189,722,008	160,234,881
22	NuclearPowerGenerationAbstract B. Nuclear Power Generation
23	NuclearPowerGenerationOperationAbstract Operation
24	OperationSupervisionAndEngineeringNuclearPowerGeneration (517) Operation Supervision and Engineering	(b) 18,443,254	16,559,670
25	NuclearFuelExpense (518) Fuel	87,999,744	85,970,603
26	CoolantsAndWater (519) Coolants and Water	6,989,349	6,660,772
27	SteamExpensesNuclearPowerGeneration (520) Steam Expenses	14,959,293	13,871,533
28	SteamFromOtherSourcesNuclearPowerGeneration (521) Steam from Other Sources
29	SteamTransferredCreditNuclearPowerGeneration (Less) (522) Steam Transferred-Cr.
30	ElectricExpensesNuclearPowerGeneration (523) Electric Expenses	5,868,035	5,503,598
31	MiscellaneousNuclearPowerExpenses (524) Miscellaneous Nuclear Power Expenses	(c) 69,106,183	82,219,394
32	RentsNuclearPowerGeneration (525) Rents
33	NuclearPowerGenerationOperationsExpense TOTAL Operation (Enter Total of lines 24 thru 32)	203,365,857	210,785,570
34	NuclearPowerGenerationMaintenanceAbstract Maintenance
35	MaintenanceSupervisionAndEngineeringNuclearPowerGeneration (528) Maintenance Supervision and Engineering	5,806,989	8,660,187
36	MaintenanceOfStructuresNuclearPowerGeneration (529) Maintenance of Structures	5,982,218	4,062,122
37	MaintenanceOfReactorPlantEquipmentNuclearPowerGeneration (530) Maintenance of Reactor Plant Equipment	65,392,064	71,015,691
38	MaintenanceOfElectricPlantNuclearPowerGeneration (531) Maintenance of Electric Plant	17,075,346	15,268,328
39	MaintenanceOfMiscellaneousNuclearPlant (532) Maintenance of Miscellaneous Nuclear Plant	16,886,003	16,434,768
40	NuclearPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 35 thru 39)	111,142,620	115,441,096
41	PowerProductionExpensesNuclearPower TOTAL Power Production Expenses-Nuclear. Power (Enter Total of lines 33 & 40)	314,508,478	326,226,666
42	HydraulicPowerGenerationAbstract C. Hydraulic Power Generation
43	HydraulicPowerGenerationOperationAbstract Operation
44	OperationSupervisionAndEngineeringHydraulicPowerGeneration (535) Operation Supervision and Engineering	220,338	372,875
45	WaterForPower (536) Water for Power
46	HydraulicExpenses (537) Hydraulic Expenses	74,927	107,514
47	ElectricExpensesHydraulicPowerGeneration (538) Electric Expenses	66,129	68,570
48	MiscellaneousHydraulicPowerGenerationExpenses (539) Miscellaneous Hydraulic Power Generation Expenses	1,036,000	1,092,039
49	RentsHydraulicPowerGeneration (540) Rents	148	27
50	HydraulicPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 44 thru 49)	1,397,542	1,640,971
51	HydraulicPowerGenerationContinuedAbstract C. Hydraulic Power Generation (Continued)
52	HydraulicPowerGenerationMaintenanceAbstract Maintenance
53	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration (541) Mainentance Supervision and Engineering	156,290	146,279
54	MaintenanceOfStructuresHydraulicPowerGeneration (542) Maintenance of Structures	981,805	686,662
55	MaintenanceOfReservoirsDamsAndWaterways (543) Maintenance of Reservoirs, Dams, and Waterways	123,885	357,746
56	MaintenanceOfElectricPlantHydraulicPowerGeneration (544) Maintenance of Electric Plant	174,757	279,950
57	MaintenanceOfMiscellaneousHydraulicPlant (545) Maintenance of Miscellaneous Hydraulic Plant	79,747	94,045
58	HydraulicPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 53 thru 57)	1,516,483	1,564,682
59	PowerProductionExpensesHydraulicPower TOTAL Power Production Expenses-Hydraulic Power (Total of Lines 50 & 58)	2,914,025	3,205,653
60	OtherPowerGenerationAbstract D. Other Power Generation
61	OtherPowerGenerationOperationAbstract Operation
62	OperationSupervisionAndEngineeringOtherPowerGeneration (546) Operation Supervision and Engineering	56,288	60,819
63	Fuel (547) Fuel
64	GenerationExpenses (548) Generation Expenses	9,992	542
64.1	OperationOfEnergyStorageEquipment (548.1) Operation of Energy Storage Equipment
65	MiscellaneousOtherPowerGenerationExpenses (549) Miscellaneous Other Power Generation Expenses	3,303,995	91,776
66	RentsOtherPowerGeneration (550) Rents	20
67	OtherPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 62 thru 67)	3,370,295	152,053
68	OtherPowerGenerationMaintenanceAbstract Maintenance
69	MaintenanceSupervisionAndEngineeringOtherPowerGeneration (551) Maintenance Supervision and Engineering	4,436
70	MaintenanceOfStructures (552) Maintenance of Structures
71	MaintenanceOfGeneratingAndElectricPlant (553) Maintenance of Generating and Electric Plant	32	281
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)	4,468	281
74	PowerProductionExpensesOtherPower TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)	3,374,763	151,772
75	OtherPowerSuplyExpensesAbstract E. Other Power Supply Expenses
76	PurchasedPower (555) Purchased Power	425,317,314	370,533,773
76.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations	0
77	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching	1,310,915	1,577,273
78	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	3,785,672	2,950,638
79	OtherPowerSupplyExpense TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)	430,413,901	375,061,684
80	PowerProductionExpenses TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74 & 79)	940,933,175	864,880,656
81	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
82	TransmissionExpensesOperationAbstract Operation
83	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	6,626,598	6,022,132
85	LoadDispatchReliability (561.1) Load Dispatch-Reliability
86	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	220,980	235,136
87	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling
88	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services	4,380,265	4,343,357
89	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development	303,852	208,996
90	TransmissionServiceStudies (561.6) Transmission Service Studies
91	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies
92	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services	1,275,988	1,233,784
93	StationExpensesTransmissionExpense (562) Station Expenses	(d) 534,639	649,124
93.1	OperationOfEnergyStorageEquipmentTransmissionExpense (562.1) Operation of Energy Storage Equipment
94	OverheadLineExpense (563) Overhead Lines Expenses	374,532	309,276
95	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses	3,244	3,182
96	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	194,809,250	151,918,388
97	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	3,361,124	3,799,819
98	RentsTransmissionElectricExpense (567) Rents	1,026,071	485,447
99	TransmissionOperationExpense TOTAL Operation (Enter Total of Lines 83 thru 98)	212,916,543	169,208,641
100	TransmissionMaintenanceAbstract Maintenance
101	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering	29,383	10,977
102	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	238,965	23,484
103	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware	(e) 15,270	12,017
104	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software	444,405	483,203
105	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment	70,960	36,208
106	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	2,872,340	1,455,788
107.1	MaintenanceOfEnergyStorageEquipmentTransmission (570.1) Maintenance of Energy Storage Equipment
108	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	16,362,132	9,693,246
109	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines	8,669	11,366
110	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant	21,519	25,206
111	TransmissionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 101 thru 110)	20,063,643	11,751,495
112	TransmissionExpenses TOTAL Transmission Expenses (Total of Lines 99 and 111)	232,980,186	180,960,136
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	4,830,186	4,203,205
122	RentsRegionalMarketExpenses (575.8) Rents
123	RegionalMarketOperationExpense Total Operation (Lines 115 thru 122)	4,830,186	4,203,205
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)	4,830,186	4,203,205
132	DistributionExpensesAbstract 4. DISTRIBUTION EXPENSES
133	DistributionExpensesOperationAbstract Operation
134	OperationSupervisionAndEngineeringDistributionExpense (580) Operation Supervision and Engineering	2,914,527	1,679,653
135	LoadDispatching (581) Load Dispatching	368,317	454,008
136	StationExpensesDistribution (582) Station Expenses	1,122,761	1,163,949
137	OverheadLineExpenses (583) Overhead Line Expenses	1,845,869	970,082
138	UndergroundLineExpenses (584) Underground Line Expenses	4,084,291	3,473,530
138.1	OperationOfEnergyStorageEquipmentDistribution (584.1) Operation of Energy Storage Equipment
139	StreetLightingAndSignalSystemExpenses (585) Street Lighting and Signal System Expenses	185,720	119,254
140	MeterExpenses (586) Meter Expenses	2,340,412	2,583,386
141	CustomerInstallationsExpenses (587) Customer Installations Expenses	248,067	354,015
142	MiscellaneousDistributionExpenses (588) Miscellaneous Expenses	10,626,921	18,649,153
143	RentsDistributionExpense (589) Rents	2,077,482	1,628,940
144	DistributionOperationExpensesElectric TOTAL Operation (Enter Total of Lines 134 thru 143)	25,814,366	31,075,970
145	DistributionExpensesMaintenanceAbstract Maintenance
146	MaintenanceSupervisionAndEngineering (590) Maintenance Supervision and Engineering	66,102	55,137
147	MaintenanceOfStructuresDistributionExpense (591) Maintenance of Structures	64,315	48,692
148	MaintenanceOfStationEquipment (592) Maintenance of Station Equipment	(f) 1,955,271	908,346
148.1	MaintenanceOfEnergyStorageEquipment (592.2) Maintenance of Energy Storage Equipment
149	MaintenanceOfOverheadLines (593) Maintenance of Overhead Lines	45,667,608	41,043,638
150	MaintenanceOfUndergroundLines (594) Maintenance of Underground Lines	1,961,672	698,897
151	MaintenanceOfLineTransformers (595) Maintenance of Line Transformers	268,535	233,498
152	MaintenanceOfStreetLightingAndSignalSystems (596) Maintenance of Street Lighting and Signal Systems	513,305	303,330
153	MaintenanceOfMeters (597) Maintenance of Meters	100,291	150,236
154	MaintenanceOfMiscellaneousDistributionPlant (598) Maintenance of Miscellaneous Distribution Plant	253,771	183,651
155	DistributionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 146 thru 154)	50,850,870	43,625,425
156	DistributionExpenses TOTAL Distribution Expenses (Total of Lines 144 and 155)	76,665,236	74,701,395
157	CustomerAccountsExpensesAbstract 5. CUSTOMER ACCOUNTS EXPENSES
158	CustomerAccountsExpensesOperationsAbstract Operation
159	SupervisionCustomerAccountExpenses (901) Supervision	865,460	1,111,598
160	MeterReadingExpenses (902) Meter Reading Expenses	969,647	828,680
161	CustomerRecordsAndCollectionExpenses (903) Customer Records and Collection Expenses	14,950,761	14,477,826
162	UncollectibleAccounts (904) Uncollectible Accounts	106,136	182,274
163	MiscellaneousCustomerAccountsExpenses (905) Miscellaneous Customer Accounts Expenses	79,628	84,534
164	CustomerAccountExpenses TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)	16,759,359	16,684,912
165	CustomerServiceAndInformationalExpensesAbstract 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166	CustomerServiceAndInformationalExpensesOperationAbstract Operation
167	SupervisionCustomerServiceAndInformationExpenses (907) Supervision	1,044,496	930,780
168	CustomerAssistanceExpenses (908) Customer Assistance Expenses	5,662,724	33,987,394
169	InformationalAndInstructionalAdvertisingExpenses (909) Informational and Instructional Expenses
170	MiscellaneousCustomerServiceAndInformationalExpenses (910) Miscellaneous Customer Service and Informational Expenses	77,580	72,868
171	CustomerServiceAndInformationExpenses TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)	6,784,801	34,991,042
172	SalesExpenseAbstract 7. SALES EXPENSES
173	SalesExpenseOperationAbstract Operation
174	SupervisionSalesExpense (911) Supervision		852
175	DemonstratingAndSellingExpenses (912) Demonstrating and Selling Expenses	256,658	433,670
176	AdvertisingExpenses (913) Advertising Expenses	265,759
177	MiscellaneousSalesExpenses (916) Miscellaneous Sales Expenses
178	SalesExpenses TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)	522,418	434,522
179	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
180	AdministrativeAndGeneralExpensesOperationAbstract Operation
181	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	42,503,580	42,601,528
182	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	3,510,368	2,450,368
183	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit	4,707,801	3,988,617
184	OutsideServicesEmployed (923) Outside Services Employed	7,706,437	6,503,145
185	PropertyInsurance (924) Property Insurance	(g) 6,038,182	8,988,528
186	InjuriesAndDamages (925) Injuries and Damages	10,459,369	9,544,343
187	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	18,528,510	18,149,825
188	FranchiseRequirements (927) Franchise Requirements
189	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	20,994,470	13,884,647
190	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.	1,082,547	1,182,382
191	GeneralAdvertisingExpenses (930.1) General Advertising Expenses	230,754	113,109
192	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	5,443,944	4,824,596
193	RentsAdministrativeAndGeneralExpense (931) Rents	3,120,314	3,486,186
194	AdministrativeAndGeneralOperationExpense TOTAL Operation (Enter Total of Lines 181 thru 193)	100,669,216	87,398,220
195	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
196	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	11,470,966	9,347,577
197	AdministrativeAndGeneralExpenses TOTAL Administrative & General Expenses (Total of Lines 194 and 196)	112,140,182	96,745,797
198	OperationsAndMaintenanceExpensesElectric TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 156, 164, 171, 178, and 197)	1,391,615,542	1,273,601,665

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

PURCHASED POWER (Account 555)
Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years. SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less. LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years. EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges. OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each adjustment. AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. Report in column (g) the megawatthours shown on bills rendered to the respondent, excluding purchases for energy storage. Report in column (h) the megawatthours shown on bills rendered to the respondent for energy storage purchases. Report in columns (i) and (j) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. Report demand charges in column (k), energy charges in column (l), and the total of any other types of charges, including out-of-period adjustments, in column (m). Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (n) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (m) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. The data in columns (g) through (n) must be totaled on the last line of the schedule. The total amount in columns (g) and (h) must be reported as Purchases on Page 401, line 10. The total amount in column (i) must be reported as Exchange Received on Page 401, line 12. The total amount in column (j) must be reported as Exchange Delivered on Page 401, line 13. Footnote entries as required and provide explanations following all required data.
					Actual Demand (MW)				POWER EXCHANGES		COST/SETTLEMENT OF POWER
Line No.	NameOfCompanyOrPublicAuthorityProvidingPurchasedPower Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	RateScheduleTariffNumber Ferc Rate Schedule or Tariff Number (c)	AverageMonthlyBillingDemand Average Monthly Billing Demand (MW) (d)	AverageMonthlyNonCoincidentPeakDemand Average Monthly NCP Demand (e)	AverageMonthlyCoincidentPeakDemand Average Monthly CP Demand (f)	MegawattHoursPurchasedOtherThanStorage MegaWatt Hours Purchased (Excluding for Energy Storage) (g)	MegawattHoursPurchasedForEnergyStorage MegaWatt Hours Purchased for Energy Storage (h)	EnergyReceivedThroughPowerExchanges MegaWatt Hours Received (i)	EnergyDeliveredThroughPowerExchanges MegaWatt Hours Delivered (j)	DemandChargesOfPurchasedPower Demand Charges ($) (k)	EnergyChargesOfPurchasedPower Energy Charges ($) (l)	OtherChargesOfPurchasedPower Other Charges ($) (m)	SettlementOfPower Total (k+l+m) of Settlement ($) (n)
1	(a) AEP GENERATING COMPANY	RQ					1,680,933				159,441,121	58,408,876		217,849,997
2	CITY OF WINCHESTER, IN	OS					0					33,666		33,666
3	FOWLER RIDGE II WIND FARM LLC	OS					101,705					9,819,049		9,819,049
4	FOWLER RIDGE WIND FARM LLC	OS					169,138					12,181,371		12,181,371
5	FRENCH PAPER	OS					291					14,252		14,252
6	FT. WAYNE ELECTRIC JATC	OS					0					10		10
7	HEADWATERS WIND FARM LLC	OS					541,471					25,224,322		25,224,322
8	ICE TRADE VAULT LLC	OS					0
9	OVEC POWER SCHEDULING	OS					790,002				30,574,154	21,600,676		52,174,830
10	(b) OVER/UNDER PJM EXP TRACKER	OS					0					28,398,030		28,398,030
11	(c) OVER/UNDER RESOURCE ADEQUACY	OS					550				5,732,076	64,209		5,667,867
12	PJM INTERCONNECTION	OS					2,124,657					119,922,485		119,922,485
13	WILDCAT WIND FARM	OS					317,169					22,163,198		22,163,198
14	WILLIAM E RICHTER	OS					0					31		31
15	TOTAL						5,725,916	0	0	0	184,283,199	241,034,115		425,317,314

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

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

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

TRANSFER OF ENERGY

REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS

Line No.

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

(m)

(n)

1

PJM Network Integ Trans Rev Whlsl

Various

FNO

(a)

PJM OATT

Various

4,686,623

2

PJM Network Integ Trans Serv

Various

FNO

PJM OATT

Various

20,048,325

3

PJM Trans Enhancement Rev

Various

FNO

PJM OATT

Various

3,794,003

4

PJM Trans Enhancement Rev Whlsle

Various

FNO

PJM OATT

Various

116,610

5

PJM Network Integ Rev - Affil

Various

FNO

PJM OATT

Various

2,516,590

6

PJM Point to Point Trans Serv

Various

LFP

PJM OATT

Various

3,613,332

7

PJM Trans Owner Admin Revenue

Various

OLF

PJM OATT

Various

5,478

8

PJM Trans Owner Serv Rev Whlsle

Various

OLF

PJM OATT

Various

24,065

9

PJM Power Factor Credits Rev Whlsle

Various

OS

PJM OATT

Various

(b)

23,263

10

PJM Trans Distribution & Meter

Various

OS

PJM OATT

Various

(c)

818,477

11

PJM Power Factor Credits Rev Nonaffiliated

Various

OS

PJM OATT

Various

(d)

393,344

12

PJM Trans Owner Admin Rev - Affil

Various

OLF

PJM OATT

Various

8,160

35

TOTAL

0

29,742,303

21,383

1,235,084

30,956,004

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

TRANSMISSION OF ELECTRICITY BY ISO/RTOs
Report in Column (a) the Transmission Owner receiving revenue for the transmission of electricity by the ISO/RTO. Use a separate line of data for each distinct type of transmission service involving the entities listed in Column (a). In Column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO – Firm Network Service for Others, FNS – Firm Network Transmission Service for Self, LFP – Long-Term Firm Point-to-Point Transmission Service, OLF – Other Long-Term Firm Transmission Service, SFP – Short-Term Firm Point-to-Point Transmission Reservation, NF – Non-Firm Transmission Service, OS – Other Transmission Service and AD- Out-of-Period Adjustments. Use this code for any accounting adjustments or “true-ups” for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes. In column (c) identify the FERC Rate Schedule or tariff Number, on separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (b) was provided. In column (d) report the revenue amounts as shown on bills or vouchers. Report in column (e) the total revenues distributed to the entity listed in column (a).
Line No.	Payment Received by (Transmission Owner Name) (a)	Statistical Classification (b)	FERC Rate Schedule or Tariff Number (c)	Total Revenue by Rate Schedule or Tariff (d)	Total Revenue (e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
40	TOTAL

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. Enter ""TOTAL"" in column (a) as the last line. Footnote entries and provide explanations following all required data.
			TRANSFER OF ENERGY		EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Line No.	NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	TransmissionOfElectricityByOthersEnergyReceived MegaWatt Hours Received (c)	TransmissionOfElectricityByOthersEnergyDelivered MegaWatt Hours Delivered (d)	DemandChargesTransmissionOfElectricityByOthers Demand Charges ($) (e)	EnergyChargesTransmissionOfElectricityByOthers Energy Charges ($) (f)	OtherChargesTransmissionOfElectricityByOthers Other Charges ($) (g)	ChargesForTransmissionOfElectricityByOthers Total Cost of Transmission ($) (h)
1	PJM Enhancements	OS					(a) 23,273,605	23,273,605
2	PJM NITS	OS					(b) 170,500,124	170,500,124
3	PJM-Trans Owner Serv	OS					(c) 1,035,521	1,035,521
	TOTAL		0	0	0	0	194,809,250	194,809,250

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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line No.	Description (a)	Amount (b)
1	IndustryAssociationDues Industry Association Dues	3,314,698
2	NuclearPowerResearchExpenses Nuclear Power Research Expenses
3	OtherExperimentalAndGeneralResearchExpenses Other Experimental and General Research Expenses	984
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	1,148,377
7	American Electric Power Service Corp Billings	925,888
8	Corporate Money Pool Allocations	67,953
9	Corporate Legal and Financing	111,520
10	Corporate Contributions and Memberships	69,234
11	Intercompany Billings	200,694
12	Minor iItems	5,984
46	MiscellaneousGeneralExpenses TOTAL	5,443,944

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

Depreciation and Amortization of Electric Plant (Account 403, 404, 405)
Report in section A for the year the amounts for: (b) Depreciation Expense (Account 403); (c) Depreciation Expense for Asset Retirement Costs (Account 403.1); (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric Plant (Account 405). Report in Section B the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to compute charges and whether any changes have been made in the basis or rates used from the preceding report year. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes to columns (c) through (g) from the complete report of the preceding year. Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount, account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant included in any sub-account used. In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the method of averaging used. For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification listed in column (a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type of mortality curve selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at the bottom of section C the amounts and nature of the provisions and the plant items to which related.
	A. Summary of Depreciation and Amortization Charges
Line No.	FunctionalClassificationAxis Functional Classification (a)	DepreciationExpenseExcludingAmortizationOfAcquisitionAdjustments Depreciation Expense (Account 403) (b)	DepreciationExpenseForAssetRetirementCostsExcludingAmortizationgOfAcquisitionAdjustments Depreciation Expense for Asset Retirement Costs (Account 403.1) (c)	AmortizationOfLimitedTermPlantOrProperty Amortization of Limited Term Electric Plant (Account 404) (d)	AmortizationOfOtherElectricPlant Amortization of Other Electric Plant (Acc 405) (e)	DepreciationAndAmortization Total (f)
1	Intangible Plant			42,310,364		42,310,364
2	Steam Production Plant	97,252,258	364,912	10,046,109		107,663,279
3	Nuclear Production Plant	142,488,388	714,490			141,773,898
4	Hydraulic Production Plant-Conventional	1,434,704	12,792			1,447,496
5	Hydraulic Production Plant-Pumped Storage
6	Other Production Plant	2,931,880				2,931,880
7	Transmission Plant	42,023,720				42,023,720
8	Distribution Plant	94,767,352				94,767,352
9	Regional Transmission and Market Operation
10	General Plant	6,155,695	20,499	682,727		6,858,921
11	Common Plant-Electric
12	TOTAL	387,053,997	316,287	53,039,201		439,776,911

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	97,794	44 years	2	7.55
14	311 - Rockport U2	4,567	33 years	2	5.05
15	311 - Rkpt DSI U1	2,905	44 years	2	7.25
16	311 - Rkpt DSI U2	772	33 years	2	10.28
17	312 - Rockport ACI	11,827	44 years	2	6.12
18	312 - Rockport U1	410,959	44 years	2	7.81
19	312 - Rockport U2	25,393	33 years	2	5.38
20	312 - Rockport U1 -SCR	133,855	44 years	2	10.31
21	312 - Rockport U2 -SCR	112,373	0 years	2	12.16
22	312 - Rkpt DSI U1	51,732	44 years	2	8.23
23	312 - Rkpt DSI U1 - Pre	24,807	44 years	2	7.81
24	312 - Rkpt DSI U2	53,932	33 years	2	10.35
25	314 - Rockport U1	107,387	44 years	2	8.16
26	314 - Rockport U2	867	33 years	2	5.44
27	315 - Rockport U1	58,991	44 years	2	7.52
28	315 - Rockport U2	2,088	33 years	2	5.17
29	316 - Rockport U1	17,652	44 years	2	7.99
30	316 - Rockport U1-SCR	8	44 years	2	11.16
31	316 - Rockport U2	6,845	33 years	2	4.94
32	TOTAL STEAM	1,124,754
33	NUCLEAR
34	321 - Cook U1	84,725	59 years	22	3.33
35	321 - Cook U2	371,999	59 years	22	3.27
36	322 - Cook U1	749,718	59 years	27	4.34
37	322 - Cook U2	989,844	59 years	27	3.82
38	323 - Cook U1	299,142	59 years	16	5.15
39	323 - Cook U2	408,614	59 years	16	4.85
40	324 - Cook U1	131,476	59 years	1	3.91
41	324 - Cook U2	188,530	59 years	1	3.68
42	325 - Cook U1	34,565	59 years		4.54
43	325 - Cook U2	236,190	59 years		3.86
44	TOTAL NUCLEAR	3,494,803
45	HYDRO
46	331 - Berrien Springs	1,982	128 years	5	2.98
47	331 - Buchanan	610	117 years	5	3.1
48	331 - Constantine	350	132 years	19	2.32

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

REGULATORY COMMISSION EXPENSES
Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts deferred in previous years. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization. List in columns (f), (g), and (h), expenses incurred during the year which were charged currently to income, plant, or other accounts. Minor items (less than $25,000) may be grouped.
						EXPENSES INCURRED DURING YEAR				AMORTIZED DURING YEAR
						CURRENTLY CHARGED TO
Line No.	RegulatoryCommissionDescription Description (Furnish name of regulatory commission or body the docket or case number and a description of the case) (a)	RegulatoryExpensesAssessedByRegulatoryCommission Assessed by Regulatory Commission (b)	RegulatoryExpensesOfUtility Expenses of Utility (c)	RegulatoryCommissionExpensesAmount Total Expenses for Current Year (d)	OtherRegulatoryAssetsRegulatoryCommissionExpenses Deferred in Account 182.3 at Beginning of Year (e)	NameOfDepartmentRegulatoryCommissionExpensesCharged Department (f)	AccountNumberRegulatoryCommissionExpensesCharged Account No. (g)	RegulatoryComissionExpensesIncurredAndCharged Amount (h)	RegulatoryCommissionExpensesDeferredToOtherRegulatoryAssets Deferred to Account 182.3 (i)	DeferredRegulatoryCommissionExpensesAmortizedInContraAccount Contra Account (j)	DeferredRegulatoryCommissionExpensesAmortized Amount (k)	OtherRegulatoryAssetsRegulatoryCommissionExpenses Deferred in Account 182.3 End of Year (l)
1	Nuclear Regulatory Commission - Inspection and Licensing Fees	1,593,234		1,593,234			928	1,593,234
2	Nuclear Regulatory Commission - Annual Fees	10,425,293		10,425,293			928	10,425,293
3	Hydro License Fee		45,207	45,207			928	45,207
4	Indiana Rate Case		3,650,232	3,650,232	1,141,808		928	2,773,648	1,018,637	928	876,584	1,283,861
5	Michigan Rate Case		421,533	421,533	521,041		928	3,145		928	418,388	102,653
6	5 Yr Dist Filing - Michigan		11,423	11,423			928	11,423
7	IN Perf Metric Collaboration		2,267	2,267			928	2,267
8	Integrated Resource Plan Filing		1,941,860	1,941,860			928	1,941,860
9	State Commission Fees		2,742,069	2,742,069			928	2,742,069
10	I&M depreciation Filing		27,007	27,007			928	27,007
11	Rockport II Lease Resolution		63,450	63,450			928	63,450
12	Minor Items < $25,000		70,895	70,895			928	70,895
46	TOTAL	12,018,527	8,975,943	20,994,470	1,662,849			19,699,498	1,018,637		1,294,972	1,386,514

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D and D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(Identify recipient regardless of affiliation.) For any R, D and D work carried with others, show separately the respondent's cost for the year and cost chargeable to others (See definition of research, development, and demonstration in Uniform System of Accounts). Indicate in column (a) the applicable classification, as shown below: Classifications: Electric R, D and D Performed Internally: Generation hydroelectric Recreation fish and wildlife Other hydroelectric Fossil-fuel steam Internal combustion or gas turbine Nuclear Unconventional generation Siting and heat rejection Transmission Overhead Underground Distribution Regional Transmission and Market Operation Environment (other than equipment) Other (Classify and include items in excess of $50,000.) Total Cost Incurred Electric, R, D and D Performed Externally: Research Support to the electrical Research Council or the Electric Power Research Institute Research Support to Edison Electric Institute Research Support to Nuclear Power Groups Research Support to Others (Classify) Total Cost Incurred Include in column (c) all R, D and D items performed internally and in column (d) those items performed outside the company costing $50,000 or more, briefly describing the specific area of R, D and D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.). Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D and D activity. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year, listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e). Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research, Development, and Demonstration Expenditures, Outstanding at the end of the year. If costs have not been segregated for R, D and D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by ""Est."" Report separately research and related testing facilities operated by the respondent.
					AMOUNTS CHARGED IN CURRENT YEAR
Line No.	ResearchDevelopmentAndDemonstrationClassification Classification (a)	ResearchDevelopmentAndDemonstrationDescription Description (b)	ResearchDevelopmentAndDemonstrationCostsIncurredInternally Costs Incurred Internally Current Year (c)	ResearchDevelopmentAndDemonstrationCostsIncurredExternally Costs Incurred Externally Current Year (d)	AccountNumberForResearchDevelopmentAndDemonstrationCosts Amounts Charged In Current Year: Account (e)	ResearchDevelopmentAndDemonstrationCosts Amounts Charged In Current Year: Amount (f)	ResearchDevelopmentAndDemonstrationExpenditures Unamortized Accumulation (g)
1	A(1)b: Generation: Fossil Fuel Steam	Generation Program Management	159,989		506,524	159,989
2		3 items < $50,000	9,109		506,517	9,109
3	A(1)e: Generation: Unconventional
4	A(2): Transmission	1 item <$50,000	9,148		566	9,148
5	A(3): Distribution	1 items <$50,000	6,585		588	6,585
6	A(5): Environment (other than equipment)	1 item <$50,000	12,496		506	12,496
7	A(6): Other	2 items <$50,000	90,306		506,524,566,588	90,306
8	A(6)a:	1 item <$50,000	23		506	23
9	A(6)f: Other: Metering	1 item <$50,000	1,287		588	1,287
10	A(6)g: Research-General	1 item <$50,000	1,398		566,588	1,398
11	A(7) TOTAL COSTS INCURRED INTERNALLY		290,341			290,341
12	B: Electric R&D External	6 items <$50,000		63,669	506,524,566,588	63,669
13	B(1): Research Support to Electric Research	EPRI Research Portfolio		516,152	506,566,588	516,152
14		EPRI Nuclear Annual Research		1,371,098	524	1,371,098
15		IT - EPRI Annual Research Port		114,885	506,524,566,588	114,885
16		31 items <$50,000		449,889	506,524,566,588	449,889
17	(B4): Steam Power	3 items <$50,000		8,479	506,566	8,479
18	B(5) TOTAL COSTS INCURRED EXTERNALLY			2,524,172		2,524,172

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

DISTRIBUTION OF SALARIES AND WAGES
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation giving substantially correct results may be used.
Line No.	Classification (a)	Direct Payroll Distribution (b)	Allocation of Payroll Charged for Clearing Accounts (c)	Total (d)
1	SalariesAndWagesElectricAbstract Electric
2	SalariesAndWagesElectricOperationAbstract Operation
3	SalariesAndWagesElectricOperationProduction Production	83,140,590
4	SalariesAndWagesElectricOperationTransmission Transmission	1,986,062
5	SalariesAndWagesElectricOperationRegionalMarket Regional Market
6	SalariesAndWagesElectricOperationDistribution Distribution	6,118,737
7	SalariesAndWagesElectricOperationCustomerAccounts Customer Accounts	2,937,174
8	SalariesAndWagesElectricOperationCustomerServiceAndInformational Customer Service and Informational	3,824,419
9	SalariesAndWagesElectricOperationSales Sales
10	SalariesAndWagesElectricOperationAdministrativeAndGeneral Administrative and General	2,962,083
11	SalariesAndWagesElectricOperation TOTAL Operation (Enter Total of lines 3 thru 10)	100,969,065
12	SalariesAndWagesElectricMaintenanceAbstract Maintenance
13	SalariesAndWagesElectricMaintenanceProduction Production	49,273,636
14	SalariesAndWagesElectricMaintenanceTransmission Transmission	2,471,220
15	SalariesAndWagesElectricMaintenanceRegionalMarket Regional Market
16	SalariesAndWagesElectricMaintenanceDistribution Distribution	11,583,587
17	SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral Administrative and General	1,752,638
18	SalariesAndWagesElectricMaintenance TOTAL Maintenance (Total of lines 13 thru 17)	65,081,081
19	SalariesAndWagesElectricOperationAndMaintenanceAbstract Total Operation and Maintenance
20	SalariesAndWagesElectricProduction Production (Enter Total of lines 3 and 13)	132,414,226
21	SalariesAndWagesElectricTransmission Transmission (Enter Total of lines 4 and 14)	4,457,282
22	SalariesAndWagesElectricRegionalMarket Regional Market (Enter Total of Lines 5 and 15)
23	SalariesAndWagesElectricDistribution Distribution (Enter Total of lines 6 and 16)	17,702,324
24	SalariesAndWagesElectricCustomerAccounts Customer Accounts (Transcribe from line 7)	2,937,174
25	SalariesAndWagesElectricCustomerServiceAndInformational Customer Service and Informational (Transcribe from line 8)	3,824,419
26	SalariesAndWagesElectricSales Sales (Transcribe from line 9)
27	SalariesAndWagesElectricAdministrativeAndGeneral Administrative and General (Enter Total of lines 10 and 17)	4,714,721
28	SalariesAndWagesElectricOperationAndMaintenance TOTAL Oper. and Maint. (Total of lines 20 thru 27)	166,050,146	7,545,475	173,595,621
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)	166,050,146	7,545,475	173,595,621
66	SalariesAndWagesUtilityPlantAbstract Utility Plant
67	SalariesAndWagesUtilityPlantConstructionAbstract Construction (By Utility Departments)
68	SalariesAndWagesUtilityPlantConstructionElectricPlant Electric Plant	50,611,243	2,299,823	52,911,066
69	SalariesAndWagesUtilityPlantConstructionGasPlant Gas Plant
70	SalariesAndWagesUtilityPlantConstructionOther Other (provide details in footnote):
71	SalariesAndWagesUtilityPlantConstruction TOTAL Construction (Total of lines 68 thru 70)	50,611,243	2,299,823	52,911,066
72	SalariesAndWagesPlantRemovalAbstract Plant Removal (By Utility Departments)
73	SalariesAndWagesPlantRemovalElectricPlant Electric Plant	8,364,005	380,068	8,744,073
74	SalariesAndWagesPlantRemovalGasPlant Gas Plant
75	SalariesAndWagesPlantRemovalOther Other (provide details in footnote):
76	SalariesAndWagesPlantRemoval TOTAL Plant Removal (Total of lines 73 thru 75)	8,364,005	380,068	8,744,073
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	435,386		435,386
80	SalariesAndWagesOtherAccountsDescription 152 - Fuel Stock Undistributed	2,377,340		2,377,340
81	SalariesAndWagesOtherAccountsDescription 163 - Stores Expense Undistributed	7,583,490	7,583,490
82	SalariesAndWagesOtherAccountsDescription 183 - Prelim Survey	27,015	27,015
83	SalariesAndWagesOtherAccountsDescription 184 - Clearing Accounts	2,614,861	2,614,861
84	SalariesAndWagesOtherAccountsDescription 185 - ODD Temporary Facilities	130,521		130,521
85	SalariesAndWagesOtherAccountsDescription 186 - Misc Deferred Debits	1,259,090		1,259,090
86	SalariesAndWagesOtherAccountsDescription 188 - Research & Development	1,420		1,420
87	SalariesAndWagesOtherAccountsDescription 228 - RAD Waste Accrual	65,993		65,993
88	SalariesAndWagesOtherAccountsDescription 417 - Misc Exp	11,393,642		11,393,642
89	SalariesAndWagesOtherAccountsDescription 426 - Political Activities	118,601		118,601
90	SalariesAndWagesOtherAccountsDescription 121 - Nonutility Property - WIP	32,878		32,878
91	SalariesAndWagesOtherAccountsDescription 154 - Materials and Supplies	7,730		7,730
92	SalariesAndWagesOtherAccountsDescription
93	SalariesAndWagesOtherAccountsDescription
94	SalariesAndWagesOtherAccountsDescription
95	SalariesAndWagesOtherAccounts TOTAL Other Accounts	26,045,127	10,225,366	15,819,761
96	SalariesAndWagesGeneralExpense TOTAL SALARIES AND WAGES	251,070,521		251,070,521

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

COMMON UTILITY PLANT AND EXPENSES
Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by accounts as provided by Electric Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated provisions, and amounts allocated to utility departments using the common utility plant to which such accumulated provisions relate, including explanation of basis of allocation and factors used. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such expenses are related. Explain the basis of allocation used and give the factors of allocation. Give date of approval by the Commission for use of the common utility plant classification and reference to the order of the Commission or other authorization.

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for Resale, for items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market for purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determining whether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively.
Line No.	Description of Item(s) (a)	Balance at End of Quarter 1 (b)	Balance at End of Quarter 2 (c)	Balance at End of Quarter 3 (d)	Balance at End of Year (e)
1	Energy
2	Net Purchases (Account 555)				72,016,475
2.1	Net Purchases (Account 555.1)
3	Net Sales (Account 447)				158,206,471
4	Transmission Rights				2,070,480
5	Ancillary Services				12,413,932
6	Other Items (list separately)
7	Congestion				25,277,633
8	Operating Reserves				2,584,639
9	Transmission Purchase Expense				44,130,318
10	Transmission Losses				15,915,021
11	Meter Correction				279,059
12	Inadvertent				74,960
13	Capacity Credits				5,888,676
46	TOTAL				10,109,252

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

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

05/19/2022

Year/Period of Report

End of:

2021

/

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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

MONTHLY TRANSMISSION SYSTEM PEAK LOAD
Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. Report on Column (b) by month the transmission system's peak load. Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the definition of each statistical classification.
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Firm Network Service for Self (e)	Firm Network Service for Others (f)	Long-Term Firm Point-to-point Reservations (g)	Other Long-Term Firm Service (h)	Short-Term Firm Point-to-point Reservation (i)	Other Service (j)
	NAME OF SYSTEM: 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:

05/19/2022

Year/Period of Report

End of:

2021

/

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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

Monthly ISO/RTO Transmission System Peak Load
Report the monthly peak load on the respondent's transmission system. If the Respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. Report on Column (b) by month the transmission system's peak load. Report on Column (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). Report on Columns (e) through (i) by month the system’s transmission usage by classification. Amounts reported as Through and Out Service in Column (g) are to be excluded from those amounts reported in Columns (e) and (f). Amounts reported in Column (j) for Total Usage is the sum of Columns (h) and (i).
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Import into ISO/RTO (e)	Exports from ISO/RTO (f)	Through and Out Service (g)	Network Service Usage (h)	Point-to-Point Service Usage (i)	Total Usage (j)
	NAME OF SYSTEM: 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:

2022-05-19

Year/Period of Report

End of:

2021

/

Q4

ELECTRIC ENERGY ACCOUNT
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
Line No.	Item (a)	MegaWatt Hours (b)	Line No.	Item (a)	MegaWatt Hours (b)
1	SOURCES OF ENERGY		21	DISPOSITION OF ENERGY
2	Generation (Excluding Station Use):		22	Sales to Ultimate Consumers (Including Interdepartmental Sales)	17,494,044
3	Steam	2,401,332	23	Requirements Sales for Resale (See instruction 4, page 311.)	2,912,995
4	Nuclear	17,956,272	24	Non-Requirements Sales for Resale (See instruction 4, page 311.)	4,423,364
5	Hydro-Conventional	83,953	25	Energy Furnished Without Charge	48
6	Hydro-Pumped Storage		26	Energy Used by the Company (Electric Dept Only, Excluding Station Use)
7	Other	48,547	27	Total Energy Losses	1,385,569
8	Less Energy for Pumping		27.1	Total Energy Stored
9	Net Generation (Enter Total of lines 3 through 8)	20,490,104	28	TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL LINE 20 UNDER SOURCES	26,216,020
10	Purchases (other than for Energy Storage)	5,725,916
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)	26,216,020

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

MONTHLY PEAKS AND OUTPUT
Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required information for each non- integrated system. Report in column (b) by month the system’s output in Megawatt hours for each month. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
Line No.	MonthAxis Month (a)	EnergyActivity Total Monthly Energy (b)	NonRequiredSalesForResaleEnergy Monthly Non-Requirement Sales for Resale & Associated Losses (c)	MonthlyPeakLoad Monthly Peak - Megawatts (d)	DayOfMonthlyPeak Monthly Peak - Day of Month (e)	HourOfMonthlyPeak Monthly Peak - Hour (f)
	NAME OF SYSTEM: 0
29	January	2,054,178	128,075	3,136	29	8
30	February	2,678,003	883,989	3,367	17	8
31	March	2,143,544	369,298	3,094	15	16
32	April	1,781,652	189,748	2,821	1	10
33	May	1,897,847	191,213	3,380	25	15
34	June	2,463,282	566,821	3,708	29	15
35	July	2,324,355	358,391	3,717	28	17
36	August	2,584,436	513,090	4,012	24	15
37	September	2,014,357	242,169	3,642	14	15
38	October	1,893,955	225,878	2,949	11	14
39	November	1,942,415	197,181	3,027	23	8
40	December	2,437,996	671,014	3,078	7	19
41	Total	26,216,020	4,536,867

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

Steam Electric Generating Plant Statistics

1. Report data for plant in Service only.
2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants.
3. Indicate by a footnote any plant leased or operated as a joint facility.
4. If net peak demand for 60 minutes is not available, give data which is available, specifying period.
5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant.
6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.
7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.
8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
9. Items under Cost of Plant are based on USofA accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses.
10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants.
11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.
12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant.

Line No.	Item (a)	Plant Name: 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)	2,305	1,306	2,612	663	653
7	PlantHoursConnectedToLoad Plant Hours Connected to Load	8,668	5,037	5,037	3,745	3,209
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	175	0	0
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh	17,956,272,000	2,401,332,000	4,802,664	1,319,228,000	1,082,104,000
13	CostOfLandAndLandRightsSteamProduction Cost of Plant: Land and Land Rights	1,879,588	6,545,276	13,061,227	6,477,506	67,770
14	CostOfStructuresAndImprovementsSteamProduction Structures and Improvements	456,149,623	107,472,210	216,689,049	99,466,884	8,005,326
15	CostOfEquipmentSteamProduction Equipment Costs	3,040,415,586	1,119,761,884	2,234,686,481	809,276,398	310,485,486
16	AssetRetirementCostsSteamProduction Asset Retirement Costs	799,433,426	11,249,431	22,475,591	5,624,715	5,624,715
17	CostOfPlant Total cost (total 13 thru 20)	4,297,878,223	1,245,028,801	2,486,912,348	920,845,503	324,183,297
18	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 17/5) Including	1,880.9095	950.4037	949.2032	1,395.2205	498.7435
19	OperationSupervisionAndEngineeringExpense Production Expenses: Oper, Supv, & Engr	18,443,251	3,965,910	7,870,057	2,042,236	1,923,673
20	FuelSteamPowerGeneration Fuel	87,999,744	83,441,345	166,882,597	44,728,641	38,712,704
21	CoolantsAndWater Coolants and Water (Nuclear Plants Only)	6,989,349
22	SteamExpensesSteamPowerGeneration Steam Expenses	14,959,261	13,397,833	24,960,582	7,057,485	6,340,348
23	SteamFromOtherSources Steam From Other Sources	0
24	SteamTransferredCredit Steam Transferred (Cr)	0
25	ElectricExpensesSteamPowerGeneration Electric Expenses	5,868,035	1,378,594	2,291,506	731,118	647,476
26	MiscellaneousSteamPowerExpenses Misc Steam (or Nuclear) Power Expenses	76,770,615	4,175,676	7,314,373	2,109,490	2,066,186
27	RentsSteamPowerGeneration Rents	0	68,627,284	135,381,966		68,627,284
28	Allowances Allowances	0	161,666	161,666	80,833	80,833
29	MaintenanceSupervisionAndEngineeringSteamPowerGeneration Maintenance Supervision and Engineering	5,803,732	2,291,659	4,583,338	1,147,429	1,144,230
30	MaintenanceOfStructuresSteamPowerGeneration Maintenance of Structures	5,982,218	706,315	1,412,637	537,196	169,119
31	MaintenanceOfBoilerPlantSteamPowerGeneration Maintenance of Boiler (or reactor) Plant	65,392,131	7,782,304	15,564,673	5,920,370	1,861,934
32	MaintenanceOfElectricPlantSteamPowerGeneration Maintenance of Electric Plant	17,051,621	2,948,926	5,837,976	2,223,581	725,345
33	MaintenanceOfMiscellaneousSteamPlant Maintenance of Misc Steam (or Nuclear) Plant	16,885,982	1,135,393	2,270,799	815,886	319,507
34	PowerProductionExpensesSteamPower Total Production Expenses	322,145,940	190,012,905	374,532,170	67,394,265	122,618,639
35	ExpensesPerNetKilowattHour Expenses per Net kWh	0.0179	0.0791	77.9843	0.0511	0.1133

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		Mcf	bbl	Mcf	bbl
38	QuantityOfFuelBurned Quantity (Units) of Fuel Burned		1,511,818	39,922	3,023,635	79,845
39	FuelBurnedAverageHeatContent Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)		8,448	136,410	8,448	136,410
40	AverageCostOfFuelPerUnitAsDelivered Avg Cost of Fuel/unit, as Delvd f.o.b. during year		56.000	85.000	56.000	85.000
41	AverageCostOfFuelPerUnitBurned Average Cost of Fuel per Unit Burned		53.000	72.000	53.000	72.000
42	AverageCostOfFuelBurnedPerMillionBritishThermalUnit Average Cost of Fuel Burned per Million BTU	0.458	2.788	13	2.784	13.000
43	AverageCostOfFuelBurnedPerKilowattHourNetGeneration Average Cost of Fuel Burned per kWh Net Gen	0.005	0.029		0.029
44	AverageBritishThermalUnitPerKilowattHourNetGeneration Average BTU per kWh Net Generation	10,680	10,043		10,043

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

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. 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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

Hydroelectric Generating Plant Statistics

Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings).
If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. If licensed project, give project number.
If net peak demand for 60 minutes is not available, give that which is available specifying period.
If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each plant.
The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.

Line No.	Item (a)	FERC Licensed Project No. 0 Plant Name: 0
1	PlantKind Kind of Plant (Run-of-River or Storage)
2	PlantConstructionType Plant Construction type (Conventional or Outdoor)
3	YearPlantOriginallyConstructed Year Originally Constructed
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed
5	InstalledCapacityOfPlant Total installed cap (Gen name plate Rating in MW)
6	NetPeakDemandOnPlant Net Peak Demand on Plant-Megawatts (60 minutes)
7	PlantHoursConnectedToLoad Plant Hours Connect to Load
8	NetPlantCapabilityAbstract Net Plant Capability (in megawatts)
9	NetPlantCapabilityUnderMostFavorableOperatingConditions (a) Under Most Favorable Oper Conditions
10	NetPlantCapabilityUnderMostAdverseOperatingConditions (b) Under the Most Adverse Oper Conditions
11	PlantAverageNumberOfEmployees Average Number of Employees
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh
13	CostOfPlantAbstract Cost of Plant
14	CostOfLandAndLandRightsHydroelectricProduction Land and Land Rights
15	CostOfStructuresAndImprovementsHydroelectricProduction Structures and Improvements
16	CostOfReservoirsDamsAndWaterwaysHydroelectricProduction Reservoirs, Dams, and Waterways
17	EquipmentCostsHydroelectricProduction Equipment Costs
18	CostOfRoadsRailroadsAndBridgesHydroelectricProduction Roads, Railroads, and Bridges
19	AssetRetirementCostsHydroelectricProduction Asset Retirement Costs
20	CostOfPlant Total cost (total 13 thru 20)
21	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 20 / 5)
22	ProductionExpensesAbstract Production Expenses
23	OperationSupervisionAndEngineeringExpense Operation Supervision and Engineering
24	WaterForPower Water for Power
25	HydraulicExpenses Hydraulic Expenses
26	ElectricExpensesHydraulicPowerGeneration Electric Expenses
27	MiscellaneousHydraulicPowerGenerationExpenses Misc Hydraulic Power Generation Expenses
28	RentsHydraulicPowerGeneration Rents
29	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration Maintenance Supervision and Engineering
30	MaintenanceOfStructuresHydraulicPowerGeneration Maintenance of Structures
31	MaintenanceOfReservoirsDamsAndWaterways Maintenance of Reservoirs, Dams, and Waterways
32	MaintenanceOfElectricPlantHydraulicPowerGeneration Maintenance of Electric Plant
33	MaintenanceOfMiscellaneousHydraulicPlant Maintenance of Misc Hydraulic Plant
34	PowerProductionExpensesHydraulicPower Total Production Expenses (total 23 thru 33)
35	ExpensesPerNetKilowattHour Expenses per net kWh

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

Pumped Storage Generating Plant Statistics
Large plants and pumped storage plants of 10,000 Kw or more of installed capacity (name plate ratings). If any plant is leased, operating under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. Give project number. If net peak demand for 60 minutes is not available, give that which is available, specifying period. If a group of employees attends more than one generating plant, report on Line 8 the approximate average number of employees assignable to each plant. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power System Control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses." Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes. Include on Line 36 the cost of energy used in pumping into the storage reservoir. When this item cannot be accurately computed leave Lines 36, 37 and 38 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of energy from each station or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses per net MWH as reported herein for each source described. Group together stations and other resources which individually provide less than 10 percent of total pumping energy. If contracts are made with others to purchase power for pumping, give the supplier contract number, and date of contract.
Line No.	Item (a)	FERC Licensed Project No. 0 Plant Name: 0
1	PlantConstructionType Type of Plant Construction (Conventional or Outdoor)
2	YearPlantOriginallyConstructed Year Originally Constructed
3	YearLastUnitOfPlantInstalled Year Last Unit was Installed
4	InstalledCapacityOfPlant Total installed cap (Gen name plate Rating in MW)
5	NetPeakDemandOnPlant Net Peak Demaind on Plant-Megawatts (60 minutes)	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:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

GENERATING PLANT STATISTICS (Small Plants)
Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped storage plants of less than 10,000 Kw installed capacity (name plate rating). Designate any plant leased from others, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project, give project number in footnote. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11, Page 402. If net peak demand for 60 minutes is not available, give the which is available, specifying period. If any plant is equipped with combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
									Production Expenses
Line No.	PlantName Name of Plant (a)	YearPlantOriginallyConstructed Year Orig. Const. (b)	InstalledCapacityOfPlant Installed Capacity Name Plate Rating (MW) (c)	NetPeakDemandOnPlant Net Peak Demand MW (60 min) (d)	NetGenerationExcludingPlantUse Net Generation Excluding Plant Use (e)	CostOfPlant Cost of Plant (f)	PlantCostPerMw Plant Cost (Incl Asset Retire. Costs) Per MW (g)	OperatingExpensesExcludingFuel Operation Exc'l. Fuel (h)	FuelProductionExpenses Fuel Production Expenses (i)	MaintenanceProductionExpenses Maintenance Production Expenses (j)	FuelKind Kind of Fuel (k)	FuelCostPerMmbtus Fuel Costs (in cents (per Million Btu) (l)	GenerationType Generation Type (m)
1	Hydro electric
2	Berrien Springs	1908	7.20	4.9	29,562	16,766,619	2,328,697	312,919		113,884
3	Buchanan	1919	4.10	2.6	15,490	8,052,820	1,964,102	216,934		132,728
4	Constantine	1921	1.20	0.9	4,831	3,284,473	2,737,061	77,061		152,309
5	Elkhart	1913	3.30	2.4	2,750	9,861,709	2,988,397	218,017		161,143
6	Mottville	1923	1.60	1.3	6,444	4,754,514	2,971,571	173,431		452,566
7	Twin Branch	1904	7.20	3.6	24,876	14,474,198	2,010,305	399,090		503,853
8	Solar electric
9	Deer Creek	2015	2.50	2.7	3,471	6,411,700	2,564,680	56,295		322
10	Olive	2016	5.00	5.5	8,267	12,062,064	2,412,413	191,886		644
11	St. Joseph	2020	20.00	21.4	27,221	37,369,642	1,868,482	263,662		2,575
12	Twin Branch Solar	2016	2.60	3.6	3,971	6,958,803	2,676,463	340,077		335
13	Watervliet	2016	4.60	4.7	5,617	11,969,137	2,601,986	94,175		592

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

ENERGY STORAGE OPERATIONS (Large Plants)
Large Plants are plants of 10,000 Kw or more. In columns (a) (b) and (c) report the name of the energy storage project, functional classification (Production, Transmission, Distribution), and location. In column (d), report Megawatt hours (MWH) purchased, generated, or received in exchange transactions for storage. In columns (e), (f) and (g) report MWHs delivered to the grid to support production, transmission and distribution. The amount reported in column (d) should include MWHs delivered/provided to a generator’s own load requirements or used for the provision of ancillary services. In columns (h), (i), and (j) report MWHs lost during conversion, storage and discharge of energy. In column (k) report the MWHs sold. In column (l), report revenues from energy storage operations. In a footnote, disclose the revenue accounts and revenue amounts related to the income generating activity. In column (m), report the cost of power purchased for storage operations and reported in Account 555.1, Power Purchased for Storage Operations. If power was purchased from an affiliated seller specify how the cost of the power was determined. In columns (n) and (o), report fuel costs for storage operations associated with self-generated power included in Account 501 and other costs associated with self-generated power. In columns (q), (r) and (s) report the total project plant costs including but not exclusive of land and land rights, structures and improvements, energy storage equipment, turbines, compressors, generators, switching and conversion equipment, lines and equipment whose primary purpose is to integrate or tie energy storage assets into the power grid, and any other costs associated with the energy storage project included in the property accounts listed.
Line No.	Name of the Energy Storage Project (a)	Functional Classification (b)	Location of the Project (c)	MWHs (d)	MWHs delivered to the grid to support Production (e)	MWHs delivered to the grid to support Transmission (f)	MWHs delivered to the grid to support Distribution (g)	MWHs Lost During Conversion, Storage and Discharge of Energy Production (h)	MWHs Lost During Conversion, Storage and Discharge of Energy Transmission (i)	MWHs Lost During Conversion, Storage and Discharge of Energy Distribution (j)	MWHs Sold (k)	Revenues from Energy Storage Operations (l)	Power Purchased for Storage Operations (555.1) (Dollars) (m)	Fuel Costs from associated fuel accounts for Storage Operations Associated with Self- Generated Power (Dollars) (n)	Other Costs Associated with Self-Generated Power (Dollars) (o)	Project Costs included in (p)	Production (Dollars) (q)	Transmission (Dollars) (r)	Distribution (Dollars) (s)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

TRANSMISSION LINE STATISTICS
Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage. If required by a State commission to report individual lines for all voltages, do so but do not group totals for each voltage under 132 kilovolts. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report substation costs and expenses on this page. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder of the line. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with respect to such structures are included in the expenses reported for the line designated. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g). Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company, give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is an associated company. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how determined. Specify whether lessee is an associated company. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
	DESIGNATION		VOLTAGE (KV) - (Indicate where other than 60 cycle, 3 phase)			LENGTH (Pole miles) - (In the case of underground lines report circuit miles)				COST OF LINE (Include in column (j) Land, Land rights, and clearing right-of-way)			EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line No.	TransmissionLineStartPoint From	TransmissionLineEndPoint To	OperatingVoltageOfTransmissionLine Operating	DesignedVoltageOfTransmissionLine Designated	SupportingStructureOfTransmissionLineType Type of Supporting Structure	LengthForStandAloneTransmissionLines On Structure of Line Designated	LengthForTransmissionLinesAggregatedWithOtherStructures On Structures of Another Line	NumberOfTransmissionCircuits Number of Circuits	SizeOfConductorAndMaterial Size of Conductor and Material	CostOfLandAndLandRightsTransmissionLines Land	ConstructionAndOtherCostsTransmissionLines Construction Costs	OverallCostOfTransmissionLine Total Costs	OperatingExpensesOfTransmissionLine Operation Expenses	MaintenanceExpensesOfTransmissionLine Maintenance Expenses	RentExpensesOfTransmissionLine Rents	OverallExpensesOfTransmissionLine Total Expenses
	(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)	(l)	(m)	(n)	(o)	(p)
1	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	92.22	0	2	1414 KCM
15	0677 BREED	DEQUINE EAST	345.00	345.00	1	0.18	0	2	1414 KCM
16	0677 BREED	DEQUINE EAST	345.00	345.00	1	3.77	0	2	2303 KCM
17	0677 BREED	DEQUINE EAST	345.00	345.00	1	0.08	0	2	2-2303 KCM
18	0678 DEQUINE	OLIVE	345.00	345.00	3	13.31	0	2	2303 KCM
19	0678 DEQUINE	OLIVE	345.00	345.00	3	54.19	0	2	1,414KCM
20	0678 DEQUINE	OLIVE	345.00	345.00	1	0.50	0	2	2156 KCM
21	0678 DEQUINE	OLIVE	345.00	345.00	1	0.14	0	2	2,303 KCM
22	0678 DEQUINE	OLIVE	345.00	345.00	1	0.45	0	2	2-954 KCM
23	0679 SORENSON	OLIVE	345.00	345.00	3	77.90	0	1	1272 KCM
24	0679 SORENSON	OLIVE	345.00	345.00	1	0.10	0	1	1272 KCM
25	0680 OLIVE	GOODINGS GROVE	345.00	345.00	3	41.00	0	2	1414 KCM
26	0683 DESOTO	JCT TOWER (MAR. CO)	345.00	345.00	3	53.00	6	1	2-954 KCM
27	0684 TANNERS CREEK	JUNCTION TOWER	345.00	345.00	3	79.98	0	1	2-954 KCM
28	0684 TANNERS CREEK	JUNCTION TOWER	345.00	345.00	2	0.02	0	1	2-954 KCM
29	0685 HANNA	JUNCTION TOWER	345.00	345.00	3	5.63	0	0	2-954 KCM
30	0687 TANNERS CREEK	MIAMI FORT	345.00	345.00	3	0.28	0	2	2-954 KCM
31	0688 EUGENE	SIDNEY	345.00	345.00	1	0.20	0	1	1414 KCM
32	0689 SORENSON-OLIVE	TWIN BRANCH	345.00	345.00	3	11.00	0	2	1563 KCM
33	0690 BREED	CIPSCO	345.00	345.00	3	0.94	0	1	2-1024 KCM
34	0690 BREED	CIPSCO	345.00	345.00	3	0.02	0	1	2-1351.5 KCM
35	0691 BREED	PETERSBURG	345.00	345.00	3	0.70	0	1	2-954 KCM
36	0691 BREED	PETERSBURG	345.00	345.00	1	0.15	0	1	2-1351.5 KCM
37	0731 Varner	South Butler	345.00	345.00	1	0.60	0	1	2-954 KCM
38	0734 Dunton Lake Extension		345.00	345.00	3	0.25	0	2	2-954 KCM
39	6118 ROBISON PARK	SORENSON-EAST LIMA	345.00	345.00	3	22.66	0	2	1414 KCM
40	6118 ROBISON PARK	SORENSON-EAST LIMA	345.00	345.00	1	0.34	0	1	1414 KCM
41	6119 COOK	OLIVE	345.00	345.00	3	4.00	0	2	2-954 KCM
42	6122 DUMONT	OLIVE	345.00	345.00	3	14.52	0	2	2-954 KCM
43	6122 DUMONT	OLIVE	345.00	345.00	1	0.60	0	1	2-954 KCM
44	6123 DUMONT	TWIN BRANCH	345.00	345.00	3	17.00	0	2	2-954 KCM
45	6125 ROBISON PARK	EAST	345.00	345.00		0.00	0	0
46	6133 DUMONT	BABCOCK	345.00	345.00	3	9.00	0	1	2-954 KCM
47	6145 TWIN BRANCH	COOK-ROB PARK JCT	345.00	345.00	3	6.00	0	2	2-954 KCM
48	6147 COOK	ROBISON PARK	345.00	345.00	3	67.41	0	2	2-954 KCM
49	6147 COOK	ROBISON PARK	345.00	345.00	1	0.41	0	0	2-954 KCM
50	6148 JACKSON ROAD	SORENSON-OLIVE	345.00	345.00	3	4.00	0	2	2303 KCM
51	6213 COOK-ROB-PARK JCT	ARGENTA	345.00	345.00	3	2.00	0	2	2-954 KCM
52	6237 JACKSON ROAD	WEST	345.00	345.00		0.00	0	0
53	6240 TWIN BRANCH	SUBSTATION CORRIDOR	345.00	345.00		0.00	0	0
54	6256 BREED	SULLIVAN	345.00	345.00	3	0.48	0	2	1351.5 KCM
55	6256 BREED	SULLIVAN	345.00	345.00	3	0.75	0	1	1351.5 KCM
56	6256 BREED	SULLIVAN	345.00	345.00	1	0.29	0	1	1351.5 KCM
57	6259 COLLINGWOOD	SOUTH BUTLER	345.00	345.00	1	14.65	0	1	2-954 KCM
58	6232 GODMAN TAP		34.00	138.00		0.00	0	0
59	0604 TWIN BRANCH	ROBISON PARK	138.00	138.00	3	8.50	0	2	397.5 KCM
60	0604 TWIN BRANCH	ROBISON PARK	138.00	138.00	1	0.28	0	2	1233.6 KCM
61	0605 SOUTH BEND	MICHIGAN CITY	138.00	138.00	3	0.00	0	1	397.5 KCM
62	0606 ROBISON PARK	HAVILAND	138.00	138.00	3	12.01	0	2	397.5 KCM
63	0606 ROBISON PARK	HAVILAND	138.00	138.00	1	0.05	0	0	1233.6 KCM
64	0607 ROBISON PARK	DEER CREEK	138.00	138.00	1	0.12	0	2	1590 KCM
65	0607 ROBISON PARK	DEER CREEK	69.00	138.00	1	0.00	1	1	1033.5 KCM
66	0608 DEER CREEK	KOKOMO	138.00	138.00	3	1.56	0	1	336.4 KCM
67	0608 DEER CREEK	KOKOMO	138.00	138.00	3	5.96	0	1	636 KCM
68	0608 DEER CREEK	KOKOMO	138.00	138.00	1	0.17	0	1	336.4 KCM
69	0609 CONCORD TAP		138.00	138.00	3	4.00	0	2	397.5 KCM
70	0613 TWIN BRANCH	JACKSON ROAD	138.00	138.00	3	8.00	0	2	447 KCM
71	0614 LINCOLN TAP		138.00	138.00	3	4.00	0	2	397.5 KCM
72	0615 TWIN BRANCH	ROBISON PARK	138.00	138.00	3	65.83	0	1	477 KCM
73	0616 DEER CREEK	DELAWARE	138.00	138.00	3	2.40	0	2	397.5 KCM
74	0618 DELAWARE	COLLEGE CORNER	138.00	138.00	3	49.31	0	2	397.5 KCM
75	0618 DELAWARE	COLLEGE CORNER	138.00	138.00	4	0.84	0	2	2,000KCM
76	0618 DELAWARE	COLLEGE CORNER	138.00	138.00	2	0.11	0	2	397.5 KCM
77	0618 DELAWARE	COLLEGE CORNER	138.00	138.00	1	0.45	0	2	397.5 KCM
78	0618 DELAWARE	COLLEGE CORNER	138.00	138.00	2	1.02	0	1	795 KCM
79	0619 MADISON	NEW CASTLE	138.00	138.00	3	6.00	1	1	795 KCM
80	0620 TANNERS CREEK	MADISON	138.00	138.00	3	82.00	0	2	636 KCM
81	0622 JACKSON ROAD	OLIVE	138.00	138.00	3	16.29	1	1	556.5 KCM
82	0622 JACKSON ROAD	OLIVE	138.00	138.00	1	0.47	0	1	556.5 KCM
83	0623 MADISON	PENDLETON	138.00	138.00	2	5.00	0	1	477 KCM
84	0624 DRAGOON TAP		138.00	138.00	3	2.00	0	1	795 KCM
85	0625 TANNERS CREEK	COLLEGE CORNER	138.00	138.00	3	51.90	0	2	636 KCM
86	0625 TANNERS CREEK	COLLEGE CORNER	138.00	138.00	1	0.37	0	2	636 KCM
87	0626 COLLEGE CORNER	RANDOLPH	138.00	138.00	2	34.58	0	1	556.5 KCM
88	0626 COLLEGE CORNER	RANDOLPH	138.00	138.00	1	1.07	0	1	556.5 KCM
89	0626 COLLEGE CORNER	RANDOLPH	138.00	138.00	2	3.34	0	0	556.5 KCM
90	0627 RANDOLPH	JAY	138.00	138.00	2	23.69	0	1	556.5 KCM
91	0627 RANDOLPH	JAY	138.00	138.00	1	0.32	0	0	556.5 KCM
92	0628 MCKINLEY TAP		138.00	138.00	3	0.85	0	2	300 KCM CU
93	0628 MCKINLEY TAP		138.00	138.00	1	0.15	0	2	300 KCM CU
94	0629 JAY	LINCOLN	138.00	138.00	2	46.18	0	1	556.5 KCM
95	0629 JAY	LINCOLN	138.00	138.00	3	3.11	0	1	1033.5 KCM
96	0630 NEW CARLISLE	MAPLE	138.00	138.00	2	1.00	0	1	397.5 KCM
97	6104 SORENSON	TWIN BRANCH	138.00	138.00	3	61.17	0	1	447 KCM
98	6104 SORENSON	TWIN BRANCH	138.00	138.00	1	0.31	0	1	556.5 KCM
99	6104 SORENSON	TWIN BRANCH	138.00	138.00	1	3.32	0	1	556.5 KCM
100	0632 SORENSON	DEVILS HOLLOW	138.00	138.00	3	0.00	0	0	556.5 KCM
101	0634 DEER CREEK	MULLIN	138.00	138.00	2	15.70	0	1	556.5 KCM
102	0635 PENDLETON	MULLIN	138.00	138.00	2	14.10	0	1	556.5 KCM
103	0635 PENDLETON	MULLIN	138.00	138.00	3	0.40	0	1	556.5 KCM
104	0635 PENDLETON	MULLIN	138.00	138.00	1	0.72	0	1	556.5 KCM
105	0636 DEER CREEK	FISHER BODY	138.00	138.00	3	5.04	0	2	397.5 KCM
106	0637 TWIN BRANCH	EAST ELKHART	138.00	138.00	3	17.00	1	2	556.5 KCM
107	0638 GRANT	FISHER BODY	138.00	138.00	3	0.00	1	1	397.5 KCM
108	0639 ROBISON PARK	AUBURN	138.00	138.00	1	0.00	0	1	556.5 KCM
109	0641 DESOTO	MEDFORD	138.00	138.00	1	0.15	0	2	795 KCM
110	0641 DESOTO	MEDFORD	138.00	138.00	3	6.86	0	2	556.5 KCM
111	0642 OLIVE	HICKORY CREEK	138.00	138.00	3	2.99	2	1	556.5 KCM
112	0645 COREY TAP		138.00	138.00	2	4.00	0	1	477 KCM
113	0646 OLIVE	NEW CARLISLE	138.00	138.00	3	2.00	0	1	556.5 KCM
114	0647 OLIVE	SOUTH BEND	138.00	138.00	3	15.97	0	2	397.5 KCM
115	0648 MEDFORD TAP		138.00	138.00	1	0.13	0	2	556.5 KCM
116	0648 MEDFORD TAP		138.00	138.00	3	7.94	0	2	556.5 KCM
117	0723 SPY RUN STATION		138.00	138.00	4	0.00	0	1	3.5IN OD
118	0730 Varner	Wilmington	138.00	138.00	1	0.83	0	1	795 KCM
119	6101 WESTINGHOUSE TAP		138.00	138.00	3	2.00	0	2	556.5 KCM
120	6102 MILAN TAP		138.00	138.00	3	6.00	0	2	397.5 KCM
121	6103 MILAN	GOODRICH	138.00	138.00	3	1.00	0	2	397.5 KCM
122	6105 DESOTO	JAY	138.00	138.00	2	10.31	0	1	2-556.5 KCM
123	6105 DESOTO	JAY	138.00	138.00	3	2.25	0	1	2-556.5 KCM
124	6106 DESOTO	DEER CREEK-DELAWARE	138.00	138.00	3	7.31	0	2	636 KCM
125	6106 DESOTO	DEER CREEK-DELAWARE	138.00	138.00	1	1.10	0	0	636 KCM
126	6107 DARDEN TAP		138.00	138.00	2	0.94	0	1	336.4 KCM
127	6109 ROBISON PARK	RICHLAND	138.00	138.00	2	13.76	0	1	636 KCM
128	6109 ROBISON PARK	RICHLAND	138.00	138.00	1	0.05	0	0	1233.6 KCM
129	6109 ROBISON PARK	RICHLAND	138.00	138.00	3	4.49	0	0	636 KCM
130	6110 WESTINGHOUSE	23RD STREET	138.00	138.00	3	0.00	0	2	556.5 KCM
131	6111 KANKAKEE	WEST SIDE	138.00	138.00	1	2.00	0	1	636 KCM
132	6113 INDUSTRIAL PARK		138.00	138.00	3	3.00	0	2	745 KCM
133	6114 OLIVE	MICHIGAN CITY	138.00	138.00	3	1.94	1	1	636 KCM
134	6115 HUMMEL CREEK	VAN BUREN	138.00	138.00	3	6.00	0	2	795 KCM
135	6130 HUMMEL CREEK	TOWER 70, GREENTOWN	138.00	138.00		0.00	0	0
136	6116 SOUTH ELWOOD TAP		138.00	138.00	1	3.07	0	1	556.5 KCM
137	6117 PENDLETON	FALL CREEK	138.00	138.00	3	10.70	0	2	795 KCM
138	6117 PENDLETON	FALL CREEK	138.00	138.00	1	0.07	0	2	795 KCM
139	6121 ROBISON PARK	LINCOLN	138.00	138.00	3	7.84	0	1	795 KCM
140	6121 ROBISON PARK	LINCOLN	138.00	138.00	1	0.02	0	0	1233.6 KCM
141	6126 CONCORD	EAST ELKHART	138.00	138.00	3	11.00	0	1	795 KCM
142	6129 GREENTOWN-GRANT	HUMMEL CREEK	138.00	138.00	3	21.00	0	1	795 KCM
143	6131 INDUSTRIAL PARK	MC KINLEY	138.00	138.00	1	5.00	0	1	795 KCM
144	6132 CROSS STREET TAP	JUNCTION TOWER #88	138.00	138.00	1	4.00	0	1	795 KCM
145	6134 LINCOLN	ANTHONY	138.00	138.00	1	3.00	0	1	795 KCM
146	6135 WAYNEDALE TAP		138.00	138.00	3	0.00	0	2	795 KCM
147	6138 JACKSON ROAD	SOUTH SIDE	138.00	138.00	1	2.00	0	1	795 KCM
148	6142 ALBION	KENDALLVILLE	138.00	138.00	3	10.00	0	1	795 KCM
149	6150 SOUTHSIDE	SOUTH BEND	138.00	138.00	1	6.07	0	1	795 KCM
150	6219 DELCO BATTERY TAP		138.00	138.00	1	1.00	0	2	795 KCM AA
151	6220 FALL CREEK	MADISON-NEW CASTLE	138.00	138.00	3	1.10	0	2	795 KCM
152	6220 FALL CREEK	MADISON-NEW CASTLE	138.00	138.00	1	0.15	0	2	795 KCM
153	6225 INDUSTRIAL PARK	SPY RUN	138.00	138.00	1	4.00	0	1	1033 KCM
154	6266 WALLEN		138.00	138.00	1	0.22	0	1	1033.5 KCM
155	6234 CABOT TAP/CR 4	EAST ELKHART	138.00	138.00	1	0.13	0	1	556.5 KCM
156	6238 SORENSON	MCKINLEYTOWER	138.00	138.00	3	2.82	0	2	795 KCM
157	6238 SORENSON	MCKINLEYTOWER	138.00	138.00	1	0.26	0	2	795 KCM
158	6241 KENDALLVILLE TAP	CITY OF AUBURN #5	138.00	138.00	1	14.00	0	1	795 KCM
159	6241 KENDALLVILLE TAP	CITY OF AUBURN #5	138.00	138.00	2	14.00	0	1	795 KCM
160	6242 AUBURN	CITY OF AUBURN #5	138.00	138.00	1	2.00	0	1	795 KCM
161	6245 LAPORTE JCT	LIQUID CARBONICS	138.00	138.00	1	4.76	0	1	795 KCM
162	6245 LAPORTE JCT	LIQUID CARBONICS	138.00	138.00	1	0.23	0	0	1033.5 KCM
163	6246 LAPORTE JCT	AIRCO	138.00	138.00	1	0.72	0	1	795 KCM
164	6248 ELCONA TAP	CONC-DUN-E-ELK	138.00	138.00	1	2.00	0	1	795 KCM
165	6249 ALLEN	LINCOLN	138.00	138.00	3	4.90	0	2	1033 KCM
166	6249 ALLEN	LINCOLN	138.00	138.00	1	0.09	0	2	1233.6 KCM
167	6250 ALLEN	ADAMS/HILLCREST	138.00	138.00	3	4.92	0	2	1033 KCM
168	6250 ALLEN	ADAMS/HILLCREST	138.00	138.00	1	0.07	0	2	1233.6 KCM
169	6251 OLIVE	EDISON	138.00	138.00	3	1.00	0	2	795 KCM
170	6253 TRIER RD TAP		138.00	138.00	1	0.00	0	1	795 KCM
171	6258 KENZIE CREEK	TWIN BRANCH	138.00	138.00	3	0.00	0	2	1033 KCM
172	6260 WILMINGTON TAP		138.00	138.00	1	0.20	9	1	2-954 KCM
173	6229 DUNLAP NORTH TAP		34.00	138.00	1	2.00	0	2	795 KCM
174	6140 INDIANA-PURDUE		34.00	138.00	1	0.00	0	2	1033 KCM
175	6217 HILLCREST	KINNERK	69.00	138.00	1	3.92	0	1	795 KCM
176	6217 HILLCREST	KINNERK	69.00	138.00	2	0.03	0	1	795 KCM
177	6252 KENDALLVILLE	BIXLER	138.00	138.00	1	2.91	0	1	795 KCM
178	6254 ALLEN/LINCOLN	ALLEN/HILLCREST	138.00	138.00		0.00	0	0
179	6265 CONCORD	WOLF	138.00	138.00	1	0.77	0	1	336.4 KCM
180	6271 INDALEX TAP/CR 4	EAST ELKHART	138.00	138.00	1	1.09	0	1	556.5 KCM
181	6267 STUDEBAKER	WEST SIDE	138.00	138.00	1	2.57	0	1	954 KCM
182	6270 JONES CREEK	HOGAN	138.00	138.00		5.47	0	1	795 KCM
183	6273 DAWKINS SWITCH	HERBERT MONROE (WVPA)	138.00	138.00	1	0.50	0	1	4/0
184	LINES<132 KV	SYSTEM	69.00	0.00	Various	634.38	72	1	VARIOUS
185	STATE OF MICHIGAN	STATE OF MICHIGAN	0.00	0.00		0.00	0	0
186	6216 D.C. COOK	DUMONT	765.00	765.00	3	16.00	0	1	4-954 KCM
187	6120 COOK	PALISADES	345.00	345.00	3	41.78	0	2	2-954 KCM
188	6120 COOK	PALISADES	345.00	345.00	1	0.23	0	0	2-954 KCM
189	6120 COOK	PALISADES	345.00	345.00	1	0.21	0	0	2-1158.4 KCM
190	6143 D.C. COOK	OLIVE-PALISADES	345.00	345.00	3	5.00	0	2	2-954 KCM
191	6144 TWIN BRANCH	COOK-ROB PARK JCT	345.00	345.00	3	0.00	0	2	2-954 KCM
192	6151 COOK	OLIVE	345.00	345.00		0.00	0	0
193	6152 COOK	ROBISON PARK	345.00	345.00		0.00	0	0
194	6146 D.C. COOK	ROBISON PARK	345.00	345.00	3	36.80	0	2	2-954 KCM
195	6146 D.C. COOK	ROBISON PARK	345.00	345.00	3	0.09	0	0	954 KCM
196	6214 COOK-ROB PARK	ARGENTA	345.00	345.00	3	28.78	0	2	2-954 KCM
197	6214 COOK-ROB PARK	ARGENTA	345.00	345.00	1	0.22	0	2	2-954 KCM
198	6221 D.C. COOK	OLIVE-PALISADES	345.00	345.00	3	5.00	0	2	2-954 KCM
199	6263 BARODA TAP		138.00	138.00		0.00	0	0
200	0601 TWIN BRANCH	RIVERSIDE	138.00	138.00	3	5.80	0	2	397.5KCM & 1033.5
201	0601 TWIN BRANCH	RIVERSIDE	138.00	138.00	1	0.10	0	2	397.5KCM & 1033.5
202	0610 AUTO SPECIALTIES		138.00	138.00		0.00	0	0
203	0621 TWIN BRANCH - R	HICKORY CREEK	138.00	138.00	3	5.00	0	2	397.5 KCM
204	0643 OLIVE	HICKORY CREEK	138.00	138.00	3	23.10	2	1	556.5 KCM
205	0644 RIVERSIDE	HARTFORD	138.00	138.00	2	14.22	0	1	397.5 KCM
206	0644 RIVERSIDE	HARTFORD	138.00	138.00	3	2.11	0	0	397.5 KCM
207	0649 COREY TAP		138.00	138.00	2	12.12	0	1	477 KCM
208	0649 COREY TAP		138.00	138.00	1	0.13	0	1	477 KCM
209	6150 SOUTHSIDE	SOUTH BEND	138.00	138.00	1	6.23	0	1	795 KCM
210	6108 RIVERSIDE	OLIVE-HICKORY CREEK	138.00	138.00	1	6.00	0	1	636 KCM
211	6124 BENTON HARBOR	RIVERSIDE-HARTFORD	138.00	138.00	3	1.00	0	2	795 KCM
212	6137 EDGEWATER TAP		138.00	138.00	1	0.76	0	1	556.5 KCM
213	6139 BENTON HARBOR	TWIN BRANCH-R SIDE	138.00	138.00	3	6.00	0	2	795 KCM
214	6149 HARTFORD	COREY	138.00	138.00	1	18.97	0	1	795 KCM
215	6149 HARTFORD	COREY	138.00	138.00		0.00	2	1	795 KCM
216	6149 HARTFORD	COREY	138.00	138.00	2	12.88	0	1	795 KCM
217	6149 HARTFORD	COREY	138.00	138.00		0.00	1	1	1033.5 KCM
218	6149 HARTFORD	COREY	138.00	138.00	1	1.34	0	1	1033.5 KCM
219	6149 HARTFORD	COREY	138.00	138.00	1	0.53	0	2	1033.5 KCM
220	6218 MOTTVILLE TAP		138.00	138.00	1	1.00	0	1	795 KCM
221	6219 DELCO BATTERY TAP		138.00	138.00	1	0.50	0	2	795 KCM
222	6219 DELCO BATTERY TAP		138.00	138.00	1	0.15	0	1	795 KCM
223	6255 KENZIE CREEK	VALLEY	138.00	138.00	1	20.00	0	1	1033 KCM
224	6257 KENZIE CREEK	T B/R'SIDE/HICK CR	138.00	138.00	3	0.00	0	0	795 KCM
225	6261 FLATBUSH TAP		138.00	138.00		1.00	0	1
226	6262 WEST ST TAP		138.00	138.00		1.00	0	2
227	6700 GM HYDRAMATIC		138.00	138.00	3	2.00	0	2	795 KCM
228	6227 NICKERSON	TOWER #13A	138.00	138.00		0.00	0	0
229	6268 SAUK TRAIL		138.00	138.00	1	1.60	0	0	1033.5KCM 45/7ACR
230	LESS THAN 132 KV LINES		69.00	0.00	Various	375.90	12	0	VARIOUS
231	Line cost and expense are	not available by individual								75,055,178	769,051,023	844,106,201	377,776	16,370,801		16,748,577
232	transmission line.	Total shown in column j-p
36	TOTAL					3,474	112	285		75,055,178	769,051,023	844,106,201	377,776	16,370,801	0	16,748,577

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

TRANSMISSION LINES ADDED DURING YEAR
Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report minor revisions of lines. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m). If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase, indicate such other characteristic.
	LINE DESIGNATION			SUPPORTING STRUCTURE		CIRCUITS PER STRUCTURE		CONDUCTORS				LINE COST
Line No.	TransmissionLineStartPoint From	TransmissionLineEndPoint To	LengthOfTransmissionLineAdded Line Length in Miles	SupportingStructureOfTransmissionLineType Type	AverageNumberOfSupportingStructuresOfTransmissionLinePerMiles Average Number per Miles	NumberOfTransmissionCircuitsPerStructurePresent Present	NumberOfTransmissionCircuitsPerStructureUltimate Ultimate	ConductorSize Size	ConductorSpecification Specification	ConductorConfigurationAndSpacing Configuration and Spacing	OperatingVoltageOfTransmissionLine Voltage KV (Operating)	CostOfLandAndLandRightsTransmissionLinesAdded Land and Land Rights	CostOfPolesTowersAndFixturesTransmissionLinesAdded Poles, Towers and Fixtures	CostOfConductorsAndDevicesTransmissionLinesAdded Conductors and Devices	Asset Retire. Costs	CostOfTransmissionLinesAdded Total	SupportingStructureConstructionType Construction
	(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)	(l)	(m)	(n)	(o)	(p)	(q)
1	0734 Dunton Lake Extension		0.25	3	3	2	2	2-954 KCM	ACSR		345.00	10,100	1,571,004	195,442		1,776,546
2	0731 Varner	South Butler	0.60	1	1	1	1	2-954 KCM	ACSR		345.00		1,831,462	179,928		2,011,389
3	0730 Varner	Wilmington	0.83	1	1	1	1	795 KCM	ACSR		138.00		933,306	509,475		1,442,781
44	TOTAL		2		5	4	4					10,100	4,335,772	884,844		5,230,716

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

SUBSTATIONS
Report below the information called for concerning substations of the respondent as of the end of the year. Substations which serve only one industrial or street railway customer should not be listed below. Substations with capacities of Less than 10 MVA except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f). Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
		Character of Substation		VOLTAGE (In MVa)						Conversion Apparatus and Special Equipment
Line No.	SubstationNameAndLocation Name and Location of Substation (a)	SubstationCharacterDescription Transmission or Distribution (b)	SubstationCharacterAttendedOrUnattended Attended or Unattended (b-1)	PrimaryVoltageLevel Primary Voltage (In MVa) (c)	SecondaryVoltageLevel Secondary Voltage (In MVa) (d)	TertiaryVoltageLevel Tertiary Voltage (In MVa) (e)	SubstationInServiceCapacity Capacity of Substation (In Service) (In MVa) (f)	NumberOfTransformersInService Number of Transformers In Service (g)	Number of Spare Transformers (h)	ConversionApparatusAndSpecialEquipmentType Type of Equipment (i)	NumberOfConversionApparatusAndSpecialEquipmentUnits Number of Units (j)	CapacityOfConversionApparatusAndSpecialEquipment Total Capacity (In MVa) (k)
1	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		138.00	69.00	12.00	90.00	1			0	0.00
5	ALBION - IN	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.40
6	ALBION - IN	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	52.79
7	ALBION - IN	Transmission		69.00	12.00		8.40	1			0	0.00
8	ALLEN (IM) - IN	Transmission		345.00	137.50	13.80	450.00	1			0	0.00
9	ALMENA - MI	Transmission		69.00	34.50		30.00	1			0	0.00
10	ALMENA - MI	Transmission		69.00	12.00		7.00	1			0	0.00
11	AM GENERAL #1 - IN	Distribution		34.50	4.00		7.17	2			0	0.00
12	ANACONDA - IN	Distribution		34.50	4.00		3.75	1			0	0.00
13	ANCHOR HOCKING (IM) - IN	Distribution		69.00	13.09		20.00	1			0	0.00
14	ANCHOR HOCKING (IM) - IN	Distribution		69.00	2.40		13.75	2			0	0.00
15	ANTHONY - IN	Transmission		34.50	12.00		29.38	2			0	0.00
16	ANTHONY - IN	Transmission		138.00	34.00		112.00	1			0	0.00
17	ANTIVILLE - IN	Distribution		69.00	12.00		3.65	1			0	0.00
18	ARMSTRONG CORK - IN	Distribution		69.00	4.00		19.88	2			0	0.00
19	ARNOLD HOGAN - IN	Transmission		138.00	34.50		75.00	1			0	0.00
20	AUBURN - IN	Transmission		138.00	70.50	36.20	130.00	1			0	0.00
21	AUBURN - IN	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	105.59
22	BANGOR - MI	Distribution		69.00	12.00		6.25	1			0	0.00
23	BARLEY - IN	Distribution		34.50	13.00		2.00	1			0	0.00
24	BARODA - MI	Distribution		138.00	13.09		20.00	1			0	0.00
25	BEECH ROAD - IN	Distribution		138.00	13.09		20.00	1			0	0.00
26	BENTON HARBOR - MI	Transmission		345.00	137.50	13.14	224.00	0	1		0	0.00
27	BENTON HARBOR - MI	Transmission		345.00	137.50	13.80	3600.00	8			0	0.00
28	BENTON HARBOR WATERWORKS - MI	Distribution		34.50	2.40		0.67	0	1		0	0.00
29	BENTON HARBOR WATERWORKS - MI	Distribution		34.50	13.00		1.00	3			0	0.00
30	BERNE - IN	Distribution		69.00	12.00		20.00	1			0	0.00
31	BERNE - IN	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	16.20
32	BERRIEN SP HYDR STAT - MI	Transmission		34.50	13.00		5.00	1			0	0.00
33	BERRIEN SP HYDR STAT - MI	Transmission		34.50	12.00		5.00	1			0	0.00
34	BERRIEN SP HYDR STAT - MI	Transmission		34.50	0.00	0.00	0.00			STATCAP	1	9.60
35	BIG RUN - IN	Transmission		69.00	0.48		2.50	1			0	0.00
36	BIXLER - IN	Distribution		138.00	13.09		20.00	1			0	0.00
37	BLAINE STREET - IN	Distribution		34.50	13.00		29.38	2			0	0.00
38	BLUFF POINT - IN	Transmission		69.00	13.00		5.60	1			0	0.00
39	BLUFF POINT - IN	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	16.20
40	BLUFFTON (IM) - IN	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	16.20
41	BOSMAN - IN	Distribution		34.50	13.00		9.38	1			0	0.00
42	BRIDGMAN - MI	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.40
43	BRIDGMAN - MI	Distribution		69.00	12.00		18.90	2			0	0.00
44	BUCHANAN HYDRO STA - MI	Transmission		69.00	12.00		7.50	1			0	0.00
45	BUCHANAN HYDRO STA - MI	Transmission		69.00	34.00		20.00	1			0	0.00
46	BUCHANAN SOUTH - MI	Distribution		69.00	12.00		22.40	1			0	0.00
47	BUTLER (IM) - IN	Distribution		69.00	0.00	0.00	0.00			STATCAP	2	30.00
48	BUTLER (IM) - IN	Distribution		69.00	13.00		20.00	1			0	0.00
49	CALVERT - IN	Distribution		138.00	13.09		20.00	1			0	0.00
50	CAMERON - MI	Distribution		69.00	34.00		7.50	1			0	0.00
51	CAPITAL AVENUE - IN	Transmission		138.00	13.09		12.00	1			0	0.00
52	CARROLL - IN	Distribution		34.50	13.00		1.50	3			0	0.00
53	CHURUBUSCO - IN	Distribution		34.50	13.00		10.50	1			0	0.00
54	CLEVELAND - IN	Distribution		138.00	13.09		20.00	1			0	0.00
55	CLIPPER - IN	Distribution		69.00	13.09		6.25	1			0	0.00
56	COLBY - MI	Transmission		138.00	69.00	34.50	75.00	1			0	0.00
57	COLBY - MI	Transmission		34.50	0.00	0.00	0.00			STATCAP	1	12.00
58	COLBY - MI	Transmission		138.00	13.09		8.40	1			0	0.00
59	COLBY - MI	Transmission		69.00	34.50		20.00	1			0	0.00
60	COLFAX - IN	Distribution		34.50	12.00		22.40	1			0	0.00
61	COLONY BAY - IN	Distribution		69.00	12.00		20.00	1			0	0.00
62	COLONY BAY - IN	Distribution		69.00	13.00		22.40	1			0	0.00
63	COLUMBIA (IM) - IN	Transmission		138.00	69.00	34.00	50.00	1			0	0.00
64	CONANT - IN	Distribution		34.50	12.00		22.40	1			0	0.00
65	CONCORD - IN	Transmission		138.00	70.50	36.20	130.00	1			0	0.00
66	CONCORD - IN	Transmission		138.00	13.09		22.40	1			0	0.00
67	CONCORD - IN	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	57.60
68	COREY - MI	Transmission		138.00	69.00	34.50	130.00	1			0	0.00
69	COREY - MI	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.40
70	COUNTRYSIDE - IN	Distribution		138.00	12.47		20.00	1			0	0.00
71	COUNTY LINE (IM) - IN	Distribution		138.00	13.09		20.00	1			0	0.00
72	COUNTY ROAD 4 - IN	Distribution		138.00	13.09		20.00	1			0	0.00
73	COVERT - MI	Distribution		69.00	13.00		9.38	1			0	0.00
74	CROSS STREET - IN	Distribution		138.00	13.09		20.00	1			0	0.00
75	CRYSTAL - MI	Distribution		138.00	13.09		22.40	1			0	0.00
76	DALEVILLE - IN	Distribution		138.00	13.09		20.00	1			0	0.00
77	DARDEN ROAD - IN	Distribution		138.00	13.09		42.40	2			0	0.00
78	DC COOK 69/12 - MI	Transmission		69.00	0.00	0.00	0.00			STATCAP	1
79	DC COOK 69/12 - MI	Transmission		69.00	13.00		1.50	1			0	0.00
80	DECATUR (FTW) - IN	Transmission		69.00	13.00		20.00	1			0	0.00
81	DECATUR (FTW) - IN	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	13.19
82	DEER CREEK - IN	Transmission		34.50	0.00	0.00	0.00			STATCAP	2	29.70
83	DEER CREEK - IN	Transmission		138.00	69.00	34.00	90.00	1			0	0.00
84	DEER CREEK - IN	Transmission		34.50	13.09		3.75	1			0	0.00
85	DEER CREEK - IN	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	57.60
86	DEER CREEK - IN	Transmission		138.00	13.09		20.00	1			0	0.00
87	DEER CREEK - IN	Transmission		138.00	34.50		75.00	1			0	0.00
88	DELAWARE (IM) - IN	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	52.79
89	DELAWARE (IM) - IN	Transmission		34.50	0.00	0.00	0.00			STATCAP	1	4.80
90	DELAWARE (IM) - IN	Transmission		138.00	34.00		125.00	2			0	0.00
91	DESOTO - IN	Transmission		345.00	138.00	34.50	675.00	1			0	0.00
92	DIEBOLD ROAD - IN	Distribution		69.00	13.00		20.00	1			0	0.00
93	DOOVILLE - IN	Distribution		138.00	13.09		12.00	1			0	0.00
94	DRAGOON - IN	Transmission		138.00	69.00	34.00	84.00	1			0	0.00
95	DREWRYS - IN	Distribution		34.50	13.09		7.50	1			0	0.00
96	DREWRYS - IN	Distribution		34.50	12.00		7.50	1			0	0.00
97	DUMONT - IN	Transmission		765.00						REACTOR	2	200.00
98	DUNLAP - IN	Transmission		138.00	13.09		20.00	1			0	0.00
99	EAST ELKHART - IN	Transmission		345.00	137.50	13.80	450.00	1			0	0.00
100	EAST SIDE (IM) - IN	Distribution		138.00	13.09		37.40	2			0	0.00
101	EAST WATERVLIET - MI	Distribution		138.00	13.09		20.00	1			0	0.00
102	EGE - IN	Distribution		138.00	34.50	13.00	7.50	1			0	0.00
103	ELCONA - IN	Distribution		138.00	13.09		22.40	1			0	0.00
104	ELLISON ROAD - IN	Transmission		138.00	13.09		20.00	1			0	0.00
105	ELMRIDGE - IN	Distribution		34.50	13.00		9.38	1			0	0.00
106	ELWOOD (IM) - IN	Distribution		34.50	0.00	0.00	0.00			STATCAP	1	5.40
107	ELWOOD (IM) - IN	Distribution		34.50	13.00		18.75	2			0	0.00
108	FAIRMOUNT - IN	Distribution		34.50	7.20		10.50	1			0	0.00
109	FARMLAND - IN	Distribution		69.00	13.09		20.00	1			0	0.00
110	FERGUSON - IN	Distribution		69.00	13.00		20.00	1			0	0.00
111	FISHER BODY - IN	Distribution		138.00	13.80		100.00	2			0	0.00
112	FLORENCE ROAD - MI	Distribution		69.00	12.00		20.00	1			0	0.00
113	FLORENCE ROAD - MI	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	9.60
114	FULTON (IM) - IN	Distribution		34.50	13.00		20.00	1			0	0.00
115	GAS CITY - IN	Distribution		34.50	0.00	0.00	0.00			STATCAP	1	9.60
116	GAS CITY - IN	Distribution		34.50	13.00		20.00	1			0	0.00
117	GASTON - IN	Distribution		138.00	13.09		20.00	1			0	0.00
118	GATEWAY (IM) - IN	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	13.19
119	GATEWAY (IM) - IN	Transmission		69.00	34.00		20.00	1			0	0.00
120	GERMAN - IN	Distribution		138.00	13.09		47.40	2			0	0.00
121	GLENBROOK - IN	Distribution		34.50	13.00		40.00	2			0	0.00
122	GRABILL - IN	Distribution		138.00	13.09		20.00	1			0	0.00
123	GRANGER - IN	Distribution		138.00	13.09		20.00	1			0	0.00
124	GRANGER - IN	Distribution		138.00	12.47		20.00	1			0	0.00
125	GRANT - IN	Transmission		138.00	34.50		30.00	1			0	0.00
126	GRANT - IN	Transmission		138.00	13.09		20.00	1			0	0.00
127	GREENLEAF - IN	Distribution		34.50	13.09		20.00	1			0	0.00
128	HACIENDA - IN	Distribution		138.00	13.09		45.00	2			0	0.00
129	HADLEY - IN	Distribution		69.00	13.00		40.00	2			0	0.00
130	HAGAR - MI	Distribution		69.00	12.00		10.50	1			0	0.00
131	HAMILTON - IN	Distribution		69.00	12.00		21.00	2			0	0.00
132	HAMILTON - IN	Distribution		69.00	13.00		21.00	2			0	0.00
133	HARLAN - IN	Distribution		69.00	13.09		12.50	1			0	0.00
134	HARPER - IN	Distribution		138.00	13.09		20.00	1			0	0.00
135	HARTFORD - MI	Transmission		138.00	70.50	36.20	54.00	1			0	0.00
136	HARTFORD CITY - IN	Transmission		69.00	13.00		20.00	1			0	0.00
137	HARVEST PARK - IN	Distribution		34.50	13.00		20.00	1			0	0.00
138	HAYMOND - IN	Distribution		34.50	13.00		24.00	2			0	0.00
139	HICKORY CREEK - MI	Transmission		138.00	69.00	34.50	75.00	1			0	0.00
140	HILLCREST - IN	Transmission		138.00	13.09		22.40	1			0	0.00
141	HILLCREST - IN	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	52.79
142	HUMMEL CREEK - IN	Transmission		138.00	13.09		20.00	1			0	0.00
143	HUMMEL CREEK - IN	Transmission		138.00	69.00	34.00	75.00	1			0	0.00
144	ILLINOIS ROAD - IN	Transmission		138.00	13.09		20.00	1			0	0.00
145	ILLINOIS ROAD - IN	Transmission		138.00	69.00	13.00	84.00	1			0	0.00
146	INDUSTRIAL PARK - IN	Transmission		138.00	69.00	34.00	75.00	1			0	0.00
147	INDUSTRIAL PARK - IN	Transmission		34.50	13.00		22.40	1			0	0.00
148	INDUSTRIAL PARK - IN	Transmission		138.00	13.09		22.40	1			0	0.00
149	INDUSTRIAL PARK - IN	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	50.40
150	IRELAND ROAD - IN	Distribution		138.00	13.09		20.00	1			0	0.00
151	IU PURDUE - IN	Distribution		13.80	4.00		5.00	1			0	0.00
152	JACKSON ROAD - IN	Transmission		138.00	13.09		32.00	2			0	0.00
153	JAY (IM) - IN	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	57.60
154	JAY (IM) - IN	Transmission		138.00	69.00	34.00	115.00	1			0	0.00
155	JAY (IM) - IN	Transmission		138.00	13.09		9.38	1			0	0.00
156	JEFFERSON (IM) - IN	Transmission		765.00						REACTOR	4	400.00
157	JOBES - IN	Distribution		34.50	4.00		9.38	1			0	0.00
158	JONES CREEK - IN	Distribution		138.00	12.47		20.00	1			0	0.00
159	KANKAKEE - IN	Transmission		138.00	13.09		22.40	1			0	0.00
160	KANKAKEE - IN	Transmission		138.00	70.50	36.20	130.00	1			0	0.00
161	KENDALLVILLE - IN	Transmission		69.00	12.00		10.50	1			0	0.00
162	KENDALLVILLE - IN	Transmission		69.00	13.00		7.50	1			0	0.00
163	KENDALLVILLE - IN	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	43.20
164	KENDALLVILLE - IN	Transmission		138.00	69.00	13.00	75.00	1			0	0.00
165	KENZIE CREEK - MI	Transmission		345.00	137.50	13.80	450.00	1			0	0.00
166	KINGSLAND - IN	Distribution		69.00	13.00		4.69	1			0	0.00
167	KLINE - IN	Transmission		138.00	34.00		100.00	1			0	0.00
168	LAKE STREET - MI	Transmission		69.00	34.00		40.00	1			0	0.00
169	LAKE STREET - MI	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.40
170	LAKESIDE (MBH) - MI	Distribution		69.00	12.00		9.38	1			0	0.00
171	LAKESIDE (MBH) - MI	Distribution		69.00	13.09		9.38	1			0	0.00
172	LANGLEY (IM) - MI	Distribution		34.50	138.00	13.80		1			0	0.00
173	LANTERN PARK - IN	Distribution		138.00	13.09		20.00	1			0	0.00
174	LIGONIER - IN	Distribution		138.00	13.09		29.38	2			0	0.00
175	LINCOLN - IN	Transmission		138.00	13.09		20.00	1			0	0.00
176	LINCOLN - IN	Transmission		138.00	36.20		75.00	1			0	0.00
177	LINCOLN - IN	Transmission		138.00	70.50	36.20	200.00	1			0	0.00
178	LINWOOD (IM) - IN	Distribution		138.00	13.09		10.50	1			0	0.00
179	LOBDELL - IN	Distribution		69.00	0.48		2.80	1			0	0.00
180	LYNN - IN	Distribution		69.00	13.00		7.00	1			0	0.00
181	MAGLEY - IN	Transmission		69.00	13.00		9.38	1			0	0.00
182	MAGLEY - IN	Transmission		138.00	69.00	13.00	90.00	1			0	0.00
183	MAIN STREET - MI	Transmission		138.00	34.00		30.00	1			0	0.00
184	MAIN STREET - MI	Transmission		138.00	13.09		22.40	1			0	0.00
185	MARION ETHANOL - IN	Distribution		34.50	4.00		10.50	1			0	0.00
186	MARION PLANT - IN	Distribution		34.50	0.00	0.00	0.00			STATCAP	1	8.75
187	MARION PLANT - IN	Distribution		34.50	4.00		6.00	1			0	0.00
188	MARION PLANT - IN	Distribution		34.50	13.00		22.40	1			0	0.00
189	MAYFIELD - IN	Distribution		138.00	13.09		20.00	1			0	0.00
190	MCCLURE - IN	Distribution		34.50	4.00		7.50	1			0	0.00
191	MCGALLIARD ROAD - IN	Distribution		34.50	13.09		25.00	1			0	0.00
192	MCKINLEY - IN	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	21.60
193	MCKINLEY - IN	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	86.40
194	MCKINLEY - IN	Transmission		138.00	70.50	36.20	130.00	1			0	0.00
195	MCKINLEY - IN	Transmission		138.00	34.00		112.00	1			0	0.00
196	MCKINLEY - IN	Transmission		138.00	13.09		40.00	2			0	0.00
197	MEADOW LAKE SW - IN	Transmission		345.00	0.00	0.00	0.00			STATCAP	2
198	MEADOWBROOK - IN	Transmission		138.00	35.00		100.00	1			0	0.00
199	MIER - IN	Distribution		138.00	13.09		10.50	1			0	0.00
200	MILLER AVENUE - IN	Distribution		34.50	4.00		8.00	1			0	0.00
201	MISSISSINEWA - IN	Distribution		138.00	13.09		12.00	1			0	0.00
202	MODOC - IN	Transmission		138.00	69.00	13.00	60.00	1			0	0.00
203	MODOC - IN	Transmission		69.00	13.00		5.00	1			0	0.00
204	MONROE (IM) - IN	Distribution		69.00	13.00		7.50	1			0	0.00
205	MOORE PARK - MI	Transmission		138.00	69.00	34.50	90.00	1			0	0.00
206	MOORE PARK - MI	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	16.20
207	MOORE PARK - MI	Transmission		138.00	13.09		20.00	1			0	0.00
208	MURCH - MI	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	13.20
209	MURCH - MI	Distribution		69.00	12.00		20.00	1			0	0.00
210	MURRAY - IN	Distribution		69.00	13.00		5.00	1			0	0.00
211	NEW BUFFALO - MI	Distribution		69.00	12.00		30.50	2			0	0.00
212	NILES - MI	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.39
213	NILES - MI	Transmission		69.00	34.00		44.80	1			0	0.00
214	NILES - MI	Transmission		69.00	13.09		20.00	1			0	0.00
215	NORTH KENDALLVILLE - IN	Distribution		69.00	12.00		22.40	1			0	0.00
216	NORTHLAND - IN	Distribution		138.00	13.09		32.00	2			0	0.00
217	OLIVE - IN	Transmission		345.00	138.00	34.50	675.00	1			0	0.00
218	OLIVE - IN	Transmission		138.00	13.09		9.38	1			0	0.00
219	OSOLO - IN	Transmission		138.00	13.09		20.00	1			0	0.00
220	OSSIAN - IN	Distribution		69.00	13.00		20.00	1			0	0.00
221	PARKWAY - IN	Distribution		34.50	13.00		4.69	1			0	0.00
222	PARNELL - IN	Distribution		34.50	13.09		20.00	1			0	0.00
223	PARNELL - IN	Distribution		34.50	13.00		20.00	1			0	0.00
224	PEACOCK - IN	Distribution		34.50	13.00		4.70	1			0	0.00
225	PEARL STREET - MI	Distribution		34.50	12.00		16.88	2			0	0.00
226	PENDLETON - IN	Transmission		138.00	35.00		75.00	1			0	0.00
227	PENNVILLE - IN	Distribution		138.00	34.00	13.00	7.50	1			0	0.00
228	PHILIPS - IN	Distribution		69.00	0.48		2.50	1			0	0.00
229	PIGEON RIVER - MI	Distribution		69.00	12.00		20.00	1			0	0.00
230	PINE ROAD - IN	Distribution		138.00	13.09		20.00	1			0	0.00
231	PIPE CREEK - IN	Distribution		138.00	12.00		20.00	1			0	0.00
232	PLEASANT - IN	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	13.19
233	PLEASANT - IN	Distribution		69.00	13.00		5.00	1			0	0.00
234	POKAGON(MBH) - MI	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.39
235	POKAGON(MBH) - MI	Transmission		138.00	69.00	13.00	115.00	1			0	0.00
236	POKAGON(MBH) - MI	Transmission		69.00	13.00		5.00	1			0	0.00
237	PORTLAND (IM) - IN	Distribution		69.00	13.00		16.80	2			0	0.00
238	PRICE - IN	Distribution		69.00	13.09		20.00	1			0	0.00
239	RANDOLPH - IN	Transmission		138.00	69.00	13.00	56.00	1			0	0.00
240	RANDOLPH - IN	Transmission		34.50	12.00		3.75	1			0	0.00
241	RANDOLPH - IN	Transmission		138.00	13.09		22.40	1			0	0.00
242	RANDOLPH - IN	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	13.50
243	REED - IN	Distribution		138.00	13.09		22.40	1			0	0.00
244	RICKERMAN ROAD - MI	Distribution		138.00	13.09		7.50	1			0	0.00
245	RIVERSIDE (IM) - MI	Transmission		138.00	13.09		20.00	1			0	0.00
246	RIVERSIDE (IM) - MI	Transmission		138.00	69.00	34.00	84.00	1			0	0.00
247	RIVERSIDE (IM) - MI	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	52.80
248	ROBISON PARK - IN	Transmission		138.00	70.50	36.20	90.00	1			0	0.00
249	ROBISON PARK - IN	Transmission		138.00	13.09		20.00	1			0	0.00
250	ROBISON PARK - IN	Transmission		138.00	13.09		25.00	1			0	0.00
251	ROCKPORT - IN	Transmission		34.50	13.00		1.50	2			0	0.00
252	ROSE HILL - IN	Distribution		138.00	13.00		7.50	1			0	0.00
253	ROYERTON - IN	Distribution		138.00	13.09		10.50	1			0	0.00
254	SATURN - IN	Transmission		138.00	13.09		12.50	1			0	0.00
255	SAUK TRAIL - MI	Distribution		138.00	13.09		20.00	1			0	0.00
256	SCOTTDALE - MI	Distribution		34.50	13.09		9.38	1			0	0.00
257	SELMA PARKER - IN	Transmission		138.00	13.09		20.00	1			0	0.00
258	SHARON ROAD - IN	Distribution		34.50	13.00		2.50	3			0	0.00
259	SISTER LAKES - MI	Distribution		34.50	12.00		15.04	2			0	0.00
260	SODUS - MI	Distribution		138.00	13.09		10.50	1			0	0.00
261	SORENSON - IN	Transmission		765.00	345.00	34.50		0	1		0	0.00
262	SORENSON - IN	Transmission		345.00	138.00	34.00	675.00	1			0	0.00
263	SORENSON - IN	Transmission		345.00	138.00	34.50	675.00	1			0	0.00
264	SORENSON - IN	Transmission		138.00	13.09		9.38	1			0	0.00
265	SOUTH BEND - IN	Transmission		138.00	69.00	34.00	130.00	1			0	0.00
266	SOUTH BEND - IN	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	52.79
267	SOUTH BEND - IN	Transmission		138.00	13.09		20.00	1			0	0.00
268	SOUTH BERNE - IN	Distribution		69.00	12.00		12.00	1			0	0.00
269	SOUTH DECATUR - IN	Distribution		69.00	13.09		20.00	1			0	0.00
270	SOUTH DECATUR - IN	Distribution		69.00	13.00		20.00	1			0	0.00
271	SOUTH ELWOOD - IN	Transmission		138.00	13.09		20.00	1			0	0.00
272	SOUTH ELWOOD - IN	Transmission		138.00	34.00		30.00	1			0	0.00
273	SOUTH SIDE (MARION) - IN	Distribution		34.50	13.09		20.00	1			0	0.00
274	SOUTH SIDE (SOUTH BEND) - IN	Distribution		138.00	13.09		20.00	1			0	0.00
275	SOUTH SUMMITVILLE - IN	Transmission		34.50	13.09		20.00	1			0	0.00
276	SOYA - IN	Distribution		34.50	4.00		10.50	1			0	0.00
277	SPRING STREET - IN	Distribution		34.50	12.00		12.00	1			0	0.00
278	SPRING STREET - IN	Distribution		34.50	13.00		7.50	1			0	0.00
279	SPY RUN SF6 - IN	Transmission		138.00	13.09		22.40	1			0	0.00
280	SPY RUN SF6 - IN	Transmission		138.00	34.00		200.00	2			0	0.00
281	ST MARYS COLLEGE - IN	Distribution		34.50	4.33		8.00	1			0	0.00
282	ST. JOE - IN	Distribution		69.00	13.09		20.00	1			0	0.00
283	STATE STREET - IN	Distribution		138.00	13.09		25.00	1			0	0.00
284	STEVENSVILLE - MI	Distribution		69.00	13.09		12.50	1			0	0.00
285	STEVENSVILLE - MI	Distribution		69.00	13.00		8.40	1			0	0.00
286	STONE LAKE - MI	Distribution		69.00	13.00		7.00	1			0	0.00
287	STONE LAKE - MI	Distribution		69.00	12.00		9.38	1			0	0.00
288	STUBEY ROAD - MI	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.40
289	STUBEY ROAD - MI	Distribution		69.00	12.00		10.50	1			0	0.00
290	STUDEBAKER - IN	Distribution		138.00	13.80		36.00	2			0	0.00
291	STUDEBAKER - IN	Distribution		138.00	13.09		20.00	1			0	0.00
292	SULLIVAN (IM) - IN	Transmission		765.00						REACTOR	1	50.00
293	SUMMIT - IN	Distribution		138.00	13.09		40.00	2			0	0.00
294	SWANSON - IN	Distribution		69.00	34.00		45.00	2			0	0.00
295	SWANSON - IN	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.40
296	THOMAS ROAD - IN	Distribution		69.00	13.09		20.00	1			0	0.00
297	THREE M - IN	Distribution		69.00	4.00		12.50	1			0	0.00
298	THREE OAKS - MI	Distribution		69.00	12.00		6.25	1			0	0.00
299	THREE RIVERS (FTW) - IN	Distribution		34.50	13.00		10.00	2			0	0.00
300	TILLMAN - IN	Transmission		138.00	13.09		10.00	1			0	0.00
301	TILLMAN - IN	Transmission		138.00	36.20		18.00	1			0	0.00
302	TORRINGTON - IN	Distribution		34.50	4.00		9.07	1			0	0.00
303	TRIER - IN	Distribution		138.00	13.09		20.00	1			0	0.00
304	TRI-LAKES - IN	Distribution		69.00	13.00		3.75	1			0	0.00
305	TWENTY FIRST STREET - IN	Distribution		34.50	13.00		18.75	2			0	0.00
306	TWENTY THIRD STREET (IM) - IN	Transmission		138.00	69.00	34.00	213.00	2			0	0.00
307	TWENTY THIRD STREET (IM) - IN	Transmission		34.50	0.00	0.00	0.00			STATCAP	2	28.80
308	TWIN BRANCH 138KV - IN	Transmission		138.00	13.09		20.00	1			0	0.00
309	TWIN BRANCH 345KV - IN	Transmission		345.00	138.00	34.50	675.00	1			0	0.00
310	TWIN BRANCH 345KV - IN	Transmission		345.00	137.50	13.20	450.00	1			0	0.00
311	TWIN BRANCH 34KV - IN	Transmission		34.50	13.00		2.67	1			0	0.00
312	UP RIVER DAM - IN	Distribution		34.50	4.00		1.50	3			0	0.00
313	UP RIVER DAM - IN	Distribution		13.80	4.00		1.50	3			0	0.00
314	UPLAND - IN	Distribution		69.00	13.20		20.00	1			0	0.00
315	UTICA (IM) - IN	Distribution		34.50	13.09		42.40	2			0	0.00
316	VALLEY - MI	Transmission		138.00	69.00	34.00	75.00	1			0	0.00
317	VAN BUREN - IN	Transmission		138.00	69.00	13.00	56.00	1			0	0.00
318	VICKSBURG - MI	Distribution		69.00	13.09		20.00	1			0	0.00
319	VICKSBURG - MI	Distribution		69.00	12.00		9.38	1			0	0.00
320	WABASH AVENUE - IN	Distribution		69.00	13.09		20.00	1			0	0.00
321	WALLEN - IN	Transmission		138.00	13.09		45.00	2			0	0.00
322	WALLEN - IN	Transmission		138.00	69.00	34.00	90.00	1			0	0.00
323	WARREN - IN	Distribution		69.00	12.00		7.00	1			0	0.00
324	WATER POLLUTION - IN	Distribution		34.50	4.00		7.00	1			0	0.00
325	WAYNE TRACE - IN	Distribution		138.00	13.09		22.40	1			0	0.00
326	WAYNEDALE - IN	Distribution		138.00	13.09		22.40	1			0	0.00
327	WAYNEDALE - IN	Distribution		138.00	12.47		20.00	1			0	0.00
328	WEST SIDE - IN	Transmission		138.00	69.00	34.00	84.00	1			0	0.00
329	WEST SIDE - IN	Transmission		138.00	13.09		42.40	2			0	0.00
330	WEST STREET - MI	Distribution		138.00	13.09		20.00	1			0	0.00
331	WHEELER STREET - MI	Distribution		69.00	13.00		8.40	1			0	0.00
332	WINCHESTER (IM) - IN	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	10.80
333	WINCHESTER (IM) - IN	Transmission		69.00	13.00		26.25	2			0	0.00
334	WOLF LAKE - IN	Distribution		69.00	13.00	0.00	7.50	1			0	0.00
335	WOLVERINE - MI	Distribution		69.00	13.00	2.40	5.00	1			0	0.00
336	WOODS ROAD - IN	Distribution		138.00	12.00		10.00	1			0	0.00
337	TotalDistributionSubstationMember			14,069	2,162	42	2,768	204	1		12	149
338	TotalGenerationSubstationMember			0	0	0	0	0	0		0	0
339	TotalTransmissionSubstationMember			24,738	6,292	1,330	14,522	140	4		43	1,650
340	Total											1,799

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

Q4

TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not attempt to include or aggregate amounts in a nonspecific category such as "general". Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.
Line No.	Description of the Good or Service (a)	Name of Associated/Affiliated Company (b)	Account(s) Charged or Credited (c)	Amount Charged or Credited (d)
1	Non-power Goods or Services Provided by Affiliated
2	Administrative and General Expenses - Maintenance	(a) AEPSC	935	5,209,992
3	Customer Support	AEPSC	920,923	1,722,304
4	Physical & Cyber Security	AEPSC	920,923	1,630,300
5	Administrative and General Expenses - Operation	AEPSC	920,921,923,925,926,928,930,931,933,922	7,353,247
6	Distribution Expenses - Maintenance	AEPSC	590-598	250,794
7	Rail Car Lease	SWEPCo	1860	324,634
8	AEPSC Support Svcs	AEPSC	417 920 923	2,744,533
9	Distribution Expenses - Maintenance	OPCo	592-598	759,222
10	Rail Car Maintenance	AEGCo	1510	343,019
11	Distribution Expenses - Maintenance	PSO	592-595	432,710
12	Real Estate & Workplace Svcs	AEPSC	920,923	3,378,714
13	Building and Property Leases	IMTCo	5890	971,215
14	Distribution Expenses - Operation	AEPSC	580-588	3,304,488
15	Regulatory Services	AEPSC	920,923	1,830,636
16	Central Machine Shop	APCo	107,108,163,500-513,524,530,510,544	2,352,794
17	Environmental Services	AEPSC	920,923	521,242
18	Research and Other Services	AEPSC	183,186,188	2,757,945
19	Civil & Political Activities and Other Svcs	AEPSC	4261-4265	1,044,388
20	Expenses of Nonutility Operations	APCo	4171	5,016,568
21	Steam Power Generation - Maintenance	AEPSC	510-514	2,220,073
22	Bus Ops & Perf Assurance	AEPSC	920,923	1,273,835
23	Fuel & Storeroom Services	AEPSC	152,163	6,323,069
24	Steam Power Generation - Operation	AEPSC	500,501,502,506	6,925,651
25	Coal Transloading	AEGCo	1510	8,120,693
26	Grid Solutions	AEPSC	920,923	795,018
27	Strategy & Transformation	AEPSC	920,923	1,121,021
28	Construction Services	AEPSC	107,108,120	95,532,162
29	Hydraulic Power Generation - Maintenance	AEPSC	541-545	324,167
30	Tax Services	AEPSC	920,923	1,157,550
31	Construction Services	OPCo	107,108	737,920
32	Hydraulic Power Generation - Operation	AEPSC	535-539	921,008
33	Transmission Expenses - Maintenance	AEPSC	568/569/5691/5692/570-573	686,916
34	Corp Safety & Health	AEPSC	920,923	1,513,922
35	Information Technology	AEPSC	920,923	9,357,224
36	Transmission Expenses - Operation	AEPSC	560/5612/5615/562-566/920/923	8,126,732
37	Corporate Accounting	AEPSC	920,923	2,869,922
38	Infrastructure Ops & Support	AEPSC	920,923	1,359,004
39	Treasury & Risk	AEPSC	920, 923	1,686,279
40	Corporate Communications	AEPSC	920,923	1,354,161
41	Legal GC/Administration	AEPSC	920,923	3,393,171
42	Corporate Human Resources	AEPSC	920,923	4,682,505
43	Materials and Supplies	OPCo	107/108/184/186/570/588/592/590/930/935	3,636,276
44	Corporate Planning & Budgeting	AEPSC	920,923	1,794,319
45	Nuclear Power Generation - Maintenance	AEPSC	528,530,531,532	903,787
46	Customer Accounts Expenses	AEPSC	901-905	9,331,009
47	Other Power Supply Expenses	AEPSC	556,557	4,520,643
48	Customer Service and Informational Expenses	AEPSC	907,908,910	328,418
49	Other Property and Investments	AEPSC	121,124	262,195
19
20	Non-power Goods or Services Provided for Affiliated
21	Building and Property Leases	AEPSC	454	1,458,210
22	Construction Services	APCo	107,108	729,672
23	Barging	AEGCo	417	7,612,396
24	Construction Services	IMTCo	107,106,108	9,746,780
25	Barging	APCO	417	40,129,350
26	Construction Services	OPCo	107,108	312,897
27	Barging	KPCO	417	3,138,826
28	Distribution Expenses - Maintenance	KPCo	592,593,595	365,227
29	Barging	WPCO	417	3,138,826
30	Distribution Expenses - Maintenance	APCo	592,593,594	529,658
31	Distribution Expenses - Maintenance	OPCo	592-597	295,951
32	Fleet and Vehicle Charges	AEPSC	188	337,644
33	Fuel Carbon Activation	AEGCo	154, 502	1,124,631
34	Fuel Consumed - Ammonia	AEGCo	154, 502	372,837
35	Fuel Consumed Handling	AEGCo	152, 501	5,931,683
36	Income Taxes, Utility Operating Income	Transrc OK	4,091	419,389
37	Materials and Supplies	APCo	154	561,541
38	Materials and Supplies	OPCo	154	291,089
39	Rail Car Lease	SWEPCo	1,510	1,331,786
40	Rockport Joint Books	(b) AEGCo	Various	37,833,241
41	Sodium Bicarbonate Activation	AEGCo	154, 502	5,729,390
42	Transmission Expenses - Maintenance	IMTCo	568/569/570-573	1,623,584
43	Transmission Expenses - Operation	IMTCo	560/562/563/566	2,236,588
44	Use of Jointly Owned Facility	IMTCo	454	4,832,039
45	Other Operating Revenue	APCO	456	305,346
42

Name of Respondent:

Indiana Michigan Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

/

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

GENERAL INFORMATION

Purpose

Who Must Submit

What and Where to Submit

When to Submit

Where to Send Comments on Public Reporting Burden.

GENERAL INSTRUCTIONS

EXCERPTS FROM THE LAW

GENERAL PENALTIES

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