ML17333A426

Indiana Michigan Power Co 1995 Annual Rept. W/960412 Ltr

ML17333A426
Person / Time
Site:	Cook
Issue date:	12/31/1995
From:	Fitzpatrick E INDIANA MICHIGAN POWER CO. (FORMERLY INDIANA & MICHIG
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
AEP:NRC:0909L, AEP:NRC:909L, NUDOCS 9604160188
Download: ML17333A426 (40)

Text

CATEGORY 1 REGULAR...Z INFORMATION DISTRIBUTION YSTEM (RIDS)-

ACCESSION NBR:9604160188 DOC.DATE: 95/12/31 NOTARIZED: NO FAC.L":p0-, 315 Donald C. Cook Nuclear Power Plant, Unit 1, Indiana M 50-3.';.6 Donald C. Cook Nuclear Power Plant, Unit 2, Indiana M AUTH. NAME AUTHOR AFFILIATION FITZPATRICK,E. Indiana Michigan'Power Co. (formerly Indiana a Michigan Ele RECIP.NAME RECIPIENT AFFILIATION

SUBJECT:

"Indiana Michigan Power, Co 1995 Annual Rept." W/960412 ltr. C DISTRIBUTION CODE: M004D COPIES RECEIVED:LTR TITLE: 50.71(b) Annual Financial Report

( ENCL l SIZE:~ 5 A T

NOTES:

RECIPIENT COPIES RECIPIENT COPIES ID CODE/NAME LTTR ENCL ID CODE/NAME LTTR ENCL PD3-1 LA 1 1 PD3-1 PD 1 1 HICKMAN J 1 1 INTERNAL: "'ILE CENTER 01 1 1 EXTERNAL: NRC PDR 1 1 D

0 NOTE TO ALL "RZDS" RECIPIENTS:

PLEASE HELP US TO REDUCE WASTEl CONTACT THE DOCUMENT CONTROL DESK, ROOM OWFN 5D-5(EX'15-2083) TO ELIMZNATE YOUR NAME FROM DISTRIBUTION LISTS FOR DOCUMENTS YOU DON'T NEEDI TOTAL NUMBER OF COPIES RF(>U RED: LTTR 5 ENCL 5

q4', a indiana Michigan ~

Power Company P.O. Box 16631 Columbus, OH 43216 April 12, 1996 AEP:NRC:0909L Docket Nos.: 50-315 50-316 U. S. Nuclear Regulatory Commission ATTN: ,Document Control Desk Washington, D. C. 20555 Gentlemen:

Donald C. Cook Nuclear Plant Units 1 and 2 FINANCIAL INFORMATION FOR INDIANA MICHIGAN POWER COMPANY Attachment 1 contains the Indiana Michigan Power Company's annual report for 1995. Attachment 2 contains a copy of I&M's projected cash flow for 1996. These reports are submitted pursuant to 10 CFR 50.71(b) and 10 CFR 140.21(e).

Sincerely, E. E. Fitzpatrick Vice President eh Attachments CC: A. A. Blind G. Charnoff H. J. Miller NFEM Section Chief NRC Resident Inspector - Bridgman J. R. Padgett yr~(}OQQ 9604i60i88 95i23i pg$

PDR ADQCK 050003i5 I PDR

ATTACHMENT 1 TO AEP'NRC:0909L INDIANA MICHIGAN POWER COMPANY'S ANNUAL REPORT FOR 1995

In iana Michigan Power Company 1 995 Annual Report

((

(~

NA MICHIGAN POWER COI(IIPANY AND SUBSIDIARIES One Summit Square, P.O. Box 60, Fort Wayne, indiana 46801 CONTENTS Background . ~ 2 Directors and Officers ~ ~ 3 Selected Consolidated Financial Data ..

Management's Discussion and Analysis of Results of Operations and Financial Condition .. 5-9 Independent Auditors'eport . 10 Consolidated Statements of Income Consolidated Balance Sheets 12-13 Consolidated Statements of Cash Flows . 14 Consolidated Statements of Retained Earnings . 15 Notes to Consolidated Financial Statements .. 1 6-28 Operating Statistics 29-30 Dividends and Price Ranges of Cumulative'Preferred Stock 31-32

BACKGROUND INDIANAMICHIGAN POWER COMPANY (the Company) is engaged in the generation, purchase, transmission and distribution of electric power. The Company serves approximately 537,000 retail customers in northern and eastern Indiana and a portion of southwestern Michigan and sells and transmits power at wholesale to other electric utilities, municipalities and electric cooperatives. Approximately 82% of the Company's retail sales are in Indiana and 18% in Michigan. The principal industries served are primary metals, electrical and electronic machinery, transportation equipment, fabricated metal products, rubber and miscellaneous plastic products and chemicals and allied products.

The Company is a subsidiary of American Electric Power Company, Inc., a public utility holding company, and was organized under the laws of Indiana on February 21, 1925. As of January 1, 1996, the Company began doing business as American Electric Power (AEP) along with all of the parent's operating subsidiary companies in order to serve its customers more efficiently as one operating organization realigned by distinct, separately managed generation, energy delivery and non-regulated business groups. The Company's two wholly-owned subsidiaries, Blackhawk Coal Company and Price River Coal Company, were formerly engaged in coal-mining operations in Utah. Blackhawk Coal Company currently leases or subleases portions of its coal rights, land and related mining equipment to unaffiliated companies. In addition, the Company has a river transportation division (RTD) that barges coal on the Ohio and Kanawha Rivers to AEP System generating plants owned by the Company and affiliated companies. The RTD also provides some barging services to unaffiliated companies.

The Company owns and leases 4,434 megawatts (mw) of generating capacity which includes 2,295 mw of coal-fired generation and 2,110 mw of nuclear generation. The Company owns the two unit Donald C. Cook Nuclear Plant located in Michigan. The generating plants and transmission facilities of the Company and certain other affiliated AEP System utility subsidiaries are operated as an integrated system with their costs and benefits shared through the AEP System Power Pool and AEP Transmission Agreement. Wholesale energy sales made by the Power Pool are allocated to the Pool members. The other AEP System Pool members are:

Appalachian Power Company, Columbus Southern Power Company, Kentucky Power Company and Ohio Power Company. The Company is also directly interconnected with its affiliate, AEP Generating Company, and the following unaffiliated entities: Central Illinois Public Service Company, The Cincinnati Gas 5 Electric Company, Commonwealth Edison Company, Consumers Power Company, Illinois Power Company, Indianapolis Power 5 Light Company, Louisville Gas and Electric Company, Northern Indiana Public Service Company, PSI Energy Inc. and Richmond Power and Light Company, as well as Indiana-Kentucky Electric Corporation (a subsidiary of Ohio Valley Electric Corporation, an affiliate that is not a member of the AEP System). In addition, the Company is interconnected through the AEP System with two other affiliated companies, Kingsport Power Company and Wheeling Power Company that are not members of the Power Pool, and with numerous unaffiliated utilities.

IND MICHIGANPOWER COMPANY AND SUBSIDIARIES Dl (ACTORS Mark A. Bailey (a) E. Linn Draper, Jr. Albert H. Potter Coulter R. Boyle, III (b) William J. Lhota David B. Synowiec (c)

Gregory A. Clark (c) Gerald P. Maloney Dale M. Trenary (b)

Peter J. DeMaria James J. Markowsky Joseph H. Vipperman (b)

William N. D'Onofrio Richard C. Menge (a) William E. Walters (b)

OFFICERS E. Linn Draper Jr. John F. DiLorenzo, Jr.

Chairman of the Board and Chief Executive Officer Secretary William J. Lhota (b) Armando A. Pena (d)

President and Chief Operating Officer Treasurer Richard C. Menge (a) Elio Bafile President and Chief Operating Officer Assistant Controller and Assistant Secretary Mark A. Bailey (a) Leonard V. Assante Vice President Assistant Controller A. Alan Blind William L. Scott (d)

Site Vice President, Donald C. Cook Nuclear Plant Assistant Controller Coulter R. Boyle, III (b) John M. Adams, Jr. (d)

Vice President Assistant Secretary Peter J. DeMaria Jeffrey D. Cross (e)

Vice President and Controller Assistant Secretary William N. O'Onofrio (a) Robert G. Griffin (f)

Vice President Assistant Secretary Eugene E. Fitzpatrick Carl J. Moos (g)

Vice President Assistant Secretary Gerald P. Maloney John B. Shinnock Vice President Assistant Secretary James J. Markowsky Bruce M. Barber Vice President Assistant Treasurer Joseph H. Vipperman (b) Christopher J. Keklak (d)

Vice President Assistant Treasurer Gerald R. Knorr (e)

Assistant Treasurer As of January 1, 1996 the cunent directors and officers of Indiona Michigan Power Company wore omployoes of American Electric Power Service Corporation with seven exceptionst Messrs. Bofile, Blind, Boyle, Clark, Griffin, Trenary and Walters, who were omployees of Indiana Michigan Power Company.

tof Resigned Jonoetr 1, 1996 Idf Elected November 1, 1995 illElected Septetnber 1, 1995 tbf Elected Jenoottr 1, 1996 lof Resigned November 1, 1995 (gl Resigned September 1, 1995 Icf Elected Aftn7 25, 1995

Selected Consolidated Financial Data rEn Dcm 1994 ~1 19 2 (in thousands)

INCOME STATEMENTS DATA:

Operating Revenues S1,283,157 S1,251,309 S1,202,643 S1,196,755 S1,225,867 Operating Expenses 1 077 434 ~12~4 ~924 5 ~100 997 ~998 9 Operating Income 205,723 221,969 210,158 195,788 227,528 Nonoperating Income (Loss)

Income Before Interest Charges

~272 ~742 211,995 229,397

~24) 209,924

~11 209,903

~721 223,807 Interest Charges ~70 03 ~71 89 ~85 2 ~)44 Net Income 141,092 157,502 129,344 123,983 136,963 Preferred Stock Dividend Requirements ~1791 ~11 1 ~14 2 ~15 4 2 ~144 Earnings Applicable to Common Stock 129 301 ~145 821 4 115 088 4 108 531 4 121 515 Dec mb r 31 1995 19 4 ~199 ~19 2 19 1 BALANCE SHEETS DATA: (in thousands)

Electric Utility Plant S4,319,564 S4,269,306 S4,290,957 S4,266,480 S4,135,820 Accumulated Depreciation and Amortization 1 7~14~5 ~15~94(2 ~1714 2 1 fg~14 ~12~14 Net Electric Utility Plant 42 567 599 42 609 366 42 576 128 42 635 042 ~26'l4 471 Total Assets ~3928 337 ~3878 035 43 723 648 43 608 645 ~3442 606 Common Stock and Paid-in Capital S 787,686 S 790,234 S 790,625 S 781,818 S 781,783 Retained Earnings ~235 1 7 ~216 65 ~177 8 ~171 09 ~124 Total Common Shareholder's Equity 41 022 793 $1 006 892 4 968 263 4 953 127 951 026 Cumulative Preferred Stock:

Not Subject to Mandatory Redemption S 52,000 S 52,000 S 87,000 S 197,000 S 197,000 Subject to Mandatory Redemption (a) 135 000 135 000 100 000 Total Cumulative Preferred Stock 4 187 000 4 187 000 4 187 000 4 197 000 197 000 Long-term Debt (a) $1 040 101 41 069 887 41 073 154 ~1211 623 ~1130 709 Obligations Under Capital Leases (a) ll 142 506 4 152 589 4 98 753 4 126 689 102 985 Total Capitalization and Liabilities 43 928 337 43 878 035 43 723 648 43 608 645 ~3442 606 (al Including gordon due wirhrn one year.

DIANA MICHIGANPOWER COMPANY AND SUBSIDIARIES MANAGElVlENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIALCONDITION Business Outlook Since its enactment in 1992, the Energy Policy Whether future results of operations are adversely Act has fostered competition in the generation and affected by losses or write-offs will also depend on sale of electricity in the wholesale market. The whether and how equitable recovery is provided for prospect for market driven rates is powering a by the applicable regulators. We intend to seek movement, mainly among large industrial energy appropriate recovery of any stranded costs and users, to introduce competition to the retail market regulatory assets that may result from a transition as well. As a result management expects that to competition.

competition will be a significant factor influencing the Company's future results of operations. Among The Company, as a member of the AEP System, the other factors that could impact future earnings has the financial strength, geographic reach, loca-are nuclear fuel disposal costs and nuclear decom- tion and cost structure to be an able competitor.

missioning costs. Although no assurance can be given that the Company can maintain this position in the future, A significant expansion of competition in the management is taking steps to prepare for the generation and sale of electricity could result in an challenges that increased competition will present.

adverse effect on future results of operations from In 1995 management took steps to prepare for stranded costs and the write-off of regulatory competition by realigning the Company's opera-assets. Stranded costs occur when a customer tions, along with the operations of the AEP Sys-switches to a new supplier creating the issue of tem's other operating companies,,into functional who pays for investments and commitments that operating units, expanding marketing and customer are no longer needed, economical or recoverable in service efforts and proposing a plan for an orderly a competitive market. The amount of any losses transition to retail competition. Management also the Company may experience from stranded costs proposed and filed open access transmission rates.

depends on the extent to which direct competition is introduced to the Company's business and the The realignment from separate operating company market price of energy. Cost-based regulation organizations to distinct fossil-fired and hydroelec-traditionally results in the recognition of revenues tric generation, nuclear generation and energy and expenses in accordance with rate commission delivery operating units will facilitate the unbundling orders which can result in revenue and expense of electric services to separate competitive genera-recognition in different time periods than for enter- tion services from regulated transmission and prises that are not regulated. As a result, regula- distribution services. It also should facilitate our tory assets have been recorded by regulated utility ability to more efficiently and effectively meet companies representing the deferral of costs for customer needs. Process improvement and cost recovery in future periods. At December 31, 1995, control will be key performance objectives for our the Company had $ 459 million of regulatory assets. new operating units.

In order to maintain regulatory assets, the Com-pany's rates must be cost-based regulated. Man- In October of 1995 management proposed the agement has reviewed the evidence currently creation of an Independent System Operator to available and concluded that the Company contin- operate a multi-state transmission grid to facilitate ues to meet the requirements to apply rate-regu- equal, safe and efficient transmission. Management lated accounting standards. In the event a portion also proposed the eventual creation of a Regional of the Company's business no longer met these Power Exchange that would accept offers to buy requirements, regulatory assets would have to be and sell power and would settle transactions based written off for that portion of the business. on the price at which supply and demand are balanced. Under the proposal regulators would continue to regulate delivery services and provide for the recovery of any stranded costs and regula-tory assets through a usage charge.

Management has also offered access to AEP's build a permanent repository for spent fuel. The extensive transmission grid at 142 interconnections federal government has not made sufficient prog-to all parties under the same terms and conditions ress toward the selection of a site and construction available to the AEP System. This should provide of a permanent repository and as long as there is a the Company with greater opportunities for trans- delay in establishing the permanent storage reposi-mission service revenues. Management has also tory for spent nuclear fuel, the cost of a temporary responded to our retail customers'eeds by intro- or permanent repository will continue to increase.

ducing new cost-based regulated rate designs (interruptible buy-through and real time pricing). The cost to decommission the Cook Plant is affected by NRC regulations and the DOE's SNF These proposals were issued to enable the Com- disposal program. Studies completed in 1994 pany to participate in a meaningful way in the estimate the cost to decommission the plant and process of shaping the form of the future competi- dispose of low-level nuclear waste accumulation to tive playing field. Our success will depend on our range from $ 634 million to $ 988 million in 1993 ability to obtain a level playing field, improve and dollars. The decommissioning estimate could expand on our energy sales and services and escalate due to uncertainty in the DOE's SNF maintain and improve on our relatively low cost disposal program and the length of time that SNF structure. may need to be stored at the plant site delaying decommissioning. Decommissioning costs are Nuclear Cost being recovered in the three rate-making jurisdic-tions based on at least the lower end of the range The Company's nuclear plant, the Donald C. Cook in the most recent decommissioning study at the Nuclear Plant, has recently achieved a superior time of the last rate proceeding. However, future rating from the Institute of Nuclear Power Opera- results of operations and possibly financial condi-tions, a nuclear industry oversight group, and tion could be adversely affected if the costs of received improved Nuclear Regulatory Commission spent nuclear fuel disposal and decommissioning (NRC) performance ratings. In an effort to continue continue to increase and if for some reason such to reduce costs and enhance organizational effi- costs cannot be recovered.

ciency, management announced in November that during the summer of 1996 we will consolidate our Environmen al Concerns Columbus-based nuclear engineering, management and support staff with the plant staff at or near the Hazardous Material Cook Plant in Bridgman, Michigan.

By-products from the generation of electricity The cost to operate and maintain the two-unit include materials such as ash, slag, sludge, low-Cook Plant is impacted by federal laws and NRC level radioactive waste and spent nuclear fuel. In requirements. The Nuclear Waste Policy Act of addition, the generating plants and transmission 1982 established federal responsibility for the and distribution facilities have used asbestos, permanent off-site disposal of spent nuclear fuel polychlorinated biphenyls (PCBs) and other hazard-and high-level radioactive waste. By law the ous and non-hazardous materials. The Company is Company participates in the Department of En- currently incurring costs to safely store and dispose ergy's (DOE's) Spent Nuclear Fuel (SNF) disposal of such substances, and additional costs could be program which is described in Note 3 of the Notes incurred to comply with new laws and regulations to Consolidated Financial Statements. Since 1983 if enacted.

our consumers of nuclear generated electricity have paid $ 237 million for the future disposal, at a yet to The Comprehensive Environmental Response, be built DOE disposal facility, of spent nuclear fuel Compensation and Liability Act (CERCLA or consumed at the Cook Plant. Under the provisions Superfund legislation) addresses'clean-up of hazard-of the Nuclear Waste Policy Act, collections from ous substances at disposal sites and authorizes the customers are to provide the DOE with money to United States Environmental Protection Agency

a NDIANA MICHIGANPOWER COMPANY AND SUBSIDIARIES (Federal EPA) to administer the clean-up programs. Operating Revenues and Energy Sales Increase As of year-end 1995, ISM is currently involved in litigation with respect to two sites being overseen Operating revenues increased 2.5% in 1995 by the Federal EPA and has been named by the following a 4% increase in 1994. The changes in Federal EPA as a "Potentially Responsible Party" revenues are analyzed as follows:

(PRP) for three other sites. Information requests have been received for four additional sites which Increase (Oecrease) could lead to PRP designation. IS.M also has From Previous Year dollars in millions 1995 1994 received information requests with respect to two sites administered by state authorities. Liability has been resolved for a number of sites with no signifi- Retail:

cant effect on results of operations. The Com- Price Variance $ (0.7) $ 69.8 Volume Variance 29.9 30.5 pany's present estimates do not anticipate material 29.2 3.3 100.3 12.9 cleanup costs for identified sites for which I%M has Mholesale:

been declared a PRP. However, if for reasons not Power Pool:

currently identified significant costs are required for Price Variance (7.9) (3.8)

Volume Variance 39.4 (62.4) cleanup, future results of operations and possibly Capacity Charges ~28.3) 2.1 financial condition would be adversely affected 32 ~64. )

unless the costs can be recovered. Unaffiliated Utilities:

Price Variance (12.7) 21.1 Litigation Volume Variance 14.0 ~9. 0) 1.3 12.1 Total Mholesale 4.5 1.3 ~52.0)(12.8)

The Company is involved in a number of legal proceedings and claims. While management is Other Operating Revenues ~1.9) 0.4 Total ~31.8 2.5 ~48.7 4.0 unable to predict the outcome of such litigation, it is not expected that the resolution of these matters The increase in 1995 operating revenues resulted will have a material adverse effect on the results of from increased energy usage by retail and unaffili-operations and/or financial condition. ated wholesale customers. Retail energy sales increased 3% reflecting warmer summer weather in Resul s of 0 erations 1995 and a colder fourth quarter in 1995 than 1994 and continuing growth in the number of Net Income residential, commercial and industrial customers.

While wholesale energy sales increased 34%,

Although revenues increased 2.5% in 1995, net wholesale revenues increased only 1% in 1995.

income declined 10.4% to $ 141 million mainly due The substantial increase in wholesale energy sales to increased operating expenses, including the was primarily due to a 69% increase in energy unfavorable effect of a provision for severance sales to the AEP System Power Pool (Power Pool),

benefits in connection with the realignment of which are made at cost, reflecting the increased operations and increased federal income tax ex- availability of lower cost nuclear generating capac-pense. The increase in net income in 1994 of ity in 1995. During 1995 one nuclear generating 21.8% was the result of a retail base rate increase unit was out of service for refueling while both in the Indiana jurisdiction, reduced interest expense units were refueled in 1994. Also contributing to due to the retirement of long-term debt, the effect the wholesale energy sales increase were increased of adopting Statement of Financial Accounting sales to unaffiliated entities. Sales to the Com-Standards No. 109, "Accounting for Income Taxes" pany's municipal and cooperative customers and to (SFAS 109) in 1993 and the retirement in 1994 of unaffiliated utilities by the Power Pool which are a generating plant. shared by the Company increased primarily due to

the warmer summer and the colder fourth quarter Fuel expense increased substantially in 1995 due weather in 1995 as compared to 1994. The in- to a 51% increase in nuclear generation reflecting crease in wholesale sales did not lead to a corre- the increased availability of nuclear generating sponding increase in revenues due to reduced capacity. During 1995 one unit was out of service capacity credits from the Power Pool and increasing for refueling while both units were out of service competition in the wholesale energy market. for refueling in 1994. Fuel expense declined in Capacity credits are designed to allocate the cost of 1994 due to a significant reduction (43%) in nu-the AEP System's generating capacity among the clear generation reflecting the refueling outages members of the Power Pool based on their relative partially offset by a 6% increase in fossil genera-peak demands and generating reserves. An in- tion.

crease in the Company's peak demand during 1995 relative to the peak demand of all Power Pool The increase in purchased power expense in 1994 members caused the decrease in capacity revenues. reflects increased receipts from the Power Pool due to the nuclear outages and increased purchases In 1994 revenues rose 4% largely due to in- from unaffiliated utilities for immediate resale to creased retail revenues partly offset by a decline in other unaffiliated utilities.

total wholesale revenues. The growth in retail revenues resulted from a $ 34.7 million annual base Other operation expense increased in 1995 rate increase in the Indiana jurisdiction, increased primarily due to a provision for severance pay decommissioning expense recoveries in the Michi- related to the functional realignment of operations gan jurisdiction and a 4% increase in energy sales and costs related to the development of a new due to growth in the number of retail customers. activity based budgeting system. The 1994 in-The decline in 1994 wholesale revenues reflected crease was caused by regulatory-approved in-the decrease in energy available for delivery to the creases in nuclear decommissioning accruals, Power Pool due to the scheduled refueling and accruals for other postretirement benefits commen-maintenance outages at the Company's two nuclear surate with rate recovery and expenses related to units in 1994 and lower energy sales by the Power the closing of the Company's Breed Plant.

Pool due to mild weather throughout most of 1994.

While severe weather in January 1994 and hot The increase in federal income taxes attributable June weather increased the Power Pool's short- to operations in 1995 was primarily due to changes term wholesale sales in those months, the mild in certain book/tax differences accounted for on a weather throughout the remainder of 1994, com- flow-through basis and the effects of favorable bined with increased competition in the wholesale accrual adjustments recorded in 1994 in connection market reduced short-term sales for the year. with the resolution of the audit of prior years'ax returns. Federal income taxes attributable to Operating Expenses Increase operations increased in 1994 due to increased pre-tax operating income.

Total operating expenses increased 5% in 1995 or

$ 48 million reflecting the increased operation of Nonoperating Income and Financing Costs the Company's nuclear units and severance pay accruals. In 1994 total operating expenses rose Nonoperating income increased in 1994 reflecting 4% or $ 37 million largely due to increased accruals a favorable tax effect from the Breed Plant closing for nuclear decommissioning expense and employee and the unfavorable effect in 1993 of adopting benefits. The significant changes in operating SFAS 109 for nonutility assets and liabilities.

expenses were:

Increase (Oecrease) Interest charges declined in 1994 due to debt From Previous Year repayments and a refinancing program which dollars in millions Amount ~

1995 Amount 1994 lowered interest rates. In 1994, $ 10 million of long-term bonds were retired and $ 90 million were Fuel $ 21.2 10.5 $ (18.5) (8.4) refinanced. The full year effects from 1993 Purchased Power (5.8) (4.4) 23.0 21.2 refinancings and retirements also contributed to the Other Operation 10.3 3.5 28.5 10.6 Federal Income Taxes 15.7 40.9 6.4 19.9 1994 reduction.

NDIANA MICHIGANPOWER COMPANy'ND SUBSIDIARIES Construction Spending Effects of Inflation Gross plant and property additions were S151 Inflation affects the cost of replacing utility plant million in 1995 and $ 212 million in 1994. Manage- and the cost of operating and maintaining such ment estimates construction expenditures for the plant. The rate-making process generally limits next three years to be $ 315 million with no major recovery to the historical cost of assets resulting in new generating plant construction planned. The economic losses when inflation effects are not funds for construction of new facilities and im- recovered from customers on a timely basis.

provement of existing facilities can come from a However, economic gains that result from the combination of internally generated funds, short- repayment of long-term debt with inflated dollars term and long-term borrowings, preferred stock partly offset such losses.

issuances and investments in common equity by the Company's parent, American Electric Power New Accounting Rules Co., Inc. However, all of the construction expendi-tures for the next three years are expected to be The Financial Accounting Standards Board (FASB) financed internally. issued a new accounting standard, SFAS 121 "Accounting for Impairment of Long-Lived Assets Liquidity and Capital Resources and for Long-Lived Assets to Be Disposed Of." The new standard is effective beginning with 1996 When necessary the Company generally issues accounting periods. The initial implementation of short-term debt to provide for interim financing of this new standard is not expected to have a signifi-capital expenditures that exceed internally generat- cant impact on the Company.

ed funds. At December 31, 1995, $ 372 million of unused short-term lines of credit shared with In 1996 the FASB issued an exposure draft other AEP System companies were available. An "Accounting for Certain Liabilities Related to Clo-authorization by the Securities and Exchange sure or Removal of Long-Lived Assets." This Commission limits short-term borrowings to $ 175 document proposes that the present value of any million. Periodic reductions of outstanding short- decommissioning or other closure or removal term debt are made through issuances of long-term obligation be recorded as a liability when the debt and preferred stock and through additional obligation is incurred. A corresponding asset would capital contributions by the parent company. be recorded in the plant investment account and recovered through depreciation charges over the The Company has regulatory approval to issue up asset's life. A proposed transition rule would to $ 150 million of long-term debt. Management require that an entity report in income the cumula-expects to use the proceeds of future long-term tive effect of initially applying the new standard.

financings to retire short-term debt, refinance The Company is currently studying the impact of maturing and other long-term debt, refund cumula- the proposed rules and evaluating its potential tive preferred stock and fund construction expendi- impact.

tures.

The Company presently exceeds all minimum coverage requirements for issuance of mortgage bonds and preferred stock. The minimum coverage ratios are 2.0 for mortgage bonds and 1.5 for preferred stock. At December 31, 1995, the mortgage bonds and preferred stock coverage ratios were 6.25 and 2.63, respectively.

INDEPENDENT AUDITORS'EPORT To the Shareholders and Board of Directors of Indiana Michigan Power Company:

We have audited the accompanying consolidated balance sheets of Indiana Michigan Power Company and its subsidiaries as of December 31, 1995 and 1994, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1995. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Indiana Michigan Power Company and its subsidiaries as of December 31, 1995 and 1994, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1995 in conformity with generally accepted accounting principles.

v- /~M L-t-I DELOITTE 5 TOUCHE LLP Columbus, Ohio February 27, 1996 10

NDIANA MICHIGANPOWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income Y rEn D m r 1 1995 1994 (in thousands)

OPERATING REVENUES ~$ 1 28 157 ~1251 309 ~$ 1 202 4 OPERATING EXPENSES:

Fuel 222,967 201,739 220,206 Purchased Power 125,413 131,234 108,274 Other Operation 306,967 296,625 268,144 Maintenance 141,813 139,423 142,637 Depreciation and Amortization 138,814 136,244 138,794 Amortization of Rockport Plant Unit 1 Phase-in Plan Deferrals 15,644 15,644 15,644 Taxes Other Than Federal Income Taxes 71,791 70,078 66,805 Federal Income Taxes 54 025 ~38 3 ~19 1 Total Operating Expenses 1 077 434 1 029 340 992 48 OPERATING INCOME 205,723 221,969 210,158 NONOPERATING INCOME (LOSS) 6 272 7 428 ~2341 INCOME BEFORE INTEREST CHARGES 211,995 229,397 209,924 INTEREST CHARGES 70 903 71 895 ~580 NET INCOME 141,092 157,502 129,344 PREFERRED STOCK DIVIDEND REQUIREMENTS 11 791 ~11 81 ~14 2 6 EARNINGS APPLICABLE TO COMMON STOCK $ 129 301 4 '145 821 ~115 088 See Notes to Consolidated Financial Statements.

11

Consolidated Balance Sheets D em r 1

~1 1994 (in thousands)

ASSETS ELECTRIC UTILITY PLANT:

Production $ 2,507,667 $ 2,494,834 Transmission 867,541 849,920 Distribution 666,810 644,720 General (including nuclear fuel) 186,959 204,909 Construction Work in Progress ~@592 ~74 2 Total Electric Utility Plant 4,319,564 4,269,306 Accumulated Depreciation and Amortization ~17 1t¹ ~1~4 NET ELECTRIC UTILITY PLANT ~2567 5 9 2 ff0~96 NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS 4 3619 534 9 OTHER PROPERTY AND INVESTMENTS 1509 4 127 424 CURRENT ASSETS:

Cash and Cash Equivalents 13.723 9,907 Accounts Receivable:

Customers 82,434 74,491 Affiliated Companies 21,881 24,848 Miscellaneous 11,450 20,334 Allowance for Uncollectible Accounts (334) (121)

Fuel - at average cost 29,093 35,802 Materials and Supplies - at average cost 72,861 59,897 Accrued Utility Revenues 43,937 40,582 Prepayments ~11 1 ~414 TOTAL CURRENT ASSETS 28 23 2741 4 REGULATORY ASSETS ~4'~2 421 7 DEFERRED CHARGES 32 64 31 515 TOTAL $3 928 337 $3 878 035 See /Votes to Consolidated hnanoial Statements.

12

IND ICHIGANPOWER COMPANY AND SUBSIDIARIES December 31 1995 1994 (in thousands)

CAPITALIZATIONAND LIABILITIES CAPITALIZATION:

Common Stock - No Par Value:

Authorized - 2,500,000 Shares Outstanding - 1,400,000 Shares S 56,584 56,584 Paid-in Capital 731,102 733,650 Retained Earnings 235 1t37 21ljJjg8 Total Common Shareholder's Equity 1,022,793 1,006,892 Cumulative Preferred Stock:

Not Subject to Mandatory Redemption 52,000 52,000 Subject to Mandatory Redemption 135,000 135,000 Long-term Debt ~1034 48 ~29 II87 TOTAL CAPITALIZATION ~2243 41 2 123 779 OTHER NONCURRENT LIABILITIES:

Nuclear Decommissioning 269,392 211,963 Other 184 103 192 758 TOTAL OTHER NONCURRENT LIABILITIES ~45 495 404 721 CURRf NT LIABILITIES:

Long-term Debt Due Within One Year 6,053 140,000 Short-term Debt 89,975 50,600 Accounts Payable - General 37,744 40,417 Accounts Payable - Affiliated Companies 22,962 22,720 Taxes Accrued 71,696 63,621 Interest Accrued 16,158 19,436 Obligations Under Capital Leases 31,776 39,003 Other 74 463 ~65 40 TOTAL CURRENT LIABILITIES ~5I~27 441 2 DEFERRED INCOME TAXES 612 147 ~$ 4!g2 DEFERRED INVfSTMENT TAX CRf DITS ~15 202 ~14~2 DEFERRED GAIN ON SALE AND LfASfBACK-ROCKPORT PLANT UNIT 2 998 2 ~1)~59 DEFERRED CREDITS 56 2 COMMITMENTS AND CONTINGENCIES t Note 3)

TOTAL $3 928 337 $3 878 035 13

Consolidated Statements of Cash Flows YarEn edDcm r 31 19 5 ~194 (in thousands)

OPERATING ACTIVITIES:

Net Income S 141,092 S 157,502 S 129,344 Adjustments for Noncash Items:

Depreciation and Amortization 148,441 146,966 148,270 Amortization of Rockport Plant Unit 1 Phase-in Plan Deferrals 15,644 15,644 15,644 Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses (net) 8,684 (18,779) 33,827 Deferred Federal Income Taxes (23,564) (19,775) (52,631)

Deferred Investment Tax Credits (9,004) (13,877) (8,543)

Changes in Certain Current Assets and Liabilities:

Accounts Receivable (net) 4,121 (7,200) 14,441 Fuel, Materials and Supplies (6,255) (3,423) 14,938 Accrued Utility Revenues (3,355) (5,940) 43,913 Accounts Payable (2,431) 5,219 8,233 Taxes Accrued 8,075 9,148 38,644 Other (net) ~23 99) ~12 14 ) ~1'~70 )

Net Cash Flows From Operating Activities 25 49 ~2'~)4(4 ~I7(7,$ 72 INVESTING ACTIVITIES:

Construction Expenditures (117,785) (11 8,094) (108,867)

Long-term Receivable from Customer for Construction of Facilities (18,733)

Proceeds from Sales of Property and Other 9 325 ~238 KZ5 Net Cash Flows Used For Investing Activities ~127 193) ~I1 056) ~)0 482)

FINANCING ACTIVITIES:

Capital Contributions from Parent Company 10,000 Issuance of Cumulative Preferred Stock 34,618 98,776 Issuance of Long-term Debt 96,819 89,221 243,426 Retirement of Cumulative Preferred Stock (35,798) (112,300)

Retirement of Long-term Debt (141,122) (101,833) (392,093)

Change in Short-term Debt (net) 39,375 525 5,875 Dividends Paid on Common Stock (110,852) (106,608) (108,696)

Dividends Paid on Cumulative Preferred Stock ~)1 56 ) ~1) 2 4) ~15 585)

Net Cash Flows Used For Financing Activities @1127 34 ) ~131 12 ) ~27 1~57)

Net increase (Decrease) in Cash and Cash Equivalents 3,816 6,155 (3,707)

Cash and Cash Equivalents January 1 ~99 7 ~72 ~74 Cash and Cash Equivalents December 31 ~13 723 4 9 907 $ 3 752 See hfotes to Consolidated Rnancial Statements.

DIANA MICHIGAIVPOWER COMPANY AIVDSUBSIDIARIES 7'onsolidated Statements of Retained Earnings Year En e Decem r 1

~199 ~14 (in thousands)

Retained Earnings January 1 $ 216,658 $ 177,638 $ 171,309 Net Income ~141 0 2 157 502 ~12 44

~357 7 335 140 Deductions:

Cash Dividends Declared:

Common Stock 110,852 106,608 108,696 Cumulative Preferred Stock:

4-1/8% Series 495 495 495 4.56% Series 273 273 273 4.12% Series 165 165 165 5.90% Series 2,360 2,360 374 6-1/4% Series 1,875 1,875 161 6.30% Series 2,205 1,978 6-7/8% Series 2,063 2,063 1,799 7.08% Series 2,124 2,124 2,124 7.76% Series 317 2,716 8.68% Series, 2,517

$ 2.15

$ 2.25 Series Series ~6 3,001 Total Cash Dividends Declared Capital Stock Expense Total Deductions

~21122,412

~122 4 118,258 224 118 482

~4 122,921 123 015 Retained Earnings December 31 $ 235 107 $ 216 658 177 638 See IVo(as to Consolidated Rnonciol Stotements.

15

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS

1. SIGNIFICANT ACCOUNTING POLICIES: Basis of Accounting Organization As a cost-based rate-regulated entity, IRM's financial statements reflect the actions of regulators Indiana Michigan Power Company (the Company that result in the recognition of revenues and or I%M) is a wholly-owned subsidiary of American expenses in different time periods than enterprises Electric Power Company, Inc. (AEP Co., Inc.), a that are not cost-based rate regulated. In accor-public utility holding company. The Company is dance with Statement of Financial Accounting engaged in the generation, purchase, transmission Standards (SFAS) No. 71, "Accounting for the and distribution of electric power to 537,000 retail Effects of Certain Types of Regulation," regulatory customers in northern and eastern Indiana and a assets and liabilities are recorded to reflect the portion of southwestern Michigan. Wholesale economic effects of regulation.

electric power is. supplied to neighboring utility systems. As a member of the American Electric Use of Estimates Power (AEP) System Power Pool (Power Pool) and a signatory company to the AEP Transmission The preparation of these financial statements in Equalization Agreement, its facilities are operated in conformity with generally accepted accounting conjunction with the facilities of certain other AEP principles requires in certain instances the use of affiliated utilities as an integrated utility system. management's estimates. Actual results could differ from those estimates.

The Company has two wholly-owned subsidiar-ies, which are consolidated in these financial UtilityPlant statements, Blackhawk Coal Company and Price River Coal Company, that were formerly engaged in Electric utility plant is stated at original cost and coal-mining operations. Blackhawk Coal Company is generally subject to first mortgage liens. Addi-currently leases and subleases portions of its Utah tions, major replacements and betterments are coal rights, land and related mining equipment to added to the plant accounts. Retirements from the unaffiliated companies. Price River Coal Company, plant accounts and associated removal costs, net of which owns no land or mineral rights, is inactive. salvage, are deducted from accumulated depreci-ation.

Regulation The costs of labor, materials and overheads As a subsidiary of AEP Co., Inc., I@M is subject incurred to operate and maintain utility plant are to regulation by the Securities and Exchange Com- included in operating expenses.

mission (SEC) under the Public Utility Holding Com-pany Act of 1935 (1935 Act). Retail rates are Allowance for Funds Used During Construction regulated by the Indiana Utility Regulatory Commis- (AFUDCJ sion (IURC) and the Michigan Public Service Com-mission. The Federal Energy Regulatory Commis- AFUDC is a noncash nonoperating income item sion (FERC) regulates wholesale rates. that is recovered with regulator approval over the service life of utility plant through depreciation and Principles of Consolidation represents the estimated cost of borrowed and equity funds used to finance construction projects.

The consolidated financial statements include The amounts of AFUDC for 1995, 1994 and 1993 ItkM and its wholly-owned subsidiaries. Significant were not significant.

intercompany items are eliminated in consolidation.

16

IANA MICHIGANPOWER COMPANY AND SUBSIDIARIES Depreciation and AmortizatI'on Levelization of Nuclear Refueling Outage Costs Depreciation is provided on a straight-line basis Incremental operation and maintenance costs over the estimated useful lives of utility plant and is associated with refueling outages at the Donald C.

calculated largely through the use of composite Cook Nuclear Plant (Cook Plant) are deferred for rates by functional class as follows: amortization over the period (generally eighteen months) beginning with the commencement of an Functional Class Compost te outage and ending with the beginning of the next

~of Pro e t Annual Rates outage.

Production:

Steam-Huclear 3.4X Income Taxes Steam-Fossil-Fired 4.4X Hydroelectric-Conventional 3.2X The Company follows the liability method of Transmission 1.9X Distribution 4.2X accounting for income taxes as prescribed by SFAS General 3.8X 109, "Accounting for Income Taxes." Under the liability method, deferred income taxes are provided Amounts to be used for demolition of non-nuclear for all temporary differences between book cost plant are presently recovered through depreciation and tax basis of assets and liabilities which will charges included in rates. The accounting and rate- result in a future tax consequence. Where the making treatment afforded nuclear decommissioning flow-through method of accounting for temporary costs and nuclear fuel disposal costs are discussed differences is reflected in rates, regulatory assets in Note 3. and liabilities are recorded in accordance with SFAS 71.

Cash and Cash Equivalents Investment Tax Credits Cash and cash equivalents include temporary cash investments with original maturities of three Based on directives of regulatory commissions, months or less. the Company reflected investment tax credits in rates on a deferral basis. Commensurate with rate Operating Revenues treatment deferred investment tax credits are being amortized over the life of the related plant invest-Revenues include the accrual of electricity con- ment. The Company's policy with regard to invest-sumed but unbilled at month-end as well as billed ment tax credits for nonutility property was to revenues. practice the flow-through method of accounting.

Fuel Costs Debt and Preferred Stock Fuel costs are matched with revenues in accor- Gains and losses on reacquired debt are deferred dance with rate commission orders. Revenues are arid amortized over the remaining term of the accrued related to unrecovered fuel in both retail reacquired debt in accordance with rate-making jurisdictions and for replacement power costs in the treatment. If the debt is refinanced the reacquisi-Michigan jurisdiction until approved for billing. If tion costs are deferred and amortized over the term the Company's earnings exceed the allowed return of the replacement debt commensurate with their in the Indiana jurisdiction, the fuel clause mecha- recovery in rates.

nism provides for the refunding of the excess earnings to ratepayers. Wholesale jurisdictional fuel In accordance with rate-making treatment debt cost changes are expensed and billed as incurred. discount or premium and debt issuance expenses are amortized over the term of the related debt, with the amortization included in interest charges.

17

Redemption premiums paid to reacquire preferred the Company's business'o longer met these stock are deferred, debited to paid-in capital and requirements regulatory assets and liabilities would amortized to reduce retained earnings in accordance have to be written off for that portion of the busi-with rate-making treatment. The excess of par ness.

value over costs of preferred stock reacquired to meet sinking fund requirements is credited to paid- Regulatory assets and liabilities are comprised of in capital. the following:

December 31 Nuclear Decommissioning and Spent Nuclear Fuel 1995 1994 Disposal Trust Funds (in thousands)

Regulatory Assets:

Amounts Due From Customers for Securities held in trust funds for decommissioning Future Income Taxes $ 309,640 $ 308,831 nuclear facilities and for the disposal of spent Department of Energy Decontamination and nuclear fuel are recorded at market value in accor- Oecocmissioning Assessment 48,862 51,896 dance with SFAS 115, "Accounting for Certain Rate Phase-in Plan Deferrals 27,515 43,159 Investments in Debt and Equity Securities." Securi- Nuclear Refueling ties in the trust funds have been classified as Outage Cost Levelization 23,467 32,151 Unamortized Loss On available-for-sale due to their long-term purpose. Reacquired Debt 20,827 18,472 Due to the rate-making process, adjustments for Other 20 214 27 500 unrealized gains and losses are not reported in Total Regulatory Assets ~458 525 ~402 107 equity but result in adjustments to regulatory assets Regulatory Liabilities:

and liabilities. Deferred Investment Tax Credits $ 155,202 $ 164,206 Other* 1 576 350 Other Property and Investments Total Regulatory tiaailitiaa ~t56 770 ~164 556

• Included in Deferred Credits on Consolidated Balance Other property and investments are stated at Sheets.

Cost.

The Rockport Plant consists of two 1,300 mega-Reclassifications watt (mw) coal-fired units. IS.M and AEP Generat-ing Company (AEGCo), an affiliate, each own 50%

Certain prior-period amounts were reclassified to of one unit (Rockport 1) and lease a 50% interest conform with current-period presentation. in the other unit (Rockport 2) from unaffiliated lessors under an operating lease. The gain on the sale and leaseback of Rockport 2 was deferred and

2. EFFECTS OF REGULATION AND PHASE-IN is being amortized, with related taxes, over the PLANS: initial lease term which expires in 2022.

The consolidated financial statements include Rate phase-in plans in the Company's Indiana and assets and liabilities recorded in accordance with FERC jurisdictions for its share of Rockport 1 regulatory actions in order to match expenses with provide for the recovery and straight-line amortiza-the related revenues included in cost-based regu- tion through 1997 of prior-year deferrals. Unamor-lated rates. Regulatory assets are expected to be tized deferred amounts under the phase-in plans recovered in future periods through the rate-making were $ 27.5 million and $ 43.2 million at December process and regulatory liabilities are expected to 31, 1995 and 1994, respectively. Amortization reduce future cost recoveries. The Company has was $ 16 million in 1995, 1994 and 1993.

reviewed all the evidence currently available and concluded that it continues to meet the require-ments to apply SFAS 71. In the event a portion of 18

IANA MICHIGANPOWER COMPANY AND SUBSIDIARIES

3. COMMITMENTS AND CONTINGENCIES: territory. The lower court had dismissed the case filed under a provision of Indiana law that allows a Construction and Other Commitments utility to seek damages equal to the gross revenues received by the Company for rendering service in Substantial construction commitments have been the designated service territory of another utility.

made. Such commitments do not include any expenditures for new generating capacity. The The Company is involved in a number of other aggregate construction program expenditures for legal proceedings and claims. While management 1996-1998 are estimated to be $ 315 million. is unable to predict the ultimate outcome of litiga-tion, it is not expected that the resolution of these Long-term fuel supply contracts contain clauses matters will have a material adverse effect on the that provide for periodic price adjustments. The results of operations or financial condition.

retail jurisdictions have fuel clause mechanisms that provide for recovery of changes in the cost of fuel Nuclear Plant with the regulators'eview and approval. The contracts are for various terms, the longest of I@M owns and operates the two-unit 2,110 mw which extends to 2014, and contain various claus- Cook Plant under licenses granted by a regulatory es that would release the Company from its obliga- authority. The operation of a nuclear facility in-tion under certain force majeure conditions. volves special risks, potential liabilities, and specific regulatory and safety requirements. Should a Unit Power Agreements nuclear incident occur at any nuclear power plant facility in the United States, the resultant liability The Company is committed under unit power could be substantial. Sy agreement IS.M is partially agreements to purchase 70% of AEGCo's 1,300 liable together with all other electric utility compa-mw Rockport Plant capacity unless it is sold to nies that own nuclear generating units for a nuclear unaffiliated utilities. AEGCo has one long-term power plant incident. In the event nuclear losses or contract with an unaffiliated utility that expires in liabilities are underinsured or exceed accumulated 1999 for 455 mw of Rockport Plant capacity. funds and recovery is not possible, results of opera-tions and financial condition would be negatively The Company sells under contract up to 250 mw affected.

of Rockport Plant capacity to an unaffiliated utility.

The contract expires in 2009. Nuclear Incident Liability Litigation Public liability is limited by law to $ 8.9 billion should an incident occur at any licensed reactor in In September 1995, the Indiana Supreme Court the United States. Commercially available insur-ruled in favor of the Company when it denied an ance provides $ 200 million of coverage. In the appeal of a March 1995 opinion from the Court of event of a nuclear incident at any nuclear plant in Appeals of Indiana. The appeals court had upheld the United States the remainder of the liability and affirmed a lower court's decision. The case would be provided by a deferred premium assess-resulted from an earlier Supreme Court of Indiana ment of $ 79.3 million on each licensed reactor decision which overruled a lower court decision and payable in annual installments of $ 10 million. As a voided an IURC order assigning a customer to the result, IRM could be assessed $ 158.6 million per Company. The Company had received approxi- nuclear incident payable in annual installments of mately $ 29 million in gross revenues from the $ 20 million. The number of incidents for which customer which was not in the Company's service payments could be required is not limited.

19

Nuclear insurance pools and other insurance . spent nuclear fuel disposal program. Continued policies provide $ 3.6 billion of property damage, delays in the federal fuel disposal program can decommissioning and decontamination coverage for result in increased decommissioning costs.

Cook Plant. Additional insurance provides coverage Decommissioning costs are being recovered in the for extra costs resulting from a prolonged acciden- three rate-making jurisdictions based on at least the tal Cook Plant outage. Some of the policies have lower end of the range in the most recent decom-deferred premium provisions which could be trig- missioning study at the time of the last rate pro-gered by losses in excess of the insurer's ceeding. The Company records decommissioning resources. The losses could result from claims at costs in other operation expense and records a the Cook Plant or certain other non-affiliate nu- noncurrent liability equal to the decommissioning clear units. The Company could be assessed up to cost recovered in rates which was $ 30 million in

$ 40.9 million annually under these policies. 1995, $ 26 million in 1994 and $ 13 million in 1993.

Decommissioning amounts recovered from custom-Spent Nuclear Fuel Disposal ers are deposited in external trusts. Trust fund earnings increase the fund assets and the recorded Federal law provides for government responsibility liability and decrease the amount to be recovered for permanent spent nuclear fuel disposal and from ratepayers. At December 31; 1995 the assesses nuclear plant owners fees for spent fuel Company has recognized a decommissioning disposal. A fee of one mill per kilowatthour for fuel liability of $ 269 million.

consumed after April 6, 1983 is being collected from customers and remitted to the U.S. Treasury.

Fees and related interest of $ 163 million for fuel 4. RELATED PARTY TRANSACTIONS:

consumed prior to April 7, 1983 have been record-ed as long-term debt. IRM has not paid the govern- Benefits and costs of the System's generating ment the pre-April 1983 fees due to various factors plants are shared by members of the Power Pool.

including continued delays and uncertainties related The Company is a member of the Power Pool.

to the federal disposal program. At December 31, Under the terms of the System Interconnection 1995, funds collected from customers to eventually Agreement, capacity charges and credits are de-pay the pre-April 1983 fee and related earnings signed to allocate the cost of the System's capacity including accrued interest approximated the liability. among the Power Pool members based on their relative peak demands and generating reserves.

Decommissioning and Low Level Waste Accumula- Power Pool members are also compensated for the tion Disposal out-of-pocket costs of energy delivered to the Power Pool and charged for energy received from Decommissioning costs are accrued over the the Power Pool. The Company is a net supplier to service life of the Cook Plant. The licenses to the pool and, therefore, receives net capacity operate the two nuclear units expire in 2014 and credits from the Power Pool.

2017. After expiration of the licenses the plant is expected to be decommissioned through disman- Operating revenues includes revenues for supply-tlement. The Company's latest estimate for decom- ing energy and capacity to the Power Pool as missioning and low level radioactive waste follows:

accumulation disposal costs range from $ 634 Year Ended Oecember 31 million to $ 988 million in 1993 nondiscounted 1995 1994 1993 dollars. The wide range is caused by variables in (in thousands) assumptions including the estimated length of time Capacity Revenues $ 59,918 $ 88,183 $ 86,050 spent nuclear fuel must be stored at the plant Energy Revenues 83 799 52 274 118 533 subsequent to ceasing operations which depends Total ~l43 717 ~l40 457 ~204 583 on future developments in the federal government's 20

IANA MICHIGANPOWER COMPANY AND SUBSIDIARIES Purchased power expense includes charges of American Electric Power Service -Corporation

$ 25.4 million in 1995, $ 33.1 million in 1994 and {AEPSC) provides certain managerial and profes-

$ 20.9 million in 1993 for energy received from the sional services to AEP System companies. The Power Pool. costs of the services are billed by AEPSC on a direct-charge basis to the extent practicable and on Power Pool members share in wholesale sales to reasonable bases of proration for indirect costs.

unaffiliated utilities made by the Power Pool. The The charges for services are made at cost and Company's share of the Power Pool wholesale sales include no compensation for the use of equity included in operating revenues were $ 52.6 million capital, which is furnished to AEPSC by AEP Co.,

in 1995, $ 54.1 million in 1994 and $ 57 million in Inc. Billings from AEPSC are capitalized or 1 993. expensed depending on the nature of the services rendered. AEPSC and its billings are subject to the In addition, the Power Pool purchases power from regulation of the SEC under the 1935 Act.

unaffiliated companies for immediate resale to other unaffiliated utilities. The Company's share of these purchases was included in purchased power ex- 5. BENEFIT PLANS:

pense and totaled $ 10.7 million in 1995, $ 14.2 million in 1994 and $ 5.1 million in 1993. Revenues The Company and its subsidiaries participate in from these transactions including a transmission fee the AEP System pension plan, a trusteed, noncon-are included in the above Power Pool wholesale tributory defined benefit plan covering all employ-operating revenues. ees meeting eligibility requirements. Benefits are based on service years and compensation levels.

The cost of power purchased from AEGCo, an Pension costs are allocated by first charging each affiliated company that is not a member of the System company with its service cost and then Power Pool, was included in purchased power allocating the remaining pension cost'in proportion expense in the amounts of $ 85.2 million, $ 82.4 to its share of the projected benefit obligation. The million and $ 78.9 million in 1995, 1994 and 1993, funding policy is to make annual trust fund contri-respectively. butions equal to the net periodic pension cost up to the maximum amount deductible for federal income The Company operates the Rockport Plant and taxes, but not less than the minimum required bills AEGCo for its share of operating costs. contribution in accordance with the Employee Retirement Income Security Act of 1974.

AEP System companies participate in a transmis-sion equalization agreement. This agreement Net pension costs for the years ended December combines certain AEP System companies'nvest- 31, 1995, 1994 and 1993 were $ 2.7 million, $ 5 ments in transmission facilities and shares the costs million and $ 4.7 million, respectively.

of ownership in proportion to the System compa-nies'espective peak demands. Pursuant to the An employee savings plan is offered which allows terms of the agreement, other operation expense participants to contribute up to 17% of their sala-includes equalization credits of $ 46.7 million, $ 50.3 ries into various investment alternatives, including million and $ 47.4 million in 1995, 1994 and 1993, AEP Co., lnc. common stock. An employer match-respectively. ing contribution, equaling one-half of the employees'ontribution to the plan up to a maxi-Revenues from providing barging services were mum of 3% of the employees'ase salary, is recorded in nonoperating income as follows: invested in AEP Coed Inc. common stock. The employer's annual contributions totaled $ 3.9 million Year Ended December 31 in 1995 and 1994 and S3.5 million in 1993.

1995 1994 1993 (in thousands)

Affiliat,ed Companies $ 23,160 $ 24,001 $ 21,332 Unaffiltaaed Cnepanlea 5 992 5 021 5 757 Total ~30 152 ~29 022 ~27 099 21

Postretirement benefits other than pensions passed by Congress which would have significantly (OPEB) are provided for retired employees under an reduced the tax benefits of a COLI program in the AEP System plan. Substantially all employees are future. The legislation containing this provision eligible for postretirement health care and life was vetoed by the President. At this time it is insurance if they have at least 10 service years and uncertain if legislation repealing certain tax benefits are age 55 or older when employment terminates. for COLI programs will be enacted. If enacted this legislation would negatively impact the effective-SFAS 106, "Employers'ccounting for ness of the COLI program as a funding and cost Postretirement Benefits Other Than Pensions" was reduction mechanism.

adopted in January 1993 for the Company's aggre-gate liability for OPEB. SFAS 106 requires the The funding policy is to make VEBA trust fund accrual during the employee's service years of the contributions equal to the increase in OPEB costs present value liability for OPEB costs. Costs for the resulting from the implementation of SFAS 106.

accumulated postretirement benefits earned and not These contributions include amounts collected from recognized at adoption are being recognized, in ratepayers and the net earnings from the COLI pro-accordance with SFAS 106, as a transition obliga- gram. Contributions to the VEBA trust fund were tion over 20 years. OPEB costs are determined by $ 10.3 million in 1995, 86.6 million in 1994 and the application of AEP System actuarial assump- 81.3 million in 1993.

tions to each operating company's employee complement. The annual accrued OPEB costs for employees and retirees required by SFAS 106, 6. SUPPLEMENTARy INFORMATION:

which includes the recognition of one-twentieth of the prior service transition obligation, were $ 13.6 Year Ended Oecember 31 million in 1995, $ 13.2 million in 1994 and $ 12.4 1995 1994 1993 million in 1993. (in thousands)

Cash was paid for:

The Company received approval from the IURC to Interest (net of recover the increased OPEB costs resulting from capitalized amounts) $ 71,457 $ 68,946 $ 82,509 Income Taxes 88,675 85,854 68,303 SFAS 106. In the Michigan and wholesale juris-dictions, the Company received authority to defer Noncash Acquisitions under certain conditions the increased OPEB costs Under Capital which are not being currently recovered in rates. Leases were 32,073 92,199 15,467 Future recovery of any deferrals and increased In connection with the sale of western coal land OPEB costs will be sought in the next base rate and equipment the Company will receive cash filings. At December 31, 1995 and 1994, $ 6.7 payments from the buyer of $ 31.6 million over a six million of incremental OPEB costs were deferred. year period which has been recorded at a net present value of $ 26.9 million. In connection with As a result of SFAS 106, a Voluntary Employees construction of facilities to provide service to a new Beneficiary Association (VEBA) trust fund for OPEB customer the Company will receive cash payments benefits was established and a corporate owned life of $ 20.9 million plus accrued interest over 20 insurance (COLI) program was implemented to years.

lower the net OPEB costs. The insurance policies have a substantial cash surrender value which is recorded, net of equally substantial policy loans, in other property and investments. Legislation was 22

IANA MICHIGANPOWER COMPANY AND SUBSIDIARIES

7. FEDERAL INCOME TAXES:

The details of federal income taxes as reported are as follows:

Year Ended December 31 1995 1994 1993 (in thousands)

Charged (Credited) to Operating Expenses (net):

Current $ 75,686 $ 64,565 $ 93,974 Deferred (13,732) (18,057) (53,685)

Deferred Investment Tax Credits ~7929 ) ~8)55) ~8308)

Total 54 025 38 353 31 981 Charged (Credited) to Nonoperating Income (net):

Current 12,872 1,390 6,026 Deferred (9,832) (1,718) 1,054 Deferred Investment Tax Credits ~)075) ~5722) ~235)

Total 1 965 ~6050) 6 845 Total Federal Income Taxes as Reported ~55 990 ~32 303 ~38 826 The following is a reconciliation of the difference between the amount of federal income taxes computed by multiplying book income before federal income taxes by the statutory tax rate, and the amount of federal income taxes reported.

Year Ended December 31 1995 1994 1993 (in thousands)

Net Income $ 141,092 $ 157,502 $ 129,344 Federal Income Taxes 55 990 32 303 38 826 Pre-tax Book Income ~)97 082 ~)89 805 ~168 170 Federal Income Tax on Pre-tax Book Income at Statutory Rate (35K) $ 68,979 $ 66,432 $ 58,860 Increase (Decrease) in Federal Income Tax Resulting From the Following Items:

Depreciation 8,954 (1,033) (747)

Adoption of SFAS 109 5,271 Corporate Owned Life Insurance (5,187) (4,521) (4,697)

Nuclear Fuel Disposal Costs (3,060) (4,498) (2,432)

Amortization of Deferred Investment Tax Credits (net) (9,004) (13,875) (8,543)

Other ~4692) ~10 202) ~8886)

Total Federal Income Taxes as Reported ~55 990 ~32 303 ~38 826 Effective Federal Income Tax Rate 28.4'A 17.0X 23. I'A 23

The following tables show the elements of the net At December 31, 1995 and 1994 the fair values deferred tax liability and the significant temporary of trust investments were $ 434 million and $ 353 differences that gave rise to it: million, respectively. Accumulated gross unrealized December 31 holding gains and losses were $ 19.1 million and 1995 1994 $ 1.0 million, respectively, at December 31, 1995.

(in thousands) The change in market value during 1995 and 1994 Deferred Tax Assets $ 221,604 $ 198,750 was a $ 24.9 million net holding gain and a $ 27.1 0eferred Tax Liabllitlea ~833 751) ~833 652) million net holding loss, respectively.

liat 0eferred Tax Llabilitlea ~612 147) ~634 902)

Temporary Differences The trust investments'ost basis by security type in Tax Dollars: were:

Property Related December 31 Temporary Differences $ (490,986) $ (498,124) 1995 1994 Amounts Due From Customers (in thousands)

For Future Federal Income Taxes (83,277) (81,812) Treasury bonds $ 14,963 $ 997 Deferred State Income Taxes (71,712) (71,712) Tax-exempt bonds 336,073 332,098 Deferred Net Gain- Equity securities 24,101 1,665 Rockport Plant Unit 2 34,941 36,239 Cash, cash equivalents All Other (net) ~))13) ~)9 493) and interest accrued 40 356 25 304 Total Net Deferred Total ~4)5 493 ~360 064 Tax Liabilities ~6)2 147) ~634 902)

Proceeds from sales and maturities of securities of The Company and its subsidiaries join in the filing $ 78.2 million during 1995 resulted in $ 1.4 million of a consolidated federal income tax return with of realized gains and $ 0.3 million of realized losses.

their affiliates in the AEP System. The allocation of Proceeds from sales and maturities of securities of the AEP System's current consolidated federal $ 20l1 million during 1994 resulted in $ 52,000 of income tax to the System companies is in accor- realized gains and $ 155,000 of realized losses. The dance with SEC rules under the 1935 Act. These cost of securities for determining realized gains and rules permit the allocation of the benefit of current losses is original acquisition cost including amor-tax losses to the System companies giving rise to tized premiums and discounts.

them in determining their current tax expense. The tax loss of the System parent company, AEP Coed At December 31, 1995, the year of maturity of Inced is allocated to its subsidiaries with taxable trust fund investments, other than equity securities, income. With the exception of the loss of the was:

parent company, the method of allocation approxi- (in thousands) mates a separate return result for each company in the consolidated group. 1996 $ 55,748 1997-2000 96,882 2001-2005 162,563 The AEP System has settled with the Internal After 2005 76 199 Revenue Service (IRS) all issues from the audits of Total ~39) 392 the consolidated federal income tax returns for the years prior to 1991. Returns for the years 1991 Other Financial Instruments Recorded at Historical through 1993 are presently being audited by the Cost IRS. In the opinion of management, the final settlement of open years will not have a material The carrying amounts of cash and cash equiva-effect on results of operations. lents, accounts receivable, short-term debt, and accounts payable approximate fair value because of the short-term maturity of these instruments. Fair

8. FAIR VALUE OF FINANCIALINSTRUMENTS: values for preferred stocks subject to mandatory redemption were $ 140 million and $ 117 million and Nuclear Trust Funds Recorded at Market Value for long-term debt were $ 1.1 billion and $ 1.0 billion at December 31, 1995 and 1994, respectively.

The trust investments are recorded at market The carrying amounts for preferred stock subject to value in accordance with SFAS 115 and consist mandatory redemption were $ 135 million at each primarily of tax-exempt municipal bonds. year end and for long-term debt were $ 1.0 billion

IANA MICHIGANPOWER COMPANY AND SUBSIDIARIES and $ 1.1 billion at December 31, 1995 and 1994, The noncurrent portion of capital lease obliga-res'pectively. Fair values are based on quoted tions is included in other noncurrent liabilities.

market prices for the same or similar issues and the current dividend or interest rates offered for instru- Properties under operating leases and related ments of the same remaining maturities. The obligations are not included in the Consolidated carrying amount of the pre-April 1983 spent nuclear Balance Sheets.

fuel disposal liability approximates the Company's best estimate of its fair value. Lease rentals are generally charged to operating expenses in accordance with rate-making treat-ment. The components of rental costs are as

9. LEASES: follows:

Year Ended Oecember 31 Leases of property, plant and equipment are for 1995 1994 1993 periods up to 35 years and require payments of (in thousands) related property taxes, maintenance and operating Operating Leases $ 96,472 $ 104,519 $ 103,884 costs. The majority of the leases have purchase or Amortization of renewal options and will be renewed or replaced by Capital Leases 45,843 30,875 46,063 other leases. interest on Capital Leases 9 987 7 643 8 873 Total Rental Properties under capital leases and related obliga- Costs ~752 302 ~743 037 ~758 820 tions recorded on the Consolidated Balance Sheets are as follows: Future minimum lease payments consisted of the Oecember 31 following at December 31, 1995:

1995 1994 Non-(in thousands) Cancelable Capital Operating Electric Utility Plant: Leases Leases Production $ 9,346 $ 8,371 (in thousands)

Oistribution 14,753 14,717 General: 1996 $ 13,765 $ 98,357 Nuclear Fuel 1997 12,518 96,593 (net of amortization) 69,442 89,478 1998 10,620 91,454 Other 54 554 53 781 1999 9,389 91,312 Total Electric Utility 2000 8,275 91,165 Plant 148,095 166,347 Later Years 44 362 1 840 723 Accumulated Amortization 24 933 27 225 Net Electric Utility Total Future Minimum Plant 123 162 139 122 Lease Payments 98,929(a) ~2 309 604 Other Property 22,361 15,842 Less Estimated Accumulated Amortization 3 017 2 375 Interact Element 25 865 Net Other Property 19 344 13 467 Net Properties under Estimated Present Capital Leases 142 506 152 589 Value of Future Minimum Lease Capital Lease Obligations: Payments 73,064 Noncurrent Liability $ 110,730 $ 113,586 Unamortized Nuclear Liability Oue Mithin Fuel 69 442 One Year 31 776 39 003 Total ~742 506 Total Capital Lease Obligations ~742 506 ~752 589 (a) Excludes nuclear fuel rentals which are paid in proportion to heat produced and carrying charges on the unamortized nuclear fuel balance. There are no minimum lease payment requirements for -leased nuclear fuel.

25

10. CUMULATIVEPREFERRED STOCK:

At December 31, 1995, authorized shares of cumulative preferred stock were as follows:

Par Value Shares Authorized

$ 100 2,250,000 25 11,200,000 The cumulative preferred stock is callable at the price indicated plus accrued dividends. The involuntary liquidation preference is par value. Unissued shares of the cumulative preferred stock may or may not possess mandatory redemption characteristics upon issuance. During 1994 the Company redeemed and cancelled 350,000 shares of the 7.76% series. During 1993 the Company redeemed and cancelled the following entire series: 8.68% series consisting of 300,000 shares and $ 2.15 and $ 2.25 series each consisting of 1,600,000 shares.

A. Cumulative Preferred Stock Not Subject to Mandatory Redemption:

Call Price Shares Amount December 31, Par Outstanding Oecember 31 Series 1995 Value Oecember 31 1995 1995 1994 (in thousands) 4-1/BX $ 106.125 $ 100 120,000 $ 12,000 $ 12,000 4.56K 102 100 60,000 6,000 6,000

4. 102.728 100 40,000 4,000 4,000 30 12'.

OBIO 101.85 100 300,000 3D ODO ODO

~52 OOD ~52 ODO B. Cumulative Preferred Stock Subject to Mandatory Redemption:

Shares Amount Par Outstanding Oecember 31 Series(a) Value December 31 1995 1995 1994 (in thousands) 5.90! (b) $ 100 400,000 $ 40,000 $ 40,000 6-1/4X(c) 100 300,000 30,000 30,000 6.30K (d) 100 350,000 35,000 35,000 6-7/BX(e) 100 300,000 30 ODD 30 ODD

~235 000 ~135 000 (a) Not callable until after 2002. Thoro are no aggregate sinking fund provisions through 2002.

(b) Shares issued November 1993. Commencing in 2004 and continuing through the year 2008, a sinking fund will require tho redemption of 20,000 shores each year and tho redemption of tho remaining shares outstanding on January 1, 2009, in each case at S100 pef share.

(c) Shares issued November 1993. Commencing in 2004 and continuing through tho year 2008, a sinking fund will require the redemption of 15,000 shares each year and tho redemption of the remaining shares outstanding on April 1, 2009, in each case at $ 100 por share.

(d) Shares issued February 1994. Commencing in 2004 and continuing through the year 2008, a sinking fund will require the redemption of 17,500 shares each year and the redemption of tho remaining shares outstanding on July 1, 2009, in each case at S100 per share.

(e) Shares issued February 1993. Commencing in 2003 and continuing through tho year 2007, a sinking fund will require the redemption of 15,000 shores each year and the redemption of the remaining shares outstanding on April 1, 2008, in each case at S100 per share.

26

0 ANA MICHIGANPOWER COMPANY AND SUBSIDIARIES

11. LONG-TERIVI DEBT AND LINES OF CREDIT: Installment purchase contracts have been entered into in connection with the issuance of pollution Long-term debt by major category was out- control revenue bonds by governmental authorities standing as follows: as follows:

December 31 1995 1994 Oecember 31 (in thousands) 1995 1994 (in thousands)

First Mortgage Bonds $ 562,017 $ 561,770 Installment Purchase ~Rate Oue Contracts 308,971 308,087 City of Lawrenceburg, Indiana:

Other Long-term Oebt(a) 163,060 153,977 7 2015 - April 1 $ 25,000 $ 25,000 Notes Payable to Banks 40,000 5.9 2019 - November 1 52,000 52,000 Sinking Fund Oebentures(b) 6 053 6 053 City of Rockport, Indiana:

1,040,101 1,069,887 9-1/4 2014 - August 1 50,000 Less Portion Oue Within 6-3/4 2014 - August 1 50,000 One Year 6 053 140 000 (a) 2014 - August 1 50,000 50,000 7.6 2016 - Harch 1 40,000 40,000 Total ~1034 040 ~929 807 6.55 2025 - June 1 50,000 (b) 2025 - June 1 50,000 (a) Nuc(ear Fuel Disposal Costs including interest accrued. See City of Sullivan, Indiana:

Nots 3. 5.95 2009 - Hay 1 45,000 45,000 (b) Called for redemption on March 1, 1996. Unamortized Oiscount ~3029 ~3913

) )

308,971 308,087 First mortgage bonds outstanding were as fol- Less Portion Oue lows: Within One Year Oecember 31 100 000 1995 1994 (in thousands) Total ~300 971 ~200 007 I Rate Oue (a) The variable interest rate is determined The average weighted interest rate was 4.6X weekly.

for 1995 7 1998 - May 1 $ 35,000 $ 35,000 and 3.8X for 1994.

7.30 1999 - Oecember 15 35,000 35,000 (b) The adjustable interest rate can be a daily, 7.63 2001 - June 1 40,000 40,000 weekly, contnercial paper or term rate as designated by 7.60 2002 - November 1 50,000 50,000 the Company. Initially, a weekly rate was selected 7.70 2002 - Oecember 15 40,000 40,000 during 1995 which ranged from 2.9X to SX and averaged 6.80 2003 - July 1 20,000 20,000 4.0X.

6.55 2003 - October 1 20,000 20,000

6. 10 2003 - November 1 30,000 30,000 Under the terms of certain installment purchase 6.55 2004 - Harch I 25,000 25,000 contracts, the Company is required to pay amounts 9.50 2021 - Hay 1 10,000 10,000 sufficient to enable the cities to pay interest on and 9.50 2021 - Hay 1 10,000 10,000 the principal (at stated maturities and upon mandatory 9.50 2021 - May 1 20,000 20,000 8.75 2022 - May 1 50,000 50,000 redemption) of related pollution control revenue bonds 8.50 2022 - December 15 75 000 F 75,000 issued to finance the construction of pollution control 7.80 2023 - July 1 20,000 20,000 facilities at certain generating plants. On the two 7.35 2023 - October 1 20,000 20,000 variable rate series the principal is payable at the 7.20 2024 - February 1 40,000 40,000 stated maturities or on the demand of the bondhoiders 7.50 2024 - March I 25,000 25,000 Unamortized Oiscount (net) ~2903) ~3230) at periodic interest adjustment dates which occur weekly. The variable rate bonds due in 2014 are Total ~562 017 ~56) 770 supported by a bank letter of credit which expires in 2002. I&M has agreements that provide for brokers Certain indentures relating to the first mortgage to remarket the variable rate bonds due in 2025 bonds contain improvement, maintenance and re- tendered at interest adjustment dates. In the event placement provisions requiring the deposit of cash certain bonds cannot be remarketed, I&M has a or bonds with the trustee, or in lieu thereof, certifi- standby bond purchase agreement with a bank that cation of unfunded property additions.

27

provides for the bank to purchase any bonds not 12. COMMON SHAREHOLDER'S remarketed. The purchase agreement expires in 2000.

Accordingly, the variable rate installment purchase Mortgage indentures, debentures, charter provi-contracts have been classified for repayment purposes sions and orders of regulatory authorities place EQUITY'he based on the expiration dates of the standby purchase various restrictions on the use of retained earnings agreement and the letter of credit. for the payment of cash dividends on common stock. At December 31, 1995, $ 5.9 million of At December 31, 1995, annual long-term debt retained earnings were restricted. Regulatory payments, excluding premium or discount, are as approval is required to pay dividends out of paid-in follows:

capital.

Princi al Amount (in thousands)

Company received from AEP Co., Inc. a cash 1996 $ 6,053 capital contribution of $ 10 million in 1993 which 1997 was credited to paid-in capital In 1995, 1994 and

~

1998 35,000 1999 35,000 1993 net charges to paid-in capital of $ 2,548,000, 2000 50,000 $ 422,000 and $ 1,224,000, respectively, repre-Later Years 920 060 sented expenses of issuing and retiring cumulative Total 1 046 113 preferred stock. There were no other transactions Short-term debt borrowings are limited by provi- affecting the common stock and paid-in capital sions of the 1935 Act to $ 175 million. Lines of accounts in 1995, 1994 and 1993.

credit are shared with AEP System companies and at December 31, 1995 and 1994 were available in the amounts of $ 372 million and $ 558 million, 13. UNAUDITED QUARTERLY FINANCIALINFOR-respectively. Commitment fees of approximately IVIATION:

1/8 of 17% of the unused short-term lines of credit are paid each year to the banks to maintain the Iiuarterly Periods Operating Operating Net tnded Revenues Income Income lines of credit. Outstanding short-term debt con- (in thousands) sisted of: 1995 Year-end Harch 31 $ 327,177 $ 56,311 $ 38,388 Balance Weighted June 30 307,820 51,386 33,780 Outstanding Average September 30 334,846 54,400 37,404 December 31 313,314 43,626 31,520 December 31, 1995:

Note Payable $ 52,200 6.1X 1994 Comnercial Paper 37 775 6.1 Harch 31 337,921 58,875 44,976 Total ~59 975 6.7 June 30 310,104 54,691 37,281 September 30 317,061 55,469 37,736 December 31, 1994: December 31 286,223 52,934 37,509 Comnercial Paper 50 600 6.3X 28

IANA MICHIGANPOWER COMPANY AND SIJBSIDIARIES OPERATING STATISTICS 1995 1994 1993 1992 1991 OPERATING REVENUES (In thousands):

Retail:

Residential:

Without Electric Heating 239,266 227,358 205,315 $ 209,682 206,257 With Electric Heating Total Residential 109 504 348,770 S

~107 52 334,881 S

97 568 302,883 98 553 308,235

~289 S

299,546 Commercial 256,319 247,938 220,938 228,285 216,303 Industrial Miscellaneous Total Retail

~42 298,256 909,827 291,527 i~1 880,662 250,939

~559 ~11 780,353 267,643 815,175 1 2 ~12 241,858 1

769,827 2

Wholesale (sales for resale) ~57 441 352 889 404 910 369 379 436 083 Total Revenues from Energy Sales 1,267,268 1,233,551 1,185,263 1,184,554 1,205,910 Provision for Refunds of Revenues Collected in Prior Years Total Net of Provision for Refunds

~7551 ~40381 5 176 1,267,268 1,233,551 1,184,508 1,180,516 1,211,086 Other 15 889 ~17 75 18 135 16 239 ~14 7 1 Total Operating Revenues 41 283 157 41 251 309 $1 202 643 ~1196 755 41 225 867 SOURCES AND SALES OF ENERGY (in millions of kilowatthours):

Sources:

Net Generated:

Fossil Fuel 12,850 13,022 12,236 11,597 12,109 Nuclear Fuel 13,999 9,291 16,313 6,418 15,524 Hydroelectric Total Net Generated

~8 26,935 22,408 100 28,655 10(}

18,115 1II9 27,742 Purchased and Power Pool 5 871 ~57 7 4 879 9 342 ~52 7 Total Sources 32,806 28,165 33,534 27,457 32,979 Less: Losses, Company Use, Etc. ~17 0 1 398 1 349 ~14 6 ~14 4 Net Sources 31 106 26 767 32 185 25 991 31 525 Sales:

Retail:

Residential:

Without Electric Heating 3,390 3,210 3,178 3,001 3,166 With Electric Heating 1 768 1 727 1 706 ~16 3 ~125 Total Residential 5,158 4,937 4,884. 4,634 4,791 Commercial 4,300 4,148 3,977 3,747 3,726 Industrial 6,582 6,453 6,025 5,685 5,382 Miscellaneous 82 82 83 194 ~23 Total Retail 16,122 15,620 14,969 14,260 14,132 Wholesale (sales for resale) 14 984 11 147 ~17 21 ~117 1 ~17',~9 Total Sales 31 106 26 767 32 185 25 991 31 525 29

OPERATING STATISTICS (Concluded) 1995 1 94 199 AVERAGE COST OF FUEL CONSUMED (in cents):

Per Million Btu:

Coal 126 124 130 136 141 Nuclear 43 42 36 54 48 Overall 78 85 72 103 84 Per Kilowatthour Generated:

Coal 1.23 1.21 1.27 1.34 1.39 Nuclear .47 .47 .40 .61 ~ 53 Overall .83 .90 .77 1.08 .91 RESIDENTIAL SERVICE - AVERAGES:

Annual Kwh Use per Customer:

With Electric Heating 18,044 17,907 17,980 17,513 17,702 Total 10,943 10,572 10,559 10,107 10,535 Annual Electric Bill:

With Electric Heating $ 1,117.55 $ 1,115.19 $ 1,028.26 $ 1,056.91 $ 1,016.16 Total $ 739.99 $ 717.17 $ 654.76 $ 672.31 $ 658.76 Price per Kwh (in cents):

With Electric Heating 6.19 6.23 5.72 6.04 5.74 Total 6.76 6.78 6.20 6.65 6.25 NUMBER OF CUSTOMERS:

Year-End:

Retail:

Residential:

Without Electric Heating 375,929 372,473 369,385 366,835 364,154 With Electric Heating QQ~3'i ~7~42 ~41 7 ~2~7 Total Residential 475,034 469,875 465,180 461,010 456,811 Commercial 55,077 53,927 53,081 52,542 51,491 Industrial 5,316 5,213 5,157 5,000 4,847 Miscellaneous ~17 7 ~10 ~17 ~17 ~222 Total Retail Wholesale (sales for resale)

Total Electric Customers

~2 537,224 537 286 530,821

~530 87 54 525,201 525257 520,303 520356 515,375 515428 30

Ig NA MICHIGANPOWER COMPANY AND SUBSIDIARIES DIVIDENDS AND PRICE RANGES OF CUMULATIVEPREFERRED STOCK By Quarters (1996 and 1994) 1995 - uarters 1994 - uarters 1st 2nd 3rd 4th 1st 2nd 3rd 4th CUMULAT(VE PREFERRED STOCK

($ 100 Par Value) 4-1/8/ Series Dividends Paid Per Share $ 1.03125 $ 1.03125 $ 1.03125 $ 1.03125 $ 1.03125 $ 1.03125 $ 1.03125 $ 1.03125 Market Price - $ Per Share (CSE) - High

- Low 4.56/, Series Dividends Paid Per Share $ 1.14 $ 1.14 $ 1.14 $ 1.14 $ 1.14 $ 1.14 $ 1.14 $ 1.14 Market Price - $ Per Share (OTC)

Ask - High

- Low Bid - High 46-5/8 47-1/4 47"1/2 49"1/2 55-5/8 54-1/8 50-5/8 46-1/8

- Low 45-1/2 46-1/4 47-1/4 47-1/2 49 45-1/2 45-1/2 45-1/2

4. 12K Series Dividends Paid Per Share $ 1.03 $ 1.03 $ 1.03 $ 1.03 $ 1.03 $ 1.03 $ 1.03 $ 1.03 Market Price - $ Per Share (OTC)

Ask - High

- Low Bid - High 46-1/2 47 51 51 58-1/2 54 48 48

- Low 43 46 46 46 51 46-1/2 46-1/8 43-1/2 5.90K Series Dividends Paid Per Share $ 1.475 $ 1.475 $ 1.475 $ 1.475 $ 1.475 $ 1.475 $ 1.475 $ 1.475 Market Price - $ Per Share (OTC)

Ask (high/low)

Bid (high/low) 6-1/4X Series Dividends Paid Per Share $ 1.5625 $ 1.5625 $ 1.5625 $ 1.5625 $ 1.5625 $ 1.5625 $ 1.5625 $ 1.5625 Market Price - $ Per Share (OTC)

Ask (high/low)

Bid (high/low) 6.30K Series (a)

Dividends Paid Per Share $ 1.575 $ 1.575 $ 1.575 $ 1.575 $ 0.9275 $ 1.575 $ 1.575 $ 1.575 Market Price - $ Per Share (OTC)

Ask (high/low)

Bid (high/low) 6-7/8/ Series Dividends Paid Per Share $ 1.71875 $ 1.71875 $ 1.71875 $ 1.71875 $ 1.71875 $ 1.71875 $ 1.71875 $ 1.71875 Market Price - $ Per Share (OTC)

Ask (high/low)

Bid (high/low) 7.08K Series Dividends Paid Per Share $ 1.77 $ 1.77 $ 1.77 $ 1.77 $ 1.77 $ 1.77 $ 1.77 $ 1.77 Market Price - $ Per Share (MYSE) - High 83-5/8 88-1/2 91 99"1/2 97-1/2 95 87-1/2 80

- Low 76 84 86 86 94 83 80 76 31

INDIANAMICHIGANPOWER COMPANY DIVIDENDS AND PRICE RANGES OF CUMULATIVEPREFERRED STOCK By Quarters (1995 and 1994) (Concluded) 1995 - uarters 1994 - uarters 1st 2nd 3rd 4th 1st 2nd 3rd 4th CUMULATIVE PREFERRED STOCK

($ 100 Par Value) 7.76K Series (Redeened)

Dividends Paid Per Share $ 0.9054 Market Price - $ Per Share (NYSE) - High 101

- Low 100 CSE - Chicago Stock Exchange OTC - Over-the-Counter NYSE - New York Stock Exchange Note - The above bid and asked quotations represent prices between dealers and do not represent actual transactions.

Market quotations provided by National quotation Bureau, Inc.

Bash indicated quotation not available.

(a) Issued February 1994 SECURITY OWNER INQUIRIES Security owners should direct their inquiries to the Security Owner Relations Division using the toll free number:

1-800-AEP-COMP (1-800-237-2667) or by writing to:

Bette Jo Rozsa Security Owner Relations Division American Electric Power Service Corporation 28th Floor 1 Riverside Plaza Columbus, OH 43215-2373 FORM 10-K ANNUALREPORT The Annual Report (Form 10-K) to the Securities and Exchange Commission will be available in April 1996 at no cost to shareholders. Please address such requests to:

Geoffrey C. Dean American Electric Power Service Corporation 27th Floor 1 Riverside Plaza Columbus, OH 43215-2373 TRANSFER AGENT AND REGISTRAR OF CUMULATIVEPREFERRED STOCK First Chicago Trust Company of New York P.O. Box 2534 Suite 4692 Jersey City, NJ 07303-2534 32

Indiana Michigan Power Service Area and the American Electric Power System LAKE MICHIGAN MICHIGAN IAKE ERIE OHIO INDIANA WEST VI RGINIA VI RG IN IA KENTUCKY Indiana Michigan Power Co. area Other AEP operating companies'reas g Major power plant TENNESSEE Cl+ prinied on recycled paper

ATTACHMENT 2 TO AEP NRC'0909L INDIANA MICHIGAN POWER COMPANY'S PROJECTED CASH FLOW FOR 1996

Indiana Michigan Power Co. Revision 1 1996 Forecasted Sources and Uses of Funds Based on Forecasted Case 9600

$ Millions Projected 1996 Net Income After Taxes 150.0 Less Dividends Paid 122.3 Retained Earnings 27.7 Adjustments:

Depreciation And Amortization 153.8 Deferred Operating Costs 9.8 Deferred Federal Income Taxes and Investment Tax Credits (29.2)

AFUDC (1.5)

Other (9.2)

Total Adjustments 123.7 Internal Cash Flow 151.4 Average Quarterly Cash Flow 37.9 Average Cash Balances and Short-Term Investments 0.5 Total 38.4

p: 4