ML17333A870

Indiana Michigan Power Co Annual Rept for 1996

ML17333A870
Person / Time
Site:	Cook
Issue date:	12/31/1996
From:	Fitzpatrick E INDIANA MICHIGAN POWER CO.
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
AEP:NRC:0909M, AEP:NRC:909M, NUDOCS 9704290273
Download: ML17333A870 (43)

Text

CATEGORY j.

,REGULATO 1NFORMATION DISTRIPUTION TEM (RIDS)

ACCESSION NBR:9704290273 DOC.DATE: +~~

NOTARIZED:'NO DOCKET I FACIL:50-315. Dona'ld C.

Cook Nuclear Power Plant, Unit 1, Indiana M

05000315 j'0-316 Donald C.

Cook Nuclear.Power Plant, Unit 2, Indiana M

05000316 AUTH.'NAME AUTHOR AFFILIATION FITZPATRICK,E.

Indiana Michigan Power Co.

RECIP.NAME RECIPIENT AFFILIATION

SUBJECT:

"Indiana Michigan Power Co Annual Rept for 1996."

W 970418 ltr.

DZSTRZBUTZON CODE:

M004D COPZES"RECEZVED:LTR I

ENCL 1

SIZE: Q TITLE: 50.71(b)

Annual Financial Report NOTES:

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E RECIPIENT ID CODE/NAME PD3-3 LA HICKMAN,J INTERN

. FILE CE E

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N NOTE TO ALL "RIDS" RECIPIENTS:

PLEASE HELP US TO REDUCE WASTE.

TO HAVE YOUR NAME OR ORGANIZATION REMOVED FROM DISTRIBUTION LISTS OR REDUCE THE NUMBER OF COPIES RECEIVED BY YOU OR YOUR ORGANIZATION, CONTACT THE DOCUMENT CONTROL DESK (DCD)

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I

Indiana Michigan Power Company 500 Circle Drive Buchanan, Ml 491071395 R

ENOMMA SIICHIGAN PQWJFR April 18, 1997 AEP:NRC:0909M 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 Indiana Michigan Power Company's annual report for 1996.

Attachment 2 contains a copy of Indiana Michigan Power Company's projected cash flow for 1997.

These reports are submitted pursuant to 10 CFR 50.71(b) and 10 CFR 140.21(e).

Sincerely, E.

E. Fitzpatrick Vice President vlb Attachments'C:

A. A. Blind A. B. Beach MDEQ -

DW & RPD NRC Resident Inspector J.

R. Padgett IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII

~/

.9704290273 96123f POR ADQCK 050003i5 I

PDR

ATTACHMENT 1 TO AEP:NRC:0909M INDIANA MICHIGAN POWER COMPANY' ANNUAL REPORT FOR 1996

1 996 Annual Report

I NA MICHIGANPOWER COMPANY AND SUBSIDIARIES One Summit Square, P.O. Box 60, Fort Wayne, Indiana 46801 ONTENTS Background..

Directors and Officers 3

Selected Consolidated Financial Data

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5-10 Independent Auditors'eport Consolidated Statements of Income 12 Consolidated Statements of Cash Flows

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1 3 Consolidated Balance Sheets

~ 14-15 Consolidated Statements of Retained Earnings

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1 6 Notes to Consolidated Financial Statements 17-29 Operating Statistics ividends and Price Ranges of Cumulative Preferred Stock 30-31 32

e BACKGROUND INDIANAMICHIGANPOWER COMPANY (the Company) is engaged in the generation, purchase, transmissi and distribution of electric power.

The Company serves approximately 542,000 retail customers in northern an eastern Indiana and a portion of southwestern Michigan and sells and transmits power at wholesale to other electric utilities, municipalities, electric cooperatives and non-utility entities engaged in the wholesale power market.

Approximately 83% of the Company's retail sales are in Indiana and 17% in Michigan. The principal industries served are primary metals, transportation equipment, electrical and electronic machinery, fabricated metal products, rubber and miscellaneous plastic products and chemicals and allied products.

The Company, which was organized under the laws of Indiana on February 21, 1925, is a subsidiary of American Electric Power Company, lnc., a public utilityholding company.

The Company does 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 aligned by distinct business units.

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.

The RTD also provides some barging services to unaffiliated companies.

The Company owns and leases 4,435 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 utilitysubsidiaries 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 Company and the other Pool members.

The other AEP System Pool members are:

Appalachian Power Company, Columbus Southern Power Company, Kentucky Power Company and Ohio Pow Company.

The Company is interconnected with two other affiliated companies, Kingsport Power Company a Wheeling Power Company that are not members of the Power Pool, and with numerous unaffiliated utilities throug the AEP System.

In addition, 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 Energy Corporation, Illinois Power Company, Indianapolis Power

&. 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).

INDIA ~

MICHIGANPOWER COMPANy AND SUBSIDIARIES DIRECTORS Coulter R. Boyle, III Gregory A. Clark Peter J. DeMaria William N. D'Onofrio E. Linn Draper, Jr.

William J. Lhota Gerald P. Maloney James J. Markowsky Albert H. Potter (a)

David B. Synowiec Dale M. Trenary Joseph H. Vipperman William E. Walters Earl H. Wittkamper (b)

OFFICERS E. Linn Draper Jr.

Chairman of the Board and Chief Executive Officer William J. Lhota President and Chief Operating Officer A. Alan Blind Site Vice President, Donald C. Cook Nuclear Plant Armando A. Pena Treasurer Elio Bafile Assistant Controller and Assistant Secretary Leonard V. Assante Assistant Controller Coulter R. Boyle, III Vice President Timothy P. Bowman (c)

Assistant Controller Peter J. DeMaria Vice President and Controller William L. Scott Assistant Controller Eugene E. Fitzpatrick Vice President Gerald P. Maloney Vice President James J. Markowsky Vice President Joseph H. Vipperman Vice President John M. Adams, Jr.

Assistant Secretary Robert G. Griffin (d)

Assistant Secretary Maurice C. Mclntyre (e)

Assistant Secretary John B. Shinnock Assistant Secretary John F. DiLorenzo, Jr.

Secretary Bruce M. Barber Assistant Treasurer Christopher J. Keklak Assistant Treasurer As ofJanuary 1, 1997 the current directors and officers of Indiana Michigan Power Company were employees ofAmerican Electric Power Service Corporation with eight eitceptionst Messrs. Bafile, Nind, Boyle, Clerk, Mclntyre, Trenary, Walters end Wt'ttkamper, who were employees ofIndiana Michigan Power Company.

tel Resigned Hovember 2O, 1996 lbl Gected Hovembor 20, 1996 tcl Gected June 1, 1996 ldl Reerened December 91, 1996 lel Gectod December 31, 1996

Selected Consolidated Financial Data INCOME STATEMENTS DATA:

(in thousands)

Operating Revenues Operating Expenses Operating Income Nonoperating Income (Loss)

Income Before Interest Charges Interest Charges Net Income Preferred Stock Dividend Requirements Earnings Applicable to Common Stock

$ 1,328,493

$ 1,283, 157

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$ 1,251,309

$ 1,202,643

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$ 1,196,755

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220,417 205,723

~23 221,969

~28 210,158 195,788

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~RK32Q 223,146

~i 'L93 229,397 209,924

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~LLGBQ 211,995

~K393 157,153

~~K581 141,092 3LZ31 157,502 129,344

~i6 123,983

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~1452)21

~2%088

~L531 BALANCESHEETS DATA:

(in thousands)

Electric UtilityPlant Accumulated Depreciation and Amortization Net Electric UtilityPlant

$4,377,669

$4,319,564

$4,269,306

$4,290,957

$4,266,480

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~5%8 4Q M515.226 M&~3 ~3.36fi M~%128 Total Assets Common Stock and Paid-in Capital Retained Earnings Total Common Shareholder's Equity 790,234 790,625

~%658 ~L93R 787,856

~iLQZ1 781,818 787,686

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Cumulative Preferred Stock:

Not Subject to Mandatory Redemption Subject to Mandatory Redemption (a)

Total Cumulative Preferred Stock 21,977 52,000 52,000 87,000 197,000

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Obligations Under Capital Leases (a)

Total Capitalization and Liabilities ie/ Including porrion due within one yeer.

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DIANAMICHIGANPOWER COMPANY ANDSUBSIDIARIES of stranded costs at the wholesale level, the issue of stranded cost recovery remains open at the much larger state retail level.

f With the issuance of two Federal Energy Regulatory Commission (FERC) orders and the commencement of planning for retail competition at the state level, we are in a better position to identify and develop strate-gies for addressing the issues that face the American Electric Power (AEP) System, Indiana Michigan Power Company and our changing industry. The industry's adjustment to greater competition in generation and sales of electricity, customer choice and the ability to fully recover costs will probably be the most signifi-cant factors affecting the Company's future profit-ability.

Although the Company, as a member of the AEP System, has the financial strength, geographic reach, location and cost structure to be an able competitor, no assurance can be given that this position can be maintained.

However, we intend to make every effort to maintain and strengthen our competitive position. We see a link between a smooth transition to a competitive marketplace and maintaining a

strong financial position.

The new FERC orders facilitate increased competi-tion in both the generation and sale of bulk power to wholesale customers.

They provide, among other things, for open access to transmission facilities.

AEP's support of the FERC's open access transmis-sion rule is evidenced by our being among the first to file a comparability tariff, offering access to AEP's transmission grid at 143 interconnections to all parties under the same terms and conditions available to AEP affiliates. This has provided greater opportu-nities for transmission service sales.

Although customer choice proposals and discus-sions are under way in the states in which we oper-ate, it is difficultto predict their result and the timing of changes, if any.

We are actively involved in discussions on the state and federal level regarding whether to and how best to transition to competition in order to represent the best interests of our custom-

ers, shareholders and employees.

We favor an orderly and smooth transition to a more competitive energy market because we believe that AEP will do better in the long term ifit is free to compete.

If the electric energy market evolves from cost-of-service rate-making to market-based pricing, many complex issues must be

resolved, including the recovery of stranded costs.

While the new FERC orders provide, under certain conditions, for recovery Stranded Costs Stranded costs occur when a customer switches to a new supplier for its electric energy needs or when a component of the business, for example generation, is no longer subject to cost4ased regulation, creating the issue of who pays for plant investment, pur-chased power or fuel contracts both non-affiliated and affiliated, inventories, construction work in

progress, nuclear decommissioning, plant removal and shutdown

costs, previously deferred costs (regulatory assets) and other investments and com-mitments that are no longer needed, economic or recoverable in a competitive market.

The amount of any stranded costs the Company may experience depends on the timing of and the extent to which direct competition is introduced to our business and the then-existing market price of energy.

Under the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation,"

regulatory assets (deferred expenses) and regulatory liabilities (deferred revenues) are included in the consolidated financial statements in accordance with regulatory actions to match expenses and revenues in cost-based rates.

In the event a portion of the business no longer met the requirements of SFAS 71, net regulatory assets would have to be written off for that portion of the business and assets tested for possible impairment.

Whether an impairment exists would depend on how low the market price of energy is in competition relative to the cost of energy.

Among other requirements the application of SFAS 71 requires that the rates charged customers be cost based.

Our generation business is still cost-based regulated and should remain so for the foreseeable future.

Should enabling state legislation be enacted we believe there should be at least a three to five year transition to full competition.

Although the recent FERC orders provide for competition in the firm wholesale market, that market is a relatively small part of our business and our firm wholesale sales are still under cost-of-service contracts.

We believe that enabling state legislation if enacted should provide for a sufficient transition period to allow for the recovery of any generation-related MANAGEMENT'SDISCUSSION AND ANALYSIS

'F RESULTS OF OPERATIONS AND FINANCIALCONDITION usiness Outlook

stranded costs and we are dedicating ourselves to work with regulators, customers and legislators to accomplish both an orderly transition and a reason-able and fair disposition of the stranded cost issue.

However, ifthe Company were to no longer be cost-based regulated and recovery of stranded costs were not possible, results of operations and financial condition would be adversely affected.

Since state commissions have jurisdiction over the sale and distribution of electricity to retail customers, we believe that state legislation and regulation should shape the future competitive market for electricity while federal legislation should seek to ensure reci-procity among the states and a level playing field for all power suppliers.

Presently states with higher cost

power, like California, are aggressively pursuing deregulation.

The states the Company operates in, however, are generally addressing the call for cus-tomer choice more cautiously.

RestructuringlFunctional Unbundling our major processes led to decisions to consolidate the management and operations of internal'service.

functions performed at multiple locations.

Amon the functions being consolidated are fossil generati plant maintenance, nuclear operations, syste operations, accounting and load research.

A study of the Company's procurement and supp'Iy chain opera-tions led to cost reductions through better inventory management, just-in-time delivery and the increased use of electronic purchasing.

Also in 1996 we completed the installation of an activity based management budgeting system.

This tool willenable managers to better analyze work and control costs.

While staff reductions and cost savings are being achieved in these and other areas, expenses for new marketing programs, customer services and modern efficient management information systems are being increased to prepare for competition.

These expendi-tures for the future should produce further improve-rnents and efficiencies, enabling the Company to maintain its position as a low-cost producer.

ln 1996 we took some major steps to maintain and enhance the Company's competitive strength.

We restructured our management and operations to allow us to comply with the new FERC orders which required separation of generation and energy sales operations from our energy transmission and delivery operations.

This has achieved and should continue to achieve staffing, managerial and operating efficien-cies.

The generation and marketing business units are preparing for the possibility of competition in an open market for customers.

Our energy delivery business expects to remain regulated and ultimately be subject to some form of incentive or performance-based ratemaking.

If competition never replaces regulation we will be a more efficient and productive business as a result of our preparations which should benefit all concerned.

Marketing and customer service efforts have been enhanced with programs like the Key Accounts Program which strives to build strong partnerships with key customers in order to build customer loy-alty.

In 1996 we also launched a series of new television commercials to inform our customers that we will be operating under the name, American Electric Power.

The commercials are intended to position AEP as more than just a

supplier of electricity.

We want to be the energy and energy services provider of choice; AEP: America's Energy Partner.

t=uel Costs Coal is 30% of the production cost of electricity.

Although our coal costs per unit of electricity (per kwh) have declined we recognize that we must continue to manage our coal costs to maintain ou competitive position.

As long-term coal supp contracts expire we are negotiating with non-affih ated suppliers to lower purchased coal costs.

We intend to continue to prudently supplement our long-term coal supplies with spot market purchases as long as favorable spot market prices exist.

Nuclear Cost Significant efforts have been made to enhance our competitiveness by improving the efficiency of the Company's nuclear operations.

Net generation in 1996 for the Company's only nuclear plant, the two-unit Donald C. Cook Nuclear Plant, located on the shores of Lake Michigan, was 16,396 gigawatts, the highest in the plant's 20-year history. The generation record was set in part due to Unit 2's best continu-ous run in its history, 226 days, reached in December 1996.

Refueling costs and related outage time have been reduced.

We also reduced nuclear staff support costs in 1996 by relocating our Columbus-based nuclear management and support staff to Michigan to consolidate it with the plant staff.

Cost Containment In 1996 we continued our efforts to reduce costs in order to maintain our competitiveness.

Reviews of It is difficult to reduce nuclear generation costs since major cost components are impacted by federa laws and Nuclear Regulatory Commission (NR regulations.

The Nuclear Waste Policy Act of 198

DIANAMICHIGANPOWER COMPANY ANDSUBSIDIARIES established federal responsibility for the permanent off-site disposal of spent nuclear fuel and high-level radioactive waste.

By law we participate in the Department of Energy's (DOE's) Spent Nuclear Fuel (SNF) disposal program which is described in Note 3 of the Notes to Consolidated Financial Statements.

Since 1983 our customers have paid 0254 millionfor the disposal of spent nuclear fuel consumed at the Cook Nuclear Plant.

Under the provisions of the Nuclear Waste Policy Act, collections from customers are to provide the DOE with money to build a reposi-tory for spent fuel. To date the federal government has not made sufficient progress towards a perma-nent repository or otherwise assuming responsibility for SNF.

As long as there is a delay in the storage repository for SNF, the cost of both temporary and permanent storage willcontinue to increase.

The cost to decommission the Cook Nuclear Plant is also affected by NRC regulations and the DOE's SNF disposal program.

Studies completed in 1994 estimate the cost to decommission the Cook Nuclear Plant and dispose of lowdevel nuclear waste accumu-lation to range from $634 million to $988 million in 1993 nondiscounted dollars.

This estimate could increase due to uncertainty in the DOE's SNF disposal program and the length of time that SNF may need to be stored at the plant site delaying decommissioning.

Presently we are recovering the estimated cost of decommissioning the Cook Nuclear Plant over its remaining life.

However, the Company's future results of operations and possibly its financial condi-tion could be adversely affected ifthe cost of spent nuclear fuel disposal and decommissioning continues to increase and cannot be recovered in regulated rates or as a stranded cost in a future competitive market.

Environmental Matters We take great pride in our efforts to economically produce and deliver electricity while minimizing the impact on the environment.

Indiana Michigan Power Company has spent hundreds of millions of dollars to equip our facilities with the latest economical clean air and water technologies and to research possible new technologies.

We intend to continue to take a leadership role to foster economically prudent efforts to protect and preserve the environment.

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and spent nuclear fuel.

Coal combustion by-products are typically disposed of or treated in captive disposal facilities or are beneficially utilized.

In addition, our generating plants and transmission and distribution facilities have used

asbestos, polychlorinated biphenyls (PCBs) and other hazardous and non-hazardous materials.

The Com-pany is currently incurring costs to safely dispose of such substances, and additional costs could be incurred to comply with new laws and regulations if enacted.

The Comprehensive Environmental

Response, Compensation and Liability Act (CERCLA or Superfund) addresses clean-up of hazardous sub-stances at disposal sites and authorized the United States Environmental Protection Agency (Federal EPA) to administer the cleanup programs. As of year-end 1996, I&Mis currently involved in litigation with respect to two sites, and has been named by the Federal EPA as a "Potentially Responsible Party" (PRP) fortwo other sites.

There are five additional sites for which the Company has received information re-quests which could lead to PRP designation as well as information requests for two state administered sites. I&M'sliabilityhas been resolved for a number of sites with no significant effect on results of operations.

The Company's present estimates do not anticipate material cleanup costs for identified sites for which I&Mhas been declared a PRP.

However, iffor reasons not currently identified significant costs are incurred for cleanup, future results of operations and possibly financial condition would be adversely affected unless the costs can be recovered.

Results of Operations In 1996 net income increased

$ 16 million or 11%.

The increase is mainly attributable to increased wholesale sales, a reduction in maintenance expense and reduced financing costs. Also contributing to the 1996 increase were severance pay charges recorded in 1995 in connection with realigning operations and management and gains recorded in 1996 from emission allowance transactions.

Although revenues increased 2.5% in 1995, net income declined S16 million or 10% as the result of increased operating

expenses, including the unfavorable effect of a provision for severance benefits in connection with the realignment of operations, and increased federal income tax expense.

Operating Revenues and Energy Sales Increase Retail:

Price Variance Volume Variance S(25.9)

S (0.7) o ~ 8 ~'ee 3 ~ 3 Wholesale:

Price Variance Volume Vaziance Other Operating Revenues Total (55.6)

(116.9) 93 ~

13 3.5 ~I 2.5 Operating revenues increased in 1996 primarily as a result of increased wholesale sales attributable to increased internal generation being supplied to the AEP System Power Pool (Power Pool) and unaffiliated utilities.

The Company's share of Power Pool allocated sales increased 40% due to increased transactions with other utilities and power marketers.

During 1996 the Company provided a new product, coal conversion services, to power marketers and unaffiliated utilities resulting in 1.2 billion kilowatthours of electricity being generated under a new FERC-approved interruptible tariff. Under this tariff the Company converts the coal of a wholesale customer to electricity for a fee.

The increase in 1995 operating revenues resulted from increased energy usage by retail and unaffiliated wholesale customers.

Retail energy sales increased 3% reflecting warmer summer weather and a colder fourth quarter in 1995 than in 1994 and continued growth in the number of retail customers.

While wholesale energy sales increased 34%, wholesale revenues increased by only 1% in 1995.

The sub-stantial increase in wholesale energy sales was primarily due to a 69% increase in energy sales to the Power Pool reflecting the increased availability of the Company's lower cost nuclear generating capac-ity in 1995. During 1995 one nuclear generating unit was out of service for refueling while both units were refueled in 1994. Sales to the Company's municipal and cooperative customers and to unaffiliated utilities by the Power Pool increased primarily due to weather related factors in 1995 versus 1994.

The increase in wholesale sales did not lead to a corresponding Operating revenues increased 3.5% in 1996 follow-ing a 2.5% increase in 1995. The price, volume analysis of revenue variances which accounted for the improved results are:

Inczease (Decrease) increase in revenues due to reduced capacity credits from the Power Pool and increasing competition in

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the wholesale energy market. Capacity credits, whic are designed to allocate the cost of the AEP System'enerating capacity among the members of th Power Pool based on their relative peak demands and generating reserves, were lower reflecting the effect of an increase in the Company's peak demand during 1995.

Operatin g Expenses Increase 8 13.3 6.0 8 21.2 10.5 13.3 10.6 (5.8)

(4.4) 3.5 1.2 10.3 3.5 (26.5) (18.7) 2.4 1.7 23.5 43.5 15.7 40.

Fuel expense increased in 1996 due to a 17%

increase in nuclear generation made possible by the shorter refueling outage in 1996 versus an extended refueling and maintenance outage in 1995. This increase was partially offset by a lower average price per ton of coal consumed from a favorable settlement of a coal transportation dispute.

Fuel expense in-creased substantially in 1995 due to a 51% increase in nuclear generation reflecting the increased avail-ability from having only one refueling outage in 1995 versus two in 1994.

The 1996 rise in purchased power expense was mainly due to additional power purchases under an agreement with the Ohio Valley Electric Corporation, an affiliated company which is not a member of the Power Pool, and increased purchases from the Power Pool to support the Company's allocated share of higher Power Pool wholesale transactions with non-affiliated utilities. The 1995 reduction in purchased power expense can be attributed to increased avail-ability of the Company's nuclear generation.

Fuel Purchased Po99er Other Opezation Maintenance Federal Income Taxes Total operating expenses increased 2.8% in 1996 or $30.6 million mainly due to the increased opera-tion of the Company's nuclear units, increased Power Pool wholesale transactions, and higher income taxes partially offset by significant reductions in mainte-nance expense.

In 1995, total operating expenses rose 4.7% or $48.1 million reflecting the increased operation of the Company's nuclear units and sever-ance pay accruals. The significant changes in operat-ing expenses were:

Increase (Decrease)

DIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Other operation expense increased in 1995 primar-y ilydiIe to a provision for severance pay related to the

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functional realignment of operations and costs related to the development of a new activity based budget-ing system.

Maintenance expense was substantially lower in 1996 due to cost-reduction measures at the Com-pany's nuclear plant, which reduced the number of employees performing maintenance and lowered payments for contract maintenance labor.

The increase in 1996 federal income taxes resulted from an increase in pre-tax operating income and changes in certain book/tax differences accounted for on a flow-through basis for rate-making purposes.

Federal income taxes increased in 1995 primarily due to changes in certain book/tax timing differences accounted for on a flow-through basis and the effects of favorable accrual adjustments recorded in 1994 in connection with the resolution of the audit of prior years'ax returns.

Financing Costs A decline in interest charges occurred in 1996 due to debt repayments and a refinancing program which lowered interest rates.

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Construction Spending Gross plant and property additions were

$ 144 million in 1996 and $ 151 million in 1995.

Manage-ment estimates construction expenditures for the next three years to be $340 million with no major new generating plant construction planned.

The funds for construction of new facilities and improve-ment of existing facilities can come from a combina-tion of internally generated funds, short-term and long-term borrowings, preferred stock issuances and investments in common equity by the Company's parent, American Electric Power Company, Inc. (AEP Co., Inc.) However, all of the construction expendi-tures for the next three years are expected to be financed with internally generated funds.

Liquidityand Capital Resources When necessary the Company generally issues short-term debt to provide for interim financing of capital expenditures that exceed internally generated funds.

At December 31, 1996,

$409 million of unused short-term lines of credit shared with other AEP System companies were available.

Short-term debt borrowings are limited by provisions of the Public UtilityHolding Company Act of 1935 to $ 175 million. Periodic reductions of outstanding short-term debt are made through issuances of long-term debt and preferred stock and through additional capital contributions by the parent company.

The Company's earnings coverage presently ex-ceeds all minimum coverage requirements for the 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,

1996, the mortgage bonds and preferred stock coverage ratios were 6.66 and 3.07, respectively.

In January 1997 a tender offer was announced for all of the Company's preferred stock in conjunction with a special meeting scheduled to be held on February 28, 1997.

The special meeting's purpose is to consider amendments to the Company's articles of incorporation to remove certain capitalization ratio requirements.

These restrictions limitthe Company's financial flexibilityand could place it at a competitive disadvantage in the future.

The amount paid to redeem the preferred stock that is tendered could total as much as $ 154 million.

A combination of short-term debt and unsecured long-term debt is expected to be used to pay for the preferred stock tendered.

Litigation The Company is involved in a number of legal proceedings and claims.

While we are unable to predict the outcome of such litigation, it is not expected that the ultimate resolution of these mat-ters willhave a material adverse effect on the results of operations and/or financial condition.

Effects of Inflation Inflation affects the Company's cost of replacing utilityplant and the cost of operating and maintaining plant.

The rate-making process generally limits our recovery to the historical cost of assets resulting in economic losses when the effects of inflation are not recovered from customers on a timely basis.

How-ever, economic gains that result from the repayment of long-term debt with inflated dollars partly offset the negative impact of inflation.

Corporate Owned Life Insurance In connection with the audit of the AEP System's 1991, 1992 and 1993 consolidated federal income tax returns the Internal Revenue Service (IRS) agents sought a ruling from the IRS National Office that certain interest deductions relating to a corporate owned life insurance (COLI) program should not be allowed. The Company established the COLI program in 1990 as a part of its strategy to fund and reduce the cost of medical benefits for retired employees.

AEP filed a brief with the IRS National Office refuting the agents'osition.

Although no adjustments have been proposed, a disallowance of the COLI interest deductions through December 31, 1996 would reduce earnings by approximately S51 million (includ-ing interest).

Management believes it willultimately prevail on this issue and willvigorously contest any disallowance that may be assessed.

In 1996 Congress enacted legislation that prospec-tively phases out the tax benefits for COLI interest deductions over a three year period beginning in 1996.

As a result the Company intends to restruc-ture its COLI program.

The restructuring of the COLI program is not expected to have a material impact on results of operations.

New Accounting Rule In 1996 the Financial Accounting Standards Board (FASB) issued an exposure draft "Accounting for Certain Liabilities Related to Closure or Removal of Long-Lived Assets."

The Company generally records such liabilities over the life of its plant commensurate with rate recovery.

The exposure draft proposes that the present value of decommissioning and certai other closure or removal obligations be recorded as a liability when the obligation is incurred.

A corre-sponding asset would be recorded in the plant invest-ment account and recovered through depreciation charges over the asset's life. A proposed transition rule would require that an entity report in income the cumulative effect of initially applying the new stan-dard. However, as a cost-based rate-regulated entity, the Company would expect to record a corresponding regulatory asset for the cumulative effect of initially applying the new standard.

The FASB is reconsider-ing several aspects of the exposure draft.

It is unclear at this time what, if any, changes the FASB willmake to the proposal.

Until it becomes apparent what the FASB willdecide and how certain questions raised by the exposure draft are resolved the Com-pany cannot determine its ultimate impact.

INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES 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, 1996 and 1995, and the related consolidated statements of income, retained

earnings, and cash flows for each of the three years in the period ended December 31, 1996.

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 disclo-sures 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, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996 in conformity with generally accepted accounting principles.

DELOITTE L TOUCHE LLP Columbus, Ohio February 25, 1997 11

Consolidated Statements of Income 3935 (in thousands)

OPERATING REVENUES

~KL92

~823 'iZ

~12QR OPERATING EXPENSES:

Fuel Purchased Power Other Operation Maintenance Depreciation and Amortization Amortization of Rockport Plant Unit 1 Phase-in Plan Deferrals Taxes Other Than Federal Income Taxes Federal Income Taxes Total Operating Expenses 236,237 138,687 310,513 115,300 140,437 222,967 125,413 306,967 141,813 138,814 201,739 131,234 296,625 139,423 136,244 15,644 70,078 15,644 71,791 25.

15,644 73,729

~L52R

~QKQZ6

~ZZ.~

~2L3&

OPERATING INCOME NONOPERATING INCOME INCOME BEFORE INTEREST CHARGES INTEREST CHARGES NET INCOME PREFERRED STOCK DIVIDENDREQUIREMENTS EARNINGS APPLICABLE TO COMMON STOCK 220,417 223,146 205,723

~i222 211,995 221,969 229,397 157,153 141,092 157,502

~8.391

~5JQl

~%681

~4231

'LLEW.

See Notes to Consolidated Financial Statements.

12

INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows OPERATING ACTIVITIES:

Net Income Adjustments for Noncash Items:

Depreciation and Amortization Amortization of Rockport Plant Unit 1 Phase-in Plan Deferrals Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses (net)

Deferred Federal Income Taxes Deferred Investment Tax Credits Changes in Certain Current Assets and Liabilities:

Accounts Receivable (net)

Fuel, Materials and Supplies Accrued UtilityRevenues Accounts Payable Taxes Accrued Other (net)

Net Cash Flows From Operating Activities 1'inthousands) 148,123 15,644 148,441 15,644 146,966 15,644 7,662 (24,687)

(8,729) 8,684 (23,564)

(9,004)

(18,779)

(19,775)

(13,877)

(10,235) 903 5,642 1,186 (6,296)

~teak 4,121 (6,255)

(3,355)

(2,431) 8,075

&2XQR))

(7,200)

(3,423)

(5,940) 5,219 9,148

~~)

S 157,153 0 141,092 0 157,502 INVESTING ACTIVITIES:

Construction Expenditures Long-term Receivable from Customer for Construction of Facilities Proceeds from Sales of Property and Other Net Cash Flows Used For Investing Activities (95,046) 62

~7~

(117,785)

(18,733)

C~

3122~)

(118,094) 311KEi6)

FINANCINGACTIVITIES:

Issuance of Cumulative Preferred Stock Issuance of Long-term Debt Retirement of Cumulative Preferred Stock Retirement of Long-term Debt Change in Short-term Debt (net)

Dividends Paid on Common Stock Dividends Paid on Cumulative Preferred Stock Net Cash Flows Used For Financing Activities Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents January 1

Cash and Cash Equivalents December 31 See Notes to Consolidated Financial Statements.

38,579 (30,568)

(46,091)

(46,475)

(112,508)

(5,490)

~4222 96,819 (141,122) 39,375 (110,852)

~L1 'iQQ) 3322~)

3,816 KKQ.

34,618 89,221 (35,798)

(101,833) 525 (106,608)

~~)

13

Consolidated Balance Sheets ASSETS 39K 1BRi (in thousands)

ELECTRIC UTILITYPLANT:

Production Transmission Distribution General (including nuclear fuel)

Construction Work in Progress Total Electric UtilityPlant Accumulated Depreciation and Amortization NET ELECTRIC UTILITYPLANT

$2,525,969 881,407 696,069 189,619

~&iQ5 02,507,667 867,541 666,810 186,959

'REST.

4,319,564

~i1 'K5.

4,377,669

~KL892

~5226

~i'F32 NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS OTHER PROPERTY AND INVESTMENTS CURRENT ASSETS:

Cash and Cash Equivalents Accounts Receivable:

Customers Affiliated Companies Miscellaneous Allowance for Uncollectible Accounts Fuel - at average cost Materials and Supplies - at average cost Accrued UtilityRevenues Prepayments TOTAL CURRENT ASSETS 8,233 90,656 13.727 21,439 (156) 23,977 77,074 38,295 1@221

~83

'i'3,723 82,434 21,881 11,450 (334) 29,093 72,861 43,937

~QJ91 REGULATORY ASSETS

~22/532

~RUi25 DEFERRED CHARGES

~185Z

~32 3k%

TOTAL See Notes to Consolidated Financial Statements.

14

INDIAi ICHIGANPOWER COMPANY AND SUBSIDIARIES CAPITALIZATIONAND LIABILmES 3986 3995.

(In thousands)

CAPITALIZATION:

Common Stock - No Par Value:

Authorized - 2,500,000 Shares Outstanding - 1,400,000 Shares Paid-in Capital Retained Earnings Total Common Shareholder's Equity Cumulative Preferred Stock:

Not Subject to Mandatory Redemption Subject to Mandatory Redemption Long-term Debt TOTALCAPITALIZATION 56,584 731 272

~6LOZ1 1,056,927 56,584 731,102

~K 'LQZ 1,022,793 52,000 135,000

~RLQ&

21,977 135,000

~2JZR

~5KQQB

~HttLu.

OTHER NONCURRENT LIABILITIES:

Nuclear Decommissioning Other TOTAL OTHER NONCURRENT LIABILITIES 313,845

~LBQ3

~LZ4R 269,392

~5193

~M.SRt CURRENT LIABILITIES:

Long-term Debt Due Within One Year Short-term Debt Accounts Payable - General Accounts Payable - Affiliated Companies Taxes Accrued Interest Accrued Obligations Under Capital Leases Other 43,500 31,015 30,877 65,400 15,281 29,740

~~K925 6,053 89,975 37,744 22,962 71,696 16,158 31,776 TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENTTAXCREDITS DEFERRED GAIN ON SALE AND LEASEBACK-ROCKPORT PLANT UNIT 2 DEFERRED CREDITS COMMITMENTSAND CONTINGENCIES (Note 3)

~K423

~iKZQ

'K1Zi

~K832

~KQQ2 12 '63 TOTAL 15

Consolidated Statements of Retained Earnin s

1835 (in thousands)

Retained Earnings January 1

Net Income

$235,107

$216,658

~~92

$ 177,638

~LRV.

Deductions:

Cash Dividends Declared:

Common Stock Cumulative Preferred Stock:

4-1/8% Series 4.56%

Series 4.1 2% Series 5.90%

Series 6-1/4% Series 6.30%

Series 6-7/8% Series 7.08%

Series 7.76%

Series Total Cash Dividends Declared Capital Stock Expense Total Deductions 112,508 495 273 165 2,360 1,875 2,205 2,063 531 122,475

~229 110,852 495 273 165 2,360 1,875 2,205 2,063 2,124 122,412 106,608 495 273 165 2,360 1,875 1,978 2,063 2,124 118,258 Retained Earnings December 31 See Notes to Consolideted Finenciel Stotements.

IANAMICHIGANPOWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIALSTATEMENTS

1. SIGNIFICANTACCOUNTING POLICIES:

Organization Indiana Michigan Power Company (the Company or I%M) is a wholly-owned subsidiary of American Electric Power Company, Inc. (AEP Co., Inc.), a public utilityholding company.

The Company is engaged in the generation, purchase, transmission and distribu-tion of electric power to 542,000 retail customers in its service territory of northern and eastern Indiana and a portion of southwestern Michigan. Wholesale electric power is supplied to neighboring utility systems, power marketers and the American Electric Power (AEP) System Power Pool (Power Pool). As a member of the Power Pool and a signatory company to the AEP Transmission Equalization Agreement, its facilities are operated in conjunction with the facili-ties of certain other AEP affiliated utilities as an integrated utilitysystem.

Basis ofAccounting As a cost-based rate-regulated entity, IRM's finan-cial statements reflect the actions of regulators that result in the recognition of revenues and expenses in different time periods than enterprises that are not cost-based rate-regulated.

In accordance with Statement of Financial Accounting Standards (SFAS)

No. 71, "Accounting for the Effects of Certain Types of Regulation," regulatory assets (deferred expenses) and regulatory liabilities (deferred income) are re-corded to reflect the economic effects of regulation.

Use ofEstimates The preparation of these financial statements in conformity with generally accepted accounting principles requires in certain instances the use of management's estimates.

Actual results could differ from those estimates.

The Company has two wholly-owned subsidiaries, which are consolidated in these financial statements, 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, land and related mining equipment to unaffiliated companies.

Price River Coal Company, which owns no land or mineral rights, is inactive.

Regulation As a subsidiary of AEP Co., Inc., I%M is subject to regulation by the Securities and Exchange Commis-sion (SEC) under the Public UtilityHolding Company Act of 1935 (1935 Act) ~

Retail rates are regulated by the Indiana UtilityRegulatory Commission (IURC) and the Michigan Public Service Commission (MPSC).

The Federal Energy Regulatory Commission (FERC) regulates wholesale rates.

Principles of Consolidation The consolidated financial statements include ILM and its wholly-owned subsidiaries. Significant inter-company items are eliminated in consolidation.

UtilityPlant Electric utilityplant is stated at original cost and is generally subject to first mortgage liens.

Addi-tions, major replacements and betterments are added to the plant accounts.

Retirements from the plant accounts and associated removal costs, net of sal-vage, are deducted from accumulated depreciation.

The costs of labor, materials and overheads in-curred to operate and maintain utility plant are included in operating expenses.

Allowance for Funds Used During Construction (AFUDCJ AFUDC is a noncash nonoperating income item that is recovered with regulator approval over the service life of utility plant through depreciation and represents the estimated cost of borrowed and equity funds used to finance construction projects.

The amounts of AFUDC for 1996, 1995 and 1994 were not significant.

17

Depreciation and Amortization Levelization ofNuclear Refueling Outage Costs Depreciation of electric utilityplant is provided on a straight-line basis over the estimated useful lives of utilityplant and is calculated largely through the use of composite rates by functional class as follows:

Punctional Class

~uumxhx Production:

Steam-Nuclear Steam-Fossil-Pired Hydroelectric-Conventional Transmission Distribution General Composite Depreciation hmHu~a 3.4X 4.4X 3.2X 1.9X 4.2X 3.8X Amounts to be used for demolition of non-nuclear plant are presently recovered through depreciation charges included in rates.

The accounting and rate-making treatment afforded nuclear decommissioning costs and nuclear fuel disposal costs are discussed in Note 3.

Cash and Cash Equivalents Cash and cash equivalents include temporary cash investments with original maturities of three months or less.

Operating Revenues Revenues include the accrual of electricity con-sumed but unbilled at month-end as well as billed revenues.

Fuel Costs Fuel costs are matched with revenues in accor-dance with rate commission orders.

Revenues are accrued related to unrecovered fuel in both retail jurisdictions and for replacement power costs in the Michigan jurisdiction until approved for billing. Ifthe Company's earnings exceed the allowed return in the Indiana jurisdiction, based on a twenty quarter rolling average, the fuel clause mechanism provides for the refunding of the excess earnings to ratepayers.

Wholesale jurisdictional fuel cost changes are expensed and billed as incurred.

Incremental operation and maintenance costs associated with refueling outages at the Donald C.

Cook Nuclear Plant (Cook Plant) are deferred commensurate with their rate-making treatment and amortized over the period (generally eighteen months) beginning with the commencement of an outage and ending with the beginning of the next outage.

Income Taxes The Company follows the liability method of accounting for income taxes as prescribed by SFAS 109, "Accounting for Income Taxes."

Under the liabilitymethod, deferred income taxes are provided for all temporary differences between book cost and tax basis of assets and liabilities which will result in a future tax consequence.

Where the flow-through method of accounting for temporary differencesis reflected in rates, regulatory assets and liabilities are recorded in accordance with SFAS 71.

Investment Tax Credits Based on directives of regulatory commissions, the Company reflected invesunent tax credits in rates on a deferral basis.

Deferred investment tax credits, which represent a regulatory liability, are bein amortized over the life of the related plant investment commensurate with recovery in rates.

The Com-pany's policy with regard to investment tax credits for nonutility property is to practice the flow-through method of accounting.

Debt and Preferred Stock Gains and losses on reacquired debt are deferred and amortized over the remaining term of the reac-quired debt in accordance with rate-making treat-ment.

If the debt is refinanced the reacquisition costs are deferred and amortized over the term of the replacement debt commensurate with their recovery in rates.

18

IANAMICHIGANPOWER COMPANY AND SUBSIDIARIES In accordance with rate-making treatment debt discount or premium and debt issuance expenses are

~

~

amortized over the term of the related debt, with the amortization included in interest charges.

Redemption premiums paid to reacquire preferred stock are deferred, debited to paid-in capital and amortized to reduce retained earnings in accordance with rate-making treatment.

The excess of par value over costs of preferred stock reacquired is credited to paid-in capital and amortized to retained earnings.

Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds Securities held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel are recorded at market value in accordance with SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities."

Securities in the trust funds have been classified as available-for-sale due to their long-term purpose.

Due to the rate-making process, adjustments for unrealized gains and losses are not reported in equity but result in adjustments to regulatory assets and liabilities.

Other Property and Investments Other property and investments are stated at cost.

2. EFFECTS OF REGULATION AND PHASE-IN PLANS:

In accordance with SFAS 71 the consolidated financial statements include assets (deferred ex-penses) and liabilities (deferred income) recorded in accordance with regulatory actions to match ex-penses and revenues in cost-based rates.

Regulatory assets are expected to be recovered in future periods through the rate-making process and the regulatory liabilities are expected to reduce future cost recover-ies.

Among other things, application of SFAS 71 requires that the Company's rates be cost-based regulated.

The Company has reviewed all the evi-dence currently available and concluded that it continues to meet the requirements to apply SFAS 71.

In the event a portion of the Company's business were to no longer meet those requirements net regulatory assets would have to be written off for that portion of the business and assets would have to be tested for possible impairment.

Regulatory besets:

hmounts Due Pzom Customers for Future Income Taxes Department oi Energy Decontamination and Decomaissioning hssessment Rate Phase-in Plan Deferrals Nuclear Refueling Outage Cost Levelization Unamortized Loss On Reacquired Debt Other Total Regulatory hssets

$317i059

$309

~ 640 45,994 11,871 48,862 27,515 15,805 19,388 852LL'Q 23,467 20,827

~F11 Regulatory Liabilities:

Deferred Investment Tax Credits S146,473 S155,202 Other*

~Zk Total Regulatory Liabilities

• Included in Deferred Czedits on Consolidated Balance Sheets.

The Rockport Plant consists of two 1,300 mega-watt (mw) coal-fired units.

I%M and AEP Generating Company (AEGCo), an affiliate, each own 50'/ of one unit (Rockport 1) and each lease a 50% interest 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 is being amortized, with related taxes, over the initial lease term which expires in 2022.

Rate phase-in plans in the Company's Indiana and FERC jurisdictions for its share of Rockport 1 provide for the recovery and straight-line amortization through 1997 of prior-year deferrals.

Unamortized deferred amounts under the phase-in plans were

$ 11.9 million and

$27.5 million at December 31, 1996 and 1995, respectively.

Amortization was

$ 15.6 million in 1996, 1995 and 1994.

Regulatory assets and liabilities are comprised of the following:

122l'L 1222 (in thousands) 19

3. COMMITMENTSAND CONTINGENCIES:

Construction and Other Commitments Substantial construction commitments have been made.

Such commitments do not include any expen-ditures for new generating capacity.

The aggregate construction program expenditures for 1997-1999 are estimated to be $340 million.

Long-term fuel supply contracts contain clauses that provide for periodic price adjustments.

The retail jurisdictions have fuel clause mechanisms that provide for recovery of changes in the cost of fuel with the regulators'eview and approval.

The contracts are for various terms, the longest of which extends to 2014, and contain various clauses that would release the Company from its obligation under certain force majeure conditions.

Nuclear Plant ISM owns and operates the two-unit 2,110 m Donald C. Cook Nuclear Plant under licenses grant by the Nuclear Regulatory Commission.

The opera tion of a nuclear facility involves special risks, poten-tial liabilities, and specific regulatory and safety re-quirements.

Should a nuclear incident occur at any nuclear power plant facility in the United States, the resultant liabilitycould be substantial.

By agreement l&Mis partially liable together with all other electric utility companies that own nuclear generating units for a nuclear power plant incident.

In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery is not possible, results of operations and financial condition would be negatively affected.

Nuclear Incident Liability Unit Power Agreements The Company is committed under unit power agreements to purchase 70% of AEGCo's 1,300 mw Rockport Plant capacity unless it is sold to unaffili-ated utilities.

AEGCo has one long-term contract with an unaffiliated utility that expires in 1999 for 455 mw of Rockport Plant capacity.

The Company sells under contract up to 250 mw of Rockport Plant capacity to an unaffiliated utility. The contract expires in 2009.

Litigation The Company is involved in a number of legal proceedings and claims.

While management is unable to predict the ultimate outcome of litigation, it is not expected that the resolution of these matters will have a material adverse effect on the results of operations or financial condition.

Public liability is limited by law to $8.9 billion should an incident occur at any licensed reactor in the United States.

Commercially available insurance provides $200 million of coverage.

In the event of a nuclear incident at any nuclear plant in the United States the remainder of the liability would be pro-vided by a deferred premium assessment of $79.3 million on each licensed reactor payable in annu installments of $ 10 million. As a result, IS.M cou be assessed

$ 158.6 million per nuclear inciden payable in annual installments of $20 million. The number of incidents for which payments could be required is not limited.

Nuclear insurance pools and other insurance policies provide $3.6 billion of property damage, decommis-sioning and decontamination coverage for Cook Plant.

Additional insurance provides coverage for extra costs resulting from a prolonged accidental Cook Plant outage.

Some of the policies have deferred premium provisions which could be triggered by losses in excess of the insurer's resources.

The losses could result from claims at the Cook Plant or certain other non-affiliated nuclear units.

The Com-pany could be assessed up to $35.8 million annually under these policies.

20

INDIANAMICHIGANPOWER COMPANy AND SUBSIDIARIES Spent Nuclear Fuel Disposal Federal law provides for government responsibility for permanent spent nuclear fuel disposal and as-sesses nuclear plant owners fees for spent fuel disposal.

A fee of one mill per kilowatthour for fuel consumed after April 6, 1983 is being collected from customers and remitted to the U.S. Treasury.

Fees and related interest of $172 millionfor fuel consumed prior to April 7, 1983 have been recorded as long-term debt.

I&Mhas not paid the government the pre-April 1983 fees due to continued delays and uncer-tainties related to the federal disposal program.

At December 31, 1996, funds collected from customers towards the pre-April 1983 fee and related earnings thereon approximate the liability.

Decommissioning and Low Level Waste Accumula-tion Disposal Decommissioning costs are accrued over the service life of the Cook Plant.

The licenses to oper-ate the two nuclear units expire in 2014 and 2017.

After expiration of the licenses the plant is expected to be decommissioned through dismantlement.

The Company's latest estimate for decommissioning and low level radioactive waste accumulation disposal costs range from $634 million to $988 million in 0

1993 nondiscounted dollars.

The wide range is caused by variables in assumptions including the estimated length of time spent nuclear fuel must be stored at the plant subsequent to ceasing operations.

This in turn depends on future developments in the federal government's spent nuclear fuel disposal program.

Continued delays in the federal fuel dis-posal program can result in increased decommission-ing costs.

The Company is recovering estimated decommissioning costs in its three rate-making jurisdictions based on at least the lower end of the range in the most recent decommissioning study at the time of the last rate proceeding.

The Company records decommissioning costs in other operation expense and records a noncurrent liability equal to the decommissioning cost recovered in rates; such amount was $27 million in 1996, $30 million in 1995 including

$4 million of special deposits and

$26 million in 1994.

Decommissioning costs recovered from customers are deposited in external trusts.

Trust fund earnings increase the fund assets and the recorded liabilityand decrease the amount needed to be recovered from ratepayers.

At December 31, 1996 the Company has recognized a decommission-ing liabilityof $314 million which is included in other noncurrent liabilities.

4. RELATED PARTY TRANSACTIONS:

Operating revenues include revenues for capacity and energy supplied to the Power Pool as follows:

Capacity Revenues Ener8y Revenues Total 12K

~

1221 (in thousands)

$ 57 ~ 594

$ 59 y 918

$ 88 ~ 183

~LZ M!2222 8152~

RKQ~

Purchased power expense includes charges of

$34.5 million in 1996,

$25.4 million in 1995 and

$33.1 million in 1994 for energy received from the Power Pool.

Benefits and costs of the AEP System's generating plants are shared by members of the Power Pool.

Under the terms of the AEP System Interconnection Agreement, capacity charges and credits are de-signed to allocate the cost of the AEP System's capacity among the Power Pool members based on their relative peak demands and generating reserves.

Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the Power Pool and charged for energy received from the Power Pool. The Company is a net supplier to the pool and, therefore, receives capacity credits from the Power Pool.

21

Power Pool members share in wholesale sales to unaffiliated entities made by the Power Pool.

The Company's share of the wholesale power pool sales included in operating revenues were $73.4 million in

1996,

$52.6 million in 1995 and

$54.1 million in 1994.

In addition, the Power Pool purchases power from unaffiliated companies for immediate resale to other unaffiliated utilities. The Company's share of these purchases was included in purchased power expense and totaled

$ 8.1 million in 1996,

$ 10.7 million in 1995 and

$ 14.2 million in 1994.

Revenues from these transactions including a transmission fee are included in the above Power Pool wholesale operating revenues.

The cost of power purchased from AEGCo, an affiliated company that is not a member of the Power Pool, was included in purchased power expense in the amounts of $85.4 million, $85.2 million and

$82.4 million in 1996, 1995 and 1994, respectively.

The cost of power purchased from Ohio Valley Electric Corporation, an affiliated but non-associated Companythat isnot a member of the Power Pool, was included in purchased power expense in the amounts of $ 10.7 million, $4.0 million and $.9 million in 1996, 1995 and 1994, respectively.

The Company operates the Rockport Plant and bills AEGCo for its share of operating costs.

AEP System companies participate in a transmis-sion equalization agreement.

This agreement corn-

~

bines certain AEP System companies'nvestments i

transmission facilities and shares the costs of owne ship in proportion to the AEP System companies respective peak demands.

Pursuant to the terms of the agreement, other operation expense includes equalization credits of $46.3 million, $46.7 million and

$50.3 million in

1996, 1995 and

1994, respectively.

Revenues from providing barging services were recorded in nonoperating income as follows:

12K (in thousands) hffiliated Companies 022,740 023,160 024,001 Unaffiliated Companies ~~

~92

~21 Total American Electric Power Service Corporation (AEPSC) provides certain managerial and professional services to AEP System companies.

The costs of the services are billed by AEPSC on a direct-charge basis to the extent practicable and on reasonable bases of proration for indirect costs.

The charges for services are made at cost and include no compensation for the use of equity capital, which is furnished t AEPSC by AEP Co., Inc.

Billings from AEPSC a capitalized or expensed depending on the nature o the, services rendered.

AEPSC and its billings are subject to the regulation of the SEC under the 1935 Act.

22

a INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES

5. BENEFIT PLANS:

The Company and its subsidiaries participate in the AEP System pension plan, a trusteed, noncontribu-tory defined benefit plan covering all employees meeting eligibilityrequirements.

Benefits are based on service years and compensation levels.

Pension costs are allocated by first charging each System company with its service cost and then allocating the remaining pension cost in proportion to its share of the projected benefit obligation.

The funding policy is to make annual trust fund contributions equal to the net periodic pension cost up to the maximum amount deductible for federal income taxes, but not less than the minimum required contribution in accordance with the Employee Retirement Income Security Act of 1974.

Net pension costs for the years ended December 31, 1996, 1995 and 1994 were

$4.1 million, S2.7 million and

$ 5 million, respectively.

An employee savings plan is offered which allows participants to contribute up to 17% of their salaries into various investment alternatives, including AEP Co., Inc. common stock.

An employer matching contribution, equaling one-half of the employees'ontribution to the plan up to a maximum of 3% of the employees'ase salary, is invested in AEP Co.,

nc. common stock. The employer's annual contribu-tions totaled $3.7 million in 1996 and $3.9 million in 1995 and 1994.

Postretirement benefits other than pensions (OPEB) are provided for retired employees under an AEP System plan. Substantially all employees are eligible for postretirement health care and life insurance if they retire from active service after reaching age 55 and have at least 10 service years.

The funding policy for OPEB cost is to make contributions to an external Voluntary Employees Beneficiary Association trust fund equal to the incremental OPEB costs (i.e.,

the amount that the total postretirement benefits cost under SFAS 106, "Employers'ccounting for Postretirement Benefits Other Than Pensions,"

exceeds the pay-as-you-go amount).

Contributions were $8.4 million in 1996, $10.3 million in 1995, and S6.6 million in 1994.

OPEB costs are determined by the application of AEP System actuarial assumptions to each company's employee complement.

The Company's annual accrued costs for 1996, 1995 and 1994 required by SFAS 106 for employees and retirees were $12.8 million, $ 13.6 million and $ 13.2 million, respectively.

6. SUPPLEMENTARY INFORMATION:

12K 1225 1RKk (in thousands)

Cash was paid for:

Interest (net of capitalised amounts)8 64,117 Tncoee Taxes 125,707 Noncash hcguisitions Under Capital Leases were 48,305 871,457 88,675 32,073 868,946 85,854 92,199 In connection with the 1996 early termination of a western coal land sublease the Company will receive cash payments from the lessee of $30.8 million over a ten year period which has been recorded at a net present value of $22.8 million.

In connection with the 1995 sale of western coal land and equipment the Company will receive cash payments from the buyer of $31.5 million over a six year period which has been recorded at a net present value of S26.9 million. In connection with construction of facilities in 1995 to provide service to a new customer the Company willreceive cash payments of $21.4 million plus accrued interest over 20 years.

The long-term portion of these receivables is recorded as other property and investments and the current portion is recorded as miscellaneous accounts receivable.

23

7. FEDERAL INCOME TAXES:

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

Charged (Credited) to Operating Expenses (net):

Current Deferred Defezred Investment Tax Credits Total Charged (Credited) to Nonoperating Income (net):

Current Defezzed Deferred Investment Tax Credits Total Total Federal Income Taxes as Reported 8110,133 (24,730)

~2i) 182 43

~M)

LH2) k2kJ52 (in thousands) 8 75,686 (13,732)

~~)

12,872 (9,832)

~~)

8 64,565 (18,057)

~~)

~LB&

1,390 (1,718)

~22)

~~)

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.

Net Income Federal Income Taxes Pre-tax Book Income Federal Incomo Tax on Pre-tax Book Income at Statutory Rate (35X)

Increase (Decrease) in Federal Incamo Tax Resulting Fram the Following Items:

Depreciation Corporate caned Life Insurance Nucloar Fuel Disposal Costs Investment Tax Credits (net)

Othez Total Federal Income Taxes as Reported Effective Federal Income Tax Rate S157,153

~52.

5~2 881,918 13,880 (2,178)

(3,096)

(8,729)

~JHK) k7LJ52 (in thousands) 8141,092 812ZJU!2 868,979 8,954 (5, 187)

(3,060)

(9,004)

~Q)

~6k 8157,502 8162JDLi S 66,432 (1,033)

(4,521)

(4,498)

='"-"'

Deferzed Tax Assets Deferred Tax Liabilities Not Deferred Tax Liabilities Property Related Temporary Differoncos Amounts Due From Customers For Future Federal Income Taxes Deferred State Income Taxes Defezred Net Gain-Rockpozt Plant Unit 2 All Other (net)

Total Net Deferred Tax Liabilities LRK (in thousands)

S 241, 842 S 221, 604

~LZZl) ~LLil)

~2R)

RUQP~)

S(480,818)

S(490,986)

(79,658)

(89,471) 33,644 (83,277)

(71,712) 34,941 F112)

RU5~~ZR)

RC5X~~)

The following tables show the elements of the net deferred tax liability and the significant temporary differences giving rise to such deferrals:

The Company and its subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System.

The allocation of the AEP System's current consolidated federal income tax to the AEP System companies is in accordance with SEC rules under the 1935 Act.

These rules permit the allocation of the benefit of current tax losses to the AEP System companies giving rise to them in determining their current tax expense.

The tax loss of the parent company, AEP Co., Inc., is allocated to its subsidiaries with taxable income.

With the exception of the loss of the parent com-

pany, the method of allocation approximates a

separate return result for each company in the consolidated group.

24

INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES The AEP System has settled with the Internal Reve-nue Service (IRS) all issues from the audits of the consolidated federal income tax returns for the years rior to 1991.

Returns for the years 1991 through 1993 are presently being audited by the IRS. During the audit the IRS agents requested a ruling from their National Office that certain interest deductions relating to corporate owned life insurance (COLI) claimed by the Company for 1991 through 1993 should not be allowed.

The COLI program was established in 1990 as part of the Company's strat-egy to fund and reduce the cost of medical benefits for retired employees.

AEP filed a brief with the IRS National Office refuting the agents'osition.

AI-though no adjustments have been

proposed, a

disallowance of the COLI interest deductions through December 31, 1996 would reduce earnings by approximately

$51 million (including interest).

Management believes it willultimately prevail on this issue and will vigorously contest any adjustments that may be assessed.

Accordingly, no provision for this amount has been recorded.

In the opinion of management, the final settlement of open years will not have a material effect on results of operations.

8. FAIR VALUEOF FINANCIALINSTRUMENTS:

0 uclear Trust Funds Recorded at Market Value The trust investments are recorded at market value in accordance with SFAS 115 and consist of long-term tax-exempt municipal bonds and other securi-ties.

At December 31, 1996 and 1995 the fair values of trust investments were

$491 million and

$434 million, respectively.

Accumulated gross unrealized holding gains were $22 million and $ 19.1 million and accumulated gross unrealized holding losses were

$ 1.2 million and

$ 1 million at December 31, 1996 and 1995, respectively.

The change in market value in 1996 was a net unrealized holding gain of $2.6 million, in 1995 a net unrealized holding gain of

$24.9 million and in 1994 a net unrealized holding loss of $27.1 million.

Proceeds from sales and maturities of securities of

$115.3 millionduring 1996 resulted in S2.6 million of realized gains and

$2.1 million of realized losses.

Proceeds from sales and maturities of securities of

$78.2 million during 1995 resulted in $ 1.4 million of realized gains and

$0.3 million of realized losses.

During 1994 proceeds from sales and maturities of securities of S20.1 million resulted in S52,000 of realized gains and S155,000 of realized losses.

The cost of securities for determining realized gains and losses is original acquisition cost including amortized premiums and discounts.

At December 31, 1996, the year of maturity of trust fund investments, other than equity securities, was:

(in thousands) 1997 1998-2001 2002-2006 After 2006 Total S 56,452 120,327 163,250 Other Financial Instruments Recorded at Historical Cost The carrying amounts of cash and cash equivalents, accounts receivable, short-term debt, and accounts payable approximate fair value because of the short-term maturity of these instruments.

Fair values for preferred stocks subject to mandatory redemption were $137 million and $ 140 million at December 31, 1996 and1995, respectively, and for long-term debt were

$ 1.1 billion at each year end. The carrying amounts for preferred stock subject to mandatory redemption were $ 135 million at each year end and for long-term debt were

$ 1.0 billion at December 31, 1996 and 1995.

Fair values are based on quoted market prices for the same or similar issues and the current dividend or interest rates offered for instru-ments of the same remaining maturities.

The carry-ing amount of the pre-April 1983 spent nuclear fuel disposal liability approximates the estimated fair value.

The trust investments'ost basis by security type were:

Tax-Except Bonds Equity Securities Treasury bonds Corporate Bonds

Cash, Cash Equivalents and Interest Accrued Total 12K(in 8340,290 54,389 26,958 7,977 thousands) 8336,073 24, 101 12,992 1,971 25

9. LEASES:

Leases of property, plant and equipment are for periods of up to 35 years and require payments of related property taxes, maintenance and operating costs.

The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases.

Lease rentals for both operating and capital leases are generally charged to operating expenses in accordance with rate-making treatment.

The compo-nents of rental costs are as follows:

The noncurrent portion of capital lease obligations is included in other noncurrent liabilities in the Con-

~

solidated Balance Sheets.

Properties under operating leases and relate obligations are not included in the Consolidated Balance Sheets.

Future minimum lease payments consisted of the following at December 31, 1996:

Non-Cancelable Capital Operatins IdmaU(

Mdmam (in thousands)

Operatin8 Leases hmortisation of Capital Leases Interest on Capital Loasos Total Rental Costs 122k

~

1RLL (in thousands)

S 96,096 S 96,472 8104,519 55,789 45,843 30,875 l~)2 915~2 515XJQZ 1997 1998 1999 2000 2001 Later Years S 14,685 12,474 11,027 9,848 8,281 Total Future Hinimum Lease Payments 92,686(a)

Less Estimated Interest Element

~~}jg 8

96,294 91,397 91,551 91,403 90,802

~~lZ Electric UtilityPlant:

Production Distribution General:

Nuclear Fuel (net of amortization)

Other Total Electric Utility Plant hccumulated hmortisation Net Electric Utility Plant 8

7,410 14,699 59,681 142,739

~K22R S 9,346 14,753 69,442 148,095

~Q2 Properties under capital leases and related obliga-tions recorded on the Consolidated Balance Sheets are as follows:

122k 1222 (in thousands)

Estimated Present Value of Future Hinimum Lease Payments Unamortized Nuclear Fuel Total 71,284 81K~i (a) Excludes nuclear fuel rentals which are proportion to heat produced and carryin8 on the unamortized nuclear fuol balance.

no minimum lease payment requirements for nuclear fuel.

yid 1 chorses There are leased Other Property hccumulated hmortisation Net Other Property Net Properties under Capital Leases Capital Lease Oblisationsro Noncurrent Liability Liability Due Within Ono Year Total Capital Leaso Oblisations 19,035 8101,225

~U?

QZL!M 22,361 8110,730 8152~

• Represents tho present value of future minimum lease payments.

26

INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES

10. CUMULATIVEPREFERRED STOCK:

2,250,000 11,200,000 At December 31, 1996, authorized shares of cumulative preferred stock were as follows:

Zar~2m

$100 25 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.

In January 1997 a tender offer for all series of preferred stock was announced.

In conjunction with the tender offer a special shareholders'eeting was scheduled to be held on February 28, 1997 for the purpose of considering amendments to the Company's articles of incorporation to remove certain capitalization ratio requirements.

A. Cumulative Preferred Stock Not Subject to Mandatory Redemption:

Call Price December 31, Par Zalea Number of Sharos Rodeemed 12K

~

122k Shares Outstanding 122k (in thousands) 4-1/8X 4.56X

4. 12X 7.08X 8106. 125 102 102.728 N/A 8100 100 100 100 233 300,000 119,767 60,000 40,000 8 11,977 6,000 4,000 8 12,000 6,000 4,000

~RJ)(U)

. Cumulative Preferred Stock Subject to Mandatory Redemption:

Par Shares Outstanding (in thousands) 5.90X (b) 6-1/4X(c) 6.30X (d) 6-7/8X(e) 8100 100 100 100 400,000 300,000 350,000 300,000 8 40,000 30,000 35,000

~DL9K 8125~

8 40,000 30,000 35,000 8125~

(s) Not csllsblo until after 2002.

There sre no aggregate sinking fund provisions through 2002.

(b) Commencing in 2004 snd continuing through the year 2008, a sinking fund will require tho redemption of the redemption of the remaining shares outstanding on January 1, 2009, in each case st 8100 por share.

(c) Commencing in 2004 snd continuing through tho year 2008, a sinking fund will require the redemption of the redemption of tho remaining shares outstanding on April 1, 2009, in each case at 8100 por share.

(d) Commencing in 2004 snd continuing through the year 2008, a sinking fund will require the redemption of the redemption of tho remaining shares outstanding on July 1, 2009, in each case st 8100 por shsro.

(e) Commencing in 2003 snd continuing through tho year 2007, s sinking fund will require the redemption of tho rodomption of tho remaining shares outstanding on April 1, 2008, in each case st 8100 per share.

20,000 shares each year and 15,000 shares each year and 17,500 shares each year and 15,000 shares each year and 27

11. LONG-TERM DEBT AND LINES OF CREDIT:

Long-term debt by major category was outstand-ing as follows:

12K(in thousands)

Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authoritie as follows:

12K (in thousands)

First Hoztgage Bonds Installment Purchase Contracts Other Long-term Debt (a)

Junior Subordinated Defezzable Interest Debentures (b)

Sinking Fund Dobentuzes (c)

Less Portion Due Within One Year Total 522,507 309, 120 171, 706 38,771 1,042,104 8

562,017 308,971 163,060

~2.

1,040, 101 XJhha City of Lawrenceburg, Indiana:

7 2015 - hpzil 1 5.9 2019 - November 1

City of Rockport, Indiana:

(a) 2014 - hugust 1

7.6 2016 - Hazch 1

6.55 2025 - June 1

(b) 2025 - June 1

City of Sullivan, Indiana:

5.95 2009 - May 1 Unamortized Discount Total 8 25,000 52,000 50,000 40,000 50,000 50,000 45,000

~III) 8 25,000 52,000 50,000 40,000 50,000 50,000 45,000

~R) 12K 1K'in thousands) 7 1998 " Hay 1

7.30 1999 - December 15 7.63 2001 - Juno 1

7.60 2002 - November 1

7.70 2002 - December 15 6.80 2003 - July 1

6.55 2003 - October 1

6.10 2003 - November 1

6.55 2004 - Hatch 1

9.50 2021 - Hay 1

9.SO 2021 - Hay 1

9.50 2021 - May 1 8.75 2022 - Hay 1 8.50 2022 - December 1S 7.80 2023 - July 1

7.35 2023 - October 1

7.20 2024 - Febzuary 1

7.50 2024 - Hazch 1

Unamortized Discount (net)

Total 8 3S,OOO 35,000 40,000 50,000 40,000 20,000 20,000 30,000 25,000 50,000 75,000 20,000 20,000 40,000 25,000

~~)

8 35,000 35,000 40,000 50,000 40,000 20,000 20,000 30,000 25,000 10,000 10,000 20,000 50,000 75,000 20,000 20,000 40,000 25,000

~~)

Certain indentures relating to the first mortgage bonds contain improvement, maintenance and re-placement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certifi-cation of unfunded property additions.

(a) Nuclear Fuel Disposal Costs including interest accruod.

Soe Note 3.

(b) 8X - Due March 31, 2026 - 840,000,000 Outstanding less 81,228,500 discount.

(c) Called for redemption on Harch 1, 1996.

First mortgage bonds outstanding were as fol-lows:

(a) The variable interest rate is determined weekly.

The average weighted interest rate was 3.5X for 1996 and 4.6X foz 1995.

(b) The adjustable interest rate can be a daily, weekly, ccmnorclal paper or term rate as designated by the Company.

h weekly rate was selected which ranged from 2.4X to S.OX in 1996 and fzom 2.9X to 5X in 1995 and averaged 3.4X and 4.0X during 1996 and 1995, zespectively.

Under the terms of certain installment purchase contracts, the Company is required to pay amounts sufficient to enable the cities to pay interest on a the principal (at stated maturities and upon man tory redemption) of related pollution control reven bonds issued to finance the construction of pollution control facilities at certain generating plants.

On the two variable rate series the principal is payable at the stated maturities or on the demand of the bondhold-ers at periodic interest adjustment dates which occur weekly.

The variable rate bonds due in 2014 are supported by a bank letter of credit which expires in 2002.

I&Mhas agreements that provide for brokers to remarket the adjustable rate bonds due in 2025 tendered at interest adjustment dates.

In the event certain bonds cannot be remarketed, IIlLM has a

standby bond purchase agreement with a bank that provides for the bank to purchase any bonds not remarketed.

The purchase agreement expires in 2000.

Accordingly, the variable and adjustable rate installment purchase contracts have been classified for repayment purposes based on the expiration dates of the standby purchase agreement and the letter of credit.

28

INDIANAhflCHIGANPOWER COhfPANY AND SUBSIDIARIES At December 31, 1996, future annual long-term debt payments, excluding premium or discount, are

12. COMMON SHAREHOLDER'S EQUITY:

as follows:

1998 1999 2000 2001 Later Years Total (in thousands)

S 35,000 35,000 50,000 40,000

~LKk Mortgage indentures, charter provisions and orders of regulatory authorities place various restrictions on the use of retained earnings for the payment of cash dividends on common stock. At December 31, 1996, S5.9 million of retained earnings were restricted.

Regulatory approval is required to pay dividends out of paid-in capital

~

Short-term debt borrowings are limited by provi-sions of the 1935 Act to S175 million.

Lines of credit are shared with AEP System companies and at December 31, 1996 and 1995 were available in the amounts of S409 million and S372 million, respec-tively. Commitment fees of approximately 1/8 of 1%

of the unused short-term lines of credit are paid each year to the banks to maintain the lines of credit.

In 1996 and 1995 net changes in paid-in capital of S170,000 and S(2,548,000),

respectively, repre-sented gains and expenses associated with cumula-tive preferred stock transactions.

13. UNAUDITEDQUARTERLY FINANCIAL INFORMATION:

Outstanding short-term debt consisted of:

Quarterly Periods Operating Operating Net Jhn(gnnng dnongtu anno(gg (in thousands)

December 31, 1996:

Note Payable Coamercial Paper Total ecember 31, 1995:

Note Payable Coamercial Paper Total Balance Outstanding 8 3,900

$52,200

~2Li S~

Year-end Weighted hverage Intdu3~Inta 5.5X 7.2 7.0 6.1X 6.1 6.1 1996 Hazch 31 June 30 September 30 December 31 1995 Hazch 31 June 30 September 30 December 31 327, 177 307,820 334,846 313,314 56,311 51,386 54,4oo 43,626 S329

~ 883

$53 ~ 018 323,494 50,430 339, 847 61, 123 335,269 55,846 S35,767 33,507 44,546 43,333 38,388 33,780 37,404 31,520 29

OPERATING STATISTICS OPERATING REVENUES (in thousands):

Retail:

Residential:

Without Electric Heating With Electric Heating Total Residential Commercial Industrial Miscellaneous Total Retail Wholesale (sales for resale)

Total Revenues from Energy Sales Provision-for Refunds of Revenues Collected in Prior Years Total Net of Provision for Refunds Other Total Operating Revenues 1,308,218 1,267,268

~a2Z6

~KBB2

~ri)

~~)

1,233,551 1,184,508 1,180,516 3LZtB ~LLK ~L238

~28A93 ~83.36Z XL261 K8 ~292~ ~96&%

232,212 S

239,266 227,358 S

205,315 S 209,682

~QB 'dB ~LSD ~LSD ~BRRk 343,768 348,770 334,881 302,883 308,235 253,750 256,319 247,938 220,938 228,285 312,777 298,256 291,527 250,939 267,643 82 ~i 'Q6

'~ ~LQ12 916,740 909,827 880,662 780,353 815,175

~KL428 ~~

~52JB)B ~LR1Q ~L322 1,308,218 1,267,268 1,233,551 1,185,263 1,184,554 SOURCES AND USES OF ENERGY (in millions of kilowatthours):

Sources:

Net Generated:

Fossil Fuel Nuclear Fuel Hydroelectric Total Net Generated Purchased and Power Pool Total Sources Less: Losses, Company Use, Etc.

Net Sources 13,304 16,396 29,799

~M1 37,380 35~

12,850 13,999 26,935

~Z1 32,806

~ZQQ 31 MB 13,022 9,291 22,408

~ZGZ 28,165

~MR 2K2fiZ 12,236 16,313 1Q6 28,655

~BZR 33,534 3233K 11,597 6,418 1QQ 18,115

~2 27,457

~466 26.991 Uses:

Retail Sales:

Residential:

Without Electric Heating With Electric Heating Total Residential Commercial Industrial Miscellaneous Total Retail Wholesale Sales (sales for resale)

Total Uses 3,329

~811 5,140 4,328 7,295 16,845 32259 32586 3,390

~Z68 5,158 4,300 6,582 16,122

~SR 31JQB 3,210

~zzz 4,937 4,148 6,453 15,620 1LX4Z 26~

3,178

~ZQB 4,884 3,977 6,025 14,969 1Z 216 32~

3,001 4,634 3,747 5,685 14,260 212lU.

2!L891 30

OPERATING STATISTICS (Concluded)

IND NA MICHIGANPOWER COMPANY AND SUBSIDIARIES AVERAGE COST OF FUEL CONSUMED (in cents):

Per MillionBtu:

Coal Nuclear Overall Per Kilowatthour Generated:

Coal Nuclear Overall 122 44 74 1.22

.47

.80 126 43 78 1.23

.47

.83 124 42 85 1.21

.47

.90 130 36 72 1.27

.40

.77 136 54 103 1.34

.61 1.08 RESIDENTIALSERVICE - AVERAGES:

Annual Kwh Use per Customer:

With Electric Heating Total Annual Electric Bill:

With Electric Heating Total Price per Kwh (in cents):

With Electric Heating Total 18,206 10,791

$ 1,121.41 0721.76 6.16 6.69 18,044 10,943

$ 1,117.55 0739.99 6.19 6.76 17,907 10,572 17,980 10,559 6.23 6.78 5.72 6.20

$ 1,115.19 01,028.26

$717.17

$654.76 17,513 10,107

$ 1,056.91

$672.31 6.04 6.65 UMBER OF CUSTOMERS:

Year-End:

Retail:

Residential:

Without Electric Heating With Electric Heating Total Residential Commercial Industrial Miscellaneous Total Retail Wholesale (sales for resale)

Total Electric Customers 378,757

&K322 479,129 55,869 5,345

~8M 542,163 375,929

~9L1QK 475,034 55,077 5,316

~ZBZ 537,224 372,473 2

469,875 53,927 5,213

~JKHi 530,821 369,385

~ZRi 465,180 53,081 5,157

~ZLi 525,201 366,835

~32'i 461,010 52,542 5,000

~Z51 520,303 K%24$k 53L2M 5ZL825

'MZH, 52(L3M 31

t DIVIDENDSAND P ICE RANGES OF CUMULATIVEPREFERRED STOCK B

Quarters (1996 and 1995)

($ 100 Paz Value) 4-1/8X Series Dividends Paid Per Shaze Market Price - 8 Per Share (CSE)

- High

- Low

$1. 03125

$1. 03125

$ 1. 03125

$1. 03125

$1. 03125

$1. 03125

$1. 03125

$1. 03125 4.56X Series Dividends Paid Per Share Hazket Price - $ Per Share (OTC)

Ask - High

- Low Bid - High

- Low

$1. 14 51 49-3/8 51-1/4 51 52 51-1/4 52 52

$1 ~ 14

$1 ~ 14

$1. 14 46-5/8 45-1/2 47-1/4 46-1/4 47-1/2 47-1/4 49-1/2 47-1/2

$ 1. 14

$1. 14

$1. 14

$1. 14 4.12X Series Dividends Paid Per Share Hazket Price - 8 Per Shaze (OTC)

Ask - High

- Low Bid - High

- Low

$ 1. 03 51 48-1/4 49 48-3/4 49-3/4 49 50 49-3/4

$1. 03

$1. 03

$1. 03

$1. 03 46-1/2 43

$ 1. 03 47 46

$ 1. 03 51 46

$1. 03 51 46 5.90X Series Dividends Paid Per Share Harket Price - 8 Per Share (OTC)

Ask (high/low)

Bid (high/low)

$1. 475

$1. 475

$1. 475

$1. 475

$1.475

$1 ~ 475

$1. 475

$1. 475 6-1/4X Series Dividends Paid Por Shaze Hazkot Price - 8 Per Share (OTC)

Ask (high/low)

Bid (high/low) 6.30X Series Dividends Paid Per Share Market Price - 8 Per Share (OTC)

Ask (high/low)

Bid (high/low)

$1.5625

$1.5625

$1.5625

$1.5625

$ 1. 575

$1. 575

$ 1. 575

$1. 575

$1.5625

$1.5625

$1.5625

$1.5

$1. 575

$1. 575

$1. 575

$1. 575 6-7/SX Series Dividends Paid Pez Share Harkot Price - 8 Per Share (OTC)

Ask (high/low)

Bid (high/low)

$ 1. 71875

$1. 71875

$1. 71875

$ 1. 71875

$1. 71875

$1. 71875

$1. 71875

$1. 71875 7.08X Series (a)

Dividends Paid Por Share Harket Price '- $ Per Share (NYSE) " High

- Low

$1.77

$ 1. 77 83-5/8 76

$1. 77 88-1/2 84

$1.77 91 86

$1.77 99-1/2 86 CSE

- Chicago Stock Exchange OTC

- Over-the-Counter NYSE - New York Stock Exchange Note - The abovo bid and asked quotations represent prices between dealers and do not represent actual tzansactions Harket quotations pzovided by National Quotation Bureau, Inc.

Dash indicated quotation not available.

(a) Redeemed April 1996 32

IND NA MICHIGANPO YVER COMPANY ECURITY OWNER INQUIRIES Security owners should direct 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 1997 at no cost to shareholders.

Please address requests for copies to:

Geoffrey C. Dean American Electric Power Service Corporation 26th 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 33

Indiana Michigan Power Service Area and the American Electric Power System LAKE MICHIGAN MICHIGAN IAKE ERIE OHIO INDIANA WEST VIRGINIA KENTUCKY VIRGINIA Indiana Michigan Power Co. area

~ Other AEP operating companies'reas

~

Major power plant TENNESSEE printed on recycled paper

ATTACHMENT 2 TO AEP:NRC:0909M INDIANAMICHIGAN POWER COMPANY'S PROJECTED CASH FLOW FOR 1997

Indiana Michigan Power Co.

1997 Forecasted Sources and Uses of Funds Based on Forecasted Case 9701 S Millions Projected 1997 Net Income After Taxes Less Dividends Paid 1 70.8 121.8 Retained Earnings Adjustments:

49.0 Depreciation And Amortization Deferred Operating Costs Deferred Federal Income Taxes and Investment Tax Credits AFUDC Other 161.6 11.3 (11.3)

(1.0)

(21.7)

Total Adjustments 1 38.9 Internal Cash Flow 1 87.9 Average Quarterly Cash Flow 47.0 Average Cash Balances and Short-Term Investments 15.3 Total 62.3

0,