ML17334B754
| ML17334B754 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 12/31/1997 |
| From: | Fitzpatrick E INDIANA MICHIGAN POWER CO. (FORMERLY INDIANA & MICHIG |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| AEP:NRC:0909N, AEP:NRC:909N, NUDOCS 9805050269 | |
| Download: ML17334B754 (102) | |
Text
CATEGORY REGUL RY INFORMATION DISTRXBUT il SYSTEM (RIDS)
~ DOCKET ACXL:50-315 Donald C. Cook Nuclear Power Plant, Unit 1, Xndiana M 05000315 50-316 Donald C. Cook Nuclear Power Plant, Unit 2, Indiana M 05000316 AUTH. NAME AUTHOR AFFILIATION FXTZPATRXCK,E.E Indiana Michigan Power Co. (formerly Indiana 8 Michigan Ele
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RECIP.NAME RECIPIENT AFFILIATION
SUBJECT:
"Indiana Michigan Power Co's Annual R t for 1997." C Projected cash flow for 1998,encl.W 980428 ltd.
SIZE:
A DISTRIBUTION CODE: M004D COPIES RECEIVED:LTR ENCL TITLE: 50.71(b) Annual Financial Report T NOTES: E RECIPIENT COPIES RECIPIENT COPIES 6 ID CODE/NAME LTTR ENCL ID CODE/NAME LTTR ENCL PD3-3 LA 1 1 PD3-3 PD 1 1 0 STANG, J 1 1 INTERN . LE 1 1 NRR/DRPM 1 1 NRR/DRPM/PGEB 1 1 EXTERNAL: NRC PDR 1 1 D
0 U
E 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) ON EXTENSION 415-2083 TOTAL NUMBER OF COPIES REQUIRED: LTTR 7 ENCL 7
Indiana Michigan Power Company~
500 Circle Drive ~
Buchanan, Ml 49107 1395 INOlAMAl NlCIHIl6AN PWM April 28, 1998 AEP:NRC:0909N Docket Nos.: 50-315 50-316 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Mail Stop 0-P1-17 Washington, D.C. 20555-0001 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 l997. Attachment 2 contains a copy of Indiana Michigan Power Company's projected cash flow for 1998. 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 CC: Z. A. Abramson A. B. Beach MDEQ - DW & RPD NRC Resident Inspector R. Sampson
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9805050269 9'7i23i PDR ADQCK 05000315 E PDR
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...9805050269 ATTACHMENT 1 TO AEP:NRC:0909N INDIANA MICHIGAN POWER COMPANY'S ANNUAL REPORT FOR 1997
2997 Financial Statements and Management's Discussion and Analysis of Results of Operations and Financial Condition
'NERlCAN ELECTRIC POWER AEP: Amen'ca's Energy Partner"
AMERICAN ELECTRIC POWER 1 Riverside Plaza Columbus, Ohio 43215-2373 CONTENTS Selected Consolidated Financial Data Management's Discussion and Analysis of Results of Operations and Financial Condition...... ~ 3 - 15 Consolidated Statements of Income and Consolidated Statements of Retained Earnings 16 Consolidated Statements of Cash Flows 17 Consolidated Balance Sheets . 18-19 Notes to Consolidated Financial Statements 20-35 Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries .. 36 Schedule of Consolidated Long-term Debt of Subsidiaries . 37 Management's Responsibility . 38 Independent Auditors'eport 39
AMERICANELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SELECTED CONSOLIDATED FINANCIALDATA INCOHE STATEHENTS DATA (in millions):
Operating Revenues $ 6,161 $ 5,849 $ 5,670 $ 5,505 $ 5,269 Operating Income 984 1,008 965 932 929 Income Before Extraordinary Item 620 587 530 500 354 Extraordinary Loss-UK Windfall Tax 109 Net Income 511 587 530 500 354 94 BALANCE SHEETS DATA (in millions):
Electric Utility Plant $ 19,597 $ 18,970 $ 18,496 $ 18,175 $ 17,712 Accumulated Depreciation and Amortization Net Electric Utility Plant %11 ~63 QL ~4 X1LBK QL2% ~m Total Assets $ 16,615 $ 15,883 $ 15,900 $ 15,736 $ 15,359 Common Shareholders'quity 4,677 4,545 4,340 4,229 4,151 Cumulative Preferred Stocks of Subsidiaries:
Not Subject to Handatory Redemption 47 90 148 233 268 Subject to Handatory Redemption* 128 510 523 590 501 Long-term Debt* 5,424 4,884 5,057 4,980 4,995 Obligations Under Capital Leases* 538 414 405 400 284
- Including portion due within one year d 0 COHHON STOCK DATA:
Earnings per Common Share:
Before Extraordinary Item $ 3.28 $ 3. 14 $ 2.85 $ 2.71 $ 1.92 Extraordinary Loss - UK Windfall Tax ~j9)
Net Income ~7 Average Number of Shares Outstanding (in thousands) 189,039 187,321 185,847 184,666 184,535 Harket Price Range: High $ 52 $ 44-3/4 $ 40-5/8 $ 37-3/8 $ 40-3/8 Low 39-1/8 38-5/8 31-1/4 27-1/4 32 Year-end Market Price 51-5/8 41-1/8 40-1/2 32-7/8 37-1/8 Cash Dividends Paid $ 2.40 $ 2.40 $ 2.40 $ 2.40 $ 2.40 Dividend Payout Ratio 88.7X(a) 76.5X 84.1g 88.6X 125.2X Book Value per Share $ 24.62 $ 24.15 $ 23.25 $ 22 '3 $ 22.50 (a) Dividend Payout Ratio before Extraordinary Loss - UK Windfall Tax is 73. IX.
AMERICANELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES ANAGENIENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND INANCIALCONDITION This discussion includes forward- facilities at large commercial and industrial looking statements within the meaning of plant sites including initially 16 Conoco and Section 21E of the Securities Exchange Act Dupont plant sites. 'The completion of of 1934. These forward-looking statements agreements for the joint venture companies reflect assumptions, and involve a number of and the commencement of operations are risks and uncertainties. Among the factors expected in 1998.
that could cause actual results to differ materially are: electric load and customer In December 1997 American Electric growth; abnormal weather conditions; Power Company (AEP or the Company) and available sources and costs of fuels and Central and South West Corporation (CSW) availability of generating capacity; the, speed agreed to merge. The merger is subject to and degree to which competition is approval by regulators and shareholders.
introduced to our power generation business, Completion of the merger is expected to the terms of the transition to competition, and occur in the first half of 1999. CSW, a its impact on rate structures; the ability to Dallas-based public utility holding company, recover stranded costs, new legislation and owns four domestic electric utility government regulations, the ability of the subsidiaries serving 1.7 million customers in Company to successfully reduce its costs portions of Texas, Oklahoma, Louisiana and including synergy estimates; the degree to Arkansas and a regional electricity company which the Company develops non-regulated in the UK. Other international energy business ventures and their success; the operations and non-utility subsidiaries owned economic climate and growth in our service by CSW are involved in energy-related territory; inflationary trends, interest rates investments, telecommunications, energy and other risks. efficiency services and financial transactions.
In 1997 management took several major steps towards our growth oriented goal of being America's Energy Partner and a AEP's 1997 income before an global energy and related services company. extraordinary loss, the one-time UK Windfall Construction of a 250-megawatt generating Tax, increased 6% to $ 620 million or $ 3.28 station in China, jointly owned with two per share from $ 587 million or $ 3.14 per Chinese partners, progressed on schedule share in 1996. The increase was primarily and within budget. In April, the Company attributable to increased transmission service and New Century Energies, Inc. acquired revenues, reduced preferred stock dividends Yorkshire Electric Group pic, a United due to a redemption program and an Kingdom (UK) distribution company. The increase in nonoperating income from the Yorkshire investment is accounted for using April 1997 investment in Yorkshire exclusive the equity method. A new power marketing of the extraordinary loss. Net income business was launched in July contributing inclusive of the $ 109 million extraordinary significantly to our operating revenues which loss decreased $ 76 million or 13% primarily surpassed $ 6 billion for the first time. A joint due to the UK one-time windfall tax which venture with Conoco, an energy subsidiary of was based on a revision or recomputation of Dupont, was announced in October that will the original privatization value of certain provide energy management services as well privatized utilities, including Yorkshire.
as financing of steam and electric generation
For further details regarding changes the then-existing market price of electricity.
in operating revenues and expenses, taxes and nonoperating investment earnings in Under the provisions of Statement of 1997 and 1996 see Results of Operations. Financial Accounting Standards (SFAS) No.
71 "Accounting for the Effects of Certain Types of Regulation," regulatory assets (deferred expenses) and regulatory liabilities The Company's ability to recover its (deferred revenues) are included in the costs as the industry transitions to consolidated balance sheets of regulated competition and as customer choice is more utilities in accordance with regulatory actions broadly available is the most significant and in order to match expenses and factor affecting its future. Competition in the revenues with cost-based rates. In order to wholesale generation market continues to maintain net regulatory assets (net expense intensify since the adoption of federal deferrals) on the balance sheet, SFAS No.
legislation in 1992 which gave wholesale 71 requires that rates charged to customers customers the right to choose their energy be cost-based. In the event a portion of supplier and the Federal Energy Regulatory AEP's business no longer meets the Commission (FERC) orders issued in 1996 requirements of SFAS No. 71, net regulatory which forced open access transmission. The assets would have to be written off for that introduction of competition and customer portion of the business. The provisions of choice for retail customers has been slow SFAS No. 71 and SFAS No. 101 "Accounting although activity has been increasing. for the Discontinuance of Application of Federal legislation has been proposed to Statement No. 71" never anticipated that mandate competition and customer choice at deregulation would include an extended the retail level, and several states have transition period or that it would provide for introduced or are considering similar recovery of stranded costs after the transition legislation. All of our states have initiatives period. In July 1997 the Emerging Issues to move to customer choice that will phase- Task Force (EITF) of the Financial in or allow for a transition to competition, Accounting Standards Board (FASB) although the timing is uncertain. The reached a consensus that the application of Company supports customer choice and is SFAS No. 71 to a segment of a regulated proactively involved in discussions at both electric utilitywhich is subject to a legislative the state and federal levels regarding how plan to transition to competition in that best to structure and transition to a segment should cease when the legislation is competitive marketplace. passed or an enabling rate order is issued containing sufficient detail for the utility to As the cost of generation in the electric reasonably determine what the plan would energy market evolves from cost-of-'service entail. The EITF indicated that the cessation ratemaking to market-based pricing, many of application of SFAS 71 would require that complex issues must be resolved, including regulatory assets and impaired plant be the recovery of stranded costs. While FERC written off unless they are recoverable.
orders No. 888 and 889 provide, under certain conditions, for recovery of stranded Although FERC orders No. 888 and cost at the wholesale level, the issue of 889 provide for competition in the firm stranded cost is unresolved at the much wholesale market, that market is a relatively larger retail level. The amount of any small part of our business and most of our stranded costs we may experience depends firm wholesale sales are still under cost-of-on the timing and extent to which direct service contracts. As a result AEP's competition is introduced to our business and generation business is still cost-based
regulated and should remain so for the near old customer system and a nine-year-old future pending the passage of enabling state transmission and distribution work legislation to deregulate the generation management system. Process improvement business. We believe that enabling state efforts and expenditures to develop and legislation should provide for the recovery of implement the new customer service system any generation-related net regulatory assets and similar efforts and expenditures to and other reasonable stranded costs from acquire, install and enhance new client impaired generation assets. We are working server-based accounting and with regulators, customers and legislators to budgeting/financial planning software should provide for recovery of these stranded costs produce further improvements and during a transition period in which rates are efficiencies, enabling AEP to continue to fixed or frozen and electric utilities would offer its customers excellent service at take steps to achieve cost savings which competitive prices.
would be used to reduce or eliminate their stranded costs. However, if in the future AEP's generation business were to no longer be cost-based regulated and if it were not AEP recognizes that it must continue to possible to demonstrate probability of manage coal costs to maintain its competitive recovery of resultant stranded costs including position. Approximately 90% of AEP's regulatory assets, results of operations, cash generation is coal fired and approximately flows and financial condition would be 17% of the 53 million tons of coal burned in adversely affected. 1997 were supplied by affiliated mines with the remainder acquired under long-term contracts and purchases in the spot market.
As long-term contracts expire we are negotiating with unaffiliated suppliers to Efforts continue by AEP to reduce the lower coal costs. We intend to continue to costs of its products and services in order to prudently supplement our long-term coal maintain our competitiveness. Prior to 1997, supplies with spot market purchases as long reviews of our major domestic processes led as favorable spot market prices exist.
to decisions to consolidate management and certain functions and operations and improve In prior years we have agreed in our certain major processes. While staff Ohio jurisdiction to certain limitations on the reductions and cost savings resulting from recovery of affiliated coal costs. Our the restructuring and improvements are analysis shows that we should be able to presently being achieved, expenses for new recover the Ohio jurisdictional portion of the marketing, customer services and modern costs of our affiliated mining operations efficient management information systems including future mine closure costs.
are increasing to prepare for competition. In Management intends to seek recovery of its 1997 the costs of these efforts to prepare for non-Ohio jurisdictional portion of the competition offset the savings from investment in and the liabilities and closing restructuring. costs of our affiliated mines estimated at
$ 102 million after tax. However, should it In 1997, AEP also began installing a become apparent that these affiliated mining new uniTied customer service system which is costs will not be recovered from Ohio and/or designed to support the request for service, non-Ohio jurisdictional customers, the mines billings, accounts receivable, credit and may have to be closed and future earnings, collection functions. AEP's new unified cash fiows and possibly financial condition customer service system replaces a 30-year- could be adversely affected. In addition
compliance with Phase II requirements of the SNF, the cost of both temporary and Clean Air Act Amendments of 1990 (CAAA), permanent storage will continue to increase.
which become effective in January 2000, The cost to decommission the Cook Plant is could also cause the mining operations to affected by both NRC regulations and the close. Unless the cost of any mine closure is DOE's SNF disposal program. Studies recovered either in regulated rates or as a completed in 1997 estimate the cost to stranded cost under a plan to transition the decommission the Cook Plant range from generation business to competition, future $ 700 million to $ 1.152 billion in 1 997 dollars.
earnings, cash flows and possibly financial This estimate could escalate due to condition could be adversely affected. uncertainty in the DOE's SNF disposal program and the length of time that SNF may ss need to be stored at the plant site delaying decommissioning. Presently we are Significant efforts have been made to recovering the estimated cost of enhance our competitiveness in nuclear decommissioning the Cook Plant over its power generation and to improve our nuclear remaining life. However, AEP's future results organizational efficiency. In 1997 we of operations, cash flows and possibly its continued to receive the "excellence in financial condition could be adversely performance" award from the Institute of affected if the cost of SNF disposal and Nuclear Power Operations. Nuclear power decommissioning continues to increase and plants have a major future financial cannot be recovered.
commitment to safely dispose of spent nuclear fuel (SNF) and radioactive plant On September 9 and 10, 1997, during components (i.e. to decommission the plant). a NRC architect engineer design inspection, It is difficult to reduce nuclear generation questions regarding the operability of certain costs since certain major cost components safety systems caused Company operations are impacted by federal laws and Nuclear personnel to shut down Units 1 and 2 of the Regulatory Commission (NRC) regulations. Cook Plant. On September 19, 1997, the NRC issued a Confirmatory Action Letter The Nuclear Waste Policy Act of 1982 requiring the Company to address the issues established federal responsibility for the identified in the letter. The Company is permanent off-site disposal of SNF and high- working with the NRC to resolve these issues level radioactive waste. By law we and other issues related to restart of the participate in the Department of Energy units. Certain issued identified in the letter (DOE) SNF disposal program which is have been addressed. At this time described in Note 4 of the Notes to management is unable to determine when Consolidated Financial Statements. Since the units will be returned to service. If the 1983 our customers have paid $ 272 million units are not returned to service in a for'the disposal of nuclear fuel consumed at reasonable period of time, it could have an the Donald C. Cook Nuclear Plant (Cook adverse impact on results of operations, cash Plant). Under the provisions of the Nuclear flows and possibly financial condition.
Waste Policy Act, collections from customers are to provide the DOE with money to build a repository for spent fuel. To date the federal government has not made sufficient progress We take great pride in our efforts to towards a permanent repository or otherwise economically produce and deliver electricity assuming responsibility for SNF. As long as while minimizing the impact on the there is a delay in the construction of a environment. Over the years AEP has spent government approved storage repository for over a billion dollars to equip our facilities
with the latest cost effective clean air and where we have been named a PRP or water technologies and to research possible defendant, our disposal or recycling activity new technologies. We are also proud of our was in accordance with the then-applicable award winning efforts to reclaim our mining laws and regulations. Unfortunately, properties. We intend to continue in a CERCLA does not recognize compliance as leadership role fostering economically a defense, but imposes strict liability on prudent efforts to protect and preserve the parties who fall within its broad statutory environment. categories.
0 s While the potential liability for each Superfund site must be evaluated separately, By-products from the generation of several general statements can be made electricity include materials such as ash, regarding our potential future liability.
slag, sludge, low-level radioactive waste and Disposal at a particular site by AEP is often SNF. Coal combustion by-products, which unsubstantiated; the quantity of material we constitute the overwhelming percentage of disposed of at a site was generally small; these materials, are typically disposed of or and the nature of the material we generally treated in captive disposal facilities or are disposed of was nonhazardous. Typically, beneficially utilized. In addition, our we are one of many parties named as PRPs generating plants and transmission and for a site and, although liability is joint and distribution facilities have used asbestos, several, generally some of the other parties polychlorinated biphenyls (PCB) and other are financially sound enterprises. Therefore, hazardous and nonhazardous materials. We our present estimates do not anticipate are currently incurring costs to safely dispose material cleanup costs for identified sites for of such substances. Additional costs could which we have been declared PRPs.
be incurred to comply with new laws and However, if for reasons not currently regulations if enacted. identified significant cleanup costs are attributed to AEP in the future, results of The Comprehensive Enviromental operations, cash flows and possibly financial Response, Compensation and Liability Act condition would be adversely affected unless (CERCLA or Superfund) addresses clean-up the costs can be recovered from customers.
of hazardous substances at disposal sites and authorized the United States c s Environmental Protection Agency (Federal EPA) to administer the clean-up programs. Federal EPA is required by the CAAA As of year-end 1997, we are involved in to issue rules to implement the law. In litigation with respect to five sites overseen December 1996 Federal EPA'issued final by the Federal EPA and have been named rules governing nitrogen oxide (NOx) by the Federal EPA as a "Potentially emissions that must be met after January 1, Responsible Party" (PRP) for seven other 2000 (Phase II of the CAAA). The final rules sites. There are seven additional sites for will require substantial reductions in NOx which AEP companies have received emissions from certain types of boilers information requests which could lead to including those in AEP's power plants. On PRP designation. Also, an AEP subsidiary February 13, 1998, the United States Court has received an information request with of Appeals for the District of Columbia respect to one site administered by state Circuit, in an appeal in which the AEP authorities. Our liability has been resolved System operating companies participated, for a number of sites with no significant effect upheld the emission limitations. In addition on results of operations. In those instances in November 1997 the Federal EPA
published a proposed rulemaking requiring Company must bear a significant portion of the revision of state implementation plans in the cost of compliance in a region that is in 22 eastern states, including those states in violation of the revised standards, it would which the operating companies of the AEP have a material adverse effect on results of System have coal-fired generating plants. operations, cash flows and possibly financial The proposed rule will require reductions in condition unless such costs are recovered NOx emissions from utility sources of from customers.
approximately 85% below 1990 levels and entail very substantial capital and operating At the global climate conference in expenditures by AEP System operating Kyoto, Japan in December 1997 more than companies. Pollution controls to meet the 160 countries, including the United States, proposed revised NOx emission limits would negotiated a treaty limiting emissions of have to be in place by 2002. Eight northeast greenhouse gases, chiefly carbon dioxide, states have petitioned Federal EPA for the which may eventually contribute to global imposition of additional NOx controls for warming. Although there is no dear scientific upwind industrial and utility sources. The evidence that carbon dioxide contributes to matter is being litigated. The costs to comply global warming and damages the with the emission reductions required by the environment, the treaty, which requires Federal EPA's actions are expected to be Congressional approval, calls for a seven substantial and would have a material percent reduction below the emission levels adverse impact on future results of of greenhouse gases in 1990. We intend to operations, cash flows and possibly financial work with Congress to insure that science condition if the resultant costs are not and reason are introduced to the debate. If recovered from customers. approved by Congress the costs to comply with the emission reductions required by the In 1997 the Federal EPA published a Kyoto treaty is expected to be substantial revised ambient air quality standard for and would have a material adverse impact on ozone and established a new ambient air results of operations, cash flows and possibly quality standard for fine particulate matter. financial condition if not recovered from These standards are expected to result in customers.
redesignation of a number of areas of the country currently in compliance with the existing standard to nonattainment status which could ultimately dictate more stringent emission restrictions for AEP generating units. Under the new rules the states must first determine whether the standards are Net income decreased 13% to $ 511 being achieved. The states then have three million primarily due to an extraordinary loss years to submit a compliance plan and up to of $ 109 million from the UKs one-time ten years after designation to come into windfall tax which was based on a retroactive compliance with the new standards. The revaluation of the original privatization price compliance deadline could be as late as of certain privatized utilities, including 2010 for the ozone standard and 2012-2015 Yorkshire. Income before the extraordinary for the fine particulate standard. Although loss increased 6% in 1997 to $ 620 million or we are reviewing the impact of the new rules, $ 3.28 per share from $ 587 million or $ 3.14 we are unable to estimate compliance costs per share in 1996. The increase is primarily without knowledge of the reductions that will attributable to increased transmission service be necessary to meet the new standards. If sales, reduced preferred stock dividends due such reductions are significant and the to a redemption program and an increase in
f The nonoperating income from the April 1997 customers reflecting mild weather.
i investment in Yorkshire exclusive of the decline in residential sales was completely extraordinary loss. offset by an increase in lower priced sales to industrial customers, reflecting increased In 1996 net income increased 11% to usage which resulted in a small increase in
$ 587 million or $ 3.14 per share from $ 530 total retail energy sales. The negative price million or $ 2.85 per share in 1995. The variance resulted from the shift from higher increase was mainly attributable to increased priced residential sales to lower priced sales of energy and services and reduced industrial sales.
interest charges and preferred stock dividends. Sales increased due to increased In 1997 wholesale revenues and sales transmission and other services provided to increased significantly primarily due to new power marketers and utilities and increased power marketing transactions which began in energy sales to non-affiliate utilities and July 1997 when AEP commenced a power industrial customers. The reduction in marketing business. The new power interest and preferred stock dividends marketing transactions involve the resulted from the Company's refinancing substantial purchase and sale of electricity program. Also contributing to the outside of the AEP transmission system. An improvement in net income in 1996 were increase in coal conversion service sales severance pay charges recorded in 1995 in also contributed to the significant increase in connection with the restructuring of wholesale sales and revenues. These sales management and operations and gains are for the generation of electricity from the recorded in 1996 from emission allowance coal of the purchaser.
transactions.
An increase of $ 33 million in transmission service revenues produced the increase in other operating revenues in Operating revenues increased 5% in 1997. Transmission service revenues are for 1997 and 3% in 1996. Increased wholesale the transmission of other companies'ower energy sales and transmission and coal through AEP's extensive transmission conversion service revenues were the system. These revenues have increased primary reasons for the increases in both significantly since the issuance of the years. The change in revenues can be FERC's open access transmission rules in analyzed as follows: 1996.
Increase (Oecrease)
III v In 1996 retail revenues increased Retail: slightly due to growth in the number of
~ customers and the addition of a major new Price Variance S(44.0) S (42.9)
Volume Variance 2.4 63.7 Fuel Cost Recoveries Mholesale:
~) (0.3) 0.7 industrial customer in December 1995.
Revenues from higher priced sales to
~
~) residential customers, the most Price Variance 9.6 (202.0)
Volume Variance 269.7 317.3 Fuel Cost Recoveries weather-sensitive customer class, were flat, 36.3 16.4 increasing less than one percent, as the Other Operating Revenues Total 6.3 ~
The slight decrease in retail revenues 3.2 effect of cold winter weather in early 1996 was offset by mild summer and December temperatures. Revenues from lower priced commercial and industrial customers in 1997 was largely due to a decline in higher increased 1% reflecting growth in the number priced sales to weather-sensitive residential of customers. The increase in lower priced
commercial and industrial sales accounted by the quantity and price of wholesale for the negative price variance in 1996. transactions which often depend on the level of competition, the weather and power plant Wholesale revenues increased 16% in availability, both affiliated and non-affiliated, 1996 reflecting a 46% increase in wholesale factors the Company does not control.
sales attributable largely to transactions with However, we work to take advantage of power marketers and other utilities. During these factors when they are favorable.
1996 the Company began providing coal conversion services resulting in 6.8 billion kilowatthours of electricity generated for power marketers and certain other utilities Operating expenses increased 7% in from their coal under a new FERC-approved 1997 and 3% in 1996. Increased purchased interruptible, contingent sales tariff. These power expense, mainly from the Company's sales have lower prices because there is no new power marketing business, was the associated fuel cost. As a result the average primary reason for the 1997 increase. New price per kilowatthour was significantly less marketing, customer services and software in 1996 than in 1995 producing a negative costs to prepare for competition also price variance. Also contributing to the contributed to the increase. The primary increased wholesale sales was a long-term items accounting for the increase in 1996 contract with an unaffiliated utility to supply were increased fuel costs, federal income 205 MW of energy for 15 years beginning taxes and expenditures for marketing, January 1, 1996. information systems and other items necessary to prepare for the transition to An increased level of activity in the competition. Changes in the components of wholesale energy markets, due to FERC's operating expenses were as follows:
open access rulemaking and AEP's aggressive efforts to provide flexible and Increase (Decrease) competitively priced transmission services led to an increase in transmission service ~m ~ ~m revenues in 1996. As a result transmission Fuel Purchased
$ 26.4 1.6 $ 63.5 4.1 Power 330.2 383.5 (2.3) (2.6) service revenues, which are recorded in Other Operat(on 17.3 1.4 25.9 2.2 Ha(ntenance (19.6) (3.9) (39.0) (7.2) other operating revenues, increased by Deprec(at(on and approximately $ 24 million. Amort(zat(on (9 ') (1.6) 7.8 1.3 The level of wholesale sales tends to fluctuate due to the highly competitive nature Taxes Other Than Federal Income Taxes Federal Income Taxes Total
~) (8.0) (1.6)
(0.3) 6.9
~
~ 9.4 1.9 25.8 2.9 of the short-term energy market and other Fuel expense increased in 1997 factors, such as affiliated and unaffiliated primarily due to an increase in the average generating plant availability, the weather and cost of fuel consumed reflecting the reduced the economy. The FERC rules which availability of lower cost nuclear generation introduce a greater degree of competition in 1997 due to the unplanned shutdown and into the wholesale energy market have had maintenance outage of both nuclear units the effect of increasing short-term wholesale which began on September 10 and continued sales and transmission service revenues. through year-end. The increase in fuel The Company's sales and in turn its results expense in 1996 was primarily due to an of operations were impacted in 1997 and increase in generation to meet the increase 1996 by the quantities of energy and in industrial and wholesale customer services sold to wholesale customers. demand. The effect of increased generation Future results of operations will be affected was partially offset by reduced average fossil 10
fuel costs, resulting from increased usage of and make investment in new non-regulated lower cost spot market coal, and lower cost business ventures.
uclear fuel.
re e a d ree d The significant increase in purchased e ts power expense in 1997 was primarily due to purchases of electricity for the new power ln 1997 interest charges on both long-marketing business. These purchases were term and short-term debt increased reflecting made to cover sales made to non-affiliates by additional borrowing primarily to fund the the new power marketers. Company's non-regulated operations including the investment in Yorkshire.
ln 1997 restructuring savings in other Preferred stock dividend requirements of the operation expense were more than offset by subsidiaries decreased in 1997 due to the additional expenses for marketing, customer reacquisition of over 4 million shares of service and software costs to prepare for the cumulative preferred stock.
service demands of competition.
The decrease in interest charges and Maintenance expense decreased in preferred stock dividend requirements in 1996 due to the deferral of previously 1996 was mainly due to continued expensed storm damage costs refinancing programs of the Company's commensurate with their recovery over 5- subsidiaries. The refinancings reduced the years and reduced nuclear plant average interest rate and the amount of maintenance expense due to workforce long-term debt and preferred stock reductions and the reduction of contract labor outstanding. The cost of short-term at the Cook Plant. borrowing s in 1996 increased slightly reflecting an increased average balance of The increase in federal income tax short-term debt outstanding.
expense attributable to operations in 1996 was primarily due to an increase in pre-tax operating income and changes in certain book/tax differences accounted for on a ln 1997 AEP maintained its strong flow-through basis and certain permanent financial condition and performance in differences. shareholder value. The year-end closing stock price of $ 51-5/8 was 25.5% higher than the prior year and 57% greater than the 1994 closing price. The Company paid a quarterly The increase in nonoperating income dividend in 1997 of 60 cents a share in 1997 was mainly due to income from non- maintaining the annual dividend rate at $ 2.40 regulated operations. The Company's share per share. The 1997 payout ratio before of earnings from its April 1997 investment in extraordinary loss at 73% was 3% better than Yorkshire was $ 34 million which includes $ 10 1996's and 15% better than 1994's. lt has million of nonrecurring tax benefits related to been a management objective to reduce the a reduction of the UK corporate income tax payout ratio through efforts to increase rate from 33% to 31% effective April 1,1997. earnings in order to enhance AEP's ability to The utilization of foreign tax credits also invest in new business ventures that can contributed to the increase in nonoperating complement our core competencies and income. Nonoperating income decreased in improve shareholder value. AEP's three-1996 due to the cost of the AEP branding year total shareholder return ranked fourth program and the cost of efforts to develop among the companies in the SBP Electric 11
Utility Index. This marked the fourth straight position. The Company's regulated year in the top quartile of the Index. subsidiaries redeemed 4,258,947 shares of Management's goal is to maintain our cumulative preferred stock with rates ranging position in the top quartile of the S8 P Electric from 4.08% to 7.875% at a total cost of $ 433 return.
Utility Index for three-year total shareholder million. The subsidiaries used short-term debt and junior subordinated deferrable interest debentures to pay for the preferred stock tendered and to benefit from the tax deductibility of interest.
The total consideration paid in 1997 by a joint venture of AEP and an unaffiliated The Company and its subsidiaries company to .acquire Yorkshire was issued $ 882 million principal amount of long-approximately $ 2.4 billion which was term obligations in 1997 at interest rates financed by a combination of equity and non- ranging from 5.9% to 8.0%. The companies recourse debt. AEP initiallyfunded its 50% continued to reduce financing costs by equity investment in the joint venture with retiring higher-cost bonds and restructuring
$ 50 million in cash, a $ 300 million adjustable the long-term debt from senior secured/first rate term loan under a long-term revolving mortgage bonds to senior unsecured debt credit agreement and $ 10 million of short- and junior debentures. The principal amount term debt. For more information see Note 7 of long-term debt retirements, including of the Notes to Consolidated Financial maturities, totaled $ 343 million with interest Statements. Also the Company's 70% rates ranging from 6.5% to 9.35%. Our interest in the construction of two 125 MW operating subsidiaries senior secured units in China will require approximately debNirst mortgage bond ratings, which were
$ 110 million of investment. reaffirmed and improved in 1997, are listed in the following table:
AEP's construction expenditures are expected to be $ 2.4 billion over the next three years which includes the Cook Plant's Appalachian Pouer Co. A3 A A A Coluahus Southern Pover Co. A3 A A A Unit 1 steam generator replacement, the Indiana B Nichtgan Pover Co. Baal A 6 8B+ H/A Kentucky Power Co. Baal A K/A China project and the cost of transmission Ohto Power Co. A3 A-BBB+
A A and distribution projects for the improvement H/A ~ llot applicable of and addition to electric energy delivery facilities. Approximately 90% of domestic The operating subsidiaries generally construction expenditures, estimated to be issue short-term debt to provide for interim
$ 2.3 billion for the next three years, will be financing of capital expenditures that exceed financed with internally generated furids. internally generated funds. They periodically reduce their outstanding short-term debt through issuances of long-term debt and additional capital contributions by the parent AEP achieved a year-end ratio of company. The companies formed to pursue common equity to total capitalization non-regulated business opportunities are including amounts due within one year of using short-term debt. Short-term debt 45.5% for 1997, compared with 45.3% for increased $ 235 million from the prior year-1S96 and 43.1% for 1995. The Company's end balance arid decreased by $ 45 million in goal is to maintain the common equity ratio at 1996. At December 31, 1997, AEP Co., lnc.
a level of at least 40 percent. During 1S97 (the parent company) and its subsidiaries the Company and its subsidiaries continued had unused short-term lines of credit of $ 442 redefining and improving their debt to equity million, and several of AEP's subsidiaries
engaged in non-regulated investments and energy businesses had available $ 330 million under a $ 600 million revolving credit In December 1997 AEP and CSW agreement which expires in 1999. The announced that their boards of directors sources of funds available to AEP are approved a definitive merger agreement for dividends from its subsidiaries, short-term a tax-free, stock-for-stock business and long-term borrowings and, when combination transaction which if necessary, proceeds from the issuance of consummated would bring AEP's total market common stock. AEP issued 1,755,000 capitalization to approximately $ 28 billion.
shares in 1997, 1,600,000 shares in 1996 The combination is expected to be accounted and 1,400,000 shares in 1995 of common for as a pooling of interests. Under the stock through a Dividend Reinvestment agreement, each common share of CSW will Program and the Employee Savings Plan be converted to 0.6 shares of AEP. Based I
raising $ 77 million, $ 65 million and $ 49 on the number of CSW common shares million, respectively. outstanding at December 31, 1997, AEP will issue approximately 127 million shares to The following debt and preferred stock CSW common stockholders (valued at $ 6.6 t
coverages of the principal operating billion based on the closing price on the last t
subsidiaries remained strong in 1997: trading day prior to the announcement of the I
merger). Under the merger agreement, there t
Preferred will be no changes with respect to the public i Appalachian Power Co.
Colunbus Southern Power Co.
Indiana h Nlchlgan Power Co.
3.72 4.95 7.57 1.92 NIA 2.88 debt issues or the outstanding preferred stock of AEP, CSW or their subsidiaries.
The merger is conditioned, among other I
Kentucky Power Co. 4.23 N/A things, upon the approval of each company's Ohio Power Co. 9.74 3.67 shareholders and certain state and federal N/A ~ Not ApplfeenIe regulatory agencies. The companies Unless the subsidiaries meet certain anticipate that the required regulatory earnings or coverage tests, they cannot approvals can be obtained in 12 to 18 issue additional mortgage bonds or preferred months. AEP is requesting regulatory and stock. In order to issue mortgage bonds shareholder approval to increase the number
{without refunding existing debt}, each of authorized shares from 300,000,000 to subsidiary must have pre-tax earnings equal 600,000,000 in connection with the merger.
to at least two times the annual interest charges on mortgage bonds after giving effect to the issuance of the new debt.
Generally, issuance of additional preferred The Company as a major power stock requires after-tax gross income at least producer and a trader of electricity and gas equal to one and one-half times annual has certain financial market risks inherent in interest and preferred stock dividend its routine business activities. The trading of requirements after giving effect to the electricity and gas and related future issuance of the new preferred stock. As the contracts exposes the Company to above chart indicates, the subsidiaries commodity price fluctuations. Market risk presently exceed these minimum coverage represents the risk of loss that may impact requirements.
the Company's consolidated financial The Company measures interest rate position, results of operations or cash flows market risk exposure utilizing a Value at Risk due to adverse changes in market prices and (VaR) model. The model is based on the rates. As trading activity increases and the Monte Carlo method of simulated price market for power evolves this risk will movements with a 95% confidence level and become much greater. Various policies and a one year holding period. The vofatilities procedures have been established to and correlations were based on three years manage market risks exposures including the of monthly prices. The risk of potential loss limited usage of energy related derivatives. in fair value attributable to the Company's In its regular business activities, certain exposure to interest rates, primarily related to trading positions of the Company for electric long-term debt with fixed interest rates, was and gas creates exposure to price volatility $ 501 million at December 31, 1997. A near for those products. These commodities are term change in interest rates would not subject to unpredictable price fluctuations materially affect the consolidated financial due to changing economic and weather position or results of operations of the conditions. During 1997 the Company Company. The Company is not currently initiated a power and gas marketing utilizing derivatives to manage its exposure operation that manages the Company's to interest rate fluctuations.
exposure to future price movements using forwards, futures and options. At December The Company has investments in debt 31, 1997, the exposure for financial and equity securities which are held in trust derivatives in these marketing activities were funds to decommission its nuclear plant.
not material to the Company's consolidated Approximately 85% of the trust fund value is results of operations, financial position or invested in tax exempt and taxable bonds, cash fiows. short-term debt instruments or cash. The trust investments and their fair value are Investment in two foreign currency discussed in Note 9 of the Notes to denominated joint ventures also exposes the Consolidated Financial Statements.
Company to currency translation rate risk. At Instruments in the trust funds have not been December 31, 1997, the Company's included in the market risk calculation for exposure to changes in foreign currency interest rates as these instruments are exchange rates related to projects in the UK marked-to-market and changes in market and China is not material to its consolidated value are reflected in a corresponding financial position, results of operations or decommissioning liability. Any differences cash flows. The Company does not between trust fund and ultimate liability are presently utilize derivatives to manage its recoverable from ratepayers.
exposures to foreign currency exchange rate movements. Inflation affects AEP's cost of replacing utility plant and the cost of operating and The Company is exposed to changes maintaining its plant. The rate-making in interest rates primarily due to short- and process limits our recovery to the historical long-term borrowings to fund its business cost of assets resulting in economic losses operations. The debt portfolio has both fixed when the effects of inflation are not and variable interest rates, terms from one recovered from customers on a timely basis.
day to thirty years and an average duration However, economic gains that result from the of eight years at December 31, 1997. repayment of long-term debt with inflated dollars partly offset such losses.
14
problem and the interdependent nature of computer systems, if the Company's corrective actions, and/or the actions of other interdependent entities, fail for critical In connection with the audit of AEP's applications, the Company may be adversely consolidated federal income tax returns the impacted in the year 2000. Although United States Internal Revenue Service (IRS) significant, the cost of correcting the "Year agents sought a ruling from the IRS National 2000" problem is not expected to have a ONce that certain interest deductions material impact on results of operations, cash relating to a corporate owned life insurance flows or financial condition.
(COLI) program should not be allowed. The Company established the COLl program in 1990 as a part of its strategy to fund and reduce the cost of medical benefits for retired In June 1997 the FASB issued SFAS employees. AEP filed a brief with the IRS No. 130 "Reporting Comprehensive income" National Office refuting the agents'osition. and SFAS No.. 131 "Disclosures About No adjustments have been proposed by the Segments of an Enterprise and Related IRS. However, should a full disallowance of Information." SFAS No. 130 establishes the COLI interest deductions be proposed it standards for reporting and displaying would, if sustained, reduce earnings by components of "comprehensive income,"
approximately $ 286 million (including which is the total of net income and all other interest). AEP believes it has meritorious changes in equity except those resulting from defenses and will vigorously contest any investments by shareholders and proposed adjustments. No provisions for this dispositions to shareholders. SFAS No. 131 amount have been recorded. In the event initiates standards for reporting information the Company is unsuccessful it could have a about operating segments in annual and material adverse impact on results of interim financial statements as well as operations and cash flows. related disclosures about products and services, geographic areas and major o e e- e 0 o 'ce customers. AEP's adoption of these new reporting standards in 1998 is not expected Many existing computer hardware and to have a material adverse effect on the software programs will not properly recognize results of operations, cash flows and/or calendar dates beginning in the year 2000. financial condition.
Unless corrected, this "Year 2000" problem may cause computer malfunctions, such as system shutdowns or incorrect calculations and system output. The Company is AEP is involved in a number of legal addressing the problem internally by proceedings and claims. While we are modifying or replacing its computer hardware unable to predict the outcome of such and software programs to mitigate its risk, litigation, it is not expected that the ultimate minimize technical failures, and repair such resolution of these matters will have a failures if they occur. The problem is also material adverse effect on the results of being addressed externally with entities that operations, cash flows and/or flinancial interact electronically with the Company, condition.
including but not limited to, suppliers, service providers, government agencies, customers, creditors and financial service organizations.
However, due to the complexity of the 15
AMERICANELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME gn thousands - except per share amounts)
OPERATING REVENUES KJ.6LÃiR 2~1~
OPERATING EXPENSES:
Fuel 1,627,066 1,600,659 1,537,135 Purchased Power 416,266 86,095 88,396 Other Operation 1,227,368 1,210,027 1,184,158 Maintenance 483,268 502,841 541>825 Depreciation and Amor tization 591,071 600,851 593,019 Taxes Other Than Federal Income Taxes 490,595 498,567 489,223 Federal Income Taxes TOTAL OPERATING EXPENSES
~4L2BQ ~f222
~512fi2
~22 Kl
~4KZ92 OPERATING INCOME 984,454 1,007,972 964,547 NONOPERATING INCOME (net)
INCOME BEFORE INTEREST CHARGES AND PREFERRED 'DIVIDENDS 1,044,026 1,010,184 984,751 INTEREST CHARGES 405,815 381,328 400,077 PREFERRED STOCK DIVIDEND REQUIREMENTS OF SUBSIDIARIES INCOME BEFORE EXTRAORDINARY ITEM 620,380 587,430 529,903 EXTRAORDINARY LOSS - UK WINDFALL TAX NET INCOME Xk ~MM4 AVERAGE NUMBER OF SHARES OUTSTANDING 89 39 ]~7:~ ~85 ~47 EARNINGS PER SHARE:
Before Extraordinary Item $ 3.28 $ 3.14 $ 2.85 Extraordinary Loss QL59)
Net Income ~7 CASH DIVIDENDS PAID PER SHARE CONSOI IDATED STATEMENTS OF RETAINED EARNINGS (in thousands)
RETAINED EARNINGS JANUARY 1 $ 1,547,746 $ 1,409,645 $ 1,325,581 NET INCOME 510,961 587,430 529,903 DEDUCTIONS:
Cash Other Dividends Declared RETAINED EARNINGS DECEMBER 31
~7 453,453
~4>
~4~4 449,353 445,831
~4~<j See Notes to Consolidated Financial Statements.
16
AMERICANELECTRIC POLVER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands) e mbr OPERATING ACTIVITIES:
Net Income $ 510.961 $ 587,430 $ 529,903 Adjustments for Noncash Items:
Depreciation and Amortization 608,217 590,657 578,003 Deferred Federal Income Taxes (6,549) (21,478) 11,916 Deferred Investment Tax Credits (25,241) (25,808) (25,819)
Amortization of Operating Expenses and Carrying Charges (net) 12,001 55,458 53,479 Extraordinary Item - UK Windfall Tax 109,419 Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (136,186) (39,049) (71,804)
Fuel, Haterials and Supplies (1,427) 35,831 457 Accrued Utility Revenues (14,225) 32,953 (40,433)
Accounts Payable (13,915) (31,044)
~4 147,029 Taxes Accrued Other (net)
Net Cash Flows From Operating
~sL2ZR (33,402)
~4 (6,019) 37,515 Activities ~2ZJUW.
INVESTING ACTIVITIES:
Construction Expenditures Investment in Yorkshire Proceeds from Sale of Property Net Cash Flows Used For Investing Activities and Other ~4 ~5)
(760,394)
(363,436)
~1Z1ddtR)
(577,691)
~Q (605,974) t)jjQ
~~40.)
FINANCING ACTIVITIES:
Issuance of Common Stock 76,745 65,461 48,707 Issuance of Long-term Debt 880,522 407,291 523,476 Retirement of Cumulative Preferred Stock (433,329) (70,761) (158,839)
Retirement of Long-term Debt (348,157) (601,278) (469,767)
Change in Short-term Debt (net)
Dividends Paid on Common Stock ~4'~) 235,380 (45,430)
~~4:52) ~i~+)48,140 Net Cash Flows Used For Net Increase Financing Activities (Decrease) in
~~) ~QLKQ) ~~4) l~
Cash and Cash Equivalents 33, 942 (22,416) 17,089 Cash and Cash Equivalents January 1 2LLi5. K Cash and Cash Equivalents December 31 See Notes to Consolidated Financial Statements.
17
AMERICANELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCESHEETS gn Thousands - Except Share Data)
ELECTRIC UTILITY PLANT:
Production $ 9,493,158 $ 9,341,849 Transmission 3,501,580 3,380,258 Distribution 4,654,234 4,402,449 General (including mining assets and nuclear fuel) 1,604,671 1,491,781 Construction Work in Progress Total Electric Utility Plant
~34 8 19,596,485
~5~3 18,970,169 Accumulated Depreciation and Amortization ~252JiK ~~Z2R NET ELECTRIC UTILITY PLANT ~~4L2D OTHER PROPERTY AND INVESTHENTS ~~64 CURRENT ASSETS:
Cash and Cash Equivalents 91,481 57,539 Accounts Receivable:
Customers (less allowance for uncollectible accounts of $ 6,760 in 1997 and $ 3,692 in 1996) 552,443 415,413 Hiscellaneous 115,075 115,919 Fuel - at average cost 224,967 235,257 Haterials and Supplies - at average cost 263,613 251,896 Accrued Utility Revenues 189,191 174,966 Prepayments and Other ~kL3K ~htJ51 TOTAL CURRENT ASSETS ~~54 51 REGULATORY ASSETS DEFERRED CHARGES TOTAL See Notes to Consolidated Financial Statements.
18
AMERICANELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLlDATED BALANCE SHEETS CAPITALIZATION:
Common Stock-Par Value $ 6.50:
192Z 12K Shar es Authori zed ..300,000,000 300,000,000 Shar es Issued....198,989,981 197,234,992 (8,999,992 shares were hei d in treasury) $ 1,293,435 $ 1,282,027 Paid-in Capital 1,778,782 1,715,554 Retained Earnings Total Common Shareholders'quity
~JiEiJUZ 4,677,234
~dLZK 4,545,327 Cumulative Preferred Stocks of Subsidiaries:*
Not Subject to Mandatory Redemption 46,724 90,323 Subject to Handatory Redemption Long-term Debt* ~22K ~49~
127,605 509,900 TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES ~%6 'QZ CURRENT LIABILITIES:
Preferred Stock and Long-term Debt Due Within One Year* 294,454 86,942 Short-term Debt 555,075 319,695 Accounts Payable 353,256 206,227 Taxes Accrued 380,771 414,173 Interest Accrued 76,361 75,124 Obligations Under Capital Leases 101,089 89,553 Other ~DH 'Q2 TOTAL CURRENT LIABILITIES DEFERRED INCOHE TAXES ~t K2?1 ~4~4 DEFERRED INVESTHENT TAX CREDITS DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 DEFERRED CREDITS ~35 ~! jjJ93 COMHITMENTS AND CONTINGENCIES (Note 4 )
TOTAL ~66 5 346 ~15 ~8~88
- See Accompanying Schedules.
19
AMERICANELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES NOTES TO CONSOLIDATED FINANCIALSTATEMENTS
- 1. Significant Accounting Policies: Power Company are distribution companies that purchase power from APCo and OPCo, Organization - American Electric Power (AEP respectively. AEPSC provides management or the Company) is one of the U.S.'s largest and professional services to the AEP investor-owned public utility holding System. The active coal-mining companies companies engaged in the generation, are wholly-owned by OPCo and sell most of purchase, transmission and distribution of their production to OPCo. AEPGEN has a electric power to nearly 3 million retail 50% interest in the Rockport Plant which is customers in its seven state service territory comprised of two of the AEP System's six which covers portions of Ohio, Michigan, 1,300 mw generating units. AEPR has Indiana, Kentucky, West Virginia, Virginia investments and projects that include: a 50%
and Tennessee. Electric power is also interest in Yorkshire Electricity Group pic supplied at wholesale to neighboring utility (Yorkshire), an electric distribution company systems and power marketers. AEP has in the UK (see Note 7); a 70% interest in a holdings in the United States, the United project to build two 125 mw coal-fired Kingdom (UK) and China. generating units in China. AEPES currently markets and trades natural gas. The non-The organization of the AEP System consists regulated subsidiaries that complement utility of American Electric Power Company, Inc. activities are, engaged in providing non-(AEP Co., lnc.), the parent holding company; regulated energy and communication seven electric utility operating companies in services and are seeking and considering the U.S. (domestic utility subsidiaries); a new business opportunities domestically and domestic generating subsidiary, AEP internationally that will permit AEP to utilize Generating Company (AEPGEN); a service its expertise and core competencies.
company, American Electric Power Service Corporation (AEPSC); AEP Resources, Inc. The AEP System's operations are divided
{AEPR) which pursues energy-related into major business units which are managed domestic and international investment centrally by AEPSC. Although the seven opportunities and projects; AEP Energy domestic utility subsidiaries and AEPSC are Services (AEPES) which markets and trades separate legal entities they operate as energy commodities; three active coal-mining American Electric Power. There has been no companies and a group of subsidiaries that change to the legal names of these provide power engineering, consulting and companies.
management services around the world to complement utility activities. Rate Regulation - The AEP System is subject to regulation by the Security and Exchange The following domestic utility subsidiaries Commission (SEC) under the Public Utility pool their generating and transmission Holding Company Act of 1935 (1935 Act).
facilities and operate them as an integrated The rates charged by the domestic utility system: Appalachian Power Company subsidiaries are approved by the Federal
{APCo), Columbus Southern Power Energy Regulatory Commission (FERC) or Company (CSPCo), indiana Michigan Power the state utility commissions as applicable.
Company (IB M), Kentucky Power Company The FERC regulates wholesale rates and the and Ohio Power Company (OPCo). The ,
state commissions regulate retail rates.
remaining two domestic utility subsidiaries, Kingsport Power Company and Wheeling 20
Principles of Consolidation - The estimated cost of borrowed and equity funds consolidated financial statements include used to finance construction projects. The AEP Co., Inc. and its wholly-owned and amounts of AFUDC for 1997, 1996 and 1995 Hes majority-owned subsidiaries consolidated were not significant.
Co, with their wholly-owned subsidiaries.
ent Significant intercompany items are eliminated Depreciation, Depletion and Amortization-
.EP in consolidation. Yorkshire is accounted for Depreciation is provided on a straight-line ies using the equity method. basis over the estimated useful lives of tof property other than coal-mining property and s a Basis of Accounting - As the owner of cost- is calculated largely through the use of I IS based rate-regulated electric public utility composite rates by functional class as SIX companies, AEP Co., Inc.'s consolidated follows:
as financial statements reflect the actions of regulators that result in the recognition of Functional Class Annual Composite ilc revenues and expenses in different time ny periods than enterprises that are not rate Production:
ia regulated. In accordance with Statement of Steam-Iiuclear 3.4X Financial Accounting Standards {SFAS) No. Steam-Fossil-Fired 3.2X to 4.4X ed Hydroelectric-Conventional tly 71, "Accounting for the Effects of Certain and Pumped Storage 2.7X to 3.2X un- Types of Regulation," regulatory assets Transmission 1.7X to 2.7X ity {deferred expenses) and regulatory liabilities Oistri buti on 3.3X to 4.2%
(deferred income) are recorded to reflect the General 2.5X to 3.8$
n-economic effects of regulation and to match The utility subsidiaries presently recover expenses with regulated revenues. amounts to be used for demolition and removal of non-nuclear plant through Use of Estimates - The preparation of these depreciation charges .included in rates.
financial statements in conformity with Depreciation, depletion and amortization of generally accepted accounting principles coal-mining assets is provided over each 3d requires in certain instances the use of asset's estimated useful life, ranging up to 30 Id estimates. Actual results could differ from years, and is calculated using the straight-In those estimates. line method for mining structures and e equipment. The units-of-production method IS Utility Plant - Electric utility plant is stated at is used to amortize coal rights and mine io original cost and is generally subject to first development costs based on estimatec e mortgage liens. Additions, major recoverable tonnages at a current average replacements and betterments are added to rate of $ 1.91 per ton. These costs ar~
the plant accounts. Retirements from the included in the cost of coal charged to fue plant accounts and associated removal expense.
costs, net of salvage, are deducted from accumulated depreciation. The costs of Cash and Cash Equivalents - Cash and cast labor, materials and overheads incurred to equivalents include casl temporary operate and maintain utility plant are investments with original maturities of threi included in operating expenses. months or less.
Allowance for Funds Used During Foreign Currency Translatl'on - The financi~
Construction (AFUDC) - AFUDC is a statements of subsidiaries outside the Unite noncash nonoperating income item that is States are measured using the local currenc recovered over the service life of utility plant as the functional currency. Assets an through depreciation and represents the
liabilities are translated to U.S. dollars at provided for all temporary differences year-end rates of exchange and revenues between the book cost and tax basis of and expenses are translated at monthly assets and liabilities which will result in a average exchange rates throughout the year. future tax consequence. Where the flow-Translation adjustments are accumulated as through method of accounting for temporary a separate component of shareholders'quity.
differences is reflected in rates, deferred The accumulated total at December income taxes are recorded with related 31, 1997 is not material. Currency regulatory assets and liabilities in transaction gains and losses are recorded in accordance with SFAS No. 71.
income.
Invesfmenf 7ax Credits - Investment tax Sale of Receivables - Vnder an agreement credits have been accounted for under the that was terminated in January 1997, fiow-through method except where regulatory CSPCo sold $ 50 million of undivided commissions have reflected investment tax interests in designated pools of accounts credits in the rate-making process on a receivable and accrued utility revenues with deferral basis. Deferred investment tax limited recourse. As collections reduced credits are being amortized over the life of previously sold pools, interests in new pools the related plant investment.
were sold. At December 31, 1996, $ 50 million remained to be collected and remitted Debf and Prefened Stock- Gains and losses to the buyer. on reacquisition of debt are deferred and amortized over the remaining term of the Operafing Revenues and Fuel Costs- reacquired debt in accordance with rate-Revenues include the accrual of electricity making treatment. If the debt is refinanced, consumed but unbilted at month-end as well the reacquisition costs are deferred and as billed revenues. Fuel costs are matched amortized over the term of the replacement with revenues in accordance with rate debt commensurate with their recovery in commission orders. Generally in the retail rates.
jurisdictions, changes in fuel costs are deferred or revenues accrued until approved Discount or premium and expenses of debt by the regulatory commission for billing or issuances are amortized over the term of the refund to customers in later months. related debt, with the amortization included in Wholesale jurisdictional fuel cost changes interest charges.
are expensed and billed as incurred.
Redemption premiums paid to reacquire Levelizafion of Nuclear Refueling Outage preferred stock are included in paid-in capital Gosfs - Incremental operation and and amortized to retained earnings maintenance costs associated with refueling commensurate with their recovery in rates.
outages at IRM's Cook Plant are deferred The excess of par value over costs of and amortized over the period (generally preferred stock reacquired is credited to eighteen months) beginning with the paid-in capital and amortized to retained commencement of an outage and ending with earnings.
the beginning of the next outage.
Ofher Properfy and Invesfmenfs - Excluding Income Taxes - The Company follows the decommissioning and spent nuclear'fuel liability method of accounting for income disposal trust funds and the investment in taxes as prescribed by SFAS No. 109, Yorkshire, other property and investments "Accounting for income Taxes." Under the are stated at cost. Securities held in trust liability method, deferred income taxes are funds for decommissioning nuclear facilities
and for the disposal of spent nuclear fuel are future recovery $ 61 million at December 31, recorded at market value in accordance with 1997.
SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." Based on the estimated future cost of coal Securities in the trust funds have been burned at Gavin Plant, management believes classified as available-for-sale due to their that the Ohio jurisdictional portion of the long-term purpose. Unrealized gains and investment in and liabilities and closing costs losses from securities in these trust funds are of the affiliated mining operations including not reported in equity- but result in deferred amounts will be recovered under the adjustments to the liability account for the terms of the predetermined price agreement.
nuclear decommissioning trust funds and to Management intends to seek from non-Ohio regulatory assets or liabilities for the spent jurisdictional ratepayers recovery of the non-nuclear fuel disposal trust funds. Ohio jurisdictional portion of the investment in and the liabilities and closing costs of the EPS - The adoption of SFAS No. 128 affiliated IVleigs, Muskingum and Windsor "Earnings per Share" had no impact on the mines. The non-Ohio jurisdictional portion of determination of Earnings per Common shutdown costs for these mines which Share. includes the investment in the mines, leased asset buy-outs, reclamation costs and employee benefits is estimated to be
- 2. Rate Matters: approximately $ 102 million after tax at December 31, 1997.
OPCo's Recovery of Fuel Costs - Under the terms of a 1992 stipulation agreement the The affiliated Muskingum and Windsor mines cost of coal burned at the Gavin Plant is may have to close by January 2000 in order subject to a 15-year predetermined price of to comply with the Phase II requirements of
$ 1.575 per million British Thermal Unit (Btu) the Clean Air Act Amendments of 1990 with quarterly escalation adjustments through (CAAA). The Muskingum and/or Windsor November 2009. A 1995 Settlement mines could close prior to January 2000 Agreement set the fuel component of the depending on the economics of continued EFC factor at 1A65 cents per Kilowatthour operation under the terms of the above (Kwh) for the period June 1, 1995 through Settlement Agreement. Unless future November 30, 1998. The stipulation and shutdown costs and/or the cost of affiliated settlement agreements provide OPCo with coal production of the Meigs, Muskingum and the opportunity to recover over the term of Windsor mines can be recovered, results of the stipulation agreement the Ohio operations and cash flows would be jurisdictional share of OPCo's investment in adversely affected.
and the liabilities and future shut-down costs of its affiliated mines as well as any fuel costs incurred above the predetermined rate 3. Effects of Regulation and Phase-In to the extent the actual cost of coal burned at Plans:
the Gavin Plant is below the predetermined prices. After full recovery of these costs or In accordance with SFAS No. 71 the November 2009, whichever comes first, the consolidated financial statements include price that OPCo can recover for coal from its assets (deferred expenses) and liabilities affiliated Meigs mine which supplies the (deferred income) recorded in accordance Gavin Plant will be limited to the lower of cost with regulatory actions to match expenses or the then~rrent market price. Pursuant to and revenues from cost-based rates.
these agreements OPCo has deferred for Regulatory assets are expected to be 23
recovered in future periods through the rate- million, $ 31.5 million and $ 28.5 million, making process and regulatory liabilities are respectively, of net phase-in deferrals were expected to reduce future cost recoveries. collected through the surcharge. The The Company has reviewed all the evidence deferral balance which was completely currently available and concluded that it recovered and amortized in 1997 was $ 1 5 4 continues to meet the requirements to apply million at December 31, 1996.
SFAS No. 71. In the event a portion of the Company's business no longer met these The Rockport Plant consists of two requirements, net regulatory assets would 1,300 mw coal-fired units. I&lVIand AEPGEN have to be written off for that portion of the each own 50% of one unit (Rockport 1) and business and assets attributable to that lease a 50% interest in the other unit portion of the business would have to be (Rockport 2) from unaffiliated lessors under tested for possible impairment and if required an operating lease. The gain on the sale an impairment loss recorded unless the net and leaseback of Rockport 2 was deferred regulatory assets and impairment losses are and is being amortized, with related taxes, recoverable as a stranded investment. over the initial lease term which expires in 2022. A rate phase-in plan in the Indiana Recognized regulatory assets and liabilities and the FERC jurisdictions provide for the are comprised of the following at: recovery and straight-line amortization of deferred Rockport Plant Unit 1 costs over ten 12K years beginning in 1987. In 1997 the 122Z fin Thousands) amortization and recovery of the deferred Regulatory Assets:
Anounts Due Frora Custouers Rockport Plant Unit 1 Phase-in Plan costs For Future Incoare Taxes $ 1,372.926 $ 1.459,086 were completed. During the recovery period Rate Phase-fn Plan Deferrals 27,249 Unarrortfzed Loss on net income was unaffected by the recovery of Reacqufred Debt 96,793 107,305
~2'44 the phase in deferrals. Amortization was Other Total Regulatory Assets ~~4 !21
$ 11.9 million in 1997 and $ 16 million in 1996 Regul a tory Lf a bi 1 f tf es r and 1995.
Deferred Investnent Tax Credits $ 376 '50 $ 401.491 Other Regulatory Liabilities" Total Regulatory 4. Commitments and Contingencies:
Lfabflftfes Included fn Deferred Credits on Consolidated Balance Construction and Other Comml'tments - The Sheets AEP System has substantial construction The rate phase-in plan deferrals are commitments to support its utility'operations applicable to the Zimmer Plant and Rockport including the replacement of the Cook Plant Plant Unit 1. The Zimmer Plant is a 1,300 Unit 1 steam generators. Such commitments mw coal-fired plant which commenced do not presently include any expenditures for commercial operation in 1991. CSPCo owns new generating capacity. Aggregate 25.4% of the plant with the remainder owned construction expenditures for 1998-2000 are by two unaffiliated companies. As a result of estimated to be $ 2.4 billion.
an Ohio Supreme Court decision, in January 1994 the Public Utility Commission of Ohio Long-term fuel supply contracts (PUCO) approved a temporary 3.39% contain clauses for periodic price surcharge effective February 1, 1994. In adjustments, and most jurisdictions have fuel June 1997 the Company completed recovery clause mechanisms that provide for recovery of its Zimmer Plant phase-in plan deferrals of changes in the cost of fuel with the and discontinued the 3.39% temporary rate regulators'eview and approval. The surcharge. In 1997, 1996 and 1995 $ 15.4 contracts are for various terms, the longest of 24
which extends to the year 2014, and contain the units will be returned to service. If the various clauses that would release the units are not returned to service in a Company from its obligation under certain reasonable period of time, it could have an force majeure conditions. adverse impact on results of operations, cash flows and possibly financial condition.
The AEP System has contracted to sell approximately 1,000 mw of capacity on a Nuclear fncidenf Liability - Public liability is long-term basis to unaffiliated utilities. limited by law to $ 8.9 billion should an Certain contracts totaling 750 mw of capacity incident occur at any licensed reactor in the are unit power agreements requiring the United States. Commercially available delivery of energy only if the unit capacity is insurance provides $ 200 million of coverage.
available. The power sales contracts expire ln the event of a nuclear incident at any from 1999 to 2010. nuclear plant in the United States the remainder of the liability would be provided Nuclear Planf - l&M owns and operates the by a deferred premium assessment of $ 79.3 two-unit 2,110 mw Cook Plant under licenses million on each licensed reactor payable in granted by the Nuclear Regulatory annual installments of $ 10 million. As a Commission (NRC.) The operation of a result, l&Mcould be assessed $ 158.6 million nuclear facility involves special risks, per nuclear incident payable in annual potential liabilities, and specific regulatory installments of $ 20 million. The number of
~
and safety requirements. Should a nuclear incidents for which payments could be incident occur at any nuclear power plant required is not limited.
facility in the United States, the resultant liability could be substantial. By agreement Nuclear insurance pools and other l&M is partially liable together with all other insurance policies provide $ 3.6 billion electric utility companies that own nuclear (reduced to $ 3.0 billion effective January 1, generating units for a nuclear power plant 1998) of property damage, decommissioning incident. In the event nuclear losses or and decontamination coverage for the Cook liabilities are underinsured or exceed Plant. Additional insurance provides accumulated funds and recovery in rates is coverage for extra costs resulting from a not possible, results of operations, cash prolonged accidental Cook Plant outage.
flows and financial condition could be Some of the policies have deferred premium negatively affected. provisions which could be triggered by losses in excess of the insurer's resources. The Nuclear Planf Shufdown - On September 9 losses could result from claims at the Cook and 10, 1997, during a NRC architect Plant or certain other non-affiliated nuclear engineer design inspection, questions units. I&M could be assessed up to $ 35.8 regarding the operability of certain safety million under these policies.
systems caused Company operations personnel to shut down Units 1 and 2 of the SNF Disposal - Federal law provides for Gook Plant. On September 19, 1997, the government responsibility for permanent NRG issued a Confirmatory Action Letter spent nuclear fuel disposal and assesses requiring the Company to address the issues nuclear plant owners fees for spent fuel identified in the letter. The Company is disposal. A fee of one mill per kilowatthour working with the NRC to resolve these issues for fuel consumed after April 6, 1983 is being and other issues related to restart of the collected from customers and remitted to the units. Certain issues identified in the letter U.S. Treasury. Fees and related interest of have been addressed. At this time $ 181 million for fuel consumed prior to April management is unable to determine when 7, 1983 have been recorded as long-term
debt. I8M has not paid the government the noncurrent liabilities.
pre-April 1983 fees due to continued delays and uncertainties related to the federal Revised Air Quality Standards - On July 18, disposal program. At December 31, 1997, 1997, the Federal EPA published a revised funds collected from customers towards National Ambient Air Quality Standard payment of the pre-April 1983 fee and (NAAQS) for ozone and a new NAAQS for related earnings thereon approximate the fine particulate matter (less than 2.5 microns liability. in size). The new ozone standard is expected to result in redesignation of a Decommissioning and Low Level Waste number of areas of the country that are Accumulation Disposa/ - Decommissioning currently in compliance with the existing costs are accrued over the service life of the standard to nonattainment status which could Cook Plant. The licenses to operate the two ultimately dictate more stringent emission nuclear units expire in 2014 and 2017. After restrictions for AEP System generating units.
expiration of the licenses the plant is New stringent emission restrictions on AEP expected to be decommissioned through System generating units to achieve dismantlement. The Company's latest attainment of the fine particulate matter estimate for decommissioning and low level standard could also be imposed. The AEP radioactive waste accumulation disposal System operating companies joined with costs range from $ 700 million to $ 1,152 other utilities to appeal the revised NAAQS million in 1997 nondiscounted dollars. The and filed petitions for review in August and wide range is caused by variables in September 1997 in the U.S. Court of Appeals assumptions including the estimated length for the District of Columbia Circuit.
of time spent nuclear fuel must be stored at Management is unable to estimate the plant subsequent to ceasing operations. compliance costs without knowledge of the This in turn depends on future developments reductions that may be necessary to meet in the federal government's SNF disposal the new standards. If such costs are program. Continued delays in the federal significant, it could have a material adverse fuel disposal program can result in increased effect on results of operations, cash flows decommissioning costs. IBM is recovering and possibly financial condition unless such estimated decommissioning costs in its three costs are recovered.
rate-making jurisdictions based on at least the lower end of the range in the most recent Lifigatjon - The Company is involved in a decommissioning study at the time of the last number of legal proceedings and claims.
rate proceeding. IBM records decom- While management is unable to predict the missioning costs in other operation expense ultimate outcome of litigation, it is not and records a noncurrent liability equal to the expected that the resolution of these matters decommissioning cost recovered in rates; will have a material adverse effect on the such amounts were $ 28 million in 1997, $ 27 results of operations, cash flows or financial million in 1996 and $ 30 million in 1995 condition.
including $ 4 million of special deposits.
Decommissioning costs recovered from customers are deposited in external trusts. 5. Dividend Restrictions:
Trust fund earnings increase the fund assets and the recorded liability and decrease the Mortgage indentures, charter provisions and amount needed to be recovered from orders of regulatory authorities place various ratepayers. At December 31, 1997, l8M has restrictions on the use of the subsidiaries'6 recognized a decommissioning liability of
$ 381 million which is included in other
retained earnings for the payment of cash equity and non-recourse debt. The Company dividends on their common stocks. At uses the equity method of accounting for its i December 31, 1997, $ 27 million of retained earnings were restricted. To pay dividends out of paid-in capital the subsidiaries need regulatory approval.
investment in YPG. The Company's original investA'Ient in the joint venture was $ 360 million and is included in other property and investments.
In July 1997 the British government enacted
- 6. I ines of Credit and Commitment Fees: a new law that imposed a one-time windfall tax on a revised privatization value which At December 31, 1997 and 1996, unused originally had been computed in 1990 on short-term bank lines of credit were available certain privatized utilities. The windfall tax is in the amounts of $ 442 million and $ 409 actually an adjustment of the original million, respectively. In addition several of privatization price by the UK government.
the subsidiaries engaged in providing non- The windfall tax liability for Yorkshire regulated energy services share a line of Electricity Group pic is estimated to be 134 credit under a revolving credit agreement. million pounds sterling ($ 219 million) and is The amounts of credit available under the payable in two equal installments. The first revolving credit agreement were $ 330 million payment was made in December 1997 and and $ 100 million at December 31, 1997 and the second installment will be due in d 1996, respectively. The short-term bank December 1998. The Company's $ 109.4 S
lines of credit and the revolving credit million share of the tax is reported as an
- t. agreement require the payment of facility extraordinary loss. The equity earnings from fees of approximately 1/10 of 1% on the daily the Yorkshire investment, excluding the amount of such commitments. extraordinary loss, which are included in nonoperating income, are $ 34 million Outstanding short-term debt consisted of: inclusive of $ 10 million of nonrecurring tax e benefits related to a reduction of the UK
's (Do))ars In Thousands) corporate income tax rate from 33% to 31%
h effective April 1, 1997.
Balance Outstanding:
Notes Payable f199,285 f 91,293 a
Comaercfal Paper Total Year-End Weighted
~k M~4 The following amounts which are not included in AEP's consolidated financial Average Interest Rate: statements represent summarized e
Notes Payable Comsercfal Paper 6.35 6.85 6.25 7.25 consolidated financial information of YPG at ot Tocal 6.65 6.95 December 31, 1997 and for the nine-months s then ended:
ie 7. Yorkshire Acquisition and UK Windfall Assets: (In Nfll fons)
Tax Property, Plant and Equipment S1.644.6 al Current Assets 602.2 Other Assets Total Assets In April 1997 the Company and New Century Energies, Inc. through an equally owned joint Capita)fzatfon and Liabilities:
Coaiaon Shareholders'quity 542.1 venture, Yorkshire Power Group Limited Long-ters Debt 704.3 Other Noncurrent Liabilities 488.7 (YPG), acquired all of the outstanding shares of Yorkshire, an electric distribution company Current Liabilities Total Capftalfaation and Liabilities
~L1 ld Js in the UK. Total consideration paid by the joint venture was approximately $ 2.4 billion which was financed by a combination of Income Statement Data:
Operating Revenues Operating Income Income Before Extraordfnary Item Net Loss 51,492.9 202.3 67.5 (151.3) 27
(a) AEP pension plan assets primarily consist of coaeon
- 8. Benefit Plans: stocks, bonds and cash equivalents and are included in a separate entity trust fund.
AEP System Pension Plan - The AEP Assumptions used to determine AEP's net pension plan is a trusteed, noncontributory pension plan liabilitywere:
defined benefit plan covering all employees meeting eligibility requirements, except Oiscount Rate l22Z ~ 122k 7.00$ 7.75K 7.2SX participants in the United Mine Workers of Average Rate of Increase in Conpensation Levels 3.2X 3.2X 3.2$
America (UMWA) pension plans. Benefits Expected Long-Tero Rate of are based on service years and Return on Plan Assets 9.0% 9.0X 9.0%
compensation levels. The funding policy is Postretin:ment Benefits Other Than Pensions to make annual contributions to a qualified (OPEB) - The AEP System provides certain trust fund equal to the net periodic pension benefits other than pensions for retired cost up to the maximum amount deductible employees. Substantially all non-UMWA for federal income taxes, but not less than employees are eligible for postretirement the minimum required contribution in health care and life insurance if they retire accordance with the Employee Retirement from active service after reaching age 55 and Income Security Act of 1974. have at least 10 service years.
Net AEP pension plan costs were computed Postretirement medical benefits for as follows:
UMWA employees at affiliated mining 12K 122k operations who have or will retire after
( In Thousands)
January 1, 1976 are the liability of the OPCo Service Cost-Benefits Earned Ouring coal-mining subsidiaries and are included in the Year 5 36,000 5 40 000 F 5 30,400 the OPEB net costs and liability. They are Interest Cost on Pro)ected Benefit eligible for postretirement medical benefits if Obligat5on 128,600 119,500 116,700 they retire from active service after reaching Actual Return on P'lan Assets (462,700) (302,400) (416,800) age 55 and have at least 10 service years.
Het Amortization (Deferral) In addition, non-active UMWAemployees will Het AEP Pens5on become eligible for postretirement benefits at Plan Costs age 55 if they have had 20 years of service.
AEP pension plan assets, actuarially computed benefit obligations and the The funding policy for AEP's OPEB plan computation of accrued net pension plan is to make contributions to an external liability are: Voluntary Employees Beneficiary Association 122Z 12K trust fund equal to the incremental OPEB (In Thousands) costs (i.e., the amount that the total Actuarial Present Value postretirement benefits cost under SFAS of Benefit Obl5gation:
Vested Obligation 51,623,200 51.377.000 106, "Employers'ccounting for Honvested Obligation 161,000 136,500 Postretirement Benefits Other Than Effects of Salary Progression ~2RdIii Pro)ected Benefit Obligation 1,890,000 Pensions," exceeds the pay-as-you-go 1,676,200 AEP Pens5on Plan Assets at Fa5r Value (a) amount). Contributions were $ 35.2 million in Funded Status - AEP Pension Plan 1997, $ 45.8 million.in 1996 and $ 53 million in Assets in Excess of ProIected Benefit Obligation 480,300 333,300 1995. In several jurisdictions the utility Unrecognized Prior subsidiaries deferred the increased OPEB Service Cost 119,400 133.200 Unrecognized Ket Gain on Assets (640,800) (488,200) costs resulting from the SFAS 106 required Unrecogn5zed Het Transition Assets (Being Anortized change from pay-as-you-go to accrual Over 17 Years)
Accrued Het AEP Pension Plan
~KJM) ~!ERE) accounting which were not being recovered Liability k~MR) ~PR) in rates. No additional deferrals were made 28
in 1997 or 1996. At December 31, 1997 and for all employees, both non-UMWA and UMWA, would increase by $ 10 million and
~
96, $ 7.9 million and $ 14.5 million,
~
spectively, of incremental OPEB costs the accumulated benefit obligations would were deferred. increase by $ 92 million.
Aggregate OPEB costs were computed as AEP System Savings Plan - An employee follows: savings plan is offered to non-UMWA employees which allows participants to (In Thousands) contribute up to 17% of their salaries into Service Cost $ 14,000 $ 15,300 $ 13.500 various investment alternatives, including Interest Cost on Pro)ected AEP common stock. An employer matching Benefit Obligation 55,900 53,500 54,900 Het Amortization of the contribution, equaling one-half of the Transition Obligation 32,000 32.300 32.000 employees'ontribution to the plan up to a Return on Plan Assets Het Amortization (Deferral)
Het OPEB Costs
~~I(44,100) (21.100)
'~R (25.400)
ARE maximum of 3% of the employees'ase salary, is invested in AEP common stock.
OPEB assets, actuarially computed benefit The employer's annual contributions totaled obligations and the computation of the $ 19.6 million in 1997, $ 19 million in 1996 and accrued net OPEB liability are: $ 18.8 million in 1995.
122Z 122I Other UMWA Benefits - The Company
( In Thousands) provides UMWApension, health and welfare Accumulated Postretirement Benef1t Obl1gation: benefits for certain employees, retirees, and Active Employees Fully their survivors who meet eligibility Eligible for Benefits 73,800 $ 57,800 requirements. The benefits are administered Current Retirees Other Active Employees Total Benefit Obligation 466,900
~!LRE 849,700
~iK 423,000 726,400 by UMWA trustees and contributions are Fair Harket Value of made to their trust funds. Contributions Plan Assets (a) U22 'iK Unfunded Benefit Obligation (537 800)
F (493,900) based on hours worked are expensed as Unrecogn1zed Net Loss (Gain) 66,100 (3,300) paid as part of the cost of active mining Unrecognized Het Transition Obligat1on Be1ng operations and were not material in 1997, Amortized Over 20 Years Accrued Net OPEB Liability 1996 and 1995. Based upon the UMWA actuary estimate the Company's share of (a) Plan assets consist of cash surrender unfunded pension liability was $ 6.9 million at value of life insurance contracts on certain June 30, 1997. In the event the Company employees owned by the trust and short-term should significantly reduce or cease mining tax-exempt municipal bonds. operations or contributions to the UMWA trust funds, a withdrawal obligation will be Assumptions used to determine OPEB's triggered for both the pension and health and funded status were: welfare plans. If the mining operations had been closed on December 31, 1997 the Discount Rate 7.00K 7.75K 7.255 estimated withdrawal liability for all UMWA Expected Long-Ters Rate benefit plans would have been $ 6.7 million.
of Return on Plan Assets 8.755 8.755 8.75%
Initial Hedical Cost Trend Rate 7.05 7.55 8.05 Ultimate Hedical Cost Trend Rate 4.251 4.75% 4.55 9. Fair Value of Financial instrument:
Hedical Cost Trend Rate Decreases to Ultimate Rate in Year 2005 2005 2005 Nuclear Trust Funds Recorded at Market ssuming a one percent increase in the Va/ue - The trust investments, reported in medical cost trend rate, the 1997 OPEB cost other property and investments, are recorded at market value in accordance with SFAS No.
29
115 and consist of tax-exempt municipal At December 31, 1997, the year of maturity bonds and other securities. of trust fund investments other than equity securities, was:
At December 31, 1997 and 1996 the fair ( In Thousands) values of the trust investments were $ 566 1998 $ 87,063 1999 - 2002 127,575 million and $ 491 million, respectively. 2003 - 2007 182,873 Accumulated gross unrealized holding gains After 2007 ~4 were $ 41 million and $ 21.9 million at Total 5~43%
December 31, 1997 and 1996, respectively and accumulated gross unrealized holding Other Financial Instruments Recorded at losses weie $ 1.2 million at both year-ends. Historical Cost - The carrying amounts of The change in market value in 1997, 1996, cash and cash equivalents, accounts and 1995 was a net unrealized holding gain receivable, short-term debt, and accounts of $ 19.1 million, $ 2.6 million and $ 24.9 payable approximate fair value because of the short-term maturity of these instruments.
million, respectively.
Fair values for preferred stock subject to The trust investments'ost basis by security mandatory redemption were $ 136 million and
$ 517 million and for long-term debt were $ 5.7 type were:
billion and $ 5.0 billion at December 31, 1997 122Z
( In Thousands) 12K and 1996, respectively. The carrying amounts on the financial statements for Tax-Exempt Bonds 4335.358 $ 340,290 Equity Securities 74.398 54 '89 preferred stock subject to mandatory Treasury Bonds 44.200 26.958 redemption were $ 128 million and $ 510 Corporate Bonds 9,167 7,977 Cash. Cash Equ5valents and million and for long-term debt were $ 5.4 Accrued Interest M2 '52 ~4~4 Total 8~i 85~44 billion and $ 4.9 billion at December 31, 1997 and 1996, respectively. Fair values are Proceeds from sales and maturities of based on quoted market prices for the same securities of $ 147.3 million during 1997 or similar issues and the current dividend or resulted in $ 3.9 million of realized gains and interest rates offered for instruments of the
$ 1.4 million of realized losses. Proceeds same remaining maturities. The carrying from sales and maturities of securities of amount of the spent nuclear fuel disposal
$ 115.3 million during 1996 resulted in $ 2.6 trust funds approximates the Company's best million of realized gains and $ 2.1 million of estimate of the fair value of the pre-April realized losses. During 1995 proceeds from 1983 SNF disposal liability.
sales and maturities of securities of $ 78.2 million resulted in $ 1.4 million of realized gains and $ 0.3 million of realized losses.
The cost of securities for determining realized gains and losses is original acquisition cost including amortized premiums and discounts.
30
- 0. Federal Income Taxes:
~
~
The details of federal income taxes as reported are as follows:
199K 12K 12K (In Thousands)
Charged (Credited) to Operating Expenses (net):
Cur r en.t $ 346,290 $ 375,528 $ 265,313 Deferred Deferred Investment Tax Credits Total
~~) ~~) ~~)
11,124 {17,008) 22,990 Charged (Credited) to Nonoperating Income (net):
Cur rent {16,038) (5,636) 11,325 Deferred Deferred Investment Tax Credits Total (17,673)
~KJQZ)
~4~) ~~)
~~)
(4,470)
~~)
{11,074)
~~)
Total Federal Income Tax as Reported gSk 46K k3ZZ~ kZGZ.~7 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.
122Z le (In Thousands) le Income Before Preferred Stock Dividend Requirements of Subsidiaries $ 638,211 $ 628,856 $ 584,674 Extraordinary Loss (Note 7) {109,419)
Federal Income Taxes 'QZ M5.
Pre-Tax Book Income g&~4 K4Z~
Federal Income Tax on Pre-Tax Book Income at Statutory Rate (95$ ) $ 289,539 $ 333,012 $ 296,593 Increase (Decrease) in Federal Income Tax Resulting from the Following Items:
Depreciation 53,239 50,537 46,453 Corporate Owned Life Insurance (18,240) (12,009) {25,506)
Investment Tax Credits (net) (25,241) (25,813) (26,179)
Extraordinary Loss Other Total Federal
- UK Windfall Tax Income Taxes as Reported
~~) ~~) ~~)
38,297 Effective Federal Income Tax Rate 31
The following tables show the elements of the net deferred tax liability and the significant temporary differences:
r l22Z b
(In Thousands) le Deferred Tax Assets $ 807,226 $ 784,349 Deferred Tax Liabilities Net Deferred Tax Liabilities Property Related Temporary Differences $ (2,161,484) $ (2,162,099)
Amounts Due From Customers For Future Federal Income Taxes (410,255) (428,698)
Deferred State Income Taxes (201,843) (229,429)
All Other (net)
Total Net Deferred Tax Liabilities 4 )
The Company has settled with the United States Internal Revenue Service (IRS) all issues from the audits of the consolidated federal income tax returns for the years prior to 1991. Returns for the years 1991 through 1996 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 Company filed a brief with the IRS National Office refuting the Although no adjustments have been proposed, a disallowance of the COLI interest agents'osition.
deductions through December 31, 1997 would reduce earnings by approximately $ 286 million (including interest). AEP believes it has meritorious defenses and will vigorously contest any proposed adjustments. No provisions for this amount have been recorded. In the event the Company is unsuccessful it could have a material adverse impact on results of operations and cash flows.
- 11. Leases:
Leases of property, plant and equipment are for periods 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 are primarily charged to operating expenses in accordance with rate-making treatment. The components of rentals are as follows:
l926.
(In Thousands)
Operating Leases $ 257,042 $ 262,451 $ 259,877 Amortization of Capital Leases 104,732 114,050 101,068 Interest on Capital Leases ~LJi.'K Total Rental Payments ~33~7 ~4~97 ~i 487
Properties under capital leases and related obligations on the Consolidated Balance Sheets e as follows:
{ In Thousands)
ELECTRIC UTILITY PLANT:
Production $ 47,246 $ 44,390 Transmission 3 6 Distribution 14,660 14,699 General:
Nuclear Fuel {net of amortization) 103,939 59,681 Mining Plant and Other Total Electric Utility Plant 682,691 585,573 Accumulated Amortization Net Electric Utility Plant M5 'M OTHER PROPERTY 57,763 33,439 Accumulated Amortization Net Other Property Net Property under Capital Leases Capital Lease Obligations:*
Noncurrent Liability Liability Due Within One Year Total Capital Lease Obligations
$ 437,303 QZ~
~(~
$ 324,674
- Represents the present, value of future minimum lease payments. The noncurrent portion of capital lease obligations is included in other noncurrent liabilities in the Consolidated Balance Sheets Properties under operating leases and related obligations are not included in the Consolidated Balance Sheets.
33
Future minimum lease rentals, consisted of the following at December 31, 1997:
Noncancelable Capital Operating (In Thousands) 1998 $ 104,623 $ 243,042 1999 92,740 229,764 2000 79,507 228,044 2001 64,438 225,482 2002 59,400 220,111 Later Years ~ZLZZ. ~~c)
Total Future Minimum Lease Rentals 565,079 (a) ~47 Less Estimated Interest Element Estimated Present Value of Future Minimum Lease Rentals 434,453 Unamortized Nuclear Fuel Total $ 53.LZQ.
(a) Minimum lease rentals do not include nuclear fuel rentals. The rentals 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.
- 12. Supplementary Information:
122Z 12K 12K (In Thousands)
Purchased Power - Ohio Valley Electric Company (44.2X owned by AEP System) $ 29,631 $ 22,156 $ 10,546 Cash was paid for:
Interest (net of capitalized amounts) $ 390,491 $ 373,570 $ 395,169 Income Taxes $ 398,833 $ 404,297 $ 273,671 Noncash Acquisitions under Capital Leases $ 234,846 $ 136,988 $ 106,256
0
- 13. Capital Stocks and Paid-ln Capital:
Changes in capital stocks and paid-in capital during the.period January 1, 1995 through ecember 31, 1997 were:
Cumulative Preferred Stocks Cumulative Hot Subject Subject to Common Stock- Preferred Stocks Paid-in To Mandatory Handatory DmhmM() B~m2$ 19II(b)
January 1, 1995 194,234,992 8 '36,251 $ 1,262,527 $ 1,640,661 $ 233.240 $ 590,385 Issuances 1.400,000 9,100 39,607 Retirements and Other December 31, 1995 195,634.992 LL52i 'U2) 6,709,751 1,271.627
~~44) 1,658,524
~r~Q.
148,240
~~0 522,735 Issuances 1,600,000 10,400 55 '61 Retirements and Other December 31, 1996 197,234,992 6,002,233 1,282>027 1,715,554 90,323
~K) 509,900 Issuances 1,754,989 11.408 65,337 Retirements and Other KJM) ~~4'~M)
December 31, 1997 (a) Includes 8,999,992 shares of treasury stock.
(b) Iriclud(ng Portion due uithin one year.
- 14. Unaudited Quarterly Financial information:
(In Thousands - Except
~a~ ~ljBp~
Operating Revenues $ 1,492,069 $ 1,382,158 $ 1,583,994 $ 1,703,147 Operating Income 271,978 221,255 275,090 216,131 Net Income Before Extraordinary Item 172,562 121,139 201,746 124,933 Net Income 172,562 121,139 91,181 126,079 Earnings per Share Before Extraordinary Item* 0.92 0.64 1.07 0.66 Earnings per Share 0.92 0.64 0.48 0.66 "Amounts for 1997 do not add to $ 3.28 earnings per share due to rounding.
The third quarter of 1997 includes an extraordinary loss of $ 110.6 million or $ 0.59 per share for a UK Windfall Tax which retroactively adjusted upward Yorkshire's privatization price discussed in Note 7.
(In Thousands - Except
~r~h ~n~ ~QJ~~
Operating Revenues $ 1,517,781 $ 1,400,941 $ 1,484,422 $ 1,446,090 Operating Income 292,122 220,625 259,745 235,480 Net Income 180,012 112,666 162,324 132,428 Earnings per Share 0.96 0.60 0.87 0.71 35
AMERICANELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SCHEDULE OF CONSOLIDATED CUMULATIVEPREFERRED STOCKS OF SUBSIDIARIES Call Price per Shares Shares Amount (In Hot Subject to Handatory Redemption:
4.085 - 4.565 (c) $ 102-$ 110 932,403 467,236 Subject to Mandatory Redemption:
5.90% - 5.925 (c)(d) (e) 1,950,000 388,100 $ 38,810 6.02K 7/85 (c)(d) (f) 1,950.000 637,950 63,795 7% (g) (g) 250,000 250,000 Total Subject to Handatory Redemption (d) ~~605 Call Price per Shares Shares Amount ( In Sh u Not Subject to Handatory Redemption:
4.085 - 4.56% $ 102- $ 110 932,403 903.233 Subject to Handatory Redemption (d):
5.90% - 5.92% (e) 1,950,000 1,904,000 $ 190,400 6.025 7/85 (f) 1,950,000 '45,000 194,500 75 7/8%
Total Subject to Handatory
$ 107.80-$ 107.88 1,250,000 1
1,250,000 ~i~)
Redemption (d)
NOTES TO SCHEDULE OF CUHULATIVE PREFERREO STOCKS OF SU8SIOIARIES (a) At the option of the subsidiary the shares may be redeemed at the call price plus accrued dividends.
The involuntary liquidation preference is $ 100 per share for all outstanding shares.
(b) As of December 31. 1997 the subsidiaries had 7,189.682. 22,200,000 and 7,579,435 shares of $ 100, $ 25 and no par value preferred stock, respectively. that were authorized but unissued.
(c) Ouring the first quarter of 1997 preferred stock was reacquired in connection with a tender offer.
(d) Shares outstanding and related amounts are stated net of applicable retirements through sinking funds (generally at par) and reacquisitions of shares in anticipation of future requirements. The subsidiaries reacquired enough shares in 1997 to meet all sinking fund requirements on certain series until 2008 and on certain series until 2009 when all remaining outstanding shares must be redeemed.
The sinking fund provisions of the series subject to mandatory redemption aggregate $ 5,000,000 each for the years 2000, 2001 and 2002.
(e) Hot callable prior to 2003; after that the call price is $ 100 per share.
(f) Not callable prior to 2000; after that the call price is $ 100 per share.
(g) Hith sinking fund. Redemption is restricted prior to 2000.
FIRST MORTGAGE 1997-2000 2001-2006 2021-2025 BONDS INSTALLMENT PURCHASE COHTRACTS n
(a) i'b AMERICANELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES Heighted Average 7.20X 7.10X 7.95X 6.35X-9.15X 6X-8.95X 7.10X-B.BOX i
6-1/4X-9.15X 6X 8 95X 7.10X-9.35X S
1 ~
1'.
466,411 511 ~ 000 1,120,419 i~ 12K 383,671 I ~511 1.276.750 000 1998-2002 4.60X 3.70X-7-1/4X 4.10X-7-1/4X 189,500 209.500 2007-2025 6.45X 5.45X-7-7/BX 5.45X 7 7/BX 756>745 756s745 NOTES PAYABLE (b) 1997-2008 6.73X ~ 29X 9 60X 5 ~ 29X 9 60'X 671 ~ 681 282 ~ 681 JUNIOR DEBENTURES 2025 - 2027 8. 17X 7.92X 8.72X BX-8.72X 495,000 315,000 OTHER LONG-TERM DEBT (c) 250,357 182.943 Unamortized Discount (net)
Total Long-term Debt
~iZ22t) ~OUI)
Outstanding (d) 5.423,917 4 '83,710 Less Portion Oue Hith(n Long-tera Portion One Year ~~44 KJ2~46 ~K' NOTES TO SCHEDULE OF COHSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES (a) For certain series of installment purchase contracts interest iates are sub)oct to periodic ad]ustment. Certain seiies will be purchased on demand at periodic interest-adjustment dates. Letters of credit from banks and standby bond purchase agreements siipport certain series.
b) Hotes payable represent outstanding promissory notes issued under term loan agreements and revolving credit agreements th a number of banks and other financial institutions and unsecured medium term notes issued to the public. At expiration I notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates enerally relate to specified short-terra interest rates.
(c) Other long-term debt consists of a liability along with accrued interest for disposal of spent nuclear fuel (see Hote 4 of the Notes to Consolidated Financial Statements) and financing obligation under sale lease back agreements.
(d) Long-term debt outstanding at Oecembei 31, 1997 is payable as follows:
Principal Amount (in thousands) 1998 5 294,454 1999 491,579 2000 321 '86 2001 267,040 2002 484,533 Later Years Total ~46~
37
Management's Responsibility The management of American Electric Power Company, Inc. is responsible for the integrity and objectivity of the information and representations in this annual report, including the consolidated financial statements. These statements have been prepared in conformity with generally accepted accounting principles, using informed estimates where appropriate, to reflect the Company's financial condition and results of operations. The information in other sections of the annual report is consistent with these statements.
The Company's Board of Directors has oversight responsibilities for determining that management has fulfilled-its obligation in the preparation of the financial statements and in the ongoing examination of the Company's established internal control structure over financial reporting. The Audit Committee, which consists solely of outside directors and which reports directly to the Board of Directors, meets regularly with management, Deloitte 8 Touche LLP-Certified Public Accountants and the Company's internal audit staff to discuss accounting, auditing and reporting matters. To ensure auditor independence, both Deloitte & Touche LLP and the internal audit staff have unrestricted access to the Audit Committee.
The financial statements have been audited by Deloitte 8 Touche LLP, whose report appears on the next page. The auditors provide an objective, independent review as to management's discharge of its responsibilities insofar as they relate to the fairness of the Company's reported financial condition and results of operations. Their audit includes procedures believed by them to provide reasonable assurance that the financial statements are free of material misstatement and includes a review of the Company's internal control structure over financial reporting.
38
independent Auditors'eport the Shareholders and Board of Directors of American Electric Power Company, Inc.:
We have audited the accompanying consolidated balance sheets of American Electric Power Company, inc. and its subsidiaries as of December 31, 1997 and 1996, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1997. 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.
ln our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of American Electric Power Company, inc. and its subsidiaries as of December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997 in conformity with generally accepted unting principles.
L L-P Deloitte 8 Touche LLP Columbus, Ohio February24, 1998 39
Indiana Michigan Power Company 1997 Annual Report
INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES One Surnrnit Square, P.o. Box Bo, Fort Wayne, indiana 48801 CONTENTS Background ... 2 Directors and Officers Selected Consolidated Financial Data . 4 Management's Discussion and Analysis of Results of Operations and Financial Condition........ 5-11 Consolidated Statements of Income Consolidated Statements of Cash Flows .. 13 Consolidated Balance Sheets . ~ 14-15 Consolidated Statements of Retained Earnings 16 Notes to Consolidated Financial Statements . 17-29 Independent Auditors'eport Operating Statistics . ~ ~ ~ ~ ~ ~ 31-32 Dividends and Price Ranges of Cumulative Preferred Stock 33 INVESTOR INQUIRIES Investors should direct inquiries to Investor Relations using the toll free number:
1-800-AEP-COMP (1-800-237-2667) or by writing to:
Bette Jo Rozsa Investor Relations American Electric Power Service Corporation 28th Floor 1 Riverside Plaza Columbus, OH 43215-2373 FORM 10-K ANNUALREPORT The Annual Report IForm 10-K) to the Securities and Exchange Commission will be available in April 1998 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
BACKGROUND INDIANAMICHIGAN POWER COMPANY (the Company) is engaged in the generation, sale, purchase, transmission and distribution of electric power. The Company serves approximately 549,000 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, electric cooperatives and non-utility entities engaged in the wholesale power market. Approximately 86% of the Company's retail sales are in Indiana and 14% in Michigan. The principal industries served are primary metals, electrical and electronic machinery, transportation equipment, chemicals and allied products, fabricated metal products and rubber and miscellaneous plastic products.
The Company, which was organized under the laws of Indiana on February 21, 1925, is a subsidiary of American Electric Power Company, Inc., a public utility holding 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 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 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 Power Company. The Company is interconnected 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 through 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 & Electric Company, Commonwealth Edison Company, Consumers Energy Corporation, Illinois Power Company, Indianapolis Power & Light Company, Louisville Gas and Electnc 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).
INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES IRECTORS Karl G. Boyd (a) William J. Lhota Dale M. Trenary (b)
Coulter R. Boyle, III Gerald P. Maloney Joseph H. Vipperman Gregory A. Clark James J. Markowsky William E. Walters Peter J. DeMaria David B. Synowiec Earl H. Wittkamper William N. D'Onofrio E. Linn Draper, Jr.
OFFICERS E. Linn Draper Jr. Armando A. Pena Chairman of the Board and Chief Executive Officer Treasurer William J. Lhota Elio Bafile President and Chief Operating Officer Assistant Controller and Assistant Secretary A. Alan Blind Leonard V. Assante Site Vice President, Donald C. Cook Nuclear Plant Assistant Controller Coulter R. Hoyle, III Timothy P. Bowman Vice President Assistant Controller Peter J. DeMaria William L. Scott Vice President and Controller Assistant Controller Eugene E. Fitzpatrick John M. Adams, Jr.
Vice President Assistant Secretary Gerald P. Maloney Maurice C. Mclntyre Vice President Assistant Secretary James J. Markowsky John B. Shinnock Vice President Assistant Secretary Joseph H. Vipperman Bruce M. Barber Vice President Assistant Treasurer John F. DiLorenzo, Jr. Christopher J. Keklak Secretary Assistant Treasurer As of January 1, 1998 the current directors and officers of Indiana Michigan Power Company were employees of American Electric Power Service Corporation with eight exceptions: Messrs. Blind, Boyd, Boyle, Clark, Mclntyre. Synowiec, Walters and VYittkamper, who were employees of indiana Michigan Power Company.
(aJ Elected April 1, 1997 (bJ Resigned April 1, 1997
Selected Consol/dated Financial Data 1RRi (in thousands)
INCOME STATEMENTS DATA:
Operating Revenues Operating Expenses Operating Income
$ 1,391,917 207,788
$ 1,328,493 220,417
~22 ~
1,283,157 205,723
~92 1,251,309
~4 221,969
$ 1,202,643 210,158 Nonoperating Income (Loss)
Income Before Interest Charges 212,203 223,146 211,995 229,397 209,924 Interest Charges Net Income 146, 740 157,153 141,092
~LRK 157,502 ELZR 129,344 Preferred Stock Dividend Requirements 11Ji9l Earnings Applicable to Common Stock ~~A 3~5 4Z ~~HE 12K (in thousands)
BALANCE SHEETS DATA:~
Electric Utility Plant $ 4,514,497
~ ~ $ 4,377,669 $ 4,319,564 $ 4,269,306 $ 4,290,957 Accumulated Depreciation and Net Amortization Electric Utility
~ILEEi, ~~422 Plant ~LSD &JH5 2K ~5523 Total Assets X~~ K~~g i3 Kk~ ~7~4 Common Stock and Paid-in Capital $ 789,056 $ 787,856 $ 787,686 $ 790,234 $ 790,625 Retained Earnings Total Common
~LRH ~iL92l ~~63 Shareholder's Equity g~~g @~~~(
Cumul ati ve Preferred Stock:
Not Subject to Mandatory Redemption $ 9,435 $ 21,977 $ 52,000 $ 52,000 $ 87,000 Subject to Mandatory Redemption (a)
Total Cumulative PreFerred Stock ~LHQ Long-term Debt (a) ~$ '~~ %1JQ~54 Obligations Under Capital Leases (a) ~km' Total Capitalization and Liabilities (a) Including portion due within
'5494 one 3~7~4 year.
~483, ~~ ~3~4
INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIALCONDITION This report includes foivIard-looking statements revenues. Indiana is considering legislative within the meaning of Section 21E of the initiatives to move to customer choice, although Secunties Exchange Act of 1934. These forward- the timing is uncertain. The Company supports looking statements reflect numerous assumptions, customer choice and is proactively involved in and involve a number of risks and uncertainties. discussions at both the state and federal levels Among the factors that could cause actual results regarding how best to structure and transition to a to differ materially are: electric load and customer competitive marketplace.
growth; abnormal weather conditions; available sources and cost of fuel and availability of As the etectric energy market evolves from cost-generating capacity; the speed and degree to of-service ratemaking to market-based pricing, which competition enters the power generation, many complex issues must be resolved, including wholesale and retail sectors of the electric utility the recovery of stranded costs. While FERC industry; state and federal regulatory initiatives orders No. 888 and 889 provide, under certain that increase competition, threaten cost and conditions, for recovery of stranded cost at the investment recovery, and impact rate structures; wholesale level, the issue of stranded cost the ability of the Company to successfully reduce recovery is unresolved at the much larger state its cost structure; the economic climate and retail level. The amount of any stranded costs the growth in the service territory; inflationary trends Company may experience depends on the timing and interest rates and other risks. and extent to which direct competition is introduced to our business and the then-existing market price of electricity.
The Company's ability to recover its costs as the Under the provisions of Statement of Financial industry transitions to competition and as Accounting Standards (SFAS) No. 71 "Accounting customer choice is more broadly available is the for the Effects of Certain Types of Regulation,"
most significant factor affecting its future. regulatoiy assets (deferred expenses) and Competition in the wholesale generation market regulatory liabilities (deferred revenues) are continues to intensify since the adoption of federal included in the consolidated balance sheets of legislation in 1992 which gave wholesale cost-based regulated utilities in accordance viith customers the right to choose their energy regulatoiy actions to match expenses and supplier and the Federal Energy Regulatory revenues with cost-based rates. In order to Commission (FERC) orders issued in 1996 which maintain net regulatory assets (net expense force open access transmission. The introduction deferrals) on the balance sheet, SFAS No.,71 of competition and customer choice for retail requires that rates charged to customers be cost-customers has been slow although activity has based and the recovery of regulatory assets must been increasing. Federal legislation has been be probable. In the event a portion of the proposed to mandate competition and customer Company's business no longer met the choice at the retail level, and several states have requirements of SFAS No. 71, net regulatory introduced or are considering similar legislation. assets would have to be written off for that portion The Michigan Commission has started a program of the business. The provisions of SFAS No. 71 for certain utilities to phase-in to competition with and SFAS No. 101 "Accounting for the the objective of providing full customer choice by Discontinuance of Application of Statement No.
2002. The Company has begun discussions with 71" never anticipated that deregulation would the Commission and other interested parties to include an extended transition period or that it formulate a plan. The actions by the Michigan would provide for recovery after the transition commission were not mandated by legislation and period of stranded costs. In July 1997 the are subject to a number of uncertainties and it is Emerging Issues Task Force (EITF) of the ot possible to determine what impact if any the Financial Accounting Standards Board (FASB) resolution of these matters will have on the reached a consensus that the application of SFAS operations of the Company. The Company's No. 71 to a segment of a regulated electric utility Michigan jurisdiction accounts for 12% of total which is subject to a legislative plan to transition
to competition in that segment should cease when and a nine-year-old transmission and distribution the legislation is passed, or an enabling rate order work management system. Process improvement is issued containing sufficient detail for the utility efforts and expenditures to develop and to reasonably determine what the plan would implement the new customer service system and entail. The EITF indicated that the cessation of similar efforts and expenditures to acquire, install application of SFAS No. 71 would require that and enhance new client server based accounting existing regulatory assets and impaired plant be and budgeting/financial planning software should written off unless they are recoverable. produce further improvements and efficiencies, enabling the Company to continue to offer its Although FERC orders No. 888 and 889 provide customers excellent service at competitive prices.
for competition in the firm wholesale market, that market is a relatively small part of our business and most of our firm wholesale sales are still under cost-of-service contracts. As a result the Significant efforts have been made to enhance Company's generation business is still cost-based our competitive-ness in nuclear power generation regulated and should remain so for the near future and to improve our nuclear organizational the passage of enabling state legislation 'ending efficiency. We continue to receive the "excellence to deregulate the generation business. We in performance" award from the Institute of believe that enabling state legislation should NucIear Power Operations. Nuclear power plants provide for the recovery of any generation-related have a major future financial commitment to safely net regulatory assets and other reasonable dispose of spent nuciear fuel and radioactive plant stranded costs from impaired generation assets. components (i.e. to decommission the plant). It is We are working with regulators, customers and difficult to reduce nuclear generation costs since legislators to provide for recovery of these certain major cost components are impacted by stranded costs during a transition period in which federal laws and Nuclear Regulatory Commission rates are fixed or frozen and electric utilities would (NRC) regulations.
take steps to achieve cost savings which would be used to reduce or eliminate their stranded The Nuclear Waste Policy Act of 1982 costs. However, if in the future the Company's established federal responsibility for, the generation business were to no longer be cost- permanent off-site disposal of spent nuclear fuel based regulated and if it were not possible to and high-level radioactive waste. By law we demonstrate probability of recovery of resultant participate in the Department of Energy's (DOE's) stranded costs including regulatory assets, results Spent Nuclear Fuel (SNF) disposal program which of operations, cash Rows and financial condition of is described in Note 3 of the Notes to the Company would be adversely affected. Consolidated Financial Statements. Since 1983 our customers have, paid $ 272 million for the disposal of spent nuclear fuel consumed at the Cook Nuclear Plant. Under the provisions of the Efforts continue to reduce the cost of products Nuclear Waste Policy Act, collections from and services in order to maintain our customers are to provide the DOE with money to competitiveness. Prior to 1997, reviews of our build a repository for spent fuel. To date the major processes led to decisions to consolidate in federal government has not made sufficient the AEP Service Corporation senior management progress towards a permanent repository or and certain functions and operations. While staff otherwise assuming responsibility for SNF. As reductions and cost savings are presently being long as there is a delay in the construction of a achieved from the consolidation and restructuring government approved storage repository for SNF, expenses for new marketing, customer services the cost of both temporaiy and permanent storage and modem efficient management information will continue to increase. The cost to systems are increasing to prepare for competition. decommission the Cook Nuclear Plant is affected by both NRC regulations and the DOE's SNF In 1997, the Company began installing a new disposal program. Studies completed in 1997 unified customer service system which is estimate the cost to decommission the Cook designed to support the request for service, Nuclear Plant range from $ 700 million to $ 1.152 illings, accounts receivable, credit and collection billion in 1997 dollars. This estimate could functions. The new unified customer service escalate due to uncertainty in the DOE's SNF system replaces a 30-year-old customer system disposal program and the length of time that SNF
INDIANAMICHIGANPOWER COMPANY AND SVBSIDIARIES may need to be stored at the plant site delaying The Comprehensive Environmental Response, decommissioning. Presently we are recovering Compensation and Liability Act (CERCLA or the estimated cost of decommissioning the Cook Superfund) addresses clean-up of hazardous Nuclear Plant over its remaining life. However, substances at disposal sites and authorized the the Company's future results of operations, cash United States Environmental Protection Agency flows and possibly its financial condition could be (Federal EPA) to administer the clean-up adversely affected if the cost of spent nuclear fuel programs. As of year-end 1997, the Company is disposal and decommissioning continues to currently involved in litigation with respect to two increase and cannot be recovered. sites overseen by the Federal EPA, and has been named by the Federal EPA as a "Potentially On September 9 and 10, 1997, during a NRC Responsible Party" (PRP) for three other sites.
architect engineer design inspection, questions There are four additional sites for which the regarding the operability of certain safety systems Company has received information requests caused Company operations personnel to shut which could lead to PRP designation as well as down Units 1 and 2 of the Cook Nuclear Plant. information requests for one state administered On September 19, 1997, the NRC issued a site. The Company's liability has been resolved Confirmatory Action Letter requiring the Company for a number of sites with no significant effect on to address the issues identified in the letter. The results of operations and present estimates do not Company is working with the NRC to resolve anticipate material cleanup costs for identified these issues and other issues related to restart of sites for which we have been declared a PRP.
the units. Certain issues identified in the letter However, if for reasons not currently identified have been addressed. At this time management significant costs are incurred for cleanup, future is unable to determine when the units will be results of operations, cash flows and possibly returned to service. If the units are not returned to financial condition would be adversely affected service in a reasonable period of time, it could unless the costs can be recovered.
have an adverse impact on results of operations, cash flows and possibly financial condition. In 1997 the Federal EPA published a revised ambient air quality standard for ozone and established a new ambient air quality standard for fine particulate matter. These standards are We take great pride in our efforts to expected to result in redesignation of a number of economically produce and deliver electricity while areas of the country currently in compliance with minimizing the impact on the environment. The the existing standard to nonattainment which Company has spent hundreds of millions of could ultimately dictate more stringent emission dollars to equip our facilities with the latest restrictions for AEP generating units including economical dean air and water technologies and those of the Company's. Under the new rules the to research possible new technologies. We intend states must first determine the attainment status to continue to take a leadership role to foster of their areas. The states then have three years economically prudent efforts to protect and to submit a compliance plan and up to ten years preserve the environment. after designation to come into compliance with the new standards. The compliance deadline could By-products from the generation of electricity be as late as 2010 for the ozone standard and include materials such as ash, slag, sludge, low- 2012-2015 for the fine particulate standard.
level radioactive waste and spent nuclear fuel. Although we are reviewing the impact of the new Coal combustion by-products are typically rules, we are unable to estimate compliance costs disposed of or treated in captive disposal facilities without knowledge of the reductions that the or are beneficially utilized. In addition, our states will find necessary to meet the new generating plants and transmission and standards. If such reductions are significant and distribution facilities have used asbestos, the Company and its affiliates must bear a polychlorinated biphenyls (PCBs) and other significant portion of the cost of compliance in a hazardous and nonhazardous materials. The region or county that is in violation of the revised Company is currently incurring costs to safely standards, it would have a material adverse effect dispose of such substances. Additional costs on results of operations, cash flows and possibly could be incurred to comply with new laws and financial condition unless such costs are regulations if enacted. recovered from customers.
At the global dimate conference in Kyoto, Japan 0 e a e e ues crease in December 1997 more than 160 countries negotiated a treaty limiting emissions of Operating revenues increased 4.8% in 1997 greenhouse gases, chiefly carbon dioxide, which following a 3.5% increase in 1996. The following may eventually contribute to global warming. analyzes the changes in operating revenues:
Although there is no dear scientific evidence that carbon dioxide contributes to global warming and Increase (Decrease)
FrmP v u damages the environment, the treaty, which ll n ei requires Congressional approval, calls for a seven percent reduction below emission levels of Retail:
greenhouse gases in 1990. We intend to work with the Congress to insure that science and reason are introduced to the debate. If approved Price Variance Volume Variance
'Nholesa)e:
~4 S
~4 26.6 37 ~
5(25.9) 08 by the Congress, the costs to comply with the emission reductions required by the Kyoto treaty are expected to be substantial and would have a Price Variance Volune Variance ~)43.8 6.0 ~4 (55.6) 9.5 material adverse impact on results of operations, Other Operatiny Revenues Total ~4 4.8 ~4 3.5 cash flows and possibly financial condition if not The increase in operating revenues in 1997 can recovered from customers. be attributed to increased retail and wholesale a'o revenues. The increase in retail revenues results from the accrual of revenues to be recovered from ratepayers for the increased cost of replacement Although operating revenues increased $ 63 power and increased fossil fuel usage during an million or 5% in 1997 due to increased accruals outage of both units at the Company's nuclear for retail power costs that will be collected in the plant. Under the retail jurisdictional fuel clauses, future under power supply cost recovery revenues are accrued for the unrecovered cost of mechanisms and increased wholesale fuel in both retail jurisdictions and for replacement transactions from a new power marketing power costs in the Michigan jurisdiction until business, net income decreased $ 10 million or 7% approved for billing. The increase in wholesale as a result of increases in purchased power and revenues in 1997 was mainly due to the other operation expenses. In July 1997 the introduction of new power marketing transactions Company started a new power marketing in July 1997. The new power marketing business of buying and selling power outside the . transactions involve the purchase and sale of AEP System which accounted for the increases in electricity outside the AEP transmission system.
purchased power and wholesale revenues. The The increase in power marketing sales was offset increase in other operation expense reflects the by a decrease in sales to the Power Pool due effect of the recognition of gains on sales of mainly to the outage of Cook Plant. The reduction emission allowance in 1996 and higher in sales to the Power Pool did not lead to a administrative and general costs and uncollectible corresponding decrease in 'revenues since accounts expenses in 1997. In 1996 net income capacity credits continue to be received. Capacity increased $ 16 million or 11% mainly due to credits are designed to allocate the cost of the increased wholesale sales, a reduction in AEP System's generating capacity among the maintenance expense and reduced financing members of the Power Pool based on the Power costs. Also contributing to the earnings increase Pool members relative peak demands and in 1996 were severance pay charges recorded in generating reserves. The Company is 1995 in connection with AEP's restructuring of compensated for the out-of-pocket costs of energy management and operations and gains recorded delivered to the Power Pool.
in 1996 from emission allowance transactions.
INDIANANICHIGANPOWER CohfPANY AhfD St/BSIDIARIES Operating revenues increased in 1996 primarily price per ton of coal consumed from a favorable as a result of increased wholesale sales settlement of a coal transportation dispute.
attributable to increased internal generation being supplied to the Power Pool and unaffiliated Purchased power expense increased utilities. The Company's share of Power Pool significantly in 1997 due to the Company's share allocated sales increased 40% due to increased of purchases of power by AEP's new power transactions with other utilities and power marketing'business and increased purchases from marketers. During 1996 the Company provided the Power Pool to replace power usually coal conversion services to power marketers and generated by the out-of-service nuclear units. The unaffiliated utilities resulting in 1.2 billion rise in purchased power expense in 1996 was kilowatthours of electricity being generated under mainly due to additional power purchases under a new FERC-approved interruptible tariff for the an agreement with the Ohio Valley Electric conversion of customers'oal to electricity and Corporation, an affiliated company which is not a does not include any fuel cost. Since these sales member of the Power Pool, and increased are for the service of converting the customers'oal purchases from the Power Pool to support the to electricity and do not include any fuel cost, Company's allocated share of higher Power Pool the average wholesale price per kilowatthour was wholesale transactions with non-affiliate utilities.
significantly less in 1996 than in 1995.
Qther operation expense increased in 1997 due Q to the effect of gains on the disposition of emission allowances recorded in 1996 and higher Total operating expenses increased 7% in 1997 administrative and general costs and uncollectible primarily due to an increase in power purchases. accounts receivable expenses.
The 3% increase in 1996 was mainly due to the increased operation of the Company's nuclear The substantial decrease in maintenance units, increased Power Pool wholesale expense in 1996 was due to cost-reduction transactions, and higher income taxes partially measures at the Company's nuclear plant, which offset by a significant reduction in maintenance reduced the number of employees performing expense. The changes in operating expenses maintenance and lowered payments for contract were: maintenance labor.
Increase (Oecrease) l m1 n The recovery period for Rockport Plant Unit 1 costs deferred under a rate phase-in plan in the Fuel 5(9.8) (4.2) 5 13.3 6.0 Indiana jurisdiction ended in August 1997 causing Purchased Power 78.8 56.8 13.3 18.6 the decrease in the amortization of phase-in plan Other Operation 23.6 7.6 3.5 1.2 deferrals. The deferred costs were amortized
)(alntenance 2.5 2.2 (26.5) (18.7)
Oeprec(ation and over a 10-year period commensurate with their Amortizat1on 0.4 0.3 1.6 1.2 collection from customers pursuant to an order of Amortization of Reexport Plant Un1t 1 Phase-in the Indiana UtilityRegulatory Commission (IURC).
Plan Oeferrals (3.8) (24.1)
Taxes Other Than Federal Income Taxes Federal Income Taxes Total
~)
(8.8) (11.9)
(8.8) 6.9
~ 1.9 2.7 43.5 2.8 The decrease in taxes other than federal income taxes in 199? was due to decreases in real and personal property taxes, Michigan single business tax and Indiana supplemental income tax.
The decrease in fuel expense in 1997 reflects a 36% decrease in nuclear generation as both Federal income taxes attributable to operations nuclear units were unavailable from September 9 through the end of the year. See Cook Plant decreased in 1997 due to a decrease in pre-tax shutdown discussed above. The decrease in operating income. The increase in 1996 reflects nuclear generation was partially offset by a 6% an increase in pre-tax operating income and
'increase in fossil generation. Fuel expense changes in certain book/tax differences accounted increased in 1996 due to a 17% increase in for on a flow-through basis for rate-making nuclear generation made possible by the shorter purposes.
refueling outage in 1996 versus an extended refueling and maintenance outage in 1995. This increase was partially offset by a lower average
When necessary the Company generally issues short-term debt to provide for interim financing of The decline in interest charges in 1996 was due capital expenditures that exceed internally to debt repayments and a refinancing program generated funds. At December 31, 1997, $ 442 which lowered interest rates. million of unused short-term lines of credit shared with other AEP System companies were available.
Short-term debt borrowing s are limited by provisions of the Public Utility Holding Company In 1997 the Company maintained its strong Act of 1935 to $ 175 million. Generally periodic financial condition. We redeemed 790,967 shares reductions of outstanding short-term debt are of cumulative preferred stock with rates ranging made through issuances of long-term debt and from 4.12% to 6.875% at a total cost of $ 79 through additional capital contributions by the million. We used short-term debt and junior parent company.
subordinated deferrable interest debentures to pay for the preferred stock tendered and to benefit The Company's earnings coverage presently from the tax deductibility of interest. exceeds all minimum coverage requirements for the issuance of mortgage bonds and preferred The Company issued $ 48 million principal stock. The minimum coverage ratios are 2.0 for amount of long-term obligations in 1997 at 6.4%. mortgage bonds and 1.5 for preferred stock. At We continued to reduce financing costs by retiring December 31, 1997, the mortgage bonds and higher-cost bonds and restructuring the long-term preferred stock coverage ratios were 7.57 and debt from senior secured/first mortgage bonds to 2.88, respectively.
senior unsecured debt and junior debentures.
The principal amount of long-term debt The Company is committed under unit power retirements, including maturities, totaled $ 50 agreements to purchase 70% of an affiliated million at 8.75%. Our senior secured debt/first (AEGCo's) share of the 1,300 mw Rockport Plant mortgage bond ratings which were reaffirmed and capacity unless it is sold to other utilities. AEGCo improved in 1997, are: Moody's, Baa1; Standard has a long contract with an unaffiliated utility for
& Poor's, A-; and Fitch, BBB+. 455 mw that expires in 1999. AEGCo's total revenues from this contract "in 1997 were $ 72 Gross plant and property additions were $ 235 million including capacity and energy charges.
million in 1997 and $ 144 million in 1996.
Management estimates construction expenditures for the next three years to be $ 456 million which Corporate Owned Life Insurance includes the replacement of the Cook Plant Unit 1 steam generators. The funds for construction of In connection, with the audit of AEP's new facilities and improvement of existing facilities consolidated federal income tax returns the can come from a combination of internally Internal Revenue Service (IRS) agents sought a generated funds, short-term and long-term ruling from the IRS National Office that certain borrowing s, preferred stock issuances and interest deductions relating to a corporate owned investments in common equity by the Company's life insurance (COLI) program should not be parent, American Electric Power Company, Inc. allowed. The Company established the COLI (AEP Co., Inc.). However, all of the construction program in 1990 as part of its strategy to fund and expenditures for the next three years are expected reduce the cost of medical benefits for retired to be financed with internally generated funds. employees. AEP filed a brief with the IRS Inflation affects the Company's cost of replacing National Office refuting the agents'osition. No utility plant and the cost of operating and adjustments have been proposed by the IRS.
maintaining plant. The rate-making process However, should a disallowance of COLI interest generally limits our recovery to the historical cost deductions be proposed it would, if sustained, of assets resulting in economic losses when the reduce earnings by approximately $ 59 million effects of inflation are not recovered from (including interest). Management believes it has customers on a timely basis. However, economic meritorious defenses and will vigorously contest gains that result from the repayment of long-term any proposed adjustments. No provisions for this debt with inflated dollars partly offset such losses. amount have been recorded. In the event the 10
INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Company is unsuccessful it could have a material New Accounting Standards adverse impact on results of operations and cash flows. In June 1997 the FASB issued SFAS 130 "Reporting Comprehensive Income" and SFAS Computer Software - Year 2000 Compliance 131 "Disclosures About Segments of an Enterprise and Related Information." SFAS 130 Many existing computer hardware and software establishes the standards for reporting and programs will not properly recognize calendar displaying components of "comprehensive dates beginning in the year 2000. Unless income," which is the total of net income and all corrected, this "Year 2000" problem may cause other changes in equity except those resulting computer malfunctions, such as system from investments by shareholders and shutdowns or incorrect calculations and system dispositions to shareholders. SFAS 131 initiates output. The Company is addressing the problem standards for reporting information about internally by modifying or replacing its computer operating segments in annual and interim financial hardware and software programs. The problem is statements as well as related disclosures about also being addressed externally with entities that products and services, geographic areas and interact electronically with the Company, including major customers. I&M's adoption of these new but not limited to, suppliers, service providers, reporting standards in 1998 is not expected to government agencies, customers, creditors and have a material effect on the results of operations, financial service organizations. However, due to cash flows and/or financial condition.
the complexity of the problem and the interdependent nature of computer systems, if the Litigation Company's corrective actions, and/or the actions of other interdependent entities, fail for critical The Company is involved in a number of legal applications, the Company may be adversely proceedings and claims. While we are unable to impacted in the year 2000. Although significant, predict the outcome of such litigation, it is not the cost of correcting the "Year 2000" problem is expected that the ultimate resolution of these not expected to have a material impact on results matters will have a material adverse effect on the of operations, cash flows or financial condition. results of operations, cash flows and/or financial condition.
11
Consolidated Statements of Income 122Z 12K (in thousands)
OPERATING REVENUES Q '51.2ll SLABS 4'Q.
OPERATING EXPENSES:
Fuel 226,402 236,237 222,967 Purchased Power 217,460 138,687 125,413 Other Operation 334,115 310,513 306,967 Maintenance 117,780 115,300 141,813 Depreciation and Amortization 140,812 140,437 138,814 Amortization of Rockport Plant Unit 1 Phase-in Plan Deferrals 11,871 15,644 15,644 Taxes Other Than Federal Income Taxes 64,945 73,729 71,791 Federal Income Taxes ~KH4 ~77 ~64 Total Operating Expenses ~kJE6 ~7~44 207,788 220,417 205,723
~7 OPERATING INCOME NONOPERATING INCOHE ~44 ~67 INCOHE BEFORE INTEREST CHARGES 212,203 223,146 211,995 INTEREST CHARGES NET INCOHE 146,740 157,153 141,092 PREFERRED STOCK DIVIDEND REQUIREMENTS MK ~LSU. 1LL'U.
EARNINGS APPLICABLE TO COHHON STOCK See Notes to Consolidated Financial Statements.
12
INDIANA MICHIGANPOWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows LRK (in thousands}
OPERATING ACTIVITIES:
Net Income S 146,740 $ 157,153 S 141,092 Adjustments for Noncash Items:
Depreciation and Amortization 148,630 148,123 148, 441 Amortization of Rockport Plant Unit 1 Phase-in Plan Oeferrals 11,871 15,644 15,644 Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses (net) (15,967) 7,662 8,684 Deferred Federal Income Taxes 3,922 (24,687) (23,564)
Deferred Investment Tax Credits (8,428} (8,729) (9,004)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (10,456) (10,235) 4,121 Fuel, Materials and Supplies 5,168 903 (6,255)
Accrued Utility Revenues 7,774 5,642 (3,355)
Accounts Payable 6,502 1,186 (2,431)
Taxes Accrued Other (net)
Net Cash Flows From Operating Activities (18,550)
~K M) ~~4
~L?ll
~7 (6,296)
~1352) 8 '75 4
INVESTING ACTIVITIES:
Construction Expenditures (122,360) (95,046) (117,785)
Long-term Receivable from Customer for Construction of Facilities Proceeds from Sales of Property and Qther Net Cash Flows Used For Investing Activities
~Ilk ~7 62 (18,733)
'LZR FINANCING ACTIVITIES:
Issuance of Long-term Debt 47,728 38,579 96,819 Retirement of Cumulative Preferred Stock (78,877) (30,568)
Retirement of Long-term Debt (50,000) (46,091) (141,122)
Change in Short-term Debt (net) 76,100 (46,475) 39,375 Dividends Paid on Common Stock (131,260) (112,508) (110,852)
Dividends Paid on Cumulative Preferred Stock Net Cash Flows Used For Financing Activities ~~4) ~2 4'5)
~~V.) ~~) ~Z2K)
)
Net Increase (Decrease) in Cash and Cash Equivalents (2,373) (5,490) 3,816 Cash and Cash Equivalents January 1 (~7 Cash and Cash Equivalents December 31 See Notes to Consolidated Financial Statements.
Consolidated Balance Sheets l22Z lRK (in thousands)
ASSETS ELECTRIC UTILITY PLANT:
Production $ 2,545,484 $ 2,525,969 Transmission 908,736 881,407 Distribution 737,902 696,069 General (including nuclear fuel) 233,888 189,619 Construction Wor k in Progress Total Electric Utility Plant
~)LSD 4,377,669 4, 514,497 Accumulated Depreciation and Amortization 52 NET ELECTRIC UTILITY PLANT NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS 'i!i!i.2K ~4 OTHER PROPERTY AND INVESTMENTS CURRENT ASSETS:
Cash and Cash Equivalents 5,860 8,233 Accounts Receivable:
Customers 107,087 90,656 Affiliated Companies 15,662 13,727 Miscellaneous 14,561 21,439 Allowance for Uncollectible Accounts (1,188) (156)
Fuel - at average cost 17,182 23,977 Materials and Supplies - at average cost 78,701 77,074 Accrued Utility Revenues Prepayments TOTAL CURRENT ASSETS
~5 30,521
~k22l 38,295 REGULATORY ASSETS DEFERRED CHARGES '~6 ~457 TOTAL ~t~Q ~F7 494 See A'otes to Conso)idated Financia1 Statements.
INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES 122Z ~6 (in thousands)
CAPIJALIZATION AND 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 732,472 731,272 Retained Earnings Total Common Shareholder's Equity 1,067,870 1,056,927 Cumulative Preferred Stock:
Not Subject to Handatory Redemption 9,435 21,977 Subject to Handatory Redemption 68,445 135,000 Long-term Debt TOTAL CAPITALIZATION
~L23Z ~~M.
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning 381,016 313,845 Other ~~4 TOTAL OTHER NONCURRENT LIABILITIES ~4~4 CURRENT LIABILITIES:
Long-term Debt Due Within One Year 35,000 Short-term Debt 119,600 43,500 Accounts Payable - General 36,729 31,015 Accounts Payable - Affiliated Companies 31,665 30,877 Taxes Accrued 46,850 65,400 Interest Accrued 15,741 15,281 Obligations Under Capital Leases 34,033 29,740 Other TOTAL CURRENT LIABILITIES DEFERRED INCOHE TAXES DEFERRED INVESTHENT TAX CREDITS ~RJL44 ~4~4 DEFERRED GAIN ON SALE AND LEASEBACK-ROCKPORT PLANT UNIT 2 DEFERRED CREDITS 8 K2 COHHITHENTS AND CONTINGENCIES (Note 3)
TOTAL ~~~44 See Notes to Consolidated Financia1 Statements.
15
Consolidated Statements of Retained Earnin s lRK (in thousands)
Retained Earnings January $ 269,071 $ 235,107 216,658 Net Income 1
~4~
Deductions:
Cash Dividends Declared:
Common Stock 131,260 112,508 110,852 Cumulative Preferred Stock:
4-1/8X Series 249 495 495 4.56X Series 88 273 273
- 4. 12% Seri es 80 165 165 5.90X Series 985 2,360 2,360 6-1/4X Series 1,266 1,875 1,875 6.30X Series 834 2,205 2,205 6-7/8X Series 7.08X Series Total Cash Dividends Declared 1,255 136,017 2,063 122,475
~4 2,063 122,412 Capital Stock Expense Total Deductions ~RL9l Retained Earnings December 31 See /Iotes to Conso7idated Financia1 Statements,
IIVDIAIVANICHIGAIVPDWER CDIMPAIVY AIVD SUBSIDIARIFS NOTES TO CONSOLIDATED FINANCIALSTATEMENTS
- 1. SIGNIFICANT ACCOUNTING POLICIES: Basis of Accounting Organization As a cost-based rate-regulated entity, l&M's financia'I statements reflect the actions of Indiana Michigan Power Company (the Company regulators that result in the recognition of or I&M)is a wholly-owned subsidiary of American revenues and expenses in different time periods Electric Power Company, Inc. {AEP Co., Inc.), a than enterprises that are not cost-based rate-public utility holding company. The Company is regulated. In accordance with Statement of engaged in the generation, sale, purchase, Financial Accounting Standards {SFAS) No. 71, transmission.and distribution of electric power to "Accounting for the Effects of Certain Types of 549,000 retail customers in its service territory in Regulation," regulatory assets {deferred northern and eastern Indiana and a portion of expenses) and regulatory liabilities (deferred southwestern Michigan. Wholesale electric power income) are recorded to reflect the economic is supplied to neighboring utility systems, power effects of regulation and to match expenses with marketers and the American Electric Power (AEP) regulated revenues.
System Power Pool (Power Pool). As a member of the AEP Power Pool and a signatoiy company Use of Estimates to the American Electric Power System (AEP System) Transmission Equalization Agreement, its The preparation of these financial statements in facilities are operated in conjunction with the conformity with generally accepted accounting facilities of certain other AEP affiliated utilities as principles requires in certain instances the use of an integrated utility system. estimates. Actual results could differ from those estimates.
The Company has two wholly-owned subsidiaries, that were formerly engaged in coal- UtilityPlant mining operations which are consolidated in these financial statements, Btackhawk Coal Company Electric utility plant is stated at original cost and and Price River Coal Company. Blackhawk Coal is generally subject to first mortgage liens.
Company currently leases and subleases portions Additions, major replacements and betterments of its Utah coal rights, land and related mining are added to the plant accounts. Retirements of equipment to unaffiliated companies. Price River plant are deducted from the electric plant in Coal Company, which owns no land or mineral service account and deducted from accumulated rights, is inactive. depreciation together with associated removal costs, net of salvage.
Regulation The costs of labor, materials and overheads As a subsidiary of AEP Co., inc., l&M is subject incurred to operate and maintain utility plant are to regulation by the Securities and Exchange included in operating expenses.
Commission (SEC) under the Public Utility Holding Company Act of 1935 (1935 Act). Retail rates are Allowance for Funds Used During ConstructIon regulated by the Indiana Utility Regufatory (AFUDC)
Commission (IURC) and the Michigan Public Service Commission (MPSC). The Federal AFUDC is a noncash nonoperating income item Energy Regulatoiy Commission (FERC) regulates that is capitalized and recovered through wholesale rates. depreciation over the service life of utility plant. It represents the estimated cost of borrowed and Principles of Consolidation equity funds used to finance construction projects.
The amounts of AFUDC for 1997, 1996 and 1995 The consolidated financial statements include were not significant.
I&M and its wholly-owned subsidiaries. Significant intercompany items are eliminated in consolidation.
17
o Depfeciation and Amortization Depreciation of electric utility plant is provided on a straight-line basis over the estimated useful lives of utility plant and is calculated largely outage and ending with the beginning of the next outage.
Income Taxes through the use of composite rates by functional The Company follows the liability method of cjass as follows: accounting for income taxes as prescribed by SFAS No. 109, "Accounting for Income Taxes."
Functional Class Annual Composite Under the liabilitymethod, deferred income taxes are provided for all temporary differences between the book cost and tax basis of assets and Production: liabilities which will result in a future tax Steam-Nuclear 3.4%
Steam-Fossil-Fired 4.4% consequence. Where the flow-through method of Hydroelectric-Conventional 3.2% accounting for temporary differences is reflected Transmission 1.9% in rates, deferred income taxes are provided with Distribution 4.2% related regulatory assets and liabilities in General 3.8% accordance with SFAS No. 71.
Amounts for the demolition and removal of non- Investment 7ax Credits nuclear plant are presently recovered through depreciation charges included in rates. The Based on directives of regulatory commissions, accounting and rate-making treatment afforded the Company reflected investment tax credits in nuclear decommissioning costs and nuclear fuel rates and on its books on a deferral basis.
disposal costs are discussed in Note 3." Commensurate with rate treatment deferred investment tax credits are being amortized over Cash and Cash Equivalents the life of the related plant investment. The Company's policy with regard to investment tax Gash and cash equivalents include temporary credits for nonutility property is to practice the cash investments with original maturities of three flow-through method of accounting.
months or less.
Debt and Preferred Stock OperatI'ng Revenues and Fuel Costs Gains and losses on reacquistion of debt are Revenues include the accrual of electricity deferred and amortized over the remaining term of consumed but unbilled at month-end as well as the reacquired debt in accordance with rate-billed revenues. Fuel costs are matched with making treatment. If the debt is refinanced the revenues in accordance with rate commission reacquisition costs are deferred and amortized orders. Revenues are accrued related to over the term of the replacement debt unrecovered fuel in both retail jurisdictions and for commensurate with their recovery in rates.
replacement power costs in the Michigan jurisdiction until approved for billing. If the of debt Debt discount or premium and expenses earnings Company's earnings exceed the allowed return in issuances are amortized over the term of the the Indiana jurisdiction, the fuel clause related debt, with the amortization included in mechanism provides for the refunding of the interest charges.
excess earnings to ratepayers. Wholesale jurisdictional fuel cost changes are expensed and Redemption premiums paid to reacquire billed as incurred. preferred stock are included in paid-in capital and amortized to reduce retained Levelizatfon of Nuclear Refueling Outage Costs commensurate with their recovery in rates. The excess of par value over the cost of preferred Incremental operation and maintenance costs stock reacquired is credited to paid-in capital and associated with refueling outages at the Donald C. amortized to retained earnings.
ook Nuclear Plant (Cook Plant) are deferred mmensurate with their rate-making treatment d amortized over the period (generally eighteen months) beginning with the commencement of an 18
POPOVER INDIANAMICHIGAN COMPANY AND SUBSIDIARIES Nuclear Decommissioning and Spent Nudear Fuel Recognized regulatory assets and liabilities are Disposal TnIst Funds comprised of the following:
Securities held in trust funds for decommissioning nuclear facilities and for the 122Z 12K
'isposal of spent nuclear fuel are recorded at Regulatory Assets:
I 1n thousands) market value in accordance with SFAS No. 115, Amounts Oue From Customers for Future Income Taxes 277,966'317.059 "Accounting for Certain Investments in Debt and DePartment of fnergy Equity Securities." Secuntfes in the trust funds Decontamination and have been classified as available-for-sale due to Oecoasafssfonfng Assessment 42,648 45,994 Rate Phase-fn Plan Deferrals 11,871 their long-term purpose. Due to the rate-making fiuclear Refueling process, adjustments for unrealized gains and Outage Cost Levelfzatfon 31,772 15,805 Unamortfzed Loss On losses are not reported in equity but result in Reacquired Debt 17,210 19,388 adjustments to the liability account for the nuclear Other decommissioning trust funds and to regulatory assets or liabilities for the spent nuclear fuel Total Regulatory Assets Regulatory Liabilities:
Q92d92 ~R disposal trust funds. Deferred Investment Tax Credits $ 138,045 $ 146,473 Othere i2 Total Regulatory Lfabflft1es Other Property and Investments
'ncluded fn Deferred Cred1ts on Consolidated Balance Sheets.
Other property and investments are stated at cost. The Rockport Plant consists of two 1,300 megawatt (mw) coahfired units. I&M and AEP Generating Company (AEGCo), an affiffate, each
- 2. EFFECTS OF REGULATION AND PHASEAN own 50% of one unit (Rockport 1) and each lease PLANS: a 50% interest in the other unit (Rockport 2) from unaffiliated lessors under an operating lease. The In accordance with SFAS No. 71 the gain on the sale and leaseback of Rockport 2 was consolidated financial statements include deferred and is being amortized, with related regulatory assets (deferred expenses) and taxes, over the initial lease term which expires in regulatory liabilities (deferred income) recorded in 2022.
accordance with regulatory actions in order to match expenses and revenues from cost-based Rate phase-in plans in the Company's Indiana rates. Regulatory assets are expected to be and FERC jurisdictions provided for the recoveiy recovered in future periods through the rate- and straight-line amortization of deferred Rockport making process and regulatory liabilities are Plant Unit 1 costs over ten years beginning in expected to reduce future cost recoveries. 1987. In 1997 the amortization and recovery of Among other things, application of SFAS No. 71 the deferred Rockport Plant Unit 1 Phase-in Plan requires that the Company's rates be cost-based costs was completed. During the recoveiy period regulated. The Company has reviewed all the net income was unaffected by the recovery of the evidence currently available and concluded that it phase-in deferrals. Amortization was $ 11.9 million continues to meet the requirements to apply SFAS in 1997 and $ 15.6 million in 1996 and 1995.
No. 71. In the event a portion of the Company's business were to no longer meet those requirements, net regulatory assets would have to 3. COMMITMENTS AND CONTINGENCIES:
be written off for that portion of the business and assets attributabfe to that portion of the business Construction and Other Commitments would have to be tested for possible impairment and if required an impairment loss recorded Substantial construction commitments have unless the net regulatory assets and impairment been made to support the Company's utility losses are recoverable as a stranded investment. operations including the replacement of the Cook 19
Plant Unit 1 steam generators. Such LitigatI'on commitments do not include any expenditures for new generating capacity. Aggregate construction The Company is involved in a number of legal program expenditures for 1998-2000 are proceedings and claims. While management is estimated to be $ 456 million. unable to predict the ultimate outcome of litigation, 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, cash flows and financial retail jurisdictions have fuel clause mechanisms condition.
that provide for recovery of changes in the cost of fuel with the regulators'eview and approval. The Nuclear Plant contracts are for various terms, the longest of which extends to 2014, and contain various l&M owns and operates the two-unit 2,110 mw clauses that would release the Company from its Donald C. Cook Nudear Plant under licenses obligation under certain force majeure conditions. granted by the Nuclear Regulatory Commission.
The operation of a nuclear facility involves special The Company is committed under unit power risks, potential liabilities, and specific regulatory agreements to purchase ?0/o of an affiliate's and safety requirements. Should a nudear (AEGCo's) share of the 1,300 mw Rockport Plant incident occur at any nuclear power plant facility in capacity unless it is sold to unaffiliated utilities. the United States, the resultant liability could be AEGCo has one long-term contract with an substantial. By agreement IBM is partially liable unaffiliated utility that expires in 1999 for 455 mw together with all other electric utility companies of Rockport Plant capacity. that own nuclear generating units for a nuclear power plant incident. In the event nuclear losses The Company sells under contract up to 250 mw or liabilities are underinsured or exceed of its Rockport Plant capacity to an unaffiliated accumulated funds and recovery is not possible, utility. The contract expires in 2009. results of operations, cash flows and financial condition would be negatively affected.
Revised AirQuality Standards Nuclear Plant Shutdown On July 18, 1997, the United States Environmental Protection Agency published a On September 9 and 10, 1997, during a Nuclear revised National Ambient Air Quality Standard Regulatory Commission (NRC) architect engineer (NAAQS) for ozone and a new NAAQS for fine design inspection, questions regarding the particulate matter (less than 2.5 microns in size). operability of certain safety systems caused The new ozone standard is expected to result in Company operations personnel to shut down Units redesignation of a number of areas of the country 1 and 2 of the Cook Nudear Plant. On September that are currently in compliance with the existing 19, 1997, the NRC issued a Confirmatory Action standard to nonattainment status which could Letter requiring the Company to address the ultimately dictate more stringent emission issues identified in the letter. The Company is restrictions for AEP System generating units. working with the NRC to resolve these issues and New stringent emission restrictions on AEP other issues related to restart of the units. Certain System generating units to achieve attainment of issues identified in the letter have been the tine particulate matter standard could also be addressed. At this time management is unable to imposed. The AEP System operating companies determine when the units will be returned to joined with other utilities to appeal the revised service. If the units are not returned to service in NAAQS and filed petitions for review in August a timely manner, it could have an adverse impact and September 1997 in the U.S. Court of Appeals on results of operations, cash flows and possibly for the District of Columbia Circuit. Management financial condition.
is unable to estimate compliance costs without knowfedge of the reductions that may be Nuclear Incident Liability necessary to meet the new standards. If such costs are significant, they could have a material Public liability is limited by law to $ 8.9 billion adverse effect on results of operations, cash flows should an incident occur at any licensed reactor in and possibly financial condition unless recovered. the United States. Commercially available insurance provides $ 200 million of coverage. In
INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES the event of a nuclear incident at any nuclear plant study has been completed. The estimated cost of in the United States the remainder of the liability decommissioning and low level waste would be provided by a deferred premium accumulation disposal costs ranges from $ 700 assessment of $ 79.3 million on each licensed million to $ 1,152 million in 1997 nondiscounted reactor payable in annual installments of $ 10 dollars. The wide range is caused by variables in million. As a result, l8M could be assessed assumptions including the estimated length of
$ 158.6 million per nuclear incident payable in time spent nuclear fuel must be stored at the plant annual installments of $ 20 million. The number of subsequent to ceasing operations. This in turn incidents for which payments could be required is depends on future developments in the federal not limited. government's spent nuclear fuel disposal program. Continued delays in the federal fuel Nuclear insurance pools and other insurance disposal program can result In increased policies provide $ 3.6 billion (reduced to $ 3.0 billion decommissioning costs. The Company is effective January 1, 1998) of property damage, , recovering estimated decommissioning costs in its decommissioning and decontamination coverage three rate-making jurisdictions based on at least Cook Plant. Additional insurance provides the lower end of the range in the most recent
'or coverage for extra costs resulting from a decommissioning study at the time of the last rate prolonged accidental Cook Plant outage. Some of proceeding. The Company records the policies have deferred premium provisions decommissioning costs in other operation which could be triggered by losses in excess of expense and records a noncurrent liability equal to the insurer's resources. The losses could result the decommissioning cost recovered in rates; from claims at the Cook Plant or certain other such amount was $ 28 million in 1S97, $ 27 million non-affiliated nuclear units. The Company could in 1S96 and $ 30 million in 1S95 including $ 4 be assessed up to $ 35.8 million annually under million of special deposits. Decommissioning these policies. costs recovered from customers are deposited in external trusts. Trust fund earnings increase the Spent Nuclear Euel Disposal fund assets and the recorded liability thereby decreasing the amount needed to be recovered Federal law provides for government from ratepayers. At December 31, 1997 the responsibility for permanent spent nuclear fuel Company has recognized a decommissioning disposal and assesses nuclear plant owners fees liability of $ 381 million.
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 4. RELATED PARTY TRANSACTIONS:
the U.S. Treasury. Fees and related interest of
$ 181 million for fuel consumed prior to April 7, Benefits and costs of the AEP System's 1983 have been recorded as long-term debt. l&M generating plants are shared by members of the has not paid the government the pre-April 1983 Power Pool. The Company is a member of the fees due to continued delays and uncertainties Power Pool. Under the terms of the AEP System related to the federal disposal program. At Interconnection Agreement, capacity charges and December 31, 1997, funds collected from credits are designed to allocate the cost of the customers towards the pre-April 1983 fee and AEP System's capacity among the Power Pool related earnings thereon approximate the liability. members based on their relative peak demands and generating reserves. Power Pool members Decommissioning and Low Level Waste are also compensated for the out-of-pocket costs Accumulation Disposal of energy delivered to the Power Pool and charged for energy received from the Power Pool.
Decommissioning costs are accrued over the The Company is a net supplier to the pool and, service life of the Cook Plant. The licenses to therefore, receives capacity credits from the operate the two nuclear units expire in 2014 and Power Pool.
017. After expiration of the licenses the plant is xpected to be decommissioned through dismantlement. A 1997 nuclear decommissioning
Operating revenues include revenues for companies'nvestments in transmission facilities capacity and energy supplied to the Power Pool and shares the costs of ownership in proportion to as follows: the AEP System companies'espective peak demands. Pursuant to the terms of the agreement, since the Company's relative 122Z 12K 1222 investment in transmission facilities is greater iin thousands}
than its relative peak demand, other operation Capacity Revenues 53,282 57.594 59,918 fnerpy Revenues
~4152 expense includes equalization credits of $ 46.1 million, $ 46.3 million and $ 46.7 million in 1997; Total RM4 Q~ 1996 and 1995, respectively.
Purchased power expense includes charges of Revenues from providing barging services were
$ 51.0 million in 1997, $ 34.5 million in 1996 and
$ 25A million in 1995 for energy received from the recorded in nonoperating income as follows:
Power Pool.
122L 12K 12K Power Pool members share in wholesale sales (fn thousands}
to unaffiliated entities made by the Power Pool. Affiliated Conpanies $ 24,427 $ 22,740 $ 23, 160 The Company's share of the wholesale power Unaffiliated Conpanies pool sales included in operating revenues were Total
$ 127.4 million in 1997, $ 73.4 million in 1996 and American Electric Power Service Corporation
$ 52.6 million in 1995. (AEPSC) provides certain managerial and professional services to AEP System companies.
In addition, the Power Pool purchases power The costs of the services are billed by AEPSC on from unaffiliated entities for resale to other a directMarge basis to the extent practicable and unaffiliated entities. The Company's share of on reasonable bases of proration for indirect these purchases was included in purchased costs. The charges for services are made at cost power expense and totaled $ 67.9 million and include no compensation for the use of equity (including new power marketing transactions) in capital, which is furnished to AEPSC by AEP Co.,
1997, $ 8.1 million in 1996 and $ 10.7 million in Inc. Billings from AEPSC are capitalized or 1995. Revenues from these transactions, expensed depending on the nature of the services inciuding a transmission fee for power that passes rendered. AEPSC and its billings are subject to through the AEP System transmission network, the regulation of the SEC under the 1935 Act.
are included in the above Power Pool wholesale operating revenues.
- 5. BENEFIT PLANS:
The cost of Rockport Plant power purchased from AEGCo, an affiliated company that is not a The Company and its subsidiaries participate in member of the Power Pool, was Included in the AEP System pension plan, a trusteed, purchased power expense in the amounts of noncontributory defined benefit plan covering all
$ 87.5 million, $ 85.4 million and $ 85.2 million in employees meeting eligibility requirements.
1997, 19S6 and 1S95, respectively.. Benefits are based on service years and compensation levels. Pension costs are allocated The cost of power purchased from Ohio Valley by first charging each System company with its Electric Corporation, an affiliated but non- service cost and then allocating the remaining associated company that is not a member of the pension cost in proportion to its share of the Power Pool, was included in purchased power projected benefit obligation. The funding policy is expense in the amounts of $ 11.0 million, $ 10.7 to make annual trust fund contributions equal to million and $ 4.0 million in 1S97, 1S96 and 1995, the net periodic pension cost up to the maximum respectively. amount deductible for federal income taxes, but not less than the minimum required contribution in The Company operates the Rockport Plant and accordance with the Employee Retirement Income bills AEGCo for its share of operating costs. Security Act of 1974. Net pension costs for the years ended December 31, 1997, 1996 and 1995 AEP System companies participate in a were $ 2.1 million, $ 4.1 million and $ 2.7 million, transmission equalization agreement. This respectively.
agreement combines certain AEP System
INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Postretirement benefits other than pensions 6. SUPPLEMENTARY INFORMATION:
(OPEB) are provided for retired employees under an AEP System plan. Substantially all employees are eligible for postretirement health care and life 1221 12K (in thousands) insurance if they retire from active service after Cash uas paid for:
reaching age 55 and have at least 10 service Interest (net of cap(tal(ted amounts) 5 62,274 S 64,117 S71.457 years. The funding policy for OPEB cost is to Incoex. Taxes 120,212 125,707 80,675 make contributions to an external Voluntary Koncash Acqufsftfons Under Capital Leases 111,395 40,305 32 '73 Employees Beneficiary Association trust fund equal to the incremental OPEB costs (i.e., the In connection with the 19S6 early termination of amount that the total postretirement benefits cost a western coal land sublease the Company will under SFAS 106, "Employers'ccounting for receive cash payments from the lessee of $ 30.8 Postretirement Benefits Other Than Pensions," million over a ten-year period which has been exceeds the pay-as-you-go amount). Contri- recorded at a net present value of $ 22.8 million.
butions were $ 6.3 million in 1997, $ 8.4 million in In connection with the 1995 sale of western coal 1996 and $ 10.3 million in 1S95. OPEB costs are land and equipment the Company will receive determined by the application of AEP System cash payments from the buyer of $ 31.5 million actuarial assumptions to each company's over a six year period which has been recorded at employee complement. The Company's annual a net present value of $ 26.9 million. In connection accrued costs for 1997, 1996 and 1995 required with construction of facilities in 1995 to provide by SFAS 106 for employees and retirees were service to a new customer the Company will
$ 11.5 million, $ 12.8 million and $ 13.6 million, receive cash payments of $ 21.4 million plus respectively. accrued interest over 20 years. The long-term portion of these receivables is recorded as other An employee savings plan is offered which property and investments and the current portion allows participants to contribute up to 17% of their is recorded as miscellaneous accounts receivable.
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 lo of the employees'ase salary, is invested in AEP Co., Inc. common stock. The employer's annual contributions totaled $ 4 million in 1S97, $ 3.7 million in 1996 and $ 3.9 million in 1995.
- 7. FEDERAL 1NCOME TAXES:
The details of federal income taxes as reported are as follows:
12K (in thousands)
Charged (Credited) to Operating Expenses (net):
Current S 75,442 1110,133 S 75,686 Deferred Deferred Investment Tax Credits Total
~)ia)
~~44 3,088
~H)
(24,730) (13,732)
~KJRR Charged (Credited) to Nonoperating Income (net)
Current 3,287 182 12,872 Deferred 834 43 (9,832)
Deferred Investment Tax Credits Total
~!K)
~iZ) ~RU Total Federal Income Taxes as Reported ~4~ ~252 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.
12K (in thousands)
Het Income i146,740 i157 153 S141,092 Federal Income Taxes pre-tax Book Income
~4RX ~J!22
~
I2'LaaliZ
~1(i Federal Income Tax on pre-tax Book Income at Statutory Rate (35X) S77,337 S81.918 568,979 Increase (Decrease) in Federal Income Tax Resulting From the Fo)lou(ng Items:
Depreciation 14,082 13,880 8,954 Corporate Ovned Life Insurance Investment Tax Credits (net)
Other Tota'i Federa'i Income Taxes as Reported
~4)
(3,348)
(8,428)
Q44Q
~)(2.178)
(8,729)
(F 187)
~7)
(9,004)
Effective Federal Income Tax Rate The following tables show the elements of the net deferred tax liability and the significant temporary differences giving rise to such deferrals:
l22l lRK (in thousands)
Deferred Tax Assets $ 223,772 $ 241,842 Deferred Tax liabilities Net Deferred Tax Liabilities ~r~c)~) ~t~<~)
~Mal)
Property Related Temporary Differences $ (471,898) $ (480,818)
Amounts Due From Customers For Future Federal Income Taxes (74,282) (79,658)
Deferred State Income Taxes (65,679) (89,471)
Deferred Net Gain - Rockport Plant Unit 2 All Other (net)
Total Net Deferred Tax Liabilities
~~4 32,347 XQiRK2M) ~~)
33,644
IIVDIAIVAhIICHIGAIVPOWER CoiHPAIVY AND SUBSIDIARIES The Company and its subsidiaries join in the At December 31, 1997 and 1996 the fair values filing of a consolidated federal income tax return of trust fund investments were $ 566 million and with their affiliated companies in the AEP System. $ 491 million, respectively. Accumulated gross The allocation of the AEP System's current unrealized holding gains were $ 41 million and consolidated federal income tax to the AEP $ 21.9 million and accumulated gross unrealized System companies is in accordance with SEC holding losses were $ 1.2 million at both December rules under the 1935 Act. These rules permit the 31, 1997 and 1996, The change in market value allocation of the benefit of current tax losses to in 1997, 1996 and 1995 was a net unrealized the System companies giving rise to them in holding gain of $ 19.1 million, $ 2.6 million and determining their current tax expense. The tax $ 24.9 million, respectively.
loss of the parent company, AEP Co., Inc., is allocated to its subsidiaries with taxable income. The trust fund investments'ost basis by With the exception of the loss of the System security type were:
parent company, the method of allocation approximates a separate return result for each 1222 12K (1n thousands) company in the consolidated group. Tax-Except Bonds 1335,358 1340,290 Equity Secur1ties 74,398 54,389 Treasury bonds 44,200 26,958 The AEP System has settled with the Internal Corporate Bonds 9,167 7,977 Revenue Service (IRS) all issues from the audits of the consolidated federal income tax returns for Cash, Cash Equivalents and Interest Accrued Total
~~ ~4 ~4 the years prior to 1991. Returns for the years 1991 through 1996 are presently open and under Proceeds from sales and maturities of securities audit by the IRS. During the audit the IRS agents of $ 147.3 million during 1997 resulted in $ 3.9 requested a ruling from their National Office that million of realized gains and $ 1.4 million of certain interest deductions relating to corporate realized losses. Proceeds from sales and owned life insurance (COLI) claimed by the maturities of securities of $ 115.3 million during Company should not be allowed. The COLI 1996 resulted in $ 2.6 million of realized gains and program was established in 1990 as part of the $ 2.1 million of realized losses. Proceeds from Company's strategy to fund and reduce cost of sales and matunties of securities of $ 78.2 million medical benefits for retired employees. AEP filed during 1S95 resulted in $ 1.4 million of realized a brief with the IRS National Office refuting the gains and $ 0.3 million of realized losses. The agents'osition. Although no adjustments have cost of securities for determining realized gains been proposed, a disallowance of the COLI and losses is original acquisition cost Including interest deductions through December 31, 1S97 amortized premiums and discounts.
would reduce earnings by approximately $ 59 million (including interest). Management believes At December 31, 1997, the year of maturity of it has meritorious defenses and will vigorously trust fund investments, other than equity contest any proposed adjustments. No provisions securities, was:
for this amount have been recorded. In the event (in thousands) the Company is unsuccessful it could have a material adverse impact on results of operations 1998 $ 87,063 1999-2002 127,575 and cash flows. 2003-2007 182,873 After 2007 Total
- 8. FAIR YALUEOF FINANCIALINSTRUMENTS:
Other Financial InstrTJments Recorded at Nuclear Trust Funds Recorded at Man(et Value Historical Cost The Nuclear Decommissioning and Spent The carrying amounts of cash and cash uclear Fuel Disposal Trust Fund investments are equivalents, accounts receivable, short-term debt, rded at market value in accordance with and accounts payable approximate fair value AS 115 and consist of tax-exempt municipal because of the short-term maturity of these bonds and other securities. instruments. Fair values for preferred stocks subject to mandatory redemption were $ 73 million and $ 137 million at December 31, 1997 and 1996,
respectively, and for long-term debt were $ 1.1 Properties under capital leases and related billion at each year end. The carrying amounts for obligations recorded on the Consolidated Balance preferred stock subject to mandatory redemption Sheets are as follows:
were $ 68 million and $ 135 million and for long-122Z 12K term debt were $ 1.0 billion at December 31, 1997 ( in thousands) and 1996, respectively. Fair values are based on Electric Utility Plant:
Production 5 9.218 5 7,410 quoted market prices for the same or similar Oistr ibution 14,660 14,699 issues and the current dividend or interest rates General:
offered for instruments of the same remaining Nuclear Fuel rnatunties. The carrying amount of the spent (net of amortization)
Other ~k103.939
~L<R 59,681 nuclear fuel disposal trust funds approximates the Company's estimate of the pre-April 1983 SNF Total Electric Ut11(ty Plant Accumulated Amortization Net Electric Uti)1ty Plant
~ik 189,085 142,739 MIL52R liability.
Other Property 40,746 19,035 Accumulated Amortization Net Other Property ~7~0 S. LEASES: Net Properties under Capital Leases Leases of property, plant and equipment are for Capital (.ease Obli gat(ons:~
Noncurrent L1abi lity 5161,194 101,225 periods of up to 35 years and require payments of related property taxes, maintenance and operating Liability Oue i((thin One Year Total Capital Lease Ob)1gations
~4~
112~7
~~4 costs. The Company is leasing 50% of the 1300 + Represents the present value of future minimum lease MW Rockport 2 generating unit under an payments.
operating lease. The lease has 25 years remaining life and total minimum lease payments The non current portion of capital lease of $ 1.8 billion. The majority of the leases have obligations is included in other noncurrent purchase or renewal options and will be renewed liabilities in the Consolidated Balance Sheets.
or replaced by other leases.
Properties under operating leases and related Lease rentals for both operating and capital obligations are not included in the Consolidated leases are generally charged to operating Balance Sheets.
expenses in accordance with rate-making treat-ment. The components of rental costs are as Future minimum lease payments consisted of follows: the following at December 31, 1997:
122Z 12K 1L5. Non-(in shousands) Cancelable Capital Operat1ng Operating Leases $ 92,067 5 9&,096 5 96.472 Amortizat1on of (1n thousands)
Cap1tal Leases 42,882 55,789 45,843 Interest on Capital 16,362 96,974 XÃ~ ~L>
1998 5 5 Leases '4222 ~LB% 1999 15>005 92,734 Tota'I Rental Costs XUidd5 ~~R 2000 2001 13,593 11,927 92,472 91,684 2002 Later Years ~iZ22,520
~2LZi2 90.655 Total Future H(nisus Lease Payments 127,174(a)
Less Estimated Interest E'lement Estimated Present Value of Future Ninisum Lease Payments 91,288 Unamortized Nuclear Fuel MKXI2 Total +<)~7 (a) Excludes nuclear fuel rentals vhlch are paid in proportion to heat produced and carrying charges on the unamortized nuclear fuel balance. There are no min1mum lease payment requ(resents for leased nuclear fuel.
INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES
- 10. CUMULATIVEPREFERRED STOCK:
At December 31, 1997, authorized shares of cumulative preferred stock were as follows:
$ 100 2,250,000 25 11,200,000 The cumulative preferred stock is callable at the price indicated below 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 1996 the Company redeemed and canceled 300,000 shares of the 7.08% series not subject to mandatory redemption.
~elhi 4-1/8$
4.56$
~
A. Cumulative Preferred Stock Not Subject to Mandatory Redemption:
Call Pr1ce December
$ 106.125 102 31, Par XILUla
$ 100 100 Number 59,760 44,788 of Shares 233 Redeemed Shares Outstanding 60,007 15,212 122Z
$ 6,001 1.521 12K (in thousands) 11,977 6,000 4.12K 102.728 100 20,869 19,131
~4
~42 KJ 'UZ
- 8. Cumulative Preferred Stock Subject to Handatory Redemption:
Shares Par Humber of Shares Redeemed Outstanding 122Z 12K 122Z 12K 1222 (in thousands) 5.90K (b) 5100 233.000 167,000 516,700 $ 40,000 6-1/4$ (b) 100 97.500 202,500 20,250 30 000 F
6.30$ (b) 6-7/8X(c) 100 100 217,550 117,500 132,450 182,500 ~ik 13,245
~~44 35,000
'8?JUL%
(a) Not callable until after 2002. There are no aggregate sinking fund prov1s1ons through 2002.
(b) Commencing in 2004 and cont1nuing through 2008 the Company may redeem, at $ 100 per share, 20,000 shares of the 5.90K series, 15,000 shares of the 6-1/4X series and 17,500 shares of the 6.30K ser1es outstanding under sink1ng fund provisions at its option and all remaining outstanding shares must be redeemed not later than 2009 . Shares redeemed in 1997 may be applied to meet the sinking fund requirement.
(c) Comnencing 1n 2003 and cont1nu1ng through the year 2007, a sinking fund will require the redemption of 15,000 shares each year and the redempt1on of the remaining shares outstanding on Apr11 1, 2008, in each case at $ 100 per share. Shares redeemed 1n 1997 may be applied to meet the sink1ng fund requirement.
27
I 11. LONG-TERM DEBT AND LINES OF CREDIT:
Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental Long-term debt by major category was authorities as follows:
outstanding as follows:
122Z 12K 12K (in thousands)
(in thousands) City of Lawrenceburg, Indiana:
First Nortgage Bonds 7.00 2015 - April 1 $ 25,000 $ 25,000
$ 520,317 $ 522,507 installment Purchase 5.90 2019 - November 1 52,000 52,000 Contracts 309,269 309,120 City of Rockport, indiana:
Other Long-tens Debt (a) (a) 2014 - August 1 50,000 50,000 180,837 171,706 Junior Debentures ~LJKi 1,049,237
~L22l 1.042.104 7.60 6.55 2016 2025
- Harch 1
- June 1 40>000 50,000 40 000 F
50,000 Less Portion Due (b) 2025 - June 1 50,000 50,000 Nithin One Year City of Sullivan, 1ndiana:
5.95 2009 - Nay 1 45,000 45,000 Total Unamortized Discount ~22)
(a) Represents a Nuclear Fuel Disposal liability including Total interest accrued payable to the,Department of Energy. See Note 3. (a) A variable interest rate is determined weekly. The average weighted interest rate was 4.3X for 1997 and 3.5X for 1996.
First mortgage bonds outstanding were as ( b) An adJustable interest rate can be a daily, weekly, follows: cossserc(al paper or term rate as designated by the Company.
A weekly rate was selected which ranged from 3.0X to 4.6X 122Z in 1997 and from 2.4X to 5.0X in 1996 and averaged 3.8X and thousands) 12'in 3.4X during 1997 and 1996, respectively.
- Hay 1 Under the terms of certain installment 7.00 1998 35,000 35,000 7.30 1999 - December 15 35.000 35,000 purchase contracts, the Company is required to 6.40 2000 - Harch 1 48,000 pay amounts sufficient to enable the cities to pay 7.63 2001 - June 1 40,000 40,000 interest on and the principal (at stated maturities 7.60 2002 ~ November 1 50,000 50,000 7.70 2002 - December 15 40,000 40>000 and upon mandatory redemption) of related 6.80 2003 - July 1 20,000 20,000 pollution control revenue bonds issued to finance 6.55 2003 - October 1 20,000 20.000 6.10 2003 - November 1 30,000 30,000 the construction of pollution control facilities at 6.55 2004 - Narch 1 25,000 25 F 000 certain generating plants. On the two variable S.75 2022 - Hay 1 50,000 S.50 2022 ~ December 75,000 rate series the principal is payable at the stated 15 75,000 7.80 2023 - July 1 20,000 20,000 matunties or on the demand of the bondholders at 7.35 - October 1 7.20 2023 20,000 20,000 periodic interest adjustment dates which occur 2024 ~ February 1 40,000 40,000 7.50 2024 - Harch 1 25,000 25,000 weeldy. The variable rate bonds due in 2014 are Unamortized Discount (net) ~()1) 520,317
~22) 522,507 supported by a bank letter of credit which expires in 2002. I8M has agreements that provide for Less Portion Oue 'Nithin One Year Total
~)2Q brokers to remarket the adjustable rate bonds due kR45l, in 2025 tendered at interest adjustment dates. In Certain indentures relating to the first the event certain bonds cannot be remarketed, mortgage bonds contain improvement, l8M has a standby bond purchase agreement maintenance and replacement provisions with a bank that provides for the bank to purchase requiring the deposit of cash or bonds with the any bonds not remarketed. The purchase trustee, or in lieu thereof, certification of unfunded agreement expires in 2000. Accordingly, the property additions. 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
INDIANAMICHIGANPO WER COMPANy'ND SuBSIDIARIES Junior debentures are composed of the following: 12. COMMON SHAREHOLDER'S EQUITY:
Mortgage indentures, charter provisions 122Z 12K (ln thousands) and orders of regulatory authorities place various 8.00 2026 - Harch 31 Unamort(zed D(scount Total
~) ~)
$ 40,000 $ 40,000 restrictions on the use of retained earnings for the payment of cash dividends on common stock. At December 31, 1997, $ 5.9 million of retained Interest may be deferred and payment of earnings were restricted. Regulatory approval is required to pay dividends out of paid-in capital.
principal and interest on the junior debentures is subordinated and subject in right to the prior ln 1997, 1996 and 1995 net changes to payment in full of all senior indebtedness of the paid-in capital of $ 1,200,000, $ 170,000 and Company. $ (2,548,000) respectively, represented gains and expenses associated with cumulative preferred At December 31, 1997, future annual long- stock transactions.
term debt payments are as follows:
((n thousands) 13. UNAUDITEDQUARTERLY FINANCIAL 1998 5 35,000 INFORMATION:
1999 35,000 2000 98,000 Ouarterly Per(ods Operat(ng Operat(ng Net 2001 40,000
((n thousands) 2002 Later Years Total Prlncl pal Amount
~LE 140,000 1,055,837 1991 Narch 31 $ 341,313 $ 59,894 $ 44,259 Dnamort(zed Discount ~iJHN) June 30 320,508 50,140 33,908 Total ~gg, September 30 December 31 362,058 368,038 60,449 37,305 45,091 23,482 Short-term debt borrowings are limited by 1996 provisions of the 1935 Act to $ 175 million. Lines Narch,31 329.883 53,018 35,167 of credit are shared with AEP System companies tune 30 323,494 50,430 33,507 September 30 339,847 61,123 44,546 and at December 31, 1997 and 1996 were December 31 335.269 55,846 43,333 available in the amounts of $ 442 million and $ 409 million, respectively. Facility fees of approximately 1/10 of 1% of the short-term lines of credit are required by the banks to maintain the lines of credit.
Outstanding short-term debt consisted of:
Year-end Balance lie(ghted December 31, 1991:
~~n~
Outstanding Average Notes Payalrle 5 56,410 6.35 Cosinerc(al Paper Total
~XJK 6.6 December 31 '996:
Notes Payable 5 3,900 5.55 Coasaerc(al Paper 7.2 Total ~4 7.0
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, 1997 and 1996, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1997.
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.
ln our opinion, such consolidated financial statements present fairly, in ail material respects, the financial position of Indiana Michigan Power Company and its subsidiaries as of December 31, 1997 and 1996, and
~ ~
the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997 in conformity with generally accepted accounting principles. ~
DELOI'1TE & TOUCHE LLP Columbus, Ohio February24, 1998 30
INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES OPERATING STATISTICS OPERATING REVENUES (in thousands):
Retail:
Residential:
Without Electric Heating 227,358 205,315 With Electric Heating Total Residential 237,475
~1QJLQ, 348,022 0
~LKQ 232,212 343,768 0 239,266
~2LSQR ~ZJi23 348,770 0
334,881 0
C~
302,883 Commercial 264,03'I 253,750 256,319 247,938 220,938 Industrial 332,218
~~R 312,777 298,256
~Lk92 ~LB'RR3 291,527 250,939 Miscellaneous Total Retail Wholesale (safes for resale)
Total Revenues from Energy Sales Provision for Refunds of Revenues LCK 950,736 1,365,813 ZZ 916,740
~iRL4ZR 1,308,218
~~ 909,827 1,267,268 880,662
~SLBBR 1,233,551
~Q~ 780,353 1,185,263 Collected in Prior Years Total Net of Provision for Refunds 1,365,813 1,308,218 1,267,268 1,233,551 1,184,508 Other ~LXQE ~QATAR ~iiJiRR ~LZGR ~L13R Total Operating Revenues ~RRZ kXA@kR ~M83-'@X ~~QR SOURCES AND USES OF ENERGY (in millions of kilowatthours):
Sources:
Net Generated:
Fossil Fuel 14,193 13,304 12,850 13,022 12,236 Nuclear Fuel 10,421 16,396 13,999 9,291 16,313 Hydroelectric Total Net Generated 133 24,747 29,799
~i6 26,935 22,408 1QG
,28,655 Purchased and Power Pool Total Sources 11.~R42 36,396
~ri91 37,380
~821 32,806
~iiZ 28,165
~R 33,534
~SO ~i% ~QQ Less: Losses, Company Use, Etc.
Net Sources 3~ 3%MR EL' 2LZfg 32JRi Uses:
Retail Safes:
Residential:
Without Electric Heating 3,307 3,329 3,390 3,210 3,178 With Electric Heating Total Residential
~ZQR 5,075
~61 5,140 5,158
~l2Z 4,937
~HE 4,884 Copmercial 4,349 4,328 4,300 4,148 3,977 Industrial Miscellaneous Total Retail
~)27,541 17,047 7,295 16,845 6,582 16,122
~Z6,453 15,620 6,025 14,969 Wholesale Sales (safes for resale) 1Z 432 1%2M 1L14Z 3Z22i Total Uses 24~ 3imm 2135% 26 ZGZ 32J95 31
/
OPERATING STATISTICS (Concluded)
AVERAGE COST OF FUEL CONSUMED (in cents):
Per Million Btu:
Coal 124 122 126 124 130 Nuclear 49 44 43 42 36 Overall 89 74 78 85 72 Per Kilowatthour Generated:
Coal 1.23 1.22 1.23 1.21 1.27 Nuclear .53 .47 .47 .47 .40 Overall .93 .80 .83 .90 ~ 77 RESIDENT)AL SERV(CE - AVERAGES:
Annual Kwh Use per Customer:
With Electric Heating 17,583 18,206 18,044 17,907 17,980 Total 10,560 10,791 10,943 10,572 10,559 Annual Electric Bill:
With Electric Heating $ 1,099.34 $ 1,121.41 $ 1,117.55 01,115.19 S1,028.26 Total $ 724.16 0721.76 0739.99 $ 717.17 0654.76 Price per Kwh (in cents):
With Electric Heating 6.25 6.16 6.19 6.23 5.72 Total 6.86 6.69 6.76 6.78 6.20 NUMBER OF CUSTOMERS:
Year-End:
Retail:
Residential:
Without Electric Heating 383,314 378,757 375,929 372,473 369,385 With Electric Heating Total Residential 101~
484,806 102222 479,129
~325 475,034 469,875 2 ~ZK 465,180 Commercial 57,311 55,869 55,077 53,927 53,081 Industrial 5,484 5,345 5,316 5,213 5,157 Miscellaneous ~JK5 ~JL20 ~292 ~BURY 'LZQ Total Retail 549,456 542,163 537,224 530,821 525,201 Wholesale (sales for resale) 222 Total Electric Customers fHLM K&K 32
/
4
INDIANAAf/CHIGANPOWER COhfPANY AND SUBSIDIARIES DIVIDENDS AND PRICE RANGES OF CUMULATIVEPREFERRED STOCK B Quarters (1997 and 1996)
U r
($ 100 Par Value) 4-1/SB Serf as 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) - Htgh
- Lov 4.565 Series D1v1dends Paid Per Share $ 1.14 $ 1.14 $ 1.14 tl.l4 t1.14 $ 1.14 $ 1.14 t1.14 Harket Price - $ Per Share (OTC)
Ask - High
- Lov S1d ~ High 52 52 57-5/8 58-1/4 51 51-1/4 52 52
- Lov 52 52 52 57-5/8 49 '/8 51 51-1/4 52 4.12% Series Dfvfdends Pa1d Per Share $ 1.03 $ 1.03 $ 1.03 $ 1.03 $ 1.03 $ 1.03 $ 1.03 $ 1.03 itarket Price - $ Per Share (OTC)
Ask - High
- Lov 81d - High 63-1/8 58 58-1/4 58 1/4 51 49 49-3/4 50
- Lov 50 58 58 58-1/4 48-1/4 48-3/4 49 49 3/4 5.90K Series Dividends Paid Per Share $ 1.475 $ 1.475 $ 1.475 $ 1.475 $ 1.475 $ 1.475 $ 1.475 $ 1.475 Harket Price - $ Per Share (OTC)
Ask (h1gh/lov) tlat Bfd (high/lov) 6-1/4X Series Dtvtdends Paid Per Share $ 1.5625 $1 '625 $ 1.5625 $ 1.5625 $ 1.5625 $ 1.5625 $ 1.5625 $ 1.5625 Market Price - $ Per Share (OTC)
Ask (high/lov)
Btd (htgh/)ow) 6.306 Series Divfdends Paid Per Share $ 1.575 $ 1.575 $ 1.575 $ 1.575 $ 1.575 $ 1.575 $ 1.575 $ 1.575 Market Pr1ce - $ Per Share (OTC)
Ask (high/lov) 81d (high/low) 6-7/SX Series Dfvfdends Paid Per Share $ 1.71875 $ 1.71875 $ 1.71875 $1 '1875 $ 1.71875 71875 $ 1.71875 $ 1.71875 Harriet Prfce - $ Per Share (OTC)
Ask (high/low)
Bfd (high/lov) 7.08% Ser1es (a) 01vtdends Paid Per Share $ 1.77 Market Price - $ Per Share (MYSE) ~ High
~ Lov CSE - Ch1cago Stock Exchange OTC - Over-the-Counter MYSE - Kev York Stock Exchange Kote - The above bfd and asked quotat1ons reprident prfces between dealers and do not represent actual transactions.
Market quotat1ons provided by Kattonal Quotatton Bureau, 1nc.
Dash indicated quotatton not available.
(a) Redeemed April 1996
Indiana Michigan Power Service Area and the American Electric Power System OHIO INDIANA WEST VI RG INIA VIRGINIA KENTUCKY R Indiana Michigan Power Co. area Other AEP operating companies'reas g Major power plant TENNESSEE printed on reoyded paper
ATTACHMENT 2 TO AEP:NRC:0909N INDIANA MICHIGAN POWER COMPANY'S PROJECTED CASH FLOW FOR 1998
1998 Forecasted Sources and Uses of Funds
$ Millions Projected 1998 Net Income Atter Taxes 148.6 Less: Dividends 117.5 31.1 Adjustments:
Depreciation and Amortization 145.3 Deferred Operating Costs 4.9 Deferred Federal Income Taxes and Investment Tax Credits (24.7)
AFUDC (6.3)
Other 30.2 Total Adjustments 149.4 Internal Cash Flow 180.5 Average Quarterly Cash Flow 45.1 Average Cash Balances and Short-Term Investments 3.7 Total 48.8