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
SUBJECT:
"Indiana Michigan Power Projected cash flow for Co's Annual R t for 1997."
1998,encl.W 980428 ltd.
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M004D COPIES TITLE: 50.71(b)
Annual Financial CATEGORY REGUL RY INFORMATION DISTRXBUT il SYSTEM (RIDS)
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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 RECIP.NAME RECIPIENT AFFILIATION C
NOTES:
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NOTE TO ALL "RIDS" RECIPIENTS:
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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 9805050269 9'7i23i PDR ADQCK 05000315 E
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...9805050269 ATTACHMENT 1 TO AEP:NRC:0909N INDIANAMICHIGAN 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"
AMERICANELECTRIC 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 Consolidated Statements of Cash Flows Consolidated Balance Sheets Notes to Consolidated Financial Statements Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries..
Schedule of Consolidated Long-term Debt of Subsidiaries Management's Responsibility Independent Auditors'eport 16 17
. 18-19 20-35 36 37 38 39
AMERICANELECTRIC POWER COMPANY, INC. ANDSUBSIDIARYCOMPANIES SELECTED CONSOLIDATED FINANCIALDATA INCOHE STATEHENTS DATA (in millions):
Operating Revenues Operating Income Income Before Extraordinary Item Extraordinary Loss-UK Windfall Tax Net Income
$ 6,161 984 620 109 511
$ 5,849 1,008 587 587
$ 5,670 965 530 530 500 94 354
$ 5,505
$ 5,269 932 929 500 354 BALANCE SHEETS DATA (in millions):
Electric Utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant
$ 19,597
$ 18,970
$ 18,496
$ 18,175
$ 17,712
%11 ~63 QL ~4 X1LBK QL2% ~m Total Assets Common Shareholders'quity
$ 16,615 4,677
$ 15,883 4,545
$ 15,900 4,340 4,229 4,151
$ 15,736
$ 15,359 Cumulative Preferred Stocks of Subsidiaries:
Not Subject to Handatory Redemption 47 Subject to Handatory Redemption*
128 Long-term Debt*
5,424 Obligations Under Capital Leases*
538
- Including portion due within one year d
0 90 510 4,884 414 148 523 5,057 405 233 590 4,980 400 268 501 4,995 284 COHHON STOCK DATA:
Earnings per Common Share:
Before Extraordinary Item
$ 3.28 Extraordinary Loss UK Windfall Tax ~j9)
Net Income
$ 3. 14
$ 2.85
$ 2.71
$ 1.92
~7 Average Number of Shares Outstanding (in thousands)
Harket Price Range:
High Low Year-end Market Price 51-5/8 41-1/8 40-1/2 189,039 187,321 185,847 52
$44-3/4
$40-5/8 39-1/8 38-5/8 31-1/4 27-1/4 32-7/8 32 37-1/8 184,666 184,535
$37-3/8
$40-3/8 Cash Dividends Paid Dividend Payout Ratio Book Value per Share (a) Dividend Payout Ratio before
$ 2.40
$ 2.40
$ 2.40 88.7X(a) 76.5X 84.1g
$ 24.62
$ 24.15
$ 23.25
$ 2.40 88.6X
$ 22 '3 Extraordinary Loss UK Windfall Tax is 73. IX.
$ 2.40 125.2X
$ 22.50
AMERICANELECTRIC POWER COMPANY, INC. AND SUBSIDIARYCOMPANIES ANAGENIENT'S DISCUSSION ANDANALYSISOF RESULTS OF OPERATIONS AND INANCIALCONDITION This discussion includes forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These forward-looking statements reflect assumptions, and involve a number of risks and uncertainties.
Among the factors that could cause actual results to differ materially are: electric load and customer growth; abnormal weather conditions; available sources and costs of fuels and availability of generating capacity; the, speed and degree to which competition is introduced to our power generation business, the terms ofthe transition to competition, and its impact on rate structures; the ability to recover stranded costs, new legislation and government regulations, the ability of the Company to successfully reduce its costs including synergy estimates; the degree to which the Company develops non-regulated business ventures and their success; the economic climate and growth in our service territory; inflationary trends, interest rates and other risks.
facilities at large commercial and industrial plant sites including initially 16 Conoco and Dupont plant sites.
'The completion of agreements for the joint venture companies and the commencement of operations are expected in 1998.
In December 1997 American Electric Power Company (AEP or the Company) and Central and South West Corporation (CSW) agreed to merge.
The merger is subject to approval by regulators and shareholders.
Completion of the merger is expected to occur in the first half of 1999.
CSW, a Dallas-based public utilityholding company, owns four domestic electric utility subsidiaries serving 1.7 million customers in portions of Texas, Oklahoma, Louisiana and Arkansas and a regional electricity company in the UK.
Other international energy operations and non-utility subsidiaries owned by CSW are involved in energy-related investments, telecommunications, energy 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 global energy and related services company.
Construction of a 250-megawatt generating station in China, jointly owned with two Chinese partners, progressed on schedule and within budget.
In April, the Company and New Century Energies, Inc. acquired Yorkshire Electric Group
- pic, a
United Kingdom (UK) distribution company.
The Yorkshire investment is accounted for using the equity method. A new power marketing business was launched in July contributing significantly to our operating revenues which surpassed
$6 billionfor the first time. Ajoint venture with Conoco, an energy subsidiary of Dupont, was announced in October that will provide energy management services as well as financing of steam and electric generation AEP's 1997 income before an extraordinary loss, the one-time UKWindfall Tax, increased 6% to $620 million or $3.28 per share from $587 million or $3.14 per share in 1996.
The increase was primarily attributable to increased transmission service revenues, reduced preferred stock dividends due to a
redemption program and an increase in nonoperating income from the April 1997 investment in Yorkshire exclusive of the extraordinary loss.
Net income inclusive of the $109 million extraordinary loss decreased
$76 million or 13% primarily due to the UK one-time windfall tax which was based on a revision or recomputation of the original privatization value of certain privatized utilities, including Yorkshire.
For further details regarding changes in operating revenues and expenses, taxes and nonoperating investment earnings in 1997 and 1996 see Results of Operations.
The Company's ability to recover its costs as the industry transitions to competition and as customer choice is more broadly available is the most significant factor affecting its future. Competition in the wholesale generation market continues to intensify since the adoption of federal legislation in 1992 which gave wholesale customers the right to choose their energy supplier and the Federal Energy Regulatory Commission (FERC) orders issued in 1996 which forced open access transmission.
The introduction of competition and customer choice for retail customers has been slow although activity has been increasing.
Federal legislation has been proposed to mandate competition and customer choice at the retail level, and several states have introduced or are considering similar legislation. All of our states have initiatives to move to customer choice that willphase-in or allow for a transition to competition, although the timing is uncertain.
The Company supports customer choice and is proactively involved in discussions at both the state and federal levels regarding how best to structure and transition to a
competitive marketplace.
As the cost ofgeneration in the electric energy market evolves from cost-of-'service ratemaking to market-based pricing, many complex issues must be resolved, including the recovery of stranded costs.
While FERC orders No. 888 and 889 provide, under certain conditions, for recovery of stranded cost at the wholesale level, the issue of stranded cost is unresolved at the much larger retail level.
The amount of any stranded costs we may experience depends on the timing and extent to which direct competition is introduced to our business and the then-existing market price of electricity.
Under the provisions of Statement of Financial Accounting Standards (SFAS) No.
71 "Accounting for the Effects of Certain Types of Regulation,"
regulatory assets (deferred expenses) and regulatory liabilities (deferred revenues) are included in the consolidated balance sheets of regulated utilities in accordance with regulatory actions and in order to match expenses and revenues with cost-based rates.
In order to maintain net regulatory assets (net expense deferrals) on the balance sheet, SFAS No.
71 requires that rates charged to customers be cost-based.
In the event a portion of AEP's business no longer meets the requirements of SFAS No. 71, net regulatory assets would have to be written off for that portion of the business.
The provisions of SFAS No. 71 and SFAS No. 101 "Accounting for the Discontinuance of Application of Statement No. 71" never anticipated that deregulation would include an extended transition period or that it would provide for recovery of stranded costs after the transition period.
In July 1997 the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) reached a consensus that the application of SFAS No. 71 to a segment of a regulated electric utilitywhich is subject to a legislative plan to transition to competition in that segment should cease when the legislation is passed or an enabling rate order is issued containing sufficient detail for the utility to reasonably determine what the plan would entail. The EITF indicated that the cessation of application of SFAS 71 would require that regulatory assets and impaired plant be written offunless they are recoverable.
Although FERC orders No. 888 and 889 provide 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 AEP's generation business is still cost-based
regulated and should remain so for the near future pending the passage of enabling state legislation to deregulate the generation business.
We believe that enabling state legislation should provide for the recovery of any generation-related net regulatory assets and other reasonable stranded costs from impaired generation assets.
We are working with regulators, customers and legislators to provide for recovery of these stranded costs during a transition period in which rates are fixed or frozen and electric utilities would take steps to achieve cost savings which 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 possible to demonstrate probability of recovery of resultant stranded costs including regulatory assets, results of operations, cash flows and financial condition would be adversely affected.
Efforts continue by AEP to reduce the costs of its products and services in order to maintain our competitiveness.
Prior to 1997, reviews of our major domestic processes led to decisions to consolidate management and certain functions and operations and improve certain major processes.
While staff reductions and cost savings resulting from the restructuring and improvements are presently being achieved, expenses for new marketing, customer services and modern efficient management information systems are increasing to prepare for competition.
In 1997 the costs of these efforts to prepare for competition offset the savings from restructuring.
In 1997, AEP also began installing a new uniTied customer service system which is designed to support the request for service,
- billings, accounts receivable, credit and collection functions.
AEP's new unified customer service system replaces a 30-year-old customer system and a nine-year-old transmission and distribution work management system.
Process improvement efforts and expenditures to develop and implement the new customer service system and similar efforts and expenditures to
- acquire, install and enhance new client server-based accounting and budgeting/financial planning software should produce further improvements and efficiencies, enabling AEP to continue to offer its customers excellent service at competitive prices.
AEP recognizes that it must continue to manage coal costs to maintain its competitive position.
Approximately 90%
of AEP's generation is coal fired and approximately 17% of the 53 million tons of coal burned in 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 lower coal costs.
We intend to continue to prudently supplement our long-term coal supplies with spot market purchases as long as favorable spot market prices exist.
In prior years we have agreed in our Ohio jurisdiction to certain limitations on the recovery of affiliated coal costs.
Our analysis shows that we should be able to recover the Ohio jurisdictional portion of the costs of our affiliated mining operations including future mine closure costs.
Management intends to seek recovery of its non-Ohio jurisdictional portion of the investment in and the liabilities and closing costs of our affiliated mines estimated at
$102 million after tax.
However, should it become apparent that these affiliated mining costs willnot be recovered from Ohio and/or non-Ohio jurisdictional customers, the mines may have to be closed and future earnings, cash fiows and possibly financial condition could be adversely affected.
In addition
compliance with Phase II requirements of the Clean AirAct Amendments of 1990 (CAAA),
which become effective in January
- 2000, could also cause the mining operations to close.
Unless the cost of any mine closure is recovered either in regulated rates or as a stranded cost under a plan to transition the generation business to competition, future earnings, cash flows and possibly financial condition could be adversely affected.
ss Significant efforts have been made to enhance our competitiveness in nuclear power generation and to improve our nuclear organizational efficiency.
In 1997 we continued to receive the "excellence in performance" award from the Institute of Nuclear Power Operations.
Nuclear power plants have a
major future financial commitment to safely dispose of spent nuclear fuel (SNF) and radioactive plant components (i.e. to decommission the plant).
It is difficult to reduce nuclear generation costs since certain major cost components are impacted by federal laws and Nuclear Regulatory Commission (NRC) regulations.
The Nuclear Waste Policy Act of 1982 established federal responsibility for the permanent off-site disposal of SNF and high-level radioactive waste.
By law we participate in the Department of Energy (DOE)
SNF disposal program which is described in Note 4 of the Notes to Consolidated Financial Statements.
Since 1983 our customers have paid $272 million for'the disposal of nuclear fuel consumed at the Donald C. Cook Nuclear Plant (Cook Plant).
Under the provisions of the Nuclear 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 towards a permanent repository or otherwise assuming responsibility for SNF. As long as there is a delay in the construction of a government approved storage repository for
- SNF, the cost of both temporary and permanent storage willcontinue to increase.
The cost to decommission the Cook Plant is affected by both NRC regulations and the DOE's SNF disposal program.
Studies completed in 1997 estimate the cost to decommission the Cook Plant range from
$700 millionto $1.152 billion in 1 997 dollars.
This estimate could escalate due to uncertainty in the DOE's SNF disposal program and the length oftime that SNF may need to be stored at the plant site delaying decommissioning.
Presently we are recovering the estimated cost of decommissioning the Cook Plant over its remaining life. However, AEP's future results of operations, cash flows and possibly its financial condition could be adversely affected if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered.
On September 9 and 10, 1997, during a NRC architect engineer design inspection, questions regarding the operability of certain safety systems caused Company operations personnel to shut down Units 1 and 2 of the Cook Plant.
On September 19, 1997, the NRC issued a Confirmatory Action Letter requiring the Company to address the issues identified in the letter.
The Company is working with the NRC to resolve these issues and other issues related to restart of the units.
Certain issued identified in the letter have been addressed.
At this time management is unable to determine when the units will be returned to service.
If the units are not returned to service in a reasonable period of time, it could have an adverse impact on results ofoperations, cash flows and possibly financial condition.
We take great pride in our efforts to economically produce and deliver electricity while minimizing the impact on the environment.
Over the years AEP has spent over a billion dollars to equip our facilities
with the latest cost effective clean air and water technologies and to research possible new technologies.
We are also proud of our award winning efforts to reclaim our mining properties.
We intend to continue in a leadership role fostering economically prudent efforts to protect and preserve the environment.
where we have been named a
PRP or defendant, our disposal or recycling activity was in accordance with the then-applicable laws and regulations.
Unfortunately, CERCLA does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories.
0 s By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF.
Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically disposed of or treated in captive disposal facilities or are beneficially utilized.
In
- addition, our generating plants and transmission and distribution facilities have used
- asbestos, polychlorinated biphenyls (PCB) and other hazardous and nonhazardous materials.
We are currently incurring costs to safely dispose of such substances.
Additional costs could be incurred to comply with new laws and regulations ifenacted.
The Comprehensive Enviromental
- Response, Compensation and Liability Act (CERCLAor Superfund) addresses clean-up of hazardous substances at disposal sites and authorized the United States Environmental Protection Agency (Federal EPA) to administer the clean-up programs.
As of year-end 1997, we are involved in litigation with respect to five sites overseen by the Federal EPA and have been named by the Federal EPA as a
"Potentially Responsible Party" (PRP) for seven other sites.
There are seven additional sites for which AEP companies have received information requests which could lead to PRP designation.
Also, an AEP subsidiary has received an information request with respect to one site administered by state authorities.
Our liabilityhas been resolved for a number of sites with no significant effect on results of operations.
In those instances While the potential liability for each Superfund site must be evaluated separately, several general statements can be made regarding our potential future liability.
Disposal at a particular site by AEP is often unsubstantiated; the quantity of material we disposed of at a site was generally small; and the nature of the material we generally disposed of was nonhazardous.
Typically, we are one of many parties named as PRPs for a site and, although liability is joint and several, generally some of the other parties are financially sound enterprises.
Therefore, our present estimates do not anticipate material cleanup costs for identified sites for which we have been declared PRPs.
- However, if for reasons not currently identified significant cleanup costs are attributed to AEP in the future, results of operations, cash flows and possibly financial condition would be adversely affected unless the costs can be recovered from customers.
c s
Federal EPA is required by the CAAA to issue rules to implement the law.
In December 1996 Federal EPA'issued final rules governing nitrogen oxide (NOx) emissions that must be met after January 1, 2000 (Phase II of the CAAA). The final rules will require substantial reductions in NOx emissions from certain types of boilers including those in AEP's power plants.
On February 13, 1998, the United States Court of Appeals for the District of Columbia Circuit, in an appeal in which the AEP System operating companies participated, upheld the emission limitations.
In addition in November 1997 the Federal EPA
published a proposed rulemaking requiring the revision of state implementation plans in 22 eastern states, including those states in which the operating companies of the AEP System have coal-fired generating plants.
The proposed rule will require reductions in NOx emissions from utility sources of approximately 85% below 1990 levels and entail very substantial capital and operating expenditures by AEP System operating companies.
Pollution controls to meet the proposed revised NOx emission limits would have to be in place by 2002.
Eight northeast states have petitioned Federal EPA for the imposition of additional NOx controls for upwind industrial and utility sources.
The matter is being litigated. The costs to comply with the emission reductions required by the Federal EPA's actions are expected to be substantial and would have a
material adverse impact on future results of operations, cash flows and possibly financial condition if the resultant costs are not recovered from customers.
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 expected to result in 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 being achieved.
The states then have three years to submit a compliance plan and up to ten years after designation to come into compliance with the new standards.
The compliance deadline could be as late as 2010 for the ozone standard and 2012-2015 for the fine particulate standard.
Although we are reviewing the impact of the new rules, we are unable to estimate compliance costs without knowledge of the reductions that will be necessary to meet the new standards.
If such reductions are significant and the Company must bear a significant portion of the cost of compliance in a region that is in violation of the revised standards, it would have a material adverse effect on results of operations, cash flows and possibly financial condition unless such costs are recovered from customers.
At the global climate conference in Kyoto, Japan in December 1997 more than 160 countries, including the United States, negotiated a treaty limiting emissions of greenhouse
- gases, chiefly carbon dioxide, which may eventually contribute to global warming. Although there is no dear scientific evidence that carbon dioxide contributes to global warming and damages the environment, the
- treaty, which requires Congressional approval, calls for a seven percent reduction below the emission levels of greenhouse gases in 1990. We intend to work with Congress to insure that science and reason are introduced to the debate.
If approved by Congress the costs to comply with the emission reductions required by the Kyoto treaty is expected to be substantial and would have a material adverse impact on results of operations, cash flows and possibly financial condition if not recovered from customers.
Net income decreased 13% to $511 millionprimarily due to an extraordinary loss of $109 million from the UKs one-time windfall tax which was based on a retroactive revaluation of the original privatization price of certain privatized utilities, including Yorkshire.
Income before the extraordinary loss increased 6% in 1997 to $620 million or
$3.28 per share from $587 million or $3.14 per share in 1996. The increase is primarily attributable to increased transmission service sales, reduced preferred stock dividends due to a redemption program and an increase in
In 1996 net income increased 11% to
$587 million or $3.14 per share from $530 million or $2.85 per share in 1995.
The increase was mainly attributable to increased sales of energy and services and reduced interest charges and preferred stock dividends. Sales increased due to increased transmission and other services provided to power marketers and utilities and increased energy sales to non-affiliate utilities and industrial customers.
The reduction in interest and preferred stock dividends resulted from the Company's refinancing program.
Also contributing to the improvement in net income in 1996 were severance pay charges recorded in 1995 in connection with the restructuring of management and operations and gains recorded in 1996 from emission allowance transactions.
Operating revenues increased 5% in 1997 and 3% in 1996.
Increased wholesale energy sales and transmission and coal conversion service revenues were the primary reasons for the increases in both years.
The change in revenues can be analyzed as follows:
Increase (Oecrease)
III v
Retail:
Price Variance Volume Variance Fuel Cost Recoveries Mholesale:
Price Variance Volume Variance Fuel Cost Recoveries Other Operating Revenues S(44.0)
S (42.9) 2.4 63.7
~) (0.3) ~
0.7 9.6 (202.0) 269.7 317.3~)
36.3 ~
16.4 Total 6.3 ~
3.2 The slight decrease in retail revenues in 1997 was largely due to a decline in higher priced sales to weather-sensitive residential f
i nonoperating income from the April 1997 investment in Yorkshire exclusive of the extraordinary loss.
customers reflecting mild weather.
The decline in residential sales was completely offset by an increase in lower priced sales to industrial customers, reflecting increased usage which resulted in a small increase in total retail energy sales.
The negative price variance resulted from the shift from higher priced residential sales to lower priced industrial sales.
In 1997 wholesale revenues and sales increased significantly primarily due to new power marketing transactions which began in July 1997 when AEP commenced a power marketing business.
The new power marketing transactions involve the substantial purchase and sale of electricity outside ofthe AEP transmission system.
An increase in coal conversion service sales also contributed to the significant increase in wholesale sales and revenues.
These sales are for the generation of electricity from the coal of the purchaser.
An increase of
$33 million in transmission service revenues produced the increase in other operating revenues in 1997. Transmission service revenues are for the transmission of other companies'ower through AEP's extensive transmission system.
These revenues have increased significantly since the issuance of the FERC's open access transmission rules in 1996.
In 1996 retail revenues increased slightly due to growth in the number of customers and the addition of a major new industrial customer in December 1995.
Revenues from higher priced sales to residential customers, the most weather-sensitive customer class, were flat, increasing less than one percent, as the effect of cold winter weather in early 1996 was offset by mild summer and December temperatures.
Revenues from lower priced commercial and industrial customers increased 1% reflecting growth in the number of customers.
The increase in lower priced
commercial and industrial sales accounted for the negative price variance in 1996.
Wholesale revenues increased 16% in 1996 reflecting a 46% increase in wholesale sales attributable largely to transactions with power marketers and other utilities. During 1996 the Company began providing coal conversion services resulting in 6.8 billion kilowatthours of electricity generated for power marketers and certain other utilities from their coal under a new FERC-approved interruptible, contingent sales tariff. These sales have lower prices because there is no associated fuel cost. As a result the average price per kilowatthour was significantly less in 1996 than in 1995 producing a negative price variance.
Also contributing to the increased wholesale sales was a long-term contract with an unaffiliated utilityto supply 205 MW of energy for 15 years beginning January 1, 1996.
An increased level of activity in the wholesale energy markets, due to FERC's open access rulemaking and AEP's aggressive efforts to provide flexible and competitively priced transmission services led to an increase in transmission service revenues in 1996. As a result transmission service
- revenues, which are recorded in other operating
- revenues, increased by approximately $24 million.
The level of wholesale sales tends to fluctuate due to the highly competitive nature of the short-term energy market and other factors, such as affiliated and unaffiliated generating plant availability, the weather and the economy.
The FERC rules which introduce a greater degree of competition into the wholesale energy market have had the effect of increasing short-term wholesale sales and transmission service revenues.
The Company's sales and in turn its results of operations were impacted in 1997 and 1996 by the quantities of energy and services sold to wholesale customers.
Future results of operations will be affected by the quantity and price of wholesale transactions which often depend on the level of competition, the weather and power plant availability, both affiliated and non-affiliated, factors the Company does not control.
However, we work to take advantage of these factors when they are favorable.
Operating expenses increased 7% in 1997 and 3% in 1996.
Increased purchased power expense, mainly from the Company's new power marketing
- business, was the primary reason for the 1997 increase.
New marketing, customer services and software costs to prepare for competition also contributed to the increase.
The primary items accounting for the increase in 1996 were increased fuel costs, federal income taxes and expenditures for marketing, information systems and other items necessary to prepare for the transition to competition. Changes in the components of operating expenses were as follows:
Increase (Decrease)
~m
~
~m Fuel
$ 26.4 1.6
$ 63.5 4.1 Purchased Power 330.2 383.5 (2.3)
(2.6)
Other Operat(on 17.3 1.4 25.9 2.2 Ha(ntenance (19.6)
(3.9)
(39.0)
(7.2)
Deprec(at(on and Amort(zat(on (9')
(1.6) 7.8 1.3 Taxes Other Than Federal Income Taxes (8.0)
(1.6) 9.4 1.9 Federal Income Taxes ~)
(0.3) ~
25.8 Total 6.9 ~
2.9 Fuel expense increased in 1997 primarily due to an increase in the average cost offuel consumed reflecting the reduced availability of lower cost nuclear generation in 1997 due to the unplanned shutdown and maintenance outage of both nuclear units which began on September 10 and continued through year-end.
The increase in fuel expense in 1996 was primarily due to an increase in generation to meet the increase in industrial and wholesale customer demand.
The effect of increased generation was partially offset by reduced average fossil 10
fuel costs, resulting from increased usage of lower cost spot market coal, and lower cost uclear fuel.
The significant increase in purchased power expense in 1997 was primarily due to purchases of electricity for the new power marketing business.
These purchases were made to cover sales made to non-affiliates by the new power marketers.
ln 1997 restructuring savings in other operation expense were more than offset by additional expenses for marketing, customer service and software costs to prepare for the service demands of competition.
Maintenance expense decreased in 1996 due to the deferral of previously expensed storm damage costs commensurate with their recovery over 5-years and reduced nuclear plant maintenance expense due to workforce reductions and the reduction of contract labor at the Cook Plant.
The increase in federal income tax 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
flow-through basis and certain permanent differences.
The increase in nonoperating income in 1997 was mainly due to income from non-regulated operations.
The Company's share of earnings from its April 1997 investment in Yorkshire was $34 millionwhich includes $10 millionof nonrecurring tax benefits related to a reduction of the UK corporate income tax rate from 33% to 31% effective April 1,1997.
The utilization of foreign tax credits also contributed to the increase in nonoperating income. Nonoperating income decreased in 1996 due to the cost of the AEP branding program and the cost of efforts to develop and make investment in new non-regulated business ventures.
re e
a d ree d
e ts ln 1997 interest charges on both long-term and short-term debt increased reflecting additional borrowing primarily to fund the Company's non-regulated operations including the investment in Yorkshire.
Preferred stock dividend requirements of the subsidiaries decreased in 1997 due to the reacquisition of over 4 million shares of cumulative preferred stock.
The decrease in interest charges and preferred stock dividend requirements in 1996 was mainly due to continued refinancing programs of the Company's subsidiaries.
The refinancings reduced the average interest rate and the amount of long-term debt and preferred stock outstanding.
The cost of short-term borrowing s in 1996 increased slightly reflecting an increased average balance of short-term debt outstanding.
ln 1997 AEP maintained its strong financial condition and performance in 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 dividend in 1997 of 60 cents a
share maintaining the annual dividend rate at $2.40 per share.
The 1997 payout ratio before extraordinary loss at 73% was 3% better than 1996's and 15% better than 1994's.
lt has been a management objective to reduce the payout ratio through efforts to increase earnings in order to enhance AEP's ability to invest in new business ventures that can complement our core competencies and improve shareholder value.
AEP's three-year total shareholder return ranked fourth among the companies in the SBP Electric 11
UtilityIndex. This marked the fourth straight year in the top quartile of the Index.
Management's goal is to maintain our position in the top quartile of the S8 P Electric UtilityIndex for three-year total shareholder return.
The total consideration paid in 1997 by a joint venture of AEP and an unaffiliated company to
.acquire Yorkshire was approximately
$2.4 billion which was financed by a combination of equity and non-recourse debt.
AEP initiallyfunded its 50%
equity investment in the joint venture with
$50 million in cash, a $300 million adjustable rate term loan under a long-term revolving credit agreement and $10 million of short-term debt.
For more information see Note 7 of the Notes to Consolidated Financial Statements.
Also the Company's 70%
interest in the construction of two 125 MW units in China will require approximately
$110 millionof investment.
AEP's construction expenditures are expected to be $2.4 billion over the next three years which includes the Cook Plant's Unit 1 steam generator replacement, the China project and the cost of transmission and distribution projects for the improvement of and addition to electric energy delivery facilities.
Approximately 90% of domestic construction expenditures, estimated to be
$2.3 billion for the next three years, will be financed with internally generated furids.
AEP achieved a year-end ratio of common equity to total capitalization including amounts due within one year of 45.5% for 1997, compared with 45.3% for 1S96 and 43.1% for 1995.
The Company's goal is to maintain the common equity ratio at a level of at least 40 percent.
During 1S97 the Company and its subsidiaries continued redefining and improving their debt to equity position.
The Company's regulated subsidiaries redeemed 4,258,947 shares of cumulative preferred stock with rates ranging from 4.08% to 7.875% at a total cost of $433 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 Company and its subsidiaries issued $882 millionprincipal amount of long-term obligations in 1997 at interest rates ranging from 5.9% to 8.0%. The companies continued to reduce financing costs by retiring higher-cost bonds and restructuring the long-term debt from senior secured/first mortgage bonds to senior unsecured debt and junior debentures.
The principal amount of long-term debt retirements, including maturities, totaled $343 million with interest rates ranging from 6.5% to 9.35%.
Our operating subsidiaries senior secured debNirst mortgage bond ratings, which were reaffirmed and improved in 1997, are listed in the following table:
Appalachian Pouer Co.
Coluahus Southern Pover Co.
Indiana B Nichtgan Pover Co.
Kentucky Power Co.
Ohto Power Co.
A3 A3 Baal Baal A3 A
A A
A A-A A
A A
6 8B+
H/A BBB+
K/A A
A H/A ~ llot applicable The operating subsidiaries generally issue short-term debt to provide for interim financing of capital expenditures that exceed internally generated funds. They periodically reduce their outstanding short-term debt through issuances of long-term debt and additional capital contributions by the parent company.
The companies formed to pursue non-regulated business opportunities are using short-term debt.
Short-term debt increased $235 million from the prior year-end balance arid decreased by $45 million in 1996. At December 31, 1997, AEP Co., lnc.
(the parent company) and its subsidiaries had unused short-term lines of credit of $442 million, and several of AEP's subsidiaries
I t
t I
ti I
The followingdebt and preferred stock coverages of the principal operating subsidiaries remained strong in 1997:
Preferred Appalachian Power Co.
3.72 Colunbus Southern Power Co.
4.95 Indiana h Nlchlgan Power Co.
7.57 Kentucky Power Co.
4.23 Ohio Power Co.
9.74 N/A ~ Not ApplfeenIe Unless the subsidiaries meet certain earnings or coverage
- tests, they cannot issue additional mortgage bonds or preferred stock.
In order to issue mortgage bonds
{without refunding existing debt},
each subsidiary must have pre-tax earnings equal 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 stock requires after-tax gross income at least equal to one and one-half times annual interest and preferred stock dividend requirements after giving effect to the issuance of the new preferred stock. As the above chart indicates, the subsidiaries presently exceed these minimum coverage requirements.
1.92 NIA 2.88 N/A 3.67 engaged in non-regulated investments and energy businesses had available
$330 million under a $600 million revolving credit agreement which expires in 1999.
The sources of funds available to AEP are dividends from its subsidiaries, short-term and long-term borrowings
- and, when necessary, proceeds from the issuance of common stock.
AEP issued 1,755,000 shares in 1997, 1,600,000 shares in 1996 and 1,400,000 shares in 1995 of common stock through a
Dividend Reinvestment Program and the Employee Savings Plan raising
$77 million, $65 million and
$49 million, respectively.
In December 1997 AEP and CSW announced that their boards of directors approved a definitive merger agreement for a
tax-free, stock-for-stock business combination transaction which if consummated would bring AEP's total market capitalization to approximately $28 billion.
The combination is expected to be accounted for as a pooling of interests.
Under the agreement, each common share of CSW will be converted to 0.6 shares of AEP.
Based on the number of CSW common shares outstanding at December 31, 1997, AEP will issue approximately 127 million shares to CSW common stockholders (valued at $6.6 billion based on the closing price on the last trading day prior to the announcement ofthe merger).
Under the merger agreement, there willbe no changes with respect to the public debt issues or the outstanding preferred stock of AEP, CSW or their subsidiaries.
The merger is conditioned, among other things, upon the approval of each company's shareholders and certain state and federal regulatory agencies.
The companies anticipate that the required regulatory approvals can be obtained in 12 to 18 months.
AEP is requesting regulatory and shareholder approval to increase the number of authorized shares from 300,000,000 to 600,000,000 in connection with the merger.
The Company as a
major power producer and a trader of electricity and gas has certain financial market risks inherent in its routine business activities. The trading of electricity and gas and related future contracts exposes the Company to commodity price fluctuations.
Market risk represents the risk of loss that may impact
the Company's consolidated financial position, results of operations or cash flows due to adverse changes in market prices and rates.
As trading activity increases and the market for power evolves this risk will become much greater.
Various policies and procedures have been established to manage market risks exposures including the limited usage of energy related derivatives.
In its regular business activities, certain trading positions of the Company for electric and gas creates exposure to price volatility for those products.
These commodities are subject to unpredictable price fluctuations due to changing economic and weather conditions.
During 1997 the Company initiated a
power and gas marketing operation that manages the Company's exposure to future price movements using forwards, futures and options. At December 31,
- 1997, the exposure for financial derivatives in these marketing activities were not material to the Company's consolidated results of operations, financial position or cash fiows.
Investment in two foreign currency denominated joint ventures also exposes the Company to currency translation rate risk. At December 31,
- 1997, the Company's exposure to changes in foreign currency exchange rates related to projects in the UK and China is not material to its consolidated financial position, results of operations or cash flows.
The Company does not presently utilize derivatives to manage its exposures to foreign currency exchange rate movements.
The Company is exposed to changes in interest rates primarily due to short-and long-term borrowings to fund its business operations.
The debt portfolio has both fixed and variable interest rates, terms from one day to thirty years and an average duration of eight years at December 31, 1997.
The Company measures interest rate market risk exposure utilizing a Value at Risk (VaR) model.
The model is based on the Monte Carlo method of simulated price movements with a 95% confidence level and a one year holding period.
The vofatilities and correlations were based on three years of monthly prices.
The risk of potential loss in fair value attributable to the Company's exposure to interest rates, primarily related to long-term debt with fixed interest rates, was
$501 million at December 31, 1997. A near term change in interest rates would not materially affect the consolidated financial position or results of operations of the Company.
The Company is not currently utilizing derivatives to manage its exposure to interest rate fluctuations.
The Company has investments in debt and equity securities which are held in trust funds to decommission its nuclear plant.
Approximately 85% of the trust fund value is invested in tax exempt and taxable bonds, short-term debt instruments or cash.
The trust investments and their fair value are discussed in Note 9
of the Notes to Consolidated Financial Statements.
Instruments in the trust funds have not been included in the market risk calculation for interest rates as these instruments are marked-to-market and changes in market value are reflected in a
corresponding decommissioning liability. Any differences between trust fund and ultimate liabilityare recoverable from ratepayers.
Inflation affects AEP's cost of replacing utility plant and the cost of operating and maintaining its plant.
The rate-making process limits our recovery to the historical cost of assets resulting in economic losses when the effects of inflation are not recovered from customers on a timely basis.
However, economic gains that result from the repayment of long-term debt with inflated dollars partly offset such losses.
14
In connection with the audit of AEP's consolidated federal income tax returns the United States Internal Revenue Service (IRS) agents sought a ruling from the IRS National ONce that certain interest deductions relating to a corporate owned life insurance (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 employees.
AEP filed a brief with the IRS National Office refuting the agents'osition.
No adjustments have been proposed by the IRS. However, should a fulldisallowance of COLI interest deductions be proposed it would, if sustained, 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.
o e
e-e 0
o
'ce Many existing computer hardware and software programs willnot properly recognize calendar dates beginning in the year 2000.
Unless corrected, this "Year 2000" problem may cause computer malfunctions, such as system shutdowns or incorrect calculations and system output.
The Company is addressing the problem internally by modifying or replacing its computer hardware and software programs to mitigate its risk, minimize technical failures, and repair such failures if they occur.
The problem is also being addressed externally with entities that interact electronically with the
- Company, including but not limited to, suppliers, service providers, government agencies, customers, creditors and financial service organizations.
- However, due to the complexity of the 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 applications, the Company may be adversely impacted in the year 2000.
Although significant, the cost of correcting the "Year 2000" problem is not expected to have a material impact on results of operations, cash flows or financial condition.
In June 1997 the FASB issued SFAS No. 130 "Reporting Comprehensive income" and SFAS No..
131 "Disclosures About Segments of an Enterprise and Related Information." SFAS No. 130 establishes the standards for reporting and displaying components of "comprehensive income,"
which is the total of net income and all other changes in equity except those resulting from investments by shareholders and dispositions to shareholders.
SFAS No. 131 initiates standards for reporting information about operating segments in annual and interim financial statements as well as related disclosures about products and
- services, geographic areas and major customers.
AEP's adoption of these new reporting standards in 1998 is not expected to have a material adverse effect on the results of operations, cash flows and/or financial condition.
AEP is involved in a number of legal proceedings and claims.
While we are unable to predict the outcome of such litigation, it is not expected that the ultimate resolution of these matters will have a
material adverse effect on the results of operations, cash flows and/or flinancial condition.
15
AMERICANELECTRIC POWER COMPANY, INC. AND SUBSIDIARYCOMPANIES CONSOLIDATED STATEMENTS OF INCOME gn thousands - except per share amounts)
OPERATING REVENUES OPERATING EXPENSES:
Fuel Purchased Power Other Operation Maintenance Depreciation and Amor tization Taxes Other Than Federal Income Taxes Federal Income Taxes TOTAL OPERATING EXPENSES KJ.6LÃiR 1,627,066 416,266 1,227,368 483,268 591,071 490,595
~4L2BQ 2~1~
1,600,659 86,095 1,210,027 502,841 600,851 498,567
~f222 1,537,135 88,396 1,184,158 541>825 593,019 489,223
~22 Kl
~512fi2
~4KZ92 OPERATING INCOME NONOPERATING INCOME (net)
INCOME BEFORE INTEREST CHARGES AND PREFERRED 'DIVIDENDS INTEREST CHARGES 984,454 1,044,026 405,815 1,007,972 1,010,184 381,328 964,547 984,751 400,077 PREFERRED STOCK DIVIDEND REQUIREMENTS OF SUBSIDIARIES INCOME BEFORE EXTRAORDINARY ITEM EXTRAORDINARY LOSS UK WINDFALL TAX 620,380 587,430 529,903 NET INCOME AVERAGE NUMBER OF SHARES OUTSTANDING Xk
~MM4 89 39
]~7:~
~85 ~47 EARNINGS PER SHARE:
Before Extraordinary Item Extraordinary Loss Net Income CASH DIVIDENDS PAID PER SHARE
$3.28 QL59)
~7
$3.14
$ 2.85 CONSOI IDATEDSTATEMENTS OF RETAINED EARNINGS (in thousands)
RETAINED EARNINGS JANUARY 1 NET INCOME DEDUCTIONS:
Cash Dividends Declared Other RETAINED EARNINGS DECEMBER 31 See Notes to Consolidated Financial Statements.
$ 1,547,746 510,961 453,453
~7
$ 1,409,645 587,430 449,353
~4>
~4~4
$ 1,325,581 529,903 445,831
~4~<j 16
AMERICANELECTRIC POLVER COMPANY, INC. AND SUBSIDIARYCOMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands) e mbr OPERATING ACTIVITIES:
Net Income Adjustments for Noncash Items:
Depreciation and Amortization Deferred Federal Income Taxes Deferred Investment Tax Credits Amortization of Operating Expenses and Carrying Charges (net)
Extraordinary Item -
UK Windfall Tax Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net)
Fuel, Haterials and Supplies Accrued Utility Revenues Accounts Payable Taxes Accrued Other (net)
Net Cash Flows From Operating Activities INVESTING ACTIVITIES:
Construction Expenditures Investment in Yorkshire Proceeds from Sale of Property and Other Net Cash Flows Used For Investing Activities FINANCING ACTIVITIES:
Issuance of Common Stock Issuance of Long-term Debt Retirement of Cumulative Preferred Stock Retirement of Long-term Debt Change in Short-term Debt (net)
Dividends Paid on Common Stock Net Cash Flows Used For Financing Activities 510.961 587,430 529,903 608,217 (6,549)
(25,241) 12,001 109,419 590,657 (21,478)
(25,808) 55,458 578,003 11,916 (25,819) 53,479 (136,186)
(1,427)
(14,225) 147,029 (33,402)
~sL2ZR (39,049) 35,831 32,953 (13,915)
(6,019)
~4
~2ZJUW.
(71,804) 457 (40,433)
(31,044) 37,515
~4 (760,394)
(363,436)
~4 (577,691)
~Q (605,974) t)jjQ 76,745 880,522 (433,329)
(348,157) 235,380
~4'~)
65,461 407,291 (70,761)
(601,278)
(45,430)
~~4:52) 48,707 523,476 (158,839)
(469,767) 48,140
~i~+)
~~)
~QLKQ) ~~4)
~1Z1ddtR) ~5)
~~40.)
Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents January 1
Cash and Cash Equivalents December 31 See Notes to Consolidated Financial Statements.
33, 942l~
(22,416) 2LLi5.
17,089K 17
AMERICANELECTRIC POWER COMPANY, INC. ANDSUBSIDIARYCOMPANIES CONSOLIDATED BALANCESHEETS gn Thousands - Except Share Data)
ELECTRIC UTILITY PLANT:
Production Transmission Distribution General (including mining assets and nuclear fuel)
Construction Work in Progress Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT
$ 9,493,158 3,501,580 4,654,234 1,604,671
~34 8
19,596,485
~252JiK
$ 9,341,849 3,380,258 4,402,449 1,491,781
~5~3 18,970,169
~~Z2R
~~4L2D OTHER PROPERTY AND INVESTHENTS
~~64 CURRENT ASSETS:
Cash and Cash Equivalents Accounts Receivable:
Customers (less allowance for uncollectible accounts of
$ 6,760 in 1997 and
$3,692 in 1996)
Hiscellaneous Fuel
- at average cost Haterials and Supplies
- at average cost Accrued Utility Revenues Prepayments and Other TOTAL CURRENT ASSETS 91,481 552,443 115,075 224,967 263,613 189,191
~kL3K 57,539 415,413 115,919 235,257 251,896 174,966
~htJ51
~~54 51 REGULATORY ASSETS DEFERRED CHARGES TOTAL See Notes to Consolidated Financial Statements.
18
AMERICANELECTRIC POWER COMPANY, INC. ANDSUBSIDIARYCOMPANIES CONSOLlDATED BALANCESHEETS 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)
Paid-in Capital Retained Earnings Total Common Shareholders'quity Cumulative Preferred Stocks of Subsidiaries:*
Not Subject to Mandatory Redemption Subject to Handatory Redemption Long-term Debt*
TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES:
Preferred Stock and Long-term Debt Due Within One Year*
Short-term Debt Accounts Payable Taxes Accrued Interest Accrued Obligations Under Capital Leases Other TOTAL CURRENT LIABILITIES
$ 1,293,435 1,778,782
~JiEiJUZ 4,677,234 46,724 127,605
~22K
~%6 'QZ 294,454 555,075 353,256 380,771 76,361 101,089
$ 1,282,027 1,715,554
~dLZK 4,545,327 90,323 509,900
~49~
86,942 319,695 206,227 414,173 75,124 89,553
~DH 'Q2 DEFERRED INCOHE TAXES DEFERRED INVESTHENT TAX CREDITS DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 DEFERRED CREDITS COMHITMENTS AND CONTINGENCIES (Note 4
)
TOTAL
- See Accompanying Schedules.
~t K2?1
~4~4
~35
~!jjJ93
~66 5 346
~15 ~8~88 19
AMERICANELECTRIC POWER COMPANY, INC. ANDSUBSIDIARYCOMPANIES NOTES TO CONSOLIDATED FINANCIALSTATEMENTS
- 1. Significant Accounting Policies:
Organization - American Electric Power (AEP or the Company) is one of the U.S.'s largest investor-owned public utility holding companies engaged in the generation,
- purchase, transmission and distribution of electric power to nearly 3 million retail customers in its seven state service territory which covers portions of Ohio, Michigan,
- Indiana, Kentucky, West Virginia, Virginia and Tennessee.
Electric power is also supplied at wholesale to neighboring utility systems and power marketers.
AEP has holdings in the United States, the United Kingdom (UK) and China.
The organization ofthe AEP System consists of American Electric Power Company, Inc.
(AEP Co., lnc.), the parent holding company; seven electric utilityoperating companies in the U.S. (domestic utility subsidiaries);
a domestic generating subsidiary, AEP Generating Company (AEPGEN); a service company, American Electric Power Service Corporation (AEPSC); AEP Resources, Inc.
{AEPR) which pursues energy-related domestic and international investment opportunities and projects; AEP Energy Services (AEPES) which markets and trades energy commodities; three active coal-mining companies and a group of subsidiaries that provide power engineering, consulting and management services around the world to complement utilityactivities.
The following domestic utility subsidiaries pool their generating and transmission facilities and operate them as an integrated system:
Appalachian Power Company
{APCo),
Columbus Southern Power Company (CSPCo), indiana Michigan Power Company (IBM), Kentucky Power Company and Ohio Power Company (OPCo).
The remaining two domestic utility subsidiaries, Kingsport Power Company and Wheeling Power Company are distribution companies that purchase power from APCo and OPCo, respectively. AEPSC provides management and professional services to the AEP System.
The active coal-mining companies are wholly-owned by OPCo and sell most of their production to OPCo.
AEPGEN has a 50% interest in the Rockport Plant which is comprised of two of the AEP System's six 1,300 mw generating units.
AEPR has investments and projects that include: a 50%
interest in Yorkshire Electricity Group pic (Yorkshire), an electric distribution company in the UK (see Note 7); a 70% interest in a project to build two 125 mw coal-fired generating units in China. AEPES currently markets and trades natural gas.
The non-regulated subsidiaries that complement utility activities are, engaged in providing non-regulated energy and communication services and are seeking and considering new business opportunities domestically and internationally that willpermit AEP to utilize its expertise and core competencies.
The AEP System's operations are divided into major business units which are managed centrally by AEPSC.
Although the seven domestic utilitysubsidiaries and AEPSC are separate legal entities they operate as American Electric Power. There has been no change to the legal names of these companies.
Rate Regulation - The AEP System is subject to regulation by the Security and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (1935 Act).
The rates charged by the domestic utility subsidiaries are approved by the Federal Energy Regulatory Commission (FERC) or the state utility commissions as applicable.
The FERC regulates wholesale rates and the
, state commissions regulate retail rates.
20
Hes Co, ent
.EP ies tof s a I IS SIX as ilc ny ia ed tly un-ity n-3d Id In e
IS io e
Principles of Consolidation The consolidated financial statements include AEP Co.,
Inc. and its wholly-owned and majority-owned subsidiaries consolidated with their wholly-owned subsidiaries.
Significant intercompany items are eliminated in consolidation.
Yorkshire is accounted for using the equity method.
Basis ofAccounting - As the owner of cost-based rate-regulated electric public utility companies, AEP Co.,
Inc.'s consolidated financial statements reflect the actions of regulators that result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated.
In accordance with Statement of Financial Accounting Standards {SFAS) No.
71, "Accounting for the Effects of Certain Types of Regulation,"
regulatory assets
{deferred expenses) and regulatory liabilities (deferred income) are recorded to reflect the economic effects of regulation and to match expenses with regulated revenues.
Use ofEstimates - The preparation of these financial statements in conformity with generally accepted accounting principles requires in certain instances the use of estimates.
Actual results could differ from those estimates.
UtilityPlant - Electric utilityplant is stated at original cost and is generally subject to first mortgage liens.
Additions, major replacements and betterments are added to the plant accounts.
Retirements from the plant accounts and associated removal
- costs, net of salvage, are deducted from accumulated depreciation.
The costs of labor, materials and overheads incurred to operate and maintain utility plant are included in operating expenses.
Allowance for Funds Used During Construction (AFUDC) -
AFUDC is a
noncash nonoperating income item that is recovered over the service life of utilityplant through depreciation and represents the Depreciation, Depletion and Amortization-Depreciation is provided on a straight-line basis over the estimated useful lives of property other than coal-mining property and is calculated largely through the use of composite rates by functional class as follows:
Functional Class Annual Composite Production:
Steam-Iiuclear Steam-Fossil-Fired Hydroelectric-Conventional and Pumped Storage Transmission Oistri buti on General 3.4X 3.2X to 4.4X 2.7X to 3.2X 1.7X to 2.7X 3.3X to 4.2%
2.5X to 3.8$
The utility subsidiaries presently recover amounts to be used for demolition and removal of non-nuclear plant through depreciation charges
.included in rates.
Depreciation, depletion and amortization of coal-mining assets is provided over each asset's estimated useful life, ranging up to 30 years, and is calculated using the straight-line method for mining structures and equipment.
The units-of-production method is used to amortize coal rights and mine development costs based on estimatec recoverable tonnages at a current average rate of $1.91 per ton.
These costs ar~
included in the cost of coal charged to fue expense.
Cash and Cash Equivalents - Cash and cast equivalents include temporary casl investments with original maturities of threi months or less.
Foreign Currency Translatl'on - The financi~
statements of subsidiaries outside the Unite States are measured using the local currenc as the functional currency.
Assets an estimated cost of borrowed and equity funds used to finance construction projects.
The amounts ofAFUDC for 1997, 1996 and 1995 were not significant.
liabilities are translated to U.S. dollars at year-end rates of exchange and revenues and expenses are translated at monthly average exchange rates throughout the year.
Translation adjustments are accumulated as a
separate component of shareholders'quity.
The accumulated total at December 31, 1997 is not material.
Currency transaction gains and losses are recorded in income.
Sale of Receivables - Vnder an agreement that was terminated in January
- 1997, CSPCo sold
$50 million of undivided interests in designated pools of accounts receivable and accrued utilityrevenues with limited recourse.
As collections reduced previously sold pools, interests in new pools were sold.
At December 31, 1996,
$50 million remained to be collected and remitted to the buyer.
Operafing Revenues and Fuel Costs-Revenues include the accrual of electricity consumed but unbilted at month-end as well as billed revenues.
Fuel costs are matched with revenues in accordance with rate commission orders.
Generally in the retail jurisdictions, changes in fuel costs are deferred or revenues accrued until approved by the regulatory commission for billing or refund to customers in later months.
Wholesale jurisdictional fuel cost changes are expensed and billed as incurred.
Levelizafion of Nuclear Refueling Outage Gosfs Incremental operation and maintenance costs associated with refueling outages at IRM's Cook Plant are deferred and amortized over the period (generally eighteen months) beginning with the commencement ofan outage and ending with the beginning of the next outage.
Income Taxes - The Company follows the liability method of accounting for income taxes as prescribed by SFAS No.
- 109, "Accounting for income Taxes."
Under the liability method, deferred income taxes are provided for all temporary differences between the book cost and tax basis of assets and liabilities which will result in a future tax consequence.
Where the flow-through method of accounting for temporary differences is reflected in rates, deferred income taxes are recorded with related regulatory assets and liabilities in accordance with SFAS No. 71.
Invesfmenf 7ax Credits - Investment tax credits have been accounted for under the fiow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis.
Deferred investment tax credits are being amortized over the life of the related plant investment.
Debf and Prefened Stock-Gains and losses on reacquisition of debt are deferred and amortized over the remaining term of the reacquired debt in accordance with rate-making treatment.
Ifthe debt is refinanced, the reacquisition costs are deferred and amortized over the term of the replacement debt commensurate with their recovery in rates.
Discount or premium and expenses of debt issuances are amortized over the term of the related debt, with the amortization included in interest charges.
Redemption premiums paid to reacquire preferred stock are included in paid-in capital and amortized to retained earnings commensurate with their recovery in rates.
The excess of par value over costs of preferred stock reacquired is credited to paid-in capital and amortized to retained earnings.
Ofher Properfy and Invesfmenfs - Excluding decommissioning and spent nuclear'fuel disposal trust funds and the investment in Yorkshire, other property and investments are stated at cost.
Securities held in trust funds for decommissioning nuclear facilities
and for the disposal of spent nuclear fuel are recorded at market value in accordance with SFAS No.
- 115, "Accounting for Certain Investments in Debt and Equity Securities."
Securities in the trust funds have been classified as available-for-sale due to their long-term purpose.
Unrealized gains and losses from securities in these trust funds are not reported in equity-but result in adjustments to the liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the spent nuclear fuel disposal trust funds.
EPS - The adoption of SFAS No.
128 "Earnings per Share" had no impact on the determination of Earnings per Common Share.
- 2. Rate Matters:
OPCo's Recovery ofFuel Costs - Under the terms of a 1992 stipulation agreement the cost of coal burned at the Gavin Plant is subject to a 15-year predetermined price of
$1.575 per million British Thermal Unit (Btu) with quarterly escalation adjustments through November 2009.
A 1995 Settlement Agreement set the fuel component of the EFC factor at 1A65 cents per Kilowatthour (Kwh) for the period June 1, 1995 through November 30, 1998.
The stipulation and settlement agreements provide OPCo with the opportunity to recover over the term of the stipulation agreement the Ohio jurisdictional share of OPCo's investment in and the liabilities and future shut-down costs of its affiliated mines as well as any fuel costs incurred above the predetermined rate to the extent the actual cost of coal burned at the Gavin Plant is below the predetermined prices.
After full recovery of these costs or November 2009, whichever comes first, the price that OPCo can recover for coal from its affiliated Meigs mine which supplies the Gavin Plant willbe limited to the lower of cost or the then~rrent market price. Pursuant to these agreements OPCo has deferred for future recovery $61 million at December 31, 1997.
Based on the estimated future cost of coal burned at Gavin Plant, management believes that the Ohio jurisdictional portion of the investment in and liabilities and closing costs of the affiliated mining operations including deferred amounts willbe recovered under the terms ofthe predetermined price agreement.
Management intends to seek from non-Ohio jurisdictional ratepayers recovery of the non-Ohio jurisdictional portion of the investment in and the liabilities and closing costs of the affiliated IVleigs, Muskingum and Windsor mines. The non-Ohio jurisdictional portion of shutdown costs for these mines which includes the investment in the mines, leased asset buy-outs, reclamation costs and employee benefits is estimated to be approximately
$102 million after tax at December 31, 1997.
The affiliated Muskingum and Windsor mines may have to close by January 2000 in order to comply with the Phase II requirements of the Clean Air Act Amendments of 1990 (CAAA). The Muskingum and/or Windsor mines could close prior to January 2000 depending on the economics of continued operation under the terms of the above Settlement Agreement.
Unless future shutdown costs and/or the cost of affiliated coal production ofthe Meigs, Muskingum and Windsor mines can be recovered, results of operations and cash flows would be adversely affected.
- 3. Effects of Regulation and Phase-In Plans:
In accordance with SFAS No.
71 the consolidated financial statements include assets (deferred expenses) and liabilities (deferred income) recorded in accordance with regulatory actions to match expenses and revenues from cost-based rates.
Regulatory assets are expected to be 23
recovered in future periods through the rate-making process and regulatory liabilities are expected to reduce future cost recoveries.
The Company has reviewed all the evidence currently available and concluded that it continues to meet the requirements to apply SFAS No. 71.
In the event a portion of the Company's business no longer met these requirements, net regulatory assets would have to be written offfor that portion of the business and assets attributable to that portion of the business would have to be tested for possible impairment and ifrequired an impairment loss recorded unless the net regulatory assets and impairment losses are recoverable as a stranded investment.
Recognized regulatory assets and liabilities are comprised of the following at:
122Z 12K fin Thousands)
Regulatory Assets:
Anounts Due Frora Custouers For Future Incoare Taxes
$ 1,372.926 Rate Phase-fn Plan Deferrals Unarrortfzed Loss on Reacqufred Debt Other Total Regulatory Assets
~~4 96,793
!21
$ 1.459,086 27,249 107,305
~2'44 Regul a tory Lfa bi 1 ftfes r Deferred Investnent Tax Credits Other Regulatory Liabilities" Total Regulatory Lfabflftfes
$376 '50
$401.491 Included fn Deferred Credits on Consolidated Balance Sheets The rate phase-in plan deferrals are applicable to the Zimmer Plant and Rockport Plant Unit 1. The Zimmer Plant is a 1,300 mw coal-fired plant which commenced commercial operation in 1991.
CSPCo owns 25.4% of the plant with the remainder owned by two unaffiliated companies.
As a result of an Ohio Supreme Court decision, in January 1994 the Public UtilityCommission of Ohio (PUCO) approved a
temporary 3.39%
surcharge effective February 1, 1994.
In June 1997 the Company completed recovery of its Zimmer Plant phase-in plan deferrals and discontinued the 3.39% temporary rate surcharge.
In 1997, 1996 and 1995 $15.4 million, $31.5 million and
$28.5
- million, respectively, of net phase-in deferrals were collected through the surcharge.
The deferral balance which was completely recovered and amortized in 1997 was $ 1 5 4 million at December 31, 1996.
The Rockport Plant consists of two 1,300 mw coal-fired units.
I&lVIand AEPGEN each own 50% of one unit (Rockport 1) and lease a
50%
interest in the other unit (Rockport 2) from unaffiliated lessors under an operating lease.
The gain on the sale and leaseback of Rockport 2 was deferred and is being amortized, with related taxes, over the initial lease term which expires in 2022.
A rate phase-in plan in the Indiana and the FERC jurisdictions provide for the recovery and straight-line amortization of deferred Rockport Plant Unit 1 costs over ten years beginning in 1987.
In 1997 the amortization and recovery of the deferred Rockport Plant Unit 1 Phase-in Plan costs were completed.
During the recovery period net income was unaffected by the recovery of the phase in deferrals.
Amortization was
$11.9 million in 1997 and $16 million in 1996 and 1995.
- 4. Commitments and Contingencies:
Construction and Other Comml'tments - The AEP System has substantial construction commitments to support its utility'operations including the replacement of the Cook Plant Unit 1 steam generators.
Such commitments do not presently include any expenditures for new generating capacity.
Aggregate construction expenditures for 1998-2000 are estimated to be $2.4 billion.
Long-term fuel supply contracts contain clauses for periodic price adjustments, and most jurisdictions have fuel clause mechanisms that provide for recovery of changes in the cost of fuel with the regulators'eview and approval.
The contracts are for various terms, the longest of 24
which extends to the year 2014, and contain various clauses that would release the Company from its obligation under certain force majeure conditions.
The AEP System has contracted to sell approximately 1,000 mw of capacity on a long-term basis to unaffiliated utilities.
Certain contracts totaling 750 mw of capacity are unit power agreements requiring the delivery of energy only ifthe unit capacity is available. The power sales contracts expire from 1999 to 2010.
Nuclear Planf - l&Mowns and operates the two-unit 2,110 mw Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC.)
The operation of a nuclear facility involves special
- risks, potential liabilities, and specific regulatory and safety requirements.
Should a nuclear incident occur at any nuclear power plant facility in the United States, the resultant liabilitycould be substantial.
By agreement l&Mis partially liable together with all other electric utility companies that own nuclear generating units for a nuclear power plant incident.
In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery in rates is not possible, results of operations, cash flows and financial condition could be negatively affected.
Nuclear Planf Shufdown - On September 9 and 10,
- 1997, during a
NRC architect engineer design inspection, questions regarding the operability of certain safety systems caused Company operations personnel to shut down Units 1 and 2 of the Gook Plant.
On September 19, 1997, the NRG issued a Confirmatory Action Letter requiring the Company to address the issues identified in the letter.
The Company is working with the NRC to resolve these issues and other issues related to restart of the units.
Certain issues identified in the letter have been addressed.
At this time management is unable to determine when the units will be returned to service.
If the units are not returned to service in a
reasonable period of time, it could have an adverse impact on results of operations, cash flows and possibly financial condition.
Nuclear fncidenf Liability-Public liability is limited by law to $8.9 billion should an incident occur at any licensed reactor in the United States.
Commercially available insurance provides $200 millionof coverage.
ln the event of a nuclear incident at any nuclear plant in the United States the remainder of the liabilitywould be provided by a deferred premium assessment of $79.3 million on each licensed reactor payable in annual installments of $10 million.
As a result, l&Mcould be assessed
$158.6 million per nuclear incident payable in annual installments of $20 million.
~ The number of incidents for which payments could be required is not limited.
Nuclear insurance pools and other insurance policies provide
$3.6 billion (reduced to $3.0 billion effective January 1, 1998) of property damage, decommissioning and decontamination coverage for the Cook Plant.
Additional insurance provides coverage for extra costs resulting from a prolonged accidental Cook Plant outage.
Some ofthe policies have deferred premium provisions which could be triggered by losses in excess of the insurer's resources.
The losses could result from claims at the Cook Plant or certain other non-affiliated nuclear units.
I&Mcould be assessed up to $35.8 million under these policies.
SNF Disposal - Federal law provides for government responsibility for permanent spent nuclear fuel disposal and assesses nuclear plant owners fees for spent fuel disposal.
A fee of one mill per kilowatthour forfuel consumed after April6, 1983 is being collected from customers and remitted to the U.S. Treasury.
Fees and related interest of
$181 millionfor fuel consumed prior to April 7, 1983 have been recorded as long-term
debt.
I8M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program.
At December 31, 1997, funds collected from customers towards payment of the pre-April 1983 fee and related earnings thereon approximate the liability.
Decommissioning and Low Level Waste Accumulation Disposa/ - Decommissioning costs are accrued over the service life of the Cook Plant. The licenses to operate the two nuclear units expire in 2014 and 2017. After expiration of the licenses the plant is expected to be decommissioned through dismantlement.
The Company's latest estimate for decommissioning and low level radioactive waste accumulation disposal costs range from $700 million to $1,152 million in 1997 nondiscounted dollars.
The wide range is caused by variables in assumptions including the estimated length of time spent nuclear fuel must be stored at the plant subsequent to ceasing operations.
This in turn depends on future developments in the federal government's SNF disposal program.
Continued delays in the federal fuel disposal program can result in increased decommissioning costs.
IBM is recovering estimated decommissioning costs in its three rate-making jurisdictions based on at least the lower end of the range in the most recent decommissioning study at the time of the last rate proceeding.
IBM records decom-missioning costs in other operation expense and records a noncurrent liabilityequal to the decommissioning cost recovered in rates; such amounts were $28 million in 1997, $27 million in 1996 and
$30 million in 1995 including $4 million of special deposits.
Decommissioning costs recovered from customers are deposited in external trusts.
Trust fund earnings increase the fund assets and the recorded liabilityand decrease the amount needed to be recovered from ratepayers.
At December 31, 1997, l8M has recognized a decommissioning liability of
$381 million which is included in other noncurrent liabilities.
Revised AirQuality Standards - On July 18, 1997, the Federal EPA published a revised National Ambient Air Quality Standard (NAAQS) for ozone and a new NAAQS for fine particulate matter (less than 2.5 microns in size).
The new ozone standard is expected to result in redesignation of a number of areas of the country that are currently in compliance with the existing standard to nonattainment status which could ultimately dictate more stringent emission restrictions forAEP System generating units.
New stringent emission restrictions on AEP System generating units to achieve attainment of the fine particulate matter standard could also be imposed.
The AEP System operating companies joined with other utilities to appeal the revised NAAQS and filed petitions for review in August and September 1997 in the U.S. Court ofAppeals for the District of Columbia Circuit.
Management is unable to estimate compliance costs without knowledge of the reductions that may be necessary to meet the new standards.
If such costs are significant, it could have a material adverse effect on results of operations, cash flows and possibly financial condition unless such costs are recovered.
Lifigatjon - The Company is involved in a number of legal proceedings and claims.
While management is unable to predict the ultimate outcome of litigation, it is not expected that the resolution of these matters will have a material adverse effect on the results of operations, cash flows or financial condition.
- 5. Dividend Restrictions:
Mortgage indentures, charter provisions and orders of regulatory authorities place various restrictions on the use of the subsidiaries'6
i retained earnings for the payment of cash dividends on their common stocks.
At December 31, 1997, $27 million of retained earnings were restricted.
To pay dividends out of paid-in capital the subsidiaries need regulatory approval.
equity and non-recourse debt. The Company uses the equity method of accounting for its investment in YPG. The Company's original investA'Ient in the joint venture was $360 million and is included in other property and investments.
d S
t.
e
's h
a e
ot s
ie al ld Js'
- 6. I ines of Credit and Commitment Fees:
Outstanding short-term debt consisted of:
(Do))ars In Thousands)
Balance Outstanding:
Notes Payable Comaercfal Paper Total Year-End Weighted Average Interest Rate:
Notes Payable Comsercfal Paper Tocal f199,285 6.35 6.85 6.65 f 91,293 M~4~k 6.25 7.25 6.95
- 7. Yorkshire Acquisition and UKWindfall Tax In April 1997 the Company and New Century Energies, Inc. through an equally owned joint
- venture, Yorkshire Power Group Limited (YPG), acquired all ofthe outstanding shares ofYorkshire, an electric distribution company in the UK. Total consideration paid by the joint venture was approximately $2.4 billion which was financed by a combination of At December 31, 1997 and 1996, unused short-term bank lines of credit were available in the amounts of $442 million and $409 million, respectively.
In addition several of the subsidiaries engaged in providing non-regulated energy services share a line of credit under a revolving credit agreement.
The amounts of credit available under the revolving credit agreement were $330 million and $100 million at December 31, 1997 and
- 1996, respectively.
The short-term bank lines of credit and the revolving credit agreement require the payment of facility fees of approximately 1/10 of 1% on the daily amount of such commitments.
The following amounts which are not included in AEP's consolidated financial statements represent summarized consolidated financial information of YPG at December 31, 1997 and for the nine-months then ended:
Assets:
- Property, Plant and Equipment Current Assets Other Assets Total Assets (In Nfllfons)
S1.644.6 602.2 Capita)fzatfon and Liabilities:
Coaiaon Shareholders'quity 542.1 Long-ters Debt 704.3 Other Noncurrent Liabilities 488.7 Current Liabilities
~L1 Total Capftalfaation and Liabilities Income Statement Data:
Operating Revenues Operating Income Income Before Extraordfnary Item Net Loss 51,492.9 202.3 67.5 (151.3)
In July 1997 the British government enacted a new law that imposed a one-time windfall tax on a revised privatization value which originally had been computed in 1990 on certain privatized utilities. The windfall tax is actually an adjustment of the original privatization price by the UK government.
The windfall tax liability for Yorkshire Electricity Group pic is estimated to be 134 million pounds sterling ($219 million) and is payable in two equal installments.
The first payment was made in December 1997 and the second installment will be due in December 1998.
The Company's
$109.4 million share of the tax is reported as an extraordinary loss. The equity earnings from the Yorkshire investment, excluding the extraordinary loss, which are included in nonoperating
- income, are
$34 million inclusive of $10 million of nonrecurring tax benefits related to a reduction of the UK corporate income tax rate from 33% to 31%
effective April 1, 1997.
27
- 8. Benefit Plans:
AEP System Pension Plan - The AEP pension plan is a trusteed, noncontributory defined benefit plan covering all employees meeting eligibility requirements, except participants in the United Mine Workers of America (UMWA) pension plans.
Benefits are based on service years and compensation levels.
The funding policy is to make annual contributions to a qualified trust fund equal to the net periodic pension cost up to the maximum amount deductible for federal income taxes, but not less than the minimum required contribution in accordance with the Employee Retirement Income Security Act of 1974.
Service Cost-Benefits Earned Ouring the Year Interest Cost on Pro)ected Benefit Obligat5on Actual Return on P'lan Assets Het Amortization (Deferral)
Het AEP Pens5on Plan Costs 5
36,000 5
40 F 000 5
30,400 128,600 119,500 116,700 (462,700)
(302,400)
(416,800)
AEP pension plan
- assets, actuarially computed benefit obligations and the computation of accrued net pension plan liabilityare:
122Z 12K (In Thousands)
Actuarial Present Value of Benefit Obl5gation:
Vested Obligation Honvested Obligation Effects of Salary Progression Pro)ected Benefit Obligation AEP Pens5on Plan Assets at Fa5r Value (a)
Funded Status
- AEP Pension Plan Assets in Excess of ProIected Benefit Obligation Unrecognized Prior Service Cost Unrecognized Ket Gain on Assets Unrecogn5zed Het Transition Assets (Being Anortized Over 17 Years)
Accrued Het AEP Pension Plan Liability 51,623,200 161,000
~2RdIii 51.377.000 136,500 1,890,000 1,676,200 480,300 119,400 (640,800) 333,300 133.200 (488,200)
~KJM) ~!ERE) k~MR) ~PR)
Net AEP pension plan costs were computed as follows:
12K 122k
( In Thousands) 28 Oiscount Rate Average Rate of Increase in Conpensation Levels Expected Long-Tero Rate of Return on Plan Assets l22Z ~
122k 7.00$ 7.75K 7.2SX 3.2X 3.2X 3.2$
9.0%
9.0X 9.0%
Postretin:ment Benefits Other Than Pensions (OPEB) - The AEP System provides certain benefits other than pensions for retired employees.
Substantially all non-UMWA employees are eligible for postretirement health care and life insurance ifthey retire from active service after reaching age 55 and have at least 10 service years.
Postretirement medical benefits for UMWA employees at affiliated mining operations who have or will retire after January 1, 1976 are the liabilityof the OPCo coal-mining subsidiaries and are included in the OPEB net costs and liability. They are eligible for postretirement medical benefits if they retire from active service after reaching age 55 and have at least 10 service years.
In addition, non-active UMWAemployees will become eligible for postretirement benefits at age 55 ifthey have had 20 years of service.
The funding policy for AEP's OPEB plan is to make contributions to an external Voluntary Employees Beneficiary Association trust fund equal to the incremental OPEB costs (i.e.,
the amount that the total postretirement benefits cost under SFAS
- 106, "Employers'ccounting for Postretirement Benefits Other Than Pensions,"
exceeds the pay-as-you-go amount).
Contributions were $35.2 million in 1997, $45.8 million.in 1996 and $53 million in 1995.
In several jurisdictions the utility subsidiaries deferred the increased OPEB costs resulting from the SFAS 106 required change from pay-as-you-go to accrual accounting which were not being recovered in rates.
No additional deferrals were made (a)
AEP pension plan assets primarily consist of coaeon
- stocks, bonds and cash equivalents and are included in a
separate entity trust fund.
Assumptions used to determine AEP's net pension plan liabilitywere:
in 1997 or 1996. At December 31, 1997 and
~
~
96,
$7.9 million and
$14.5
- million, spectively, of incremental OPEB costs were deferred.
for all employees, both non-UMWA and UMWA, would increase by $10 million and the accumulated benefit obligations would increase by $92 million.
(In Thousands)
Service Cost
$ 14,000 Interest Cost on Pro)ected Benefit Obligation 55,900 Het Amortization of the Transition Obligation 32,000 Return on Plan Assets (44,100)
Het Amortization (Deferral) ~~I Het OPEB Costs
$ 15,300
$ 13.500 53,500 54,900 32.300 (21.100)
'~R 32.000 (25.400)
ARE OPEB assets, actuarially computed benefit obligations and the computation of the accrued net OPEB liabilityare:
Aggregate OPEB costs were computed as follows:
AEP System Savings Plan - An employee savings plan is offered to non-UMWA employees which allows participants to contribute up to 17% of their salaries into various investment alternatives, including AEP common stock. An employer matching contribution, equaling one-half of the employees'ontribution to the plan up to a maximum of 3% of the employees'ase
- salary, is invested in AEP common stock.
The employer's annual contributions totaled
$19.6 million in 1997, $19 millionin 1996 and
$18.8 million in 1995.
122Z 122I
( In Thousands)
Accumulated Postretirement Benef1t Obl1gation:
Active Employees Fully Eligible for Benefits Current Retirees Other Active Employees Total Benefit Obligation Fair Harket Value of Plan Assets (a)
Unfunded Benefit Obligation Unrecogn1zed Net Loss (Gain)
Unrecognized Het Transition Obligat1on Be1ng Amortized Over 20 Years Accrued Net OPEB Liability 73,800 466,900
~!LRE 849,700 (537 F 800) 66,100
$ 57,800 423,000
~iK 726,400 U22 'iK (493,900)
(3,300)
(a) Plan assets consist of cash surrender value of life insurance contracts on certain employees owned by the trust and short-term tax-exempt municipal bonds.
Discount Rate Expected Long-Ters Rate of Return on Plan Assets Initial Hedical Cost Trend Rate Ultimate Hedical Cost Trend Rate Hedical Cost Trend Rate Decreases to Ultimate Rate in Year 7.00K 7.75K 7.255 8.755 8.755 8.75%
7.05 7.55 8.05 4.251 4.75%
4.55 2005 2005 2005 ssuming a one percent increase in the medical cost trend rate, the 1997 OPEB cost Assumptions used to determine OPEB's funded status were:
Other UMWA Benefits
- The Company provides UMWApension, health and welfare benefits for certain employees, retirees, and their survivors who meet eligibility requirements.
The benefits are administered by UMWA trustees and contributions are made to their trust funds.
Contributions based on hours worked are expensed as paid as part of the cost of active mining operations and were not material in 1997, 1996 and 1995.
Based upon the UMWA actuary estimate the Company's share of unfunded pension liabilitywas $6.9 million at June 30, 1997.
In the event the Company should significantly reduce or cease mining operations or contributions to the UMWA trust funds, a withdrawal obligation will be triggered for both the pension and health and welfare plans.
Ifthe mining operations had been closed on December 31, 1997 the estimated withdrawal liabilityfor all UMWA benefit plans would have been $6.7 million.
- 9. Fair Value of Financial instrument:
Nuclear Trust Funds Recorded at Market Va/ue - The trust investments, reported in other property and investments, are recorded at market value in accordance with SFAS No.
29
115 and consist of tax-exempt municipal bonds and other securities.
At December 31, 1997 and 1996 the fair values of the trust investments were $566 million and
$491
- million, respectively.
Accumulated gross unrealized holding gains were
$41 million and
$21.9 million at December 31, 1997 and 1996, respectively and accumulated gross unrealized holding losses weie $1.2 million at both year-ends.
The change in market value in 1997, 1996, and 1995 was a net unrealized holding gain of $19.1 million, $2.6 million and
$24.9 million, respectively.
The trust investments'ost basis by security type were:
122Z 12K
( In Thousands)
Tax-Exempt Bonds 4335.358
$340,290 Equity Securities 74.398 54 '89 Treasury Bonds 44.200 26.958 Corporate Bonds 9,167 7,977 Cash.
Cash Equ5valents and Accrued Interest M2 '52
~4~4 Total 8~i 85~44 Proceeds from sales and maturities of securities of $147.3 million during 1997 resulted in $3.9 million of realized gains and
$1.4 million of realized losses.
Proceeds from sales and maturities of securities of
$115.3 million during 1996 resulted in $2.6 million of realized gains and $2.1 million of realized losses.
During 1995 proceeds from 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.
At December 31, 1997, the year of maturity of trust fund investments other than equity securities, was:
1998 1999
- 2002 2003
- 2007 After 2007 Total
( In Thousands)
$ 87,063 127,575 182,873
~4 5~43%
Other Financial Instruments Recorded at Historical Cost - The carrying amounts of cash and cash equivalents, accounts receivable, short-term debt, and accounts payable approximate fair value because of the short-term maturity of these instruments.
Fair values for preferred stock subject to mandatory redemption were $136 million and
$517 millionand for long-term debt were $5.7 billion and $5.0 billion at December 31, 1997 and
- 1996, respectively.
The carrying amounts on the financial statements for preferred stock subject to mandatory redemption were
$128 million and
$510 million and for long-term debt were $5.4 billionand $4.9 billion at December 31, 1997 and
- 1996, respectively.
Fair values are based on quoted market prices for the same or similar issues and the current dividend or interest rates offered for instruments of the same remaining maturities.
The carrying amount of the spent nuclear fuel disposal trust funds approximates the Company's best estimate of the fair value of the pre-April 1983 SNF disposal liability.
30
- 0. Federal Income Taxes:
~
~
The details of federal income taxes as reported are as follows:
Charged (Credited) to Operating Expenses Cur r en.t Deferred Deferred Investment Tax Credits Total 199K 12K 12K (In Thousands)
(net):
$346,290
$375,528
$265,313 11,124
{17,008) 22,990
~~) ~~) ~~)
Charged (Credited) to Nonoperating Cur rent Deferred Deferred Investment Tax Credits Total Income (net):
{16,038)
(17,673)
~KJQZ)
~4~)
(5,636) 11,325 (4,470)
{11,074)
~~) ~~)
~~) ~~)
Total Federal Income Tax as Reported gSk 46K k3ZZ~
kZGZ.~7 The following is a reconciliation of the difference between the amount offederal income taxes computed by multiplying book income before federal income taxes by the statutory tax rate, and the amount offederal income taxes reported.
Income Before Preferred Stock Dividend Requirements of Subsidiaries Extraordinary Loss (Note 7)
Federal Income Taxes Pre-Tax Book Income Federal Income Tax on Pre-Tax Book Income at Statutory Rate (95$)
Increase (Decrease) in Federal Income Tax Resulting from the Following Items:
Depreciation Corporate Owned Life Insurance Investment Tax Credits (net)
Extraordinary Loss UK Windfall Tax Other Total Federal Income Taxes as Reported Effective Federal Income Tax Rate 122Z le le (In Thousands)
$ 289,539
$333,012
$296,593 53,239 (18,240)
(25,241) 38,297
~~)
50,537 46,453 (12,009)
{25,506)
(25,813)
(26,179)
~~) ~~)
$ 638,211
$628,856
$584,674
{109,419)
'QZ M5.
g&~4 K4Z~
31
The following tables show the elements of the net deferred tax liability and the significant temporary differences:
Deferred Tax Assets Deferred Tax Liabilities Net Deferred Tax Liabilities b r l22Z le (In Thousands) 807,226 784,349 Property Related Temporary Differences Amounts Due From Customers For Future Federal Income Taxes Deferred State Income Taxes All Other (net)
Total Net Deferred Tax Liabilities (410,255)
(201,843)
(428,698)
(229,429) 4
)
$ (2,161,484)
$ (2,162,099)
The Company has settled with the United States Internal Revenue Service (IRS) all issues from the audits ofthe consolidated federal income tax returns for the years prior to 1991.
Returns forthe 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 agents'osition.
Although no adjustments have been proposed, a disallowance of the COLI interest deductions through December 31, 1997 would reduce earnings by approximately $286 million (including interest).
AEP believes it has meritorious defenses and willvigorously 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 ofproperty, 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 willbe 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:
Operating Leases Amortization of Capital Leases Interest on Capital Leases Total Rental Payments l926.
(In Thousands)
$257,042
$262,451 104,732 114,050
~LJi.'K
~33~7
~4~97
$259,877 101,068
~i 487
Properties under capital leases and related obligations on the Consolidated Balance Sheets e as follows:
{In Thousands)
ELECTRIC UTILITY PLANT:
Production Transmission Distribution General:
Nuclear Fuel {net of amortization)
Mining Plant and Other Total Electric Utility Plant Accumulated Amortization Net Electric Utility Plant OTHER PROPERTY Accumulated Amortization Net Other Property Net Property under Capital Leases
$ 47,246 3
14,660 103,939 682,691 M5 'M 57,763
$ 44,390 6
14,699 59,681 585,573 33,439 Capital Lease Obligations:*
Noncurrent Liability
$324,674 Liability Due Within One Year
~(~
Total Capital Lease Obligations QZ~
- 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
$437,303 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 1999 2000 2001 2002 Later Years Total Future Minimum Lease Rentals Less Estimated Interest Element Estimated Present Value of Future Minimum Lease Rentals Unamortized Nuclear Fuel Total
$ 104,623 92,740 79,507 64,438 59,400 565,079 434,453
$53.LZQ.
243,042 229,764 228,044 225,482 220,111
~ZLZZ.
(a)
~47 ~~c)
(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)
Income Taxes Noncash Acquisitions under Capital Leases
$ 390,491
$373,570
$395,169
$ 398,833
$404,297
$ 273,671
$ 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 Common Stock-Preferred Stocks Paid-in Hot Subject To Mandatory DmhmM()
Subject to Handatory B~m2$19II(b)
January 1,
1995 Issuances Retirements and Other December 31, 1995 Issuances Retirements and Other December 31, 1996 Issuances Retirements and Other December 31, 1997 194,234,992 1.400,000 195,634.992 1,600,000 197,234,992 1,754,989 8 '36,251 LL52i 'U2) 6,709,751 6,002,233
$ 1,262,527 9,100 1,271.627 10,400 1,282>027 11.408
$ 1,640,661 39,607 233.240 1,658,524 55 '61 148,240 1,715,554 65,337 90,323 KJM)
~~4'~M)
~~44) ~r~Q.
$ 590,385
~~0 522,735
~K) 509,900 (a) Includes 8,999,992 shares of treasury stock.
(b) Iriclud(ng Portion due uithin one year.
- 14. Unaudited Quarterly Financial information:
~a~
~ljBp~
(In Thousands
- Except Operating Revenues Operating Income Net Income Before Extraordinary Item Net Income Earnings per Share Before Extraordinary Item*
Earnings per Share
$ 1,492,069 271,978 172,562 172,562 0.92 0.92
$ 1,382,158 221,255 121,139 121,139 0.64 0.64
$ 1,583,994 275,090 201,746 91,181 1.07 0.48
$ 1,703,147 216,131 124,933 126,079 0.66 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 UKWindfall Tax which retroactively adjusted upward Yorkshire's privatization price discussed in Note 7.
~r~h
~n~
~QJ~~
(In Thousands
- Except Operating Revenues Operating Income Net Income Earnings per Share
$ 1,517,781 292,122 180,012 0.96
$ 1,400,941 220,625 112,666 0.60
$ 1,484,422 259,745 162,324 0.87
$ 1,446,090 235,480 132,428 0.71 35
AMERICANELECTRIC POWER COMPANY, INC. ANDSUBSIDIARYCOMPANIES 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) 6.02K 7/85 (c)(d) 7% (g)
Total Subject to Handatory Redemption (d)
(e)
(f)
(g) 1,950,000 1,950.000 250,000 388,100 637,950 250,000
$ 38,810 63,795
~~605 Call Price per Sh Shares Shares Amount ( In u
Not Subject to Handatory Redemption:
4.085 - 4.56%
Subject to Handatory Redemption (d):
5.90%
- 5.92%
6.025 7/85 75 7/8%
Total Subject to Handatory Redemption (d)
$ 102- $ 110 (e)
(f)
$ 107.80-$ 107.88 932,403 1,950,000 1,950,000 1,250,000 903.233 1,904,000
$ 190,400 1 '45,000 194,500 1,250,000
~i~)
NOTES TO SCHEDULE OF CUHULATIVE PREFERREO STOCKS OF SU8SIOIARIES (a)
(b)
(c)
(d)
(e)
(f)
(g)
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.
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.
Ouring the first quarter of 1997 preferred stock was reacquired in connection with a tender offer.
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.
Hot callable prior to 2003; after that the call price is
$ 100 per share.
Not callable prior to 2000; after that the call price is
$ 100 per share.
Hith sinking fund.
Redemption is restricted prior to 2000.
AMERICANELECTRIC POWER COMPANY, INC. AND SUBSIDIARYCOMPANIES CHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES Heighted Average ni'b i 1'.
12Ki~
FIRST MORTGAGE BONDS 1997-2000 2001-2006 2021-2025 INSTALLMENT PURCHASE COHTRACTS (a) 1998-2002 2007-2025 7.20X 7.10X 7.95X 4.60X 6.45X 6.35X-9.15X 6X-8.95X 7.10X-B.BOX 3.70X-7-1/4X 5.45X-7-7/BX 6-1/4X-9.15X S
466,411 383,671 6X 8 95X 1 ~ 511 ~ 000 I ~511 000 7.10X-9.35X 1,120,419 1.276.750 4.10X-7-1/4X 189,500 209.500 5.45X 7 7/BX 756>745 756s745 NOTES PAYABLE (b) 1997-2008 JUNIOR DEBENTURES 2025 - 2027 OTHER LONG-TERM DEBT (c)
Unamortized Discount (net)
Total Long-term Debt Outstanding (d)
Less Portion Oue Hith(n One Year Long-tera Portion 6.73X
- 8. 17X 7.92X 8.72X BX-8.72X 495,000 250,357 315,000 182.943
~iZ22t) ~OUI) 4 '83,710 5.423,917
~~44 KJ2~46 ~K'
~ 29X 9 60X 5 ~ 29X 9 60'X 671
~ 681 282
~ 681 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 1999 2000 2001 2002 Later Years Total 5
294,454 491,579 321 '86 267,040 484,533
~46~
37
Management's Responsibility The management ofAmerican 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-itsobligation 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 ofAmerican Electric Power Company, inc. and its subsidiaries as of December 31, 1997 and 1996, and the results oftheir operations and their cash flows for each ofthe three years in the period ended December 31, 1997 in conformity with generally accepted unting principles.
LL-P Deloitte 8 Touche LLP Columbus, Ohio February24, 1998 39
Indiana Michigan Power Company 1997 Annual Report
CONTENTS INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES One Surnrnit Square, P.o. Box Bo, Fort Wayne, indiana 48801 Background...
Directors and Officers 2
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 Notes to Consolidated Financial Statements 16 17-29 Independent Auditors'eport Operating Statistics
~
~
~
~
~
~
Dividends and Price Ranges of Cumulative Preferred Stock 31-32 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 INDIANAMICHIGANPOWER 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 ofAmerican Electric Power Company, Inc., a public utilityholding company.
The Company does business as American Electric Power (AEP) along with all of the parent's operating subsidiary companies in order to serve its customers more efficiently as one operating organization aligned by distinct business units. The Company's two wholly-owned subsidiaries, Blackhawk Coal Company and Price River Coal Company, were formerly engaged in coal-mining operations in Utah.
Blackhawk Coal Company currently leases or subleases portions of its coal rights, land and related mining equipment to unaffiliated companies.
In addition, the Company has a river transportation division (RTD) that barges coal on the Ohio and Kanawha Rivers to AEP System generating plants.
The RTD also provides some barging services to unaffiliated companies.
The Company owns and leases 4,435 megawatts (mw) of generating capacity which includes 2,295 mw of coal-fired generation and 2,110 mw of nuclear generation.
The Company owns the two unit Donald C. Cook Nuclear Plant located in Michigan.
The generating plants and transmission facilities of the Company and certain other affiliated AEP System utilitysubsidiaries are operated as an integrated system with their costs and benefits shared through the AEP System Power Pool and AEP Transmission Agreement.
Wholesale energy sales made by the Power Pool are allocated to the Company and the other Pool members.
The other AEP System Pool members are: Appalachian Power Company, Columbus Southern Power Company, Kentucky Power Company and Ohio 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)
Coulter R. Boyle, III Gregory A. Clark Peter J. DeMaria William N. D'Onofrio E. Linn Draper, Jr.
WilliamJ. Lhota Gerald P. Maloney James J. Markowsky David B. Synowiec Dale M. Trenary (b)
Joseph H. Vipperman William E. Walters Earl H. Wittkamper OFFICERS E. Linn Draper Jr.
Chairman of the Board and Chief Executive Officer William J. Lhota President and Chief Operating Officer A. Alan Blind Site Vice President, Donald C. Cook Nuclear Plant Coulter R. Hoyle, III Vice President Peter J. DeMaria Vice President and Controller Eugene E. Fitzpatrick Vice President Armando A. Pena Treasurer Elio Bafile Assistant Controller and Assistant Secretary Leonard V. Assante Assistant Controller Timothy P. Bowman Assistant Controller William L. Scott Assistant Controller John M. Adams, Jr.
Assistant Secretary Gerald P. Maloney Vice President James J. Markowsky Vice President Joseph H. Vipperman Vice President John F. DiLorenzo, Jr.
Secretary Maurice C. Mclntyre Assistant Secretary John B. Shinnock Assistant Secretary Bruce M. Barber Assistant Treasurer Christopher J. Keklak Assistant Treasurer As of January 1, 1998 the current directors and officers of Indiana Michigan Power Company were employees ofAmerican 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 INCOME STATEMENTS DATA:
Operating Revenues
$ 1,391,917 Operating Expenses Operating Income 207,788 Nonoperating Income (Loss)
Income Before Interest Charges 212,203 Interest Charges Net Income 146, 740 Preferred Stock Dividend Requirements Earnings Applicable to Common Stock
~~A 1RRi (in thousands)
$ 1,328,493 220,417
$ 1,283,157
~22 ~
205,723
$ 1,251,309
~92 ~4 221,969 223,146 157,153 211,995 141,092 229,397
~LRK 157,502 11Ji9l 3~5 4Z
~~HE
$ 1,202,643 210,158 209,924 ELZR 129,344 BALANCE SHEETS DATA:
~
~
~
Electric Utility Plant
$4,514,497 Accumulated Depreciation and Amortization Net Electric Utility Plant
~LSD
$4,377,669 12K (in thousands)
$4,319,564
~ILEEi,
$4,269,306
$4,290,957
~~422
&JH5 2K
~5523 Total Assets X~~
K~~g i3 Kk~
~7~4 Common Stock and Paid-in Capital Retained Earnings Total Common Shareholder's Equity g~~g 789,056
~LRH Cumul ati ve Preferred Stock:
Not Subject to Mandatory Redemption 9,435 Subject to Mandatory Redemption (a)
Total Cumulative PreFerred Stock
~LHQ 787,856
~iL92l 21,977 787,686
@~~~(
52,000 790,234 52,000 790,625
~~63 87,000 Long-term Debt (a)
Obligations Under Capital Leases (a)
Total Capitalization and Liabilities
~$'~~
%1JQ~54
~km'
'5494 3~7~4
~483, ~~
~3~4 (a) Including portion due within one year.
INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES MANAGEMENT'SDISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIALCONDITION This report includes foivIard-looking statements within the meaning of Section 21E of the Secunties Exchange Act of 1934. These forward-looking statements reflect numerous assumptions, and involve a number of risks and uncertainties.
Among the factors that could cause actual results to differmaterially are: electric load and customer growth; abnormal weather conditions; available sources and cost of fuel and availability of generating capacity; the speed and degree to which competition enters the power generation, wholesale and retail sectors of the electric utility industry; state and federal regulatory initiatives that increase competition, threaten cost and investment recovery, and impact rate structures; the ability of the Company to successfully reduce its cost structure; the economic climate and growth in the service territory; inflationary trends and interest rates and other risks.
revenues.
Indiana is considering legislative initiatives to move to customer choice, although the timing is uncertain.
The Company supports customer choice and is proactively involved in discussions at both the state and federal levels regarding how best to structure and transition to a competitive marketplace.
As the etectric energy market evolves from cost-of-service ratemaking to market-based
- pricing, many complex issues must be resolved, including the recovery of stranded costs.
While FERC orders No. 888 and 889 provide, under certain conditions, for recovery of stranded cost at the wholesale
- level, the issue of stranded cost recovery is unresolved at the much larger state retail level. The amount of any stranded costs the Company may experience depends on the timing 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 industry transitions to competition and as customer choice is more broadly available is the most significant factor affecting its future.
Competition in the wholesale generation market continues to intensify since the adoption of federal legislation in 1992 which gave wholesale customers the right to choose their energy supplier and the Federal Energy Regulatory Commission (FERC) orders issued in 1996 which force open access transmission.
The introduction of competition and customer choice for retail customers has been slow although activity has been increasing.
Federal legislation has been proposed to mandate competition and customer choice at the retail level, and several states have introduced or are considering similar legislation.
The Michigan Commission has started a program for certain utilities to phase-in to competition with the objective of providing full customer choice by 2002. The Company has begun discussions with the Commission and other interested parties to formulate a plan.
The actions by the Michigan commission were not mandated by legislation and are subject to a number of uncertainties and it is ot possible to determine what impact if any the resolution of these matters will have on the operations of the Company.
The Company's Michigan jurisdiction accounts for 12% of total Under the provisions of Statement of Financial Accounting Standards (SFAS) No. 71 "Accounting for the Effects of Certain Types of Regulation,"
regulatoiy assets (deferred expenses) and regulatory liabilities (deferred revenues) are included in the consolidated balance sheets of cost-based regulated utilities in accordance viith regulatoiy actions to match expenses and revenues with cost-based rates.
In order to maintain net regulatory assets (net expense deferrals) on the balance
- sheet, SFAS No.,71 requires that rates charged to customers be cost-based and the recovery of regulatory assets must be probable.
In the event a portion of the Company's business no longer met the requirements of SFAS No. 71, net regulatory assets would have to be written offfor that portion of the business.
The provisions of SFAS No. 71 and SFAS No.
101 "Accounting for the Discontinuance of Application of Statement No.
71" never anticipated that deregulation would include an extended transition period or that it would provide for recovery after the transition period of stranded costs.
In July 1997 the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) reached a consensus that the application of SFAS No. 71 to a segment of a regulated electric utility which is subject to a legislative plan to transition
to competition in that segment should cease when the legislation is passed, or an enabling rate order is issued containing sufficient detail for the utility to reasonably determine what the plan would entail.
The EITF indicated that the cessation of application of SFAS No. 71 would require that existing regulatory assets and impaired plant be written off unless they are recoverable.
Although FERC orders No. 888 and 889 provide 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 Company's generation business is still cost-based regulated and should remain so for the near future
'ending the passage of enabling state legislation to deregulate the generation business.
We believe that enabling state legislation should provide for the recovery of any generation-related net regulatory assets and other reasonable stranded costs from impaired generation assets.
We are working with regulators, customers and legislators to provide for recovery of these stranded costs during a transition period in which rates are fixed or frozen and electric utilities would take steps to achieve cost savings which would be used to reduce or eliminate their stranded costs.
However, if in the future the Company's generation business were to no longer be cost-based regulated and if it were not possible to demonstrate probability of recovery of resultant stranded costs including regulatory assets, results of operations, cash Rows and financial condition of the Company would be adversely affected.
Efforts continue to reduce the cost of products and services in order to maintain our competitiveness.
Prior to 1997, reviews of our major processes led to decisions to consolidate in the AEP Service Corporation senior management and certain functions and operations.
While staff reductions and cost savings are presently being achieved from the consolidation and restructuring expenses for new marketing, customer services and modem efficient management information systems are increasing to prepare for competition.
In 1997, the Company began installing a new unified customer service system which is designed to support the request for service, illings, accounts receivable, credit and collection functions.
The new unified customer service system replaces a 30-year-old customer system and a nine-year-old transmission and distribution work management system.
Process improvement efforts and expenditures to develop and implement the new customer service system and similar efforts and expenditures to acquire, install and enhance new client server based accounting and budgeting/financial planning software should produce further improvements and efficiencies, enabling the Company to continue to offer its customers excellent service at competitive prices.
Significant efforts have been made to enhance our competitive-ness in nuclear power generation and to improve our nuclear organizational efficiency. We continue to receive the "excellence in performance" award from the Institute of NucIear Power Operations.
Nuclear power plants have a major future financial commitment to safely dispose of spent nuciear fuel and radioactive plant components (i.e. to decommission the plant).
It is difficultto reduce nuclear generation costs since certain major cost components are impacted by federal laws and Nuclear Regulatory Commission (NRC) regulations.
The Nuclear Waste Policy Act of 1982 established federal responsibility for, the permanent off-site disposal of spent nuclear fuel and high-level radioactive waste.
By law we participate in the Department of Energy's (DOE's)
Spent Nuclear Fuel (SNF) disposal program which is described in Note 3
of the Notes to Consolidated Financial Statements.
Since 1983 our customers have, paid $272 million for the disposal of spent nuclear fuel consumed at the Cook Nuclear Plant.
Under the provisions of the Nuclear Waste Policy Act, collections from customers are to provide the DOE with money to build a repository for spent fuel.
To date the federal government has not made sufficient progress towards a
permanent repository or otherwise assuming responsibility for SNF.
As long as there is a delay in the construction of a government approved storage repository for SNF, the cost of both temporaiy and permanent storage will continue to increase.
The cost to decommission the Cook Nuclear Plant is affected by both NRC regulations and the DOE's SNF disposal program.
Studies completed in 1997 estimate the cost to decommission the Cook Nuclear Plant range from $700 million to $1.152 billion in 1997 dollars.
This estimate could escalate due to uncertainty in the DOE's SNF disposal program and the length of time that SNF
may need to be stored at the plant site delaying decommissioning.
Presently we are recovering the estimated cost of decommissioning the Cook Nuclear Plant over its remaining life. However, the Company's future results of operations, cash flows and possibly its financial condition could be adversely affected ifthe cost of spent nuclear fuel disposal and decommissioning continues to increase and cannot be recovered.
On September 9 and 10, 1997, during a NRC architect engineer design inspection, questions regarding the operability of certain safety systems caused Company operations personnel to shut down Units 1 and 2 of the Cook Nuclear Plant.
On September 19,
- 1997, the NRC issued a
Confirmatory Action Letter requiring the Company to address the issues identified in the letter. The Company is working with the NRC to resolve these issues and other issues related to restart of the units.
Certain issues identified in the letter have been addressed.
At this time management is unable to determine when the units will be returned to service.
Ifthe units are not returned to service in a reasonable period of time, it could have an adverse impact on results of operations, cash flows and possibly financial condition.
We take great pride in our efforts to economically produce and deliver electricity while minimizing the impact on the environment.
The Company has spent hundreds of millions of dollars to equip our facilities with the latest economical dean air and water technologies and to research possible new technologies.
We intend to continue to take a leadership role to foster economically prudent efforts to protect and preserve the environment.
By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and spent nuclear fuel.
Coal combustion by-products are typically disposed of or treated in captive disposal facilities or are beneficially utilized.
In addition, our generating plants and transmission and distribution facilities have used
- asbestos, polychlorinated biphenyls (PCBs) and other hazardous and nonhazardous materials.
The Company is currently incurring costs to safely dispose of such substances.
Additional costs could be incurred to comply with new laws and regulations ifenacted.
INDIANAMICHIGANPOWER COMPANY AND SVBSIDIARIES The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or Superfund) addresses clean-up of hazardous substances at disposal sites and authorized the United States Environmental Protection Agency (Federal EPA) to administer the clean-up programs.
As of year-end 1997, the Company is currently involved in litigation with respect to two sites overseen by the Federal EPA, and has been named by the Federal EPA as a "Potentially Responsible Party" (PRP) for three other sites.
There are four additional sites for which the Company has received information requests which could lead to PRP designation as well as information requests for one state administered site.
The Company's liabilityhas been resolved for a number of sites with no significant effect on results of operations and present estimates do not anticipate material cleanup costs for identified sites for which we have been declared a PRP.
However, if for reasons not currently identified significant costs are incurred for cleanup, future results of operations, cash flows and possibly financial condition would be adversely affected unless the costs can be recovered.
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 expected to result in redesignation of a number of areas of the country currently in compliance with the existing standard to nonattainment which could ultimately dictate more stringent emission restrictions for AEP generating units including those of the Company's.
Under the new rules the states must first determine the attainment status of their areas.
The states then have three years to submit a compliance plan and up to ten years after designation to come into compliance with the new standards.
The compliance deadline could be as late as 2010 for the ozone standard and 2012-2015 for the fine particulate standard.
Although we are reviewing the impact of the new rules, we are unable to estimate compliance costs without knowledge of the reductions that the states will find necessary to meet the new standards.
Ifsuch reductions are significant and the Company and its affiliates must bear a
significant portion of the cost of compliance in a region or county that is in violation of the revised standards, it would have a material adverse effect on results of operations, cash flows and possibly financial condition unless such costs are recovered from customers.
Atthe global dimate conference in Kyoto, Japan in December 1997 more than 160 countries negotiated a
treaty limiting emissions of greenhouse
- gases, chiefly carbon dioxide, which may eventually contribute to global warming.
Although there is no dear scientific evidence that carbon dioxide contributes to global warming and damages the environment, the
- treaty, which requires Congressional approval, calls for a seven percent reduction below emission levels of greenhouse gases in 1990.
We intend to work with the Congress to insure that science and reason are introduced to the debate.
Ifapproved 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 material adverse impact on results of operations, cash flows and possibly financial condition if not recovered from customers.
a'o Although operating revenues increased
$63 million or 5% in 1997 due to increased accruals for retail power costs that will be collected in the future under power supply cost recovery mechanisms and increased wholesale transactions from a
new power marketing business, net income decreased
$ 10 million or 7%
as a result of increases in purchased power and other operation expenses.
In July 1997 the Company started a
new power marketing business of buying and selling power outside the AEP System which accounted for the increases in purchased power and wholesale revenues.
The increase in other operation expense reflects the effect of the recognition of gains on sales of emission allowance in 1996 and higher administrative and general costs and uncollectible accounts expenses in 1997.
In 1996 net income increased
$16 million or 11% mainly due to increased wholesale
- sales, a
reduction in maintenance expense and reduced financing costs.
Also contributing to the earnings increase in 1996 were severance pay charges recorded in 1995 in connection with AEP's restructuring of management and operations and gains recorded in 1996 from emission allowance transactions.
0 e a e e ues crease Operating revenues increased 4.8% in 1997 following a 3.5% increase in 1996. The following analyzes the changes in operating revenues:
Increase (Decrease)
FrmP v
u ll n ei Retail:
Price Variance S 26.6 5(25.9)
Volume Variance
~4
~4 37 ~
08
'Nholesa)e:
Price Variance 43.8 (55.6)
Volune Variance
~)
6.0
~4 9.5 Other Operatiny Revenues Total
~4 4.8
~4 3.5 The increase in operating revenues in 1997 can be attributed to increased retail and wholesale revenues.
The increase in retail revenues results from the accrual of revenues to be recovered from ratepayers for the increased cost of replacement power and increased fossil fuel usage during an outage of both units at the Company's nuclear plant.
Under the retail jurisdictional fuel clauses, revenues are accrued for the unrecovered cost of fuel in both retail jurisdictions and for replacement power costs in the Michigan jurisdiction until approved for billing. The increase in wholesale revenues in 1997 was mainly due to the introduction of new power marketing transactions in July 1997.
The new power marketing
. transactions involve the purchase and sale of electricity outside the AEP transmission system.
The increase in power marketing sales was offset by a decrease in sales to the Power Pool due mainly to the outage of Cook Plant. The reduction in sales to the Power Pool did not lead to a corresponding decrease in
'revenues since capacity credits continue to be received.
Capacity credits are designed to allocate the cost of the AEP System's generating capacity among the members of the Power Pool based on the Power Pool members relative peak demands and generating reserves.
The Company is compensated for the out-of-pocket costs of energy delivered to the Power Pool.
INDIANANICHIGANPOWER CohfPANY AhfD St/BSIDIARIES Operating revenues increased in 1996 primarily as a
result of increased wholesale sales attributable to increased internal generation being supplied to the Power Pool and unaffiliated utilities.
The Company's share of Power Pool allocated sales increased 40% due to increased transactions with other utilities and power marketers.
During 1996 the Company provided coal conversion services to power marketers and unaffiliated utilities resulting in 1.2 billion kilowatthours of electricity being generated under a new FERC-approved interruptible tariff for the conversion of customers'oal to electricity and does not include any fuel cost.
Since these sales are for the service of converting the customers'oal to electricity and do not include any fuel cost, the average wholesale price per kilowatthour was significantly less in 1996 than in 1995.
Q Fuel Purchased Power Other Operation
)(alntenance Oeprec(ation and Amortizat1on Amortization of Reexport Plant Un1t 1 Phase-in Plan Oeferrals Taxes Other Than Federal Income Taxes Federal Income Taxes Total 5(9.8)
(4.2) 5 13.3 6.0 78.8 56.8 13.3 18.6 23.6 7.6 3.5 1.2 2.5 2.2 (26.5) (18.7) 0.3 1.6 1.2 0.4 (3.8) (24.1)
(8.8) (11.9) 1.9 2.7
~)
(8.8) ~
43.5 6.9 ~
2.8 The decrease in fuel expense in 1997 reflects a 36% decrease in nuclear generation as both nuclear units were unavailable from September 9 through the end of the year.
See Cook Plant shutdown discussed above.
The decrease in nuclear generation was partially offset by a 6%
'increase in fossil generation.
Fuel expense increased in 1996 due to a 17% increase in nuclear generation made possible by the shorter refueling outage in 1996 versus an extended refueling and maintenance outage in 1995. This increase was partially offset by a lower average Total operating expenses increased 7% in 1997 primarily due to an increase in power purchases.
The 3% increase in 1996 was mainly due to the increased operation of the Company's nuclear
- units, increased Power Pool wholesale transactions, and higher income taxes partially offset by a significant reduction in maintenance expense.
The changes in operating expenses were:
Increase (Oecrease) l m1 n
price per ton of coal consumed from a favorable settlement of a coal transportation dispute.
Purchased power expense increased significantly in 1997 due to the Company's share of purchases of power by AEP's new power marketing'business and increased purchases from the Power Pool to replace power usually generated by the out-of-service nuclear units. The rise in purchased power expense in 1996 was mainly due to additional power purchases under an agreement with the Ohio Valley Electric Corporation, an affiliated company which is not a member of the Power
- Pool, and increased purchases from the Power Pool to support the Company's allocated share of higher Power Pool wholesale transactions with non-affiliate utilities.
Qther operation expense increased in 1997 due to the effect of gains on the disposition of emission allowances recorded in 1996 and higher administrative and general costs and uncollectible accounts receivable expenses.
The substantial decrease in maintenance expense in 1996 was due to cost-reduction measures at the Company's nuclear plant, which reduced the number of employees performing maintenance and lowered payments for contract maintenance labor.
The recovery period for Rockport Plant Unit 1 costs deferred under a rate phase-in plan in the Indiana jurisdiction ended in August 1997 causing the decrease in the amortization of phase-in plan deferrals.
The deferred costs were amortized over a 10-year period commensurate with their collection from customers pursuant to an order of the Indiana UtilityRegulatory Commission (IURC).
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.
Federal income taxes attributable to operations decreased in 1997 due to a decrease in pre-tax operating income.
The increase in 1996 reflects an increase in pre-tax operating income and changes in certain book/tax differences accounted for on a
flow-through basis for rate-making purposes.
The decline in interest charges in 1996 was due to debt repayments and a refinancing program which lowered interest rates.
In 1997 the Company maintained its strong financial condition. We redeemed 790,967 shares of cumulative preferred stock with rates ranging from 4.12% to 6.875% at a total cost of $79 million.
We 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 Company issued
$48 million principal amount of long-term obligations in 1997 at 6.4%.
We continued to reduce financing costs by retiring higher-cost bonds and restructuring the long-term debt from senior secured/first mortgage bonds to senior unsecured debt and junior debentures.
The principal amount of long-term debt retirements, including maturities, totaled
$50 million at 8.75%.
Our senior secured debt/first mortgage bond ratings which were reaffirmed and improved in 1997, are: Moody's, Baa1; Standard
& Poor's, A-; and Fitch, BBB+.
Gross plant and property additions were $235 million in 1997 and
$144 million in 1996.
Management estimates construction expenditures for the next three years to be $456 million which includes the replacement of the Cook Plant Unit 1 steam generators.
The funds for construction of new facilities and improvement of existing facilities can come from a combination of internally generated
- funds, short-term and long-term borrowing s, preferred stock issuances and investments in common equity by the Company's parent, American Electric Power Company, Inc.
(AEP Co., Inc.). However, all of the construction expenditures for the next three years are expected to be financed with internally generated funds.
Inflation affects the Company's cost of replacing utility plant and the cost of operating and maintaining plant.
The rate-making process generally limits our recovery to the historical cost of assets resulting in economic losses when the effects of inflation are not recovered from customers on a timely basis.
However, economic gains that result from the repayment of long-term debt with inflated dollars partly offset such losses.
When necessary the Company generally issues short-term debt to provide for interim financing of capital expenditures that exceed internally generated funds. At December 31, 1997, $442 millionof 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 UtilityHolding Company Act of 1935 to $175 million. Generally periodic reductions of outstanding short-term debt are made through issuances of long-term debt and through additional capital contributions by the parent company.
The Company's earnings coverage presently exceeds all minimum coverage requirements for the issuance of mortgage bonds and preferred stock.
The minimum coverage ratios are 2.0 for mortgage bonds and 1.5 for preferred stock.
At December 31, 1997, the mortgage bonds and preferred stock coverage ratios were 7.57 and 2.88, respectively.
The Company is committed under unit power agreements to purchase 70% of an affiliated (AEGCo's) share of the 1,300 mw Rockport Plant capacity unless it is sold to other utilities. AEGCo has a long contract with an unaffiliated utilityfor 455 mw that expires in 1999.
AEGCo's total revenues from this contract "in 1997 were $72 million including capacity and energy charges.
Corporate Owned Life Insurance In connection, with the audit of AEP's consolidated federal income tax returns the Internal Revenue Service (IRS) agents sought a ruling from the IRS National Office that certain interest deductions relating to a corporate owned life insurance (COLI) program should not be allowed.
The Company established the COLI program in 1990 as part of its strategy to fund and reduce the cost of medical benefits for retired employees.
AEP filed a brief with the IRS National Office refuting the agents'osition.
No adjustments have been proposed by the IRS.
However, should a disallowance of COLI interest deductions be proposed it would, if sustained, reduce earnings by approximately
$59 million (including interest).
Management believes it has meritorious defenses and will vigorously contest any proposed adjustments.
No provisions for this amount have been recorded.
In the event the 10
INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Company is unsuccessful it could have a material adverse impact on results of operations and cash flows.
Computer Software - Year 2000 Compliance Many existing computer hardware and software programs will not properly recognize calendar dates beginning in the year 2000.
Unless corrected, this "Year 2000" problem may cause computer malfunctions, such as system shutdowns or incorrect calculations and system output. The Company is addressing the problem internally by modifying or replacing its computer hardware and software programs.
The problem is also being addressed externally with entities that interact electronically with the Company, including but not limited to, suppliers, service providers, government agencies, customers, creditors and financial service organizations.
However, due to the complexity of the problem and the interdependent nature of computer systems, ifthe Company's corrective actions, and/or the actions of other interdependent entities, fail for critical applications, the Company may be adversely impacted in the year 2000. Although significant, the cost of correcting the "Year 2000" problem is not expected to have a material impact on results of operations, cash flows or financial condition.
New Accounting Standards In June 1997 the FASB issued SFAS 130 "Reporting Comprehensive Income" and SFAS 131 "Disclosures About Segments of an Enterprise and Related Information." SFAS 130 establishes the standards for reporting and displaying components of "comprehensive income," which is the total of net income and all other changes in equity except those resulting from investments by shareholders and dispositions to shareholders.
SFAS 131 initiates standards for reporting information about operating segments in annual and interim financial statements as well as related disclosures about products and services, geographic areas and major customers.
I&M's adoption of these new reporting standards in 1998 is not expected to have a material effect on the results of operations, cash flows and/or financial condition.
Litigation The Company is involved in a number of legal proceedings and claims. While we are unable to predict the outcome of such litigation, it is not expected that the ultimate resolution of these matters willhave a material adverse effect on the results of operations, cash flows and/or financial condition.
11
Consolidated Statements of Income OPERATING REVENUES 122Z 12K (in thousands)
Q '51.2ll SLABS 4'Q.
OPERATING EXPENSES:
Fuel Purchased Power Other Operation Maintenance Depreciation and Amortization Amortization of Rockport Plant Unit 1
Phase-in Plan Deferrals Taxes Other Than Federal Income Taxes Federal Income Taxes Total Operating Expenses 226,402 217,460 334,115 117,780 140,812 11,871 64,945
~KH4 222,967 125,413 306,967 141,813 138,814 236,237 138,687 310,513 115,300 140,437 15,644 73,729
~77 15,644 71,791
~64
~kJE6
~7~44 OPERATING INCOME NONOPERATING INCOHE 207,788 220,417 205,723
~44
~7
~67 INCOHE BEFORE INTEREST CHARGES INTEREST CHARGES 212,203 223,146 211,995 NET INCOHE PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS APPLICABLE TO COHHON STOCK See Notes to Consolidated Financial Statements.
146,740 157,153 141,092 MK
~LSU.
1LL'U.
12
Consolidated Statements of Cash Flows INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES OPERATING ACTIVITIES:
Net Income Adjustments for Noncash Items:
Depreciation and Amortization Amortization of Rockport Plant Unit 1
Phase-in Plan Oeferrals Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses (net)
Deferred Federal Income Taxes Deferred Investment Tax Credits Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net)
Fuel, Materials and Supplies Accrued Utility Revenues Accounts Payable Taxes Accrued Other (net)
Net Cash Flows From Operating Activities LRK (in thousands}
$ 157,153 148,123 15,644 S 146,740 148,630 11,871 7,662 (24,687)
(8,729)
(15,967) 3,922 (8,428}
(10,235) 903 5,642 1,186 (6,296)
~7 (10,456) 5,168 7,774 6,502 (18,550)
~K M)
~L?ll
~~4 S 141,092 148, 441 15,644 8,684 (23,564)
(9,004) 4,121 (6,255)
(3,355)
(2,431) 8 '75
~1352) 4 INVESTING ACTIVITIES:
Construction Expenditures Long-term Receivable from Customer for Construction of Facilities Proceeds from Sales of Property and Qther Net Cash Flows Used For Investing Activities FINANCING ACTIVITIES:
Issuance of Long-term Debt Retirement of Cumulative Preferred Stock Retirement of Long-term Debt Change in Short-term Debt (net)
Dividends Paid on Common Stock Dividends Paid on Cumulative Preferred Stock Net Cash Flows Used For Financing Activities 38,579 (30,568)
(46,091)
(46,475)
(112,508)
~2 4'5) 96,819 (141,122) 39,375 (110,852)
)
47,728 (78,877)
(50,000) 76,100 (131,260)
~~V.)
~~4) ~~)
~Z2K)
(122,360)
(95,046)
(117,785) 62 (18,733)
~Ilk ~7
'LZR Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents January 1
Cash and Cash Equivalents December 31 See Notes to Consolidated Financial Statements.
(2,373)
(5,490) 3,816
(~7
Consolidated Balance Sheets ASSETS l22Z lRK (in thousands)
ELECTRIC UTILITY PLANT:
Production Transmission Distribution General (including nuclear fuel)
Construction Wor k in Progress Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT
$ 2,545,484 908,736 737,902 233,888 4, 514,497
$ 2,525,969 881,407 696,069 189,619
~)LSD 4,377,669 52 NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS
'i!i!i.2K
~4 OTHER PROPERTY AND INVESTMENTS CURRENT ASSETS:
Cash and Cash Equivalents Accounts Receivable:
Customers Affiliated Companies Miscellaneous Allowance for Uncollectible Accounts Fuel
- at average cost Materials and Supplies
- at average cost Accrued Utility Revenues Prepayments TOTAL CURRENT ASSETS 5,860 107,087 15,662 14,561 (1,188) 17,182 78,701 30,521
~5 8,233 90,656 13,727 21,439 (156) 23,977 77,074 38,295
~k22l REGULATORY ASSETS DEFERRED CHARGES
'~6
~457 TOTAL See A'otes to Conso)idated Financia1 Statements.
~t~Q
~F7 494
INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES CAPIJALIZATION AND LIABILITIES 122Z
~6 (in thousands)
CAPITALIZATION:
Common Stock No Par Value:
Authorized
- 2,500,000 Shares Outstanding
- 1,400,000 Shares Paid-in Capital Retained Earnings Total Common Shareholder's Equity Cumulative Preferred Stock:
Not Subject to Handatory Redemption Subject to Handatory Redemption Long-term Debt TOTAL CAPITALIZATION S
56,584 732,472 1,067,870 9,435 68,445
~L23Z 56, 584 731,272 1,056,927 21,977 135,000
~~M.
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning Other TOTAL OTHER NONCURRENT LIABILITIES 381,016 313,845
~~4
~4~4 CURRENT LIABILITIES:
Long-term Debt Due Within One Year Short-term Debt Accounts Payable
- General Accounts Payable
- Affiliated Companies Taxes Accrued Interest Accrued Obligations Under Capital Leases Other TOTAL CURRENT LIABILITIES DEFERRED INCOHE TAXES DEFERRED INVESTHENT TAX CREDITS DEFERRED GAIN ON SALE AND LEASEBACK-ROCKPORT PLANT UNIT 2 DEFERRED CREDITS COHHITHENTS AND CONTINGENCIES (Note 3)
TOTAL See Notes to Consolidated Financia1 Statements.
35,000 119,600 36,729 31,665 46,850 15,741 34,033
~RJL44 43,500 31,015 30,877 65,400 15,281 29,740
~4~4 8 K2
~~~44 15
Consolidated Statements of Retained Earnin s Retained Earnings January 1
Net Income Deductions:
Cash Dividends Declared:
Common Stock Cumulative Preferred Stock:
4-1/8X Series 4.56X Series
- 4. 12%
Seri es 5.90X Series 6-1/4X Series 6.30X Series 6-7/8X Series 7.08X Series Total Cash Dividends Declared Capital Stock Expense Total Deductions Retained Earnings December 31 See /Iotes to Conso7idated Financia1 Statements,
$ 269,071 131,260 249 88 80 985 1,266 834 1,255 136,017
~RL9l lRK (in thousands)
$ 235,107 112,508 495 273 165 2,360 1,875 2,205 2,063 122,475
$ 216,658
~4~
110,852 495 273 165 2,360 1,875 2,205 2,063
~4 122,412
IIVDIAIVANICHIGAIVPDWER CDIMPAIVY AIVDSUBSIDIARIFS NOTES TO CONSOLIDATED FINANCIALSTATEMENTS
- 1. SIGNIFICANTACCOUNTING POLICIES:
Organization Indiana Michigan Power Company (the Company or I&M)is a wholly-owned subsidiary of American Electric Power Company, Inc. {AEP Co., Inc.), a public utility holding company.
The Company is engaged in the generation,
- sale, purchase, transmission.and distribution of electric power to 549,000 retail customers in its service territory in northern and eastern Indiana and a portion of southwestern Michigan. Wholesale electric power is supplied to neighboring utility systems, power marketers and the American Electric Power (AEP)
System Power Pool (Power Pool). As a member of the AEP Power Pool and a signatoiy company to the American Electric Power System (AEP System) Transmission Equalization Agreement, its facilities are operated in conjunction with the facilities of certain other AEP affiliated utilities as an integrated utilitysystem.
The Company has two wholly-owned subsidiaries, that were formerly engaged in coal-mining operations which are consolidated in these financial statements, Btackhawk Coal Company and Price River Coal Company.
Blackhawk Coal Company currently leases and subleases portions of its Utah coal rights, land and related mining equipment to unaffiliated companies.
Price River Coal Company, which owns no land or mineral rights, is inactive.
Regulation As a subsidiary of AEP Co., inc., l&Mis subject to regulation by the Securities and Exchange Commission (SEC) under the Public UtilityHolding Company Act of 1935 (1935 Act). Retail rates are regulated by the Indiana Utility Regufatory Commission (IURC) and the Michigan Public Service Commission (MPSC).
The Federal Energy Regulatoiy Commission (FERC) regulates wholesale rates.
Principles of Consolidation The consolidated financial statements include I&Mand its wholly-owned subsidiaries.
Significant intercompany items are eliminated in consolidation.
Basis ofAccounting As a cost-based rate-regulated entity, l&M's financia'I statements reflect the actions of regulators that result in the recognition of revenues and expenses in different time periods than enterprises that are not cost-based rate-regulated.
In accordance with Statement of Financial Accounting Standards
{SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation,"
regulatory assets
{deferred expenses) and regulatory liabilities (deferred income) are recorded to reflect the economic effects of regulation and to match expenses with regulated revenues.
Use ofEstimates The preparation of these financial statements in conformity with generally accepted accounting principles requires in certain instances the use of estimates.
Actual results could differ from those estimates.
UtilityPlant Electric utilityplant is stated at original cost and is generally subject to first mortgage liens.
Additions, major replacements and betterments are added to the plant accounts.
Retirements of plant are deducted from the electric plant in service account and deducted from accumulated depreciation together with associated removal costs, net of salvage.
The costs of labor, materials and overheads incurred to operate and maintain utilityplant are included in operating expenses.
Allowance for Funds Used During ConstructIon (AFUDC)
AFUDC is a noncash nonoperating income item that is capitalized and recovered through depreciation over the service life of utilityplant.
It represents the estimated cost of borrowed and equity funds used to finance construction projects.
The amounts of AFUDC for 1997, 1996 and 1995 were not significant.
17
Functional Class Annual Composite Production:
Steam-Nuclear Steam-Fossil-Fired Hydroelectric-Conventional Transmission Distribution General 3.4%
4.4%
3.2%
1.9%
4.2%
3.8%
Amounts for the demolition and removal of non-nuclear plant are presently recovered through depreciation charges included in rates.
The accounting and rate-making treatment afforded nuclear decommissioning costs and nuclear fuel disposal costs are discussed in Note 3."
Cash and Cash Equivalents Gash and cash equivalents include temporary cash investments with original maturities of three months or less.
OperatI'ng Revenues and Fuel Costs Revenues include the accrual of electricity consumed but unbilled at month-end as well as billed revenues.
Fuel costs are matched with revenues in accordance with rate commission orders.
Revenues are accrued related to unrecovered fuel in both retail jurisdictions and for replacement power costs in the Michigan jurisdiction until approved for billing.
If the Company's earnings exceed the allowed return in the Indiana jurisdiction, the fuel clause mechanism provides for the refunding of the excess earnings to ratepayers.
Wholesale jurisdictional fuel cost changes are expensed and billed as incurred.
Levelizatfon ofNuclear Refueling Outage Costs Incremental operation and maintenance costs associated with refueling outages at the Donald C.
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 o
Depfeciation and Amortization Depreciation of electric utilityplant is provided on a straight-line basis over the estimated useful lives of utility plant and is calculated largely through the use of composite rates by functional cjass as follows:
outage and ending with the beginning of the next outage.
Income Taxes The Company follows the liability method of accounting for income taxes as prescribed by SFAS No. 109, "Accounting for Income Taxes."
Under the liabilitymethod, deferred income taxes are provided for all temporary differences between the book cost and tax basis of assets and liabilities which will result in a
future tax consequence.
Where the flow-through method of accounting for temporary differences is reflected in rates, deferred income taxes are provided with related regulatory assets and liabilities in accordance with SFAS No. 71.
Investment 7ax Credits Based on directives of regulatory commissions, the Company reflected investment tax credits in rates and on its books on a deferral basis.
Commensurate with rate treatment deferred investment tax credits are being amortized over the life of the related plant investment.
The Company's policy with regard to investment tax credits for nonutility property is to practice the flow-through method of accounting.
Debt and Preferred Stock Gains and losses on reacquistion of debt are deferred and amortized over the remaining term of the reacquired debt in accordance with rate-making treatment.
If the debt is refinanced the reacquisition costs are deferred and amortized over the term of the replacement debt commensurate with their recovery in rates.
Debt discount or premium and expenses of debt issuances are amortized over the term of the related debt, with the amortization included in interest charges.
Redemption premiums paid to reacquire preferred stock are included in paid-in capital and amortized to reduce retained earnings commensurate with their recovery in rates.
The excess of par value over the cost of preferred stock reacquired is credited to paid-in capital and amortized to retained earnings.
18
Nuclear Decommissioning and Spent Nudear Fuel Disposal TnIst Funds Securities held in trust funds for decommissioning nuclear facilities and for the
'isposal of spent nuclear fuel are recorded at market value in accordance with SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities."
Secuntfes in the trust funds have been classified as available-for-sale due to their long-term purpose.
Due to the rate-making
- process, adjustments for unrealized gains and losses are not reported in equity but result in adjustments to the liabilityaccount for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the spent nuclear fuel disposal trust funds.
Other Property and Investments Other property and investments are stated at cost.
- 2. EFFECTS OF REGULATIONAND PHASEAN PLANS:
In accordance with SFAS No.
71 the consolidated financial statements include regulatory assets (deferred expenses) and regulatory liabilities (deferred income) recorded in accordance with regulatory actions in order to match expenses and revenues from cost-based rates.
Regulatory assets are expected to be recovered in future periods through the rate-making process and regulatory liabilities are expected to reduce future cost recoveries.
Among other things, application of SFAS No. 71 requires that the Company's rates be cost-based regulated.
The Company has reviewed all the evidence currently available and concluded that it continues to meet the requirements to apply SFAS 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 be written offfor that portion of the business and assets attributabfe to that portion of the business would have to be tested for possible impairment and if required an impairment loss recorded unless the net regulatory assets and impairment losses are recoverable as a stranded investment.
Regulatory Assets:
Amounts Oue From Customers for Future Income Taxes DePartment of fnergy Decontamination and Oecoasafssfonfng Assessment Rate Phase-fn Plan Deferrals fiuclear Refueling Outage Cost Levelfzatfon Unamortfzed Loss On Reacquired Debt Other Total Regulatory Assets Regulatory Liabilities:
Deferred Investment Tax Credits Othere Total Regulatory Lfabflft1es
'ncluded fn Deferred Cred1ts on Sheets.
122Z 12K I 1n thousands)
$277,966'317.059 42,648 45,994 11,871 31,772 15,805 17,210 19,388 Q92d92 ~R
$ 138,045
$ 146,473 i2 Consolidated Balance The Rockport Plant consists of two 1,300 megawatt (mw) coahfired units.
I&M and AEP Generating Company (AEGCo), an affiffate, each own 50% ofone unit (Rockport 1) and each lease a 50% interest in the other unit (Rockport 2) from unaffiliated lessors under an operating lease.
The gain on the sale and leaseback of Rockport 2 was deferred and is being amortized, with related taxes, over the initial lease term which expires in 2022.
Rate phase-in plans in the Company's Indiana and FERC jurisdictions provided for the recoveiy and straight-line amortization of deferred Rockport Plant Unit 1 costs over ten years beginning in 1987.
In 1997 the amortization and recovery of the deferred Rockport Plant Unit 1 Phase-in Plan costs was completed.
During the recoveiy period net income was unaffected by the recovery of the phase-in deferrals. Amortization was $11.9 million in 1997 and $15.6 million in 1996 and 1995.
- 3. COMMITMENTSAND CONTINGENCIES:
Construction and Other Commitments Substantial construction commitments have been made to support the Company's utility operations including the replacement of the Cook INDIANAMICHIGAN POPOVER COMPANY ANDSUBSIDIARIES Recognized regulatory assets and liabilities are comprised of the following:
19
Plant Unit 1
Such commitments do not include any expenditures for new generating capacity.
Aggregate construction program expenditures for 1998-2000 are estimated to be $456 million.
Long-term fuel supply contracts contain clauses that provide for periodic price adjustments.
The retail jurisdictions have fuel clause mechanisms that provide for recovery of changes in the cost of fuel with the regulators'eview and approval.
The contracts are for various terms, the longest of which extends to 2014, and contain various clauses that would release the Company from its obligation under certain force majeure conditions.
The Company is committed under unit power agreements to purchase
?0/o of an affiliate's (AEGCo's) share of the 1,300 mw Rockport Plant capacity unless it is sold to unaffiliated utilities.
AEGCo has one long-term contract with an unaffiliated utilitythat expires in 1999 for 455 mw of Rockport Plant capacity.
The Company sells under contract up to 250 mw of its Rockport Plant capacity to an unaffiliated utility. The contract expires in 2009.
Revised AirQuality Standards On July 18,
- 1997, the United States Environmental Protection Agency published a
revised National Ambient Air Quality Standard (NAAQS) for ozone and a new NAAQS for fine particulate matter (less than 2.5 microns in size).
The new ozone standard is expected to result in redesignation of a number of areas of the country that are currently in compliance with the existing standard to nonattainment status which could ultimately dictate more stringent emission restrictions for AEP System generating units.
New stringent emission restrictions on AEP System generating units to achieve attainment of the tine particulate matter standard could also be imposed.
The AEP System operating companies joined with other utilities to appeal the revised NAAQS and filed petitions for review in August and September 1997 in the U.S. Court of Appeals for the District of Columbia Circuit. Management is unable to estimate compliance costs without knowfedge of the reductions that may be necessary to meet the new standards.
If such costs are significant, they could have a material adverse effect on results of operations, cash flows and possibly financial condition unless recovered.
LitigatI'on The Company is involved in a number of legal proceedings and claims.
While management is unable to predict the ultimate outcome of litigation, it is not expected that the resolution of these matters willhave a material adverse effect on the results of operations, cash flows and financial condition.
Nuclear Plant l&Mowns and operates the two-unit 2,110 mw Donald C. Cook Nudear Plant under licenses granted by the Nuclear Regulatory Commission.
The operation of a nuclear facilityinvolves special risks, potential liabilities, and specific regulatory and safety requirements.
Should a nudear incident occur at any nuclear power plant facilityin the United States, the resultant liabilitycould be substantial.
By agreement IBM is partially liable together with all other electric utility companies that own nuclear generating units for a nuclear power plant incident.
In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery is not possible, results of operations, cash flows and financial condition would be negatively affected.
Nuclear Plant Shutdown On September 9 and 10, 1997, during a Nuclear Regulatory Commission (NRC) architect engineer design inspection, questions regarding the operability of certain safety systems caused Company operations personnel to shut down Units 1 and 2 ofthe Cook Nudear Plant. On September 19, 1997, the NRC issued a Confirmatory Action Letter requiring the Company to address the issues identified in the letter.
The Company is working with the NRC to resolve these issues and other issues related to restart of the units. Certain issues identified in the letter have been addressed.
Atthis time management is unable to determine when the units will be returned to service.
Ifthe units are not returned to service in a timely manner, it could have an adverse impact on results of operations, cash flows and possibly financial condition.
Nuclear Incident Liability Public liability is limited by law to $8.9 billion should an incident occur at any licensed reactor in the United States.
Commercially available insurance provides $200 million of coverage.
In
the event of a nuclear incident at any nuclear plant in the United States the remainder of the liability would be provided by a deferred premium assessment of $79.3 million on each licensed reactor payable in annual installments of $10 million.
As a result, l8M could be assessed
$ 158.6 million per nuclear incident payable in annual installments of$20 million. The number of incidents forwhich payments could be required is not limited.
Nuclear insurance pools and other insurance policies provide $3.6 billion (reduced to $3.0 billion effective January 1, 1998) of property damage, decommissioning and decontamination coverage
'or Cook Plant.
Additional insurance provides coverage for extra costs resulting from a
prolonged accidental Cook Plant outage.
Some of the policies have deferred premium provisions which could be triggered by losses in excess of the insurer's resources.
The losses could result from claims at the Cook Plant or certain other non-affiliated nuclear units. The Company could be assessed up to $35.8 million annually under these policies.
Spent Nuclear Euel Disposal Federal law provides for government responsibility for permanent spent nuclear fuel disposal and assesses nuclear plant owners fees for spent fuel disposal.
A fee of one mill per kilowatthour for fuel consumed after April 6, 1983 is being collected from customers and remitted to the U.S. Treasury.
Fees and related interest of
$ 181 million for fuel consumed prior to April 7, 1983 have been recorded as long-term debt.
l&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program.
At December 31,
- 1997, funds collected from customers towards the pre-April 1983 fee and related earnings thereon approximate the liability.
Decommissioning and Low Level Waste Accumulation Disposal Decommissioning costs are accrued over the service life of the Cook Plant.
The licenses to operate the two nuclear units expire in 2014 and 017. After expiration of the licenses the plant is xpected to be decommissioned through dismantlement.
A 1997 nuclear decommissioning INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES study has been completed.
The estimated cost of decommissioning and low level waste accumulation disposal costs ranges from $700 million to $1,152 million in 1997 nondiscounted dollars. The wide range is caused by variables in assumptions including the estimated length of time spent nuclear fuel must be stored at the plant subsequent to ceasing operations.
This in turn depends on future developments in the federal government's spent nuclear fuel disposal program.
Continued delays in the federal fuel disposal program can result In increased decommissioning costs.
The Company is
, recovering estimated decommissioning costs in its three rate-making jurisdictions based on at least the lower end of the range in the most recent decommissioning study at the time of the last rate proceeding.
The Company records decommissioning costs in other operation expense and records a noncurrent liabilityequal to the decommissioning cost recovered in rates; such amount was $28 million in 1S97, $27 million in 1S96 and $30 million in 1S95 including $4 million of special deposits.
Decommissioning costs recovered from customers are deposited in external trusts. Trust fund earnings increase the fund assets and the recorded liability thereby decreasing the amount needed to be recovered from ratepayers.
At December 31, 1997 the Company has recognized a decommissioning liabilityof $381 million.
- 4. RELATED PARTY TRANSACTIONS:
Benefits and costs of the AEP System's generating plants are shared by members of the Power Pool.
The Company is a member of the Power Pool. Under the terms of the AEP System Interconnection Agreement, capacity charges and credits are designed to allocate the cost of the AEP System's capacity among the Power Pool members based on their relative peak demands and generating reserves.
Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the Power Pool and charged forenergy received from the Power Pool.
The Company is a net supplier to the pool and, therefore, receives capacity credits from the Power Pool.
Operating revenues include revenues for capacity and energy supplied to the Power Pool as follows:
122Z 12K 1222 iin thousands}
Capacity Revenues fnerpy Revenues
$ 53,282
$ 57.594
$ 59,918
~4152 Total RM4 Q~
Purchased power expense includes charges of
$51.0 million in 1997, $34.5 million in 1996 and
$25A million in 1995 for energy received from the Power Pool.
Power Pool members share in wholesale sales to unaffiliated entities made by the Power Pool.
The Company's share of the wholesale power pool sales included in operating revenues were
$ 127.4 million in 1997, $73.4 million in 1996 and
$52.6 million in 1995.
In addition, the Power Pool purchases power from unaffiliated entities for resale to other unaffiliated entities.
The Company's share of these purchases was included in purchased power expense and totaled
$67.9 million (including new power marketing transactions) in 1997, $8.1 million in 1996 and $10.7 million in 1995.
Revenues from these transactions, inciuding a transmission fee for power that passes through the AEP System transmission network, are included in the above Power Pool wholesale operating revenues.
The cost of Rockport Plant power purchased from AEGCo, an affiliated company that is not a member of the Power Pool, was Included in purchased power expense in the amounts of
$87.5 million, $85.4 million and $85.2 million in 1997, 19S6 and 1S95, respectively..
The cost of power purchased from Ohio Valley Electric Corporation, an affiliated but non-associated company that is not a member of the Power Pool, was included in purchased power expense in the amounts of $11.0 million, $10.7 million and $4.0 million in 1S97, 1S96 and 1995, respectively.
The Company operates the Rockport Plant and bills AEGCo for its share of operating costs.
AEP System companies participate in a
transmission equalization agreement.
This agreement combines certain AEP System companies'nvestments in transmission facilities and shares the costs of ownership in proportion to the AEP System companies'espective peak demands.
Pursuant to the terms of the agreement, since the Company's relative investment in transmission facilities is greater than its relative peak demand, other operation expense includes equalization credits of $46.1 million, $46.3 million and $46.7 million in 1997; 1996 and 1995, respectively.
Revenues from providing barging services were recorded in nonoperating income as follows:
122L 12K 12K (fn thousands}
Affiliated Conpanies
$24,427
$22,740
$23, 160 Unaffiliated Conpanies Total American Electric Power Service Corporation (AEPSC) provides certain managerial and professional services to AEP System companies.
The costs ofthe services are billed by AEPSC on a directMarge basis to the extent practicable and on reasonable bases of proration for indirect costs. The charges for services are made at cost and include no compensation for the use of equity capital, which is furnished to AEPSC by AEP Co.,
Inc.
Billings from AEPSC are capitalized or expensed depending on the nature of the services rendered.
AEPSC and its billings are subject to the regulation of the SEC under the 1935 Act.
- 5. BENEFIT PLANS:
The Company and its subsidiaries participate in the AEP System pension
- plan, a
- trusteed, noncontributory defined benefit plan covering all employees meeting eligibility requirements.
Benefits are based on service years and compensation levels. Pension costs are allocated by first charging each System company with its service cost and then allocating the remaining pension cost in proportion to its share of the projected benefit obligation. The funding policy is to make annual trust fund contributions equal to the net periodic pension cost up to the maximum amount deductible for federal income taxes, but not less than the minimum required contribution in accordance with the Employee Retirement Income Security Act of 1974.
Net pension costs for the years ended December 31, 1997, 1996 and 1995 were $2.1 million, $4.1 million and $2.7 million, respectively.
Postretirement benefits other than pensions (OPEB) are provided for retired employees under an AEP System plan. Substantially all employees are eligible for postretirement health care and life insurance if they retire from active service after reaching age 55 and have at least 10 service years.
The funding policy for OPEB cost is to make contributions to an external Voluntary Employees Beneficiary Association trust fund equal to the incremental OPEB costs (i.e., the amount that the total postretirement benefits cost under SFAS 106, "Employers'ccounting for Postretirement Benefits Other Than Pensions,"
exceeds the pay-as-you-go amount).
Contri-butions were $6.3 million in 1997, $8.4 million in 1996 and $10.3 million in 1S95.
OPEB costs are determined by the application of AEP System actuarial assumptions to each company's employee complement.
The Company's annual accrued costs for 1997, 1996 and 1995 required by SFAS 106 for employees and retirees were
$11.5 million, $12.8 million and $ 13.6 million, respectively.
An employee savings plan is offered which allows participants to contribute up to 17% of their salaries into various investment alternatives, including AEP Co.,
Inc. common stock.
An employer matching contribution, equaling one-half of the employees'ontribution to the plan up to a maximum of3 lo ofthe 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.
INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES
- 6. SUPPLEMENTARY INFORMATION:
1221 12K (in thousands)
Cash uas paid for:
Interest (net of cap(tal(ted amounts) 5 62,274 S 64,117 S71.457 Incoex. Taxes 120,212 125,707 80,675 Koncash Acqufsftfons Under Capital Leases 111,395 40,305 32 '73 In connection with the 19S6 early termination of a western coal land sublease the Company will receive cash payments from the lessee of $30.8 million over a ten-year period which has been recorded at a net present value of $22.8 million.
In connection with the 1995 sale of western coal land and equipment the Company will receive cash payments from the buyer of $31.5 million over a six year period which has been recorded at a net present value of$26.9 million. In connection with construction of facilities in 1995 to provide service to a new customer the Company will receive cash payments of $21.4 million plus accrued interest over 20 years.
The long-term portion of these receivables is recorded as other property and investments and the current portion is recorded as miscellaneous accounts receivable.
- 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 Deferred Deferred Investment Tax Credits Total Charged (Credited) to Nonoperating Income (net)
Current Deferred Deferred Investment Tax Credits Total Total Federal Income Taxes as Reported 1110,133 (24,730)
~H)
S 75,442 3,088
~)ia)
~~44 S 75,686 (13,732)
~KJRR 3,287 834
~4~
182 12,872 43 (9,832)
~!K)
~RU
~iZ)
~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.
Het Income Federal Income Taxes pre-tax Book Income Federal Income Tax on pre-tax Book Income at Statutory Rate (35X)
Increase (Decrease) in Federal Income Tax Resulting From the Fo)lou(ng Items:
Depreciation Corporate Ovned Life Insurance Investment Tax Credits (net)
Other Tota'i Federa'i Income Taxes as Reported Effective Federal Income Tax Rate i146,740
~4RX S77,337 14,082 (3,348)
(8,428)
~4)
Q44Q 12K (in thousands) i157 ~ 153
~J!22 I2'LaaliZ S81.918 13,880 (2.178)
(8,729)
~)
S141,092
~1(i 568,979 8,954 (F 187)
(9,004)
~7)
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 Deferred Tax liabilities Net Deferred Tax Liabilities Property Related Temporary Differences Amounts Due From Customers For Future Federal Income Taxes Deferred State Income Taxes Deferred Net Gain
- Rockport Plant Unit 2 All Other (net)
Total Net Deferred Tax Liabilities
$ 223,772
$ 241,842
~Mal)
~r~c)~) ~t~<~)
$ (471,898)
$ (480,818)
(74,282)
(79,658)
(65,679)
(89,471) 32,347 33,644
~~4 XQiRK2M) ~~)
The Company and its subsidiaries join in the filingof a consolidated federal income tax return with their affiliated companies in the AEP System.
The allocation of the AEP System's current consolidated federal income tax to the AEP System companies is in accordance with SEC rules under the 1935 Act. These rules permit the allocation of the benefit of current tax losses to the System companies giving rise to them in determining their current tax expense.
The tax loss of the parent company, AEP Co., Inc., is allocated to its subsidiaries with taxable income.
With the exception of the loss of the System parent
- company, the method of allocation approximates a separate return result for each company in the consolidated group.
The AEP System has settled with the Internal Revenue Service (IRS) all issues from the audits ofthe consolidated federal income tax returns for the years prior to 1991.
Returns for the years 1991 through 1996 are presently open and under audit 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 should not be allowed.
The COLI program was established in 1990 as part of the Company's strategy to fund and reduce cost of medical benefits for retired employees.
AEP filed a brief with the IRS National Office refuting the agents'osition.
Although no adjustments have been
- proposed, a disallowance of the COLI interest deductions through December 31, 1S97 would reduce earnings by approximately
$59 million (including interest).
Management 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.
- 8. FAIRYALUEOF FINANCIALINSTRUMENTS:
Nuclear Trust Funds Recorded at Man(et Value 1998 1999-2002 2003-2007 After 2007 Total
$ 87,063 127,575 182,873 Other Financial InstrTJments Recorded at Historical Cost IIVDIAIVAhIICHIGAIVPOWER CoiHPAIVY AND SUBSIDIARIES At December 31, 1997 and 1996 the fair values of trust fund investments were $566 million and
$491 million, respectively.
Accumulated gross unrealized holding gains were $41 million and
$21.9 million and accumulated gross unrealized holding losses were $1.2 million at both December 31, 1997 and 1996, The change in market value in 1997, 1996 and 1995 was a net unrealized holding gain of $19.1 million, $2.6 million and
$24.9 million, respectively.
The trust fund investments'ost basis by security type were:
1222 12K (1n thousands)
Tax-Except Bonds 1335,358 1340,290 Equity Secur1ties 74,398 54,389 Treasury bonds 44,200 26,958 Corporate Bonds 9,167 7,977
- Cash, Cash Equivalents and Interest Accrued
~~
~4 ~4 Total Proceeds from sales and maturities of securities of $147.3 million during 1997 resulted in $3.9 million of realized gains and
$1.4 million of realized losses.
Proceeds from sales and maturities of securities of $115.3 million during 1996 resulted in $2.6 million of realized gains and
$2.1 million of realized losses.
Proceeds from sales and matunties of securities of $78.2 million during 1S95 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.
At December 31, 1997, the year of maturity of trust fund investments, other than equity securities, was:
(in thousands)
The Nuclear Decommissioning and Spent uclear Fuel Disposal Trust Fund investments are rded at market value in accordance with AS 115 and consist of tax-exempt municipal bonds and other securities.
The carrying amounts of cash and cash equivalents, accounts receivable, short-term debt, and accounts payable approximate fair value because of the short-term maturity of these instruments.
Fair values for preferred stocks subject to mandatory redemption were $73 million and $ 137 million at December 31, 1997 and 1996,
respectively, and for long-term debt were $ 1.1 billion at each year end. The carrying amounts for preferred stock subject to mandatory redemption were $68 million and $135 million and for long-term debt were $1.0 billion at December 31, 1997 and 1996, respectively.
Fair values are based on quoted market prices for the same or similar issues and the current dividend or interest rates offered for instruments of the same remaining rnatunties.
The carrying amount of the spent nuclear fuel disposal trust funds approximates the Company's estimate of the pre-April 1983 SNF liability.
Electric Utility Plant:
Production Oistr ibution General:
Nuclear Fuel (net of amortization)
Other Total Electric Ut11(ty Plant Accumulated Amortization Net Electric Uti)1ty Plant 5 7,410 14,699 5
9.218 14,660 59,681
~L<R 142,739 MIL52R 103.939
~k 189,085
~ik Properties under capital leases and related obligations recorded on the Consolidated Balance Sheets are as follows:
122Z 12K
( in thousands)
S. LEASES:
Other Property Accumulated Amortization Net Other Property Net Properties under Capital Leases 40,746
~7~0 19,035 Leases of property, plant and equipment are for periods of up to 35 years and require payments of related property taxes, maintenance and operating costs.
The Company is leasing 50% of the 1300 MW Rockport 2
generating unit under an operating lease.
The lease has 25 years remaining life and total minimum lease payments of $ 1.8 billion. The majority of the leases have purchase or renewal options and willbe renewed or replaced by other leases.
Lease rentals for both operating and capital leases are generally charged to operating expenses in accordance with rate-making treat-ment.
The components of rental costs are as follows:
Capital
(.ease Obligat(ons:~
Noncurrent L1abi lity 5161,194 Liability Oue i((thin One Year
~4~
Total Capital Lease Ob)1gations 112~7
$ 101,225
~~4
+ Represents the present value of future minimum lease payments.
The non current portion of capital lease obligations is included in other noncurrent liabilities in the Consolidated Balance Sheets.
Future minimum lease payments consisted of the following at December 31, 1997:
Properties under operating leases and related obligations are not included in the Consolidated Balance Sheets.
Operating Leases Amortizat1on of Cap1tal Leases Interest on Capital Leases Tota'I Rental Costs 122Z 12K 1L5.
(in shousands)
$ 92,067 5 9&,096 5 96.472 42,882 55,789 45,843
'4222
~LB% ~L>
XUidd5 XÃ~ ~~R 1998 1999 2000 2001 2002 Later Years Capital (1n 5 16,362 15>005 13,593 11,927 22,520
~iZ Non-Cancelable Operat1ng thousands) 5 96,974 92,734 92,472 91,684 90.655
~2LZi2 Total Future H(nisus Lease Payments Less Estimated Interest E'lement Estimated Present Value of Future Ninisum Lease Payments Unamortized Nuclear Fuel Total 127,174(a) 91,288 MKXI2
+<)~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.
- 10. CUMULATIVEPREFERRED STOCK:
INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES At December 31, 1997, authorized shares of cumulative preferred stock were as follows:
$ 100 25 2,250,000 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.
A. Cumulative Preferred Stock Not Subject to Mandatory Redemption:
Call Pr1ce December 31, Par
~elhi~
XILUla Number of Shares Redeemed Shares Outstanding 122Z 12K (in thousands) 4-1/8$
$ 106.125
$ 100 4.56$
102 100 4.12K 102.728 100 59,760 44,788 20,869 233 60,007 15,212 19,131
$ 6,001
$ 11,977 1.521 6,000
~42
~4 KJ 'UZ
- 8. Cumulative Preferred Stock Subject to Handatory Redemption:
Par Humber of Shares Redeemed 122Z 12K 1222 Shares Outstanding 122Z 12K (in thousands) 5.90K (b) 6-1/4$ (b) 6.30$ (b) 6-7/8X(c) 5100 233.000 100 97.500 100 217,550 100 117,500 167,000 202,500 132,450 182,500 516,700 20,250 13,245
~ik
~~44
$ 40,000 30 F 000 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:
Long-term debt by major category was outstanding as follows:
Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:
122Z 12K (in thousands)
First Nortgage Bonds installment Purchase Contracts Other Long-tens Debt (a)
Junior Debentures Less Portion Due Nithin One Year Total 309,269 180,837
~LJKi 1,049,237 309,120 171,706
~L22l 1.042.104 12K (in thousands) 520,317 522,507 City of Lawrenceburg, Indiana:
7.00 2015
- April 1 5.90 2019
- November 1
City of Rockport, indiana:
(a) 2014 - August 1
7.60 2016
- Harch 1
6.55 2025 - June 1
(b) 2025 - June 1
City of Sullivan, 1ndiana:
5.95 2009
- Nay 1
Unamortized Discount
$ 25,000 52,000 50,000 40>000 50,000 50,000 45,000
$ 25,000 52,000 50,000 40 F 000 50,000 50,000 45,000
~22)
(a)
Represents a Nuclear Fuel Disposal liability including interest accrued payable to the,Department of Energy.
See Note 3.
First mortgage bonds outstanding were as follows:
122Z 12'in thousands) 7.00 1998 - Hay 1
$ 35,000
$ 35,000 7.30 1999
- December 15 35.000 35,000 6.40 2000 - Harch 1
48,000 7.63 2001
- June 1
40,000 40,000 7.60 2002
~ November 1
50,000 50,000 7.70 2002
- December 15 40,000 40>000 6.80 2003
- July 1
20,000 20,000 6.55 2003
- October 1
20,000 20.000 6.10 2003
- November 1
30,000 30,000 6.55 2004
- Narch 1
25,000 25 F 000 S.75 2022
- Hay 1
50,000 S.50 2022
~ December 15 75,000 75,000 7.80 2023
- July 1
20,000 20,000 7.35 2023
- October 1
20,000 20,000 7.20 2024
~ February 1
40,000 40,000 7.50 2024
- Harch 1
25,000 25,000 Unamortized Discount (net)
~()1) ~22) 520,317 522,507 Less Portion Oue 'Nithin One Year ~)2Q Total
- kR45l, Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions.
Total (a)
A variable interest rate is determined weekly.
The average weighted interest rate was 4.3X for 1997 and 3.5X for 1996.
( b)
An adJustable interest rate can be a daily, weekly, cossserc(al paper or term rate as designated by the Company.
A weekly rate was selected which ranged from 3.0X to 4.6X in 1997 and from 2.4X to 5.0X in 1996 and averaged 3.8X and 3.4X during 1997 and 1996, respectively.
Under the terms of certain installment purchase contracts, the Company is required to pay amounts sufficient to enable the cities to pay interest on and the principal (at stated maturities and upon mandatory redemption) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain generating plants.
On the two variable rate series the principal is payable at the stated matunties or on the demand of the bondholders at periodic interest adjustment dates which occur weeldy. The variable rate bonds due in 2014 are supported by a bank letter of credit which expires in 2002.
I8M has agreements that provide for brokers to remarket the adjustable rate bonds due in 2025 tendered at interest adjustment dates.
In the event certain bonds cannot be remarketed, l8M has a standby bond purchase agreement with a bank that provides for the bank to purchase any bonds not remarketed.
The purchase agreement expires in 2000.
Accordingly, the variable and adjustable rate installment purchase contracts have been classified for repayment purposes based on the expiration dates of the standby purchase agreement and the letter of credit.
28
Junior debentures are composed of the following:
INDIANAMICHIGANPO WER COMPANy'ND SuBSIDIARIES
- 12. COMMON SHAREHOLDER'S EQUITY:
122Z 12K (ln thousands) 8.00 2026 - Harch 31 Unamort(zed D(scount Total At December 31, 1997, future annual long-term debt payments are as follows:
$40,000
$40,000
~) ~)
Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of the Company.
Mortgage indentures, charter provisions and orders of regulatory authorities place various restrictions on the use of retained earnings for the payment of cash dividends on common stock. At December 31,
- 1997,
$5.9 million of retained earnings were restricted.
Regulatory approval is required to pay dividends out of paid-in capital.
ln 1997, 1996 and 1995 net changes to paid-in capital of $1,200,000,
$170,000 and
$(2,548,000) respectively, represented gains and expenses associated with cumulative preferred stock transactions.
((n thousands) 1998 5
35,000 1999 35,000 2000 98,000 2001 40,000 2002 140,000 Later Years
~LE Total Prlncl pal Amount 1,055,837 Dnamort(zed Discount
~iJHN)
Total
~gg, Short-term debt borrowings are limited by provisions of the 1935 Act to $175 million. Lines of credit are shared with AEP System companies and at December 31, 1997 and 1996 were 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.
Ouarterly Per(ods Operat(ng Operat(ng Net
((n thousands) 1991 Narch 31 June 30 September 30 December 31 1996 Narch,31 tune 30 September 30 December 31
$341,313 320,508 362,058 368,038 329.883 323,494 339,847 335.269
$ 59,894 50,140 60,449 37,305 53,018 50,430 61,123 55,846
$44,259 33,908 45,091 23,482 35,167 33,507 44,546 43,333
- 13. UNAUDITEDQUARTERLYFINANCIAL INFORMATION:
Outstanding short-term debt consisted of:
December 31, 1991:
Notes Payalrle Cosinerc(al Paper Total Year-end Balance lie(ghted Outstanding Average
~~n~
5 56,410 6.35
~XJK 6.6 December 31 '996:
Notes Payable Coasaerc(al Paper Total 5 3,900
~4 5.55 7.2 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 oftheir 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 With Electric Heating Total Residential Commercial Industrial Miscellaneous Total Retail Wholesale (safes for resale)
Total Revenues from Energy Sales Provision for Refunds of Revenues Collected in Prior Years Total Net of Provision for Refunds Other Total Operating Revenues 237,475 0
232,212 0
239,266 0 227,358
~1QJLQ, ~LKQ ~2LSQR ~ZJi23 0 205,315 C~
1,365,813 1,308,218 1,267,268 1,233,551 1,184,508
~LXQE ~QATAR ~iiJiRR ~LZGR ~L13R
~RRZ kXA@kR ~M83-'@X ~~QR 348,022 343,768 348,770 334,881 302,883 264,03'I 253,750 256,319 247,938 220,938 332,218 312,777 298,256 291,527 250,939 LCK ~~R ~Lk92 ~LB'RR3 950,736 916,740 909,827 880,662 780,353 ZZ
~iRL4ZR ~~
~SLBBR ~Q~
1,365,813 1,308,218 1,267,268 1,233,551 1,185,263 SOURCES AND USES OF ENERGY (in millions of kilowatthours):
Sources:
Net Generated:
Fossil Fuel Nuclear Fuel Hydroelectric Total Net Generated Purchased and Power Pool Total Sources Less: Losses, Company Use, Etc.
Net Sources Uses:
Retail Safes:
Residential:
Without Electric Heating With Electric Heating Total Residential Copmercial Industrial Miscellaneous Total Retail Wholesale Sales (safes for resale)
Total Uses 14,193 10,421 133 24,747 11.~R42 36,396
~SO 3~
3,307
~ZQR 5,075 4,349 7,541
~)2 17,047 1Z 432 24~
13,304 16,396 29,799
~ri91 37,380
~i%
3%MR 3,329
~61 5,140 4,328 7,295 16,845 1%2M 3imm 12,850 13,999
~i6 26,935
~821 32,806
~QQ EL' 3,390 5,158 4,300 6,582 16,122 2135%
13,022 9,291 22,408
~iiZ 28,165 2LZfg 3,210
~l2Z 4,937 4,148 6,453
~Z 15,620 1L14Z 26 ZGZ 12,236 16,313 1QG
,28,655
~R 33,534 32JRi 3,178
~HE 4,884 3,977 6,025 14,969 3Z22i 32J95 31
/
OPERATING STATISTICS (Concluded)
AVERAGE COST OF FUEL CONSUMED (in cents):
Per MillionBtu:
Coal Nuclear Overall Per Kilowatthour Generated:
Coal Nuclear Overall 124 49 89 1.23
.53
.93 122 44 74 1.22
.47
.80 126 43 78 1.23
.47
.83 124 42 85 1.21
.47
.90 130 36 72 1.27
.40
~77 RESIDENT)ALSERV(CE - AVERAGES:
Annual Kwh Use per Customer:
With Electric Heating Total Annual Electric Bill:
With Electric Heating Total Price per Kwh (in cents):
With Electric Heating Total 17,583 10,560 18,206 10,791 6.25 6.86 6.16 6.69
$ 1,099.34
$ 1,121.41
$724.16 0721.76 18,044 10,943 17,907 10,572 6.19 6.76 6.23 6.78
$ 1,117.55 01,115.19 0739.99
$717.17 17,980 10,559 S1,028.26 0654.76 5.72 6.20 NUMBER OF CUSTOMERS:
Year-End:
Retail:
Residential:
Without Electric Heating With Electric Heating Total Residential Commercial Industrial Miscellaneous Total Retail Wholesale (sales for resale)
Total Electric Customers 378,757 102222 383,314 101~
484,806 57,311 5,484
~JK5 479,129 55,869 5,345
~JL20 542,163 549,456 222 fHLM K&K 375,929
~325 475,034 55,077 5,316
~292 537,224 372,473 2
469,875 53,927 5,213
~BURY 530,821 369,385
~ZK 465,180 53,081 5,157
'LZQ 525,201 32
/
4
INDIANAAf/CHIGANPOWER COhfPANY AND SUBSIDIARIES DIVIDENDSAND PRICE RANGES OF CUMULATIVEPREFERRED STOCK B
Quarters (1997 and 1996)
U r
($ 100 Par Value) 4-1/SB Serf as Dividends Paid Per Share Market Price -
$ Per Share (CSE)
- Htgh
- Lov
$ 1.03125
$ 1.03125
$ 1.03125
$ 1.03125
$ 1.03125
$ 1.03125
$ 1.03125
$ 1.03125 4.565 Series D1v1dends Paid Per Share Harket Price
$ Per Share (OTC)
Ask - High
- Lov S1d
~ High
- Lov 4.12% Series Dfvfdends Pa1d Per Share itarket Price
$ Per Share (OTC)
Ask - High
- Lov 81d
- High
- Lov 5.90K Series Dividends Paid Per Share Harket Price
$ Per Share (OTC)
Ask (h1gh/lov)
Bfd (high/lov)
$ 1.14
$ 1.14
$ 1.14 tl.l4 52 52 52 52 57-5/8 52 58-1/4 57-5/8
$ 1.03
$ 1.03
$ 1.03
$ 1.03 63-1/8 50 58 58 58-1/4 58 58 1/4 58-1/4
$ 1.475
$ 1.475
$ 1.475
$ 1.475 t1.14
$ 1.14
$ 1.14 t1.14 51 49'/8 51-1/4 51 52 51-1/4 52 52
$ 1.03
$ 1.03
$ 1.03
$ 1.03 51 48-1/4 49 48-3/4 49-3/4 49 50 49 3/4
$ 1.475
$ 1.475
$ 1.475
$ 1.475 6-1/4X Series Dtvtdends Paid Per Share Market Price -
$ Per Share (OTC)
Ask (high/lov)
Btd (htgh/)ow)
$ 1.5625
$ 1 '625
$ 1.5625
$ 1.5625
$ 1.5625
$ 1.5625
$ 1.5625
$ 1.5625 6.306 Series Divfdends Paid Per Share Market Pr1ce
$ Per Share (OTC)
Ask (high/lov) 81d (high/low)
$ 1.575
$ 1.575
$ 1.575
$ 1.575
$ 1.575
$ 1.575
$ 1.575
$ 1.575 6-7/SX Series Dfvfdends Paid Per Share Harriet Prfce
$ Per Share (OTC)
Ask (high/low)
Bfd (high/lov) 7.08% Ser1es (a) 01vtdends Paid Per Share Market Price
$ Per Share (MYSE)
~ High
~ Lov
$ 1.71875
$ 1.71875
$ 1.71875
$ 1 '1875
$ 1.71875 tlat 71875
$ 1.71875
$ 1.71875
$ 1.77 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 VIRG INIA KENTUCKY VIRGINIA Indiana Michigan Power R
Co. area Other AEP operating companies'reas g
Major power plant TENNESSEE printed on reoyded paper
ATTACHMENT 2 TO AEP:NRC:0909N INDIANAMICHIGAN POWER COMPANY'S PROJECTED CASH FLOW FOR 1998
1998 Forecasted Sources and Uses of Funds
$Millions Projected 1998 Net Income Atter Taxes Less: Dividends 148.6 117.5 31.1 Adjustments:
Depreciation and Amortization Deferred Operating Costs Deferred Federal Income Taxes and Investment Tax Credits AFUDC Other 145.3 4.9 (24.7)
(6.3) 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