ML17325B618
| ML17325B618 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 12/31/1998 |
| From: | Powers R INDIANA MICHIGAN POWER CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| AEP:NRC:09090, AEP:NRC:9090, NUDOCS 9906030223 | |
| Download: ML17325B618 (58) | |
Text
CATEGORY'EGULATORY INFORMATION DISTRIBUTI
~ SYSTEM (RIDS)
ACCESSION NBR:9906030223 DOC.DATE: ~+M-NOTARIZED: NO FACIL:50-315 Donald C.
Cook Nuclear Power Plant, Unit 1, Indiana M
50-316 Donald C.
Cook Nuclear Power Plant, Unit 2, Indiana M
AUTH.NANT AUTHOR AFFILIATION" POWERS,R.P.
RECIP.NAME RECIPIENT AFFILIATION DOCKET 05000315 05000316
SUBJECT:
"Indiana Michigan Power Co 19 ual Rept." Projected cash flow for 1999,included. With 9052 ltr.
DISTRIBUTION CODE:
M004D COPIES RECEIVED:LTR ENCL SIZE:
TITLE: 50.71(b)
Annual Financial Report NOTES:
C'ECIPIENT ID CODE/NAME LPD3-1 LA STANGiJ INTERNAL.
NRR/DRIP/RGEB EZTERNAL: NRC PDQ COPIES LTTR ENCL 1
1 1
1 1
1 1
1 1
1 RECIPIENT ID CODE/NAME LPD3-1 PD NRR/DRIP COPIES LTTR ENCL 1
1 R
D U
'E NOTE TO ALL "RIDS" RECIPIENTS:
PLEASE HELP US TO REDUCE WASTETH TO HAVE YOUR NAME OR ORGANIZATION REMOVED FROM DISTRIBUTION LISTS OR REDUCE THE NUMBER OF COPIES RECEIVED BY YOU OR YOUR ORGANIZATION, CONTACT THE DOCUMENT CONTROL DESK (DCD)
ON EXTENSION 415-2083 TOTAL NUMBER OF COPIES REQUIRED:
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ENCL 7
Indiana Michigan~
Power Comp'any~
500 Circle Drive Buchanan, Ml 491071373 l&fblANA MCHIGAM lrOMfM May 28, 1999 AEP:NRC:09090 Docket Nos.:
50-315 50-316 U.
S. Nuclear Regulatory Commission ATTN:
Document Control Desk Mail Stop 0-Pl-17 Washington, D.
C.
20555-0001 Donald C.
Cook Nuclear Plant Units 1 and 2
FINANCIAL INFORMATION FOR INDIANA MICHIGAN POWER COMPANY Gentlemen:
In accordance with 10 CFR 50.71(b),
Indiana Michigan Power Company is submitting its 1998 annual report (attachment 1).
Also in accordance with 10 CFR 140.21(e) a copy of Indiana Michigan Power Company's projected cash flow for 1999
,(attachment
- 2) is being provided.
The NRC staff has been notified that this transmittal was delayed due to an administrative error in the Regulatory Affairs Department.
This condition has been entered into our corrective action program to ensure timely resolution.
Sincerely, R.
P.
Powers Vice President
/mjg Attachments c:
J.
E.
& RPD NRC Resident Inspector R. Whale
'F906030223 981231 PDR ADQCK 05000315
~,
I PDR e
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ATTACHMENT 1 TO AEP:NRC:09090 INDIANA MICHIGAN POWER COMPANY'S ANNUAL REPORT FOR 1998
lie'limen@ IMIIchmgen Power Company 1998 Annual Report
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DIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES One Summit Square, P.o. Box 60, Fort Wayne, Indiana 46801 CONTENTS
Background
Directors and Officers 2
3 Selected Consolidated Financial Data 4
Management's Discussion and Analysis of Results of Oper and Financial Condition Independent Auditors'eport Consolidated Statements of Income Consolidated Balance Sheets Consolidated Statements of Cash Flows Consolidated Statements of Retained Earnings Notes to Consolidated Financial Statements Operating Statistics ations 5-19 20 21 22-23 24 25 26-45 46-47 Dividends and Price Ranges of Cumulative Preferred Stock 48
BACKGROUND l
INDIANA MICHIGAN POWER COMPANY (the Company) is engaged in the generation, sale,'urchase, transmission and distribution of electric power.
The Company serves approximately 554,000 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 83X of the Company's retail sales are in Indiana and 17K 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
'ubsidiary of American Electric Power Company, Inc.,
a public utility holding company.
The Company does business as American Electric Power (AEP) along with all of the parent's operating subsidiary companies in order to serve its customers more efficiently as one operating organization aligned by distinct business units.
The Company's two wholly-owned subsidiaries, Blackhawk Coal Company and Price River Coal Company; were formerly engaged in coal-mining operations in Utah.
Blackhawk Coal Company currently leases or subleases portions of its coal rights, land and related mining equipment to unaffiliated companies.
In addition, the Company has a river transportation division (RTD) that barges coal on the Ohio and Kanawha Rivers to AEP System generating plants.
The RTD also provides some barging services to unaffiliated companies.
The Company owns and leases 4,435 megawatts (mw) of generating capacity which includes 2,295 mw of coal-fired generation and 2, 110 mw of nuclear generation.
The Company owns the two unit Donald C.
Cook Nuclear Plant located in Michigan.
The generating plants and transmission facilities of the Company and certain other affiliated AEP System utility subsidiaries are operated as an integrated system with their costs and benefits shared through the AEP System Power Pool and AEP Transmission Equalization 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
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 5 Electric Company, Commonwealth Edison
- Company, Consumers Energy Corporation, Illinois Power
- Company, Indianapolis Power Im Light Company, Louisville Gas and Electric Company, Northern Indiana Public Service
- Company, PSI Energy Inc.
and Richmond Power and Light Company, as well as Indiana-Kentucky Electric Corporation (a subsidiary of Ohio Valley Electric Corporation, an affiliate that is not a
member of the AEP System).
ANA MICHIGANPOWER COMPANY AND SUBSIDIARIES DIRECTORS Karl G.
Boyd Coulter R. Boyle, III Gregory A. Clark Peter J.
DeNaria (a)
William.N. O'Onofrio (b)
E. Linn Draper, Jr.
Henry W.
Fayne (c)
James A. Kobyra (d)
William J.
Lhota Gerald P. Haloney (a)
James J.
Harkowsky Armando A.
Pena (c)
David B. Synowiec Joseph H. Vipperman William E. Walters Earl H. Wittkamper E. Linn Draper Jr.
Chairman of the Board and Chief Executive Officer William J.
Lhota President and Chief Operating Officer A. Alan Blind (e)
Vice President, Nuclear Engineering Coulter R. Boyle, III Vice President Peter J.
DeMaria (a)
Vice President and Controller Henry W.
Fayne (c)
Vice President Eugene E. Fitzpatrick (f)
Vice President Gerald P. Haloney (a)
Vice President James J.
Markowsky Vice President Armando A.
Pena (c)
Vice President, Treasurer and Chief Financial Officer Robert P.
Powers (g)
Vice President Michael W.
Rencheck (h)
Vice President
- Nuclear Engineering John R.
Sampson (i)
Site Vice President, Donald C.
Cook Plant Joseph H. Vipperman Vice President Leonard V. Assante (c)
Controller and Chief Accounting Officer John F. DiLorenzo, Jr.
Secretary Elio Bafile Assistant Controller and Assistant Secretary Timothy P.
Bowman Assistant Controller William L. Scott Assistant Controller John H. Adams, Jr.
(b)
Assistant Secretary Thomas G. Berkemeyer (d)
Assistant Secretary Maurice C. McIntyre Assistant Secretary John B. Shinnock Assistant Secretary Bruce H. Barber Assistant Treasurer Christopher J.
Keklak Assistant Treasurer As of January I, 1999 the current dfrectors and offfcers of Indfana Mfchfgan'ower Company were empfoyees of Amer1can Electrfc Power Servfce Corporatfon w1th sfx exceptfons:
Messrs.
Boyd, Boyle, CIark, Mclntyre, IfaIters and Nfttkamper, who sere empIoyees of Indfana Mfchfgan PoNer Company.
(a)
Resigned June 1,
1998 (d)
Elected January 28, 1998 (g)
Elected August 27, 1998 (b)
Resigned January 28, 1998 (e)
Resigned June 17, 1998 (h)
Elected December 16, 1998 (c)
Elected June 1,
1998 (f)
Resigned Hay 1, 1998 (l)
Elected January 15, 1998
INCOME STATEMENTS DATA:
Operating Revenues
$ 1,405,794 Operating Expenses 3
78 Operating Income 1
Nonoperating Income (Loss)
Income Before Interest Charges 165,168 Interest Charges 6
5 Net Income 9,
8 Preferred Stock Dividend Requirements
~48 4
Earnings Applicable to Common Shock
~~84 r
n d
e ember 192Z 1RK (in thousands)
$ 1,339,232 7
~ 7 7
$ 1,283,157 4
4
$ 1,251,309 1,7 157,15 211,995
- 111, P2
~4221 229,397 5
157,502
~4~4 M346.~47
~29 ZR
~L44.~
BALANCE SHEETS DATA:
Electric Utility Plant
$4,631,848 Accumulated Depreciation and Amortization Net Electric Utility Plant g
5~5 Total Assets
~4~4~5 (in t ousands)
$4,514,497
$4,377,669
$4,319,564
$4,269,306
~~4
~4~5(jg,
~5~,7Z6 ~~
~6~66 XX35%2$1 ~23M XXBZ~7 Common Stock and Paid-in Capital Retained Earnings Total Common Shareholder's Equity 789,189 4
789,056 787,856 787,686 790,234
~~65 a k44 ~3 aJK~I XL95RBZZ K.JR3 a M6 m Cumulative Preferred Stock:
Not Subject to Handatory Redemption 9,273 Subject to Mandatory Redemption (a)
Total Cumulative Preferred Stock 9,435 21,977
~KJHE
~~JtK
~6322 52,000 52,000
~!SPRUE
~Z.999 ~U GK Long-term Debt (a)
XL1L'~~7 kl.~4~7 41JL44 ~4 S ~4~
~L66 E~Z Obligations Under Capital Leases (a) 86 4
7 M39'~l PAL2K 4uL H Total Capitalization and Liabilities
~148 523.
n.~.zm.
~892.~4 a
Inc u sng portion due within one year.
I IANAMICHIGANPOWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.
These
'orward-looking statements reflect assumptions, and involve a
number of risks and uncertainties.
Among the factors that could cause actual results to differ materially from forward looking statements are:
electric load and customer growth; abnormal weather conditions; available sources and costs of fuels; availability of generating capacity; the speed and degree to which competition is introduced to the power generation
- business, the structure and timing of a competitive market and its impact on energy prices or fixed rates; the ability to recover stranded costs in connection with possible deregulation of generation; new legislation and government regulations; the ability of the Company to successfully control its costs; the economic climate and growth in our service territory; unforeseen events affecting the Company's nuclear plant which is on an extended safety related shutdown; unforeseen problems or failures related to Year 2000 readiness of computer software and hardware; inflationary trends; electricity market prices; interest rates; and other risks and unforeseen events.
This discussion contains a
"Year 2000 Readiness Disclosure" within the meaning of the Year 2000 Information and Readiness Disclosure Act.
Indiana Michigan Power Company (the Company) 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,
- purchase, sale, transmission and distribution of electric power to 554,000 retail customers in its service territory in northern and eastern Indiana and a
portion of southwestern Michigan and conducts business as American Electric Power (AEP).
The Company supplies electric power to the AEP System Power Pool (AEP Power Pool) and shares the revenues and costs of AEP Power Pool wholesale sales to utility systems and power marketers.
The Company also sells wholesale power to municipalities and electric cooperatives.
As a member of the AEP Power Pool and a signatory company to the AEP System Transmission Equalization Agreement, the Company's generation and transmission facilities are operated in conjunction with the facilities of certain other affiliated utilities as an integrated utility system.
suts f
ra in Although operating revenues increased
$ 67 million or 5X in 1998 and
$ 11 million or 1X in 1997, net income decreased in both years.
Net income declined
$ 50 million or 34K in 1998 due to increased purchased power and maintenance expense related to an extended outage of the Company's two unit Donald C.
Cook Nuclear Plant (Cook Plant) which was shutdown in September 1997 and losses on certain non-regulated energy trades outside of the AEP Power Pool's traditional marketing area.
The 1997 decline of
$ 10 million or 7X resulted from increases in purchased power and other operation expenses due in part to the nuclear plant outage.
Operating revenues increased 5X in 1998 following a
1X increase in 1997.
The increases in operating revenues in 1998 and 1997 can be attributed mainly to increased retail revenues.
The following analyzes the
changes in operating revenues:
Increase (Oecrease) m u
ol ars in Milli n Retail:
Residential Commercial Industr ial Other Wholesale
~mon
~mn
$ 26.4 5
4.3 26.1 10.3 38.1 19.4
~4 91.0 9.6 34.0 3.7 (40.6)(11.2)
(29.1)
(7.4)
Transmission 13.4 83.2 4.3 35.9 Miscellaneous 27.6 ~
18.6 Total
~6 5.0
~0 0.8 The Company as part of the AEP System shares costs and benefits of the System's generating facilities through the AEP Power Pool.
The cost of the System's generating capacity is allocated among the AEP Power Pool
- members, based on their relative peak demands and generating reserves thiough the payment or receipt of capacity charges and credits.
AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool.
The AEP.
Power Pool calculates each Company's prior twelve month peak demand relative to the total Revenues from reta i 1 customers increased in 1998 due to the accrual of revenues under fuel adjustment clauses for the increased cost of replacement power and increased fossil fuel usage necessitated by the extended outage of the Company's two nuclear units and a
3X increase in sales.
The increase in retail revenues in 1997 resulted from the acct'uals of revenues to be recovered under power supply recovery mechanisms.
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.
peak demand of all member companies as a basis for sharing revenues and costs.
The result of this calculation is each Company's member load ratio (MLR) which determines each Company's percentage share of revenues or costs.
During 1998 the Company's MLR increased resulting in the Company being allocated a larger share of wholesale revenues and expenses from the AEP Power Pool.
In 1997 management decided to develop a power marketing and trading business.
The power marketing and trading business is conducted by the AEP Power Pool and its revenues and expenses are allocated to AEP Power Pool members based on MLR.
Wholesale revenues declined in 1998 due to a decline in sales to the AEP Power Pool reflecting the unavailability of the nuclear units.
The decline was partially offset by the Company's share of increased power marketing sales and trading activities.
A decrease in sales to the AEP Power Pool due mainly to the outage of Cook Plant is'lso the primary reason for the decline in wholesale revenues in 1997.
~mu
~
~mn Fuel 5(53.8) (23.8)
Purchased Power 133.3 80.9 Other OPeration 13.1 3.9 Maintenance 39.8 33.8 Oepreciation and Amortization 4.3 3.1 Amortization of Reexport Plant Unit 1 Phase-in Plan Oeferrals (11.9)(100.0)
Taxes Other Than Federal Income Taxes 2.6 4.1 Federal Income Taxes ~) (27.0)
Total
~08.
- 9. 6
$ (9.8)
(4.2) 26.1 18.8 23.6 7.6 2.5 2.2 0.4 0.3 (3.8)
(24.1)
(8.8)
(11.9)
~)
(8.8) 2.1 Total operating expenses increased 10X in 1998 and 2X in 1997 primaiily due to an increase in power purchases.
The changes in operating expenses were:
Increase (Oecrease)
I IANAMICHIGAIVPOWER COMPANY AND SUBSIDIARIES The decrease in fuel expense in 1998 and 1997 reflects the decrease in nucle'ar generation as both nuclear units were unavailable from September 1997 through the end of 1998.
See Cook Nuclear Plant Shutdown discussed below.
Purchased power expense increased significantly in 1998 and 1997 due to increased purchases from the AEP Power Pool and the Company's MLR share of increased purchases of electricity by the AEP Power Pool.
The purchases replace power usually generated by the unavailable nuclear units and supply the electricity for the AEP Power Pool's marketing sales.
The increases in other operation and maintenance expenses in 1998 were due to expenditures to prepare the nuclear units for restart.
Other 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 recovery period for Rockport Plant Unit 1
costs deferred under rate phase-in plans in the Indiana and the Federal Energy Regulatory Commission (FERC) jurisdictions ended in 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.
The decrease in taxes other than federal income taxes in 1997 was due to decreases in real and personal property
Federal income taxes attributable to operations decreased in 1998 and 1997 due to decreases in pre-tax operating income.
nc me The decline in nonoperating income is due to losses in 1998 from non-regulated electricity trading activities.
These trading activities are for forward electricity sales and purchases outside of the AEP Power Pool's traditional marketing area and also include electricity derivatives such as
- options, swaps, etc.
Open trades are marked-to-market and recorded in nonoperating income.
ines u loo The most significant factors affecting the Company's future earnings are the restart of the Cook Plant units (discussed below under Cook Nuclear Plant Shutdown) and the ability to recover costs as the electric generating business becomes more competitive.
The introduction of competition and customer choice for retail customers in the Company's service territory has been slow and continues at a
deliberate pace as legislators and regulatory officials recognize the complexity of the issues.
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.
Certain states, including California, instituted full customer choice in 1998.
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 Michigan 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 not presently 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 13X of total revenues.
Indiana is
considering 1 egi sl ati ve initiati ves 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 the best competitive market structure and method to transition to a competitive marketplace.
As the pricing of generation in the electric energy market evolves from regulated cost-of-service ratemaking to market-based
- rates, many complex issues must be resolved, including the recovery of stranded costs.
Stranded costs are those costs above market that potentially would not be recoverable in a
competitive market.
At the wholesale level recovery of stranded costs under certain conditions was addressed by the FERC when it established rules for open transmission access and competition in the wholesale markets.
- However, the issue of stranded cost is unresolved at the retail level where it is much larger than it is at the wholesale level.
The amount of stranded cost the Company could experience depends on the timing and extent to which competition is introduced to its generation business and the future market prices of electricity.
The recovery of stranded cost is dependent on the terms of future legislation and related regulatory proceedings.
Under the pr ovisions of Statement of Financial Accounting Standards (SFAS) 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 to match expenses and revenues with cost-based rates in the same accounting period.
In order to maintain net regulatory assets on the balance
- sheet, SFAS 71 requires that rates charged to customers be cost-based and provide for the recovery of deferred expenses over'uture accounting periods.
In the event a
portion of the Company's business no longer meets the requirements of SFAS 71, SFAS 101 "Accounting for the Discontinuance of Application of Statement 71" requires that net regulatory assets be written off for that portion of the business.
The provisions of SFAS 71 and SFAS 101 never anticipated that deregulation would include an extended transition period or that it could provide for recovery of stranded costs during and after the transition period.
In 1997 the Financial Accounting Standards Board's (FASB)
Emerging Issues Task Force (EITF) addressed such a
situation with the consensus reached on issue 97-4 that requires the application of SFAS 71 to a
segment of a regulated electric utility cease when that segment is subject to a
legislatively approved plan for competition 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 off unless they are recoverable in future rates.
Although certain FERC orders 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.
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 generating assets.
- However, if in the future the Company's generation business were to no longer be cost-based regulated and if it
IN IANAMICHIGANPOWER COMPANY ANDSUBSIDIARIES were not possible to demonstrate probability of recovery of resultant stranded'osts including regulatory
- assets, results of operations, cash flows and financial condition would be adversely affected.
believes that it has a meritorious position and will vigorously pursue
.this lawsuit.
In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows.
w d if n
ra The Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns for the years 1991 to 1993 requested a ruling from their National Office that certain interest deductions claimed by the Company relating to AEP's corporate owned life insurance (COLI) program should not be allowed.
As a result of a
suit filed by the Company in United States (US) District Court (discussed below) this request for ruling was withdrawn by the IRS agents.
Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96.
A disallowance of the COLI interest deductions through December 31, 1998 would reduce earnings by approximately
$ 66 million (including interest).
The Company has made no provision for any possible adverse earnings impact from this matter.
In 1998 the Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-97 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount.
The payments to the IRS are included on the balance sheet in other property and investments pending the resolution of this matter.
The Company will seek
- refund, either administratively or through litigation, of all amounts paid plus interest.
In order to resolve this issue without further
- delay, on March 24, 1998, the Company filed suit against the US in the US District Court for the Southern District of Ohio.
Management The Company is involved in a
number of other 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 financial condition.
mrvmn Efforts continue to reduce the cost of products and services in order to maintain competitiveness.
The accounting department completed its consolidation of operations and the marketing department completed its reorganization in 1998 producing cost reductions.
In 1998 the Company reviewed its staffing levels for power generation and energy delivery and developed plans to reduce staff in 1999.
The cost of staff reductions planned for 1999 was provided for in the fourth quarter of 1998.
Although cost savings are expected to result from the power generation and energy delivery reorganizations, the Company continues to incur expenses related to investments in marketing and customer services and the r eengineering and improvement of business processes.
During
- 1998, the Company completed installation of a
new unified customer service system which is designed to support customer requests for
- service, billings, accounts receivable, credit and collection functions.
On January 1,
- 1999, the Company's new financial data base and PeopleSoft client
server accounting and purchasing software became operational.
The move to client server business software and related online data bases will empower employees to maximize the benefits of their personal computers and will position them to better access the power of the Internet and other new technologies.
r n
N l
r F
1 The Company, as the owner of the Cook Plant, like other nuclear power plant
- owners, has a
significant future financial commitment to safely dispose of spent nuclear fuel (SNF) and decommission and decontaminate the plant.
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's (DOE)
SNF disposal program which is described in Note 3 of the Notes to Consolidated Financial Statements.
Since 1983 we have collected
$272 million from customers for the disposal of nuclear fuel consumed at the Cook Plant.
Of these
- funds,
$ 115 million has been deposited in external trust funds to provide for the future disposal of SNF and
$ 157 million has been remitted to the DOE.
Under the provisions of the Nuclear Waste Policy
- However, in December
- 1996, the DOE notified the Company that it would be unable to begin accepting SNF by the January 1998 deadline required by law.
As a result of DOE's failure to make sufficient progress toward a
permanent repository or otherwise assume responsibility for
- SNF, the Company along with a
number of unaffiliated utilities and states filed suit in the US Court of Appeals for the District of Columbia Circuit requesting, among other things, that the court order DOE to meet.its obligations under the law.
The court ordered the parties to proceed with contractual remedies but declined to order DOE to begin accepting SNF for disposal.
DOE estimates its planned site for the nuclear waste will not be ready until 2010.
In June
- 1998, the Company filed a complaint in the US Court of Federal Claims seeking damages in excess of $ 150 million due to the DOE's partial material breach of its unconditional contractual deadline to begin disposing of SNF generated by the Cook Plant.
Similar lawsuits have been filed by other utilities.
As long as the delay in the availability of a
government approved storage repository for SNF continues, the cost of both temporary and permanent storage will increase.
The cost to decommission the Cook Plant is affected by both Nuclear Regulatory Commission (NRC) regulations and the delayed SNF disposal program.
Studies completed in 1997 estimate the cost to de-commission the Cook Plant ranges from
$ 700 million to
$ 1,152 million in 1997 dollars.
This estimate could escalate due to continued uncertainty in the SNF disposal program and the length of time that SNF may need to be stored at the plant site.
External trust funds have been established and funded with amounts collected from customers to decommission the plant.
At December 31,
- 1998, the total decommissioning trust fund balance was
$ 443 million which includes earnings on the trust investments.
We will work with regulators and customers to recover the remaining estimated cost of decommissioning the Cook Plant.
- However, future results of operations, cash flows and possibly financial condition would be adversely affected if the cost of SNF disposal and decommissioning continue to incr ease and cannot be recovered from customers.
10
I DIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Manhgement shut down both units of the Cook Plant in September 1997 due to questions, which arose during a
NRC architect engineer design inspection, regarding the operability of certain safety systems.
The NRC issued a Confirmatory Action Letter in September 1997 requiring the Company to address the issues identified in the letter.
We are working with the NRC to resolve the remaining open issue in the letter.
In April 1998 the NRC notified the Company that it had convened a
Restart Panel for Cook Plant.
A list of required restart activities was provided by the NRC in July 1998 and in October the NRC expanded the list.
In order to identify and resolve the issues necessary to restart the Cook
- units, the Company is and will be meeting with the Panel on a regular
- basis, until the units are returned to service.
In Januar y 1999 we announced that we will conduct additional engineering reviews at the Cook Plant that will delay restart of the units.
Previously, the units were scheduled to return to service at the end of the first and second quarters of 1999.
The decision to delay restart resulted from internal assessments that indicated a
need to conduct expanded system readiness reviews.
A new restart schedule will be developed based on the results of the expanded reviews and should be available in June 1999.
When maintenance and other activities required for restart are
- complete, the Company will seek concurrence from the NRC to return the Cook Plant to service.
Until these additional reviews are completed, management is unable to determine when the units will be returned to service.
One of the steps the Company has taken toward expediting the restart of the Cook units is to augment its existing nuclear generation management and staff with personnel experienced in restarting unaffiliated companies'uclear plants during NRC supervised extended outages.
The costs incurred in 1997 and 1998 for restart of the Cook units were
$ 6 million and
$ 78
- million, respectively, and were recorded as operation and maintenance expense.
Reductions in other operation and maintenance expenses partially offset these costs.
Currently incremental restart expenses are approximately
$ 12 million a month.
In July 1998 the Company received an "adverse trend letter" from the NRC indicating that NRC senior managers determined that there had been a
slow decline in performance at the Cook Plant during the 18 month period preceding the letter.
The letter indicated that the NRC will closely monitor efforts to address issues at Cook Plant through additional inspection activities.
In October 1998 the NRC issued the Company a
Notice of Violation and proposed a
$ 500,000 civil penalty for alleged violations at the Cook Plant discovered during five inspections conducted between August 1997 and April 1998.
The penalty was paid.
The cost of electricity supplied to retail customers rose due to the outage of the two units since higher cost coal-fired generation and coal based purchased power were substituted for low cost nuclear generation.
The Indiana and Michigan retail jurisdictional fuel cost recovery mechanisms permit the
- recovery, subject to regulatory commission review and
- approval, of changes in fuel costs including the fuel component of purchased power in the Indiana jurisdiction and changes in replacement power in the Michigan jurisdiction.
Under these fuel cost recovery mechanisms, retail rates 11
contain a fuel cost adjustment factor that reflects estimated fuel costs for the period during which the factor will be in effect subject to reconciliation to actual fuel costs in a future proceeding.
When actual fuel costs exceed the estimated costs reflected in the billing factor a
regulatory asset is recorded and revenues are accrued.
Therefore, a
regulatory asset has been recorded and revenues accrued in anticipation of the future reconciliation and billing under the fuel cost recovery mechanisms of the higher fuel costs to replace Cook energy during the extended outage.
At December 31,
- 1998, the regulatory asset was
$ 65 million.
The Indiana Utility Regul ator y Commi ssi on
( IURC) approved, subject to future reconciliation or refund, agreements authorizing the
- Company, during the billing months of July 1998 through Harch
- 1999, to include in rates a
fuel cost adjustment factor less than that requested.
The agreements provide the parties to the proceedings with the opportunity to conduct discovery regarding certain issues that were raised in the proceedings, including the appropriateness of the recovery of replacement energy cost due to the extended Cook Plant
- outage, in anticipation of resolving the issues in a
future fuel cost adjustment proceeding.
On Harch 16, 1999 a settlement agreement was filed with the IURC resolving all matters related to the reasonableness of fuel costs and all outage issues during an extended outage of the Cook Plant.
The settlement agreement, which is subject to IURC approval, provides
- for, among other things, a credit of
$ 55 million to Indiana retail customers; authorization to defer any unrecovered fuel revenues accrued between September 9,
1997 and December 31, 1999 including the
$ 55 million; authorization to defer up to
$ 150 million of incremental operation and maintenance restart costs for the Cook Plant above.the base rate level incurred during 1999; amortization of the fuel recoveries and restart cost deferral s over a
five-year period ending December 31, 2003; a freeze in base rates though December 31, 2003; and a cap on fuel recovery charges through Harch 1,
2004.
The
$ 55 million credit will be refunded through customer's bills during the months of July, August and September 1999.
If the IURC does not approve the settlement, the issue of recovery of replacement energy costs would be resolved through regulatory hearings.
Unless the costs of the extended outage and restart efforts are recovered from customers, there would be a
material adverse effect on results of operations, cash
- flows, and possibly financial condition.
v' l
n r
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 clean air and water technologies and to research new technologies.
We intend to continue in a
leadership role fostering 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 SNF.
Coal combustion by-products are typically disposed of or treated in captive disposal facilities or are beneficially utilized.
In addition, our generating plants and trans-mission and distribution facilities have used
- asbestos, polychlorinated biphenyls (PCBs) and other hazardous and nonhazardous materials.
The 12
t INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Company is currently incurring costs to safely dispose of such substances.
Additional costs could be incurred to comply with new laws and regulations if enacted.
The Comprehensive Environmental
- Response, Compensation and Liability Act (Superfund) addresses clean-up of hazardous substances at disposal sites and authorized the US Environmental Protection Agency (Federal EPA) to administer the clean-up programs.
As of year-end
- 1998, the Company is currently involved in litigation with respect to one site overseen by the Federal
potentially responsible party (PRP) for two other sites.
There is one additional site for which the Company has received an information request which could lead to PRP designation.
Historically, the Company's liability has 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 cleanup costs are incurred, results of operations, cash flows and possibly financial condition would be adversely affected unless the costs can be recovered from customers.
On September 24,
- 1998, the administrator of Federal EPA signed final rules which require reductions in nitrogen oxides (NOx) emissions in 22 eastern
- states, including the states in which the generating plants of the Company and its affiliates in the AEP System are located.
The implementation of the final rules would be achieved through the revision of state implementation plans (SIPs) by September 1999.
SIPs are a procedural method used by each state to comply with Federal EPA rules.
The final rules anticipate the imposition of a
NOx reduction on utility sources of approximately 85K below 1990 emission levels by the year 2003.
On October 30,
- 1998, a
number of utilities, including the Company and the other operating companies of the AEP System, filed a petition in the US Court of Appeals for the District of Columbia Circuit seeking a review of the final rules.
Should the states fail to adopt the required revisions to their SIPs within one year of the date the final rules were signed (September 24, 1999),
Federal EPA has proposed to implement a
federal plan to accomplish the NOx reductions.
Federal EPA also proposed the approval of portions of petitions filed by eight northeastern states that would result in imposition of NOx emission reductions on utility and industrial sources in upwind midwestern states.
These reductions are substantially the same as those required by the final NOx rules and could be adopted by Federal EPA in the event the states fail to implement SIPs in accordance with the final rules.
Preliminary estimates indicate that compliance could result in required capital expenditures of approximately
$ 169 million.
Compliance costs cannot be estimated with certainty and the actual costs incurred to comply could be significantly different from this preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions.
Unless such costs are recovered from customers, they would have a
material adverse effect on results of operations, cash flows and possibly financial conditions At the Third Conference of the Parties to the United Nations Framework Convention on Climate Change held in
- Kyoto, Japan in December 1997 more than 160 countries, including the US, negotiated a
treaty requiring 13
legally-binding reductions in emissions of greenhouse
- gases, chiefly carbon
- dioxide, which many scientists believe are contributing to global climate change.
The
- treaty, which requires the advice and consent of the US Senate for ratification, would require the US to reduce greenhouse gas emissions seven percent below 1990 levels in the year s 2008-2012.
Although the US has agreed to the treaty and signed it on November 12,
- 1998, President Clinton has indicated that he will not submit the treaty to the Senate for consideration until it contains requirements for "meaningful participation by key developing countries" and the rules, procedures, methodology and guidelines of the treaty's market-based policy instruments, joint implementation programs and compliance enforcement provisions have been negotiated.
At the Fourth Conference of the Parties, held in Buenos Aires, Argentina, in November 1998, the parties agreed to a work plan to complete negotiations on outstanding issues with a
view toward approving them at the Sixth Confer ence of the Parties to be held in December 2000.
We will continue to work with the Administration and Congress to monitor the development of public policy on this issue.
If the Kyoto treaty is approved by Congress, the costs to comply with the emission reductions required by the 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.
The Company issued
$ 175 million principal amount of long-term obligations in 1998 at interest rates ranging from 6.45K to 7.6X.
The principal amount of long-term debt r etir ements, including maturiti es, totaled
$ 55 million at interest rates ranging from 7X to 7.8X.
Our senior secured debt/first mortgage bond ratings are:
Moody's, Baal; Standard
& Poor's, A-; and Fitch, BBB+.
Gross plant and property additions were
$ 159 million in 1998 and
$ 235 million in 1997.
Management estimates construction expenditures for the next three years to be
$366 million which includes the replacement of the Cook Plant Unit 1
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 borrowings, preferred stock issuances and investments in common equity by the Company's
- parent, American Electric Power
- Company, Inc.
(AEP Co.,
Inc.)
- However, all of the construction expenditures for the next three years are expected to be financed with internally generated funds.
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,
- 1998,
$ 763 million of unused short-term lines of credit shared with other AEP System companies were available.
Short-term debt borrowings are limited by provisions of the Public Utility Holding Company Act of 1935 to
$ 300 million.
Generally periodic reductions of outstanding short-term debt are made through issuances of long-term debt and 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,
- 1998, the mortgage bond and preferred stock coverage ratios were 6.39 and 2.08, respectively.
I DIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES The Company i s committed under unit power agreements to purchase all of.
an a'ffiliate's share, 50K of the 2,600 megawatt (mw)
Rockport Plant
- capacity, unless it is sold to other utilities.
The affiliate has a long-term unit power agreement for the sale of 455 mw to an unaffiliated utility.
Revenues received under this agreement (which expires at the end of 1999) were
$ 70 million in 1998.
An agreement between the affiliate which owns Rockport Plant and another affiliate provides for the sale of 390 mw of capacity to that affiliate through 2004.
The Company has certain market risks inherent in its business activities from changes in electricity commodity prices and interest rates.
The trading of electricity and related financial derivative instruments through the AEP Power Pool on the Company's behalf exposes the Company to market risk.
Market risk represents the risk of loss that may impact the Company due to adverse changes in electricity commodity market prices and rates.
In 1998 the AEP Power Pool substantially increased the volume of its wholesale power marketing and trading activities.
Various policies and procedures have been established to manage market risk exposures including the use of a
risk measurement model utilizing Value at Risk (VaR).
Throughout the year ending December 31,
- 1998, the Company's share of the
- highest, lowest and average quarterly VaR in the wholesale trading portfolio was less than
$ 2 million at a
95K confidence level with a
holding period of three business days.
The AEP Power Pool uses the variance-covariance method for calculating VaR based on three months of daily prices.
Based on this VaR analysis, at December 31, 1998 a
near term change in commodity prices is not expected to have a material effect on the Company's results of operations, cash flows or financial condition.
The Company is exposed to changes in interest rates primarily due to short-term and long-term borrowings to fund its business operations.
The debt portfolio has both fixed and variable interest rates with terms from one day to forty years and an average duration of six years at December 31, 1998.
The Company measures interest rate market risk exposure utilizing a VaR model.
The model is based on the Monte Carlo method of simulated price movements with a 95X confidence level and a
one year holding period.
The volatilities and correlations are 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
$ 102 million at December 31, 1998.
The Company would not expect to liquidate its entire debt portfolio in a
one year holding periods Therefore, a
near term change in interest rates should not materially affect results of operations or the consolidated financial position of the Company.
Also since the Company's rates are cost-based regulated, the risk of interest rate changes on debt used to finance regulated operations is mitigated.
Inflation affects the Company's cost of replacing utility plant and the cost of operating and maintaining its 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.
15
On or about midnight on Oecember 31, 1999, digital computing systems may begin to produce erroneous results or fail, unless these systems are modified or
- replaced, because such systems may be programmed incorrectly and interpret the date of January 1,
2000 as being January 1st of the year 1900 or another incorrect date.
In addition, certain systems may fail to detect that the year 2000 is a
leap year.
Problems can also arise earlier than January 1,
- 2000, as dates in the next millennium are entered into non-Year 2000 ready programs.
Readiness Program
- Internally, the
- Company, through the AEP System, is modifying or replacing its computer hardware and software programs to minimize Year 2000-related failures and repair such failures if they occur.
This includes both information technology systems (IT), which are mainframe and client server applications, and embedded logic systems (non-IT), such as process controls fo'r energy production and delivery.
Externally, the problem is being addressed with entities that interact with the
- Company, including suppliers, customers, creditors, financial service organizations and other parties essential to the Company's operations.
In the course of the external evaluation, the Company has sought written assurances from third parties regarding their state of Year 2000 readiness.
Another issue we are addressing is the impact of electric power grid problems that may occur outside of our transmission system.
The
- Company, along with other electric utilities in North America, regularly submits information to the North American Electric Reliability Council (NERC) as part of NERC's Year 2000 readiness program.
HERC then publicly reports summary information to the DOE regarding the Year 2000 readiness of electric utilities.
In 1999 AEP plans to participate in two NERC-sponsored coordinated electric industry Year 2000 readiness drills.
The second NERC
- report, dated January 11, 1999 and entitled:
re ari h
1 ctr' r
m or Fo t
ar r
states that:
"With more than 44X of mi ssi on critical components tested through November 30,
- 1998, findings continue to indicate that transition through critical Year 2000 (Y2K) rollover dates is expected to have minimal impact
,on electric system operations in North America."
The Company continues to set a
target date of June 30, 1999 for having all mission critical and high priority systems and components Y2K ready.
Company's State of Readiness Wor k has been prioritized in accordance with business risk.
The highest priority has been assigned to acti vities that potenti al ly affect
- safety, the physical generation and delivery of
- energy, and communications; followed by back office activities such as customer service/billing, regulatory reporting, internal reporting and administrative activities (e.g.
- payroll, procurement, accounts Through the El ectri c Power Research Institute, an electric industry-wide effort has been established to deal with Year 2000 problems affecting embedded systems.
Under this
- effort, participating utilities are working together to assess specific vendors'ystem problems and test plans.
The state regulatory commissions in the Company's service territory are also reviewing the Year 2000 readiness of the Company.
16
INDIANAMICHIGANPOWER COMPANY AND SUBSIDlARIES payable);
and finally, those activities that would cause inconvenience or productivity loss in normal business operations.
The following chart shows our progress toward becoming ready for the Year 2000 as of December 31, 1998:
IT SYSTEMS HOH-IT SYSTEMS COMPLETIOH COMP LETIOH DATE/ESTIMATED PERCEHT DATE/ESTIMATED PERCEHT COMPLETIOH DATE COMPLETE COMPLETIOH DATE COMPLETE Y
0 P
PH Launch: In1tiation of the Year 2000 activ1ties within the organization.
Establishment of organizational structure, personnel assignments and budget for the workgroup.
Cont1nuous management update and awareness program.
Inventory and Assessment:
Identifying all Company computer systems that could be affected by the millennium change.
Prioritize repair efforts based upon criticality to maintaining ongoing operations.
2/24/1998 7/31/1998 100$
100K 5/31/1998 100$
2/15/1999 99$
Remediation/Testing:
The process of mod1fying, replacing or retir1ng those m1ss1on cr1tical and high prior1ty d1gital-based system w1th problems processing dates past the Year 2000. Testing these systems to ensure that after modif1cat1ons have been implemented correct date processing occurs and full functionality has been maintained.
6/30/1999 Mainframe:
70K Client Server:
18$
6/30/1999 37K Costs to Address the Company 's Year ZOOO Issues
- Through December 31,
- 1998, the Company has spent
$ 4 million on the Year 2000 project and, estimates spending an additional
$ 6 million to
$ 9 million to achieve Year 2000 readiness.
Most Year 2000 costs are for software modifications, IT consultants and salaries and are expensed;
- however, in certain cases the Company has acquired hardware that was capitalized.
The Company intends to fund these expenditures through internal sources.
Although significant, the cost of becoming Year 2000 compliant is not expected to have a
material impact on the Company's results of operations, cash flows or financial condition.
Risks of the Company's Year ZOOO Issues
- The applications posing the greatest business risk to the Company's operations should they experience Y2K problems are:
, Automated power generation, transmission and distribution systems Telecommunications systems Energy trading systems Time-in-use, demand and remote metering systems for commercial and industrial customers and Work management and billing systems.
17
The potential problems related to erroneous processing by, or failure of, these systems are:
Power service interruptions to customers Interrupted revenue data gathering and collection Poor customer relations resulting from delayed billing and settlement.
In
- addition, although as discussed relationships with third
- parties, such as suppliers, customers and other electric utilities, are being monitored, these third parties nonetheless represent a
risk that cannot be assessed with precision or controlled with certainty.
Due to the complexity of the problem and the interdependent nature of computer
- systems, if our corrective
- actions, and/or the actions of others not affiliated with the AEP
- System, fail for critical applications, Year 2000-related issues may materially adversely affect the Company.
Company 's Contingency Plans To address possible failures of electric generation and delivery of electrical energy due to Year 2000 related
- failures, we have established a draft Year 2000 contingency plan and submitted it to the East Central Area Reliability Council in December 1998 as part of NERC's review of regional and individual electric utility contingency plans in 1999.
NERC's target date is June 1999 for the completion of this contingency plan.
In addition, the Company intends to establish contingency plans for its business units to address alternatives if Year 2000 related failures occur.
Contingency plans will be developed by the end of 1999.
The Company's plans build upon the disaster
- recovery, system restoration, and contingency planning that we have had in place.
Nw c nin In 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 transactions not included in net income affecting equity except those with shareholders.
The Company adopted SFAS 130 in the first quarter of 1998.
For 1998 there were no material differences between net income and comprehensive income.
SFAS 131 initiates standards for annual and interim financial statements to report operating segments of a
business for which separate financial information is available and regularly evaluated by the chief operating decision maker in allocating resources and reviewing performance.
Information about products and services and geographic areas is to be reported at an enterprise-level instead of by segment.
SFAS 131 was required to be adopted by the Company for the year ended December 31, 1998 with restatement of prior period comparative information.
Adoption of SFAS 131 did not have any effect on results of operations, cash flows or financial condition.
In the first quarter of 1998 the Company adopted the American Institute of Certified Public Accountants'AICPA)
Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use".
The SOP requires the capitalization and amortization of certain costs of acquiring or developing internal use computer software.
Previously the Company expensed all software acquisition and development costs.
The SOP had to be 18
INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES adopted at the beginning of a fiscal year with no restatement or retroactive adjustment of prior periods.
The adoption of the SOP effective January 1,
1998 did not have a material effect on results of operations, cash flows or financial condition.
In February
- 1998, the FASB issued SFAS 132 "Employers'isclosure about Pensions and Other Postretirement Benefits" which revised employers'isclosures about pensions and other postretirement benefit plans and suggested that the disclosure be combined.
It did not change the measurement or recognition requirements for postretirement benefit accounting.
The adoption of SFAS 132 did not have an effect on results of operations, cash flows or financial condition.
EITF 98-10 "Accounting for Contracts Involved in Energy Trading and Risk Management Act.ivities" was issued in November 1998 to address the application of mark-to-market accounting for energy trading contracts.
Under the provisions of this standard, which must be adopted by the Company in January
, 1999, energy trading contracts can no longer be accounted for on a
settlement basis.
Instead they are to be marked-to-market.
Initial adoption of EITF 98-10 is not expected to have a significant impact on results of operations, cash flows, or financial condition.
The FASB i ssued SFAS 133 "Accounting for Deri vati ve Instruments and Hedging Activities" in June 1998.
SFAS 133 establishes accounting and reporting standards for derivative instruments.
It requires that all derivatives be recognized as either an asset or a
liability and measured at fair value in the financial statements.
If certain conditions are met a
derivative may be designated as a
hedge of possible changes in fair value of an asset, liability or firm commitment; variable cash flows of forecasted transactions; or foreign currency exposure.
The accounting/reporting for changes in a
derivative's fair value (gains and losses) depend on the intended use and resulting designation of the derivative.
Management is currently studying the provisions of SFAS 133 to determine the
- impact, of its adoption on January 1,
- 2000, on results of operations, cash flows and financial condition.
In April 1998 the AICPA issued SOP 98-5 "Reporting on the Costs of Start-up Activities".
The SOP clarifies the accounting and reporting for one time start-up activities and organization
- costs, requiring that they be expensed as incurred.
The adoption of this standard in January 1999 is not expected to have a material effect on results of operations, cash flows or financial condition.
19
INDEPENDENT AUDITORS'EPORT To the Shareholders and Board of Directors of Indiana Hichigan Power Company:
We have audited the accompanying consolidated balance sheets of Indiana Hichigan Power Company and its subsidiaries as of December 31, 1998 and
- 1997, and the related consolidated statements of income, retained
- earnings, and cash flows for each of the three years in the period ended December 31, 1998.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards.
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and significant estimates made by management, as well-as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material
- respects, the financial position of Indiana Hichigan Power Company and its subsidiaries as of December 31, 1998 and
- 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998 in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
- Columbus, Ohio February 23, 1999 (Harch 16, 1999 as to Note 4) 20
DIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income OPERATING REVENUES Y
r n
d mbr
~7 (in thousands)
~8~4
~XhZR
~K~ 44>
.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 172,592 298,046 347,207 157,593 145,112 226,402 164,775 334,115 117,780 140,812 67,592 11,871 64,945
~~V. ~
44 236,237 138,687 310,513 115,300 140,437 15,644 73,729 22 'RR; OPERATING INCOME NONOPERATING INCOME (LOSS)
INCOME BEFORE INTEREST CHARGES INTEREST CHARGES NET INCOME PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS APPLICABLE TO COMMON STOCK See Notes to Consolidated Financial Statements.
166,007 207,788 220,417
~)
4 4 ~7 165,168 212,203 223,146 96,628
~44 146,740 157,153 MLK1
~~84
~4 4
~144 4~
21
Consolidated Balance Sheets ASSETS 1RRR
~97 (in thousands)
ELECTRIC UTILITY PLANT:
Production Transmission Distribution General (including nuclear fuel)
Construction Work in Progress Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT
$ 2,556,732 913,252 768,803 236,650
~K 411 4,631,848
~EL'.
55 43
$2,545,484-908,736 737,902 233,888,
~5 48Z 4,514,497
~4~56 NUCLEAR DECOHHISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS OTHER PROPERTY AND INVESTHENTS CURRENT ASSETS:
Cash and Cash Equivalents Accounts Receivable:
Customers Affiliated Companies Hiscellaneous Allowance for Uncollectible Accounts Fuel
- at average cost Haterials and Supplies
- at average cost Accrued Utility Revenues Prepayments and Other TOTAL CURRENT ASSETS 12,465 94,502 19,528 18,743 (2,027) 20,857 78,009 37 277 5,860 107,087 15,662 14,561 (1,188) 17,182 78,701 30,521
~48 REGULATORY ASSETS
~4M 4M DEFERRED CHARGES TOTAL See A'otes to Consolidated Financial Statements.
~6L2.'5 22
IAhfAMICHIGANPOWER COMPANY AND SUBSIDIARIES CAPITALIZATION AND LIABILITIES mber 3
192R'99Z (in thousands)
CAP ITALIZATION:
Common Stock No Par Value:
Authorized
- 2,500,000 Shares Outstanding
- 1,400,000 Shares Paid-in Capital Retained Earnings Total Common Shareholder's Equity Cumulative Preferred Stock:
Not Subject to Mandatory Redemption Subject to Mandatory Redemption Long-term Debt TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning Other TOTAL OTHER NONCURRENT LIABILITIES 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 INCOME TAXES DEFERRED INVESTMENT TAX CREDITS DEFERRED GAIN ON SALE AND LEASEBACK-ROCKPORT PLANT UNIT 2 DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 3)
TOTAL See Notes to Consolidated Financial Statement's.
56,584 732,605
~~~5~4 1,042,343 9,273 68,445
~4
~~JJK9.
445,934 35,000 108,700 53,187 37,647 35,161 15,279 9,667 4~)
~4~41
'Q3.
56,584 732,472
~78 4
1,067,870 9,435 68,445
~~4 381,016
~~2
~~36 35,000 119,600 36,729 31,665 46,850 15,741 34,033
'i2~E 4
23
Consolidated Statements of Cash Flows OPERATING, ACTIVITIES:
Net Income Adjustments for Noncash Items:
Depreciation and Amortization Amortization of Rockport Plant Unit 1
Phase-in Plan Deferrals Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses (net)
Deferred Federal Income Taxes Deferred Investment Tax Credits Over (Under)-recovery of Fuel and Purchased Power Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net)
Fuel, Materials and Supplies Accrued Utility Revenues Accounts Payable Taxes Accrued Payment of Disputed Tax and Interest Related to COLI Other (net)
Net Cash Flows From Operating Activi.ties 12RZ (in thousands) 149,209 14,142 17,905 (8,266)
(46,846) 5,376 (2,983)
(6,756) 22,440 (11,689)
(53,628)
~~7)
~~2K'M.
148,630 11,871 (15,967) 3,922 (8,428)
(22,812)
(10,456) 5,168 7,774 6,502 (18,550)
~57 96,628 146,740
$ 157,153 148,123 15,644 7,662 (24,687)
(8,729) 12,477 (10,235) 903 5,642 1,186 (6,296)
~45
)
INVESTING ACTIVITIES:
Construction Expenditures Proceeds from Sales of Property and Other Net Cash Flows Used For Investing Activities (147,627)
~44
~4~2)
(122,360)
(95,046)
~26.
~~44)
~>2 U2)
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 170,675 (120)
(55,000)
(10,900)
(117,464)
~4~)
47,728 (78,877)
(50,000) 76,100 (131,260)
)
r~r54
)
Upp~4 38,579 (30,568)
(46,091)
(46,475)
(112,508)
~LQR)
~
~L Kl)
Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents January 1
Cash and Cash Equivalents December 31 See Notes to Consol idated Financial Statements.
6,605 (2,373) 5JKG (5,490).
IANAMICHIGANPOWER COMPANY AND SUBSIDIARIES 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 4.12X Series 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
/Yotes to Consolidated Financial Statements.
$278,814
~96 8
117,464 247 67 79 985 1,266 834 1,255 122,197 Y
r 3292 (in thousands)
$269,071
~4 ~4 131,260 249 88 80 985 1,266 834 1,255 136,017
~8
$ 235,107
~57 53 112,508 495 273 165 2,360 1,875 2,205 2,063 122,475
~4 25
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Regulation 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,
- purchase, sale, transmission and distribution of electric power to 554,000 retail customers in its service territory in northern and eastern Indiana and a
portion of southwestern Michigan and conducts business as American Electric Power (AEP).
The Company supplies electric power to the AEP System Power Pool (Power Pool) and shares the revenues and costs of Power Pool'holesale sales to utility systems and power marketers.
The Company also sells wholesale power to municipalities and electric cooperatives.
As a
member of the Power Pool and a signatory company to the AEP System Transmission Equalization Agreement, the Company's gener ation and transmission facilities are operated in conjunction with the facilities of certain other affiliated utilities as an integrated utility system.
The Company has two wholly-owned subsidiaries, that were formerly engaged in coal-mining operations which are consolidated in these financial statements, Blackhawk 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.
The Company's River Transportation Division provided barging services to affiliated and unaffiliated companies.
As a
subsidiary of AEP Co.,
Inc.,
the Company is subject to the regulation of the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (1935 Act).
Retail rates are regulated by the Indiana Utility Regulatory Commission (IURC) and the Michigan Public Service Commission (MPSC).
The Federal Energy Regulatory Commission (FERC) regulates wholesale rates.
Principles of Consolidation The consolidated financial statements include the
- revenues, expenses, cash
- flows, assets, liabilities and equity of I&M and its wholly-owned subsidiaries.
Significant intercompany items are eliminated in consolidation.
Basis of Accounting As a
cost-based rate-regulated
- entity, I&M's 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) 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 of Estimates The preparation of these financi al statements in conformi ty with generally accepted accounting principles requires in certain 26
IANAMICHIGANPOWER COMPANY AND SUBSIDIARIES instances the use of estimates.
Actual results could differ from those e'stimates.
Vdi 1ity Plant AllopIance for Funds Used During Construction CAFVDC)
AFUDC is a
noncash nonoperating income item that is capitalized and recovered through depreciation over the service life of utility plant.
It represents the estimated cost of borrowed and equity funds used to finance construction projects.
The amounts of AFUDC for 1998, 1997 and 1996 were not significant.
Depreciation and Amortization Depreciation of electric utility plant is provided on a straight-line basis over the estimated useful lives of utility plant and is calculated largely through the use of composite rates by functional class.
The annual composite depreciation rates for
- 1998, 1997 and 1996 are as follows:
Functional Class
~rMrlUK3X Productionr Steam-Huclear Steam-Fossil-Fired Hydroelectric-Conventional Transmission Distribution General Annual Composite 1222 12K 3.4%
3.4$
3.4X 4.4$
4.4X 4.4X 3.4$
3.2X 3.2$
1.9X 1.9X 1.9$
4.2X 4.2X 4.2$
3.8X 3.8X 3.8X Electric utility plant is stated at ori ginal cost and is generally subject to first mortgage 1 iens.
Additions, major replacements and betterments are added to the plant
~ accounts.
Retirements of plant are deducted from the electric utility plant in service account and are deducted from accumulated depreciation together with associated lemoval
- costs, net of salvage.
The costs of
- labor, materials and overheads incurred to operate and maintain utility plant are included in operating expenses.
Amounts for the demolition and removal of non-nuclear plant are charged to the accumulated provision for depreciation and recovered through depreciation charges included in rates.
The accounting and rate-making treatment afforded nuclear decommissioning costs and nuclear fuel disposal costs are discussed in Note 3.
Cash and Cash Equivalents Cash and cash equivalents include temporary cash investments with original maturities of three months or less.
Operating Revenues 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 state 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 Indi ana jul i sdi cti on, the fuel cl ause mechani sm provides for the refunding of the excess earnings to ratepayers.
FERC wholesale jurisdictional fuel cost changes are expensed and billed as incurred.
Derivative Financial Instruments During 1998, the AEP Power Pool substantially increased the volume of its power marketing and trading transactions (trading activities) in which the Company shares.
Trading activities involve the sale of electricity under physical forward contracts at fixed and variable prices and the trading of electricity contracts including exchange traded futures and options and over-the-counter options and swaps.
The majority of these transactions represent physical forward contracts 27
in the AEP System's traditional marketing area and are typical ly settled by entering into offsetting contracts.
The net revenues from these transactions are included in operating revenues for ratemaking, accounting and financial
'nd regulatory reporting purposes.
income.
Certain prior year amounts have been reclassified to conform to current year presentation.'uch reclassifications had no impact on previously reported net income.
Levelization of Nuclear Refueling Outage Costs In addition the AEP Power Pool enters into transactions for the purchase and sale of electricity
- options, futures and
- swaps, and for the forward purchase and sale of electricity outside of the AEP Power Pool's traditional marketing area.
These non-regulated trading activities are included in nonoperating income and accounted for on a
mark-to-market basis.
The unrealized mark-to-market gains and losses from such non-regulated trading activity are reported as assets and liabilities, respectively.
The Company enters into forward contracts to manage the exposure to unfavorable changes in the cost of debt to be issued.
These anticipatory debt instruments are entered into in order to manage the change in interest rates between the time a debt offering is initiated and the issuance of the debt (usually a
period of 60 days).
Any resultant gains or losses are deferred and amortized over the life of the debt issuance.
There were no such forward contracts outstanding at December 31, 1998 or 1997.
Incremental operation and maintenance costs associated with refueling outages at the Company's Donald C.
Cook Nuclear Plant (Cook Plant) are deferred commensurate with their rate-making treatment and amortized over the period beginning with the commencement of an outage and ending with the beginning of the next outage.
Income Taxes The Company follows the liability method of accounting for income taxes as prescribed by SFAS
- 109, "Accounting for Income Taxes."
Under the 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 provided with related regulatory assets and liabilities i n accordance with SFAS 71.
Investment Tax Credits See Note 7
Financial Instruments, Credit and Risk Management for further discussion.
Reel assi fica tion In the fourth quarter of 1998 the Company changed the presentation of its trading activities from a
gross basis (purchases and sales reported separately) to a net basis (purchases and sales are reported on a
net basis as revenues).
This reclassification had no impact on net Investment tax credits have been accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a
deferral basis.
Investment tax credits that have been deferred are being amortized over the life of regulated plant investment.
Oebt and Preferred Shock Gains and losses from the reacquisition of debt are deferred as 28
DIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES regulatory assets and amortized over the remaining term of the reacquired debt i'n 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 debt issuance expenses are deferred and amortized over the term of the related
- debt, with the amortization included in interest charges.
Other Property and Investments Other pr operty and investments are stated at cost.
Comprehensive Income There were no material differences between net income and comprehensive income.
2.
~PAN 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 the cost of preferred stock reacquired is credited to paid-in capital and amortized to retained earnings.
Nuclear Decommissioning and Spent Nuclear Fuel Oisposal Trust Funds Securities held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel (SNF) are recorded at market value in accordance with SFAS
- 115, "Accounting for Certain Investments in Debt and Equity Securities."
Securities in the trust funds have been classified as available-for-sale due to their long-term purpose.
Due to the rate-making
- process, adjustments for unrealized gains and losses are not reported in equity but result in adjustments to the liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds.
In accordance with SFAS 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 in the same accounting period.
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 71 requires that the Company's regulated rates be cost-based and recovery of regulatory assets must be probable.
Management has reviewed the evidence currently available and concluded that the Company continues to meet the requirements to apply SFAS 71.
In the event a
portion of the Company's business no longer met these requirements, that is, its rates were no longer cost-based, regulatory assets and liabilities would have to be written off for that portion of the business and tangible assets 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 cost.
29
Recognized regulatory assets and liabilities are comprised of the following:
m 122K 122Z (in thousands)
Regulatory Assets:
Amounts Due From Customers for Future Income Taxes Unrecovered Fuel and Purchased Pover Department of Energy Decontamination and Decoavnissioning Assessment Kuclear Refueling Outage Cost Levelization Unamortized Loss On Reacquired Debt Other Total Regulatory Asset Regulatory Liabilities:
Deferred Investment Tax Credits Other*
Total Regulatory Liabilities
$ 259,641
$277,966 65.308 18,462 38,898 42,648 17,630 31,772 16,434 17,210
~~4
~4~4
~4~4
$ 129,779
$ 138,045
~iE ~R At January 1,
1997 rate phase-in plan deferrals existed for the Rockport Plant.
Rate phase-in plans in the Company's Indiana and FERC jurisdictions provided for the recover y and straight-1 ine amor tization 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
$ 15.6 million in 1996.
~ Included in Deferred Credits on Consolidated Balance Sheets.
The Rockport Plant consists of two 1,300 megawatt (mw) coal-fired units.
I'M and AEP Generating Company (AEGCo),
an affiliate, each own 50K of one unit (Rockport 1) and each lease a
50X 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.
3.
Construction and Other Commitments Substantial construction commitments have been made to support the Company's utility operations including the replacement of the Cook Plant Unit 1 steam generators.
Such commitments do not include any expenditures for new generating capacity.
Construction program expenditures for 1999-2001 are estimated to be
$ 366 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.
See Note 4 for changes in the fuel clause mechanism in the Indiana jurisdiction proposed in a settlement agreement.
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 all of an affiliate's share, 50X of the 2,600 mw Rockport Plant
- capacity, unless it is sold to other utilities.
The affiliate has a
long-term unit power agreement for the sale of 455 mw to an unaffiliated utility.
Revenues received under this agreement (which expires at the end of 1999) were
$ 70 million in 1998.
An agreement between the affiliate which owns Rockport Plant and another affiliate provides for the sales of 390 mw of capacity to that affiliate through 2004.
The Company sells under contract up to 250 mw of its Rockport Plant capacity to an unaffiliated utility.
The contract expires in 2009.
30
I IANAMICHIGAIVPOWER COMPANY AND SUBSIDIARIES Nuclear Plant
~
I&H owns 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 (US), the resultant liability could be substantial.
By agreement I&H 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 in rates is not possible, results of operations, cash flows and financial condition would be negatively affected.
Nuclear Plant'hutdown I&M shut down both units of the Cook Plant in September 1997 due to questions, which arose during a
NRC architect engineer design inspection, regarding the operability of certain safety systems.
The NRC issued a
Confirmatory Action Letter in September 1997 requiring I&H to address the issues identified in the letter.
I&H is working with the NRC to resolve the remaining open issue in the letter.
In January 1999 I&H announced that it will conduct additional engineering reviews at the Cook Plant that will delay restart of the units.
Previously, the units were scheduled to return to service at the end of the first and second quarters of 1999.
The decision to delay restart resulted from internal assessments that indicated a
need to conduct expanded system readiness reviews.
A new restart schedule will be developed based on the results of the expanded reviews and should be available in June 1999.
When maintenance and other activities required for restart are
- complete, I&M will seek concurrence from the NRC to return the Cook Plant to service.
Until these additional reviews are completed, management is unable to determine when the units will be returned to service.
Unless the costs of the extended outage and
'estart efforts are recovered from customers, there would be a material adverse effect on results of operations, cash flows and possibly financial condition.
The costs incurred in 1997 and 1998 for restart of the Cook units were
$ 6 million and
$ 78
- million, respectively, and were recorded as operation and maintenance expense.
Reductions in other operation and maintenance expenses partially offset these costs.
Currently incremental restart expenses are approximately
$ 12 million a month.
In April 1998 the NRC notified I&H that it had convened a
Restar t Panel for Cook Plant.
A list of required restart activities was provided by the NRC in July 1998 and in October the NRC expanded the list.
In order to identify and resolve the issues necessary to restart the Cook
- units, I&M is and will be meeting with the Panel on a
regular
- basis, until the units are returned to service.
In July 1998 IEH received an "adverse trend letter" from the NRC indicating that NRC senior managers determined that there had been a slow decline in performance at the Cook Plant during the 18 month period preceding the letter.
The letter indicated that the NRC will closely monitor efforts to address issues at Cook Plant through additional inspection activities.
In October 31
1998 the NRC issued II%M a Notice of Violation and proposed a
$ 500,000 civil penalty for alleged violations at the Cook Plant discovered during five inspections conducted between August 1997 and April 1998.
IICM paid the penalty.
recovery of the replacement costs is
- denied, future results of operations and cash flows would be adversely affected by the writeoff of the regulatory asset.
Nuclear Incident Liability The cost of electricity supplied to certain retail customers rose due to the extended outage since higher cost coal-fired generation and coal based purchased power were substituted for low cost nuclear generation.
IICM's Indiana and Michigan retail jurisdictional fuel cost recovery mechanisms permit the
- recovery, subject to regulatory commission review and
- approval, of changes in fuel costs including the fuel component of purchased power in the Indiana jurisdiction and changes in replacement power in the Michigan jurisdiction.
The IURC
- approved, subject to future reconciliation or
- refund, agreements authorizing
- IICM, during the billing months of July 1998 through March
- 1999, to include in rates a
fuel cost adjustment factor less than that requested by IICM.
The agreements provide the parties to the proceedings with the opportunity to conduct discovery regarding certain issues that were raised in the proceedings, including the appropriateness of the recovery of replacement energy cost due to the extended Cook Plant
- outage, in anticipation of resolving the issues in a
future fuel cost adjustment proceeding.
A regulatory asset in the amount of
$ 65 million of replacement energy costs has been recorded at Oecember 31, 1998.
See Note 4 for discussion of proposed settlement agreement for the Indiana jurisdiction.
Hi stor i cal 1 y, the Company has been permitted to recover through the fuel recovery mechanism the cost of replacement energy during outages.
Management believes that it should be allowed to recover the deferred Cook replacement energy costs; however, if Publ i c 1 i abi1 ity i s 1 imited by law to
$ 9 billion should an incident occur at any licensed reactor in the US.
Commercially available insurance provides
$ 200 million of coverage.
In the event of a nuclear incident at any nuclear plant in the US the remainder of the liability would be provided by a
deferred premium assessment of
$88 million on each licensed reactor payable in annual installments of
$ 10 million.
As a
- result, IICM could be assessed
$ 176 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 billion of property
- damage, decommissioning and decontamination coverage for Cook Plant.
Additional insurance provides coverage for extra costs resulting from a
prolonged accidental Cook Plant outage.
Some of the policies have deferred premium provisions which could be triggered by losses in excess of the insurer's resources.
The losses could result from claims at the Cook Plant or certain other unaffiliated nuclear units.
The Company could be assessed up to
$23.2 million annually under these policies.
SNF Disposal Federal law provides for government responsibility for permanent SNF disposal and assesses nuclear plant owners fees for SNF disposal.
A fee of one mill per kilowatthour for fuel consumed after April 6, 1983 is being collected from customers and remitted to the US 32
IANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Treasury.
Fees and related interest of
$ 190 million for fuel consumed pri or to April 7,
1983 have been r ecor ded as long-term debt.
IKN 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,
- 1998, funds collected from customers towards payment of the pre-April 1983 fee and related earnings thereon approximate the,liability.
Oecommissioning and Los Level Paste Accumulation Disposal Decommissioning costs are being 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 estimated cost of decommissioning and low level radioactive 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 SNF may need to be stored at the plant site 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 decommission-ing costs.
The Company is recovering estimated decommissioning costs in its three rate-making jurisdictions based on at least the lower end of the range in the most recent decommissioning study at the time of the last rate proceeding.
The Company records decommissioning costs in other operation expense and records a noncurr ent liability equal to the decommissioning cost recovered in rates; such amount was
$ 29 million in 1998,
$ 28 million in 1997 and
$ 27 million in 1996.
Decommissioning costs recovered from customers are deposited in external
- trusts, which are described in Note 7.
Trust fund earnings increase the fund assets and the recorded liability and decrease the amount needed to be recovered from ratepayer s.
During 1998 the Company withdrew
$ 3 million from the trust funds and expects to withdraw
$ 8 million in 1999 for decommissioning the original steam generators removed from Unit 2.
At December 31, 1998 and
- 1997, the Company has recognized a
decommissioning liability of
$ 446 million and
$381
- million, respectively.
Air guality On September 24,
- 1998, the US Environmental Protection Agency (Federal EPA) finalized rules which require reductions in nitrogen oxides (NOx) emissions in 22 eastern
- states, including the states in which the generating plants of the Company and its AEP Power Pool affiliates are located.
The implementation of the final rules would be achieved thr ough the revision of state implementation plans (SIPs) by September 1999.
SIPs are a procedural method used by each state to comply with Federal EPA rules.
The final rules anticipate the imposition of a
NOx reduction on utility sources of approximately 85K below 1990 emission levels by the year 2003.
On October 30,
- 1998, a
number of utilities, including the Company and the other operating companies of the AEP
- System, filed petitions in the US Court of Appeals for the District of Columbia Circuit seeking a review of the final rules.
Should the states fail to adopt the required revisions to their SIPs within one year of the date of the final rules (September 24, 1999),
Federal EPA has proposed to implement a federal plan to accomplish the NOx reductions.
Federal EPA also proposed the approval of portions of petitions filed by eight northeastern states that would result in imposition of NOx emission reductions on utility and industrial sources in 33
upwind midwestern states.
These reductions are substantially the same as those required by the final NOx rules and could be adopted by Federal EPA in the event the states fail to implement SIPs in accordance with the final rules.
Prel iminary estimates indi cate that compliance could result in required capital expenditures of approximately
$ 169 million.
Compliance costs cannot be estimated with certainty and the actual costs incurred to comply could be significantly different from this preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions.
Unless such costs are recovered from customers, they would have a
material adverse effect on results of operations, cash flows and possibly financial condition.
deductions for taxable years 1991-97 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount.
The payments to the IRS are included on the balance sheet in other property and investments pending the resolution of this matter.
The Company will seek
- refund, either administratively or through litigation, of all amounts paid plus interest.
In order to resolve this issue without further
- delay, on March 24, 1998, the Company filed suit against the US in the US District Court for the Southern District of Ohio.
Management believes that it has a meritorious position and will vigorously pursue this lawsuit.
In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows.
Litigation The Inter nal Revenue Servi ce
( I RS) agents auditing the AEP System's consolidated federal income tax returns for the years 1991 to 1993 requested a ruling from their National Office that certain interest deductions claimed by the Company relating to a
corporate owned life insurance (COLI) program should not be allowed.
As a result of a suit filed by the Company in US District Court (discussed below) the request for ruling was withdrawn by the IRS agents.
Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96.
A disallowance of the COLI interest deductions through December 31, 1998 would reduce earnings by approximately
$ 66 million (including interest).
The Company has made no provision for any possible adverse earnings impact from this matter.
In 1998 the Company made payments of taxes and interest attributable to COLI interest The Company is involved in a
number of other 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 and financial condition.
4.
NT V NT M NT On March 16, 1999 a
settlement agreement was filed with the IURC resolving all matters related to the reasonableness of fuel costs and all outage issues during an extended outage of the Cook Plant.
The settlement agreement, which is subject to IURC approval, provides
- for, among other things, a credit of
$ 55 million to Indiana retail customers; authorization to defer any unrecovered fuel revenues accrued between September 9,
1997 and December 31, 1999 including the
$ 55 million; authorization to defer up to
$ 150 million of incremental operation
I ANA MICHIGANPOWER COMPANY AND SUBSIDIARIES and maintenance restart costs for the Cook Plant above the base rate level incurred during 1999; amortization of the fuel recoveries and restart cost deferrals over a
five-year period ending December 31, 2003; a freeze in base rates though December 31, 2003; and a
cap on fuel recovery charges through March 1,
2004.
The
$ 55 million credit will be refunded through customer's bills during the months of July, August and September 1999.
If the IURC does not approve the settlement, the issue of recovery of replacement energy costs would be resolved through regulatory hearings.
Unless the costs of the extended outage and restart efforts are recovered from customers, there would be a material adverse effect on results of operations, cash
- flows, and possibly financial condition.
5.
Benefits and costs of the AEP System's generating plants are shared by members of the AEP Power Pool of which the Company is a member.
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 AEP Power Pool members based on their relative peak demands and generating reserves.
AEP Power Pool
.members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool.
The Company is a net supplier to the AEP Power Pool
- and, therefore, receives capacity credits from the AEP Power Pool.
Operating revenues include revenues for capacity and energy Total
~37 56 QQ~4
~5~756 Purchased power expense includes charges of
$ 125.2 million in
- 1998,
$ 51 million in 1997 and
$34.5 million in 1996 for energy received from the AEP Power Pool.
Power marketing and trading operations, which are described in Note 1,
are conducted by the AEP Power Pool and shared with the Company.
The Company's operating
- revenues, purchased power expense and nonoperating income include amounts for power marketing and trading allocated by the AEP Power Pool as follows:
Ih 1222 122l 1299.
((n thousands)
Operat(ng Revenues
$ 124,973
$ 74,895
$73,424 Purchased Power Expense 71,588 15,415 8,098 Honoperat(ng Loss (7,122)
(61)
The cost of Rockport Plant power purchased from AEGCo, an affiliated company that is not a
member of the AEP Power
- Pool, was included in purchased power expense in the amounts of
$86.2
- million,
$87.5 million and
$85.4 million in
- 1998, 1997 and 1996, respectively.
The cost of power purchased from Ohio Valley Electric Corporation, an affiliated company that is not a
member of the AEP Power Pool, was included in purchased power expense in the amounts of
$ 14.3 million,
$ 11 million and
$ 10.7 million in
- 1998, 1997 and 1996, respectively.
The Company operates the Rockport Plant and bills AEGCo for its share of operating costs.
supplied to the AEP Power Pool as follows:
1222 1222 12K
((n thousands)
Capac(ty Revenues
$ 33,011
$ 53.282
$ 57.594 Energy Revenues
~4 5
~4 il MEGAL 35
AEP System companies participate in the AEP System Transmi ssi on 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
$44. 1
- million,
$46.1 million and
$46.3 million in
- 1998, 1997 and
- 1996, respectively.
Revenues from providing barging services were recorded in nonoperating income as follows:
122k 122Z 12K (5n thousands) 6.
Effective December 31, 1998 the Company adopted SFAS
- 131, "Disclosures about Segments of an Enterprise and Related Information".
The Company has one reportable
- segment, a
regulated vertically integrated electricity generation and energy delivery business.
All other activities are insignificant.
The Company's operations are managed on an integrated basis because of the substantial impact of bundled cost-based rates and regulatory oversight on business processes, cost structures and operating results.
Aggregated in the regulated electric utility segment is the power marketing and trading activities that are discussed in Note 1
and the Company's barging activities.
For the years ended December 31,
- 1998, 1997 and
- 1996, all revenues are derived in the US.
Affflfated Coepanfes 523,494 524,427 522,740 Unaffflfated CNapan5es ~4 Total
~35 984 gg 810
~56 7..
N M NT R
T AN American Electric Power Service Corporation (AEPSC) provides certain managerial and professional services to AEP System companies including the Company.
The costs of the services are billed by AEPSC to its affiliated clients on a
direct-charge basis whenever possible and on reasonable bases of proration for shared services.
The billing 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.
The Company is subject to market risk as a
result of changes in electricity commodity prices and interest rates.
The Company participates in the AEP Power Pool's power marketing and trading operation that manages the exposure to electricity commodity price movements using physical forward purchase and sale contracts at fixed and variable
- prices, and financial derivative instruments including exchange traded futures and options, over-the-counter
- options, swaps and other financial derivative contracts at both fixed and variable prices.
Physical forward electricity contracts within the AEP Power Pool's traditional marketing area are recorded on a net basis as operating revenues in the month when the physical contract settles.
The Company's share of the net gains from these regulated transactions for the year ended December 31, 1998 was
$ 21 million.
36
IANAMICHIGANPOWER COMPANy'ND SUBSIDIARIES Physical forward electricity contracts outside the AEP Power Pool's traditional marketing area and all financial electricity trading transactions including exchange traded contracts that are marked to market and recorded in nonoperating income.
The Company's share of the net losses from these non-regulated tl'ading transactions for the year ended December 31, 1998 was
$ 7 million.
The unrealized mark-to-mar ket gains and losses from such trading of financial instruments are reported as assets and liabilities, respectively.
These activities were not material in prior periods.
The Company is exposed to risk from changes in interest rates primarily due to short-term and long-term borrowings used to fund its business operations.
The debt portfolio has both fixed and variable interest rates with terms from one day to forty years and an average duration of six years at December 31, 1998.
A near term change in interest rates should not materially affect results of operations or financial position since the Company would not expect to liquidate its entire debt portfolio in a
one year holding period.
Also since the,Company's rates are cost-based regulated, the risk of interest rate changes on debt used to finance regulated operations is mitigated.
Market Va7(Iat ion The book value 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.
The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the Company's best estimate of its fair value.
The book value amounts and fair values of the Company's share of-significant financial instruments at Non-Derivatives 1998 Long-term Debt Preferred Stock 1997
~ova1ue
~F1r u
ue (in thousands)
$ 1,175,800
$ 1,235,200 68,400 72,600 Long-ters Debt Preferred Stock Derivatives 1998 1.049,200 1,094 '00 68,400 73,300 Q~fn
( 1n thousands)
~~ri Physical s Options Swaps
$ 8,700 6 '00 600
$ 7,700 15,300 200 fllect t, Futures Physicals Options Swaps (1,300)
(300)
(9,400)
(8,800)
(5,700)
(15,200)
(1,400)
(400)
At December 31, 1998 the notional amounts of the Company's nonregulated electric trading physical forward contract purchases and sales are 1,912 Gigawatt hours December 31, 1998 and 1997 are summa ri zed in the fol 1 owing tabl e.
The fair values of long-term debt and preferred stock are based on quoted market prices for the same or similar issues and the current dividend or interests rates offered for instruments of the same remaining maturities.
The fail value of those financial instruments that are marked-to-market are based on management's best estimates using over-the-counter quotations, exchange
- plices, volatility factors and valuation methodology.
The estimates presented her ein are not necessarily indicative of the amounts that the Company could realize in a
current market exchange.
At December 31, 1997 the notional amounts and fair values of derivatives were not material.
37
(Gwh) and 2,044
- Gwh, respectively; the notional amounts for fixed priced swaps purchases and sales are 70 Gwh and 75
- Gwh, respectively; and the notional amounts for options to purchase and to sell are 1,381 Gwh and 992
- Gwh, respectively.
The Company has a net long position of 74 Gwh for electric future contracts.
At December 31, 1998 the fair value of the assets and liabilities related to the wholesale electric forward contracts was
$ 69 million and
$ 67
- million, respectively.
The related notional amounts were 9,094 Gwh for purchases and 9,280 Gwh for sales.
The average fair value amounts outstanding duling the period were
$ 175 million of assets and
$ 167 million of liabilities.
Credit and Risk management In addition to market risk associated with price movements, the Company through the AEP Power Pool is also subject to the credit risk inherent in its risk management activities.
Credit risk refers to the financial risk arising from commercial transactions and/or the intrinsic financial value of contractual agreements with trading counter
- parties, by which there exists a
potential risk of nonperformance.
The AEP Power Pool has established and enforced credit policies that minimize this risk.
The AEP Power Pool accepts as counter parties to
- forwards, futures, and other derivative contracts primarily those entities that are classified as Investment
- Grade, or those that can be considered as such due to the effective placement of credit enhancements and/or collateral agreements.
Investment grade is the designation given to the foul highest debt rating categories (ice.,
- AAA, AA, A,
BBB) of the major rating
- services, e.g.,
ratings BBB-and above at Standard
& Poor's and Baa3 and above at Hoody's.
Mhen adverse market conditions have the potential to negatively affect a
counter party's credit
- position, the AEP Power Pool requires further credit enhancements to mitigate lisk.
Since the formation of the power marketing and trading business in July of 1997, the Company has experienced no significant losses due to the credit risk associated with risk management activities; furthermore, the Company does not anticipate any future material effect on its results of operations, cash flow or financial condition as a
result of counter party nonperformance.
The Nuclear Decommissioning and Spent Nuclear fuel Disposal Trust Fund investments are recorded at market value in accordance with SFAS 115 and consist of tax-exempt municipal bonds and other securities.
At December 31, 1998 and 1997 the fair values of trust fund investments were
$ 648 million and
$ 566
- million, respectively.
Accumulated gross unrealized holding gains were
$ 65 million and
$ 41 million and accumulated gross unrealized holding losses were
$ 1. 1 million and
$ 1 '
million at December 31, 1998 and 1997, respectively.
The change in market value in 1998, 1997 and 1996 was a net unrealized holding gain of
$ 24 million,
$ 19. 1 million and
$ 2.6 million, I'espectively.
The trust fund investments'ost basis by security type were:
Tax-Exempt Bonds Equity Securities Treasury Bonds Corporate Bonds
- Cash, Cash Equivalents and Interest Accrued Total 122K(in S326,239 95 '54 71,194 10,661
~49K DR4~0 122Z thousands)
$335,350 74,398 44 '00 9,167 Proceeds from sales and maturities of securities of
$225 million during 1998 resulted in
$8.2 Nuc1 ear Trust Funds Recorded a t Pfarket Value 38
I IANAMICHIGANPOWER COMPANY AND SUBSIDIARIES million of realized gains and
$ 2.8 million of realized losses.
Proceeds from sales and maturities of securities of
$ 147.3 million during 1997 resulted in
$ 3 '
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.
The cost of securities for determining realized gains and losses is original acquisition cost including amortized premiums and discounts.
1999 2000-2003 2004-2008 After 2000 Total 4106,316 157,224 175,751 KR 144!@F2 8.
During 1998 an internal evaluation of the power generation organization was conducted with a
goal of developing a
better organizational structure for a
competitive generation market.
The study was completed in October 1998.
In
- addition, a
review of energy delivery staffing levels was conducted in 1998.
As a
result approximately 80 power generation and energy delivery positions were identified for elimination.
At December 31,
- 1998, the year of maturity of trust fund investments, other than equity securities, was:
(fn thousands)
Severance accruals totaling
$3.7 million were recorded in December 1998 for reductions in power generation and energy delivery staffs and were charged to other operation expense in the Consolidated Statements of Income.
In the first quarter of 1999 the power generation and energy delivery staff reductions were made.
9.
NF P
N The Company and its subsidiaries participate in the AEP System qualified pension
- plan, a
defined benefit plan which covers all employees.
Net pension costs for the years ended December 31,
- 1998, 1997 and 1996 were
$ 2. 1
- million,
$2. 1 million and
$4. 1
- million, respectively.
Postretirement benefits other than pensions ar e provided for retired employees for medical and death benefits under an AEP System plan.
The Company's annual accrued costs for 1998, 1997 and 1996 were
$ 12 million,
$ 11.5 million and
$ 12.8, million, respectively.
A defined contribution employee savings plan required that the Company make contributions to the plan totaling
$ 4 million in 1998 and 1997 and
$3.7 million in 1996.
39
10.
The details of federal income taxes as reported are as follows:
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
$ 38.165 21,073
~le)
~~4 (594)
(3,168)
~>ZX)
~4~4)
~4~
n III I'22Z (in thousands)
$ 75,442 3,088
~~44 3,287 834
~4)
~4)
~74
$ 110,133 (24,730)
~24)
~i22 182 43
~!K)
~0)
~~8<>
The following is a reconciliation of the difference between the amount of federal income taxes computed by multiplying book income before federal income taxes by the statutory tax rate, and the amount of federal income taxes reported.
Net Income Federal Income Taxes Pre-tax Book Income Federal Income Tax on pre-tax Book Income at Statutory Rate (355)
Increase (Decrease) in Federal Income Tax Resulting From the Following Items:
Depreciation Corporate Owned Life Insurance Nuclear Fuel Disposal Costs Investment Tax Credits (net)
Other Total Federal Income Taxes as Reported Effective Federal Income Tax Rate
$ 96,628
&446K
$ 50'43 17,257 (3,263)
(3,397)
(8,266)
~4 4)
~4 Y
r nd III I'22Z (in thousands)
$ 146,740
&4M'VJL2H
$ 77,337 14,082 (3>348)
(3 '86)
(8'28)
~4)
~74
$ 157,153
~252
~4
$81,918 13 F 880 (2,178)
(3,096)
(8,729)
~4)
~7 The following tables show the elements of the net deferred tax liability and the significant temporary differences giving rise to such deferrals:
~8
~7 (in thousands)
Deferred Tax Assets Deferred Tax Liabilities Net Deferred Tax Liabilities
$ 226,118
$ 223,772
~~4) ~7~4)
Property Rel a ted Tempo ra ry Differences Amounts Due From Customers For Future Federal Income Taxes Deferred State Income Taxes Deferred Gain on Sale and Leaseback of Rockport Plant Unit 2 Accrued Nuclear Decommissioning Expense All Other (net)
Net Deferred Tax Liabilities
$ (460,077)
$ (471,898)
(69,102)
(62,302)
(74,282)
(65,679) 31,049 32,347 29,930 26,991
) ~7~)
am~88) kab5'>
77.8) 40
IAIVAMICHIGANPOWER COMPANY AND SUBSIDIARIES The Company and its subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System.
The allocation of the AEP System's curl ent 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 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 IRS all issues from the audits of the consolidated federal income tax returns for the years prior to 1991.
Returns for the years 1991 through 1996 are presently being audited by the IRS.
With the exception of interest deductions related to COLI, which are discussed under the
- heading, Litigation, in Note 3,
management is not aware of any issues for open tax years that upon final resolution are expected to have a
material adverse effect on results of operations.
Y
~
earnings, for the payment of cash dividends on common stock.
At December 31,
- 1998,
$ 5.9 million of retained earnings were restricted.
Regulatory approval is required to pay dividends out of paid-in capital.
In
- 1998, 1997 and 1996 net changes to paid-in capital of
$ 133,000,
$ 1,200,000 and
$ 170,000 respectively, represented gains and expenses associated with cumulative preferred stock transactions.
12.
P H
Y NF MATI N:
Y nd mb 12'22 12K (fn thousands)
Cash was pa(d for:
Interest (net of capital(zed amounts)
Income Taxes 566,313 36,413 S 62,274 120,212 S 64,117 125,707 Honcash Acqufs(t(ons Under Capftal Leases 9,658 111,395 48,305 In connection with the 1996 early termination of a western coal land sublease the Company will receive cash payments from the lessee of
$30.8 million over a
ten-year period which was recorded at a
net present value of
$ 22.8 million.
The long-term portion of this receivable is recorded as other property and investments and the culrent portion is recorded as miscellaneous accounts receivable.
Hortgage indentures, charter provisions and orders of regulatory author ities place various restrictions on the use of retained 41
13.
At December 31, 1998, authorized shares of cumulative preferred stock were as follows:
2)~~l
$ 100 25 har th ri d
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 7.08K series not subject to mandatory redemption.
A. Cumulative Preferred Stock Not Subject to Mandatory Redemption:
Call Price December 31, Par
~~r ~
Giga 4-1/8X
$ 106.125
$ 100 4.56%
102 100 4.12K 102.728 100 Number of Shares Redeemed m
771 59,760 233 650 44,788 200 20,869 Shares Outstanding 59,236 14,562 18,931 m
3 1229 129Z (in thousands)
$ 5,924
$6,001 1,456 1,521 XK222 B. Cumulative Preferred Stock Subject to Mandatory Redemption:
Par
~a Number of Shares Redeemed r
0 mbr3 Shares Amoun cemb r 3 8
(in thousands) 5.90$ (b) 6-1/4X(b) 6.30K (b) 6-7/8%(c)
$ 100 100 100 100 233,000 97,500 217,550 117,500 167.000 202,500 132,450 182,500
$16,700 20,250 13,245
~68 445
$ 16,700 20,250 13,245
~68 445 (a)
Not callable until after 2002.
There are no aggregate sinking fund provisions through 2002.
A sinking fund provision requires the redemption of 15,000 shares in 2003.
(b) Commencing in 2004 and continuing 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 series outstanding under sinking 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)
Commencing in 2003 and continuing through the year
- 2007, a sinking fund will require the redemption of 15,000 shares each year and the redemption of the remaining shares outstanding on April 1, 2008, in each case at
$ 100 per share.
Shares redeemed in 1997 may be applied to meet the sinking fund requirement.
42
INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES 14.
control revenue bonds 'by governmental authorities as follows:
Long-term debt by major category was outstanding as follows:
1222 1227 (1n thousands)
First Hortgage Bonds Installment Purchase Contracts Senior Unsecured Hotes Other Long-term Debt (a)
Junior Debentures Less Portion Oue Hithin One Year 1
466,330 309,418 48,559 190,192
~6LZl(I 1,175,789 520,317 309,269 180,837
~KJD4 1,049,237 cembe 3
1222 122l (in thousands)
~%Ra Du City of Lawrenceburg, Ind1ana:
7.00 2015
- Apr11 1
5.90 2019
- Hovember 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, Indiana:
5.95 2009
- Hay 1
Unamortized D1scount Total
$ 25,000 52,000 50,000 40.000 50,000 50,000 45,000
~E)
L3304 8
$ 25,000 52,000 50 F 000 40,000 50,000 50,000 45,000 Total HJ4RZ62 F44'R (a)
Represents a
SHF disposal liability including 1nterest accrued payable to the Department of Energy.
See Hote 3.
First mortgage bonds out-standing were as follows:
(a)
(b)
A variable,interest rate 1s determined weekly.
The average weighted interest rate was 4.1X for 1998 and 4.3% for 1997.
An adjustable interest rate can be a daily,
- weekly, cosgaercial paper or term rate as designated by the Company.
A weekly rate was selected which ranged from 2.75 to 4.3% in 1998 and from 3.05 to 4.6%
in 1997 and averaged 3.6X and 3.8X during 1998 and 1997
'espectively.
1222 1227 (in thousands)
~Ra u
7.00 1998 - Hay 1
7.30 1999 - December 15 6.40 2000 - Harch 1
7.63 2001
- June 1
7.60 2002 - Hovember 1
7.70 2002
- December 15 6.80 2003
- July 1
6.55 2003
- October 1
6.10 2003
- Hovember 1
6.55 2004
- Harch 1
8.50 2022
- December 15 7.80 2023
- July 1
7.35 2023
- October 1
7.20 2024 - February 1
7.50 2024
- March 1
Unamortized Discount (net)
Less Portion Due llithin One Year Total 35,000 48,000 40,000 50 F 000 40,000 20,000 20,000 30 F 000 25,000 75,000 20,000 40,000 25,000 466,330
~KJHHI 14'%2K
$ 35,000 35,000 48,000 40,000 50,000 40,000 20,000 20,000 30,000 25,000 75,000 20,000 20,000 40,000 25,000
~~D 520,317
~AULD
~4'~7 Installment purchase contiacts have been entered into in connection with the issuance of pollution Certain indentures relating to the fiist 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.
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 seiies the principal is payable at the stated maturities or on the demand of the bondholders at periodic interest adjustment dates which occur weekly.
The variable rate bonds due in 2014 are supported by a
bank letter of credit which expires in 2002.
I&M 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, I&M has a
standby bond purchase agreement with a
bank that provides for the bank to purchase any bonds not remarketed.
The purchase agreement 43
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.
consisted December 31, 1998:
Commercial Paper Year-en'alance'Neighted Outstanding Average
~in Lhh)~n 6.2%
Outstanding short-term debt of:
In November 1998 the Company issued
$ 50,000,000 of 6.45X senior unsecui'ed notes due November 10, 2008.
The unamortized discount at December 31, 1998 was
$ 1,441,000.
December 31, 1997:
Notes Payable Commercial Paper Total
- 15. ~Q:
$ 56,410 H1KHQ 6.3X 6.8 6.6 Junior debentures are composed of the following:
m UZR l222 (in thousands) 8.00 2026 - Harch 31 7.60 2038
- June 30 Unamortized Discount Total
$ 40,000
$40,000 125.000 DH~
Inter est may be defer red 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.
At December 31,
- 1998, future annual long-term debt payments are as follows'mn (in thousands) 1999 35,000 2000 98,000 2001 40,000 2002 140,000 2003 70,000 Later Years Total Principal Amount 1,185.192 Unamortized Discount 1~41)
I Total II Short-term debt borrowings are limited by provisions of the 1935 Act to
$300 million.
Lines of credit are shared with AEP System companies and at December 31, 1998 and 1997 were available in the amounts of
$ 763 million and
$ 442
- million, respectively.
Facility fees of approximately 1/10 of 1X of the short-term lines of credit are required by the banks to maintain the lines of credit.
Lease rentals for both operating and capital leases are generally charged to operating expenses in accordance with rate-making treatment.
The components of rental costs are as follows:
Yar n
1998 1297 (in thousands)
Lease Payments on Operating Leases
$ 88,297
$ 92,067
$ 96,096 Amortization of Capital Leases 10,717 42,882 55 '89 Interest on Capital Leases MVZZ Total Lease Rental Costs MVL4 Q44~i 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 50K of the 1,300 mw Rockport 2 generating unit under an operating lease.
The lease has 24 years remaining and total minimum lease payments of
$ 1.8 billion.
The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases.
44
I NA MICHIGANPOWER COMPANY'ND SUBSIDIARIES Properties under capital leases and related obligations recorded on the Con'solidated Balance Sheets are as follows:
emb 12K 1222 (in thousands)
Future minimum lease payments consisted of the following at December 31, 1998:
Hon-Cancelable Capital Operating
~a
~ea (in thousands)
Electric Utility Plant Under Capital Leases:
Production Plant Distribution Plant General Plant:
Huclear Fuel (net of amort1zat1on)
Other Plant Total Electric Utility Plant Under Capital Leases Accumulated Amortizat1on Het Electric Utility Plant Under Capital Leases Other Property Under Capital Leases Accumulated Amortization Het Other Property Under Capital Leases Het Properties Under Capital Leases 5
8,850 5
9,218 14,645 14,660 103,939 103,939 187,436
~31 4
~5:~4%
189,085
~i(I 376672 40,746
~~4 119~4 51K~
1999 2000 2001 2002 2003 Later Years Total Future Minimum Lease Payments Less Estimated Interest Element Estimated Present Value of Future M1nimum Lease Payments Unamortized Huclear Fuel Total 5 15,807 14,371 12,524 18,521 9,141 98,992 98,729 97,494 95,778 95,685
~L2K 82,488 Mh232
~366 4
1 108,869(a) ~~4 5
Capital Lease Obligations*:
Honcurrent Liability Liability Due Uithin One Year Total Capital Lease Obligations
$ 176,760 5161,194 03~4 DR~)
- Represents the present value of future minimum lease payments.
The noncurrent portion of capital lease obligations is included in other noncurrent liabilities in the Consolidated Balance Sheets.
Properties under operating leases and related obligations are not included in the Consolidated Balance Sheets.
16.
T D
ART Y
I NF RUATI N:
N A
Quarterly Periods Het Operating Operating Income
~hC 4 (in thousands)
(a)
Excludes nuclear fuel rentals which are paid in proportion to heat produced and carrying charges on the unamortized nuclear fuel balance.
There are no minimum lease payment requirements for leased nuclear fuel.
1998 March 31 June 30 September 30 December 31 1997 March 31 June 30 September 30 December 31 5328,468 348,271 412,908 316,147 341,313 320,508 347,668 329,743 551.368 42,194 58,639 13,806 59,894 50,140 60,449 37,305 533,744 2'36 38,691 (4'43) 44,259 33,908 45,091 23,482 Fourth quarter 1998 operating income and net income declined primarily as a result of expenditures to prepare the nuclear units for restart.
See "Reclassification" in Note 1
regarding reclassification of prior period amounts.
45
OPERATING STATISTICS OPERATING REVENUES (in thousands):
Retail:
Residential:
Without Electric Heating With Electric Heating Total Residential Commercial Industrial Hiscellaneous Total. Retail Wholesale (sales for resale)
Total Revenues from Energy Sales Other 265,442
~UL2K 374,392 290,149 370,329 1,041,719
~L22l 1,363,490 237,475
~~HZ 348,022 264,031 332,218 950,736
~6~**
1,313,128**
232,212 343,768 253,750 312,777 916,740 899348 1,308,218 239,266
~(LLEW 348,770 256,319 298,256 R
909,827
~~4 1,267,268
~ ~4 227,358 334,881 247,938 291,527 880,662
~5889 1,233,551
~L2K Total Operating Revenues ~~
J1 339 ~** ~32~4
~~
Mal.292 SOURCES AND USES OF ENERGY (in millions of kilowatthours):
Sources:
Net Generated:
Fossil Fuel Nuclear Fuel Hydroelectric Total Net Generated Purchased and AEP Power Pool Total Sources Less:
- Losses, Company
- Use, Etc.
Net Sources Uses; Retail Sales:
Residential:
Without Electric Heating With Electric Heating Total Residential Commercial Industrial Miscellaneous Total Retail Wholesale Sales (sales for resale)
Total Uses 13,432
- 13,548 12 Kl 27,169 UK 2f7~
3,518
~Sly 5,134 4,540 7,755 17,515 ZRZ5 14,193 10,421 U2 24,747
~~+*
34,304**
~~44**
3,307
~ZH 5,075 4,349 7,541 17,047 g5~**
~45+**
13,304 16,396 29,799
~5/Q 37,380
~5 3,329
~911 5, 140 4,328 7,295 16,845 ZLZZ
~5M5 12,850 13,999 26,935
~QH 32,806
~ZQQ K
3,390
~lH 5,158 4,300 6,582 16,122 31 1K 13,022 9,291 22,408 5 757 28,165
~rK 3,210
~ZZZ 4,937 4,148 6,453
~8 15,620 11 HZ 26~6 During 1998 the Company's nuclear plant was shutdown for an extended outage which began in September 1997 to address certain safety concerns.
See Note 3.
- Reclassified
I NA MICHIGANPOWER COMPANY AND SUBSIDIARIES OPERATING STATISTICS (Concluded)
AVERAGE COST OF FUEL CONSUMED (in cents):
Per Million Btu:
Per Kilowatthour Generated:
130 1.21 89
.93 74
.80 78
.83 85
.90 RESIDENTIAL SERVICE - 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 15,922 10,566 17,583 10,560 6.74 7.29 6.25 6.86
$ 1,073.77
$ 1,099.34
$ 770 '0
$ 724.16 18,206 10,791 18,044 10,943 6.16 6.69 6.19 6.76
$ 1,121.41
$ 1,117.55
$ 721.76
$ 739 '9 17,907 10,572
$ 1,115.19
$ 717.17 6.23 6.78 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 375,929
~325.
378,757 1EL2l?
383,314
~49+
386,253 1KJ29 475,034 55,077 5,316
~22Z 479,129 55,869 5,345
~JQ9 484,806 57,311 5,484
~55.
488,331 58,720 5,437
~%6 537,224 542,163
~5 549,456 554,444 md '56 244.~
k4?-~4 53LZJK 372,473
<)~4 469,875 53,927 5,213 530,821
~4 47
DIVIDENDS AND PRICE RANGES OF CUMULATIVE PREFERRED STOCK B
Quarters (1998 and 1997)
($ 100 Par Value) 4-1/BX Series Dividends Paid Per Share Market Price
$ Per Share (CSE)
- High Low
$ 1.03125
$ 1.03125
$ 1.03125
$ 1.03125
$ 1.03125
$ 1.03125
$ 1.03125
$ 1.03125 4.56$ Series Dividends Paid Per Share Harket Price -
$ Per Share (OTC)
Ask - High Low Bfd High Low 4.12% Series Dividends Pafd Per Share Harket Price
$ Per Share (OTC)
Ask - High Low Bfd - High Low 5.90K Series Dividends Paid Per Share Market Price
$ Per Share (OTC)
Ask (high/low)
Bfd (high/low)
$ 1. 14
$ 1. 14
$ 1. 14
$ 1. 14 58-1/2 58-1/4 66 58-1/2 67-5/8 68 66 64
$ 1.03
$ 1.03
$ 1.03
$ 1.03 59 3/8 58-1/4 63-7/8 59-3/8 64-5/8 63-7/8 67-3/8 64-5/8
$ 1.475
$ 1.475
$ 1.475
$ 1.475
$ 1.14
$ 1.14
$ 1.14
$ 1.14 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 6-1/4X Series Dividends Paid Per Share Market Price -
$ Per Share (OTC)
Ask (high/low)
Bid (high/low)
$ 1.5625
$ 1.5625
$ 1.5625
$ 1.5625
$ 1.5625
$ 1.5625
$ 1.5625
$ 1.5625 6.30K Series Dividends Paid Per Share Market Price
$ Per Share (OTC)
Ask (high/low)
Bfd (high/low)
$ 1.575
$ 1.575
$ 1.575
$ 1.575
$ 1.575
$ 1.575
$ 1.575
$ 1.575 6-7/BX Series Dividends Paid Per Share Harket Price
$ Per Share (OTC)
Ask (high/low)
Bfd (high/low)
$ 1.71875
$ 1.71875
$ 1.71875
$ 1.71875
$ 1.71875
$ 1.71875
$ 1.71875
$ 1.71875 CSE
- Chicago Stock Exchange OTC
- Over-the-Counter Kote - The above bfd and asked quotatfons represent prices between dealers and do not represent actual transactions.
Market quotations provided by Hatfonal Quotation Bureau, Inc.
Dash indicated quotation not available.
48
NDIANAAIICHIGANPOWER COAIPANY INVESTOR INQUIRIES Investors should direct inquiries to Investor Services using the toll free number, 1-800-AEP-COMP (1-800-237-2667) or by writing to:
Investor Services American Electric Power Service Corporation 28th Floor 1 Riverside Plaza
- Columbus, OH 43215-2373 FORM 10-K ANNUAL REPORT The Annual Report (Form 10-K) to the Securities and Exchange Commission will be available in April 1999 at no cost to shareholders.
Please address requests for copies to:
Financial Reporting Division American Electric Power Service Corporation 26th Floor 1 Riverside Plaza
- Columbus, OH 43215-2373 TRANSFER AGENT AND REGISTRAR OF CUMULATIVE PREFERRED STOCK First Chicago Division, Equiserve P.O.
Box 2500 Jersey City, NJ 07303-2500 Phone number:
1-800-328-6955
Indiana Michigan Power Service Area and the American Electric Power System lAKE trl I c tt I G A8 MICH IGAN OHIO INDIANA WEST V I RG IN I A KENTUCKY VIRG INIA Indiana Michigan Power Co. area Other AEP operating companies'reas Q
Major power plant TENNESSEE O~
Clg printed on recycled paper
ATTACHMENT 2 TO AEP:NRC:09090 INDIANA MICHIGAN POWER COMPANY'S PROJECTED CASH FLOW FOR 1999
1999 Forecasted Internal Cash Flow 0 Millions Projected 1999 Net Income After Taxes Less: Dividends 99.5 114.4 (14.9)
Ad'ustments:
Depreciation and Amortization Deferred Operating Costs Deferred Federal Income Taxes and Investment Tax Credits AFUDC Other 148.5 (86.2) 4.6 (9.2)
(5.7)
Total Adjustments 52.0 Internal Cash Flow 37.1 Average Quarterly Cash Flow 9.3 Average Cash Balances and Short-Term Investments 2.9 Total 12.2 nukecf99.xls 5/14/99
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