ML17329A455
| ML17329A455 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 04/15/1992 |
| From: | Fitzpatrick E INDIANA MICHIGAN POWER CO. (FORMERLY INDIANA & MICHIG |
| To: | Murley T NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| AEP:NRC:0909H, AEP:NRC:909H, NUDOCS 9204200117 | |
| Download: ML17329A455 (41) | |
Text
ACCELERATED DT TRIBUTION DEMONS TION SYSTEM
)
REGULATORY INFORMATION DISTRIBUTION SYSTEM (RXDS)
ACCESSXON NBR:9204200117 DOC.DATE: 92/04/15 NOTARIZED:
NO DOCKET FACIL:50-315 Donald C.
Cook Nuclear Power Plant, Unit 1, Indiana M
05000315 50-316 Donald C.
Cook Nuclear Power Plant, Unit 2, Indiana M
05000316 AUTH.NAME AUTHOR AFFILIATION FXTZPATRICK,E.
(formerly Indiana 6 Michigan Ele RECIP.NAME RECIPIENT AFFXLIATION MURLEY,T.E.
Document Control Branch (Document Control Desk)
SUBJECT:
Forwards financial info projected cash flow for DISTRIBUTXON CODE:
M004D COPIES TITLE: 50.71(b)
Annual Financial NOTES from annual rept for 1991 6
1992.
RECEIVED:LTR ENCL SIZE:
Report RECXPIENT ID CODE/NAME PD3-1 PD INTERNAL: AEOD/DOA EXTERNAL: NRC PDR COPIES LTTR ENCL 1
1 1
1 1
1 RECIPIENT ID CODE/NAME STANG,J
~~4:~~
EG->'FILE 01 COPXES LTTR ENCL 1
0 1
1 D
R NOTE TO ALL"RIDS" RECIPIENTS:
D D
PLEASE HELP US TO REDUCE WASTE! CONTACT THE DOCUMENT CONTROL DESK, ROOlVI P 1-37 (EXT. 20079) TO ELIMINATEYOUR NAME FROM DISTRIBUTION LISTS FOR DOCUMENTS YOU DON'T NEED!
TOTAL NUMBER OF COPIES REQUIRED:
LTTR 5
ENCL 4
l 0
'i
~ t g4 W
1 rg J
indiana Mict(igah Power Company P.O. Box 16631 Columbus, OH 43216 MEHANA MCM635N PQMFR AEP:NRC:0909H 10 CFR 50.71(b) & 140.21(e)
Donald C.
Cook Nuclear Plant Unit Nos.
1 and 2
Docket Nos.
50-315 and 50-316 License Nos.
DPR-58 and DPR-74 FINANCIAL INFORMATION FOR INDIANAMICHIGAN POWER COMPANY U.S. Nuclear Regulatory Commission Attn:
Document Control Desk Washington, D.C.
20555 Attn:
T. E. Murley April 15, 1992
Dear Dr. Murley:
Enclosure 1 contains the Indiana Michigan Power Company's (I&M) annual report for 1991.
Enclosure 2
contains a
copy of I&M's projected cash flow for 1992.
These reports are submitted pursuant to 10 CFR 50.71(b) and 10 CFR 140.21(e).'his document has been prepared following Corporate procedures that incorporate a reasonable set of controls to ensure its accuracy and completeness prior to signature by the undersigned.
Sincerely, E.
E. Fitzp trick Vice President dfw Enclosures CC:
D. H. Williams, Jr.
A. A. Blind - Bridgman J.
R. Padgett G. Charnoff A. B. Davis - Region III NRC Resident Inspector
- Bridgman NFEM Section Chief
", '9204200117 9204i5 PDR ADOCK 050003i5 PDR
ENCLOSURE 1 TO AEP'NRC'0909H INDIANAMICHIGAN POWER COMPANY'S 1991 ANNUAL REPORT
Indiana Michigan Power Company 1991 Annual Report ANERlCAN ELECfRIC POWER
Contents
Background
of the Company Directors and Officers of the Company Selected Consolidated Financial Data Management's Discussion and Analysis of Results of Operations 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 Dividends and Price Ranges of Cumulative Preferred Stock
INDIANAMICHIGANPOWER COMPANY One Summit Squa
. Box 60, Fort Wayne, Indiana 46801 Background of the Company INDIANAMIGHIGAN PowER C0MPANY (the Company), a subsidiary of American Electric Power Company, Inc.
(AEP), is engaged in the generation, purchase, transmission and distribution of electric power. The Company was organized under the laws of Indiana on February 21, 1925, and is also authorized to transact business in Michigan and West Virginia. Its principal executive offices are in Fort Wayne, Indiana.
The Company has two wholly owned subsidiaries; they are Blackhawk Coal Company and Price River Coal Company, which were formerly engaged in coal-mining operations.
Blackhawk Coal Company currently
'eases 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 generating plants of the Company and affiliates. RTD also provides some barging services to unaffiliated companies.
The Company serves approximately 483,000 customers in northern and eastern Indiana and a portion of southwestern Michigan. Among the principal industries served are transportation equipment, primary metals, fabricated metal products, electrical and electronic machinery, and chemicals and allied products. In addition, the Company supplies wholesale electric power to other electric utilities, municipalities and electric cooperatives.
The Company's generating plants and important load centers are interconnected by a high-voltage trans-mission network. This network in turn is interconnected either directly or indirectly with the following other AEP System companies to form a single integrated power system: AEP Generating Company, Appalachian Power Company, Columbus Southern Power Company, Kentucky Power Company, Kingsport Power Company, Michigan Power Company, Ohio Power Company and Wheeling Power Company.
The Company is also interconnected with the following unaffiliated utilities: Central Illinois Public Service Company, The Cincinnati Gas 8
Electric Company, Commonwealth Edison Company, Consumers Power Company, Illinois Power Company, Indianapolis Power 8 Light Company, Louisville Gas and Electric Company, Northern Indiana Public Service Company, PSI Energy Inc. and Richmond Power 8 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). The Company shares generating and transmission capacity and the cost of such capacity with the other affiliated AEP System companies through the AEP System Power Pool and AEP Transmission Agreement.
Directors MARKA. BAILEY RICHARD E. DISBROVI WILLIAMN. 0 ONOFRIO E. LINN DRAPER, JR. (a)
ALLEN R. GLASSBURN (b)
WILLIAMJ. LHOTA GERALD P. MALONEY RICHARD C. MENGE DWIGHT I. PITTENGER (b)
WILLIAMF. POHLMAN (C)
RONALD E. PRATER (C)
DALE M. TRENARY (b)
WILLIAME. WALTERS (C)
W. S. WHITE, JR. (d)
DAVID H. WILLIAMS,JR.
Officers W. S. WHITE, JR. (d)
Chairman of the Board RICHARD E. DISBROW (e)
Chairman of the Board and Chief Fxecuti've Officer RICHARD C. MENGE President and Chief Operating Officer MILTON P. ALEXICH (f)
Vice President MARKA. BAILEY Vice President PETER J. DEMARIA(g)
Vice President and Treasurer WILLIAMN. 0'ONOFRIO Vice President A. JOSEPH DOWD Vice President E. LINN DRAPER, JR. (a)
Vice President EUGENE E. FITZPATRICK (It)
Vice President RICHARD F. HERING Vice President WILLIAMJ.
LHOTA Vice President GERALD P. MALONEY Vice President DAViD H. WILLIAMS,JR.
Vice President JOHN F. DILORENZO, JR.
Secretary ELIO BAFILE Assistant Secretary and Assistant Treasurer JEFFREY D. CROSS Assistant Secretary CARL J. MOOS Assistant Secretary JOHN B. SHINNOCK Assistant Secretary LEONARD V. ASSANTE Assistant Treasurer BRUCE M. BARBER Assistant Treasurer GERALD R. KNORR Assistant Treasurer As ol January f, f992 the current directors and ollicers ol Indiana Michigan Power Company were employees olAmerican Electric Power Service Corporation with eight exceptions: Messrs.
Balile, Bailey, D'Onolrio, Menge, Moos, Pohlman, Prater, and Walters, who were employees oi Indiana Michigan Power Company.
(a) Elected effective March 1, 1992 (b) Resigned April 23, 1991 (c) Elected April 23, 1991 (d) Resigned December 31, 1991 (e) Elected Chairman of the Board December 31, 1991 (f) Resigned April 1, 1991 (g) Elected Vice President April 23, 1991
,(h) Elected April 1, 1991
I Selected Consolidated Financial Data INDIANAMICHIGANPOWER COMPANY t
AND SIJBSIDIARIES Year Ended December 31, 1991 1990 1989 (in thousands) 1988 1987 INCOME STATEMENTS DATA:
OPERATING REVENUES OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME (Loss)
INCOME BEFORE INTEREST CHARGES.......
INTEREST CHARGES NET INCOME PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS APPLICABLE To COMMON STOCK..
210,396 32,930 243,326 106,181 224,310
~3,699) 215,443 43,454 198,136 7,592 205,728 89,413 223,046 56,828 279,874 113,508 166,366 20,955 258,897 107,092 220,611 85,325 151,805 18,848 137,145 18,048 116,315 15,587 135,286 15,417 119,869 100,728 119,097 132,957 145,411
$1,211,607
$1,257,089
$1,121,407
$1,053,994
$1,078,330 987,297 1,058,953 911,011 838,551 855,284 1991 1990 December 31, 1989 (in thousands) 1988 1987 BALANCESHEETS DATA:
ELECTRIC UTILITY PLANT ACCUMULATED DEPRECIATION AND AMORTIZATION NET ELECTRIC UTILITY PLANT TOTAL ASSETS
$4,078,336
$4,011,464
$3,918,616
$4,411,271
$4,153,281 1,503,761 1,403,871 1,292,430 1,218,060 1,118,254
$2,574,575
$2,607,593
$2,626,186
$3,193,211
$3,035,027
$3,573,847
$3,599,669
$4,229,812
$3,966,277
$3,920,163 COMMON STOCK AND PAID-IN CAPITAL..
RETAINED EARNINGS TOTAL COMMON SHAREOWNER S EQUITY.
CUMULATIVEPREFERRED STOCK:
NOT SUBJECT To MANDATORY REDEMPTION SUBJECT To MANDAT0RY REDEMPTI0N (a)
TOTAL L0NG-TERM DEBT (a)
OBLIGATI0Ns UNDER CAPITAL LEAsEs (a)
TOTAL CAPITALIZATIONAND LIABILITIES...
774,193 774,193 774,193 838,347 828,347 164,166 145,489 157,825 161,443 145,302 938,359 919,682 932,018 999,790 973,649 197,000 197,000 197,000 197,000 197,000 18,030 25,030 32,030 197,000 197,000 215,030 222,030 229,030
$1,120,709
$1,123,833
$1,522,736
$1,575,220
$1,591,768 102,511 133,064 122,977 167,920 170,830
$3,573,847
$3,599,669
$4,229,812
$3,966,277
$3,920,163 (a) Including portion due within one year:
Management's Discussion and Analysis of Results of Operations and Financial Condition Results of Operations Net lncon1e Increases Net income increased 16% to $135 million in 1991 after decreasing 15% in 1990 to $116 million. The increase in 1991 was predominantly due to reductions in fuel expense, energy purchases and maintenance
- expense, reflecting the fact that neither of the Company's two nuclear generating units were refueled during 1991 and decreased interest charges, partially offset by a decline in demand for wholesale energy.
The decrease in 1990 was primarily due to a decline in accruals for allowance for funds used during construction (AFUDC) as a result of the commercial operation of Rockport Plant Unit 2 (Rockport 2) in December 1989 and increased operating and maintenance costs related to the refueling outages at the nuclear units. In 1989 net income decreased $15 millionfrom 1988 primarily due to the effects of refueling outages for the two nuclear units.
Outlook The Company faces a number of challenges that could adversely affect the Company's financial performance and possibly its ability to meet its financial obligations and com-mitments. While management believes the Company is equipped to deal with the future, uncertainties that could adversely affect the Company's future financial performance include the ability to obtain favorable rate-making treatment to recover from ratepayers on a timely basis its cost of service, including the cost of compliance with the Clean Air Act Amendments of 1990 and other environmental costs under present and future laws and regulations.
In addition, the Company's results could be negatively affected by: (a) the recession, especially if it were to deepen and impact the Company's highly industrialized service ter-ritory; (b) increased competition in the wholesale electric energy market; and (c) unseasonably mild weather. With its large industrial base, results of operations for the Company are sensitive to economic conditions which can also be impacted by inflation, foreign currency fluctuations and the market price of primary metals. Unfortunately these items are not generally within management's control.
The ability of the American Electric Power System Power Pool (Power Pool) to make wholesale sales, which the Com-pany shares in, equal to or greater than the level of such sales reflected in the Company's rates will affect future results of operations. The Power Pool willmake every effort to continue marketing available capacity in the near term.
In addition, management will be devoting particular attention in 1992 toward the reduction of growth in its cost of service and the finalization of a plan to comply with the Phase I requirements of the Clean AirAct Amendments of 1990.
(dollars in millions)
Amount Amount Amount Retail:
Price variance...
Volume variance..
$ (1.2)
$ (8.1)
$ (18.5) 27.1 (8.4) 10.0 25.9 3.7 (16.5)
(2.3)
(8.5)
(1.2)
Wholesale:
Price variance Volume variance (54.0) '1.1 (94.6)
(27.0) 83.8 166.0 (81.0) (14.9) 154.9 39.6 71.4 22.4 Other Operating Revenues 9.6 (2.7) 4.5 Total...........
$(45.5)
(3.6) $135.7 12.1
$ 67.4 6.4 The increase in 1991 retail sales volume reflects a return to more seasonable weather patterns with a warmer spring and summer, partially offset by a decrease in industrial sales volume caused by the transfer of service of a major industrial customer to a local distribution utility which is served as a wholesale customer. The slight decrease in 1990 retail sales volume reflects the effects of mild weather on residential sales. A modest increase in 1989 retail sales volume reflects growth in the number of customers and increased commercial development. Growth in electric heating and cooling load has made results of operations more sensitive to weather.
Revenues and Energy Sales Decline Operating revenues declined $45 million in 1991 following increases of $136 million and $67 million in 1990 and 1989, respectively. The significant fluctuation in operating revenues reflects the volatilityof the Power Pool's wholesale sales. The decline in 1991 revenues was due to price competition in the wholesale energy market and the continued decline in whole-sale sales by the Power Pool to unaffiliated utilities which began in the fourth quarter of 1990. The significant increase in 1990 reven(les was attributable to increased wholesale sales to unaffiliated utilities in the first three quarters of 1990 and the commercial operation of Rockport 2 in December 1989 resulting in the Company receiving capacity payments from the AEP System Power Pool. The increase in 1989 rev-enues resulted from the increased short-term wholesale sales.
The changes in revenues can be analyzed as follows:
Increase (Decrease)
From Previous Year 1991 1990 1989
INDIANAMICHIGANPOWER COMPANY t
AND SUBSIDIARIES Fuel...............
Purchased and tnterchange Power (net).........
Other Operation.......
Maintenance.........
Oepreciation and Amortization........
Taxes Other Than Federal Income Taxes.......
Federal Income Taxes....
Total.............
Amount Amount Amount
$(25.4)
(9.2) S 26.8 10.7
$16.9 7.3 (40.1) (24.7) 21.5 15.3 (2.2)
(0.9) 73.5 43.0 (17.4) (13.0) 30.3 29.1 22.7 19.2 9.3 5.8 14.7 16.4 1.0 0.7 4.3 3.0 3.5 2.6 6.7 12.2 (2.0)
(3.5) 0.1 0.2 5.8 14.4 (6.5) (14.0) 5.2 12.4
$(71.6)
(6.8) $147.9 16.2
$72.4 8.6 The negative wholesale volume variance in 1991 reflects a substantial decrease in Power Pool wholesale sales. A Power Pool long-term contract for the sale of up to 560 mw of power to an unaffiliated utilityexpired on December 31, 1990. Also during 1990 the Power Pool sold significant quantities of energy to a Canadian utility under a series of short-term wholesale contracts which expired at the end of 1990. Man-agement has sought to make short-term sales but has had limited success due to the highly competitive nature of the energy market and its dependence on factors, such as the increased availability of unaffiliated generating capacity and economic conditions, which are not generally within man-agement's control.
The increase in 1990 wholesale sales volume was predom-inantly due to the commencement in January 1990 of a 250 megawatt (mw) long-term Rockport 2 unit power sales agree-ment and increased sales of energy to affiliated and unaffi-liated utilities with increased capacity from Rockport 2, including the sale by the Power Pool of substantial short-term energy to a Canadian utility. The lack of available unaffiliated generating capacity throughout.most of 1989, a reduction by the Power Pool of its short-term energy prices and extremely cold weather in December 1989 combined to produce a sig-nificant increase in 1989's short-term wholesale sales com-pared with 1988.
Operating Expenses Decline Operating expenses decreased nearly 7% in 1991 due to reduced fuel expense, energy purchases and maintenance expense reflecting the return to service of the Company's nuclear generating units and decreased demand forwholesale energy. Operating expenses increased16% in1990 and nearly 9% in 1989 due to increased wholesale sales and nuclear plant maintenance.
The addition of Rockport 2 generating capacity also contributed to the 1990 increase.
Changes in the components of operating expenses were as follows:
Increase (Decrease)
From Previous Year 1990 1989 (dollars in millions) 1991 Although generation increased by 8% in1991, fuel expense declined 9% due to a shift in the generation mixfrom relatively higher cost coal-fired generation to lower cost nuclear gen-eration coupled with a decreased average cost of fuel con-sumed. The increase in 1990 and 1989 fuel expense reflects higher net generation resulting from the commercial operation of Rockport 2 in December 1989 and the substantial increase in wholesale demand of unaffiliated utilities.
Purchased and interchange power expense generally varies directly with Power Pool wholesale sales since many of the wholesale sales result from purchases of power from unaf-filiated utilities for immediate resale to other unaffiliated util-ities. The decrease in 1991 reflects the decline in wholesale power demand while the 1990 and 1989 increases reflected higher levels of wholesale power transactions.
The significant increase in other operation expense in 1990 was primarily due to lease expense on Rockport 2 which was sold and leased back in December 1989.
In addition, the increase in other operation expense and maintenance expense in 1990 and 1989 was due to scheduled refueling outages of both of the Company's nuclear generating units. In the second half of 1990, both units were out of service for several months each for scheduled refueling. In 1989, Unit 1 was refueled and Unit 2 was out of service to replace its steam generators, refuel and conduct a 10-year service inspection as required by the Nuclear Regulatory Commission. The units are gen-erally refueled on an approximately18-month cycle. The com-parative decrease in maintenance expense in 1991 reflects the fact that the Company's two nuclear units were in service almost all of 1991. Prior to the replacement of Unit 2's steam generators the refueling schedule required only one unit to be out of service per year. Both units are scheduled for refuel-ing outages in 1992. In order to mitigate the fluctuation of earnings that willresult from the new refueling schedule man-agement has petitioned its applicable regulatory commissions to permit the deferral of incremental refueling outage costs for amortization over the period between outages. The Indiana UtilityRegulatory Commission (IURC) has approved the Com-pany's request.
A combination of stricter regulatory requirements for main-tenance and training and the limited supply of nuclear grade materials for replacement parts has contributed to nuclear industry operation and maintenance expenses increasing at a rate higher than the general inflation rate. Industry efforts are underway to change this trend. As the Company's two nuclear units, which were placed in service in 1975 and 1978, con-tinue to age, the Company expects to incur increasing oper-ation and maintenance costs.
Taxes other than Federal income taxes increased in 1991 primarily due to the effect of a property tax over accrual adjustment recorded in1990 and a provision recorded in1991 for an audit assessment of Indiana gross receipts tax on payments received under the AEP System transmission equal-ization agreement.
The increase in'1991 Federal income tax expense attributed to operations was primarily due to the increase in pre-tax operating book income offset in part by changes in items included in 1991 operating book income which were not included in the Federal tax return. The 1990 decrease in Fed-eral income tax expense was primarily due to adjustments relating to prior years'ax returns and an increase in the amortization of deferred investment tax credits due predom-inantly to placing Rockport 2 in service. The increase in Fed-eral income tax expense in 1989 was primarily due to changes in certain book/tax timing differences accounted for on a flow-through basis.
Nonoperating Income and Interest Charges Nonoperating income declined in1991 due to a $3.2 million after-tax provision for a loss which may result from a royalty dispute with the state of Utah concerning prior coal mining operations and a $2.3 million after-tax write-off of the costs associated with a Federal coal lease of a currently inactive subsidiary.
Interest income from temporary investments decreased in 1991 compared with 1990 when the Company invested part of the proceeds from the sale of Rockport 2 until it retired debt, redeemed preferred stock and paid taxes related to the sale.
AFUDC decreased substantially in 1990 since accruals on Rockport 2 ceased effective with its commercial operation on December 1, 1989. The increase in 1989's AFUDC reflected the additional accumulated Rockport 2 construction expen-ditures.
The 1989 nonoperating income decrease was the result of a one-time credit to income in the fourth quarter of 1988 to record, in accordance with Federal Energy Regulatory Commission (FERC) guidance, the interest accrued on nuclear decommissioning trust funds since their inception.
The decline in interest charges on long-term debt in 1991 was due to the retirement of debt in February 1990 with proceeds from the sale of Rockport 2, the refinancing of Installment Purchase Contracts (IPC) at lower rates and a lower average interest rate on the variable IPC partially offset by increased interest on short-term borrowings incurred in 1991 to meet temporary cash requirements. The reduction in interest charges on long-term debt in 1990 was primarily due to the repayment of first mortgage bonds with the Rockport 2 proceeds.
Liquidityand Capital Resources Construction Spending Drops Gross plant and property additions dropped to $145 million in1991 and $162 million in 1990 from $206 million in-1989 primarily reflecting the completion of Rockport 2 and the replacement of one unit's steam generator at the. Company's nuclear plant. Construction expenditures for the next three years are estimated at $438 million, exclusive of yet to be determined additional expenditures necessary to meet the requirements of the Clean AirAct Amendments of 1990. The Company funds its substantial annual capital requirements for construction of new facilities and improvement of existing facilities through a combination of internally generated funds, short-term and long-term borrowings and investments in its common equity by its parent, AEP. Approximately 92% of the Company's construction expenditures for the next three years, exclusive of any expenditures necessary to meet the requirements of the Clean AirAct Amendments of 1990, are expected to be financed internally.
Capital Resources The Company generally issues short-term debt to provide for interim financing of construction and capital expenditures in excess of available internally generated funds. The Com-pany has increased its short-term borrowings by $10 million and $34 million in the last two years primarily to fund capital improvements and decreased its short-term debt by $36 mil-lion in 1989 reflecting the repayment of debt with some of the proceeds from the Rockport 2 sale. At December 31, 1991, the Company had available unused short-term lines of credit of $374 million shared with other AEP System com-panies. Regulatory provisions limit short-term debt borrow-ings to $200 million and a charter provision further limits short-term borrowings to $130 million. The Company period-ically reduces its outstanding short-term debt through the issuance of long-term debt and preferred stock securities and investments in its common equity by AEP.
The Company is seeking regulatory authority to issue up to $150 million of long-term debt. The proceeds are expected to be used to refinance $25 million of 8~/~% installment pur-chase contracts, retire short-term debt and fund construction expenditures.
INDIANAMICHIGANPOWER COMPANY I
AND SIJBSIOIARIES Generally, in order to issue long-term debt without refund-ing an equal amount of existing debt, the Company must have pre-tax earnings equal to at least twice annual interest charges on long-term debt after giving effect to the issuance of the new debt. To issue additional preferred stock, the Company must have after-tax gross income at least equal to one and one-half times annual interest and preferred dividend require-ments after giving effect to the issuance of the new preferred stock. As a result, the earnings performance of the Company willdetermine its ability to finance, which, in turn, willdeter-mine its ability to fund construction.
As of December 31, 1991, the Company's long-term debt and preferred stock coverage ratios were 4.19 and 2.24, respectively.
Concerns and Contingencies Environmental Costs Clean AirAct Amendments of 1990 In November 1990 the Clean AirAct Amendments became law. They require, among other things, substantial reductions in allowable levels of sulfur dioxide and nitrogen oxide emis-sions from coal-fired electric generating plants and place a permanent nationwide limiton sulfur dioxide emissions after 1999. The Amendments establish a strict timetable for com-pliance, setting a deadline of1995 for the first phase of reduc-tions and 2000 for the second phase.
Although the AEP System has in the past made substantial expenditures to sat-isfy the provisions of clean air laws, the System will have to adopt substantial additional measures to comply with the Amendments.
The compliance alternatives being considered for the AEP System include: (a) installation of sulfur dioxide and nitrogen oxide emissions reduction equipment on affected generating units which would require substantial capital expenditures and result in significantly increased operating costs and reduced generating efficiency; (b) switching to lower sulfur coal or natural gas, resulting in adverse impacts on affiliated mining operations and related facilities and less substantial capital expenditures; and (c) premature retirement of certain existing generating units. The Company's Cook Nuclear Plant is not affected by the new legislation. Addition-ally, the Company's Rockport Plant and three of the four units at its Tanners Creek Plant, all of which burn low sulfur coal, are currently in compliance with the new law. Alternatives to meet the new requirements at the Company's coal-fired Tan-ners Creek Unit 4 are being studied.
The Company has announced the retirement of the Breed Plant no later than the end of 1994. The 31 year age of the plant and a deteriorating boiler requiring costly repairs have made it economically impractical to operate the unit full time and to meet the requirements of the Clean AirActAmendments. As a member of the Power Pool the Company could be impacted by the cost of compliance at generating units owned by other Power Pool member companies. Management intends to seek recov-ery of any compliance costs. The Company's cost of com-pliance could adversely affect results of operations and financial condition if not recovered through the rate-making process.
Hazardous Material The generation of electricity unavoidably produces a num-ber of non-hazardous and hazardous materials such as ash, slag, sludge, low level radioactive waste, spent nuclear fuel, etc. In addition the Company's generating plants and trans-mission/distribution facilities have used asbestos, polychlo-rinated biphenyls (PCB's) and other hazardous materials. The Company incurs significant costs to store and dispose of hazardous materials in accordance with current laws and reg-ulations. Additional compliance efforts and costs could be incurred to meet the requirements of new laws and regulations.
The Comprehensive Environmental Response Compensa-tion and LiabilityAct (Superfund) established programs deal-ing with clean-up of hazardous waste disposal sites, as well as other matters, and authorized the U.S. Environmental Pro-tection Agency (EPA) to administer them. The Company has been named by the EPA as a "potentially responsible party" (PRP) for seven sites and has received information requests for two other sites. The Company has also been identified as a PRP under illinois law for one additional site. For two of these sites the Company's liability has been settled for an insignificant amount. Although the potential liability associ-ated with each PRP has been and must be evaluated individ-ually, several general statements can be made regarding the PRP notices the Company has received. The claim that the Company disposed of hazardous waste at a site is often unsubstantiated, the quantity of material disposed of at a site was generally minor and/or the nature of the material the Company generally disposed of at such site was non-hazard-ous. Typically the Company is one of many parties named as PRP's for a site and, although liabilityis joint and several, at least several of the other parties are generally financiallysound enterprises.
Therefore the Company's present estimates do not anticipate material clean up costs. However, should mate-rial costs be required, the Company's results of operations and financial condition could be adversely impacted unless the costs can be recovered from insurance and/or ratepayers.
The Company maintains insurance against damage and liabilityfrom its nuclear plant. In the event of a nuclear incident at the Company's nuclear plant or any nuclear plant in the United States the insurance program would require the Com-pany to pay significant retrospective premiums.
In addition the Company may incur additional uninsured costs.
If not recovered from ratepayers, such costs could adversely impact results of operations and financial condition.
The Company has a significant liabilityfor decommission-ing of its nuclear plant and demolition of its coal-fired plants.
The Company is recording a provision for such decommis-sioning and demolition commensurate with recovery through rates.
The regulators have authorized recovery of nuclear decommissioning costs over the life of the plant based on an independent 1989 study which estimated decommissioning to cost between $330 millionand $369 million. Recently how-ever, a new study was performed which estimated that the cost of decommissioning ranges from $588 million to
$1,102 million. The substantial increase in the cost is pri-marily due to the possible need to store spent nuclear fuel at the plant site for an extended time after the plant ceases operation delaying the commencement of dismantling activ-ities. Variables in the length of time spent nuclear fuel must be stored at the plant subsequent to ceasing operations, which is dependent on future developments in the U.S. Department of Energy's program for disposal of spent nuclear fuel, have widened the range of the estimate. Management plans to seek an appropriate increase in the level of collections for decom-missioning expense. Management willcontinue to periodically reevaluate the cost ofdecommissioning and to seek regulatory approval to revise rates as necessary.
Low Level Radioactive Waste Disposal Under Federal law, states can enter into regional compacts to provide for the disposal of low level radioactive waste.
Membership forthe state'of Michigan in the Midwest Compact has been revoked for its failure to meet host state obligations.
The Company's nuclear plant is located in Michigan. As a result, the nuclear plant has been denied access since Novem-ber 1990 to currently operating low level radioactive waste disposal sites and its low level radioactive waste is being stored in a facility at the plant site. The Company is con-structing an additional facility at its nuclear plant (with com-pletion scheduled for 1992) for temporary storage of the plant's low level radioactive waste. The on-site storage facility is expected to provide ample temporary space for a number of years. The long-term effects on the Company of the revo-cation of Michigan's membership in the Midwest Compact cannot be predicted presently.
Other New Environmental and Health Concerns In recent years there has been considerable discussion of the potential for global climate change due to the emission of carbon dioxide into the atmosphere and the effects on public health ofelectric and magnetic fields (EMF) from transmission and distribution facilities. Management is concerned that new laws may be passed or new regulations promulgated without
- sufficient scientific study and support. The Company will be working to support further efforts to properly study the issues of global climate change and EMF to define the extent, ifany, to which they pose a threat to the environment and public health before new restrictions are imposed. Should Congress enact legislation to address these
- issues, the Company's results of operations and financial condition could be adversely affected unless the cost of compliance can be recovered from ratepayers.
Regulatory Matters During 1991 the IURC issued orders granting the Company additional net annual revenues totaling approximately $4 mil-lion. These orders stem from a rate proceeding that began in July 1989 when the Company requested an annual increase of $60 million. In 1990, the IURC had granted the Company
$19 million of the requested increase.
In November 1991 the Company filed notice of its intent.to seek additional rate relief in its Indiana retail jurisdiction during 1992. The request will seek recovery of increased operating costs including increased nuclear decommissioning cost esti-mates as discussed above and postretirement benefits other than pensions discussed in a later section.
In February1991 the Michigan Public Service Commission (MPSC) approved a settlement agreement granting the Com-pany a $7.4 million increase in April 1991 and an additional
$3 millionincrease effective April1992. The settlement agree-ment resulted from a request filed by the Company in June 1990 seeking an annual increase in Michigan retail rates of
$16 million.
In June 1991 the FERC approved a final settlement agree-ment granting the Company a $4 million annual wholesale rate increase.
The settlement agreement was the result of a request filed in March 1990 seeking an annual rate increase of $11 million.
INDIANAMICHIGANPOWER COMPANY t
AND SUBSIDIARIES ln 1990 an initial decision was issued by a FERC admin-istrative law judge regarding a complaint filed by a wholesale customer concerning the reasonableness of the Company's coal costs and the coal transportation charges of affiliates.
The initial decision would require the Company to refund to wholesale customers $25 million related to coal costs and a yet to be determined amount of affiliated transportation charges. The Company has filed exceptions to the initial deci-sion and the matter is subject to a final decision of the full Commission.
Merger During 1991 the Company and Michigan Power Company (MPCo), an affiliate, filed with the IURC, MPSC, Securities and Exchange Commission (SEC) and FERC. The applications, were filed pursuant to a settlement agreement previously approved by the MPSC. The applications sought approval, in connection with the merger of MPCo into the Company with the surviving entity (the Company) to have all the rights, privileges and obligations of both companies prior to the merger.
All applicable regulatory authorities approved the merger which became effective February 29, 1992.
The merger will be accounted for as a pooling-of-interests.
For the year ended December 31, 1991, operating revenues, net income and earnings applicable to common stock would have been $1,226 million, $137 million and $122 million, respec-tively, ifthe merger had occurred during the year. The merger will not significantly impact results of operations or financial condition.
Effects of Inflation Inflation affects the Company's cost of replacing utilityplant as well as the cost of operating and maintaining such plant.
The rate-making process generally limits the Company to recovery of 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.
New Accounting Standards The Financial Accounting Standards Board's (FASB) new accounting
- standard, Statement of Financial Accounting Standards (SFAS) 109 Accounting for Income Taxes, supersedes SFAS 96 and will require the Company to adopt the liability method of accounting for income taxes in 1993.
SFAS 109 will result in a significant increase in total assets and liabilities due to the recording of deferred income taxes on temporary differences previously flowed through and of corresponding offsetting regulatory assets and liabilities. In addition, existing deferred taxes will be adjusted to the level required at the then-current statutory tax rate. Whether the Company implements the new standard on a restated or pro-spective basis has not yet been determined. It is not presently anticipated that the implementation of the new standard will significantly impact results of operations and financial condition.
The FASB issued an accounting standard in December 1990 that requires a change in accounting for postretirement ben-efits other than pensions from an expense-as-paid method to an accrual method effective in 1993. This standard permits an initial year recognition of the entire prior service costs or their accrual as a transition obligation over periods of up to 20 years. The Company expects to elect the 20-year transition option to comply with the new standard.
The Company amended its other post-retirement plan effective January 1992. The annual expense, inclusive of the plan changes, required by the new standard is expected to be approximately three times the current pay-as-you-go expense and the tran-sition obligation is estimated to be between $80 million and
$90 million. The Company plans to seek recovery of the increased expense in its next base rate filings and to request authority before January1, 1993 to defer under the provisions of SFAS 71 any increased costs for which recovery is not provided currently. Although the Company expects to file a rate case in its Indiana jurisdiction in the second quarter of 1992, the Company is unable to determine if the rate pro-ceeding will be concluded by the January 1, 1993 effective date. Should recovery of or a commitment to allow future recovery of these new accruals be denied, the Company's results ofoperations and possibly its financial condition would be adversely impacted.
10
Independent Auditors'eport Oeloitte &
Touche
/W 155 East Broad Street Facsimile: (614) 229-4647 Columbus, Ohio 43215.3650 Telephone: (614) 221 1000 To the Shareowners and Board of Directors of Indiana Michigan Power Company:
We have audited the accompanying consolidated balance sheets of Indiana Michigan Power Company and its subsidiaries as of December 31, 1991 and 1990, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1991.
These financial statements are the responsibility of th' Company's management.
Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards.
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Indiana Michigan Power Company and its subsidiaries as of December 31, 1991 and 1990, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1991 in conformity with generally accepted accounting principles.
February 25, 1992 Memb~
DHIlnternational
INDIANAMICHIGANPOWER COMPANY t
AND SUBSIDIARIES Consolidated Statements of Income OPERATING REVENUES Year Ended December 31, 1989 1991 1990 (in thousands)
$1,211,607
$1,257,089
$1,121,407 OPERATING EXPENSES:
Fuel Purchased and Interchange Power (net)
Other Operation Maintenance Depreciation and Amortization Amortization of Rockport Plant Unit 1 Phase-in Costs Taxes Other Than Federal Income Taxes Federal Income Taxes Total Operating Expenses OPERATING INCOME NONOPERATING INCOME (Loss):
Allowance for Equity Funds Used During Construction Other Total Nonoperating Income (Loss)
INCOME BEFORE INTEREST CHARGES 251,325 122,573 242,161 117,100 130,132 16,961 61,049 45,996
- 987,297 224,310 986
~4,666) 3,699 220,611 276,719 162,676 244,382 134,521 129,091 16,961 54,389 40,214 1,058,953 198,136 1,174 6,418 7,592 205,728 249,886 141,145 170,855 104,223 124,809 16,961 56,377 46,755 911,011 210,396 2?,972 4,958 32,930 243,326 INTEREST CHARGES:
Long-term Debt Short-term Debt and Other Allowance for Borrowed Funds Used During Construction Net Interest Charges NET INcoME PREFERRED STOCK DIVIOENO REQUIREMENTS EARNINGS APPLICABLE TO COMMON STOCK See Notes to Consolidated Financial Statements.
131,009 7,279
~32,107 87,385 3,507
~1,479) 82,172 4,293
~1,140 106,181 137,145 18,048 89,413 85,325 116,315 15,587 135,286 15,417 119,86$
3 100,728 119,097
Consolidated Balance Sheets ASSETS December 31, 1991 1990 (in thousands)
ELEcTRIc UTILITYPLANT:
Production Transmission Distribution General (includes nuclear fuel).
Construction Work in Progress Total Electric UtilityPlant Accumulated Depreciation and Amortization Net Electric Utility Plant
$2,524,826 807,555 510,923 152,740 82,292 4,078,336 1,503,761 2,574,575
$2,473,678 778,115 482,324 182,906 94,441 4,011,464 1,403,871 2,607,593 OTHER PR0PERTY AND INVEsTMENTs 369,925 347,381 CuRRENT AssETs:
Cash and Cash Equivalents Accounts Receivable:
Customers Affiliated Companies Miscellaneous Allowance for Uncollectible Accounts Fuel at average cost Materials and Supplies at average cost Accrued Utility Revenues Other Total Current Assets 11,605 61,301 38,791 27,078 (589) 59,148 48,539 36,184 7,911 289,968 2,721 70,677 26,926 25,237 (674) 54,790 38,483 39,085 7,786 265,031 DEFERRED CHARGES:
Taxes Gain on Sale and Leaseback of Rockport Plant Unit 2 Depreciation and Return Rockport Plant Unit 1...........
Nuclear Fuel Disposal Costs Other 169,874 97s 957 36,097 35,451 176,967 114,918 43,615 44,164 Total Deferred Charges Total See Notes to Consolidated Financial Statements.
379,664 339,379
$3,573,847
$3,599,669
INDIANAMICHIGANPDHIER COMPANY AND SUBSIDIARIES CAPITALIZATIONAIIDLIABILITIES December 31, 1991 1990 (in thousands)
CAPITALIZATION:
Common Stock No Par Value:
Authorized 2,500,000 Shares Outstanding 1,400,000 Shares Paid-in Capital Retained Earnings Total Common Shareowner's Equity Cumulative Preferred Stock Not Subject to Mandatory Redemption Long-term Debt Total Capitalization 56,584 717,609 164,166 938,359 197,000 1,107,209 2,242,568 56,584 717,609 145,489 919,682 197,000 1,072,333 2,189,015 OTHER NONCURRENT LIABILITIES 220,998 225,652 CURRENT LIABILITIES:
Long-term Debt Due Within One Year Short-term Debt Accounts Payable:
General Affiliated Companies Taxes Accrued Interest Accrued Obligations Under Capital Leases Other Total Current Liabilities.
13,500 43,900 47,634 16,380 9,141 22,765 26,597 63,743 243,660 51,500 33,945 62,343 16,831 21,900 36,399 55,471 278,389 DEFERRED CREDITS:
Income Taxes Investment Tax Credits Gain on Sale and Leaseback Rockport Plant Unit 2 Other Total Deferred Credits 416,883 203,397 226,965 19,3?6 866,621 442,239 212,913 234,303 17,158 906,613 C0MMITMENTs AND C0NTINGENGIEs (Note 3)
Total 83,573,847
$3,599,669 14
Consolidated Statements of Cash Flows 1991 Year Ended December 31, 1990 (in thousands) 1989 OPERATING AcTIYITIEs:
Net Income Adjustments for Noncash Items:
Depreciation and Amortization Amortization of Rockport Plant Unit 1 Phase-in Costs.......
Amortization of Deferred Nuclear Fuel Disposal Costs.......
Deferred Income Taxes Deferred State Taxes Rockport Plant Unit 2 Sale and Leaseback Transaction Deferred Investment Tax Credits Allowance for Equity Funds Used During Construction......
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net)
Fuel, Materials and Supplies Accrued Utility Revenues Accounts Payable Taxes Accrued Interest Accrued Other (net)
Net Cash Flows From Operating Activities..........
INYEsTING AGTIYITIEs:
Construction Expenditures Allowance for Equity Funds Used During Construction........
Cash Used for Construction Expenditures Proceeds from Sale and Leaseback Rockport Plant Unit 2...
Proceeds from Sales of Other Property Net Cash Flows From (Used For) Investing Activities FINANCING ACTIVITIES:
Capital Contributions Returned to Parent Issuance of Long-term Debt Change in Short-term Debt (net)
Retirement of Cumulative Preferred Stock Retirement of Long-term Debt Dividends Paid on Common Stock Dividends Paid on Cumulative Preferred Stock Net Cash Flows Used For Financing Activities.......
Net Increase (Decrease) in Cash and Cash Equivalents..........
Cash and Cash Equivalents January 1
Cash and Cash Equivalents December 31 See Notes to Consottdated Finanotal Statements.
139,660 16,961 7,518 (21,821) 3,558 (9,011)
(966)
(4,415)
(14,414) 2,901 (15,160) 9,141 865
~5,420) 244,683 (119,368) 966 (118,402) 3,246 138,747 16,961 4,207 (8,804) 1,937 (8,248)
(1,174) 25,688 (20,737)
(3,200)
(9,239)
(200,787)
(14,201)
~6.919) 30,546 (104,494) 1,174 (103,320) 6,039 133,551 16,961 3,204 (196,977)
(39,943) 27,445 (27,972)
(79,755) 4,682 (8,373) 18,367 196,502 (252) 26,510 211,095 (196,824) 27,972 (168,852) 850,000 1,381
~115 156
~97.281) 682,529 78,634 9,955 (92,623)
(101,192)
~15,417 40,000 33,945 (19,048)
(451,770)
(113,064)
~16,094 (63,000)
(35,850)
(7,000)
(62,512)
(119,952)
~18.248 526,031 120,643 8,884 2,721 (592,766) 595,487 S
11,605 S
2,721
~306,662 587,062 8,425 S 595,487 6 135,286 S 116,315
$ 137,145 15
INDIANAMICHIGANPOWER COMPANY ANDSUBSIDIARIES Consolidated Statements of Retained Earnings Year Ended December 31, Retained Earnings January 1
Net Income 1991
$145,489 135,286 280,775 1990 (in thousands)
$157,825 116,315 274,140 1989
$161,443 137,145 298,588 Cash Dividends Declared:
Common Stock Cumulative Preferred Stock:
4'/n%
Series 4.56%
Series 4.12%
Series 7.08%
Series 7.76%
Series 8.68%
Series 12%
Series
$2.15 Series
$2.25 Series
$2.75 Series Total Dividends Net Premium on Reacquisition of Preferred Stock Total Deductions Retained Earnings December 31 See Notes to Consolidated Finandat Statements.
101,192 495 273 165 2,124 2,716 2$ 604 3,440 3,600 116,609 116,609
$164,166 113,064 495 273 165 2,124 2,716 2,604 48 3,440 3,600 122 128,651 128,651
$145,489 119,952 495 273 165 2,124 2,716 2,604 838 3,440 3,600 1,793 138,000 2,763 140,763
$157,825 16
Notes to Consolidated Financial Statements
- 1. Significant Accounting Policies:
Organization and Regulation Indiana Michigan Power Company (the Company) is a wholly owned subsidiary of American Electric Power Com-
~ pany, Inc. (AEP). The Company is engaged in the generation, purchase, transmission and distribution of electric power and is a member of the AEP System. Accordingly, the Company's facilities are operated in conjunction with the facilities of other AEP owned utilities as an integrated utilitysystem.
The Company, as a subsidiary of AEP which is an electric utility holding company, is subject to the regulation of the Securities and Exchange Commission (SEC) under the Public UtilityHolding Company Act of1935 (1935 Act). The rates of the Company are regulated by the Indiana Utility Regulatory Commission (IURC), Michigan Public Service Commission (MPSC) and Federal Energy Regulatory Commission (FERC).
Principles of Consolidation The consolidated financial statements include the accounts of the Company and its whollyowned subsidiaries. Significant intercompany transactions have been eliminated in consolidation.
Basis ofAccounting The accounting of the Company conforms to the Uniform System of Accounts prescribed by the FERC and the require-ments of the state commissions. The Company also is subject to the accounting and reporting requirements of the SEC. The financial statements comply with generally accepted account-ing principles.
Electric UtilityPlant; Depreciation and Amortization; Other Property and Investments Electric utility plant, which is stated at original cost, gen-erally is subject to first mortgage liens.
The Company capitalizes, as a construction cost, an allow-ance for funds used during construction (AFUDC), a non-cash income item, which is defined in the applicable regulatory systems of accounts as the net cost of borrowed funds used for construction purposes and a reasonable return on equity funds when so used. The composite AFUDC rates used by the Company after compounding on a semi-annual basis were 9.25% in 1991 and 10.5% in 1990 and 1989.
The Company provides for depreciation on a straight-line basis over the estimated useful lives of its property and deter-mines depreciation provisions largely through the use of com-posite rates by functional class of property.
The Company recovers through depreciation charges included in rates amounts to be used for demolition of non-nuclear plant. Decommissioning costs for the Company's nuclear plant are discussed in Note 3. Periodic demolition studies are performed in order to evaluate the amounts being collected and seek recovery of revised amounts as necessary.
Operating expenses are charged with the costs of labor, materials, supervision and other costs incurred in operating and maintaining the Company's properties. Property accounts are charged with the cost of property additions, major replace-ments of property and betterments.
The accumulated provi-sions for depreciation are charged with retirements and associated removal costs net of salvage.
Other property and investments are generally stated at cost.
Cash and Cash Equivalents The Company and its subsidiaries consider cash, unre-stricted special deposits, working funds, and temporary cash investments as defined by the FERC to be cash and cash equivalents. Temporary cash investments include highly liquid investments purchased with an original maturity of three months or less.
Income Taxes Deferred income taxes are provided except where flow-through accounting for certain timing differences is reflected in the Company's rates. The Company defers and amortizes over the life of its plant the effect of tax reductions resulting from investment tax credits utilized in Federal income tax returns consistent with rate-making policies.
Operating Revenues The Company accrues revenues for electric service ren-dered but unbilled at month-end.
Fuel Costs The Company bills its fuel costs under fuel recovery mech-anisms designed to reflect, in rates, changes in costs of fuel with the approval of various regulatory commissions. Accord-ingly, the Company accrues revenues related to unrecovered fuel.
17
INDIANAMICHIGANPOWER COMPANy t
AND SUBSIDIARIES Other In accordance with regulatory approvals, the Company rec-ognizes gain or loss on reacquired debt in income in the year of reacquisition unless such debt is refinanced, in which case, the gain or loss is deferred and amortized over the term of the replacement debt.
Debt discount or premium and debt issuance expenses are being amortized over the lives of the related debt issues, and the amortization thereof is included in other interest charges.
The excess of par value over costs of cumulative preferred stock reacquired to meet sinking fund requirements is credited to paid-in capital. Redemption premiums paid by the Com-pany are deferred and amortized in accordance with rate-making treatment.
Reclassifications The Company changed the way it reports interchange power transactions in accordance with an accounting release of the FERC. The accounting release requires that interchange power transactions which involve delivery of energy to the AEP Sys-tem Power Pool or to unaffiliated utilities for settlement in cash be recorded as revenues instead of as credits to the purchased and interchange power expense account.
This change increased revenues on a restatedbasis by $231 million in 1990 and $116 million in 1989 with a corresponding increase in purchased and interchange power expense. There was no effect on net income.
In addition certain other prior-period amounts have been reclassified to conform to current-period presentation.
- 2. Rate Matters:
Rate Recovery During 1991 the IURC issued orders on rehearing granting the Company additional annual revenues of approximately
$4 million. These orders stem from a rate proceeding that began in July 1989 when the Company requested an annual increase in rates of $60 million. In 1990 the IURC granted the Company an increase in rates of $19 million annually.
In February 1991 the MPSC approved a settlement agree-ment granting the Company atwo step increase of $7.4 million in April 1991 and $3 million in April 1992. The settlement agreement resulted from a request filed in June 1990 seeking an annual increase in Michigan retail rates of $16 million.
In June 1991 the FERC approved a final settlement agree-ment granting the Company a $4 million annual wholesale rate increase.
The settlement agreement resulted from a request filed in March 1990 seeking an $11 million annual rate increase.
In November 1991 the Company filed notice with the IURC of its intent to file for a rate increase in 1992.
Coal and Transportation Charges A FERC administrative law judge issued an initial decision in 1990 regarding a complaint filed by a wholesale customer concerning the reasonableness of the Company's coal costs and the coal transportation charges of affiliates. The initial decision would require the Company to refund to wholesale customers
$25 million related to coal costs and a yet to be determined amount for affiliated transportation charges. The Company has filed exceptions to the initial decision and the matter is subject to final decision of the full Commission.
Rockport 1 Phase-in Plan The Company is in the sixth year of phase-in plans in its Indiana and FERC jurisdictions for recovery of a portion of the cost of operation incurred in the first three years of oper-ation of its Rockport Plant Unit 1. The phase-in plans satisfy the requirements of Statement of Financial Accounting Stan-dards 92. At December 31, 1991 and 1990 the Company's balance sheet contained unamortized deferred returns of
$76 million and $89 million, respectively, and unamortized deferred depreciation of $22 million and $26 million, respec-tively. The phase-in plan deferrals are being amortized on a straight-line basis through 1997.
Merger During 1991 the Company and Michigan Power Company (MPCo), an affiliate, filed applications with the IURC, MPSC, SEC and FERC seeking approval in connection with the merger of MPCo into the Company with the surviving entity (the Company) to have all the rights, privileges and obligations of both companies prior to the merger. Allapplicable regulatory authorities approved the merger which became effective Feb-ruary 29, 1992. The merger willbe accounted foras a pooling-of-interests.
For the year ended December 31, 1991, oper-ating revenues, net income and earnings applicable to com-mon stock would have been $1,226 million, $137 million and
$122 million, respectively, if the merger had occurred in 1991. The merger willnot significantly impact results of oper-ations or financial condition.
18
NOTES TO CONSOLIDATED FINANCIALSTATEMENTS (Continued)
- 3. Commitments and Contingencies:
Construction The construction expenditures of the Company and its sub-sidiaries for the years 1992-1994 are estimated at $438 mil-lion, exclusive of the requirements of the Clean Air Act Amendments of1990 and, in connection with the construction program, commitments have been made.
Unit Power Agreements The Company is committed under unit power agreements to purchase from AEP Generating Company (AEGCo), an affil-iated company, 70% of AEGCo's Rockport Plant capacity unless it is sold to unaffiliated utilities.
Fuel Supply The Company has long-term contracts to obtain fuel for electric generation.
The contracts generally contain clauses that provide for periodic price adjustments and the Company's jurisdictions have fuel clause mechanisms that generally pro-vide for recovery of changes in the cost of fuel. The contracts are for as long as 23 years and contain clauses that would release the Company from its obligation under certain conditions.
Litigation In February 1990 the Supreme Court of Indiana overruled an appeals court and reversed an IURC order that had assigned a major industrial customer to the Company's serv-ice territory. In August 1990 the IURC issued an order trans-ferring the right to serve the industrial customer to an unaffiliated local distribution utility.Concurrent with the trans-fer of service the Company began providing service to the local distribution utility in an amount sufficient to meet the energy needs of the industrial customer.
In October 1990 the local distribution utilitysued the Com-pany under a provision of Indiana law that allows the local distribution utility to seek damages equal to the gross reve-nues received by a utility that renders retail service in the designated service territory of another utility. The Company received revenues of approximately $29 million from serving the major industrial customer. It is not clear whether such a claim would be upheld since the service was rendered in accordance with an IURC order which the Company believed in good faith to be valid. The matter is pending.
The Company is involved in other legal proceedings and claims. While management is unable to predict the outcome of litigation, it is not expected that the resolution of these other matters willhave a material adverse effect on the Com-pany's financial'condition.
Environmental Matters The Company and its subsidiaries are subject to regulation by Federal, state and local authorities with respect to air-and water-quality control and other environmental matters, and are subject to zoning and other regulation by local authorities.
The generation of electricity produces non-hazardous and hazardous by-products. Also asbestos, polychlorinated biphenyls (PCB's) and other hazardous materials have been used in the Company's generating plants and transmission/
distribution facilities. The Company incurs substantial costs to store and dispose of hazardous materials in accordance with current laws and regulations. Significant additional costs could be incurred to meet the requirements of new laws and regulations.
The Clean Air Act Amendments of 1990 require, among other things, significant reductions in the emission of sulfur dioxide and nitrogen oxide from various existing AEP System generating plants. The law established a deadline of 1995 for the first phase of reductions and 2000 for the second phase as well as a permanent nationwide cap on sulfur dioxide emis-sions after 1999. The AEP System reviewed the provisions of the 1990 law and is evaluating compliance alternatives which include: (a) installation of sulfur dioxide and nitrogen oxide.
emissions reduction equipment on affected generating units which would require substantial capital expenditures and result in significant operating costs and reduced generating efficiency; (b) switching to lower sulfur coal or natural gas,
'esulting in adverse impacts on affiliated mining operations and related facilities and less substantial capital expenditures; and (c) premature retirement of certain generating units.
The AEP System has completed a preliminary systemwide compliance report (Compliance Report) as ordered by a state commission in an affiliate's retail jurisdiction. The Compliance Report evaluated the cost of compliance with the Clean Air Act Amendments on a systemwide basis and compared pre-liminary estimates of the revenue requirements on a five-year
- average, a 10-year average and a 16-year net present value basis. The Company's additional annual revenue requirement for the System's least cost option, excluding any potential transfer payments or credits for emission allowances, is esti-mated to be $15 million based on a five-year average and
$29 million based on a 10-year average. The 10-year average includes tentatively projected Phase II compliance measures which expanded the compliance requirements to additional generating units and increased the cost. Unless the costs of compliance are recovered through
- rates, the Company's results of operations will be adversely affected.
Recent concerns about the potential for global climate change and policies to address this issue continue to be the focus of international negotiations and Congressional debate.
Legislation has been introduced in Congress to control emis-sion of "greenhouse" gases such as carbon dioxide. Since the System's coal-fired generating plants emit significant
INDIANAMICHIGANPOWER COMPANY t
AND SUBSIDIARIES quantities of carbon dioxide, the cost of any restrictions could adversely affect the Company's results of operations and financial position if not recovered from ratepayers.
Nuclear Insurance The Price-Anderson Act limits the public liabilityof a licen-see of a nuclear plant for a nuclear incident to $7.7 billion.
The Company maintains the maximum private insurance avail-able of $200 million for the Donald C. Cook Nuclear Plant (Cook Plant). The balance of any claims would be paid by
.a retrospective deferred premium assessment plan.
The maximum standard deferred premium that the Company may be assessed, in the event of a nuclear incident at any nuclear plant, is $63 million per reactor, but may not exceed
$10 million in any one year. If claims exceed the amount of liability insurance and deferred premiums, a licensee must pay a surcharge of up to 5 percent of the standard deferred premium for such claims. Thus, if damages in excess of private insurance result from a nuclear incident, the Company could be assessed its pro rata share of the liability up to a maximum of $126 million for its two reactors, in annual installments of $20 million plus $6.3 million for excess claims. There is no limiton the number of incidents for which the Company could be assessed these sums.
The Company also has property damage, decontamina-tion and decommissioning insurance in the amount of
$2.515 billion. Nuclear insurance pools provide $1.265 bil-lion of coverage and Nuclear Electric Insurance Limited (NEIL) provides the remainder. If NEIL's losses exceed its available resources, the Company would be subject to a retrospective premium assessment of up to $7.4 million. Nuclear Regu-latory Commission regulations require that the insurance pro-ceeds must be used, first, to return the reactor to, and maintain it in, a safe and stable condition and, second, to decontaminate the reactor and reactor station site. The in-surers then would indemnify the Company for property dam-age up to $2.315 billion less any amounts used for stabilization and decontamination.
As provided by NEIL the remaining $200 million (less any stabilization and decontam-ination expenditures over $2.315 billion)would cover decom-missioning costs in excess of funds already collected for decommissioning, as discussed below.
NEIL's extra-expense program provides insurance to cover extra costs from a prolonged accidental outage of a nuclear unit. The Company's policy insures against such increased costs up to approximately $3.5 million per week (starting 21 weeks after the outage) for the first year, $2.3 million per week for the second year and $1.15 million per week for the third year, or 80% of those amounts per unit if both units are down forthe same reason. IfNEIL's losses exceed its available resources, the Company would be subject to a retrospective premium assessment of up to $9 million.
Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including liabilities relating to damage to the Cook Plant and other costs in the event of a nuclear incident at the Cook Plant. Any future losses or lia-bilities which are not completely insured, unless recovered through rates, could have a material adverse effect on results of operations and financial condition of the Company.
Disposal of Spent Nuclear Fuel and Nuclear Decommissioning The Nuclear Waste Policy Act of 1982 established Federal responsibility for the permanent off-site disposal of spent nuclear fuel and assesses owners of nuclear plants fees for the disposal cost. The Company entered into a contract with the U.S. Department of Energy (DOE) forthe disposal of spent nuclear fuel. Under the terms of the contract the Company pays a fee of one mill per kwh sold for fuel consumed after April 6, 1983 which is being collected from customers and remitted to the U.S. Treasury.
The fee for disposai of fuel consumed prior to April 7, 1983 of $72 million plus interest of $66 million to December 31, 1991, has been recorded as other long-term debt and deferred. The amount deferred is being amortized commensurate with recovery from rate-payers.
Due to the delays and continuing uncertainties of DOE's program for permanent disposal of spent nuclear fuel, the Company has not commenced paying the fee for fuel consumed prior to April 7, 1983. Funds collected from rate-payers of $10 million in each year for 1991, 1990 and 1989 were deposited in external funds. Interest earned by the exter-nal funds, $6 million in1991, $3 million in 1990 and $4 mil-lion in 1989, increase the fund balance and will be used to settle the Company's liabilityfor disposal of nuclear fuel con-sumed prior to April 7, 1983.
The Company has received regulatory approval from all of its jurisdictions to recover an approved level of decom-missioning costs in revenues which before income taxes amounted to $11 million in 1991, $10 million in 1990 and
$9 million in 1989. These collections were granted by the Company's regulatory commissions after the commissions reviewed a study by an independent consulting firm employed by the Company, which estimated that the cost of decom-missioning the Cook Plant could range from $330 million to
$369 million in 1989 dollars.
/
20
NOTES TO CONSOLIDATED FINANCIALSTATEMENTS (Continued)
The consultant recently updated this study, which has not yet been filed with or reviewed by the Company's regulators.
The update estimates, based on changed conditions (related to delays in DOE's program for disposal of spent nuclear fuel and other factors), that the cost of post-shutdown fuel storage and decommissioning at the Cook Plant would be in the range of $588 millionto $1,102 millionin 1991 dollars for the cases studied. The substantial increase is primarily due to the pos-sible need to store spent nuclear fuel at the plant site for an extended time after the plant ceases operation delaying the commencement of dismantling activities. Variables in the length of time spent nuclear fuel must be stored at the plant subsequent to ceasing operations, which is dependent on future developments in DOE's program for disposal of spent nuclear fuel, have widened the range of the estimate.
The Company intends to seek an appropriate increase in its level of collections for decommissioning expense.
The Company will continue to periodically reevaluate the cost of decom-missioning and to seek regulatory approval to revise its rates as necessary.
The Company records decommissioning costs in other operation expense and records a provision for nuclear decom-missioning expense in other noncurrent liabilities equal to the amount of cost recovery in rates.
Funds recovered through the rate-making process for nuclear decommissioning are deposited in external funds for the future payment of such costs. Trust fund earnings increase the fund balance and the recorded liability, thus reducing the amount to be collected from ratepayers.
- 4. Common Shareowner's Equity:
In December 1989 the Company returned $63 million of cash capital contributions to its parent from paid-in capital.
In 1989, the Company recorded charges of $1.2 million to paid-in capital and $2.8 million to retained earnings repre-senting the write-offof premiums paid in connection with the reacquisition of its $3.63 Series Cumulative Preferred Stock.
There were no other transactions affecting the common stock or paid-in capital accounts in 1991, 1990 or 1989.
Covenants in mortgage indentures, debenture and bank loan agreements, charter provisions and orders of regulatory authorities place various restrictions on the use of retained earnings of the Company to pay dividends (other than stock dividends) on its common stock and for other purposes. At December 31, 1991, approximately $45.9 million of retained earnings were restricted.
In addition, regulatory approval is required for the Company to pay dividends out of paid-in capital.
- 5. Related-party Transactions:
The Company is a member of the AEP System Power Pool (Power Pool) which allows the Company to share'the benefits and costs associated with the System's generating plants.
Under the terms of the System Interchange Agreement,
- capacity charges and credits are designed to allocate the cost of the System's capacity among the Power Pool members based on their relative peak demands and generating reserves.
Net energy charges and credits are intended to compensate Power Pool members for their out of pocket cost when they deliver more energy to the Power Pool than they receive. In addition the Company shares in wholesale sales to unaffiliated utilities made by the Power Pool. The Company's share was credited to operating revenues in the amount of $65.5 million in 1991, $126.7 million in 1990 and $127.7 million in 1989.
The revenues (credits) from providing capacity and sup-plying energy to the Power Pool totaled $204.8 million in 1991, $230.5 million in 1990 and $114.1 million in 1989.
The placing in service of the 1300 mw Rockport Plant Unit 2 in December 1989 accounted for the significant increase in Power Pool capacity credits beginning in 1990. The charges for energy received from the Power Pool were included in purchased and interchange power expense and totaled
$24.6 millionin1991, $53.9 millionin1990 and $96.4 million in 1989.
The Power Pool purchases power for immediate resale to other unaffiliated utilities. The Company's share of these pur-chases is included in purchased and interchange power expense and totaled $13.7 million in 1991, $28.2 million in 1990 and $21.5 million in 1989.
Operating revenues shown in the Consolidated Statements of Income include sales of energy to MPCo, an affiliated utility that is not a member of the Power Pool, of approximately
$32 million, $31 million and $32 million for the years ended December 31, 1991, 1990 and 1989, respectively.
The cost of power purchased from AEGCo, an affiliated company that is not a member of the Power Pool, shown as purchased and interchange power expense was $83 million,
$79 million and
$13 million in 1991, 1990 and
- 1989, respectively.
21
INDIANAMICHIGANPOIVER COMPANY ANDSUBSIDIARIES The Company participates with other AEP System com-panies in a transmission equalization agreement.
This agree-ment combines certain AEP System companies'nvestments in transmission facilities and shares the costs of ownership in proportion to the System companies'espective peak demands.
Pursuant to the terms of the agreement, the Company recorded in other operation expenses credits of
$46.2 million, $47.6 million and $37.3 million for transmis-sion services in 1991, 1990 and 1989, respectively.
The Company recorded revenues in nonoperating income from providing barging services as follows:
Year Ended December 31, 1991 1990 1989 (in thousands)
$16,306
$17,094
$21,092 4,641 2,882 5,173
$20,947
$19,976
$26,265 Affiliated Companies Unaffiliated Companies Total American Electric Power Service Corporation (AEPSC) pro-vides certain professional services to the Company and its affiliated companies in the AEP System.
The costs of the services are determined by AEPSC on a direct-charge basis to the extent practicable and on reasonable bases of proration for indirect costs. The charges for services are made at cost and include no compensation for the use of equity capital, all of which is furnished to AEPSC by AEP. The Company expenses or capitalizes billings from AEPSC depending on the nature of the professional service rendered.
AEPSC and its billings are subject to the regulation of the SEC under the 1935 Act.
- 6. Benefit Plans:
The Company and its subsidiaries participate with other companies in the AEP System in a trusteed, noncontributory defined benefit plan to provide pensions, subject to certain eligibility requirements, for all employees.
Plan benefits are determined by a formula which considers each participant's highest average
- earnings, years of accredited service and social security covered compensation.
Pension costs are allo-cated to each System company by first charging each System company with its service cost and then allocating the remain-ing pension cost in proportion to its share of the projected benefit obligation. The Company and its subsidiaries'unding policy is to make annual contributions to the plan's trust fund equal to the net periodic pension cost to the extent deductible for Federal income tax purposes, but not less than the min-imum contribution required by law.
Net pension costs for the years ended December 31, 1991, 1990 and 1989 were $2.3 million, $2.7 millionand $1.3 million, respectively.
The Company offers an employee savings plan under which eligible participants can invest from 1% to 16% of their salar-ies among three investment alternatives, including AEP com-mon stock. An employer contribution equal to one-half of the first 6% of the employees'ontributions is invested in AEP common stock. The Company's annual contributions to the savings plan trust were $3 million in 1991, $2.8 million in 1990 and $2.7 million in 1989.
In addition to providing pension benefits, the Company and its subsidiaries provide certain other benefits for retired employees.
Substantially all employees may become eligible for health care and life insurance benefits ifthey have 10 years of service at retirement. The cost of retiree benefits is rec-ognized as an expense when paid and totaled $2.4'million in 1991, $2.6 million in 1990 and $2.1 million in 1989.
The Financial Accounting Standards Board (FASB) has issued Statement of Financial Accounting Standards (SFAS) 106 Emp/oyers'Accountf'ng forPostretirement Benefits Other Than Pensions which requires employers, beginning in 1993, to accrue for the costs of retiree benefits other. than pensions.
SFAS 106 requires the recognition of prior service costs (the unfunded and unrecognized accumulated postretirement ben-efit obligation) in the initial year of implementation or their accrual as a transition obligation over either the greater of the average remaining service period of employees or 20 years.
The Company expects to elect the 20-year transition option.
In anticipation of this new requirement, the Company and its subsidiaries established a Voluntary Employee Beneficiary Association (VEBA) trust fund for postretirement benefits other than pensions and made a $4.1 million contribution in 1990, the maximum amount deductible for Federal income tax purposes.
Another measure taken by the Company in 1990, except where restricted by state law, was to implement a program of corporate owned life insurance to help fund and reduce the future cost of postretirement benefits other than pensions. The insurance policies have a substantial cash sur-render value which is recorded, net of equally substantial policy loans, as other property and investments.
In 1991 the policies generated $700,000, inclusive of related tax benefits, which was contributed to the VEBA trust fund.
22
NOTES TO CONSOLIDATED FINANCIALSTATEMENTS (Continued)
The pension and other postretirement benefit plans were amended effective January1, 1992. The change in the pension plan allows employees to retire without reduction of benefits at age 62 instead of age 65 and to retire as early as age 55 instead of age 60 with reduced benefits. It is estimated that the pension plan amendments will increase annual pension expense in 1992 to $5.5 million. The change in the other postretirement benefit plan grants employees eligibility for health care and life insurance benefits if they retire as early as age 55 with 10 years of service.
Previously employees could not receive other postretirement benefits unless they retired at age 60 or later.
The annual expense required by SFAS 106 for employees and retirees, inclusive of the changes in the other postretire-ment benefit plan, is expected to be approximately three times the currently recognized pay-as-you-go expenses and the transition obligation is estimated to range from $80 million to $90 million. The Company plans to seek recovery of the increased expense in its next base rate filing and to request authority before January1, 1993 to defer under the provisions of SFAS 71 any increased costs for which recovery is not provided currently. Although the. Company expects to file a rate case in its Indiana jurisdiction in the second quarter of 1992, the Company is unable to determine if the rate pro-ceeding will be concluded by the January 1, 1993 effective date. Should recovery of or a commitment to allow future recovery of the SFAS 106 accruals be denied, the Company's results of operations and possibly its financial condition would be adversely impacted.
Real and Personaf Property...
State Gross Receipts, Excise, Franchise and Miscellaneous State and Local State Income Payroll Deferred Taxes Rockport 2 Sale and Leaseback Transaction Total 1991 1990 (in thousands)
$31,892
$26,946 1989
$31,897 15,469 4,848 7,914 12,156 5,760 7,590 29,282 28,057 7,084 926
$6I,049 1,937 (39,943)
$54,389
$56,377 The following are the amounts of cash paid for:
Year Ended December 31
~
1991 1990 1989 (in thousands)
Interest (net of capitalized amounts)
Income Taxes........
$83,276
$101,905
$107,124 72,831 247,172 64,843 The amounts of non-cash investing acquisitions under cap-ital leases were $25,438,000 in 1991, $57,112,000 in 1990 and $9,035,000 in 1989.
- 7. Supplementary Information:
The following are the components of taxes other than Fed-eral income taxes:
Year Ended December 31,
- 8. Federal Income Taxes:
The details of Federal income taxes as reported are as follows:
1991 Year Ended December 31, 1990 (in thousands) 1989 Charged (Credited) to Operating Expenses (net):
Current Deferred Deferred Investment Tax Credits Total Charged (Credited) to Ifonoperating Income (net):
Current Deferred Deferred Investment Tax Credits Total Total Federal Income Taxes as Reported
$ 73,010 (18,737)
(8,277) 45,996 3,370 (3,084)
(734)
(448)
$ 45,548
$52,894 (6,921)
(5,759) 40,214 7,288 (1,883)
(2,489) 2,916
$43,130 S 215,793 (196,503) 27,465 46,755 1,234 (474)
(20) 740 47,495 23
INDIANAMICHIGANPOWER COMPANY ANDSUBSIDIARIES I ~
r
$137,145 47,495
$184,640
$135,286 45.548
$180,834 Net Income Federal Income Taxes Pre-tax Book Income The following is a reconciliation of the difference between the amount of Federal income taxes computed by multiplying book income before Federal income taxes by the statutory tax rate, and the amount of Federal income taxes reported.
Year Ended December 31
~
1991 1990 1989.
(in thousands)
$116,315 43,130
$159,445 Federal Income Taxes on Pre-Tax Book Income at Statutory Rate (34%).
Increase (Decrease) in Federal fncome Taxes Resulting From the Following Items:
Allowance for Funds Used During Construction Mine Development and Mineral Rights Amortization Investment Tax Credits (net)
Other Total Federal Income Taxes as Reported Effective Federal income Tax Rate The following are the principal components of Federal income taxes as reported:
$ 61,484 (2,071) 2,773 (8,910)
(7,728)
$ 45,548 25.2%
$ 54,211 (2 ~161) 4,369 (10,810)
(2,479)
S 43,130 27.1%
S 62,778 (12,364) 3,048 (6,395) 428 S 47,495 25.7%
Current:
Federal Income Taxes Investment Tax Credits Total Current Federal income Taxes Deferred:
Depreciation Allowance for Borrowed Funds Used During Construction Unrecovered and Levelized Fuel Nuclear Fuel Unbilled Revenue Deferred Return Rockport Plant Unit 1 Sale of Rockport Plant Unit 2 Deferred Net Gain Rockport Plant Unit 2 Other Total Deferred Federal Income Taxes Total Deferred Investment Tax Credits Total Federal Income Taxes as Reported (a) The significant increase in current Federal income taxes resulted 1989 enabled the Company to utilize significant investment tax credits gain and the credits utilized were deferred.
Year Ended December 31, 1991 1990 1989 (in thousands)
$76,279 101 76,380
$62,744
$250,867 (2,562)
(33,840) 60,182 217,027 (a)
(7,000) 1,041 2,254 (1,960)
(2,519) 7,433 (492) 4,214 (5,453)
(6,484) 384 (2,701)
(3,349)
(3,713)
(2,864)
(2,864)
(2,864)
(56,863) 3,099 3,457 (128,194)
(6,120)
(9,168)
(6,876)
(196,977)
(9,011)
(8,248) 27,445 (a)
$45,548
$43,130 S 47,495 from the gain on the sale of Rockport 2. The placing of Rockport 2 in service in December generated by the sale and leaseback to reduce its taxes payable. The tax effect of both the 24
NOTES TO CONSOLIDATED FINANCIALSTATEMENTS (Continued)
The Company and its subsidiaries join in the filing of a consolidated Federal income tax return with their affiliated companies in the AEP System.
The allocation of the AEP System's current consolidated Federal income tax to the Sys-tem companies is in accordance with SEC rules under the 1935 Act. These rules permit the allocation of the benefit of current tax losses and investment tax credits utilized to the System companies giving rise to them in determining taxes currently payable. The tax loss of the System parent company, AEP, 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.
At December 31, 1991, the cumulative net amount of income tax timing differences on which deferred taxes have not been provided totaled $442 million.
The AEP System reached a settlement with the Internal Revenue Service (IRS) for all issues from the audits of the consolidated Federal income tax returns for the years prior to 1985. Returns for the years 1985 through 1987 are being audited by the IRS. In the opinion of management, the final settlement of open years should not have a material effect on the earnings of the Company.
The FASB has issued SFAS 109 Accounting for Income Taxes which supersedes SFAS 96. SFAS 109 requires the use of the liabilitymethod of accounting for income taxes and has an effective date of January 1, 1993.
SFAS 109 may be adopted on a restated basis or as a cumulative effect of an accounting change in the year of adoption.
When the new standard is adopted, total assets and lia-bilities will increase significantly to reflect previously unre-corded deferred tax assets and liabilities on temporary differences 'and related regulatory assets and liabilities. In addition, existing deferred taxes will be adjusted to the level required at the then-current statutory tax rate. It is not pres-ently anticipated that implementation of the new standard will significantly impact results of operations and financial con-dition. Whether the new standard will be implemented on a restated or prospective basis has not yet been determined.
1991 March 31 June 30 September 30.......
December 31 1990 March 31 June 30 September 30......
December 31 (a) Quarterly revenues described in Note 1.
$304,444 289,630 311,214 306,319 323,320 312,350 317,823 303,596 have been restated to
$60,319 48,437 60,679 54,875 59,281 48,733 52,886 37,236 reflect the
$39,793 28,460 35,311 31,722 37,699 27,442 32,077 19,097 r cclassification
- 9. Unaudited Quarterly Financial lnforntttio:
The following consolidated quarterly financial information is unaudited but, in the opinion of the Company, includes all adjustments (consisting of only normal recurring accruals) necessary for a fair presentation of the amounts shown:
Quarterly Periods Operating Operating Net Ended Revenues (a)
Income Income (in thousands) 25
INDIANAMICHIGANPOWER COMPANY t
AND SUBSIDIARIES II Operating Leases.........
Capital Leases:
Amortization of Principal...
interest Total Rental Payments 1991 1990 1989 (in thousands)
$100,958
$ 87,357
$16,454 54,453 46,836 52,815 9,865 10.877 13,733
$165,276
$145,070
$83,002
- 10. Leases:
The Company and its subsidiaries lease property, plant and equipment for periods up to 35 years.
Most of the leases require the lessee to pay related property taxes, maintenance costs and other costs of operation.
The Company and its subsidiaries expect that leases generally will be renewed or replaced by other leases.
The majority of the leases have purchase or renewal options.
The Company and AEGCO each lease 50% of Rockport 2 which cost $1.3 billion and began commercial operation in December 1989. Rockport 2 was sold in December 1989 for S1.7 billion, its estimated fair market value, and leased back for an initial term of 33 years. The gain from the sale was deferred and is being amortized, with related deferred taxes, over the initial lease term. The leases are accounted for as operating leases.
The Company leases its nuclear fuel from a special purpose entity which provides for leasing of up to $140 million of nuclear fuel. The special purpose entity owns the nuclear fuel and finances all of its investment in nuclear fuel. The Company accounts for the nuclear fuel lease as a capital lease.
Rental payments for capital and operating leases are pri-marily charged to operating expenses in accordance with rate-making treatment.
The components of rental payments are as follows:
Year Ended December 31 ~
Properties under capital leases and related obligations recorded on the Consolidated Balance Sheets are as follows:
December 31 ~
1991 1990 (in thousands)
Electric UtilityPlant:
Production Distribution General:
Nuclear Fuel (net of amortization).......
Other Total Electric UtiIityPlant...........
Accumulated Amortization Net Electric Utility Plant Other Property Accumulated Amortization Net Other Property.............,..
Net Properties under Capital Leases....
Obligations under Capital Leases (a)
$ 10,568 9,090 14,652 14,607 66,456 38,601 130,277 27,970 102,307 1,949 1,745 204
$102,511 96,914 38,013 158,624 25,675 132.949 2,008 1,893 115
$133,064
$102,511
$133,064 1992 1993 1994 1995 1996 Later Years Total Future Minimum Lease Payments
$2,558,000 60,000 (a) Including amounts due within one year.
Properties and related obligations under operating leases are not included in the Company's Consolidated Balance Sheets.
Future minimum lease payments, by year and in the aggre-gate, consisted of the following at December 31, 1991:
Capital Operating Leases Leases (in thousands) 8,000 93,000 6,000 92,000 5,000 92,000 5,000 91,000 4,000 91,000 32,000 2,099,000 Less Estimated Interest Element..
Estimated Present Value of Future Minimum Lease Payments Unamortized Nuclear Fuel Total 23,000 37,000 66,000(a)
$103,000 (a) Including portion due within one year. Rental payments for nuclear fuel willbe paid in proportion to heat produced and carrying charges on the lessor's unrecovered costs.
Nuclear fuel rentals of $56.6 million, $50 million and
$59.2 million were charged to fuel expense in
- 1991, 1990 and
- 1989, respectively.
Included in the above analysis of future minimum lease payments and of properties under capital leases and related obligations are certain leases in which portions of the related rentals are paid for or reimbursed by affiliated companies in the AEP System based on their usage of the leased property.
The Company and its subsidiaries cannot predict the extent to which affiliated companies will utilize the properties under such leases in the future.
26
NOTES TO CONSOLIDATED FINANCIALSTATEMENTS (Concluded)
- 11. Cumulative Preferred Stock:
At December 31, 1991, authorized shares of cumulative preferred stock were as follows:
Par Value Shares Authorized
$100 2,250,000 25 11,200,000 In 1990 and 1989, the Company redeemed 47,325 and 30,000 shares, respectively, of the 12% series and 531,900 and 160,000
- shares, respectively, of the $2.75 series cumulative preferred stock subject to mandatory redemption. The cumulative preferred stock is callable at the option of the Company at the price indicated plus accrued dividends. The involuntary liquidation preference is par value. Unissued shares of the cumulative preferred stock may or may not possess mandatory redemption characteristics upon issuance.
The cumulative preferred stock not subject to mandatory redemption is as follows:
Series 4'/s%
4.56%
4.12%
7 08%
7 76%
8.68%
$2.15
$2.25 Call Price December 31, 1991
$106.125 102 102.728 101.85 102.28 103.10 26.08 26.13 Par Value
$100 100 100 100 100 100 25 25 Shares Outstanding December 31
~ 1991 120,000 60,000 40,000 300,000 350,000 300,000 1,600,000 1,600,000 Amount December 31.
1991 1990 (in thousands)
$ 12,000 S 12,000 6,000 6,000 4,000 4,000 30,000 30,000 35,000 35,000 30,000 30,000 40,000 40,000 40.000 40,000
$197,000
$197,000 First Mortgage Bonds.......
Sinking Fund Debentures Notes Payable to Banks Installment Purchase Contracts Other Long.term Debt (a)....
Less Portion Oue Within One Year Total 1991 1990 (in thousands)
S 627,494 599,179 6,053 6,188 40,000 80,000 308,971 308,175 138.191 130,291 1,120,709 1 ~123,833 13,500 51,500
$ 1 ~107,209
$1.072.333 (a) Nuclear Fuel Disposal Costs including interest accrued.
See Note 3.
- 12. Long-term Debt and Lines of Credit Long-term debt by major category was outstanding as follows:
December 31 ~
First mortgage bonds outstanding were as follows:
December 31.
1991 1990 (in thousands)
% Rate Due 4'993 August 1.
7rls 1997 February 1
9~/o 1997 July 1
7 1998 May 1 Br/e 2000 April 1 9iA 2003 June 1 (a) 8~/o 2003 December 1
9iA 2008 March 1
8~/.
2017 February 1
9.5 2021 May 1 9.5 2021 May 1 9.5 2021 May 1 Unamortized Discount (net)..
S 42,902
$ 42,902 50,000 50,000 75,000 75,000 35,000 35,000 50,000 50,000 162,000 173,500 40,000 40,000 34,034 34,034 100,000 100,000 10,000 10,000 20,000 (1,442)
(1,257) 627,494 599,179 13,500 11,500
$613,994
$587,679 (a) The 9'/a% series due 2003 requfres sinking fund payments of
$13,500,000 annually on June 1 ~ 1992 through 2002 with the noncumulative option to redeem an additional amount in each of the specified years from a minimum of $100,000 to a maximum equal to the scheduled requirement for each year, but with a mzdmum optional redemption, as to all years in the aggregate, of $75,000,000.
27
INDIANAMICHIGANPOWER COMPANY ANO SIIBSIOIARIES The indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions.
The sinking fund debentures are due May 1, 1998 at an interest rate of 7/4%. Prior to December 31, 1991 sufficient principal amounts of debentures had been reacquired in antic-ipation of all future sinking fund requirements.
The Company may call additional debentures of up to $300,000 annually.
Unsecured promissory notes payable to banks have been entered into by the Company as follows:
December 31, 1991 1990 (in thousands) s
$20,000 20,000 40,000 40.000
$40.000 S80.000 9.28% due 1991 9.28% due 1991 9.07% due 1995 Total
% Rate Due City of Lawrenceburg, Indiana:
ei/r 2006 July 1
7 2006 May 1 6rle 2006 May 1 City of Rockport, Indiana:
9i/s 2005 June 1...
9i/i 2010 June 1...
9y4 2014 August 1..
6N (a) 2014 August 1..
(b) 2014 August 1..
7.6 2016 March 1..
City of Sullivan, Indiana:
7r/s 2004 May 1 6rls 2006 May 1
'7~A 2009 May 1 Unamortized Discount Total S 25,000 40,000 12,000 50,000 50,000 50,000 40,000 7,000 25,000 13,000 (3,029)
$308,971 S 25,000 40,000 12,000 6,500 33,500 50,000 50,000 50,000 7,000 25,000 13,000 (3,825)
$308,175 (a) The adjustable interest rate changed on August 1, 1990 and will change every five years thereafter.
(b) The variable interest rate is determined weekly. The average weighted interest was 4.7% for 1991 and 6.5% for 1990.
Installment purchase contracts have been entered into by the Company in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:
December 31, 1991 1990 (in thousands)
Under the terms of certain installment purchase contracts, the Company is required to pay purchase price installments in 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 Company's share of construction of pollution control facilities at certain generating plants of the Company.
On certain series the principal is payable at stated maturities or on the demand of the bondholders at periodic interest adjustment dates. Accordingly, the installment purchase con-tracts have been classified for repayment purposes based on their next interest rate adjustment date.
Certain series are supported by bank letters of credit which expire in 1995.,
Long-term debt, excluding premium or discount, outstand-ing at December 31, 1991 is due as follows:
Principal Amount (in thousands) 1992 S
13,500 1993 56,402 1994 13,500 1995 153,500 1996 13,500 Later Years 874,778 Total
$1,125,180 The amount of short-term debt the Company may borrow is limited by the provisions of the 1935 Act to $200 million and further limited by provision of the charter to $130 million The Company shares bank lines of credit with other AEP System companies and at December 31, 1991 and 1990 had unused shared lines of $374 millionand $263 million, respec-tively. Under the terms of the lines of credit, notes can be issued with a maturity of up to 270 days. In accordance with agreements with the banks, commitment fees averaging approximately%8 of 1% a year are required to maintain the lines of credit.
28
Operating Statistics 1991 1990 1989 1988 1987 OPERATING REYENUEs (in thousands):
From Kilowatt-hour Sales:
Retail:
Residential:
Without Electric Heating........
With Electric Heating..........
Total Residential Commercial Industrial Miscellaneous Total Retail Wholesale (sales for resale).........
Total from Kilowatt-hour Sales Provision for Revenue Refunds......
Total Net of Provision for Revenue Refunds.........
Other Operating Revenues Total Operating Revenues.....
192,926 90,495 179,955 86,108 182,786 93,291 189,845 96,145 186,418 90,261 283,421 206,243 226,085 11,631 727,380 464 527 266,063 195,184 228,927 11,273 701,447 545,556 1,191,907 1,247,003 5,175
~5,175) 276,077 196,404 233,990 11,475 717,946 390,685 285,990 194,982 233,855 11,645 726,472 319,211 1,108,631 1,045,683
~1,800) 276,679 191,352 235,470 11,533 715,034 354,441 1,069,475 1,069,475 8,855 1,043,883 10,111 1,241,828 15,261 1,197,082 14 525 1,108,631 12,776
$1,211,607
$1,257,089
$1,121,407
$1,053,994
$1,078,330 SOURCES AND SALES OF ENERGY (in millions of kilowatt-hours):
Sources:
Net Generated:
Fossil Fuel Nuclear Fuel Hydroelectric..........
Total Net Generated......
Purchased and Interchange (net)..
Total Sources Less: Losses, Company Use, Etc..
Net Sources Sales:
Retail:
Residential:
Without Electric Heating With Electric Heating...
Total Residential.....
Commercial Industrial Miscellaneous Total Retail Wholesale (sales for resale)..
Total Sales 12,109 15,524 99 27,732 5,237 32,969 1,408 31,561 2,977
~1582 4,559 3,575 5,078 226 13,438 18,123
- 31) 561 14,451 11,115 116 25,682 7,983 33,665 1,590 32,075 2,774 1,484 4,258 3,388 5,140 221 13,007 19,068 32,075 10,634 12,094 97 22,825 7,630 30,455 1,606 28,849 2,792 1,585 4,377 3,375 5,168 228 13,148 15,701 28,849 8,707 9,791 70 18,568 6,341 24,909 1,630 23,279 2,825 1,571 4,396 3,290 5,036 228 12,950 10,329 23,279 6,662 10,060 62 16,784 7,912 24,696 1,456 23,240 2,719 1,445 4,164 3,142 4,834 221 12,361 10,879 23,240 29
7 INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES OPERATING STATISTICS (Concluded)
- 1991 1990 1989 1988 1987 AYERAGE CosT 0F FUEL C0NSUMEO (in cents):
Per Million Btu:
Coal Nuclear Overall Per Kilowatt-hour Generated:
Coal Nuclear Overall 141 48 84 1.39
~53
.91 145 58 105 1.42
.64 1.08 164 61 106 182 70 120 1.62 1.81
.67
.77 1.11 1.26 190 75 117 1.87
.84 1.25 REsIDENT/AL SERYICE AYERAGES:
Annual Kwh Use per Customer:
Total With Electric Heating Annual Electric Bill:
'otal With Electric Heating Price per Kwh (in cents):
Total With Electric Heating 10s6?8 17,809
$663.80
$1,018.93 6.22 5.72 10,047 16,979
$627.84
$985.16 6.25 5.80 10,434 18,447
$658.08
$1,085.56 6.31 5.88 10,596 18,551
$689.33
$1,135.46 6.51 6.12 10,146 17,341
$674.13
$1,083.10 6.64 6.25 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 Customers 339,448 89 620 429,068 47,433 4,517 2,059 483s077 52 483,129 338,171 88,258 426,429 47,020 4,494 2,018 479,961 54 480,015 335,625 87,016 422,641 46,176 4,485 2,026 475,328 50 475,378 332,488 85,635 418,123 45,249 4,479 1,984 469,835 108 469,943 328,937 84,442 413,379 44,207 4,345 1,946 463,877 105 463,982 30
INDIANAMICHIGANPOWER COMPANY C
Dividends and Price Ranges of Cumulative Preferred Stock BI/Quarters (1991 and 1990)
Cumulative Preferred Stock 1st 1991 Quarters 2nd 3rd 4th 1st 1990 Quarters 2nd 3rd 4th
($100 Par Value) 4/s% Series Dividends Paid Per Share Market Price $ Per Share (MSE) High Low 4.56% Series Dividends Paid Per Share Market Price $ Per Share (OTC)
Ask (high/low)
Bid (high/low) 4.12% Series Dividends Paid Per Share Market Price $ Per Share (OTC)
Ask (high/low)
Bid (high/low) 7.08% Series Dividends Paid Per Share Market Price $ Per Share (NYSE) High Low 7.76% Series Dividends Paid Per Share Market Price $ Per Share (NYSE) High Low 8.68% Series Dividends Paid Per Share Market Price $ Per Share (NYSE) High Low 12% Series (a)
Dividends Paid Per Share Market Price $ Per Share (NYSE) High Low
($25 Par Value)
$2.15 Series Dividends Paid Per Share Market Price $ Per Share (NYSE) High Low
$2.25 Series Dividends Paid Per Share Market Price $ Per Share (NYSE) High Low
$2.75 Series (a)
Dividends Paid Per Share Market Price $ Per Share (NYSE) High Low 39 39 36 36
$1.14
$1.14
$1;14
$1.14
$1.14
$1.14
$1.14
$1.14
$1.03
$1.03
$1.03
$1.03
$1.03
$1.03
$1.03
$1.03 42/39'/s 42/39'/s 42'/>>/39'/s 44/39'/z
$1.77
$1.77
$1.77
$1.77 44/44 42'/2/41'/s 42/40'/s 42/39'/s
$1.77
$1.77
$1.77
$1.77 80'/a 71 79a/>>
76'/>>
83 76'/>>
85'/>>
81 78 73 75 72 77 73 75 72
$1.94
$1.94
$1.94
$1.94
$1.94
$1.94
$1.94
$1.94 92 83 87'/a 83s/>>
87 83'/>>
92s/>>
88 83 79 81 76'/s 77'I>>
76'/>>
83 76s/>>
$2.17
$2.17
$2.17
$2.17 94'/s 89 95 92'/s 96'/s 91'/s 100'/s 95
$2.17
$2.17
$2.17 88'/s
'7'/>>
88'/>>
85'8 85'la 85'/>>
$1.00 107'/z 105'/>>
$2.17 91 84'/>>
$0.5375
$0.5375
$0.5375
$0.5375
$0.5375
$0.5375
$0.5375
$0.5375 25 23'/a 25'/s 23'/i 25%
23'/s 26 24'/s 23 a/s 22%
21 a/a 21%
23'/>>
21%
24'/a 22'/s
$0.5625
$0.5625
$0.5625
$0.5625
$0.5625
$0.5625
$0.5625
$0.5625 26 23%
25'/s 24'/>>
26 24'I>>
26'/>>
24 24'/s 22'/s
$0.229 27 26'l>>
23'/a 22'/s 23'/>>
22'/a 24'/a 23s/s
$1.03125
$1.03125
$1.03125
$1.03125
$1.03125
$1.03125
$1.03125
$1.03125 MSE Midwest Stock Exchange OTC Over-the-Counter NYSE New York Stock Exchange Note The above bid and asked quotations represent prices between dealers and do not represent actual transactions.
Market quotations provided by National Quotation Bureau, inc.
Dash indicates quotation not available.
(a) Redeemed February 1990.
The Company's Annual Report (Form 10-K) to the Securities and Exchange Commission will be available in April 1992 to shareowners upon written request and at no cost.
Please address such requests to:
Mr. G. C. Dean American Electric Power Service Corporation 1 Riverside Plaza Columbus, Ohio 43215 Transfer Agent and Registrar of Cumulative Preferred Stock First Chicago Trust Company of New York 30 West Broadway, New York, N.Y. 10007-2192 32
Indiana Michigan Power Service Area and the American Electric Power System Lrrho M I c h I g rr n MICHIGAN OHIO INDIANA WEST VIRGINIA KENTUCKY VIRGINIA LEGEND Indiana Michigan Power Co. Area Other AEP operating companies'reas 9
MaJor power plant TENNESSEE QP printed onrocycbd paper
ENCLOSURE 2 TO AEP:NRC:0909H INDIANAMICHIGAN POWER COMPANY'S PROJECTED CASH FLOW
t 1992 Internal Cash Flow Projection for Donald C. Cook Nuclear Plant
($ Millions)
Actual 1991 (1)
Projected 1992 Net Income AfterTaxes Less Dividends Paid Retained Earnings 136.9 118.1 18.8 119.3 125.3 (6.0)
Adjustments:
Depreciation And Amortization Deferred Federal Income Taxes and Investment Tax Credits AFUDC Total Adjustments 158.8 (31.1)
(2.1) 125.6 160.8 (17.6)
(5.1) 138.1 Internal Cash Flow Average Quarterly Cash Flow 144.4 36.1 132.1 33.0 Average Cash Balances and Short-Term Investments Total 5.8 41.9 11.4 44.4 (1) Restated for MPCO merger with 18 M
% Ownership in all operating nuclear units:
Unit 1 and Unit 2-100%
Maximum Total Contingent Liability- $20.0 million (2 units)
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