<PAGE> 1
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
----------------------------
FORM 10-K
----------------------------
(Mark One)
|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1999
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 For the transition period from _____________ to
______________
COMMISSION REGISTRANT; STATE OF INCORPORATION; I.R.S. EMPLOYER
FILE NUMBER ADDRESS AND TELEPHONE NUMBER IDENTIFICATION NO.
- ----------- ----------------------------------- ------------------
1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. 13-4922640
(A New York Corporation)
1 Riverside Plaza
Columbus, Ohio 43215
Telephone (614) 223-1000
0-18135 AEP GENERATING COMPANY 31-1033833
(An Ohio Corporation)
1 Riverside Plaza
Columbus, Ohio 43215
Telephone (614) 223-1000
1-3457 APPALACHIAN POWER COMPANY 54-0124790
(A Virginia Corporation)
40 Franklin Road, S.W.
Roanoke, Virginia 24011
Telephone (540) 985-2300
1-2680 COLUMBUS SOUTHERN POWER COMPANY 31-4154203
(An Ohio Corporation)
1 Riverside Plaza
Columbus, Ohio 43215
Telephone (614) 223-1000
1-3570 INDIANA MICHIGAN POWER COMPANY 35-0410455
(An Indiana Corporation)
One Summit Square
P. O. Box 60
Fort Wayne, Indiana 46801
Telephone (219) 425-2111
1-6858 KENTUCKY POWER COMPANY 61-0247775
(A Kentucky Corporation)
1701 Central Avenue
Ashland, Kentucky 41101
Telephone (800) 572-1141
1-6543 OHIO POWER COMPANY 31-4271000
(An Ohio Corporation)
301 Cleveland Avenue, S.W.
Canton, Ohio 44702
Telephone (330) 456-8173
AEP Generating Company, Columbus Southern Power Company and Kentucky
Power Company meet the conditions set forth in General Instruction I(1)(a) and
(b) of Form 10-K and are therefore filing this Form 10-K with the reduced
disclosure format specified in General Instruction I(2) to such Form 10-K.
<PAGE> 2
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
<TABLE>
<CAPTION>
NAME OF EACH EXCHANGE
REGISTRANT TITLE OF EACH CLASS ON WHICH REGISTERED
---------- ------------------- ---------------------
<S> <C> <C>
AEP Generating Company None
American Electric Common Stock,
Power Company, Inc. $6.50 par value.................................. New York Stock Exchange
Appalachian Power Cumulative Preferred Stock,
Company Voting, no par value:
4-1/2%.......................................... Philadelphia Stock Exchange
8-1/4% Junior Subordinated Deferrable
Interest Debentures, Series A,
Due 2026........................................ New York Stock Exchange
8% Junior Subordinated Deferrable
Interest Debentures, Series B,
Due 2027........................................ New York Stock Exchange
7.20% Senior Notes, Series A,
Due 2038........................................ New York Stock Exchange
7.30% Senior Notes, Series B,
Due 2038..........................................New York Stock Exchange
Columbus Southern 8-3/8% Junior Subordinated Deferrable
Power Company Interest Debentures, Series A,
Due 2025........................................ New York Stock Exchange
7.92% Junior Subordinated Deferrable
Interest Debentures, Series B,
Due 2027........................................ New York Stock Exchange
Indiana Michigan 8% Junior Subordinated Deferrable
Power Company Interest Debentures, Series A,
Due 2026........................................ New York Stock Exchange
7.60% Junior Subordinated Deferrable
Interest Debentures, Series B,
Due 2038..........................................New York Stock Exchange
Kentucky Power 8.72% Junior Subordinated Deferrable
Company Interest Debentures, Series A,
Due 2025........................................ New York Stock Exchange
Ohio Power Company 8.16% Junior Subordinated Deferrable
Interest Debentures, Series A,
Due 2025........................................ New York Stock Exchange
7.92% Junior Subordinated Deferrable
Interest Debentures, Series B,
Due 2027..........................................New York Stock Exchange
7 3/8% Senior Notes, Series A,
Due 2038........................................ New York Stock Exchange
</TABLE>
Indicate by check mark whether the registrants (1) have filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. Yes X . No.
---
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. X
---
<PAGE> 3
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
<TABLE>
<CAPTION>
REGISTRANT TITLE OF EACH CLASS
---------- -------------------
<S> <C>
AEP Generating Company None
American Electric Power Company, Inc None
Appalachian Power Company None
Columbus Southern Power Company None
Indiana Michigan Power Company 4-1/8% Cumulative Preferred Stock, Non-Voting, $100 par value
Kentucky Power Company None
Ohio Power Company 4-1/2% Cumulative Preferred Stock, Voting, $100 par value
</TABLE>
<TABLE>
<CAPTION>
AGGREGATE MARKET VALUE
OF VOTING AND NON-VOTING NUMBER OF SHARES
COMMON EQUITY HELD OF COMMON STOCK
BY NON-AFFILIATES OF OUTSTANDING OF
THE REGISTRANTS AT THE REGISTRANTS AT
FEBRUARY 1, 2000 FEBRUARY 1, 2000
------------------------- ---------------------
<S> <C> <C>
AEP Generating Company None 1,000
($1,000 par value)
American Electric Power Company, Inc $6,538,856,569 194,103,349
($6.50 par value)
Appalachian Power Company None 13,499,500
(no par value)
Columbus Southern Power Company None 16,410,426
(no par value)
Indiana Michigan Power Company None 1,400,000
(no par value)
Kentucky Power Company None 1,009,000
($50 par value)
Ohio Power Company None 27,952,473
(no par value)
</TABLE>
NOTE ON MARKET VALUE OF COMMON EQUITY HELD BY NON-AFFILIATES
All of the common stock of AEP Generating Company, Appalachian Power
Company, Columbus Southern Power Company, Indiana Michigan Power Company,
Kentucky Power Company and Ohio Power Company is owned by American Electric
Power Company, Inc. (see Item 12 herein).
<PAGE> 4
DOCUMENTS INCORPORATED BY REFERENCE
<TABLE>
<CAPTION>
PART OF FORM 10-K
INTO WHICH DOCUMENT
DESCRIPTION IS INCORPORATED
- ----------- -------------------
<S> <C>
Portions of Annual Reports of the following companies for the fiscal year Part II
ended December 31, 1999:
AEP Generating Company
American Electric Power Company, Inc.
Appalachian Power Company
Columbus Southern Power Company
Indiana Michigan Power Company
Kentucky Power Company
Ohio Power Company
Portions of Proxy Statement of American Electric Power Company, Inc. for Part III
2000 Annual Meeting of Shareholders, to be filed within 120 days after
December 31, 1999
Portions of Information Statements of the following companies for 2000 Part III
Annual Meeting of Shareholders, to be filed within 120 days after December 31,
1999
Appalachian Power Company
Ohio Power Company
</TABLE>
------------------------------
THIS COMBINED FORM 10-K IS SEPARATELY FILED BY AEP GENERATING COMPANY,
AMERICAN ELECTRIC POWER COMPANY, INC., APPALACHIAN POWER COMPANY, COLUMBUS
SOUTHERN POWER COMPANY, INDIANA MICHIGAN POWER COMPANY, KENTUCKY POWER COMPANY
AND OHIO POWER COMPANY. INFORMATION CONTAINED HEREIN RELATING TO ANY INDIVIDUAL
REGISTRANT IS FILED BY SUCH REGISTRANT ON ITS OWN BEHALF. EXCEPT FOR AMERICAN
ELECTRIC POWER COMPANY, INC., EACH REGISTRANT MAKES NO REPRESENTATION AS TO
INFORMATION RELATING TO THE OTHER REGISTRANTS.
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<PAGE> 5
TABLE OF CONTENTS
PAGE
NUMBER
------
Glossary of Terms........................................................ i
Forward-Looking Information.............................................. 1
PART I
Item 1. Business............................................. 2
Item 2. Properties........................................... 38
Item 3. Legal Proceedings.................................... 43
Item 4. Submission of Matters to a Vote of Security Holders.. 44
Executive Officers of the Registrants.............................. 44
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters.............................. 46
Item 6. Selected Financial Data.............................. 47
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition............... 47
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk ............................................ 48
Item 8. Financial Statements and Supplementary Data.......... 48
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure........... 48
PART III
Item 10. Directors and Executive Officers of the Registrants.. 48
Item 11. Executive Compensation............................... 50
Item 12. Security Ownership of Certain Beneficial Owners
and Management.................................. 54
Item 13. Certain Relationships and Related Transactions....... 56
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K..................................... 56
Signatures............................................................... 58
Index to Financial Statement Schedules................................... S-1
Independent Auditors' Report............................................. S-2
Exhibit Index............................................................ E-1
<PAGE> 6
GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this
report, they have the meanings indicated below.
TERM MEANING
<TABLE>
<CAPTION>
<S> <C>
AEGCo...........................AEP Generating Company, an electric utility subsidiary of AEP.
AEP ............................American Electric Power Company, Inc.
AEP System or the System........The American Electric Power System, an integrated electric utility system,
owned and operated by AEP's electric utility subsidiaries.
AFUDC...........................Allowance for funds used during construction. Defined in regulatory systems
of accounts as the net cost of borrowed funds used for construction and a
reasonable rate of return on other funds when so used.
APCo............................Appalachian Power Company, an electric utility subsidiary of AEP.
Buckeye.........................Buckeye Power, Inc., an unaffiliated corporation.
CCD Group.......................CSPCo, CG&E and DP&L.
CG&E............................The Cincinnati Gas & Electric Company, an unaffiliated utility company.
Cook Plant......................The Donald C. Cook Nuclear Plant, owned by I&M.
CSPCo...........................Columbus Southern Power Company, an electric utility subsidiary of AEP.
CSW.............................Central and South West Corporation.
DOE.............................United States Department of Energy.
DP&L............................The Dayton Power and Light Company, an unaffiliated utility company.
Federal EPA.....................United States Environmental Protection Agency.
FERC............................Federal Energy Regulatory Commission (an independent commission within
the DOE).
I&M.............................Indiana Michigan Power Company, an electric utility subsidiary of AEP.
IURC............................Indiana Utility Regulatory Commission.
KEPCo...........................Kentucky Power Company, an electric utility subsidiary of AEP.
KPSC............................Kentucky Public Service Commission.
MPSC............................Michigan Public Service Commission.
NEIL............................Nuclear Electric Insurance Limited.
NPDES...........................National Pollutant Discharge Elimination System.
NRC.............................Nuclear Regulatory Commission.
Ohio EPA........................Ohio Environmental Protection Agency.
OPCo............................Ohio Power Company, an electric utility subsidiary of AEP.
OVEC............................Ohio Valley Electric Corporation, an electric utility company in which AEP
and CSPCo own a 44.2% equity interest.
PCBs............................Polychlorinated biphenyls.
PUCO............................The Public Utilities Commission of Ohio.
PUHCA...........................Public Utility Holding Company Act of 1935, as amended.
RCRA............................Resource Conservation and Recovery Act of 1976, as amended.
Rockport Plant..................A generating plant, consisting of two 1,300,000-kilowatt coal-fired
generating units, near Rockport, Indiana.
SEC.............................Securities and Exchange Commission.
Service Corporation.............American Electric Power Service Corporation, a service subsidiary of AEP.
SO(2) Allowance.................An allowance to emit one ton of sulfur dioxide granted under the Clean Air
Act Amendments of 1990.
TVA ............................Tennessee Valley Authority.
VEPCo...........................Virginia Electric and Power Company, an unaffiliated utility company.
Virginia SCC....................Virginia State Corporation Commission.
West Virginia PSC...............Public Service Commission of West Virginia.
Zimmer or Zimmer Plant..........Wm. H. Zimmer Generating Station, commonly owned by CSPCo, CG&E and DP&L.
</TABLE>
i
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[THIS PAGE INTENTIONALLY LEFT BLANK]
<PAGE> 8
FORWARD-LOOKING INFORMATION
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This report made by AEP and certain of its subsidiaries includes
forward-looking statements within the meaning of Section 21E of the Securities
Exchange Act of 1934. These forward-looking statements reflect assumptions and
involve a number of risks and uncertainties. Among the factors that could cause
actual results to differ materially from forward-looking statements are:
o Electric load and customer growth.
o Abnormal weather conditions.
o Available sources and costs of fuels.
o Availability of generating capacity.
o The impact of the proposed merger with CSW, including any
regulatory conditions imposed on the merger and the ability of
the combined companies to realize the synergies expected as a
result of the proposed combination, or the inability to
consummate the merger with CSW.
o The speed and degree to which competition is introduced to our
power generation business.
o The structure and timing of a competitive market and its
impact on energy prices or fixed rates.
o The ability to recover net regulatory assets and other
stranded costs in connection with deregulation of generation.
o New legislation and government regulations.
o The ability of AEP to successfully control its costs.
o The success of new business ventures.
o International developments affecting AEP's foreign
investments.
o The effects of fluctuations in foreign currency exchange
rates.
o The economic climate and growth in AEP's service territory.
o Unforeseen events affecting AEP's efforts to restart its
nuclear generating units which are on an extended safety
related shutdown.
o The ability of AEP to challenge successfully new environmental
regulations and to litigate successfully claims that AEP
violated the Clean Air Act.
o Inflationary trends.
o Changes in electricity and gas market prices.
o Interest rates.
o Other risks and unforeseen events.
1
<PAGE> 9
PART I ========================================================================
Item 1. BUSINESS
- --------------------------------------------------------------------------------
GENERAL
AEP was incorporated under the laws of the State of New York in 1906
and reorganized in 1925. It is a public utility holding company which owns,
directly or indirectly, all of the outstanding common stock of its domestic
electric utility subsidiaries and varying percentages of other subsidiaries.
Substantially all of the operating revenues of AEP and its subsidiaries are
derived from the furnishing of electric service. In addition, in recent years
AEP has been pursuing various unregulated business opportunities worldwide as
discussed in New Business Development.
The service area of AEP's domestic electric utility subsidiaries covers
portions of the states of Indiana, Kentucky, Michigan, Ohio, Tennessee, Virginia
and West Virginia. The generating and transmission facilities of AEP's
subsidiaries are physically interconnected, and their operations are
coordinated, as a single integrated electric utility system. Transmission
networks are interconnected with extensive distribution facilities in the
territories served. The electric utility subsidiaries of AEP, which do business
as "American Electric Power," have traditionally provided electric service,
consisting of generation, transmission and distribution, on an integrated basis
to their retail customers.
At December 31, 1999, the subsidiaries of AEP had a total of 17,306
employees. AEP, as such, has no employees. The operating subsidiaries of AEP
are:
APCo (organized in Virginia in 1926) is engaged in the generation, sale,
purchase, transmission and distribution of electric power to approximately
896,000 retail customers in the southwestern portion of Virginia and
southern West Virginia, and in supplying electric power at wholesale to
other electric utility companies and municipalities in those states and in
Tennessee. At December 31, 1999, APCo and its wholly owned subsidiaries had
3,290 employees. Among the principal industries served by APCo are coal
mining, primary metals, chemicals and textile mill products. In addition to
its AEP System interconnections, APCo also is interconnected with the
following unaffiliated utility companies: Carolina Power & Light Company,
Duke Energy Corporation and VEPCo. A comparatively small part of the
properties and business of APCo is located in the northeastern end of the
Tennessee Valley. APCo has several points of interconnection with TVA and
has entered into agreements with TVA under which APCo and TVA interchange
and transfer electric power over portions of their respective systems.
CSPCo (organized in Ohio in 1937, the earliest direct predecessor
company having been organized in 1883) is engaged in the generation, sale,
purchase, transmission and distribution of electric power to approximately
655,000 customers in Ohio, and in supplying electric power at wholesale to
other electric utilities and to municipally owned distribution systems
within its service area. At December 31, 1999, CSPCo had 1,466 employees.
CSPCo's service area is comprised of two areas in Ohio, which include
portions of twenty-five counties. One area includes the City of Columbus and
the other is a predominantly rural area in south central Ohio. Approximately
80% of CSPCo's retail revenues are derived from the Columbus area. Among the
principal industries served are food processing, chemicals, primary metals,
electronic machinery and paper products. In addition to its AEP System
interconnections, CSPCo also is interconnected with the following
unaffiliated utility companies: CG&E, DP&L and Ohio Edison Company.
I&M (organized in Indiana in 1925) is engaged in the generation, sale,
purchase, transmission and distribution of electric power to approximately
559,000 customers in northern and eastern Indiana and southwestern Michigan,
and in supplying electric power at wholesale to other electric utility
companies, rural electric cooperatives and municipalities. At December 31,
1999, I&M had 3,130 employees. Among the principal industries
2
<PAGE> 10
served are primary metals, transportation equipment, electrical and
electronic machinery, fabricated metal products, rubber and miscellaneous
plastic products and chemicals and allied products. Since 1975, I&M has
leased and operated the assets of the municipal system of the City of Fort
Wayne, Indiana. In addition to its AEP System interconnections, I&M also is
interconnected with the following unaffiliated utility companies: Central
Illinois Public Service Company, CG&E, Commonwealth Edison Company,
Consumers Energy Company, Illinois Power Company, Indianapolis Power & Light
Company, Louisville Gas and Electric Company, Northern Indiana Public
Service Company, PSI Energy Inc. and Richmond Power & Light Company.
KEPCo (organized in Kentucky in 1919) is engaged in the generation,
sale, purchase, transmission and distribution of electric power to
approximately 171,000 customers in an area in eastern Kentucky, and in
supplying electric power at wholesale to other utilities and municipalities
in Kentucky. At December 31, 1999, KEPCo had 501 employees. In addition to
its AEP System interconnections, KEPCo also is interconnected with the
following unaffiliated utility companies: Kentucky Utilities Company and
East Kentucky Power Cooperative Inc. KEPCo is also interconnected with TVA.
Kingsport Power Company (organized in Virginia in 1917) provides
electric service to approximately 45,000 customers in Kingsport and eight
neighboring communities in northeastern Tennessee. Kingsport Power Company
has no generating facilities of its own. It purchases electric power
distributed to its customers from APCo. At December 31, 1999, Kingsport
Power Company had 62 employees.
OPCo (organized in Ohio in 1907 and re-incorporated in 1924) is engaged
in the generation, sale, purchase, transmission and distribution of electric
power to approximately 691,000 customers in the northwestern, east central,
eastern and southern sections of Ohio, and in supplying electric power at
wholesale to other electric utility companies and municipalities. At
December 31, 1999, OPCo and its wholly owned subsidiaries had 3,941
employees. Among the principal industries served by OPCo are primary metals,
rubber and plastic products, stone, clay, glass and concrete products,
petroleum refining and chemicals. In addition to its AEP System
interconnections, OPCo also is interconnected with the following
unaffiliated utility companies: CG&E, The Cleveland Electric Illuminating
Company, DP&L, Duquesne Light Company, Kentucky Utilities Company,
Monongahela Power Company, Ohio Edison Company, The Toledo Edison Company
and West Penn Power Company.
Wheeling Power Company (organized in West Virginia in 1883 and
reincorporated in 1911) provides electric service to approximately 42,000
customers in northern West Virginia. Wheeling Power Company has no
generating facilities of its own. It purchases electric power distributed to
its customers from OPCo. At December 31, 1999, Wheeling Power Company had 74
employees.
Another principal electric utility subsidiary of AEP is AEGCo, which was
organized in Ohio in 1982 as an electric generating company. AEGCo sells power
at wholesale to I&M and KEPCo. AEGCo's agreement to sell power to VEPCo expired
December 31, 1999. AEGCo has no employees.
See Item 2 for information concerning the properties of the subsidiaries
of AEP.
The Service Corporation provides accounting, administrative, information
systems, engineering, financial, legal, maintenance and other services at cost
to the AEP System companies. The executive officers of AEP and its public
utility subsidiaries are all employees of the Service Corporation.
REGULATION
General
AEP and its subsidiaries are subject to the broad regulatory provisions of
PUHCA administered by the SEC. The public utility subsidiaries' retail rates and
certain other matters are
3
<PAGE> 11
subject to regulation by the public utility commissions of the states in which
they operate. Such subsidiaries are also subject to regulation by the FERC under
the Federal Power Act in respect of rates for interstate sale at wholesale and
transmission of electric power, accounting and other matters and construction
and operation of hydroelectric projects. I&M is subject to regulation by the NRC
under the Atomic Energy Act of 1954, as amended, with respect to the operation
of the Cook Plant.
Possible Change to PUHCA
The provisions of PUHCA, administered by the SEC, regulate all aspects of
a registered holding company system, such as the AEP System. PUHCA requires that
the operations of a registered holding company system be limited to a single
integrated public utility system and such other businesses as are incidental or
necessary to the operations of the system. In addition, PUHCA governs, among
other things, financings, sales or acquisitions of assets and intra-system
transactions.
On June 20, 1995, the SEC released a report from its Division of
Investment Management recommending a conditional repeal of PUHCA, including its
limits on financing and on geographic and business diversification. Specific
federal authority, however, would be preserved over access to the books and
records of registered holding company systems, audit authority over registered
holding companies and their subsidiaries and oversight over affiliate
transactions. This authority would be transferred to the FERC. Legislation was
introduced in Congress in 1997 that would repeal PUHCA and transfer certain
federal authority to the FERC as recommended in the SEC report as part of
broader legislation regarding changes in the electric industry. Such legislation
has been reintroduced in 1999. It is expected that a number of bills
contemplating the restructuring of the electric utility industry will be
introduced in the current Congress. See Competition and Business Change. If
PUHCA is repealed, registered holding company systems, including the AEP System,
will be able to compete in the changing industry without the constraints of
PUHCA. Management of AEP believes that removal of these constraints would be
beneficial to the AEP System.
PUHCA and the rules and orders of the SEC currently require that
transactions between associated companies in a registered holding company system
be performed at cost with limited exceptions. Over the years, the AEP System has
developed numerous affiliated service, sales and construction relationships and,
in some cases, invested significant capital and developed significant operations
in reliance upon the ability to recover its full costs under these provisions.
Legislation has been introduced in Congress to repeal PUHCA or modify its
provisions governing intra-system transactions. The effect of repeal or
amendment of PUHCA on AEP's intra-system transactions depends on whether the
assurance of full cost recovery is eliminated immediately or phased-in and
whether it is eliminated for all intra-system transactions or only some. If the
cost recovery assurance is eliminated immediately for all intra-system
transactions, it could have a material adverse effect on results of operations
and financial condition of AEP and OPCo.
Conflict of Regulation
Public utility subsidiaries of AEP can be subject to regulation of the
same subject matter by two or more jurisdictions. In such situations, it is
possible that the decisions of such regulatory bodies may conflict or that the
decision of one such body may affect the cost of providing service and so the
rates in another jurisdiction. In a case involving OPCo, the U.S. Court of
Appeals for the District of Columbia held that the determination of costs to be
charged to associated companies by the SEC under PUHCA precluded the FERC from
determining that such costs were unreasonable for ratemaking purposes. The U.S.
Supreme Court also has held that a state commission may not conclude that a FERC
approved wholesale power agreement is unreasonable for state ratemaking
purposes. Certain actions that would overturn these decisions or otherwise
affect the jurisdiction of the SEC and FERC are under consideration by the U.S.
Congress and these regulatory bodies. Such conflicts of jurisdiction often
result in litigation and, if resolved adversely to a public utility subsidiary
of AEP, could have a material adverse effect on the results of operations or
financial condition of such subsidiary or AEP.
4
<PAGE> 12
CLASSES OF SERVICE
The principal classes of service from which the domestic electric utility
subsidiaries of AEP derive revenues and the amount of such revenues (from
kilowatt-hour sales) during the year ended December 31, 1999 are as follows:
<TABLE>
<CAPTION>
AEP
AEGCo APCo CSPCo I&M KEPCo OPCo SYSTEM (a)
----- ---- ----- --- ----- ---- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
Retail
Residential
Without Electric Heating .... $ 0 $ 232,122 $ 359,319 $ 263,467 $ 39,460 $ 289,705 $1,205,461
With Electric Heating ....... 0 346,040 113,881 114,319 67,196 144,034 822,111
-------- ---------- ---------- ---------- -------- ---------- ----------
Total Residential ....... 0 578,162 473,200 377,786 106,656 433,739 2,027,572
Commercial ..................... 0 301,325 420,612 290,833 62,641 276,539 1,390,453
Industrial ..................... 0 377,373 151,353 364,607 96,660 665,751 1,716,254
Miscellaneous .................. 0 35,378 17,289 6,708 898 8,222 72,211
-------- ---------- ---------- ---------- -------- ---------- ----------
Total Retail ............. 0 1,292,238 1,062,454 1,039,934 266,855 1,384,251 5,206,490
Wholesale (sales for resale) ...... 216,959 269,368 120,374 303,533 80,455 572,136 814,190
-------- ---------- ---------- ---------- -------- ---------- ----------
Total from KWH Sales ..... 216,959 1,561,606 1,182,828 1,343,467 347,310 1,956,387 6,020,680
Provision for Revenue Refunds ..... 0 8,687 0 (1,143) 0 0 8,466
-------- ---------- ---------- ---------- -------- ---------- ----------
Total Net of Provision for
Revenue Refunds ...... 216,959 1,570,293 1,182,828 1,342,324 347,310 1,956,387 6,029,146
Other Operating Revenues .......... 230 80,644 47,166 51,795 26,672 82,876 285,517
-------- ---------- ---------- ---------- -------- ---------- ----------
Total Electric Operating
Revenues ............. $217,189 $1,650,937 $1,229,994 $1,394,119 $373,982 $2,039,263 $6,314,663
======== ========== ========== ========== ======== ========== ==========
</TABLE>
- ----------------------------
(a) Includes revenues of other subsidiaries not shown and elimination of
intercompany transactions.
SALE OF POWER
AEP's electric utility subsidiaries own or lease generating stations
with total generating capacity of 23,759 megawatts. See Item 2 for more
information regarding the generating stations. They operate their generating
plants as a single interconnected and coordinated electric utility system and
share the costs and benefits in the AEP System Power Pool. Most of the electric
power generated at these stations is sold, in combination with transmission and
distribution services, to retail customers of AEP's utility subsidiaries in
their service territories. These sales are made at rates that are established by
the public utility commissions of the state in which they operate. See Rates and
Regulation. Some of the electric power is sold at wholesale to non-affiliated
companies.
AEP System Power Pool
APCo, CSPCo, I&M, KEPCo and OPCo are parties to the Interconnection
Agreement, dated July 6, 1951, as amended (the Interconnection Agreement),
defining how they share the costs and benefits associated with the System's
generating plants. This sharing is based upon each company's "member-load-
ratio," which is calculated monthly on the basis of each company's maximum peak
demand in relation to the sum of the maximum peak demands of all five companies
during the preceding 12 months. In addition, since 1995, APCo, CSPCo, I&M, KEPCo
and OPCo have been parties to the AEP System Interim Allowance Agreement which
provides, among other things, for the transfer of SO(2) Allowances associated
with transactions under the Interconnection Agreement.
Power marketing and trading transactions (trading activities) are
conducted by the AEP Power Pool and shared among the parties under the
Interconnection Agreement. Trading activities involve the purchase and sale of
electricity under physical forward contracts at fixed and variable prices and
the trading of electricity contracts including exchange traded futures and
options and over-the-counter options and swaps. The majority of these
transactions represent physical forward contracts in the AEP System's
traditional marketing area and are typically settled by entering into offsetting
contracts. The regulated physical forward contracts are recorded on a net basis
in the month when the contract settles.
In addition, the AEP Power Pool enters into transactions for the
purchase and sale of electricity options, futures and swaps, and for the forward
purchase and sale of electricity outside of the AEP System's traditional
marketing area.
The following table shows the net credits or (charges) allocated among
the parties under
5
<PAGE> 13
the Interconnection Agreement and Interim Allowance Agreement during the years
ended December 31, 1997, 1998 and 1999:
<TABLE>
<CAPTION>
1997(a) 1998(a) 1999(a)
------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
APCo....... $(237,000) $(142,500) $ (89,100)
CSPCo...... (138,000) (146,800) (184,500)
I&M........ 67,000 (86,100) (61,700)
KEPCo...... 20,000 34,000 23,700
OPCo....... 288,000 341,400 311,600
</TABLE>
- -------------------------
(a) Includes credits and charges from allowance transfers related to the
transactions.
Wholesale Sales of Power to Non-Affiliates
AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo also sell electric power on a
wholesale basis to non-affiliated electric utilities and power marketers. Such
sales are either made by the AEP System Power Pool and then allocated among
APCo, CSPCo, I&M, KEPCo and OPCo based on member-load-ratios or made by
individual companies pursuant to various long-term power agreements. The
following table shows the net realization (revenue less operating, maintenance,
fuel and federal income tax expenses) of the various companies from such sales
during the years ended December 31, 1997, 1998 and 1999:
<TABLE>
<CAPTION>
1997(a) 1998(a) 1999(a)
------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
AEGCo(b)....... $ 26,200 $ 23,500 $ 23,800
APCo(c)........ 37,500 40,700 32,900
CSPCo(c)....... 18,300 23,000 19,700
I&M(c)(d)...... 42,400 47,800 42,300
KEPCo(c)....... 7,700 8,700 7,700
OPCo(c)........ 30,200 36,900 30,500
-------- -------- --------
Total System... $162,300 $180,600 $156,900
======== ======== ========
</TABLE>
- -----------------------
(a) Such sales do not include wholesale sales to full/partial requirement
customers of AEP System companies. See the discussion below.
(b) All amounts for AEGCo are from sales made pursuant to a long-term power
agreement that expired on December 31, 1999. See AEGCo--Unit Power
Agreements.
(c) All amounts, except for I&M, are from System sales which are allocated
among APCo, CSPCo, I&M, KEPCo and OPCo based upon member-load-ratio. All
System sales made in 1997, 1998 and 1999 were made on a short-term basis,
except that $25,900,000, $38,300,000 and $37,400,000, respectively, of the
contribution to operating income for the total System were from long-term
System sales.
(d) In addition to its allocation of System sales, the 1997, 1998 and 1999
amounts for I&M include $21,100,000, $21,800,000 and $20,800,000,
respectively, from a long-term agreement to sell 250 megawatts of power
scheduled to terminate in 2009.
The AEP System has long-term system agreements to sell the following to
unaffiliated utilities: (1) 205 megawatts of electric power through August 2010;
and (2) 50 megawatts of electric power through August 2001.
In June 1993, certain municipal customers of APCo filed an application
with the FERC for transmission service in order to reduce by 50 megawatts the
power these customers then purchased under existing Electric Service Agreements
(ESAs) and to purchase power from a third party. APCo maintains that its
agreements with these customers were full-requirements contracts which precluded
the customers from purchasing power from third parties until 1998. On February
10, 1994, the FERC issued an order finding that the ESAs are not full
requirements contracts and that the ESAs give these municipal wholesale
customers the option of substituting alternative sources of power for energy
purchased from APCo. On May 24, 1994, APCo appealed the February 10, 1994 order
of the FERC to the U.S. Court of Appeals for the District of Columbia Circuit.
On July 1, 1994, the FERC ordered the requested transmission service and granted
a complaint filed by the municipal customers directing certain modifications to
the ESAs in order to accommodate their power purchases from the third party.
Following FERC's denial of APCo's requests for rehearing, on December 20, 1995,
APCo appealed the July 1, 1994 orders to the U.S. Court of Appeals for the
District of Columbia. Effective August 1994, these municipal customers reduced
their purchases by 40 megawatts. Certain of these customers further reduced
their purchases by an additional 21 megawatts effective February 1996. On
December 17, 1996, the U.S. Court of Appeals reversed the FERC's order directing
APCo to provide transmission service and remanded the case to the FERC. On April
5, 1999, the FERC found that its previous orders did not violate the Federal
Power Act. On February 29, 2000, the FERC denied APCo's request for rehearing.
The customers terminated their contracts with APCo in 1998.
TRANSMISSION SERVICES
AEP's electric utility subsidiaries own and operate transmission and
distribution lines and other facilities to deliver electric power. See Item 2
for
6
<PAGE> 14
more information regarding the transmission and distribution lines. AEP's
electric utility subsidiaries operate their transmission lines as a single
interconnected and coordinated system and share the cost and benefits in the AEP
System Transmission Pool. Most of the transmission and distribution services is
sold, in combination with electric power, to retail customers of AEP's utility
subsidiaries in their service territories. These sales are made at rates that
are established by the public utility commissions of the state in which they
operate. See Rates and Regulation. As discussed below, some transmission
services also are separately sold to non-affiliated companies.
AEP System Transmission Pool
APCo, CSPCo, I&M, KEPCo and OPCo are parties to the Transmission
Agreement, dated April 1, 1984, as amended (the Transmission Agreement),
defining how they share the costs associated with their relative ownership of
the extra-high-voltage transmission system (facilities rated 345 kv and above)
and certain facilities operated at lower voltages (138 kv and above). Like the
Interconnection Agreement, this sharing is based upon each company's
"member-load-ratio." See Sale of Power.
The following table shows the net (credits) or charges allocated among
the parties to the Transmission Agreement during the years ended December 31,
1997, 1998 and 1999:
<TABLE>
<CAPTION>
1997 1998 1999
---- ---- ----
(IN THOUSANDS)
<S> <C> <C> <C>
APCo........ $ 8,400 $ (2,400) $ (8,300)
CSPCo....... 29,900 35,600 39,000
I&M......... (46,100) (44,100) (43,900)
KEPCo....... (2,700) (6,000) (4,300)
OPCo........ 10,500 16,900 17,500
</TABLE>
Transmission Services for Non-Affiliates
APCo, CSPCo, I&M, KEPCo, OPCo and other System companies also provide
transmission services for non-affiliated companies. The following table shows
the revenues net of federal income tax expenses of the various companies from
such services during the years ended December 31, 1997, 1998 and 1999:
<TABLE>
<CAPTION>
1997 1998 1999
---- ---- ----
(IN THOUSANDS)
<S> <C> <C> <C>
APCo............. $18,000 $ 30,600 $ 28,600
CSPCo............ 10,200 18,100 18,600
I&M.............. 10,500 19,200 19,800
KEPCo............ 3,900 6,400 6,800
OPCo............. 27,200 42,100 38,300
------- -------- --------
Total System..... $69,800 $116,400 $112,100
======= ======== ========
</TABLE>
The AEP System has contracts with non-affiliated companies for
transmission of approximately 5,400 megawatts of electric power on an annual or
longer basis.
On April 24, 1996, the FERC issued orders 888 and 889. These orders
require each public utility that owns or controls interstate transmission
facilities to file an open access network and point-to-point transmission tariff
that offers services comparable to the utility's own uses of its transmission
system. The orders also require utilities to functionally unbundle their
services, by requiring them to use their own tariffs in making off-system and
third-party sales. As part of the orders, the FERC issued a pro-forma tariff
which reflects the Commission's views on the minimum non-price terms and
conditions for non-discriminatory transmission service. In addition, the orders
require all transmitting utilities to establish an Open Access Same-time
Information System (OASIS) which electronically posts transmission information
such as available capacity and prices, and require utilities to comply with
Standards of Conduct which prohibit utilities' system operators from providing
non-public transmission information to the utility's merchant employees. The
orders also allow a utility to seek recovery of certain prudently-incurred
stranded costs that result from unbundled transmission service.
In December 1999, FERC issued Order 2000, which provides for the
voluntary formation of regional transmission organizations (RTOs), entities
created to operate, plan and control utility transmission assets. Order 2000
also prescribes certain characteristics and functions of acceptable RTO
proposals. The rule requires all public utilities, such as the AEP operating
companies, that are members of an approved or conditionally approved
transmission entity, to file by January 2001 an explanation of how that entity
meets the characteristics and functions specified in the order.
7
<PAGE> 15
On July 9, 1996, the AEP System companies filed a tariff conforming
with the FERC's pro-forma transmission tariff.
During 1998 and 1999 AEP engaged in discussions with Consumers Energy
Company, FirstEnergy Corp., Detroit Edison Company and VEPCo regarding the
development of the Alliance RTO which may take the form of an independent system
operator (ISO) or an independent transmission company (Transco), depending upon
the occurrence of certain conditions. The Transco, if formed, would operate
transmission assets that it would own, and also would operate other owners'
transmission assets on a contractual basis. In 1999, these companies filed with
the FERC a proposal to form the RTO. In December 1999, the FERC approved the
Alliance RTO, conditioned upon certain changes to the proposal relating to
governance of the RTO, resolution of intra-RTO conflicts and establishment of a
rate structure. The participants are currently developing a revised proposal to
respond to the concerns expressed in the FERC's order. See Competition and
Business Change -- AEP Position on Competition.
OVEC
AEP, CSPCo and several unaffiliated utility companies jointly own OVEC,
which supplies the power requirements of a uranium enrichment plant near
Portsmouth, Ohio, owned by the DOE. The aggregate equity participation of AEP
and CSPCo in OVEC is 44.2%. The DOE demand under OVEC's power agreement, which
is subject to change from time to time, is 899,000 kilowatts. On March 1, 2000,
it is scheduled to increase to approximately 1,249,000 kilowatts. The proceeds
from the sale of power by OVEC are designed to be sufficient for OVEC to meet
its operating expenses and fixed costs and to provide a return on its equity
capital. APCo, CSPCo, I&M and OPCo, as sponsoring companies, are entitled to
receive from OVEC, and are obligated to pay for, the power not required by DOE
in proportion to their power participation ratios, which averaged 42.1% in 1999.
The power agreement with DOE terminates on December 31, 2005, subject to early
termination by DOE on not less than three years notice. The power agreement
among OVEC and the sponsoring companies expires by its terms on March 12, 2006.
BUCKEYE
Contractual arrangements among OPCo, Buckeye and other investor-owned
electric utility companies in Ohio provide for the transmission and delivery,
over facilities of OPCo and of other investor-owned utility companies, of power
generated by the two units at the Cardinal Station owned by Buckeye and back-up
power to which Buckeye is entitled from OPCo under such contractual
arrangements, to facilities owned by 26 of the rural electric cooperatives which
operate in the State of Ohio at 324 delivery points. Buckeye is entitled under
such arrangements to receive, and is obligated to pay for, the excess of its
maximum one-hour coincident peak demand plus a 15% reserve margin over the
1,226,500 kilowatts of capacity of the generating units which Buckeye currently
owns in the Cardinal Station. Such demand, which occurred on July 30, 1999, was
recorded at 1,251,946 kilowatts.
In January 2000, OPCo and National Power Cooperative, Inc. (NPC), an
affiliate of Buckeye, entered into an agreement, subject to specified
conditions, relating to construction and operation of a 510 mw gas-fired
electric generating peaking facility to be owned by NPC. From the commercial
operation date (expected in early 2002) until the end of 2005, OPCo will be
entitled to the power generated by the facility, and responsible for the fuel
and other costs of the facility. After 2005, NPC and OPCo will be entitled to
80% and 20%, respectively, of the power of the facility, and both parties will
generally be responsible for the fuel and other costs of the facility. OPCo will
also provide certain back-up power to NPC. AEP Resources Service Company will
provide engineering, procurement and construction for the facility.
CERTAIN INDUSTRIAL CUSTOMERS
Century Aluminum of West Virginia, Inc. (formerly Ravenswood Aluminum
Corporation), and Ormet Corporation operate major aluminum reduction plants in
the Ohio River Valley at Ravenswood, West Virginia, and in the vicinity of
Hannibal, Ohio, respectively. The power requirements of such plants presently
are approximately 357,000 kilowatts for Century and 537,000 kilowatts for Ormet.
OPCo is providing electric
8
<PAGE> 16
service to Century pursuant to a contract approved by the PUCO for the period
July 1, 1996 through July 31, 2003.
On November 14, 1996, the PUCO approved (1) an interim agreement
pursuant to which OPCo would continue to provide electric service to Ormet for
the period December 1, 1997 through December 31, 1999 and (2) a joint petition
with an electric cooperative to transfer the right to serve Ormet to the
electric cooperative after December 31, 1999. As part of the territorial
transfer, OPCo and Ormet entered into an agreement which contains penalties and
other provisions designed to avoid having OPCo provide involuntary back-up power
to Ormet. Effective January 1, 2000, OPCo transferred its obligation and right
to serve Ormet to the electric cooperative. See Legal Proceedings for a
discussion of litigation involving Ormet.
AEGCO
Since its formation in 1982, AEGCo's business has consisted of the
ownership and financing of its 50% interest in the Rockport Plant and, since
1989, leasing of its 50% interest in Unit 2 of the Rockport Plant. The operating
revenues of AEGCo are derived from the sale of capacity and energy associated
with its interest in the Rockport Plant to I&M, KEPCo and, through December 31,
1999, VEPCo, pursuant to unit power agreements. Pursuant to these unit power
agreements, AEGCo is entitled to recover its full cost of service from the
purchasers and will be entitled to recover future increases in such costs,
including increases in fuel and capital costs. See Unit Power Agreements.
Pursuant to a capital funds agreement, AEP has agreed to provide cash capital
contributions, or in certain circumstances subordinated loans, to AEGCo, to the
extent necessary to enable AEGCo, among other things, to provide its
proportionate share of funds required to permit continuation of the commercial
operation of the Rockport Plant and to perform all of its obligations, covenants
and agreements under, among other things, all loan agreements, leases and
related documents to which AEGCo is or becomes a party. See Capital Funds
Agreement.
Unit Power Agreements
A unit power agreement between AEGCo and I&M (the I&M Power Agreement)
provides for the sale by AEGCo to I&M of all the power (and the energy
associated therewith) available to AEGCo at the Rockport Plant. I&M is
obligated, whether or not power is available from AEGCo, to pay as a demand
charge for the right to receive such power (and as an energy charge for any
associated energy taken by I&M) such amounts, as when added to amounts received
by AEGCo from any other sources, will be at least sufficient to enable AEGCo to
pay all its operating and other expenses, including a rate of return on the
common equity of AEGCo as approved by FERC, currently 12.16%. The I&M Power
Agreement will continue in effect until the date that the last of the lease
terms of Unit 2 of the Rockport Plant has expired unless extended in specified
circumstances.
Pursuant to an assignment between I&M and KEPCo, and a unit power
agreement between KEPCo and AEGCo, AEGCo sells KEPCo 30% of the power (and the
energy associated therewith) available to AEGCo from both units of the Rockport
Plant. KEPCo has agreed to pay to AEGCo in consideration for the right to
receive such power the same amounts which I&M would have paid AEGCo under the
terms of the I&M Power Agreement for such entitlement. The KEPCo unit power
agreement expires on December 31, 2004.
A unit power agreement among AEGCo, I&M, VEPCo, and APCo provided for,
among other things, the sale of 70% of the power and energy available to AEGCo
from Unit 1 of the Rockport Plant to VEPCo by AEGCo from January 1, 1987 through
December 31, 1999. VEPCo agreed to pay to AEGCo in consideration for the right
to receive such power those amounts which I&M would have paid AEGCo under the
terms of the I&M Power Agreement for such entitlement. With the expiration of
the VEPCo agreement on December 31, 1999, I&M increased its purchases of energy
from AEGCo to 910 megawatts of Rockport capacity. Approximately 30% of AEGCo's
operating revenue in 1999 was derived from its sales to VEPCo.
Capital Funds Agreement
AEGCo and AEP have entered into a capital funds agreement pursuant to
which, among other things, AEP has unconditionally agreed to make
9
<PAGE> 17
cash capital contributions, or in certain circumstances subordinated loans, to
AEGCo to the extent necessary to enable AEGCo to (i) maintain such an equity
component of capitalization as required by governmental regulatory authorities,
(ii) provide its proportionate share of the funds required to permit commercial
operation of the Rockport Plant, (iii) enable AEGCo to perform all of its
obligations, covenants and agreements under, among other things, all loan
agreements, leases and related documents to which AEGCo is or becomes a party
(AEGCo Agreements), and (iv) pay all indebtedness, obligations and liabilities
of AEGCo (AEGCo Obligations) under the AEGCo Agreements, other than
indebtedness, obligations or liabilities owing to AEP. The Capital Funds
Agreement will terminate after all AEGCo Obligations have been paid in full.
INDUSTRY PROBLEMS
The electric utility industry, including the operating subsidiaries of
AEP, has encountered at various times in the last 15 years significant problems
in a number of areas, including: delays in and limitations on the recovery of
fuel costs from customers; proposed legislation, initiative measures and other
actions designed to prohibit construction and operation of certain types of
power plants and transmission lines under certain conditions and to eliminate or
reduce the extent of the coverage of fuel adjustment clauses; inadequate rate
increases and delays in obtaining rate increases; jurisdictional disputes with
state public utilities commissions regarding the interstate operations of
integrated electric systems; requirements for additional expenditures for
pollution control facilities; increased capital and operating costs;
construction delays due, among other factors, to pollution control and
environmental considerations and to material, equipment and fuel shortages; the
economic effects on net income (which when combined with other factors may be
immediate and adverse) associated with placing large generating units and
related facilities in commercial operation, including the commencement at that
time of substantial charges for depreciation, taxes, maintenance and other
operating expenses, and the cessation of AFUDC with respect to such units;
uncertainties as to conservation efforts by customers and the effects of such
efforts on load growth; depressed economic conditions in certain regions of the
United States; increasingly competitive conditions in the wholesale and retail
markets; availability of capacity; proposals to deregulate certain portions of
the industry and revise the rules and responsibilities under which new
generating capacity is supplied; and substantial increases in construction costs
and difficulties in financing due to high costs of capital, uncertain capital
markets and shortages of cash for construction and other purposes.
SEASONALITY
Sales of electricity by the AEP System tend to increase and decrease
because of the use of electricity by residential and commercial customers for
cooling and heating and relative changes in temperature.
FRANCHISES
The operating companies of the AEP System hold franchises to provide
electric service in various municipalities in their service areas. These
franchises have varying provisions and expiration dates. In general, the
operating companies consider their franchises to be adequate for the conduct of
their business.
COMPETITION AND BUSINESS CHANGE
General
The public utility subsidiaries of AEP, like many other electric
utilities, have traditionally provided electric generation and energy delivery,
consisting of transmission and distribution services, as a single product to
their retail customers. Proposals are being made and legislation has been
enacted in Ohio and Virginia that would also require electric utilities to sell
distribution services separately. These measures generally allow competition in
the generation and sale of electric power, but not in its transmission and
distribution.
Competition in the generation and sale of electric power will require
resolution of complex issues, including who will pay for the unused generating
plant of, and other stranded costs incurred by, the utility when a customer
stops buying power from the utility; will all customers
10
<PAGE> 18
have access to the benefits of competition; how will the rules of competition be
established; what will happen to conservation and other regulatory-imposed
programs; how will the reliability of the transmission system be ensured; and
how will the utility's obligation to serve be changed. As a result, it is not
clear how or when competition in generation and sale of electric power will be
instituted. However, as competition in generation and sale of electric power is
instituted, the public utility subsidiaries of AEP believe that they have a
favorable competitive position because of their relatively low costs. If
stranded costs are not recovered from customers, however, the public utility
subsidiaries of AEP, like all electric utilities, will be required by existing
accounting standards to recognize any stranded investment losses.
AEP Position on Competition
In October 1995, AEP announced that it favored freedom for customers to
purchase electric power from anyone that they choose. Generation and sale of
electric power would be in the competitive marketplace. To facilitate reliable,
safe and efficient service, AEP supports creation of independent system
operators to operate the transmission system in a region of the United States.
In addition, AEP supports the evolution of regional power exchanges which would
establish a competitive marketplace for the sale of electric power. Transmission
and distribution would remain monopolies and subject to regulation with respect
to terms and price. Regulators would be able to establish distribution service
charges which would provide, as appropriate, for recovery of stranded costs and
regulatory assets. AEP's working model for industry restructuring envisions a
progressive transition to full customer choice. Implementation of these measures
would require legislative changes and regulatory approvals.
Wholesale
The public utility subsidiaries of AEP, like the electric industry
generally, face increasing competition to sell available power on a wholesale
basis, primarily to other public utilities and also to power marketers. The
Energy Policy Act of 1992 was designed, among other things, to foster
competition in the wholesale market (a) through amendments to PUHCA,
facilitating the ownership and operation of generating facilities by "exempt
wholesale generators" (which may include independent power producers as well as
affiliates of electric utilities) and (b) through amendments to the Federal
Power Act, authorizing the FERC under certain conditions to order utilities
which own transmission facilities to provide wholesale transmission services for
other utilities and entities generating electric power. The principal factors in
competing for such sales are price (including fuel costs), availability of
capacity and reliability of service. The public utility subsidiaries of AEP
believe that they maintain a favorable competitive position on the basis of all
of these factors. However, because of the availability of capacity of other
utilities and the lower fuel prices in recent years, price competition has been,
and is expected for the next few years to be, particularly important.
FERC orders 888 and 889, issued in April 1996, provide that utilities must
functionally unbundle their transmission services, by requiring them to use
their own tariffs in making off-system and third-party sales. See Transmission
Services. The public utility subsidiaries of AEP have functionally separated
their wholesale power sales from their transmission functions, as required by
orders 888 and 889.
Retail
The public utility subsidiaries of AEP generally have the exclusive
right to sell electric power at retail within their service areas. However, they
do compete with self-generation and with distributors of other energy sources,
such as natural gas, fuel oil and coal, within their service areas. The primary
factors in such competition are price, reliability of service and the capability
of customers to utilize sources of energy other than electric power. With
respect to self-generation, the public utility subsidiaries of AEP believe that
they maintain a favorable competitive position on the basis of all of these
factors. With respect to alternative sources of energy, the public utility
subsidiaries of AEP believe that the reliability of their service and the
limited ability of customers to substitute other cost-effective sources for
electric power place them in a favorable competitive position, even though their
11
<PAGE> 19
prices may be higher than the costs of some other sources of energy.
Significant changes in the global economy in recent years have led to
increased price competition for industrial companies in the United States,
including those served by the AEP System. Such industrial companies have
requested price reductions from their suppliers, including their suppliers of
electric power. In addition, industrial companies which are downsizing or
reorganizing often close a facility based upon its costs, which may include,
among other things, the cost of electric power. The public utility subsidiaries
of AEP cooperate with such customers to meet their business needs through, for
example, various off-peak or interruptible supply options and believe that, as
low cost suppliers of electric power, they should be less likely to be
materially adversely affected by this competition and may be benefited by
attracting new industrial customers to their service territories.
The legislatures and/or the regulatory commissions in many states,
including some in AEP's service territory, are considering or have adopted
"retail customer choice" which, in general terms, means the transmission by an
electric utility of electric power generated by an entity of the customer's
choice over its transmission and distribution system to a retail customer in
such utility's service territory. A requirement to transmit directly to retail
customers would have the result of permitting retail customers to purchase
electric power, at the election of such customers, not only from the electric
utility in whose service area they are located but from another electric
utility, an independent power producer or an intermediary, such as a power
marketer. Although AEP's power generation would have competitors under some of
these proposals, its transmission and distribution would not. If competition
develops in retail power generation, the public utility subsidiaries of AEP
believe that they should have a favorable competitive position because of their
relatively low costs.
Federal: Legislation to provide for retail competition among electric
energy suppliers has been introduced in both the U.S. Senate and House of
Representatives.
Indiana: In January 2000, Senate Bill 450 was introduced in the Indiana
Senate on behalf of a group of industrial customers. The bill would have allowed
retail electric customers to choose their electricity supply companies. The bill
was not reported out of committee prior to legislative adjournment. AEP
continues to work with other utilities in Indiana to develop a consensus on
customer-choice legislation that can be enacted into law in Indiana. The outcome
of this effort is uncertain.
Kentucky: During the 1998 Regular Session of the Kentucky legislature,
the Electric Utility Restructuring Task Force was established by resolution. The
final report of the Task Force issued in December 1999 recommended that, during
the 2000 General Assembly, the legislature should not take any action to
restructure the electric utility industry and the legislature should reauthorize
the Task Force. It is unlikely that comprehensive restructuring legislation will
be introduced in Kentucky until the 2002 General Assembly.
The KPSC on February 18, 2000, issued an order stating its intent to
promulgate regulations governing cost allocation for affiliate transactions and
a code of conduct. There may be legislative action in the 2000 General Assembly
to codify some or all of the concepts outlined by the KPSC order.
The KPSC Chairwoman leads 23 state public utility commissions in a
coalition entitled Low Cost States Initiative. The coalition's stated purpose is
to ensure that the U.S. Congress gives equal consideration to the issues facing
low-cost states. The coalition is focusing on the following five issues:
o A National Voice.
o Low Rates.
o Rural Electricity Rates.
o Stranded Costs and Benefits.
o Economic Development.
Michigan: In June 1995, the MPSC issued an order approving an
experimental five-year retail wheeling program and ordered Consumers Energy
Company (Consumers) and Detroit Edison Company (Detroit Edison), unaffiliated
utilities, to make retail
12
<PAGE> 20
delivery services available to a group of industrial customers, in the amount of
60 megawatts and 90 megawatts, respectively. The experiment, which commences
when each utility needs new capacity, seeks to determine whether a retail
wheeling program best serves the public interest. During the experiment, the
MPSC will collect information regarding the effects of retail wheeling.
Consumers, Detroit Edison and other parties appealed the MPSC's order to the
Michigan Supreme Court and in June 1999 the Supreme Court ruled that the MPSC
lacks the authority to mandate retail wheeling programs, but does have the
authority to set transmission rates for wheeled power if a utility voluntarily
chooses to offer direct retail access service. In response to the court ruling,
Consumers and Detroit Edison committed to participate voluntarily in the MPSC's
restructuring program described below.
In January 1996, the Governor of Michigan endorsed a proposal of the
Michigan Jobs Commission to promote competition and customer choice in energy
and requested that the MPSC review the existing statutory and regulatory
framework governing Michigan utilities in light of increasing competition in the
utility industry. In December 1996, the MPSC staff issued a report on electric
industry restructuring which recommended a phase-in program from 1997 through
2004 of direct access to electricity suppliers applicable to all customers. On
June 5, 1997, the MPSC entered an order requiring electric utilities (including
I&M) to phase in retail open access for customers, with full customer choice by
2002 (MPSC Order). Under the MPSC Order, customer choice is phased in from 1997
through 2001, at the rate of 2.5% of each utility's customer load per year, with
all customers becoming eligible to choose their electric supplier effective
January 1, 2002. The MPSC Order essentially adopted the December 1996 MPSC staff
report that recommended full recovery of stranded costs of utilities, including
nuclear generating investment, through the use of a transition charge applicable
to customers exercising choice. While concluding that securitization of stranded
costs would be feasible, the MPSC Order stated that legislative authorization is
required prior to the implementation of any securitization program.
In January 2000, Senate Bill 937 was introduced in the Michigan Senate,
which is an attempt to codify the MPSC's restructuring orders with certain other
modifications. The bill provides for:
o Phase-in period to begin June 1, 2000.
o Three-year rate freeze for customers who choose to remain with
their incumbent utility.
o Recovery of stranded costs during a transition period
extending through 2007.
Ohio: In October 1999, electric utility restructuring legislation (Am. Sub. S.B.
No. 3) was enacted into law. The law provides for:
o Effective January 1, 2001:
o Customer choice of electricity supplier.
o Residential rate reduction of 5% for the generation
portion of rates.
o Freezing of generation rates, including fuel.
o PUCO Authorization:
o To address certain major transition issues, including
the unbundling of rates and recovery of transition
costs. Transition costs can include regulatory
assets, stranded costs such as the impairment of
generating assets, employee severance and retraining
costs, consumer education and other costs. Stranded
generation costs are those costs of generation above
the market price for electricity that potentially
would not be recoverable in a competitive market.
o To approve a transition plan for each electric
utility company with a deadline of no later than
October 31, 2000 for those approvals.
CSPCo and OPCo filed their transition plans with the PUCO on December 30, 1999.
Their plans included the following:
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<PAGE> 21
o Rate unbundling plan, including tariff terms and conditions
necessary for restructuring.
o Corporate separation plan.
o Application for transition revenues.
o Plan for independent operation of transmission facilities.
o Other components for the implementation of restructuring.
Virginia: In March 1999, the Virginia Electric Utility Industry
Restructuring Act and related tax legislation were enacted into law. The
restructuring law requires Virginia utilities to join or establish a regional
transmission entity by January 2001, to which such utilities shall transfer the
management and control of their transmission systems. The law provides for a
transition to retail customer choice from January 1, 2002 through January 1,
2004. The Virginia SCC can delay or accelerate the implementation of choice
based on considerations of reliability, safety, communications or market power,
but in no event shall any delay extend the implementation of customer choice
beyond January 1, 2005. With limited exceptions, the generation of electricity
will no longer be subject to regulation.
The law provides for capped rates, effective January 1, 2001, for a period
of time ending as late as July 1, 2007. The capped rates may be terminated after
January 1, 2004, upon petition of the Virginia SCC by the utility and a finding
by the Virginia SCC that an effective competitive market exists. If capped rates
continue beyond January 1, 2004, the law provides for a one-time change in the
non-generation components of such rates upon approval by the Virginia SCC. The
Virginia SCC also may adjust the capped rates in connection with the utility's
recovery of fuel costs, changes in taxation by Virginia, and any financial
distress of the utility beyond the utility's control.
The restructuring law provides for recovery of just and reasonable net
stranded costs to the extent that such costs exceed zero in total value for any
incumbent electric utility through either capped rates or the imposition of a
wires charge upon customers who may depart the incumbent in favor of an
alternative supplier prior to the termination of the rate cap.
A ten-member legislative task force, to serve from July 1, 1999 through
July 1, 2005, will monitor the work of the Virginia SCC in implementing the law
and review related matters. The task force will report annually to the Governor
and legislature.
The tax law provides for replacement of gross receipts and certain
other taxes by (i) a consumption tax levied upon customers on the basis of
kilowatt-hour usage and (ii) a state corporate net income tax. The intention of
the tax law is to achieve approximate revenue neutrality for Virginia.
West Virginia: On January 28, 2000, the West Virginia PSC issued an
order approving an electricity restructuring plan for West Virginia that was
supported by a broad range of interested parties, including AEP. Among other
provisions, the restructuring plan provides for:
o Customer choice to begin on January 1, 2001, or at a later
date set by the West Virginia PSC after all necessary rules
are in place (the "starting date").
o Deregulation of generation assets occurring on the starting
date.
o A transition period of up to 13 years, during which an
incumbent utility must provide default service for customers
who do not change suppliers unless an alternative default
supplier is selected through a West Virginia PSC-sponsored
bidding process.
o Default rates for residential and small commercial
customers are capped for four years after the
starting date, and then increased at pre- defined
levels for the next nine years.
o Default rates for industrial and large commercial
customers are discounted by 1% for 4.5 years,
beginning July 1, 2000, and then increased at pre-
defined levels for an additional three years.
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<PAGE> 22
o Metering and billing are deregulated for industrial and large
commercial customers on the starting date; metering and
billing are deregulated for residential and small commercial
customers no later than four years after the starting date.
On March 11, 2000, the West Virginia legislature approved the
restructuring plan by joint resolution. The joint resolution provides that the
West Virginia PSC cannot implement the plan until the legislature makes
necessary tax law changes to preserve revenues of state and local governments.
Possible Strategic Responses
In response to the competitive forces and regulatory changes being
faced by AEP and its public utility subsidiaries, as discussed under this
heading and under Regulation, AEP and its public utility subsidiaries have from
time to time considered, and expect to continue to consider, various strategies
designed to enhance their competitive position and to increase their ability to
adapt to and anticipate changes in their utility business. These strategies may
include business combinations with other companies, internal restructurings
involving the complete or partial separation of their generation, transmission
and distribution businesses, acquisitions of related or unrelated businesses,
and additions to or dispositions of portions of their franchised service
territories. AEP and its public utility subsidiaries may from time to time be
engaged in preliminary discussions, either internally or with third parties,
regarding one or more of these potential strategies. No assurances can be given
as to whether any potential transaction of the type described above may actually
occur, or as to its ultimate effect on the financial condition or competitive
position of AEP and its public utility subsidiaries.
NEW BUSINESS DEVELOPMENT
AEP has expanded its business to non-regulated energy activities
through several subsidiaries, including AEP Energy Services, Inc. (AEPES), AEP
Resources, Inc. (Resources), AEP Pro Serv, Inc. (formerly AEP Resources Service
Company) (Pro Serv) and AEP Communications, LLC (AEP Communications).
AEPES
AEPES markets and trades natural gas and provides gas storage and
transportation services.
Resources
Resources' primary business is development of, and investment in,
exempt wholesale generators, foreign utility companies, qualifying cogeneration
facilities and other energy-related domestic and international investment
opportunities and projects. Resources has business development offices in
London, Beijing, Singapore, Sydney, Washington and Houston.
Resources and another AEP subsidiary have a 50% interest in Yorkshire
Electric Group plc (Yorkshire Electricity) with an indirect wholly-owned
subsidiary of New Century Energies, Inc. Yorkshire Electricity is a United
Kingdom independent regional electricity company. It is principally engaged in
the supply and distribution of electricity. Yorkshire Electricity has two
million distribution customers in its authorized service territory which is
comprised of 3,860 square miles and located centrally in the east coast of
England.
Resources also indirectly owns CitiPower Pty., an electric distribution
and retail sales company in Victoria, Australia. CitiPower serves approximately
250,000 customers in the city of Melbourne. With about 3,100 miles of
distribution lines in a service area that covers approximately 100 square miles,
CitiPower distributes about 4,800 gigawatt-hours annually.
Resources' indirect subsidiary, AEP Pushan Power LDC, has a 70%
interest in Nanyang General Light Electric Co., Ltd. (Nanyang Electric), a joint
venture organized to develop and build two 125 megawatt coal-fired generating
units near Nanyang City in the Henan Province of The Peoples Republic of China.
Nanyang Electric was established in 1996 by AEP Pushan Power LDC, Henan Electric
Power Development Co. (15% interest) and Nanyang City Hengsheng Energy
Development Company Limited (formerly Nanyang Municipal Finance Development Co.)
(15% interest). Unit 1 went into service in February 1999 and Unit 2 went into
service in June
15
<PAGE> 23
1999. Resources' share of the total cost of the project of $185,000,000 was
approximately $110,000,000.
In December 1999, Resources contributed $47,000,000 to acquire a 50%
interest in the Bajio power project in Mexico. The Bajio project is a 600
megawatt natural gas-fired, combined cycle plant and related assets located
approximately 160 miles from Mexico City. Bechtel Power Corporation, an
affiliate of Resources' partner (InterGen), will build the facility, which is
estimated to cost $430,000,000. Approximately 80% of the project costs will be
provided by third party debt, some of which will be supported by letters of
credit issued on behalf of Resources. The facility will be operated and managed
by one or more companies jointly owned by Resources and InterGen. Bajio has a
25-year contract to sell 495 megawatts of the plant's output to Mexico's
federally owned electric system; the remainder is expected to be sold to
industrial customers in the region. Construction is expected to be completed in
the fall of 2001.
Resources, through AEP Resources Australia Pty., Ltd., a special
purpose subsidiary of Resources, owns a 20% interest in Pacific Hydro Limited.
Pacific Hydro is principally engaged in the development and operation of, and
ownership of interests in, hydroelectric facilities in the Asia Pacific region.
Currently, Pacific Hydro has interests in six hydroelectric units that operate
or are under construction in Australia and the Philippines. The hydroelectric
facilities in which Pacific Hydro had interests as of December 31, 1999
(including those under construction) had total design capacity of approximately
163 megawatts.
Resources owns midstream gas assets, including:
o A 2,000-mile intrastate pipeline system in Louisiana.
o Four natural gas processing plants that straddle the pipeline.
o A ten billion cubic foot underground natural gas storage
facility directly connected to the Henry Hub, the most active
gas trading area in North America.
The pipeline and storage facilities are interconnected to 15 interstate
and 23 intrastate pipelines.
Pro Serv
Pro Serv offers engineering, construction, project management and other
consulting services for projects involving transmission, distribution or
generation of electric power both domestically and internationally.
AEP Communications
AEP Communications markets energy information, wireless tower
infrastructure and fiber optic services. In 1998, AEP Communications launched
Datapult(SM), a portfolio of energy information data and analysis tools designed
to help customers identify energy- and cost-saving opportunities. AEP
Communications also is expanding its fiber optic network and marketing dedicated
telecommunications bandwidth to other carriers.
SEC Limitations
AEP has received approval from the SEC under PUHCA to issue and sell
securities in an amount up to 100% of its average quarterly consolidated
retained earnings balance (such average balance was approximately $1.7 billion
for the twelve months ended December 31, 1999) for investment in exempt
wholesale generators and foreign utility companies. Resources expects to
continue its pursuit of new and existing energy generation and delivery projects
worldwide.
SEC Rule 58 permits AEP and other registered holding companies to
invest up to 15% of consolidated capitalization in energy-related companies.
AEPES, an energy-related company under Rule 58, is authorized to engage in
energy-related activities, including marketing electricity, gas and other energy
commodities.
Risk
These continuing efforts to invest in and develop new business
opportunities offer the potential of earning returns which may exceed those of
traditional AEP rate-regulated operations. However,
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<PAGE> 24
they also involve a higher degree of risk which must be carefully considered and
assessed. AEP may make additional substantial investments in these and other new
businesses.
Reference is made to Market Risks under Item 7A herein for a discussion
of certain market risks inherent in AEP business activities.
PROPOSED AEP-CSW MERGER
AEP and CSW entered into an Agreement and Plan of Merger, dated as of
December 21, 1997, pursuant to which CSW would, on the closing date, merge with
and into a wholly owned merger subsidiary of AEP with CSW being the surviving
corporation. As a result of the merger, each outstanding share of common stock,
par value $3.50 per share, of CSW (other than shares owned by AEP or CSW) shall
be converted into the right to receive 0.6 of a share of common stock, par value
$6.50 per share, of AEP. The combined company will be named American Electric
Power Company, Inc. and will be based in Columbus, Ohio.
Consummation of the merger is subject to certain conditions, including
the receipt of required regulatory approvals. Assuming the receipt of all
required approvals, completion of the merger is anticipated to occur in the
second quarter of 2000.
The merger agreement has been extended for six months until June 30,
2000 by both AEP's and CSW's boards of directors. Should the merger approval
process extend beyond June, either AEP or CSW could terminate the merger
agreement.
On March 15, 2000, the FERC conditionally approved the merger.
Conditions placed on the merger include:
o Transfer operational control of AEP's east and west
transmission systems to a fully-functioning, FERC-approved
regional transmission organization by December 15, 2001. See
Transmission Services for Non-Affiliates.
o Two interim transmission-related mitigation measures
consisting of market monitoring and independent calculation
and posting of available transmission capacity to monitor the
operation of AEP's east transmission system.
o Divestiture of 550 MW of generating capacity comprised of 300
MW of capacity in the Southwest Power Pool (SPP) and 250 MW of
capacity in the Electric Reliability Council of Texas (ERCOT).
The FERC will require AEP and CSW to divest their entire
ownership interest in the generating facilities that are to be
divested. Alternatively, AEP and CSW may choose to divest the
same or greater amount of capacity from different generating
plants in their entirety. However, such generating plants must
be of similar cost, operation and location characteristics as
the generating plants AEP and CSW originally proposed.
o AEP and CSW must complete divestiture of the ERCOT capacity by
March 15, 2001 and divestiture of the SPP capacity by July 1,
2002.
The FERC found that certain energy sales of SPP and ERCOT capacity
would be reasonable and effective interim mitigation measures until completion
of the required SPP and ERCOT divestitures. The FERC will require the proposed
interim energy sales to be in effect when the merger is consummated.
AEP and CSW must notify the FERC by March 30, 2000 whether they accept
the condition that they transfer operational control of their transmission
facilities to a fully-functioning, FERC-approved regional transmission
organization by December 15, 2001 and the condition requiring the interim
mitigation sales measures. If AEP and CSW accept the conditions, then AEP and
CSW must make a compliance filing at least 60 days prior to consummation of the
merger describing their plan to implement the interim mitigation measures. AEP
and CSW intend to make this compliance filing on such date to permit completion
of the merger in the second quarter of 2000. AEP and CSW believe they can
address the conditions.
CSW is a global, diversified public utility holding company based in
Dallas, Texas. CSW owns four domestic electric utility subsidiaries serving 1.8
million customers in portions of the states of Texas, Oklahoma, Louisiana and
Arkansas and a regional electricity company in the United Kingdom. CSW also owns
other international
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<PAGE> 25
energy operations and non-regulated subsidiaries involved in energy-related
investments, energy efficiency services and financial transactions.
CONSTRUCTION PROGRAM
New Generation
The AEP System is continuously involved in assessing the adequacy of
its generation, transmission, distribution and other facilities to plan and
provide for the reliable supply of electric power and energy to its customers.
In this assessment and planning process, assumptions are continually being
reviewed as new information becomes available, and assessments and plans are
modified, as appropriate. Thus, System reinforcement plans are subject to
change, particularly with the anticipated restructuring of the electric utility
industry and the move to increasing competition in the marketplace. See
Competition and Business Change.
Committed or anticipated capability changes to the AEP System's
generation resources include:
o Purchase from an independent power producer's hydro project
with an expected capacity value of 28 megawatts, commencing
January 1, 2001.
o Expiration of the Rockport Unit 2 sale of 250 megawatts to
Carolina Power & Light Company, an unaffiliated company, on
December 31, 2009.
Apart from these changes and temporary power purchases that can be
arranged, there are no specific commitments for additions of new generation
resources on the AEP System. In this regard, the most recent resource plan filed
by AEP's electric utility subsidiaries with various state commissions indicates
no need for new generation resources until about the year 2005. When the time
for commitment to additional generation resources approaches, all means for
adding such resources, including self-build and external resource options, will
be considered. However, given the restructuring that is expected to take place
in the industry, the extent of the need of AEP's operating companies for any
additional generation resources in the foreseeable future is highly uncertain.
Proposed Transmission Facilities
On September 30, 1997, APCo refiled applications in Virginia and West
Virginia for certificates to build the Wyoming-Cloverdale 765,000-volt line. The
preferred route for this line is approximately 132 miles in length, connecting
APCo's Wyoming Station in southern West Virginia to APCo's Cloverdale Station
near Roanoke, Virginia. APCo's estimated cost is $263,300,000.
APCo announced this project in 1990. Since then it has been in the
process of trying to obtain federal permits and state certificates. At the
federal level, the U.S. Forest Service (Forest Service) is directing the
preparation of an Environmental Impact Statement (EIS), which is required prior
to granting permits for crossing lands under federal jurisdiction. Permits are
needed from the (i) Forest Service to cross federal forests, (ii) Army Corps of
Engineers to cross the New River and a watershed near the Wyoming Station, and
(iii) National Park Service or Forest Service to cross the Appalachian National
Scenic Trail.
In June 1996, the Forest Service released a Draft EIS and preliminarily
identified a "No Action Alternative" as its preferred alternative. If this
alternative were incorporated into the Final EIS, APCo would not be authorized
to cross federal forests administered by the Forest Service. The Forest Service
stated that it would not prepare the Final EIS until after Virginia and West
Virginia determined need and routing issues.
West Virginia: On May 27, 1998, the West Virginia PSC issued an order
granting APCo's application for a certificate with respect to the preferred
route for the Wyoming-Cloverdale 765,000-volt line.
Virginia: By Hearing Examiner's Ruling of June 9, 1998, the procedural
schedule for the certificate in Virginia was suspended for 90 days to allow APCo
to conduct additional studies. On August 21, 1998, APCo filed a report stating
that a two-phased alternative project could provide electrical transmission
reinforcement comparable to the Wyoming-Cloverdale line.
By Hearing Examiner's Ruling of September 22, 1998, the proceeding was
continued and APCo was directed to study the first phase of the alternative
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<PAGE> 26
project, involving a line running from Wyoming Station in West Virginia to
APCo's existing Jacksons Ferry Station in Virginia or any point on the Jacksons
Ferry-Cloverdale 765kV transmission line. APCo estimates that the
Wyoming-Jacksons Ferry line would be between 82-100 miles in length, including
32 miles in West Virginia previously certified. The Hearing Examiner also
ordered APCo and the Virginia SCC Staff to provide at the evidentiary hearing
information on generation alternatives, specifically natural gas generation, to
APCo's proposed transmission line. APCo filed its study in May 1999, identifying
the Jacksons Ferry Project as an alternative project to Cloverdale. A hearing
was to have begun in November 1999, but this has been delayed to May 1, 2000.
If the Virginia SCC grants a certificate for the Wyoming-Jacksons Ferry
line, APCo will have to amend its certificate from West Virginia.
Proposed Completion Schedule: If the Virginia SCC and West Virginia PSC
issue the required certificates, APCo will cooperate with the Forest Service to
complete the EIS process and obtain the federal permits. Management estimates
that neither project can be completed before the summer of 2004. However, given
the findings in the Draft EIS, APCo cannot presently predict the schedule for
completion of the state and federal permitting process.
Construction Expenditures
The following table shows the construction expenditures by AEGCo, APCo,
CSPCo, I&M, KEPCo, OPCo and the AEP System and their respective consolidated
subsidiaries during 1997, 1998 and 1999 and their current estimate of 2000
construction expenditures, in each case including AFUDC but excluding nuclear
fuel and other assets acquired under leases.
<TABLE>
<CAPTION>
1997 1998 1999 2000
ACTUAL ACTUAL ACTUAL ESTIMATE
------ ------ ------ --------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
AEP System (a).. $762,000 $792,100 $866,900 $893,900
AEGCo ....... 3,900 6,600 8,300 4,200
APCo ........ 218,100 204,900 211,400 218,500
CSPCo ....... 108,900 115,300 115,300 136,100
I&M ......... 123,400 148,900 165,300 126,100
KEPCo ....... 66,700 43,800 44,300 33,200
OPCo ........ 172,700 185,200 193,900 233,600
</TABLE>
- -----------------------
(a) Includes expenditures of other subsidiaries not shown.
Reference is made to the footnotes to the financial statements entitled
Commitments and Contingencies incorporated by reference in Item 8, for further
information with respect to the construction plans of AEP and its operating
subsidiaries for the next three years.
The System construction program is reviewed continuously and is revised
from time to time in response to changes in estimates of customer demand,
business and economic conditions, the cost and availability of capital,
environmental requirements and other factors. Changes in construction schedules
and costs, and in estimates and projections of needs for additional facilities,
as well as variations from currently anticipated levels of net earnings, Federal
income and other taxes, and other factors affecting cash requirements, may
increase or decrease the estimated capital requirements for the System's
construction program.
From time to time, as the System companies have encountered the
industry problems described above, such companies also have encountered
limitations on their ability to secure the capital necessary to finance
construction expenditures.
Environmental Expenditures: Expenditures related to compliance with air
and water quality standards, included in the gross additions to plant of the
System, during 1997, 1998 and 1999 and the current estimate for 2000 are shown
below. Substantial expenditures in addition to the amounts set forth below may
be required by the System in future years in connection with the modification
and addition of facilities at generating plants for environmental quality
controls in order to comply with air and water quality standards which have been
or may be adopted.
<TABLE>
<CAPTION>
1997 1998 1999 2000
ACTUAL ACTUAL ACTUAL ESTIMATE
------ ------ ------ --------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
AEGCo ........... $ 0 $ 800 $ 8 $ 0
APCo ............ 9,100 25,000 24,500 19,314
CSPCo ........... 1,300 5,300 10,600 13,154
I&M ............. 100 13,000 4,500 731
KEPCo ........... 1,300 4,600 1,900 313
OPCo ............ 11,800 27,100 37,400 70,888
------- ------- ------- --------
AEP System.... $23,600 $75,800 $78,908 $104,400
======= ======= ======= ========
</TABLE>
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<PAGE> 27
FINANCING
It has been the practice of AEP's operating subsidiaries to finance
current construction expenditures in excess of available internally generated
funds by initially issuing unsecured short-term debt, principally commercial
paper and bank loans, at times up to levels authorized by regulatory agencies,
and then to reduce the short-term debt with the proceeds of subsequent sales by
such subsidiaries of long-term debt securities and cash capital contributions by
AEP. It has been the practice of AEP, in turn, to finance cash capital
contributions to the common stock equities of its subsidiaries by issuing
unsecured short-term debt, principally commercial paper, and then to sell
additional shares of Common Stock of AEP for the purpose of retiring the
short-term debt previously incurred. In 1999, AEP issued approximately 2,287,000
shares of Common Stock pursuant to its Dividend Reinvestment and Stock Purchase
Plan and Employees Savings Plan. Although prevailing interest costs of
short-term bank debt and commercial paper generally have been lower than
prevailing interest costs of long-term debt securities, whenever interest costs
of short-term debt exceed costs of long-term debt, the companies might be
adversely affected by reliance on the use of short-term debt to finance their
construction and other capital requirements.
During the period 1997-1999, net external funds from financings and
capital contributions by AEP amounted, with respect to APCo, I&M, KEPCo and
OPCo, to approximately 48%, 80%, 71% and 20%, respectively, of the aggregate
construction expenditures shown above. During this same period, the amount of
funds used to retire long-term and short-term debt and preferred stock of AEGCo
and CSPCo exceeded the amount of funds from financings and capital contributions
by AEP.
The ability of AEP's regulated subsidiaries to issue short-term debt is
limited by regulatory restrictions and, in the case of some of the operating
subsidiaries, by provisions contained in certain debt and other instruments. The
approximate amounts of short-term debt which the companies estimate that they
were permitted to issue under the most restrictive such restriction, at January
1, 2000, and the respective amounts of short-term debt outstanding on that date,
on a corporate basis, are shown in the following tabulation:
<TABLE>
<CAPTION>
TOTAL AEP
SHORT-TERM DEBT AEP AEGCO APCO CSPCO I&M KEPCO OPCO SYSTEM(a)
--------------- --- ----- ---- ----- --- ----- ---- ---------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Amount authorized ....... $500 $ 80 $325 $350 $500 $150 $450 $2,415
==== ==== ==== ==== ==== ==== ==== ======
Amount outstanding:
Notes payable ..... $ -- $ 25 $ -- $ -- $ -- $ -- $ 5 $ 208
Commercial paper... 57 -- 123 46 224 40 190 680
---- ---- ---- ---- ---- ---- ---- ------
$ 57 $ 25 $123 $ 46 $224 $ 40 $195 $ 888
==== ==== ==== ==== ==== ==== ==== ======
</TABLE>
- -----------------------
(a) Includes short-term debt of other subsidiaries not shown.
Reference is made to the footnotes to the financial statements
incorporated by reference in Item 8 for further information with respect to
unused short-term bank lines of credit.
If one or more of the subsidiaries are unable to continue the issuance
and sale of securities on an orderly basis, such company or companies will be
required to consider the curtailment of construction and other outlays or the
use of alternative financing arrangements, if available, which may be more
costly.
AEP's subsidiaries have also utilized, and expect to continue to
utilize, additional financing arrangements, such as unsecured debt, leasing
arrangements, including the leasing of utility assets, coal mining and
transportation equipment and facilities and nuclear fuel. Pollution control
revenue bonds have been used in the past and may be used in the future in
connection with the construction of pollution control facilities; however,
Federal tax law has limited the utilization of this type of financing except for
purposes of certain financing of solid waste disposal facilities and of certain
refunding of outstanding pollution control revenue bonds issued before August
16, 1986.
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<PAGE> 28
New projects undertaken by Resources and its subsidiaries are generally
financed through equity funds provided by AEP, non-recourse debt incurred on a
project-specific basis, debt issued by Resources or through a combination
thereof. See New Business Development and Item 7 for additional information
concerning Resources and its subsidiaries.
RATES AND REGULATION
General
The rates charged by the electric utility subsidiaries of AEP are
approved by the FERC or one of the state utility commissions as applicable. The
FERC regulates wholesale rates and the state commissions regulate retail rates.
In recent years the number of rate increase applications filed by the operating
subsidiaries of AEP with their respective state commissions and the FERC has
decreased. Under current rate regulation, if increases in operating,
construction and capital costs exceed increases in revenues resulting from
previously granted rate increases and increased customer demand, then it may be
appropriate for certain of AEP's electric utility subsidiaries to file rate
increase applications in the future.
Generally the rates of AEP's operating subsidiaries are determined
based upon the cost of providing service including a reasonable return on
investment. Certain states served by the AEP System allow alternative forms of
rate regulation in addition to the traditional cost-of-service approach.
However, the rates of AEP's operating subsidiaries in those states continue to
be cost-based. The IURC may approve alternative regulatory plans which could
include setting customer rates based on market or average prices, price caps,
index-based prices and prices based on performance and efficiency. The Virginia
SCC may approve (i) special rates, contracts or incentives to individual
customers or classes of customers and (ii) alternative forms of regulation
including, but not limited to, the use of price regulation, ranges of authorized
returns, categories of services and price indexing.
All of the seven states served by the AEP System, as well as the FERC,
either permit the incorporation of fuel adjustment clauses in a utility
company's rates and tariffs, which are designed to permit upward or downward
adjustments in revenues to reflect increases or decreases in fuel costs above or
below the designated base cost of fuel set forth in the particular rate or
tariff, or permit the inclusion of specified levels of fuel costs as part of
such rate or tariff.
AEP cannot predict the timing or probability of approvals regarding
applications for additional rate changes, the outcome of action by regulatory
commissions or courts with respect to such matters, or the effect thereof on the
earnings and business of the AEP System. In addition, current rate regulation
may, and in the case of Ohio and Virginia will, be subject to significant
revision. See Competition and Business Change.
APCo
Virginia: In June 1997, APCo filed an application with the Virginia SCC
for approval of an alternative regulatory plan (Plan) and proposed, among other
things, an increase of $30,500,000 in base rates on an annual basis to be
effective July 13, 1997. On July 10, 1997, the Virginia SCC issued an order
suspending implementation of the proposed rates until November 11, 1997 when
these rates were placed into effect subject to refund.
On February 18, 1999, the Virginia SCC approved a stipulation and
settlement agreement among APCo, the Virginia SCC Staff and consumer and major
industrial customer representatives that provides for the following:
o Elimination of the $30,500,000 annual increase in base rates
that has been collected subject to refund since mid-November
1997.
o During the period January 1, 1998 through December 31, 2000:
o Reduction in base rates of $6,000,000 from the level
in effect prior to the November 1997 increase, with
the expectation that rates would remain at the
agreed-upon levels.
o APCo's commitment to invest at least $90,000,000 in
Virginia distribution facilities to maintain the
overall quality and reliability of electric service.
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<PAGE> 29
o Benchmark rate of return on equity of 10.85% with
one-third of earnings above that level to be retained
by APCo and the remaining two-thirds to be refunded
to ratepayers.
o Refund with interest of all amounts collected above the
approved rates.
APCo made the refund with interest as ordered in the amount of
$49,628,000.
West Virginia: In May 1999, APCo filed with the West Virginia PSC for a
base rate increase of $50,000,000 annually and a reduction in Expanded Net
Energy Cost (ENEC) rates of $38,000,000 annually. On February 7, 2000, APCo and
other parties to the proceeding filed for approval a Joint Stipulation and
Agreement for Settlement with the West Virginia PSC that provides for, among
other things:
o No change in either base or ENEC rates after January 1, 2000
from those that expired on December 31, 1999 that were part of
a prior West Virginia PSC-approved settlement.
o Annual ENEC recovery proceedings are suspended and deferral
accounting for over- or under-recovery is discontinued
effective January 1, 2000.
o The net cumulative deferred ENEC recovery balance as
established by the prior West Virginia PSC order, which is
$66,000,000 at December 31, 1999, shall remain as a regulatory
liability until generation is deregulated.
o APCo's share of any net savings from the pending merger
between AEP and Central and South West Corporation prior to
December 31, 2004 shall be retained by APCo.
CSPCo
Zimmer Plant: The Zimmer Plant was placed in commercial operation as a
1,300-megawatt coal-fired plant on March 30, 1991. CSPCo owns 25.4% of the
Zimmer Plant with the remainder owned by two unaffiliated companies, CG&E
(46.5%) and DP&L (28.1%).
From the in-service date of March 1991 until rates went into effect in
May 1992, deferred carrying charges of $43,000,000 were recorded on the Zimmer
Plant investment. Recovery of the deferred carrying charges is being sought
under the transition charge provision of the Ohio electric utility restructuring
law discussed in Competition and Business Change--Ohio.
I&M
Reference is made to Cook Nuclear Plant --Cook Plant Shutdown under
Item 2 herein for a discussion of recovery of fuel costs.
OPCo
Under the terms of a stipulation agreement approved by the PUCO in
November 1992, beginning December 1, 1994, the cost of coal burned at the Gavin
Plant is subject to a 15-year predetermined price of $1.575 per million Btus
with quarterly escalation adjustments. A 1995 PUCO-approved settlement agreement
fixed the electric fuel component factor at 1.465 cents per kwh for the period
June 1995 through November 1998. After the first to occur of either full
recovery of these costs or November 2009, the price that OPCo can recover for
coal from its affiliated Meigs mine which supplies the Gavin Plant will be
limited to the lower of cost or the then-current market price. The agreements
provide OPCo with the opportunity to recover any operating losses incurred under
the predetermined or fixed price, as well as its investment in, and liabilities
and closing costs associated with, its affiliated mining operations attributable
to its Ohio jurisdiction, to the extent the actual cost of coal burned at the
Gavin Plant is below the predetermined price.
As a result of the Ohio electric utility restructuring law discussed in
Competition and Business Change--Ohio, beginning in 2001, fuel adjustment
proceedings in Ohio cease, thus ending the recovery mechanism in the 1992 and
1995 agreements and specifically ceasing the escalation feature of the Gavin
cap. Therefore, OPCo must now rely on the transition charge for recovery of the
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<PAGE> 30
deferred fuel cost regulatory asset balance after December 31, 2000.
The Muskingum mine, which supplied coal to the Muskingum River Plant
Units 1-4, ceased operation in October 1999 with the exception of a limited
amount of economically viable coal production ancillary to the reclamation
activities. The Windsor mine, which supplies Cardinal Plant Unit 1, is scheduled
to close in April 2000. The Meigs mine is scheduled to close in December 2001.
These mines are closing, in part, as a result of compliance with the Phase II
requirements of the Clean Air Act Amendments of 1990 (see Environmental and
Other Matters -- Air Pollution Control -- Acid Rain). Unless future shutdown
costs and/or the cost of coal production of OPCo's Muskingum, Windsor and Meigs
mines, including amounts deferred, can be recovered, AEP's and OPCo's results of
operations would be adversely affected.
FUEL SUPPLY
The following table shows the sources of power generated by the AEP
System:
<TABLE>
<CAPTION>
1995 1996 1997 1998 1999
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Coal....................... 88% 87% 92% 99% 99%
Nuclear.................... 11% 12% 7% 0% 0%
Hydroelectric and other.... 1% 1% 1% 1% 1%
</TABLE>
Variations in the generation of nuclear power are primarily related to
refueling outages and, for 1997 through 1999, the shutdown of the Cook Plant to
respond to issues raised by the NRC. See Cook Nuclear Plant -- Cook Plant
Shutdown.
Coal
The Clean Air Act Amendments of 1990 provide for the issuance of annual
allowance allocations covering sulfur dioxide emissions at levels below historic
emission levels for many coal-fired generating units of the AEP System. Phase I
of this program began in 1995 and Phase II begins in 2000, with both phases
requiring significant changes in coal supplies and suppliers. The full extent of
such changes, particularly in regard to Phase II, however, has not been
determined. See Environmental and Other Matters -- Air Pollution Control -- Acid
Rain for the current compliance plan.
In order to meet emission standards for existing and new emission
sources, the AEP System companies will, in any event, have to obtain coal
supplies, in addition to coal reserves now owned by System companies, through
the acquisition of additional coal reserves and/or by entering into additional
supply agreements, either on a long-term or spot basis, at prices and upon terms
which cannot now be predicted.
No representation is made that any of the coal rights owned or
controlled by the System will, in future years, produce for the System any major
portion of the overall coal supply needed for consumption at the coal-fired
generating units of the System. Although AEP believes that in the long run it
will be able to secure coal of adequate quality and in adequate quantities to
enable existing and new units to comply with emission standards applicable to
such sources, no assurance can be given that coal of such quality and quantity
will in fact be available. No assurance can be given either that statutes or
regulations limiting emissions from existing and new sources will not be further
revised in future years to specify lower sulfur contents than now in effect or
other restrictions. See Environmental and Other Matters herein.
The FERC has adopted regulations relating, among other things, to the
circumstances under which, in the event of fuel emergencies or shortages, it
might order electric utilities to generate and transmit electric power to other
regions or systems experiencing fuel shortages, and to rate-making principles by
which such electric utilities would be compensated. In addition, the Federal
Government is authorized, under prescribed conditions, to allocate coal and to
require the transportation thereof, for the use of power plants or major
fuel-burning installations.
System companies have developed programs to conserve coal supplies at
System plants which involve, on a progressive basis, limitations on sales of
power and energy to neighboring utilities, appeals to customers for voluntary
limitations of electric usage to essential needs, curtailment of sales to
certain industrial customers, voltage reductions and, finally, mandatory
reductions in cases where current coal supplies fall below minimum levels. Such
programs have been filed and reviewed with
23
<PAGE> 31
officials of Federal and state agencies and, in some cases, the state regulatory
agency has prescribed actions to be taken under specified circumstances by
System companies, subject to the jurisdiction of such agencies.
The mining of coal reserves is subject to Federal requirements with
respect to the development and operation of coal mines, and to state and Federal
regulations relating to land reclamation and environmental protection, including
Federal strip mining legislation enacted in August 1977. Continual evaluation
and study is given to possible divestiture of coal properties in light of
Federal and state environmental and mining laws and regulations.
Western coal purchased by System companies is transported by rail to an
affiliated terminal on the Ohio River for transloading to barges for delivery to
generating stations on the river. Subsidiaries of AEP lease approximately 4,055
coal hopper cars to be used in unit train movements, as well as 15 towboats, 451
jumbo barges and 145 standard barges. Subsidiaries of AEP also own or lease coal
transfer facilities at various other locations.
The System generating companies procure coal from coal reserves which
are owned or mined by subsidiaries of AEP, and through purchases pursuant to
long-term contracts, or on a spot purchase basis, from unaffiliated producers.
The following table shows the amount of coal delivered to the AEP System during
the past five years, the proportion of such coal which was obtained either from
coal-mining subsidiaries, from unaffiliated suppliers under long-term contracts
or through spot or short-term purchases, and the average delivered price of spot
coal purchased by System companies:
<TABLE>
<CAPTION>
1995 1996 1997 1998 1999
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Total coal delivered to
AEP operated plants (thousands of tons)....................... 46,867 51,030 54,292 54,004 54,306
Sources (percentage):
Subsidiaries.................................................. 14% 13% 14% 14% 11%
Long-term contracts........................................... 75% 71% 66% 66% 64%
Spot or short-term purchases.................................. 11% 16% 20% 20% 24%
Average price per ton of spot-purchased coal..................... $25.15 $23.85 $24.38 $25.05 $27.18
</TABLE>
The average cost of coal consumed during the past five years by all AEP
System companies, AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo is shown in the
following tables:
<TABLE>
<CAPTION>
1995 1996 1997 1998 1999
---- ---- ---- ---- ----
DOLLARS PER TON
---------------
<S> <C> <C> <C> <C> <C>
AEP System Companies........................................... $ 32.52 $ 31.70 $ 31.77 $ 32.60 $ 32.94
AEGCo....................................................... 18.80 18.22 19.30 19.37 20.79
APCo........................................................ 38.86 37.60 36.09 34.81 33.29
CSPCo....................................................... 33.23 31.70 31.69 31.63 29.94
I&M......................................................... 23.25 22.99 23.68 22.61 24.54
KEPCo....................................................... 26.91 27.25 26.76 27.42 26.76
OPCo........................................................ 37.58 35.96 36.00 38.94 40.56
CENTS PER MILLION BTU'S
-----------------------
AEP System Companies........................................... 145.26 140.48 140.23 143.51 143.07
AEGCo....................................................... 112.87 109.25 115.21 112.63 116.90
APCo........................................................ 156.96 152.54 146.54 141.76 135.40
CSPCo....................................................... 140.79 134.60 134.44 134.15 127.42
I&M......................................................... 125.50 121.16 123.36 118.02 121.90
KEPCo....................................................... 114.77 114.42 110.37 112.15 109.91
OPCo........................................................ 157.62 151.55 151.66 164.44 169.23
</TABLE>
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<PAGE> 32
The coal supplies at AEP System plants vary from time to time depending
on various factors, including customers' usage of electric power, space
limitations, the rate of consumption at particular plants, labor unrest and
weather conditions which may interrupt deliveries. At December 31, 1999, the
System's coal inventory was approximately 50 days of normal System usage. This
estimate assumes that the total supply would be utilized by increasing or
decreasing generation at particular plants.
The following tabulation shows the total consumption during 1999 of the
coal-fired generating units of AEP's principal electric utility subsidiaries,
coal requirements of these units over the remainder of their useful lives and
the average sulfur content of coal delivered in 1999 to these units. Reference
is made to Environmental and Other Matters for information concerning current
emissions limitations in the AEP System's various jurisdictions and the effects
of the Clean Air Act Amendments.
<TABLE>
<CAPTION>
AVERAGE SULFUR CONTENT
ESTIMATED REQUIRE- OF DELIVERED COAL
TOTAL CONSUMPTION MENTS FOR REMAINDER -----------------------------
DURING 1999 OF USEFUL LIVES POUNDS OF SO(2)
(IN THOUSANDS OF TONS) (IN MILLIONS OF TONS) BY WEIGHT PER MILLION BTU'S
---------------------- --------------------- --------- -----------------
<S> <C> <C> <C> <C>
AEGCo (a)............................... 4,510 225 0.3% 0.7
APCo.................................... 12,206 432 0.8% 1.3
CSPCo................................... 5,849(b) 234(b) 2.7% 4.5
I&M (c)................................. 6,948 254 0.6% 1.2
KEPCo................................... 3,099 93 1.1% 1.8
OPCo.................................... 19,088 623 2.1% 3.6
</TABLE>
- ------------------------
(a) Reflects AEGCo's 50% interest in the Rockport Plant
(b) Includes coal requirements for CSPCo's interest in Beckjord, Stuart and
Zimmer Plants.
(c) Includes I&M's 50% interest in the Rockport Plant.
AEGCo: See Fuel Supply -- I&M for a discussion of the coal supply for
the Rockport Plant.
APCo: Substantially all of the coal consumed at APCo's generating
plants is obtained from unaffiliated suppliers under long-term contracts and/or
on a spot purchase basis.
The average sulfur content by weight of the coal received by APCo at
its generating stations approximated 0.8% during 1999, whereas the maximum
sulfur content permitted, for emission standard purposes, for existing plants in
the regions in which APCo's generating stations are located ranged between 0.78%
and 2% by weight depending in some circumstances on the calorific value of the
coal which can be obtained for some generating stations.
CSPCo: CSPCo has coal supply agreements with unaffiliated suppliers for
the delivery of approximately 3,150,000 tons per year through 2001. Some of this
coal is washed to improve its quality and consistency for use principally at
Unit 4 of the Conesville Plant.
CSPCo has been informed by CG&E and DP&L that, with respect to the CCD
Group units partly owned but not operated by CSPCo, sufficient coal has been
contracted for or is believed to be available for the approximate lives of the
respective units operated by them. Under the terms of the operating agreements
with respect to CCD Group units, each operating company is contractually
responsible for obtaining the needed fuel.
I&M: I&M has two coal supply agreements with unaffiliated suppliers
pursuant to which the suppliers are delivering low sulfur coal from surface
mines in Wyoming, principally for consumption by the Rockport Plant. Under these
agreements, the suppliers will sell to I&M, for consumption by I&M at the
Rockport Plant or consignment to other System companies, coal with an average
sulfur content not exceeding 1.2 pounds of sulfur dioxide per million Btu's of
heat input. One contract with remaining deliveries of 46,510,000 tons expires on
25
<PAGE> 33
December 31, 2014 and another contract with remaining deliveries of 32,175,000
tons expires on December 31, 2004.
All of the coal consumed at I&M's Tanners Creek Plant is obtained from
unaffiliated suppliers under long-term contracts and/or on a spot purchase
basis.
KEPCo: Substantially all of the coal consumed at KEPCo's Big Sandy
Plant is obtained from unaffiliated suppliers under long-term contracts and/or
on a spot purchase basis. KEPCo has coal supply agreements with unaffiliated
suppliers pursuant to which KEPCo will receive approximately 2,300,000 tons of
coal in 2000. To the extent that KEPCo has additional coal requirements, it may
purchase coal from the spot market and/or suppliers under contract to supply
other System companies.
OPCo: The coal consumed at OPCo's generating plants is obtained from
both affiliated and unaffiliated suppliers. The coal obtained from unaffiliated
suppliers is purchased under long-term contracts and/or on a spot purchase
basis.
OPCo and certain of its coal-mining subsidiaries own or control coal
reserves in the State of Ohio containing approximately 184,000,000 tons of clean
recoverable coal and ranging in sulfur content between 3.4% and 4.5% sulfur by
weight (weighted average, 3.8%), which reserves are presently being mined. OPCo
and certain of its mining subsidiaries own an additional 113,000,000 tons of
clean recoverable coal in Ohio which ranges in sulfur content between 2.4% and
3.4% sulfur by weight (weighted average 2.7%). Recovery of this coal would
require substantial development.
OPCo and certain of its coal-mining subsidiaries also own or control
coal reserves in the State of West Virginia which contain approximately
100,000,000 tons of clean recoverable coal ranging in sulfur content between
1.4% and 4.0% sulfur by weight (weighted average, 2.1%) of which approximately
23,000,000 tons can be recovered based upon existing mining plans and
projections and employing current mining practices and techniques.
Nuclear
I&M has made commitments to meet certain of the nuclear fuel
requirements of the Cook Plant. The nuclear fuel cycle consists of:
o Mining and milling of uranium ore to uranium concentrates.
o Conversion of uranium concentrates to uranium hexafluoride.
o Enrichment of uranium hexafluoride.
o Fabrication of fuel assemblies.
o Utilization of nuclear fuel in the reactor.
o Disposition of spent fuel.
Steps currently are being taken, based upon the planned fuel cycles for
the Cook Plant, to review and evaluate I&M's requirements for the supply of
nuclear fuel. I&M has made and will make purchases of uranium in various forms
in the spot, short-term, and mid-term markets until it decides that deliveries
under long-term supply contracts are warranted.
For purposes of the storage of high-level radioactive waste in the form
of spent nuclear fuel, I&M has completed modifications to its spent nuclear fuel
storage pool. AEP anticipates that the Cook Plant has storage capacity to permit
normal operations through 2012.
I&M's costs of nuclear fuel consumed do not assume any residual or
salvage value for residual plutonium and uranium.
Nuclear Waste and Decommissioning
The Nuclear Waste Policy Act of 1982, as amended, establishes Federal
responsibility for the permanent off-site disposal of spent nuclear fuel and
high-level radioactive waste. Disposal costs are paid by fees assessed against
owners of nuclear plants and deposited into the Nuclear Waste Fund created by
the Act. In 1983, I&M entered into a contract with DOE for the disposal of spent
nuclear fuel. Under terms of the contract, for the disposal of nuclear fuel
consumed after April 6, 1983 by I&M's Cook Plant, I&M is paying to the fund a
fee of one
26
<PAGE> 34
mill per kilowatt-hour, which I&M is currently recovering from customers. For
the disposal of nuclear fuel consumed prior to April 7, 1983, I&M must pay the
U.S. Treasury a fee estimated at approximately $72,000,000, exclusive of
interest of $127,000,000 at December 31, 1999. The aggregate amount has been
recorded as long-term debt. Because of the current uncertainties surrounding
DOE's program to provide for permanent disposal of spent nuclear fuel, I&M has
not yet paid any of the pre-April 1983 fee. At December 31, 1999, funds
collected from customers to pay the pre-April 1983 fee and accrued interest
approximated the long-term liability. In November 1996, the IURC and MPSC issued
orders approving flexible funding procedures in which any excess funds collected
for pre-April 7, 1983 spent nuclear fuel disposal would be deposited into I&M's
nuclear decommissioning trust funds.
On May 30, 1995, I&M and a group of unaffiliated utilities owning and
operating nuclear plants filed a petition for review in the U.S. Court of
Appeals for the District of Columbia Circuit requesting that the court issue a
declaration that the Nuclear Waste Policy Act of 1982 (NWPA) imposes on DOE an
unconditional obligation to begin acceptance of spent nuclear fuel and high
level radioactive waste by January 31, 1998. On July 23, 1996, the court ruled
that the NWPA creates an obligation for DOE, reciprocal to the utilities'
obligation to pay, to start disposing of the spent nuclear fuel and high level
radioactive waste no later than January 31, 1998. The court remanded the case to
DOE, holding that determination of a remedy was premature, since DOE had not yet
defaulted on its obligations.
In December 1996, I&M received a letter from DOE advising that DOE
anticipates that it will be unable to begin acceptance of spent nuclear fuel and
high level radioactive waste for disposal in a repository or interim storage
facility by January 31, 1998. On January 31, 1997, in anticipation of DOE's
breach of their statutory and contractual obligations, I&M along with 35
unaffiliated utilities and 33 states filed joint petitions for review in the
U.S. Court of Appeals for the District of Columbia Circuit requesting that the
court permit the utilities to suspend further payments into the nuclear waste
fund, authorize escrow of the payments, and order further action on the part of
DOE to meet its obligations under the NWPA. On November 12, 1997, the Court of
Appeals issued a decision granting in part and denying in part the utilities'
request for relief. The court ordered DOE to proceed with contractual remedies
and to refrain from concluding that DOE's delay is unavoidable due to the lack
of a repository or the lack of interim storage authority. The court, however,
declined to order DOE to begin disposing of fuel. On January 31, 1998, the
deadline for DOE's performance, the DOE failed to begin disposing of the
utilities' spent nuclear fuel. DOE estimates its planned site for spent nuclear
fuel will not be ready until at least 2010.
On June 8, 1998, I&M filed a complaint in the U.S. Court of Federal
Claims seeking damages in excess of $150,000,000 due to the U.S. Department of
Energy's partial material breach of its unconditional contractual deadline to
begin disposing of spent nuclear fuel and high level nuclear waste generated by
the Cook Nuclear Plant. Similar lawsuits have been filed by other utilities. On
April 6, 1999, the court granted DOE's motion to dismiss a lawsuit file by an
unaffiliated utility. On May 20, 1999, the other utility appealed this decision
to the U.S. Court of Appeals for the Federal Circuit. I&M's case has been stayed
pending final resolution of the other utility's appeal.
Studies completed in 1997 estimate decommissioning and low-level
radioactive waste disposal costs for the Cook Plant to range from $700,000,000
to $1.152 billion in 1997 nondiscounted dollars. The wide range is caused by
variables in assumptions, including the estimated length of time spent nuclear
fuel must be stored at the Cook Plant subsequent to ceasing operations, which
depends on future developments in the federal government's spent nuclear fuel
disposal program. Continued delays in the federal fuel disposal program can
result in increased decommissioning costs. I&M is recovering decommissioning
costs in its three rate-making jurisdictions based on at least the lower end of
the range in the most recent respective decommissioning study available at the
time of the rate proceeding (the study range utilized in the Indiana rate case,
I&M's primary jurisdiction, was $588,000,000 to $1.102
27
<PAGE> 35
billion in 1991 dollars). I&M records decommissioning costs in other operation
expense and records a noncurrent liability equal to the decommissioning cost
recovered in rates which was $28,000,000 in 1999, $29,000,000 in 1998, and
$28,000,000 in 1997. At December 31, 1999 and 1998, I&M had recognized a
decommissioning liability of $501,000,000 and $446,000,000, respectively. I&M
will continue to reevaluate periodically the cost of decommissioning and to seek
regulatory approval to revise its rates as necessary.
Funds recovered through the rate-making process for disposal of spent
nuclear fuel consumed prior to April 7, 1983 and for nuclear decommissioning
have been segregated and deposited in external funds for the future payment of
such costs. Trust fund earnings decrease the amount to be recovered from
ratepayers.
The ultimate cost of retiring I&M's Cook Plant may be materially
different from the estimates contained in the site-specific study and the
funding targets as a result of the:
o Type of decommissioning plan selected.
o Escalation of various cost elements (including, but not
limited to, general inflation).
o Further development of regulatory requirements governing
decommissioning.
o Limited availability to date of significant experience in
decommissioning such facilities.
o Technology available at the time of decommissioning differing
significantly from that assumed in these studies.
o Availability of nuclear waste disposal facilities.
Accordingly, management is unable to provide assurance that the ultimate cost of
decommissioning the Cook Plant will not be significantly greater than current
projections.
Low-Level Waste: The Low-Level Waste Policy Act of 1980 (LLWPA)
mandates that the responsibility for the disposal of low-level waste rests with
the individual states. Low-level radioactive waste consists largely of ordinary
refuse and other items that have come in contact with radioactive materials. To
facilitate this approach, the LLWPA authorized states to enter into regional
compacts for low-level waste disposal subject to Congressional approval. The
LLWPA also specified that, beginning in 1986, approved compacts may prohibit the
importation of low-level waste from other regions, thereby providing a strong
incentive for states to enter into compacts. Michigan, the state where the Cook
Plant is located, was a member of the Midwest Compact, but its membership was
revoked in 1991. As a result, Michigan is responsible for developing a disposal
site for the low-level waste generated in Michigan.
Although Michigan amended its law regarding low-level waste site
development in 1994 to allow a volunteer to host a facility, little progress has
been made to date. A bill was introduced in 1996 to further address the issue
but no action was taken. Development of required legislation and progress with
the site selection process has been inhibited by many factors, and management is
unable to predict when a new disposal site for Michigan low-level waste will be
available.
On July 1, 1995, the disposal site in South Carolina reopened to accept
waste from most areas of the U.S., including Michigan. This was the first
opportunity for the Cook Plant to dispose of low-level waste since 1990. To the
extent practicable, the waste formerly placed in storage and the waste presently
generated are now being sent to the disposal site.
Energy Policy Act -- Nuclear Fees
The Energy Policy Act of 1992 (Energy Act), contains a provision to
fund the decontamination and decommissioning of uranium enrichment facilities
formerly owned by DOE. Funding is to be provided from a combination of sources
including assessments against electric utilities which purchased enrichment
services from DOE facilities. I&M's remaining estimated liability is
$32,000,000, subject to inflation adjustments, and is payable in annual
assessments over the next seven years. I&M recorded a regulatory asset
concurrent with the
28
<PAGE> 36
recording of the liability. The payments are being recorded and recovered as
fuel expense over a 15-year period ending in 2007.
I&M has joined with 25 other utility plaintiffs in filing a complaint
in the U.S. District Court for the Southern District of New York seeking a
declaratory judgment that the annual decontamination and decommissioning
assessments are unconstitutional. I&M's claims for refund of previously paid
assessments remain pending in the U.S. Court of Federal Claims. I&M is seeking
to stay the Court of Federal Claims action pending the outcome of the District
Court action.
ENVIRONMENTAL AND OTHER MATTERS
AEP's subsidiaries are subject to regulation by federal, state and
local authorities with regard to air and water-quality control and other
environmental matters, and are subject to zoning and other regulation by local
authorities. In addition to imposing continuing compliance obligations, these
laws and regulations authorize the imposition of substantial penalties for
noncompliance, including fines, injunctive relief and other sanctions.
It is expected that costs related to environmental requirements will
eventually be reflected in the rates of AEP's electric utility subsidiaries and
that AEP's electric utility subsidiaries will be able to provide for required
environmental controls. However, some customers may curtail or cease operations
as a consequence of higher energy costs. There can be no assurance that all such
costs will be recovered. Moreover, legislation recently adopted by certain
states and proposed at the state and federal level governing restructuring of
the electric utility industry may also affect the recovery of certain costs. See
Competition and Business Change.
Except as noted herein, AEP's subsidiaries that own or operate
generating, transmission and distribution facilities are in substantial
compliance with pollution control laws and regulations.
Air Pollution Control
For the AEP System, compliance with the Clean Air Act (CAA) is
requiring substantial expenditures that generally are being recovered through
increases in the rates of AEP's operating subsidiaries. However, there can be no
assurance that all such costs will be recovered. See Construction Program --
Construction Expenditures.
Acid Rain: The Acid Rain Program (Title IV) of the Clean Air Act
Amendments of 1990 (CAAA) created an emission allowance program pursuant to
which utilities are authorized to emit a designated quantity of sulfur dioxide
(SO(2)), measured in tons per year, on an aggregate basis. There are two phases
of SO(2) control under the Acid Rain Program. Phase I, effective January 1,
1995, required SO(2) emission reductions from certain units that emitted SO(2)
above a rate of 2.5 pounds per million Btu heat input in 1985.
Phase II, which affects all fossil fuel-fired steam generating units
with capacity greater than 25 megawatts imposes more stringent SO(2) emission
control requirements beginning January 1, 2000. If a unit emitted SO(2) in 1985
at a rate in excess of 1.2 pounds per million Btu heat input, the Phase II
allowance allocation is premised upon an emission rate of 1.2 pounds at 1985
utilization levels.
In addition to regulating SO(2) emissions, Title IV of the CAAA
regulates emissions of nitrogen oxides (NOx). Federal EPA has promulgated NOx
emission limitations for all boiler types in the AEP System at levels
significantly below original design. All emission limitations were to be
achieved by January 1, 2000 on a unit-by-unit or System-wide average basis.
Title I National Ambient Air Quality Standards Attainment: The CAA
contains additional provisions, other than the Acid Rain Program, which could
require reductions in emissions of NOx and other pollutants from fossil
fuel-fired power plants. See NOx SIP Call and Section 126 Petitions below.
In July 1997, Federal EPA revised the ozone and particulate matter
National Ambient Air Quality Standards (NAAQS), creating a new eight-hour ozone
standard and establishing a new standard for particulate matter less than 2.5
microns in diameter (PM(2.5)). Both of these new standards have the potential to
affect adversely the operation of AEP System generating units. In May 1999, the
U.S.
29
<PAGE> 37
Court of Appeals for the District of Columbia Circuit remanded the ozone and
PM(2.5) NAAQS to Federal EPA. Following denial of a request for rehearing and
rehearing en banc by the Circuit Court, Federal EPA and several others filed
petitions for a writ of certiorari with the U.S. Supreme Court on January 27,
2000.
In September 1998, Federal EPA issued revisions to the New Source
Performance Standards applicable to new and modified fossil fuel-fired power
plants. The emission limit is set at a level which will require the use of post
combustion control equipment. The final rule effectively requires selective
catalytic reduction or comparable technology to control NOx emissions from new
or modified coal-fired boilers. On September 21, 1999, the U.S. Court of Appeals
for the District of Columbia Circuit vacated the standard with respect to
modified sources. On December 21, 1999, the court issued an opinion upholding
the standard as it applies to new sources.
NOx SIP Call: On October 27, 1998, Federal EPA published in the Federal
Register a final rule (NOx transport SIP call or NOx SIP Call) concluding that
certain State Implementation Plans are deficient because they allow NOx
emissions that contribute excessively to ozone non-attainment in downwind
states. Federal EPA's NOx transport SIP call establishes state-by-state NOx
emission budgets for the five-month ozone season to be met beginning May 1,
2003. The NOx budgets apply to 22 eastern states and the District of Columbia
and are premised mainly on the assumption of controlling power plant NOx
emissions projected for the year 2007 to 0.15 lb. per million Btu (approximately
85% below 1990 levels), although the reductions could be substantially greater
for certain State Implementation Plans. The NOx transport SIP call purported to
implement both the new eight-hour ozone standard and the one-hour ozone
standard. Federal EPA subsequently stayed its reliance on the eight-hour
standard for purposes of the NOx SIP Call. The SIP call was accompanied by a
proposed Federal Implementation Plan, which could be implemented in any state
that fails to submit an approvable SIP by September 1999. The NOx reductions
called for by Federal EPA are targeted at coal-fired electric utilities and may
adversely impact the ability of electric utilities to obtain new and modified
source permits or to operate affected facilities without making significant
capital expenditures. In October 1998, the AEP System operating companies joined
with certain other utilities seeking a review of the final NOx SIP Call rule in
the U.S. Court of Appeals for the District of Columbia Circuit.
In May 1999, the court issued a stay of the September 1999 SIP
submittal date. On March 3, 2000, the court issued a decision upholding the
major provisions of the NOx SIP Call rule. The court did not take any action to
lift the stay of the SIP submittal date.
Preliminary estimates indicate that compliance with the revised NOx SIP
Call rule could result in required capital expenditures as follows:
(IN MILLIONS)
AEP System.......................... $1,600
AEGCo............................ 125
APCo............................. 365
CSPCo............................ 136
I&M.............................. 202
KEPCo............................ 106
OPCo............................. 624
Compliance costs cannot be estimated with certainty and the actual costs
incurred to comply could be significantly different from this preliminary
estimate depending upon the compliance alternatives selected to achieve
reductions in NOx emissions. Unless such costs are recovered from customers
through regulated rates and/or reflected in the future market price of
electricity if generation is deregulated, they could have a material adverse
effect on results of operations, cash flows and possibly financial condition.
Section 126 Petitions: In August 1997, eight northeastern states
(Connecticut, Maine, Massachusetts, New Hampshire, New York, Pennsylvania, Rhode
Island, and Vermont) filed petitions with Federal EPA under Section 126 of the
CAA, claiming that NOx emissions from certain named sources in midwestern
states, including all the coal-fired plants of AEP's operating subsidiaries,
prevent those states from attaining the ozone NAAQS. Among other things, the
petitioners
30
<PAGE> 38
generally seek NOx emission reductions 85% below 1990 levels from the utility
sources in midwestern states, as in the NOx SIP Call. On May 25, 1999, Federal
EPA published in the Federal Register a final rule, which granted certain of
these petitions. On January 18, 2000, Federal EPA revised and limited the rule
to implementation of the one-hour ozone standard. The revised rule imposes
reduction requirements comparable to the NOx SIP Call beginning May 1, 2003 for
most of AEP's coal fired generating units. Certain AEP System companies and
other utilities appealed the revised rule to the U.S. Court of Appeals for the
District of Columbia Circuit on January 18, 2000.
In 1999, Delaware, the District of Columbia, Maryland and New Jersey
filed additional Section 126 petitions seeking similar relief. No action has yet
been taken on those petitions.
Hazardous Air Pollutants: Hazardous air pollutant emissions from
utility boilers are potentially subject to control requirements under Title III
of the CAAA. The CAAA specifically directed Federal EPA to study potential
public health impacts of hazardous air pollutants emitted from electric utility
steam generating units. Federal EPA was required to report the results of this
study to Congress by November 1993 and to regulate emissions of these hazardous
pollutants if necessary. On February 25, 1998, Federal EPA issued a final report
to Congress citing as potential health and environmental threats, mercury and
three other hazardous air pollutants present in power plant emissions. Noting
uncertainty regarding health effects and the absence of control technology for
mercury, no immediate regulatory action was proposed regarding emission
reductions.
In addition, Federal EPA is required to study the deposition of
hazardous pollutants in the Great Lakes, the Chesapeake Bay, Lake Champlain, and
other coastal waters. As part of this assessment, Federal EPA is authorized to
adopt regulations to prevent serious adverse effects to public health and
serious or widespread environmental effects. In 1998, Federal EPA determined
that the CAA, including the provisions discussed in the paragraph above, is
adequate to address any adverse public health or environmental effects
associated with the atmospheric deposition of hazardous air pollutants in the
Great Lakes.
Federal EPA was also required to study mercury emissions and report its
findings to Congress by 1994. Federal EPA presented that report to Congress in
December 1997. The report identifies electric utilities as being the third
leading emitter of mercury. Presently, mercury emissions from electric utilities
are not regulated under the CAA. However, Federal EPA intends to engage in
further studies of mercury emissions, which may lead to additional regulation in
the future.
Permitting and Enforcement: The CAAA expanded the enforcement authority
of the federal government by:
o Increasing the range of civil and criminal penalties for
violations of the CAA and enhancing administrative civil
provisions.
o Imposing a national operating permit system, emission fee
program and enhanced monitoring, recordkeeping and reporting
requirements.
Section 103 of the Comprehensive Environmental Response, Compensation,
and Liability Act and Section 304 of the Emergency Planning and Community
Right-to-Know Act require notification to state and federal authorities of
releases of reportable quantities (RQs) of hazardous and extremely hazardous
substances. A number of these substances are emitted by AEP's power plants and
other sources. Until recently, emissions of these substances, whether expressly
limited in a permit or otherwise subject to federal review or waiver (e.g.,
mercury), were deemed "federally permitted releases" which did not require
emergency notification. On December 21, 1999, Federal EPA published interim
guidance in the Federal Register, which provides that any hazardous substance or
extremely hazardous substance not expressly and individually limited in a permit
that is emitted at levels above an RQ must be reported. Specifically,
constituents of regulated pollutants (e.g., metals contained in particulate
matter) are not deemed to be federally permitted. Recognizing that this interim
guidance would cause sources to reevaluate their air releases, Federal EPA
issued a memorandum on
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<PAGE> 39
February 15, 2000 announcing its decision to exercise enforcement discretion for
facilities that failed to report air releases prior to December 21, 1999. AEP is
reevaluating its air releases and will provide supplemental information as
appropriate.
Global Climate Change: In December 1997, delegates from 167 nations,
including the United States, agreed to a treaty, known as the "Kyoto Protocol,"
establishing legally-binding emission reductions for gases suspected of causing
climate change. If the U.S. becomes a party to the treaty it will be bound to
reduce emissions of carbon dioxide (CO(2)), methane and nitrous oxides by 7%
below 1990 levels and emissions of hydrofluorcarbons, perfluorocarbons and
sulfur hexafluoride 7% below 1995 levels in the years 2008-2012. The Protocol
was available for signature from March 16, 1998 to March 15, 1999 and requires
ratification by at least 55 nations that account for at least 55% of developed
countries' 1990 emissions of CO(2) to enter into force.
Although the United States has agreed to the treaty and signed it on
November 12, 1998, President Clinton has indicated that he will not submit the
treaty to the Senate for ratification until it contains requirements for
"meaningful participation by key developing countries" and the rules,
procedures, methodology and guidelines of the treaty's market-based policy
instruments, joint implementation programs and compliance enforcement provisions
have been negotiated. At the Fourth Conference of the Parties, held in Buenos
Aires, Argentina, in November 1998, the parties agreed to a work plan to
complete negotiations on outstanding issues with a view toward approving them at
the Sixth Conference of the Parties to be held in November 2000.
Since the AEP System is a significant emitter of carbon dioxide, its
results of operations, cash flows and financial condition could be adversely
affected by the imposition of limitations on CO(2) emissions if compliance costs
cannot be fully recovered from customers. In addition, any such severe program
to reduce CO(2) emissions could impose substantial costs on industry and society
and erode the economic base that AEP's operations serve. However, it is
management's belief that the Kyoto Protocol is highly unlikely to be ratified or
implemented in the U. S.
West Virginia SO(2) Limits: West Virginia promulgated SO(2)
limitations, which Federal EPA approved in February 1978. The emission
limitations for the Mitchell Plant have been approved by Federal EPA for primary
ambient air quality (health-related) standards only. West Virginia is obligated
to reanalyze SO(2) emission limits for the Mitchell Plant with respect to
secondary ambient air quality (welfare-related) standards. Because the CAA
provides no specific deadline for approval of emission limits to achieve
secondary ambient air quality standards, it is not certain when Federal EPA will
take dispositive action regarding the Mitchell Plant.
On August 4, 1994, Federal EPA issued a Notice of Violation to OPCo
alleging that Kammer Plant was operating in violation of the applicable
federally enforceable SO(2) emission limit. On May 20, 1996, the Notice of
Violation and an enforcement action subsequently filed by Federal EPA were
resolved through the entry of a consent decree in the U.S. District Court for
the Northern District of West Virginia. As of December 31, 1999, Kammer Plant
had achieved compliance with an SO(2) emission limit of 2.7 lb. mm/Btu design
heat input, pursuant to the provisions of the consent decree and the federally
approved West Virginia State Implementation Plan.
Short Term SO(2) Limits: On January 2, 1997, Federal EPA proposed a new
intervention level program under the authority of Section 303 of the CAA to
address five minute peak SO(2) concentrations believed to pose a health risk to
certain segments of the population. The proposal establishes a "concern" level
and an "endangerment" level. States must investigate exceedances of the concern
level and decide whether to take corrective action. If the endangerment level is
exceeded, the state must take action to reduce SO(2) levels. The effects of this
proposed intervention program on AEP operations cannot be predicted at this
time.
Regional Haze: On July 1, 1999, Federal EPA finalized rules to regulate
regional haze attributable to anthropogenic emissions. The primary goal of
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<PAGE> 40
the new regional haze program is to address visibility impairment in and around
"Class I" protected areas, such as national parks and wilderness areas. Because
regional haze precursor emissions are believed by Federal EPA to travel long
distances, Federal EPA proposes to regulate such precursor emissions in every
state. Under the proposal, each state must develop a regional haze control
program that imposes controls necessary to steadily reduce visibility impairment
in Class I areas on the worst days and that ensures that visibility remains good
on the best days.
The AEP System is a significant emitter of fine particulate matter and
its precursors that could be linked to the creation of regional haze. Federal
EPA's regional haze rule may have an adverse financial impact on AEP as it may
trigger the requirement to install costly new pollution control devices to
control emissions of fine particulate matter and its precursors (including SO(2)
and NOx). The actual impact of the regional haze regulations cannot be
determined at this time. AEP System operating companies and other utilities
filed a petition seeking a review of the regional haze rule in the U.S. Court of
Appeals for the District of Columbia Circuit on August 30, 1999.
New Source Review: On July 21, 1992, Federal EPA published final
regulations in the Federal Register governing application of new source rules to
generating plant repairs and pollution control projects undertaken to comply
with the CAA. Generally, the rule provides that plants undertaking pollution
control projects will not trigger New Source Review requirements. The Natural
Resources Defense Council and a group of utilities, including five AEP System
companies, have filed petitions in the U.S. Court of Appeals for the District of
Columbia Circuit seeking a review of the regulations. In July 1998, Federal EPA
requested comment on proposed revisions to the New Source Review rules which
would change New Source Review applicability criteria by eliminating exemptions
contained in the current regulation.
New Source Review Litigation: In February 1999, Federal EPA (Regions
III and V) issued a request under Section 114 of the CAA seeking documents and
information regarding capital and maintenance expenditures at AEP's Cardinal,
Gavin, Mitchell, Muskingum River and Sporn plants. Federal EPA conducted a
review of the accounting records of AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo in
the summer of 1998. Federal EPA subsequently issued Section 114 requests for
Amos, Clinch River, Conesville, Kammer, Kanawha River and Tanners Creek plants.
On November 3, 1999, the Department of Justice (DOJ), on Federal EPA's behalf,
filed a complaint in the U.S. District Court for the Southern District of Ohio
that alleges AEP made modifications to generating units at certain of its
coal-fired generating plants over the course of the past 25 years that extend
unit operating lives or restore or increase unit generating capacity without a
preconstruction permit in violation of the CAA. The complaint named Cardinal,
Mitchell, Muskingum River, Sporn and Tanners Creek plants. Federal EPA also
issued Notices of Violation to AEP alleging similar violations at certain other
AEP plants.
A number of unaffiliated utilities (one of which operates a unit which
AEP owns a portion of) also received Notices of Violation, complaints or
administrative orders. One of the unaffiliated utilities, Tampa Electric
Company, has settled its litigation with the federal government.
The court has granted the states of Connecticut, New Jersey and New
York leave to intervene in Federal EPA's action against AEP under the CAA. On
March 17, 2000, the states of Maryland, Massachusetts, New Hampshire, Rhode
Island and Vermont petitioned the court for leave to intervene in Federal EPA's
action. AEP has not opposed these intervention requests and believes the court
will grant them. On November 18, 1999, a number of environmental groups filed a
lawsuit against power plants owned by AEP alleging similar violations to those
in the Federal EPA complaint and Notices of Violation.
On March 1, 2000, DOJ filed an amended complaint that added allegations
for certain of the AEP plants previously named in the complaint as well as
counts for Amos, Clinch River, Conesville, Kammer and Kanawha River plants. The
plants included in the amended complaint are named by the environmental groups
plaintiff and, along with
33
<PAGE> 41
Gavin, are also named by the intervenor states. In addition to the allegations
regarding New Source Review and New Source Performance Standard violations, DOJ
included allegations regarding visible particulate emission violations for
Cardinal and Muskingum River plants in connection with Notices of Violation
issued by Region V, Federal EPA, on November 30, 1999.
The CAA authorizes civil penalties of up to $27,500 per day per
violation at each generating unit ($25,000 per day prior to January 30, 1997).
Civil penalties, if ultimately imposed by the court, and the cost of any
required new pollution control equipment, if the court accepts Federal EPA's
contentions, could be substantial.
In the event AEP does not prevail, any capital and operating costs of
additional pollution control equipment that may be required as well as any
penalties imposed could materially adversely affect future results of
operations, cash flows and possibly financial condition unless such costs can be
recovered through regulated rates, and where states are deregulating generation,
unbundled transition period generation rates, wires charges and future market
prices for energy.
Water Pollution Control
The Clean Water Act prohibits the discharge of pollutants to waters of
the United States from point sources except pursuant to an NPDES permit issued
by Federal EPA or a state under a federally authorized state program.
Under the Clean Water Act, effluent limitations requiring application
of the best available technology economically achievable are to be applied, and
those limitations require that no pollutants be discharged if Federal EPA finds
elimination of such discharges is technologically and economically achievable.
The Clean Water Act provides citizens with a cause of action to enforce
compliance with its pollution control requirements. Since 1982, many such
actions against NPDES permit holders have been filed. To date, no AEP System
plants have been named in such actions.
All System generating plants are operating with NPDES permits. Under
Federal EPA's regulations, operation under an expired NPDES permit is authorized
provided an application is filed at least 180 days prior to expiration. Renewal
applications are being prepared or have been filed for renewal of NPDES permits
that expire in 2000.
The NPDES permits generally require that certain thermal impact study
programs be undertaken. These studies have been completed for all System plants.
Thermal variances are in effect for all plants with once-through cooling water.
The thermal variances for Conesville and Muskingum River plants impose thermal
management conditions that could result in load curtailment under certain
conditions, but the cost impacts are not expected to be significant. Based on
favorable results of in-stream biological studies, the thermal temperature
limits for both Conesville and Muskingum River plants were raised in the renewed
permits issued in 1996. Consequently, the potential for load curtailment and
adverse cost impacts is further reduced.
Section 316(b) of the Clean Water Act requires that cooling water
intake structures reflect the best technology available (BTA) for minimizing
adverse environmental impact. Under a court established schedule, Federal EPA is
required to develop regulations defining adverse impacts and BTA by August 2001.
As part of the rulemaking, Federal EPA has issued questionnaires to electric
generating power plants, including AEP System plants, requesting information on
impingement and entrainment of aquatic organisms from existing plant cooling
water intakes. Federal EPA's rulemaking could result in a definition of BTA that
would require retrofitting of certain plant intake structures. Such changes
would involve costs for AEP System companies, but the significance of these
costs cannot be determined at this time.
Certain mining operations conducted by System companies as discussed
under Fuel Supply are also subject to federal and state water pollution control
requirements, which may entail substantial expenditures for control facilities,
not included at present in the System's construction cost estimates set forth
herein.
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<PAGE> 42
The Federal Water Quality Act of 1987 requires states to adopt
stringent water quality standards for a large category of toxic pollutants and
to identify specialized control measures for dischargers to waters where it is
shown through the use of total maximum daily loads (TMDLs) that water quality
standards are not being met. Implementation of these provisions could result in
significant costs to the AEP System if biological monitoring requirements and
water quality-based effluent limits are placed in NPDES permits.
In March 1995, Federal EPA finalized a set of rules that establish
minimum water quality standards, anti-degradation policies and implementation
procedures for more stringently controlling releases of toxic pollutants into
the Great Lakes system. This regulatory package is called the Great Lakes Water
Quality Initiative (GLWQI). The most direct compliance cost impact could be
related to I&M's Cook Plant. Based on Federal EPA's current policy on intake
credits and site specific variables and Michigan's implementation strategy,
management does not presently expect the GLWQI will have a significant adverse
impact on Cook Plant operations. If Indiana and Ohio eventually adopt the GLWQI
criteria for statewide application, AEP System plants located in those states
could be adversely affected, although the significance depends on the
implementation strategy of those states.
Oil Pollution Act: The Oil Pollution Act of 1990 (OPA) defines certain
facilities that, due to oil storage volume and location, could reasonably be
expected to cause significant and substantial harm to the environment by
discharging oil. Such facilities must operate under approved spill response
plans and implement spill response training and drill programs. OPA imposes
substantial penalties for failure to comply. AEP companies with oil handling and
storage facilities meeting the OPA criteria have in place required response
plans, training and drill programs.
Solid and Hazardous Waste
Section 311 of the Clean Water Act imposes substantial penalties for
spills of Federal EPA-listed hazardous substances into water and for failure to
report such spills. The Comprehensive Environmental Response, Compensation, and
Liability Act (CERCLA) expanded the reporting requirements to cover the release
of hazardous substances generally into the environment, including water, land
and air. AEP's subsidiaries store and use some of these hazardous substances,
including PCBs contained in certain capacitors and transformers, but the
occurrence and ramifications of a spill or release of such substances cannot be
predicted.
CERCLA, RCRA and similar state laws provide governmental agencies with
the authority to require clean-up of hazardous waste sites and releases of
hazardous substances into the environment and to seek compensation for damages
to natural resources. Since liability under CERCLA is strict, joint and several,
and can be applied retroactively, AEP System companies which previously disposed
of PCB-containing electrical equipment and other hazardous substances may be
required to participate in remedial activities at such disposal sites should
environmental problems result. OPCo is the only AEP System company which is a
defendant in a cost-recovery lawsuit related to clean-up liability at a Federal
EPA-identified CERCLA site. OPCo settled its alleged liability at this site
under terms of a consent decree and is awaiting formal dismissal from the case.
AEP System companies are identified as Potentially Responsible Parties
(PRPs) for four additional federal sites, including CSPCo at two sites and I&M
at two sites. Management's present estimates do not anticipate material clean-up
costs for identified sites for which AEP subsidiaries have been declared PRPs or
are defendants in CERCLA cost recovery litigation. However, if for reasons not
currently identified significant costs are incurred for clean-up, future results
of operations and possibly financial condition could be adversely affected
unless the costs can be recovered through rates.
Regulations issued by Federal EPA under the Toxic Substances Control
Act govern the use, distribution and disposal of PCBs, including PCBs in
electrical equipment. Deadlines for removing certain PCB-containing electrical
equipment from service have been met.
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<PAGE> 43
In addition to handling hazardous substances, the System companies
generate solid waste associated with the combustion of coal, the vast majority
of which is fly ash, bottom ash and flue gas desulfurization wastes. These
wastes presently are considered to be non-hazardous under RCRA and applicable
state law and the wastes are treated and disposed of in surface impoundments or
landfills in accordance with state permits or authorization or are beneficially
utilized. As required by RCRA, Federal EPA evaluated whether high volume coal
combustion wastes (such as fly ash, bottom ash and flue gas desulfurization
wastes) should be regulated as hazardous waste. In August 1993, Federal EPA
issued a regulatory determination that such high volume coal combustion wastes
should not be regulated as hazardous waste. For low volume coal combustion
wastes, such as metal and boiler cleaning wastes, which are traditionally
co-managed with high volume wastes, Federal EPA will gather additional
information and make a regulatory determination by April 2000. Until that time,
these low volume wastes are provisionally excluded from regulation under the
hazardous waste provisions of RCRA when mixed with and co-managed with high
volume coal combustion wastes. If Federal EPA determines that certain low volume
coal combustion wastes should be subject to RCRA Subtitle C hazardous waste
regulations, AEP System companies may incur additional waste management
expenses. The significance of these costs cannot be determined at this time.
All presently generated hazardous waste is being disposed of at
permitted off-site facilities in compliance with applicable federal and state
laws and regulations. For System facilities that generate such wastes, System
companies have filed the requisite notices and are complying with RCRA and
applicable state regulations for generators. Nuclear waste produced at the Cook
Plant regulated under the Atomic Energy Act is excluded from regulation under
RCRA.
Underground Storage Tanks: Federal EPA's technical requirements for
underground storage tanks containing petroleum required retrofitting or
replacement of an appreciable number of tanks. Compliance costs for tank
replacement were not significant. Some limited site remediation associated with
tank removal is ongoing, but these costs are not expected to be significant.
Electric and Magnetic Fields (EMF)
EMF is found everywhere there is electricity. Electric fields are
created by the presence of electric charges. Magnetic fields are produced by the
flow of those charges. This means that EMF is created by electricity flowing in
transmission and distribution lines, household wiring, and appliances.
A number of studies in the past several years have examined the
possibility of adverse health effects from EMF. While some of the
epidemiological studies have indicated some association between exposure to EMF
and health effects, the majority of studies have indicated no such association.
The Energy Policy Act of 1992 established a coordinated Federal EMF
research program which ended in 1998. The program funding was $65,000,000, half
of which was provided by private parties including utilities. AEP contributed
over $400,000 to this program. In 1999, the National Institute of Environmental
Health Sciences (NIEHS), as required by the Act, provided a report to Congress
summarizing the results of this program. The report concluded that "the
probability that ...EMF is truly a health hazard is currently small" and that
the evidence that exists for health effects is "insufficient to warrant
aggressive regulatory actions." Nevertheless, the NIEHS identified several areas
where further research might be warranted. AEP has supported EMF research
through the years and continues to fund the Electric Power Research Institute's
EMF research program, contributing over $400,000 to this program in 1999 and
intending to contribute a similar amount in 2000. See Research and Development.
AEP's participation in these programs is a continuation of its efforts
to monitor and support further research and to communicate with its customers
and employees about this issue. Residential customers of AEP are provided
information and field measurements on request, although there is no scientific
basis for interpreting such measurements.
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<PAGE> 44
A number of lawsuits based on EMF-related grounds have been filed
against electric utilities. A suit was filed on May 23, 1990 against I&M
involving claims that EMF from a 345 KV transmission line caused adverse health
effects. On March 23, 1998 the court ruled that the plaintiffs failed to prove
that I&M caused any of the injuries claimed by the plaintiffs. This part of the
trial court's decision was upheld on appeal. Certain issues unrelated to health
effects are pending at the trial court. No specific amount has been requested
for damages in this case and no trial date has been set.
Some states have enacted regulations to limit the strength of magnetic
fields at the edge of transmission line rights-of-way. No state which the AEP
System serves has done so. In March 1993, The Ohio Power Siting Board issued its
amended rules providing for additional consideration of the possible effects of
EMF in the certification of electric transmission facilities. Applicants are
required to address possible health effects and discuss the consideration of
design alternatives with respect to estimates of EMF levels. These rules were
reissued in 1998 with no change to EMF language.
Management cannot predict the ultimate impact of the question of EMF
exposure and adverse health effects. If further research shows that EMF exposure
contributes to increased risk of cancer or other health problems, or if the
courts conclude that EMF exposure harms individuals and that utilities are
liable for damages, or if states limit the strength of magnetic fields to such a
level that the current electricity delivery system must be significantly
changed, then the results of operations and financial condition of AEP and its
operating subsidiaries could be materially adversely affected unless these costs
can be recovered from ratepayers.
RESEARCH AND DEVELOPMENT
AEP and its subsidiaries are involved in over 100 research projects
which are directed toward:
o Developing more efficient methods of burning coal.
o Reducing the emissions resulting from the combustion of coal.
o Utilizing combustion by-products of coal.
o Exploring new methods of generating electricity.
o Exploring the application of new electrotechnologies.
o Improving the efficiency and reliability of power
transmission, distribution and utilization.
AEP System operating companies are members of the Electric Power
Research Institute (EPRI), an organization founded in 1973 that manages research
and development initiatives, primarily on behalf of the U.S. electric utility
industry. These initiatives include technical programs to improve power
production, delivery and use. EPRI's more than 700 members represent over 90% of
the kilowatt sales in the U.S., but also include competitive power producers,
international organizations and others. Total AEP dues to EPRI were $14,000,000
for 1999, $15,400,000 for 1998 and $15,300,000 for 1997.
Total research and development expenditures by AEP and its
subsidiaries, including EPRI dues, were approximately $17,000,000 for the year
ended December 31, 1999, $24,100,000 for the year ended December 31, 1998 and
$23,600,000 for the year ended December 31, 1997. This includes expenditures of
$700,000 for 1999, $3,300,000 for 1998 and $4,600,000 for 1997 related to
pressurized fluidized-bed combustion, a process in which sulfur is removed
during coal combustion and nitrogen oxide formation is minimized.
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Item 2. PROPERTIES
- --------------------------------------------------------------------------------
At December 31, 1999, subsidiaries of AEP owned (or leased where
indicated) generating plants with the net power capabilities (winter rating)
shown in the following table:
<TABLE>
<CAPTION>
NET KILOWATT
OWNER, PLANT TYPE AND NAME LOCATION (NEAR) CAPABILITY
-------------------------- --------------- ----------
<S> <C> <C>
AEP GENERATING COMPANY:
Steam -- Coal-Fired:
Rockport Plant (AEGCo share) Rockport, Indiana 1,300,000(a)
----------
APPALACHIAN POWER COMPANY:
Steam -- Coal-Fired:
John E. Amos, Units 1 & 2 St. Albans, West Virginia 1,600,000
John E. Amos, Unit 3 (APCo share) St. Albans, West Virginia 433,000(b)
Clinch River Carbo, Virginia 705,000
Glen Lyn Glen Lyn, Virginia 335,000
Kanawha River Glasgow, West Virginia 400,000
Mountaineer New Haven, West Virginia 1,300,000
Philip Sporn, Units 1 & 3 New Haven, West Virginia 308,000
Hydroelectric -- Conventional:
Buck Ivanhoe, Virginia 10,000
Byllesby Byllesby, Virginia 20,000
Claytor Radford, Virginia 76,000
Leesville Leesville, Virginia 40,000
London Montgomery, West Virginia 16,000
Marmet Marmet, West Virginia 16,000
Niagara Roanoke, Virginia 3,000
Reusens Lynchburg, Virginia 12,000
Winfield Winfield, West Virginia 19,000
Hydroelectric -- Pumped Storage:
Smith Mountain Penhook, Virginia 565,000
----------
5,858,000
----------
COLUMBUS SOUTHERN POWER COMPANY:
Steam -- Coal-Fired:
Beckjord, Unit 6 New Richmond, Ohio 53,000(c)
Conesville, Units 1-3, 5 & 6 Coshocton, Ohio 1,165,000
Conesville, Unit 4 Coshocton, Ohio 339,000(c)
Picway, Unit 5 Columbus, Ohio 100,000
Stuart, Units 1-4 Aberdeen, Ohio 608,000(c)
Zimmer Moscow, Ohio 330,000(c)
----------
2,595,000
----------
INDIANA MICHIGAN POWER COMPANY:
Steam -- Coal-Fired:
Rockport Plant (I&M share) Rockport, Indiana 1,300,000(a)
Tanners Creek Lawrenceburg, Indiana 995,000
Steam -- Nuclear:
</TABLE>
38
<PAGE> 46
<TABLE>
<CAPTION>
NET KILOWATT
OWNER, PLANT TYPE AND NAME LOCATION (NEAR) CAPABILITY
-------------------------- --------------- ----------
<S> <C> <C>
Donald C. Cook Bridgman, Michigan 2,110,000
Gas Turbine:
Fourth Street Fort Wayne, Indiana 18,000(d)
Hydroelectric -- Conventional
Berrien Springs Berrien Springs, Michigan 3,000
Buchanan Buchanan, Michigan 2,000
Constantine Constantine, Michigan 1,000
Elkhart Elkhart, Indiana 1,000
Mottville Mottville, Michigan 1,000
Twin Branch Mishawaka, Indiana 3,000
----------
4,434,000
----------
KENTUCKY POWER COMPANY:
Steam -- Coal-Fired:
Big Sandy Louisa, Kentucky 1,060,000
----------
OHIO POWER COMPANY:
Steam-- Coal-Fired:
John E. Amos, Unit 3 (OPCo share) St. Albans, West Virginia 867,000(b)
Cardinal, Unit 1 Brilliant, Ohio 600,000
General James M. Gavin Cheshire, Ohio 2,600,000(e)
Kammer Captina, West Virginia 630,000
Mitchell Captina, West Virginia 1,600,000
Muskingum River Beverly, Ohio 1,425,000
Philip Sporn, Units 2, 4 & 5 New Haven, West Virginia 742,000
Hydroelectric-- Conventional:
Racine Racine, Ohio 48,000
----------
8,512,000
----------
Total Generating Capability 23,759,000
==========
SUMMARY:
Total Steam--
Coal-Fired............................................................. 20,795,000
Nuclear................................................................ 2,110,000
Total Hydroelectric--
Conventional........................................................... 271,000
Pumped Storage......................................................... 565,000
Other.................................................................. 18,000
----------
Total Generating Capability.............. 23,759,000
==========
</TABLE>
- --------------------
(a) Unit 1 of the Rockport Plant is owned one-half by AEGCo and one-half by
I&M. Unit 2 of the Rockport Plant is leased one-half by AEGCo and
one-half by I&M. The leases terminate in 2022 unless extended.
(b) Unit 3 of the John E. Amos Plant is owned one-third by APCo and
two-thirds by OPCo.
(c) Represents CSPCo's ownership interest in generating units owned in
common with CG&E and DP&L.
(d) Leased from the City of Fort Wayne, Indiana. Since 1975, I&M has leased
and operated the assets of the municipal system of the City of Fort
Wayne, Indiana under a 35-year lease with a provision for an additional
15-year extension at the election of I&M.
(e) The scrubber facilities at the Gavin Plant are leased. The lease
terminates in 2010 unless extended.
See Item 1 under Fuel Supply, for information concerning coal reserves
owned or controlled by subsidiaries of AEP.
The following table sets forth the total overhead circuit miles of
transmission and distribution lines of the AEP System, APCo,
39
<PAGE> 47
CSPCo, I&M, KEPCo and OPCo and that portion of the total representing
765,000-volt lines:
<TABLE>
<CAPTION>
TOTAL OVERHEAD
CIRCUIT MILES OF
TRANSMISSION AND CIRCUIT MILES OF
DISTRIBUTION LINES 765,000-VOLT LINES
------------------ ------------------
<S> <C> <C>
AEP System (a).............. 129,106(b) 2,022
APCo..................... 50,008 642
CSPCo (a)................ 14,947 --
I&M...................... 20,938 614
KEPCo.................... 10,352 258
OPCo .................... 29,756 509
</TABLE>
- ----------------------
(a) Includes 766 miles of 345,000-volt jointly owned lines.
(b) Includes lines of other AEP System companies not shown.
TITLES
The AEP System's electric generating stations are generally located on
lands owned in fee simple. The greater portion of the transmission and
distribution lines of the System has been constructed over lands of private
owners pursuant to easements or along public highways and streets pursuant to
appropriate statutory authority. The rights of the System in the realty on which
its facilities are located are considered by it to be adequate for its use in
the conduct of its business. Minor defects and irregularities customarily found
in title to properties of like size and character may exist, but such defects
and irregularities do not materially impair the use of the properties affected
thereby. System companies generally have the right of eminent domain whereby
they may, if necessary, acquire, perfect or secure titles to or easements on
privately-held lands used or to be used in their utility operations.
Substantially all the physical properties of APCo, CSPCo, I&M, KEPCo
and OPCo are subject to the lien of the mortgage and deed of trust securing the
first mortgage bonds of each such company.
SYSTEM TRANSMISSION LINES AND FACILITY SITING
Legislation in the states of Indiana, Kentucky, Michigan, Ohio,
Virginia, and West Virginia requires prior approval of sites of generating
facilities and/or routes of high-voltage transmission lines. Delays and
additional costs in constructing facilities have been experienced as a result of
proceedings conducted pursuant to such statutes, as well as in proceedings in
which operating companies have sought to acquire rights-of-way through
condemnation, and such proceedings may result in additional delays and costs in
future years.
PEAK DEMAND
The AEP System is interconnected through 121 high-voltage transmission
interconnections with 25 neighboring electric utility systems. The all-time and
1999 one-hour peak System demands were 25,940,000 and 23,392,000 kilowatts,
respectively (which included 7,314,000 and 3,408,000 kilowatts, respectively, of
scheduled deliveries to unaffiliated systems which the System might, on
appropriate notice, have elected not to schedule for delivery) and occurred on
June 17, 1994 and June 10, 1999, respectively. The net dependable capacity to
serve the System load on such date, including power available under contractual
obligations, was 23,457,000 and 23,919,000 kilowatts, respectively. The all-time
and 1999 one-hour internal peak demands were 19,557,000 and 19,952,000
kilowatts, respectively, and occurred on February 5, 1996 and July 30, 1999,
respectively. The net dependable capacity to serve the System load on such date,
including power dedicated under contractual arrangements, was 23,765,000 and
23,829,000 kilowatts, respectively. The all-time one-hour integrated and
internal net system peak demands and 1999 peak demands for AEP's generating
subsidiaries are shown in the following tabulation:
<TABLE>
<CAPTION>
ALL-TIME ONE-HOUR INTEGRATED 1999 ONE-HOUR INTEGRATED
NET SYSTEM PEAK DEMAND NET SYSTEM PEAK DEMAND
- ------------------------------ --------------------------
(IN THOUSANDS)
NUMBER OF NUMBER OF
KILOWATTS DATE KILOWATTS DATE
----------- ------ ----------- -------
<S> <C> <C> <C> <C>
APCo....... 8,303 January 17, 1997 6,676 January 5, 1999
CSPCo...... 4,172 June 17, 1994 4,139 July 30, 1999
I&M........ 5,027 June 17, 1994 4,798 June 10, 1999
KEPCo...... 1,711 January 17, 1997 1,561 January 5, 1999
OPCo....... 7,291 June 17, 1994 6,626 June 8, 1999
</TABLE>
<TABLE>
<CAPTION>
ALL-TIME ONE-HOUR INTEGRATED 1999 ONE-HOUR INTEGRATED
NET INTERNAL PEAK DEMAND NET INTERNAL PEAK DEMAND
- ------------------------------ --------------------------
(IN THOUSANDS)
NUMBER OF NUMBER OF
KILOWATTS DATE KILOWATTS DATE
----------- ------ ----------- -------
<S> <C> <C> <C> <C>
APCo ...... 6,908 February 5, 1996 6,070 January 5, 1999
CSPCo...... 3,804 July 30, 1999 3,804 July 30, 1999
I&M........ 4,127 July 30, 1999 4,127 July 30, 1999
KEPCo..... 1,558 January 27, 2000 1,432 January 5, 1999
OPCo....... 5,705 June 11, 1999 5,705 June 11, 1999
</TABLE>
40
<PAGE> 48
HYDROELECTRIC PLANTS
AEP has 17 facilities, of which 16 are licensed through FERC. The
license for the hydroelectric plant at Elkhart, Indiana expires in 2000. In
1995, a notice of intent to relicense the Elkhart project was filed. The
application was filed in 1998. The license for the Mottville hydroelectric plant
in Michigan expires in 2003. A notice of intent to relicense was filed in 1998.
COOK NUCLEAR PLANT
Unit 1 of the Cook Plant, which was placed in commercial operation in
1975, has a nominal net electric rating of 1,020,000 kilowatts. Unit 1's
availability factor was -0-% during 1999 and -0-% during 1998. Unit 2, of
slightly different design, has a nominal net electrical rating of 1,090,000
kilowatts and was placed in commercial operation in 1978. Unit 2's availability
factor was -0-% during 1999 and -0-% during 1998. The Cook Plant was shut down
in September 1997 to respond to issues raised regarding the operability of
certain safety systems. See Cook Plant Shutdown.
Units 1 and 2 are licensed by the NRC to operate at 100% of rated
thermal power to October 25, 2014 and December 23, 2017, respectively. However,
for economic or other reasons, operation of the Cook Plant for the full term of
its operating licenses cannot be assured.
Costs associated with the operation, maintenance and retirement of
nuclear plants continue to be of greater significance and less predictable than
costs associated with other sources of generation, in large part due to changing
regulatory requirements and safety standards, availability of nuclear waste
disposal facilities and experience gained in the construction and operation of
nuclear facilities. I&M may also incur costs and experience reduced output at
its Cook Plant because of the design criteria prevailing at the time of
construction and the age of the plant's systems and equipment. Nuclear
industry-wide and Cook Plant initiatives have contributed to slowing the growth
of operating and maintenance costs. However, the ability of I&M to obtain
adequate and timely recovery of costs associated with the Cook Plant, including
replacement power, any unamortized investment at the end of the Cook Plant's
useful life (whether scheduled or premature), the carrying costs of that
investment and retirement costs, is not assured. See Competition and Business
Change.
Cook Plant Shutdown
On September 9 and 10, 1997, during a NRC architect engineer design
inspection, questions regarding the operability of certain safety systems caused
AEP operations personnel to shut down Units 1 and 2 of the Cook Plant. On
September 19, 1997, the NRC issued a Confirmatory Action Letter requiring AEP to
address the issues identified in the letter.
In April 1998 the NRC notified I&M that it had convened a Restart Panel
for Cook Plant. In July 1998 the NRC provided a list of the required restart
activities and in October the NRC expanded the list. In order to identify and
resolve the issues necessary to restart the Cook units, AEP has been meeting
with the Panel on a regular basis until the units are returned to service.
The NRC notified I&M, in a February 2, 2000, letter, that the
Confirmatory Action Letter has been closed. Closing of the Confirmatory Action
Letter is one of the key approvals needed for restart of the Cook Plant.
In July 1998 AEP received an "adverse trend letter" from the NRC
indicating that NRC senior managers determined that there had been a slow
decline in performance at the Cook Plant during the 18-month period preceding
the letter. The letter indicated that the NRC will closely monitor efforts to
address issues at Cook Plant through additional inspection activities.
In October 1998 the NRC issued AEP a Notice of Violation and proposed a
$500,000 civil penalty for alleged violations at the Cook Plant discovered
during five inspections conducted between August 1997 and April 1998. AEP paid
the penalty.
Unit 2 of the Cook Plant is scheduled to restart in April 2000. Unit 1
is currently undergoing steam generator replacement, but restart work has begun
41
<PAGE> 49
and will accelerate following Unit 2 start-up. Unit 1 restart is scheduled for
September 2000. Any issues or difficulties encountered in the testing of
equipment as part of the restart process could delay the scheduled restart
dates. When maintenance and other activities required for restart are complete,
AEP will seek concurrence from the NRC to return the Cook Plant to service.
Costs associated with the steam generator replacement for Unit 1 are
estimated to be approximately $165,000,000, which will be accounted for as a
capital investment unrelated to the restart. At December 31, 1999, $119,000,000
has been spent on the steam generator replacement.
The cost of electricity supplied to retail customers has increased due
to the outage of the Cook Plant because higher cost coal-fired generation and
coal-based purchased power has been substituted for the unavailable lower cost
nuclear generation. With regulator approvals, actual replacement energy fuel
costs that exceeded the costs reflected in billings were recorded as a
regulatory asset under the Indiana and Michigan retail jurisdictional fuel cost
recovery mechanisms.
Indiana Settlement: On March 30, 1999, the IURC approved a settlement
agreement resolving all matters related to the recovery of replacement energy
costs due to the extended Cook Plant outage. The settlement agreement provided
for, among other things:
o Acredit of $55,000,000, including interest, to Indiana retail
customers that was refunded through customer bills during the
months of July, August and September 1999. The credit returned
to customers Cook replacement fuel costs previously recovered.
o Authorization to defer any unrecovered fuel revenues accrued
between September 9, 1997 and December 31, 1999, including the
$55,000,000 credited to customers.
o Authorization to defer up to $150,000,000 in incremental
operation and maintenance restart costs for the Cook Plant
above the base rate level incurred during 1999.
o Amortization of the fuel recoveries and restart cost deferrals
over a five-year period ending December 31, 2003.
o Subject to certain force majeure provisions, a freeze in base
rates through December 31, 2003 and a cap on fuel recovery
charges through March 1, 2004.
o Incremental nuclear decommissioning trust fund deposits of
$2,500,000 annually over a five-year period ending December
31, 2003.
Michigan Settlement: On December 16, 1999, the MPSC approved a
settlement agreement for two open Michigan power supply cost recovery
reconciliation cases that resolves all issues related to the Cook Plant extended
outage. The settlement agreement provides for the following:
o Limits I&M's ability to increase base rates and freezes the
power supply cost recovery factor for five years.
o Permits the deferral of up to $50,000,000 in 1999 of
jurisdictional non-fuel restart nuclear operation and
maintenance expenses.
o Authorizes the amortization of power supply cost recovery
revenues accrued from September 9, 1997 to December 31, 1999
and non-fuel nuclear operation and maintenance cost deferrals
over a five-year period ending December 31, 2003.
Expenses to restart the Cook units are estimated to total approximately
$574,000,000. Through December 31, 1999, $373,000,000 has been spent. The costs
of the Cook outage and restart efforts will have a material adverse effect on
future results of operations and possibly financial condition through 2003 and
on cash flows through 2000. If the Cook units are not returned to service as
scheduled, their continued outage would make the adverse effect greater on
future results of operations, cash flows and financial condition.
Nuclear Incident Liability
The Price-Anderson Act limits public liability for a nuclear incident
at any licensed reactor in the
42
<PAGE> 50
United States to $9.9 billion. I&M has insurance coverage for liability from a
nuclear incident at its Cook Plant. Such coverage is provided through a
combination of private liability insurance, with the maximum amount available of
$200,000,000, and mandatory participation for the remainder of the $9.9 billion
liability, in an industry retrospective deferred premium plan which would, in
case of a nuclear incident, assess all licensees of nuclear plants in the U.S.
Under the deferred premium plan, I&M could be assessed up to $176,000,000
payable in annual installments of $20,000,000 in the event of a nuclear incident
at Cook or any other nuclear plant in the U.S. There is no limit on the number
of incidents for which I&M could be assessed these sums.
I&M also has property damage, decontamination and decommissioning
insurance for loss resulting from damage to the Cook Plant facilities in the
amount of $2.75 billion. Coverage is provided by Energy Insurance Bermuda (EIB)
and Nuclear Electric Insurance Limited (NEIL). If EIB's and NEIL's losses exceed
their available resources, I&M would be subject to a total retrospective premium
assessment of up to $16,704,380. NRC regulations require that, in the event of
an accident, whenever the estimated costs of reactor stabilization and site
decontamination exceed $100,000,000, the insurance proceeds 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 in accordance with
a plan approved by the NRC. The insurers then would indemnify I&M for
decommissioning costs in excess of funds already collected for decommissioning
and for property damage up to $3.0 billion less any amounts used for
stabilization and decontamination. See Fuel Supply -- Nuclear Waste.
The NEIL extra-expense programs provide insurance to cover extra costs
resulting from a prolonged accidental outage of a nuclear unit. I&M's policy
insures against such increased costs up to approximately $3,500,000 per week
(starting 12 weeks after the outage) for 52 weeks and $2,800,000 per week for
the next 110 weeks, or 80% of those amounts per unit if both units are down for
the same reason. If NEIL's losses exceed its available resources, I&M would be
subject to a total retrospective premium assessment of up to $5,485,760.
POTENTIAL UNINSURED LOSSES
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
costs of replacement power in the event of a nuclear incident at the Cook Plant.
Future losses or liabilities which are not completely insured, unless allowed to
be recovered through rates, could have a material adverse effect on results of
operations and the financial condition of AEP, I&M and other AEP System
companies.
Item 3. LEGAL PROCEEDINGS
- --------------------------------------------------------------------------------
On February 28, 1994, Ormet Corporation filed a complaint in the U.S.
District Court, Northern District of West Virginia, against AEP, OPCo, the
Service Corporation and two of its employees, Federal EPA and the Administrator
of Federal EPA. Ormet is the operator of a major aluminum reduction plant in
Ohio and was a customer of OPCo until December 31, 1999. See Certain Industrial
Customers. Pursuant to the Clean Air Act Amendments of 1990, OPCo received SO2
Allowances for its Kammer Plant. See Environmental and Other Matters. Ormet's
complaint sought a declaration that it is the owner of approximately 89% of the
Phase I and Phase II SO2 allowances issued for use by the Kammer Plant. In March
1995, the District Court dismissed the complaint for lack of jurisdiction and,
in October 1996, the U.S. Court of Appeals for the Fourth Circuit reversed this
decision. In March 1999, the District Court granted the motion of OPCo and the
Service Corporation for summary judgment and dismissed the case. Ormet filed an
appeal in the U.S. Court of Appeals for the Fourth Circuit in March 1999. On
November 30, 1999, the court held oral argument.
-------------------------
43
<PAGE> 51
The Internal Revenue Service (IRS) agents auditing the AEP System's
consolidated federal income tax returns requested a ruling from their National
Office that certain interest deductions claimed by AEP relating to its corporate
owned life insurance (COLI) program should not be allowed. As a result of a suit
filed in U.S. District Court (discussed below) this request for ruling was
withdrawn by the IRS agents. Adjustments have been or will be proposed by the
IRS disallowing COLI interest deductions for taxable years 1991-96. A
disallowance of the COLI interest deductions through December 31, 1999 would
reduce earnings (including interest) as follows:
(in millions)
AEP System........................ $317
APCo........................... 79
CSPCo.......................... 43
I&M............................ 66
KEPCo.......................... 8
OPCo........................... 118
AEP made payments of taxes and interest attributable to COLI interest
deductions for taxable years 1991-98 to avoid the potential assessment by the
IRS of any additional above- market rate interest on the contested amount. The
payments to the IRS are included on the consolidated balance sheet in other
assets pending the resolution of this matter. AEP is seeking refund through
litigation of all amounts paid plus interest.
In order to resolve this issue, AEP filed suit against the U.S. in the
U.S. District Court for the Southern District of Ohio in March 1998. In 1999 a
U.S. Tax Court judge decided in a case involving an unaffiliated company that a
corporate taxpayer's COLI interest deduction should be disallowed.
Notwithstanding the decision in this case, management has made no provision for
any possible adverse earnings impact from this matter because it believes, and
has been advised by outside counsel, that it has a meritorious position. In the
event the resolution of this matter is unfavorable, it could have a material
adverse impact on results of operations, cash flows and financial condition.
----------------------
See Item 1 for a discussion of certain environmental and rate matters.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- --------------------------------------------------------------------------------
AEP, APCO, I&M AND OPCO. None.
AEGCO, CSPCO AND KEPCO. Omitted pursuant to Instruction I(2)(c).
---------------------
EXECUTIVE OFFICERS OF THE REGISTRANTS
AEP. The following persons are, or may be deemed, executive officers of
AEP. Their ages are given as of March 1, 2000.
<TABLE>
<CAPTION>
NAME AGE OFFICE (a)
- ---- --- ----------
<S> <C> <C>
E. Linn Draper, Jr............ 58 Chairman of the Board, President and Chief Executive Officer of AEP and of the
Service Corporation
Paul D. Addis................. 46 Executive Vice President of the Service Corporation
Donald M. Clements, Jr........ 50 Executive Vice President-Corporate Development of the Service
Corporation
Henry W. Fayne................ 53 Executive Vice President-Financial Services of the Service Corporation
William J. Lhota.............. 60 Executive Vice President of the Service Corporation
Susan Tomasky................. 46 Executive Vice President of the Service Corporation
J. H. Vipperman............... 59 Executive Vice President-Corporate Services of the Service Corporation
</TABLE>
- -----------------------
(a) All of the executive officers listed above have been employed by the
Service Corporation or System companies in various capacities (AEP, as
such, has no employees) during the past five years, except for Mr.
Addis and Ms. Tomasky. Prior to joining the Service Corporation in
February 1997 in his present position, Mr. Addis was Executive Vice
President (1992-1993) and President (1993-January 1997) of Louis
Dreyfus Electric Power, Inc. and President of Duke/Louis Dreyfus LLC
(1995-January 1997). Mr. Addis became an executive officer of AEP
effective January 1, 2000. Prior to joining the Service Corporation in
July 1998 as Senior Vice President, Ms. Tomasky was a partner with the
law firm of Hogan & Hartson (August 1997-July 1998) and General Counsel
of the Federal Energy Regulatory Commission (May 1993-August 1997). Ms.
Tomasky became an executive officer of AEP effective with her promotion
to Executive Vice President on January 26, 2000. All of the above
officers are appointed annually for a one-year term by the board of
directors of AEP, the board of directors of the Service Corporation, or
both, as the case may be.
44
<PAGE> 52
APCO. The names of the executive officers of APCo, the positions they
hold with APCo, their ages as of March 1, 2000, and a brief account of their
business experience during the past five years appears below. The directors and
executive officers of APCo are elected annually to serve a one-year term.
<TABLE>
<CAPTION>
NAME AGE POSITION (a) PERIOD
- ---- --- ------------ ------
<S> <C> <C> <C>
E. Linn Draper, Jr............ 58 Director 1992-Present
Chairman of the Board and Chief Executive Officer 1993-Present
Vice President 1992-1993
Chairman of the Board, President and Chief Executive
Officer of AEP and the Service Corporation 1993-Present
President of AEP 1992-1993
President and Chief Operating Officer of the
Service Corporation 1992-1993
Henry W. Fayne................ 53 Director 1995-Present
Vice President 1998-Present
Vice President and Chief Financial Officer of AEP 1998-Present
Executive Vice President-Financial Services of the
Service Corporation 1998-Present
Senior Vice President-Corporate Planning & Budgeting
of the Service Corporation 1995-1998
Senior Vice President-Controller of the
Service Corporation 1993-1995
William J. Lhota.............. 60 Director 1990-Present
President and Chief Operating Officer 1996-Present
Vice President 1989-1995
Executive Vice President of the Service Corporation 1993-Present
Executive Vice President-Operations of the Service
Corporation 1989-1993
J. H. Vipperman............... 59 Director 1985-Present
Vice President 1996-Present
President and Chief Operating Officer 1990-1995
Executive Vice President-Corporate Services of the
Service Corporation 1998-Present
Executive Vice President-Energy Delivery of the
Service Corporation 1996-1997
</TABLE>
- ----------------------
(a) Positions are with APCo unless otherwise indicated.
OPCO. The names of the executive officers of OPCo, the positions they
hold with OPCo, their ages as of March 1, 2000, and a brief account of their
business experience during the past five years appear below. The directors and
executive officers of OPCo are elected annually to serve a one-year term.
<TABLE>
<CAPTION>
NAME AGE POSITION (a) PERIOD
- ---- --- ------------ ------
<S> <C> <C> <C>
E. Linn Draper, Jr.......... 58 Director 1992-Present
Chairman of the Board and Chief Executive Officer 1993-Present
Vice President 1992-1993
Chairman of the Board, President and Chief Executive
Officer of AEP and the Service Corporation 1993-Present
President of AEP 1992-1993
President and Chief Operating Officer of the Service
Corporation 1992-1993
</TABLE>
45
<PAGE> 53
<TABLE>
<CAPTION>
NAME AGE POSITION (a) PERIOD
- ---- --- ------------ ------
<S> <C> <C> <C>
Henry W. Fayne.............. 53 Director 1993-Present
Vice President 1998-Present
Vice President and Chief Financial Officer of AEP 1998-Present
Executive Vice President-Financial Services of the
Service Corporation 1998-Present
Senior Vice President-Corporate Planning & Budgeting
of the Service Corporation 1995-1998
Senior Vice President-Controller of the
Service Corporation 1993-1995
William J. Lhota............ 60 Director 1989-Present
President and Chief Operating Officer 1996-Present
Vice President 1989-1995
Executive Vice President of the Service Corporation 1993-Present
Executive Vice President-Operations of the Service
Corporation 1989-1993
J. H. Vipperman............. 59 Director and Vice President 1996-Present
Executive Vice President-Corporate Services of the
Service Corporation 1998-Present
Executive Vice President-Energy Delivery of the
Service Corporation 1996-1997
President and Chief Operating Officer of APCo 1990-1995
</TABLE>
- ---------------------
(a) Positions are with OPCo unless otherwise indicated.
PART II=========================================================================
Item 5. MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
- --------------------------------------------------------------------------------
AEP. AEP Common Stock is traded principally on the New York Stock
Exchange. The following table sets forth for the calendar periods indicated the
high and low sales prices for the Common Stock as reported on the New York Stock
Exchange Composite Tape and the amount of cash dividends paid per share of
Common Stock.
<TABLE>
<CAPTION>
PER SHARE
MARKET PRICE
----------------------
QUARTER ENDED HIGH LOW DIVIDEND
- ------------- ---- --- --------
<S> <C> <C> <C>
March 1998............................................ 51-11/16 47-13/16 .60
June 1998............................................. 50-3/4 44-11/16 .60
September 1998........................................ 48-13/16 42-1/16 .60
December 1998......................................... 53-5/16 45-5/16 .60
March 1999............................................ 48-3/16 39-5/16 .60
June 1999............................................. 44-1/16 37-7/16 .60
September 1999........................................ 37-7/8 33-1/2 .60
December 1999......................................... 35-13/16 30-9/16 .60
</TABLE>
At December 31, 1999, AEP had approximately 125,000 shareholders of
record.
AEGCO, APCO, CSPCO, I&M, KEPCO AND OPCO. The information required by this item
is not applicable as the common stock of all these companies is held solely by
AEP.
46
<PAGE> 54
Item 6. SELECTED FINANCIAL DATA
- --------------------------------------------------------------------------------
AEGCO. Omitted pursuant to Instruction I(2)(a).
AEP. The information required by this item is incorporated herein by
reference to the material under Selected Consolidated Financial Data in the AEP
1999 Annual Report (for the fiscal year ended December 31, 1999).
APCO. The information required by this item is incorporated herein by
reference to the material under Selected Consolidated Financial Data in the APCo
1999 Annual Report (for the fiscal year ended December 31, 1999).
CSPCO. Omitted pursuant to Instruction I(2)(a).
I&M. The information required by this item is incorporated herein by
reference to the material under Selected Consolidated Financial Data in the I&M
1999 Annual Report (for the fiscal year ended December 31, 1999).
KEPCO. Omitted pursuant to Instruction I(2)(a).
OPCO. The information required by this item is incorporated herein by
reference to the material under Selected Consolidated Financial Data in the OPCo
1999 Annual Report (for the fiscal year ended December 31, 1999).
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
- --------------------------------------------------------------------------------
AEGCO. Omitted pursuant to Instruction I(2)(a). Management's narrative
analysis of the results of operations and other information required by
Instruction I(2)(a) is incorporated herein by reference to the material under
Management's Narrative Analysis of Results of Operations in the AEGCo 1999
Annual Report (for the fiscal year ended December 31, 1999).
AEP. The information required by this item is incorporated herein by
reference to the material under Management's Discussion and Analysis of Results
of Operations and Financial Condition in the AEP 1999 Annual Report (for the
fiscal year ended December 31, 1999).
APCO. The information required by this item is incorporated herein by
reference to the material under Management's Discussion and Analysis of Results
of Operations and Financial Condition in the APCo 1999 Annual Report (for the
fiscal year ended December 31, 1999).
CSPCO. Omitted pursuant to Instruction I(2)(a). Management's narrative
analysis of the results of operations and other information required by
Instruction I(2)(a) is incorporated herein by reference to the material under
Management's Narrative Analysis of Results of Operations in the CSPCo 1999
Annual Report (for the fiscal year ended December 31, 1999).
I&M. The information required by this item is incorporated herein by
reference to the material under Management's Discussion and Analysis of Results
of Operations and Financial Condition in the I&M 1999 Annual Report (for the
fiscal year ended December 31, 1999).
KEPCO. Omitted pursuant to Instruction I(2)(a). Management's narrative
analysis of the results of operations and other information required by
Instruction I(2)(a) is incorporated herein by reference to the material under
Management's Narrative Analysis of Results of Operations in the KEPCo 1999
Annual Report (for the fiscal year ended December 31, 1999).
OPCO. The information required by this item is incorporated herein by
reference to the material under Management's Discussion and Analysis of Results
of Operations and Financial Condition in the OPCo 1999 Annual Report (for the
fiscal year ended December 31, 1999).
47
<PAGE> 55
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
- --------------------------------------------------------------------------------
AEGCO. The information required by this item is incorporated herein by
reference to the material under Management's Narrative Analysis of Results of
Operations in the AEGCo 1999 Annual Report (for the fiscal year ended December
31, 1999).
AEP. The information required by this item is incorporated herein by
reference to the material under Management's Discussion and Analysis of Results
of Operations and Financial Condition in the AEP 1999 Annual Report (for the
fiscal year ended December 31, 1999).
APCO. The information required by this item is incorporated herein by
reference to the material under Management's Discussion and Analysis of Results
of Operations and Financial Condition in the APCo 1999 Annual Report (for the
fiscal year ended December 31, 1999).
CSPCO. The information required by this item is incorporated herein by
reference to the material under Management's Narrative Analysis of Results of
Operations in the CSPCo 1999 Annual Report (for the fiscal year ended December
31, 1999).
I&M. The information required by this item is incorporated herein by
reference to the material under Management's Discussion and Analysis of Results
of Operations and Financial Condition in the I&M 1999 Annual Report (for the
fiscal year ended December 31, 1999).
KEPCO. The information required by this item is incorporated herein by
reference to the material under Management's Narrative Analysis of Results of
Operations in the KEPCo 1999 Annual Report (for the fiscal year ended December
31, 1999).
OPCO. The information required by this item is incorporated herein by
reference to the material under Management's Discussion and Analysis of Results
of Operations and Financial Condition in the OPCo 1999 Annual Report (for the
fiscal year ended December 31, 1999).
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- --------------------------------------------------------------------------------
AEGCO, AEP, APCO, CSPCO, I&M, KEPCO, AND OPCO. The information required
by this item is incorporated herein by reference to the financial statements and
supplementary data described under Item 14 herein.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
- --------------------------------------------------------------------------------
AEGCO, AEP, APCO, CSPCO, I&M, KEPCO AND OPCO. None.
PART III =======================================================================
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
- --------------------------------------------------------------------------------
AEGCO. Omitted pursuant to Instruction I(2)(c).
AEP. The information required by this item is incorporated herein by
reference to the material under Nominees for Director of the definitive proxy
statement of AEP for the 2000 annual meeting of shareholders, to be filed within
120 days after December 31, 1999. Reference also is made to the information
under the caption Executive Officers of the Registrants in Part I of this
report.
48
<PAGE> 56
APCO. The information required by this item is incorporated herein by
reference to the material under Election of Directors of the definitive
information statement of APCo for the 2000 annual meeting of stockholders, to be
filed within 120 days after December 31, 1999. Reference also is made to the
information under the caption Executive Officers of the Registrants in Part I of
this report.
CSPCO. Omitted pursuant to Instruction I(2)(c).
I&M. The names of the directors and executive officers of I&M, the
positions they hold with I&M, their ages as of March 1, 2000, and a brief
account of their business experience during the past five years appear below.
The directors and executive officers of I&M are elected annually to serve a
one-year term.
<TABLE>
<CAPTION>
NAME AGE POSITION (a)(b)(c) PERIOD
- ---- --- ------------------ ------
<S> <C> <C> <C>
E. Linn Draper, Jr............ 58 Director 1992-Present
Chairman of the Board and Chief Executive Officer 1993-Present
Vice President 1992-1993
Chairman of the Board, President and Chief Executive
Officer of AEP and of the Service Corporation 1993-Present
President of AEP 1992-1993
President and Chief Operating Officer of the Service
Corporation 1992-1993
Henry W. Fayne................ 53 Director and Vice President 1998-Present
Vice President and Chief Financial Officer of AEP 1998-Present
Executive Vice President-Financial Services of the
Service Corporation 1998-Present
Senior Vice President-Corporate Planning &
Budgeting of the Service Corporation 1995-1998
Senior Vice President-Controller of the
Service Corporation 1993-1995
William J. Lhota.............. 60 Director 1989-Present
President and Chief Operating Officer 1996-Present
Vice President 1989-1995
Executive Vice President of the Service Corporation 1993-Present
Executive Vice President-Operations of the Service
Corporation 1989-1993
Armando A. Pena............... 55 Director, Vice President and Chief Financial Officer 1998-Present
Treasurer 1995-Present
Chief Financial Officer of the Service Corporation 1998-Present
Senior Vice President-Finance of the Service
Corporation 1996-Present
Treasurer of AEP and the Service Corporation 1995-Present
J. H. Vipperman............... 59 Director and Vice President 1996-Present
Executive Vice President-Corporate Services of the
Service Corporation 1998-Present
Executive Vice President-Energy Delivery of the 1996-1997
Service Corporation
President and Chief Operating Officer of APCo 1990-1995
K. G. Boyd.................... 48 Director 1997-Present
Indiana Region Manager 1997-Present
Fort Wayne District Manager 1994-1997
</TABLE>
49
<PAGE> 57
<TABLE>
<CAPTION>
NAME AGE POSITION (a)(b)(c) PERIOD
- ---- --- ------------------ ------
<S> <C> <C> <C>
Jeffrey A. Drozda............. 32 Director 1999-Present
Governmental Affairs Manager-Indiana 1997-Present
Federal Regulatory Affairs Manager 1996-1997
Executive Assistant-Public Utilities Commission of Ohio 1993-1996
Mark W. Marano............... 38 Director 1999-Present
Director, Business Services (Cook Nuclear Plant) 1999-Present
Director, Nuclear Site & Business Support-Florida Power 1997-1999
Corp.
Manager, Corrective Action/Quality Services-Public
Service Electric & Gas 1995-1997
John R. Sampson............... 47 Director and Vice President 1999-Present
Indiana & Michigan State President 1999-Present
Site Vice President, Cook Nuclear Plant 1998-1999
Plant Manager, Cook Nuclear Plant 1996-1998
D. B. Synowiec................ 56 Director 1995-Present
Plant Manager, Rockport Plant 1990-Present
W. E. Walters................. 52 Director 1991-Present
Michiana Region Manager 1994-Present
Executive Assistant to President 1987-1994
E. H. Wittkamper.............. 61 Director 1996-Present
Director of System Operations (Fort Wayne) 1996
System Operations Manager (Fort Wayne) 1990-1996
</TABLE>
- -----------------
(a) Positions are with I&M unless otherwise indicated.
(b) Dr. Draper is a director of BCP Management, Inc., which is the general
partner of Borden Chemicals and Plastics L.P., and CellNet Data
Systems, Inc. and Mr. Lhota is a director of Huntington Bancshares
Incorporated and State Auto Financial Corporation.
(c) Dr. Draper and Messrs. Fayne, Lhota and Pena are directors of AEGCo,
APCo, CSPCo, KEPCo and OPCo. Dr. Draper is also a director of AEP. Mr.
Vipperman is a director of APCo, CSPCo, KEPCo and OPCo.
KEPCO. Omitted pursuant to Instruction I(2)(c).
OPCO. The information required by this item is incorporated herein by
reference to the material under the heading Election of Directors of the
definitive information statement of OPCo for the 2000 annual meeting of
shareholders, to be filed within 120 days after December 31, 1999. Reference
also is made to the information under the caption Executive Officers of the
Registrants in Part I of this report.
Item 11. EXECUTIVE COMPENSATION
- --------------------------------------------------------------------------------
AEGCO. Omitted pursuant to Instruction I(2)(c).
AEP. The information required by this item is incorporated herein by
reference to the material under Directors Compensation and Stock Ownership
Guidelines, Executive Compensation and the performance graph of the definitive
proxy statement of AEP for the 2000 annual meeting of shareholders to be filed
within 120 days after December 31, 1999.
APCO. The information required by this item is incorporated herein by
reference to the material under Executive Compensation of the definitive
information statement of APCo for the 2000 annual meeting of stockholders, to be
filed within 120 days after December 31, 1999.
CSPCO. Omitted pursuant to Instruction I(2)(c).
KEPCO. Omitted pursuant to Instruction I(2)(c).
50
<PAGE> 58
OPCO. The information required by this item is incorporated herein by
reference to the material under Executive Compensation of the definitive
information statement of OPCo for the 2000 annual meeting of shareholders, to be
filed within 120 days after December 31, 1999.
I&M. Certain executive officers of I&M are employees of the Service
Corporation. The salaries of these executive officers are paid by the Service
Corporation and a portion of their salaries has been allocated and charged to
I&M. The following table shows for 1999, 1998 and 1997 the compensation earned
from all AEP System companies by the chief executive officer and four other most
highly compensated executive officers (as defined by regulations of the SEC) of
I&M at December 31, 1999.
Summary Compensation Table
<TABLE>
<CAPTION>
LONG TERM
ANNUAL COMPENSATION
COMPENSATION --------------------- ALL OTHER
-------------------- PAYOUTS COMPENSATION
SALARY BONUS --------------------- ($)(2)
NAME AND PRINCIPAL POSITION YEAR ($) ($)(1) LTIP PAYOUTS ($)(1)
---------------------------------- ------- ------- --------- --------------------- ------------
<S> <C> <C> <C> <C> <C>
E. LINN DRAPER, JR. - Chairman of the board, 1999 820,000 208,280 -0- 103,218
president and chief executive officer of the 1998 780,000 194,376 345,906 104,941
Company and the Service Corporation; chairman 1997 720,000 327,744 951,132 31,620
and chief executive officer of other
subsidiaries
WILLIAM J. LHOTA - Executive vice president and 1999 400,000 71,120 -0- 55,690
director of the Service Corporation; 1998 380,000 82,859 134,266 56,493
president, chief operating officer and 1997 355,000 141,396 364,436 20,570
director of other subsidiaries
JAMES J. MARKOWSKY - Executive vice president - 1999 370,000 65,786 -0- 51,047
power generation and director of the Service 1998 350,000 76,317 127,115 51,859
Corporation; vice president and director of 1997 325,000 129,447 338,382 18,020
other subsidiaries (3)
JOSEPH H. VIPPERMAN - Executive vice president 1999 330,000 58,674 -0- 63,006
-corporate services and director of the 1998 310,000 67,595 82,859 58,435
Service Corporation; vice president and
director of other subsidiaries (4)
HENRY W. FAYNE - Executive vice president - 1999 315,000 56,007 -0- 34,885
financial services and director of the Service 1998 290,000 63,234 61,555 34,124
Corporation; vice president and director of
other subsidiaries (4)
</TABLE>
- ------------------------
(1) Amounts in the Bonus column reflect awards under the Senior Officer Annual
Incentive Compensation Plan. Payments are made in March of the succeeding
fiscal year for performance in the year indicated. Amounts for 1999 are
estimates but should not change significantly.
Amounts in the Long Term Compensation column reflect performance share unit
targets earned under the Performance Share Incentive Plan for three-year
performance periods.
See below under Long Term Incentive Plans - Awards in 1999.
(2) Amounts in the All Other Compensation column include (i) AEP's matching
contributions under the AEP Employees Savings Plan and the AEP Supplemental
Savings Plan, a non-qualified plan designed to supplement the AEP Savings
Plan, and (ii) subsidiary companies director fees. For 1998 and 1999, the
amounts also include split-dollar insurance. Split-dollar insurance
represents the present value of the interest projected to accrue for the
employee's benefit on the current year's insurance premium paid by AEP.
Cumulative net life insurance premiums paid are recovered by AEP at the
later of retirement or 15 years. Detail of the 1999 amounts in the All
Other Compensation column is shown below.
<TABLE>
<CAPTION>
Item Dr. Draper Mr. Lhota Dr. Markowsky Mr. Vipperman Mr. Fayne
---- ---------- --------- ------------- ------------- ---------
<S> <C> <C> <C> <C> <C>
Savings Plan Matching Contributions $ 3,462 $ 4,800 $ 3,381 $ 3,762 $ 4,800
Supplemental Savings Plan Matching
Contributions 21,138 7,200 7,719 6,138 4,650
Split-Dollar Insurance 68,638 33,710 29,967 47,106 17,105
Subsidiaries Directors Fees 9,980 9,980 9,980 6,000 8,330
-------- -------- -------- -------- --------
Total All Other Compensation $103,218 $ 55,690 $ 51,047 $ 63,006 $ 34,885
======== ======== ======== ======== ========
</TABLE>
(3) Dr. Markowsky resigned effective February 1, 2000.
(4) No 1997 compensation information is reported for Messrs. Vipperman and
Fayne because they were not executive officers in these years.
51
<PAGE> 59
Long-Term Incentive Plans -- Awards In 1999
Each of the awards set forth below establishes performance share unit
targets, which represent units equivalent to shares of Common Stock, pursuant to
the Company's Performance Share Incentive Plan. Since it is not possible to
predict future dividends and the price of AEP Common Stock, credits of
performance share units in amounts equal to the dividends that would have been
paid if the performance share unit targets were established in the form of
shares of Common Stock are not included in the table.
The ability to earn performance share unit targets is tied to achieving
specified levels of total shareholder return (TSR) relative to the S&P Electric
Utility Index. Notwithstanding AEP's TSR ranking, no performance share unit
targets are earned unless AEP shareholders realize a positive TSR over the
relevant three performance period. The Human Resources Committee may, at its
discretion, reduce the number of performance share unit targets otherwise
earned. In accordance with the performance goals established for the periods set
forth below, the threshold, target and maximum awards are equal to 25%, 100% and
200%, respectively, of the performance share unit targets. No payment will be
made for performance below the threshold.
Payments of earned awards are deferred in the form of restricted stock
units (equivalent to shares of AEP Common Stock) until officers have met the
equivalent stock ownership target. Once officers meet and maintain their
respective targets, they may elect either to continue to defer or to receive
further earned awards in cash and/or Common Stock.
<TABLE>
<CAPTION>
ESTIMATED FUTURE PAYOUTS OF
PERFORMANCE SHARE UNITS UNDER
PERFORMANCE NON-STOCK PRICE-BASED PLAN
NUMBER OF PERIOD UNTIL --------------------------------------------
PERFORMANCE MATURATION THRESHOLD TARGET MAXIMUM
NAME SHARE UNITS OR PAYOUT (#) (#) (#)
----------------- --------------- ----------------- ------------- --------- -------------
<S> <C> <C> <C> <C> <C>
E. L. Draper, Jr................... 8,728 1999-2001 2,182 8,728 17,456
W. J. Lhota........................ 2,980 1999-2001 745 2,980 5,960
J. J. Markowsky.................... 2,794 1999-2001 698 2,794 5,588
J. H. Vipperman.................... 2,459 1999-2001 615 2,459 4,918
H. W. Fayne........................ 2,347 1999-2001 587 2,347 4,694
</TABLE>
Retirement Benefits
The American Electric Power System Retirement Plan provides pensions
for all employees of AEP System companies (except for employees covered by
certain collective bargaining agreements), including the executive officers of
the Company. The Retirement Plan is a noncontributory defined benefit plan.
The following table shows the approximate annual annuities under the
Retirement Plan that would be payable to employees in certain higher salary
classifications, assuming retirement at age 65 after various periods of service.
Pension Plan Table
<TABLE>
<CAPTION>
YEARS OF ACCREDITED SERVICE
HIGHEST AVERAG -------------------------------------------------------------------------------------------
ANNUAL EARNINGS 15 20 25 30 35 40
--------------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
$ 300,000 $ 69,345 $ 92,460 $115,575 $138,690 $161,805 $181,755
400,000 93,345 124,460 155,575 186,690 217,805 244,405
500,000 117,345 156,460 195,575 234,690 273,805 307,055
700,000 165,345 220,460 275,575 330,690 385,805 432,355
900,000 213,345 284,460 355,575 426,690 497,805 557,655
1,200,000 285,345 380,460 475,575 570,690 665,805 745,605
</TABLE>
The amounts shown in the table are the straight life annuities payable
under the Retirement Plan without reduction for the joint and survivor annuity.
Retirement benefits listed in the table are not subject to any deduction for
Social Security or other offset amounts. The retirement annuity is reduced 3%
per
52
<PAGE> 60
year in the case of retirement between ages 55 and 62. If an employee retires
after age 62, there is no reduction in the retirement annuity.
The Company maintains a supplemental retirement plan which provides for
the payment of benefits that are not payable under the Retirement Plan due
primarily to limitations imposed by Federal tax law on benefits paid by
qualified plans. The table includes supplemental retirement benefits.
Compensation upon which retirement benefits are based, for the
executive officers named in the Summary Compensation Table above, consists of
the average of the 36 consecutive months of the officer's highest aggregate
salary and Senior Officer Annual Incentive Compensation Plan awards, shown in
the "Salary" and "Bonus" columns, respectively, of the Summary Compensation
Table, out of the officer's most recent 10 years of service. As of December 31,
1999, the number of full years of service applicable for retirement benefit
calculation purposes for such officers were as follows: Dr. Draper, seven years;
Mr. Lhota, 34 years; Dr. Markowsky, 28 years; Mr. Vipperman, 37 years; and Mr.
Fayne, 24 years.
Dr. Draper has a contract with the Company and AEP Service Corporation
which provides him with a supplemental retirement annuity that credits him with
24 years of service in addition to his years of service credited under the
Retirement Plan less his actual pension entitlement under the Retirement Plan
and any pension entitlement from the Gulf States Utilities Company Trusteed
Retirement Plan, a plan sponsored by his prior employer.
Eight AEP System employees (including Messrs. Fayne, Lhota and
Vipperman and Dr. Markowsky) whose pensions may be adversely affected by
amendments to the Retirement Plan made as a result of the Tax Reform Act of
1986 are eligible for certain supplemental retirement benefits. Such payments,
if any, will be equal to any reduction occurring because of such amendments.
Assuming retirement in 2000 of the executive officers named in the Summary
Compensation Table (including Dr. Markowsky who resigned effective February 1,
2000), none of them would receive any supplemental benefits.
AEP made available a voluntary deferred-compensation program in 1982
and 1986, which permitted certain members of AEP System management to defer
receipt of a portion of their salaries. Under this program, a participant was
able to defer up to 10% or 15% annually (depending on the terms of the program
offered), over a four-year period, of his or her salary, and receive
supplemental retirement or survivor benefit payments over a 15-year period. The
amount of supplemental retirement payments received is dependent upon the amount
deferred, age at the time the deferral election was made, and number of years
until the participant retires. The following table sets forth, for the executive
officers named in the Summary Compensation Table, the amounts of annual
deferrals and, assuming retirement at age 65, annual supplemental retirement
payments under the 1982 and 1986 programs.
<TABLE>
<CAPTION>
1982 PROGRAM 1986 PROGRAM
------------------------------------------- -------------------------------------------
ANNUAL AMOUNT OF ANNUAL AMOUNT OF
ANNUAL SUPPLEMENTAL ANNUAL SUPPLEMENTAL
AMOUNT RETIREMENT AMOUNT RETIREMENT
DEFERRED PAYMENT DEFERRED PAYMENT
NAME (4-YEAR PERIOD) (15-YEAR PERIOD) (4-YEAR PERIOD) (15-YEAR PERIOD)
-------- ------------------- -------------------- ------------------- --------------------
<S> <C> <C> <C> <C>
J. H. Vipperman............... $ 11,000 $ 90,750 $ 10,000 $ 67,500
H. W. Fayne................... $ 0 $ 0 $ 9,000 $ 95,400
</TABLE>
Severance Plan and Change-In-Control Agreements
SEVERANCE PLAN. In connection with the proposed merger with Central and
South West Corporation, AEP's Board of Directors adopted a severance plan on
February 24, 1999, effective March 1, 1999, that includes Dr. Markowsky and
Messrs. Lhota, Vipperman and Fayne. The severance plan provides for payments and
other benefits if, at any time before the second anniversary of the merger
consummation date (or, if
53
<PAGE> 61
the merger has not occurred, before the expiration of the severance plan which
will occur upon the termination of the merger agreement), the officer's
employment is terminated (i) by AEP without "cause" or (ii) by the officer
because of a detrimental change in responsibilities or a reduction in salary or
benefits. Under the severance plan, the officer will receive:
o A lump sum payment equal to three times the officer's annual
base salary plus target annual incentive under the Senior
Officer Annual Incentive Compensation Plan.
o Maintenance for a period of three additional years of all
medical and dental insurance benefits substantially similar to
those benefits to which the officer was entitled immediately
prior to termination, reduced to the extent comparable
benefits are otherwise received.
o Outplacement services not to exceed a cost of $30,000 or use
of an office and secretarial services for up to one year.
AEP's obligation for the payments and benefits under the severance plan
is subject to the waiver by the officer of any other severance benefits that may
be provided by AEP. In addition, the officer agrees to refrain from the
disclosure of confidential information relating to AEP.
Dr. Markowsky resigned effective February 1, 2000 and has received a
lump sum payment in accordance with the terms of the severance plan.
CHANGE-IN-CONTROL AGREEMENTS. AEP has change-in-control agreements with
Dr. Draper and Messrs. Lhota, Vipperman and Fayne. If there is a
"change-in-control" of AEP and the employee's employment is terminated by AEP or
by the employee for reasons substantially similar to those in the severance
plan, these agreements provide for substantially the same payments and benefits
as the severance plan with the following additions:
o Three years of service credited for purposes of determining
non-qualified retirement benefits.
o Transfer to the employee of title to AEP's automobile then
assigned to the employee.
o Payment, if required, to make the employee whole for any
excise tax imposed by Section 4999 of the Internal Revenue
Code.
"Change-in-control" means:
o The acquisition by any person of the beneficial ownership of
securities representing 25% or more of AEP's voting stock.
o A change in the composition of a majority of the Board of
Directors under certain circumstances within any two-year
period.
o Approval by the shareholders of the liquidation of AEP,
disposition of all or substantially all of the assets of AEP
or, under certain circumstances, a merger of AEP with another
corporation.
-----------------------------
Directors of I&M receive a fee of $100 for each meeting of the Board of
Directors attended in addition to their salaries.
-----------------------------
The AEP System is an integrated electric utility system and, as a
result, the member companies of the AEP System have contractual, financial and
other business relationships with the other member companies, such as
participation in the AEP System savings and retirement plans and tax returns,
sales of electricity, transportation and handling of fuel, sales or rentals of
property and interest or dividend payments on the securities held by the
companies' respective parents.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
- --------------------------------------------------------------------------------
AEGCO. Omitted pursuant to Instruction I(2)(c).
AEP. The information required by this item is incorporated herein by
reference to the material under Share Ownership of Directors and Executive
Officers of the definitive proxy statement of AEP
54
<PAGE> 62
for the 2000 annual meeting of shareholders to be filed within 120 days after
December 31, 1999.
APCO. The information required by this item is incorporated herein by
reference to the material under Share Ownership of Directors and Executive
Officers in the definitive information statement of APCo for the 2000 annual
meeting of stockholders, to be filed within 120 days after December 31, 1999.
CSPCO. Omitted pursuant to Instruction I(2)(c).
I&M. All 1,400,000 outstanding shares of Common Stock, no par value, of
I&M are directly and beneficially held by AEP. Holders of the Cumulative
Preferred Stock of I&M generally have no voting rights, except with respect to
certain corporate actions and in the event of certain defaults in the payment of
dividends on such shares.
The table below shows the number of shares of AEP Common Stock and
stock-based units that were beneficially owned, directly or indirectly, as of
January 1, 2000, by each director and nominee of I&M and each of the executive
officers of I&M named in the summary compensation table, and by all directors
and executive officers of I&M as a group. It is based on information provided to
I&M by such persons. No such person owns any shares of any series of the
Cumulative Preferred Stock of I&M. Unless otherwise noted, each person has sole
voting power and investment power over the number of shares of AEP Common Stock
and stock-based units set forth opposite his name. Fractions of shares and units
have been rounded to the nearest whole number.
<TABLE>
<CAPTION>
STOCK
NAME SHARES(a) UNITS(b) TOTAL
- ---- --------- -------- -----
<S> <C> <C> <C>
Karl G. Boyd........................................................... 1,897 287 2,184
E. Linn Draper, Jr..................................................... 8,670(c) 89,257 97,927
Jeffrey A. Drozda...................................................... 149(c)(d) -- 149
Henry W. Fayne......................................................... 5,091 10,424 15,515
William J. Lhota....................................................... 17,364(c)(e) 15,174 32,538
Mark W. Marano......................................................... 159 133 292
James J. Markowsky..................................................... 2,871(d) 13,923 16,794
Armando A. Pena........................................................ 5,307 5,239 10,546
John R. Sampson........................................................ 230 315 545
David B. Synowiec...................................................... 171 395 566
Joseph H. Vipperman.................................................... 11,569(c)(e) 4,549 16,118
William E. Walters..................................................... 6,762 312 7,074
Earl H. Wittkamper..................................................... 3,561(c) 315 3,876
All Directors and Executive Officers................................... 149,032(e)(f) 140,323 289,355
</TABLE>
- -------------------------
(a) Includes share equivalents held in the AEP Employees Savings Plan in
the amounts listed below:
<TABLE>
<CAPTION>
AEP EMPLOYEES SAVINGS AEP EMPLOYEES SAVINGS
NAME PLAN (SHARE EQUIVALENTS) NAME PLAN (SHARE EQUIVALENTS)
---- ------------------------ ---- ------------------------
<S> <C> <S> <C>
Mr. Boyd............................. 1,897 Mr. Pena................................... 3,792
Dr. Draper........................... 3,449 Mr. Sampson................................ 230
Mr. Drozda........................... 127 Mr. Synowiec............................... 171
Mr. Fayne............................ 4,553 Mr. Vipperman.............................. 10,790
Mr. Lhota............................ 15,184 Mr. Walters................................ 6,762
Mr. Marano........................... 159 Mr. Wittkamper............................. 2,025
Dr. Markowsky........................ 3,888 All Directors and Executive Officers............ 53,027
</TABLE>
With respect to the share equivalents held in the AEP Employees Savings
Plan, such persons have sole voting power, but the investment/
disposition power is subject to the terms of the Plan.
(b) This column includes amounts deferred in stock units and held under
AEP's officer benefit plans.
(c) Includes the following numbers of shares held in joint tenancy with a
family member: Dr. Draper, 5,221; Mr. Drozda, 16; Mr. Lhota, 2,180; Mr.
Vipperman, 71; and Mr. Wittkamper, 1,536.
(d) Includes 6 and 21 shares held by family members of Mr. Drozda and Dr.
Markowsky, respectively, over which beneficial ownership is disclaimed.
(e) Does not include, for Messrs. Lhota and Vipperman, 85,231 shares in the
American Electric Power System Educational Trust Fund over which
Messrs. Lhota and Vipperman share voting and investment power as
trustees (they disclaim beneficial ownership). The amount of shares
shown for all directors and executive officers as a group includes
these shares.
(f) Represents less than 1% of the total number of shares outstanding
55
<PAGE> 63
KEPCO. Omitted pursuant to Instruction I(2)(c).
OPCO. The information required by this item is incorporated herein by
reference to the material under Share Ownership of Directors and Executive
Officers in the definitive information statement of OPCo for the 2000 annual
meeting of shareholders, to be filed within 120 days after December 31, 1999
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
- --------------------------------------------------------------------------------
AEP, APCO, I&M AND OPCO. None.
AEGCO, CSPCO, AND KEPCO. Omitted pursuant to Instruction I(2)(c).
PART IV ========================================================================
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
- --------------------------------------------------------------------------------
(a) The following documents are filed as a part of this report:
1. FINANCIAL STATEMENTS:
The following financial statements have been incorporated herein by
reference pursuant to Item 8.
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
AEGCo:
Independent Auditors' Report; Statements of Income for the years
ended December 31, 1999, 1998, and 1997; Statements of Retained
Earnings for the years ended December 31, 1999, 1998 and 1997;
Statements of Cash Flows for the years ended December 31, 1999, 1998
and 1997; Balance Sheets as of December 31, 1999 and 1998; Notes to
Financial Statements
AEP and its subsidiaries consolidated:
Consolidated Statements of Income for the years ended December 31,
1999, 1998 and 1997; Consolidated Statements of Comprehensive Income
for the years ended December 31, 1999, 1998 and 1997; Consolidated
Balance Sheets as of December 31, 1999 and 1998; Consolidated
Statements of Cash Flows for the years ended December 31, 1999, 1998
and 1997; Consolidated Statements of Common Shareholders' Equity for
the years ended December 31, 1999, 1998 and 1997; Notes to
Consolidated Financial Statements; Schedule of Consolidated
Cumulative Preferred Stocks of Subsidiaries at December 31, 1999 and
1998; Schedule of Consolidated Long-term Debt of Subsidiaries at
December 31, 1999 and 1998; Independent Auditors' Report.
APCo:
Independent Auditors' Report; Consolidated Statements of Income for
the years ended December 31, 1999, 1998 and 1997; Consolidated
Balance Sheets as of December 31, 1999 and 1998; Consolidated
Statements of Cash Flows for the years ended December 31, 1999, 1998
and 1997; Consolidated Statements of Retained Earnings for the years
ended December 31, 1999, 1998 and 1997; Notes to Consolidated
Financial Statements.
CSPCo:
Consolidated Statements of Income for the years ended December 31,
1999, 1998 and 1997; Consolidated Statements of Retained Earnings for
the years ended December 31, 1999, 1998 and 1997; Consolidated
Balance Sheets as of December 31, 1999 and 1998; Consolidated
Statements of Cash Flows for the years ended December 31, 1999, 1998
and 1997; Notes to Consolidated Financial Statements; Independent
Auditors' Report.
</TABLE>
56
<PAGE> 64
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
I&M:
Independent Auditors' Report; Consolidated Statements of Income for
the years ended December 31, 1999, 1998 and 1997; Consolidated
Balance Sheets as of December 31, 1999 and 1998; Consolidated
Statements of Cash Flows for the years ended December 31, 1999, 1998
and 1997; Consolidated Statements of Retained Earnings for the years
ended December 31, 1999, 1998 and 1997; Notes to Consolidated
Financial Statements.
KEPCo:
Independent Auditors' Report; Statements of Income for the years
ended December 31, 1999, 1998 and 1997; Statements of Retained
Earnings for the years ended December 31, 1999, 1998 and 1997;
Balance Sheets as of December 31, 1999 and 1998; Statements of Cash
Flows for the years ended December 31, 1999, 1998 and 1997; Notes to
Financial Statements.
OPCo:
Consolidated Statements of Income for the years ended December 31,
1999, 1998 and 1997; Consolidated Statements of Cash Flows for the
years ended December 31, 1999, 1998 and 1997; Consolidated Balance
Sheets as of December 31, 1999 and 1998; Consolidated Statements of
Retained Earnings for the years ended December 31, 1999, 1998 and
1997; Notes to Consolidated Financial Statements; Independent
Auditors' Report.
2. FINANCIAL STATEMENT SCHEDULES:
Financial Statement Schedules are listed in the Index to Financial
Statement Schedules (Certain schedules have been omitted because the
required information is contained in the notes to financial
statements or because such schedules are not required or are not
applicable.) S-1
Independent Auditors' Report S-2
3. EXHIBITS:
Exhibits for AEGCo, AEP, APCo, CSPCo, I&M, KEPCo and OPCo are listed
in the Exhibit Index and are incorporated herein by reference E-1
</TABLE>
(b) REPORTS ON FORM 8-K:
<TABLE>
<CAPTION>
Company Reporting Date of Report Item Reported
----------------- -------------- -------------
<S> <C> <C>
AEGCo, AEP, APCo, CSPCo, December 15, 1999 Item 5. Other Events
I&M, KEPCo and OPCo Item 7. Financial Statements and Exhibits
</TABLE>
57
<PAGE> 65
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE
UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE
TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.
AEP GENERATING COMPANY
BY: /S/ A. A. PENA
---------------------------------
(A. A. PENA, VICE PRESIDENT, TREASURER
AND CHIEF FINANCIAL OFFICER)
Date: March 20, 2000
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934,
THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF
EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
(I) PRINCIPAL EXECUTIVE OFFICER:
*E. LINN DRAPER, JR. President,
Chief Executive Officer
and Director
(II) PRINCIPAL FINANCIAL OFFICER:
/S/ A. A. PENA Vice President, Treasurer, March 20, 2000
- --------------------------------------------- Chief Financial Officer
(A. A. PENA) and Director
(III) PRINCIPAL ACCOUNTING OFFICER:
/S/ L. V. ASSANTE Controller and March 20, 2000
- --------------------------------------------- Chief Accounting Officer
(L. V. ASSANTE)
(IV) A MAJORITY OF THE DIRECTORS:
*HENRY W. FAYNE
*JOHN R. JONES, III
*WM. J. LHOTA
*By: /S/ A. A. PENA
-----------------------------------------
(A. A. PENA, ATTORNEY-IN-FACT) March 20, 2000
</TABLE>
58
<PAGE> 66
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
AMERICAN ELECTRIC POWER COMPANY, INC.
BY: /S/ H. W. FAYNE
----------------------------------
(H. W. FAYNE, VICE PRESIDENT
AND CHIEF FINANCIAL OFFICER)
Date: March 20, 2000
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934,
THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
(I) PRINCIPAL EXECUTIVE OFFICER:
*E. LINN DRAPER, JR. Chairman of the Board,
President,
Chief Executive Officer
and Director
(II) PRINCIPAL FINANCIAL OFFICER:
/S/ H. W. FAYNE Vice President and March 20, 2000
- ---------------------------------------------- Chief Financial Officer
(H. W. FAYNE)
(III) PRINCIPAL ACCOUNTING OFFICER:
/S/ L. V. ASSANTE Controller and March 20, 2000
- ---------------------------------------------- Chief Accounting Officer
(L. V. ASSANTE)
(IV) A MAJORITY OF THE DIRECTORS:
*JOHN P. DESBARRES
*ROBERT M. DUNCAN
*ROBERT W. FRI
*LESTER A. HUDSON, JR.
*LEONARD J. KUJAWA
*DONALD G. SMITH
*LINDA GILLESPIE STUNTZ
*KATHRYN D. SULLIVAN
*MORRIS TANENBAUM
*By: /S/ H. W. FAYNE
------------------------------------------
(H. W. FAYNE, ATTORNEY-IN-FACT) March 20, 2000
</TABLE>
59
<PAGE> 67
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE
UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE
TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.
APPALACHIAN POWER COMPANY
COLUMBUS SOUTHERN POWER COMPANY
KENTUCKY POWER COMPANY
OHIO POWER COMPANY
BY: /S/ A. A. PENA
--------------------------------------
(A. A. PENA, VICE PRESIDENT, TREASURER
AND CHIEF FINANCIAL OFFICER)
Date: March 20, 2000
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934,
THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF
EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
(I) PRINCIPAL EXECUTIVE OFFICER:
*E. LINN DRAPER, JR. Chairman of the Board,
Chief Executive Officer
and Director
(II) PRINCIPAL FINANCIAL OFFICER:
/S/ A. A. PENA Vice President, Treasurer, March 20, 2000
- --------------------------------------------- Chief Financial Officer
(A. A. PENA)
(III) PRINCIPAL ACCOUNTING OFFICER:
/S/ L. V. ASSANTE Controller and March 20, 2000
- --------------------------------------------- Chief Accounting Officer
(L. V. ASSANTE)
(IV) A MAJORITY OF THE DIRECTORS:
*HENRY W. FAYNE
*WM. J. LHOTA
*J. H. VIPPERMAN
*By: /S/ A. A. PENA
-----------------------------------------
(A. A. PENA, ATTORNEY-IN-FACT) March 20, 2000
</TABLE>
60
<PAGE> 68
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE
UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE
TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.
INDIANA MICHIGAN POWER COMPANY
BY: /S/ A. A. PENA
--------------------------------------
(A. A. PENA, VICE PRESIDENT, TREASURER
AND CHIEF FINANCIAL OFFICER)
Date: March 20, 2000
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934,
THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF
EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
(I) PRINCIPAL EXECUTIVE OFFICER:
*E. LINN DRAPER, JR. Chairman of the Board,
Chief Executive Officer
and Director
(II) PRINCIPAL FINANCIAL OFFICER:
/S/ A. A. PENA Vice President, Treasurer, March 20, 2000
- ------------------------------------------------ Chief Financial Officer
(A. A. PENA) and Director
(III) PRINCIPAL ACCOUNTING OFFICER:
/S/ L. V. ASSANTE Controller and March 20, 2000
- ------------------------------------------------ Chief Accounting Officer
(L. V. ASSANTE)
(IV) A MAJORITY OF THE DIRECTORS:
*K. G. BOYD
*JEFFREY A. DROZDA
*HENRY W. FAYNE
*WM. J. LHOTA
*MARK W. MARANO
*JOHN R. SAMPSON
*D. B. SYNOWIEC
*J. H. VIPPERMAN
*W. E. WALTERS
*E. H. WITTKAMPER
*By: /s/ A. A. PENA
---------------------------------------
(A. A. PENA, ATTORNEY-IN-FACT) March 20, 2000
</TABLE>
61
<PAGE> 69
INDEX TO FINANCIAL STATEMENT SCHEDULES
Page
INDEPENDENT AUDITORS' REPORT ........................................... S-2
The following financial statement schedules for the years ended
December 31, 1999, 1998 and 1997 are included in this report on
the pages indicated.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Schedule II-- Valuation and Qualifying Accounts and Reserves.... S-3
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Schedule II-- Valuation and Qualifying Accounts and Reserves.... S-3
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Schedule II-- Valuation and Qualifying Accounts and Reserves ... S-3
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Schedule II-- Valuation and Qualifying Accounts and Reserves.... S-4
KENTUCKY POWER COMPANY
Schedule II-- Valuation and Qualifying Accounts and Reserves ... S-4
OHIO POWER COMPANY AND SUBSIDIARIES
Schedule II-- Valuation and Qualifying Accounts and Reserves.... S-4
S-1
<PAGE> 70
INDEPENDENT AUDITORS' REPORT
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARIES:
We have audited the consolidated financial statements of American Electric
Power Company, Inc. and its subsidiaries and the financial statements of certain
of its subsidiaries, listed in Item 14 herein, as of December 31, 1999 and 1998,
and for each of the three years in the period ended December 31, 1999, and have
issued our reports thereon dated February 22, 2000 (March 3, 2000 as to Note 7
for American Electric Power Company, Inc. and its subsidiaries; Note 6 for
Appalachian Power Company and its subsidiaries, Columbus Southern Power Company
and its subsidiaries, Indiana Michigan Power Company and its subsidiaries,
Kentucky Power Company and Ohio Power Company and its subsidiaries; and Note 3
for AEP Generating Company); such financial statements and reports are included
in the respective 1999 Annual Report and are incorporated herein by reference.
Our audits also included the financial statement schedules of American Electric
Power Company, Inc. and its subsidiaries and of certain of its subsidiaries,
listed in Item 14. These financial statement schedules are the responsibility of
the respective Company's management. Our responsibility is to express an opinion
based on our audits. In our opinion, such financial statement schedules, when
considered in relation to the corresponding basic financial statements taken as
a whole, present fairly in all material respects the information set forth
therein.
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 22, 2000
S-2
<PAGE> 71
<TABLE>
<CAPTION>
===========================================================================================================================
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
===========================================================================================================================
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- ---------------------------------------------------------------------------------------------------------------------------
ADDITIONS
------------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
- ---------------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 1999....... $11,075 $18,816 $15,746(a) $33,185(b) $12,452
======= ======= ======= ======= =======
Year Ended December 31, 1998....... $ 6,760 $23,646 $ 8,290(a) $27,621(b) $11,075
======= ======= ======= ======= =======
Year Ended December 31, 1997....... $ 3,692 $20,650 $ 8,953(a) $26,535(b) $ 6,760
======= ======= ======= ======= =======
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
===========================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
===========================================================================================================================
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
===========================================================================================================================
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- ---------------------------------------------------------------------------------------------------------------------------
ADDITIONS
------------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
- ---------------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 1999....... $2,234 $5,492 $1,995(a) $7,112(b) $2,609
====== ====== ====== ====== ======
Year Ended December 31, 1998....... $1,333 $5,093 $1,306(a) $5,498(b) $2,234
====== ====== ====== ====== ======
Year Ended December 31, 1997....... $ 687 $3,621 $ 666(a) $3,641(b) $1,333
====== ====== ====== ====== ======
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
===========================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
==========================================================================================================================
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
==========================================================================================================================
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- ---------------------------------------------------------------------------------------------------------------------------
ADDITIONS
------------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
- ---------------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 1999....... $2,598 $3,334 $10,782(a) $13,669(b) $3,045
====== ====== ======= ======= ======
Year Ended December 31, 1998....... $1,058 $7,551 $ 5,278(a) $11,289(b) $2,598
====== ====== ======== ======= ======
Year Ended December 31, 1997....... $1,032 $6,815 $ 6,380(a) $13,169(b) $1,058
====== ====== ======== ======= ======
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
===========================================================================================================================
</TABLE>
S-3
<PAGE> 72
<TABLE>
<CAPTION>
===========================================================================================================================
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
===========================================================================================================================
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- ---------------------------------------------------------------------------------------------------------------------------
ADDITIONS
------------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
- ---------------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 1999......... $2,027 $3,966 $1,367(a) $5,512(b) $1,848
====== ====== ====== ====== ======
Year Ended December 31, 1998......... $1,188 $4,630 $ 221(a) $4,012(b) $2,027
====== ====== ====== ====== ======
Year Ended December 31, 1997......... $ 156 $4,411 $ 798(a) $4,177(b) $1,188
====== ====== ====== ====== ======
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
==========================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
=========================================================================================================================
KENTUCKY POWER COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- ---------------------------------------------------------------------------------------------------------------------------
ADDITIONS
------------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
- ---------------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 1999......... $848 $1,032 $467(a) $1,710(b) $637
==== ====== ==== ====== ====
Year Ended December 31, 1998......... $525 $1,280 $392(a) $1,349(b) $848
==== ====== ==== ====== ====
Year Ended December 31, 1997......... $272 $1,482 $347(a) $1,576(b) $525
==== ====== ==== ====== ====
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
==========================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
===========================================================================================================================
OHIO POWER COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
===========================================================================================================================
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- ---------------------------------------------------------------------------------------------------------------------------
ADDITIONS
------------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
- ---------------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 1999......... $1,678 $4,730 $1,273(a) $5,458(b) $2,223
====== ====== ====== ====== ======
Year Ended December 31, 1998......... $2,501 $3,255 $ 941(a) $5,019(b) $1,678
====== ====== ====== ====== ======
Year Ended December 31, 1997......... $1,433 $4,008 $ 675(a) $3,615(b) $2,501
====== ====== ====== ====== ======
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
==========================================================================================================================
</TABLE>
S-4
<PAGE> 73
EXHIBIT INDEX
Certain of the following exhibits, designated with an asterisk(*), are
filed herewith. The exhibits not so designated have heretofore been filed with
the Commission and, pursuant to 17 C.F.R. 229.10(d) and 240.12b-32, are
incorporated herein by reference to the documents indicated in brackets
following the descriptions of such exhibits. Exhibits, designated with a dagger
(++) are management contracts or compensatory plans or arrangements
required to be filed as an exhibit to this form pursuant to Item 14(c) of this
report.
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
<S> <C> <C>
AEGCo
3(a) -- Copy of Articles of Incorporation of AEGCo [Registration Statement on Form 10 for the Common
Shares of AEGCo, File No. 0-18135, Exhibit 3(a)].
3(b) -- Copy of the Code of Regulations of AEGCo [Registration Statement on Form 10 for the Common
Shares of AEGCo, File No. 0-18135, Exhibit 3(b)].
10(a) -- Copy of Capital Funds Agreement dated as of December 30, 1988 between AEGCo and AEP
[Registration Statement No. 33-32752, Exhibit 28(a)].
10(b)(1) -- Copy of Unit Power Agreement dated as of March 31, 1982 between AEGCo and I&M, as amended
[Registration Statement No. 33-32752, Exhibits 28(b)(1)(A) and 28(b)(1)(B)].
10(b)(2) -- Copy of Unit Power Agreement, dated as of August 1, 1984, among AEGCo, I&M and KEPCo
[Registration Statement No. 33-32752, Exhibit 28(b)(2)].
10(b)(3) -- Copy of Agreement, dated as of October 1, 1984, among AEGCo, I&M, APCo and Virginia Electric
and Power Company [Registration Statement No. 33-32752, Exhibit 28(b)(3)].
10(c) -- Copy of Lease Agreements, dated as of December 1, 1989, between AEGCo and Wilmington Trust
Company, as amended [Registration Statement No. 33-32752, Exhibits 28(c)(1)(C), 28(c)(2)(C),
28(c)(3)(C), 28(c)(4)(C), 28(c)(5)(C) and 28(c)(6)(C); Annual Report on Form 10-K of AEGCo
for the fiscal year ended December 31, 1993, File No. 0-18135, Exhibits 10(c)(1)(B),
10(c)(2)(B), 10(c)(3)(B), 10(c)(4)(B), 10(c)(5)(B) and 10(c)(6)(B)].
*13 -- Copy of those portions of the AEGCo 1999 Annual Report (for the fiscal year
ended December 31, 1999) which are incorporated by reference in this filing.
*24 -- Power of Attorney.
*27 -- Financial Data Schedules.
AEP++
3(a) -- Copy of Restated Certificate of Incorporation of AEP, dated October 29, 1997
[Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1997,
File No. 1-3525, Exhibit 3(a)].
3(b) -- Copy of Certificate of Amendment of the Restated Certificate of Incorporation of AEP,
dated January 13, 1999 [Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1998, File No. 1-3525, Exhibit 3(b)].
3(c) -- Composite copy of the Restated Certificate of Incorporation of AEP, as amended
[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998,
File No. 1-3525, Exhibit 3(c)].
3(d) -- Copy of By-Laws of AEP, as amended through January 28, 1998 [Annual Report on
Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525,
Exhibit 3(b)].
10(a) -- Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, OPCo and I&M and
with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a);
Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)].
</TABLE>
E-1
<PAGE> 74
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
AEP++ (CONTINUED)
<S> <C> <C>
10(b) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and
with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on
Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit
10(b)(2)].
10(c) -- Copy of Lease Agreements, dated as of December 1, 1989, between AEGCo or I&M and Wilmington
Trust Company, as amended [Registration Statement No. 33-32752, Exhibits 28(c)(1)(C),
28(c)(2)(C), 28(c)(3)(C), 28(c)(4)(C), 28(c)(5)(C) and 28(c)(6)(C); Registration Statement
No. 33-32753, Exhibits 28(a)(1)(C), 28(a)(2)(C), 28(a)(3)(C), 28(a)(4)(C), 28(a)(5)(C) and
28(a)(6)(C); and Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31,
1993, File No. 0-18135, Exhibits 10(c)(1)(B), 10(c)(2)(B), 10(c)(3)(B), 10(c)(4)(B),
10(c)(5)(B) and 10(c)(6)(B); Annual Report on Form 10-K of I&M for the fiscal year ended
December 31, 1993, File No. 1-3570, Exhibits 10(e)(1)(B), 10(e)(2)(B), 10(e)(3)(B),
10(e)(4)(B), 10(e)(5)(B) and 10(e)(6)(B)].
10(d) -- Lease Agreement dated January 20, 1995 between OPCo and JMG Funding, Limited Partnership, and
amendment thereto (confidential treatment requested) [Annual Report on Form 10-K of OPCo for
the fiscal year ended December 31, 1994, File No. 1-6543, Exhibit 10(l)(2)].
10(e) -- Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among
APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)].
10(f)(1) -- Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric
Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation
[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No.
1-3525, Exhibit 10(f)].
10(f)(2) -- Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current
Report on Form 8-K of AEP dated December 15, 1999, File No. 1-3525, Exhibit 10].
+10(g)(1) -- AEP Deferred Compensation Agreement for certain executive officers [Annual Report
on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No.
1-3525, Exhibit 10(e)].
+10(g)(2) -- Amendment to AEP Deferred Compensation Agreement for certain executive officers [Annual
Report on Form 10-K of AEP for the fiscal year ended December 31, 1986, File No. 1-3525,
Exhibit 10(d)(2)].
+10(h) -- AEP Accident Coverage Insurance Plan for directors [Annual Report on Form 10-K of
AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(g)].
+10(i)(1) -- AEP Deferred Compensation and Stock Plan for Non-Employee Directors [Annual
Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File
No. 1-3525, Exhibit 10(f)(1)].
+10(i)(2) -- AEP Stock Unit Accumulation Plan for Non-Employee Directors [Annual Report on
Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525,
Exhibit 10(f)(2)].
+10(j)(1)(A) -- AEP System Excess Benefit Plan, Amended and Restated as of August 1, 1999
[Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1999,
File No. 1-3525, Exhibit 10(a)].
+10(j)(1)(B) -- Guaranty by AEP of the Service Corporation Excess Benefits Plan [Annual Report on
Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525,
Exhibit 10(h)(1)(B)].
</TABLE>
E-2
<PAGE> 75
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
AEP++ (CONTINUED)
<S> <C> <C>
+10(j)(2) -- AEP System Supplemental Savings Plan, Amended and Restated as of November 1, 1999
(Non-Qualified) [Quarterly Report on Form 10-Q of AEP for the quarter ended September 30,
1999, File No. 1-3525, Exhibit 10(b)].
+10(j)(3) -- Service Corporation Umbrella Trust for Executives [Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)].
+10(k) -- Employment Agreement between E. Linn Draper, Jr. and AEP and the Service Corporation [Annual
Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1991, File No. 0-18135,
Exhibit 10(g)(3)].
+10(l)(1) -- AEP System Senior Officer Annual Incentive Compensation Plan [Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)].
+10(l)(2) -- American Electric Power System Performance Share Incentive Plan, as Amended and Restated through
February 26, 1997 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996,
File No. 1-3525, Exhibit 10(i)(2)].
+10(m) -- AEP System Survivor Benefit Plan, effective January 27, 1998 [Quarterly Report on Form 10-Q of
AEP for the quarter ended September 30, 1998, File No. 1-3525, Exhibit 10].
+10(n) -- Letter agreement between AEP and Donald M. Clements, Jr. dated August 19, 1994 [Annual Report
on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No. 1-3525, Exhibit 10(n)].
+10(o) -- AEP Senior Executive Severance Plan for Merger with Central and South West Corporation, effective
March 1, 1999 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998,
File No. 1-3525, Exhibit 10(o)].
+*10(p) -- AEP Change In Control Agreement.
*13 -- Copy of those portions of the AEP 1999 Annual Report (for the fiscal year ended December 31, 1999)
which are incorporated by reference in this filing.
*21 -- List of subsidiaries of AEP.
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*27 -- Financial Data Schedules.
APCo++
3(a) -- Copy of Restated Articles of Incorporation of APCo, and amendments thereto to November 4,
1993 [Registration Statement No. 33-50163, Exhibit 4(a); Registration Statement No. 33-53805,
Exhibits 4(b) and 4(c)].
3(b) -- Copy of Articles of Amendment to the Restated Articles of Incorporation of APCo, dated June 6, 1994
[Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1994, File No. 1-3457,
Exhibit 3(b)].
3(c) -- Copy of Articles of Amendment to the Restated Articles of Incorporation of APCo, dated March 6,
1997 [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1996, File No. 1-3457,
Exhibit 3(c)].
3(d) -- Composite copy of the Restated Articles of Incorporation of APCo (amended as of March 7, 1997)
[Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1996, File No. 1-3457,
Exhibit 3(d)].
*3(e) -- Copy of By-Laws of APCo (amended as of June 1, 1998).
</TABLE>
E-3
<PAGE> 76
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
APCo++ (CONTINUED)
<S> <C> <C>
4(a) -- Copy of Mortgage and Deed of Trust, dated as of December 1, 1940, between APCo and Bankers
Trust Company and R. Gregory Page, as Trustees, as amended and supplemented [Registration
Statement No. 2-7289, Exhibit 7(b); Registration Statement No. 2-19884, Exhibit 2(1);
Registration Statement No. 2-24453, Exhibit 2(n); Registration Statement No. 2-60015,
Exhibits 2(b)(2), 2(b)(3), 2(b)(4), 2(b)(5), 2(b)(6), 2(b)(7), 2(b)(8), 2(b)(9), 2(b)(10),
2(b)(12), 2(b)(14), 2(b)(15), 2(b)(16), 2(b)(17), 2(b)(18), 2(b)(19), 2(b)(20), 2(b)(21), 2(b)(22),
2(b)(23), 2(b)(24), 2(b)(25), 2(b)(26), 2(b)(27) and 2(b)(28); Registration Statement No. 2-64102,
Exhibit 2(b)(29); Registration Statement No. 2-66457, Exhibits (2)(b)(30) and 2(b)(31); Registration
Statement No. 2-69217, Exhibit 2(b)(32); Registration Statement No. 2-86237, Exhibit 4(b);
Registration Statement No. 33-11723, Exhibit 4(b); Registration Statement No. 33-17003,
Exhibit 4(a)(ii), Registration Statement No. 33-30964, Exhibit 4(b); Registration Statement
No. 33-40720, Exhibit 4(b); Registration Statement No. 33-45219, Exhibit 4(b); Registration Statement
No. 33-46128, Exhibits 4(b) and 4(c); Registration Statement No. 33-53410, Exhibit 4(b); Registration
Statement No. 33-59834, Exhibit 4(b); Registration Statement No. 33-50229, Exhibits 4(b) and 4(c);
Registration Statement No. 33-58431, Exhibits 4(b), 4(c), 4(d) and 4(e); Registration Statement
No. 333-01049, Exhibits 4(b) and 4(c); Registration Statement No. 333-20305, Exhibits 4(b) and 4(c);
Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1996, File No. 1-3457,
Exhibit 4(b); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1998,
Exhibit 4(b)].
4(b) -- Indenture (for unsecured debt securities), dated as of January 1, 1998, between APCo and The Bank
of New York, As Trustee [Registration Statement No. 333-45927, Exhibits 4(a) and 4(b);
Registration Statement No. 333-49071, Exhibit 4(b); Registration Statement No. 333-84061,
Exhibits 4(b) and 4(c)].
*4(c) -- Company Order and Officers' Certificate, dated October 19, 1999, establishing certain terms of the
7.45% Senior Notes, Series D, due 2004.
10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America,
acting by and through the United States Atomic Energy Commission, and, subsequent to January
18, 1975, the Administrator of the Energy Research and Development Administration, as amended
[Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234,
Exhibit 5(a)(1)(B); Registration Statement No 2-66301, Exhibit 5(a)(1)(C); Registration
Statement No. 2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal
year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form
10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit
10(a)(1)(B)].
10(a)(2) -- Copy of Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the
Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c);
Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); and Annual Report on Form 10-K of
APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)].
10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric
Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)].
10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, OPCo and I&M
and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit
5(a); Registration Statement No. 2-61009, Exhibit 5(b); Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)].
</TABLE>
E-4
<PAGE> 77
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
APCo++ (CONTINUED)
<S> <C> <C>
10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and
with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); Annual Report on Form
10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)].
10(d) -- Copy of Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28,
1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form
10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)].
10(e)(1) -- Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric
Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation
[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No.
1-3525, Exhibit 10(f)].
10(e)(2) -- Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current
Report on Form 8-K of APCo dated December 15, 1999, File No. 1-3457, Exhibit 10].
+10(f)(1) -- AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(e)].
+10(f)(2) -- Amendment to AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form
10-K of AEP for the fiscal year ended December 31,1986, File No. 1-3525, Exhibit 10(d)(2)].
+10(g)(1) -- AEP System Senior Officer Annual Incentive Compensation Plan [Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)].
+10(g)(2) -- American Electric Power System Performance Share Incentive Plan as Amended and Restated through
February 26, 1997 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996,
File No. 1-3525, Exhibit 10(i)(2)].
+10(h)(1) -- AEP System Excess Benefit Plan, Amended and Restated as of August 1, 1999 [Quarterly Report on
Form 10-Q of AEP for the quarter ended September 30, 1999, File No. 1-3525, Exhibit 10(a)].
+10(h)(2) -- AEP System Supplemental Savings Plan, Amended and Restated as of November 1, 1999 (Non-Qualified)
[Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1999, File No. 1-3525,
Exhibit 10(b)].
+10(h)(3) -- Umbrella Trust for Executives [Annual Report on Form 10-K of AEP for the fiscal year ended December
31, 1993, File No. 1-3525, Exhibit 10(g)(3)].
+10(i) -- Employment Agreement between E. Linn Draper, Jr. and AEP and the Service Corporation [Annual
Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1991, File No. 0-18135,
Exhibit 10(g)(3)].
+10(j) -- AEP System Survivor Benefit Plan, effective January 27, 1998 [Quarterly Report on Form 10-Q of
AEP for the quarter ended September 30, 1998, File No. 1-3525, Exhibit 10].
+10(k) -- AEP Senior Executive Severance Plan for Merger with Central and South West Corporation, effective
March 1, 1999[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No.
1-3525, Exhibit 10(o)].
+10(l) -- AEP Change In Control Agreement [Annual Report on Form 10-K of AEP for the fiscal year ended December
31, 1999, File No. 1-3525, Exhibit 10(p)].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the APCo 1999 Annual Report (for the fiscal year ended December 31, 1999)
which are incorporated by reference in this filing.
</TABLE>
E-5
<PAGE> 78
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
APCo++ (CONTINUED)
<S> <C> <C>
21 -- List of subsidiaries of APCo [Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1999, File No. 1-3525, Exhibit 21].
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*27 -- Financial Data Schedules.
CSPCo++
3(a) -- Copy of Amended Articles of Incorporation of CSPCo, as amended to March 6, 1992 [Registration
Statement No. 33-53377, Exhibit 4(a)].
3(b) -- Copy of Certificate of Amendment to Amended Articles of Incorporation of CSPCo, dated May 19, 1994
[Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1994, File No. 1-2680,
Exhibit 3(b)].
3(c) -- Composite copy of Amended Articles of Incorporation of CSPCo, as amended [Annual Report on
Form 10-K of CSPCo for the fiscal year ended December 31, 1994, File No. 1-2680, Exhibit 3(c)].
3(d) -- Copy of Code of Regulations and By-Laws of CSPCo [Annual Report on Form 10-K of CSPCo for the fiscal
year ended December 31, 1987, File No. 1-2680, Exhibit 3(d)].
4(a) -- Copy of Indenture of Mortgage and Deed of Trust, dated September 1, 1940, between CSPCo and
City Bank Farmers Trust Company (now Citibank, N.A.), as trustee, as supplemented and amended
[Registration Statement No. 2-59411, Exhibits 2(B) and 2(C); Registration Statement No.
2-80535, Exhibit 4(b); Registration Statement No. 2-87091, Exhibit 4(b); Registration
Statement No. 2-93208, Exhibit 4(b); Registration Statement No. 2-97652, Exhibit 4(b);
Registration Statement No. 33-7081, Exhibit 4(b); Registration Statement No. 33-12389,
Exhibit 4(b); Registration Statement No. 33-19227, Exhibits 4(b), 4(e), 4(f), 4(g) and 4(h);
Registration Statement No. 33-35651, Exhibit 4(b); Registration Statement No. 33-46859,
Exhibits 4(b) and 4(c); Registration Statement No. 33-50316, Exhibits 4(b) and 4(c);
Registration Statement No. 33-60336, Exhibits 4(b), 4(c) and 4(d); Registration Statement No.
33-50447, Exhibits 4(b) and 4(c); Annual Report on Form 10-K of CSPCo for the fiscal year
ended December 31, 1993, File No. 1-2680, Exhibit 4(b)].
4(b) -- Copy of Indenture (for unsecured debt securities), dated as of September 1, 1997, between CSPCo and
Bankers Trust Company, as Trustee [Registration Statement No. 333-54025, Exhibits 4(a), 4(b), 4(c)
and 4(d); Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1998, File
No. 1-2680, Exhibits 4(c) and 4(d)].
10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America,
acting by and through the United States Atomic Energy Commission, and, subsequent to January
18, 1975, the Administrator of the Energy Research and Development Administration, as amended
[Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234,
Exhibit 5(a)(1)(B); Registration Statement No. 2-66301, Exhibit 5(a)(1)(C); Registration
Statement No. 2-67728, Exhibit 5(a)(1)(B); Annual Report on Form 10-K of APCo for the fiscal
year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form
10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit
10(a)(1)(B)].
10(a)(2) -- Copy of Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring
Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration
Statement No. 2-67728, Exhibit 5(a)(3)(B); and Annual Report on Form 10-K of APCo for the
fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)].
</TABLE>
E-6
<PAGE> 79
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
CSPCo++ (CONTINUED)
<S> <C> <C>
10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation,
as amended [Registration Statement No. 2-60015, Exhibit 5(e)].
10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, OPCo and I&M
and the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a);
Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)].
10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo, and
with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on
Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit
10(b)(2)].
10(d) -- Copy of Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28,
1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form
10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)].
10(e)(1) -- Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric
Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation
[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No.
1-3525, Exhibit 10(f)].
10(e)(2) -- Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current
Report on Form 8-K of CSPCo dated December 15, 1999, File No. 1-2680, Exhibit 10].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the CSPCo 1999 Annual Report (for the fiscal year ended December 31, 1999)
which are incorporated by reference in this filing.
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*27 -- Financial Data Schedules.
I&M++
3(a) -- Copy of the Amended Articles of Acceptance of I&M and amendments thereto [Annual Report on Form 10-K of
I&M for fiscal year ended December 31, 1993, File No.1-3570, Exhibit 3(a)].
3(b) -- Copy of Articles of Amendment to the Amended Articles of Acceptance of I&M, dated March 6, 1997
[Annual Report on Form 10-K of I&M for fiscal year ended December 31, 1996, File No. 1-3570, Exhibit
3(b)].
3(c) -- Composite Copy of the Amended Articles of Acceptance of I&M (amended as of March 7, 1997)
[Annual Report on Form 10-K of I&M for fiscal year ended December 31, 1996, File No. 1-3570, Exhibit
3(c)].
3(d) -- Copy of the By-Laws of I&M (amended as of January 1, 1996) [Annual Report on Form 10-K of I&M for
fiscal year ended December 31, 1995, File No. 1-3570, Exhibit 3(c)].
</TABLE>
E-7
<PAGE> 80
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
I&M++ (CONTINUED)
<S> <C> <C>
4(a) -- Copy of Mortgage and Deed of Trust, dated as of June 1, 1939, between I&M and Irving Trust
Company (now The Bank of New York) and various individuals, as Trustees, as amended and
supplemented [Registration Statement No. 2-7597, Exhibit 7(a); Registration Statement No.
2-60665, Exhibits 2(c)(2), 2(c)(3), 2(c)(4), 2(c)(5), 2(c)(6), 2(c)(7), 2(c)(8), 2(c)(9),
2(c)(10), 2(c)(11), 2(c)(12), 2(c)(13), 2(c)(14), 2(c)(15), (2)(c)(16), and 2(c)(17);
Registration Statement No. 2-63234, Exhibit 2(b)(18); Registration Statement No. 2-65389,
Exhibit 2(a)(19); Registration Statement No. 2-67728, Exhibit 2(b)(20); Registration
Statement No. 2-85016, Exhibit 4(b); Registration Statement No. 33-5728, Exhibit 4(c);
Registration Statement No. 33-9280, Exhibit 4(b); Registration Statement No. 33-11230,
Exhibit 4(b); Registration Statement No. 33-19620, Exhibits 4(a)(ii), 4(a)(iii), 4(a)(iv) and
4(a)(v); Registration Statement No. 33-46851, Exhibits 4(b)(i), 4(b)(ii) and 4(b)(iii);
Registration Statement No. 33-54480, Exhibits 4(b)(I) and 4(b)(ii); Registration Statement
No. 33-60886, Exhibit 4(b)(i); Registration Statement No. 33-50521, Exhibits 4(b)(I),
4(b)(ii) and 4(b)(iii); Annual Report on Form 10-K of I&M for fiscal year ended December 31,
1993, File No. 1-3570, Exhibit 4(b); Annual Report on Form 10-K of I&M for fiscal year ended
December 31, 1994, File No. 1-3570, Exhibit 4(b); Annual Report on Form 10-K of I&M for
fiscal year ended December 31, 1996, File No. 1-3570, Exhibit 4(b)].
4(b) -- Copy of Indenture (for unsecured debt securities), dated as of October 1, 1998, between I&M and
The Bank of New York, as Trustee [Registration Statement No. 333-88523, Exhibits 4(a), 4(b) and 4(c)].
*4(c) -- Copy of Company Order and Officers' Certificate, dated November 23, 1999, establishing
certain terms of the Floating Rate Notes, Series A, due 2000.
10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America,
acting by and through the United States Atomic Energy Commission, and, subsequent to January
18, 1975, the Administrator of the Energy Research and Development Administration, as amended
[Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234,
Exhibit 5(a)(1)(B); Registration Statement No. 2-66301, Exhibit 5(a)(1)(C); Registration
Statement No. 2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal
year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form
10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit
10(a)(1)(B)].
10(a)(2) -- Copy of Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the
Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c);
Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); Annual Report on Form 10-K of APCo
for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)].
10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric
Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)].
10(a)(4) -- Copy of Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the
Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c);
Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); Annual Report on Form 10-K of APCo
for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)].
10(a)(5) -- Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric
Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)].
</TABLE>
E-8
<PAGE> 81
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
<S> <C> <C>
I&M++ (CONTINUED)
10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, I&M, and
OPCo and with the Service Corporation, as amended [Registration Statement No. 2-52910,
Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form
10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)].
10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and
with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on
Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit
10(b)(2)].
10(d) -- Copy of Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28,
1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form
10-K of AEP for the fiscal year ended December 1, 1996, File No. 1-3525, Exhibit 10(l)].
10(e) -- Copy of Nuclear Material Lease Agreement, dated as of December 1, 1990, between I&M and DCC
Fuel Corporation [Annual Report on Form 10-K of I&M for the fiscal year ended December 31,
1993, File No. 1-3570, Exhibit 10(d)].
10(f) -- Copy of Lease Agreements, dated as of December 1, 1989, between I&M and Wilmington Trust
Company, as amended [Registration Statement No. 33-32753, Exhibits 28(a)(1)(C), 28(a)(2)(C),
28(a)(3)(C), 28(a)(4)(C), 28(a)(5)(C) and 28(a)(6)(C); Annual Report on Form 10-K of I&M for
the fiscal year ended December 31, 1993, File No. 1-3570, Exhibits 10(e)(1)(B), 10(e)(2)(B),
10(e)(3)(B), 10(e)(4)(B), 10(e)(5)(B) and 10(e)(6)(B)].
10(g)(1) -- Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric
Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation
[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No.
1-3525, Exhibit 10(f)].
10(g)(2) -- Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current
Report on Form 8-K of I&M dated December 15, 1999, File No. 1-3570, Exhibit 10].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the I&M 1999 Annual Report (for the fiscal year ended December 31, 1999)
which are incorporated by reference in this filing.
21 -- List of subsidiaries of I&M [Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1999, File No. 1-3525, Exhibit 21].
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*27 -- Financial Data Schedules.
KEPCo++
3(a) -- Copy of Restated Articles of Incorporation of KEPCo [Annual Report on Form 10-K of KEPCo for the
fiscal year ended December 31, 1991, File No. 1-6858, Exhibit 3(a)].
3(b) -- Copy of By-Laws of KEPCo (amended as of January 1, 1996) [Annual Report on Form 10-K of KEPCo for the
fiscal year ended December 31, 1995, File No. 1-6858,Exhibit 3(b)].
4(a) -- Copy of Mortgage and Deed of Trust, dated May 1, 1949, between KEPCo and Bankers Trust
Company, as supplemented and amended [Registration Statement No. 2-65820, Exhibits 2(b)(1),
2(b)(2), 2(b)(3), 2(b)(4), 2(b)(5), and 2(b)(6); Registration Statement No. 33-39394,
Exhibits 4(b) and 4(c); Registration Statement No. 33-53226, Exhibits 4(b) and 4(c);
Registration Statement No. 33-61808, Exhibits 4(b) and 4(c), Registration Statement No.
33-53007, Exhibits 4(b), 4(c) and 4(d)].
</TABLE>
E-9
<PAGE> 82
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
<S> <C> <C>
KEPCo++ (CONTINUED)
4(b) -- Copy of Indenture (for unsecured debt securities), dated as of September 1, 1997, between KEPCo and
Bankers Trust Company, as Trustee [Registration Statement No. 333-75785, Exhibits 4(a), 4(b), 4(c)
and 4(d)].
*4(c) -- Copy of Company Order and Officers' Certificate, dated November 2, 1999, establishing certain terms of
the Floating Rate Notes, Series A, due 2000.
10(a) -- Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, I&M and OPCo
and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit
5(a);Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)].
10(b) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and
with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on
Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit
10(b)(2)].
10(c) -- Copy of Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28,
1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form
10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)].
10(d)(1) -- Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric
Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation
[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No.
1-3525, Exhibit 10(f)].
10(d)(2) -- Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current
Report on Form 8-K of KEPCo dated December 15, 1999, File No. 1-6858, Exhibit 10].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the KEPCo 1999 Annual Report (for the fiscal year ended December 31, 1999)
which are incorporated by reference in this filing.
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*27 -- Financial Data Schedules.
OPCo++
3(a) -- Copy of Amended Articles of Incorporation of OPCo, and amendments thereto to December 31, 1993
[Registration Statement No. 33-50139, Exhibit 4(a); Annual Report on Form 10-K of OPCo for the fiscal
year ended December 31, 1993, File No. 1-6543, Exhibit 3(b)].
3(b) -- Certificate of Amendment to Amended Articles of Incorporation of OPCo, dated May 3, 1994
[Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1994, File No.
1-6543, Exhibit 3(b)].
3(c) -- Copy of Certificate of Amendment to Amended Articles of Incorporation of OPCo, dated March 6,
1997 [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1996, File
No. 1-6543, Exhibit 3(c)].
3(d) -- Composite copy of the Amended Articles of Incorporation of OPCo (amended as of March 7, 1997)
[Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1996, File No. 1-6543,
Exhibit 3(d)].
3(e) -- Copy of Code of Regulations of OPCo [Annual Report on Form 10-K of OPCo for the fiscal year ended
December 31, 1990, File No. 1-6543, Exhibit 3(d)].
</TABLE>
E-10
<PAGE> 83
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
<S> <C> <C>
OPCo++ (CONTINUED)
4(a) -- Copy of Mortgage and Deed of Trust, dated as of October 1, 1938, between OPCo and
Manufacturers Hanover Trust Company (now Chemical Bank), as Trustee, as amended and
supplemented [Registration Statement No. 2-3828, Exhibit B-4; Registration Statement No.
2-60721, Exhibits 2(c)(2), 2(c)(3), 2(c)(4), 2(c)(5), 2(c)(6), 2(c)(7), 2(c)(8), 2(c)(9),
2(c)(10), 2(c)(11), 2(c)(12), 2(c)(13), 2(c)(14), 2(c)(15), 2(c)(16), 2(c)(17), 2(c)(18),
2(c)(19), 2(c)(20), 2(c)(21), 2(c)(22), 2(c)(23), 2(c)(24), 2(c)(25), 2(c)(26), 2(c)(27),
2(c)(28), 2(c)(29), 2(c)(30), and 2(c)(31); Registration Statement No. 2-83591, Exhibit 4(b);
Registration Statement No. 33-21208, Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(iv); Registration
Statement No. 33-31069, Exhibit 4(a)(ii); Registration Statement No. 33-44995, Exhibit
4(a)(ii); Registration Statement No. 33-59006, Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(iv);
Registration Statement No. 33-50373, Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(iv); Annual Report
on Form 10-K of OPCo for the fiscal year ended December 31, 1993, File No. 1-6543, Exhibit 4(b)].
4(b) -- Copy of Indenture (for unsecured debt securities), dated as of September 1, 1997, between OPCo and
Bankers Trust Company, as Trustee [Registration Statement No. 333-49595, Exhibits 4(a), 4(b) and
4(c); Annual Report on Form 10-K for the fiscal year ended December 31, 1998, Exhibits 4(c) and 4(d)].
*4(c) -- Copy of Company Order and Officers' Certificate, dated June 9, 1999, establishing certain terms of the
6.75% Senior Notes, Series B, due 2004.
*4(d) -- Copy of Company Order and Officers' Certificate, dated September 1, 1999, establishing certain terms
of the 7% Senior Notes, Series C, due 2004.
10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America,
acting by and through the United States Atomic Energy Commission, and, subsequent to January
18, 1975, the Administrator of the Energy Research and Development Administration, as amended
[Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234,
Exhibit 5(a)(1)(B); Registration Statement No. 2-66301, Exhibit 5(a)(1)(C); Registration
Statement No. 2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal
year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); Annual Report on Form
10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)].
10(a)(2) -- Copy of Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring
Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration
Statement No. 2-67728, Exhibit 5(a)(3)(B); Annual Report on Form 10-K of APCo for the fiscal
year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)].
10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation,
as amended [Registration Statement No. 2-60015, Exhibit 5(e)].
10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, I&M and OPCo
and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit
5(a); Registration Statement No. 2-61009, Exhibit 5(b); Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1990, File 1-3525, Exhibit 10(a)(3)].
10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and
with the Service Corporation as agent [Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1985, File No. 1-3525, Exhibit 10(b); Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)].
</TABLE>
E-11
<PAGE> 84
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
<S> <C> <C>
OPCo++ (CONTINUED)
10(d) -- Copy of Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28,
1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form
10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)].
10(e) -- Copy of Amendment No. 1, dated October 1, 1973, to Station Agreement dated January 1, 1968,
among OPCo, Buckeye and Cardinal Operating Company, and amendments thereto [Annual Report on
Form 10-K of OPCo for the fiscal year ended December 31, 1993, File No. 1-6543, Exhibit
10(f)].
10(f) -- Lease Agreement dated January 20, 1995 between OPCo and JMG Funding, Limited Partnership, and
amendment thereto (confidential treatment requested) [Annual Report on Form 10-K of OPCo for
the fiscal year ended December 31, 1994, File No. 1-6543, Exhibit 10(l)(2)].
10(g)(1) -- Agreement and Plan of Merger, dated as of December 21, 1997, by and among American Electric
Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation
[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No.
1-3525, Exhibit 10(f)].
10(g)(2) -- Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current
Report on Form 8-K of OPCo dated December 15, 1999, File No. 1-6543, Exhibit 10].
+10(h)(1) -- AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of
OPCo for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(e)].
+10(h)(2) -- Amendment to AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form
10-K of AEP for the fiscal year ended December 31, 1986, File No. 1-3525, Exhibit 10(d)(2)].
+10(i)(1) -- AEP System Senior Officer Annual Incentive Compensation Plan [Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)].
+10(i)(2) -- American Electric Power System Performance Share Incentive Plan, as Amended and Restated through
February 26, 1997 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File
No. 1-3525, Exhibit 10(i)(2)].
+10(j)(1) -- AEP System Excess Benefit Plan, Amended and Restated as of August 1, 1999 [Quarterly Report on
Form 10-Q of AEP for the quarter ended September 30, 1999, File No. 1-3525, Exhibit 10(a)].
+10(j)(2) -- AEP System Supplemental Savings Plan, Amended and Restated as of November 1, 1999 (Non-Qualified)
[Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1999, File No. 1-3525, Exhibit
10(b)].
+10(j)(3) -- Umbrella Trust for Executives [Annual Report on Form 10-K of AEP for the fiscal year ended December
31, 1993, File No. 1-3525, Exhibit 10(g)(3)].
+10(k) -- Employment Agreement between E. Linn Draper, Jr. and AEP and the Service Corporation [Annual
Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1991, File No. 0-18135,
Exhibit 10(g)(3)].
+10(l) -- AEP System Survivor Benefit Plan, effective January 27, 1998 [Quarterly Report on Form 10-Q of
AEP for the quarter ended September 30, 1998, File No. 1-3525, Exhibit 10].
+10(m) -- AEP Senior Executive Severance Plan for Merger with Central and South West Corporation, effective
March 1, 1999[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No.
1-3525, Exhibit 10(o)].
+10(n) -- AEP Change In Control Agreement [Annual Report on Form 10-K of AEP for the fiscal year ended December
31, 1999, File No. 1-3525, Exhibit 10(p)].
*12 -- Statement re: Computation of Ratios.
</TABLE>
E-12
<PAGE> 85
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
<S> <C> <C>
OPCo++ (CONTINUED)
*13 -- Copy of those portions of the OPCo 1999 Annual
Report (for the fiscal year ended December 31, 1999)
which are incorporated by reference in this filing.
21 -- List of subsidiaries of OPCo [Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1999, File No. 1-3525, Exhibit 21].
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*27 -- Financial Data Schedules.
</TABLE>
================================
++Certain instruments defining the rights of holders of long-term debt of
the registrants included in the financial statements of registrants filed
herewith have been omitted because the total amount of securities authorized
thereunder does not exceed 10% of the total assets of registrants. The
registrants hereby agree to furnish a copy of any such omitted instrument to the
SEC upon request.
E-13
<PAGE>
EXHIBIT 4(c)
November 23, 1999
Company Order and Officers' Certificate
Floating Rate Notes, Series A, due 2000
The Bank of New York
Attn: Corporate Trust Division
101 Barclay Street, 21 West
New York, New York 10286
Ladies and Gentlemen:
Pursuant to Article Two of the Indenture, dated as of October 1, 1998 (as it
may be amended or supplemented, the "Indenture"), from Indiana Michigan Power
Company (the "Company") to The Bank of New York, as trustee (the "Trustee"),
and the Board Resolutions dated August 25, 1999, a copy of which certified by
the Secretary or an Assistant Secretary of the Company is being delivered
herewith under Section 2.01 of the Indenture, and unless otherwise provided
in a subsequent Company Order pursuant to Section 2.04 of the Indenture,
1. The Company's Floating Rate Notes, Series A, due 2000 (the
"Notes") are hereby established. The Notes shall be in substantially
the form attached hereto as Exhibit 1.
2. The terms and characteristics of the Notes shall be as
follows (the numbered clauses set forth below correspond to the
numbered subsections of Section 2.01 of the Indenture, with terms used
and not defined herein having the meanings specified in the Indenture
or in the Notes):
(i) the aggregate principal amount of Notes which may be
authenticated and delivered under the Indenture shall be limited
to $100,000,000, except as contemplated in Section 2.01(i) of the
Indenture;
(ii) the date on which the principal of the Notes shall be
payable shall be November 22, 2000;
(iii) interest on the Notes shall be payable monthly on the
twenty-second day of each month in each year (each, an "Interest
Payment Date"), commencing on December 22, 1999 and shall accrue
from and including the date of authentication of the Notes to,
but excluding December 22, 1999, and thereafter, from and
including each Interest Payment Date to, but excluding, the next
succeeding Interest Payment Date or Stated Maturity, as the case
may be; the Regular Record Date for the determination of holders
to whom interest is payable on any such Interest Payment Date
shall be the fifteenth calendar day preceding the relevant
Interest Payment Date; provided that interest payable on Stated
Maturity shall be paid to the Person to whom principal shall be
paid;
(iv) the Notes will bear interest at a per annum rate ("Interest
Rate") determined by the Calculation Agent, subject to the
maximum interest rate permitted by New York or other applicable
state law, as such law may be modified by United States law of
general application. The Interest Rate for each Interest Period
will be equal to LIBOR on the Interest Determination Date for
such Interest Period plus .65%; provided, however, that in
certain circumstances described below, the Interest Rate will be
determined without reference to LIBOR.
If the following circumstances exist on any Interest
Determination Date, the Calculation Agent shall determine the
Interest Rate for the Notes as follows:
(1) In the event no Reported Rate appears on Telerate Page
3750 as of approximately 11:00 a.m. London time on an
Interest Determination Date, the Calculation Agent shall
request the principal London offices of each of four major
banks in the London interbank market selected by the
Calculation Agent (after consultation with the Company) to
provide a quotation of the rate (the "Rate Quotation") at
which one month deposits in amounts of not less than
$1,000,000 are offered by it to prime banks in the London
interbank market, as of approximately 11:00 a.m. on such
Interest Determination Date, that is representative of single
transactions at such time (the "Representative Amounts"). If
at least two Rate Quotations are provided, the interest rate
will be the arithmetic mean of the Rate Quotations obtained
by the Calculation Agent, plus .65%.
(2) In the event no Reported Rate appears on Telerate
Page 3750 as of approximately 11:00 a.m. London time on an
Interest Determination Date and there are fewer than two Rate
Quotations, the interest rate will be the arithmetic mean of
the rates quoted at approximately 11:00 a.m. New York City
time on such Interest Determination Date, by three major
banks in New York City selected by the Calculation Agent
(after consultation with the Company), for loans in
Representative Amounts in U. S. dollars to leading European
banks, having an index maturity of one month for a period
commencing on the second London Business Day immediately
following such Interest Determination Date, plus .65%;
provided, however, that if fewer than three banks selected by
the Calculation Agent are quoting such rates, the interest
rate for the applicable Interest Period will be the same as
the interest rate in effect for the immediately preceding
Interest Period.
(v) the Notes shall not be redeemable prior to maturity;
(vi)(a) the Notes shall be issued in the form of a Global Note;
(b) the Depositary for such Global Note shall be The Depository
Trust Company; and (c) the procedures with respect to transfer
and exchange of Global Notes shall be as set forth in the form of
Note attached hereto;
(vii) the title of the Notes shall be "Floating Rate Notes,
Series A, due 2000";
(viii) the form of the Notes shall be as set forth in
Paragraph 1, above;
(ix) see item (iv) above;
(x) the Notes shall not be subject to a Periodic Offering;
(xi) not applicable;
(xii) not applicable;
(xiii) not applicable;
(xiv) the Notes shall be issuable in denominations of $1,000 and
any integral multiple thereof;
(xv) not applicable;
(xvi) the Notes shall not be issued as Discount Securities;
(xvii) not applicable;
(xviii) see item (iv) above; and
(xix) not applicable.
3. You are hereby requested to authenticate $100,000,000
aggregate principal amount of Floating Rate Notes, Series A, due 2000,
executed by the Company and delivered to you concurrently with this
Company Order and Officers' Certificate, in the manner provided by the
Indenture.
4. You are hereby requested to hold the Notes as custodian for
DTC in accordance with the Letter of Representations dated November 17,
1999, from the Company and the Trustee to DTC.
5. Concurrently with this Company Order and Officers'
Certificate, an Opinion of Counsel under Sections 2.04 and 13.06 of the
Indenture is being delivered to you.
6. The undersigned Henry W. Fayne and Thomas G. Berkemeyer,
the Vice President and Assistant Secretary, respectively, of the
Company do hereby certify that:
(i) we have read the relevant portions of the Indenture,
including without limitation the conditions precedent provided
for therein relating to the action proposed to be taken by the
Trustee as requested in this Company Order and Officers'
Certificate, and the definitions in the Indenture relating
thereto;
(ii) we have read the Board Resolutions of the Company and the
Opinion of Counsel referred to above;
(iii) we have conferred with other officers of the Company, have
examined such records of the Company and have made such other
investigation as we deemed relevant for purposes of this
certificate;
(iv) in our opinion, we have made such examination or
investigation as is necessary to enable us to express an informed
opinion as to whether or not such conditions have been complied
with; and
(v) on the basis of the foregoing, we are of the opinion that
all conditions precedent provided for in the Indenture relating
to the action proposed to be taken by the Trustee as requested
herein have been complied with.
Kindly acknowledge receipt of this Company Order and Officers' Certificate,
including the documents listed herein, and confirm the arrangements set forth
herein by signing and returning the copy of this document attached hereto.
Very truly yours,
INDIANA MICHIGAN POWER COMPANY
By: /s/ A. A. Pena
Vice President
And: /s/ Thomas G. Berkemeyer .
Assistant Secretary
Acknowledged by Trustee:
THE BANK OF NEW YORK
By: /s/ Michael Culhane.
Vice President
<PAGE>
<TABLE>
EXHIBIT 12
INDIANA MICHIGAN POWER COMPANY
Computation of Consolidated Ratio of Earnings to Fixed Charges
(in thousands except ratio data)
<CAPTION>
Year Ended December 31,
----------------------------------------------------
1995 1996 1997 1998 1999
<S> <C> <C> <C> <C> <C>
Fixed Charges:
Interest on First Mortgage Bonds. . . . . . . . $ 43,410 $ 41,209 $ 39,678 $ 35,910 $ 31,442
Interest on Other Long-term Debt. . . . . . . . 23,564 20,100 21,064 27,457 38,623
Interest on Short-term Debt . . . . . . . . . . 2,003 2,982 3,248 4,903 9,207
Miscellaneous Interest Charges. . . . . . . . . 3,472 3,262 3,187 3,113 6,754
Estimated Interest Element in Lease Rentals . . 82,700 82,600 79,700 79,300 73,800
Total Fixed Charges. . . . . . . . . . . . $155,149 $150,153 $146,877 $150,683 $159,826
Earnings:
Net Income. . . . . . . . . . . . . . . . . . . $141,092 $157,153 $146,740 $ 96,628 $ 32,776
Plus Federal Income Taxes . . . . . . . . . . . 55,990 76,899 74,223 47,210 18,866
Plus State Income Taxes . . . . . . . . . . . . 7,058 9,270 7,519 4,938 (7,352)
Plus Fixed Charges (as above) . . . . . . . . . 155,149 150,153 146,877 150,683 159,826
Total Earnings . . . . . . . . . . . . . . $359,289 $393,475 $375,359 $299,459 $204,116
Ratio of Earnings to Fixed Charges. . . . . . . . 2.31 2.62 2.55 1.98 1.27
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
Year Ended December 31,
1999 1998 1997 1996 1995
(in thousands)
INCOME STATEMENTS DATA:
<S> <C> <C> <C> <C> <C>
Operating Revenues $1,394,119 $1,405,794 $1,339,232 $1,328,493 $1,283,157
Operating Expenses 1,285,467 1,239,787 1,131,444 1,108,076 1,077,434
Operating Income 108,652 166,007 207,788 220,417 205,723
Nonoperating Income (Loss) 4,530 (839) 4,415 2,729 6,272
Income Before Interest
Charges 113,182 165,168 212,203 223,146 211,995
Interest Charges 80,406 68,540 65,463 65,993 70,903
Net Income 32,776 96,628 146,740 157,153 141,092
Preferred Stock Dividend
Requirements 4,885 4,824 5,736 10,681 11,791
Earnings Applicable to
Common Stock $ 27,891 $ 91,804 $ 141,004 $ 146,472 $ 129,301
December 31,
1999 1998 1997 1996 1995
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $4,770,027 $4,631,848 $4,514,497 $4,377,669 $4,319,564
Accumulated Depreciation
and Amortization 2,194,397 2,081,355 1,973,937 1,861,893 1,751,965
Net Electric Utility Plant $2,575,630 $2,550,493 $2,540,560 $2,515,776 $2,567,599
Total Assets $4,576,696 $4,148,523 $3,967,798 $3,897,484 $3,928,337
Common Stock and Paid-in
Capital $ 789,323 $ 789,189 $ 789,056 $ 787,856 $ 787,686
Retained Earnings 166,389 253,154 278,814 269,071 235,107
Total Common Shareholder's
Equity $ 955,712 $1,042,343 $1,067,870 $1,056,927 $1,022,793
Cumulative Preferred Stock:
Not Subject to Mandatory
Redemption $ 9,248 $ 9,273 $ 9,435 $ 21,977 $ 52,000
Subject to Mandatory
Redemption (a) 64,945 68,445 68,445 135,000 135,000
Total Cumulative
Preferred Stock $ 74,193 $ 77,718 $ 77,880 $ 156,977 $ 187,000
Long-term Debt (a) $1,324,326 $1,175,789 $1,049,237 $1,042,104 $1,040,101
Obligations Under Capital
Leases (a) $ 187,965 $ 186,427 $ 195,227 $ 130,965 $ 142,506
Total Capitalization
and Liabilities $4,576,696 $4,148,523 $3,967,798 $3,897,484 $3,928,337
(a) Including portion due within one year.
</TABLE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
This discussion includes forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934.
These forward-looking statements reflect assumptions, and involve
a number of risks and uncertainties. Among the factors that could
cause actual results to differ materially from forward looking
statements are: electric load and customer growth; abnormal weather
conditions; available sources and costs of fuels; availability of
generating capacity; the speed and degree to which competition is
introduced to the power generation business, the structure and
timing of a competitive market and its impact on energy prices or
fixed rates; the ability to recover regulatory assets and other
stranded costs in connection with deregulation of generation; new
legislation and government regulations; the ability of the Company
to successfully control its costs; the economic climate and growth
in our service territory; unforeseen events affecting the Company's
efforts to restart its nuclear generating units which are on an
extended safety related shutdown; the outcome of litigation with
the Internal Revenue Service (IRS) related to certain interest
deductions for a corporate owned life insurance (COLI) program; the
ability of the Company to successfully challenge new environmental
regulations and to successfully litigate claims that the Company
violated the Clean Air Act; inflationary trends; changes in
electricity market prices; interest rates; and other risks and
unforeseen events.
Indiana Michigan Power Company (the Company) is a wholly-owned
subsidiary of American Electric Power Company, Inc. (AEP Co.,
Inc.), a public utility holding company. The Company is engaged in
the generation, purchase, sale, transmission and distribution of
electric power to 559,000 retail customers in its service territory
in northern and eastern Indiana and a portion of southwestern
Michigan and conducts business as American Electric Power (AEP).
The Company as a member of the AEP System Power Pool (AEP Power
Pool) shares the revenues and costs of the AEP Power Pool's
wholesale sales to neighboring utility systems and power marketers.
The Company also sells wholesale power to municipalities and
electric cooperatives.
The cost of the AEP System's generating capacity is allocated
among the AEP Power Pool members based on their relative peak
demands and generating reserves through the payment or receipt of
capacity charges and credits. AEP Power Pool members are also
compensated for the out-of-pocket costs of energy delivered to the
AEP Power Pool and charged for energy received from the AEP Power
Pool.
The AEP Power Pool calculates each Company's prior twelve month
peak demand relative to the total peak demand of all member
companies as a basis for sharing revenues and costs. The result of
this calculation is each Company's member load ratio (MLR) which
determines each Company's percentage share of revenues or costs.
Since the Company's MLR decreased in 1999 and increased during
1998, the AEP Power Pool allocated to the Company a smaller share
in 1999 and a larger share in 1998 of wholesale revenues and
expenses.
Results of Operations
Net income declined $64 million or 66% in 1999 primarily due to
the cost of efforts to restart the Company's two unit Donald C.
Cook Nuclear Plant (Cook Plant) which was shutdown in September
1997 to address safety concerns and issues.
Although operating revenues increased $67 million or 5% in
1998, net income decreased $50 million or 34% due mainly to
increased purchased power and maintenance expense related to the
extended outage of the Cook Plant and the adverse effect on
non-operating income of losses on certain non-regulated energy trades
outside of the AEP Power Pool's traditional marketing area.
Operating Revenues
Operating revenues decreased 1% in 1999 and increased 5% in
1998. The decrease in 1999 was primarily due to a decline in
margins on wholesale sales and net power trading transactions
within the AEP Power Pool's traditional marketing area. An
increase in retail revenues in 1998 was the primary reason for the
1998 increase. The following analyzes the changes in operating
revenues:
Increase (Decrease)
From Previous Year
(dollars in millions) 1999 1998
Amount % Amount %
Retail:
Residential $ 3.4 $ 26.4
Commercial 0.7 26.1
Industrial (5.7) 38.1
Other (0.2) 0.4
(1.8) (0.2) 91.0 9.6
Wholesale (18.2) (5.7) (40.6) (11.2)
Transmission (0.3) (1.1) 13.4 83.2
Miscellaneous 8.6 68.4 2.8 27.6
Total $(11.7) (0.8) $ 66.6 5.0
Operating revenues decreased in 1999 primarily due to reduced
margins on the Company's MLR share of wholesale sales and net
revenues from regulated power trading transactions in the AEP Power
Pool's traditional marketing area. The decline in margins reflects
the moderation in 1999 of extreme weather in 1998 and capacity
shortages experienced in the summer of 1998.
Revenues from retail customers increased significantly in 1998
due to the accrual of revenues under fuel adjustment clauses for
the increased cost of replacement power and increased fossil fuel
usage necessitated by the extended outage of the Company's two
nuclear units and a 3% increase in sales. Under the retail
jurisdictional fuel clauses, revenues are accrued for the
unrecovered cost of fuel in both retail jurisdictions and for
replacement power costs in the Michigan jurisdiction until approved
for billing. See "Nuclear Plant Restart Effort" for discussion of
settlement agreements in the Indiana and Michigan jurisdictions
regarding recovery of deferred Cook Plant fuel-related revenues.
Wholesale revenues declined significantly in 1998 due to a
decline in sales to the AEP Power Pool reflecting the
unavailability of the nuclear units. The decline was partially
offset by the Company's MLR share of increased power marketing
sales and net trading transactions of the AEP Power Pool.
Operating Expenses Increase
Total operating expenses increased 4% in 1999 and 10% in 1998
primarily due to costs related to the extended Cook Plant outage
and efforts to restart the units. The changes in the components of
operating expenses were:
Increase (Decrease)
From Previous Year
(dollars in millions) 1999 1998
Amount % Amount %
Fuel $ 12.8 7.4 $(53.8) (23.8)
Purchased Power (21.1) (7.1) 133.3 80.9
Other Operation 114.3 32.9 13.1 3.9
Maintenance (22.3)(14.1) 39.8 33.8
Depreciation and
Amortization 4.9 3.4 4.3 3.1
Amortization of Rockport
Plant Unit 1 Phase-in
Plan Deferrals - - (11.9)(100.0)
Taxes Other Than
Federal Income Taxes (8.8)(13.1) 2.6 4.1
Federal Income Taxes (34.1)(66.0) (19.1) (27.0)
Total $ 45.7 3.7 $108.3 9.6
Fuel expense increased in 1999 primarily due to an increase in
coal-fired generation as more internal generation was utilized in
place of purchasing power from the AEP Power Pool. The decrease in
fuel expense in 1998 was principally due to the unavailability of
the Company's two nuclear generating units from September 1997
through the end of 1999. See Nuclear Plant Restart Effort
discussed below.
The decrease in purchased power expense in 1999 reflects the
purchase of less power in 1999 at lower prices from the AEP Power
Pool, AEP Generating Company, an affiliate that is not a member of
the AEP Power Pool and unaffiliated entities. Purchased power
expense increased significantly in 1998 due to increased purchases
from the AEP Power Pool and the Company's MLR share of increased
purchases of electricity by the AEP Power Pool. The purchases were
made to replace power previously generated by the unavailable
nuclear units and to supply the electricity for the AEP Power
Pool's wholesale marketing sales.
The increases in other operation expense in 1999 and 1998 were
due to expenditures to prepare the nuclear units for restart.
Maintenance expense declined in 1999 due to cost containment
efforts including staff reductions at the Company's fossil-fired
power plants, in the engineering and maintenance staff of AEP
Service Corporation and in the Company's transmission and
distribution operations. The increase in maintenance expense in
1998 was due to expenditures to prepare the Cook Plant for restart.
The recovery period for the Rockport Plant Unit 1 cost deferral
under rate phase-in plans in the Indiana and the Federal Energy
Regulatory Commission (FERC) jurisdictions ended in 1997 causing
the decrease in the amortization of phase-in plan deferrals. The
deferred costs were amortized over a 10-year period commensurate
with their collection from customers.
The decrease in taxes other than federal income taxes in 1999
is primarily due to a decline in estimated taxable income for
Indiana supplemental income tax.
Federal income taxes attributable to operations decreased in
1999 and 1998 due to decreases in pre-tax operating income.
Nonoperating Income
The increase in nonoperating income in 1999 is primarily due to
the effect of non-regulated electricity trading transactions, which
resulted in a gain in 1999 and a loss in 1998. The decline in
nonoperating income in 1998 is due to net losses from non-regulated
electricity trading transactions outside of the AEP Power Pool's
traditional marketing area which are marked-to-market.
Interest Charges
Interest charges increased in 1999 due to increased borrowings
to support expenditures, both current and deferred, for the Cook
Plant restart effort.
<PAGE>
Business Outlook
The most significant factors affecting the Company's future
earnings are the restart of the Cook Plant nuclear generating
units; weather in the service territories served by the Company and
its wholesale customers; generating unit availability; the ability
to recover costs as the electric generating business becomes more
competitive; the outcome of litigation with the IRS related to
certain interest deductions for a COLI program; and the outcome of
ongoing environmental litigation and proposed air quality
standards. In 1999 significant progress was made related to many
of these major challenges.
Nuclear Plant Restart Effort
Management shut down both units of the Cook Plant in September
1997 due to questions regarding the operability of certain safety
systems that arose during a Nuclear Regulatory Commission (NRC)
architect engineer design inspection. The NRC issued a
Confirmatory Action Letter in September 1997 requiring the Company
to address certain issues identified in the letter. In 1998 the
NRC notified the Company that it had convened a Restart Panel for
Cook Plant and provided a list of required restart activities. In
order to identify and resolve all issues necessary to restart the
Cook units, the Company is working with the NRC and will be meeting
with the Panel on a regular basis until the units are returned to
service. In a February 2, 2000 letter from the NRC, the Company
was notified that the Confirmatory Action Letter had been closed.
Closing of the Confirmatory Action Letter is one of the key
approvals needed to restart the nuclear units.
The Company's plan to restart the Cook Plant units has Unit 2
scheduled to restart in April 2000 and Unit 1 scheduled to restart
in September 2000. The restart plan was developed based upon a
comprehensive systems readiness review of all operating systems at
the Cook Plant. When maintenance and other work including testing
required for restart are complete, the Company will seek
concurrence from the NRC to restart the Cook Plant units. Any
issues or difficulties encountered in testing of equipment as part
of the restart process could delay the scheduled restart dates.
Earnings for 2000 will be adversely affected by restart expenses
expected to be incurred in 2000, which are estimated to be $200
million, and amortization of previously deferred non-fuel restart
costs and fuel-related revenues of $78 million.
Replacement of the steam generator for Unit 1 will be completed
before it is returned to service. Costs associated with the steam
generator replacement are estimated to be approximately $165
million, which will be accounted for as a capital investment
unrelated to the restart. At December 31, 1999, $119 million has
been spent on the steam generator replacement.
<PAGE>
The cost of electricity supplied to retail customers increased
due to the outage of the two Cook Plant nuclear units since higher
cost coal-fired generation and coal-based purchased power is being
substituted for the unavailable low cost nuclear generation. With
regulator approvals, actual replacement energy fuel costs that
exceeded the costs reflected in billings were recorded as a
regulatory asset under the Indiana and Michigan retail
jurisdictional fuel cost recovery mechanisms.
On March 30, 1999, the Indiana Utility Regulatory Commission
(IURC) approved a settlement agreement that resolved all matters
related to the recovery of replacement energy fuel costs and all
outage/restart costs and related issues during the extended outage
of the Cook Plant. The settlement agreement provided for, among
other things, a replacement fuel billing credit of $55 million,
including interest, to Indiana retail customers' bills; the
deferral of unrecovered fuel revenues accrued between September 9,
1997 and December 31, 1999, including the billing credit; the
deferral of up to $150 million of jurisdictional restart related
nuclear operation and maintenance costs in 1999 above the amount
included in base rates; the amortization of the deferred fuel and
non-fuel operation and maintenance cost deferrals over a five-year
period ending December 31, 2003; a freeze in base rates through
December 31, 2003; and a fixed fuel recovery charge until March 1,
2004. The $55 million credit was applied to retail customers'
bills during the months of July, August and September 1999.
On December 16, 1999, the Michigan Public Service Commission
(MPSC) approved a settlement agreement for two open Michigan power
supply cost recovery reconciliation cases which resolves all issues
related to the Cook Plant extended outage. The settlement
agreement limits the Company's ability to increase base rates and
freezes the power supply cost recovery factor through December 31,
2003; permits the deferral of up to $50 million in 1999 of
jurisdictional non-fuel restart nuclear operation and maintenance
expenses and authorizes the amortization of power supply cost
recovery revenues accrued from September 9, 1997 to December 31,
1999 and non-fuel nuclear operation and maintenance costs deferrals
over a five-year period ending December 31, 2003.
Expenditures to restart the Cook units are estimated to total
approximately $574 million. Through December 31, 1999, $373
million has been spent. These expenditures are not capital in
nature and as such have negatively affected current earnings and
will negatively affect earnings in 2000, and through amortization
of the above described deferrals through December 31, 2003. In
1999 the restart costs incurred were $289 million of which $200
million were deferred for amortization over a five-year period,
beginning January 1, 1999, in accordance with the settlement
agreements. Consequently, $129 million of restart costs negatively
affected 1999 earnings inclusive of $40 million of amortization of
deferred restart costs. Also reflected in 1999 earnings is
amortization of $38 million of fuel-related revenues. At December
31, 1999, regulatory assets included $160 million of deferred
restart related operation and maintenance costs. Also deferred as
a regulatory asset at December 31, 1999 was $150 million of
fuel-related revenues.
The costs of the extended outage and restart efforts will have
a material adverse effect on future results of operations and
possibly financial condition through 2003 and on cash flows through
2000. Management believes that the Cook units will be successfully
restarted in April and September 2000, however, if for some unknown
reason the units are not returned to service or their restart is
delayed significantly it would have an even greater adverse effect
on future results of operations, cash flows and financial
condition.
Restructuring Activities
The introduction of competition and customer choice for retail
customers in the Company's service territory has been slow and
continues at a deliberate pace as legislators and regulatory
officials recognize the complexity of the issues. Federal
legislation has been proposed to mandate competition and customer
choice at the retail level, and several states have introduced or
are considering similar legislation. The MPSC has started a
program for certain utilities to phase-in to competition with the
objective of providing full customer choice by 2002. The Company
has begun discussions with the MPSC and other interested parties to
formulate a plan. The actions by the MPSC were not mandated by
legislation and are subject to a number of uncertainties and it is
not presently possible to determine what impact if any the
resolution of these matters will have on the operations of the
Company. Indiana is considering legislative initiatives to move to
customer choice, although the timing is uncertain. The Company
supports customer choice and is proactively involved in discussions
at both the state and federal levels regarding the best competitive
market structure and method to transition to a competitive
marketplace.
As the pricing of generation in the electric energy market
evolves from regulated cost-of-service ratemaking to market-based
rates, many complex issues must be resolved, including the recovery
of stranded costs. Stranded costs are those costs above market
that potentially would not be recoverable in a competitive market.
At the wholesale level recovery of stranded costs under certain
conditions was addressed by the FERC when it established rules for
open transmission access and competition in the wholesale markets.
However, the issue of stranded cost is unresolved at the retail
level where it is much larger than it is at the wholesale level.
The amount of stranded cost the Company could experience depends on
the timing and extent to which competition is introduced to its
generation business and the future market prices of electricity.
The recovery of stranded cost is dependent on the terms of future
legislation and related regulatory proceedings.
Under the provisions of Statement of Financial Accounting
Standards (SFAS) 71 "Accounting for the Effects of Certain Types of
Regulation," regulatory assets (deferred expenses) and regulatory
liabilities (deferred revenues) are included in the consolidated
balance sheets of cost-based regulated utilities in accordance with
regulatory actions to match expenses and revenues. In order to
maintain net regulatory assets on the balance sheet, SFAS 71
requires that rates charged to customers be cost-based and provide
for the probable recovery of regulatory assets over future
accounting periods. Management has concluded that as of December
31, 1999 the requirements to apply SFAS 71 continue to be met.
In the event a portion of the Company's business no longer
meets the requirements of SFAS 71, SFAS 101 "Accounting for the
Discontinuance of Application of Statement 71" requires that net
regulatory assets be written off for that portion of the business.
The provisions of SFAS 71 and SFAS 101 did not anticipate or
provide accounting guidance for an extended transition period and
for recovery of stranded costs during and after a transition period
through a wires charge or regulated distribution rates. In 1997
the Financial Accounting Standards Board's (FASB) Emerging Issues
Task Force (EITF) addressed such a situation with the consensus
reached on issue 97-4 that requires that the application of SFAS 71
to a segment of a regulated electric utility cease when that
segment is subject to a legislatively approved plan for transition
to competitive market pricing from cost-based regulated rates
and/or a rate order is issued containing sufficient detail for the
utility to reasonably determine what the restructuring plan would
entail and how it will affect the utility's financial statements.
The EITF indicated that the cessation of application of SFAS 71
would require that regulatory assets and impaired stranded plant
cost applicable to the portion of the business that was no longer
cost-based regulated be written off unless they are recoverable in
the future through cost-based regulated rates.
Although certain FERC orders provide for competition in the
firm wholesale market, that market is a relatively small part of
our business and most of our firm wholesale sales are still under
cost-of-service contracts. As a result, the Company's generation
business is still cost-based regulated and should remain so for the
near future. We believe that enabling federal and state
legislation should provide for the recovery of any generation-related
net regulatory assets and other reasonable stranded costs
from impaired generating assets. However, if in the future the
Company's generation business were to no longer be cost-based
regulated and if it were not possible to demonstrate probability of
recovery of resultant stranded costs including regulatory assets,
results of operations, cash flows and financial condition would be
adversely affected.
The Company supports the orderly transition to market pricing
for electricity because we believe our low cost generating units
provide us with a competitive advantage provided the legislators
and/or regulators provide a level playing field for all
competitors. The Company is working to develop and acquire the
necessary skills and competencies to succeed in a competitive
electricity commodity market. The AEP Power Pool has developed an
extensive wholesale electricity trading business. However, many
factors, some of which the Company does not control, could
negatively impact future success in a market price based,
competitive environment.
Customer choice and competition could ultimately result in
adverse impacts on results of operations and cash flows depending
on the future market prices of electricity and the ability of the
Company to recover its stranded costs including net regulatory
assets during a transition period and during a subsequent period
through a wires charge or other recovery mechanism. We believe
that enabling state legislation and the regulatory process should
provide for the full recovery of generation related net regulatory
assets and other reasonable stranded costs. However, if in the
future any portion of the generation business in our jurisdictions
were to no longer be cost-based regulated and if it were not
possible to demonstrate probability of recovery of resultant
stranded costs including regulatory assets, results of operations,
cash flows and financial condition would be adversely affected.
Environmental Concerns and Issues
We take great pride in our efforts to economically produce and
deliver electricity while minimizing the impact on the environment.
The Company has spent hundreds of millions of dollars to equip our
facilities with the latest cost effective clean air and water
technologies and to research new technologies. We intend to
continue in a leadership role fostering economically prudent
efforts to protect and preserve the environment while providing a
vital commodity, electricity, to our customers at a fair price.
Air Quality
In 1998 the United States (U.S.) Environmental Protection
Agency (Federal EPA) issued a final rule which requires substantial
reductions in nitrogen oxide (NOx) emissions in 22 eastern states,
including the states in which the Company's generating plants are
located. A number of utilities, including the Company, filed
petitions seeking a review of the final rule in the U.S. Court of
Appeals for the District of Columbia Circuit (Appeals Court). On
March 3, 2000, the Appeals Court issued a decision generally
upholding Federal EPA's final rule on NOx emission reductions.
On April 30, 1999, Federal EPA took final action with respect
to petitions filed by eight northeastern states pursuant to Section
126 of the Clean Air Act. The Rule approved portions of the
states' petitions and imposed NOx reduction requirements on AEP
System generating units which are approximately equivalent to the
reductions contemplated by the NOx emission reduction final rule.
The Company and its affiliates in the AEP System with coal-fired
generating plants, as well as other utility companies, filed a
petition in the Appeals Court seeking review of the Section 126
Rule. In 1999, three additional northeastern states and the
District of Columbia filed petitions with Federal EPA similar to
those originally filed by the eight northeastern states. Since the
petitions relied in part on compliance with an 8-hour ozone
standard remanded by the Appeals Court, Federal EPA indicated its
intent to decouple compliance with the 8-hour standard and issue a
revised rule.
On December 17, 1999, Federal EPA issued a revised Section 126
Rule requiring 392 industrial plants, including certain generating
plants owned by the Company, to reduce their NOx emissions by May
1, 2003. This rule approves petitions of four northeastern states
which contend that their failure to meet Federal EPA smog standards
is due to coal-fired generating plants in upwind states, including
many plants in the AEP System, and not their automobiles and other
local sources.
Preliminary estimates indicate that compliance with the Federal
EPA's final rule on NOx emission reductions that was upheld by the
Appeals Court could result in required capital expenditures of
approximately $202 million for the Company. It should be noted,
however, that compliance costs cannot be estimated with certainty
since actual costs incurred to comply could be significantly
different from this preliminary estimate depending upon the
compliance alternatives selected to achieve reductions in NOx
emissions. Unless compliance costs are recovered from customers
through regulated rates, such compliance costs will have an adverse
effect on future results of operations, cash flows and possibly
financial condition.
Federal EPA Complaint and Notice of Violation
Under the Clean Air Act, if a fossil plant undergoes a major
modification that results in a significant emissions increase,
permitting requirements might be triggered and the plant may be
required to install additional pollution control technology. This
requirement does not apply to activities such as routine
maintenance, replacement of degraded equipment or failed
components, or other repairs needed for the reliable, safe and
efficient operation of the plant.
On November 3, 1999, the Department of Justice, at the request
of Federal EPA, filed a complaint in the U.S. District Court for
the Southern District of Ohio that alleges the Company and its
affiliates in the AEP System made modifications to certain of their
coal-fired generating plants over the course of the past 25 years
that extend their operating lives or increase their generating
capacity in violation of the Clean Air Act. Federal EPA also
issued Notices of Violation alleging violations of certain
provisions of the Clean Air Act at certain AEP System plants. A
number of unaffiliated utilities also received Notices of
Violation, complaints or administrative orders.
<PAGE>
The states of New Jersey, New York and Connecticut were
subsequently allowed to join Federal EPA's action against the AEP
System companies under the Clean Air Act. On November 18, 1999, a
number of environmental groups filed a lawsuit against power plants
owned by the Company and its AEP System affiliates alleging similar
violations to those in the Federal EPA complaint and Notices of
Violation. This action has been consolidated with the Federal EPA
action. The complaints and Notices of Violation named one of the
Company's two coal-fired generating plants. Management believes its
maintenance, repair and replacement activities were in conformity
with the Clean Air Act provisions and intends to vigorously pursue
its defense of this matter.
The Clean Air Act authorizes civil penalties of up to $27,500
per day per violation at each generating unit ($25,000 per day
prior to January 30, 1997). Civil penalties, if ultimately imposed
by the court, and the cost of any required new pollution control
equipment, if the court accepts all of Federal EPA's contentions,
could be substantial. In the event the Company does not prevail,
any capital and operating costs of additional pollution control
equipment that may be required as well as any penalties imposed
would adversely affect future results of operations, cash flows and
possibly financial condition unless such costs can be recovered
through regulated rates.
Financial Condition
The Company issued $250 million principal amount of long-term
obligations in 1999; $150 million with an interest rate of 6-7/8%
and $100 million with a variable interest rate. The principal
amount of long-term debt retirements, including maturities, totaled
$110 million at interest rates ranging from 6.55% to 7.3%. Our
senior secured debt/first mortgage bond ratings are: Moody's, Baa1;
Standard & Poor's, A-; and Fitch, BBB+.
Gross plant and property additions were $178 million in 1999
and $159 million in 1998. Management estimates construction
expenditures for the next three years to be $329 million. The
funds for construction of new facilities and improvement of
existing facilities can come from a combination of internally
generated funds, short-term and long-term borrowings, preferred
stock issuances and investments in common equity by AEP Co., Inc.
However, all of the construction expenditures for the next three
years are expected to be financed with internally generated funds.
When necessary the Company generally issues short-term debt to
provide for interim financing of capital expenditures that exceed
internally generated funds. At December 31, 1999, $1,056 million
of unused short-term lines of credit shared with other AEP System
companies were available. Short-term debt borrowings are limited
by provisions of the Public Utility Holding Company Act of 1935 to
$500 million. Generally periodic reductions of outstanding
short-term debt are made through issuances of long-term debt and
additional capital contributions by the parent company.
The Company's earnings coverage presently exceeds all minimum
coverage requirements for the issuance of mortgage bonds. The
minimum coverage ratio is 2.0 for mortgage bonds and at December
31, 1999, the mortgage bond coverage ratio was 4.81.
The Company is committed under unit power agreements to
purchase all of an affiliate's share, 50% of the 2,600 megawatt
(mw) Rockport Plant capacity, unless it is sold to other utilities.
The affiliate had a long-term unit power agreement that expired at
the end of 1999 for the sale of 455 mw to an unaffiliated utility.
Revenues received by the affiliate under this agreement were $64
million in 1999. An agreement between the affiliate which owns
Rockport Plant and another affiliate provides for the sale of 390
mw of capacity to that affiliate through 2004. Effective January
1, 2000, the Company is required to purchase 910 mw of its
affiliate's 50% share of Rockport Plant capacity.
Market Risks
The Company has certain market risks inherent in its business
activities from changes in electricity commodity prices and
interest rates. As a member of the AEP Power Pool, trading of
electricity and related financial derivative instruments by the AEP
Power Pool exposes the Company to market risk. Market risk
represents the risk of loss that may impact the Company due to
adverse changes in electricity commodity market prices and rates.
Policies and procedures have been established to identify, assess
and manage market risk exposures including the use of a risk
measurement model which calculates Value at Risk (VaR). The VaR is
based on the variance-covariance method using historical prices to
estimate volatilities and correlations and assuming a 95%
confidence level and a three-day holding period. Throughout 1999
and 1998, the Company's share of the highest, lowest and average
quarterly VaR in the wholesale trading portfolio was less than $2.7
million and $2 million, respectively. Based on this VaR analysis,
at December 31, 1999 a near term change in commodity prices is not
expected to have a material effect on the Company's results of
operations, cash flows or financial condition.
The Company is exposed to changes in interest rates primarily
due to short-term and long-term borrowings to fund its business
operations. The debt portfolio has both fixed and variable
interest rates with terms from one day to 39 years and an average
duration of five years at December 31, 1999. The Company measures
interest rate market risk exposure utilizing a VaR model. The
interest rate VaR model is based on a Monte Carlo simulation with
a 95% confidence level and a one year holding period. The
volatilities and correlations were based on three years of weekly
prices. The risk of potential loss in fair value attributable to
the Company's exposure to interest rates, primarily related to
long-term debt with fixed interest rates, was $127 million at
December 31, 1999 and $102 million at December 31, 1998. The
Company would not expect to liquidate its entire debt portfolio in
a one year holding period. Therefore, a near term change in
interest rates should not materially affect results of operations
or the consolidated financial position of the Company.
Inflation affects the Company's cost of replacing utility plant
and the cost of operating and maintaining its plant. The rate-making
process generally limits our recovery to the historical cost
of assets resulting in economic losses when the effects of
inflation are not recovered from customers on a timely basis.
However, economic gains that result from the repayment of long-term
debt with inflated dollars partly offset such losses.
Litigation
Corporate Owned Life Insurance
The IRS agents auditing the AEP System's consolidated federal
income tax returns requested a ruling from their National Office
that certain interest deductions claimed by the Company relating to
AEP's COLI program should not be allowed. As a result of a suit
filed by the Company in U.S. District Court (discussed below) the
request for ruling was withdrawn by the IRS agents. Adjustments
have been or will be proposed by the IRS disallowing COLI interest
deductions for taxable years 1991-96. A disallowance of the COLI
interest deductions through December 31, 1999 would reduce earnings
by approximately $66 million (including interest).
The Company made payments of taxes and interest attributable to
COLI interest deductions for taxable years 1991-98 to avoid the
potential assessment by the IRS of any additional above market rate
interest on the contested amount. The payments to the IRS are
included on the Consolidated Balance Sheets in other property and
investments pending the resolution of this matter. The Company is
seeking refund through litigation of all amounts paid plus
interest.
In order to resolve this issue, the Company filed suit against
the U.S. in the U.S. District Court for the Southern District of
Ohio in March 1998. In 1999 a U.S. Tax Court judge decided in the
Winn-Dixie Stores v. Commissioner case that a corporate taxpayer's
COLI deductions should be disallowed. Notwithstanding the Tax
Court's decision in Winn-Dixie management has made no provision for
any possible adverse earnings impact from this matter because it
believes, and has been advised by outside counsel, that it has a
meritorious position and will vigorously pursue its lawsuit. In
the event the resolution of this matter is unfavorable, it will
have a material adverse impact on results of operations, cash flows
and possibly financial condition.
The Company is involved in a number of other legal proceedings
and claims. While management is unable to predict the outcome of
such litigation, it is not expected that the ultimate resolution of
these matters will have a material adverse effect on the results of
operations, cash flows or financial condition.
Other Matters
Superfund
By-products from the generation of electricity include
materials such as ash, slag, sludge, low-level radioactive waste
and spent nuclear fuel (SNF). Coal combustion by-products are
typically disposed of or treated in captive disposal facilities or
are beneficially utilized. In addition, our generating plants and
transmission and distribution facilities have used asbestos,
polychlorinated biphenyls (PCBs) and other hazardous and
nonhazardous materials. The Company is currently incurring costs
to safely dispose of such substances. Additional costs could be
incurred to comply with new laws and regulations if enacted.
The Comprehensive Environmental Response, Compensation and
Liability Act (Superfund) addresses clean-up of hazardous
substances at disposal sites and authorizes Federal EPA to
administer the clean-up programs. As of year-end 1999, the Company
has been named by the Federal EPA as a potentially responsible
party (PRP) for two sites. Historically, the Company's liability
has been resolved for a number of sites with no significant effect
on results of operations and present estimates do not anticipate
material cleanup costs for identified sites for which we have been
declared a PRP. However, if for reasons not currently identified
significant cleanup costs are incurred, results of operations, cash
flows and possibly financial condition would be adversely affected
unless the costs can be recovered from customers.
The Clean Air Act Amendments (CAAA) required Federal EPA to
issue rules to implement the law. In 1996 Federal EPA issued final
rules governing NOx emissions that must be met after January 1,
2000 (Phase II of CAAA). The final rules required substantial
reductions in NOx emissions from certain types of boilers including
those in the power plants of the Company and its affiliates in the
AEP System. To comply with Phase II of CAAA, the Company installed
NOx emission control equipment on certain units and switched fuel
at other units. The Company is operating under the Phase II rules
which require reporting at the end of each year. The Company does
not anticipate any material problems complying with the rules.
At the Third Conference of the Parties to the United Nations
Framework Convention on Climate Change held in Kyoto, Japan in
December 1997 more than 160 countries, including the U.S.,
negotiated a treaty requiring legally-binding reductions in
emissions of greenhouse gases, chiefly carbon dioxide, which many
scientists believe are contributing to global climate change. The
treaty, which requires the advice and consent of the U.S. Senate
for ratification, would require the U.S. to reduce greenhouse gas
emissions seven percent below 1990 levels in the years 2008-2012.
Although the U.S. has agreed to the treaty and signed it on
November 12, 1998, President Clinton has indicated that he will not
submit the treaty to the Senate for consideration until it contains
requirements for "meaningful participation by key developing
countries" and the rules, procedures, methodologies and guidelines
of the treaty's emissions trading and joint implementation programs
and compliance enforcement provisions have been negotiated. At the
Fourth Conference of the Parties, held in Buenos Aires, Argentina,
in November 1998, the parties agreed to a work plan to complete
negotiations on outstanding issues with a view toward approving
them at the Sixth Conference of the Parties to be held in November
2000. We will continue to work with the Administration and
Congress to develop responsible public policy on this issue.
If the Kyoto treaty is approved by Congress, the costs to
comply with the emission reductions required by the treaty are
expected to be substantial and would have a material adverse impact
on results of operations, cash flows and possibly financial
condition if not recovered from customers. It is management's
belief, that the Kyoto protocol is unlikely to be ratified or
implemented in the U.S. in its current form.
Costs for Spent Nuclear Fuel and Decommissioning
The Company, as the owner of the Cook Plant, like other nuclear
power plants, has a significant future financial commitment to
safely dispose of SNF and decommission and decontaminate the plant.
The Nuclear Waste Policy Act of 1982 established federal
responsibility for the permanent off-site disposal of SNF and
high-level radioactive waste. By law the Company participates in the
Department of Energy's (DOE) SNF disposal program which is
described in Note 5 of the Notes to Consolidated Financial
Statements. Since 1983 we have collected $272 million from
customers for the disposal of nuclear fuel consumed at the Cook
Plant. $115 million of these funds have been deposited in external
trust funds to provide for the future disposal of SNF and $157
million has been remitted to the DOE. Under the provisions of the
Nuclear Waste Policy Act, collections from customers are to provide
the DOE with money to build a permanent repository for spent fuel.
However, in December 1996, the DOE notified the Company that it
would be unable to begin accepting SNF by the January 1998 deadline
required by law. To date DOE has failed to comply with the
requirements of the Nuclear Waste Policy Act.
As a result of DOE's failure to make sufficient progress toward
a permanent repository or otherwise assume responsibility for SNF,
the Company along with a number of unaffiliated utilities and
states filed suit in the Appeals Court requesting, among other
things, that the Appeals Court order DOE to meet its obligations
under the law. The Appeals Court ordered the parties to proceed
with contractual remedies but declined to order DOE to begin
accepting SNF for disposal. DOE estimates its planned site for the
nuclear waste will not be ready until at least 2010. In 1998, the
Company filed a complaint in the U.S. Court of Federal Claims
seeking damages in excess of $150 million due to the DOE's partial
material breach of its unconditional contractual deadline to begin
disposing of SNF generated by the Cook Plant. Similar lawsuits
were filed by other utilities. On April 6, 1999, the Court granted
DOE's motion to dismiss a lawsuit filed by another utility. On May
20, 1999, the other utility appealed this decision to the U.S.
Court of Appeals for the Federal Circuit. The Company's case has
been stayed pending final resolution of the other utility's appeal.
As long as the delay in the availability of a government approved
storage repository for SNF continues, the cost of both temporary
and permanent storage will continue to increase.
The cost to decommission the Cook Plant is affected by both NRC
regulations and the delayed SNF disposal program. Studies
completed in 1997 estimate the cost to decommission the Cook Plant
ranges from $700 million to $1,152 million in 1997 nondiscounted
dollars. This estimate could escalate due to continued uncertainty
in the SNF disposal program and the length of time that SNF may
need to be stored at the plant site. External trust funds have
been established with amounts collected from customers to
decommission the plant. At December 31, 1999, the total
decommissioning trust fund balance was $498 million which includes
earnings on the trust investments. We will work with regulators
and customers to recover the remaining estimated cost of
decommissioning the Cook Plant. However, future results of
operations, cash flows and possibly financial condition would be
adversely affected if the cost of SNF disposal and decommissioning
continues to increase and cannot be recovered.
Year 2000 Readiness Disclosure
On or about midnight on December 31, 1999, digital computing
systems could have produced erroneous results or failed, unless
these systems had been modified or replaced, because such systems
may have been programmed incorrectly and interpreted the date of
January 1, 2000 as being January 1st of the year 1900 or another
incorrect date. In addition, certain systems may fail to detect
that the year 2000 is a leap year or otherwise incorrectly
interpret a year 2000 date.
The Company has not experienced any material failure of
generation and delivery of electric energy due to Year 2000 because
of the AEP System's preparations. Such preparation included the
modification or replacement of certain computer hardware and
software to minimize Year 2000-related failures and repair. This
included both information technology systems (IT), which are
mainframe and client server applications, and embedded logic
systems (non-IT), such as process controls for energy production
and delivery. Externally, the problem was addressed with entities
that interact with the Company, including suppliers, customers,
creditors, financial service organizations and other parties
essential to the Company's operations. In the course of the
external evaluation, the Company sought written assurances from
third parties regarding their state of Year 2000 readiness.
Another issue addressed was the impact of electric power grid
problems that may have occurred outside of our transmission system.
Through December 31, 1999, the Company's share of the AEP
System's expenditures on the Year 2000 project was $8 million.
Most Year 2000 costs were for IT contractors and consultants and
for salaries of internal IT professionals and were expensed;
however, in certain cases the Company acquired hardware and new
software that was capitalized.
New Accounting Standards
The FASB issued SFAS 133 "Accounting for Derivative Instruments
and Hedging Activities" in June 1998. SFAS 133 establishes
accounting and reporting standards for derivative instruments. It
requires that all derivatives be recognized as either an asset or
a liability and measured at fair value in the financial statements.
If certain conditions are met, a derivative may be designated as a
hedge of possible changes in fair value of an asset, liability or
firm commitment; variable cash flows of forecasted transactions; or
foreign currency exposure. The accounting/reporting for changes in
a derivative's fair value (gains and losses) depend on the intended
use and resulting designation of the derivative. Management is
currently studying the provisions of SFAS 133 and reviewing the
Company's contracts and transactions to determine the impact on the
Company's results of operations, cash flows and financial condition
when SFAS 133 is adopted on January 1, 2001.
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Indiana Michigan Power Company:
We have audited the accompanying consolidated balance sheets of
Indiana Michigan Power Company and its subsidiaries as of December
31, 1999 and 1998, and the related consolidated statements of
income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 1999. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An audit also
includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of Indiana
Michigan Power Company and its subsidiaries as of December 31, 1999
and 1998, and the results of their operations and their cash flows
for each of the three years in the period ended December 31, 1999
in conformity with generally accepted accounting principles.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 22, 2000
(March 3, 2000 as to Note 6)
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
Year Ended December 31,
1999 1998 1997
(in thousands)
<S> <C> <C> <C>
OPERATING REVENUES $1,394,119 $1,405,794 $1,339,232
OPERATING EXPENSES:
Fuel 185,419 172,592 226,402
Purchased Power 276,962 298,046 164,775
Other Operation 461,494 347,207 334,115
Maintenance 135,331 157,593 117,780
Depreciation and Amortization 149,988 145,112 140,812
Amortization of Rockport Plant Unit 1
Phase-in Plan Deferrals - - 11,871
Taxes Other Than Federal Income Taxes 58,713 67,592 64,945
Federal Income Taxes 17,560 51,645 70,744
Total Operating Expenses 1,285,467 1,239,787 1,131,444
OPERATING INCOME 108,652 166,007 207,788
NONOPERATING INCOME (LOSS) 4,530 (839) 4,415
INCOME BEFORE INTEREST CHARGES 113,182 165,168 212,203
INTEREST CHARGES 80,406 68,540 65,463
NET INCOME 32,776 96,628 146,740
PREFERRED STOCK DIVIDEND REQUIREMENTS 4,885 4,824 5,736
EARNINGS APPLICABLE TO COMMON STOCK $ 27,891 $ 91,804 $ 141,004
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
December 31,
1999 1998
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production $2,587,288 $2,565,041
Transmission 928,758 913,495
Distribution 818,697 768,888
General (including nuclear fuel) 244,981 228,013
Construction Work in Progress 190,303 156,411
Total Electric Utility Plant 4,770,027 4,631,848
Accumulated Depreciation and Amortization 2,194,397 2,081,355
NET ELECTRIC UTILITY PLANT 2,575,630 2,550,493
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR
FUEL DISPOSAL TRUST FUNDS 707,967 648,307
OTHER PROPERTY AND INVESTMENTS 213,658 197,368
CURRENT ASSETS:
Cash and Cash Equivalents 3,863 5,424
Accounts Receivable:
Customers 91,268 94,502
Affiliated Companies 48,901 26,569
Miscellaneous 18,644 18,743
Allowance for Uncollectible Accounts (1,848) (2,027)
Fuel - at average cost 27,597 20,857
Materials and Supplies - at average cost 84,149 78,009
Accrued Utility Revenues 44,428 37,277
Energy Marketing and Trading Contracts 97,946 14,105
Prepayments 7,631 4,848
TOTAL CURRENT ASSETS 422,579 298,307
REGULATORY ASSETS 624,810 421,475
DEFERRED CHARGES 32,052 32,573
TOTAL $4,576,696 $4,148,523
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
</TABLE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
December 31,
1999 1998
(in thousands)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 2,500,000 Shares
Outstanding - 1,400,000 Shares $ 56,584 $ 56,584
Paid-in Capital 732,739 732,605
Retained Earnings 166,389 253,154
Total Common Shareholder's Equity 955,712 1,042,343
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 9,248 9,273
Subject to Mandatory Redemption 64,945 68,445
Long-term Debt 1,126,326 1,140,789
TOTAL CAPITALIZATION 2,156,231 2,260,850
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning 501,185 445,934
Other 242,522 240,320
TOTAL OTHER NONCURRENT LIABILITIES 743,707 686,254
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 198,000 35,000
Short-term Debt 224,262 108,700
Accounts Payable - General 78,784 53,187
Accounts Payable - Affiliated Companies 31,118 37,647
Taxes Accrued 48,970 35,161
Interest Accrued 13,955 15,279
Obligations Under Capital Leases 11,072 9,667
Energy Marketing and Trading Contracts 95,564 15,228
Other 91,684 72,065
TOTAL CURRENT LIABILITIES 793,409 381,934
DEFERRED INCOME TAXES 622,157 559,288
DEFERRED INVESTMENT TAX CREDITS 121,627 129,779
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 85,005 88,712
DEFERRED CREDITS 54,560 41,706
COMMITMENTS AND CONTINGENCIES (Notes 5 and 6)
TOTAL $4,576,696 $4,148,523
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Year Ended December 31,
1999 1998 1997
(in thousands)
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net Income $ 32,776 $ 96,628 $ 146,740
Adjustments for Noncash Items:
Depreciation and Amortization 153,921 149,209 148,630
Amortization of Rockport Plant Unit 1
Phase-in Plan Deferrals - - 11,871
Amortization (Deferral) of Incremental Nuclear
Refueling Outage Expenses (net) 8,480 14,142 (15,967)
Deferred Nuclear Outage Costs (net) (160,000) - -
Deferred Federal Income Taxes 85,727 17,905 3,922
Deferred Investment Tax Credits (8,152) (8,266) (8,428)
Underrecovery of Fuel and Purchased Power (84,696) (46,846) (22,812)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (19,178) 1,462 (10,504)
Fuel, Materials and Supplies (12,880) (2,983) 5,168
Accrued Utility Revenues (7,151) (6,756) 7,774
Accounts Payable 19,068 22,440 6,502
Taxes Accrued 13,809 (11,689) (18,550)
Payment of Disputed Tax and Interest Related to COLI (3,228) (53,628) -
Other (net) 12,831 (8,176) 5,817
Net Cash Flows From Operating Activities 31,327 163,442 260,163
INVESTING ACTIVITIES:
Construction Expenditures (165,331) (147,627) (122,360)
Proceeds from Sales of Property and Other 2,501 4,419 2,016
Net Cash Flows Used For Investing Activities (162,830) (143,208) (120,344)
FINANCING ACTIVITIES:
Issuance of Long-term Debt 247,989 170,675 47,728
Retirement of Cumulative Preferred Stock (3,597) (120) (78,877)
Retirement of Long-term Debt (109,500) (55,000) (50,000)
Change in Short-term Debt (net) 115,562 (10,900) 76,100
Dividends Paid on Common Stock (114,656) (117,464) (131,260)
Dividends Paid on Cumulative Preferred Stock (5,856) (4,734) (5,931)
Net Cash Flows From (Used For) Financing Activities 129,942 (17,543) (142,240)
Net Increase (Decrease) in Cash and Cash Equivalents (1,561) 2,691 (2,421)
Cash and Cash Equivalents January 1 5,424 2,733 5,154
Cash and Cash Equivalents December 31 $ 3,863 $ 5,424 $ 2,733
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
Year Ended December 31,
1999 1998 1997
(in thousands)
<S> <C> <C> <C>
Retained Earnings January 1 $253,154 $278,814 $269,071
Net Income 32,776 96,628 146,740
285,930 375,442 415,811
Deductions:
Cash Dividends Declared:
Common Stock 114,656 117,464 131,260
Cumulative Preferred Stock:
4-1/8% Series 244 247 249
4.56% Series 66 67 88
4.12% Series 78 79 80
5.90% Series 963 985 985
6-1/4% Series 1,250 1,266 1,266
6.30% Series 834 834 834
6-7/8% Series 1,238 1,255 1,255
Total Cash Dividends Declared 119,329 122,197 136,017
Capital Stock Expense 212 91 980
Total Deductions 119,541 122,288 136,997
Retained Earnings December 31 $166,389 $253,154 $278,814
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING POLICIES:
Organization
Indiana Michigan Power Company (the Company or I&M) is a
wholly-owned subsidiary of American Electric Power Company, Inc.
(AEP Co., Inc.), a public utility holding company. The Company is
engaged in the generation, purchase, sale, transmission and
distribution of electric power to 559,000 retail customers in its
service territory in northern and eastern Indiana and a portion of
southwestern Michigan and conducts business as American Electric
Power (AEP). Under the terms of the AEP System Power Pool (AEP
Power Pool) and the AEP System Transmission Equalization Agreement,
the Company's generation and transmission facilities are operated
in conjunction with the facilities of certain other affiliated
utilities as an integrated utility system. The Company as a member
of the AEP Power Pool shares in the revenues and costs of the AEP
Power Pool's wholesale sales to utility systems and power
marketers. The Company also sells wholesale power to municipalities
and electric cooperatives.
The Company has two wholly-owned subsidiaries, that were
formerly engaged in coal-mining operations which are consolidated
in these financial statements, Blackhawk Coal Company and Price
River Coal Company. Blackhawk Coal Company currently leases and
subleases portions of its Utah coal rights, land and related mining
equipment to unaffiliated companies. Price River Coal Company,
which owns no land or mineral rights, is inactive. The Company's
River Transportation Division provides barging services to
affiliated and unaffiliated companies.
Regulation
As a subsidiary of AEP Co., Inc., the Company is subject to the
regulation of the Securities and Exchange Commission (SEC) under
the Public Utility Holding Company Act of 1935 (1935 Act). Retail
rates are regulated by the Indiana Utility Regulatory Commission
(IURC) and the Michigan Public Service Commission (MPSC). The
Federal Energy Regulatory Commission (FERC) regulates wholesale and
transmission rates.
Principles of Consolidation
The consolidated financial statements include the revenues,
expenses, cash flows, assets, liabilities and equity of I&M and its
wholly-owned subsidiaries. Significant intercompany items are
eliminated in consolidation.
Basis of Accounting
As a cost-based rate-regulated entity, I&M's financial
statements reflect the actions of regulators that result in the
recognition of revenues and expenses in different time periods than
enterprises that are not rate regulated. In accordance with
Statement of Financial Accounting Standards (SFAS) 71, "Accounting
for the Effects of Certain Types of Regulation," regulatory assets
(deferred expenses) and regulatory liabilities (deferred income)
are recorded to reflect the economic effects of regulation and to
match expenses with regulated revenues.
Use of Estimates
The preparation of these financial statements in conformity
with generally accepted accounting principles requires in certain
instances the use of estimates. Actual results could differ from
those estimates.
Utility Plant
Electric utility plant is stated at original cost and is
generally subject to first mortgage liens. Additions, major
replacements and betterments are added to the plant accounts.
Retirements of plant are deducted from the electric utility plant
in service account and are deducted from accumulated depreciation
together with associated removal costs, net of salvage. The costs
of labor, materials and overheads incurred to operate and maintain
utility plant are included in operating expenses.
Allowance for Funds Used During Construction (AFUDC)
AFUDC is a noncash nonoperating income item that is capitalized
and recovered through depreciation over the service life of utility
plant. It represents the estimated cost of borrowed and equity
funds used to finance construction projects. The amounts of AFUDC
for 1999, 1998 and 1997 were not significant.
Depreciation and Amortization
Depreciation of electric utility plant is provided on a
straight-line basis over the estimated useful lives of utility
plant and is calculated largely through the use of composite rates
by functional class. The annual composite depreciation rates for
1999, 1998 and 1997 are as follows:
Functional Class Annual Composite
of Property Depreciation Rates
1999 1998 1997
Production:
Steam-Nuclear 3.4% 3.4% 3.4%
Steam-Fossil-Fired 4.5% 4.4% 4.4%
Hydroelectric-Conventional 3.4% 3.4% 3.2%
Transmission 1.9% 1.9% 1.9%
Distribution 4.2% 4.2% 4.2%
General 3.8% 3.8% 3.8%
Amounts for the demolition and removal of non-nuclear plant are
charged to the accumulated provision for depreciation and recovered
through depreciation charges included in rates. The accounting and
rate-making treatment afforded nuclear decommissioning costs and
nuclear fuel disposal costs are discussed in Note 5.
Cash and Cash Equivalents
Cash and cash equivalents include temporary cash investments
with original maturities of three months or less.
Operating Revenues and Fuel Costs
Revenues include billed revenues as well as an accrual for
electricity consumed but unbilled at month-end. Fuel costs are
matched with revenues in accordance with rate commission orders.
Through December 31, 1999, revenues were accrued related to
unrecovered fuel in both state retail jurisdictions and for
replacement power costs in the Michigan jurisdiction until approved
for billing. If the Company's earnings exceed the allowed return
in the Indiana jurisdiction, the fuel clause mechanism provides for
the refunding of the excess earnings to ratepayers. As part of
settlement agreements related to fuel cost during an extended
outage at the Donald C. Cook Nuclear Plant (Cook Plant) approved by
the IURC and the MPSC, fuel costs could be deferred through
December 31, 1999. Over or under recovered fuel from January 1,
2000 through February 29, 2004 in the Indiana jurisdiction and
through December 31, 2003 in the Michigan jurisdiction will not be
eligible for deferral due to fixed fuel recovery amounts in the
settlement agreements. Effective March 1, 2004 and January 1,
2004, the fixed fuel recovery amount will expire and the Company
will return to recording over and under recovery of fuel costs for
the Indiana and Michigan jurisdictions, respectively, assuming that
generation is still cost-based rate regulated. Substantially all
FERC wholesale jurisdictional fuel cost changes are expensed and
billed as incurred. See Note 2 "Cook Nuclear Plant Shutdown" for
a complete discussion of the settlement agreements.
Energy Marketing and Trading Transactions
The AEP Power Pool administers and implements power marketing
and trading transactions (trading activities) in which the Company
shares. Trading activities involve the sale of electricity under
physical forward contracts at fixed and variable prices and the
trading of electricity contracts including exchange traded futures
and options, over-the-counter options and swaps. The majority of
these transactions represents physical forward electricity
contracts in the AEP Power Pool's traditional marketing area and
are typically settled by entering into offsetting contracts. The
net revenues from these regulated transactions in AEP's traditional
marketing area are included in operating revenues for rate-making,
accounting and financial and regulatory reporting purposes.
<PAGE>
In addition, the AEP Power Pool purchases and sells electricity
options, futures and swaps, and enters into forward purchase and
sale contracts for electricity outside of the AEP Power Pool's
traditional marketing area. The Company's share of these
non-regulated trading activities are included in nonoperating income.
In the first quarter of 1999 the Company adopted the Financial
Accounting Standards Board's (FASB) Emerging Issues Task Force
Consensus (EITF) 98-10, "Accounting for Contracts Involved in
Energy Trading and Risk Management Activities." The EITF requires
that all energy trading contracts be marked-to-market. The effect
on the Consolidated Statements of Income of marking open trading
contracts to market is deferred as regulatory assets or liabilities
for those open trading transactions within the AEP Power Pool's
marketing area that are included in cost of service on a settlement
basis for rate-making purposes. The Company's share of
non-regulated open trading contracts are accounted for on a
mark-to-market basis in nonoperating income. Unrealized mark-to-market
gains and losses from trading activities are reported as assets and
liabilities, respectively. The adoption of the EITF did not have
a material effect on results of operations, cash flows or financial
condition.
The Company enters into contracts to manage the exposure to
unfavorable changes in the cost of debt to be issued. These
anticipatory debt instruments are entered into in order to manage
the change in interest rates between the time a debt offering is
initiated and the issuance of the debt (usually a period of 60
days). Gains or losses on the anticipatory debt instruments are
deferred and amortized over the life of the debt issuance with the
amortization included in interest charges. There were no such
forward contracts outstanding at December 31, 1999 or 1998.
See Note 11 - Financial Instruments, Credit and Risk Management
for further discussion.
Levelization of Nuclear Refueling Outage Costs
Incremental operation and maintenance costs associated with
refueling outages at the Cook Plant are deferred commensurate with
their rate-making treatment and amortized over the period beginning
with the commencement of an outage and ending with the beginning of
the next outage.
Amortization of Cook Plant Deferred Restart Costs
Pursuant to settlement agreements approved by the IURC and the
MPSC to resolve all issues related to the extended outage of the
Cook Plant, the Company deferred certain operation and maintenance
costs in 1999. The settlement agreements provide for the deferral
of up to $150 million of Indiana jurisdictional and up to $50
million of Michigan jurisdictional non-fuel operation and
maintenance costs incurred in 1999. The deferred amount will be
amortized to expense on a straight-line basis over five years
beginning January 1, 1999. The Company deferred $200 million and
amortized $40 million in 1999 leaving $160 million as a SFAS 71
regulatory asset at December 31, 1999 on the Consolidated Balance
Sheet. See Note 2 "Cook Nuclear Plant Shutdown" for a discussion
of the settlement agreements.
Income Taxes
The Company follows the liability method of accounting for
income taxes as prescribed by SFAS 109, "Accounting for Income
Taxes." Under the liability method, deferred income taxes are
provided for all temporary differences between the book cost and
tax basis of assets and liabilities which will result in a future
tax consequence. Where the flow-through method of accounting for
temporary differences is reflected in rates (that is, deferred
taxes are not included in the cost of service for determining
regulated rates for electricity), deferred income taxes are
recorded and related regulatory assets and liabilities are
established in accordance with SFAS 71.
Investment Tax Credits
Investment tax credits have been accounted for under the
flow-through method except where regulatory commissions have reflected
investment tax credits in the rate-making process on a deferral
basis. Investment tax credits that have been deferred are being
amortized over the life of regulated plant investment.
Debt and Preferred Stock
Gains and losses from the reacquisition of debt are deferred
and amortized over the remaining term of the reacquired debt in
accordance with rate-making treatment. If the debt is refinanced
the reacquisition costs are deferred and amortized over the term of
the replacement debt commensurate with their recovery in rates.
Debt discount or premium and debt issuance expenses are
deferred and amortized over the term of the related debt, with the
amortization included in interest charges.
Redemption premiums paid to reacquire preferred stock are
included in paid-in capital and amortized to retained earnings
commensurate with their recovery in rates. The excess of par value
over the cost of preferred stock reacquired is credited to paid-in
capital and amortized to retained earnings.
Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds
Securities held in trust funds for decommissioning nuclear
facilities and for the disposal of spent nuclear fuel (SNF) are
recorded at market value in accordance with SFAS 115, "Accounting
for Certain Investments in Debt and Equity Securities." Securities
in the trust funds have been classified as available-for-sale due
to their long-term purpose. Under the provisions of SFAS 71,
unrealized gains and losses from securities in these trust funds
are not reported in equity but result in adjustments to the
liability account for the nuclear decommissioning trust funds and
to regulatory assets or liabilities for the SNF disposal trust
funds.
Other Property and Investments
Other property and investments are stated at cost.
Comprehensive Income
There were no material differences between net income and
comprehensive income.
Reclassification
Certain prior year amounts have been reclassified to conform to
current year presentation. Such reclassifications had no impact on
previously reported net income.
2. COOK NUCLEAR PLANT SHUTDOWN:
I&M owns and operates the two-unit 2,110 megawatt (mw) Cook
Plant under licenses granted by the Nuclear Regulatory Commission
(NRC). The Company shut down both units of the Cook Plant in
September 1997 due to questions regarding the operability of
certain safety systems that arose during a NRC architect engineer
design inspection. The NRC issued a Confirmatory Action Letter in
September 1997 requiring the Company to address certain issues
identified in the letter. In 1998 the NRC notified the Company
that it had convened a Restart Panel for Cook Plant and provided a
list of required restart activities. In order to identify and
resolve the issues necessary to restart the Cook units, the Company
is working with the NRC and will be meeting with the Panel on a
regular basis until the units are returned to service. In a
February 2, 2000 letter from the NRC, I&M was notified that the
Confirmatory Action Letter had been closed. Closing of the
Confirmatory Action Letter is one of the key approvals needed to
restart the nuclear units.
The Company's plan to restart the Cook Plant units has Unit 2
scheduled to return to service in April 2000 and Unit 1 scheduled
to return to service in September 2000. The restart plan was
developed based upon a comprehensive systems readiness review of
all operating systems at the Cook Plant. When maintenance and
other work including testing required for restart are complete, the
Company will seek concurrence from the NRC to return the Cook Plant
to service. Any issues or difficulties encountered in testing of
equipment as part of the restart process could delay the scheduled
restart dates.
Replacement of the steam generator for Unit 1 will be completed
before it is returned to service. Costs associated with the steam
generator replacement are estimated to be approximately $165
million, which will be accounted for as a capital investment
unrelated to the restart. At December 31, 1999, $119 million has
been spent on the steam generator replacement.
The cost of electricity supplied to retail customers increased
due to the outage of the two Cook Plant nuclear units since higher
cost coal-fired generation and coal-based purchased power is being
substituted for the unavailable low cost nuclear generation. With
regulator approvals, actual replacement energy fuel costs that
exceeded the costs reflected in billings were recorded as a
regulatory asset under the Indiana and Michigan retail
jurisdictional fuel cost recovery mechanisms.
On March 30, 1999, the IURC approved a settlement agreement
that resolved all matters related to the recovery of replacement
energy fuel costs and all outage/restart costs and issues during
the extended outage of the Cook Plant. The settlement agreement
provided for, among other things, a replacement fuel billing credit
of $55 million, including interest, to Indiana retail customers'
bills; the deferral of unrecovered fuel revenues accrued between
September 9, 1997 and December 31, 1999, including the billing
credit; the deferral of up to $150 million of jurisdictional
restart related nuclear operation and maintenance costs in 1999
above the amount included in base rates; the amortization of the
deferred fuel revenues and non-fuel operation and maintenance cost
deferrals over a five-year period ending December 31, 2003; a
freeze in base rates through December 31, 2003; and a fixed fuel
recovery charge through March 1, 2004. The $55 million credit was
applied to retail customers' bills during the months of July,
August and September 1999.
On December 16, 1999, the MPSC approved a settlement agreement
for two open Michigan power supply cost recovery reconciliation
cases which resolves all issues related to the Cook Plant extended
outage. The settlement agreement limits the Company's ability to
increase base rates and freezes the power supply cost recovery
factor until January 1, 2004; permits the deferral of up to $50
million in 1999 of jurisdictional non-fuel nuclear operation and
maintenance expenses; authorizes the amortization of power supply
cost recovery revenues accrued from September 9, 1997 to December
31, 1999 and non-fuel nuclear operation and maintenance cost
deferrals over a five-year period ending December 31, 2003.
Expenditures to restart the Cook Plant units are estimated to
total approximately $574 million. Through December 31, 1999, $373
million has been spent. The restart costs incurred in 1997 and
1998 were $6 and $78 million, respectively, and were recorded in
other operation and maintenance expense. In 1999 the restart costs
incurred were $289 million and were recorded in accordance with the
Indiana and Michigan settlement agreements whereby $150 million and
$50 million, respectively, of operation and maintenance costs were
deferred in 1999 for amortization through December 31, 2003. The
amortization of the non-fuel operation and maintenance restart cost
deferrals through December 31, 1999 was $40 million. Consequently,
maintenance and other operation expenses included $129 million of
Cook restart expense for 1999. Also reflected in 1999 earnings is
amortization of $38 million of fuel-related revenues. Restart
costs incurred in 2000 will be accounted for as a current period
operations and maintenance expense. At December 31, 1999, the
unamortized balance of restart related operation and maintenance
costs was $160 million and is included in the Company's regulatory
assets. Also deferred as a regulatory asset at December 31, 1999
was $150 million of fuel-related revenues.
The costs of the extended outage and restart efforts will have
a material adverse effect on future results of operations and
possibly financial condition through 2003 and on cash flows through
2000. Management believes that the Cook Plant units will be
successfully returned to service by April and September 2000.
However, if for some unknown reason the units are not returned to
service or their return is delayed significantly it would have an
even greater adverse effect on future results of operations, cash
flows and financial condition.
3. RATE MATTERS:
Transmission
The FERC issued orders 888 and 889 in April 1996 which required
each public utility that owns or controls interstate transmission
facilities to file an open access network and point-to-point
transmission tariff that offers services comparable to the
utility's own uses of its transmission system. The orders also
require utilities to functionally unbundle their services, by
requiring them to use their own transmission service tariffs in
making off-system and third-party sales. As part of the orders,
the FERC issued a pro-forma tariff which reflects the Commission's
views on the minimum non-price terms and conditions for
non-discriminatory transmission service. The FERC orders also allow a
utility to seek recovery of certain prudently-incurred stranded
costs that result from unbundled transmission service.
In July 1996, the AEP System companies filed an Open Access
Transmission Tariff conforming with the FERC's pro-forma
transmission tariff, subject to the resolution of certain pricing
issues. The 1996 tariff incorporated transmission rates which were
the result of a settlement of a pending rate case, but which were
being collected subject to refund from certain customers who
opposed the settlement and continued to litigate the reasonableness
of the AEP System's transmission rates. On July 30, 1999, the FERC
issued an order in the litigated rate case which would reduce AEP's
rates for the affected customers below the settlement rate. The
AEP System and certain of the affected customers sought rehearing
of the FERC order. The Company made a provision in September 1999
for its share of the refund including interest.
On December 10, 1999, the AEP System companies filed a
settlement agreement with the FERC resolving the issues on
rehearing of the July 30, 1999 order. Under terms of the
settlement, the AEP System will make refunds retroactive to
September 7, 1993 to certain customers affected by the July 30,
1999 FERC order. The refunds will be made in two payments. The
first payment was made on February 2, 2000 pursuant to a FERC
order granting AEP's request to make interim refunds. The
remainder will be paid after the FERC issues a final order and
approves a compliance filing that the AEP System companies will
make pursuant to the final order. In addition, a new rate was made
effective January 1, 2000, subject to FERC approval, for all
transmission service customers and a future rate was established to
take effect upon the consummation of the AEP and Central and South
West Corporation merger unless a superseding rate is made effective
prior to the merger.
Retail
In December 1997, AEP Co., Inc. and Central and South West
Corporation announced their plan to merge. As part of the
regulatory approval process, the IURC and MPSC intervened in the
FERC proceeding.
The IURC approved a settlement agreement related to the merger
on April 26, 1999. The settlement agreement resulted from an
investigation of the proposed merger initiated by the IURC. The
terms of the settlement agreement provide for, among other things,
a sharing of net merger savings for eight years through reductions
in customers' bills of approximately $67 million over eight years
following consummation of the merger; a one year extension through
January 1, 2005 of a freeze in base rates; additional annual
deposits of $6 million to the nuclear decommissioning trust fund
for the Indiana jurisdiction for the years 2001 through 2003;
quality-of-service standards; and participation in a regional
transmission organization. As part of the settlement agreement,
the IURC agreed not to oppose the merger in the FERC or SEC
proceedings.
The MPSC has also approved a settlement agreement with the
Company related to the pending merger. In approving the settlement
agreement, the MPSC has agreed to not oppose the merger at the
federal level. AEP has agreed to share net merger savings with
Michigan customers as well as AEP shareowners for eight years;
establish performance standards that will maintain or improve
customer service and system reliability; join a regional
transmission organization by December 31, 2000; and establish
affiliate rules to protect consumers and promote fair competition.
The Michigan jurisdictional customers' share of the net guaranteed
merger savings is approximately $14 million over the eight years
following the consummation of the merger. Once the merger is
consummated, Michigan customers will receive their share of the net
savings through billing credits of approximately 1 percent to 1.5
percent each year. The credits will continue for at least eight
years and will not be affected by any changes to the current
regulatory structure in Michigan.
4. EFFECTS OF REGULATION AND PHASE-IN PLANS:
In accordance with SFAS 71 the consolidated financial
statements include regulatory assets (deferred expenses) and
regulatory liabilities (deferred income) recorded in accordance
with regulatory actions in order to match expenses and revenues
from cost-based rates in the same accounting period. Regulatory
assets are expected to be recovered in future periods through the
rate-making process and regulatory liabilities are expected to
reduce future cost recoveries. Among other things, application of
SFAS 71 requires that the Company's regulated rates be cost-based
and the recovery of regulatory assets probable. Management has
reviewed the evidence currently available and concluded that the
Company continues to meet the requirements to apply SFAS 71. In
the event a portion of the Company's business no longer met those
requirements net regulatory assets would have to be written off for
that portion of the business and assets attributable to that
portion of the business would have to be tested for possible
impairment and, if required, an impairment loss recorded unless the
net regulatory assets and impairment losses are recoverable as a
stranded cost.
Recognized regulatory assets and liabilities are comprised of
the following at:
December 31,
1999 1998
(in thousands)
Regulatory Assets:
Amounts Due From Customers for
Future Income Taxes $236,783 $259,641
Cook Plant Restart Costs 160,000 -
Unrecovered Fuel and
Purchased Power 150,004 65,308
Department of Energy
Decontamination and
Decommissioning Assessment 35,238 38,898
Nuclear Refueling
Outage Cost Levelization 9,150 17,630
Unamortized Loss On
Reacquired Debt 14,780 16,434
Other 18,855 23,564
Total Regulatory Assets $624,810 $421,475
<PAGE>
Regulatory Liabilities:
Deferred Investment Tax Credits $121,627 $129,779
Other* 17,238 16,507
Total Regulatory Liabilities $138,865 $146,286
* Included in Deferred Credits on Consolidated Balance
Sheets.
The Rockport Plant consists of two 1,300 mw coal-fired units.
I&M and AEP Generating Company (AEGCo), an affiliate, each own 50%
of one unit (Rockport 1) and each lease a 50% interest in the other
unit (Rockport 2) from unaffiliated lessors under an operating
lease. The gain on the sale and leaseback of Rockport 2 was de-
ferred and is being amortized, with related taxes and investment
tax credits, over the initial lease term which expires in 2022.
At January 1, 1997 rate phase-in plan deferrals existed for the
Rockport Plant. Rate phase-in plans in the Company's Indiana and
FERC jurisdictions provided for the recovery and straight-line
amortization of deferred Rockport Plant Unit 1 costs over ten years
beginning in 1987. In 1997 the amortization and recovery of the
deferred Rockport Plant Unit 1 Phase-in Plan costs were completed.
During the recovery period net income was unaffected by the
recovery of the phase-in deferrals. Amortization was $11.9 million
in 1997.
5. COMMITMENTS AND CONTINGENCIES:
Construction and Other Commitments
Substantial construction commitments have been made to support
the Company's utility operations and are estimated to be $329
million for 2000-2002.
Long-term fuel supply contracts contain clauses that provide
for periodic price adjustments. The fuel supply contracts are for
various terms, the longest of which extends to 2014, and contain
various clauses that would release the Company from its obligation
under certain force majeure conditions. The Michigan and Indiana
retail jurisdictions, under the terms of settlement agreements have
suspended the operation of fuel clause mechanisms that provide for
recovery of changes in the cost of fuel with the regulators' review
and approval until January 2004 and March 2004, respectively.
The Company is committed under unit power agreements to
purchase all of AEGCo's share, 50% of the 2,600 mw Rockport Plant
capacity, unless it is sold to other utilities. AEGCo had a
long-term unit power agreement which expired December 31, 1999 for the
sale of 455 mw to an unaffiliated utility. Revenues received by
AEGCo under this agreement were $64 million in 1999. An agreement
between AEGCo and another affiliate provides for the sale of 390 mw
of capacity to that affiliate through 2004. Effective January 1,
2000, I&M is required to purchase 910 mw of Rockport Plant capacity
from AEGCo.
The Company sells under contract up to 250 mw of its Rockport
Plant capacity to an unaffiliated utility. The contract expires in
2009.
Nuclear Plant
The operation of a nuclear facility involves special risks,
potential liabilities, and specific regulatory and safety
requirements. Should a nuclear incident occur at any nuclear power
plant facility in the United States (U.S.), the resultant liability
could be substantial. By agreement I&M is partially liable
together with all other electric utility companies that own nuclear
generating units for a nuclear power plant incident. In the event
nuclear losses or liabilities are underinsured or exceed
accumulated funds and recovery in rates is not possible, results of
operations, cash flows and financial condition would be negatively
affected.
Nuclear Incident Liability
Public liability is limited by law to $9.9 billion should an
incident occur at any licensed reactor in the U.S. Commercially
available insurance provides $200 million of coverage. In the
event of a nuclear incident at any nuclear plant in the U.S. the
remainder of the liability would be provided by a deferred premium
assessment of $88 million on each licensed reactor payable in
annual installments of $10 million. As a result, I&M could be
assessed $176 million per nuclear incident payable in annual
installments of $20 million. The number of incidents for which
payments could be required is not limited.
Nuclear insurance pools and other insurance policies provide $3
billion of property damage, decommissioning and decontamination
coverage for Cook Plant. Additional insurance provides coverage
for extra costs resulting from a prolonged accidental Cook Plant
outage. Some of the policies have deferred premium provisions
which could be triggered by losses in excess of the insurer's
resources. The losses could result from claims at the Cook Plant
or certain other unaffiliated nuclear units. The Company could be
assessed up to $23 million annually under these policies.
SNF Disposal
Federal law provides for government responsibility for
permanent SNF disposal and assesses nuclear plant owners fees for
SNF disposal. A fee of one mill per kilowatthour for fuel consumed
after April 6, 1983 is being collected from customers and remitted
to the U.S. Treasury. Fees and related interest of $199 million
for fuel consumed prior to April 7, 1983 have been recorded as
long-term debt. I&M has not paid the government the pre-April 1983
fees due to continued delays and uncertainties related to the
federal disposal program. At December 31, 1999, funds collected
from customers towards payment of the pre-April 1983 fee and
related earnings thereon approximate the liability.
Decommissioning and Low Level Waste Accumulation Disposal
Decommissioning costs are being accrued over the service life
of the Cook Plant. The licenses to operate the two nuclear units
expire in 2014 and 2017. After expiration of the licenses the
plant is expected to be decommissioned through dismantlement. The
estimated cost of decommissioning and low level radioactive waste
accumulation disposal costs ranges from $700 million to $1,152
million in 1997 nondiscounted dollars. The wide range is caused by
variables in assumptions including the estimated length of time SNF
may need to be stored at the plant site subsequent to ceasing
operations. This, in turn, depends on future developments in the
federal government's SNF disposal program. Continued delays in the
federal fuel disposal program can result in increased
decommissioning costs. The Company is recovering estimated
decommissioning costs in its three rate-making jurisdictions based
on at least the lower end of the range in the most recent
decommissioning study at the time of the last rate proceeding. The
Company records decommissioning costs in other operation expense
and records a noncurrent liability equal to the decommissioning
cost recovered in rates; such amounts were $28 million in 1999, $29
million in 1998 and $28 million in 1997. Decommissioning costs
recovered from customers are deposited in external trusts. In 1999
the Company also deposited in the decommissioning trust $4 million
related to a special regulatory commission approved funding method.
Trust fund earnings increase the fund assets and the recorded
liability and decrease the amount needed to be recovered from
ratepayers. During 1999 and 1998 the Company withdrew $8 million
and $3 million, respectively, from the trust funds for
decommissioning of the original steam generators removed from Unit
2. At December 31, 1999 and 1998, the Company has recognized a
decommissioning liability of $501 million and $446 million,
respectively.
Federal EPA Complaint and Notice of Violation
Under the Clean Air Act, if a fossil plant undertakes a major
modification that directly results in an emissions increase,
permitting requirements might be triggered and the plant may be
required to install additional pollution control technology. This
requirement does not apply to activities such as routine
maintenance, replacement of degraded equipment or failed
components, or other repairs needed for the reliable, safe and
efficient operation of the plant.
On November 3, 1999, the Department of Justice, at the request
of the U.S. Environmental Protection Agency (Federal EPA), filed a
complaint in the U.S. District Court for the Southern District of
Ohio that alleges the Company made modifications to generating
units at its Tanners Creek Plant over the course of the past 25
years that extend unit operating lives or increase unit generating
capacity without a preconstruction permit in violation of the Clean
Air Act. Federal EPA also issued a Notice of Violation to the
Company and other AEP companies alleging violations at certain AEP
Plants. A number of unaffiliated utilities also received Notices
of Violation, complaints or administrative orders.
The states of New Jersey, New York and Connecticut were
subsequently granted leave to intervene in the Federal EPA's action
against the Company under the Clean Air Act. On November 18, 1999,
a number of environmental groups filed a lawsuit against power
plants owned by the Company and its AEP System affiliates alleging
similar violations to those in the Federal EPA complaint and
Notices of Violation. This action has been consolidated with the
Federal EPA action.
The Clean Air Act authorizes civil penalties of up to $27,500
per day per violation at each generating unit ($25,000 per day
prior to January 30, 1997). Civil penalties, if ultimately imposed
by the court, and the cost of any required new pollution control
equipment, if the court accepts all of Federal EPA's contentions,
could be substantial.
Management believes its maintenance, repair and replacement
activities were in conformity with the Clean Air Act and intends to
vigorously pursue its defense of this matter.
In the event the Company does not prevail, any capital and
operating costs of additional pollution control equipment that may
be required as well as any penalties imposed would adversely affect
future results of operations, cash flows and possibly financial
condition unless such costs can be recovered through regulated
rates or the future market prices of electricity if generation is
deregulated.
Litigation
The Internal Revenue Service (IRS) agents auditing the AEP
System's consolidated federal income tax returns requested a ruling
from their National Office that certain interest deductions claimed
by the Company relating to AEP's corporate owned life insurance
(COLI) program should not be allowed. As a result of a suit filed
in U.S. District Court (discussed below) this request for ruling
was withdrawn by the IRS agents. Adjustments have been or will be
proposed by the IRS disallowing COLI interest deductions for
taxable years 1991-96. A disallowance of the COLI interest
deductions through December 31, 1999 would reduce earnings by
approximately $66 million (including interest).
The Company made payments of taxes and interest attributable to
COLI interest deductions for taxable years 1991-98 to avoid the
potential assessment by the IRS of any additional above market rate
interest on the contested amount. The payments to the IRS are
included on the Consolidated Balance Sheets in other property and
investments pending the resolution of this matter. The Company is
seeking refunds through litigation of all amounts paid plus
interest.
In order to resolve this issue, the Company filed suit against
the United States in the U.S. District Court for the Southern
District of Ohio in March 1998. In 1999 a U.S. Tax Court judge
decided in the Winn-Dixie Stores v. Commissioner case that a
corporate taxpayer's COLI interest deduction should be disallowed.
Notwithstanding the Tax Court's decision in Winn-Dixie, management
has made no provision for any possible adverse earnings impact from
this matter because it believes, and has been advised by outside
counsel, that it has a meritorious position and will vigorously
pursue its lawsuit. In the event the resolution of this matter is
unfavorable, it will have a material adverse impact on results of
operations, cash flows and possibly financial condition.
The Company is involved in a number of other legal proceedings
and claims. While management is unable to predict the ultimate
outcome of litigation, it is not expected that the resolution of
these matters will have a material adverse effect on the results of
operations, cash flows and financial condition.
6. SUBSEQUENT EVENT - NOx REDUCTIONS (March 3, 2000):
On March 3, 2000, the U.S. Court of Appeals for the District of
Columbia Circuit (Appeals Court) issued a decision generally
upholding Federal EPA's final rule (the NOx rule) that requires
substantial reductions in nitrogen oxide (NOx) emissions in 22
eastern states, including the states in which the Company's
generating plants are located. A number of utilities, including the
AEP System companies, had filed petitions seeking a review of the
final rule in the Appeals Court. On May 25, 1999, the Appeals
Court had indefinitely stayed the requirement that states develop
revised air quality programs to impose the NOx reductions but did
not, however, stay the final compliance date of May 1, 2003.
On April 30, 1999, Federal EPA took final action with respect
to petitions filed by eight northeastern states pursuant to the
Clean Air Act (Section 126 Rule). The rule approved portions of
the states' petitions and imposed NOx reduction requirements on AEP
System generating units which are approximately equivalent to the
reductions contemplated by the NOx Rule. The AEP System companies
with generating plants, as well as other utility companies, filed
a petition in the Appeals Court seeking review of Federal EPA's
approval of the northeastern states' petitions. In 1999, three
additional northeastern states and the District of Columbia filed
petitions with Federal EPA similar to those originally filed by the
eight northeastern states. Since the petitions relied in part on
compliance with an 8-hour ozone standard remanded by the Appeals
Court in May 1999, Federal EPA indicated its intent to decouple
compliance with the 8-hour standard and issue a revised rule.
On December 17, 1999, Federal EPA issued a revised Section 126
Rule not based on the 8-hour standard and ordered 392 industrial
facilities, including certain coal-fired generating plants owned by
the Company, to reduce their NOx emissions by May 1, 2003. This
rule approves portions of the petitions filed by four northeastern
states which contend that their failure to meet Federal EPA smog
standards is due to emissions from upwind states' industrial and
coal-fired generating facilities.
Preliminary estimates indicate that compliance with the NOx
rule upheld by the Appeals Court could result in required capital
expenditures of approximately $202 million for the Company. Since
compliance costs cannot be estimated with certainty, the actual
cost to comply could be significantly different than the Company's
preliminary estimate depending upon the compliance alternatives
selected to achieve reductions in NOx emissions. Unless such costs
are recovered from customers through regulated rates and/or
reflected in the future market price of electricity if generation
is deregulated, they will have an adverse effect on future results
of operations, cash flows and possibly financial condition.
7. RELATED PARTY TRANSACTIONS:
Benefits and costs of the AEP System's generating plants are
shared by members of the AEP Power Pool of which the Company is a
member. Under the terms of the AEP System Interconnection
Agreement, capacity charges and credits are designed to allocate
the cost of the AEP System's capacity among the AEP Power Pool
members based on their relative peak demands and generating
reserves. AEP Power Pool members are also compensated for the
out-of-pocket costs of energy delivered to the AEP Power Pool and
charged for energy received from the AEP Power Pool. The Company
is a net supplier to the AEP Power Pool and, therefore, receives
capacity credits from the AEP Power Pool.
Operating revenues include revenues for capacity and energy
supplied to the AEP Power Pool as follows:
Year Ended December 31,
1999 1998 1997
(in thousands)
Capacity Revenues $42,575 $33,011 $ 53,282
Energy Revenues 8,049 4,550 64,861
Total $50,624 $37,561 $118,143
Purchased power expense includes charges of $112.3 million in
1999, $125.2 million in 1998 and $51 million in 1997 for energy
received from the AEP Power Pool.
The AEP Power Pool allocates operating revenues, purchased
power expense and nonoperating income to the Company. Power
marketing and trading operations, which are described in Note 1,
are conducted by the AEP Power Pool and shared with the Company.
Net trading transactions are included in operating revenues if the
trading transactions are within the AEP Power Pool's traditional
marketing area and are recorded in nonoperating income if the net
trading transactions are outside of the AEP Power Pool's
traditional marketing area. The total amount allocated by the AEP
Power Pool, which includes amounts for power marketing and trading
transactions, are as follows:
Year Ended December 31,
1999 1998 1997
(in thousands)
Operating Revenues $81,659 $124,973 $74,895
Purchased Power Expense 66,285 71,588 15,415
Nonoperating Income (Loss) 2,104 (7,122) (61)
The cost of Rockport Plant power purchased from AEGCo, an
affiliated company that is not a member of the AEP Power Pool, was
included in purchased power expense in the amounts of $88.1
million, $86.2 million and $87.5 million in 1999, 1998 and 1997,
respectively.
The cost of power purchased from Ohio Valley Electric
Corporation, an affiliated company that is not a member of the AEP
Power Pool, was included in purchased power expense in the amounts
of $10.2 million, $14.3 million and $11 million in 1999, 1998 and
1997, respectively.
The Company operates the Rockport Plant and bills AEGCo for its
share of operating costs.
The Company participates in the AEP System Transmission
Equalization Agreement along with other AEP System electric
operating utility companies. This agreement combines certain AEP
System companies' investments in transmission facilities and shares
the costs of ownership in proportion to the AEP System companies'
respective peak demands. Pursuant to the terms of the agreement,
since the Company's relative investment in transmission facilities
is greater than its relative peak demand, other operation expense
includes equalization credits of $43.9 million, $44.1 million and
$46.1 million in 1999, 1998 and 1997, respectively.
Revenues from providing barging services were recorded in
nonoperating income as follows:
Year Ended December 31,
1999 1998 1997
(in thousands)
Affiliated Companies $28,100 $23,494 $24,427
Unaffiliated Companies 15,700 12,490 8,383
Total $43,800 $35,984 $32,810
American Electric Power Service Corporation (AEPSC) provides
certain managerial and professional services to AEP System
companies including the Company. The costs of the services are
billed by AEPSC to its affiliated companies on a direct-charge
basis whenever possible and on reasonable bases of proration for
shared services. The billings for services are made at cost and
include no compensation for the use of equity capital, which is
furnished to AEPSC by AEP Co., Inc. Billings from AEPSC are
capitalized or expensed depending on the nature of the services
rendered. AEPSC and its billings are subject to the regulation of
the SEC under the 1935 Act.
8. STAFF REDUCTIONS:
During 1998 an internal evaluation of the power generation
organization was conducted with a goal of developing an optimum
organizational structure for a competitive generation market. The
study was completed in October 1998. In addition, a review of
energy delivery staffing levels was conducted in 1998. As a result
approximately 80 power generation and energy delivery positions
were identified for elimination.
A provision for severance costs totaling $3.7 million was
recorded in December 1998 for reductions in power generation and
energy delivery staffs and was charged to maintenance and other
operation expense in the Consolidated Statements of Income. The
power generation and energy delivery staff reductions were made in
the first quarter of 1999. The amount of severance benefits paid
was not significantly different from the amount accrued.
9. BENEFIT PLANS:
The Company and its subsidiaries participate in the AEP System
qualified pension plan, a defined benefit plan which covers all
employees. Net pension (credits) costs for the years ended
December 31, 1999, 1998 and 1997 were $(1.3) million, $2.1 million
and $2.1 million, respectively.
Postretirement benefits other than pensions are provided for
retired employees for medical and death benefits under an AEP
System plan. The Company's annual accrued costs for 1999, 1998 and
1997 were $13.7 million, $12 million and $11.5 million,
respectively.
A defined contribution employee savings plan required that the
Company make contributions to the plan totaling $4 million each
year in 1999, 1998 and 1997.
<PAGE>
10. SEGMENT INFORMATION:
Effective December 31, 1998, the Company adopted SFAS 131,
"Disclosures about Segments of an Enterprise and Related
Information". The Company has one reportable segment, a regulated
vertically integrated electricity generation and energy delivery
business. All other activities are insignificant. The Company's
operations are managed on an integrated basis because of the
substantial impact of bundled cost-based rates and regulatory
oversight on business processes, cost structures and operating
results. Aggregated in the regulated electric utility segment is
the power marketing and trading activities that are discussed in
Note 1. For the years ended December 31, 1999, 1998 and 1997, all
revenues are derived in the U.S.
11. FINANCIAL INSTRUMENTS, CREDIT AND RISK MANAGEMENT:
The Company is subject to market risk as a result of changes in
electricity commodity prices and interest rates. The Company
through its membership in the AEP Power Pool participates in a
power marketing and trading operation that manages the exposure to
electricity commodity price movements using physical forward
purchase and sale contracts at fixed and variable prices, and
financial derivative instruments including exchange traded futures
and options, over-the-counter options, swaps and other financial
derivative contracts at both fixed and variable prices. Physical
forward electricity contracts within the AEP Power Pool's
traditional marketing area are recorded on a net basis as operating
revenues in the month when the physical contract settles. The
Company's share of the net gains from these regulated transactions
for the year ended December 31, 1999 and 1998 was $4 million and
$21 million, respectively. These activities were not material in
1997.
Non-regulated physical forward electricity contracts outside
the AEP Power Pool's traditional marketing area and all financial
electricity trading transactions where the underlying physical
commodity is outside AEP's traditional marketing area are recorded
in nonoperating income. Non-regulated open trading contracts are
accounted for on a mark-to-market basis in nonoperating income.
The Company's share of the net gains (losses) from these
non-regulated trading transactions for the year ended December 31, 1999
and 1998 was $2 million and $(7) million, respectively.
In the first quarter of 1999 the Company adopted EITF 98-10
"Accounting for Contracts Involved in Energy Trading and Risk
Management Activities." The EITF requires that all energy trading
contracts be marked-to-market. The effect on the consolidated
Statements of Income of marking open trading contracts to market is
deferred as regulatory assets or liabilities for those open trading
transactions within the AEP Power Pool's marketing area that are
included in the cost of service on a settlement basis for
rate-making purposes. The unrealized mark-to-market gains and losses
from trading of financial instruments are reported as assets and
liabilities, respectively. These activities were not material in
prior periods.
The Company is exposed to risk from changes in interest rates
primarily due to short-term and long-term borrowings used to fund
its business operations. The debt portfolio has both fixed and
variable interest rates with terms from one day to 39 years and an
average duration of five years at December 31, 1999. A near term
change in interest rates should not materially affect results of
operations or financial position since the Company would not expect
to liquidate its entire debt portfolio in a one year holding
period.
Market Valuation
The book value of cash and cash equivalents, accounts
receivable, short-term debt and accounts payable approximate fair
value because of the short-term maturity of these instruments. The
book value of the pre-April 1983 spent nuclear fuel disposal
liability approximates the Company's best estimate of its fair
value.
The book value amounts and fair values of the Company's
significant financial instruments at December 31, 1999 and 1998 are
summarized in the following table. The fair values of long-term
debt and preferred stock are based on quoted market prices for the
same or similar issues and the current dividend or interest rates
offered for instruments of the same remaining maturities. The fair
value of those financial instruments that are marked-to-market are
based on management's best estimates using over-the-counter
quotations, exchange prices, volatility factors and valuation
methodology. The estimates presented herein are not necessarily
indicative of the amounts that the Company could realize in a
current market exchange.
<TABLE>
<CAPTION>
1999 1998
Book Value Fair Value Book Value Fair Value
(in thousands) (in thousands)
Non-Derivatives
<S> <C> <C> <C> <C>
Long-term Debt $1,324,326 $1,283,300 $1,175,789 $1,235,200
Preferred Stock 64,945 63,500 68,445 72,600
</TABLE>
<TABLE>
Derivatives
<CAPTION>
1999 1998
Notional Fair Average Notional Fair Average
Amount Value Fair Value Amount Value Fair Value
(Dollars in thousands)
Trading Assets
GWH GWH
<S> <C> <C> <C> <C> <C> <C>
Electric
NYMEX Futures
and Options 43 $ 340 $ 171 - $ - $ -
Physicals 13,592 112,830 99,621 11,097 8,700 7,700
Options 1,213 8,010 12,125 734 6,300 15,300
Swaps 35 76 61 52 600 200
Trading Liabilities
GWH GWH
Electric
NYMEX Futures
and Options - $ - $ - 133 $(1,300) $ (300)
Physicals 14,620 (105,169) (95,948) 10,932 (9,400) (8,800)
Options 1,742 (8,391) (11,010) 557 (5,700) (15,200)
Swaps 35 (70) (58) 93 (1,400) (400)
</TABLE>
Credit and Risk Management
In addition to market risk associated with price movements, the
Company through the AEP Power Pool is also subject to the credit
risk inherent in its risk management activities. Credit risk
refers to the financial risk arising from commercial transactions
and/or the intrinsic financial value of contractual agreements with
trading counter parties, by which there exists a potential risk of
nonperformance. The AEP Power Pool has established and enforced
credit policies that minimize this risk. The AEP Power Pool
accepts as counter parties to forwards, futures, and other
derivative contracts primarily those entities that are classified
as Investment Grade, or those that can be considered as such due to
the effective placement of credit enhancements and/or collateral
agreements. Investment grade is the designation given to the four
highest debt rating categories (i.e., AAA, AA, A, BBB) of the major
rating services, e.g., ratings BBB- and above at Standard & Poor's
and Baa3 and above at Moody's. When adverse market conditions have
the potential to negatively affect a counter party's credit
position, the AEP Power Pool requires further credit enhancements
to mitigate risk. Since the formation of the power marketing and
trading business in July of 1997, the Company has experienced no
significant losses due to the credit risk associated with risk
management activities; furthermore, the Company does not anticipate
any future material effect on its results of operations, cash flow
or financial condition as a result of counter party nonperformance.
Nuclear Trust Funds Recorded at Market Value
The Nuclear Decommissioning and SNF Disposal Trust Fund
investments are recorded at market value in accordance with SFAS
115 and consist of tax-exempt municipal bonds and other securities.
At December 31, 1999 and 1998 the fair values of trust fund
investments were $708 million and $648 million, respectively.
Accumulated gross unrealized holding gains were $78 million and $65
million and accumulated gross unrealized holding losses were $6.7
million and $1.1 million at December 31, 1999 and 1998,
respectively. The change in market value in 1999, 1998 and 1997
was a net unrealized holding gain of $7.5 million, $24 million and
$19.1 million, respectively.
<PAGE>
The trust fund investments' cost basis by security type were:
December 31,
1999 1998
(in thousands)
Tax-Exempt Bonds $350,798 $326,239
Equity Securities 116,110 95,854
Treasury Bonds 72,927 71,194
Corporate Bonds 13,162 10,661
Cash, Cash Equivalents
and Interest Accrued 83,129 80,065
Total $636,126 $584,013
Proceeds from sales and maturities of securities of $226
million during 1999 resulted in $5.8 million of realized gains and
$5.3 million of realized losses. Proceeds from sales and
maturities of securities of $225 million during 1998 resulted in
$8.2 million of realized gains and $2.8 million of realized losses.
Proceeds from sales and maturities of securities of $147.3 million
during 1997 resulted in $3.9 million of realized gains and $1.4
million of realized losses. The cost of securities for determining
realized gains and losses is original acquisition cost including
amortized premiums and discounts.
At December 31, 1999, the year of maturity of trust fund
investments, other than equity securities, was:
(in thousands)
2000 $120,630
2001-2004 173,851
2005-2009 181,860
After 2009 43,675
Total $520,016
<TABLE>
12. FEDERAL INCOME TAXES:
<CAPTION>
The details of federal income taxes as reported are as follows:
Year Ended December 31,
1999 1998 1997
(in thousands)
<S> <C> <C> <C>
Charged (Credited) to Operating Expenses (net):
Current $(60,238) $ 38,165 $ 75,442
Deferred 85,345 21,073 3,088
Deferred Investment Tax Credits (7,547) (7,593) (7,786)
Total 17,560 51,645 70,744
Charged (Credited) to Nonoperating Income (net):
Current 1,529 (594) 3,287
Deferred 382 (3,168) 834
Deferred Investment Tax Credits (605) (673) (642)
Total 1,306 (4,435) 3,479
Total Federal Income Taxes as Reported $ 18,866 $ 47,210 $ 74,223
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,
1999 1998 1997
(in thousands)
Net Income $ 32,776 $ 96,628 $146,740
Federal Income Taxes 18,866 47,210 74,223
Pre-tax Book Income $ 51,642 $143,838 $220,963
Federal Income Tax on Pre-tax Book Income at
Statutory Rate (35%) $18,075 $50,343 $77,337
Increase (Decrease) in Federal Income Tax
Resulting From the Following Items:
Depreciation 19,966 17,257 14,082
Corporate Owned Life Insurance 594 (3,263) (3,348)
Nuclear Fuel Disposal Costs (3,347) (3,397) (3,286)
AFUDC (2,174) (2,184) (1,987)
Investment Tax Credits (net) (8,152) (8,266) (8,428)
Other (6,096) (3,280) (147)
Total Federal Income Taxes as Reported $18,866 $47,210 $74,223
Effective Federal Income Tax Rate 36.5% 32.8% 33.6%
</TABLE>
The following tables show the elements of the net deferred tax
liability and the significant temporary differences giving rise to
such deferrals:
December 31,
1999 1998
(in thousands)
Deferred Tax Assets $ 231,329 $ 226,118
Deferred Tax Liabilities (853,486) (785,406)
Net Deferred Tax Liabilities $(622,157) $(559,288)
Property Related
Temporary Differences $(436,162) $(460,077)
Amounts Due From Customers
For Future Federal
Income Taxes (61,311) (69,102)
Deferred State Income Taxes (61,700) (62,302)
Deferred Gain on Sale and
Leaseback of Rockport
Plant Unit 2 29,752 31,049
Accrued Nuclear
Decommissioning Expense 32,097 29,930
Deferred Fuel and
Purchased Power (52,713) (22,737)
Deferred Cook Plant
Restart Costs (56,000) -
All Other (net) (16,120) (6,049)
Net Deferred Tax Liabilities $(622,157) $(559,288)
The Company and its subsidiaries join in the filing of a
consolidated federal income tax return with their affiliates in the
AEP System. The allocation of the AEP System's current
consolidated federal income tax to the AEP System companies is in
accordance with SEC rules under the 1935 Act. These rules permit
the allocation of the benefit of current tax losses to the System
companies giving rise to them in determining their current tax
expense. The tax loss of the parent company, AEP Co., Inc., is
allocated to its subsidiaries with taxable income. With the
exception of the loss of the parent company, the method of
allocation approximates a separate return result for each company
in the consolidated group.
The AEP System has settled with the IRS all issues from the
audits of the consolidated federal income tax returns for the years
prior to 1991. Returns for the years 1991 through 1996 are
presently being audited by the IRS. With the exception of interest
deductions related to COLI, which are discussed under the heading
"Litigation" in Note 5, management is not aware of any issues for
open tax years that upon final resolution are expected to have a
material adverse effect on results of operations.
13. CUMULATIVE PREFERRED STOCK:
At December 31, 1999, authorized shares of cumulative
preferred stock were as follows:
Par Value Shares Authorized
$100 2,250,000
25 11,200,000
The cumulative preferred stock is callable at the price
indicated below plus accrued dividends. The involuntary
liquidation preference is par value. Unissued shares of the
cumulative preferred stock may or may not possess mandatory
redemption characteristics upon issuance.
<TABLE>
A. Cumulative Preferred Stock Not Subject to Mandatory Redemption:
<CAPTION>
Call Price Shares Amount
December 31, Par Number of Shares Redeemed Outstanding December 31,
Series 1999 Value Year Ended December 31, December 31, 1999 1999 1998
1999 1998 1997 (in thousands)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
4-1/8% $106.125 $100 97 771 59,760 59,139 $5,914 $5,924
4.56% 102 100 150 650 44,788 14,412 1,441 1,456
4.12% 102.728 100 - 200 20,869 18,931 1,893 1,893
$9,248 $9,273
</TABLE>
<TABLE>
B. Cumulative Preferred Stock Subject to Mandatory Redemption:
<CAPTION>
Shares Amount
Par Number of Shares Redeemed Outstanding December 31,
Series(a) Value Year Ended December 31, December 31, 1999 1999 1998
1999 1998 1997 (in thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
5.90% (b) $100 15,000 - 233,000 152,000 $15,200 $16,700
6-1/4%(b) 100 10,000 - 97,500 192,500 19,250 20,250
6.30% (b) 100 - - 217,550 132,450 13,245 13,245
6-7/8%(c) 100 10,000 - 117,500 172,500 17,250 18,250
$64,945 $68,445
(a) Not callable until after 2002. There are no aggregate sinking
fund provisions through 2002. Sinking fund provisions require the
redemption of 15,000 shares in 2003 and 67,500 shares in 2004.
(b) Commencing in 2004 and continuing through 2008 the Company may
redeem, at $100 per share, 20,000 shares of the 5.90% series,
15,000 shares of the 6-1/4% series and 17,500 shares of the 6.30%
series outstanding under sinking fund provisions at its option and
all remaining outstanding shares must be redeemed not later than
2009. Shares redeemed in 1999 and 1997 may be applied to meet the
sinking fund requirement.
(c) Commencing in 2003 and continuing through the year 2007, a
sinking fund will require the redemption of 15,000 shares each year
and the redemption of the remaining shares outstanding on April 1,
2008, in each case at $100 per share. Shares redeemed in 1999 and
1997 may be applied to meet the sinking fund requirement.
</TABLE>
14. LONG-TERM DEBT AND LINES OF CREDIT:
Long-term debt by major category was outstanding as follows:
December 31,
1999 1998
(in thousands)
First Mortgage Bonds $ 356,820 $ 466,330
Installment Purchase
Contracts 309,568 309,418
Senior Unsecured Notes 297,282 48,559
Other Long-term Debt (a) 199,259 190,192
Junior Debentures 161,397 161,290
1,324,326 1,175,789
Less Portion Due Within
One Year 198,000 35,000
Total $1,126,326 $1,140,789
(a) Represents a SNF disposal liability including interest accrued
payable to the Department of Energy. See Note 5.
First mortgage bonds outstanding were as follows:
December 31,
1999 1998
(in thousands)
% Rate Due
7.30 1999 - December 15 $ - $ 35,000
6.40 2000 - March 1 48,000 48,000
7.63 2001 - June 1 40,000 40,000
7.60 2002 - November 1 50,000 50,000
7.70 2002 - December 15 40,000 40,000
6.80 2003 - July 1 - 20,000
6.55 2003 - October 1 - 20,000
6.10 2003 - November 1 30,000 30,000
6.55 2004 - March 1 - 25,000
8.50 2022 - December 15 75,000 75,000
7.35 2023 - October 1 20,000 20,000
7.20 2024 - February 1 30,000 40,000
7.50 2024 - March 1 25,000 25,000
Unamortized Discount (net) (1,180) (1,670)
356,820 466,330
Less Portion Due Within One Year 48,000 35,000
Total $308,820 $431,330
Certain indentures relating to the first mortgage bonds
contain improvement, maintenance and replacement provisions
requiring the deposit of cash or bonds with the trustee, or in lieu
thereof, certification of unfunded property additions.
Installment purchase contracts have been entered into in
connection with the issuance of pollution control revenue bonds by
governmental authorities as follows:
December 31,
1999 1998
(in thousands)
% Rate Due
City of Lawrenceburg, Indiana:
7.00 2015 - April 1 $ 25,000 $ 25,000
5.90 2019 - November 1 52,000 52,000
City of Rockport, Indiana:
(a) 2014 - August 1 50,000 50,000
7.60 2016 - March 1 40,000 40,000
6.55 2025 - June 1 50,000 50,000
(b) 2025 - June 1 50,000 50,000
City of Sullivan, Indiana:
5.95 2009 - May 1 45,000 45,000
Unamortized Discount (2,432) (2,582)
309,568 309,418
Less Portion Due Within
One Year 50,000 -
Total $259,568 $309,418
(a) A variable interest rate is determined weekly. The average
weighted interest rate was 3.2% for 1999 and 4.1% for 1998.
(b) An adjustable interest rate can be a daily, weekly, commercial
paper or term rate as designated by the Company. A weekly
rate was selected which ranged from 2.2% to 5.6% in 1999 and
from 2.7% to 4.3% in 1998 and averaged 3.2% and 3.6% during
1999 and 1998, respectively.
Under the terms of certain installment purchase contracts, the
Company is required to pay amounts sufficient to enable the cities
to pay interest on and the principal (at stated maturities and upon
mandatory redemption) of related pollution control revenue bonds
issued to finance the construction of pollution control facilities
at certain generating plants. On the two variable rate series the
principal is payable at the stated maturities or on the demand of
the bondholders at periodic interest adjustment dates which occur
weekly. The variable rate bonds due in 2014 are supported by a
bank letter of credit which expires in 2002. I&M has agreements
that provide for brokers to remarket the adjustable rate bonds due
in 2025 tendered at interest adjustment dates. In the event
certain bonds cannot be remarketed, I&M has a standby bond
purchase agreement with a bank that provides for the bank to
purchase any bonds not remarketed. The purchase agreement expires
in 2000. Accordingly, the variable and adjustable rate installment
purchase contracts have been classified for repayment purposes
based on the expiration dates of the standby purchase agreement and
the letter of credit.
Senior unsecured notes outstanding were as follows:
December 31,
1999 1998
(in thousands)
% Rate Due
(a) 2000 - November 22 $100,000 $ -
6-7/8 2004 - July 1 150,000 -
6.45 2008 - November 10 50,000 50,000
Unamortized Discount (2,718) (1,441)
297,282 48,559
Less Portion Due Within One Year 100,000 -
Total $197,282 $48,559
(a) A floating interest rate is determined monthly. The rate on
December 31, 1999 was 7.1%.
<PAGE>
Junior debentures are composed of the following:
December 31,
1999 1998
(in thousands)
% Rate Due
8.00 2026 - March 31 $ 40,000 $ 40,000
7.60 2038 - June 30 125,000 125,000
Unamortized Discount (3,603) (3,710)
Total $161,397 $161,290
Interest may be deferred and payment of principal and interest
on the junior debentures is subordinated and subject in right to
the prior payment in full of all senior indebtedness of the
Company.
At December 31, 1999, future annual long-term debt payments
are as follows:
Amount
(in thousands)
2000 $ 198,000
2001 40,000
2002 140,000
2003 30,000
2004 150,000
Later Years 776,259
Total Principal Amount 1,334,259
Unamortized Discount (9,933)
Total $1,324,326
Short-term debt borrowings are limited by provisions of the
1935 Act to $500 million. Lines of credit are shared with AEP
System companies and at December 31, 1999 were available in the
amounts of $1,056 million. The short-term lines of credit require
the payment of facility fees and do not require compensating
balances. At December 31, 1999 and 1998, outstanding short-term
debt consisted of commercial paper with year-end weighted average
interest rates of 6.6% and 6.2%, respectively.
15. LEASES:
Leases of property, plant and equipment are for periods of up
to 35 years and require payments of related property taxes,
maintenance and operating costs. The majority of the leases have
purchase or renewal options and will be renewed or replaced by
other leases. The Company is leasing 50% of the 1,300 mw Rockport
2 generating unit under an operating lease. The lease has 23 years
remaining and total minimum lease payments of $1.7 billion.
Lease rentals for both operating and capital leases are
generally charged to operating expenses in accordance with rate-making
treatment. The components of rental costs are as follows:
Year Ended December 31,
1999 1998 1997
(in thousands)
Lease Payments on
Operating Leases $ 81,611 $ 88,297 $ 92,067
Amortization of Capital Leases 11,320 10,717 42,882
Interest on Capital Leases 9,338 10,302 9,737
Total Lease Rental Costs $102,269 $109,316 $144,686
Properties under capital leases and related obligations
recorded on the Consolidated Balance Sheets are as follows:
December 31,
1999 1998
(in thousands)
Electric Utility Plant Under Capital Leases:
Production Plant $ 8,348 $ 8,850
Transmission Plant 4 -
Distribution Plant 14,645 14,645
General Plant:
Nuclear Fuel (net of amortization) 108,140 103,939
Other Plant 59,150 60,002
Total Electric Utility Plant
Under Capital Leases 190,287 187,436
Accumulated Amortization 35,176 33,948
Net Electric Utility Plant
Under Capital Leases 155,111 153,488
Other Property Under Capital Leases 40,213 37,672
Accumulated Amortization 7,359 4,733
Net Other Property Under Capital Leases 32,854 32,939
Net Properties Under Capital Leases $187,965 $186,427
Capital Lease Obligations*:
Noncurrent Liability $176,893 $176,760
Liability Due Within One Year 11,072 9,667
Total Capital Lease Obligations $187,965 $186,427
* Represents the present value of future minimum lease payments.
The noncurrent portion of capital lease obligations is
included in other noncurrent liabilities on the Consolidated
Balance Sheets. Properties under operating leases and related
obligations are not included on the Consolidated Balance Sheets.
<PAGE>
Future minimum lease payments consisted of the following at
December 31, 1999:
Non-
Cancelable
Capital Operating
Leases Leases
(in thousands)
2000 $ 15,186 $ 100,288
2001 13,535 99,061
2002 16,116 97,341
2003 10,259 97,207
2004 8,641 96,395
Later Years 38,808 1,528,873
Total Future Minimum
Lease Payments 102,545 (a) $2,019,165
Less Estimated
Interest Element 22,720
Estimated Present
Value of Future
Minimum Lease
Payments 79,825
Unamortized Nuclear
Fuel 108,140
Total $187,965
(a) Excludes nuclear fuel rentals which are paid in proportion to
heat produced and carrying charges on the unamortized nuclear
fuel balance. There are no minimum lease payment requirements
for leased nuclear fuel.
16. COMMON SHAREHOLDER'S EQUITY:
Mortgage indentures, charter provisions and orders of
regulatory authorities place various restrictions on the use of
retained earnings for the payment of cash dividends on common
stock. At December 31, 1999, $5.9 million of retained earnings
were restricted. Regulatory approval is required to pay dividends
out of paid-in capital.
In 1999, 1998 and 1997 net changes to paid-in capital of
$134,000, $133,000 and $1,200,000 respectively, represented gains
and expenses associated with cumulative preferred stock
transactions.
<PAGE>
17. SUPPLEMENTARY INFORMATION:
Year Ended December 31,
1999 1998 1997
(in thousands)
Cash was paid (received) for:
Interest (net of
capitalized amounts) $ 78,703 $66,313 $ 62,274
Income Taxes (71,395) 36,413 120,212
Noncash Acquisitions
Under Capital Leases 10,852 9,658 111,395
18. UNAUDITED QUARTERLY FINANCIAL INFORMATION:
Net
Quarterly Periods Operating Operating Income
Ended Revenues Income (Loss)
(in thousands)
1999
March 31 $334,113 $38,838 $20,070
June 30 336,553 26,966 9,745
September 30 411,248 26,085 8,084
December 31 312,205 16,763 (5,123)
1998
March 31 328,468 51,368 33,744
June 30 348,271 42,194 28,536
September 30 412,908 58,639 38,691
December 31 316,147 13,806 (4,343)
Fourth quarter 1999 and 1998 net loss declined primarily as a
result of expenditures to prepare the nuclear units for restart.
Fourth quarter 1999 operating income include a favorable adjustment
of $21 million net of tax from the deferral of Cook Plant restart
expenses net of amortization under the terms of a Michigan
jurisdiction settlement agreement approved on December 16, 1999
(see Note 2 for details).
<PAGE>
Exhibit 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement No.
333-88523 of Indiana Michigan Power Company on Form S-3 of our reports dated
February 22, 2000 (March 3, 2000 as to Note 6), appearing in and incorporated
by reference in this Annual Report on Form 10-K of Indiana Michigan Power
Company for the year ended December 31, 1999.
Deloitte & Touche LLP
Columbus, Ohio
March 24, 2000
<PAGE>
Exhibit 24
POWER OF ATTORNEY
INDIANA MICHIGAN POWER COMPANY
Annual Report on Form 10-K for the Fiscal Year Ended
December 31, 1999
The undersigned directors of INDIANA MICHIGAN POWER COMPANY, an Indiana
corporation (the "Company"), do hereby constitute and appoint E. LINN DRAPER,
JR., ARMANDO A. PENA and HENRY W. FAYNE, and each of them, their
attorneys-in-fact and agents, to execute for them, and in their names, and in
any and all of their capacities, the Annual Report of the Company on Form
10-K, pursuant to Section 13 of the Securities Exchange Act of 1934, for the
fiscal year ended December 31, 1999, and any and all amendments thereto, and
to file the same, with all exhibits thereto and other documents in connection
therewith, with the Securities and Exchange Commission, granting unto said
attorneys-in-fact and agents, and each of them, full power and authority to
do and perform every act and thing required or necessary to be done, as fully
to all intents and purposes as the undersigned might or could do in person,
hereby ratifying and confirming all that said attorneys-in-fact and agents,
or any of them, may lawfully do or cause to be done by virtue hereof.
IN WITNESS WHEREOF, the undersigned have signed these presents this 2nd
day of March, 2000.
/s/ Karl G. Boyd /s/ Armando A. Pena
Karl G. Boyd Armando A. Pena
/s/ E. Linn Draper, Jr. /s/ John R. Sampson
E. Linn Draper, Jr. John R. Sampson
/s/ Jeffrey A. Drozda /s/ D. B. Synowiec
Jeffrey A. Drozda D. B. Synowiec
/s/ Henry W. Fayne /s/ J. H. Vipperman
Henry W. Fayne J. H. Vipperman
/s/ Wm. J. Lhota /s/ W. E. Walters
Wm. J. Lhota W. E. Walters
/s/ Mark W. Marano /s/ E. H. Wittkamper
Mark W. Marano E. H. Wittkamper
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000050172
<NAME> INDIANA MICHIGAN POWER COMPANY
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,575,630
<OTHER-PROPERTY-AND-INVEST> 921,625
<TOTAL-CURRENT-ASSETS> 422,579
<TOTAL-DEFERRED-CHARGES> 32,052
<OTHER-ASSETS> 624,810
<TOTAL-ASSETS> 4,576,696
<COMMON> 56,584
<CAPITAL-SURPLUS-PAID-IN> 732,739
<RETAINED-EARNINGS> 166,389
<TOTAL-COMMON-STOCKHOLDERS-EQ> 955,712
64,945
9,248
<LONG-TERM-DEBT-NET> 1,126,326
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 224,262
<LONG-TERM-DEBT-CURRENT-PORT> 198,000
0
<CAPITAL-LEASE-OBLIGATIONS> 176,893
<LEASES-CURRENT> 11,072
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,810,238
<TOT-CAPITALIZATION-AND-LIAB> 4,576,696
<GROSS-OPERATING-REVENUE> 1,394,119
<INCOME-TAX-EXPENSE> 10,429
<OTHER-OPERATING-EXPENSES> 1,275,038
<TOTAL-OPERATING-EXPENSES> 1,285,467
<OPERATING-INCOME-LOSS> 108,652
<OTHER-INCOME-NET> 4,530
<INCOME-BEFORE-INTEREST-EXPEN> 113,182
<TOTAL-INTEREST-EXPENSE> 80,406
<NET-INCOME> 32,776
4,885
<EARNINGS-AVAILABLE-FOR-COMM> 27,891
<COMMON-STOCK-DIVIDENDS> 114,656
<TOTAL-INTEREST-ON-BONDS> 31,442
<CASH-FLOW-OPERATIONS> 31,327
<EPS-BASIC> 0<F1>
<EPS-DILUTED> 0<F1>
<FN>
<F1> All common stock owned by parent company; no EPS required.
</FN>
</TABLE>
