<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>
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<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>
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<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
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<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>
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<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 10(p)
AMERICAN ELECTRIC POWER SERVICE CORPORATION
CHANGE IN CONTROL AGREEMENT
This Change In Control Agreement ("Agreement"), made as of this ____day of
___________, 2000, by and between American Electric Power Service Corporation, a
New York corporation, including any of its subsidiary companies, divisions,
organizations, or affiliated entities (collectively referred to as "AEPSC") and
______________, ________________, _______________ (the "Executive").
Whereas, AEPSC considers it essential to its best interests and the best
interests of the shareholders of the Corporation to foster the continued
employment of key management personnel; and
Whereas, the uncertainty attendant to a Change In Control of the
Corporation may result in the departure or distraction of management personnel
to the detriment of AEPSC and the shareholders of the Corporation; and
Whereas, the Board of the Corporation has determined that steps should be
taken to reinforce and encourage the continued attention and dedication of
members of AEPSC's management, including the Executive, to their assigned duties
in the event of a Change In Control of the Corporation.
Now Therefore, it is hereby agreed as follows:
ARTICLE I
DEFINITIONS
As used herein the following words and phrases shall have the following
respective meanings unless the context clearly indicates otherwise.
(a) "Annual Compensation" means the sum of the Executive's Annual Salary
and the Executive's Target Annual Incentive.
(b) "Annual Salary" means the Executive's regular annual base salary
immediately prior to the Executive's termination of employment, including
compensation converted to other benefits under a flexible pay arrangement
maintained by AEPSC or deferred pursuant to a written plan or agreement with
AEPSC, but excluding overtime pay, allowances, premium pay, compensation paid or
payable under any of AEPSC's long-term or short-term incentive plans or any
similar payments.
(c) "Board" means the Board of Directors of American Electric Power
Company, Inc.
(d) "Cause" shall mean
(i) the willful and continued failure of the Executive to perform
substantially the Executive's duties with AEPSC (other than any such
failure resulting from incapacity due to physical or mental
illness), after a written demand for substantial performance is
delivered to the Executive by the Board or an elected officer of
AEPSC which specifically identifies the manner in which the Board or
the elected officer believes that the Executive has not
substantially performed the Executive's duties, or
(ii) the willful engaging by the Executive in illegal conduct or
gross misconduct which is materially and demonstrably injurious to
AEPSC or the Corporation, as determined by the Board.
For purposes of this provision, no act or failure to act, on the part of
the Executive, shall be considered "willful" unless it is done, or omitted to be
done, by the Executive in bad faith or without reasonable belief that the
Executive's action or omission was in the best interests of AEPSC or the
Corporation. Any act, or failure to act, based upon authority given pursuant to
a resolution duly adopted by the Board or upon the advice of counsel for AEPSC
or the Corporation, shall be conclusively presumed to be done, or omitted to be
done, by the Executive in good faith and in the best interests of AEPSC or the
Corporation
(e) "Change In Control" of the Corporation shall be deemed to have
occurred if (i) any "person" or "group" (as such terms are used in Section 13(d)
and 14(d) of the Securities Exchange Act of 1934 ("Exchange Act"), other than
AEPSC, any company owned, directly or indirectly, by the shareholders of the
Corporation in substantially the same proportions as their ownership of stock of
the Corporation or a trustee or other fiduciary holding securities under an
employee benefit plan of the Corporation, becomes the "beneficial owner" (as
defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of more
than 25 percent of the then outstanding voting stock of the Corporation; (ii)
during any period of two consecutive years, individuals who at the beginning of
such period constitute the Board, together with any new directors (other than a
director nominated by a person (x) who has entered into an agreement with the
Corporation to effect a transaction described in Article 1(e)(i), (iii) or (iv)
hereof or (y) who publicly announces an intention to take or to consider taking
action (including, but not limited to, an actual or threatened proxy contest)
which if consummated would constitute a Change In Control) whose election or
nomination for election was approved by a vote of at least two-thirds of the
directors then still in office who were either directors at the beginning of the
period or whose election or nomination for election was previously so approved,
cease for any reason, except for death or disability, to constitute at least a
majority of the Board; or (iii) the consummation of a merger or consolidation of
the Corporation with any other entity, other than a merger or consolidation
which would result in the voting securities of the Corporation outstanding
immediately prior thereto continuing to represent (either by remaining
outstanding or by being converted into voting securities of the surviving
entity) at least 50 percent of the total voting power represented by the voting
securities of the Corporation or such surviving entity outstanding immediately
after such merger or consolidation; or (iv) the shareholders of the Corporation
approve a plan of complete liquidation of the Corporation, or an agreement for
the sale or disposition by the Corporation (in one transaction or a series of
transactions) of all or substantially all of the Corporation's assets.
Notwithstanding the foregoing, a Change In Control shall not be deemed to
occur as a result of the consummation of the transactions contemplated in the
Agreement and Plan of Merger by and among the American Electric Power Company,
Inc., Augusta Acquisition Corporation and Central and South West Corporation
dated as of December 21, 1997, nor thereafter as a result of any event in (i) or
(iii) above, if directors who were members of the Board prior to such event and
continue to constitute a majority of the Board after such event.
(f) "Code" means the Internal Revenue Code of 1986, as amended from time
to time.
(g) "Commencement Date" means the date of this Agreement, which shall be
the beginning date of the term of this Agreement.
(h) "Corporation" means American Electric Power Company, Inc., a New York
corporation.
(i) "Disability" means the Executive's total and permanent disability as
defined in AEPSC's long-term disability plan covering the Executive immediately
prior to the Change In Control.
(j) "Good Reason" means;
(1) an adverse change in the Executive's status, duties or
responsibilities as an executive of AEPSC as in effect immediately prior
to the Change In Control, provided that the Executive shall have given
AEPSC written notice of the alleged adverse change and AEPSC shall have
failed to cure such change within thirty (30) days after its receipt of
such notice;
(2) failure of AEPSC to pay or provide the Executive in a timely
fashion the salary or benefits to which the Executive is entitled under
any employment agreement between AEPSC and the Executive in effect on the
date of the Change In Control, or under any benefit plans or policies in
which the Executive was participating at the time of the Change In
Control, provided that such failure was other than an isolated,
insubstantial and inadvertent action not taken in bad faith and which is
remedied by the Corporation within eight days following notice from the
Executive;
(3) the reduction of the Executive's salary as in effect on the date
of the Change In Control;
(4) the taking of any action by AEPSC (including the elimination of
a plan without providing substitutes therefore, the reduction of the
Executive's awards thereunder or failure to continue the Executive's
participation therein) that would substantially diminish the aggregate
projected value of the Executive's awards or benefits under AEPSC's
benefit plans or policies in which the Executive was participating at the
time of the Change In Control;
(5) a failure by AEPSC or the Corporation to obtain from any
successor the assent to this Agreement contemplated by Article IV hereof;
or
(6) the relocation, without the Executive's prior approval, of the
office at which the Executive is to perform services on behalf of AEPSC to
a location more than fifty (50) miles from its location immediately prior
to the Change In Control or a change, without the Executive's prior
approval, in the Executive's business travel obligation subsequent to the
Change In Control that requires the Executive to travel on a regular and
continuous basis in an amount that represents a significant increase, from
immediately prior to the Change In Control, in the portion of the
Executive's working time routinely devoted to business travel.
Any circumstance described in this Article I (j) shall constitute Good
Reason even if such circumstance would not constitute a breach by AEPSC of the
terms of an employment agreement between AEPSC and the Executive in effect on
the date of the Change In Control. The Executive shall be deemed to have
terminated employment for Good Reason effective upon the effective date stated
in a written notice of such termination given by the Executive to AEPSC (which
notice shall not be given, in circumstances described in Article I (j)(1),
before the end of the thirty (30) day period described therein, or in
circumstances described in Article I(j)(2), before the end of the eight day
period described therein), setting forth in reasonable detail the facts and
circumstances claimed to provide the basis for termination, provided that the
effective date may not precede, nor be more than sixty (60) days from, the date
such notice is given. The Executive's continued employment shall not constitute
consent to, or a waiver of rights with respect to, any circumstances
constituting Good Reason hereunder.
(k) "Retirement" shall mean a termination of employment due to the
Executive's voluntary late, normal or early retirement under a pension plan
sponsored by AEPSC as defined in such plan.
(l) "Target Annual Incentive" shall mean the award that the Executive
would have received under the Senior Officer Annual Incentive Compensation Plan,
the AEP Energy Services, Inc. Incentive Compensation Plan or the Management
Incentive Compensation Plan for the year in which the Executive's termination
occurs, if one hundred percent (100%) of the annual target award has been
earned.
(m) "Qualifying Termination" shall mean following a Change In Control and
during the term of this Agreement the Executive's employment is terminated for
any reason excluding (i) the Executive's death, (ii) the Executive's Disability,
(iii) the Executive's Retirement, (iv) by AEPSC for Cause or (v) by the
Executive without Good Reason. In addition, a Qualifying Termination shall be
deemed to have occurred if, prior to a Change In Control, the Executive's
employment was terminated during the term of this Agreement by AEPSC without
Cause, or by the Executive for Good Reason based on events or circumstances that
occurred, (i) at the request of a person who has entered into an agreement with
AEPSC or the Corporation, the consummation of which would constitute a Change In
Control or (ii) otherwise in connection with, as a result of or in anticipation
of a Change In Control. The mere act of approving a Change In Control agreement
shall not in and of itself be deemed to constitute an event or circumstance in
anticipation of a Change In Control for purposes of this Article I(m).
ARTICLE II
TERM OF AGREEMENT
2.1 The term of this Agreement shall initially be for the period beginning
on the Commencement Date and ending on the day before the first anniversary of
the Commencement Date. The term of this Agreement shall automatically be
extended on the first anniversary of the Commencement Date until the day before
the second anniversary of the Commencement Date without further action by the
parties, and shall be automatically extended by an additional year on each
succeeding anniversary of the Commencement Date, unless either AEPSC or the
Executive shall have served notice upon the other party at least sixty (60) days
prior to such anniversary of its or the Executive's intention that this
Agreement shall not be extended, provided, however, that if a Change In Control
of the Corporation shall occur during the term of this Agreement, this Agreement
shall terminate two years after the date the Change In Control is completed.
2.2 Notwithstanding Section 2.1, the term of this Agreement shall end upon
any termination of the Executive's employment prior to a Change In Control of
the Corporation.
ARTICLE III
COMPENSATION UPON A CHANGE IN CONTROL FOLLOWED BY A TERMINATION
3.1 Upon a Qualifying Termination, the Executive shall be under no further
obligation to perform services for AEPSC and shall be entitled to receive the
following payments and benefits:
(a) Within ten (10) days of the Executive's date of termination, AEPSC
shall make a lump sum cash payment to the Executive in an amount
equal to the sum of (1) the Executive's Annual Salary through the
date of termination to the extent not theretofore paid, (2) the
product of (x) the Target Annual Incentive and (y) a fraction, the
numerator of which is the number of days in such calendar year
through the date of termination, and the denominator of which is
365, and (3) any accrued vacation pay, in each case the extent not
theretofore paid and in full satisfaction of the rights of the
Executive thereto;
(b) Within ten (10) days of the Executive's date of termination, AEPSC
shall make a lump sum cash payment to the Executive in an amount
equal to three times the Executive's Annual Compensation; and
(c) For purposes of the American Electric Power System Excess Benefit
Plan, or any successor thereto, provided that the Executive is a
participant thereunder, the Executive shall be credited with three
(3) additional years of service; provided that if the Executive is
older than age 62 as of the Executive's date of termination the
additional years of service shall be limited to the difference
between the Executive's age as of the date of termination and the
date the Executive would attain age 65, and assuming that the
Executive's compensation for the additional period of service would
have been equal to the Executive's compensation in effect as of the
Executive's date of termination.
3.2 The Executive shall be entitled to the continuing benefits as follows:
(a) For the three (3) year period following the Executive's date of
termination, the Executive and the Executive's family shall be
provided with medical and dental insurance benefits as if the
Executive's employment had not been terminated; provided, however,
that if the Executive becomes reemployed with another employer and
is eligible to receive medical or other welfare benefits under
another employer-provided plan, the medical and other welfare
benefits described herein shall be secondary to those provided under
such other plan during such applicable period of eligibility. For
purposes of determining eligibility (but not the time of
commencement of benefits) of the Executive for retiree medical and
dental insurance benefits under AEPSC's plans, practices, programs
and policies, the Executive shall be considered to have remained
employed during the three (3) year period and to have retired on the
last day of the three (3) year period;
(b) AEPSC shall, at its sole expense as incurred, provide the Executive
with outplacement services the scope and provider of which shall be
selected by the Executive in the Executive's sole discretion (but at
a cost to AEPSC of not more that $30,000) or, at the Executive's
option, the use of comparable and accessible office space, office
supplies and equipment and secretarial services for a period not to
exceed one year, which in the aggregate are of comparable cost to
the Corporation as the outplacement services; and
(c) AEPSC shall transfer to the Executive, at no cost to the Executive,
the title to AEPSC's car being used by the Executive as of the date
of termination.
(d) To the extent any benefits described in this Article III, Section
3.2 cannot be provided pursuant to the appropriate plan or program
maintained by AEPSC, AEPSC shall provide such benefits outside such
plan or program at no additional cost (including without limitation
tax cost) to the Executive.
3.3 Notwithstanding the foregoing;
(a) The severance payments and benefits provided under Sections 3.1 and
3.2 hereof shall be subject to, and conditioned upon, the waiver of
any other cash severance payment or other benefits provided by AEPSC
pursuant to any other severance agreement between AEPSC and the
Executive. No amount shall be payable under this Agreement to, or
on behalf of the Executive, if the Executive elects benefits under
any other cash severance plan or program, or any other special pay
arrangement with respect to the termination of the Executive's
employment.
(b) The Executive agrees that at all times following termination, the
Executive will not, without the prior written consent of AEPSC or
the Corporation, disclose to any person, firm or corporation any
"confidential information," of AEPSC or the Corporation which is now
known to the Executive or which hereafter may become known to the
Executive as a result of the Executive's employment or association
with AEPSC or the Corporation, unless such disclosure is required
under the terms of a valid and effective subpoena or order issued by
a court or governmental body; provided, however, that the foregoing
shall not apply to confidential information which becomes publicly
disseminated by means other than a breach of this provision. It is
recognized that damages in the event of breach of this Section
3.3(ii) by the Executive would be difficult, if not impossible, to
ascertain, and it is therefore agreed that AEPSC and the
Corporation, in addition to and without limiting any other remedy or
right that AEPSC or the Corporation may have, shall have the right
to an injunction or other equitable relief in any court of competent
jurisdiction, enjoining any such breach, and the Executive hereby
waives any and all defenses the Executive may have on the ground of
lack of jurisdiction or competence of the court to grant such an
injunction or other equitable relief. The existence of this
right shall not preclude AEPSC or the Corporation from pursuing any
other rights or remedies at law or in equity which AEPSC or the
Corporation may have.
"Confidential information" shall mean any confidential concepts,
ideas, information and materials relating to AEPSC or the
Corporation, including, but not limited to, client records, client
lists, economic and financial analysis, financial data, customer
contracts, notes, memoranda, lists, books, correspondence, manuals,
reports or research, whether developed by AEPSC or the Corporation
or developed by the Executive acting alone or jointly with AEPSC or
the Corporation while the Executive was employed by AEPSC.
3.4 Notwithstanding anything to the contrary in this Agreement, in the
event that any payment or distribution by AEPSC to or for the benefit of the
Executive, whether paid or payable or distributed or distributable pursuant to
the terms of this Agreement or otherwise (a "Payment"), would be subject to the
excise tax imposed by Section 4999 of the Code or any interest or penalties with
respect to such excise tax (such excise tax, together with any such interest or
penalties, are hereinafter collectively referred to as the "Excise Tax"), AEPSC
shall pay to the Executive an additional payment (a "Gross-up Payment") in an
amount such that after payment by the Executive of all taxes (including any
interest or penalties imposed with respect to such taxes), including any Excise
Tax imposed on any Gross-up Payment, the Executive retains an amount of the
Gross-up Payment equal to the Excise Tax imposed upon the Payments. AEPSC and
the Executive shall make an initial determination as to whether a Gross-up
Payment is required and the amount of any such Gross-up Payment. Executive shall
notify AEPSC immediately in writing of any claim by the Internal Revenue Service
which, if successful, would require AEPSC to make a Gross-up Payment (or a
Gross-up Payment in excess of that, if any, initially determined by AEPSC and
the Executive) within five days of the receipt of such claim. AEPSC shall notify
the Executive in writing at least five days prior to the due date of any
response required with respect to such claim, or such shorter time period
following AEPSC's receipt of the notice, if it plans to contest the claim. If
AEPSC decides to contest such claim, the Executive shall cooperate fully with
AEPSC in such action; provided, however, AEPSC shall bear and pay directly or
indirectly all costs and expenses (including additional interest and penalties)
incurred in connection with such action and shall indemnify and hold the
Executive harmless, on an after-tax basis, for any Excise Tax or income tax,
including interest and penalties with respect thereto, imposed as a result of
AEPSC's action. If, as a result of AEPSC's action with respect to a claim, the
Executive receives a refund of any amount paid by AEPSC with respect to such
claim, the Executive shall promptly pay such refund to AEPSC. If AEPSC fails to
timely notify the Executive whether it will contest such claim or AEPSC
determines not to contest such claim, then AEPSC shall immediately pay to the
Executive the portion of such claim, if any, which it has not previously paid to
the Executive.
3.5 The obligations of AEPSC to pay the benefits described in Sections 3.1
and 3.2 shall be absolute and unconditional and shall not be affected by any
circumstances, including, without limitation, any set-off, counterclaim,
recoupment, defense or other right which AEPSC may have against the Executive.
In no event shall the Executive be obligated to seek other employment or take
any other action by way of mitigation of the amounts payable to the Executive
under any of the provisions of this Agreement, nor shall the amount of any
payment hereunder be reduced by any compensation earned by the Executive as a
result of employment by another employer, except as specifically provided in
Section 3.2.
ARTICLE IV
SUCCESSOR TO CORPORATION
This Agreement shall bind any successor of AEPSC or the Corporation, its
assets or its businesses (whether direct or indirect, by purchase, merger,
consolidation or otherwise) in the same manner and to the same extent that AEPSC
or the Corporation would be obligated under this Agreement if no succession had
taken place.
In the case of any transaction in which a successor would not by the
foregoing provision or by operation of law be bound by this Agreement, AEPSC and
the Corporation shall require such successor expressly and unconditionally to
assume and agree to perform AEPSC's and the Corporation's obligations under this
Agreement, in the same manner and to the same extent that AEPSC and the
Corporation would be required to perform if no such succession had taken place.
The term "Corporation," as used in this Agreement, shall mean the Corporation as
hereinbefore defined and any successor or assignee to the business assets which
by reason hereof becomes bound by this Agreement.
ARTICLE V
MISCELLANEOUS
5.1 Any notices and all other communications provided for herein shall be
in writing and shall be deemed to have been duly given when delivered or mailed,
by certified or registered mail, return receipt requested, postage prepaid
addressed to the respective addresses as follows:
To AEPSC:
-----------------------------------
To the Executive
-----------------------------------
5.2 No provision of this Agreement may be modified, waived or
discharged except in a writing specifically referring to such provision and
signed by the party against which enforcement of such modification, waiver or
discharge is sought. No waiver by either party hereto of the breach of any
condition or provision of this Agreement shall be deemed a waiver of any other
condition or provision at the same or any other time.
5.3 The validity, interpretation, construction and performance of this
Agreement shall be governed by the laws of the State of Ohio.
5.4 The invalidity or unenforceability of any provision of this Agreement
shall not affect the validity or enforceability of any other provision of this
Agreement, which shall remain in full force and effect.
5.5 This Agreement does not constitute a contract of employment or impose
on the Executive, AEPSC or the Corporation any obligation to retain the
Executive as an employee, to change the status of the Executive's employment, or
to change AEPSC's policies regarding the termination of employment.
5.6 If the Executive institutes any legal action in seeking to obtain or
enforce or is required to defend in any legal action the validity or
enforceability of, any right or benefit provided by this Plan, AEPSC will pay
for all actual and reasonable legal fees and expenses incurred (as incurred) by
the Executive, regardless of the outcome of such action; provided, however, that
if such action instituted by the Executive is found by a court of competent
jurisdiction to be frivolous, the Executive shall not be entitled to legal fees
and expenses and shall be liable to AEPSC for amounts already paid for this
purpose.
5.7 If the Executive makes a written request alleging a right to receive
benefits under this Agreement or alleging a right to receive an adjustment in
benefits being paid under the Agreement, AEPSC shall treat it as a claim for
benefit. All claims for benefit under the Agreement shall be sent to the Human
Resources Department of AEPSC and must be received within 30 days after the Date
of Termination. If AEPSC determines that the Executive who has claimed a right
to receive benefits, or different benefits, under the Agreement is not entitled
to receive all or any part of the benefits claimed, it will inform the Executive
in writing of its determination and the reasons therefor in terms calculated to
be understood by the Executive. The notice will be sent within 90 days of the
claim unless AEPSC determines additional time, not exceeding 90 days, is needed.
The notice shall make specific reference to the pertinent Agreement provisions
on which the denial is based, and describe any additional material or
information, if any, necessary for the Executive to perfect the claim and the
reason any such addition material or information is necessary. Such notice
shall, in addition, inform the Executive what procedure the Executive should
follow to take advantage of the review procedures set forth below in the event
the Executive desires to contest the denial of the claim. The Executive may
within 90 days thereafter submit in writing to AEPSC a notice that the Executive
contests the denial of the claim by AEPSC and desires a further review. AEPSC
shall within 60 days thereafter review the claim and authorize the Executive to
appear personally and review pertinent documents and submit issues and comments
relating to the claim to the persons responsible for making the determination on
behalf of AEPSC. AEPSC will render its final decision with specific reasons
therefore in writing and will transmit it to the Executive within 60 days of the
written request for review, unless AEPSC determines additional time, not
exceeding 60 days, is needed, and so notifies the Executive. If AEPSC fails to
respond to a claim filed in accordance with the foregoing within 60 days or any
such extended period, AEPSC shall be deemed to have denied the claim.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
executed as of the day and year first above written.
American Electric Power Service Corporation
By__________________________________
(Title)
- ------------------------------------
Executive
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SELECTED CONSOLIDATED FINANCIAL DATA
<CAPTION>
Year Ended December 31, 1999 1998 1997 1996 1995
<S> <C> <C> <C> <C> <C>
INCOME STATEMENTS DATA (in millions):
Total Revenues $6,916 $6,397 $5,928 $5,861 $5,673
Operating Income 1,305 1,247 1,346 1,369 1,254
Income Before Extraordinary Item 520 536 620 587 530
Extraordinary Loss -
UK Windfall Tax - - 109 - -
Net Income 520 536 511 587 530
December 31, 1999 1998 1997 1996 1995
BALANCE SHEETS DATA (in millions):
Property, Plant and Equipment $22,205 $21,351 $20,005 $19,289 $18,815
Accumulated Depreciation
and Amortization 9,150 8,549 8,087 7,656 7,206
Net Property,
Plant and Equipment $13,055 $12,802 $11,918 $11,633 $11,609
Total Assets $21,488 $19,483 $16,615 $15,883 $15,900
Common Shareholders' Equity 5,006 4,842 4,677 4,545 4,340
Cumulative Preferred Stocks
of Subsidiaries:
Not Subject to Mandatory Redemption 45 46 47 90 148
Subject to Mandatory Redemption* 119 128 128 510 523
Long-term Debt* 7,447 7,006 5,424 4,884 5,057
Obligations Under Capital Leases* 520 533 538 414 405
*Including portion due within one year
Year Ended December 31, 1999 1998 1997 1996 1995
COMMON STOCK DATA:
Earnings per Common Share:
Before Extraordinary Item $2.69 $ 2.81 $3.28 $3.14 $2.85
Extraordinary Loss - UK Windfall Tax - - (0.58) - -
Net Income $2.69 $ 2.81 $2.70 $3.14 $2.85
Average Number of Shares
Outstanding (in millions) 193 191 189 187 186
Market Price Range: High $48-3/16 $53-5/16 $ 52 $44-3/4 $40-5/8
Low 30-9/16 42-1/16 39-1/8 38-5/8 31-1/4
Year-end Market Price 32-1/8 47-1/16 51-5/8 41-1/8 40-1/2
Cash Dividends Paid $2.40 $2.40 $2.40 $2.40 $2.40
Dividend Payout Ratio 89.1% 85.4% 88.7%(a) 76.5% 84.1%
Book Value per Share $25.79 $25.24 $24.62 $24.15 $23.25
(a) Dividend Payout Ratio before Extraordinary Loss - UK Windfall Tax is 73.1%.
</TABLE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
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 impact of the proposed merger with
Central and South West Corporation (CSW) including any regulatory
conditions imposed on the merger or the inability to consummate the merger;
the speed and degree to which competition is introduced to our power
generation business, the structure and timing of a competitive market and
its impact on energy prices or fixed rates; the ability to recover net
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 success of new business
ventures; international developments affecting our foreign investments; 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 related to certain interest deductions
for a corporate owned life insurance 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 and gas market prices; interest rates; and
other risks and unforeseen events.
American Electric Power (AEP or the Company), one of the United
States' (U.S.) largest investor-owned electric utilities, is a global
energy company. Its domestic regulated electric utility operations provide
electric power to 3 million retail customers in Indiana, Kentucky,
Michigan, Ohio, Tennessee, Virginia and West Virginia and markets, trades
and transmits electricity in most of the Northern and Eastern U.S. AEP's
worldwide electric and gas operations has holdings in the U.S., the United
Kingdom (U.K.), Australia, China and Mexico. These holdings include
electric distribution systems in the U.K. and Australia; generation assets
in China; a Louisiana gas storage facility, an intrastate gas pipeline
operation and a gas trading business in the U.S.; generation facilities
under construction in Mexico; and an energy trading business in a
developmental stage in Europe. Subsidiaries also provide power engineering
and construction, energy consulting and energy management services
worldwide. The businesses that comprise worldwide operations are not
cost-based rate regulated for accounting purposes, although they are generally
subject to different forms of price regulation. As a result regulatory
assets and liabilities are not recorded for the worldwide operations. In
December 1997 the Company announced plans to merge with CSW, another
investor owned electric utility with regulated operations in Arkansas,
Louisiana, Oklahoma and Texas; global energy investments in the U.K.,
Brazil, Chile and Mexico and ownership interests in non-regulated
generating plants in Florida, Texas and Colorado.
Management faced many challenges in 1999 including:
Managing the Cook Nuclear Plant restart efforts under Nuclear
Regulatory Commission (NRC) supervision and the recovery of the
restart costs in regulated rates,
Working with regulators to secure approval of the AEP-CSW merger,
Managing energy-related investments in the U.K., China and Australia,
Operating the newly acquired Louisiana Intrastate Gas (LIG), a fully
integrated natural gas gathering, processing, storage and
transportation operation in Louisiana,
Growing the electricity and gas trading operations,
Implementing laws, passed in 1999, for electric competition in Ohio
and Virginia,
Working to shape restructuring legislation to make it fair and
advantageous to all interested stakeholders and to recover generation
related stranded costs including regulatory assets,
Dealing with actions and litigation against the Company's coal-fired
generating plants by the U.S. Environmental Protection Agency
(Federal EPA) and certain northeastern states, and
Working to mitigate new U.K. price constraints.
Although earnings will continue to be adversely affected by the
expenditures to restart the Cook nuclear units, we expect positive things
to occur in 2000 including the restart of the Cook Plant units and the
consummation of the merger with CSW. Management expects earnings to
recover in 2001 when both Cook nuclear units are expected to be in service
for the full year. Although AEP's three-year total shareholder return was
in the top quartile of the S&P Electric Utility Index for 1997, AEP's
three-year total shareholder return ranked 25th among the companies in the
S&P Electric Utility Index for 1999, reflecting the decline in AEP's common
stock price. The decline in AEP's stock price in 1999, in management's
opinion, reflects the uncertainties associated with the Cook Plant restart
and the consummation of the merger with CSW as well as a general decline
in the utility sector.
<PAGE>
Results of Operations
Net Income
Net income for 1999 declined 3% to $520 million or $2.69 per share
from $536 million or $2.81 per share in 1998 primarily due to increased
costs of the Cook Plant restart efforts and moderation of extreme weather
experienced in the summer of 1998. In 1998 net income increased 5% to $536
million or $2.81 per share from $511 million or $2.70 per share in 1997
primarily due to the effect of a 1997 extraordinary loss of $109 million.
The extraordinary loss, recorded in 1997, was a result of the U.K.'s
one-time windfall tax which was based on a revision or recomputation of the
original privatization value of certain privatized utilities, including
Yorkshire Electricity Group plc (Yorkshire).
Income Before Extraordinary Item
In 1998 income before the extraordinary loss, recorded in 1997,
decreased 14% to $536 million or $2.81 per share from $620 million or $3.28
per share in 1997. Several major items reduced 1998 earnings including the
cost of restart activities at the Cook Plant, a write-down of Yorkshire's
investment in Ionica, a U.K. telecommunications company, severance accruals
for reductions in power generation and energy delivery staff and mild
winter and fall weather.
Revenues Increase
Total revenues increased 8% in 1999 and 1998. Revenues increased in
1999 primarily due to the worldwide electric and gas operations' sale of
electricity in Australia and China and gas in the U.S. These transactions
are primarily from the activities of businesses acquired in December 1998,
CitiPower in Australia and LIG, and the commencement of commercial
operation of a two-unit 250 megawatt (MW) coal-fired generating plant in
China. The 1998 increase was primarily due to increased revenues from
retail, wholesale and transmission service customers in the Company's
domestic regulated electric utility operations.
The table below shows the changes in the components of revenues from
domestic regulated electric utility operations and the increase in
worldwide electric and gas operations. Revenues from the domestic
regulated electric utility operations decreased slightly in 1999 and
increased 8% in 1998. The worldwide electric and gas operations revenues
increased significantly in 1999 following a 6% increase in 1998.
Increase (Decrease)
From Previous Year
(Dollars in Millions) 1999 1998
Amount % Amount %
Domestic Regulated
Electric Utility
Operations:
Retail:
Residential $ 66 $ 37
Commercial 47 57
Industrial (11) 90
Other 1 4
103 2.0 188 3.8
Wholesale (191)(19.0) 207 25.9
Transmission (6) (3.3) 68 61.7
Other 63 106.1 3 4.8
Total Domestic
Regulated
Electric Utility
Operations (31) (0.5) 466 7.9
Worldwide Electric
and Gas Operations 550 N.M. 3 6.3
Total $ 519 8.1 $469 7.9
N.M. = Not Meaningful.
In 1999 retail revenues increased 2% reflecting a 2% increase in
retail sales. Sales to residential and commercial customers increased 4%
reflecting colder winter weather and customer growth.
Retail revenues increased 4% in 1998 reflecting a 2% rise in sales and
increased retail fuel cost recoveries. The increase in retail fuel
recoveries reflects the greater use of internal higher cost coal fired
generation and purchased power partially resulting from the need to replace
nuclear power usually generated at the Cook Plant. Although residential
sales were flat reflecting mild winter and fall weather in 1998, revenues
from residential customers increased 2%. The accrual of fuel-related
revenues for the recovery of the higher cost Cook Plant replacement energy
accounted for the increase in residential revenues. The rise in commercial
revenues resulted from a 4% increase in sales reflecting increased usage
and growth in the number of commercial customers. Industrial revenues
increased 6% reflecting a sales increase of 2% following the resumption of
operations by a major industrial customer after an extended labor strike.
Also contributing to the increase in industrial revenues were favorable
contract price adjustments to certain major industrial customers and the
pass-through of higher power costs during periods of peak demand.
Wholesale revenues declined 19% in 1999 predominantly due to a
decrease in wholesale energy sales and a reduction in net revenues from
power trading due to a decline in margins. The decrease in wholesale sales
reflects the expiration in July 1998 of a power contract which supplied
power to several municipal customers and the decision by another wholesale
customer who buys energy under a unit power agreement not to take energy
from AEP during an outage of that unit. The decline in margins reflects
the moderation of extreme weather and capacity shortages experienced in the
summer of 1998. The Company engages in the trading of electricity with
other utilities and power marketers in the Company's traditional marketing
area. Revenues from the trading of electricity are recorded net of
purchases. Regulated trading activities are conducted as part of AEP's
electric power wholesale marketing and trading operations and involve the
purchase and sale of substantial amounts of electricity.
The 26% increase in wholesale revenues in 1998 is attributable to net
revenues from trading of electricity and increased power marketing sales.
Although wholesale revenues rose, total wholesale sales declined due to a
reduction in coal conversion service sales. These sales are for the
generation of electricity from the purchaser's coal and as a result do not
include fuel costs. Consequently, the drop in coal conversion service
sales did not have a significant effect on wholesale revenues.
The 62% increase in transmission service revenues in 1998 is
attributable to a substantial rise in the quantity of energy transmitted
for other entities over AEP's transmission lines. Open transmission access
rules issued in 1996 by the FERC and the expansion of wholesale power
marketing has contributed to growth in the use of AEP's transmission
services.
In 1999 other revenues increased substantially due to a favorable
adjustment to a provision for revenue refund in the Company's Virginia
jurisdiction in connection with the commission's final order and increased
rental income. The increase in rental income reflects agreed to revisions
in the billings for pole attachments with telecommunications companies.
The level of wholesale transactions, including transmission services,
tends to fluctuate due to the highly competitive nature of the short-term
(spot) energy market and other factors, such as affiliated and unaffiliated
generating plant availability, the weather and the economy. The FERC rules
which introduced a greater degree of competition into the wholesale energy
market have had a major effect on wholesale sales and transmission service
revenues as more electricity is traded in the short-term market.
Operating Expenses Increase
Operating expenses increased 9% in 1999 and 12% in 1998. The
increases were attributable to acquisitions in late 1998 of new worldwide
electricity and gas operations and the costs to restart the shutdown Cook
Plant nuclear generating units. Exclusive of these factors operating
expenses actually declined in 1999. Changes in the components of operating
expenses were as follows:
Increase (Decrease)
From Previous Year
(Dollars in Millions) 1999 1998
Amount % Amount %
Fuel and
Purchased Power $(38) (1.8) $392 22.2
Maintenance and
Other Operation 22 1.2 135 7.9
Depreciation and
Amortization 20 3.4 (11) (1.9)
Taxes Other Than
Income Taxes 1 0.2 6 1.3
Worldwide Electric
and Gas
Operations 456 480.0 46 93.9
Total $461 9.0 $568 12.4
The decline in fuel and purchased power expense in 1999 is primarily
due to a decrease in fuel expense as generation declined 2% reflecting
lower demand for electricity by the Company's firm wholesale customers.
Firm wholesale customers include municipal distribution systems that
purchase electricity at wholesale to supply the needs of their retail
customers and unaffiliated electric utilities that buy power under long-term
contracts. The expiration in July 1998 of a contract to supply
several municipal customers and the outage of an AEP generating unit with
a long-term unit power agreement accounted for the reduced demand.
Fuel and purchased power expense increased significantly in 1998
primarily due to additional purchases of electricity for resale to other
utilities and power marketers and for replacement of energy usually
generated by the Cook Plant. Both of Cook's nuclear generating units were
unavailable due to the unplanned safety related shutdown which began in
September 1997 and continued throughout 1999. Also contributing to the
increase in fuel and purchased power expense was an increase in the average
cost of fuel consumed reflecting the reduced availability of lower cost
nuclear generation.
<PAGE>
The increase in maintenance and other operation expense in 1999 is
primarily due to the cost of restart efforts at the Cook Plant. The
increased Cook Plant restart expenditures were partially offset by cost
containment efforts in power generation, transmission and distribution and
lower costs to restore service after severe weather damage to the Company's
transmission and distribution system in 1998. The increase in maintenance
and other operation expenses in 1998 is primarily due to the extended Cook
Plant outage, power marketing and trading costs associated with the efforts
of AEP to build a major power trading business, severance accruals for
reductions in power generation and energy delivery staff and costs to
restore service interrupted by two severe snowstorms in the winter of 1998.
Expenses of the Company's worldwide electric and gas operations
increased significantly in 1999 and 1998 due to the addition of expenses
of the businesses acquired in December 1998 and the commercial operation
of the generating units constructed in China. LIG was acquired on December
1, 1998 resulting in one month of operating costs being included in AEP's
1998 operating costs and CitiPower, an Australian electric distribution
business, was acquired on December 31, 1998. Both acquisitions were
accounted for using the purchase method which recognizes revenues and costs
from the purchase date.
Interest and Preferred Dividends
The significant increase in interest and preferred dividends in 1999
reflects increased borrowings to support the expansion of AEP's worldwide
electric and gas operations and related acquisitions including CitiPower
and LIG in December 1998.
<PAGE>
Income Taxes
Income taxes declined in 1999 primarily due to an increase in foreign
tax credits and a decrease in state income taxes.
The decrease in income tax expense in 1998 was primarily due to a
decrease in pre-tax income excluding the extraordinary loss for the U.K.
windfall tax.
Business Outlook - Domestic Regulated Electric Utility Operations
The most significant factors affecting the Company's future earnings
from its domestic regulated electric utility operations are the restart of
the Cook Plant; weather in the Company's service territory; the ability to
recover costs including a fair return on equity in the Company's regulated
electric distribution business and its generation business which is being
restructured in certain regulatory jurisdictions to a competitive market;
the ability to manage costs and risks in the Company's domestic regulated
electric utility operations; the consummation of the CSW merger and the
realization of related net cost savings 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 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.
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 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 for five years; 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. 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
Cook 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.
Ohio Restructuring and The Transition To Market Pricing For Generation
The Ohio Electric Restructuring Act of 1999 (the Act) became law in
October 1999. The Act provides for customer choice of electricity
supplier, a residential rate reduction of 5% for the generation portion of
rates and a freezing of the unbundled generation rates including fuel rates
beginning on January 1, 2001. The Act also provides for a five-year
transition period to move from cost based rates to market pricing for
generation services. It authorizes the Public Utilities Commission of Ohio
(PUCO) to address certain major transition issues including unbundling of
rates and the recovery of transition costs including stranded costs.
Transition costs include generation-related regulatory assets, (which
include, among other expense deferrals, unrecovered deferred fuel costs,
deferred tax benefits that were flowed through to reduce past rates and
deferred affiliated mine shutdown costs), impaired tangible generating
asset values, and future contract costs. Stranded costs are those costs
of generation above market that would not be recoverable in a competitive
market. Transition costs also include customer choice education costs,
development costs of new billing and metering systems, costs of filing a
transition plan, employee severance and retraining costs and other costs.
Retail electric services that will be competitive are defined in the
Act as electric generation service, aggregation service, and power
marketing and brokering. Under the Act the PUCO is granted broad oversight
responsibility and is required to approve by October 31, 2000 a transition
plan for each electric utility company. Ohio electric utilities were
required to file their transition plans by January 3, 2000. The Company
filed its plan in December 1999.
The Act provides Ohio electric utilities with an opportunity to
recover PUCO approved allowable transition costs through the generation
portion of transition rates paid through December 31, 2005 by customers who
do not switch generation suppliers and through a transition charge for
customers who switch generation suppliers. Under the Act recovery of the
regulatory asset portion of transition costs can, under certain
circumstances, extend beyond the five-year transition period but cannot
continue beyond December 31, 2010.
The Act also provides for a reduction in property tax assessments;
exemption of electric utilities from the gross receipts tax; and the
imposition of a franchise tax, income taxes, and a new kilowatthour (kwh)
excise tax. The property tax assessment percentage on electric generation
property will be lowered from 100% to 25% of value effective January 1,
2001 and electric utilities will become subject to the Ohio Corporate
Franchise Tax and municipal income taxes on January 1, 2002. The last year
for which electric utilities will pay a tax based on gross receipts is the
tax year ending April 30, 2002. As of May 1, 2001 electric distribution
companies will be subject to an excise tax based on kwh sold to Ohio
customers. The gross receipts tax, which will terminate for electric
utilities, is paid by the Company at the beginning of the tax year,
deferred as a prepaid expense and amortized to expense during the tax year
pursuant to the tax law whereby the payment of the tax results in the
privilege to conduct business in the year following the payment of the tax.
The change in the tax law to impose an excise tax based on kwh sold to Ohio
customers commencing before the expiration of the gross receipts tax
privilege period will result in a 12 month period (May 1, 2001 to April 30,
2002) when our Ohio electric utilities are recording as an expense both the
gross receipts tax and the kwh excise tax. In the Company's Ohio
transition plan filing, recovery of $90 million was sought for this overlap
of the gross receipts and excise taxes.
The PUCO is required to issue a transition order no later than October
31, 2000 regarding the Company's transition filings which included the
following elements:
a rate unbundling plan including tariff terms and conditions
necessary for restructuring,
a corporate separation plan,
an application for transition revenues,
a plan for independent operation of transmission facilities and
other components for the implementation of restructuring.
The rate unbundling portion of the Company's transition plan filing
provides for the Company's Ohio retail jurisdictional companies to offer
two transition period tariffs beginning January 1, 2001, the standard
tariff and the open access distribution tariff. The Company's proposed
standard tariff applies to customers who do not choose an alternative
energy supplier. This tariff schedule includes detailed charges for
generation, transmission and distribution and riders to fund universal
service, to promote energy efficiency and to recover regulatory assets and
taxes. Taxes include charges for municipal income, excise and franchise
taxes and tax credits for gross receipts and property taxes. For customers
who choose an alternative electric supplier, the proposed open access
distribution tariff will apply. This tariff includes charges for
distribution and riders to fund universal service, to promote energy
efficiency and to recover regulatory assets and taxes. These riders are
the same as those in the standard tariff except there is no property tax
credit.
The Company's corporate separation plan proposal requires that each
of the Company's Ohio jurisdictional companies establish separate
subsidiaries to own and operate their transmission and distribution assets.
The separation plan will be implemented in a manner that recognizes the
current overlap of financing arrangements. This would permit an orderly
and economically efficient separation of each operating company so that
additional transition costs from prematurely retiring of financial
instruments can be avoided. Prior to the actual legal separation, the Ohio
jurisdictional companies will functionally separate generation from
transmission and distribution.
The transition plan filing requests recovery of stranded generation
costs over a five year period and recovery of generation-related regulatory
assets and other transition costs of $974 million over a 10-year period
through transition revenues. The amount requested for recovery of
regulatory assets includes current and new regulatory assets including
those arising from compliance with the electric restructuring law. Also
included in the requested recovery amount were deferred fuel and affiliated
mine closure costs.
In the Ohio jurisdiction the Company is subject to certain limitations
on the current recovery of affiliated coal costs under PUCO approved
agreements, which are discussed in Note 3 of the Notes to Consolidated
Financial Statements. Under the terms of the agreements full recovery of
the Ohio jurisdictional portion of deferred unrecovered costs of affiliated
mining operations including future mine closure costs was expected to occur
before the expiration of the PUCO approved agreements in 2009. Management
closed the Muskingum mine in 1999 and plans to close the Windsor mine in
2000 and the Meigs mine in 2001. Provisions for Muskingum and Windsor mine
shutdown costs totaling $45 million and $48 million were recorded in 1998
for Muskingum mine and 1999 for the Windsor mine, respectively. Management
deferred these provisions in the Ohio jurisdiction under the PUCO approved
agreements because it believed that these deferrals for the cost of the
mine shutdowns are probable of future recovery through the agreements.
However, since the Act will supersede the agreements effective January 1,
2001, the Company has filed under the provisions of the Act for recovery
of all of its stranded regulatory assets including the affiliated coal
costs deferred under the agreements of $196 million at December 31, 1999
plus the projected amount that will be deferred by the beginning of the
transition period, January 1, 2001, which includes the accrual for the
closure costs of the Meigs mine.
Included in the transition plan is a proposal to implement independent
operation of the transmission system. The Company proposes to join a
regional transmission organization (RTO) whose approval is currently
pending before the Federal Energy Regulatory Commission (FERC).
See Note 5 of the Notes to Consolidated Financial Statements for
further discussion.
Virginia Restructuring
In March 1999 a law was enacted in Virginia to restructure the
electric utility industry. Under the restructuring law, a transition to
choice of electricity supplier for retail customers will commence on
January 1, 2002 and be completed, subject to a finding by the Virginia
State Corporation Commission (Virginia SCC) that an effective competitive
market exists, on or before January 1, 2004.
The law also provides an opportunity to recover just and reasonable
net stranded generation costs. The mechanisms in the Virginia law for net
stranded cost recovery are: a capping of rates until as late as July 1,
2007, and the application of a wires charge upon customers who depart the
incumbent utility in favor of an alternative supplier prior to the
termination of the rate cap. The law provides for the establishment of
capped rates prior to January 1, 2001 and the establishment of a wires
charge by the fourth quarter of 2001.
West Virginia Restructuring
On January 28, 2000, after over three years of workshops, hearings and
negotiations, the Public Service Commission of West Virginia (WVPSC) issued
an order approving an electricity restructuring plan for West Virginia.
The restructuring plan has been submitted to the West Virginia Legislature
for approval or rejection which is expected to occur during the current
legislative session that ends in March 2000. Until approved by the West
Virginia Legislature, the restructuring plan cannot take effect. The
Company's subsidiaries, Appalachian Power Company (APCo) and Wheeling Power
Company, which do business in West Virginia, will be affected by the
proposed restructuring.
The provisions of the proposed restructuring plan provide for customer
choice to begin on January 1, 2001, or at a later date set by the WVPSC
after all necessary rules are in place (the "starting date"); deregulation
of generation assets occurring on the starting date; functional separation
of the generation, transmission and distribution businesses on the start
date and their legal corporate separation no later than January 1, 2005;
a transition period of up to 13 years, during which the incumbent utility
must provide default service for customers who do not change suppliers
unless an alternative default supplier is selected through a WVPSC-sponsored
bidding process; capped and fixed rates for the 13 year
transition period as discussed below; deregulation of metering and billing;
a 0.5 mills per kwh wires charge applicable to all retail customers for the
period January 1, 2001 through December 31, 2010 intended to provide for
recovery of any stranded cost including net regulatory assets;
establishment of a rate stabilization deferred balance by AEP of $81
million by the end of year ten of the transition period to be used as
determined by the WVPSC to offset prices paid in the eleventh, twelfth, and
thirteenth year of the transition period by residential and small
commercial customers that do not choose a supplier.
Default rates for residential and small commercial customers are
capped for four years after the starting date and then increased as
specified in the plan for the next six years. In years eleven, twelve and
thirteen of the transition period, the power supply rate shall equal the
market price of comparable power. Default rates for industrial and large
commercial customers are discounted by 1% for four and a half years,
beginning July 1, 2000, and then increased at pre-defined levels for the
next three years. After seven years the power supply rate for industrial
and large commercial customers will be market based.
Restructuring In Other Jurisdictions
All of the other states within our service territory have initiatives
to implement or review customer choice, although the timing of any
implementation is uncertain. The Company supports customer choice and
deregulation of generation and is proactively involved in discussions
regarding the best competitive market structure and transition method to
arrive at a fair, competitive marketplace. As the pricing of generation
in these markets evolves from regulated cost-of-service rates to
market-based pricing, the recovery of stranded costs including net regulatory
assets and other transition costs must be addressed. The amount of
stranded costs the Company could experience when restructuring occurs in
these jurisdictions depends on the timing and extent to which competition
is introduced to its business and the future market prices of electricity.
The recovery of stranded cost is dependent on the terms of future
legislation and, if required, related regulatory proceedings.
Regulatory/Restructuring Accounting
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 in order 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 for AEP's
jurisdictions. However, the recent legislation in Ohio and Virginia will
result in the discontinuance of SFAS 71 regulatory accounting for the
generation portion of the Ohio and Virginia jurisdictions. If the West
Virginia Legislature approves the restructuring plan as submitted by the
WVPSC it will result in the discontinuance of SFAS 71 regulatory accounting
for the generation portion of the West Virginia jurisdiction.
In the event a portion of AEP'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 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 regulatory accounting 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 transition rates and/or post-transition
cost based regulated rates.
Potential For Write Offs In Ohio, Virginia And West Virginia Jurisdictions
The Company's accounting for generation will continue to be in
accordance with SFAS 71 in the Ohio and Virginia jurisdictions and will
continue to be considered to be cost-based regulated for accounting
purposes until the amount of transition rates and stranded cost wires
charges are determined and known. The establishment of transition rates
and wire charges should enable management to determine the Company's
ability to recover stranded costs including regulatory assets and
transition costs, a requirement under EITF 97-4 to discontinue application
of SFAS 71. When the amount of unbundled frozen generation transition
rates and distribution stranded cost wires charges are known for the Ohio
jurisdiction, the application of SFAS 71 will be discontinued for the Ohio
retail jurisdictional portion of the Company's generation business.
Management expects this to occur when the PUCO issues its order to approve
a transition plan for the Company's Ohio jurisdictional electric operating
subsidiaries. The Act requires that the PUCO issue its order no later than
October 31, 2000. The application of SFAS 71 will be discontinued for the
Virginia retail jurisdictional portion of the Company's generation business
when the capped rates and the wires charge are known in Virginia which is
expected to occur by the fourth quarter of 2000. In the West Virginia
jurisdiction accounting for generation will continue to be in accordance
with SFAS 71 and the generation business will continue to be considered to
be cost-based regulated for accounting purposes until the proposed
restructuring plan is enacted into law. The application of SFAS 71 for the
generation portion of the West Virginia jurisdiction will be discontinued
when the West Virginia Legislature approves the restructuring plan and when
the WVPSC approves the rate stipulation filed with the Commission, which
are both expected to occur in March 2000. Together these two documents
provides sufficient information for management to determine the impact of
restructuring on the Company's financial statements.
Upon the discontinuance of SFAS 71 the Company will have to write off
its Ohio, Virginia and West Virginia jurisdictional generation-related
regulatory assets to the extent that they cannot be recovered under the
frozen transition rates and stranded costs distribution wires charges and
record any asset accounting impairments. An impairment loss would be
recorded to the extent that the cost of generation assets cannot be
recovered through non-discounted generation-related revenues during the
transition period and future market prices. Absent the determination in
the legislative or regulatory process of transition rates, any wires charge
and other pertinent information, it is not possible at this time for
management to determine if any of the Company's generating assets are
impaired for accounting purposes on an undiscounted cash flow basis.
The amount of regulatory assets recorded on the books at December 31,
1999 applicable to the Ohio, Virginia and West Virginia retail
jurisdictional generation business before related tax effects is estimated
to be $666 million, $64 million and $131 million, respectively. Due to the
planned closing of the Company's affiliated mines, including the Meigs
mine, projected generation-related regulatory assets as of December 31,
2000 (the date that recoverable generation related regulatory assets are
measured under the Ohio law) allocable to the Ohio retail jurisdiction are
estimated to exceed $800 million, before income tax effects. Recovery of
these Ohio generation related regulatory assets was sought as a part of the
Company's Ohio transition plan filing. Based on current projections of
future market prices, the Company does not anticipate that it will
experience material tangible asset accounting impairment write-offs.
Whether the Company will experience material regulatory asset write-offs
will depend on whether the PUCO approves the Company's request for their
recovery and whether the capped transition rates and allowed wires charges
in Virginia and West Virginia will permit their recovery.
An estimated determination of whether the Company will experience any
asset impairment loss regarding its Ohio, Virginia and West Virginia
retail jurisdictional generating assets and any loss from the possible
inability to recover Ohio, Virginia and West Virginia generation related
regulatory assets and other transition costs cannot be made until such time
as the transition rates and the wires charges are determined through the
regulatory or legislative process. Should the PUCO or the Virginia SCC
fail to approve transition rates and wires charges that are sufficient to
provide for recovery or the West Virginia Legislature approves a
restructuring plan that does not provide for recovery of the Company's
generation-related regulatory assets, any other stranded costs and
transition costs, it could have a material adverse effect on results of
operations, cash flows and possibly financial condition.
AEP 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. AEP is working to develop and
acquire the necessary skills and competencies to succeed in a competitive
electricity commodity market. AEP has developed an extensive wholesale
electricity trading business. However, many factors, some of which AEP
does not control, could negatively impact AEP's future success in a market
priced, competitive environment.
Customer choice and competition in AEP's other domestic jurisdictions
could also 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 or 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 AEP's generation business
in other 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.
Completion of the Merger
In 1999 the Company and CSW made significant progress towards
receiving all the approvals necessary to complete their merger which was
announced in December 1997. FERC and the Securities and Exchange
Commission (SEC) approvals are needed to consummate the merger.
In 1998 the appropriate shareholder approvals were acquired and the
NRC and the Arkansas Public Service Commission approved the merger. In
1998 the FERC issued an order which confirmed that a 250 MW firm contract
path with the Ameren System was available to meet the Public Utility
Holding Company Act of 1935 (1935 Act) requirement that the two electric
transmission systems operate on an integrated and coordinated basis.
During 1999 the regulatory commissions of Louisiana, Texas and Oklahoma
approved the merger and related settlement agreements, and settlements were
reached with the FERC staff and certain other parties who had intervened
in the FERC proceeding or who had asserted a right to review the merger.
The Company reached agreements in 1999 with its state regulatory
commissions in Indiana, Michigan and Kentucky and in 2000 the Department
of Justice closed its investigation.
In granting approval of the merger, the CSW state regulatory
commissions, Arkansas, Louisiana, Oklahoma and Texas, required the Company
to take several steps to protect the interest of their constituents. Among
those requirements are sharing of net merger savings at a rate of
approximately 55% to customers and 45% to the Company's shareholders; a
freezing or capping of base rates for defined periods of three to five
years; joining an RTO; implementing standards to insure quality of service;
divesting 1,604 MW of generation in Texas; agreeing to comply with code of
conduct standards for affiliated transactions, shared cost allocations and
prevention of cross subsidization of non-regulated operations by regulated
operations and other provisions facilitating competition. See Note 8 of
the Notes to Consolidated Financial Statement for additional detail.
Merger settlement agreements were approved in 1999 by the IURC, MPSC
and the Kentucky Public Service Commission (KPSC). The terms of the
settlement agreements provide for, among other things, a 55%/45% sharing
of net merger savings with Indiana, Michigan and Kentucky customers; a
one-year extension through January 1, 2005 of a freeze in base rates in Indiana
and Michigan; 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 for customer service and
reliability; and participation in an RTO; and other steps to protect and
promote fair competition. As part of the settlement agreements, the IURC,
MPSC and the key parties to the Kentucky settlement agreed not to oppose
the merger in the FERC and the SEC proceedings.
AEP and CSW also reached settlements in 1999 with the Missouri Public
Service Commission, the International Brotherhood of Electrical Workers,
representing employees of AEP and CSW, the Utility Worker's Union of
America representing AEP employees, and certain wholesale customers who had
intervened in the FERC proceeding. All have agreed not to oppose the
merger in the FERC and the SEC proceedings. In October 1999 the PUCO
withdrew its opposition to the Company's pending merger with CSW in the
FERC proceeding.
During 1999 FERC reviewed the proposed merger addressing issues of
competition, market power and customer protection. AEP and CSW reached
settlements with the FERC trial staff resolving competition, rate and other
issues relating to the merger. The settlements have been submitted to the
FERC for approval. Under the terms of the settlements, AEP filed an RTO
proposal with the FERC whereby it will transfer the operation and control
of AEP's bulk transmission facilities to an RTO known as the Alliance RTO.
The settlements also cover rates for transmission services and ancillary
service as well as resolving issues related to system integration
agreements and confirm, subject to FERC guidance on certain elements, that
a proposed generation divestiture of up to 550 MW of capacity will satisfy
the FERC staff's market power concerns. Hearings on the merger and related
settlement agreements were held before a FERC administrative law judge
(ALJ) in 1999. In November 1999 the ALJ issued a favorable decision
finding the merger and the proposed settlement agreements to be in the
public interest. The FERC is expected to issue a final order in the first
quarter of 2000. SEC approval of the merger under the 1935 Act is expected
to follow the FERC's issuance of a final order.
The proposed merger of CSW into AEP would result in common ownership
of two U.K. regional electricity companies (RECs), Yorkshire Electricity
Group plc (Yorkshire) and SEEBOARD, plc. AEP has a 50% ownership interest
in Yorkshire and CSW has a 100% interest in SEEBOARD. On January 25, 2000,
the U.K. Department of Trade and Industry approved the common ownership of
two RECs which will result from the consummation of the AEP-CSW merger.
The approval was conditioned on agreement to certain assurances concerning
the U.K. operations of Yorkshire and SEEBOARD including meeting customer
service obligations, maintaining debt ratings of investment grade or above
and separate distribution and supply activities. This approval is the
final clearance for the merger in the U.K.
At December 31, 1999, AEP had deferred $42 million of transaction and
transition costs related to the merger, which will be charged to expense
if AEP and CSW are not successful in completing their proposed merger. If
the merger is consummated, the deferred costs allocable to those regulated
electric operating subsidiaries with merger settlement agreements will be
amortized over a five- to eight-year recovery period depending on the
specific terms of their settlement agreements. The remainder of the
deferred merger costs will be expensed upon consummation of the merger.
Merger transition costs are expected to continue to be incurred and
expensed or deferred for amortization as appropriate for several years
after the merger is consummated.
The merger with CSW is conditioned upon, among other things, the
approval of certain state and federal regulatory agencies. The transaction
must satisfy many conditions, a number of which may not be waived by the
parties, including the condition that the merger must be accounted for as
a pooling of interests. 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. Although consummation of the merger
is expected to occur in the second quarter of 2000, the Company is unable
to predict the outcome or the timing of the remaining required regulatory
proceedings. If realized merger savings do not match or exceed the
estimated savings included in merger settlement agreements in the
eight-year period following consummation of the merger, future results of
operations, cash flows and possibly financial condition could be adversely
affected.
<PAGE>
Environmental Concerns and Issues
We take great pride in our efforts to economically produce and deliver
electricity while minimizing the impact on the environment. AEP has spent
over a billion dollars to equip its facilities with the latest cost
effective clean air and water technologies and to research new
technologies. We are also proud of our award winning efforts to reclaim
our mining properties. We intend to continue in a leadership role
fostering economically prudent efforts to protect and preserve the
environment while providing a vital commodity, electricity, to our
customers at a fair price.
Air Quality
In 1998 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 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
emission reduction final rule. The AEP System companies 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 of the Company's plants, 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 $1.6 billion
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 and, where generation is being deregulated, unbundled generation
transition rates, wires charges and the future market price of electricity,
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 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 made modifications to certain of
its 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 to the Company alleging violations of certain provisions of the
Clean Air Act 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
allowed to join 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 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 11 of AEP's 17 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 and, where states are deregulating generation, approved
unbundled transition generation rates, wires charges and future market
prices for electricity.
Business Outlook - Worldwide Electric and Gas Operations
In 1999 no significant new investments were made in the worldwide
electric and gas operations outside the U.S. Management continues to
evaluate its current investments and opportunities for growth with the goal
of maximizing shareholder value. In January 2000 European trading of
electricity and gas began. In 1999 the construction of two generating
units in China was completed on schedule and the Company acquired a 50%
investment interest in a Mexican generation project and commenced energy
trading operations in Canada. This follows acquisitions made in December
1998 to expand AEP's electric and gas operations overseas and in the U.S.
which included the purchase of CitiPower, an Australian electric
distribution utility, and the purchase of LIG's gas operations in Louisiana
and gas trading operation in Houston, Texas.
The most significant factor affecting the Company's future earnings
from its worldwide electric and gas operations is the performance of its
energy investments and business ventures including the ability to control
costs as the U.K. and Australian electricity supply markets are deregulated
and electricity distribution rate regulation becomes more performance
based. The Company continues to evaluate the U.S. and international energy
markets for investment opportunities to create shareholder value. Future
earnings will also be impacted by the performance of any future
acquisitions, mergers and investments.
Pursuant to the 1935 Act, AEP's investment in certain types of
non-regulated energy ventures is limited. SEC authorization under the 1935 Act
limits AEP to issuing and selling 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 (EWGs) and foreign
utility companies (FUCOs). At December 31, 1999, AEP's investment in EWGs
and FUCOs was $885 million. Management expects to continue to pursue new
and existing energy projects and to provide energy related services
worldwide.
In December 1999 the Company contributed $47 million to acquire a 50%
interest in a Mexican power project. The power project (Bajio) is a 600
MW natural gas-fired, combined cycle plant located approximately 160 miles
from Mexico City. An affiliate of the Company's partner will build the
facility, which is estimated to cost $430 million. The Company is not
expected to contribute any additional capital to the project; the remainder
of the funding will be provided by third party debt some of which will be
supported by letters of credit issued on behalf of the Company. The
facility will be operated and managed by companies jointly owned by the
Company and its partner. Bajio has a 25-year contract to sell 495 MW 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.
The Bajio power project is expected to be completed in the fall of 2001.
The $1.1 billion acquisition of CitiPower, completed on December 31,
1998, was accounted for using the purchase method of accounting. CitiPower
provides electricity and electric distribution service to approximately
250,000 customers in the city of Melbourne.
In March 1998 the Company acquired a 20% equity interest in Pacific
Hydro. Pacific Hydro operates four hydroelectric power stations in
Australia with an installed capacity of 40 MW and has interests in two
hydroelectric projects under construction in the Philippines.
Two newly constructed 250 MW coal-fired generating units in China,
owned 70% by the Company with the remaining 30% owned by two Chinese
partners, began commercial operation in 1999. Although the units incurred
a loss in 1999, a higher tariff rate approved by the Central Chinese
government in January 2000 should result in the units contributing to the
Company's future earnings.
In addition, the Company has a 50% investment in Yorkshire, a U.K.
supplier of electricity and gas and electric service distribution company.
The investment was made in April 1997 and contributed $45 million and $39
million of equity earnings in 1999 and 1998, respectively, which is
included in worldwide electric and gas operations revenues. Since May 1999
all residential and commercial customers in the U.K. could choose their
electricity supplier. Yorkshire has been successful in maintaining its
customer base since the start of full competition. However, as expected,
margins on retail electric sales have been declining due to competition.
In December 1999 the Office of Gas and Electricity Markets (OFGEM), the
U.K. gas and electric regulatory body, published final proposals for
Yorkshire's new rates in its distribution business and for price caps in
its supply business. The final proposals reduce distribution rates and
electricity supply price caps beginning on April 1, 2000. The rate
reductions and reduced price caps are expected to reduce the Company's
equity earnings from its Yorkshire investment. This reduction may be
significant if it is not offset by increased revenues and/or cost savings.
On December 1, 1998, the Company purchased LIG, a midstream natural
gas operation for approximately $340 million including working capital
funds. The midstream operations include a fully integrated natural gas
gathering, processing, storage and transportation operation in Louisiana
and a gas trading and marketing operation in Houston, Texas. Assets
include an intrastate pipeline system, natural gas processing plants and
natural gas storage facilities. The gas trading operation included in this
purchase was merged with AEP's existing gas trading organization which
began operating in December 1997. This acquisition is expected to enhance
AEP's gas trading operations by improving management's knowledge of the
Henry Hub gas market.
SEC rules under the 1935 Act permit AEP to invest up to 15% of
consolidated capitalization (such amount was $2 billion at December 31,
1999) in energy-related companies that engage in marketing and/or trading
electricity, gas and other energy commodities. The Company's gas trading
business is reported as an investment under this rule and at December 31,
1999, AEP's investment was $337 million.
Financial Condition
AEP's financial condition continues to be strong. The Cook Plant
extended outage and related restart expenditures negatively affected 1999
earnings and will continue to adversely impact earnings in 2000. The 1999
dividend payout ratio was 89.1% and is expected to increase in 2000 as the
Cook Plant restart is completed. Nonetheless, it has been a management
objective to reduce the payout ratio by increasing earnings.
AEP's ratio of common equity to total capitalization including long-term
debt due within one year was 39.7% on December 31, 1999, compared with
40.3% on December 31, 1998 and 45.5% on December 31, 1997. The decline in
1999 and 1998 primarily reflects borrowing to support the acquisitions and
investments made by the worldwide electric and gas operations. AEP issued
2,287,000 shares of common stock in 1999, 1,826,000 shares in 1998 and
1,755,000 shares in 1997 through a Dividend Reinvestment and Direct Stock
Purchase Plan and the Employee Savings Plan raising $91 million, $86
million and $77 million, respectively. Additional sales of common stock
and/or equity linked securities may be necessary in the future to support
the Company's growth.
Consolidated construction expenditures for all subsidiaries are
expected to be $2.8 billion over the next three years. All expenditures
for domestic regulated electric utility construction, estimated to be $2.5
billion for the next three years, are expected to be financed with
internally generated funds.
Capital Resources - Structure and Liquidity
The Company and its subsidiaries issued $810 million principal amount
of long-term obligations in 1999 at interest rates ranging from 5.15% to
7.45%. The Company also increased its borrowing under two long-term
revolving credit agreement: $60 million under an agreement which expires
in June 2000 and $30 million under an agreement which expires in December
2002. The principal amount of long-term debt retirements, including
maturities, totaled $506 million with interest rates ranging from 6.42% to
9.6%. The ratings of the subsidiaries' first mortgage bonds are listed in
the following table:
Company Moody's S&P Fitch D & P
APCo A3 A A A
CSPCo A3 A- A- A
I&M Baa1 A- BBB+ BBB+
KPCo Baa1 A BBB+ BBB+
OPCo A3 A- A- A
The Company's subsidiaries also issue senior unsecured debt. Their
senior unsecured debt ratings are listed in the following table:
Company Moody's S&P D & P
AEP Resources* Baa2 BBB+ N/A
APCo Baa1 BBB+ A-
CitiPower Baa2 BBB+ N/A
CSPCo Baa1 BBB+ A-
I&M Baa2 BBB BBB
KPCo Baa2 BBB BBB
OPCo Baa1 BBB+ A-
* The rating is for a series of senior notes
issued with a Support Agreement from AEP.
The domestic electric utility subsidiaries generally issue short-term
debt to provide for interim financing of capital expenditures that exceed
internally generated funds. They periodically reduce their outstanding
short-term debt through issuances of long-term debt and additional capital
contributions by the parent company. The sources of funds available to AEP
Co., Inc. are dividends from its subsidiaries, short-term and long-term
borrowings and proceeds from the issuance of common stock.
The subsidiaries formed to pursue worldwide electric and gas
opportunities use short-term debt (through revolving credit facilities) and
capital contributions by the parent company to provide for interim
financing of capital expenditures and acquisitions. Short-term debt is
replaced with long-term debt when financial market conditions are
favorable. Some acquisition transactions of existing business entities
include the assumption of their outstanding debt.
Short-term debt increased $271 million and $62 million in 1999 and
1998, respectively. At December 31, 1999, AEP Co., Inc. (the parent
company) and its subsidiaries had unused short-term lines of credit of
$1,056 million, and another subsidiary had $20 million available under a
$50 million revolving credit agreement that expires in December 2002. An
AEP subsidiary engaged in the acquisitions of worldwide energy investments
and businesses had no funds available under a $600 million revolving credit
agreement that expires in June 2000.
Unless the domestic electric utility subsidiaries meet certain
earnings or coverage tests, they cannot issue additional mortgage bonds.
In order to issue mortgage bonds (without refunding existing debt), each
subsidiary must have pre-tax earnings equal to at least two times the
annual interest charges on mortgage bonds after giving effect to the
issuance of the new debt.
<PAGE>
The following debt coverages of AEP's principal domestic electric
utility subsidiaries remained strong in 1999 and were as follows:
Coverages at
December 31, 1999
Mortgage
APCo 5.29
CSPCo 7.42
I&M 4.81
KPCo 5.57
OPCo 11.78
As the above table indicates, the major domestic electric utility
subsidiaries presently exceed the minimum coverage requirements.
Market Risks
The Company as a major power producer and a trader of wholesale
electricity and natural gas has certain market risks inherent in its
business activities. The trading of electricity and natural gas and
related financial derivative instruments exposes the Company to market
risk. Market risk represents the risk of loss that may impact the Company
due to adverse changes in 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 highest, lowest and average VaR in
the wholesale electricity and gas trading portfolio was less than $14
million and $11 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.
Investments in foreign ventures expose the Company to risk of foreign
currency fluctuations. The Company's exposure to changes in foreign
currency exchange rates related to these foreign ventures and investments
is not expected to be significant for the foreseeable future.
The Company is exposed to changes in interest rates primarily due to
short- and long-term borrowings to fund its business operations. The debt
portfolio has both fixed and variable interest rates with terms from one
day to forty years and an average duration of four 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 $575 million at December 31, 1999 and $589 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. The Company is currently
utilizing interest rate swaps as a hedge to manage its exposure to interest
rate fluctuations in Australia.
The Company has investments in debt and equity securities which are
held in nuclear trust funds. Approximately 80% of the trust fund value is
invested in tax exempt and taxable bonds, short-term debt instruments or
cash. The trust investments and their fair value are discussed in Note 14
of the Notes to Consolidated Financial Statements. Instruments in the
trust funds have not been included in the market risk calculation for
interest rates as these instruments are marked-to-market and changes in
market value are reflected in a corresponding decommissioning liability.
Any differences between the trust fund assets and the ultimate liability
should be recoverable from ratepayers.
Inflation affects AEP's cost of replacing utility plant and the cost
of operating and maintaining its plant. The rate-making process limits our
recovery to the historical cost of assets resulting in economic losses when
the effects of inflation are not recovered from customers on a timely
basis. However, economic gains that result from the repayment of long-term
debt with inflated dollars partly offset such losses.
Litigation
Corporate Owned Life Insurance
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 $317 million inclusive of 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 sheet in other assets 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 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.
AEP 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, which constitute the overwhelming
percentage of these materials, are typically disposed of or treated in
captive disposal facilities or are beneficially utilized. In addition, our
generating plants and transmission and distribution facilities have used
asbestos, polychlorinated biphenyls (PCBs) and other hazardous and
nonhazardous materials. We are currently incurring costs to safely dispose
of such substances. Additional costs could be incurred to comply with new
laws and regulations if enacted.
The Comprehensive Environmental Response, Compensation and Liability
Act (Superfund) addresses clean-up of hazardous substances at disposal
sites and authorized Federal EPA to administer the clean-up programs. As
of year-end 1999, we are involved in litigation with respect to two sites
overseen by the Federal EPA and have been named by the Federal EPA as a
potentially responsible party (PRP) for three other sites. There are three
additional sites for which AEP has received information requests which
could lead to PRP designation. The Company has also been named a PRP at
one site under state law. Our liability has been resolved for a number of
sites with no significant effect on results of operations. In those
instances where we have been named a PRP or defendant, our disposal or
recycling activities were in accordance with the then-applicable laws and
regulations. Unfortunately, Superfund does not recognize compliance as a
defense, but imposes strict liability on parties who fall within its broad
statutory categories.
While the potential liability for each Superfund site must be
evaluated separately, several general statements can be made regarding our
potential future liability. AEP's disposal of materials at a particular
site is often unsubstantiated and the quantity of materials deposited at
a site was small and often nonhazardous. Although liability is joint and
several, typically many parties are named as PRPs for each site and several
of the parties are financially sound enterprises. Therefore, our present
estimates do not anticipate material cleanup costs for identified sites for
which we have been declared PRPs. If significant cleanup costs are
attributed to AEP in the future, results of operations, cash flows and
possibly financial condition would be adversely affected unless the costs
can be recovered from customers.
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 AEP's power plants. 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 for the Company
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
AEP, 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 6 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
spent nuclear fuel 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 AEP 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, AEP 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, AEP 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, AEP's future results of operations, cash flows and possibly its
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 failures of generation
and delivery of electric energy due to Year 2000 because of its
preparations. Such preparations 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 spent $46 million on its Year
2000 project. 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>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(in millions - except per share amounts)
<CAPTION>
Year Ended December 31,
1999 1998 1997
<S> <C> <C> <C>
REVENUES
Domestic Regulated Electric Utility Operations $6,315 $6,346 $5,880
Worldwide Electric and Gas Operations 601 51 48
TOTAL REVENUES 6,916 6,397 5,928
OPERATING EXPENSES:
Fuel and Purchased Power 2,116 2,154 1,762
Maintenance and Other Operation 1,868 1,846 1,711
Depreciation and Amortization 600 580 591
Taxes Other Than Income Taxes 476 475 469
Worldwide Electric and Gas Operations 551 95 49
TOTAL EXPENSES 5,611 5,150 4,582
OPERATING INCOME 1,305 1,247 1,346
OTHER INCOME (net) 15 - 18
INCOME BEFORE INTEREST, PREFERRED
DIVIDENDS AND INCOME TAXES 1,320 1,247 1,364
INTEREST AND PREFERRED DIVIDENDS 540 430 424
INCOME BEFORE INCOME TAXES 780 817 940
INCOME TAXES 260 281 320
INCOME BEFORE EXTRAORDINARY ITEM 520 536 620
EXTRAORDINARY ITEM - U.K. WINDFALL TAX - - (109)
NET INCOME $ 520 $ 536 $ 511
AVERAGE NUMBER OF SHARES OUTSTANDING 193 191 189
EARNINGS PER SHARE:
Before Extraordinary Item $2.69 $2.81 $ 3.28
Extraordinary Item - U.K. Windfall Tax - - (0.58)
Net Income $2.69 $2.81 $ 2.70
CASH DIVIDENDS PAID PER SHARE $2.40 $2.40 $2.40
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year Ended December 31,
1999 1998 1997
(in millions)
Net Income $520 $536 $511
Other Comprehensive Gain (Loss) 15 (1) -
COMPREHENSIVE INCOME $535 $535 $511
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(in millions - except share data)
<CAPTION>
December 31,
1999 1998
ASSETS
<S> <C> <C>
CURRENT ASSETS:
Cash and Cash Equivalents $ 333 $ 173
Accounts Receivable:
Customers 553 557
Miscellaneous 369 333
Allowance for Uncollectible Accounts (12) (11)
Fuel - at average cost 307 216
Materials and Supplies - at average cost 311 280
Accrued Utility Revenues 246 214
Energy Marketing and Trading Contracts 1,001 372
Prepayments and Other 108 84
TOTAL CURRENT ASSETS 3,216 2,218
PROPERTY PLANT AND EQUIPMENT:
Electric:
Production 9,949 9,615
Transmission 3,832 3,692
Distribution 5,536 5,125
Other (including gas and coal mining assets
and nuclear fuel) 2,307 2,118
Construction Work in Progress 581 801
Total Property, Plant and Equipment 22,205 21,351
Accumulated Depreciation and Amortization 9,150 8,549
NET PROPERTY, PLANT AND EQUIPMENT 13,055 12,802
REGULATORY ASSETS 2,171 1,847
OTHER ASSETS 3,046 2,616
TOTAL $21,488 $19,483
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
<CAPTION>
December 31,
1999 1998
LIABILITIES AND SHAREHOLDERS' EQUITY
<S> <C> <C>
CURRENT LIABILITIES:
Accounts Payable $ 699 $ 607
Short-term Debt 888 617
Long-term Debt Due Within One Year* 1,111 206
Taxes Accrued 414 382
Interest Accrued 78 75
Obligations Under Capital Leases 91 82
Energy Marketing and Trading Contracts 964 360
Other 425 472
TOTAL CURRENT LIABILITIES 4,670 2,801
LONG-TERM DEBT* 6,336 6,800
DEFERRED INCOME TAXES 2,745 2,601
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 213 222
DEFERRED INVESTMENT TAX CREDITS 326 351
DEFERRED CREDITS AND REGULATORY LIABILITIES 517 263
OTHER NONCURRENT LIABILITIES 1,511 1,429
CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES* 164 174
COMMITMENTS AND CONTINGENCIES (Notes 6 and 7)
COMMON SHAREHOLDERS' EQUITY:
Common Stock-Par Value $6.50:
1999 1998
Shares Authorized. .600,000,000 600,000,000
Shares Issued. . . .203,103,341 200,816,469
(8,999,992 shares were held in treasury
at December 31, 1999 and 1998) 1,320 1,305
Paid-in Capital 1,932 1,854
Accumulated Other Comprehensive Income-
Foreign Currency Translation Adjustments 14 (1)
Retained Earnings 1,740 1,684
TOTAL COMMON SHAREHOLDERS' EQUITY 5,006 4,842
TOTAL $21,488 $19,483
*See Accompanying Schedules.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
<CAPTION>
Year Ended December 31,
1999 1998 1997
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net Income $ 520 $ 536 $ 511
Adjustments for Noncash Items:
Depreciation and Amortization 714 620 608
Deferred Federal Income Taxes 144 41 (7)
Deferred Investment Tax Credits (25) (25) (25)
Amortization (Deferral) of Operating
Expenses and Carrying Charges (net) (151) 15 12
Equity in Earnings of Yorkshire
Electricity Group plc (45) (38) (34)
Extraordinary Item - UK Windfall Tax - - 109
Deferred Costs Under Fuel Clause Mechanisms (116) (73) (52)
Changes in Certain Current Assets
and Liabilities:
Accounts Receivable (net) (31) (142) (136)
Fuel, Materials and Supplies (122) 2 (1)
Accrued Utility Revenues (32) 3 (14)
Accounts Payable 92 200 147
Taxes Accrued 32 (1) (33)
Payment of Disputed Tax and Interest
Related to COLI (19) (303) (3)
Other (net) (144) 195 116
Net Cash Flows From Operating Activities 817 1,030 1,198
INVESTING ACTIVITIES:
Construction Expenditures (867) (792) (760)
Investment in Yorkshire Electricity Group plc - - (364)
Investment in CitiPower - (1,054) -
Investment in Gas Assets - (340) -
Other (47) (27) 2
Net Cash Flows Used For
Investing Activities (914) (2,213) (1,122)
FINANCING ACTIVITIES:
Issuance of Common Stock 91 86 77
Issuance of Long-term Debt 892 2,491 880
Retirement of Cumulative Preferred Stock (10) (1) (433)
Retirement of Long-term Debt (523) (915) (348)
Change in Short-term Debt (net) 271 62 235
Dividends Paid on Common Stock (464) (458) (453)
Net Cash Flows From (Used For)
Financing Activities 257 1,265 (42)
Net Increase in Cash and Cash Equivalents 160 82 34
Cash and Cash Equivalents January 1 173 91 57
Cash and Cash Equivalents December 31 $ 333 $ 173 $ 91
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
<CAPTION>
Paid-In Comprehensive Retained
(in millions) Common Stock Capital Income Earnings Total
Shares Amount
<S> <C> <C> <C> <C> <C> <C>
JANUARY 1, 1997 197 $1,282 $1,716 $- $1,548 $4,546
Issuances 2 11 66 - - 77
Retirements and Other - - (3) - - (3)
Net Income - - - - 511 511
Cash Dividends Declared - - - - (453) (453)
Foreign Currency
Translation Adjustments - - - - - -
DECEMBER 31, 1997 199 1,293 1,779 - 1,606 4,678
Issuances 2 12 74 - - 86
Retirements and Other - - 1 - - 1
Net Income - - - - 536 536
Cash Dividends Declared - - - - (458) (458)
Foreign Currency
Translation Adjustments - - - (1) - (1)
DECEMBER 31, 1998 201 1,305 1,854 (1) 1,684 4,842
Issuances 2 15 76 - - 91
Retirements and Other - - 2 - - 2
Net Income - - - - 520 520
Cash Dividends Declared - - - - (464) (464)
Foreign Currency
Translation Adjustments - - - 15 - 15
DECEMBER 31, 1999 203 $1,320 $1,932 $14 $1,740 $5,006
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Significant Accounting Policies:
Organization - American Electric Power Company, Inc. (AEP or the
Company) is one of the United States' (U.S.) largest investor-owned
public utility holding companies engaged in the generation,
purchase, transmission and distribution of electric power to 3
million retail customers in its seven state service territory which
covers portions of Ohio, Michigan, Indiana, Kentucky, West
Virginia, Virginia and Tennessee. Electric power is also supplied
at wholesale to neighboring utility systems and power marketers.
AEP also has energy holdings in the U.S., the United Kingdom (UK),
China and Australia.
The organization of AEP consists of American Electric Power
Company, Inc. (AEP Co., Inc.), the parent holding company; seven
domestic regulated electric utility operating companies (domestic
utility subsidiaries); a domestic generating subsidiary, AEP
Generating Company (AEGCo); two active coal-mining companies; a
service company, American Electric Power Service Corporation
(AEPSC); AEP Resources, Inc. (AEPR) a subsidiary which invests in,
owns and operates energy-related domestic and international
projects and companies; AEP Energy Services, Inc. (AEPES) a
non-regulated subsidiary which markets and trades energy commodities;
and other subsidiaries that provide energy and communication
services.
The following domestic utility subsidiaries pool their generating
and transmission facilities and operate them as an integrated
system: Appalachian Power Company (APCo), Columbus Southern Power
Company (CSPCo), Indiana Michigan Power Company (I&M), Kentucky
Power Company (KPCo) and Ohio Power Company (OPCo). The remaining
two domestic utility subsidiaries, Kingsport Power Company (KGPCo)
and Wheeling Power Company (WPCo) are distribution companies that
purchase power from APCo and OPCo, respectively. AEPSC provides
management, professional and other services to the AEP System
subsidiaries. The active coal-mining companies are wholly-owned by
OPCo (see Note 3 for information regarding shutdown of affiliated
mines). AEGCo has a 50% interest in the Rockport Plant which is
comprised of two of the AEP System's six 1,300 megawatt (MW)
generating units. AEPR owns 50% of Yorkshire Electricity Group plc
(Yorkshire), a supply and distribution utility company in the UK
(see Note 9); 70% of Nanyang General Light Electric Co., Ltd.,
owner of a two-unit power plant in China; 20% of Pacific Hydro, an
Australian hydroelectric generating company; all of the assets of
a midstream natural gas operation in Louisiana and 100% of
CitiPower, a Melbourne, Australia supply and distribution utility.
AEPES principally markets and trades natural gas. Two non-regulated
subsidiaries, AEP Resources Service Company and AEP
Communications are engaged in providing power engineering,
consulting and management services around the world and fiber,
wireless and information communication services in the U.S.
Although the domestic utility subsidiaries are managed centrally by
AEPSC and operate as American Electric Power they and AEPSC have
not changed their names and remain separate legal entities.
Rate Regulation - The AEP System is subject to regulation by the
Securities and Exchange Commission (SEC) under the Public Utility
Holding Company Act of 1935 (1935 Act). The rates charged by the
domestic utility subsidiaries are approved by the Federal Energy
Regulatory Commission (FERC) and the state utility commissions.
The FERC regulates wholesale electricity rates and transmission
rates and the state commissions regulate retail generation and
distribution rates.
Principles of Consolidation - The consolidated financial statements
include AEP Co., Inc. and its wholly-owned and majority-owned
subsidiaries consolidated with their wholly-owned subsidiaries.
Significant intercompany items are eliminated in consolidation.
Yorkshire and Pacific Hydro are accounted for using the equity
method with their equity earnings included in revenues from
worldwide electric and gas operations.
Basis of Accounting - As the owner of cost-based rate-regulated
electric public utility companies, AEP Co., Inc.'s consolidated
financial statements reflect the actions of regulators that result
in the recognition of revenues and expenses in different time
periods than enterprises that are not rate regulated. In
accordance with Statement of Financial Accounting Standards (SFAS)
71, "Accounting for the Effects of Certain Types of Regulation,"
regulatory assets (deferred expenses) and regulatory liabilities
(deferred revenue) are recorded to reflect the economic effects of
regulation by matching expenses with their recovery through
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.
Property, Plant and Equipment - Property, plant and equipment are
stated at original cost of the acquirer. Additions, major
replacements and betterments are added to the plant accounts.
Retirements from the plant accounts and associated removal costs,
net of salvage, are deducted from accumulated depreciation. The
costs of labor, materials and overheads incurred to operate and
maintain utility plant are included in operating expenses.
Allowance for Funds Used During Construction (AFUDC) - AFUDC is a
noncash nonoperating income item that is capitalized and recovered
through depreciation over the service life of domestic regulated
electric utility plant. For domestic regulated electric 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. Worldwide operations
capitalize interest during construction in accordance with SFAS 34,
"Capitalization of Interest Costs."
Depreciation, Depletion and Amortization - Depreciation of
property, plant and equipment is provided on a straight-line basis
over the estimated useful lives of property, other than coal-mining
property, and is calculated largely through the use of composite
rates by functional class as follows:
<TABLE>
<CAPTION>
Functional Class
of Property Annual Composite Depreciation Rates Ranges
1999 1998 1997
<S> <C> <C> <C>
Production:
Steam-Nuclear 3.4% 3.4% 3.4%
Steam-Fossil-Fired 3.2% to 5.0% 3.2% to 4.4% 3.2% to 4.4%
Hydroelectric-Conventional
and Pumped Storage 2.7% to 3.4% 2.7% to 3.4% 2.7% to 3.2%
Transmission 1.7% to 2.7% 1.7% to 2.7% 1.7% to 2.7%
Distribution 2.8% to 4.2% 3.3% to 4.2% 3.3% to 4.2%
Other 2.0% to 20.0% 2.5% to 3.8% 2.5% to 3.8%
</TABLE>
Depreciation, depletion and amortization of coal-mining assets is
provided over each asset's estimated useful life or the estimated
life of the mine, whichever is shorter, and is calculated using the
straight-line method for mining structures and equipment. The
units-of-production method is used to amortize coal rights and mine
development costs based on estimated recoverable tonnages at a
current average rate of $2.32 per ton in 1999, $1.85 per ton in
1998 and $1.91 per ton in 1997. These costs are included in the
cost of coal charged to fuel expense. See Note 3 regarding closure
of affiliated mines.
Cash and Cash Equivalents - Cash and cash equivalents include
temporary cash investments with original maturities of three months
or less.
Foreign Currency Translation - The financial statements of
subsidiaries outside the U.S. are measured using the local currency
as the functional currency. Assets and liabilities are translated
to U.S. dollars at year-end rates of exchange and revenues and
expenses are translated at monthly average exchange rates
throughout the year. Currency translation gain and loss
adjustments are accumulated in shareholders' equity. Currency
transaction gains and losses are recorded in income.
Energy Marketing and Trading Transactions - The Company makes
wholesale electricity and natural gas marketing and trading
transactions (trading activities). Trading activities involve the
sale of energy under physical forward contracts at fixed and
variable prices and the trading of energy 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 Company's traditional
marketing area and are typically settled by entering into
offsetting contracts. The net revenues from these transactions in
the Company's traditional marketing area are included in regulated
revenues for ratemaking, accounting and financial and regulatory
reporting purposes.
The Company also purchases and sells electricity and gas options,
futures and swaps, and enters into forward purchase and sale
contracts for electricity outside its traditional marketing area
and for gas. These transactions represent non-regulated trading
activities that are included in worldwide revenues.
In the first quarter of 1999 the Company adopted the Financial
Accounting Standards Board's 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 electricity trading transactions within the Company's
marketing area that are included in cost of service on a settlement
basis for ratemaking purposes in the Company's non-Virginia
jurisdictions. A Virginia jurisdiction net mark-to-market after-tax
gain of $3 million as of December 31, 1999 is included in net
income as a result of an agreed prohibition against establishing
new regulatory assets in a February 1999 Virginia State Corporation
Commission (Virginia SCC) approved settlement agreement. Non-regulated
open trading contracts are accounted for on a mark-to-market basis
and included in worldwide electric and gas operations
revenues. Unrealized mark-to-market gains and losses from all
trading activity 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 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 14 - Financial Instruments, Credit and Risk Management for
further discussion.
Revenues and Fuel Costs - Regulated revenues include the accrual of
electricity consumed but unbilled at month-end as well as billed
revenues. Fuel costs are matched, in accordance with SFAS 71, with
their recovery from/to customers through regulated revenues in
accordance with rate commission orders. Generally in order to
accomplish a proper matching in the retail jurisdictions, changes
in fuel costs are deferred or revenues accrued until approved by
the regulatory commission for billing or refund to customers in
later months. Wholesale jurisdictional fuel cost changes are
expensed and billed as incurred.
Levelization of Nuclear Refueling Outage Costs - In order to match
costs with regulated revenues, incremental operation and
maintenance costs associated with refueling outages at I&M's 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 Indiana Utility Regulatory
Commission (IURC) and the Michigan Public Service Commission (MPSC)
to resolve all issues related to an extended outage of the Cook
Plant, I&M deferred certain operation and maintenance costs in
1999. The settlement agreements provide for the deferral of $150
million of Indiana jurisdictional and $50 million of Michigan
jurisdictional incremental 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. I&M
deferred $200 million and amortized $40 million in 1999 leaving
$160 million as an SFAS 71 regulatory asset at December 31, 1999 on
the Consolidated Balance Sheet. See Note 2 "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 regulated
revenues (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 the
regulated plant investment.
Debt and Preferred Stock - Gains and losses from the reacquisition
of debt used to finance domestic regulated electric utility plant
are generally deferred and amortized over the remaining term of the
reacquired debt in accordance with their rate-making treatment. If
the debt is refinanced the reacquisition costs are generally
deferred except in Virginia and amortized over the term of the
replacement debt commensurate with their recovery in rates.
Debt discount or premium and debt issuances 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 of the
domestic utility subsidiaries are included in paid-in capital and
amortized to retained earnings commensurate with their recovery in
rates. The excess of par value over costs of preferred stock
reacquired is credited to paid-in capital and amortized to retained
earnings consistent with the timing of its recovery in rates in
accordance with SFAS 71.
Other Assets - Other assets are comprised primarily of nuclear
decommissioning and spent nuclear fuel disposal trust funds;
licenses for CitiPower operating franchises; amounts for corporate
owned life insurance and related disputed tax payments; the
investments in Yorkshire and Pacific Hydro which are accounted for
under the equity method of accounting; and goodwill. Securities
held in trust funds for decommissioning nuclear facilities and for
the disposal of spent nuclear fuel are recorded at market value in
accordance with SFAS 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 spent nuclear fuel disposal trust funds. The
recoverability of goodwill (evaluated on the basis of undiscounted
operating cash flow analysis) is reviewed when events or changes in
circumstances indicate that the carrying amount may exceed fair
value.
EPS - Earnings per share is determined based upon the weighted
average number of shares outstanding. There are no dilutive
potential common shares. Therefore, earnings per share is the same
for basic earnings per share and diluted earnings per share.
Reclassification - Certain prior year amounts have been
reclassified to conform to current year presentation. Such
reclassification had no impact on previously reported net income.
2. Nuclear Plant Shutdown:
I&M owns and operates the two-unit 2,110 MW Cook Plant under
licenses granted by the Nuclear Regulatory Commission (NRC). I&M
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 I&M
to address certain issues identified in the letter. In 1998 the
NRC notified I&M 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, I&M 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.
I&M'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, I&M 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 certain 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 I&M's actual replacement
energy fuel costs that exceeded the costs reflected in billings
were recorded as a regulatory asset under 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 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 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 I&M'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 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 million and $78 million, respectively, and were
recorded in other operation and maintenance expense. In 1999 the
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. Restart costs
incurred in 2000 will be accounted for as a current period
operation 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 units will be successfully
returned to service in 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:
OPCo's Recovery of Fuel Costs - Under the terms of a 1992
stipulation agreement the cost of coal burned at the Gavin Plant is
subject to a 15-year predetermined price of $1.575 per million
Btu's with quarterly escalation adjustments through November 2009.
A 1995 Settlement Agreement set the fuel component of the electric
fuel component (EFC) factor at 1.465 cents per kilowatthour (kwh)
for the period June 1, 1995 through November 30, 1998. The 1995
Settlement Agreement requires for the two year period from December
1, 1998 through November 30, 2000 that coal from Central Ohio Coal
Company's Muskingum mine and Windsor Coal Company's mine be priced
at the market price for comparable quality coal. The Company is
allowed to defer the difference for future recovery. Effective
December 1, 1998 the 1992 stipulation continued to control the
recovery of fuel costs at the Gavin Plant and the ability of OPCo
to recover the costs to shut down its affiliated mines. To the
extent the actual cost of coal burned at the Gavin Plant is below
the predetermined prices, the stipulation agreement provides OPCo
with the opportunity to recover over its term the Ohio
jurisdictional share of OPCo's investment in and the liabilities
and future shutdown costs of its affiliated mines as well as any
fuel costs incurred above the predetermined rate and deferred for
future recovery under the agreements. These agreements will be
superseded effective January 1, 2001 by the Ohio Electric
Restructuring Act of 1999 (see Note 5).
The Muskingum coal mine which supplied all of its output to OPCo
was closed in October 1999. During 1999 efforts began to reclaim
the properties, sell or scrap all mining equipment, terminate both
capital and operating leases and perform other activities necessary
to shut down the mine. Mine reclamation activities should be
completed by December 31 2002; postremediation monitoring is
anticipated to continue for five years after completion of
reclamation.
In 1999 the Company announced that the affiliated Windsor coal mine
would close April 30, 2000. After the mine closes, efforts will
begin to reclaim the property, sell or scrap all mining equipment
and perform other activities necessary to shut down the mine.
Reclamation activities should be completed within two to three
years after shutdown.
The Company recorded mine closing costs of $45 million in 1998 for
the Muskingum mine and $48 million in 1999 for the Windsor mine.
Pursuant to terms of the 1992 and 1995 agreements, the Company
deferred accrued mine closure costs of $19 million in 1998 for the
Muskingum mine and $25 million in 1999 for the Windsor mine. Fuel
expense included $23 million and $26 million in 1999 and 1998,
respectively, of mine closure costs. At December 31, 1999, the
accrued liabilities for reclamation, mine closing costs and post
shutdown costs were $119 million for the Muskingum mine and $84
million for the Windsor mine.
Revenues and net income for the Muskingum mining operation in 1999
up to the shutdown date were $64 million and $1,000, respectively.
For the years ended December 31, 1998 and 1997 revenues and net
income from the Muskingum mining operation were $110 million and
$1,000 and $66 million and zero, respectively. For the years ended
December 31, 1999, 1998 and 1997 revenues and net income from the
Windsor mining operation were $123 million and $18,000, $65 million
and $123,000, and $69 million and $1 million, respectively.
Management believes that existing deferrals for the Ohio
jurisdictional portion of the cost of the mine shutdowns can be
deferred for future recovery through the Ohio fuel clause mechanism
under terms of the Ohio fuel clause predetermined price agreements.
At December 31, 1999 the Company has deferred $196 million under
the terms of the Ohio fuel clause predetermined price agreements.
However, since the Ohio Electric Restructuring Act of 1999 (the
Act) supersedes the agreements, the Company has filed under the
provisions of the Act for recovery of all of its generation
related regulatory assets which includes the fuel deferral at
December 31, 1999 plus the projected balance that will be deferred
for the accrual of the Meigs mine closure costs by the beginning of
the transition period, January 1, 2001. Under the provisions of
the Act the Company is seeking a total of $360 million for the
regulatory assets deferred under the above agreements through
transition rates and a post generation deregulation five year wires
charge. Unless the cost of the remaining coal production and
deferred mine shutdowns are recovered through the remaining Ohio
fuel clause rates and Ohio restructuring transition rates and/or a
post deregulation wires charge, future results of operations and
cash flows will be adversely affected.
Management intends to continue to recover from non-Ohio
jurisdictional ratepayers the non-Ohio jurisdictional portion of
the investment in and the liabilities and closing costs of the
Meigs, Muskingum and Windsor mines. The non-Ohio jurisdictional
portion of shutdown costs for these mines which includes the
investment in the mines, leased asset buy-outs, reclamation costs
and employee benefits is estimated to be approximately $62 million
after tax at December 31, 1999.
FERC - 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.
On July 9, 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 AEP'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. AEP and certain
of the affected customers sought rehearing of the Commission's
Order. The Company made a provision in September 1999 for the
refund including interest.
On December 10, 1999, AEP filed a settlement agreement with the
FERC resolving the issues on rehearing of the July 30, 1999 order.
Under terms of the settlement, AEP 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 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 AEP 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.
West Virginia
On May 12, 1999, the Company's subsidiary, APCo, filed with the
Public Service Commission of West Virginia (WVPSC) for a base rate
increase of $50 million annually and a reduction in expanded net
energy cost (ENEC) rates of $38 million annually. On February 7,
2000, APCo and other parties to the proceeding filed a Joint
Stipulation and Agreement for Settlement (Joint Stipulation) with
the WVPSC for approval. The Joint Stipulation's main provisions
include no change in either base or ENEC rates effective January 1,
2000 from those base and ENEC rates in effect from November 1, 1996
until December 31, 1999 (these rates provide for recovery of
regulatory assets including any generation related regulatory
assets of approximately 0.5 mills per kwh); annual ENEC recovery
proceedings are suspended and deferral accounting for over or under
recovery is discontinued effective January 1, 2000; the net
cumulative deferred ENEC recovery balance as established by a WVPSC
order on December 27, 1996, which is $66 million at December 31,
1999, shall remain on the books as a regulatory liability.
However, if deregulation of generation occurs in West Virginia
(WV), APCo will use this regulatory liability to reduce
unrecoverable generation-related regulatory assets and, to the
extent possible, any additional cost or obligations that
deregulation may impose. 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. All cost
incurred in the merger that are allocated to APCo, whether the
merger is consummated or not, shall be fully charged to expense as
of December 31, 2004 and shall not be included in any WV rate
proceeding after that date. After December 31, 2004, any savings
related to the merger will be reflected in rates in any future rate
proceeding before the WVPSC to establish distribution rates or to
adjust rate caps during the transition to market based rates. If
deregulation of generation occurs in WV the net retained generation
related merger savings should be used to recover any generation
related regulatory assets that are not recovered under the
provisions of the Joint Stipulation and the mechanisms provided for
in the deregulation legislation and, to the extent possible, to
recover any additional costs or obligations that deregulation may
impose on APCo. Regardless of whether the net cumulative deferred
ENEC recovery balance and the net merger savings are sufficient to
offset all of APCo's generation related regulatory assets, under
the terms of the Joint Stipulation there will be no further
explicit adjustment to APCo's rates to provide for recovery of
generation-related regulatory assets beyond the above discussed
specific adjustments provided in the Joint Stipulation and the 0.5
mills per kwh wires charge in the WV Restructuring Plan (see Note
5 for discussion of WV Restructuring Plan).
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 revenues) 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
all 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. (See Note 5 "Restructuring Legislation".)
Recognized regulatory assets and liabilities are comprised of the
following at:
December 31,
1999 1998
(in millions)
Regulatory Assets:
Amounts Due From Customers For
Future Income Taxes $1,278 $1,324
Deferred Fuel Costs 424 193
Unamortized Loss on Reacquired Debt 84 91
Other 385 239
Total Regulatory Assets $2,171 $1,847
Regulatory Liabilities:
Deferred Investment Tax Credits $326 $351
Other Regulatory Liabilities* 300 148
Total Regulatory Liabilities $626 $499
* Included in Deferred Credits and Regulatory Liabilities on
Consolidated Balance Sheets.
Rate phase-in plans in the Indiana and the FERC jurisdictions
provided for the recovery and straight-line amortization of
deferred Rockport Plant Unit 1 costs over a ten year period that
ended in 1997. In 1997 amortization and recovery of the deferred
Rockport Plant Unit 1 phase-in plan costs were $11.9 million.
During the recovery period net income was unaffected by the
recovery of the phase-in deferrals.
5. Restructuring Legislation:
Ohio
The Ohio Electric Restructuring Act of 1999 (the Act) became law in
October 1999. The Act provides for customer choice of electricity
supplier, a residential rate reduction of 5% for the generation
portion of rates and a freezing of generation rates including fuel
rates beginning on January 1, 2001. The Act also provides for a
five-year transition period to move from cost based rates to market
pricing for generation services. It authorizes the Public
Utilities Commission of Ohio (PUCO) to address certain major
transition issues including unbundling of rates and the recovery of
transition costs. Under the Act, transition costs can include
regulatory assets, generating asset impairments and other stranded
costs, employee severance and retraining costs, consumer education
costs 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.
Retail electric services that will be competitive are defined in
the Act as electric generation service, aggregation service and
power marketing and brokering. Under the legislation the PUCO is
granted broad oversight responsibility and is required by the Act
to promulgate rules for competitive retail electric generation
service and transition plan filings. The Act also gives the PUCO
authority to approve a transition plan for each electric utility
company and sets a deadline of no later than October 31, 2000 for
those approvals.
The Act provides Ohio electric utilities with an opportunity to
recover PUCO approved allowable transition costs through generation
rates paid through December 31, 2005 by customers who do not switch
generation suppliers and through a transition charge for customers
who switch generation suppliers. Recovery of the regulatory asset
portion of transition costs can, under certain circumstances,
extend beyond the five-year transition period but cannot continue
beyond December 31, 2010.
The Act also provides for a reduction in property tax assessments,
the imposition of franchise and income taxes, and the replacement
of a gross receipts tax with a kwh based excise tax. The property
tax assessment percentage on generation property will be lowered
from 100% to 25% of value effective January 1, 2001 and electric
utilities will become subject to the Ohio Corporate Franchise Tax
and municipal income taxes on January 1, 2002. The last year for
which electric utilities will pay the excise tax based on gross
receipts is the tax year ending April 30, 2002. As of May 1, 2001
electric distribution companies will be subject to an excise tax
based on kwh sold to Ohio customers. The gross receipts tax is
paid at the beginning of the tax year, deferred as a prepaid
expense and amortized to expense during the tax year pursuant to
the tax law whereby the payment of the tax results in the privilege
to conduct business in the year following the payment of the tax.
The change in the tax law to impose an excise tax based on kwh sold
to Ohio customers commencing before the expiration of the gross
receipts tax privilege period will result in a 12 month period when
electric utilities are recording as an expense both the gross
receipts tax and the excise tax. In the Company's Ohio transition
plan filings, recovery of $90 million was sought for this overlap
of the gross receipts and excise taxes.
The Company filed its transition plan for OPCo and CSPCo (its Ohio
jurisdictional subsidiaries) with the PUCO on December 30, 1999.
The filings included the following elements:
a rate unbundling plan including tariff terms and conditions
necessary for restructuring,
a corporate separation plan,
an application for transition revenues,
a plan for independent operation of transmission facilities
and
other components for the implementation of restructuring.
Under the rate unbundling plan in the transition plan filing, the
Company's Ohio retail jurisdictional companies will offer two
transition period tariffs beginning January 1, 2001, the standard
tariff and the open access distribution tariff. The proposed
standard tariff applies to customers who do not choose an
alternative energy supplier. This tariff schedule includes
detailed charges for generation, transmission and distribution and
riders to fund universal service, to promote energy efficiency and
to recover regulatory assets and taxes. Taxes include charges for
municipal income, excise and franchise taxes and tax credits for
gross receipts and property taxes. For customers who choose an
alternative electric supplier, the proposed open access
distribution tariff will apply. This tariff includes charges for
transmission and distribution and riders to fund universal service,
to promote energy efficiency and to recover regulatory assets and
taxes. These riders are the same as those in the standard tariff
except there is no property tax credit.
The corporate separation plan contains proposals for each of the
Company's Ohio jurisdictional companies to establish separate
subsidiaries to own and operate their transmission and distribution
assets. The separation plan will be implemented in a manner that
recognizes the current overlap of financing arrangements. This
would permit an orderly and economically efficient separation of
each operating company so that additional transition costs can be
avoided from premature unwinding of existing financial instruments.
Prior to the actual legal separation, the Ohio jurisdictional
companies will functionally separate generation from transmission
and distribution.
An application to receive transition revenues was included in the
transition plan filing. It requests recovery of stranded
generation costs over a five year period and recovery of
generation-related regulatory assets of $974 million over a 10-year
period. The amount requested for recovery of regulatory assets
includes current and new regulatory assets including those arising
from compliance with the Act and closure of the affiliated mines.
Included in the transition plan is a proposal to implement
independent operation of the transmission system. The Company
proposes to join a regional transmission organization whose
approval is currently pending before the FERC.
A project timeline for activities to implement operational support
systems and other technical implementation issues to arrive at and
support a competitive electricity market are included in the
transition plan.
The Company plans to provide severance, retraining, early
retirement, retention, outplacement and other assistance for
displaced employees. At this time no employees are identified as
affected by electric utility restructuring. Consequently, recovery
of such costs was not requested in transition revenues as filed
with the transition plan.
The transition plan includes a consumer education plan which will
be implemented in conjunction with other electric utilities and the
PUCO staff. The transition plan also has terms and conditions for
changing suppliers and the commitment of time a customer must
accept in a service contract which are two features necessary to
accommodate restructuring.
A proposed shopping incentive in the transition plan represents the
lower of the market price or the unbundled generation rate in
current tariff schedules.
As discussed in Note 4, "Effects of Regulation and Phase-In Plans,"
the Company defers as regulatory assets and liabilities certain
expenses and revenues consistent with the regulatory process in
accordance with SFAS 71. Management has concluded that as of
December 31, 1999 the requirements to apply SFAS 71 continue to be
met since the Company's rates for generation will continue to be
cost-based regulated until the PUCO takes action on the transition
plan and the proposed tariff schedules contained in it as provided
in the Act. The establishment of rates and charges under the
transition plan should enable the Company to determine its ability
to recover regulatory assets, transition costs and other stranded
costs, a requirement to discontinue application of SFAS 71.
When the transition plan and tariff schedules are approved, the
application of SFAS 71 will be discontinued for the Ohio retail
jurisdictional portion of the generation business. At that time
the Company will have to write-off its Ohio jurisdictional
generation-related regulatory assets to the extent that they cannot
be recovered under the tariff schedules in the transition plan
approved by the PUCO and record any asset impairments in accordance
with SFAS 121, "Accounting for the Impairment of Long-lived Assets
and for Long-lived Assets to Be Disposed Of." An impairment loss
would be recorded to the extent that the cost of generation assets
cannot be recovered through generation-related revenues during the
transition period and future market prices. Until the PUCO
completes its regulatory process and issues an order related to the
Company's transition plan, it is not possible for management to
determine if any of the Company's generating assets are impaired in
accordance with SFAS 121. The amount of regulatory assets recorded
on the books at December 31, 1999 applicable to the Ohio retail
jurisdictional generating business is $666 million before related
tax effects. Due to the planned closing of affiliated mines and
other anticipated events, generation-related regulatory assets as
of December 31, 2000 allocable to the Ohio retail jurisdiction are
estimated to exceed $800 million, before income tax effects.
Recovery of these regulatory assets and an estimated asset
impairment are being sought as a part of the Company's Ohio
transition plan filing.
A determination of whether the Company will experience any asset
impairment loss regarding its Ohio retail jurisdictional generating
assets and any loss from a possible inability to recover Ohio
generation-related regulatory assets and other transition costs
cannot be made until the PUCO takes action on the Company's
transition plan. Management is seeking full recovery of
generation-related regulatory assets, stranded costs and other
transition costs in its transition plan filing. The PUCO is
required to complete its regulatory process including review of the
Company's transition plan filing and issue a transition order no
later than October 31, 2000. Should the PUCO fail to fully approve
the Company's transition plan and its tariff schedules which
include recovery of the Company's generation-related regulatory
assets, stranded costs and other transition costs, it could have a
material adverse effect on results of operations, cash flows and
possibly financial condition.
Virginia
In March 1999 a law was enacted in Virginia to restructure the
electric utility industry. Under the restructuring law a
transition to choice of electricity supplier for retail customers
will commence on January 1, 2002 and be completed, subject to a
finding by the Virginia SCC that an effective competitive market
exists, on January 1, 2004.
The law also provides an opportunity for recovery of just and
reasonable net stranded generation costs. The mechanisms in the
Virginia law for net stranded cost recovery are: a capping of rates
until as late as July 1, 2007, and the application of a wires
charge upon customers who depart the incumbent utility in favor of
an alternative supplier prior to the termination of the rate cap.
The law provides for the establishment of capped rates prior to
January 1, 2001 and the establishment of a wires charge by the
fourth quarter of 2001.
Management has concluded that as of December 31, 1999 the
requirements to apply SFAS 71 continue to be met. The Company's
Virginia rates for generation will continue to be cost-based
regulated until the establishment of capped rates and the wires
charge as provided in the law. The establishment of capped rates
and the wires charge should enable management to determine its
ability to recover stranded costs, a requirement to discontinue
application of SFAS 71.
When the capped rates and the wires charge are established in
Virginia, the application of SFAS 71 will be discontinued for the
Virginia retail jurisdictional portion of the Company's generating
business. At that time the Company will have to write-off its
generation-related regulatory assets to the extent that they cannot
be recovered under the capped rates and wire charges approved by
the Virginia SCC under the provisions of the restructuring law and
record any asset impairments in accordance with SFAS 121. An
impairment loss would be recorded to the extent that the cost of
impaired assets cannot be recovered through generation-related
revenues during the transition period and future market prices.
Absent the determination through the regulatory process, wires
charges and other pertinent information of capped rates as required
by the restructuring law, it is not possible at this time for
management to determine if any generation-related assets are
impaired in accordance with SFAS 121 and if generation-related
regulatory assets will be recovered. The amount of regulatory
assets recorded on the books applicable to the Company's Virginia
retail generating business at December 31, 1999 is estimated to be
$64 million before related tax effects.
Should it not be possible under the Virginia law to recover all or
a portion of the generation-related regulatory assets and/or
tangible generating assets, it could have a material adverse impact
on results of operations and cash flows. An estimated
determination of whether the Company will experience any asset
impairment loss regarding its Virginia retail jurisdictional
generating assets and any loss from a possible inability to recover
generation-related regulatory assets and other transition costs
cannot be made until such time as the Company completes economic
studies to estimate an asset impairment and until the transition
period capped rates and the wires charge are determined under the
law, which is expected to occur by the fourth quarter of 2000.
West Virginia
On January 28, 2000, the WVPSC issued an order approving an
electricity restructuring plan for West Virginia. The
restructuring plan has been submitted to the West Virginia
Legislature for approval or rejection which is expected to occur
during the current legislative session that ends in March 2000.
Until approved by the West Virginia Legislature, the restructuring
plan cannot take effect. The Company's subsidiaries, APCo and
WPCo, which do business in West Virginia, will be affected by the
proposed restructuring.
The provisions of the proposed restructuring plan provide for
customer choice to begin on January 1, 2001, or at a later date set
by the WVPSC after all necessary rules are in place (the "starting
date"); deregulation of generation assets occurring on the starting
date; functional separation of the generation, transmission and
distribution businesses on the start date and their legal corporate
separation no later than January 1, 2005; a transition period of up
to 13 years, during which the incumbent utility must provide
default service for customers who do not change suppliers unless an
alternative default supplier is selected through a WVPSC-sponsored
bidding process; capped and fixed rates for the 13 year transition
period as discussed below; deregulation of metering and billing; a
0.5 mills per kwh wires charge applicable to all retail customers
for the period January 1, 2001 through December 31, 2010 intended
to provide for recovery of any stranded cost including net
regulatory assets; establishment of a rate stabilization deferred
balance by AEP of $81 million by the end of year ten of the
transition period to be used as determined by the WVPSC to offset
prices paid in the eleventh, twelfth, and thirteenth year of the
transition period by residential and small commercial customers
that do not choose a supplier.
Default rates for residential and small commercial customers are
capped for four years after the starting date and then increased as
specified in the plan for the next six years. In years eleven,
twelve and thirteen of the transition period, the power supply rate
shall equal the market price of comparable power. Default rates
for industrial and large commercial customers are discounted by 1%
for four and a half years, beginning July 1, 2000, and then
increased at pre-defined levels for the next three years. After
seven years the power supply rate for industrial and large
commercial customers will be market based.
Management has concluded that as of December 31, 1999 the
requirements to apply SFAS 71 continue to be met. The Company's
West Virginia rates for generation will continue to be cost-based
regulated until the West Virginia Legislature approves the
restructuring plan. At that time, management should be able to
determine its ability to recover stranded costs, a requirement to
discontinue application of SFAS 71.
When the restructuring plan is enacted into law, the application of
SFAS 71 will be discontinued for the West Virginia retail
jurisdictional portion of the Company's generating business. At
that time the Company will have to write-off its generation-related
regulatory assets to the extent that they cannot be recovered under
the provisions of the approved restructuring plan and record any
asset impairments in accordance with SFAS 121. An impairment loss
would be recorded to the extent that the cost of impaired assets
cannot be recovered through generation-related revenues during the
transition period and future market prices. Absent the approval
through the regulatory and legislative processes of rates and other
pertinent information, it is not possible at this time for
management to determine if any generation-related assets are
impaired in accordance with SFAS 121 and if generation-related
regulatory assets will be recovered. The amount of regulatory
assets recorded on the books applicable to the Company's West
Virginia retail generating business at December 31, 1999 is
estimated to be $131 million before related tax effects.
Should it not be possible under the West Virginia restructuring
plan to recover all or a portion of the generation-related
regulatory assets and/or tangible generating assets, it could have
a material adverse impact on results of operations and cash flows.
An estimated determination of whether the Company will experience
any asset impairment loss regarding its West Virginia retail
jurisdictional generating assets and any loss from a possible
inability to recover generation-related regulatory assets and other
transition costs cannot be made until such time as the Company
completes economic studies to estimate an asset impairment and
until the West Virginia Legislature approves the restructuring plan
and the WVPSC approves the Joint Stipulation (See Note 3), which
are both expected to occur in March 2000.
6. Commitments and Contingencies:
Construction and Other Commitments - The AEP System has substantial
construction commitments to support its utility operations.
Aggregate construction expenditures for 2000-2002 for consolidated
domestic and foreign operations are estimated to be $2.8 billion.
Long-term contracts to acquire fuel for electric generation have
been entered into for various terms, the longest of which extends
to the year 2014. The contracts provide for periodic price
adjustments and contain various clauses that would release the
Company from its obligation under certain force majeure conditions.
The AEP System has contracted to sell approximately 1,275 MW of
capacity domestically on a long-term basis to unaffiliated
utilities. Certain of these contracts totaling 250 mw of capacity
are unit power agreements requiring the delivery of energy only if
the unit capacity is available. The power sales contracts expire
from 2000 to 2010.
Nuclear Plant - I&M owns and operates the two-unit 2,110 MW Cook
Plant under licenses granted by the NRC. The operation of a
nuclear facility involves special risks, potential liabilities, and
specific regulatory and safety requirements. Should a nuclear
incident occur at any nuclear power plant facility in the 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 adversely 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 the 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. I&M could
be assessed up to $23 million annually under these policies.
Spent Nuclear Fuel (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
kwh 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 are in trust funds
and approximate the liability.
Decommissioning and Low Level Waste Accumulation Disposal -
Decommissioning costs are accrued over the service life of the Cook
Plant. The licenses to operate the two nuclear units expire in
2014 and 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. I&M 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. I&M 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 I&M
withdrew $8 million and $3 million, respectively, from the trust
fund for decommissioning of the original steam generators removed
from Unit 2. At December 31, 1999 and 1998, I&M 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 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 certain of its coal-fired generating plants 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 Notices
of Violation to the Company alleging similar 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 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 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, and where states are deregulating generation, unbundled
transition period generation rates, wires charges and future market
prices for energy.
COLI 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 $317 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 sheet in other assets 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
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 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.
Other - The Company is involved in a number of other legal
proceedings and claims. While management is unable to predict the
ultimate outcome of these matters, it is not expected that their
resolution will have a material adverse effect on the results of
operations, cash flows or financial condition.
7. 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
Company, 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 $1.6 billion 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.
8. Proposed Merger:
The Company and Central and South West Corporation (CSW) announced
plans to merge in December 1997. The appropriate shareholder
proposals for the consummation of the merger were approved in 1998.
Both companies have mutually agreed to extend the closing of the
merger available in the original 1997 agreement to gain the final
regulatory approvals. The amendment to the merger agreement
requires that the companies close the merger before June 30, 2000.
The merger has already received approval from state regulatory
commissions in Arkansas, Louisiana, Oklahoma and Texas, the four
states within CSW's service territory which are required to approve
the merger. AEP has reached agreements with its state regulatory
commission in Indiana, Michigan, Ohio and Kentucky. These AEP
service territory state commissions have agreed not to oppose the
merger in federal proceedings. In addition, the Nuclear Regulatory
Commission has approved a license transfer application for the
transfer of control of CSW subsidiary Central Power and Light's
South Texas Nuclear Plant to the Company and the Department of
Justice closed its investigation under the Hart-Scott-Rodino
Antitrust Improvements Act. Also, in 1998 the FERC issued an order
which confirmed that a 250 MW firm contract path with the Ameren
System was available. The contract path was obtained by the
Company and CSW to meet the requirement of the Public Utility
Holding Company Act of 1935 that the two systems operate on an
integrated and coordinated basis.
The merger requires additional approvals by the FERC and the SEC.
On July 29, 1999 applications were made with the Federal
Communication Commission to authorize the transfer of control of
licenses of several CSW entities to the Company.
FERC
In November, 1998 the FERC issued an order establishing hearing
procedures for the merger. The 1998 FERC order indicated that the
review of the proposed merger will address the issues of
competition, market power and customer protection. On May 25, 1999
AEP and CSW reached a settlement with the FERC trial staff
resolving competition and rate issues relating to the merger. On
July 13, 1999 AEP and CSW reached an additional settlement with the
FERC trial staff resolving additional issues. The settlements were
submitted to the FERC for approval. Under the terms of the
settlements, AEP filed with the FERC a regional transmission
organization (RTO) proposal whereby it will transfer the operation
and control of AEP's bulk transmission facilities to an RTO. The
settlements also cover rates for transmission services and
ancillary service as well as resolve issues related to system
integration agreements and confirm, subject to FERC guidance on
certain elements, that the proposed generation divestiture of up to
550 megawatts of capacity will satisfy the staff's market power
concerns. FERC hearings began on June 29, 1999 and concluded on
July 19, 1999.
On June 28, 1999, the Company and CSW filed a motion asking the
FERC to waive the requirement for a post-hearing decision by an
administrative law judge (ALJ) who presides over the merger
hearing. The motion indicated that the commission could then
decide the matter based on the hearing record and briefs submitted
by all interested parties. On July 28, 1999, the FERC ordered the
ALJ to issue an initial decision as soon as possible, but no later
than November 24, 1999. The commission concluded that it needed
the benefit of the ALJ's opinion and, therefore, decided not to
grant the request. The administrative law judge who presided over
the FERC merger hearing filed an initial decision with the
commission on November 23 1999 and found the AEP-CSW merger to be
in the public interest. The FERC indicated it will act on the
merger no later than February or March 2000.
Arkansas
On December 17, 1998, the Arkansas Commission approved a stipulated
agreement related to a proposed merger regulatory plan. The
stipulated agreement calls for CSW's Arkansas operating subsidiary,
Southwestern Electric Power Company to share net merger savings
with its retail customers through a net merger savings rate
reduction rider of $6 million over the five-year period following
completion of the merger.
Louisiana
In September, 1999 the Louisiana Public Service Commission (LPSC)
issued a final order granting approval of the pending merger
between the Company and CSW. In granting approval, the LPSC also
approved a stipulated settlement in which the Company and CSW
agreed to share with SWEPCO's Louisiana customers net merger
savings created as a result of the merger over the eight years
following its consummation. The net merger savings are estimated
to total more than $18 million during that eight-year period. In
addition the settlement also includes a cap on base rates for five
years after consummation of the merger; sharing of benefits from
off-system sales; establishment of conditions for affiliate
transactions with other AEP and CSW subsidiaries; provisions to
ensure continued quality of service; and provisions to hold
SWEPCO's Louisiana customers harmless for adverse effects of the
merger, if any.
Oklahoma
On May 11, 1999, the Oklahoma Corporation Commission (OCC) approved
the proposed merger between the Company and CSW. The approval
follows an administrative law judge's oral decision on a partial
settlement between certain principal parties to the Oklahoma merger
proceeding which recommended that the OCC approve the merger. The
partial settlement provides for sharing of net merger savings with
Oklahoma customers; no increase in Oklahoma base rates prior to
January 1, 2003; filing by December 31, 2001 with the FERC an
application to join a regional transmission organization; and
implementing additional quality of service standards for Oklahoma
retail customers. Oklahoma's share (approximately $50 million) of
net merger savings over the first five years after the merger is
consummated will be shared between Oklahoma customers and AEP
shareholders. The partial settlement agreement includes a
recommendation by the OCC staff that the OCC file with FERC
indicating that it does not oppose the merger, but reserves the
right to ensure that there are no adverse impacts on the Oklahoma
transmission system from the FERC's approval order. Certain
municipal and cooperative customers appealed the OCC's merger
approval order. On October 13, 1999 this appeal was dismissed by
the Oklahoma Supreme Court and the municipal and cooperative
customers have since asked the OCC to withdraw or dismiss their
appeal.
Texas
On May 4, 1999, AEP and CSW announced that a stipulated settlement
had been reached in Texas. The agreement builds upon an earlier
settlement agreement signed by AEP, CSW and certain parties to the
Texas merger proceeding. In addition to the parties that were
signatories to the earlier agreement, the staff of the Public
Utility Commission of Texas is a signatory to the new settlement as
well as other key parties to the merger proceeding. The stipulated
settlement would result in rate reductions for Texas customers
totaling $221 million over a six-year period commencing with the
merger's consummation. The rate reduction is composed of $84
million of net merger savings and $137 million to resolve existing
issues associated with CSW operating subsidiaries' rate and fuel
reconciliation proceedings in Texas. Under the terms of the
settlement agreement, base rates can not be increased before
January 1, 2003 or three years after the merger is consummated,
whichever is later. The settlement also calls for the divestiture
of a total of 1,604 megawatts of existing and proposed generating
capacity within Texas. If it is determined that the divestiture
can proceed immediately after the merger closes without
jeopardizing pooling-of-interests accounting treatment for the
merger, sale of the plants would begin no later than 90 days after
the merger closes. Absent that determination, the divestiture
would begin approximately two years after the merger closes to
satisfy the requirements to use pooling-of-interests accounting
treatment. Other provisions in the settlement agreement provide
for, among other things, accelerated stranded cost recovery,
quality-of-service standards, continuation of programs for
disadvantaged customers and transfer of control of bulk
transmission facilities to a regional transmission organization.
Hearings on the merger in Texas began August 9, 1999 and concluded
on August 10, 1999. Before the hearings began, settlements were
reached with all but one of the parties in the case. The settling
parties are all wholesale electric customers of CSW's Texas
electric operating companies. The settlements call for the
withdrawal of their opposition to the merger in all regulatory
approval proceedings. In its open meeting on November 4, 1999, the
Texas Commission approved the application on the pending merger and
the stipulated settlement announced in May.
Indiana
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 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.
Michigan
The MPSC has 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; 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
savings through credits of approximately 1 percent to 1.5 percent
every 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.
Kentucky
On April 15, 1999, in compliance with a request from the staff of
the Kentucky Public Service Commission (KPSC) AEP filed an
application seeking KPSC approval for the indirect change in
control of KPCo that will occur as a result of the proposed merger.
Although AEP did not believe that the KPSC has the jurisdictional
authority to approve the merger, AEP reached a merger settlement
agreement on May 24, 1999 with key parties in Kentucky which the
KPSC approved on June 14, 1999. Under the terms of the Kentucky
settlement, AEP has agreed to share net merger savings with
Kentucky customers; establish performance standards that will
maintain or improve customer service and system reliability; and to
establish rules to protect consumers and promote fair competition.
The Kentucky customers' share of the net merger savings are
expected to be approximately $28 million. The key parties to the
Kentucky settlement agreed not to oppose the merger during the FERC
or the SEC proceedings.
Ohio
On October 21, 1999, the PUCO issued a decision stating that it
will notify the FERC that it will withdraw its opposition to the
Company's pending merger with CSW and will not seek conditions on
the merger.
American Municipal Power - Ohio (AMP-Ohio) and AEP reached a
settlement addressing outstanding issues. As part of the
settlement AMP-Ohio agreed to withdraw as an intervenor in the
merger process. AMP-Ohio is the nonprofit wholesale power supplier
and service provider for most of Ohio's 84 community-owned public
power systems, two West Virginia public power systems and four
Pennsylvania public power systems.
Other
AEP and CSW have reached settlements with the Missouri Commission,
the International Brotherhood of Electrical Workers, representing
employees of AEP and CSW, and the Utility Worker's Union of America
representing AEP employees, and certain wholesale customers. All
have agreed not to oppose the merger in the FERC or SEC
proceedings.
The proposed merger of CSW into AEP would result in common
ownership of two United Kingdom (UK) regional electricity companies
(RECs), Yorkshire and SEEBOARD, plc. AEP has a 50% ownership
interest in Yorkshire and CSW has a 100% interest in SEEBOARD. On
January 25, 2000 the UK's Department of Trade and Industry gave its
approval to the merger finding no competitive problems with the
ownership of two UK RECs. This final clearance was conditional on
the companies agreeing to certain assurance concerning operation of
the UK interest including meeting customer service obligations,
maintaining debt ratings of investment grade or above and separate
distribution and supply activities.
Completion of the Merger
As of December 31, 1999, AEP had deferred $42 million of
incremental costs related to the merger on its consolidated balance
sheet, which will be charged to expense if AEP and CSW are not
successful in completing their proposed merger. If the merger is
consummated the deferred costs allocable to the domestic utility
subsidiaries will be amortized over their recovery period,
generally five to eight years, in accordance with state regulator
orders. The remainder of the deferred merger costs will be
expensed upon consummation of the merger.
The merger is conditioned upon, among other things, the approval of
certain state and federal regulatory agencies. The transaction
must satisfy many conditions, a number of which may not be waived
by the parties, including the condition that the merger must be
accounted for as a pooling of interests. To consummate the merger,
the Company needs to obtain the approval of the FERC and the SEC.
Although consummation of the merger is expected to occur in the
second quarter of 2000, the Company is unable to predict the
outcome or the timing of the required regulatory proceedings. Also
if the merger savings do not approximate the agreed to net merger
savings rate reduction riders in the five to eight years after the
consummation of the merger, future results of operations, cash flow
and possibly financial condition could be adversely affected.
9. Acquisitions:
The Company completed two energy related acquisitions in 1998
through a subsidiary, AEPR. Both acquisitions have been accounted
for using the purchase method. One acquisition was of CitiPower,
an Australian distribution utility, that serves approximately
250,000 customers in Melbourne with 3,100 miles of distribution
lines in a service area of approximately 100 square miles. All of
the stock of CitiPower was acquired on December 31, 1998 for
approximately $1.1 billion. The acquisition of CitiPower had no
effect on the results of operations for 1998 and a full year of
CitiPower's results of operations are included in the 1999
consolidated statement of income. Assets acquired and liabilities
assumed have been recorded at their fair values. Based on an
independent appraisal, $616 million of the purchase price was
allocated to retail and wholesale distribution licenses which are
being amortized on a straight-line basis over 20 years and 40
years, respectively. The excess of cost over fair value of the net
assets acquired was approximately $34 million and has been recorded
as goodwill in other assets and is being amortized on a
straight-line basis over 40 years.
The other acquisition was of midstream gas operations that include
a fully integrated natural gas gathering, processing, storage and
transportation operation in Louisiana and a gas trading and
marketing operation in Houston. The gas operations were acquired
for approximately $340 million, including working capital funds, on
December 1, 1998 with one month of earnings reflected in AEP's
consolidated results of operations for the year ended December 31,
1998. A full year of the midstream gas operations' results of
operations is included in the 1999 consolidated statement of
income. Assets acquired and liabilities assumed have been recorded
at their fair values. The excess of cost over fair value of the
net assets acquired was approximately $158 million for the
midstream gas storage operations and $17 million for the gas
trading and marketing operation and has been recorded as goodwill
in other assets and is being amortized on a straight-line basis
over 40 years and 10 years, respectively.
10. Yorkshire Acquisition and UK Windfall Tax:
In April 1997 the Company and New Century Energies, Inc. through an
equally owned joint venture, Yorkshire Power Group Limited (YPG),
acquired all of the outstanding shares of Yorkshire. Total
consideration paid by the joint venture was approximately $2.4
billion which was financed by a combination of equity and
non-recourse debt. The Company uses the equity method of accounting
for its investment in YPG. The Company's investment in the joint
venture was $368 million and $326 million at December 31, 1999 and
1998, respectively, and is included in other assets.
In July 1997 the British government enacted a new law that imposed
a one-time windfall tax on a revised privatization value which
originally had been computed in 1990 on certain privatized
utilities. The windfall tax is actually an adjustment by the UK
government of the original privatization price. The windfall tax
liability for Yorkshire was 134 million pounds sterling ($219
million) and was paid in two equal installments made in December
1997 and December 1998. The Company's $109 million share of the
tax is reported as an extraordinary loss in 1997.
The 1999 and 1998 equity earnings from the Yorkshire investment are
$45 million and $39 million, respectively, and are included in
worldwide electric and gas operations revenues. Equity earnings
from the Yorkshire investment for 1997, excluding the extraordinary
loss, were $34 million.
<PAGE>
The following amounts which are not included in AEP's consolidated
financial statements represent 100% of YPG's summarized
consolidated financial information:
December 31,
1999 1998
(in millions)
Assets:
Property, Plant and Equipment $1,666 $1,602
Current Assets 450 552
Goodwill (net) 1,461 1,547
Other Assets 289 295
Total Assets $3,866 $3,996
Capitalization and Liabilities:
Common Shareholders' Equity $ 725 $ 666
Long-term Debt 2,031 2,121
Other Noncurrent Liabilities 442 414
Long-term Debt Due Within One Year 14 13
Current Liabilities 654 782
Total Capitalization and
Liabilities $3,866 $3,996
Twelve Months Ended Nine Months Ended
December 31, December 31,
(in millions)
1999 1998 1997
Income Statement Data:
Operating Revenues $2,335 $2,284 $1,493
Operating Income 301 298 202
Income Before
Extraordinary Item 90 77 68
Net Income (Loss) 90 77 (151)
In August 1999 the Office of Gas and Electricity Markets (OFGEM,
which is the UK regulator of gas and electricity rates), published
draft price proposals for the UK's regional distribution businesses
including Yorkshire and SEEBOARD that would be effective for the
five-year period beginning April 1, 2000. Under the draft price
proposals, the distribution rates for Yorkshire would be reduced
15% to 20% from current rates. Yorkshire filed comments on
September 17, 1999 with OFGEM expressing various concerns with the
analysis used by OFGEM.
On October 8, 1999, OFGEM issued updated draft price proposals for
Yorkshire's electric distribution business. The updated proposals
would require Yorkshire to reduce distribution rates 15% and
transfer 8% of costs to Yorkshire's electricity supply business, an
overall reduction in distribution prices of 23%.
Also on October 8, 1999, OFGEM issued draft price proposals for
Yorkshire's electric supply business. Under the proposals, a
supply price cap for certain domestic UK customers is retained from
April 2000 through March 2002. For Yorkshire, these proposals
would result in a price reduction of approximately 10.7% on the
standard domestic tariff commencing April 2000 and ending March
2001 and a nominal price freeze for the year commencing April 2001
and ending March 2002.
In December 1999 OFGEM issued its final proposals for both
Yorkshire's distribution and supply businesses. The final
distribution and supply price controls were substantially the same
as OFGEM's October 8, 1999 proposals except that the reduction in
the standard domestic tariff is 3.6% for the supply business. On
December 20, 1999, Yorkshire informed OFGEM of its intention to
accept the final proposals.
Yorkshire management also believes that supply prices established
in the competitive market may require Yorkshire to charge supply
prices that are lower than the maximum prices established by OFGEM
for customers Yorkshire wishes to retain and who are subject to
supply price controls. If Yorkshire charges lower supply prices,
the result will be a further reduction in supply revenues beyond
that required by OFGEM.
Yorkshire management intends to take all available opportunities to
increase revenues and reduce costs to mitigate the impact of the
final OFGEM distribution and supply price reductions. Should
Yorkshire be unable to increase revenues and reduce costs in
amounts sufficient to offset the impact of the OFGEM distribution
and supply price reductions, AEP's equity earnings from its
investment in Yorkshire will be significantly reduced in comparison
to its current level of earnings.
11. 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 and called for the elimination
of approximately 450 positions. In addition, a review of energy
delivery staffing levels in 1998 identified 65 positions for
elimination.
A provision for severance costs totaling $26 million was recorded
in December 1998 for reductions in power generation and energy
delivery staffs and were 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.
<PAGE>
12. Benefit Plans:
AEP System Pension and Other Postretirement Benefit Plans - The AEP
System sponsors a qualified pension plan and a nonqualified pension
plan. All employees, except participants in the United Mine
Workers of America (UMWA) pension plans are covered by one or both
of the pension plans. Other Postretirement Benefit Plans (OPEB)
are sponsored by the AEP System to provide medical and death
benefits for retired employees.
The following tables provide a reconciliation of the changes in the
plans' benefit obligations and fair value of assets over the
two-year period ending December 31, 1999, and a statement of the funded
status as of December 31 for both years:
<TABLE>
<CAPTION>
Pension Plan OPEB
1999 1998 1999 1998
(in millions)
<S> <C> <C> <C> <C>
Reconciliation of benefit
obligation:
Obligation at January 1 $2,126 $1,909 $1,022 $ 850
Service Cost 50 45 22 17
Interest Cost 146 133 72 59
Participant Contributions - - 7 6
Plan Amendments (a) 7 48 - -
Actuarial (Gain) Loss (253) 96 19 133
Acquisitions (b) - - - 3
Benefit Payments (109) (105) (53) (46)
Curtailments - - 10(c) -
Obligation at December 31 $1,967 $2,126 $1,099 $1,022
Reconciliation of fair value
of plan assets:
Fair value of plan assets at
January 1 $2,651 $2,370 $396 $312
Actual Return on Plan Assets 248 386 79 53
Company Contributions - - 47 72
Participant Contributions - - 6 6
Benefit Payments (109) (105) (52) (47)
Fair value of plan assets at
December 31 $2,790 $2,651 $476 $396
Funded status:
Funded status at December 31 $ 823 $ 525 $(623) $(626)
Unrecognized Net Transition
(Asset) Obligation (39) (49) 317 361
Unrecognized Prior-Service Cost 146 157 - -
Unrecognized Actuarial
(Gain) Loss (1,042) (757) 179 175
Accrued Benefit Liability $ (112) $(124) $(127) $ (90)
(a) Early retirement factors for the Company pension plan were changed to provide
more generous benefits to participants retiring between ages 55 and 60.
(b) On December 1, 1998 the Company acquired midstream gas operations resulting
in approximately 170 new employees becoming participants in the Company's pension
and OPEB plans.
(c) Related to the October 31, 1999 shutdown of Central Ohio Coal Company's
Muskingum mine and the anticipated April 30, 2000 shutdown of the Windsor Coal
Company mine. Both companies are subsidiaries of AEP.
<PAGE>
The following table provides the amounts recognized in the
consolidated balance sheets as of December 31 of both years:
</TABLE>
<TABLE>
<CAPTION>
Pension Plan OPEB
1999 1998 1999 1998
(in millions)
<S> <C> <C> <C> <C>
Accrued Benefit Liability $(112) $(124) $(127) $(90)
Additional Minimum Liability (8) (3) - -
Intangible Asset 8 3 - -
Net Amount Recognized $(112) $(124) $(127) $(90)
</TABLE>
The Company's nonqualified pension plan had an accumulated benefit
obligation in excess of plan assets of $29 million and $25 million
at December 31, 1999 and 1998, respectively. There are no plan
assets in the nonqualified plan.
The Company's OPEB plans had accumulated benefit obligations in
excess of plan assets of $623 million and $626 million at December
31, 1999 and 1998, respectively.
<TABLE>
The following table provides the components of net periodic benefit
cost for the plans for fiscal years 1999, 1998 and 1997:
<CAPTION>
Pension Plan OPEB
1999 1998 1997 1999 1998 1997
(in millions)
<S> <C> <C> <C> <C> <C> <C>
Service cost $ 50 $ 45 $ 36 $ 22 $ 17 $ 14
Interest cost 146 133 129 72 59 55
Expected return
on plan assets (201) (172) (154) (36) (28) (22)
Amortization of
transition
(asset) obligation (10) (10) (10) 32 32 32
Amortization of
prior-service
cost 18 14 14 - - -
Amortization of
net actuarial
(gain) loss (15) (2) (5) 5
Net periodic
benefit cost (12) 8 10 95 80 79
Curtailment loss(a) - - - 18 24 -
Net periodic
benefit
cost after
curtailments $(12) $ 8 $ 10 $113 $104 $79
(a) Curtailment charges were recognized during 1999 and 1998 for the October 31,
1999 shutdown of Central Ohio Coal Company's Muskingum mine and the anticipated
April 30, 2000 shutdown of the Windsor Coal Company mine. Both companies are
subsidiaries of AEP.
<PAGE>
The assumptions used in the measurement of the Company's benefit
obligation are shown in the following table:
</TABLE>
<TABLE>
Pension Plan OPEB
1999 1998 1997 1999 1998 1997
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
Weighted-average
assumptions
as of December 31
Discount rate (a) 8.00% 6.75% 7.00% 8.00% 6.75% 7.00%
Expected return on plan
assets 9.00% 9.00% 9.00% 8.75% 8.75% 8.75%
Rate of compensation
increase 3.2% 3.2% 3.2% N/A N/A N/A
(a) The 1999 expense was re-measured as of July 31, 1999 using a discount rate
of 7.50%.
</TABLE>
For measurement purposes, a 5.5% annual rate of increase in the per
capita cost of covered health care benefits was assumed for 2000.
The rate was assumed to decrease gradually each year to a rate of
5.0% for 2005 and remain at that level thereafter.
Assumed health care cost trend rates have a significant effect on
the amounts reported for the OPEB health care plans. A 1% change
in assumed health care cost trend rates would have the following
effects:
1% Increase 1% Decrease
(in millions)
Effect on total of service and
interest cost components of
net periodic postretirement
health care benefit cost $ 12 $ (10)
Effect on the health care
component of the accumulated
postretirement benefit obligation 123 (109)
CitiPower, a subsidiary acquired on December 31, 1998 sponsors a
defined benefit pension plan. At December 31, 1999 and 1998, the
fair value of the plan assets was $30 million and $25 million,
respectively, and the accumulated benefit obligation of this plan
was $27 million and $25 million, respectively. This plan's
actuarial assumptions are not significantly different from AEP's.
AEP System Savings Plan - The AEP System Savings Plan is a defined
contribution plan offered to non-UMWA employees. The cost for
contributions to this plan totaled $21 million in 1999 and 1998 and
$20 million in 1997.
Other UMWA Benefits - The Company provides UMWA pension, health and
welfare benefits for certain unionized mining employees, retirees,
and their survivors who meet eligibility requirements. The
benefits are administered by UMWA trustees and contributions are
made to their trust funds. Contributions based on hours worked are
expensed as paid as part of the cost of active mining operations
and were not material in 1999, 1998 and 1997. Based upon the UMWA
actuary estimate, the Company's share of unfunded pension liability
was $17 million at June 30, 1999. In the event the Company should
significantly reduce or cease mining operations or contributions to
the UMWA trust funds, a withdrawal obligation will be triggered for
the pension plan that equals the unfunded pension liability. If
the Meigs mining operations had been closed on December 31, 1999
the estimated annual liability for the UMWA health and welfare
plans would have been approximately $1 million.
13. Business Segments:
As of December 31, 1998, the Company adopted SFAS 131, "Disclosure
about Segments of an Enterprise and Related Information." SFAS 131
establishes standards for reporting information about operating
segments in annual financial statements and requires selected
information about operating segments in interim financial reports
issued to shareholders. It also established standards for related
disclosures about products and services, and geographic areas.
Operating segments are defined as components of an enterprise about
which separate financial information is available and evaluated
regularly by the chief operating decision maker.
The Company's reportable segments are primarily differentiated
based on whether the business activity is conducted within a
cost-based regulated environment. The Company manages its operations on
this basis because of the substantial impact of regulatory
oversight on business processes, cost structures and operating
results. The accounting policies of the reportable segments are
the same as those described in Note 1, "Significant Accounting
Policies."
The Company's principal business segment is its cost-based rate
regulated domestic regulated electric utility operations consisting
of seven domestic regulated utility subsidiaries companies
providing retail, commercial, industrial and wholesale electric
services in seven Atlantic and Midwestern states. Also included in
this segment are the Company's electric power wholesale marketing
and trading activities that are conducted in the Company's
traditional marketing area as part of regulated operations and
subject to regulatory ratemaking oversight.
The worldwide electric and gas operations segment is principally
made up of international investments in energy-related projects and
operations. It also includes the acquisition, development and
management of electricity and gas projects and operations
worldwide. Such investment activities include electric generation,
supply and distribution, and natural gas pipeline, storage and
other natural gas services. Although the businesses in the
worldwide operations segment are generally subject to different
forms of price regulation, they are not cost-based rate regulated.
As a result for reporting purposes under U.S. generally accepted
accounting principles they do not record regulatory assets and
liabilities in accordance with SFAS 71. The other operations
business segment includes electric trading outside the Company's
traditional marketing area, gas trading operations,
telecommunication services, and the marketing of various energy
related products and services. As of December 31, 1999 and 1998,
less than 6% of consolidated long-lived assets were located in
foreign countries.
<TABLE>
<CAPTION>
Domestic Regulated Worldwide Elimination
Electric Utility Electric and Other Reconciling AEP
Year Operations Gas Operations Operations Adjustments Consolidated
(in millions)
<S> <C> <C> <C> <C> <C>
1999
Revenues from
external unaffiliated
customers $6,315 $722* $(121) - $6,916
Revenues from transactions
with other operating
segments - 72 143 $(215) -
Interest expense 412 109 7 - 528
Depreciation, depletion and
amortization expense 600 55 5 (60) 600
Income tax expense (benefit) 316 (39) (17) - 260
Segment net income (loss) 508 41 (29) - 520
Total assets 18,038 2,482 968 - 21,488
Investments in equity method
subsidiaries - 433 - - 433
Gross property additions 735 114 18 - 867
1998
Revenues from
external unaffiliated
customers $6,346 $94* $(43) - $6,397
Revenues from transactions
with other operating
segments - 2 14 $(16) -
Interest expense 399 17 3 - 419
Depreciation, depletion and
amortization expense 580 1 1 (2) 580
Income tax expense (benefit) 317 (15) (21) - 281
Segment net income (loss) 564 12 (40) - 536
Total assets 16,837 2,063 583 - 19,483
Investments in equity method
subsidiaries - 335 - - 335
Gross property additions 700 1,463 23 - 2,186
1997
Revenues from
external unaffiliated
customers $5,880 $48* $ - $ - $ 5,928
Revenues from transactions
with other operating
segments - - - - -
Interest expense 390 15 1 - 406
Depreciation, depletion and
amortization expense 591 - - - 591
Income tax expense (benefit) 352 (25) (7) - 320
Extraordinary Loss -
UK Windfall Tax - (109) - - (109)
Segment net income (loss) 603 (80) (12) - 511
Total assets 16,224 367 24 - 16,615
Investments in equity method
subsidiaries - 287 - - 287
Gross property additions 694 62 4 - 760
* Worldwide electric and gas revenues for the years ended December 31, 1999 and 1998 include net
income from subsidiaries accounted for under the equity method of $45 million and $39 million,
respectively. For the year ended December 31, 1997 worldwide electric and gas revenues include $34
million of earnings excluding an extraordinary loss from subsidiaries accounted for under the equity
method.
</TABLE>
14. Financial Instruments, Credit and Risk Management:
The Company is subject to market risk as a result of changes in
commodity prices, foreign currency exchange rates, and interest
rates. The Company has wholesale electricity and gas trading and
marketing operations that manage the exposure to 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 AEP's traditional
economic market area are recorded on a net basis as domestic
regulated electric utility operations revenues in the month when
the physical contract settles. Physical forward electricity
contracts outside AEP's traditional marketing area, and all
financial electricity trading transactions where the underlying
physical commodity is outside AEP's traditional economic market
area are recorded on a net basis in worldwide electric and gas
operations revenues.
In the first quarter of 1999 the Company adopted the Financial
Accounting Standards Board's 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 the portion of those open electricity
trading transactions within the AEP's marketing area that are
included in cost of service on a settlement basis for ratemaking
purposes in the Company's non-Virginia jurisdictions. A Virginia
jurisdiction net mark-to-market pre-tax gain of $5 million for the
year ended December 31, 1999 is included in domestic regulated
revenues as a result of an agreed prohibition against establishing
new regulatory assets in a February 1999 Virginia SCC approved
settlement agreement. Open contracts outside of AEP Power Pool's
marketing area are marked-to-market in worldwide electric and gas
operations revenues. The adoption of the EITF did not have a
material effect on results of operations, cash flows or financial
condition. All physical and financial instruments for natural gas
except for certain qualifying hedges are marked to market and are
included on a net basis in worldwide electric and gas operations
revenues. The unrealized mark-to-market gains and losses from
trading of financial instruments are reported as assets and
liabilities, respectively.
<PAGE>
The amounts of net revenues recorded in 1999 and 1998 for electric
and gas trading activities were:
Revenues - Net Gain (Loss) 1999 1998
(in millions)
Domestic Regulated Electric
Utility Operations $27 $111
Worldwide Electric and Gas Operations 14 (33)
Electric and gas trading activities were not material in 1997.
Investment in foreign ventures exposes the Company to risk of
foreign currency fluctuations. Also, the Company is exposed to
changes in interest rates primarily due to short- and long-term
borrowings used to fund its business operations. The debt
portfolio has both fixed and variable interest rates with terms
from one day to forty years and an average duration of four years
at December 31, 1999. The Company does not presently utilize
derivatives to manage its exposures to foreign currency exchange
rate movements.
Market Valuation - The book values 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 values 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.
Book Value Fair Value
(in millions)
Non-Derivatives
1999
Long-term Debt $7,447 $7,209
Preferred Stock 119 117
1998
Long-term Debt 7,006 7,291
Preferred Stock 128 134
<PAGE>
Derivatives
Trading Assets
<TABLE>
<CAPTION>
1999 1998
Notional Fair Average Notional Fair Average
Amount Value Fair Value Amount Value Fair Value
GWH (in millions) GWH (in millions)
<S> <C> <C> <C> <C> <C> <C>
Electric
Futures and
Options-NYMEX (net) 224 $ 2 $ 1 - $ - $ -
Physicals 69,509 577 517 58,521 46 41
Options - OTC 6,203 39 62 3,873 32 79
Swaps 177 1 1 276 3 1
MMMBTU (in millions) MMMBTU (in millions)
Gas
Futures and
Options-NYMEX (net) - $ - $ - 55,442 $ 6 $ 2
Physicals 345,830 37 39 212,307 44 30
Options - OTC 192,593 54 40 65,920 18 12
Swaps 2,682,033 410 312 1,081,954 246 143
Trading Liabilities
GWH (in millions) GWH (in millions)
Electric
Futures and
Options-NYMEX (net) - $ - $ - 705 $ (7) $ (2)
Physicals 74,764 (536) (498) 57,652 (51) (46)
Options - OTC 8,907 (43) (56) 2,935 (29) (78)
Swaps 180 (2) (2) 490 (8) (2)
MMMBTU (in millions) MMMBTU (in millions)
Gas
Futures and
Options-
NYMEX (net) 69,840 $ (8) $ (5) - $ - $ -
Physicals 301,271 (32) (26) 180,949 (42) (29)
Options - OTC 227,225 (55) (37) 74,770 (23) (14)
Swaps 2,601,644 (379) (303) 1,092,660 (231) (136)
</TABLE>
AEP routinely enters into exchange traded futures and options
transactions for electricity and natural gas as part of its
wholesale trading operations. These transactions are executed
through brokerage accounts with brokers who are registered with the
Commodity Futures Trading Commission. Brokers require cash or cash
related instruments to be deposited on these accounts as margin
calls against the customer's open position. The amount of these
deposits at December 31, 1999 and 1998 was $25 million and $10
million, respectively.
Credit and Risk Management - In addition to market risk associated
with price movements, AEP 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 Company has established and enforced credit
policies that minimize or eliminate this risk. AEP 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 Company will require further enhancements to mitigate
risk. Since the formation of the trading business in July of 1997,
the Company has not experienced a significant loss due to the
credit risk; 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.
Other Financial Instruments - Nuclear Trust Funds Recorded at
Market Value - The trust investments, reported in other assets, 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 the trust investments were $708
million and $648 million, respectively, and had a cost basis of
$636 million and $584 million, respectively. Accumulated gross
unrealized holding gains were $78 million and $65 million at
December 31, 1999 and 1998, respectively and accumulated gross
unrealized holding losses were $7 million and $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
$8 million, $24 million, and $19 million, respectively.
The cost basis of trust investments by security type was:
December 31,
1999 1998
(in millions)
Tax-Exempt Bonds $351 $326
Equity Securities 116 96
Treasury Bonds 73 71
Corporate Bonds 13 11
Cash, Cash Equivalents and
Accrued Interest 83 80
Total $636 $584
Proceeds from sales and maturities of trust securities of $226
million during 1999 resulted in $6 million of realized gains and $5
million of realized losses. Proceeds from sales and maturities of
securities of $225 million during 1998 resulted in $8 million of
realized gains and $3 million of realized losses. Proceeds from
sales and maturities of trust securities of $147 million during
1997 resulted in $4 million of realized gains and $1 million of
realized losses. The cost of trust securities for determining
realized gains and losses is original acquisition cost including
amortized premiums and discounts.
<PAGE>
At December 31, 1999, the year
of maturity of trust fund investments other than equity
securities, was:
(in millions)
2000 $120
2001 - 2004 174
2005 - 2009 182
After 2009 44
Total $520
CitiPower entered into several interest rate swap agreements for
$788 million of borrowings under a credit facility. The swap
agreements involve the exchange of floating-rate for fixed-rate
interest payments. Interest is recognized currently based on the
fixed rate of interest resulting from use of these swap agreements.
Market risks arise from the movements in interest rates. If
counter parties to an interest rate swap agreement were to default
on contractual payments, CitiPower could be exposed to increased
costs related to replacing the original agreement. However,
CitiPower does not anticipate non-performance by any counter party
to any interest rate swap in effect as of December 31, 1999. As of
December 31, 1999, CitiPower was a party to interest rate swaps
having a aggregate notional amount of $630 million, with $367
million maturing on December 31, 2000, and $263 million maturing on
December 31, 2003. The average fixed interest rate payable on the
aggregate of the interest rate swaps is 5.32%. The average
floating rate for interest rate swaps was 5.93% at December 31,
1999. The estimated fair value of the interest rate swaps, which
represents the estimated amount CitiPower would receive to
terminate the swaps at December 31, 1999, based on quoted interest
rates, is a net receivable of $17 million.
In accordance with the debt covenants included in the financing
provisions of this credit facility, CitiPower must hedge at least
80% of its energy purchase requirements through energy trading
derivative instruments entered into with market participants,
predominantly generators. As of December 31, 1999, CitiPower had
outstanding energy trading derivatives with a total contracted load
of 7,313 Gwh's. The maturities for these contracts range from
three months to six years. Management's estimate of the fair value
of these derivatives as of December 31, 1999 is $7 million in
excess of net contract value.
<TABLE>
<PAGE>
15. Income Taxes:
The details of income taxes as reported are as follows:
<CAPTION>
Year Ended December 31,
1999 1998 1997
(in millions)
<S> <C> <C> <C>
Federal:
Current $139 $247 $330
Deferred 116 16 (32)
Total 255 263 298
State:
Current 3 18 22
Deferred - - -
Total 3 18 22
International:
Current - - -
Deferred 2 - -
Total 2 - -
Total Income Tax as Reported $260 $281 $320
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 income taxes reported.
Year Ended December 31,
1999 1998 1997
(in millions)
Income Before Preferred Stock Dividend
Requirements of Subsidiaries $531 $547 $ 638
Extraordinary Loss - UK Windfall Tax(Note 10) - - (109)
Federal Income Taxes 255 263 298
Pre-Tax Book Income $786 $810 $ 827
Federal Income Tax on Pre-Tax Book Income
at Statutory Rate (35%) $275 $283 $289
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 62 58 53
Corporate Owned Life Insurance 2 (16) (18)
Foreign Tax Credits (35) (8) (13)
Investment Tax Credits (net) (25) (25) (25)
Extraordinary Loss - UK Windfall Tax - - 38
State 3 18 22
International 2 - -
Other (24) (29) (26)
Total Income Taxes as Reported $260 $281 $320
Effective Income Tax Rate 32.9% 33.9% 37.7%
<PAGE>
The following tables show the elements of the Company's net
deferred tax liability and the significant temporary differences:
December 31,
1999 1998
(in millions)
Deferred Tax Assets $ 930 $ 879
Deferred Tax Liabilities (3,675) (3,480)
Net Deferred Tax Liabilities $(2,745) $(2,601)
Property Related Temporary Differences $(2,151) $(2,170)
Amounts Due From Customers For Future
Federal Income Taxes (376) (395)
Deferred State Income Taxes (205) (194)
All Other (net) (13) 158
Net Deferred Tax Liabilities $(2,745) $(2,601)
</TABLE>
The Company has settled with the IRS all issues from the audits of
its 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 AEP's corporate owned life insurance program, which are
discussed under the heading, COLI Litigation, in Note 6, 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.
<TABLE>
16. Supplementary Information:
<CAPTION>
Year Ended December 31,
1999 1998 1997
(in million)
<S> <C> <C> <C>
Purchased Power -
Ohio Valley Electric Corporation
(44.2% owned by AEP System) $64 $43 $30
Cash was paid for:
Interest (net of capitalized amounts) $513 $413 $390
Income Taxes $95 $282 $399
Noncash Investing and Financing Activities:
Acquisitions under Capital Leases $80 $119 $235
Assumption of Liabilities related
to Acquisitions $ - $152 $ -
</TABLE>
17. Leases:
Leases of property, plant and equipment are for periods up to 35
years and require payments of related property taxes, maintenance
and operating costs. The majority of the leases have purchase or
renewal options and will be renewed or replaced by other leases.
Lease rentals 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 millions)
Lease Payments on Operating Leases $245 $255 $257
Amortization of Capital Leases 96 91 105
Interest on Capital Leases 34 37 31
Total Lease Rental Costs $375 $383 $393
Property, plant and equipment under capital leases and related
obligations recorded on the Consolidated Balance Sheets are as
follows:
December 31,
1999 1998
(in millions)
PROPERTY, PLANT AND EQUIPMENT UNDER CAPITAL LEASES:
Production $ 46 $ 47
Distribution 15 15
Other:
Nuclear Fuel (net of amortization) 108 104
Mining Assets and Other 612 584
Total Property, Plant and Equipment 781 750
Accumulated Amortization 261 217
Net Property, Plant and Equipment
under Capital Leases $520 $533
Obligations Under Capital Leases:
Noncurrent Liability $429 $451
Liability Due Within One Year 91 82
Total Obligations Under Capital Leases $520 $533
Properties under operating leases and related obligations are not
included in the Consolidated Balance Sheets.
Future minimum lease payments consisted of the following at
December 31, 1999:
Noncancelable
Capital Operating
Leases Leases
(in millions)
2000 $116 $ 234
2001 98 231
2002 74 225
2003 55 224
2004 41 223
Later Years 134 3,226
Total Future Minimum Lease Payments 518 (a) $4,363
Less Estimated Interest Element 106
Estimated Present Value of Future
Minimum Lease Payments 412
Unamortized Nuclear Fuel 108
Total $520
(a) Minimum lease payments do not include nuclear fuel payments.
The payments 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.
<PAGE>
18. Lines of Credit and Commitment Fees:
At December 31, 1999, unused short-term bank lines of credit were
available in the amount of $1,056 million. In addition one
subsidiary not engaged in providing domestic regulated electric
utility services has a line of credit under a revolving credit
agreement that expires in December 2002. The amount of credit
available under the revolving credit agreement was $20 million at
December 31, 1999. The short-term bank lines of credit and the
revolving credit agreement require the payment of facility fees and
do not require compensating balances.
Outstanding short-term debt consisted of:
December 31,
1999 1998
(dollars in millions)
Balance Outstanding:
Notes Payable $208 $198
Commercial Paper 680 419
Total $888 $617
Year-End Weighted
Average Interest Rate:
Notes Payable 6.7% 5.8%
Commercial Paper 6.5% 6.2%
Total 6.6% 6.1%
<TABLE>
19. Unaudited Quarterly Financial Information:
<CAPTION>
Quarterly Periods Ended
1999
March 31 June 30 Sept. 30 Dec. 31
(In Millions - Except
Per Share Amounts)
<S> <C> <C> <C> <C>
Operating Revenues $1,694 $1,643 $1,914 $1,665
Operating Income 381 285 376 263
Net Income 151 88 174 107
Earnings per Share* 0.79 0.46 0.90 0.55
*Amounts for 1999 do not add to $2.69 earnings per share due to rounding.
Fourth quarter 1999 earnings include various favorable adjustments
totaling $53 million. These adjustments include $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);
$17 million net of tax from changes in estimates of state and local
taxes that resulted from the resolution of property valuation
disputes, a net operating loss carry back and adjustments to the
prior year tax accrual after filing state tax returns; $8 million
net of tax from changes in estimates for pole attachment revenues
due to adjustments to the accrual for prior billings for usage of
pole attachments by telecommunications companies; and $7 million
from a reduction in Australian income tax rates.
Quarterly Periods Ended
1998
March 31 June 30 Sept. 30 Dec. 31
(In Millions - Except
Per Share Amounts)
Operating Revenues $1,521 $1,557 $1,858 $1,461
Operating Income 344 294 413 196
Net Income 151 118 195 72
Earnings per Share 0.79 0.62 1.02 0.38
See "Reclassification" in Note 1 regarding reclassification of prior period
amounts.
</TABLE>
<TABLE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
<CAPTION.
December 31, 1999
Call
Price per Shares Shares Amount (In
Share (a) Authorized(b) Outstanding(g) Millions)
<S> <C> <C> <C> <C>
Not Subject to Mandatory Redemption:
4.08% - 4.56% $102-$110 932,403 446,764 $ 45
Subject to Mandatory Redemption:
5.90% - 5.92% (c) (d) 1,950,000 343,100 $ 34
6.02% - 6-7/8% (c) (e) 1,950,000 597,950 60
7% (f) (f) 250,000 250,000 25
Total Subject to Mandatory
Redemption (c) $119
________________________________________________________________________________________________________
December 31, 1998
Call
Price per Shares Shares Amount (In
Share (a) Authorized(b) Outstanding(g) Millions)
Not Subject to Mandatory Redemption:
4.08% - 4.56% $102-$110 932,403 460,016 $ 46
Subject to Mandatory Redemption:
5.90% - 5.92% (c) (d) 1,950,000 388,100 $ 39
6.02% - 6-7/8% (c) (e) 1,950,000 637,950 64
7% (f) (f) 250,000 250,000 25
Total Subject to Mandatory
Redemption (c) $128
NOTES TO SCHEDULE OF CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
(a) At the option of the subsidiary the shares may be redeemed at the call price plus accrued dividends.
The involuntary liquidation preference is $100 per share for all outstanding shares.
(b) As of December 31, 1999 the subsidiaries had 7,262,605, 22,200,000 and 7,611,984 shares of $100, $25
and no par value preferred stock, respectively, that were authorized but unissued.
(c) Shares outstanding and related amounts are stated net of applicable retirements through sinking funds
(genera lly at par) and reacquisitions of shares in anticipation of future requirements.
The subsidiaries reac quired enough shares in 1997 to meet all sinking fund requirements
on certain series until 2008 and on certain series until 2009 when all remaining
outstanding shares must be redeemed.The sinking fund provisions of the series subject
to mandatory redemption aggregate $5,000,000 million each year for the years 2000, 2001,
2002, $11,600,000 million in 2003 and $7,700,000 in 2004.
(d) Not callable prior to 2003; after that the call price is $100 per share.
(e) Not callable prior to 2000; after that the call price is $100 per share.
(f) With sinking fund.
(g) The number of shares of preferred stock redeemed is 98,252 shares in 1999, 7,220 shares in 1998 and
4,258,947 shares in 1997.
</TABLE>
<TABLE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES
<CAPTION>
Weighted Average
Maturity Interest Rate Interest Rates at December 31, December 31,
December 31, 1999 1999 1998 1999 1998
(in millions)
<S> <C> <C> <C> <C> <C>
FIRST MORTGAGE BONDS
1999-2002 7.19% 6.35%-8.95% 6.35%-8.95% $ 609 $ 759
2003-2006 6.77% 6%-8% 6%-8% 783 846
2022-2025 7.92% 7.10%-8.80% 7.10%-8.80% 822 1,021
INSTALLMENT PURCHASE CONTRACTS (a)
1999-2002 5.08% 4.80%-5.55% 4.05%-5.15% 145 145
2007-2026 6.26% 5.00%-7-7/8% 5.00%-7-7/8% 806 776
NOTES PAYABLE (b)
1999-2008 6.56% 5.8675%-9.60% 5.49%-9.60% 1,594 1,493
SENIOR UNSECURED NOTES
2000-2004 6.79% 6.50%-7.45% 6-1/2%-6.73% 1,003 448
2005-2009 6.58% 6.24%-6.91% 6.24%-6.91% 488 338
2038 7.30% 7.20%-7-3/8% 7.20%-7-3/8% 340 340
JUNIOR DEBENTURES
2025 - 2038 8.05% 7.60%-8.72% 7.60%-8.72% 620 620
OTHER LONG-TERM DEBT (c) 285 269
Unamortized Discount (net) (48) (49)
Total Long-term Debt
Outstanding (d) 7,447 7,006
Less Portion Due Within One Year 1,111 206
Long-term Portion $6,336 $6,800
NOTES TO SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES
(a) For certain series of installment purchase contracts interest rates are subject to periodic adjustment.
Certain series will be purchased on demand at periodic interest-adjustment dates. Letters of credit from
banks and standby bond purchase agreements support certain series.
(b) Notes payable represent outstanding promissory notes issued under term loan agreements and revolving
credit agreements with a number of banks and other financial institutions. At expiration all notes then
issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates
generally relate to specified short-term interest rates.
(c) Other long-term debt consists of a liability along with accrued interest for disposal of spent nuclear
fuel (see Note 6 of the Notes to Consolidated Financial Statements) and financing obligation under sale lease
back agreements.
(d) Long-term debt outstanding at December 31, 1999 is payable as follows:
Principal Amount (in millions)
2000 $1,111
2001 270
2002 391
2003 1,374
2004 601
Later Years 3,748
Total Principal
Amount 7,495
Unamortized
Discount (48)
Total $7,447
</TABLE>
<PAGE>
Management's Responsibility
The management of American Electric Power Company, Inc. is
responsible for the integrity and objectivity of the information and
representations in this annual report, including the consolidated
financial statements. These statements have been prepared in conformity
with generally accepted accounting principles, using informed estimates
where appropriate, to reflect the Company's financial condition and
results of operations. The information in other sections of the annual
report is consistent with these statements.
The Company's Board of Directors has oversight responsibilities for
determining that management has fulfilled its obligation in the
preparation of the financial statements and in the ongoing examination
of the Company's established internal control structure over financial
reporting. The Audit Committee, which consists solely of outside
directors and which reports directly to the Board of Directors, meets
regularly with management, Deloitte & Touche LLP - independent auditors
and the Company's internal audit staff to discuss accounting, auditing
and reporting matters. To ensure auditor independence, both Deloitte &
Touche LLP and the internal audit staff have unrestricted access to the
Audit Committee.
The financial statements have been audited by Deloitte & Touche
LLP, whose report appears on the next page. The auditors provide an
objective, independent review as to management's discharge of its
responsibilities insofar as they relate to the fairness of the Company's
reported financial condition and results of operations. Their audit
includes procedures believed by them to provide reasonable assurance
that the financial statements are free of material misstatement and
includes an evaluation of the Company's internal control structure over
financial reporting.
<PAGE>
Independent Auditors' Report
To the Shareholders and Board of Directors
of American Electric Power Company, Inc.:
We have audited the accompanying consolidated balance sheets of
American Electric Power Company, Inc. and its subsidiaries as of
December 31, 1999 and 1998, and the related consolidated statements of
income, comprehensive income, common shareholders' equity, 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 American
Electric Power Company, Inc. 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 7)
<PAGE>
<TABLE>
EXHIBIT 21
Subsidiaries of
American Electric Power Company, Inc.
As of January 1, 2000
The voting stock of each company shown indented is owned by the company
immediately above which is not indented to the same degree. Subsidiaries not
indented are directly owned by American Electric Power Company, Inc.
<CAPTION>
Percentage
of Voting
Securities
Location of Owned By
Name of Company Incorporation Immediate Parent
<S> <S> <C>
American Electric Power Service Corporation New York 100.0
AEP Communications, Inc. Ohio 100.0
AEP Communications, LLC Virginia 100.0
AEP Energy Services, Inc. Ohio 100.0
AEP Generating Company Ohio 100.0
AEP Investments, Inc. Ohio 100.0
AEP Power Marketing, Inc. Ohio 100.0
AEP Resources Service Company Ohio 100.0
AEP Resources, Inc. Ohio 100.0
AEP Energy Management, L.L.C. Delaware 100.0
AEP Holdings I CV Netherlands 99.0 (a)
AEP Resources Australia Holdings Pty Ltd Australia 100.0
AEP Resources CitiPower I Pty Ltd Australia 100.0
Australia's Energy Partnership Australia 99.0 (b)
Marregon II Pty Ltd Australia 100.0
CitiPower Pty Australia 100.0
Marregon Pty Ltd Australia 100.0
AEP Resources CitiPower II Pty Ltd Australia 100.0
Australia's Energy Partnership Australia 1.0 (b)
Marregon II Pty Ltd Australia 100.0
CitiPower Pty Australia 100.0
Marregon Pty Ltd Australia 100.0
AEP Resources Australia Pty., Ltd. Australia 100.0
Pacific Hydro Limited Australia 20.0 (c)
AEP Delaware Investment Company Delaware 100.0
AEP Holdings I CV Netherlands 1.0 (a)
AEP Holdings II CV Netherlands 85.0 (d)
AEP Energy Services Limited Great Britain 100.0
AEP Funding Limited Cayman Islands 100.0
AEPR Global Investments B.V. Netherlands 100.0
AEPR Global Holland Holding B.V. Netherlands 100.0
AEPR Global Ventures B.V. Netherlands 100.0
Australian Energy International Pty Ltd Australia 16.0 (e)
AEI (Loy Yang) Pty Ltd Australia 100.0
Intergen Denmark, Aps Denmark 50.0 (f)
AEP Delaware Investment Company II Delaware 100.0
AEP Holdings II CV Netherlands 15.0 (d)
AEP Energy Services Limited Great Britain 100.0
AEP Funding Limited Cayman Islands 100.0
AEPR Global Investments B.V. Netherlands 100.0
AEPR Global Holland Holding B.V. Netherlands 100.0
AEPR Global Ventures B.V. Netherlands 100.0
Australian Energy International Pty Ltd Australia 16.0 (e)
AEI (Loy Yang) Pty Ltd Australia 100.0
Intergen Denmark, Aps Denmark 50.0 (f)
AEP Resources Do Brasil LTDA. Brazil 0.1 (g)
AEP Resources Do Brasil LTDA. Brazil 99.9 (g)
AEP Resources Gas Holding Company Delaware 100.0
AEP Resources Investments, Inc. Delaware 100.0
LIG Pipeline Company Nevada 100.0
LIG, Inc. Nevada 100.0
Louisiana Intrastate Gas Company, L.L.C.Louisiana 10.0 (h)
LIG Chemical Company Louisiana 100.0
LIG Liquids Company,L.L.C. Louisiana 10.0 (i)
LIG Liquids Company,L.L.C. Louisiana 90.0 (i)
Tuscaloosa Pipeline Company Louisiana 100.0
Louisiana Intrastate Gas Company,L.L.C. Louisiana 90.0 (h)
LIG Chemical Company Louisiana 100.0
LIG Liquids Company,L.L.C. Louisiana 10.0 (i)
LIG Liquids Company,L.L.C. Louisiana 90.0 (i)
Tuscaloosa Pipeline Company Louisiana 100.0
AEP Resources Ventures, Inc. Delaware 100.0
AEP Acquisition, L.L.C. Delaware 50.0 (j)
Jefferson Island Storage & Hub L.L.C. Delaware 100.0
AEP Resources Ventures II, Inc. Delaware 100.0
AEP Acquisition, L.L.C. Delaware 50.0 (j)
AEP Resources Ventures III, Inc. Delaware 100.0
AEP Resources International, Limited Cayman Islands 100.0
AEP Pushan Power, LDC Cayman Islands 99.0 (k)
Nanyang General Light Electric Co., Ltd. People's Republic of China 70.0 (l)
AEP Resources Mauritius Company Mauritius 99.0 (k)
AEP Resources Mauritius Investment Company Mauritius 100.0
AEP Resources Project Management Company, Ltd.Cayman Islands 100.0
AEP Pushan Power, LDC Cayman Islands 1.0 (k)
Nanyang General Light Electric Co., Ltd. People's Republic of China 70.0 (l)
AEP Resources Mauritius Company Mauritius 1.0 (k)
AEP Resources Limited Great Britain 100.0
Yorkshire Power Group Limited Great Britain 50.0 (m)
Yorkshire Cayman Holding Limited Cayman Islands 100.0
Yorkshire Holdings plc Great Britain 100.0
Yorkshire Electricity Group plc Great Britain 100.0
Yorkshire Power Finance Limited Cayman Islands 2.0 (n)
Yorkshire Power Finance Limited Cayman Islands 98.0 (n)
Appalachian Power Company Virginia 98.6 (o)
Cedar Coal Co. West Virginia 100.0
Central Appalachian Coal Company West Virginia 100.0
Central Coal Company West Virginia 50.0 (p)
Central Operating Company West Virginia 50.0 (p)
Southern Appalachian Coal Company West Virginia 100.0
West Virginia Power Company West Virginia 100.0
Columbus Southern Power Company Ohio 100.0
Colomet, Inc. Ohio 100.0
Conesville Coal Preparation Company Ohio 100.0
Simco Inc. Ohio 100.0
Franklin Real Estate Company Pennsylvania 100.0
Indiana Franklin Realty, Inc. Indiana 100.0
Indiana Michigan Power Company Indiana 100.0
Blackhawk Coal Company Utah 100.0
Price River Coal Company, Inc. Indiana 100.0
Kentucky Power Company Kentucky 100.0
Kingsport Power Company Virginia 100.0
Ohio Power Company Ohio 99.1 (q)
Cardinal Operating Company Ohio 50.0 (r)
Central Coal Company West Virginia 50.0 (p)
Central Ohio Coal Company Ohio 100.0
Central Operating Company West Virginia 50.0 (p)
Southern Ohio Coal Company West Virginia 100.0
Windsor Coal Company West Virginia 100.0
Ohio Valley Electric Corporation Ohio 44.2 (s)
Indiana-Kentucky Electric Corporation Indiana 100.0
Wheeling Power Company West Virginia 100.0
(a) Owned 99% by AEP Resources, Inc. and 1% by AEP Delaware Investment Company.
(b) Owned 99% by AEP Resources CitiPower I Pty Ltd and 1% by AEP Resources
CitiPower II Pty Ltd.
(c) Owned 20% by AEP Resources Australia Pty Ltd and 80% by an unaffiliated company.
(d) Owned 85% by AEP Holdings I CV and 15% by AEP Delaware Investment Company II.
(e) AEPR Global Ventures B.V. owns 16% and the remaining 84% is owned by an unaffiliated
company.
(f) Owned 50% by AEP Holdings II CV and 50% by an unaffiliated company.
(g) Owned 99.9% by AEP Resources, Inc. and 0.1% by AEP Delaware Investment Company II.
(h) Owned 90% by LIG Pipeline Company and 10% by LIG, Inc.
(i) Owned 90% by Louisiana Intrastate Gas Company, L.L.C. and 10% by Lig Chemical Company
(j) Owned 50% by AEP Resources Ventures, Inc and 50% by AEP Resources Ventures II.
(k) Owned 99% by AEP Resources International, Ltd. and 1% by AEP Resources
Project Management Company, Ltd.
(l) AEP Pushan Power LDC owns 70% and the remaining 30% is owned by two unaffiliated
companies.
(m) Owned 50% by AEP Resources, Inc. and 50% by an unaffiliated company.
(n) Yorkshire Power Group Limited owns 980 shares and Yorkshire Holdings plc owns 20 shares.
(o) 13,499,500 shares of Common Stock, all owned by parent, have one vote each
and 184,916 shares of Preferred Stock, all owned by the public, have one
vote each.
(p) Owned 50% by Appalachian Power Company and 50% by Ohio Power Company.
(q) 27,952,473 shares of Common Stock, all owned by parent, have one vote each
and 241,866 shares of Preferred Stock, all owned by the public, have one
vote each.
(r) Ohio Power Company owns 50% of the stock; the other 50% is owned by a
corporation not affiliated with American Electric Power Company, Inc.
(s) American Electric Power Company, Inc. and Columbus Southern Power Company own 39.9% and
4.3% of the stock, respectively, and the remaining 55.8% is owned by unaffiliated
companies.
</TABLE>
<PAGE>
Exhibit 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Post-Effective Amendment No.
3 to Registration Statement No. 33-01052 of American Electric Power Company,
Inc. on Form S-8 and Post-Effective Amendment No. 3 to Registration Statement
No. 33-01734 of American Electric Power Company, Inc. on Form S-3 of our
reports dated February 22, 2000 (March 3, 2000 as to Note 7), appearing in
and incorporated by reference in this Annual Report on Form 10-K of American
Electric Power Company, Inc. for the year ended December 31, 1999.
Deloitte & Touche LLP
Columbus, Ohio
March 24, 2000
<PAGE>
Exhibit 24
POWER OF ATTORNEY
AMERICAN ELECTRIC POWER COMPANY, INC.
Annual Report on Form 10-K for the Fiscal Year Ended
December 31, 1999
The undersigned directors of AMERICAN ELECTRIC POWER COMPANY, INC., a New
York 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 23rd
day of February, 2000.
/s/ John P. DesBarres /s/ Leonard J. Kujawa
John P. DesBarres Leonard J. Kujawa
/s/ E. Linn Draper, Jr. /s/ Donald G. Smith
E. Linn Draper, Jr. Donald G. Smith
/s/ Robert M. Duncan /s/ Linda Gillespie Stuntz
Robert M. Duncan Linda Gillespie Stuntz
/s/ Robert W. Fri /s/ Kathryn D. Sullivan
Robert W. Fri Kathryn D. Sullivan
/s/ Lester A. Hudson, Jr. /s/ Morris Tanenbaum
Lester A. Hudson, Jr. Morris Tanenbaum
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000004904
<NAME> AMERICAN ELECTRIC POWER COMPANY, INC.
<MULTIPLIER> 1,000,000
<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> 11,836
<OTHER-PROPERTY-AND-INVEST> 1,219
<TOTAL-CURRENT-ASSETS> 3,216
<TOTAL-DEFERRED-CHARGES> 3,046
<OTHER-ASSETS> 2,171
<TOTAL-ASSETS> 21,488
<COMMON> 1,320
<CAPITAL-SURPLUS-PAID-IN> 1,946
<RETAINED-EARNINGS> 1,740
<TOTAL-COMMON-STOCKHOLDERS-EQ> 5,006
119
45
<LONG-TERM-DEBT-NET> 6,336
<SHORT-TERM-NOTES> 208
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 680
<LONG-TERM-DEBT-CURRENT-PORT> 1,111
0
<CAPITAL-LEASE-OBLIGATIONS> 429
<LEASES-CURRENT> 91
<OTHER-ITEMS-CAPITAL-AND-LIAB> 7,463
<TOT-CAPITALIZATION-AND-LIAB> 21,488
<GROSS-OPERATING-REVENUE> 6,916
<INCOME-TAX-EXPENSE> 260
<OTHER-OPERATING-EXPENSES> 5,611
<TOTAL-OPERATING-EXPENSES> 5,871
<OPERATING-INCOME-LOSS> 1,045
<OTHER-INCOME-NET> 15
<INCOME-BEFORE-INTEREST-EXPEN> 1,060
<TOTAL-INTEREST-EXPENSE> 529
<NET-INCOME> 520
11<F1>
<EARNINGS-AVAILABLE-FOR-COMM> 520
<COMMON-STOCK-DIVIDENDS> 464
<TOTAL-INTEREST-ON-BONDS> 179
<CASH-FLOW-OPERATIONS> 817
<EPS-BASIC> 2.69
<EPS-DILUTED> 2.69
<FN>
<F1>Represents preferred stock dividend requirements of subsidiaries; deducted
before computation of net income.
</FN>
</TABLE>
