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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
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FORM 10-K
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(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, 2001
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _____________ to ______________
COMMISSION REGISTRANTS; STATES OF INCORPORATION; I.R.S. EMPLOYER
FILE NUMBER ADDRESS AND TELEPHONE NUMBER IDENTIFICATION NOS.
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1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation) 13-4922640
0-18135 AEP GENERATING COMPANY (An Ohio Corporation) 31-1033833
1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790
0-346 CENTRAL POWER AND LIGHT COMPANY (A Texas Corporation) 74-0550600
1-2680 COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation) 31-4154203
1-3570 INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) 35-0410455
1-6858 KENTUCKY POWER COMPANY (A Kentucky Corporation) 61-0247775
1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000
0-343 PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation) 73-0410895
1-3146 SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation) 72-0323455
0-340 WEST TEXAS UTILITIES COMPANY (A Texas Corporation) 75-0646790
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 223-1000
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.
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Indicate by check mark if disclosure of delinquent filers with respect to
American Electric Power Company, Inc. 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. [ ]
Indicate by check mark if disclosure of delinquent filers with respect to
Appalachian Power Company. Indiana Michigan Power Company or Ohio Power Company
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 of Appalachian Power
Company or Ohio Power Company incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K. X
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AEP Generating Company, Columbus Southern Power Company, Kentucky Power
Company, Public Service Company of Oklahoma and West Texas Utilities 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.
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE
REGISTRANT TITLE OF EACH CLASS ON WHICH REGISTERED
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AEP Generating Company None
American Electric Common Stock,
Power Company, Inc. $6.50 par value................................. New York Stock Exchange
Appalachian Power 8-1/4% Junior Subordinated Deferrable
Company 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
CPL Capital I 8.00% Cumulative Quarterly Income
Preferred Securities, Series A, Liquidation
Preference $25 per Preferred Security............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
PSO Capital I 8.00% Trust Originated Preferred
Securities, Series A, Liquidation
Preference $25 per Preferred Security.......... New York Stock Exchange
SWEPCo Capital I 7.875% Trust Preferred Securities,
Series A, Liquidation amount $25
per Preferred Security......................... New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
REGISTRANT TITLE OF EACH CLASS
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AEP Generating Company None
American Electric Power Company, Inc. None
Appalachian Power Company None
Central Power and Light Company 4.00% Cumulative Preferred Stock, Non-Voting, $100 par value
4.20% Cumulative Preferred Stock, Non-Voting, $100 par value
Columbus Southern Power Company None
Indiana Michigan Power Company 4.125% Cumulative Preferred Stock, Non-Voting, $100 par value
Kentucky Power Company None
Ohio Power Company 4.50% Cumulative Preferred Stock, Voting, $100 par value
Public Service Company of Oklahoma None
Southwestern Electric Power Company 4.28% Cumulative Preferred Stock, Non-Voting, $100 par value
4.65% Cumulative Preferred Stock, Non-Voting, $100 par value
5.00% Cumulative Preferred Stock, Non-Voting, $100 par value
West Texas Utilities Company None
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, 2002 FEBRUARY 1, 2002
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AEP Generating Company None 1,000
($1,000 par value)
American Electric Power Company, Inc. $13,478,213,062 322,368,167
($6.50 par value)
Appalachian Power Company None 13,499,500
(no par value)
Central Power and Light Company None 6,755,535
($25 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)
Public Service Company of Oklahoma None 9,013,000
($15 par value)
Southwestern Electric Power Company None 7,536,640
($18 par value)
West Texas Utilities Company None 5,488,560
($25 par value)
NOTE ON MARKET VALUE OF COMMON EQUITY HELD BY NON-AFFILIATES
American Electric Power Company, Inc. owns, directly or indirectly, all of
the common stock of AEP Generating Company, Appalachian Power Company, Central
Power and Light Company, Columbus Southern Power Company, Indiana Michigan Power
Company, Kentucky Power Company, Ohio Power Company, Public Service Company of
Oklahoma, Southwestern Electric Power Company and West Texas Utilities Company
(see Item 12 herein).
DOCUMENTS INCORPORATED BY REFERENCE
PART OF FORM 10-K
INTO WHICH DOCUMENT
DESCRIPTION IS INCORPORATED
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Portions of Annual Reports of the following companies for the fiscal year Part II
ended December 31, 2001:
AEP Generating Company
American Electric Power Company, Inc.
Appalachian Power Company
Central Power and Light Company
Columbus Southern Power Company
Indiana Michigan Power Company
Kentucky Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company
West Texas Utilities Company
Portions of Proxy Statement of American Electric Power Company, Inc. for Part III
2002 Annual Meeting of Shareholders, to be filed within 120 days after
December 31, 2001
Portions of Information Statements of the following companies for 2002 Part III
Annual Meeting of Shareholders, to be filed within 120 days after December
31, 2001:
Appalachian Power Company
Ohio Power Company
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THIS COMBINED FORM 10-K IS SEPARATELY FILED BY AEP GENERATING COMPANY,
AMERICAN ELECTRIC POWER COMPANY, INC., APPALACHIAN POWER COMPANY, CENTRAL POWER
AND LIGHT COMPANY, COLUMBUS SOUTHERN POWER COMPANY, INDIANA MICHIGAN POWER
COMPANY, KENTUCKY POWER COMPANY, OHIO POWER COMPANY, PUBLIC SERVICE COMPANY OF
OKLAHOMA, SOUTHWESTERN ELECTRIC POWER COMPANY AND WEST TEXAS UTILITIES 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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TABLE OF CONTENTS
PAGE
NUMBER
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Glossary of Terms...................................................................... i
Forward-Looking Information............................................................ 1
PART I
Item 1. Business............................................................. 2
Item 2. Properties........................................................... 35
Item 3. Legal Proceedings.................................................... 39
Item 4. Submission of Matters to a Vote of Security Holders.................. 40
Executive Officers of the Registrants.............................................. 40
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters........................................... 42
Item 6. Selected Financial Data............................................ 42
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition............................. 42
Item 7A. Quantitative and Qualitative Disclosures About Market Risk ...Risk 43
Item 8. Financial Statements and Supplementary Data........................ 43
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure......................... 43
PART III
Item 10. Directors and Executive Officers of the Registrants................ 43
Item 11. Executive Compensation............................................. 44
Item 12. Security Ownership of Certain Beneficial Owners
and Management................................................ 45
Item 13. Certain Relationships and Related Transactions..................... 46
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K................................................... 46
Signatures............................................................................. 49
Index to Financial Statement Schedules................................................. S-1
Independent Auditors' Report........................................................... S-2
Exhibit Index.......................................................................... E-1
GLOSSARY OF TERMS
The following abbreviations or acronyms used in this Form 10-K are defined
below:
ABBREVIATION OR ACRONYM DEFINITION
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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.
Btu..................................... British thermal unit.
Buckeye................................. Buckeye Power, Inc., an unaffiliated corporation.
C3...................................... C3 Communications, Inc.
CAA..................................... Clean Air Act.
CAAA.................................... Clean Air Act Amendments of 1990.
CCD Group............................... CSPCo, CG&E and DP&L.
CERCLA.................................. Comprehensive Environmental Response, Compensation and Liability Act of 1980.
CG&E.................................... The Cincinnati Gas & Electric Company, an unaffiliated utility company.
CO2..................................... Carbon dioxide.
Cook Plant.............................. The Donald C. Cook Nuclear Plant, owned by I&M, located near Bridgman, Michigan.
CPL..................................... Central Power and Light Company, an electric utility subsidiary of AEP.
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.
East Zone Companies of AEP.............. APCo, CSPCo, I&M, KEPCo and OPCo.
ERCOT................................... Electric Reliability Council of Texas.
EWG..................................... Exempt wholesale generator.
Federal EPA............................. United States Environmental Protection Agency.
FERC.................................... Federal Energy Regulatory Commission (an independent commission within the DOE).
FUCO.................................... Foreign utility company as defined by PUHCA.
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.
MTM..................................... Mark-to-market.
NOx..................................... Nitrogen oxide.
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.
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ABBREVIATION OR ACRONYM DEFINITION
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PSO..................................... Public Service Company of Oklahoma, an electric utility subsidiary of AEP.
PUCO.................................... The Public Utilities Commission of Ohio.
PUHCA................................... Public Utility Holding Company Act of 1935, as amended.
QF...................................... Qualifying facility as defined in the Public Utility Regulatory Policies Act of 1978.
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.
SEEBOARD................................ SEEBOARD Group plc, Crawley, West Sussex, United Kingdom.
Service Corporation..................... American Electric Power Service Corporation, a service subsidiary of AEP.
SO2..................................... Sulfur dioxide.
SO2 Allowance........................... An allowance to emit one ton of sulfur dioxide granted under the Clean Air Act
Amendments of 1990.
SPP..................................... Southwest Power Pool.
STPNOC.................................. STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on
behalf of its joint owners including CPL.
SWEPCo.................................. Southwestern Electric Power Company, an electric utility subsidiary of AEP.
TVA .................................... Tennessee Valley Authority.
Vale.................................... Empresa De Electricidade Vale Paranapanema SA, a Brazilian Electric Distribution
Company.
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.
West Zone Companies of AEP.............. CPL, PSO, SWEPCo and WTU.
WTU..................................... West Texas Utilities Company, an electric utility subsidiary of AEP.
Zimmer or Zimmer Plant.................. Wm. H. Zimmer Generating Station, a 1,300,000-kilowatt coal-fired generating unit
commonly owned by CSPCo (25.4%), CG&E (46.5%) and DP&L (28.1%), and operated by
CG&E.
ii
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:
- Electric load and customer growth.
- Abnormal weather conditions.
- Available sources of and prices for coal and gas.
- Availability of generating capacity.
- Litigation concerning AEP's merger with CSW.
- The timing of the implementation of AEP's restructuring plan.
- Risks related to energy trading and construction under contract.
- The speed and degree to which competition is introduced to our power
generation business.
- The ability to recover net regulatory assets, other stranded costs and
implementation costs in connection with deregulation of generation in
certain states.
- New legislation and government regulations.
- The structure and timing of a competitive market for electricity and
its impact on prices.
- The ability of AEP to successfully control its costs.
- The success of new business ventures.
- International developments affecting AEP's foreign investments.
- The effects of fluctuations in foreign currency exchange rates.
- The economic climate and growth in AEP's service and trading
territories, both domestic and foreign.
- The ability of AEP to comply with or to challenge successfully new
environmental regulations and to litigate successfully claims that AEP
violated the CAA.
- Inflationary trends.
- Changes in electricity and gas market prices and interest rates.
- Other risks and unforeseen events.
1
PART I -------------------------------------------------------------------------
Item 1. BUSINESS
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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 marketing and trading of power and gas and the furnishing of
electric service.
The service area of AEP's domestic electric utility subsidiaries covers
portions of the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan,
Ohio, Oklahoma, Tennessee, Texas, 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, 2001, the subsidiaries of AEP had a total of 27,726
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 917,000 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, 2001, APCo and its wholly owned
subsidiaries had 2,629 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.
CPL (organized in Texas in 1945) is engaged in the generation, sale,
purchase, transmission and distribution of electric power to approximately
689,000 customers in southern Texas, and in supplying electric power at
wholesale to other utilities, municipalities and rural electric
cooperatives. At December 31, 2001, CPL had 1,374 employees. Among the
principal industries served by CPL are oil and gas extraction, food
processing, apparel, metal refining, chemical and petroleum refining,
plastics, and machinery equipment.
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
678,000 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, 2001, CSPCo had 1,222 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. 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.
2
I&M (organized in Indiana in 1925) is engaged in the generation, sale,
purchase, transmission and distribution of electric power to approximately
567,000 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, 2001, I&M had 2,851 employees. Among the principal industries
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 173,000 customers in an area in eastern Kentucky, and in
supplying electric power at wholesale to other utilities and municipalities
in Kentucky. At December 31, 2001, KEPCo had 427 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, 2001, Kingsport
Power Company had 58 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 698,000 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, 2001, OPCo and its wholly owned subsidiaries had 2,297
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.
PSO (organized in Oklahoma in 1913) is engaged in the generation,
sale, purchase, transmission and distribution of electric power to
approximately 502,000 customers in eastern and southwestern Oklahoma, and
in supplying electric power at wholesale to other utilities, municipalities
and rural electric cooperatives. At December 31, 2001, PSO had 989
employees. Among the principal industries served by PSO are natural gas and
oil production, oil refining, steel processing, aircraft maintenance, paper
manufacturing and timber products, glass, chemicals, cement, plastics,
aerospace manufacturing, telecommunications, and rubber goods.
SWEPCo (organized in Delaware in 1912) is engaged in the generation,
sale, purchase, transmission and distribution of electric power to
approximately 431,000 customers in northeastern Texas, northwestern
Louisiana, and western Arkansas, and in supplying electric power at
wholesale to other utilities, municipalities and rural electric
cooperatives. At December 31, 2001, SWEPCo had 1,375 employees. Among the
principal industries served by SWEPCo are natural gas and oil production,
petroleum
3
refining, manufacturing of pulp and paper, chemicals, food processing, and
metal refining. The territory served by SWEPCo also includes several
military installations, colleges, and universities.
Wheeling Power Company (organized in West Virginia in 1883 and
reincorporated in 1911) provides electric service to approximately 41,000
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, 2001, Wheeling Power Company
had 64 employees.
WTU (organized in Texas in 1927) is engaged in the generation, sale,
purchase, transmission and distribution of electric power to approximately
189,000 customers in west and central Texas, and in supplying electric
power at wholesale to other utilities, municipalities and rural electric
cooperatives. At December 31, 2001, WTU had 689 employees. The principal
industry served by WTU is agriculture. The territory served by WTU also
includes several military installations and correctional facilities.
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 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.
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.
AEP-CSW MERGER
On June 15, 2000, CSW merged with and into a wholly owned merger subsidiary
of AEP with CSW being the surviving corporation. The merger was pursuant to an
Agreement and Plan of Merger, dated as of December 21, 1997, that AEP and CSW
had entered into. 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)
was converted into 0.6 of a share of common stock, par value $6.50 per share, of
AEP. CSW's four wholly-owned domestic electric utility subsidiaries are CPL,
PSO, SWEPCo and WTU.
AEP is complying or intends to comply with the following conditions imposed
by the FERC as part of the FERC's order approving the merger:
- Transfer operational control of AEP's east and west transmission
systems to fully-functioning, FERC-approved regional transmission
organizations. See Transmission Services for Non-Affiliates.
- 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. AEP implemented these measures upon the
consummation of the merger.
- Divestiture of 550 MW of generating capacity comprised of 300 MW of
capacity in SPP and 250 MW of capacity in ERCOT. AEP must complete
divestiture of the SPP capacity by July 1, 2002. AEP has completed
divestiture of the ERCOT capacity.
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. As required by the FERC, the proposed
interim energy sales were in effect when the merger was consummated.
4
Litigation: On January 18, 2002, the U.S. Court of Appeals for the District
of Columbia ruled that the SEC failed to prove that the merger met the
requirements of PUHCA and remanded the case to the SEC for further review. The
court held that the SEC must explain its conclusion that the merger met PUHCA
requirements that utilities be "physically interconnected" and justify its
finding that the merger will result in a combined entity that is confined to a
"single area or region."
In its June 2000 approval of the merger, the SEC agreed with AEP that AEP's
and CSW's systems are interconnected because they have transmission access
rights to a single high-voltage line through Missouri and also meet the PUHCA's
single region requirement because it is now technically possible to centrally
control the output of power plants across many states. In its ruling, the court
held that the SEC failed to explain its conclusions that the transmission
integration and single region requirements are satisfied.
Management believes that the merger meets the requirements of PUHCA and
expects the matter to be resolved favorably.
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 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 and CPL are subject to regulation by the NRC under the Atomic
Energy Act of 1954, as amended, with respect to the operation of the Cook Plant
and STP, respectively.
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. Following the report, legislation
was introduced in Congress to repeal PUHCA and transfer certain federal
authority to the FERC as recommended in the SEC report. Since 1997, such PUHCA
repeal language has been reintroduced in each session of Congress both as a
separate bill and as part of broader legislation regarding changes in the
electric industry. Legislative hearings were held but neither the House of
Representatives nor the Senate passed any PUHCA repeal legislation. A number of
bills contemplating PUHCA repeal separately and with the restructuring of the
electric utility industry have been 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.
5
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.
Rates
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,
except for the states of Ohio, Texas and Virginia as noted below. 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.
AEP is exposed to risk from changes in the market prices of coal and
natural gas used to generate electricity where generation is no longer regulated
or where existing fuel clauses are suspended or frozen. The protection afforded
by fuel clause recovery mechanisms has either been eliminated by the
implementation of customer choice in Ohio (effective January 1, 2001) and in the
ERCOT power grid area of Texas (effective January 1, 2002) or frozen by
settlement agreements in Indiana, Michigan, and West Virginia. To the extent the
fuel supply of the generating units in these states is not under fixed price
long-term contracts, AEP is subject to market price risk. AEP continues to be
protected against market price changes by active fuel clauses in Oklahoma,
Arkansas, Louisiana, Kentucky, Virginia and the SPP area of Texas.
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, Texas and Virginia has been, subject to
significant revision. See Competition and Business Change and the footnote to
the financial statements entitled Customer Choice and Industry Restructuring.
6
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 during the
year ended December 31, 2001 are as follows:
AEP
SYSTEM(a) AEGCo APCo CPL CSPCo
--------- ----- ---- --- -----
(IN THOUSANDS)
Wholesale Business:
Residential............................... $ 3,553,216 $ 0 $ 587,062 $ 660,884 $ 477,341
Commercial................................ 2,328,383 0 267,312 473,337 426,444
Industrial................................ 2,388,354 0 353,070 345,071 141,583
Other Retail Customers.................... 419,232 0 77,258 49,007 46,948
Energy Delivery........................... (3,356,000) (575,036) (473,182) (483,219)
------------- -------------- ------------- --------- ---------
Total Retail........................... 5,333,185 0 709,666 1,055,117 609,097
Marketing and Trading-Electricity......... 35,339,641 227,338 5,571,750 1,671,686 3,117,136
Marketing and Trading-Gas................. 14,368,857 0 0 0 0
Unrealized MTM Income:....................
Electric.............................. 209,660 0 29,334 19,930 16,730
Gas................................... 46,990 0 0 0 0
Other..................................... 631,016 210 113,644 101,812 73,681
------------- -------------- ------------- --------- ---------
Total Wholesale Business............ 55,929,349 227,548 6,424,394 2,848,545 3,816,644
------------- -------------- ------------- --------- ---------
Energy Delivery Business:....................
Transmission.............................. 1,029,000 0 180,244 162,734 109,824
Distribution.............................. 2,327,000 0 394,792 310,448 373,395
------------- -------------- ------------- --------- ---------
Total Energy Delivery............... 3,356,000 0 575,036 473,182 483,219
------------- -------------- ------------- --------- ---------
Other Investments:...........................
SEEBOARD.................................. 1,451,233 0 0 0 0
CitiPower................................. 349,773 0 0 0 0
Other..................................... 170,645 0 0 0 0
------------- -------------- ------------- --------- ---------
Total Other Investments............. 1,971,651 0 0 0 0
------------- -------------- ------------- --------- ---------
Total Revenues................ $ 61,257,000 $ 227,548 $ 6,999,430 $ 3,321,727 $ 4,299,863
============= ============== ============= ========= =========
I&M KEPCo OPCo PSO SWEPCo WTU
--- ----- ---- --- ------ ----
(IN THOUSANDS)
Wholesale Business:
Residential............................... $ 350,600 $ 109,882 $ 444,418 $ 381,515 $ 321,022 $ 160,520
Commercial................................ 218,818 47,369 235,220 305,525 226,946 98,153
Industrial................................ 323,157 92,215 526,431 215,038 273,096 60,032
Other Retail Customers.................... 59,983 16,058 68,968 12,746 33,271 44,318
Energy Delivery........................... (314,410) (134,619) (552,713) (261,877) (333,004) (169,036)
--------- --------- --------- --------- -------- -------
Total Retail........................... 638,148 130,905 722,324 652,947 521,331 193,987
Marketing and Trading-Electricity......... 3,783,302 1,364,877 4,848,386 1,258,861 1,653,208 648,527
Marketing and Trading-Gas................. 0 0 0 0 0 0
Unrealized MTM Income:....................
Electric............................. 0 0 23,139 0 10,830 4,390
Gas.................................. 0 0 0 0 0 0
Other..................................... 67,765 28,994 115,840 27,564 56,075 48,331
--------- --------- --------- --------- -------- -------
Total Wholesale Business............ 4,489,215 1,524,776 5,709,689 1,939,372 2,241,444 895,235
--------- --------- --------- --------- -------- -------
Energy Delivery Business:....................
Transmission.............................. 122,345 53,697 167,399 63,045 81,324 75,443
Distribution.............................. 192,065 80,922 385,314 198,832 251,680 93,593
--------- --------- --------- --------- -------- -------
Total Energy Delivery............... 314,410 134,619 552,713 261,877 333,004 169,036
--------- --------- --------- --------- -------- -------
Other Investments:
SEEBOARD.................................. 0 0 0 0 0 0
CitiPower................................. 0 0 0 0 0 0
Other 0 0 0 0 0 0
--------- --------- --------- --------- -------- -------
Total Other Investments............. 0 0 0 0 0 0
--------- --------- --------- --------- -------- -------
Total Revenues................ $ 4,803,625 $1,659,395 $ 6,262,402 $ 2,201,249 $ 2,574,448 $ 1,064,271
========= ========= =========== =========== =========== ===========
- ---------------------------
(a) Includes revenues of other subsidiaries not shown and elimination of
intercompany transactions.
7
SALE OF POWER
AEP's electric utility subsidiaries own or lease generating stations with
total generating capacity of approximately 38,300 megawatts. See Item 2.
Properties, for more information regarding the generating stations. They operate
their generating plants as a single interconnected and coordinated electric
utility system and, in the east zone, share the costs and benefits in the AEP
System Power Pool. As discussed below under AEP System Power Pool, after
corporate separation, the public utility subsidiaries that are no longer
regulated at the state level will participate in a separate power pool. Most of
the electric power generated at AEP's generating stations is sold, in
combination with transmission and distribution services, to retail customers of
AEP's utility subsidiaries in their service territories. See Regulation--Rates.
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 their 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 SO2 Allowances associated with
transactions under the Interconnection Agreement. As part of AEP's restructuring
settlement agreement filed with the FERC, CSPCo and OPCo would no longer be
parties to the Interconnection Agreement and certain other modifications to its
terms would also be made. See Competition and Business Change--AEP Restructuring
Plan.
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 gross 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 the Interconnection Agreement and Interim Allowance Agreement
during the years ended December 31, 1999, 2000 and 2001:
1999(a) 2000(a) 2001(a)
---- ---- ----
(IN THOUSANDS)
APCo.............. $ (89,100) $(274,000) $(256,700)
CSPCo............. (184,500) (250,400) (251,200)
I&M............... (61,700) 93,900 166,200
KEPCo............. 23,700 (21,500) (27,600)
OPCo.............. 311,600 452,000 369,300
- -------------------------
(a) Includes credits and charges from allowance transfers related to the
transactions.
CPL, PSO, SWEPCo, WTU, and AEP Service Corporation are parties to a
Restated and Amended Operating Agreement originally dated as of January 1, 1997
(CSW Operating Agreement). The CSW Operating Agreement requires the operating
companies of the west zone to maintain specified annual planning reserve margins
and requires the subsidiaries that have capacity in excess of the required
margins to make such capacity available for sale to other AEP subsidiaries as
capacity commitments. The CSW Operating Agreement also delegates to AEP Service
Corporation the authority to coordinate the acquisition, disposition, planning,
design and construction of generating units and to supervise the operation and
maintenance of a central control center. As part of AEP's restructuring
settlement agreement filed with the FERC, CPL and WTU would no longer be parties
to the CSW Operating Agreement and certain other
8
modifications to its terms would also be made. See Competition and Business
Change--AEP Restructuring Plan.
Wholesale Sales of Power to Non-Affiliates
AEP's electric utility subsidiaries also sell electric power on a wholesale
basis to non-affiliated electric utilities and power marketers. Such sales are
either made (i) by individual companies pursuant to various long-term power
agreements or (ii) under the Interconnection Agreement (AEP Power Pool) or the
CSW Operating Agreement. Sales made under the Interconnection Agreement are
allocated among the East Zone subsidiaries based on member-load ratios. Sales
made under the CSW Operating Agreement are allocated among the West Zone
subsidiaries based on participation ratios.
Reference is made to the footnote to the financial statements entitled
Commitments and Contingencies that is incorporated by reference in Item 8 for
information with respect to AEP's long-term agreements to sell power.
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 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 are
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 Regulation--Rates. 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, 1999,
2000 and 2001:
1999 2000 2001
---- ---- ----
(IN THOUSANDS)
APCo......... $ (8,300) $ (3,400) $ (3,100)
CSPCo........ 39,000 38,300 40,200
I&M.......... (43,900) (43,800) (41,300)
KEPCo........ (4,300) (6,000) (4,600)
OPCo......... 17,500 14,900 8,800
CPL, PSO, SWEPCo, WTU, and AEP Service Corporation are parties to a
Transmission Coordination Agreement originally dated as of January 1, 1997
(TCA). The TCA establishes a coordinating committee, which is charged with the
responsibility of overseeing the coordinated planning of the transmission
facilities of the west zone operating subsidiaries, including the performance of
transmission planning studies, the interaction of such subsidiaries with
independent system operators (ISO) and other regional bodies interested in
transmission planning and compliance with the terms of the Open Access
Transmission Tariff (OATT) filed with the FERC and the rules of the FERC
relating to such tariff.
Under the TCA, the west zone operating subsidiaries have delegated to AEP
Service Corporation the responsibility of monitoring the reliability of their
transmission systems and administering the OATT on their behalf. The TCA also
provides for the allocation among the west zone operating subsidiaries of
revenues collected for transmission and ancillary services provided under the
OATT.
Transmission Services for Non-Affiliates
AEP's electric utility subsidiaries and other System companies also provide
transmission services for non-affiliated companies.
9
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.
On July 9, 1996, the AEP System companies filed a tariff conforming with
the FERC's pro-forma transmission tariff.
Since 1998 AEP has engaged in discussions with a group of Midwestern
utilities regarding the development of the Alliance RTO which may take the form
of an 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 2001 the Alliance companies filed with the FERC a proposed business plan
for the Alliance RTO. In December 2001, the FERC issued an order approving the
proposal of the Midwest ISO (an independent operator of transmission assets in
the Midwest) for an RTO and rejecting the Alliance RTO's business plan and
finding that the Alliance RTO lacks sufficient scope and regional configuration
to exist as a stand-alone RTO. The FERC directed the Alliance companies to
negotiate with the Midwest ISO and others to explore possible combinations.
Following such discussions, on March 5, 2002, the Alliance RTO filed with the
FERC a request for a declaratory order seeking resolution of these issues.
COORDINATION OF EAST AND WEST ZONE OPERATING SUBSIDIARIES
AEP's System Integration Agreement provides for the integration and
coordination of AEP's east and west zone operating subsidiaries, joint dispatch
of generation within the AEP System, and the distribution, between the two
operating zones, of costs and benefits associated with the System's generating
plants. It is designed to function as an umbrella agreement in addition to the
AEP Interconnection Agreement and the CSW Operating Agreement, each of which
will continue to control the distribution of costs and benefits within each zone
for all regulated subsidiaries.
AEP's System Transmission Integration Agreement provides for the
integration and coordination of the planning, operation and maintenance of the
transmission facilities of AEP's east and west zone operating subsidiaries. Like
the System Integration Agreement, the System Transmission Integration Agreement
functions as an umbrella agreement in addition to the AEP Transmission Agreement
and the Transmission Coordination Agreement. The System Transmission Integration
Agreement contains two service schedules that govern:
- The allocation of transmission costs and revenues.
- The allocation of third-party transmission costs and revenues and
System dispatch costs.
The Transmission Integration Agreement anticipates that additional service
schedules may be added as circumstances warrant.
10
CERTAIN POWER AGREEMENTS
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 aggregate power participation ratio of APCo,
CSPCo, I&M and OPCo is 42.1%. 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. On September 29, 2000, DOE
issued a notice of cancellation of the DOE/OVEC power agreement, such
cancellation to be effective no later than April 30, 2003. In conjunction with
this notice, DOE released all future rights to OVEC's generating capacity,
effective September 1, 2001. DOE was therefore not entitled to any OVEC capacity
beyond August 31, 2001, and the sponsoring companies became entitled to receive
and pay for all OVEC capacity (approximately 2,200MW) in proportion to their
power participation ratios at that time.
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 25 of the rural electric cooperatives which
operate in the State of Ohio at 337 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 August 8, 2001, was
recorded at 1,344,315 kilowatts.
Reference is made to Wholesale Business Operations -- Structured
Arrangements Involving Capacity, Energy, and Ancillary Services for a discussion
of an agreement with an affiliate of Buckeye to construct and operate a
gas-fired electric generating peaking facility.
Century Aluminum
Century Aluminum of West Virginia, Inc. (formerly Ravenswood Aluminum
Corporation), operates a major aluminum reduction plant in the Ohio River Valley
at Ravenswood, West Virginia. The power requirement of such plant presently is
approximately 357,000 kilowatts. OPCo is providing electric service pursuant to
a contract approved by the PUCO for the period July 1, 1996 through July 31,
2003.
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 and KEPCo 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
11
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. As part of AEP's restructuring settlement agreement
pending with the FERC, the KEPCo unit power agreement would be extended to
December 31, 2009 for Unit 1 and December 7, 2022 for Unit 2. See Competition
and Business Change--AEP Restructuring Plan.
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 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.
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/or legislation has been enacted in
Arkansas, Michigan, Ohio, Oklahoma, Texas, Virginia and West 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. However, movement toward
retail deregulation in certain of these states is slowing as a consequence of,
among other things, adverse developments related to deregulation of the electric
industry in California.
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
12
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 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.
Reference is made to Management's Discussion and Analysis of Results of
Operations and Management's Discussion and Analysis of Financial Condition,
Contingencies and Other Matters and the footnote to the financial statements
entitled Customer Choice and Industry Restructuring incorporated by reference in
Items 7 and 8, respectively, for further information with respect to competition
and business change.
AEP Position on Competition
AEP favors 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. 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.
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. As 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.
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.
13
Retail
The public utility subsidiaries of AEP have the exclusive right to sell
electric power at retail within their service areas in the states of Arkansas,
Indiana, Kentucky, Louisiana, Oklahoma, Tennessee and West Virginia.
Furthermore, while customer choice commenced in Michigan on January 1, 2002, I&M
does not have any competing suppliers active in its Michigan service territory
at this time. However, AEP's public utility subsidiaries 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 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.
AEP Restructuring Plan
As a result of deregulating legislation that has been enacted or is being
considered in several of the states in which the AEP public utility subsidiaries
provide service, AEP has reassessed the corporate ownership of its public
utility subsidiaries' assets. Deregulating legislation in some of the states
requires the separation of generation assets from transmission and distribution
assets. On November 1, 2000, AEP filed with the SEC under PUHCA for approval of
a restructuring plan in part to meet the requirements of this legislation. This
application is pending.
On July 24, 2001, AEP filed with the FERC for approval of the restructuring
plan and on December 21, 2001, a settlement agreement with six state regulatory
commissions and other major parties was filed with the FERC. The settlement
agreement is pending approval. FERC approval is necessary before the SEC will
issue its order.
AEP's restructuring plan is designed to align its legal structure and
business activities with the requirements of deregulation. AEP's plan
contemplates the formation of two first tier subsidiaries that would hold the
following public utility assets:
- A subsidiary would hold the assets of public utility subsidiaries that
remain subject to regulation as to rates by at least one state utility
commission. AEP intends for this subsidiary ultimately to hold all
transmission and distribution assets.
- A subsidiary would hold (i) public utility and non-utility
subsidiaries that derive their revenues from competitive activity and
(ii) foreign utility subsidiaries and other investments. AEP intends
for this subsidiary to ultimately hold all generation assets not
subject to regulation.
WHOLESALE BUSINESS OPERATIONS
AEP's wholesale business operations focus on value-driven asset
optimization at each link of the energy chain through the following activities:
- A diversified portfolio of owned assets and structured third party
arrangements, including:
14
- Power generation facilities and renewable energy sources.
- Natural gas pipeline, storage and processing facilities.
- Coal mines and related facilities.
- Barge, rail and other fuel transportation related assets.
- Trade and market energy commodities, including electric power, natural
gas, natural gas liquids, oil, coal, and SO2 allowances in North
America and Europe.
- Price-risk management services and liquidity through a variety of
energy-related financial instruments, including exchange-traded
futures and over-the-counter forward, option, and swap agreements.
- Long-term transactions to buy or sell capacity, energy, and ancillary
services of electric generating facilities, either existing or to be
constructed, at various locations in North America and Europe.
Power Generation Facilities and Renewable Energy Sources
In addition to approximately 38,300 MW listed under Item 2. Properties, AEP
has ownership interests in the generating facilities listed under AEP-Other
Generation of approximately 1,900 MW domestically and 6,700 MW internationally,
of which approximately 1,100 MW is from renewable energy sources.
Natural Gas Pipeline, Storage and Processing Facilities
In June 2001, AEP acquired Houston Pipe Line Company (HPL) and Lodisco LLC
for $727 million from Enron Corp. The acquired assets include: (i) a 4,200-mile
intrastate gas pipeline in Texas with capacity of approximately 2.4 billion
cubic feet per day; (ii) the exclusive right (for 30 years with an additional
20-year extension) to the underground Bammel Storage Facility (one of the
largest natural gas storage facilities in North America) with 118 billion cubic
feet of storage capacity and appurtenant pipelines including the Bammel Loop,
Houston City Loop and the Texas City Loop; and (iii) certain gas marketing
contracts.
AEP acquired Louisiana Intrastate Gas Company, LLC ("LIG") in 1998. LIG's
midstream gas assets include: (i) a 2,000-mile intrastate gas pipeline in
Louisiana with capacity of approximately 800 million cubic feet per day; (ii)
five natural gas processing plants that straddle the pipeline; and (iii) a ten
billion cubic foot underground natural gas storage facility directly connected
to the Henry Hub, one of the most active gas trading areas in North America.
Coal Mines and Related Facilities
In October 2001, to enhance its coal trading and marketing activities, AEP
acquired substantially all the assets of Quaker Coal Company as part of a
bankruptcy proceeding restructuring. AEP paid $101 million to Quaker's creditors
and assumed additional liabilities of approximately $58 million. The acquisition
included property, coal reserves, mining operations and royalty interests in
Colorado, Kentucky, Ohio, Pennsylvania and West Virginia. AEP will continue to
operate the mines and facilities which have approximately 800 employees.
Barge, Rail and Other Fuel Transportation Related Assets
In November 2001, AEP acquired MEMCO Barge Line Inc. for $270 million as
part of its overall asset optimization program. MEMCO is engaged in the
transportation of coal and dry bulk commodities, primarily on the Ohio,
Illinois, and Lower Mississippi rivers. MEMCO owns or leases 1,200 hopper barges
and 30 towboats. The addition of MEMCO's barge assets to AEP's existing fleet
places AEP among the leading barge operators in the country. See Fuel
Supply--Coal and Lignite for other barges and towboats leased by I&M and OPCo.
Trading and Marketing of Energy Commodities
Sales: Based upon volumetric sales in the U.S., Power Markets Weekly ranked
AEP's wholesale trading business No. 2 in electric sales for the first, second
and third quarters of 2001. Platts Gas Daily ranked AEP Nos. 14, 10 and 2 in gas
sales for the
15
first, second and third quarters, respectively, of 2001.
ICEX: To gain access to additional liquidity trading points, AEP acquired
an interest in the internet-based electronic trading system, Intercontinental
Exchange, L.L.C. (ICEX), in 2000 that enables participants to initiate,
negotiate, and execute trades in the crude oil, natural gas, and spot and
forward energy markets. Other investors include global energy companies and
leading investment banking firms.
Structured Arrangements Involving Capacity, Energy, and Ancillary Services
AEP has entered into an agreement with The Dow Chemical Company to
construct a 900 MW cogeneration facility at Dow's chemical facility in
Plaquemine, Louisiana. Commercial operation is expected in 2003. AEP is entitled
to 100% of the facility's capacity and energy and has contracted to sell the
power from this facility to an unaffiliated party.
In January 2000, OPCo and National Power Cooperative, Inc. (NPC), an
affiliate of Buckeye, entered into an agreement 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 2002) until the end of
2005, OPCo will be entitled to 100% of 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.
INTERNATIONAL ELECTRIC
Other international holdings of AEP include the following.
Australia: CitiPower Pty. is an electric distribution and retail sales
company in Victoria, Australia. CitiPower serves approximately 240,000 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. AEP acquired CitiPower in 1998 for U.S.$1.1
billion.
UK: SEEBOARD, headquartered in Crawley, West Sussex and acquired as part of
AEP's merger with CSW, is one of the 12 regional electricity companies formed as
a result of the restructuring and subsequent privatization of the United Kingdom
electricity industry in 1990. CSW acquired indirect control of SEEBOARD in April
1996. SEEBOARD's principal businesses are the distribution and supply of
electricity. In addition, SEEBOARD is engaged in other businesses, including gas
supply, electricity generation, and electrical contracting. SEEBOARD has
approximately 2,000,000 customers and its service area covers approximately
3,000 square miles in Southeast England with the majority of its customers in
Kent, Sussex and parts of Surrey.
Possible Divestitures: On February 3, 2002, AEP announced the appointment
of investment banks to advise AEP on the prospects for divestment of CitiPower
and/or SEEBOARD. Because of pooling of interests accounting restrictions,
imposed as part of AEP's merger with CSW and which expire in June 2002, any
possible divestment of CitiPower and/or SEEBOARD is not anticipated until after
these restrictions lapse.
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 wholesale, high capacity, fiber optic services,
colocation, and wireless tower infrastructure services under the C3 brand with
operations in Arkansas, Kansas, Louisiana, Oklahoma and Texas.
AEP Communications joined with several other energy and telecommunications
companies to form AFN Communications, LLC. (AFN). AFN is a
16
super regional telecommunications company that provides long haul fiber optic
capacity to competitive local exchange carriers, wireless carriers and long
distance companies. AFN does business in New York, Pennsylvania, Virginia, West
Virginia, Ohio, Indiana, Michigan, Illinois, and Kentucky and has approximately
10,000 route miles of fiber optic network.
C3, an entity that was acquired through the merger with CSW, is engaged in
providing fiber optic and collocation services in Texas, Louisiana, Oklahoma,
Arkansas, and Kansas. C3 does business as C3 Networks and has approximately
5,300 route miles of fiber optic network.
Management is evaluating certain of AEP's telecommunications investments
for possible disposal.
CONSTRUCTION PROGRAM
General
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 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 restructuring of the electric utility industry and the
move to increasing competition in the marketplace. See Competition and Business
Change.
Generation
Committed or anticipated capability changes to the AEP System's generation
resources includes the expiration of the Rockport Unit 2 sale of 250 megawatts
to Carolina Power & Light Company, an unaffiliated company, on December 31,
2009. See AEP-CSW Merger for a discussion of the divestiture of generating
capacity as part of the merger.
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. Given the restructuring taking 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 a Wyoming-Cloverdale 765,000-volt Project.
The preferred route for this line was approximately 132 miles in length,
connecting APCo's Wyoming Station in southern West Virginia to APCo's Cloverdale
Station near Roanoke, Virginia.
APCo originally 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 for the
original Wyoming-Cloverdale Project. If this alternative were incorporated into
a 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 on non-federal lands.
West Virginia: On May 27, 1998, the West Virginia PSC issued an order
granting APCo's application for a certificate to construct the
Wyoming-Cloverdale 765,000-volt Project. On March 13, 2002, the West Virginia
PSC issued an order granting APCo's request to construct the line with a
terminus at Jacksons Ferry substation in Virginia instead of the Cloverdale
substation as discussed below under Virginia.
17
Virginia: Following several procedural delays and Hearing Examiner's
rulings, APCo filed a study in May 1999 identifying the Wyoming-Jacksons Ferry
Project as an alternative project to the Wyoming-Cloverdale Project. The
Jacksons Ferry Project proposes a line from Wyoming Station in West Virginia to
APCo's existing 765,000-volt Jacksons Ferry Station in Virginia. APCo estimates
that the Wyoming-Jacksons Ferry line would be 90 miles in length, including 32
miles in West Virginia previously certified. In May 2000, the Virginia SCC held
an evidentiary hearing to consider both projects. On October 2, 2000, the
Hearing Examiner's report to the Virginia SCC recommended approval of the
Wyoming-Jacksons Ferry Alternative Project. On May 31, 2001, the Virginia SCC
issued an order granting APCo's application for a certificate to construct the
Wyoming-Jacksons Ferry 765,000-volt Project.
Proposed Completion Schedule and Estimated Cost: Subsequent to Virginia and
West Virginia granting certificates to construct the Project, the Forest Service
restarted the EIS process and is scheduled to complete and release a supplement
to the Draft EIS in April 2002. The Final EIS process should continue for the
balance of 2002, with a decision on the federal permits anticipated in Spring
2003. APCo has also begun required consultation with the U.S. Fish and Wildlife
Service under the Endangered Species Act, which should be completed concurrently
with the EIS process.
Given the status of the Project permitting process, and assuming that the
projected schedule of the EIS process will be met, management estimates that the
Wyoming-Jacksons Ferry 765,000-volt Project cannot be completed before Summer
2006.
Depending upon the outcome of the EIS permitting process by the Forest
Service, APCo's estimated cost for the Wyoming-Jacksons Ferry Project ranges
from $250 to $280 million, assuming a Summer 2006 in-service date.
Construction Expenditures
The following table shows construction expenditures during 1999, 2000 and
2001 and current estimates of 2002 construction expenditures, in each case
including AFUDC but excluding assets acquired under leases.
1999 2000 2001 2002
ACTUAL ACTUAL ACTUAL ESTIMATE
------ ------ ------ --------
(IN THOUSANDS)
AEP System (a).. $1,679,600 $1,773,400 $1,832,000 $1,820,400
AEGCo........ 8,300 5,200 6,900 45,600
APCo......... 211,400 199,300 306,000 258,200
CPL.......... 255,800 199,500 194,100 172,300
CSPCo........ 115,300 128,000 132,500 145,400
I&M.......... 165,300 171,100 91,100 205,400
KEPCo........ 44,300 36,200 37,200 128,800
OPCo......... 193,900 254,000 344,600 349,700
PSO.......... 104,500 176,900 124,900 80,600
SWEPCo....... 112,900 120,200 112,100 111,900
WTU.......... 52,600 64,500 39,800 51,800
- -----------------------
(a) Includes expenditures of other subsidiaries not shown.
Reference is made to the footnote 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 1999, 2000 and 2001 and the current estimate for 2002 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
18
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.
1999 2000 2001 2002
ACTUAL ACTUAL ACTUAL ESTIMATE
------ ------ ------ --------
(IN THOUSANDS)
AEGCo............. $ 8 $ 70 $ 3,500 27,700
APCo.............. 24,500 2,100 99,200 86,500
CPL............... (a) (a) 2,500 200
CSPCo............. 10,600 6,600 22,500 25,500
I&M............... 4,500 1,900 700 28,500
KEPCo............. 1,900 400 11,200 60,200
OPCo.............. 37,400 91,200 125,300 103,900
PSO............... (a) (a) 400 400
SWEPCo............ (a) (a) 9,200 9,600
WTU............... (a) (a) 800 3,000
------- ------ ------- -------
AEP System (a).. $ 78,908 $102,270 $275,300 $345,500
======== ======== ======== ========
- -----------------------
(a) Amounts not available for west zone companies of AEP prior to AEP-CSW
merger.
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.
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 and leasing
arrangements, including the leasing of utility assets and coal mining and
transportation equipment and facilities. 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.
New projects undertaken by AEP's unregulated subsidiaries are generally
financed through equity funds provided by AEP, non-recourse debt incurred on a
project-specific basis, debt issued by such subsidiaries or through a
combination thereof. See Wholesale Business Operations and Item 7 for additional
information concerning AEP's unregulated subsidiaries.
AEP's revolving credit agreements include covenants and events of default
typical for this type of facility, including a maximum debt/capital test and a
$50 million cross-acceleration provision. At December 31, 2001, AEP was in
compliance with its debt covenants. With the exception of a voluntary bankruptcy
or insolvency, any event of default has either or both a cure period or notice
requirement before termination of the agreements. A voluntary bankruptcy or
insolvency would be considered an immediate termination event.
Reference is made to Management's Discussion and Analysis of Results of
Operations and Management's Discussion and Analysis of Financial Condition,
Contingencies and Other Matters incorporated by reference in Item 7 for
information with respect to AEP's plans to restructure its debt to implement
corporate separation. See Competition and Business Change--AEP Restructuring
Plan herein.
FUEL SUPPLY
The following table shows the sources of power generated by the AEP System:
1997 1998 1999 2000 2001
---- ---- ---- ---- ----
Coal.................... 76% 79% 79% 78% 74%
Gas..................... 12% 14% 15% 13% 12%
Nuclear................. 8% 3% 3% 5% 11%
Hydroelectric and other. 4% 4% 3% 4% 3%
Variations in the generation of nuclear power are primarily related to
refueling outages and, in 1997 through 2000, the shutdown of the Cook Plant to
respond to issues raised by the NRC.
19
Natural Gas
AEP consumed over 240 billion cubic feet of natural gas during 2001 for the
system operating companies. A majority of the gas fired electric generation
plants are connected to at least two natural gas pipelines, which provides
greater access to competitive supplies and improves reliability. Natural gas
requirements for each plant are supplied by a portfolio of long-term and
short-term purchase and transportation agreements that are acquired on a
competitive basis and based on market prices.
Coal and Lignite
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 began 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 --
Title IV Acid Rain Program 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 by
entering into additional supply agreements, either on a long-term or spot basis,
at prices and upon terms which cannot now be predicted.
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 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.
Western coal purchased by System companies is transported to AEP generating
stations by rail and via an affiliated river terminal for subsequent
transloading to barges for final delivery. CPL, PSO and SWEPCo own (in the
aggregate) 2,982 coal hopper cars and APCo, I&M and OPCo lease (in the
aggregate) an additional 4,066 coal hopper cars to be used in unit train
movements. I&M and OPCo lease (in the aggregate) 15 towboats, 454 jumbo barges
and 143 standard barges. Certain subsidiaries of AEP also own or lease coal
transfer facilities at various other locations.
See Wholesale Business Operations--Barge, Rail and Other Fuel
Transportation Related Assets herein for information with respect to the
acquisition of MEMCO Barge Line Inc. in 2001.
The System generating companies procure coal through purchases pursuant to
long-term contracts or spot purchases from affiliated and 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
20
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:
1997(a) 1998(a) 1999(a) 2000 2001
---- ---- ---- ---- ----
Total coal delivered to
AEP operated plants (thousands of tons)........... 54,292 54,004 54,306 73,259 73,889
Sources (percentage):
Subsidiaries........................................ 14% 14% 12% 9% 4%
Long-term contracts................................. 66% 66% 64% 67% 68%
Spot or short-term purchases........................ 20% 20% 24% 24% 28%
Average price per ton of spot-purchased coal........... $24.38 $25.05 $27.18 $24.03 $27.30
- --------------------
(a) Includes east zone companies only.
The average cost of coal consumed during the past five years by all AEP
System companies is shown below. AEP System companies' data for 1997 includes
only AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo.
1997 1998 1999 2000 2001
---- ---- ---- ---- ----
DOLLARS PER TON
AEP System Companies............................................. $ 29.68 $ 29.87 $ 30.01 $ 31.39 $ 28.55
AEGCo......................................................... 19.30 19.37 20.79 20.65 21.01
APCo.......................................................... 36.09 34.81 33.29 32.84 32.41
CPL........................................................... 26.93 26.93 26.49 25.95 26.78
CSPCo......................................................... 31.69 31.63 29.94 28.50 30.63
I&M........................................................... 23.68 22.61 24.54 23.44 23.57
KEPCo......................................................... 26.76 27.42 26.76 25.35 25.02
OPCo.......................................................... 36.00 38.94 40.56 46.52 35.06
PSO........................................................... 21.11 20.37 20.94 21.21 20.45
SWEPCo........................................................ 23.16 23.02 21.34 22.59 24.22
WTU........................................................... 18.19 21.37 21.72 22.26 23.81
1997 1998 1999 2000 2001
---- ---- ---- ---- ----
CENTS PER MILLION BTU'S
AEP System Companies............................................. 140.13 142.17 141.95 149.12 136.85
AEGCo......................................................... 115.21 112.63 116.90 116.23 118.89
APCo.......................................................... 146.54 141.76 135.40 134.86 135.88
CPL........................................................... 136.40 137.00 135.78 137.86 140.22
CSPCo......................................................... 134.44 134.15 127.42 120.83 131.64
I&M........................................................... 123.36 118.02 121.90 117.99 121.27
KEPCo......................................................... 110.37 112.15 109.91 104.88 104.97
OPCo.......................................................... 151.66 164.44 169.23 194.77 146.87
PSO........................................................... 120.91 116.73 119.54 121.83 116.33
SWEPCo........................................................ 152.79 150.62 143.34 144.96 153.88
WTU........................................................... 109.13 126.22 129.13 131.56 143.21
21
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, 2001, the
System's coal inventory was approximately 41 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 2001 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 2001 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.
AVERAGE SULFUR CONTENT
ESTIMATED REQUIRE- OF DELIVERED COAL
TOTAL CONSUMPTION MENTS FOR REMAINDER ----------------------------
DURING 2001 OF USEFUL LIVES POUNDS OF SO2
(IN THOUSANDS OF TONS) (IN MILLIONS OF TONS) BY WEIGHT PER MILLION BTU'S
-------------------- ------------------- --------- -----------------
AEGCo (a)............................... 4,829 215 0.3% 0.7
APCo.................................... 10,529 375 0.7% 1.2
CPL..................................... 2,470 36 0.3% 0.7
CSPCo................................... 5,637 213(b) 2.4% 4.1
I&M (c)................................. 7,026 244 0.6% 1.2
KEPCo................................... 2,981 80 0.9% 1.5
OPCo.................................... 19,392 546(d) 2.1% 3.5
PSO..................................... 4,049 41 0.4% 0.9
SWEPCo.................................. 12,254 117 0.6% 1.6
WTU..................................... 1,370 32 0.4% 0.8
- ------------------------
(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.
(d) Total does not include OPCo's portion of Sporn 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 0.7% during 2001, 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.
CPL: CPL has coal supply agreements of one year or less duration with two
coal suppliers and various coal trading firms for the delivery of approximately
2,400,000 tons of coal for the year 2002. Approximately one half of the coal
delivered to Coleto Creek is from Wyoming with the other half from Colorado.
Both sources supply low sulfur coal with a limit of 1.2 lbs/MMBtu.
CSPCo: CSPCo has coal supply agreements with unaffiliated suppliers for the
delivery of approximately 3,780,000 tons in 2002. 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
22
units, each operating company is contractually responsible for obtaining the
needed fuel.
I&M: I&M has historically received coal under two coal supply agreements
with unaffiliated Wyoming suppliers for low sulfur coal from surface mines
principally for consumption at the Rockport Plant. As a result of litigation
involving future deliveries from one of these suppliers, there will not be any
coal delivered under this contract in 2002. Under the other agreement, the
supplier 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. This
contract, which expires on December 31, 2004, has remaining deliveries of
approximately 22,800,000 tons.
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 648,000 tons of coal in 2002.
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 has historically been
supplied from both affiliated and unaffiliated suppliers. As a result of the
2001 sale of AEP's coal mines in Ohio and West Virginia and an agreement to
purchase approximately 34,000,000 tons of coal through 2008 from the purchaser
of the mines, coal consumed at OPCo's plants in 2002 will be supplied from
unaffiliated suppliers under long-term contracts and/or on a spot purchase
basis.
PSO: PSO takes all its coal from one coal supplier under a contract that
provides for the entire plant requirements with at least 16,830,000 tons
remaining to be delivered between 2002 and 2007. The coal is supplied from
Wyoming and has a maximum sulfur content of 1.2 lbs. SO2 per MMBtu.
SWEPCo: SWEPCo receives coal at its plants under a combination of
agreements, including one long-term coal contract with a Wyoming producer, one
affiliate mine-mouth lignite operation and agreements with various producers and
coal trading firms. SWEPCo's long-term coal supply contract provides
approximately half of the requirements for both coal plants. SWEPCo must take
delivery of 25,625,000 tons of coal through 2006, with the remainder of its coal
requirements met through short-term spot agreements for low sulfur (less than
1.2 lbs. SO2 per MMBtu) coal with various Wyoming coal suppliers and trading
companies.
WTU: WTU has one long-term coal supply contract that provides approximately
two-thirds of the coal requirements for the Oklaunion Power Station. This
contract has approximately 9,180,000 tons of coal remaining to be delivered
between 2002 and mid-2006. The remaining coal requirements for Oklaunion are
being purchased under short-term agreements with various Wyoming coal suppliers
and coal trading firms, with such coal being low sulfur (less than 1.2 lbs. SO2
per MMBtu).
Nuclear
I&M and STPNOC have made commitments to meet certain of the nuclear fuel
requirements of the Cook Plant and STP, respectively. The nuclear fuel cycle
consists of:
- Mining and milling of uranium ore to uranium concentrates.
- Conversion of uranium concentrates to uranium hexafluoride.
- Enrichment of uranium hexafluoride.
- Fabrication of fuel assemblies.
- Utilization of nuclear fuel in the reactor.
- 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
23
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.
CPL and the other STP participants have entered into contracts with
suppliers for 100% of the uranium concentrate sufficient for the operation of
both STP units through Spring 2006 and with an additional 50% of the uranium
concentrate needed for STP through Spring 2007. In addition, CPL and the other
STP participants have entered into contracts with suppliers for 100% of the
nuclear fuel conversion service sufficient for the operation of both STP units
through Spring 2003, with additional flexible contracts to provide at least 50%
of the conversion service needed for STP through 2008. CPL and the other STP
participants have entered into flexible contracts to provide for 100% of
enrichment through Fall 2004, with additional flexible contracts to provide at
least 50% of enrichment services through Fall 2008. Also, fuel fabrication
services have been contracted for operation through 2028 for Unit 1 and 2029 for
Unit 2.
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.
STP has on-site storage facilities with the capability to store the spent
nuclear fuel generated by the STP units over their licensed lives.
The costs of nuclear fuel consumed by I&M and CPL do not assume any
residual or salvage value for residual plutonium and uranium.
Nuclear Waste and Decommissioning
Reference is made to Management's Discussion and Analysis of Results of
Operations and Management's Discussion and Analysis of Financial Condition,
Contingencies and Other Matters in the financial statements and Commitments and
Contingencies in the footnotes to these statements that are incorporated by
reference in Items 7 and 8, respectively, for information with respect to
nuclear waste and decommissioning and related litigation.
The ultimate cost of retiring the Cook Plant and STP may be materially
different from estimates and funding targets as a result of the:
- Type of decommissioning plan selected.
- Escalation of various cost elements (including, but not limited to,
general inflation).
- Further development of regulatory requirements governing
decommissioning.
- Limited availability to date of significant experience in
decommissioning such facilities.
- Technology available at the time of decommissioning differing
significantly from that assumed in these studies.
- Availability of nuclear waste disposal facilities.
Accordingly, management is unable to provide assurance that the ultimate cost of
decommissioning the Cook Plant and STP 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
24
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.
Texas is a member of the Texas Compact, which includes the states of Maine
and Vermont. Texas had identified a disposal site in Hudspeth County for
construction of a low-level waste disposal facility. During the licensing
process for the Hudspeth site, that site was found to be unsuitable. No
additional site has been considered. Management is unable to predict when a
disposal site for Texas 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 and Texas. 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 by the Cook Plant and STP are now being sent to the disposal
site.
Under state law, the amounts of low-level radioactive waste being disposed
of at the South Carolina facility from non-regional generators, such as the Cook
Plant and STP, are limited and being reduced. Non-regional access to the South
Carolina facility is currently allowed through the end of fiscal year 2008.
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, or
where states are deregulating generation, unbundled transition period
generation rates, stranded cost wires charges and future market prices
for electricity.
- 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 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.
AEP's international operations are subject to regulation with respect to
air, waste and water quality standards and other environmental matters by
various authorities within the host countries. Under certain circumstances,
these authorities may require modifications to these facilities and operations
or impose fines and other costs for violations of applicable statutes and
regulations. From time to time, these operations are made aware of various
environmental issues or are named as parties to various legal claims, actions,
complaints or other proceedings related to environmental matters. Management
does not expect disposition of any such pending environmental proceedings to
have a material adverse effect on AEP's consolidated results of operations or
financial condition.
Reference is made to Management's Discussion and Analysis of Results of
Operations and Management's Discussion and Analysis of Financial Condition,
Contingencies and Other Matters and the footnote to the financial statements
entitled
25
Commitments and Contingencies incorporated by reference in Items 7 and 8,
respectively, for further information with respect to environmental matters,
including discussion of legislative proposals under consideration by the
Administration and Congress focused on reductions in emissions of CO2, NOx, SO2,
mercury and other constituents.
Air Pollution Control
For the AEP System operating companies, compliance with the CAA is
requiring substantial expenditures that generally are being recovered through
the rates of AEP's operating subsidiaries. Certain matters discussed below may
require significant additional operating and capital expenditures. However,
there can be no assurance that all such costs will be recovered. See
Construction Program -- Construction Expenditures.
Title I National Ambient Air Quality Standards Attainment: 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 (PM2.5). In addition to the potential financial consequences discussed
above, both of these new standards have the potential to affect adversely the
operation of AEP System generating units. In May 1999, the U.S. Court of Appeals
for the District of Columbia Circuit remanded the ozone and PM2.5 NAAQS to
Federal EPA. In February 2001, the U.S. Supreme Court issued an opinion
reversing in part and affirming in part the Court of Appeals decision. The
Supreme Court remanded the case to the Court of Appeals for further proceedings,
including a review of whether adoption of the standards was arbitrary and
capricious and directed Federal EPA to develop a policy for implementing the
revised ozone standard in conformity with the CAA. The Court of Appeals held
oral argument on the remanded issues in December 2001.
NOx SIP Call: In October 1998, Federal EPA issued a final rule (NOx
transport SIP call or NOx SIP Call) establishing state-by-state NOx emission
budgets for the five-month ozone season to be met beginning May 1, 2003. The NOx
budgets originally applied 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 SIP call was accompanied by a proposed Federal
Implementation Plan, which could be implemented in any state that fails to
submit an approvable SIP. 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 construct new facilities or to operate affected
facilities without making significant capital expenditures.
In October 1998, the AEP System operating companies joined with certain
other parties seeking a review of the final NOx SIP Call rule in the U.S. Court
of Appeals for the District of Columbia Circuit. In March 2000, the court issued
a decision upholding the major provisions of the rule. The court subsequently
extended the date for submission of SIP revisions until October 30, 2000, and
the compliance deadline until May 31, 2004. In March 2001, the U.S. Supreme
Court denied petitions filed by industry petitioners, including AEP System
operating companies, seeking review of the Court of Appeals decision.
In May 1999 and March 2000, Federal EPA finalized the NOx budget
allocations to be implemented through the NOx SIP Call. AEP and other parties
filed petitions for review in the U.S. Court of Appeals for the District of
Columbia Circuit and in June 2000 the court issued an opinion remanding the
budget determinations for further consideration of certain growth factor
assumptions made by Federal EPA. In December 2000, Federal EPA issued a
determination that eleven states, including certain states in which AEP System
operating companies have sources covered by the NOx SIP Call rule, had failed to
submit complying SIP revisions. AEP System operating companies and unaffiliated
utilities appealed this determination to the U.S. Court of Appeals for the
District of Columbia Circuit and the court has stayed the proceeding pending
Federal EPA action on the remand of growth factor issues.
26
In April 2000, the Texas Natural Resource Conservation Commission adopted
rules requiring significant reductions in NOx emissions from utility sources,
including those of CPL and SWEPCo. The rule compliance date is May 2003 for CPL
and May 2005 for SWEPCo.
Management's estimates indicate that compliance with the revised NOx SIP
Call rule, and SIP revisions already adopted, could result in required capital
expenditures for the AEP System of approximately $1.6 billion, of which
approximately $450 million has been expended through December 31, 2001.
Reference is made to the footnote to the financial statements entitled
Commitments and Contingencies incorporated by reference in Item 8 for
information with respect to AEP registrant subsidiaries' compliance cost
estimates and amounts expended.
In May 2001, OPCo completed a $175 million installation of selective
catalytic reduction (SCR) technology to reduce NOx emissions on its two-unit
2,600 MW Gavin Plant and, during the 2001 ozone season (May through September),
operated the SCR units. Construction of selective catalytic reduction technology
on Amos Plant Unit 3, which is jointly owned by OPCo and APCo, and on APCo's
Mountaineer Plant, began in 2001. The Amos and Mountaineer projects (expected to
be completed in 2002) are estimated to cost a total of $230 million. Management
has undertaken the Gavin, Amos and Mountaineer projects to meet applicable NOx
emission reduction requirements. Additional expenditures of approximately $7
million are planned or undertaken to address certain operational issues arising
during initial operation of the Gavin SCR units.
Since compliance costs cannot be estimated with certainty, the actual costs
to comply could be significantly different from management's estimates depending
upon the compliance alternatives selected to achieve reductions in NOx
emissions. Unless capital and operating costs of any additional pollution
control equipment necessary for compliance are recovered from customers through
regulated rates and market prices for electricity, they could have a material
adverse effect on future results of operations, cash flows and possibly
financial condition of AEP and its affected subsidiaries.
Section 126 Petitions: In January 2000, Federal EPA adopted a revised rule
granting petitions filed by certain northeastern states under Section 126 of the
CAA. The petitions sought significant reductions in nitrogen oxide emissions
from utility and industrial sources. The rule imposed emission reduction
requirements comparable to the NOx SIP Call rule beginning May 1, 2003, for most
of AEP's coal-fired generating units. Certain AEP System operating companies and
other utilities filed petitions for review in the U.S. Court of Appeals for the
District of Columbia Circuit. In May 2001, the court issued an opinion which
upheld substantially the entire rule. The court did not agree that Federal EPA
had properly supported the growth factors for the NOx allowance budgets. In
August 2001, the court issued an order tolling the May 1, 2003, compliance date
pending resolution of the remand of the growth factor issues. In January 2002,
Federal EPA advised that it intends to establish May 31, 2004, as the final
compliance date for the rule. Cost estimates for compliance with Section 126 are
projected to be somewhat less than those set forth above for the NOx SIP Call
rule reflecting the fact that Section 126 does not apply to AEGCo's and I&M's
Rockport Plant.
West Virginia SO2 Limits: West Virginia promulgated SO2 limitations, which
Federal EPA approved in February 1978. The emission limitations for OPCo's
Mitchell Plant have been approved by Federal EPA for primary ambient air quality
(health-related) standards only. West Virginia is obligated to reanalyze SO2
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.
In August 1994, Federal EPA issued a Notice of Violation to OPCo alleging
that Kammer Plant was operating in violation of the applicable federally
enforceable SO2 emission limit. In May 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
27
U.S. District Court for the Northern District of West Virginia. Kammer Plant has
achieved and maintained compliance with the applicable SO2 emission limit for a
period in excess of one year, pursuant to the provisions of the consent decree.
In May 2001, the court terminated the consent decree.
Short Term SO2 Limits: In January 1997, Federal EPA proposed a new
intervention level program under the authority of Section 303 of the CAA to
address five-minute peak SO2 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 SO2 levels. In January 2001,
Federal EPA published a Federal Register notice inviting comment with respect to
its decision not to promulgate a five-minute SO2 NAAQS and intent to take final
action on the intervention level program by the summer of 2001. The effect of
this proposed intervention program on AEP operations or financial performance
cannot be predicted at this time.
Hazardous Air Pollutants: Hazardous air pollutant (HAP) emissions from
utility boilers are potentially subject to control requirements under Title III
of the CAAA which specifically directed Federal EPA to study potential public
health impacts of HAPs emitted from electric utility steam generating units. In
December 2000, Federal EPA announced its intent to regulate emissions of mercury
from coal and oil-fired power plants, concluding that these emissions pose
significant hazards to public health. A decision on whether to regulate other
HAPs emissions from these sources was deferred.
Federal EPA added coal and oil-fired electric utility steam generating
units to the list of "major sources" of HAPs under Section 112 (c) of the CAA,
which compels the development of "Maximum Achievable Control Technology" (MACT)
standards for these units. Listing under Section 112 (c) also compels a
preconstruction permitting obligation to establish case-by-case MACT standards
for each new or reconstructed source in the category. MACT standards for utility
mercury emissions are scheduled to be proposed by December 2003 and finalized by
December 2004. The Utility Air Regulatory Group (which includes AEP System
operating companies as members) filed a petition with Federal EPA seeking
reconsideration of the decision to regulate mercury emissions from power plants
under Section 112(c) of the CAA.
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
is adequate to address any adverse public health or environmental effects
associated with the atmospheric deposition of hazardous air pollutants in the
Great Lakes. The potential impact of adverse developments in these programs on
AEP operations or financial performance cannot be predicted at this time.
Title IV Acid Rain Program: The Acid Rain Program (Title IV) of the CAAA
created an emission allowance program pursuant to which utilities are authorized
to emit a designated quantity of SO2, measured in tons per year.
Phase II of the Acid Rain Program, which affects all fossil fuel-fired
steam generating units with capacity greater than 25 megawatts imposed more
stringent SO2 emission control requirements beginning January 1, 2000. If a unit
emitted SO2 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. Future SO2 requirements will be met
through accumulation or acquisition of allowances, the use of controls or fuels,
or a combination thereof. See Fuel Supply--Coal and Lignite.
Title IV of the CAAA also regulates emissions of NOx. Federal EPA has
promulgated NOx emission limitations for all boiler types in the AEP System at
levels significantly below original design, which were to be achieved by January
1, 2000 on a unit-by-unit or System-wide average basis. AEP sources subject to
Title IV of the CAAA are in
28
compliance with the provisions thereof.
Regional Haze: In July 1999, Federal EPA finalized rules to regulate
regional haze attributable to anthropogenic emissions. The primary goal of 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, the rules address the potential regulation of such precursor
emissions in every state. Under the rule, 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. In addition, Federal EPA intends to
require Best Available Retrofit Technology (BART) for power plants and other
large emission sources constructed between 1962 and 1977.
In January 2001, Federal EPA proposed guidelines for states to use in
setting BART emission limits for power plants and other large emission sources
and in determining which sources are subject to those limits. The proposed rule
calls for technologies which Federal EPA estimates are capable of reducing SO2
emissions by 90 to 95 percent. The proposed rule also contemplates that other
visibility-impairing emissions must be reduced. Emission trading programs could
be used in lieu of unit-by-unit BART requirements under the proposal, provided
they yield greater visibility improvement and emission reductions.
The AEP System is a significant emitter of fine particulate matter and
other precursors of regional haze and a number of AEP's generating units could
be subject to BART controls. 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 SO2 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 in August 1999.
Permitting and Enforcement: The CAAA expanded the enforcement authority of
the federal government by:
- Increasing the range of civil and criminal penalties for violations of
the CAA and enhancing administrative civil provisions.
- Imposing a national operating permit system, emission fee program and
enhanced monitoring, recordkeeping and reporting requirements.
Section 103 of CERCLA 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. In December 1999,
Federal EPA published interim guidance in the Federal Register, which provided
that any hazardous substance or extremely hazardous substance not expressly and
individually limited in a permit must be reported if they are emitted at levels
above an RQ. Specifically, constituents of regulated pollutants (e.g., metals
contained in particulate matter) were not deemed to be federally permitted. AEP
System operating companies have provided supplemental information regarding air
releases from their facilities and are submitting follow-up reports. Federal EPA
suspended its December 1999 guidance as it considers certain revisions to the
guidance. Settlement discussions regarding the guidance are underway.
Global Climate Change: In December 1997, delegates from 167 nations,
including the U.S., agreed to a treaty, known as the "Kyoto Protocol,"
establishing legally-binding emission reductions for gases suspected of causing
climate change. The Protocol requires ratification by at least 55 nations that
account for at least 55% of developed countries' 1990 emissions of CO2 to enter
into force.
Although the U.S. signed the treaty on November 12, 1998, it was not sent
to the Senate for
29
its advice and consent to ratification. In a letter dated March 13, 2001 from
President Bush to four U. S. senators, he indicated his opposition to the Kyoto
Protocol and said he does not believe that the government should impose
mandatory emissions reductions for CO2 on the electric utility sector.
Despite U.S. opposition to the treaty, at the Seventh Conference of the
Parties to the United Nations Framework Convention on Climate Change, held in
Marrakech, Morocco in November 2001, the parties finalized the rules, procedures
and guidelines required to facilitate ratification of the treaty by most
nations, and entry into force is expected by 2003.
Since the AEP System is a significant emitter of carbon dioxide, its
results of operations, cash flows and financial condition could be materially
adversely affected by the imposition of limitations on CO2 emissions if
compliance costs cannot be fully recovered from customers. In addition, any
program to reduce CO2 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. in its current form. AEP's 4,000 MW of coal-fired
generation in the United Kingdom acquired in 2001 may be exposed to potential
carbon dioxide emission control obligations since the U.K. is expected to be a
party to the Kyoto Protocol. AEP is developing an emissions mitigation plan for
these plants to ensure compliance as necessary.
On February 14, 2002, President Bush announced new climate change
initiatives for the U.S. Among the policies to be pursued is a voluntary
commitment to reduce the "greenhouse gas intensity" of the economy by 18% within
the next ten years. It is anticipated that the Administration will seek to
partner with various industrial sectors, including the electric utility
industry, to reach this goal. AEP is unable to predict at this time the effect
that this program will have upon its operations or financial performance in the
future.
New Source Review: In July 1992, Federal EPA published final regulations
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 (NSR) requirements. The Natural Resources Defense
Council and a group of utilities, including five AEP System operating companies,
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 exclusions contained in
the current regulation. The Administration and Congress are considering
initiatives to reform the NSR requirements, but no regulatory revisions have
been proposed to date.
New Source Review Litigation: On November 3, 1999, following issuance by
Federal EPA of substantial information requests to AEP System operating
companies, 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 20 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 OPCo's
Cardinal Unit 1, Mitchell, Muskingum River, and Sporn plants and I&M's Tanners
Creek plant. Federal EPA also issued Notices of Violation to AEP alleging
similar violations at certain other AEP plants.
In March 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 APCo's Amos, Clinch River, and Kanawha River plants, CSPCo's Conesville
Plant, and OPCo's Kammer Plant. 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.
A number of northeastern and eastern states have been allowed to intervene
in the litigation, and
30
a number of special interest groups filed a separate complaint based on
substantially similar allegations, which has been consolidated with the DOJ
complaint. In addition to the plants named by the government and special
interest groups, the intervenor states have included allegations concerning
OPCo's Gavin Plant.
In May 2000, AEP filed a motion to dismiss with the District Court, which,
if granted, would dispose of most of the claims of the government and
intervenors.
In February 2001, the plaintiffs filed a motion for partial summary
judgment seeking a determination that four projects undertaken on units at
Sporn, Cardinal, and Clinch River Plants do not constitute "routine maintenance,
repair and replacement" as used in the NSR programs. In August 2001, the court
issued an order denying the plaintiffs' motion as premature. Management believes
its maintenance, repair and replacement activities were in conformity with the
CAA and intends to vigorously pursue its defense.
A number of unaffiliated utilities have also received notices of violation,
complaints, or administrative orders relating to NSR. A notice of violation was
issued in June 2000 to DP&L with respect to its ownership interest in Stuart
Station, in which CSPCo also owns a 26 percent interest. W.C. Beckjord Unit 6,
operated by CG&E, in which CSPCo owns a 12.5 percent interest, is also the
subject of an enforcement action. Cinergy Corp., the parent company of CG&E, has
entered into an agreement in principle with the DOJ in an attempt to resolve the
litigation relating to W.C. Beckjord Unit 6 and other plants owned or operated
by Cinergy and its subsidiaries. This agreement in principle also covers the
Zimmer Plant which has not been the subject of an enforcement action. VEPCo has
also entered into a similar agreement in principle. Neither CG&E nor VEPCo have
reached final agreements with the DOJ. Two other unaffiliated utilities, Tampa
Electric Company and PSEG Fossil, LLC, have reached settlements with the Federal
government.
In November 2000, several environmental groups filed a petition with Ohio
EPA seeking to have the draft Title V operating permits for OPCo's Cardinal and
Muskingum River plants as well as the Beckjord Plant and a plant owned by an
unaffiliated utility, modified to incorporate requirements and timetables for
compliance with New Source Review requirements. In December 2000, a petition was
filed by these groups with the Administrator of Federal EPA seeking a similar
modification of the final Title V permit for CSPCo's Conesville Plant. Ohio EPA
has refused to consider these petitions outside the regular Title V permit
processing procedures or to interfere with the resolution of these issues by the
District Court.
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). In March
2001, the District Court issued orders holding that claims for civil penalties
based on alleged activities that occurred more than five years prior to the
filing of the complaint are barred. Although the plaintiffs' claims for
injunctive relief are not barred, the court noted that the nature of the relief
ordered may be impacted by the plaintiffs' delay in filing the complaints.
Management is unable to estimate the loss or range of loss related to the
contingent liability for civil penalties under the CAA proceedings and unable to
predict the timing of resolution of these matters due to the number of alleged
violations and issues to be determined by the court. In the event the AEP System
companies do 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 market prices for electricity.
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
31
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 AEP System generating plants are required to have NPDES permits and
have received them. NPDES permit conditions and effluent limitations are
reviewed during the permit renewal process. 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 2002.
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 CSPCo's Conesville and OPCo's 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 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 was further reduced. In early 2002, AEP submitted a
petition to Ohio EPA requesting additional less stringent thermal loading
limitations for these plants.
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. Federal EPA issued final regulations defining BTA for new
sources that were published in the Federal Register on December 18, 2001. New
sources are those commencing construction after January 17, 2002. On February
28, 2002, Federal EPA issued a proposed rule addressing BTA for intake
structures at existing plants. This proposal is expected to be published in the
Federal Register for comment in April 2002. Under a previous court-established
schedule, Federal EPA is required to issue final regulations for existing plants
by August 2003. Federal EPA's rulemaking could result in a definition of BTA
that could ultimately require retrofitting of certain existing plant intake
structures. Such changes would involve costs for AEP System operating 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.
Section 303 of the Federal Clean Water Act 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 that water quality standards are not being met. In order to bring these
waters back into compliance, total maximum daily load (TMDL) allocations of
these pollutants will be made, and subsequently translated into discharge limits
in NPDES permits. Federal EPA has also directed that states take action to adopt
enhanced anti-degradation of water quality requirements. In October 2001,
Federal EPA issued a rule delaying until April 30, 2003, the effective date of
its TMDL rule issued in July 2000, the effective date of which had been
previously delayed by Congress. Implementation of these provisions could result
in significant costs to the AEP System if biological monitoring requirements and
water quality-based effluent limits and requirements 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
32
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 System operating 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. CERCLA expanded the reporting requirement 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 cleanup 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 operating 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.
AEP System operating companies are identified as Potentially Responsible
Parties (PRPs) for five federal sites where remediation has not been completed,
including APCo at one site, CSPCo at one site, I&M at two sites, and OPCo at one
site. AEP has also been named a PRP at two sites under state law. Management's
present estimates do not anticipate material clean-up costs for identified sites
for which AEP subsidiaries have been declared PRPs. In addition, AEP subsidiary
companies are engaged in certain remedial projects at various locations, the
costs of which are not expected to be material. However, if significant costs
are incurred for cleanup, future results of operations and possibly financial
condition could be adversely affected unless the costs can be recovered through
rates and/or future market prices for electricity where generation is
deregulated.
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.
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. Federal EPA chose to address separately the issue
of low volume wastes (such as metal and boiler cleaning wastes) associated with
burning coal and other fossil fuels. In May 2000, Federal EPA issued a
regulatory determination that such low volume wastes are also
33
excluded from regulation under the RCRA hazardous waste provisions when mixed
and co-managed with high volume fossil fuel combustion wastes.
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 and
STP and 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, electrical equipment, 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. 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 2001, and
intending to contribute a similar amount in 2002. 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.
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.
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 that
focus on:
- Exploring new methods of generating electricity, such as through
renewable sources (e.g., wind, solar).
- Enhancing energy trading infrastructure.
- Developing more efficient methods of operating generating plants.
34
- Optimizing and efficiently managing generation and other
energy-related assets.
- Reducing emissions resulting from the burning of fossil fuels (coal
and natural gas).
- Improving the efficiency, utilization and reliability of the
transmission and distribution systems.
- Exploring the application of new technologies.
AEP System operating companies are members of the Electric Power Research
Institute (EPRI), an organization founded in 1973 that manages science and
technology initiatives on behalf of its members. EPRI's members include investor
owned and public utilities, independent power producers, international
organizations and others.
AEP participates in EPRI programs that meet its research and development
objectives. Total AEP dues to EPRI were $9,000,000 for 2001, $17,000,000 for
2000 and $22,000,000 for 1999. Of these amounts, the former CSW System paid
approximately $7,000,000 in 2000 and $8,000,000 in 1999 for EPRI programs.
Total research and development expenditures by AEP and its subsidiaries,
including EPRI dues, were approximately $15,000,000 for 2001, $20,000,000 for
2000 and $25,000,000 for 1999.
Item 2. PROPERTIES
- --------------------------------------------------------------------------------
At December 31, 2001, the AEP System owned (or leased where indicated)
generating plants with net power capabilities (east zone subsidiaries-winter
rating; west zone subsidiaries-summer rating) shown in the following table:
Coal Natural Gas Hydro Nuclear Lignite Other Total
Company Stations MW MW MW MW MW MW MW
- -------------------------------------------------------------------------------------------------------------------------
AEGCo 1(a) 1,300 1,300
APCo 17(b) 5,081 777 5,858
CPL 12(c)(d) 686 3,175 6 630 4,497
CSPCo 6(e) 2,595 2,595
I&M 10(a) 2,295 11 2,110 4,416
KEPCo 1 1,060 1,060
OPCo 8(b)(f) 8,464 48 8,512
PSO 8(c) 1,043 3,169 25(g) 4,237
SWEPCo 9 1,848 1,797 842 4,487
WTU 12(c) 377 999 16(g) 1,392
- -------------------------------------------------------------------------------------------------------------------------
Totals: 84 24,749 9,140 842 2,740 842 41 38,354
- -------------------------------------------------------------------------------------------------------------------------
- ----------------------------------
(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) CPL, PSO, and WTU jointly own the Oklaunion power station. Their respective
ownership interests are reflected in this table.
(d) Reflects CPL's interest in STP.
(e) CSPCo owns generating units in common with CG&E and DP&L. Its ownership
interest of 1,330 MW is reflected in this table.
(f) The scrubber facilities at the General James M. Gavin Plant are leased. The
lease terminates in 2010 unless extended.
(g) PSO and WTU have 25 MW and 10 MW respectively of facilities designed
primarily to burn oil. WTU has one 6 MW wind farm facility.
35
AEP-Other Generation: In addition to the generating facilities described
above, AEP has ownership interests in other electrical generating facilities,
both foreign and domestic. Information concerning these facilities at December
31, 2001 is listed below (except for Bajio which went into commercial operation
in March 2002).
CAPACITY OWNERSHIP
FACILITY FUEL LOCATION TOTAL MW INTEREST STATUS
- ---------------------------------------------------------------------------------------------------------------------
Brush II Natural gas Colorado 68 47.75% QF
Eastex Natural gas Texas 440 50% QF
Indian Mesa Wind Texas 161 100% EWG
Mulberry Natural gas Florida 120 46.25% QF
Newgulf Natural gas Texas 85 100% EWG
Orange Cogen Natural gas Florida 103 50% QF
Sweeny Natural gas Texas 480 50% QF
Thermo Cogeneration Natural gas Colorado 272 50% QF
Trent Wind Farm Wind Texas 150 100% EWG
- ---------------------------------------------------------------------------------------------------------------------
Total U.S. 1,879
- ---------------------------------------------------------------------------------------------------------------------
Bajio Natural gas Mexico 605 50% FUCO
Bakun Hydro Philippines 70 10% FUCO
Codrington Wind Australia 18 20% FUCO
Ferrybridge Coal United Kingdom 2,000 100% FUCO
Fiddler's Ferry Coal United Kingdom 2,000 100% FUCO
Medway Natural gas United Kingdom 675 37.5% FUCO
Nanyang Coal China 250 70% FUCO
Ord Hydro Hydro Australia 30 20% FUCO
Southcoast Natural gas United Kingdom 380 50% FUCO
Vale Hydro/Thermal Brazil 665 (a) FUCO
Victoria Hydro Australia 10 20% FUCO
- ---------------------------------------------------------------------------------------------------------------------
Total International 6,703
- ---------------------------------------------------------------------------------------------------------------------
(a) AEP has varying minority interests which aggregate to 168 MW.
See Item 1 under Fuel Supply for information concerning coal reserves owned
or controlled by subsidiaries of AEP and under Wholesale Business Operations for
information concerning AEP's natural gas pipeline, storage and processing
facilities.
The following table sets forth the total overhead circuit miles of
transmission and distribution lines of the AEP System and its operating
companies and that portion of the total representing 765,000-volt lines:
TOTAL OVERHEAD
CIRCUIT MILES OF
TRANSMISSION AND CIRCUIT MILES OF
DISTRIBUTION LINES 765,00-VOLT LINES
------------------ -----------------
AEP System (a).............. 211,300(b) 2,023
APCo..................... 51,295 642
CPL...................... 31,210 ---
CSPCo (a)................ 13,703 ---
I&M...................... 20,672 614
KEPCo.................... 10,443 258
OPCo .................... 29,347 509
PSO...................... 18,713 ---
SWEPCo................... 19,873 ---
WTU...................... 12,605 ---
- ----------------------
(a) Includes 766 miles of 345,000-volt jointly owned lines.
(b) Includes 73 miles of transmission lines not identified with an operating
company.
36
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 fixed physical properties and franchises of the AEP
System operating companies, except for limited conditions and limitations, 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 Arkansas, Indiana, Kentucky, Michigan, Ohio,
Texas, 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 east zone system is interconnected through 121 high-voltage
transmission interconnections with 25 neighboring electric utility systems. The
all-time and 2001 one-hour peak system demands were 25,940,000 and 25,433,000
kilowatts, respectively (which included 7,314,000 and 5,469,000 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 July 24, 2001, respectively. The net dependable
capacity to serve the system load on such date, including power available under
contractual obligations, was 23,457,000 and 23,974,000 kilowatts, respectively.
The all-time and 2001 one-hour internal peak demand was 20,218,000 kilowatts,
and occurred on August 8, 2001. The net dependable capacity to serve the system
load on such date, including power dedicated under contractual arrangements, was
23,935,000 kilowatts. The all-time one-hour integrated and internal net system
peak demands and 2001 peak demands for the east zone generating subsidiaries are
shown in the following tabulation:
ALL-TIME ONE-HOUR INTEGRATED 2001 ONE-HOUR INTEGRATED
NET SYSTEM PEAK DEMAND NET SYSTEM PEAK DEMAND
- ------------------------------ --------------------------
(IN THOUSANDS)
NUMBER OF NUMBER OF
KILOWATTS DATE KILOWATTS DATE
----------- ------ ----------- -------
APCo...... 8,303 January 17, 1997 7,750 January 10, 2001
CSPCo..... 4,833 July 23, 2001 4,833 July 23, 2001
I&M....... 5,403 June 23, 2001 5,403 July 23, 2001
KEPCo..... 1,860 January 10, 2001 1,860 January 10, 2001
OPCo...... 7,291 June 17, 1994 6,668 July 24, 2001
ALL-TIME ONE-HOUR INTEGRATED 2001 ONE-HOUR INTEGRATED
NET INTERNAL PEAK DEMAND NET INTERNAL PEAK DEMAND
- ------------------------------ --------------------------
(IN THOUSANDS)
NUMBER OF NUMBER OF
KILOWATTS DATE KILOWATTS DATE
----------- ------ ----------- -------
APCo ...... 6,908 February 5, 1996 6,402 January 3, 2001
CSPCo...... 3,927 August 8, 2001 3,927 August 8, 2001
I&M........ 4,232 August 8, 2001 4,232 August 8, 2001
KEPCo..... 1,579 January 3, 2001 1,579 January 3, 2001
OPCo....... 5,705 June 11, 1999 5,341 July 24, 2001
The all-time and 2001 one-hour internal peak demand for the west zone
system was 15,048,000 and 14,648,000 kilowatts, respectively, and occurred on
August 31, 2000 and July 23, 2001, respectively. The all-time one-hour internal
net system peak demands and 2001 peak demands for the west zone generating
subsidiaries are shown in the following tabulation:
37
ALL-TIME ONE-HOUR INTEGRATED 2001 ONE-HOUR INTEGRATED
NET INTERNAL PEAK DEMAND NET INTERNAL PEAK DEMAND
- ------------------------------- -------------------------
(IN THOUSANDS)
NUMBER OF NUMBER OF
KILOWATTS DATE KILOWATTS DATE
----------- ----- ----------- -------
CPL ....... 4,623 September 5, 2000 4,323 June 12, 2001
PSO........ 3,823 August 30, 2000 3,785 August 9, 2001
SWEPCo..... 4,625 August 31, 2000 4,344 July 18, 2001
WTU....... 1,537 September 5, 2000 1,472 July 19, 2001
HYDROELECTRIC PLANTS
AEP has 18 hydro facilities, of which 16 are licensed through FERC. The
license for the Elkhart hydroelectric plant in Indiana was issued in January
2001 and extends for a period of thirty years. The license for the Mottville
hydroelectric plant in Michigan expires in 2003 and the application for a new
license was filed with FERC in September 2001.
COOK NUCLEAR PLANT AND STP
The following table provides operating information relating to the Cook
Plant and STP.
COOK PLANT STP(a)
------------------- ------------------
UNIT 1 UNIT 2 UNIT 1 UNIT 2
------ ------ ------ ------
Year Placed in
Operation 1975 1978 1988 1989
Year of
Expiration of
Nrc License (b) 2014 2017 2027 2028
Nominal Net
Electrical
Rating in 1,020,000 1,090,000 1,250,600 1,250,600
Kilowatts
Net Capacity Factors
2001 (c) 87.3% 83.4% 94.4% 87.1%
2000 (d) 1.4% 50.0% 78.2% 96.1%
- ---------------------
(a) Reflects total plant.
(b) For economic or other reasons, operation of the Cook Plant and STP for the
full term of their operating licenses cannot be assured.
(c) The capacity factor for both units of the Cook Plant was significantly
reduced in 2001 due to an unplanned dual maintenance outage in September
2001 to implement design changes that improved the performance of the
essential service water system.
(d) The Cook Plant was shut down in September 1997 to respond to issues raised
regarding the operability of certain safety systems. The restart of both
units of the Cook Plant was completed with Unit 2 reaching 100% power on
July 5, 2000 and Unit 1 achieving 100% power on January 3, 2001.
Costs associated with the operation (excluding fuel), 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 and CPL may also incur costs and
experience reduced output at Cook Plant and STP, respectively, 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 and STP
initiatives have contributed to slowing the growth of operating and maintenance
costs at these plants. However, the ability of I&M and CPL to obtain adequate
and timely recovery of costs associated with the Cook Plant and STP,
respectively, including replacement power, any unamortized investment at the end
of the useful life of the Cook Plant and STP (whether scheduled or premature),
the carrying costs of that investment and retirement costs, is not assured. See
Competition and Business Change.
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 or STP
and costs of replacement power in the event of a nuclear incident at the Cook
Plant or STP. 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, CPL, I&M and
other AEP System companies.
Reference is made to the footnote to the financial statements entitled
Commitments and Contingencies that is incorporated by reference in Item 8 for
information with respect to nuclear incident liability insurance.
38
Item 3. LEGAL PROCEEDINGS
- --------------------------------------------------------------------------------
Federal EPA Notice of Violation to OPCo: On August 31, 2000, Region V,
Federal EPA, issued a Notice of Violation (NOV) to OPCo's Gavin Plant that
alleges violations of the Federal EPA-approved Ohio mass particulate emission
limit, opacity, and air pollution nuisance rules. AEP has submitted information
in response to the allegations and requested a conference to discuss the NOV
with Region V representatives.
Ohio EPA Notices of Violation to OPCo: On August 17, 2001, Ohio EPA issued
proposed findings and orders to OPCo's Gavin Plant based on the alleged failure
of a mass particulate emissions test on May 17, 2000. OPCo requested a
conference to discuss the proposed findings and orders and submitted the results
of its investigation of the test procedures, which confirmed that the May 17
test was invalid due to the corrosion and disintegration of the test probe.
On December 27, 2001, Ohio EPA issued two NOVs to OPCo's Gavin Plant,
alleging that OPCo failed to notify Ohio EPA of a malfunction of the flyash
handling system at the plant, and that OPCo failed to conduct a required mass
particulate emissions test. OPCo has submitted additional control plans for the
flyash handling system and information regarding the particulate testing
completed at the Gavin Plant in response to the NOVs.
COLI Litigation: On February 20, 2001, the U.S. District Court for the
Southern District of Ohio ruled against AEP in its suit against the United
States over deductibility of interest claimed by AEP in its consolidated federal
income tax return related to its COLI program. AEP had filed suit to resolve the
IRS' assertion that interest deductions for AEP's COLI program should not be
allowed. In 1998 and 1999 AEP paid the disputed taxes and interest attributable
to COLI interest deductions for taxable years 1991-98 to avoid the potential
assessment by the IRS of additional interest on the contested tax. The payments
were included in other assets pending the resolution of this matter. As a result
of the U.S. District Court's decision to deny the COLI interest deductions, net
income was reduced in 2000 as follows:
(IN MILLIONS)
AEP System operating companies...... $ 319
APCo............................. 82
CSPCo............................ 41
I&M.............................. 66
KEPCo............................ 8
OPCo............................. 118
The Company has filed an appeal of the U.S. District Court's decision with
the U.S. Court of Appeals for the Sixth Circuit.
----------------------
See Item 1 for a discussion of certain environmental matters.
----------------------
Reference is made to the footnote to the financial statements entitled
Commitments and Contingencies incorporated by reference in Item 8 for further
information with respect to other legal proceedings.
39
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- --------------------------------------------------------------------------------
AEP, APCO, CPL, I&M, OPCO AND SWEPCO. None.
AEGCO, CSPCO, KEPCO, PSO AND WTU. 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, 2002.
NAME AGE OFFICE (a)
- ---- --- ---------
E. Linn Draper, Jr............. 60 Chairman of the Board, President and Chief Executive Officer of AEP and of the
Service Corporation
Thomas V. Shockley, III........ 56 Vice Chairman and Chief Operating Officer of the Service Corporation
Henry W. Fayne................. 55 Executive Vice President of the Service Corporation
Robert P. Powers............... 48 Executive Vice President-Nuclear Generation and Technical Services of the Service
Corporation
Susan Tomasky.................. 48 Executive Vice President-Policy, Finance and Strategic Planning of the Service
Corporation
J. H. Vipperman................ 61 Executive Vice President-Shared Services of the Service Corporation
- -------------------------
(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 Messrs.
Powers and Shockley and Ms. Tomasky. Prior to joining the Service
Corporation in July 1998 as Senior Vice President-Generation, Mr. Powers
was Vice President of Pacific Gas & Electric and plant manager of its
Diablo Canyon Nuclear Generating Station (1996-1998). 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). Mr. Powers and Ms. Tomasky became executive officers of
AEP effective with their promotions to Executive Vice President on October
24, 2001 and January 26, 2000, respectively. Prior to joining the Service
Corporation in his current position upon the merger with CSW, Mr. Shockley
was President and Chief Operating Officer of CSW (1997-2000) and Executive
Vice President of CSW (1990-1997). 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.
APCO, CPL, I&M, OPCO AND SWEPCO. The names of the executive officers of
APCo, CPL, I&M, OPCo and SWEPCo, the positions they hold with these companies,
their ages as of March 1, 2002, and a brief account of their business experience
during the past five years appear below. The directors and executive officers of
APCo, CPL, I&M, OPCo and SWEPCo are elected annually to serve a one-year term.
NAME AGE POSITION (a)(b) PERIOD
- ---- --- --------------- ------
E. Linn Draper, Jr............ 60 Director of CPL and SWEPCo 2000-Present
Chairman of the Board and Chief Executive Officer of CPL and
SWEPCo 2000-Present
Director of APCo, I&M and OPCo 1992-Present
Chairman of the Board and Chief Executive Officer of APCo, I&M
and OPCo 1993-Present
Chairman of the Board, President and Chief Executive Officer of
AEP and the Service Corporation 1993-Present
40
NAME AGE POSITION (a)(b) PERIOD
- ---- --- --------------- ------
Thomas V. Shockley, III....... 56 Director and Vice President of APCo, CPL, I&M, OPCo and SWEPCo 2000-Present
Chief Operating Officer of the Service Corporation 2001-Present
Vice Chairman of AEP and the Service Corporation 2000-Present
President and Chief Operating Officer of CSW 1997-2000
Executive Vice President of CSW 1990-1997
Henry W. Fayne................ 55 President of APCo, CPL, I&M, OPCo and SWEPCo 2001-Present
Director of CPL and SWEPCO 2000-Present
Director of APCo 1995-Present
Director of OPCo 1993-Present
Director of I&M 1998-Present
Vice President of CPL and SWEPCo 2000-2001
Vice President of APCo, I&M and OPCo 1998-2001
Vice President of AEP 1998-Present
Chief Financial Officer of AEP 1998-2001
Executive Vice President of the Service Corporation 2001-Present
Executive Vice President-Finance and Analysis of the Service
Corporation 2000-2001
Executive Vice President-Financial Services of the Service
Corporation 1998-2000
Senior Vice President-Corporate Planning & Budgeting of the
Service Corporation 1995-1998
Robert P. Powers.............. 48 Director and Vice President of APCo, CPL, OPCo and SWEPCo 2001-Present
Director of I&M 2001-Present
Vice President of I&M 1998-Present
Executive Vice President-Nuclear Generation and Technical
Services of the Service Corporation 2001-Present
Senior Vice President-Nuclear Operations of the Service
Corporation 2000-2001
Senior Vice President-Nuclear Generation of the Service
Corporation 1998-2000
Vice President of Pacific Gas & Electric and Plant Manager of
its Diablo Canyon Nuclear Generating Station 1996-1998
Susan Tomasky................. 48 Director and Vice President of APCo, CPL, I&M, OPCo and SWEPCo 2000-Present
Executive Vice President-Policy, Finance and Strategic Planning
of the Service Corporation 2001-Present
Executive Vice President-Legal, Policy and Corporate
Communications and General Counsel of the Service Corporation 2000-2001
Senior Vice President and General Counsel of the Service
Corporation 1998-2000
Hogan & Hartson (law firm) 1997-1998
General Counsel of the FERC 1993-1997
41
NAME AGE POSITION (a)(b) PERIOD
- ---- --- --------------- ------
J. H. Vipperman............... 61 Director and Vice President of CPL and SWEPCo 2000-Present
Director of APCo 1985-Present
Director of I&M and OPCo 1996-Present
Vice President of APCo, I&M and OPCo 1996-Present
Executive Vice President-Shared Services of the Service
Corporation 2000-Present
Executive Vice President-Corporate Services of the
Service Corporation 1998-2000
Executive Vice President-Energy Delivery of the
Service Corporation 1996-1997
- -----------------
(a) Dr. Draper is a director of BCP Management, Inc., which is the general
partner of Borden Chemicals and Plastics L.P.
(b) Dr. Draper, Messrs. Fayne, Powers, Shockley and Vipperman and Ms. Tomasky
are directors of AEGCo, CSPCo, KEPCo, PSO and WTU. Dr. Draper and Mr.
Shockley are also directors of AEP.
PART II ------------------------------------------------------------------------
Item 5. MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
- --------------------------------------------------------------------------------
AEP. The information required by this item is incorporated herein by
reference to the material under Common Stock and Dividend Information in the
2001 Annual Report.
AEGCO, APCO, CPL, CSPCO, I&M, KEPCO, OPCO, PSO, SWEPCO AND WTU. The common
stock of these companies is held solely by AEP. The amounts of cash dividends on
common stock paid by these companies to AEP during 2001 and 2000 are
incorporated by reference to the material under Statement of Retained Earnings
in the 2001 Annual Reports.
Item 6. SELECTED FINANCIAL DATA
- --------------------------------------------------------------------------------
AEGCO, CSPCO, KEPCO, PSO AND WTU. Omitted pursuant to Instruction I(2)(a).
AEP, APCO, CPL, I&M, OPCO AND SWEPCO. The information required by this item
is incorporated herein by reference to the material under Selected Consolidated
Financial Data in the 2001 Annual Reports.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
- --------------------------------------------------------------------------------
AEGCO, CSPCO, KEPCO, PSO AND WTU. 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 2001 Annual Reports.
AEP, APCO, CPL, I&M, OPCO AND SWEPCO. 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 Management's Discussion and
Analysis of Financial Condition, Contingencies and Other Matters in the 2001
Annual Reports.
42
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
- --------------------------------------------------------------------------------
AEGCO, AEP, APCO, CPL, CSPCO, I&M, KEPCO, OPCO, PSO, SWEPCO AND WTU. The
information required by this item is incorporated herein by reference to the
material under Management's Discussion and Analysis of Financial Condition,
Contingencies and Other Matters in the 2001 Annual Reports.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- --------------------------------------------------------------------------------
AEGCO, AEP, APCO, CPL, CSPCO, I&M, KEPCO, OPCO, PSO, SWEPCO AND WTU. 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.
CPL, PSO, SWEPCO AND WTU. The information required by this item is
incorporated herein by reference to each company's Current Report on Form 8-K
dated July 5, 2000.
PART III -----------------------------------------------------------------------
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
- --------------------------------------------------------------------------------
AEGCo, CSPCo, KEPCo, PSO and WTU. 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 and Section 16(a)
Beneficial Ownership Reporting Compliance of the definitive proxy statement of
AEP for the 2002 annual meeting of shareholders, to be filed within 120 days
after December 31, 2001. Reference also is made to the information under the
caption Executive Officers of the Registrants in Part I of this report.
APCO AND OPCO. The information required by this item is incorporated herein
by reference to the material under Election of Directors of the definitive
information statement of each company for the 2002 annual meeting of
stockholders, to be filed within 120 days after December 31, 2001. Reference
also is made to the information under the caption Executive Officers of the
Registrants in Part I of this report.
CPL AND SWEPCO. 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 2002 annual meeting of
stockholders, to be filed within 120 days after December 31, 2001. Reference
also is made to the information under the caption Executive Officers of the
Registrants in Part I of this report.
I&M. The names of the directors and executive officers of I&M, the
positions they hold
43
with I&M, their ages as of March 12, 2002, and a brief account of their business
experience during the past five years appear below and under the caption
Executive Officers of the Registrants in Part I of this report.
NAME AGE POSITION (a) PERIOD
- ---- --- ------------ ------
K. G. Boyd..................... 50 Director 1997-Present
Vice President - Fort Wayne Region Distribution Operations 2000-Present
Indiana Region Manager 1997-2000
Fort Wayne District Manager 1994-1997
John E. Ehler.................. 45 Director 2001-Present
Manager of Distribution Systems-Fort Wayne District 2000-Present
Region Operations Manager 1997-2000
David L. Lahrman............... 50 Director and Manager, Region Support 2001-Present
Fort Wayne District Manager 1997-2001
Region Operations Manager 1994-1997
Marc E. Lewis.................. 47 Director 2001-Present
Assistant General Counsel of the Service Corporation 2001-Present
Senior Counsel of the Service Corporation 2000-2001
Senior Attorney of the Service Corporation 1994-2000
Susanne M. Moorman............ 52 Director and General Manager, Community Services 2000-Present
Manager, Customer Services Operations 1997-2000
Director, Customer Services 1994-1997
John R. Sampson................ 49 Director and Vice President 1999-Present
Indiana State President 2000-Present
Indiana & Michigan State President 1999-2000
Site Vice President, Cook Nuclear Plant 1998-1999
Plant Manager, Cook Nuclear Plant 1996-1998
D. B. Synowiec................. 58 Director 1995-Present
Plant Manager, Rockport Plant 1990-Present
- -----------------
(a) Positions are with I&M unless otherwise indicated.
Item 11. EXECUTIVE COMPENSATION
- --------------------------------------------------------------------------------
AEGCO, CSPCO, KEPCO, PSO AND WTU. 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 2002 annual meeting of shareholders to be filed
within 120 days after December 31, 2001.
APCO AND OPCO. The information required by this item is incorporated herein
by reference to the material under Executive Compensation of the definitive
information statement of each company for the 2002 annual meeting of
stockholders, to be filed within 120 days after December 31, 2001.
CPL, I&M AND SWEPCO. The information required by this item is incorporated
herein by reference to the material under Executive Compensation of the
definitive information
44
statement of APCo for the 2002 annual meeting of stockholders, to be filed
within 120 days after December 31, 2001.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
- --------------------------------------------------------------------------------
AEGCO, CSPCO, KEPCO, PSO AND WTU. 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 for the 2002 annual meeting of
shareholders to be filed within 120 days after December 31, 2001.
APCO AND 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 each company for the 2002
annual meeting of stockholders, to be filed within 120 days after December 31,
2001.
CPL AND SWEPCO. 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 2002
annual meeting of stockholders, to be filed within 120 days after December 31,
2001.
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, 2002, 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.
STOCK
-----
NAME SHARES (a) UNITS (b) TOTAL
- ---- --------- -------- -----
Karl G. Boyd........................................................... 6,964 88 7,052
E. Linn Draper, Jr..................................................... 238,274(c) 119,218 357,492
John E. Ehler.......................................................... 7 -- 7
Henry W. Fayne......................................................... 72,685(d) 13,735 86,420
David L. Lahrman....................................................... 360 -- 360
Marc E. Lewis.......................................................... 1,117 -- 1,117
Susanne M. Moorman..................................................... 841 -- 841
Robert P. Powers....................................................... 21,269 1,209 22,478
John R. Sampson........................................................ 5,525 109 5,634
Thomas V. Shockley, III................................................ 138,822(d)(e) -- 138,822
David B. Synowiec...................................................... 2,361 129 2,490
Susan Tomasky.......................................................... 67,322 4,329 71,651
Joseph H. Vipperman.................................................... 78,043(c)(d) 7,201 85,244
All Directors and Executive Officers................................... 633,590(d)(f) 146,018 779,608
45
- -------------------------
(a) Includes share equivalents held in the AEP Retirement Savings Plan (and
for Mr. Shockley, the CSW Retirement Savings Plan) in the amounts listed
below:
AEP RETIREMENT SAVINGS AEP RETIREMENT SAVINGS
NAME PLAN (SHARE EQUIVALENTS) NAME PLAN (SHARE EQUIVALENTS)
---- ------------------------ ---- ------------------------
Mr. Boyd............................. 1,964 Mr. Powers................................. 436
Dr. Draper........................... 4,280 Mr. Sampson................................ 525
Mr. Ehler............................ 7 Mr. Shockley............................... 6,579
Mr. Fayne............................ 5,412 Mr. Synowiec............................... 695
Mr. Lahrman.......................... 360 Ms. Tomasky................................ 656
Mr. Lewis............................ 1,117 Mr. Vipperman.............................. 10,498
Ms. Moorman.........................` 841 All Directors and Executive Officers............ 33,370
With respect to the share equivalents held in the AEP Retirement
Savings Plan, such persons have sole voting power, but the
investment/disposition power is subject to the terms of the Plan.
Also, includes the following numbers of shares attributable to options
exercisable within 60 days: Mr. Boyd, 5,000; Dr. Draper, 233,333; Mr.
Powers, 20,833; Mr. Sampson, 5,000; Mr. Shockley, 94,450; Mr.
Synowiec, 1,666; and Messrs. Fayne and Vipperman and Ms. Tomasky,
66,666.
(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, 661; and Mr. Vipperman, 80.
(d) Does not include, for Messrs. Fayne, Shockley and Vipperman, 85,231 shares
in the American Electric Power System Educational Trust Fund over which
Messrs. Fayne, Shockley 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
(e) Includes the following numbers of shares held by family members over which
beneficial ownership is disclaimed: Mr. Shockley, 496.
(f) Represents less than 1% of the total number of shares outstanding
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
- --------------------------------------------------------------------------------
AEP, APCO, CPL, I&M, OPCO AND SWEPCO. None.
AEGCO, CSPCO, KEPCO, PSO AND WTU. 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.
PAGE
----
AEGCo:
Independent Auditors' Report; Statements of Income for the years ended
December 31, 2001, 2000, and 1999; Statements of Retained Earnings for
the years ended December 31, 2001, 2000 and 1999; Statements of Cash
Flows for the years ended December 31, 2001, 2000, and 1999; Balance
Sheets as of December 31, 2001 and 2000; Statements of Capitalization
as of December 31, 2001 and 2000; Combined Notes to Financial
Statements.
AEP and its subsidiaries consolidated:
Consolidated Statements of Income for the years ended December 31,
2001, 2000, and 1999; Consolidated Balance Sheets as of December 31,
2001 and 2000; Consolidated
46
PAGE
----
Statements of Cash Flows for the years ended December 31, 2001, 2000,
and 1999; Consolidated Statements of Common Shareholders' Equity and
Comprehensive Income for the years ended December 31, 2001, 2000, and
1999; Combined Notes to Financial Statements; Schedule of Consolidated
Cumulative Preferred Stocks of Subsidiaries at December 31, 2001 and
2000; Schedule of Consolidated Long-term Debt of Subsidiaries at
December 31, 2001 and 2000; Independent Auditors' Reports.
APCo, I&M, and OPCo:
Independent Auditors' Report; Consolidated Statements of Income for
the years ended December 31, 2001, 2000, and 1999; Consolidated
Statements of Comprehensive Income for the years ended December 31,
2001, 2000 and 1999; Consolidated Balance Sheets as of December 31,
2001 and 2000; Consolidated Statements of Cash Flows for the years
ended December 31, 2001, 2000, and 1999; Consolidated Statements of
Retained Earnings for the years ended December 31, 2001, 2000, and
1999; Consolidated Statements of Capitalization as of December 31,
2001 and 2000; Schedule of Consolidated Long-term Debt as of December
31, 2001 and 2000; Combined Notes to Financial Statements.
CPL, CSPCo, PSO, and SWEPCo:
Independent Auditors' Report(s); Consolidated Statements of Income for
the years ended December 31, 2001, 2000, and 1999; Consolidated
Balance Sheets as of December 31, 2001 and 2000; Consolidated
Statements of Cash Flows for the years ended December 31, 2001, 2000,
and 1999; Consolidated Statements of Retained Earnings for the years
ended December 31, 2001, 2000, and 1999; Consolidated Statements of
Capitalization as of December 31, 2001 and 2000; Schedule of
Consolidated Long-term Debt as of December 31, 2001 and 2000; Combined
Notes to Financial Statements.
KEPCo:
Independent Auditors' Report; Statements of Income for the years ended
December 31, 2001, 2000, and 1999; Statements of Retained Earnings for
the years ended December 31, 2001, 2000, and 1999; Statements of Cash
Flows for the years ended December 31, 2001, 2000, and 1999;
Statements of Comprehensive Income for the years ended December 31,
2001, 2000 and 1999; Balance Sheets as of December 31, 2001 and 2000;
Statements of Capitalization as of December 31, 2001 and 2000;
Schedule of Long-term Debt as of December 31, 2001 and 2000; Combined
Notes to Financial Statements.
WTU:
Independent Auditors' Reports; Statements of Income for the years
ended December 31, 2001, 2000, and 1999; Statements of Retained
Earnings for the years ended December 31, 2001, 2000, and 1999;
Statements of Cash Flows for the years ended December 31, 2001, 2000,
and 1999; Balance Sheets as of December 31, 2001 and 2000; Statements
of Capitalization as of December 31, 2001 and 2000; Schedule of
Long-term Debt as of December 31, 2001 and 2000; Combined Notes to
Financial Statements.
47
PAGE
----
2. FINANCIAL STATEMENT SCHEDULES:
Page
----
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, CPL, CSPCo, I&M, KEPCo, OPCo, PSO, SWEPCo
and WTU are listed in the Exhibit Index and are incorporated herein by
reference E-1
(b) No Reports on Form 8-K were filed during the quarter ended December 31,
2001.
48
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/ SUSAN TOMASKY
-------------------------------------------
(SUSAN TOMASKY, VICE PRESIDENT,
SECRETARY AND CHIEF FINANCIAL OFFICER)
Date: March 18, 2002
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.
SIGNATURE TITLE DATE
--------- ----- -----
(i) PRINCIPAL EXECUTIVE OFFICER:
*E. LINN DRAPER, JR. Chairman of the Board,
President,
Chief Executive Officer
And Director
(ii) PRINCIPAL FINANCIAL OFFICER:
/s/ SUSAN TOMASKY Vice President, Secretary and March 18, 2002
- -------------------------------------------- Chief Financial Officer
(SUSAN TOMASKY)
(iii) PRINCIPAL ACCOUNTING OFFICER:
/s/ JOSEPH M. BUONAIUTO Controller and March 18, 2002
- ------------------------------------------- Chief Accounting Officer
(JOSEPH M. BUONAIUTO)
(iv) A MAJORITY OF THE DIRECTORS:
*E. R. BROOKS
*DONALD M. CARLTON
*JOHN P. DESBARRES
*ROBERT W. FRI
*WILLIAM R. HOWELL
*LESTER A. HUDSON, JR.
*LEONARD J. KUJAWA
*JAMES L. POWELL
*RICHARD L. SANDOR
*THOMAS V. SHOCKLEY, III
*DONALD G. SMITH
*LINDA GILLESPIE STUNTZ
*KATHRYN D. SULLIVAN
March 18, 2002
*By: /s/ SUSAN TOMASKY
---------------------------------
(SUSAN TOMASKY, ATTORNEY-IN-FACT)
49
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
APPALACHIAN POWER COMPANY
CENTRAL POWER AND LIGHT COMPANY
COLUMBUS SOUTHERN POWER COMPANY
KENTUCKY POWER COMPANY
OHIO POWER COMPANY
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY
WEST TEXAS UTILITIES COMPANY
BY: /s/ SUSAN TOMASKY
---------------------------------
(SUSAN TOMASKY, VICE PRESIDENT)
Date: March 18, 2002
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.
SIGNATURE TITLE DATE
--------- ----- -----
(i) PRINCIPAL EXECUTIVE OFFICER:
*E. LINN DRAPER, JR. Chairman of the Board,
Chief Executive Officer
And Director
(ii) PRINCIPAL FINANCIAL OFFICER:
/s/ SUSAN TOMASKY Vice President March 18, 2002
------------------------------------------- And Director
(SUSAN TOMASKY)
(iii) PRINCIPAL ACCOUNTING OFFICER:
/s/ JOSEPH M. BUONAIUTO Controller and March 18, 2002
------------------------------------------- Chief Accounting Officer
(JOSEPH M. BUONAIUTO)
(iv) A MAJORITY OF THE DIRECTORS:
*HENRY W. FAYNE
*A. A. PENA
*ROBERT P. POWERS
*THOMAS V. SHOCKLEY, III
*J. H. VIPPERMAN
March 18, 2002
*By: /s/ SUSAN TOMASKY
-------------------------------------------
(SUSAN TOMASKY, ATTORNEY-IN-FACT)
50
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/ SUSAN TOMASKY
----------------------------------------
(SUSAN TOMASKY, VICE PRESIDENT)
Date: March 18, 2002
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.
SIGNATURE TITLE DATE
--------- ----- -----
(i) PRINCIPAL EXECUTIVE OFFICER:
*E. LINN DRAPER, JR. Chairman of the Board,
Chief Executive Officer
And Director
(ii) PRINCIPAL FINANCIAL OFFICER:
/s/ SUSAN TOMASKY Vice President March 18, 2002
------------------------------------------------ And Director
(SUSAN TOMASKY)
(iii) PRINCIPAL ACCOUNTING OFFICER:
/s/ JOSEPH M. BUONAIUTO Controller and March 18, 2002
------------------------------------------------ Chief Accounting Officer
(JOSEPH M. BUONAIUTO)
(iv) A MAJORITY OF THE DIRECTORS
:
*K. G. BOYD
*JOHN E. EHLER
*HENRY W. FAYNE
*DAVID L. LAHRMAN
*MARC E. LEWIS
*SUSANNE M. MOORMAN
*ROBERT P. POWERS
*JOHN R. SAMPSON
*THOMAS V. SHOCKLEY, III
*D. B. SYNOWIEC
*J. H. VIPPERMAN
*By: /s/ SUSAN TOMASKY
--------------------------------------------------
(SUSAN TOMASKY, ATTORNEY-IN-FACT) March 18, 2002
51
INDEX TO FINANCIAL STATEMENT SCHEDULES
Page
INDEPENDENT AUDITORS' REPORT ............................................................................... S-2
The following financial statement schedules 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
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY
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-4
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-5
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Schedule II-- Valuation and Qualifying Accounts and Reserves....................................... S-5
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Schedule II-- Valuation and Qualifying Accounts and Reserves....................................... S-5
WEST TEXAS UTILITIES COMPANY
Schedule II-- Valuation and Qualifying Accounts and Reserves....................................... S-6
S-1
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, 2001 and 2000,
and for each of the three years in the period ended December 31, 2001, and have
issued our reports thereon dated February 22, 2002; such financial statements
and reports are included in the 2001 Annual Reports 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, except for the financial statement schedules of
Central Power and Light Company and subsidiary, Public Service Company of
Oklahoma and its subsidiaries, Southwestern Electric Power Company and
subsidiaries, and West Texas Utilities Company for the year ended December 31,
1999 and the financial information of Central and South West Corporation and its
subsidiaries that is included in the financial statement schedule for American
Electric Power Company, Inc. and its subsidiaries for the year ended December
31, 1999. 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, 2002
S-2
===========================================================================================================================
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)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2001....... $71,722 $124,542 $19,766(a) $106,589(b) $109,441
======= ======== ======= ======== ========
Year Ended December 31, 2000....... $63,207 $ 70,670 $ 8,358(a) $ 70,513(b) $ 71,722
======= ======== ======= ======== ========
Year Ended December 31, 1999....... $52,543 $ 38,347 $15,802(a) $ 43,485(b) $ 63,207
======= ======== ======= ======== ========
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
===========================================================================================================================
===========================================================================================================================
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)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2001....... $2,588 $2,644 $1,017(a) $4,372(b) $1,877
====== ====== ====== ====== ======
Year Ended December 31, 2000....... $2,609 $6,592 $1,526(a) $8,139(b) $2,588
====== ====== ====== ====== ======
Year Ended December 31, 1999....... $2,234 $5,492 $1,995(a) $7,112(b) $2,609
====== ====== ====== ====== ======
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
===========================================================================================================================
===========================================================================================================================
CENTRAL POWER AND LIGHT AND SUBSIDIARY
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)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2001....... $1,675 $ 186 $ --_ (a) $1,675(b) $ 186
====== ====== ====== ====== ======
Year Ended December 31, 2000....... $-- $1,675 $ -- (a) $ -- (b) $1,675
====== ====== ====== ====== ======
Year Ended December 31, 1999....... $-- $-- $ -- (a) $ -- (b) $--
====== ====== ====== ====== ======
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
===========================================================================================================================
S-3
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)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2001....... $ 659 $ 331 $ --(a) $ 245(b) $ 745
====== ====== ======= ======= =======
Year Ended December 31, 2000....... $3,045 $2,082 $ 1,405(a) $ 5,873(b) $ 659
====== ====== ======= ======= =======
Year Ended December 31, 1999....... $2,598 $3,334 $10,782(a) $13,669(b) $ 3,045
====== ====== ======= ======= =======
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
===========================================================================================================================
===========================================================================================================================
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)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2001....... $ 759 $ 65 $ 3(a) $ 86(b) $ 741
====== ====== ====== ====== ======
Year Ended December 31, 2000....... $1,848 $ (235) $ 907(a) $1,761(b) $ 759
====== ====== ====== ====== ======
Year Ended December 31, 1999....... $2,027 $3,966 $1,367(a) $5,512(b) $1,848
====== ====== ====== ====== ======
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
===========================================================================================================================
===========================================================================================================================
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)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2001....... $282 $ -- $(24)(a) $ (6)(b) $264
==== ====== ===== ======= ====
Year Ended December 31, 2000....... $637 $ 187 $ 9 (a) $ 551(b) $282
==== ====== ===== ====== ====
Year Ended December 31, 1999....... $848 $1,032 $ 467(a) $1,710(b) $637
==== ====== ===== ====== ====
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
===========================================================================================================================
S-4
===========================================================================================================================
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)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2001....... $1,054 $ 554 $ -- (a) $ 229(b) $1,379
====== ====== ====== ====== ======
Year Ended December 31, 2000....... $2,223 $ 472 $ 778(a) $2,419(b) $1,054
====== ====== ====== ====== ======
Year Ended December 31, 1999....... $1,678 $4,730 $1,273(a) $5,458(b) $2,223
====== ====== ====== ====== ======
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
===========================================================================================================================
===========================================================================================================================
PUBLIC SERVICE COMPANY OF OKLAHOMA 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)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2001....... $ 467 $ 44 $ -- (a) $ 467(b) $ 44
====== ======= ====== ======= ======
Year Ended December 31, 2000....... $-- $ 467 $ -- (a) $ -- (b) $ 467
====== ======= ====== ======= ======
Year Ended December 31, 1999....... $-- $ -- $ -- (a) $ -- (b) $ --
====== ======= ====== ======= ======
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
===========================================================================================================================
===========================================================================================================================
SOUTHWESTERN ELECTRIC 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)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2001....... $ 911 $ 89 $ -- (a) $ 911(b) $ 89
====== ====== ======= ====== ======
Year Ended December 31, 2000....... $4,428 $ 911 $(4,428)(a) $ -- (b) $ 911
====== ====== ======= ====== ======
Year Ended December 31, 1999....... $3,269 $5,415 $ -- (a) $4,256(b) $4,428
====== ====== ======= ====== ======
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
===========================================================================================================================
S-5
===========================================================================================================================
WEST TEXAS UTILITIES 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)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2001....... $288 $ 13 $35(a) $ 140(b) $196
==== ====== === ====== ====
Year Ended December 31, 2000....... $186 $1,499 $46(a) $1,443(b) $288
==== ====== === ====== ====
Year Ended December 31, 1999....... $497 $ (66) $43(a) $ 288(b) $186
==== ===== === ====== ====
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
===========================================================================================================================
S-6
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.
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
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 (amended as of June 15, 2000) [Annual
Report on Form 10-K of AEGCo for the fiscal year ended December 31, 2000,
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 2001 Annual Report (for the fiscal year ended December 31,
2001) which are incorporated by reference in this filing.
*24 -- Power of Attorney.
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)].
*4(a) -- Indenture (for unsecured debt securities), dated as of May 1, 2001, between AEP and The Bank
of New York, as Trustee.
E-1
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
*4(b) -- First Supplemental Indenture, dated as of May 1, 2001, between AEP and The Bank of New York,
as Trustee, for 6.125% Senior Notes, Series A, due May 15, 2006.
*4(c) -- Second Supplemental Indenture, dated as of May 1, 2001, between AEP and The Bank of New York, as
Trustee, for 5.50% Putable Callable Notes, Series B, Putable Callable May 15, 2003.
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)].
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)].
E-2
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
+10(i)(1) -- AEP Deferred Compensation and Stock Plan for Non-Employee Directors, as amended June 1, 2000
[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525,
Exhibit 10(i)(1)].
*+10(i)(2) -- AEP Stock Unit Accumulation Plan for Non-Employee Directors, as amended January 1, 2002.
+10(j)(1)(A) -- AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2001 [Annual Report on
Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525,
Exhibit 10(j)(1)(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)].
+10(j)(2) -- AEP System Supplemental Retirement Savings Plan, Amended and Restated as of June 1, 2001
(Non-Qualified) [Registration Statement No. 333-66048, Exhibit 4].
+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) -- 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(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) -- 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(o) -- AEP Change In Control Agreement.
+10(p) -- AEP System 2000 Long-Term Incentive Plan [Proxy Statement of AEP, March 10, 2000].
+10(q) -- Memorandum of agreement between Susan Tomasky and the Service Corporation dated January 3,
2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000,
File No. 1-3525, Exhibit 10(s)].
+10(r)(1) -- Central and South West System Special Executive Retirement Plan as amended and restated effective
July 1, 1997 [Annual Report on Form 10-K of CSW for the fiscal year ended December 31, 1998,
File No. 1-1443, Exhibit 18].
*+10(r)(2) -- Certified CSW Board Resolution of April 18, 1991.
+10(r)(3) -- CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW, March 13, 1992].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the AEP 2001 Annual Report (for the fiscal year ended December 31,
2001) which are incorporated by reference in this filing.
*21 -- List of subsidiaries of AEP.
*23(a) -- Consent of Deloitte & Touche LLP.
*23(b) -- Consent of Arthur Andersen LLP.
*23(c) -- Consent of KPMG Audit plc.
*24 -- Power of Attorney.
E-3
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
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 October 24, 2001).
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, File No. 1-3457,
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, Exhibit 4(a);
Registration Statement No. 333-49071, Exhibit 4(b); Registration Statement No. 333-84061,
Exhibits 4(b) and 4(c); Annual Report on Form 10-K of APCo for the fiscal year ended December
31, 1999, File No. 1-3457, Exhibit 4(c); Registration Statement No. 333-81402, Exhibits 4(b),
4(c) and 4(d)].
E-4
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
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)].
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) -- 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)].
E-5
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
+10(h)(1) -- AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2001 [Annual Report on Form
10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(j)(1)(A)].
+10(h)(2) -- AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2001
(Non-Qualified) [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000,
File No. 1-3525, Exhibit 10(j)(2)].
+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, 2001, File No. 1-3525, Exhibit 10(o)].
+10(m) -- AEP System 2000 Long-Term Incentive Plan [Proxy Statement of AEP, March 10, 2000].
+10(n) -- Memorandum of agreement between Susan Tomasky and the Service Corporation dated January 3,
2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000,
File No. 1-3525, Exhibit 10(s)].
+10(o)(1) -- Central and South West System Special Executive Retirement Plan as amended and restated effective
July 1, 1997 [Annual Report on Form 10-K of CSW for the fiscal year ended December 31, 1998,
File No. 1-1443, Exhibit 18].
+10(o)(2) -- Certified CSW Board Resolution of April 18, 1991 [Annual Report on Form 10-K of AEP for the fiscal
year ended December 31, 2001, File No. 1-3525, Exhibit 10(r)(2)].
+10(o)(3) -- CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW, March 13, 1992].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the APCo 2001 Annual Report (for the fiscal year ended December 31,
2001) which are incorporated by reference in this filing.
21 -- List of subsidiaries of APCo [Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 2001, File No. 1-3525, Exhibit 21].
*24 -- Power of Attorney.
CPL++
3(a) -- Restated Articles of Incorporation Without Amendment, Articles of Correction to Restated
Articles of Incorporation Without Amendment, Articles of Amendment to Restated Articles of
Incorporation, Statements of Registered Office and/or Agent, and Articles of Amendment to the
Articles of Incorporation [Quarterly Report on Form 10-Q of CPL for the quarter ended March
31, 1997, File No. 0-346, Exhibit 3.1].
3(b) -- By-Laws of CPL (amended as of April 19, 2000) [Annual Report on Form 10-K of CPL for the fiscal
year ended December 31, 2000, File No. 0-346, Exhibit 3(b)].
E-6
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
4(a) -- Indenture of Mortgage or Deed of Trust, dated November 1, 1943, between CPL and The First
National Bank of Chicago and R. D. Manella, as Trustees, as amended and supplemented
[Registration Statement No. 2-60712, Exhibit 5.01; Registration Statement No. 2-62271,
Exhibit 2.02; Form U-1 No. 70-7003, Exhibit 17; Registration Statement No. 2-98944, Exhibit 4
(b); Form U-1 No. 70-7236, Exhibit 4; Form U-1 No. 70-7249, Exhibit 4; Form U-1 No. 70-7520,
Exhibit 2; Form U-1 No. 70-7721, Exhibit 3; Form U-1 No. 70-7725, Exhibit 10; Form U-1 No.
70-8053, Exhibit 10 (a); Form U-1 No. 70-8053, Exhibit 10 (b); Form U-1 No. 70-8053, Exhibit
10 (c); Form U-1 No. 70-8053, Exhibit 10 (d); Form U-1 No. 70-8053, Exhibit 10 (e); Form U-1
No. 70-8053, Exhibit 10 (f)].
4(b) -- CPL-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely
Junior Subordinated Debentures of CPL:
(1) Indenture, dated as of May 1, 1997, between CPL and the Bank of New York, as Trustee
[Quarterly Report on Form 10-Q of CPL dated March 31, 1997, File No. 0-346, Exhibits 4.1 and
4.2].
(2) Amended and Restated Trust Agreement of CPL Capital I, dated as of May 1, 1997, among CPL,
as Depositor, the Bank of New York, as Property Trustee, The Bank of New York (Delaware), as
Delaware Trustee, and the Administrative Trustee [Quarterly Report on Form 10-Q of CPL dated
March 31, 1997, File No. 0-346, Exhibit 4.3].
(3) Guarantee Agreement, dated as of May 1, 1997, delivered by CPL for the benefit of the holders
of CPL Capital I's Preferred Securities [Quarterly Report on Form 10-Q of CPL dated
March 31, 1997, File No. 0-346, Exhibit 4.4].
(4) Agreement as to Expenses and Liabilities dated as of May 1, 1997, between CPL and CPL Capital I
[Quarterly Report on Form 10-Q of CPL dated March 31, 1997, File No. 0-346, Exhibit 4.5].
4(c) -- Indenture (for unsecured debt securities), dated as of November 15, 1999, between CPL and The Bank of
New York, as Trustee, as amended and supplemented [Annual Report on Form 10-K of CPL for the fiscal
year ended December 31, 2000, File No. 0-346, Exhibits 4(c), 4(d) and 4(e)].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the CPL 2001 Annual Report (for the fiscal year ended December 31, 2001)
which are incorporated by reference in this filing.
*23(a) -- Consent of Deloitte & Touche LLP.
*23(b) -- Consent of Arthur Andersen LLP.
*24 -- Power of Attorney.
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)].
E-7
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
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)].
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)].
E-8
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
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 2001 Annual Report (for the fiscal year ended December 31,
2001) which are incorporated by reference in this filing.
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
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 the 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 November 28, 2001).
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 the fiscal year ended December
31, 1993, File No. 1-3570, Exhibit 4(b); Annual Report on Form 10-K of I&M for the fiscal
year ended December 31, 1994, File No. 1-3570, Exhibit 4(b); Annual Report on Form 10-K of
I&M for the 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); Registration Statement No. 58656, Exhibits 4(b) and 4(c)].
*4(c) -- Copy of Company Order and Officers' Certificate, dated December 12, 2001, establishing
certain terms of the 6.125% Notes, Series C, due 2006.
E-9
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
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)].
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)].
E-10
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
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 2001 Annual Report (for the fiscal year ended December 31,
2001) 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, 2001, File No. 1-3525, Exhibit 21].
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
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 June 15, 2000) [Annual Report on Form 10-K of KEPCo for the
fiscal year ended December 31, 2000, 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)].
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); Annual Report on Form 10-K of KEPCo for the fiscal year ended
December 31, 1999, File No. 1-6858, Exhibit 4(c); Annual Report on Form 10-K of KEPCo for the
fiscal year ended December 31, 2000, File No. 1-6858, Exhibit 4(c)].
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)].
E-11
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
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 2001 Annual Report (for the fiscal year ended December 31,
2001) which are incorporated by reference in this filing.
*24 -- Power of Attorney.
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)].
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 of OPCo for the fiscal year ended December
31, 1998, File No. 1-6543, Exhibits 4(c) and 4(d); Annual Report on Form 10-K of OPCo for the
fiscal year ended December 31, 1999, File No. 1-6543, Exhibits 4(c) and 4(d); Annual Report
on Form 10-K of OPCo for the fiscal year ended December 31, 2000, File No. 1-6543, Exhibit
4(c)].
E-12
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
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)].
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].
E-13
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
+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) -- 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(j)(1) -- AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2001 [Annual Report on Form
10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(j)(1)(A)].
+10(j)(2) -- AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2001
(Non-Qualified) [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No.
1-3525, Exhibit 10(j)(2)].
+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, 2001, File No. 1-3525, Exhibit 10(o)].
+10(o) -- AEP System 2000 Long-Term Incentive Plan [Proxy Statement of AEP, March 10, 2000].
+10(p) -- Memorandum of agreement between Susan Tomasky and the Service Corporation dated January 3,
2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525,
Exhibit 10(s)].
+10(q)(1) -- Central and South West System Special Executive Retirement Plan as amended and restated effective
July 1, 1997 [Annual Report on Form 10-K of CSW for the fiscal year ended December 31, 1998, File No.
1-1443, Exhibit 18].
+10(q)(2) -- Certified CSW Board Resolution of April 18, 1991 [Annual Report on Form 10-K of AEP for the fiscal
year ended December 31, 2001, File No. 1-3525, Exhibit 10(r)(2)].
+10(q)(3) -- CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW, March 13, 1992].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the OPCo 2001 Annual Report (for the fiscal year ended December 31,
2001) 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, 2001, File No. 1-3525, Exhibit 21].
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
E-14
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
PSO++
3(a) -- Restated Certificate of Incorporation of PSO [Annual Report on Form U5S of Central and South West
Corporation for the fiscal year ended December 31, 1996, File No. 1-1443, Exhibit B-3.1].
3(b) -- By-Laws of PSO (amended as of June 28, 2000) [Annual Report on Form 10-K of PSO for the fiscal
year ended December 31, 2000, File No. 0-343, Exhibit 3(b)].
4(a) -- Indenture, dated July 1, 1945, between PSO and Liberty Bank and Trust Company of Tulsa,
National Association, as Trustee, as amended and supplemented [Registration Statement No.
2-60712, Exhibit 5.03; Registration Statement No. 2-64432, Exhibit 2.02; Registration
Statement No. 2-65871, Exhibit 2.02; Form U-1 No. 70-6822, Exhibit 2; Form U-1 No. 70-7234,
Exhibit 3; Registration Statement No. 33-48650, Exhibit 4(b); Registration Statement No.
33-49143, Exhibit 4(c); Registration Statement No. 33-49575, Exhibit 4(b); Annual Report on
Form 10-K of PSO for the fiscal year ended December 31, 1993, File No. 0-343, Exhibit 4(b);
Current Report on Form 8-K of PSO dated March 4, 1996, No. 0-343, Exhibit 4.01; Current
Report on Form 8-K of PSO dated March 4, 1996, No. 0-343, Exhibit 4.02; Current Report on
Form 8-K of PSO dated March 4, 1996, No. 0-343, Exhibit 4.03].
4(b) -- PSO-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely
Junior Subordinated Debentures of PSO:
(1) Indenture, dated as of May 1, 1997, between PSO and The Bank of New York, as Trustee
[Quarterly Report on Form 10-Q of PSO dated March 31, 1997, File No. 0-343, Exhibits 4.6
and 4.7].
(2) Amended and Restated Trust Agreement of PSO Capital I, dated as of May 1, 1997, among PSO,
as Depositor, The Bank of New York, as Property Trustee, The Bank of New York (Delaware), as
Delaware Trustee, and the Administrative Trustee [Quarterly Report on Form 10-Q of PSO dated
March 31, 1997, File No. 0-343, Exhibit 4.8].
(3) Guarantee Agreement, dated as of May 1, 1997, delivered by PSO for the benefit of the holders
of PSO Capital I's Preferred Securities [Quarterly Report on Form 10-Q of PSO dated
March 31, 1997, File No. 0-343, Exhibits 4.9].
(4) Agreement as to Expenses and Liabilities, dated as of May 1, 1997, between PSO and PSO Capital I
[Quarterly Report on Form 10-Q of PSO dated March 31, 1997, File No. 0-343, Exhibits 4.10].
4(c) -- Indenture (for unsecured debt securities), dated as of November 1, 2000, between PSO and The Bank of
New York, as Trustee [Annual Report on Form 10-K of PSO for the fiscal year ended December 31, 2000, File
No. 0-343, Exhibits 4(c) and 4(d)]
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the PSO 2001 Annual Report (for the fiscal year ended December 31, 2001)
which are incorporated by reference in this filing.
*23(a) -- Consent of Deloitte & Touche LLP.
*23(b) -- Consent of Arthur Andersen LLP.
*24 -- Power of Attorney.
SWEPCO++
3(a) -- Restated Certificate of Incorporation, as amended through May 6, 1997, including Certificate of
Amendment of Restated Certificate of Incorporation [Quarterly Report on Form 10-Q of SWEPCo for the
quarter ended March 31, 1997, File No. 1-3146, Exhibit 3.4].
E-15
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
3(b) -- By-Laws of SWEPCo (amended as of April 27, 2000) [Quarterly Report on Form 10-Q of SWEPCo for
the quarter ended March 31, 2000, File No. 1-3146, Exhibit 3.3].
4(a) -- Indenture, dated February 1, 1940, between SWEPCo and Continental Bank, National Association
and M. J. Kruger, as Trustees, as amended and supplemented [Registration Statement No.
2-60712, Exhibit 5.04; Registration Statement No. 2-61943, Exhibit 2.02; Registration
Statement No. 2-66033, Exhibit 2.02; Registration Statement No. 2-71126, Exhibit 2.02;
Registration Statement No. 2-77165, Exhibit 2.02; Form U-1 No. 70-7121, Exhibit 4; Form U-1
No. 70-7233, Exhibit 3; Form U-1 No. 70-7676, Exhibit 3; Form U-1 No. 70-7934, Exhibit 10;
Form U-1 No. 72-8041, Exhibit 10(b); Form U-1 No. 70-8041, Exhibit 10(c); Form U-1 No.
70-8239, Exhibit 10(a)].
4(b) -- SWEPCO-obligated, mandatorily redeemable preferred securities of subsidiary trust holding
solely Junior Subordinated Debentures of SWEPCo:
(1) Indenture, dated as of May 1, 1997, between SWEPCo and the Bank of New York, as Trustee
[Quarterly Report on Form 10-Q of SWEPCo dated March 31, 1997, File No. 1-3146, Exhibits 4.11
and 4.12].
(2) Amended and Restated Trust Agreement of SWEPCo Capital I, dated as of May 1, 1997, among
SWEPCo, as Depositor, the Bank of New York, as Property Trustee, The Bank of New York
(Delaware), as Delaware Trustee, and the Administrative Trustee [Quarterly Report on Form
10-Q of SWEPCo dated March 31, 1997, File No. 1-3146, Exhibit 4.13].
(3) Guarantee Agreement, dated as of May 1, 1997, delivered by SWEPCo for the benefit of the
holders of SWEPCo Capital I's Preferred Securities [Quarterly Report on Form 10-Q of
SWEPCo dated March 31, 1997, File No. 1-3146, Exhibit 4.14].
(4) Agreement as to Expenses and Liabilities, dated as of May 1, 1997 between SWEPCo and SWEPCo
Capital I [Quarterly Report on Form 10-Q of SWEPCo dated March 31, 1997, File No. 1-3146,
Exhibits 4.15].
4(c) -- Indenture (for unsecured debt securities), dated as of February 4, 2000, between SWEPCo and The Bank
of New York, as Trustee [Annual Report on Form 10-K of SWEPCo for the fiscal year ended December 31,
2000, File No. 1-3146, Exhibits 4(c) and 4(d)].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the SWEPCo 2001 Annual
Report (for the fiscal year ended December 31, 2001)
which are incorporated by reference in this filing.
*23(a) -- Consent of Deloitte & Touche LLP.
*23(b) -- Consent of Arthur Andersen LLP.
*24 -- Power of Attorney.
WTU++
3(a) -- Restated Articles of Incorporation, as amended, and Articles of Amendment to the Articles of
Incorporation [Annual Report on Form 10-K of WTU for the fiscal year ended December 31, 1996,
File No. 0-340, Exhibit 3.5].
3(b) -- By-Laws of WTU (amended as of May 1, 2000) [Quarterly Report on Form 10-Q of WTU for the
quarter ended March 31, 2000, File No. 0-340, Exhibit 3.4].
E-16
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
4(a) -- Indenture, dated August 1, 1943, between WTU and Harris Trust and Savings Bank and J.
Bartolini, as Trustees, as amended and supplemented [Registration Statement No. 2-60712,
Exhibit 5.05; Registration Statement No. 2-63931, Exhibit 2.02; Registration Statement No.
2-74408, Exhibit 4.02; Form U-1 No. 70-6820, Exhibit 12; Form U-1 No. 70-6925, Exhibit 13;
Registration Statement No. 2-98843, Exhibit 4(b); Form U-1 No. 70-7237, Exhibit 4; Form U-1
No. 70-7719, Exhibit 3; Form U-1 No. 70-7936, Exhibit 10; Form U-1 No. 70-8057, Exhibit 10;
Form U-1 No. 70-8265, Exhibit 10; Form U-1 No. 70-8057, Exhibit 10(b); Form U-1 No. 70-8057,
Exhibit 10(c)].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the WTU 2001 Annual
Report (for the fiscal year ended December 31, 2001) which are incorporated by reference in
this filing.
*24 -- Power of Attorney.
-------------------------------------
++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-17