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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
-----------------------
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, 2000
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 For the transition period from _____________ to
______________
COMMISSION REGISTRANT; STATE OF INCORPORATION; I.R.S. EMPLOYER
FILE NUMBER ADDRESS AND TELEPHONE NUMBER IDENTIFICATION NO.
----------- ---------------------------- ------------------
1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation) 13-4922640
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 223-1000
0-18135 AEP GENERATING COMPANY (An Ohio Corporation) 31-1033833
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 223-1000
1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790
40 Franklin Road, Roanoke, Virginia 24011
Telephone (540) 985-2300
0-346 CENTRAL POWER AND LIGHT COMPANY (A Texas Corporation) 74-0550600
539 North Carancahua Street, Corpus Christi, Texas 78401-2802
Telephone (361) 881-5300
1-2680 COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation) 31-4154203
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 223-1000
1-3570 INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) 35-0410455
One Summit Square, P. O. Box 60, Fort Wayne, Indiana 46801
Telephone (219) 425-2111
1-6858 KENTUCKY POWER COMPANY (A Kentucky Corporation) 61-0247775
1701 Central Avenue, Ashland, Kentucky 41101
Telephone (800) 572-1141
1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000
301 Cleveland Avenue, S.W., Canton, Ohio 44701
Telephone (330) 456-8173
0-343 PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation) 73-0410895
212 East 6th Street, Tulsa, Oklahoma 74119-1212
Telephone (918) 599-2000
1-3146 SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation) 72-0323455
428 Travis Street, Shreveport, Louisiana 71156-0001
Telephone (318) 673-3000
0-340 WEST TEXAS UTILITIES COMPANY (A Texas Corporation) 75-0646790
301 Cypress Street, Abilene, Texas 79601-5820
Telephone (915) 674-7000
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.
2
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
NAME OF EACH EXCHANGE
REGISTRANT TITLE OF EACH CLASS ON WHICH REGISTERED
---------- ------------------- -------------------
AEP Generating Company None
American Electric Common Stock,
Power Company, Inc. $6.50 par value............................................ New York Stock Exchange
Appalachian Power 4-1/2% Cumulative Preferred Stock,
Company Voting, no par value....................................... Philadelphia Stock Exchange
8-1/4% Junior Subordinated Deferrable
Interest Debentures, Series A, Due 2026.................. New York Stock Exchange
8% Junior Subordinated Deferrable
Interest Debentures, Series B, Due 2027.................. New York Stock Exchange
7.20% Senior Notes, Series A, Due 2038......................... New York Stock Exchange
7.30% Senior Notes, Series B, Due 2038......................... New.York Stock Exchange
Columbus Southern 8-3/8% Junior Subordinated Deferrable
Power Company Interest Debentures, Series A, Due 2025................... New York Stock Exchange
7.92% Junior Subordinated Deferrable
Interest Debentures, Series B, Due 2027................... New York Stock Exchange
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
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SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
REGISTRANT TITLE OF EACH CLASS
---------- -------------------
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 4-1/8% Cumulative Preferred Stock, Non-Voting, $100 par value
Kentucky Power Company None Ohio Power Company 4-1/2% Cumulative Preferred Stock, Voting, $100 par value
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, 2001 FEBRUARY 1, 2001
---------------- ----------------
AEP Generating Company None 1,000
($1,000 par value)
American Electric Power Company, Inc. $13,853,503,196 322,024,714
($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 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).
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Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. Yes [X]. No.
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. [X]
DOCUMENTS INCORPORATED BY REFERENCE
PART OF FORM 10-K
INTO WHICH DOCUMENT
DESCRIPTION IS INCORPORATED
----------- ---------------
Portions of Annual Reports of the following companies for the fiscal year ended Part II
December 31, 2000:
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 2001 Annual Part III
Meeting of Shareholders, to be filed within 120 days after December 31, 2000
Portions of Information Statements of the following companies for 2001 Annual Part III
Meeting of Shareholders, to be filed within 120 days after December 31,
2000
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............................................................ 38
Item 4. Submission of Matters to a Vote of Security Holders.......................... 39
Executive Officers of the Registrants.................................................... 39
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters..................................................... 41
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 .................. 42
Item 8. Financial Statements and Supplementary Data.................................. 42
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure.................................. 42
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.......................................................... 46
Item 13. Certain Relationships and Related Transactions............................... 47
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K............................................................. 48
Signatures...................................................................................... 49
Index to Financial Statement Schedules.......................................................... S-1
Independent Auditors' Report.................................................................... S-2
Exhibit Index................................................................................... E-1
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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.
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.
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.
PSO............................................ Public Service Company of Oklahoma, an electric utility subsidiary of AEP.
PUCO........................................... The Public Utilities Commission of Ohio.
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ABBREVIATION OR ACRONYM DEFINITION
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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.
STP............................................ South Texas Project Nuclear Generating Plant, owned 25.2% by CPL, located near
Bay City, Texas.
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, commonly owned by CSPCo, CG&E and DP&L.
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FORWARD-LOOKING INFORMATION
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.
- The impact of the merger with CSW, including the ability of the
combined companies to realize the synergies expected as a result of
the combination.
- 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 structure and timing of a competitive market for electricity and
its impact on prices.
- 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 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.
- Successful resolution of litigation regarding municipal franchise fees
in Texas.
- Successful appeal of decision in connection with COLI litigation.
- Interest rates.
- Other risks and unforeseen events.
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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 furnishing of electric service. In addition, in recent years
AEP has been pursuing various unregulated business opportunities worldwide as
discussed in New Business Development.
The service area of AEP's domestic electric utility subsidiaries
covers portions of the states of 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, 2000, the subsidiaries of AEP had a total of 26,376
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 909,000 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, 2000, APCo and its wholly owned
subsidiaries had 2,846 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
680,000 customers in southern Texas, and in supplying electric power at
wholesale to other utilities, municipalities and rural electric
cooperatives. At December 31, 2000, CPL had 1,444 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
668,000 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, 2000, CSPCo had 1,264 employees.
CSPCo's service area is comprised of two areas in Ohio, which include
portions of twenty-five counties. One area includes the City of Columbus
and the other is a predominantly rural area in south central Ohio.
Approximately 80% of CSPCo's retail revenues are derived from the Columbus
area. Among the principal industries served are food processing, chemicals,
primary metals, electronic machinery and paper products. In addition to its
AEP
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System interconnections, CSPCo also is interconnected with the following
unaffiliated utility companies: CG&E, DP&L and Ohio Edison Company.
I&M (organized in Indiana in 1925) is engaged in the generation, sale,
purchase, transmission and distribution of electric power to approximately
565,000 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, 2000, I&M had 2,965 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 172,000 customers in an area in eastern Kentucky, and in
supplying electric power at wholesale to other utilities and municipalities
in Kentucky. At December 31, 2000, KEPCo had 451 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, 2000, Kingsport
Power Company had 62 employees.
OPCo (organized in Ohio in 1907 and re-incorporated in 1924) is engaged
in the generation, sale, purchase, transmission and distribution of
electric power to approximately 696,000 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, 2000, OPCo and its wholly owned subsidiaries had 3,532
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
499,000 customers in eastern and southwestern Oklahoma, and in supplying
electric power at wholesale to other utilities, municipalities and rural
electric cooperatives. At December 31, 2000, PSO had 1,005 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 Oklahoma in 1912) is engaged in the generation,
sale, purchase, transmission and distribution of electric power to
approximately 428,000 customers in northeastern Texas, northwestern
Louisiana, and western Arkansas, and in supplying electric power at
wholesale to other utilities, municipalities and
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rural electric cooperatives. At December 31, 2000, SWEPCo had 1,243
employees. Among the principal industries served by SWEPCo are natural
gas and oil production, petroleum 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 42,000
customers in northern West Virginia. Wheeling Power Company has no
generating facilities of its own. It purchases electric power distributed
to its customers from OPCo. At December 31, 2000, Wheeling Power Company
had 75 employees.
WTU (organized in Texas in 1927) is engaged in the generation, sale,
purchase, transmission and distribution of electric power to approximately
190,000 customers in west and central Texas, and in supplying electric power
at wholesale to other utilities, municipalities and rural electric
cooperatives. At December 31, 2000, WTU had 718 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. CSW also has the following principal subsidiaries: CSW
International, CSW Energy, SEEBOARD, AEP Credit, Inc., C3 and CSW Energy
Services, Inc.
AEP 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 by December 15, 2001. 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.
- Divestiture of 550 MW of generating capacity comprised of 300 MW of
capacity in the Southwest Power Pool (SPP) and 250 MW of capacity in
the Electric Reliability Council of Texas (ERCOT). AEP must complete
divestiture of the SPP capacity by
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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.
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 part of broader legislation regarding
changes in the electric industry. Such legislation, both as a separate bill and
as part of broader electricity restructuring legislation, was reintroduced in
1999 and 2000. Legislative hearings were held but no PUHCA repeal legislation
was passed by either the House of Representatives or Senate. It is expected that
a number of bills contemplating PUHCA repeal separately and the restructuring of
the electric utility industry will be introduced in the current Congress. See
Competition and Business Change. If PUHCA is repealed, registered holding
company systems, including the AEP System, will be able to compete in the
changing industry without the constraints of PUHCA. Management of AEP believes
that removal of these constraints would be beneficial to the AEP System.
PUHCA and the rules and orders of the SEC currently require that
transactions between associated companies in a registered holding company system
be performed at cost with limited exceptions. Over the years, the AEP System has
developed numerous affiliated service, sales and construction relationships and,
in some cases, invested significant capital and developed significant operations
in reliance upon the ability to recover its full costs under these provisions.
Legislation has been introduced in Congress to repeal PUHCA or modify its
provisions governing intra-system transactions. The effect of repeal or
amendment of PUHCA on AEP's intra-system transactions depends on whether the
assurance of full cost recovery is eliminated immediately or phased in and
whether it is eliminated for all intra-system transactions or only some. If the
cost recovery assurance is eliminated immediately for all intra-system
transactions, it could have a material adverse effect on results of operations
and financial condition of AEP and OPCo. Current legislation grandfathers
transactions legally authorized on the effective date of PUHCA repeal.
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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.
CLASSES OF SERVICE
The principal classes of service from which the domestic electric utility
subsidiaries of AEP derive revenues and the amount of such revenues (from
kilowatt-hour sales) during the year ended December 31, 2000 are as follows:
AEP
SYSTEM(a) AEGCO APCO
--------- ----- ----
(IN THOUSANDS)
Retail
Residential...................................... $3,517,058 $0 $593,636
Commercial....................................... 2,451,068 0 310,478
Industrial....................................... 2,443,750 0 362,303
Miscellaneous.................................... 213,620 0 37,070
---------- -------- ---------
Total Retail............................... 8,625,496 0 1,303,487
Wholesale (sales for resale)........................ 1,795,041 228,304 506,365
---------- ------- ---------
Total from KWH Sales....................... 10,420,537 228,304 1,809,852
Other Operating Revenues and Refunds................ 406,895 212 54,135
----------- -------- ----------
Total Electric Operating Revenues.......... $10,827,432 $228,516 $1,863,987
=========== ======== ==========
CPL CSPCO
--- -----
(IN THOUSANDS)
Retail
Residential...................................... $651,580 $473,986
Commercial....................................... 460,433 434,785
Industrial....................................... 370,161 145,326
Miscellaneous.................................... 49,204 18,176
------ ------
Total Retail............................... 1,531,378 1,072,273
Wholesale (sales for resale)........................ 140,671 243,827
------- -------
Total from KWH Sales....................... 1,672,049 1,316,100
Other Operating Revenues and Refunds................ 99,128 42,250
------ ------
Total Electric Operating Revenues.......... $1,771,177 $1,358,350
========== ==========
I&M KEPCO OPCO PSO
------ ------- ------- -------
(IN THOUSANDS)
Retail
Residential...................................... $340,484 $112,707 $429,491 $361,853
Commercial....................................... 269,650 62,431 278,224 278,940
Industrial....................................... 334,622 93,111 548,599 198,498
Miscellaneous.................................... 6,689 950 8,426 11,372
---------- -------- ---------- --------
Total Retail............................... 951,445 269,199 1,264,740 850,663
Wholesale (sales for resale)........................ 557,235 120,482 894,253 93,993
---------- -------- ---------- --------
Total from KWH Sales....................... 1,508,680 389,681 2,158,993 944,656
Other Operating Revenues and Refunds................ 41,907 20,722 80,638 17,953
---------- -------- ---------- --------
Total Electric Operating Revenues.......... $1,550,587 $410,403 $2,239,631 $962,609
========== ======== ========== ========
SWEPCO WTU
-------- --------
(IN THOUSANDS)
Retail
Residential...................................... $328,873 $164,973
Commercial....................................... 219,318 97,583
Industrial....................................... 273,430 65,517
Miscellaneous.................................... 31,782 46,060
---------- --------
Total Retail............................... 853,403 374,133
Wholesale (sales for resale)........................ 240,792 150,986
---------- --------
Total from KWH Sales....................... 1,094,195 525,119
-------
Other Operating Revenues and Refunds................ 30,015 47,675
---------- --------
Total Electric Operating Revenues.......... $1,124,210 $572,794
========== ========
------------------------
(a) Includes revenues of other subsidiaries not shown and elimination of
intercompany transactions.
SALE OF POWER
AEP's electric utility subsidiaries own or lease generating stations
with total generating capacity of 38,033 megawatts. See Item 2 for more
information regarding the generating stations. They operate their generating
plants as a single interconnected and coordinated electric utility system and,
in the east zone, share the costs and benefits in the AEP System Power Pool.
Most of the electric power generated at these stations is sold, in combination
with transmission and distribution services, to retail customers of AEP's
utility subsidiaries in their service territories. These sales are made at rates
that are established by the public utility commissions of the state in which
they operate. See Rates and
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Regulation. Some of the electric power is sold at wholesale to non-affiliated
companies.
AEP System Power Pool
APCo, CSPCo, I&M, KEPCo and OPCo are parties to the Interconnection
Agreement, dated July 6, 1951, as amended (the Interconnection Agreement),
defining how they share the costs and benefits associated with 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.
Power marketing and trading transactions (trading activities) are
conducted by the AEP Power Pool and shared among the parties under the
Interconnection Agreement. Trading activities involve the purchase and sale of
electricity under physical forward contracts at fixed and variable prices and
the trading of electricity contracts including exchange traded futures and
options and over-the-counter options and swaps. The majority of these
transactions represent physical forward contracts in the AEP System's
traditional marketing area and are typically settled by entering into offsetting
contracts. The regulated physical forward contracts are recorded on a net basis
in the month when the contract settles.
In addition, the AEP Power Pool enters into transactions for the purchase
and sale of electricity options, futures and swaps, and for the forward purchase
and sale of electricity outside of the AEP System's traditional marketing area.
The following table shows the net credits or (charges) allocated among
the parties under the Interconnection Agreement and Interim Allowance Agreement
during the years ended December 31, 1998, 1999 and 2000:
1998(a) 1999(a) 2000(a)
---- ---- ----
(IN THOUSANDS)
APCo................. $(142,500) $(89,100) $(274,000)
CSPCo................ (146,800) (184,500) (250,400)
I&M.................. (86,100) (61,700) 93,900
KEPCo................ 34,000 23,700 (21,500)
OPCo................. 341,400 311,600 452,000
-----------------------
(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. The CSW Operating Agreement has been
accepted for filing and allowed to become effective by the FERC.
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 by the AEP System Power Pool and then allocated among
APCo, CSPCo, I&M, KEPCo and OPCo based on member-load-ratios or made by
individual companies pursuant to various long-term power agreements.
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
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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 Rates and
Regulation. As discussed below, some transmission services also are separately
sold to non-affiliated companies.
AEP System Transmission Pool
APCo, CSPCo, I&M, KEPCo and OPCo are parties to the Transmission
Agreement, dated April 1, 1984, as amended (the Transmission Agreement),
defining how they share the costs associated with their relative ownership of
the extra-high-voltage transmission system (facilities rated 345 kv and above)
and certain facilities operated at lower voltages (138 kv and above). Like the
Interconnection Agreement, this sharing is based upon each company's
"member-load-ratio." See Sale of Power.
The following table shows the net (credits) or charges allocated among
the parties to the Transmission Agreement during the years ended December 31,
1998, 1999 and 2000:
1998 1999 2000
---- ---- ----
(IN THOUSANDS)
APCo........... $(2,400) $(8,300) $(3,400)
CSPCo.......... 35,600 39,000 38,300
I&M............ (44,100) (43,900) (43,800)
KEPCo.......... (6,000) (4,300) (6,000)
OPCo........... 16,900 17,500 14,900
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. The TCA has been accepted for filing by the FERC effective as of January
1, 1997, and is the subject of proceedings commenced to consider the
reasonableness of its terms and conditions.
Transmission Services for Non-Affiliates
AEP's electric utility subsidiaries and other System companies also
provide transmission services for non-affiliated companies.
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.
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On July 9, 1996, the AEP System companies filed a tariff conforming
with the FERC's pro-forma transmission tariff.
During 1998 and 1999 AEP engaged in discussions with Consumers Energy
Company, FirstEnergy Corp., Detroit Edison Company and VEPCo regarding the
development of the Alliance RTO which may take the form of an ISO or an
independent transmission company (Transco), depending upon the occurrence of
certain conditions. The Transco, if formed, would operate transmission assets
that it would own, and also would operate other owners' transmission assets on a
contractual basis. In 1999, these companies filed with the FERC a proposal to
form the RTO. In December 1999, the FERC approved the Alliance RTO, conditioned
upon certain changes to the proposal relating to governance of the RTO,
resolution of intra-RTO conflicts and establishment of a rate structure. On
January 24, 2001, the FERC approved the compliance filing made by the Alliance
RTO in September 2000 and generally accepted the responses to the changes
proposed in the December 1999 FERC order. The January 2001 FERC order also
directed the Alliance companies to file their actual rates no later than 120
days prior to the commencement of operations by the Alliance RTO.
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.
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.
OVEC
AEP, CSPCo and several unaffiliated utility companies jointly own OVEC,
which supplies the power requirements of a uranium enrichment plant near
Portsmouth, Ohio, owned by the DOE. The aggregate equity participation of AEP
and CSPCo in OVEC is 44.2%. The DOE demand under OVEC's power agreement, which
is subject to change from time to time, is 800,000 kilowatts. On April 1, 2001,
it is scheduled to decrease to approximately 600,000 kilowatts. The proceeds
from the sale of power by OVEC are designed to be sufficient for OVEC to meet
its operating expenses and fixed costs and to provide a return on its equity
capital. APCo, CSPCo, I&M and OPCo, as sponsoring companies, are entitled to
receive from OVEC, and are obligated to pay for, the power not required by DOE,
which averaged 42.1% in 2000. On September 29, 2000, DOE issued a notice of
cancellation of the power agreement. DOE will therefore not be entitled to any
OVEC capacity beyond August 31, 2001. The sponsoring companies will be entitled
to all OVEC capacity in proportion to their power participation ratios
(approximately 2,200MW) beginning September 1, 2001.
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
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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 331 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 December
22, 2000, was recorded at 1,304,134 kilowatts.
In January 2000, OPCo and National Power Cooperative, Inc. (NPC), an
affiliate of Buckeye, entered into an agreement, subject to specified
conditions, relating to construction and operation of a 510 mw gas-fired
electric generating peaking facility to be owned by NPC. From the commercial
operation date (expected in early 2002) until the end of 2005, OPCo will be
entitled to the power generated by the facility, and responsible for the fuel
and other costs of the facility. After 2005, NPC and OPCo will be entitled to
80% and 20%, respectively, of the power of the facility, and both parties will
generally be responsible for the fuel and other costs of the facility. OPCo will
also provide certain back-up power to NPC. AEP Pro Serv, Inc. will provide
engineering, procurement and construction for the facility.
CERTAIN INDUSTRIAL CUSTOMERS
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 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.
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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 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.
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 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 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
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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. If competition
develops in retail power generation, the public utility subsidiaries of AEP
believe that they should have a favorable competitive position because of their
relatively low costs.
Legislation to provide for retail competition among electric energy
suppliers has been introduced in both the U.S. Senate and House of
Representatives.
Wholesale
The public utility subsidiaries of AEP, like the electric industry
generally, face increasing competition to sell available power on a wholesale
basis, primarily to other public utilities and also to power marketers. The
Energy Policy Act of 1992 was designed, among other things, to foster
competition in the wholesale market (a) through amendments to PUHCA,
facilitating the ownership and operation of generating facilities by "exempt
wholesale generators" (which may include independent power producers as well as
affiliates of electric utilities) and (b) through amendments to the Federal
Power Act, authorizing the FERC under certain conditions to order utilities
which own transmission facilities to provide wholesale transmission services for
other utilities and entities generating electric power. The principal factors in
competing for such sales are price (including fuel costs), availability of
capacity and reliability of service. The public utility subsidiaries of AEP
believe that they maintain a favorable competitive position on the basis of all
of these factors. However, because of the availability of capacity of other
utilities and the lower fuel prices in recent years, price competition has been,
and is expected for the next few years to be, particularly important.
FERC orders 888 and 889, issued in April 1996, provide that utilities
must functionally unbundle their transmission services, by requiring them to use
their own tariffs in making off-system and third-party sales. See Transmission
Services. The public utility subsidiaries of AEP have functionally separated
their wholesale power sales from their transmission functions, as required by
orders 888 and 889.
Retail
The public utility subsidiaries of AEP generally (except in Ohio) have
the exclusive right to sell electric power at retail within their service areas,
with the exception of Virginia and Texas beginning in 2002 and Ohio. However,
they do compete with self-generation and with distributors of other energy
sources, such as natural gas, fuel oil and coal, within their service areas. The
primary factors in such competition are price, reliability of service and the
capability of customers to utilize sources of energy other than electric power.
With respect to self-generation, the public utility subsidiaries of AEP believe
that they maintain a favorable competitive position on the basis of all of these
factors. With respect to alternative sources of energy, the public utility
subsidiaries of AEP believe that the reliability of their service and the
limited ability of customers to substitute other cost-effective sources for
electric power place them in a favorable competitive position, even though their
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
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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 most 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.
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 (i) public utility
subsidiaries that remain subject to regulation by at least one
state utility commission and (ii) foreign utility subsidiaries
subject to regulation as to rates or tariffs. AEP intends for this
subsidiary ultimately to hold all transmission and distribution
assets.
- A subsidiary would hold public utility and non-utility
subsidiaries that derive their revenues from competitive activity.
AEP intends for this subsidiary to ultimately hold all generation
assets not subject to regulation.
NEW BUSINESS DEVELOPMENT
AEP has expanded its business to non-regulated energy activities through
several subsidiaries, including AEP Energy Services, Inc. (AEPES), AEP
Resources, Inc. (Resources), AEP Pro Serv, Inc. (formerly AEP Resources Service
Company) (Pro Serv) and AEP Communications, LLC (AEP Communications).
Wholesale Business Operations
Various AEP subsidiaries, including AEPES, engage in wholesale business
operations that focus primarily upon the following activities:
- Trade and market energy commodities, including electric power,
natural gas, natural gas liquids, oil, coal, and SO2 allowances in
North America and Europe.
- Provide 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.
- Enter into 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.
- Optimize trading and marketing through a diversified portfolio of
owned assets and structured third party arrangements, including:
- Power generation facilities.
- Natural gas pipeline, storage and processing facilities.
- Coal mines and related facilities.
- Other transportation and fuel supply related assets.
- Acquire, develop, engineer, construct, operate and maintain owned
and third party exempt wholesale generation and cogeneration
facilities and ancillary energy-related assets.
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AEP's subsidiaries are engaged in the engineering and construction for
third parties of three power plants in the U. S. with a capacity of 1,910 MW.
These plants, which are listed below, will be natural gas-fired facilities that
are scheduled to be completed from 2001 to 2003. These projects synchronize the
wholesale business through the integration of trading, marketing, engineering,
construction and operations.
- AEP subsidiaries reached agreement with The Dow Chemical Company
to construct a 900MW cogeneration facility in Louisiana.
Commercial operation is expected in 2003.
- AEP subsidiaries reached agreement with Buckeye (an Ohio electric
cooperative) to construct and operate a 510 MW peaking facility in
Ohio. This agreement entitles AEP to 100% of the facility's
capacity and energy in the upfront operating years through 2005.
Commercial operation is expected in 2002.
- AEP subsidiaries reached agreement with Twelvepole Creek, LLC, a
subsidiary of Columbia Electric, which was subsequently acquired
by Orion Power Holdings, Inc., to engineer, procure and construct
a 500 MW peaking facility in West Virginia. Commercial operation
is expected in May 2001.
Houston Pipe Line Company: AEP subsidiaries reached agreement to acquire
Houston Pipe Line Company (HPL) and its Bammel Storage Facility (one of the
largest natural gas storage facilities in North America). HPL is a Texas
intrastate pipeline and, along with Resources' midstream gas assets discussed
below which were acquired in 1998, will provide a daily gas capacity of
approximately 3.5 billion cubic feet, more than 6,400 miles of natural gas
pipeline and a total storage capacity of approximately 128 billion cubic feet of
high injection and withdrawal capabilities.
ICEX: AEP subsidiaries reached agreement to participate and to make an
equity investment in a new internet-based electronic trading system
Intercontinental Exchange, L.L.C. (ICEX) 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. This interest, along with an earlier
investment in Altra Energy Technologies, Inc., provides additional liquidity
trading points for the wholesale trading and marketing platform.
CSW Energy: CSW Energy presently owns interests in operating power
projects located in Colorado, Florida and Texas. In addition to these projects,
CSW Energy has other projects in various stages of development.
- CSW Energy has entered into an agreement with Eastman Chemical
Company to construct and operate a 440 MW cogeneration facility in
Longview, Texas. This facility will be known as the Eastex
Cogeneration Project. Construction of the facility began in the
fourth quarter of 1999, with expected operation in the second or
third quarter of 2001. Excess electricity generated by the plant
will be sold in the wholesale market.
- In October 1999, GE Capital Structured Finance Group purchased 50%
of the equity ownership of Sweeny Cogeneration Limited
Partnership. CSW Energy's after-tax earnings from the proceeds of
the transaction were approximately $33 million. The agreement
between CSW Energy and GE Capital Structured Financial Group
provides for additional payments to CSW Energy subject to
completion of a planned expansion of the Sweeny cogeneration
facility, which may be operational in the second quarter of 2001.
CSW International: CSW International currently holds investments in the
United Kingdom, Mexico and South America.
CSW International and its 50% partner, Scottish Power plc, have entered
into a joint venture to construct and operate the South Coast Power Project, a
400 MW combined cycle gas turbine power station in Shoreham, United Kingdom. CSW
International has guaranteed approximately Pound Sterling 19 million of the
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Pound Sterling 190 million construction financing. Both the guarantee and the
construction financing are denominated in pounds sterling. The U. S. dollar
equivalent at December 29, 2000 would be $28.4 million and $284.1 million
respectively, using a conversion rate of Pound Sterling 1.00 equals $1.4953.
Construction of the project began in March 1999, and commercial operation has
begun though it is not yet running at full capacity.
Through November 1999, CSW International had purchased a 36% equity
interest in Vale for $80 million. In 1998, CSW International also extended $100
million of debt convertible into equity in Vale. In December 1999, CSW
International converted $69 million of that $100 million of debt into equity,
thereby raising its equity interest in Vale to 44%. CSW International
anticipates converting the remaining debt and accrued interest to equity in
Caiua, a subsidiary of Vale, on December 1, 2001.
CSW International invested $110 million from September through November
1997 for 5% of the common stock of Gener, a Chilean electric company. This
investment was sold in December 2000 for $67 million.
Resources
Resources' primary business is development of, and investment in, exempt
wholesale generators, foreign utility companies, qualifying cogeneration
facilities and other energy-related domestic and international investment
opportunities and projects. Resources has business development offices in
London; Beijing; Columbus, Ohio; Sydney and Washington D.C.
Resources also indirectly owns CitiPower Pty., an electric distribution
and retail sales company in Victoria, Australia. CitiPower serves approximately
250,000 customers in the city of Melbourne. With about 3,100 miles of
distribution lines in a service area that covers approximately 100 square miles,
CitiPower distributes about 4,800 gigawatt-hours annually.
Resources' indirect subsidiary, AEP Pushan Power LDC, has a 70% interest
in Nanyang General Light Electric Co., Ltd. (Nanyang Electric), a joint venture
organized to develop and build two 125 megawatt coal-fired generating units near
Nanyang City in the Henan Province of The Peoples Republic of China. Nanyang
Electric was established in 1996 by AEP Pushan Power LDC, Henan Electric Power
Development Co. (15% interest) and Nanyang City Hengsheng Energy Development
Company Limited (formerly Nanyang Municipal Finance Development Co.) (15%
interest). Unit 1 went into service in February 1999 and Unit 2 went into
service in June 1999. Resources' share of the total cost of the project of
$185,000,000 was approximately $110,000,000.
In December 1999, Resources contributed $47,000,000 to acquire a 50%
interest in the Bajio power project in Mexico. The Bajio project is a 600
megawatt natural gas-fired, combined cycle plant and related assets located
approximately 160 miles from Mexico City. Bechtel Power Corporation, an
affiliate of Resources' partner (InterGen), will build the facility, which is
estimated to cost $430,000,000. Approximately 80% of the project costs will be
provided by third party debt, some of which will be supported by letters of
credit issued on behalf of Resources. The facility will be operated and managed
by one or more companies jointly owned by Resources and InterGen. Bajio has a
25-year contract to sell 495 megawatts of the plant's output to Mexico's
federally owned electric system; the remainder is expected to be sold to
industrial customers in the region. The Bajio project was approximately 60%
completed as of December 31, 2000 and construction is expected to be completed
in the fall of 2001.
Resources, through AEP Resources Australia Pty., Ltd., a special purpose
subsidiary of Resources, owns a 20% interest in Pacific Hydro Limited. Pacific
Hydro is principally engaged in the development and operation of, and ownership
of interests in, hydroelectric facilities in the Asia Pacific region. Currently,
Pacific Hydro has interests in six hydroelectric units and one wind farm unit
that operate or are under construction in Australia and the Philippines. The
hydroelectric facilities in which Pacific Hydro had interests as of December 31,
2000 (including those under construction) had total design capacity of
approximately 181 megawatts.
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Resources owns midstream gas assets, including:
- A 2,000-mile intrastate pipeline system in Louisiana.
- Four natural gas processing plants that straddle the pipeline.
- A ten billion cubic foot underground natural gas storage facility
directly connected to the Henry Hub, the most active gas trading
area in North America.
The pipeline and storage facilities are interconnected to 15 interstate
and 23 intrastate pipelines.
U. K. Electric: Resources and another AEP subsidiary have a 50% interest
in Yorkshire Electric Group plc (Yorkshire Electricity) with an indirect
wholly-owned subsidiary of Xcel Energy, Inc. Yorkshire Electricity is a United
Kingdom independent regional electricity company. It is principally engaged in
the supply and distribution of electricity. Yorkshire Electricity has two
million distribution customers in its authorized service territory which is
comprised of 3,860 square miles and located centrally in the east coast of
England.
In February 2001, AEP entered into an agreement to sell its 50% interest
in Yorkshire. The sale is anticipated to be completed in the second quarter of
2001.
SEEBOARD, a wholly-owned subsidiary of CSW International, 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's service area covers approximately 3,000
square miles in Southeast England. The area has a population of approximately
4.7 million people with significant portions of the area, such as south London,
having a high population density.
In a joint venture, SEEBOARD Powerlink won a 30-year contract for $1.6
billion to operate, maintain, finance and renew the high-voltage power
distribution network of the London Underground, the largest metropolitan rail
system in the world. SEEBOARD's partners in the Powerlink consortium are an
international electrical engineering group and an international cable and
construction group.
On June 30, 1999, SEEBOARD purchased the 50% interest in Beacon Gas held
by BP Amoco. Beacon Gas was a joint venture between SEEBOARD and BP Amoco set up
for the supply of gas.
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. In addition to expanding its fiber optic network during 2000, AEP
Communications joined with several other energy and telecommunications companies
to form AFN Communications, LLC. (AFN). AFN is a 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, with plans to expand
nationally, 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. AEP Communications also joined with Touch America,
Inc. to form American Fiber Touch, LLC, an entity that will construct, own, and
market a long haul fiber optic route that interconnects the AEP Communications
and C3 through Illinois and Missouri.
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AEP Communications and C3 also operate business units engaged in
marketing energy information. AEP Communications offers a portfolio of energy
information data and analysis tools designed to help customers identify energy
and cost saving opportunities. C3's energy information services include:
- Meter reading, validation and settlement services.
- Automated meter reading equipment sales and leasing.
- Energy information services.
- Equipment sales and services.
Since the merger of AEP and CSW, a realignment of the energy information
business units has taken place through the formation of Datapult Limited
Partnership. Energy information services will be offered under the Datapult
brand. Evaluation of partnerships and acquisitions will also be a key element of
growth for Datapult Limited Partnership in 2001.
SEC Limitations
AEP has received approval from the SEC under PUHCA to issue and sell
securities in an amount up to 100% of its average quarterly consolidated
retained earnings balance (such average balance was approximately $3.4 billion
for the twelve months ended December 31, 2000) for investment in exempt
wholesale generators and foreign utility companies. Resources expects to
continue its pursuit of new and existing energy generation and delivery projects
worldwide.
SEC Rule 58 permits AEP and other registered holding companies to invest
up to 15% of consolidated capitalization in energy-related companies. AEPES, an
energy-related company under Rule 58, is authorized to engage in energy-related
activities, including marketing electricity, gas and other energy commodities.
Risk
These continuing efforts to invest in and develop new business
opportunities offer the potential of earning returns which may exceed those of
traditional AEP rate-regulated operations. However, they also involve a higher
degree of risk which must be carefully considered and assessed. AEP may make
additional substantial investments in these and other new businesses.
Reference is made to Market Risks under Item 7A herein for a discussion
of certain market risks inherent in AEP business activities.
CONSTRUCTION PROGRAM
New Generation
The AEP System is continuously involved in assessing the adequacy of its
generation, transmission, distribution and other facilities to plan and provide
for the reliable supply of electric power and energy to its customers. In this
assessment 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.
Committed or anticipated capability changes to the AEP System's
generation resources include:
- Purchase from an independent power producer's hydro project with
an expected capacity value of 28 megawatts, commencing June 1,
2001.
- Expiration of the Rockport Unit 2 sale of 250 megawatts to
Carolina Power & Light Company, an unaffiliated company, on
December 31, 2009.
Apart from these changes and temporary power purchases that can be
arranged, there are no specific commitments for additions of new generation
resources on the AEP System. 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 the Wyoming-Cloverdale
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765,000-volt Project. The preferred route for this line is approximately 132
miles in length, connecting APCo's Wyoming Station in southern West Virginia to
APCo's Cloverdale Station near Roanoke, Virginia. APCo's estimated cost for the
Wyoming-Cloverdale Project is $283,254,000, assuming a 2004 in-service date.
APCo announced this project in 1990. Since then it has been in the
process of trying to obtain federal permits and state certificates. At the
federal level, the U.S. Forest Service (Forest Service) is directing the
preparation of an Environmental Impact Statement (EIS), which is required prior
to granting permits for crossing lands under federal jurisdiction. Permits are
needed from the (i) Forest Service to cross federal forests, (ii) Army Corps of
Engineers to cross the New River and a watershed near the Wyoming Station, and
(iii) National Park Service or Forest Service to cross the Appalachian National
Scenic Trail.
In June 1996, the Forest Service released a Draft EIS and preliminarily
identified a "No Action Alternative" as its preferred alternative. If this
alternative were incorporated into the Final EIS, APCo would not be authorized
to cross federal forests administered by the Forest Service. The Forest Service
stated that it would not prepare the Final EIS until after Virginia and West
Virginia determined need and routing issues.
West Virginia: On May 27, 1998, the West Virginia PSC issued an order
granting APCo's application for a certificate with respect to the
Wyoming-Cloverdale 765,000-volt Project. On October 27, 2000, APCo filed with
the West Virginia PSC a request to amend the certificate by adding the
alternative end point of Jacksons Ferry in Virginia as discussed below under
Virginia.
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 between 82-100 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. The matter is pending before
the Virginia SCC. APCo's estimated cost for the Wyoming-Jacksons Ferry Project
is $232,455,000, assuming a 2004 in-service date.
Proposed Completion Schedule: If the Virginia SCC and West Virginia PSC
issue the required certificates, APCo will cooperate with the Forest Service to
complete the EIS process and obtain the federal permits. The Forest Service has
begun preliminary work on a supplement to the Draft EIS. APCo has also begun
required consultation with the U.S. Fish and Wildlife Service under the
Endangered Species Act.
Management estimates that neither project can be completed before the
winter of 2004/2005. However, given the findings in the Draft EIS, APCo cannot
presently predict the schedule for completion of the federal permitting process.
Construction Expenditures
The following table shows construction expenditures during 1998, 1999 and
2000 and current estimates of 2001 construction expenditures, in each case
including AFUDC but excluding assets acquired under leases.
1998 1999 2000 2001
ACTUAL ACTUAL ACTUAL ESTIMATE
------ ------ ------ --------
(IN THOUSANDS)
AEP System (a).... $792,100 $866,900 $1,773,400 $2,077,400
AEGCo.......... 6,600 8,300 5,200 3,200
APCo........... 204,900 211,400 199,300 394,800
CPL............ 126,600 255,800 199,500 295,000
CSPCo.......... 115,300 115,300 128,000 146,300
I&M............ 148,900 165,300 171,100 127,900
KEPCo.......... 43,800 44,300 36,200 53,400
OPCo........... 185,200 193,900 254,000 447,700
PSO............ 70,100 104,500 176,900 136,600
SWEPCo......... 84,500 112,900 120,200 123,700
WTU............ 37,600 52,600 64,500 77,500
-----------------------
(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.
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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 1998, 1999 and 2000 and the current estimate for 2001 are shown
below. Substantial expenditures in addition to the amounts set forth below may
be required by the System in future years in connection with the modification
and addition of facilities at generating plants for environmental quality
controls in order to comply with air and water quality standards which have been
or may be adopted.
1998 1999 2000 2001
ACTUAL ACTUAL ACTUAL ESTIMATE
------ ------ ------ --------
(IN THOUSANDS)
AEGCo................ $800 $8 $70 $100
APCo................. 25,000 24,500 2,100 203,100
CPL.................. (a) (a) (a) 3,300
CSPCo................ 5,300 10,600 6,600 17,700
I&M.................. 13,000 4,500 1,900 7,600
KEPCo................ 4,600 1,900 400 23,300
OPCo................. 27,100 37,400 91,200 271,900
PSO.................. (a) (a) (a) 1,000
SWEPCo............... (a) (a) (a) 13,200
WTU.................. (a) (a) (a) 1,100
------- ------- -------- --------
AEP System (a)..... $75,800 $78,908 $102,270 $542,300
======= ======= ======== ========
-----------------------
(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 other 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 New Business Development and Item 7 for
additional information concerning AEP's other unregulated subsidiaries.
RATES AND REGULATION
General
The rates charged by the electric utility subsidiaries of AEP are
approved by the FERC or one of the state utility commissions as applicable. The
FERC regulates wholesale rates and the state commissions regulate retail rates.
In recent years the number of rate increase applications filed by the operating
subsidiaries of AEP with their respective state commissions and the FERC has
decreased. Under current rate regulation, if increases in operating,
construction and capital costs exceed increases in revenues resulting from
previously
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granted rate increases and increased customer demand, then it may be appropriate
for certain of AEP's electric utility subsidiaries to file rate increase
applications in the future.
Generally the rates of AEP's operating subsidiaries are determined based
upon the cost of providing service including a reasonable return on investment.
Certain states served by the AEP System allow alternative forms of rate
regulation in addition to the traditional cost-of-service approach. However, the
rates of AEP's operating subsidiaries in those states continue to be cost-based.
The IURC may approve alternative regulatory plans which could include setting
customer rates based on market or average prices, price caps, index-based prices
and prices based on performance and efficiency. The Virginia SCC may approve (i)
special rates, contracts or incentives to individual customers or classes of
customers and (ii) alternative forms of regulation including, but not limited
to, the use of price regulation, ranges of authorized returns, categories of
services and price indexing.
All of the eleven states served by the AEP System, as well as the FERC,
either currently permit the incorporation of fuel adjustment clauses in a
utility company's rates and tariffs, which are designed to permit upward or
downward adjustments in revenues to reflect increases or decreases in fuel costs
above or below the designated base cost of fuel set forth in the particular rate
or tariff, or currently permit the inclusion of specified levels of fuel costs
as part of such rate or tariff.
AEP cannot predict the timing or probability of approvals regarding
applications for additional rate changes, the outcome of action by regulatory
commissions or courts with respect to such matters, or the effect thereof on the
earnings and business of the AEP System. In addition, current rate regulation
may, and in the case of Ohio, Texas and Virginia will, be subject to significant
revision. See Competition and Business Change.
FUEL SUPPLY
The following table shows the sources of power generated by the AEP
System:
1996 1997 1998 1999 2000
---- ---- ---- ---- ----
Coal........................ 73% 76% 79% 79% 78%
Gas......................... 12% 12% 14% 15% 13%
Nuclear..................... 11% 8% 3% 3% 5%
Hydroelectric and other..... 4% 4% 4% 3% 4%
Variations in the generation of nuclear power are primarily related to
refueling outages and, in 1997 through 1999, the shutdown of the Cook Plant to
respond to issues raised by the NRC.
Natural Gas
AEP consumed over 273 billion cubic feet of natural gas during 2000 for
the system operating companies, which ranks them as the fourth largest consumer
of natural gas in the United States. 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 which 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, in addition to coal reserves now owned by System companies, through
the acquisition of additional coal reserves and/or by entering into additional
supply agreements, either on a long-term or spot basis, at prices and upon terms
which cannot now be predicted.
No representation is made that any of the coal rights owned or controlled
by the System will, in
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future years, produce for the System any major portion of the overall coal
supply needed for consumption at the coal-fired generating units of the System.
Although AEP believes that in the long run it will be able to secure coal of
adequate quality and in adequate quantities to enable existing and new units to
comply with emission standards applicable to such sources, no assurance can be
given that coal of such quality and quantity will in fact be available. No
assurance can be given either that statutes or regulations limiting emissions
from existing and new sources will not be further revised in future years to
specify lower sulfur contents than now in effect or other restrictions. See
Environmental and Other Matters herein.
The FERC has adopted regulations relating, among other things, to the
circumstances under which, in the event of fuel emergencies or shortages, it
might order electric utilities to generate and transmit electric power to other
regions or systems experiencing fuel shortages, and to rate-making principles by
which such electric utilities would be compensated. In addition, the Federal
Government is authorized, under prescribed conditions, to allocate coal and to
require the transportation thereof, for the use of power plants or major
fuel-burning installations.
System companies have developed programs to conserve coal supplies at
System plants which involve, on a progressive basis, limitations on sales of
power and energy to neighboring utilities, appeals to customers for voluntary
limitations of electric usage to essential needs, curtailment of sales to
certain industrial customers, voltage reductions and, finally, mandatory
reductions in cases where current coal supplies fall below minimum levels. Such
programs have been filed and reviewed with officials of Federal and state
agencies and, in some cases, the state regulatory agency has prescribed actions
to be taken under specified circumstances by System companies, subject to the
jurisdiction of such agencies.
The mining of coal reserves is subject to Federal requirements with
respect to the development and operation of coal mines, and to state and Federal
regulations relating to land reclamation and environmental protection, including
Federal strip mining legislation enacted in August 1977. Continual evaluation
and study is given to possible closure of existing coal mines and divestiture or
acquisition of coal properties in light of Federal and state environmental and
mining laws and regulations which may affect the System's need for or ability to
mine such coal.
Western coal purchased by System companies is transported by rail to an
affiliated terminal on the Ohio River for transloading to barges for delivery to
generating stations on the river. Subsidiaries of AEP own 3,030 coal hopper cars
and lease an additional 4,079 coal hopper cars to be used in unit train
movements. Subsidiaries of AEP lease 15 towboats, 492 jumbo barges and 145
standard barges. Subsidiaries of AEP also own or lease coal transfer facilities
at various other locations.
The System generating companies procure coal from coal reserves which are
owned or mined by subsidiaries of AEP, and through purchases pursuant to
long-term contracts, or on a spot purchase basis, from unaffiliated producers.
The following table shows the amount of coal delivered to the AEP System during
the past five years, the proportion of such coal which was obtained either from
coal-mining subsidiaries, from unaffiliated suppliers under long-term contracts
or through spot or short-term purchases, and the average delivered price of spot
coal purchased by System companies:
1996(a) 1997(a) 1998(a) 1999(a) 2000
---- ---- ---- ---- ----
Total coal delivered to
AEP operated plants (thousands of tons)........... 51,030 54,292 54,004 54,306 73,259
Sources (percentage):
Subsidiaries........................................ 13% 14% 14% 11% 9%
Long-term contracts................................. 71% 66% 66% 64% 67%
Spot or short-term purchases........................ 16% 20% 20% 24% 24%
Average price per ton of spot-purchased coal........... $23.85 $24.38 $25.05 $27.18 $24.03
--------------------
(a) Includes east zone companies only.
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The average cost of coal consumed during the past five years by all AEP
System companies is shown below. AEP System companies data for 1996 and 1997
includes only AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo.
1996 1997 1998 1999 2000
---- ---- ---- ---- ----
DOLLARS PER TON
---------------
AEP System Companies............................. $29.38 $29.68 $29.87 $30.01 $31.39
AEGCo......................................... 18.22 19.30 19.37 20.79 20.65
APCo.......................................... 37.60 36.09 34.81 33.29 32.84
CPL........................................... 28.81 26.93 26.93 26.49 25.95
CSPCo......................................... 31.70 31.69 31.63 29.94 28.50
I&M........................................... 22.99 23.68 22.61 24.54 23.44
KEPCo......................................... 27.25 26.76 27.42 26.76 25.35
OPCo.......................................... 35.96 36.00 38.94 40.56 46.52
PSO........................................... 21.84 21.11 20.37 20.94 21.21
SWEPCo........................................ 23.81 23.16 23.02 21.34 22.59
WTU........................................... 24.41 18.19 21.37 21.72 22.26
1996 1997 1998 1999 2000
---- ---- ---- ---- ----
CENTS PER MILLION BTU'S
-----------------------
AEP System Companies............................. 139.44 140.13 142.17 141.95 149.12
AEGCo......................................... 109.25 115.21 112.63 116.90 116.23
APCo.......................................... 152.54 146.54 141.76 135.40 134.86
CPL........................................... 143.12 136.40 137.00 135.78 137.86
CSPCo......................................... 134.60 134.44 134.15 127.42 120.83
I&M........................................... 121.16 123.36 118.02 121.90 117.99
KEPCo......................................... 114.42 110.37 112.15 109.91 104.88
OPCo.......................................... 151.55 151.66 164.44 169.23 194.77
PSO........................................... 125.87 120.91 116.73 119.54 121.83
SWEPCo........................................ 155.88 152.79 150.62 143.34 144.96
WTU........................................... 146.26 109.13 126.22 129.13 131.56
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, 2000, the
System's coal inventory was approximately 35 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 2000 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 2000 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.
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AVERAGE SULFUR CONTENT
ESTIMATED REQUIRE- OF DELIVERED COAL
TOTAL CONSUMPTION MENTS FOR REMAINDER --------------------------------
DURING 2000 OF USEFUL LIVES POUNDS OF SO2
(IN THOUSANDS OF TONS) (IN MILLIONS OF TONS) BY WEIGHT PER MILLION BTU'S
---------------------- --------------------- --------- -----------------
AEGCo (a)..................... 4,944 211 0.3% 0.7
APCo.......................... 11,662 384 0.8% 1.2
CPL........................... 2,745 41 0.3% 0.7
CSPCo......................... 6,368 222(b) 2.5% 4.2
I&M (c)....................... 7,342 241 0.7% 1.4
KEPCo......................... 2,794 82 0.9% 1.5
OPCo.......................... 20,723 533(d) 2.1% 3.5
PSO........................... 4,199 47 0.2% 0.5
SWEPCo........................ 12,720 151 0.5% 1.3
WTU........................... 1,519 35 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 0.8% during 2000, 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 with four coal suppliers which
delivered approximately 2,255,000 tons of coal during the year 2000. One
contract for Colorado coal extends through 2001 and has 1,000,000 tons to be
delivered during that year. 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 3,120,000 tons per year through 2004. Some of this
coal is washed to improve its quality and consistency for use principally at
Unit 4 of the Conesville Plant.
CSPCo has been informed by CG&E and DP&L that, with respect to the CCD
Group units partly owned but not operated by CSPCo, sufficient coal has been
contracted for or is believed to be available for the approximate lives of the
respective units operated by them. Under the terms of the operating agreements
with respect to CCD Group units, each operating company is contractually
responsible for obtaining the needed fuel.
I&M: I&M has two coal supply agreements with unaffiliated Wyoming
suppliers for low sulfur coal from surface mines principally for consumption by
the Rockport Plant. Under these agreements, the suppliers will sell to I&M, for
consumption by I&M at the Rockport Plant or consignment to other System
companies, coal with an average sulfur content not exceeding 1.2 pounds of
sulfur dioxide per million Btu's of heat input. One contract with remaining
deliveries of 45,138,543 tons expires on December 31, 2014 and another contract
with remaining deliveries of 26,400,000 tons expires on December 31, 2004.
All of the coal consumed at I&M's Tanners Creek Plant is obtained from
unaffiliated suppliers under long-term contracts and/or on a spot purchase
basis.
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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 1,600,000 tons of
coal in 2001. To the extent that KEPCo has additional coal requirements, it may
purchase coal from the spot market and/or suppliers under contract to supply
other System companies.
OPCo: The coal consumed at OPCo's generating plants is obtained from both
affiliated and unaffiliated suppliers. The coal obtained from unaffiliated
suppliers is purchased under long-term contracts and/or on a spot purchase
basis.
OPCo and certain of its coal-mining subsidiaries own or control coal
reserves in the State of Ohio containing approximately 145,000,000 tons of clean
recoverable coal and ranging in sulfur content between 3.8% and 4.5% sulfur by
weight (weighted average, 4.1%), which reserves are presently being mined. OPCo
and certain of its mining subsidiaries own an additional 113,000,000 tons of
clean recoverable coal in Ohio which ranges in sulfur content between 2.4% and
3.4% sulfur by weight (weighted average 2.7%). Recovery of this coal would
require substantial development.
OPCo and certain of its coal-mining subsidiaries also own or control coal
reserves in the State of West Virginia which contain approximately 96,000,000
tons of clean recoverable coal ranging in sulfur content between 1.4% and 4.0%
sulfur by weight (weighted average, 2.0%) of which approximately 19,000,000 tons
can be recovered based upon existing mining plans and projections and employing
current mining practices and techniques.
PSO: The coal contract under which coal is supplied to PSO provides the
entire plant requirements with at least 20,285,000 tons remaining to be
delivered. The coal is supplied from Wyoming and has a maximum sulfur content of
1.2 lbs. SO2 per MMBtu.
SWEPCo: SWEPCo has one coal contract with a Wyoming producer that
provides the majority of its coal requirements. The coal is supplied from
Wyoming and has a maximum sulfur content of 1.2 lbs. SO2 per MMBtu. SWEPCo has
remaining deliveries of approximately 31 million tons through 2006 under this
contract. In 2000, the remaining coal requirements for SWEPCo were obtained
under short term coal agreements with Wyoming producers. SWEPCo also has a
mine-mouth lignite operation in East Texas that provides a low cost source to
the Pirkey Plant. North American Coal Company's Sabine Mining Company operates
the mine.
WTU: WTU has one coal contract designed to supply approximately two
thirds of the coal requirements for the Oklaunion Power Station. This contract
has approximately 10,920,000 tons remaining to be delivered between 2001 and the
middle of 2006. The remaining one third of the coal requirements delivered in
2000 for Oklaunion were under two contracts with Wyoming suppliers. Both were
low sulfur coal contracts.
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 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.
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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 Fall 2005 and with an additional 50% of the uranium
concentrate needed for STP through Spring 2006. 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 2005. CPL and the other STP
participants have entered into flexible contracts to provide for 100% of
enrichment through Spring 2003, with additional flexible contracts to provide at
least 40% of enrichment services through Fall 2005. 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.
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Although Michigan amended its law regarding low-level waste site
development in 1994 to allow a volunteer to host a facility, little progress has
been made to date. A bill was introduced in 1996 to further address the issue
but no action was taken. Development of required legislation and progress with
the site selection process has been inhibited by many factors, and management is
unable to predict when a new disposal site for Michigan low-level waste will be
available.
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. Several bills have been submitted in the
Texas legislature in 2001 to address this issue. 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 recently adopted by certain states and proposed
at the state and federal level governing restructuring of the electric utility
industry may also affect the recovery of certain costs. See Competition and
Business Change.
Except as noted herein, AEP's subsidiaries that own or operate
generating, transmission and distribution facilities are in substantial
compliance with pollution control laws and regulations.
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 Commitments and Contingencies incorporated by reference in Items 7 and
8, respectively, for further information with respect to environmental matters.
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.
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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). 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.
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 obtain new and modified source permits or to operate
affected facilities without making significant capital expenditures.
In October 1998, the AEP System operating companies joined with certain
other 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. On March 5, 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
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. This
determination has been appealed by AEP System operating companies and
unaffiliated utilities to the U.S. Court of Appeals for the District of Columbia
Circuit.
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.
Preliminary 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. AEP operating
company estimates are as follows:
(IN MILLIONS)
AEGCo...................................................$125
APCo.....................................................365
CPL.......................................................57
CSPCo....................................................106
I&M......................................................202
KEPCo....................................................140
OPCo.....................................................606
SWEPCo....................................................28
In June 2000 OPCo announced that it was beginning a $175 million
installation of selective catalytic reduction technology (expected to be
operational in 2001) to reduce NOx emissions on its two-unit 2,600 MW Gavin
Plant. Construction of selective catalytic reduction technology on Amos Plant
Unit 3, which is jointly owned by OPCo and APCo, and APCo's Mountaineer Plant is
scheduled to begin 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.
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Since compliance costs cannot be estimated with certainty, the actual
costs to comply could be significantly different from this preliminary estimate
depending upon the compliance alternatives selected to achieve reductions in NOx
emissions. Unless any capital and operating costs of additional pollution
control equipment are recovered from customers through regulated rates and/or
future market prices for electricity where generation is deregulated, they will
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 imposes 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. Briefing has been
completed and oral argument was held in December 2000. 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 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 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. OPCo is currently seeking the termination
of 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 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, modified, or
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reconstructed source in the category. MACT standards for utility mercury
emissions are scheduled to be proposed by December 2003 and finalized by
December 2004. On February 16 and 20, 2001, utility industry groups filed
petitions for review of Federal EPA's action in the U.S. Court of Appeals for
the District of Columbia Circuit. On February 23, 2001, 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.
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 allowance requirements will be
met through accumulation, acquisition, the use of controls or fuels, or a
combination thereof.
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 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, Federal EPA proposes to regulate such precursor emissions in every
state. Under the proposal, each state must develop a regional haze control
program that imposes controls necessary to steadily reduce visibility impairment
in Class I areas on the worst days and that ensures that visibility remains good
on the best days.
The AEP System is a significant emitter of fine particulate matter and
other precursors of regional haze. Federal EPA's regional haze rule may have an
adverse financial impact on AEP as it may trigger the requirement to install
costly new pollution control devices to control emissions of fine particulate
matter and its precursors (including 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.
In January 2001, Federal EPA announced that it is considering the
issuance of proposed guidelines for states to use in setting Best Available
Retrofit Technology (BART) emission limits for power plants and other large
emission sources. The proposal would call for technologies to reduce
visibility-impairing emissions by 90 to 95 percent. 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.
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.
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- 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 provided supplemental information regarding air
releases from their facilities in the spring of 2000. Annual follow-up reports
will be submitted in April 2001.
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. If the U.S. becomes a party to the treaty, it will be bound to
reduce emissions of CO2, methane and nitrous oxides by 7% below 1990 levels and
emissions of hydrofluorcarbons, perfluorocarbons and sulfur hexafluoride 7%
below 1995 levels in the years 2008-2012. The Protocol 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. agreed to the treaty and President Clinton signed it on
November 12, 1998, the treaty has not been sent to the Senate for 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.
The treaty is currently incomplete and international negotiations that
were to resolve the outstanding issues were suspended in November 2000. The
major issues requiring resolution include:
- Participation by developing countries in the control requirements.
- Rules, procedures, methodologies and guidelines of the treaty's
emission trading and joint implementation provisions.
- Crediting for terrestrial carbon sequestration activities.
- Compliance enforcement provisions.
Negotiations are scheduled to resume in July 2001.
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 such
severe 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.
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
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the New Source Review rules, which would change New Source Review applicability
criteria by eliminating exclusions contained in the current regulation.
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 25 years that extend unit
operating lives or restore or increase unit generating capacity without a
preconstruction permit in violation of the CAA. The complaint named 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 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.
On May 10, 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. This motion is currently pending before the Court.
On February 23, 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. Management believes its
maintenance, repair and replacement activities were in conformity with the Clean
Air Act 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. CG&E and VEPCo have each entered into an
agreement in principle with the DOJ in an attempt to resolve the litigation, but
no final agreements have been announced. One of the unaffiliated utilities,
Tampa Electric Company, has reached a settlement in its litigation with the
Federal government.
The CAA authorizes civil penalties of up to $27,500 per day per violation
at each generating unit ($25,000 per day prior to January 30, 1997). Civil
penalties, if ultimately imposed by the court, and the cost of any required new
pollution control equipment, if the court accepts Federal EPA's contentions,
could be substantial.
In 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.
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In the event AEP does not prevail, any capital and operating costs of
additional pollution control equipment that may be required as well as any
penalties imposed could materially adversely affect future results of
operations, cash flows and possibly financial condition unless such costs can be
recovered through regulated rates, and where states are deregulating generation,
unbundled transition period generation rates, wires charges and future market
prices for energy.
Water Pollution Control
The Clean Water Act prohibits the discharge of pollutants to waters of
the United States from point sources except pursuant to an NPDES permit issued
by Federal EPA or a state under a federally authorized state program.
Under the Clean Water Act, effluent limitations requiring application of
the best available technology economically achievable are to be applied, and
those limitations require that no pollutants be discharged if Federal EPA finds
elimination of such discharges is technologically and economically achievable.
The Clean Water Act provides citizens with a cause of action to enforce
compliance with its pollution control requirements. Since 1982, many such
actions against NPDES permit holders have been filed. To date, no AEP System
plants have been named in such actions.
All AEP System generating plants are required to have NPDES permits and
have received them. 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 2001.
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.
Section 316(b) of the Clean Water Act requires that cooling water intake
structures reflect the best technology available (BTA) for minimizing adverse
environmental impact. Under a revised court established schedule, Federal EPA is
required to develop regulations defining adverse impacts and BTA for new sources
by November 2001. Regulations applicable to existing power plants are not
required to be issued by Federal EPA until August 2003. As part of the
rulemaking, Federal EPA has issued questionnaires to power plants, including AEP
System plants, requesting information on impingement and entrainment of aquatic
organisms from existing plant cooling water intakes. Federal EPA's rulemaking
could result in a definition of BTA that would affect any new plant construction
and 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. Implementation of these
provisions
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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
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. Management's present estimates do not anticipate material clean-up costs
for identified sites for which AEP subsidiaries have been declared PRPs.
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
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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 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 2000 and
intending to contribute a similar amount in 2001. 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.
A number of lawsuits based on EMF-related grounds have been filed against
electric utilities. A suit was filed on May 23, 1990 against I&M involving
claims that EMF from a 345 KV transmission line caused adverse health effects.
On March 23, 1998 the court ruled that the plaintiffs failed to prove that I&M
caused any of the injuries claimed by the plaintiffs. This part of the trial
court's decision was upheld on appeal. Certain issues unrelated to health
effects are pending at the trial court. No specific amount has been requested
for damages in this case. Mediation is scheduled for June, 2001.
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
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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 150 research projects that
are directed to:
- Exploring new methods of generating electricity, such as through
renewable sources (e.g., wind, solar).
- Developing more efficient methods of operating generating plants.
- 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 electrotechnologies.
- Exploring the use and application of distributed generation.
AEP System operating companies are members of the Electric Power Research
Institute (EPRI), an organization founded in 1973 that manages research and
development 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 $17,000,000 for 2000, $22,000,000 for
1999 and $23,000,000 for 1998. Of these amounts, the former CSW System paid
approximately $7,000,000 in 2000, $8,000,00 in 1999 and $8,000,000 in 1998 for
EPRI programs.
Total research and development expenditures by AEP and its subsidiaries,
including EPRI dues, were approximately $20,000,000 for the year ended December
31, 2000, $25,000,000 for the year ended December 31, 1999 and $32,000,000 for
the year ended December 31, 1998.
Item 2. PROPERTIES
At December 31, 2000, the subsidiaries of AEP owned (or leased where
indicated) generating plants with the net power capabilities (winter 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) 1,018 2,873 25(g) 3,916
SWEPCo 9 1,848 1,797 842 4,487
WTU 12(c) 377 999 16(g) 1,392
================================================================================================================================
Totals: 79 24,724 8,862 842 2,740 842 41 38,033
================================================================================================================================
----------------------------------
(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 OPCo's 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.
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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, 2000 is listed below.
CAPACITY OWNERSHIP
FACILITY COMPANY LOCATION TOTAL MW INTEREST STATUS
===================================================================================================================================
Brush II CSWEnergy Colorado 68 47% QF
Fort Lupton CSWEnergy Colorado 272 50% QF
Mulberry CSWEnergy Florida 120 50% QF
Orange Cogen CSWEnergy Florida 103 50% QF
Newgulf CSWEnergy Texas 85 100% EWG
Sweeny (a) CSWEnergy Texas 360 50% QF
-----------------------------------------------------------------------------------------------------------------------------------
Total U.S. 1,008
-----------------------------------------------------------------------------------------------------------------------------------
Medway CSWInternational UnitedKingdom 675 37.5% n/a
Altamira CSWInternational Mexico 118 50% FUCO
-----------------------------------------------------------------------------------------------------------------------------------
Total International 793
-----------------------------------------------------------------------------------------------------------------------------------
-----------------------------
(a) During 2001, additional development at the Sweeny facility is expected to
add approximately 120 MW to current capacity.
See Item 1 under Fuel Supply, for information concerning coal reserves
owned or controlled by subsidiaries of AEP.
The following table sets forth the total overhead circuit miles of
transmission and distribution lines of the AEP System 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 765,000-VOLT LINES
------------------ ------------------
AEP System (a)................... 208,809(b) 2,023
APCo.......................... 50,187 642
CPL........................... 31,125 ---
CSPCo (a)..................... 13,864 ---
I&M........................... 20,602 614
KEPCo......................... 10,385 258
OPCo ......................... 29,620 509
PSO........................... 18,565 ---
SWEPCo........................ 18,851 ---
WTU........................... 12,439 ---
----------------------
(a) Includes 766 miles of 345,000-volt jointly owned lines.
(b) Includes 73 miles of transmission lines not identified with an
operating company.
TITLES
The AEP System's electric generating stations are generally located on
lands owned in fee simple. The greater portion of the transmission and
distribution lines of the System has been constructed over lands of private
owners pursuant to easements or along public highways and streets pursuant to
appropriate statutory authority. The rights of the System in the realty on which
its facilities are located are considered by it to be adequate for its use in
the conduct of its business. Minor defects and irregularities customarily found
in title to properties of like size and character may exist, but such defects
and irregularities do not materially impair the use of the properties affected
thereby. System companies generally have the right of eminent domain whereby
they may, if necessary, acquire, perfect or secure titles to or easements on
privately-held lands used or to be used in their utility operations.
Substantially all the physical properties of the AEP System operating
companies 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.
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PEAK DEMAND
The east zone system is interconnected through 121 high-voltage
transmission interconnections with 25 neighboring electric utility systems. The
all-time and 2000 one-hour peak system demands were 25,940,000 and 23,223,000
kilowatts, respectively (which included 7,314,000 and 5,341,000 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 August 7, 2000, respectively. The net dependable
capacity to serve the system load on such date, including power available under
contractual obligations, was 23,457,000 and 23,790,000 kilowatts, respectively.
The all-time and 2000 one-hour internal peak demands were 19,952,000 and
19,167,000 kilowatts, respectively, and occurred on July 30, 1999 and January
28, 2000, respectively. The net dependable capacity to serve the system load on
such date, including power dedicated under contractual arrangements, was
23,829,000 and 24,036,000 kilowatts, respectively. The all-time one-hour
integrated and internal net system peak demands and 2000 peak demands for the
east zone generating subsidiaries are shown in the following tabulation:
ALL-TIME ONE-HOUR INTEGRATED 2000 ONE-HOUR INTEGRATED NET
NET SYSTEM PEAK DEMAND SYSTEM PEAK DEMAND
----------------------------------- ------------------------------
(IN THOUSANDS)
NUMBER OF NUMBER OF
KILOWATTS DATE KILOWATTS DATE
-------------- -------- ------------- --------
APCo........ 8,303 January 17, 1997 7,509 December 20, 2000
CSPCo....... 4,239 August 2, 2000 4,240 August 2, 2000
I&M......... 5,040 August 15, 2000 5,048 August 15, 2000
KEPCo....... 1,860 January 10, 2001 1,761 December 20, 2000
OPCo........ 7,291 June 17, 1994 6,199 August 2, 2000
ALL-TIME ONE-HOUR INTEGRATED 2000 ONE-HOUR INTEGRATED NET
NET INTERNAL PEAK DEMAND INTERNAL PEAK DEMAND
----------------------------------- ------------------------------
(IN THOUSANDS)
NUMBER OF NUMBER OF
KILOWATTS DATE KILOWATTS DATE
------------- -------- ------------- --------
APCo......... 6,908 February 5, 1996 6,558 January 28, 2000
CSPCo........ 3,804 July 30, 1999 3,499 August 31, 2000
I&M.......... 4,127 July 30, 1999 3,949 August 30, 2000
KEPCo....... 1,579 January 3, 2001 1,558 January 27, 2000
OPCo......... 5,705 June 11, 1999 5,029 June 14, 2000
The all-time and 2000 one-hour internal peak demand for the west zone
system was 14,234,000 kilowatts on August 31, 2000. The all-time one-hour
internal net system peak demands and 2000 peak demands for the west zone
generating subsidiaries are shown in the following tabulation:
ALL-TIME ONE-HOUR INTEGRATED 2000 ONE-HOUR INTEGRATED NET
NET INTERNAL PEAK DEMAND INTERNAL PEAK DEMAND
------------------------------------ ------------------------------
(IN THOUSANDS)
NUMBER OF NUMBER OF
KILOWATTS DATE KILOWATTS DATE
------------- ------ ------------- --------
CPL ......... 4,623 September 5, 2000 4,623 September 5, 2000
PSO.......... 3,823 August 30, 2000 3,823 August 30, 2000
SWEPCo....... 4,625 August 31, 2000 4,625 August 31, 2000
WTU......... 1,537 September 5, 2000 1,537 September 5, 2000
HYDROELECTRIC PLANTS
AEP has 18 facilities, of which 16 are licensed through FERC. The new
license for the Elkhart hydroelectric plant in Indiana was issued January 11,
2001 and extends for a period of thirty years. The license for the Mottville
hydroelectric plant in Michigan expires in 2003. A notice of intent to relicense
was filed in 1998. The application for new license will be filed in 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 KILOWATTS 1,020,000 1,090,000 1,250,600 1,250,600
NET CAPACITY FACTORS
2000 (c) 1.4% 50.0% 78.2% 96.1%
1999 (c) 0% 0% 88.0% 89.4%
---------------------
(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 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
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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.
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 in
connection with stack emissions. Among other alleged violations, the NOV alleges
violation of the Federal EPA-approved Ohio air pollution nuisance rule. AEP has
submitted a request for a conference to discuss the NOV with Region V
representatives.
Municipal Franchise Fee Litigation: CPL has been involved in litigation
regarding municipal franchise fees in Texas as a result of a class action suit
filed by the City of San Juan, Texas in 1996. The City of San Juan claims CPL
underpaid municipal franchise fees and seeks damages of up to $300 million plus
attorney's fees. CPL filed a counterclaim for overpayment of franchise fees.
During 1997, 1998 and 1999 the litigation moved procedurally through the
Texas Court System and was sent to mediation without resolution.
In 1999 a class notice was mailed to each of the cities served by CPL.
Over 90 of the 128 cities declined to participate in the lawsuit. However, CPL
has pledged that if any final, non-appealable court decision awards a judgment
against CPL for a franchise underpayment, CPL will extend the principles of that
decision, with regard to any franchise underpayment, to the cities that declined
to participate in the litigation. In December 1999, the court ruled that the
class of plaintiffs would consist of approximately 30 cities. A trial date for
June 2001 has been set.
Although management believes that it has substantial defenses to the
cities' claims and intends to defend itself against the cities' claims and
pursue its counterclaim vigorously, management cannot predict the outcome of
this litigation or its impact on results of operations, cash flows or financial
condition.
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
38
46
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 plans to appeal the decision.
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.
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, 2001.
NAME AGE OFFICE (a)
---- --- ----------
E. Linn Draper, Jr................... 59 Chairman of the Board, President and Chief Executive Officer of AEP and of the
Service Corporation
Thomas V. Shockley, III.............. 55 Vice Chairman of the Service Corporation
Paul D. Addis........................ 47 Executive Vice President-Wholesale/Energy Services of the Service Corporation
Donald M. Clements, Jr............... 51 Executive Vice President-Corporate Development of the Service
Corporation
Henry W. Fayne....................... 54 Executive Vice President-Finance and Analysis of the Service Corporation
William J. Lhota..................... 61 Executive Vice President- Energy Delivery of the Service Corporation
Susan Tomasky........................ 47 Executive Vice President-Legal, Policy and Corporate Communications of the Service
Corporation
J. H. Vipperman...................... 60 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.
Addis and Shockley and Ms. Tomasky. Prior to joining the Service
Corporation in February 1997 in his present position, Mr. Addis was
Executive Vice President (1992-1993) and President (1993-January 1997) of
Louis Dreyfus Electric Power, Inc. and President of Duke/Louis Dreyfus
LLC (1995-January 1997). Mr. Addis became an executive officer of AEP
effective January 1, 2000. Prior to joining the Service Corporation in
July 1998 as Senior Vice President, Ms. Tomasky was a partner with the
law firm of Hogan & Hartson (August 1997-July 1998) and General Counsel
of the Federal Energy Regulatory Commission (May 1993-August 1997). Ms.
Tomasky became an executive officer of AEP effective with her promotion
to Executive Vice President on January 26, 2000. 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
Senior Vice President of CSW (1980-1997). 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.
39
47
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, 2001, 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........ 59 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
Thomas V. Shockley, III... 55 Director and Vice President of APCo, CPL, I&M, OPCo and SWEPCo 2000-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............ 54 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-Present
Vice President of APCo, I&M and OPCo 1998-Present
Vice President and Chief Financial Officer of AEP 1998-Present
Executive Vice President-Finance and Analysis of the Service Corporation 2000-Present
Executive Vice President-Financial Services of the
Service Corporation 1998-2000
Senior Vice President-Corporate Planning & Budgeting
of the Service Corporation 1995-1998
William J. Lhota.......... 61 Director of CPL and SWEPCo 2000-Present
Director of APCo 1990-Present
Director of I&M and OPCo 1989-Present
President and Chief Operating Officer of CPL and SWEPCo 2000-Present
President and Chief Operating Officer of APCo, I&M and OPCo 1996-Present
Executive Vice President-Energy Delivery of the Service Corporation 2000-Present
Executive Vice President of the Service Corporation 1993-2000
Susan Tomasky............. 47 Director and Vice President of APCo, CPL, I&M, OPCo and SWEPCo 2000-Present
Executive Vice President-Legal, Policy and Corporate Communications and
General Counsel of the Service Corporation 2000-Present
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
40
48
NAME AGE POSITION (a)(b) PERIOD
---- --- --------------- ------
J. H. Vipperman........... 60 Director of CPL and SWEPCo 2000-Present
Director of APCo 1985-Present
Director of I&M and OPCo 1996-Present
Vice President of CPL and SWEPCo 2000-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., and Mr. Lhota is a
director of Huntington Bancshares Incorporated and State Auto Financial
Corporation.
(b) Dr. Draper, Messrs. Fayne, Lhota, 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. AEP Common Stock is traded principally on the New York Stock
Exchange. The following table sets forth for the calendar periods indicated the
high and low sales prices for the Common Stock as reported on the New York Stock
Exchange Composite Tape and the amount of cash dividends paid per share of
Common Stock.
PER SHARE
MARKET PRICE
-------------------------------
QUARTER ENDED HIGH LOW DIVIDEND
------------- ---- --- --------
March 1999................................................... 48-3/16 39-5/16 .60
June 1999.................................................... 44-1/16 37-7/16 .60
September 1999............................................... 37-7/8 33-1/2 .60
December 1999................................................ 35-13/16 30-9/16 .60
March 2000................................................... 34-15/16 25-15/16 .60
June 2000.................................................... 38-1/2 29-7/16 .60
September 2000............................................... 40 29-15/16 .60
December 2000................................................ 48-15/16 36-3/16 .60
At December 31, 2000, AEP had approximately 160,000 shareholders of
record.
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 2000 and 1999 are
incorporated by reference to the material under Statement of Retained Earnings
in the 2000 Annual Reports.
41
49
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 2000 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 2000 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 2000
Annual Reports.
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 2000 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.
42
50
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 of the definitive proxy
statement of AEP for the 2001 annual meeting of shareholders, to be filed within
120 days after December 31, 2000. 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 2001 annual meeting of
stockholders, to be filed within 120 days after December 31, 2000. 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 2001 annual meeting of
stockholders, to be filed within 120 days after December 31, 2000. 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 with I&M, their ages as of March 12, 2001, 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.............. 49 Director 1997-Present
Vice President - Fort Wayne Distribution Operations 2000-Present
Indiana Region Manager 1997-2000
Fort Wayne District Manager 1994-1997
Marc E. Lewis........... 46 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..... 51 Director 2000-Present
General Manager, Community Services 2000-Present
Manager, Customer Services Operations 1997-2000
Director, Customer Services 1994-1997
John R. Sampson......... 48 Director and Vice President 1999-Present
Indiana & Michigan State President 1999-Present
Site Vice President, Cook Nuclear Plant 1998-1999
Plant Manager, Cook Nuclear Plant 1996-1998
Jackie S. Siefker....... 47 Director 2000-Present
Manager, Distribution Systems 2000-Present
District Manager 1995-2000
D. B. Synowiec.......... 57 Director 1995-Present
Plant Manager, Rockport Plant 1990-Present
W. E. Walters........... 53 Director 1991-Present
Michiana Region Manager 1994-2000
Director of Projects 2000-Present
-----------------
(a) Positions are with I&M unless otherwise indicated.
43
51
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 2001 annual meeting of shareholders to be filed
within 120 days after December 31, 2000.
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 2001 annual meeting of
stockholders, to be filed within 120 days after December 31, 2000.
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 statement of APCo for the 2001 annual meeting of
stockholders, to be filed within 120 days after December 31, 2000.
The following table sets forth the aggregate cash and other compensation
for services rendered for the fiscal years of 2000, 1999 and 1998 paid or
awarded to the presidents of CPL and SWEPCo.
Summary Compensation Table
ANNUAL
COMPENSATION
---------------------------------------------
OTHER
SALARY BONUS ANNUAL
NAME AND PRINCIPAL POSITION YEAR ($) ($) COMPENSATION
---------------------------------------------------------------------------------------------------
J. GONZALO SANDOVAL - General 2000 143,323 38,153 0
manager/president of CPL (3) 1999 138,863 31,268 0
1998 138,115 34,955 0
MICHAEL H. MADISON - President of 2000 179,922 78,937 0
SWEPCo (3) 1999 186,944 91,065 5,544
1998 178,953 87,380 28,914
LONG-TERM
COMPENSATION
----------------------
AWARDS PAYOUTS
------ -------
SECURITIES LTIP ALL OTHER
UNDERLYING PAYOUTS COMPENSATION
NAME AND PRINCIPAL POSITION OPTIONS (#) ($)(1) ($)(2)
-------------------------------------------------------------------------------------
J. GONZALO SANDOVAL - General 6,250 14,656 7,068
manager/president of CPL (3) 0 19,661 7,200
0 9,961 6,580
MICHAEL H. MADISON - President of 15,000 192,444 198,211
SWEPCo (3) 0 19,661 8,103
0 9,961 7,900
------------------------
(1) The awards reflected in this column are the value of restricted shares
paid out under CSW's Long-Term Incentive Plan and, in the case of Mr.
Madison, performance share units. Upon vesting, shares of AEP Common
Stock were reissued without restrictions. The amounts reported in the
Summary Compensation Table represent the market value of the shares at
the date of grant.
(2) Detail of the 2000 amounts in the All Other Compensation column is shown
below.
Item Mr. Sandoval Mr. Madison
---- ------------ -----------
Savings Plan Matching Contributions.................. $7,068 $7,650
Personal Liability Insurance......................... 0 761
Change-in Control Payment............................ 0 179,000
Vehicle Allowance.................................... 0 10,800
- ------
Total All Other Compensation...................... $7,068 $198,211
====== ========
(3) Messrs. Sandoval and Madison resigned their positions on June 28, 2000,
but remained employees of the AEP System.
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52
Option Grants in 2000
INDIVIDUAL GRANTS
------------------------------------------------------------------------------------
NUMBER OF PERCENT OF
SECURITIES TOTAL OPTIONS
UNDERLYING GRANTED TO GRANT DATE
OPTIONS GRANTED EMPLOYEES IN EXERCISE OR BASE PRESENT VALUE
NAME (#) (1) 2000 (2) PRICE ($/SH) EXPIRATION DATE ($) (3)
---------------------- ----------------- --------------- ------------------- ------------------- --------------
J. Gonzalo Sandoval 6,250 0.1% 35.625 09-20-2010 36,783
Michael H. Madison 15,000 0.2% 35.625 09-20-2010 88,280
---------------------
(1) Options were granted on September 20, 2000, pursuant to the AEP 2000
Long-Term Incentive Plan. All options granted on this date have an
exercise price equal to the closing price of AEP Common Stock on the New
York Stock Exchange Composite Transactions Tape on September 20, 2000.
These options will vest in equal increments, annually, over a three-year
period beginning on January 1, 2002. Options also fully vest upon
termination due to retirement after one year from the grant date or due
to disability or death and expire five years thereafter, or on their
scheduled expiration date if earlier. Options expire upon termination of
employment for reasons other than retirement, disability or death, unless
the Human Resources Committee determines that circumstances warrant
continuation of the options for up to five years. Options are
nontransferable.
(2) A total of 6,046,000 options were granted in 2000.
(3) Value was calculated using the Black-Scholes option valuation model. The
actual value, if any, ultimately realized depends on the market value of
AEP's Common Stock at a future date. Significant assumptions are shown
below:
Stock Price Volatility 24.75% Dividend Yield 6.02%
Risk-Free Rate of Return 6.50% Option Term 10 years
Aggregated Option Exercises in 2000 and Year-End Option Values
SHARE NUMBER OF SECURITIES UNDERLYING
ACQUIRED ON VALUE UNEXERCISED OPTIONS AT 12-31-00 (#)
EXERCISE REALIZED ------------------------------------
NAME (#) (1) ($) (1) EXERCISABLE UNEXERCISABLE
---------------------------- ------------- ----------- -------------- -----------------
J. Gonzalo Sandoval -- -- 1,750 6,250
Michael H. Madison -- -- 6,281 15,000
VALUE OF UNEXERCISED IN-THE-MONEY
OPTIONS AT 12-31-00 ($) (2)
------------------------------------
NAME EXERCISABLE UNEXERCISABLE
---------------------------- ---------------- ----------------
J. Gonzalo Sandoval 0 67,969
Michael H. Madison 52,448 163,125
---------------------
(1) Neither of these officers exercised options during 2000.
(2) Based on the difference between the closing price of AEP Common Stock on
the New York Stock Exchange Composite Transactions Tape on December 29,
2000 ($46.50) and the option exercise price. "In-the-money" means the
market price of the stock is greater than the exercise price of the
option on the date indicated.
Cash Balance Retirement Plan
CPL and SWEPCo maintain the Cash Balance Plan for eligible employees. In
addition, these companies maintain the Special Executive Retirement Plan (SERP),
a non-qualified plan that provides benefits that cannot be payable under the
Cash Balance Plan because of maximum limitations imposed on such plans by the
Internal Revenue Code. Under the cash balance formula, each participant has an
account for recordkeeping purposes only, to which dollar amount credits are
allocated annually based on a percentage of the participant's pay. Pay for the
Cash Balance Plan includes base pay, bonuses, overtime, and commissions. The
applicable percentage is determined by the age and years of vesting service the
participant has as of December 31 of each year.
45
53
The following table shows the percentage used to determine dollar amount
credits at the age and years of service indicated:
SUM OF AGE PLUS
YEARS OF SERVICE APPLICABLE PERCENTAGE
---------------- ---------------------
<30 3.0%
30-39 3.5%
40-49 4.5%
50-59 5.5%
60-69 7.0%
70 or more 8.5%
As of December 31, 2000, the sum of age plus years of service of Messrs.
Sandoval and Madison were 78 and 81, respectively.
At retirement or other termination of employment, an amount equal to the
vested balance (including qualified and SERP benefit) then credited to the
account is payable to the participant in the form of an immediate or deferred
lump sum or annuity. Benefits (both from the Cash Balance Plan and the SERP)
under the cash balance formula are not subject to reduction for Social Security
benefits or other offset amounts. The estimated annual benefits payable to
Messrs. Sandoval and Madison as a single life annuity at age 65 under the Cash
Balance Plan and the SERP are $93,508 for Mr. Sandoval and $122,555 for Mr.
Madision.
These amounts are based on the following assumptions:
- Salary used is base pay paid for calendar year 2000 assuming no
future increases plus bonus at 2000 target level.
- Conversion of the lump-sum cash balance to a single life annuity
at age 65, based on an interest rate of 5.78% and the 1983 Group
Annuity Mortality Table.
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 2001 annual meeting of
shareholders to be filed within 120 days after December 31, 2000.
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 2001 annual meeting of stockholders, to be filed within 120 days after
December 31, 2000.
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 2001
annual meeting of stockholders, to be filed within 120 days after December 31,
2000.
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, 2001, by each director and nominee of I&M as of March 12, 2001 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.
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54
STOCK
-----
NAME SHARES(a) UNITS(b) TOTAL
---- --------- -------- -----
Karl G. Boyd................................................. 2,137 308 2,445
E. Linn Draper, Jr........................................... 9,535(c) 106,181 115,716
Henry W. Fayne............................................... 5,590(d) 11,163 16,753
Marc E. Lewis................................................ 898 -- 898
William J. Lhota............................................. 18,854(c)(d) 16,249 35,103
Susanne M. Moorman........................................... 685 -- 685
John R. Sampson.............................................. 430 338 768
Thomas V. Shockley, III...................................... 93,965(e)(f) -- 93,965
Jackie S. Siefker............................................ 3,093 -- 3,093
David B. Synowiec............................................ 2,505 423 2,928
Susan Tomasky................................................ 1,744 98 1,842
Joseph H. Vipperman.......................................... 12,460(c)(d) 4,871 17,331
William E. Walters........................................... 7,441 334 7,775
All Directors and Executive Officers......................... 244,568(d)(g) 139,965 384,533
-------------------------
(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
NAME PLAN (SHARE EQUIVALENTS)
---- ------------------------
Mr. Boyd.................................... 2,137
Dr. Draper.................................. 3,947
Mr. Fayne................................... 5,014
Mr. Lewis................................... 898
Mr. Lhota................................... 16,674
Ms. Moorman................................. 685
Mr. Sampson................................ 430
AEP RETIREMENT SAVINGS
NAME PLAN (SHARE EQUIVALENTS)
---- ------------------------
Mr. Shockley...................................... 6,234
Ms. Siefker....................................... 3,093
Mr. Synowiec...................................... 2,505
Ms. Tomasky....................................... 1,744
Mr. Vipperman..................................... 11,626
Mr. Walters....................................... 7,441
All Directors and Executive Officers.................... 62,428
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.
(b) This column includes amounts deferred in stock units and held under AEP's
officer benefit plans.
(c) Includes the following numbers of shares held in joint tenancy with a
family member: Dr. Draper, 5,588; Mr. Lhota, 2,180; and Mr. Vipperman,
76.
(d) Does not include, for Messrs. Fayne, Lhota and Vipperman, 85,231 shares
in the American Electric Power System Educational Trust Fund over which
Messrs. Fayne, Lhota and Vipperman share voting and investment power as
trustees (they disclaim beneficial ownership). The amount of shares shown
for all directors and executive officers as a group includes these shares
(e) Includes the following numbers of shares held by family members over
which beneficial ownership is disclaimed: Mr. Shockley, 496.
(f) Includes 49, 938 shares for Mr. Shockley attributable to options
exercisable within 60 days.
(g) 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).
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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, 2000, 1999 and 1998; Statements of Retained
Earnings for the years ended December 31, 2000, 1999 and 1998;
Statements of Cash Flows for the years ended December 31, 2000, 1999
and 1998; Balance Sheets as of December 31, 2000 and 1999;
Statements of Capitalization as of December 31, 2000 and 1999;
Combined Notes to Financial Statements.
AEP and its subsidiaries consolidated:
Consolidated Statements of Income for the years ended December 31,
2000, 1999 and 1998; Consolidated Balance Sheets as of December 31,
2000 and 1999; Consolidated Statements of Cash Flows for the years
ended December 31, 2000, 1999 and 1998; Consolidated Statements of
Common Shareholders' Equity for the years ended December 31, 2000,
1999 and 1998; Combined Notes to Financial Statements; Schedule of
Consolidated Cumulative Preferred Stocks of Subsidiaries at December
31, 2000 and 1999; Schedule of Consolidated Long-term Debt of
Subsidiaries at December 31, 2000 and 1999; Independent Auditors'
Reports.
APCo, CPL, CSPCo, I&M, OPCo, PSO and SWEPCo:
Independent Auditors' Report(s); Consolidated Statements of Income
for the years ended December 31, 2000, 1999 and 1998; Consolidated
Balance Sheets as of December 31, 2000 and 1999; Consolidated
Statements of Cash Flows for the years ended December 31, 2000, 1999
and 1998; Consolidated Statements of Retained Earnings for the years
ended December 31, 2000, 1999 and 1998; Consolidated Statements of
Capitalization as of December 31, 2000 and 1999; Schedule of
Consolidated Long-term Debt as of December 31, 2000 and 1999;
Combined Notes to Financial Statements.
KEPCo and WTU:
Independent Auditors' Report(s); Statements of Income for the years
ended December 31, 2000, 1999 and 1998; Statements of Retained
Earnings for the years ended December 31, 2000, 1999 and 1998;
Statements of Cash Flows for the years ended December 31, 2000, 1999
and 1998; Balance Sheets as of December 31, 2000 and 1999;
Statements of Capitalization as of December 31, 2000 and 1999;
Schedule of Long-term Debt as of December 31, 2000 and 1999;
Combined Notes to Financial Statements.
2. FINANCIAL STATEMENT SCHEDULES:
Financial Statement Schedules are listed in the Index to Financial
Statement Schedules (Certain schedules have been omitted because the
required information is contained in the notes to financial
statements or because such schedules are not required or are not
applicable).
S-1
Independent Auditors' Report S-2
3. EXHIBITS:
Exhibits for AEGCo, AEP, APCo, 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,
2000.
48
56
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
AMERICAN ELECTRIC POWER COMPANY, INC.
BY: /S/ H. W. FAYNE
---------------------------------------
(H. W. FAYNE, VICE PRESIDENT
AND CHIEF FINANCIAL OFFICER)
Date: March 20, 2001
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/ H. W. FAYNE Vice President and March 20, 2001
----------------------------------------- Chief Financial Officer
(H. W. FAYNE)
(III) PRINCIPAL ACCOUNTING OFFICER:
/S/ L. V. ASSANTE Deputy Controller March 20, 2001
-----------------------------------------
(L. V. ASSANTE)
(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
*MORRIS TANENBAUM March 20, 2001
*By: /S/ H. W. FAYNE
-------------------------------------
(H. W. FAYNE, ATTORNEY-IN-FACT)
49
57
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/ A. A. PENA
-------------------------------------------
(A. A. PENA, VICE PRESIDENT AND TREASURER)
Date: March 20, 2001
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/ A. A. PENA Vice President, Treasurer, March 20, 2001
------------------------------------------- And Director
(A. A. PENA)
(iii) PRINCIPAL ACCOUNTING OFFICER:
/S/ L. V. ASSANTE Deputy Controller March 20, 2001
-------------------------------------------
(L. V. ASSANTE)
(iv) A MAJORITY OF THE DIRECTORS:
*HENRY W. FAYNE
*WM. J. LHOTA
*THOMAS V. SHOCKLEY, III
*SUSAN TOMASKY
*J. H. VIPPERMAN
March 20, 2001
*By: /S/ A. A. PENA
------------------------------------------
(A. A. PENA, ATTORNEY-IN-FACT)
50
58
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE
UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE
TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.
INDIANA MICHIGAN POWER COMPANY
BY: /S/ A. A. PENA
---------------------------------------------
(A. A. PENA, VICE PRESIDENT AND TREASURER)
Date: March 20, 2001
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/ A. A. PENA Vice President and Treasurer March 20, 2001
------------------------------------------------
(A. A. PENA)
(iii) PRINCIPAL ACCOUNTING OFFICER:
/S/ L. V. ASSANTE Deputy Controller March 20, 2001
------------------------------------------------
(L. V. ASSANTE)
(iv) A MAJORITY OF THE DIRECTORS:
*K. G. BOYD
* HENRY W. FAYNE
*MARC E. LEWIS
*WM. J. LHOTA
*SUSANNE M. MOORMAN
*JOHN R. SAMPSON
*THOMAS V. SHOCKLEY, III
*JACKIE S. SIEFKER
*D. B. SYNOWIEC
*SUSAN TOMASKY
*J. H. VIPPERMAN
*W. E. WALTERS
*By: /s/ A. A. Pena March 20, 2001
------------------------------------------------
(A. A. PENA, ATTORNEY-IN-FACT)
51
59
[THIS PAGE INTENTIONALLY LEFT BLANK]
60
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
61
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,
2000 and 1999, and for each of the three years in the period ended December 31,
2000, and have issued our reports thereon dated February 26, 2001; such
financial statements and reports are included in the 2000 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 years ended December 31, 1999 and 1998 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 years ended December 31, 1999 and
1998. 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 26, 2001
S-2
62
==========================================================================================================
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
==========================================================================================================
COLUMN A COLUMN B COLUMN C
==========================================================================================================
ADDITIONS
----------------------------
BALANCE AT CHARGED TO CHARGED TO
BEGINNING COSTS AND OTHER
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS
----------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2000.............. $17,066 $14,878 $ 423(a)
======= ======= =========
Year Ended December 31, 1999.............. $14,841 $24,165 $15,788(a)
======= ======= =======
Year Ended December 31, 1998.............. $ 9,049 $28,809 $ 8,330(a)
======= ======= ========
============================================================================================
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
============================================================================================
COLUMN A COLUMN D COLUMN E
============================================================================================
BALANCE AT
END OF
DESCRIPTION DEDUCTIONS PERIOD
--------------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2000.............. $21,323(b) $11,044
======= =======
Year Ended December 31, 1999.............. $37,728(b) $17,066
======= =======
Year Ended December 31, 1998.............. $31,347(b) $14,841
======= =======
----------------
(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
==========================================================================================================
ADDITIONS
----------------------------
BALANCE AT CHARGED TO CHARGED TO
BEGINNING COSTS AND OTHER
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS
----------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2000.............. $2,609 $6,592 $1,526(a)
====== ====== ======
Year Ended December 31, 1999.............. $2,234 $5,492 $1,995(a)
====== ====== ======
Year Ended December 31, 1998.............. $1,333 $5,093 $1,306(a)
====== ====== ======
==========================================================================================
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
==========================================================================================
COLUMN A COLUMN D COLUMN E
==========================================================================================
BALANCE AT
END OF
DESCRIPTION DEDUCTIONS PERIOD
------------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2000.............. $8,139(b) $2,588
====== ======
Year Ended December 31, 1999.............. $7,112(b) $2,609
====== ======
Year Ended December 31, 1998.............. $5,498(b) $2,234
====== ======
-----------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
========================================================================================================
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
========================================================================================================
COLUMN A COLUMN B COLUMN C
========================================================================================================
ADDITIONS
----------------------------
BALANCE AT CHARGED TO CHARGED TO
BEGINNING COSTS AND OTHER
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS
--------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2000.............. $ -- $1,675 $ -- (a)
======== ====== ========
Year Ended December 31, 1999.............. $ -- $ -- $ -- (a)
======== ====== ========
Year Ended December 31, 1998.............. $ -- $ -- $ -- (a)
======== ====== ========
===========================================================================================
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
===========================================================================================
COLUMN A COLUMN D COLUMN E
===========================================================================================
BALANCE AT
END OF
DESCRIPTION DEDUCTIONS PERIOD
-------------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2000.............. $ -- (b) $1,675
======== ======
Year Ended December 31, 1999.............. $ -- (b) $ --
======== ======
Year Ended December 31, 1998.............. $ -- (b) $ --
======== ======
---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
S-3
63
===========================================================================================================
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
===========================================================================================================
COLUMN A COLUMN B COLUMN C
===========================================================================================================
ADDITIONS
------------------------------------
BALANCE AT CHARGED TO CHARGED TO
BEGINNING COSTS AND OTHER
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS
---------------------------------------------------- ------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2000.............. $3,045 $2,082 $ 1,405(a)
====== ====== ========
Year Ended December 31, 1999.............. $2,598 $3,334 $10,782(a)
====== ====== =======
Year Ended December 31, 1998.............. $1,058 $7,551 $ 5,278(a)
====== ====== ========
========================================================================================
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
========================================================================================
COLUMN A COLUMN D COLUMN E
========================================================================================
BALANCE AT
END OF
DESCRIPTION DEDUCTIONS PERIOD
----------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2000.............. $ 5,873(b) $ 659
======== =======
Year Ended December 31, 1999.............. $13,669(b) $3,045
======= ======
Year Ended December 31, 1998.............. $11,289(b) $2,598
======= ======
--------------------
(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
===========================================================================================================
ADDITIONS
------------------------------------
BALANCE AT CHARGED TO CHARGED TO
BEGINNING COSTS AND OTHER
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS
---------------------------------------------------- ------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2000.............. $1,848 $ (235) $ 907(a)
====== ====== ======
Year Ended December 31, 1999.............. $2,027 $3,966 $1,367(a)
====== ====== ======
Year Ended December 31, 1998.............. $1,188 $4,630 $ 221(a)
====== ====== ======
=======================================================================================
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
=======================================================================================
COLUMN A COLUMN D COLUMN E
=======================================================================================
BALANCE AT
END OF
DESCRIPTION DEDUCTIONS PERIOD
---------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2000.............. $1,761(b) $ 759
====== ======
Year Ended December 31, 1999.............. $5,512(b) $1,848
====== ======
Year Ended December 31, 1998.............. $4,012(b) $2,027
====== ======
---------------------
(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
===========================================================================================================
ADDITIONS
------------------------------------
BALANCE AT CHARGED TO CHARGED TO
BEGINNING COSTS AND OTHER
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS
---------------------------------------------------- ------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2000.............. $637 $ 187 $ 9(a)
==== ====== ====
Year Ended December 31, 1999.............. $848 $1,032 $467(a)
==== ====== ====
Year Ended December 31, 1998.............. $525 $1,280 $392(a)
==== ====== ====
=========================================================================================
KENTUCKY POWER COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
=========================================================================================
COLUMN A COLUMN D COLUMN E
=========================================================================================
BALANCE AT
END OF
DESCRIPTION DEDUCTIONS PERIOD
---------------------------------------------------- ------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2000.............. $ 551(b) $282
======= ====
Year Ended December 31, 1999.............. $1,710(b) $637
====== ====
Year Ended December 31, 1998.............. $1,349(b) $848
====== ====
---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
S-4
64
===========================================================================================================
OHIO POWER COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
===========================================================================================================
COLUMN A COLUMN B COLUMN C
===========================================================================================================
ADDITIONS
------------------------------------
BALANCE AT CHARGED TO CHARGED TO
BEGINNING COSTS AND OTHER
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS
---------------------------------------------------- ------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2000.............. $2,223 $ 472 $ 778(a)
====== ====== ======
Year Ended December 31, 1999.............. $1,678 $4,730 $1,273(a)
====== ====== ======
Year Ended December 31, 1998.............. $2,501 $3,255 $ 941(a)
====== ====== ======
============================================================================================
OHIO POWER COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
============================================================================================
COLUMN A COLUMN D COLUMN E
============================================================================================
BALANCE AT
END OF
DESCRIPTION DEDUCTIONS PERIOD
--------------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2000.............. $2,419(b) $1,054
====== ======
Year Ended December 31, 1999.............. $5,458(b) $2,223
====== ======
Year Ended December 31, 1998.............. $5,019(b) $1,678
====== ======
---------------------
(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
=============================================================================================================
ADDITIONS
------------------------------------
BALANCE AT CHARGED TO CHARGED TO
BEGINNING COSTS AND OTHER
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS
-------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2000.............. $ -- $ 467 $ -- (a)
======== ======= ========
Year Ended December 31, 1999.............. $ -- $ -- $ -- (a)
======== ======== ========
Year Ended December 31, 1998.............. $ -- $ -- $ -- (a)
======== ======== ========
========================================================================================
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
========================================================================================
COLUMN A COLUMN D COLUMN E
========================================================================================
BALANCE AT
END OF
DESCRIPTION DEDUCTIONS PERIOD
---------------------------------------------------- -----------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2000.............. $ -- (b) $ 467
======== ======
Year Ended December 31, 1999.............. $ -- (b) $ --
======== ======
Year Ended December 31, 1998.............. $ -- (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
============================================================================================================
ADDITIONS
------------------------------------
BALANCE AT CHARGED TO CHARGED TO
BEGINNING COSTS AND OTHER
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS
---------------------------------------------------- -------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2000.............. $4,428 $ 911 $(4,428)(a)
====== ======= ===========
Year Ended December 31, 1999.............. $3,269 $5,415 $ -- (a)
====== ====== ==========
Year Ended December 31, 1998.............. $2,216 $4,547 $ -- (a)
====== ====== ==========
==========================================================================================
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
==========================================================================================
COLUMN A COLUMN D COLUMN E
==========================================================================================
BALANCE AT
END OF
DESCRIPTION DEDUCTIONS PERIOD
------------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2000.............. $ -- (b) $ 911
======= ======
Year Ended December 31, 1999.............. $ 4,256(b) $4,428
======= ======
Year Ended December 31, 1998.............. $ 3,494(b) $3,269
======= ======
---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
S-5
65
===========================================================================================================
WEST TEXAS UTILITIES COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
===========================================================================================================
COLUMN A COLUMN B COLUMN C
===========================================================================================================
ADDITIONS
------------------------------------
BALANCE AT CHARGED TO CHARGED TO
BEGINNING COSTS AND OTHER
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS
---------------------------------------------------- ------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2000.............. $186 $1,499 $46(a)
==== ====== ===
Year Ended December 31, 1999.............. $497 $ (66) $43(a)
==== ======= ===
Year Ended December 31, 1998.............. $ 73 $ 616 $40(a)
===== ======= ===
=======================================================================================
WEST TEXAS UTILITIES COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
=======================================================================================
COLUMN A COLUMN D COLUMN E
=======================================================================================
BALANCE AT
END OF
DESCRIPTION DEDUCTIONS PERIOD
---------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2000.............. $1,443(b) $288
====== ====
Year Ended December 31, 1999.............. $ 288(b) $186
====== ====
Year Ended December 31, 1998.............. $ 232(b) $497
======= ====
---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
S-6
66
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).
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 2000 Annual Report
(for the fiscal year ended December 31, 2000) 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)].
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,
E-1
67
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
AEP++ (continued)
Exhibit 10(b); and Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1988, File No. 1-3525,
Exhibit 10(b)(2)].
10(c) -- Copy of Lease Agreements, dated as of December 1,
1989, between AEGCo or I&M and Wilmington Trust Company,
as amended [Registration Statement No. 33-32752, Exhibits
28(c)(1)(C), 28(c)(2)(C), 28(c)(3)(C), 28(c)(4)(C),
28(c)(5)(C) and 28(c)(6)(C); Registration Statement No.
33-32753, Exhibits 28(a)(1)(C), 28(a)(2)(C), 28(a)(3)(C),
28(a)(4)(C), 28(a)(5)(C) and 28(a)(6)(C); and Annual
Report on Form 10-K of AEGCo for the fiscal year ended
December 31, 1993, File No. 0-18135, Exhibits
10(c)(1)(B), 10(c)(2)(B), 10(c)(3)(B), 10(c)(4)(B),
10(c)(5)(B) and 10(c)(6)(B); Annual Report on Form 10-K
of I&M for the fiscal year ended December 31, 1993, File
No. 1-3570, Exhibits 10(e)(1)(B), 10(e)(2)(B),
10(e)(3)(B), 10(e)(4)(B), 10(e)(5)(B) and 10(e)(6)(B)].
10(d) -- Lease Agreement dated January 20, 1995 between OPCo
and JMG Funding, Limited Partnership, and amendment
thereto (confidential treatment requested) [Annual Report
on Form 10-K of OPCo for the fiscal year ended December
31, 1994, File No. 1-6543, Exhibit 10(l)(2)].
10(e) -- Modification No. 1 to the AEP System Interim Allowance
Agreement, dated July 28, 1994, among APCo, CSPCo, I&M,
KEPCo, OPCo and the Service Corporation [Annual Report on
Form 10-K of AEP for the fiscal year ended December 31,
1996, File No. 1-3525, Exhibit 10(l)].
10(f)(1) -- Agreement and Plan of Merger, dated as of December 21,
1997, By and Among American Electric Power Company, Inc.,
Augusta Acquisition Corporation and Central and South
West Corporation [Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1997, File No. 1-3525,
Exhibit 10(f)].
10(f)(2) -- Amendment No. 1, dated as of December 31, 1999, to the
Agreement and Plan of Merger [Current Report on Form 8-K
of AEP dated December 15, 1999, File No. 1-3525, Exhibit
10].
+10(g)(1) -- AEP Deferred Compensation Agreement for certain
executive officers [Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1985, File No. 1-3525,
Exhibit 10(e)].
+10(g)(2) -- Amendment to AEP Deferred Compensation Agreement for
certain executive officers [Annual Report on Form 10-K of
AEP for the fiscal year ended December 31, 1986, File No.
1-3525, Exhibit 10(d)(2)].
+10(h) -- AEP Accident Coverage Insurance Plan for directors
[Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1985, File No. 1-3525, Exhibit 10(g)].
*+10(i)(1) -- AEP Deferred Compensation and Stock Plan for
Non-Employee Directors, as amended June 1, 2000.
*+10(i)(2) -- AEP Stock Unit Accumulation Plan for Non-Employee
Directors, as amended June 1, 2000.
*+10(j)(1)(A) -- AEP System Excess Benefit Plan, Amended and Restated
as of January 1, 2001.
+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 January 1, 2001
(Non-Qualified).
+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)].
E-2
68
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
AEP++ (continued)
+10(m) -- AEP System Survivor Benefit Plan, effective January
27, 1998 [Quarterly Report on Form 10-Q of AEP for the
quarter ended September 30, 1998, File No. 1-3525,
Exhibit 10].
+10(n) -- Letter agreement between AEP and Donald M. Clements,
Jr. dated August 19, 1994 [Annual Report on Form 10-K of
AEP for the fiscal year ended December 31, 1998, File No.
1-3525, Exhibit 10(n)].
+10(o) -- AEP Senior Executive Severance Plan for Merger with
Central and South West Corporation, effective March 1,
1999 [Annual Report on Form 10-K of AEP for the fiscal
year ended December 31, 1998, File No. 1-3525, Exhibit
10(o)].
+10(p) -- AEP Change In Control Agreement [Annual Report on Form
10-K of AEP for the fiscal year ended December 31, 1999,
File No. 1-3525, Exhibit 10(p)].
+10(q) -- AEP System 2000 Long-Term Incentive Plan [Proxy
Statement of AEP, March 10, 2000].
*+10(r)(1) -- Employment Agreement between Paul Addis and the
Service Corporation dated January 17, 1996.
*+10(r)(2) -- Amending Agreement dated July 30, 1998 to Employment
Agreement of Paul Addis.
*+10(r)(3) -- AEP Energy Services Incentive Compensation Plan.
*+10(r)(4) -- AEP Energy Services Phantom Equity Plan.
*+10(s) -- Memorandum of agreement between Susan Tomasky and the
Service Corporation dated January 3, 2001.
*13 -- Copy of those portions of the AEP 2000 Annual Report
(for the fiscal year ended December 31, 2000) 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.
APCO++
3(a) -- Copy of Restated Articles of Incorporation of APCo,
and amendments thereto to November 4, 1993 [Registration
Statement No. 33-50163, Exhibit 4(a); Registration
Statement No. 33-53805, Exhibits 4(b) and 4(c)].
3(b) -- Copy of Articles of Amendment to the Restated Articles
of Incorporation of APCo, dated June 6, 1994 [Annual
Report on Form 10-K of APCo for the fiscal year ended
December 31, 1994, File No. 1-3457, Exhibit 3(b)].
3(c) -- Copy of Articles of Amendment to the Restated Articles
of Incorporation of APCo, dated March 6, 1997 [Annual
Report on Form 10-K of APCo for the fiscal year ended
December 31, 1996, File No. 1-3457, Exhibit 3(c)].
3(d) -- Composite copy of the Restated Articles of
Incorporation of APCo (amended as of March 7, 1997)
[Annual Report on Form 10-K of APCo for the fiscal year
ended December 31, 1996, File No. 1-3457, Exhibit 3(d)].
*3(e) -- Copy of By-Laws of APCo (amended as of June 15, 2000).
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, Exhibit2(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
E-3
69
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
APCO++ (continued)
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) and4(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)].
*4(c) -- Company Order and Officers' Certificate, dated June
27, 2000, establishing certain terms of the Floating Rate
Notes, Series A, due 2001.
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)].
E-4
70
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
APCO++ (continued)
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)].
+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, 1999,
File No. 1-3525, Exhibit 10(p)].
+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)].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the APCo 2000 Annual Report
(for the fiscal year ended December 31, 2000) 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, 2000,
File No. 1-3525, Exhibit 21].
*23 -- Consent of Deloitte & Touche LLP.
*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).
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
E-5
71
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
CPL++ (continued)
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.
*4(d) -- First Supplemental Indenture, dated as of November 15,
1999, between CPL and The Bank of New York, as Trustee,
for Floating Rate Notes due November 23, 2001.
*4(e) -- Second Supplemental Indenture, dated as of February
16, 2000, between CPL and The Bank of New York, as
Trustee, for Floating Rate Notes due February 22, 2002.
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the CPL 2000 Annual Report
(for the fiscal year ended December 31, 2000) 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)].
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.
E-6
72
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
CSPCO++ (continued)
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)].
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 2000 Annual Report
(for the fiscal year ended December 31, 2000) which are
incorporated by reference in this filing.
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
E-7
73
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
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 January 1,
1996) [Annual Report on Form 10-K of I&M for the fiscal
year ended December 31, 1995, File No. 1-3570, Exhibit
3(c)].
4(a) -- Copy of Mortgage and Deed of Trust, dated as of June
1, 1939, between I&M and Irving Trust Company (now The
Bank of New York) and various individuals, as Trustees,
as amended and supplemented [Registration Statement No.
2-7597, Exhibit 7(a); Registration Statement No. 2-60665,
Exhibits 2(c)(2), 2(c)(3), 2(c)(4), 2(c)(5), 2(c)(6),
2(c)(7), 2(c)(8), 2(c)(9), 2(c)(10), 2(c)(11), 2(c)(12),
2(c)(13), 2(c)(14), 2(c)(15), (2)(c)(16), and 2(c)(17);
Registration Statement No. 2-63234, Exhibit 2(b)(18);
Registration Statement No. 2-65389, Exhibit 2(a)(19);
Registration Statement No. 2-67728, Exhibit 2(b)(20);
Registration Statement No. 2-85016, Exhibit 4(b);
Registration Statement No. 33-5728, Exhibit 4(c);
Registration Statement No. 33-9280, Exhibit 4(b);
Registration Statement No. 33-11230, Exhibit 4(b);
Registration Statement No. 33-19620, Exhibits 4(a)(ii),
4(a)(iii), 4(a)(iv) and 4(a)(v); Registration Statement
No. 33-46851, Exhibits 4(b)(i), 4(b)(ii) and 4(b)(iii);
Registration Statement No. 33-54480, Exhibits 4(b)(I) and
4(b)(ii); Registration Statement No. 33-60886, Exhibit
4(b)(I); Registration Statement No. 33-50521, Exhibits
4(b)(I), 4(b)(ii) and 4(b)(iii); Annual Report on Form
10-K of I&M for 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); Annual Report on
Form 10-K of I&M for the fiscal year ended December 31,
1999, File No. 1-3570, Exhibit 4(c)].
* 4(c) -- Copy of Company Order and Officers' Certificate,
dated August 31, 2000, establishing certain terms of the
Floating Rate Notes, Series B, due 2002.
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)].
E-8
74
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
I&M++ (CONTINUED)
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)].
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 2000 Annual Report
(for the fiscal year ended December 31, 2000) 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, 2000,
File No. 1-3525, Exhibit 21].
*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).
E-9
75
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
KEPCO++ (CONTINUED)
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)].
*4(c) -- Copy of Company Order and Officers' Certificate, dated
November 17, 2000, establishing certain terms of the
Floating Rate Notes, Series B, due 2002.
10(a) -- Copy of Interconnection Agreement, dated July 6, 1951,
among APCo, CSPCo, KEPCo, I&M and OPCo and with the
Service Corporation, as amended [Registration Statement
No. 2-52910, Exhibit 5(a);Registration Statement No.
2-61009, Exhibit 5(b); and Annual Report on Form 10-K of
AEP for the fiscal year ended December 31, 1990, File No.
1-3525, Exhibit 10(a)(3)].
10(b) -- Copy of Transmission Agreement, dated April 1, 1984,
among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service
Corporation as agent, as amended [Annual Report on Form
10-K of AEP for the fiscal year ended December 31, 1985,
File No. 1-3525, Exhibit 10(b); and Annual Report on Form
10-K of AEP for the fiscal year ended December 31, 1988,
File No. 1-3525, Exhibit 10(b)(2)].
10(c) -- Copy of Modification No. 1 to the AEP System Interim
Allowance Agreement, dated July 28, 1994, among APCo,
CSPCo, I&M, KEPCo, OPCo and the Service Corporation
[Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1996, File No. 1-3525, Exhibit 10(l)].
10(d)(1) -- Agreement and Plan of Merger, dated as of December 21,
1997, By and Among American Electric Power Company, Inc.,
Augusta Acquisition Corporation and Central and South
West Corporation [Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1997, File No. 1-3525,
Exhibit 10(f)].
10(d)(2) -- Amendment No. 1, dated as of December 31, 1999, to the
Agreement and Plan of Merger [Current Report on Form 8-K
of KEPCo dated December 15, 1999, File No. 1-6858,
Exhibit 10].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the KEPCo 2000 Annual Report
(for the fiscal year ended December 31, 2000) 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)].
E-10
76
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
OPCO++ (CONTINUED)
4(a) -- Copy of Mortgage and Deed of Trust, dated as of
October 1, 1938, between OPCo and Manufacturers Hanover
Trust Company (now Chemical Bank), as Trustee, as amended
and supplemented [Registration Statement No. 2-3828,
Exhibit B-4; Registration Statement No. 2-60721, Exhibits
2(c)(2), 2(c)(3), 2(c)(4), 2(c)(5), 2(c)(6), 2(c)(7),
2(c)(8), 2(c)(9), 2(c)(10), 2(c)(11), 2(c)(12), 2(c)(13),
2(c)(14), 2(c)(15), 2(c)(16), 2(c)(17), 2(c)(18),
2(c)(19), 2(c)(20), 2(c)(21), 2(c)(22), 2(c)(23),
2(c)(24), 2(c)(25), 2(c)(26), 2(c)(27), 2(c)(28),
2(c)(29), 2(c)(30), and 2(c)(31); Registration Statement
No. 2-83591, Exhibit 4(b); Registration Statement No.
33-21208, Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(iv);
Registration Statement No. 33-31069, Exhibit 4(a)(ii);
Registration Statement No. 33-44995, Exhibit 4(a)(ii);
Registration Statement No. 33-59006, Exhibits 4(a)(ii),
4(a)(iii) and 4(a)(iv); Registration Statement No.
33-50373, Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(iv);
Annual Report on Form 10-K of OPCo for the fiscal year
ended December 31, 1993, File No. 1-6543, Exhibit 4(b)].
4(b) -- Copy of Indenture (for unsecured debt securities),
dated as of September 1, 1997, between OPCo and Bankers
Trust Company, as Trustee [Registration Statement No.
333-49595, Exhibits 4(a), 4(b) and 4(c); Annual Report on
Form 10-K 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)].
*4(c) -- Copy of Company Order and Officers' Certificate, dated
May 22, 2000, establishing certain terms of the Floating
Rate Notes, Series A, due 2001.
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)].
E-11
77
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
OPCO++ (CONTINUED)
10(e) -- Copy of Amendment No. 1, dated October 1, 1973, to
Station Agreement dated January 1, 1968, among OPCo,
Buckeye and Cardinal Operating Company, and amendments
thereto [Annual Report on Form 10-K of OPCo for the
fiscal year ended December 31, 1993, File No. 1-6543,
Exhibit 10(f)].
10(f) -- Lease Agreement dated January 20, 1995 between OPCo
and JMG Funding, Limited Partnership, and amendment
thereto (confidential treatment requested) [Annual Report
on Form 10-K of OPCo for the fiscal year ended December
31, 1994, File No. 1-6543, Exhibit 10(l)(2)].
10(g)(1) -- Agreement and Plan of Merger, dated as of December 21,
1997, by and among American Electric Power Company, Inc.,
Augusta Acquisition Corporation and Central and South
West Corporation [Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1997, File No. 1-3525,
Exhibit 10(f)].
10(g)(2) -- Amendment No. 1, dated as of December 31, 1999, to the
Agreement and Plan of Merger [Current Report on Form 8-K
of OPCo dated December 15, 1999, File No. 1-6543, Exhibit
10].
+10(h)(1) -- AEP Deferred Compensation Agreement for certain
executive officers [Annual Report on Form 10-K of OPCo
for the fiscal year ended December 31, 1985, File No.
1-3525, Exhibit 10(e)].
+10(h)(2) -- Amendment to AEP Deferred Compensation Agreement for
certain executive officers [Annual Report on Form 10-K of
AEP for the fiscal year ended December 31, 1986, File No.
1-3525, Exhibit 10(d)(2)].
+10(i) -- 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, 1999,
File No. 1-3525, Exhibit 10(p)].
+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)].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the OPCo 2000 Annual Report
(for the fiscal year ended December 31, 2000) 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, 2000,
File No. 1-3525, Exhibit 21].
*23 -- Consent of Deloitte & Touche LLP.
E-12
78
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
OPCO++ (CONTINUED)
*24 -- Power of Attorney.
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).
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.
*4(d) -- First Supplemental Indenture, dated as of November 1,
2000, between PSO and The Bank of New York, as Trustee,
for Floating Rate Notes, Series A, due November 21, 2002.
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the PSO 2000 Annual Report
(for the fiscal year ended December 31, 2000) 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].
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].
E-13
79
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
SWEPCO++ (CONTINUED)
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.
*4(d) -- First Supplemental Indenture, dated as of February 25,
2000, between SWEPCO and The Bank of New York, as
Trustee, for Floating Rate Notes due March 1, 2001.
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the SWEPCo 2000 Annual
Report (for the fiscal year ended December 31, 2000)
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].
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 2000 Annual Report
(for the fiscal year ended December 31, 2000) which are
incorporated by reference in this filing.
E-14
80
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
WTU++ (CONTINUED)
*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.