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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
---------------------------
FORM 10-K
---------------------------
(Mark One)
x[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
[FEE REQUIRED]
For the fiscal year ended December 31, 1995
2002
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
[NO FEE REQUIRED]
For the transition period from _____________-------------- to ______________
COMMISSION REGISTRANT; STATE OF INCORPORATION; I.R.S. EMPLOYER
FILE NUMBER ADDRESS; AND TELEPHONE NUMBER IDENTIFICATION NO.--------------
COMMISSION REGISTRANTS; STATES OF INCORPORATION; I.R.S. EMPLOYER
FILE NUMBER ADDRESS AND TELEPHONE NUMBER IDENTIFICATION NOS.
----------- ------------------------------------- -------------------
1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. 13-4922640 (A New York 13-4922640
Corporation)
0-18135 AEP GENERATING COMPANY (An Ohio Corporation) 31-1033833
0-346 AEP TEXAS CENTRAL COMPANY (A Texas Corporation) 74-0550600
0-340 AEP TEXAS NORTH COMPANY (A Texas Corporation) 75-0646790
1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790
1-2680 COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation) 31-4154203
1-3570 INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) 35-0410455
1-6858 KENTUCKY POWER COMPANY (A Kentucky Corporation) 61-0247775
1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000
0-343 PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation) 73-0410895
1-3146 SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation) 72-0323455
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 223-1000
0-18135 AEP GENERATING COMPANY 31-1033833
(An Ohio Corporation)
1 Riverside Plaza
Columbus, Ohio 43215
Telephone (614) 223-1000
1-3457 APPALACHIAN POWER COMPANY 54-0124790
(A Virginia Corporation)
40 Franklin Road, S.W.
Roanoke, Virginia 24011
Telephone (540) 985-2300
1-2680 COLUMBUS SOUTHERN POWER COMPANY 31-4154203
(An Ohio Corporation)
215 North Front Street
Columbus, Ohio 43215
Telephone (614) 464-7700
1-3570 INDIANA MICHIGAN POWER COMPANY 35-0410455
(An Indiana Corporation)
One Summit Square
P. O. Box 60
Fort Wayne, Indiana 46801
Telephone (219) 425-2111
1-6858 KENTUCKY POWER COMPANY 61-0247775
(A Kentucky Corporation)
1701 Central Avenue
Ashland, Kentucky 41101
Telephone (800) 572-1113
1-6543 OHIO POWER COMPANY 31-4271000
(An Ohio Corporation)
301 Cleveland Avenue, S.W.
Canton, Ohio 44702
Telephone (330) 456-8173
AEP Generating Company, Columbus Southern Power Company and Kentucky Power
Company meet the conditions set forth in General Instruction J(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 J(2) to such Form 10-K.
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. .
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 Cumulative Preferred
Company Stock Voting,
no par value:
4-1/2% Philadelphia Stock Exchange
4.50% Philadelphia Stock Exchange
7.40% New York Stock Exchange
Columbus Southern 8-3/8% Junior Subordinated
Power Company Deferrable Interest
Debentures, Series A,
Due 2025 New York Stock Exchange
Indiana Michigan Cumulative Preferred
Power Company Stock, Non-Voting,
$100 par value:
4-1/8% Chicago Stock Exchange
7.08% New York Stock Exchange
Kentucky Power Company 8.72% Junior Subordinated
Deferrable 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
Indicate by check mark if disclosure of delinquent filers with respect to
American Electric Power Company, Inc. and Appalachian Power Company pursuant to Item 405 of Regulation S-K
(229.405(229.405 of this chapter) is not contained herein, and will not be contained, to
the best of registrant's knowledge, in the definitive proxy statement of American Electric Power Company, Inc. or definitive information
statement of Appalachian Power Companystatements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
Indicate by check mark if disclosure of delinquent filers with respect to
Appalachian Power Company, Indiana Michigan Power Company or Ohio Power Company
pursuant to Item 405 of Regulation S-K (229.405(229.405 of this chapter) is not
contained herein, and will not be contained, to the best of registrant's
knowledge, in the definitive proxy or information statementstatements of Appalachian Power
Company or Ohio Power Company incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K.
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
REGISTRANT TITLE OF EACH CLASS
AEP Generating Company NoneX
Indicate by check mark whether American Electric Power Company, Inc. None
Appalachian Power Company None
Columbus Southern Power Company None
Indiana Michigan Power Company None
Kentucky Power Company None
Ohio Power Company 4-1/2% Cumulative Preferred Stock,
Voting, $100 par value
AGGREGATE MARKET VALUE NUMBER OF SHARES
OF VOTING STOCK HELD OF COMMON STOCK
BY NON-AFFILIATES OF OUTSTANDING OF
THE REGISTRANTS AT THE REGISTRANTS AT
FEBRUARY 2, 1996 FEBRUARY 2, 1996is an
accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of
1934). Yes X No __
Indicate by check mark whether AEP Generating Company, None 1,000
($1,000 par value)
American Electric
PowerAEP Texas Central
Company, Inc. $8,164,000,000 186,635,000
($6.50 par value)
Appalachian PowerAEP Texas North Company, $43,000,000 13,499,500
(no par value)
Columbus Southern
Power Company None 16,410,426
(no par value)
Indiana Michigan
Power Company None 1,400,000
(no par value)
Kentucky Power
Company None 1,009,000
($50 par value)
Ohio Power
Company $68,000,000 27,952,473
(no par value)
NOTE ON MARKET VALUE OF VOTING STOCK HELD BY NON-AFFILIATES
All of the common stock of AEP Generating Company, Appalachian Power
Company, Columbus Southern Power Company, Indiana Michigan Power Company,
Kentucky Power Company and Ohio Power Company is owned by American Electric
Power Company, Inc. (see Item 12 herein). The voting stock owned by non-
affiliates of (i) Appalachian Power Company consists of 552,348 shares of
Cumulative Preferred Stock, no par value; and (ii) Ohio Power Company consists
of 862,403 shares of Cumulative Preferred Stock, $100 par value. Some of the
series of Cumulative Preferred Stock are not regularly traded. The aggregate
market value of the Cumulative Preferred Stock is based on the average of the
high and low prices on the closest trading date to February 2, 1996 for series
traded on the New York or Philadelphia Stock Exchange, or the most recent
reported bid prices for those series not recently traded. Where recent market
price information was not available with respect to a series, the market price
for such series is based on the price of a recently traded series with an
adjustment related to any difference in the current yields of the two series.
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 December 31, 1995: Part II
AEP Generating Company
American Electric Power Company, Inc. Appalachian Power Company, Columbus Southern
Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio
Power Company, PortionsPublic Service Company of Proxy StatementOklahoma and Southwestern Electric
Power Company are accelerated filers (as defined in Rule 12b-2 of the Securities
Exchange Act of 1934). Yes __ No X
AEP Generating Company, AEP Texas North Company, Columbus Southern Power
Company, Kentucky Power Company and Public Service Company of Oklahoma meet the
conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are
therefore filing this Form 10-K with the reduced disclosure format specified in
General Instruction I(2) to such Form 10-K.
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
NAME OF EACH EXCHANGE
REGISTRANT TITLE OF EACH CLASS ON WHICH REGISTERED
---------- ------------------- ---------------------
AEP Generating Company None
AEP Texas Central Company None
AEP Texas North Company None
American Electric Common Stock,
Power Company, Inc. $6.50 par value.................................. New York Stock Exchange
9.25% Equity Units................................. New York Stock Exchange
Appalachian Power Company 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 Power Company None
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 Debentures, Series A, Due
Power Company 2026............................................. New York Stock Exchange
7.60% Junior Subordinated Deferrable
Interest Debentures, Series B, Due 2038.......... New York Stock Exchange
6% Senior Notes, Series D, Due 2032................ New York Stock Exchange
Kentucky Power Company 8.72% Junior Subordinated Deferrable
Interest Debentures, Series A, Due 2025.......... New York Stock Exchange
Ohio Power Company 7 3/8% Senior Notes, Series A, Due 2038............ New York Stock Exchange
Public Service Company 6% Senior Notes, Series B, Due 2032................ New York Stock Exchange
of Oklahoma
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
Southwestern Electric None
Power Company
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
REGISTRANT TITLE OF EACH CLASS
---------- -------------------
AEP Generating Company None
AEP Texas Central Company 4.00% Cumulative Preferred Stock, Non-Voting, $100 par value
4.20% Cumulative Preferred Stock, Non-Voting, $100 par value
AEP Texas North Company None
American Electric Power Company, Inc. None
Appalachian Power Company 4.50% Cumulative Preferred Stock, Voting, no par value
Columbus Southern Power Company None
Indiana Michigan Power Company 4.125% Cumulative Preferred Stock, Non-Voting, $100 par
value
Kentucky Power Company None
Ohio Power Company 4.50% Cumulative Preferred Stock, Voting, $100 par value
Public Service Company of Oklahoma None
Southwestern Electric Power Company 4.28% Cumulative Preferred Stock, Non-Voting, $100 par value
4.65% Cumulative Preferred Stock, Non-Voting, $100 par value
5.00% Cumulative Preferred Stock, Non-Voting, $100 par value
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
JUNE 28, 2002 JUNE 28, 2002
------------------------ ------------------
AEP Generating Company None 1,000
($1,000 par value)
AEP Texas Central Company None 2,211,678
($25 par value)
AEP Texas North Company None 5,488,560
($25 par value)
American Electric Power Company, Inc. $13,560,125,474 338,833,720
($6.50 par value)
Appalachian Power Company None 13,499,500
(no par value)
Columbus Southern Power Company None 16,410,426
(no par value)
Indiana Michigan Power Company None 1,400,000
(no par value)
Kentucky Power Company None 1,009,000
($50 par value)
Ohio Power Company None 27,952,473
(no par value)
Public Service Company of Oklahoma None 9,013,000
($15 par value)
Southwestern Electric Power Company None 7,536,640
($18 par value)
NOTE ON MARKET VALUE OF COMMON EQUITY HELD BY NON-AFFILIATES
American Electric Power Company, Inc., dated March 9, 1996, for Annual
Meeting of Shareholders Part III
Portions of Information Statements owns, directly or indirectly, all of
the following companies
for 1996 Annual Meetingcommon stock of Shareholders, to be filed within
120 days after December 31, 1995:AEP Generating Company, AEP Texas Central Company, AEP Texas
North Company, Appalachian Power Company, Columbus Southern Power Company,
Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company,
Public Service Company of Oklahoma and Southwestern Electric Power Company (see
Item 12 herein).
DOCUMENTS INCORPORATED BY REFERENCE
PART OF FORM 10-K
INTO WHICH DOCUMENT
DESCRIPTION IS INCORPORATED
- ----------- -------------------
Portions of Annual Reports of the following companies for Part II
the fiscal year ended December 31, 2002:
AEP Generating Company
AEP Texas Central Company
AEP Texas North Company
American Electric Power Company, Inc.
Appalachian Power Company
Columbus Southern Power Company
Indiana Michigan Power Company
Kentucky Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company
Portions of Proxy Statement of American Electric Power Part III
Company, Inc. for 2003 Annual Meeting of Shareholders, to be
filed within 120 days after December 31, 2002
Portions of Information Statements of the following Part III
companies for 2003 Annual Meeting of Shareholders, to be
filed within 120 days after December 31, 2002:
Appalachian Power Company
Ohio Power Company
------------------
THIS COMBINED FORM 10-K IS SEPARATELY FILED BY AEP GENERATING COMPANY,
AEP TEXAS CENTRAL COMPANY, AEP TEXAS NORTH COMPANY, AMERICAN ELECTRIC POWER
COMPANY, INC., APPALACHIAN POWER COMPANY, COLUMBUS SOUTHERN POWER COMPANY,
INDIANA MICHIGAN POWER COMPANY, KENTUCKY POWER COMPANY, OHIO POWER COMPANY,
PUBLIC SERVICE COMPANY OF OKLAHOMA AND OHIOSOUTHWESTERN ELECTRIC POWER COMPANY.
INFORMATION CONTAINED HEREIN RELATING TO ANY INDIVIDUAL REGISTRANT IS FILED BY
SUCH REGISTRANT ON ITS OWN BEHALF. EXCEPT FOR AMERICAN ELECTRIC POWER COMPANY,
INC., EACH REGISTRANT MAKES NO REPRESENTATION AS TO INFORMATION RELATING TO THE
OTHER REGISTRANTS.
YOU CAN ACCESS FINANCIAL AND OTHER INFORMATION AT AEP'S WEBSITE. THE
ADDRESS IS WWW.AEP.COM. AEP MAKES AVAILABLE, FREE OF CHARGE ON ITS WEBSITE,
COPIES OF ITS ANNUAL REPORT ON FORM 10-K, QUARTERLY REPORTS ON FORM 10-Q,
CURRENT REPORTS ON FORM 8-K AND AMENDMENTS TO THOSE REPORTS FILED OR FURNISHED
PURSUANT TO SECTION 13(A) OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 AS
SOON AS REASONABLY PRACTICABLE AFTER FILING SUCH MATERIAL ELECTRONICALLY OR
OTHERWISE FURNISHING IT TO THE SEC.
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TABLE OF CONTENTS
PAGE
NUMBER
Glossary of Terms i
PART I
Item 1. Business 1
Item 2. Properties 29
Item 3. Legal Proceedings 33
Item 4. Submission of Matters to a Vote of Security
Holders 34
Executive Officers of the Registrants 34
PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 37
Item 6. Selected Financial Data 37
Item 7. Management's Discussion and Analysis of Results
of Operations and Financial Condition 37
Item 8. Financial Statements and Supplementary Data 38
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 38
PART III
Item 10. Directors and Executive Officers of the
Registrants 39
Item 11. Executive Compensation 40
Item 12. Security Ownership of Certain Beneficial
Owners and Management 44
Item 13. Certain Relationships and Related Transactions 45
PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K 46
Signatures 48
Index to Financial Statement Schedules S-1
Independent Auditors' Report S-2
Exhibit
PAGE
NUMBER
------
Glossary of Terms........................................................... i
Forward-Looking Information................................................. 1
PART I
Item 1. Business.................................................... 2
Item 2. Properties.................................................. 26
Item 3. Legal Proceedings........................................... 29
Item 4. Submission of Matters to a Vote of Security Holders......... 30
Executive Officers of the Registrants.................................... 30
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters....................................... 32
Item 6. Selected Financial Data..................................... 32
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition........................ 33
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk...................................................... 33
Item 8. Financial Statements and Supplementary Data................. 33
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 33
PART III
Item 10. Directors and Executive Officers of the Registrants......... 33
Item 11. Executive Compensation...................................... 34
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters................ 34
Item 13. Certain Relationships and Related Transactions.............. 37
PART IV
Item 14. Controls and Procedures..................................... 37
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form
8-K....................................................... 37
Signatures.................................................................. 39
Certifications.............................................................. 42
Index to Financial Statement Schedules...................................... S-1
Independent Auditors' Report................................................ S-2
Exhibit Index............................................................... E-1
GLOSSARY OF TERMS
WhenThe following abbreviations or acronyms used in this Form 10-K are defined
below:
ABBREVIATION OR ACRONYM DEFINITION
----------------------- ----------
AEGCo. ................................ AEP Generating Company, an electric utility subsidiary of
AEP
AEP.................................... American Electric Power Company, Inc.
AEPES.................................. AEP Energy Services, Inc., a subsidiary of AEP
AEP Power Pool......................... APCo, CSPCo, I&M, KPCo and OPCo, as parties to the
Interconnection Agreement
AEPR................................... AEP Resources, Inc., a subsidiary of AEP
AEPSC or Service Corporation........... American Electric Power Service Corporation, a service
subsidiary of AEP
AEP System or the System............... The American Electric Power System, an integrated electric
utility system, owned and operated by AEP's electric utility
subsidiaries
AEP Utilities.......................... AEP Utilities, Inc., subsidiary of AEP, formerly, Central
and South West Corporation
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
CAA.................................... Clean Air Act
CAAA................................... Clean Air Act Amendments of 1990
Cardinal Station....................... Generating facility co-owned by Buckeye and OPCo
Centrica............................... Centrica U.S. Holdings, Inc., and its affiliates
collectively, unaffiliated companies
CERCLA................................. Comprehensive Environmental Response, Compensation and
Liability Act of 1980
CG&E................................... The Cincinnati Gas & Electric Company, an unaffiliated
utility company
Cook Plant............................. The Donald C. Cook Nuclear Plant, owned by I&M, located near
Bridgman, Michigan
CSPCo. ................................ Columbus Southern Power Company, a public utility subsidiary
of AEP
CSW Operating Agreement................ Agreement, dated January 1, 1997, by and among PSO, SWEPCo,
TCC and TNC governing generating capacity allocation
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, KPCo and OPCo
ECOM................................... Excess cost over market
EMF.................................... Electric and Magnetic Fields
EPA.................................... United States Environmental Protection Agency
ERCOT.................................. Electric Reliability Council of Texas
EWG.................................... Exempt wholesale generator, as defined under PUHCA
FERC................................... Federal Energy Regulatory Commission
Fitch.................................. Fitch Ratings, Inc.
FPA.................................... Federal Power Act
FUCO................................... Foreign utility company as defined under PUHCA
I&M.................................... Indiana Michigan Power Company, a public utility subsidiary
of AEP
I&M Power Agreement.................... Unit Power Agreement Between AEGCo and I&M, dated March 31,
1982
Interconnection Agreement.............. Agreement, dated July 6, 1951, by and among APCo, CSPCo,
I&M, KPCo and OPCo, defining the sharing of costs and
benefits associated with their respective generating
plants
IURC................................... Indiana Utility Regulatory Commission
KPCo. ................................. Kentucky Power Company, a public utility subsidiary of AEP
LLWPA.................................. Low-Level Waste Policy Act of 1980
LPSC................................... Louisiana Public Service Commission
MECPL.................................. Mutual Energy CPL, L.P., a Texas REP and former AEP
affiliate
MEWTU.................................. Mutual Energy WTU, L.P., a Texas REP and former AEP
affiliate
MISO................................... Midwest Independent Transmission System Operator
Moody's................................ Moody's Investors Service, Inc.
i
ABBREVIATION OR ACRONYM DEFINITION
----------------------- ----------
MTM.................................... Marked-to-market
MW..................................... Megawatt
NOx.................................... Nitrogen oxide
NPC.................................... National Power Cooperatives, Inc., an unaffiliated
corporation
NRC.................................... Nuclear Regulatory Commission
OASIS.................................. Open Access Same-time Information System
OATT................................... Open Access Transmission Tariff, filed with FERC
OCC.................................... Corporation Commission of the State of Oklahoma
Ohio Act............................... Ohio electric restructuring legislation
OPCo. ................................. Ohio Power Company, a public utility subsidiary of AEP
OVEC................................... Ohio Valley Electric Corporation, an electric utility
company in which AEP and CSPCo together own a 44.2% equity
interest
PJM.................................... PJM Interconnection, L.L.C.
Pro Serv............................... AEP Pro Serv, Inc., a subsidiary of AEP
PSO.................................... Public Service Company of Oklahoma, a public utility
subsidiary of AEP
PTB.................................... Price to beat, as defined by the Texas Act
PUCO................................... The Public Utilities Commission of Ohio
PUCT................................... Public Utility Commission of Texas
PUHCA.................................. Public Utility Holding Company Act of 1935, as amended
QF..................................... Qualifying facility, as defined under the Public Utility
Regulatory Policies Act of 1978
RCRA................................... Resource Conservation and Recovery Act of 1976, as amended
REP.................................... Retail electricity provider
Rockport Plant......................... A generating plant, consisting of two 1,300,000-kilowatt
coal-fired generating units, near Rockport, Indiana
RTO.................................... Regional Transmission Organization
SEC.................................... Securities and Exchange Commission
S&P.................................... Standard & Poor's Ratings Service
SO(2).................................. Sulfur dioxide
SO(2) Allowance........................ An allowance to emit one ton of sulfur dioxide granted under
the Clean Air Act Amendments of 1990
SPP.................................... Southwest Power Pool
STPNOC................................. STP Nuclear Operating Company, a non-profit Texas
corporation which operates STP on behalf of its joint
owners, including TCC
SWEPCo. ............................... Southwestern Electric Power Company, a public utility
subsidiary of AEP
TCA.................................... Transmission Coordination Agreement dated January 1, 1997 by
and among, PSO, SWEPCo, TCC, TNC and AEPSC, which allocates
costs and benefits in connection with the operation of the
transmission assets of the four public utility
subsidiaries
TCC.................................... AEP Texas Central Company, formerly Central Power and Light
Company, a public utility subsidiary of AEP
TEA.................................... Transmission Equalization Agreement dated April 1, 1984 by
and among APCo, CSPCo, I&M, KPCo and OPCo, which allocates
costs and benefits in connection with the operation of
transmission assets
Texas Act.............................. Texas electric restructuring legislation
TNC.................................... AEP Texas North Company, formerly West Texas Utilities
Company, a public utility subsidiary of AEP
TVA.................................... Tennessee Valley Authority
UCOS................................... Unbundled cost of service
Virginia Act........................... Virginia electric restructuring legislation
VSCC................................... Virginia State Corporation Commission
WVPSC.................................. West Virginia Public Service Commission
West Zone Companies of AEP............. PSO, SWEPCo, TCC and TNC
ii
FORWARD-LOOKING INFORMATION
- --------------------------------------------------------------------------------
This report made by AEP and certain of its subsidiaries contains
forward-looking statements within the following termsmeaning of Section 21E of the Securities
Exchange Act of 1934. Although AEP and abbreviations appeareach of its subsidiaries believe that
their expectations are based on reasonable assumptions, any such statements may
be influenced by factors that could cause actual outcomes and results to be
materially different from those projected. Among the factors that could cause
actual results to differ materially from those in the textforward-looking statements
are:
- Electric load and customer growth.
- Abnormal weather conditions
- Available sources and costs of this
report, they havefuels.
- Availability of generating capacity.
- The speed and degree to which competition is introduced to AEP's power
generation business.
- The ability to recover stranded costs in connection with
possible/proposed deregulation of generation.
- New legislation and government regulation
- Oversight and/or investigation of the meanings indicated below.
TERM MEANING
AEGCoenergy sector or its participants.
- The ability of AEP Generating Company, an electric utility subsidiaryto successfully control its costs.
- The success of AEP.
AEP American Electric Power Company, Inc.
AEP System oracquiring new business ventures and disposing of existing
investments that no longer match AEP's corporate profile.
- International and country-specific developments affecting AEP's foreign
investments, including the Systemdisposition of any current foreign investments
and potential additional foreign investments.
- The American Electric Power System, an integrated
electric utility system, ownedeconomic climate and operated bygrowth in AEP's electric utility subsidiaries.
AFUDC Allowance for funds used during construction. Definedservice territory and changes in
regulatory systemsmarket demand and demographic patterns.
- Inflationary trends.
- Electricity and gas market prices.
- Interest rates.
- Liquidity in the banking, capital and wholesale power markets.
- Actions of accounts asrating agencies.
- Changes in technology, including the net costincreased use of borrowed funds used for constructiondistributed
generation within AEP's transmission and a reasonable
ratedistribution service territory.
- Other risks and unforeseen events, including wars, the effects of
return onterrorism, embargoes and other funds when so used.
APCo Appalachian Power Company, an electric utility
subsidiary of AEP.
Buckeye Buckeye Power, Inc., an unaffiliated corporation.
CCD Group CSPCo, CG&E and DP&L.
CG&E The Cincinnati Gas & Electric Company, an unaffiliated
utility company.
Cook Plant The Donald C. Cook Nuclear Plant, owned by I&M.
CSPCo Columbus Southern Power Company, an electric utility
subsidiary of AEP.
DOE United States Department of Energy.
DP&L The Dayton Power and Light Company, an unaffiliated
utility company.
Federal EPA United States Environmental Protection Agency.
FERC Federal Energy Regulatory Commission (an independent
commission within the DOE).
I&M Indiana Michigan Power Company, an electric utility
subsidiary of AEP.
IURC Indiana Utility Regulatory Commission.
KEPCo Kentucky Power Company, an electric utility subsidiary
of AEP.
KPSC Kentucky Public Service Commission.
MPSC Michigan Public Service Commission.
NEIL Nuclear Electric Insurance Limited.
NPDES National Pollutant Discharge Elimination System.
NRC Nuclear Regulatory Commission.
Ohio EPA Ohio Environmental Protection Agency.
OPCo Ohio Power Company, an electric utility subsidiary of
AEP.
OVEC Ohio Valley Electric Corporation, an electric utility
company in which AEP and CSPCo own a 44.2% equity
interest.
PCB's Polychlorinated biphenyls.
PUCO The Public Utilities Commission of Ohio.
PUHCA Public Utility Holding Company Act of 1935, as amended.
RCRA Resource Conservation and Recovery Act of 1976, as
amended.
Rockport Plant A generating plant, consisting of two 1,300,000-kilowatt
coal-fired generating units, near Rockport, Indiana.
SEC Securities and Exchange Commission.
Service Corporation American Electric Power Service Corporation, a service
subsidiary of AEP.
SO{2} Allowance An allowance to emit one ton of sulfur dioxide granted
under the Clean Air Act Amendments of 1990.
TVA Tennessee Valley Authority.
VEPCo Virginia Electric and Power Company, an unaffiliated
utility company.
Virginia SCC State Corporation Commission of Virginia.
West Virginia PSC Public Service Commission of West Virginia.
Zimmer or Zimmer Plant Wm. H. Zimmer Generating Station, commonly owned by
CSPCo, CG&E and DP&L.
i
[THIS PAGE INTENTIONALLY LEFT BLANK]catastrophic events.
1
PART I
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Item 1. BUSINESS
- --------------------------------------------------------------------------------
GENERAL
OVERVIEW AND DESCRIPTION OF SUBSIDIARIES
AEP was incorporated under the laws of the State of New York in 1906 and
reorganized in 1925. It is a registered public utility holding company whichunder
PUHCA that owns, directly or indirectly, all of the outstanding common stock of
its electricpublic 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.
The service areaareas of AEP's electricpublic utility subsidiaries coverscover 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 public utility 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 electricpublic 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. AsRestructuring legislation in
Michigan, Ohio, Texas and Virginia has caused or will cause AEP public utility
subsidiaries in those states to unbundle previously integrated regulated rates
for their retail customers.
The AEP System is an integrated electric utility system and, as a result,
the member companies of the changing natureAEP 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 and transportation and handling of fuel. The member companies of the
electric
business (see COMPETITION AND BUSINESS CHANGE), effective January 1, 1996,
AEP's subsidiaries realigned into four functional business units: Power
Generation; Nuclear Generation; Energy Delivery;AEP System also obtain certain accounting, administrative, information systems,
engineering, financial, legal, maintenance and Corporate Development. In
addition, the electric utility subsidiaries began to do business as "American
Electric Power." The legal and financial structure of AEP and its
subsidiaries, however, did not change.other services at cost from a
common provider, AEPSC.
At December 31, 1995,2002, the subsidiaries of AEP had a total of 18,50222,083
employees. AEP, as such,because it is a holding company rather than an operating
company, has no employees. The operatingpublic utility subsidiaries of AEP are:
APCOAPCo (organized in Virginia in 1926) is engaged in the generation,
purchase, transmission and distribution of electric power to approximately 859,000925,000
retail customers in the southwestern portion of Virginia and southern West
Virginia, and in supplying and marketing electric power at wholesale to other
electric utility companies, municipalities and municipalities in those states and in
Tennessee.other market participants. At
December 31, 1995,2002, APCo and its wholly owned subsidiaries had 4,3382,520 employees.
Among the principal industries served by APCo are coal mining, primary metals,
chemicals textiles, paper, stone, clay, glass and concrete products, rubber, plastic products and furniture.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
Virginia Electric and Power Company and VEPCo. A comparatively small part of the properties
and business of APCo is located in the northeastern end of the Tennessee
Valley.Company. 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.
CSPCOCSPCo (organized in Ohio in 1937, the earliest direct predecessor company
having been organized in 1883) is engaged in the generation, purchase,
transmission and
distribution of electric power to approximately 599,000689,000 retail customers in
Ohio, and in supplying and marketing electric power at wholesale to other
electric utilities, municipalities and to municipally owned distribution systems within its
service area.other market participants. At December
31, 1995,2002, CSPCo had 2,1741,171 employees. CSPCo's service area is comprised of two
areas in Ohio, which include portions of twenty-five counties. One area
includes the City of Columbus and the other is a predominantly rural area in
south central Ohio. Approximately 80% of
CSPCo's retail revenues are derived from the Columbus area. Among the principal industries served are food processing,
chemicals, primary metals, electronic machinery and paper products. In
addition to its AEP System interconnections, CSPCo also is interconnected with
the following unaffiliated utility companies: CG&E, DP&L and Ohio Edison
Company.
I&M (organized in Indiana in 1925) is engaged in the generation,
purchase, transmission and distribution of electric power to approximately 537,000571,000
retail customers in northern and eastern Indiana and southwestern Michigan,
and in supplying and marketing electric power at wholesale to other electric
utility companies, rural electric cooperatives, municipalities and municipalities.other
market participants. At December 31, 1995,2002, I&M had 3,5252,667 employees. Among the
principal industries served are primary metals, transportation equipment,
fabricated metal products,
electrical and electronic
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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
PowerEnergy 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.
KEPCOKPCo (organized in Kentucky in 1919) is engaged in the generation,
purchase, transmission and distribution of electric power to approximately 165,000174,000
retail customers in an area in eastern Kentucky, and in supplying and
marketing electric power at wholesale to other utilitieselectric utility companies,
municipalities and municipalities in Kentucky.other market participants. At December 31, 1995, KEPCo2002, KPCo had
748412 employees. In addition to its AEP System interconnections, KEPCoKPCo also is
interconnected with the following unaffiliated utility companies: Kentucky
Utilities Company and East Kentucky Power Cooperative Inc. KEPCoKPCo is also
interconnected with TVA.
KINGSPORT POWER COMPANYKingsport Power Company (organized in Virginia in 1917) provides electric
service to approximately 42,00046,000 retail customers in Kingsport and eight
neighboring communities in northeastern Tennessee. Kingsport Power Company
has nodoes not own any generating facilities of its own.facilities. It purchases electric power distributedfrom APCo
for distribution to its customers from APCo.customers. At December 31, 1995,2002, Kingsport Power
Company had 10157 employees.
OPCOOPCo (organized in Ohio in 1907 and reincorporatedre-incorporated in 1924) is engaged
in the generation, purchase, transmission and distribution of electric power to
approximately 668,000702,000 retail customers in the northwestern, east central,
eastern and southern sections of Ohio, and in supplying and marketing electric
power at wholesale to other electric utility companies, municipalities and
municipalities.other market participants. At December 31, 1995,2002, OPCo and its wholly owned subsidiaries had 4,9981,988 employees.
Among the principal industries served by OPCo are primary metals, rubber and
plastic products, stone, clay, glass and concrete products, petroleum refining
chemicals and electrical and electronic machinery.chemicals. In addition to its AEP System interconnections, OPCo also is
interconnected with the following unaffiliated utility companies: CG&E, The
Cleveland Electric Illuminating Company, DP&L, Duquesne Light Company,
Kentucky Utilities Company, Monongahela Power Company, Ohio Edison Company,
The Toledo Edison Company and West Penn Power Company.
WHEELING POWER COMPANYPSO (organized in Oklahoma in 1913) is engaged in the generation,
transmission and distribution of electric power to approximately 505,000
retail customers in eastern and southwestern Oklahoma, and in supplying and
marketing electric power at wholesale to other electric utility companies,
municipalities, rural electric cooperatives and other market participants. At
December 31, 2002, PSO had 998 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. In addition to its AEP System
interconnections, PSO also is interconnected with Ameren Corporation, Empire
District Electric Co., Oklahoma Gas & Electric Co., Southwestern Public
Service Co. and Westar Energy Inc.
SWEPCo (organized in Delaware in 1912) is engaged in the generation,
transmission and distribution of electric power to approximately 437,000
retail customers in northeastern Texas, northwestern Louisiana and western
Arkansas, and in supplying and marketing electric power at wholesale to other
electric utility companies, municipalities, rural electric cooperatives and
other market participants. At December 31, 2002, SWEPCo had 1,372 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. In
addition to its AEP System interconnections, SWEPCo is also interconnected
with CLECO Corp., Empire District Electric Co., Entergy Corp. and Oklahoma Gas
& Electric Co.
TCC (organized in Texas in 1945) is engaged in the generation,
transmission and sale of power to affiliated and non-affiliated entities and
the distribution of electric power to approximately 689,000 retail customers
through REPs in southern Texas, and in supplying and marketing electric power
at wholesale to other electric utility companies, municipalities, rural
electric cooperatives and other market
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participants. At December 31, 2002, TCC had 1,248 employees. Among the
principal industries served by TCC are oil and gas extraction, food
processing, apparel, metal refining, chemical and petroleum refining,
plastics, and machinery equipment. In addition to its AEP System
interconnections, TCC is a member of ERCOT.
TNC (organized in Texas in 1927) is engaged in the generation,
transmission and sale of power to affiliated and non-affiliated entities and
the distribution of electric power to approximately 189,000 retail customers
through REPs in west and central Texas, and in supplying and marketing
electric power at wholesale to other electric utility companies,
municipalities, rural electric cooperatives and other market participants. At
December 31, 2002, TNC had 595 employees. The principal industry served by TNC
is agriculture. The territory served by TNC also includes several military
installations and correctional facilities. In addition to its AEP System
interconnections, TNC is a member of ERCOT.
Wheeling Power Company (organized in West Virginia in 1883 and
reincorporated in 1911) provides electric service to approximately 41,000
retail customers in northern West Virginia. Wheeling Power Company has nodoes not
own any generating facilities of its own.facilities. It purchases electric power distributedfrom OPCo for
distribution to its customers from OPCo.customers. At December 31, 1995,2002, Wheeling Power Company
had 13559 employees.
Another principal electric utility subsidiary of AEP is AEGCo which was
organized(organized in Ohio in 1982 as1982) is an electric generating company.
AEGCo sells power at wholesale to I&M KEPCo and VEPCo.KPCo. AEGCo has no employees.
See Item 2 for information concerning the properties of the subsidiaries of
AEP.
The Service CorporationCompany Subsidiary
AEP also owns a service company subsidiary, AEPSC. AEPSC 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 AEPSC. At December 31, 2002, AEPSC had 6,548 employees.
CLASSES OF SERVICE
The principal classes of service from which the Service Corporation.public utility subsidiaries
of AEP derive revenues and the amount of such revenues during the year ended
December 31, 2002 are as follows:
AEP
SYSTEM(A) APCo CSPCo I&M KPCo
----------- ---------- ---------- ---------- ---------
(IN THOUSANDS)
Wholesale Business:
Residential........................ $ 3,713,000 $ 616,509 $ 533,061 $ 371,329 $ 118,654
Commercial......................... 2,156,000 276,238 442,847 224,843 50,075
Industrial......................... 1,903,000 353,841 138,174 330,428 96,716
Other Retail Customers............. 385,000 80,429 38,018 61,450 16,911
Energy Delivery.................... (3,551,000) (594,089) (492,278) (321,721) (132,054)
----------- ---------- ---------- ---------- ---------
Total Retail.................... 4,606,000 732,928 659,822 666,329 150,302
Marketing and
Trading-Electricity............. 2,227,000 204,878 134,836 279,705 50,056
Marketing and Trading-Gas.......... 3,021,000 0 0 0 0
Unrealized MTM Income:
Electric........................ 136,000 18,089 13,388 0 0
Gas............................. (399,000) 0 0 0 0
Other.............................. 1,397,000 264,486 99,836 259,009 46,271
----------- ---------- ---------- ---------- ---------
Total Wholesale Business........ 10,988,000 1,220,381 907,882 1,205,043 246,629
----------- ---------- ---------- ---------- ---------
Energy Delivery Business:
Transmission....................... 922,000 186,960 107,673 118,812 50,381
Distribution....................... 2,629,000 407,129 384,605 202,909 81,673
----------- ---------- ---------- ---------- ---------
Total Energy Delivery........... 3,551,000 594,089 492,278 321,721 132,054
----------- ---------- ---------- ---------- ---------
Total Other Investments......... 16,000 0 0 0 0
----------- ---------- ---------- ---------- ---------
Total Revenues................ $14,555,000 $1,814,470 $1,400,160 $1,526,764 $ 378,683
=========== ========== ========== ========== =========
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OPCo PSO SWEPCo TCC TNC
---------- --------- ---------- ---------- --------
(IN THOUSANDS)
Wholesale Business:
Residential........................... $ 475,210 $ 315,711 $ 313,023 $ 49,210 $ 8,651
Commercial............................ 244,943 218,718 212,626 32,518 4,098
Industrial............................ 531,085 162,386 214,622 12,395 2,134
Other Retail Customers................ 71,737 38,998 33,104 3,594 1,638
Energy Delivery....................... (589,673) (275,547) (348,236) (554,547) (73,353)
---------- --------- ---------- ---------- --------
Total Retail....................... 733,302 460,266 425,139 (456,830) (56,832)
Marketing and Trading-Electricity..... 219,488 17,394 157,159 811,800 283,883
Marketing and Trading-Gas............. 0 0 0 0 0
Unrealized MTM Income:
Electric........................... 25,574 0 (3,686) (8,490) (1,473)
Gas................................ 0 0 0 0 0
Other................................. 545,088 40,440 157,872 789,466 151,809
---------- --------- ---------- ---------- --------
Total Wholesale Business........... 1,523,452 518,100 736,484 1,135,946 377,387
---------- --------- ---------- ---------- --------
Energy Delivery Business:
Transmission.......................... 162,660 63,178 92,076 68,003 25,273
Distribution.......................... 427,013 212,369 256,160 486,544 48,080
---------- --------- ---------- ---------- --------
Total Energy Delivery.............. 589,673 275,547 348,236 554,547 73,353
---------- --------- ---------- ---------- --------
Total Other Investments............ 0 0 0 0 0
---------- --------- ---------- ---------- --------
Total Revenues................... $2,113,125 $ 793,647 $1,084,720 $1,690,493 $450,740
========== ========= ========== ========== ========
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(a) Includes revenues of other subsidiaries not shown. Intercompany transactions
have been eliminated, including AEGCo's total revenues of $213,281,000 for
the year ended December 31, 2002, all of which resulted from its wholesale
business, including its marketing and trading of power.
REGULATION
GENERAL
AEPExcept for retail generation sales in Ohio, Virginia and its subsidiaries are subject to the broad regulatory provisionsERCOT area of
PUHCA administered by the SEC. TheTexas, AEP's public utility subsidiaries' retail rates and certain other matters
are subject to traditional regulation by the publicstate utility commissions of thecommissions. Retail
sales in Michigan, while still regulated, are now made at unbundled rates. Other
states in which they operate. SuchAEP's service territory have also passed restructuring legislation
that has not been implemented or has been repealed. See Electric Restructuring
and Customer Choice Legislation and Energy Delivery--Regulation--Rates. AEP's
subsidiaries are also subject to regulation by the FERC under the Federal Power Act in respect of
rates for interstate sale at wholesaleFPA. I&M and
transmission of electric power,
accounting and other matters and construction and operation of hydroelectric
projects. I&M isTCC 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.
POSSIBLE CHANGE TOPlant and STP, respectively.
AEP and its subsidiaries are also subject to the broad regulatory provisions of
PUHCA administered by the SEC.
FERC
Under the FPA, FERC regulates rates for interstate sales at wholesale,
transmission of electric power, accounting and other matters, including
construction and operation of hydroelectric projects. FERC regulations require
AEP to provide open access transmission service at FERC-approved rates. The
transmission service regulated by FERC is predominantly wholesale transmission
service, which is service not associated with bundled electricity sales to
retail customers. FERC also regulates unbundled transmission service to retail
customers.
Under the FPA, the FERC regulates the sale of power for resale in
interstate commerce by (i) approving contracts for wholesale sales to municipal
and cooperative utilities and (ii) granting authority to public utilities to
sell power at wholesale at market-based rates upon a showing that the seller
lacks the ability to improperly influence market prices. AEP has
5
market-rate authority from FERC, under which most of its wholesale marketing
activity takes place. In November 2001, the FERC issued an order in connection
with its triennial review of AEP's market based pricing authority requiring (i)
certain actions by AEP in connection with its sales and purchases within its
control area and (ii) posting of information related to generation facility
status on AEP's website. AEP has appealed this order, and the FERC has issued an
order delaying the effective date of the order. See Note 9 to the consolidated
financial statements, entitled Commitments and Contingencies, incorporated by
reference in Item 8, for more information on the current status of this
proceeding.
SEC
The provisions of PUHCA, administered by the SEC, regulate allmany aspects of
a registered holding company system, such as the AEP System. PUHCA requires thatlimits 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. In October 1995, legislation
was introduced in the U.S. Senate to repeal PUHCA and transfer certain federal
authority to the FERC as recommended in the SEC report. 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.
On December 28, 1994, the SEC proposed revisions to
its rules governing transactions between associated companies in a registered
holding company system. These proposed revisions to the rules would price
transactions governed by SEC rules at a market-based price if it is lower than
cost. In its June 1995 report, theThe Division of Investment Management of the SEC has recommended that the
proposed revisionsconditional repeal of PUHCA. Under its recommendation, certain oversight
authority would be transferred to the rules be withdrawn.
In addition, proposals haveFERC. Legislation has since been
made forintroduced in numerous sessions of Congress tothat would repeal PUHCA, or modify
its provisions governing intra-system transactions.but such
legislation has not passed.
AEP-CSW MERGER
On June 15, 2000, CSW (now known as AEP Utilities, Inc.) merged with and
into a wholly-owned merger subsidiary of AEP. As a result, CSW became a wholly
owned subsidiary of AEP. The effectfour wholly owned public utility subsidiaries of
possible SEC
revisions of these cost provisions or the 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-inCSW--PSO, SWEPCo, TCC and whether it is eliminated
for all intra-system transactions or only some. If the cost recovery
assurance is eliminated immediately for all intra-system transactions,
it could have a material adverse effect on results of operations and
financial condition of AEP and OPCo.
CONFLICT OF REGULATION
PublicTNC--became indirect wholly owned public utility
subsidiaries of AEP can be subject to regulationas a result of the same
subject mattermerger. The merger was approved by two or more jurisdictions. In such situations, it is
possible that the
decisions of such regulatory bodies may conflict or thatFERC and 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,SEC (with respect to PUHCA).
On January 18, 2002, the U.S. Court of Appeals for the District of Columbia
ruled that the SEC failed to properly explain how the merger met the
requirements of PUHCA and remanded the case to the SEC for further review. The
court held that the determinationSEC had not adequately explained its conclusions that the
merger met PUHCA requirements that the merging entities be "physically
interconnected" and that the combined entity was confined to a "single area or
region."
Management believes that the merger meets the requirements of costsPUHCA and
expects the matter to be chargedresolved favorably.
ELECTRIC RESTRUCTURING AND CUSTOMER CHOICE LEGISLATION
Certain states in AEP's service area have adopted restructuring or customer
choice legislation. In general, this legislation provides for a transition from
bundled cost-based rate regulated electric service to associated companies by the SEC under PUHCA precluded the FERC from
determining that such costs were unreasonableunbundled cost-based rates
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 major electric utility
subsidiaries of AEP derive revenues and the amount of such revenues (from
kilowatt-hour sales) during the year ended December 31, 1995 are as follows:
AEGCO APCO CSPCO I&M KEPCO OPCO AEP SYSTEM (a)
(IN THOUSANDS)
Retail
Residential
Without Electric Heating $ -- $ 240,385 $ 329,881 $ 239,266 $ 43,938 $ 277,780 $1,151,981
With Electric Heating -- 331,445 115,386 109,504 63,609 145,688 801,956
Total Residential -- 571,830 445,267 348,770 107,547 423,468 1,953,937
Commercial -- 284,866 371,461 256,319 58,606 257,300 1,265,776
Industrial -- 366,329 143,162 298,256 96,647 639,177 1,606,451
Miscellaneous -- 32,270 16,041 6,482 847 8,065 67,047
Total Retail -- 1,255,295 975,931 909,827 263,647 1,328,010 4,893,211
Wholesale (sales for resale) 231,659 269,493 75,466 357,441 60,567 457,758 680,905
Total from KWH Sales 231,659 1,524,788 1,051,397 1,267,268 324,214 1,785,768 5,574,116
Provision for Revenue Refunds -- (1,100) -- -- -- -- (1,100)
Total Net of Provision for
Revenue Refunds 231,659 1,523,688 1,051,397 1,267,268 324,214 1,785,768 5,573,016
Other Operating Revenues 136 21,351 20,465 15,889 3,930 37,229 97,314
Total Electric Operating
Revenues $231,795 $1,545,039 $1,071,862 $1,283,157 $328,144 $1,822,997 $5,670,330
(a) Includes revenues of other subsidiaries not shown and reflects elimination
of intercompany transactions.
SALE OF POWER
AEP's electric utility subsidiaries own or lease generating stations with
total generating capacity of 23,759 megawatts. See Item 2 for more information
regarding the generating stations. They operate their generating plants as a
single interconnected and coordinated electric utility system and share the
costs and benefits in the AEP System Power Pool. Most of the electric power
generated at these stations is sold, in combination with transmission and distribution services, toservice and market pricing for the supply of
electricity with customer choice of supplier. At a minimum, this legislation
allows retail customers to select alternative generation suppliers. Electric
restructuring and/or customer choice began on January 1, 2001 in Ohio and on
January 1, 2002 in Michigan, Virginia and the ERCOT area of AEP's utility subsidiariesTexas. Electric
restructuring in their service territories. These sales are made at rates that are establishedthe SPP area of Texas, also scheduled to begin on January 1,
2002, has been delayed by the public utility commissions of the state in which they operate. See
RATES. Some of the electric power is sold at wholesale to non-affiliated
companies.
AEP SYSTEM POWER POOL
APCo, CSPCo, I&M, KEPCo and OPCo are parties to the Interconnection
Agreement, dated July 6, 1951, as amended (the Interconnection Agreement),
defining how they share the costs and benefits associated with the System's
generating plants. This sharing is based upon each company's "member-load-
ratio," which is calculated monthly on the basis of each company's maximum peak
demand in relation to the sum of the maximum peak demands of all five companies
during the preceding 12 months. In addition, since 1995, APCo, CSPCo, I&M,
KEPCo and OPCo have been parties to the AEP System Interim Allowance Agreement
which provides, among other things, for the transfer of SO{2} Allowances
associated with transactions under the Interconnection Agreement.
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, 1993, 1994 and 1995:
1993 1994 1995(a)
(in thousands)
APCo $(260,000) $(254,000) $(252,000)
CSPCo (141,000) (105,000) (143,000)
I&M 183,000 107,000 118,000
KEPCo 1,000 12,000 23,000
OPCo 217,000 240,000 254,000
(a) Includes credits and charges from allowance transfers related to the
transactions.
In July 1994, APCo, CSPCo, I&M, KEPCo and OPCo entered into the AEP System
Interim Allowance Agreement (IAA). Reference is made to ENVIRONMENTAL AND
OTHER MATTERS - CLEAN AIR ACT AMENDMENTS OF 1990 for a discussion of SO{2}
Allowances. The IAA provides for and governs the terms of the following
allowance transactions among the parties which began January 1, 1995: (1) an
annual reallocation of certain SO{2} Allowances initially allocated by the
Federal EPA to OPCo's Gavin Plant; (2) transfer of SO{2} Allowances associated
with energy transactions among APCo, CSPCo, I&M, KEPCo and OPCo, (3) a monthly
cash settlement for SO{2} Allowances consumed in connection with power sales to
non-affiliated electric utilities; and (4) transfers of SO{2} Allowances for
current and future period compliance. The IAA does not provide for the
allocation of costs and proceeds related to the sale or purchase of SO{2}
Allowances to or from non-affiliated companies. The IAA was accepted by the
FERC on December 30, 1994.
WHOLESALE SALES OF POWER TO NON-AFFILIATES
AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo also sell electric power on a
wholesale basis to non-affiliated electric utilities and power marketers. Such
sales are either made by the AEP System and then allocated among APCo, CSPCo,
I&M, KEPCo and OPCo based on member-load-ratios or made by individual companies
pursuant to various long-term power agreements. The following table shows the
amounts contributed to operating income of the various companies from such
sales during the years ended December 31, 1993, 1994 and 1995:
1993(a) 1994(a) 1995(a)
(in thousands)
AEGCo(b) $ 32,500 $ 30,800 $ 29,200
APCo(c) 23,600 25,000 24,100
CSPCo(c) 12,000 11,700 12,000
I&M(c)(d) 35,300 34,600 34,700
KEPCo(c) 4,900 4,800 5,000
OPCo(c) 20,700 20,000 20,200
Total System $129,000 $126,900 $125,200
(a) Such sales do not include wholesale sales to full/partial requirement
customers of AEP System companies. See the discussion below.
(b) All amounts for AEGCo are from sales made pursuant to a long-term power
agreement. See AEGCO - UNIT POWER AGREEMENTS.
(c) All amounts, except for I&M, are from System sales which are allocated
among APCo, CSPCo, I&M, KEPCo and OPCo based upon member-load-ratio. All
System sales made in 1993, 1994 and 1995 were made on a short-term basis,
except that $16,800,000, $21,800,000 and $22,500,000, respectively, of the
contribution to operating income for the total System were from long-term
System sales.
(d) In addition to its allocation of System sales, the 1993, 1994 and 1995
amounts for I&M include $21,600,000, $21,600,000 and $21,000,000 from a
long-term agreement to sell 250 megawatts of power scheduled to terminate
in 2009.
The AEP System has long-term system agreements to sell 100 megawatts of
electric power through 1997 and to sell at times up to 200 megawatts of peaking
power through March 1997 to unaffiliated utilities. In addition, commencing
January 1996, the AEP System began supplying 205 megawatts of electric power to
an unaffiliated utility for 15 years and commencing September 1996, the AEP
System will begin supplying 50 megawatts of electric power to an unaffiliated
utility for five years.
In addition to long-term and short-term sales, APCo, CSPCo, I&M, KEPCo and
OPCo serve unaffiliated wholesale customers that are full/partial requirement
customers. The aggregate maximum demand for these customers in 1995 was 574,
112, 536, 17 and 138 megawatts for APCo, CSPCo, I&M, KEPCo and OPCo,
respectively. Although the terms of the contracts with these customers vary,
they generally can be terminated by the customer upon one to four years'
notice. In 1995, customers gave notices of termination, effective in 1998, for
419, 5 and 67 megawatts for APCo, I&M and OPCo, respectively.
In June 1993, certain municipal customers of APCo, who have since given APCo
notice to terminate their contracts in 1998, filed an application with the FERC
for transmission service in order to reduce by 50 megawatts the power these
customers purchase under existing Electric Service Agreements (ESAs) and to
purchase power from a third party. APCo maintains that its agreements with
these customers are full-requirements contracts which preclude the customers
from purchasing power from third parties. On February 10, 1994, the FERC
issued an order finding that the ESAs are not full requirements contracts and
that the ESAs give these municipal wholesale customers the option of
substituting alternative sources of power for energy purchased from APCo. On
May 24, 1994, APCo appealed the February 10, 1994 order of the FERC to the U.S.
Court of Appeals for the District of Columbia Circuit. On July 1, 1994, the
FERC ordered the requested transmission service and granted a complaint filed
by the municipal customers directing certain modifications to the ESAs in order
to accommodate their power purchases from the third party. Following FERC's
denial of APCo's requests for rehearing, on December 20, 1995, APCo appealed
the July 1, 1994 Orders to the U.S. Court of Appeals for the District of
Columbia. Effective August 1994, these municipal customers reduced their
purchases by 40 megawatts. Certain of these customers further reduced their
purchases by an additional 21 megawatts effective February 1996.
TRANSMISSION SERVICESPUCT. 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
electricpublic utility subsidiaries operate their transmission lines as a single
interconnectedin
both the ERCOT and coordinated systemSPP areas of Texas.
Implementation of legislation enacted in Oklahoma and share the cost and benefits in the
AEP System Transmission Pool. Most of the transmission and distribution
services is sold, in combination with electric power, to retail customers of
AEP's utility subsidiaries in their service territories. These sales are made
at rates that are established by the public utility commissions of the state in
which they operate. See RATES. 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, 1993,
1994 and 1995:
1993 1994 1995
(in thousands)
APCo $ (3,200) $(10,200) $ (5,400)
CSPCo (31,200) (30,100) (31,100)
I&M 47,400 50,300 46,700
KEPCo 3,800 4,300 3,500
OPCo (16,800) (14,300) (13,700)
TRANSMISSION SERVICES FOR NON-AFFILIATES
APCo, CSPCo, I&M, KEPCo, OPCo and other System companies also provide
transmission services for non-affiliated companies. The following table shows
the amounts contributed to operating income of the various companies from such
services during the years ended December 31, 1993, 1994 and 1995:
1993 1994 1995
(in thousands)
APCo $ 2,900 $ 4,100 $ 6,000
CSPCo 2,500 3,100 4,200
I&M 7,700 6,700 4,800
KEPCo 600 800 1,200
OPCo 9,900 15,700 17,800
Total System $23,600 $30,400 $34,000
The AEP System has long-term contracts with non-affiliated companies for
transmission of approximately 690 megawatts of electric power and contracts
with non-affiliated companies for transmission during 1996 of approximately
1,400 megawatts of electric power.
On April 12, 1993, APCo, CSPCo, I&M, KEPCo and OPCo and two other AEP System
companies filed a transmission tariff with the FERC under which these AEP
System companies would provide limited transmission service to certain
companies. The tariff covered the terms and conditions of the service, as well
as the price which the companies pay for transmission services, regardless of
the source of electric power generation. On September 3, 1993, the FERC issued
an order accepting the transmission service tariff for filing, with the tariff
becoming effective on September 7, 1993, subject to refund. On May 11, 1994,
the FERC issued an order on rehearing and indicated that an open access tariff
should offer third parties access to the transmission system on the same or
comparable basis, and under the same or comparable terms and conditions, as the
transmission provider's access to its system.
On March 29, 1995, the FERC issued a Notice of Proposed Rulemaking ("Mega-
NOPR"). The Mega-NOPR proposes to require each public utility that owns or
controls interstate transmission facilities to file open access network and
point-to-point transmission tariffs that offer services comparable to the
utility's own uses of its transmission system. The Mega-NOPR also proposes to
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 proposed rule, the FERC issued recommended PRO-FORMA tariffs which reflect
the Commission's preliminary views on the minimum non-price terms and
conditions for non-discriminatory transmission service. In connection with the
Mega-NOPR, the Commission offered certain waivers of its regulations to
utilities willing to adopt the PRO-FORMA tariffs prior to issuance of the final
rule. The Mega-NOPR also would allow a utility to seek recovery of certain
prudently-incurred stranded costs that result from unbundled transmission
service.
On July 18, 1995, the AEP System companies filed an Offer of Settlement in
their transmission tariff case, in which the companies proposed to adopt the
FERC's PRO-FORMA transmission tariffs at certain stated rates that were lower
than those requested in their initial tariff filing. The Offer of Settlement
was approved by the FERC on February 14, 1996, except for certain pricing
issues, which are still pending resolution by FERC.
AEP has proposed creation of an independent system operator to operate the
transmission system in a region of the United States. See COMPETITION AND
BUSINESS CHANGE - AEP POSITION ON COMPETITION.
OVEC
AEP, CSPCo and several unaffiliated utility companies jointly own OVEC,
which supplies the power requirements of a uranium enrichment plant near
Portsmouth, Ohio owned by the DOE. The aggregate equity participation of AEP
and CSPCo in OVEC is 44.2%. The DOE demand under OVEC's power agreement, which
is subject to change from time to time, is 1,305,000 kilowatts. On October 1,
1996, it is scheduled to increase to approximately 1,905,000 kilowatts and to
remain at about that level through the remaining term of the contract. The
proceeds from the sale of power by OVEC, aggregating $299,000,000 in 1995, are
designed to be sufficient for OVEC to meet its operating expenses and fixed
costs and to provide a return on its equity capital. APCo, CSPCo, I&M and
OPCo, as sponsoring companies, are entitled to receive from OVEC, and are
obligated to pay for, the power not required by DOE in proportion to their
power participation ratios, which averaged 42.1% in 1995. The power agreement
with DOE terminates on December 31, 2005, subject to early termination by DOE
on not less than three years notice. The power agreement among OVEC and the
sponsoring companies expires by its terms on March 12, 2006.
BUCKEYE
Contractual arrangements among OPCo, Buckeye and other investor-owned
electric utility companies in Ohio provide for the transmission and delivery,
over facilities of OPCo and of other investor-owned utility companies, of power
generated by the two units at the Cardinal Station owned by Buckeye and back-up
power to which Buckeye is entitled from OPCo under such contractual
arrangements, to facilities owned by 27 of the rural electric cooperatives
which operate in the State of Ohio at 301 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 January 18, 1994,
was recorded at 1,146,933 kilowatts.
CERTAIN INDUSTRIAL CUSTOMERS
Ravenswood Aluminum Corporation and Ormet Corporation operate major aluminum
reduction plants in the Ohio River Valley at Ravenswood, West Virginia and in
the vicinity of Hannibal, Ohio, respectively. OPCo supplies all of the power
requirements of these plants pursuant to
long-term contracts with such
companies which, subject to certain curtailment provisions, terminate in 1997
in the case of Ormet and 1998 in the case of Ravenswood. The power
requirements of such plants presently aggregate approximately 890,000
kilowatts. OPCo is currently negotiating with Ormet and Ravenswood regarding
the extension of their contracts. See LEGAL PROCEEDINGS for a discussion of
litigation involving Ormet.
AEGCO
Since its formation in 1982, AEGCo's business has consisted of the ownership
and financing of its 50% interest in the Rockport Plant and, since 1989,
leasing of its 50% interest in Unit 2 of the Rockport Plant. The operating
revenues of AEGCo are derived from the sale of capacity and energy associated
with its interest in the Rockport Plant to I&M, KEPCo and VEPCo, pursuant to
unit power agreements. Pursuant to these unit power agreements, AEGCo is
entitled to recover its full cost of service from the purchasers and will be
entitled to recover future increases in such costs, including increases in fuel
and capital costs. See UNIT POWER AGREEMENTS. Pursuant to a capital funds
agreement, AEP has agreed to provide cash capital contributions, or in certain
circumstances subordinated loans, to AEGCo, to the extent necessary to enable
AEGCo, among other things, to provide its proportionate share of funds required
to permit continuation of the commercial operation of the Rockport Plant and to
perform all of its obligations, covenants and agreements under, among other
things, all loan agreements, leases and related documents to which AEGCo is or
becomes a party. See CAPITAL FUNDS AGREEMENT.
UNIT POWER AGREEMENTS
A unit power agreement between AEGCo and I&M (the I&M Power Agreement)
provides for the sale by AEGCo to I&M of all the power (and the energy
associated therewith) available to AEGCo at the Rockport Plant. I&M is
obligated, whether or not power is available from AEGCo, to pay as a demand
charge for the right to receive such power (and as an energy charge for any
associated energy taken by I&M) such amounts, as when added to amounts received
by AEGCo from any other sources, will be at least sufficient to enable AEGCo to
pay all its operating and other expenses, including a rate of return on the
common equity of AEGCo as approved by FERC, currently 12.16%. The I&M Power
Agreement will continue in effect until the date that the last of the lease
terms of Unit 2 of the Rockport Plant has expired unless extended in specified
circumstances.
Pursuant to an assignment between I&M and KEPCo, and a unit power agreement
between KEPCo and AEGCo, AEGCo sells KEPCo 30% of the power (and the energy
associated therewith) available to AEGCo from both units of the Rockport Plant.
KEPCo has agreed to pay to AEGCo in consideration for the right to receive such
power the same amounts which I&M would have paid AEGCo under the terms of the
I&M Power Agreement for such entitlement. The KEPCo unit power agreement
expires on December 31, 1999, unless extended.
A unit power agreement among AEGCo, I&M, VEPCo, and APCo provides for, among
other things, the sale of 70% of the power and energy available to AEGCo from
Unit 1 of the Rockport Plant to VEPCo by AEGCo from January 1, 1987 through
December 31, 1999. VEPCo has agreed to pay to AEGCo in consideration for the
right to receive such power those amounts which I&M would have paid AEGCo under
the terms of the I&M Power Agreement for such entitlement. Approximately 34%
of AEGCo's operating revenue in 1995 was derived from its sales to VEPCo.
CAPITAL FUNDS AGREEMENT
AEGCo and AEP have entered into a capital funds agreement pursuant to which,
among other things, AEP has unconditionally agreed to make cash capital
contributions, or in certain circumstances subordinated loans, to AEGCo to the
extent necessary to enable AEGCo to (i) maintain such an equity component of
capitalization as required by governmental regulatory authorities, (ii) provide
its proportionate share of the funds required to permit commercial operation of
the Rockport Plant, (iii) enable AEGCo to perform all of its obligations,
covenants and agreements under, among other things, all loan agreements, leases
and related documents to which AEGCo is or becomes a party (AEGCo Agreements),
and (iv) pay all indebtedness, obligations and liabilities of AEGCo (AEGCo
Obligations) under the AEGCo Agreements, other than indebtedness, obligations
or liabilities owing to AEP. The Capital Funds Agreement will terminate after
all AEGCo Obligations have been paid in full.
INDUSTRY PROBLEMS
The electric utility industry, including the operating subsidiaries of AEP,
has encountered at various times in the last 15 years significant problems in a
number of areas, including: delays in and limitations on the recovery of fuel
costs from customers; proposed legislation, initiative measures and other
actions designed to prohibit construction and operation of certain types of
power plants under certain conditions and to eliminate or reduce the extent of
the coverage of fuel adjustment clauses; inadequate rate increases and delays
in obtaining rate increases; jurisdictional disputes with state public
utilities commissions regarding the interstate operations of integrated
electric systems; requirements for additional expenditures for pollution
control facilities; increased capital and operating costs; construction delays
due, among other factors, to pollution control and environmental considerations
and to material, equipment and fuel shortages; the economic effects on net
income (which when combined with other factors may be immediate and adverse)
associated with placing large generating units and related facilities in
commercial operation, including the commencement at that time of substantial
charges for depreciation, taxes, maintenance and other operating expenses, and
the cessation of AFUDC with respect to such units; uncertainties as to
conservation efforts by customers and the effects of such efforts on load
growth; depressed economic conditions in certain regions of the United States;
increasingly competitive conditions in the wholesale and retail markets;
proposals to deregulate certain portions of the industry and revise the rules
and responsibilities under which new generating capacity is supplied; and
substantial increases in construction costs and difficulties in financing due
to high costs of capital, uncertain capital markets, charter and indenture
limitations restricting conventional financing, and shortages of cash for
construction and other purposes.
SEASONALITY
Sales of electricity by the AEP System tend to increase and decrease because
of the use of electricity by residential and commercial customers for cooling
and heating and relative changes in temperature.
FRANCHISES
The operating companies of the AEP System hold franchises to provide
electric service in various municipalities in their service areas. These
franchises have varying provisions and expiration dates. In general, the
operating companies consider their franchises to be adequate for the conduct of
their business.
COMPETITION AND BUSINESS CHANGE
GENERAL
The public utility subsidiaries of AEP, like 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. FERC has proposed that utilities be required, and the public
utility subsidiaries of AEP have agreed, to sell transmission services
separately from their other services. Proposals are being made that would also
require electric utilities to sell distribution services separately. These
proposals 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 a result, it is not clear how or when
competition in generation and sale of electric power will be instituted.
However, if 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 stranded investment losses.
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.
The Mega-NOPR proposes that utilities be required to 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 Mega-
NOPR also would allow a utility to seek recovery of certain prudently-incurred
stranded costs that result from unbundled transmission service. The public
utility subsidiaries of AEP are preparing to functionally separate their
wholesale power sales from their transmission functions, as proposed in the
Mega-NOPR and required by their transmission tariffs.
RETAIL
The public utility subsidiaries of AEP generally have the exclusive right to
sell electric power at retail within their service areas. However, they do
compete with self-generation and with distributors of other energy sources,
such as natural gas, fuel oil and coal, within their service areas. The
primary factors in such competition are price, reliability of service and the
capability of customers to utilize sources of energy other than electric power.
With respect to self-generation, the public utility subsidiaries of AEP believe
that they maintain a favorable competitive position on the basis of all of
these factors. With respect to alternative sources of energy, the public
utility subsidiaries of AEP believe that the reliability of their service and
the limited ability of customers to substitute other cost-effective sources for
electric power place them in a favorable competitive position, even though
their prices may be higher than the costs of some other sources of energy.
Significant changes in the global economy in recent years have led to
increased price competition for industrial companies in the United States,
including those served by the AEP System. Such industrial companies have
requested price reductions from their suppliers, including their suppliers of
electric power. In addition, industrial companies which are downsizing or
reorganizing often close a facility based upon its costs, which may include,
among other things, the cost of electric power. The public utility
subsidiaries of AEP cooperate with such customers to meet their business needs
through, for example, various off-peak or interruptible supply options and
believe that, as low cost suppliers of electric power, they should be less
likely to be materially adversely affected by this competition and may be
benefitted by attracting new industrial customers to their service territories.
The legislatures and/or the regulatory commissions in several states are
considering "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 electionchoose their electricity supplier is on hold. In 2001
Oklahoma delayed implementation 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 have a favorable competitive
position because of their relatively low costs.
MICHIGAN: On June 19, 1995, the MPSC approved an experimental five-year
retail wheeling program and ordered Consumers Power Company and Detroit Edison
Company, unaffiliated utilities, to make retail delivery services available to
a group of industrial customers, in the amount of 60 megawatts and 90
megawatts, respectively. The experiment will commence when each utility needs
new capacity. The experiment seeks, as its goal, to determine whether a retail
wheeling program best serves the public interest in a manner that promotes
retail competition in a non-discriminatory fashion. During the experiment, the
MPSC will collect information regarding the effects of retail wheeling.
In January 1996, the Governor of Michigan endorsed a proposal of the
Michigan Jobs Commission to promote competition and customer choice indefinitely. Before West
Virginia's choice plan can be effective, tax legislation must be passed to
preserve pre-legislation levels of funding for state and local governments. No
further legislation has been passed related to restructuring in energy.
Under the proposal, by January 1997, industrial and commercial customers would
be permitted to choose suppliers for new electrical load and tariffs would be
unbundled. By January 1998, an independent wholesale power pool with an
independent operator would be formed. By 2001, power generation for industrial
and commercial would not be subject to rate regulation and franchise
territories would be eliminated.
OHIO: On April 15, 1994, the Ohio Energy Strategy Task Force releasedWest Virginia.
In February 2003, Arkansas repealed its final report. The report contained seven broad implementation strategies along
with 53 specific initiatives to be undertaken by government and the private
sector. One strategy recommended continuing to encourage competition in the
electric utility industry in a manner which maximizes benefits and efficiencies
for all customers. An initiative under this strategy recommends facilitating
informal roundtable discussions on issues concerning competition in the
electric utility industry and promoting increased competitive options for Ohio
businesses that do not unduly harm the interests of utility company
shareholders or ratepayers. The PUCO has begun such discussions. As a result,
on February 15, 1996, the PUCO adopted guidelines for interruptible electric
service, including a buy-through provision that will enable customers to avoid
being interrupted during utility capacity deficiencies by having the utility
purchase off-system replacement power for the customer.
In March 1996, H.B. 653 was introduced in the Ohio House of Representatives.
The bill proposes that all customers be permitted to select their electricity
suppliers effective January 1, 1998. The bill eliminates price regulation of
electricity generation functions in favor of market based prices. Service area
rights for Ohio's electricity suppliers would be confined to distribution
service. Transmission and distribution services would continue to be regulated
at the federal and state levels, respectively. The bill would require Ohio's
electric utilities to functionally unbundle their generation, transmission and
distribution services. Electric utilities would be permitted to recover
transition costs provided that such recovery does not cause prices to exceed
those in effect on the effective date of therestructuring legislation.
VIRGINIA: In September 1995, the Virginia SCC instituted a proceeding to
review and consider policy regarding restructuring and the role of competition
in the electric utility industry in Virginia. The Virginia SCC has directed
its staff to conduct an investigation of current issues in the electric utility
industry and to file a report of its observation and recommendations on issues
identified in the Virginia SCC order. In addition, the Virginia legislature
has adopted a resolution establishing a subcommittee to study, in consultation
with the Virginia SCC, restructuring and potential changes in the electric
utility industry in Virginia and determine the need for legislative changes.
AEP POSITION ON COMPETITION
In October 1995, AEP announced that it favored freedom for customers to
purchase electric power from anyone that they choose. Generation and sale of
electric power would be in the competitive marketplace. To facilitate
reliable, safe and efficient service, AEP supports creation of independent
system operators to operate the transmission system in a region of the United
States. In addition, AEP supports the evolution of regional power exchanges
which would establish a competitve marketplace for the sale of electric power.
Transmission and distribution would remain monopolies and subject to regulation
with respect to terms and price. Regulators would be able to establish
distribution service charges which would provide, as appropriate, for recovery
of stranded costs and regulatory assets. Implementation of this proposal would
require legislative changes and regulatory approvals.
POSSIBLE STRATEGIC RESPONSES
In responseSee Note 7 to the competitive forces and regulatory changes being faced by
AEP and its public utility subsidiaries, as discussed under this heading and
under REGULATION, AEP and its public utility subsidiaries have from time to
time considered, and expect to continue to consider, various strategies
designed to enhance their competitive position and to increase their ability to
adapt to and anticipate changes in their utility business. These strategies
may include business combinations with other companies, internal restructurings
involving the complete or partial separation of their generation, transmission
and distribution businesses, acquisitions of related or unrelated businesses,
and additions to or dispositions of portions of their franchised service
territories. AEP and its public utility subsidiaries may from time to time be
engaged in preliminary discussions, either internally or with third parties,
regarding one or more of these potential strategies. No assurances can be
given as to whether any potential transaction of the type described above may
actually occur, or as to its ultimate effect on the financial condition or
competitive position of AEP and its public utility subsidiaries.
NEW BUSINESS DEVELOPMENT
AEP continues to consider new business opportunities, particularly those
which allow use of its expertise. These endeavors began in 1982 and are
conducted through AEP Energy Services, Inc. (AEPES) and AEP Resources, Inc.
(Resources).
Resources' primary business is development of, and investment in, exempt
wholesale generators, foreign utility companies, qualifying cogeneration
facilities and other power projects. Resources currently does not have an
interest in any power projects. Resources, however, has entered into a
strategic alliance with Cogentrix Energy, Inc. and Zurn Industries, Inc. to
develop, own and operate industrial power projects in the United States and
Canada. In addition, Resources is investigating opportunities to develop and
invest in new, and invest in existing, generation projects in China, Australia,
Mexico and India.
In 1994, AEP Resources International, Limited (AEPRI), a wholly owned
subsidiary of Resources, signed an agreement of intent with Northeast China
Electric Power Group Corp. (NEPG) to design two 1,300-megawatt, coal-fired
electric generating units in Suizhong, Liaoning Province, China. The
feasibility study for this project has been approved by the Chinese Ministry of
Electric Power and is awaiting approval by the State Planning Commission.
AEPRI is also involved in the advanced stages of negotiations to establish a
joint venture with two Chinese partners to develop and own two 125-megawatt,
coal-fired units in Henan Province, China.
AEPES offers engineering, construction, project management and other
consulting services for projects involving transmission, distribution or
generation of electric power both domestically and internationally.
AEP has received approval from the SEC under PUHCA to finance up to
$300,000,000, and has requested approval to finance up to 50% of its
consolidated retained earnings (approximately $700,000,000), for investment in
exempt wholesale generators and foreign utility companies. AEP also has
requested authority from the SEC under PUHCA to invest up to $100,000,000 in
subsidiaries engaged in the business of marketing energy commodities, including
electricity and gas.
These continuing efforts to invest in and develop new business opportunities
offer the potential of earning returns which may exceed those of rate-regulated
operations. However, they also involve a higher degree of risk which must be
carefully considered and assessed. AEP may make substantial investments in
these and other new businesses.
CONSTRUCTION PROGRAM
NEW GENERATION
The AEP System companies are engaged in a continuing construction program,
involving assessment of needs, selection of sites, design and acquisition of
equipment, and installation of the generating, transmission, distribution and
other facilities necessary to provide for generation, transmission and
distribution of electric power. At the present time, there are no specific
commitments for additions of new generating stations on the AEP System. Size,
technology, type, ownership (among AEP operating companies), means of
acquisition and precise timing of future capacity additions on the AEP System
have not yet been determined. However, the resource plan filed by AEP's
electric utility subsidiaries with various state commissions indicates no need
for new generation until sometime after the year 2000. Initial future capacity
additions will most likely be short lead time, simple-cycle, gas-fired
combustion turbines. The current resource plan indicates no need for new coal-
fired baseload generation until sometime after the year 2010. The size of any
new coal-fired generation will most likely be significantly smaller than the
1,300-megawatt units last added to the AEP System, to better match projected
load growth.
Proposals have been made, some of which have been adopted, that require the
public utility subsidiaries of AEP to file with state commissions resource
plans, indicating their plans to satisfy expected demand for electric power in
their service territory. When the AEP System needs new generation, some of
these proposals also require the public utility subsidiaries of AEP which wish
to provide the new generation to compete with exempt wholesale generators,
independent power producers and other utilities. Although the specific
guidelines for such competition have not yet been developed and may vary from
jurisdiction to jurisdiction (see the discussion below), significant factors
will include price and reliability.
For some years, the AEP System has put in place a series of customer
programs for encouraging electric conservation and load management (CLM). The
CLM programs also are referred to in the electric utility industry as "demand-
side management" programs (DSM) since they affect the demand for electric power
as opposed to its supply. The AEP System utilizes integrated resource planning
and has in place a detailed analysis procedure in which effective demand-side
and supply-side options are both considered in order to determine the least
cost approach to provide reliable electric service for its customers, taking
into account environmental and other considerations.
INDIANA: In May 1995, the IURC adopted rules for integrated resource
planning guidelines, including consideration of resource bidding and
independent power producers, and for demand-side management. I&M filed its
first integrated resource plan in November 1995.
MICHIGAN: The MPSC has adopted guidelines governing the acquisition of new
capacity by large Michigan electric utilities. The guidelines do not apply to
I&M.
OHIO: On December 17, 1992, the PUCO issued an order proposing rules for
competitive bidding for new generating capacity, including transmission access
for winning bidders. The proposed rules would establish a rebuttable
presumption of prudence where new generating capacity is acquired through
competitive bidding and provide other incentives to use competitive bidding.
The proposed rules also contain procedures to ensure that bidders for a
utility's new capacity will have open access to certain transmission facilities
and prohibit the utility acquiring new capacity from withholding SO{2}
Allowances from potential bidders. CSPCo and OPCo filed comments on the
proposed rules generally supporting promulgation of rules governing competitive
bidding but stating that the rules should not address access to transmission
facilities or SO{2} Allowances, because existing federal laws address such
concerns.
VIRGINIA: On October 24, 1994, the Virginia SCC began a proceeding to
consider whether to adopt standards related to integrated resource planning,
conservation, demand-side management and energy efficiency in power generation
and supply for jurisdictional electric utilities. On September 27, 1995, the
Virginia SCC declined to adopt the proposed standards, but reaffirmed its goals
for integrated resource planning, investment in cost-effective conservation and
demand management programs. Virginia electric utilities are to continue to
file biennial twenty-year resource plans. The Virginia SCC also has adopted
minimum requirements for any electric utility that elects to acquire new
generation through a bidding program. An electric utility is not required to
use the bidding process and may participate in the bidding process.
WEST VIRGINIA: On October 8, 1993, the West Virginia PSC issued an order
proposing rules that generally require electric utilities to procure
competitively all new sources of generation. APCo and Wheeling Power Company
filed comments stating that the rules should not require competitive bidding
and should permit the utility to participate in the bidding process.
PROPOSED TRANSMISSION FACILITIES
APCO: On March 23, 1990, APCo and VEPCo announced plans, subject to
regulatory approval, for major new transmission facilities. APCo will
construct approximately 115 miles of 765,000-volt line from APCo's Wyoming
station in southern West Virginia to APCo's Cloverdale station near Roanoke,
Virginia. VEPCo will construct approximately 102 miles of 500,000-volt line
from APCo's Joshua Falls station east of Lynchburg, Virginia to VEPCo's
Ladysmith station north of Richmond, Virginia. The construction of the
transmission lines and related station improvements will provide needed
reinforcement for APCo's internal load, reinforce the ability to exchange
electric power between the two companies and relieve present constraints on the
transmission of electric power from potential independent power producers in
the APCo service area to VEPCo. APCo's cost is estimated at $245,000,000 while
VEPCo's cost is estimated at $164,000,000. Completion of the project is
presently scheduled for 2000 but the actual service date will be dependent upon
the time necessary to meet various regulatory requirements.
Hearings before the Virginia SCC were concluded in September 1993. A report
was issued by the hearing examiner in December 1993 which recommended that the
Virginia SCC grant APCo approval to construct the proposed 765,000-volt line.
In an interim order issued on December 13, 1995, the Virginia SCC found that
major additional transmission capacity was needed to serve APCo's native load
customers. The Virginia SCC further asked that APCo provide additional
information on possible routing modifications and utilization of the additional
transmission capacity prior to a final ruling.
APCo refiled with the West Virginia PSC in February 1993 its application for
certification. An application filed in June 1992 was withdrawn at the request
of the West Virginia PSC to permit additional time for review by the West
Virginia PSC. The West Virginia PSC rejected APCo's application for
certification in May 1993, directing APCo to supplement its line siting
information. APCo intends to refile its application with the West Virginia
PSC. Hearings are expected to be held in late 1996 or early 1997, with a
decision expected in late 1997 or early 1998.
The Jefferson National Forest (JNF) is directing the preparation of an
Environmental Impact Statement (EIS) which will be required prior to the
granting of special use permits for crossing Federal lands. The present
schedule of the JNF calls for completion of the draft EIS in June 1996 and the
final EIS in early 1998.
APCO AND KEPCO: APCo and KEPCo have announced an improvement plan to be
implemented during a four-year period (1996-1999) to reinforce their 138,000-
volt transmission system. Included in this plan is a new transmission line to
link KEPCo's Big Sandy Plant to communities in eastern Kentucky. APCo's and
KEPCo's estimated project costs are $5,115,000 and $84,184,000, respectively.
Work on the project is scheduled to begin later in 1996, pending approval from
the KPSC.
CONSTRUCTION EXPENDITURES
The following table shows the construction expenditures by AEGCo, APCo,
CSPCo, I&M, KEPCo, OPCo and the AEP System and their respective consolidated
subsidiaries during 1993, 1994 and 1995 and their current estimate of 1996
construction expenditures, in each case including AFUDC but excluding nuclear
fuel and other assets acquired under leases. The construction expenditures for
the years 1993-1995 were applied, and it is anticipated that the estimated
construction expenditures for 1996 will be applied, approximately as follows to
construction of the following classes of assets:
1993 1994 1995 1996
ACTUAL ACTUAL ACTUAL ESTIMATE
(in thousands)
AEGCO
Generating plant and facilities $ 3,100 $ 3,900 $ 4,000 $ 1,900
TOTAL $ 3,100 $ 3,900 $ 4,000 $ 1,900
APCO
Generating plant and facilities $ 51,200 $ 65,600 $ 42,400 $ 55,700
Transmission lines and facilities 36,700 38,700 35,200 31,300
Distribution lines and facilities 98,200 116,500 121,400 102,900
General plant and other facilities 4,800 9,500 18,600 13,900
TOTAL $190,900 $230,300 $217,600 $203,800
CSPCO
Generating plant and facilities $ 33,300 $ 24,800 $ 30,500 $ 20,400
Transmission lines and facilities 10,100 3,600 10,700 10,800
Distribution lines and facilities 40,700 50,800 56,600 50,800
General plant and other facilities 2,200 2,300 1,700 12,500
TOTAL $ 86,300 $ 81,500 $ 99,500 $ 94,500
1993 1994 1995 1996
ACTUAL ACTUAL ACTUAL ESTIMATE
(in thousands)
I&M
Generating plant and facilities $ 50,200 $ 49,700 $ 46,200 $ 33,600
Transmission lines and facilities 10,100 20,300 22,600 17,600
Distribution lines and facilities 41,300 42,300 41,500 40,900
General plant and other facilities 6,700 2,200 2,700 18,500
TOTAL $108,300 $114,500 $113,000 $110,600
KEPCO
Generating plant and facilities $ 8,100 $ 22,600 $ 6,200 $ 25,400
Transmission lines and facilities 6,700 6,400 7,900 33,000
Distribution lines and facilities 20,300 23,700 23,900 23,200
General plant and other facilities 0 500 1,300 3,400
TOTAL $ 35,100 $ 53,200 $ 39,300 $ 85,000
OPCO
Generating plant and facilities (a) $112,700 $ 83,800 $ 40,000 $ 36,200
Transmission lines and facilities 28,600 15,300 23,500 22,000
Distribution lines and facilities 46,000 45,200 51,400 52,200
General plant and other facilities 10,500 4,700 2,000 12,700
TOTAL $197,800 $149,000 $116,900 $123,100
AEP SYSTEM (b)
Generating plant and facilities (a) $258,600 $250,400 $169,300 $173,200
Transmission lines and facilities 92,800 85,400 102,500 115,400
Distribution lines and facilities 252,300 286,900 302,800 277,000
General plant and other facilities 24,400 19,400 26,600 61,400
TOTAL $628,100 $642,100 $601,200 $627,000
(a) Excludes expenditures associated with flue-gas desulfurization system which
was constructed by a non-affiliate at the Gavin Plant and is being leased
by OPCo. Actual expenditures for such system for 1993, 1994 and 1995 and
the current estimate for 1996 are $256,673,000, $176,220,000, $48,804,000
and $12,915,000, respectively. See ENVIRONMENTAL AND OTHER MATTERS - ACID
RAIN PROGRAM - AEP SYSTEM COMPLIANCE PLAN.
(b) Includes expenditures of other subsidiaries not shown.
Reference is made to the footnotes to the financial statements, entitled COMMITMENTS AND CONTINGENCIESEffects of
Regulation, incorporated by reference in Item 8, for a discussion of the effect
of restructuring and customer choice legislation on accounting procedures. See
Management's Discussion
6
and Analysis of Results of Operations and Financial Condition, under the
headings entitled Industry Restructuring and Corporate Separation for a
discussion of AEP's corporate separation plan filed with the FERC and related
settlement agreements with state commissions and other intervenors.
Michigan Customer Choice
Customer choice commenced for I&M's Michigan customers on January 1, 2002.
Rates for retail electric service for I&M's Michigan customers were unbundled
(though they continue to be regulated) to allow customers the ability to
evaluate the cost of generation service for comparison with other suppliers. At
December 31, 2002, none of I&M's Michigan customers had elected to change
suppliers and no alternative electric suppliers are registered to compete in
I&M's Michigan service territory.
Ohio Restructuring
The Ohio Act requires vertically integrated electric utility companies that
offer competitive retail electric service in Ohio to separate their generating
functions from their transmission and distribution functions. Following the
market development period (which will terminate no later than December 31,
2005), retail customers will receive distribution and, where applicable,
transmission service from the incumbent utility whose distribution rates will be
approved by the PUCO and whose transmission rates will be approved by the FERC.
See General--Regulation--FERC for a discussion of FERC regulation of
transmission rates and Energy Delivery--Regulation--Rates--Ohio for a discussion
of the impact of restructuring on distribution rates.
CSPCo and OPCo are each presently operating as functionally separated
electric utility companies and no longer charge bundled rates for retail
electric service. Each has sought and, from certain regulatory authorities,
obtained regulatory approval to legally separate its transmission and
distribution assets from its generation assets. CSPCo and OPCo are, however,
currently determining the regulatory feasibility of complying with restructuring
legislation through continued functional separation. Assuming regulatory
compliance, it is currently their intention to remain functionally separated.
Texas Restructuring
The Texas Act substantially amends the regulatory structure governing
electric utilities in Texas in order to allow retail electric competition for
all customers and requires each utility to separate into (i) a REP, (ii) a power
generation company and (iii) a transmission and distribution utility. Upon
separation, neither the REP nor the power generation company will be subject to
traditional cost of service rate regulation. See Energy Delivery--Regulation--
Rates--Texas for a discussion of the impact of restructuring on rates.
SWEPCo, TCC and TNC initially filed a restructuring plan in January 2000
(which they subsequently updated) that the PUCT approved in February 2002. The
updated restructuring plan provided for the legal separation of TCC's and TNC's
assets in accordance with the Texas Act into (i) an affiliate power generation
company, (ii) a transmission and distribution utility and (iii) various REPs,
including those subsequently purchased by Centrica (see below). TCC and TNC
continue to pursue legal separation as required by the Texas Act. The PUCT has
delayed the implementation of the plan for SWEPCo operations within the SPP area
of Texas.
Under the Texas Act, a REP, which itself cannot own any generation assets,
obtains its electricity from power generation companies, EWGs and other
generating entities and provides services at generally unregulated rates, except
that the prices that may be charged to residential and small commercial
customers by REPs affiliated with a utility within the affiliated utility's
service area are set by the PUCT until January 1, 2007. This set price is
referred to as the "price to beat" rate (PTB). Affiliate REPs are required to
offer the PTB rate to all residential and small commercial customers (with a
peak usage of less than 1,000 KW) effective January 1, 2002. As described below,
AEP sold its affiliate REPs that must provide PTB service. The PTB rate is still
relevant to AEP, however, in determining (i) the contingent portion of the sales
price of the affiliate REPs AEP sold and (ii) certain of AEP's obligations in
the 2004 true-up proceedings.
Prior to the start of retail competition in January 2002, AEP formed MECPL
and MEWTU to act as affiliate REPs for TCC and TNC respectively. MECPL and MEWTU
were sold in December 2002 to Centrica, which assumed all of the rights and
obligations of an affiliated REP, including the provision of PTB service and the
obligation to provide data necessary for TCC's and TNC's 2004 true-up
proceeding. In connection with the sale, TCC and TNC have contracted to supply
approximately 90% of MECPL's and
7
MEWTU's respective power requirements relating to former TCC and TNC PTB
customers for a two-year period. See Note 12 to the consolidated financial
statements, entitled Acquisitions, Distributions and Discontinued Operations,
incorporated by reference in Item 8, for more information on the sale of these
REPs and AEP's contractual rights and obligations in connection with the sale.
The Texas Act also allows certain transmission and distribution utilities
whose generation assets were unbundled to recover certain regulatory assets and
stranded costs related to their generation assets. For a discussion of (i)
regulatory assets and stranded costs subject to recovery by TCC and (ii) rate
adjustments made after implementation of restructuring to allow recovery of
certain costs by or with respect to TCC and TNC, see Energy Delivery--Regulatory
Assets, Stranded Cost Recovery and Certain Post-Restructuring Rate Adjustments.
Virginia Restructuring
The Virginia Act was enacted in 1999 providing for retail choice of
generation suppliers to be phased in over the January 1, 2002 to January 1, 2004
period. The Virginia Act required jurisdictional utilities to unbundle their
power supply and energy delivery rates and to file functional separation plans
by January 1, 2002. APCo filed its plan and, following VSCC approval of a
settlement agreement, now operates in Virginia as a functionally separated
electric utility charging unbundled rates for its retail sales of electricity.
The settlement agreement addressed functional separation, leaving decisions
related to legal separation for later VSCC consideration.
FINANCING
General
AEP's goal is to use cash from operations to fund capital expenditures,
dividends and working capital. Short-term debt is used as an interim bridge for
timing differences in the need for cash or to fund debt maturities until
permanent financing is arranged.
It has been the practice of AEP's operating subsidiaries to finance current
construction expenditures in excess of available cash from operations by
initially incurring short-term debt, 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. In the past, short-term debt has come from AEP's
commercial paper program and revolving credit facilities. Proceeds were loaned
to the subsidiaries through intercompany notes under the AEP money pool. The
recent downgrade of AEP's commercial paper rating by Moody's, described below,
may limit AEP's access to commercial paper on terms as favorable as those of
recent years. Therefore, AEP may establish commercial paper programs for certain
of its public utility subsidiaries and AEP Utilities. Certain public utility
subsidiaries of AEP also sell accounts receivable to provide liquidity.
AEP's revolving credit agreements (which backstop the commercial paper
program) include covenants and events of default typical for this type of
facility, including a maximum debt/capital test and a $50 million
cross-acceleration provision. At December 31, 2002, AEP was in compliance with
its debt covenants. With the exception of a voluntary bankruptcy or insolvency,
any event of default has either or both a cure period or notice requirement
before termination of the agreements. A voluntary bankruptcy or insolvency would
be considered an immediate termination event.
AEP's subsidiaries have also utilized, and expect to continue to utilize,
additional financing arrangements, such as leasing arrangements, including the
leasing of utility assets and coal mining and transportation equipment and
facilities.
Credit Ratings
The rating agencies have been conducting credit reviews of AEP and its
registrant subsidiaries. The agencies are also reviewing many companies in the
energy sector due to issues that impact the entire industry.
In February 2003 Moody's completed its review of AEP and its rated
subsidiaries. The results of that review were downgrades of the following
ratings for unsecured debt: AEP from Baa2 to Baa3, APCo from Baa1 to Baa2, TCC
from Baa1 to Baa2, PSO from A2 to Baa1, SWEPCo from A2 to Baa1. TNC, which had
no senior unsecured notes outstanding at the time of the ratings action, had its
mortgage bond debt downgraded from A2 to A3. AEP's commercial paper was also
concurrently downgraded from P-2 to P-3. The completion of this review was a
culmination of earlier ratings action in 2002 that had included a downgrade of
AEP from Baa1 to Baa2. With the completion of the reviews, Moody's has placed
AEP and its rated subsidiaries on stable outlook.
8
In March 2003 S&P completed its review of AEP and its rated subsidiaries.
The results of that review were downgrades of the ratings for unsecured debt for
AEP and its rated subsidiaries from BBB+ to BBB. AEP's commercial paper rating
was affirmed at A-2. With the completion of the reviews, S&P has placed AEP and
its rated subsidiaries on stable outlook.
In March 2003 Fitch completed its review of AEP. The result of that review
was a downgrade of AEP's unsecured debt rating from BBB+ to BBB. AEP's
commercial paper rating was affirmed at F-2. With the completion of the reviews,
Fitch has placed AEP and its rated subsidiaries on stable outlook.
See Management's Discussion and Analysis of Financial Condition, Accounting
Policies and Other Matters, incorporated by reference in Item 7, under the
heading entitled Financial Condition for additional information with respect to
AEP's credit ratings, liquidity and specific financing activities.
ENVIRONMENTAL AND OTHER MATTERS
General
AEP's subsidiaries are currently 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. The environmental issues that are potentially material to the AEP
system include:
- The CAA and CAAA and state laws and regulations (including State
Implementation Plans) that require compliance, obtaining permits and
reporting as to air emissions.
- Litigation with the federal and certain state governments and certain
special interest groups regarding whether modifications to or maintenance
of certain coal-fired generating plants required additional permitting or
pollution control technology. See Management's Discussion and Analysis of
Financial Condition, Accounting Policies and Other Matters under the
heading entitled Federal EPA Complaint and Notice of Violation and Note 9
to the consolidated financial statements entitled Commitments and
Contingencies, incorporated by reference in Items 7 and 8 respectively
for further information.
- Rules issued by the EPA and certain states that require substantial
reductions in NOx emissions. The compliance dates for these rules range
from 2003 to 2005. AEP is installing (or has installed) emission control
technology and is taking other measures to comply with required
reductions. See Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters and Note 9 to the
consolidated financial statements entitled Commitments and Contingencies,
incorporated by reference in Items 7 and 8 respectively, under the
heading entitled NOx Reductions for further information.
- CERCLA, which imposes upon owners and previous owners of sites, as well
as transporters and generators of hazardous material disposed of at such
sites, costs for environmental remediation. AEP does not, however,
anticipate that any of its currently identified CERCLA-related issues
will result in material costs or penalties to the AEP System. See
Management's Discussion and Analysis of Financial Condition, Accounting
Policies and Other Matters, incorporated by reference in Item 7, under
the heading entitled Superfund for further information.
- The Federal Clean Water Act, which prohibits the discharge of pollutants
into waters of the United States except pursuant to appropriate permits.
There are, however, no matters material to the AEP System currently
pending under the Clean Water Act.
- Solid and hazardous waste laws and regulations, which govern the
management and disposal of certain wastes. The majority of solid waste
created from the combustion of coal and fossil fuels is fly ash and other
coal combustion byproducts, which the EPA has determined are not
hazardous waste governed subject to RCRA.
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.
AEP's subsidiaries will confront several new environmental policies and
regulations over the next decade with the potential for substantial control
costs and premature retirement of some generating plants. These could include
(i) new or additional controls on sulfur dioxide, NOx and mercury emissions from
future laws or regulations, or the possibility of an
9
adverse decision in the new source review litigation; (ii) a new Clean Water Act
rule to reduce fish and other aquatic organisms killed at once-through cooled
power plants; (iii) finalization and implementation of more stringent water
quality-based permit limits; and (iv) a possible future requirement to reduce
carbon dioxide emissions. See Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters, incorporated by reference in
Item 7, under the heading entitled Environmental Concerns and Issues for
information on current environmental issues.
AEP expects costs related to environmental controls to eventually be
reflected in some jurisdictions in the rates of AEP's public utility
subsidiaries. In Michigan, Ohio, Texas and Virginia, those costs may not be
recoverable if future market prices for electricity generated by plants in those
jurisdictions are insufficient to permit AEP to recover such costs. Moreover,
legislation adopted by certain states and proposed at the state and federal
level governing restructuring of the electric utility industry may also affect
the recovery of certain of these costs. There can be no assurance that these
costs will be recovered.
AEP's international operations are subject to environmental regulation by
various authorities within the host countries. Under certain circumstances,
these authorities may require modifications to these facilities and operations
or impose fines and other costs for violations of applicable statutes and
regulations. From time to time, these operations are named as parties to various
legal claims, actions, complaints or other proceedings related to environmental
matters. AEP's UK generation facilities will be subject to additional
environmental constraints in 2008 (which become more stringent after 2015)
because they are subject to regulation governing large combustion plants. In the
fourth quarter of 2002, AEP decided not to install certain emission control
technology on its Fiddler's Ferry and Ferrybridge generation facilities in 2008.
This decision and its legal and regulatory consequences will result in a
significant reduction in the estimated economic life of those facilities.
The cost of complying with applicable environmental laws, regulations and
rules is expected to be material to the AEP System.
See Management's Discussion and Analysis of Results of Operations and
Management's Discussion and Analysis of Financial Condition, Accounting Policies
and Other Matters and Note 9 to the consolidated financial statements entitled
Commitments and Contingencies, incorporated by reference in Items 7 and 8,
respectively, for further information with respect to the construction plans of AEP and its operating
subsidiaries for the next three years.
The System construction program is reviewed continuously and is revised from
time to time in response to changes in estimates of customer demand, business
and economic conditions, the cost and availability of capital, environmental requirements and other factors. Changes in construction schedules and costs,
and in estimates and projections of needs for additional facilities, as well as
variations from currently anticipated levels of net earnings, Federal income
and other taxes, and other factors affecting cash requirements, may increase or
decrease the estimates of 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:matters.
Environmental Expenditures
Expenditures related to generation facility compliance with air and water
quality standards included in the gross additions to plant of the
System, during 1993, 19942001 and 19952002 and the current estimate for 19962003 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. 1993 1994 1995 1996
ACTUAL ACTUAL ACTUAL ESTIMATE
(in thousands)
AEGCo $ 0 $ 0 $ 0 $ 0
APCo 16,800 32,000 7,800 8,500
CSPCo 15,800 13,700 10,000 1,300
I&M 0 0 0 400
KEPCo 1,000 9,500 600 600
OPCo (a) 31,600 22,400 3,100 0Future expenditures could be significantly greater
if litigation regarding whether AEP System (a) $65,200 $77,600 $21,500 $10,800
(a)Excludes expenditures associated with flue-gas desulfurization system which
was constructed by a non-affiliate at the Gavin Plant andproperly installed emission control
equipment on its plants is being leased by
OPCo. Actual expenditures for such system for 1993, 1994 and 1995 and the
current estimate for 1996 are $256,673,000, $176,220,000, $48,804,000 and
$12,915,000, respectively.resolved against AEP. See ENVIRONMENTAL AND OTHER MATTERS - ACID RAIN
PROGRAM - AEP SYSTEM COMPLIANCE PLAN.
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 preferred stock, and cash capital
contributions by AEP. It has been the practice of AEP, in turn, to finance
cash capital contributionsNote 9 to the common stock equities of the operating
subsidiaries by issuing unsecured short-term debt, principally commercial
paper,consolidated
financial statements, entitled Commitments and then to sell additional shares of Common Stock of AEP for the
purpose of retiring the short-term debt previously incurred. In 1995, AEP
issued 1,400,000 shares of Common Stock pursuant to its Dividend Reinvestment
and Stock Purchase Plan. Although prevailing interest costs of short-term bank
debt and commercial paper generally have been lower than prevailing interest
costs of long-term debt securities, whenever interest costs of short-term debt
exceed costs of long-term debt, the companies might be adversely affected by
reliance on the use of short-term debt to finance their construction and other
apital requirements.
During the period 1993-1995, external funds from financings and capital
contributions by AEP amounted, with respect to APCo and KEPCo to approximately
31% and 53%, respectively, of the aggregate construction expenditures shown
above. During this same period, the amount of funds used to retire long-term
and short-term debt and preferred stock of AEGCo, CSPCo, I&M and OPCo exceeded
the amount of funds from financings and capital contributions by AEP.
The ability of AEP and its operating subsidiaries to issue short-term debt is
limited by regulatory restrictions and, in the case of most of the operating
subsidiaries, by provisions contained in their charters and in certain debt and
other instruments. The approximate amounts of short-term debt which the
companies estimate that they were permitted to issue under the most restrictive
such restriction, at January 1, 1996, and the respective amounts of short-term
debt outstanding on that date, on a corporate basis, are shown in the following
tabulation:
TOTAL AEP
SHORT-TERM DEBT AEP AEGCO APCO CSPCO I&M KEPCO OPCO SYSTEM(a)
(in millions)
Amount authorized $150 $80 $228 $175 $175 $150 $223 $1,256
Amount outstanding:
Notes payable $ 18 $22 $ -- $ 13 $ 52 $ 16 $ -- $ 128
Commercial paper 32 -- 126 21 38 11 9 237
$ 50 $22 $126 $ 34 $ 90 $ 27 $ 9 $ 365
(a) Includes short-term debt of other subsidiaries not shown.
Reference is made to the footnotes to the financial statementsContingencies, incorporated by
reference in Item 8, for further information with respect to unused short-
term bank lines of credit.
In order to issue additional first mortgage bonds and preferred stock, it is
necessary for APCo, CSPCo, I&M, KEPCo and OPCo to comply with earnings coverage
requirements contained in their respective mortgages and charters. The most
restrictive of these provisions in each instance generally requires (1) for the
issuance of first mortgage bonds for purposes other than the refunding of
outstanding first mortgage bonds, a minimum, before income tax, earnings
coverage of twice the pro forma annual interest charges on first mortgage bonds
and (2) for the issuance of additional preferred stock by APCo, I&M and OPCo, a
minimum, after income tax, gross income coverage of one and one-half times pro
forma annual interest charges and preferred stock dividends, in each case for a
period of twelve consecutive calendar months within the fifteen calendar months
immediately preceding the proposed new issue. In computing such coverages, the
companies include as a component of earnings revenues collected subject to
refund (where applicable) and, to the extent not limited by the instrument
under which the computation is made, AFUDC, including amounts positioned and
classified as an allowance for borrowed funds used during construction. These
coverage provisions have from time to time restricted the ability of one or
more of the above subsidiaries of AEP to issue senior securities.
The respective mortgage and preferred stock coverages of APCo, CSPCo, I&M,
KEPCo and OPCo under their respective mortgage and charter provisions,
calculated on the foregoing basis and in accordance with the respective amounts
then recorded in the accounts of the companies, assuming the respective short-
term debt of the companies at those dates were to remain outstanding for a
twelve-month period at the respective rates of interest prevailing at those
dates, were at least those stated in the following table:
DECEMBER 31,
1993 1994 1995
APCo
Mortgage coverage 3.64 3.12 3.47
Preferred stock coverage 2.04 1.65 1.78
CSPCo
Mortgage coverage 2.91 3.64 3.90
I&M
Mortgage coverage 5.49 6.23 6.25
Preferred stock coverage 2.48 2.74 2.63
KEPCo
Mortgage coverage 2.19 2.60 2.86
OPCo
Mortgage coverage 5.24 5.04 6.17
Preferred stock coverage 2.88 2.58 3.04
Although certain other subsidiaries of AEP either are not subject to any
coverage restrictions or are not subject to restrictions as constraining as
those to which APCo, CSPCo, I&M, KEPCo and OPCo are subject, their ability to
finance substantial portions of their construction programs may be subject to
market limitations and other constraints unless other assurances are furnished.
AEP believes that the ability of its operating subsidiaries to issue short-
and long-term debt securities and preferred stock in the amounts required to
finance their business may depend upon the timely approval of rate increase
applications. If one or more of the operating 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 use of alternative financing
arrangements, if available, which may be more costly or the curtailment of
construction and other outlays.
AEP's subsidiaries have also utilized, and expect to continue to utilize,
additional financing arrangements, such as leasing arrangements, including the
leasing of utility assets, coal mining and transportation equipment and
facilities and nuclear fuel. Pollution control revenue bonds have been used in
the past and may be used in the future in connection with the construction of
pollution control facilities; however, Federal tax law has limited the
utilization of this type of financing except for purposes of certain financing
of solid waste disposal facilities and of certain refunding of outstanding
pollution control revenue bonds issued before August 16, 1986.
Shares of AEP Common Stock may be sold by AEP from time to time at prices
below the then current book value per share and repurchased by AEP at prices
above book value. Such sales or purchases, if any, would have a dilutive
effect on the book value of then outstanding shares but are not expected to
have a material adverse effect on AEP's business including its future financing
plans or capabilities and pending construction projects.
RATES
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. If increases in operating, construction and capital costs exceed
increases in revenues resulting from previously granted rate increases and
increased customer demand, then it may be appropriate for certain of AEP's
electric utility subsidiaries to file rate increase applications in the future.
Generally the rates of AEP's operating subsidiaries are determined based
upon the cost of providing service including a reasonable return on investment.
Certain states served by the AEP System allow alternative forms of rate
regulation in addition to the traditional cost-of-service approach. In April
1995, Indiana enacted into law legislation providing that 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. In March 1996, Virginia enacted into law
legislation which provides that the Virginia SCC may approve (i) special rates,
contracts or incentives to individual customers or classes of customers and
(ii) alternative forms of regulation including, but not limited to, the use of
price regulation, ranges of authorized returns, categories of services and
price indexing.
All of the seven states served by the AEP System, as well as the FERC,
either permit the incorporation of fuel adjustment clauses in a utility
company's rates and tariffs, which are designed to permit upward or downward
adjustments in revenues to reflect increases or decreases in fuel costs above
or below the designated base cost of fuel set forth in the particular rate or
tariff, or permit the inclusion of specified levels of fuel costs as part of
such rate or tariff.
AEP cannot predict the timing or probability of approvals regarding
applications for additional rate changes, the outcome of action by regulatory
commissions or courts with respect to such matters, or the effect thereof on
the earnings and business of the AEP System.
APCO
FERC: On February 14, 1992, APCo filed with the FERC applications for an
increase in its wholesale rates to Kingsport Power Company and non-affiliated
customers in the amounts of approximately $3,933,000 and $4,759,000,
respectively. APCo began collecting the rate increases, subject to refund, on
September 15, 1992. In addition, the Financial Accounting Standards Board has
issued Statement of Financial Accounting Standards No. 106, EMPLOYERS'
ACCOUNTING FOR POSTRETIREMENT BENEFITS OTHER THAN PENSIONS (SFAS 106), which
requires employers, beginning in 1993, to accrue for the costs of retiree
benefits other than pensions. These rates include the higher level of SFAS 106
costs. On November 9, 1993, the administrative law judge issued an initial
decision recommending, among other things, the higher level of postretirement
benefits other than pensions under SFAS 106. FERC action on APCo's
applications is pending.
VIRGINIA: On June 27, 1994, the Virginia SCC issued a final order granting
APCo an increase in annual revenues of $17,900,000. APCo had requested to
increase its Virginia retail rates by $31,400,000 annually and, on May 4, 1993,
implemented the rates, subject to refund, based on an interim order. As a
result of the final order, APCo made a revenue refund including interest to its
Virginia customers in August 1994 of $15,800,000.
As a result of certain significant fuel cost reductions, on November 15,
1994, APCo implemented a net decrease in rates charged to its Virginia retail
customers of $13,200,000, subject to final approval by the Virginia SCC. The
net decrease consisted of a $28,900,000 decrease in the fuel component of its
rates offset, in part, by an increase of $15,700,000 in base rates. On
December 19, 1994, the Virginia SCC issued an order approving the decrease in
the fuel factor component of rates. APCo proposes in the base rate proceeding
to amortize Virginia deferred storm damage expenses of $23,900,000 related to
two major ice storms in February and March 1994 over a three-year period,
consistent with the amortization of previous storm damage expense deferrals
approved in a 1992 rate case. The ultimate recovery of the entire deferred
storm damage costs is subject to Virginia SCC approval. If not approved,
results of operations could be adversely affected. The Virginia SCC Staff has
recommended that approximately $12,000,000 of the $23,900,000 in storm damage
expenses be treated as if they have previously been recovered in earnings
(based on the results of the Staff's earnings test) and the remainder be
deferred for future recovery over a five-year period. A hearing examiner's
report is pending.
CSPCO
ZIMMER PLANT: The Zimmer Plant was placed in commercial operation as a
1,300-megawatt coal-fired plant on March 30, 1991. CSPCo owns 25.4% of the
Zimmer Plant with the remainder owned by two unaffiliated companies, CG&E
(46.5%) and DP&L (28.1%).
ZIMMER PLANT - RATE RECOVERY: In May 1992, the PUCO issued an order
providing for a phased-in rate increase of $123,000,000 for the Zimmer Plant to
be implemented in three steps over a two-year period and disallowed
$165,000,000 of Zimmer Plant investment. CSPCo appealed the PUCO ordered
Zimmer disallowance and phase-in plan to the Ohio Supreme Court. In November
1993, the Supreme Court issued a decision on CSPCo's appeal affirming the
disallowance and finding that the PUCO did not have statutory authority to
order phased-in rates. The court instructed the PUCO to fix rates to provide
gross annual revenue in accordance with the law and to provide a mechanism to
recover the revenues deferred under the phase-in order.
As a result of the ruling, 1993 net income was reduced by $144,500,000 after
tax to reflect the disallowance and in January 1994, the PUCO approved a 7.11%
or $57,167,000 rate increase effective February 1, 1994. The increase is
comprised of a 3.72% base rate increase and a temporary 3.39% surcharge, which
will be in effect until the phase-in plan deferrals are recovered, currently
estimated to be mid-1997. In 1995, $28,500,000 of net phase-in deferrals were
collected through the surcharge which reduced the deferrals from $75,400,000 at
December 31, 1994 to $46,900,000 at December 31, 1995. In 1993 and 1992,
$47,900,000 and $46,000,000, respectively, were deferred under the phase-in
plan. The recovery of amounts deferred under the phase-in plan and the
increase in rates to the full rate level did not affect net income.
From the in-service date of March 1991 until rates went into effect in May
1992, deferred carrying charges of $43,000,000 were recorded on the Zimmer
Plant investment. Recovery of the deferred carrying charges will be sought in
the next PUCO base rate proceeding in accordance with the PUCO accounting order
that authorized the deferral.
Reference is made to the caption ENVIRONMENTAL AND OTHER MATTERS - ACID RAIN
PROGRAM - AEP SYSTEM COMPLIANCE PLAN for information regarding AEP's compliance
plan which was approved by the PUCO.
KEPCO
In September 1995, KEPCo, the Kentucky Attorney General and other interested
parties filed an application with the KPSC to implement KEPCo's DSM Three-Year
Experimental Plan which consisted of DSM programs for residential, commercial
and industrial sectors. Under the plan, program costs, as well as net lost
revenues and incentives, would be recovered by sector under an annual surcharge
tariff. In December 1995, the KPSC issued an order approving the three-year
plan for the period ending December 31, 1998.
OPCO
An application was filed by OPCo in July 1994 with the PUCO seeking a
$152,500,000 annual base retail rate increase to recover, among other things,
the costs associated with the Gavin Plant's flue gas desulfurization systems
(scrubbers). In February 1995, OPCo and certain other parties to the
proceeding entered into a settlement agreement to resolve, among other issues,
the pending base rate case and the current electric fuel component (EFC)
proceeding. On March 23, 1995, the PUCO issued an order approving the
settlement agreement, with certain minor exceptions. Under the terms of the
settlement agreement, effective March 23, 1995, base rates increase by
$66,000,000 annually which includes recovery of the annual cost of the
scrubbers; the EFC rate is fixed at 1.465 cents per kwh from June 1, 1995
through November 30, 1998; OPCo is provided with the opportunity to recover its
Ohio jurisdictional share of the investment in, and the liabilities and future
shutdown costs of, all affiliated mines as well as any fuel costs incurred
above the fixed rate; and OPCo may proceed with its Clean Air Act Amendments of
1990 compliance plan as filed with the PUCO (discussed under ENVIRONMENTAL AND
OTHER MATTERS - ACID RAIN PROGRAM - AEP SYSTEM COMPLIANCE PLAN). The
settlement agreement allows OPCo to continue to operate its Muskingum and
Windsor mines.
Based on a stipulation agreement approved by the PUCO in November 1992,
beginning December 1, 1994, the cost of coal burned at the Gavin Plant is
subject to a 15-year predetermined price of $1.575 per million Btus with
quarterly escalation adjustments. As discussed above, the PUCO-approved
settlement agreement fixes the EFC factor at 1.465 cents per kwh for the period
June 1995 through November 1998. After November 2009, the price that OPCo can
recover for coal from its affiliated Meigs mine which supplies the Gavin Plant
will be limited to the lower of cost or the then-current market price. The
predetermined Gavin Plant price agreement, in conjunction with the above-
referenced settlement agreement, provide OPCo with an opportunity to recover
any operating losses incurred under the predetermined or fixed price, as well
as its investment in, and liabilities and closing costs associated with, its
affiliated mining operations attributable to its Ohio jurisdiction, to the
extent the actual cost of coal burned at the Gavin Plant is below the
predetermined price.
Based on the estimated future cost of coal burned at Gavin Plant, management
believes that the Ohio jurisdictional portion of the investment in, and
liabilities and closing costs of, the affiliated mining operations will be
recovered under the terms of the predetermined price agreement.
In November 1992, the municipal wholesale customers of OPCo filed a
complaint with the SEC requesting an investigation of the sale of the Martinka
mining operation to an unaffiliated company and an investigation into the
pricing of OPCo's affiliated coal purchases back to 1986. OPCo has filed a
response with the SEC seeking to dismiss this complaint.
FUEL SUPPLY
The following table shows the sources of power generated by the AEP System:
1991 1992 1993 1994 1995
Coal 86% 93% 86% 91% 88%
Nuclear 13% 6% 13% 8% 11%
Hydroelectric
and other 1% 1% 1% 1% 1%
Variations in the generation of nuclear power are primarily related to
refueling outages and, in 1992, a forced outage at Cook Plant Unit 2. See COOK
NUCLEAR PLANT.
COAL
The Clean Air Act Amendments of 1990 provide for the issuance of annual
allowance allocations covering sulfur dioxide emissions at levels below
historic emission levels for many coal-fired generating units of the AEP
System. Phase I of this program began in 1995 and Phase II begins in 2000,
with both phases requiring significant changes in coal supplies and suppliers.
The full extent of such changes, particularly in regard to Phase II, however,
has not been determined. See ENVIRONMENTAL AND OTHER MATTERS - ACID RAIN
PROGRAM - AEP SYSTEM COMPLIANCE PLAN for the current compliance plan.
In order to meet emission standards for existing and new emission sources,
the AEP System companies will, in any event, have to obtain coal supplies, in
addition to coal reserves now owned by System companies, through the
acquisition of additional coal reserves and/or by entering into additional
supply agreements, either on a long-term or spot basis, at prices and upon
terms which cannot now be predicted.
No representation is made that any of the coal rights owned or controlled by
the System will, in future years, produce for the System any major portion of
the overall coal supply needed for consumption at the coal-fired generating
units of the System. Although AEP believes that in the long run it will be
able to secure coal of adequate quality and in adequate quantities to enable
existing and new units to comply with emission standards applicable to such
sources, no assurance can be given that coal of such quality and quantity will
in fact be available. No assurance can be given either that statutes or
regulations limiting emissions from existing and new sources will not be
further revised in future years to specify lower sulfur contents than now in
effect or other restrictions. See ENVIRONMENTAL AND OTHER MATTERS herein.
The FERC has adopted regulations relating, among other things, to the
circumstances under which, in the event of fuel emergencies or shortages, it
might order electric utilities to generate and transmit electric power to other
regions or systems experiencing fuel shortages, and to rate-making principles
by which such electric utilities would be compensated. In addition, the
Federal Government is authorized, under prescribed conditions, to allocate coal
and to require the transportation thereof, for the use of power plants or major
fuel-burning installations.
System companies have developed programs to conserve coal supplies at System
plants which involve, on a progressive basis, limitations on sales of power and
energy to neighboring utilities, appeals to customers for voluntary limitations
of electric usage to essential needs, curtailment of sales to certain
industrial customers, voltage reductions and, finally, mandatory reductions in
cases where current coal supplies fall below minimum levels. Such programs
have been filed and reviewed with 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 reclamationlitigation and
environmental protection,
including Federal strip mining legislation enactedexpenditures 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 a
terminal on the Ohio River for transloading to barges for delivery to
generating stations on the river. Subsidiaries of AEP lease approximately
3,535 coal hopper cars to be used in unit train movements, as well as 14
towboats, 295 jumbo barges and 185 standard barges. Subsidiaries of AEP also
own or lease coal transfer facilities at various locations on the river.
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:general.
1991 1992 1993 1994 19952001 2002 2003
ACTUAL ACTUAL ESTIMATE
-------- -------- --------
(IN THOUSANDS)
Total coal delivered toAEGCo................ $ 3,500 $ 1,200 $ 11,200
APCo................. 99,200 108,400 65,700
CSPCo................ 22,500 25,400 39,300
I&M.................. 700 1,200 18,500
KPCo................. 11,200 110,600 39,900
OPCo................. 125,300 110,300 53,100
PSO.................. 400 1,200 100
SWEPCo............... 9,200 3,400 9,000
TCC.................. 2,500 600 0
TNC.................. 800 1,900 0
-------- -------- --------
AEP operated plants (thousands of tons) 45,232 44,738 40,561 49,024 46,867
Sources (percentage):
Subsidiaries 28% 25% 20% 15% 14%
Long-term contracts 62% 65% 66% 65% 75%
Spot or short-term purchases 10% 10% 14% 20% 11%
Average price per ton of spot-purchased
coal $25.40 $23.88 $23.55 $23.00 $25.15System........... $275,300 $364,200 $236,800
======== ======== ========
The average cost of coal consumed during the past five years by all AEP
System companies, AEGCo, APCo, CSPCo, I&M, KEPCoElectric and OPCo is shown in the
following tables:
1991 1992 1993 1994 1995
Dollars per ton
AEP System Companies $35.16 $34.31 $33.57 $33.95 $32.52
AEGCo 20.65 20.11 17.74 18.59 18.80
APCo 41.99 43.00 42.65 39.89 38.86
CSPCo 35.18 33.87 33.87 32.80 33.23
I&M 25.57 24.23 23.80 22.85 23.25
KEPCo 31.38 30.24 27.08 26.83 26.91
OPCo 40.18 38.36 38.12 41.10 37.58
CENTS PER MILLION BTU'S
AEP System Companies 158.88154.41150.89152.41145.26
AEGCo 123.33 120.90 107.71 112.06 112.87
APCo 169.48 173.05 173.32 161.37 156.96
CSPCo 152.55 143.94 143.66 140.45 140.79
I&M 139.16 135.11 129.39 123.62 125.50
KEPCo 132.25 126.92 113.90 113.40 114.77
OPCo 171.65 163.89 161.25 173.51 157.62
The coal supplies at AEP System plants vary from time to time
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, 1995, the System's coal
inventory was approximately 55 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 1995 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 1995 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.
ESTIMATED REQUIRE- AVERAGE SULFUR CONTENT
TOTAL CONSUMPTION MENTS FOR REMAINDER OF DELIVERED COAL
During 1995 of Useful Lives Pounds of SO{2}
(IN THOUSANDS OF TONS) (IN MILLIONS OF TONS) BY WEIGHT PER MILLION BTU'S
AEGCo (a) 5,267 261 0.3% 0.7
APCo 8,988 446 0.8% 1.3
CSPCo (b) 5,367 234 2.9% 4.9
I&M (c) 6,723 300 0.5% 1.1
KEPCo 2,953 91 1.2% 2.0
OPCo 17,910 650 2.2% 3.7
(a) Reflects AEGCo's 50% interest in the Rockport Plant.
(b) Includes coal requirements for CSPCo's interest in Beckjord, Stuart and
Zimmer Plants.
(c) Includes I&M's 50% interest in the Rockport Plant.
AEGCO: See FUEL SUPPLY - I&M for a discussion of the coal supply for the
Rockport Plant.
APCO: Substantially all of the coal consumed at APCo's generating plants is
obtained from unaffiliated suppliers under long-term contracts and/or on a spot
purchase basis.
The average sulfur content by weight of the coal received by APCo at its
generating stations approximated 0.8% during 1995, whereas the maximum sulfur
content permitted, for emission standard purposes, for existing plants in the
regions in which APCo's generating stationsMagnetic Fields
EMF are located ranged between 0.78%
and 2% by weight depending in some circumstances on the calorific value of the
coal which can be obtained for some generating stations.
CSPCO: CSPCo has coal supply agreements with unaffiliated suppliers for the
delivery of approximately 3,400,000 tons per year through 1998. 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 three coal supply agreements with unaffiliated suppliers
pursuant to which the suppliers are delivering low sulfur coal from surface
mines in Wyoming, principally for consumption by the Rockport Plant. Under
these agreements, the suppliers will sell to I&M, for consumption by I&M at the
Rockport Plant or consignment to other System companies, coal with an average
sulfur content not exceeding 1.2 pounds of sulfur dioxide per million Btu's of
heat input. One contract with remaining deliveries of 67,750,000 tons expires
on December 31, 2014 and another contract with remaining deliveries of
56,400,000 tons expires on December 31, 2004. The third contract with
deliveries of 750,000 tons per year expires in late 1996.
All of the coal consumed at I&M's Tanners Creek Plant is obtained from
unaffiliated suppliers under long-term contracts and/or on a spot purchase
basis.
KEPCO: Substantially all of the coal consumed at KEPCo's Big Sandy Plant is
obtained from unaffiliated suppliers under long-term contracts and/or on a spot
purchase basis. KEPCo has coal supply agreements with unaffiliated suppliers
pursuant to which KEPCo will receive approximately 2,500,000 tons of coal in
1996. 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 which contain approximately 212,000,000 tons of
clean recoverable coal, which ranges in sulfur content between 3.4% and 4.5%
sulfur by weight (weighted average, 3.8%), which can be recovered based upon
existing mining plans and projections and employing current mining practices
and techniques. 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 106,000,000
tons of clean recoverable coal ranging in sulfur content between 1.4% and 3.3%
sulfur by weight (weighted average, 2.0%) of which approximately 29,000,000
tons can be recovered based upon existing mining plans and projections and
employing current mining practices and techniques.
NUCLEAR
I&M has made commitments to meet certain of the nuclear fuel requirements of
the Cook Plant. The nuclear fuel cycle consists of the mining and milling of
uranium ore to uranium concentrates; the conversion of uranium concentrates to
uranium hexafluoride; the enrichment of uranium hexafluoride; the fabrication
of fuel assemblies; the utilization of nuclear fuel in the reactor; and the
reprocessing or other 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 beyond the existing
contractual commitments shown in the following table. I&M has made and will
make purchases of uranium in various forms in the spot and short-term market
until it decides that deliveries under mid- or long-term supply contracts are
warranted. The following table shows the year through which contracts have
been entered into to provide the requirements of the units for the various
segments of the nuclear fuel cycle.
URANIUM
CONCENTRATES CONVERSION ENRICHMENT (1) FABRICATION REPROCESSING (2)
Unit 1 -- -- 2000 2000 --
Unit 2 -- -- 2000 2000 --
1) I&M has a requirements-type contract with DOE. I&M has partially terminated
the contract, subject to revocation of the termination, so that it may
procure enrichment services cost-effectively from the spot market.
2) No reprocessing facility in the United States currently is in operation.
I&M has contracted for reprocessing services at a facility on which
construction has been halted. Lack of reprocessing services has resulted in
the need to increase on-site storage capacity for spent fuel.
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 to permit normal operations through 2010.
I&M's costs of nuclear fuel consumed do not assume any residual or salvage
value for residual plutonium and uranium.
NUCLEAR WASTE AND DECOMMISSIONING
The Nuclear Waste Policy Act of 1982, as amended, establishes Federal
responsibility for the permanent off-site disposal of spent nuclear fuel and
high-level radioactive waste. Disposal costs are paid by fees assessed against
owners of nuclear plants and deposited into the Nuclear Waste Fund created by
the Act. In 1983, I&M entered into a contract with DOE for the disposal of
spent nuclear fuel. Under terms of the contract, for the disposal of nuclear
fuel consumed after April 6, 1983 by I&M's Cook Plant, I&M is paying to the
fund a fee of one mill per kilowatt-hour, which I&M is currently recovering
from customers. For the disposal of nuclear fuel consumed prior to April 7,
1983, I&M must pay the U.S. Treasury a fee estimated at approximately
$71,964,000, exclusive of interest of $91,096,000 at December 31, 1995. The
aggregate amount has been recorded as long-term debt. Because of the current
uncertainties surrounding DOE's program to provide for permanent disposal of
spent nuclear fuel, I&M has not yet paid any of the pre-April 1983 fee. At
December 31, 1995, funds collected from customers to pay the pre-April 1983 fee
and accrued interest approximated the long-term debt liability.
On June 20, 1994, a group of 14 unaffiliated utilities owning and operating
nuclear plants and a group of states each filed a petition for review in the
U.S. Court of Appeals for the District of Columbia Circuit requesting that the
court issue a declaration that the Nuclear Waste Policy Act of 1982 imposes on
DOE an unconditional obligation to begin acceptance of spent nuclear fuel and
high level radioactive waste by January 31, 1998. DOE has indicated in its
Notice of Inquiry of May 25, 1994 that its preliminary view is that it has no
statutory obligation to begin to accept spent nuclear fuel beginning in 1998 in
the absence of an operational repository. In April 1995, DOE issued its Final
Interpretation affirming its earlier view. On May 30, 1995, I&M filed a
petition for review seeking the same relief requested earlier by the group of
utilities. This action was consolidated with the earlier petition. I&M also
seeks, if warranted, relief from the financial burden of fees being paid to
DOE.
Studies completed in 1994 estimate decommissioning and low-level radioactive
waste disposal costs for the Cook Plant to range from $634,000,000 to
$988,000,000 in 1993 nondiscounted dollars. The wide range is caused by
variables in assumptions, including the estimated length of time spent nuclear
fuel must be stored at the Cook Plant subsequent to ceasing operations, which
depends on future developments in the federal government's spent nuclear fuel
disposal program. Continued delays in the federal fuel disposal program can
result in increased decommissioning costs. I&M is recovering decommissioning
costs in its three rate-making jurisdictions based on at least the lower end of
the range in the most recent respective decommissioning study available at the
time of the rate proceeding (the study range utilized in the Indiana rate case,
I&M's primary jurisdiction, was $588,000,000 to $1.102 billion in 1991
dollars). I&M records decommissioning costs in other operation expense and
records a noncurrent liability equal to the decommissioning cost recovered in
rates which was $30,000,000 in 1995, $26,000,000 in 1994 and $13,000,000 in
1993. At December 31, 1995, I&M had recognized a decommissioning liability of
$269,000,000. I&M will continue to reevaluate periodically the cost of
decommissioning and to seek regulatory approval to revise its rates as
necessary.
Funds recovered through the rate-making process for disposal of spent
nuclear fuel consumed prior to April 7, 1983 and for nuclear decommissioning
have been segregated and deposited in external funds for the future payment of
such costs. Trust fund earnings decrease the amount to be recovered from
ratepayers.
The ultimate cost of retiring I&M's Cook Plant may be materially different
from the estimates contained in the site-specific study and the funding targets
as a result of (a) the type of decommissioning plan selected, (b) the
escalation of various cost elements (including, but not limited to, general
inflation), (c) the further development of regulatory requirements governing
decommissioning, (d) the absence to date of significant experience in
decommissioning such facilities and (e) the technology available at the time of
decommissioning differing significantly from that assumed in these studies.
Accordingly, management is unable to provide assurance that the ultimate cost
of decommissioning the Cook Plant will not be significantly greater than
current projections.
In February 1996, the Financial Accounting Standards Board (FASB) issued an
exposure draft entitled ACCOUNTING FOR CERTAIN LIABILITIES RELATED TO CLOSURE
OR REMOVAL OF LONG-LIVED ASSETS. The exposure draft proposes that the present
value of any decommissioning or other closure or removal obligation be recorded
as a liability when the obligation is incurred. A corresponding asset would be
recorded in the plant investment account and recovered through depreciation
charges over the asset's life. A proposed transition rule would require that
an entity report a charge to income for the cumulative effect of initially
applying the proposed standard. Management is studying the proposed standard
and evaluating its potential impact.
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 trash 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. As 1986 approached it
became apparent that no new disposal facilities would be operational, and
enforcement of the LLWPA would leave no disposal capacity for the majority of
the low-level waste generated in the United States. Congress, therefore,
passed the Low-Level Waste Policy Amendments Act of 1985. Michigan, the state
where the Cook Plant is located, was a member of the Midwest Compact, but its
membership was revoked in 1991. Michigan is responsible for developing a
disposal site for the low-level waste generated in Michigan.
In 1994, Michigan amended its law regarding disposal sites to provide for
allowing a volunteer to host a facility. Although progress has been made, the
site selection process is very long and management is unable to predict when a
permanent disposal site for Michigan low-level waste will be available.
On July 1, 1995, the disposal site in South Carolina reopened to accept
waste from most areas of the U.S., including Michigan. This is the first
opportunity for the Cook Plant to dispose of waste at that site since November
1990 when South Carolina denied access to its disposal site. To the extent
necessary, the Cook Plant's low-level radioactive waste is being stored on-
site. I&M has an on-site radioactive material storage facility at the Cook
Plant for temporary preshipment storage of the plant's low-level radioactive
waste. The facility can hold as much low-level waste as the Cook Plant is
expected to produce through approximately 2001, and the building could be
expanded to accommodate the storage of such waste through approximately 2017.
Currently, the Cook Plant produces less than 7,000 cubic feet of low-level
waste annually.
ENERGY POLICY ACT - NUCLEAR FEES
The Energy Policy Act of 1992 (Energy Act), contains a provision to fund the
decommissioning and decontamination of DOE's existing uranium enrichment
facilities from a combination of sources including assessments against electric
utilities which purchased enrichment services from DOE facilities. I&M's
remaining estimated liability is $45,703,000, subject to inflation adjustments,
and is payable in annual assessments over the next 11 years. I&M recorded a
regulatory asset concurrent with the recording of the liability. The payments
are being recorded and recovered as fuel expense.
In a case involving an unaffiliated utility, the U.S. Court of Federal
Claims decided in June 1995 that these assessments are unlawful. On November
13, 1995, the Federal Government appealed this decision to the U.S. Court of
Appeals for the Federal Circuit. I&M has filed with DOE claims for refunds
under certain of its enrichment services contracts based on this decision. I&M
also intends to pursue refund claims on other enrichment services contracts
directly to the U.S. Court of Federal Claims.
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.
It is expected that costs related to environmental requirements will
eventually be reflected in the rates of AEP's electric utility subsidiaries and
that, in the long term, AEP's electric utility subsidiaries will be able to
provide for such environmental controls as are required. 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.
Except as noted herein, AEP's subsidiaries which own or operate generating
facilities generally are in compliance with pollution control laws and
regulations.
AIR POLLUTION CONTROL
CLEAN AIR ACT AMENDMENTS OF 1990: For the AEP System, compliance with the
Clean Air Act Amendments of 1990 (CAAA) is requiring substantial expenditures
which are being recovered through increases in the rates of AEP's operating
subsidiaries. OPCo is incurring a major portion of such costs. There can be
no assurance that all such costs will be recovered. See CONSTRUCTION PROGRAM -
CONSTRUCTION EXPENDITURES.
The Acid Rain Program provisions of the CAAA create an emission allowance
program pursuant to which utilities are authorized to emit a designated
quantity of sulfur dioxide, measured in tons per year, on a system wide or
aggregate basis. Emission reductions are required by virtue of the
establishment of annual allowance allocations at a level below historical
emission levels for many utility units. For units that emitted sulfur dioxide
above a rate of 2.5 pounds per million Btu heat input in 1985, the CAAA
establish sulfur dioxide allowance limitations (caps or ceilings on emissions)
premised upon sulfur dioxide emissions at a rate of 2.5 pounds per million Btu
heat input at 1985 utilization levels as of the Phase I deadline of January 1,
1995. The following AEP System units are Phase I-affected units: I&M's Breed
Plant and Tanners Creek Unit 4; CSPCo's Beckjord Unit 6, Conesville Units 1-4,
Picway Unit 5 and Stuart Units 1-4; and OPCo's Gavin Units 1-2, Muskingum River
Units 1-5, Cardinal Unit 1, Mitchell Units 1-2 and Kammer Units 1-3. Phase I
permits have been issued for all Phase I-affected units in the AEP System.
All fossil fuel-fired steam generating units with capacity greater than 25
megawatts are affected in Phase II of the acid rain control program. All Phase
II-affected units are allocated allowances with which compliance must be
accomplished beginning January 1, 2000. The basis for Phase II allowance
allocation depends on 1985 sulfur dioxide emission rates - if a unit emitted
sulfur dioxide in 1985 at a rate in excess of 1.2 pounds per million Btu heat
input, the allowance allocation is premised upon an emission rate of 1.2 pounds
at 1985 utilization levels as of the Phase II deadline of January 1, 2000; if a
unit emitted sulfur dioxide in 1985 at a rate of less than 1.2 pounds, the
allowance allocation is in most instances premised upon the actual 1985
emission rate.
The Acid Rain Title also contains provisions concerning nitrogen oxides
emissions. In March 1994, Federal EPA issued final regulations governing
nitrogen oxides emissions from tangentially fired and dry bottom wall-fired
boilers at Phase I units which were appealed to the U.S. Court of Appeals for
the District of Columbia Circuit by APCo, CSPCo, I&M, KEPCo and OPCo and a
group of unaffiliated utilities based on the failure of Federal EPA to
correctly define low NOx burner technology. On November 29, 1994, the court
remanded the rules to Federal EPA and on April 13, 1995, Federal EPA issued
revised regulations pursuant to the court's remand. Compliance with these
emission limitations is determined on an annual basis beginning in 1996.
OPCo's Mitchell Units 1 & 2 and CSPCo's Conesville Units 3 & 4 and Picway Unit
5 are Phase I units subject to these regulations.
On January 19, 1996, Federal EPA published proposed Nox emission limitations
in the FEDERAL REGISTER for wet bottom wall-fired boilers, cyclone boilers,
units applying cell burner technology and all other types of boilers. These
proposed emission limitations are purported to be comparable in cost to the
controls applicable to tangentially fired boilers and non-cell burner dry
bottom wall-fired boilers. These emission limitations are required to be met
by Phase II-affected sources after January 1, 2000. Also on January 19, 1996,
Federal EPA published proposed revisions to the existing emission limitations
for tangentially fired and dry bottom wall-fired boilers. Federal EPA must
take final action on the proposed revisions by January 1, 1997. These
limitations are expected to be more restrictive than those which are currently
applicable.
The CAAA contain additional provisions, other than the Acid Rain Title,
which could require reductions in emissions of nitrogen oxides from fossil
fuel-fired power plants. Title I, dealing generally with non-attainment of
ambient air quality standards, establishes a tiered system for classifying
degrees of non-attainment with air quality standards for ozone. Depending upon
the severity of non-attainment within a given non-attainment area, reductions
in nitrogen oxides emissions from fossil fuel-fired power plants may be
required as part of a state's plan for achieving attainment with ozone air
quality standards. On February 25, 1994, the West Virginia Division of
Environmental Protection issued a consent order for APCo's Amos Units 1 and 2,
requiring reductions in nitrogen oxides emissions from these units after June
1, 1995. The reduction in nitrogen oxides emissions will be less than that
required under Title IV of the CAAA but will be required at an earlier time.
On September 6, 1994, Federal EPA officially redesignated Putnam, Wood and
Kanawha counties to ozone attainment. West Virginia does not plan to impose
Nox reduction requirements under Title I of the CAAA as part of its ozone
maintenance plan in any of the five former moderate ozone non-attainment
counties, barring any other mandate from Federal EPA to do so. While ozone
non-attainment is largely restricted to urban areas, AEP System generating
stations could be determined to be affecting ozone concentrations and may
therefore, eventually be required to reduce nitrogen oxides emissions pursuant
to Title I.
In addition, certain environmental organizations and northeastern states
have filed comments with Federal EPA contending that nitrogen oxides emissions
from the midwest must be reduced in order to achieve the National Ambient Air
Quality Standard for ozone in the northeast. Similar comments have been filed
by these organizations and others with the FERC in connection with the proposed
rulemaking involving open access to transmission facilities. See TRANSMISSION
SERVICES - TRANSMISSION SERVICES FOR NON-AFFILIATES. All AEP coal-fired plants
are potentially subject to the imposition of additional emission controls
resulting from these initiatives. The Environmental Council of States formed
the Ozone Transport Assessment Group (OTAG) in early 1995 to develop estimates
of levels of reduction in volatile organic compound and/or nitrogen oxides
emissions required for significant reductions in ozone concentrations in the
eastern United States. OTAG, consisting of the environmental commissioners and
air directors of 37 eastern states, Federal EPA and representatives from
environmental and industry groups, is currently scheduled to complete modeling
and technical work by the fall of 1996 - with evaluation of technical findings
and recommendations on regional emission controls to be submitted to Federal
EPA by January 1997. The cost of meeting Nox emissions reduction requirements
which might be imposed to achieve the ozone ambient air quality standard cannot
be precisely predicted but could be substantial.
Utility boilers are potentially subject to additional control requirements
under Title III of the CAAA governing hazardous air pollutant emissions.
Federal EPA is directed to conduct studies concerning the potential public
health impacts of pollutants identified by the legislation as hazardous in
connection with their emission from electric utility steam generating units.
Federal EPA was required to report the results of this study to Congress by
November 1993 and is required to regulate emissions of these pollutants from
electric utility steam generating units if it is determined that such
regulation is necessary and appropriate, based on the results of the study.
Federal EPA informed Congress that completion of this study has been delayed
significantly beyond the November 1993 deadline. Federal EPA is subject to a
judicial consent decree requiring completion of the study and submission of it
by April 15, 1996. Additionally, Federal EPA is directed to study the
deposition of hazardous pollutants to 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. It is possible that
emissions from electric utility steam generating units may be regulated under
this water body deposition assessment program.
The CAAA expand the enforcement authority of the Federal government by
increasing the range of civil and criminal penalties for violations of the
Clean Air Act and enhancing administrative civil provisions, adding a citizen
suit provision and imposing a national operating permit system, emission fee
program and enhanced monitoring, record keeping and reporting requirements for
existing and new sources.
ACID RAIN PROGRAM - AEP SYSTEM COMPLIANCE PLAN: In 1992, the PUCO approved
a system-wide Phase I Acid Rain Program compliance plan. The AEP System's
compliance plan centers around the compliance method selected for OPCo's two-
unit 2,600-megawatt Gavin Plant which was emitting about 25% of the System's
total sulfur dioxide emissions. Under an Ohio law, utilities could obtain
advance PUCO approval of a least-cost compliance plan which would be deemed
prudent in subsequent PUCO rate proceedings.
The PUCO approved least-cost plan set forth compliance measures for the
System's affected generating units, which included (i) installing leased flue
gas desulfurization equipment (scrubbers) to burn Ohio high-sulfur coal at
Gavin and (ii) designating Gavin's coal supply sources to include the
affiliated Meigs mine at a reduced operating capacity and under predetermined
prices, new long-term contracts with unaffiliated sources and spot market
purchases.
Pursuant to a settlement agreement approved by the PUCO in connection with
OPCo's rate case discussed in RATES - OPCO, the PUCO reaffirmed its approval of
the compliance plan, which does not seek to fuel switch Cardinal Unit 1 or
Muskingum River Units 1-4 to low-sulfur coal at the beginning of Phase I of the
CAAA. Under the terms of the compliance plan, OPCo's Muskingum River Unit 5
has been switched to low-sulfur coal. CSPCo's Conesville Units 1-3 have been
modified to enable these units to burn coal or natural gas to comply. Actual
fuel choice will depend on the cost and availability of gas. Although the
compliance plan originally contemplated that CSPCo's Picway Unit 5 also would
be modified to enable this unit to burn coal or natural gas to comply, this
proposed modification has been indefinitely deferred. Beckjord Unit 6 (owned
with CG&E and DP&L) has been switched to moderate sulfur coal. I&M's Tanners
Creek Unit 4 has also been switched to moderate sulfur coal and I&M's Breed
Plant was retired in 1994. Eight additional units are subject to Phase I rules,
but no operating or fuel changes are planned, because they will hold allowances
sufficient for compliance.
Since the approved plan reflects fuel switching to comply at OPCo's
Muskingum River Plant and Cardinal Unit 1, mining operations at OPCo's wholly-
owned coal-mining subsidiaries, Central Ohio Coal Company and Windsor Coal
Company, could be shut down resulting in substantial costs. Central Ohio Coal
Company and Windsor Coal Company supply coal to Muskingum River Plant and
Cardinal Plant, respectively.
As a result of the aforementioned PUCO approval of OPCo's least-cost
compliance plan, OPCo entered into an agreement in 1992 for construction and
lease of the Gavin Plant scrubbers with JMG Funding, Limited Partnership (JMG),
an unaffiliated entity. The scrubbers on Gavin Units 1 and 2 commenced
operation in December 1994 and March 1995, respectively. On March 15, 1995,
OPCo began to lease the scrubbers from JMG. See CONSTRUCTION PROGRAM -
CONSTRUCTION EXPENDITURES.
Recovery of compliance costs has been and will be sought through the rate-
making process. The aforementioned OPCo settlement agreement provides, among
other things, for OPCo to recover the annual lease cost of the scrubbers and
other compliance costs and provides OPCo with an opportunity to recover its
Ohio jurisdictional share of its investment in and the liabilities and closing
costs of the affiliated Central Ohio and Windsor mining operations to the
extent the actual cost of coal burned at the Gavin Plant is below a
predetermined price. AEP intends to also seek timely recovery of all
compliance costs, including mine shutdown costs, from its non-Ohio
jurisdictional customers. OPCo's non-Ohio jurisdictional portion of shutdown
costs for these mines, which includes the investment in the mines, leased asset
buy-outs, reclamation costs and employee benefits is estimated to be
approximately $195,000,000 net of tax at December 31, 1995. There can be no
assurance that regulators will provide for recovery of all CAAA compliance
costs. Compliance with the CAAA, including potential mine closure costs, could
have an adverse effect on results of operations and possibly financial
condition unless the costs can be recovered from ratepayers and/or from asset
dispositions.
GLOBAL CLIMATE CHANGE: Increasing concentrations of "greenhouse gases,"
including carbon dioxide (CO{2}), in the atmosphere have led to concerns about
the potential for the earth's climate to change in ways that could result in
adverse human health effects, destruction of sensitive ecosystems, inundated
low-lying areas caused by sea-level rise, shifts in agricultural production and
other serious environmental consequences. The proponents of this view maintain
that rising levels of greenhouse gas emissions will cause some of the sun's
energy that is normally radiated back into space to be trapped in the
atmosphere, warming the biosphere and triggering these detrimental effects.
At the Earth Summit in Rio de Janeiro, Brazil in June 1992, 165 nations,
including the United States, signed a global climate change treaty. Each
country that ratifies the treaty commits itself to a process of achieving the
aim of reducing greenhouse gas emissions, including CO{2}, to their 1990 level
by the year 2000. On October 7, 1992, the U.S. Senate ratified the treaty.
The treaty went into effect on March 21, 1994. In April 1995, the first
meeting of the nations that have ratified was held. The parties declared that
the existing commitments under the treaty are not adequate to address the
threat of global climate change and authorized the immediate commencement of
negotiations on a protocol or other legal instrument for emission controls in
the post-2000 period. The protocol or other legal instrument is required to
set forth "policies and measures," and "quantified limitation and reduction
objectives within specified time frames, such as 2005, 2010 and 2020" to be
adopted by signatory nations. The negotiations are expected to be complete in
early 1997.
In accordance with the obligations set forth in the global climate change
treaty, on April 21, 1993, President Clinton committed the United States to
reducing greenhouse gas emissions to 1990 levels by the year 2000. On October
19, 1993, the President unveiled the Administration's Climate Change Action
Plan for meeting this emission reduction target. The plan emphasizes
reductions in fossil fuel use, the largest source of CO{2} emissions, primarily
through reliance on voluntary energy efficiency programs and partnerships
between the Federal government and U.S. industry. One such collaboration is
between the electric utility industry and DOE. Known as the Climate Challenge,
this initiative has identified flexible, cost-effective measures to reduce,
avoid or sequester future greenhouse gas emissions. AEP System companies
joined with nearly 800 investor-owned, municipal, rural electric cooperative
and Federal utilities in a voluntary agreement signed with DOE on April 20,
1994 that has led to individual utility Participation Accords resulting in
substantial reductions in future greenhouse gas emissions. On February 3,
1995, the AEP System entered into its Climate Challenge Participation Accord
with DOE. The Accord contains a diverse portfolio of supply-side, demand-side
and forest management/tree planting activities that will be undertaken on the
AEP System between now and the year 2000 with a projected reduction in CO{2}
emissions of 9,550,000 tons from what would have otherwise been emitted but for
these actions.
As a result of the AEP System's historical practice of using low-cost
indigenous coal supplies to produce electricity, AEP System power plants are
significant sources of CO{2} emissions. Management is working to support
further efforts to properly study the issue of global climate change to define
the extent, if any, to which it poses a threat to the environment. Management
is concerned that new laws may be passed or new regulations promulgated without
sufficient scientific study and support.
Since the AEP System is a major emitter of carbon dioxide, its financial
condition and results of operations could be materially adversely affected by
the imposition of stringent command-and-control limitations on CO{2} emissions
if the compliance costs incurred are not fully recovered from ratepayers. In
addition, any such severe program to stabilize or reduce CO{2} emissions could
impose substantial costs on industry and society and seriously erode the
economic base that AEP's operations serve.
WEST VIRGINIA: West Virginia promulgated sulfur dioxide limitations which
Federal EPA approved in February 1978. The emission limitations for the
Mitchell Plant have been approved by Federal EPA for primary ambient air
quality (health-related) standards only. West Virginia is obliged to reanalyze
sulfur dioxide emission limits for the Mitchell Plant with respect to secondary
ambient air quality (welfare-related) standards. Because the Clean Air Act
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.
West Virginia has had a request to increase the sulfur dioxide emission
limitation for Kammer pending before Federal EPA for many years, although the
change has not been acted upon by Federal EPA. On August 4, 1994, however,
Federal EPA issued a Notice of Violation to OPCo alleging that Kammer Plant was
operating in violation of the applicable federally enforceable sulfur dioxide
emission limit. See Item 3. LEGAL PROCEEDINGS - KAMMER PLANT. A portion of
the Notice of Violation relating to compliance has been resolved. Separate
proceedings have been initiated by OPCo with both the West Virginia Division of
Environmental Protection and Region III, Federal EPA in an effort to obtain
approval for utilization of the existing fuel supply beyond the current final
compliance date of May 15, 1996. While it is likely that the May 15, 1996
final compliance date will be extended, management cannot predict at this time
how long it will be able to utilize the existing fuel supply at the Kammer
Plant.
STACK HEIGHT REGULATIONS: On June 27, 1985, Federal EPA issued stack height
regulations pursuant to an order of the United States Court of Appeals for the
District of Columbia Circuit. These regulations were appealed by a number of
states, environmental groups and investor-owned electric utilities (including
APCo, CSPCo, I&M, KEPCo and OPCo), along with three electric utility trade
associations. OPCo also filed a separate petition for review to raise issues
unique to its Kammer Plant. Various petitions for reconsideration filed with
and denied by Federal EPA were also appealed. This litigation was consolidated
into a single case.
On January 22, 1988, the U.S. Court of Appeals issued a decision in part
upholding the June 1985 stack height rules and remanding certain of the June
1985 rules to Federal EPA for further consideration. With respect to Kammer
Plant, the January 1988 court decision rejected OPCo's appeal, holding that
Federal EPA acted lawfully in revoking stack height credit previously granted
for Kammer Plant in October 1982. As discussed above, OPCo has also commenced
administrative proceedings with the State of West Virginia and Federal EPA in
an effort to preserve stack height credit for Kammer Plant.
While it is not possible to state with particularity the ultimate impact of
the final rules on AEP System operations, at present it appears that the most
likely AEP System plants at which the final rules could possibly result in more
stringent emission limitations are CSPCo's Conesville Plant, AEGCo's and I&M's
Rockport Plant, I&M's Tanners Creek Plant and OPCo's Gavin and Kammer plants.
Gavin and Rockport plants were not affected by Federal EPA's stack height rules
as issued in June 1985. However, the provision exempting these plants was
remanded to Federal EPA in the January 1988 court decision. Accordingly, the
ultimate impact of the stack height rules on Gavin and Rockport plants will not
be known until Federal EPA completes administrative proceedings on remand and
reissues final stack height rules. OPCo and AEGCo and I&M intend to
participate in the remand rulemaking affecting Gavin and Rockport plants,
respectively.
State air pollution control agencies will be required to implement the stack
height rules by revising emission limitations for sources subject to the rules
and submitting such revisions to Federal EPA.
On June 1, 1989, Ohio EPA adopted a rule concerning CSPCo's Conesville Plant
in response to Federal EPA's stack height rules adopted in 1985. Under Federal
EPA policy published in January 1988, emission reductions required by the stack
height rules may be obtained at plants other than the plant directly affected
by the rules, and thereafter credited to the directly affected plant. Under
Ohio EPA's June 1 rule, the sulfur dioxide emission limitations for Conesville
Units 5 and 6 remain at 1.2 pounds sulfur dioxide per million Btu heat input as
long as the emission rate at CSPCo's retired Poston Units 1-4 remains at 0.0
pounds sulfur dioxide per million Btu heat input. Federal EPA has yet to take
action concerning Ohio EPA's June 1 rule.
ADMINISTRATIVE DEVELOPMENTS REGARDING SULFUR DIOXIDE: On November 15, 1994,
Federal EPA published a notice in the FEDERAL REGISTER proposing to retain the
present 24-hour national ambient air quality standard for sulfur dioxide.
Federal EPA also sought comment on the need to adopt additional regulations to
address short-term peak exposures to sulfur dioxide. Federal EPA is soliciting
comments on three alternatives, including the adoption of a short-term standard
averaged over a five-minute period. Adoption of any of these proposed
approaches, or other targeted programs, could require substantial reductions in
sulfur dioxide emissions from the System's coal-fired generating plants which
would entail substantial capital and operating costs. In a related action,
Federal EPA, on March 7, 1995, proposed requirements for implementing
strategies to reduce short-term (five-minute) peak concentrations of sulfur
dioxide in order to reduce health risks to exercising asthmatics. The effect
on AEP operations of Federal EPA's proposed risk-based targeting strategies for
further regulating sulfur dioxide emissions, if finalized, cannot be predicted,
but may be significant. Federal EPA is expected to take final action on these
proposals in the spring of 1996.
LIFE EXTENSION: On July 21, 1992, Federal EPA published final regulations
in the FEDERAL REGISTER governing application of new source rules to generating
plant repairs and pollution control projects undertaken to comply with the
Clean Air Act Amendments of 1990. Generally, the rule provides that plants
undertaking pollution control projects will not trigger new source review
requirements. The Natural Resources Defense Council and a group of utilities,
including five AEP System companies, have filed petitions in the U.S. Court of
Appeals for the District of Columbia Circuit seeking a review of the
regulations.
OTHER REGULATORY DEVELOPMENTS: Federal EPA is considering whether the
National Ambient Air Quality Standard for ozone should be revised and is
currently expected to make a final decision on this issue in 1997.
Federal EPA is also considering revision of the National Ambient Air Quality
Standard for particulate matter. Federal EPA is required by court order to
make a final determination on this issue by June 28, 1997.
WATER POLLUTION CONTROL
Under the Clean Water Act, effluent limitations requiring application of the
best available technology economically achievable are to be applied, and those
limitations require that no pollutants be discharged if Federal EPA finds
elimination of such discharges is technologically and economically achievable.
The Clean Water Act provides citizens with a cause of action to enforce
compliance with its pollution control requirements. Since 1982, many such
actions against NPDES permit holders have been filed. To date, no AEP System
plants have been named in such actions.
All System Plants are operating with NPDES permits. Under 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
which expire in 1996.
The NPDES permits generally require that certain thermal impact study
programs be undertaken. These studies have been completed for all System
plants. Thermal variances are in effect for all plants with once-through
cooling water. The thermal variances for Conesville and Muskingum River plants
impose thermal management conditions that could result in load curtailment
under certain conditions, but the cost impacts are not expected to be
significant. Based on favorable results of in-stream biological studies, OPCo
has requested a modification of the thermal management plan in the renewed
permit for Muskingum River expected to be issued this year.
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. See Item 3. LEGAL PROCEEDINGS - MEIGS MINE with respect to litigation
regarding certain discharges from OPCo's Meigs 31 mine.
The Federal Water Quality Act of 1987 requires states to adopt stringent
water quality standards for a large category of toxic pollutants and to
identify specialized control measures for dischargers to waters where water
quality standards are not being met. Implementation of these provisions could
result in significant costs to the AEP System if biological monitoring
requirements and water quality-based effluent limits are placed in NPDES
permits.
In March 1995, Federal EPA finalized a set of rules which 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. Management cannot presently determine whether
the GLWQI would have a significant adverse impact on AEP operations. The
significance of such impact will depend on the outcome of Federal EPA's policy
on intake credits and site specific variables as well as Michigan's
implementation strategy. Federal EPA's rule is presently under review by the
District of Columbia Circuit Court of Appeals in litigation initiated by
several industry groups. If Indiana and Ohio eventually adopt the GLWQI
criteria for statewide application, AEP System plants located in those states
could also be affected.
HAZARDOUS SUBSTANCES AND WASTES
Section 311 of the Clean Water Act imposes substantial penalties for spills
of Federal EPA-listed hazardous substances into water and for failure to report
such spills. The Comprehensive Environmental Response, Compensation, and
Liability Act (CERCLA) expanded the reporting requirements to cover the release
of hazardous substances generally into the environment, including water, land
and air. AEP's subsidiaries store and use some of these hazardous substances,
including PCB's contained in certain capacitors and transformers, but the
occurrence and ramifications of a spill or release of such substances cannot be
predicted.
CERCLA provides governmental agencies with the authority to require clean-up
of hazardous waste sites and releases of hazardous substances into the
environment. Since liability under CERCLA is strict and can be applied
retroactively, AEP System companies which previously disposed of PCB-containing
electrical equipment and other hazardous substances may be required to
participate in remedial activities at such disposal sites should environmental
problems result. AEP System companies are presently identified by Federal EPA
as potentially responsible parties (PRPs) for cleanup of seven federal sites,
including I&M at four sites, KEPCo at one site, OPCo at one site, and Wheeling
Power Company at one site. OPCo is a defendant in a cost recovery suit for the
site where OPCo is a PRP and at two additional CERCLA sites. I&M is a
defendant in a cost recovery action at one of the sites where I&M is a PRP and
for one additional CERCLA site. APCo and I&M each have been named as parties
potentially responsible at a state remediation site. Management's present
estimates do not anticipate material cleanup costs for identified sites for
which AEP subsidiaries have been declared PRPs. However, if for reasons not
currently identified significant costs are incurred for cleanup, future results
of operations and possibly financial condition would be adversely affected
unless the costs can be recovered through rates.
Regulations issued by Federal EPA under the Toxic Substances Control Act
govern the use, distribution and disposal of PCBs, including PCBs in electrical
equipment. Deadlines for removing certain PCB-containing electrical equipment
from service have been met.
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 in surface impoundments or
landfills in accordance with state permits or authorization or beneficially
utilized. As required by RCRA, 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 EPA issued a
regulatory determination that such high volume coal combustion wastes should
not be regulated as hazardous waste. For low volume coal combustion wastes,
such as metal and boiler cleaning wastes, Federal EPA will gather additional
information and make a regulatory determination by April 1998. Until that
time, these low volume wastes are provisionally excluded from regulation under
the hazardous waste provisions of RCRA. 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 which
generate such wastes, System companies have filed the requisite notices and are
complying with RCRA and applicable state regulations for generators. Nuclear
waste produced at the Cook Plant regulated under the Atomic Energy Act is
excluded from regulation under RCRA.
Federal EPA's technical requirements for underground storage tanks
containing petroleum will require retrofitting or replacement of an appreciable
number of tanks. Compliance costs for tank replacement and site remediation
have not been significant to date.
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, or being used inelectrical 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
10
EMF and health effects, the
majority of studies have indicated no such association. The epidemiological
studiesnone has produced any conclusive evidence that have received the most public attention reflect a weak correlation
between surrogateEMF does
or indirect estimates of EMF exposure and certain cancers.
Studies using direct measurements of EMF exposure show no such association.
There were two residential epidemiological studies of childhood brain cancer
published in early 1996 which showed no association with EMF exposure.
Research to date hasdoes not shown any causal relationship between EMF exposure and
cancer, or any othercause adverse health effects. Additional studies, which are
intended to provide a better understanding of the subject, are continuing.
Federal EPA is currently studying whether exposure to EMF is associated with
cancer in humans. In 1990, Federal EPA issued a draft report on EMF, received
interagency review and public comment, and is in the process of preparing its
final report. A December 1992 brochure from Federal EPA, QUESTIONS AND ANSWERS
ABOUT ELECTRIC AND MAGNETIC FIELDS (EMFS), states at page 3, "The bottom line
is that there is no established cause and effect relationship between EMF
exposure and cancer or other disease."
The Energy Policy Act of 1992 established a coordinated Federal EMF research
program. The program funding is $65,000,000 over five years, half of which is
to be provided by private parties including utilities. AEP has committed to
contribute $446,571 over the five-year period.
AEP's participation is a continuation of its efforts to support further
research and to communicate with its customers and employees about this issue.
Its operating company subsidiaries provide their residential customers with
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 in recent
years 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. No specific amount has been requested for damages in this case and no
trial date has been set.
Some states have enacted regulations to limit the strength of magnetic
fields at the edge of transmission line rights-of-way. No state which the AEP
System serves has done so. In March 1993, The Ohio Power Siting Board issued
its amended rules providing for additional consideration of the possible
effects of EMF in the certification of electric transmission facilities. Under
the amended EMF rules, persons seeking approval to build electric transmission
lines have to provide estimates of EMF from transmission lines under a variety
of conditions. In addition, applicants are required to address possible health
effects and discuss the consideration of design alternatives with respect to
EMF.
In April 1993, the State of Indiana enacted a law which provides that the
IURC shall determine, based on the preponderance of evidence in the scientific
literature, whether rules are necessary to protect the public health from EMF.
If the IURC determines that such rules are necessary, the IURC is required to
adopt rules that reasonably protect the public health from EMF.
Management cannot predict the ultimate impact of the question of EMF
exposure and adverse health effects. If further research shows that EMF exposure
contributes to increased risk of cancer or other health problems, or if the
courts conclude that EMF exposure harms individuals and that utilities are
liable for damages, or if states limit the strength of magnetic fields to such a
level that the current electricity delivery system must be significantly
changed, then the results of operations and financial condition of AEP and its
operating subsidiaries could be materially adversely affected unless these costs
can be recovered from ratepayers.
RESEARCH AND DEVELOPMENTcustomers.
WHOLESALE OPERATIONS
GENERAL
AEP conducts its wholesale business operations through its public utility
subsidiaries (through which AEP also conducts its energy delivery operations),
AEPES, AEPR and Pro Serv. Wholesale operations use and manage the following
assets:
- Power generation facilities (or interests therein) owned by AEP's public
utility and other subsidiaries;
- Natural gas pipeline, storage and processing facilities;
- Coal mines and related facilities; and
- Barge, rail and other fuel transportation related assets.
Wholesale operations include the following activities:
- Through AEP's public utility subsidiaries, the generation and sale of
power (i) to retail customers at unbundled or bundled rates regulated at
least in part by state public utility commissions and (ii) at wholesale
at rates regulated, in certain instances, by the FERC.
- Trading and marketing energy commodities in transactions predominantly
limited to risk management around assets used or managed by AEP's
wholesale operations, including electric power, natural gas, natural gas
liquids, oil, coal, and SO(2) allowances in North America and, where
applicable, Europe. Electric power transactions in the United States are
conducted principally through AEP's public utility subsidiaries. Other
energy commodity and allowances transactions are conducted through AEPES
and AEPR.
- Entering 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.
- Through Pro Serv, providing engineering, construction, project management
and other consulting services for energy-related projects.
In October 2002 AEP announced its plans to reduce the exposure to energy
trading markets and to downsize the trading and wholesale marketing operations.
It is expected that in the future power trading and marketing operations will be
smaller in scope and size, will generally be limited to risk management around
AEP's assets and, accordingly, focused in those regions in which AEP owns
assets.
POWER GENERATION
General
Power generation accounts for the majority of wholesale operations revenue.
In 2002, on an as-reported basis, power generation revenue included the
following components: (i) 63% from retail sales at predominantly regulated
rates; (ii) 33% from power marketing transactions of a type AEP intends to
continue and which are regulated in certain instances by the FERC; (iii) 3% from
retail sales at rates not regulated by states; and (iv) 1% attributable to power
marketing transactions of a type that management has stated are transitional.
This final category of transactions will be reduced consistent with AEP's
decision to scale back certain trading and marketing operations as described in
the preceding paragraph.
AEP's public utility subsidiaries own approximately 38,000 MW of domestic
generation. See Deactivation and Planned Disposition of Generating Facilities
for a discussion of planned reductions in AEP's generating fleet. Other AEP
subsidiaries hold interests in entities owning 1,879 MW of domestic power
facilities and 5,235 MW of international power facilities. The AEP public
utility subsidiaries operate their generating plants as a single interconnected
and coordinated electric utility system. See Item 2 - Properties for more
information regarding generation facilities.
11
AEP Power Pool and CSW Operating Agreement
APCo, CSPCo, I&M, KPCo and OPCo are involvedparties to the Interconnection
Agreement, dated July 6, 1951, as amended (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."
The member-load ratio is calculated monthly by dividing such company's
highest monthly peak demand for the last twelve months by the aggregate of the
highest monthly peak demand for the last twelve months for all east zone
operating companies. As of December 31, 2002, the member-load ratios were as
follows:
PEAK
DEMAND MEMBER-LOAD
(KW) RATIO (%)
------ -----------
APCo..................... 6,010 28.2
CSPCo.................... 4,040 19.0
I&M...................... 4,323 20.3
KPCo..................... 1,551 7.3
OPCo..................... 5,360 25.2
Although the FERC has approved the right of withdrawal of CSPCo and OPCo
from the AEP Power Pool as part of its order approving the settlement agreements
and AEP's FERC restructuring application, CSPCo and OPCo have remained a party
to the AEP Power Pool. If CSPCo and OPCo continue to remain in the AEP Power
Pool, notification to or approval by the FERC may be required. See Management's
Discussion and Analysis of Results of Operations and Financial Condition, under
the headings entitled Industry Restructuring and Corporate Separation for a
discussion of AEP's corporate separation plan filed with the FERC and related
settlement agreements with state commissions and other intervenors.
The following table shows the net credits or (charges) allocated among the
parties under the Interconnection Agreement and AEP System Interim Allowance
Agreement during the years ended December 31, 2000, 2001 and 2002:
2000 2001 2002
--------- --------- ---------
(IN THOUSANDS)
APCo. ............... $(274,000) $(256,700) $(127,000)
CSPCo................ (250,400) (251,200) (267,000)
I&M.................. 93,900 166,200 113,600
KPCo. ............... (21,500) (27,600) (46,500)
OPCo. ............... 452,000 369,300 326,900
PSO, SWEPCo, TCC and TNC, and AEPSC 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 west zone public utility
subsidiaries 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 west zone 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 following table shows the net credits or (charges) allocated among the
parties under the CSW Operating Agreement during the years ended December 31,
2000, 2001 and 2002:
2000 2001 2002
------- ------- --------
(IN THOUSANDS)
PSO.................. $(9,000) $(6,500) $(53,700)
SWEPCo............... 55,400 62,300 67,800
TCC.................. 3,600 (13,500) 15,400
TNC.................. (50,000) (42,300) (29,500)
Power generated by or allocated or provided under the Interconnection
Agreement or CSW Operating Agreement to any public utility subsidiary is often
sold to customers (or in the case of the ERCOT area of Texas, REPs) by such
public utility subsidiary at rates approved (other than in the ERCOT area of
Texas) by the public utility commission in the jurisdiction of sale. In Ohio,
Virginia and the ERCOT area of Texas, such rates are based on a statutory
formula as those jurisdictions transition to the use of market rates for
generation. See Energy Delivery -- Regulation -- Rates.
Under the Interconnection Agreement, power allocated to a public utility
subsidiary that is not required to serve its native load is sold at wholesale on
behalf of such subsidiary. Under the CSW Operating Agreement, power generated
that is not needed to serve the native load of any public utility subsidiary is
sold at wholesale by the generating subsidiary. See Trading and Marketing of
Energy Commodities for a discussion of the trading and marketing of such power.
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 distribu-
12
tion, 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 Interconnection Agreement and the CSW Operating Agreement,
each of which controls the distribution of costs and benefits within each zone.
Competition and Regulation
Retail Sales: AEP's public utility subsidiaries have the right (which in
some cases is exclusive) to sell electric power at retail within their
respective service areas in the states of Arkansas, Indiana, Kentucky,
Louisiana, Oklahoma, Tennessee, West Virginia and the SPP area of Texas. In
Michigan, Ohio and Virginia, AEP's public utility subsidiaries continue to
provide service to customers who have not been offered or have not selected
alternate service from competing suppliers. In those states, service is
currently being provided according to prescribed rules and rates. In the ERCOT
area of Texas, TCC and TNC sell power to Centrica, which provides PTB service to
certain former customers of TCC and TNC and must compete for customers.
AEP's public utility subsidiaries also 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 competing generators and
self-generation, the public utility subsidiaries of AEP believe that they
generally maintain a favorable competitive position. 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 customers in the United States,
including those served by the AEP System. Some of these industrial customers
have requested price reductions from their suppliers of electric power. In
addition, industrial customers that 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, providing various
off-peak or interruptible supply options pursuant to tariffs filed with the
various state commissions. Occasionally, these rates are first negotiated, and
then filed with the state commissions. The public utility subsidiaries believe
that they are unlikely to be materially adversely affected by this competition.
See Energy Delivery -- Regulation -- Rates for a description of the setting
of rates for power sold at bundled or unbundled state-regulated rates.
Wholesale Sales: The public utility subsidiaries of AEP, like the electric
industry generally, face increasing competition in the sale of available power
on a wholesale basis, primarily to other public utilities and power marketers.
The Energy Policy Act of 1992 was designed, among other things, to foster
competition in the wholesale market by creating a generation market with fewer
barriers to entry and mandating that all generators have equal access to
transmission services. As a result, there are more generators able to
participate in this market. The principal factors in competing for wholesale
sales are price (including fuel costs), availability of capacity and power and
reliability of service.
The public utility subsidiaries of AEP are subject to regulation by the
FERC under the Federal Power Act in respect of rates for interstate sales at
wholesale. See General -- Regulation -- FERC.
Seasonality
Sale of electric power is generally a seasonal business. In many parts of
the country, demand for power peaks during the hot summer months, with market
prices also peaking at that time. In other areas, power demand peaks during the
winter. The pattern of this fluctuation may change due to the nature and
location of AEP's facilities and the terms of power sale contracts AEP enters
into. In addition, AEP has historically sold less power, and consequently earned
less income, when weather conditions are milder. Unusually mild weather in the
future could diminish AEP's results of operations and may impact its financial
condition.
13
Fuel Supply
The following table shows the sources of power generated by the AEP System:
2000 2001 2002
---- ---- ----
Coal........................ 78% 74% 78%
Natural Gas................. 13% 12% 8%
Nuclear..................... 5% 11% 11%
Hydroelectric and other..... 4% 3% 3%
Variations in the generation of nuclear power are primarily related to
refueling outages and, in a portion of 2000, the shutdown of the Cook Plant to
respond to issues raised by the NRC. Variations in the generation of natural gas
power are primarily related to the availability of cheaper alternatives to
fulfill certain power requirements and to deactivate certain of its gas-fired
plants.
Coal and Lignite: AEP System generating companies procure coal and lignite
under a combination of purchasing arrangements including long-term contracts,
affiliate operations, short-term, and spot agreements with various producers and
coal trading firms. AEP believes, but cannot provide assurances that, it will be
able to secure coal and lignite of adequate quality and in adequate quantities
to operate its coal and lignite-fired units.
The following table shows the amount of coal delivered to the AEP System
during the past three years and the average delivered price of spot coal
purchased by System companies:
2000 2001 2002
------- ------- -------
Total coal delivered
to AEP operated
plants (thousands
of tons)........... 73,259 73,889 76,442
Average price per ton
of spot-purchased
coal............... $ 24.03 $ 27.30 $ 27.06
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, 2002, the
System's coal inventory was roughly 56 days of normal usage. This estimate
assumes that the total supply would be utilized through the operation of plants
that use coal most efficiently.
In cases of emergency or shortage, system companies have developed programs
to conserve coal supplies at their plants. 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 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 ratemaking 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.
Natural Gas: AEP, through its public utility subsidiaries, consumed over
163 billion cubic feet of natural gas during 2002 for generating power. 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. A portfolio of long-term and short-term purchase and
transportation agreements (that are acquired on a competitive basis and based on
market prices) supplies natural gas requirements for each plant.
Nuclear: I&M and STPNOC have made commitments to meet certain of the
nuclear fuel requirements of the Cook Plant and STP, respectively. 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. TCC and the other STP participants
have entered into contracts with suppliers for (i) 100% of the uranium
concentrate sufficient for the operation of both STP units through spring 2006
and (ii) 50% of the uranium concentrate needed for STP through spring 2007.
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
14
capability to store the spent nuclear fuel generated by the STP units over their
licensed lives.
Nuclear Waste and Decommissioning
I&M, as the owner of the Cook Plant, and TCC, as a partial owner of STP,
have a significant future financial commitment to safely dispose of SNF and
decommission and decontaminate the plants. 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; and
- 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 different than
current projections.
See Management's Discussion and Analysis of Results of Operations and
Management's Discussion and Analysis of Financial Condition, Accounting Policies
and Other Matters and Note 9 to the consolidated financial statements, entitled
Commitments and Contingencies, which are incorporated by reference in Items 7
and 8, respectively, for information with respect to nuclear waste and
decommissioning and related litigation.
Low-Level Radioactive Waste: The LLWPA mandates that the responsibility for
the disposal of low-level radioactive 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. Michigan and Texas do not
currently have disposal sites for such waste available. AEP cannot predict when
such sites may be available, but South Carolina and Utah operate low-level
radioactive waste disposal sites and accept low-level radioactive waste from
Michigan and Texas. AEP's access to the South Carolina facility is currently
allowed through the end of fiscal year 2008.
Deactivation and Planned Disposition of Generation Facilities
In September 2002, AEP indicated to ERCOT its intent to deactivate 16
gas-fired power plants (8 TCC plants and 8 TNC plants). ERCOT subsequently
conducted reliability studies that determined that seven plants (4 TCC plants
and 3 TNC plants) would be required to ensure reliability of the electricity
grid. As a result of these studies, ERCOT and AEP agreed to enter into
reliability must run agreements (which expired in December 2002, but have been
renewed for all but two units of these plants) to continue operation of these
plants. With ERCOT's approval, AEP proceeded with its planned deactivation of
the remaining nine plants.
TCC has also filed a plan of divestiture with the PUCT proposing to sell
all of its power generation assets in an effort to determine its level of
stranded costs in accordance with the Texas Act. The PUCT has dismissed its
proceeding relating to TCC's plan of divestiture in anticipation of promulgating
rules of general application regarding stranded cost determination for nuclear
facilities. See Energy Delivery-Regulatory Assets and Stranded Cost Recovery and
Post-Restructuring Wires Charges.
The assets to be sold have a generating capacity of 4,497 MW and include
eight gas-fired generating plants, one coal-fired plant, TCC's interest in
another coal-fired plant, a hydroelectric facility and TCC's interest in STP.
See Note 8 to the consolidated financial statements entitled Customer Choice and
Industry Restructuring, incorporated by reference in Item 8, for more
information on the planned disposition of TCC generation facilities.
TRADING AND MARKETING OF ENERGY COMMODITIES
AEP enters into transactions for the purchase and sale of electricity and
natural gas as part of wholesale trading operations. Electric and gas
transactions are executed over-the-counter with counterparties or through
brokers. Gas transactions are also executed through brokerage accounts with
brokers who are registered with the Commodity Futures Trading Commission.
Brokers and counterparties may require cash or cash related instruments to be
deposited on these transactions as margin against open positions.
AEP trades electricity and gas contracts with numerous counterparties.
Since AEP's open energy trading contracts are valued based on changes in
15
market prices of the related commodities, our exposures change daily.
In October 2002, AEP announced its plans to reduce its exposure to energy
trading markets and to downsize the trading and wholesale marketing operations.
It is expected that in the future power trading and marketing operations will be
smaller in scope, will generally be limited to risk management around AEP assets
and, accordingly, focused in regions in which AEP owns assets.
Energy Market Investigations
During 2002, several governmental entities launched investigations of
participants in energy trading markets, including AEP. A number of research projects which
are directed toward developing more efficient methodsthose
investigations resulted in data requests of burningAEP. See Management's Discussion and
Analysis of Financial Condition, Accounting Policies and Other Matters,
incorporated by reference in Item 7, under the heading Energy Market
Investigations.
NATURAL GAS PIPELINE, STORAGE AND PROCESSING FACILITIES
AEP, through certain subsidiaries, operates and owns an interest in a
significant amount of gas-related assets, including:
- 6,400 miles of natural gas pipelines between two systems;
- 128 billion cubic feet of storage among two facilities;
- Five natural gas processing plants; and
- Certain gas marketing contracts.
COAL MINES AND RELATED FACILITIES
AEP, through certain subsidiaries, holds various properties, coal reducingreserves,
mining operations and royalty interests in Colorado, Kentucky, Louisiana, Ohio,
Pennsylvania and West Virginia.
BARGE, RAIL AND OTHER FUEL TRANSPORTATION RELATED ASSETS
AEP, through MEMCO Barge Line Inc., is engaged in the contaminants resulting from combustiontransportation of
coal and improvingdry bulk commodities, primarily on the efficiencyOhio, Illinois, and reliabilityLower
Mississippi rivers for AEP, as well as unaffiliated customers. AEP, through
certain subsidiaries, owns or leases 7,000 railcars, 1,800 barges, 37 tug boats
and two coal handling terminals with 20 million tons of power transmission, distribution and utilization,
including load management.annual capacity.
STRUCTURED ARRANGEMENTS INVOLVING CAPACITY, ENERGY, AND ANCILLARY SERVICES
Dow
AEP System operating companies are membershas entered into an agreement with The Dow Chemical Company to
construct a 900 MW cogeneration facility at Dow's chemical facility in
Plaquemine, Louisiana. Commercial operation is expected in November 2003. AEP is
entitled to 100% of the Electric Power Research
Institute (EPRI),facility's capacity and energy over The Dow Chemical
Company's requirements and has contracted to sell the power from this facility
to an unaffiliated party.
Buckeye
In January 2000, OPCo and NPC, an affiliate of Buckeye, entered into an
agreement relating to the construction and operation of a nonprofit organization that manages research and
development on behalf510 MW gas-fired
electric generating peaking facility to be owned by NPC. From the commercial
operation date (which occurred in 2002) until the end of 2005, OPCo will be
entitled to 100% of the U.S. electric utility industry. EPRI, foundedpower 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.
CERTAIN POWER AGREEMENTS
AEGCo
Since its formation in 1973, manages technical research1982, AEGCo's business has consisted of the
ownership and development programsfinancing of its 50% interest in Unit 1 of 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 KPCo pursuant to
unit power agreements.
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, when added to amounts
received by AEGCo from any other sources, will be at least
16
sufficient to enable AEGCo to pay all its membersoperating 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 improvean assignment between I&M and KPCo, and a unit power production, deliveryagreement
between KPCo and use. Approximately 700 utilities are
members. EPRIAEGCo, AEGCo sells KPCo 30% of the power (and the energy
associated therewith) available to AEGCo from both units of the Rockport Plant.
KPCo has agreed to pay to AEGCo the same amounts which I&M would have paid AEGCo
under the terms of the I&M Power Agreement for such entitlement. The KPCo unit
power agreement expires on December 31, 2004. The agreement will be extended
until December 31, 2009 for Unit 1 and December 31, 2022 for Unit 2 if AEP's
restructuring settlement agreement filed with the FERC becomes effective.
AEGCo and AEP have entered into a membership programcapital 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.
OVEC
AEP, CSPCo and several unaffiliated utility companies jointly own OVEC. The
aggregate equity participation of AEP and CSPCo in OVEC is 44.2%. Until
September 1, 2001, OVEC supplied the power requirements of a uranium enrichment
plant near Portsmouth, Ohio owned by the DOE. The sponsoring companies are now
entitled to receive and pay for all OVEC capacity (approximately 2,200 MW) in
proportion to their power participation ratios. The aggregate power
participation ratio of APCo, CSPCo, I&M and OPCo is 42.1%. The proceeds from the
sale of power by OVEC are designed to be sufficient for OVEC to meet its
operating expenses and fixed costs and to provide a return on its equity
capital. The Inter-Company Power Agreement, which defines the rights of the
owners and sets the power participation ratio of each, will expire by its terms
on March 12, 2006.
Buckeye
Contractual arrangements among OPCo, Buckeye and other investor-owned
electric utility companies in Ohio provide for the transmission and delivery,
over facilities of OPCo and of other investor-owned utility companies, of power
generated by the two units at the Cardinal Station owned by Buckeye and back-up
power to which Buckeye is entitled from OPCo under such contractual
arrangements, to facilities owned by 25 of the rural electric cooperatives which
operate in the State of Ohio at 342 delivery points. Buckeye is entitled under
such arrangements to receive, and is obligated to pay for, the excess of its
maximum one-hour coincident peak demand plus a 15% reserve margin over the
1,226,500 kilowatts of capacity of the generating units which Buckeye currently
owns in the Cardinal Station. Such demand, which occurred on August 1, 2002, was
recorded at 1,398,559 kilowatts.
ENERGY DELIVERY
GENERAL
AEP's public utility subsidiaries own and operate transmission and
distribution lines and other facilities to deliver electric power. See Item
2--Properties for more information regarding the transmission and distribution
lines. Most of the transmission and distribution services are sold, in
combination with AEP whereby dueselectric power, to retail customers of AEP's public utility
subsidiaries in their service territories. These sales are being phasedmade at rates
established by the state utility commissions of the states in from 1994 through 1996. Recovery ofwhich they
operate, and in some instances, the FERC as well. See Regulation-- Rates. The
FERC regulates and approves the rates for wholesale transmission transactions.
See General--Regulation-- FERC. As discussed below, some transmission services
also are separately sold to non-affiliated companies.
AEP's public utility subsidiaries hold franchises or other rights to
provide electric service in various municipalities and regions in their service
areas. In some cases, these dues through rates
by AEP'sfranchises provide the utility with the exclusive
right to provide electric service. These franchises have varying provisions and
expiration
17
dates. In general, the operating companies has reasonably coincidedconsider their franchises to be
adequate for the conduct of their business. For a discussion of competition in
the sale of power, see Wholesale Operations-- Generation-- Competition and
Regulation.
REGULATION
AEP is in the business of providing generation, transmission and
distribution services. The transmission and distribution functions are part of
AEP's energy delivery segment. The generation function is part of AEP's
wholesale operations segment. This discussion covers the regulation of
transmission and distribution, but also generation sold at retail (which would
otherwise be included in the wholesale operations segment discussion).
Rates
Historically, state utility commissions have established electric service
rates on a cost-of-service basis, which is designed to allow a utility an
opportunity to recover its cost of providing service and to earn a reasonable
return on its investment used in providing that service. A utility's cost of
service is generally comprised of its operating expenses, including operation
and maintenance expense, depreciation expense and taxes. State utility
commissions periodically adjust rates pursuant to a review of (i) a utility's
revenues and expenses during a defined test period and (ii) such utility's level
of investment. Absent a legal limitation, such as a law limiting the frequency
of rate changes or capping rates for a period of time as part of a transition to
customer choice of generation suppliers, a state utility commission can review
and change rates on its own initiative. Some states may initiate reviews at the
request of a utility, customer, governmental or other representative of a group
of customers. Such parties may, however, agree with their phase-in
dates. It is anticipated thatone another not to request
reviews of or changes to rates for a specified period of time.
The rates of AEP's public utility subsidiaries are generally based on the
cost of providing traditional bundled electric service (i.e., generation,
transmission and distribution service). In Ohio, Virginia and the ERCOT area of
Texas, rates are transitioning from bundled cost-based rates for electric
service to unbundled cost-based rates for transmission and distribution service
on the one hand, and market pricing for and/or customer choice of generation on
the other.
Historically, the state regulatory frameworks in the service area of the
AEP System reflected specified fuel costs as part of bundled (or, more recently,
unbundled) rates or incorporated fuel adjustment clauses in a utility's rates
and tariffs. Fuel adjustment clauses permit periodic adjustments to fuel cost
recovery from customers and therefore provide protection against exposure to
fuel cost changes. While the historical framework remains in a portion of AEP's
service territory, recovery of increased fuel costs (i) is no longer provided
for in Ohio and (ii) may be limited in Indiana and Michigan, which have capped
rates. Fuel recovery is also limited in the final 1996 dues phase-inERCOT area of Texas, but because AEP
sold MECPL and MEWTU, there is little impact on AEP of fuel recovery procedures
related to service in ERCOT.
The following state-by-state analysis summarizes the regulatory environment
of each jurisdiction in which AEP operates. Several public utility subsidiaries
operate in more than one jurisdiction.
Indiana: I&M provides retail electric service in Indiana at a bundled rate
approved by the IURC. While rates are set on a cost-of-service basis, utilities
may also generally seek to adjust fuel clause rates quarterly. I&M's base rate
is capped through December 31, 2004 and its fuel recovery rate is capped through
February 29, 2004.
Ohio: CSPCo and OPCo operate as functionally separated utilities and
provide "default" retail electric service to customers at unbundled rates
established by the Ohio Act through December 31, 2005. Thereafter, CSPCo and
OPCo will continue to provide distribution services to retail customers at rates
approved by the PUCO. These rates will be soughtfrozen from December 31, 2005 to (i)
December 31, 2008 for CSPCo and (ii) December 31, 2007 for OPCo. Transmission
services will continue to be provided at rates established by the FERC. Default
retail generation service rates will be based on market prices pursuant to rules
currently under consideration by the PUCO.
Oklahoma: PSO provides retail electric service in Oklahoma at a bundled
rate approved by the OCC. PSO's rates are set on a cost-of-service basis. Fuel
and purchased power costs above the amount included in base rates are recovered
by applying a fuel adjustment factor to retail kilowatt-hour sales. The factor
is adjusted quarterly and is based upon forecasted fuel and purchased power
costs. Over or under collections of fuel costs for prior periods can be
recovered when new quarterly factors are established.
Texas: The Texas Act requires the legal separation of generation-related
assets from transmission and
18
distribution assets. TCC and TNC currently operate on a functionally separated
basis. In January 2002, TCC and TNC transferred all their retail customers in
the ERCOT area of Texas to MECPL, MEWTU and AEP Commercial and Industrial REP
(an AEP affiliate). TNC's retail SPP customers were ultimately transferred to
Mutual Energy SWEPCo L.P. (an AEP affiliate). TCC and TNC provide retail
transmission and distribution service on a cost-of-service basis at rates
approved by the PUCT and wholesale transmission service under tariffs approved
by the FERC consistent with PUCT rules.
The implementation of the business separation plan for SWEPCo operations in
the SPP area of Texas was delayed by the PUCT. As such, SWEPCo's Texas
operations continue to operate and to be regulated as a traditional bundled
utility with both base and fuel rates.
Virginia: APCo provides unbundled retail electric service in Virginia.
APCo's unbundled generation, transmission (which reflect FERC approved
transmission rates) and distribution rates as well as its functional separation
plan were approved by the VSCC in December 2001.
The Virginia Act capped base rates at their mid-1999 levels until the end
of the transition period (July 1, 2007), or sooner if the VSCC finds that a
competitive market for generation exists in Virginia. The Virginia Act permits
APCo to seek a one-time change to its capped non-generation rates after January
1, 2004. The Virginia Act allows adjustments to fuel rates during the transition
period and continues to permit utilities to recover their actual fuel costs, the
fuel component of their purchased power costs and certain capacity charges. APCo
recovers its generation capacity charges through capped base rates.
West Virginia: APCo and Wheeling Power Company provide retail electric
service at bundled rates approved by the WVPSC. A plan to introduce customer
choice was approved by the West Virginia Legislature in its 2000 legislative
session. However, implementation of that plan was placed on hold pending
necessary changes to the state's tax laws in a subsequent session. Those changes
have not been made.
While West Virginia generally allows recovery of fuel costs, the most
recent proceeding resulted in the suspension of an active fuel clause for APCo
and WPCo (though they continue to recover fuel costs through fixed bundled
rates). APCo and Wheeling Power Company are currently unable to change the
current level of fuel cost recovery, though this ability could be reinstated in
a future proceeding.
Other Jurisdictions: The public utility subsidiaries of AEP also provide
service at regulated bundled rates in Arkansas, Kentucky, Louisiana and
Tennessee and regulated unbundled rates in Michigan.
19
The table below illustrates the current rate cases.
Total research and development expenditures byregulation status of the
states in which the public utility subsidiaries of AEP and its subsidiaries were
approximately $19,300,000operate:
FUEL CLAUSE RATES PERCENTAGE
------------------------------------------------- OF AEP
STATUS OF BASE RATES FOR SYSTEM SALES SYSTEM
----------------------------------------------- PROFITS SHARED RETAIL
JURISDICTION POWER SUPPLY ENERGY DELIVERY STATUS INCLUDES W/RATEPAYERS REVENUES(1)
- ------------ ---------------------- ---------------------- -------------- -------------- --------------- -----------
Ohio Frozen through 2005 Distribution frozen None Not applicable Not applicable 30%
through 2007 for OPCo
and 2008 for CSP;
Transmission frozen
through 2005
Texas
(TCC, TNC) See footnote 2 Not capped or frozen Not applicable Not applicable Not applicable 17%(2)
Texas
(SWEPCo) Capped until 6/15/03 Active Fuel and fuel Yes, above base 3%
portion of levels
purchased
power
Indiana Capped until 1/1/05(3) Capped until Fuel and fuel No 10%
3/1/04(3) portion of
purchased
power
Virginia Capped until as late Capped until as late Active Fuel and fuel No 9%
as 7/1/07(4) as 7/1/07(4) portion of
purchased
power
West Virginia Fixed(5) Suspended(5) Fuel and fuel Yes, but 9%
portion of suspended
purchased
power
Oklahoma Cap expired 1/1/03 Active Fuel and fuel Yes 9%
portion of
purchased
power
Louisiana Capped until 6/15/05 Active Fuel and fuel Yes, above base 5%
portion of levels
purchased
power
Kentucky Frozen until 6/15/03(6) Active Fuel and fuel Yes, above base 3%
portion of levels
purchased
power
Arkansas Capped until 6/15/03 Active Fuel and fuel Yes, above base 2%
portion of levels
purchased
power
Michigan Capped until 1/1/05(7) Capped until 1/1/05(7) Capped until Fuel and fuel Yes, in some 2%
1/1/04(8) portion of areas, but
purchased suspended
power
Tennessee Not capped or frozen Active Fuel and fuel No 1%
portion of
purchased
power
- ---------------------------------
(1) Represents the percentage of revenues from sales to retail customers from
AEP utility companies operating in each state to the total AEP System
revenues from sales to retail customers for the year ended December 31,
1995, $7,600,0002002.
(2) Retail electric service in the ERCOT area of Texas is provided to most
customers through unaffiliated REPs which must offer PTB rates until January
1, 2007. The percentage of revenues shown includes revenues from power sales
contracts between MECPL and TCC and MEWTU and TNC.
20
(3) Capped base and fuel rates pursuant to a 1999 settlement with base rate
freeze extended pursuant to merger stipulation.
(4) Base rates are capped until the earlier of 7/1/07 or a finding by the VSCC
that a competitive market for generation exists. One-time change in
non-generation rates is allowed in Virginia after 1/1/04.
(5) Rates fixed and expanded net energy clause suspended in West Virginia
pursuant to a 1999 rate case stipulation, but subject to change in a future
proceeding.
(6) Utilities may request that an environmental surcharge be imposed to recover
costs associated with the installation of emission control equipment.
(7) Capped base and fuel rates pursuant to a 1999 settlement and base rates
extended pursuant to merger stipulation.
(8) Michigan fuel rates capped until 1/1/04 pursuant to a 1999 fuel settlement.
AEP TRANSMISSION POOL
Transmission Equalization Agreement
APCo, CSPCo, I&M, KPCo and OPCo operate their transmission lines as a
single interconnected and coordinated system and are parties to the Transmission
Equalization Agreement, dated April 1, 1984, as amended (TEA), defining how they
share the costs and benefits 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). This sharing
is based upon each company's "member-load ratio." The member-load ratio is
calculated monthly by dividing such company's highest monthly peak demand for
the yearlast twelve months by the aggregate of the highest monthly peak demand for
the last twelve months for all east zone operating companies. As of December 31,
2002, the member-load ratios were as follows:
PEAK
DEMAND MEMBER-LOAD
(KW) RATIO (%)
------ -----------
APCo..................... 6,010 28.2
CSPCo.................... 4,040 19.0
I&M...................... 4,323 20.3
KPCo..................... 1,551 7.3
OPCo..................... 5,360 25.2
The following table shows the net credits or (charges) allocated among the
parties to the TEA during the years ended December 31, 19942000, 2001 and $13,800,0002002:
2000 2001 2002
-------- -------- -------
(IN THOUSANDS)
APCo................. $ 3,400 $ 3,100 $ 13,400
CSPCo................ (38,300) (40,200) (42,200)
I&M.................. 43,800 41,300 36,100
KPCo................. 6,000 4,600 5,400
OPCo................. (14,900) (8,800) (12,700)
Transmission Coordination Agreement
PSO, SWEPCo, TCC, TNC and AEPSC 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 public
utility subsidiaries, including the performance of transmission planning
studies, the interaction of such subsidiaries with independent system operators
and other regional bodies interested in transmission planning and compliance
with the terms of the OATT filed with the FERC and the rules of the FERC
relating to such tariff.
Under the TCA, the west zone public utility subsidiaries have delegated to
AEPSC the responsibility of monitoring the reliability of their transmission
systems and administering the AEP OATT on their behalf. The TCA also provides
for the yearallocation among the west zone public utility subsidiaries of revenues
collected for transmission and ancillary services provided under the AEP OATT.
The following table shows the net credits or (charges) allocated among the
parties to the TCA during the years ended December 31, 1993. This includes expenditures2000, 2001 and 2002:
2000 2001 2002
------ ------ ------
(IN THOUSANDS)
PSO................... $ 3,300 $ 4,000 $ 4,200
SWEPCo................ 5,900 5,400 5,000
TCC................... (3,400) (3,900) (3,600)
TNC................... (5,800) (5,500) (5,600)
Transmission Services for Non-Affiliates
In addition to providing transmission services in connection with their own
power sales, AEP's public utility subsidiaries and other System companies also
provide transmission services for non-affiliated compa-
21
nies. See Regulation--Regional Transmission Organizations. AEP's public utility
subsidiaries are subject to regulation by the FERC under the FPA in respect of
$6,700,000transmission of electric power.
Coordination of East and West Zone Transmission
AEP's System Transmission Integration Agreement provides for 1995, $2,200,000the
integration and coordination of the planning, operation and maintenance of the
transmission facilities of AEP's east and west zone public utility subsidiaries.
The System Transmission Integration Agreement functions as an umbrella agreement
in addition to the TEA and the TCA. The System Transmission Integration
Agreement contains two service schedules that govern:
- The allocation of transmission costs and revenues and
- The allocation of third-party transmission costs and revenues and System
dispatch costs.
The System Transmission Integration Agreement contemplates that additional
service schedules may be added as circumstances warrant.
COMPETITION
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. Legislation has been enacted in Michigan, Ohio, Texas and Virginia
that allows for 1994customer choice of generation supplier. Although restructuring
legislation has been passed in Oklahoma and $10,900,000West Virginia, it has been delayed
indefinitely in Oklahoma and not implemented in West Virginia. In addition,
restructuring legislation in Arkansas has been repealed. See General--Electric
Restructuring Legislation. Customer choice legislation generally allows
competition in the generation and sale of electric power, but not in its
transmission and distribution.
See Management's Discussion and Analysis of Results of Operations and
Management's Discussion and Analysis of Financial Condition, Accounting Policies
and Other Matters and Note 8 to the consolidated financial statements entitled
Customer Choice and Industry Restructuring incorporated by reference in Items 7
and 8, respectively, for 1993further information with respect to restructuring
legislation affecting AEP subsidiaries.
SEASONALITY
Sale of electric power is generally a seasonal business. In many parts of
the country, demand for power peaks during the hot summer months, with market
prices also peaking at that time. In other areas, power demand peaks during the
winter. The pattern of this fluctuation may change due to the nature and
location of AEP's facilities and the terms of power sale contracts AEP enters
into. In addition, AEP has historically sold less power, and consequently earned
less income, when weather conditions are milder. Unusually mild weather in the
future could diminish AEP's results of operations and may impact its financial
condition.
REGIONAL TRANSMISSION ORGANIZATIONS
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 that 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
that 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 RTOs, entities created to operate, plan and control utility
transmission assets. Order 2000 also prescribes certain characteristics and
functions of acceptable RTO proposals.
AEP is required, as a condition of FERC's approval in 2000 of AEP's merger
with CSW, to transfer functional control of its transmission facilities to one
or more RTOs. In May 2002, AEP announced an agreement with PJM to pursue terms
for its east zone public utility subsidiaries to participate in PJM, a
22
FERC approved RTO. In July 2002, the FERC tentatively approved AEP subsidiaries'
decision to join PJM, subject to certain conditions being met. The satisfaction
of these conditions is only partially within AEP's control. AEP's public utility
subsidiaries have filed applications with the state utility commissions of
Indiana, Kentucky, Ohio and Virginia requesting approval of the transfer of
functional control of transmission assets in those states to PJM. Those
applications are pending. In February 2003, the Virginia legislature enacted
legislation that would prohibit the transfer of functional control of
transmission assets to an RTO until at least July 2004.
In July 2002, FERC conditionally accepted filings related to pressurized fluidized-bed combustion,
a processproposed
consolidation of MISO and the SPP. In that order the FERC required AEP's west
zone subsidiaries in SPP to file reasons why those subsidiaries should not be
required to join MISO. SWEPCo has filed an application with the LPSC requesting
approval of the transfer of functional control of its Louisiana transmission
assets to MISO and intends to make a similar filing in Arkansas with respect to
its Arkansas transmission assets. AEP presently plans to transfer functional
control of its transmission facilities in SPP to MISO or the merged MISO/SPP.
TEXAS REGULATORY ASSETS AND STRANDED COST RECOVERY AND POST-RESTRUCTURING WIRES
CHARGES
Certain transmission and distribution utilities in Texas whose generation
assets were unbundled pursuant to the Texas Act may recover generation-related
regulatory assets and generation-related stranded costs. Regulatory assets
consist of the Texas jurisdictional amount of generation-related regulatory
assets and liabilities in the audited financial statements as of December 31,
1998. Stranded costs consist of the positive excess of the net regulated book
value of generation assets over the market value of those assets, taking
specified factors into account. The Texas Act allows alternative methods of
valuation to determine the fair market value of generation assets, including
outright sale, full and partial stock valuation and asset exchanges, and also,
for nuclear generation assets, the ECOM model.
The Texas Act further permits utilities to establish a special purpose
entity to issue securitization bonds for the recovery of regulatory assets and,
after the 2004 true-up proceeding, the amount of stranded costs and remaining
regulatory assets not previously securitized. Securitization bonds allow for
regulatory assets and stranded costs to be refinanced with recovery of the bond
principal and financing costs ensured through a non-bypassable rate surcharge by
the regulated transmission and distribution utility over the life of the
securitization bonds. Any stranded costs not recovered through the sale of
securitization bonds may be recovered through a separate non-bypassable
competitive transition charge to transmission and distribution customers.
Regulatory Assets
In 1999, TCC filed an application with the PUCT to securitize approximately
$1.27 billion of its retail generation-related regulatory assets and
approximately $47 million in other qualified restructuring costs. On March 27,
2000, the PUCT issued an order authorizing issuance of up to $797 million of
securitization bonds including $764 million for recovery of net generation-
related regulatory assets and $33 million for other qualified refinancing costs.
The securitization bonds were issued in February 2002. TCC has included a
transition charge in its distribution rates to repay the bonds over a 14-year
period. In addition, another $185 million of generation-related regulatory
assets are being recovered through distribution rates beginning in January 2002.
Remaining generation-related regulatory assets of approximately $214 million
originally included by TCC in its 1999 securitization request along with certain
other regulatory assets will be included in TCC's request to recover stranded
costs in the 2004 true-up proceeding.
Stranded Costs
In a March 2000 filing with the PUCT to determine unbundled transmission
and distribution charges and initial stranded cost recovery, TCC requested
recovery of an additional $1.1 billion of stranded costs and regulatory assets
that were not securitized. In October 2001, the PUCT issued an order in the UCOS
proceeding determining an initial amount of TCC ECOM or stranded costs of
approximately negative $615 million based upon the PUCT's ECOM model. The ruling
indicated that TCC costs were below market after securitization of regulatory
assets. TCC disagrees with the ruling and believes it has positive stranded
costs in addition to the securitized regulatory assets.
As a result of this stranded cost determination, the PUCT ordered TCC to
refund $55 million of estimated excess earnings for the period 1999 through 2001
to customers through a credit applied to distribu-
23
tion rates over a five-year period. TCC appealed the PUCT's estimate of stranded
costs and refund of excess earnings, among other issues, to the Travis County
District Court. This estimate may be superseded by a final determination made as
part of the 2004 true-up proceedings.
The final amount of TCC's stranded costs including regulatory assets and
ECOM will be established by the PUCT in the 2004 true-up proceeding. Pursuant to
PUCT rules, if TCC's total stranded costs determined in the 2004 true-up
proceeding are less than the amount of securitized regulatory assets, the PUCT
can implement an offsetting credit to transmission and distribution rates. The
Texas Third Circuit Court of Appeals ruled in February 2003 that the Texas Act
does not contemplate the refunding to customers of negative stranded costs. In
addition, the Court ruled that negative stranded costs cannot be offset against
other true-up adjustments, including under-recovered fuel amounts. This ruling
may be appealed to the Texas Supreme Court, which sulfurhas discretion as to whether
to accept and consider the appeal.
2004 True-Up Proceedings
Beginning as early as January 2004, the PUCT will conduct true-up
proceedings (with respect to the ERCOT area of Texas) for each investor-owned
utility, its affiliated REP and affiliated power generation company. The purpose
of the true-up proceeding is removedto (i) quantify and reconcile the amount of
stranded costs and generation-related regulatory assets that have not yet been
securitized, (ii) conduct a true-up of the PUCT ECOM model for 2002 and 2003 to
reflect market prices determined in required capacity auctions, (iii) establish
final fuel recovery balances and (iv) determine the price to beat clawback
component. The true-up proceeding will generally result in either additional
charges or credits to retail customers through transmission and distribution
rates collected by their REPs and remitted to the utility.
Stranded Cost and Generation-Related Regulatory Asset Determination: The
Texas Act authorized the use of several valuation methodologies to quantify
stranded costs and generation-related regulatory assets in the 2004 true-up
proceeding, including by the sale of assets. TCC filed a plan of divestiture
with the PUCT in December 2002 seeking approval to sell its generation assets to
determine their market value. The PUCT has dismissed its proceeding relating to
TCC's plan of divestiture in anticipation of promulgating rules of general
application regarding stranded cost determination. If the PUCT determines the
sale of assets methodology cannot be used to determine the market value of STP,
TCC intends to pursue the use of one or more market valuation methods.
Divestiture of TCC's interest in STP to a nonaffiliate will also require NRC
approval. TNC does not have any recoverable stranded costs or generation-related
regulatory assets that can be considered as part of the 2004 true-up.
ECOM/Capacity Auction Component: The PUCT used a computer model or
projection, called an ECOM model, to estimate stranded costs related to
generation plant assets in the UCOS proceeding. In connection with using the
ECOM model to calculate the stranded cost estimate, the PUCT estimated the
market power prices that will be received in the competitive wholesale
generation market. Any difference between the ECOM model market prices and
actual market power prices as measured by generation capacity auctions required
by the Texas Act during coal combustionthe period of January 1, 2002 through December 31, 2003
will be a component of the 2004 true-up proceeding, either increasing or
decreasing the amount of recovery for TCC. Auctions to date have generally
indicated that market prices have been lower than the PUCT's ECOM estimates.
Unless this is reversed, TCC's recovery in the 2004 true-up proceeding would be
increased. In the event TCC has transferred its generation assets to an
affiliate, the Texas Act would require TCC to remit to its affiliate the
recovery amount accruing after the transfer. See Note 8 to the consolidated
financial statements, entitled Customer Choice and nitrogen oxide
formationIndustry Restructuring,
incorporated by reference in Item 8, for a discussion of the current calculation
of the difference between the market price and ECOM estimate.
Fuel Recovery Balance Determination: The amount TCC or TNC recovers in the
2004 true-up proceeding could be increased or reduced (or the amount TCC must
refund could be increased) by any under or over-recovery of fuel. The fuel
component will be determined by the amount of fuel costs and expenses the PUCT
approves based on a final fuel reconciliation that TCC filed on December 2, 2002
and that TNC filed on June 3, 2002. TCC's fuel reconciliation covers its fuel
costs from the period beginning July 1, 1998 and ending December 31, 2001. TCC's
fuel reconciliation filing seeks approval for $1.6 billion in fuel expense
collected from retail customers during that period. TCC's fuel reconciliation
filing reflects a fuel over-recovery balance, as of December 31, 2001, of $63.5
million, including
24
interest. A procedural schedule has been set with a hearing scheduled to begin
May 7, 2003. TNC's fuel reconciliation requests approval of $292 million in fuel
costs associated with serving both ERCOT and SPP retail customers from July 1,
2000 through December 31, 2001. It reflects a fuel under-recovery balance, as of
December 31, 2001, of $26.9 million, including interest. The amounts in this
paragraph may periodically be adjusted as filings are updated or adjusted. A
final order from the PUCT is minimized. EPRI duesexpected in the first half of $9,600,0002003. Any under or
over-recovery, plus interest thereon, will be recovered from or returned to
customers as a component of the 2004 true-up proceeding.
Price to Beat Clawback Component: The amount TCC or TNC recovers in the
2004 true-up proceeding could be reduced (or the amount TCC or TNC must refund
could be increased) by the PTB clawback component. If MECPL and MEWTU (which are
no longer affiliated with TCC or TNC) continue to serve 60% or more of TCC's and
TNC's respective PTB load as of January 1, 2004 and the PTB (reduced by
non-bypassable wires charges) exceeds the market price of electricity, any such
excess must be credited to customers of TCC and TNC in the 2004 true-up
proceeding, by up to $150 per customer, subject to certain adjustments. The
Texas Act provides that MECPL and MEWTU effectively indemnify TCC and TNC,
respectively, for 1995any PTB clawback amounts assessed them. The MECPL and $3,200,000MEWTU
sale agreements provide that Centrica (as purchaser of MECPL and MEWTU) and AEP
Utilities (the parent of TCC and TNC, as seller of MECPL and MEWTU) will share
responsibility for 1994this indemnity.
Further Securitization Bonds and Wires Charges: After final determination
of its stranded costs and other true-up adjustments by the PUCT, TCC expects to
issue securitization bonds in the amount of its non-securitized stranded costs
and generation-related regulatory assets determined in the 2004 true-up
proceeding. The bonds can have a maximum term of 15 years. If securitization
bonds are not issued to finance all non-securitized stranded costs and
generation-related regulatory assets, TCC will seek recovery of these amounts as
well as its other true-up adjustments, through a non-bypassable competition
transition charge in transmission and distribution rates.
For a discussion of recovery of regulatory assets and stranded costs in
Ohio and Virginia, see Note 8 to the consolidated financial statements entitled
Customer Choice and Industry Restructuring, incorporated by reference in Item 8.
OTHER INVESTMENTS
AEP has made certain investments in telecommunications, international
energy and other concerns. In 2002, AEP wrote down the value of certain of those
investments. See Management's Discussion and Analysis of Results of Operations
and Management's Discussion and Analysis of Financial Condition, Accounting
Policies and Other Matters and Note 13 to the consolidated financial statements
entitled Asset Impairment and Investment Value Losses, incorporated by reference
in Items 7 and 8, respectively.
AEP also included.sold the following foreign investments in 2002:
- SEEBOARD, an electricity supply and distribution company in the United
Kingdom serving 2,000,000 customers and covering 3,000 square miles of
service territory.
- CitiPower, a retail electricity and gas supply and distribution
subsidiary in Australia serving 240,000 customers.
25
Item 2. PROPERTIES
- --------------------------------------------------------------------------------
GENERATION FACILITIES
General
At December 31, 1995, subsidiaries of2002, the AEP System owned (or leased where indicated)
generating plants with the net power capabilities (winter(east zone public utility
subsidiaries-winter rating; west zone public utility subsidiaries-summer rating)
shown in the following table:
NET KILOWATT
OWNER, PLANT TYPE AND NAME LOCATION (NEAR) CAPABILITYCOAL NATURAL GAS HYDRO NUCLEAR LIGNITE OTHER TOTAL
COMPANY STATIONS MW MW MW MW MW MW MW
- ------------------------------------------------------------------------------------------------------------
AEP GENERATING COMPANY:
Steam
AEGCo 1(a) 1,300 1,300
APCo 17(b) 5,073 777 5,850
CSPCo 6(e) 2,595 2,595
I&M 10(a) 2,295 11 2,110 4,416
KPCo 1 1,060 1,060
OPCo 8(b)(f) 8,472 48 8,520
PSO 8(c) 1,043 3,169 25(g) 4,237
SWEPCo 9 1,848 1,797 842 4,487
TCC 12(c)(d)(h) 686 3,175 6 630 4,497
TNC 12(c) 377 999 16(g) 1,392
- Coal-Fired:
Rockport Plant (AEGCo share) Rockport, Indiana 1,300,000(a)
APPALACHIAN POWER COMPANY:
Steam------------------------------------------------------------------------------------------------------------
Totals: 84 24,749 9,140 842 2,740 842 41 38,354
- Coal-Fired:
John E. Amos, Units 1 & 2 St. Albans, West Virginia 1,600,000
John E. Amos, Unit 3 (APCo share) St. Albans, West Virginia 433,000(b)
Clinch River Carbo, Virginia 705,000
Glen Lyn Glen Lyn, Virginia 335,000
Kanawha River Glasgow, West Virginia 400,000
Mountaineer New Haven, West Virginia 1,300,000
Philip Sporn, Units 1 & 3 New Haven, West Virginia 308,000
Hydroelectric - Conventional:
Buck Ivanhoe, Virginia 10,000
Byllesby Byllesby, Virginia 20,000
Claytor Radford, Virginia 76,000
Leesville Leesville, Virginia 40,000
London Montgomery, West Virginia 16,000
Marmet Marmet, West Virginia 16,000
Niagara Roanoke, Virginia 3,000
Reusens Lynchburg, Virginia 12,000
Winfield Winfield, West Virginia 19,000
Hydroelectric - Pumped Storage:
Smith Mountain Penhook, Virginia 565,000
5,858,000
COLUMBUS SOUTHERN POWER COMPANY:
Steam - Coal-Fired:
Beckjord, Unit 6 New Richmond, Ohio 53,000(c)
Conesville, Units 1-3, 5 & 6 Coshocton, Ohio 1,165,000
Conesville, Unit 4 Coshocton, Ohio 339,000(c)
Picway, Unit 5 Columbus, Ohio 100,000
Stuart, Units 1-4 Aberdeen, Ohio 608,000(c)
Zimmer Moscow, Ohio 330,000(c)
2,595,000
INDIANA MICHIGAN POWER COMPANY:
Steam - Coal-Fired:
Rockport Plant (I&M share) Rockport, Indiana 1,300,000(a)
Tanners Creek Lawrenceburg, Indiana 995,000
Steam - Nuclear:
Donald C. Cook Bridgman, Michigan 2,110,000
Gas Turbine:
Fourth Street Fort Wayne, Indiana 18,000(d)
Hydroelectric - Conventional:
Berrien Springs Berrien Springs, Michigan 3,000
Buchanan Buchanan, Michigan 2,000
Constantine Constantine, Michigan 1,000
Elkhart Elkhart, Indiana 1,000
Mottville Mottville, Michigan 1,000
Twin Branch Mishawaka, Indiana 3,000
4,434,000
KENTUCKY POWER COMPANY:
Steam - Coal-Fired:
Big Sandy Louisa, Kentucky 1,060,000
OHIO POWER COMPANY:
Steam - Coal-Fired:
John E. Amos, Unit 3 (OPCo share) St. Albans, West Virginia 867,000(b)
Cardinal, Unit 1 Brilliant, Ohio 600,000
General James M. Gavin Cheshire, Ohio 2,600,000(e)
Kammer Captina, West Virginia 630,000
Mitchell Captina, West Virginia 1,600,000
Steam - Coal-Fired:
Muskingum River Beverly, Ohio 1,425,000
Philip Sporn, Units 2, 4 & 5 New Haven, West Virginia 742,000
Hydroelectric - Conventional:
Racine Racine, Ohio 48,000
8,512,000
Total Generating Capability 23,759,000
SUMMARY:
Total Steam -
Coal-Fired 20,795,000
Nuclear 2,110,000
Total Hydroelectric -
Conventional 271,000
Pumped Storage 565,000
Other 18,000
Total Generating Capability 23,759,000------------------------------------------------------------------------------------------------------------
- ------------------------------------
(a)Unit 1 of the Rockport Plant is owned one-half by AEGCo and one-half by I&M.
Unit 2 of the Rockport Plant is leased one-half by AEGCo and one-half by
I&M. The leases terminate in 2022 unless extended.
(b)Unit 3 of the John E. Amos Plant is owned one-third by APCo and two-thirds
by OPCo.
(c)Represents CSPCo's PSO, TCC and TNC jointly own the Oklaunion power station. Their respective
ownership interests are reflected in this table.
(d) Reflects TCC's interest in STP.
(e) CSPCo owns generating units owned in common with CG&E and DP&L. (d)Leased from the CityIts ownership
interest of Fort Wayne, Indiana. Since 1975, I&M has leased and
operated the assets of the municipal system of the City of Fort Wayne,
Indiana under a 35-year lease with a provision for an additional 15-year
extension at the election of I&M.
(e)1,330 MW is reflected in this table.
(f) The scrubber facilities at the General James M. Gavin Plant are leased. The
lease terminates in 2010 unless extended.
(g) PSO and TNC have 25 MW and 10 MW respectively of facilities designed
primarily to burn oil. TNC has one 6 MW wind farm facility.
(h) See Item 1 under FUEL SUPPLY,-- Wholesale Operations -- Power Generation -- Planned
Deactivation and Planned Disposition of Generation Facilities for a
discussion of TCC's planned disposition of its generation facilities.
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, 2002 is listed below.
CAPACITY OWNERSHIP
FACILITY FUEL LOCATION TOTAL MW INTEREST STATUS
- ----------------------------------------------------------------------------------------------------------
Brush II Natural gas Colorado 68 47.75% QF
Eastex Natural gas Texas 440 50% QF
Indian Mesa Wind Texas 161 100% EWG
Mulberry Natural gas Florida 120 46.25% QF
Newgulf Natural gas Texas 85 100% EWG
Orange Cogen Natural gas Florida 103 50% QF
Sweeny Natural gas Texas 480 50% QF
Thermo Cogeneration Natural gas Colorado 272 50% QF
Trent Wind Farm Wind Texas 150 100% EWG
- ----------------------------------------------------------------------------------------------------------
Total U.S. 1,879
- ----------------------------------------------------------------------------------------------------------
26
CAPACITY OWNERSHIP
FACILITY FUEL LOCATION TOTAL MW INTEREST STATUS
- ----------------------------------------------------------------------------------------------------------
Bajio Natural gas Mexico 605 50% FUCO
Ferrybridge Coal United Kingdom 2,000 100% FUCO
Fiddler's Ferry Coal United Kingdom 2,000 100% FUCO
Nanyang Coal China 250 70% FUCO
Southcoast Natural gas United Kingdom 380 50% FUCO
- ----------------------------------------------------------------------------------------------------------
Total International 5,235
- ----------------------------------------------------------------------------------------------------------
See Item 1 -- Wholesale Operations for information concerning natural gas
pipelines, storage and processing facilities, transportation related assets and
coal operations and reserves owned or controlled by subsidiariesAEP subsidiaries.
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
2002............... 86.6% 80.5% 99.2% 75.0%
2001 (C)........... 87.3% 83.4% 94.4% 87.1%
2000 (D)........... 1.4% 50.0% 78.2% 96.1%
- ------------------------------------
(a) Reflects total plant.
(b) For economic or other reasons, operation of AEP.the Cook Plant and STP for the
full term of their operating licenses cannot be assured.
(c) The capacity factor for both units of the Cook Plant was significantly
reduced in 2001 due to an unplanned dual maintenance outage in September
2001 to implement design changes that improved the performance of the
essential service water system.
(d) The Cook Plant was shut down in September 1997 to respond to issues raised
regarding the operability of certain safety systems. The restart of both
units of the Cook Plant was completed with Unit 2 reaching 100% power on
July 5, 2000 and Unit 1 achieving 100% power on January 3, 2001.
Costs associated with the operation (excluding fuel), maintenance and
retirement of nuclear plants continue to be of greater significance and less
predictable than costs associated with other sources of generation, in large
part due to changing regulatory requirements and safety standards, availability
of nuclear waste disposal facilities and experience gained in the construction
and operation of nuclear facilities. I&M and TCC 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 TCC 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
Item 1 -- Wholesale Operations -- Power Generation -- Planned Deactivation and
Planned Disposition of Generation Facilities for a discussion of TCC's planned
disposition of its interest in STP.
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, I&M, TCC and
other AEP System companies. See Note 9 to the consolidated financial statements
entitled Commitments and Contingencies, incorporated by reference in Item 8, for
information with respect to nuclear incident liability insurance.
27
TRANSMISSION AND DISTRIBUTION FACILITIES
The following table sets forth the total overhead circuit miles of
transmission and distribution lines of the AEP System APCo, CSPCo, I&M, KEPCo and OPCoits operating
companies and that portion of the total representing 765,000-volt lines:
TOTAL CIRCUIT MILES
OF TRANSMISSION AND CIRCUIT MILES OF
DISTRIBUTION LINES 765,000-VOLT LINES
AEP System (a) 125,545(b) 2,022
APCo 48,961 641
CSPCo (a) 14,710 ---
I&M 20,784 614
KEPCo 9,944 258
OPCo 28,286
TOTAL OVERHEAD
CIRCUIT MILES OF
TRANSMISSION AND CIRCUIT MILES OF
DISTRIBUTION LINES 765,000-VOLT LINES
------------------ ------------------
AEP System (a)....... 226,330(b) 2,023
APCo. ............. 50,756 642
CSPCo (a).......... 12,255 --
I&M................ 25,128 615
Kingsport Power
Company......... 1,335 --
KPCo. ............. 10,555 258
OPCo. ............. 35,551 509
PSO................ 21,539 --
SWEPCo............. 20,075 --
TCC................ 33,515 --
TNC................ 13,637 --
Wheeling Power
Company......... 1,941 --
- ------------------------------------
(a) Includes 766 miles of 345,000-volt jointly owned lines.
(b) Includes 73 miles of transmission lines of other AEP System companies not shown.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-heldprivately held lands used or to be used in their utility operations.
Substantially all the fixed physical properties and franchises of APCo, CSPCo, I&M, KEPCo and
OPCothe AEP
System operating companies, except for limited exceptions, are subject to the
lien of the mortgage and deed of trust securing the first mortgage bonds of each
such company.
SYSTEM TRANSMISSION LINES AND FACILITY SITING
Legislation in the states of Arkansas, Indiana, Kentucky, Michigan, Ohio,
Texas, Virginia, and West Virginia requires prior approval of sites of
generating facilities and/or routes of high-voltage transmission lines. Delays
and additional costs in constructing facilities have been experienced as a
result of proceedings conducted pursuant to such statutes, as well as in
proceedings in which operating companies have sought to acquire rights-of-way
through condemnation, and such proceedings may result in additional delays and
costs in future years.
PEAK DEMANDCONSTRUCTION PROGRAM
General
The AEP System is interconnected through 120 high-voltagecontinuously involved in assessing the adequacy of its
generation, transmission, interconnectionsdistribution 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 29 neighboringthe restructuring of the electric utility systems.industry.
Proposed Transmission Facilities
APCo is proceeding with its plan to build the Wyoming-Jacksons Ferry
765,000-volt transmission line. The all-timeWVPSC and 1995 one-hour peak System demands were 25,940,000 and 24,888,000 kilowatts,
respectively (which included 7,314,000 and 4,934,000 kilowatts, respectively,
of scheduled deliveries to unaffiliated systems which the System might, on
appropriate notice,VSCC have elected not to schedule for delivery) and occurred on
June 17, 1994 and August 15, 1995, respectively. The net dependable capacity
to serve the System load on such date, including power available under
contractual obligations, was 23,457,000 and 23,364,000 kilowatts, respectively.
The all-time and 1995 one-hour internal peak demands were 19,557,000 and
19,516,000 kilowatts, respectively, and occurred on February 5, 1996 and August
14, 1995, respectively. The net dependable capacity to serve the System load
on such date, including power dedicated under contractual arrangements, was
23,670,000 and 23,364,000 kilowatts, respectively. The all-time one-hour
integrated and internal net system peak demands and 1995 peak demands for AEP's
generating subsidiaries are shown in the following tabulation:
ALL-TIME ONE-HOUR INTEGRATED 1995 ONE-HOUR INTEGRATED
NET SYSTEM PEAK DEMAND NET SYSTEM PEAK DEMAND
(in thousands)
Number of Number of
KILOWATTS DATE KILOWATTS DATE
APCo 8,214 February 5, 1996 7,327 February 6, 1995
CSPCo 4,172 June 17, 1994 4,085 August 14, 1995
I&M 5,027 June 17, 1994 4,949 August 15, 1995
KEPCo 1,686 February 5, 1996 1,512 February 6, 1995
OPCo 7,291 June 17, 1994 6,913 August 15, 1995
ALL-TIME ONE-HOUR INTEGRATED 1995 ONE-HOUR INTEGRATED
NET INTERNAL PEAK DEMAND NET INTERNAL PEAK DEMAND
(in thousands)
Number of Number of
KILOWATTS DATE KILOWATTS DATE
APCo 6,908 February 5, 1996 6,507 February 9, 1995
CSPCo 3,378 August 14, 1995 3,378 August 14, 1995
I&M 3,864 August 14, 1995 3,864 August 14, 1995
KEPCo 1,418 February 5, 1996 1,363 February 9, 1995
OPCo 5,641 August 14, 1995 5,641 August 14, 1995
HYDROELECTRIC PLANTS
Licenses for hydroelectric plants, issued under the Federal Power Act,
reserve to the United States the right to take over the project at the
expiration of the license term, to issue a new license to another entity, or to
relicense the project to the existing licensee. In the event that a project is
taken over by the United States or licensed to a new licensee, the Federal
Power Act provides for payment to the existing licensee of its "net investment"
plus severance damages. Licenses for six System hydroelectric plants expired
in 1993 and applications for new licenses for these plants were filed in 1991.
The existing licenses for these plants were extended on an annual basis and
will be renewed automatically until new licenses are issued. No competing
license applications were filed. Four new licenses were issued in 1994. New
licenses for two other projects, one in Indiana and one in Michigan, are still
pending before the FERC. An original license for the previously unlicensed
Constantine project was issued in 1993. In 1995, a notice of intent to
relicense the Elkhart project located in Indiana was filed.
COOK NUCLEAR PLANT
Unit 1 of the Cook Plant, which was placed in commercial operation in 1975,
has a nominal net electric rating of 1,020,000 kilowatts. Unit 1's
availability factor was 66.3% during 1995 and 71.0% during 1994. Unit 2, of
slightly different design, has a nominal net electrical rating of 1,090,000
kilowatts and was placed in commercial operation in 1978. Unit 2's
availability factor was 94.4% during 1995 and 54.3% during 1994. Outages to
refuel affected the availability of Unit 1 in 1995 and Units 1 and 2 in 1994.
Units 1 and 2 are licensed by the NRC to operate at 100% of rated thermal
power to October 25, 2014 and December 23, 2017, respectively.
Costs associated with the operation, maintenance and retirement of nuclear
plants continue to be significant and less predictable than costs associated
with other sources of generation, in large part due to changing regulatory
requirements and safety standards and experience gained in thecertificates
authorizing construction and operation of nuclear facilities. I&M may also incurthe line. On December 31, 2002, the
U.S. Forest Service issued a final environmental impact statement and record of
decision to allow the use of federal lands in the Jefferson National Forest for
construction of a portion of the line. Additional state and federal permits are
expected to be issued in the first half of 2003. Through December 31, 2002 APCo
had invested approximately $51 million in this project. The line is estimated to
cost $287 million with completion scheduled in 2006.
28
Construction Expenditures
The following table shows construction expenditures during 2000, 2001 and
2002 and current estimates of 2003 construction expenditures, in each case
including AFUDC but excluding assets acquired under leases.
2000 2001 2002 2003
ACTUAL ACTUAL ACTUAL ESTIMATE
---------- ---------- ---------- ----------
(IN THOUSANDS)
AEP System (a)....... $1,773,400 $1,832,000 $1,709,800 $1,458,100
AEGCo. ............ 5,200 6,900 5,300 21,400
APCo. ............. 199,300 306,000 276,500 247,900
CSPCo. ............ 128,000 132,500 136,800 142,300
I&M................ 171,100 91,100 159,400 188,000
KPCo. ............. 36,200 37,200 178,700 72,300
OPCo. ............. 254,000 344,600 354,800 241,000
PSO................ 176,900 124,900 89,400 81,500
SWEPCo. ........... 120,200 112,100 111,800 104,900
TCC................ 199,500 194,100 151,500 126,800
TNC................ 64,500 39,800 43,600 46,500
(a) Includes expenditures of other subsidiaries not shown.
See Note 9 to the consolidated financial statements entitled Commitments
and Contingencies, incorporated by reference in Item 8, for further information
with respect to the construction plans of AEP and its operating subsidiaries for
the next three years.
The System construction program is reviewed continuously and is revised
from time to time in response to changes in estimates of customer demand,
business and economic conditions, the cost and availability of capital,
environmental requirements and other factors. Changes in construction schedules
and costs, and experience
reduced output at its Cook Plant becausein 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 design criteria prevailing at
the time of construction and the age of the plant's systems and equipment. In
addition, for economic or other reasons, operation of the Cook Plantestimated capital requirements for the full term of its now assumed life cannot be assured. Nuclear industry-wide and
Cook Plant initiatives have contributed to slowing the growth of operating and
maintenance costs. However, the ability of I&M to obtain adequate and timely
recovery of costs associated with the Cook Plant, including replacement power
and retirement costs, is not assured.
NUCLEAR INCIDENT LIABILITY
The Price-Anderson Act limits public liability for a nuclear incident at any
licensed reactor in the United States to $8.9 billion. I&M has insurance
coverage for liability from a nuclear incident at its Cook Plant. Such
coverage is provided through a combination of private liability insurance, with
the maximum amount available of $200,000,000, and mandatory participation for
the remainder of the $8.9 billion liability, in an industry retrospective
deferred premium plan which would, in case of a nuclear incident, assess all
licensees of nuclear plants in the U.S. Under the deferred premium plan, I&M
could be assessed up to $158,600,000 payable in annual installments of
$20,000,000 in the event of a nuclear incident at Cook or any other nuclear
plant in the U.S. There is no limit on the number of incidents for which I&M
could be assessed these sums.
I&M also has property damage, decontamination and decommissioning insurance
for loss resulting from damage to the Cook Plant facilities in the amount of
$3.6 billion. Energy Insurance Bermuda (EIB), Nuclear Mutual Limited (NML) and
Nuclear Electric Insurance Limited (NEIL) provide $2.75 billion of coverage and
nuclear insurance pools provide the remainder. If EIB's, NML's and NEIL's
losses exceed their available resources, I&M would be subject to a total
retrospective premium assessment of up to $33,000,000. NRC regulations require
that, in the event of an accident, whenever the estimated costs of reactor
stabilization and site decontamination exceed $100,000,000, the insurance
proceeds must be used, first, to return the reactor to, and maintain it in, a
safe and stable condition and, second, to decontaminate the reactor and reactor
station site in accordance with a plan approved by the NRC. The insurers then
would indemnify I&M for property damage up to $3.35 billion less any amounts
used for stabilization and decontamination. The remaining $250,000,000, as
provided by NEIL (reduced by any stabilization and decontamination expenditures
over $3.35 billion), would cover decommissioning costs in excess of funds
already collected for decommissioning. See FUEL SUPPLY - NUCLEAR WASTE.
NEIL's extra-expense program provides insurance to cover extra costs
resulting from a prolonged accidental outage of a nuclear unit. I&M's policy
insures against such increased costs up to approximately $3,500,000 per week
(starting 21 weeks after the outage) for one year, $2,800,000 per week for the
second and third years, or 80% of those amounts per unit if both units are down
for the same reason. If NEIL's losses exceed its available resources, I&M
would be subject to a total retrospective premium assessment of up to
$7,900,000.
POTENTIAL UNINSURED LOSSES
Some potential losses or liabilities may not be insurable or the amount of
insurance carried may not be sufficient to meet potential losses and
liabilities, including liabilities relating to damage to the Cook Plant and
costs of replacement power in the event of a nuclear incident at the Cook
Plant. Future losses or liabilities which are not completely insured, unless
allowed to be recovered through rates, could have a material adverse effect on
results of operations and the financial condition of AEP, I&M and other AEP
System companies.
System's
construction program.
Item 3. LEGAL PROCEEDINGS
On April 4, 1991, then Secretary of Labor Lynn Martin announced that the
U.S. Department of Labor (DOL) had issued a total of 4,710 citations to
operators of 847 coal mines who allegedly submitted respirable dust sampling
cassettes that had been altered so as to remove a portion of the dust. The
cassettes were submitted in compliance with DOL regulations which require
systematic sampling of airborne dust in coal mines and submission of the entire
cassettes (which include filters for collecting dust particulates) to the Mine
Safety and Health Administration (MSHA) for analysis. The amount of dust
contained on the cassette's filter determines an operator's compliance with
respirable dust standards under the law. OPCo's Meigs No. 2, Meigs No. 31,
Martinka, and Windsor Coal mines received 16, 3, 15 and 2 citations,
respectively. MSHA has assessed civil penalties totalling $56,900 for all
these citations. OPCo's samples in question involve about 1 percent of the
2,500 air samples that OPCo submitted over a 20-month period from 1989 through
1991 to the DOL. OPCo is contesting the citations before the Federal Mine
Safety and Health Review Commission. An administrative hearing was held before
an administrative law judge with respect to all affected coal operators. On
July 20, 1993, the administrative law judge rendered a decision in this case
holding that the Secretary of Labor failed to establish that the presence of a
"white center" on the dust sampling filter indicated intentional alteration.
In the case of an unaffiliated mine, the administrative law judge ruled on
April 20, 1994, that there was not an intentional alteration of the dust
sampling filter. The Secretary of Labor appealed to the Federal Mine Safety
and Health Review Commission the July 20, 1993 and April 20, 1994
administrative law judge decisions and in November 1995 the Commission affirmed
these decisions. All remaining cases, including the citations involving OPCo's
mines, have been stayed.
On September 30, 1994, Federal EPA served APCo and Global Power Company, an
independent contractor retained by APCo, with a complaint alleging violations
of the Clean Air Act. The complaint is based on alleged violations of the
National Emission Standard for Asbestos related to an asbestos abatement
project at APCo's Kanawha River Plant. The complaint seeks a civil
administrative penalty of $167,500. On October 27, 1994, APCo and Global
jointly filed an answer to this complaint and requested both a formal hearing
and informal settlement conference.
On February 28, 1994, Ormet Corporation filed a complaint in the U.S.
District Court, Northern District of West Virginia, against AEP, OPCo, the
Service Corporation and two of its employees, Federal EPA and the Administrator
of Federal EPA. Ormet is the operator of a major aluminum reduction plant in
Ohio and is a customer of OPCo. See CERTAIN INDUSTRIAL CUSTOMERS. Pursuant to
the Clean Air Act Amendments of 1990, OPCo received SO{2} Allowances for its
Kammer Plant. See ENVIRONMENTAL AND OTHER MATTERS. Ormet's complaint sought a
declaration that it is the owner of approximately 89% of the Phase I and Phase
II SO{2} allowances issued for use by the Kammer Plant. On March 31, 1995, the
District Court issued an opinion and order dismissing Ormet's claims based on a
lack of jurisdiction. On April 11, 1995, Ormet appealed the District Court's
decision to the U.S. Court of Appeals for the Fourth Circuit with respect to
the Service Corporation and OPCo only.
See Item 1 for- --------------------------------------------------------------------------------
For a discussion of certain environmental and rate matters.
MEIGS MINE: On July 11, 1993, water from an adjoining sealed and abandoned
mine owned by Southern Ohio Coal Company (SOCCo), a mining subsidiary of OPCo,
entered Meigs 31 mine, one of two mines currently being operated by SOCCo.
Ohio EPA approved a plan to pump water from the mine to certain Ohio River
tributaries under stringent conditions for biological and water quality
monitoring and restoring the streams after pumping. On July 30, pumping
commenced in accordance with the Ohio EPA approved plan and, after all water
was removed from the mine, the mine was returned to service in February 1994.
In April 1994, the U.S. Court of Appeals for the Sixth Circuit reversed the
judgement of the U.S. District Court for the Southern District of Ohio which
had granted a preliminary injunction to SOCCo preventing Federal EPA and the
Federal Office of Surface Mining, Reclamation and Enforcement (OSM) from
interfering with the removal of water from SOCCo's Meigs 31 mine.
The West Virginia Division of Environmental Protection (West Virginia DEP)
had proposed fining SOCCo $1,800,000 for violations of West Virginia Water
Quality Standards and permitting requirements alleged to have resulted from the
release of mine water into the Ohio River. As a result of the West Virginia
DEP proposing to fine SOCCo, SOCCo filed an action on June 1, 1994 in the U.S.
District Court for the Southern District of West Virginia seeking a
determination that the state of West Virginia has no jurisdiction to impose
penalties with respectmaterial legal proceedings, see Note 9 to the
mine water discharges. SOCCoconsolidated financial statements, entitled Commitments and the West
Virginia DEP have entered into a settlement agreement dated May 8, 1995, under
which the West Virginia DEP has released SOCCo from any claims which it may
have had and SOCCo has made a donation of $260,000 to the Water Quality
Management Fund of the West Virginia DEP.
SOCCo has entered into a consent decree and settlement agreement with
Federal EPA and OSM which was lodged with the U.S. District Court, Southern
District of Ohio, on January 30, 1996 and noticedContingencies,
incorporated by reference in the FEDERAL REGISTER on
February 15, 1996. The decree and settlement agreement resolve all disputes
between SOCCo and Federal EPA and OSM over the legality of the removal of water
from SOCCo's Meigs 31 mine. Under the terms of the settlement agreement, SOCCo
is responsible for the return of pre-pumping biological conditions in the
affected streams if those conditions do not return to pre-pumping status under
the plan previously agreed to by SOCCo and the Ohio EPA as a condition to the
pumping. SOCCo will pay to the U.S. $1,900,000 as compensation for natural
resources alleged to have been affected by the mine dewatering. The $1,900,000
will be used to fund Leading Creek watershed enhancement projects in three Ohio
counties. Under the settlement agreement, SOCCo is also required to pay to the
U.S. $242,200 as reimbursement for costs incurred in monitoring and assessing
the effects of its discharge of water. SOCCo will also pay to the U.S. a civil
penalty of $300,000. Of this amount, $200,000 is designated as settlement for
claims under the Clean Water Act, and $100,000 is designated as settlement for
claims under the Surface Mining Control and Reclamation Act. Finally, SOCCo
will provide $100,000 to the State of West Virginia for work in the Ohio
River for the benefit of Leading Creek on acceptance by the U.S. Fish and
Wildlife Service of an acceptable plan from the State.
KAMMER PLANT: In August 1994, Federal EPA issued a Notice of Violation (NOV)
to OPCo alleging that its Kammer Plant has been operating in violation of
applicable federally enforceable air pollution control requirements for sulfur
dioxide since at least January 1, 1989. The Clean Air Act provides that
Federal EPA may commence a civil action for injunctive relief and/or civil
penalties of up to $25,000 per day for each day of violation. On November 15,
1994, a civil complaint containing the allegations included in the NOV was
filed by Federal EPA against OPCo in the U.S. District Court, Northern District
of West Virginia. A Partial Consent Decree has been entered by the court,
extending until May 15, 1996 the date by which OPCo would need to reduce the
sulfur content of the fuel supply for Kammer. Negotiations are in an advanced
stage to extend the final compliance date beyond May 15, 1996 and to resolve
the penalty issues raised by the civil complaint. It is not anticipated that
the ultimate resolution of this matter will have a material adverse impact on
results of operations.Item 8.
29
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- --------------------------------------------------------------------------------
AEP, APCO, I&M, OPCO, SWEPCO AND OPCO.TCC. None.
AEGCO, CSPCO, KPCO, PSO AND KEPCO.TNC. Omitted pursuant to Instruction J(2)I(2)(c).
---------------------
EXECUTIVE OFFICERS OF THE REGISTRANTS
AEPAEP. The following persons are, or may be deemed, executive officers of
AEP. Their ages are given as of March 15, 1996.
NAME AGE OFFICE (a)
E. Linn Draper, Jr. 541, 2003.
NAME AGE OFFICE (A)
- ---- --- ----------
E. Linn Draper, Jr. ........... 61 Chairman of the Board, President and Chief Executive Officer
of AEP and of the Service Corporation
Thomas V. Shockley, III........ 57 Vice Chairman of AEP and Vice Chairman and Chief Operating
Officer of the Service Corporation
Henry W. Fayne................. 56 Vice President of AEP, Executive Vice President of the
Service Corporation
Thomas M. Hagan................ 58 Executive Vice President-Shared Services of the Service
Corporation
Holly K. Koeppel............... 44 Executive Vice President of the Service Corporation
Robert P. Powers............... 49 Executive Vice President-Nuclear Generation and Technical
Services of the Service Corporation
Susan Tomasky.................. 49 Vice President of AEP, Executive Vice President-Policy,
Finance and Strategic Planning of the Service Corporation
Peter J. DeMaria 61 Controller of AEP; Executive Vice President-
Administration
- ---------------
(a) Dr. Draper and Chief Accounting Officer of the
Service Corporation
William J. Lhota 56 Executive Vice President of the Service Corporation
Gerald P. Maloney 63 Vice President and Secretary of AEP; Executive Vice
President-Chief Financial Officer of the Service
Corporation
James J. Markowsky 51 Executive Vice President-Power Generation of the
Service Corporation
(a)All of the executive officers listed aboveMr. Fayne have been employed by the Service Corporation or
System companies in various capacities (AEP, as such, has no employees) duringfor
the past five years, except E. Linn Draper, Jr. whoyears. Prior to joining the Service Corporation in July 1998
as Senior Vice President-Generation, Mr. Powers was ChairmanVice President of
Pacific Gas & Electric and plant manager of its Diablo Canyon Nuclear
Generating Station (1996-1998). Prior to joining the Service Corporation in
July 1998 as Senior Vice President, Ms. Tomasky was a partner with the law
firm of Hogan & Hartson (August 1997-July 1998) and General Counsel of the
Board,Federal Energy Regulatory Commission (May 1993-August 1997). Prior to
joining the Service Corporation in June 2000 as Senior Vice President-
Governmental Affairs, Mr. Hagan was Senior Vice President-External Affairs
of CSW. Prior to joining the Service Corporation in July 2000 as Vice
President-New Ventures, Ms. Koeppel was Regional Vice President of
Asia-Pacific Operations for Consolidated Natural Gas International
(1996-2000). Messrs. Hagan and Powers, Ms. Koeppel and Ms. Tomasky became
executive officers of AEP effective with their promotions to Executive Vice
President on September 9, 2002, October 24, 2001, November 18, 2002 and
January 26, 2000, respectively. Prior to joining the Service Corporation in
his current position upon the merger with CSW, Mr. Shockley was President
and Chief ExecutiveOperating Officer of Gulf States
Utilities Company from 1987 until 1992 when he joined AEPCSW (1997-2000) and the Service
Corporation.Executive Vice President
of CSW (1990-1997). All of the above officers are appointed annually for a
one-
yearone-year term by the board of directors of AEP, the board of directors of
the Service Corporation, or both, as the case may be.
APCO, I&M, OPCO, SWEPCO AND TCC. The names of the executive officers of
APCo, I&M, OPCo, SWEPCo and TCC, the positions they hold with APCo,these companies,
their ages as of March 15, 1996,1, 2003, and a brief account of their business experience
during the past five years appearsappear below. The directors and executive officers of
APCo, I&M, OPCo, SWEPCo and TCC are elected annually to serve a one-year term.
30
NAME AGE POSITION (a)(A)(B) PERIOD
- ---- --- --------------- ------
E. Linn Draper, Jr. 54........... 61 Director of SWEPCo and TCC 2000-Present
Chairman of the Board and Chief Executive Officer
of SWEPCo and TCC 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
Vice President 1992-1993
Chairman of the Board, President and Chief
Executive Officer of AEP and the Service Corporation 1993-Present
Thomas V. Shockley, III........ 57 Director and Vice President of AEP 1992-1993
PresidentAPCo, I&M, OPCo,
SWEPCo and TCC 2000-Present
Chief Operating Officer of the Service Corporation 1992-19932001-Present
Vice Chairman of the Board, PresidentAEP and Chief Executive
Officer of Gulf States Utilities Company 1987-1992
Peter J. DeMaria 61 Director 1988-Present
Vice President 1991-Present
Controller 1995-Present
Treasurer 1978-1995
Controller of AEP 1995-Present
Treasurer of AEP 1978-1995
Executive Vice President-Administration and Chief
Accounting Officer of the Service Corporation 1984-Present
Treasurer of the Service Corporation 1989-1990
William J. Lhota 56 Director 1990-Present2000-Present
President and Chief Operating Officer 1996-Presentof CSW 1997-2000
Executive Vice President 1989-1995of CSW 1990-1997
Henry W. Fayne................. 56 President of APCo, I&M, OPCo, SWEPCo and TCC 2001-Present
Director of SWEPCo and TCC 2000-Present
Director of APCo 1995-Present
Director of OPCo 1993-Present
Director of I&M 1998-Present
Vice President of SWEPCo and TCC 2000-2001
Vice President of APCo, I&M and OPCo 1998-2001
Vice President of AEP 1998-Present
Chief Financial Officer of AEP 1998-2001
Executive Vice President of the Service Corporation 1993-Present2001-Present
Executive Vice President-OperationsPresident-Finance and Analysis of
the Service Corporation 1989-1993
Gerald P. Maloney 632000-2001
Executive Vice President-Financial Services of the
Service Corporation 1998-2000
Senior Vice President-Corporate Planning & Budgeting
of the Service Corporation 1995-1998
Thomas M. Hagan................ 58 Director and Vice President 1970-Present
Vice President of AEP 1974-Present
Secretary of AEP 1994-PresentAPCo, I&M, OPCo,
SWEPCo and TCC 2002-Present
Executive Vice President-Chief Financial OfficerPresident-Shared Services of the
Service Corporation 1991-Present2002-Present
Senior Vice President-FinancePresident-Governmental Affairs of the
Service Corporation 1974-1990
James J. Markowsky 51 Director 1993-Present
Vice President 1995-Present
Executive Vice President-Power Generation of the
Service Corporation 1996-Present
Executive Vice President-Engineering and Construction
of the Service Corporation 1993-19962000-2002
Senior Vice President and Chief EngineerPresident-External Affairs of the
Service Corporation 1988-1993
(a) Positions are with APCo unless otherwise indicated.
OPCO
The names of the executive officers of OPCo, the positions they hold with
OPCo, their ages as of March 15, 1996, and a brief account of their business
experience during the past five years appear below. The directors and
executive officers of OPCo are elected annually to serve a one-year term.
NAME AGE POSITION (a) PERIOD
E. Linn Draper, Jr. 54 Director 1992-Present
Chairman of the Board and Chief Executive Officer 1993-Present
Vice President 1992-1993
Chairman of the Board, President and Chief Executive
Officer of AEP and the Service Corporation 1993-Present
President of AEP 1992-1993
President and Chief Operating Officer of the Service
Corporation 1992-1993
Chairman of the Board, President and Chief Executive
Officer of Gulf States Utilities Company 1987-1992
Peter J. DeMaria 61 Director 1978-Present
Vice President 1991-Present
Controller 1995-Present
Treasurer 1978-1995
Controller of AEP 1995-Present
Treasurer of AEP 1978-1995
Executive Vice President-Administration and Chief
Accounting Officer of the Service Corporation 1984-Present
Treasurer of the Service Corporation 1989-1990
William J. Lhota 56 Director 1989-Present
President and Chief Operating Officer 1996-Present
Vice President 1989-1995CSW 1996-2000
Holly K. Koeppel............... 44 Executive Vice President of the Service Corporation 1993-Present2002-Present
Vice President-New Ventures 2000-2002
Regional Vice President of Asia-Pacific Operations
for Consolidated Natural Gas International 1996-2000
31
NAME AGE POSITION (A)(B) PERIOD
- ---- --- --------------- ------
Robert P. Powers............... 49 Director and Vice President of APCo, I&M, OPCo,
SWEPCo and TCC 2001-Present
Director of I&M 2001-Present
Vice President of I&M 1998-Present
Executive Vice President-OperationsPresident- Generation 2003-Present
Executive Vice President-Nuclear Generation and
Technical Services of the Service Corporation 1989-1993
Gerald P. Maloney 63 Director 1973-Present2001-2003
Senior Vice President 1970-Present
Vice President of AEP 1974-Present
Secretary of AEP 1994-Present
Executive Vice President-Chief Financial OfficerPresident-Nuclear Operations of the
Service Corporation 1991-Present2000-2001
Senior Vice President-Finance of the Service
Corporation 1974-1990
James J. Markowsky 51 Director 1989-Present
Vice President 1995-Present
Executive Vice President-PowerPresident-Nuclear Generation of the
Service Corporation 1996-Present1998-2000
Vice President of Pacific Gas & Electric and Plant
Manager of its Diablo Canyon Nuclear Generating
Station 1996-1998
Susan Tomasky.................. 49 Director and Vice President of APCo, I&M, OPCo,
SWEPCo and TCC 2000-Present
Executive Vice President-EngineeringPresident-Policy, Finance and
ConstructionStrategic Planning of the Service Corporation 1993-19962001-Present
Executive Vice President-Legal, Policy and
Corporate Communications and General Counsel of
the Service Corporation 2000-2001
Senior Vice President and Chief EngineerGeneral Counsel of the
Service Corporation 1988-1993
(a) Positions are with OPCo unless otherwise indicated.
PART II
Item 5.MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
AEP. AEP Common Stock is traded principally on the New York Stock Exchange.
The following table sets forth for the calendar periods indicated the high and
low sales prices for the Common Stock as reported on the New York Stock
Exchange Compsite Tape and the amount of cash dividends paid per share of
Common Stock.
At December 31, 1995, AEP had approximately 170,980 shareholders of
record.
AEGCO, APCO, CSPCO, I&M, KEPCO AND OPCO. The information required by
this item is not applicable as the common stock of all these companies is
held solely by AEP.
PER SHARE
MARKET PRICE
QUARTER ENDED HIGH LOW DIVIDEND(1)
March 1994 $37-3/8 $29-7/8 $.60
June 1994 32-7/8 27-1/4 .60
September 1994 31-3/4 28 .60
December 1994 33-5/8 30-1/2 .60
March 1995 35-3/4 31-1/4 .60
June 1995 35-3/8 31-1/2 .60
September 1995 36-1/2 33-5/8 .60
December 1995 40-5/8 35-7/8 .60
(1)See Note 51998-2000
Hogan & Hartson (law firm) 1997-1998
General Counsel of the Notes to the Consolidated Financial Statements of
AEP for information regarding restrictions on payment of dividends.FERC 1993-1997
- ---------------
(a) Dr. Draper is a director of BCP Management, Inc., which is the general
partner of Borden Chemicals and Plastics L.P.
(b) Dr. Draper, Messrs. Fayne, Hagan, Powers and Shockley and Ms. Tomasky are
directors of AEGCo, CSPCo, KPCo, PSO and TNC. Dr. Draper and Mr. Shockley
are also directors of AEP.
PART II
- --------------------------------------------------------------------------------
Item 6. SELECTED FINANCIAL DATA
AEGCO. Omitted pursuant to Instruction J(2)(a).5. MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
- --------------------------------------------------------------------------------
AEP. The information required by this item is incorporated herein by
reference to the material under Common Stock and Dividend Information in the
2002 Annual Report.
AEGCO, APCO, CSPCO, I&M, KPCO, OPCO, PSO, SWEPCO, TCC AND TNC. 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 2002 and 2001 are
incorporated by reference to the material under Statement of Retained Earningsin
the 2002 Annual Reports.
Item 6. SELECTED CONSOLIDATED FINANCIAL DATA
in the- --------------------------------------------------------------------------------
AEGCO, CSPCO, KPCO, PSO AND TNC. Omitted pursuant to Instruction I(2)(a).
AEP, 1995 Annual Report (for the fiscal year ended December 31, 1995).
APCO.APCO, I&M, OPCO, SWEPCO AND TCC. The information required by this item
is incorporated herein by reference to the material under SELECTED CONSOLIDATED FINANCIAL DATASelected Consolidated
Financial Data in the APCo 19952002 Annual Report (for the fiscal year ended December 31, 1995).
CSPCO.Reports.
32
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
- --------------------------------------------------------------------------------
AEGCO, CSPCO, KPCO, PSO AND TNC. Omitted pursuant to Instruction J(2)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 2002 Annual Reports.
AEP, APCO, I&M.&M, OPCO, SWEPCO AND TCC. The information required by this item
is incorporated herein by reference to the material under SELECTED CONSOLIDATED FINANCIAL DATAManagement's
Discussion and Analysis of Results of Operations and Management's Discussion and
Analysis of Financial Condition, Contingencies and Other Matters in the 2002
Annual Reports.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
- --------------------------------------------------------------------------------
AEGCO, AEP, APCO, CSPCO, I&M, 1995 Annual Report (for the fiscal year ended December 31, 1995).
KEPCO. Omitted pursuant to Instruction J(2)(a).
OPCO.KPCO, OPCO, PSO, SWEPCO, TCC AND TNC. The
information required by this item is incorporated herein by reference to the
material under SELECTED CONSOLIDATED FINANCIAL DATAManagement's Discussion and Analysis of Financial Condition,
Contingencies and Other Matters in the OPCo 19952002 Annual Report (for the fiscal year ended December 31, 1995).Reports.
Item 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
OPERATIONS AND8. FINANCIAL CONDITION
AEGCO. Omitted pursuant to Instruction J(2)(a). Management's narrative
analysis of the results of operations and other information required by
Instruction J(2)(a) is incorporated herein by reference to the material under
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS in the AEGCo 1995
Annual Report (for the fiscal year ended December 31, 1995).
AEP. The information required by this item is incorporated herein by
reference to the material under MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION in the AEP 1995 Annual Report
(for the fiscal year ended December 31, 1995).
APCO. The information required by this item is incorporated herein by
reference to the material under MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION in the APCo 1995 Annual Report
(for the fiscal year ended December 31, 1995).
CSPCO. Omitted pursuant to Instruction J(2)(a). Management's narrative
analysis of the results of operations and other information required by
Instruction J(2)(a) is incorporated herein by reference to the material under
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS in the CSPCo 1995
Annual Report (for the fiscal year ended December 31, 1995).
I&M. The information required by this item is incorporated herein by
reference to the material under MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION in the I&M 1995 Annual Report
(for the fiscal year ended December 31, 1995).
KEPCO. Omitted pursuant to Instruction J(2)(a). Management's narrative
analysis of the results of operations and other information required by
Instruction J(2)(a) is incorporated herein by reference to the material under
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS in the KEPCo 1995
Annual Report (for the fiscal year ended December 31, 1995).
OPCO. The information required by this item is incorporated herein by
reference to the material under MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION in the OPCo 1995 Annual Report
(for the fiscal year ended December 31, 1995).
Item 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
AEGCO.- --------------------------------------------------------------------------------
AEGCO, AEP, APCO, CSPCO, I&M, KPCO, OPCO, PSO, SWEPCO, TCC AND TNC. The
information required by this item is incorporated herein by reference to the
financial statements and supplementary datafinancial statement schedules described under Item 14 herein.
AEP. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
APCO. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
CSPCO. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
I&M. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
KEPCO. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
OPCO. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 1415
herein.
Item 9.CHANGES9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
- --------------------------------------------------------------------------------
AEGCO, AEP, APCO, CSPCO, I&M, KEPCOKPCO, OPCO, PSO, SWEPCO, TCC AND OPCO.TNC. None.
PART III
- --------------------------------------------------------------------------------
Item 10.DIRECTORS10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
AEGCO.- --------------------------------------------------------------------------------
AEGCO, CSPCO, KPCO, PSO AND TNC. Omitted pursuant to Instruction J(2)I(2)(c).
AEP. The information required by this item is incorporated herein by
reference to the material under NOMINEES FOR DIRECTORNominees for Director and SHARE OWNERSHIP OF
DIRECTORS AND EXECUTIVE OFFICERSSection 16(a)
Beneficial Ownership Reporting Compliance of the definitive proxy statement of
AEP dated March 9, 1996, for the 19962003 annual meeting of shareholders.shareholders, to be filed within 120 days
after December 31, 2002. Reference also is made to the information under the
caption EXECUTIVE OFFICERS OF THE
REGISTRANTSExecutive Officers of the Registrants in Part I of this report.
APCO.APCO AND OPCO. The information required by this item is incorporated herein
by reference to the material under ELECTION OF DIRECTORSElection of Directors of the definitive
information statement of APCoeach company for the 19962003 annual meeting of
stockholders, to be filed within 120 days after December 31, 1995.2002. Reference
also is made to the information under the caption EXECUTIVE OFFICERS OF THE REGISTRANTSExecutive Officers of the
Registrants in Part I of this report.
CSPCO. Omitted pursuantSWEPCO AND TCC. The information required by this item is incorporated
herein by reference to Instruction J(2)(c).the material under Election of Directors of the
definitive information statement of APCo for the 2003 annual meeting of
stockholders, to be filed within 120 days after December 31, 2002. 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 15, 1996,12, 2003, and a brief
account of their business experience during the past five years appear below.
The directorsbelow and
executive officersunder the caption Executive Officers of the Registrants in Part I&M are elected annually to serve a
one-year term. of this
report.
33
NAME AGE POSITION (A)(B)(C) PERIOD
- ---- --- ------------ ------
E. Linn Draper, Jr. 54K. G. Boyd..................... 51 Director 1992-Present
Chairman of the Board and Chief Executive
Officer 1993-Present1997-Present
Vice President 1992-1993
Chairman(Appointed) -- Fort Wayne Region
Distribution Operations 2000-Present
Indiana Region Manager 1997-2000
John E. Ehler.................. 46 Director 2001-Present
Manager of the Board, PresidentDistribution Systems-Fort Wayne District 2000-Present
Region Operations Manager 1997-2000
David L. Lahrman............... 51 Director and Chief
Executive Officer of AEP andManager, Region Support 2001-Present
Fort Wayne District Manager 1997-2001
Marc E. Lewis.................. 48 Director 2001-Present
Assistant General Counsel of the Service
Corporation 1993-Present
President of AEP 1992-1993
President and Chief Operating Officer2001-Present
Senior Counsel of the Service Corporation 1992-1993
Chairman of the Board, President and Chief
Executive Officer of Gulf States Utilities
Company 1987-1992
Peter J. DeMaria 61 Director 1992-Present
Vice President 1991-Present
Controller 1995-Present
Treasurer 1978-1995
Controller of AEP 1995-Present
Treasurer of AEP 1978-1995
Executive Vice President-Administration and
Chief Accounting Officer2000-2001
Senior Attorney of the Service Corporation 1984-Present
Treasurer of the Service Corporation 1989-1990
William N. D'Onofrio 481994-2000
Susanne M. Moorman............. 53 Director 1984-Present
Vice President 1984-1995
Director-Regions of the Service Corporation 1996-Present
William J. Lhota 56 Director 1989-Present
President and Chief Operating Officer 1996-Present
Vice President 1989-1995
Executive Vice President of the Service
Corporation 1993-Present
Executive Vice President-Operations of the
Service Corporation 1989-1993
Gerald P. Maloney 63 Director 1978-Present
Vice President 1970-Present
Vice President of AEP 1974-Present
Secretary of AEP 1994-Present
Executive Vice President-Chief Financial
Officer of the Service Corporation 1991-Present
Senior Vice President-Finance of the Service
Corporation 1974-1990
James J. Markowsky 51 Director 1995-Present
Vice President 1993-Present
Executive Vice President-Power Generation
of the Service Corporation 1996-Present
Executive Vice President-Engineering &
Construction of the Service Corporation 1993-1996
Senior Vice President and Chief Engineer
of the Service Corporation 1988-1993
A. H. Potter 48 Director 1994-Present
Transmission and Distribution Director 1987-Present
D. M. Trenary 59 Director 1994-Present
Indiana RegionGeneral Manager, 1994-Present
DivisionCommunity Services 2000-Present
Manager, 1989-1994
W. E. Walters 48 Director 1991-Present
Michiana Region Manager 1994-Present
Executive Assistant to President 1987-1994
C.Customer Services Operations 1997-2000
John R. Boyle, III 48Sampson................ 50 Director and Vice President 1996-Present1999-Present
Indiana State President and Chief Operating Officer of KEPCo1990-1995
G. A. Clark 44 Director 1995-Present
Governmental Affairs2000-Present
Indiana & Michigan State President 1999-2000
Site Vice President, Cook Nuclear Plant 1998-1999
Plant Manager, 1996-Present
General Counsel 1994-1995
General Attorney 1991-1993Cook Nuclear Plant 1996-1998
D. B. Synowiec 52Synowiec................. 59 Director 1995-Present
Plant Manager, 1990-Present
J. H. Vipperman 55 Director and Vice President 1996-Present
Executive Vice President- Energy Delivery
of the Service Corporation 1996-Present
President and Chief Operating Officer of APCo 1990-1995Rockport Plant 1990-Present
- ---------------
(a) Positions are with I&M unless otherwise indicated.
(b) Dr. Draper is a director of VECTRA Technologies, Inc. and Mr. Lhota is a
director of Huntington Bancshares Incorporated.
(c) Drs. Draper and Markowsky and Messrs. DeMaria, Lhota and Maloney are
directors of AEGCo, APCo, CSPCo, KEPCo and OPCo. Dr. Draper and Messrs.
DeMaria and Maloney are also directors of AEP. Mr. Vipperman is a director
of APCo, CSPCo, KEPCo and OPCo.
KEPCo. Omitted pursuant to Instruction J(2)(c).
OPCo. The information required by this item is incorporated herein by
reference to the material under the heading Election of Directors of the
definitive information statement of OPCo for the 1996 annual meeting of
shareholders, to be filed within 120 days after December 31, 1995.
Reference also is made to the information under the caption EXECUTIVE
OFFICERS OF THE REGISTRANTS in Part I of this report.
Item 11. EXECUTIVE COMPENSATION
AEGCO. Omitted pursuant to Instruction J(2)(c).
AEP. The information required by this item is incorporated herein by
reference to the material under COMPENSATION OF DIRECTORS, EXECUTIVE COMPENSATION
- --------------------------------------------------------------------------------
AEGCO, CSPCO, KPCO, PSO AND TNC. 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, dated March 9, 1996, for the 1996 annual meeting of shareholders.
APCO. The information required by this item is incorporated herein by
reference to the material under EXECUTIVE COMPENSATION of the definitive
information statement of APCo for the 1996 annual meeting of stockholders, to
be filed within 120 days after December 31, 1995.
CSPCO. Omitted pursuant to Instruction J(2)(c).
KEPCO. Omitted pursuant to Instruction J(2)(c).
OPCO. The information required by this item is incorporated herein by
reference to the material under EXECUTIVE COMPENSATION of the definitive
information statement of OPCo for the 1996 annual meeting of shareholders, to
be filed within 120 days after December 31, 1995.
I&M. Certain executive officers of I&M are employees of the Service
Corporation. The salaries of these executive officers are paid by the
Service Corporation and a portion of their salaries has been allocated and
charged to I&M. The following table shows for 1995, 1994 and 1993 the
compensation earned from all AEP System companies by the chief executive
officer and four other most highly compensated executive officers (as
defined by regulations of the SEC) of I&M at December 31, 1995.
SUMMARY COMPENSATION TABLE
LONG-TERM
ANNUAL COMPENSATION COMPENSATION All Other
Salary Bonus PAYOUTS Compensation
NAME AND PRINCIPAL POSITION YEAR ($) ($)(1) LTIP PAYOUTS($)(1) ($)(2)
E. LINN DRAPER, JR. - chairman of the board, 1995 685,000 236,325 334,851 30,790
president and chief executive officer of the 1994 620,000 209,436 137,362 29,385
Company and the Service Corporation; chairman 1993 538,333 148,742 18,180
and chief executive officer of other subsidiaries
PETER J. DEMARIA - Controller and director of the 1995 330,000 113,850 143,829 20,050
Company; executive vice president-administration 1994 305,000 103,029 59,032 18,750
and chief accounting officer and director of the 1993 280,000 77,364 17,811
Service Corporation; vice president, controller
and director of other subsidiaries
G. P. MALONEY - Vice president, secretary and 1995 330,000 113,850 141,582 20,060
director of the Company; executive vice president 1994 300,000 101,340 58,094 19,745
- chief financial officer and director of the 1993 269,000 74,325 18,000
Service Corporation; vice president and director
of other subsidiaries
WILLIAM J. LHOTA - Executive vice president and 1995 300,000 103,500 132,592 19,140
director of the Service Corporation; president, 1994 280,000 94,584 54,409 19,185
chief operating officer and director of other 1993 249,000 68,799 17,160
subsidiaries
JAMES J. MARKOWSKY - Executive vice president 1995 285,000 98,325 126,599 17,515
- power generation and director of the Service 1994 267,000 90,193 51,930 14,755
Corporation; vice president and director of 1993 247,000 65,259 11,165
other subsidiaries
(1)Amounts in the "Bonus" column reflect payments under the Management
Incentive Compensation Plan for performance measured for each of the years
ended December 31, 1993, 1994 and 1995. Payments are made in March of the
subsequent year. Amounts for 1995 are estimates but should not change
significantly.
Amounts in the "Long-Term Compensation" column reflect performance share
units earned under the Performance Share Incentive Plan (which became
effective January 1, 1994) for the one-year and two-year transition
performance periods ending December 31, 1994 and 1995, respectively. For
1995, their value was calculated by multiplying the $40.50 closing price of
AEP's Common Stock as reported on the New York Stock Exchange on December
29, 1995, the last trading day of fiscal year 1995, by the number of units
earned.
See below under "Long-Term Incentive Plans - Awards in 1995" and pages 13
and 14 for additional information.
(2)For 1995, includes (i) employer matching contributions under the AEP System
Employees Savings Plan: $4,500 for each of the named executive officers;
(ii) employer matching contributions under the AEP System Supplemental
Savings Plan (which became effective January 1, 1994), a non-qualified plan
designed to supplement the AEP Savings Plan: Dr. Draper, $16,050;
Mr. DeMaria, $5,400; Mr. Maloney, $5,400; Mr. Lhota, $4,500; and
Dr. Markowsky, $4,050; and (iii) subsidiary companies director fees:
Dr. Draper, $10,240; Mr. DeMaria, $10,150; Mr. Maloney, $10,160; Mr. Lhota,
$10,140; and Dr. Markowsky, $8,965.
LONG-TERM INCENTIVE PLANS - AWARDS IN 1995
Each of the awards set forth below constitutes a grant of performance share
units, which represent units equivalent to shares of Common Stock, pursuant to
the Company's Performance Share Incentive Plan. Since it is not possible to
predict future dividends and the price of AEP Common Stock, credits of
performance share units in amounts equal to the dividends that would have been
paid if the performance share units were granted in the form of shares of
Common Stock are not included in the table.
The ability to earn performance share units is tied to achieving specified
levels of total shareholder return ("TSR") relative to the S&P Electric Utility
Index. Notwithstanding AEP's TSR ranking, no performance share units are
earned unless AEP shareholders realize a positive TSR over the relevant
three-year performance period. The Human Resources Committee may, at its
discretion, reduce the number of performance share units otherwise earned.
In accordance with the performance goals established for the periods set
forth below, the threshold, target and maximum awards are equal to 25%,
100% and 200%, respectively, of the performance share units held. No
payment will be made for performance below the threshold.
Payments of earned awards are deferred in the form of restricted stock units
(equivalent to shares of AEP Common Stock) until the officer has met the
equivalent stock ownership target discussed in the Human Resources Committee
Report. Once officers meet and maintain their respective targets, they may
elect either to continue to defer or to receive further earned awards in cash
and/or Common Stock.
ESTIMATED FUTURE PAYOUTS OF
PERFORMANCE PERFORMANCE SHARE UNITS UNDER
NUMBER OF PERIOD UNTIL NON-STOCK PRICE-BASED PLAN
Performance Maturation Threshold Target Maximum
NAME SHARE UNITS OR PAYOUT (#) (#) (#)
E. L. Draper, Jr. 8,302 1995-1997 2,075 8,302 16,604
P. J. DeMaria 3,499 1995-1997 875 3,499 6,998
G. P. Maloney 3,499 1995-1997 875 3,499 6,998
W. J. Lhota 3,181 1995-1997 795 3,181 6,362
J. J. Markowsky 3,022 1995-1997 755 3,022 6,044
RETIREMENT BENEFITS
The American Electric Power System Retirement Plan provides pensions for all
employees of AEP System companies (except for employees coveredthe 2003 annual meeting of shareholders to be filed
within 120 days after December 31, 2002.
APCO AND OPCO. The information required by certain
collective bargaining agreements), includingthis item is incorporated herein
by reference to the executive officersmaterial under Executive Compensation of the Company. The Retirement Plan is a noncontributory defined benefit plan.
The following table shows the approximate annual annuities under the
Retirement Plan that would be payable to employees in certain higher salary
classifications, assuming retirement at age 65 after various periodsdefinitive
information statement of service.
PENSION PLAN TABLE
HIGHEST AVERAGE YEARS OF ACCREDITED SERVICE
ANNUAL EARNINGS 15 20 25 30 35 40 45
$ 300,000 $ 69,930 $ 93,240 $116,550 $139,860 $163,170 $183,120 $203,070
400,000 93,930 125,240 156,550 187,860 219,170 245,770 272,370
500,000 117,930 157,240 196,550 235,860 275,170 308,420 341,670
700,000 165,930 221,240 276,550 331,860 387,170 433,720 480,270
900,000 213,930 285,240 356,550 427,860 499,170 559,020 618,870
1,100,000 261,930 349,240 436,550 523,860 611,170 684,320 757,470
The amounts shown in the table are the straight life annuities payable under
the Retirement Plan without reductioneach company for the joint and survivor annuity.
Retirement benefits listed in2003 annual meeting of
stockholders, to be filed within 120 days after December 31, 2002.
I&M, SWEPCO AND TCC. The information required by this item is incorporated
herein by reference to the table are not subject to any deduction for
Social Security or other offset amounts. The retirement annuity is reduced 3%
per year inmaterial under Executive Compensationof the
casedefinitive information statement of retirement between ages 60 and 62 and further reduced
6% per year in the case of retirement between ages 55 and 60. If an employee
retires after age 62, there is no reduction in the retirement annuity.
The Company maintains a supplemental retirement plan which providesAPCo for the payment2003 annual meeting of
benefits that are not payable under the Retirement Plan due
primarilystockholders, to limitations imposed by Federal tax law on benefits paid by
qualified plans. The table includes supplemental retirement benefits.
Compensation upon which retirement benefits are based, for the executive
officers named in the Summary Compensation Table above, consists of the average
of the 36 consecutive months of the officer's highest aggregate salary and
Management Incentive Compensation Plan awards, shown in the "Salary" and
"Bonus" columns, respectively, of the Summary Compensation Table, out of the
officer's most recent 10 years of service. As ofbe filed within 120 days after December 31, 1995, the number
of full years of service applicable for retirement benefit calculation purposes
for such officers were as follows: Dr. Draper, three years; Mr. DeMaria,
36 years; Mr. Maloney, 40 years; Mr. Lhota, 31 years; and Dr. Markowsky,
24 years.
Dr. Draper's employment agreement described below provides him with a
supplemental retirement annuity that credits him with 24 years of service in
addition to his years of service credited under the Retirement Plan less his
actual pension entitlement under the Retirement Plan and any pension
entitlement from the Gulf States Utilities Company Trusteed Retirement Plan, a
plan sponsored by his prior employer.
The Company will pay supplemental retirement benefits to 19 AEP System
employees (including Messrs. DeMaria, Maloney and Lhota and Dr. Markowsky)
whose pensions may be adversely affected by amendments to the Retirement Plan
made as a result of the Tax Reform Act of 1986. Such payments, if any, will be
equal to any reduction occurring because of such amendments. Assuming
retirement in 1996 of the executive officers named in the Summary
Compensation Table, only Mr. Maloney would be affected and his annual
supplemental benefit would be $972.
The Company made available a voluntary deferred-compensation program in 1982
and 1986, which permitted certain members of AEP System management to defer
receipt of a portion of their salaries. Under this program, a participant was
able to defer up to 10% or 15% annually (depending on the terms of the program
offered), over a four-year period, of his or her salary, and receive
supplemental retirement or survivor benefit payments over a 15-year period.
The amount of supplemental retirement payments received is dependent upon the
amount deferred, age at the time the deferral election was made, and number of
years until the participant retires. The following table sets forth, for the
executive officers named in the Summary Compensation Table, the amounts of
annual deferrals and, assuming retirement at age 65, annual supplemental
retirement payments under the 1982 and 1986 programs.
1982 PROGRAM 1986 PROGRAM
Annual Amount of Annual Amount of
Annual Supplemental Annual Supplemental
Amount Retirement Amount Retirement
Deferred Payment Deferred Payment
NAME (4-YEAR PERIOD) (15-YEAR PERIOD) (4-YEAR PERIOD) (15-YEAR PERIOD)
P. J. DeMaria $10,000 $52,000 $13,000 $53,300
G. P. Maloney 15,000 67,500 16,000 56,400
EMPLOYMENT AGREEMENT
Dr. Draper has a contract with the Company and AEP Service Corporation which
provides for his employment for an initial term from no later than March 15,
1992 until March 15, 1997. Dr. Draper commenced his employment with the
Company and AEP Service Corporation on March 1, 1992. The Company or AEP
Service Corporation may terminate the contract at any time and, if this is done
for reasons other than cause and other than as a result of Dr. Draper's death
or permanent disability, AEP Service Corporation must pay Dr. Draper's then
base salary through March 15, 1997, less any amounts received by Dr. Draper
from other employment.
Directors of I&M receive a fee of $100 for each meeting of the Board of
Directors attended in addition to their salaries.
The AEP System is an integrated electric utility system and, as a result,
the member companies of the AEP System have contractual, financial and other
business relationships with the other member companies, such as participation
in the AEP System savings and retirement plans and tax returns, sales of
electricity, transportation and handling of fuel, sales or rentals of property
and interest or dividend payments on the securities held by the companies'
respective parents.
2002.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AEGCO.AND
RELATED STOCKHOLDER MATTERS
- --------------------------------------------------------------------------------
AEGCO, CSPCO, KPCO, PSO AND TNC. Omitted pursuant to Instruction J(2)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 dated March 9, 1996, for the 19962003 annual meeting of
shareholders.
APCO.shareholders to be filed within 120 days after December 31, 2002.
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 statementstate-
34
ment of APCoeach company for the 19952003 annual meeting of stockholders, to be filed
within 120 days after December 31, 1995.
CSPCO. Omitted pursuant to Instruction J(2)(c).2002.
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.
SWEPCO AND TCC. 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 2003
annual meeting of stockholders, to be filed within 120 days after December 31,
2002.
The table below shows the number of shares of AEP Common Stock and
stock-
basedstock-based units that were beneficially owned, directly or indirectly, as of
January 1, 1996,2003, by each director and nominee of I&M and each of the executive
officers of I&M named in the summary compensation table, and by all directors
and executive officers of I&M as a group. It is based on information provided to
I&M by such persons. No such person owns any shares of any series of the
Cumulative Preferred Stock of I&M. Unless otherwise noted, each person has sole
voting power and investment power over the number of shares of AEP Common Stock
and stock-based units set forth opposite his or her name. Fractions of shares
and units have been rounded to the nearest whole number.
STOCK
NAME SHARES UNITS(a)(A) UNITS (B) TOTAL
- ---- ---------- --------- ---------
Coulter R. Boyle, III 3,470(b) 629 4,099
Gregory A. Clark 833(b) 327 1,160
Peter J. DeMaria 7,356(b)(c)(d)(e)(f) 5,391 12,747
William N. D'Onofrio 4,154(b)(e) 492 4,646Karl G. Boyd................................................ 10,675 607 11,282
E. Linn Draper, Jr. 6,119(b)........................................ 472,034(c) 117,803 589,837
John E. Ehler............................................... 11 -- 11
Henry W. Fayne.............................................. 139,787(d) 12,362 152,149
Thomas M. Hagan............................................. 54,392 140 54,532
David L. Lahrman............................................ 430 -- 430
Marc E. Lewis............................................... 3,290 -- 3,290
Susanne M. Moorman.......................................... 908 -- 908
Robert P. Powers............................................ 65,862 1,293 67,155
John R. Sampson............................................. 10,643 173 10,816
Thomas V. Shockley, III..................................... 211,067(d)(e) 11,984 18,103
William J. Lhota 13,064(b)(d)(e) 4,944 18,008
Gerald P. Maloney 5,227(b)(d)(e) 5,306 10,533
James J. Markowsky 6,631(b)(f) 4,714 11,345
Albert H. Potter 3,084(b)(e) - 3,084-- 211,067
David B. Synowiec 2,214(b) 398 2,612
Dale M. Trenary 64(b) 412 476
Joseph H. Vipperman 5,092(b)(e) 3,365 8,457
William E. Walters 4,738(b) 278 5,016Synowiec........................................... 7,645 182 7,827
Susan Tomasky............................................... 134,449(d) 6,126 140,575
All Directors and Executive Officers 147,277(d)(g) 38,240 185,517Officers........................ 1,196,424(d)(f) 138,686 1,335,110
- ---------------
(a)This column includes amounts deferred in stock units and held under the
Management Incentive Compensation Plan and Performance Share Incentive Plan.
(b)Includes shares and share equivalents held in the following plansAEP Retirement Savings Plan in the
amounts listed below:
AEP EMPLOYEE STOCK AEP PERFORMANCE AEP EMPLOYEESRETIREMENT SAVINGS
OWNERSHIP PLAN (SHARES) SHARE INCENTIVE PLAN (SHARES)NAME PLAN (SHARE EQUIVALENTS)
---- ------------------------
Mr. Boyd.......................... 675
Dr. Draper........................ 4,659
Mr. Ehler......................... 11
Mr. Fayne......................... 5,804
Mr. Hagan......................... 2,515
Mr. Lahrman....................... 430
Mr. Lewis......................... 1,207
AEP RETIREMENT SAVINGS
NAME PLAN (SHARE EQUIVALENTS)
---- ------------------------
Ms. Moorman....................... 908
Mr. Boyle 47 316 3,107Powers........................ 596
Mr. Clark 8 - 825Sampson....................... 643
Mr. DeMaria 83 944 2,705Shockley...................... 7,104
Mr. D'Onofrio 59 - 3,595
Dr. Draper - 2,196 1,958
Mr. Lhota 60 812 10,824
Mr. Maloney 85 867 2,775
Dr. Markowsky 66 830 5,718
Mr. Potter 41 - 3,029
Mr. Synowiec 53 - 2,161
Mr. Trenary 41 - 23
Mr. Vipperman 80 564 4,391
Mr. Walters 45 - 4,693Synowiec...................... 4,312
Ms. Tomasky....................... 1,116
All Directors and Executive
Officers 668 6,529 45,804Officers........................ 29,980
With respect to the shares and share equivalents held in these plans,the AEP Retirement Savings
Plan, such persons have sole voting power, but the investment/disposition
power is subject to the terms of suchthe Plan. Also, includes the following
numbers of shares attributable to options exercisable within 60 days: Mr.
Boyd, 10,000; Dr. Draper, 466,666;
35
Mr. Hagan, 41,666; Mr. Lewis, 2,083; Mr. Powers, 65,266; Mr. Sampson,
10,000; Mr. Shockley, 166,666; Mr. Synowiec, 3,333; and Mr. Fayne and Ms.
Tomasky, 133,333.
(b) This column includes amounts deferred in stock units and held under AEP's
officer benefit plans.
(c)Mr. DeMaria owns 100 Includes 661 shares of Cumulative Preferred Shares 9.50% Series,
$100 par value, of Columbus Southern Power Company.held by Dr. Draper in joint tenancy with a family
member.
(d)Does not include, for Messrs. DeMaria, LhotaFayne, and Maloney,Shockley and Ms. Tomasky, 85,231
shares in the American Electric Power System Educational Trust Fund over
which Messrs. DeMaria, LhotaFayne and MaloneyShockley and Ms. Tomasky 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 in joint tenancy with a family
member: Mr. DeMaria, 1,232; Mr. D'Onofrio, 500; Dr. Draper, 1,965;
Mr. Lhota, 1,368; Mr. Maloney, 1,500; Mr. Potter, 14; and Mr. Vipperman, 57.
(f)Includes the following numbers of496 shares held by family members of Mr. Shockley over which he
disclaimed beneficial ownership is disclaimed: Mr. DeMaria, 2,392; and Dr. Markowsky,
17.
(g)ownership.
(f) Represents less than 1% of the total number of shares outstanding.
KEPCO. OmittedEQUITY COMPENSATION PLAN INFORMATION
The following table summarizes the ability of AEP to issue common stock
pursuant to Instruction J(2)(c).
OPCO.equity compensation plans as of December 31, 2002:
NUMBER OF SECURITIES
NUMBER OF REMAINING AVAILABLE
SECURITIES TO BE FOR FUTURE ISSUANCE
ISSUED UPON WEIGHTED AVERAGE UNDER EQUITY
EXERCISE OF EXERCISE PRICE OF COMPENSATION PLANS
OUTSTANDING OPTIONS OUTSTANDING (EXCLUDING SECURITIES
WARRANTS AND OPTIONS, WARRANTS REFLECTED IN
RIGHTS AND RIGHTS COLUMN (a))
PLAN CATEGORY (a) (b) (c)
- ------------- ------------------- ------------------- ---------------------
Equity compensation plans approved by security
holders(1)................................... 8,779,217 $33.5767 6,901,693(2)
Equity compensation plans not approved by
security holders............................. 0 N/A 0
Total........................................ 8,779,217 $33.5767 6,901,693
- ------------------------------------
(1) Consists of shares to be issued upon exercise of outstanding options granted
under the American Electric Power System 2000 Long-Term Incentive Plan, the
CSW 1992 Long-Term Incentive Plan (CSW Plan) and the AEP Deferred
Compensation and Stock Plan for Non-Employee Directors. The information required by this item is incorporated herein by
referenceCSW Plan was in
effect prior to the materialconsummation of the AEP-CSW merger. All unexercised
options granted under Share Ownershipthe CSW Plan were converted into 0.6 options to
purchase AEP common shares, vested on the merger date and will expire ten
years after their grant date. No additional options will be issued under the
CSW Plan.
(2) Excludes shares available for further issuance under the AEP Deferred
Compensation and Stock Plan for Non-Employee Directors, which does not have
a limit on the number of Directors and Executive
Officers inshares which may be issued. The amount of shares is
capped, however, by the definitive information statement of OPCo forannual retainer amount paid to the 1996 annual
meeting of shareholders, to be filed within 120 days after December 31, 1995.Non-Employee
Directors.
36
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
AEP. The- --------------------------------------------------------------------------------
AEP, AEGCO, APCO, CSPCO, I&M, KPCO, OPCO, PSO, SWEPCO, TCC AND TNC: None.
PART IV
- --------------------------------------------------------------------------------
Item 14. CONTROLS AND PROCEDURES
- --------------------------------------------------------------------------------
AEP maintains disclosure controls and procedures designed to ensure that
the information AEP must disclose in its filings with the Securities and
Exchange Commission is recorded, processed, summarized and reported on a timely
basis. AEP's principal executive officer and principal financial officer have
reviewed and evaluated AEP's disclosure controls and procedures as defined in
Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934, as
amended (the Exchange Act) as of a date within 90 days prior to the filing date
of this report (the Evaluation Date). Such officers have concluded that, as of
the Evaluation Date, AEP's disclosure controls and procedures are effective in
accumulating and communicating to management on a timely basis information
required by this item is incorporated herein by
reference to be disclosed in AEP's periodic filings under the material under Transactions With Management ofExchange Act.
Since the definitive
proxy statement of AEP, dated March 9, 1996, for the 1996 annual meeting of
shareholders.
APCO, I&M AND OPCO. None.
AEGCO, CSPCO, AND KEPCO. Omitted pursuant to Instruction J(2)(c).
PART IVEvaluation Date, there have not been any significant changes in
AEP's internal controls, or in other factors that could significantly affect
these controls.
Item 14.EXHIBITS,15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
- --------------------------------------------------------------------------------
(a)The following documents are filed as a part of this report:
1.FINANCIAL1. 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, 2002, 2001,
and 2000; Statements of Retained Earnings for the years ended
December 31, 2002, 2001, and 2000; Balance Sheets as of December
31, 2002 and 2001; Statements of Cash Flows for the years ended
December 31, 2002, 2001, and 2000; Statements of Capitalization as
of December 31, 2002 and 2001; Combined Notes to Financial
Statements; Independent Auditors' Report.
AEP and Subsidiary Companies:
Consolidated Statements of Operations for the years ended
December 31, 2002, 2001, and 2000; Consolidated Balance Sheets
as of December 31, 2002 and 2001; Consolidated Statements of
Cash Flows for the years ended December 31, 2002, 2001, and
2000; Consolidated Statements of Common Shareholders' Equity and
Comprehensive Income for the years ended December 31, 2002,
2001, and 2000; Schedule of Consolidated Cumulative Preferred
Stocks of Subsidiaries at December 31, 2002 and 2001; Schedule
of Consolidated Long-term Debt of Subsidiaries at December 31,
2002 and 2001; Combined Notes to Consolidated Financial
Statements; Independent Auditors' Report.
APCo, CSPCo, I&M, PSO, SWEPCo and TCC:
Consolidated Statements of Income for the years ended December
31, 2002, 2001, and 2000; Consolidated Statements of
Comprehensive Income for the years ended December 31, 2002,
2001, and 2000; Consolidated Statements of Retained Earnings for
the years ended December 31, 2002, 2001, and 2000; Consolidated
Balance Sheets as of December 31, 2002 and 2001; Consolidated
Statements of Cash Flows for the years ended December 31, 2002,
2001, and 2000; Consolidated Statements of Capitalization as of
December 31, 2002 and 2001; Schedule of Long-term Debt as of
December 31, 2002 and 2001; Combined Notes to Consolidated
Financial Statements; Independent Auditors' Report.
37
KPCo, OPCo and TNC:
Statements of Income (or Statements of Operations) for the years
ended December 31, 2002, 2001, and 2000; Statements of
Comprehensive Income for the years ended December 31, 1995, 19942002, 2001,
and 1993;2000; Statements of Retained Earnings for the years ended
December 31, 1995, 19942002, 2001, and 1993;2000; Balance Sheets as of December
31, 2002 and 2001; Statements of Cash Flows for the years ended
December 31, 1995, 19942002, 2001, and 1993; Balance
Sheets2000; Statements of Capitalization as
of December 31, 19952002 and 1994; Notes to Financial Statements.
AEP and its subsidiaries consolidated:
Consolidated Statements2001; Schedule of Income for the years ended December 31, 1995,
1994 and 1993; Consolidated Statements of Retained Earnings for the
years ended December 31, 1995, 1994 and 1993; Consolidated Statements of
Cash Flows for the years ended December 31, 1995, 1994 and 1993;
Consolidated Balance SheetsLong-term Debt as of
December 31, 19952002 and 1994;2001; Combined Notes to Consolidated Financial
Statements; Schedule of Consolidated Cumulative
Preferred Stocks of Subsidiaries at December 31, 1995 and 1994; Schedule
of Consolidated Long-term Debt of Subsidiaries at December 31, 1995 and
1994; Independent Auditors' Report.
APCo:
Independent Auditors' Report; Consolidated Statements of Income for the
years ended December 31, 1995, 1995 and 1994; Consolidated Balance
Sheets as of December 31, 1995 and 1994; Consolidated Statements of Cash
Flows for the years ended December 31, 1995, 1994 and 1993; Consolidated
Statements of Retained Earnings for the years ended December 31, 1995,
1994 and 1993; Notes to Consolidated Financial Statements.
CSPCo:
Independent Auditors' Report; Consolidated Statements of Income for the
years ended December 31, 1995, 1994 and 1993; Consolidated Balance
Sheets as of December 31, 1995 and 1994; Consolidated Statements of Cash
Flows for the years ended December 31, 1995, 1994 and 1993; Consolidated
Statements of Retained Earnings for the years ended December 31, 1995,
1994 and 1993; Notes to Consolidated Financial Statements.
I&M:
Independent Auditors' Report; Consolidated Statements of Income for the
years ended December 31, 1995, 1994 and 1993; Consolidated Balance
Sheets as of December 31, 1995 and 1994; Consolidated Statements of Cash
Flows for the years ended December 31, 1995, 1994 and 1993; Consolidated
Statements of Retained Earnings for the years ended December 31, 1995,
1994 and 1993; Notes to Consolidated Financial Statements.
KEPCo:
Independent Auditors' Report; Statements of Income for the years ended
December 31, 1995, 1994 and 1993; Statements of Retained Earnings for
the years ended December 31, 1995, 1994 and 1993; Balance Sheets as of
December 31, 1995 and 1994; Statements of Cash Flows for the years ended
December 31, 1995, 1994 and 1993; Notes to Financial Statements.
OPCo:
Independent Auditors' Report; Consolidated Statements of Income for the
years ended December 31, 1995, 1994 and 1993; Consolidated Balance
Sheets as of December 31, 1995 and 1994; Consolidated Statements of Cash
Flows for the years ended December 31, 1995, 1994 and 1993; Consolidated
Statements of Retained Earnings for the years ended December 31, 1995,
1994 and 1993; Notes to Consolidated Financial Statements.
2.FINANCIAL2. FINANCIAL STATEMENT SCHEDULES:
Financial Statement Schedules are listed in the Index to S-1
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-1applicable). Independent Auditors' Report
S-2
3.EXHIBITS:3. EXHIBITS:
Exhibits for AEGCo, AEP, APCo, CSPCo, I&M, KEPCoKPCo, OPCo, PSO, E-1
SWEPCo, TCC and OPCoTNC 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,
1995.Forms 8-K:
COMPANY REPORTING DATE OF REPORT ITEM REPORTED
- ----------------- ----------------- ----------------------------------------------
APCo, CSPCo, I&M, KPCo, OPCo, PSO,
SWEPCo, TCC and TNC.................. November 18, 2002 Item 5. Other Events
I&M.................................. November 22, 2002 Item 5. Other Events
Item 7. Financial Statements and Exhibits
I&M.................................. November 25, 2002 Item 5. Other Events
Item 7. Financial Statements and Exhibits
PSO.................................. November 26, 2002 Item 5. Other Events
Item 7. Financial Statements and Exhibits
Reports on Forms 8-K/A:
COMPANY REPORTING DATE OF REPORT ITEM REPORTED
- ----------------- ----------------- ----------------------------------------------
PSO, SWEPCo, TCC and TNC............. November 26, 2002 Item 7. Financial Statements and Exhibits
(c) Exhibits: See Exhibit Index beginning on page E-1.
38
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D)15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
AMERICAN ELECTRIC POWER COMPANY, INC.
By:
/s/ SUSAN TOMASKY
-------------------------------------
(SUSAN TOMASKY, VICE PRESIDENT,
SECRETARY AND CHIEF FINANCIAL
OFFICER)
Date: March 20, 2003
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, March 20, 2003
President,
Chief Executive Officer
And Director
(II) PRINCIPAL FINANCIAL OFFICER:
/s/ SUSAN TOMASKY Vice President, Secretary and March 20, 2003
- ------------------------------------------------ Chief Financial Officer
(SUSAN TOMASKY)
(III) PRINCIPAL ACCOUNTING OFFICER:
/s/ JOSEPH M. BUONAIUTO Controller and March 20, 2003
- ------------------------------------------------ Chief Accounting Officer
(JOSEPH M. BUONAIUTO)
(IV) A MAJORITY OF THE DIRECTORS:
*E. R. BROOKS
*DONALD M. CARLTON
*JOHN P. DESBARRES
*ROBERT W. FRI
*WILLIAM R. HOWELL
*LESTER A. HUDSON, JR.
*LEONARD J. KUJAWA
*RICHARD L. SANDOR
*THOMAS V. SHOCKLEY, III
*DONALD G. SMITH
*LINDA GILLESPIE STUNTZ
*KATHRYN D. SULLIVAN March 20, 2003
*By: /s/ SUSAN TOMASKY
------------------------------------------
(SUSAN TOMASKY, ATTORNEY-IN-FACT)
39
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE
UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE
TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.
AEP GENERATING COMPANY
BY: /S/ G. P. MALONEY
(G. P. MALONEY,AEP TEXAS CENTRAL COMPANY
AEP TEXAS NORTH COMPANY
APPALACHIAN POWER COMPANY
COLUMBUS SOUTHERN POWER COMPANY
KENTUCKY POWER COMPANY
OHIO POWER COMPANY
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY
By:
/s/ SUSAN TOMASKY
-------------------------------------
(SUSAN TOMASKY, VICE PRESIDENT)
Date: March 25, 199620, 2003
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:PRINCIPAL EXECUTIVE OFFICER:
*E. LINN DRAPER, JR. Chairman of the Board, March 20, 2003
President,
Chief Executive Officer
andAnd Director
(II)(ii) PRINCIPAL FINANCIAL OFFICER:
/S/ G. P. MALONEY/s/ SUSAN TOMASKY Vice President, Secretary, March 25, 1996
(G. P. MALONEY)20, 2003
- ------------------------------------------------ Chief Financial Officer and Director
(III)(SUSAN TOMASKY)
(iii) PRINCIPAL ACCOUNTING OFFICER:
/S/ P. J. DEMARIA Vice President,
(P. J. DEMARIA)/s/ JOSEPH M. BUONAIUTO Controller and March 25, 1996
and Director
(IV)20, 2003
- ------------------------------------------------ Chief Accounting Officer
(JOSEPH M. BUONAIUTO)
(iv) A MAJORITY OF THE DIRECTORS:
*HENRY W. FAYNE
*JOHN R. JONES,*THOMAS M. HAGAN
*A. A. PENA
*ROBERT P. POWERS
*THOMAS V. SHOCKLEY, III *WM. J. LHOTA
*JAMES J. MARKOWSKYMarch 20, 2003
*By: /S/ G. P. MALONEY March 25, 1996
(G. P. MALONEY,/s/ SUSAN TOMASKY
------------------------------------------
(SUSAN TOMASKY, ATTORNEY-IN-FACT)
40
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/ G. P. MALONEY
(G. P. MALONEY, VICE
PRESIDENT)
Date: March 25, 1996
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/ G. P. MALONEY Vice President, March 25, 1996
(G. P. MALONEY) Secretary and
Director
(III) PRINCIPAL ACCOUNTING OFFICER:
/S/ P. J. DEMAA Controller and Director March 25, 1996
(P. J. DEMARIA)
(IV) A MAJORITY OF THE DIRECTORS:
*ROBERT M. DUNCAN
*ROBERT W. FRI
*ARTHUR G. HANSEN
*LESTER A. HUDSON, JR.
*ANGUS E. PEYTON
*TOY F. REID
*DONALD G. SMITH
*LINDA GILLESPIE STUNTZ
*MORRIS TANENBAUM
*ANN HAYMOND ZWINGER
*By: /S/ G. P. MALONEY March 25, 1996
(G. P. MALONEY, ATTORNEY-IN-FACT)
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D)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.
APPALACHIANINDIANA MICHIGAN POWER COMPANY
BY: /S/ G. P. MALONEY
(G. P. MALONEY,By:
/s/ SUSAN TOMASKY
-------------------------------------
(SUSAN TOMASKY, VICE PRESIDENT)
Date: March 25, 199620, 2003
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:PRINCIPAL EXECUTIVE OFFICER:
*E. LINN DRAPER, JR. Chairman of the Board, March 20, 2003
President,
Chief Executive Officer
and Director
(II)(ii) PRINCIPAL FINANCIAL OFFICER:
/S/ G. P. MALONEY/s/ SUSAN TOMASKY Vice President, Secretary, March 25, 1996
(G. P. MALONEY)20, 2003
- ------------------------------------------------ Chief Financial Officer
(SUSAN TOMASKY) and Director
(III)(iii) PRINCIPAL ACCOUNTING OFFICER:
/S/ P. J. DEMARIA Vice President, March 25, 1996
(P. J. DEMARIA)/s/ JOSEPH M. BUONAIUTO Controller and Director
(IV)March 20, 2003
- ------------------------------------------------ Chief Accounting Officer
(JOSEPH M. BUONAIUTO)
(iv) A MAJORITY OF THE DIRECTORS:
*K. G. BOYD
*JOHN E. EHLER
*HENRY W. FAYNE
*WM. J. LHOTA
*JAMES J. MARKOWSKY
*J. H. VIPPERMAN
*By: /S/ G.*THOMAS M. HAGAN
*DAVID L. LAHRMAN
*MARC E. LEWIS
*SUSANNE M. MOORMAN
*ROBERT P. MALONEY March 25, 1996
(G. P. MALONEY, ATTORNEY-IN-FACT)
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.
COLUMBUS SOUTHERN POWER COMPANY
BY: /S/ G. P. MALONEY
(G. P. MALONEY, VICE
PRESIDENT)
Date: March 25, 1996
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/ G. P. MALONEY Vice President March 25, 1996
(G. P. MALONEY) and Director
(III) PRINCIPAL ACCOUNTING OFFICER:
/S/ P. J. DEMARIA Vice President, ControllerMarch 25, 1996
(P. J. DEMARIA) Controller
and Director
(IV) A MAJORITY OF THE DIRECTORS:
*HENRY FAYNE
*WM. J. LHOTA
*JAMES J. MARKOWSKY
*J. H. VIPPERMAN
*By: /S/ G. P. MALONEY March 25, 1996
(G. P. MALONEY, ATTORNEY-IN-FACT)
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/ G. P. MALONEY
(G. P. MALONEY, VICE
PRESIDENT)
Date: March 25, 1996
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/ G. P. MALONEY Vice President March 25, 1996
(G. P. MALONEY) and Director
(III) PRINCIPAL ACCOUNTING OFFICER:
/S/ P. J. DEMARIA Vice President, March 25, 1996
(P. J. DEMARIA) Controller
and Director
(IV) A MAJORITY OF THE DIRECTORS:
*C.POWERS
*JOHN R. BOYLE,SAMPSON
*THOMAS V. SHOCKLEY, III
*G. A. CLARK
*W. N. D'ONOFRIO
*WM. J. LHOTA
*JAMES J. MARKOWSKY
*A. H. POTTER
*D. B. SYNOWIEC *D. M. TRENARY
*J. H. VIPPERMAN
*W. E. WALTERSMarch 20, 2003
*By: /S/ G. P. MALONEY March 25, 1996
(G. P. MALONEY,/s/ SUSAN TOMASKY
------------------------------------------
(SUSAN TOMASKY, ATTORNEY-IN-FACT)
41
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.
KENTUCKY POWER COMPANY
BY: /S/ G. P. MALONEY
(G. P. MALONEY, VICE
PRESIDENT)
Date:CERTIFICATIONS
I, E. Linn Draper, Jr., certify that:
1. I have reviewed this annual report on Form 10-K of:
American Electric Power Company, Inc.
AEP Generating Company
AEP Texas Central Company
AEP Texas North Company
Appalachian Power Company
Columbus Southern Power Company
Indiana Michigan Power Company
Kentucky Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Dated: March 25, 1996
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/ G. P. MALONEY Vice President March 25, 1996
(G. P. MALONEY) and Director
(III) PRINCIPAL ACCOUNTING OFFICER:
/S/ P. J. DEMARIA Vice President, March 25, 1996
(P. J. DEMARIA) Controller
and Director
(IV) A MAJORITY OF THE DIRECTORS:
*WM. J. LHOTA
*JAMES J. MARKOWSKY
*J. H. VIPPERMAN
*By: /S/ G. P. MALONEY March 25, 1996
(G. P. MALONEY, ATTORNEY-IN-FACT)
20, 2003 By:
/s/ E. LINN DRAPER, JR.
--------------------------------------
E. Linn Draper, Jr.
Chief Executive Officer
42
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.
OHIO POWER COMPANY
BY: /S/ G. P. MALONEY
(G. P. MALONEY, VICE
PRESIDENT)
Date:I, Susan Tomasky, certify that:
1. I have reviewed this annual report on Form 10-K of:
American Electric Power Company, Inc.
AEP Generating Company
AEP Texas Central Company
AEP Texas North Company
Appalachian Power Company
Columbus Southern Power Company
Indiana Michigan Power Company
Kentucky Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a. designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;
b. evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c. presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a. all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b. any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Dated: March 25, 1996
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/ G. P. MALONEY Vice President March 25, 1996
(G. P. MALONEY) and Director
(III) PRINCIPAL ACCOUNTING OFFICER:
/S/ P. J. DEMARIA Vice President, March 25, 1996
(P. J. DEMARIA) Controller
and Director
(IV) A MAJORITY OF THE DIRECTORS:
*HENRY FAYNE
*WM. J. LHOTA
*JAMES J. MARKOWSKY
*J. H. VIPPERMAN
*By: /S/ G. P. MALONEY March 25, 1996
(G. P. MALONEY, ATTORNEY-IN-FACT)
20, 2003 By:
/s/ SUSAN TOMASKY
--------------------------------------
Susan Tomasky
Chief Financial Officer
43
INDEX TO FINANCIAL STATEMENT SCHEDULES
PAGE
INDEPENDENT AUDITORS' REPORT S-2
The following financial statement schedules for the years ended
December 31, 1995, 1994 and 1993 are included in this report on
the pages indicated.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Schedule II- Valuation and Qualifying Accounts and Reserves S-3
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Schedule II- Valuation and Qualifying Accounts and Reserves S-3
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Schedule II- Valuation and Qualifying Accounts and Reserves S-3
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Schedule II- Valuation and Qualifying Accounts and Reserves S-4
KENTUCKY POWER COMPANY
Schedule II- Valuation and Qualifying Accounts and Reserves S-4
OHIO POWER COMPANY AND SUBSIDIARIES
Schedule II- Valuation and Qualifying Accounts and Reserves
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
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Schedule II -- Valuation and Qualifying Accounts and
Reserves.............................................. S-3
AEP TEXAS NORTH COMPANY
Schedule II -- Valuation and Qualifying Accounts and
Reserves.............................................. S-3
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Schedule II -- Valuation and Qualifying Accounts and
Reserves.............................................. S-4
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-5
OHIO POWER COMPANY
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-6
S-1
INDEPENDENT AUDITORS' REPORT
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARIES:
We have audited the consolidated financial statements of American Electric
Power Company, Inc. and its subsidiaries and the financial statements of certain of
its subsidiaries, listed in Item 1415 herein, as of December 31, 19952002 and 1994,2001,
and for each of the three years in the period ended December 31, 1995,2002, and have
issued our reports thereon dated February 27, 1996;21, 2003; such financial statements
and reports are included in your respective 1995the 2002 Annual ReportReports 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 14.15. These financial statement schedules are the
responsibility of the respective Company'scompany'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.
DELOITTEDeloitte & TOUCHETouche LLP
Columbus, Ohio
February 27, 199621, 2003
S-2
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE II -AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
- -------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- -------------------------------------------------------------------------------------------------------------------
ADDITIONS
Balance at Charged to Charged to Balance at
Beginning Costs and Other End of
Description of Period Expenses Accounts Deductions Period-------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS(a) DEDUCTIONS(b) PERIOD
- -------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
(in thousands)
Deducted from Assets:DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 1995 $4,056 $12,9072002........... $69,416 $ 5,927(a) $17,460(b) $5,43097,772 $11,766 $59,723 $119,231
======= ======== ======= ======= ========
Year Ended December 31, 1994 $4,048 $20,265 $(3,556)(a) $16,701(b) $4,0562001(c)........ $31,905 $109,635 $20,763 $92,887 $ 69,416
======= ======== ======= ======= ========
Year Ended December 31, 1993 $7,287 $14,2372000(c)........ $27,091 $ 4,163(a) $21,639(b) $4,04851,457 $11,729 $58,372 $ 31,905
======= ======== ======= ======= ========
- ---------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II -(c) 2001 and 2000 amounts have been adjusted to reflect the treatment of
SEEBOARD and CitiPower as discontinued operations in AEP's Consolidated
Statements of Operations.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
- -------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- -------------------------------------------------------------------------------------------------------------------
ADDITIONS
Balance at Charged to Charged to Balance at
Beginning Costs and Other End of
Description of Period Expenses Accounts Deductions Period-------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS(a) DEDUCTIONS(b) PERIOD
- -------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
(in thousands)
Deducted from Assets:DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 19952002........... $ 830186 $ 3,442162 $ 963 (a)1 $ 2,982(b) $2,2533 $ 346
====== ====== ====== ====== ======
Year Ended December 31, 1994 $1,3442001........... $1,675 $ 2,297186 $ 596 (a)-- $1,675 $ 3,407(b) $ 830186
====== ====== ====== ====== ======
Year Ended December 31, 19932000........... $ 724-- $1,675 $ 3,392-- $ 627-- $1,675
====== ====== ====== ====== ======
- ---------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
AEP TEXAS NORTH COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
- -------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- -------------------------------------------------------------------------------------------------------------------
ADDITIONS
-------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS(a) DEDUCTIONS(b) PERIOD
- -------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2002........... $ 3,399(b) $1,344196 $4,846 $ 17 $ 18 $5,041
====== ====== ====== ====== ======
Year Ended December 31, 2001........... $ 288 $ 13 $ 35 $ 140 $ 196
====== ====== ====== ====== ======
Year Ended December 31, 2000........... $ 186 $1,499 $ 46 $1,443 $ 288
====== ====== ====== ====== ======
- ---------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
S-3
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
- -------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- -------------------------------------------------------------------------------------------------------------------
ADDITIONS
-------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS(a) DEDUCTIONS(b) PERIOD
- -------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2002........... $1,877 $3,937 $12,367 $4,742 $13,439
====== ====== ======= ====== =======
Year Ended December 31, 2001........... $2,588 $2,644 $ 1,017 $4,372 $ 1,877
====== ====== ======= ====== =======
Year Ended December 31, 2000........... $2,609 $6,592 $ 1,526 $8,139 $ 2,588
====== ====== ======= ====== =======
- ---------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II --- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
- -------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- -------------------------------------------------------------------------------------------------------------------
ADDITIONS
Balance at Charged to Charged to Balance at
Beginning Costs and Other End of
Description of Period Expenses Accounts Deductions Period-------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS(a) DEDUCTIONS(b) PERIOD
- -------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
(in thousands)
Deducted from Assets:DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 1995 $1,7682002........... $ 4,873745 $ 3,531(a)(100) $ 9,111(b) $1,061-- $ 11 $ 634
====== ====== ====== ====== ======
Year Ended December 31, 19942001........... $ 991659 $ 6,181331 $ 2,778(a)-- $ 8,182(b) $1,768245 $ 745
====== ====== ====== ====== ======
Year Ended December 31, 1993 $1,3322000........... $3,045 $2,082 $1,405 $5,873 $ 4,167 $ 2,106(a) $ 6,614(b) $ 991659
====== ====== ====== ====== ======
- ---------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II --- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
- -------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- -------------------------------------------------------------------------------------------------------------------
ADDITIONS
Balance at Charged to Charged to Balance at
Beginning Costs and Other End of
Description of Period Expenses Accounts Deductions Period-------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS(a) DEDUCTIONS(b) PERIOD
- -------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
(in thousands)
Deducted from Assets:DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 19952002........... $ 121741 $ 1,506(161) $ 632(a)-- $ 1,925(b)2 $ 334578
====== ====== ====== ====== ======
Year Ended December 31, 19942001........... $ 504759 $ 77465 $ 707(a)3 $ 1,864(b)86 $ 121741
====== ====== ====== ====== ======
Year Ended December 31, 19932000........... $1,848 $ 562(235) $ 1,380907 $1,761 $ 624(a) $ 2,062(b) $ 504759
====== ====== ====== ====== ======
- ---------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
KENTUCKY POWER COMPANY
SCHEDULE II -S-4
KENTUCKY POWER COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
- -------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- -------------------------------------------------------------------------------------------------------------------
ADDITIONS
Balance at Charged to Charged to Balance at
Beginning Costs and Other End of
Description of Period Expenses Accounts Deductions Period-------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS(a) DEDUCTIONS(b) PERIOD
- -------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
(in thousands)
Deducted from Assets:DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 19952002........... $ 260264 $ 925(68) $ 234(a)-- $ 1,160(b)4 $ 259192
====== ====== ====== ====== ======
Year Ended December 31, 19942001........... $ 208282 $ 600-- $ 84(a)(24) $ 632(b)(6) $ 260264
====== ====== ====== ====== ======
Year Ended December 31, 19932000........... $ 248637 $ 390187 $ 179(a)9 $ 609(b)551 $ 208282
====== ====== ====== ====== ======
- ---------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
OHIO POWER COMPANY
AND SUBSIDIARIES
SCHEDULE II --- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
- -------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- -------------------------------------------------------------------------------------------------------------------
ADDITIONS
Balance at Charged to Charged to Balance at
Beginning Costs and Other End of
Description of Period Expenses Accounts Deductions Period-------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS(a) DEDUCTIONS(b) PERIOD
- -------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
(in thousands)
Deducted from Assets:DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 1995 $1,0192002........... $1,379 $ 1,952(457) $ 472(a)-- $ 2,019(b) $1,42413 $ 909
====== ====== ====== ====== ======
Year Ended December 31, 19942001........... $1,054 $ 960 $10,087 $(7,785)(a)554 $ 2,243(b) $1,019-- $ 229 $1,379
====== ====== ====== ====== ======
Year Ended December 31, 1993 $4,3532000........... $2,223 $ 4,812472 $ 549(a) $ 8,754(b) $960778 $2,419 $1,054
====== ====== ====== ====== ======
- ---------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
- -------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- -------------------------------------------------------------------------------------------------------------------
ADDITIONS
-------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS(a) DEDUCTIONS(b) PERIOD
- -------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2002........... $ 44 $ 7 $ 33 $ -- $ 84
====== ====== ====== ====== ======
Year Ended December 31, 2001........... $ 467 $ 44 $ -- $ 467 $ 44
====== ====== ====== ====== ======
Year Ended December 31, 2000........... $ -- $ 467 $ -- $ -- $ 467
====== ====== ====== ====== ======
- ---------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
S-5
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
- -------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- -------------------------------------------------------------------------------------------------------------------
ADDITIONS
-------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS(A) DEDUCTIONS(B) PERIOD
- -------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2002........... $ 89 $2,036 $ 4 $ 1 $2,128
====== ====== ======= ====== ======
Year Ended December 31, 2001........... $ 911 $ 89 $ -- $ 911 $ 89
====== ====== ======= ====== ======
Year Ended December 31, 2000........... $4,428 $ 911 $(4,428) $ -- $ 911
====== ====== ======= ====== ======
- ---------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
S-6
EXHIBIT INDEX
Certain of the following exhibits, designated with an asterisk(*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 exhibitExhibit to this formForm pursuant to Item 14(c) of this report.
EXHIBIT NUMBER DESCRIPTION
AEGCO
3(a)
- --------------- -----------
AEGCO
3(a) -- Copy of Articles of Incorporation of AEGCo [Registration
Statement on Form 10 for the Common Shares of AEGCo, File
No. 0-18135, Exhibit 3(a)].
3(b) -- Copy of the Code of Regulations of AEGCo (amended as of June
15, 2000) [Annual Report on Form 10-K of AEGCo for the
fiscal year ended December 31, 2000, File No. 0-18135,
Exhibit 3(b)].
10(a) -- Copy of Capital Funds Agreement dated as of December 30,
1988 between AEGCo and AEP [Registration Statement No.
33-32752, Exhibit 28(a)].
10(b)(1) -- Copy of Unit Power Agreement dated as of March 31, 1982
between AEGCo and I&M, as amended [Registration Statement
No. 33-32752, Exhibits 28(b)(1)(A) and 28(b)(1)(B)].
10(b)(2) -- Copy of Unit Power Agreement, dated as of August 1, 1984,
among AEGCo, I&M and KPCo [Registration Statement No.
33-32752, Exhibit 28(b)(2)].
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 2002 Annual Report (for
the fiscal year ended December 31, 2002) which are
incorporated by reference in this filing.
*24 -- Power of Attorney.
*99(a) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
*99(b) -- Certification of Chief Financial Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
AEP++
3(a) -- Copy of Restated Certificate of Incorporation of AEP, dated
October 29, 1997 [Quarterly Report on Form 10-Q of AEP for
the quarter ended September 30, 1997, File No. 1-3525,
Exhibit 3(a)].
3(b) -- Copy of Certificate of Amendment of the Restated Certificate
of Incorporation of AEP, dated January 13, 1999 [Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 1998, File No. 1-3525, Exhibit 3(b)].
3(c) -- Composite copy of the Restated Certificate of Incorporation
of AEP, as amended [Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1998, File No. 1-3525,
Exhibit 3(c)].
3(d) -- Copy of By-Laws of AEP, as amended through January 28, 1998
[Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1997, File No. 1-3525, Exhibit 3(b)].
4(a) -- Indenture (for unsecured debt securities), dated as of May
1, 2001, between AEP and The Bank of New York, as Trustee
[Registration Statement No. 333-86050, Exhibits 4(a), 4(b)
and 4(c)].
*4(b) -- Third Supplemental Indenture, dated as of June 11, 2002,
between AEP and The Bank of New York, as Trustee, for 5.75%
Senior Notes, Series C, due August 16, 2007.
E-1
EXHIBIT NUMBER DESCRIPTION
- --------------- -----------
*4(c) -- Forward Purchase Contract Agreement, dated as of June 11,
2002, between AEP and The Bank of New York, as Forward
Purchase Contract Agent.
10(a) -- Interconnection Agreement, dated July 6, 1951, among APCo,
CSPCo, KPCo, 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) -- Restated and Amended Operating Agreement, dated as of
January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC.
10(c) -- Transmission Agreement, dated April 1, 1984, among APCo,
CSPCo, I&M, KPCo, 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) -- Transmission Coordination Agreement, dated October 29, 1998,
among PSO, TCC, TNC, SWEPCo and AEPSC.
10(e) -- 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(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) -- Modification No. 1 to the AEP System Interim Allowance
Agreement, dated July 28, 1994, among APCo, CSPCo, I&M,
KPCo, 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(h)(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(h)(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(i)(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(i)(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(j) -- 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(k)(1) -- AEP Deferred Compensation and Stock Plan for Non-Employee
Directors, as amended June 1, 2000 [Annual Report on Form
10-K of AEP for the fiscal year ended December 31, 2000,
File No. 1-3525, Exhibit 10(i)(1)].
3(b) - Copy of the Code of Regulations of AEGCo [Registration Statement
on Form 10 for the Common Shares of AEGCo, File No. 0-18135,
Exhibit 3(b)
E-2
EXHIBIT NUMBER DESCRIPTION
- --------------- -----------
+10(k)(2) -- AEP Stock Unit Accumulation Plan for Non-Employee Directors,
as amended January 1, 2002[Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 2001, File No.
1-3525, Exhibit 10(i)(2)].
+10(l)(1)(A) -- AEP System Excess Benefit Plan, Amended and Restated as of
January 1, 2001 [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 2000, File No. 1-3525,
Exhibit 10(j)(1)(A)].
+10(l)(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(l)(1)(C) -- First Amendment to AEP System Excess Benefit Plan, dated as
of March 5, 2003.
+10(l)(2) -- AEP System Supplemental Retirement Savings Plan, Amended and
Restated as of June 1, 2001 (Non-Qualified) [Registration
Statement No. 333-66048, Exhibit 4].
+10(l)(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(m)(1) -- 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(m)(2) -- Memorandum of agreement between Susan Tomasky and the
Service Corporation dated January 3, 2001 [Annual Report on
Form 10-K of AEP for the fiscal year ended December 31,
2000, File No. 1-3525, Exhibit 10(s)].
*+10(m)(3)(A) -- Letter Agreement dated June 23, 2000 between AEPSC and Holly
K. Koeppel.
*+10(m)(3)(B) -- Letter Agreement dated April 19, 2001 between AEPR and Holly
K. Koeppel.
*+10(m)(4) -- Employment Agreement dated July 29, 1998 between AEPSC and
Robert P. Powers.
+10(n) -- 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(o)(1) -- 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(o)(2) -- First Amendment to AEP System Survivor Benefit Plan, as
amended and restated effective January 31, 2000.
+10(p) -- 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(q)(1) -- AEP System Incentive Compensation Deferral Plan dated
January 1, 2001.
*+10(q)(2) -- First Amendment to AEP System Incentive Compensation
Deferral Plan dated December 6, 2002.
*+10(r) -- AEP System Nuclear Performance Long Term Incentive
Compensation Plan dated August 1, 1998.
*+10(s) -- Nuclear Key Contributor Retention Plan dated May 1, 2000.
+10(t) -- AEP Change In Control Agreement [Annual Report on Form 10-K
of AEP for the fiscal year ended December 31, 2001, File No.
1-3525, Exhibit 10(o)].
+10(u) -- AEP System 2000 Long-Term Incentive Plan [Proxy Statement of
AEP, March 10, 2000].
+10(v)(1) -- Central and South West System Special Executive Retirement
Plan as amended and restated effective July 1, 1997 [Annual
Report on Form 10-K of CSW for the fiscal year ended
December 31, 1998, File No. 1-1443, Exhibit 18].
+10(v)(2) -- Certified CSW Board Resolution of April 18, 1991 [Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 2001, File No. 1-3525, Exhibit 10(r)(2)].
+10(v)(3) -- CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW,
March 13, 1992].
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 1995 Annual Report (for the
fiscal year ended December 31, 1995) which are incorporated by
reference in this filing.
*24 - Power of Attorney.
*27 - Financial Data Schedules.
AEP
3(a) - Copy of Restated Certificate of Incorporation of AEP, dated April
26, 1978 [Registration Statement No. 2-62778, Exhibit 2(a)].
3(b)(1) - Copy of Certificate of Amendment of the Restated Certificate of
Incorporation of AEP, dated April 23, 1980 [Registration Statement
No. 33-1052,
E-3
EXHIBIT NUMBER DESCRIPTION
- --------------- -----------
+10(v)(4) -- Central and South West Corporation Executive Deferred
Savings Plan as amended and restated effective as of January
1, 1997 [Annual Report on Form 10-K of CSW for the fiscal
year ended December 31, 1998, File No. 1-1443, Exhibit 24].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the AEP 2002 Annual Report (for
the fiscal year ended December 31, 2002) which are
incorporated by reference in this filing.
*21 -- List of subsidiaries of AEP.
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*99(a) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
*99(b) -- Certification of Chief Financial Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
APCO++
3(a) -- Copy of Restated Articles of Incorporation of APCo, and
amendments thereto to November 4, 1993 [Registration
Statement No. 33-50163, Exhibit 4(a); Registration Statement
No. 33-53805, Exhibits 4(b) and 4(c)].
3(b) -- Copy of Articles of Amendment to the Restated Articles of
Incorporation of APCo, dated June 6, 1994 [Annual Report on
Form 10-K of APCo for the fiscal year ended December 31,
1994, File No. 1-3457, Exhibit 3(b)].
3(c) -- Copy of Articles of Amendment to the Restated Articles of
Incorporation of APCo, dated March 6, 1997 [Annual Report on
Form 10-K of APCo for the fiscal year ended December 31,
1996, File No. 1-3457, Exhibit 3(c)].
3(d) -- Composite copy of the Restated Articles of Incorporation of
APCo (amended as of March 7, 1997) [Annual Report on Form
10-K of APCo for the fiscal year ended December 31, 1996,
File No. 1-3457, Exhibit 3(d)].
3(e) -- Copy of By-Laws of APCo (amended as of October 24, 2001)
[Annual Report on Form 10-K of APCo for the fiscal year
ended December 31, 2001, File No. 1-3457, Exhibit 3(e)].
4(a) -- Copy of Mortgage and Deed of Trust, dated as of December 1,
1940, between APCo and Bankers Trust Company and R. Gregory
Page, as Trustees, as amended and supplemented [Registration
Statement No. 2-7289, Exhibit 7(b); Registration Statement
No. 2-19884, Exhibit 2(1); Registration Statement No.
2-24453, Exhibit 2(n); Registration Statement No. 2-60015,
Exhibits 2(b)(2), 2(b)(3), 2(b)(4), 2(b)(5), 2(b)(6),
2(b)(7), 2(b)(8), 2(b)(9), 2(b)(10), 2(b)(12), 2(b)(14),
2(b)(15), 2(b)(16), 2(b)(17), 2(b)(18), 2(b)(19), 2(b)(20),
2(b)(21), 2(b)(22), 2(b)(23), 2(b)(24), 2(b)(25), 2(b)(26),
2(b)(27) and 2(b)(28); Registration Statement No. 2-64102,
Exhibit 2(b)(29); Registration Statement No. 2-66457,
Exhibits (2)(b)(30) and 2(b)(31); Registration Statement No.
2-69217, Exhibit 2(b)(32); Registration Statement No.
2-86237, Exhibit 4(b); Registration Statement No. 33-11723,
Exhibit 4(b); Registration Statement No. 33-17003, Exhibit
4(a)(ii), Registration Statement No. 33-30964, Exhibit 4(b);
Registration Statement No. 33-40720, Exhibit 4(b);
Registration Statement No. 33-45219, Exhibit 4(b);
Registration Statement No. 33-46128, Exhibits 4(b) and 4(c);
Registration Statement No. 33-53410, Exhibit 4(b);
Registration Statement No. 33-59834, Exhibit 4(b);
Registration Statement No. 33-50229, Exhibits 4(b) and 4(c);
Registration Statement No. 33-58431, Exhibits 4(b), 4(c),
4(d) and 4(e); Registration Statement No. 333-01049,
Exhibits 4(b) and 4(c); Registration Statement No.
333-20305, Exhibits 4(b) and 4(c); Annual Report on Form
10-K of APCo for the fiscal year ended December 31, 1996,
File No. 1-3457, Exhibit 4(b); Annual Report on Form 10-K of
APCo for the fiscal year ended December 31, 1998, File No.
1-3457, Exhibit 4(b)].
3(b)(2) - Copy of Certificate
E-4
EXHIBIT NUMBER DESCRIPTION
- --------------- -----------
4(b) -- Indenture (for unsecured debt securities), dated as of
January 1, 1998, between APCo and The Bank of New York, As
Trustee [Registration Statement No. 333-45927, Exhibit 4(a);
Registration Statement No. 333-49071, Exhibit 4(b);
Registration Statement No. 333-84061, Exhibits 4(b) and
4(c); Annual Report on Form 10-K of APCo for the fiscal year
ended December 31, 1999, File No. 1-3457, Exhibit 4(c);
Registration Statement No. 333-81402, Exhibits 4(b), 4(c)
and 4(d); Registration Statement No. 333-100451, Exhibit
4(b)].
*4(c) -- Copy of Company Order and Officer's Certificate, dated
November 6, 2002, establishing terms of 4.3148% Senior
Notes, Series F, due 2007.
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, KPCo, 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, KPCo, 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, KPCo, OPCo and the Service Corporation [Annual Report
on Form 10-K of AEP for the fiscal year ended December 31,
1996, File No. 1-3525, Exhibit 10(l)].
10(e)(1) -- Agreement and Plan of Merger, dated as of December 21, 1997,
By and Among American Electric Power Company, Inc., Augusta
Acquisition Corporation and Central and South West
Corporation [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1997, File No. 1-3525,
Exhibit 10(f)].
10(e)(2) -- Amendment No. 1, dated as of December 31, 1999, to the
Agreement and Plan of Merger [Current Report on Form 8-K of
APCo dated December 15, 1999, File No. 1-3457, Exhibit 10].
+10(f)(1) -- AEP Deferred Compensation Agreement for certain executive
officers [Annual Report on Form 10-K of AEP for the fiscal
year ended December 31, 1985, File No. 1-3525, Exhibit
10(e)].
+10(f)(2) -- Amendment of the Restated Certificate of
Incorporation of AEP, dated April 28, 1982 [Registration Statement
No. 33-1052, Exhibit 4(c)].
3(b)(3) - Copy of Certificate of Amendment of the Restated Certificate of
Incorporation of AEP, dated April 25, 1984 [Registration Statement
No. 33-1052, Exhibit 4(d)].
3(b)(4) - Copy of Certificate of Change of the Restated Certificate of
Incorporation of AEP, dated July 5, 1984 [Registration Statement
No. 33-1052, Exhibit 4(e)].
3(b)(5) - Copy of Certificate of Amendment of the Restated Certificate of
Incorporation of AEP, dated April 27, 1988 [Registration Statement
No. 33-1052, Exhibit 4(f)].
3(c) - Composite copy of the Restated Certificate of Incorporation of
AEP, as amended [Registration Statement No. 33-1052, Exhibit
4(g)].
3(d) - Copy of By-Laws of AEP, as amended through July 26, 1989 [Annual
Report on Form 10-K of AEP for the fiscal year ended December 31,
1989, File No. 1-3525, Exhibit 3(d)].
10(a) - Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo,
KEPCo, OPCo and I&M and with the Service Corporation, as amended
[Registration Statement No. 2-52910, Exhibit 5(a); Registration
Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-
K of AEP for the fiscal year ended December 31, 1990, File No. 1-
3525, Exhibit 10(a)(3)].
10(b) - Copy of Transmission Agreement, dated April 1, 1984, among APCo,
CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent,
as amended [Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and
Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)].
AEP (continued)
EXHIBIT NUMBER DESCRIPTION
10(c)(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(c)(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(d)-AEP Deferred Compensation Agreement for directors, as amended,
effective October 24, 1984 [Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1984, File No. 1-3525, Exhibit
10(e)].
10(e)-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(f)-AEP Retirement Plan for directors [Annual Report on Form 10-K of
AEP for the fiscal year ended December 31, 1986, File No. 1-3525,
Exhibit 10(g)].
*10(g)(1)(A)-AEP Excess Benefit Plan, as amended through January 4,
1996.
10(g)(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(g)(2)-AEP System Supplemental Savings Plan (Non-Qualified) [Annual
Report on Form 10-K of AEP for the fiscal year ended December 31,
1993, File No. 1-3525, Exhibit 10(g)(2)].
10(g)(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(h)(1)-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(i)(1)-AEP Management Incentive Compensation Plan.
10(i)(2)-American Electric Power System Performance Share Incentive
Plan, as Amended and Restated through October 1, 1995 [Quarterly
Report on Form 10-Q of AEP for the quarterly period ended
September 30, 1995, File No. 1-3525, Exhibit 10].
10(j) - 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(k)(1) - Copy of Agreement for Lease, dated as of September 17, 1992,
between JMG Funding, Limited Partnership and OPCo [Annual Report
on Form 10-K of OPCo for the fiscal year ended December 31, 1992,
File No. 1-6543, Exhibit 10(l)].
10(k)(2) - Lease Agreement between Ohio Power Company and JMG Funding,
Limited, dated January 20, 1995 [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(l) - 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 APCo for the fiscal year ended December 31, 1994,
File No. 1-3457, Exhibit 10(d)].
*13 - Copy of those portions of the AEP 1995 Annual Report (for the
fiscal year ended December 31, 1995) which are incorporated by
reference in this filing.
*21 - List of subsidiaries of AEP.
*23 - Consent of Deloitte & Touche LLP.
*24 - Power of Attorney.
*27 - Financial Data Schedules.
APCO
E-5
EXHIBIT NUMBER DESCRIPTION
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) - Composite copy of the Restated Articles of Incorporation of APCo,
as amended [Annual Report on Form 10-K of APCo for the fiscal year
ended December 31, 1994, File No. 1-3457, Exhibit 3(c)].
*3(d) - Copy of By-Laws of APCo (amended as of January 1, 1996).
4(a) - Copy of Mortgage and Deed of Trust, dated as of December 1, 1940,
between APCo and Bankers Trust Company and R. Gregory Page, as
Trustees, as amended and supplemented [Registration Statement No.
2-7289, Exhibit 7(b); Registration Statement No. 2-19884, Exhibit
2(1); Registration Statement No. 2-24453, Exhibit 2(n);
Registration Statement No. 2-60015, Exhibits 2(b)(2), 2(b)(3),
2(b)(4), 2(b)(5), 2(b)(6), 2(b)(7), 2(b)(8), 2(b)(9), 2(b)(10),
2(b)(12), 2(b)(14), 2(b)(15), 2(b)(16), 2(b)(17), 2(b)(18),
2(b)(19), 2(b)(20), 2(b)(21), 2(b)(22), 2(b)(23), 2(b)(24),
2(b)(25), 2(b)(26), 2(b)(27) and 2(b)(28); Registration Statement
No. 2-64102, Exhibit 2(b)(29); Registration Statement No. 2-66457,
Exhibits (2)(b)(30) and 2(b)(31); Registration Statement No. 2-
69217, Exhibit 2(b)(32); Registration Statement No. 2-86237,
Exhibit 4(b); Registration Statement No. 33-11723, Exhibit 4(b);
Registration Statement No. 33-17003, Exhibit 4(a)(ii),
Registration Statement No. 33-30964, Exhibit 4(b); Registration
Statement No. 33-40720, Exhibit 4(b); Registration Statement No.
33-45219, Exhibit 4(b); Registration Statement No. 33-46128,
Exhibits 4(b) and 4(c); Registration Statement No. 33-53410,
Exhibit 4(b); Registration Statement No. 33-59834, Exhibit 4(b);
Registration Statement No. 33-50229, Exhibits 4(b) and 4(c);
Registration Statement No. 33-58431, Exhibits 4(b), 4(c), 4(d) and
4(e); Registration Statement No. 333-01049, Exhibits 4(b) and
4(c); Form 8-K, dated March 18, 1996, File No. 1-3457, Exhibit 4].
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)
- --------------- -----------
+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)(A) -- AEP System Excess Benefit Plan, Amended and Restated as of
January 1, 2001 [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 2000, File No. 1-3525,
Exhibit 10(j)(1)(A)].
*+10(h)(1)(B) -- First Amendment to AEP System Excess Benefit Plan, dated as
of March 5, 2003.
+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)(1) -- 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(i)(2) -- Memorandum of agreement between Susan Tomasky and the
Service Corporation dated January 3, 2001 [Annual Report on
Form 10-K of AEP for the fiscal year ended December 31,
2000, File No. 1-3525, Exhibit 10(s)].
*+10(i)(3) -- Employment Agreement dated July 29, 1998 between AEPSC and
Robert P. Powers.
+10(j)(1) -- 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(j)(2) -- First Amendment to AEP System Survivor Benefit Plan, as
amended and restated effective January 31, 2000.
+10(k) -- AEP Senior Executive Severance Plan for Merger with Central
and South West Corporation, effective March 1, 1999[Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 1998, File No. 1-3525, Exhibit 10(o)].
+10(l) -- AEP Change In Control Agreement [Annual Report on Form 10-K
of AEP for the fiscal year ended December 31, 2001, File No.
1-3525, Exhibit 10(o)].
+10(m) -- AEP System 2000 Long-Term Incentive Plan [Proxy Statement of
AEP, March 10, 2000].
+10(n)(1) -- Central and South West System Special Executive Retirement
Plan as amended and restated effective July 1, 1997 [Annual
Report on Form 10-K of CSW for the fiscal year ended
December 31, 1998, File No. 1-1443, Exhibit 18].
+10(n)(2) -- Certified CSW Board Resolution of April 18, 1991 [Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 2001, File No. 1-3525, Exhibit 10(r)(2)].
+10(n)(3) -- CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW,
March 13, 1992].
*+10(o)(1) -- AEP System Incentive Compensation Deferral Plan dated
January 1, 2001.
*+10(o)(2) -- First Amendment to AEP System Incentive Compensation
Deferral Plan dated December 6, 2002.
*+10(p) -- AEP System Nuclear Performance Long Term Incentive
Compensation Plan dated August 1, 1998.
*+10(q) -- Nuclear Key Contributor Retention Plan dated May 1, 2000.
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the APCo 2002 Annual Report (for
the fiscal year ended December 31, 2002) 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, 2002, File No.
1-3525, Exhibit 21].
*23 -- Consent of Deloitte & Touche LLP
E-6
EXHIBIT NUMBER DESCRIPTION
- --------------- -----------
*24 -- Power of Attorney.
*99(a) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
*99(b) -- Certification of Chief Financial Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
CSPCO++
3(a) -- Copy of Amended Articles of Incorporation of CSPCo, as
amended to March 6, 1992 [Registration Statement No.
33-53377, Exhibit 4(a)].
3(b) -- Copy of Certificate of Amendment to Amended Articles of
Incorporation of CSPCo, dated May 19, 1994 [Annual Report on
Form 10-K of CSPCo for the fiscal year ended December 31,
1994, File No. 1-2680, Exhibit 3(b)].
3(c) -- Composite copy of Amended Articles of Incorporation of
CSPCo, as amended [Annual Report on Form 10-K of CSPCo for
the fiscal year ended December 31, 1994, File No. 1-2680,
Exhibit 3(c)].
3(d) -- Copy of Code of Regulations and By-Laws of CSPCo [Annual
Report on Form 10-K of CSPCo for the fiscal year ended
December 31, 1987, File No. 1-2680, Exhibit 3(d)].
4(a) -- Copy of Indenture of Mortgage and Deed of Trust, dated
September 1, 1940, between CSPCo and City Bank Farmers Trust
Company (now Citibank, N.A.), as trustee, as supplemented
and amended [Registration Statement No. 2-59411, Exhibits
2(B) and 2(C); Registration Statement No. 2-80535, Exhibit
4(b); Registration Statement No. 2-87091, Exhibit 4(b);
Registration Statement No. 2-93208, Exhibit 4(b);
Registration Statement No. 2-97652, Exhibit 4(b);
Registration Statement No. 33-7081, Exhibit 4(b);
Registration Statement No. 33-12389, Exhibit 4(b);
Registration Statement No. 33-19227, Exhibits 4(b), 4(e),
4(f), 4(g) and 4(h); Registration Statement No. 33-35651,
Exhibit 4(b); Registration Statement No. 33-46859, Exhibits
4(b) and 4(c); Registration Statement No. 33-50316, Exhibits
4(b) and 4(c); Registration Statement No. 33-60336, Exhibits
4(b), 4(c) and 4(d); Registration Statement No. 33-50447,
Exhibits 4(b) and 4(c); Annual Report on Form 10-K of CSPCo
for the fiscal year ended December 31, 1993, File No.
1-2680, Exhibit 4(b)].
4(b) -- Copy of Indenture (for unsecured debt securities), dated as
of September 1, 1997, between CSPCo and Bankers Trust
Company, as Trustee [Registration Statement No. 333-54025,
Exhibits 4(a), 4(b), 4(c) and 4(d); Annual Report on Form
10-K of CSPCo for the fiscal year ended December 31, 1998,
File No. 1-2680, Exhibits 4(c) and 4(d)].
10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between
OVEC and United States of America, acting by and through the
United States Atomic Energy Commission, and, subsequent to
January 18, 1975, the Administrator of the Energy Research
and Development Administration, as amended [Registration
Statement No. 2-60015, Exhibit 5(a); Registration Statement
No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No.
2-66301, Exhibit 5(a)(1)(C); Registration Statement No.
2-67728, Exhibit 5(a)(1)(B); Annual Report on Form 10-K of
APCo for the fiscal year ended December 31, 1989, File No.
1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form 10-K
of APCo for the fiscal year ended December 31, 1992, File
No. 1-3457, Exhibit 10(a)(1)(B)].
10(a)(2) -- Copy of Inter-Company Power Agreement, dated July 10, 1953,
among OVEC and the Sponsoring Companies, as amended
[Registration Statement No. 2-60015, Exhibit 5(c);
Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); and
Annual Report on Form 10-K of APCo for the fiscal year ended
December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)].
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 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 APCo for the fiscal
year ended December 31, 1994, File No. 1-3457, Exhibit 10(d)].
10(e)(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(e)(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)].
APCO (continued)
EXHIBIT NUMBER DESCRIPTION
10(f)(1)-Management Incentive Compensation Plan [Annual Report on Form
10-K of AEP for the fiscal year ended December 31, 1995, File No.
1-3525, Exhibit 10(i)(1)].
10(f)(2)-American Electric Power System Performance Share Incentive
Plan [Quarterly Report on Form 10-Q of APCo for the quarterly
period ended September 30, 1995, File No. 1-3457, Exhibit 10].
10(g)(1)-Excess Benefits Plan [Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1995, File No. 1-3525, Exhibit
10(g)(1)(A)].
10(g)(2)-AEP System Supplemental Savings Plan (Non-Qualified) [Annual
Report on Form 10-K of AEP for the fiscal year ended December 31,
1993, File No. 1-3525, Exhibit 10(g)(2)].
10(g)(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(h)(1)-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)].
*12 - Statement re: Computation of Ratios.
*13 - Copy of those portions of the APCo 1995 Annual Report (for the
fiscal year ended December 31, 1995) 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, 1995, File No. 1-3525,
Exhibit 21].
*23 - Consent of Deloitte & Touche LLP.
*24 - Power of Attorney.
*27 - Financial Data Schedules.
CSPCO
3(a) - Copy of Amended Articles of Incorporation of CSPCo, as amended to
March 6, 1992 [Registration Statement No. 33-53377, Exhibit 4(a)].
3(b) - Copy of Certificate of Amendment to Amended Articles of
Incorporation of CSPCo, dated May 19, 1994 [Annual Report on Form
10-K of CSPCo for the fiscal year ended December 31, 1994, File
No. 1-2680, Exhibit 3(b)].
3(c) - Composite copy of Amended Articles of Incorporation of CSPCo, as
amended [Annual Report on Form 10-K of CSPCo for the fiscal year
ended December 31, 1994, File No. 1-2680, Exhibit 3(c)].
3(d) - Copy of Code of Regulations and By-Laws of CSPCo [Annual Report on
Form 10-K of CSPCo for the fiscal year ended December 31, 1987,
E-7
EXHIBIT NUMBER DESCRIPTION
- --------------- -----------
10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among
APCo, CSPCo, KPCo, 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, KPCo, 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, KPCo, 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 2002 Annual Report (for
the fiscal year ended December 31, 2002) which are
incorporated by reference in this filing.
21 -- List of subsidiaries of CSPCo [Annual Report on Form 10-K of
AEP for the fiscal year ended December 31, 2002, File No.
1-3525, Exhibit 21]
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*99(a) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
*99(b) -- Certification of Chief Financial Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
I&M++
3(a) -- Copy of the Amended Articles of Acceptance of I&M and
amendments thereto [Annual Report on Form 10-K of I&M for
fiscal year ended December 31, 1993, File No. 1-3570,
Exhibit 3(a)].
3(b) -- Copy of Articles of Amendment to the Amended Articles of
Acceptance of I&M, dated March 6, 1997 [Annual Report on
Form 10-K of I&M for fiscal year ended December 31, 1996,
File No. 1-3570, Exhibit 3(b)].
3(c) -- Composite Copy of the Amended Articles of Acceptance of I&M
(amended as of March 7, 1997) [Annual Report on Form 10-K of
I&M for the fiscal year ended December 31, 1996, File No.
1-3570, Exhibit 3(c)].
3(d) -- Copy of the By-Laws of I&M (amended as of November 28, 2001)
[Annual Report on Form 10-K of I&M for the fiscal year ended
December 31, 2001, File No. 1-3570, Exhibit 3(d)].
4(a) - Copy of Indenture of Mortgage and Deed of Trust, dated September
1, 1940, between CSPCo and City Bank Farmers Trust Company (now
Citibank, N.A.), as trustee, as supplemented and amended
[Registration Statement No. 2-59411, Exhibits 2(B) and 2(C);
Registration Statement No. 2-80535, Exhibit 4(b); Registration
Statement No. 2-87091, Exhibit 4(b); Registration Statement No. 2-
93208, Exhibit 4(b); Registration Statement No. 2-97652, Exhibit
4(b); Registration Statement No. 33-7081, Exhibit 4(b);
Registration Statement No. 33-12389, Exhibit 4(b); Registration
Statement No. 33-19227, Exhibits 4(b), 4(e), 4(f), 4(g) and 4(h);
Registration Statement No. 33-35651, Exhibit 4(b); Registration
Statement No. 33-46859, Exhibits 4(b) and 4(c); Registration
Statement No. 33-50316, Exhibits 4(b) and 4(c); Registration
Statement No. 33-60336, Exhibits 4(b), 4(c) and 4(d); Registration
Statement No. 33-50447, Exhibits 4(b) and 4(c); Annual Report on
Form 10-K of CSPCo for the fiscal year ended December 31, 1993,
File No. 1-2680, Exhibit 4(b)].
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)].
E-8
CSPCO (continued)
EXHIBIT NUMBER DESCRIPTION
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 Interim Allowance Agreement [Annual Report on Form 10-K of
APCo for the fiscal year ended December 31, 1994, File No. 1-3457,
Exhibit 10(d)].
*12 - Statement re: Computation of Ratios.
*13 - Copy of those portions of the CSPCo 1995 Annual Report (for the
fiscal year ended December 31, 1995) which are incorporated by
reference in this filing.
*23 - Consent of Deloitte & Touche LLP.
*24 - Power of Attorney.
*27 - Financial Data Schedules.
I&M
3(a) - Copy of the Amended Articles of Acceptance of I&M and amendments
thereto [Annual Report on Form 10-K of I&M for fiscal year ended
December 31, 1993, File No. 1-3570, Exhibit 3(a)].
3(b) - Composite Copy of the Amended Articles of Acceptance of I&M, as
amended [Annual Report on Form 10-K of I&M for fiscal year ended
December 31, 1993, File No. 1-3570, Exhibit 3(b)].
*3(c) - Copy of the By-Laws of I&M (amended as of January 1, 1996).
4(a) - Copy of Mortgage and Deed of Trust, dated as of June 1, 1939,
between I&M and Irving Trust Company (now The Bank of New York)
and various individuals, as Trustees, as amended and supplemented
[Registration Statement No. 2-7597, Exhibit 7(a); Registration
Statement No. 2-60665, Exhibits 2(c)(2), 2(c)(3), 2(c)(4),
2(c)(5), 2(c)(6), 2(c)(7), 2(c)(8), 2(c)(9), 2(c)(10), 2(c)(11),
2(c)(12), 2(c)(13), 2(c)(14), 2(c)(15), (2)(c)(16), and 2(c)(17);
Registration Statement No. 2-63234, Exhibit 2(b)(18); Registration
Statement No. 2-65389, Exhibit 2(a)(19); Registration Statement
No. 2-67728, Exhibit 2(b)(20); Registration Statement No. 2-85016,
Exhibit 4(b); Registration Statement No. 33-5728, Exhibit 4(c);
Registration Statement No. 33-9280, Exhibit 4(b); Registration
Statement No. 33-11230, Exhibit 4(b); Registration Statement No.
33-19620, Exhibits 4(a)(ii), 4(a)(iii), 4(a)(iv) and 4(a)(v);
Registration Statement No. 33-46851, Exhibits 4(b)(i), 4(b)(ii)
and 4(b)(iii); Registration Statement No. 33-54480, Exhibits
4(b)(i) and 4(b)(ii); Registration Statement No. 33-60886, Exhibit
4(b)(i); Registration Statement No. 33-50521, Exhibits 4(b)(i),
4(b)(ii) and 4(b)(iii); Annual Report on Form 10-K of I&M for
fiscal year ended December 31, 1993, File No. 1-3570, Exhibit
4(b); Annual Report on Form 10-K of I&M for fiscal year ended
December 31, 1994, File No. 1-3570, Exhibit 4(b)].
10(a)(1) - Copy of Power Agreement, dated October 15, 1952, between OVEC and
United States of America, acting by and through the United States
Atomic Energy Commission, and, subsequent to January 18, 1975, the
Administrator of the Energy Research and Development
Administration, as amended [Registration Statement No. 2-60015,
Exhibit 5(a); Registration Statement No. 2-63234, Exhibit
5(a)(1)(B); Registration Statement No. 2-66301, Exhibit
5(a)(1)(C); Registration Statement No. 2-67728, Exhibit
5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year
ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and
Annual Report on Form 10-K of APCo for the fiscal year ended
December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)].
10(a)(2) - Copy of Inter-Company Power Agreement, dated as of July 10, 1953,
among OVEC and the Sponsoring Companies, as amended [Registration
Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-
67728, Exhibit 5(a)(3)(B); Annual Report on Form 10-K of APCo for
the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit
10(a)(2)(B)].
10(a)(3) - Copy of Power Agreement, dated July 10, 1953, between OVEC and
Indiana-Kentucky Electric Corporation, as amended [Registration
Statement No. 2-60015, Exhibit 5(e)].
I&M (continued)
EXHIBIT NUMBER DESCRIPTION
10(b) - Copy of Interconnection Agreement, dated July 6, 1951, between
APCo, CSPCo, KEPCo,
EXHIBIT NUMBER DESCRIPTION
- --------------- -----------
4(a) -- Copy of Mortgage and Deed of Trust, dated as of June 1,
1939, between I&M and Irving Trust Company (now The Bank of
New York) and various individuals, as Trustees, as amended
and supplemented [Registration Statement No. 2-7597, Exhibit
7(a); Registration Statement No. 2-60665, Exhibits 2(c)(2),
2(c)(3), 2(c)(4), 2(c)(5), 2(c)(6), 2(c)(7), 2(c)(8),
2(c)(9), 2(c)(10), 2(c)(11), 2(c)(12), 2(c)(13), 2(c)(14),
2(c)(15), (2)(c)(16), and 2(c)(17); Registration Statement
No. 2-63234, Exhibit 2(b)(18); Registration Statement No.
2-65389, Exhibit 2(a)(19); Registration Statement No.
2-67728, Exhibit 2(b)(20); Registration Statement No.
2-85016, Exhibit 4(b); Registration Statement No. 33-5728,
Exhibit 4(c); Registration Statement No. 33-9280, Exhibit
4(b); Registration Statement No. 33-11230, Exhibit 4(b);
Registration Statement No. 33-19620, Exhibits 4(a)(ii),
4(a)(iii), 4(a)(iv) and 4(a)(v); Registration Statement No.
33-46851, Exhibits 4(b)(i), 4(b)(ii) and 4(b)(iii);
Registration Statement No. 33-54480, Exhibits 4(b)(I) and
4(b)(ii); Registration Statement No. 33-60886, Exhibit
4(b)(I); Registration Statement No. 33-50521, Exhibits
4(b)(I), 4(b)(ii) and 4(b)(iii); Annual Report on Form 10-K
of I&M for the fiscal year ended December 31, 1993, File No.
1-3570, Exhibit 4(b); Annual Report on Form 10-K of I&M for
the fiscal year ended December 31, 1994, File No. 1-3570,
Exhibit 4(b); Annual Report on Form 10-K of I&M for the
fiscal year ended December 31, 1996, File No. 1-3570,
Exhibit 4(b)].
4(b) -- Copy of Indenture (for unsecured debt securities), dated as
of October 1, 1998, between I&M and The Bank of New York, as
Trustee [Registration Statement No. 333-88523, Exhibits
4(a), 4(b) and 4(c); Registration Statement No. 333-58656,
Exhibits 4(b) and 4(c); Annual Report of Form 10-K of I&M
for fiscal year ended December 31, 2001, File No. 1-3570,
Exhibit 4(c)].
*4(c) -- Copy of Company Order and Officer's Certificate, dated
November 22, 2002 establishing certain terms of the 6%
Senior Notes, Series D, due 2032.
4(d) -- Copy of Company Order and Officers' Certificate, dated
December 12, 2001, establishing certain terms of the 6.125%
Notes, Series C, due 2006. [Annual Report on Form 10-K of
I&M for the fiscal year ended December 31, 2001, File No.
1-3570, Exhibit 4(c)].
10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between
OVEC and United States of America, acting by and through the
United States Atomic Energy Commission, and, subsequent to
January 18, 1975, the Administrator of the Energy Research
and Development Administration, as amended [Registration
Statement No. 2-60015, Exhibit 5(a); Registration Statement
No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No.
2-66301, Exhibit 5(a)(1)(C); Registration Statement No.
2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of
APCo for the fiscal year ended December 31, 1989, File No.
1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form 10-K
of APCo for the fiscal year ended December 31, 1992, File
No. 1-3457, Exhibit 10(a)(1)(B)].
10(a)(2) -- Copy of Inter-Company Power Agreement, dated as of July 10,
1953, among OVEC and the Sponsoring Companies, as amended
[Registration Statement No. 2-60015, Exhibit 5(c);
Registration Statement No. 2-67728, Exhibit 5(a)(3)(B);
Annual Report on Form 10-K of APCo for the fiscal year ended
December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)].
10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC
and Indiana-Kentucky Electric Corporation, as amended
[Registration Statement No. 2-60015, Exhibit 5(e)].
10(a)(4) -- Copy of Inter-Company Power Agreement, dated as of July 10,
1953, among OVEC and the Sponsoring Companies, as amended
[Registration Statement No. 2-60015, Exhibit 5(c);
Registration Statement No. 2-67728, Exhibit 5(a)(3)(B);
Annual Report on Form 10-K of APCo for the fiscal year ended
December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)].
10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among
APCo, CSPCo, KPCo, 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,
E-9
EXHIBIT NUMBER DESCRIPTION
- --------------- -----------
10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among
APCo, CSPCo, I&M, KPCo, 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, KPCo, 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 2002 Annual Report (for
the fiscal year ended December 31, 2002) 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, 2002, File No.
1-3525, Exhibit 21].
*24 -- Power of Attorney.
*99(a) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
*99(b) -- Certification of Chief Financial Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
KPCO++
3(a) -- Copy of Restated Articles of Incorporation of KPCo [Annual
Report on Form 10-K of KPCo for the fiscal year ended
December 31, 1991, File No. 1-6858, Exhibit 3(a)].
3(b) -- Copy of By-Laws of KPCo (amended as of June 15, 2000)
[Annual Report on Form 10-K of KPCo for the fiscal year
ended December 31, 2000, File No. 1-6858, Exhibit 3(b)].
4(a) -- Copy of Mortgage and Deed of Trust, dated May 1, 1949,
between KPCo and Bankers Trust Company (now Deutsche Bank
Trust Company Americas, 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 KPCo and Bankers Trust
Company, as Trustee [Registration Statement No. 333-75785,
Exhibits 4(a), 4(b), 4(c) and 4(d); Registration Statement
No. 333-87216, Exhibits 4E) and 4(f).
*4(c) -- Copy of Company Order and Officer's Certificate, dated June
28, 2002 establishing certain terms of the 5.50% Senior
Notes, Series A, due 2007.
E-10
EXHIBIT NUMBER DESCRIPTION
- --------------- -----------
*4(d) -- Copy of Company Order and Officer's Certificate, dated
November 6, 2002 establishing certain terms of the 4.3148%
Senior Notes, Series B, due 2007.
*4(e) -- Copy of Company Order and Officer's Certificate, dated
December 12, 2002 establishing certain terms of the 4.368%
Senior Notes, Series C, due 2007.
10(a) -- Copy of Interconnection Agreement, dated July 6, 1951, among
APCo, CSPCo, KPCo, 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, KPCo, 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, KPCo, 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
KPCo dated December 15, 1999, File No. 1-6858, Exhibit 10].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the KPCo 2002 Annual Report (for
the fiscal year ended December 31, 2002) which are
incorporated by reference in this filing.
*23 -- Consent of Deloitte & Touche LLP
*24 -- Power of Attorney.
*99(a) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
*99(b) -- Certification of Chief Financial Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
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) -- Copy of 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) -- Copy of Certificate of Amendment to Amended Articles of
Incorporation of OPCo, dated June 3, 2002 [Quarterly Report
on Form 10-Q of OPCo for the quarter ended June 30, 2002,
File No. 1-6543, Exhibit 3(d)].
3(e) -- Composite copy of the Amended Articles of Incorporation of
OPCo (amended as of June 3, 2002) [[Quarterly Report on Form
10-Q of OPCo for the quarter ended June 30, 2002, File No.
1-6543, Exhibit 3(e)].
10(d) - Copy of Interim Allowance Agreement [Annual Report on Form 10-K of
APCo for the fiscal year ended December 31, 1994,
E-11
EXHIBIT NUMBER DESCRIPTION
- --------------- -----------
3(f) -- Copy of Code of Regulations of OPCo [Annual Report on Form
10-K of OPCo for the fiscal year ended December 31, 1990,
File No. 1-6543, Exhibit 3(d)].
4(a) -- Copy of Mortgage and Deed of Trust, dated as of October 1,
1938, between OPCo and Manufacturers Hanover Trust Company
(now Chemical Bank), as Trustee, as amended and supplemented
[Registration Statement No. 2-3828, Exhibit B-4;
Registration Statement No. 2-60721, Exhibits 2(c)(2),
2(c)(3), 2(c)(4), 2(c)(5), 2(c)(6), 2(c)(7), 2(c)(8),
2(c)(9), 2(c)(10), 2(c)(11), 2(c)(12), 2(c)(13), 2(c)(14),
2(c)(15), 2(c)(16), 2(c)(17), 2(c)(18), 2(c)(19), 2(c)(20),
2(c)(21), 2(c)(22), 2(c)(23), 2(c)(24), 2(c)(25), 2(c)(26),
2(c)(27), 2(c)(28), 2(c)(29), 2(c)(30), and 2(c)(31);
Registration Statement No. 2-83591, Exhibit 4(b);
Registration Statement No. 33-21208, Exhibits 4(a)(ii),
4(a)(iii) and 4(a)(iv); Registration Statement No. 33-31069,
Exhibit 4(a)(ii); Registration Statement No. 33-44995,
Exhibit 4(a)(ii); Registration Statement No. 33-59006,
Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(iv); Registration
Statement No. 33-50373, Exhibits 4(a)(ii), 4(a)(iii) and
4(a)(iv); Annual Report on Form 10-K of OPCo for the fiscal
year ended December 31, 1993, File No. 1-6543, Exhibit
4(b)].
4(b) -- Copy of Indenture (for unsecured debt securities), dated as
of September 1, 1997, between OPCo and Bankers Trust Company
(now Deutsche Bank Trust Company Americas), as Trustee
[Registration Statement No. 333-49595, Exhibits 4(a), 4(b)
and 4(c); Annual Report on Form 10-K of OPCo for the fiscal
year ended December 31, 1998, File No. 1-6543, Exhibits 4(c)
and 4(d); Annual Report on Form 10-K of OPCo for the fiscal
year ended December 31, 1999, File No. 1-6543, Exhibits 4(c)
and 4(d); Annual Report on Form 10-K of OPCo for the fiscal
year ended December 31, 2000, File No. 1-6543, Exhibit
4(c)].
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, KPCo, 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, KPCo, 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, KPCo, OPCo and the Service Corporation [Annual Report
on Form 10-K of AEP for the fiscal year ended December 31,
1996, File No. 1-3525, Exhibit 10(l)].
10(e) - Copy of 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)
E-12
EXHIBIT NUMBER DESCRIPTION
- --------------- -----------
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) -- AEP System Senior Officer Annual Incentive Compensation Plan
[Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)].
+10(i)(1)(A) -- AEP System Excess Benefit Plan, Amended and Restated as of
January 1, 2001 [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 2000, File No. 1-3525,
Exhibit 10(j)(1)(A)].
*+10(i)(1)(B) -- First Amendment to AEP System Excess Benefit Plan, dated as
of March 5, 2003.
+10(i)(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(i)(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(j)(1) -- 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)(2) -- Memorandum of agreement between Susan Tomasky and the
Service Corporation dated January 3, 2001 [Annual Report on
Form 10-K of AEP for the fiscal year ended December 31,
2000, File No. 1-3525, Exhibit 10(s)].
*+10(j)(3) -- Employment Agreement dated July 29, 1998 between AEPSC and
Robert P. Powers.
+10(k)(1) -- 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)(2) -- First Amendment to AEP System Survivor Benefit Plan, as
amended and restated effective January 31, 2000.
+10(l) -- 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(m) -- AEP Change In Control Agreement [Annual Report on Form 10-K
of AEP for the fiscal year ended December 31, 2001, File No.
1-3525, Exhibit 10(o)].
+10(n) -- AEP System 2000 Long-Term Incentive Plan [Proxy Statement of
AEP, March 10, 2000].
+10(o)(1) -- Central and South West System Special Executive Retirement
Plan as amended and restated effective July 1, 1997 [Annual
Report on Form 10-K of CSW for the fiscal year ended
December 31, 1998, File No. 1-1443, Exhibit 18].
+10(o)(2) -- Certified CSW Board Resolution of April 18, 1991 [Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 2001, File No. 1-3525, Exhibit 10(r)(2)].
+10(o)(3) -- CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW,
March 13, 1992].
*+10(p)(1) -- AEP System Incentive Compensation Deferral Plan dated
January 1, 2001.
E-13
EXHIBIT NUMBER DESCRIPTION
- --------------- -----------
*+10(p)(2) -- First Amendment to AEP System Incentive Compensation
Deferral Plan dated December 6, 2002.
*+10(q) -- AEP System Nuclear Performance Long Term Incentive
Compensation Plan dated August 1, 1998.
*+10(r) -- Nuclear Key Contributor Retention Plan dated May 1, 2000.
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the OPCo 2002 Annual Report (for
the fiscal year ended December 31, 2002) 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, 2002, File No.
1-3525, Exhibit 21].
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*99(a) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
*99(b) -- Certification of Chief Financial Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
PSO++
3(a) -- Restated Certificate of Incorporation of PSO [Annual Report
on Form U5S of Central and South West Corporation for the
fiscal year ended December 31, 1996, File No. 1-1443,
Exhibit B-3.1].
3(b) -- By-Laws of PSO (amended as of June 28, 2000) [Annual Report
on Form 10-K of PSO for the fiscal year ended December 31,
2000, File No. 0-343, Exhibit 3(b)].
4(a) -- Indenture, dated July 1, 1945, between 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].
10(f) - Copy of Lease Agreements, dated as of December 1, 1989, between
I&M and Wilmington Trust Company, as amended [Registration
Statement No. 33-32753, Exhibits 28(a)(1)(C), 28(a)(2)(C),
28(a)(3)(C), 28(a)(4)(C), 28(a)(5)(C) and 28(a)(6)(C); Annual
Report on Form 10-K of I&M for the fiscal year ended December 31,
1993, File No. 1-3570, Exhibits 10(e)(1)(B), 10(e)(2)(B),
10(e)(3)(B), 10(e)(4)(B), 10(e)(5)(B) and 10(e)(6)(B)
E-14
EXHIBIT NUMBER DESCRIPTION
- --------------- -----------
(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 [Registration Statement No. 333-100623, Exhibits
4(a) and 4(b)].
*4(d) -- Second Supplemental Indenture, dated as of November 26, 2002
establishing certain terms of the 6% Senior Notes, Series B,
due 2032.
*10(a) -- Copy of Restated and Amended Operating Agreement, dated as
of January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC.
*10(b) -- Transmission Coordination Agreement, dated October 29, 1998,
among PSO, TCC, TNC, SWEPCo and AEPSC.
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the PSO 2002 Annual Report (for
the fiscal year ended December 31, 2002) which are
incorporated by reference in this filing.
21 -- List of subsidiaries of PSO [Annual Report on Form 10-K of
AEP for the fiscal year ended December 31, 2002, File No.
1-3525, Exhibit 21]
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*99(a) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
*99(b) -- Certification of Chief Financial Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
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].
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].
*12 - Statement re: Computation of Ratios
*13 - Copy of those portions of the I&M 1995 Annual Report (for the
fiscal year ended December 31, 1995) 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, 1995,
E-15
EXHIBIT NUMBER DESCRIPTION
- --------------- -----------
(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 [Registration Statement No. 333-87834, Exhibits
4(a) and 4(b); Form 8-K of SWEPCo filed on June 26, 2002,
File No. 1-3146, Exhibit 4(b)].
*10(a) -- Copy of Restated and Amended Operating Agreement, dated as
of January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC.
*10(b) -- Transmission Coordination Agreement, dated October 29, 1998,
among PSO, TCC, TNC, SWEPCo and AEPSC.
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the SWEPCo 2002 Annual Report (for
the fiscal year ended December 31, 2002) which are
incorporated by reference in this filing.
21 -- List of subsidiaries of SWEPCo [Annual Report on Form 10-K
of AEP for the fiscal year ended December 31, 2002, File No.
1-3525, Exhibit 21]
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*99(a) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
*99(b) -- Certification of Chief Financial Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
TCC++
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 TCC for the
quarter ended March 31, 1997, File No. 0-346, Exhibit 3.1].
*3(b) -- Articles of Amendment to Restated Articles of Incorporation
of TCC dated December 18, 2002.
3(c) -- By-Laws of TCC (amended as of April 19, 2000) [Annual Report
on Form 10-K of TCC for the fiscal year ended December 31,
2000, File No. 0-346, Exhibit 3(b)].
4(a) -- Indenture of Mortgage or Deed of Trust, dated November 1,
1943, between TCC and The First National Bank of Chicago and
R. D. Manella, as Trustees, as amended and supplemented
[Registration Statement No. 2-60712, Exhibit 5.01;
Registration Statement No. 2-62271, Exhibit 2.02; Form U-1
No. 70-7003, Exhibit 17; Registration Statement No. 2-98944,
Exhibit 4 (b); Form U-1 No. 70-7236, Exhibit 4; Form U-1 No.
70-7249, Exhibit 4; Form U-1 No. 70-7520, Exhibit 2; Form
U-1 No. 70-7721, Exhibit 3; Form U-1 No. 70-7725, Exhibit
10; Form U-1 No. 70-8053, Exhibit 10 (a); Form U-1 No.
70-8053, Exhibit 10 (b); Form U-1 No. 70-8053, Exhibit 10
(c); Form U-1 No. 70-8053, Exhibit 10 (d); Form U-1 No.
70-8053, Exhibit 10 (e); Form U-1 No. 70-8053, Exhibit 10
(f)].
4(b) -- TCC-obligated, mandatorily redeemable preferred securities
of subsidiary trust holding solely Junior Subordinated
Debentures of TCC:
(1) Indenture, dated as of May 1, 1997, between TCC and the
Bank of New York, as Trustee [Quarterly Report on Form 10-Q
of TCC dated March 31, 1997, File No. 0-346, Exhibits
4.1 and 4.2].
*23 - Consent of Deloitte & Touche LLP.
*24 - Power of Attorney.
*27 - Financial Data Schedules.
KEPCO
3(a) - Copy of Restated Articles of Incorporation of KEPCo [Annual Report
on Form 10-K of KEPCo for the fiscal year ended December 31, 1991,
File No. 1-6858, Exhibit 3(a)].
*3(b) - Copy of By-Laws of KEPCo (amended as of January 1, 1996).
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)].
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 Interim Allowance Agreement [Annual Report on Form 10-K of
APCo for the fiscal year ended December 31, 1994, File No. 1-3457,
Exhibit 10(d)].
*12
E-16
EXHIBIT NUMBER DESCRIPTION
- --------------- -----------
(2) Amended and Restated Trust Agreement of TCC Capital I,
dated as of May 1, 1997, among TCC, 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 TCC dated
March 31, 1997, File No. 0-346, Exhibit 4.3].
(3) Guarantee Agreement, dated as of May 1, 1997, delivered
by TCC for the benefit of the holders of TCC Capital I's
Preferred Securities [Quarterly Report on Form 10-Q of
TCC 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 TCC and TCC Capital I [Quarterly Report on
Form 10-Q of TCC 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 TCC and The Bank of New York, as
Trustee, as amended and supplemented [Annual Report on Form
10-K of TCC for the fiscal year ended December 31, 2000,
File No. 0-346, Exhibits 4(c), 4(d) and 4(e)].
*10(a) -- Copy of Restated and Amended Operating Agreement, dated as
of January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC.
*10(b) -- Transmission Coordination Agreement, dated October 29, 1998,
among PSO, TCC, TNC, SWEPCo and AEPSC.
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the TCC 2002 Annual Report (for
the fiscal year ended December 31, 2002) which are
incorporated by reference in this filing.
21 -- List of subsidiaries of TCC [Annual Report on Form 10-K of
AEP for the fiscal year ended December 31, 2002, File No.
1-3525, Exhibit 21]
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*99(a) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
*99(b) -- Certification of Chief Financial Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
TNC++
3(a) -- Restated Articles of Incorporation, as amended, and Articles
of Amendment to the Articles of Incorporation [Annual Report
on Form 10-K of TNC for the fiscal year ended December 31,
1996, File No. 0-340, Exhibit 3.5].
*3(b) -- Articles of Amendment to Restated Articles of Incorporation
of TNC dated December 17, 2002.
3(c) -- By-Laws of TNC (amended as of May 1, 2000) [Quarterly Report
on Form 10-Q of TNC for the quarter ended March 31, 2000,
File No. 0-340, Exhibit 3.4].
4(a) -- Indenture, dated August 1, 1943, between TNC 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)].
*10(a) -- Copy of Restated and Amended Operating Agreement, dated as
of January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC.
*10(b) -- Transmission Coordination Agreement, dated October 29, 1998,
among PSO, TCC, TNC, SWEPCo and AEPSC.
*12 -- Statement re: Computation of Ratios.
*13 - Copy those portions of the KEPCo 1995 Annual Report (for the
fiscal year ended December 31, 1995) which are incorporated by
reference in this filing.
*23 - Consent of Deloitte & Touche LLP.
*24 - Power of Attorney.
*27 - Financial Data Schedules.
E-17
OPCO
EXHIBIT NUMBER DESCRIPTION
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) - Composite copy of the Amended Articles of Incorporation of OPCo,
as amended [Annual Report on Form 10-K of OPCo for the fiscal year
ended December 31, 1994, File No. 1-6543, Exhibit 3(c)].
3(d) - Copy of Code of Regulations of OPCo [Annual Report on Form 10-K of
OPCo for the fiscal year ended December 31, 1990, File No. 1-6543,
Exhibit 3(d)].
4(a) - Copy of Mortgage and Deed of Trust, dated as of October 1, 1938,
between OPCo and Manufacturers Hanover Trust Company (now Chemical
Bank), as Trustee, as amended and supplemented [Registration
Statement No. 2-3828, Exhibit B-4; Registration Statement No. 2-
60721, Exhibits 2(c)(2), 2(c)(3), 2(c)(4), 2(c)(5), 2(c)(6),
2(c)(7), 2(c)(8), 2(c)(9), 2(c)(10), 2(c)(11), 2(c)(12), 2(c)(13),
2(c)(14), 2(c)(15), 2(c)(16), 2(c)(17), 2(c)(18), 2(c)(19),
2(c)(20), 2(c)(21), 2(c)(22), 2(c)(23), 2(c)(24), 2(c)(25),
2(c)(26), 2(c)(27), 2(c)(28), 2(c)(29), 2(c)(30), and 2(c)(31);
Registration Statement No. 2-83591, Exhibit 4(b); Registration
Statement No. 33-21208, Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(vi);
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)].
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, between
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 Interim Allowance Agreement [Annual Report on Form 10-K of
APCo for the fiscal year ended December 31, 1994, File No. 1-3457,
Exhibit 10(d)].
10(e) - Copy of Agreement, dated June 18, 1968, between OPCo and Kaiser
Aluminum & Chemical Corporation (now known as Ravenswood Aluminum
Corporation) and First Supplemental Agreement thereto
[Registration Statement No. 2-31625, Exhibit 4(c); Annual Report
on Form 10-K of OPCo for the fiscal year ended December 31, 1986,
File No. 1-6543, Exhibit 10(d)(2)].
10(f) - Copy of Power Agreement, dated November 16, 1966, between OPCo and
Ormet Generating Corporation and First Supplemental Agreement
thereto [Annual Report on Form 10-K of OPCo for the fiscal year
ended December 31, 1993, File No. 1-6543, Exhibit 10(e)].
10(g) - 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
OPCO (continued)
EXHIBIT NUMBER DESCRIPTION
on Form 10-K of OPCo for the fiscal year ended December 31, 1993,
File No. 1-6543, Exhibit 10(f)].
10(h)(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(h)(2)-Amendment to AEP Deferred Compensation Agreement for certain
executive officers [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1986, File No. 1-3525, Exhibit
10(d)(2)].
10(i)(1)-Management Incentive Compensation Plan [Annual Report on Form
10-K of AEP for the fiscal year ended December 31, 1995, File No.
1-3525, Exhibit 10(i)(1)].
10(i)(2)-American Electric Power System Performance Share Incentive
Plan, as Amended and Restated through January 1, 1995 [Quarterly
Report on Form 10-Q of OPCo for the quarterly period ended
September 30, 1995, File No. 1-6543].
10(j)(1)-Excess Benefits Plan [Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1995, File No. 1-3525, Exhibit
10(g)(1)(A)].
10(j)(2)-AEP System Supplemental Savings Plan (Non-Qualified) [Annual
Report on Form 10-K of AEP for the fiscal year ended December 31,
1993, File No. 1-3525, Exhibit 10(g)(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)(1)-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)(2)].
10(l)(1) - Agreement for Lease dated as of September 17, 1992 between JMG
Funding, Limited Partnership and OPCo [Annual Report on Form 10-K
of OPCo for the fiscal year ended December 31, 1992, File No. 1-
6543, Exhibit 10(l)].
10(l)(2) - 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)].
*12 - Statement re: Computation of Ratios.
*13 - Copy of those portions of the OPCo 1995 Annual Report (for the
fiscal year ended December 31, 1995) 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, 1995, File No. 1-3525,
Exhibit 21].
*23 - Consent of Deloitte & Touche LLP.
*24 - Power of Attorney.
*27 - Financial Data Schedules.
EXHIBIT NUMBER DESCRIPTION
- --------------- -----------
*13 -- Copy of those portions of the TNC 2002 Annual Report (for
the fiscal year ended December 31, 2002) which are
incorporated by reference in this filing.
*24 -- Power of Attorney.
*99(a) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
*99(b) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
----------------------
++ 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.
EX-3
2
APCO 10-K EX. 3(D)
Exhibit 3(d)
APPALACHIAN POWER COMPANY
BY-LAWS
As Amended January 1, 1996
APPALACHIAN POWER COMPANY
BY-LAWS
Section 1. The annual meeting of the shareholders of the
corporation for the election of directors and for the transaction
of such other corporate business as may properly come before said
meeting shall be held at the main office of the corporation, in the
City of Roanoke, Virginia, or at such other place within or without
the Commonwealth of Virginia as shall be specified in the notice,
or waiver of notice, of such meeting, on the fourth Tuesday of
April in each year, or on such other day as shall be specified in
the notice, or waiver of notice, of such meeting. (As amended
1/26/67)
Section 2. Special meetings of the shareholders of the
corporation may be held upon the call of the Chairman of the Board
or of the Board of Directors or Executive Committee, or of
shareholders holding one-tenth of the then outstanding capital
stock entitled to vote, at such time and at such place within or
without the Commonwealth of Virginia as may be stated in the call
and notice of any such special meeting. (As amended 1/31/80)
Section 3. Notice of the time, place and purpose of every
meeting of shareholders shall be mailed by the Secretary or the
officer performing his duties at least ten days before the meeting
to each shareholder of record entitled to vote, at his last known
post office address, but meetings may be held without notice if all
shareholders entitled to vote are present or if notice is waived
before or after the meeting by those not present. No shareholders
shall be entitled to notice of any meeting of shareholders with
respect to any shares registered in his name after the date upon
which notice of such meeting is required by law or by these by-laws
to have been mailed or otherwise given to shareholders.
Section 4. The holders of a majority of the stock of the
corporation entitled to vote, present in person or by proxy, shall
constitute a quorum, but less than a quorum shall have power to
adjourn.
At all meetings of shareholders, each shareholder entitled to
vote may vote and otherwise act either in person or by proxy.
Section 5. Meetings of shareholders shall be presided over by
the Chairman of the Board, or, in his absence, by the President,
or, in the absence of both, by a Vice President, or, if none of
such officers is present, by a Chairman to be elected at the
meeting. The Secretary of the corporation shall act as Secretary
of such meeting if present. In his absence the Chairman may
appoint a Secretary. (As amended 1/31/80)
Section 6. The stock of the corporation shall be transferable
or assignable on the books of the corporation by the holders in
person or by attorney on the surrender of the certificate therefor
duly endorsed. Certificates of stock shall be in such form and
executed in such manner as may be prescribed by law and the Board
of Directors. The Board of Directors may appoint one or more
transfer agents and registrars for the stock.
The Board of Directors are hereby authorized to fix in advance
a date not less than ten nor more than fifty days preceding the
date of any meeting of shareholders, or the date for the payment of
any dividend, or the date for the allotment of rights, or the date
when any change or conversion or exchange of capital stock shall go
into effect, as a record for the determination of the shareholders
entitled to notice of and to vote at any such meeting, or entitled
to receive payment of any such dividend, or any such allotment of
rights, or to exercise the rights in respect to any such change,
conversion or exchange of capital stock, and in such case only
shareholders of record on the date so fixed shall be entitled to
such notice of and to vote at such meeting, or to receive payment
of such dividend, or allotment of rights, or exercise such rights,
as the case may be, and notwithstanding any transfer of any stock
on the books of the corporation after such record date fixed as
aforesaid. (As amended 2/25/71)
Section 7. The directors shall be elected at the annual
meeting of shareholders or as soon thereafter as practicable and
shall hold office for one year or until their successors are
elected and qualify. It shall not be necessary to be a shareholder
in order to be a director. The shareholders may remove any
director at any time without cause assigned and fill the vacancy at
a meeting called for the purpose of considering such action. Any
vacancy in the Board of Directors not caused by such removal may be
filled by the Board at any meeting. (As amended 1/29/81 )
Section 8. Meetings of the Board of Directors shall be held
at the time fixed by resolution of the Board or upon call of the
Chairman of the Board, the President or a Vice President and may be
held at any place within or without the State of Virginia. The
Secretary or officer performing his duties shall give reasonable
notice (which need not exceed two days) of all meetings of
directors, provided that a meeting may be held without notice
immediately after the annual election, and notice need not be given
of regular meetings held at times fixed by resolution of the Board.
Meetings may be held at any time without notice if all the
directors are present or if those not present waive notice either
before or after the meeting. Notice by mail or telegraph to the
usual business or residence address of the director shall be
sufficient. A majority of the Board of Directors in office shall
constitute a quorum. Less than such a quorum shall have power to
adjourn any meeting from time to time without notice.
Section 9. The Board of Directors as soon as may be after
their election in each year may appoint an Executive Committee to
consist of the Chairman of the Board and such number of directors
as the Board may from time to time determine. Such Committee shall
have and may exercise during the intervals between meetings of the
Board all the powers vested in the Board except the power to fill
vacancies in the Board, the power to change the membership of or
fill vacancies in said Committee and the power to change the by-
laws. The Board shall have the power at any time to change the
membership of such Committee and to fill vacancies in it. The
Executive Committee may make rules for the conduct of its business
and may appoint such committees and assistants as it may deem
necessary. A majority of the members of said Committee shall
constitute a quorum. The Chairman of the Board shall be the
Chairman of the Executive Committee. During the intervals between
the meetings of the Executive Committee the Chairman of said
Committee shall possess and may exercise such of the powers vested
in the Executive Committee as from time to time may be conferred
upon him by resolution of the Board of Directors or the Executive
Committee. (As amended 1/31/80)
Section 10. The Board of Directors, as soon as may be
convenient after the election of directors in each year, shall
elect from among their number a Chairman of the Board and shall
also elect a President, one or more Vice Presidents, a Secretary
and a Treasurer and shall, from time to time, elect such other
officers as they may deem proper. The same person may be elected
to more than one office. (As amended 12/19/90)
Section 11. The term of office of all officers shall be until
the next election of directors and until their respective
successors are chosen and qualify, but any officer may be removed
from office at any time by the Board of Directors. Vacancies in the
offices shall be filled by the Board of Directors.
Section 12. The officers of the corporation shall have such
duties as usually pertain to their offices except as modified by
the Board of Directors, and shall also have such powers and duties
as may from time to time be conferred upon them by the Board of
Directors.
Section 13. The Board of Directors are authorized to select
such depositaries as they shall deem proper for the funds of the
corporation. All checks and drafts against such deposited funds
shall be signed by officers or persons to be specified by the Board
of Directors.
Section 14. The corporate seal of the corporation shall be in
such form as the Board of Directors shall prescribe.
Section 15. A director of this corporation shall not be
disqualified by his office from dealing or contracting with the
corporation either as a vendor, purchaser or otherwise, nor shall
any transaction or contract of this corporation be void or voidable
by reason of the fact that any director or any firm of which any
director is a member or any corporation of which any director is a
shareholder or director, is in any way interested in such
transaction on contract, provided that such transaction or contract
is or shall be authorized, ratified or approved either (1) by a
vote of a majority of a quorum of the Board of Directors or of the
Executive Committee without counting in such majority or quorum any
director so interested or member of a firm so interested or a
shareholder or director of a corporation so interested, or (2) by
vote at any shareholders' meeting of the holders of record of a
majority of all the outstanding shares for stock of this
corporation entitled to vote or by writing or writings signed by a
majority of such holders; nor shall any director be liable to
account to this corporation for any profits realized by him from or
through any such transaction, or contract of this corporation
authorized, ratified or approved as aforesaid by reason of the fact
that he or any firm of which he is a member or any corporation of
which he is a shareholder or director, was interested in such
transaction or contract. Nothing herein contained shall create any
liability in the events above described or prevent the
authorization, ratification or approval of such contracts in any
other manner provided by law; nor shall anything herein be
considered as in any way affecting the rights of the corporation or
of any person interested, on account of any fraud in connection
with any such transaction.
Section 16. (1) Definitions. In this Section 16:
(a) "expenses" includes, without limitation, counsel
fees;
(b) "employee" shall include, without limitation, any
employee, including any professionally licensed
employee of the corporation. Such term shall also
include, without limitation, any employee,
including any professionally licensed employee of a
subsidiary or affiliate of the corporation who is
acting on behalf of the corporation;
(c) "liability" means the obligation to pay a judgment,
settlement, penalty, fine, including any excise tax
assessed with respect to any employee benefit plan,
or reasonable expenses incurred with respect to a
proceeding;
(d) "official capacity" means, (i) when used with
respect to a director, the office of director in
the corporation; or (ii) when used with respect to
an individual other than a director, the office in
the corporation held by the officer or the
employment or agency relationship undertaken by the
employee or agent on behalf of the corporation.
"Official capacity" does not include service for
any other foreign or domestic corporation or any
partnership, joint venture, trust, employee benefit
plan, or other enterprise whether at the request of
the corporation or otherwise;
(e) "party" includes an individual who was, is, or is
threatened to be made a named defendant or
respondent in a proceeding;
(f) "proceeding" means any threatened, pending, or
completed action, suit, or proceeding, whether
civil, criminal, administrative or investigative
and whether formal or informal, including all
appeals.
(2) Indemnification. The corporation shall indemnify any
person who was or is a party to any proceeding by reason of the
fact that such person is or was a director, officer or employee of
the corporation, or any subsidiary or affiliate of the corporation
or is or was serving at the request of the corporation as a
director, trustee, partner, officer, employee, or agent of another
foreign or domestic corporation, partnership, joint venture, trust,
employee benefit plan or other enterprise, against any liability
incurred by such person in connection with such proceeding if (a)
such person conducted him or herself in good faith; and (b) such
person believed, in the case of conduct in his or her official
capacity, that his or her conduct was in the best interests of the
corporation, and in all other cases that his or her conduct was at
least not opposed to its best interests; and (c) in the case of any
criminal proceeding, such person had no reasonable cause to believe
his or her conduct was unlawful; and (d) such person was not
grossly negligent or guilty of willful misconduct. Indemnification
required under this Section 16 in connection with a proceeding by
or in the right of the corporation is limited to reasonable
expenses incurred in connection with the proceeding. A person is
considered to be serving an employee benefit plan at the
corporation's request if such person's duties to the corporation
also impose duties on, or otherwise involve services by, such
person to the plan or to participants in or beneficiaries of the
plan. A person's conduct with respect to an employee benefit plan
for a purpose such person believed to be in the interests of the
participants and beneficiaries of the plan is conduct that
satisfies the requirements of this Section 16. The termination of
any proceeding by judgment, order, settlement, conviction, or upon
a plea of nolo contendere or its equivalent, shall not of itself
create a presumption that the standard of conduct described in this
subsection (2) has not been met.
(3) Limitations upon indemnification. Notwithstanding the
provisions of subsection (2) of this Section 16, no indemnification
shall be made in connection with: (a) any proceeding by or in the
right of the corporation in which the person seeking
indemnification was adjudged liable to the corporation; or (b) any
proceeding charging any person with improper benefit to him or
herself, whether or not involving action in such person's official
capacity, in which such person was adjudged liable on the basis
that personal benefit was improperly received by such person.
(4) Determination and Authorization of Indemnification. In
any case in which a director, officer or employee of the
corporation requests indemnification, upon such person's request,
the Board of Directors shall meet within sixty (60) days thereof to
determine whether such person is eligible for indemnification in
accordance with the applicable standards of conduct set forth in
subsections (2) and (3) of this Section 16. Such determination
shall be made as follows:
(a) By the Board of Directors by a majority vote of a
quorum consisting of directors not at the time
parties to the proceeding;
(b) If a quorum cannot be obtained under paragraph (a)
of this subsection (4), by majority vote of a
committee duly designated by the Board of Directors
(in which designation directors who are parties may
participate), consisting of two or more directors
not at the time parties to the proceeding;
(c) By special legal counsel;
(i) Selected by the Board of Directors or its
committee in the manner prescribed in
paragraphs (a) or (b) of this subsection (4);
or
(ii) If a quorum of the Board of Directors cannot
be obtained under paragraph (a) of this
subsection (4) and a committee cannot be
designated under paragraph (b) of this
subsection (4), selected by majority vote of
the full Board of Directors, in which
selection directors who are parties may
participate; or
(d) By the shareholders, but shares owned by or voted
under the control of directors, officers or
employees who are at the time parties to the
proceeding may not be voted on the determination;
or
(e) By the Chairman of the Board if the person seeking
indemnification is neither a director nor an
officer of the corporation.
Authorization of indemnification and evaluation as to
reasonableness of expenses shall be made in the same manner as the
determination that indemnification is permissible, except that if
the determination is made by special legal counsel, authorization
of indemnification and evaluation as to reasonableness of expenses
shall be made by those entitled under paragraph (c) of this
subsection (4) to elect counsel.
(5) Advancement of Expenses. To the fullest extent permitted
by law, the corporation shall promptly advance expenses as they are
incurred by any person who is a party to any proceeding, whether by
or in the right of the corporation or otherwise, by reason of the
fact that such person is or was a director, officer or employee of
the corporation or of any subsidiary or affiliate of the
corporation, or is or was serving at the request of the corporation
as a director, trustee, partner, officer, or employee of another
corporation, partnership, joint venture, trust, employee benefit
plan or other enterprise, upon request of such person and receipt
of an undertaking by or on behalf of such director, officer or
employee to repay amounts advanced to the extent that it is
ultimately determined that such person was not eligible for
indemnification in accordance with the standards set forth in
subsections (2) and (3) of this Section 16.
(6) Contract Rights: Non-exclusivity of Indemnification:
Contractual Indemnification. The foregoing provisions of this
Section 16 shall be deemed to be a contract between the corporation
and each director, officer or employee of the corporation, or its
subsidiaries, or affiliates, and any modification or repeal of this
Section 16 or such provisions of the Code of Virginia shall not
diminish any rights or obligations existing prior to such
modification or repeal with respect to any proceeding theretofore
or thereafter brought; provided, however, that the right of
indemnification provided in this Section 16 shall not be deemed
exclusive of any other rights to which any director, officer or
employee of the corporation may now be or hereafter become entitled
apart from this Section 16, under any applicable law including the
Code of Virginia. Irrespective of the provisions of this Section
16, the Board of Directors may, at any time from time to time,
approve indemnification of directors, officers, employees or agents
to the full extent permitted by the Code of Virginia at the time in
effect, whether on account of past or future actions or
transactions. Notwithstanding the foregoing, the corporation shall
enter into such additional contracts providing for indemnification
and advancement of expenses with directors, officers or employees
of the corporation or its subsidiaries or affiliates as the Board
of Directors shall authorize, provided that the terms of any such
contract shall be consistent with the provisions of the Code of
Virginia.
(7) Miscellaneous Provisions. The indemnification provided
by this Section 16 shall be limited with respect to directors,
officers and controlling persons to the extent provided in any
undertaking entered into by the corporation or its subsidiaries or
affiliates, as required by the Securities and Exchange Commission
pursuant to any rule or regulation of the Securities and Exchange
Commission now or hereafter in effect.
The corporation may purchase and maintain insurance on
behalf of any person described in this Section 16 against any
liability which may be asserted against such person whether or not
the corporation would have the power to indemnify such person
against such liability under the provisions of this Section 16.
Every reference in this Section 16 to directors, officers
or employees shall include former directors, officers and employees
and their respective heirs, executors and administrators.
If any provision of this Section 16 shall be found
to be invalid or limited in application by reason of any law,
regulation or proceeding, it shall not affect any other provision
of the validity of the remaining provisions hereof.
The provisions of this Section 16 shall be applicable to
claims, actions, suits or proceedings made, commenced or pending
after the adoption hereof, whether arising from acts or omissions
to act occurring before or after the adoption hereof. (As amended
4/21/87)
Section 17. These by-laws may at any time be amended or added
to or any part thereof repealed by affirmative vote of a majority
of a quorum of the Board of Directors given at a duly convened
meeting of the Board of Directors, the notice of which includes
notice of the proposed amendment, addition or repeal.
Section 18. The Board of Directors shall be seven in number.
The directors need not be shareholders. A majority of the
directors shall constitute a quorum for the transaction of
business. (As amended 1/1/96)
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