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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------------
FORM 10-K
----------------
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 2003
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 For the transition period from __________ to_________
Commission Registrants; States of Incorporation; I.R.S. Employer
File Number Address and Telephone Number Identification Nos.
1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation) 13-4922640
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) 716-1000
Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. Yes [X]. No. [ ]
Indicate by check mark if disclosure of delinquent filers with respect to
American Electric Power Company, Inc. pursuant to Item 405 of Regulation S-K
(229.405 of this chapter) is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
Indicate by check mark if disclosure of delinquent filers with respect to
Appalachian Power Company, Indiana Michigan Power Company or Ohio Power Company
pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not
contained herein, and will not be contained, to the best of registrant's
knowledge, in definitive proxy or information statements of Appalachian Power
Company or Ohio Power Company incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K. [X]
Indicate by check mark whether American Electric Power Company, Inc. is 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, 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 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, $6.50 par value.............New York Stock Exchange
Power Company, Inc. 9.25% Equity Units........................New York Stock Exchange
Appalachian Power Company None
Columbus Southern Power None
Company
CPL Capital I 8.00% Cumulative Quarterly Income
Preferred Securities, Series A, Liquidation
Preference $25 per Preferred Security.....New York Stock Exchange
Indiana Michigan Power
Company 6% Senior Notes, Series D, Due 2032.......New York Stock Exchange
Kentucky Power Company None
Ohio Power Company 7 3/8% Senior Notes, Series A, Due 2038...New York Stock Exchange
Public Service Company of 6% Senior Notes, Series B, Due 2032.......New York Stock Exchange
Oklahoma
PSO Capital I 8.00% Trust Originated Preferred
Securities, Series A, Liquidation
Preference $25 per Preferred Security.....New York Stock Exchange
Southwestern Electric Power None
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 30, 2003 December 31, 2003
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. $11,782,905,274 395,016,421
($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. owns, directly or indirectly, all of
the common stock of 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, 2003:
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 2004 Annual Meeting of Shareholders,
to be filed within 120 days after December 31, 2003
Portions of Information Statements of the following Part III
companies for 2004 Annual Meeting of Shareholders, to
be filed within 120 days after December 31, 2003:
Appalachian Power Company
Ohio Power Company
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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 Southwestern 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, including
AEP's Principles of Business Conduct (which also serves as a code of ethics
applicable to Item 10 of this Form 10-K), certain committee charters and
Principles of Corporate Governance. 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
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................... 29
Executive Officers of the Registrants............................................ 30
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities................................. 31
Item 6. Selected Financial Data............................................... 31
Item 7. Management's Financial Discussion and Analysis and Financial Condition 32
Item 7A. Quantitative and Qualitative Disclosures About Market Risk............ 32
Item 8. Financial Statements and Supplementary Data........................... 32
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.................................................. 32
Item 9A. Controls and Procedures............................................... 32
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........................ 36
Item 14. Principal Accountant Fees and Services................................ 36
PART IV
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K...... 37
Signatures.......................................................................... 39
Index to Financial Statement Schedules.............................................. S-1
Independent Auditors' Report........................................................ S-2
Exhibit Index....................................................................... E-1
GLOSSARY OF TERMS
The following abbreviations or acronyms used in this Form 10-K are defined
below:
Abbreviation or Acronym Definition
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.
ALJ........................... Administrative law judge
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 public utility
subsidiaries................ 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
KPSC.......................... Kentucky Public Service Commission
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.
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, anelectric 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
SO2........................... Sulfur dioxide
SO2 Allowance................. An allowance to emit one ton of sulfur dioxide granted under the Clean Air Act
Amendments of 1990
SPP........................... Southwest Power Pool
STPNOC........................ STP Nuclear Operating Company, a non-profit Texas corporation which operates STP
on behalf of its joint owners, including 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
Virginia Act.................. Virginia electric restructuring legislation
VSCC.......................... Virginia State Corporation Commission
WVPSC......................... West Virginia Public Service Commission
West zone public utility
subsidiaries................ PSO, SWEPCo, TCC and TNC
FORWARD-LOOKING INFORMATION
These reports made by AEP and its registrant subsidiaries contain
forward-looking statements within the meaning of Section 21E of the
Securities Exchange Act of 1934. Although AEP and its registrant 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
forward-looking statements are:
o Electric load and customer growth.
o Weather conditions.
o Available sources and costs of fuels.
o Availability of generating capacity and the performance of AEP's
generating plants.
o The ability to recover regulatory assets and stranded costs in connection
with deregulation.
o New legislation and government regulation including requirements for
reduced emissions of sulfur, nitrogen, carbon and other substances.
o Resolution of pending and future rate cases, negotiations and other
regulatory decisions (including rate or other recovery for environmental
compliance).
o Oversight and/or investigation of the energy sector or its participants.
o Resolution of litigation (including pending Clean Air Act enforcement
actions and disputes arising from the bankruptcy of Enron Corp.)
o AEP's ability to reduce its operation and maintenance costs.
o The success of disposing of investments that no longer match AEP's
corporate profile.
o AEP's ability to sell assets at attractive prices and on other attractive
terms.
o International and country-specific developments affecting foreign
investments including the disposition of any current foreign investments.
o The economic climate and growth in AEP's service territory and changes in
market demand and demographic patterns.
o Inflationary trends.
o AEP's ability to develop and execute on a point of view regarding prices
of electricity, natural gas, and other energy-related commodities.
o Changes in the creditworthiness and number of participants in the energy
trading market.
o Changes in the financial markets, particularly those affecting the
availability of capital and AEP's ability to refinance existing debt at
attractive rates.
o Actions of rating agencies, including changes in the ratings of debt and
preferred stock.
o Volatility and changes in markets for electricity, natural gas, and other
energy-related commodities.
o Changes in utility regulation, including the establishment of a regional
transmission structure.
o Accounting pronouncements periodically issued by accounting
standard-setting bodies.
o The performance of AEP's pension plan.
o Prices for power that we generate and sell at wholesale.
o Changes in technology and other risks and unforeseen events, including
wars, the effects of terrorism (including increased security costs),
embargoes and other catastrophic events.
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 under
PUHCA that owns, directly or indirectly, all of the outstanding common stock of
its public utility subsidiaries and varying percentages of other subsidiaries.
The service areas of AEP's public utility subsidiaries cover 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 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 public 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. Restructuring 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 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 and transportation and handling of fuel. The member companies of the
AEP System also obtain certain accounting, administrative, information systems,
engineering, financial, legal, maintenance and other services at cost from a
common provider, AEPSC.
At December 31, 2003, the subsidiaries of AEP had a total of 22,075
employees. AEP, because it is a holding company rather than an operating
company, has no employees. The public utility subsidiaries of AEP are:
APCo (organized in Virginia in 1926) is engaged in the generation,
transmission and distribution of electric power to approximately 929,000
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 other market participants. At
December 31, 2003, APCo and its wholly owned subsidiaries had 2,371
employees. Among the principal industries served by APCo are coal mining,
primary metals, chemicals and textile mill products. In addition to its AEP
System interconnections, APCo also is interconnected with the following
unaffiliated utility companies: Carolina Power & Light Company, Duke Energy
Corporation and Virginia Electric and Power 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.
CSPCo (organized in Ohio in 1937, the earliest direct predecessor company
having been organized in 1883) is engaged in the generation, transmission and
distribution of electric power to approximately 698,000 retail customers in
Ohio, and in supplying and marketing electric power at wholesale to other
electric utilities, municipalities and other market participants. At December
31, 2003, CSPCo had 1,125 employees. CSPCo's service area is comprised of two
areas in Ohio, which include portions of twenty-five counties. One area
includes the City of Columbus and the other is a predominantly rural area in
south central Ohio. Among the principal industries served are food
processing, chemicals, primary metals, electronic machinery and paper
products. In addition to its AEP System interconnections, CSPCo also is
interconnected with the following unaffiliated utility companies: CG&E, DP&L
and Ohio Edison Company.
I&M (organized in Indiana in 1925) is engaged in the generation,
transmission and distribution of electric power to approximately 575,000
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 other
market participants. At December 31, 2003, I&M had 2,634 employees. Among the
principal industries served are primary metals, transportation equipment,
electrical and electronic machinery, fabricated metal products, rubber and
miscellaneous plastic products and chemicals and allied products. Since 1975,
I&M has leased and operated the assets of the municipal system of the City of
Fort Wayne, Indiana. In addition to its AEP System interconnections, I&M also
is interconnected with the following unaffiliated utility companies: Central
Illinois Public Service Company, CG&E, Commonwealth Edison Company, Consumers
Energy Company, Illinois Power Company, Indianapolis Power & Light Company,
Louisville Gas and Electric Company, Northern Indiana Public Service Company,
PSI Energy Inc. and Richmond Power & Light Company.
KPCo (organized in Kentucky in 1919) is engaged in the generation,
transmission and distribution of electric power to approximately 175,000
retail customers in an area in eastern Kentucky, and in supplying and
marketing electric power at wholesale to other electric utility companies,
municipalities and other market participants. At December 31, 2003, KPCo had
394 employees. In addition to its AEP System interconnections, KPCo also is
interconnected with the following unaffiliated utility companies: Kentucky
Utilities Company and East Kentucky Power Cooperative Inc. KPCo is also
interconnected with TVA.
Kingsport Power Company (organized in Virginia in 1917) provides electric
service to approximately 46,000 retail customers in Kingsport and eight
neighboring communities in northeastern Tennessee. Kingsport Power Company
does not own any generating facilities. It purchases electric power from APCo
for distribution to its customers. At December 31, 2003, Kingsport Power
Company had 57 employees.
OPCo (organized in Ohio in 1907 and re-incorporated in 1924) is engaged in
the generation, transmission and distribution of electric power to
approximately 704,000 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 other market participants. At December 31, 2003, OPCo had
2,153 employees. Among the principal industries served by OPCo are primary
metals, rubber and plastic products, stone, clay, glass and concrete
products, petroleum refining and chemicals. In addition to its AEP System
interconnections, OPCo also is interconnected with the following unaffiliated
utility companies: CG&E, The Cleveland Electric Illuminating Company, DP&L,
Duquesne Light Company, Kentucky Utilities Company, Monongahela Power
Company, Ohio Edison Company, The Toledo Edison Company and West Penn Power
Company.
PSO (organized in Oklahoma in 1913) is engaged in the generation,
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, 2003, PSO had 1,067 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 439,000
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, 2003, SWEPCo had 1,351 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 711,000 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 participants. At December 31, 2003,
TCC had 1,203 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 190,000 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, 2003, TNC had 472 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 does not
own any generating facilities. It purchases electric power from OPCo for
distribution to its customers. At December 31, 2003, Wheeling Power Company
had 57 employees.
AEGCo (organized in Ohio in 1982) is an electric generating company. AEGCo
sells power at wholesale to I&M and KPCo. AEGCo has no employees.
Service Company 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, 2003, AEPSC had 6,215 employees.
Classes of Service
The principal classes of service from which the public utility subsidiaries
of AEP derive revenues and the amount of such revenues during the year ended
December 31, 2003 are as follows:
AEP
System(a) APCo CSPCo I&M KPCo
(in thousands)
Utility Operations:
Retail Sales
Residential.............. $3,171,000 $ 623,435 $ 509,919 $ 352,710 $120,001
Commercial............... 2,348,000 321,515 455,304 272,319 68,904
Industrial............... 1,977,000 342,593 133,242 319,783 94,567
Other Retail Sales....... 173,000 41,060 17,975 6,154 926
---------- --------- --------- --------- --------
Total Retail.......... 7,669,000 1,328,603 1,116,440 950,966 284,398
Wholesale
System Sales and
Transmission............... 2,554,000 311,056 183,490 337,275 69,451
Other Wholesale Revenues. - - - - -
Risk Management Realized. 205,000 17,391 10,491 11,440 4,038
Risk Management Mark-
to-Market ............ (198,000) (2,249) (5,134) - -
---------- --------- --------- --------- --------
Total Wholesale......... 2,561,000 326,198 188,847 348,715 73,489
Other Operating Revenues... 745,000 79,583 42,195 46,712 18,775
Sales to Affiliates........ - 222,793 84,369 249,203 39,808
---------- --------- --------- --------- --------
Gross Utility Operations 10,975,000 1,957,177 1,431,851 1,595,596 416,470
Provision for Rate Refund.. (104,000) 181 - - -
----------- --------- --------- --------- --------
Net Utility Operations 10,871,000 1,957,358 1,431,851 1,595,596 416,470
Investments- Gas Operations.. 3,097,000 - - - -
Investments- Other........... 577,000 - - - -
---------- --------- --------- --------- --------
Total Revenues........ $14,545,000 $1,957,358 $1,431,851 $1,595,596 $416,470
=========== ========== ========== ========== ========
OPCo PSO SWEPCo TCC TNC
(in thousands)
Utility Operations:
Retail Sales
Residential.............. $ 474,323 $ 402,988 $ 350,386 $ 215,330 $ 57,191
Commercial............... 314,526 275,852 291,859 158,307 28,395
Industrial............... 522,449 231,638 215,805 43,469 8,199
Other Retail Sales....... 8,413 83,491 6,478 8,824 11,484
---------- --------- --------- --------- ---------
Total Retail.......... 1,319,711 993,969 864,528 425,930 105,269
Wholesale
System Sales and
Transmission............... 263,397 61,173 147,885 894,509 279,973
Other Wholesale Revenues. - - - - -
Risk Management Realized. 13,882 3,667 4,325 26,331 9,590
Risk Management
Mark-to-Market......... (11,381) - 3,439 2,801 911
----------- --------- --------- --------- ---------
Total Wholesale....... 265,898 64,840 155,649 923,641 290,474
Other Operating Revenues... 74,766 20,883 66,373 339,696 39,292
Sales to Affiliates........ 584,278 23,130 68,854 141,698 51,625
---------- --------- --------- --------- ---------
Gross Utility Operations 2,244,653 1,102,822 1,155,404 1,830,965 486,660
Provision for Rate Refund.. - - (8,562) (83,454) (20,714)
---------- --------- ---------- ---------- ----------
Net Utility Operations 2,244,653 1,102,822 1,146,842 1,747,511 465,946
Investments- Gas Operations.. - - - - -
Investments- Other........... - - - - -
---------- --------- --------- --------- ---------
Total Revenues...........$2,244,653 $1,102,822$1,146,842 $1,747,511 $ 465,946
========== ==================== ========== =========
- ----------
(a) Includes revenues of other subsidiaries not shown. Intercompany transactions
have been eliminated, including AEGCo's total revenues of $233,165,000 for
the year ended December 31, 2003, all of which resulted from its wholesale
business, including its marketing and trading of power.
Holding Company Regulation
The provisions of PUHCA, administered by the SEC, regulate many aspects of a
registered holding company system, such as the AEP System. PUHCA limits the
operations of a registered holding company system 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 utility assets and intra-system
transactions.
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.
The Division of Investment Management of the SEC has recommended the
conditional repeal of PUHCA. Under its recommendation, certain oversight
authority would be transferred to the FERC. Legislation has since been
introduced in numerous sessions of Congress that would repeal PUHCA, 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 four wholly owned public utility subsidiaries of
CSW--PSO, SWEPCo, TCC and TNC--became indirect wholly owned public utility
subsidiaries of AEP as a result of the merger. The merger was approved by the
FERC and the 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 SEC 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 PUHCA and
expects the matter to be resolved favorably.
Financing
General
Companies within the AEP System generally use short-term debt to finance
working capital needs, acquisitions and construction. The companies periodically
issue long-term debt to reduce short-term debt. Short-term debt has in recent
history been provided by AEP's commercial paper program and revolving credit
facilities. Proceeds were made available to subsidiaries under the AEP corporate
borrowing program. Throughout 2003, AEP was successful in accessing the
commercial paper market. 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, 2003, 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. See Management's Financial
Discussion and Analysis of Results of Operations, included in the 2003 Annual
Reports, under the heading entitled Financial Condition for additional
information with respect to AEP's credit agreements.
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
In 2003, the rating agencies conducted credit reviews of AEP and its
registrant subsidiaries. The agencies also reviewed many companies in the energy
sector due to issues that impact the entire industry.
Moody's completed its review of AEP and its rated subsidiaries in February
2003. 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 placed AEP and its rated
subsidiaries on stable outlook.
S&P completed its review of AEP and its rated subsidiaries in March 2003. 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 placed AEP and its
rated subsidiaries on stable outlook.
Fitch completed its review of AEP and its rated subsidiaries in March 2003.
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 placed AEP and its rated subsidiaries on stable
outlook.
See Management's Financial Discussion and Analysis of Results of Operations,
included in the 2003 Annual Reports, 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:
o The CAA and CAAA and state laws and regulations (including State
Implementation Plans) that require compliance, obtaining permits and
reporting as to air emissions. See Management's Financial Discussion and
Analysis of Results of Operations under the heading entitled The Current
Air Quality Regulatory Framework.
o 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 Financial Discussion and
Analysis of Results of Operations under the headings entitled The Current
Air Quality Regulatory Framework and New Source Review Litigation and Note
9 to the consolidated financial statements entitled Commitments and
Contingencies, included in the 2003 Annual Reports, for further
information.
o Rules issued by the EPA and certain states that require substantial
reductions in SO2, mercury and NOx emissions, some of which became
effective in 2003. The remaining compliance dates and proposals would take
effect periodically through as late as 2018. AEP is installing (or has
installed) emission control technology and is taking other measures to
comply with required reductions. See Management's Financial Discussion and
Analysis of Results of Operations under the headings entitled Future
Reduction Requirements for NOx, SO2 and Hg and Estimated Air Quality
Investments and Note 7 to the consolidated financial statements entitled
Commitments and Contingencies, included in the 2003 Annual Reports under
the heading entitled NOx Reductions for further information.
o 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
Financial Discussion and Analysis of Results of Operations, included in the
2003 Annual Reports, under the heading entitled Superfund and State
Remediation for further information.
o The Federal Clean Water Act, which prohibits the discharge of pollutants
into waters of the United States except pursuant to appropriate permits.
The EPA recently adopted a new Clean Water Act rule to reduce the number of
fish and other aquatic organisms killed at once-through cooled power
plants. See Management's Financial Discussion and Analysis of Results of
Operations, included in the 2003 Annual Reports, under the heading entitled
Clean Water Act Regulation for additional information.
o 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. See Management's
Financial Discussion and Analysis of Results of Operations, included in the 2003
Annual Reports, under the heading entitled Environmental Matters for information
on current environmental issues.
If our expenditures for pollution control technologies, replacement
generation and associated operating costs are not recoverable from customers
through regulated rates (in regulated jurisdictions) or market prices (in
deregulated jurisdictions), those costs could adversely affect future results of
operations and cash flows, and possibly financial condition.
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 resulted in a
significant reduction in the estimated economic life of those facilities. See
also Investments--UK Operations for a discussion of AEP's planned disposition of
these assets in 2004.
The cost of complying with applicable environmental laws, regulations and
rules is expected to be material to the AEP System.
See Management's Financial Discussion and Analysis of Results of Operations
under the heading entitled Environmental Matters and Note 7 to the consolidated
financial statements entitled Commitments and Contingencies, included in the
2003 Annual Reports, for further information with respect to environmental
matters.
Environmental Investments
Investments related to improving AEP System plants' environmental performance
and compliance with air and water quality standards during 2002 and 2003 and the
current estimate for 2004 are shown below. Substantial investments in addition
to the amounts set forth below are expected 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. Future investments could be
significantly greater if litigation regarding whether AEP properly installed
emission control equipment on its plants is resolved against any AEP
subsidiaries or emissions reduction requirements are accelerated or otherwise
become more onerous. See Management's Financial Discussion and Analysis of
Results of Operations under the headings entitled Future Reduction Requirements
for NOx, SO2 and Hg and Estimated Air Quality Investments Note 7 to the
consolidated financial statements, entitled Commitments and Contingencies,
included in the 2003 Annual Reports, for more information regarding this
litigation and environmental expenditures in general.
2002 2003 2004
Actual Actual Estimate
(in thousands)
AEGCo....................... $ 1,200 11,800 9,800
APCo........................ 108,400 70,600 145,500
CSPCo....................... 25,400 31,400 18,000
I&M......................... 1,200 14,900 12,100
KPCo........................ 110,600 40,500 3,500
OPCo........................ 110,300 40,000 108,400
PSO......................... 1,200 1,700 0
SWEPCo...................... 3,400 3,200 2,700
TCC......................... 600 500 0
TNC......................... 1,900 2,600 800
-------- -------- --------
AEP System.................. $364,200 $217,200 $300,800
======== ======== ========
Electric and Magnetic Fields
EMF are 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 are created by electricity flowing in
transmission and distribution lines, electrical equipment, household wiring, and
appliances.
A number of studies in the past several years have examined the possibility
of adverse health effects from EMF. While some of the epidemiological studies
have indicated some association between exposure to EMF and health effects, none
has produced any conclusive evidence that EMF does or does not cause adverse
health effects.
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 customers.
SEC Subpoena, CFTC Complaint ant Other Energy Market Investigations
AEP received data requests, subpoenas and information requests from the SEC,
CFTC and other state and federal governmental agencies relating to certain
energy market investigations. On September 30, 2003, the CFTC filed a complaint
against AEP in federal district court alleging that it provided false or
misleading information about market conditions and prices of natural gas in an
attempt to manipulate the price of natural gas. See Management's Financial
Discussion and Analysis of Results of Operations, included in the 2003 Annual
Reports, under the heading Energy Market Investigations.
Utility Operations
General
Utility operations constitute the majority of AEP's business operations.
Utility operations include (i) the generation, transmission and distribution of
electric power to retail customers and (ii) the supplying and marketing of
electric power at wholesale (through the electric generation function) to other
electric utility companies, municipalities and other market participants. AEPSC,
as agent for AEP's public utility subsidiaries performs marketing, generation
dispatch, fuel procurement and power-related risk management and trading
activities.
Electric Generation
Facilities
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 sales of certain of AEP's generating facilities.
Pursuant to regulatory orders, the AEP public utility subsidiaries operate their
generating facilities as a single interconnected and coordinated electric
utility system. See Item 2 -- Properties for more information regarding AEP's
generation capacity.
AEP Power Pool and CSW Operating Agreement
APCo, CSPCo, I&M, KPCo and OPCo are parties 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 Interconnection
Agreement has been approved by the FERC.
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, 2003, the member-load ratios were as
follows:
Peak
Demand Member-Load
(MW) Ratio (%)
APCo............... 6,873 31.7
CSPCo.............. 3,871 17.9
I&M................ 4,243 19.6
KPCo............... 1,564 7.2
OPCo............... 5,121 23.6
Although the FERC has approved CSPCo's and OPCo's request to withdraw from
the AEP Power Pool as part of its order approving the settlement agreements and
AEP's FERC restructuring application, CSPCo and OPCo plan to remain functionally
separated through at least December 31, 2008 as provided by their rate
stabilization plan filed with the PUCO. See Management's Financial Discussion
and Analysis and Financial Condition, under the heading entitled Corporate
Separation, included in the 2003 Annual Reports and Note 6 to the consolidated
financial statements, entitled Customer Choice and Industry Restructuring,
included in the 2003 Annual Reports, for a discussion of AEP's corporate
separation plan.
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, 2001, 2002 and 2003:
2001 2002 2003
--------- --------- -------
(in thousands)
APCo............... $ 256,700 $ 127,000 $ 218,000
CSPCo.............. 251,200 267,000 276,800
I&M................ (166,200) (113,600) (118,800)
KPCo............... 27,600 46,500 38,400
OPCo............... (369,300) (326,900) (414,400)
PSO, SWEPCo, TCC, TNC, and AEPSC are parties to a Restated and Amended
Operating Agreement originally dated as of January 1, 1997 (CSW Operating
Agreement), which has been approved by the FERC. The CSW Operating Agreement
requires the west zone public utility subsidiaries to maintain adequate 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 public utility subsidiaries as capacity commitments. Parties are
compensated for energy delivered to recipients based upon the deliverer's
incremental cost plus a portion of the recipient's savings realized by the
purchaser that avoids the use of more costly alternatives. Revenues and costs
arising from third party sales are shared based on the amount of energy each
west zone public utility subsidiary contributes that is sold to third parties.
Upon the sale of its generation assets, TCC will no longer supply generating
capacity under the CSW Operating Agreement.
The following table shows the net (credits) or charges allocated among the
parties under the CSW Operating Agreement during the years ended December 31,
2001, 2002 and 2003:
2001 2002 2003
-------- -------- ------
(in thousands)
PSO................. $ 6,500 $ 53,700 $ 44,000
SWEPCo.............. (62,300) (67,800) (46,600)
TCC................. 13,500 (15,400) (29,500)
TNC................. 42,300 29,500 32,100
Power generated by or allocated or provided under the Interconnection
Agreement or CSW Operating Agreement to any public utility subsidiary is
primarily 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 Regulation -- Rates.
Under both the Interconnection Agreement and CSW Operating Agreement, power
generated that is not needed to serve the native load of any public utility
subsidiary is sold in the wholesale market by AEPSC on behalf of the generating
subsidiary. See Risk Management and Trading for a discussion of the trading and
marketing of such power.
AEP's System Integration Agreement, which has been approved by the FERC,
provides for the integration and coordination of AEP's east and west zone
operating subsidiaries. This includes joint dispatch of generation within the
AEP System and the distribution, between the two zones, of costs and benefits
associated with the transfers of power between the two zones (including sales to
third parties and risk management and trading activities). 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.
Risk Management and Trading
AEPSC, as agent for AEP's public utility subsidiaries, sells excess power
into the market and engages in power and natural gas risk management and trading
activities focused in regions in which AEP traditionally operates. These
activities primarily involve the purchase and sale of electricity (and to a
lesser extent, natural gas) under physical forward contracts at fixed and
variable prices. These contracts include physical transactions, over-the-counter
swaps and exchange-traded futures and options. The majority of physical forward
contracts are typically settled by entering into offsetting contracts. These
transactions are executed with numerous counterparties or on exchanges.
Counterparties and exchanges may require cash or cash related instruments to be
deposited on these transactions as margin against open positions. As of December
31, 2003, counterparties have posted approximately $45 million in cash, cash
equivalents or letters of credit with AEPSC for the benefit of AEP's public
utility subsidiaries. Since open trading contracts are valued based on changes
in market power prices, exposures change daily.
Fuel Supply
The following table shows the sources of power generated by the AEP System:
2001 2002 2003
Coal.......................... 74% 78% 80%
Natural Gas................... 12% 8% 7%
Nuclear....................... 11% 11% 9%
Hydroelectric and other....... 3% 3% 4%
Variations in the generation of nuclear power are primarily related to
refueling and maintenance outages. Variations in the generation of natural gas
power are primarily related to the availability of cheaper alternatives to
fulfill certain power requirements and the deactivation of certain gas-fired
plants owned by TCC and TNC.
Coal and Lignite: AEP's public utility subsidiaries 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. Management believes, but cannot provide assurances that,
AEP's public utility subsidiaries will be able to secure coal and lignite of
adequate quality and in adequate quantities to operate their coal and
lignite-fired units. See Investments-Other for a discussion of AEP's coal
marketing and transportation operations.
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:
2001 2002 2003
---- ---- ----
Total coal delivered to AEP operated plants
(thousands of tons)........................... 73,889 76,442 76,042
Average price per ton of spot-purchased coal... $27.30 $27.06 $28.91
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 issues and
weather conditions which may interrupt deliveries. At December 31, 2003, the
System's coal inventory was approximately 42 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
relevant state regulatory agency has prescribed actions to be taken under
specified circumstances by System companies, subject to the jurisdiction of such
agency.
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 138
billion cubic feet of natural gas during 2003 for generating power. A majority
of the gas-fired power 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 entered into 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. See Deactivation and Planned
Disposition of Generation Facilities for more information about TCC's interest
in STP.
For purposes of the storage of high-level radioactive waste in the form of
spent nuclear fuel, I&M has completed modifications to its spent nuclear fuel
storage pool. AEP anticipates that the Cook Plant has storage capacity to permit
normal operations through 2012. STP has on-site storage facilities with the
capability to store the spent nuclear fuel generated by the STP units over their
licensed lives.
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 spent nuclear
fuel 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:
o Type of decommissioning plan selected;
o Escalation of various cost elements (including, but not limited to,
general inflation);
o Further development of regulatory requirements governing decommissioning;
o Limited availability to date of significant experience in
decommissioning such facilities;
o Technology available at the time of decommissioning differing significantly
from that assumed in these studies;
o Availability of nuclear waste disposal facilities; and
o Approval of the Cook Plant's license extension.
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 Financial Discussion and Analysis of Results of Operations
and Note 7 to the consolidated financial statements, entitled Commitments and
Contingencies, included in the 2003 Annual Reports, 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. There is currently no set date
limiting AEP's access to the Utah facility.
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 mutually agreed to enter into
reliability must run agreements to continue operation of these seven plants.
With ERCOT's approval, AEP deactivated the remaining nine plants. The agreements
allowed ERCOT to terminate the agreement with 90 days notice if the facility was
no longer needed to ensure reliability of the electricity grid. ERCOT provided
such notice with respect to one TNC plant in August 2003 and the plant was
deactivated. AEP and ERCOT agreed to new reliability must run contracts at the
remaining six plants through December 2004, subject to the same termination
provision.
TCC is conducting an auction to sell all of its generation facilities in
Texas to establish the market value of the assets and TCC's stranded costs in
accordance with the Texas Act. See Texas Regulatory Assets and Stranded Cost
Recovery and Post-Restructuring Wires Charges. The competitive bidding process
began in June 2003 after the PUCT issued a rule confirming TCC's ability to
establish the value of its generation assets and amount of stranded costs by
selling the generation assets. The PUCT has engaged a consultant and designated
a team to monitor the auction and advise TCC on the sale of its generating
assets, including requirements of the Texas Act for establishing stranded costs.
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
Oklaunion Power Station, a hydroelectric facility and TCC's interest in STP. TCC
has entered into agreements to sell its 7.8% share of Oklaunion Power Station
and 25.2% share in STP and is continuing to evaluate bids for its remaining
generation assets. See Note 6 to the consolidated financial statements entitled
Customer Choice and Industry Restructuring, included in the 2003 Annual Reports,
for more information on the planned disposition of TCC generation facilities.
Structured Arrangements Involving Capacity, Energy, and Ancillary Services
In January 2000, OPCo and NPC, an affiliate of Buckeye, entered into an
agreement relating to the construction and operation of a 510 MW gas-fired
electric generating peaking facility to be owned by NPC. OPCo is entitled to
100% of the power generated by the facility, and is responsible for the fuel and
other costs of the facility through 2005. 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.
Certain Power Agreements
AEGCo: Since its formation in 1982, AEGCo's business has consisted of the
ownership and financing 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, which have been approved by the FERC.
The I&M Power Agreement provides for the sale by AEGCo to I&M of all the
capacity (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 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 KPCo, and a unit power agreement
between KPCo and AEGCo, AEGCo sells KPCo 30% of the capacity (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.
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.
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 from its generating capacity 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. The AEP-affiliated owners of OVEC are evaluating
the need for environmental investments related to their ownership interests.
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 January
23, 2003, was recorded at 1,409,726 kilowatts.
Electric Transmission and Distribution
General
AEP's public utility subsidiaries (other than AEGCo) 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 electric power, to retail customers of AEP's public
utility subsidiaries in their service territories. These sales are made at rates
established and approved by the state utility commissions of the states in which
they operate, and in some instances, approved by the FERC. See Regulation--
Rates. The FERC regulates and approves the rates for wholesale transmission
transactions. See Regulation-- FERC. As discussed below, some transmission
services also are separately sold to non-affiliated companies.
AEP's public utility subsidiaries (other than AEGCo) hold franchises or other
rights to provide electric service in various municipalities and regions in
their service areas. In some cases, these franchises provide the utility with
the exclusive right to provide electric service. 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. For a
discussion of competition in the sale of power, see Competition.
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). The TEA has been approved by the FERC. Sharing
under the TEA 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, 2003, the member-load ratios were as follows:
Peak
Demand Member-Load
(MW) Ratio (%)
APCo............... 6,873 31.7
CSPCo.............. 3,871 17.9
I&M................ 4,243 19.6
KPCo............... 1,564 7.2
OPCo............... 5,121 23.6
The following table shows the net (credits) or charges allocated among the
parties to the TEA during the years ended December 31, 2001, 2002 and 2003:
2001 2002 2003
-------- -------- ------
(in thousands)
APCo..................... $ (3,100) $(13,400)$ 0
CSPCo.................... 40,200 42,200 38,200
I&M...................... (41,300) (36,100) (39,800)
KPCo..................... (4,600) (5,400) (5,600)
OPCo..................... 8,800 12,700 7,200
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 has been approved by the FERC and 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 allocation 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, 2001, 2002 and 2003:
2001 2002 2003
------- ------- ------
(in thousands)
PSO....................... $ 4,000 $ 4,200 $ 4,200
SWEPCo.................... 5,400 5,000 5,000
TCC....................... (3,900) (3,600) (3,600)
TNC....................... (5,500) (5,600) (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 companies. See Regional Transmission Organizations.
AEP's public utility subsidiaries are subject to regulation by the FERC under
the FPA in respect of transmission of electric power.
Coordination of East and West Zone Transmission: AEP's System Transmission
Integration Agreement provides for the integration and coordination of the
planning, operation and maintenance of the transmission facilities of AEP's east
and west zone 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:
o The allocation of transmission costs and revenues and
o 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.
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 energy 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
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 may only be partially within AEP's control.
In December 2002, AEP's public utility subsidiaries 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. The status of these applications is as follows:
o The IURC conditionally approved the transfer of functional control of
I&M's transmission assets to an RTO in September 2003, though the
satisfaction of these conditions is not fully within I&M's or AEP's
control;
o In July 2003, the KPSC denied KPCo's request to join PJM based on a
lack of evidence that it would benefit Kentucky retail customers, but
granted KPCo's request for rehearing. KPCo filed a cost/benefit study
in December 2003 and a rehearing has been scheduled for April 2004;
o CSPCo and OPCo filed an application seeking approval of their plan to
join PJM in December 2002. In addition, a group of complainants
have filed a complaint with the PUCO alleging that CSPCo and OPCo
have violated Ohio law by not participating in an RTO and seeking
(i) a suspension of certain transmission-related charges to
customers, (ii) requiring that CSPCo and OPCo continue to offer
service at the prices set forth in their 1999 transition plan filing
until January 1, 2006 and (iii) a penalty of $25,000 for each day
that CSPCo and OPCo do not participate in an RTO. The PUCO
consolidated our application with the complaint in February 2003.
The PUCO has stayed the matter pending greater clarification with
respect to RTO matters at the FERC and elsewhere;
o 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 and thereafter only with
VSCC approval. The legislation requires a transfer by January 2005.
In January 2004, APCo filed a supplement to its application with the
VSCC consisting of a cost/benefit analysis of its participation in
PJM and additional information required by the VSCC. A hearing on
APCo's Virginia application is scheduled for July 2004.
In November 2003, the FERC issued an order (i) proposing to exempt AEP's east
zone public utility subsidiaries from Kentucky and Virginia laws requiring state
approval of the AEP east zone public utility subsidiaries' transfer of
functional control of their transmission assets to an RTO and (ii) directing
AEP's east zone public utility subsidiaries to join PJM by October 1, 2004.
Several issues, including whether the FERC may exempt AEP's east zone public
utility subsidiaries from Kentucky and Virginia law preventing them from joining
an RTO, have been heard by an administrative law judge. The FERC has directed
that an initial decision be issued by the ALJ by March 15, 2004.
SWEPCo and PSO currently intend to transfer functional control of their
transmission assets to SPP subject to receipt of appropriate regulatory
approvals. In February 2004, the FERC conditionally approved SPP as an RTO. The
Arkansas Public Service Commission and LPSC have required filings related to
SWEPCo's and PSO's transfer of functional control of transmission facilities to
an RTO. The remaining west zone public utility subsidiaries (TCC and TNC) are
members of ERCOT.
See Note 4 to the consolidated financial statements, entitled Rate Matters,
included in the 2003 Annual Reports and Management's Financial Discussion and
Analysis of Results of Operations under the heading entitled RTO Formation for a
discussion of public utility subsidiary participation in RTOs.
Regional Through and Out Rates
The FERC has proposed to eliminate our ability to collect certain
transmission charges associated with the transmission assets of our east zone
public utility subsidiaries and implement transitional rates to mitigate the
lost revenues for a two-year period commencing May 1, 2004. The FERC did not
indicate how or if the lost revenues would be recovered after the expiration of
the transitional rates. Management, however, believes that we are entitled to
recover costs of owning and operating these facilities, including a reasonable
rate of return. See Management's Financial Discussion and Analysis of Results of
Operations under the heading entitled FERC Order on Regional Through and Out
Rates for more information.
Regulation
General
Except for retail generation sales in Ohio, Virginia and the ERCOT area of
Texas, AEP's public utility subsidiaries' retail rates and certain other matters
are subject to traditional regulation by the state utility commissions. Retail
sales in Michigan, while still regulated, are now made at unbundled rates. Other
states in AEP'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 Rates. AEP's subsidiaries are also subject
to regulation by the FERC under the FPA. I&M and TCC are subject to regulation
by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the
operation of the Cook Plant and STP, respectively. AEP and certain of its
subsidiaries are also subject to the broad regulatory provisions of PUHCA
administered by the SEC.
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 generally reflects 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 one 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 is no longer provided for in
Ohio. Fuel recovery is also limited in the ERCOT 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. Its fuel recovery rate was capped through
February 29, 2004 but is expected to return to traditional cost recovery.
Ohio: CSPCo and OPCo each operates as a functionally separated utility and
provides "default" retail electric service to customers at unbundled rates
pursuant to the Ohio Act through December 31, 2005. Market-based default retail
generation service rates will be determined in accordance with PUCO rules after
December 31, 2005, unless the rate stabilization plan filed by CSPCo and OPCo
(which, among other things, addresses default retail generation service rates
from January 1, 2006 through December 31, 2008) is approved by the PUCO, in
which case retail generation rates would be determined consistent with the rate
stabilization plan until December 31, 2008. CSPCo and OPCo are and will continue
to provide distribution services to retail customers at rates approved by the
PUCO. These rates will be frozen from their levels as of December 31, 2005 to
(i) December 31, 2008 for CSPCo and (ii) December 31, 2007 (December 31, 2008,
if the rate stabilization plan is approved) for OPCo. Transmission services will
continue to be provided at rates established by the FERC. See Note 6 to the
consolidated financial statements, entitled Customer Choice and Industry
Restructuring, included in the 2003 Annual Reports, for more information.
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 energy 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 energy costs.
Over or under collections of fuel costs for prior periods can be recovered when
new quarterly factors are established. See Note 4 to the consolidated financial
statements, entitled Rate Matters, included in the 2003 Annual Reports, for
information regarding current rate proceedings.
Texas: The Texas Act requires the legal separation of generation-related
assets from transmission and 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. See Note
4 to the consolidated financial statements, entitled Rate Matters, included in
the 2003 Annual Reports, for information on current rate proceedings.
In May 2003, the PUCT delayed competition in the SPP area of Texas until at
least January 1, 2007. 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. Management currently believes that implementation of the
plan is unlikely.
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.
The table below illustrates the current rate regulation status of the states
in which the public utility subsidiaries of AEP operate:
Percentage
Fuel Clause Rates Of AEP
System Sales System
Status of Base Rates for Profits Shared Retail
Jurisdiction Power Supply Energy Delivery Status Includes w/Ratepayers Revenues(1)
------------ -------------- --------------- -------- ---------- -------------- -----------
Ohio Frozen Distribution None Not applicable Not applicable 32%
through frozen through
2005(2) 2007 for OPCo and
2008 for CSP;
Transmission frozen
through 2005
Texas-ERCOT
(TCC, TNC) See footnote 3 Not capped or frozen Not applicable Not applicable Not applicable 9%(3)
Texas- SPP
(SWEPCo, TNC) Not capped or Active Fuel and fuel Yes, above base 5%
frozen portion of levels
purchased
power
Oklahoma Not capped or Active Fuel and fuel Yes 13%
frozen portion of
purchased
power
Indiana Capped until Active Fuel and Fuel No 10%
1/1/05 (4) portion of
purchased
power
Virginia Capped until Capped until Active Fuel and fuel No 9%
as late as late portion of
as 7/1/07(5) as 7/1/07(5) purchased
power
West Not capped or Suspended(6) Fuel and fuel Yes, but 9%
Virginia frozen portion of suspended
purchased
power
Louisiana Capped until Active Fuel and fuel Yes, above 4%
6/15/05 portion of base levels
purchased
power
Kentucky(7) Not capped or Active Fuel and fuel Yes, above 4%
frozen portion of base levels
purchased
power
Arkansas Not capped or Active Fuel and fuel Yes, above 2%
frozen portion of base levels
purchased
power
Michigan Capped until Capped until Active Fuel and fuel Yes, in some 2%
1/1/05(8) 1/1/05(8) portion of areas
purchased
power
Tennessee Not capped or Active Fuel and fuel No 1%
frozen 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, 2003.
(2) CSPCo and OPCo have filed a rate stabilization plan with the PUCO to
establish (after the market development period) a rate stabilization period
from January 1, 2006 through December 31, 2008 during which their default
retail generation rates would be established pursuant to such filing. The
rate stabilization plan would also extend OPCo's distribution rate freeze
through the end of 2008.
(3) 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.
(4) Capped base rates pursuant to a 1999 settlement with base rate freeze
extended pursuant to merger stipulation.
(5) Base rates are capped until the earlier of July 1, 2007 or a finding by the
VSCC that a competitive market for generation exists. One-time change in
non-generation rates is allowed in Virginia.
(6) Expanded net energy clause suspended in West Virginia pursuant to a 1999
rate case stipulation, but subject to change in a future proceeding.
(7) KPCo applied for an environmental surcharge to recover costs incurred in
connection with the installation of emission control equipment and in 2003
the KPSC granted recovery of $18 million.
(8) Capped base and fuel rates pursuant to a 1999 settlement and base rates
extended pursuant to merger stipulation.
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 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. This was done in connection with the FERC's adoption of a new
test called supply management assessment (SMA). In December 2003, the FERC
issued a staff paper discussing alternatives to SMA and held a technical
conference in January 2004. See Note 7 to the consolidated financial statements,
entitled Commitments and Contingencies, included in the 2003 Annual Reports, for
more information on the current status of this proceeding.
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 unbundled cost-based rates
for transmission and distribution service 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 Texas. Electric
restructuring in the SPP area of Texas has been delayed by the PUCT until at
least 2007. AEP's public utility subsidiaries operate in both the ERCOT and SPP
areas of Texas.
Implementation of legislation enacted in West Virginia to allow retail
customers to choose their electricity supplier is on hold. 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. Management currently believes that
implementation of the plan is unlikely. In February 2003, Arkansas repealed its
restructuring legislation.
See Note 5 to the consolidated financial statements, entitled Effects of
Regulation, included in the 2003 Annual Reports, for a discussion of the effect
of restructuring and customer choice legislation on accounting procedures. See
Note 6 to the consolidated financial statements entitled Customer Choice and
Industry Restructuring and Management's Financial Discussion and Analysis and
Financial Condition, included in the 2003 Annual Reports, under the heading
entitled Corporate Separation for a discussion of AEP's corporate separation
plan.
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, 2003, 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.
CSPCo and OPCo have filed a rate stabilization plan with the PUCO that, among
other things, addresses default generation service rates from January 1, 2006
through December 31, 2008. See Regulation--FERC for a discussion of FERC
regulation of transmission rates and Regulation--Rates--Ohio for a discussion of
the impact of restructuring on distribution rates. If the PUCO approves the rate
stabilization plan filed by CSPCo and OPCo, they will remain functionally
separated through at least December 31, 2008.
Texas Restructuring
Signed into law in June of 1999, the Texas Act substantially amended the
regulatory structure governing electric utilities in Texas in order to allow
retail electric competition for all customers. Among other things, the Texas
Legislation:
o gave Texas customers the opportunity to choose their REP beginning January
1, 2002 (delayed until at least 2007 in the SPP portion of Texas),
o required each utility to legally separate into a REP, a power generation
company, and a transmission and distribution utility, and
o required that REPs obtain electricity 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, at the PTB, until
certain conditions in the Texas Legislation are met.
The Texas Act provides each affected utility an opportunity to recover its
generation related regulatory assets and stranded costs resulting from the legal
separation of the transmission and distribution utility from the generation
facilities and the related introduction of retail electric competition.
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 (as of December 31,
2001) over the market value of those assets, taking specified factors into
account, as ultimately determined in a PUCT true-up proceeding (the True-Up
Proceeding).
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 Texas Regulatory Asset and Stranded Cost Recovery and
Post-Restructuring Wires Charges.
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.
Texas Regulatory Assets and Stranded Cost Recovery and Post-Restructuring
Wires Charges
TCC and TNC may recover generation-related regulatory assets and
plant-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. Plant-related stranded
costs co