--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
---------------------------
FORM 10-K/A
---------------------------
(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, 2002
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from -------------- to --------------
COMMISSION REGISTRANT; STATE OF INCORPORATION; I.R.S. EMPLOYER
FILE NUMBER ADDRESS AND TELEPHONE NUMBER IDENTIFICATION NOS.
----------- ------------------------------------- -------------------
1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation) 13-4922640
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 716-1000
Indicate by check mark whether the registrant (1) has 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
registrant was required to file such reports), and (2) has 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 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 __
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- ---------------------
Common Stock,
$6.50 par value.................................. New York Stock Exchange
9.25% Equity Units................................. New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None
AGGREGATE MARKET VALUE
OF VOTING AND NON-VOTING NUMBER OF SHARES
COMMON EQUITY HELD OF COMMON STOCK
BY NON-AFFILIATES OF OUTSTANDING OF
THE REGISTRANTS AT THE REGISTRANTS AT
JUNE 28, 2002 JUNE 28, 2002
------------------------ ------------------
American Electric Power Company, Inc. $13,560,125,474 338,833,720
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.
DOCUMENTS INCORPORATED BY REFERENCE
PART OF FORM 10-K
INTO WHICH DOCUMENT
DESCRIPTION IS INCORPORATED
----------- -------------------
Portions of Annual Report of American Electric Power Company, Inc. Part II
the fiscal year ended December 31, 2002:
------------------
YOU CAN ACCESS FINANCIAL AND OTHER INFORMATION AT AEP'S WEBSITE. THE
ADDRESS IS WWW.AEP.COM. AEP MAKES AVAILABLE, FREE OF CHARGE ON ITS WEBSITE,
COPIES OF ITS ANNUAL REPORT ON FORM 10-K, QUARTERLY REPORTS ON FORM 10-Q,
CURRENT REPORTS ON FORM 8-K AND AMENDMENTS TO THOSE REPORTS FILED OR FURNISHED
PURSUANT TO SECTION 13(A) OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 AS
SOON AS REASONABLY PRACTICABLE AFTER FILING SUCH MATERIAL ELECTRONICALLY OR
OTHERWISE FURNISHING IT TO THE SEC.
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
American Electric Power Company, Inc. Form 10-K/A
Introductory Note
This amendment on Form 10-K/A amends American Electric Power Company, Inc.'s
annual report on Form 10-K for the fiscal year ended December 31, 2002, as
initially filed with the Securities and Exchange Commission on March 20, 2003,
and is being filed to reflect certain revisions to the consolidated financial
statements. The significant effects of these revisions are presented in Note 28
to the consolidated financial statements. This amendment incorporates certain
revisions to historical financial data and related descriptions, but is not
intended to update other information presented in this annual report as
originally filed, except where specifically noted.
The following Items of the Original Filing are revised by this filing:
Item 1. Business
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Results of Operations and
Financial Condition
Item 7A. Quantitative and Qualitative Disclosures About Risk
Item 8. Financial Statements and Supplemental Data
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K
Unaffected items have not been repeated in this filing.
TABLE OF CONTENTS
PAGE
NUMBER
------
Glossary of Terms........................................................... i
Forward-Looking Information................................................. 1
PART I
Item 1. Business.................................................... 2
PART II
Item 6. Selected Financial Data..................................... 25
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition........................ 26
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk...................................................... 26
Item 8. Financial Statements and Supplementary Data................. 26
PART IV
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form
8-K....................................................... 26
Signatures.................................................................. 27
Certifications.............................................................. 28
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.
APCo. ................................. Appalachian Power Company, an electric utility subsidiary of
AEP
Btu.................................... British thermal unit
Buckeye................................ Buckeye Power, Inc., an unaffiliated corporation
CAA.................................... Clean Air Act
CAAA................................... Clean Air Act Amendments of 1990
Cardinal Station....................... Generating facility co-owned by Buckeye and OPCo
Centrica............................... Centrica U.S. Holdings, Inc., and its affiliates
collectively, unaffiliated companies
CERCLA................................. Comprehensive Environmental Response, Compensation and
Liability Act of 1980
CG&E................................... The Cincinnati Gas & Electric Company, an unaffiliated
utility company
Cook Plant............................. The Donald C. Cook Nuclear Plant, owned by I&M, located near
Bridgman, Michigan
CSPCo. ................................ Columbus Southern Power Company, a public utility subsidiary
of AEP
CSW Operating Agreement................ Agreement, dated January 1, 1997, by and among PSO, SWEPCo,
TCC and TNC governing generating capacity allocation
DOE.................................... United States Department of Energy
DP&L................................... The Dayton Power and Light Company, an unaffiliated utility
company
East Zone Companies of AEP............. APCo, CSPCo, I&M, KPCo and OPCo
ECOM................................... Excess cost over market
EMF.................................... Electric and Magnetic Fields
EPA.................................... United States Environmental Protection Agency
ERCOT.................................. Electric Reliability Council of Texas
EWG.................................... Exempt wholesale generator, as defined under PUHCA
FERC................................... Federal Energy Regulatory Commission
Fitch.................................. Fitch Ratings, Inc.
FPA.................................... Federal Power Act
FUCO................................... Foreign utility company as defined under PUHCA
I&M.................................... Indiana Michigan Power Company, a public utility subsidiary
of AEP
I&M Power Agreement.................... Unit Power Agreement Between AEGCo and I&M, dated March 31,
1982
Interconnection Agreement.............. Agreement, dated July 6, 1951, by and among APCo, CSPCo,
I&M, KPCo and OPCo, defining the sharing of costs and
benefits associated with their respective generating
plants
IURC................................... Indiana Utility Regulatory Commission
KPCo. ................................. Kentucky Power Company, a public utility subsidiary of AEP
LLWPA.................................. Low-Level Waste Policy Act of 1980
LPSC................................... Louisiana Public Service Commission
MECPL.................................. Mutual Energy CPL, L.P., a Texas REP and former AEP
affiliate
MEWTU.................................. Mutual Energy WTU, L.P., a Texas REP and former AEP
affiliate
MISO................................... Midwest Independent Transmission System Operator
Moody's................................ Moody's Investors Service, Inc.
i
ABBREVIATION OR ACRONYM DEFINITION
----------------------- ----------
MTM.................................... Marked-to-market
MW..................................... Megawatt
NOx.................................... Nitrogen oxide
NPC.................................... National Power Cooperatives, Inc., an unaffiliated
corporation
NRC.................................... Nuclear Regulatory Commission
OASIS.................................. Open Access Same-time Information System
OATT................................... Open Access Transmission Tariff, filed with FERC
OCC.................................... Corporation Commission of the State of Oklahoma
Ohio Act............................... Ohio electric restructuring legislation
OPCo. ................................. Ohio Power Company, a public utility subsidiary of AEP
OVEC................................... Ohio Valley Electric Corporation, an electric utility
company in which AEP and CSPCo together own a 44.2% equity
interest
PJM.................................... PJM Interconnection, L.L.C.
Pro Serv............................... AEP Pro Serv, Inc., a subsidiary of AEP
PSO.................................... Public Service Company of Oklahoma, a public utility
subsidiary of AEP
PTB.................................... Price to beat, as defined by the Texas Act
PUCO................................... The Public Utilities Commission of Ohio
PUCT................................... Public Utility Commission of Texas
PUHCA.................................. Public Utility Holding Company Act of 1935, as amended
QF..................................... Qualifying facility, as defined under the Public Utility
Regulatory Policies Act of 1978
RCRA................................... Resource Conservation and Recovery Act of 1976, as amended
REP.................................... Retail electricity provider
Rockport Plant......................... A generating plant, consisting of two 1,300,000-kilowatt
coal-fired generating units, near Rockport, Indiana
RTO.................................... Regional Transmission Organization
SEC.................................... Securities and Exchange Commission
S&P.................................... Standard & Poor's Ratings Service
SO(2).................................. Sulfur dioxide
SO(2) Allowance........................ An allowance to emit one ton of sulfur dioxide granted under
the Clean Air Act Amendments of 1990
SPP.................................... Southwest Power Pool
STPNOC................................. STP Nuclear Operating Company, a non-profit Texas
corporation which operates STP on behalf of its joint
owners, including TCC
SWEPCo. ............................... Southwestern Electric Power Company, a public utility
subsidiary of AEP
TCA.................................... Transmission Coordination Agreement dated January 1, 1997 by
and among, PSO, SWEPCo, TCC, TNC and AEPSC, which allocates
costs and benefits in connection with the operation of the
transmission assets of the four public utility
subsidiaries
TCC.................................... AEP Texas Central Company, formerly Central Power and Light
Company, a public utility subsidiary of AEP
TEA.................................... Transmission Equalization Agreement dated April 1, 1984 by
and among APCo, CSPCo, I&M, KPCo and OPCo, which allocates
costs and benefits in connection with the operation of
transmission assets
Texas Act.............................. Texas electric restructuring legislation
TNC.................................... AEP Texas North Company, formerly West Texas Utilities
Company, a public utility subsidiary of AEP
TVA.................................... Tennessee Valley Authority
UCOS................................... Unbundled cost of service
Virginia Act........................... Virginia electric restructuring legislation
VSCC................................... Virginia State Corporation Commission
WVPSC.................................. West Virginia Public Service Commission
West Zone Companies of AEP............. PSO, SWEPCo, TCC and TNC
ii
FORWARD-LOOKING INFORMATION
--------------------------------------------------------------------------------
This report made by AEP and certain of its subsidiaries contains
forward-looking statements within the meaning of Section 21E of the Securities
Exchange Act of 1934. Although AEP and each of its subsidiaries believe that
their expectations are based on reasonable assumptions, any such statements may
be influenced by factors that could cause actual outcomes and results to be
materially different from those projected. Among the factors that could cause
actual results to differ materially from those in the forward-looking statements
are:
- Electric load and customer growth.
- Abnormal weather conditions
- Available sources and costs of fuels.
- Availability of generating capacity.
- The speed and degree to which competition is introduced to AEP's power
generation business.
- The ability to recover stranded costs in connection with
possible/proposed deregulation of generation.
- New legislation and government regulation
- Oversight and/or investigation of the energy sector or its participants.
- The ability of AEP to successfully control its costs.
- The success of acquiring new business ventures and disposing of existing
investments that no longer match AEP's corporate profile.
- International and country-specific developments affecting AEP's foreign
investments, including the disposition of any current foreign investments
and potential additional foreign investments.
- The economic climate and growth in AEP's service territory and changes in
market demand and demographic patterns.
- Inflationary trends.
- Electricity and gas market prices.
- Interest rates.
- Liquidity in the banking, capital and wholesale power markets.
- Actions of rating agencies.
- Changes in technology, including the increased use of distributed
generation within AEP's transmission and distribution service territory.
- Other risks and unforeseen events, including wars, the effects of
terrorism, embargoes and other catastrophic events.
PART I
--------------------------------------------------------------------------------
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, 2002, the subsidiaries of AEP had a total of 22,083
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 925,000
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, 2002, APCo and its wholly owned subsidiaries had 2,520 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 689,000 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, 2002, CSPCo had 1,171 employees. CSPCo's service area is comprised of two
areas in Ohio, which include portions of twenty-five counties. One area
includes the City of Columbus and the other is a predominantly rural area in
south central Ohio. 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 571,000
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, 2002, I&M had 2,667 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 174,000
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, 2002, KPCo had
412 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, 2002, 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 702,000 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, 2002, OPCo had 1,988 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, 2002, PSO had 998 employees. Among the principal industries
served by PSO are natural gas and oil production, oil refining, steel
processing, aircraft maintenance, paper manufacturing and timber products,
glass, chemicals, cement, plastics, aerospace manufacturing,
telecommunications, and rubber goods. In addition to its AEP System
interconnections, PSO also is interconnected with Ameren Corporation, Empire
District Electric Co., Oklahoma Gas & Electric Co., Southwestern Public
Service Co. and Westar Energy Inc.
SWEPCo (organized in Delaware in 1912) is engaged in the generation,
transmission and distribution of electric power to approximately 437,000
retail customers in northeastern Texas, northwestern Louisiana and western
Arkansas, and in supplying and marketing electric power at wholesale to other
electric utility companies, municipalities, rural electric cooperatives and
other market participants. At December 31, 2002, SWEPCo had 1,372 employees.
Among the principal industries served by SWEPCo are natural gas and oil
production, petroleum refining, manufacturing of pulp and paper, chemicals,
food processing, and metal refining. The territory served by SWEPCo also
includes several military installations, colleges, and universities. In
addition to its AEP System interconnections, SWEPCo is also interconnected
with CLECO Corp., Empire District Electric Co., Entergy Corp. and Oklahoma Gas
& Electric Co.
TCC (organized in Texas in 1945) is engaged in the generation,
transmission and sale of power to affiliated and non-affiliated entities and
the distribution of electric power to approximately 689,000 retail customers
through REPs in southern Texas, and in supplying and marketing electric power
at wholesale to other electric utility companies, municipalities, rural
electric cooperatives and other market
participants. At December 31, 2002, TCC had 1,248 employees. Among the
principal industries served by TCC are oil and gas extraction, food
processing, apparel, metal refining, chemical and petroleum refining,
plastics, and machinery equipment. In addition to its AEP System
interconnections, TCC is a member of ERCOT.
TNC (organized in Texas in 1927) is engaged in the generation,
transmission and sale of power to affiliated and non-affiliated entities and
the distribution of electric power to approximately 189,000 retail customers
through REPs in west and central Texas, and in supplying and marketing
electric power at wholesale to other electric utility companies,
municipalities, rural electric cooperatives and other market participants. At
December 31, 2002, TNC had 595 employees. The principal industry served by TNC
is agriculture. The territory served by TNC also includes several military
installations and correctional facilities. In addition to its AEP System
interconnections, TNC is a member of ERCOT.
Wheeling Power Company (organized in West Virginia in 1883 and
reincorporated in 1911) provides electric service to approximately 41,000
retail customers in northern West Virginia. Wheeling Power Company does not
own any generating facilities. It purchases electric power from OPCo for
distribution to its customers. At December 31, 2002, Wheeling Power Company
had 59 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, 2002, AEPSC had 6,548 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, 2002 are as follows:
AEP
SYSTEM(A) APCo CSPCo I&M KPCo
----------- ---------- ---------- ---------- ---------
(IN THOUSANDS)
Wholesale Business:
Residential........................ $ 3,713,000 $ 616,509 $ 533,061 $ 371,329 $ 118,654
Commercial......................... 2,156,000 276,238 442,847 224,843 50,075
Industrial......................... 1,903,000 353,841 138,174 330,428 96,716
Other Retail Customers............. 385,000 80,429 38,018 61,450 16,911
Energy Delivery.................... (3,551,000) (594,089) (492,278) (321,721) (132,054)
----------- ---------- ---------- ---------- ---------
Total Retail.................... 4,606,000 732,928 659,822 666,329 150,302
Marketing and
Trading-Electricity............. 2,214,000 204,878 134,836 279,705 50,056
Marketing and Trading-Gas.......... 3,015,000 0 0 0 0
Unrealized MTM Income:
Electric........................ 136,000 18,089 13,388 0 0
Gas............................. (399,000) 0 0 0 0
Other.............................. 1,397,000 264,486 99,836 259,009 46,271
----------- ---------- ---------- ---------- ---------
Total Wholesale Business........ 10,969,000 1,220,381 907,882 1,205,043 246,629
----------- ---------- ---------- ---------- ---------
Energy Delivery Business:
Transmission....................... 922,000 186,960 107,673 118,812 50,381
Distribution....................... 2,629,000 407,129 384,605 202,909 81,673
----------- ---------- ---------- ---------- ---------
Total Energy Delivery........... 3,551,000 594,089 492,278 321,721 132,054
----------- ---------- ---------- ---------- ---------
Total Other Investments......... 16,000 0 0 0 0
----------- ---------- ---------- ---------- ---------
Total Revenues................ $14,536,000 $1,814,470 $1,400,160 $1,526,764 $ 378,683
=========== ========== ========== ========== =========
OPCo PSO SWEPCo TCC TNC
---------- --------- ---------- ---------- --------
(IN THOUSANDS)
Wholesale Business:
Residential........................... $ 475,210 $ 315,711 $ 313,023 $ 49,210 $ 8,651
Commercial............................ 244,943 218,718 212,626 32,518 4,098
Industrial............................ 531,085 162,386 214,622 12,395 2,134
Other Retail Customers................ 71,737 38,998 33,104 3,594 1,638
Energy Delivery....................... (589,673) (275,547) (348,236) (554,547) (73,353)
---------- --------- ---------- ---------- --------
Total Retail....................... 733,302 460,266 425,139 (456,830) (56,832)
Marketing and Trading-Electricity..... 219,488 17,394 157,159 811,800 283,883
Marketing and Trading-Gas............. 0 0 0 0 0
Unrealized MTM Income:
Electric........................... 25,574 0 (3,686) (8,490) (1,473)
Gas................................ 0 0 0 0 0
Other................................. 545,088 40,440 157,872 789,466 151,809
---------- --------- ---------- ---------- --------
Total Wholesale Business........... 1,523,452 518,100 736,484 1,135,946 377,387
---------- --------- ---------- ---------- --------
Energy Delivery Business:
Transmission.......................... 162,660 63,178 92,076 68,003 25,273
Distribution.......................... 427,013 212,369 256,160 486,544 48,080
---------- --------- ---------- ---------- --------
Total Energy Delivery.............. 589,673 275,547 348,236 554,547 73,353
---------- --------- ---------- ---------- --------
Total Other Investments............ 0 0 0 0 0
---------- --------- ---------- ---------- --------
Total Revenues................... $2,113,125 $ 793,647 $1,084,720 $1,690,493 $450,740
========== ========= ========== ========== ========
---------------
(a) Includes revenues of other subsidiaries not shown. Intercompany transactions
have been eliminated, including AEGCo's total revenues of $213,281,000 for
the year ended December 31, 2002, all of which resulted from its wholesale
business, including its marketing and trading of power.
REGULATION
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 Energy Delivery--Regulation--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 its subsidiaries are also subject to the broad regulatory provisions of
PUHCA administered by the SEC.
FERC
Under the FPA, FERC regulates rates for interstate sales at wholesale,
transmission of electric power, accounting and other matters, including
construction and operation of hydroelectric projects. FERC regulations require
AEP to provide open access transmission service at FERC-approved rates. The
transmission service regulated by FERC is predominantly wholesale transmission
service, which is service not associated with bundled electricity sales to
retail customers. FERC also regulates unbundled transmission service to retail
customers.
Under the FPA, the FERC regulates the sale of power for resale in
interstate commerce by (i) approving contracts for wholesale sales to municipal
and cooperative utilities and (ii) granting authority to public utilities to
sell power at wholesale at market-based rates upon a showing that the seller
lacks the ability to improperly influence market prices. AEP has
market-rate authority from FERC, under which most of its wholesale marketing
activity takes place. In November 2001, the FERC issued an order in connection
with its triennial review of AEP's market based pricing authority requiring (i)
certain actions by AEP in connection with its sales and purchases within its
control area and (ii) posting of information related to generation facility
status on AEP's website. AEP has appealed this order, and the FERC has issued an
order delaying the effective date of the order. See Note 9 to the consolidated
financial statements, entitled Commitments and Contingencies, incorporated by
reference in Item 8, for more information on the current status of this
proceeding.
SEC
The provisions of PUHCA, administered by the SEC, regulate 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 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.
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, also scheduled to begin on January 1,
2002, has been delayed by the PUCT. AEP's public utility subsidiaries operate in
both the ERCOT and SPP areas of Texas.
Implementation of legislation enacted in Oklahoma and West Virginia to
allow retail customers to choose their electricity supplier is on hold. In 2001
Oklahoma delayed implementation of customer choice indefinitely. Before West
Virginia's choice plan can be effective, tax legislation must be passed to
preserve pre-legislation levels of funding for state and local governments. No
further legislation has been passed related to restructuring in West Virginia.
In February 2003, Arkansas repealed its restructuring legislation.
See Note 7 to the consolidated financial statements, entitled Effects of
Regulation, incorporated by reference in Item 8, for a discussion of the effect
of restructuring and customer choice legislation on accounting procedures. See
Management's Discussion
and Analysis of Results of Operations and Financial Condition, under the
headings entitled Industry Restructuring and Corporate Separation for a
discussion of AEP's corporate separation plan filed with the FERC and related
settlement agreements with state commissions and other intervenors.
Michigan Customer Choice
Customer choice commenced for I&M's Michigan customers on January 1, 2002.
Rates for retail electric service for I&M's Michigan customers were unbundled
(though they continue to be regulated) to allow customers the ability to
evaluate the cost of generation service for comparison with other suppliers. At
December 31, 2002, none of I&M's Michigan customers had elected to change
suppliers and no alternative electric suppliers are registered to compete in
I&M's Michigan service territory.
Ohio Restructuring
The Ohio Act requires vertically integrated electric utility companies that
offer competitive retail electric service in Ohio to separate their generating
functions from their transmission and distribution functions. Following the
market development period (which will terminate no later than December 31,
2005), retail customers will receive distribution and, where applicable,
transmission service from the incumbent utility whose distribution rates will be
approved by the PUCO and whose transmission rates will be approved by the FERC.
See General--Regulation--FERC for a discussion of FERC regulation of
transmission rates and Energy Delivery--Regulation--Rates--Ohio for a discussion
of the impact of restructuring on distribution rates.
CSPCo and OPCo are each presently operating as functionally separated
electric utility companies and no longer charge bundled rates for retail
electric service. Each has sought and, from certain regulatory authorities,
obtained regulatory approval to legally separate its transmission and
distribution assets from its generation assets. CSPCo and OPCo are, however,
currently determining the regulatory feasibility of complying with restructuring
legislation through continued functional separation. Assuming regulatory
compliance, it is currently their intention to remain functionally separated.
Texas Restructuring
The Texas Act substantially amends the regulatory structure governing
electric utilities in Texas in order to allow retail electric competition for
all customers and requires each utility to separate into (i) a REP, (ii) a power
generation company and (iii) a transmission and distribution utility. Upon
separation, neither the REP nor the power generation company will be subject to
traditional cost of service rate regulation. See Energy Delivery--Regulation--
Rates--Texas for a discussion of the impact of restructuring on rates.
SWEPCo, TCC and TNC initially filed a restructuring plan in January 2000
(which they subsequently updated) that the PUCT approved in February 2002. The
updated restructuring plan provided for the legal separation of TCC's and TNC's
assets in accordance with the Texas Act into (i) an affiliate power generation
company, (ii) a transmission and distribution utility and (iii) various REPs,
including those subsequently purchased by Centrica (see below). TCC and TNC
continue to pursue legal separation as required by the Texas Act. The PUCT has
delayed the implementation of the plan for SWEPCo operations within the SPP area
of Texas.
Under the Texas Act, a REP, which itself cannot own any generation assets,
obtains its electricity from power generation companies, EWGs and other
generating entities and provides services at generally unregulated rates, except
that the prices that may be charged to residential and small commercial
customers by REPs affiliated with a utility within the affiliated utility's
service area are set by the PUCT until January 1, 2007. This set price is
referred to as the "price to beat" rate (PTB). Affiliate REPs are required to
offer the PTB rate to all residential and small commercial customers (with a
peak usage of less than 1,000 KW) effective January 1, 2002. As described below,
AEP sold its affiliate REPs that must provide PTB service. The PTB rate is still
relevant to AEP, however, in determining (i) the contingent portion of the sales
price of the affiliate REPs AEP sold and (ii) certain of AEP's obligations in
the 2004 true-up proceedings.
Prior to the start of retail competition in January 2002, AEP formed MECPL
and MEWTU to act as affiliate REPs for TCC and TNC respectively. MECPL and MEWTU
were sold in December 2002 to Centrica, which assumed all of the rights and
obligations of an affiliated REP, including the provision of PTB service and the
obligation to provide data necessary for TCC's and TNC's 2004 true-up
proceeding. In connection with the sale, TCC and TNC have contracted to supply
approximately 90% of MECPL's and
MEWTU's respective power requirements relating to former TCC and TNC PTB
customers for a two-year period. See Note 12 to the consolidated financial
statements, entitled Acquisitions, Distributions and Discontinued Operations,
incorporated by reference in Item 8, for more information on the sale of these
REPs and AEP's contractual rights and obligations in connection with the sale.
The Texas Act also allows certain transmission and distribution utilities
whose generation assets were unbundled to recover certain regulatory assets and
stranded costs related to their generation assets. For a discussion of (i)
regulatory assets and stranded costs subject to recovery by TCC and (ii) rate
adjustments made after implementation of restructuring to allow recovery of
certain costs by or with respect to TCC and TNC, see Energy Delivery--Regulatory
Assets, Stranded Cost Recovery and Certain Post-Restructuring Rate Adjustments.
Virginia Restructuring
The Virginia Act was enacted in 1999 providing for retail choice of
generation suppliers to be phased in over the January 1, 2002 to January 1, 2004
period. The Virginia Act required jurisdictional utilities to unbundle their
power supply and energy delivery rates and to file functional separation plans
by January 1, 2002. APCo filed its plan and, following VSCC approval of a
settlement agreement, now operates in Virginia as a functionally separated
electric utility charging unbundled rates for its retail sales of electricity.
The settlement agreement addressed functional separation, leaving decisions
related to legal separation for later VSCC consideration.
FINANCING
General
AEP's goal is to use cash from operations to fund capital expenditures,
dividends and working capital. Short-term debt is used as an interim bridge for
timing differences in the need for cash or to fund debt maturities until
permanent financing is arranged.
It has been the practice of AEP's operating subsidiaries to finance current
construction expenditures in excess of available cash from operations by
initially incurring short-term debt, up to levels authorized by regulatory
agencies, and then to reduce the short-term debt with the proceeds of subsequent
sales by such subsidiaries of long-term debt securities and cash capital
contributions by AEP. In the past, short-term debt has come from AEP's
commercial paper program and revolving credit facilities. Proceeds were loaned
to the subsidiaries through intercompany notes under the AEP money pool. The
recent downgrade of AEP's commercial paper rating by Moody's, described below,
may limit AEP's access to commercial paper on terms as favorable as those of
recent years. Therefore, AEP may establish commercial paper programs for certain
of its public utility subsidiaries and AEP Utilities. Certain public utility
subsidiaries of AEP also sell accounts receivable to provide liquidity.
AEP's revolving credit agreements (which backstop the commercial paper
program) include covenants and events of default typical for this type of
facility, including a maximum debt/capital test and a $50 million
cross-acceleration provision. At December 31, 2002, AEP was in compliance with
its debt covenants. With the exception of a voluntary bankruptcy or insolvency,
any event of default has either or both a cure period or notice requirement
before termination of the agreements. A voluntary bankruptcy or insolvency would
be considered an immediate termination event.
AEP's subsidiaries have also utilized, and expect to continue to utilize,
additional financing arrangements, such as leasing arrangements, including the
leasing of utility assets and coal mining and transportation equipment and
facilities.
Credit Ratings
The rating agencies have been conducting credit reviews of AEP and its
registrant subsidiaries. The agencies are also reviewing many companies in the
energy sector due to issues that impact the entire industry.
In February 2003 Moody's completed its review of AEP and its rated
subsidiaries. The results of that review were downgrades of the following
ratings for unsecured debt: AEP from Baa2 to Baa3, APCo from Baa1 to Baa2, TCC
from Baa1 to Baa2, PSO from A2 to Baa1, SWEPCo from A2 to Baa1. TNC, which had
no senior unsecured notes outstanding at the time of the ratings action, had its
mortgage bond debt downgraded from A2 to A3. AEP's commercial paper was also
concurrently downgraded from P-2 to P-3. The completion of this review was a
culmination of earlier ratings action in 2002 that had included a downgrade of
AEP from Baa1 to Baa2. With the completion of the reviews, Moody's has placed
AEP and its rated subsidiaries on stable outlook.
In March 2003 S&P completed its review of AEP and its rated subsidiaries.
The results of that review were downgrades of the ratings for unsecured debt for
AEP and its rated subsidiaries from BBB+ to BBB. AEP's commercial paper rating
was affirmed at A-2. With the completion of the reviews, S&P has placed AEP and
its rated subsidiaries on stable outlook.
In March 2003 Fitch completed its review of AEP. The result of that review
was a downgrade of AEP's unsecured debt rating from BBB+ to BBB. AEP's
commercial paper rating was affirmed at F-2. With the completion of the reviews,
Fitch has placed AEP and its rated subsidiaries on stable outlook.
See Management's Discussion and Analysis of Financial Condition, Accounting
Policies and Other Matters, incorporated by reference in Item 7, under the
heading entitled Financial Condition for additional information with respect to
AEP's credit ratings, liquidity and specific financing activities.
ENVIRONMENTAL AND OTHER MATTERS
General
AEP's subsidiaries are currently subject to regulation by federal, state
and local authorities with regard to air and water-quality control and other
environmental matters, and are subject to zoning and other regulation by local
authorities. The environmental issues that are potentially material to the AEP
system include:
- The CAA and CAAA and state laws and regulations (including State
Implementation Plans) that require compliance, obtaining permits and
reporting as to air emissions.
- Litigation with the federal and certain state governments and certain
special interest groups regarding whether modifications to or maintenance
of certain coal-fired generating plants required additional permitting or
pollution control technology. See Management's Discussion and Analysis of
Financial Condition, Accounting Policies and Other Matters under the
heading entitled Federal EPA Complaint and Notice of Violation and Note 9
to the consolidated financial statements entitled Commitments and
Contingencies, incorporated by reference in Items 7 and 8 respectively
for further information.
- Rules issued by the EPA and certain states that require substantial
reductions in NOx emissions. The compliance dates for these rules range
from 2003 to 2005. AEP is installing (or has installed) emission control
technology and is taking other measures to comply with required
reductions. See Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters and Note 9 to the
consolidated financial statements entitled Commitments and Contingencies,
incorporated by reference in Items 7 and 8 respectively, under the
heading entitled NOx Reductions for further information.
- CERCLA, which imposes upon owners and previous owners of sites, as well
as transporters and generators of hazardous material disposed of at such
sites, costs for environmental remediation. AEP does not, however,
anticipate that any of its currently identified CERCLA-related issues
will result in material costs or penalties to the AEP System. See
Management's Discussion and Analysis of Financial Condition, Accounting
Policies and Other Matters, incorporated by reference in Item 7, under
the heading entitled Superfund for further information.
- The Federal Clean Water Act, which prohibits the discharge of pollutants
into waters of the United States except pursuant to appropriate permits.
There are, however, no matters material to the AEP System currently
pending under the Clean Water Act.
- Solid and hazardous waste laws and regulations, which govern the
management and disposal of certain wastes. The majority of solid waste
created from the combustion of coal and fossil fuels is fly ash and other
coal combustion byproducts, which the EPA has determined are not
hazardous waste governed subject to RCRA.
In addition to imposing continuing compliance obligations, these laws and
regulations authorize the imposition of substantial penalties for noncompliance,
including fines, injunctive relief and other sanctions.
AEP's subsidiaries will confront several new environmental policies and
regulations over the next decade with the potential for substantial control
costs and premature retirement of some generating plants. These could include
(i) new or additional controls on sulfur dioxide, NOx and mercury emissions from
future laws or regulations, or the possibility of an
adverse decision in the new source review litigation; (ii) a new Clean Water Act
rule to reduce fish and other aquatic organisms killed at once-through cooled
power plants; (iii) finalization and implementation of more stringent water
quality-based permit limits; and (iv) a possible future requirement to reduce
carbon dioxide emissions. See Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters, incorporated by reference in
Item 7, under the heading entitled Environmental Concerns and Issues for
information on current environmental issues.
AEP expects costs related to environmental controls to eventually be
reflected in some jurisdictions in the rates of AEP's public utility
subsidiaries. In Michigan, Ohio, Texas and Virginia, those costs may not be
recoverable if future market prices for electricity generated by plants in those
jurisdictions are insufficient to permit AEP to recover such costs. Moreover,
legislation adopted by certain states and proposed at the state and federal
level governing restructuring of the electric utility industry may also affect
the recovery of certain of these costs. There can be no assurance that these
costs will be recovered.
AEP's international operations are subject to environmental regulation by
various authorities within the host countries. Under certain circumstances,
these authorities may require modifications to these facilities and operations
or impose fines and other costs for violations of applicable statutes and
regulations. From time to time, these operations are named as parties to various
legal claims, actions, complaints or other proceedings related to environmental
matters. AEP's UK generation facilities will be subject to additional
environmental constraints in 2008 (which become more stringent after 2015)
because they are subject to regulation governing large combustion plants. In the
fourth quarter of 2002, AEP decided not to install certain emission control
technology on its Fiddler's Ferry and Ferrybridge generation facilities in 2008.
This decision and its legal and regulatory consequences will result in a
significant reduction in the estimated economic life of those facilities.
The cost of complying with applicable environmental laws, regulations and
rules is expected to be material to the AEP System.
See Management's Discussion and Analysis of Results of Operations and
Management's Discussion and Analysis of Financial Condition, Accounting Policies
and Other Matters and Note 9 to the consolidated financial statements entitled
Commitments and Contingencies, incorporated by reference in Items 7 and 8,
respectively, for further information with respect to environmental matters.
Environmental Expenditures
Expenditures related to generation facility compliance with air and water
quality standards during 2001 and 2002 and the current estimate for 2003 are
shown below. Substantial expenditures in addition to the amounts set forth below
may be required by the System in future years in connection with the
modification and addition of facilities at generating plants for environmental
quality controls in order to comply with air and water quality standards which
have been or may be adopted. Future expenditures could be significantly greater
if litigation regarding whether AEP properly installed emission control
equipment on its plants is resolved against AEP. See Note 9 to the consolidated
financial statements, entitled Commitments and Contingencies, incorporated by
reference in Item 8, for more information regarding this litigation and
environmental expenditures in general.
2001 2002 2003
ACTUAL ACTUAL ESTIMATE
-------- -------- --------
(IN THOUSANDS)
AEGCo................ $ 3,500 $ 1,200 $ 11,200
APCo................. 99,200 108,400 65,700
CSPCo................ 22,500 25,400 39,300
I&M.................. 700 1,200 18,500
KPCo................. 11,200 110,600 39,900
OPCo................. 125,300 110,300 53,100
PSO.................. 400 1,200 100
SWEPCo............... 9,200 3,400 9,000
TCC.................. 2,500 600 0
TNC.................. 800 1,900 0
-------- -------- --------
AEP System........... $275,300 $364,200 $236,800
======== ======== ========
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 is created by electricity flowing in
transmission and distribution lines, electrical equipment, household wiring, and
appliances.
A number of studies in the past several years have examined the possibility
of adverse health effects from EMF. While some of the epidemiological studies
have indicated some association between exposure to EMF and health effects, 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.
WHOLESALE OPERATIONS
GENERAL
AEP conducts its wholesale business operations through its public utility
subsidiaries (through which AEP also conducts its energy delivery operations),
AEPES, AEPR and Pro Serv. Wholesale operations use and manage the following
assets:
- Power generation facilities (or interests therein) owned by AEP's public
utility and other subsidiaries;
- Natural gas pipeline, storage and processing facilities;
- Coal mines and related facilities; and
- Barge, rail and other fuel transportation related assets.
Wholesale operations include the following activities:
- Through AEP's public utility subsidiaries, the generation and sale of
power (i) to retail customers at unbundled or bundled rates regulated at
least in part by state public utility commissions and (ii) at wholesale
at rates regulated, in certain instances, by the FERC.
- Trading and marketing energy commodities in transactions predominantly
limited to risk management around assets used or managed by AEP's
wholesale operations, including electric power, natural gas, natural gas
liquids, oil, coal, and SO(2) allowances in North America and, where
applicable, Europe. Electric power transactions in the United States are
conducted principally through AEP's public utility subsidiaries. Other
energy commodity and allowances transactions are conducted through AEPES
and AEPR.
- Entering into long-term transactions to buy or sell capacity, energy, and
ancillary services of electric generating facilities, either existing or
to be constructed, at various locations in North America and Europe.
- Through Pro Serv, providing engineering, construction, project management
and other consulting services for energy-related projects.
In October 2002 AEP announced its plans to reduce the exposure to energy
trading markets and to downsize the trading and wholesale marketing operations.
It is expected that in the future power trading and marketing operations will be
smaller in scope and size, will generally be limited to risk management around
AEP's assets and, accordingly, focused in those regions in which AEP owns
assets.
POWER GENERATION
General
Power generation accounts for the majority of wholesale operations revenue.
In 2002, on an as-reported basis, power generation revenue included the
following components: (i) 63% from retail sales at predominantly regulated
rates; (ii) 33% from power marketing transactions of a type AEP intends to
continue and which are regulated in certain instances by the FERC; (iii) 3% from
retail sales at rates not regulated by states; and (iv) 1% attributable to power
marketing transactions of a type that management has stated are transitional.
This final category of transactions will be reduced consistent with AEP's
decision to scale back certain trading and marketing operations as described in
the preceding paragraph.
AEP's public utility subsidiaries own approximately 38,000 MW of domestic
generation. See Deactivation and Planned Disposition of Generating Facilities
for a discussion of planned reductions in AEP's generating fleet. Other AEP
subsidiaries hold interests in entities owning 1,879 MW of domestic power
facilities and 5,235 MW of international power facilities. The AEP public
utility subsidiaries operate their generating plants as a single interconnected
and coordinated electric utility system. See Item 2 - Properties for more
information regarding generation facilities.
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 member-load ratio is calculated monthly by dividing such company's
highest monthly peak demand for the last twelve months by the aggregate of the
highest monthly peak demand for the last twelve months for all east zone
operating companies. As of December 31, 2002, the member-load ratios were as
follows:
PEAK
DEMAND MEMBER-LOAD
(KW) RATIO (%)
------ -----------
APCo..................... 6,010 28.2
CSPCo.................... 4,040 19.0
I&M...................... 4,323 20.3
KPCo..................... 1,551 7.3
OPCo..................... 5,360 25.2
Although the FERC has approved the right of withdrawal of CSPCo and OPCo
from the AEP Power Pool as part of its order approving the settlement agreements
and AEP's FERC restructuring application, CSPCo and OPCo have remained a party
to the AEP Power Pool. If CSPCo and OPCo continue to remain in the AEP Power
Pool, notification to or approval by the FERC may be required. See Management's
Discussion and Analysis of Results of Operations and Financial Condition, under
the headings entitled Industry Restructuring and Corporate Separation for a
discussion of AEP's corporate separation plan filed with the FERC and related
settlement agreements with state commissions and other intervenors.
The following table shows the net credits or (charges) allocated among the
parties under the Interconnection Agreement and AEP System Interim Allowance
Agreement during the years ended December 31, 2000, 2001 and 2002:
2000 2001 2002
--------- --------- ---------
(IN THOUSANDS)
APCo. ............... $(274,000) $(256,700) $(127,000)
CSPCo................ (250,400) (251,200) (267,000)
I&M.................. 93,900 166,200 113,600
KPCo. ............... (21,500) (27,600) (46,500)
OPCo. ............... 452,000 369,300 326,900
PSO, SWEPCo, TCC and TNC, and AEPSC are parties to a Restated and Amended
Operating Agreement originally dated as of January 1, 1997 (CSW Operating
Agreement). The CSW Operating Agreement requires the west zone public utility
subsidiaries to maintain specified annual planning reserve margins and requires
the subsidiaries that have capacity in excess of the required margins to make
such capacity available for sale to other AEP west zone subsidiaries as capacity
commitments. The CSW Operating Agreement also delegates to AEP Service
Corporation the authority to coordinate the acquisition, disposition, planning,
design and construction of generating units and to supervise the operation and
maintenance of a central control center.
The following table shows the net credits or (charges) allocated among the
parties under the CSW Operating Agreement during the years ended December 31,
2000, 2001 and 2002:
2000 2001 2002
------- ------- --------
(IN THOUSANDS)
PSO.................. $(9,000) $(6,500) $(53,700)
SWEPCo............... 55,400 62,300 67,800
TCC.................. 3,600 (13,500) 15,400
TNC.................. (50,000) (42,300) (29,500)
Power generated by or allocated or provided under the Interconnection
Agreement or CSW Operating Agreement to any public utility subsidiary is often
sold to customers (or in the case of the ERCOT area of Texas, REPs) by such
public utility subsidiary at rates approved (other than in the ERCOT area of
Texas) by the public utility commission in the jurisdiction of sale. In Ohio,
Virginia and the ERCOT area of Texas, such rates are based on a statutory
formula as those jurisdictions transition to the use of market rates for
generation. See Energy Delivery -- Regulation -- Rates.
Under the Interconnection Agreement, power allocated to a public utility
subsidiary that is not required to serve its native load is sold at wholesale on
behalf of such subsidiary. Under the CSW Operating Agreement, power generated
that is not needed to serve the native load of any public utility subsidiary is
sold at wholesale by the generating subsidiary. See Trading and Marketing of
Energy Commodities for a discussion of the trading and marketing of such power.
AEP's System Integration Agreement provides for the integration and
coordination of AEP's east and west zone operating subsidiaries, joint dispatch
of generation within the AEP System, and the distribution, between the two
operating zones, of costs and benefits associated with the System's generating
plants. It is designed to function as an umbrella agreement in addition to the
Interconnection Agreement and the CSW Operating Agreement, each of which
controls the distribution of costs and benefits within each zone.
Competition and Regulation
Retail Sales: AEP's public utility subsidiaries have the right (which in
some cases is exclusive) to sell electric power at retail within their
respective service areas in the states of Arkansas, Indiana, Kentucky,
Louisiana, Oklahoma, Tennessee, West Virginia and the SPP area of Texas. In
Michigan, Ohio and Virginia, AEP's public utility subsidiaries continue to
provide service to customers who have not been offered or have not selected
alternate service from competing suppliers. In those states, service is
currently being provided according to prescribed rules and rates. In the ERCOT
area of Texas, TCC and TNC sell power to Centrica, which provides PTB service to
certain former customers of TCC and TNC and must compete for customers.
AEP's public utility subsidiaries also compete with self-generation and
with distributors of other energy sources, such as natural gas, fuel oil and
coal, within their service areas. The primary factors in such competition are
price, reliability of service and the capability of customers to utilize sources
of energy other than electric power. With respect to competing generators and
self-generation, the public utility subsidiaries of AEP believe that they
generally maintain a favorable competitive position. With respect to alternative
sources of energy, the public utility subsidiaries of AEP believe that the
reliability of their service and the limited ability of customers to substitute
other cost-effective sources for electric power place them in a favorable
competitive position, even though their prices may be higher than the costs of
some other sources of energy.
Significant changes in the global economy in recent years have led to
increased price competition for industrial customers in the United States,
including those served by the AEP System. Some of these industrial customers
have requested price reductions from their suppliers of electric power. In
addition, industrial customers that are downsizing or reorganizing often close a
facility based upon its costs, which may include, among other things, the cost
of electric power. The public utility subsidiaries of AEP cooperate with such
customers to meet their business needs through, for example, providing various
off-peak or interruptible supply options pursuant to tariffs filed with the
various state commissions. Occasionally, these rates are first negotiated, and
then filed with the state commissions. The public utility subsidiaries believe
that they are unlikely to be materially adversely affected by this competition.
See Energy Delivery -- Regulation -- Rates for a description of the setting
of rates for power sold at bundled or unbundled state-regulated rates.
Wholesale Sales: The public utility subsidiaries of AEP, like the electric
industry generally, face increasing competition in the sale of available power
on a wholesale basis, primarily to other public utilities and power marketers.
The Energy Policy Act of 1992 was designed, among other things, to foster
competition in the wholesale market by creating a generation market with fewer
barriers to entry and mandating that all generators have equal access to
transmission services. As a result, there are more generators able to
participate in this market. The principal factors in competing for wholesale
sales are price (including fuel costs), availability of capacity and power and
reliability of service.
The public utility subsidiaries of AEP are subject to regulation by the
FERC under the Federal Power Act in respect of rates for interstate sales at
wholesale. See General -- Regulation -- FERC.
Seasonality
Sale of electric power is generally a seasonal business. In many parts of
the country, demand for power peaks during the hot summer months, with market
prices also peaking at that time. In other areas, power demand peaks during the
winter. The pattern of this fluctuation may change due to the nature and
location of AEP's facilities and the terms of power sale contracts AEP enters
into. In addition, AEP has historically sold less power, and consequently earned
less income, when weather conditions are milder. Unusually mild weather in the
future could diminish AEP's results of operations and may impact its financial
condition.
Fuel Supply
The following table shows the sources of power generated by the AEP System:
2000 2001 2002
---- ---- ----
Coal........................ 78% 74% 78%
Natural Gas................. 13% 12% 8%
Nuclear..................... 5% 11% 11%
Hydroelectric and other..... 4% 3% 3%
Variations in the generation of nuclear power are primarily related to
refueling outages and, in a portion of 2000, the shutdown of the Cook Plant to
respond to issues raised by the NRC. Variations in the generation of natural gas
power are primarily related to the availability of cheaper alternatives to
fulfill certain power requirements and to deactivate certain of its gas-fired
plants.
Coal and Lignite: AEP System generating companies procure coal and lignite
under a combination of purchasing arrangements including long-term contracts,
affiliate operations, short-term, and spot agreements with various producers and
coal trading firms. AEP believes, but cannot provide assurances that, it will be
able to secure coal and lignite of adequate quality and in adequate quantities
to operate its coal and lignite-fired units.
The following table shows the amount of coal delivered to the AEP System
during the past three years and the average delivered price of spot coal
purchased by System companies:
2000 2001 2002
------- ------- -------
Total coal delivered
to AEP operated
plants (thousands
of tons)........... 73,259 73,889 76,442
Average price per ton
of spot-purchased
coal............... $ 24.03 $ 27.30 $ 27.06
The coal supplies at AEP System plants vary from time to time depending on
various factors, including customers' usage of electric power, space
limitations, the rate of consumption at particular plants, labor unrest and
weather conditions which may interrupt deliveries. At December 31, 2002, the
System's coal inventory was roughly 56 days of normal usage. This estimate
assumes that the total supply would be utilized through the operation of plants
that use coal most efficiently.
In cases of emergency or shortage, system companies have developed programs
to conserve coal supplies at their plants. Such programs have been filed and
reviewed with officials of federal and state agencies and, in some cases, the
state regulatory agency has prescribed actions to be taken under specified
circumstances by System companies, subject to the jurisdiction of such agencies.
The FERC has adopted regulations relating, among other things, to the
circumstances under which, in the event of fuel emergencies or shortages, it
might order electric utilities to generate and transmit electric power to other
regions or systems experiencing fuel shortages, and to ratemaking principles by
which such electric utilities would be compensated. In addition, the federal
government is authorized, under prescribed conditions, to allocate coal and to
require the transportation thereof, for the use of power plants or major
fuel-burning installations.
Natural Gas: AEP, through its public utility subsidiaries, consumed over
163 billion cubic feet of natural gas during 2002 for generating power. A
majority of the gas fired electric generation plants are connected to at least
two natural gas pipelines, which provides greater access to competitive supplies
and improves reliability. A portfolio of long-term and short-term purchase and
transportation agreements (that are acquired on a competitive basis and based on
market prices) supplies natural gas requirements for each plant.
Nuclear: I&M and STPNOC have made commitments to meet certain of the
nuclear fuel requirements of the Cook Plant and STP, respectively. Steps
currently are being taken, based upon the planned fuel cycles for the Cook
Plant, to review and evaluate I&M's requirements for the supply of nuclear fuel.
I&M has made and will make purchases of uranium in various forms in the spot,
short-term, and mid-term markets until it decides that deliveries under
long-term supply contracts are warranted. TCC and the other STP participants
have entered into contracts with suppliers for (i) 100% of the uranium
concentrate sufficient for the operation of both STP units through spring 2006
and (ii) 50% of the uranium concentrate needed for STP through spring 2007.
For purposes of the storage of high-level radioactive waste in the form of
spent nuclear fuel, I&M has completed modifications to its spent nuclear fuel
storage pool. AEP anticipates that the Cook Plant has storage capacity to permit
normal operations through 2012. STP has on-site storage facilities with the
capability to store the spent nuclear fuel generated by the STP units over their
licensed lives.
Nuclear Waste and Decommissioning
I&M, as the owner of the Cook Plant, and TCC, as a partial owner of STP,
have a significant future financial commitment to safely dispose of SNF and
decommission and decontaminate the plants. The ultimate cost of retiring the
Cook Plant and STP may be materially different from estimates and funding
targets as a result of the:
- Type of decommissioning plan selected;
- Escalation of various cost elements (including, but not limited to,
general inflation);
- Further development of regulatory requirements governing decommissioning;
- Limited availability to date of significant experience in decommissioning
such facilities;
- Technology available at the time of decommissioning differing
significantly from that assumed in these studies; and
- Availability of nuclear waste disposal facilities.
Accordingly, management is unable to provide assurance that the ultimate cost of
decommissioning the Cook Plant and STP will not be significantly different than
current projections.
See Management's Discussion and Analysis of Results of Operations and
Management's Discussion and Analysis of Financial Condition, Accounting Policies
and Other Matters and Note 9 to the consolidated financial statements, entitled
Commitments and Contingencies, which are incorporated by reference in Items 7
and 8, respectively, for information with respect to nuclear waste and
decommissioning and related litigation.
Low-Level Radioactive Waste: The LLWPA mandates that the responsibility for
the disposal of low-level radioactive waste rests with the individual states.
Low-level radioactive waste consists largely of ordinary refuse and other items
that have come in contact with radioactive materials. Michigan and Texas do not
currently have disposal sites for such waste available. AEP cannot predict when
such sites may be available, but South Carolina and Utah operate low-level
radioactive waste disposal sites and accept low-level radioactive waste from
Michigan and Texas. AEP's access to the South Carolina facility is currently
allowed through the end of fiscal year 2008.
Deactivation and Planned Disposition of Generation Facilities
In September 2002, AEP indicated to ERCOT its intent to deactivate 16
gas-fired power plants (8 TCC plants and 8 TNC plants). ERCOT subsequently
conducted reliability studies that determined that seven plants (4 TCC plants
and 3 TNC plants) would be required to ensure reliability of the electricity
grid. As a result of these studies, ERCOT and AEP agreed to enter into
reliability must run agreements (which expired in December 2002, but have been
renewed for all but two units of these plants) to continue operation of these
plants. With ERCOT's approval, AEP proceeded with its planned deactivation of
the remaining nine plants.
TCC has also filed a plan of divestiture with the PUCT proposing to sell
all of its power generation assets in an effort to determine its level of
stranded costs in accordance with the Texas Act. The PUCT has dismissed its
proceeding relating to TCC's plan of divestiture in anticipation of promulgating
rules of general application regarding stranded cost determination for nuclear
facilities. See Energy Delivery-Regulatory Assets and Stranded Cost Recovery and
Post-Restructuring Wires Charges.
The assets to be sold have a generating capacity of 4,497 MW and include
eight gas-fired generating plants, one coal-fired plant, TCC's interest in
another coal-fired plant, a hydroelectric facility and TCC's interest in STP.
See Note 8 to the consolidated financial statements entitled Customer Choice and
Industry Restructuring, incorporated by reference in Item 8, for more
information on the planned disposition of TCC generation facilities.
TRADING AND MARKETING OF ENERGY COMMODITIES
AEP enters into transactions for the purchase and sale of electricity and
natural gas as part of wholesale trading operations. Electric and gas
transactions are executed over-the-counter with counterparties or through
brokers. Gas transactions are also executed through brokerage accounts with
brokers who are registered with the Commodity Futures Trading Commission.
Brokers and counterparties may require cash or cash related instruments to be
deposited on these transactions as margin against open positions.
AEP trades electricity and gas contracts with numerous counterparties.
Since AEP's open energy trading contracts are valued based on changes in
market prices of the related commodities, our exposures change daily.
In October 2002, AEP announced its plans to reduce its exposure to energy
trading markets and to downsize the trading and wholesale marketing operations.
It is expected that in the future power trading and marketing operations will be
smaller in scope, will generally be limited to risk management around AEP assets
and, accordingly, focused in regions in which AEP owns assets.
Energy Market Investigations
During 2002, several governmental entities launched investigations of
participants in energy trading markets, including AEP. A number of those
investigations resulted in data requests of AEP. See Management's Discussion and
Analysis of Financial Condition, Accounting Policies and Other Matters,
incorporated by reference in Item 7, under the heading Energy Market
Investigations.
NATURAL GAS PIPELINE, STORAGE AND PROCESSING FACILITIES
AEP, through certain subsidiaries, operates and owns an interest in a
significant amount of gas-related assets, including:
- 6,400 miles of natural gas pipelines between two systems;
- 128 billion cubic feet of storage among two facilities;
- Five natural gas processing plants; and
- Certain gas marketing contracts.
COAL MINES AND RELATED FACILITIES
AEP, through certain subsidiaries, holds various properties, coal reserves,
mining operations and royalty interests in Colorado, Kentucky, Louisiana, Ohio,
Pennsylvania and West Virginia.
BARGE, RAIL AND OTHER FUEL TRANSPORTATION RELATED ASSETS
AEP, through MEMCO Barge Line Inc., is engaged in the transportation of
coal and dry bulk commodities, primarily on the Ohio, Illinois, and Lower
Mississippi rivers for AEP, as well as unaffiliated customers. AEP, through
certain subsidiaries, owns or leases 7,000 railcars, 1,800 barges, 37 tug boats
and two coal handling terminals with 20 million tons of annual capacity.
STRUCTURED ARRANGEMENTS INVOLVING CAPACITY, ENERGY, AND ANCILLARY SERVICES
Dow
AEP has entered into an agreement with The Dow Chemical Company to
construct a 900 MW cogeneration facility at Dow's chemical facility in
Plaquemine, Louisiana. Commercial operation is expected in November 2003. AEP is
entitled to 100% of the facility's capacity and energy over The Dow Chemical
Company's requirements and has contracted to sell the power from this facility
to an unaffiliated party.
Buckeye
In January 2000, OPCo and NPC, an affiliate of Buckeye, entered into an
agreement relating to the construction and operation of a 510 MW gas-fired
electric generating peaking facility to be owned by NPC. From the commercial
operation date (which occurred in 2002) until the end of 2005, OPCo will be
entitled to 100% of the power generated by the facility, and responsible for the
fuel and other costs of the facility. After 2005, NPC and OPCo will be entitled
to 80% and 20%, respectively, of the power of the facility, and both parties
will generally be responsible for the fuel and other costs of the facility. OPCo
will also provide certain back-up power to NPC.
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.
The I&M Power Agreement provides for the sale by AEGCo to I&M of all the
power (and the energy associated therewith) available to AEGCo at the Rockport
Plant. I&M is obligated, whether or not power is available from AEGCo, to pay as
a demand charge for the right to receive such power (and as an energy charge for
any associated energy taken by I&M). Such amounts, when added to amounts
received by AEGCo from any other sources, will be at least
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 power (and the energy
associated therewith) available to AEGCo from both units of the Rockport Plant.
KPCo has agreed to pay to AEGCo the same amounts which I&M would have paid AEGCo
under the terms of the I&M Power Agreement for such entitlement. The KPCo unit
power agreement expires on December 31, 2004. The agreement will be extended
until December 31, 2009 for Unit 1 and December 31, 2022 for Unit 2 if AEP's
restructuring settlement agreement filed with the FERC becomes effective.
AEGCo and AEP have entered into a 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 the power requirements of a uranium enrichment
plant near Portsmouth, Ohio owned by the DOE. The sponsoring companies are now
entitled to receive and pay for all OVEC capacity (approximately 2,200 MW) in
proportion to their power participation ratios. The aggregate power
participation ratio of APCo, CSPCo, I&M and OPCo is 42.1%. The proceeds from the
sale of power by OVEC are designed to be sufficient for OVEC to meet its
operating expenses and fixed costs and to provide a return on its equity
capital. The Inter-Company Power Agreement, which defines the rights of the
owners and sets the power participation ratio of each, will expire by its terms
on March 12, 2006.
Buckeye
Contractual arrangements among OPCo, Buckeye and other investor-owned
electric utility companies in Ohio provide for the transmission and delivery,
over facilities of OPCo and of other investor-owned utility companies, of power
generated by the two units at the Cardinal Station owned by Buckeye and back-up
power to which Buckeye is entitled from OPCo under such contractual
arrangements, to facilities owned by 25 of the rural electric cooperatives which
operate in the State of Ohio at 342 delivery points. Buckeye is entitled under
such arrangements to receive, and is obligated to pay for, the excess of its
maximum one-hour coincident peak demand plus a 15% reserve margin over the
1,226,500 kilowatts of capacity of the generating units which Buckeye currently
owns in the Cardinal Station. Such demand, which occurred on August 1, 2002, was
recorded at 1,398,559 kilowatts.
ENERGY DELIVERY
GENERAL
AEP's public utility subsidiaries own and operate transmission and
distribution lines and other facilities to deliver electric power. See Item
2--Properties for more information regarding the transmission and distribution
lines. Most of the transmission and distribution services are sold, in
combination with electric power, to retail customers of AEP's public utility
subsidiaries in their service territories. These sales are made at rates
established by the state utility commissions of the states in which they
operate, and in some instances, the FERC as well. See Regulation-- Rates. The
FERC regulates and approves the rates for wholesale transmission transactions.
See General--Regulation-- FERC. As discussed below, some transmission services
also are separately sold to non-affiliated companies.
AEP's public utility subsidiaries hold franchises or other rights to
provide electric service in various municipalities and regions in their service
areas. In some cases, these 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 Wholesale Operations-- Generation-- Competition and
Regulation.
REGULATION
AEP is in the business of providing generation, transmission and
distribution services. The transmission and distribution functions are part of
AEP's energy delivery segment. The generation function is part of AEP's
wholesale operations segment. This discussion covers the regulation of
transmission and distribution, but also generation sold at retail (which would
otherwise be included in the wholesale operations segment discussion).
Rates
Historically, state utility commissions have established electric service
rates on a cost-of-service basis, which is designed to allow a utility an
opportunity to recover its cost of providing service and to earn a reasonable
return on its investment used in providing that service. A utility's cost of
service is generally comprised of its operating expenses, including operation
and maintenance expense, depreciation expense and taxes. State utility
commissions periodically adjust rates pursuant to a review of (i) a utility's
revenues and expenses during a defined test period and (ii) such utility's level
of investment. Absent a legal limitation, such as a law limiting the frequency
of rate changes or capping rates for a period of time as part of a transition to
customer choice of generation suppliers, a state utility commission can review
and change rates on its own initiative. Some states may initiate reviews at the
request of a utility, customer, governmental or other representative of a group
of customers. Such parties may, however, agree with 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 (i) is no longer provided
for in Ohio and (ii) may be limited in Indiana and Michigan, which have capped
rates. Fuel recovery is also limited in the 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 and its fuel recovery rate is capped through
February 29, 2004.
Ohio: CSPCo and OPCo operate as functionally separated utilities and
provide "default" retail electric service to customers at unbundled rates
established by the Ohio Act through December 31, 2005. Thereafter, CSPCo and
OPCo will continue to provide distribution services to retail customers at rates
approved by the PUCO. These rates will be frozen from December 31, 2005 to (i)
December 31, 2008 for CSPCo and (ii) December 31, 2007 for OPCo. Transmission
services will continue to be provided at rates established by the FERC. Default
retail generation service rates will be based on market prices pursuant to rules
currently under consideration by the PUCO.
Oklahoma: PSO provides retail electric service in Oklahoma at a bundled
rate approved by the OCC. PSO's rates are set on a cost-of-service basis. Fuel
and purchased power costs above the amount included in base rates are recovered
by applying a fuel adjustment factor to retail kilowatt-hour sales. The factor
is adjusted quarterly and is based upon forecasted fuel and purchased power
costs. Over or under collections of fuel costs for prior periods can be
recovered when new quarterly factors are established.
Texas: The Texas Act requires the legal separation of generation-related
assets from transmission and
distribution assets. TCC and TNC currently operate on a functionally separated
basis. In January 2002, TCC and TNC transferred all their retail customers in
the ERCOT area of Texas to MECPL, MEWTU and AEP Commercial and Industrial REP
(an AEP affiliate). TNC's retail SPP customers were ultimately transferred to
Mutual Energy SWEPCo L.P. (an AEP affiliate). TCC and TNC provide retail
transmission and distribution service on a cost-of-service basis at rates
approved by the PUCT and wholesale transmission service under tariffs approved
by the FERC consistent with PUCT rules.
The implementation of the business separation plan for SWEPCo operations in
the SPP area of Texas was delayed by the PUCT. As such, SWEPCo's Texas
operations continue to operate and to be regulated as a traditional bundled
utility with both base and fuel rates.
Virginia: APCo provides unbundled retail electric service in Virginia.
APCo's unbundled generation, transmission (which reflect FERC approved
transmission rates) and distribution rates as well as its functional separation
plan were approved by the VSCC in December 2001.
The Virginia Act capped base rates at their mid-1999 levels until the end
of the transition period (July 1, 2007), or sooner if the VSCC finds that a
competitive market for generation exists in Virginia. The Virginia Act permits
APCo to seek a one-time change to its capped non-generation rates after January
1, 2004. The Virginia Act allows adjustments to fuel rates during the transition
period and continues to permit utilities to recover their actual fuel costs, the
fuel component of their purchased power costs and certain capacity charges. APCo
recovers its generation capacity charges through capped base rates.
West Virginia: APCo and Wheeling Power Company provide retail electric
service at bundled rates approved by the WVPSC. A plan to introduce customer
choice was approved by the West Virginia Legislature in its 2000 legislative
session. However, implementation of that plan was placed on hold pending
necessary changes to the state's tax laws in a subsequent session. Those changes
have not been made.
While West Virginia generally allows recovery of fuel costs, the most
recent proceeding resulted in the suspension of an active fuel clause for APCo
and WPCo (though they continue to recover fuel costs through fixed bundled
rates). APCo and Wheeling Power Company are currently unable to change the
current level of fuel cost recovery, though this ability could be reinstated in
a future proceeding.
Other Jurisdictions: The public utility subsidiaries of AEP also provide
service at regulated bundled rates in Arkansas, Kentucky, Louisiana and
Tennessee and regulated unbundled rates in Michigan.
The table below illustrates the current rate regulation status of the
states in which the public utility subsidiaries of AEP operate:
FUEL CLAUSE RATES PERCENTAGE
------------------------------------------------- OF AEP
STATUS OF BASE RATES FOR SYSTEM SALES SYSTEM
----------------------------------------------- PROFITS SHARED RETAIL
JURISDICTION POWER SUPPLY ENERGY DELIVERY STATUS INCLUDES W/RATEPAYERS REVENUES(1)
------------ ---------------------- ---------------------- -------------- -------------- --------------- -----------
Ohio Frozen through 2005 Distribution frozen None Not applicable Not applicable 30%
through 2007 for OPCo
and 2008 for CSP;
Transmission frozen
through 2005
Texas
(TCC, TNC) See footnote 2 Not capped or frozen Not applicable Not applicable Not applicable 17%(2)
Texas
(SWEPCo) Capped until 6/15/03 Active Fuel and fuel Yes, above base 3%
portion of levels
purchased
power
Indiana Capped until 1/1/05(3) Capped until Fuel and fuel No 10%
3/1/04(3) portion of
purchased
power
Virginia Capped until as late Capped until as late Active Fuel and fuel No 9%
as 7/1/07(4) as 7/1/07(4) portion of
purchased
power
West Virginia Fixed(5) Suspended(5) Fuel and fuel Yes, but 9%
portion of suspended
purchased
power
Oklahoma Cap expired 1/1/03 Active Fuel and fuel Yes 9%
portion of
purchased
power
Louisiana Capped until 6/15/05 Active Fuel and fuel Yes, above base 5%
portion of levels
purchased
power
Kentucky Frozen until 6/15/03(6) Active Fuel and fuel Yes, above base 3%
portion of levels
purchased
power
Arkansas Capped until 6/15/03 Active Fuel and fuel Yes, above base 2%
portion of levels
purchased
power
Michigan Capped until 1/1/05(7) Capped until 1/1/05(7) Capped until Fuel and fuel Yes, in some 2%
1/1/04(8) portion of areas, but
purchased suspended
power
Tennessee Not capped or frozen Active Fuel and fuel No 1%
portion of
purchased
power
---------------------------------
(1) Represents the percentage of revenues from sales to retail customers from
AEP utility companies operating in each state to the total AEP System
revenues from sales to retail customers for the year ended December 31,
2002.
(2) Retail electric service in the ERCOT area of Texas is provided to most
customers through unaffiliated REPs which must offer PTB rates until January
1, 2007. The percentage of revenues shown includes revenues from power sales
contracts between MECPL and TCC and MEWTU and TNC.
(3) Capped base and fuel rates pursuant to a 1999 settlement with base rate
freeze extended pursuant to merger stipulation.
(4) Base rates are capped until the earlier of 7/1/07 or a finding by the VSCC
that a competitive market for generation exists. One-time change in
non-generation rates is allowed in Virginia after 1/1/04.
(5) Rates fixed and expanded net energy clause suspended in West Virginia
pursuant to a 1999 rate case stipulation, but subject to change in a future
proceeding.
(6) Utilities may request that an environmental surcharge be imposed to recover
costs associated with the installation of emission control equipment.
(7) Capped base and fuel rates pursuant to a 1999 settlement and base rates
extended pursuant to merger stipulation.
(8) Michigan fuel rates capped until 1/1/04 pursuant to a 1999 fuel settlement.
AEP TRANSMISSION POOL
Transmission Equalization Agreement
APCo, CSPCo, I&M, KPCo and OPCo operate their transmission lines as a
single interconnected and coordinated system and are parties to the Transmission
Equalization Agreement, dated April 1, 1984, as amended (TEA), defining how they
share the costs and benefits associated with their relative ownership of the
extra-high-voltage transmission system (facilities rated 345 KV and above) and
certain facilities operated at lower voltages (138 KV and above). This sharing
is based upon each company's "member-load ratio." The member-load ratio is
calculated monthly by dividing such company's highest monthly peak demand for
the last twelve months by the aggregate of the highest monthly peak demand for
the last twelve months for all east zone operating companies. As of December 31,
2002, the member-load ratios were as follows:
PEAK
DEMAND MEMBER-LOAD
(KW) RATIO (%)
------ -----------
APCo..................... 6,010 28.2
CSPCo.................... 4,040 19.0
I&M...................... 4,323 20.3
KPCo..................... 1,551 7.3
OPCo..................... 5,360 25.2
The following table shows the net credits or (charges) allocated among the
parties to the TEA during the years ended December 31, 2000, 2001 and 2002:
2000 2001 2002
-------- -------- -------
(IN THOUSANDS)
APCo................. $ 3,400 $ 3,100 $ 13,400
CSPCo................ (38,300) (40,200) (42,200)
I&M.................. 43,800 41,300 36,100
KPCo................. 6,000 4,600 5,400
OPCo................. (14,900) (8,800) (12,700)
Transmission Coordination Agreement
PSO, SWEPCo, TCC, TNC and AEPSC are parties to a Transmission Coordination
Agreement originally dated as of January 1, 1997 (TCA). The TCA establishes a
coordinating committee, which is charged with the responsibility of overseeing
the coordinated planning of the transmission facilities of the west zone public
utility subsidiaries, including the performance of transmission planning
studies, the interaction of such subsidiaries with independent system operators
and other regional bodies interested in transmission planning and compliance
with the terms of the OATT filed with the FERC and the rules of the FERC
relating to such tariff.
Under the TCA, the west zone public utility subsidiaries have delegated to
AEPSC the responsibility of monitoring the reliability of their transmission
systems and administering the AEP OATT on their behalf. The TCA also provides
for the 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, 2000, 2001 and 2002:
2000 2001 2002
------ ------ ------
(IN THOUSANDS)
PSO................... $ 3,300 $ 4,000 $ 4,200
SWEPCo................ 5,900 5,400 5,000
TCC................... (3,400) (3,900) (3,600)
TNC................... (5,800) (5,500) (5,600)
Transmission Services for Non-Affiliates
In addition to providing transmission services in connection with their own
power sales, AEP's public utility subsidiaries and other System companies also
provide transmission services for non-affiliated companies. See Regulation--
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:
- The allocation of transmission costs and revenues and
- The allocation of third-party transmission costs and revenues and System
dispatch costs.
The System Transmission Integration Agreement contemplates that additional
service schedules may be added as circumstances warrant.
COMPETITION
The public utility subsidiaries of AEP, like many other electric utilities,
have traditionally provided electric generation and energy delivery, consisting
of transmission and distribution services, as a single product to their retail
customers. Legislation has been enacted in Michigan, Ohio, Texas and Virginia
that allows for customer choice of generation supplier. Although restructuring
legislation has been passed in Oklahoma and West Virginia, it has been delayed
indefinitely in Oklahoma and not implemented in West Virginia. In addition,
restructuring legislation in Arkansas has been repealed. See General--Electric
Restructuring Legislation. Customer choice legislation generally allows
competition in the generation and sale of electric power, but not in its
transmission and distribution.
See Management's Discussion and Analysis of Results of Operations and
Management's Discussion and Analysis of Financial Condition, Accounting Policies
and Other Matters and Note 8 to the consolidated financial statements entitled
Customer Choice and Industry Restructuring incorporated by reference in Items 7
and 8, respectively, for further information with respect to restructuring
legislation affecting AEP subsidiaries.
SEASONALITY
Sale of electric power is generally a seasonal business. In many parts of
the country, demand for power peaks during the hot summer months, with market
prices also peaking at that time. In other areas, power demand peaks during the
winter. The pattern of this fluctuation may change due to the nature and
location of AEP's facilities and the terms of power sale contracts AEP enters
into. In addition, AEP has historically sold less power, and consequently earned
less income, when weather conditions are milder. Unusually mild weather in the
future could diminish AEP's results of operations and may impact its financial
condition.
REGIONAL TRANSMISSION ORGANIZATIONS
On April 24, 1996, the FERC issued orders 888 and 889. These orders require
each public utility that owns or controls interstate transmission facilities to
file an open access network and point-to-point transmission tariff that offers
services comparable to the utility's own uses of its transmission system. The
orders also require utilities to functionally unbundle their services, by
requiring them to use their own tariffs in making off-system and third-party
sales. As part of the orders, the FERC issued a pro-forma tariff that reflects
the Commission's views on the minimum non-price terms and conditions for
non-discriminatory transmission service. In addition, the orders require all
transmitting utilities to establish an Open Access Same-time Information System
(OASIS), which electronically posts transmission information such as available
capacity and prices, and require utilities to comply with Standards of Conduct
that prohibit utilities' system operators from providing non-public transmission
information to the utility's merchant employees. The orders also allow a utility
to seek recovery of certain prudently incurred stranded costs that result from
unbundled transmission service.
In December 1999, FERC issued Order 2000, which provides for the voluntary
formation of RTOs, entities created to operate, plan and control utility
transmission assets. Order 2000 also prescribes certain characteristics and
functions of acceptable RTO proposals.
AEP is required, as a condition of FERC's approval in 2000 of AEP's merger
with CSW, to transfer functional control of its transmission facilities to one
or more RTOs. In May 2002, AEP announced an agreement with PJM to pursue terms
for its east zone public utility subsidiaries to participate in PJM, a
FERC approved RTO. In July 2002, the FERC tentatively approved AEP subsidiaries'
decision to join PJM, subject to certain conditions being met. The satisfaction
of these conditions is only partially within AEP's control. AEP's public utility
subsidiaries have filed applications with the state utility commissions of
Indiana, Kentucky, Ohio and Virginia requesting approval of the transfer of
functional control of transmission assets in those states to PJM. Those
applications are pending. In February 2003, the Virginia legislature enacted
legislation that would prohibit the transfer of functional control of
transmission assets to an RTO until at least July 2004.
In July 2002, FERC conditionally accepted filings related to a proposed
consolidation of MISO and the SPP. In that order the FERC required AEP's west
zone subsidiaries in SPP to file reasons why those subsidiaries should not be
required to join MISO. SWEPCo has filed an application with the LPSC requesting
approval of the transfer of functional control of its Louisiana transmission
assets to MISO and intends to make a similar filing in Arkansas with respect to
its Arkansas transmission assets. AEP presently plans to transfer functional
control of its transmission facilities in SPP to MISO or the merged MISO/SPP.
TEXAS REGULATORY ASSETS AND STRANDED COST RECOVERY AND POST-RESTRUCTURING WIRES
CHARGES
Certain transmission and distribution utilities in Texas whose generation
assets were unbundled pursuant to the Texas Act may recover generation-related
regulatory assets and generation-related stranded costs. Regulatory assets
consist of the Texas jurisdictional amount of generation-related regulatory
assets and liabilities in the audited financial statements as of December 31,
1998. Stranded costs consist of the positive excess of the net regulated book
value of generation assets over the market value of those assets, taking
specified factors into account. The Texas Act allows alternative methods of
valuation to determine the fair market value of generation assets, including
outright sale, full and partial stock valuation and asset exchanges, and also,
for nuclear generation assets, the ECOM model.
The Texas Act further permits utilities to establish a special purpose
entity to issue securitization bonds for the recovery of regulatory assets and,
after the 2004 true-up proceeding, the amount of stranded costs and remaining
regulatory assets not previously securitized. Securitization bonds allow for
regulatory assets and stranded costs to be refinanced with recovery of the bond
principal and financing costs ensured through a non-bypassable rate surcharge by
the regulated transmission and distribution utility over the life of the
securitization bonds. Any stranded costs not recovered through the sale of
securitization bonds may be recovered through a separate non-bypassable
competitive transition charge to transmission and distribution customers.
Regulatory Assets
In 1999, TCC filed an application with the PUCT to securitize approximately
$1.27 billion of its retail generation-related regulatory assets and
approximately $47 million in other qualified restructuring costs. On March 27,
2000, the PUCT issued an order authorizing issuance of up to $797 million of
securitization bonds including $764 million for recovery of net generation-
related regulatory assets and $33 million for other qualified refinancing costs.
The securitization bonds were issued in February 2002. TCC has included a
transition charge in its distribution rates to repay the bonds over a 14-year
period. In addition, another $185 million of generation-related regulatory
assets are being recovered through distribution rates beginning in January 2002.
Remaining generation-related regulatory assets of approximately $214 million
originally included by TCC in its 1999 securitization request along with certain
other regulatory assets will be included in TCC's request to recover stranded
costs in the 2004 true-up proceeding.
Stranded Costs
In a March 2000 filing with the PUCT to determine unbundled transmission
and distribution charges and initial stranded cost recovery, TCC requested
recovery of an additional $1.1 billion of stranded costs and regulatory assets
that were not securitized. In October 2001, the PUCT issued an order in the UCOS
proceeding determining an initial amount of TCC ECOM or stranded costs of
approximately negative $615 million based upon the PUCT's ECOM model. The ruling
indicated that TCC costs were below market after securitization of regulatory
assets. TCC disagrees with the ruling and believes it has positive stranded
costs in addition to the securitized regulatory assets.
As a result of this stranded cost determination, the PUCT ordered TCC to
refund $55 million of estimated excess earnings for the period 1999 through 2001
to customers through a credit applied to distribu-
tion rates over a five-year period. TCC appealed the PUCT's estimate of stranded
costs and refund of excess earnings, among other issues, to the Travis County
District Court. This estimate may be superseded by a final determination made as
part of the 2004 true-up proceedings.
The final amount of TCC's stranded costs including regulatory assets and
ECOM will be established by the PUCT in the 2004 true-up proceeding. Pursuant to
PUCT rules, if TCC's total stranded costs determined in the 2004 true-up
proceeding are less than the amount of securitized regulatory assets, the PUCT
can implement an offsetting credit to transmission and distribution rates. The
Texas Third Circuit Court of Appeals ruled in February 2003 that the Texas Act
does not contemplate the refunding to customers of negative stranded costs. In
addition, the Court ruled that negative stranded costs cannot be offset against
other true-up adjustments, including under-recovered fuel amounts. This ruling
may be appealed to the Texas Supreme Court, which has discretion as to whether
to accept and consider the appeal.
2004 True-Up Proceedings
Beginning as early as January 2004, the PUCT will conduct true-up
proceedings (with respect to the ERCOT area of Texas) for each investor-owned
utility, its affiliated REP and affiliated power generation company. The purpose
of the true-up proceeding is to (i) quantify and reconcile the amount of
stranded costs and generation-related regulatory assets that have not yet been
securitized, (ii) conduct a true-up of the PUCT ECOM model for 2002 and 2003 to
reflect market prices determined in required capacity auctions, (iii) establish
final fuel recovery balances and (iv) determine the price to beat clawback
component. The true-up proceeding will generally result in either additional
charges or credits to retail customers through transmission and distribution
rates collected by their REPs and remitted to the utility.
Stranded Cost and Generation-Related Regulatory Asset Determination: The
Texas Act authorized the use of several valuation methodologies to quantify
stranded costs and generation-related regulatory assets in the 2004 true-up
proceeding, including by the sale of assets. TCC filed a plan of divestiture
with the PUCT in December 2002 seeking approval to sell its generation assets to
determine their market value. The PUCT has dismissed its proceeding relating to
TCC's plan of divestiture in anticipation of promulgating rules of general
application regarding stranded cost determination. If the PUCT determines the
sale of assets methodology cannot be used to determine the market value of STP,
TCC intends to pursue the use of one or more market valuation methods.
Divestiture of TCC's interest in STP to a nonaffiliate will also require NRC
approval. TNC does not have any recoverable stranded costs or generation-related
regulatory assets that can be considered as part of the 2004 true-up.
ECOM/Capacity Auction Component: The PUCT used a computer model or
projection, called an ECOM model, to estimate stranded costs related to
generation plant assets in the UCOS proceeding. In connection with using the
ECOM model to calculate the stranded cost estimate, the PUCT estimated the
market power prices that will be received in the competitive wholesale
generation market. Any difference between the ECOM model market prices and
actual market power prices as measured by generation capacity auctions required
by the Texas Act during the period of January 1, 2002 through December 31, 2003
will be a component of the 2004 true-up proceeding, either increasing or
decreasing the amount of recovery for TCC. Auctions to date have generally
indicated that market prices have been lower than the PUCT's ECOM estimates.
Unless this is reversed, TCC's recovery in the 2004 true-up proceeding would be
increased. In the event TCC has transferred its generation assets to an
affiliate, the Texas Act would require TCC to remit to its affiliate the
recovery amount accruing after the transfer. See Note 8 to the consolidated
financial statements, entitled Customer Choice and Industry Restructuring,
incorporated by reference in Item 8, for a discussion of the current calculation
of the difference between the market price and ECOM estimate.
Fuel Recovery Balance Determination: The amount TCC or TNC recovers in the
2004 true-up proceeding could be increased or reduced (or the amount TCC must
refund could be increased) by any under or over-recovery of fuel. The fuel
component will be determined by the amount of fuel costs and expenses the PUCT
approves based on a final fuel reconciliation that TCC filed on December 2, 2002
and that TNC filed on June 3, 2002. TCC's fuel reconciliation covers its fuel
costs from the period beginning July 1, 1998 and ending December 31, 2001. TCC's
fuel reconciliation filing seeks approval for $1.6 billion in fuel expense
collected from retail customers during that period. TCC's fuel reconciliation
filing reflects a fuel over-recovery balance, as of December 31, 2001, of $63.5
million, including
interest. A procedural schedule has been set with a hearing scheduled to begin
May 7, 2003. TNC's fuel reconciliation requests approval of $292 million in fuel
costs associated with serving both ERCOT and SPP retail customers from July 1,
2000 through December 31, 2001. It reflects a fuel under-recovery balance, as of
December 31, 2001, of $26.9 million, including interest. The amounts in this
paragraph may periodically be adjusted as filings are updated or adjusted. A
final order from the PUCT is expected in the first half of 2003. Any under or
over-recovery, plus interest thereon, will be recovered from or returned to
customers as a component of the 2004 true-up proceeding.
Price to Beat Clawback Component: The amount TCC or TNC recovers in the
2004 true-up proceeding could be reduced (or the amount TCC or TNC must refund
could be increased) by the PTB clawback component. If MECPL and MEWTU (which are
no longer affiliated with TCC or TNC) continue to serve 60% or more of TCC's and
TNC's respective PTB load as of January 1, 2004 and the PTB (reduced by
non-bypassable wires charges) exceeds the market price of electricity, any such
excess must be credited to customers of TCC and TNC in the 2004 true-up
proceeding, by up to $150 per customer, subject to certain adjustments. The
Texas Act provides that MECPL and MEWTU effectively indemnify TCC and TNC,
respectively, for any PTB clawback amounts assessed them. The MECPL and MEWTU
sale agreements provide that Centrica (as purchaser of MECPL and MEWTU) and AEP
Utilities (the parent of TCC and TNC, as seller of MECPL and MEWTU) will share
responsibility for this indemnity.
Further Securitization Bonds and Wires Charges: After final determination
of its stranded costs and other true-up adjustments by the PUCT, TCC expects to
issue securitization bonds in the amount of its non-securitized stranded costs
and generation-related regulatory assets determined in the 2004 true-up
proceeding. The bonds can have a maximum term of 15 years. If securitization
bonds are not issued to finance all non-securitized stranded costs and
generation-related regulatory assets, TCC will seek recovery of these amounts as
well as its other true-up adjustments, through a non-bypassable competition
transition charge in transmission and distribution rates.
For a discussion of recovery of regulatory assets and stranded costs in
Ohio and Virginia, see Note 8 to the consolidated financial statements entitled
Customer Choice and Industry Restructuring, incorporated by reference in Item 8.
OTHER INVESTMENTS
AEP has made certain investments in telecommunications, international
energy and other concerns. In 2002, AEP wrote down the value of certain of those
investments. See Management's Discussion and Analysis of Results of Operations
and Management's Discussion and Analysis of Financial Condition, Accounting
Policies and Other Matters and Note 13 to the consolidated financial statements
entitled Asset Impairment and Investment Value Losses, incorporated by reference
in Items 7 and 8, respectively.
AEP also sold the following foreign investments in 2002:
- SEEBOARD, an electricity supply and distribution company in the United
Kingdom serving 2,000,000 customers and covering 3,000 square miles of
service territory.
- CitiPower, a retail electricity and gas supply and distribution
subsidiary in Australia serving 240,000 customers.
PART II
--------------------------------------------------------------------------------
Item 6. SELECTED FINANCIAL DATA
--------------------------------------------------------------------------------
The information required by this item is incorporated herein by reference
to the material under Selected Consolidated Financial Data in the 2002 Annual
Reports.
As described in Note 28 to the Consolidated Financial Statements, the
Company's 2002 and 2001 Consolidated Financial Statements have been revised. The
summary financial data incorporated by reference herein gives effect to such
revisions.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
--------------------------------------------------------------------------------
The information required by this item is incorporated herein by reference
to the material under Management's Discussion and Analysis of Results of
Operations and Management's Discussion and Analysis of Financial Condition,
Contingencies and Other Matters in the 2002 Annual Report.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
--------------------------------------------------------------------------------
The information required by this item is incorporated herein by reference
to the material under Management's Discussion and Analysis of Financial
Condition, Contingencies and Other Matters in the 2002 Annual Report.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
--------------------------------------------------------------------------------
The information required by this item is incorporated herein by reference
to the financial statements and financial statement schedules described under
Item 15 herein.
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
--------------------------------------------------------------------------------
(a) The following documents are filed as a part of this report:
1. FINANCIAL STATEMENTS:
The following financial statements have been incorporated herein by
reference pursuant to Item 8.
PAGE
----
Consolidated Statements of Operations for the years ended
December 31, 2002, 2001, and 2000; Consolidated Balance Sheets
as of December 31, 2002 and 2001; Consolidated Statements of
Cash Flows for the years ended December 31, 2002, 2001, and
2000; Consolidated Statements of Common Shareholders' Equity and
Comprehensive Income for the years ended December 31, 2002,
2001, and 2000; Schedule of Consolidated Cumulative Preferred
Stocks of Subsidiaries at December 31, 2002 and 2001; Schedule
of Consolidated Long-term Debt of Subsidiaries at December 31,
2002 and 2001; Combined Notes to Consolidated Financial
Statements; Independent Auditors' Report.
3. EXHIBITS:
Exhibits for AEP are listed in the Exhibit Index and are E-1
incorporated herein by reference
(b) Reports on Forms 8-K:
NONE
(c) Exhibits:
See Exhibit Index beginning on page E-1.
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
AMERICAN ELECTRIC POWER COMPANY, INC.
By:
/s/ SUSAN TOMASKY
-------------------------------------
(SUSAN TOMASKY, VICE PRESIDENT,
SECRETARY AND CHIEF FINANCIAL
OFFICER)
Date: May 14, 2003
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
SIGNATURE TITLE DATE
--------- ----- ----
(I) PRINCIPAL EXECUTIVE OFFICER:
*E. LINN DRAPER, JR. Chairman of the Board, May 14, 2003
President,
Chief Executive Officer
And Director
(II) PRINCIPAL FINANCIAL OFFICER:
/s/ SUSAN TOMASKY Vice President, Secretary and May 14, 2003
------------------------------------------------ Chief Financial Officer
(SUSAN TOMASKY)
(III) PRINCIPAL ACCOUNTING OFFICER:
/s/ JOSEPH M. BUONAIUTO Controller and May 14, 2003
------------------------------------------------ Chief Accounting Officer
(JOSEPH M. BUONAIUTO)
(IV) A MAJORITY OF THE DIRECTORS:
*E. R. BROOKS
*DONALD M. CARLTON
*JOHN P. DESBARRES
*ROBERT W. FRI
*WILLIAM R. HOWELL
*LESTER A. HUDSON, JR.
*LEONARD J. KUJAWA
*RICHARD L. SANDOR
*THOMAS V. SHOCKLEY, III
*DONALD G. SMITH
*LINDA GILLESPIE STUNTZ
*KATHRYN D. SULLIVAN May 14, 2003
*By: /s/ SUSAN TOMASKY
------------------------------------------
(SUSAN TOMASKY, ATTORNEY-IN-FACT)
CERTIFICATIONS
I, E. Linn Draper, Jr., certify that:
1. I have reviewed this annual report on Form 10-K/A of American Electric
Power Company, Inc.
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Dated: May 14, 2003 By:
/s/ E. LINN DRAPER, JR.
--------------------------------------
E. Linn Draper, Jr.
Chief Executive Officer
CERTIFICATIONS
I, Susan Tomasky, certify that:
1. I have reviewed this annual report on Form 10-K/A of American Electric
Power Company, Inc.
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a. designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;
b. evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c. presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a. all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b. any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Dated: May 14, 2003 By:
/s/ SUSAN TOMASKY
--------------------------------------
Susan Tomasky
Chief Financial Officer
EXHIBIT INDEX
Certain of the following exhibits, designated with an asterisk (*), have
been previously filed. Items designated with two asterisks (**) are filed
herewith. The exhibits not so designated have heretofore been filed with the
Commission and, pursuant to 17 C.F.R. 229.10(d) and 240.12b-32, are
incorporated herein by reference to the documents indicated in brackets
following the descriptions of such exhibits. Exhibits, designated with a dagger
(+), are management contracts or compensatory plans or arrangements required to
be filed as an Exhibit to this Form pursuant to Item 14(c) of this report.
EXHIBIT NUMBER DESCRIPTION
--------------- -----------
AEP++
3(a) -- Copy of Restated Certificate of Incorporation of AEP, dated
October 29, 1997 [Quarterly Report on Form 10-Q of AEP for
the quarter ended September 30, 1997, File No. 1-3525,
Exhibit 3(a)].
3(b) -- Copy of Certificate of Amendment of the Restated Certificate
of Incorporation of AEP, dated January 13, 1999 [Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 1998, File No. 1-3525, Exhibit 3(b)].
3(c) -- Composite copy of the Restated Certificate of Incorporation
of AEP, as amended [Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1998, File No. 1-3525,
Exhibit 3(c)].
3(d) -- Copy of By-Laws of AEP, as amended through January 28, 1998
[Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1997, File No. 1-3525, Exhibit 3(b)].
4(a) -- Indenture (for unsecured debt securities), dated as of May
1, 2001, between AEP and The Bank of New York, as Trustee
[Registration Statement No. 333-86050, Exhibits 4(a), 4(b)
and 4(c)].
*4(b) -- Third Supplemental Indenture, dated as of June 11, 2002,
between AEP and The Bank of New York, as Trustee, for 5.75%
Senior Notes, Series C, due August 16, 2007.
*4(c) -- Forward Purchase Contract Agreement, dated as of June 11,
2002, between AEP and The Bank of New York, as Forward
Purchase Contract Agent.
10(a) -- Interconnection Agreement, dated July 6, 1951, among APCo,
CSPCo, KPCo, OPCo and I&M and with the Service Corporation,
as amended [Registration Statement No. 2-52910, Exhibit
5(a); Registration Statement No. 2-61009, Exhibit 5(b); and
Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)].
*10(b) -- Restated and Amended Operating Agreement, dated as of
January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC.
10(c) -- Transmission Agreement, dated April 1, 1984, among APCo,
CSPCo, I&M, KPCo, OPCo and with the Service Corporation as
agent, as amended [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1985, File No. 1-3525,
Exhibit 10(b); and Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1988, File No. 1-3525,
Exhibit 10(b)(2)].
*10(d) -- Transmission Coordination Agreement, dated October 29, 1998,
among PSO, TCC, TNC, SWEPCo and AEPSC.
10(e) -- Lease Agreements, dated as of December 1, 1989, between
AEGCo or I&M and Wilmington Trust Company, as amended
[Registration Statement No. 33-32752, Exhibits 28(c)(1)(C),
28(c)(2)(C), 28(c)(3)(C), 28(c)(4)(C), 28(c)(5)(C) and
28(c)(6)(C); Registration Statement No. 33-32753, Exhibits
28(a)(1)(C), 28(a)(2)(C), 28(a)(3)(C), 28(a)(4)(C),
28(a)(5)(C) and 28(a)(6)(C); and Annual Report on Form 10-K
of AEGCo for the fiscal year ended December 31, 1993, File
No. 0-18135, Exhibits 10(c)(1)(B), 10(c)(2)(B), 10(c)(3)(B),
10(c)(4)(B), 10(c)(5)(B) and 10(c)(6)(B); Annual Report on
Form 10-K of I&M for the fiscal year ended December 31,
1993, File No. 1-3570, Exhibits 10(e)(1)(B), 10(e)(2)(B),
10(e)(3)(B), 10(e)(4)(B), 10(e)(5)(B) and 10(e)(6)(B)].
10(f) -- Lease Agreement dated January 20, 1995 between OPCo and JMG
Funding, Limited Partnership, and amendment thereto
(confidential treatment requested) [Annual Report on Form
10-K of OPCo for the fiscal year ended December 31, 1994,
File No. 1-6543, Exhibit 10(l)(2)].
E-1
EXHIBIT NUMBER DESCRIPTION
--------------- -----------
10(g) -- Modification No. 1 to the AEP System Interim Allowance
Agreement, dated July 28, 1994, among APCo, CSPCo, I&M,
KPCo, OPCo and the Service Corporation [Annual Report on
Form 10-K of AEP for the fiscal year ended December 31,
1996, File No. 1-3525, Exhibit 10(l)].
10(h)(1) -- Agreement and Plan of Merger, dated as of December 21, 1997,
By and Among American Electric Power Company, Inc., Augusta
Acquisition Corporation and Central and South West
Corporation [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1997, File No. 1-3525,
Exhibit 10(f)].
10(h)(2) -- Amendment No. 1, dated as of December 31, 1999, to the
Agreement and Plan of Merger [Current Report on Form 8-K of
AEP dated December 15, 1999, File No. 1-3525, Exhibit 10].
+10(i)(1) -- AEP Deferred Compensation Agreement for certain executive
officers [Annual Report on Form 10-K of AEP for the fiscal
year ended December 31, 1985, File No. 1-3525, Exhibit
10(e)].
+10(i)(2) -- Amendment to AEP Deferred Compensation Agreement for certain
executive officers [Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1986, File No. 1-3525,
Exhibit 10(d)(2)].
+10(j) -- AEP Accident Coverage Insurance Plan for directors [Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 1985, File No. 1-3525, Exhibit 10(g)].
+10(k)(1) -- AEP Deferred Compensation and Stock Plan for Non-Employee
Directors, as amended June 1, 2000 [Annual Report on Form
10-K of AEP for the fiscal year ended December 31, 2000,
File No. 1-3525, Exhibit 10(i)(1)].
+10(k)(2) -- AEP Stock Unit Accumulation Plan for Non-Employee Directors,
as amended January 1, 2002[Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 2001, File No.
1-3525, Exhibit 10(i)(2)].
+10(l)(1)(A) -- AEP System Excess Benefit Plan, Amended and Restated as of
January 1, 2001 [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 2000, File No. 1-3525,
Exhibit 10(j)(1)(A)].
+10(l)(1)(B) -- Guaranty by AEP of the Service Corporation Excess Benefits
Plan [Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1990, File No. 1-3525, Exhibit
10(h)(1)(B)].
*+10(l)(1)(C) -- First Amendment to AEP System Excess Benefit Plan, dated as
of March 5, 2003.
+10(l)(2) -- AEP System Supplemental Retirement Savings Plan, Amended and
Restated as of June 1, 2001 (Non-Qualified) [Registration
Statement No. 333-66048, Exhibit 4].
+10(l)(3) -- Service Corporation Umbrella Trust for Executives [Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)].
+10(m)(1) -- Employment Agreement between E. Linn Draper, Jr. and AEP and
the Service Corporation [Annual Report on Form 10-K of AEGCo
for the fiscal year ended December 31, 1991, File No.
0-18135, Exhibit 10(g)(3)].
+10(m)(2) -- Memorandum of agreement between Susan Tomasky and the
Service Corporation dated January 3, 2001 [Annual Report on
Form 10-K of AEP for the fiscal year ended December 31,
2000, File No. 1-3525, Exhibit 10(s)].
*+10(m)(3)(A) -- Letter Agreement dated June 23, 2000 between AEPSC and Holly
K. Koeppel.
*+10(m)(3)(B) -- Letter Agreement dated April 19, 2001 between AEPR and Holly
K. Koeppel.
*+10(m)(4) -- Employment Agreement dated July 29, 1998 between AEPSC and
Robert P. Powers.
+10(n) -- AEP System Senior Officer Annual Incentive Compensation Plan
[Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)].
+10(o)(1) -- AEP System Survivor Benefit Plan, effective January 27, 1998
[Quarterly Report on Form 10-Q of AEP for the quarter ended
September 30, 1998, File No. 1-3525, Exhibit 10].
*+10(o)(2) -- First Amendment to AEP System Survivor Benefit Plan, as
amended and restated effective January 31, 2000.
+10(p) -- AEP Senior Executive Severance Plan for Merger with Central
and South West Corporation, effective March 1, 1999 [Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 1998, File No. 1-3525, Exhibit 10(o)].
*+10(q)(1) -- AEP System Incentive Compensation Deferral Plan dated
January 1, 2001.
*+10(q)(2) -- First Amendment to AEP System Incentive Compensation
Deferral Plan dated December 6, 2002.
E-2
EXHIBIT NUMBER DESCRIPTION
--------------- -----------
*+10(r) -- AEP System Nuclear Performance Long Term Incentive
Compensation Plan dated August 1, 1998.
*+10(s) -- Nuclear Key Contributor Retention Plan dated May 1, 2000.
+10(t) -- AEP Change In Control Agreement [Annual Report on Form 10-K
of AEP for the fiscal year ended December 31, 2001, File No.
1-3525, Exhibit 10(o)].
+10(u) -- AEP System 2000 Long-Term Incentive Plan [Proxy Statement of
AEP, March 10, 2000].
+10(v)(1) -- Central and South West System Special Executive Retirement
Plan as amended and restated effective July 1, 1997 [Annual
Report on Form 10-K of CSW for the fiscal year ended
December 31, 1998, File No. 1-1443, Exhibit 18].
+10(v)(2) -- Certified CSW Board Resolution of April 18, 1991 [Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 2001, File No. 1-3525, Exhibit 10(r)(2)].
+10(v)(3) -- CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW,
March 13, 1992].
+10(v)(4) -- Central and South West Corporation Executive Deferred
Savings Plan as amended and restated effective as of January
1, 1997 [Annual Report on Form 10-K of CSW for the fiscal
year ended December 31, 1998, File No. 1-1443, Exhibit 24].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the AEP 2002 Annual Report (for
the fiscal year ended December 31, 2002) which are
incorporated by reference in this filing.
*21 -- List of subsidiaries of AEP.
**23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
**99(a) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
**99(b) -- Certification of Chief Financial Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
E-3