EXHIBIT 99.1
PLEASE NOTE THAT THE INFORMATION CONTAINED IN THIS ITEM 1 DOES NOT REFLECT
EVENTS OCCURRING AFTER THE DATE OF THE FILING OF THE ANNUAL REPORT ON FORM 10-K
OF THE REGISTRANTS OTHER THAN AEP OR THE ANNUAL REPORT ON FORM 10-K/A IN THE
CASE OF AEP. NO ATTEMPT HAS BEEN MADE IN THIS REPORT TO MODIFY OR UPDATE OTHER
DISCLOSURES EXCEPT AS REQUIRED TO REFLECT THE EFFECTS OF THE NEW REPORTABLE
SEGMENTS.
GLOSSARY OF TERMS
The following abbreviations or acronyms used in Item 1 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.
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
SO2........................................Sulfur dioxide
SO2 Allowance..............................An allowance to emit one ton of sulfur dioxide granted under the Clean Air Act
Amendments of 1990
SPP........................................Southwest Power Pool
STPNOC.....................................STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on
behalf of its joint owners, including TCC
SWEPCo.....................................Southwestern Electric Power Company, a public utility subsidiary of AEP
TCA........................................Transmission Coordination Agreement dated January 1, 1997 by and among, PSO, SWEPCo,
TCC, TNC and AEPSC, which allocates costs and benefits in connection with
the operation of the transmission assets of the four public utility subsidiaries
TCC........................................AEP Texas Central Company, formerly Central Power and Light Company, a public utility
subsidiary of AEP
TEA........................................Transmission Equalization Agreement dated April 1, 1984 by and among APCo, CSPCo,
I&M, KPCo and OPCo, which allocates costs and benefits in connection with the
operation of transmission assets
Texas Act..................................Texas electric restructuring legislation
TNC........................................AEP Texas North Company, formerly West Texas Utilities Company, a public utility
subsidiary of AEP
TVA........................................Tennessee Valley Authority
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
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:
o Electric load and customer growth.
o Abnormal weather conditions
o Available sources and costs of fuels.
o Availability of generating capacity.
o The speed and degree to which competition is introduced to AEP's power
generation business.
o The ability to recover stranded costs in connection with possible/
proposed deregulation of generation.
o New legislation and government regulation
o Oversight and/or investigation of the energy sector or its participants.
o The ability of AEP to successfully control its costs.
o The success of acquiring new business ventures and disposing of existing
investments that no longer match AEP's corporate profile.
o International and country-specific developments affecting AEP's foreign
investments, including the disposition of any current foreign
investments and potential additional foreign investments.
o The economic climate and growth in AEP's service territory and changes
in market demand and demographic patterns.
o Inflationary trends.
o Electricity and gas market prices.
o Interest rates.
o Liquidity in the banking, capital and wholesale power markets.
o Actions of rating agencies.
o Changes in technology, including the increased use of distributed
generation within AEP's transmission and distribution service territory.
o Other risks and unforeseen events, including wars, the effects of
terrorism, embargoes and other catastrophic events.
Item 1. Business
General
Overview and Description of Subsidiaries
AEP was incorporated under the laws of the State of New York in 1906 and
reorganized in 1925. It is a registered public utility holding company under
PUHCA that owns, directly or indirectly, all of the outstanding common stock of
its public utility subsidiaries and varying percentages of other subsidiaries.
The service areas of AEP's public utility subsidiaries cover portions of the
states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma,
Tennessee, Texas, Virginia and West Virginia. The generating and transmission
facilities of AEP's public utility subsidiaries are interconnected, and their
operations are coordinated, as a single integrated electric utility system.
Transmission networks are interconnected with extensive distribution facilities
in the territories served. The public utility subsidiaries of AEP, which do
business as "American Electric Power," have traditionally provided electric
service, consisting of generation, transmission and distribution, on an
integrated basis to their retail customers. Restructuring legislation in
Michigan, Ohio, Texas and Virginia has caused or will cause AEP public utility
subsidiaries in those states to unbundle previously integrated regulated rates
for their retail customers.
The AEP System is an integrated electric utility system and, as a result,
the member companies of the AEP System have contractual, financial and other
business relationships with the other member companies, such as participation in
the AEP System savings and retirement plans and tax returns, sales of
electricity and transportation and handling of fuel. The member companies of the
AEP System also obtain certain accounting, administrative, information systems,
engineering, financial, legal, maintenance and other services at cost from a
common provider, AEPSC.
At December 31, 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)
Utility Operations:
Electric Generation
Residential........................... $ 3,701,000 $ 616,509 $ 533,061 $ 371,329 $ 118,654
Commercial............................ 2,126,000 276,238 442,847 224,843 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
Electric T&D.......................... (3,643,000) (594,089) (492,278) (321,721) (132,054)
-------------- ------------- ------------- ------------- ------------
Total Retail....................... 4,472,000 732,928 659,822 666,329 150,302
Marketing and Trading-Electricity..... 1,846,000 204,878 134,836 279,705 50,056
Unrealized MTM Income................. 270,000 18,089 13,388 0 0
Other................................. 202,000 264,486 99,836 259,009 46,271
-------------- ------------- ------------- ------------- ------------
Total Electric Generation.......... 6,790,000 1,220,381 907,882 1,205,043 246,629
-------------- ------------- ------------- ------------- ------------
Electric Transmission and Distribution
Transmission.......................... 922,000 186,960 107,673 118,812 50,381
Distribution.......................... 2,721,000 407,129 384,605 202,909 81,673
-------------- ------------- ------------- ------------- ------------
Total Electric T&D................. 3,643,000 594,089 492,278 321,721 132,054
-------------- ------------- ------------- ------------- ------------
Total Utility Operations........... 10,433,000 1,814,470 1,400,160 1,526,764 378,683
--------------- -------------- -------------- -------------- ------------
Investments- Gas Operations:
Marketing and Trading-Gas............. 3,444,000 0 0 0 0
Unrealized MTM Income................. (399,000) 0 0 0 0
--------------
Total Investments- Gas Operations.. 3,045,000 0 0 0 0
Investments- UK Operations................ 264,000 0 0 0 0
Investments- Other........................ 794,000 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)
Utility Operations:
Electric Generation
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
Electric T&D.......................... (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
Unrealized MTM Income....................... 25,574 0 (3,686) (8,490) (1,473)
Other......................................... 545,088 40,440 157,872 789,466 151,809
------------- ------------ ------------- ------------- -----------
Total Electric Generation.................. 1,523,452 518,100 736,484 1,135,946 377,387
------------- ------------ ------------- ------------- -----------
Electric Transmission and Distribution
Transmission.......................... 162,660 63,178 92,076 68,003 25,273
Distribution.......................... 427,013 212,369 256,160 486,544 48,080
------------- ------------ ------------- ------------- -----------
Total Electric T&D................. 589,673 275,547 348,236 554,547 73,353
------------- ------------ ------------- ------------- -----------
Total Utility Operations................. 2,113,125 793,647 1,084,720 1,690,493 450,740
-------------- ------------ ------------- -------------- ------------
Investments- Gas Operations:
Marketing and Trading-Gas............. 0 0 0 0 0
Unrealized MTM Income................. 0 0 0 0 0
Total Investments- Gas Operations.. 0 0 0 0 0
Investments- UK Operations................ 0 0 0 0 0
Investments- Other........................ 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.
Holding Company Regulation
The provisions of PUHCA, administered by the SEC, regulate many aspects of a
registered holding company system, such as the AEP System. PUHCA limits the
operations of a registered holding company system to a single integrated public
utility system and such other businesses as are incidental or necessary to the
operations of the system. In addition, PUHCA governs, among other things,
financings, sales or acquisitions of assets and intra-system transactions.
PUHCA and the rules and orders of the SEC currently require that
transactions between associated companies in a registered holding company system
be performed at cost with limited exceptions. Over the years, the AEP System has
developed numerous affiliated service, sales and construction relationships and,
in some cases, invested significant capital and developed significant operations
in reliance upon the ability to recover its full costs under these provisions.
The Division of Investment Management of the SEC has recommended the
conditional repeal of PUHCA. Under its recommendation, certain oversight
authority would be transferred to the FERC. Legislation has since been
introduced in numerous sessions of Congress that would repeal PUHCA, but such
legislation has not passed.
AEP-CSW Merger
On June 15, 2000, CSW (now known as AEP Utilities, Inc.) merged with and
into a wholly-owned merger subsidiary of AEP. As a result, CSW became a wholly
owned subsidiary of AEP. The four wholly owned public utility subsidiaries of
CSW--PSO, SWEPCo, TCC and TNC--became indirect wholly owned public utility
subsidiaries of AEP as a result of the merger. The merger was approved by the
FERC and the SEC (with respect to PUHCA).
On January 18, 2002, the U.S. Court of Appeals for the District of Columbia
ruled that the SEC failed to properly explain how the merger met the
requirements of PUHCA and remanded the case to the SEC for further review. The
court held that the SEC had not adequately explained its conclusions that the
merger met PUHCA requirements that the merging entities be "physically
interconnected" and that the combined entity was confined to a "single area or
region."
Management believes that the merger meets the requirements of PUHCA and
expects the matter to be resolved favorably.
Financing
General
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, included in the updated 2002 Annual Reports, under
the heading entitled Financial Condition for additional information with respect
to AEP's credit ratings, liquidity and specific financing activities.
Environmental and Other Matters
General
AEP's subsidiaries are currently subject to regulation by federal, state and
local authorities with regard to air and water-quality control and other
environmental matters, and are subject to zoning and other regulation by local
authorities. The environmental issues that are potentially material to the AEP
system include:
o The CAA and CAAA and state laws and regulations (including State
Implementation Plans) that require compliance, obtaining permits and
reporting as to air emissions.
o Litigation with the federal and certain state governments and certain
special interest groups regarding whether modifications to or
maintenance of certain coal-fired generating plants required additional
permitting or pollution control technology. See Management's 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, included in the updated 2002 Annual
Reports, for further information.
o 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, included in the updated 2002 Annual Reports, under the
heading entitled NOx Reductions for further information.
o CERCLA, which imposes upon owners and previous owners of sites, as well
as transporters and generators of hazardous material disposed of at such
sites, costs for environmental remediation. AEP does not, however,
anticipate that any of its currently identified CERCLA-related issues
will result in material costs or penalties to the AEP System. See
Management's Discussion and Analysis of Financial Condition, Accounting
Policies and Other Matters, included in the updated 2002 Annual Reports,
under the heading entitled Superfund for further information.
o The Federal Clean Water Act, which prohibits the discharge of pollutants
into waters of the United States except pursuant to appropriate permits.
There are, however, no matters material to the AEP System currently
pending under the Clean Water Act.
o Solid and hazardous waste laws and regulations, which govern the
management and disposal of certain wastes. The majority of solid waste
created from the combustion of coal and fossil fuels is fly ash and
other coal combustion byproducts, which the EPA has determined are not
hazardous waste governed subject to RCRA.
In addition to imposing continuing compliance obligations, these laws and
regulations authorize the imposition of substantial penalties for noncompliance,
including fines, injunctive relief and other sanctions.
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, included in the updated 2002 Annual
Reports, 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, included in the updated 2002 Annual Reports, 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, included in the
updated 2002 Annual Reports, 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.
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, included
in the updated 2002 Annual Reports, under the heading Energy Market
Investigations.
Utility Operations
General
Utility operations constitute the majority of AEP's business operations.
Utility operations include the generation, transmission and distribution of
electric power to retail customers and the supplying and marketing of electric
power at wholesale (through the electric generation function) to other electric
utility companies, municipalities and other market participants
Electric Generation
Facilities
AEP's public utility subsidiaries own approximately 38,000 MW of domestic
generation. See Deactivation and Planned Disposition of Generating Facilities
for a discussion of planned reductions in AEP's generating fleet. The AEP public
utility subsidiaries operate their generating plants as a single interconnected
and coordinated electric utility system. See Item 2 -- Properties of the Annual
Report on Form 10-K of AEP for the fiscal year ended December 31, 2002, filed on
March 20, 2003, 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, included
in the updated 2002 Annual Reports, 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 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 Marketing and Trading-
Electricity 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.
Marketing and Trading- Electricity
AEP enters into transactions for the purchase and sale of power as part of
its utility operations. Power transactions are executed with counterparties or
through brokers. Brokers and counterparties may require cash or cash related
instruments to be deposited on these transactions as margin against open
positions.
AEP trades power with numerous counterparties. Since AEP's open power
trading contracts are valued based on changes in market power prices, 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.
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 power 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:
o Type of decommissioning plan selected;
o Escalation of various cost elements (including, but not limited to,
general inflation);
o Further development of regulatory requirements governing decommissioning;
o Limited availability to date of significant experience in decommissioning
such facilities;
o Technology available at the time of decommissioning differing
significantly from that assumed in these studies; and
o 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, included in the updated 2002 Annual Reports, for
information with respect to nuclear waste and decommissioning and related
litigation.
Low-Level Radioactive Waste: The LLWPA mandates that the responsibility for
the disposal of low-level radioactive waste rests with the individual states.
Low-level radioactive waste consists largely of ordinary refuse and other items
that have come in contact with radioactive materials. Michigan and Texas do not
currently have disposal sites for such waste available. AEP cannot predict when
such sites may be available, but South Carolina and Utah operate low-level
radioactive waste disposal sites and accept low-level radioactive waste from
Michigan and Texas. AEP's access to the South Carolina facility is currently
allowed through the end of fiscal year 2008.
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 Texas 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, included in the updated 2002 Annual Reports, for more
information on the planned disposition of TCC generation facilities.
Structured Arrangements Involving Capacity, Energy, and Ancillary Services
In January 2000, OPCo and NPC, an affiliate of Buckeye, entered into an
agreement relating to the construction and operation of a 510 MW gas-fired
electric generating peaking facility to be owned by NPC. 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.
Electric Transmission and Distribution
General
AEP's public utility subsidiaries own and operate transmission and
distribution lines and other facilities to deliver electric power. See Item
2--Properties of the Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 2002, filed on March 20, 2003, 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 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 Competition.
AEP Transmission Pool
Transmission Equalization Agreement: APCo, CSPCo, I&M, KPCo and OPCo operate
their transmission lines as a single interconnected and coordinated system and
are parties to the Transmission Equalization Agreement, dated April 1, 1984, as
amended (TEA), defining how they share the costs and benefits associated with
their relative ownership of the extra-high-voltage transmission system
(facilities rated 345 KV and above) and certain facilities operated at lower
voltages (138 KV and above). 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 Regional Transmission Organizations.
AEP's public utility subsidiaries are subject to regulation by the FERC under
the FPA in respect of transmission of electric power.
Coordination of East and West Zone Transmission: AEP's System Transmission
Integration Agreement provides for the integration and coordination of the
planning, operation and maintenance of the transmission facilities of AEP's east
and west zone public utility subsidiaries. The System Transmission Integration
Agreement functions as an umbrella agreement in addition to the TEA and the TCA.
The System Transmission Integration Agreement contains two service schedules
that govern:
o The allocation of transmission costs and revenues and
o The allocation of third-party transmission costs and revenues and System
dispatch costs.
The System Transmission Integration Agreement contemplates that additional
service schedules may be added as circumstances warrant.
Regional Transmission Organizations
On April 24, 1996, the FERC issued orders 888 and 889. These orders require
each public utility that owns or controls interstate transmission facilities to
file an open access network and point-to-point transmission tariff that offers
services comparable to the utility's own uses of its transmission system. The
orders also require utilities to functionally unbundle their services, by
requiring them to use their own tariffs in making off-system and third-party
sales. As part of the orders, the FERC issued a pro-forma tariff that reflects
the Commission's views on the minimum non-price terms and conditions for
non-discriminatory transmission service. In addition, the orders require all
transmitting utilities to establish an Open Access Same-time Information System
(OASIS), which electronically posts transmission information such as available
capacity and prices, and require utilities to comply with Standards of Conduct
that prohibit utilities' system operators from providing non-public transmission
information to the utility's merchant 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.
Regulation
General
Except for retail generation sales in Ohio, Virginia and the ERCOT area of
Texas, AEP's public utility subsidiaries' retail rates and certain other matters
are subject to traditional regulation by the state utility commissions. Retail
sales in Michigan, while still regulated, are now made at unbundled rates. Other
states in AEP's service territory have also passed restructuring legislation
that has not been implemented or has been repealed. See Electric Restructuring
and Customer Choice Legislation and Rates. AEP's subsidiaries are also subject
to regulation by the FERC under the FPA. I&M and TCC are subject to regulation
by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the
operation of the Cook Plant and STP, respectively. AEP and its subsidiaries are
also subject to the broad regulatory provisions of PUHCA administered by the
SEC.
Rates
Historically, state utility commissions have established electric service
rates on a cost-of-service basis, which is designed to allow a utility an
opportunity to recover its cost of providing service and to earn a reasonable
return on its investment used in providing that service. A utility's cost of
service 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:
Percentage
Fuel Clause Rates Of AEP
System Sales System
Status of Base Rates for Profits Shared Retail
Jurisdiction Power Supply Energy Delivery Status Includes w/Ratepayers Revenues(1)
-------------- -------------------- -------------------- --------------- --------------- --------------- ----------------
Ohio Frozen 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 Active Fuel and fuel Yes, above base 3%
6/15/03 portion of levels
purchased
power
Indiana Capped until Capped until Fuel and fuel No 10%
1/1/05(3) 3/1/04(3) portion
of
purchased
power
Virginia Capped until as Capped until as late Active Fuel and fuel No 9%
lateas 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 Active Fuel and fuel Yes, above base 5%
6/15/05 portion of levels
purchased
power
Kentucky Frozen until Active Fuel and fuel Yes, above base 3%
6/15/03(6) portion of levels
purchased
power
Arkansas Capped until Active Fuel and fuel Yes, above base 2%
6/15/03 portion of levels
purchased
power
Michigan Capped until Capped until Capped until Fuel and fuel Yes, in some 2%
1/1/05(7) 1/1/05(7) 1/1/04(8) portion of areas, but
purchased suspended
power
Tennessee Not capped or Active Fuel and fuel No 1%
frozen portion of
purchased
power
(1) Represents the percentage of revenues from sales to retail customers from
AEP utility companies operating in each state to the total AEP System
revenues from sales to retail customers for the year ended December 31,
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.
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, included in the updated 2002 Annual Reports, for
more information on the current status of this proceeding.
Electric Restructuring and Customer Choice Legislation
Certain states in AEP's service area have adopted restructuring or customer
choice legislation. In general, this legislation provides for a transition from
bundled cost-based rate regulated electric service to unbundled cost-based rates
for transmission and distribution service and market pricing for the supply of
electricity with customer choice of supplier. At a minimum, this legislation
allows retail customers to select alternative generation suppliers. Electric
restructuring and/or customer choice began on January 1, 2001 in Ohio and on
January 1, 2002 in Michigan, Virginia and the ERCOT area of Texas. Electric
restructuring in the SPP area of Texas, 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, included in the updated 2002 Annual Reports, 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, included in the updated 2002 Annual Reports, 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 Regulation--FERC for a discussion of FERC regulation of transmission rates
and Regulation--Rates--Ohio for a discussion of the impact of restructuring on
distribution rates.
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 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, included in the updated 2002 Annual Reports, 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 Texas Regulatory Asset and
Stranded Cost Recovery and Post-Restructuring Wires Charges.
Virginia Restructuring
The Virginia Act was enacted in 1999 providing for retail choice of
generation suppliers to be phased in over the January 1, 2002 to January 1, 2004
period. The Virginia Act required jurisdictional utilities to unbundle their
power supply and energy delivery rates and to file functional separation plans
by January 1, 2002. APCo filed its plan and, following VSCC approval of a
settlement agreement, now operates in Virginia as a functionally separated
electric utility charging unbundled rates for its retail sales of electricity.
The settlement agreement addressed functional separation, leaving decisions
related to legal separation for later VSCC consideration.
Texas Regulatory Assets and Stranded Cost Recovery and Post-Restructuring Wires
Charges
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 distribution 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,
included in the updated 2002 Annual Reports, 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, included in the updated 2002 Annual
Reports.
Competition
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. See Regulation -- Rates for a
description of the setting of rates for power sold at bundled or unbundled
state-regulated rates.
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 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, included in the updated 2002 Annual
Reports, for further information with respect to restructuring legislation
affecting AEP subsidiaries.
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.
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.
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.
Investments- Gas Operations
AEP, through certain subsidiaries, operates and owns an interest in a
significant amount of gas-related assets, including:
o 6,400 miles of natural gas pipelines between two systems;
o 128 billion cubic feet of storage among two facilities;
o Five natural gas processing plants; and
o Certain gas marketing contracts.
AEP enters into transactions for the purchase and sale of natural gas. 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 gas contracts with numerous counterparties. Since AEP's open gas
trading contracts are valued based on changes in market gas prices, 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 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.
Investments- UK Operations
AEP, through certain subsidiaries, operates and owns 4,000 MW of power
generation facilities in the UK and engages in the following activities:
o Selling wholesale power in the UK.
o Trading and marketing power in transactions predominantly limited to
risk management around assets used or managed by AEP subsidiaries in the
UK. AEP trades with numerous counterparties. Since AEP's open power
trading contracts are valued based on changes in market power prices,
our exposures change daily.
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.
Investments- Other
AEP, through certain subsidiaries, conducts certain business operations
other than those included in other segments in which it uses and manage the
following assets:
o 1,879 MW of domestic and 1,235 MW of international power generation
facilities;
o Coal mines and related facilities; and
o Barge, rail and other fuel transportation related assets.
These operations include the following activities:
o 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.
o Through Pro Serv, providing engineering, construction, project
management and other consulting services for energy-related projects.
o Holding and/or operating various properties, coal reserves, mining
operations and royalty interests in Colorado, Kentucky, Louisiana, Ohio,
Pennsylvania and West Virginia.
o Through MEMCO Barge Line Inc., transporting 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.
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.
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, included in the updated
2002 Annual Reports.
AEP also sold the following foreign investments in 2002:
o 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.
o CitiPower, a retail electricity and gas supply and distribution
subsidiary in Australia serving 240,000 customers.
See Note 12 to the consolidated financial statements entitled Acquisitions,
Dispositions and Discontinued Operations, included in the updated 2002 Annual
Reports.