(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 2002
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from -------------- to --------------
COMMISSION REGISTRANTS; STATES OF INCORPORATION; I.R.S. EMPLOYER
FILE NUMBER ADDRESS AND TELEPHONE NUMBER IDENTIFICATION NOS.
----------- ------------------------------------- -------------------
1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. (A New York 13-4922640
Corporation)
0-18135 AEP GENERATING COMPANY (An Ohio Corporation) 31-1033833
0-346 AEP TEXAS CENTRAL COMPANY (A Texas Corporation) 74-0550600
0-340 AEP TEXAS NORTH COMPANY (A Texas Corporation) 75-0646790
1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790
1-2680 COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation) 31-4154203
1-3570 INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) 35-0410455
1-6858 KENTUCKY POWER COMPANY (A Kentucky Corporation) 61-0247775
1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000
0-343 PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation) 73-0410895
1-3146 SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation) 72-0323455
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 223-1000
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Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X . No.
Indicate by check mark if disclosure of delinquent filers with respect to American Electric Power Company, Inc. pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]
Indicate by check mark if disclosure of delinquent filers with respect to Appalachian Power Company, Indiana Michigan Power Company or Ohio Power Company pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements of Appalachian Power Company or Ohio Power Company incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X
Indicate by check mark whether American Electric Power Company, Inc. is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes X No __
Indicate by check mark whether AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are accelerated filers (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes __ No X
AEP Generating Company, AEP Texas North Company, Columbus Southern Power Company, Kentucky Power Company and Public Service Company of Oklahoma meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) to such Form 10-K.
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
NAME OF EACH EXCHANGE
REGISTRANT TITLE OF EACH CLASS ON WHICH REGISTERED
---------- ------------------- ---------------------
AEP Generating Company None
AEP Texas Central Company None
AEP Texas North Company None
American Electric Common Stock,
Power Company, Inc. $6.50 par value.................................. New York Stock Exchange
9.25% Equity Units................................. New York Stock Exchange
Appalachian Power Company 7.20% Senior Notes, Series A, Due 2038............. New York Stock Exchange
7.30% Senior Notes, Series B, Due 2038............. New York Stock Exchange
Columbus Southern Power Company None
CPL Capital I 8.00% Cumulative Quarterly Income
Preferred Securities, Series A, Liquidation
Preference $25 per Preferred Security............ New York Stock Exchange
Indiana Michigan 8% Junior Subordinated Debentures, Series A, Due
Power Company 2026............................................. New York Stock Exchange
7.60% Junior Subordinated Deferrable
Interest Debentures, Series B, Due 2038.......... New York Stock Exchange
6% Senior Notes, Series D, Due 2032................ New York Stock Exchange
Kentucky Power Company 8.72% Junior Subordinated Deferrable
Interest Debentures, Series A, Due 2025.......... New York Stock Exchange
Ohio Power Company 7 3/8% Senior Notes, Series A, Due 2038............ New York Stock Exchange
Public Service Company 6% Senior Notes, Series B, Due 2032................ New York Stock Exchange
of Oklahoma
PSO Capital I 8.00% Trust Originated Preferred
Securities, Series A, Liquidation
Preference $25 per Preferred Security............ New York Stock Exchange
SWEPCo Capital I 7.875% Trust Preferred Securities,
Series A, Liquidation amount $25
per Preferred Security........................... New York Stock Exchange
Southwestern Electric None
Power Company
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SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
REGISTRANT TITLE OF EACH CLASS
---------- -------------------
AEP Generating Company None
AEP Texas Central Company 4.00% Cumulative Preferred Stock, Non-Voting, $100 par value
4.20% Cumulative Preferred Stock, Non-Voting, $100 par value
AEP Texas North Company None
American Electric Power Company, Inc. None
Appalachian Power Company 4.50% Cumulative Preferred Stock, Voting, no par value
Columbus Southern Power Company None
Indiana Michigan Power Company 4.125% Cumulative Preferred Stock, Non-Voting, $100 par
value
Kentucky Power Company None
Ohio Power Company 4.50% Cumulative Preferred Stock, Voting, $100 par value
Public Service Company of Oklahoma None
Southwestern Electric Power Company 4.28% Cumulative Preferred Stock, Non-Voting, $100 par value
4.65% Cumulative Preferred Stock, Non-Voting, $100 par value
5.00% Cumulative Preferred Stock, Non-Voting, $100 par value
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AGGREGATE MARKET VALUE
OF VOTING AND NON-VOTING NUMBER OF SHARES
COMMON EQUITY HELD OF COMMON STOCK
BY NON-AFFILIATES OF OUTSTANDING OF
THE REGISTRANTS AT THE REGISTRANTS AT
JUNE 28, 2002 JUNE 28, 2002
------------------------ ------------------
AEP Generating Company None 1,000
($1,000 par value)
AEP Texas Central Company None 2,211,678
($25 par value)
AEP Texas North Company None 5,488,560
($25 par value)
American Electric Power Company, Inc. $13,560,125,474 338,833,720
($6.50 par value)
Appalachian Power Company None 13,499,500
(no par value)
Columbus Southern Power Company None 16,410,426
(no par value)
Indiana Michigan Power Company None 1,400,000
(no par value)
Kentucky Power Company None 1,009,000
($50 par value)
Ohio Power Company None 27,952,473
(no par value)
Public Service Company of Oklahoma None 9,013,000
($15 par value)
Southwestern Electric Power Company None 7,536,640
($18 par value)
|
NOTE ON MARKET VALUE OF COMMON EQUITY HELD BY NON-AFFILIATES
American Electric Power Company, Inc. owns, directly or indirectly, all of the common stock of AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company (see Item 12 herein).
DOCUMENTS INCORPORATED BY REFERENCE
PART OF FORM 10-K
INTO WHICH DOCUMENT
DESCRIPTION IS INCORPORATED
----------- -------------------
Portions of Annual Reports of the following companies for Part II
the fiscal year ended December 31, 2002:
AEP Generating Company
AEP Texas Central Company
AEP Texas North Company
American Electric Power Company, Inc.
Appalachian Power Company
Columbus Southern Power Company
Indiana Michigan Power Company
Kentucky Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company
Portions of Proxy Statement of American Electric Power Part III
Company, Inc. for 2003 Annual Meeting of Shareholders, to be
filed within 120 days after December 31, 2002
Portions of Information Statements of the following Part III
companies for 2003 Annual Meeting of Shareholders, to be
filed within 120 days after December 31, 2002:
Appalachian Power Company
Ohio Power Company
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THIS COMBINED FORM 10-K IS SEPARATELY FILED BY AEP GENERATING COMPANY, AEP TEXAS CENTRAL COMPANY, AEP TEXAS NORTH COMPANY, AMERICAN ELECTRIC POWER COMPANY, INC., APPALACHIAN POWER COMPANY, COLUMBUS SOUTHERN POWER COMPANY, INDIANA MICHIGAN POWER COMPANY, KENTUCKY POWER COMPANY, OHIO POWER COMPANY, PUBLIC SERVICE COMPANY OF OKLAHOMA AND SOUTHWESTERN ELECTRIC POWER COMPANY. INFORMATION CONTAINED HEREIN RELATING TO ANY INDIVIDUAL REGISTRANT IS FILED BY SUCH REGISTRANT ON ITS OWN BEHALF. EXCEPT FOR AMERICAN ELECTRIC POWER COMPANY, INC., EACH REGISTRANT MAKES NO REPRESENTATION AS TO INFORMATION RELATING TO THE OTHER REGISTRANTS.
TABLE OF CONTENTS
PAGE
NUMBER
------
Glossary of Terms........................................................... i
Forward-Looking Information................................................. 1
PART I
Item 1. Business.................................................... 2
Item 2. Properties.................................................. 26
Item 3. Legal Proceedings........................................... 29
Item 4. Submission of Matters to a Vote of Security Holders......... 30
Executive Officers of the Registrants.................................... 30
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters....................................... 32
Item 6. Selected Financial Data..................................... 32
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition........................ 33
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk...................................................... 33
Item 8. Financial Statements and Supplementary Data................. 33
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 33
PART III
Item 10. Directors and Executive Officers of the Registrants......... 33
Item 11. Executive Compensation...................................... 34
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters................ 34
Item 13. Certain Relationships and Related Transactions.............. 37
PART IV
Item 14. Controls and Procedures..................................... 37
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form
8-K....................................................... 37
Signatures.................................................................. 39
Certifications.............................................................. 42
Index to Financial Statement Schedules...................................... S-1
Independent Auditors' Report................................................ S-2
Exhibit Index............................................................... E-1
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GLOSSARY OF TERMS
The following abbreviations or acronyms used in this Form 10-K are defined below:
ABBREVIATION OR ACRONYM DEFINITION
----------------------- ----------
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.
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ABBREVIATION OR ACRONYM DEFINITION
----------------------- ----------
MTM.................................... Marked-to-market
MW..................................... Megawatt
NOx.................................... Nitrogen oxide
NPC.................................... National Power Cooperatives, Inc., an unaffiliated
corporation
NRC.................................... Nuclear Regulatory Commission
OASIS.................................. Open Access Same-time Information System
OATT................................... Open Access Transmission Tariff, filed with FERC
OCC.................................... Corporation Commission of the State of Oklahoma
Ohio Act............................... Ohio electric restructuring legislation
OPCo. ................................. Ohio Power Company, a public utility subsidiary of AEP
OVEC................................... Ohio Valley Electric Corporation, an electric utility
company in which AEP and CSPCo together own a 44.2% equity
interest
PJM.................................... PJM Interconnection, L.L.C.
Pro Serv............................... AEP Pro Serv, Inc., a subsidiary of AEP
PSO.................................... Public Service Company of Oklahoma, a public utility
subsidiary of AEP
PTB.................................... Price to beat, as defined by the Texas Act
PUCO................................... The Public Utilities Commission of Ohio
PUCT................................... Public Utility Commission of Texas
PUHCA.................................. Public Utility Holding Company Act of 1935, as amended
QF..................................... Qualifying facility, as defined under the Public Utility
Regulatory Policies Act of 1978
RCRA................................... Resource Conservation and Recovery Act of 1976, as amended
REP.................................... Retail electricity provider
Rockport Plant......................... A generating plant, consisting of two 1,300,000-kilowatt
coal-fired generating units, near Rockport, Indiana
RTO.................................... Regional Transmission Organization
SEC.................................... Securities and Exchange Commission
S&P.................................... Standard & Poor's Ratings Service
SO(2).................................. Sulfur dioxide
SO(2) Allowance........................ An allowance to emit one ton of sulfur dioxide granted under
the Clean Air Act Amendments of 1990
SPP.................................... Southwest Power Pool
STPNOC................................. STP Nuclear Operating Company, a non-profit Texas
corporation which operates STP on behalf of its joint
owners, including TCC
SWEPCo. ............................... Southwestern Electric Power Company, a public utility
subsidiary of AEP
TCA.................................... Transmission Coordination Agreement dated January 1, 1997 by
and among, PSO, SWEPCo, TCC, TNC and AEPSC, which allocates
costs and benefits in connection with the operation of the
transmission assets of the four public utility
subsidiaries
TCC.................................... AEP Texas Central Company, formerly Central Power and Light
Company, a public utility subsidiary of AEP
TEA.................................... Transmission Equalization Agreement dated April 1, 1984 by
and among APCo, CSPCo, I&M, KPCo and OPCo, which allocates
costs and benefits in connection with the operation of
transmission assets
Texas Act.............................. Texas electric restructuring legislation
TNC.................................... AEP Texas North Company, formerly West Texas Utilities
Company, a public utility subsidiary of AEP
TVA.................................... Tennessee Valley Authority
UCOS................................... Unbundled cost of service
Virginia Act........................... Virginia electric restructuring legislation
VSCC................................... Virginia State Corporation Commission
WVPSC.................................. West Virginia Public Service Commission
West Zone Companies of AEP............. PSO, SWEPCo, TCC and TNC
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This report made by AEP and certain of its subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and each of its subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:
- Electric load and customer growth.
- Abnormal weather conditions
- Available sources and costs of fuels.
- Availability of generating capacity.
- The speed and degree to which competition is introduced to AEP's power generation business.
- The ability to recover stranded costs in connection with possible/proposed deregulation of generation.
- New legislation and government regulation
- Oversight and/or investigation of the energy sector or its participants.
- The ability of AEP to successfully control its costs.
- The success of acquiring new business ventures and disposing of existing investments that no longer match AEP's corporate profile.
- International and country-specific developments affecting AEP's foreign investments, including the disposition of any current foreign investments and potential additional foreign investments.
- The economic climate and growth in AEP's service territory and changes in market demand and demographic patterns.
- Inflationary trends.
- Electricity and gas market prices.
- Interest rates.
- Liquidity in the banking, capital and wholesale power markets.
- Actions of rating agencies.
- Changes in technology, including the increased use of distributed generation within AEP's transmission and distribution service territory.
- Other risks and unforeseen events, including wars, the effects of terrorism, embargoes and other catastrophic events.
GENERAL
OVERVIEW AND DESCRIPTION OF SUBSIDIARIES
AEP was incorporated under the laws of the State of New York in 1906 and reorganized in 1925. It is a registered public utility holding company under PUHCA that owns, directly or indirectly, all of the outstanding common stock of its public utility subsidiaries and varying percentages of other subsidiaries.
The service areas of AEP's public utility subsidiaries cover portions of the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. The generating and transmission facilities of AEP's public utility subsidiaries are interconnected, and their operations are coordinated, as a single integrated electric utility system. Transmission networks are interconnected with extensive distribution facilities in the territories served. The public utility subsidiaries of AEP, which do business as "American Electric Power," have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers. Restructuring legislation in Michigan, Ohio, Texas and Virginia has caused or will cause AEP public utility subsidiaries in those states to unbundle previously integrated regulated rates for their retail customers.
The AEP System is an integrated electric utility system and, as a result, the member companies of the AEP System have contractual, financial and other business relationships with the other member companies, such as participation in the AEP System savings and retirement plans and tax returns, sales of electricity and transportation and handling of fuel. The member companies of the AEP System also obtain certain accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost from a common provider, AEPSC.
At December 31, 2002, the subsidiaries of AEP had a total of 22,083 employees. AEP, because it is a holding company rather than an operating company, has no employees. The public utility subsidiaries of AEP are:
APCo (organized in Virginia in 1926) is engaged in the generation, transmission and distribution of electric power to approximately 925,000 retail customers in the southwestern portion of Virginia and southern West Virginia, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. At December 31, 2002, APCo and its wholly owned subsidiaries had 2,520 employees. Among the principal industries served by APCo are coal mining, primary metals, chemicals and textile mill products. In addition to its AEP System interconnections, APCo also is interconnected with the following unaffiliated utility companies: Carolina Power & Light Company, Duke Energy Corporation and Virginia Electric and Power Company. APCo has several points of interconnection with TVA and has entered into agreements with TVA under which APCo and TVA interchange and transfer electric power over portions of their respective systems.
CSPCo (organized in Ohio in 1937, the earliest direct predecessor company having been organized in 1883) is engaged in the generation, transmission and distribution of electric power to approximately 689,000 retail customers in Ohio, and in supplying and marketing electric power at wholesale to other electric utilities, municipalities and other market participants. At December 31, 2002, CSPCo had 1,171 employees. CSPCo's service area is comprised of two areas in Ohio, which include portions of twenty-five counties. One area includes the City of Columbus and the other is a predominantly rural area in south central Ohio. Among the principal industries served are food processing, chemicals, primary metals, electronic machinery and paper products. In addition to its AEP System interconnections, CSPCo also is interconnected with the following unaffiliated utility companies: CG&E, DP&L and Ohio Edison Company.
I&M (organized in Indiana in 1925) is engaged in the generation, transmission and distribution of electric power to approximately 571,000 retail customers in northern and eastern Indiana and southwestern Michigan, and in supplying and marketing electric power at wholesale to other electric utility companies, rural electric cooperatives, municipalities and other market participants. At December 31, 2002, I&M had 2,667 employees. Among the principal industries served are primary metals, transportation equipment, electrical and electronic
machinery, fabricated metal products, rubber and miscellaneous plastic products and chemicals and allied products. Since 1975, I&M has leased and operated the assets of the municipal system of the City of Fort Wayne, Indiana. In addition to its AEP System interconnections, I&M also is interconnected with the following unaffiliated utility companies: Central Illinois Public Service Company, CG&E, Commonwealth Edison Company, Consumers Energy Company, Illinois Power Company, Indianapolis Power & Light Company, Louisville Gas and Electric Company, Northern Indiana Public Service Company, PSI Energy Inc. and Richmond Power & Light Company.
KPCo (organized in Kentucky in 1919) is engaged in the generation, transmission and distribution of electric power to approximately 174,000 retail customers in an area in eastern Kentucky, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. At December 31, 2002, KPCo had 412 employees. In addition to its AEP System interconnections, KPCo also is interconnected with the following unaffiliated utility companies: Kentucky Utilities Company and East Kentucky Power Cooperative Inc. KPCo is also interconnected with TVA.
Kingsport Power Company (organized in Virginia in 1917) provides electric service to approximately 46,000 retail customers in Kingsport and eight neighboring communities in northeastern Tennessee. Kingsport Power Company does not own any generating facilities. It purchases electric power from APCo for distribution to its customers. At December 31, 2002, Kingsport Power Company had 57 employees.
OPCo (organized in Ohio in 1907 and re-incorporated in 1924) is engaged in the generation, transmission and distribution of electric power to approximately 702,000 retail customers in the northwestern, east central, eastern and southern sections of Ohio, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. At December 31, 2002, OPCo had 1,988 employees. Among the principal industries served by OPCo are primary metals, rubber and plastic products, stone, clay, glass and concrete products, petroleum refining and chemicals. In addition to its AEP System interconnections, OPCo also is interconnected with the following unaffiliated utility companies: CG&E, The Cleveland Electric Illuminating Company, DP&L, Duquesne Light Company, Kentucky Utilities Company, Monongahela Power Company, Ohio Edison Company, The Toledo Edison Company and West Penn Power Company.
PSO (organized in Oklahoma in 1913) is engaged in the generation, transmission and distribution of electric power to approximately 505,000 retail customers in eastern and southwestern Oklahoma, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. At December 31, 2002, PSO had 998 employees. Among the principal industries served by PSO are natural gas and oil production, oil refining, steel processing, aircraft maintenance, paper manufacturing and timber products, glass, chemicals, cement, plastics, aerospace manufacturing, telecommunications, and rubber goods. In addition to its AEP System interconnections, PSO also is interconnected with Ameren Corporation, Empire District Electric Co., Oklahoma Gas & Electric Co., Southwestern Public Service Co. and Westar Energy Inc.
SWEPCo (organized in Delaware in 1912) is engaged in the generation, transmission and distribution of electric power to approximately 437,000 retail customers in northeastern Texas, northwestern Louisiana and western Arkansas, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. At December 31, 2002, SWEPCo had 1,372 employees. Among the principal industries served by SWEPCo are natural gas and oil production, petroleum refining, manufacturing of pulp and paper, chemicals, food processing, and metal refining. The territory served by SWEPCo also includes several military installations, colleges, and universities. In addition to its AEP System interconnections, SWEPCo is also interconnected with CLECO Corp., Empire District Electric Co., Entergy Corp. and Oklahoma Gas & Electric Co.
TCC (organized in Texas in 1945) is engaged in the generation, transmission and sale of power to affiliated and non-affiliated entities and the distribution of electric power to approximately 689,000 retail customers through REPs in southern Texas, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market
participants. At December 31, 2002, TCC had 1,248 employees. Among the principal industries served by TCC are oil and gas extraction, food processing, apparel, metal refining, chemical and petroleum refining, plastics, and machinery equipment. In addition to its AEP System interconnections, TCC is a member of ERCOT.
TNC (organized in Texas in 1927) is engaged in the generation, transmission and sale of power to affiliated and non-affiliated entities and the distribution of electric power to approximately 189,000 retail customers through REPs in west and central Texas, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. At December 31, 2002, TNC had 595 employees. The principal industry served by TNC is agriculture. The territory served by TNC also includes several military installations and correctional facilities. In addition to its AEP System interconnections, TNC is a member of ERCOT.
Wheeling Power Company (organized in West Virginia in 1883 and reincorporated in 1911) provides electric service to approximately 41,000 retail customers in northern West Virginia. Wheeling Power Company does not own any generating facilities. It purchases electric power from OPCo for distribution to its customers. At December 31, 2002, Wheeling Power Company had 59 employees.
AEGCo (organized in Ohio in 1982) is an electric generating company. AEGCo sells power at wholesale to I&M and KPCo. AEGCo has no employees.
Service Company Subsidiary
AEP also owns a service company subsidiary, AEPSC. AEPSC provides accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost to the AEP System companies. The executive officers of AEP and its public utility subsidiaries are all employees of AEPSC. At December 31, 2002, AEPSC had 6,548 employees.
CLASSES OF SERVICE
The principal classes of service from which the public utility subsidiaries
of AEP derive revenues and the amount of such revenues during the year ended
December 31, 2002 are as follows:
AEP
SYSTEM(A) APCo CSPCo I&M KPCo
----------- ---------- ---------- ---------- ---------
(IN THOUSANDS)
Wholesale Business:
Residential........................ $ 3,713,000 $ 616,509 $ 533,061 $ 371,329 $ 118,654
Commercial......................... 2,156,000 276,238 442,847 224,843 50,075
Industrial......................... 1,903,000 353,841 138,174 330,428 96,716
Other Retail Customers............. 385,000 80,429 38,018 61,450 16,911
Energy Delivery.................... (3,551,000) (594,089) (492,278) (321,721) (132,054)
----------- ---------- ---------- ---------- ---------
Total Retail.................... 4,606,000 732,928 659,822 666,329 150,302
Marketing and
Trading-Electricity............. 2,227,000 204,878 134,836 279,705 50,056
Marketing and Trading-Gas.......... 3,021,000 0 0 0 0
Unrealized MTM Income:
Electric........................ 136,000 18,089 13,388 0 0
Gas............................. (399,000) 0 0 0 0
Other.............................. 1,397,000 264,486 99,836 259,009 46,271
----------- ---------- ---------- ---------- ---------
Total Wholesale Business........ 10,988,000 1,220,381 907,882 1,205,043 246,629
----------- ---------- ---------- ---------- ---------
Energy Delivery Business:
Transmission....................... 922,000 186,960 107,673 118,812 50,381
Distribution....................... 2,629,000 407,129 384,605 202,909 81,673
----------- ---------- ---------- ---------- ---------
Total Energy Delivery........... 3,551,000 594,089 492,278 321,721 132,054
----------- ---------- ---------- ---------- ---------
Total Other Investments......... 16,000 0 0 0 0
----------- ---------- ---------- ---------- ---------
Total Revenues................ $14,555,000 $1,814,470 $1,400,160 $1,526,764 $ 378,683
=========== ========== ========== ========== =========
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OPCo PSO SWEPCo TCC TNC
---------- --------- ---------- ---------- --------
(IN THOUSANDS)
Wholesale Business:
Residential........................... $ 475,210 $ 315,711 $ 313,023 $ 49,210 $ 8,651
Commercial............................ 244,943 218,718 212,626 32,518 4,098
Industrial............................ 531,085 162,386 214,622 12,395 2,134
Other Retail Customers................ 71,737 38,998 33,104 3,594 1,638
Energy Delivery....................... (589,673) (275,547) (348,236) (554,547) (73,353)
---------- --------- ---------- ---------- --------
Total Retail....................... 733,302 460,266 425,139 (456,830) (56,832)
Marketing and Trading-Electricity..... 219,488 17,394 157,159 811,800 283,883
Marketing and Trading-Gas............. 0 0 0 0 0
Unrealized MTM Income:
Electric........................... 25,574 0 (3,686) (8,490) (1,473)
Gas................................ 0 0 0 0 0
Other................................. 545,088 40,440 157,872 789,466 151,809
---------- --------- ---------- ---------- --------
Total Wholesale Business........... 1,523,452 518,100 736,484 1,135,946 377,387
---------- --------- ---------- ---------- --------
Energy Delivery Business:
Transmission.......................... 162,660 63,178 92,076 68,003 25,273
Distribution.......................... 427,013 212,369 256,160 486,544 48,080
---------- --------- ---------- ---------- --------
Total Energy Delivery.............. 589,673 275,547 348,236 554,547 73,353
---------- --------- ---------- ---------- --------
Total Other Investments............ 0 0 0 0 0
---------- --------- ---------- ---------- --------
Total Revenues................... $2,113,125 $ 793,647 $1,084,720 $1,690,493 $450,740
========== ========= ========== ========== ========
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(a) Includes revenues of other subsidiaries not shown. Intercompany transactions have been eliminated, including AEGCo's total revenues of $213,281,000 for the year ended December 31, 2002, all of which resulted from its wholesale business, including its marketing and trading of power.
REGULATION
Except for retail generation sales in Ohio, Virginia and the ERCOT area of Texas, AEP's public utility subsidiaries' retail rates and certain other matters are subject to traditional regulation by the state utility commissions. Retail sales in Michigan, while still regulated, are now made at unbundled rates. Other states in AEP's service territory have also passed restructuring legislation that has not been implemented or has been repealed. See Electric Restructuring and Customer Choice Legislation and Energy Delivery--Regulation--Rates. AEP's subsidiaries are also subject to regulation by the FERC under the FPA. I&M and TCC are subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant and STP, respectively. AEP and its subsidiaries are also subject to the broad regulatory provisions of PUHCA administered by the SEC.
FERC
Under the FPA, FERC regulates rates for interstate sales at wholesale, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. FERC regulations require AEP to provide open access transmission service at FERC-approved rates. The transmission service regulated by FERC is predominantly wholesale transmission service, which is service not associated with bundled electricity sales to retail customers. FERC also regulates unbundled transmission service to retail customers.
Under the FPA, the FERC regulates the sale of power for resale in interstate commerce by (i) approving contracts for wholesale sales to municipal and cooperative utilities and (ii) granting authority to public utilities to sell power at wholesale at market-based rates upon a showing that the seller lacks the ability to improperly influence market prices. AEP has
market-rate authority from FERC, under which most of its wholesale marketing activity takes place. In November 2001, the FERC issued an order in connection with its triennial review of AEP's market based pricing authority requiring (i) certain actions by AEP in connection with its sales and purchases within its control area and (ii) posting of information related to generation facility status on AEP's website. AEP has appealed this order, and the FERC has issued an order delaying the effective date of the order. See Note 9 to the consolidated financial statements, entitled Commitments and Contingencies, incorporated by reference in Item 8, for more information on the current status of this proceeding.
SEC
The provisions of PUHCA, administered by the SEC, regulate many aspects of a registered holding company system, such as the AEP System. PUHCA limits the operations of a registered holding company system to a single integrated public utility system and such other businesses as are incidental or necessary to the operations of the system. In addition, PUHCA governs, among other things, financings, sales or acquisitions of assets and intra-system transactions.
PUHCA and the rules and orders of the SEC currently require that transactions between associated companies in a registered holding company system be performed at cost with limited exceptions. Over the years, the AEP System has developed numerous affiliated service, sales and construction relationships and, in some cases, invested significant capital and developed significant operations in reliance upon the ability to recover its full costs under these provisions.
The Division of Investment Management of the SEC has recommended the conditional repeal of PUHCA. Under its recommendation, certain oversight authority would be transferred to the FERC. Legislation has since been introduced in numerous sessions of Congress that would repeal PUHCA, but such legislation has not passed.
AEP-CSW MERGER
On June 15, 2000, CSW (now known as AEP Utilities, Inc.) merged with and into a wholly-owned merger subsidiary of AEP. As a result, CSW became a wholly owned subsidiary of AEP. The four wholly owned public utility subsidiaries of CSW--PSO, SWEPCo, TCC and TNC--became indirect wholly owned public utility subsidiaries of AEP as a result of the merger. The merger was approved by the FERC and the SEC (with respect to PUHCA).
On January 18, 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC failed to properly explain how the merger met the requirements of PUHCA and remanded the case to the SEC for further review. The court held that the SEC had not adequately explained its conclusions that the merger met PUHCA requirements that the merging entities be "physically interconnected" and that the combined entity was confined to a "single area or region."
Management believes that the merger meets the requirements of PUHCA and expects the matter to be resolved favorably.
ELECTRIC RESTRUCTURING AND CUSTOMER CHOICE LEGISLATION
Certain states in AEP's service area have adopted restructuring or customer choice legislation. In general, this legislation provides for a transition from bundled cost-based rate regulated electric service to unbundled cost-based rates for transmission and distribution service and market pricing for the supply of electricity with customer choice of supplier. At a minimum, this legislation allows retail customers to select alternative generation suppliers. Electric restructuring and/or customer choice began on January 1, 2001 in Ohio and on January 1, 2002 in Michigan, Virginia and the ERCOT area of Texas. Electric restructuring in the SPP area of Texas, also scheduled to begin on January 1, 2002, has been delayed by the PUCT. AEP's public utility subsidiaries operate in both the ERCOT and SPP areas of Texas.
Implementation of legislation enacted in Oklahoma and West Virginia to allow retail customers to choose their electricity supplier is on hold. In 2001 Oklahoma delayed implementation of customer choice indefinitely. Before West Virginia's choice plan can be effective, tax legislation must be passed to preserve pre-legislation levels of funding for state and local governments. No further legislation has been passed related to restructuring in West Virginia. In February 2003, Arkansas repealed its restructuring legislation.
See Note 7 to the consolidated financial statements, entitled Effects of Regulation, incorporated by reference in Item 8, for a discussion of the effect of restructuring and customer choice legislation on accounting procedures. See Management's Discussion
and Analysis of Results of Operations and Financial Condition, under the headings entitled Industry Restructuring and Corporate Separation for a discussion of AEP's corporate separation plan filed with the FERC and related settlement agreements with state commissions and other intervenors.
Michigan Customer Choice
Customer choice commenced for I&M's Michigan customers on January 1, 2002. Rates for retail electric service for I&M's Michigan customers were unbundled (though they continue to be regulated) to allow customers the ability to evaluate the cost of generation service for comparison with other suppliers. At December 31, 2002, none of I&M's Michigan customers had elected to change suppliers and no alternative electric suppliers are registered to compete in I&M's Michigan service territory.
Ohio Restructuring
The Ohio Act requires vertically integrated electric utility companies that offer competitive retail electric service in Ohio to separate their generating functions from their transmission and distribution functions. Following the market development period (which will terminate no later than December 31, 2005), retail customers will receive distribution and, where applicable, transmission service from the incumbent utility whose distribution rates will be approved by the PUCO and whose transmission rates will be approved by the FERC. See General--Regulation--FERC for a discussion of FERC regulation of transmission rates and Energy Delivery--Regulation--Rates--Ohio for a discussion of the impact of restructuring on distribution rates.
CSPCo and OPCo are each presently operating as functionally separated electric utility companies and no longer charge bundled rates for retail electric service. Each has sought and, from certain regulatory authorities, obtained regulatory approval to legally separate its transmission and distribution assets from its generation assets. CSPCo and OPCo are, however, currently determining the regulatory feasibility of complying with restructuring legislation through continued functional separation. Assuming regulatory compliance, it is currently their intention to remain functionally separated.
Texas Restructuring
The Texas Act substantially amends the regulatory structure governing electric utilities in Texas in order to allow retail electric competition for all customers and requires each utility to separate into (i) a REP, (ii) a power generation company and (iii) a transmission and distribution utility. Upon separation, neither the REP nor the power generation company will be subject to traditional cost of service rate regulation. See Energy Delivery--Regulation-- Rates--Texas for a discussion of the impact of restructuring on rates.
SWEPCo, TCC and TNC initially filed a restructuring plan in January 2000 (which they subsequently updated) that the PUCT approved in February 2002. The updated restructuring plan provided for the legal separation of TCC's and TNC's assets in accordance with the Texas Act into (i) an affiliate power generation company, (ii) a transmission and distribution utility and (iii) various REPs, including those subsequently purchased by Centrica (see below). TCC and TNC continue to pursue legal separation as required by the Texas Act. The PUCT has delayed the implementation of the plan for SWEPCo operations within the SPP area of Texas.
Under the Texas Act, a REP, which itself cannot own any generation assets, obtains its electricity from power generation companies, EWGs and other generating entities and provides services at generally unregulated rates, except that the prices that may be charged to residential and small commercial customers by REPs affiliated with a utility within the affiliated utility's service area are set by the PUCT until January 1, 2007. This set price is referred to as the "price to beat" rate (PTB). Affiliate REPs are required to offer the PTB rate to all residential and small commercial customers (with a peak usage of less than 1,000 KW) effective January 1, 2002. As described below, AEP sold its affiliate REPs that must provide PTB service. The PTB rate is still relevant to AEP, however, in determining (i) the contingent portion of the sales price of the affiliate REPs AEP sold and (ii) certain of AEP's obligations in the 2004 true-up proceedings.
Prior to the start of retail competition in January 2002, AEP formed MECPL
and MEWTU to act as affiliate REPs for TCC and TNC respectively. MECPL and MEWTU
were sold in December 2002 to Centrica, which assumed all of the rights and
obligations of an affiliated REP, including the provision of PTB service and the
obligation to provide data necessary for TCC's and TNC's 2004 true-up
proceeding. In connection with the sale, TCC and TNC have contracted to supply
approximately 90% of MECPL's and
MEWTU's respective power requirements relating to former TCC and TNC PTB customers for a two-year period. See Note 12 to the consolidated financial statements, entitled Acquisitions, Distributions and Discontinued Operations, incorporated by reference in Item 8, for more information on the sale of these REPs and AEP's contractual rights and obligations in connection with the sale.
The Texas Act also allows certain transmission and distribution utilities whose generation assets were unbundled to recover certain regulatory assets and stranded costs related to their generation assets. For a discussion of (i) regulatory assets and stranded costs subject to recovery by TCC and (ii) rate adjustments made after implementation of restructuring to allow recovery of certain costs by or with respect to TCC and TNC, see Energy Delivery--Regulatory Assets, Stranded Cost Recovery and Certain Post-Restructuring Rate Adjustments.
Virginia Restructuring
The Virginia Act was enacted in 1999 providing for retail choice of generation suppliers to be phased in over the January 1, 2002 to January 1, 2004 period. The Virginia Act required jurisdictional utilities to unbundle their power supply and energy delivery rates and to file functional separation plans by January 1, 2002. APCo filed its plan and, following VSCC approval of a settlement agreement, now operates in Virginia as a functionally separated electric utility charging unbundled rates for its retail sales of electricity. The settlement agreement addressed functional separation, leaving decisions related to legal separation for later VSCC consideration.
FINANCING
General
AEP's goal is to use cash from operations to fund capital expenditures, dividends and working capital. Short-term debt is used as an interim bridge for timing differences in the need for cash or to fund debt maturities until permanent financing is arranged.
It has been the practice of AEP's operating subsidiaries to finance current construction expenditures in excess of available cash from operations by initially incurring short-term debt, up to levels authorized by regulatory agencies, and then to reduce the short-term debt with the proceeds of subsequent sales by such subsidiaries of long-term debt securities and cash capital contributions by AEP. In the past, short-term debt has come from AEP's commercial paper program and revolving credit facilities. Proceeds were loaned to the subsidiaries through intercompany notes under the AEP money pool. The recent downgrade of AEP's commercial paper rating by Moody's, described below, may limit AEP's access to commercial paper on terms as favorable as those of recent years. Therefore, AEP may establish commercial paper programs for certain of its public utility subsidiaries and AEP Utilities. Certain public utility subsidiaries of AEP also sell accounts receivable to provide liquidity.
AEP's revolving credit agreements (which backstop the commercial paper program) include covenants and events of default typical for this type of facility, including a maximum debt/capital test and a $50 million cross-acceleration provision. At December 31, 2002, AEP was in compliance with its debt covenants. With the exception of a voluntary bankruptcy or insolvency, any event of default has either or both a cure period or notice requirement before termination of the agreements. A voluntary bankruptcy or insolvency would be considered an immediate termination event.
AEP's subsidiaries have also utilized, and expect to continue to utilize, additional financing arrangements, such as leasing arrangements, including the leasing of utility assets and coal mining and transportation equipment and facilities.
Credit Ratings
The rating agencies have been conducting credit reviews of AEP and its registrant subsidiaries. The agencies are also reviewing many companies in the energy sector due to issues that impact the entire industry.
In February 2003 Moody's completed its review of AEP and its rated subsidiaries. The results of that review were downgrades of the following ratings for unsecured debt: AEP from Baa2 to Baa3, APCo from Baa1 to Baa2, TCC from Baa1 to Baa2, PSO from A2 to Baa1, SWEPCo from A2 to Baa1. TNC, which had no senior unsecured notes outstanding at the time of the ratings action, had its mortgage bond debt downgraded from A2 to A3. AEP's commercial paper was also concurrently downgraded from P-2 to P-3. The completion of this review was a culmination of earlier ratings action in 2002 that had included a downgrade of AEP from Baa1 to Baa2. With the completion of the reviews, Moody's has placed AEP and its rated subsidiaries on stable outlook.
In March 2003 S&P completed its review of AEP and its rated subsidiaries. The results of that review were downgrades of the ratings for unsecured debt for AEP and its rated subsidiaries from BBB+ to BBB. AEP's commercial paper rating was affirmed at A-2. With the completion of the reviews, S&P has placed AEP and its rated subsidiaries on stable outlook.
In March 2003 Fitch completed its review of AEP. The result of that review was a downgrade of AEP's unsecured debt rating from BBB+ to BBB. AEP's commercial paper rating was affirmed at F-2. With the completion of the reviews, Fitch has placed AEP and its rated subsidiaries on stable outlook.
See Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters, incorporated by reference in Item 7, under the heading entitled Financial Condition for additional information with respect to AEP's credit ratings, liquidity and specific financing activities.
ENVIRONMENTAL AND OTHER MATTERS
General
AEP's subsidiaries are currently subject to regulation by federal, state and local authorities with regard to air and water-quality control and other environmental matters, and are subject to zoning and other regulation by local authorities. The environmental issues that are potentially material to the AEP system include:
- The CAA and CAAA and state laws and regulations (including State Implementation Plans) that require compliance, obtaining permits and reporting as to air emissions.
- Litigation with the federal and certain state governments and certain special interest groups regarding whether modifications to or maintenance of certain coal-fired generating plants required additional permitting or pollution control technology. See Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters under the heading entitled Federal EPA Complaint and Notice of Violation and Note 9 to the consolidated financial statements entitled Commitments and Contingencies, incorporated by reference in Items 7 and 8 respectively for further information.
- Rules issued by the EPA and certain states that require substantial reductions in NOx emissions. The compliance dates for these rules range from 2003 to 2005. AEP is installing (or has installed) emission control technology and is taking other measures to comply with required reductions. See Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters and Note 9 to the consolidated financial statements entitled Commitments and Contingencies, incorporated by reference in Items 7 and 8 respectively, under the heading entitled NOx Reductions for further information.
- CERCLA, which imposes upon owners and previous owners of sites, as well as transporters and generators of hazardous material disposed of at such sites, costs for environmental remediation. AEP does not, however, anticipate that any of its currently identified CERCLA-related issues will result in material costs or penalties to the AEP System. See Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters, incorporated by reference in Item 7, under the heading entitled Superfund for further information.
- The Federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits. There are, however, no matters material to the AEP System currently pending under the Clean Water Act.
- Solid and hazardous waste laws and regulations, which govern the management and disposal of certain wastes. The majority of solid waste created from the combustion of coal and fossil fuels is fly ash and other coal combustion byproducts, which the EPA has determined are not hazardous waste governed subject to RCRA.
In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions.
AEP's subsidiaries will confront several new environmental policies and
regulations over the next decade with the potential for substantial control
costs and premature retirement of some generating plants. These could include
(i) new or additional controls on sulfur dioxide, NOx and mercury emissions from
future laws or regulations, or the possibility of an
adverse decision in the new source review litigation; (ii) a new Clean Water Act rule to reduce fish and other aquatic organisms killed at once-through cooled power plants; (iii) finalization and implementation of more stringent water quality-based permit limits; and (iv) a possible future requirement to reduce carbon dioxide emissions. See Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters, incorporated by reference in Item 7, under the heading entitled Environmental Concerns and Issues for information on current environmental issues.
AEP expects costs related to environmental controls to eventually be reflected in some jurisdictions in the rates of AEP's public utility subsidiaries. In Michigan, Ohio, Texas and Virginia, those costs may not be recoverable if future market prices for electricity generated by plants in those jurisdictions are insufficient to permit AEP to recover such costs. Moreover, legislation adopted by certain states and proposed at the state and federal level governing restructuring of the electric utility industry may also affect the recovery of certain of these costs. There can be no assurance that these costs will be recovered.
AEP's international operations are subject to environmental regulation by various authorities within the host countries. Under certain circumstances, these authorities may require modifications to these facilities and operations or impose fines and other costs for violations of applicable statutes and regulations. From time to time, these operations are named as parties to various legal claims, actions, complaints or other proceedings related to environmental matters. AEP's UK generation facilities will be subject to additional environmental constraints in 2008 (which become more stringent after 2015) because they are subject to regulation governing large combustion plants. In the fourth quarter of 2002, AEP decided not to install certain emission control technology on its Fiddler's Ferry and Ferrybridge generation facilities in 2008. This decision and its legal and regulatory consequences will result in a significant reduction in the estimated economic life of those facilities.
The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the AEP System.
See Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters and Note 9 to the consolidated financial statements entitled Commitments and Contingencies, incorporated by reference in Items 7 and 8, respectively, for further information with respect to environmental matters.
Environmental Expenditures
Expenditures related to generation facility compliance with air and water quality standards during 2001 and 2002 and the current estimate for 2003 are shown below. Substantial expenditures in addition to the amounts set forth below may be required by the System in future years in connection with the modification and addition of facilities at generating plants for environmental quality controls in order to comply with air and water quality standards which have been or may be adopted. Future expenditures could be significantly greater if litigation regarding whether AEP properly installed emission control equipment on its plants is resolved against AEP. See Note 9 to the consolidated financial statements, entitled Commitments and Contingencies, incorporated by reference in Item 8, for more information regarding this litigation and environmental expenditures in general.
2001 2002 2003
ACTUAL ACTUAL ESTIMATE
-------- -------- --------
(IN THOUSANDS)
AEGCo................ $ 3,500 $ 1,200 $ 11,200
APCo................. 99,200 108,400 65,700
CSPCo................ 22,500 25,400 39,300
I&M.................. 700 1,200 18,500
KPCo................. 11,200 110,600 39,900
OPCo................. 125,300 110,300 53,100
PSO.................. 400 1,200 100
SWEPCo............... 9,200 3,400 9,000
TCC.................. 2,500 600 0
TNC.................. 800 1,900 0
-------- -------- --------
AEP System........... $275,300 $364,200 $236,800
======== ======== ========
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Electric and Magnetic Fields
EMF are found everywhere there is electricity. Electric fields are created by the presence of electric charges. Magnetic fields are produced by the flow of those charges. This means that EMF is created by electricity flowing in transmission and distribution lines, electrical equipment, household wiring, and appliances.
A number of studies in the past several years have examined the possibility of adverse health effects from EMF. While some of the epidemiological studies have indicated some association between exposure to
EMF and health effects, none has produced any conclusive evidence that EMF does or does not cause adverse health effects.
Management cannot predict the ultimate impact of the question of EMF exposure and adverse health effects. If further research shows that EMF exposure contributes to increased risk of cancer or other health problems, or if the courts conclude that EMF exposure harms individuals and that utilities are liable for damages, or if states limit the strength of magnetic fields to such a level that the current electricity delivery system must be significantly changed, then the results of operations and financial condition of AEP and its operating subsidiaries could be materially adversely affected unless these costs can be recovered from customers.
WHOLESALE OPERATIONS
GENERAL
AEP conducts its wholesale business operations through its public utility subsidiaries (through which AEP also conducts its energy delivery operations), AEPES, AEPR and Pro Serv. Wholesale operations use and manage the following assets:
- Power generation facilities (or interests therein) owned by AEP's public utility and other subsidiaries;
- Natural gas pipeline, storage and processing facilities;
- Coal mines and related facilities; and
- Barge, rail and other fuel transportation related assets.
Wholesale operations include the following activities:
- Through AEP's public utility subsidiaries, the generation and sale of power (i) to retail customers at unbundled or bundled rates regulated at least in part by state public utility commissions and (ii) at wholesale at rates regulated, in certain instances, by the FERC.
- Trading and marketing energy commodities in transactions predominantly limited to risk management around assets used or managed by AEP's wholesale operations, including electric power, natural gas, natural gas liquids, oil, coal, and SO(2) allowances in North America and, where applicable, Europe. Electric power transactions in the United States are conducted principally through AEP's public utility subsidiaries. Other energy commodity and allowances transactions are conducted through AEPES and AEPR.
- Entering into long-term transactions to buy or sell capacity, energy, and ancillary services of electric generating facilities, either existing or to be constructed, at various locations in North America and Europe.
- Through Pro Serv, providing engineering, construction, project management and other consulting services for energy-related projects.
In October 2002 AEP announced its plans to reduce the exposure to energy trading markets and to downsize the trading and wholesale marketing operations. It is expected that in the future power trading and marketing operations will be smaller in scope and size, will generally be limited to risk management around AEP's assets and, accordingly, focused in those regions in which AEP owns assets.
POWER GENERATION
General
Power generation accounts for the majority of wholesale operations revenue. In 2002, on an as-reported basis, power generation revenue included the following components: (i) 63% from retail sales at predominantly regulated rates; (ii) 33% from power marketing transactions of a type AEP intends to continue and which are regulated in certain instances by the FERC; (iii) 3% from retail sales at rates not regulated by states; and (iv) 1% attributable to power marketing transactions of a type that management has stated are transitional. This final category of transactions will be reduced consistent with AEP's decision to scale back certain trading and marketing operations as described in the preceding paragraph.
AEP's public utility subsidiaries own approximately 38,000 MW of domestic generation. See Deactivation and Planned Disposition of Generating Facilities for a discussion of planned reductions in AEP's generating fleet. Other AEP subsidiaries hold interests in entities owning 1,879 MW of domestic power facilities and 5,235 MW of international power facilities. The AEP public utility subsidiaries operate their generating plants as a single interconnected and coordinated electric utility system. See Item 2 - Properties for more information regarding generation facilities.
AEP Power Pool and CSW Operating Agreement
APCo, CSPCo, I&M, KPCo and OPCo are parties to the Interconnection Agreement, dated July 6, 1951, as amended (Interconnection Agreement), defining how they share the costs and benefits associated with their generating plants. This sharing is based upon each company's "member-load-ratio."
The member-load ratio is calculated monthly by dividing such company's highest monthly peak demand for the last twelve months by the aggregate of the highest monthly peak demand for the last twelve months for all east zone operating companies. As of December 31, 2002, the member-load ratios were as follows:
PEAK
DEMAND MEMBER-LOAD
(KW) RATIO (%)
------ -----------
APCo..................... 6,010 28.2
CSPCo.................... 4,040 19.0
I&M...................... 4,323 20.3
KPCo..................... 1,551 7.3
OPCo..................... 5,360 25.2
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Although the FERC has approved the right of withdrawal of CSPCo and OPCo from the AEP Power Pool as part of its order approving the settlement agreements and AEP's FERC restructuring application, CSPCo and OPCo have remained a party to the AEP Power Pool. If CSPCo and OPCo continue to remain in the AEP Power Pool, notification to or approval by the FERC may be required. See Management's Discussion and Analysis of Results of Operations and Financial Condition, under the headings entitled Industry Restructuring and Corporate Separation for a discussion of AEP's corporate separation plan filed with the FERC and related settlement agreements with state commissions and other intervenors.
The following table shows the net credits or (charges) allocated among the parties under the Interconnection Agreement and AEP System Interim Allowance Agreement during the years ended December 31, 2000, 2001 and 2002:
2000 2001 2002
--------- --------- ---------
(IN THOUSANDS)
APCo. ............... $(274,000) $(256,700) $(127,000)
CSPCo................ (250,400) (251,200) (267,000)
I&M.................. 93,900 166,200 113,600
KPCo. ............... (21,500) (27,600) (46,500)
OPCo. ............... 452,000 369,300 326,900
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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)
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Power generated by or allocated or provided under the Interconnection Agreement or CSW Operating Agreement to any public utility subsidiary is often sold to customers (or in the case of the ERCOT area of Texas, REPs) by such public utility subsidiary at rates approved (other than in the ERCOT area of Texas) by the public utility commission in the jurisdiction of sale. In Ohio, Virginia and the ERCOT area of Texas, such rates are based on a statutory formula as those jurisdictions transition to the use of market rates for generation. See Energy Delivery -- Regulation -- Rates.
Under the Interconnection Agreement, power allocated to a public utility subsidiary that is not required to serve its native load is sold at wholesale on behalf of such subsidiary. Under the CSW Operating Agreement, power generated that is not needed to serve the native load of any public utility subsidiary is sold at wholesale by the generating subsidiary. See Trading and Marketing of Energy Commodities for a discussion of the trading and marketing of such power.
AEP's System Integration Agreement provides for the integration and coordination of AEP's east and west zone operating subsidiaries, joint dispatch of generation within the AEP System, and the distribu-
tion, between the two operating zones, of costs and benefits associated with the System's generating plants. It is designed to function as an umbrella agreement in addition to the Interconnection Agreement and the CSW Operating Agreement, each of which controls the distribution of costs and benefits within each zone.
Competition and Regulation
Retail Sales: AEP's public utility subsidiaries have the right (which in some cases is exclusive) to sell electric power at retail within their respective service areas in the states of Arkansas, Indiana, Kentucky, Louisiana, Oklahoma, Tennessee, West Virginia and the SPP area of Texas. In Michigan, Ohio and Virginia, AEP's public utility subsidiaries continue to provide service to customers who have not been offered or have not selected alternate service from competing suppliers. In those states, service is currently being provided according to prescribed rules and rates. In the ERCOT area of Texas, TCC and TNC sell power to Centrica, which provides PTB service to certain former customers of TCC and TNC and must compete for customers.
AEP's public utility subsidiaries also compete with self-generation and with distributors of other energy sources, such as natural gas, fuel oil and coal, within their service areas. The primary factors in such competition are price, reliability of service and the capability of customers to utilize sources of energy other than electric power. With respect to competing generators and self-generation, the public utility subsidiaries of AEP believe that they generally maintain a favorable competitive position. With respect to alternative sources of energy, the public utility subsidiaries of AEP believe that the reliability of their service and the limited ability of customers to substitute other cost-effective sources for electric power place them in a favorable competitive position, even though their prices may be higher than the costs of some other sources of energy.
Significant changes in the global economy in recent years have led to increased price competition for industrial customers in the United States, including those served by the AEP System. Some of these industrial customers have requested price reductions from their suppliers of electric power. In addition, industrial customers that are downsizing or reorganizing often close a facility based upon its costs, which may include, among other things, the cost of electric power. The public utility subsidiaries of AEP cooperate with such customers to meet their business needs through, for example, providing various off-peak or interruptible supply options pursuant to tariffs filed with the various state commissions. Occasionally, these rates are first negotiated, and then filed with the state commissions. The public utility subsidiaries believe that they are unlikely to be materially adversely affected by this competition.
See Energy Delivery -- Regulation -- Rates for a description of the setting of rates for power sold at bundled or unbundled state-regulated rates.
Wholesale Sales: The public utility subsidiaries of AEP, like the electric industry generally, face increasing competition in the sale of available power on a wholesale basis, primarily to other public utilities and power marketers. The Energy Policy Act of 1992 was designed, among other things, to foster competition in the wholesale market by creating a generation market with fewer barriers to entry and mandating that all generators have equal access to transmission services. As a result, there are more generators able to participate in this market. The principal factors in competing for wholesale sales are price (including fuel costs), availability of capacity and power and reliability of service.
The public utility subsidiaries of AEP are subject to regulation by the FERC under the Federal Power Act in respect of rates for interstate sales at wholesale. See General -- Regulation -- FERC.
Seasonality
Sale of electric power is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. The pattern of this fluctuation may change due to the nature and location of AEP's facilities and the terms of power sale contracts AEP enters into. In addition, AEP has historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could diminish AEP's results of operations and may impact its financial condition.
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%
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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
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The coal supplies at AEP System plants vary from time to time depending on various factors, including customers' usage of electric power, space limitations, the rate of consumption at particular plants, labor unrest and weather conditions which may interrupt deliveries. At December 31, 2002, the System's coal inventory was roughly 56 days of normal usage. This estimate assumes that the total supply would be utilized through the operation of plants that use coal most efficiently.
In cases of emergency or shortage, system companies have developed programs to conserve coal supplies at their plants. Such programs have been filed and reviewed with officials of federal and state agencies and, in some cases, the state regulatory agency has prescribed actions to be taken under specified circumstances by System companies, subject to the jurisdiction of such agencies.
The FERC has adopted regulations relating, among other things, to the circumstances under which, in the event of fuel emergencies or shortages, it might order electric utilities to generate and transmit electric power to other regions or systems experiencing fuel shortages, and to ratemaking principles by which such electric utilities would be compensated. In addition, the federal government is authorized, under prescribed conditions, to allocate coal and to require the transportation thereof, for the use of power plants or major fuel-burning installations.
Natural Gas: AEP, through its public utility subsidiaries, consumed over 163 billion cubic feet of natural gas during 2002 for generating power. A majority of the gas fired electric generation plants are connected to at least two natural gas pipelines, which provides greater access to competitive supplies and improves reliability. A portfolio of long-term and short-term purchase and transportation agreements (that are acquired on a competitive basis and based on market prices) supplies natural gas requirements for each plant.
Nuclear: I&M and STPNOC have made commitments to meet certain of the nuclear fuel requirements of the Cook Plant and STP, respectively. Steps currently are being taken, based upon the planned fuel cycles for the Cook Plant, to review and evaluate I&M's requirements for the supply of nuclear fuel. I&M has made and will make purchases of uranium in various forms in the spot, short-term, and mid-term markets until it decides that deliveries under long-term supply contracts are warranted. TCC and the other STP participants have entered into contracts with suppliers for (i) 100% of the uranium concentrate sufficient for the operation of both STP units through spring 2006 and (ii) 50% of the uranium concentrate needed for STP through spring 2007.
For purposes of the storage of high-level radioactive waste in the form of spent nuclear fuel, I&M has completed modifications to its spent nuclear fuel storage pool. AEP anticipates that the Cook Plant has storage capacity to permit normal operations through 2012. STP has on-site storage facilities with the
capability to store the spent nuclear fuel generated by the STP units over their licensed lives.
Nuclear Waste and Decommissioning
I&M, as the owner of the Cook Plant, and TCC, as a partial owner of STP, have a significant future financial commitment to safely dispose of SNF and decommission and decontaminate the plants. The ultimate cost of retiring the Cook Plant and STP may be materially different from estimates and funding targets as a result of the:
- Type of decommissioning plan selected;
- Escalation of various cost elements (including, but not limited to, general inflation);
- Further development of regulatory requirements governing decommissioning;
- Limited availability to date of significant experience in decommissioning such facilities;
- Technology available at the time of decommissioning differing significantly from that assumed in these studies; and
- Availability of nuclear waste disposal facilities.
Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant and STP will not be significantly different than current projections.
See Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters and Note 9 to the consolidated financial statements, entitled Commitments and Contingencies, which are incorporated by reference in Items 7 and 8, respectively, for information with respect to nuclear waste and decommissioning and related litigation.
Low-Level Radioactive Waste: The LLWPA mandates that the responsibility for the disposal of low-level radioactive waste rests with the individual states. Low-level radioactive waste consists largely of ordinary refuse and other items that have come in contact with radioactive materials. Michigan and Texas do not currently have disposal sites for such waste available. AEP cannot predict when such sites may be available, but South Carolina and Utah operate low-level radioactive waste disposal sites and accept low-level radioactive waste from Michigan and Texas. AEP's access to the South Carolina facility is currently allowed through the end of fiscal year 2008.
Deactivation and Planned Disposition of Generation Facilities
In September 2002, AEP indicated to ERCOT its intent to deactivate 16 gas-fired power plants (8 TCC plants and 8 TNC plants). ERCOT subsequently conducted reliability studies that determined that seven plants (4 TCC plants and 3 TNC plants) would be required to ensure reliability of the electricity grid. As a result of these studies, ERCOT and AEP agreed to enter into reliability must run agreements (which expired in December 2002, but have been renewed for all but two units of these plants) to continue operation of these plants. With ERCOT's approval, AEP proceeded with its planned deactivation of the remaining nine plants.
TCC has also filed a plan of divestiture with the PUCT proposing to sell all of its power generation assets in an effort to determine its level of stranded costs in accordance with the Texas Act. The PUCT has dismissed its proceeding relating to TCC's plan of divestiture in anticipation of promulgating rules of general application regarding stranded cost determination for nuclear facilities. See Energy Delivery-Regulatory Assets and Stranded Cost Recovery and Post-Restructuring Wires Charges.
The assets to be sold have a generating capacity of 4,497 MW and include eight gas-fired generating plants, one coal-fired plant, TCC's interest in another coal-fired plant, a hydroelectric facility and TCC's interest in STP. See Note 8 to the consolidated financial statements entitled Customer Choice and Industry Restructuring, incorporated by reference in Item 8, for more information on the planned disposition of TCC generation facilities.
TRADING AND MARKETING OF ENERGY COMMODITIES
AEP enters into transactions for the purchase and sale of electricity and natural gas as part of wholesale trading operations. Electric and gas transactions are executed over-the-counter with counterparties or through brokers. Gas transactions are also executed through brokerage accounts with brokers who are registered with the Commodity Futures Trading Commission. Brokers and counterparties may require cash or cash related instruments to be deposited on these transactions as margin against open positions.
AEP trades electricity and gas contracts with numerous counterparties. Since AEP's open energy trading contracts are valued based on changes in
market prices of the related commodities, our exposures change daily.
In October 2002, AEP announced its plans to reduce its exposure to energy trading markets and to downsize the trading and wholesale marketing operations. It is expected that in the future power trading and marketing operations will be smaller in scope, will generally be limited to risk management around AEP assets and, accordingly, focused in regions in which AEP owns assets.
Energy Market Investigations
During 2002, several governmental entities launched investigations of participants in energy trading markets, including AEP. A number of those investigations resulted in data requests of AEP. See Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters, incorporated by reference in Item 7, under the heading Energy Market Investigations.
NATURAL GAS PIPELINE, STORAGE AND PROCESSING FACILITIES
AEP, through certain subsidiaries, operates and owns an interest in a significant amount of gas-related assets, including:
- 6,400 miles of natural gas pipelines between two systems;
- 128 billion cubic feet of storage among two facilities;
- Five natural gas processing plants; and
- Certain gas marketing contracts.
COAL MINES AND RELATED FACILITIES
AEP, through certain subsidiaries, holds various properties, coal reserves, mining operations and royalty interests in Colorado, Kentucky, Louisiana, Ohio, Pennsylvania and West Virginia.
BARGE, RAIL AND OTHER FUEL TRANSPORTATION RELATED ASSETS
AEP, through MEMCO Barge Line Inc., is engaged in the transportation of coal and dry bulk commodities, primarily on the Ohio, Illinois, and Lower Mississippi rivers for AEP, as well as unaffiliated customers. AEP, through certain subsidiaries, owns or leases 7,000 railcars, 1,800 barges, 37 tug boats and two coal handling terminals with 20 million tons of annual capacity.
STRUCTURED ARRANGEMENTS INVOLVING CAPACITY, ENERGY, AND ANCILLARY SERVICES
Dow
AEP has entered into an agreement with The Dow Chemical Company to construct a 900 MW cogeneration facility at Dow's chemical facility in Plaquemine, Louisiana. Commercial operation is expected in November 2003. AEP is entitled to 100% of the facility's capacity and energy over The Dow Chemical Company's requirements and has contracted to sell the power from this facility to an unaffiliated party.
Buckeye
In January 2000, OPCo and NPC, an affiliate of Buckeye, entered into an agreement relating to the construction and operation of a 510 MW gas-fired electric generating peaking facility to be owned by NPC. From the commercial operation date (which occurred in 2002) until the end of 2005, OPCo will be entitled to 100% of the power generated by the facility, and responsible for the fuel and other costs of the facility. After 2005, NPC and OPCo will be entitled to 80% and 20%, respectively, of the power of the facility, and both parties will generally be responsible for the fuel and other costs of the facility. OPCo will also provide certain back-up power to NPC.
CERTAIN POWER AGREEMENTS
AEGCo
Since its formation in 1982, AEGCo's business has consisted of the ownership and financing of its 50% interest in Unit 1 of the Rockport Plant and, since 1989, leasing of its 50% interest in Unit 2 of the Rockport Plant. The operating revenues of AEGCo are derived from the sale of capacity and energy associated with its interest in the Rockport Plant to I&M and KPCo pursuant to unit power agreements.
The I&M Power Agreement provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M). Such amounts, when added to amounts received by AEGCo from any other sources, will be at least
sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by FERC, currently 12.16%. The I&M Power Agreement will continue in effect until the date that the last of the lease terms of Unit 2 of the Rockport Plant has expired unless extended in specified circumstances.
Pursuant to an assignment between I&M and KPCo, and a unit power agreement between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo has agreed to pay to AEGCo the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KPCo unit power agreement expires on December 31, 2004. The agreement will be extended until December 31, 2009 for Unit 1 and December 31, 2022 for Unit 2 if AEP's restructuring settlement agreement filed with the FERC becomes effective.
AEGCo and AEP have entered into a capital funds agreement pursuant to which, among other things, AEP has unconditionally agreed to make cash capital contributions, or in certain circumstances subordinated loans, to AEGCo to the extent necessary to enable AEGCo to (i) maintain such an equity component of capitalization as required by governmental regulatory authorities; (ii) provide its proportionate share of the funds required to permit commercial operation of the Rockport Plant; (iii) enable AEGCo to perform all of its obligations, covenants and agreements under, among other things, all loan agreements, leases and related documents to which AEGCo is or becomes a party (AEGCo Agreements); and (iv) pay all indebtedness, obligations and liabilities of AEGCo (AEGCo Obligations) under the AEGCo Agreements, other than indebtedness, obligations or liabilities owing to AEP. The capital funds agreement will terminate after all AEGCo Obligations have been paid in full.
OVEC
AEP, CSPCo and several unaffiliated utility companies jointly own OVEC. The aggregate equity participation of AEP and CSPCo in OVEC is 44.2%. Until September 1, 2001, OVEC supplied the power requirements of a uranium enrichment plant near Portsmouth, Ohio owned by the DOE. The sponsoring companies are now entitled to receive and pay for all OVEC capacity (approximately 2,200 MW) in proportion to their power participation ratios. The aggregate power participation ratio of APCo, CSPCo, I&M and OPCo is 42.1%. The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and to provide a return on its equity capital. The Inter-Company Power Agreement, which defines the rights of the owners and sets the power participation ratio of each, will expire by its terms on March 12, 2006.
Buckeye
Contractual arrangements among OPCo, Buckeye and other investor-owned electric utility companies in Ohio provide for the transmission and delivery, over facilities of OPCo and of other investor-owned utility companies, of power generated by the two units at the Cardinal Station owned by Buckeye and back-up power to which Buckeye is entitled from OPCo under such contractual arrangements, to facilities owned by 25 of the rural electric cooperatives which operate in the State of Ohio at 342 delivery points. Buckeye is entitled under such arrangements to receive, and is obligated to pay for, the excess of its maximum one-hour coincident peak demand plus a 15% reserve margin over the 1,226,500 kilowatts of capacity of the generating units which Buckeye currently owns in the Cardinal Station. Such demand, which occurred on August 1, 2002, was recorded at 1,398,559 kilowatts.
ENERGY DELIVERY
GENERAL
AEP's public utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power. See Item 2--Properties for more information regarding the transmission and distribution lines. Most of the transmission and distribution services are sold, in combination with electric power, to retail customers of AEP's public utility subsidiaries in their service territories. These sales are made at rates established by the state utility commissions of the states in which they operate, and in some instances, the FERC as well. See Regulation-- Rates. The FERC regulates and approves the rates for wholesale transmission transactions. See General--Regulation-- FERC. As discussed below, some transmission services also are separately sold to non-affiliated companies.
AEP's public utility subsidiaries hold franchises or other rights to provide electric service in various municipalities and regions in their service areas. In some cases, these franchises provide the utility with the exclusive right to provide electric service. These franchises have varying provisions and expiration
dates. In general, the operating companies consider their franchises to be adequate for the conduct of their business. For a discussion of competition in the sale of power, see Wholesale Operations-- Generation-- Competition and Regulation.
REGULATION
AEP is in the business of providing generation, transmission and distribution services. The transmission and distribution functions are part of AEP's energy delivery segment. The generation function is part of AEP's wholesale operations segment. This discussion covers the regulation of transmission and distribution, but also generation sold at retail (which would otherwise be included in the wholesale operations segment discussion).
Rates
Historically, state utility commissions have established electric service rates on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service. A utility's cost of service is generally comprised of its operating expenses, including operation and maintenance expense, depreciation expense and taxes. State utility commissions periodically adjust rates pursuant to a review of (i) a utility's revenues and expenses during a defined test period and (ii) such utility's level of investment. Absent a legal limitation, such as a law limiting the frequency of rate changes or capping rates for a period of time as part of a transition to customer choice of generation suppliers, a state utility commission can review and change rates on its own initiative. Some states may initiate reviews at the request of a utility, customer, governmental or other representative of a group of customers. Such parties may, however, agree with one another not to request reviews of or changes to rates for a specified period of time.
The rates of AEP's public utility subsidiaries are generally based on the cost of providing traditional bundled electric service (i.e., generation, transmission and distribution service). In Ohio, Virginia and the ERCOT area of Texas, rates are transitioning from bundled cost-based rates for electric service to unbundled cost-based rates for transmission and distribution service on the one hand, and market pricing for and/or customer choice of generation on the other.
Historically, the state regulatory frameworks in the service area of the AEP System reflected specified fuel costs as part of bundled (or, more recently, unbundled) rates or incorporated fuel adjustment clauses in a utility's rates and tariffs. Fuel adjustment clauses permit periodic adjustments to fuel cost recovery from customers and therefore provide protection against exposure to fuel cost changes. While the historical framework remains in a portion of AEP's service territory, recovery of increased fuel costs (i) is no longer provided for in Ohio and (ii) may be limited in Indiana and Michigan, which have capped rates. Fuel recovery is also limited in the ERCOT area of Texas, but because AEP sold MECPL and MEWTU, there is little impact on AEP of fuel recovery procedures related to service in ERCOT.
The following state-by-state analysis summarizes the regulatory environment of each jurisdiction in which AEP operates. Several public utility subsidiaries operate in more than one jurisdiction.
Indiana: I&M provides retail electric service in Indiana at a bundled rate approved by the IURC. While rates are set on a cost-of-service basis, utilities may also generally seek to adjust fuel clause rates quarterly. I&M's base rate is capped through December 31, 2004 and its fuel recovery rate is capped through February 29, 2004.
Ohio: CSPCo and OPCo operate as functionally separated utilities and provide "default" retail electric service to customers at unbundled rates established by the Ohio Act through December 31, 2005. Thereafter, CSPCo and OPCo will continue to provide distribution services to retail customers at rates approved by the PUCO. These rates will be frozen from December 31, 2005 to (i) December 31, 2008 for CSPCo and (ii) December 31, 2007 for OPCo. Transmission services will continue to be provided at rates established by the FERC. Default retail generation service rates will be based on market prices pursuant to rules currently under consideration by the PUCO.
Oklahoma: PSO provides retail electric service in Oklahoma at a bundled rate approved by the OCC. PSO's rates are set on a cost-of-service basis. Fuel and purchased power costs above the amount included in base rates are recovered by applying a fuel adjustment factor to retail kilowatt-hour sales. The factor is adjusted quarterly and is based upon forecasted fuel and purchased power costs. Over or under collections of fuel costs for prior periods can be recovered when new quarterly factors are established.
Texas: The Texas Act requires the legal separation of generation-related
assets from transmission and
distribution assets. TCC and TNC currently operate on a functionally separated basis. In January 2002, TCC and TNC transferred all their retail customers in the ERCOT area of Texas to MECPL, MEWTU and AEP Commercial and Industrial REP (an AEP affiliate). TNC's retail SPP customers were ultimately transferred to Mutual Energy SWEPCo L.P. (an AEP affiliate). TCC and TNC provide retail transmission and distribution service on a cost-of-service basis at rates approved by the PUCT and wholesale transmission service under tariffs approved by the FERC consistent with PUCT rules.
The implementation of the business separation plan for SWEPCo operations in the SPP area of Texas was delayed by the PUCT. As such, SWEPCo's Texas operations continue to operate and to be regulated as a traditional bundled utility with both base and fuel rates.
Virginia: APCo provides unbundled retail electric service in Virginia. APCo's unbundled generation, transmission (which reflect FERC approved transmission rates) and distribution rates as well as its functional separation plan were approved by the VSCC in December 2001.
The Virginia Act capped base rates at their mid-1999 levels until the end of the transition period (July 1, 2007), or sooner if the VSCC finds that a competitive market for generation exists in Virginia. The Virginia Act permits APCo to seek a one-time change to its capped non-generation rates after January 1, 2004. The Virginia Act allows adjustments to fuel rates during the transition period and continues to permit utilities to recover their actual fuel costs, the fuel component of their purchased power costs and certain capacity charges. APCo recovers its generation capacity charges through capped base rates.
West Virginia: APCo and Wheeling Power Company provide retail electric service at bundled rates approved by the WVPSC. A plan to introduce customer choice was approved by the West Virginia Legislature in its 2000 legislative session. However, implementation of that plan was placed on hold pending necessary changes to the state's tax laws in a subsequent session. Those changes have not been made.
While West Virginia generally allows recovery of fuel costs, the most recent proceeding resulted in the suspension of an active fuel clause for APCo and WPCo (though they continue to recover fuel costs through fixed bundled rates). APCo and Wheeling Power Company are currently unable to change the current level of fuel cost recovery, though this ability could be reinstated in a future proceeding.
Other Jurisdictions: The public utility subsidiaries of AEP also provide service at regulated bundled rates in Arkansas, Kentucky, Louisiana and Tennessee and regulated unbundled rates in Michigan.
The table below illustrates the current rate regulation status of the states in which the public utility subsidiaries of AEP operate:
FUEL CLAUSE RATES PERCENTAGE
------------------------------------------------- OF AEP
STATUS OF BASE RATES FOR SYSTEM SALES SYSTEM
----------------------------------------------- PROFITS SHARED RETAIL
JURISDICTION POWER SUPPLY ENERGY DELIVERY STATUS INCLUDES W/RATEPAYERS REVENUES(1)
------------ ---------------------- ---------------------- -------------- -------------- --------------- -----------
Ohio Frozen through 2005 Distribution frozen None Not applicable Not applicable 30%
through 2007 for OPCo
and 2008 for CSP;
Transmission frozen
through 2005
Texas
(TCC, TNC) See footnote 2 Not capped or frozen Not applicable Not applicable Not applicable 17%(2)
Texas
(SWEPCo) Capped until 6/15/03 Active Fuel and fuel Yes, above base 3%
portion of levels
purchased
power
Indiana Capped until 1/1/05(3) Capped until Fuel and fuel No 10%
3/1/04(3) portion of
purchased
power
Virginia Capped until as late Capped until as late Active Fuel and fuel No 9%
as 7/1/07(4) as 7/1/07(4) portion of
purchased
power
West Virginia Fixed(5) Suspended(5) Fuel and fuel Yes, but 9%
portion of suspended
purchased
power
Oklahoma Cap expired 1/1/03 Active Fuel and fuel Yes 9%
portion of
purchased
power
Louisiana Capped until 6/15/05 Active Fuel and fuel Yes, above base 5%
portion of levels
purchased
power
Kentucky Frozen until 6/15/03(6) Active Fuel and fuel Yes, above base 3%
portion of levels
purchased
power
Arkansas Capped until 6/15/03 Active Fuel and fuel Yes, above base 2%
portion of levels
purchased
power
Michigan Capped until 1/1/05(7) Capped until 1/1/05(7) Capped until Fuel and fuel Yes, in some 2%
1/1/04(8) portion of areas, but
purchased suspended
power
Tennessee Not capped or frozen Active Fuel and fuel No 1%
portion of
purchased
power
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(1) Represents the percentage of revenues from sales to retail customers from AEP utility companies operating in each state to the total AEP System revenues from sales to retail customers for the year ended December 31, 2002.
(2) Retail electric service in the ERCOT area of Texas is provided to most customers through unaffiliated REPs which must offer PTB rates until January 1, 2007. The percentage of revenues shown includes revenues from power sales contracts between MECPL and TCC and MEWTU and TNC.
(3) Capped base and fuel rates pursuant to a 1999 settlement with base rate freeze extended pursuant to merger stipulation.
(4) Base rates are capped until the earlier of 7/1/07 or a finding by the VSCC that a competitive market for generation exists. One-time change in non-generation rates is allowed in Virginia after 1/1/04.
(5) Rates fixed and expanded net energy clause suspended in West Virginia pursuant to a 1999 rate case stipulation, but subject to change in a future proceeding.
(6) Utilities may request that an environmental surcharge be imposed to recover costs associated with the installation of emission control equipment.
(7) Capped base and fuel rates pursuant to a 1999 settlement and base rates extended pursuant to merger stipulation.
(8) Michigan fuel rates capped until 1/1/04 pursuant to a 1999 fuel settlement.
AEP TRANSMISSION POOL
Transmission Equalization Agreement
APCo, CSPCo, I&M, KPCo and OPCo operate their transmission lines as a single interconnected and coordinated system and are parties to the Transmission Equalization Agreement, dated April 1, 1984, as amended (TEA), defining how they share the costs and benefits associated with their relative ownership of the extra-high-voltage transmission system (facilities rated 345 KV and above) and certain facilities operated at lower voltages (138 KV and above). This sharing is based upon each company's "member-load ratio." The member-load ratio is calculated monthly by dividing such company's highest monthly peak demand for the last twelve months by the aggregate of the highest monthly peak demand for the last twelve months for all east zone operating companies. As of December 31, 2002, the member-load ratios were as follows:
PEAK
DEMAND MEMBER-LOAD
(KW) RATIO (%)
------ -----------
APCo..................... 6,010 28.2
CSPCo.................... 4,040 19.0
I&M...................... 4,323 20.3
KPCo..................... 1,551 7.3
OPCo..................... 5,360 25.2
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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)
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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)
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Transmission Services for Non-Affiliates
In addition to providing transmission services in connection with their own power sales, AEP's public utility subsidiaries and other System companies also provide transmission services for non-affiliated compa-
nies. See Regulation--Regional Transmission Organizations. AEP's public utility subsidiaries are subject to regulation by the FERC under the FPA in respect of transmission of electric power.
Coordination of East and West Zone Transmission
AEP's System Transmission Integration Agreement provides for the integration and coordination of the planning, operation and maintenance of the transmission facilities of AEP's east and west zone public utility subsidiaries. The System Transmission Integration Agreement functions as an umbrella agreement in addition to the TEA and the TCA. The System Transmission Integration Agreement contains two service schedules that govern:
- The allocation of transmission costs and revenues and
- The allocation of third-party transmission costs and revenues and System dispatch costs.
The System Transmission Integration Agreement contemplates that additional service schedules may be added as circumstances warrant.
COMPETITION
The public utility subsidiaries of AEP, like many other electric utilities, have traditionally provided electric generation and energy delivery, consisting of transmission and distribution services, as a single product to their retail customers. Legislation has been enacted in Michigan, Ohio, Texas and Virginia that allows for customer choice of generation supplier. Although restructuring legislation has been passed in Oklahoma and West Virginia, it has been delayed indefinitely in Oklahoma and not implemented in West Virginia. In addition, restructuring legislation in Arkansas has been repealed. See General--Electric Restructuring Legislation. Customer choice legislation generally allows competition in the generation and sale of electric power, but not in its transmission and distribution.
See Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters and Note 8 to the consolidated financial statements entitled Customer Choice and Industry Restructuring incorporated by reference in Items 7 and 8, respectively, for further information with respect to restructuring legislation affecting AEP subsidiaries.
SEASONALITY
Sale of electric power is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. The pattern of this fluctuation may change due to the nature and location of AEP's facilities and the terms of power sale contracts AEP enters into. In addition, AEP has historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could diminish AEP's results of operations and may impact its financial condition.
REGIONAL TRANSMISSION ORGANIZATIONS
On April 24, 1996, the FERC issued orders 888 and 889. These orders require each public utility that owns or controls interstate transmission facilities to file an open access network and point-to-point transmission tariff that offers services comparable to the utility's own uses of its transmission system. The orders also require utilities to functionally unbundle their services, by requiring them to use their own tariffs in making off-system and third-party sales. As part of the orders, the FERC issued a pro-forma tariff that reflects the Commission's views on the minimum non-price terms and conditions for non-discriminatory transmission service. In addition, the orders require all transmitting utilities to establish an Open Access Same-time Information System (OASIS), which electronically posts transmission information such as available capacity and prices, and require utilities to comply with Standards of Conduct that prohibit utilities' system operators from providing non-public transmission information to the utility's merchant employees. The orders also allow a utility to seek recovery of certain prudently incurred stranded costs that result from unbundled transmission service.
In December 1999, FERC issued Order 2000, which provides for the voluntary formation of RTOs, entities created to operate, plan and control utility transmission assets. Order 2000 also prescribes certain characteristics and functions of acceptable RTO proposals.
AEP is required, as a condition of FERC's approval in 2000 of AEP's merger with CSW, to transfer functional control of its transmission facilities to one or more RTOs. In May 2002, AEP announced an agreement with PJM to pursue terms for its east zone public utility subsidiaries to participate in PJM, a
FERC approved RTO. In July 2002, the FERC tentatively approved AEP subsidiaries' decision to join PJM, subject to certain conditions being met. The satisfaction of these conditions is only partially within AEP's control. AEP's public utility subsidiaries have filed applications with the state utility commissions of Indiana, Kentucky, Ohio and Virginia requesting approval of the transfer of functional control of transmission assets in those states to PJM. Those applications are pending. In February 2003, the Virginia legislature enacted legislation that would prohibit the transfer of functional control of transmission assets to an RTO until at least July 2004.
In July 2002, FERC conditionally accepted filings related to a proposed consolidation of MISO and the SPP. In that order the FERC required AEP's west zone subsidiaries in SPP to file reasons why those subsidiaries should not be required to join MISO. SWEPCo has filed an application with the LPSC requesting approval of the transfer of functional control of its Louisiana transmission assets to MISO and intends to make a similar filing in Arkansas with respect to its Arkansas transmission assets. AEP presently plans to transfer functional control of its transmission facilities in SPP to MISO or the merged MISO/SPP.
TEXAS REGULATORY ASSETS AND STRANDED COST RECOVERY AND POST-RESTRUCTURING WIRES CHARGES
Certain transmission and distribution utilities in Texas whose generation assets were unbundled pursuant to the Texas Act may recover generation-related regulatory assets and generation-related stranded costs. Regulatory assets consist of the Texas jurisdictional amount of generation-related regulatory assets and liabilities in the audited financial statements as of December 31, 1998. Stranded costs consist of the positive excess of the net regulated book value of generation assets over the market value of those assets, taking specified factors into account. The Texas Act allows alternative methods of valuation to determine the fair market value of generation assets, including outright sale, full and partial stock valuation and asset exchanges, and also, for nuclear generation assets, the ECOM model.
The Texas Act further permits utilities to establish a special purpose entity to issue securitization bonds for the recovery of regulatory assets and, after the 2004 true-up proceeding, the amount of stranded costs and remaining regulatory assets not previously securitized. Securitization bonds allow for regulatory assets and stranded costs to be refinanced with recovery of the bond principal and financing costs ensured through a non-bypassable rate surcharge by the regulated transmission and distribution utility over the life of the securitization bonds. Any stranded costs not recovered through the sale of securitization bonds may be recovered through a separate non-bypassable competitive transition charge to transmission and distribution customers.
Regulatory Assets
In 1999, TCC filed an application with the PUCT to securitize approximately $1.27 billion of its retail generation-related regulatory assets and approximately $47 million in other qualified restructuring costs. On March 27, 2000, the PUCT issued an order authorizing issuance of up to $797 million of securitization bonds including $764 million for recovery of net generation- related regulatory assets and $33 million for other qualified refinancing costs. The securitization bonds were issued in February 2002. TCC has included a transition charge in its distribution rates to repay the bonds over a 14-year period. In addition, another $185 million of generation-related regulatory assets are being recovered through distribution rates beginning in January 2002. Remaining generation-related regulatory assets of approximately $214 million originally included by TCC in its 1999 securitization request along with certain other regulatory assets will be included in TCC's request to recover stranded costs in the 2004 true-up proceeding.
Stranded Costs
In a March 2000 filing with the PUCT to determine unbundled transmission and distribution charges and initial stranded cost recovery, TCC requested recovery of an additional $1.1 billion of stranded costs and regulatory assets that were not securitized. In October 2001, the PUCT issued an order in the UCOS proceeding determining an initial amount of TCC ECOM or stranded costs of approximately negative $615 million based upon the PUCT's ECOM model. The ruling indicated that TCC costs were below market after securitization of regulatory assets. TCC disagrees with the ruling and believes it has positive stranded costs in addition to the securitized regulatory assets.
As a result of this stranded cost determination, the PUCT ordered TCC to refund $55 million of estimated excess earnings for the period 1999 through 2001 to customers through a credit applied to distribu-
tion rates over a five-year period. TCC appealed the PUCT's estimate of stranded costs and refund of excess earnings, among other issues, to the Travis County District Court. This estimate may be superseded by a final determination made as part of the 2004 true-up proceedings.
The final amount of TCC's stranded costs including regulatory assets and ECOM will be established by the PUCT in the 2004 true-up proceeding. Pursuant to PUCT rules, if TCC's total stranded costs determined in the 2004 true-up proceeding are less than the amount of securitized regulatory assets, the PUCT can implement an offsetting credit to transmission and distribution rates. The Texas Third Circuit Court of Appeals ruled in February 2003 that the Texas Act does not contemplate the refunding to customers of negative stranded costs. In addition, the Court ruled that negative stranded costs cannot be offset against other true-up adjustments, including under-recovered fuel amounts. This ruling may be appealed to the Texas Supreme Court, which has discretion as to whether to accept and consider the appeal.
2004 True-Up Proceedings
Beginning as early as January 2004, the PUCT will conduct true-up proceedings (with respect to the ERCOT area of Texas) for each investor-owned utility, its affiliated REP and affiliated power generation company. The purpose of the true-up proceeding is to (i) quantify and reconcile the amount of stranded costs and generation-related regulatory assets that have not yet been securitized, (ii) conduct a true-up of the PUCT ECOM model for 2002 and 2003 to reflect market prices determined in required capacity auctions, (iii) establish final fuel recovery balances and (iv) determine the price to beat clawback component. The true-up proceeding will generally result in either additional charges or credits to retail customers through transmission and distribution rates collected by their REPs and remitted to the utility.
Stranded Cost and Generation-Related Regulatory Asset Determination: The Texas Act authorized the use of several valuation methodologies to quantify stranded costs and generation-related regulatory assets in the 2004 true-up proceeding, including by the sale of assets. TCC filed a plan of divestiture with the PUCT in December 2002 seeking approval to sell its generation assets to determine their market value. The PUCT has dismissed its proceeding relating to TCC's plan of divestiture in anticipation of promulgating rules of general application regarding stranded cost determination. If the PUCT determines the sale of assets methodology cannot be used to determine the market value of STP, TCC intends to pursue the use of one or more market valuation methods. Divestiture of TCC's interest in STP to a nonaffiliate will also require NRC approval. TNC does not have any recoverable stranded costs or generation-related regulatory assets that can be considered as part of the 2004 true-up.
ECOM/Capacity Auction Component: The PUCT used a computer model or projection, called an ECOM model, to estimate stranded costs related to generation plant assets in the UCOS proceeding. In connection with using the ECOM model to calculate the stranded cost estimate, the PUCT estimated the market power prices that will be received in the competitive wholesale generation market. Any difference between the ECOM model market prices and actual market power prices as measured by generation capacity auctions required by the Texas Act during the period of January 1, 2002 through December 31, 2003 will be a component of the 2004 true-up proceeding, either increasing or decreasing the amount of recovery for TCC. Auctions to date have generally indicated that market prices have been lower than the PUCT's ECOM estimates. Unless this is reversed, TCC's recovery in the 2004 true-up proceeding would be increased. In the event TCC has transferred its generation assets to an affiliate, the Texas Act would require TCC to remit to its affiliate the recovery amount accruing after the transfer. See Note 8 to the consolidated financial statements, entitled Customer Choice and Industry Restructuring, incorporated by reference in Item 8, for a discussion of the current calculation of the difference between the market price and ECOM estimate.
Fuel Recovery Balance Determination: The amount TCC or TNC recovers in the 2004 true-up proceeding could be increased or reduced (or the amount TCC must refund could be increased) by any under or over-recovery of fuel. The fuel component will be determined by the amount of fuel costs and expenses the PUCT approves based on a final fuel reconciliation that TCC filed on December 2, 2002 and that TNC filed on June 3, 2002. TCC's fuel reconciliation covers its fuel costs from the period beginning July 1, 1998 and ending December 31, 2001. TCC's fuel reconciliation filing seeks approval for $1.6 billion in fuel expense collected from retail customers during that period. TCC's fuel reconciliation filing reflects a fuel over-recovery balance, as of December 31, 2001, of $63.5 million, including
interest. A procedural schedule has been set with a hearing scheduled to begin May 7, 2003. TNC's fuel reconciliation requests approval of $292 million in fuel costs associated with serving both ERCOT and SPP retail customers from July 1, 2000 through December 31, 2001. It reflects a fuel under-recovery balance, as of December 31, 2001, of $26.9 million, including interest. The amounts in this paragraph may periodically be adjusted as filings are updated or adjusted. A final order from the PUCT is expected in the first half of 2003. Any under or over-recovery, plus interest thereon, will be recovered from or returned to customers as a component of the 2004 true-up proceeding.
Price to Beat Clawback Component: The amount TCC or TNC recovers in the 2004 true-up proceeding could be reduced (or the amount TCC or TNC must refund could be increased) by the PTB clawback component. If MECPL and MEWTU (which are no longer affiliated with TCC or TNC) continue to serve 60% or more of TCC's and TNC's respective PTB load as of January 1, 2004 and the PTB (reduced by non-bypassable wires charges) exceeds the market price of electricity, any such excess must be credited to customers of TCC and TNC in the 2004 true-up proceeding, by up to $150 per customer, subject to certain adjustments. The Texas Act provides that MECPL and MEWTU effectively indemnify TCC and TNC, respectively, for any PTB clawback amounts assessed them. The MECPL and MEWTU sale agreements provide that Centrica (as purchaser of MECPL and MEWTU) and AEP Utilities (the parent of TCC and TNC, as seller of MECPL and MEWTU) will share responsibility for this indemnity.
Further Securitization Bonds and Wires Charges: After final determination of its stranded costs and other true-up adjustments by the PUCT, TCC expects to issue securitization bonds in the amount of its non-securitized stranded costs and generation-related regulatory assets determined in the 2004 true-up proceeding. The bonds can have a maximum term of 15 years. If securitization bonds are not issued to finance all non-securitized stranded costs and generation-related regulatory assets, TCC will seek recovery of these amounts as well as its other true-up adjustments, through a non-bypassable competition transition charge in transmission and distribution rates.
For a discussion of recovery of regulatory assets and stranded costs in Ohio and Virginia, see Note 8 to the consolidated financial statements entitled Customer Choice and Industry Restructuring, incorporated by reference in Item 8.
OTHER INVESTMENTS
AEP has made certain investments in telecommunications, international energy and other concerns. In 2002, AEP wrote down the value of certain of those investments. See Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters and Note 13 to the consolidated financial statements entitled Asset Impairment and Investment Value Losses, incorporated by reference in Items 7 and 8, respectively.
AEP also sold the following foreign investments in 2002:
- SEEBOARD, an electricity supply and distribution company in the United Kingdom serving 2,000,000 customers and covering 3,000 square miles of service territory.
- CitiPower, a retail electricity and gas supply and distribution subsidiary in Australia serving 240,000 customers.
GENERATION FACILITIES
General
At December 31, 2002, the AEP System owned (or leased where indicated) generating plants with net power capabilities (east zone public utility subsidiaries-winter rating; west zone public utility subsidiaries-summer rating) shown in the following table:
COAL NATURAL GAS HYDRO NUCLEAR LIGNITE OTHER TOTAL
COMPANY STATIONS MW MW MW MW MW MW MW
------------------------------------------------------------------------------------------------------------
AEGCo 1(a) 1,300 1,300
APCo 17(b) 5,073 777 5,850
CSPCo 6(e) 2,595 2,595
I&M 10(a) 2,295 11 2,110 4,416
KPCo 1 1,060 1,060
OPCo 8(b)(f) 8,472 48 8,520
PSO 8(c) 1,043 3,169 25(g) 4,237
SWEPCo 9 1,848 1,797 842 4,487
TCC 12(c)(d)(h) 686 3,175 6 630 4,497
TNC 12(c) 377 999 16(g) 1,392
------------------------------------------------------------------------------------------------------------
Totals: 84 24,749 9,140 842 2,740 842 41 38,354
------------------------------------------------------------------------------------------------------------
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(a) Unit 1 of the Rockport Plant is owned one-half by AEGCo and one-half by I&M. Unit 2 of the Rockport Plant is leased one-half by AEGCo and one-half by I&M. The leases terminate in 2022 unless extended.
(b) Unit 3 of the John E. Amos Plant is owned one-third by APCo and two-thirds by OPCo.
(c) PSO, TCC and TNC jointly own the Oklaunion power station. Their respective ownership interests are reflected in this table.
(d) Reflects TCC's interest in STP.
(e) CSPCo owns generating units in common with CG&E and DP&L. Its ownership interest of 1,330 MW is reflected in this table.
(f) The scrubber facilities at the General James M. Gavin Plant are leased. The lease terminates in 2010 unless extended.
(g) PSO and TNC have 25 MW and 10 MW respectively of facilities designed primarily to burn oil. TNC has one 6 MW wind farm facility.
(h) See Item 1 -- Wholesale Operations -- Power Generation -- Planned Deactivation and Planned Disposition of Generation Facilities for a discussion of TCC's planned disposition of its generation facilities.
In addition to the generating facilities described above, AEP has ownership interests in other electrical generating facilities, both foreign and domestic. Information concerning these facilities at December 31, 2002 is listed below.
CAPACITY OWNERSHIP
FACILITY FUEL LOCATION TOTAL MW INTEREST STATUS
----------------------------------------------------------------------------------------------------------
Brush II Natural gas Colorado 68 47.75% QF
Eastex Natural gas Texas 440 50% QF
Indian Mesa Wind Texas 161 100% EWG
Mulberry Natural gas Florida 120 46.25% QF
Newgulf Natural gas Texas 85 100% EWG
Orange Cogen Natural gas Florida 103 50% QF
Sweeny Natural gas Texas 480 50% QF
Thermo Cogeneration Natural gas Colorado 272 50% QF
Trent Wind Farm Wind Texas 150 100% EWG
----------------------------------------------------------------------------------------------------------
Total U.S. 1,879
----------------------------------------------------------------------------------------------------------
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CAPACITY OWNERSHIP
FACILITY FUEL LOCATION TOTAL MW INTEREST STATUS
----------------------------------------------------------------------------------------------------------
Bajio Natural gas Mexico 605 50% FUCO
Ferrybridge Coal United Kingdom 2,000 100% FUCO
Fiddler's Ferry Coal United Kingdom 2,000 100% FUCO
Nanyang Coal China 250 70% FUCO
Southcoast Natural gas United Kingdom 380 50% FUCO
----------------------------------------------------------------------------------------------------------
Total International 5,235
----------------------------------------------------------------------------------------------------------
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See Item 1 -- Wholesale Operations for information concerning natural gas pipelines, storage and processing facilities, transportation related assets and coal operations and reserves owned or controlled by AEP subsidiaries.
Cook Nuclear Plant and STP
The following table provides operating information relating to the Cook Plant and STP.
COOK PLANT STP(A)
--------------------- ---------------------
UNIT 1 UNIT 2 UNIT 1 UNIT 2
--------- --------- --------- ---------
YEAR PLACED IN
OPERATION.......... 1975 1978 1988 1989
YEAR OF EXPIRATION OF
NRC LICENSE (B).... 2014 2017 2027 2028
NOMINAL NET
ELECTRICAL RATING
IN KILOWATTS....... 1,020,000 1,090,000 1,250,600 1,250,600
NET CAPACITY FACTORS
2002............... 86.6% 80.5% 99.2% 75.0%
2001 (C)........... 87.3% 83.4% 94.4% 87.1%
2000 (D)........... 1.4% 50.0% 78.2% 96.1%
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(a) Reflects total plant.
(b) For economic or other reasons, operation of the Cook Plant and STP for the full term of their operating licenses cannot be assured.
(c) The capacity factor for both units of the Cook Plant was significantly reduced in 2001 due to an unplanned dual maintenance outage in September 2001 to implement design changes that improved the performance of the essential service water system.
(d) The Cook Plant was shut down in September 1997 to respond to issues raised regarding the operability of certain safety systems. The restart of both units of the Cook Plant was completed with Unit 2 reaching 100% power on July 5, 2000 and Unit 1 achieving 100% power on January 3, 2001.
Costs associated with the operation (excluding fuel), maintenance and retirement of nuclear plants continue to be of greater significance and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements and safety standards, availability of nuclear waste disposal facilities and experience gained in the construction and operation of nuclear facilities. I&M and TCC may also incur costs and experience reduced output at Cook Plant and STP, respectively, because of the design criteria prevailing at the time of construction and the age of the plant's systems and equipment. Nuclear industry-wide and Cook Plant and STP initiatives have contributed to slowing the growth of operating and maintenance costs at these plants. However, the ability of I&M and TCC to obtain adequate and timely recovery of costs associated with the Cook Plant and STP, respectively, including replacement power, any unamortized investment at the end of the useful life of the Cook Plant and STP (whether scheduled or premature), the carrying costs of that investment and retirement costs, is not assured. See Item 1 -- Wholesale Operations -- Power Generation -- Planned Deactivation and Planned Disposition of Generation Facilities for a discussion of TCC's planned disposition of its interest in STP.
POTENTIAL UNINSURED LOSSES
Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including liabilities relating to damage to the Cook Plant or STP and costs of replacement power in the event of a nuclear incident at the Cook Plant or STP. Future losses or liabilities which are not completely insured, unless allowed to be recovered through rates, could have a material adverse effect on results of operations and the financial condition of AEP, I&M, TCC and other AEP System companies. See Note 9 to the consolidated financial statements entitled Commitments and Contingencies, incorporated by reference in Item 8, for information with respect to nuclear incident liability insurance.
TRANSMISSION AND DISTRIBUTION FACILITIES
The following table sets forth the total overhead circuit miles of transmission and distribution lines of the AEP System and its operating companies and that portion of the total representing 765,000-volt lines:
TOTAL OVERHEAD
CIRCUIT MILES OF
TRANSMISSION AND CIRCUIT MILES OF
DISTRIBUTION LINES 765,000-VOLT LINES
------------------ ------------------
AEP System (a)....... 226,330(b) 2,023
APCo. ............. 50,756 642
CSPCo (a).......... 12,255 --
I&M................ 25,128 615
Kingsport Power
Company......... 1,335 --
KPCo. ............. 10,555 258
OPCo. ............. 35,551 509
PSO................ 21,539 --
SWEPCo............. 20,075 --
TCC................ 33,515 --
TNC................ 13,637 --
Wheeling Power
Company......... 1,941 --
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(a) Includes 766 miles of 345,000-volt jointly owned lines.
(b) Includes 73 miles of transmission lines not identified with an operating company.
TITLES
The AEP System's electric generating stations are generally located on lands owned in fee simple. The greater portion of the transmission and distribution lines of the System has been constructed over lands of private owners pursuant to easements or along public highways and streets pursuant to appropriate statutory authority. The rights of the System in the realty on which its facilities are located are considered by it to be adequate for its use in the conduct of its business. Minor defects and irregularities customarily found in title to properties of like size and character may exist, but such defects and irregularities do not materially impair the use of the properties affected thereby. System companies generally have the right of eminent domain whereby they may, if necessary, acquire, perfect or secure titles to or easements on privately held lands used or to be used in their utility operations.
Substantially all the fixed physical properties and franchises of the AEP System operating companies, except for limited exceptions, are subject to the lien of the mortgage and deed of trust securing the first mortgage bonds of each such company.
SYSTEM TRANSMISSION LINES AND FACILITY SITING
Legislation in the states of Arkansas, Indiana, Kentucky, Michigan, Ohio, Texas, Virginia, and West Virginia requires prior approval of sites of generating facilities and/or routes of high-voltage transmission lines. Delays and additional costs in constructing facilities have been experienced as a result of proceedings conducted pursuant to such statutes, as well as in proceedings in which operating companies have sought to acquire rights-of-way through condemnation, and such proceedings may result in additional delays and costs in future years.
CONSTRUCTION PROGRAM
General
The AEP System is continuously involved in assessing the adequacy of its generation, transmission, distribution and other facilities to plan and provide for the reliable supply of electric power and energy to its customers. In this assessment process, assumptions are continually being reviewed as new information becomes available, and assessments and plans are modified, as appropriate. Thus, System reinforcement plans are subject to change, particularly with the restructuring of the electric utility industry.
Proposed Transmission Facilities
APCo is proceeding with its plan to build the Wyoming-Jacksons Ferry 765,000-volt transmission line. The WVPSC and the VSCC have issued certificates authorizing construction and operation of the line. On December 31, 2002, the U.S. Forest Service issued a final environmental impact statement and record of decision to allow the use of federal lands in the Jefferson National Forest for construction of a portion of the line. Additional state and federal permits are expected to be issued in the first half of 2003. Through December 31, 2002 APCo had invested approximately $51 million in this project. The line is estimated to cost $287 million with completion scheduled in 2006.
Construction Expenditures
The following table shows construction expenditures during 2000, 2001 and 2002 and current estimates of 2003 construction expenditures, in each case including AFUDC but excluding assets acquired under leases.
2000 2001 2002 2003
ACTUAL ACTUAL ACTUAL ESTIMATE
---------- ---------- ---------- ----------
(IN THOUSANDS)
AEP System (a)....... $1,773,400 $1,832,000 $1,709,800 $1,458,100
AEGCo. ............ 5,200 6,900 5,300 21,400
APCo. ............. 199,300 306,000 276,500 247,900
CSPCo. ............ 128,000 132,500 136,800 142,300
I&M................ 171,100 91,100 159,400 188,000
KPCo. ............. 36,200 37,200 178,700 72,300
OPCo. ............. 254,000 344,600 354,800 241,000
PSO................ 176,900 124,900 89,400 81,500
SWEPCo. ........... 120,200 112,100 111,800 104,900
TCC................ 199,500 194,100 151,500 126,800
TNC................ 64,500 39,800 43,600 46,500
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(a) Includes expenditures of other subsidiaries not shown.
See Note 9 to the consolidated financial statements entitled Commitments and Contingencies, incorporated by reference in Item 8, for further information with respect to the construction plans of AEP and its operating subsidiaries for the next three years.
The System construction program is reviewed continuously and is revised from time to time in response to changes in estimates of customer demand, business and economic conditions, the cost and availability of capital, environmental requirements and other factors. Changes in construction schedules and costs, and in estimates and projections of needs for additional facilities, as well as variations from currently anticipated levels of net earnings, Federal income and other taxes, and other factors affecting cash requirements, may increase or decrease the estimated capital requirements for the System's construction program.
For a discussion of material legal proceedings, see Note 9 to the consolidated financial statements, entitled Commitments and Contingencies, incorporated by reference in Item 8.
AEP, APCO, I&M, OPCO, SWEPCO AND TCC. None.
AEGCO, CSPCO, KPCO, PSO AND TNC. Omitted pursuant to Instruction I(2)(c).
EXECUTIVE OFFICERS OF THE REGISTRANTS
AEP. The following persons are, or may be deemed, executive officers of AEP. Their ages are given as of March 1, 2003.
NAME AGE OFFICE (A)
---- --- ----------
E. Linn Draper, Jr. ........... 61 Chairman of the Board, President and Chief Executive Officer
of AEP and of the Service Corporation
Thomas V. Shockley, III........ 57 Vice Chairman of AEP and Vice Chairman and Chief Operating
Officer of the Service Corporation
Henry W. Fayne................. 56 Vice President of AEP, Executive Vice President of the
Service Corporation
Thomas M. Hagan................ 58 Executive Vice President-Shared Services of the Service
Corporation
Holly K. Koeppel............... 44 Executive Vice President of the Service Corporation
Robert P. Powers............... 49 Executive Vice President-Nuclear Generation and Technical
Services of the Service Corporation
Susan Tomasky.................. 49 Vice President of AEP, Executive Vice President-Policy,
Finance and Strategic Planning of the Service Corporation
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(a) Dr. Draper and Mr. Fayne have been employed by the Service Corporation or System companies in various capacities (AEP, as such, has no employees) for the past five years. Prior to joining the Service Corporation in July 1998 as Senior Vice President-Generation, Mr. Powers was Vice President of Pacific Gas & Electric and plant manager of its Diablo Canyon Nuclear Generating Station (1996-1998). Prior to joining the Service Corporation in July 1998 as Senior Vice President, Ms. Tomasky was a partner with the law firm of Hogan & Hartson (August 1997-July 1998) and General Counsel of the Federal Energy Regulatory Commission (May 1993-August 1997). Prior to joining the Service Corporation in June 2000 as Senior Vice President- Governmental Affairs, Mr. Hagan was Senior Vice President-External Affairs of CSW. Prior to joining the Service Corporation in July 2000 as Vice President-New Ventures, Ms. Koeppel was Regional Vice President of Asia-Pacific Operations for Consolidated Natural Gas International (1996-2000). Messrs. Hagan and Powers, Ms. Koeppel and Ms. Tomasky became executive officers of AEP effective with their promotions to Executive Vice President on September 9, 2002, October 24, 2001, November 18, 2002 and January 26, 2000, respectively. Prior to joining the Service Corporation in his current position upon the merger with CSW, Mr. Shockley was President and Chief Operating Officer of CSW (1997-2000) and Executive Vice President of CSW (1990-1997). All of the above officers are appointed annually for a one-year term by the board of directors of AEP, the board of directors of the Service Corporation, or both, as the case may be.
APCO, I&M, OPCO, SWEPCO AND TCC. The names of the executive officers of APCo, I&M, OPCo, SWEPCo and TCC, the positions they hold with these companies, their ages as of March 1, 2003, and a brief account of their business experience during the past five years appear below. The directors and executive officers of APCo, I&M, OPCo, SWEPCo and TCC are elected annually to serve a one-year term.
NAME AGE POSITION (A)(B) PERIOD
---- --- --------------- ------
E. Linn Draper, Jr. ........... 61 Director of SWEPCo and TCC 2000-Present
Chairman of the Board and Chief Executive Officer
of SWEPCo and TCC 2000-Present
Director of APCo, I&M and OPCo 1992-Present
Chairman of the Board and Chief Executive Officer
of APCo, I&M and OPCo 1993-Present
Chairman of the Board, President and Chief
Executive Officer of AEP and the Service Corporation 1993-Present
Thomas V. Shockley, III........ 57 Director and Vice President of APCo, I&M, OPCo,
SWEPCo and TCC 2000-Present
Chief Operating Officer of the Service Corporation 2001-Present
Vice Chairman of AEP and the Service Corporation 2000-Present
President and Chief Operating Officer of CSW 1997-2000
Executive Vice President of CSW 1990-1997
Henry W. Fayne................. 56 President of APCo, I&M, OPCo, SWEPCo and TCC 2001-Present
Director of SWEPCo and TCC 2000-Present
Director of APCo 1995-Present
Director of OPCo 1993-Present
Director of I&M 1998-Present
Vice President of SWEPCo and TCC 2000-2001
Vice President of APCo, I&M and OPCo 1998-2001
Vice President of AEP 1998-Present
Chief Financial Officer of AEP 1998-2001
Executive Vice President of the Service Corporation 2001-Present
Executive Vice President-Finance and Analysis of
the Service Corporation 2000-2001
Executive Vice President-Financial Services of the
Service Corporation 1998-2000
Senior Vice President-Corporate Planning & Budgeting
of the Service Corporation 1995-1998
Thomas M. Hagan................ 58 Director and Vice President of APCo, I&M, OPCo,
SWEPCo and TCC 2002-Present
Executive Vice President-Shared Services of the
Service Corporation 2002-Present
Senior Vice President-Governmental Affairs of the
Service Corporation 2000-2002
Senior Vice President-External Affairs of CSW 1996-2000
Holly K. Koeppel............... 44 Executive Vice President of the Service Corporation 2002-Present
Vice President-New Ventures 2000-2002
Regional Vice President of Asia-Pacific Operations
for Consolidated Natural Gas International 1996-2000
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NAME AGE POSITION (A)(B) PERIOD
---- --- --------------- ------
Robert P. Powers............... 49 Director and Vice President of APCo, I&M, OPCo,
SWEPCo and TCC 2001-Present
Director of I&M 2001-Present
Vice President of I&M 1998-Present
Executive Vice President- Generation 2003-Present
Executive Vice President-Nuclear Generation and
Technical Services of the Service Corporation 2001-2003
Senior Vice President-Nuclear Operations of the
Service Corporation 2000-2001
Senior Vice President-Nuclear Generation of the
Service Corporation 1998-2000
Vice President of Pacific Gas & Electric and Plant
Manager of its Diablo Canyon Nuclear Generating
Station 1996-1998
Susan Tomasky.................. 49 Director and Vice President of APCo, I&M, OPCo,
SWEPCo and TCC 2000-Present
Executive Vice President-Policy, Finance and
Strategic Planning of the Service Corporation 2001-Present
Executive Vice President-Legal, Policy and
Corporate Communications and General Counsel of
the Service Corporation 2000-2001
Senior Vice President and General Counsel of the
Service Corporation 1998-2000
Hogan & Hartson (law firm) 1997-1998
General Counsel of the FERC 1993-1997
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(a) Dr. Draper is a director of BCP Management, Inc., which is the general partner of Borden Chemicals and Plastics L.P.
(b) Dr. Draper, Messrs. Fayne, Hagan, Powers and Shockley and Ms. Tomasky are directors of AEGCo, CSPCo, KPCo, PSO and TNC. Dr. Draper and Mr. Shockley are also directors of AEP.
AEP. The information required by this item is incorporated herein by reference to the material under Common Stock and Dividend Information in the 2002 Annual Report.
AEGCO, APCO, CSPCO, I&M, KPCO, OPCO, PSO, SWEPCO, TCC AND TNC. The common stock of these companies is held solely by AEP. The amounts of cash dividends on common stock paid by these companies to AEP during 2002 and 2001 are incorporated by reference to the material under Statement of Retained Earningsin the 2002 Annual Reports.
AEGCO, CSPCO, KPCO, PSO AND TNC. Omitted pursuant to Instruction I(2)(a).
AEP, APCO, I&M, OPCO, SWEPCO AND TCC. The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the 2002 Annual Reports.
AEGCO, CSPCO, KPCO, PSO AND TNC. Omitted pursuant to Instruction I(2)(a). Management's narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management's Narrative Analysis of Results of Operations in the 2002 Annual Reports.
AEP, APCO, I&M, OPCO, SWEPCO AND TCC. The information required by this item is incorporated herein by reference to the material under Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Contingencies and Other Matters in the 2002 Annual Reports.
AEGCO, AEP, APCO, CSPCO, I&M, KPCO, OPCO, PSO, SWEPCO, TCC AND TNC. The information required by this item is incorporated herein by reference to the material under Management's Discussion and Analysis of Financial Condition, Contingencies and Other Matters in the 2002 Annual Reports.
AEGCO, AEP, APCO, CSPCO, I&M, KPCO, OPCO, PSO, SWEPCO, TCC AND TNC. The information required by this item is incorporated herein by reference to the financial statements and financial statement schedules described under Item 15 herein.
AEGCO, AEP, APCO, CSPCO, I&M, KPCO, OPCO, PSO, SWEPCO, TCC AND TNC. None.
AEGCO, CSPCO, KPCO, PSO AND TNC. Omitted pursuant to Instruction I(2)(c).
AEP. The information required by this item is incorporated herein by reference to the material under Nominees for Director and Section 16(a) Beneficial Ownership Reporting Compliance of the definitive proxy statement of AEP for the 2003 annual meeting of shareholders, to be filed within 120 days after December 31, 2002. Reference also is made to the information under the caption Executive Officers of the Registrants in Part I of this report.
APCO AND OPCO. The information required by this item is incorporated herein by reference to the material under Election of Directors of the definitive information statement of each company for the 2003 annual meeting of stockholders, to be filed within 120 days after December 31, 2002. Reference also is made to the information under the caption Executive Officers of the Registrants in Part I of this report.
SWEPCO AND TCC. The information required by this item is incorporated herein by reference to the material under Election of Directors of the definitive information statement of APCo for the 2003 annual meeting of stockholders, to be filed within 120 days after December 31, 2002. Reference also is made to the information under the caption Executive Officers of the Registrants in Part I of this report.
I&M. The names of the directors and executive officers of I&M, the positions they hold with I&M, their ages as of March 12, 2003, and a brief account of their business experience during the past five years appear below and under the caption Executive Officers of the Registrants in Part I of this report.
NAME AGE POSITION (A) PERIOD
---- --- ------------ ------
K. G. Boyd..................... 51 Director 1997-Present
Vice President (Appointed) -- Fort Wayne Region
Distribution Operations 2000-Present
Indiana Region Manager 1997-2000
John E. Ehler.................. 46 Director 2001-Present
Manager of Distribution Systems-Fort Wayne District 2000-Present
Region Operations Manager 1997-2000
David L. Lahrman............... 51 Director and Manager, Region Support 2001-Present
Fort Wayne District Manager 1997-2001
Marc E. Lewis.................. 48 Director 2001-Present
Assistant General Counsel of the Service
Corporation 2001-Present
Senior Counsel of the Service Corporation 2000-2001
Senior Attorney of the Service Corporation 1994-2000
Susanne M. Moorman............. 53 Director and General Manager, Community Services 2000-Present
Manager, Customer Services Operations 1997-2000
John R. Sampson................ 50 Director and Vice President 1999-Present
Indiana State President 2000-Present
Indiana & Michigan State President 1999-2000
Site Vice President, Cook Nuclear Plant 1998-1999
Plant Manager, Cook Nuclear Plant 1996-1998
D. B. Synowiec................. 59 Director 1995-Present
Plant Manager, Rockport Plant 1990-Present
|
(a) Positions are with I&M unless otherwise indicated.
AEGCO, CSPCO, KPCO, PSO AND TNC. Omitted pursuant to Instruction I(2)(c).
AEP. The information required by this item is incorporated herein by reference to the material under Directors Compensation and Stock Ownership Guidelines, Executive Compensation and the performance graph of the definitive proxy statement of AEP for the 2003 annual meeting of shareholders to be filed within 120 days after December 31, 2002.
APCO AND OPCO. The information required by this item is incorporated herein by reference to the material under Executive Compensation of the definitive information statement of each company for the 2003 annual meeting of stockholders, to be filed within 120 days after December 31, 2002.
I&M, SWEPCO AND TCC. The information required by this item is incorporated herein by reference to the material under Executive Compensationof the definitive information statement of APCo for the 2003 annual meeting of stockholders, to be filed within 120 days after December 31, 2002.
AEGCO, CSPCO, KPCO, PSO AND TNC. Omitted pursuant to Instruction I(2)(c).
AEP. The information required by this item is incorporated herein by reference to the material under Share Ownership of Directors and Executive Officers of the definitive proxy statement of AEP for the 2003 annual meeting of shareholders to be filed within 120 days after December 31, 2002.
APCO AND OPCO. The information required by this item is incorporated herein by reference to the material under Share Ownership of Directors and Executive Officers in the definitive information state-
ment of each company for the 2003 annual meeting of stockholders, to be filed within 120 days after December 31, 2002.
I&M. All 1,400,000 outstanding shares of Common Stock, no par value, of I&M are directly and beneficially held by AEP. Holders of the Cumulative Preferred Stock of I&M generally have no voting rights, except with respect to certain corporate actions and in the event of certain defaults in the payment of dividends on such shares.
SWEPCO AND TCC. The information required by this item is incorporated herein by reference to the material under Share Ownership of Directors and Executive Officers in the definitive information statement of APCo for the 2003 annual meeting of stockholders, to be filed within 120 days after December 31, 2002.
The table below shows the number of shares of AEP Common Stock and stock-based units that were beneficially owned, directly or indirectly, as of January 1, 2003, by each director and nominee of I&M and each of the executive officers of I&M named in the summary compensation table, and by all directors and executive officers of I&M as a group. It is based on information provided to I&M by such persons. No such person owns any shares of any series of the Cumulative Preferred Stock of I&M. Unless otherwise noted, each person has sole voting power and investment power over the number of shares of AEP Common Stock and stock-based units set forth opposite his or her name. Fractions of shares and units have been rounded to the nearest whole number.
STOCK
NAME SHARES (A) UNITS (B) TOTAL
---- ---------- --------- ---------
Karl G. Boyd................................................ 10,675 607 11,282
E. Linn Draper, Jr. ........................................ 472,034(c) 117,803 589,837
John E. Ehler............................................... 11 -- 11
Henry W. Fayne.............................................. 139,787(d) 12,362 152,149
Thomas M. Hagan............................................. 54,392 140 54,532
David L. Lahrman............................................ 430 -- 430
Marc E. Lewis............................................... 3,290 -- 3,290
Susanne M. Moorman.......................................... 908 -- 908
Robert P. Powers............................................ 65,862 1,293 67,155
John R. Sampson............................................. 10,643 173 10,816
Thomas V. Shockley, III..................................... 211,067(d)(e) -- 211,067
David B. Synowiec........................................... 7,645 182 7,827
Susan Tomasky............................................... 134,449(d) 6,126 140,575
All Directors and Executive Officers........................ 1,196,424(d)(f) 138,686 1,335,110
|
(a) Includes share equivalents held in the AEP Retirement Savings Plan in the amounts listed below:
AEP RETIREMENT SAVINGS
NAME PLAN (SHARE EQUIVALENTS)
---- ------------------------
Mr. Boyd.......................... 675
Dr. Draper........................ 4,659
Mr. Ehler......................... 11
Mr. Fayne......................... 5,804
Mr. Hagan......................... 2,515
Mr. Lahrman....................... 430
Mr. Lewis......................... 1,207
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AEP RETIREMENT SAVINGS
NAME PLAN (SHARE EQUIVALENTS)
---- ------------------------
Ms. Moorman....................... 908
Mr. Powers........................ 596
Mr. Sampson....................... 643
Mr. Shockley...................... 7,104
Mr. Synowiec...................... 4,312
Ms. Tomasky....................... 1,116
All Directors and Executive
Officers........................ 29,980
|
With respect to the share equivalents held in the AEP Retirement Savings Plan, such persons have sole voting power, but the investment/disposition power is subject to the terms of the Plan. Also, includes the following numbers of shares attributable to options exercisable within 60 days: Mr. Boyd, 10,000; Dr. Draper, 466,666;
Mr. Hagan, 41,666; Mr. Lewis, 2,083; Mr. Powers, 65,266; Mr. Sampson, 10,000; Mr. Shockley, 166,666; Mr. Synowiec, 3,333; and Mr. Fayne and Ms. Tomasky, 133,333.
(b) This column includes amounts deferred in stock units and held under AEP's officer benefit plans.
(c) Includes 661 shares held by Dr. Draper in joint tenancy with a family member.
(d) Does not include, for Messrs. Fayne, and Shockley and Ms. Tomasky, 85,231 shares in the American Electric Power System Educational Trust Fund over which Messrs. Fayne and Shockley and Ms. Tomasky share voting and investment power as trustees (they disclaim beneficial ownership). The amount of shares shown for all directors and executive officers as a group includes these shares.
(e) Includes 496 shares held by family members of Mr. Shockley over which he disclaimed beneficial ownership.
(f) Represents less than 1% of the total number of shares outstanding.
EQUITY COMPENSATION PLAN INFORMATION
The following table summarizes the ability of AEP to issue common stock pursuant to equity compensation plans as of December 31, 2002:
NUMBER OF SECURITIES
NUMBER OF REMAINING AVAILABLE
SECURITIES TO BE FOR FUTURE ISSUANCE
ISSUED UPON WEIGHTED AVERAGE UNDER EQUITY
EXERCISE OF EXERCISE PRICE OF COMPENSATION PLANS
OUTSTANDING OPTIONS OUTSTANDING (EXCLUDING SECURITIES
WARRANTS AND OPTIONS, WARRANTS REFLECTED IN
RIGHTS AND RIGHTS COLUMN (a))
PLAN CATEGORY (a) (b) (c)
------------- ------------------- ------------------- ---------------------
Equity compensation plans approved by security
holders(1)................................... 8,779,217 $33.5767 6,901,693(2)
Equity compensation plans not approved by
security holders............................. 0 N/A 0
Total........................................ 8,779,217 $33.5767 6,901,693
|
(1) Consists of shares to be issued upon exercise of outstanding options granted under the American Electric Power System 2000 Long-Term Incentive Plan, the CSW 1992 Long-Term Incentive Plan (CSW Plan) and the AEP Deferred Compensation and Stock Plan for Non-Employee Directors. The CSW Plan was in effect prior to the consummation of the AEP-CSW merger. All unexercised options granted under the CSW Plan were converted into 0.6 options to purchase AEP common shares, vested on the merger date and will expire ten years after their grant date. No additional options will be issued under the CSW Plan.
(2) Excludes shares available for further issuance under the AEP Deferred Compensation and Stock Plan for Non-Employee Directors, which does not have a limit on the number of shares which may be issued. The amount of shares is capped, however, by the annual retainer amount paid to the Non-Employee Directors.
AEP, AEGCO, APCO, CSPCO, I&M, KPCO, OPCO, PSO, SWEPCO, TCC AND TNC: None.
AEP maintains disclosure controls and procedures designed to ensure that the information AEP must disclose in its filings with the Securities and Exchange Commission is recorded, processed, summarized and reported on a timely basis. AEP's principal executive officer and principal financial officer have reviewed and evaluated AEP's disclosure controls and procedures as defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934, as amended (the Exchange Act) as of a date within 90 days prior to the filing date of this report (the Evaluation Date). Such officers have concluded that, as of the Evaluation Date, AEP's disclosure controls and procedures are effective in accumulating and communicating to management on a timely basis information required to be disclosed in AEP's periodic filings under the Exchange Act.
Since the Evaluation Date, there have not been any significant changes in AEP's internal controls, or in other factors that could significantly affect these controls.
(a) The following documents are filed as a part of this report:
1. FINANCIAL STATEMENTS:
The following financial statements have been incorporated herein by reference pursuant to Item 8.
PAGE
----
AEGCo:
Statements of Income for the years ended December 31, 2002, 2001,
and 2000; Statements of Retained Earnings for the years ended
December 31, 2002, 2001, and 2000; Balance Sheets as of December
31, 2002 and 2001; Statements of Cash Flows for the years ended
December 31, 2002, 2001, and 2000; Statements of Capitalization as
of December 31, 2002 and 2001; Combined Notes to Financial
Statements; Independent Auditors' Report.
AEP and Subsidiary Companies:
Consolidated Statements of Operations for the years ended
December 31, 2002, 2001, and 2000; Consolidated Balance Sheets
as of December 31, 2002 and 2001; Consolidated Statements of
Cash Flows for the years ended December 31, 2002, 2001, and
2000; Consolidated Statements of Common Shareholders' Equity and
Comprehensive Income for the years ended December 31, 2002,
2001, and 2000; Schedule of Consolidated Cumulative Preferred
Stocks of Subsidiaries at December 31, 2002 and 2001; Schedule
of Consolidated Long-term Debt of Subsidiaries at December 31,
2002 and 2001; Combined Notes to Consolidated Financial
Statements; Independent Auditors' Report.
APCo, CSPCo, I&M, PSO, SWEPCo and TCC:
Consolidated Statements of Income for the years ended December
31, 2002, 2001, and 2000; Consolidated Statements of
Comprehensive Income for the years ended December 31, 2002,
2001, and 2000; Consolidated Statements of Retained Earnings for
the years ended December 31, 2002, 2001, and 2000; Consolidated
Balance Sheets as of December 31, 2002 and 2001; Consolidated
Statements of Cash Flows for the years ended December 31, 2002,
2001, and 2000; Consolidated Statements of Capitalization as of
December 31, 2002 and 2001; Schedule of Long-term Debt as of
December 31, 2002 and 2001; Combined Notes to Consolidated
Financial Statements; Independent Auditors' Report.
|
KPCo, OPCo and TNC:
Statements of Income (or Statements of Operations) for the years
ended December 31, 2002, 2001, and 2000; Statements of
Comprehensive Income for the years ended December 31, 2002, 2001,
and 2000; Statements of Retained Earnings for the years ended
December 31, 2002, 2001, and 2000; Balance Sheets as of December
31, 2002 and 2001; Statements of Cash Flows for the years ended
December 31, 2002, 2001, and 2000; Statements of Capitalization as
of December 31, 2002 and 2001; Schedule of Long-term Debt as of
December 31, 2002 and 2001; Combined Notes to Financial
Statements; Independent Auditors' Report.
2. FINANCIAL STATEMENT SCHEDULES:
Financial Statement Schedules are listed in the Index to S-1
Financial Statement Schedules (Certain schedules have been
omitted because the required information is contained in the
notes to financial statements or because such schedules are not
required or are not applicable). Independent Auditors' Report
3. EXHIBITS:
Exhibits for AEGCo, AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, E-1
SWEPCo, TCC and TNC are listed in the Exhibit Index and are
incorporated herein by reference
(b) Reports on Forms 8-K:
COMPANY REPORTING DATE OF REPORT ITEM REPORTED
----------------- ----------------- ----------------------------------------------
APCo, CSPCo, I&M, KPCo, OPCo, PSO,
SWEPCo, TCC and TNC.................. November 18, 2002 Item 5. Other Events
I&M.................................. November 22, 2002 Item 5. Other Events
Item 7. Financial Statements and Exhibits
I&M.................................. November 25, 2002 Item 5. Other Events
Item 7. Financial Statements and Exhibits
PSO.................................. November 26, 2002 Item 5. Other Events
Item 7. Financial Statements and Exhibits
|
Reports on Forms 8-K/A:
COMPANY REPORTING DATE OF REPORT ITEM REPORTED ----------------- ----------------- ---------------------------------------------- PSO, SWEPCo, TCC and TNC............. November 26, 2002 Item 7. Financial Statements and Exhibits |
(c) Exhibits: See Exhibit Index beginning on page E-1.
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
AMERICAN ELECTRIC POWER COMPANY, INC.
By:
/s/ SUSAN TOMASKY
-------------------------------------
(SUSAN TOMASKY, VICE PRESIDENT,
SECRETARY AND CHIEF FINANCIAL
OFFICER)
Date: March 20, 2003
|
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
SIGNATURE TITLE DATE
--------- ----- ----
(I) PRINCIPAL EXECUTIVE OFFICER:
*E. LINN DRAPER, JR. Chairman of the Board, March 20, 2003
President,
Chief Executive Officer
And Director
(II) PRINCIPAL FINANCIAL OFFICER:
/s/ SUSAN TOMASKY Vice President, Secretary and March 20, 2003
------------------------------------------------ Chief Financial Officer
(SUSAN TOMASKY)
(III) PRINCIPAL ACCOUNTING OFFICER:
/s/ JOSEPH M. BUONAIUTO Controller and March 20, 2003
------------------------------------------------ Chief Accounting Officer
(JOSEPH M. BUONAIUTO)
(IV) A MAJORITY OF THE DIRECTORS:
*E. R. BROOKS
*DONALD M. CARLTON
*JOHN P. DESBARRES
*ROBERT W. FRI
*WILLIAM R. HOWELL
*LESTER A. HUDSON, JR.
*LEONARD J. KUJAWA
*RICHARD L. SANDOR
*THOMAS V. SHOCKLEY, III
*DONALD G. SMITH
*LINDA GILLESPIE STUNTZ
*KATHRYN D. SULLIVAN March 20, 2003
*By: /s/ SUSAN TOMASKY
------------------------------------------
(SUSAN TOMASKY, ATTORNEY-IN-FACT)
|
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.
AEP GENERATING COMPANY
AEP TEXAS CENTRAL COMPANY
AEP TEXAS NORTH COMPANY
APPALACHIAN POWER COMPANY
COLUMBUS SOUTHERN POWER COMPANY
KENTUCKY POWER COMPANY
OHIO POWER COMPANY
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY
By:
/s/ SUSAN TOMASKY
-------------------------------------
(SUSAN TOMASKY, VICE PRESIDENT)
Date: March 20, 2003
|
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
SIGNATURE TITLE DATE
--------- ----- ----
(i) PRINCIPAL EXECUTIVE OFFICER:
*E. LINN DRAPER, JR. Chairman of the Board, March 20, 2003
President,
Chief Executive Officer
And Director
(ii) PRINCIPAL FINANCIAL OFFICER:
/s/ SUSAN TOMASKY Vice President, Secretary, March 20, 2003
------------------------------------------------ Chief Financial Officer and Director
(SUSAN TOMASKY)
(iii) PRINCIPAL ACCOUNTING OFFICER:
/s/ JOSEPH M. BUONAIUTO Controller and March 20, 2003
------------------------------------------------ Chief Accounting Officer
(JOSEPH M. BUONAIUTO)
(iv) A MAJORITY OF THE DIRECTORS:
*HENRY W. FAYNE
*THOMAS M. HAGAN
*A. A. PENA
*ROBERT P. POWERS
*THOMAS V. SHOCKLEY, III March 20, 2003
*By: /s/ SUSAN TOMASKY
------------------------------------------
(SUSAN TOMASKY, ATTORNEY-IN-FACT)
|
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.
INDIANA MICHIGAN POWER COMPANY
By:
/s/ SUSAN TOMASKY
-------------------------------------
(SUSAN TOMASKY, VICE PRESIDENT)
Date: March 20, 2003
|
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
SIGNATURE TITLE DATE
--------- ----- ----
(i) PRINCIPAL EXECUTIVE OFFICER:
*E. LINN DRAPER, JR. Chairman of the Board, March 20, 2003
President,
Chief Executive Officer
and Director
(ii) PRINCIPAL FINANCIAL OFFICER:
/s/ SUSAN TOMASKY Vice President, Secretary, March 20, 2003
------------------------------------------------ Chief Financial Officer
(SUSAN TOMASKY) and Director
(iii) PRINCIPAL ACCOUNTING OFFICER:
/s/ JOSEPH M. BUONAIUTO Controller and March 20, 2003
------------------------------------------------ Chief Accounting Officer
(JOSEPH M. BUONAIUTO)
(iv) A MAJORITY OF THE DIRECTORS:
*K. G. BOYD
*JOHN E. EHLER
*HENRY W. FAYNE
*THOMAS M. HAGAN
*DAVID L. LAHRMAN
*MARC E. LEWIS
*SUSANNE M. MOORMAN
*ROBERT P. POWERS
*JOHN R. SAMPSON
*THOMAS V. SHOCKLEY, III
*D. B. SYNOWIEC March 20, 2003
*By: /s/ SUSAN TOMASKY
------------------------------------------
(SUSAN TOMASKY, ATTORNEY-IN-FACT)
|
CERTIFICATIONS
I, E. Linn Draper, Jr., certify that:
1. I have reviewed this annual report on Form 10-K of:
American Electric Power Company, Inc. AEP Generating Company AEP Texas Central Company AEP Texas North Company Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Dated: March 20, 2003 By:
/s/ E. LINN DRAPER, JR.
--------------------------------------
E. Linn Draper, Jr.
Chief Executive Officer
|
I, Susan Tomasky, certify that:
1. I have reviewed this annual report on Form 10-K of:
American Electric Power Company, Inc. AEP Generating Company AEP Texas Central Company AEP Texas North Company Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a. designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b. evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c. presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
a. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Dated: March 20, 2003 By:
/s/ SUSAN TOMASKY
--------------------------------------
Susan Tomasky
Chief Financial Officer
|
INDEX TO FINANCIAL STATEMENT SCHEDULES
PAGE
----
INDEPENDENT AUDITORS' REPORT................................ S-2
The following financial statement schedules are included in
this report on the pages indicated
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY
COMPANIES
Schedule II -- Valuation and Qualifying Accounts and
Reserves.............................................. S-3
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Schedule II -- Valuation and Qualifying Accounts and
Reserves.............................................. S-3
AEP TEXAS NORTH COMPANY
Schedule II -- Valuation and Qualifying Accounts and
Reserves.............................................. S-3
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Schedule II -- Valuation and Qualifying Accounts and
Reserves.............................................. S-4
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Schedule II -- Valuation and Qualifying Accounts and
Reserves.............................................. S-4
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Schedule II -- Valuation and Qualifying Accounts and
Reserves.............................................. S-4
KENTUCKY POWER COMPANY
Schedule II -- Valuation and Qualifying Accounts and
Reserves.............................................. S-5
OHIO POWER COMPANY
Schedule II -- Valuation and Qualifying Accounts and
Reserves.............................................. S-5
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Schedule II -- Valuation and Qualifying Accounts and
Reserves.............................................. S-5
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Schedule II -- Valuation and Qualifying Accounts and
Reserves.............................................. S-6
|
INDEPENDENT AUDITORS' REPORT
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARIES:
We have audited the consolidated financial statements of American Electric Power Company, Inc. and subsidiaries and the financial statements of certain of its subsidiaries, listed in Item 15 herein, as of December 31, 2002 and 2001, and for each of the three years in the period ended December 31, 2002, and have issued our reports thereon dated February 21, 2003; such financial statements and reports are included in the 2002 Annual Reports and are incorporated herein by reference. Our audits also included the financial statement schedules of American Electric Power Company, Inc. and subsidiaries and of certain of its subsidiaries, listed in Item 15. These financial statement schedules are the responsibility of the respective company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the corresponding basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.
Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
-------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
-------------------------------------------------------------------------------------------------------------------
ADDITIONS
-------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS(a) DEDUCTIONS(b) PERIOD
-------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2002........... $69,416 $ 97,772 $11,766 $59,723 $119,231
======= ======== ======= ======= ========
Year Ended December 31, 2001(c)........ $31,905 $109,635 $20,763 $92,887 $ 69,416
======= ======== ======= ======= ========
Year Ended December 31, 2000(c)........ $27,091 $ 51,457 $11,729 $58,372 $ 31,905
======= ======== ======= ======= ========
|
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
(c) 2001 and 2000 amounts have been adjusted to reflect the treatment of SEEBOARD and CitiPower as discontinued operations in AEP's Consolidated Statements of Operations.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
-------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
-------------------------------------------------------------------------------------------------------------------
ADDITIONS
-------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS(a) DEDUCTIONS(b) PERIOD
-------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2002........... $ 186 $ 162 $ 1 $ 3 $ 346
====== ====== ====== ====== ======
Year Ended December 31, 2001........... $1,675 $ 186 $ -- $1,675 $ 186
====== ====== ====== ====== ======
Year Ended December 31, 2000........... $ -- $1,675 $ -- $ -- $1,675
====== ====== ====== ====== ======
|
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
AEP TEXAS NORTH COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
-------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
-------------------------------------------------------------------------------------------------------------------
ADDITIONS
-------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS(a) DEDUCTIONS(b) PERIOD
-------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2002........... $ 196 $4,846 $ 17 $ 18 $5,041
====== ====== ====== ====== ======
Year Ended December 31, 2001........... $ 288 $ 13 $ 35 $ 140 $ 196
====== ====== ====== ====== ======
Year Ended December 31, 2000........... $ 186 $1,499 $ 46 $1,443 $ 288
====== ====== ====== ====== ======
|
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
-------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
-------------------------------------------------------------------------------------------------------------------
ADDITIONS
-------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS(a) DEDUCTIONS(b) PERIOD
-------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2002........... $1,877 $3,937 $12,367 $4,742 $13,439
====== ====== ======= ====== =======
Year Ended December 31, 2001........... $2,588 $2,644 $ 1,017 $4,372 $ 1,877
====== ====== ======= ====== =======
Year Ended December 31, 2000........... $2,609 $6,592 $ 1,526 $8,139 $ 2,588
====== ====== ======= ====== =======
|
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
-------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
-------------------------------------------------------------------------------------------------------------------
ADDITIONS
-------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS(a) DEDUCTIONS(b) PERIOD
-------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2002........... $ 745 $ (100) $ -- $ 11 $ 634
====== ====== ====== ====== ======
Year Ended December 31, 2001........... $ 659 $ 331 $ -- $ 245 $ 745
====== ====== ====== ====== ======
Year Ended December 31, 2000........... $3,045 $2,082 $1,405 $5,873 $ 659
====== ====== ====== ====== ======
|
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
-------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
-------------------------------------------------------------------------------------------------------------------
ADDITIONS
-------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS(a) DEDUCTIONS(b) PERIOD
-------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2002........... $ 741 $ (161) $ -- $ 2 $ 578
====== ====== ====== ====== ======
Year Ended December 31, 2001........... $ 759 $ 65 $ 3 $ 86 $ 741
====== ====== ====== ====== ======
Year Ended December 31, 2000........... $1,848 $ (235) $ 907 $1,761 $ 759
====== ====== ====== ====== ======
|
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
KENTUCKY POWER COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
-------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
-------------------------------------------------------------------------------------------------------------------
ADDITIONS
-------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS(a) DEDUCTIONS(b) PERIOD
-------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2002........... $ 264 $ (68) $ -- $ 4 $ 192
====== ====== ====== ====== ======
Year Ended December 31, 2001........... $ 282 $ -- $ (24) $ (6) $ 264
====== ====== ====== ====== ======
Year Ended December 31, 2000........... $ 637 $ 187 $ 9 $ 551 $ 282
====== ====== ====== ====== ======
|
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
OHIO POWER COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
-------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
-------------------------------------------------------------------------------------------------------------------
ADDITIONS
-------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS(a) DEDUCTIONS(b) PERIOD
-------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2002........... $1,379 $ (457) $ -- $ 13 $ 909
====== ====== ====== ====== ======
Year Ended December 31, 2001........... $1,054 $ 554 $ -- $ 229 $1,379
====== ====== ====== ====== ======
Year Ended December 31, 2000........... $2,223 $ 472 $ 778 $2,419 $1,054
====== ====== ====== ====== ======
|
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
-------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
-------------------------------------------------------------------------------------------------------------------
ADDITIONS
-------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS(a) DEDUCTIONS(b) PERIOD
-------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2002........... $ 44 $ 7 $ 33 $ -- $ 84
====== ====== ====== ====== ======
Year Ended December 31, 2001........... $ 467 $ 44 $ -- $ 467 $ 44
====== ====== ====== ====== ======
Year Ended December 31, 2000........... $ -- $ 467 $ -- $ -- $ 467
====== ====== ====== ====== ======
|
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
-------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
-------------------------------------------------------------------------------------------------------------------
ADDITIONS
-------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS(A) DEDUCTIONS(B) PERIOD
-------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS)
DEDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 2002........... $ 89 $2,036 $ 4 $ 1 $2,128
====== ====== ======= ====== ======
Year Ended December 31, 2001........... $ 911 $ 89 $ -- $ 911 $ 89
====== ====== ======= ====== ======
Year Ended December 31, 2000........... $4,428 $ 911 $(4,428) $ -- $ 911
====== ====== ======= ====== ======
|
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
EXHIBIT INDEX
Certain of the following exhibits, designated with an asterisk (*), are filed herewith. The exhibits not so designated have heretofore been filed with the Commission and, pursuant to 17 C.F.R. 229.10(d) and 240.12b-32, are incorporated herein by reference to the documents indicated in brackets following the descriptions of such exhibits. Exhibits, designated with a dagger (+), are management contracts or compensatory plans or arrangements required to be filed as an Exhibit to this Form pursuant to Item 14(c) of this report.
EXHIBIT NUMBER DESCRIPTION
--------------- -----------
AEGCO
3(a) -- Copy of Articles of Incorporation of AEGCo [Registration
Statement on Form 10 for the Common Shares of AEGCo, File
No. 0-18135, Exhibit 3(a)].
3(b) -- Copy of the Code of Regulations of AEGCo (amended as of June
15, 2000) [Annual Report on Form 10-K of AEGCo for the
fiscal year ended December 31, 2000, File No. 0-18135,
Exhibit 3(b)].
10(a) -- Copy of Capital Funds Agreement dated as of December 30,
1988 between AEGCo and AEP [Registration Statement No.
33-32752, Exhibit 28(a)].
10(b)(1) -- Copy of Unit Power Agreement dated as of March 31, 1982
between AEGCo and I&M, as amended [Registration Statement
No. 33-32752, Exhibits 28(b)(1)(A) and 28(b)(1)(B)].
10(b)(2) -- Copy of Unit Power Agreement, dated as of August 1, 1984,
among AEGCo, I&M and KPCo [Registration Statement No.
33-32752, Exhibit 28(b)(2)].
10(c) -- Copy of Lease Agreements, dated as of December 1, 1989,
between AEGCo and Wilmington Trust Company, as amended
[Registration Statement No. 33-32752, Exhibits 28(c)(1)(C),
28(c)(2)(C), 28(c)(3)(C), 28(c)(4)(C), 28(c)(5)(C) and
28(c)(6)(C); Annual Report on Form 10-K of AEGCo for the
fiscal year ended December 31, 1993, File No. 0-18135,
Exhibits 10(c)(1)(B), 10(c)(2)(B), 10(c)(3)(B), 10(c)(4)(B),
10(c)(5)(B) and 10(c)(6)(B)].
*13 -- Copy of those portions of the AEGCo 2002 Annual Report (for
the fiscal year ended December 31, 2002) which are
incorporated by reference in this filing.
*24 -- Power of Attorney.
*99(a) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
*99(b) -- Certification of Chief Financial Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
AEP++
3(a) -- Copy of Restated Certificate of Incorporation of AEP, dated
October 29, 1997 [Quarterly Report on Form 10-Q of AEP for
the quarter ended September 30, 1997, File No. 1-3525,
Exhibit 3(a)].
3(b) -- Copy of Certificate of Amendment of the Restated Certificate
of Incorporation of AEP, dated January 13, 1999 [Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 1998, File No. 1-3525, Exhibit 3(b)].
3(c) -- Composite copy of the Restated Certificate of Incorporation
of AEP, as amended [Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1998, File No. 1-3525,
Exhibit 3(c)].
3(d) -- Copy of By-Laws of AEP, as amended through January 28, 1998
[Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1997, File No. 1-3525, Exhibit 3(b)].
4(a) -- Indenture (for unsecured debt securities), dated as of May
1, 2001, between AEP and The Bank of New York, as Trustee
[Registration Statement No. 333-86050, Exhibits 4(a), 4(b)
and 4(c)].
*4(b) -- Third Supplemental Indenture, dated as of June 11, 2002,
between AEP and The Bank of New York, as Trustee, for 5.75%
Senior Notes, Series C, due August 16, 2007.
|
EXHIBIT NUMBER DESCRIPTION
--------------- -----------
*4(c) -- Forward Purchase Contract Agreement, dated as of June 11,
2002, between AEP and The Bank of New York, as Forward
Purchase Contract Agent.
10(a) -- Interconnection Agreement, dated July 6, 1951, among APCo,
CSPCo, KPCo, OPCo and I&M and with the Service Corporation,
as amended [Registration Statement No. 2-52910, Exhibit
5(a); Registration Statement No. 2-61009, Exhibit 5(b); and
Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)].
*10(b) -- Restated and Amended Operating Agreement, dated as of
January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC.
10(c) -- Transmission Agreement, dated April 1, 1984, among APCo,
CSPCo, I&M, KPCo, OPCo and with the Service Corporation as
agent, as amended [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1985, File No. 1-3525,
Exhibit 10(b); and Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1988, File No. 1-3525,
Exhibit 10(b)(2)].
*10(d) -- Transmission Coordination Agreement, dated October 29, 1998,
among PSO, TCC, TNC, SWEPCo and AEPSC.
10(e) -- Lease Agreements, dated as of December 1, 1989, between
AEGCo or I&M and Wilmington Trust Company, as amended
[Registration Statement No. 33-32752, Exhibits 28(c)(1)(C),
28(c)(2)(C), 28(c)(3)(C), 28(c)(4)(C), 28(c)(5)(C) and
28(c)(6)(C); Registration Statement No. 33-32753, Exhibits
28(a)(1)(C), 28(a)(2)(C), 28(a)(3)(C), 28(a)(4)(C),
28(a)(5)(C) and 28(a)(6)(C); and Annual Report on Form 10-K
of AEGCo for the fiscal year ended December 31, 1993, File
No. 0-18135, Exhibits 10(c)(1)(B), 10(c)(2)(B), 10(c)(3)(B),
10(c)(4)(B), 10(c)(5)(B) and 10(c)(6)(B); Annual Report on
Form 10-K of I&M for the fiscal year ended December 31,
1993, File No. 1-3570, Exhibits 10(e)(1)(B), 10(e)(2)(B),
10(e)(3)(B), 10(e)(4)(B), 10(e)(5)(B) and 10(e)(6)(B)].
10(f) -- Lease Agreement dated January 20, 1995 between OPCo and JMG
Funding, Limited Partnership, and amendment thereto
(confidential treatment requested) [Annual Report on Form
10-K of OPCo for the fiscal year ended December 31, 1994,
File No. 1-6543, Exhibit 10(l)(2)].
10(g) -- Modification No. 1 to the AEP System Interim Allowance
Agreement, dated July 28, 1994, among APCo, CSPCo, I&M,
KPCo, OPCo and the Service Corporation [Annual Report on
Form 10-K of AEP for the fiscal year ended December 31,
1996, File No. 1-3525, Exhibit 10(l)].
10(h)(1) -- Agreement and Plan of Merger, dated as of December 21, 1997,
By and Among American Electric Power Company, Inc., Augusta
Acquisition Corporation and Central and South West
Corporation [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1997, File No. 1-3525,
Exhibit 10(f)].
10(h)(2) -- Amendment No. 1, dated as of December 31, 1999, to the
Agreement and Plan of Merger [Current Report on Form 8-K of
AEP dated December 15, 1999, File No. 1-3525, Exhibit 10].
+10(i)(1) -- AEP Deferred Compensation Agreement for certain executive
officers [Annual Report on Form 10-K of AEP for the fiscal
year ended December 31, 1985, File No. 1-3525, Exhibit
10(e)].
+10(i)(2) -- Amendment to AEP Deferred Compensation Agreement for certain
executive officers [Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1986, File No. 1-3525,
Exhibit 10(d)(2)].
+10(j) -- AEP Accident Coverage Insurance Plan for directors [Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 1985, File No. 1-3525, Exhibit 10(g)].
+10(k)(1) -- AEP Deferred Compensation and Stock Plan for Non-Employee
Directors, as amended June 1, 2000 [Annual Report on Form
10-K of AEP for the fiscal year ended December 31, 2000,
File No. 1-3525, Exhibit 10(i)(1)].
|
EXHIBIT NUMBER DESCRIPTION
--------------- -----------
+10(k)(2) -- AEP Stock Unit Accumulation Plan for Non-Employee Directors,
as amended January 1, 2002[Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 2001, File No.
1-3525, Exhibit 10(i)(2)].
+10(l)(1)(A) -- AEP System Excess Benefit Plan, Amended and Restated as of
January 1, 2001 [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 2000, File No. 1-3525,
Exhibit 10(j)(1)(A)].
+10(l)(1)(B) -- Guaranty by AEP of the Service Corporation Excess Benefits
Plan [Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1990, File No. 1-3525, Exhibit
10(h)(1)(B)].
*+10(l)(1)(C) -- First Amendment to AEP System Excess Benefit Plan, dated as
of March 5, 2003.
+10(l)(2) -- AEP System Supplemental Retirement Savings Plan, Amended and
Restated as of June 1, 2001 (Non-Qualified) [Registration
Statement No. 333-66048, Exhibit 4].
+10(l)(3) -- Service Corporation Umbrella Trust for Executives [Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)].
+10(m)(1) -- Employment Agreement between E. Linn Draper, Jr. and AEP and
the Service Corporation [Annual Report on Form 10-K of AEGCo
for the fiscal year ended December 31, 1991, File No.
0-18135, Exhibit 10(g)(3)].
+10(m)(2) -- Memorandum of agreement between Susan Tomasky and the
Service Corporation dated January 3, 2001 [Annual Report on
Form 10-K of AEP for the fiscal year ended December 31,
2000, File No. 1-3525, Exhibit 10(s)].
*+10(m)(3)(A) -- Letter Agreement dated June 23, 2000 between AEPSC and Holly
K. Koeppel.
*+10(m)(3)(B) -- Letter Agreement dated April 19, 2001 between AEPR and Holly
K. Koeppel.
*+10(m)(4) -- Employment Agreement dated July 29, 1998 between AEPSC and
Robert P. Powers.
+10(n) -- AEP System Senior Officer Annual Incentive Compensation Plan
[Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)].
+10(o)(1) -- AEP System Survivor Benefit Plan, effective January 27, 1998
[Quarterly Report on Form 10-Q of AEP for the quarter ended
September 30, 1998, File No. 1-3525, Exhibit 10].
*+10(o)(2) -- First Amendment to AEP System Survivor Benefit Plan, as
amended and restated effective January 31, 2000.
+10(p) -- AEP Senior Executive Severance Plan for Merger with Central
and South West Corporation, effective March 1, 1999 [Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 1998, File No. 1-3525, Exhibit 10(o)].
*+10(q)(1) -- AEP System Incentive Compensation Deferral Plan dated
January 1, 2001.
*+10(q)(2) -- First Amendment to AEP System Incentive Compensation
Deferral Plan dated December 6, 2002.
*+10(r) -- AEP System Nuclear Performance Long Term Incentive
Compensation Plan dated August 1, 1998.
*+10(s) -- Nuclear Key Contributor Retention Plan dated May 1, 2000.
+10(t) -- AEP Change In Control Agreement [Annual Report on Form 10-K
of AEP for the fiscal year ended December 31, 2001, File No.
1-3525, Exhibit 10(o)].
+10(u) -- AEP System 2000 Long-Term Incentive Plan [Proxy Statement of
AEP, March 10, 2000].
+10(v)(1) -- Central and South West System Special Executive Retirement
Plan as amended and restated effective July 1, 1997 [Annual
Report on Form 10-K of CSW for the fiscal year ended
December 31, 1998, File No. 1-1443, Exhibit 18].
+10(v)(2) -- Certified CSW Board Resolution of April 18, 1991 [Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 2001, File No. 1-3525, Exhibit 10(r)(2)].
+10(v)(3) -- CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW,
March 13, 1992].
|
EXHIBIT NUMBER DESCRIPTION
--------------- -----------
+10(v)(4) -- Central and South West Corporation Executive Deferred
Savings Plan as amended and restated effective as of January
1, 1997 [Annual Report on Form 10-K of CSW for the fiscal
year ended December 31, 1998, File No. 1-1443, Exhibit 24].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the AEP 2002 Annual Report (for
the fiscal year ended December 31, 2002) which are
incorporated by reference in this filing.
*21 -- List of subsidiaries of AEP.
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*99(a) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
*99(b) -- Certification of Chief Financial Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
APCO++
3(a) -- Copy of Restated Articles of Incorporation of APCo, and
amendments thereto to November 4, 1993 [Registration
Statement No. 33-50163, Exhibit 4(a); Registration Statement
No. 33-53805, Exhibits 4(b) and 4(c)].
3(b) -- Copy of Articles of Amendment to the Restated Articles of
Incorporation of APCo, dated June 6, 1994 [Annual Report on
Form 10-K of APCo for the fiscal year ended December 31,
1994, File No. 1-3457, Exhibit 3(b)].
3(c) -- Copy of Articles of Amendment to the Restated Articles of
Incorporation of APCo, dated March 6, 1997 [Annual Report on
Form 10-K of APCo for the fiscal year ended December 31,
1996, File No. 1-3457, Exhibit 3(c)].
3(d) -- Composite copy of the Restated Articles of Incorporation of
APCo (amended as of March 7, 1997) [Annual Report on Form
10-K of APCo for the fiscal year ended December 31, 1996,
File No. 1-3457, Exhibit 3(d)].
3(e) -- Copy of By-Laws of APCo (amended as of October 24, 2001)
[Annual Report on Form 10-K of APCo for the fiscal year
ended December 31, 2001, File No. 1-3457, Exhibit 3(e)].
4(a) -- Copy of Mortgage and Deed of Trust, dated as of December 1,
1940, between APCo and Bankers Trust Company and R. Gregory
Page, as Trustees, as amended and supplemented [Registration
Statement No. 2-7289, Exhibit 7(b); Registration Statement
No. 2-19884, Exhibit 2(1); Registration Statement No.
2-24453, Exhibit 2(n); Registration Statement No. 2-60015,
Exhibits 2(b)(2), 2(b)(3), 2(b)(4), 2(b)(5), 2(b)(6),
2(b)(7), 2(b)(8), 2(b)(9), 2(b)(10), 2(b)(12), 2(b)(14),
2(b)(15), 2(b)(16), 2(b)(17), 2(b)(18), 2(b)(19), 2(b)(20),
2(b)(21), 2(b)(22), 2(b)(23), 2(b)(24), 2(b)(25), 2(b)(26),
2(b)(27) and 2(b)(28); Registration Statement No. 2-64102,
Exhibit 2(b)(29); Registration Statement No. 2-66457,
Exhibits (2)(b)(30) and 2(b)(31); Registration Statement No.
2-69217, Exhibit 2(b)(32); Registration Statement No.
2-86237, Exhibit 4(b); Registration Statement No. 33-11723,
Exhibit 4(b); Registration Statement No. 33-17003, Exhibit
4(a)(ii), Registration Statement No. 33-30964, Exhibit 4(b);
Registration Statement No. 33-40720, Exhibit 4(b);
Registration Statement No. 33-45219, Exhibit 4(b);
Registration Statement No. 33-46128, Exhibits 4(b) and 4(c);
Registration Statement No. 33-53410, Exhibit 4(b);
Registration Statement No. 33-59834, Exhibit 4(b);
Registration Statement No. 33-50229, Exhibits 4(b) and 4(c);
Registration Statement No. 33-58431, Exhibits 4(b), 4(c),
4(d) and 4(e); Registration Statement No. 333-01049,
Exhibits 4(b) and 4(c); Registration Statement No.
333-20305, Exhibits 4(b) and 4(c); Annual Report on Form
10-K of APCo for the fiscal year ended December 31, 1996,
File No. 1-3457, Exhibit 4(b); Annual Report on Form 10-K of
APCo for the fiscal year ended December 31, 1998, File No.
1-3457, Exhibit 4(b)].
|
EXHIBIT NUMBER DESCRIPTION
--------------- -----------
4(b) -- Indenture (for unsecured debt securities), dated as of
January 1, 1998, between APCo and The Bank of New York, As
Trustee [Registration Statement No. 333-45927, Exhibit 4(a);
Registration Statement No. 333-49071, Exhibit 4(b);
Registration Statement No. 333-84061, Exhibits 4(b) and
4(c); Annual Report on Form 10-K of APCo for the fiscal year
ended December 31, 1999, File No. 1-3457, Exhibit 4(c);
Registration Statement No. 333-81402, Exhibits 4(b), 4(c)
and 4(d); Registration Statement No. 333-100451, Exhibit
4(b)].
*4(c) -- Copy of Company Order and Officer's Certificate, dated
November 6, 2002, establishing terms of 4.3148% Senior
Notes, Series F, due 2007.
10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between
OVEC and United States of America, acting by and through the
United States Atomic Energy Commission, and, subsequent to
January 18, 1975, the Administrator of the Energy Research
and Development Administration, as amended [Registration
Statement No. 2-60015, Exhibit 5(a); Registration Statement
No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No
2-66301, Exhibit 5(a)(1)(C); Registration Statement No.
2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of
APCo for the fiscal year ended December 31, 1989, File No.
1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form 10-K
of APCo for the fiscal year ended December 31, 1992, File
No. 1-3457, Exhibit 10(a)(1)(B)].
10(a)(2) -- Copy of Inter-Company Power Agreement, dated as of July 10,
1953, among OVEC and the Sponsoring Companies, as amended
[Registration Statement No. 2-60015, Exhibit 5(c);
Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); and
Annual Report on Form 10-K of APCo for the fiscal year ended
December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)].
10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC
and Indiana-Kentucky Electric Corporation, as amended
[Registration Statement No. 2-60015, Exhibit 5(e)].
10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among
APCo, CSPCo, KPCo, OPCo and I&M and with the Service
Corporation, as amended [Registration Statement No. 2-52910,
Exhibit 5(a); Registration Statement No. 2-61009, Exhibit
5(b); Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)].
10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among
APCo, CSPCo, I&M, KPCo, OPCo and with the Service
Corporation as agent, as amended [Annual Report on Form 10-K
of AEP for the fiscal year ended December 31, 1985, File No.
1-3525, Exhibit 10(b); Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1988, File No. 1-3525,
Exhibit 10(b)(2)].
10(d) -- Copy of Modification No. 1 to the AEP System Interim
Allowance Agreement, dated July 28, 1994, among APCo, CSPCo,
I&M, KPCo, OPCo and the Service Corporation [Annual Report
on Form 10-K of AEP for the fiscal year ended December 31,
1996, File No. 1-3525, Exhibit 10(l)].
10(e)(1) -- Agreement and Plan of Merger, dated as of December 21, 1997,
By and Among American Electric Power Company, Inc., Augusta
Acquisition Corporation and Central and South West
Corporation [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1997, File No. 1-3525,
Exhibit 10(f)].
10(e)(2) -- Amendment No. 1, dated as of December 31, 1999, to the
Agreement and Plan of Merger [Current Report on Form 8-K of
APCo dated December 15, 1999, File No. 1-3457, Exhibit 10].
+10(f)(1) -- AEP Deferred Compensation Agreement for certain executive
officers [Annual Report on Form 10-K of AEP for the fiscal
year ended December 31, 1985, File No. 1-3525, Exhibit
10(e)].
+10(f)(2) -- Amendment to AEP Deferred Compensation Agreement for certain
executive officers [Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1986, File No. 1-3525,
Exhibit 10(d)(2)].
|
EXHIBIT NUMBER DESCRIPTION
--------------- -----------
+10(g) -- AEP System Senior Officer Annual Incentive Compensation Plan
[Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)].
+10(h)(1)(A) -- AEP System Excess Benefit Plan, Amended and Restated as of
January 1, 2001 [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 2000, File No. 1-3525,
Exhibit 10(j)(1)(A)].
*+10(h)(1)(B) -- First Amendment to AEP System Excess Benefit Plan, dated as
of March 5, 2003.
+10(h)(2) -- AEP System Supplemental Retirement Savings Plan, Amended and
Restated as of January 1, 2001 (Non-Qualified) [Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 2000, File No. 1-3525, Exhibit 10(j)(2)].
+10(h)(3) -- Umbrella Trust for Executives [Annual Report on Form 10-K of
AEP for the fiscal year ended December 31, 1993, File No.
1-3525, Exhibit 10(g)(3)].
+10(i)(1) -- Employment Agreement between E. Linn Draper, Jr. and AEP and
the Service Corporation [Annual Report on Form 10-K of AEGCo
for the fiscal year ended December 31, 1991, File No.
0-18135, Exhibit 10(g)(3)].
+10(i)(2) -- Memorandum of agreement between Susan Tomasky and the
Service Corporation dated January 3, 2001 [Annual Report on
Form 10-K of AEP for the fiscal year ended December 31,
2000, File No. 1-3525, Exhibit 10(s)].
*+10(i)(3) -- Employment Agreement dated July 29, 1998 between AEPSC and
Robert P. Powers.
+10(j)(1) -- AEP System Survivor Benefit Plan, effective January 27, 1998
[Quarterly Report on Form 10-Q of AEP for the quarter ended
September 30, 1998, File No. 1-3525, Exhibit 10].
*+10(j)(2) -- First Amendment to AEP System Survivor Benefit Plan, as
amended and restated effective January 31, 2000.
+10(k) -- AEP Senior Executive Severance Plan for Merger with Central
and South West Corporation, effective March 1, 1999[Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 1998, File No. 1-3525, Exhibit 10(o)].
+10(l) -- AEP Change In Control Agreement [Annual Report on Form 10-K
of AEP for the fiscal year ended December 31, 2001, File No.
1-3525, Exhibit 10(o)].
+10(m) -- AEP System 2000 Long-Term Incentive Plan [Proxy Statement of
AEP, March 10, 2000].
+10(n)(1) -- Central and South West System Special Executive Retirement
Plan as amended and restated effective July 1, 1997 [Annual
Report on Form 10-K of CSW for the fiscal year ended
December 31, 1998, File No. 1-1443, Exhibit 18].
+10(n)(2) -- Certified CSW Board Resolution of April 18, 1991 [Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 2001, File No. 1-3525, Exhibit 10(r)(2)].
+10(n)(3) -- CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW,
March 13, 1992].
*+10(o)(1) -- AEP System Incentive Compensation Deferral Plan dated
January 1, 2001.
*+10(o)(2) -- First Amendment to AEP System Incentive Compensation
Deferral Plan dated December 6, 2002.
*+10(p) -- AEP System Nuclear Performance Long Term Incentive
Compensation Plan dated August 1, 1998.
*+10(q) -- Nuclear Key Contributor Retention Plan dated May 1, 2000.
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the APCo 2002 Annual Report (for
the fiscal year ended December 31, 2002) which are
incorporated by reference in this filing.
21 -- List of subsidiaries of APCo [Annual Report on Form 10-K of
AEP for the fiscal year ended December 31, 2002, File No.
1-3525, Exhibit 21].
*23 -- Consent of Deloitte & Touche LLP
|
EXHIBIT NUMBER DESCRIPTION
--------------- -----------
*24 -- Power of Attorney.
*99(a) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
*99(b) -- Certification of Chief Financial Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
CSPCO++
3(a) -- Copy of Amended Articles of Incorporation of CSPCo, as
amended to March 6, 1992 [Registration Statement No.
33-53377, Exhibit 4(a)].
3(b) -- Copy of Certificate of Amendment to Amended Articles of
Incorporation of CSPCo, dated May 19, 1994 [Annual Report on
Form 10-K of CSPCo for the fiscal year ended December 31,
1994, File No. 1-2680, Exhibit 3(b)].
3(c) -- Composite copy of Amended Articles of Incorporation of
CSPCo, as amended [Annual Report on Form 10-K of CSPCo for
the fiscal year ended December 31, 1994, File No. 1-2680,
Exhibit 3(c)].
3(d) -- Copy of Code of Regulations and By-Laws of CSPCo [Annual
Report on Form 10-K of CSPCo for the fiscal year ended
December 31, 1987, File No. 1-2680, Exhibit 3(d)].
4(a) -- Copy of Indenture of Mortgage and Deed of Trust, dated
September 1, 1940, between CSPCo and City Bank Farmers Trust
Company (now Citibank, N.A.), as trustee, as supplemented
and amended [Registration Statement No. 2-59411, Exhibits
2(B) and 2(C); Registration Statement No. 2-80535, Exhibit
4(b); Registration Statement No. 2-87091, Exhibit 4(b);
Registration Statement No. 2-93208, Exhibit 4(b);
Registration Statement No. 2-97652, Exhibit 4(b);
Registration Statement No. 33-7081, Exhibit 4(b);
Registration Statement No. 33-12389, Exhibit 4(b);
Registration Statement No. 33-19227, Exhibits 4(b), 4(e),
4(f), 4(g) and 4(h); Registration Statement No. 33-35651,
Exhibit 4(b); Registration Statement No. 33-46859, Exhibits
4(b) and 4(c); Registration Statement No. 33-50316, Exhibits
4(b) and 4(c); Registration Statement No. 33-60336, Exhibits
4(b), 4(c) and 4(d); Registration Statement No. 33-50447,
Exhibits 4(b) and 4(c); Annual Report on Form 10-K of CSPCo
for the fiscal year ended December 31, 1993, File No.
1-2680, Exhibit 4(b)].
4(b) -- Copy of Indenture (for unsecured debt securities), dated as
of September 1, 1997, between CSPCo and Bankers Trust
Company, as Trustee [Registration Statement No. 333-54025,
Exhibits 4(a), 4(b), 4(c) and 4(d); Annual Report on Form
10-K of CSPCo for the fiscal year ended December 31, 1998,
File No. 1-2680, Exhibits 4(c) and 4(d)].
10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between
OVEC and United States of America, acting by and through the
United States Atomic Energy Commission, and, subsequent to
January 18, 1975, the Administrator of the Energy Research
and Development Administration, as amended [Registration
Statement No. 2-60015, Exhibit 5(a); Registration Statement
No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No.
2-66301, Exhibit 5(a)(1)(C); Registration Statement No.
2-67728, Exhibit 5(a)(1)(B); Annual Report on Form 10-K of
APCo for the fiscal year ended December 31, 1989, File No.
1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form 10-K
of APCo for the fiscal year ended December 31, 1992, File
No. 1-3457, Exhibit 10(a)(1)(B)].
10(a)(2) -- Copy of Inter-Company Power Agreement, dated July 10, 1953,
among OVEC and the Sponsoring Companies, as amended
[Registration Statement No. 2-60015, Exhibit 5(c);
Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); and
Annual Report on Form 10-K of APCo for the fiscal year ended
December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)].
10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC
and Indiana-Kentucky Electric Corporation, as amended
[Registration Statement No. 2-60015, Exhibit 5(e)].
|
EXHIBIT NUMBER DESCRIPTION
--------------- -----------
10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among
APCo, CSPCo, KPCo, OPCo and I&M and the Service Corporation,
as amended [Registration Statement No. 2-52910, Exhibit
5(a); Registration Statement No. 2-61009, Exhibit 5(b); and
Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)].
10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among
APCo, CSPCo, I&M, KPCo, OPCo, and with the Service
Corporation as agent, as amended [Annual Report on Form 10-K
of AEP for the fiscal year ended December 31, 1985, File No.
1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 1988, File No.
1-3525, Exhibit 10(b)(2)].
10(d) -- Copy of Modification No. 1 to the AEP System Interim
Allowance Agreement, dated July 28, 1994, among APCo, CSPCo,
I&M, KPCo, OPCo and the Service Corporation [Annual Report
on Form 10-K of AEP for the fiscal year ended December 31,
1996, File No. 1-3525, Exhibit 10(l)].
10(e)(1) -- Agreement and Plan of Merger, dated as of December 21, 1997,
By and Among American Electric Power Company, Inc., Augusta
Acquisition Corporation and Central and South West
Corporation [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1997, File No. 1-3525,
Exhibit 10(f)].
10(e)(2) -- Amendment No. 1, dated as of December 31, 1999, to the
Agreement and Plan of Merger [Current Report on Form 8-K of
CSPCo dated December 15, 1999, File No. 1-2680, Exhibit 10].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the CSPCo 2002 Annual Report (for
the fiscal year ended December 31, 2002) which are
incorporated by reference in this filing.
21 -- List of subsidiaries of CSPCo [Annual Report on Form 10-K of
AEP for the fiscal year ended December 31, 2002, File No.
1-3525, Exhibit 21]
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*99(a) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
*99(b) -- Certification of Chief Financial Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
I&M++
3(a) -- Copy of the Amended Articles of Acceptance of I&M and
amendments thereto [Annual Report on Form 10-K of I&M for
fiscal year ended December 31, 1993, File No. 1-3570,
Exhibit 3(a)].
3(b) -- Copy of Articles of Amendment to the Amended Articles of
Acceptance of I&M, dated March 6, 1997 [Annual Report on
Form 10-K of I&M for fiscal year ended December 31, 1996,
File No. 1-3570, Exhibit 3(b)].
3(c) -- Composite Copy of the Amended Articles of Acceptance of I&M
(amended as of March 7, 1997) [Annual Report on Form 10-K of
I&M for the fiscal year ended December 31, 1996, File No.
1-3570, Exhibit 3(c)].
3(d) -- Copy of the By-Laws of I&M (amended as of November 28, 2001)
[Annual Report on Form 10-K of I&M for the fiscal year ended
December 31, 2001, File No. 1-3570, Exhibit 3(d)].
|
EXHIBIT NUMBER DESCRIPTION
--------------- -----------
4(a) -- Copy of Mortgage and Deed of Trust, dated as of June 1,
1939, between I&M and Irving Trust Company (now The Bank of
New York) and various individuals, as Trustees, as amended
and supplemented [Registration Statement No. 2-7597, Exhibit
7(a); Registration Statement No. 2-60665, Exhibits 2(c)(2),
2(c)(3), 2(c)(4), 2(c)(5), 2(c)(6), 2(c)(7), 2(c)(8),
2(c)(9), 2(c)(10), 2(c)(11), 2(c)(12), 2(c)(13), 2(c)(14),
2(c)(15), (2)(c)(16), and 2(c)(17); Registration Statement
No. 2-63234, Exhibit 2(b)(18); Registration Statement No.
2-65389, Exhibit 2(a)(19); Registration Statement No.
2-67728, Exhibit 2(b)(20); Registration Statement No.
2-85016, Exhibit 4(b); Registration Statement No. 33-5728,
Exhibit 4(c); Registration Statement No. 33-9280, Exhibit
4(b); Registration Statement No. 33-11230, Exhibit 4(b);
Registration Statement No. 33-19620, Exhibits 4(a)(ii),
4(a)(iii), 4(a)(iv) and 4(a)(v); Registration Statement No.
33-46851, Exhibits 4(b)(i), 4(b)(ii) and 4(b)(iii);
Registration Statement No. 33-54480, Exhibits 4(b)(I) and
4(b)(ii); Registration Statement No. 33-60886, Exhibit
4(b)(I); Registration Statement No. 33-50521, Exhibits
4(b)(I), 4(b)(ii) and 4(b)(iii); Annual Report on Form 10-K
of I&M for the fiscal year ended December 31, 1993, File No.
1-3570, Exhibit 4(b); Annual Report on Form 10-K of I&M for
the fiscal year ended December 31, 1994, File No. 1-3570,
Exhibit 4(b); Annual Report on Form 10-K of I&M for the
fiscal year ended December 31, 1996, File No. 1-3570,
Exhibit 4(b)].
4(b) -- Copy of Indenture (for unsecured debt securities), dated as
of October 1, 1998, between I&M and The Bank of New York, as
Trustee [Registration Statement No. 333-88523, Exhibits
4(a), 4(b) and 4(c); Registration Statement No. 333-58656,
Exhibits 4(b) and 4(c); Annual Report of Form 10-K of I&M
for fiscal year ended December 31, 2001, File No. 1-3570,
Exhibit 4(c)].
*4(c) -- Copy of Company Order and Officer's Certificate, dated
November 22, 2002 establishing certain terms of the 6%
Senior Notes, Series D, due 2032.
4(d) -- Copy of Company Order and Officers' Certificate, dated
December 12, 2001, establishing certain terms of the 6.125%
Notes, Series C, due 2006. [Annual Report on Form 10-K of
I&M for the fiscal year ended December 31, 2001, File No.
1-3570, Exhibit 4(c)].
10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between
OVEC and United States of America, acting by and through the
United States Atomic Energy Commission, and, subsequent to
January 18, 1975, the Administrator of the Energy Research
and Development Administration, as amended [Registration
Statement No. 2-60015, Exhibit 5(a); Registration Statement
No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No.
2-66301, Exhibit 5(a)(1)(C); Registration Statement No.
2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of
APCo for the fiscal year ended December 31, 1989, File No.
1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form 10-K
of APCo for the fiscal year ended December 31, 1992, File
No. 1-3457, Exhibit 10(a)(1)(B)].
10(a)(2) -- Copy of Inter-Company Power Agreement, dated as of July 10,
1953, among OVEC and the Sponsoring Companies, as amended
[Registration Statement No. 2-60015, Exhibit 5(c);
Registration Statement No. 2-67728, Exhibit 5(a)(3)(B);
Annual Report on Form 10-K of APCo for the fiscal year ended
December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)].
10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC
and Indiana-Kentucky Electric Corporation, as amended
[Registration Statement No. 2-60015, Exhibit 5(e)].
10(a)(4) -- Copy of Inter-Company Power Agreement, dated as of July 10,
1953, among OVEC and the Sponsoring Companies, as amended
[Registration Statement No. 2-60015, Exhibit 5(c);
Registration Statement No. 2-67728, Exhibit 5(a)(3)(B);
Annual Report on Form 10-K of APCo for the fiscal year ended
December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)].
10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among
APCo, CSPCo, KPCo, I&M, and OPCo and with the Service
Corporation, as amended [Registration Statement No. 2-52910,
Exhibit 5(a); Registration Statement No. 2-61009, Exhibit
5(b); and Annual Report on Form 10-K of AEP for the fiscal
year ended December 31, 1990, File No. 1-3525, Exhibit
10(a)(3)].
|
EXHIBIT NUMBER DESCRIPTION
--------------- -----------
10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among
APCo, CSPCo, I&M, KPCo, OPCo and with the Service
Corporation as agent, as amended [Annual Report on Form 10-K
of AEP for the fiscal year ended December 31, 1985, File No.
1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 1988, File No.
1-3525, Exhibit 10(b)(2)].
10(d) -- Copy of Modification No. 1 to the AEP System Interim
Allowance Agreement, dated July 28, 1994, among APCo, CSPCo,
I&M, KPCo, OPCo and the Service Corporation [Annual Report
on Form 10-K of AEP for the fiscal year ended December 1,
1996, File No. 1-3525, Exhibit 10(l)].
10(e) -- Copy of Nuclear Material Lease Agreement, dated as of
December 1, 1990, between I&M and DCC Fuel Corporation
[Annual Report on Form 10-K of I&M for the fiscal year ended
December 31, 1993, File No. 1-3570, Exhibit 10(d)].
10(f) -- Copy of Lease Agreements, dated as of December 1, 1989,
between I&M and Wilmington Trust Company, as amended
[Registration Statement No. 33-32753, Exhibits 28(a)(1)(C),
28(a)(2)(C), 28(a)(3)(C), 28(a)(4)(C), 28(a)(5)(C) and
28(a)(6)(C); Annual Report on Form 10-K of I&M for the
fiscal year ended December 31, 1993, File No. 1-3570,
Exhibits 10(e)(1)(B), 10(e)(2)(B), 10(e)(3)(B), 10(e)(4)(B),
10(e)(5)(B) and 10(e)(6)(B)].
10(g)(1) -- Agreement and Plan of Merger, dated as of December 21, 1997,
By and Among American Electric Power Company, Inc., Augusta
Acquisition Corporation and Central and South West
Corporation [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1997, File No. 1-3525,
Exhibit 10(f)].
10(g)(2) -- Amendment No. 1, dated as of December 31, 1999, to the
Agreement and Plan of Merger [Current Report on Form 8-K of
I&M dated December 15, 1999, File No. 1-3570, Exhibit 10].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the I&M 2002 Annual Report (for
the fiscal year ended December 31, 2002) which are
incorporated by reference in this filing.
21 -- List of subsidiaries of I&M [Annual Report on Form 10-K of
AEP for the fiscal year ended December 31, 2002, File No.
1-3525, Exhibit 21].
*24 -- Power of Attorney.
*99(a) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
*99(b) -- Certification of Chief Financial Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
KPCO++
3(a) -- Copy of Restated Articles of Incorporation of KPCo [Annual
Report on Form 10-K of KPCo for the fiscal year ended
December 31, 1991, File No. 1-6858, Exhibit 3(a)].
3(b) -- Copy of By-Laws of KPCo (amended as of June 15, 2000)
[Annual Report on Form 10-K of KPCo for the fiscal year
ended December 31, 2000, File No. 1-6858, Exhibit 3(b)].
4(a) -- Copy of Mortgage and Deed of Trust, dated May 1, 1949,
between KPCo and Bankers Trust Company (now Deutsche Bank
Trust Company Americas, as supplemented and amended
[Registration Statement No. 2-65820, Exhibits 2(b)(1),
2(b)(2), 2(b)(3), 2(b)(4), 2(b)(5), and 2(b)(6);
Registration Statement No. 33-39394, Exhibits 4(b) and 4(c);
Registration Statement No. 33-53226, Exhibits 4(b) and 4(c);
Registration Statement No. 33-61808, Exhibits 4(b) and 4(c),
Registration Statement No. 33-53007, Exhibits 4(b), 4(c) and
4(d)].
4(b) -- Copy of Indenture (for unsecured debt securities), dated as
of September 1, 1997, between KPCo and Bankers Trust
Company, as Trustee [Registration Statement No. 333-75785,
Exhibits 4(a), 4(b), 4(c) and 4(d); Registration Statement
No. 333-87216, Exhibits 4E) and 4(f).
*4(c) -- Copy of Company Order and Officer's Certificate, dated June
28, 2002 establishing certain terms of the 5.50% Senior
Notes, Series A, due 2007.
|
EXHIBIT NUMBER DESCRIPTION
--------------- -----------
*4(d) -- Copy of Company Order and Officer's Certificate, dated
November 6, 2002 establishing certain terms of the 4.3148%
Senior Notes, Series B, due 2007.
*4(e) -- Copy of Company Order and Officer's Certificate, dated
December 12, 2002 establishing certain terms of the 4.368%
Senior Notes, Series C, due 2007.
10(a) -- Copy of Interconnection Agreement, dated July 6, 1951, among
APCo, CSPCo, KPCo, I&M and OPCo and with the Service
Corporation, as amended [Registration Statement No. 2-52910,
Exhibit 5(a);Registration Statement No. 2-61009, Exhibit
5(b); and Annual Report on Form 10-K of AEP for the fiscal
year ended December 31, 1990, File No. 1-3525, Exhibit
10(a)(3)].
10(b) -- Copy of Transmission Agreement, dated April 1, 1984, among
APCo, CSPCo, I&M, KPCo, OPCo and with the Service
Corporation as agent, as amended [Annual Report on Form 10-K
of AEP for the fiscal year ended December 31, 1985, File No.
1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 1988, File No.
1-3525, Exhibit 10(b)(2)].
10(c) -- Copy of Modification No. 1 to the AEP System Interim
Allowance Agreement, dated July 28, 1994, among APCo, CSPCo,
I&M, KPCo, OPCo and the Service Corporation [Annual Report
on Form 10-K of AEP for the fiscal year ended December 31,
1996, File No. 1-3525, Exhibit 10(l)].
10(d)(1) -- Agreement and Plan of Merger, dated as of December 21, 1997,
By and Among American Electric Power Company, Inc., Augusta
Acquisition Corporation and Central and South West
Corporation [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1997, File No. 1-3525,
Exhibit 10(f)].
10(d)(2) -- Amendment No. 1, dated as of December 31, 1999, to the
Agreement and Plan of Merger [Current Report on Form 8-K of
KPCo dated December 15, 1999, File No. 1-6858, Exhibit 10].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the KPCo 2002 Annual Report (for
the fiscal year ended December 31, 2002) which are
incorporated by reference in this filing.
*23 -- Consent of Deloitte & Touche LLP
*24 -- Power of Attorney.
*99(a) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
*99(b) -- Certification of Chief Financial Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
OPCO++
3(a) -- Copy of Amended Articles of Incorporation of OPCo, and
amendments thereto to December 31, 1993 [Registration
Statement No. 33-50139, Exhibit 4(a); Annual Report on Form
10-K of OPCo for the fiscal year ended December 31, 1993,
File No. 1-6543, Exhibit 3(b)].
3(b) -- Copy of Certificate of Amendment to Amended Articles of
Incorporation of OPCo, dated May 3, 1994 [Annual Report on
Form 10-K of OPCo for the fiscal year ended December 31,
1994, File No. 1-6543, Exhibit 3(b)].
3(c) -- Copy of Certificate of Amendment to Amended Articles of
Incorporation of OPCo, dated March 6, 1997 [Annual Report on
Form 10-K of OPCo for the fiscal year ended December 31,
1996, File No. 1-6543, Exhibit 3(c)].
3(d) -- Copy of Certificate of Amendment to Amended Articles of
Incorporation of OPCo, dated June 3, 2002 [Quarterly Report
on Form 10-Q of OPCo for the quarter ended June 30, 2002,
File No. 1-6543, Exhibit 3(d)].
3(e) -- Composite copy of the Amended Articles of Incorporation of
OPCo (amended as of June 3, 2002) [[Quarterly Report on Form
10-Q of OPCo for the quarter ended June 30, 2002, File No.
1-6543, Exhibit 3(e)].
|
EXHIBIT NUMBER DESCRIPTION
--------------- -----------
3(f) -- Copy of Code of Regulations of OPCo [Annual Report on Form
10-K of OPCo for the fiscal year ended December 31, 1990,
File No. 1-6543, Exhibit 3(d)].
4(a) -- Copy of Mortgage and Deed of Trust, dated as of October 1,
1938, between OPCo and Manufacturers Hanover Trust Company
(now Chemical Bank), as Trustee, as amended and supplemented
[Registration Statement No. 2-3828, Exhibit B-4;
Registration Statement No. 2-60721, Exhibits 2(c)(2),
2(c)(3), 2(c)(4), 2(c)(5), 2(c)(6), 2(c)(7), 2(c)(8),
2(c)(9), 2(c)(10), 2(c)(11), 2(c)(12), 2(c)(13), 2(c)(14),
2(c)(15), 2(c)(16), 2(c)(17), 2(c)(18), 2(c)(19), 2(c)(20),
2(c)(21), 2(c)(22), 2(c)(23), 2(c)(24), 2(c)(25), 2(c)(26),
2(c)(27), 2(c)(28), 2(c)(29), 2(c)(30), and 2(c)(31);
Registration Statement No. 2-83591, Exhibit 4(b);
Registration Statement No. 33-21208, Exhibits 4(a)(ii),
4(a)(iii) and 4(a)(iv); Registration Statement No. 33-31069,
Exhibit 4(a)(ii); Registration Statement No. 33-44995,
Exhibit 4(a)(ii); Registration Statement No. 33-59006,
Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(iv); Registration
Statement No. 33-50373, Exhibits 4(a)(ii), 4(a)(iii) and
4(a)(iv); Annual Report on Form 10-K of OPCo for the fiscal
year ended December 31, 1993, File No. 1-6543, Exhibit
4(b)].
4(b) -- Copy of Indenture (for unsecured debt securities), dated as
of September 1, 1997, between OPCo and Bankers Trust Company
(now Deutsche Bank Trust Company Americas), as Trustee
[Registration Statement No. 333-49595, Exhibits 4(a), 4(b)
and 4(c); Annual Report on Form 10-K of OPCo for the fiscal
year ended December 31, 1998, File No. 1-6543, Exhibits 4(c)
and 4(d); Annual Report on Form 10-K of OPCo for the fiscal
year ended December 31, 1999, File No. 1-6543, Exhibits 4(c)
and 4(d); Annual Report on Form 10-K of OPCo for the fiscal
year ended December 31, 2000, File No. 1-6543, Exhibit
4(c)].
10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between
OVEC and United States of America, acting by and through the
United States Atomic Energy Commission, and, subsequent to
January 18, 1975, the Administrator of the Energy Research
and Development Administration, as amended [Registration
Statement No. 2-60015, Exhibit 5(a); Registration Statement
No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No.
2-66301, Exhibit 5(a)(1)(C); Registration Statement No.
2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of
APCo for the fiscal year ended December 31, 1989, File No.
1-3457, Exhibit 10(a)(1)(F); Annual Report on Form 10-K of
APCo for the fiscal year ended December 31, 1992, File No.
1-3457, Exhibit 10(a)(1)(B)].
10(a)(2) -- Copy of Inter-Company Power Agreement, dated July 10, 1953,
among OVEC and the Sponsoring Companies, as amended
[Registration Statement No. 2-60015, Exhibit 5(c);
Registration Statement No. 2-67728, Exhibit 5(a)(3)(B);
Annual Report on Form 10-K of APCo for the fiscal year ended
December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)].
10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC
and Indiana-Kentucky Electric Corporation, as amended
[Registration Statement No. 2-60015, Exhibit 5(e)].
10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among
APCo, CSPCo, KPCo, I&M and OPCo and with the Service
Corporation, as amended [Registration Statement No. 2-52910,
Exhibit 5(a); Registration Statement No. 2-61009, Exhibit
5(b); Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1990, File 1-3525, Exhibit 10(a)(3)].
10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among
APCo, CSPCo, I&M, KPCo, OPCo and with the Service
Corporation as agent [Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1985, File No. 1-3525,
Exhibit 10(b); Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1988, File No. 1-3525,
Exhibit 10(b)(2)].
10(d) -- Copy of Modification No. 1 to the AEP System Interim
Allowance Agreement, dated July 28, 1994, among APCo, CSPCo,
I&M, KPCo, OPCo and the Service Corporation [Annual Report
on Form 10-K of AEP for the fiscal year ended December 31,
1996, File No. 1-3525, Exhibit 10(l)].
|
EXHIBIT NUMBER DESCRIPTION
--------------- -----------
10(e) -- Copy of Amendment No. 1, dated October 1, 1973, to Station
Agreement dated January 1, 1968, among OPCo, Buckeye and
Cardinal Operating Company, and amendments thereto [Annual
Report on Form 10-K of OPCo for the fiscal year ended
December 31, 1993, File No. 1-6543, Exhibit 10(f)].
10(f) -- Lease Agreement dated January 20, 1995 between OPCo and JMG
Funding, Limited Partnership, and amendment thereto
(confidential treatment requested) [Annual Report on Form
10-K of OPCo for the fiscal year ended December 31, 1994,
File No. 1-6543, Exhibit 10(l)(2)].
10(g)(1) -- Agreement and Plan of Merger, dated as of December 21, 1997,
by and among American Electric Power Company, Inc., Augusta
Acquisition Corporation and Central and South West
Corporation [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1997, File No. 1-3525,
Exhibit 10(f)].
10(g)(2) -- Amendment No. 1, dated as of December 31, 1999, to the
Agreement and Plan of Merger [Current Report on Form 8-K of
OPCo dated December 15, 1999, File No. 1-6543, Exhibit 10].
+10(h) -- AEP System Senior Officer Annual Incentive Compensation Plan
[Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)].
+10(i)(1)(A) -- AEP System Excess Benefit Plan, Amended and Restated as of
January 1, 2001 [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 2000, File No. 1-3525,
Exhibit 10(j)(1)(A)].
*+10(i)(1)(B) -- First Amendment to AEP System Excess Benefit Plan, dated as
of March 5, 2003.
+10(i)(2) -- AEP System Supplemental Retirement Savings Plan, Amended and
Restated as of January 1, 2001 (Non-Qualified) [Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 2000, File No. 1-3525, Exhibit 10(j)(2)].
+10(i)(3) -- Umbrella Trust for Executives [Annual Report on Form 10-K of
AEP for the fiscal year ended December 31, 1993, File No.
1-3525, Exhibit 10(g)(3)].
+10(j)(1) -- Employment Agreement between E. Linn Draper, Jr. and AEP and
the Service Corporation [Annual Report on Form 10-K of AEGCo
for the fiscal year ended December 31, 1991, File No.
0-18135, Exhibit 10(g)(3)].
+10(j)(2) -- Memorandum of agreement between Susan Tomasky and the
Service Corporation dated January 3, 2001 [Annual Report on
Form 10-K of AEP for the fiscal year ended December 31,
2000, File No. 1-3525, Exhibit 10(s)].
*+10(j)(3) -- Employment Agreement dated July 29, 1998 between AEPSC and
Robert P. Powers.
+10(k)(1) -- AEP System Survivor Benefit Plan, effective January 27, 1998
[Quarterly Report on Form 10-Q of AEP for the quarter ended
September 30, 1998, File No. 1-3525, Exhibit 10].
*+10(k)(2) -- First Amendment to AEP System Survivor Benefit Plan, as
amended and restated effective January 31, 2000.
+10(l) -- AEP Senior Executive Severance Plan for Merger with Central
and South West Corporation, effective March 1, 1999[Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 1998, File No. 1-3525, Exhibit 10(o)].
+10(m) -- AEP Change In Control Agreement [Annual Report on Form 10-K
of AEP for the fiscal year ended December 31, 2001, File No.
1-3525, Exhibit 10(o)].
+10(n) -- AEP System 2000 Long-Term Incentive Plan [Proxy Statement of
AEP, March 10, 2000].
+10(o)(1) -- Central and South West System Special Executive Retirement
Plan as amended and restated effective July 1, 1997 [Annual
Report on Form 10-K of CSW for the fiscal year ended
December 31, 1998, File No. 1-1443, Exhibit 18].
+10(o)(2) -- Certified CSW Board Resolution of April 18, 1991 [Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 2001, File No. 1-3525, Exhibit 10(r)(2)].
+10(o)(3) -- CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW,
March 13, 1992].
*+10(p)(1) -- AEP System Incentive Compensation Deferral Plan dated
January 1, 2001.
|
EXHIBIT NUMBER DESCRIPTION
--------------- -----------
*+10(p)(2) -- First Amendment to AEP System Incentive Compensation
Deferral Plan dated December 6, 2002.
*+10(q) -- AEP System Nuclear Performance Long Term Incentive
Compensation Plan dated August 1, 1998.
*+10(r) -- Nuclear Key Contributor Retention Plan dated May 1, 2000.
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the OPCo 2002 Annual Report (for
the fiscal year ended December 31, 2002) which are
incorporated by reference in this filing.
21 -- List of subsidiaries of OPCo [Annual Report on Form 10-K of
AEP for the fiscal year ended December 31, 2002, File No.
1-3525, Exhibit 21].
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*99(a) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
*99(b) -- Certification of Chief Financial Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
PSO++
3(a) -- Restated Certificate of Incorporation of PSO [Annual Report
on Form U5S of Central and South West Corporation for the
fiscal year ended December 31, 1996, File No. 1-1443,
Exhibit B-3.1].
3(b) -- By-Laws of PSO (amended as of June 28, 2000) [Annual Report
on Form 10-K of PSO for the fiscal year ended December 31,
2000, File No. 0-343, Exhibit 3(b)].
4(a) -- Indenture, dated July 1, 1945, between and Liberty Bank and
Trust Company of Tulsa, National Association, as Trustee, as
amended and supplemented [Registration Statement No.
2-60712, Exhibit 5.03; Registration Statement No. 2-64432,
Exhibit 2.02; Registration Statement No. 2-65871, Exhibit
2.02; Form U-1 No. 70-6822, Exhibit 2; Form U-1 No. 70-7234,
Exhibit 3; Registration Statement No. 33-48650, Exhibit
4(b); Registration Statement No. 33-49143, Exhibit 4(c);
Registration Statement No. 33-49575, Exhibit 4(b); Annual
Report on Form 10-K of PSO for the fiscal year ended
December 31, 1993, File No. 0-343, Exhibit 4(b); Current
Report on Form 8-K of PSO dated March 4, 1996, No. 0-343,
Exhibit 4.01; Current Report on Form 8-K of PSO dated March
4, 1996, No. 0-343, Exhibit 4.02; Current Report on Form 8-K
of PSO dated March 4, 1996, No. 0-343, Exhibit 4.03].
4(b) -- PSO-obligated, mandatorily redeemable preferred securities
of subsidiary trust holding solely Junior Subordinated
Debentures of PSO:
(1) Indenture, dated as of May 1, 1997, between PSO and The
Bank of New York, as Trustee [Quarterly Report on Form 10-Q
of PSO dated March 31, 1997, File No. 0-343, Exhibits
4.6 and 4.7].
(2) Amended and Restated Trust Agreement of PSO Capital I,
dated as of May 1, 1997, among PSO, as Depositor, The Bank
of New York, as Property Trustee, The Bank of New York
(Delaware), as Delaware Trustee, and the Administrative
Trustee [Quarterly Report on Form 10-Q of PSO dated
March 31, 1997, File No. 0-343, Exhibit 4.8].
|
EXHIBIT NUMBER DESCRIPTION
--------------- -----------
(3) Guarantee Agreement, dated as of May 1, 1997, delivered
by PSO for the benefit of the holders of PSO Capital I's
Preferred Securities [Quarterly Report on Form 10-Q of
PSO dated March 31, 1997, File No. 0-343, Exhibits 4.9].
(4) Agreement as to Expenses and Liabilities, dated as of
May 1, 1997, between PSO and PSO Capital I [Quarterly Report
on Form 10-Q of PSO dated March 31, 1997, File No.
0-343, Exhibits 4.10].
4(c) -- Indenture (for unsecured debt securities), dated as of
November 1, 2000, between PSO and The Bank of New York, as
Trustee [Registration Statement No. 333-100623, Exhibits
4(a) and 4(b)].
*4(d) -- Second Supplemental Indenture, dated as of November 26, 2002
establishing certain terms of the 6% Senior Notes, Series B,
due 2032.
*10(a) -- Copy of Restated and Amended Operating Agreement, dated as
of January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC.
*10(b) -- Transmission Coordination Agreement, dated October 29, 1998,
among PSO, TCC, TNC, SWEPCo and AEPSC.
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the PSO 2002 Annual Report (for
the fiscal year ended December 31, 2002) which are
incorporated by reference in this filing.
21 -- List of subsidiaries of PSO [Annual Report on Form 10-K of
AEP for the fiscal year ended December 31, 2002, File No.
1-3525, Exhibit 21]
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*99(a) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
*99(b) -- Certification of Chief Financial Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
SWEPCO++
3(a) -- Restated Certificate of Incorporation, as amended through
May 6, 1997, including Certificate of Amendment of Restated
Certificate of Incorporation [Quarterly Report on Form 10-Q
of SWEPCo for the quarter ended March 31, 1997, File No.
1-3146, Exhibit 3.4].
3(b) -- By-Laws of SWEPCo (amended as of April 27, 2000) [Quarterly
Report on Form 10-Q of SWEPCo for the quarter ended March
31, 2000, File No. 1-3146, Exhibit 3.3].
4(a) -- Indenture, dated February 1, 1940, between SWEPCo and
Continental Bank, National Association and M. J. Kruger, as
Trustees, as amended and supplemented [Registration
Statement No. 2-60712, Exhibit 5.04; Registration Statement
No. 2-61943, Exhibit 2.02; Registration Statement No.
2-66033, Exhibit 2.02; Registration Statement No. 2-71126,
Exhibit 2.02; Registration Statement No. 2-77165, Exhibit
2.02; Form U-1 No. 70-7121, Exhibit 4; Form U-1 No. 70-7233,
Exhibit 3; Form U-1 No. 70-7676, Exhibit 3; Form U-1 No.
70-7934, Exhibit 10; Form U-1 No. 72-8041, Exhibit 10(b);
Form U-1 No. 70-8041, Exhibit 10(c); Form U-1 No. 70-8239,
Exhibit 10(a)].
4(b) -- SWEPCO-obligated, mandatorily redeemable preferred
securities of subsidiary trust holding solely Junior
Subordinated Debentures of SWEPCo:
(1) Indenture, dated as of May 1, 1997, between SWEPCo and
the Bank of New York, as Trustee [Quarterly Report on Form
10-Q of SWEPCo dated March 31, 1997, File No. 1-3146,
Exhibits 4.11 and 4.12].
(2) Amended and Restated Trust Agreement of SWEPCo Capital
I, dated as of May 1, 1997, among SWEPCo, as Depositor, the
Bank of New York, as Property Trustee, The Bank of New
York (Delaware), as Delaware Trustee, and the
Administrative Trustee [Quarterly Report on Form 10-Q of
SWEPCo dated March 31, 1997, File No. 1-3146, Exhibit
4.13].
|
EXHIBIT NUMBER DESCRIPTION
--------------- -----------
(3) Guarantee Agreement, dated as of May 1, 1997, delivered
by SWEPCo for the benefit of the holders of SWEPCo Capital
I's Preferred Securities [Quarterly Report on Form 10-Q
of SWEPCo dated March 31, 1997, File No. 1-3146, Exhibit
4.14].
(4) Agreement as to Expenses and Liabilities, dated as of
May 1, 1997 between SWEPCo and SWEPCo Capital I [Quarterly
Report on Form 10-Q of SWEPCo dated March 31, 1997, File
No. 1-3146, Exhibits 4.15].
4(c) -- Indenture (for unsecured debt securities), dated as of
February 4, 2000, between SWEPCo and The Bank of New York,
as Trustee [Registration Statement No. 333-87834, Exhibits
4(a) and 4(b); Form 8-K of SWEPCo filed on June 26, 2002,
File No. 1-3146, Exhibit 4(b)].
*10(a) -- Copy of Restated and Amended Operating Agreement, dated as
of January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC.
*10(b) -- Transmission Coordination Agreement, dated October 29, 1998,
among PSO, TCC, TNC, SWEPCo and AEPSC.
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the SWEPCo 2002 Annual Report (for
the fiscal year ended December 31, 2002) which are
incorporated by reference in this filing.
21 -- List of subsidiaries of SWEPCo [Annual Report on Form 10-K
of AEP for the fiscal year ended December 31, 2002, File No.
1-3525, Exhibit 21]
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*99(a) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
*99(b) -- Certification of Chief Financial Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
TCC++
3(a) -- Restated Articles of Incorporation Without Amendment,
Articles of Correction to Restated Articles of Incorporation
Without Amendment, Articles of Amendment to Restated
Articles of Incorporation, Statements of Registered Office
and/or Agent, and Articles of Amendment to the Articles of
Incorporation [Quarterly Report on Form 10-Q of TCC for the
quarter ended March 31, 1997, File No. 0-346, Exhibit 3.1].
*3(b) -- Articles of Amendment to Restated Articles of Incorporation
of TCC dated December 18, 2002.
3(c) -- By-Laws of TCC (amended as of April 19, 2000) [Annual Report
on Form 10-K of TCC for the fiscal year ended December 31,
2000, File No. 0-346, Exhibit 3(b)].
4(a) -- Indenture of Mortgage or Deed of Trust, dated November 1,
1943, between TCC and The First National Bank of Chicago and
R. D. Manella, as Trustees, as amended and supplemented
[Registration Statement No. 2-60712, Exhibit 5.01;
Registration Statement No. 2-62271, Exhibit 2.02; Form U-1
No. 70-7003, Exhibit 17; Registration Statement No. 2-98944,
Exhibit 4 (b); Form U-1 No. 70-7236, Exhibit 4; Form U-1 No.
70-7249, Exhibit 4; Form U-1 No. 70-7520, Exhibit 2; Form
U-1 No. 70-7721, Exhibit 3; Form U-1 No. 70-7725, Exhibit
10; Form U-1 No. 70-8053, Exhibit 10 (a); Form U-1 No.
70-8053, Exhibit 10 (b); Form U-1 No. 70-8053, Exhibit 10
(c); Form U-1 No. 70-8053, Exhibit 10 (d); Form U-1 No.
70-8053, Exhibit 10 (e); Form U-1 No. 70-8053, Exhibit 10
(f)].
4(b) -- TCC-obligated, mandatorily redeemable preferred securities
of subsidiary trust holding solely Junior Subordinated
Debentures of TCC:
(1) Indenture, dated as of May 1, 1997, between TCC and the
Bank of New York, as Trustee [Quarterly Report on Form 10-Q
of TCC dated March 31, 1997, File No. 0-346, Exhibits
4.1 and 4.2].
|
EXHIBIT NUMBER DESCRIPTION
--------------- -----------
(2) Amended and Restated Trust Agreement of TCC Capital I,
dated as of May 1, 1997, among TCC, as Depositor, the Bank
of New York, as Property Trustee, The Bank of New York
(Delaware), as Delaware Trustee, and the Administrative
Trustee [Quarterly Report on Form 10-Q of TCC dated
March 31, 1997, File No. 0-346, Exhibit 4.3].
(3) Guarantee Agreement, dated as of May 1, 1997, delivered
by TCC for the benefit of the holders of TCC Capital I's
Preferred Securities [Quarterly Report on Form 10-Q of
TCC dated March 31, 1997, File No. 0-346, Exhibit 4.4].
(4) Agreement as to Expenses and Liabilities dated as of May
1, 1997, between TCC and TCC Capital I [Quarterly Report on
Form 10-Q of TCC dated March 31, 1997, File No. 0-346,
Exhibit 4.5].
4(c) -- Indenture (for unsecured debt securities), dated as of
November 15, 1999, between TCC and The Bank of New York, as
Trustee, as amended and supplemented [Annual Report on Form
10-K of TCC for the fiscal year ended December 31, 2000,
File No. 0-346, Exhibits 4(c), 4(d) and 4(e)].
*10(a) -- Copy of Restated and Amended Operating Agreement, dated as
of January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC.
*10(b) -- Transmission Coordination Agreement, dated October 29, 1998,
among PSO, TCC, TNC, SWEPCo and AEPSC.
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the TCC 2002 Annual Report (for
the fiscal year ended December 31, 2002) which are
incorporated by reference in this filing.
21 -- List of subsidiaries of TCC [Annual Report on Form 10-K of
AEP for the fiscal year ended December 31, 2002, File No.
1-3525, Exhibit 21]
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*99(a) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
*99(b) -- Certification of Chief Financial Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
TNC++
3(a) -- Restated Articles of Incorporation, as amended, and Articles
of Amendment to the Articles of Incorporation [Annual Report
on Form 10-K of TNC for the fiscal year ended December 31,
1996, File No. 0-340, Exhibit 3.5].
*3(b) -- Articles of Amendment to Restated Articles of Incorporation
of TNC dated December 17, 2002.
3(c) -- By-Laws of TNC (amended as of May 1, 2000) [Quarterly Report
on Form 10-Q of TNC for the quarter ended March 31, 2000,
File No. 0-340, Exhibit 3.4].
4(a) -- Indenture, dated August 1, 1943, between TNC and Harris
Trust and Savings Bank and J. Bartolini, as Trustees, as
amended and supplemented [Registration Statement No.
2-60712, Exhibit 5.05; Registration Statement No. 2-63931,
Exhibit 2.02; Registration Statement No. 2-74408, Exhibit
4.02; Form U-1 No. 70-6820, Exhibit 12; Form U-1 No.
70-6925, Exhibit 13; Registration Statement No. 2-98843,
Exhibit 4(b); Form U-1 No. 70-7237, Exhibit 4; Form U-1 No.
70-7719, Exhibit 3; Form U-1 No. 70-7936, Exhibit 10; Form
U-1 No. 70-8057, Exhibit 10; Form U-1 No. 70-8265, Exhibit
10; Form U-1 No. 70-8057, Exhibit 10(b); Form U-1 No.
70-8057, Exhibit 10(c)].
*10(a) -- Copy of Restated and Amended Operating Agreement, dated as
of January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC.
*10(b) -- Transmission Coordination Agreement, dated October 29, 1998,
among PSO, TCC, TNC, SWEPCo and AEPSC.
*12 -- Statement re: Computation of Ratios.
|
EXHIBIT NUMBER DESCRIPTION
--------------- -----------
*13 -- Copy of those portions of the TNC 2002 Annual Report (for
the fiscal year ended December 31, 2002) which are
incorporated by reference in this filing.
*24 -- Power of Attorney.
*99(a) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
*99(b) -- Certification of Chief Executive Officer Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code.
|
++ Certain instruments defining the rights of holders of long-term debt of the registrants included in the financial statements of registrants filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10% of the total assets of registrants. The registrants hereby agree to furnish a copy of any such omitted instrument to the SEC upon request.
(LOGO)
RECYCLE LOGO
PRINTED ON RECYCLED PAPER
EXHIBIT 4(b)
AMERICAN ELECTRIC POWER COMPANY, INC.
AND
THE BANK OF NEW YORK,
as Trustee
THIRD SUPPLEMENTAL INDENTURE
Dated as of June 11, 2002
TO
INDENTURE
Dated as of May 1, 2001
5.75% Senior Notes Due August 16, 2007
TABLE OF CONTENTS*
ARTICLE ONE
GENERAL TERMS AND CONDITIONS OF THE SENIOR NOTES
Section 1.1. Definitions................................................1 Section 1.2. Establishment, Designation and Principal Amount............3 Section 1.3. Payment of Principal and Interest..........................4 Section 1.4. Denominations..............................................6 Section 1.5. Global Securities..........................................6 Section 1.6. Remarketing................................................7 Section 1.7. Optional Remarketing.......................................13 Section 1.8. Sinking Fund...............................................14 Section 1.9. Redemption and Repurchase..................................14 Section 1.10. Covenants..................................................14 Section 1.11. Defeasance.................................................14 Section 1.12. Tax Event Redemption.......................................15 Section 1.13. Tax Treatment..............................................16 |
ARTICLE II
MISCELLANEOUS PROVISIONS
Section 2.1. Recitals by Company........................................16 Section 2.2. Ratification and Incorporation of Original Indenture.......16 Section 2.3. Executed in Counterparts...................................16 Section 2.4. Separability...............................................16 Section 2.5. Governing Law..............................................17 Exhibit A Form of Senior Note........................................A-1 |
THIRD SUPPLEMENTAL INDENTURE, dated as of June 11, 2002 (the "Third Supplemental Indenture"), between AMERICAN ELECTRIC POWER COMPANY, INC., a corporation duly organized and existing under the laws of the State of New York (hereinafter sometimes referred to as the "Company"), and THE BANK OF NEW YORK, a New York banking corporation, as trustee (hereinafter sometimes referred to as the "Trustee"), under the Indenture dated as of May 1, 2001 between the Company and the Trustee (the "Original Indenture"). The Original Indenture, as previously supplemented from time to time, including by this Third Supplemental Indenture, is hereafter referred to as the "Indenture."
WITNESSETH:
WHEREAS, the Company has executed and delivered the Original Indenture to the Trustee to provide for the issuance of unsecured promissory notes or other evidences of indebtedness (the "Securities") in an unlimited aggregate principal amount, to be issued from time to time in one or more series as provided in the Original Indenture; and
WHEREAS, pursuant to the terms of the Original Indenture, the Company desires to provide for the establishment of a new series of its Securities (said series being hereinafter referred to as the "Senior Notes"), the form and substance of such Senior Notes and the terms, provisions and conditions thereof to be set forth as provided in the Original Indenture and this Third Supplemental Indenture; and
WHEREAS, the Company desires and has requested the Trustee to join with it in the execution and delivery of this Third Supplemental Indenture, and all requirements necessary to make this Third Supplemental Indenture a valid instrument, in accordance with its terms, and to make the Senior Notes, when executed by the Company and authenticated and delivered by the Trustee, the valid obligations of the Company, have been performed and fulfilled, and the execution and delivery hereof have been in all respects duly authorized;
NOW THEREFORE, in consideration of the purchase and acceptance of the Senior Notes by the holders thereof, and for the purpose of setting forth, as provided in the Original Indenture, the form and substance of the Senior Notes and the terms, provisions and conditions thereof, the Company covenants and agrees with the Trustee as follows:
ARTICLE ONE
GENERAL TERMS AND CONDITIONS OF THE SENIOR NOTES
Except as otherwise expressly provided in or pursuant to this Third Supplemental Indenture or unless the context otherwise requires:
(1) a term defined in the Original Indenture has the same meaning when used in this Third Supplemental Indenture;
(2) a term defined anywhere in this Third Supplemental Indenture has the same meaning throughout;
(3) the singular includes the plural and vice versa;
(4) headings are for convenience of reference only and do not affect interpretation;
(5) capitalized terms used herein for which no definition is provided herein shall have the meanings set forth in the Original Indenture, the Forward Purchase Contract Agreement, the Remarketing Agreement or the Pledge Agreement, as the case may be and as the context may require; and
(6) the following terms have the meanings given to them in this
Section 1.1(6):
"Business Day" means any day other than a Saturday, Sunday or any other day on which banking institutions and trust companies the State of New York or at a place of payment are authorized or required by law, regulation or executive order to be closed.
"Company" has the meaning set forth in the preamble.
"Contingent Payment Regulations" has the meaning set forth in
Section 1.13.
"Forward Purchase Contract Agent" means The Bank of New York.
"Forward Purchase Contract Agreement" means the agreement, dated as of June 11, 2002, between the Company and the Forward Purchase Contract Agent.
"Global Securities" has the meaning set forth in Section 1.5.
"Interest Payment Date" has the meaning set forth in Section 1.3.
"Pledge Agreement" means the Pledge Agreement, dated as of June 11, 2002, between the Company and The Bank of New York, as Forward Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary.
"Regular Record Date" means, with respect to each Interest Payment Date, the close of business on the Business Day preceding such Interest Payment Date; provided, that with respect to Separate Notes that are not in book-entry only form, the Regular Record Date shall be the close of business on the 15th Business Day preceding such Interest Payment Date.
"Remarketing" means any remarketing conducted pursuant to and in accordance with the Remarketing Agreement.
"Remarketing Agreement" means the Remarketing Agreement, dated as of June 11, 2002, by and among the Company, the Remarketing Agent and the Forward Purchase Contract Agent.
"Remarketing Value" means
(i) the value at the Remarketing Date or any Subsequent Remarketing Date, as the case may be, of either (a) U.S. Treasury securities that will pay, on or prior to the Payment Date falling on the Stock Purchase Date, an amount of cash equal to the aggregate interest payment that is scheduled to be payable on that Payment Date, on (x) the Notes which are included in Equity Units and are participating in the remarketing and (y) the Separate Notes which are to be remarketed pursuant to Section 4.5(d) of the Pledge Agreement, assuming for that purpose that the interest rate on the Notes is equal to the Coupon Rate, if the Remarketing occurs prior to the fourth Business Day preceding the Stock Purchase Date, or (b) an amount of cash equal to the aggregate interest payment that is scheduled to be payable on that Payment Date, on (x) the Notes which are included in Equity Units and are participating in the remarketing and (y) the Separate Notes which are to be remarketed pursuant to Section 4.5(d) of the Pledge Agreement and Section 1.6 of this Third Supplemental Indenture, assuming for that purpose that the interest rate on the Notes is equal to the Coupon Rate, if the Remarketing occurs on or after the fourth Business Day preceding the Stock Purchase Date; and
(ii) the value at the Remarketing Date or any Subsequent
Remarketing Date, as the case may be, of either (a) U.S.
Treasury securities that will pay, on or prior to the Stock
Purchase Date, an amount of cash equal to the Stated Amount
of (x) such Notes which are included in Equity Units and are
participating in the remarketing and (y) the Separate Notes
which are to be remarketed pursuant to Section 4.5(d) of the
Pledge Agreement, if the Remarketing occurs prior to the
fourth Business Day preceding the Stock Purchase Date, or
(b) an amount of cash equal to the Stated Amount of (x) such
Notes which are included in Equity Units and are
participating in the remarketing and (y) the Separate Notes
which are to be remarketed pursuant to Section 4.5(d) of the
Pledge Agreement and Section 1.6 of this Third Supplemental
Indenture, if the Remarketing occurs on or after the fourth
Business Day preceding the Stock Purchase Date
provided that for purposes of clauses (1) and (2) above, the Remarketing Value shall be calculated on the assumptions that (x) the U.S. Treasury securities are highly liquid and mature on or within 35 days prior to the Stock Purchase Date, as determined in good faith by the Remarketing Agent in a manner intended to minimize the cash value of the U.S. Treasury securities, and (y) the U.S. Treasury securities are valued based on the ask-side price of the U.S. Treasury securities at a time between 9:00 a.m. and 11:00 a.m., New York City time, selected by the Remarketing Agent, on the Remarketing Date or any Subsequent Remarketing Date, as the case may be, as determined on a third-day settlement basis by reasonable and customary means selected in good faith by the Remarketing Agent, plus accrued interest to that date.
"Reset Rate" means the interest rate per annum with respect to the Senior Notes that is determined by the Remarketing Agent pursuant to the Remarketing Agreement as follows:
(i) in connection with a successful Remarketing, the rate of interest that, in the opinion of the Remarketing Agent, will, when applied to the Outstanding Senior Notes, enable the then current aggregate market value of the Senior Notes to have a value equal to approximately, but not less than, 100.25% of the Remarketing Value as of the Remarketing Date or as of any Subsequent Remarketing Date, as the case may be; or
(ii) upon the occurrence of a Failed Remarketing, the rate of interest applicable to the Senior Notes initially until (A) the Senior Notes are successfully remarketed pursuant to the Forward Purchase Contract Agreement and the Remarketing Agreement or (B) if the Last Failed Remarketing shall have occurred, a market rate of interest as determined in accordance with Section 1.6 of this Supplemental Indenture.
"Senior Notes" has the meaning set forth in the recitals.
"Stated Maturity" means August 16, 2007.
"Telerate" means the Dow Jones Telerate Service.
"Tax Event Redemption Date" has the meaning set forth in Section 1.11.
(a) There shall be and is hereby authorized a series of Securities under the Original Indenture designated the "5.75% Senior Notes Due August 16, 2007," in the initial aggregate principal amount of $300,000,000, which amount shall be as set forth in the Company Order for the authentication and delivery of the Senior Notes pursuant to Section 2.04 of the Original Indenture. Such aggregate principal amount of the 5.75% Senior Notes Due August 16, 2007 may be increased from time to time in accordance with Section 2.01 of the Original Indenture.
(b) The Senior Notes shall mature and the principal shall be due and payable together with all accrued and unpaid interest thereon on August 16, 2007.
(c) The Senior Notes that are part of the Equity Units shall be issued in definitive fully registered form (the "Registered Securities"), without coupons, in substantially the form set out in Exhibit A hereto. The entire principal amount of the Senior Notes shall initially be evidenced by one or more certificates issued to The Bank of New York, as the Forward Purchase Contract Agent under the Forward Purchase Contract Agreement (as defined below).
(d) The Senior Notes that, in accordance with the Forward Purchase Contract Agreement, are no longer part of Equity Units shall be represented initially by Global Securities (as defined below). Each such Registered Security and Global Security shall represent such aggregate principal amount of the Outstanding Senior Notes as shall be from time to time endorsed thereon, which principal amounts may be increased or decreased, as applicable, to reflect Transfers from Pledged Notes to Separate Notes and Transfers from Separate Notes to Pledged Notes. Any such increase or decrease in the aggregate principal amount of (i) Registered Securities shall be made by the Collateral Agent and (ii) Global Securities representing Senior Notes shall be made by the Trustee, as custodian of the Global Securities, in each case upon the instructions of the Collateral Agent given pursuant to Article IV of the Pledge Agreement.
(a) The unpaid principal amount of the Senior Notes shall initially bear interest at the rate of 5.75% per annum, payable on each February 16, May 16, August 16 and November 16 (each, with respect to the Senior Notes, an "Interest Payment Date"), from the original date of issuance, to, but excluding, the earlier of (i) the settlement date of a successful Remarketing under the Forward Purchase Contract Agreement or (ii) the Stock Purchase Date, and, thereafter, at the Reset Rate to, but excluding, the Stated Maturity of the Senior Notes.
(b) Interest shall be payable quarterly in arrears on each Interest Payment
Date to the Person in whose name the Senior Notes are registered on the Regular
Record Date for such Interest Payment Date; provided that interest payable on
the Stated Maturity of principal as provided herein shall be paid to the person
to whom principal is payable. Any such interest not punctually paid or duly
provided for with respect to any Interest Payment Date falling after the Stock
Purchase Date shall forthwith cease to be payable to the registered holders on
such regular record date, and may be paid to the person or persons in whose name
the Senior Notes are registered at the close of business on a special record
date to be fixed by the Trustee for the payment of such defaulted interest,
notice whereof shall be given to the registered holders of the Senior Notes not
less than ten (10) days prior to such special record date, or may be paid at any
time in any other lawful manner not inconsistent with the requirements of any
securities exchange, if any, on which the Senior Notes may be listed, and upon
such notice as may be required by such exchange, all as more fully provided in
Section 2.03 of the Original Indenture.
(c) The amount of interest payable for any period will be computed (1) for
any quarterly period, on the basis of a 360-day year of twelve 30-day months,
(2) for any period shorter than a full quarterly period, on the basis of a
30-day month and (3) for periods of less than a month, on the basis of the
actual number of days elapsed per 30-day month. If any date on which principal
or interest is payable is not a Business Day, then payment of principal or
interest payable on such date will be made on the next succeeding day which is a
Business Day (and without any interest or other payment in respect of any such
delay), except that, if such Business Day is in the next succeeding calendar
year, such payment shall be made on the immediately preceding Business Day, in
each case with the same force and effect as if made on such date.
(d) Payment of the principal of and interest on the Senior Notes shall be
made at an Office or Agency of the Company or at the Office of the Agent in The
City of New York in such coin or currency of the United States of America as at
the time of payment is legal tender for payment of public and private debts,
with any such payment that is due on the Stated Maturity of any Senior Notes
being made upon surrender of such Senior Notes to the Office or Agency of the
Company or at the Office of the Agent in The City of New York. Payments of
interest will be made, subject to such surrender where applicable, at the option
of the Company, (i) by check mailed to the address of the person entitled
thereto as such address shall appear in the Security Register or (ii) by wire
transfer at such place and to such account at a banking institution in the
United States as may be designated in writing to the Trustee at least sixteen
(16) days prior to the date for payment by the Person entitled hereto.
The Senior Notes shall be issued in denominations of $50 and integral multiples of $50.
(a) The Senior Notes that, in accordance with the Forward Purchase Contract Agreement, are no longer part of the Equity Units will be issued initially in the form of one or more global securities (the "Global Securities") registered in the name of DTC or its nominee. Except under the limited circumstances described below or in Section 1.3 above, Senior Notes represented by such Global Securities will not be exchangeable for, and will not otherwise be issuable as, Senior Notes in definitive form. The Global Securities described above may not be transferred except by DTC to a nominee of DTC or by a nominee of DTC to DTC or another nominee of DTC or to a successor Depository or its nominee.
(b) Owners of beneficial interests in such a Global Security will not be considered the Holders thereof for any purpose under the Indenture, and no Global Security representing a Senior Note shall be exchangeable, except for another Global Security of like denomination and tenor to be registered in the name of DTC or its nominee or to a successor Depository or its nominee or except as described below. The rights of owners of beneficial interests in such a Global Security shall be exercised only through DTC.
(c) A Global Security shall be exchangeable for Senior Notes registered in the names of persons other than DTC or its nominee only if (i) DTC notifies the Company that it is unwilling or unable to continue as a Depository for such Global Security and no successor Depository shall have been appointed by the Company within 90 days of receipt by the Company of such notification, or if at any time DTC ceases to be a clearing agency registered under the Securities Exchange Act of 1934 at a time when DTC is required to be so registered to act as such Depository and no successor Depository shall have been appointed by the Company within 90 days after it becomes aware of such cessation, or (ii) the Company in its sole discretion determines that it no longer has any senior debt securities represented by global securities or that it will permit a Global Security to be exchangeable or an Event of Default under the Indenture has occurred and is continuing. Any Global Security that is exchangeable pursuant to the preceding sentence shall be exchangeable for Senior Notes registered in such names as DTC shall direct.
(a) The Pledged Notes comprising part of Equity Units and the Separate Notes of holders of Separate Notes that have elected to participate in the Remarketing shall be remarketed by the Remarketing Agent on the Remarketing Date. A Holder of Equity Units may elect not to participate in a Remarketing and retain the Senior Notes underlying such Equity Units by notifying the Forward Purchase Contract Agent of such election and delivering the Opt-out Treasury Consideration to the Forward Purchase Contract Agent not later than 10:00 a.m. on the fourth Business Day prior to the Remarketing Date, as applicable (or, in the case of a Failed Remarketing, not later than 10:00 a.m. on the fourth Business Day immediately prior to the subsequent Remarketing Period). Upon receipt thereof by the Forward Purchase Contract Agent, the Forward Purchase Contract Agent shall deliver such Opt-out Treasury Consideration to the Collateral Agent, which will, for the benefit of the Company, thereupon apply such Opt-out Treasury Consideration to secure such Holder's obligations under the Forward Purchase Contracts. On the first Business Day immediately preceding the Remarketing Date (or, in the case of a Failed Remarketing, the subsequent Remarketing Period), the Collateral Agent, pursuant to the terms of the Pledge Agreement, will deliver the Pledged Notes to the Forward Purchase Contract Agent. Within three Business Days following any Remarketing Period (A) if the Remarketing was successful, the Forward Purchase Contract Agent shall distribute such Notes to the new Holders thereof and (B) if there was a Failed Remarketing, the Forward Purchase Contract Agent will deliver such Notes to the Collateral Agent, which will, for the benefit of the Company, thereupon apply such Notes that are a component of Equity Units to secure such Holders' obligations under the Forward Purchase Contracts, return any Opt-out Treasury Consideration delivered by such Holders to such Holders and return the Separate Notes to the holders thereof. A Holder that does not so deliver the Opt-out Treasury Consideration or has not settled the related Purchase Contract through a Cash Settlement or an Early Settlement pursuant to Sections 5.4 and 5.9 of the Forward Purchase Contract Agreement shall be deemed to have elected to participate in the Remarketing.
(b) On the seventh Business Day prior to the Remarketing Date or the first day of any subsequent Remarketing Period, the Company shall give Holders of Equity Units and Holders of Separate Notes notice of the Remarketing in an Authorized Newspaper, including the specific U.S. Treasury security or securities (including the CUSIP number and/or the principal terms of such Treasury security or securities) that must be delivered by Holders of Equity Units that elect not to participate in the Remarketing pursuant to Section 5.4(g) of the Forward Purchase Contract Agreement, no later than 10:00 a.m. (New York City time) on the seventh Business Day preceding the Remarketing Date. Not later than seven nor more than 15 calendar days prior to any Remarketing Period, the Company shall request DTC (or any successor Clearing Agency) to notify, directly or indirectly, each Beneficial Owner or Clearing Agency Participant holding Equity Units or Stripped Units and each Beneficial Owner of a Separate Note of the Remarketing and of the procedures that must be followed in connection with the Remarketing.
(c) The Forward Purchase Contract Agent shall notify, by 10:00 a.m., New York City time, on the third Business Date preceding the Remarketing Date or the first day of any subsequent Remarketing Period, as applicable, the Remarketing Agent and the Collateral Agent of the aggregate number of Senior Notes of Equity Units Holders to be remarketed. On the third Business Day immediately preceding the Remarketing Date or the first day of any subsequent Remarketing Period, as applicable, no later than by 10:00 a.m. New York City time, pursuant to the terms of the Pledge Agreement, the Custodial Agent will notify the Remarketing Agent of the aggregate number of Separate Notes to be remarketed. On the third Business Day immediately preceding the Remarketing Date or the first day of any subsequent Remarketing Period, as applicable, the Collateral Agent and the Custodial Agent, pursuant to the terms of the Pledge Agreement, will deliver for Remarketing to the Remarketing Agent all Notes to be remarketed. Upon receipt of such notice from the Forward Purchase Contract Agent and the Custodial Agent and such Notes from the Collateral Agent and the Custodial Agent, the Remarketing Agent will, on the Remarketing Date, use its commercially reasonable best efforts to establish a Reset Rate pursuant to clause (i) of the definition of Reset Rate and remarket such Senior Notes pursuant to the Remarketing procedures in the Remarketing Agreement.
(d) The right of each Holder of Senior Notes to have its Senior Notes
tendered for purchase will be limited to the extent that (i) the Remarketing
Agent conducts a Remarketing pursuant to the terms of the Remarketing Agreement,
(ii) the Remarketing Agent is able to find a purchaser or purchasers for the
tendered Senior Notes and (iii) such purchaser or purchasers deliver the
purchase price therefor to the Remarketing Agent.
(e) Upon receipt of the notice provided above in paragraph (c) from the Forward Purchase Contract Agent and the Custodial Agent and such Notes from the Collateral Agent and the Custodial Agent, the Remarketing Agent will, on the Remarketing Date, use its commercially reasonable best efforts to (i) establish a rate of interest that, in the opinion of the Remarketing Agent, will, when applied to the outstanding Notes, enable the then current aggregate market value of the Notes to have a value equal to approximately, but not less than, 100.25% of the Remarketing Value as of the Remarketing Date or as of any Subsequent Remarketing Date, as the case may be (the "Reset Rate") and (ii) sell such Notes on such date at a price equal to approximately, but not less than, 100.25% of the Remarketing Value.
(f) If, in spite of using its commercially reasonable best efforts, the Remarketing Agent cannot establish the Reset Rate and remarket the Notes included in the remarketing at a price equal to approximately, but not less than, 100.25% of the Remarketing Value, the Remarketing Agent will again attempt to establish the Reset Rate and remarket the Notes included in the remarketing at a price equal to approximately, but not less than, 100.25% of the Remarketing Value on each of the two immediately following Business Days. If the Remarketing Agent cannot remarket the Notes included in the remarketing at a price equal to approximately, but not less than, 100.25% of the Remarketing Value on any of those days, it will attempt to establish the Reset Rate and remarket the Notes included in the remarketing at a price equal to approximately, but not less than, 100.25% of the Remarketing Value on each of the three Business Days immediately preceding June 16, 2005. If the Remarketing Agent cannot remarket the Notes included in the remarketing at a price equal to approximately, but not less than, 100.25% of the Remarketing Value on any of those days, it will attempt to establish the Reset Rate and remarket the Notes included in the remarketing at a price equal to approximately, but not less than, 100.25% of the Remarketing Value on each of the three Business Days immediately preceding July 16, 2005. If the Remarketing Agent cannot establish the Reset Rate and remarket the Notes included in the remarketing at a price equal to approximately, but not less than, 100.25% of the Remarketing Value either on any of the two Business Days immediately following the Remarketing Date or on any of the three Business Days immediately preceding June 16, 2005 or on any of the three Business Days immediately preceding July 16, 2005, the remarketing in each period will be deemed to have failed (each, a "Failed Remarketing"). If the Remarketing Agent cannot establish the Reset Rate and remarket the Notes included in the remarketing at a price equal to approximately, but not less than, 100.25% of the Remarketing Value on any of the three Business Days immediately preceding July 16, 2005, the Remarketing Agent will further attempt to establish the Reset Rate and remarket the Notes included in the remarketing at a price equal to approximately, but not less than, 100.25% of the Remarketing Value on each of the three Business Days immediately preceding August 12, 2005. If, in spite of using its commercially reasonable best efforts, the Remarketing Agent fails to remarket the Notes underlying the Equity Units at a price equal to approximately, but not less than, 100.25% of the Remarketing Value in accordance with the terms of the Pledge Agreement by 4:00 p.m., New York City time, on the third Business Day immediately preceding the Stock Purchase Date, a "Last Failed Remarketing" will be deemed to have occurred.
(g) If a successful Remarketing shall have occurred prior to the fourth Business Day preceding the Stock Purchase Date, the Remarketing Agent will, in accordance with the Forward Purchase Contract Agreement and the Remarketing Agreement:
(i) deduct and retain for itself the Remarketing Fee;
(ii) use the proceeds from such successful Remarketing to purchase the Agent-purchased Treasury Consideration with the CUSIP numbers, if any, selected by the Remarketing Agent, described in clauses (1) and (2) of the definition of Remarketing Value related to the Senior Notes of Holders of Equity Units that were remarketed;
(iii)if any Separate Notes were remarketed, remit to the Collateral Agent for payment to the Holders of such Separate Notes sold in the Remarketing the remaining proceeds from such successful Remarketing attributable to the Separate Notes; and
(iv) if there remain any proceeds from such successful Remarketing,
after the application of such proceeds as set forth in clauses
(i) through (iii) of this sentence, then remit such remaining
proceeds to the Forward Purchase Contract Agent for payment to
the Holders of the Equity Units that were remarketed, on a pro
rata basis, in accordance with the Remarketing Agreement.
(h) In the case of a successful Remarketing occurring prior to the fourth Business Day preceding the Stock Purchase Date, on or prior to the third Business Day following the Remarketing Date or any Subsequent Remarketing Date, the Remarketing Agent shall deliver such Agent-purchased Treasury Consideration to the Forward Purchase Contract Agent, which shall thereupon deliver such Agent-purchased Treasury Consideration to the Collateral Agent. The Collateral Agent, for the benefit of the Company, will thereupon apply such Agent-purchased Treasury Consideration, in accordance with the Pledge Agreement, to secure such Holders' obligations under the Forward Purchase Contracts.
(i) If a successful Remarketing shall have occurred on or after the fourth Business Day preceding the Stock Purchase Date, the Remarketing Agent will, in accordance with the Forward Purchase Contract Agreement and the Remarketing Agreement:
(i) deduct and retain for itself the Remarketing Fee;
(ii) pay the proceeds from such successful Remarketing to the Forward Purchase Contract Agent, which shall thereupon deliver such proceeds to the Collateral Agent which, for the benefit of the Company, will thereupon apply such proceeds, in accordance with the Pledge Agreement in direct settlement of the Holders' obligations under the Forward Purchase Contracts;
(iii)if any Separate Notes were remarketed, remit to the Collateral Agent for payment to the Holders of such Separate Notes sold in the Remarketing the remaining proceeds from such successful Remarketing attributable to the Separate Notes; and
(iv) if there remain any proceeds from such successful Remarketing,
after the application of such proceeds as set forth in clauses
(i) through (iii) of this sentence, then remit such remaining
proceeds to the Forward Purchase Contract Agent for payment to
the Holders of the Equity Units that were remarketed, on a pro
rata basis, in accordance with the Remarketing Agreement.
(j) If a successful Remarketing occurs, by approximately 4:30 p.m. (New York City time) on the Remarketing Date, the Remarketing Agent shall advise, by telephone (promptly confirmed in writing in the case of clause (i)):
(i) the Company, the Forward Purchase Contract Agent, the Collateral Agent, the Securities Intermediary, DTC and the Trustee of the Reset Rate determined in the Remarketing;
(ii) each purchaser (or the Depository Participant thereof) of Senior Notes in the Remarketing of the Reset Rate and the number of Senior Notes such purchaser is to purchase; and
(iii)each purchaser to give instructions to its Depository Participant to pay the purchase price on the date of settlement for such Remarketing in same day funds against delivery of the remarketed Senior Notes purchased through the facilities of DTC.
(k) Any distribution to Holders of excess funds and interest described in this Section 1.6 shall be payable at the Office of the Agent in The City of New York maintained for that purpose or, at the option of the Holder or the holder of Separate Notes, as applicable, by check mailed to the address of the Person entitled thereto at such address as it appears on the relevant Register or by wire transfer to an account specified by the Holder or the holder of Separate Notes, as applicable.
(l) If a Failed Remarketing occurs, the Remarketing Agent and the Company, as applicable, shall take the following actions:
(i) the Remarketing Agent shall notify by telephone the Company, the Forward Purchase Contract Agent, the Collateral Agent and the Trustee, that a Failed Remarketing has occurred, whereupon the Company shall notify the Clearing Agency, by telephone, that a Failed Remarketing has occurred;
(ii) with respect to any Remarketing Period during which no successful Remarketing occurred, the Company shall publish notice by means of Bloomberg and Reuters newswires, such notice to be published no later than the fourth Business Day following the end of such Remarketing Period;
(iii)the Remarketing Agent shall determine the Reset Rate in accordance with clause (ii) of the Reset Rate definition; and
(iv) the Remarketing Agent shall remit, within three Business Days following the end of a Remarketing Period which constituted a Failed Remarketing, the Pledged Notes that were to be remarketed to the Collateral Agent and the Separate Notes that were to be remarketed to the Custodial Agent.
(m) If upon a Last Failed Remarketing, the Collateral Agent delivers any
Senior Notes to the Company in full satisfaction of the Holder's obligation
under the related Forward Purchase Contracts, any accumulated and unpaid
interest on such Notes will become payable by the Company to the Forward
Purchase Contract Agent for payment to the Holder of the Equity Units to which
such Notes relate. Such payment will be made by the Company on or prior to 11:00
a.m., New York City time, on the Stock Purchase Date in lawful money of the
United States by certified or cashier's check or wire transfer in immediately
available funds payable to or upon the order of the Forward Purchase Contract
Agent. Upon the occurrence of a Last Failed Remarketing, the Company will retain
and dispose of the Pledged Notes of all Holders in satisfaction of the Holders'
obligations under the related Forward Purchase Contracts. The Company will
publish notice by means of Bloomberg and Reuters newswires of any Remarketing
Period during which no successful Remarketing occurred, such notice to be
published not later than the fourth Business Day following the end of such
Remarketing Period. The Company will cause a notice of the Last Failed
Remarketing to be published on the fourth Business Day following the date of the
Last Failed Remarketing in an Authorized Newspaper.
(n) In the event of a Last Failed Remarketing, the Remarketing Agent shall determine the Reset Rate that shall apply to the Senior Notes held by the Holders of Equity Units that elected not to participate in the remarketing and Holders of Separate Notes according to the following method, provided that in no event shall the Reset Rate exceed the maximum rate permitted by state usury laws and other applicable laws. After the Last Failed Remarketing, the Remarketing Agent will take the average of the interest rates quoted to it by three nationally recognized investment banks selected by the Company, which are underwriters or dealers in debt securities similar to the Senior Notes, that in their judgment reflects an accurate market rate of interest applicable to the Senior Notes at that time. Following receipt of these quotes, the Remarketing Agent will have the right, in its sole judgment, to either recalculate the average based on only two of the quoted interest rates if one of the three quotes, in the Remarketing Agent's sole discretion, did not reflect market conditions or, alternatively, determine a consensus among the investment banks rather than a strict mathematical average by taking into account all relevant qualitative and quantitative factors. These factors may include, but shall not limited to, maturity of the Senior Notes, the credit rating and credit risk of the Company and companies of similar industries, the then yield to maturity of the Senior Notes and the state of the markets for primary and secondary sales of similar debt securities.
(o) In accordance with DTC's normal procedures, on the date of settlement of such Remarketing or the Stock Purchase Date, as applicable, the transactions described above with respect to each Senior Notes remarketed in the Remarketing shall be executed through DTC, and the accounts of the respective Depository Participants shall be debited and credited and such remarketed Senior Notes delivered by book entry as necessary to effect purchases and sales of such remarketed Senior Notes. DTC shall make payment in accordance with its normal procedures.
(p) If any Holder of Senior Notes selling Senior Notes in the Remarketing fails to deliver such Senior Notes, the direct or indirect Depository Participant of such selling Holder and of any other Person who was to have purchased Senior Notes in the Remarketing may deliver to any such other Person an aggregate principal amount of Senior Notes that is less than the aggregate principal amount of Senior Notes that otherwise was to be purchased by such Person. In such event, the aggregate principal amount of Senior Notes to be so delivered shall be determined by such direct or indirect Depository Participant, and delivery of such lesser aggregate principal amount of Senior Notes shall constitute good delivery.
(q) The Remarketing Agent is not obligated to purchase any Senior Notes that otherwise would remain unsold in the Remarketing. Neither the Company nor the Remarketing Agent shall be obligated in any case to provide funds to make payment upon tender of the Senior Notes for Remarketing.
(r) Under the Remarketing Agreement, the Company, in its capacity as issuer of the Senior Notes, shall be liable for, and shall pay, any and all costs and expenses incurred in connection with the Remarketing, other than the Remarketing Fee.
(s) The settlement procedures set forth herein, including provisions for payment by purchasers of the remarketed Senior Notes in the Remarketing, shall be subject to modification to the extent required by DTC or if the book-entry system is no longer available for the remarketed Senior Notes at the time of the Remarketing, to facilitate the Remarketing of the remarketed Senior Notes in certificated form, and shall provide for the authentication and delivery of Senior Notes in a principal amount equal to the unremarketed portion of such Senior Notes. In addition, the Remarketing Agent may modify the settlement procedures set forth herein in order to facilitate the settlement process.
(a) On or prior to the fourth Business Day immediately preceding either the Remarketing Date or if applicable, the first day of any subsequent Remarketing Period, but no earlier than the Interest Payment Date immediately preceding the last Interest Payment Date before the Stock Purchase Date, holders of Separate Notes may elect to have their Separate Notes remarketed by Transferring their Separate Notes and delivering a notice of such election, substantially in the form of Exhibit C to the Pledge Agreement, to the Collateral Agent. On the third Business Day immediately prior to the Remarketing Date or the first day of any subsequent Remarketing Period, by 10:00 a.m., New York City time, the Collateral Agent shall notify the Remarketing Agent of the number of such Separate Notes to be remarketed. The Collateral Agent will hold such Separate Notes in an account separate from the Collateral Account. A holder of Separate Notes electing to have its Separate Notes remarketed will also have the right to withdraw such election by written notice to the Collateral Agent, substantially in the form of Exhibit D to the Pledge Agreement, on or prior to the fourth Business Day immediately preceding the applicable Remarketing Date or the first day of a subsequent Remarketing Period, upon which notice the Collateral Agent will return such Separate Notes to such holder.
(b) On the third Business Day immediately preceding the Remarketing Date or
the first day of any subsequent Remarketing Period, the Collateral Agent at the
written direction of the Remarketing Agent will deliver to the Remarketing Agent
for Remarketing all Separate Notes delivered to the Collateral Agent pursuant to
Section 4.5(d) of the Pledge Agreement and not withdrawn pursuant to the terms
thereof prior to such date. If the holder of the Separate Notes delivers only
such notice but not the Separate Notes subject to such notice, then none of such
holder's Separate Notes shall be included in the Remarketing. Once the holder of
Separate Notes elects to participate in the Remarketing, such Separate Notes
will be remarketed in the Remarketing, unless such notice is properly withdrawn.
In accordance with Section 4.5(d) of the Pledge Agreement, upon the occurrence
of a Failed Remarketing, the Remarketing Agent will promptly return such
Separate Notes to the Collateral Agent for redelivery to such holders of such
Separate Notes.
The Senior Notes shall not be entitled to any sinking fund.
Except as provided in Section 1.12, the Senior Notes shall not be redeemable prior to their Stated Maturity.
(a) For so long as any Senior Notes of this series remain outstanding, the Company will not create or incur or allow any of its subsidiaries to create or incur any pledge or security interest on any of the capital stock of a Public Utility Subsidiary held by the Company or one of its subsidiaries or a Significant Subsidiary.
For purposes of this covenant:
(i) Public Utility Subsidiary means, at any particular time, a direct or indirect subsidiary of the Company that, as a substantial part of its business, distributes or transmits electric energy to retail or wholesale customers at rates or tariffs that are regulated by either a state or Federal regulatory authority.
(ii) Significant Subsidiary means, at any particular time, any direct subsidiary of the Company whose consolidated gross assets or consolidated gross revenues (having regard to the Company's direct beneficial interest in the shares, or the like, of that subsidiary) represent at least 25% of the Company's consolidated gross assets or consolidated gross revenues appearing in the most recent audited financial statements of the Company as of the date of determination.
(b) The provisions of Article Ten of the Original Indenture shall be applicable to the Senior Notes.
The provisions of Section 11.01 of the Original Indenture shall not apply to the Senior Notes.
(a) If a Tax Event shall occur, the Company may, at its option, redeem the Senior Notes in whole (but not in part) at any time at a price per Senior Note equal to the Redemption Price. Installments of interest on the Senior Notes that are due and payable on or prior to the date of redemption (the "Tax Event Redemption Date") will be payable to the Holders of the Senior Notes registered as such on the Record Date next preceding such Tax Event Redemption Date. If, following the settlement of the Forward Purchase Contracts and following the occurrence of a Tax Event, the Company, at its option, redeems the Senior Notes, the proceeds of the redemption will be payable in cash to the Holders of the Senior Notes.
(b) If the Company exercises its option to redeem the Senior Notes following the occurrence of a Tax Event prior to the Remarketing Date, or if there has not been a successful Remarketing prior to the Stock Purchase Date, the Company shall in the notice to the Trustee pursuant to Section 3.02 of the Original Indenture specify the Redemption Price. Upon the specification of the Redemption Price by the Company, the Company shall appoint the Collateral Agent to acquire the Treasury Portfolio in consultation with the Company and in accordance with the Forward Purchase Contract Agreement. The Collateral Agent shall then apply, out of the aggregate Redemption Price for the Senior Notes that are components of Equity Units, an amount equal to the aggregate Redemption Amount for the Senior Notes that are components of Equity Units to purchase on behalf of the Holders of Equity Units the Treasury Portfolio and promptly remit the remaining portion, if any, of such aggregate Redemption Price to the Forward Purchase Contract Agent for payment to the Holders of such Equity Units. The Treasury Portfolio will be substituted for the Pledged Notes, and will be pledged to the Collateral Agent in accordance with the terms of the Pledge Agreement to secure the obligation of each Holder of an Equity Unit to purchase the Common Stock under the Forward Purchase Contract constituting a part of such Equity Units. Payment of the Redemption Price to Holders of Separate Notes shall be made in cash on the Tax Event Redemption Date.
(c) If a Tax Event Redemption occurs after the earlier of a successful Remarketing or the Stock Purchase Date, payment of the Redemption Price to each Holder of Senior Notes shall be made by the Trustee (subject to its receipt of funds), no later than 12:00 noon, New York City time, on the Tax Event Redemption Date, by check or wire transfer in immediately available funds (provided the necessary wire instructions have been provided to the Trustee at least 15 days prior to the Tax Event Redemption Date) at such place and to such account as may be designated by each such Holder of Senior Notes, including the Collateral Agent. If the Trustee holds immediately available funds sufficient to pay the Redemption Price of the Senior Notes, then, on such Tax Event Redemption Date, such Senior Notes will cease to be Outstanding.
(d) The Trustee shall have no duty or liability to determine or verify the Redemption Price. Notice of any redemption will be mailed at least 30 days but not more than 60 days before the Tax Event Redemption Date to each registered Holder of the Senior Notes to be repaid at its registered address. Unless the Company defaults in payment of the Redemption Price, on and after the Tax Event Redemption Date interest shall cease to accrue on the Senior Notes, whether or not such Senior Notes have been received by the Company, and all other rights of the Holders in respect of the Senior Notes shall terminate and lapse (other than the right to receive the Redemption Price upon delivery of such Senior Notes but without interest on such Redemption Price).
The Company agrees, and by acceptance of a beneficial ownership interest in the Senior Notes, each beneficial holder of Senior Notes will be deemed to have agreed (1) to treat the acquisition of an Equity Unit as the acquisition of the Senior Note and the Forward Purchase Contract constituting the Equity Unit and to allocate the purchase price of the Equity Unit between the Senior Note and the Forward Purchase Contract as $50 and $0, respectively, (2) to treat the Senior Notes as indebtedness that is subject to Treas. Reg. Sec. 1.1275-4 (the "Contingent Payment Regulations") for United States federal income tax purposes and (3) to be bound by the Company's determination of the "comparable yield" and "projected payment schedule," within the meaning of the Contingent Payment Regulations, with respect to the Senior Notes for United States federal income tax purposes. A Holder of Senior Notes may obtain the amount of original issue discount, issue date, yield to maturity, comparable yield and projected payment schedule by submitting a written request for it to the Company at the following address: American Electric Power, Investor Relations, One Riverside Plaza, Columbus, Ohio 43215.
ARTICLE TWO
MISCELLANEOUS PROVISIONS
The recitals in this Third Supplemental Indenture are made by the Company only and not by the Trustee, and all of the provisions contained in the Original Indenture in respect of the rights, privileges, immunities, powers and duties of the Trustee shall be applicable in respect of the Senior Notes and of this Third Supplemental Indenture as fully and with like effect as if set forth herein in full.
As supplemented hereby, the Original Indenture is in all respects ratified and confirmed, and the Original Indenture and this Third Supplemental Indenture shall be read, taken and construed as one and the same instrument.
This Third Supplemental Indenture may be executed in several counterparts, each of which shall be deemed to be an original, and such counterparts shall together constitute but one and the same instrument.
In case any provisions contained in this Third Supplemental Indenture or in any Senior Note shall be invalid, illegal or unenforceable, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impaired thereby.
THIS THIRD SUPPLEMENTAL INDENTURE AND EACH SENIOR NOTE SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK APPLICABLE TO AGREEMENTS MADE OR INSTRUMENTS ENTERED INTO AND, IN EACH CASE, PERFORMED IN SAID STATE.
IN WITNESS WHEREOF, the parties hereto have caused this Third Supplemental Indenture to be duly executed, and their respective corporate seals to be hereunto affixed, all as of the day and year first above written.
AMERICAN ELECTRIC POWER COMPANY, INC.
By: /s/ A. A. Pena Name: A. A. Pena Title: Treasurer |
THE BANK OF NEW YORK, as Trustee
By: /s/ Terence Rawlins Name: Terence Rawlins Title: Vice President |
EXHIBIT A
FORM OF SENIOR NOTE
[Face of Note]
[UNLESS AND UNTIL IT IS EXCHANGED IN WHOLE OR IN PART FOR THE INDIVIDUAL
SECURITIES REPRESENTED HEREBY, THIS GLOBAL SECURITY MAY NOT BE TRANSFERRED
EXCEPT AS A WHOLE BY THE DEPOSITORY TRUST COMPANY OR ANY SUCCESSOR DEPOSITARY
APPOINTED AS SUCH PURSUANT TO THE INDENTURE (THE "DEPOSITARY") TO A NOMINEE OF
THE DEPOSITARY OR BY A NOMINEE OF THE DEPOSITARY TO THE DEPOSITARY OR ANOTHER
NOMINEE OF THE DEPOSITARY OR BY THE DEPOSITARY OR ANY SUCH NOMINEE TO SUCH A
SUCCESSOR DEPOSITARY OR A NOMINEE OF SUCH SUCCESSOR DEPOSITARY. UNLESS THIS
GLOBAL SECURITY IS PRESENTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITARY
TO THE COMPANY OR ITS AGENT FOR REGISTRATION OR TRANSFER, EXCHANGE OR PAYMENT,
AND ANY SECURITY ISSUED IS REGISTERED IN THE NAME OF THE DEPOSITARY OR ITS
NOMINEE OR SUCH OTHER NAME AS IS REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF
THE DEPOSITARY AND ANY PAYMENT IS MADE TO THE DEPOSITARY OR ITS NOMINEE, ANY
TRANSFER, PLEDGE OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON
IS WRONGFUL SINCE THE REGISTERED OWNER HEREOF HAS AN INTEREST HEREIN.]*
CUSIP No.
ISIN No.
No. ___ $_______________
AMERICAN ELECTRIC POWER COMPANY, INC.
5.75% Senior Notes Due August 16, 2007
American Electric Power Company, Inc., a corporation duly organized and existing under the laws of New York (the "Company," which term includes any successor corporation under the Indenture hereinafter referred to), for value received, hereby promises to pay to [Cede & Co.]* or registered assigns, the principal sum of _______________________ United States Dollars [, or such other principal amount as shall be set forth in the Schedule of Increases or Decreases attached hereto,]** at the Company's Office or Agency or Office of the Agent in The City of New York for said purpose, on August 16, 2007 in such coin or currency of the United States of America as at the time of payment shall be legal tender for the payment of public and private debts, and to pay interest thereon from June 11, 2002 or from the next most recent date to which interest has been paid or duly provided for, quarterly in arrears on each February 16, May 16, August 16 and November 16 of each year (each such date, an "Interest Payment Date"), commencing on August 16, 2002, at the rate of 5.75% per annum to, but excluding, the earlier of (i) the settlement date of a successful Remarketing under the Forward Purchase Contract Agreement or (ii) the Stock Purchase Date, and, thereafter, at the Reset Rate to, but excluding, the Stated Maturity.
The amount of interest so payable for any period shall be computed (i) for any full quarterly period on the basis of a 360-day year of twelve 30-day months and (ii) for any period shorter than a full quarterly period, on the basis of a 30-day month and, for periods of less than a month, on the basis of the actual number of days elapsed per 30-day month. In the event that any Interest Payment Date is not a Business Day, then payment of the interest or principal payable on such date will be made on the next succeeding day which is a Business Day and no interest shall accrue in respect of the amounts which payment is so delayed for the period from and after such interest payment date or other payment date, except that, if such Business Day is in the next succeeding calendar year, such payment shall be made on the immediately preceding Business Day, in each case with the same force and effect as if made on such date.
Payments of the principal of and interest on the Senior Notes shall be made
at said Office or Agency of the Company or at the Office of the Agent in The
City of New York to which interest on the Senior Notes has been paid or duly
provided for, until payment of said principal sum has been made or duly provided
for; provided that, unless this Senior Note is a Senior Note issued in global
form ("Global Security"), interest may be paid, at the option of the Company,
(i) by check mailed to the address of the Person entitled thereto as such
address shall appear in the Security Register or (ii) by wire transfer at such
place and to such account at a banking institution in the United States as may
be designated in writing to the Trustee at least sixteen (16) days prior to the
date for payment by the Person entitled thereto. The interest so payable, and
punctually paid or duly provided for, on any Interest Payment Date, as provided
in the Indenture, as hereinafter defined, shall be paid to the Person in whose
name this Note (or one or more Predecessor Securities) shall have been
registered at the close of business on the Regular Record Date with respect to
such Interest Payment Date, provided that interest payable on the Stated
Maturity or any redemption date shall be paid to the Person to whom principal is
paid. Any such interest not so punctually paid or duly provided for shall
forthwith cease to be payable to the Holder on such Regular Record Date and
shall be paid as provided in said Indenture.
Reference is hereby made to the further provisions of this Senior Note set forth herein, which further provisions shall for all purposes have the same effect as if set forth at this place.
Unless the certificate of authentication hereon has been executed by the Trustee referred to herein by manual signature, this Senior Note shall not be entitled to any benefit under the Indenture or be valid or obligatory for any purpose.
IN WITNESS WHEREOF, the Company has caused this instrument to be duly executed.
Dated: ___________________
AMERICAN ELECTRIC POWER COMPANY, INC.
By: _________________________________
Name:
Title:
TRUSTEE'S CERTIFICATE OF AUTHENTICATION
This is one of the Securities of the series designated in accordance with, and referred to in, the within-mentioned Indenture.
Dated: ___________________
THE BANK OF NEW YORK, as Trustee
By: __________________________
Authorized Signatory
[Reverse of Note]
American Electric Power Company, Inc.
5.75% Senior Notes Due August 16, 2007
This Senior Note is one of a duly authorized issue of securities of the Company (the "Securities"), issued and to be issued in one or more series under an Indenture, dated as of May 1, 2001 (the "Original Indenture"), as previously supplemented and as to be supplemented by a third supplemental indenture, dated as of June 11, 2002 (the "Third Supplemental Indenture" and the Original Indenture, as so supplemented, the "Indenture"), between the Company and The Bank of New York, a New York banking corporation, as trustee (the "Trustee," which term includes any successor trustee under the Indenture), and reference is hereby made to the Indenture for a statement of the respective rights, limitations of rights, duties and immunities thereunder of the Company, the Trustee and the Holders and of the terms upon which the Securities are, and are to be, authenticated and delivered. This Senior Note is one of a series designated as 5.75% Senior Notes Due August 16, 2007 of the Company (hereinafter called the "Senior Notes"), issued under the Original Indenture, which is limited in aggregate principal amount to $300,000,000.
Neither the Original Indenture nor the Senior Notes limit or otherwise restrict the amount of indebtedness which may be incurred or other securities which may be issued by the Company. The Senior Notes issued under the Indenture are direct, unsecured obligations of the Company and will mature on August 16, 2007. The Senior Notes rank on parity with all other unsecured, unsubordinated indebtedness of the Company.
The Senior Notes will bear interest as set forth on the face hereof and in the Third Supplemental Indenture. The Reset Rate will be the interest rate per annum that is determined by the Remarketing Agent pursuant to the Remarketing Agreement as follows: (i) in connection with a successful Remarketing, the rate of interest that will, when applied to the Outstanding Notes, enable the then current aggregate market value of the Notes to have a value equal to approximately, but not less than, 100.25% of the Remarketing Value as of the Remarketing Date or as of any Subsequent Remarketing Date, as the case may be, or (ii) upon the occurrence of a Failed Remarketing the rate of interest applicable to the Senior Notes initially until (A) the Senior Notes are successfully remarketed pursuant to the Forward Purchase Contract Agreement and the Remarketing Agreement or (B) if the Last Failed Remarketing shall have occurred, in accordance with the method as described below.
Notwithstanding anything herein to the contrary, the Reset Rate shall in no event exceed the maximum rate, if any, permitted by applicable law.
In the event of a Last Failed Remarketing, the Remarketing Agent shall determine the Reset Rate that shall apply to the Senior Notes held by the Holders of Equity Units that elected not to participate in the remarketing and Holders of Separate Notes according to the following method. After the Last Failed Remarketing, the Remarketing Agent will take the average of the interest rates quoted to it by three nationally recognized investment banks selected by the Company, which are underwriters or dealers in debt securities similar to the Senior Notes, that in their judgment reflects an accurate market rate of interest applicable to the Senior Notes at that time. Following receipt of these quotes, the Remarketing Agent will have the right, in its sole judgment, to either recalculate the average based on only two of the quoted interest rates if one of the three quotes, in the Remarketing Agent's sole discretion, did not reflect market conditions or, alternatively, determine a consensus among the investment banks rather than a strict mathematical average by taking into account all relevant qualitative and quantitative factors. These factors may include, but shall not limited to, maturity of the Senior Notes, the credit rating and credit risk of the Company and companies of similar industries, the then yield to maturity of the Senior Notes and the state of the markets for primary and secondary sales of similar debt securities.
The Senior Notes are not redeemable prior to maturity except pursuant to a Tax Event in accordance with the Third Supplemental Indenture. If a Tax Event shall occur, the Company may, at its option, redeem the Senior Notes in whole (but not in part) at any time at a price per Senior Note equal to the Redemption Price. Installments of interest on the Senior Notes that are due and payable on or prior to the date of redemption will be payable to the Holders of the Senior Notes registered as such at the close of business on the Record Date next preceding such Tax Event Redemption Date. If, following the settlement of the Forward Purchase Contracts and following the occurrence of a Tax Event, the Company, at its option, redeems the Senior Notes, the proceeds of the redemption will be payable in cash to the Holders of the Senior Notes.
The Company agrees, and by acceptance of a beneficial ownership interest in the Senior Notes, each beneficial holder of Senior Notes will be deemed to have agreed (1) for United States federal, state and local income and franchise tax purposes to treat the acquisition of an Equity Unit as the acquisition of the Senior Note and the Forward Purchase Contract constituting the Equity Unit, (2) to treat the Senior Notes as indebtedness that is subject to Treas. Reg. Sec. 1.1275-4 (the "Contingent Payment Regulations") for United States federal income tax purposes and (3) to be bound by the Company's determination of the "comparable yield" and "projected payment schedule," within the meaning of the Contingent Payment Regulations, with respect to the Senior Notes for United States federal income tax purposes. A Holder of Senior Notes may obtain the amount of original issue discount, issue date, yield to maturity, comparable yield and projected payment schedule by submitting a written request for it to the Company at the following address: American Electric Power, Investor Relations, One Riverside Plaza, Columbus, Ohio 43215.
The Senior Notes are not entitled to any sinking fund.
The Senior Notes that are a component of Equity Units or that so elect under Section 1.7 of the Supplemental Indenture will be subject to Remarketing and, in the case of a Failed Remarketing, the Collateral Agent for the benefit of the Company reserves all of its rights as a secured party of the Pledged Notes with respect thereto and, subject to applicable law and Section 5.4 of the Forward Purchase Contract Agreement, may, among other things, permit the Company to cause the Senior Notes to be sold or to retain and cancel such Senior Notes, in either case, in full satisfaction of the Holders' obligations under the Forward Purchase Contracts.
If an Event of Default with respect to the Senior Notes shall occur and be continuing, the principal of the Senior Notes may be declared due and payable in the manner and with the effect provided in the Indenture. The Senior Indenture provides that in certain circumstances such declaration and its consequences may be waived by the Holders of a majority in aggregate principal amount of the Senior Notes then Outstanding. However, any such consent or waiver by the Holder shall not affect any subsequent default or impair any right consequent thereon.
The Indenture contains provisions permitting the Company and the Trustee, with the consent of the Holders of not less than a majority in aggregate principal amount of the Securities of all series affected by such supplemental indenture or indentures at the time outstanding voting as one class, as defined in the Indenture, to execute supplemental indentures for the purpose of adding any provisions to or changing in any manner or eliminating any of the provisions of the Indenture or of any supplemental indenture or of modifying in any manner the rights of the Holders of the Securities; provided, however, that no such supplemental indenture shall (i) extend the fixed maturity of any Securities of any series, or reduce the principal amount thereof, or reduce the rate or extend the time of payment of interest thereon, or reduce any premium payable upon the redemption thereof, or reduce the amount of the principal of a Discount Security that would be due and payable upon a declaration of acceleration of the maturity thereof pursuant to the Indenture, without the consent of the holder of each Senior Note then outstanding and affected; (ii) reduce the aforesaid percentage of Senior Notes, the holders of which are required to consent to any such supplemental indenture, or reduce the percentage of Senior Notes, the holders of which are required to waive any default and its consequences, without the consent of the holder of each Senior Note then outstanding and affected thereby; or (iii) modify any provision of Section 6.01(c) of the Indenture (except to increase the percentage of principal amount of securities required to rescind and annul any declaration of amounts due and payable under the Senior Notes), without the consent of the holder of each Senior Note then outstanding and affected thereby. The Indenture also contains provisions permitting the Holders of a majority in aggregate principal amount of the Senior Notes of any series at the time outstanding affected thereby, on behalf of the Holders of the Senior Notes of such series, to waive any past default in the performance of any of the covenants contained in the Indenture, or established pursuant to the Indenture with respect to such series, and its consequences, except a default in the payment of the principal of or premium, if any, or interest on any of the Notes of such series. Any such consent or waiver by the registered Holder of this Note (unless revoked as provided in the Indenture) shall be conclusive and binding upon such Holder and upon all future Holders and owners of this Note and of any Note issued in exchange herefor or in place hereof (whether by registration of transfer or otherwise), irrespective of whether or not any notation of such consent or waiver is made upon this Note.
Limitation upon Liens of Certain Subsidiaries
For so long as any Senior Notes of this series remain outstanding, the Company will not create or incur or allow any of its subsidiaries to create or incur any pledge or security interest on any of the capital stock of a Public Utility Subsidiary held by the Company or one of its subsidiaries or a Significant Subsidiary.
For purposes of this covenant:
(i) Public Utility Subsidiary means, at any particular time, a direct or indirect subsidiary of the Company that, as a substantial part of its business, distributes or transmits electric energy to retail or wholesale customers at rates or tariffs that are regulated by either a state or Federal regulatory authority.
(ii) Significant Subsidiary means, at any particular time, any direct subsidiary of ours whose consolidated gross assets or consolidated gross revenues (having regard to the Company's direct beneficial interest in the shares, or the like, of that subsidiary) represent at least 25% of the Company's consolidated gross assets or consolidated gross revenues appearing in the most recent audited financial statements of the Company as of the date of determination.
Limitation upon Mergers, Consolidations and Sale of Assets
The provisions of Article Ten of the Indenture shall be applicable to the Senior Notes of this series.
The Indenture contains provisions for defeasance of (a) the entire indebtedness evidenced by this Senior Note and (b) certain restrictive covenants upon compliance by the Company with certain conditions set forth therein; provided, however, Section 11.01 of the Original Indenture shall not apply to the Senior Notes.
No reference herein to the Indenture and no provision of this Senior Note or of the Indenture shall alter or impair the obligation of the Company, which are absolute and unconditional, to pay the principal of (and premium, if any) and interest, if any, on this Senior Note at the times, places and rates, and in the coin or currency, herein prescribed.
The Senior Notes of this series are issuable only in registered form without coupons in minimum denominations of $50 or any integral multiple of $50 over such minimum denomination. At the Office or Agency of the Company or at the Office of the Agent in The City of New York referred to on the face hereof and as provided in the Indenture and subject to certain limitations therein set forth, the Senior Notes are exchangeable for a like aggregate principal amount of Senior Notes and of like tenor of a difference authorized denomination, as requested by the Holder surrendering the same.
As provided in the Indenture and subject to certain limitations therein set forth, this Senior Note is transferable by the registered holder hereof on the Security Register of the Company, upon surrender of this Senior Note for registration of transfer at the office or agency of the Company as may be designated by the Company accompanied by a written instrument or instruments of transfer in form satisfactory to the Company or the Trustee duly executed by the registered Holder hereof or his or her attorney duly authorized in writing, and thereupon one or more new Senior Notes of authorized denominations and for the same aggregate principal amount and series will be issued to the designated transferee or transferees. No service charge will be made for any such transfer, but the Company may require payment of a sum sufficient to cover any tax or other governmental charge payable in relation thereto.
Prior to due presentment of this Senior Note for registration of transfer, the Company, the Trustee and any agent of the Company or the Trustee may treat the Person in whose name this Senior Note is registered as the owner hereof for all purposes, whether or not this Senior Note be overdue and neither the Company, the Trustee nor any such agent shall be affected by notice to the contrary.
No recourse shall be had for the payment of the principal of or the interest on this Senior Note, or for any claim based hereon, or otherwise in respect hereof, or based on or in respect of the Indenture, or any indenture supplement thereto, against any incorporator, stockholder, officer or director, past, present or future, as such, of the Company or of any predecessor or successor corporation, whether by virtue of any constitution, statute or rule of law, or by the enforcement of any assessment or penalty or otherwise, all such liability being, by the acceptance hereof and as part of the consideration for the issue hereof, expressly waived and released.
THIS SENIOR NOTE SHALL BE DEEMED TO BE A CONTRACT MADE UNDER THE LAWS OF THE STATE OF NEW YORK, AND FOR ALL PURPOSES SHALL BE CONSTRUED IN ACCORDANCE WITH THE LAWS OF SAID STATE.
All terms used in this Senior Note (and not otherwise defined in this Senior Note) that are defined in the Indenture, the Forward Purchase Contract Agreement, the Remarketing Agreement or the Pledge Agreement, as the case may be, shall have the meanings assigned to them in the Indenture, the Forward Purchase Contract Agreement, the Remarketing Agreement or the Pledge Agreement, as the case may be and as the context may require.
FOR VALUE RECEIVED, the undersigned hereby sell(s) and transfer(s) unto
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(please insert Social Security or other identifying number of assignee)
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PLEASE PRINT OR TYPEWRITE NAME AND ADDRESS, INCLUDING POSTAL ZIP CODE OF ASSIGNEE
the within Senior Note and all rights thereunder, hereby irrevocably constituting and appointing
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agent to transfer said Senior Note on the books of the Company, with full power of substitution in the premises.
Dated:_______________ __, ______
NOTICE: The signature to this assignment must correspond with the name as written upon the face of the within instrument in every particular without alteration or enlargement, or any change whatever.
[TO BE ATTACHED TO GLOBAL CERTIFICATES AND PLEDGED NOTES]
SCHEDULE OF INCREASES OR DECREASES
The following increases or decreases in this [Global Certificate] [Pledged
Note] have been made:
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Principal amount of
Amount of decrease Amount of increase in Senior Notes
in principal amount principal amount of evidenced by the
of Senior Notes Senior Notes [Global Certificate] Signature of
evidenced by the evidenced by the [Pledged Note] authorized signatory
[Global Certificate] [Global Certificate] following such of Trustee or
Date [Pledged Note] [Pledged Note] decrease or increase Collateral Agent
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EXHIBIT 4(c)
AMERICAN ELECTRIC POWER COMPANY, INC.
AND
THE BANK OF NEW YORK
AS FORWARD PURCHASE CONTRACT AGENT
FORWARD PURCHASE CONTRACT AGREEMENT
Dated as of June 11, 2002
Table of Contents
. Page
ARTICLE I. DEFINITIONS AND OTHER PROVISIONS OF GENERAL APPLICATION........... 1
Section 1.1 Definitions.................................................. 1
Section 1.2 Compliance Certificates and Opinions.........................13
Section 1.3 Form of Documents Delivered to Agent.........................14
Section 1.4 Acts of Holders; Record Dates................................14
Section 1.5 Notices......................................................16
Section 1.6 Notice to Holders; Waiver....................................16
Section 1.7 Effect of Headings and Table of Contents.....................17
Section 1.8 Successors and Assigns.......................................17
Section 1.9 Separability Clause..........................................17
Section 1.10 Benefits of Agreement........................................17
Section 1.11 Governing Law................................................17
Section 1.12 Legal Holidays...............................................17
Section 1.13 Counterparts.................................................18
Section 1.14 Inspection of Agreement......................................18
ARTICLE II. CERTIFICATE FORMS................................................18
Section 2.1 Forms of Certificates Generally..............................18
Section 2.2 Form of Agent's Certificate of Authentication................19
ARTICLE III. THE EQUITY UNITS................................................20
Section 3.1 Title and Terms; Denominations...............................20
Section 3.2 Rights and Obligations Evidenced by the Certificates.........20
Section 3.3 Execution, Authentication, Delivery and Dating...............21
Section 3.4 Temporary Certificates.......................................22
Section 3.5 Registration; Registration of Transfer and Exchange..........22
Section 3.6 Book-Entry Interests.........................................24
Section 3.7 Notices To Holders...........................................24
Section 3.8 Appointment of Successor Clearing Agency.....................24
Section 3.9 Definitive Certificates......................................24
Section 3.10 Mutilated, Destroyed, Lost and Stolen Certificates...........25
Section 3.11 Persons Deemed Owners........................................26
Section 3.12 Cancellation.................................................27
Section 3.13 Establishment of Stripped Units..............................27
Section 3.14 Reestablishment of Equity Units..............................28
Section 3.15 Transfer of Collateral Upon Occurrence of Termination Event..30
Section 3.16 No Consent to Assumption.....................................30
ARTICLE IV. THE NOTES........................................................30
Section 4.1 Payment of Interest; Rights to Interest Payments
Preserved; Notice....................................30
Section 4.2 Notice and Voting............................................31
Section 4.3 Tax Event Redemption.........................................32
ARTICLE V. THE FORWARD PURCHASE CONTRACTS; THE REMARKETING...................32
Section 5.1 Purchase of Shares of Common Stock...........................32
Section 5.2 Contract Adjustment Payments...................................
Section 5.3 Deferral of Contract Adjustment Payments.....................35
Section 5.4 Payment of Purchase Price; Remarketing.......................37
Section 5.5 Issuance of Shares of Common Stock...........................42
Section 5.6 Adjustment of Settlement Rate................................42
Section 5.7 Notice of Adjustments and Certain Other Events...............49
Section 5.8 Termination Event; Notice....................................50
Section 5.9 Early Settlement.............................................50
Section 5.10 Early Settlement Upon Merger.................................52
Section 5.11 Charges and Taxes............................................53
Section 5.12 No Fractional Shares.........................................54
Section 5.13 Tax Treatment................................................54
ARTICLE VI. REMEDIES.........................................................54
Section 6.1 Unconditional Right of Holders to Purchase Common Stock......54
Section 6.2 Restoration of Rights and Remedies...........................55
Section 6.3 Rights and Remedies Cumulative...............................55
Section 6.4 Delay or Omission Not Waiver.................................55
Section 6.5 Undertaking For Costs........................................55
Section 6.6 Waiver of Stay or Extension Laws.............................56
ARTICLE VII. THE AGENT.......................................................56
Section 7.1 Certain Duties, Rights and Immunities........................56
Section 7.2 Notice of Default............................................58
Section 7.3 Certain Rights of Agent......................................58
Section 7.4 Not Responsible For Recitals, Etc............................59
Section 7.5 May Hold Equity Units and Stripped Units and Other Dealings..60
Section 7.6 Money Held In Custody........................................60
Section 7.7 Compensation and Reimbursement...............................60
Section 7.8 Corporate Agent Required; Eligibility........................61
Section 7.9 Resignation and Removal; Appointment of Successor............61
Section 7.10 Acceptance of Appointment By Successor.......................62
Section 7.11 Merger, Conversion, Consolidation or Succession to Business..63
Section 7.12 Preservation of Information; Communications to Holders.......63
Section 7.13 Failure to Act...............................................63
Section 7.14 No Obligations of Agent......................................64
Section 7.15 Tax Compliance...............................................64
ARTICLE VIII. SUPPLEMENTAL AGREEMENTS........................................65
Section 8.1 Supplemental Agreements Without Consent of Holders...........65
Section 8.2 Supplemental Agreements With Consent of Holders..............65
Section 8.3 Execution of Supplemental Agreements.........................67
Section 8.4 Effect of Supplemental Agreements............................67
Section 8.5 Reference to Supplemental Agreements.........................67
ARTICLE IX. CONSOLIDATION, MERGER, SALE OR CONVEYANCE........................67
Section 9.1 Company May Consolidate, Etc., Only on Certain Terms.........67
Section 9.2 Successor Substituted........................................68
ARTICLE X. COVENANTS.........................................................68
Section 10.1 Performance Under Forward Purchase Contracts.................68
Section 10.2 Maintenance of Office or Agency..............................68
Section 10.3 Company to Reserve Common Stock..............................69
Section 10.4 Covenants as to Common Stock.................................69
Section 10.5 Statements of Officer of the Company as to Default...........69
Section 10.6 ERISA........................................................70
EXHIBITS
Exhibit A...Form of Equity Units Certificate
Exhibit B...Form of Stripped Units Certificate
Exhibit C...Instruction from Forward Purchase Contract Agent to Collateral Agent
Exhibit D...Instruction to Forward Purchase Contract Agent
Exhibit E...Notice to Settle by Cash
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FORWARD PURCHASE CONTRACT AGREEMENT, dated as of June 11, 2002, between American Electric Power Company, Inc., a New York corporation (the "Company"), and The Bank of New York, a New York banking corporation, acting as Forward Purchase Contract Agent for the Holders of Equity Units and Stripped Units from time to time (the "Agent").
RECITALS
The Company has duly authorized the execution and delivery of this Agreement and the Certificates evidencing the Equity Units and Stripped Units.
All things necessary to make the Forward Purchase Contracts, when the Certificates are executed by the Company and authenticated, executed on behalf of the Holders and delivered by the Agent, as provided in this Agreement, the valid obligations of the Company, and to constitute this Agreement a valid agreement of the Company, in accordance with its terms, have been done.
For and in consideration of the premises and the purchase of the Equity Units by the Holders thereof, the Company and the Agent mutually agree as follows:
ARTICLE .
DEFINITIONS AND OTHER PROVISIONS
OF GENERAL APPLICATION
For all purposes of this Agreement, except as otherwise expressly provided or unless the context otherwise requires:
(a) the terms defined in this Article have the meanings assigned to them in this Article and include the plural as well as the singular, and nouns and pronouns of the masculine gender include the feminine and neuter genders;
(b) all accounting terms not otherwise defined herein have the meanings assigned to them in accordance with generally accepted accounting principles in the United States;
(c) the words "herein," "hereof" and "hereunder" and other words of similar import refer to this Agreement as a whole and not to any particular Article, Section or other subdivision; and
(d) the following terms have the meanings given to them in this
Section 1.1(d):
"Act" when used with respect to any Holder, has the meaning specified in Section 1.4.
"Affiliate" has the same meaning as given to that term in Rule 405 under the Securities Act or any successor rule thereunder.
"Agent" means the Person named as the "Agent" in the first paragraph of this instrument until a successor Agent shall have become such pursuant to the applicable provisions of this Agreement, and thereafter "Agent" shall mean such Person.
"Agent-purchased Treasury Consideration" has the meaning specified in
Section 5.4(d).
"Agreement" means this instrument as originally executed or as it may from time to time be supplemented or amended by one or more agreements supplemental hereto entered into pursuant to the applicable provisions hereof.
"Applicable Market Value" has the meaning specified in Section 5.1(c).
"Applicable Ownership Interest" means, with respect to an Equity Unit and the U.S. Treasury Securities in the Treasury Portfolio, (A) for the principal amount of a Note, a 1/20, or 5.0%, undivided beneficial ownership interest in a $1,000 principal or interest amount of a principal or interest strip in a U.S. Treasury security included in such Treasury Portfolio which matures on or prior to the Stock Purchase Date and (B) for the scheduled interest Payment Date on the Notes that occurs on the Stock Purchase Date, in the case of a successful remarketing, or for each scheduled interest Payment Date on the Notes that occurs after the Tax Event Redemption Date and on or before the Stock Purchase Date, in the case of a Tax Event Redemption, a 0.071875% undivided beneficial ownership interest in a $1,000 principal or interest amount of a principal or interest strip in a U.S. Treasury security included in the Treasury Portfolio that matures on or prior to that interest Payment Date or Dates.
"Applicants" has the meaning specified in Section 7.12(b).
"Bankruptcy Code" means Title 11 of the United States Code, or any other law of the United States that from time to time provides a uniform system of bankruptcy laws.
"Beneficial Owner" means, with respect to a Book-Entry Interest, a Person who is the beneficial owner of such Book-Entry Interest as reflected on the books of the Clearing Agency or on the books of a Person maintaining an account with such Clearing Agency (directly as a Clearing Agency Participant or as an indirect participant, in each case in accordance with the rules of such Clearing Agency).
"Board of Directors" means either the Board of Directors of the Company or any other committee of such Board duly authorized to act generally or in any particular respect for such Board hereunder.
"Board Resolution" means (i) a copy of a resolution certified by the Secretary or an Assistant Secretary of the Company to have been duly adopted by the Board of Directors and to be in full force and effect on the date of such certification or (ii) a copy of a unanimous written consent of the Board of Directors.
"Book-Entry Interest" means a beneficial interest in a Global Certificate, ownership and transfers of which shall be maintained and made through book entries by a Clearing Agency as described in Section 3.6.
"Business Day" means any day other than a Saturday, Sunday or any other day on which banking institutions and trust companies in the State of New York or at a place of payment are authorized or required by law, regulation or executive order to be closed.
"Capital Stock" means any and all shares, interests, rights to purchase, warrants, options, participations or other equivalents of or interests in (however designated, whether voting or non-voting) corporate stock or similar interests in other types of entities.
"Cash Merger" has the meaning specified in Section 5.10(a).
"Cash Settlement" has the meaning specified in Section 5.4(a).
"Certificate" means an Equity Units Certificate or a Stripped Units Certificate.
"Clearing Agency" means an organization registered as a "Clearing Agency" pursuant to Section 17A of the Exchange Act that is acting as a Depository for the Equity Units and Stripped Units and in whose name, or in the name of a nominee of that organization, shall be registered a Global Certificate and which shall undertake to effect book-entry transfers and pledges of the Equity Units and Stripped Units.
"Clearing Agency Participant" means a broker, dealer, bank, other financial institution or other Person for whom from time to time the Clearing Agency effects book-entry transfers and pledges of securities deposited with the Clearing Agency.
"Closing Price" has the meaning specified in Section 5.1(c).
"Code" means Internal Revenue Code of 1986, as amended, and the rules and regulations promulgated thereunder.
"Collateral" has the meaning specified in Section 2.1(a) of the Pledge Agreement.
"Collateral Agent" means The Bank of New York, as Collateral Agent under the Pledge Agreement until a successor Collateral Agent shall have become such pursuant to the applicable provisions of the Pledge Agreement, and thereafter "Collateral Agent" shall mean the Person who is then the Collateral Agent thereunder.
"Collateral Substitution" has the meaning specified in Section 3.13(a).
"Common Stock" means the common stock, par value $6.50 per share, of the Company.
"Company" means the Person named as the "Company" in the first paragraph of this instrument until a successor shall have become such pursuant to the applicable provisions of this Agreement, and thereafter "Company" shall mean such successor.
"Constituent Person" has the meaning specified in Section 5.6(b).
"Contract Adjustment Payments" means, in the case of Equity Units and Stripped Units, the amount payable by the Company in respect of each Forward Purchase Contract constituting a part of such Equity Units or Stripped Units, equal to 3.50% per year of the Stated Amount, in each case computed (1) for any full quarterly period on the basis of a 360-day year of twelve 30-day months, and (2) for any period shorter than a full quarterly period, on the basis of a 30-day month and (3) for periods of less than a month, on the basis of the actual number of days elapsed per 30-day month, plus any Deferred Contract Adjustment Payments accrued pursuant to Section 5.3.
"Corporate Trust Office" means the office of the Agent at which, at any particular time, its corporate trust business shall be principally administered, which office at the date hereof is located at The Bank of New York, 101 Barclay Street, New York, New York 10286.
"Coupon Rate" means the percentage rate per annum at which each Note will bear interest initially.
"Current Market Price" has the meaning specified in Section 5.6(a)(8).
"Custodial Agent" means The Bank of New York, as Custodial Agent under the Pledge Agreement until a successor Custodial Agent shall have become such pursuant to the applicable provisions of the Pledge Agreement, and thereafter "Custodial Agent" shall mean the Person who is then the Custodial Agent thereunder.
"Deferred Contract Adjustment Payments" has the meaning specified in
Section 5.3.
"Depository" means, initially, DTC, until another Clearing Agency becomes its successor, and thereafter "Depository" shall mean such successor.
"DTC" means The Depository Trust Company, the initial Clearing Agency.
"Early Settlement" has the meaning specified in Section 5.9(a).
"Early Settlement Amount" has the meaning specified in Section 5.9(a).
"Early Settlement Date" has the meaning specified in Section 5.9(a).
"Early Settlement Rate" has the meaning specified in Section 5.9(b).
"Equity Units" means the collective rights and obligations of a Holder of an Equity Units Certificate in respect of a Note or the appropriate Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, as the case may be, subject in each case to the Pledge thereof, and the related Forward Purchase Contract.
"Equity Units Certificate" means a certificate evidencing the rights and obligations of a Holder in respect of the number of Equity Units specified on such certificate, substantially in the form of Exhibit A hereto.
"Equity Units Register" and "Equity Units Registrar" have the respective meanings specified in Section 3.5(a).
"ERISA" means the Employee Retirement Income Security Act of 1974, as amended.
"Exchange Act" means the Securities Exchange Act of 1934 and any statute successor thereto, in each case as amended from time to time, and the rules and regulations promulgated thereunder.
"Expiration Date" has the meaning specified in Section 1.4(f).
"Expiration Time" has the meaning specified in Section 5.6(a)(6).
"Failed Remarketing" has the meaning specified in Section 5.4(e).
"Fair Market Value" with respect to securities distributed in a Spin-Off means (a) in the case of any Spin-Off that is effected simultaneously with an Initial Public Offering of such securities, the Initial Public Offering price of those securities, and (b) in the case of any other Spin-Off, the average of the Sale Prices of those securities over the first 10 Trading Days after the effective date of such Spin-Off.
"Forward Purchase Contract," when used with respect to any Equity Units or Stripped Units, means the contract forming a part of such Equity Unit or Stripped Unit and obligating the Company to sell and the Holder of such Equity Unit or Stripped Unit to purchase Common Stock on the terms and subject to the conditions set forth in Article Five.
"Forward Purchase Contract Settlement Fund" has the meaning specified in Section 5.5.
"Global Certificate" means a Certificate that evidences all or part of the Units and is registered in the name of a Depository or a nominee thereof.
"Holder" means the Person in whose name the Units evidenced by an Equity Units Certificate or a Stripped Units Certificate is registered in the Equity Units Register or the Stripped Units Register, as the case may be.
"Indenture" means the Indenture, dated as of May 1, 2001, between the Company and the Trustee as supplemented by any officers' certificate or supplemental indenture.
"Initial Public Offering," with respect to any Spin-Off, means the first time securities of the same class or type as the securities being distributed in the Spin-Off are bone fide offered to the public for cash.
"Issuer Order" or "Issuer Request" means a written order or request signed in the name of the Company by the Chief Executive Officer, the Chief Financial Officer, the President, any Vice-President, the Treasurer, any Assistant Treasurer, the Secretary or any Assistant Secretary (or other officer performing similar functions) of the Company and delivered to the Agent.
"Last Failed Remarketing" has the meaning specified in Section 5.4(e)(i).
"Merger Early Settlement" has the meaning specified in Section 5.10.
"Merger Early Settlement Amount" has the meaning specified in Section 5.10.
"Merger Early Settlement Date" has the meaning specified in Section 5.10.
"Non-electing Share" has the meaning specified in Section 5.6(b).
"Notes" means the series of senior debt securities of the Company designated the 5.75% Senior Notes Due August 16, 2007, to be issued under the Indenture.
"NYSE" has the meaning specified in Section 5.1(c).
"Office of the Agent in The City of New York" means an office where Certificates may be presented or surrendered for acquisition of shares of Common Stock, transfer or exchange, Notes may be presented for payment or surrendered for transfer or exchange, and where notices and demands to or upon the Company in respect of Units may be served, such office being located initially at 101 Barclay Street, New York, New York 10286.
"Officer's Certificate" means a certificate signed by the Chief Executive Officer, the Chief Financial Officer, the President, any Vice-President, the Treasurer, any Assistant Treasurer, the Secretary or any Assistant Secretary (or other officer performing similar functions) of the Company and delivered to the Agent.
"Opinion of Counsel" means an opinion in writing signed by legal counsel, who may be an employee of or counsel to the Company or an Affiliate of the Company.
"Opt-out Treasury Consideration" has the meaning specified in Section 5.4(g).
"Outstanding Units" means, as of the date of determination, all Equity Units or Stripped Units evidenced by Certificates theretofore authenticated, executed and delivered under this Agreement, except:
(i) If a Termination Event has occurred, (A) Stripped Units and (B) Equity Units for which the related Note or the appropriate Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, as the case may be, has been theretofore deposited with the Agent in trust for the Holders of such Equity Units;
(ii) Equity Units and Stripped Units evidenced by Certificates theretofore cancelled by the Agent or delivered to the Agent for cancellation or deemed cancelled pursuant to the provisions of this Agreement; and
(iii)Equity Units and Stripped Units evidenced by Certificates in exchange for or in lieu of which other Certificates have been authenticated, executed on behalf of the Holder and delivered pursuant to this Agreement, other than any such Certificate in respect of which there shall have been presented to the Agent proof satisfactory to it that such Certificate is held by a bona fide purchaser in whose hands the Equity Units or Stripped Units evidenced by such Certificate are valid obligations of the Company;
provided, that in determining whether the Holders of the requisite number of the Equity Units or Stripped Units have given any request, demand, authorization, direction, notice, consent or waiver hereunder, Equity Units or Stripped Units owned by the Company or any Affiliate of the Company shall be disregarded and deemed not to be outstanding, except that, in determining whether the Agent shall be protected in relying upon any such request, demand, authorization, direction, notice, consent or waiver, only Equity Units or Stripped Units which a Responsible Officer of the Agent actually knows to be so owned shall be so disregarded. Equity Units or Stripped Units so owned which have been pledged in good faith may be regarded as Outstanding Units if the pledgee establishes to the satisfaction of the Agent the pledgee's right so to act with respect to such Equity Units or Stripped Units and that the pledgee is not the Company or any Affiliate of the Company.
"Payment Date" means each February 16, May 16, August 16 and November 16, commencing August 16, 2002.
"Person" means any individual, corporation, limited liability company, partnership, joint venture, association, joint-stock company, trust, unincorporated organization or government or any agency or political subdivision thereof.
"Plan" means an employee benefit plan that is subject to Title I of ERISA, a plan, individual retirement account or other arrangement that is subject to Section 4975 of the Code or any similar law or any entity whose underlying assets are considered to include "plan assets" of any such plan, account or arrangement.
"Pledge" means the pledge under the Pledge Agreement of the Notes, the Treasury Securities or the appropriate Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, in each case constituting a part of the Equity Units or Stripped Units, property, cash, securities, financial assets and security entitlements of the Collateral Account (as defined in Section 1.1 of the Pledge Agreement) and any proceeds of any of the foregoing.
"Pledge Agreement" means the Pledge Agreement, dated as of the date hereof, by and among the Company, the Collateral Agent, the Custodial Agent, the Securities Intermediary and the Agent, on its own behalf and as attorney-in-fact for the Holders from time to time of the Equity Units and Stripped Units.
"Pledged Applicable Ownership Interest in the Treasury Portfolio" has the meaning specified in Section 2.1(c) of the Pledge Agreement.
"Pledged Notes" has the meaning specified in Section 2.1(c) of the Pledge Agreement.
"Pledged Treasury Consideration" has the meaning specified in Section 2.1(c) of the Pledge Agreement.
"Pledged Treasury Securities" has the meaning specified in Section 2.1(c) of the Pledge Agreement.
"Predecessor Certificate" means a Predecessor Equity Units Certificate or a Predecessor Stripped Units Certificate.
"Predecessor Equity Units Certificate" of any particular Equity Units Certificate means every previous Equity Units Certificate evidencing all or a portion of the rights and obligations of the Company and the Holder under the Equity Units evidenced thereby; and, for the purposes of this definition, any Equity Units Certificate authenticated and delivered under Section 3.10 in exchange for or in lieu of a mutilated, destroyed, lost or stolen Equity Units Certificate shall be deemed to evidence the same rights and obligations of the Company and the Holder as the mutilated, destroyed, lost or stolen Equity Units Certificate.
"Predecessor Stripped Units Certificate" of any particular Stripped Units Certificate means every previous Stripped Units Certificate evidencing all or a portion of the rights and obligations of the Company and the Holder under the Stripped Units evidenced thereby; and, for the purposes of this definition, any Stripped Units Certificate authenticated and delivered under Section 3.10 in exchange for or in lieu of a mutilated, destroyed, lost or stolen Stripped Units Certificate shall be deemed to evidence the same rights and obligations of the Company and the Holder as the mutilated, destroyed, lost or stolen Stripped Units Certificate.
"Purchase Price" has the meaning specified in Section 5.1(a).
"Purchased Shares" has the meaning specified in Section 5.6(a)(6).
"Quotation Agent" means J.P. Morgan Securities Inc. or its successor or any other primary U.S. government securities dealer in New York City selected by the Company.
"Record Date" for the distribution payable on any Payment Date means, as to any Global Certificate, the Business Day next preceding such Payment Date, and as to any other Certificate, the 15th day preceding such Payment Date.
"Redemption Amount" means, (A) in the case of a Tax Event Redemption occurring prior to the earlier of a successful remarketing of the Notes or the Stock Purchase Date, for each Note the product of (i) the Stated Amount of such Note and (ii) a fraction whose numerator is the applicable Treasury Portfolio Purchase Price and whose denominator is the aggregate principal amount of Notes outstanding on the Tax Event Redemption Date, and (B) in the case of a Tax Event Redemption occurring after the earlier of a successful remarketing of the Notes or the Stock Purchase Date, for each Note the Stated Amount of the Note.
"Redemption Price" means the redemption price per Note equal to the Redemption Amount.
"Register" means the Equity Units Register and the Stripped Units Register, as applicable.
"Registrar" means the Equity Units Registrar and the Stripped Units Registrar, as applicable.
"Remarketing Agent" means Salomon Smith Barney Inc. or its successor under the Remarketing Agreement.
"Remarketing Agreement" means the Remarketing Agreement dated June 11, 2002 by and among the Company, the Remarketing Agent and the Agent.
"Remarketing Date" means the third Business Day preceding May 16, 2005.
"Remarketing Fee" has the meaning specified in Section 5.4(d).
"Remarketing Period" means the three Business Day period either: (i)
beginning on the Remarketing Date and ending after the two immediately
following Business Days; (ii) immediately preceding June 16, 2005;
(iii) immediately preceding July 16, 2005; or (iv) immediately
preceding August 12, 2005.
"Remarketing Value" means
(1) the value at the Remarketing Date or any Subsequent Remarketing
Date, as the case may be, of either (a) U.S. Treasury securities
that will pay, on or prior to the Payment Date falling on the
Stock Purchase Date, an amount of cash equal to the aggregate
interest payment that is scheduled to be payable on that Payment
Date, on (x) the Notes which are included in Equity Units and are
participating in the remarketing and (y) the Separate Notes which
are to be remarketed pursuant to Section 4.5(d) of the Pledge
Agreement and Section 1.6 of the Supplemental Indenture, assuming
for that purpose that the interest rate on the Notes is equal to
the Coupon Rate, if the remarketing occurs prior to the fourth
Business Day preceding the Stock Purchase Date, or (b) an amount
of cash equal to the aggregate interest payment that is scheduled
to be payable on that Payment Date, on (x) the Notes which are
included in Equity Units and are participating in the remarketing
and (y) the Separate Notes which are to be remarketed pursuant to
Section 4.5(d) of the Pledge Agreement, assuming for that purpose
that the interest rate on the Notes is equal to the Coupon Rate,
if the remarketing occurs on or after the fourth Business Day
preceding the Stock Purchase Date; and
(2) the value at the Remarketing Date or any Subsequent Remarketing
Date, as the case may be, of either (a) U.S. Treasury securities
that will pay, on or prior to the Stock Purchase Date, an amount
of cash equal to the Stated Amount of (x) such Notes which are
included in Equity Units and are participating in the remarketing
and (y) the Separate Notes which are to be remarketed pursuant to
Section 4.5(d) of the Pledge Agreement and Section 1.6 of the
Supplemental Indenture, if the remarketing occurs prior to the
fourth Business Day preceding the Stock Purchase Date, or (b) an
amount of cash equal to the Stated Amount of (x) such Notes which
are included in Equity Units and are participating in the
remarketing and (y) the Separate Notes which are to be remarketed
pursuant to Section 4.5(d) of the Pledge Agreement, if the
remarketing occurs on or after the fourth Business Day preceding
the Stock Purchase Date
provided that for purposes of clauses (1) and (2) above, the Remarketing Value shall be calculated on the assumptions that (x) the U.S. Treasury securities are highly liquid and mature on or within 35 days prior to the Stock Purchase Date, as determined in good faith by the Remarketing Agent in a manner intended to minimize the cash value of the U.S. Treasury securities, and (y) the U.S. Treasury securities are valued based on the ask-side price of the U.S. Treasury securities at a time between 9:00 a.m. and 11:00 a.m., New York City time, selected by the Remarketing Agent, on the Remarketing Date or any Subsequent Remarketing Date, as the case may be, as determined on a third-day settlement basis by reasonable and customary means selected in good faith by the Remarketing Agent, plus accrued interest to that date.
"Reorganization Event" has the meaning specified in Section 5.6(b).
"Reset Rate" has the meaning specified in Section 5.4(c).
"Responsible Officer" means, when used with respect to the Agent, any officer within the corporate trust department of the Agent (or any successor of the Agent), including any Vice-President, any assistant Vice-President, any assistant secretary, any assistant treasurer, any trust officer, any senior trust officer or any other officer of the Agent who customarily performs functions similar to those performed by the Persons who at the time shall be such officers, respectively, or to whom any corporate trust matter is referred because of such Person's knowledge of and familiarity with the particular subject and who, in each of the above cases, shall have direct responsibility for the administration of this Agreement.
"Sale Price" of the Common Stock or any securities distributed in a Spin-Off, as the case may be, on any Trading Day means the closing sale price per share (or if no closing sale price is reported, the average of the bid and asked prices or, if more than one in either case, the average of the average bid and the average asked prices) on such Trading Day as reported in composite transactions for the principal U.S. securities exchange on which the Common Stock or such securities are traded or, if the Common Stock or such securities are not listed on a U.S. national or regional securities exchange, as reported by NASDAQ.
"Securities Act" means the Securities Act of 1933, and any statute successor thereto, in each case as amended from time to time, and the rules and regulations promulgated thereunder.
"Securities Intermediary" means The Bank of New York, in its capacity as securities intermediary under the Pledge Agreement, together with its successors in such capacity.
"Separate Notes" has the meaning specified in Section 1.1 of the Pledge Agreement.
"Settlement Date" means any Early Settlement Date or Merger Early Settlement Date or the Stock Purchase Date.
"Settlement Rate" has the meaning specified in Section 5.1(a).
"Spin-Off" means a dividend or other distribution of shares of Capital Stock of any class or series, or similar equity interests, of or relating to a subsidiary or other business unit of the Company.
"Stated Amount" means, with respect to any one Note, Equity Unit or Stripped Unit, $50.
"Stock Purchase Date" means August 16, 2005.
"Stripped Units" means the collective rights and obligations of a holder of a Stripped Units Certificate in respect of a 1/20 undivided beneficial interest in a Treasury Security, subject in each case to the Pledge thereof, and the related Forward Purchase Contract.
"Stripped Units Certificate" means a certificate evidencing the rights and obligations of a Holder in respect of the number of Stripped Units specified on such certificate, substantially in the form of Exhibit B hereto.
"Stripped Units Register" and "Stripped Units Registrar" have the respective meanings specified in Section 3.5(a).
"Subsequent Remarketing Date" means, provided there has been one or
more Failed Remarketings, the date on which the Remarketing Agent has
consummated a remarketing in accordance with Section 5.4 hereof and
Section 1.6 of the Indenture, such date to be no later than the third
Business Day immediately preceding the Stock Purchase Date.
"Supplemental Indenture" means a supplemental indenture dated as of June 11, 2002, between the Company and the Trustee to the indenture dated as of May 1, 2001, between the Company and the Trustee.
"Tax Event" means the receipt by the Company of an opinion of nationally recognized independent tax counsel experienced in such matters, which may be Simpson Thacher & Bartlett, to the effect that there is more than an insubstantial risk that interest payable by the Company on the Notes would not be deductible, in whole or in part, by the Company for United States federal income tax purposes, as a result of (a) any amendment to, or change (including any announced proposed change) in, the laws (or any regulations thereunder) of the United States or any political subdivision or taxing authority thereof or therein affecting taxation, (b) any amendment to or change in an official interpretation or application of such laws or regulations by any legislative body, court, governmental agency or regulatory authority or (c) any interpretation or pronouncement that provides for a position with respect to such laws or regulations that differs from the generally accepted position on June 11, 2002, which amendment, change or proposed change is effective or which interpretation or pronouncement is announced on or after June 11, 2002.
"Tax Event Redemption" means, if a Tax Event shall occur, the redemption of the Notes, at the option of the Company, in whole but not in part, on not less than 30 days' nor more than 60 days' written notice.
"Tax Event Redemption Date" means the date upon which a Tax Event Redemption is to occur.
"Termination Date" means the date, if any, on which a Termination Event occurs.
"Termination Event" means the occurrence of any of the following events, at any time on or prior to the Stock Purchase Date:
(i) the entry by a court having competent jurisdiction of:
(a) a decree or order for relief in respect of the Company in an involuntary proceeding under any applicable bankruptcy, insolvency, reorganization or other similar law or a decree or order adjudging the Company to be insolvent, or approving a petition seeking reorganization, arrangement, adjustment or composition of the Company and such decree or order shall remain unstayed and in effect for a period of 60 consecutive days; or
(b) a final and non-appealable order appointing a custodian, receiver, liquidator, assignee, trustee or other similar official of the Company or of any substantial part of the property of the Company ordering the winding up or liquidation of the affairs of the Company; or
(ii) the commencement by the Company of a voluntary proceeding under any applicable bankruptcy, insolvency, reorganization or other similar law or of a voluntary proceeding seeking to be adjudicated insolvent or the consent by the Company to the entry of a decree or order for relief in an involuntary proceeding under any applicable bankruptcy, insolvency, reorganization or other similar law or to the commencement of any insolvency proceedings against it, or the filling by the Company of a petition or answer or consent seeking organization or relief under any applicable law, or the consent by the Company to the filing of such petition or to the appointment of or taking possession by a custodian, receiver, liquidator, assignee, trustee or similar official of the or any substantial part of the property of the Company or the making by the Company of an assignment for the benefit of creditors, or the taking of corporate action by the Company or any in furtherance of any such action.
"Threshold Appreciation Price" has the meaning specified in Section 5.1(a)(i).
"TIA" means the Trust Indenture Act of 1939, and any statute successor thereto, in each case as amended from time to time, and the rules and regulations promulgated thereunder.
"Trading Day" has the meaning specified in Section 5.1(c).
"Transaction Documents" has the meaning specified in Section 7.1(a).
"Treasury Consideration" means the Agent-purchased Treasury Consideration or the Opt-out Treasury Consideration.
"Treasury Portfolio" means: (i) if a Tax Event Redemption occurs prior to a successful remarketing of the Notes or the Stock Purchase Date, a portfolio of zero-coupon U.S. Treasury Securities consisting of principal or interest strips of U.S. Treasury Securities that mature on or prior to the Stock Purchase Date in an aggregate amount equal to the aggregate principal amount of the Notes included in the Equity Units on the Tax Event Redemption Date and, with respect to each scheduled interest Payment Date on the Notes that occurs after the Tax Event Redemption Date and on or before the Stock Purchase Date, interest or principal strips of U.S. Treasury Securities that mature on or prior to such Payment Date in an aggregate amount equal to the aggregate interest payment that would be due on the aggregate principal amount of the Notes included in the Equity Units on such Payment Date if the interest rate of the Notes were not reset on the applicable Remarketing Date, and (ii) solely for purposes of determining the Treasury Portfolio Purchase Price in the case of a Tax Event Redemption Date occurring prior to a successful remarketing of the Notes, a portfolio of zero-coupon U.S. Treasury Securities consisting of principal or interest strips of U.S. Treasury Securities that mature on or prior to the Stock Purchase Date in an aggregate amount equal to the aggregate principal amount of the Notes outstanding on the Tax Event Redemption Date and with respect to each scheduled interest Payment Date on the Notes outstanding that occurs after the Tax Event Redemption Date and on or before the Stock Purchase Date, interest or principal strips of U.S. Treasury Securities that mature on or prior to such interest Payment Date in an aggregate amount equal to the aggregate interest payment that would be due on the aggregate principal amount of the Notes outstanding on the Tax Event Redemption Date.
"Treasury Portfolio Purchase Price" means the lowest aggregate price quoted by a primary U.S. government securities dealer in New York City to the Quotation Agent on the third Business Day immediately preceding the Tax Event Redemption Date for the purchase of the Treasury Portfolio for settlement on the Tax Event Redemption Date.
"Treasury Security" means a zero-coupon U.S. Treasury security (CUSIP Number 912803AG8) maturing on August 15, 2005 that will pay $1,000 on such maturity date.
"Trustee" means The Bank of New York, a New York banking corporation, as trustee under the Indenture, or any successor thereto.
"Underwriting Agreement" means the Underwriting Agreement relating to the Equity Units dated June 5, 2002 between the Company and the underwriters named therein.
"Vice-President" means any vice-president, whether or not designated by a number or a word or words added before or after the title "vice-president."
Except as otherwise expressly provided by this Agreement, upon any application or request by the Company to the Agent to take any action under any provision of this Agreement, the Company shall furnish to the Agent an Officer's Certificate stating that all conditions precedent, if any, provided for in this Agreement relating to the proposed action have been complied with and, if requested by the Agent, an Opinion of Counsel stating that, in the opinion of such counsel, all such conditions precedent, if any, have been complied with, except that in the case of any such application or request as to which the furnishing of such documents is specifically required by any provision of this Agreement relating to such particular application or request, no additional certificate or opinion need be furnished.
Every certificate or opinion with respect to compliance with a condition or covenant provided for in this Agreement (other than the Officer's Certificate provided for in Section 10.5) shall include:
(a) a statement that the individual signing such certificate or opinion has read such covenant or condition and the definitions herein relating thereto;
(b) a brief statement as to the nature and scope of the examination or investigation upon which the statements or opinions contained in such certificate or opinion are based;
(c) a statement that, in the opinion of such individual, he or she has made such examination or investigation as is necessary to enable such individual to express an informed opinion as to whether or not such covenant or condition has been complied with; and
(d) a statement as to whether, in the opinion of such individual, such condition or covenant has been complied with.
(a) In any case where several matters are required to be certified by, or covered by an opinion of, any specified Person, it is not necessary that all such matters be certified by, or covered by the opinion of, only one such Person, or that they be so certified or covered by only one document, but one such Person may certify or give an opinion with respect to some matters and one or more other such Persons as to other matters, and any such Person may certify or give an opinion as to such matters in one or several documents.
(b) Any certificate or opinion of an officer of the Company may be based, insofar as it relates to legal matters, upon a certificate or opinion of, or representations by, counsel, unless such officer knows, or in the exercise of reasonable care should know, that the certificate or opinion or representations with respect to the matters upon which his certificate or opinion is based are erroneous. Any such certificate or Opinion of Counsel may be based, insofar as it relates to factual matters, upon a certificate or opinion of, or representations by, an officer or officers of the Company stating that the information with respect to such factual matters is in the possession of the Company unless such counsel knows, or in the exercise of reasonable care should know, that the certificate or opinion or representations with respect to such matters are erroneous.
Where any Person is required to make, give or execute two or more applications, requests, consents, certificates, statements, opinions or other instruments under this Agreement, they may, but need not, be consolidated and form one instrument.
(a) Any request, demand, authorization, direction, notice, consent,
waiver or other action provided by this Agreement to be given or taken by
Holders may be embodied in and evidenced by one or more instruments of
substantially similar tenor signed by such Holders in person or by an agent
of such Holders duly appointed in writing; and, except as herein otherwise
expressly provided, such action shall become effective when such instrument
or instruments are delivered to the Agent and, where it is hereby expressly
required, to the Company. Such instrument or instruments (and the action
embodied therein and evidenced thereby) are herein sometimes referred to as
the "Act" of the Holders signing such instrument or instruments. Proof of
execution of any such instrument or of a writing appointing any such agent
shall be sufficient for any purpose of this Agreement and (subject to
Section 7.1) conclusive in favor of the Agent and the Company, if made in
the manner provided in this Section.
(b) The fact and date of the execution by any Person of any such instrument or writing may be proved in any manner which the Agent deems sufficient.
(c) The ownership of Equity Units or Stripped Units shall be proved by the Equity Units Register or the Stripped Units Register, as the case may be.
(d) Any request, demand, authorization, direction, notice, consent, waiver or other Act of the Holder of any Certificate shall bind every future Holder of the same Certificate and the Holder of every Certificate issued upon the registration of transfer thereof or in exchange therefor or in lieu thereof in respect of anything done, omitted or suffered to be done by the Agent or the Company in reliance thereon, whether or not notation of such action is made upon such Certificate.
(e) The Company may set any day as a record date for the purpose of determining the Holders of Outstanding Units entitled to give, make or take any request, demand, authorization, direction, notice, consent, waiver or other action provided or permitted by this Agreement to be given, made or taken by Holders of Equity Units and Stripped Units. If any record date is set pursuant to this paragraph, the Holders of the Outstanding Units on such record date, and no other Holders, shall be entitled to take the relevant action with respect to the Equity Units or the Stripped Units, as the case may be, whether or not such Holders remain Holders after such record date; provided that no such action shall be effective hereunder unless taken on or prior to the applicable Expiration Date by Holders of the requisite number of Outstanding Units on such record date. Nothing in this paragraph shall be construed to prevent the Company from setting a new record date for any action for which a record date has previously been set pursuant to this paragraph (whereupon the record date previously set shall automatically and with no action by any Person be cancelled and of no effect), and nothing in this paragraph shall be construed to render ineffective any action taken by Holders of the requisite number of Outstanding Units on the date such action is taken. Promptly after any record date is set pursuant to this paragraph, the Company, at its own expense, shall cause notice of such record date, the proposed action by Holders and the applicable Expiration Date to be given to the Agent in writing and to each Holder of Equity Units and Stripped Units in the manner set forth in Section 1.6.
(f) With respect to any record date set pursuant to this Section, the Company may designate any date as the "Expiration Date" and from time to time may change the Expiration Date to any earlier or later day; provided that no such change shall be effective unless notice of the proposed new Expiration Date is given to the Agent in writing, and to each Holder of Equity Units and Stripped Units in the manner set forth in Section 1.6, on or prior to the existing Expiration Date. If an Expiration Date is not designated with respect to any record date set pursuant to this Section, the Company shall be deemed to have initially designated the 180th day after such record date as the Expiration Date with respect thereto, subject to its right to change the Expiration Date as provided in this paragraph. Notwithstanding the foregoing, no Expiration Date shall be later than the 180th day after the applicable record date.
Any request, demand, authorization, direction, notice, consent, waiver or Act of Holders or other document provided or permitted by this Agreement to be made upon, given or furnished to, or filed with:
(a) the Agent by any Holder or by the Company shall be sufficient for every purpose hereunder (unless otherwise herein expressly provided) if made, given, furnished or filed in writing and personally delivered, mailed, first-class postage prepaid, telecopied or delivered by overnight air courier guaranteeing next day delivery, to the Agent at 101 Barclay Street, New York, New York 10286, telecopy number: (212) 328-8243, Attention: Corporate Trust Department, or at any other address furnished in writing by the Agent to the Holders and the Company; or
(b) the Company by the Agent or by any Holder shall be sufficient for every purpose hereunder (unless otherwise herein expressly provided) if made, given, furnished or filed in writing and personally delivered, mailed, first-class postage prepaid, telecopied or delivered by overnight air courier guaranteeing next day delivery, to the Company at American Electric Power Company, Inc., 1 Riverside Plaza, Columbus, Ohio 43215, telecopy number: (614) 223-1687, Attention: General Counsel, or at any other address furnished in writing to the Agent and the Holders by the Company; or
(c) the Collateral Agent by the Agent, the Company or any Holder shall be sufficient for every purpose hereunder (unless otherwise herein expressly provided) if made, given, furnished or filed in writing and personally delivered, mailed, first-class postage prepaid, telecopied or delivered by overnight air courier guaranteeing next day delivery, addressed to the Collateral Agent at 101 Barclay Street, New York, New York 10286, telecopy number: (212) 328-8243, Attention: Corporate Trust Department, or at any other address furnished in writing by the Collateral Agent to the Agent, the Company and the Holders; or
(d) the Trustee by the Company shall be sufficient for every purpose hereunder (unless otherwise herein expressly provided) if made, given, furnished or filed in writing and personally delivered, mailed, first-class postage prepaid, telecopied or delivered by overnight air courier guaranteeing next day delivery, addressed to the Trustee at The Bank of New York, 101 Barclay Street, New York, New York 10286, telecopy number: (212) 328-8243, Attention: Corporate Trust Department, or at any other address furnished in writing by the Trustee to the Company.
(a) Where this Agreement provides for notice to Holders of any event, such notice shall be sufficiently given (unless otherwise herein expressly provided) if in writing and mailed, first-class postage prepaid, to each Holder affected by such event, at its address as it appears in the applicable Register, not later than the latest date, and not earlier than the earliest date, prescribed for the giving of such notice. In any case where notice to Holders is given by mail, neither the failure to mail such notice nor any defect in any notice so mailed to any particular Holder shall affect the sufficiency of such notice with respect to other Holders. Where this Agreement provides for notice in any manner, such notice may be waived in writing by the Person entitled to receive such notice, either before or after the event, and such waiver shall be the equivalent of such notice. Waivers of notice by Holders shall be filed with the Agent, but such filing shall not be a condition precedent to the validity of any action taken in reliance upon such waiver.
(b) In case by reason of the suspension of regular mail service or by reason of any other cause it shall be impracticable to give such notice by mail, then such notification as shall be made with the approval of the Agent shall constitute a sufficient notification for every purpose hereunder.
The Article and Section headings herein and the Table of Contents are for convenience only and shall not affect the construction hereof.
All covenants and agreements in this Agreement by the Company shall bind its successors and assigns, whether so expressed or not.
In case any provision in this Agreement or in the Equity Units or Stripped Units shall be invalid, illegal or unenforceable, the validity, legality and enforceability of the remaining provisions hereof and thereof shall not in any way be affected or impaired thereby.
Nothing in this Agreement or in the Equity Units or Stripped Units, express or implied, shall give to any Person, other than the parties hereto and their successors hereunder and, to the extent provided hereby, the Holders, any benefits or any legal or equitable right, remedy or claim under this Agreement. The Holders from time to time shall be beneficiaries of this Agreement and shall be bound by all of the terms and conditions hereof and of the Equity Units and Stripped Units evidenced by their Certificates by their acceptance of delivery of such Certificates.
This Agreement and the Equity Units and Stripped Units shall be governed by and construed in accordance with the laws of the State of New York, without regard to its principles of conflicts of laws.
(a) In any case where any Payment Date shall not be a Business Day, then (notwithstanding any other provision of this Agreement or the Equity Units Certificates) payments on the Notes shall not be made on such date, but such payments shall be made on the next succeeding Business Day with the same force and effect as if made on such Payment Date, provided that no interest shall accrue or be payable by the Company for the period from and after any such Payment Date, except that if such next succeeding Business Day is in the next succeeding calendar year, such payment shall be made on the Business Day immediately preceding the Payment Date with the same force and effect as if made on such Payment Date.
(b) If any date on which Contract Adjustment Payments are to be made on the Forward Purchase Contracts is not a Business Day, then payment of the Contract Adjustment Payments payable on that date will be made on the next succeeding day which is a Business Day, and no interest or additional payment will be paid in respect of the delay. However, if that Business Day is in the next succeeding calendar year, the payment will be made on the Business Day immediately preceding the Payment Date with the same force and effect as if made on that Payment Date.
(c) In any case where the Stock Purchase Date shall not be a Business Day, then (notwithstanding any other provision of this Agreement or the Certificates), the Forward Purchase Contracts shall not be performed on such date, but the Forward Purchase Contracts shall be performed on the immediately following Business Day with the same force and effect as if performed on the Stock Purchase Date.
This Agreement may be executed in any number of counterparts by the parties hereto, each of which, when so executed and delivered, shall be deemed an original, but all such counterparts shall together constitute one and the same instrument.
A copy of this Agreement shall be available at all reasonable times during normal business hours at the Corporate Trust Office for inspection by any Holder.
ARTICLE II.
CERTIFICATE FORMS
(a) The Equity Units Certificates (including the form of Forward Purchase Contract forming part of the Equity Units evidenced thereby) shall be in substantially the form set forth in Exhibit A hereto, with such letters, numbers or other marks of identification or designation and such legends or endorsements printed thereon, as may be required by the rules of any securities exchange or quotation system on which the Equity Units are listed or quoted for trading or any Depository therefor, or as may, consistently herewith, be determined by the officers of the Company executing such Equity Units Certificates, as evidenced by their execution of the Equity Units Certificates.
(b) The definitive Equity Units Certificates shall be printed or may be produced in any other manner, all as determined by the officers of the Company executing such Equity Units Certificates, consistent with the provisions of this Agreement, as evidenced by their execution thereof.
(c) The Stripped Units Certificates (including the form of Forward Purchase Contracts forming part of the Stripped Units evidenced thereby) shall be in substantially the form set forth in Exhibit B hereto, with such letters, numbers or other marks of identification or designation and such legends or endorsements printed thereon as may be required by the rules of any securities exchange or quotation system on which the Stripped Units may be listed or quoted for trading or any Depository therefor, or as may, consistently herewith, be determined by the officers of the Company executing such Stripped Units Certificates, as evidenced by their execution of the Stripped Units Certificates.
(d) The definitive Stripped Units Certificates shall be printed or may be produced in any other manner, all as determined by the officers of the Company executing such Stripped Units Certificates, consistent with the provisions of this Agreement, as evidenced by their execution thereof.
(e) Every Global Certificate authenticated, executed on behalf of the Holders and delivered hereunder shall bear a legend in substantially the following form:
"THIS CERTIFICATE IS A GLOBAL CERTIFICATE WITHIN THE MEANING OF THE FORWARD PURCHASE CONTRACT AGREEMENT (AS HEREINAFTER DEFINED) AND IS REGISTERED IN THE NAME OF THE CLEARING AGENCY OR A NOMINEE THEREOF. THIS CERTIFICATE MAY NOT BE EXCHANGED IN WHOLE OR IN PART FOR A CERTIFICATE REGISTERED, AND NO TRANSFER OF THIS CERTIFICATE IN WHOLE OR IN PART MAY BE REGISTERED, IN THE NAME OF ANY PERSON OTHER THAN SUCH CLEARING AGENCY OR A NOMINEE THEREOF, EXCEPT IN THE LIMITED CIRCUMSTANCES DESCRIBED IN THE FORWARD PURCHASE CONTRACT AGREEMENT."
Unless this Certificate is presented by an authorized representative of The Depository Trust Company (55 Water Street, New York, New York) to the Company or its agent for registration of transfer, exchange or payment, and any Certificate issued is registered in the name of Cede & Co., or such other name as requested by an authorized representative of The Depository Trust Company, and any payment hereon is made to Cede & Co., ANY TRANSFER, PLEDGE OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY A PERSON IS WRONGFUL since the registered owner hereof, Cede & Co., has an interest herein."
(a) The form of the Agent's certificate of authentication of the Equity Units shall be in substantially the form set forth on the form of the Equity Units Certificates.
(b) The form of the Agent's certificate of authentication of the Stripped Units shall be in substantially the form set forth on the form of the Stripped Units Certificates.
ARTICLE III.
THE EQUITY UNITS
(a) The aggregate number of Equity Units and Stripped Units, if any,
evidenced by Certificates authenticated, executed on behalf of the Holders
and delivered hereunder is limited to 6,000,000 (6,900,000 if the
Underwriters' (as defined in the Underwriting Agreement) over-allotment
option pursuant to the Underwriting Agreement is exercised in full), except
for Certificates authenticated, executed and delivered upon registration of
transfer of, in exchange for, or in lieu of other Certificates pursuant to
Section 3.4, 3.5, 3.10, 3.13, 3.14, 5.9, 5.10 or 8.5.
(b) The Certificates shall be issuable only in registered form and only in denominations of a single Equity Unit and any integral multiple thereof.
(a) Each Equity Units Certificate shall evidence the number of Equity Units specified therein, with each such Equity Units Certificate representing the ownership by the Holder thereof of a beneficial interest in a Note or the appropriate Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, as the case may be, subject to the Pledge of such Note or such Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, as the case may be, by such Holder pursuant to the Pledge Agreement, and the rights and obligations of the Holder thereof and the Company under one Forward Purchase Contract. The Agent as attorney-in-fact for, and on behalf of, the Holder of each Equity Unit shall pledge, pursuant to the Pledge Agreement, the Note or the appropriate Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, as the case may be, forming a part of such Equity Units, to the Collateral Agent and grant to the Collateral Agent a security interest in the right, title, and interest of such Holder in such Note or such Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, as the case may be, for the benefit of the Company, to secure the obligation of the Holder under each Forward Purchase Contract to purchase the Common Stock of the Company. Prior to the purchase of shares of Common Stock under each Forward Purchase Contract, such Forward Purchase Contracts shall not entitle the Holders of Equity Units Certificates to any of the rights of a holder of shares of Common Stock, including, without limitation, the right to vote or receive any dividends or other payments or to consent or to receive notice as stockholders in respect of the meetings of stockholders or for the election of directors of the Company or for any other matter, or any other rights whatsoever as stockholders of the Company.
(b) Each Stripped Units Certificate shall evidence the number of Stripped Units specified therein, with each such Stripped Units Certificate representing the ownership by the Holder thereof of a 1/20 undivided beneficial interest in a Treasury Security, subject to the Pledge of such interest in such Treasury Security by such Holder pursuant to the Pledge Agreement, and the rights and obligations of the Holder thereof and the Company under one Forward Purchase Contract. The Agent as attorney-in-fact for, and on behalf of, the Holder of each Stripped Unit shall pledge, pursuant to the Pledge Agreement, the Treasury Security, forming a part of such Stripped Unit, to the Collateral Agent and grant to the Collateral Agent a security interest in the right, title and interest of such Holder in such Treasury Security for the benefit of the Company, to secure the obligation of the Holder under each Forward Purchase Contract to purchase shares of Common Stock pursuant to this Agreement and the related Forward Purchase Contract. Prior to the purchase of shares of Common Stock under each Forward Purchase Contract, such Forward Purchase Contracts shall not entitle the Holders of Stripped Units Certificates to any of the rights of a holder of shares of Common Stock, including, without limitation, the right to vote or receive any dividends or other payments or to consent or to receive notice as stockholders in respect of the meetings of stockholders or for the election of directors of the Company or for any other matter, or any other rights whatsoever as stockholders of the Company.
(a) Subject to the provisions of Sections 3.13 and 3.14, upon the execution and delivery of this Agreement, and at any time and from time to time thereafter, the Company may deliver Certificates executed by the Company to the Agent for authentication, execution on behalf of the Holders and delivery, together with its Issuer Order for authentication of such Certificates, and the Agent in accordance with such Issuer Order shall authenticate, execute on behalf of the Holders and deliver such Certificates.
(b) The Certificates shall be executed on behalf of the Company by the Chief Executive Officer, the Chief Financial Officer, the President, any Vice-President, the Treasurer, any Assistant Treasurer, the Secretary or any Assistant Secretary (or other officer performing similar functions) of the Company and delivered to the Agent. The signature of any of these officers on the Certificates may be manual or by facsimile.
(c) Certificates bearing the manual or facsimile signatures of individuals who were at any time the proper officers of the Company shall bind the Company, notwithstanding that such individuals or any of them have ceased to hold such offices prior to the authentication and delivery of such Certificates or did not hold such offices at the date of such Certificates.
(d) No Forward Purchase Contract evidenced by a Certificate shall be valid until such Certificate has been executed on behalf of the Holder by the manual signature of an authorized signatory of the Agent, as such Holder's attorney-in-fact. Such signature by an authorized signatory of the Agent shall be conclusive evidence that the Holder of such Certificate has entered into the Forward Purchase Contracts evidenced by such Certificate.
(e) Each Certificate shall be dated the date of its authentication.
(f) No Certificate shall be entitled to any benefit under this Agreement or be valid or obligatory for any purpose unless there appears on such Certificate a certificate of authentication substantially in the form provided for herein executed by an authorized signatory of the Agent by manual signature, and such certificate upon any Certificate shall be conclusive evidence, and the only evidence, that such Certificate has been duly authenticated and delivered hereunder.
(a) Pending the preparation of definitive Certificates, the Company shall execute and deliver to the Agent, and the Agent shall authenticate, execute on behalf of the Holders, and deliver, in lieu of such definitive Certificates, temporary Certificates which are in substantially the form set forth in Exhibit A or Exhibit B hereto, as the case may be, with such letters, numbers or other marks of identification or designation and such legends or endorsements printed, lithographed or engraved thereon as may be required by the rules of any securities exchange on which the Equity Units or Stripped Units, as the case may be, are listed, or as may, consistent herewith, be determined by the officers of the Company executing such Certificates, as evidenced by their execution of the Certificates.
(b) If temporary Certificates are issued, the Company will cause definitive Certificates to be prepared without unreasonable delay. After the preparation of definitive Certificates, the temporary Certificates shall be exchangeable for definitive Certificates upon surrender of the temporary Certificates at the Corporate Trust Office, at the expense of the Company and without charge to the Holder. Upon surrender for cancellation of any one or more temporary Certificates, the Company shall execute and deliver to the Agent, and the Agent shall authenticate, execute on behalf of the Holder, and deliver in exchange therefor, one or more definitive Certificates of like tenor and denominations and evidencing a like number of Equity Units or Stripped Units, as the case may be, as the temporary Certificate or Certificates so surrendered. Until so exchanged, the temporary Certificates shall in all respects evidence the same benefits and the same obligations with respect to the Equity Units or Stripped Units, as the case may be, evidenced thereby as definitive Certificates.
(a) The Agent shall keep at the Corporate Trust Office a register (the "Equity Units Register") in which, subject to such reasonable regulations as it may prescribe, the Agent shall provide for the registration of Equity Units Certificates and of transfers of Equity Units Certificates (the Agent, in such capacity, the "Equity Units Registrar") and a register (the "Equity Units Register") in which, subject to such reasonable regulations as it may prescribe, the Agent shall provide for the registration of the Equity Units Certificates and transfers of Equity Units Certificates (the Agent, in such capacity, the "Equity Units Registrar").
(b) Upon surrender for registration of transfer of any Certificate at the Corporate Trust Office, the Company shall execute and deliver to the Agent, and the Agent shall authenticate, execute on behalf of the designated transferee or transferees, and deliver, in the name of the designated transferee or transferees, one or more new Certificates of like tenor and denominations, and evidencing a like number of Equity Units or Stripped Units, as the case may be.
(c) At the option of the Holder, Certificates may be exchanged for other Certificates, of like tenor and denominations and evidencing a like number of Equity Units or Stripped Units, as the case may be, upon surrender of the Certificates to be exchanged at the Corporate Trust Office. Whenever any Certificates are so surrendered for exchange, the Company shall execute and deliver to the Agent, and the Agent shall authenticate, execute on behalf of the Holder, and deliver the Certificates which the Holder making the exchange is entitled to receive.
(d) All Certificates issued upon any registration of transfer or exchange of a Certificate shall evidence the ownership of the same number of Equity Units or Stripped Units, as the case may be, and be entitled to the same benefits and subject to the same obligations, under this Agreement as the Equity Units or Stripped Units, as the case may be, evidenced by the Certificate surrendered upon such registration of transfer or exchange.
(e) Every Certificate presented or surrendered for registration of transfer or for exchange shall (if so required by the Agent) be duly endorsed, or be accompanied by a written instrument of transfer in form satisfactory to the Company and the Agent duly executed, by the Holder thereof or its attorney duly authorized in writing.
(f) No service charge shall be made for any registration of transfer or exchange of a Certificate, but the Company and the Agent may require payment from the Holder of a sum sufficient to cover any tax or other governmental charge that may be imposed in connection with any registration of transfer or exchange of Certificates, other than any exchanges pursuant to Sections 3.4, 3.6, 3.9 and 8.5 not involving any transfer.
(g) Notwithstanding the foregoing, the Company shall not be obligated to execute and deliver to the Agent, and the Agent shall not be obligated to authenticate, execute on behalf of the Holder and deliver any Certificate presented or surrendered for registration of transfer or for exchange on or after the Business Day immediately preceding the earlier of the Stock Purchase Date or the Termination Date. In lieu of delivery of a new Certificate, upon satisfaction of the applicable conditions specified above in this Section and receipt of appropriate registration or transfer instructions from such Holder, the Agent shall,
(i) if the Stock Purchase Date has occurred, deliver the shares of Common Stock issuable in respect of the Forward Purchase Contracts forming a part of the Equity Units or Stripped Units, as the case may be, evidenced by such Certificate,
(ii) in the case of Equity Units, if a Termination Event shall have occurred prior to the Stock Purchase Date, transfer the Notes or the appropriate Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, as applicable, relating to such Equity Units, or
(iii)in the case of Stripped Units, if a Termination Event shall have occurred prior to the Stock Purchase Date, transfer the Treasury Securities relating to such Stripped Units,
in each case subject to the applicable conditions and in accordance with the applicable provisions of Article V.
The Certificates, on original issuance will be issued in the form of one or more fully registered Global Certificates, to be delivered to the Depository or its custodian by, or on behalf of, the Company. Such Global Certificate shall initially be registered in the applicable Register in the name of Cede & Co., the nominee of the Depository, and no Beneficial Owner will receive a definitive Certificate representing such Beneficial Owner's interest in such Global Certificate, except as provided in Section 3.9. The Agent shall enter into an agreement with the Depository if so requested by the Company. Unless and until definitive, fully registered Certificates have been issued to Beneficial Owners pursuant to Section 3.9:
(a) the provisions of this Section 3.6 shall be in full force and effect;
(b) the Company shall be entitled to deal with the Clearing Agency for all purposes of this Agreement (including receiving approvals, votes or consents hereunder) as the Holder of the Equity Units and Stripped Units and the sole holder of the Global Certificate(s) and shall have no obligation to the Beneficial Owners;
(c) to the extent that the provisions of this Section 3.6 conflict with any other provisions of this Agreement, the provisions of this Section 3.6 shall control; and
(d) the rights of the Beneficial Owners shall be exercised only through the Clearing Agency and shall be limited to those established by law and agreements between such Beneficial Owners and the Clearing Agency and/or the Clearing Agency Participants. The Clearing Agency will make book-entry transfers among Clearing Agency Participants.
Whenever a notice or other communication to the Holders is required to be given under this Agreement, the Company or the Company's agent shall give such notices and communications to the Holders and, with respect to any Equity Units or Stripped Units registered in the name of a Clearing Agency or the nominee of a Clearing Agency, the Company or the Company's agent shall, except as set forth herein, have no obligations to the Beneficial Owners.
If any Clearing Agency elects to discontinue its services as securities Depository with respect to the Equity Units and Stripped Units or ceases to be eligible as a "clearing agency" under the Exchange Act, the Company may, in its sole discretion, appoint a successor Clearing Agency with respect to the Equity Units and Stripped Units.
If
(i) a Clearing Agency elects to discontinue its services as
securities Depository with respect to the Equity Units and
Stripped Units or ceases to be eligible as a "clearing agency"
under the Exchange Act and a successor Clearing Agency is not
appointed within 90 days after such discontinuance pursuant to
Section 3.8,
(ii) the Company elects to terminate the book-entry system through the Clearing Agency with respect to the Equity Units and Stripped Units, or
(iii)there shall have occurred and be continuing a default by the Company in respect of its obligations under one or more Forward Purchase Contracts, this Agreement, the Indenture, the Notes, the Equity Units, the Pledge Agreement or any other principal agreements or instruments executed in connection with the offering of Equity Units
then upon surrender of the Global Certificates representing the Book-Entry Interests with respect to the Equity Units and Stripped Units by the Clearing Agency, accompanied by registration instructions, the Company shall cause definitive Certificates to be delivered to Clearing Agency Participants in accordance with the instructions of the Clearing Agency. The Company and the Agent shall not be liable for any delay in delivery of such instructions and may conclusively rely on and shall be protected in relying on such instructions.
(a) If any mutilated Certificate is surrendered to the Agent, the Company shall execute and deliver to the Agent, and the Agent shall authenticate, execute on behalf of the Holder, and deliver in exchange therefor, a new Certificate at the cost of the Holder, evidencing the same number of Equity Units or Stripped Units, as the case may be, and bearing a Certificate number not contemporaneously outstanding.
(b) If there shall be delivered to the Company and the Agent (i) evidence to their satisfaction of the destruction, loss or theft of any Certificate, and (ii) such security or indemnity at the cost of the Holder as may be required by them to hold each of them and any agent of any of them harmless, then, in the absence of notice to the Company or the Agent that such Certificate has been acquired by a bona fide purchaser, the Company shall execute and deliver to the Agent, and the Agent shall authenticate, execute on behalf of the Holder, and deliver to the Holder, in lieu of any such destroyed, lost or stolen Certificate, a new Certificate, evidencing the same number of Equity Units or Stripped Units, as the case may be, and bearing a Certificate number not contemporaneously outstanding.
(c) Notwithstanding the foregoing, the Company shall not be obligated to execute and deliver to the Agent, and the Agent shall not be obligated to authenticate, execute on behalf of the Holder, and deliver to the Holder, a Certificate on or after the Business Day immediately preceding the earlier of the Stock Purchase Date or the Termination Date. In lieu of delivery of a new Certificate, upon satisfaction of the applicable conditions specified above in this Section and receipt of appropriate registration or transfer instructions from such Holder, the Agent shall (i) if the Stock Purchase Date has occurred, deliver the shares of Common Stock issuable in respect of the Forward Purchase Contracts forming a part of the Equity Units or Stripped Units evidenced by such Certificate, or (ii) if a Termination Event shall have occurred prior to the Stock Purchase Date, transfer the Notes, the appropriate Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, or the Treasury Securities, as the case may be, evidenced thereby, in each case subject to the applicable conditions and in accordance with the applicable provisions of Article V.
(d) Upon the issuance of any new Certificate under this Section, the Company and the Agent may require the payment by the Holder of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Agent) connected therewith.
(e) Every new Certificate issued pursuant to this Section in lieu of any destroyed, lost or stolen Certificate shall constitute an original contractual obligation of the Company and of the Holder in respect of the Equity Units or Stripped Units, as the case may be, evidenced thereby, whether or not the destroyed, lost or stolen Certificate (and the Equity Units and Stripped Units evidenced thereby) shall be at any time enforceable by anyone, and shall be entitled to all the benefits and be subject to all the obligations of this Agreement equally and proportionately with any and all other Certificates delivered hereunder.
(f) The provisions of this Section are exclusive and shall preclude (to the extent lawful) all other rights and remedies with respect to the replacement or payment of mutilated, destroyed, lost or stolen Certificates.
(a) Prior to due presentment of a Certificate for registration of transfer, the Company and the Agent, and any agent of the Company or the Agent, may treat the Person in whose name such Certificate is registered as the owner of the Equity Units or Stripped Units, as the case may be, evidenced thereby, for the purpose of receiving interest payments on the Notes, receiving payment of Contract Adjustment Payments, performance of the Forward Purchase Contracts and for all other purposes whatsoever (subject to Section 4.1(a) and 5.2(a)), whether or not any such payments shall be overdue and notwithstanding any notice to the contrary, and neither the Company nor the Agent, nor any agent of the Company or the Agent, shall be affected by notice to the contrary.
(b) Notwithstanding the foregoing, with respect to any Global Certificate, nothing herein shall prevent the Company, the Agent or any agent of the Company or the Agent from giving effect to any written certification, proxy or other authorization furnished by any Clearing Agency (or its nominee), as a Holder, with respect to such Global Certificate or impair, as between such Clearing Agency and owners of beneficial interests in such Global Certificate, the operation of customary practices governing the exercise of rights of such Clearing Agency (or its nominee) as Holder of such Global Certificate. None of the Company, the Agent, or any agent of the Company or the Agent will have any responsibility or liability for any aspect of the records relating to or payments made on account of beneficial ownership interests in a Global Certificate or maintaining, supervising or reviewing any records relating to such beneficial ownership interests.
(a) All Certificates surrendered (i) for delivery of shares of Common Stock on or after any Settlement Date; (ii) upon the transfer of Notes, the appropriate Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, or Treasury Securities, as the case may be, after the occurrence of a Termination Event; or (iii) upon the registration of a transfer or exchange of Equity Units or Stripped Units, as the case may be, shall, if surrendered to any Person other than the Agent, be delivered to the Agent and, if not already cancelled, shall be promptly cancelled by it. The Company may at any time deliver to the Agent for cancellation any Certificates previously authenticated, executed and delivered hereunder which the Company may have acquired in any manner whatsoever, and all Certificates so delivered shall, upon Issuer Order, be promptly cancelled by the Agent. No Certificates shall be authenticated, executed on behalf of the Holder and delivered in lieu of or in exchange for any Certificates cancelled as provided in this Section, except as expressly permitted by this Agreement. All cancelled Certificates held by the Agent shall be disposed of by the Agent in accordance with its customary procedures.
(b) If the Company or any Affiliate of the Company shall acquire any Certificate, such acquisition shall not operate as a cancellation of such Certificate unless and until such Certificate is cancelled or delivered to the Agent for cancellation.
(a) Unless a successful remarketing or a Tax Event Redemption has occurred, a Holder may separate the Pledged Notes from the related Forward Purchase Contracts in respect of the Equity Units held by such Holder by substituting for such Pledged Notes Treasury Securities that will pay, on the Stock Purchase Date, an amount equal to the aggregate principal amount of such Notes (a "Collateral Substitution"), at any time from and after the date of this Agreement and on or prior to the tenth Business Day immediately preceding the Stock Purchase Date, by (i) depositing with the Collateral Agent Treasury Securities having an aggregate principal amount equal to the aggregate Stated Amount of such Equity Units, and (ii) transferring the related Equity Units to the Agent accompanied by a notice to the Agent, substantially in the form of Exhibit D hereto, stating that the Holder has transferred the relevant amount of Treasury Securities to the Collateral Agent and requesting that the Agent instruct the Collateral Agent to release the Pledged Notes underlying such Equity Units, whereupon the Agent shall promptly give such instruction to the Collateral Agent, substantially in the form of Exhibit C hereto. Notwithstanding the foregoing, a Holder may not separate the Pledged Notes from the related Forward Purchase Contracts in respect of the Equity Units held by such Holder during the periods beginning on the fourth Business Day prior to any Remarketing Period and ending on the third Business Day after the end of such Remarketing Period. Upon receipt of the Treasury Securities described in clause (i) above and the instruction described in clause (ii) above, in accordance with the terms of the Pledge Agreement, the Collateral Agent will release to the Agent, on behalf of the Holder, such Pledged Notes from the Pledge, free and clear of the Company's security interest therein, and upon receipt thereof the Agent shall promptly:
(i) cancel the related Equity Units;
(ii) transfer the Pledged Notes to the Holder; and
(iii)authenticate, execute on behalf of such Holder and deliver to such Holder a Stripped Units Certificate executed by the Company in accordance with Section 3.3 evidencing the same number of Forward Purchase Contracts as were evidenced by the cancelled Equity Units.
(b) Holders who elect to separate the Pledged Notes from the related Forward Purchase Contract and to substitute Treasury Securities for such Pledged Notes shall be responsible for any fees or expenses payable to the Collateral Agent for its services as Collateral Agent in respect of the substitution, and the Company shall not be responsible for any such fees or expenses.
(c) Holders may make Collateral Substitutions if Treasury Securities are being substituted for Pledged Notes, only in integral multiples of 20 Equity Units.
(d) In the event a Holder making a Collateral Substitution pursuant to this Section 3.13 fails to effect a book-entry transfer of the Equity Units or fails to deliver an Equity Units Certificate to the Agent after depositing Treasury Securities with the Collateral Agent, the Pledged Notes constituting a part of such Equity Units, and any distributions on such Pledged Notes shall be held in the name of the Agent or its nominee in trust for the benefit of such Holder, until such Equity Units are so transferred or the Equity Units Certificate is so delivered, as the case may be, or, with respect to an Equity Units Certificate, such Holder provides evidence satisfactory to the Company and the Agent that such Equity Units Certificate has been destroyed, lost or stolen, together with any indemnity that may be required by the Agent and the Company.
(e) Except as described in this Section 3.13, for so long as the Forward Purchase Contract underlying an Equity Unit remains in effect, such Equity Unit shall not be separable into its constituent parts, and the rights and obligations of the Holder of such Equity Unit in respect of the Note or the appropriate Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, as the case may be, and the Forward Purchase Contract comprising such Equity Unit may be acquired, and may be transferred and exchanged, only as an Equity Unit.
(a) Unless a successful remarketing or a Tax Event Redemption has occurred, a Holder of Stripped Units may reestablish Equity Units at any time from and after the date of this Agreement and on or prior to the tenth Business Day immediately preceding the Stock Purchase Date, by (i) depositing with the Collateral Agent the Notes then comprising such number of Equity Units as is equal to such Stripped Units and (ii) transferring such Stripped Units to the Agent accompanied by a notice to the Agent, substantially in the form of Exhibit D hereto, stating that the Holder has transferred the relevant amount of Notes to the Collateral Agent and requesting that the Agent instruct the Collateral Agent to release the Pledged Treasury Securities underlying such Stripped Units, whereupon the Agent shall promptly give such instruction to the Collateral Agent, substantially in the form of Exhibit C hereto. Notwithstanding the foregoing, a Holder may not reestablish Equity Units during the periods beginning on the fourth Business Day prior to any Remarketing Period and ending on the third Business Day after the end of such Remarketing Period. Upon receipt of the Notes described in clause (i) above and the instruction described in clause (ii) above, in accordance with the terms of the Pledge Agreement, the Collateral Agent will release to the Agent, on behalf of the Holder, such Pledged Treasury Securities from the Pledge, free and clear of the Company's security interest therein, and upon receipt thereof the Agent shall promptly:
(i) cancel the related Stripped Units;
(ii) transfer the Pledged Treasury Securities to the Holder; and
(iii)authenticate, execute on behalf of such Holder and deliver an Equity Units Certificate executed by the Company in accordance with Section 3.3 evidencing the same number of Forward Purchase Contracts as were evidenced by the cancelled Stripped Units.
(b) Holders of Stripped Units may reestablish Equity Units only in integral multiples of 20 Stripped Units for 20 Equity Units.
(c) Except as provided in this Section 3.14, for so long as the Forward Purchase Contract underlying a Stripped Unit remains in effect, such Stripped Unit shall not be separable into its constituent parts, and the rights and obligations of the Holder of such Stripped Unit in respect of the Treasury Security and Forward Purchase Contract comprising such Stripped Unit may be acquired, and may be transferred and exchanged, only as a Stripped Unit.
(d) Holders of Stripped Units who reestablish Equity Units shall be responsible for any fees or expenses payable to the Collateral Agent for its services as Collateral Agent in respect of the substitution, and the Company shall not be responsible for any such fees or expenses.
(e) In the event a Holder who reestablishes Equity Units pursuant to this Section 3.14 fails to effect a book-entry transfer of the Stripped Units or fails to deliver a Stripped Units Certificate to the Agent after depositing Pledged Notes with the Collateral Agent, the Treasury Securities constituting a part of such Stripped Units, and any distributions on such Treasury Securities shall be held in the name of the Agent or its nominee in trust for the benefit of such Holder, until such Stripped Units are so transferred or the Stripped Units Certificate is so delivered, as the case may be, or, with respect to a Stripped Units Certificate, such Holder provides evidence satisfactory to the Company and the Agent that such Stripped Units Certificate has been destroyed, lost or stolen, together with any indemnity that may be required by the Agent and the Company.
Upon the occurrence of a Termination Event and the transfer to the Agent by the Collateral Agent of the Notes, the appropriate Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, or the Treasury Securities, as the case may be, underlying the Equity Units or the Stripped Units, as the case may be, pursuant to the terms of the Pledge Agreement, the Agent shall request transfer instructions with respect to such Notes or the appropriate Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, or Treasury Securities, as the case may be, from each Holder by written request mailed to such Holder at its address as it appears in the Equity Units Register or the Stripped Units Register, as the case may be. Upon book-entry transfer of the Equity Units or Stripped Units or delivery of an Equity Units Certificate or Stripped Units Certificate to the Agent with such transfer instructions, the Agent shall transfer the Notes, the appropriate Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, or Treasury Securities, as the case may be, underlying such Equity Units or Stripped Units, as the case may be, to such Holder by book-entry transfer, or other appropriate procedures, in accordance with such instructions. In the event a Holder would be entitled to receive less than $1,000 principal amount at maturity of any Treasury security, the Agent shall dispose of such Treasury security for cash and deliver such cash to the Holder. In the event a Holder of Equity Units or Stripped Units fails to effect such transfer or delivery, the Notes, the appropriate Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio or Treasury Securities, as the case may be, underlying such Equity Units or Stripped Units, as the case may be, and any distributions thereon, shall be held in the name of the Agent or its nominee in trust for the benefit of such Holder, until (i) such Equity Units or Stripped Units are transferred or the Equity Units Certificate or Stripped Units Certificate is surrendered or such Holder provides satisfactory evidence that such Equity Units Certificate or Stripped Units Certificate has been destroyed, lost or stolen, together with any indemnity that may be required by the Agent and the Company; and (ii) the expiration of the time period specified in the abandoned property laws of the relevant State.
Each Holder of Equity Units or Stripped Units, as the case may be, by acceptance thereof, shall be deemed expressly to have withheld any consent to the assumption under Section 365 of the Bankruptcy Code or otherwise, of the Forward Purchase Contract by the Company, any receiver, liquidator or person or entity performing similar functions or its trustee in the event that the Company becomes the debtor under the Bankruptcy Code or subject to other similar state or federal law providing for reorganization or liquidation.
ARTICLE IV.
THE NOTES
(a) A payment on any Note, Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, as the case may be, which is paid on any Payment Date other than a Payment Date with respect to the Stated Amount due on Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio shall, subject to receipt thereof by the Agent from the Collateral Agent (if the Collateral Agent is the registered owner thereof) as provided by the terms of the Pledge Agreement, be paid to the Person in whose name the Equity Units Certificate (or one or more Predecessor Equity Units Certificates) of which such Note or the appropriate Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, as the case may be, is a part is registered at the close of business on the Record Date for such Payment Date.
(b) Each Equity Units Certificate evidencing Notes delivered under this Agreement upon registration of transfer of or in exchange for or in lieu of any other Equity Units Certificate shall carry the rights to interest accrued and unpaid which were carried by the Notes and Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, as the case may be, underlying such other Equity Units Certificate.
(c) In the case of any Equity Units with respect to which Early Settlement of the underlying Forward Purchase Contract is effected on an Early Settlement Date, Merger Early Settlement of the underlying Forward Purchase Contract is effected on a Merger Early Settlement Date, Cash Settlement is effected on the seventh Business Day immediately preceding the Stock Purchase Date, or a Collateral Substitution is effected, in each case on a date that is after any Record Date and on or prior to the next succeeding Payment Date, payments on the Note or the appropriate Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, as the case may be, underlying such Equity Units otherwise payable on such Payment Date shall be payable on such Payment Date notwithstanding such Early Settlement, Merger Early Settlement, Cash Settlement or Collateral Substitution, as the case may be, and such payments shall, subject to receipt thereof by the Agent, be payable to the Person in whose name the Equity Units Certificate (or one or more Predecessor Equity Units Certificates) was registered at the close of business on the Record Date. Except as otherwise expressly provided in the immediately preceding sentence, in the case of any Equity Units with respect to which Early Settlement, Merger Early Settlement or Cash Settlement of the underlying Forward Purchase Contract is effected, or with respect to which a Collateral Substitution has been effected, payments on the related Notes or payments on the appropriate Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, as the case may be, that would otherwise be payable after the applicable Settlement Date or after such Collateral Substitution, as the case may be, shall not be payable hereunder to the Holder of such Equity Units; provided, that to the extent that such Holder continues to hold the Separate Notes that formerly comprised a part of such Holder's Equity Units, such Holder shall be entitled to receive the payments on such Separate Notes.
Under the terms of the Pledge Agreement, the Agent will be entitled to exercise the voting and any other consensual rights pertaining to the Pledged Notes but only to the extent instructed by the Holders as described below. Upon receipt of notice of any meeting at which holders of Notes are entitled to vote or upon any solicitation of consents, waivers or proxies of holders of Notes, the Agent shall, as soon as practicable thereafter, mail to the Holders of Equity Units a notice (a) containing such information as is contained in the notice or solicitation, (b) stating that each Holder on the record date set by the Agent therefor (which, to the extent possible, shall be the same date as the record date for determining the holders of Notes entitled to vote) shall be entitled to instruct the Agent as to the exercise of the voting rights pertaining to the Pledged Notes underlying their Equity Units and (c) stating the manner in which such instructions may be given. Upon the written request of the Holders of Equity Units on such record date, the Agent shall endeavor insofar as practicable to vote or cause to be voted, in accordance with the instructions set forth in such requests, the maximum number of Pledged Notes as to which any particular voting instructions are received. In the absence of specific instructions from the Holder of an Equity Unit, the Agent shall abstain from voting the Pledged Note underlying such Equity Units. The Company hereby agrees, if applicable, to solicit Holders of Equity Units to timely instruct the Agent in order to enable the Agent to vote such Pledged Notes.
Upon the occurrence of a Tax Event Redemption prior to the earlier of a successful remarketing of the Notes or the Stock Purchase Date, the Company may elect to instruct in writing the Collateral Agent to apply, and upon such written instruction, the Collateral Agent shall apply, out of the aggregate Redemption Price for the Notes that are components of Equity Units, an amount equal to the aggregate Redemption Amount for the Notes that are components of Equity Units to purchase on behalf of the Holders of Equity Units the Treasury Portfolio and promptly remit the remaining portion of such aggregate Redemption Price to the Agent for payment to the Holders of such Equity Units. The Treasury Portfolio will be substituted for the Pledged Notes, and will be pledged to the Collateral Agent in accordance with the terms of the Pledge Agreement to secure the obligation of each Holder of an Equity Units to purchase the Common Stock under the Forward Purchase Contract constituting a part of such Equity Units. Following the occurrence of a Tax Event Redemption prior to the earlier of a successful remarketing of the Notes or the Stock Purchase Date, the Holders of Equity Units and the Collateral Agent shall have such security interests, rights and obligations with respect to the Treasury Portfolio as the Holder of Equity Units and the Collateral Agent had in respect of the Notes, as the case may be, subject to the Pledge thereof as provided in Articles II, III, IV, V and VI of the Pledge Agreement, and any reference herein or in the Certificates to the Note shall be deemed to be a reference to such Treasury Portfolio and any reference herein or in the Certificates to interest on the Notes shall be deemed to be a reference to corresponding distributions on the Treasury Portfolio. The Company may cause to be made in any Equity Units Certificates thereafter to be issued such change in phraseology and form (but not in substance) as may be appropriate to reflect the substitution of the Treasury Portfolio for Notes as collateral.
The Company shall cause notice of any Tax Event Redemption to be mailed, at least 30 calendar days but not more than 60 calendar days before such Tax Event Redemption Date, to each Holder of Equity Units including Notes to be redeemed at its registered address.
Upon the occurrence of a Tax Event Redemption after the earlier of a successful remarketing of the Notes or the Stock Purchase Date, the Redemption Price will be payable in cash to the holders of the Notes.
ARTICLE V.
THE FORWARD PURCHASE CONTRACTS; THE REMARKETING
(a) Each Forward Purchase Contract shall, unless an Early Settlement has occurred in accordance with Section 5.9, or a Merger Early Settlement has occurred in accordance with Section 5.10, obligate the Holder of the related Equity Units or Stripped Units, as the case may be, to purchase, and the Company to sell, on the Stock Purchase Date at a price equal to $50 (the "Purchase Price"), a number of newly issued shares of Common Stock equal to the Settlement Rate unless, on or prior to the Stock Purchase Date, there shall have occurred a Termination Event with respect to the Units of which such Forward Purchase Contract is a part. The "Settlement Rate" is equal to,
(i) if the Applicable Market Value (as defined below) is greater than or equal to $49.08 (the "Threshold Appreciation Price"), 1.0187 shares of Common Stock per Forward Purchase Contract,
(ii) if the Applicable Market Value is less than the Threshold Appreciation Price, but is greater than $40.90, the number of shares of Common Stock per Forward Purchase Contract equal to $50 divided by the Applicable Market Value, and
(iii)if the Applicable Market Value is equal to or less than $40.90, 1.2225 shares of Common Stock per Forward Purchase Contract,
in each case subject to adjustment as provided in Section 5.6 and in each case rounded upward or downward to the nearest 1/10,000th of a share.
As provided in Section 5.12, no fractional shares of Common Stock will be issued upon settlement of Forward Purchase Contracts.
Promptly after the calculation of the Settlement Rate and the Applicable Market Value, the Company shall give the Agent notice thereof. All calculations and determinations of the Settlement Rate and the Applicable Market Value shall be made by the Company or its agents based on their good faith calculations, and the Agent shall have no responsibility with respect thereto.
(b) The "Applicable Market Value" means the average of the Closing Price per share of Common Stock on each of the 20 consecutive Trading Days ending on the third Trading Day immediately preceding the Stock Purchase Date. The "Closing Price" of the Common Stock on any date of determination means the closing sale price (or, if no closing price is reported, the last reported sale price) of the Common Stock on the New York Stock Exchange (the "NYSE") on such date or, if the Common Stock is not listed for trading on the NYSE on any such date, as reported in the composite transactions for the principal United States securities exchange on which the Common Stock is so listed, or if the Common Stock is not so listed on a United States national or regional securities exchange, as reported by The NASDAQ Stock Market, or, if the Common Stock is not so reported, the last quoted bid price for the Common Stock in the over-the-counter market as reported by the National Quotation Bureau or similar organization, or, if such bid price is not available, the market value of the Common Stock on such date as determined by a nationally recognized independent investment banking firm retained for this purpose by the Company. A "Trading Day" means a day on which the Common Stock (A) is not suspended from trading on any national or regional securities exchange or association or over-the-counter market at the close of business and (B) has traded at least once on the national or regional securities exchange or association or over-the-counter market that is the primary market for the trading of the Common Stock.
(c) Each Holder of Equity Units or Stripped Units, as the case may be, by its acceptance thereof, irrevocably authorizes the Agent to enter into and perform the related Forward Purchase Contract on its behalf as its attorney-in-fact (including the execution of Certificates on behalf of such Holder), agrees to be bound by the terms and provisions thereof, covenants and agrees to perform its obligations under such Forward Purchase Contracts, and consents to the provisions hereof, irrevocably authorizes the Agent as its attorney-in-fact to enter into and perform the Pledge Agreement on its behalf as its attorney-in-fact, and consents to and agrees to be bound by the Pledge of the Notes, the appropriate Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, or the Treasury Securities pursuant to the Pledge Agreement; provided that upon a Termination Event, the rights of the Holder of such Equity Units or Stripped Units, as the case may be, under the Forward Purchase Contract may be enforced without regard to any other rights or obligations. Each Holder of Equity Units or Stripped Units, as the case may be, by its acceptance thereof, further covenants and agrees that, to the extent and in the manner provided in Section 5.4 and the Pledge Agreement, but subject to the terms thereof, payments in respect of the Notes, the appropriate Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, or the Treasury Securities, to be paid upon settlement of such Holder's obligations to purchase Common Stock under the Forward Purchase Contract, shall be paid on the Stock Purchase Date by the Collateral Agent to the Company in satisfaction of such Holder's obligations under such Forward Purchase Contract and such Holder shall acquire no right, title or interest in such payment.
(d) Upon registration of transfer of a Certificate, the transferee shall be bound (without the necessity of any other action on the part of such transferee) under the terms of this Agreement, the Forward Purchase Contracts underlying such Certificate and the Pledge Agreement, and the transferor shall be released from the obligations under this Agreement, the Forward Purchase Contracts underlying the Certificates so transferred and the Pledge Agreement. The Company covenants and agrees, and each Holder of a Certificate, by its acceptance thereof, likewise covenants and agrees, to be bound by the provisions of this paragraph.
(a) Contract Adjustment Payments shall accrue on each Forward Purchase Contract constituting a part of an Equity Unit or Stripped Unit at 3.50% per year of the Stated Amount of such Equity Unit or Stripped Unit, from June 11, 2002 through and including the Stock Purchase Date, provided that no Contract Adjustment Payment shall accrue after an Early Settlement or Merger Early Settlement. Subject to Section 5.3 herein, the Company shall pay, on each Payment Date, the Contract Adjustment Payments, if any, payable in respect of each Forward Purchase Contract to the Person in whose name a Certificate (or one or more Predecessor Certificates) is registered at the close of business on the Record Date immediately preceding such Payment Date in such coin or currency of the United States as at the time of payment shall be legal tender for payments. The Contract Adjustment Payments, if any, will be payable at the office in New York, New York, maintained for that purpose or, at the option of the Company, by check mailed to the address of the Person entitled thereto at such Person's address as it appears on the Register or by wire transfer to the account designated to the Agent by a prior written notice by such Person delivered at least five Business Days prior to the applicable Payment Date.
(b) Upon the occurrence of a Termination Event, the Company's obligation to pay Contract Adjustment Payments (including any accrued Deferred Contract Adjustment Payments), if any, shall cease.
(c) Each Certificate delivered under this Agreement upon registration of transfer of or in exchange for or in lieu of (including as a result of a Collateral Substitution or the re-establishment of an Equity Unit) any other Certificate shall carry the rights to Contract Adjustment Payments, if any, accrued and unpaid, and to accrue Contract Adjustment Payments, if any, which were carried by the Forward Purchase Contracts underlying such other Certificates.
(d) Subject to Sections 5.9 and 5.10, in the case of any Equity Units or Stripped Units, as the case may be, with respect to which Early Settlement or Merger Early Settlement of the underlying Forward Purchase Contract is effected on an Early Settlement Date or a Merger Early Settlement Date, respectively, or in respect of which Cash Settlement of the underlying Forward Purchase Contract is effected on the seventh Business Day immediately preceding the Stock Purchase Date, or with respect to which a Collateral Substitution or an establishment or re-establishment of an Equity Units pursuant to Section 3.14 is effected, in each case on a date that is after any Record Date and on or prior to the next succeeding Payment Date, Contract Adjustment Payments on the Forward Purchase Contract underlying such Equity Units or Stripped Units, as the case may be, otherwise payable on such Payment Date shall be payable on such Payment Date notwithstanding such Cash Settlement, Early Settlement, Merger Early Settlement, Collateral Substitution or establishment or re-establishment of Equity Units, and such Contract Adjustment Payments shall be paid to the Person in whose name the Certificate evidencing such Equity Units or Stripped Units (or one or more Predecessor Certificates) is registered at the close of business on such Record Date. Except as otherwise expressly provided in the immediately preceding sentence, in the case of any Equity Units or Stripped Units with respect to which Cash Settlement, Early Settlement, Merger Early Settlement of the underlying Forward Purchase Contract is effected on the seventh Business Day immediately preceding the Stock Purchase Date, an Early Settlement Date or Merger Early Settlement Date, as the case may be, or with respect to which a Collateral Substitution or an establishment or re-establishment of an Equity Unit has been effected, Contract Adjustment Payments, if any, that would otherwise be payable after the Early Settlement Date, or Merger Early Settlement Date, Collateral Substitution or such establishment or re-establishment with respect to such Forward Purchase Contract shall not be payable.
(a) The Company shall have the right, at any time prior to the Stock
Purchase Date, to defer the payment of any or all of the Contract
Adjustment Payments otherwise payable on any Payment Date, but only if the
Company shall give the Holders and the Agent written notice of its election
to defer each such deferred Contract Adjustment Payment (specifying the
amount to be deferred) at least ten Business Days prior to the earlier of
(i) the next succeeding Payment Date or (ii) the date the Company is
required to give notice of the Record Date or Payment Date with respect to
payment of such Contract Adjustment Payments to the NYSE or other
applicable self-regulatory organization or to Holders of the Equity Units
and Stripped Units, but in any event not less than one Business Day prior
to such Record Date. Any Contract Adjustment Payments so deferred shall, to
the extent permitted by law, bear additional Contract Adjustment Payments
thereon at the rate of 5.75% per year (computed on the basis of a 360-day
year of twelve 30-day months), compounding on each succeeding Payment Date,
until paid in full (such deferred installments of Contract Adjustment
Payments, if any, together with the additional Contract Adjustment Payments
accrued thereon, being referred to herein as the "Deferred Contract
Adjustment Payments"). Deferred Contract Adjustment Payments, if any, shall
be due on the next succeeding Payment Date except to the extent that
payment is deferred pursuant to this Section 5.3. No Contract Adjustment
Payments may be deferred to a date that is after the Stock Purchase Date
and no such deferral period may end other than on a Payment Date. If the
Forward Purchase Contracts are terminated upon the occurrence of a
Termination Event, the Holder's right to receive Contract Adjustment
Payments, if any, and Deferred Contract Adjustment Payments, will
terminate. If Deferred Contract Adjustment Payments are deferred until the
Stock Purchase Date, all payments in respect thereof shall be made in cash
on the Stock Purchase Date.
(b) In the event that the Company elects to defer the payment of Contract Adjustment Payments on the Forward Purchase Contracts until a Payment Date prior to the Stock Purchase Date, then all Deferred Contract Adjustment Payments, if any, shall be payable to the registered Holders as of the close of business on the Record Date immediately preceding such Payment Date.
(c) In the event the Company exercises its option to defer the payment of Contract Adjustment Payments then, until the Deferred Contract Adjustment Payments have been paid, the Company shall not declare or pay dividends on, make distributions with respect to, or redeem, purchase or acquire, or make a liquidation payment with respect to, any of the Company's Common Stock other than:
(i) purchases, redemptions or acquisitions of shares of Common Stock in connection with any employment contract, benefit plan or other similar arrangement with or for the benefit of employees, officers or directors or a stock purchase or dividend reinvestment plan, or the satisfaction by the Company of its obligations pursuant to any contract or security outstanding on the date the Company exercises its right to defer the Contract Adjustment Payments;
(ii) as a result of a reclassification of the Company's Capital Stock or the exchange or conversion of one class or series of the Company's Capital Stock for another class or series of the Company's Capital Stock;
(iii)the purchase of fractional interests of the Common Stock pursuant to the conversion or exchange provisions of such Common Stock or the security being converted or exchanged;
(iv) dividends or distributions in any series of the Company's Common Stock (or rights to acquire Common Stock) or repurchases, acquisitions or redemptions of Common Stock in connection with the issuance or exchange of the Common Stock (or securities convertible into or exchangeable for shares of the Company's Common Stock); or
(v) redemptions, exchanges or repurchases of any rights outstanding under a shareholder rights plan or the declaration or payment thereunder of a dividend or distribution of or with respect to rights in the future.
(a) Unless a Tax Event Redemption, successful remarketing, Termination Event, Merger Early Settlement or Early Settlement has occurred, each Holder of an Equity Unit may pay in cash ("Cash Settlement") the Purchase Price for the shares of Common Stock to be purchased pursuant to a Forward Purchase Contract if such Holder notifies the Agent by use of a notice in substantially the form of Exhibit E hereto of its intention to make a Cash Settlement. Such notice shall be made on or prior to 5:00 p.m., New York City time, on the tenth Business Day immediately preceding the Stock Purchase Date. The Agent shall promptly notify the Collateral Agent of the receipt of such a notice from a Holder intending to make a Cash Settlement.
(i) A Holder of an Equity Unit who has so notified the Agent of
its intention to make a Cash Settlement is required to pay
the Purchase Price to the Collateral Agent prior to 11:00
a.m., New York City time, on the seventh Business Day
immediately preceding the Stock Purchase Date in lawful
money of the United States by certified or cashiers' check
or wire transfer, in each case payable to or upon the order
of the Company. Any cash received by the Collateral Agent
will be paid to the Company on the Stock Purchase Date in
settlement of the Forward Purchase Contract in accordance
with the terms of this Agreement and the Pledge Agreement.
(ii) If a Holder of an Equity Unit fails to notify the Agent of
its intention to make a Cash Settlement in accordance with
this paragraph (a), the Holder shall be deemed to have
consented to the disposition of the Pledged Notes pursuant
to the remarketing as described in paragraph 5.4(b) below.
If a Holder of an Equity Unit does notify the Agent as
provided in this paragraph (a) of its intention to pay the
Purchase Price in cash, but fails to make such payment as
required by paragraph (a)(i) above, the Holder shall be
deemed to have consented to the disposition of the Pledged
Notes pursuant to the remarketing as described in paragraph
5.4 (b) below.
(b) The Company has engaged the Remarketing Agent to sell the Notes of
(A) Holders of Equity Units, other than Holders that have elected not to
participate in the remarketing pursuant to the procedures set forth in
subsection (g) below, and (B) holders of Separate Notes that have elected
to participate in the remarketing pursuant to the procedures set forth in
Section 4.5(d) of the Pledge Agreement. On the seventh Business Day prior
to the Remarketing Date, the Agent shall give Holders of Equity Units and
holders of Separate Notes notice of the remarketing (the form of which
notice to be provided by the Company) in a daily newspaper in the English
language of general circulation in The City of New York, which is expected
to be The Wall Street Journal, including the specific U.S. Treasury
security or securities (including the CUSIP number and/or the principal
terms of such Treasury security or securities) described in subsection (g)
below, that must be delivered by Holders of Equity Units that elect not to
participate in the remarketing pursuant to subsection (g) below, no later
than 10:00 a.m., New York City time, on the fourth Business Day preceding
the Remarketing Date or the first day of any Subsequent Remarketing Period,
as applicable. The Agent shall notify, by 10:00 a.m., New York City time,
on the third Business Day preceding the Remarketing Date or the first day
of any subsequent Remarketing Period, as applicable, the Remarketing Agent
and the Collateral Agent of the aggregate number of Notes of Equity Units
Holders to be remarketed. On the third Business Day immediately preceding
the Remarketing Date or the first day of any subsequent Remarketing Period,
as applicable, no later than by 10:00 a.m. New York City time, pursuant to
the terms of the Pledge Agreement, the Custodial Agent will notify the
Remarketing Agent of the aggregate number of Separate Notes to be
remarketed. On the third Business Day immediately preceding the Remarketing
Date or the first day of any subsequent Remarketing Period, as applicable,
the Collateral Agent and the Custodial Agent, pursuant to the terms of the
Pledge Agreement, will deliver for remarketing to the Remarketing Agent all
Notes to be remarketed.
(c) Upon receipt of such notice from the Agent and the Custodial Agent and such Notes from the Collateral Agent and the Custodial Agent, the Remarketing Agent will, on the Remarketing Date, use its commercially reasonable best efforts to (i) establish a rate of interest that, in the opinion of the Remarketing Agent, will, when applied to the outstanding Notes, enable the then current aggregate market value of the Notes to have a value equal to approximately, but not less than, 100.25% of the Remarketing Value as of the Remarketing Date or as of any Subsequent Remarketing Date, as the case may be (the "Reset Rate") and (ii) sell such Notes on such date at a price equal to approximately, but not less than, 100.25% of the Remarketing Value.
(d) If the remarketing occurs prior to the fourth Business Day
preceding the Stock Purchase Date, the Remarketing Agent will use the
proceeds from a successful remarketing to purchase the appropriate U.S.
Treasury securities (the "Agent-purchased Treasury Consideration") with the
CUSIP numbers, if any, selected by the Remarketing Agent, described in
clauses (1) and (2) of the definition of Remarketing Value related to the
Notes of Holders of Equity Units or that were remarketed. On or prior to
the third Business Day following the Remarketing Date or any Subsequent
Remarketing Date the Remarketing Agent shall deliver such Agent-purchased
Treasury Consideration to the Agent, which shall thereupon deliver such
Agent-purchased Treasury Consideration to the Collateral Agent. The
Collateral Agent, for the benefit of the Company, will thereupon apply such
Agent-purchased Treasury Consideration, in accordance with the Pledge
Agreement, to secure such Holders' obligations under the Forward Purchase
Contracts. If the remarketing occurs on or after the fourth Business Day
preceding the Stock Purchase Date, the proceeds of the remarketing will not
be used to purchase the Agent-purchased Treasury Consideration, but such
proceeds will be paid to the Agent in direct settlement of the obligations
of the Holders under the related Forward Purchase Contracts to purchase
Common Stock of the Company. The Remarketing Agent will deduct as a
remarketing fee an amount not exceeding 25 basis points (0.25%) of the
total proceeds from the remarketing (the "Remarketing Fee"). The
Remarketing Agent will remit (1) the remaining portion of the proceeds from
the remarketing attributable to the Separate Notes to the Custodial Agent
for the benefit of the holders of Separate Notes that were remarketed and
(2) the remaining portion of the proceeds, less those proceeds used to
purchase the Agent-purchased Treasury Consideration or to pay the Company
in direct settlement of the Holders' obligations under the Forward Purchase
Contracts, to the Agent for payment to the Holders of the Equity Units that
were remarketed, all determined on a pro rata basis, in each case, on or
prior to the third Business Day following such Remarketing Date or
Subsequent Remarketing Date. Holders whose Notes are so remarketed will not
otherwise be responsible for the payment of any Remarketing Fee in
connection therewith.
(e)
(i) If, in spite of using its commercially reasonable best efforts, the Remarketing Agent cannot establish the Reset Rate and remarket the Notes included in the remarketing at a price equal to approximately, but not less than, 100.25% of the Remarketing Value, the Remarketing Agent will again attempt to establish the Reset Rate and remarket the Notes included in the remarketing at a price equal to approximately, but not less than, 100.25% of the Remarketing Value on each of the two immediately following Business Days. If the Remarketing Agent cannot remarket the Notes included in the remarketing at a price equal to approximately, but not less than, 100.25% of the Remarketing Value on either of those days, it will attempt to establish the Reset Rate and remarket the Notes included in the remarketing at a price equal to approximately, but not less than, 100.25% of the Remarketing Value on each of the three Business Days immediately preceding June 16, 2005. If the Remarketing Agent cannot remarket the Notes included in the remarketing at a price equal to approximately, but not less than, 100.25% of the Remarketing Value on any of those days, it will attempt to establish the Reset Rate and remarket the Notes included in the remarketing at a price equal to approximately, but not less than, 100.25% of the Remarketing Value on each of the three Business Days immediately preceding July 16, 2005. If the Remarketing Agent cannot establish the Reset Rate and remarket the Notes included in the remarketing at a price equal to approximately, but not less than, 100.25% of the Remarketing Value either on any of the two Business Days immediately following the Remarketing Date or on any of the three Business Days immediately preceding June 16, 2005 or on any of the three Business Days immediately preceding July 16, 2005, the remarketing in each period will be deemed to have failed (each, a "Failed Remarketing"). If the Remarketing Agent cannot establish the Reset Rate and remarket the Notes included in the remarketing at a price equal to approximately, but not less than, 100.25% of the Remarketing Value on any of the three Business Days immediately preceding July 16, 2005, the Remarketing Agent will further attempt to establish the Reset Rate and remarket the Notes included in the remarketing at a price equal to approximately, but not less than, 100.25% of the Remarketing Value on each of the three Business Days immediately preceding August 12, 2005. If, in spite of using its commercially reasonable best efforts, the Remarketing Agent fails to remarket the Notes underlying the Equity Units at a price equal to approximately, but not less than, 100.25% of the Remarketing Value in accordance with the terms of the Pledge Agreement by 4:00 p.m., New York City time, on the third Business Day immediately preceding the Stock Purchase Date, a "Last Failed Remarketing" will be deemed to have occurred.
(ii) Within three Business Days following the end of the Last Failed Remarketing, the Remarketing Agent shall return any Notes delivered to it to the Collateral Agent and the Custodial Agent, as applicable, together with written notice from the Remarketing Agent of such Last Failed Remarketing. The Collateral Agent, for the benefit of the Company, may exercise its rights as a secured party with respect to such Notes, including those actions specified in Section 5.4(f) below, and the Holders of Equity Units, by their acceptance of the Equity Units shall be deemed to have agreed to such exercise by the Collateral Agent in such case; provided, that if upon the Last Failed Remarketing, the Collateral Agent delivers any Notes to the Company in full satisfaction of the Holder's obligation under the related Forward Purchase Contracts, any accumulated and unpaid interest on such Notes will become payable by the Company to the Agent for payment to the Holder of the Equity Units to which such Notes relate. Such payment will be made by the Company on or prior to 11:00 a.m., New York City time, on the Stock Purchase Date in lawful money of the United States by certified or cashier's check or wire transfer in immediately available funds payable to or upon the order of the Agent. The Company will publish notice by means of Bloomberg and Reuters newswires of any Remarketing Period during which no successful remarketing occurred, such notice to be published not later than the fourth Business Day following the end of such Remarketing Period. The Company will also cause a notice of the Last Failed Remarketing to be published on the fourth Business Day following the date of the Last Failed Remarketing in a daily newspaper in the English language of general circulation in The City of New York, which is expected to be The Wall Street Journal.
(f) With respect to any Notes which constitute part of Equity Units which are subject to the Last Failed Remarketing, the Collateral Agent for the benefit of the Company reserves all of its rights as a secured party with respect thereto and, subject to applicable law and Section 5.4 (j) below, may, among other things, permit the Company to cause the Notes to be sold or to retain and cancel such Notes, in either case, in full satisfaction of the Holders' obligations under the Forward Purchase Contracts and the Holders of the Equity Units, by their acceptance of the Equity Units shall be deemed to have agreed to such action by the Collateral Agent.
(g) A Holder of Equity Units may elect not to participate in the remarketing and retain the Notes underlying such Equity Units by notifying the Agent of such election and delivering the specific U.S. Treasury security or securities (including the CUSIP number and/or the principal terms of such security or securities) identified by the Agent that constitute the U.S. Treasury securities described in clauses (1) and (2) of the definition of Remarketing Value relating to the retained Notes (as if only such Notes were being remarketed) (the "Opt-out Treasury Consideration") to the Agent not later than 10:00 a.m. on the fourth Business Day prior to the Remarketing Date (or, in the case of a Failed Remarketing, not later than 10:00 a.m. on the fourth Business Day immediately prior to the subsequent Remarketing Period). Upon receipt thereof by the Agent, the Agent shall deliver such Opt-out Treasury Consideration to the Collateral Agent, which will, for the benefit of the Company, thereupon apply such Opt-out Treasury Consideration to secure such Holder's obligations under the Forward Purchase Contracts. On the first Business Day immediately preceding the Remarketing Date (or, in the case of a Failed Remarketing, the subsequent Remarketing Period), the Collateral Agent, pursuant to the terms of the Pledge Agreement, will deliver the Pledged Notes of such Holder to the Agent. Within three Business Days following any Remarketing Period, (A) if the remarketing was successful, the Agent shall distribute such Notes to the new holders thereof, and (B) if there was a Failed Remarketing, the Agent will deliver such Notes to the Collateral Agent, which will, for the benefit of the Company, thereupon apply such Notes to secure such Holders' obligations under the Forward Purchase Contracts and return the Opt-out Treasury Consideration delivered by such Holders to such Holders. A Holder that does not so deliver the Opt-out Treasury Consideration pursuant to this clause (g) shall be deemed to have elected to participate in the remarketing.
(h) Upon the maturity of the Pledged Treasury Securities underlying the Stripped Units and the Pledged Treasury Consideration or Pledged Applicable Ownership Interest in the Treasury Portfolio, as the case may be, underlying the Equity Units, on the Stock Purchase Date, the Collateral Agent shall remit to the Company an amount equal to the aggregate Purchase Price applicable to such Units, as payment for the Common Stock issuable upon settlement thereof without receiving any instructions from the Holders of such Units. In the event the payments in respect of the Pledged Treasury Securities, Pledged Treasury Consideration or Pledged Applicable Ownership Interest in the Treasury Portfolio underlying a Unit are in excess of the Purchase Price under the Forward Purchase Contract being settled thereby, the Collateral Agent will distribute such excess to the Agent for the benefit of the Holder of such Units when received.
(i) Any distribution to Holders of excess funds and interest described in Section 5.4(c) and (d) above shall be payable at the Office of the Agent in The City of New York maintained for that purpose or, at the option of the Holder or the holder of Separate Notes, as applicable, by check mailed to the address of the Person entitled thereto at such address as it appears on the relevant Register or by wire transfer to an account specified by the Holder or the holder of Separate Notes, as applicable.
(j) The obligations of each Holder to pay the Purchase Price are non-recourse obligations and except to the extent paid by Cash Settlement, Early Settlement or Merger Early Settlement, are payable solely out of the proceeds of any Collateral pledged to secure the obligations of the Holder, and in no event will any Holder be liable for any deficiency between such proceeds and the Purchase Price.
(k) Notwithstanding anything to the contrary herein, the Company shall not be obligated to issue any Common Stock in respect of a Forward Purchase Contract or deliver any certificates therefor to the Holder of the related Equity Units or Stripped Units, as the case may be, unless the Company shall have received payment in full for the shares of Common Stock to be purchased thereunder by such Holder in the manner herein set forth.
(l) In the event of a successful remarketing, the interest rate on all of the outstanding Notes (whether or not included in the remarketing) shall be adjusted to the Reset Rate.
Unless a Termination Event shall have occurred on or prior to the Stock Purchase Date or an Early Settlement or a Merger Early Settlement shall have occurred with respect to all of the outstanding Units, on the Stock Purchase Date, upon its receipt of payment for the shares of Common Stock purchased by the Holders pursuant to the provisions of this Article and subject to Section 5.4, the Company shall issue and deposit with the Agent, for the benefit of the Holders of the Outstanding Units, one or more certificates or book-entry interests representing the newly issued shares of Common Stock registered in the name of the Agent (or its nominee) as custodian for the Holders (such certificates or book-entry interests for shares of Common Stock, together with any dividends or distributions for which a record date and payment date for such dividend or distribution has occurred after the Stock Purchase Date, being hereinafter referred to as the "Forward Purchase Contract Settlement Fund") to which the Holders are entitled hereunder. Subject to the foregoing, upon surrender of a Certificate to the Agent on or after the Stock Purchase Date, together with settlement instructions thereon duly completed and executed, the Holder of such Certificate shall be entitled to receive in exchange therefor a certificate or book-entry interest representing that number of whole shares of Common Stock which such Holder is entitled to receive pursuant to the provisions of this Article V (after taking into account all Equity Units and Stripped Units then held by such Holder) together with cash in lieu of fractional shares as provided in Section 5.12 and any dividends or distributions with respect to such shares constituting part of the Forward Purchase Contract Settlement Fund, but without any interest thereon, and the Certificate so surrendered shall forthwith be cancelled. Such shares shall be registered in the name of the Holder or the Holder's designee as specified in the settlement instructions provided by the Holder to the Agent. If any shares of Common Stock issued in respect of a Forward Purchase Contract are to be registered to a Person other than the Person in whose name the Certificate evidencing such Forward Purchase Contract is registered, no such registration shall be made unless the Person requesting such registration has paid any transfer and other taxes required by reason of such registration in a name other than that of the registered Holder of such Certificate or has established to the satisfaction of the Company that such tax either has been paid or is not payable.
(a) Adjustments for Dividends, Distributions, Stock Splits, Etc.
(1) Stock Dividends. In case the Company shall pay or make a dividend or other distribution on the Common Stock in Common Stock, the Settlement Rate or Early Settlement Rate, as applicable, as in effect at the opening of business on the day following the date fixed for the determination of stockholders entitled to receive such dividend or other distribution shall be increased by dividing such Settlement Rate or Early Settlement Rate by a fraction of which the numerator shall be the number of shares of Common Stock outstanding at the close of business on the date fixed for such determination and the denominator shall be the sum of such number of shares and the total number of shares constituting such dividend or other distribution, such increase to become effective immediately after the opening of business on the day following the date fixed for such determination. For the purposes of this paragraph (1), the number of shares of Common Stock at the time outstanding shall not include shares held in the treasury of the Company but shall include any shares issuable in respect of any scrip certificates issued in lieu of fractions of shares of Common Stock. The Company will not pay any dividend or make any distribution on shares of Common Stock held in the treasury of the Company.
(2) Stock Purchase Rights. In case the Company shall issue
rights, options or warrants to all holders of its Common Stock (not
being available on an equivalent basis to Holders of the Equity Units
and Stripped Units upon settlement of the Forward Purchase Contracts
underlying such Equity Units and Stripped Units) entitling them to
subscribe for or purchase shares of Common Stock at a price per share
less than the Current Market Price per share of the Common Stock on
the date fixed for the determination of stockholders entitled to
receive such rights, options or warrants (other than pursuant to a
dividend reinvestment, share purchase or similar plan), the Settlement
Rate or Early Settlement Rate, as applicable, in effect at the opening
of business on the day following the date fixed for such determination
shall be increased by dividing such Settlement Rate or Early
Settlement Rate, as applicable, by a fraction, the numerator of which
shall be the number of shares of Common Stock outstanding at the close
of business on the date fixed for such determination plus the number
of shares of Common Stock which the aggregate of the offering price of
the total number of shares of Common Stock so offered for subscription
or purchase would purchase at such Current Market Price and the
denominator of which shall be the number of shares of Common Stock
outstanding at the close of business on the date fixed for such
determination plus the number of shares of Common Stock so offered for
subscription or purchase, such increase to become effective
immediately after the opening of business on the day following the
date fixed for such determination. For the purposes of this paragraph
(2), the number of shares of Common Stock at any time outstanding
shall not include shares held in the treasury of the Company but shall
include any shares issuable in respect of any scrip certificates
issued in lieu of fractions of shares of Common Stock. The Company
shall not issue any such rights, options or warrants in respect of
shares of Common Stock held in the treasury of the Company.
(3) Stock Splits; Reverse Splits. In case outstanding shares of Common Stock shall be subdivided or split into a greater number of shares of Common Stock, the Settlement Rate or Early Settlement Rate, as applicable, in effect at the opening of business on the day following the day upon which such subdivision or split becomes effective shall be proportionately increased, and, conversely, in case outstanding shares of Common Stock shall be combined into a smaller number of shares of Common Stock, the Settlement Rate or Early Settlement Rate, as applicable, in effect at the opening of business on the day following the day upon which such combination becomes effective shall be proportionately reduced, such increase or reduction, as the case may be, to become effective immediately after the opening of business on the day following the day upon which such subdivision, split or combination becomes effective.
(4) Debt or Asset Distributions.
(i) In case the Company shall, by dividend or otherwise,
distribute to all holders of its Common Stock evidences of
its indebtedness or assets (including securities, but
excluding any rights or warrants referred to in paragraph
(2) of this Section, any dividend or distribution paid
exclusively in cash and any dividend, shares of capital
stock of any class or series, or similar equity interests,
of or relating to a subsidiary or other business unit in the
case of a Spin-Off referred to in the next paragraph, or
distribution referred to in paragraph (1) of this Section),
the Settlement Rate or Early Settlement Rate, as applicable,
shall be adjusted so that the same shall equal the rate
determined by dividing the Settlement Rate or Early
Settlement Rate, as applicable, in effect immediately prior
to the close of business on the date fixed for the
determination of stockholders entitled to receive such
distribution by a fraction, the numerator of which shall be
the Current Market Price per share of the Common Stock on
the date fixed for such determination less the then fair
market value (as determined by the Board of Directors, whose
determination shall be conclusive and described in a Board
Resolution) of the portion of the assets or evidences of
indebtedness so distributed applicable to one share of
Common Stock and the denominator of which shall be such
Current Market Price per share of the Common Stock, such
adjustment to become effective immediately prior to the
opening of business on the day following the date fixed for
the determination of stockholders entitled to receive such
distribution. In any case in which this paragraph (4) is
applicable, paragraph (2) of this Section shall not be
applicable.
(ii) In the case of a Spin-Off, the Settlement Rate or Early Settlement Rate, as applicable, in effect immediately before the close of business on the record date fixed for determination of stockholders entitled to receive that distribution will be increased by multiplying the Settlement Rate or Early Settlement Rate, as applicable, by a fraction, the numerator of which is the Current Market Price per share of the Common Stock plus the Fair Market Value of the portion of those shares of Capital Stock or similar equity interests so distributed applicable to one share of Common Stock and the denominator of which is the Current Market Price per share of the Common Stock. Any adjustment to the Settlement Rate or Early Settlement Rate under this paragraph 4(ii) will occur at the earlier of (1) the tenth Trading Day from, and including, the effective date of the Spin-Off and (2) the date of the securities being offered in the Initial Public Offering of the Spin-Off, if that Initial Public Offering is effected simultaneously with the Spin-Off.
(5) Cash Distributions. In case the Company shall, (i) by
dividend or otherwise, distribute to all holders of its Common Stock
cash (excluding any cash that is distributed in a Reorganization Event
to which Section 5.6(b) applies or as part of a distribution referred
to in paragraph (4) of this Section) in an aggregate amount that,
combined together with (ii) the aggregate amount of any other
distributions to all holders of its Common Stock made exclusively in
cash within the 12 months preceding the date of payment of such
distribution and in respect of which no adjustment pursuant to this
paragraph (5) or paragraph (6) of this Section has been made and (iii)
the aggregate of any cash plus the fair market value as of the date of
the expiration of the tender or exchange offer referred to below (as
determined by the Board of Directors, whose determination shall be
conclusive and described in a Board Resolution) of consideration
payable in respect of any tender or exchange offer by the Company or
any of its subsidiaries for all or any portion of the Common Stock
concluded within the 12 months preceding the date of payment of the
distribution described in clause (i) above and in respect of which no
adjustment pursuant to this paragraph (5) or paragraph (6) of this
Section has been made, exceeds 15% of the product of the Current
Market Price per share of the Common Stock on the date for the
determination of holders of shares of Common Stock entitled to receive
such distribution times the number of shares of Common Stock
outstanding on such date, then, and in each such case, immediately
after the close of business on such date for determination, the
Settlement Rate or Early Settlement Rate, as applicable, shall be
increased so that the same shall equal the rate determined by dividing
the Settlement Rate or Early Settlement Rate, as applicable, in effect
immediately prior to the close of business on the date fixed for
determination of the stockholders entitled to receive such
distribution by a fraction (A) the numerator of which shall be equal
to the Current Market Price per share of the Common Stock on the date
fixed for such determination less an amount equal to the quotient of
(x) the combined amount distributed or payable in the transactions
described in clauses (i), (ii) and (iii) above and (y) the number of
shares of Common Stock outstanding on such date for determination and
(B) the denominator of which shall be equal to the Current Market
Price per share of the Common Stock on such date for determination.
(6) Tender Offers. In case (i) a tender or exchange offer made by the Company or any subsidiary of the Company for all or any portion of the Common Stock shall expire and such tender or exchange offer (as amended upon the expiration thereof) shall require the payment to stockholders (based on the acceptance (up to any maximum specified in the terms of the tender or exchange offer) of Purchased Shares) of an aggregate consideration having a fair market value (as determined by the Board of Directors, whose determination shall be conclusive and described in a Board Resolution) that combined together with (ii) the aggregate of the cash plus the fair market value (as determined by the Board of Directors, whose determination shall be conclusive and described in a Board Resolution), as of the expiration of such tender or exchange offer, of consideration payable in respect of any other tender or exchange offer, by the Company or any subsidiary of the Company for all or any portion of the Common Stock expiring within the 12 months preceding the expiration of such tender or exchange offer and in respect of which no adjustment pursuant to paragraph (5) of this Section or this paragraph (6) has been made and (iii) the aggregate amount of any distributions to all holders of the Company's Common Stock made exclusively in cash within the 12 months preceding the expiration of such tender or exchange offer and in respect of which no adjustment pursuant to paragraph (5) of this Section or this paragraph (6) has been made, exceeds 15% of the product of the Current Market Price per share of the Common Stock as of the last time (the "Expiration Time") tenders could have been made pursuant to such tender or exchange offer (as it may be amended) times the number of shares of Common Stock outstanding (including any tendered shares) at the Expiration Time, then, and in each such case, immediately prior to the opening of business on the day after the date of the Expiration Time, the Settlement Rate or Early Settlement Rate, as applicable, shall be adjusted so that the same shall equal the rate determined by dividing the Settlement Rate or Early Settlement Rate, as applicable, immediately prior to the close of business on the date of the Expiration Time by a fraction (A) the numerator of which shall be equal to (x) the product of (I) the Current Market Price per share of the Common Stock on the date of the Expiration Time and (II) the number of shares of Common Stock outstanding (including any tendered shares) at the Expiration Time less (y) the amount of cash plus the fair market value (determined as aforesaid) of the aggregate consideration payable to stockholders based on the transactions described in clauses (i), (ii) and (iii) above (assuming in the case of clause (i) the acceptance, up to any maximum specified in the terms of the tender or exchange offer, of Purchased Shares), and (B) the denominator of which shall be equal to the product of (x) the Current Market Price per share of the Common Stock as of the Expiration Time and (y) the number of shares of Common Stock outstanding (including any tendered shares) as of the Expiration Time less the number of all shares validly tendered and not withdrawn as of the Expiration Time (the shares deemed so accepted, up to any such maximum, being referred to as the "Purchased Shares").
(7) Reclassification. The reclassification of Common Stock into securities including securities other than Common Stock (other than any reclassification upon a Reorganization Event to which Section 5.6(b) applies) shall be deemed to involve (i) a distribution of such securities other than Common Stock to all holders of Common Stock (and the effective date of such reclassification shall be deemed to be "the date fixed for the determination of stockholders entitled to receive such distribution" and the "date fixed for such determination" within the meaning of paragraph (4) of this Section), and (ii) a subdivision, split or combination, as the case may be, of the number of shares of Common Stock outstanding immediately prior to such reclassification into the number of shares of Common Stock outstanding immediately thereafter (and the effective date of such reclassification shall be deemed to be "the day upon which such subdivision or split becomes effective" or "the day upon which such combination becomes effective," as the case may be, and "the day upon which such subdivision, split or combination becomes effective" within the meaning of paragraph (3) of this Section).
(8) "Current Market Price". The "Current Market Price" of the Common Stock means (a) on any day the average of the Sales Prices for the 5 consecutive Trading Days preceding the earlier of the day preceding the day in question and the day before the "ex date" with respect to the issuance or distribution requiring computation, (b) in the case of any Spin-Off that is effected simultaneously with an Initial Public Offering of the securities being distributed in the Spin-Off, the Sale Price of the Common Stock on the Trading Day on which the Initial Public Offering price of the securities being distributed in the Spin-Off is determined, and (c) in the case of any other Spin-Off, the average of the Sale Prices of the Common Stock over the first 10 Trading Days after the effective date of such Spin-Off. For purposes of this paragraph, the term "ex date," when used with respect to any issuance or distribution, shall mean the first date on which the Common Stock trades regular way on the relevant exchange or in the relevant market without the right to receive such issuance or distribution.
(9) Calculation of Adjustments. All adjustments to the Settlement
Rate or Early Settlement Rate, as applicable, shall be calculated to
the nearest 1/10,000th of a share of Common Stock (or if there is not
a nearest 1/10,000th of a share to the next lower 1/10,000th of a
share). No adjustment in the Settlement Rate or Early Settlement Rate,
as applicable, shall be required unless such adjustment would require
an increase or decrease of at least one percent therein; provided,
that any adjustments which by reason of this subparagraph are not
required to be made shall be carried forward and taken into account in
any subsequent adjustment. If an adjustment is made to the Settlement
Rate or Early Settlement Rate, as applicable, pursuant to paragraph
(1), (2), (3), (4), (5), (6), (7) or (10) of this Section 5.6(a), an
adjustment shall also be made to the Applicable Market Value solely to
determine which of clauses (i), (ii) or (iii) of the definition of
Settlement Rate or Early Settlement Rate, as applicable, in Section
5.1(a) will apply on the Stock Purchase Date. Such adjustment shall be
made by multiplying the Applicable Market Value by a fraction, the
numerator of which shall be the Settlement Rate or Early Settlement
Rate, as applicable, immediately after such adjustment pursuant to
paragraph (1), (2), (3), (4), (5), (6), (7) or (10) of this Section
5.6(a) and the denominator of which shall be the Settlement Rate or
Early Settlement Rate, as applicable, immediately before such
adjustment; provided, that if such adjustment to the Settlement Rate
or Early Settlement Rate, as applicable, is required to be made
pursuant to the occurrence of any of the events contemplated by
paragraph (1), (2), (3), (4), (5), (7) or (10) of this Section 5.6(a)
during the period taken into consideration for determining the
Applicable Market Value, appropriate and customary adjustments shall
be made to the Settlement Rate or Early Settlement Rate, as
applicable.
(10) Increase of Settlement Rate. The Company may make such increases in the Settlement Rate or Early Settlement Rate, as applicable, in addition to those required by this Section, as it considers to be advisable in order to avoid or diminish any income tax to any holders of shares of Common Stock resulting from any dividend or distribution of stock or issuance of rights or warrants to purchase or subscribe for stock or from any event treated as such for income tax purposes or for any other reasons.
(b) Adjustment for Consolidation, Merger or Other Reorganization Event.
In the event of
(1) any consolidation or merger of the Company with or into another Person (other than a merger or consolidation in which the Company is the continuing corporation and in which the Common Stock outstanding immediately prior to the merger or consolidation is not exchanged for cash, securities or other property of the Company or another corporation),
(2) any sale, transfer, lease or conveyance to another Person of the property of the Company as an entirety or substantially as an entirety,
(3) any statutory exchange of securities of the Company with another Person (other than in connection with a merger or acquisition), or
(4) any liquidation, dissolution or winding up of the Company other than as a result of or after the occurrence of a Termination Event (any such event, a "Reorganization Event"),
each share of Common Stock covered by each Forward Purchase Contract
forming a part of an Equity Unit or Stripped Unit, as the case may be,
immediately prior to such Reorganization Event shall, after such
Reorganization Event, be converted for purposes of the Forward Purchase
Contract into the kind and amount of securities, cash and other property
receivable in such Reorganization Event (without any interest thereon, and
without any right to dividends or distributions thereon which have a record
date that is prior to the Stock Purchase Date) per share of Common Stock by
a holder of Common Stock that (i) is not a Person with which the Company
consolidated or into which the Company merged or which merged into the
Company or to which such sale or transfer was made, as the case may be (any
such Person, a "Constituent Person"), or an Affiliate of a Constituent
Person to the extent such Reorganization Event provides for different
treatment of Common Stock held by Affiliates of the Company and
non-Affiliates, and (ii) failed to exercise his rights of election, if any,
as to the kind or amount of securities, cash and other property receivable
upon such Reorganization Event (provided that if the kind or amount of
securities, cash and other property receivable upon such Reorganization
Event is not the same for each share of Common Stock held immediately prior
to such Reorganization Event by other than a Constituent Person or an
Affiliate thereof and in respect of which such rights of election shall not
have been exercised ("Non-electing Share"), then for the purpose of this
Section the kind and amount of securities, cash and other property
receivable upon such Reorganization Event by each Non-electing Share shall
be deemed to be the kind and amount so receivable per share by a plurality
of the Non-electing Shares). On the Stock Purchase Date, the Settlement
Rate then in effect will be applied to the value on the Stock Purchase Date
of such securities, cash or other property. In the event of such a
Reorganization Event, the Person formed by such consolidation, merger or
exchange or the Person which acquires the assets of the Company or, in the
event of a liquidation or dissolution of the Company, the Company or a
liquidating trust created in connection therewith, shall execute and
deliver to the Agent an agreement supplemental hereto providing that the
Holder of each Outstanding Unit shall have the rights provided by this
Section 5.6. Such supplemental agreement shall provide for adjustments
which, for events subsequent to the effective date of such supplemental
agreement, shall be as nearly equivalent as may be practicable to the
adjustments provided for in this Section. The above provisions of this
Section shall similarly apply to successive Reorganization Events.
(a) Whenever the Settlement Rate or Early Settlement Rate, as applicable, is adjusted as herein provided, the Company shall:
(i) forthwith compute the Settlement Rate or Early Settlement Rate, as applicable, and the Applicable Market Value in accordance with Section 5.6 and prepare and transmit to the Agent an Officer's Certificate setting forth the Settlement Rate and the Applicable Market Value, the method of calculation thereof in reasonable detail, and the facts requiring such adjustment and upon which such adjustment is based; and
(ii) as soon as practicable following the occurrence of an event that requires an adjustment to the Settlement Rate or Early Settlement Rate, as applicable, pursuant to Section 5.6 (or if the Company is not aware of such occurrence, as soon as practicable after becoming so aware), provide a written notice to the Holders of the Equity Units and Stripped Units of the occurrence of such event and a statement in reasonable detail setting forth the method by which the adjustment to the Settlement Rate or Early Settlement Rate, as applicable, and the Applicable Market Value was determined and setting forth the adjusted Settlement Rate or Early Settlement Rate, as applicable, and the Applicable Market Value.
(b) The Agent shall not at any time be under any duty or responsibility to any Holder of Equity Units and Stripped Units to determine whether any facts exist which may require any adjustment of the Settlement Rate or Early Settlement Rate, as applicable, and the Applicable Market Value, or with respect to the nature or extent or calculation of any such adjustment when made, or with respect to the method employed in making the same. The Agent shall not be accountable with respect to the validity or value (or the kind or amount) of any shares of Common Stock, or of any securities or property, which may at any time be issued or delivered with respect to any Forward Purchase Contract; and the Agent makes no representation with respect thereto. The Agent shall not be responsible for any failure of the Company to issue, transfer or deliver any shares of Common Stock pursuant to a Forward Purchase Contract or to comply with any of the duties, responsibilities or covenants of the Company contained in this Article.
The Forward Purchase Contracts and all obligations and rights of the Company and the Holders thereunder, including the rights and obligations of Holders to purchase Common Stock, shall immediately and automatically terminate, without the necessity of any notice or action by any Holder, the Agent or the Company, if, on or prior to the Stock Purchase Date, a Termination Event shall have occurred. Upon and after the occurrence of a Termination Event, the Equity Units shall thereafter represent the right to receive the Notes or the appropriate Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, as the case may be, forming a part of such Equity Units, and the Stripped Units shall thereafter represent the right to receive the Treasury Securities forming a part of such Stripped Units, in each case in accordance with the provisions of Section 4.3 of the Pledge Agreement. Upon the occurrence of a Termination Event, the Company shall promptly but in no event later than two Business Days thereafter give written notice to the Agent, the Collateral Agent and to the Holders, at their addresses as they appear in the applicable Register.
(a) Subject to and upon compliance with the provisions of this Section 5.9, Forward Purchase Contracts underlying Equity Units or Stripped Units may, at the option of the Holder thereof, be settled early ("Early Settlement") at any time not later than 10:00 a.m. on the seventh Business Day immediately preceding the Stock Purchase Date. In order to exercise the right to effect Early Settlement with respect to any Forward Purchase Contracts, the Holder of the Certificate evidencing the related Equity Units or Stripped Units, as the case may be, shall deliver such Certificate to the Agent at the Corporate Trust Office duly endorsed for transfer to the Company or in blank with the form of Election to Settle Early on the reverse thereof duly completed and accompanied by payment payable to the Company in immediately available funds in an amount (the "Early Settlement Amount") equal to (A) the product of (i) the Stated Amount of such Equity Units or Stripped Units, as the case may be, multiplied by (ii) the number of Forward Purchase Contracts with respect to which the Holder has elected to effect Early Settlement, plus (B) if such delivery is made with respect to any Forward Purchase Contracts during the period from the close of business on any Record Date next preceding any Payment Date to the opening of business on such Payment Date, an amount equal to the Contract Adjustment Payments, if any, payable on such Payment Date with respect to such Forward Purchase Contracts; provided that no payment shall be required pursuant to clause (B) of this sentence if the Company shall have elected to defer the Contract Adjustment Payments that would otherwise be payable on such Payment Date and further provided that, at that time, if so required by the United States federal securities laws, a registration statement is in effect and a prospectus is available covering the shares of the Common Stock of the Company to be delivered in respect of the Forward Purchase Contracts being settled. Except as provided in the immediately preceding sentence and subject to Section 5.2(d), no payment or adjustment shall be made upon Early Settlement of any Forward Purchase Contract on any Contract Adjustment Payments accrued on such Forward Purchase Contract or on account of any dividends on the Common Stock issued upon such Early Settlement. If the foregoing requirements are first satisfied with respect to Forward Purchase Contracts underlying any Equity Units or Stripped Units, as the case may be, at or prior to 5:00 p.m., New York City time, on a Business Day, such day shall be the "Early Settlement Date" with respect to such Equity Units or Stripped Units, as the case may be, and if such requirements are first satisfied after 5:00 p.m., New York City time, on a Business Day or on a day that is not a Business Day, the "Early Settlement Date" with respect to such Equity Units or Stripped Units, as the case may be, shall be the next succeeding Business Day.
(b) Holders of Equity Units may settle only in units of 20 and integral multiples of 20. If a successful remarketing or a Tax Event Redemption has occurred, Holders of Stripped Units may effect Early Settlement pursuant to this Section 5.9 only in integral multiples of 32,000.
(c) Upon Early Settlement of any Forward Purchase Contract by the Holder of the related Equity Units or Stripped Units, as the case may be, the Company shall issue, and the Holder shall be entitled to receive, 1.0187 shares of Common Stock for each Equity Unit or Stripped Unit on account of such Forward Purchase Contract (the "Early Settlement Rate"). The Early Settlement Rate shall be adjusted in the same manner and at the same time as the Settlement Rate is adjusted. As promptly as practicable after Early Settlement of Forward Purchase Contracts in accordance with the provisions of this Section 5.9, the Company shall issue and shall deliver to the Agent at the Corporate Trust Office a certificate or certificates or book entry interest for the full number of shares of Common Stock issuable upon such Early Settlement together with payment in lieu of any fraction of a share, as provided in Section 5.12.
(d) No later than the third Business Day after the applicable Early Settlement Date the Company shall cause (i) the shares of Common Stock issuable upon Early Settlement of Forward Purchase Contracts to be issued and delivered, and (ii) the related Pledged Notes or Pledged Treasury Consideration or Pledged Applicable Ownership Interest in the Treasury Portfolio, in the case of Equity Units, or the related Pledged Treasury Securities, in the case of Stripped Units, to be released from the Pledge by the Collateral Agent and transferred, in each case, to the Agent for delivery to the Holder thereof or the Holder's designee.
(e) Upon Early Settlement of any Forward Purchase Contracts, and subject to receipt of shares of Common Stock from the Company and the Pledged Notes, Pledged Treasury Consideration, Pledged Applicable Ownership Interest in the Treasury Portfolio, or Pledged Treasury Securities, as the case may be, from the Collateral Agent, as applicable, the Agent shall, in accordance with the instructions provided by the Holder thereof on the applicable form of Election to Settle Early on the reverse of the Certificate evidencing the related Equity Units or Stripped Units, as the case may be, (i) transfer to the Holder the Pledged Notes, Pledged Treasury Consideration, Pledged Applicable Ownership Interest in the Treasury Portfolio, or Pledged Treasury Securities, as the case may be, forming a part of such Equity Units or Stripped Units, as the case may be, and (ii) deliver to the Holder a certificate or certificates or book-entry interest for the full number of shares of Common Stock issuable upon such Early Settlement together with payment in lieu of any fraction of a share, as provided in Section 5.12.
(f) In the event that Early Settlement is effected with respect to Forward Purchase Contracts underlying less than all the Equity Units or Stripped Units, as the case may be, evidenced by a Certificate, upon such Early Settlement the Company shall execute and the Agent shall authenticate, execute on behalf of the Holder thereof and deliver to the Holder thereof, at the expense of the Company, a Certificate evidencing the Equity Units or Stripped Units, as the case may be, as to which Early Settlement was not effected.
(a) In the event of a merger or consolidation of the Company of the type described in clause (1) of Section 5.6(b) in which the Common Stock outstanding immediately prior to such merger or consolidation is exchanged for consideration consisting of at least 30% cash or cash equivalents (any such event a "Cash Merger"), then the Company (or the successor to the Company hereunder) shall be required to offer the Holder of each Equity Unit or Stripped Unit, as the case may be, the right to settle the Forward Purchase Contract underlying such Equity Units or Stripped Units, as the case may be, prior to the Stock Purchase Date ("Merger Early Settlement") as provided herein. On or before the fifth Business Day after the consummation of a Cash Merger, the Company or, at the request and expense of the Company, the Agent, shall give all Holders notice of the occurrence of the Cash Merger and of the right of Merger Early Settlement arising as a result thereof. The Company shall also deliver a copy of such notice to the Agent and the Collateral Agent.
Each such notice shall contain:
(i) the date, which shall be not less than 20 nor more than 30 calendar days after the date of such notice, on which the Merger Early Settlement will be effected (the "Merger Early Settlement Date");
(ii) the date, which shall be on or one Business Day prior to the Merger Early Settlement Date, by which the Merger Early Settlement right must be exercised;
(iii)the Settlement Rate in effect as a result of such Cash Merger and the kind and amount of securities, cash and other property receivable by the Holder upon settlement of each Forward Purchase Contract pursuant to Section 5.6(b);
(iv) a statement to the effect that all or a portion of the Purchase Price payable by the Holder to settle the Forward Purchase Contract will be offset against the amount of cash so receivable upon exercise of Merger Early Settlement, as applicable; and
(v) the instructions a Holder must follow to exercise the Merger Early Settlement right.
(b) To exercise a Merger Early Settlement right, a Holder shall deliver to the Agent at the Corporate Trust Office on or before 5:00 p.m., New York City time on the date specified in the notice the Certificate(s) evidencing the Equity Units or Stripped Units, as the case may be, with respect to which the Merger Early Settlement right is being exercised duly endorsed for transfer to the Company or in blank with the form of Election to Settle Early on the reverse thereof duly completed and accompanied by payment payable to the Company in immediately available funds in an amount equal to the Early Settlement Amount less the amount of cash that otherwise would be deliverable by the Company or its successor upon settlement of the Forward Purchase Contract in lieu of Common Stock pursuant to Section 5.4(b) and as described in the notice to Holders (the "Merger Early Settlement Amount").
(c) On the Merger Early Settlement Date, the Company shall deliver or cause to be delivered (i) the net cash, securities and other property to be received by such exercising Holder, equal to the Settlement Rate as adjusted pursuant to Section 5.6, in respect of the number of Forward Purchase Contracts for which such Merger Early Settlement right was exercised, and (ii) the related Pledged Notes, Pledged Treasury Consideration or Pledged Applicable Ownership Interest in the Treasury Portfolio, in the case of Equity Units, or Pledged Treasury Securities, in the case of Stripped Units, to be released from the Pledge by the Collateral Agent and transferred, in each case, to the Agent for delivery to the Holder thereof or its designee. In the event a Merger Early Settlement right shall be exercised by a Holder in accordance with the terms hereof, all references herein to the Stock Purchase Date shall be deemed to refer to such Merger Early Settlement Date.
(d) Upon Merger Early Settlement of any Forward Purchase Contracts, and subject to receipt of such net cash, securities or other property from the Company and the Pledged Notes, Pledged Treasury Consideration, Pledged Applicable Ownership Interest in the Treasury Portfolio or Pledged Treasury Securities, as the case may be, from the Collateral Agent, as applicable, the Agent shall, in accordance with the instructions provided by the Holder thereof on the applicable form of Election to Settle Early on the reverse of the Certificate evidencing the related Equity Units or Stripped Units, as the case may be, (i) transfer to the Holder the Pledged Notes, Pledged Treasury Consideration, Pledged Applicable Ownership Interest in the Treasury Portfolio, or Pledged Treasury Securities, as the case may be, forming a part of such Equity Units or Stripped Units, as the case may be, and (ii) deliver to the Holder such net cash, securities or other property issuable upon such Merger Early Settlement together with payment in lieu of any fraction of a share, as provided in Section 5.12.
(e) In the event that Merger Early Settlement is effected with respect to Forward Purchase Contracts underlying less than all the Equity Units or Stripped Units, as the case may be, evidenced by a Certificate, upon such Merger Early Settlement the Company (or the successor to the Company hereunder) shall execute and the Agent shall authenticate, execute on behalf of the Holder thereof and deliver to the Holder thereof, at the expense of the Company, a Certificate evidencing the Equity Units or Stripped Units, as the case may be, as to which Merger Early Settlement was not effected.
The Company will pay all stock transfer and similar taxes attributable to the initial issuance and delivery of the shares of Common Stock pursuant to the Forward Purchase Contracts; provided, that the Company shall not be required to pay any such tax or taxes which may be payable in respect of any exchange of or substitution for a Certificate evidencing Equity Units or Stripped Units or any issuance of a share of Common Stock in a name other than that of the registered Holder of a Certificate surrendered in respect of the Equity Units and Stripped Units evidenced thereby, other than in the name of the Agent, as custodian for such Holder, and the Company shall not be required to issue or deliver such share certificates or book-entry interest in Common Stock or Certificates unless and until the Person or Persons requesting the transfer or issuance thereof shall have paid to the Company the amount of such tax or shall have established to the satisfaction of the Company that such tax has been paid.
No fractional shares or scrip representing fractional shares of Common Stock shall be issued or delivered upon settlement on the Stock Purchase Date or upon Early Settlement or Merger Early Settlement of any Forward Purchase Contracts. If Certificates evidencing more than one Forward Purchase Contract shall be surrendered for settlement at one time by the same Holder, the number of full shares of Common Stock which shall be delivered upon settlement shall be computed on the basis of the aggregate number of Forward Purchase Contracts evidenced by the Certificates so surrendered. Instead of any fractional share of Common Stock which would otherwise be deliverable upon settlement of any Forward Purchase Contracts on the applicable Settlement Date or upon Early Settlement or Merger Early Settlement, the Company, through the Agent, shall make a cash payment in respect of such fractional share in an amount equal to the value of such fractional share times the Applicable Market Value. The Company shall provide the Agent from time to time with sufficient funds to permit the Agent to make all cash payments required by this Section 5.12 in a timely manner.
The Company covenants and agrees and each Holder, by purchasing the Equity Units agrees, (i) to treat a Holder's acquisition of the Equity Units as the acquisition of the Note and Forward Purchase Contract constituting the Equity Units, (ii) to treat a Holder's acquisition of the Stripped Units as the acquisition of the Treasury Security and Forward Purchase Contract constituting the Stripped Unit, (iii) to treat each Holder as the owner of the related Notes, Treasury Consideration, Applicable Ownership Interest in the Treasury Portfolio or Treasury Securities, as the case may be and (iv) to allocate the purchase price of the Equity Unit between the Note and Forward Purchase Contract as $50 and $0, respectively.
ARTICLE VI.
REMEDIES
(a) The Holder of any Equity Units or Stripped Units, as the case may be shall have the right, which is absolute and unconditional, subject to the right of the Company to defer payment thereof pursuant to Section 5.3, and to the forfeiture of any Deferred Contract Adjustment Payments upon Cash Settlement pursuant to Section 5.2(d), upon Early Settlement pursuant to Section 5.9(a), upon Merger Early Settlement pursuant to Section 5.10 or upon the occurrence of a Termination Event, to receive payment of each installment of the Contract Adjustment Payments, if any, with respect to the Purchase Contract constituting a part of such Equity Units or Stripped Units, as the case may be, on the respective Payment Date for such Equity Units or Stripped Units, as the case may be, and
(b) Subject to Section 5.6, the Holder of any Units shall have the right, which is absolute and unconditional, to purchase Common Stock pursuant to the Forward Purchase Contract constituting a part of such Units and to institute suit for the enforcement of any such right to purchase Common Stock, and such right shall not be impaired without the consent of such Holder.
If any Holder has instituted any proceeding to enforce any right or remedy under this Agreement and such proceeding has been discontinued or abandoned for any reason, or has been determined adversely to such Holder, then and in every such case, subject to any determination in such proceeding, the Company and such Holder shall be restored severally and respectively to their former positions hereunder and thereafter all rights and remedies of such Holder shall continue as though no such proceeding had been instituted.
Except as otherwise provided with respect to the replacement or payment of mutilated, destroyed, lost or stolen Certificates in Section 3.10(f), no right or remedy herein conferred upon or reserved to the Holders is intended to be exclusive of any other right or remedy, and every right and remedy shall, to the extent permitted by law, be cumulative and in addition to every other right and remedy given hereunder or now or hereafter existing at law or in equity or otherwise. The assertion or employment of any right or remedy hereunder, or otherwise, shall not prevent the concurrent assertion or employment of any other appropriate right or remedy.
No delay or omission of any Holder to exercise any right or remedy upon a default shall impair any such right or remedy or constitute a waiver of any such right. Every right and remedy given by this Article or by law to the Holders may be exercised from time to time, and as often as may be deemed expedient, by such Holders.
All parties to this Agreement agree, and each Holder of Equity Units or Stripped Units, as the case may be, by its acceptance of such Equity Units or Stripped Units, as the case may be, shall be deemed to have agreed, that any court may in its discretion require, in any suit for the enforcement of any right or remedy under this Agreement, or in any suit against the Agent for any action taken, suffered or omitted by it as Agent, the filing by any party litigant in such suit of an undertaking to pay the costs of such suit, and that such court may in its discretion assess reasonable costs, including reasonable attorneys' fees and expenses, against any party litigant in such suit, having due regard to the merits and good faith of the claims or defenses made by such party litigant; provided that the provisions of this Section shall not apply to any suit instituted by the Company, to any suit instituted by the Agent, to any suit instituted by any Holder, or group of Holders, holding in the aggregate more than 10% of the Outstanding Units, or to any suit instituted by any Holder for the enforcement of distributions on any Notes or any Forward Purchase Contract on or after the respective Payment Date therefor in respect of any Equity Units or Stripped Units, as the case may be, held by such Holder, or for enforcement of the right to purchase shares of Common Stock under the Forward Purchase Contract constituting part of any Equity Units or Stripped Units, as the case may be, held by such Holder.
The Company covenants (to the extent that it may lawfully do so) that it will not at any time insist upon, or plead, or in any manner whatsoever claim or take the benefit or advantage of, any stay or extension law wherever enacted, now or at any time hereafter in force, which may affect the covenants in or the performance of this Agreement; and the Company (to the extent that it may lawfully do so) hereby expressly waives all benefit or advantage of any such law, but will suffer and permit the execution of every power of the Agent and the Holders as though no such law had been enacted.
ARTICLE VII
THE AGENT
(a) The Agent shall act as agent and attorney-in-fact for the Holders of the Equity Units and Stripped Units hereunder with such powers as are specifically vested in the Agent by the terms of this Agreement, the Pledge Agreement, the Remarketing Agreement, the Notes, the Equity Units and Stripped Units, and any documents evidencing them or related thereto (the "Transaction Documents"), together with such other powers as are reasonably incidental thereto. The Agent:
(1) shall have no duties or responsibilities except those expressly set forth in the Transaction Documents and no implied covenants or obligations shall be inferred from any Transaction Documents against the Agent, nor shall the Agent be bound by the provisions of any agreement by any party hereto beyond the specific terms hereof;
(2) shall be entitled to conclusively rely upon (x) any certificate, order, judgment, opinion, notice or other communication (including, without limitation, any thereof by telephone or facsimile) reasonably believed by it to be genuine and correct and to have been signed or sent by or on behalf of the proper Person or Persons (without being required to determine the correctness of any fact stated therein), (y) the truth of the statements and the correctness of the opinions expressed therein and (z) advice and statements of legal counsel and other experts selected by the Agent;
(3) shall in all cases be fully protected in acting, or in refraining from acting, hereunder or under any Transaction Documents in accordance with instructions given by the Company or the Holders in accordance herewith or with the Transaction Documents;
(4) shall not be responsible for any recitals contained in any Transaction Document, or in any certificate or other document referred to or provided for in, or received by it under, any Transaction Document or the Equity Units or Stripped Units, or for the value, validity, effectiveness, genuineness, enforceability or sufficiency of any Transaction Document (other than as against the Agent) or the Equity Units or Stripped Units or any other document referred to or provided for herein or therein or for any failure by the Company, any Holder or any other Person (except the Agent) to perform any of its obligations hereunder or thereunder or for the perfection, priority or, except as expressly required hereby, existence, validity, perfection or maintenance of any security interest created under the Pledge Agreement, or for the use or application by the Company of the proceeds in respect of the Forward Purchase Contracts;
(5) shall not be required to initiate or conduct any litigation or collection proceedings hereunder;
(6) shall not be responsible for any action taken or omitted to be taken by it hereunder or under the Transaction Documents or any other document or instrument referred to or provided for herein or therein or in connection herewith or therewith, except for its own negligence, bad faith or willful misconduct; and
(7) shall not be required to advise any party as to selling or retaining, or taking or refraining from taking any action with respect to, the Equity Units or Stripped Units or other rights under any Transaction Document.
(b) No provision of any Transaction Document shall be construed to relieve the Agent from liability for its own negligent action, its own negligent failure to act, its own bad faith, or its own willful misconduct, except that:
(1) this paragraph (b) shall not be construed to limit the effect of paragraph (a) of this Section;
(2) the Agent shall not be liable for any error of judgment made in good faith by a Responsible Officer, unless it shall be proved that the Agent was grossly negligent in ascertaining the pertinent facts; and
(3) in no event shall the Agent be required to expend or risk its own funds or otherwise incur any financial liability in the performance of any of its duties hereunder.
(c) In no event shall the Agent or its officers, employees or agents be liable for any special, indirect, individual, punitive or consequential loss or damages, lost profits or loss of business, arising in connection with any Transaction Document, whether or not the likelihood of such loss or damage was known to the Agent, and regardless of the form of action.
(d) Whether or not therein expressly so provided, every provision of every Transaction Document relating to the conduct or affecting the liability of or affording protection to the Agent shall be subject to the provisions of this Section.
(e) The Agent is authorized to execute and deliver the Pledge Agreement and the Remarketing Agreement and any supplement thereto in its capacity as Agent. The Agent shall be entitled to all of the rights, privileges, immunities and indemnities contained in this Agreement with respect to any duties of the Agent under, or actions taken, omitted to be taken or suffered by the Agent pursuant to the Pledge Agreement.
(f) The Agent shall have no liability whatsoever for the action or inaction of any Clearing Agency or any book-entry system thereof. In no event shall any Clearing Agency or any book-entry system thereof be deemed an agent or subcustodian of the Agent.
(g) The Agent shall not be responsible or liable for any failure or delay in the performance of its obligations under any Transaction Document arising out of or caused, directly or indirectly, by circumstances beyond its reasonable control, including, without limitation, acts of God; acts of terrorism; earthquakes; fires; floods; wars; civil or military disturbances; sabotage; epidemics; riots; interruptions, loss or malfunctions of utilities, computer (hardware or software) or communications service; accidents; labor disputes; acts of civil or military authority; governmental actions; or inability to obtain labor, material, equipment or transportation.
Within 30 days after the occurrence of any default by the Company of its obligations hereunder or under one or more Forward Purchase Contracts of which a Responsible Officer of the Agent has actual knowledge, the Agent shall transmit by mail to the Company and the Holders of Equity Units and Stripped Units, as their names and addresses appear in the Register, notice of such default hereunder, unless such default shall have been cured or waived.
Subject to the provisions of Section 7.1:
(a) the Agent may conclusively rely and shall be fully protected in acting or refraining from acting upon any resolution, certificate, statement, instrument, opinion, report, notice, request, direction, consent, order, bond, debenture, note, other evidence of indebtedness or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties;
(b) any request or direction of the Company mentioned herein shall be sufficiently evidenced by an Officer's Certificate, Issuer Order or Issuer Request, and any resolution of the Board of Directors of the Company may be sufficiently evidenced by a Board Resolution;
(c) whenever in the administration of this Agreement the Agent shall deem it desirable that a matter be proved or established prior to taking, suffering or omitting any action hereunder, the Agent (unless other evidence be herein specifically prescribed) may, in the absence of bad faith on its part, rely upon an Officer's Certificate of the Company;
(d) the Agent may consult with counsel of its selection and the advice of such counsel or any Opinion of Counsel shall be full and complete authorization and protection in respect of any action taken, suffered or omitted by it hereunder in good faith and in reliance thereon;
(e) the Agent shall not be bound to make any investigation into the facts or matters stated in any resolution, certificate, statement, instrument, opinion, report, notice, request, direction, consent, order, bond, debenture, note, other evidence of indebtedness or other paper or document, but the Agent, in its discretion, may make reasonable further inquiry or investigation into such facts or matters related to the execution, delivery and performance of the Forward Purchase Contracts as it may see fit, and, if the Agent shall determine to make such further inquiry or investigation, it shall be given a reasonable opportunity to examine the books, records and premises of the Company, personally or by agent or attorney;
(f) the Agent may execute any of the powers hereunder or perform any duties hereunder either directly or by or through agents or attorneys or an Affiliate of the Agent and the Agent shall not be responsible for any misconduct or negligence on the part of any agent or attorney or an Affiliate appointed with due care by it hereunder;
(g) the rights, privileges, protections, immunities and benefits given to the Agent, including, but not limited to, its right to be indemnified, are extended to, and shall be enforceable by, the Agent in each of its capacities hereunder, and to each custodian and other person employed to act hereunder;
(h) the Agent shall not be charged with knowledge of any default by the Company hereunder unless a Responsible Officer of the Agent shall have received at the Corporate Trust Office of the Agent written notice of such default; and
(i) the permissive right of the Agent to do things enumerated in this Agreement shall not be construed as a duty.
The recitals contained herein, in any other Transaction Documents and in the Certificates shall be taken as the statements of the Company and the Agent assumes no responsibility for their accuracy. The Agent makes no representations as to the validity or sufficiency of either this Agreement or any other Transaction Documents. The Agent shall not be accountable for the use or application by the Company of the proceeds in respect of the Equity Units or Stripped Units or the Forward Purchase Contracts and shall not be responsible for the perfection, priority or maintenance of any security interests created or intended to be created under the Pledge Agreement.
Any Registrar or any other agent of the Company, or the Agent and its Affiliates, in their individual or any other capacity, may become the owner or pledgee of Equity Units or Stripped Units, as the case may be, and may otherwise deal with the Company, the Collateral Agent or any other Person with the same rights it would have if it were not Registrar or such other agent, or the Agent. The Agent and its Affiliates may (without having to account therefor to the Company or any Holder of Equity Units or Stripped Units or holder of Separate Notes) accept deposits from, lend money to, make other investments in and generally engage in any kind of banking, trust or other business with the Company, any Holder of Equity Units or Stripped Units and any holder of Separate Notes (and any of their respective subsidiaries or Affiliates) as if it were not acting as the Agent and the Agent and its Affiliates may accept fees and other consideration from the Company, any Holder of Equity Units or Stripped Units or any holder of Separate Notes without having to account for the same to any such Person.
Money held by the Agent in custody hereunder need not be segregated from the Agent's other funds except to the extent required by law or provided herein. The Agent shall be under no obligation to invest or pay interest on any money received by it hereunder except as otherwise agreed in writing with the Company.
The Company agrees:
(a) to pay to the Agent from time to time compensation for all services rendered by it hereunder or under the Transaction Documents as shall be agreed in writing between the Company and the Agent;
(b) to reimburse the Agent upon its request for all reasonable expenses, disbursements and advances incurred or made by the Agent in accordance with any provision of this Agreement or the other Transaction Documents (including the reasonable compensation and the reasonable expenses and disbursements of its agents and counsel), except any such expense, disbursement or advance as may be attributable to its negligence, willful misconduct or bad faith; and
(c) to indemnify the Agent for, and to hold it harmless against, any
loss, liability or reasonable out-of-pocket expense incurred without gross
negligence, willful misconduct or bad faith on its part, arising out of or
in connection with the acceptance or administration of its duties under the
other Transaction Documents, including the costs and expenses (including
reasonable fees and expenses of counsel) of defending itself against any
claim, whether asserted by the Company, a Holder or any other Person, or
liability in connection with the exercise or performance of any of its
powers or duties under the Transaction Documents. The Agent shall promptly
notify the Company of any third party claim which may give rise to the
indemnity hereunder and give the Company the opportunity to participate in
the defense of such claim with counsel reasonably satisfactory to the
indemnified party, and no such claim shall be settled without the written
consent of the Company, which consent shall not be unreasonably withheld,
provided that any failure to give any such notice shall not affect the
obligation of the Company under this Section. The provisions of this
Section 7.7 shall survive the termination of any and all Transaction
Documents, the satisfaction or discharge of the Equity Units or Stripped
Units and/ or the Separate Notes or the resignation or removal of the
Agent.
There shall at all times be an Agent hereunder which shall be a corporation organized and doing business under the laws of the United States of America, any State thereof or the District of Columbia, authorized under such laws to exercise corporate trust powers, having (or being a member of a bank holding company having) a combined capital and surplus of at least $500,000,000, subject to supervision or examination by federal or state authority and having (or being a member of a bank holding company having) a Corporate Trust Office in the Borough of Manhattan, the City of New York, if there be such a corporation, qualified and eligible under this Article and willing to act on reasonable terms. If such corporation publishes reports of condition at least annually, pursuant to law or to the requirements of said supervising or examining authority, then for the purposes of this Section, the combined capital and surplus of such corporation shall be deemed to be its combined capital and surplus as set forth in its most recent report of condition so published. If at any time the Agent shall cease to be eligible in accordance with the provisions of this Section, it shall resign immediately in the manner and with the effect hereinafter specified in this Article.
(a) No resignation or removal of the Agent and no appointment of a successor Agent pursuant to this Article shall become effective until the acceptance of appointment by the successor Agent in accordance with the applicable requirements of Section 7.10.
(b) The Agent may resign at any time by giving written notice thereof to the Company 60 days prior to the effective date of such resignation. If the instrument of acceptance by a successor Agent required by Section 7.10 shall not have been delivered to the Agent within 30 days after the giving of such notice of resignation, the resigning Agent may petition, at the expense of the Company, any court of competent jurisdiction for the appointment of a successor Agent.
(c) The Agent may be removed at any time by Act of the Holders of a majority in number of the Outstanding Units upon delivery of a written notice to the Agent and the Company. If the instrument of acceptance by a successor Agent required by Section 7.10 shall not have been delivered to the Agent within 30 days after the giving of such notice of removal, the Agent to be removed may petition, at the expense of the Company, any court of competent jurisdiction for the appointment of a successor Agent.
(d) If at any time:
(1) the Agent has a "conflicting interest" (as defined in
Section 310(b) of the TIA) and fails to eliminate the
conflicting interest or resign pursuant to Section 310(b) of
the TIA upon written request therefor by the Company or by
any Holder who has been a bona fide Holder of a Unit for at
least six months, as if this Agreement were an indenture
qualified under the TIA, as if the Equity Units or Stripped
Units were in default and as if such default had not been
cured or waived within the applicable period under Section
310(b) of the TIA; or
(2) the Agent shall cease to be eligible under Section 7.8 and shall fail to resign after written request therefor by the Company or by any such Holder; or
(3) the Agent shall become incapable of acting or shall be adjudged a bankrupt or insolvent or a receiver of the Agent or of its property shall be appointed or any public officer shall take charge or control of the Agent or of its property or affairs for the purpose of rehabilitation, conservation or liquidation;
then, in any such case, (x) the Company by a Board Resolution may remove the Agent, or (y) any Holder who has been a bona fide Holder of Equity Units or Stripped Equity Units for at least six months may, on behalf of himself and all others similarly situated, petition any court of competent jurisdiction for the removal of the Agent and the appointment of a successor Agent.
(e) If the Agent shall resign, be removed or become incapable of acting, or if a vacancy shall occur in the office of Agent for any cause, the Company, by a Board Resolution, shall promptly appoint a successor Agent and shall comply with the applicable requirements of Section 7.10. If no successor Agent shall have been so appointed by the Company and accepted appointment in the manner required by Section 7.10, any Holder who has been a bona fide Holder of Equity Units or Stripped Equity Units for at least six months may, on behalf of himself and all others similarly situated, petition any court of competent jurisdiction for the appointment of a successor Agent.
(f) The Company shall give, or shall cause such successor Agent to give, notice of each resignation and each removal of the Agent and each appointment of a successor Agent by mailing written notice of such event by first-class mail, postage prepaid, to all Holders as their names and addresses appear in the applicable Register. Each notice shall include the name of the successor Agent and the address of its Corporate Trust Office.
(a) In case of the appointment hereunder of a successor Agent, every such successor Agent so appointed shall execute, acknowledge and deliver to the Company and to the retiring Agent an instrument accepting such appointment, and thereupon the resignation or removal of the retiring Agent shall become effective and such successor Agent, without any further act, deed or conveyance, shall become vested with all the rights, powers, agencies, trusts and duties of the retiring Agent; but, on the request of the Company or the successor Agent, such retiring Agent shall, upon payment of its charges, execute and deliver an instrument transferring to such successor Agent all the rights, powers, agencies, trusts and duties of the retiring Agent and duly assign, transfer and deliver to such successor Agent all property and money held by such retiring Agent hereunder.
(b) Upon request of any such successor Agent, the Company shall execute any and all instruments for more fully and certainly vesting in and confirming to such successor Agent all such rights, powers, agencies, trusts and duties referred to in paragraph (a) of this Section.
(c) No successor Agent shall accept its appointment unless at the time of such acceptance such successor Agent shall be qualified and eligible under this Article.
Any corporation into which the Agent may be merged or converted or with which it may be consolidated, or any corporation resulting from any merger, conversion or consolidation to which the Agent shall be a party, or any corporation succeeding to all or substantially all the corporate trust business of the Agent, shall be the successor of the Agent hereunder, provided such corporation shall be otherwise qualified and eligible under this Article, without the execution or filing of any paper or any further act on the part of any of the parties hereto. In case any Certificates shall have been authenticated and executed on behalf of the Holders, but not delivered, by the Agent then in office, any successor by merger, conversion or consolidation to such Agent shall adopt such authentication and execution and deliver the Certificates so authenticated and executed with the same effect as if such successor Agent had itself authenticated and executed such Equity Units and Stripped Units.
(a) The Agent shall preserve, in as current a form as is reasonably practicable, the names and addresses of Holders received by the Agent in its capacity as Registrar.
(b) If three or more Holders (herein referred to as "Applicants") apply in writing to the Agent, and furnish to the Agent reasonable proof that each such applicant has owned Equity Units or Stripped Units, as the case may be, for a period of at least six months preceding the date of such application, and such application states that the Applicants desire to communicate with other Holders with respect to their rights under this Agreement or under the Equity Units or Stripped Units, as the case may be, and is accompanied by a copy of the form of proxy or other communication which such Applicants propose to transmit, then the Agent shall mail to all the Holders copies of the form of proxy or other communication which is specified in such request, with reasonable promptness after a tender to the Agent of the materials to be mailed and of payment, or provision, in the absence of bad faith, satisfactory to the Agent for the payment, of the reasonable expenses of such mailing.
In the event of any ambiguity in the provisions of any Transaction Document or any dispute between or conflicting claims by or among the parties hereto or any other Person, the Agent shall be entitled, after prompt notice to the Company and the Holders of Equity Units and Stripped Units, at its sole option, to refuse to comply with any and all such claims, demands or instructions so long as such dispute or conflict shall continue, and the Agent shall not be or become liable in any way to any of the parties hereto for its failure or refusal to comply with such conflicting claims, demands or instructions. The Agent shall be entitled to refuse to act until either (i) such conflicting or adverse claims or demands shall have been finally determined by a court of competent jurisdiction or settled by agreement between the conflicting parties as evidenced in a writing, reasonably satisfactory to the Agent, or (ii) the Agent shall have received security or an indemnity reasonably satisfactory to the Agent sufficient to save the Agent harmless from and against any and all loss, liability or reasonable out-of-pocket expense which the Agent may incur by reason of its acting without bad faith, willful misconduct or gross negligence. The Agent may in addition elect to commence an interpleader action or seek other judicial relief or orders as the Agent may deem necessary. Notwithstanding anything contained herein to the contrary, the Agent shall not be required to take any action that is in its opinion contrary to law or to the terms of any Transaction Document, or which would in its opinion subject it or any of its officers, employees or directors to liability.
Except to the extent otherwise provided in this Agreement, the Agent assumes no obligation and shall not be subject to any liability under this Agreement, the Pledge Agreement or any Forward Purchase Contract in respect of the obligations of the Holder of any Equity Units or Stripped Units thereunder. The Company agrees, and each Holder of a Certificate, by such Holder's acceptance thereof, shall be deemed to have agreed, that the Agent's execution of the Certificates on behalf of the Holders shall be solely as agent and attorney-in-fact for the Holders, and that the Agent shall have no obligation to perform such Forward Purchase Contracts on behalf of the Holders, except to the extent expressly provided in Article V. Anything contained in this Agreement to the contrary notwithstanding, in no event shall the Agent or its officers, employees or agents be liable for indirect, special, punitive, or consequential loss or damage of any kind whatsoever, including, but not limited to, lost profits, whether or not the likelihood of such loss or damage was known to the Agent and regardless of the form of action.
(a) The Agent, on its own behalf and on behalf of the Company, will comply with all applicable certification, information reporting and withholding (including "backup" withholding) requirements imposed on it as a paying agent by applicable tax laws, regulations or administrative practice with respect to any payments made with respect to the Equity Units and Stripped Units. Such compliance shall include, without limitation, the preparation and timely filing of required returns and the timely payment of all amounts required to be withheld to the appropriate taxing authority or its designated agent.
(b) The Agent shall comply with any reasonable written direction timely received from the Company with respect to the application of such requirements to particular payments to Holders or in other particular circumstances, and may for purposes of this Agreement rely on any such direction in accordance with Section 7.1(a)(2).
(c) The Agent shall maintain all appropriate records documenting compliance with such requirements, and shall make such records available, on written request, to the Company or its authorized representative within a reasonable period of time after receipt of such request.
ARTICLE VIII.
SUPPLEMENTAL AGREEMENTS
Without the consent of any Holders, the Company and the Agent, at any time and from time to time, may enter into one or more agreements supplemental hereto, in form satisfactory to the Company and the Agent, for any of the following purposes:
(a) to evidence the succession of another Person to the Company, and the assumption by any such successor of the covenants of the Company herein and in the Certificates; or
(b) to add to the covenants of the Company for the benefit of the Holders, or to surrender any right or power herein conferred upon the Company; or
(c) to evidence and provide for the acceptance of appointment hereunder by a successor Agent; or
(d) to make provision with respect to the rights of Holders pursuant to the requirements of Section 5.6(b) or 5.10; or
(e) to cure any ambiguity, to correct or supplement any provisions herein which may be inconsistent with any other provisions herein, or to make any other provisions with respect to such matters or questions arising under this Agreement, provided such action shall not adversely affect the interests of the Holders; or
(f) to permit the substitution by Holders of designated Company debt instruments for the Pledged Notes as Collateral under this Agreement.
(a) With the consent of the Holders of not less than a majority of the outstanding Forward Purchase Contracts voting together as one class, by Act of said Holders delivered to the Company and the Agent, the Company, when authorized by a Board Resolution, and the Agent may enter into an agreement or agreements supplemental hereto, in form satisfactory to the Company and the Agent, for the purpose of modifying in any manner the terms of the Forward Purchase Contracts, or the provisions of this Agreement or the rights of the Holders in respect of the Equity Units and Stripped Units; provided, that, except as contemplated herein, no such supplemental agreement shall, without the consent of the Holder of each Outstanding Unit affected thereby:
(1) change any Payment Date;
(2) change the amount or the type of Collateral required to be Pledged to secure a Holder's Obligations under the Forward Purchase Contract unless not adverse to Holders, impair the right of the Holder of any Forward Purchase Contract to receive distributions on the related Collateral (except as provided in Section 8.1(f) and except for the rights of Holders of Equity Units to substitute the Treasury Securities for the Pledged Notes, Pledged Treasury Consideration or Pledged Applicable Ownership Interest in the Treasury Portfolio, or the rights of holders of Stripped Units to substitute Notes or appropriate Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio for the Pledged Treasury Securities) or otherwise adversely affect the Holder's rights in or to such Collateral;
(3) reduce any Contract Adjustment Payments, if any, or any Deferred Contract Adjustment Payment, or change any place where, or the coin or currency in which, any Contract Adjustment Payment is payable;
(4) impair the right to institute suit for the enforcement of any Forward Purchase Contract, any Contract Adjustment Payment, if any, or any Deferred Contract Adjustment Payment, if any;
(5) impair the right to institute suit for the enforcement of any Forward Purchase Contract;
(6) reduce the number of shares of Common Stock to be purchased pursuant to any Forward Purchase Contract, increase the price to purchase shares of Common Stock upon settlement of any Forward Purchase Contract, change the Stock Purchase Date or otherwise materially adversely affect the Holder's rights under any Forward Purchase Contract; or
(7) reduce the percentage of the outstanding Forward Purchase Contracts the consent of whose Holders is required for any such supplemental agreement;
provided, that if any amendment or proposal referred to above would adversely affect only the Equity Units or the Stripped Units, then only the affected class of Holder as of the record date for the Holders entitled to vote thereon will be entitled to vote on such amendment or proposal, and such amendment or proposal shall not be effective except with the consent of Holders of not less than a majority or 100% of such class, as the case may be; provided further, however, that no agreement, whether with or without the consent of Holders shall affect Section 3.16.
(b) It shall not be necessary for any Act of Holders under this
Section to approve the particular form of any proposed supplemental
agreement, but it shall be sufficient if such Act shall approve the
substance thereof.
In executing, or accepting the additional agencies created by, any supplemental agreement permitted by this Article or the modifications thereby of the agencies created by this Agreement, the Agent shall be provided and (subject to Section 7.1) shall be fully protected in relying upon, an Opinion of Counsel stating that the execution of such supplemental agreement is authorized or permitted by this Agreement. The Agent may, but shall not be obligated to, enter into any such supplemental agreement which affects the Agent's own rights, duties or immunities under this Agreement or otherwise.
Upon the execution of any supplemental agreement under this Article, this Agreement shall be modified in accordance therewith, and such supplemental agreement shall form a part of this Agreement for all purposes; and every Holder of Certificates theretofore or thereafter authenticated, executed on behalf of the Holders and delivered hereunder shall be bound thereby.
Certificates authenticated, executed on behalf of the Holders and delivered after the execution of any supplemental agreement pursuant to this Article may, and shall if required by the Agent, bear a notation in form approved by the Agent as to any matter provided for in such supplemental agreement. If the Company shall so determine, new Certificates so modified as to conform, in the opinion of the Agent and the Company, to any such supplemental agreement may be prepared and executed by the Company and authenticated, executed on behalf of the Holders and delivered by the Agent in exchange for outstanding Certificates.
ARTICLE IX.
CONSOLIDATION, MERGER, SALE OR CONVEYANCE
The Company shall not consolidate with or merge into any other Person or convey, transfer or lease its properties and assets substantially as an entirety to any Person, unless:
(a) the Person formed by such consolidation or into which the Company is merged or the Person which acquires by conveyance, transfer or lease the properties and assets of the Company substantially as an entirety shall be a corporation, partnership, limited liability company or trust, shall be organized and validly existing under the laws of the United States of America, any State thereof or the District of Columbia and shall expressly assume every covenant of this Agreement, the Forward Purchase Contracts, the Notes, the Remarketing Agreement and the Pledge Agreement on the part of the Company to be performed or observed by one or more supplemental agreements in form reasonably satisfactory to the Agent and the Collateral Agent, executed and delivered to the Agent and the Collateral Agent by such Person;
(b) immediately after giving effect to such transaction, no default under this Agreement, the Forward Purchase Contracts, the Remarketing Agreement or the Pledge Agreement shall have happened and be continuing; and
(c) the Company has delivered to the Agent an Officers' Certificate and an Opinion of Counsel, each stating that such consolidation, merger, conveyance, transfer or lease and such supplemental agreement(s) comply with this Section 9.1 and that all conditions precedent herein provided for relating to such transaction have been complied with.
This Section 9.1 shall not apply to any merger or consolidation in which the Company is the surviving corporation.
(a) Upon any consolidation with or merger of the Company into any
other Person, or any conveyance, transfer or lease of the properties and
assets of the Company substantially as an entirety in accordance with
Section 9.1, the successor Person formed by such consolidation or into
which the Company is merged or to which such conveyance, transfer or lease
is made shall succeed to, and be substituted for, and may exercise every
right and power of, the Company under this Agreement with the same effect
as if such successor Person had been named as the Company herein, and
thereafter, except in the case of a lease, the predecessor Person shall be
relieved of all obligations and covenants under this Agreement, the Forward
Purchase Contracts, the Notes, the Units, the Remarketing Agreement and the
Pledge Agreement.
(b) In case of any such consolidation, merger, sale, assignment, transfer, lease or conveyance such change in phraseology and form (but not in substance) may be made in the Certificates evidencing Units thereafter to be issued as may be appropriate.
ARTICLE X.
COVENANTS
The Company covenants and agrees for the benefit of the Holders from time to time of the Equity Units and Stripped Units that it will duly and punctually perform its obligations under the Forward Purchase Contracts in accordance with the terms of the Forward Purchase Contracts and this Agreement. In the case of Early Settlement pursuant to Section 5.9, if the United States federal securities laws so require, the Company will use commercially reasonable efforts to (i) have in effect a registration statement covering the shares of Common Stock to be delivered in respect of the Forward Purchase Contracts being settled and (ii) provide a prospectus in connection therewith, in each case that may be used in connection with such Early Settlement.
(a) The Company will maintain in the Borough of Manhattan, The City of New York an office or agency where Certificates may be presented or surrendered for payment of Contract Adjustment Payments, acquisition of shares of Common Stock upon settlement of the Forward Purchase Contracts on any Settlement Date and for transfer of Collateral upon occurrence of a Termination Event, where Certificates may be surrendered for registration of transfer or exchange, for a Collateral Substitution or reestablishment of Equity Units and where notices and demands to or upon the Company in respect of the Equity Units and Stripped Units and this Agreement may be served. The Company will give prompt written notice to the Agent of the location, and any change in the location, of such office or agency. If at any time the Company shall fail to maintain any such required office or agency or shall fail to furnish the Agent with the address thereof, such presentations, surrenders, notices and demands may be made or served at the Corporate Trust Office, Office of the Agent in The City of New York, and the Company hereby appoints the Agent as its agent to receive all such presentations, surrenders, notices and demands.
(b) The Company may also from time to time designate one or more other offices or agencies where Certificates may be presented or surrendered for any or all such purposes and may from time to time rescind such designations; provided, that no such designation or rescission shall in any manner relieve the Company of its obligation to maintain an office or agency in the Borough of Manhattan, The City of New York for such purposes. The Company will give prompt written notice to the Agent of any such designation or rescission and of any change in the location of any such other office or agency. The Company hereby designates as the place of payment for the Equity Units and Stripped Units the Office of the Agent in The City of New York and appoints the Agent at the Office of the Agent in The City of New York as paying agent in such city.
The Company shall at all times prior to the Stock Purchase Date reserve and keep available, free from preemptive rights, out of its authorized but unissued Common Stock the full number of shares of Common Stock issuable against tender of payment in respect of all Forward Purchase Contracts constituting a part of the Equity Units and Stripped Units evidenced by outstanding Certificates.
The Company covenants that all shares of Common Stock which may be issued against tender of payment in respect of any Forward Purchase Contract constituting a part of the Outstanding Units will, upon issuance, be duly authorized, validly issued, fully paid and nonassessable.
The Company will deliver to the Agent, within 120 days after the end of each fiscal year of the Company ending after the date hereof, an Officer's Certificate, stating whether or not to the best knowledge of the signer thereof the Company is in default in the performance and observance of any of the terms, provisions and conditions hereof, and if the Company shall be in default, specifying all such defaults and the nature and status thereof of which such officer may have knowledge.
Each Holder from time to time of the Equity Units or Stripped Units which is a Plan hereby represents that its acquisition of the Equity Units or Stripped Units and the holding of the same satisfies the applicable fiduciary requirements of ERISA and that it is entitled to exemption relief from the prohibited transaction provisions of ERISA and the Code in accordance with one or more prohibited transaction exemptions or otherwise will not result in a nonexempt prohibited transaction.
[SIGNATURE PAGES FOLLOW]
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed as of the day and year first above written.
AMERICAN ELECTRIC POWER COMPANY, INC.
By: /s/ A. A. Pena
Name: A. A. Pena
Title: Treasurer
|
THE BANK OF NEW YORK,
as Forward Purchase Contract Agent
By: /s/ Terence Rawlins
Name: Terence Rawlins
Title: Vice President
|
EXHIBIT A
FORM OF EQUITY UNITS CERTIFICATE
[FOR INCLUSION IN GLOBAL CERTIFICATES ONLY -- THIS CERTIFICATE IS A GLOBAL
CERTIFICATE WITHIN THE MEANING OF THE FORWARD PURCHASE CONTRACT AGREEMENT (AS HEREINAFTER DEFINED) AND IS REGISTERED IN THE NAME OF THE CLEARING AGENCY OR A NOMINEE THEREOF. THIS CERTIFICATE MAY NOT BE EXCHANGED IN WHOLE OR IN PART FOR A CERTIFICATE REGISTERED, AND NO TRANSFER OF THIS CERTIFICATE IN WHOLE OR IN PART MAY BE REGISTERED, IN THE NAME OF ANY PERSON OTHER THAN SUCH CLEARING AGENCY OR A NOMINEE THEREOF, EXCEPT IN THE LIMITED CIRCUMSTANCES DESCRIBED IN THE FORWARD PURCHASE CONTRACT AGREEMENT.
Unless this Certificate is presented by an authorized representative of The Depository Trust Company (55 Water Street, New York, New York) to the Company or its agent for registration of transfer, exchange or payment, and any Certificate issued is registered in the name of Cede & Co., or such other name as requested by an authorized representative of The Depository Trust Company, and any payment hereon is made to Cede & Co., ANY TRANSFER, PLEDGE OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY A PERSON IS WRONGFUL since the registered owner hereof, Cede & Co., has an interest herein.]
(Form of Face of Equity Units Certificate)
No. ______________ CUSIP No. ____________
Number of Equity Units____________
This Equity Units Certificate certifies that [For inclusion in Global
Certificates only -- Cede & Co.] is the registered Holder of the number of
Equity Units set forth above [For inclusion in Global Certificates only - or
such other number of Equity Units reflected in the Schedule of Increases or
Decreases in Global Certificates attached hereto]. Each Equity Unit represents
(i) either (a) beneficial ownership by the Holder of one 5.75% Senior Note Due
August 16, 2007 (the "Note") of American Electric Power Company, Inc., a New
York corporation (the "Company") having a principal amount of $50, subject to
the Pledge of such Note by such Holder pursuant to the Pledge Agreement, or (b)
if the Note has been remarketed by the Remarketing Agent (or if the Holder has
elected not to have the Note remarketed by delivering the Opt-out Treasury
Consideration specified by the Remarketing Agent), the Agent-purchased Treasury
Consideration, subject to the Pledge of such Treasury Consideration by such
Holder pursuant to the Pledge Agreement, or (c) if a Tax Event Redemption has
occurred, the Applicable Ownership Interest in the Treasury Portfolio subject to
the Pledge of such Applicable Ownership Interest in the Treasury Portfolio
pursuant to the Pledge Agreement, and (ii) the rights and obligations of the
Holder under one Forward Purchase Contract with the Company. All capitalized
terms used herein which are defined in the Forward Purchase Contract Agreement
have the meaning set forth therein.
Pursuant to the Pledge Agreement, the Note, the appropriate Treasury Consideration or the Applicable Ownership Interest in the Treasury Portfolio, as the case may be, constituting part of each Equity Unit evidenced hereby has been pledged to the Collateral Agent, for the benefit of the Company, to secure the obligations of the Holder under the Forward Purchase Contract comprising a part of such Equity Unit.
The Pledge Agreement provides that all payments in respect of the Pledged Notes, Pledged Treasury Consideration or Pledged Applicable Ownership Interest in the Treasury Portfolio received by the Collateral Agent shall be paid by the Collateral Agent by wire transfer in same day funds (i) in the case of (A) quarterly cash distributions on Equity Units which include Pledged Notes, Pledged Treasury Consideration or Pledged Applicable Ownership Interest in the Treasury Portfolio and (B) any payments in respect of the Notes, Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, as the case may be, that have been released from the Pledge pursuant to the Pledge Agreement, to the Agent to the account designated by the Agent, no later than 10:00 a.m., New York City time, on the Business Day such payment is received by the Collateral Agent (provided that in the event such payment is received by the Collateral Agent on a day that is not a Business Day or after 9:00 a.m., New York City time, on a Business Day, then such payment shall be made no later than 9:30 a.m., New York City time, on the next succeeding Business Day) and (ii) in the case of payments in respect of any Pledged Notes, Pledged Treasury Consideration or Pledged Applicable Ownership Interest in the Treasury Portfolio, as the case may be, to be paid upon settlement of such Holder's obligations to purchase Common Stock under the Forward Purchase Contract, to the Company on the Stock Purchase Date (as defined herein) in accordance with the terms of the Pledge Agreement, in full satisfaction of the respective obligations of the Holders of the Equity Units of which such Pledged Notes, Pledged Treasury Consideration or Pledged Applicable Ownership Interest in the Treasury Portfolio, as the case may be, are a part under the Forward Purchase Contracts forming a part of such Equity Units. Quarterly distributions on Equity Units which include Pledged Notes, Pledged Treasury Consideration or Pledged Applicable Ownership Interest in the Treasury Portfolio, as the case may be, which are payable quarterly in arrears on February 16, May 16, August 16 and November 16, each year, commencing August 16, 2002 (a "Payment Date"), shall, subject to receipt thereof by the Agent from the Collateral Agent (if the Collateral Agent is the registered owner thereof), be paid by the Agent to the Person in whose name this Equity Units Certificate (or a Predecessor Equity Units Certificate) is registered at the close of business on the Record Date for such Payment Date.
Each Forward Purchase Contract evidenced hereby obligates the Holder of this Equity Units Certificate to purchase, and the Company to sell, on August 16, 2005 (the "Stock Purchase Date"), at a price equal to $50 (the "Stated Amount"), a number of newly issued shares of common stock, $6.50 par value per share ("Common Stock"), of the Company, equal to the Settlement Rate unless on or prior to the Stock Purchase Date there shall have occurred a Termination Event or a Cash Settlement, Early Settlement or Merger Early Settlement with respect to the Equity Units of which such Forward Purchase Contract is a part, all as provided in the Forward Purchase Contract Agreement and more fully described on the reverse hereof. The Purchase Price (as defined herein) for the shares of Common Stock purchased pursuant to each Forward Purchase Contract evidenced hereby, if not paid earlier, shall be paid on the Stock Purchase Date by application of payments received in respect of the Pledged Notes, Pledged Treasury Consideration or Pledged Applicable Ownership Interest in the Treasury Portfolio, as the case may be, pledged to secure the obligations of the Holder under such Forward Purchase Contract in accordance with the terms of the Pledge Agreement.
Payments on the Notes, the appropriate Treasury Consideration or the Applicable Ownership Interest in the Treasury Portfolio, as the case may be, will be payable at the Office of the Agent in The City of New York or, at the option of the Company, by check mailed to the address of the Person entitled thereto as such address appears on the Equity Units Register or by wire transfer to an account specified by such Person at least five Business Days prior to the applicable Payment Date.
The Company shall pay on each Payment Date in respect of each Forward Purchase Contract forming part of an Equity Unit evidenced hereby an amount (the "Contract Adjustment Payment") equal to 3.50% per year of the Stated Amount, computed on the basis of a 360-day year of twelve 30-day months, subject to deferral at the option of the Company as provided in the Forward Purchase Contract Agreement and more fully described on the reverse hereof (provided that if any date on which a Contract Adjustment Payment is to be made on the Forward Purchase Contracts is not a Business Day, then payment of such Contract Adjustment Payment payable on such date will be made on the next succeeding day which is a Business Day, and no interest or payment will be paid in respect of such delay, except that if such next succeeding Business Day is in the next succeeding calendar year, then such payment will be made on the immediately preceding Business Day). Such Contract Adjustment Payments shall be payable to the Person in whose name this Equity Units Certificate (or a Predecessor Equity Units Certificate) is registered at the close of business on the Record Date for such Payment Date.
Contract Adjustment Payments will be payable at the Office of the Agent in The City of New York or, at the option of the Company, by check mailed to the address of the Person entitled thereto as such address appears on the Equity Units Register or by wire transfer to the account designated to the Agent by a prior written notice by such Person delivered at least five Business Days prior to the applicable Payment Date. Reference is hereby made to the further provisions set forth on the reverse hereof, which further provisions shall for all purposes have the same effect as if set forth at this place.
Unless the certificate of authentication hereon has been executed by the Agent by manual signature, this Equity Units Certificate shall not be entitled to any benefit under the Pledge Agreement or the Forward Purchase Contract Agreement or be valid or obligatory for any purpose.
IN WITNESS WHEREOF, the Company has caused this instrument to be duly executed.
AMERICAN ELECTRIC POWER COMPANY, INC.
By: _____________________________________
Name:
Title:
HOLDER SPECIFIED ABOVE (as to
obligations of such Holder
under the Forward Purchase
Contracts evidenced hereby)
By: THE BANK OF NEW YORK, not individually but
solely as Attorney-in-Fact of such Holder
By: __________________________________________
Authorized Signatory
AGENT'S CERTIFICATE OF AUTHENTICATION
This is one of the Equity Units Certificates referred to in the within-mentioned Forward Purchase Contract Agreement.
THE BANK OF NEW YORK,
as Forward Purchase Contract Agent
Dated: June 11, 2002 By: ___________________________________ Authorized Signatory
(Form of Reverse of Equity Units Certificate)
Each Forward Purchase Contract evidenced hereby is governed by a Forward Purchase Contract Agreement, dated as of June 11, 2002 (as may be supplemented from time to time, the "Forward Purchase Contract Agreement"), between the Company and The Bank of New York, as Forward Purchase Contract Agent (including its successors thereunder, herein called the "Agent"), to which Forward Purchase Contract Agreement and supplemental agreements thereto reference is hereby made for a description of the respective rights, limitations of rights, obligations, duties and immunities thereunder of the Agent, the Company, and the Holders and of the terms upon which the Equity Units Certificates are, and are to be, executed and delivered.
Each Forward Purchase Contract evidenced hereby obligates the Holder of this Equity Units Certificate to purchase, and the Company to sell, on the Stock Purchase Date at a price equal to $50 (the "Purchase Price"), a number of shares of Common Stock of the Company equal to the Settlement Rate, unless, on or prior to the Stock Purchase Date, there shall have occurred a Termination Event or an Early Settlement, Merger Early Settlement or Cash Settlement with respect to the Units of which such Forward Purchase Contract is a part. The "Settlement Rate" is equal to (a) if the Applicable Market Value (as defined below) is greater than or equal to $49.08 (the "Threshold Appreciation Price"), 1.0187 shares of Common Stock per Forward Purchase Contract, (b) if the Applicable Market Value is less than the Threshold Appreciation Price but is greater than $40.90, the number of shares of Common Stock per Forward Purchase Contract equal to the Stated Amount of the related Equity Units divided by the Applicable Market Value and (c) if the Applicable Market Value is less than or equal to $40.90, 1.2225 shares of Common Stock per Forward Purchase Contract, in each case subject to adjustment as provided in the Forward Purchase Contract Agreement. No fractional shares of Common Stock will be issued upon settlement of Forward Purchase Contracts, as provided in the Forward Purchase Contract Agreement.
The "Applicable Market Value" means the average of the Closing Price per share of Common Stock on each of the 20 consecutive Trading Days ending on the third Trading Day immediately preceding the Stock Purchase Date.
The "Closing Price" of the Common Stock on any date of determination means the closing sale price (or, if no closing price is reported, the last reported sale price) of the Common Stock on the New York Stock Exchange (the "NYSE") on such date or, if the Common Stock is not listed for trading on the NYSE on any such date, as reported in the composite transactions for the principal United States securities exchange on which the Common Stock is so listed, or if the Common Stock is not so listed on a United States national or regional securities exchange, as reported by The NASDAQ Stock Market, or, if the Common Stock is not so reported, the last quoted bid price for the Common Stock in the over-the-counter market as reported by the National Quotation Bureau or similar organization, or, if such bid price is not available, the market value of the Common Stock on such date as determined by a nationally recognized independent investment banking firm retained for this purpose by the Company.
A "Trading Day" means a day on which the Common Stock (A) is not suspended from trading on any national or regional securities exchange or association or over-the-counter market at the close of business and (B) has traded at least once on the national or regional securities exchange or association or over-the-counter market that is the primary market for the trading of the Common Stock.
Each Forward Purchase Contract evidenced hereby may be settled prior to the Stock Purchase Date through Early Settlement or Merger Early Settlement, and may be settled on the Stock Purchase Date through Cash Settlement, all in accordance with the terms of the Forward Purchase Contract Agreement.
In accordance with the terms of the Forward Purchase Contract Agreement, the Holder of this Equity Units Certificate shall pay the Purchase Price for the shares of Common Stock purchased pursuant to each Forward Purchase Contract evidenced hereby (i) by effecting a Cash Settlement, Early Settlement or Merger Early Settlement, (ii) by application of payments received in respect of the Pledged Treasury Consideration acquired from the proceeds of a remarketing of the related Pledged Notes underlying the Equity Units represented by this Equity Units Certificate, (iii) if the Holder has elected not to participate in the remarketing, by application of payments received in respect of the Pledged Treasury Consideration deposited by such Holder in respect of such Forward Purchase Contract, or (iv) if a Tax Event Redemption has occurred prior to the successful remarketing of the Notes, by application of payments received in respect of the Pledged Applicable Ownership Interest in the Treasury Portfolio purchased by the Collateral Agent on behalf of the Holder of this Equity Units Certificate. If, as provided in the Forward Purchase Contract Agreement, upon the occurrence of the Last Failed Remarketing, the Collateral Agent, for the benefit of the Company, exercises its rights as a secured creditor with respect to the Pledged Notes related to this Equity Units Certificate, any accrued and unpaid interest on such Pledged Notes will become payable by the Company to the Holder of this Equity Units Certificate in the manner provided for in the Forward Purchase Contract Agreement.
The Company shall not be obligated to issue any shares of Common Stock in respect of a Forward Purchase Contract or deliver any certificates or book-entry interest therefor to the Holder unless it shall have received payment in full of the aggregate Purchase Price for the shares of Common Stock to be purchased thereunder in the manner herein set forth.
Under the terms of the Pledge Agreement, the Agent will be entitled to exercise the voting and any other consensual rights pertaining to the Pledged Notes, but only to the extent instructed by the Holders as described below. Upon receipt of notice of any meeting at which holders of Notes are entitled to vote or upon the solicitation of consents, waivers or proxies of holders of Notes, the Agent shall, as soon as practicable thereafter, mail to the Holders of Equity Units a notice (a) containing such information as is contained in the notice or solicitation, (b) stating that each such Holder on the record date set by the Agent therefor (which, to the extent possible, shall be the same date as the record date for determining the holders of Notes entitled to vote) shall be entitled to instruct the Agent as to the exercise of the voting rights pertaining to the Pledged Notes constituting a part of such Holder's Equity Units and (c) stating the manner in which such instructions may be given. Upon the written request of the Holders of Equity Units on such record date, the Agent shall endeavor insofar as practicable to vote or cause to be voted, in accordance with the instructions set forth in such requests, the maximum number of Pledged Notes as to which any particular voting instructions are received. In the absence of specific instructions from the Holder of an Equity Unit, the Agent shall abstain from voting the Pledged Note evidenced by such Equity Units.
The Equity Units Certificates are issuable only in registered form and only in denominations of a single Equity Unit and any integral multiple thereof. The transfer of any Equity Units Certificate will be registered and Equity Units Certificates may be exchanged as provided in the Forward Purchase Contract Agreement. The Equity Units Registrar may require a Holder, among other things, to furnish appropriate endorsements and transfer documents permitted by the Forward Purchase Contract Agreement. No service charge shall be required for any such registration of transfer or exchange, but the Company and the Agent may require payment of a sum sufficient to cover any tax or other governmental charge payable in connection therewith. The Holder of an Equity Units may substitute for the Pledged Notes securing its obligations under the related Forward Purchase Contract Treasury Securities in accordance with the terms of the Forward Purchase Contract Agreement and the Pledge Agreement. From and after such Collateral Substitution, the Units for which such Pledged Treasury Securities secure the Holder's obligation under the Forward Purchase Contract shall be referred to as a "Stripped Unit." A Holder that elects to substitute a Treasury Security for Pledged Notes thereby creating Stripped Units, shall be responsible for any fees or expenses payable in connection therewith. Except as provided in the Forward Purchase Contract Agreement, for so long as the Forward Purchase Contract underlying an Equity Unit remains in effect, such Equity Unit shall not be separable into its constituent parts, and the rights and obligations of the Holder of such Equity Unit in respect of the Pledged Note and Forward Purchase Contract constituting such Equity Unit may be transferred and exchanged only as an Equity Unit.
A Holder of Stripped Units may reestablish Equity Units by delivering to the Collateral Agent Notes in exchange for the release of the Pledged Treasury Securities in accordance with the terms of the Forward Purchase Contract Agreement and the Pledge Agreement.
Subject to the next succeeding paragraph, the Company shall pay on each Payment Date, the Contract Adjustment Payments, if any, payable in respect of each Forward Purchase Contract to the Person in whose name the Equity Units Certificate evidencing such Forward Purchase Contract is registered at the close of business on the Record Date for such Payment Date. Contract Adjustment Payments, if any, will be payable at the office of the Agent in the City of New York or, at the option of the Company, by check mailed to the address of the Person entitled thereto at such address as it appears on the Equity Units Register or by wire transfer to the account designated by such Person in writing at least five Business Days prior to the applicable Payment Date.
The Company shall have the right, at any time prior to the Stock Purchase Date, to defer the payment of any or all of the Contract Adjustment Payments otherwise payable on any Payment Date, but only if the Company shall give the Holders and the Agent written notice of its election to defer Contract Adjustment Payments as provided in the Forward Purchase Contract Agreement. Any Contract Adjustment Payments so deferred shall, to the extent permitted by law, bear additional Contract Adjustment Payments thereon at the rate of 5.75% per year (computed on the basis of a 360-day year of twelve 30-day months), compounding on each succeeding Payment Date, until paid in full (such deferred installments of Contract Adjustment Payments, if any, together with the additional Contract Adjustment Payments, if any, accrued thereon, are referred to herein as the "Deferred Contract Adjustment Payments"). Deferred Contract Adjustment Payments, if any, shall be due on the next succeeding Payment Date except to the extent that payment is deferred pursuant to the Forward Purchase Contract Agreement. No Contract Adjustment Payments may be deferred to a date that is after the Stock Purchase Date and no such deferral period may end other than on a Payment Date.
In the event that the Company elects to defer the payment of Contract Adjustment Payments on the Forward Purchase Contracts until a Payment Date prior to the Stock Purchase Date, then all Deferred Contract Adjustment Payments, if any, shall be payable to the registered Holders as of the close of business on the Record Date immediately preceding such Payment Date.
In the event the Company exercises its option to defer the payment of
Contract Adjustment Payments, then, until the Deferred Contract Adjustment
Payments have been paid, the Company shall not declare or pay dividends on, make
distributions with respect to, or redeem, purchase or acquire, or make a
liquidation payment with respect to, any of its Common Stock other than (i)
purchases, redemptions or acquisitions of shares of Common Stock in connection
with any employment contract, benefit plan or other similar arrangement with or
for the benefit of employees, officers or directors or a stock purchase or
dividend reinvestment plan, or the satisfaction by the Company of its
obligations pursuant to any contract or security outstanding on the date the
Company exercises its rights to defer the Contract Adjustment Payments; (ii) as
a result of a reclassification of the Company's Capital Stock or the exchange or
conversion of one class or series of for another class or series of the
Company's Capital Stock; (iii) the purchase of fractional interests in shares of
any series of the Company's Common Stock pursuant to the conversion or exchange
provisions of such Common Stock or the security being converted or exchanged;
(iv) dividends or distributions in any series of the Company's Common Stock (or
rights to acquire Common Stock) or repurchases, acquisitions or redemptions of
Common Stock in connection with the issuance or exchange of any series of Common
Stock (or securities convertible into or exchangeable for shares of the
Company's Common Stock); or (v) redemptions, exchanges or repurchases of any
rights outstanding under a shareholder rights plan or the declaration or payment
thereunder of a dividend or distribution of or with respect to rights in the
future.
The Forward Purchase Contracts and all obligations and rights of the Company and the Holders thereunder, including, without limitation, the rights and obligations of the Holders to receive and the obligation of the Company to pay Contract Adjustment Payments, if any, or any Deferred Contract Adjustment Payments, and the rights of the Holders to purchase Common Stock, shall immediately and automatically terminate, without the necessity of any notice or action by any Holder, the Agent or the Company, if, on or prior to the Stock Purchase Date, a Termination Event shall have occurred. Upon the occurrence of a Termination Event, the Company shall promptly but in no event later than two Business Days thereafter give written notice to the Agent, the Collateral Agent and to the Holders, at their addresses as they appear in the Equity Units Register. Upon and after the occurrence of a Termination Event, the Collateral Agent shall release the Pledged Notes, Pledged Treasury Consideration or Pledged Applicable Ownership Interest in the Treasury Portfolio, as the case may be, from the Pledge in accordance with the provisions of the Pledge Agreement.
Upon registration of transfer of this Equity Units Certificate, the transferee shall be bound (without the necessity of any other action on the part of such transferee, except as may be required by the Agent pursuant to the Forward Purchase Contract Agreement), by the terms of the Forward Purchase Contract Agreement and the Forward Purchase Contracts evidenced hereby and the transferor shall be released from the obligations under the Forward Purchase Contracts evidenced by this Equity Units Certificate. The Company covenants and agrees, and the Holder, by its acceptance hereof, likewise covenants and agrees, to be bound by the provisions of this paragraph.
The Holder of this Equity Units Certificate, by its acceptance hereof, authorizes the Agent to enter into and perform the related Forward Purchase Contracts forming part of the Equity Units evidenced hereby on its behalf as its attorney-in-fact, expressly withholds any consent to the assumption (i.e., affirmance) of the Forward Purchase Contracts by the Company or its trustee in the event that the Company becomes the subject of a case under the Bankruptcy Code, agrees to be bound by the terms and provisions of the Forward Purchase Contracts, covenants and agrees to perform such Holder's obligations under such Forward Purchase Contracts, consents to the provisions of the Forward Purchase Contract Agreement, irrevocably authorizes the Agent to enter into and perform the Pledge Agreement on such Holder's behalf as attorney-in-fact, and consents to and agrees to be bound by the Pledge of the Notes or the appropriate Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, as the case may be, underlying this Equity Units Certificate pursuant to the Pledge Agreement, provided, that upon a Termination Event, the rights of the Holder of such Units under the Forward Purchase Contract may be enforced without regard to any other rights or obligations. The Holder further covenants and agrees, that, to the extent and in the manner provided in the Forward Purchase Contract Agreement and the Pledge Agreement, but subject to the terms thereof, payments in respect of the Pledged Notes, Pledged Treasury Consideration or Pledged Applicable Ownership Interest in the Treasury Portfolio, as the case may be, to be paid upon settlement of such Holder's obligations to purchase Common Stock under the Forward Purchase Contract, shall be paid on the Stock Purchase Date by the Collateral Agent to the Company in satisfaction of such Holder's obligations under such Forward Purchase Contract and such Holder shall acquire no right, title or interest in such payments.
The Company and each Holder of an Equity Unit, and each Beneficial Owner thereof, by its acceptance thereof or of its interest therein, further agrees to treat (i) the purchase of Equity Units as the purchase of a unit consisting of the Forward Purchase Contract and the Note and to allocate the purchase price of the Equity Unit between the Note and the Forward Purchase Contract as $50 and $0, respectively, and (ii) the holder as the owner of the applicable interest in the Collateral Account, including the related Notes, Treasury Consideration or Applicable Ownership Interest in the Treasury Portfolio, as the case may be.
Subject to certain exceptions, the provisions of the Forward Purchase Contract Agreement may be amended with the consent of the Holders of a majority of the Forward Purchase Contracts.
The Forward Purchase Contracts shall for all purposes be governed by, and construed in accordance with, the laws of the State of New York, without regard to its principles of conflicts of laws. The Company, the Agent and any agent of the Company or the Agent may treat the Person in whose name this Equity Units Certificate is registered as the owner of the Equity Units evidenced hereby for the purpose of receiving quarterly payments on the Notes, the Treasury Consideration or the Applicable Ownership Interest in the Treasury Portfolio, as the case may be, receiving payments of Contract Adjustment Payments, if any, and any Deferred Contract Adjustment Payments, performance of the Forward Purchase Contracts and for all other purposes whatsoever (subject to the Record Date provisions hereof), whether or not any payments in respect thereof be overdue and notwithstanding any notice to the contrary, and neither the Company, the Agent, nor any such agent shall be affected by notice to the contrary.
The Forward Purchase Contracts shall not, prior to the settlement thereof, entitle the Holder to any of the rights of a holder of shares of Common Stock.
A copy of the Forward Purchase Contract Agreement is available for inspection by any Holder at the Corporate Trust Office.
ABBREVIATIONS
The following abbreviations, when used in the inscription on the face of this instrument, shall be construed as though they were written out in full according to applicable laws or regulations:
TEN COM - as tenants in common
UNIF GIFT MIN ACT - Custodian
(cust) (minor)
Under Uniform Gifts to Minors Act
(State)
TEN ENT - as tenants by the entireties
JT TEN - as joint tenants with right of survivorship
and not as tenants in common
|
Additional abbreviations may also be used though not in the above list.
ASSIGNMENT
FOR VALUE RECEIVED, the undersigned hereby sell(s), assign(s) and transfer(s) unto
(Please insert Social Security or Taxpayer I.D. or other Identifying Number of Assignee)
(Please Print or Type Name and Address Including Postal Zip Code of Assignee)
the within Equity Units Certificate and all rights thereunder, hereby irrevocably constituting and appointing ___________________________ attorney to transfer said Equity Units Certificate on the books of American Electric Power Company, Inc. with full power of substitution in the premises.
Dated: _________________________
Signature: _____________________________
NOTICE: The signature to this assignment must correspond with the name as it appears upon the face of the within Equity Units Certificate in every particular, without alteration or enlargement or any change whatsoever.
Signature Guarantee: ___________________________.
SETTLEMENT INSTRUCTIONS
The undersigned Holder directs that a certificate or book-entry interest for shares of Common Stock deliverable upon settlement on or after the Stock Purchase Date of the Forward Purchase Contracts underlying the number of Equity Units evidenced by this Equity Units Certificate be registered in the name of, and delivered, together with a check in payment for any fractional share, to the undersigned at the address indicated below unless a different name and address have been indicated below. If shares are to be registered in the name of a Person other than the undersigned, the undersigned will pay any transfer tax payable incident thereto.
Dated: ______________________ Signature: _________________________
Signature Guarantee: _______________
(if assigned to another person)
|
If shares are to be registered in the name of REGISTERED HOLDER and delivered to a Person other than the Holder, please (i) print such Person's name Please print name and address of and address and (ii) provide a guarantee of Registered Holder: your signature:
Name Name Address Address Social Security or other Taxpayer Identification Number, if any |
ELECTION TO SETTLE EARLY
The undersigned Holder of this Equity Units Certificate hereby irrevocably exercises the option to effect Early Settlement in accordance with the terms of the Forward Purchase Contract Agreement with respect to the Forward Purchase Contracts underlying the number of Equity Units evidenced by this Equity Units Certificate specified below. The option to effect Early Settlement may be exercised only with respect to Forward Purchase Contracts underlying Equity Units with an aggregate Stated Amount equal to $1,000 or an integral multiple thereof. The undersigned Holder directs that a certificate or book-entry interest for shares of Common Stock deliverable upon such Early Settlement be registered in the name of, and delivered, together with a check in payment for any fractional share and any Equity Units Certificate representing any Equity Units evidenced hereby as to which Early Settlement of the related Forward Purchase Contracts is not effected, to the undersigned at the address indicated below unless a different name and address have been indicated below. The Pledged Notes, Pledged Treasury Consideration or Pledged Applicable Ownership Interest in the Treasury Portfolio, as the case may be, deliverable upon such Early Settlement will be transferred in accordance with the transfer instructions set forth below. If shares are to be registered in the name of a Person other than the undersigned, the undersigned will pay any transfer tax payable incident thereto.
Dated: ____________________ Signature: ___________________________
Signature Guarantee: _________________
Number of Units evidenced hereby as to which Early Settlement of the related Forward Purchase Contracts is being elected:
If shares of Common Stock are to be EGISTERED HOLDER registered in the name of and delivered to and Pledged Notes, Please print name and address of Pledged Treasury Consideration or Registered Holder: Pledged Applicable Ownership Interest in the Treasury Portfolio, as the case may be, are to be transferred to a Person other than the Holder, please print such Person's name and address: Name Name Address Address Social Security or other Taxpayer Identification Number, if any |
Transfer instructions for Pledged Notes, Pledged Treasury Consideration or the Pledged Applicable Ownership Interest in the Treasury Portfolio, as the case may be, transferable upon Early Settlement or a Termination Event:
(TO BE ATTACHED TO GLOBAL CERTIFICATES)
SCHEDULE OF INCREASES OR DECREASES IN GLOBAL CERTIFICATE
The following increases or decreases in this Global Certificate have been
made:
Stated Amount of the
Amount of Decrease in Amount of Increase in Global Certificate
Stated Amount of the Stated Amount of the Following Such Decrease Signature of
Date Global Certificate Global Certificate or Increase Authorized Signatory
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EXHIBIT B
FORM OF STRIPPED UNITS CERTIFICATE
[FOR INCLUSION IN GLOBAL CERTIFICATES ONLY -- THIS CERTIFICATE IS A GLOBAL
CERTIFICATE WITHIN THE MEANING OF THE FORWARD PURCHASE CONTRACT AGREEMENT (AS HEREINAFTER DEFINED) AND IS REGISTERED IN THE NAME OF A CLEARING AGENCY OR A NOMINEE THEREOF. THIS CERTIFICATE MAY NOT BE EXCHANGED IN WHOLE OR IN PART FOR A CERTIFICATE REGISTERED, AND NO TRANSFER OF THIS CERTIFICATE IN WHOLE OR IN PART MAY BE REGISTERED, IN THE NAME OF ANY PERSON OTHER THAN SUCH CLEARING AGENCY OR A NOMINEE THEREOF, EXCEPT IN THE LIMITED CIRCUMSTANCES DESCRIBED IN THE FORWARD PURCHASE CONTRACT AGREEMENT.
Unless this Certificate is presented by an authorized representative of The Depository Trust Company (55 Water Street, New York, New York) to the Company or its agent for registration of transfer, exchange or payment, and any Certificate issued is registered in the name of Cede & Co., or such other name as requested by an authorized representative of The Depository Trust Company, and any payment hereon is made to Cede & Co., ANY TRANSFER, PLEDGE OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY A PERSON IS WRONGFUL since the registered owner hereof, Cede & Co., has an interest herein.]
(Form of Face of Stripped Units Certificate)
No. CUSIP No. ____________
Number of Stripped Units
This Stripped Units Certificate certifies that [For inclusion in Global
Certificates only -- Cede & Co.] is the registered Holder of the number of
Stripped Units set forth above [For inclusion in Global Certificates only - or
such other number of Stripped Units reflected in the Schedule of Increases or
Decreases in Global Certificate attached hereto]. Each Stripped Unit represents
(i) a 1/20 undivided beneficial ownership interest in a Treasury Security,
subject to the Pledge of such interest in such Treasury Security by such Holder
pursuant to the Pledge Agreement, and (ii) the rights and obligations of the
Holder under one Forward Purchase Contract with American Electric Power Company,
Inc., a New York corporation (the "Company"). All capitalized terms used herein
which are defined in the Forward Purchase Contract Agreement have the meaning
set forth therein.
Pursuant to the Pledge Agreement, the Treasury Security constituting part of each Stripped Unit evidenced hereby has been pledged to the Collateral Agent, for the benefit of the Company, to secure the obligations of the Holder under the Forward Purchase Contract comprising a part of such Stripped Units.
Each Forward Purchase Contract evidenced hereby obligates the Holder of this Stripped Units Certificate to purchase, and the Company to sell, on the Stock Purchase Date, at a price equal to $50 (the "Stated Amount"), a number of shares of common stock, $6.50 par value per share ("Common Stock"), of the Company, equal to the Settlement Rate, unless on or prior to the Stock Purchase Date there shall have occurred a Termination Event or an Early Settlement, Merger Early Settlement or Cash Settlement with respect to the Stripped Units of which such Forward Purchase Contract is a part, all as provided in the Forward Purchase Contract Agreement and more fully described on the reverse hereof. The Purchase Price (as defined herein) for the shares of Common Stock purchased pursuant to each Forward Purchase Contract evidenced hereby, if not paid earlier, shall be paid on the Stock Purchase Date by application of payments received in respect of the Pledged Treasury Securities pledged to secure the obligations under such Forward Purchase Contract in accordance with the terms of the Pledge Agreement.
The Company shall pay on each Payment Date in respect of each Forward Purchase Contract forming part of a Stripped Units evidenced hereby an amount (the "Contract Adjustment Payments") equal to 3.50% per year of the Stated Amount, computed on the basis of a 360-day year of twelve 30-day months, subject to deferral at the option of the Company as provided in the Forward Purchase Contract Agreement and more fully described on the reverse hereof (provided that if any date on which Contract Adjustment Payments are to be made on the Forward Purchase Contracts is not a Business Day, then payment of the Contract Adjustment Payments payable on that date will be made on the next succeeding day which is a Business Day, and no interest or payment will be paid in respect of the delay, except that if such next succeeding Business Day is in the next succeeding calendar year, such payment will be made on the immediately preceding Business Day). Such Contract Adjustment Payments shall be payable to the Person in whose name this Stripped Units Certificate (or a Predecessor Stripped Units Certificate) is registered at the close of business on the Record Date for such Payment Date.
Contract Adjustment Payments, if any, will be payable at the Office of the Agent in the City of New York or, at the option of the Company, by check mailed to the address of the Person entitled thereto at such address as it appears on the Stripped Units Register or by wire transfer to the account designated by such Person in writing at least five Business Days prior to the applicable Payment Date.
Reference is hereby made to the further provisions set forth on the reverse hereof, which further provisions shall for all purposes have the same effect as if set forth at this place.
Unless the certificate of authentication hereon has been executed by the Agent by manual signature, this Stripped Units Certificate shall not be entitled to any benefit under the Pledge Agreement or the Forward Purchase Contract Agreement or be valid or obligatory for any purpose.
IN WITNESS WHEREOF, the Company has caused this instrument to be duly executed.
AMERICAN ELECTRIC POWER COMPANY, INC.
By: ____________________________________
Name:
Title:
HOLDER SPECIFIED ABOVE (as to obligations of such
Holder under the Forward Purchase Contracts)
By: THE BANK OF NEW YORK, not individually but
solely as Attorney-in-Fact of such Holder
By: ____________________________________
Authorized Signatory
AGENT'S CERTIFICATE OF AUTHENTICATION
This is one of the Stripped Units referred to in the within-mentioned Forward Purchase Contract Agreement.
THE BANK OF NEW YORK,
as Forward Purchase Contract Agent
Dated: June 11, 2002 By:_____________________________________ Authorized Signatory
(Reverse of Stripped Units Certificate)
Each Forward Purchase Contract evidenced hereby is governed by a Forward Purchase Contract Agreement, dated as of June 11, 2002 (as may be supplemented from time to time, the "Forward Purchase Contract Agreement"), between the Company and The Bank of New York, as Forward Purchase Contract Agent (including its successors thereunder, herein called the "Agent"), to which Forward Purchase Contract Agreement and supplemental agreements thereto reference is hereby made for a description of the respective rights, limitations of rights, obligations, duties and immunities thereunder of the Agent, the Company and the Holders and of the terms upon which the Stripped Units Certificates are, and are to be, executed and delivered.
Each Forward Purchase Contract evidenced hereby obligates the Holder of this Stripped Units Certificate to purchase, and the Company to sell, on the Stock Purchase Date at a price equal to $50 (the "Purchase Price"), a number of shares of Common Stock of the Company equal to the Settlement Rate, unless, on or prior to the Stock Purchase Date, there shall have occurred a Termination Event or an Early Settlement or Merger Early Settlement with respect to the Stripped Units of which such Forward Purchase Contract is a part. The "Settlement Rate" is equal to (a) if the Applicable Market Value (as defined below) is greater than or equal to $49.08 (the "Threshold Appreciation Price"), 1.0187 shares of Common Stock per Forward Purchase Contract, (b) if the Applicable Market Value is less than the Threshold Appreciation Price but is greater than $40.90, the number of shares of Common Stock per Forward Purchase Contract equal to the Stated Amount of the related Stripped Units divided by the Applicable Market Value and (c) if the Applicable Market Value is less than or equal $40.90, 1.2225 shares of Common Stock per Forward Purchase Contract, in each case subject to adjustment as provided in the Forward Purchase Contract Agreement. No fractional shares of Common Stock will be issued upon settlement of Forward Purchase Contracts, as provided in the Forward Purchase Contract Agreement.
The "Applicable Market Value" means the average of the Closing Price per share of Common Stock on each of the 20 consecutive Trading Days ending on the third Trading Day immediately preceding the Stock Purchase Date.
The "Closing Price" of the Common Stock on any date of determination means the closing sale price (or, if no closing price is reported, the last reported sale price) of the Common Stock on the New York Stock Exchange (the "NYSE") on such date or, if the Common Stock is not listed for trading on the NYSE on any such date, as reported in the composite transactions for the principal United States securities exchange on which the Common Stock is so listed, or if the Common Stock is not so listed on a United States national or regional securities exchange, as reported by The NASDAQ Stock Market, or, if the Common Stock is not so reported, the last quoted bid price for the Common Stock in the over-the-counter market as reported by the National Quotation Bureau or similar organization, or, if such bid price is not available, the market value of the Common Stock on such date as determined by a nationally recognized independent investment banking firm retained for this purpose by the Company.
A "Trading Day" means a day on which the Common Stock (A) is not suspended from trading on any national or regional securities exchange or association or over-the-counter market at the close of business and (B) has traded at least once on the national or regional securities exchange or association or over-the-counter market that is the primary market for the trading of the Common Stock.
Each Forward Purchase Contract evidenced hereby may be settled prior to the Stock Purchase Date through Early Settlement or Merger Early Settlement, and may be settled on the Stock Purchase Date through Cash Settlement, all in accordance with the terms of the Forward Purchase Contract Agreement.
In accordance with the terms of the Forward Purchase Contract Agreement, the Holder of this Stripped Units Certificate shall pay the Purchase Price for the shares of Common Stock purchased pursuant to each Forward Purchase Contract evidenced hereby (i) by effecting an Early Settlement, Merger Early Settlement or Cash Settlement or (ii) by application of payments received in respect of the Pledged Treasury Securities underlying the Stripped Units represented by this Stripped Units Certificate.
The Company shall not be obligated to issue any shares of Common Stock in respect of a Forward Purchase Contract or deliver any certificates or book-entry interest therefor to the Holder unless it shall have received payment in full of the aggregate Purchase Price for the shares of Common Stock to be purchased thereunder in the manner herein set forth.
The Stripped Units Certificates are issuable only in registered form and only in denominations of a single Stripped Units and any integral multiple thereof. The transfer of any Stripped Units Certificate will be registered and Stripped Units Certificates may be exchanged as provided in the Forward Purchase Contract Agreement. The Stripped Units Registrar may require a Holder, among other things, to furnish appropriate endorsements and transfer documents permitted by the Forward Purchase Contract Agreement. No service charge shall be required for any such registration of transfer or exchange, but the Company and the Agent may require payment of a sum sufficient to cover any tax or other governmental charge payable in connection therewith. The Holder of a Stripped Unit may substitute for the Pledged Treasury Securities securing its obligations under the related Forward Purchase Contract Notes in accordance with the terms of the Forward Purchase Contract Agreement and the Pledge Agreement. From and after such substitution, the Units for which such Pledged Notes secure the Holder's obligation under the Forward Purchase Contract shall be referred to as an "Equity Unit." A Holder that elects to substitute Notes for Pledged Treasury Securities, thereby reestablishing Equity Units, shall be responsible for any fees or expenses payable in connection therewith. Except as provided in the Forward Purchase Contract Agreement, for so long as the Forward Purchase Contract underlying a Stripped Unit remains in effect, such Stripped Units shall not be separable into its constituent parts, and the rights and obligations of the Holder of such Stripped Units in respect of the Pledged Treasury Security and the Forward Purchase Contract constituting such Stripped Units may be transferred and exchanged only as a Stripped Unit.
Subject to the next succeeding paragraph, the Company shall pay on each Payment Date, the Contract Adjustment Payments, if any, payable in respect of each Forward Purchase Contract to the Person in whose name the Stripped Units Certificate evidencing such Forward Purchase Contract is registered at the close of business on the Record Date for such Payment Date. Contract Adjustment Payments, if any, will be payable at the Office of the Agent in the City of New York or, at the option of the Company, by check mailed to the address of the Person entitled thereto at such address as it appears on the Stripped Units Register or by wire transfer to the account designated by such Person in writing at least five Business Days prior to the applicable Payment Date.
The Company shall have the right, at any time prior to the Stock Purchase Date, to defer the payment of any or all of the Contract Adjustment Payments otherwise payable on any Payment Date, but only if the Company shall give the Holders and the Agent written notice of its election to defer Contract Adjustment Payments as provided in the Forward Purchase Contract Agreement. Any Contract Adjustment Payments so deferred shall, to the extent permitted by law, bear additional Contract Adjustment Payments thereon at the rate of 5.75% per year (computed on the basis of a 360-day year of twelve 30-day months), compounding on each succeeding Payment Date, until paid in full (such deferred installments of Contract Adjustment Payments, if any, together with the additional Contract Adjustment Payments, if any, accrued thereon, are referred to herein as the "Deferred Contract Adjustment Payments"). Deferred Contract Adjustment Payments, if any, shall be due on the next succeeding Payment Date except to the extent that payment is deferred pursuant to the Forward Purchase Contract Agreement. No Contract Adjustment Payments may be deferred to a date that is after the Stock Purchase Date and no such deferral period may end other than on a Payment Date.
In the event that the Company elects to defer the payment of Contract Adjustment Payments on the Forward Purchase Contracts until a Payment Date prior to the Stock Purchase Date, then all Deferred Contract Adjustment Payments, if any, shall be payable to the registered Holders as of the close of business on the Record Date immediately preceding such Payment Date.
In the event the Company exercises its option to defer the payment of Contract Adjustment Payments, then, until the Deferred Contract Adjustment Payments have been paid, the Company shall not declare or pay dividends on, make distributions with respect to, or redeem, purchase or acquire, or make a liquidation payment with respect to, any of its Common Stock other than (i) purchases, redemptions or acquisitions of shares of Common Stock in connection with any employment contract, benefit plan or other similar arrangement with or for the benefit of employees, officers or directors or a stock purchase or dividend reinvestment plan, or the satisfaction by the Company of its obligations pursuant to any contract or security outstanding on the date the Company exercises its rights to defer the Contract Adjustment Payments; (ii) as a result of a reclassification of the Company's Capital Stock or the exchange or conversion of one class or series of the Company's Capital Stock for another class or series of the Company's Capital Stock; (iii) the purchase of fractional interests in shares of any series of the Company's Common Stock pursuant to the conversion or exchange provisions of such Common Stock or the security being converted or exchanged; (iv) dividends or distributions in any series of the Company's Common Stock (or rights to acquire Common Stock) or repurchases, acquisitions or redemptions of Common Stock in connection with the issuance or exchange of any series of Common Stock (or securities convertible into or exchangeable for shares of the Company's Common Stock; or (v) redemptions, exchanges or repurchases of any rights outstanding under a shareholder rights plan or the declaration or payment thereunder of a dividend or distribution of or with respect to rights in the future.
The Forward Purchase Contracts and all obligations and rights of the Company and the Holders thereunder, including, without limitation, the rights and obligations of Holders to receive and the obligation of the Company to pay Contract Adjustment Payments, if any, or any Deferred Contract Adjustment Payments, and the rights and obligations of Holders to purchase Common Stock, shall immediately and automatically terminate, without the necessity of any notice or action by any Holder, the Agent or the Company, if, on or prior to the Stock Purchase Date, a Termination Event shall have occurred. Upon the occurrence of a Termination Event, the Company shall promptly but in no event later than two Business Days thereafter give written notice to the Agent, the Collateral Agent and to the Holders, at their addresses as they appear in the Stripped Units Register. Upon and after the occurrence of a Termination Event, the Collateral Agent shall release the Pledged Treasury Securities from the Pledge in accordance with the provisions of the Pledge Agreement.
Upon registration of transfer of this Stripped Units Certificate, the transferee shall be bound (without the necessity of any other action on the part of such transferee, except as may be required by the Agent pursuant to the Forward Purchase Contract Agreement), by the terms of the Forward Purchase Contract Agreement and the Forward Purchase Contracts evidenced hereby and the transferor shall be released from the obligations under the Forward Purchase Contracts evidenced by this Stripped Units Certificate. The Company covenants and agrees, and the Holder, by its acceptance hereof, likewise covenants and agrees, to be bound by the provisions of this paragraph.
The Holder of this Stripped Units Certificate, by its acceptance hereof, authorizes the Agent to enter into and perform the related Forward Purchase Contracts forming part of the Stripped Units evidenced hereby on its behalf as its attorney-in-fact, expressly withholds any consent to the assumption (i.e., affirmance) of the Forward Purchase Contracts by the Company or its trustee in the event that the Company becomes the subject of a case under the Bankruptcy Code, agrees to be bound by the terms and provisions of the Forward Purchase Contracts, covenants and agrees to perform such Holder's obligations under such Forward Purchase Contracts, consents to the provisions of the Forward Purchase Contract Agreement, irrevocably authorizes the Agent to enter into and perform the Pledge Agreement on such Holder's behalf as attorney-in-fact, and consents to and agrees to be bound by the Pledge of the Treasury Securities underlying this Stripped Units Certificate pursuant to the Pledge Agreement, provided, that upon a Termination Event, the rights of the Holder of such Units under the Forward Purchase Contract may be enforced without regard to any other rights or obligations. The Holder further covenants and agrees, that, to the extent and in the manner provided in the Forward Purchase Contract Agreement and the Pledge Agreement, but subject to the terms thereof, payments in respect of the Pledged Treasury Securities, to be paid upon settlement of such Holder's obligations to purchase Common Stock under the Forward Purchase Contract, shall be paid on the Stock Purchase Date by the Collateral Agent to the Company in satisfaction of such Holder's obligations under such Forward Purchase Contract and such Holder shall acquire no right, title or interest in such payments.
The Company and each Holder of any Stripped Units, and each Beneficial Owner thereof, by its acceptance thereof or of its interest therein, further agrees to treat (i) the formation of Stripped Units as the purchase of a unit consisting of the Purchase Contract and the Treasury Securities and (ii) the holder as the owner of the applicable interest in the Collateral Account, including the Treasury Securities.
Subject to certain exceptions, the provisions of the Forward Purchase Contract Agreement may be amended with the consent of the Holders of a majority of the Forward Purchase Contracts.
The Forward Purchase Contracts shall for all purposes be governed by, and construed in accordance with, the laws of the State of New York, without regard to its principles of conflicts of laws.
The Company, the Agent and any agent of the Company or the Agent may treat the Person in whose name this Stripped Units Certificate is registered as the owner of the Stripped Units evidenced hereby for the purpose of receiving any Contract Adjustment Payments and any Deferred Contract Adjustment Payments, performance of the Forward Purchase Contracts and for all other purposes whatsoever (subject to the Record Date provisions hereof), whether or not any payments in respect thereof be overdue and notwithstanding any notice to the contrary, and neither the Company, the Agent, nor any such agent shall be affected by notice to the contrary.
The Forward Purchase Contracts shall not, prior to the settlement thereof, entitle the Holder to any of the rights of a holder of shares of Common Stock.
A copy of the Forward Purchase Contract Agreement is available for inspection by any Holder at the Corporate Trust Office.
ABBREVIATIONS
The following abbreviations, when used in the inscription on the face of this instrument, shall be construed as though they were written out in full according to applicable laws or regulations:
TEN COM - as tenants in common
UNIF GIFT MIN ACT - Custodian
(cust) (minor)
Under Uniform Gifts to Minors Act
(State)
TEN ENT - as tenants by the entireties
JT TEN - as joint tenants with right of survivorship and
not as tenants in common
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Additional abbreviations may also be used though not in the above list.
ASSIGNMENT
FOR VALUE RECEIVED, the undersigned hereby sell(s), assign(s) and transfer(s) unto
(Please insert Social Security or Taxpayer I.D. or other Identifying Number of Assignee)
(Please Print or Type Name and Address Including Postal Zip Code of Assignee)
the within Stripped Units Certificate and all rights thereunder, hereby irrevocably constituting and appointing ____________________________ attorney to transfer said Stripped Units Certificate on the books of American Electric Power Company, Inc. with full power of substitution in the premises.
Dated: ______________________ Signature: ___________________________
NOTICE: The signature to this assignment must correspond with the name as it appears upon the face of the within Stripped Units Certificate in every particular, without alteration or enlargement or any change whatsoever.
Signature Guarantee: ________________________
SETTLEMENT INSTRUCTIONS
The undersigned Holder directs that a certificate or book-entry interest for shares of Common Stock deliverable upon settlement on or after the Stock Purchase Date of the Forward Purchase Contracts underlying the number of Stripped Units evidenced by this Stripped Units Certificate be registered in the name of, and delivered, together with a check in payment for any fractional share, to the undersigned at the address indicated below unless a different name and address have been indicated below. If shares are to be registered in the name of a Person other than the undersigned, the undersigned will pay any transfer tax payable incident thereto.
Dated: ___________________ Signature: _________________________________
Signature Guarantee: _______________________
(if assigned to another person)
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If shares are to be registered in the REGISTERED HOLDER
name of and delivered to a Person other
than the Holder, please (i) print such Please print name and address of
Person's name and address and (ii) Registered Holder: provide a guarantee of your signature: Name Name Address Address Social Security or other Taxpayer Identification Number, if any |
ELECTION TO SETTLE EARLY
The undersigned Holder of this Stripped Units Certificate hereby irrevocably exercises the option to effect Early Settlement in accordance with the terms of the Forward Purchase Contract Agreement with respect to the Forward Purchase Contracts underlying the number of Stripped Units evidenced by this Stripped Units Certificate specified below. The option to effect Early Settlement may be exercised only with respect to Forward Purchase Contracts underlying Stripped Units with an aggregate Stated Amount equal to $1,000 or an integral multiple thereof. The undersigned Holder directs that a certificate or book-entry interest for shares of Common Stock deliverable upon such Early Settlement be registered in the name of, and delivered, together with a check in payment for any fractional share and any Stripped Units Certificate representing any Stripped Units evidenced hereby as to which Early Settlement of the related Forward Purchase Contracts is not effected, to the undersigned at the address indicated below unless a different name and address have been indicated below. Pledged Treasury Securities deliverable upon such Early Settlement will be transferred in accordance with the transfer instructions set forth below. If shares are to be registered in the name of a Person other than the undersigned, the undersigned will pay any transfer tax payable incident thereto.
Dated: ____________________ Signature: ___________________________________
Signature Guarantee: _________________________
Number of Stripped Units evidenced hereby as to which Early Settlement of the related Forward Purchase Contracts is being elected:
If shares of Common Stock are to be REGISTERED HOLDER registered in the name of and delivered to and Pledged Treasury Please print name and address of Securities are to be transferred to Registered Holder: a Person other than the Holder, please print such Person's name and address: Name Name Address Address Social Security or other Taxpayer Identification Number, if any |
Transfer instructions for Pledged Treasury Securities transferable upon Early Settlement or a Termination Event:
(TO BE ATTACHED TO GLOBAL CERTIFICATES)
SCHEDULE OF INCREASES OR DECREASES IN GLOBAL CERTIFICATE
The following increases or decreases in this Global Certificate have been
made:
Stated Amount of the
Amount of Decrease in Amount of Increase in Global Certificate
Stated Amount of the Stated Amount of the Following Such Signature of
Date Global Certificate Global Certificate Decrease or Increase Authorized Signatory
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EXHIBIT C
INSTRUCTION FROM FORWARD PURCHASE CONTRACT AGENT
TO COLLATERAL AGENT
The Bank of New York
101 Barclay Street
New York, New York 10286
Attention: Corporate Trust Department
We hereby notify you in accordance with Section [4.1] [4.2] of the Pledge
Agreement, dated as of June 11, 2002, (the "Pledge Agreement") among the
Company, you, as Collateral Agent, Custodial Agent and Securities Intermediary
and us, as Forward Purchase Contract Agent and as attorney-in-fact for the
holders of [Equity Units] [Stripped Units] from time to time, that the Holder of
Equity Units and Stripped Units listed below (the "Holder") has elected to
substitute [$_____ aggregate principal amount of Treasury Securities (CUSIP No.
_____________)] [$_______ aggregate principal amount of Notes] in exchange for
the related [Pledged Notes] [Pledged Treasury Securities] held by you in
accordance with the Pledge Agreement and has delivered to us a notice stating
that the Holder has Transferred [Treasury Securities] [Notes] to you, as
Collateral Agent. We hereby instruct you, upon receipt of such [Pledged Treasury
Securities] [Pledged Notes], and upon the payment by such Holder of any
applicable fees, to release the [Notes] [Treasury Securities] related to such
[Equity Units] [Stripped Units] to us in accordance with the Holder's
instructions. Capitalized terms used herein but not defined shall have the
meaning set forth in the Pledge Agreement.
Date: _____________________
THE BANK OF NEW YORK,
as Forward Purchase Contract Agent
By: _________________________________
Name:
Title:
Please print name and address of Registered Holder electing to substitute
[Treasury Securities] [Notes] for the [Pledged Notes] [Pledged Treasury
Securities]:
Name:
Social Security or other Taxpayer
Identification Number, if any:
Address:
EXHIBIT D
INSTRUCTION TO FORWARD PURCHASE CONTRACT AGENT
The Bank of New York,
as Forward Purchase Contract Agent
101 Barclay Street
New York, New York 10286
Attention: Corporate Trust Department
Telecopy:
The undersigned Holder hereby notifies you that it has delivered to The Bank of New York, as Collateral Agent, Custodial Agent and Securities Intermediary [$_______ aggregate principal amount of Treasury Securities (CUSIP No. ______________)] [$_______ aggregate principal amount of Notes] in exchange for the related [Pledged Notes] [Pledged Treasury Securities] held by the Collateral Agent, in accordance with Section [4.1] [4.2] of the Pledge Agreement, dated June 11, 2002 (the "Pledge Agreement"), among you, the Company and the Collateral Agent. The undersigned Holder has paid the Collateral Agent all applicable fees relating to such exchange. The undersigned Holder hereby instructs you to instruct the Collateral Agent to release to you on behalf of the undersigned Holder the [Pledged Notes] [Pledged Treasury Securities] related to such [Equity Units] [Stripped Units]. Capitalized terms used herein but not defined shall have the meaning set forth in the Pledge Agreement.
Date: ___________________ Signature:_________________________________
Signature Guarantee:_______________________
Please print name and address of Registered Holder:
Name:
Social Security or other Taxpayer Identification Number, if any:
Address:
EXHIBIT E
NOTICE TO SETTLE BY CASH
The Bank of New York,
as Forward Purchase Contract Agent
101 Barclay Street
New York, New York 10286
Attention: Corporate Trust Department
Telecopy: (212) 328-8243
The undersigned Holder hereby irrevocably notifies you in accordance with
Section 5.4 of the Forward Purchase Contract Agreement dated as of June 11, 2002
among the Company and yourselves, as Forward Purchase Contract Agent and as
Attorney-in-Fact for the Holders of the Forward Purchase Contracts, that such
Holder has elected to pay to the Collateral Agent, on or prior to 11:00 a.m. New
York City time, on the seventh Business Day immediately preceding the Stock
Purchase Date, (in lawful money of the United States by [certified or cashiers
check or] wire transfer, in each case in immediately available funds),
$_________ as the Purchase Price for the shares of Common Stock issuable to such
Holder by the Company under the related Forward Purchase Contract on the Stock
Purchase Date. The undersigned Holder hereby instructs you to notify promptly
the Collateral Agent of the undersigned Holder's election to make such cash
settlement with respect to the Forward Purchase Contracts related to such
Holder's Equity Units.
Dated:_____________ __________________________________________
Signature
Signature Guarantee:_______________
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Signatures must be guaranteed by an "eligible guarantor institution" meeting the requirements of the Registrar, which requirements include membership or participation in the Security Transfer Agent Medallion Program ("STAMP") or such other "signature guarantee program" as may be determined by the Registrar in addition to, or in substitution for, STAMP, all in accordance with the Securities Exchange Act of 1934, as amended.
Please print name and address of Registered Holder:
Social Security or other Taxpayer Identification Number, if any:
EXHIBIT 10(b)
RESTATED AND AMENDED
OPERATING AGREEMENT
Among
Central Power and Light Company
Public Service Company of Oklahoma
Southwestern Electric Power Company
West Texas Utilities Company
Central and South West Services, Inc.
January 1, 1998
OPERATING AGREEMENT
TABLE OF CONTENTS
Page
ARTICLE I
TERM OF AGREEMENT........................... 2
ARTICLE II
DEFINITIONS.............................. 2
2.1 Agent..................................................... 3
2.2 Agreement................................................. 3
2.3 Capacity Commitment....................................... 3
2.4 Capacity Commitment Charge................................ 3
2.5 Central Control Center.................................... 3
2.6 Chief Executive Officer (CEO)............................. 3
2.7 Company................................................... 3
2.8 Company Capability........................................ 3
2.9 Company Demand............................................ 4
2.10 Company Hourly Capability................................. 4
2.11 Company Load Responsibility............................... 4
2.12 Company Operating Capability.............................. 5
2.13 Company Operating Reserve................................. 5
2.14 Company Peak Demand....................................... 5
2.15 Day....................................................... 5
2.16 Decremental Energy Value.................................. 5
2.17 Economic Dispatch......................................... 5
2.18 Energy.................................................... 5
2.19 Generating Unit........................................... 5
2.20 Hour...................................................... 6
2.21 Incremental Energy Cost................................... 6
2.22 Internal Economy Energy................................... 6
2.23 Joint Resource Plan....................................... 6
2.24 Joint Unit................................................ 6
2.25 (a) Margin on Sales.................................. 6
2.25 (b) Margin on Purchases.............................. 6
2.25 (c) Margin on Internal Economy Energy................ 6
2.25 (d) Margin........................................... 7
2.26 Month..................................................... 7
2.27 Operating Committee....................................... 7
2.28 Own Load.................................................. 7
2.29 Parent Company............................................ 7
2.30 Planning Reserve Level.................................... 7
2.31 Pool Energy............................................... 7
2.32 Power..................................................... 8
2.33 Prorated Reserve Level.................................... 8
2.34 Reserve Capacity (Company or System)...................... 8
2.35 System.................................................... 8
2.36 System Capability......................................... 8
2.37 System Demand............................................. 8
2.38 System Load Responsibility................................ 8
2.39 System Operating Capability............................... 9
2.40 System Operating Reserve.................................. 9
2.41 System Peak Demand........................................ 9
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2.42 Transaction Cost.......................................... 9
2.43 Variable Cost............................................. 9
2.44 Year...................................................... 9
ARTICLE III
OBJECTIVES.............................. 9
3.1 Purpose................................................... 9
ARTICLE IV
AGENT................................. 10
4.1 Responsibility of the Agent............................... 10
4.2 Delegation and Acceptance of Authority.................... 10
4.3 Reporting................................................. 10
ARTICLE V
OPERATING COMMITTEE......................... 11
5.1 Operating Committee....................................... 11
ARTICLE VI
OPERATIONS.............................. 11
6.1 Planning and Authorization of Production Facilities....... 11
6.2 Planning Reserve Levels................................... 12
6.3 Provision to Achieve Planning Reserve Levels.............. 12
6.4 Capacity Sales and Purchases and Reserve Shortfalls....... 13
6.5 Energy Exchanges Among the Companies...................... 13
6.6 Energy Exchange Pricing................................... 13
6.7 Energy Exchanges with Non-Associated Utilities............ 14
6.8 Communications and other Facilities....................... 15
ARTICLE VII
CENTRAL CONTROL CENTER......................... 15
7.1 Central Control Center.................................... 15
7.2 Expenses.................................................. 15
ARTICLE VIII
GENERAL................................ 16
8.1 Regulatory Authorization.................................. 16
8.2 Effect on Other Agreements................................ 16
8.3 Schedules................................................. 16
8.4 Billings.................................................. 16
8.5 Waivers................................................... 17
8.6 Successors and Assigns; No Third Party Beneficiary........ 17
8.7 Amendment................................................. 18
8.8 Independent Contractors................................... 18
8.9 Responsibility and Liability.............................. 18
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SCHEDULES
A JOINT UNIT
B COMPANY UNITS THAT ARE NOT JOINT UNITS
C CAPACITY COMMITMENT CHARGE
D PAYMENTS AND RECEIPTS FOR POOL ENERGY EXCHANGES AMONG THE COMPANIES
E PAYMENTS AND RECEIPTS FOR INTERNAL ECONOMY ENERGY EXCHANGES AMONG THE
COMPANIES AND FOR OFF-SYSTEM ENERGY PURCHASES AND SALES
F DISTRIBUTION OF MARGIN FOR INTERNAL ECONOMY ENERGY EXCHANGES AND FOR OFF-
SYSTEM ENERGY PURCHASES AND SALES
G DISTRIBUTION OF OPERATING EXPENSES OF THE CENTRAL CONTROL CENTER
H CAPACITY COMMITMENT UNITS
I PLANNING-RESERVE CRITERIA
J STATEMENT OF PRACTICE REGARDING OFF-SYSTEM ENERGY SALES
K DISTRIBUTION OF CERTAIN TRANSACTION COSTS
RESTATED AND AMENDED
OPERATING AGREEMENT
Among
Central Power and Light Company
Public Service Company of Oklahoma
Southwestern Electric Power Company
West Texas Utilities Company
Central and South West Services, Inc.
THIS RESTATED AND AMENDED OPERATING AGREEMENT, hereinafter called Agreement, is made and entered into as of the 1st day of January, 1998 by and among Central Power and Light Company, hereinafter called CPL; Public Service Company of Oklahoma, hereinafter called PSO; Southwestern Electric Power Company, hereinafter called SWEPCO; West Texas Utilities Company, hereinafter called WTU; and Central and South West Services, Inc., hereinafter called CSWS; all of whose common stock is wholly owned by Central and South West Corporation, and supersedes the Restated and Amended Operating Agreement dated October 1, 1993.
WHEREAS, CPL, PSO, SWEPCO, and WTU are the owners and operators of interconnected electric generation, transmission, and distribution facilities with which they are engaged in the business of generating, transmitting, and selling electric Power and Energy to the general public and to other electric utilities; and
WHEREAS, the Companies achieve economic benefits for their customers through operation as a single interconnected system and through coordinated planning, construction, operation and maintenance of their electric supply facilities; and
WHEREAS, CSWS is qualified to act as Agent for the Companies;
NOW, THEREFORE, the parties hereto mutually agree as follows:
ARTICLE I
TERM OF AGREEMENT
1.1 This Agreement shall become effective on such date as is established by the Federal Energy Regulatory Commission. This Agreement shall continue in force and effect for a period of ten (10) Years from the effective date hereinabove described, and continue from Year to Year thereafter until terminated by one or more of the parties upon three (3) Years written notice to the other parties.
1.2 This Agreement is intended to cover only the acquisition, disposition, planning, design, construction, operation and maintenance of the Generating Units and is not to affect those matters that are the subject of orders of the United States Securities and Exchange Commission authorizing certain cost allocation methods for CSWS billings.
ARTICLE II
DEFINITIONS
For the purposes of this Agreement and of Schedules A through K which are attached hereto and made a part hereof, the following definitions shall apply:
2.1 Agent for the Companies shall be CSWS.
2.2 Agreement shall be this Agreement including all attachments and schedules applying hereto and any amendments made hereafter.
2.3 Capacity Commitment shall be generating capacity committed by a Company to provide capability to enable another Company to attain its Planning or Prorated Reserve Level, whichever shall be lower.
2.4 Capacity Commitment Charge shall be the charge made by a Company supplying a Capacity Commitment to the Company receiving the Capacity Commitment.
2.5 Central Control Center shall be a center operated by the Agent for the optimal utilization of System resources for the supply of Power and Energy.
2.6 Chief Executive Officer (CEO) shall be the Chief Executive Officer of Central and South West Corporation or the CEO's designee.
2.7 Company shall be any one of the Central and South West Corporation operating companies and Companies shall be the Central and South West Corporation operating companies collectively.
2.8 Company Capability shall be:
(a) The sum of the Company net plant capability in megawatts; plus
(b) The megawatt amount of purchases and exchanges without reserves, under contract from other systems; less
(c) The megawatt amount of sales and exchanges without reserves, under contract to other systems.
2.9 Company Demand shall be:
(a) The clock-hour demand in megawatts of a Company's system represented by the simultaneous hourly input in megawatt-hours from all sources into the system of a Company; less
(b) The sum of the simultaneous hourly output in megawatt-hours to other systems (exclusive of any wholesale requirements obligations of the Company).
2.10 Company Hourly Capability for a Company shall be:
(a) The megawatt amount of dependable capability of the Company's generating units on line, including its shares of Joint Units and its shares of units owned jointly with non-associated entities, during the Hour; plus
(b) The megawatt amount of capability committed to the Company by other Companies or non-associated suppliers during the Hour; less
(c) The megawatt amount of capability committed by the Company to other Companies or non-associated purchasers during the Hour; less
(d) Any capability required to provide operating reserves.
2.11 Company Load Responsibility shall be as follows:
(a) Company Peak Demand; less
(b) the difference between Company Peak Demand and Company Demand at the time of System Peak Demand; less
(c) The megawatt-hour output of the Company served on an interruptible basis during the hour of Company Peak Demand; plus
(d) The contractual amount of sales and exchanges with reserves during the period to other systems; less
(e) The contractual amount of purchases and exchanges with reserves during the period from other systems.
2.12 Company Operating Capability shall be the dependable net capability in megawatts of Generating Units of a Company carrying load or ready to take load.
2.13 Company Operating Reserve shall be the excess of Company Operating Capability over Company Demand expressed in megawatts.
2.14 Company Peak Demand for a period shall be the highest Company Demand for any Hour during the period.
2.15 Day shall be a calendar day.
2.16 Decremental Energy Value shall be the cost that a buying Company avoids by reducing the generation of Energy from its Company Operating Capability or by reducing its purchase of Energy from others.
2.17 Economic Dispatch shall be the distribution of total generation requirements among alternative sources for System economy with due consideration of incremental generating costs, incremental transmission losses, and System security.
2.18 Energy shall be work and shall be expressed in megawatt-hours (MWH).
2.19 Generating Unit shall be an electric generator, together with its prime mover and all auxiliary and appurtenant devices and equipment designed to be operated as a unit for the production of electric Power and Energy. The above is to include equipment necessary for connection to the transmission system.
2.20 Hour shall be a clock-hour.
2.21 Incremental Energy Cost shall be the variable cost which a selling Company incurs in order to supply Energy for resale.
2.22 Internal Economy Energy shall be Energy supplied and sold by one Company to another Company, under Economic Dispatch, to meet a portion of the purchasing Company's Own Load that could otherwise be supplied internally by the purchasing Company.
2.23 Joint Resource Plan shall be the formal documented plan developed from time to time for all future Generating Units and other power supply and demand management resources.
2.24 Joint Unit shall be any Generating Unit jointly owned by two or more of the Companies.
2.25 (a) Margin on Sales shall be the difference between: (1) the revenue from off-System Energy sales made pursuant to Section 6.7 and (2) the selling Companies' Incremental Energy Cost incurred in making such sales.
2.25 (b) Margin on Purchases shall be the difference between (1) the buying Companies' Decremental Energy Value avoided as a result of off-System Energy purchases made pursuant to Section 6.7 and (2) payments for off-System Energy purchases made pursuant to Section 6.7.
2.25 (c) Margin on Internal Economy Energy shall be the difference between
(1) the buying Companies' Decremental Energy Value avoided as the result of
receiving Internal Economy Energy and (2) the selling Companies' Internal
Economy Energy Cost incurred in supplying Internal Economy Energy.
2.25 (d) Margin for a given period shall be the sum of the amounts developed in accordance with Sections 2.25 (a), 2.25 (b) and 2.25 (c).
2.26 Month shall be a calendar Month.
2.27 Operating Committee shall be the organization established pursuant to
Section 5.1 and whose duties are more fully set forth therein.
2.28 Own Load shall be Energy required to meet Company Demand plus Energy associated with sales or exchanges with reserves less Energy associated with purchases or exchanges with reserves.
2.29 Parent Company shall be Central and South West Corporation.
2.30 Planning Reserve Level shall be the megawatt amount of required Reserve Capacity for a Company, expressed as a percentage of its forecasted Company Load Responsibility.
2.31 Pool Energy shall be the Energy supplied and sold by one Company to another Company to enable the purchasing Company to meet a portion of its Own Load that such other Company cannot or does not plan to serve with its other resources. There shall be two categories of Pool Energy. Emergency Pool Energy shall be the Energy required by a Company that becomes deficient because of an unplanned occurrence (such as a generator unit trip or a missed load forecast). Planned Pool Energy shall be the Energy required by a Company to meet portions of its Own Load when it determines that (a) it will be short of capacity when planning for future operations or (b) such Energy can be taken to economic advantage.
2.32 Power shall be the rate of doing work and shall be expressed in megawatts (MW).
2.33 Prorated Reserve Level shall be a percentage reserve level for each Company that when divided by that Company's Planning Reserve Level gives the same quotient as that for all other Companies.
2.34 Reserve Capacity (Company or System) shall be that amount in megawatts by which Company or System Capability exceeds Company or System Load Responsibility.
2.35 System shall be the coordinated Generating Units of the Companies.
2.36 System Capability shall be the arithmetical sum in megawatts of the individual Company Capabilities.
2.37 System Demand shall be the arithmetical sum of the Companies' clock-hour demand in megawatts represented by:
(a) The simultaneous hourly input in megawatt-hours from all sources into the System; less
(b) The sum of the simultaneous hourly outputs in megawatt-hours to other systems (exclusive of any wholesale requirements obligations of the Companies).
2.38 System Load Responsibility shall be as follows:
(a) System Peak Demand; less
(b) The megawatt-hour output of the Companies served on an interruptible basis during the Hour of System Peak Demand; plus
(c) The arithmetic sum in megawatts of all of the Companies' contractual amount of sales and exchanges with reserves during the period to other systems; less
(d) The arithmetic sum in megawatts of all the Companies' contractual amount of purchases and exchanges with reserves during the period from other systems.
2.39 System Operating Capability shall be the arithmetical sum in megawatts of the individual Company Operating Capabilities.
2.40 System Operating Reserve shall be the arithmetical sum of the individual Company Operating Reserves, expressed in megawatts.
2.41 System Peak Demand for a period shall be the highest System Demand for any hour during the period.
2.42 Transaction Cost shall be the sum of the charges assessed against any one or more of the Companies for transmission services related to Internal Economy Energy exchanges and off-System Energy purchases and sales, other than such charges allocated among the Companies pursuant to the Distribution of Certain Transaction Costs procedure set forth in Schedule K.
2.43 Variable Cost shall be a Company's incremental generation cost or purchased energy cost.
2.44 Year shall be a calendar Year.
ARTICLE III
OBJECTIVES
3.1 Purpose
The purpose of this Agreement is to provide the contractual basis for the coordinated planning, construction, operation and maintenance of the System to achieve optimal economies, consistent with reliable electric service, reasonable utilization of natural resources, and environmental requirements.
ARTICLE IV
AGENT
4.1 Responsibility of the Agent
The Companies hereby designate CSWS as their Agent for the purpose of:
(a) coordinating the acquisition, disposition, planning, design, construction, operation and maintenance of the Generating Units of the Companies, including any Joint Units; and
(b) supervising the design, construction, operation and maintenance of the Central Control Center.
4.2 Delegation and Acceptance of Authority
The Companies hereby delegate to the Agent and the Agent hereby accepts responsibility and authority for the duties listed in Section 4.1 and elsewhere in this Agreement. Except as herein expressly established otherwise, the Agent shall perform each of those duties in consultation with the Operating Committee. The Agent shall also perform each of those duties in accordance with the standards of conduct described in 18 C.F.R. Section 37.4.
4.3 Reporting
The Agent shall provide periodic summary reports of its activities under this Agreement to the Companies and shall keep the Companies and the Operating Committee currently informed of situations or problems that may materially affect the outcome of these activities. Furthermore, the Agent agrees to report to the Companies or to the Operating Committee in such additional detail as is requested regarding specific issues or projects under its supervision as Agent.
ARTICLE V
OPERATING COMMITTEE
5.1 Operating Committee
The Operating Committee is the organization established to ensure the coordinated operation of the System by making recommendations to the CEO regarding operations under this Agreement. The Operating Committee members will be designated by the CEO and shall include a chairperson and at least one member from the Agent and from each Company. Operating Committee decisions shall be by a majority vote of those present and shall be in the form of recommendations to the CEO. However, any member not present may vote by proxy. In any non-unanimous decision the principles of the difference shall be reported to the CEO. The chairperson shall vote only in case of a tie.
ARTICLE VI
OPERATIONS
6.1 Planning and Authorization of Production Facilities
(a) Each Company shall forecast the amount of generating capability required to meet its Company Load Responsibility and its Planning Reserve Level in future Years.
(b) A current Joint Resource Plan will be maintained that will state the current forecasted System Load Responsibility including the Planning Reserve Level and the required resources.
(c) All Generating Units placed in service after the date of this Agreement shall be in accordance with the then current Joint Resource Plan. Joint Units shall be authorized by the Board of Directors of the Parent Company prior to the commencement of detailed engineering of the units.
(d) For the purpose of this Agreement, the Generating Units listed in Schedule B are not Joint Units.
(e) The organization designated by the CEO shall be responsible for the staffing, operation and maintenance of each Generating Unit.
6.2 Planning Reserve Levels
The Operating Committee shall periodically review the Planning Reserve Level for each Company and recommend any modifications of such to the CEO.
6.3 Provision to Achieve Planning Reserve Levels
(a) Each Company shall own or have available to it under contract such generating capability and other facilities as are necessary to supply its Company Load Responsibility plus its Planning Reserve Level.
(b) The Joint Resource Plan shall be periodically reviewed and adjusted to provide the Companies their required Planning Reserve Levels. Any Company with Reserve Capacity in excess of its Planning Reserve Level for a future Year shall commit such excess capacity to Companies with insufficient Reserve Capacity to meet their Planning Reserve Level during that Year or any portion thereof. The deficit Companies shall make payments to the excess Companies in respect of each Month of the Year to which the commitment applies in the amount of the Capacity Commitment Charge in accordance with Schedule C. In the event that the System Capability, including outside capacity purchases, is insufficient to meet such Planning Reserve Levels, the System Capability shall be allocated to provide each Company its Prorated Reserve Level.
(c) The ownership percentages in future Joint Units are established in accordance with Schedule A, but may be reallocated in the Joint Resource Plan by recommendation of the Operating Committee and authorization by the CEO.
6.4 Capacity Sales and Purchases and Reserve Shortfalls
(a) The Agent shall coordinate and assist the Companies in making off-System capacity sales and purchases.
(b) The System Reserve Capacity shall be at the disposal of any Company requiring such capacity. Should the System be short of capacity as a result of an emergency and be unable to purchase the deficit, each Company shall take such actions as are necessary to bring System load and generation into balance.
6.5 Energy Exchanges Among the Companies
The Agent shall schedule the Energy output of System Capability to obtain the lowest cost of Energy for serving System Demand consistent with each Company's operating and security constraints, including voltage control, stability loading of facilities, operating guides as recommended by the Operating Committee and approved by the CEO, fuel commitments, environmental requirements, and continuity of service to customers.
6.6 Energy Exchange Pricing
For the purpose of pricing Energy exchange among the Companies, System resources shall be utilized to serve System requirements in the following order:
a) Those Generating Units which are designated not to be operated in the order of lowest to highest Variable Cost due to Company operating constraints shall be allocated to the Company requiring the Generating Unit.
(b) The lowest Variable Cost generation of each Company's Hourly Capability shall first be allocated to serve its Own Load.
c) The next lowest Variable Cost portion of each Company's remaining Hourly Capability shall be allocated to serve Pool Energy requirements of Companies under System Economic Dispatch. Pool Energy shall be priced in accordance with Schedule D.
(d) The next lowest Variable Cost portion of each Company's remaining Hourly Capability shall be used to supply Internal Economy Energy to Companies under System Economic Dispatch. Internal Economy Energy shall be priced in accordance with Schedule E.
6.7 Energy Exchanges with Non-Associated Entities
The Agent shall coordinate and direct off-System purchases of Energy necessary to meet System requirements or improve System economy, after Internal Economy Energy transactions have been effected. The Agent shall coordinate and direct off-System sales of Energy available after meeting all of the requirements of the System including the Energy associated with contractual requirements for off-System capacity sales. Such off-System Energy purchases or sales shall be implemented by decremental or incremental System Economic Dispatch as appropriate. Any Margin on off-System Energy sales or purchases made to improve System economy shall be distributed to the Companies in accordance with Schedule F. Price quotations for such Energy sales shall be determined in accordance with Schedule J.
6.8 Communications and other Facilities
The Companies shall provide communications and other facilities necessary for:
(a) The metering and control of the generating and transmission facilities;
(b) The dispatch of electric Power and Energy; and
(c) For such other purposes as may be necessary for optimum operation of the System.
ARTICLE VII
CENTRAL CONTROL CENTER
7.1 Central Control Center
The Agent shall provide and operate a Central Control Center adequately equipped and staffed to meet the requirements of the Companies for efficient, economical and reliable operation as contemplated by this Agreement.
7.2 Expenses
All expenses for operation of the Central Control Center shall be paid by the Agent and billed monthly to each Company in accordance with Schedule G.
ARTICLE VIII
GENERAL
8.1 Regulatory Authorization
This Agreement is subject to certain regulatory approvals and each Company and the Agent shall diligently seek all necessary regulatory authorization for this Agreement.
8.2 Effect on Other Agreements
This Agreement shall not modify the obligations of any Company under any agreement between that Company and others not parties to this Agreement in effect at the date of this Agreement, nor shall it modify any agreement between or among the Companies under any transmission tariff or other agreement filed with the Federal Energy Regulatory Commission.
8.3 Schedules
The basis of compensation for the use of facilities and for the Power and Energy provided or supplied by a Company to another Company or Companies under this Agreement shall be in accordance with arrangements agreed upon from time to time among the Companies. Such arrangements shall be in the form of Schedules, each of which, when signed by the parties thereto and approved or accepted by appropriate regulatory authority, shall become a part of this Agreement.
8.4 Billings
Bills for services rendered hereunder shall be calculated in accordance with applicable Schedules, and shall be issued on or before the tenth working Day of the Month following that in which such service was rendered and shall be payable on or before the twentieth Day of such Month. After the thirtieth Day, interest shall accrue on any balance due until paid at the latest rate approved by the United States Securities and Exchange Commission for loans among Companies in the Central and South West System. Billings in good faith disputed and paid shall be deemed to have been paid under protest.
8.5 Waivers
Any waiver at any time by a Company of its rights with respect to a default by any other Company under this Agreement shall not be deemed a waiver with respect to any subsequent default of similar or different nature, nor shall it prejudice its right to deny waiver of similar default to a different Company.
8.6 Successors and Assigns; No Third Party Beneficiary
This Agreement shall inure to and be binding upon the successors and assigns of the respective parties hereto, but shall not be assignable by any party without the written consent of the other parties, except upon foreclosure of a mortgage or deed of trust. Nothing expressed or mentioned or to which reference is made in this Agreement is intended or shall be construed to give any person or corporation other than the parties hereto any legal or equitable right, remedy or claim under or in respect of this Agreement or any provision herein contained, expressly or by reference, or any Schedule hereto, this Agreement, any such Schedule and any and all conditions and provisions hereof and thereof being intended to be and being for the sole and exclusive benefit of the parties hereto, and for the benefit of no other person or corporation.
8.7 Amendment
It is contemplated by the parties that it may be appropriate from time to time to change, amend, modify or supplement this Agreement or the Schedules which are attached to this Agreement to reflect changes in operating practices or costs of operations or for other reasons. This Agreement may be changed, amended, modified or supplemented by an instrument in writing executed by all of the parties.
8.8 Independent Contractors
It is agreed among the Companies that by entering into this Agreement the Companies shall not become partners, but as to each other and to third persons, the Companies shall remain independent contractors in all matters relating to this Agreement.
8.9 Responsibility and Liability
The liability of the parties shall be several, not joint or collective. Each party shall be responsible only for its obligations, and shall be liable only for its proportionate share of the costs and expenses as provided in this Agreement, and any liability resulting herefrom. Each party hereto will defend, indemnify, and save harmless the other parties hereto from and against any and all liability, loss, costs, damages, and expenses, including reasonable attorney's fees, caused by or growing out of the gross negligence, willful misconduct, or breach of this Agreement by such indemnifying party.
IN WITNESS WHEREOF, each of the Companies has caused this Agreement and the attached Schedules to be signed in its name and on its behalf by its President attested by its Secretary, both being duly authorized, and CSWS has caused this Agreement and the attached Schedules to be signed in its name and on its behalf by its Chief Executive Officer attested by its Secretary, both being duly authorized. This Agreement and attached Schedules shall become effective on such date as is established by the Federal Energy Regulatory Commission.
CENTRAL POWER AND LIGHT COMPANY
Attest
By /s/
Secretary President
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PUBLIC SERVICE COMPANY OF OKLAHOMA
Attest
By /s/
Secretary President
|
SOUTHWESTERN ELECTRIC POWER COMPANY
Attest
By /s/
Secretary President
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WEST TEXAS UTILITIES COMPANY
Attest
By /s/
Secretary President
|
CENTRAL AND SOUTH WEST SERVICES, INC.
Attest
By /s/
Secretary Chief Executive Officer
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SCHEDULE A
JOINT UNIT
9.1 Purpose
The purpose of this Schedule is to provide the basis for the Companies' participation in Joint Units.
9.2 Ownership
(a) Every Joint Unit shall be owned by the Companies participating in the Joint Unit as tenants in common. Ownership shares in each Joint Unit shall be allocated insofar as practical to achieve a Prorated Reserve Level for all Companies participating in the unit. The allocation shall be recommended by the Operating Committee and authorized by the CEO prior to the time the unit is authorized by the Board of Directors of the Parent Company. However, each Company shall own at least fifty (50) megawatts of each Joint Unit unless otherwise agreed to by the Operating Committee. Each Company shall be responsible for its pro rata share of the costs of construction of the unit and shall contribute such funds to the Agent as billed.
(b) When a new Joint Unit is installed at a site already occupied by one or more existing Generating Units the Agent, in consultation with the Operating Committee, shall identify any existing facilities that will be common to the new Joint Unit and the portion of the common facilities to be allocated to the new Joint Unit. The owners of the new Joint Unit shall compensate the owners of the existing common facilities for the use of those common facilities.
9.3 Contracts
The Companies shall execute a joint ownership agreement for each Joint Unit, such agreement to set out all of the rights and obligations of the parties relating to the specific Joint Unit, including the allocation of fuel costs, the allocation of other operation costs and the allocation of maintenance costs among the owners.
SCHEDULE B
COMPANY UNITS THAT ARE NOT JOINT UNITS
10.1 Purpose
The purpose of this Schedule is to list the Generating Units, to be placed in service after the date of the original Operating Agreement dated September 28, 1983, which are not Joint Units.
10.2 Company Units That Are Not Joint Units
The Company units that are not Joint Units are as follows:
South Texas Project Unit Number 1 - CPL
South Texas Project Unit Number 2 - CPL
Dolet Hills Unit Number 1 - SWEPCO
Pirkey Unit Number 1 - SWEPCO
SCHEDULE C
CAPACITY COMMITMENT CHARGE
11.1 Purpose
The purpose of this Schedule is to establish the basis for Capacity Commitments between the Companies and the rates for the Capacity Commitment Charge and associated Energy.
11.2 Basis for Capacity Commitment
A committing Company shall make available to a receiving Company unit capacity consisting of a portion of the output of one or more specific Generating Units. The receiving Company shall be entitled to receive Energy from the specified Generating Unit(s) up to an amount equal to an annual load factor of sixty (60) percent or such other amount as is mutually agreeable.
11.3 Provisions for Capacity Commitment Charge
The monthly Capacity Commitment Charge for each specific Generating Unit(s) from which capacity is committed shall be an amount not to exceed the result of the following formula:
A = (1/12) (B) (C/D) (E)
Where:
A = Monthly Capacity Commitment Charge for the specified unit to be due each month regardless of the availability of the specific unit.
B = 0.1712 (fixed charge rate for the committing Company).
C = Committing Company's total dollar investment, at original cost, in the specific Generating Unit as of December 31 of the year prior to the year of the Capacity Commitment.
D = Rated net dependable capability of the specific Generating Unit in megawatts.
E = Megawatts of capacity committed from the specified unit.
11.4 Provision for Energy Charge
The rate for Energy received by a receiving Company from specified unit(s) shall be the Variable Cost of Energy produced from each specified unit(s) plus ten (10) percent of such costs or three (3) mills per kilowatt-hour, whichever is less.
SCHEDULE D
PAYMENTS AND RECEIPTS FOR POOL ENERGY EXCHANGES
AMONG THE COMPANIES
12.1 Purpose
The purpose of this Schedule is to provide the basis for determining payments and receipts among the Companies for Pool Energy exchanges.
12.2 Hourly Calculations
The payments and receipts of Section 12.3 are calculated Hourly, but are accumulated and billed Monthly among the Companies
12.3 Receipts and Payments
A selling Company shall receive from a purchasing Company one hundred and ten percent (110%) of the selling Company's Incremental Energy Cost for Pool Energy sold. A purchasing Company shall pay for Pool Energy received one hundred and ten percent (110%) of its portion of the aggregate of the selling Companies' Incremental Cost for Pool Energy. Where Pool Energy is purchased simultaneously by more than one Company, these charges shall be pro rated in proportion to the megawatt-hours of Pool Energy purchased by each buyer.
SCHEDULE E
PAYMENTS AND RECEIPTS FOR INTERNAL
ECONOMY ENERGY EXCHANGES AMONG THE COMPANIES AND
FOR OFF-SYSTEM ENERGY PURCHASES AND SALES
13.1 Purpose
The purpose of this Schedule is to provide the basis for determining payments and receipts among the Companies for Internal Economy Energy exchanges and for off-System Energy purchases and sales made to improve System economy.
13.2 Hourly Calculations
The payments of Section 13.3 and receipts of Section 13.4 shall be calculated Hourly, but are accumulated and billed Monthly among the Companies.
13.3 Payments
A purchasing Company shall pay its Decremental Energy Value for Internal Economy Energy purchased and off-System Energy purchased to improve System economy.
13.4 Receipts
A selling Company shall receive its Incremental Energy Cost for Internal Economy Energy sold and off-System Energy sold to improve System economy.
SCHEDULE F
DISTRIBUTION OF MARGIN FOR INTERNAL
ECONOMY ENERGY EXCHANGES AND FOR OFF-SYSTEM
ENERGY PURCHASES AND SALES
14.1 Purpose
The purpose of this Schedule is to establish the basis for distributing among the Companies the Margin resulting from Internal Economy Energy exchanges and for off-System Energy purchases and sales made to improve System economy.
14.2 Distribution of Margin
Any Margin remaining from Internal Economy Energy exchanges and off-System Energy purchases and sales made to improve System economy after deducting any Transaction Cost incurred in the period to which the Margin relates shall be distributed to the Companies in proportion to the relative magnitude of the sums for each Company of the Energy generated or not generated by such Company in order to participate in Internal Economy Energy exchanges or such off-System purchases or sales.
SCHEDULE G
DISTRIBUTION OF OPERATING EXPENSES
OF THE CENTRAL CONTROL CENTER
15.1 Purpose
The purpose of this Schedule is to provide a basis for the distribution among the Companies of the costs incurred by the Agent in operating the Central Control Center.
15.2 Costs
Costs for the purpose of this Schedule shall include all costs incurred in maintaining and operating the Central Control Center including, among others, such items as salaries, wages, rentals, the cost of materials and supplies, interest, taxes, depreciation, transportation, travel expenses, consulting, and other professional services.
15.3 Distribution of Costs
All costs shall be billed by Agent to the Companies in proportion to the average of the maximum Company Peak Demands experienced during the three previous calendar Years with the following exception. In the event the Central Control Center makes a study or performs a special service in which all Companies are not thus proportionately interested, any resulting cost shall be distributed to the interested parties in accordance with the standard procedures of Agent authorized by the United States Securities and Exchange Commission.
SCHEDULE H
CAPACITY COMMITMENT UNITS
16.1 Purpose
The purpose of this Schedule is to identify the Generating Units of the Companies from which Capacity Commitments shall be made pursuant to Section 6.3 in accordance with Schedule C.
16.2 Commitment Units
Listed below are the Generating Units from which each of the Companies shall commit Capacity to other Companies pursuant to Section 6.3. Capacity Commitments shall be made from the first listed unit of the committing Company unless or to the extent that such unit is not expected to be available during the commitment period. In such event, Capacity Commitments shall be made from the second listed unit of the committing Company.
COMPANY UNIT NAME RATING(MW) YEAR INSTALLED
CPL B. M. Davis #2 341 1976
Laredo #3 101 1975
PSO Riverside #2 465 1976
Riverside #1 457 1974
SWEPCO Knox Lee #5 344 1974
Wilkes #3 351 1971
WTU Fort Phantom #2 204 1977
Fort Phantom #1 158 1974
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SCHEDULE I
PLANNING-RESERVE CRITERIA
17.1 Purpose
The purpose of this Schedule is to identify the criteria which shall be used by the Companies in determining their respective Planning Reserve Levels for purposes of determining their respective Capacity Commitment obligations
17.2 Planning Reserve Criteria
The Planning Reserve Level for each of the Companies shall be equal to 15% of Company Load Responsibility.
SCHEDULE J
STATEMENT OF PRACTICE
REGARDING OFF-SYSTEM
ENERGY SALES
18.1 Purpose
The purpose of this Schedule is to identify the basis upon which price quotations for energy sales to a non-associated entity made to improve System economy will be determined when any such non-associated entity makes a request of a Company or the Agent to purchase System Energy. The prices for sales made shall be set by negotiation or in accordance with filed rate schedules of the Companies and may include standard industry adders.
18.2 Determination of Energy Price Quotations
The CSW Central Control Center will predispatch System Energy requirements based upon an estimate of on-line System generation and such System Energy requirements. Any request for the purchase of System Energy will result in a price quotation based upon the incremental running cost of the next-least-costly-to-operate System Generating Unit (that will be available to make the sale requested during the time period that is the subject of the request by the non-associated entity) after System needs have been met. In determining whether a Generating Unit will be available to make a requested sale, the matters listed in Section 6.5 and the availability of adequate transmission capacity on the System and on the systems of other utilities shall be considered.
SCHEDULE K
DISTRIBUTION OF CERTAIN TRANSACTION COSTS
19.1 Purpose
The purpose of this Schedule is to provide a basis for the distribution among the Companies of certain charges assessed by non-associated entities against one or more of the Companies for transmission service related to transactions contemplated by the Agreement.
19.2 Fixed Transaction Costs
For purposes of this Schedule, Fixed Transaction Costs shall consist of transmission service charges that are not computed based on specific schedules that vary on an hour-by-hour basis or that are not computed for specific firm transmission service reservations between Companies dependent on the level of reservation.
19.3 Distribution of Fixed Transaction Costs
All Fixed Transaction Costs shall be billed to the Companies in proportion to their maximum Company Peak Demands experienced during the previous calendar Year less interruptible loads served during the peak hour.
19.4 Directly Assigned Transaction Costs
For purposes of this Schedule, Directly Assigned Transaction Costs shall consist of transmission service charges due to non-associated entities that are not Fixed Transaction Costs and that are associated with the receipt by a Company of Pool Energy, Energy produced from a Joint Unit, Energy associated with a Capacity Commitment and off-System Energy purchased with reserves to meet the requirements of the receiving Company.
19.5 Distribution of Directly Assigned Transaction Costs
All Directly Assigned Transaction Costs shall be billed to the Companies in accordance with the following implementation steps:
1) Directly Assigned Transaction Costs due to non-associated entities shall be paid by the Company receiving the bill. Where two or more Companies are jointly receiving such Energy for which a consolidated transmission service bill is rendered, the involved Companies will be responsible for the charges in proportion to their megawatt-hour (MWH) share of such Energy.
2) Should a non-associated entity render a bill for Directly Assigned Transaction Costs that does not separately attribute such costs to particular Pool Energy, Joint Unit, Capacity Commitment or off-System Energy purchased with reserves transactions, the terms and conditions of the contracts, tariffs or ERCOT practices on which the charges are based will be used to determine which Companies will be responsible for such Energy transaction charges.
3) When losses are required to be paid in kind, and the responsible Company provides Energy (to the scheduling Company) sufficient to cover the losses to be returned, such payments shall not be considered as Directly Assigned Transaction Costs. When the responsible Company chooses to pay the cost associated with the scheduling Company's returning the losses on behalf of the System, such Directly Assigned Transaction Costs shall be determined as the product of the losses paid back (in MWH) and the scheduling Company's average monthly fuel cost for the Month in which the losses are returned.
4) On a calendar Month basis, according to transaction date, the total Directly Assigned Transmission Costs for which each Company is responsible and the total Directly Assigned Transmission Costs paid by each Company shall be tabulated. For a given Month, an adjustment shall be made in an appropriate CSW Money Pool account for each Company by an amount equal to the difference between the total Directly Assigned Transaction Costs paid by the Company and the Directly Assigned Transaction Costs for which the Company is responsible.
EXHIBIT 10(d)
TRANSMISSION COORDINATION AGREEMENT
Between
Central Power and Light Company,
West Texas Utilities Company,
Public Service Company of Oklahoma,
Southwestern Electric Power Company
and
Central and South West Services, Inc.
Dated as of January 1, 1997
Revised as of October 29, 1999
TABLE OF CONTENTS
Page
ARTICLE I
TERM OF AGREEMENT...................................................2
1.1 Effective Date.............................................2
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1.2 Periodic Review............................................2
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ARTICLE II
DEFINITIONS.........................................................3
2.1 Agreement..................................................3
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2.2 Ancillary Services.........................................3
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2.3 Company Demand.............................................3
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2.4 Company Peak Demand........................................3
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2.5 Control Area...............................................3
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2.6 Coordinating Committee.....................................3
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2.7 Designated Agent...........................................4
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2.8 Direct Assignment Facilities...............................4
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2.9 Generating Unit............................................4
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2.10 Hour.......................................................4
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2.11 Month......................................................4
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2.12 Network Integration Transmission Service...................4
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2.13 Open Access Transmission Tariff............................4
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2.14 Point-to-Point Transmission Service........................4
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2.15 PUCT.......................................................5
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2.16 Scheduling, System Control and Dispatch Service............5
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2.17 Transmission Customer......................................5
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2.18 Transmission Provider......................................5
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2.19 Transmission Service.......................................5
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2.20 Transmission System........................................5
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2.21 Transmission System Operator...............................5
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ARTICLE III
OBJECTIVES..........................................................6
3.1 Purposes...................................................6
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ARTICLE IV
COORDINATING COMMITTEE..............................................7
4.1 Coordinating Committee.....................................7
4.2 Responsibilities of the Coordinating Committee.............7
4.3 Delegation and Acceptance of Authority.....................8
4.4 Reporting..................................................8
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ARTICLE V
PLANNING............................................................9
5.1 Transmission Planning......................................9
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ARTICLE VI
TRANSMISSION.......................................................10
6.1 Delegation to the Transmission System Operator............10
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6.2 Transmission Facilities...................................10
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6.3 Direct Assignment Facilities..............................10
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6.4 Transmission Service Revenues.............................10
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6.5 Payment of Costs for Network Use..........................12
--------------------------------
6.6 Payment of Costs for Point-to-Point Transmission Service..13
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ARTICLE VII
ANCILLARY SERVICES.................................................14
7.1 Ancillary Services........................................14
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ARTICLE VIII
GENERAL............................................................15
8.1 Regulatory Authorization..................................15
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8.2 Effect on Other Agreements................................15
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8.3 Waivers...................................................15
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8.4 Successors and Assigns; No Third Party Beneficiary........15
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8.5 Amendment.................................................16
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8.6 Independent Contractors...................................16
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8.7 Responsibility and Liability..............................16
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SCHEDULE A
ALLOCATION OF TRANSMISSION REVENUES................................18
SCHEDULE B
ANNUAL TRANSMISSION REVENUE REQUIREMENTS RATIOS....................20
SCHEDULE C
ALLOCATION OF ANCILLARY SERVICE REVENUES...........................22
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TRANSMISSION COORDINATION AGREEMENT
Between
Central Power and Light Company,
West Texas Utilities Company,
Public Service Company of Oklahoma,
Southwestern Electric Power Company
and
Central and South West Services, Inc.
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This TRANSMISSION COORDINATION AGREEMENT, hereinafter called "Agreement," is made and entered into as of the first day of January, 1997, by and among Central Power and Light Company (CPL), West Texas Utilities Company (WTU), Public Service Company of Oklahoma (PSO), and Southwestern Electric Power Company (SWEPCO), hereinafter separately referred to as "Company" and jointly as "Companies," and Central and South West Services, Inc. (CSWS).
WHEREAS, Companies are the owners and operators of interconnected generation, transmission and distribution facilities with which they are engaged in the business of transmitting and selling electric power to the general public, to other entities and to other electric utilities; and
WHEREAS, Companies achieve economic benefits for their customers through coordinated planning, operation and maintenance of their transmission facilities;
NOW, THEREFORE, the Companies and CSWS mutually agree as follows:
ARTICLE I
TERM OF AGREEMENT
1.1 Effective Date
This Agreement shall become effective as of January 1, 1997, or such later date as is established by the Federal Energy Regulatory Commission. This Agreement shall continue in force and effect until December 31, 2001, and continue from year to year thereafter until terminated by written notice given by any Company to the other Companies and to CSWS.
1.2 Periodic Review
This Agreement will be reviewed periodically by the Coordinating Committee,
as defined herein, to determine whether revisions are necessary to meet changing
conditions. In the event that revisions are made by the Companies pursuant to
Section 8.5, and after requisite approval or acceptance for filing by the
appropriate regulatory authorities, the Coordinating Committee may thereafter,
for the purpose of ready reference to a single document, prepare for
distribution to the Companies an amended document reflecting all changes in and
additions to this Agreement with notations thereon of the date amended.
ARTICLE II
DEFINITIONS
For purposes of this Agreement, the following definitions shall apply:
2.1 Agreement shall mean this Transmission Coordination Agreement including all attachments and schedules applying thereto and any amendments made hereafter.
2.2 Ancillary Services shall mean those services that are necessary to support the transmission of capacity and energy from resources to loads while maintaining reliable operation of the Companies' transmission facilities in accordance with Good Utility Practice, as that term is defined in the Open Access Transmission Tariff.
2.3 Company Demand shall mean the demand in megawatts of all retail and wholesale power customers on whose behalf the Company, by statute, franchise, regulatory requirement, or contract, has undertaken an obligation to construct and operate its transmission system to meet the reliable electric needs of such customers, integrated over a period of one hour, plus the losses incidental to that service.
2.4 Company Peak Demand for a period shall be the highest Company Demand for any hour during the period.
2.5 Control Area shall mean an electric power system or combination of electric power systems to which a common automatic generation control scheme is applied for the purposes specified in the Open Access Transmission Tariff.
2.6 Coordinating Committee shall mean the organization established pursuant to Section 4.1 of this Agreement and whose duties are more fully set forth herein.
2.7 Designated Agent shall mean any entity that performs actions or functions on behalf of the Transmission Provider, an Eligible Customer (as that term is defined in the Open Access Transmission Tariff), or the Transmission Customer required under the Open Access Transmission Tariff.
2.8 Direct Assignment Facilities shall mean facilities or portions of facilities that are constructed by the Transmission Provider for the sole use or benefit of a particular Transmission Customer requesting service under the Open Access Transmission Tariff.
2.9 Generating Unit shall mean an electric generator, together with its prime mover and all auxiliary and appurtenant devices and equipment designed to be operated as a unit for the production of electric capacity and energy.
2.10 Hour shall mean a clock-hour.
2.11 Month shall mean a calendar month consisting of the applicable 24-Hour periods as measured by Central Standard Time.
2.12 Network Integration Transmission Service shall mean the transmission service provided under Part III of the Open Access Transmission Tariff.
2.13 Open Access Transmission Tariff shall mean the Open Access Transmission Tariff filed with the Federal Energy Regulatory Commission on behalf of the Companies as it may be amended from time to time.
2.14 Point-to-Point Transmission Service shall mean the reservation and transmission of capacity and energy on either a firm or non-firm basis from the points of receipt to the points of delivery under Part II of the Open Access Transmission Tariff.
2.15 PUCT shall mean the Public Utility Commission of Texas.
2.16 Scheduling, System Control and Dispatch Service shall mean the service required to schedule the movement of power through, out of, within, or into a Control Area, as specified in Schedule 1 of the Open Access Transmission Tariff.
2.17 Transmission Customer shall mean any Eligible Customer as defined in the Open Access Transmission Tariff (or its Designated Agent) that (i) executes a Service Agreement, or (ii) requests in writing that the Transmission Provider file with the Federal Energy Regulatory Commission a proposed unexecuted Service Agreement to receive service under the Open Access Transmission Tariff. This term is used in the Part I Common Service Provisions of the Open Access Transmission Tariff to include customers receiving service under Part II and
Part III of the Open Access Transmission Tariff.
2.18 Transmission Provider shall mean the Transmission System Operator (or its Designated Agent).
2.19 Transmission Service shall mean Point-to-Point Transmission Service provided under Part II of the Open Access Transmission Tariff on a firm and non-firm basis.
2.20 Transmission System shall mean the facilities owned, controlled or operated by the Companies that are used to provide transmission service under Parts II and III of the Open Access Transmission Tariff.
2.21 Transmission System Operator shall mean that part of CSWS that is charged with monitoring the reliability of the Companies' Transmission System.
ARTICLE III
OBJECTIVES
3.1 Purposes
The purposes of this Agreement are (a) to provide the contractual basis for the coordinated planning and operation of the Companies' transmission facilities to achieve optimal economies, consistent with reliable electric service and regulatory and environmental requirements and (b) to provide the means by which the Companies will allocate among themselves the revenue that they receive for service provided under the Open Access Transmission Tariff. Any revenue received by a Company(ies) from the provision of service under an agreement, tariff or rate schedule other than the Open Access Transmission Tariff, including without limitation the Open Access Transmission Tariff for Service Offered by the Southwest Power Pool Transmission Providers, will be kept by the Company(ies) that is (are) the party(ies) to such agreement, tariff or rate schedule.
ARTICLE IV
COORDINATING COMMITTEE
4.1 Coordinating Committee
The Coordinating Committee is the organization established to oversee planning, construction, operation, and maintenance of the Transmission System. The Coordinating Committee members shall include at least one member representing each of the parties hereto who is not a member of the Operating Committee established under the CSW Operating Agreement. The chairperson, who shall be the appointed by the chief executive officer of the holder of the majority of the common stock of the Companies, shall appoint the member representative(s) of the Companies. Other than the chairperson, there shall be the same number of members representing each Company. The majority of the members on the Coordinating Committee shall be representatives of the Companies. Coordinating Committee decisions shall be by a majority vote of those present. However, any member not present may vote by proxy. The chairperson shall vote only in case of a tie. No merchant function employee of the Companies shall be appointed to, or serve on, the Coordinating Committee.
4.2 Responsibilities of the Coordinating Committee
The Coordinating Committee shall be responsible for overseeing:
(a) the Companies in the coordinated planning of their transmission facilities, including studies for transmission planning purposes and their interaction with independent system operators and other regional bodies that are interested in transmission planning; and
(b) compliance with the terms of the Open Access Transmission Tariff and the rules and regulations of the Federal Energy Regulatory Commission relating thereto.
4.3 Delegation and Acceptance of Authority
The Companies hereby delegate to the Coordinating Committee, and the Coordinating Committee hereby accepts, responsibility and authority for the duties listed in this Article and elsewhere in this Agreement.
4.4 Reporting
The Coordinating Committee shall provide periodic summary reports of its activities under this Agreement to the transmission and reliability function employees of the Companies and shall keep such employees of the Companies informed of situations or problems that may materially affect the reliability of the Transmission System. Furthermore, the Coordinating Committee agrees to report to the transmission and reliability function employees of the Companies in such additional detail as is requested regarding specific issues or projects under its oversight.
ARTICLE V
PLANNING
5.1 Transmission Planning
The Companies agree that their respective transmission facilities shall be planned and developed on the basis that their combined individual systems constitute a coordinated transmission system and that the objective of their planning shall be to maximize the economy, efficiency and reliability of the Transmission System as a whole. In this connection, the Coordinating Committee will from time to time, as it deems appropriate, direct studies for transmission planning purposes.
ARTICLE VI
TRANSMISSION
6.1 Delegation to the Transmission System Operator
The Companies shall delegate to the Transmission System Operator the responsibility and authority to act as Transmission Provider on behalf of the Companies for all of the requirements and purposes of the Open Access Transmission Tariff.
6.2 Transmission Facilities
Each Company shall make its transmission facilities available to the Transmission System Operator.
6.3 Direct Assignment Facilities
Each Company shall make Direct Assignment Facilities available to the Transmission System Operator as may be required to provide service to a particular Transmission Customer requesting service under the Open Access Transmission Tariff.
6.4 Transmission Service Revenues
(a) The Companies shall share transmission service revenues obtained from the use of the transmission facilities that comprise the Transmission System in accordance with Schedule A to this Agreement. Transmission service revenues are those revenues received for service provided under the Open Access Transmission Tariff. The Companies' annual transmission revenue requirements are shown on Schedule B to this Agreement and shall be revised whenever there is a change to the annual transmission revenue requirements in Attachment H to the Open Access Transmission Tariff or a change to the annual transmission
revenue requirements underlying the rates set forth in Schedules 7 and 8 to the Open Access Transmission Tariff. Future revisions to the transmission revenue requirements ratios set forth in Schedule B will be made by the Companies' making an appropriate filing with the Commission, if required by law. Such changes shall become effective as of the date accepted or approved by the Commission, subject to refund if the Commission so orders.
(b) Revenues received for ERCOT Regional Transmission Service provided under Part IV of the Open Access Transmission Tariff shall be allocated between CPL and WTU in accordance with matrices prepared by the ERCOT independent system operator (ISO).
(c) Revenues received for Ancillary Services shall be allocated among the Companies in accordance with the revenue ratios set forth in Schedule C. Future revisions to the revenue ratios set forth in Schedule C will be made by the Companies' making an appropriate filing with the Commission, if required by law. Such changes shall become effective as of the date accepted or approved by the Commission, subject to refund if the Commission so orders.
(d) Revenues received for third-party use of Direct Assignment Facilities shall be distributed to the Company(ies) owning such facilities.
(e) The distribution to the Companies of revenues received for stranded costs received from third-party customers under the Open Access Transmission Tariff shall be determined on a case-by-case basis and shall be filed with the Commission, if required by law.
(f) The distribution to the Companies of revenues received for new transmission facilities received from third-party customers under the Open Access Transmission Tariff shall be determined on a case-by-case basis and shall be filed with the Commission, if required by law.
(g) Revenues received for studies performed for the benefit of a Transmission Customer under Part II or Part III of the Open Access Transmission Tariff shall be allocated to each CSW Operating Company in proportion to the ratio of each CSW Operating Company's number of transmission pole miles, as such number of transmission pole miles is reported in each CSW Operating Company's Form 1 annual report, over the total number of transmission pole miles of the Transmission System. Revenues received for studies performed for the benefit of a Transmission Customer under Part IV of the Open Access Transmission Tariff shall be allocated between CPL and WTU in proportion to the ratio of each of their respective transmission pole miles, as such transmission pole miles are reported in their Form 1 annual reports, over the total number of transmission pole miles of CPL and WTU combined.
6.5 Payment of Costs for Network Use
The Transmission System Operator shall bill each of the Companies for the amount due to the Transmission System Operator in each Month for their use of Network Integration Transmission Service and Ancillary Services under the Open Access Transmission Tariff on the basis set forth in the Open Access Transmission Tariff.
6.6 Payment of Costs for Point-to-Point Transmission Service
(a) The cost of Transmission Service on the Transmission System for third-party off-system sales by a Company shall be borne by the selling Company(ies).
(b) The cost of Transmission Service provided by a third-party for off-system sales by a Company shall be borne by the selling Company(ies).
ARTICLE VII
ANCILLARY SERVICES
7.1 Ancillary Services
(a) Each Company shall make available Ancillary Services as required to provide service under the Open Access Transmission Tariff.
(b) Revenues received for Ancillary Services will be allocated between the Companies in accordance with Section 6.4(c) of this Agreement.
ARTICLE VIII
GENERAL
8.1 Regulatory Authorization
This Agreement is subject to certain regulatory approvals and the Companies shall diligently seek all necessary regulatory authorization for this Agreement.
8.2 Effect on Other Agreements
This Agreement shall not modify the obligations of any of the Companies under any agreement between such Company and others not parties to this Agreement in effect on the effective date of this Agreement.
8.3 Waivers
Any waiver at any time by a Company of its rights with respect to a default by any other Company under this Agreement shall not be deemed a waiver with respect to any subsequent default of similar or different nature.
8.4 Successors and Assigns; No Third Party Beneficiary
This Agreement shall inure to and be binding upon the successors and assigns of the respective Companies, but shall not be assignable by any of the Companies without the written consent of the other Companies, except upon foreclosure of a mortgage or deed of trust. Nothing expressed or mentioned or to which reference is made in this Agreement is intended or shall be construed to give any person or corporation other than the Companies any legal or equitable right, remedy or claim under or in respect of this Agreement or any provision herein contained, expressly or by reference, or any schedule hereto, this Agreement, any such schedule
and any and all conditions and provisions hereof and thereof being intended to be and being for the sole exclusive benefit of the Companies, and for the benefit of no other person or corporation.
8.5 Amendment
It is contemplated by the Companies that it may be appropriate from time to time to change, amend, modify or supplement this Agreement or the schedules that are attached to this Agreement, to reflect changes in operating practices or costs of operations or for other reasons. This Agreement or such schedules may be changed, amended, modified or supplemented by an instrument in writing executed by all of the Companies subject to any required approval or acceptance for filing by the appropriate regulatory authorities.
8.6 Independent Contractors
By entering into this Agreement the Companies shall not become partners, and as to each other and to third persons, the Companies shall remain independent contractors in all matters relating to this Agreement.
8.7 Responsibility and Liability
The liability of the Companies shall be several, not joint or collective. Each Company shall be responsible only for its obligations, and shall be liable only for its proportionate share of the costs and expenses as provided in this Agreement, and any liability resulting herefrom. Each Company will defend, indemnify, and save harmless the other Companies hereto from and against any and all liability, loss, costs, damages, and expenses, including reasonable attorney's fees, caused by or growing out of the gross negligence, willful misconduct, or breach of this Agreement by such indemnifying Company.
IN WITNESS WHEREOF, each Company has caused this Agreement to be executed and attested by its duly authorized officers.
CENTRAL POWER AND LIGHT COMPANY
Attest
________________________ By:________________________________
Secretary President
WEST TEXAS UTILITIES COMPANY
Attest
________________________ By:________________________________
Secretary President
PUBLIC SERVICE COMPANY OF OKLAHOMA
Attest
________________________ By:________________________________
Secretary President
SOUTHWESTERN ELECTRIC POWER COMPANY
Attest
_________________________ By:________________________________
Secretary President
CENTRAL AND SOUTH WEST SERVICES, INC.
Attest
_________________________ By:________________________________
Secretary President
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SCHEDULE A
ALLOCATION OF TRANSMISSION REVENUES
1. Allocation of Transmission Revenues
The revenue the Transmission System Operator receives pursuant to Section 6.4 of the Agreement for service provided by the Companies under Parts II and III of the Open Access Transmission Tariff, other than revenues received pursuant to Sections 26 (Stranded Cost Recovery), 27 (Compensation for New Facilities and Redispatch Costs), and 34.4 (Redispatch Charge) thereof and for System and Facilities Studies made pursuant to Sections 19 (Additional Study Procedures for Firm Point-to-Point Transmission Service Requests) and 32 (Additional Study Procedures for Network Integration Transmission Service Requests), will be allocated among the Companies based on the ratios determined in accordance with Schedule B and Schedule C.
Revenues related to studies performed for the benefit of Transmission Customers under Part II or Part III of the Open Access Transmission Tariff will be allocated among the four CSW Operating Companies in proportion to their respective number of transmission pole miles on the Transmission System. Revenues related to studies performed for the benefit of Transmission Customers under Part IV of the Open Access Transmission Tariff will be allocated between CPL and WTU in proportion to their respective number of transmission pole miles on the combined CPL/WTU system. Direct Assignment Facilities will be assigned to the Companies in proportion to the related costs that each of them incurred. Assignment of revenues received from a third
party related to stranded cost or new transmission facilities shall be determined on a case-by-case basis.
SCHEDULE B
ANNUAL TRANSMISSION REVENUE REQUIREMENTS RATIOS
From time to time the Coordinating Committee will calculate for each of the Companies its Transmission Revenue Requirements Ratios set forth below. A Company's Transmission Revenue Requirements Ratio for revenue received under Part III of the Open Access Transmission Tariff shall be a fraction, the numerator of which is the Company's transmission revenue requirement that is used to calculate the Annual Transmission Revenue Requirements amount set forth on Attachment H to the Open Access Transmission Tariff (herein called the Company Revenue Requirement) and the denominator of which is the sum of the Company Revenue Requirement for all of the Companies. A Company's Transmission Revenue Requirement Ratio for revenue received under Part II of the Open Access Transmission Tariff shall be a fraction, the numerator of which is the Company's transmission revenue requirement that is used to calculate the Annual cost of service Transmission Revenue Requirements amount underlying the rates set forth on Schedules 7 and 8 to the Open Access Transmission Tariff and the denominator of which is the sum of the Company Revenue Requirements for all of the Companies.
1. Allocation Ratio for Revenue Received Under Part III of the Open Access Transmission Tariff from a Non-ERCOT Loading Serving Entity
Revenue Requirement Revenue Requirement Ratio
CPL $60,092,806 33.58595%
PSO $43,794,213 24.47665%
SWEPCO $48,986,232 27.37848%
WTU $26,049,174 14.55892%
TOTAL $178,922,425 100.00000%
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2. Allocation Ratio for Revenue Received Under Part-III of the Open Access Transmission Tariff from an ERCOT Load Serving Entity
Revenue Requirement Revenue Requirement Ratio
CPL $ 2,834,098 2.93693%
PSO $43,794,213 45.38323%
SWEPCO $48,986,232 50.76364%
WTU $ 884,123 0.91620%
TOTAL $96,498,666 100.00000%
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3. Allocation Ratio for Revenue Received Under Part II of the Open Access
Transmission Tariff
Revenue Requirement Revenue Requirement Ratio
CPL $60,092,806 32.83174%
PSO $45,727,891 24.98347%
SWEPCO $51,149,157 27.94538%
WTU $26,062,756 14.23941%
TOTAL $183,032,610 100.00000%
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4. Allocation Ratio for Revenue Received Under Part II of the Open Access Transmission Tariff When Part II Service Is Taken In Conjunction With
Part IV Service
Revenue Requirement Revenue Requirement Ratio
CPL $ 2,834,098 2.81695%
PSO $45,727,891 45.45116%
SWEPCO $51,149,157 50.83962%
WTU $ 897,705 0.89227%
TOTAL $100,608,851 100.00000%
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5. Allocation Ratio for Revenue Received Under Part II the of Open Access Transmission Tariff When Part II Service Is Taken In Conjunction With
the SPP Tariff
Revenue Requirement Revenue Requirement Ratio
CPL $60,092,806 70.01019%
WTU $25,741,569 29.98981%
TOTAL $85,834,375 100.00000%
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SCHEDULE C
ALLOCATION OF ANCILLARY SERVICE REVENUES
The revenues the Transmission System Operator receives pursuant to Schedules 1 through 6 and Schedules 9 through 19 under the Open Access Transmission Tariff shall be allocated among the Companies as set forth below. Future revisions to the revenue ratios set forth in Schedule C will be made by the Companies' making an appropriate filing with the Commission, if required by law. Such changes shall become effective as of the date accepted or approved by the Commission, subject to refund if the Commission so orders.
(a) Revenues received from System Scheduling, System Control and Dispatch Service under Schedule 1 of the Open Access Transmission Tariff will be allocated among the Companies based on the following ratio:
CPL 31.25% WTU 11.78% PSO 25.48% SWEPCO 31.49% |
(b) Revenues received from System Reactive Supply and Voltage Control from Generation Sources Service under Schedule 2 of the Open Access Transmission Tariff will be allocated among the Companies based on the following ratio:
CPL 53.59% WTU 7.23% PSO 15.60% SWEPCO 23.58% |
(c) Revenues received from System Regulation and Frequency Response Service under Schedule 3-A and from System Load Following Service under Schedule 3-B for load served in the PSO/SWEPCO Control Area will be allocated between PSO and SWEPCO based on the following ratio:
PSO 40.00%
SWEPCO 60.00%
Revenues received from System Regulation and Frequency Response Service under Schedule 3-A and from System Load Following Service under Schedule 3-B for load served in the CPL/WTU Control Area will be allocated between CPL and WTU based on the following ratio:
CPL 70.18% WTU 29.82%
(d) Revenues received for and energy exchanged as part of System Energy Imbalance Service rendered under Schedule 4 will be allocated in the same manner as margin from off- system sales and purchases as set forth in Schedule F to the CSW Operating Agreement, a copy of which is attached hereto.
(e) Revenues received from System Operating Reserve - Spinning Reserve Service (SPP) under Schedule 5 and from System Operating Reserve - Supplemental Reserve Service under Schedule 6 for load served in the PSO/SWEPCO Control Area will be allocated between PSO and SWEPCO based on the following ratio:
PSO 35.91%
SWEPCO 64.09%
(f) Revenues received from System Operating Reserve - Responsive Reserve Service (ERCOT) under Schedule 5 and from System Operating Reserve - Supplemental Reserve Service under Schedule 6 for load served in the CPL/WTU Control Area will be allocated between CPL and WTU based on the following ratio:
CPL 68.71% WTU 31.29%
(g) Revenues received from the provision of the ERCOT Responsive Reserve Service under Schedule 9, ERCOT Spinning Reserve Service under Schedule 10, ERCOT Load Following Service under Schedule 13, ERCOT Generation - Scheduling Imbalance Service under Schedule 15, ERCOT Load - Schedule Imbalance Service under Schedule 16, ERCOT Scheduled Backup Service under Schedule 17, ERCOT Automatic Backup Service under Schedule 18, and ERCOT Emergency Energy Service under Schedule 19 for load served in the CPL/WTU Control Area will be allocated between CPL and WTU based on the following ratio:
CPL 69.22% WTU 30.78%
(h) Revenues received from the provision of the ERCOT Static Scheduling Service under Schedule 11 and ERCOT Dynamic Scheduling Service under Schedule 12 for load served in the CPL/WTU Control Area will be allocated between CPL and WTU based on the following ratio:
CPL 72.62% WTU 27.38%
(i) Revenues received from the provision of the ERCOT Load Regulation Service under Schedule 14 for load served in the CPL/WTU Control Area will be allocated between CPL and WTU based on the following ratio:
CPL 70.53% WTU 29.47%
EXHIBIT 10(l)(1)(C)
FIRST AMENDMENT
TO
AMERICAN ELECTRIC POWER SYSTEM
EXCESS BENEFIT PLAN
(As amended and restated effective January 1, 2001)
American Electric Power Service Corporation adopts the following amendment to the American Electric Power System Excess Benefit Plan, as amended and restated as of January 1, 2001 (the "Plan").
1. Section 2.14 of the Plan is hereby amended in its entirety to read as follows:
"2.14 `Maximum Benefit' means the vested retirement benefit payable from the Retirement Plan under either the Final Average Pay Formula or the Cash Balance Formula, whichever is greater, given the Participant's marital status, Beneficiary, credited service and earnings for services rendered to the Company, to the extent such are permitted by the Code and the Retirement Plan to be taken into account under either the Final Average Pay Formula or the Cash Balance Formula."
2. Section 2.21 of the Plan is hereby amended in its entirety to read as follows:
"2.21 `Unrestricted Benefit' means the vested retirement benefit that would be payable from the Retirement Plan under either the Final Average Pay Formula or the Cash Balance Formula, whichever is greater, given the Participant's marital status, Beneficiary, credited service and Plan Earnings, assuming sections 401(a)(17) (Compensation Limit) and 415 (Limitation on Benefits) of the Code are not applicable and taking into account any service, Plan Earnings and other adjustments as are provided for in an Employment Agreement."
3. In all other respects, the terms of the Plan are ratified and confirmed.
IN WITNESS WHEREOF, this Amendment has been executed this 5th day of March, 2003.
American Electric Power Service Corporation
By: /s/ Thomas M. Hagan Title Executive Vice President - Shared Services |
EXHIBIT 10(m)(3)(A)
American Electric Power
1 Riverside Plaza
Columbus, OH 43215-2373
Ms. Holly Keller Koeppel
29 Lynwood Avenue
Killara, NSW, AU 2071
June 23, 2000
Dear Holly:
This letter supercedes our earlier letter dated April 13, 2000 regarding our offer of employment to you as Vice President-New Ventures of American Electric Power Service Corporation. Your primary work location will be Columbus, Ohio and you will report directly to me. We will determine a mutually acceptable start date following your acceptance of this offer.
Among other duties that may be assigned, you will be responsible for managing the activities of AEP's New Ventures group. This will include the development and application of screening criteria to assist AEP in decisions regarding the commitment of resources in the pursuit of new business opportunities developed by New Ventures. In addition, you will be responsible for the development of business plans for new business opportunities that are pursued by New Ventures. You will also assume responsibility for certain administrative functions in AEP Corporate Development.
Your position will be at an AEP salary grade of 36. Your starting salary will be $200,000 a year and will be reviewed on an annual basis. Subject to their specific terms, including Board approval as necessary, you will be eligible for AEP's Management Incentive Compensation Plan (MICP), effective upon merger closing and AEP's Performance Share Incentive Plan (PSIP) beginning January 1, 2001. In addition, you will be eligible to participate in AEP's Long-Term Stock Option Incentive Plan.
The MICP for your position presently has an annual target of 30% of your base compensation, 100% of which will be based on overall corporate performance under the Plan. Actual awards may range from 0% to 200% of target and are paid as soon as possible, after year-end results are confirmed.
The PSIP for your position presently provides an annual award of 30% of your base compensation converted to AEP share units at market value at the end of each three-year performance period. Those units are subsequently multiplied from 0% to 200% to establish actual awards based on comparative three-year Total Shareholder Return. Dividends are credited during the performance period and converted to equivalent performance share units.
PSIP payments are made annually at the end of each three-year performance cycle based on the market value of AEP stock at that time. Payment can be taken in cash or stock once the stock ownership target for your position has been achieved. Your participation in PSIP will begin on January 1, 2001 with an initial award that will be comprised of 1/3 of your normal target for the 1999-2001 performance cycle, 2/3 of your normal target for the 2000-2002 performance cycle, and the full award for your normal target of 30% for the 2001-2003 performance cycle.
AEP's Long-Term Stock Option Incentive Plan was approved by shareholders at the Annual Meeting in April. Given this approval by the shareholders, it is anticipated that there will be a stock option grant during 2000, but specific eligibility, amounts, and terms have not been approved yet by AEP Senior Management or the HR Committee of the Board.
This offer of employment is contingent upon the following:
* successful completion of a pre-employment physical exam
* verification of academic credentials
* acceptable reference checks
Therefore, please complete the enclosed Application for Employment and associated documents as soon as possible and return it in the envelope provided.
You will also find enclosed a letter, which outlines those health and welfare benefits for which you will be eligible (the benefit letter was sent with the earlier offer letter and remains unchanged). In addition to those benefits outlined in the that letter, your pension when you retire at any time after vesting will be calculated using your actual AEP years of service at retirement, plus your years of service while you were employed by CNG, as if you had been continuously employed for the combined period, less any retirement benefit you are entitled to receive from CNG's retirement plan.
Please feel free to contact me or Tim Harshbarger (624-223-1576) if you have any questions or concerns.
Sincerely,
/s/ Donald M. Clements, Jr. Donald M. Clements, Jr. Executive Vice President |
Enclosures
c: T. G. Harshbarger
W. R. Beckley
S.D. Thomas
EXHIBIT 10(m)(3)(B)
AEP Resources, Inc.
1 Riverside Plaza
Columbus, OH 43215-2373
Ms. Holly Koeppel AEP Resources, Inc.
April 19, 2001
Dear Holly,
As you are aware, AEP has recently revised its strategy relative to the long-term ownership and participation in a number of our assets, joint ventures and investments. I realize this decision raises questions in your mind regarding your own future.
I would like to take this opportunity to emphasize the critical role you are playing as we seek to evaluate, restructure and where necessary divest of these assets, joint ventures and investments; the need for you to continue in this role; and the value the company places on your experience and expertise.
In addition, and to further emphasize the desire to retain your services, a retention plan has been developed. In consideration of your agreement to continue your employment in the Corporate Development group until December 31, 2002 (or an earlier date mutually agreed to by yourself and an AEP representative), you will receive a lump sum retention payment equal to nine months of your annual base salary minus applicable withholdings. This payment shall be made regardless of whether or not you are thereafter employed by AEP.
You would forfeit all rights and claims to any retention payments should you leave Corporate Development voluntarily prior to December 31, 2002 or be terminated for cause.
If the proposal contained in this letter is acceptable to you, it will become effective when you sign this letter and return it to me.
Sincerely,
/s/ Donald M. Clements, Jr. Donald M. Clements, Jr. President |
Agreed:
/s/ Holly K. Koeppel 25 April 2001 |
EXHIBIT 10(m)(4)
EMPLOYMENT AGREEMENT
In consideration of the mutual promises and covenants contained herein, this Employment Agreement (the "Agreement") is entered into by and between American Electric Power Service Corporation, including any of its parent and/or subsidiary companies, divisions, organizations, or affiliated entities (collectively referred to as "AEP"), and Robert P. Powers (the "Employee" and with AEP sometimes collectively referred to as the "Parties"), this 29th day of July, 1998.
Section I: Term of Employment
1.01 AEP agrees to employ Employee as Senior Vice President-Nuclear beginning on July 31, 1998 (hereafter referred to as the "Date of Hire").
Section II: Duties of Employee
2.01 Employee shall report to E. Linn Draper, Jr. or such other individual as he may designate. Employee's duties and responsibilities shall include, but are not limited to, the following: operating AEP's Cook Nuclear Plant and such other nuclear generation facilities that AEP may periodically acquire, in a safe and efficient manner, ensuring that operations are in full compliance with all applicable local, state and federal laws, regulations and/or ordinances; and perform other related duties that may be assigned from time to time.
2.02 During Employee's employment with AEP, Employee shall devote Employee's best efforts, loyalty, and entire working time with AEP to the performance of Employee's duties, and shall not render services to, or enter into an employment, independent contractor, consultancy, or agency relationship with, any person, firm, corporation, other business entity and/or governmental body or agency other than AEP without AEP's express, prior and written consent.
Section III: Compensation and Benefits
3.01 As compensation for services and duties rendered under the Agreement, Employee shall receive from AEP an annual salary of $240,000.00 payable in accordance with AEP's standard payroll practices and subject to withholdings for FICA and applicable federal, state and local income taxes.
3.02 Subject to AEP's right to change, modify, amend and/or eliminate any of the following, Employee shall be entitled to participate in AEP's Exempt Salary Administration Program, The Management Incentive Program ("MICP"), The Performance Share Incentive Program ("PSIP"), The Nuclear Performance Incentive Program ("NPIP"), The AEP System Survivor Benefit Plan (Split Dollar), the American Electric Power Excess Benefit Plan, and AEP's savings, retirement and employee welfare/benefit programs. Upon such terms and conditions established by AEP, and subject to AEP's right to change, modify, amend and/or eliminate the following, the Employee shall also be entitled to additional executive-level benefits such as a company car and a country club membership.
3.03 Employee shall be entitled to ten days of paid vacation and three paid personal days to be used during 1998, and twenty days of paid vacation and three paid personal days to be used during each year thereafter.
3.04 Employee shall receive a $300,000.00 bonus payment, subject to withholding for FICA and applicable federal, state and local income tax, as follows: $150,000.00 paid at or around the Date of Hire; $100,000.00 paid on January 1, 1999; and $50,000.00 on January 1, 2000. The Employee can, at Employee's option, defer some or all of the $300,000.00 bonus payment until Employee retires, in the form of a financial instrument that is agreeable to both AEP and the Employee. AEP shall not be obligated to pay the bonus payments that are due and owing to Employee on January 1, 1999 and January 1, 2000 if, prior to those dates, AEP terminates Employee's employment for performance-related reasons or Employee resigns.
Section IV: Supplemental Retirement Benefit
4.01 The Employee shall be entitled to a Supplemental Retirement Benefit. For pension calculation purposes, employee shall be credited with seventeen years of service in addition to the number of years that the Employee actually works for AEP. The Employee shall be entitled to a retirement benefit calculated as follows:
(a) The retirement benefit the Employee would be entitled to receive as of the date of the Employee's termination of employment, under the terms of the American Electric Power Excess Benefit Plan, as amended from time to time or any successor thereto, based upon the compensation the Employee received during the term of this Employment Agreement, including earned MICP awards and excluding earned PSIP and NPIP awards, based upon the actual number of years of service to AEP plus seventeen years of credited service;
(b) Less the retirement benefit the Employee would be entitled to receive as of the date of the Employee's termination of employment, under the terms of the American Electric Power System Retirement Plan, as amended from time to time or any successor thereto, based upon the compensation the Employee received during the term of this Employment Agreement, excluding earned MICP, PSIP and NPIP awards, for the actual years of service to AEP;
(c) Less any retirement benefit the Employee is entitled to receive from all qualified and non-qualified plans sponsored by any prior employer of the Employee. The Employee shall provide the Company with a list of such other plans within a reasonable time after Employee's employment terminates.
4.02 The Employee's election under the terms of the American Electric Power System Retirement Plan of a 50% Joint and Survivor Annuity or any other optional form of payment, with the valid consent of the Employee's Spouse where required, shall be deemed to be the payment election the Employee makes for purposes of the Supplemental Retirement Benefit.
4.03 In the event the Agreement is terminated due to the death of the Employee, the Employee's spouse shall be entitled to a Supplemental Pre-Retirement Surviving Spouse Annuity provided that the Employee and the Employee's spouse were married for at least one year prior to the employee's death. The amount of the Supplemental Pre-Retirement Surviving Spouse Annuity shall be equal to the following:
(a) The pre-retirement surviving spouse annuity the Employee's spouse would be entitled to receive under the terms of the American Electric Power System Excess Benefit Plan, based upon the compensation the Employee received from the Company prior to his death, including earned MICP awards and excluding earned PSIP and NPIP awards;
(b) Less any surviving spouse annuity the Employee's surviving spouse is entitled to receive from any qualified or non-qualified plan sponsored by any prior employer of the Employee;
(c) Less any surviving spouse annuity the Employee's surviving spouse is entitled to receive from the American Electric Power System Retirement Plan.
4.04 The Supplemental Retirement Benefit or the Supplemental Pre-Retirement Surviving Spouse Annuity shall be paid out of the general assets of AEP and shall be covered by the American Electric Power Service Corporation Umbrella Trust for Executives. The supplemental benefits provided by this Agreement are in lieu of any similar benefit provided by the American Electric Power System Excess Benefit Plan.
Section V: Termination
5.01 Employee's employment with AEP is, and will be at all times, "at will". Thus, AEP or Employee may terminate Employee's employment and this Agreement for any or no reason upon written notice to the other. In the case of the Employee, the notice shall be furnished not less than fourteen calendar days prior to the designated date of termination. In the latter instance, AEP reserves the right to accelerate Employee's date of termination by paying Employee two weeks' salary calculated on the basis of the annualized amount indicated in Section 3.01.
5.02 In the event that Employee's employment is terminated under this
Agreement by either the Employee or AEP, AEP shall no longer be obligated to
provide Employee with any compensation under Section 3.01, but Employee shall,
in accordance with the terms and conditions set forth in each plan then in
effect as applicable, be entitled to any amounts to which the Employee may be
eligible to receive pursuant to Sections 3.02, Section 3.03, Section 4, and
Section 5.01 and in accordance with the terms and conditions of each plan then
in effect.
5.03 In the event that the Employee's position is eliminated due to a change in AEP's business strategy or organization not related to Employee's performance as the Senior Vice President-Nuclear prior to Employee reaching age 55, AEP will offer Employee either:
(a) a comparable position with comparable pay, benefits, and responsibilities within AEP; or
(b) if no such position is available, AEP will continue Employee's pay and benefits for a period not to exceed eighteen months (hereinafter referred to as the "Transition Period") to provide Employee with an opportunity to find employment outside of AEP. Payments during the first twelve months of the Transition Period shall include Employee's normal salary, benefits, and Employee's target MICP, PSIP and NPIP incentive payments at target, prorated for partial portions of a year. Payment during the last six months of the Transition Period shall include Employee's base salary and benefits only. In the event that no comparable position is available within AEP, the Employee covenants and agrees in good faith to diligently search for a position outside of AEP. AEP's obligations to compensate Employee any amount of pay and/or benefits pursuant to this provision shall cease as of the Employee's effective date of hire with a new employer or at the end of the Transition Period, whichever occurs first.
(c) For purposes of Section 5.03(a) of this Agreement, a position shall be deemed to be comparable if Employee's total compensation, including incentives at target, equal at least 90% of the compensation that the Employee received with AEP including incentives at target.
(d) If, prior to the expiration of the Transition Period, the Employee accepts employment with another company that is not comparable (as defined in Section 5.03(b) of this Agreement), AEP will, during the Transition Period, pay the difference between Employee's new total compensation, including incentives at target, and the payments the Employee would have received had the Employee not accepted the employment with another company.
Section VI: Confidential Business Information and Trade Secrets
6.01 Employee recognizes that during Employee's employment with AEP, the Employee will have access to and become familiar with confidential, proprietary and/or trade secret information which is owned by AEP and regularly used in its operation. Employee understands and agrees that AEP's confidential, proprietary and/or trade secret information derives independent economic value for AEP, actual or potential, from not being generally known or readily ascertainable by other persons and entities who can obtain economic value from such information, and that AEP takes reasonable efforts to maintain the secrecy of this information. Employee agrees that during Employee's employment with AEP, except as required in the performance of Employee's employment with AEP, or at any time thereafter, Employee shall not directly or indirectly possess, use, convert, misappropriate, copy or duplicate any confidential, proprietary and/or trade secret information, or communicate, disclose, sell, transmit or transfer any confidential, proprietary and/or trade secret information to any person, firm, partnership, corporation, proprietorship, or business organization or entity of any kind or description.
6.02 Employee acknowledges that confidential, proprietary and/or trade secret information is defined to include, but is not limited to, the whole or any part of paper copies or paper documents of any kind, computer data bases, computer e-mail, computer programs and/or computer memory or storage devices of any kind that contain, reflect, or relate to: (a) the design, process, procedure, method, technique, formula, or improvement of any current or future products or services developed, manufactured, owned, produced, sold, leased, distributed or provided by AEP; (b) marketing plans and any associated information such as customer names and/or contacts, addresses, telephone or fax numbers, mailing lists, and customer, vendor and supplier account data; (c) consulting reports; (d) site assessments; (e) business plans, financial information, billing information, sales figures, price lists, discounts, or any financial information; (f) computer passwords or codes; (g) information or data relating to the energy commodity market and related financial instruments, and/or statistical and analytical data, including analytical models, used to forecast changes in the pricing of energy commodities or the value of related financial instruments.
6.03 Employee understands and agrees that prior to or immediately upon the termination of Employee's employment with AEP, whether voluntarily or involuntarily and regardless of the circumstances relating to the termination, Employee shall deliver and leave with AEP in good order all such confidential, proprietary and/or trade secret information, in addition to any other AEP property, including computer diskettes, laptops and any related equipment, which is in Employee's possession and/or control.
Section VII: Miscellaneous
7.01 The Agreement shall be binding upon and inure to the benefit of AEP and its successors and assigns, and Employee and Employee's assigns, legal representatives and heirs. The Agreement shall be assignable by AEP to any successor employer.
7.02 Nothing herein shall be construed as amending the terms and conditions of the American Electric Power System Retirement Plan, the American Electric Power System Employees Savings Plan, the MICP, PSIP or NPIP.
7.03 The provisions of the Agreement are severable. If any provision of the Agreement is found by a court of competent jurisdiction to be unreasonable and invalid, that determination shall not affect the enforceability of the other provisions, which shall be enforced in all respects to the maximum benefit of AEP.
7.04 The Agreement shall be governed by and construed in accordance with the laws of the State of Ohio. Employee and AEP agree that AEP has the exclusive right to decide the forum appropriate for any litigation that relates to the validity, interpretation, performance, enforcement, breach or threatened breach of the Agreement and/or Employee's job performance, conduct, and/or termination from employment thereunder. In the event that AEP determines that it is appropriate for any of the aforementioned issues relating to the Agreement to be litigated in a state or federal court located in the State of Ohio, by entering into this Agreement Employee expressly agrees to confer personal jurisdiction of Employee upon the common pleas, municipal, and federal courts of the State of Ohio. In the event that the Employee initiates any legal action relating to the aforementioned issues, Employee expressly agrees to bring said legal action in the Franklin County Court of Common Pleas, Franklin County, Ohio (subject to AEP's right to remove the action to federal court if allowed by law) or the United States District Court for the Southern District of Ohio, Eastern Division in Columbus, Ohio.
7.05 AEP shall have the right to assign this Agreement to any of its parent and/or subsidiary companies, divisions, organizations or affiliated entities that presently exist or which may be established in the future.
7.06 The Agreement contains the entire understanding of the Parties relating to the subject matter hereof, and AEP and Employee each acknowledge that they have made no agreements, representations or warranties, express or implied, relating to the subject matter of the Agreement which are not set forth herein or attached hereto as an addendum. No provision of the Agreement may be changed, modified or waived except by an agreement in writing and signed by Employee and E. Linn Draper, Jr.
/s/ Robert P. Powers /s/ E. Linn Draper, Jr. Chairman of the Board, President and Chief Executive Officer, American Electric Power Service Corporation |
EXHIBIT 10(o)(2)
First Amendment
to the
AEP System Survivor Benefit plan
as amended and restated effective January 31, 2000
This First Amendment is made to the AEP System Survivor Benefit Plan, as amended (the "Plan"), by American Electric Power Service Corporation, a New York corporation, on behalf of itself and any affiliate or subsidiary participating in the Plan (collectively, the "Employer").
Recitals
A. The Plan was adopted effective January 27, 1998 and most recently amended and restated effective January 31, 2000, on January 30, 2000. Eligibility for the Plan has generally been made available to all employees of the Employer who are in or enter salary grade 30 or higher and such other employees of the Employer who are approved for participation by the Chief Executive Officer of the Employer.
B. Section 9.1 of the Plan permits the Employer to amend the Plan from time to time as may be necessary for administrative purposes and legal compliance, provided that no amendment reduces the amount of benefit payable with respect to a Participant who is eligible to retire or who has retired. Section 9.2 of the Plan permits the Employer to terminate the Plan in whole or in part at any time in the Employer's sole discretion.
C. On or about July 31, 2002, the Employer determined to discontinue offering the Plan to any additional Employees hired on or after August 1, 2002, such that such additional Employees hired into salary grades 30 through 38 (other than such Employees hired or promoted to salary grade 38 or higher with an officer title of SVP or higher with American Electric Power Service Corporation) shall instead become eligible to participate in the group term coverage offered under the American Electric Power System Group Life & AD&D Insurance Plan.
Amendment
Section 3.1 of the Plan is hereby amended in its entirety to read as follows:
3.1 Eligibility
All employees of the Employer who, within the period January 27, 1997 through July 31, 2002, were either (a) in management salary grade 30 or higher or (b) approved for participation by the Chief Executive Officer of the Employer, and who are currently enrolled in the plan, shall be eligible to participate. No additional employees of the Employer shall become eligible to participate after July 31, 2002.
The Employer has caused this amendment to be signed by its duly authorized officer this 11th day of November, 2002.
American Electric Power Service Corporation
By /s/ Armando A. Pena Armando A. Pena Title: Senior Vice President-Finance, Treasurer and Chief Financial Officer |
EXHIBIT 10(q)(1)
AMERICAN ELECTRIC POWER SYSTEM
INCENTIVE COMPENSATION DEFERRAL PLAN
ARTICLE I
PURPOSE AND EFFECTIVE DATE
1.1 The American Electric Power System Incentive Compensation Deferral Plan ("Plan") is established to allow Eligible Employees to elect to defer receipt of all or a portion of their Incentive Compensation until their termination of employment.
1.2 The effective date of the Plan is January 1, 2001.
ARTICLE II
DEFINITIONS
2.1 "Account" means the separate memo account established and maintained by the Company or the recordkeeper employed by the Company to record Participant deferrals of Incentive Compensation and to record any related Investment Income on the Fund or Funds selected by the Participant or Former Participant.
2.2 "Base Compensation" means an employee's regular base salary or wage including any salary or wage reductions made pursuant to sections 125 and 402(e) of the Code and employee elective contributions to the American Electric Power System Supplemental Retirement Savings Plan.
2.3 "Code" means the Internal Revenue Code of 1986 as amended from time to time.
2.4 "Committee" means employees of the Company holding the following offices; Senior Vice President Human Resources, Executive Vice President - Shared Services, and Executive Vice President - Finance and Analysis.
2.5 "Company" means American Electric Power Service Corporation, its subsidiaries and affiliates.
2.6 "Disability" means the Participant's entitlement to disability benefits under the terms of the American Electric Power System Disability Plan.
2.7 "Eligible Employee" means any employee of the Company whose Base Compensation for the Plan Year exceeds $100,000 or is in salary grade 26 or higher.
2.8 "Former Participant" means a Participant who has terminated employment or a Participant who is no longer an Eligible Employee but who has Funds in the Plan.
2.9 "Fund" means the investment options made available to Eligible Employees in the American Electric Power System Retirement Savings Plan or other funds selected by the Committee.
2.10 "Incentive Compensation" means incentive compensation paid pursuant to the terms of annual and long-term incentive compensation plans approved by the Committee for inclusion in the Plan. Incentive Compensation will not include Base Compensation, non-annual bonuses compensation (such as but not limited to project bonuses and sign-on bonuses), severance pay, or relocation payments
2.11 "Investment Income" means with respect to the Fund or Funds selected by the Participant or Former Participant the earning, gains and losses derived from the investment of deferred compensation in the Fund or Funds.
2.12 "Participant" means an Eligible Employee who elects to defer part or all of his or her Incentive Compensation.
2.13 "Plan Year" means the calendar year commencing each January 1and ending each December 31.
2.14 "Retirement" means a Participant or Former Participant's termination of employment after attaining age 55 and the completion of five years of service with the Company.
ARTICLE III
ADMINISTRATION
3.1 The Committee shall (i) administer and interpret the terms and conditions of the Plan, (ii) establish reasonable procedures with which Participants must comply to exercise any right established hereunder, and (iii) be permitted to delegate its responsibilities or duties hereunder to any person or entity. The rights and duties of the Participants and all other persons and entities claiming an interest under the Plan are subject to, and governed by, such acts of administration, interpretation, procedure and delegation taken by the Committee.
3.2 The Committee may employ agents, attorneys, accountants, or other persons and allocate or delegate to them powers, rights, and duties all as the Committee may consider necessary or advisable to properly carry out the administration of the Plan.
3.3 The Company shall maintain, or cause to be maintained, records showing the individual balances in each Participant's Account. Each Participant shall receive quarterly statements setting forth the balance of the Participant's Account at the end of the quarter. The maintenance of the Account records and the distribution of the quarterly statements may be delegated to a recordkeeper by either the Company or the Committee.
ARTICLE IV
PARTICIPATION
4.1 Eligible Employees shall become Plan Participants by making a deferral election on a form prescribed by the Company to defer part or all of the Eligible Employee's Incentive Compensation earned during the Plan Year but which is paid after the end of the Plan Year.
ARTICLE V
DEFERRALS
5.1 A Participant shall make a separate Incentive Compensation deferral election for each Plan Year. If a deferral election for a Plan Year is not made within the time period prescribed by the Company, no portion of the Eligible Employee's Incentive Compensation for the Plan Year shall be deferred.
5.2 All deferred Incentive Compensation shall be paid in accordance with the distribution option selected by the Participant in accordance with the terms of section 7.3.
ARTICLE VI
INVESTMENT OF DEFERRED AMOUNTS
6.1 All deferred incentive compensation shall be invested in the Funds selected by the Participant. A Participant may change the selected Funds by notifying the recordkeeper retained by the Company. Any change in the Funds selected by the Participant shall be implemented as soon as practicable.
6.2 A Participant or Former Participant may elect to transfer all or a portion of the Funds to any other Fund or Funds by giving notice to the recordkeeper. Transfers between Funds may be made in any whole percentage or dollar amounts and shall be implemented as soon as possible.
6.3 The Funds shall be valued daily at their fair market value and each Participant's and Former Participant's Account shall be valued daily at its fair market value. The fair market value shall be calculated by the recordkeeper.
6.4 The Plan is an unfunded non-qualified deferred compensation plan and amounts credited to a Participant's or Former Participant's Account and the investment of the credited amounts in the Fund or Funds selected by the Participant or Former Participant are memo accounts that represent general, unsecured liabilities of the Company payable exclusively out of the general assets of the Company.
ARTICLE VII
DISTRIBUTIONS
7.1 Upon a Participant's or Former Participant's termination of employment with the Company for any reason other than Retirement, Disability or death the Company shall pay the Participant or the Former Participant the full amount credited to the Participant's or Former Participant's Account. The payment shall be made within 60 days of the Participant's or Former Participant's termination of employment.
7.2 Upon a Participant's or Former Participant's termination of employment due to Retirement, Disability or death benefits shall be paid in the form elected by the Participant or Former Participant that is in effect at least one year prior to the payment or the scheduled payment to the Participant whichever is sooner. The payment form elected by a Participant or a Former Participant shall apply to all Incentive Compensation deferral elections made by the Participant or the Former Participant.
7.3 The form of benefit payments shall be one of the following:
1. A single lump sum distribution at the time of Retirement or Disability or up to five years after Retirement or Disability;
2. Annual distributions over not less than two and not more than ten years commencing one to five years after Retirement or Disability;
7.4 Distributions to Participants who are not executive officers of the Company shall commence as soon as practical (generally within 60 days) after the Participant's or Former Participant's Retirement, Disability or death unless a Participant has elected to defer distributions. Distributions to Participants who are executive officers of the Company shall commence in January of the year following the Participant's or Former Participant's Retirement, Disability or death unless a Participant has elected to defer distributions. If the Participant or Former Participant elected to defer distributions for one to five years, distributions shall be made on the selected deferral date except for balances of $5,000 or less as provided in section 7.5.
7.5 If a Participant's or Former Participant's Account is $5,000 or less on the date that such Participant or Former Participant becomes eligible for a distribution due to Retirement, Disability, death or the receipt of a withdrawal request, the full value of the Account shall be distributed as a lump sum.
7.6 If an annual distribution is selected, the amount to be distributed in any one-year shall be determined by dividing the Participant's or Former Participant's Account by the number of years remaining in the elected distribution period. The Participant or Former Participant electing annual distributions shall have the right to make changes in the Fund or Funds the Account is invested in accordance with section 6.2.
7.7 Notwithstanding any other provision of this Plan a Participant or Former Participant shall be entitled to receive, upon written request to the Committee, a lump sum distribution from his or her Account of an amount equal to or greater than 25% of the Participant's Account as of the date of the request. The date of the request shall be the date the Committee or the Committee's representative receives the request. The lump sum amount to be paid to the Participant shall be subject to a 10% early withdrawal penalty, which penalty shall reduce the amount to be distributed to the Participant or Former Participant. The Participant or Former Participant shall forfeit the amount of the 10% withdrawal penalty. The lump sum amount shall be paid within 60 days after the Committee receives the withdrawal request. Any Participant or Former Participant who elects to receive a benefit under this section shall not be eligible to participate in future Incentive Compensation deferrals for the Plan Year in which the request is made and for two consecutive Plan Years thereafter and the Participant may not request any additional withdrawals prior to the Participant's termination of employment.
ARTICLE VIII
BENEFICIARIES
8.1 Each Participant or Former Participant shall have the right at any time, to designate one or more persons or an entity as a beneficiary (both primary or secondary) to whom benefits under this Plan shall be paid in the event of a Participant's or Former Participant's death prior to complete distribution of the Account. Each beneficiary designation shall be in a written form prescribed by the Committee and shall be effective only when filed with the Committee during the Participant's or Former Participant's lifetime.
8.2 If the designated beneficiaries predecease the Participant or Former Participant, or if the Participant or Former Participant did not designate a beneficiary, or if the beneficiary designation is not valid, the value of the Account shall be distributed to the Participant's or Former Participant's spouse if then living. If the spouse is not living, then the value of the Account shall be distributed to the representative of the estate. Distributions to a surviving spouse, beneficiary or representative of the estate shall be made as soon as reasonable in accordance with a distribution election made by the surviving spouse, beneficiary or representative of the estate. If a distribution election is not completed within 90 days of the Participant's or Former Participant's death, the value of the account shall be distributed in a lump sum.
ARTICLE IX
M ISCELLANEOUS PROVISIONS
9.1 Each Participant agrees that as a condition of participation in the Plan, the Company may withhold federal, state and local income taxes, Social Security taxes and Medicare taxes from any distribution hereunder to the extent that such taxes are then payable.
9.2 In the event that a Participant or beneficiary is unable to care for his or her affairs because of illness or accident, the Company may direct that any payment due the Participant or the beneficiary be paid to the duly appointed legal representative of the Participant or beneficiary, and any such payment so made shall be a complete discharge of the liabilities of the Plan and the Company.
9.3 The Company intends to continue the Plan indefinitely but reserves the right to modify the Plan from time to time, or to terminate the Plan entirely, provided that no such modification or termination shall affect or otherwise deprive a Participant or beneficiary of any distributions to which they may be entitled under the Plan.
9.4 Nothing in the Plan shall interfere with or limit in any way the right of the Company to terminate any Participant's employment at any time, or confer upon a Participant any right to continue in the employ of the Company.
9.5 The Plan shall be construed and administered according to the laws of the State of Ohio.
EXHIBIT 10(q)(2)
FIRST AMENDMENT TO
AMERICAN ELECTRIC POWER SYSTEM
INCENTIVE COMPENSATION DEFERRAL PLAN
This First Amendment is made by American Electric Power Service Corporation (the "Company") to the American Electric Power System Incentive Compensation Deferral Plan (the "Plan") that was made effective January 1, 2001.
WHEREAS, the Company reserved the right to modify the Plan from time to time in a manner that does not affect or otherwise deprive a Plan participant or beneficiary of any distributions to which he may be entitled under the Plan; and
WHEREAS, the Company desires to implement a claims procedure under the Plan to provide for the efficient disposition of disputed claims that may arise under the terms of the Plan;
NOW, THEREFORE, the Company hereby amends the Plan by adding a new Article X at the end thereof, effective with respect to all claims that may be raised under the terms of the Plan, regardless of whether such claim may have arisen before or after the date that this amendment is adopted:
ARTICLE X
CLAIMS PROCEDURE
Section 10.1 The following procedures shall apply with respect to claims for benefits under the Plan.
(a) Any Participant or beneficiary who believes he or she is entitled to receive a distribution under the Plan which he or she did not receive or that amounts credited to his or her Account are inaccurate, may file a written claim signed by the Participant, beneficiary or authorized representative with the Company's Director-Compensation and Executive Benefits, specifying the basis for the claim. The Director-Compensation and Executive Benefits shall provide a claimant with written or electronic notification of its determination on the claim within ninety days after such claim was filed; provided, however, if the Director-Compensation and Executive Benefits determines special circumstances require an extension of time for processing the claim, the claimant shall receive within the initial ninety-day period a written notice of the extension for a period of up to ninety days from the end of the initial ninety day period. The extension notice shall indicate the special circumstances requiring the extension and the date by which the Plan expects to render the benefit determination.
(b) If the Director-Compensation and Executive Benefits renders an adverse benefit determination under Section 10.1(a), the notification to the claimant shall set forth, in a manner calculated to be understood by the claimant:
(1) the specific reasons for the denial of the claim;
(2) specific reference to the provisions of the Plan upon which the denial of the claim was based;
(3) a description of any additional material or information necessary for the claimant to perfect the claim and an explanation of why such material or information is necessary, and
(4) an explanation of the review procedure specified in Section 10.2, and the time limits applicable to such procedures, including a statement of the claimant's right to bring a civil action under section 502(a) of the Employee Retirement Income Security Act of 1974, as amended, following an adverse benefit determination on review.
Section 10.2 The following procedures shall apply with respect to the review on appeal of an adverse determination on a claim for benefits under the Plan.
(a) Within sixty days after the receipt by the claimant of an adverse benefit determination, the claimant may appeal such denial by filing with the Committee a written request for a review of the claim. If such an appeal is filed within the sixty day period, the Committee, or a duly appointed representative of the Committee, shall conduct a full and fair review of such claim that takes into account all comments, documents, records and other information submitted by the claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination. The claimant shall be entitled to submit written comments, documents, records and other information relating to the claim for benefits and shall be provided, upon request and free of charge, reasonable access to, and copies of all documents, records and other information relevant to the claimant's claim for benefits. If the claimant requests a hearing on the claim and the Committee concludes such a hearing is advisable and schedules such a hearing, the claimant shall have the opportunity to present the claimant's case in person or by an authorized representative at such hearing.
(b) The claimant shall be notified of the Committee's benefit determination on review within sixty days after receipt of the claimant's request for review, unless the Committee determines that special circumstances require an extension of time for processing the review. If the Committee determines that such an extension is required, written notice of the extension shall be furnished to the claimant within the initial sixty-day period. Any such extension shall not exceed a period of sixty days from the end of the initial period. The extension notice shall indicate the special circumstances requiring the extension and the date by which the Committee expects to render the benefit determination.
(c) The Committee shall provide a claimant with written or electronic notification of the Plan's benefit determination on review. The determination of the Committee shall be final and binding on all interested parties. Any adverse benefit determination on review shall set forth, in a manner calculated to be understood by the claimant:
(1) the specific reason(s) for the adverse determination;
(2) reference to the specific provisions of the Plan on which the determination was based;
(3) a statement that the claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the claimant's claim for benefits; and
(4) a statement of the claimant's right to bring an action under
Section 502(a) of ERISA.
American Electric Power Service Corporation has caused this First Amendment to the American Electric Power System Incentive Compensation Deferral Plan to be signed as of this 6th day of December, 2002.
American Electric Power Service Corporation
By /s/ Melinda S. Ackerman
Melinda S. Ackerman, Senior Vice
President, Human Resources
|
EXHIBIT 10(r)
AMERICAN ELECTRIC POWER SYSTEM
NUCLEAR PERFORMANCE
LONG TERM INCENIVE COMPENSATON PLAN
ARTICLE I
Establishment and Purpose
1.1 The Company hereby establishes the American Electric Power System Nuclear Performance Long Term Incentive Compensation Plan effective as of August 1, 1998.
1.2 The purpose of the American Electric Power System Nuclear Performance Long Term Incentive Compensation Plan is to enhance the performance of the D.C. Cook Nuclear Plant and to reward those employees who efforts are instrumental to the performance of the D.C. Cook Nuclear Plant.
ARTICLE II
Definitions
As used herein the following words and phrases shall have the following respective meanings unless the context clearly indicates otherwise.
(a) "AEP Stock Unit" means a phantom stock unit equal to one share of Common Stock for which no certificates shall be issued, which do not have voting rights and a bookkeeping record of which shall be maintained by the Company.
(b) "Award Certificate" means a certificate setting forth the terms and provisions applicable to each grant of AEP Stock Units, which shall include, but shall not be limited to, the number of AEP Stock Units granted to the Participant, the Performance Objectives, and the length of the Performance Period.
(c) "Committee" means the individuals holding the following offices within the Company; Chairman of the Board, President and Chief Executive Officer; Executive Vice President-Financial Services; Executive Vice President-Corporate Services; Senior Vice President-Nuclear Generation; and Senior Vice President-Human Resources.
(d) "Common Stock" means the common stock of American Electric Power Company, Inc., a New York corporation and any successor thereto.
(e) "Company" means American Electric Power Service Corporation, a New York corporation, and any of its subsidiaries and affiliates.
(f) "Disability" means a total and permanent disability as defined in the American Electric Power System Retirement Plan as amended from time to time.
(g) "Fair Market Value" means the closing sale price of the Common Stock as published in the Wall Street Journal report of the New York Stock Exchange on the date in question, or if the New York Stock Exchange is Closed on such date, then the first day prior theret6 on which the Common Stock was so traded.
(h) "Participant" means any full-time employee of the Company, who has been selected to participate in the Plan for a stipulated Performance Period.
(i) "Performance Objectives" means the annual Plan Year objectives or multiple Plan Year objectives established by the Company for the operation of the D. C. Cook Nuclear Plant
(j) "Performance Period" means the Plan Year or Plan Years established by the Company over which the Performance Objectives will be measured. If a Performance Period is for two or more Plan Years, the attained Performance Objectives for each Plan Year within the Performance Period shall be averaged to determine the attained Performance Objective for the Performance Period.
(k) "Plan" means the American Electric Power System Nuclear Performance Long Term Incentive Compensation Plan.
(l) "Plan Year" means the calendar year commencing on January 1 and ending on December 31.
(m) "Retirement" means a termination of employment after the Participant attains age 55 and has completed five years of service.
ARTICLE III
Administration
3.1 The Committee shall administer the Plan. The Committee shall have the authority to interpret the Plan and to prescribe, amend and rescind rules and regulations relating to the administration of the Plan, and all such interpretation, rules and regulation shall be conclusive and binding on all Participants.
3.2 The Committee may employ agents, attorneys, accountants, or other person and allocate or delegate to them powers, rights, and duties all as the Committee may consider necessary or advisable to properly carry out the administration of the Plan.
3.3 If the Committee determines that the occurrence of any merger, reclassification, consolidation, recapitalization, stock dividend or stock split requires an adjustment in order to preserve the benefits intended under the Plan, then the Committee may, in its discretion, make equitable proportionate adjustments in individual AEP Stock Unit grants.
ARTICLE V
Eligibility and Participation
4.1 Eligibility for participation in the Plan shall be limited to senior officers who, in the opinion of the Committee, have the capacity for contributing in a substantial measure to the successful performance of the D.C. Cook Nuclear Plant.
4.2 At the beginning of each Plan Year, the Committee shall identify which, if any, Participants shall receive a grant of AEP Stock Units for a Performance Period that commences at the start of the Plan Year. At the sole discretion of the Committee an individual may become a Participant in the Plan after tile start of a Plan Year or a Performance Period and shall receive prorated grants of AEP Stock Units. As soon as practicable following the selection of the Participants, the Committee shall provide each Participant with an Award Certificate.
ARTICLE V
Grants of AEP Stock Units
5.1 Grants of AEP Stock Units:
(a) AEP Stock Units may be granted to Participants as of the first day of each Performance Period; however, grants do not necessarily have to be made to Participant on an annual basis. The number of AEP Stock Units to be granted to each Participant shall be determined by the Committee in its sole discretion.
(b) If an individual becomes a Participant after the first day of a
Plan Year or Performance Period, the Committee may grant AEP Stock Units to
tile Participant as follows: (i) AEP Stock Units for a Performance Period
that ends in tile Plan Year in which tile individual becomes a Participant;
(ii) AEP Stock Units for a Performance Period that ends in the Plan Year
immediately following the Plan Year in which the individual becomes a
Participant; and (iii) AEP Stock Units for a Performance Period that ends
in the second full Plan Year after the individual becomes a Participant.
The number of AEP Stock Units granted for each such Performance Period
shall be determined by the Committee in its sole discretion.
(c) The value of the AEP Stock Units granted to a Participant at the commencement of a Plan Year or Performance Period as provided in section 5.1(a) or after the commencement of a Plan Year or Performance Period as provided in section 5.1(b) shall be calculated on the basis of the average of the Fair Market Value of the Common Stock for the last 20 trading days prior to the start of a Plan Year or Performance Period.
5.2 During the Performance Period, Participants will be credited with dividends, equivalent in value to those declared and paid on shares of the Common Stock, on all AEP Stock Units granted to them. These dividends will be regarded as having been reinvested in AEP Stock Units on the date of the Common Stock dividend payments based on the then Fair Market Value of the Common Stock, thereby increasing the number of AEP Stock Units Held by the Participant.
5.3 The Committee shall establish Performance Periods in its sole discretion. The minimum Performance Period shall be for one year and the maximum Performance Period shall be for three years in length.
ARTICLE VI
Determination and Payment
6.1 The number of AEP Stock Units earned by a Participant for a Performance Period shall be determined by multiplying the number of AEP Stock Units held by the Participant at the end of the Performance Period by a factor based upon the Performance Objectives.
6.2 The payment of earned AEP Stock Units shall be made in cash. The cash payment shall be calculated on the basis of the average of the Fair Market Value of the Common Stock for the last 20 trading days of the Performance Period for which the AEP Stock Units were earned.
6.3 At least one year prior to the end of a Performance Period, Participants may make an election to defer the cash payment of earned ABP Stock Units for one or more years. However, if the Participant's deferral period extends beyond the Participant's employment termination date, cash payment of the earned AEP Stock Units must commence no later than five years after the Participant's termination of employment. Deferred AEP Stock Units shall continue to be credited with dividends during the deferral period and the dividends shall be reinvested in additional AEP Stock Units as provided in Section 5.2. The cash payment of the deferred AEP Stock Units shall be calculated on the basis of the average of the Fair Market Value of the Common Stock for the last 20 trading days prior to the date the Participant's deferral period terminates.
ARTICLE VII
Termination of Employment
7.1 In the event of a Participant's termination of employment prior to the end of a Performance Period, but after the first six months of such Performance period, by reason of the Participant's death, Disability Retirement or involuntary termination other then for cause, the Participant will be eligible to earn prorated AEP Stock Units for each such Performance Period which has not yet ended, determined pursuant to Section 6.1 for such period and the number of days of participation during such Performance Period.
7.2 In the event a Participant's employment is terminated prior to the end of a Performance Period for reasons other than death, Disability, Retirement or involuntary termination other than for cause, all rights to any unearned AEP Stock Units under the Nuclear Performance Plan shall be forfeited.
7.3 In the event a Participant dies prior to the complete payment of the Participant's award, the amount owning to the Participant shall be paid to the Participant's spouse if the spouse is then living. If the Participant is not married at the time of death, the amount owing to the Participant shall be paid to the Participant's estate.
7.4 In the event American Electric Power Company, Inc., or the Company, or Indiana Michigan Power Company sells or otherwise disposes of the D.C. Cook Nuclear Plant and the acquirer of the D.C. Cook Nuclear Plant does not continue this Plan, the Plan shall be deemed to have terminated as of the date of the sale or disposition and the AEP Stock Units awarded and credited to the Participants as of the date of sale or disposition shall become fully vested. The value of each AEP Stock Unit shall be paid in cash to the Participants within 60 days of the date of sale or disposition assuming that as of the date of sale or disposition the Performance Measure was attained. The cash payment shall be calculated on the basis of the average of the Fair Market Value of the Common 8tock for the last 20 trading days immediately prior to the date of sale or disposition. If the acquirer of the D.C. Cook Nuclear Plant continues this Plan, American Electric Power Company, Inc., or the Company or Indiana Michigan Power Company will not be liable or obligated to make any payments under this Plan.
ARTICLE VIII
Amendment or Termination
8.1 The Committee shall have the right, authority and power to alter, amend, modify, revoke or terminate the Plan.
8.2 No amendment or termination of the Plan shall directly or indirectly deprive any current or former Participant of all or any portion of any benefits earned up to the date of the amendment or termination of the Plan.
ARTICLE IX
Change In Control
9.1 Notwithstanding any provisions of this Plan to the contrary, if a Change in Control of the Company occurs, all AEP Stock Unit grants awarded and credited to the Participants shall be deemed to be fully earned as of the date of the Change in Control. The determination of the AEP Stock Units shall be made as of the last day before the Change in Control. Payments of AEP Stock Units shall be made in cash within three months after the Change in Control. The cash payment shall be calculated on the basis of the average of the Fair Market Value of the Common Stock for the last 20 trading days immediately proceeding the date of the Change In Control.
9.2 For purposes of this Article IX, the term "Company" shall mean the American Electric Power Company, Inc., a New York corporation and it's subsidiaries. All references to the term Company in other Articles of this Plan shall have the meaning as provided in Article II(e).
9.3 A "Change in Control" of the Company shall be deemed to have occurred if (a) any "person" or "group" (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934 ("Exchange Act")), other than a trustee or other fiduciary holding securities under an employee benefit plan of the Company, becomes the "beneficial owner" (as defined in Rule l3d-3 under the Exchange Act), directly or indirectly, of more than 25 percent of the then outstanding voting stock of the Company; (b)during any period of two consecutive years, individuals who at the beginning of such period constitute the Board, together with any new Directors whose election or nomination for election was approved by a vote of at least two-thirds of the Directors then still in office who were either Directors at the beginning of the period or whose election or nomination for election was previously so approved; cease for any reason to constitute at least a majority of the Board; or (e) the Company's shareholders approve a merger or consolidation of the Company with any other corporation, other than a merger or consolidation which would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 75 percent of the total voting power represented by the voting securities of the Company or such surviving entity outstanding immediately after such merger or consolidation; or (d) the shareholders of the Company approve a plan of complete liquidation of the Company, or an agreement for the date or disposition by the Company (in one transaction or a series of transactions) of all or substantially all of the Company's assets.
Notwithstanding the foregoing, a Change in Control shall not be deemed to occur as a result of any event described in (a) or (c) above, if Directors who were a majority of the members of the Board prior to such event and who continue to serve as Directors after such event determine that the event shall not constitute a Change in Control
For purposes of this Section 9.3, "Board" shall mean the Board of Directors of American Electric Power Company, Inc. and `"Directors" shall mean an individual who is a member of the Board.
ARTICLE X
Miscellaneous
10.1 Nothing in this Plan shall interfere with or limit in any way the right of the Company to terminate any Participant's employment at any time, nor confer upon a Participant any right to continue in the employ of the Company.
10.2 In the event the Committee shall find that a Participant is unable to care for his or her affairs because of illness or accident, the Committee may direct that any payment due the Participant be paid to the duly appointed legal representative of the Participant, and any such payment so made shall be a complete discharge of the liabilities of the Plan.
10.3 The Plan shall be construed and administered according to the laws of the State of Ohio.
EXHIBIT 10(s)
NUCLEAR KEY CONTRIBUTOR
RETENTION PLAN
ARTICLE I
Establishment and Purpose
1.1 The Company hereby establishes the Nuclear Key Contributor Retention Plan effective as of May 1, 2000.
1.2 The purpose of the Nuclear Key Contributor Retention Plan is to retain the services of key employees who are very important to the ongoing performance of the Company and of the D. C. Cook Nuclear Plant.
ARTICLE II
Definitions
As used herein the following words and phrases shall have the following respective meanings unless the context clearly indicates otherwise.
(a) "Account" means the separate memo account established by the Company for each Participant.
(b) "Award Letter" means a letter setting forth the terms and conditions applicable to the establishment of a Participant's Account which shall include, but shall not be limited to, the amount credited to a Participant's Account and the time period over which the amount credited to the Account shall vest.
(c) "Cause" means and shall include, but is not limited to, the Participant's theft or destruction of Company property, the Participant's willful breach or habitual neglect of the duties that the Participant is required to perform, or the Participant's behavior or actions which are illegal and or unethical.
(d) "Committee" means the individuals holding the following offices within the Company; Chairman of the Board, President and Chief Executive Officer; Executive Vice President-Financial Services; Executive Vice President-Corporate Services; and Senior Vice President-Human Resources.
(e) "Company" means, except as provided in Article 11, the American Electric Power Service Corporation, a New York corporation, and any of its subsidiaries and affiliates.
(f) "Comparable Job" means a job at the same pay grade with the same or equivalent level of responsibility.
(g) "Disability" means a total and permanent disability as defined in the American Electric Power System Retirement Plan as amended from time to time.
(h) "Fund" means the investment options made available to participants in the Supplemental Savings Plan.
(i) "Investment Income" means with respect to a Participant's Account the earnings, gains and losses derived from the investment of the amount credited to a Participant's Account in a Fund or Funds.
(j) "Participant" means any full-time employee of the Company, who has been selected to participate in the Plan.
(k) "Plan" means the Nuclear Key Contributor Retention Plan.
(l) "Retirement" means a termination of employment after the Participant attains age 55 and has completed five years of service.
(m) "Supplemental Savings Plan" means the American Electric Power System Supplemental Savings Plan, a non-qualified deferred compensation plan sponsored by the Company, as amended from time to time.
ARTICLE III
Administration
3.1 The Committee shall administer the Plan. The Committee shall have the authority to interpret the Plan and to prescribe, amend and rescind rules and regulations relating to the administration of the Plan, and all such interpretation, rules and regulation shall be conclusive and binding on all Participants.
3.2 The Committee may employ agents, attorneys, accountants, or other persons and allocate or delegate to them powers, rights, and duties all as the Committee may consider necessary or advisable to properly carry out the administration of the Plan.
ARTICLE IV
Eligibility and Participation
4.1 Eligibility for participation in the Plan shall be limited to employees who, in the opinion of the Committee, have the capacity for contributing in a substantial measure to the successful performance of the D.C. Cook Nuclear Plant. At the sole discretion of the Committee an employee may become a Participant in the Plan on or after May 1, 2000.
4.2 The Committee shall determine the amount to be credited to a Participant's Account and the credited amount shall be specified in the Participant's Award Letter. As soon as practicable following a Participant's selection, the Committee shall provide the Participant with an Award Letter.
ARTICLE V
Investment of Credited Amounts
5.1 The initial contribution by the Company to a Participant's Account shall be invested in the AEP Fixed Income Fund and shall remain in that Fund until such time that the Participant elects to invest the initial contribution in a different Fund or Funds. The Participant may change the selected Funds by notifying the Company or the recordkeeper retained by the Company. Any change in the Funds selected by the Participant shall be implemented as soon as practicable.
5.2 A Participant may elect to transfer all or a portion of the amount credited to the Participant's Account from any Fund or Funds to any other Fund or Funds by giving notice to the Company or the recordkeeper retained by the Company. Transfers between Funds may be made in any whole percentage or dollar amounts and shall be implemented as soon as possible.
5.3 The Funds shall be valued daily at their fair market value and each Participant's Account shall be valued daily at its fair market value. The fair market value calculation for a Participant's Account shall be made after all Investment Income and Fund transfers for the day are recorded.
5.4 If a Participant receives a payment of a portion of the amount credited to the Participant's Account in accordance with sections 7.1 or 7.2, the payment shall be taken pro-rata from the Funds the Participant's Account is then invested in.
5.4 The Plan is an unfunded non-qualified deferred compensation plan and therefore the amounts credited to a Participant's Account and the Participant's investment of the credited amounts in the Fund or Funds selected by the Participant are memo accounts that represent general, unsecured liabilities of the Company payable exclusively out of the general assets of the Company.
ARTICLE VI
Vesting
6.1 Except as provided in Section 6.2, a Participant's Account shall vest after a set term as specified in the Award Letter. A Participant will forfeit any unvested portion of the Participant's Account if the Participant voluntary resigns before Retirement or Disability or if the Participant is terminated for Cause.
6.2 The portion of the Participant's Account that is not vested in accordance with Section 6.1 shall become fully vested:
(a) Upon the Retirement of the Participant,
(b) Upon the Participant's Disability,
(c) If the Company ceases or restructures its nuclear operations and the Participant's position with the Company is terminated, or
(d) If there is a change in control of the Company's nuclear operations such that the Company does not have primary management or operation responsibility for the D.C. Cook Nuclear Plant, or
(e) If the Company is part of a consortium or joint venture the purpose of which is to operate several nuclear electric generation plants and the Company does not have a controlling interest in the consortium or joint venture, and
(f) If as a result of a transaction described in (c), (b) or (d) the Participant's position is terminated and the Company does not offer a Comparable Job to the Participant.
ARTICLE VII
Determination and Payment
7.1 The Participant shall receive a lump sum cash distribution of the
vested portion of the Participant's Account within ten days after the vesting
date specified in the Award Letter, unless the Participant elects to defer
payment of the vested portion of the Participant's Account as provided in
Section 7.2. The lump sum cash payment shall be calculated on the basis of the
market value of the Fund or Funds the Participant's Account is invested in as of
the day the Participant's Account becomes vested.
7.2 Within sixty days of becoming a Participant, a Participant may make an election to defer the cash payment of the amounts credited in the Account as they become vested. The vested amounts may be deferred for one or more years. However, if the Participant's deferral period extends beyond the Participant's Retirement date, the payment of the deferred amounts must commence no later than one year after the Participant's date of Retirement. Upon the expiration of the deferral period, the deferred amounts shall be paid in a lump sum or over a period of years, not to exceed ten years, as elected by the Participant. The deferred amounts shall continue to be invested in the Fund or Funds as selected by the Participant as provided in Article V. The cash payment of the deferred amounts shall be calculated on the basis of the market value of the Fund or Funds the deferred amounts are invested in as of the date the deferred amounts are to be paid to the Participant.
7.3 If a Participant voluntarily terminates employment with the Company prior to Retirement or Disability or if the Participant's employment with the Company is terminated for Cause, any election the Participant may have made pursuant to Section 7.2 shall be null and void. Upon a voluntary termination or a termination for cause, the vested portion of the Participant's account shall be paid as a lump sum within 10 days of the Participant's termination.
ARTICLE VIII
Death
8.1 In the event a Participant dies prior to the complete payment of the Participant's vested Account, the amount owning to the Participant shall be paid to the Participant's spouse if the spouse is then living. If the Participant is not married at the time of death, the amount owing to the Participant shall be paid to the Participant's estate.
Article IX
Taxes and Tax Treatment
9.1 The Company shall withhold federal, state and local income taxes, Social Security taxes and Medicare Taxes from any distribution hereunder to the extent that such taxes are then payable.
ARTICLE X
Amendment or Termination
10.1 The Committee shall have the right, authority and power to alter, amend, modify, revoke or terminate the Plan.
10.2 No amendment or termination of the Plan shall directly or indirectly deprive any current or former Participant of all or any portion of any benefits earned up to the date of the amendment or termination of the Plan.
ARTICLE XI
Change in Control
11.1 Notwithstanding any provisions of this Plan to the contrary, if a Change in Control of the Company occurs, all amounts credited to a Participant's Account and not then vested shall be deemed to be fully vested as of the date of the Change in Control. Payment of the amount credited to the Participant's Account shall be made in cash within three months after the Change in Control. The cash payment shall be calculated on the basis of the fair market value of the Funds the Participant's Account is invested in as of the date of the Change in Control.
11.2 For purpose of this Article XI, the term "Company" shall mean the American Electric Power Company, Inc., a New York corporation and it's subsidiaries. All references to the term Company in other Articles of this Plan shall have the meaning as provided in Article II (e).
11.3 A "Change in Control" of the Company shall be deemed to have occurred
if (a) any "person" or "group" (as such terms are used in Sections 13(d) and
14(d) of the Securities Exchange Act of 1934 ("Exchange Act")), other than a
trustee or other fiduciary holding securities under an employee benefit plan of
the Company, becomes the "beneficial owner" (as defined in Rule 13d-3 under the
Exchange Act), directly or indirectly, or more than 25 percent of the then
outstanding voting stock of the Company; (b) during any period of two
consecutive years, individuals who at the beginning of such period constitute
the Board, together with any new Directors whose election or nomination for
election was approved by a vote of at least two-thirds of the Directors then
still in office who were either Directors at the beginning of the period or
whose election or nomination for election was previously so approved, cease for
any reason to constitute at least a majority of the Board; or (c) the Company's
shareholders approve a merger or consolidation of the Company with any other
corporation, other than a merger or consolidation which would result in the
voting securities of the Company outstanding immediately prior thereto
continuing to represent (either by remaining outstanding or by being converted
into voting securities of the surviving entity) at least 75 percent of the total
voting power represented by the voting securities of the Company or such
surviving entity outstanding immediately after such merger or consolidation; or
(d) the shareholders of the Company approve a plan of complete liquidation of
the Company, or an agreement for the date or disposition by the Company (in one
transaction or a series of transactions) of all or substantially all of the
Company's assets.
Notwithstanding the foregoing, a Change in Control shall not be deemed to occur as a result of any event described in (a) or (c) above, if Directors who were a majority of the members of the Board prior to such event and who continue to serve as Directors after such event determine that the event shall not constitute a Change in Control.
For purposes of this Section 11.3, "Board" shall mean the Board of Directors of American Electric Power Company, Inc. and "Director" shall mean an individual who is a member of the Board.
ARTICLE XII
Miscellaneous
12.1 Nothing in this Plan shall interfere with or limit in any way the right of the Company to terminate any Participant's employment at any time, nor confer upon a Participant any right to continue in the employ of the Company.
12.2 In the event the Committee shall find that a Participant is unable to care for his or her affairs because of illness or accident, the Committee may direct that any payment due the Participant be paid to the duly appointed legal representative of the Participant, and any such payment so made shall be a complete discharge of the liabilities of the Plan.
12.3 The Plan shall be construed and administered according to the laws of the State of Ohio.
EXHIBIT 12
AMERICAN ELECTRIC POWER COMPANY, INC.
Computation of Consolidated Ratio of Earnings to Fixed Charges
(in millions except ratio data)
Year Ended December 31,
1998 1999 2000 2001 2002
Fixed Charges:
Interest on Long-term Debt . . . . . . . . . . . . $ 569 $ 618 $ 618 $ 605 $ 642
Interest on Short-term Debt. . . . . . . . . . . . 134 149 259 148 67
Miscellaneous Interest Charges . . . . . . . . . . 77 77 161 132 106
Estimated Interest Element in Lease Rentals. . . . 222 212 223 222 229
Preferred Stock Dividends. . . . . . . . . . . . . 29 28 32 15 84
Total Fixed Charges. . . . . . . . . . . . . $1,031 $1,084 $1,293 $1,122 $1,128
Earnings:
Income Before Income Taxes . . . . . . . . . . . . $1,357 $1,333 $ 782 $1,463 $ 235
Plus Fixed Charges (as above). . . . . . . . . . . 1,031 1,084 1,293 1,122 1,128
Less Undistributed Earnings in Equity Investments. 42 46 46 28 12
Total Earnings. . . . . . . . . . . . . . . . $2,346 $2,371 $2,029 $2,557 $1,351
Ratio of Earnings to Fixed Charges . . . . . . . . . 2.27 2.18 1.56 2.27 1.19
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2002 Annual Reports
American Electric Power Company, Inc. AEP Generating Company AEP Texas Central Company AEP Texas North Company Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company
Audited Financial Statements and Management's Discussion and Analysis
Contents
Page
Glossary of Terms i
Forward Looking Information iv
AEP Common Stock and Dividend Information v
American Electric Power Company, Inc. and Subsidiary Companies
Selected Consolidated Financial Data A-1
Management's Discussion and Analysis of Results of Operations A-2
Consolidated Statements of Operations A-12
Consolidated Balance Sheets A-13
Consolidated Statements of Cash Flows A-15
Consolidated Statements of Common Shareholders' Equity and
Comprehensive Income A-16
Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries A-17
Schedule of Consolidated Long-term Debt of Subsidiaries A-18
Index to Combined Notes to Consolidated Financial Statements A-19
Independent Auditors' Report A-20
Management's Responsibility A-21
AEP Generating Company
Selected Financial Data B-1
Management's Narrative Analysis of Results of Operations B-2
Statements of Income and Statements of Retained Earnings B-3
Balance Sheets B-4
Statements of Cash Flows B-6
Statements of Capitalization B-7
Index to Combined Notes to Financial Statements B-8
Independent Auditors' Report B-9
AEP Texas Central Company and Subsidiaries
Selected Consolidated Financial Data C-1
Management's Discussion and Analysis of Results of Operations C-2
Consolidated Statements of Income and Consolidated Statements of
Comprehensive Income C-6
Consolidated Statements of Retained Earnings C-7
Consolidated Balance Sheets C-8
Consolidated Statements of Cash Flows C-10
Consolidated Statements of Capitalization C-11
Schedule of Long-term Debt C-12
Index to Combined Notes to Consolidated Financial Statements C-13
Independent Auditors' Report C-14
AEP Texas North Company
Selected Financial Data D-1
Management's Narrative Analysis of Results of Operations D-2
Statements of Operations and Statements of Comprehensive Income D-6
Statements of Retained Earnings D-7
Balance Sheets D-8
Statements of Cash Flows D-10
Statements of Capitalization D-11
Schedule of Long-term Debt D-12
Index to Combined Notes to Financial Statements D-13
Independent Auditors' Report D-14
Appalachian Power Company and Subsidiaries
Selected Consolidated Financial Data E-1
Management's Discussion and Analysis of Results of Operations E-2
Consolidated Statements of Income and Consolidated Statements of
Comprehensive Income E-7
Consolidated Statements of Retained Earnings E-8
Consolidated Balance Sheets E-9
Consolidated Statements of Cash Flows E-11
Consolidated Statements of Capitalization E-12
Schedule of Long-term Debt E-13
Index to Combined Notes to Consolidated Financial Statements E-14
Independent Auditors' Report E-15
Columbus Southern Power Company and Subsidiaries
Selected Consolidated Financial Data F-1
Management's Narrative Analysis of Results of Operations F-2
Consolidated Statements of Income and
Consolidated Statements of Comprehensive Income F-6
Consolidated Statements of Retained Earnings F-7
Consolidated Balance Sheets F-8
Consolidated Statements of Cash Flows F-10
Consolidated Statements of Capitalization F-11
Schedule of Long-term Debt F-12
Index to Combined Notes to Consolidated Financial Statements F-13
Independent Auditors' Report F-14
Indiana Michigan Power Company and Subsidiaries
Selected Consolidated Financial Data G-1
Management's Discussion and Analysis of Results of Operations G-2
Consolidated Statements of Income and Consolidated Statements of
Comprehensive Income G-7
Consolidated Statements of Retained Earnings G-8
Consolidated Balance Sheets G-9
Consolidated Statements of Cash Flows G-11
Consolidated Statements of Capitalization G-12
Schedule of Long-term Debt G-13
Index to Combined Notes to Consolidated Financial Statements G-14
Independent Auditors' Report G-15
Kentucky Power Company
Selected Financial Data H-1
Management's Narrative Analysis of Results of Operations H-2
Statements of Income, Statements of Comprehensive Income
and Statements of Retained Earnings H-6
Balance Sheets H-7
Statements of Cash Flows H-9
Statements of Capitalization H-10
Schedule of Long-term Debt H-11
Index to Combined Notes to Financial Statements H-12
Independent Auditors' Report H-13
Ohio Power Company
Selected Financial Data I-1
Management's Discussion and Analysis of Results of Operations I-2
Statements of Income and Statements of Comprehensive Income I-7
Statements of Retained Earnings I-8
Balance Sheets I-9
Statements of Cash Flows I-11
Statements of Capitalization I-12
Schedule of Long-term Debt I-13
Index to Combined Notes to Financial Statements I-14
Independent Auditors' Report I-15
Public Service Company of Oklahoma and Subsidiary
Selected Consolidated Financial Data J-1
Management's Narrative Analysis of Results of Operations J-2
Consolidated Statements of Income and
Consolidated Statements of Comprehensive Income J-5
Consolidated Statements of Retained Earnings J-6
Consolidated Balance Sheets J-7
Consolidated Statements of Cash Flows J-9
Consolidated Statements of Capitalization J-10
Schedule of Long-term Debt J-11
Index to Combined Notes to Consolidated Financial Statements J-12
Independent Auditors' Report J-13
Southwestern Electric Power Company and Subsidiaries
Selected Consolidated Financial Data K-1
Management's Discussion and Analysis of Results of Operations K-2
Consolidated Statements of Income and
Consolidated Statements of Comprehensive Income K-6
Consolidated Statements of Retained Earnings K-7
Consolidated Balance Sheets K-8
Consolidated Statements of Cash Flows K-10
Consolidated Statements of Capitalization K-11
Schedule of Long-term Debt K-12
Index to Combined Notes to Consolidated Financial Statements K-13
Independent Auditors' Report K-14
Combined Notes to Financial Statements L-1
Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters M-1
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GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this report,
they have the meanings indicated below.
Term Meaning
2004 True-up Proceeding............A filing to be made after January 10, 2004 under the Texas Legislation to finalize the amount
of stranded costs and the recovery of such costs.
AEGCo..............................AEP Generating Company, an electric utility subsidiary of AEP.
AEP................................American Electric Power Company, Inc.
AEP Consolidated...................AEP and its majority owned consolidated subsidiaries.
AEP Credit.........................AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility
revenues for affiliated and non-affiliated domestic electric utility companies.
AEP East companies.................APCo, CSPCo, I&M, KPCo and OPCo.
AEPR...............................AEP Resources, Inc.
AEP System or the System...........The American Electric Power System, an integrated electric utility system, owned and operated
by AEP's electric utility subsidiaries.
AEPSC..............................American Electric Power Service Corporation, a service subsidiary providing management and
professional services to AEP and its subsidiaries.
AEP Power Pool.....................AEP System Power Pool. Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the
generation, cost of generation and resultant wholesale system sales of the member
companies.
AEP West companies.................PSO, SWEPCo, TCC and TNC.
AFUDC..............................Allowance for funds used during construction, a noncash nonoperating income item that is
capitalized and recovered through depreciation over the service life of domestic
regulated electric utility plant.
Alliance RTO.......................Alliance Regional Transmission Organization, an ISO formed by AEP and four unaffiliated
utilities (the FERC overturned earlier approvals of this RTO in December 2001).
Amos Plant.........................John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and OPCo.
APCo...............................Appalachian Power Company, an AEP electric utility subsidiary.
Arkansas Commission................Arkansas Public Service Commission.
Buckeye............................Buckeye Power, Inc., an unaffiliated corporation.
CLECO..............................Central Louisiana Electric Company, Inc., an unaffiliated corporation.
COLI...............................Corporate owned life insurance program.
Cook Plant.........................The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CPL................................Central Power and Light Company [legal name changed to AEP Texas Central
Company (TCC) effective December 2002]. See TCC.
CSPCo..............................Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW............................... Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal
name of Central and South West Corporation was changed to AEP Utilities, Inc.).
CSW Energy.........................CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants.
CSW International..................CSW International, Inc., an AEP subsidiary which invests in energy projects and entities
outside the United States.
D.C. Circuit Court.................The United States Court of Appeals for the District of Columbia Circuit.
DHMV...............................Dolet Hills Mining Venture.
DOE................................United States Department of Energy.
ECOM...............................Excess Cost Over Market.
ENEC...............................Expanded Net Energy Costs.
EITF...............................The Financial Accounting Standards Board's Emerging Issues Task Force.
ERCOT..............................The Electric Reliability Council of Texas.
EWGs...............................Exempt Wholesale Generators.
FASB...............................Financial Accounting Standards Board.
Federal EPA........................United States Environmental Protection Agency.
FERC...............................Federal Energy Regulatory Commission.
FMB ...............................First Mortgage Bond.
FUCOs..............................Foreign Utility Companies.
GAAP...............................Generally Accepted Accounting Principles.
I&M................................Indiana Michigan Power Company, an AEP electric utility subsidiary.
ICR................................Interchange Cost Reconstruction.
IPC................................Installment Purchase Contract.
IRS................................Internal Revenue Service.
IURC...............................Indiana Utility Regulatory Commission.
ISO................................Independent System Operator.
Joint Stipulation..................Joint Stipulation and Agreement for Settlement of APCo's WV rate proceeding.
KPCo...............................Kentucky Power Company, an AEP electric utility subsidiary.
KPSC...............................Kentucky Public Service Commission.
KWH................................Kilowatthour.
LIG................................Louisiana Intrastate Gas.
Michigan Legislation...............The Customer Choice and Electricity Reliability Act, a Michigan law which provides for
customer choice of electricity supplier.
MISO...............................Midwest Independent System Operator (an independent operator of transmission assets in the
Midwest).
MLR................................Member Load Ratio, the method used to allocate AEP Power Pool transactions to its members.
Money Pool.........................AEP System's Money Pool.
MPSC...............................Michigan Public Service Commission.
MTM................................Mark-to-Market.
MTN................................Medium Term Notes.
MW.................................Megawatt.
MWH................................Megawatthour.
NEIL...............................Nuclear Electric Insurance Limited.
NOx................................Nitrogen oxide.
NOx Rule...........................A final rule issued by Federal EPA which requires NOx reductions in 22 eastern states including
seven of the states in which AEP companies operate.
NP.................................Notes Payable.
NRC................................Nuclear Regulatory Commission.
Ohio Act...........................The Ohio Electric Restructuring Act of 1999.
Ohio EPA...........................Ohio Environmental Protection Agency.
OPCo.............................. Ohio Power Company, an AEP electric utility subsidiary.
OVEC...............................Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo own a
44.2% equity interest.
PCBs...............................Polychlorinated Biphenyls.
PJM................................Pennsylvania - New Jersey - Maryland regional transmission organization.
PRP.............................. Potentially Responsible Party.
PSO................................Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO...............................The Public Utilities Commission of Ohio.
PUCT...............................The Public Utility Commission of Texas.
PUHCA..............................Public Utility Holding Company Act of 1935, as amended.
PURPA..............................The Public Utility Regulatory Policies Act of 1978.
RCRA...............................Resource Conservation and Recovery Act of 1976, as amended.
Registrant Subsidiaries............AEP subsidiaries who are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo,
TCC and TNC.
REP................................Retail Electric Provider.
Rockport Plant.....................A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport,
Indiana owned by AEGCo and I&M.
RTO................................Regional Transmission Organization.
SEC................................Securities and Exchange Commission.
SFAS...............................Statement of Financial Accounting Standards issued by the Financial Accounting Standards
Board.
SFAS 71............................Statement of Financial Accounting Standards No. 71,
Accounting for the Effects of Certain Types of Regulation.
---------------------------------------------------------
SFAS 101...........................Statement of Financial Accounting Standards No. 101,
Accounting for the Discontinuance of Application of Statement 71.
----------------------------------------------------------------
SFAS 133...........................Statement of Financial Accounting Standards No. 133,
Accounting for Derivative Instruments and Hedging Activities.
------------------------------------------------------------
SNF................................Spent Nuclear Fuel.
SPP................................Southwest Power Pool.
STP................................South Texas Project Nuclear Generating Plant, owned 25.2% by AEP Texas Central Company, an
AEP electric utility subsidiary.
STPNOC.............................STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of
its joint owners including TCC.
Superfund......................... The Comprehensive Environmental, Response, Compensation and Liability Act.
SWEPCo.............................Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC................................AEP Texas Central Company, an AEP electric utility subsidiary [formerly known as Central
Power and Light Company (CPL)].
Texas Appeals Court................The Third District of Texas Court of Appeals.
Texas Legislation..................Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC................................AEP Texas North Company, an AEP electric utility subsidiary [formerly known as West Texas
Utilities Company (WTU)].
Travis District Court..............State District Court of Travis County, Texas.
TVA ...............................Tennessee Valley Authority.
U.K................................The United Kingdom.
UN.................................Unsecured Note.
VaR................................Value at Risk, a method to quantify risk exposure.
Virginia SCC.......................Virginia State Corporation Commission.
WV.................................West Virginia.
WVPSC..............................Public Service Commission of West Virginia.
WPCo...............................Wheeling Power Company, an AEP electric distribution subsidiary.
WTU................................West Texas Utilities Company [legal name changed to AEP Texas North Company (TNC) effective
December 2002]. See TNC.
Yorkshire..........................Yorkshire Electricity Group plc, a U.K. regional electricity company owned jointly by AEP and
New Century Energies until April 2001.
Zimmer Plant.......................William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by Columbus
Southern Power Company, an AEP subsidiary.
|
FORWARD LOOKING INFORMATION
These reports made by AEP and its registrant subsidiaries contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and its registrant subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:
o Electric load and customer growth.
o 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 our service
territories.
o The ability to recover stranded costs in connection with
possible/proposed deregulation.
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 our 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 our transmission and distribution service territory.
o Other risks and unforeseen events, including wars, the effects of
terrorism, embargoes and other catastrophic events.
AEP Common Stock and Dividend Information
The quarterly high and low sales prices and the quarter-end closing price for
AEP common stock and the cash dividends paid per share are shown in the
following table:
Quarter-end
Quarter Ended High Low Closing Price Dividend
------------- ------ ------- ------------- --------
March 2002 $47.08 $39.70 $46.09 $0.60
June 2002 48.80 39.00 40.02 0.60
September 2002 40.37 22.74 28.51 0.60
December 2002 30.55 15.10 27.33 0.60
March 2001 $48.10 $39.25 $47.00 $0.60
June 2001 51.20 45.10 46.17 0.60
September 2001 48.90 41.50 43.23 0.60
December 2001 46.95 39.70 43.53 0.60
AEP common stock is traded principally on the New York Stock Exchange. At
December 31, 2002, AEP had approximately 144,000 shareholders of record. In 2003
management recommended that the Company reduce dividends by approximately 40%
after payment of the March 2003 dividend which was approved by the Company's
Board of Directors at the current level of $0.60 per share.
|
AMERICAN ELECTRIC POWER COMPANY, INC.
AND SUBSIDIARY COMPANIES
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Selected Consolidated Financial Data
Year Ended December 31, 2002 2001 2000 1999 1998
----------------------- ---- ---- ---- ---- ----
OPERATIONS STATEMENTS DATA (in millions):
Total Revenues $14,555 $12,767 $11,113 $10,019 $14,080
Operating Income 1,263 2,182 1,774 2,061 2,046
Income Before Discontinued Operations, Extraordinary
Items and Cumulative Effect 21 917 180 869 859
Discontinued Operations Income (Loss) (190) 86 122 117 116
Extraordinary Losses - (50) (35) (14) -
Cumulative Effect of
Accounting Change Gain (Loss) (350) 18 - - -
Net Income (Loss) (519) 971 267 972 975
December 31, 2002 2001 2000 1999 1998
------------ ---- ---- ---- ---- ----
BALANCE SHEET DATA (in millions):
Property, Plant and Equipment $37,857 $37,414 $34,895 $33,930 $32,400
Accumulated Depreciation
and Amortization 16,173 15,310 14,899 14,266 13,374
------- ------- ------- ------- -------
Net Property,
Plant and Equipment $21,684 $22,104 $19,996 $19,664 $19,026
======= ======= ======= ======= =======
Total Assets $34,741 $39,297 $46,633 $35,296 $33,418
Common Shareholders' Equity 7,064 8,229 8,054 8,673 8,452
Cumulative Preferred Stocks
of Subsidiaries* 145 156 161 182 350
Trust Preferred Securities 321 321 334 335 335
Long-term Debt* 10,496 9,505 8,980 9,471 9,215
Obligations Under Capital Leases* 228 451 614 610 539
Year Ended December 31, 2002 2001 2000 1999 1998
----------------------- ---- ---- ---- ---- ----
COMMON STOCK DATA:
Earnings per Common Share:
Before Discontinued Operations, Extraordinary
Items and Cumulative Effect $ 0.06 $ 2.85 $ 0.56 $ 2.71 $2.70
Discontinued Operations (0.57) 0.26 0.38 0.36 0.36
Extraordinary Losses - (0.16) (0.11) (0.04) -
Cumulative Effect of
Accounting Change (1.06) 0.06 - - -
------- ------ ------ ------ -----
Earnings (Loss) Per Share $ (1.57) $ 3.01 $ 0.83 $ 3.03 $3.06
======= ====== ====== ====== =====
Average Number of Shares
Outstanding (in millions) 332 322 322 321 318
Market Price Range:
High $ 48.80 $51.20 $48-15/16 $48-3/16 $53-5/16
Low 15.10 39.25 25-15/16 30-9/16 42-1/16
Year-end Market Price 27.33 43.53 46-1/2 32-1/8 47-1/16
Cash Dividends on Common** $ 2.40 $2.40 $2.40 $2.40 $2.40
Dividend Payout Ratio** (152.9)% 79.7% 289.2% 79.2% 78.4%
Book Value per Share $20.85 $25.54 $25.01 $26.96 $26.46
*Including portion due within one year. Long-term Debt includes Equity Unit Senior Notes.
**Based on AEP historical dividend rate. See "Common Stock and Dividend
Information" (on page V) regarding the potential reduction of future dividends.
|
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Management's Discussion and Analysis of Results of Operations
American Electric Power Company, Inc. (AEP or the Company) is one of the largest investor owned electric public utility holding companies in the U.S. We provide generation, transmission and distribution service to almost five million retail customers in eleven states (Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia) through our electric utility operating companies.
We have a vast portfolio of assets including:
o 38,000 megawatts of generating capacity, the largest complement
of generation in the U.S., the majority of which has a
significant cost advantage in our market areas
o 4,000 megawatts of generating capacity in the U.K., a country which is
currently experiencing excess generation capacity
o 38,000 miles of transmission lines, the backbone of the electric
interconnection grid in the Eastern U.S.
o 186,000 miles of distribution lines that support delivery of
electricity to our customers' premises
o Substantial coal transportation assets (7,000 railcars, 1,800 barges,
37 tug boats and two coal handling terminals with 20 million tons of
annual capacity)
o 6,400 miles of gas pipelines in Louisiana and Texas with 128 Bcf of
gas storage facilities
Business Strategy
We plan to focus on utility operations in the U.S. We continue to participate in wholesale electricity and natural gas markets. Weakness in these markets after the collapse of Enron and other companies caused us to re-examine and realign our strategy to direct our attention to our utility markets. We have reduced trading to focus predominantly in markets where we have assets. We plan to obtain maximum value for our assets by selling excess output and procuring economical energy using commercial expertise gained from our extensive experience in the wholesale business.
Through our utility operations focus, we intend to be the energy and low cost generation provider of choice. We have ample generation to meet our customers' needs. We have a cost advantage resulting from AEP's long tradition of designing, building and operating efficient power plants and delivery networks. Our customers continue to show top quartile level of satisfaction. We provide safe and reliable sources of energy.
Our business provides a vital requirement of our economy and affords an opportunity for a fair return to our shareholders. Our business provides the opportunity for a predictable stream of cash flows and earnings, allowing us to pay a competitive dividend to investors.
We are addressing many challenges in our unregulated business. We have already substantially reduced our trading activities. We have written down the value of several investments to reflect deterioration in market conditions. We are evaluating our portfolio and plan to sell assets that are no longer core to our business strategy. We are also in discussion with our regulators to determine if the legal separation of certain operating company subsidiaries into regulated and unregulated segments can be avoided. We believe that the expected benefits from legal separation are no longer compelling. Transition rules for Michigan and Virginia do not require legal separation. Deregulation is no longer an expectation in the foreseeable future in the other states where we operate.
Our strategy for the core business of utility operations is to:
o Maintain moderate but steady earnings growth
o Maximize value of transmission assets and protect our revenue stream
in an RTO membership environment
o Continue process improvement to maintain distribution service quality
while, at the same time, further enhancing financial performance
o Optimize generation assets through increased availability and sale of
excess capacity
o Manage the regulatory process to maximize retention of earnings
improvement while providing fair and reasonable rates to our
customers
We remain very focused on credit quality and liquidity as discussed in greater detail later in this report.
We are committed to continually evaluating the need to reallocate resources to areas with greater potential, to match investments with our strategy and to pare investments that do not produce sufficient return and sustainable shareholder value. Any investment dispositions could affect future results of operations, cash flows and possibly financial condition.
2002 Overview
2002 was a year of rapid and dramatic change for the energy industry, including AEP, as the wholesale energy market quickly shrank and many of its participants exited or significantly limited future trading activity. Investors lost confidence in corporate America and the economy stalled. Investors' demand for stability, predictable cash flows, earnings, and financial strength have replaced their demand for rapid growth.
Our wholesale business did not perform well. We had significant losses in options trading in the first half of the year and new investments performed well below our expectations.
We focused on financial strength by:
o Issuing approximately $1 billion in common stock and equity units
o Retiring debt of approximately $3 billion through the sale of two f
oreign retail utility companies in the U.K. (SEEBOARD) and
Australia (CitiPower)
o Establishing a cash liquidity reserve of $1 billion at year-end
See Financing Activity in Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters in section M for an overview of all changes to capital structure.
We also focused on:
o Implementing an enterprise-wide risk management system
o Completing a cost reduction initiative which we expect to result in
sustainable net annual savings of more than $200 million beginning
in 2003
o Eliminating or reducing future capital requirements associated with
non-core assets
We have redirected our business strategy by:
o Scaling back trading activities to focus principally on supporting
our core assets
o Selling our Texas retail business o Proposing the sale of a significant
portion of the Texas unregulated generation assets
Outlook for 2003
We remain focused on the fundamental earnings power of our utility operations,
and we are committed to strengthening our balance sheet. Our strategy for
achieving these goals is well planned:
o First, we will continue to identify opportunities to reduce our
operations and maintenance expense.
o Second, we will find opportunities to reduce capital expenditures.
o Third, management recommended a 40% reduction in the common stock
dividend beginning in the second quarter to a quarterly rate of $0.35
per share. This will result in annual cash savings of approximately
$340 million and should improve our retained earnings as well as create
free cash flow to improve liquidity and pay-down outstanding debt.
o Fourth, we plan to evaluate and, where appropriate, dispose of non-core
assets. Proceeds from these sales will be used to reduce debt.
o Fifth, we will continue to evaluate the potential for issuing
additional equity to further strengthen our balance sheet and maintain
credit quality.
We remain committed to being a low cost provider of electricity, to serving our customers with excellence and to providing an attractive return to investors. We will therefore focus on producing the best possible results from our utility operations enhanced by a commercial group that ensures maximum value from our assets.
Although we aim for excellent results from operations there are challenges and certain risks. We discuss these matters in detail in the Notes to Financial Statements and in Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters. We will work diligently to resolve these matters by finding workable solutions that balance the interests of our customers, our employees and our investors.
Results of Operations
In 2002, AEP's principal operating business segments and their major activities
were:
o Wholesale:
o Generation of electricity for sale to retail and wholesale customers
o Gas pipeline and storage services
o Marketing and trading of electricity, gas, coal and other
commodities
o Coal mining, bulk commodity barging operations and other energy
supply related businesses
o Energy Delivery
o Domestic electricity trans-mission
o Domestic electricity distri-bution
o Other Investments
o Energy Services
Net Income
Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect decreased $896 million or 98% to $21 million in 2002 from $917 million in 2001. The Company recognized impairments on under-performing assets and recorded losses in value of $854 million (net of tax) (see Note 13). The losses in the fourth quarter 2002 were generally caused by the extended decline in domestic and international wholesale energy markets and in telecommunications. In 2002, the Company's Net Loss was $519 million or a loss of $1.57 per share including the fourth quarter losses, losses on sales of SEEBOARD and CitiPower, and a loss for transitional goodwill impairment related to SEEBOARD and CitiPower that resulted from the adoption of SFAS 142 (see Note 3).
Net Income increased in 2001 to $971 million or $3.01 per share from $267 million or $0.83 per share in 2000. The increase of $704 million or $2.18 per share was due to the growth of AEP's wholesale marketing business, increased revenues and the controlling of our operating and maintenance costs in the energy delivery business, and declining capital costs. The effect of 2000 charges for a disallowance of COLI-related tax deductions, expenses of the merger with CSW, write-offs related to non-regulated investments and restart costs of the Cook Nuclear Plant were all contributing factors to the increase in 2001 earnings compared to 2000. The favorable effect on comparative Net Income of these 2000 charges was offset in part in 2001 by losses from Enron's bankruptcy and extraordinary losses for the effects of deregulation and a loss on reacquired debt.
Our wholesale business has been affected by a slowing economy. Wholesale energy margins and energy use by industrial customers declined in 2002 and 2001. Earnings from our wholesale business, which includes generation, increased in 2001 largely as a result of the successful return to service of the Cook Plant in June 2000 and by acquisitions of HPL and MEMCO.
Our energy delivery business, which consists of domestic electricity transmission and distribution services, contributed to the increase in earnings by controlling operating and maintenance expenses and by increasing revenues in 2002 and 2001.
Capital costs decreased due primarily to interest paid to the IRS in 2000 on a COLI deduction disallowance and continuing declines in short-term market interest rate conditions since early 2001.
Volatility in energy commodities markets affects the fair values of all of our open trading and derivative contracts exposing AEP to market risk and causing our results of operations to be more volatile. See "Market Risks" section for a discussion of the policies and procedures AEP uses to manage its exposure to market and other risks from trading activities.
Revenues Increase
AEP's total revenues increased 14% in 2002 and 15% in 2001. The following table shows the components of revenues:
For The Year Ended
December 31
--------------------
2002 2001 2000
(in millions)
WHOLESALE:
Residential $ 3,713 $ 3,553 $ 3,511
Commercial 2,156 2,328 2,249
Industrial 1,903 2,388 2,444
Other Retail
Customers 385 419 414
Electricity
Marketing (net) 2,227 802 1,073
Unrealized MTM
Income-Electric 136 210 38
Other 1,397 632 837
Less: Transmission and
Distribution Revenues
Assigned to Energy
Delivery* (3,551) (3,356) (3,174)
------ ------- -------
Wholesale
Electric 8,366 6,976 7,392
------ ------- -------
Gas Marketing (net) 3,021 2,274 310
Unrealized MTM Income
(Loss)-Gas (399) 47 132
------- ------- -------
Wholesale Gas 2,622 2,321 442
------- ------- -------
TOTAL WHOLESALE 10,988 9,297 7,834
------- ------- -------
DOMESTIC ELECTRICITY
DELIVERY:
Transmission 922 1,029 1,009
Distribution 2,629 2,327 2,165
------- ------- -------
TOTAL DOMESTIC
ELECTRICITY
DELIVERY 3,551 3,356 3,174
------- ------- -------
OTHER
INVESTMENTS 16 114 105
------- ------- -------
TOTAL REVENUES $14,555 $12,767 $11,113
======= ======= =======
|
*Certain revenues in the Wholesale business include energy delivery revenues due primarily to bundled tariffs that are assignable to the Energy Delivery business.
The level of electricity transactions tends to fluctuate due to the highly competitive nature of the short-term (spot) energy market and other factors, such as affiliated and unaffiliated generating plant availability, weather conditions and the economy. The FERC's introduction of a greater degree of competition into the wholesale energy market has had a major effect on the volume of wholesale power marketing especially in the short-term market.
The increase in 2002 in wholesale revenues resulted from a 27% increase in trading volume associated with Wholesale Electricity which was offset by a continuing decrease in gross margins which began in the fourth quarter of 2001, and an increase in residential sales as a result of favorable weather conditions in the third quarter 2002. In addition Other Wholesale electric revenues increased due to the mid-year 2001 acquisition of barging and coal mining operations as well as the recognition of revenues for generation projects completed for third parties. The increase in 2002 Wholesale Gas revenues resulted from a full year of HPL operations compared to a partial year from our acquisition date in July 2001, offset by a decrease in the results from financial trading and MTM unrealized losses. Other Investments revenue decreased in 2002 due to the elimination of factoring of accounts receivable of an unaffiliated utility.
Prior to the third quarter of 2002, we recorded and reported upon settlement, sales under forward trading contracts as revenues and purchases under forward trading contracts as purchased energy expenses. Effective July 1, 2002, we reclassified such forward trading revenues and purchases on a net basis, as permitted by EITF 98-10 (see Note 1).
Kilowatthour sales to industrial customers decreased by 10% in 2002 and by 5% in 2001. This decrease was due to the economic slow down which began in late 2001. Sales to residential customers rose 5% due to weather related demand in 2002. The economic slow down reduced demand and wholesale prices especially in the latter part of 2001.
Operating Expenses Increase
Changes in the components of operating expenses were as follows:
Increase (Decrease)
From Previous Year
2002 2001
---- ----
(in millions)
Amount % Amount %
------ - ------ -
Fuel and Purchased
Energy:
Electricity $ 959 43.7 $(1,275) (36.7)
Gas 404 14.7 2,339 570.5
Maintenance and
Other Operation 303 8.2 228 6.5
Non-recoverable
Merger Costs (11) (52.4) (182) (89.7)
Asset Impairments 867 N.M. - -
Depreciation and
Amortization 134 10.8 152 13.9
Taxes Other Than
Income Taxes 51 7.6 (16) (2.3)
------ ------
Total $2,707 25.6 $1,246 13.3
====== ======
|
The increase in Fuel and Purchased Energy expense was primarily attributable to an increase in power generation. Net generation increased 6% for Eastern plants due to increased demand for electricity and a reduction in planned power plant maintenance outages for various plants as compared to 2001. The return to service of the Cook Plant's two nuclear generating units in June 2000 and December 2000 accounted for the increase in nuclear generation. The increase in Gas expense was primarily due to a full year of HPL operations compared to a partial year from our acquisition date in July 2001.
The increase in Maintenance and Other Operation expense in 2002 is primarily due to recognizing a full year's expense for the businesses acquired during 2001 including MEMCO (a barging line), Quaker Coal, two power plants in the U.K. and HPL. In addition, increased administrative costs for the implementation of customer choice in Texas contributed to the increase. The increase was offset in part by a reduction in trading incentive compensation and the effect of planned boiler plant maintenance at various plants in 2001 and less refueling outages for STP in 2002 than 2001.
Maintenance and Other Operation expense rose in 2001 mainly as a result of additional traders' incentive compensation and accruals for severance costs related to corporate restructuring.
With the consummation of the merger with CSW, certain deferred merger costs were expensed in 2000. The merger costs charged to expense included transaction and transition costs not allocable to and recoverable from ratepayers under regulatory commission approved settlement agreements to share net merger savings. As expected, merger costs declined in 2001 and 2002 after the merger was consummated.
In 2002 AEP recorded pre-tax impairments of assets (including Goodwill) and investments totaling $1.4 billion (consisting of approximately, $866.6 million related to asset impairments, $321.1 million related to investment value losses, and $238.7 million related to discontinued operations) that reflected downturns in energy trading markets, projected long-term decreases in electricity prices, and other factors. These impairments exclude the transitional impairment loss from adoption of SFAS142 (see Note 2). The categories of impairments included:
2002 Pre-Tax Estimated Loss
(in millions)
Asset Impairments
Held for Sale $ 483.1
Asset Impairments
Held and Used 651.4
Investment Value
Losses 291.9
--------
Total $1,426.4
========
|
Additional market deterioration associated with our non-core wholesale investments, including our U.K. operations, could have an adverse impact on our future results of operations and cash flows. Significant long-term changes in external market conditions could lead to additional write-offs and potential divestitures of our wholesale investments, including, but not limited to, our U.K. operations.
The rise in Depreciation and Amortization expense in 2002 resulted from the amortization of Texas generation related Regulatory Assets that were securitized in early 2002, businesses acquired in 2001 and additional production plant placed into service.
Depreciation and Amortization expense increased in 2001 primarily as a result of the commencement of amortization of transition generation regulatory assets in the Ohio, Virginia and West Virginia jurisdictions due to passage of restructuring legislation, the new businesses acquired in 2001 and additional investments in Property, Plant and Equipment.
Taxes Other Than Income Taxes increased in 2002 due to a full year of state excise taxes which replaced the state gross receipts tax in Ohio and increased local franchise taxes in Texas partly offset by the effect of Texas one-time 2001 assessments and decreased gross Texas receipts taxes due to deregulation.
Interest, Preferred Stock Dividends, Minority Interest
The decrease in Interest in 2002 was primarily due to a reduction in short-term interest rates and lower outstanding balances of short-term debt and the refinancing of long-term debt at favorable interest rates offset in part by an increased amount of long-term debt outstanding.
Interest expense decreased 15% in 2001 due to the effect of interest paid to the IRS on a COLI deduction disallowance in 2000 and lower average outstanding short-term debt balances and a decrease in average short-term interest rates.
Minority Interest in Finance Subsidiary increased substantially in 2002 because the distributions to minority interest were in effect for the entire year. In 2001 we issued a preferred member interest to finance the acquisition of HPL and paid a preferred return of $13 million to the preferred member interest. The minority interest was only in effect during the last four months of 2001.
Other Income/Other Expenses
Other Income increased by $110 million or 33% in 2002 due to the sale of AEP'S
retail electric providers in Texas and due to non-operational revenue (see Note
1). Other Expenses increased $134 million or 72% in 2002 due to non-operational
expenses (see Note 1).
Other Income increased $240 million in 2001. This increase was primarily caused by an increase in equity earnings due to acquisitions of $63 million and a $73 million gain from the sale of a generating plant (see Note 1). Other Expenses increased by $110 million or 143% in 2001 due to costs to exit air transportation, fiber optic and Datapult businesses (see Note 1).
Income Taxes
The decrease in total Income Taxes in 2002 was due to a decrease in pre-tax book income offset by the tax effects of the sale of foreign operations.
Although pre-tax book income increased considerably in 2001, Income Taxes decreased due to the effect of recording in 2000 prior year federal income taxes as a result of the disallowance of COLI interest deductions by the IRS and nondeductible merger related costs in 2000.
Extraordinary Losses and Cumulative Effect
The loss for transitional goodwill impairment related to SEEBOARD and CitiPower resulted from the adoption of SFAS 142 (see Notes 2 and 3) and has been reported as a Cumulative Effect of Accounting Change on January 1, 2002.
In 2001 we recorded an extraordinary loss of $48 million net of tax to write-off prepaid Ohio excise taxes stranded by Ohio deregulation. The application of regulatory accounting for generation was discontinued in 2000 for the Ohio, Virginia and West Virginia jurisdictions which resulted in the after-tax extraordinary loss of $35 million.
New accounting rules that became effective in 2001 regarding accounting for derivatives required us to mark-to-market certain fuel supply contracts that qualify as financial derivatives. The effect of initially adopting the new rules at July 1, 2001 was a favorable earnings effect of $18 million, net of tax, which is reported as a Cumulative Effect of Accounting Change.
Discontinued Operations
The operations shown below were discontinued or held for sale in 2002 (See Note 12). Results of operations including impairment losses, net of tax, of these businesses have been reclassified:
Company 2002 2001 2000
------- ---- ---- ----
(in millions)
SEEBOARD $ 96 $ 88 $ 99
CitiPower (123) (6) 17
Pushan (7) 4 7
Eastex (156) - (1)
----- ---- ----
$(190) $ 86 $122
===== ==== ====
|
Reclassification
Balance sheet amounts have been restated to reflect our change in accounting policy regarding certain assets and liabilities related to forward physical and financial transactions (see "Reclassification" discussion Note 1.) Based upon AEP's legal rights of offset, physical and financial contracts were netted in 2002 and 2001 amounts and financial contracts were netted in 2000 and 1999 amounts. Related assets and liabilities were not netted in 1998 amounts as the impact is not material.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Statements of Operations
-------------------------------------
(in millions - except per share amounts)
Year Ended December 31,
--------------------------
2002 2001 2000
---- ---- ----
REVENUES:
Wholesale Electricity $ 8,366 $ 6,976 $ 7,392
Wholesale Gas 2,622 2,321 442
Domestic Electricity Delivery 3,551 3,356 3,174
Other Investment 16 114 105
------- ------- -------
TOTAL REVENUES 14,555 12,767 11,113
------- ------- -------
EXPENSES:
Fuel and Purchased Energy:
Electricity 3,154 2,195 3,470
Gas 3,153 2,749 410
------- ------- -------
TOTAL FUEL AND PURCHASED ENERGY 6,307 4,944 3,880
Maintenance and Other Operation 4,013 3,710 3,482
Non-recoverable Merger Costs 10 21 203
Asset Impairments 867 - -
Depreciation and Amortization 1,377 1,243 1,091
Taxes Other Than Income Taxes 718 667 683
------- ------- -------
TOTAL EXPENSES 13,292 10,585 9,339
------- ------- -------
OPERATING INCOME 1,263 2,182 1,774
OTHER INCOME 445 335 95
LESS: INVESTMENT VALUE AND OTHER IMPAIRMENT LOSSES 321 - -
LESS: OTHER EXPENSES 321 187 77
LESS: INTEREST 785 844 999
PREFERRED STOCK DIVIDEND REQUIREMENTS OF
SUBSIDIARIES 11 10 11
MINORITY INTEREST IN FINANCE SUBSIDIARY 35 13 -
------- ------- -------
INCOME BEFORE INCOME TAXES 235 1,463 782
INCOME TAXES 214 546 602
------- ------- -------
INCOME BEFORE DISCONTINUED OPERATIONS, EXTRAORDINARY ITEMS
AND CUMULATIVE EFFECT 21 917 180
DISCONTINUED OPERATIONS (LOSS) INCOME (NET OF TAX) (190) 86 122
EXTRAORDINARY LOSSES (NET OF TAX):
DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION - (48) (35)
LOSS ON REACQUIRED DEBT - (2) -
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF TAX) (350) 18 -
------- ------- -------
NET INCOME (LOSS) $ (519) $ 971 $ 267
======= ======= =======
AVERAGE NUMBER OF SHARES OUTSTANDING 332 322 322
=== === ===
EARNINGS (LOSS) PER SHARE:
Income Before Discontinued Operations, Extraordinary Items
and Cumulative Effect of Accounting Change $ 0.06 $ 2.85 $ 0.56
Discontinued Operations (0.57) 0.26 0.38
Extraordinary Losses - (0.16) (0.11)
Cumulative Effect of Accounting Change (1.06) 0.06 -
------ ------ ------
Earnings (Loss) Per Share (Basic and Diluted) $(1.57) $ 3.01 $ 0.83
====== ====== ======
CASH DIVIDENDS PAID PER SHARE $2.40 $2.40 $2.40
===== ===== =====
See Notes to Consolidated Financial Statements beginning on page L-1.
|
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
---------------------------
(in millions - except share data)
December 31,
-----------
2002 2001
---- ----
ASSETS
CURRENT ASSETS:
Cash and Cash Equivalents $ 1,213 $ 224
Accounts Receivable:
Customers 466 343
Miscellaneous 1,394 1,365
Allowance for Uncollectible Accounts (119) (69)
Fuel, Materials and Supplies 1,166 1,037
Energy Trading and Derivative Contracts 1,046 2,125
Other 935 639
------- -------
TOTAL CURRENT ASSETS 6,101 5,664
------- -------
PROPERTY, PLANT AND EQUIPMENT:
Electric:
Production 17,031 17,054
Transmission 5,882 5,764
Distribution 9,573 9,309
Other (including gas and coal mining assets
and nuclear fuel) 3,965 4,272
Construction Work in Progress 1,406 1,015
------- -------
Total Property, Plant and Equipment 37,857 37,414
Accumulated Depreciation and Amortization 16,173 15,310
------- -------
NET PROPERTY, PLANT AND EQUIPMENT 21,684 22,104
------- -------
REGULATORY ASSETS 2,688 3,162
------- -------
SECURITIZED TRANSITION ASSETS 735 -
------- -------
INVESTMENTS IN POWER AND DISTRIBUTION PROJECTS 283 633
------- -------
ASSETS HELD FOR SALE 247 721
------- -------
ASSETS OF DISCONTINUED OPERATIONS - 3,954
------- -------
GOODWILL 396 392
------- -------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 824 795
------- -------
OTHER ASSETS 1,783 1,872
------- -------
TOTAL ASSETS $34,741 $39,297
======= =======
See Notes to Consolidated Financial Statements beginning on page L-1.
|
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
December 31,
-----------
2002 2001
---- ----
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts Payable $ 2,042 $ 1,914
Short-term Debt 3,164 4,011
Long-term Debt Due Within One Year* 1,633 1,095
Energy Trading and Derivative Contracts 1,147 1,877
Other 1,804 1,924
------- -------
TOTAL CURRENT LIABILITIES 9,790 10,821
------- -------
LONG-TERM DEBT* 8,487 8,410
------- -------
EQUITY UNIT SENIOR NOTES 376 -
------- -------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 484 603
------- -------
DEFERRED INCOME TAXES 3,916 4,500
------- -------
DEFERRED INVESTMENT TAX CREDITS 455 491
------- -------
DEFERRED CREDITS AND REGULATORY LIABILITIES 765 819
------- -------
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 185 194
------- -------
OTHER NONCURRENT LIABILITIES 1,903 1,334
------- -------
LIABILITIES HELD FOR SALE 91 87
------- -------
LIABILITIES OF DISCONTINUED OPERATIONS - 2,582
------- -------
COMMITMENTS AND CONTINGENCIES (Note 9)
CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING
SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH
SUBSIDIARIES 321 321
------- -------
MINORITY INTEREST IN FINANCE SUBSIDIARY 759 750
------- -------
CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES* 145 156
------- -------
COMMON SHAREHOLDERS' EQUITY:
Common Stock-Par Value $6.50:
2002 2001
---- ----
Shares Authorized. . . . .600,000,000 600,000,000
Shares Issued. . . . . . .347,835,212 331,234,997
(8,999,992 shares were held in treasury
at December 31, 2002 and 2001) 2,261 2,153
Paid-in Capital 3,413 2,906
Accumulated Other Comprehensive Income (Loss) (609) (126)
Retained Earnings 1,999 3,296
------- -------
TOTAL COMMON SHAREHOLDERS' EQUITY 7,064 8,229
------- -------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $34,741 $39,297
======= =======
*See Accompanying Schedules.
See Notes to Consolidated Financial Statements beginning on page L-1.
|
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Statements of Cash Flows
(in millions)
Year Ended December 31,
---------------------------
2002 2001 2000
---- ---- ----
OPERATING ACTIVITIES:
Net Income (Loss) $ (519) $ 971 $ 267
Plus: Discontinued Operations 540 (86) (122)
------ ------- ------
Net Income from Continuing Operations 21 885 145
Adjustments for Noncash Items:
Asset Impairments, Investment Value and Other Impairments 1,188 - -
Depreciation and Amortization 1,403 1,277 1,152
Deferred Investment Tax Credits (31) (29) (36)
Deferred Income Taxes (66) 157 (190)
Amortization of Operating Expenses and Carrying Charges 40 40 48
Cumulative Effect of Accounting Change - (18) -
Equity Earnings of Yorkshire Electricity Group plc - - (44)
Extraordinary Loss - 50 35
Deferred Costs Under Fuel Clause Mechanisms (31) 340 (449)
Mark-to-Market of Energy Trading Contracts 263 (257) (170)
Miscellaneous Accrued Expenses 30 (384) 217
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (152) 1,766 (1,530)
Fuel, Materials and Supplies (127) (78) 149
Accrued Revenues (283) 35 (71)
Accounts Payable 52 (478) 1,292
Taxes Accrued (216) (147) 171
Payment of Disputed Tax and Interest Related to COLI - - 319
Change in Other Assets (177) (239) (283)
Change in Other Liabilities (237) (161) 386
------ ------- -------
Net Cash Flows From Operating Activities 1,677 2,759 1,141
------ ------- -------
INVESTING ACTIVITIES:
Construction Expenditures (1,722) (1,654) (1,468)
Purchase of Gas Pipe Line - (727) -
Purchase of U.K. Generation - (943) -
Purchase of Coal Company - (101) -
Purchase of Barging Operations - (266) -
Purchase of Wind Generation - (175) -
Proceeds from Sale of Retail Electric Providers 146 - -
Proceeds from Sale of Foreign Investments 1,117 383 -
Proceeds from Sale of U.S. Generation - 265 -
Other 37 (42) (18)
------ ------- -------
Net Cash Flows Used For Investing Activities (422) (3,260) (1,486)
------ ------- -------
FINANCING ACTIVITIES:
Issuance of Common Stock 656 11 14
Issuance of Minority Interest - 744 -
Issuance of Long-term Debt 2,893 2,863 878
Issuance of Equity Unit Senior Notes 334 - -
Retirement of Cumulative Preferred Stock (10) (5) (21)
Retirement of Long-term Debt (2,514) (1,570) (1,303)
Change in Short-term Debt (net) (829) (790) 1,328
Dividends Paid on Common Stock (793) (773) (805)
Dividends on Minority Interest in Subsidiary - (5) -
------ ------- -------
Net Cash Flows From (Used for) Financing Activities (263) 475 91
------ ------- -------
Effect of Exchange Rate Changes on Cash (3) (1) 30
------ ------- -------
Net Increase (Decrease) in Cash and Cash Equivalents 989 (27) (224)
Cash and Cash Equivalents from Continuing Operations - Beginning of Period 224 251 475
------ ------- -------
Cash and Cash Equivalents from Continuing Operations - End of Period $1,213 $ 224 $ 251
====== ======= =======
Net Increase (Decrease) in Cash and Cash Equivalents from
Discontinued Operations $ (100) $ 17 $ (17)
Cash and Cash Equivalents from Discontinued Operations - Beginning of Period 108 91 108
------ ------- -------
Cash and Cash Equivalents from Discontinued Operations - End of Period $ 8 $ 108 $ 91
====== ======= =======
See Notes to Consolidated Financial Statements beginning on page L-1.
|
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Statements of Common Shareholders' Equity and Comprehensive Income
-------------------------------------------------------------------------------
(in millions)
Accumulated
Other
Common Stock Paid-In Retained Comprehensive
Shares Amount Capital Earnings Income (Loss) Total
------ ------ ------- -------- ------------- -----
DECEMBER 31, 1999 331 $2,149 $2,898 $3,630 $ (4) $8,673
Issuances - 3 11 - - 14
Cash Dividends Declared - - - (805) - (805)
Other - - 6 (2) - 4
------
7,886
Comprehensive Income:
Other Comprehensive Income, Net of Taxes
Foreign Currency Translation Adjustment - - - - (119) (119)
Reclassification Adjustment
For Loss Included in Net Income - - - - 20 20
Net Income - - - 267 267
------
Total Comprehensive Income 168
--- ------ ------ ------ ----- ------
DECEMBER 31, 2000 331 $2,152 $2,915 $3,090 $(103) $8,054
Issuances - 1 9 - - 10
Cash Dividends Declared - - - (773) - (773)
Other - - (18) 8 - (10)
------
7,281
Comprehensive Income:
Other Comprehensive Income, Net of Taxes
Foreign Currency Translation Adjustment - - - - (14) (14)
Unrealized Gain (Loss) on
Hedged Derivatives (3) (3)
Minimum Pension Liability - - - - (6) (6)
Net Income - - - 971 971
------
Total Comprehensive Income 948
--- ------ ------ ------ ----- ------
DECEMBER 31, 2001 331 $2,153 $2,906 $3,296 $(126) $8,229
Issuances 17 108 568 - - 676
Cash Dividends Declared - - - (793) - (793)
Other - - (61) 15 - (46)
------
(163)
Comprehensive Income:
Other Comprehensive Income, Net of Taxes
Foreign Currency Translation Adjustment - - - - 117 117
Unrealized Gain (Loss) on
Hedged Derivatives (13) (13)
Minimum Pension Liability - - - - (585) (585)
Unrealized Loss on Securities Available
For Sale (2) (2)
Net Income (Loss) - - - (519) (519)
------
Total Comprehensive Income (1,002)
--- ------ ------ ------ ----- ------
DECEMBER 31, 2002 348 $2,261 $3,413 $1,999 $(609) $7,064
=== ====== ====== ====== ===== ======
See Notes to Consolidated Financial Statements beginning on page L-1.
|
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries
December 31, 2002
-----------------
Call
Price per Shares Shares Amount (In
Share(a) Authorized(b) Outstanding(f) Millions)
--------------------------------------------------------------------
Not Subject to Mandatory Redemption:
4.00% - 5.00% $102-$110 1,525,903 608,150 $ 61
----
Subject to Mandatory Redemption:
5.90% - 5.92% (c) (d) 1,950,000 333,100 33
6.02% - 6-7/8% (c) $100 1,650,000 513,450 51
----
Total Subject to Mandatory
Redemptio(C)(c) 84
Total Preferred Stock $145
====
|
December 31, 2001
-----------------
Call
Price per Shares Shares Amount (In
Share(a) Authorized(b) Outstanding(f) Millions)
--------------------------------------------------------------------
Not Subject to Mandatory Redemption:
4.00% - 5.00% $102-$110 1,525,903 614,608 $ 61
----
Subject to Mandatory Redemption:
5.90% - 5.92% (c) (d) 1,950,000 333,100 33
6.02% - 6-7/8% (c) $100 1,650,000 513,450 52
7% (e) (e) 250,000 100,000 10
----
Total Subject to Mandatory
Redemption (c) 95
----
Total Preferred Stock $156
====
|
NOTES TO SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
(a) At the option of the subsidiary the shares may be redeemed at the call
price plus accrued dividends. The involuntary liquidation preference is
$100 per share for all outstanding shares.
(b) As of December 31, 2002 the subsidiaries had 13,749,202, 22,200,000 and
7,713,501 shares of $100, $25 and no par value preferred stock,
respectively, that were authorized but unissued. (c) Shares outstanding
and related amounts are stated net of applicable retirements through
sinking funds(generally at par)
and reacquisitions of shares in anticipation of future requirements. The
subsidiaries reacquired enough shares in 1997 to meet all sinking fund
requirements on certain series until 2008 and on certain series until
2009 when all remaining outstanding shares must be redeemed.
(d) Not callable prior to 2003, after that the call price is $100 per share
plus accrued dividends. (e) With sinking fund. (f) The number of shares
of preferred stock redeemed is 106,458 shares in 2002, 50,000 shares
in 2001 and 209,563 shares in 2000.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Schedule of Consolidated Long-term Debt of Subsidiaries
Weighted Average
Maturity Interest Rate Interest Rates at December 31, December 31,
-------- ----------------- ----------------------------- -----------
December 31, 2002 2002 2001 2002 2001
----------------- ---- ---- ---- ----
(in millions)
-------------
FIRST MORTGAGE BONDS (a)
2002-2004 6.87% 6.00%-7.85% 6.00%-7.85% $ 648 $ 1,246
2005-2008 6.90% 6.20%-8% 6.20%-8% 463 699
2022-2025 7.66% 6.875%-8.7% 6-7/8%-8.80% 773 850
INSTALLMENT PURCHASE CONTRACTS (b)
2002-2009 4.62% 3.75%-7.70% 1.80%-7.70% 396 446
2011-2030 5.83% 1.35%-8.20% 1.55%-8.20% 1,284 1,234
NOTES PAYABLE (c)
2002-2021 5.54% 3.732%-9.60% 4.048%-9.60% 520 217
SENIOR UNSECURED NOTES
2002-2005 5.53% 2.12%-7.45% 2.31%-7.45% 1,834 1,910
2006-2012 5.91% 4.31%-6.91% 6.125%-6.91% 2,295 1,727
2032-2038 6.64% 6.00%-7-3/8% 7.20%-7-3/8% 690 340
JUNIOR DEBENTURES
2025-2038 7.90% 7.60%-8.72% 7.60%-8.72% 205 618
SECURITIZATION BONDS
2003-2016 5.40% 3.54%-6.25% - 797 -
OTHER LONG-TERM DEBT (d) 247 258
Unamortized Discount (net) (32) (40)
------- -------
Total Long-term Debt
Outstanding 10,120 9,505
Less Portion Due Within One Year 1,633 1,095
------- -------
Long-term Portion $ 8,487 $ 8,410
======= =======
EQUITY UNIT SENIOR NOTES
2007 5.75% 5.75% - $ 376 $ -
======= =======
|
NOTES TO SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES
(a) First mortgage bonds are secured by first mortgage liens on electric property, plant and equipment.
(b) For certain series of installment purchase contracts interest rates are subject to periodic adjustment. Certain series will be purchased on demand at periodic interest-adjustment dates. Letters of credit from banks and standby bond purchase agreements support certain series.
(c) Notes payable represent outstanding promissory notes issued under term loan agreements and revolving credit agreements with a number of banks and other financial institutions. At expiration all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (
d) Other long-term debt consists of a liability along with accrued interest for disposal of spent nuclear fuel(see Note 9 of the Notes to Consolidated Financial Statements) and financing obligation under sale lease back agreements.
Long-term debt outstanding at December 31, 2002 (includes Equity Unit Senior Notes) is payable as follows:
(in millions)
2003 $ 1,633
2004 824
2005 993
2006 1,611
2007 1,081
Later Years 4,386
-------
10,528
Unamortized Discount 32
-------
Total $10,496
|
AMERICAN ELECTRIC POWER COMPANY INC. AND SUBSIDIARY COMPANIES
Index to Combined Notes to Consolidated Financial Statements
The notes listed below are combined with the notes to financial statements for AEP and its other subsidiary registrants. The combined footnotes begin on page L-1.
Combined
Footnote
Reference
---------
Significant Accounting Policies Note 1
Extraordinary Items and Cumulative Effect Note 2
Goodwill and Other Intangible Assets Note 3
Merger Note 4
Nuclear Plant Restart Note 5
Rate Matters Note 6
Effects of Regulation Note 7
Customer Choice and Industry Restructuring Note 8
Commitments and Contingencies Note 9
Guarantees Note 10
Sustained Earnings Improvement Initiative Note 11
Acquisitions, Dispositions and Discontinued Operations Note 12
Asset Impairments and Investment Value Losses Note 13
Benefit Plans Note 14
Stock-Based Compensation Note 15
Business Segments Note 16
Risk Management, Financial Instruments And Derivatives Note 17
Income Taxes Note 18
Basic and Diluted Earnings Per Share Note 19
Supplementary Information Note 20
Power and Distribution Projects Note 21
Leases Note 22
Lines of Credit and Sale of Receivables Note 23
Unaudited Quarterly Financial Information Note 24
Trust Preferred Securities Note 25
Minority Interest in Finance Subsidiary Note 26
Equity Units Note 27
Subsequent Events (Unaudited) Note 30
|
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of Directors of American Electric Power Company, Inc.:
We have audited the accompanying consolidated balance sheets of American Electric Power Company, Inc. and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of operations, cash flows and common shareholders' equity and comprehensive income, for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of American Electric Power Company, Inc. and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 3 to the consolidated financial statements, the Company adopted SFAS 142, "Goodwill and Other Intangible Assets," effective January 1, 2002.
As discussed in Note 13 to the consolidated financial statements, the Company recorded certain impairments of goodwill, long-lived assets and other investments in the fourth quarter of 2002.
/s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 |
MANAGEMENT'S RESPONSIBILITY
The management of American Electric Power Company, Inc. has prepared the financial statements and schedules herein and is responsible for the integrity and objectivity of the information and representations in this annual report, including the consolidated financial statements. These statements have been prepared in conformity with accounting principles generally accepted in the United States of America, using informed estimates where appropriate, to reflect the Company's financial condition and results of operations. The information in other sections of the annual report is consistent with these statements.
The Company's Board of Directors has oversight responsibilities for determining that management has fulfilled its obligation in the preparation of the financial statements and in the ongoing examination of the Company's established internal control structure over financial reporting. The Audit Committee, which consists solely of outside directors and which reports directly to the Board of Directors, meets regularly with management, Deloitte & Touche LLP - independent auditors and the Company's internal audit staff to discuss accounting, auditing and reporting matters. To ensure auditor independence, both Deloitte & Touche LLP and the internal audit staff have unrestricted access to the Audit Committee.
The financial statements have been audited by Deloitte & Touche LLP, whose report appears on the previous page. The auditors provide an objective, independent review as to management's discharge of its responsibilities insofar as they relate to the fairness of the Company's reported financial condition and results of operations. Their audit includes procedures believed by them to provide reasonable assurance that the financial statements are free of material misstatement and includes an evaluation of the Company's internal control structure over financial reporting.
AEP GENERATING COMPANY
AEP GENERATING COMPANY
Selected Financial Data
-----------------------
Year Ended December 31,
----------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $213,281 $227,548 $228,516 $217,189 $224,146
Operating Expenses 207,152 220,571 220,092 211,849 215,415
-------- -------- -------- -------- --------
Operating Income 6,129 6,977 8,424 5,340 8,731
Nonoperating Items, Net 3,681 3,484 3,429 3,659 3,364
Interest Charges 2,258 2,586 3,869 2,804 3,149
-------- -------- -------- -------- --------
Net Income $ 7,552 $ 7,875 $ 7,984 $ 6,195 $ 8,946
======== ======== ======== ======== ========
December 31,
-----------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $652,213 $648,254 $642,302 $640,093 $636,460
Accumulated Depreciation 358,174 337,151 315,566 295,065 277,855
-------- -------- -------- -------- --------
Net Electric Utility Plant $294,039 $311,103 $326,736 $345,028 $358,605
======== ======== ======== ======== ========
Total Assets $349,729 $361,341 $374,602 $398,640 $403,892
======== ======== ======== ======== ========
Common Stock and Paid-in Capital $ 24,434 $ 24,434 $ 24,434 $ 30,235 $ 36,235
Retained Earnings 18,163 13,761 9,722 3,673 2,770
-------- -------- -------- -------- --------
Total Common Shareholder's Equity $ 42,597 $ 38,195 $ 34,156 $ 33,908 $ 39,005
======== ======== ======== ======== ========
Long-term Debt (a) $ 44,802 $ 44,793 $ 44,808 $ 44,800 $ 44,792
======== ======== ======== ======== ========
Total Capitalization
And Liabilities $349,729 $361,341 $374,602 $398,640 $403,892
======== ======== ======== ======== ========
(a) Including portion due within one year.
|
AEP Generating Company is engaged in the generation and wholesale sale of electric power to two affiliates under long-term agreements.
Operating Revenues are derived from the sale of Rockport Plant energy and capacity to two affiliated companies, I&M and KPCo, pursuant to FERC approved long-term unit power agreements. Under the terms of its unit power agreement, I&M will purchase all of AEGCo's Rockport capacity unless it is sold to other utilities. A unit power agreement between AEGCo and KPCo expires in 2004. The KPCo unit power agreement extends until December 31, 2009 for Rockport Plant Unit 1 and until December 7, 2022 for Rockport Plant Unit 2 if AEP's restructuring settlement agreement filed with the FERC becomes operative. The unit power agreements provide for recovery of costs including a FERC approved rate of return on common equity and a return on other capital net of temporary cash investments. Under terms of the unit power agreements, AEGCo accumulates all expenses monthly and prepares the bills for its affiliates. In the month the expenses are incurred, AEGCo recognizes the billing revenues and establishes a receivable from the affiliated companies.
Results of Operations
Net Income decreased $323,000 or 4% as a result of limits on recovery of return on capital related to operating and in-service ratios of the Rockport Plant.
The decrease in Operating Revenues of $14,267,000 or 6% reflects a decrease in recoverable expenses, primarily fuel.
Operating Expenses decreased 6% as follows:
Increase
(Decrease)
(dollars in thousands) From Previous Year
--------------------- ------------------
Amount %
------ -
Fuel $(13,723) (13)
Other Operation 1,899 17
Maintenance 565 6
Depreciation 137 1
Taxes Other Than Income Taxes (976) (23)
Income Taxes (1,321) (46)
--------
Total $(13,419) (6)
========
|
The decrease in Fuel expense reflects a decrease in generation and lower average fuel costs.
Other Operation expense increased due to increased costs for employee benefits and property insurance.
The increase in Maintenance expense can be attributed to shorter duration of maintenance outages for boiler inspection and repair in 2001.
Taxes Other Than Income Taxes decreased due to a decrease in Indiana real and personal property taxes reflecting a favorable change in the law which lowered the tax for Rockport Plant.
The decrease in Income Taxes attributable to operations is primarily due to a decrease in pre-tax operating income and a change in estimate for state income tax accruals.
AEP GENERATING COMPANY
Statements of Income
--------------------
Year Ended December 31,
-----------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING REVENUES $213,281 $227,548 $228,516
-------- -------- --------
OPERATING EXPENSES:
Fuel 89,105 102,828 102,978
Rent - Rockport Plant Unit 2 68,283 68,283 68,283
Other Operation 12,924 11,025 10,295
Maintenance 9,418 8,853 9,616
Depreciation 22,560 22,423 22,162
Taxes Other Than Income Taxes 3,281 4,257 3,854
Income Taxes 1,581 2,902 2,904
-------- -------- --------
TOTAL OPERATING EXPENSES 207,152 220,571 220,092
-------- -------- --------
OPERATING INCOME 6,129 6,977 8,424
NONOPERATING INCOME 343 30 6
NONOPERATING EXPENSES 198 16 17
NONOPERATING INCOME TAX CREDITS 3,536 3,470 3,440
INTEREST CHARGES 2,258 2,586 3,869
-------- -------- --------
NET INCOME $ 7,552 $ 7,875 $ 7,984
======== ======== ========
Statements of Retained Earnings
Year Ended December 31,
----------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
RETAINED EARNINGS JANUARY 1 $13,761 $ 9,722 $3,673
NET INCOME 7,552 7,875 7,984
CASH DIVIDENDS DECLARED 3,150 3,836 1,935
------- ------- ------
RETAINED EARNINGS DECEMBER 31 $18,163 $13,761 $9,722
======= ======= ======
See Notes to Financial Statements beginning on page L-1.
|
AEP GENERATING COMPANY
Balance Sheets
--------------
December 31,
-----------------------------
2002 2001
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $637,095 $638,297
General 4,728 3,012
Construction Work in Progress 10,390 6,945
-------- --------
Total Electric Utility Plant 652,213 648,254
Accumulated Depreciation 358,174 337,151
-------- -------
NET ELECTRIC UTILITY PLANT 294,039 311,103
-------- -------
OTHER PROPERTY AND INVESTMENTS 119 119
-------- --------
CURRENT ASSETS:
Cash and Cash Equivalents - 983
Accounts Receivable:
Affiliated Companies 18,454 22,344
Miscellaneous - 147
Fuel 20,260 15,243
Materials and Supplies 4,913 4,480
Prepayments - 244
-------- --------
TOTAL CURRENT ASSETS 43,627 43,441
-------- --------
REGULATORY ASSETS 4,970 5,207
-------- --------
DEFERRED CHARGES 6,974 1,471
-------- --------
TOTAL ASSETS $349,729 $361,341
======== ========
See Notes to Financial Statements beginning on page L-1.
|
AEP GENERATING COMPANY
December 31,
-----------
2002 2001
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - Par Value $1,000:
Authorized and Outstanding - 1,000 Shares $ 1,000 $ 1,000
Paid-in Capital 23,434 23,434
Retained Earnings 18,163 13,761
-------- --------
Total Common Shareholder's Equity 42,597 38,195
Long-term Debt 44,802 44,793
-------- --------
TOTAL CAPITALIZATION 87,399 82,988
-------- --------
OTHER NONCURRENT LIABILITIES 301 76
-------- --------
CURRENT LIABILITIES:
Advances from Affiliates 28,034 32,049
Accounts Payable:
General 26 7,582
Affiliated Companies 15,907 1,654
Taxes Accrued 2,327 4,777
Rent Accrued - Rockport Plant Unit 2 4,963 4,963
Other 1,111 3,481
-------- --------
TOTAL CURRENT LIABILITIES 52,368 54,506
-------- --------
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 111,046 116,617
-------- --------
REGULATORY LIABILITIES:
Deferred Investment Tax Credits 52,943 56,304
Amounts Due to Customers for Income Taxes 16,670 22,725
-------- --------
TOTAL REGULATORY LIABILITIES 69,613 79,029
-------- --------
DEFERRED INCOME TAXES 29,002 27,975
-------- --------
DEFERRED CREDITS - 150
-------- --------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $349,729 $361,341
======== ========
See Notes to Financial Statements beginning on page L-1.
|
AEP GENERATING COMPANY
Statements of Cash Flows
------------------------
Year Ended December 31,
-------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 7,552 $ 7,875 $ 7,984
Adjustments for Noncash Items:
Depreciation 22,560 22,423 22,162
Deferred Income Taxes (5,028) (6,224) (5,842)
Deferred Investment Tax Credits (3,361) (3,414) (3,396)
Amortization of Deferred Gain on Sale and
Leaseback - Rockport Plant Unit 2 (5,571) (5,571) (5,571)
Change in Certain Current Assets and Liabilities:
Accounts Receivable 4,037 1,224 1,392
Fuel, Materials and Supplies (5,450) (4,738) 6,486
Accounts Payable 6,697 (4,597) (13,157)
Taxes Accrued (2,450) (216) 708
Other Assets (5,211) (569) 1,636
Other Liabilities (2,295) (1,244) (404)
-------- -------- --------
Net Cash Flows From Operating Activities 11,480 4,949 11,998
-------- -------- --------
INVESTING ACTIVITIES - Construction Expenditures (5,298) (6,868) (5,190)
-------- -------- --------
FINANCING ACTIVITIES:
Return of Capital to Parent Company - - (5,801)
Change in Short-term Debt (net) - - (24,700)
Change in Advances From Affiliates (net) (4,015) 3,981 28,068
Dividends Paid (3,150) (3,836) (1,935)
-------- -------- --------
Net Cash Flows From (Used For)
Financing Activities (7,165) 145 (4,368)
-------- -------- --------
Net Increase (Decrease) in Cash and Cash Equivalents (983) (1,774) 2,440
Cash and Cash Equivalents January 1 983 2,757 317
-------- -------- --------
Cash and Cash Equivalents December 31 $ - $ 983 $ 2,757
======== ======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $2,019,000, $1,509,000 and
$3,531,000 and for income taxes was $7,884,000, $8,597,000 and $6,820,000 in
2002, 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
|
AEP GENERATING COMPANY
Statements of Capitalization
----------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
COMMON STOCK EQUITY (a) $42,597 $38,195
------- -------
LONG-TERM DEBT
Installment Purchase Contracts - City of Rockport (b)
Series Due Date
1995 A, 2025 (c) 22,500 22,500
1995 B, 2025 (c) 22,500 22,500
Unamortized Discount (198) (207)
------- -------
TOTAL LONG-TERM DEBT 44,802 44,793
------- -------
TOTAL CAPITALIZATION $87,399 $82,988
======= =======
(a) In 2000, AEGCo returned capital to AEP in the amounts of $5.8 million. There
were no other material transactions affecting Common Stock and Paid-in Capital
in 2002, 2001 and 2000. (b) Installment purchase contracts were entered into in
connection with the issuance of pollution control revenue bonds by the City of
Rockport, Indiana. The terms of the installment purchase contracts require AEGCo
to pay amounts sufficient to enable the payment of interest and principal on the
related pollution control revenue bonds issued to refinance the construction
costs of pollution control facilities at the Rockport Plant.
(c) These series have an adjustable interest rate that can be a daily, weekly,
commercial paper or term rate as designated by AEGCo. Prior to July 13, 2001,
AEGCo had selected a daily rate which ranged from 0.9% to 5.6% during 2001 and
averaged 2.8% in 2001. Effective July 13, 2001, AEGCo selected a term rate of
4.05% for five years ending July 12, 2006.
See Notes to Financial Statements beginning on page L-1.
|
Combined
Footnote
Reference
---------
Significant Accounting Policies Note 1
Effects of Regulation Note 7
Commitments and Contingencies Note 9
Guarantees Note 10
Sustained Earnings Improvement Initiative Note 11
Business Segments Note 16
Risk Management, Financial Instruments and Derivatives Note 17
Income Taxes Note 18
Leases Note 22
Lines of Credit and Sale of Receivables Note 23
Unaudited Quarterly Financial Information Note 24
Related Party Transactions Note 29
|
INDEPENDENT AUDITORS' REPORT
To the Shareholder and Board of Directors of AEP Generating Company:
We have audited the accompanying balance sheets and statements of capitalization of AEP Generating Company as of December 31, 2002 and 2001, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of AEP Generating Company as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 |
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
------------------------------------
Year Ended December 31,
----------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,690,493 $1,738,837 $1,770,402 $1,482,475 $1,406,117
Operating Expenses 1,296,760 1,443,106 1,463,304 1,188,490 1,123,330
--------- --------- --------- --------- ---------
Operating Income 393,733 295,731 307,098 293,985 282,787
Nonoperating Items, Net 8,079 5,324 7,235 8,113 760
Interest Charges 125,871 116,268 124,766 114,380 122,036
------- --------- ------- ------- ---------
Income Before
Extraordinary Item 275,941 184,787 189,567 187,718 161,511
Extraordinary Loss - (2,509) - (5,517) -
--------- --------- --------- -------- ---------
Net Income 275,941 182,278 189,567 182,201 161,511
Preferred Stock
Dividend
Requirements 241 242 241 6,931 6,901
Gain (Loss) on
Reacquired Preferred
Stock 4 - - (2,763) -
--------- --------- --------- -------- --------
Earnings Applicable
To Common Stock $275,704 $182,036 $189,326 $172,507 $154,610
======== ======== ======== ======== ========
Year Ended December 31,
----------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility
Plant $5,625,736 $5,769,707 $5,592,444 $5,511,894 $5,336,191
Accumulated
Depreciation
And Amortization 2,405,492 2,446,027 2,297,189 2,247,225 2,072,686
--------- ---------- --------- --------- ---------
Net Electric Utility
Plant $3,220,244 $3,323,68 $3,295,255 $3,264,669 $3,263,505
========== ========== ========== ========== ==========
Total Assets $5,356,438 $4,893,030 $5,467,701 $4,847,857 $4,735,656
========== ========== ========== ========== ==========
Common Stock and
Paid-in Capital $187,898 $ 573,903 $573,904 $573,904 $573,904
Accumulated Other
Comprehensive
Income (Loss) (73,160) - - - -
Retained Earnings 986,396 826,197 792,219 758,894 734,387
------- ---------- ------- ------- -------
Total Common
Shareholder's Equity $1,101,134 $1,400,100 $1,366,123 $1,332,798 $1,308,291
========== ========== ========== ========== ==========
Preferred Stock $ 5,942 $ 5,952 $ 5,951 $ 5,951 $163,188
======= ========== ======= ======= ========
CPL - Obligated,
Mandatorily
Redeemable Preferred
Securities of
Subsidiary Trust
Holding Solely
Junior Subordinated
Debentures of CPL
$136,250 $ 136,250 $148,500 $150,000 $150,000
======== ========= ======== ======== ========
Long-term Debt (a) $1,438,565 $1,253,768 $1,454,559 $1,454,541 $1,350,706
========== ========== ========== ========== ==========
Total Capitalization
And Liabilities $5,356,438 $4,893,030 $5,467,701 $4,847,857 $4,735,656
========== ========== ========== ========== ==========
(a) Including portion due within one year.
|
AEP Texas Central Company (TCC), formerly known as Central Power and Light Company (CPL), is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power in southern Texas. TCC also sells electric power at wholesale to other utilities, municipalities, rural electric cooperatives and beginning in 2002 to its affiliated retail electric provider (REP) in Texas.
Wholesale power marketing activities are conducted on TCC's behalf by AEPSC. TCC, along with the other AEP electric operating subsidiaries, shares in AEP's electric power transactions with other utility systems and power marketers.
On January 1, 2002, customer choice of electricity supplier began in the Electric Reliability Council of Texas (ERCOT) area of Texas where TCC operates.
Under the Texas Restructuring Legislation, each electric utility was required to submit a plan to structurally unbundle its business into an affiliated REP, a power generator, and a transmission and distribution utility. During the year 2000, TCC submitted a plan for separation that was subsequently approved by the PUCT. TCC has functionally separated its generation from its transmission and distribution operations and AEP formed a separate affiliated REP. Pending regulatory approval, TCC anticipates legally separating its generation from its transmission and distribution operations (see Note 8). The affiliated REP, a separate legal entity that was an AEP subsidiary (not owned by or consolidated with TCC) was sold in December 2002 (see Note 12).
Since the affiliated REP is the electricity supplier to retail customers in the ERCOT area, TCC sells its generation to the affiliated REP and other market participants and provides transmission and distribution services to retail customers of the REPs in the TCC service territory. As a result of the formation of the affiliated REP, effective January 1, 2002, TCC no longer supplies electricity directly to retail customers. The implementation of REPs as suppliers to retail customers has caused a significant shift in TCC's sales as described below under "Results of Operations."
In December 2002, AEP sold the affiliated REP to an unrelated third party who assumed the obligations of the affiliated REP under the Texas Restructuring Legislation (see Note 12). Prior to the sale during 2002 sales to the affiliated REP were classified as Sales to AEP Affiliates. Subsequent to the sale, transactions with the REP were classified as Wholesale Electricity or Energy Delivery.
In 2002, Net Income increased $94 million or 51% primarily due to $262 million of revenues associated with recognition of stranded costs in Texas offset in part by losses associated with the commencement of customer choice in Texas which resulted in the loss of customers and reduced prices (see Note 8). In 2001, Income Before Extraordinary Item decreased $5 million or 3%, primarily resulting from a settlement of Texas municipal franchise fees and increased Maintenance expenses.
Increase (Decrease)
From Previous Year
(dollars in millions)
---------------------
2002 2001
Amount % Amount %
------ - ------ -
Wholesale
Electricity* $(1,096.4) (90) $(29.9) (2)
Energy Delivery* 81.4 17 (5.6) (1)
Sales to AEP
Affiliates 966.7 N.M. 4.0 11
-------- ------
Total $ (48.3) (3) $(31.5) (2)
======= ======
|
*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.
N.M. = Not Meaningful
In 2002, Wholesale Electricity revenues decreased as a result of the elimination of TCC's retail electricity sales in the ERCOT region as of January 1, 2002 and a decrease in wholesale power marketing margins offset in part by the interchange cost reconstruction (ICR) adjustments (see Note 6). In 2001, the decrease in Wholesale Electricity revenues was primarily attributable to unfavorable wholesale power marketing and trading conditions.
In 2002, Sales to AEP Affiliates revenue increased primarily due to increased revenues from the newly created affiliated REP. Although TCC sold electricity to the affiliated REP instead of directly to retail customers, total revenues decreased due to lower prices for power sold to the affiliated REP.
Additionally, delivery charges provided to the affiliated REP in 2002 are
classified as Sales to AEP Affiliates in 2002, whereas in 2001 they were
classified as Energy Delivery revenue. Revenues for 2002 included $262 million
of revenues, associated with recognition of stranded costs in Texas (see Note
8). Energy Delivery revenue also included revenues received for securitized
assets beginning in 2002 (see Note 8).
2002 2001
Amount % Amount %
------ - ------ -
Fuel $(246.2) (50) $(58.8) (11)
Purchased
Power:
Wholesale
Electricity
83.5 65 (16.2) (11)
AEP Affiliates (35.3) (60) 26.0 80
Other
Operation (17.1) (5) 1.7 1
Maintenance (7.8) (11) 10.7 18
Depreciation
And
Amortization
45.8 27 (10.4) (6)
Taxes Other
Than
Income
Taxes
4.6 5 14.4 19
Income
Taxes 26.1 23 12.4 12
------- ------
Total $(146.4) (10) $(20.2) (1)
======= ======
|
In 2002, the decrease in Fuel expense was due to a decrease in the average unit cost of fuel and decreased generation. The decrease in Fuel expense in 2001 was primarily due to a reduction in the average cost of fuel primarily from a decline in natural gas prices. TCC used natural gas as fuel for 32% of its generation in 2002. The nature of the natural gas market is such that both long-term and short-term contracts are generally based on the current spot market price. Changes in natural gas prices affect TCC's fuel expense; however, they generally did not impact results of operations in 2001 and 2000 due to fuel recovery mechanisms, which are no longer in place beginning with deregulation in 2002.
In 2002, the increase in Wholesale Electricity Purchased Power expense is due to higher MWH purchases from the market where we could purchase power at prices lower than our cost to produce. ICR adjustments also had the effect of increasing Wholesale Electricity Purchased Power expense and decreasing AEP Affiliates Purchased Power expense in 2002 (see Note 6).
In 2001, Purchased Power increased overall largely due to higher natural gas prices. Although gas prices declined in 2001, they were higher during the first half of 2001 when TCC was making most of its purchases.
In 2002, Other Operation expense decreased due primarily to the elimination of factoring of accounts receivable and lower ERCOT transmission related expenses.
In 2002, Maintenance expense decreased due to two scheduled "18 month interval" refueling outages for STP during 2001 that increased Maintenance expense above the 2002 and 2000 levels. Also contributing to the decrease in 2002, and the increase in 2001, was an increase in Maintenance expense for scheduled major overhauls of four power plants in 2001.
In 2002, the increase in Depreciation and Amortization is attributable to the amortization of regulatory assets that were securitized in the first quarter of 2002, offset by the elimination of excess earnings expense in 2002 under Texas Restructuring Legislation (see Note 8).
In 2002, the increase in Taxes Other Than Income Taxes resulted primarily from higher local franchise taxes, offset by one-time 2001 assessments and decreased gross receipts tax, due to deregulation. In 2001, Taxes Other Than Income Taxes increased due primarily to an increase in franchise related taxes, including a settlement of disputed franchise fees, and a new tax levied by the PUCT, the Texas System Benefit Fund Assessment.
In 2002, the increase in Income Taxes is due to an increase in pre-tax income offset by changes in timing between book/tax accounting differences in state income taxes. In 2001 the increase in Income Tax expense is primarily due to adjustments associated with prior year tax returns and an increase in pre-tax book income.
In 2002, Nonoperating Income and Nonoperating Expenses increased significantly as a result of increased non-utility revenue and expenses associated with energy related construction projects for third parties, offset in part by decreased interest income. The revenues associated with the energy related construction projects included in Nonoperating Income increased $34 million and $15 million in 2002 and 2001. The expenses associated with these projects included in Nonoperating Expenses increased $32 million and $14 million in 2002 and 2001.
In 2002, Nonoperating Income Tax Expense increased due to increases in pre-tax non-operating income.
In 2002, Interest Charges increased primarily due to higher levels of outstanding debt (see TCC's schedule of Long-term Debt and Consolidated Statements of Capitalization for further information). In 2001, the decrease in interest charges was attributable to lower average interest rates associated with short-term and long-term debt.
The extraordinary loss on reacquired debt recorded in 2001 was the result of reacquisition of installment purchase contracts for Matagorda County, Navigation District, Texas.
As a result of TCC's recent ability to purchase electricity at a significantly lower price than its current cost to generate electricity, TCC proposed in September 2002 to "inactivate" various, high-cost gas fired generating facilities. In the third quarter 2002, TCC recorded an impairment charge of approximately $95.6 million (pre-tax) related to these plants and recorded approximately $4.0 million (pre-tax) for severance charges. Both of these charges were deferred and recorded in Regulatory Assets Designated for or Subject to Securitization, to be included as a stranded cost in the Texas 2004 true-up proceeding (see Note 8). In the fourth quarter 2002 an additional pre-tax charge of $21.6 million was recorded related to additional plant impairments, fuel inventory and materials and supplies, and an additional $1.5 million pre-tax charge was recorded related to severance charges (see Note 13) related to the "inactivated" plants. The entire $23.1 million was also deferred and recorded in Regulatory Assets Designated for or Subject to Securitization.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
---------------------------------
Year Ended December 31,
-------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING REVENUES:
Wholesale Electricity $ 127,502 $1,223,893 $1,253,836
Energy Delivery 554,547 473,182 478,814
Sales to AEP Affiliates 1,008,444 41,762 37,752
---------- ---------- ----------
TOTAL OPERATING REVENUES 1,690,493 1,738,837 1,770,402
---------- ---------- ----------
OPERATING EXPENSES:
Fuel 245,834 492,057 550,903
Purchased Power:
Wholesale Electricity 211,358 127,816 144,021
AEP Affiliates 23,406 58,641 32,591
Other Operation 304,094 321,227 319,539
Maintenance 63,392 71,212 60,528
Depreciation and Amortization 214,162 168,341 178,786
Taxes Other Than Income Taxes 95,500 90,916 76,477
Income Taxes 139,014 112,896 100,459
---------- ---------- ----------
TOTAL OPERATING EXPENSES 1,296,760 1,443,106 1,463,304
---------- ---------- ----------
OPERATING INCOME 393,733 295,731 307,098
NONOPERATING INCOME 53,141 22,552 5,830
NONOPERATING EXPENSES 41,910 17,626 3,668
NONOPERATING INCOME TAX EXPENSE (CREDIT) 3,152 (398) (5,073)
INTEREST CHARGES 125,871 116,268 124,766
---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 275,941 184,787 189,567
EXTRAORDINARY LOSS ON REACQUIRED DEBT (Net of Tax of $1,351,000 for 2001) - (2,509) -
---------- ---------- ----------
NET INCOME 275,941 182,278 189,567
PREFERRED STOCK DIVIDEND REQUIREMENTS 241 242 241
GAIN ON REACQUIRED PREFERRED STOCK 4 - -
---------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 275,704 $ 182,036 $ 189,326
========== ========== ==========
Consolidated Statements of Comprehensive Income
-----------------------------------------------
Year Ended December 31,
------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
NET INCOME $275,941 $182,278 $189,567
OTHER COMPREHENSIVE INCOME (LOSS):
Cash Flow Power Hedges (36) - -
Minimum Pension Liability (73,124) - -
-------- -------- --------
COMPREHENSIVE INCOME $202,781 $182,278 $189,567
======== ======== ========
The common stock of TCC is owned by a wholly owned subsidiary of AEP.
See Notes to Financial Statements beginning on page L-1.
|
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
--------------------------------------------
Year Ended December 31,
---------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
BEGINNING OF PERIOD $826,197 $792,219 $758,894
NET INCOME 275,941 182,278 189,567
DEDUCTIONS (ADDITIONS):
Capital Stock Gains (4) - -
Cash Dividends Declared:
Common Stock 115,505 148,057 156,000
Preferred Stock 241 242 241
Other - 1 1
-------- -------- --------
BALANCE AT END OF PERIOD $986,396 $826,197 $792,219
======== ======== ========
The common stock of TCC is owned by a wholly owned subsidiary of AEP.
See Notes to Financial Statements beginning on page L-1.
|
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
---------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,903,942 $3,169,421
Transmission 698,964 663,655
Distribution 1,296,731 1,279,037
General 258,386 241,137
Construction Work in Progress 200,947 169,075
Nuclear Fuel 266,766 247,382
------- -------
Total Electric Utility Plant 5,625,736 5,769,707
Accumulated Depreciation and Amortization 2,405,492 2,446,027
--------- ---------
NET ELECTRIC UTILITY PLANT 3,220,244 3,323,680
--------- ---------
OTHER PROPERTY AND INVESTMENTS 3,977 47,950
----- ------
SECURITIZED TRANSITION ASSETS 734,591 -
------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 4,392 28,039
----- ------
CURRENT ASSETS:
Cash and Cash Equivalents 85,420 10,909
Accounts Receivable:
General 113,543 38,459
Affiliated Companies 121,324 6,249
Allowance for Uncollectible Accounts (346) (186)
Fuel Inventory 32,563 38,690
Materials and Supplies 51,593 55,475
Accrued Utility Revenues 27,150 -
Energy Trading and Derivative Contracts 22,493 34,480
Prepayments and Other Current Assets 2,133 2,742
----- -----
TOTAL CURRENT ASSETS 455,873 186,818
------- -------
REGULATORY ASSETS 458,552 226,812
------- -------
REGULATORY ASSETS DESIGNATED FOR OR SUBJECT TO SECURITIZATION 336,444 959,294
------- -------
NUCLEAR DECOMMISSIONING TRUST FUND 98,474 98,600
------ ------
DEFERRED CHARGES 43,891 21,837
------ ------
TOTAL ASSETS $5,356,438 $4,893,030
========== ==========
See Notes to Financial Statements beginning on page L-1.
|
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
December 31,
-----------
2002 2001
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $25 Par Value:
Authorized - 12,000,000 Shares
Outstanding - 2,211,678 Shares at December 31, 2002 6,755,535 Shares at
December 31, 2001 $ 55,292 $ 168,888
Paid-in Capital 132,606 405,015
Accumulated Other Comprehensive Income (Loss) (73,160) -
Retained Earnings 986,396 826,197
--------- ---------
Total Common Shareholder's Equity 1,101,134 1,400,100
Preferred Stock 5,942 5,952
CPL - Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely
Junior Subordinated Debentures of CPL 136,250 136,250
Long-term Debt 1,209,434 988,768
--------- -------
TOTAL CAPITALIZATION 2,452,760 2,531,070
--------- ---------
OTHER NONCURRENT LIABILITIES 74,572 10,905
--------- ---------
CURRENT LIABILITIES:
Short-term Debt - Affiliates 650,000 -
Long-term Debt Due Within One Year 229,131 265,000
Advances from Affiliates (net) 126,711 354,277
Accounts Payable - General 72,199 65,307
Accounts Payable - Affiliated Companies 36,242 49,301
Customer Deposits 666 26,744
Taxes Accrued 24,791 83,512
Interest Accrued 51,205 23,715
Energy Trading and Derivative Contracts 19,811 40,987
Other 36,698 18,076
------ ------
TOTAL CURRENT LIABILITIES 1,247,454 926,919
--------- -------
DEFERRED INCOME TAXES 1,261,252 1,163,795
--------- ---------
DEFERRED INVESTMENT TAX CREDITS 117,686 122,892
------- -------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 1,713 17,675
----- ------
REGULATORY LIABILITIES AND DEFERRED CREDITS 201,001 119,774
------- -------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $5,356,438 $4,893,030
========== ==========
See Notes to Financial Statements beginning on page L-1.
|
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
-------------------------------------
Year Ended December 31,
-------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $275,941 $182,278 $189,567
Adjustments to Reconcile Net Income to Net Cash Flows from Operating
Activities:
Depreciation and Amortization 214,162 168,341 178,786
Extraordinary Loss on Reacquired Debt - 2,509 -
Deferred Income Taxes 113,655 (72,568) 16,263
Deferred Investment Tax Credits (5,206) (5,208) (5,207)
Mark-toMarket Energy Trading and Derivative Contracts (1,558) (12,048) 8,191
Change in Certain Current Assets and Liabilities:
Accounts Receivable (net) (189,999) 52,862 (32,902)
Fuel, Materials and Supplies (4,899) (18,215) 8,680
Interest Accrued 27,490 (2,502) 11,494
Accrued Utility Revenues (27,150) - -
Accounts Payable (6,167) (55,311) 45,873
Taxes Accrued (58,721) 27,986 14,405
Fuel Recovery 16,455 179,866 (96,872)
Transmission Coordination Agreement Settlement - - 15,519
Texas Wholesale Clawback (see Note 7) (262,000) - -
Change in Other Assets (534) 10,767 589
Change in Other Liabilities 56,024 11,163 12,243
-------- -------- --------
Net Cash Flows From Operating Activities 147,493 469,920 366,629
-------- -------- --------
INVESTING ACTIVITIES:
Construction Expenditures (151,645) (193,732) (199,484)
Proceeds From Sales of Property and Other 143 (354) -
-------- -------- --------
Net Cash Flows Used For Investing
Activities (151,502) (194,086) (199,484)
-------- -------- --------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 797,335 260,162 149,248
Change in Short-term Debt Affiliate (Net) 650,000 - -
Retirement of Common Stock (386,005) - -
Retirement of Preferred Stock (6) - -
Retirement of Long-term Debt (639,492) (475,606) (151,440)
Change in Advances from Affiliates (net) (227,566) 84,565 (52,446)
Special Deposit for Reacquisition of Long-term Debt - - 50,000
Dividends Paid on Common Stock (115,505) (148,057) (156,000)
Dividends Paid on Cumulative Preferred Stock (241) (242) (249)
-------- -------- --------
Net Cash Flows From (Used For)
Financing Activities 78,520 (279,178) (160,887)
-------- -------- --------
Net Increase (Decrease) in Cash and Cash Equivalents
74,511 (3,344) 6,258
Cash and Cash Equivalents January 1 10,909 14,253 7,995
-------- -------- --------
Cash and Cash Equivalents December 31 $ 85,420 $ 10,909 $ 14,253
======== ======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts (including distributions on
Trust Preferred Securities) was $93,120,000, $109,835,000 and $110,010,000 and
for income taxes was $95,600,000, $161,529,000 and $48,141,000 in 2002, 2001 and
2000,respectively.
See Notes to Financial Statements beginning on page L-1.
|
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
-----------------------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY (a) $1,101,134 $1,400,100
---------- ----------
PREFERRED STOCK - 3,035,000 authorized shares, $100 par value
Not Subject to Mandatory Redemption:
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2002 Year Ended December 31, December 31, 2002
------ ------------ ---------------------------- -----------------
2002 2001 2000
---- ---- ----
4.00% $105.75 100 - - 41,938 4,194 4,204
4.20% 103.75 - - - 17,476 1,748 1,748
---------- ----------
Total Preferred Stock 5,942 5,952
---------- ----------
TRUST PREFERRED SECURITIES:
TCC-obligated, mandatorily redeemable preferred
securities of subsidiary trust holding solely
Junior Subordinated Debentures of TCC, 8.00%,
due April 30, 2037 136,250 136,250
---------- ----------
LONG-TERM (See Schedule of Long-term Debt):
First Mortgage Bonds 152,353 614,200
Securitization Bonds (a) 796,635 -
Installment Purchase Contracts 489,577 489,568
Senior Unsecured Notes - 150,000
Less Portion Due Within One year (229,131) (265,000)
---------- ----------
Long-term Debt Excluding Portion Due Within One Year 1,209,434 988,768
---------- ----------
TOTAL CAPITALIZATION $2,452,760 $2,531,070
========== ==========
(a) In February 2002, TCC issued securitization bonds. $386 million of the proceeds was used to retire 4,543,857 shares of
common stock.
See Notes to Financial Statements beginning on page L-1.
|
First mortgage bonds outstanding were as follows:
December 31,
2002 2001
---- ----
(in thousands)
% Rate Due
7.25 2004 - October 1 $ 27,400 $100,000
7.50 2002 - December 1 - 115,000
6-7/8 2003 - February 1 16,418 49,200
7-1/8 2008 - February 1 18,581 75,000
7.50 2023 - April 1 17,996 75,000
6-5/8 2005 - July 1 71,958 200,000
-------- --------
Total $152,353 $614,200
======== ========
|
First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions.
Securitization Bonds outstanding were as follows:
December 31,
------------------
Final 2002 2001
---- ----
Payment Maturity (in thousands)
Rate Date Date
---- --------- ------------
3.54 1/15/2005 1/15/2007 $128,950 $ -
5.01 1/15/2008 1/15/2010 154,507 -
5.56 1/15/2010 1/15/2012 107,094 -
5.96 7/15/2013 7/15/2015 214,927 -
6.25 1/15/2016 1/15/2017 191,857 -
Unamortized Discount (700) -
-------- -----
Total $796,635 $ -
======== =====
|
In February 2002, CPL Transition Funding LLC, a special purpose subsidiary of TCC, issued $797 million of Securitization Bonds, Series 2002-1. The Securitization Bonds mature at different times through 2017 and have a weighted average interest rate of 5.4 percent.
Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:
December 31,
2002 2001
---- ----
(in thousands)
% Rate Due
Matagorda County
Navigation District,
Texas:
6.00 2028 - July 1 $120,265 $120,265
6-1/8 2030 - May 1 60,000 60,000
3.75 2030(a) - May 1 111,700 111,700
4.00 2030(a) - May 1 50,000 50,000
4.55 2029(a) - Nov 1 100,635 100,635
Guadalupe-Blanco
River Authority
District, Texas:
(b) 2015 - November 1 40,890 40,890
Red River Authority
District, Texas:
6.00 2020 - June 1 6,330 6,330
Unamortized Discount (243) (252)
-------- --------
Total $489,577 $489,568
======== ========
|
(a)Installment Purchase Contract provides for bonds to be tendered in 2003 for
3.75% and 4.00% series and in 2006 for 4.55% series. Therefore, these
installment purchase contracts have been classified for payments in those years.
(b) A floating interest rate is determined monthly. The rate on December 31,
2002 was 1.7%.
Under the terms of the installment purchase contracts, TCC is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.
Senior unsecured notes outstanding were as follows:
December 31,
2002 2001
---- ----
(in thousands)
% Rate Due
2002 - February 22 (c) $ - $150,000
------ --------
Total $ - $150,000
====== ========
|
(c) A floating interest rate is determined monthly. The rate on December 31, 2001 was 2.56%.
At December 31, 2002, future annual long-term debt payments are as follows:
Amount
------
(in thousands)
2003 $229,131
2004 75,951
2005 121,937
2006 152,900
2007 52,729
Later Years 806,860
----------
Total Principal Amount 1,439,508
Unamortized Discount (943)
----------
Total $1,438,565
|
See Note 25 for discussion of the Trust Preferred Securities issued by a wholly owned statutory business trust of TCC.
The notes to TCC's consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to TCC. The combined footnotes begin on page L-1.
Combined
Footnote
Reference
---------
Significant Accounting Policies Note 1
Extraordinary Items and Cumulative Effect Note 2
Merger Note 4
Rate Matters Note 6
Effects of Regulation Note 7
Customer Choice and Industry Restructuring Note 8
Commitments and Contingencies Note 9
Guarantees Note 10
Sustained Earnings Improvement Initiative Note 11
Acquisitions, Dispositions and Discontinued Operations Note 12
Asset Impairment and Investment Value Losses Note 13
Benefit Plans Note 14
Business Segments Note 16
Risk Management, Financial Instruments and Derivatives Note 17
Income Taxes Note 18
Leases Note 22
Lines of Credit and Sale of Receivables Note 23
Unaudited Quarterly Financial Information Note 24
Trust Preferred Securities Note 25
Jointly Owned Electric Utility Plant Note 28
Related Party Transactions Note 29
|
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of Directors of AEP Texas Central Company:
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of AEP Texas Central Company and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of AEP Texas Central Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 |
AEP TEXAS NORTH COMPANY
AEP TEXAS NORTH COMPANY
Selected Financial Data
-----------------------
Year Ended December 31,
------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $ 450,740 $556,458 $571,064 $445,709 $424,953
Operating Expenses 442,869 523,068 518,723 391,910 365,677
---------- -------- -------- -------- --------
Operating Income 7,871 33,390 52,341 53,799 59,276
Nonoperating Items, Net (703) 2,195 (1,675) 2,488 2,712
Interest Charges 20,845 23,275 23,216 24,420 24,263
---------- -------- -------- -------- --------
Income (Loss) Before
Extraordinary Item (13,677) 12,310 27,450 31,867 37,725
Extraordinary Loss - - - (5,461) -
---------- -------- -------- -------- --------
Net Income (Loss) (13,677) 12,310 27,450 26,406 37,725
Preferred Stock
Dividend Requirements 104 104 104 104 104
---------- -------- -------- -------- --------
Earnings (Loss) Applicable to
Common Stock $ (13,781) $ 12,206 $ 27,346 $ 26,302 $ 37,621
========== ======== ======== ======== ========
December 31,
-----------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $1,201,747 $1,260,872 $1,229,339 $1,182,544 $1,146,582
Accumulated
Depreciation and
Amortization 521,792 546,162 515,041 495,847 473,503
---------- ---------- ---------- ---------- ----------
Net Electric Utility
Plant $679,955 $714,710 $714,298 $686,697 $673,079
======== ======== ======== ======== ========
Total Assets $877,175 $ 864,875 $1,087,504 $861,205 $819,446
======== ========== ========== ======== ========
Common Stock and
Paid-in Capital $139,565 $139,565 $139,565 $139,565 $139,565
Accumulated Other Comprehensive
Income (Loss) (30,763) - - - -
Retained Earnings 71,942 105,970 122,588 113,242 114,940
--------- ---------- ---------- ---------- ----------
Total Common
Shareholder's Equity $180,744 $245,535 $262,153 $252,807 $254,505
======== ======== ======== ======== ========
Cumulative Preferred Stock:
Not Subject to
Mandatory Redemption $2,367 $ 2,367 $ 2,367 $ 2,367 $ 2,368
====== ======= ======= ======= =======
Long-term Debt (a) $132,500 $255,967 $255,843 $303,686 $303,518
======== ======== ======== ======== ========
Total Capitalization
And Liabilities $877,175 $ 864,875 $1,087,504 $861,205 $819,446
======== ========== ========== ======== ========
(a) Including portion due within one year.
|
AEP Texas North Company (TNC), formerly known as West Texas Utilities Company (WTU), is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power in west and central Texas. TNC also sells electric power at wholesale to other utilities, municipalities, rural electric cooperatives and beginning in 2002 to its affiliated retail electric provider (REP) in Texas.
Wholesale power marketing activities are conducted on TNC's behalf by AEPSC. TNC, along with the other AEP electric operating subsidiaries, shares in AEP's electric power transactions with other utility systems and power marketers.
On January 1, 2002, customer choice of electricity supplier began in the Electric Reliability Council of Texas (ERCOT) area of Texas. TNC operates in both the ERCOT and Southwest Power Pool (SPP) regions of Texas, with the majority of its operations being in the ERCOT territory.
Under the Texas Restructuring Legislation, each electric utility was required to submit a plan to structurally unbundle its business into an affiliated REP, a power generator, and a transmission and distribution utility. During the year 2000, TNC submitted a plan for separation that was subsequently approved by the PUCT. TNC has functionally separated its generation from its transmission and distribution operations and AEP formed a separate affiliated REP. Pending regulatory approval, TNC anticipates legally separating its generation from its transmission and distribution operations (see Note 8). The affiliated REP, a separate legal entity that was an AEP subsidiary (not owned by or consolidated with TNC) was sold in December 2002 (see Note 12).
Since the affiliated REP is the electricity supplier to retail customers in the ERCOT area, TNC sells its generation to the affiliated REP and other market participants and provides transmission and distribution services to retail customers of the REPs in the TNC service territory. As a result of the formation of the affiliated REP, effective January 1, 2002, TNC no longer supplies electricity directly to retail customers. The implementation of REPs as suppliers to retail customers has caused a significant shift in TNC's sales as described below under "Results of Operations."
In December 2002, AEP sold the affiliated REP to an unrelated third party, who assumed the obligations of the affiliated REP under the Texas Restructuring Legislation (see Note 12). Prior to the sale, during 2002, sales to the affiliated REP were classified as Sales to AEP Affiliates. Subsequent to the sale, transactions with the REP will be classified as Wholesale Electricity or Energy Delivery.
In 2002, Net Income decreased $26.0 million or 211% primarily due to a $38.1 million long-lived asset impairment charge ($24.8 million net of tax) related to the inactivation of inefficient gas fired plants (see Note 13) and a $4.7 million impairment charge ($3.1 million net of tax) related to the abandonment of a wind-powered generation facility (see Note 13).
(in millions) %
Wholesale Electricity* $(231.7) (63)
Energy Delivery* (95.7) (57)
Sales to AEP
Affiliates 221.7 N.M.
-------
Total $(105.7) (19)
=======
|
*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.
N.M. = Not Meaningful
Wholesale Electricity revenues decreased as a result of the elimination of TNC's retail electricity sales in the ERCOT region as of January 1, 2002 and a decrease in wholesale power marketing margins, partially offset by the ICR adjustments (see Note 6).
Sales to AEP Affiliates increased primarily due to increased revenues from the newly created affiliated REP. Although TNC sold electricity to the affiliated REP instead of directly to retail customers in the ERCOT region, total revenues decreased due to lower prices for power sold to the affiliated REP.
Additionally, delivery charges provided to the affiliated REP in 2002 are classified as Sales to AEP Affiliates in 2002, whereas in 2001 they were classified as Energy Delivery revenue.
(in millions) %
Fuel $(76.7) (43)
Purchased Power:
Wholesale Electricity 10.0 14
AEP Affiliates (19.1) (34)
Other Operation (6.3) (6)
Asset Impairments 42.9 N.M.
Maintenance - -
Depreciation and
Amortization (7.1) (14)
Taxes Other
Than Income Taxes (5.8) (21)
Income Taxes (18.1) N.M.
-----
Total $(80.2) (15)
======
|
N.M. = Not Meaningful
Fuel expense decreased due to a decrease in the average unit cost of fuel and decreased generation required due to decreased energy sales. TNC used natural gas as fuel for 42% of its generation in 2002. The nature of the natural gas market is such that both long-term and short-term contracts are generally based on the current spot market price. Changes in natural gas prices affect TNC's fuel expense; however, they generally did not impact results of operations in 2001 due to fuel recovery mechanisms, which are no longer in place beginning with deregulation in 2002.
The net decline in total Purchased Power expense in 2002 was mainly due to both reduced MWHs purchased and reduced prices, partially offset by ICR adjustments (see Note 6).
Other Operation expense decreased slightly in 2002 due to lower factoring and transmission expenses, offset in part by a $1.4 million write-down of material and supply inventory associated with the impaired plants.
As a result of TNC's recent ability to purchase electricity at a significantly lower price than its current cost to generate electricity, TNC proposed in September 2002 to "inactivate" various, high-cost gas fired generating facilities. TNC recorded an impairment charge in the third quarter 2002 of approximately $34.2 million related to these plants, which was recorded in Asset Impairments expense. In the fourth quarter 2002, an additional asset impairments charge of $3.9 million was also recorded in connection with these plants, along with a $4.7 million charge for a wind-powered generation facility (see Note 13). Additionally, a $1.2 million charge associated with fuel inventory (recorded in Fuel) and a $1.4 million charge associated with materials and supplies (recorded in Other Operations) was recorded in the fourth quarter of 2002 related to the "inactivated" plants.
Depreciation and Amortization expense decreased due to the elimination in 2002 of excess earnings expense under Texas Restructuring Legislation and the elimination of regulatory asset amortization that ended in 2001.
The decrease in Taxes Other Than Income Taxes is primarily a result of one time 2001 assessments and a decrease in the gross receipts tax due to deregulation.
The decrease in Income Taxes is primarily a result of a decrease in pre-tax income resulting from the impairment of various generating facilities.
Other Changes
Nonoperating Income and Nonoperating Expenses increased significantly as a result of increased non-utility revenue and expenses associated with energy related construction projects for third parties, offset in part by decreased interest income. The revenues associated with the aforementioned energy related construction projects included in Nonoperating Income increased $45.5 million in 2002. The expenses associated with these projects included in Nonoperating Expenses increased $43.0 million in 2002.
Interest Charges declined primarily due to lower interest rates.
AEP TEXAS NORTH COMPANY
Statements of Operations
------------------------
Year Ended December 31,
-------------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING REVENUES:
Wholesale Electricity $136,962 $368,741 $376,206
Energy Delivery 73,353 169,036 176,204
Sales to AEP Affiliates 240,425 18,681 18,654
-------- -------- --------
TOTAL OPERATING REVENUES 450,740 556,458 571,064
-------- -------- --------
OPERATING EXPENSES:
Fuel 100,466 177,140 183,154
Purchased Power:
Wholesale Electricity 80,391 70,395 68,080
AEP Affiliates 37,582 56,656 57,773
Other Operation 104,960 111,248 93,078
Asset Impairments 42,898 - -
Maintenance 22,295 22,343 21,241
Depreciation and Amortization 43,620 50,705 55,172
Taxes Other Than Income Taxes 22,471 28,319 25,321
Income Tax Expense (Credit) (11,814) 6,262 14,904
-------- -------- --------
TOTAL OPERATING EXPENSES 442,869 523,068 518,723
-------- -------- --------
OPERATING INCOME 7,871 33,390 52,341
NONOPERATING INCOME 53,763 12,199 9,530
NONOPERATING EXPENSES 54,755 10,695 12,664
NONOPERATING INCOME TAX CREDIT (289) (691) (1,459)
INTEREST CHARGES 20,845 23,275 23,216
-------- -------- --------
NET INCOME (LOSS) (13,677) 12,310 27,450
PREFERRED STOCK DIVIDEND REQUIREMENTS 104 104 104
-------- -------- --------
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $(13,781) $ 12,206 $ 27,346
======== ======== ========
Statements of Comprehensive Income
Year Ended December 31,
----------------------------------------------
2002 2001 2000
---- ---- ----
NET INCOME (LOSS) $(13,677) $12,310 $27,450
OTHER COMPREHENSIVE INCOME (LOSS):
Cash Flow Power Hedges (15) - -
Minimum Pension Liability (30,748) - -
-------- ------- -------
COMPREHENSIVE INCOME (LOSS) $(44,440) $12,310 $27,450
======== ======= =======
The common stock of TNC is owned by a wholly owned subsidiary of AEP. See notes
to Financial Statements beginning on page L-1.
|
AEP TEXAS NORTH COMPANY
Statements of Retained Earnings
-------------------------------
Year Ended December 31,
----------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
BEGINNING OF PERIOD $105,970 $122,588 $113,242
NET INCOME (LOSS) (13,677) 12,310 27,450
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 20,247 28,824 18,000
Preferred Stock 104 104 104
-------- -------- --------
BALANCE AT END OF PERIOD $ 71,942 $105,970 $122,588
======== ======== ========
The common stock of TNC is owned by a wholly owned subsidiary of AEP. See notes
to Financial Statements beginning on page L-1.
|
AEP TEXAS NORTH COMPANY
Balance Sheets
--------------
December 31,
2002 2001
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $ 353,087 $ 443,508
Transmission 254,483 250,023
Distribution 445,486 431,969
General 111,679 112,797
Construction Work in Progress 37,012 22,575
---------- ----------
Total Electric Utility Plant 1,201,747 1,260,872
Accumulated Depreciation and Amortization 521,792 546,162
---------- ----------
NET ELECTRIC UTILITY PLANT 679,955 714,710
---------- ----------
OTHER PROPERTY AND INVESTMENTS 1,213 24,933
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 2,248 8,327
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 1,219 2,454
Accounts Receivable:
Customers 62,660 18,720
Affiliated Companies 43,632 8,656
Allowance for Uncollectible Accounts (5,041) (196)
Fuel Inventory 12,677 8,307
Materials and Supplies 9,574 11,190
Accrued Utility Revenues 6,829 -
Energy Trading and Derivative Contracts 4,130 10,240
Prepayments and Other 1,070 966
---------- ----------
TOTAL CURRENT ASSETS 136,750 60,337
---------- ----------
REGULATORY ASSETS 45,097 54,122
---------- ----------
DEFERRED CHARGES 11,912 2,446
---------- ----------
TOTAL ASSETS $ 877,175 $ 864,875
========== ==========
See Notes to Financial Statements beginning on page L-1.
|
AEP TEXAS NORTH COMPANY
December 31,
2002 2001
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $25 Par Value:
Authorized - 7,800,000 Shares
Outstanding - 5,488,560 Shares $137,214 $137,214
Paid-in Capital 2,351 2,351
Accumulated Other Comprehensive Income (Loss) (30,763) -
Retained Earnings 71,942 105,970
-------- --------
Total Common Shareholder's Equity 180,744 245,535
Cumulative Preferred Stock
Not Subject to Mandatory Redemption 2,367 2,367
Long-term Debt 132,500 220,967
-------- --------
TOTAL CAPITALIZATION 315,611 468,869
-------- --------
OTHER NONCURRENT LIABILITIES 28,861 6,296
-------- --------
CURRENT LIABILITIES:
Short-term Debt - Affiliates 125,000 -
Long-term Debt Due Within One Year - 35,000
Advances from Affiliates 80,407 50,448
Accounts Payable - General 32,714 33,782
Accounts Payable - Affiliated Companies 76,217 11,388
Customer Deposits 117 4,191
Taxes Accrued 3,697 17,358
Interest Accrued 2,776 4,762
Energy Trading and Derivative Contracts 3,801 12,402
Other 17,414 9,824
-------- --------
TOTAL CURRENT LIABILITIES 342,143 179,155
-------- --------
DEFERRED INCOME TAXES 117,521 145,049
-------- --------
DEFERRED INVESTMENT TAX CREDITS 21,510 22,781
-------- --------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 557 5,250
-------- --------
REGULATORY LIABILITIES AND DEFERRED CREDITS 50,972 37,475
-------- --------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $877,175 $864,875
======== ========
See Notes to Financial Statements beginning on page L-1.
|
AEP TEXAS NORTH COMPANY
Statements of Cash Flows
------------------------
Year Ended December 31,
----------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income (Loss) $(13,677) $ 12,310 $ 27,450
Adjustments to Reconcile Net Income to Net Cash Flows From Operating
Activities:
Depreciation and Amortization 43,620 50,705 55,172
Writedown of Utility Assets 38,154 -
Writedown of Wind Farm Assets 4,744 - -
Deferred Income Taxes (12,275) (11,891) 8,164
Deferred Investment Tax Credits (1,271) (1,271) (1,271)
Mark-to-Market Energy Trading and Derivative Contracts (1,127) (3,506) 2,590
CHANGES IN CERTAIN CURRENT ASSETS AND LIABILITIES:
Accounts Receivable (net) (74,071) 24,844 (1,445)
Fuel, Materials and Supplies (2,754) 3,187 8,478
Accrued Utility Revenues (6,829) - -
Accounts Payable 63,761 (42,604) 28,393
Taxes Accrued (13,661) (1,543) 6,443
Fuel Recovery 14,169 32,505 (53,841)
Transmission Coordination Agreement Settlement - - 15,465
Change in Other Assets (16,928) (1,432) 2,549
Change in Other Liabilities 16,514 11,056 (3,869)
-------- -------- --------
Net Cash Flows From Operating Activities 38,369 72,360 94,278
-------- -------- --------
INVESTING ACTIVITIES:
Construction Expenditures (43,563) (39,662) (64,477)
Sales Proceeds and Other 150 (127) -
-------- -------- --------
Net Cash Used For Investing Activities (43,413) (39,789) (64,477)
-------- -------- --------
FINANCING ACTIVITIES:
Retirement of Long-term Debt (130,799) - (48,000)
Change in Short-term Debt Affiliated (net) 125,000 - -
Change in Advances from Affiliates (net) 29,959 (8,130) 37,170
Dividends Paid on Common Stock (20,247) (28,824) (18,000)
Dividends Paid on Cumulative Preferred Stock (104) (104) (104)
-------- -------- --------
Net Cash Flows From (Used For) Financing Activities 3,809 (37,058) (28,934)
-------- -------- --------
Net Increase (Decrease) in Cash and Cash Equivalents (1,235) (4,487) 867
Cash and Cash Equivalents at Beginning of Period 2,454 6,941 6,074
-------- -------- --------
Cash and Cash Equivalents at End of Period $ 1,219 $2,454 $6,941
======== ====== ======
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $19,934,000
$19,279,000 and $19,088,000 and for income taxes was $15,544,000, $21,997,000
and ($906,000) in 2002, 2001 and 2000 respectively.
See Notes to Financial Statements beginning on page L-1.
|
AEP TEXAS NORTH COMPANY
Statements of Capitalization
----------------------------
December 31,
2002 2001
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY $180,744 $245,535
-------- --------
PREFERRED STOCK: $100 par value - authorized shares 810,000
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2002 Year Ended December 31, December 31, 2002
------ ------------ ---------------------------- -----------------
2002 2001 2000
---- ---- ----
Not Subject to Mandatory Redemption:
4.40% $107 - - 1 23,672 2,367 2,367
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 88,190 211,657
Installment Purchase Contracts 44,310 44,310
Less Portion Due Within One Year - (35,000)
-------- --------
Long-term Debt Excluding Portion Due Within One Year 132,500 220,967
-------- --------
TOTAL CAPITALIZATION $315,611 $468,869
======== ========
See Notes to Financial Statements beginning on page L-1.
|
First mortgage bonds outstanding were as follows:
% Rate Due
6-7/8 2002 - October 1 $ - $ 35,000
7 2004 - October 1 18,469 40,000
6-1/8 2004 - February 1 24,036 40,000
6-3/8 2005 - October 1 37,609 72,000
7-3/4 2007 - June 1 8,151 25,000
Unamortized Discount (75) (343)
------- --------
$88,190 $211,657
|
First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions.
Installment purchase contracts have been entered into, in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:
Under the terms of the installment purchase contracts, TNC is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.
At December 31, 2002, future annual long-term debt payments are as follows:
Amount
------
(in thousands)
2003 $ -
2004 42,505
2005 37,609
2006 -
2007 8,151
Later Years 44,310
--------
Principal Amount 132,575
Less: Unamortized Discount (75)
--------
Total $132,500
|
The notes to TNC's financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to TNC. The combined footnotes begin on page L-1.
Combined
Footnote
Reference
---------
Significant Accounting Policies Note 1
Extraordinary Items and Cumulative Effect Note 2
Merger Note 4
Rate Matters Note 6
Effects of Regulation Note 7
Customer Choice and Industry Restructuring Note 8
Commitments and Contingencies Note 9
Guarantees Note 10
Sustained Earnings Improvement Initiative Note 11
Acquisitions, Dispositions and Discontinued Operations Note 12
Asset Imapairments and Investment Value Losses Note 13
Benefit Plans Note 14
Business Segments Note 16
Risk Management, Financial Instruments and Derivatives Note 17
Income Taxes Note 18
Leases Note 22
Lines of Credit and Sale of Receivables Note 23
Unaudited Quarterly Financial Information Note 24
Jointly Owned Electric Utility Plant Note 28
Related Party Transactions Note 29
|
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of AEP Texas North Company:
We have audited the accompanying balance sheets and statements of capitalization of AEP Texas North Company as of December 31, 2002 and 2001, and the related statements of operations, retained earnings, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of AEP Texas North Company as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
------------------------------------
Year Ended December 31,
-----------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,814,470 $1,784,259 $1,759,253 $1,586,050 $1,672,244
Operating Expenses 1,512,407 1,509,273 1,558,099 1,344,814 1,443,701
---------- ---------- ---------- ---------- ----------
Operating Income 302,063 274,986 201,154 241,236 228,543
Nonoperating Items,
Net 20,106 6,868 11,752 8,096 (8,301)
Interest Charges 116,677 120,036 148,000 128,840 126,912
---------- ---------- ---------- ---------- -----------
Income Before
Extraordinary Item 205,492 161,818 64,906 120,492 93,330
Extraordinary Gain - - 8,938 - -
---------- ---------- ---------- ---------- ----------
Net Income 205,492 161,818 73,844 120,492 93,330
Preferred Stock
Dividend Requirements 2,897 2,011 2,504 2,706 2,497
---------- ---------- ---------- ---------- ----------
Earnings Applicable
to Common Stock $ 202,595 $ 159,807 $ 71,340 $ 117,786 $ 90,833
=========== ========== ========== ========== ==========
December 31,
------------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility
Plant $5,895,303 $5,664,657 $5,418,278 $5,262,951 $5,087,359
Accumulated
Depreciation and
Amortization 2,424,607 2,296,481 2,188,796 2,079,490 1,984,856
---------- ---------- ---------- ---------- ----------
Net Electric Utility
Plant $3,470,696 $3,368,176 $3,229,482 $3,183,461 $3,102,503
========== ========== ========== ========== ==========
Total Assets $4,627,847 $4,482,785 $6,572,595 $4,352,219 $4,047,038
========== ========== ========== ========== ==========
Common Stock and
Paid-in Capital $977,700 $976,244 $975,676 $974,717 $924,091
Accumulated Other
Comprehensive Income
(Loss) (72,082) (340) - - -
Retained Earnings 260,439 150,797 120,584 175,854 179,461
---------- ---------- ---------- ---------- ----------
Total Common
Shareholder's Equity $1,166,057 $1,126,701 $1,096,260 $1,150,571 $1,103,552
========== ========== ========== ========== ==========
Cumulative Preferred Stock:
Not Subject to
Mandatory Redemption $ 17,790 $ 17,790 $ 17,790 $ 18,491 $ 19,359
Subject to Mandatory
Redemption 10,860 10,860 10,860 20,310 22,310
---------- ---------- ---------- ---------- -----------
Total Cumulative
Preferred Stock $ 28,650 $ 28,650 $ 28,650 $ 38,801 $ 41,669
======== ========== ========== ========== ==========
Long-term Debt (a) $1,893,861 $1,556,559 $1,605,818 $1,665,307 $1,552,455
========== ========== ========== ========== ==========
Obligations Under
Capital Leases (a) $ 33,589 $ 46,285 $ 63,160 $ 64,645 $ 65,175
========== ========== ======== ========== ==========
Total Capitalization
And Liabilities $4,627,847 $4,482,785 $6,572,595 $4,352,219 $4,047,038
========== ========== ========== ========== ==========
(a) Including portion due within one year.
|
APCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 925,000 retail customers in southwestern Virginia and southern West Virginia. APCo, as a member of the AEP Power Pool, shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. APCo also sells wholesale power to municipalities.
The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of revenues and costs.
Net Income increased $44 million or 27% in 2002 due to higher retail sales resulting from increased generation, weather related electricity demands and reductions in Maintenance expense. Most significantly, the Mountainer, Amos and Glen Lyn plants, down for boiler maintenance in 2001, were back online in 2002 resulting in increased availability of generation and decreased maintenance expense. In addition, Nonoperating Income less Nonoperating Expenses increased $10 million as a result of a reduction in trading incentive compensation recorded in Nonoperating Expenses offset in part by decreased power trading gains recorded in Nonoperating Income.
Net Income increased $88 million or 119% in 2001 primarily due to the effect of a court decision related to a corporate owned life insurance (COLI) program recorded in 2000. In February 2001, the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including APCo, in a suit over deductibility of interest claimed in AEP's consolidated tax return related to COLI. In 1998 and 1999 APCo paid the disputed taxes and interest attributable to the COLI interest deductions for taxable years 1991-98. Also contributing to the increase in net income was growth in and strong performance by the wholesale electricity business in the first half of 2001 offset in part by the effect of extremely mild weather in November and December combined with weak economic conditions which reduced retail energy sales.
Operating Revenues increased $30 million or 2% in 2002 as a result of weather related demand and increased generation resulting from availablility of plants previously down for maintenance coming back online. An increase of $25 million, or 1%, in 2001 Operating Revenues was attributable to an increase in AEP Power Pool transactions. Changes in components of revenues were as follows:
Increase (Decrease)
From Previous Year
(dollars in millions)
2002 2001
---------------------------
Amount % Amount %
------ - ------ -
Wholesale
Electricity* $16.0 2 $(11.7) (1)
Energy Delivery* (1.0) - 20.1 3
Sales to AEP
Affiliates 15.2 9 16.6 11
----- ------
Total
Revenues $30.2 2 $ 25.0 1
===== ======
|
*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.
Operating Revenues for 2002 increased as a result of an increase in generation and availability at the Mountaineer, Amos and Glen Lyn plants; and increases in residential and commercial sales due to warmer weather during July and September. Sales to AEP affiliates increased for the year due to an increase in generation capacity and power available to be delivered to AEP Power Pool. These increases were partially offset by flat industrial sales as recessionary conditions continued into 2002.
The year 2001 saw a decrease in kilowatt hour sales to industrial customers. This decrease was due to the economic recession. In the fourth quarter, sales to residential and commercial customers declined, reflecting recession-related reductions in demand.
The increase in Sales to AEP Affiliates in 2001 is due to an increase in AEP Power Pool transactions. As the quantity of energy sold by the AEP Power Pool rose, APCo's contribution of energy to the Pool rose, accounting for the increase in APCo's revenues from Sales to AEP Affiliates.
Operating Expenses for 2002 were comparable to those of 2001. Increases in Fuel and Wholesale Electricity Purchased Power expenses were offset by decreases in power purchases from AEP Affiliates due to increases in APCo generation and availability as plants previously down for maintenance resumed operations. The decrease in operating expenses in 2001 of 3% is due to decreases in income taxes, other operation expense, fuel expense and taxes other than income taxes partially offset by increases in electricity purchased power expense and depreciation and amortization expenses. Changes in the components of Operating Expenses are as follows:
Increase (Decrease)
From Previous Year
(dollars in millions)
2002 2001
-----------------------------
Amount % Amount %
------ - ------ -
Fuel $ 79.4 23 $ (17.6) (5)
Wholesale
Electricity
Purchases 15.0 36 17.4 70
AEP Affiliate
Purchases (112.3) (32) (8.9) (3)
Other Operation 8.9 3 (18.6) (7)
Maintenance (10.2) (8) 7.9 6
Depreciation and
Amortization 8.9 5 17.3 11
Taxes Other Than
Income Taxes (4.6) (5) (11.8) (11)
Income Taxes 18.0 19 (34.5) (27)
------- --------
Total $ 3.1 - $ (48.8) (3)
======= ========
|
Fuel expense increased for 2002 as a result of an increase in APCo generation. Mountaineer, Amos, and Glen Lyn plants had undergone boiler plant maintenance in 2001 which resulted in increased availability in 2002. The decrease in Fuel expense in 2001 is due to a decline in generation as a result of scheduled plant maintenance.
Wholesale Electricity Purchases increased for 2002 as a result of increased purchases from third parties for resale to wholesale customers and to meet internal demand. Electricity purchased power expense increased in 2001 due to increases in wholesale electricity prices and as a result of the previously mentioned plant outages.
The decrease for 2002 in Purchases from AEP Affiliates is a result of increased internal generation due to plant availability. Purchased power from AEP affiliates decreased in 2001 as the result of a decrease in AEP Power Pool capacity charges due to a reduction in APCo's MLR.
Other Operation expense increased in 2002 mainly due to severance expenses related to the sustained earnings initiative plan, a reduction in the gains recorded on the dispositions of SO2 emission allowances, and increased insurance premiums and other employee benefit costs. These increases were offset by reduced trading overhead expenses as a result of reduced staffing and weaker market conditions; a decrease in transmission equalization charges caused by a reduction in APCo's MLR ratio; and energy delivery severance accruals recorded in 2001 for which there was no comparable activity in 2002. Other operation expense decreased in 2001 mainly due to the effect of AEPSC billings in 2000 for the disallowance of the COLI program interest deduction. Additionally, the decrease was the result of a gain recorded on the disposition of SO2 emission allowances offset in part by increased wholesale power trading incentive compensation expense.
The decrease in Maintenance expense in 2002 is primarily due to previously discussed boiler plant maintenance at Amos, Mountaineer and Glen Lyn plants in the year 2001.
Depreciation and Amortization expense increased during 2002 due to increased amortization for the net generation-related regulatory assets related to the Company's West Virginia jurisdiction which were assigned to the distribution portion of the Company's business and are being recovered through regulated rates. Investment in production plant in service, primarily equipment related to emission control, contributed to the increase in depreciation and amortization expense.
Depreciation and Amortization expense increased in 2001 due to accelerated amortization, beginning in July 2000, of the transition regulatory assets in the Virginia and West Virginia jurisdictions. Additional investments in distribution and transmission plant also contributed to the increases in depreciation and amortization expense in 2001. During June 2000 we discontinued the application of SFAS 71 in the Virginia and West Virginia jurisdictions. Consequently net generation-related regulatory assets were assigned to the energy delivery business's regulated distribution business where the Virginia and West Virginia jurisdictions authorized the recovery of these transition regulatory assets through regulated rates.
The decrease in Taxes Other Than Income Taxes for the year 2002 is due primarily to a decrease in municipal license tax. The municipal license tax was replaced by the Virginia consumption tax. The municipal license tax was imposed on APCo and the Virginia consumption tax is imposed on the customer with APCo acting as collector agent. The decrease in Taxes Other Than Income Taxes in 2001 is due to the elimination of the Virginia gross receipts tax as a result of a tax law change due to deregulation in that state.
The increase in Income Taxes for 2002 was due to an increase in pre-tax income. Income taxes attributable to operations decreased in 2001 due to the effect of the disallowance of COLI interest deductions in 2000 offset in part by an increase in pre-tax operating income.
The Nonoperating Income decrease for 2002 was due primarily to a decrease in net power trading gains driven by a decline in market prices. Nonoperating Expenses decreased as a result of decreased trading incentives. The increase in Nonoperating Income and Nonoperating Expenses for 2001 is due to considerable increases in the level of activity in the wholesale business's trading transactions outside of the AEP System's traditional marketing area.
Interest Charges for 2002 decreased primarily as a result of lower AEP money pool balances and interest rates and the retirement of first mortgage bonds in 2001. Interest charges decreased in 2001 primarily due to the effect of recognizing in 2000 previously deferred interest payments to the IRS related to the COLI disallowances and interest on resultant state income tax deficiencies. Additionally, the decrease in 2001 is due to the retirement of first mortgage bonds in 2000.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
---------------------------------
Year Ended December 31,
---------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING REVENUES:
Wholesale Electricity $1,033,904 $1,017,938 $1,029,657
Energy Delivery 594,089 595,036 574,918
Sales to AEP Affiliates 186,477 171,285 154,678
---------- ---------- ----------
Total Operating Revenues 1,814,470 1,784,259 1,759,253
---------- ---------- ----------
OPERATING EXPENSES:
Fuel 430,963 351,557 369,161
Purchased Power:
Wholesale Electricity 57,091 42,092 24,720
AEP Affiliates 234,597 346,878 355,774
Other Operation 269,426 260,518 279,114
Maintenance 122,209 132,373 124,493
Depreciation and Amortization 189,335 180,393 163,089
Taxes Other Than Income Taxes 95,249 99,878 111,692
Income Taxes 113,537 95,584 130,056
---------- ---------- ----------
Total Operating Expenses 1,512,407 1,509,273 1,558,099
---------- ---------- ----------
OPERATING INCOME 302,063 274,986 201,154
NONOPERATING INCOME 29,278 49,507 31,204
NONOPERATING EXPENSES 11,783 41,500 16,329
NONOPERATING INCOME TAX EXPENSE (BENEFIT) (2,611) 1,139 3,123
INTEREST CHARGES 116,677 120,036 148,000
---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 205,492 161,818 64,906
EXTRAORDINARY GAIN - DISCONTINUANCE OF
REGULATORY ACCOUNTING FOR GENERATION
(Inclusive of Tax Benefit of $7,872,000) - - 8,938
---------- ---------- ----------
NET INCOME 205,492 161,818 73,844
PREFERRED STOCK DIVIDEND REQUIREMENTS 2,897 2,011 2,504
---------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $202,595 $159,807 $ 71,340
======== ======== ========
Consolidated Statements of Comprehensive Income
Year Ended December 31,
------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
NET INCOME $205,492 $161,818 $73,844
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign Currency Exchange Rate Hedge (1,580) (340) -
Minimum Pension Liability (70,162) - -
-------- -------- -------
COMPREHENSIVE INCOME $133,750 $161,478 $73,844
======== ======== =======
See Notes to Financial Statements beginning on page L-1.
|
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
--------------------------------------------
Year Ended December 31,
---------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
Retained Earnings January 1 $150,797 $120,584 $175,854
Net Income 205,492 161,818 73,844
-------- -------- --------
356,289 282,402 249,698
-------- -------- --------
Deductions:
Cash Dividends Declared:
Common Stock 92,952 129,594 126,612
Cumulative Preferred Stock:
4-1/2% Series 801 801 811
5.90% Series 278 278 307
5.92% Series 364 364 364
6.85% Series - - 289
-------- -------- --------
Total Cash Dividends Declared 94,395 131,037 128,383
Capital Stock Expense 1,455 568 731
-------- -------- --------
Total Deductions 95,850 131,605 129,114
-------- -------- --------
Retained Earnings December 31 $260,439 $150,797 $120,584
======== ======== ========
See Notes to Financial Statements beginning on page L-1.
|
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
---------------------------
December 31,
------------------------------
2002 2001
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,245,945 $2,093,532
Transmission 1,218,108 1,222,226
Distribution 1,951,804 1,887,020
General 272,901 257,957
Construction Work in Progress 206,545 203,922
---------- ----------
Total Electric Utility Plant 5,895,303 5,664,657
Accumulated Depreciation and Amortization 2,424,607 2,296,481
---------- ----------
NET ELECTRIC UTILITY PLANT 3,470,696 3,368,176
---------- ----------
OTHER PROPERTY AND INVESTMENTS 54,653 53,736
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 115,748 119,638
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 4,285 13,663
Accounts Receivable:
Customers 132,266 113,371
Affiliated Companies 122,665 63,368
Miscellaneous 28,629 11,847
Allowance for Uncollectible Accounts (13,439) (1,877)
Fuel Inventory 53,646 56,699
Materials and Supplies 59,886 59,849
Accrued Utility Revenues 30,948 30,907
Energy Trading and Derivative Contracts 94,238 137,742
Prepayments and Other 13,396 16,018
---------- ----------
TOTAL CURRENT ASSETS 526,520 501,587
---------- ----------
REGULATORY ASSETS 395,553 397,383
---------- ----------
DEFERRED CHARGES 64,677 42,265
---------- ----------
TOTAL ASSETS $4,627,847 $4,482,785
========== ==========
See Notes to Financial Statements beginning on page L-1.
|
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
December 31,
-------------------------------
2002 2001
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 30,000,000 Shares
Outstanding - 13,499,500 Shares $ 260,458 $ 260,458
Paid-in Capital 717,242 715,786
Accumulated Other Comprehensive Income (Loss) (72,082) (340)
Retained Earnings 260,439 150,797
---------- ----------
Total Common Shareowner's Equity 1,166,057 1,126,701
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 17,790 17,790
Subject to Mandatory Redemption 10,860 10,860
Long-term Debt 1,738,854 1,476,552
---------- ----------
TOTAL CAPITALIZATION 2,933,561 2,631,903
---------- ----------
OTHER NONCURRENT LIABILITIES 173,438 84,104
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 155,007 80,007
Advances From Affiliates 39,205 291,817
Accounts Payable - General 141,546 127,597
Accounts Payable - Affiliated Companies 98,374 84,518
Taxes Accrued 29,181 55,583
Customer Deposits 26,186 13,177
Interest Accrued 22,437 21,770
Energy Trading and Derivative Contracts 69,001 121,161
Other 79,832 79,089
---------- ----------
Total CURRENT LIABILITIES 660,769 874,719
---------- ----------
DEFERRED INCOME TAXES 701,801 703,575
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 33,691 38,328
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 44,517 60,518
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 80,070 89,638
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $4,627,847 $4,482,785
========== ==========
See Notes to Financial Statements beginning on page L-1.
|
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
-------------------------------------
Year Ended December 31,
-----------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 205,492 $ 161,818 $73,844
Adjustments for Noncash Items:
Depreciation and Amortization 189,335 180,505 163,202
Deferred Income Taxes 16,777 42,498 8,602
Deferred Investment Tax Credits (4,637) (4,765) (4,915)
Deferred Power Supply Costs (net) 6,365 1,411 (84,408)
Mark-to-Market of Energy Trading Contracts (21,151) (68,254) (1,843)
Provision for Rate Refunds - - (4,818)
Extraordinary Gain - - (8,938)
Change in Certain Current Assets and Liabilities:
Accounts Receivable (net) (83,412) 134,099 (166,911)
Fuel, Materials and Supplies 3,016 (19,957) 18,487
Accrued Utility Revenues (41) 35,592 (13,081)
Accounts Payable 27,805 (45,073) 159,369
Taxes Accrued (26,402) (7,675) 14,220
Revenue Refunds Accrued - - 181
Incentive Plan Accrued (858) (2,451) 10,662
Disputed Tax and Interest Related to COLI - - 72,440
Change in Operating Reserves (3,190) (5,358) (19,770)
Rate Stabilization Deferral - - 75,601
Change in Other Assets (43,337) 19,418 (13,021)
Change in Other Liabilities 14,948 (27,954) 9,817
--------- --------- ---------
Net Cash Flows From Operating Activities 280,710 393,854 288,720
--------- --------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (276,549) (306,046) (199,285)
Proceeds From Sales of Property and Other 1,074 1,182 159
Net Cost of Removal and Other - (8,434) (7,500)
--------- --------- ---------
Net Cash Flows Used For Investing
Activities (275,475) (313,298) (206,626)
--------- --------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 647,401 124,588 74,788
Retirement of Cumulative Preferred Stock - - (9,924)
Retirement of Long-term Debt (315,007) (175,000) (136,166)
Change in Short-term Debt (net) - (191,495) 68,015
Change in Advances From Affiliates (252,612) 300,204 (8,387)
Dividends Paid on Common Stock (92,952) (129,594) (126,612)
Dividends Paid on Cumulative Preferred Stock (1,443) (1,443) (1,938)
--------- --------- ---------
Net Cash Flows Used For
Financing Activities (14,613) (72,740) (140,224)
--------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (9,378) 7,816 (58,130)
Cash and Cash Equivalents January 1 13,663 5,847 63,977
--------- --------- ---------
Cash and Cash Equivalents December 31 $ 4,285 $13,663 $ 5,847
========= ======= =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $111,528,000, $117,283,000
and $124,579,000 and for income taxes was $125,120,000, $56,981,000 and
$63,682,000 in 2002, 2001 and 2000, respectively. There were no noncash
acquisitions under capital leases in 2002. In 2001 and 2000, non cash
acquisitions under capital leases were $2,510,000 and $14,116,000, respectively.
See Notes to Financial Statements beginning on page L-1.
|
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
-----------------------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY $1,166,057 $1,126,701
---------- ----------
PREFERRED STOCK: No par value - authorized shares 8,000,000
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2002 (a) Year Ended December 31, December 31, 2002
------ ------------ ---------------------------- -----------------
2002 2001 2000
---- ---- ----
Not Subject to Mandatory Redemption (b):
4-1/2% $110 6 - 7,011 177,899 17,790 17,790
---------- ----------
Subject to Mandatory Redemption (b):
5.90% (c) - - 10,000 47,100 4,710 4,710
5.92% (c) - - - 61,500 6,150 6,150
---------- ----------
10,860 10,860
---------- ----------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 489,697 639,365
Installment Purchase Contracts 235,027 234,904
Senior Unsecured Notes 1,166,609 518,247
Junior Debentures - 161,507
Other Long-term Debt 2,528 2,536
Less Portion Due Within One Year (155,007) (80,007)
---------- ----------
Long-term Debt Excluding Portion Due Within One Year 1,738,854 1,476,552
---------- ----------
TOTAL CAPITALIZATION $2,933,561 $2,631,903
========== ==========
(a) The cumulative preferred stock is callable at the price indicated plus
accrued dividends. The involuntary liquidation preference is $100 per
share. The aggregate involuntary liquidation price for all shares of
cumulative preferred stock may not exceed $300 million. The unissued shares
of the cumulative preferred stock may or may not possess mandatory
redemption characteristics upon issuance.
(b) The sinking fund provisions of each series subject to mandatory redemption
have been met by shares purchased in advance of the due date.
(c) Commencing in 2003 and continuing through 2007 APCo may redeem at $100 per
share 25,000 shares of the 5.90% series and 30,000 shares of the 5.92%
series outstanding under sinking fund provisions at its option and all
outstanding shares must be redeemed in 2008. Shares previously redeemed may
be applied to meet the sinking fund requirement.
See Notes to Financial Statements beginning on page L-1.
|
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
--------------------------
First mortgage bonds outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
7.38 2002 - August 15 $ - $ 50,000
7.40 2002 - December 1 - 30,000
6.65 2003 - May 1 - 40,000
6.85 2003 - June 1 - 30,000
6.00 2003 - November 1 30,000 30,000
7.70 2004 - September 1 21,000 21,000
7.85 2004 - November 1 50,000 50,000
8.00 2005 - May 1 50,000 50,000
6.89 2005 - June 22 30,000 30,000
6.80 2006 - March 1 100,000 100,000
8.50 2022 - December 1 70,000 70,000
7.80 2023 - May 1 30,237 30,237
7.15 2023 - November 1 20,000 20,000
7.125 2024 - May 1 45,000 45,000
8.00 2025 - June 1 45,000 45,000
Unamortized Discount (1,540) (1,872)
-------- --------
Total $489,697 $639,365
======== ========
First mortgage bonds are secured by a first mortgage lien on electric utility
plant. Certain supplemental indentures to the first mortgage lien contain
maintenance and replacement provisions requiring the deposit of cash or bonds
with the trustee, or in lieu thereof, certification of unfunded property
additions.
Installment purchase contracts have been entered into, in connection with the
issuance of pollution control revenue bonds, by governmental authorities as
follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
Industrial Development
Authority of
Russell County, Virginia:
7.70 2007 - November 1 $ 17,500 $ 17,500
5.00 2021 - November 1 19,500 19,500
Putnam County, West Virginia:
5.45 2019 - June 1 40,000 40,000
6.60 2019 - July 1 30,000 30,000
Mason County, West Virginia:
7-7/8 2013 - November 1 10,000 10,000
6.85 2022 - June 1 40,000 40,000
6.60 2022 - October 1 50,000 50,000
6.05 2024 - December 1 30,000 30,000
Unamortized Discount (1,973) (2,096)
-------- --------
Total $235,027 $234,904
======== ========
Under the terms of the installment purchase contracts, APCo is required to pay
amounts sufficient to enable the payment of interest on and the principal of (at
stated maturities and upon mandatory redemptions) related pollution control
revenue bonds issued to finance the construction of pollution control facilities
at certain plants.
Senior unsecured notes outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
(a) 2003 - August 20 $ 125,000 $125,000
7.45 2004 - November 1 50,000 50,000
4.80 2005 - June 15 450,000 -
4.32 2007 - November 12 200,000 -
6.60 2009 - May 1 150,000 150,000
7.20 2038 - March 31 100,000 100,000
7.30 2038 - June 30 100,000 100,000
Unamortized Discount (8,391) (6,753)
Total $1,166,609 $518,247
========== ========
(a) A floating interest rate is determined monthly. The rate on December
31, 2002 and 2001 was 2.167% and 2.839%, respectively.
Junior debentures outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
8-1/4% Series A due
2026 - September 30 $ - $ 75,000
8% Series B due 2027
- March 31 - 90,000
Unamortized Discount - (3,493)
-------- --------
Total $ - $161,507
======== ========
At December 31, 2002, future annual long-term debt payments are as follows:
Amount
------
(in thousands)
2003 $ 155,007
2004 121,008
2005 530,010
2006 100,011
2007 217,513
Later Years 782,216
----------
Total Principal Amount 1,905,765
Unamortized Discount (11,904)
----------
Total $1,893,861
==========
|
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Index to Combined Notes to Consolidated Financial Statements
------------------------------------------------------------
The notes to APCo's consolidated financial statements are combined with the
notes to financial statements for AEP and its other subsidiary registrants.
Listed below are the combined notes that apply to APCo. The combined footnotes
begin on page L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Extraordinary Items and Cumulative Effect Note 2
Effects of Regulation Note 7
Customer Choice and Industry Restructuring Note 8
Commitments and Contingencies Note 9
Guarantees Note 10
Sustained Earnings Improvement Initiative Note 11
Asset Impairments and Investments Value Losses Note 13
Benefit Plans Note 14
Business Segments Note 16
Risk Management, Financial Instruments
and Derivatives Note 17
Income Taxes Note 18
Supplementary Information Note 20
Leases Note 22
Lines of Credit and Sale of Receivables Note 23
Unaudited Quarterly Financial Information Note 24
Related Party Transactions Note 29
|
INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Appalachian Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Appalachian Power Company and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Appalachian Power Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. /s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 |
COLUMBUS SOUTHERN POWER COMPANY
AND SUBSIDIARIES
|
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
------------------------------------
Year Ended December 31,
--------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,400,160 $1,350,319 $1,304,409 $1,190,997 $1,187,745
Operating Expenses 1,180,381 1,098,142 1,108,532 968,207 975,534
---------- ---------- ---------- ---------- ----------
Operating Income 219,779 252,177 195,877 222,790 212,211
Nonoperating Items,
Net 15,263 7,738 5,153 2,709 (1,343)
Interest Charges 53,869 68,015 80,828 75,229 77,824
---------- ---------- --------- ---------- ----------
Income Before
Extraordinary Item 181,173 191,900 120,202 150,270 133,044
Extraordinary Loss - (30,024) (25,236) - -
---------- ---------- --------- ---------- ----------
Net Income 181,173 161,876 94,966 150,270 133,044
Preferred Stock
Dividend
Requirements 1,332 1,095 1,783 2,131 2,131
---------- ---------- --------- ---------- ----------
Earnings Applicable to
Common Stock $179,841 $160,781 $93,183 $148,139 $130,913
======== ======== ======= ======== ========
Year Ended December 31,
--------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $3,467,626 $3,354,320 $3,266,794 $3,151,619 $3,053,565
Accumulated Depreciation 1,465,174 1,377,032 1,299,697 1,210,994 1,134,348
---------- ---------- ---------- ---------- ----------
Net Electric Utility
Plant $2,002,452 $1,977,288 $1,967,097 $1,940,625 $1,919,217
========== ========== ========== ========== ==========
Total Assets $2,753,240 $2,722,388 $3,877,491 $2,808,623 $2,681,690
========== ========== ========== ========== ==========
Common Stock and
Paid-in Capital $616,410 $615,395 $614,380 $613,899 $613,518
Accumulated Other
Comprehensive Income
(Loss) (59,357) - - - -
Retained Earnings 290,611 176,103 99,069 246,584 186,441
---------- ---------- ---------- ---------- ----------
Total Common
Shareholder's Equity $847,664 $791,498 $713,449 $860,483 $799,959
======== ======== ======== ======== ========
Cumulative Preferred
Stock - Subject to
Mandatory
Redemption (a) $ - $ 10,000 $ 15,000 $ 25,000 $ 25,000
======== ======== ======== ======== ========
Long-term Debt (a) $621,626 $791,848 $899,615 $924,545 $959,786
======== ======== ======== ======== ========
Obligations Under
Capital Leases (a) $ 27,610 $ 34,887 $ 42,932 $ 40,270 $ 42,362
======== ======== ======== ======== ========
Total Capitalization and
Liabilities $2,753,240 $2,722,388 $3,877,491 $2,808,623 $2,681,690
========== ========== ========== ========== ==========
(a) Including portion due within one year.
|
Columbus Southern Power Company is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 689,000 retail customers in central and southern Ohio. CSPCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. CSPCo also sells wholesale power to municipalities.
The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing AEP Power Pool revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each companies percentage share of AEP Power Pool revenues and costs.
Net Income increased $19 million or 12% in 2002 due to reduced interest charges and a $30 million extraordinary loss recorded in 2001 to recognize prepaid Ohio excise taxes stranded by Ohio deregulation offset by higher operating expenses.
Operating Revenues increased in 2002 mainly as a result of increased residential and commercial sales due to demand caused by weather conditions.
Changes in the components of Operating Revenues were:
Increase (Decrease)
From Previous Year
------------------
(dollars in millions)
Amount %
------ -
Retail* $51 8
Wholesale Marketing 3 2
Unrealized MTM (4) (22)
Other 1 3
---
Wholesale Electricity* 51 6
Energy Delivery* 9 2
Sales to AEP Affiliates (10) (15)
----
Total Revenues $50 4
===
|
* Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.
During the summer months, cooling degree days increased 35%. For the fall season, heating degree days increased 34%. This reflects a return to more normal weather conditions since the weather experienced in 2001 was abnormally mild.
Operating Expenses increased in 2002 mainly as a result of purchased power, operating expenses and state taxes.
Changes in the components of Operating Expenses were:
Increase (Decrease)
From Previous Year
------------------
(dollars in millions)
Amount %
------ -
Fuel $10 6
Wholesale Purchased Power 4 37
AEP Affiliates Purchased
Power 18 6
Other Operation Expenses 18 8
Maintenance Expense (2) (4)
Depreciation and
Amortization 4 3
Taxes Other Than
Income Taxes 25 22
Income Taxes 5 5
---
Total $82 7
===
|
Fuel cost increased as a result of a 10% increase in generation partially offset by a slight cost decrease per ton of coal consumed.
Wholesale Purchased Power increased in 2002 due to increased purchases from third parties for resale to wholesale customers and to meet internal demand.
Expenses related to AEP Affiliates Purchased Power increased due to greater system pool capacity charges.
The increase in Other Operation expenses was attributable to a number of factors: higher OPEB post retirement costs as a result of higher medical cost and lower investment performance, 2002 Sustained Earnings Initiative Expenses, and the 2001 reversal of a quality of service liability accrual. The increase was partially offset by a reduction in energy trading overheads reflecting reduced marketing activity.
The increase in Taxes Other Than Income Taxes in 2002 is due to an increase in property taxes and a full year of the state excise tax which replaced the state gross receipts tax during 2001.
The increase in Income Taxes is predominately due to an increase in state taxes as a result of the State of Ohio's tax legislation resulting from utility deregulation. This increase was offset in part by a decrease in federal taxes due to a decrease in pre-tax operating income.
The decrease in Nonoperating Income in 2002 is due to a reduction in net gains from AEP Power Pool trading transactions outside of the AEP System's traditional marketing area. The AEP Power Pool enters into power trading transactions for the purchase and sale of electricity and for options, futures and swaps. CSPCo's share of the AEP Power Pool's gains and losses from forward electricity trading transactions outside of the AEP System traditional marketing area and for speculative financial transactions (options, futures, swaps) is included in Nonoperating Income. The decrease reflects a reduction in electricity prices and margins due to a decrease in demand.
The decrease in Nonoperating Expenses in 2002 was due to a decrease in energy trading incentive compensation.
Nonoperating Income Tax Expense increased in 2002 due to increase in pre-tax nonoperating income.
Interest Charges decreased in 2002 primarily due to a decrease in the outstanding balance of long-term debt since the first quarter of 2001, the refinancing of debt at favorable interest rates and a reduction in short-term interest rates.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
---------------------------------
Year Ended December 31,
---------------------------------------------------
2002 2001 2000
---- ---- ----
OPERATING REVENUES:
Wholesale Electricity $ 850,680 $ 799,589 $ 856,998
Energy Delivery 492,278 483,219 398,046
Sales to AEP Affiliates 57,202 67,511 49,365
---------- ---------- ----------
Total Operating Revenues 1,400,160 1,350,319 1,304,409
---------- ---------- ----------
OPERATING EXPENSES:
Fuel 185,086 175,153 189,155
Purchased Power:
Wholesale Electricity 15,023 10,957 9,879
AEP Affiliates 310,605 292,199 287,750
Other Operation 237,802 219,497 219,840
Maintenance 60,003 62,454 69,676
Depreciation and Amortization 131,624 127,364 99,640
Taxes Other Than Income Taxes 136,024 111,481 123,223
Income Taxes 104,214 99,037 109,369
---------- ---------- ----------
TOTAL OPERATING EXPENSES 1,180,381 1,098,142 1,108,532
---------- ---------- ----------
OPERATING INCOME 219,779 252,177 195,877
NONOPERATING INCOME 26,360 32,756 20,580
NONOPERATING EXPENSES 4,308 21,095 8,070
NONOPERATING INCOME TAX EXPENSE 6,789 3,923 7,357
INTEREST CHARGES 53,869 68,015 80,828
---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 181,173 191,900 120,202
EXTRAORDINARY LOSS - DISCONTINUANCE OF
REGULATORY ACCOUNTING FOR GENERATION - Net of
tax (Note 2) - (30,024) (25,236)
---------- ---------- ----------
NET INCOME 181,173 161,876 94,966
PREFERRED STOCK DIVIDEND REQUIREMENTS 1,332 1,095 1,783
---------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $179,841 $160,781 $ 93,183
======== ======== ========
Consolidated Statements of Comprehensive Income
-----------------------------------------------
Year Ended December 31,
-------------------------------------------------
2002 2001 2000
---- ---- ----
NET INCOME $181,173 $161,876 $94,966
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign Currency Exchange Rate Hedge (267) - -
Minimum Pension Liability (59,090) - -
-------- -------- -------
COMPREHENSIVE INCOME $121,816 $161,876 $94,966
======== ======== =======
The common stock of the CSPCo is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
|
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
--------------------------------------------
Year Ended December 31,
--------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
Retained Earnings January 1 $176,103 $ 99,069 $246,584
Net Income 181,173 161,876 94,966
-------- -------- --------
357,276 260,945 341,550
-------- -------- --------
Deductions:
Cash Dividends Declared:
Common Stock 65,300 82,952 240,600
Cumulative Preferred Stock - 7% Series 350 875 1,400
-------- -------- --------
Total Cash Dividends Declared 65,650 83,827 242,000
Capital Stock Expense 1,015 1,015 481
-------- -------- --------
Total Deductions 66,665 84,842 242,481
-------- -------- --------
Retained Earnings December 31 $290,611 $176,103 $ 99,069
======== ======== ========
See Notes to Financial Statements beginning on page L-1.
|
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
---------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $1,582,627 $1,574,506
Transmission 413,286 401,405
Distribution 1,208,255 1,159,105
General 165,025 146,732
Construction Work in Progress 98,433 72,572
---------- ----------
Total Electric Utility Plant 3,467,626 3,354,320
Accumulated Depreciation 1,465,174 1,377,032
---------- ----------
NET ELECTRIC UTILITY PLANT 2,002,452 1,977,288
---------- ----------
OTHER PROPERTY AND INVESTMENTS 35,759 40,369
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 77,810 73,310
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 1,479 12,358
Advances to Affiliates 31,257 -
Accounts Receivable:
Customers 49,566 41,770
Affiliated Companies 54,518 63,470
Miscellaneous 22,005 16,968
Allowance for Uncollectible Accounts (634) (745)
Fuel 24,844 20,019
Materials and Supplies 40,339 38,984
Accrued Utility Revenues 12,671 7,087
Energy Trading Contracts 63,348 84,323
Prepayments and Other Current Assets 7,308 28,733
---------- ----------
TOTAL CURRENT ASSETS 306,701 312,967
---------- ----------
REGULATORY ASSETS 257,682 262,267
---------- ----------
DEFERRED CHARGES 72,836 56,187
---------- ----------
TOTAL ASSETS $2,753,240 $2,722,388
========== ==========
See Notes to Financial Statements beginning on page L-1.
|
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
December 31,
-----------
2002 2001
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 24,000,000 Shares
Outstanding - 16,410,426 Shares $ 41,026 $ 41,026
Paid-in Capital 575,384 574,369
Accumulated Other Comprehensive Income (Loss) (59,357) -
Retained Earnings 290,611 176,103
---------- ----------
Total Common Shareholder's Equity 847,664 791,498
Cumulative Preferred Stock - Subject to
Mandatory Redemption - 10,000
Long-term Debt - General 418,626 571,348
Long term Debt - Affiliated Companies 160,000 -
---------- ----------
TOTAL CAPITALIZATION 1,426,290 1,372,846
---------- ----------
OTHER NONCURRENT LIABILITIES 95,460 36,715
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - General 43,000 20,500
Long-term Debt Due Within One Year - Affiliated Companies - 200,000
Short-term Debt - Affiliated Companies 290,000 -
Advances from Affiliates - 181,384
Accounts Payable - General 89,736 60,689
Accounts Payable - Affiliated Companies 81,599 83,697
Taxes Accrued 112,172 116,364
Interest Accrued 9,798 10,907
Energy Trading Contracts 46,375 72,082
Other 36,790 36,305
---------- ----------
TOTAL CURRENT LIABILITIES 709,470 781,928
---------- ----------
DEFERRED INCOME TAXES 437,771 443,722
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 33,907 37,176
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 29,926 37,101
---------- ----------
DEFERRED CREDITS 20,416 12,900
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $2,753,240 $2,722,388
========== ==========
See Notes to Financial Statements beginning on page L-1.
|
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
-------------------------------------
Year Ended December 31,
-----------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 181,173 $ 161,876 $ 94,966
Adjustments for Noncash Items:
Depreciation and Amortization 131,753 128,500 100,182
Deferred Income Taxes 23,292 24,108 (4,063)
Deferred Investment Tax Credits (3,269) (4,058) (3,482)
Deferred Fuel Costs (net) - - 5,352
Mark to Market of Energy Trading Contracts (16,667) (44,680) (3,393)
Extraordinary Loss - 30,024 25,236
Change in Certain Current Assets and Liabilities:
Accounts Receivable (net) (3,992) 19,987 (29,737)
Fuel, Materials and Supplies (6,180) (7,780) 11,957
Accrued Utility Revenues (5,584) 2,551 38,479
Accounts Payable 26,949 (16,249) 81,284
Disputed Tax and Interest Related to COLI - - 39,483
Change in Other Assets (8,027) (42,066) (121,115)
Change in Other Liabilities (22,448) (18,769) 132,441
--------- --------- ---------
Net Cash Flows From Operating Activities 297,000 233,444 367,590
--------- --------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (136,800) (132,532) (127,987)
Proceeds From Sales and Leaseback
Transactions and Other 730 10,841 1,560
--------- --------- ---------
Net Cash Flows Used For Investing
Activities (136,070) (121,691) (126,427)
--------- --------- ---------
FINANCING ACTIVITIES:
Change in Advances from Affiliates (net) (212,641) 92,652 88,732
Issuance of Affiliated Long-term Debt 160,000 200,000 -
Retirement of Preferred Stock (10,000) (5,000) (10,000)
Retirement of General Long-term Debt (133,343) (314,733) (25,274)
Retirement of Affiliated Long-term Debt (200,000) - -
Change in Short-term Debt (net) 290,000 - (45,500)
Dividends Paid on Common Stock (65,300) (82,952) (240,600)
Dividends Paid on Cumulative Preferred Stock (525) (962) (1,575)
--------- --------- ---------
Net Cash Flows Used For
Financing Activities (171,809) (110,995) (234,217)
--------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (10,879) 758 6,946
Cash and Cash Equivalents January 1 12,358 11,600 4,654
--------- --------- ---------
Cash and Cash Equivalents December 31 $ 1,479 $ 12,358 $ 11,600
========= ========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $53,514,000, $68,596,000
and $68,506,000 and for income taxes was $117,591,000, 80,485,000 and
$81,109,000 in 2002, 2001 and 2000, respectively. Noncash acquisitions under
capital leases were $1,019,000 and $10,777,000 in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
|
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
-----------------------------------------
December 31,
-----------
2002 2001
(in thousands)
COMMON SHAREHOLDER'S EQUITY $ 847,664 $ 791,498
---------- ----------
PREFERRED STOCK: $100 par value - authorized shares 2,500,000
$25 par value - authorized shares 7,000,000
Shares
Number of Shares Redeemed Outstanding
Series Year Ended December 31, December 31, 2002
------ ---------------------------- -----------------
2002 2001 2000
---- ---- ----
Subject to Mandatory Redemption:
7.00% 100,000 50,000 100,000 - - 10,000
---------- ----------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 222,797 243,197
Installment Purchase Contracts 91,275 91,220
Senior Unsecured Notes 147,554 147,458
Notes - Affiliated 160,000 200,000
Junior Debentures - 109,973
Less Portion Due Within One Year ( 43,000) (220,500)
---------- ----------
Total Long-term Debt Excluding Portion Due Within One Year 578,626 571,348
---------- ----------
TOTAL CAPITALIZATION $1,426,290 $1,372,846
========== ==========
See Notes to Financial Statements beginning on page L-1.
|
% Rate Due
7.25 2002 - October 1 $ - $ 14,000
7.15 2002 - November 1 - 6,500
6.80 2003 - May 1 13,000 13,000
6.60 2003 - August 1 25,000 25,000
6.10 2003 - November 1 5,000 5,000
6.55 2004 - March 1 26,500 26,500
6.75 2004 - May 1 26,000 26,000
8.70 2022 - July 1 2,000 2,000
8.55 2022 - August 1 15,000 15,000
8.40 2022 - August 15 14,000 14,000
8.40 2022 - October 15 13,000 13,000
7.90 2023 - May 1 40,000 40,000
7.75 2023 - August 1 33,000 33,000
7.60 2024 - May 1 11,000 11,000
Unamortized Discount (703) (803)
-------- --------
Total $222,797 $243,197
======== ========
|
First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions.
Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by the Ohio Air Quality Development Authority:
% Rate Due
6-3/8 2020 - December 1 $48,550 $48,550
6-1/4 2020 - December 1 43,695 43,695
Unamortized Discount (970) (1,025)
------- -------
Total $91,275 $91,220
======= =======
|
Under the terms of the installment purchase contracts, CSPCo is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at the Zimmer Plant.
Senior unsecured notes outstanding were as follows:
% Rate Due
------ ------------------
6.85 2005 - October 3 $ 36,000 $ 36,000
6.51 2008 - February 1 52,000 52,000
6.55 2008 - June 26 60,000 60,000
Unamortized Discount (446) (542)
-------- --------
Total $147,554 $147,458
======== ========
|
Notes payable to parent company were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
(a) 2002 - Sept 25 $ - $200,000
6.501% 2006 - May 15 160,000 -
-------- --------
Total $160,000 $200,000
======== ========
|
(a) Redemed 9/25/02
Junior debentures outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
------ ------------------
8-3/8 2025 - Sept 30 $ - $ 72,843
7.92 2027 - March 31 - 40,000
Unamortized Discount - (2,870)
-------- --------
Total $ - $109,973
======== ========
|
At December 31, 2002, future annual long-term debt payments are as follows:
Amount
------
(in thousands)
2003 $ 43,000
2004 52,500
2005 36,000
2006 160,000
2007 -
Later Years 332,245
--------
Total Principal Amount 623,745
Unamortized Discount (2,119)
--------
Total $621,626
|
The notes to CSPCo's consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to CSPCo. The combined footnotes begin on page L-1.
Combined
Footnote
Reference
---------
Significant Accounting Policies Note 1
Extraordinary Items and Cumulative Effect Note 2
Effects of Regulation Note 7
Customer Choice and Industry Restructuring Note 8
Commitments and Contingencies Note 9
Guarantees Note 10
Sustained Earnings Improvement Initiative Note 11
Asset Impairments and Investment Value Losses Note 13
Benefit Plans Note 14
Business Segments Note 16
Risk Management, Financial Instruments and Derivatives Note 17
Income Taxes Note 18
Supplementary Information Note 20
Leases Note 22
Lines of Credit and Sale of Receivables Note 23
Unaudited Quarterly Financial Information Note 24
Jointly Owned Electric Utility Plant Note 28
Related Party Transactions Note 29
|
INDEPENDENT AUDITORS' REPORT
To the Shareholder and Board of Directors of Columbus Southern Power Company:
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Columbus Southern Power Company and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Columbus Southern Power Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 |
INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
------------------------------------
Year Ended December 31,
-----------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,526,764 $1,526,997 $1,488,209 $1,351,666 $1,405,794
Operating Expenses 1,375,575 1,367,292 1,522,911 1,243,014 1,239,787
---------- ---------- ---------- ---------- ----------
Operating Income
(Loss) 151,189 159,705 (34,702) 108,652 166,007
Nonoperating Items,
Net 16,726 9,730 9,933 4,530 (839)
Interest Charges 93,923 93,647 107,263 80,406 68,540
---------- ---------- ---------- ---------- ----------
Net Income (Loss) 73,992 75,788 (132,032) 32,776 96,628
Preferred Stock
Dividend
Requirements 4,601 4,621 4,624 4,885 4,824
---------- ---------- --------- ---------- ----------
Earnings (Loss)
Applicable to
Common Stock $ 69,391 $ 71,167 $(136,656) $ 27,891 $ 91,804
========== ========== ========= ========== ==========
December 31,
-----------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility
Plant $5,029,958 $4,923,721 $4,871,473 $4,770,027 $4,631,848
Accumulated
Depreciation and
Amortization 2,568,604 2,436,972 2,280,521 2,194,397 2,081,355
---------- ---------- ---------- ---------- ----------
Net Electric Utility
Plant $2,461,354 $2,486,749 $2,590,952 $2,575,630 $2,550,493
========== ========== ========== ========== ==========
Total Assets $4,587,191 $4,394,062 $5,774,108 $4,575,210 $4,148,523
========== ========== ========== ========== ==========
Common Stock and
Paid-in Capital $ 915,144 $ 789,800 $ 789,656 $ 789,323 $ 789,189
Accumulated Other
Comprehensive Income
(Loss) (40,487) (3,835) - - -
Retained Earnings 143,996 74,605 3,443 166,389 253,154
---------- ---------- ---------- ---------- ----------
Total Common
Shareholder's Equity $1,018,653 $ 860,570 $ 793,099 $ 955,712 $1,042,343
========== ========== ========== ========== ==========
Cumulative Preferred
Stock:
Not Subject to
Mandatory
Redemption $ 8,101 $ 8,736 $ 8,736 $ 9,248 $ 9,273
Subject to
Mandatory
Redemption (a) 64,945 64,945 64,945 64,945 68,445
---------- ---------- ---------- ---------- ----------
Total Cumulative
Preferred Stock $ 73,046 $ 73,681 $ 73,681 $ 74,193 $ 77,718
========== ========== ========== ========== ==========
Long-term Debt (a) $1,617,062 $1,652,082 $1,388,939 $1,324,326 $1,175,789
========== ========== ========== ========== ==========
Obligations Under
Capital Leases (a) $ 50,848 $ 61,933 $ 163,173 $ 187,965 $ 186,427
========== ========== ========== ========== ==========
Total Capitalization
And Liabilities $4,587,191 $4,394,062 $5,774,108 $4,575,210 $4,148,523
========== ========== ========== ========== ==========
(a) Including portion due within one year. (a)
|
I&M is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 571,000 retail customers in its service territory in northern and eastern Indiana and a portion of southwestern Michigan. As a member of the AEP Power Pool, I&M shares the revenues and the costs of the AEP Power Pool's wholesale sales to neighboring utilities and power marketers. I&M also sells wholesale power to municipalities and electric cooperatives.
The cost of the AEP Power Pool's generating capacity is allocated among its members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is each company's member load ratio (MLR) which determines each company's percentage share of revenues and costs.
Under unit power agreements, I&M purchases AEGCo's 50% share of the 2,600 MW Rockport Plant capacity unless it is sold to other utilities. AEGCo is an affiliate that is not a member of the AEP Power Pool. An agreement between AEGCo and KPCo provides for the sale of 390 MW of AEGCo's Rockport Plant capacity to KPCo through 2004. The KPCo agreement extends until December 31, 2009 for Rockport Unit 1 and until December 7, 2022 for Rockport Plant Unit 2 if AEP's restructuring settlement agreement filed with the FERC becomes operative. Therefore, I&M purchases 910 MW of AEGCo's 50% share of Rockport Plant capacity.
During 2002 Net Income decreased by $2 million due to increased operations and maintenance costs incurred as part of planned and unplanned outages at Cook Plant and Rockport Plant.
During 2000 both of the Cook Plant nuclear units were successfully restarted after being shutdown in September 1997 due to questions regarding the operability of certain safety systems which arose during a NRC architect engineer design inspection (see Note 5).
As a result of costs incurred in 2000 to restart the Cook Plant and a disallowance of interest deductions for a corporate owned life insurance (COLI) program, Net Income increased in 2001 by $208 million. In February 2001 the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including I&M, in a suit over deductibility of interest claimed in AEP's consolidated tax return related to COLI. In 1998 and 1999 I&M paid the disputed taxes and interest attributable to the COLI interest deductions for the taxable years 1991-98 and deferred them. The deferrals were expensed and impacted Net Income in 2000.
Operating Revenues were flat in 2002 and increased 3% in 2001. The 2001 increase reflects increased sales to AEP affiliates through the AEP Power Pool. The following analyzes the changes in Operating Revenues:
(dollars in millions)
2002 2001
------------------------------
Amount % Amount %
------ - ------ -
Retail* $ 28.2 4 $ (2.3) N.M
Marketing 2.6 1 (12.0) (4)
Other 2.6 6 5.0 13
------ ------
Total
Wholesale
Electricity 33.4 3 (9.3) (1)
Energy
Delivery* 7.3 2 3.4 1
Sales to AEP
Affiliates (40.9) (16) 44.7 21
------ ------
Total $ (0.2) N.M. $ 38.8 3
====== ======
|
N.M. = Not Meaningful
*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The increase in Operating Revenues in 2001 is primarily due to increased sales to AEP affiliates reflecting increased availablility of the Cook Plant. The return to service of the Cook Plant units increased the amount of power I&M could sell to its affiliates in the AEP Power Pool.
Total Operating Expenses increased 1% in 2002 and decreased 10% in 2001. The 2001 decrease was primarily due to the unfavorable COLI tax ruling and costs related to the extended Cook Plant outage and restart efforts in 2000. The changes in the components of Operating Expenses were:
(dollars in millions)
2002 2001
-----------------------------
Amount % Amount %
------ - ------ -
Fuel $(10.6) (4) $ 39.2 19
Wholesale
Electricity
Purchases 4.7 25 4.9 36
AEP Affiliate
Purchases (4.5) (2) (27.2) (10)
Other Operation 13.6 3 (147.7) (25)
Maintenance 24.3 19 (92.6) (42)
Depreciation and
Amortization 3.8 2 9.3 6
Taxes Other Than
Income Taxes (7.8) (12) 4.9 8
Income Taxes (15.2) (28) 53.6 N.M.
------ -------
Total $ 8.3 1 $(155.6) (10)
====== =======
|
N.M. = Not Meaningful
Fuel expense decreased in 2002 due to lower average costs of fuel and a decline in nuclear generation. The increase in Fuel expense in 2001 reflects an increase in nuclear generation as the Cook Plant units returned to service following the extended outage.
Wholesale Electricity purchases increased in 2002 and 2001 due to increased purchases from third parties for sales for resale. AEP Affiliates purchases declined in 2002 due to lower purchases from AEGCo at lower costs. The decline in purchased power from AEP affiliates in 2001 reflects generation from the Cook Plant replacing purchases from the AEP Power Pool which declined 21%.
Other Operation expense increased in 2002 primarily due to higher costs for pensions, other benefits and insurance. The decrease in Other Operation and Maintenance expenses in 2001 was primarily due to the cessation of expenditures to prepare the Cook Plant nuclear units for restart with their return to service in 2000. Maintenance expense increased for nuclear maintenance costs incurred during refueling outages in 2002.
The increase in Depreciation and Amortization charges in 2001 reflects increased generation and distribution plant investments and amortization of I&M's share of deferred merger costs.
Due to a change in the Indiana property tax law which lowered the floor percentage for calculating tax liability, Taxes Other Than Income Taxes declined in 2002. Taxes Other than Income Taxes increased in 2001 due to higher real and personal property tax expense from the effect of a favorable accrual adjustment of amounts recorded in December 2000 to actual expenses.
Income Taxes attributable to operations decreased in 2002 due to a decrease in pre-tax operating income. The significant increase in Income Taxes attributable to operations in 2001 is due to an increase in pre-tax operating income.
The decrease in Nonoperating Income in 2002 is primarily due to decreased net gains on forward electricity trading transactions outside AEP's traditional marketing area. The increase in Nonoperating Income in 2001 is primarily due to increased net gains on forward electricity trading transactions outside AEP's traditional marketing area.
Nonoperating Expenses decreased in 2002 due to decreased trading overheads and traders' incentive compensation. Nonoperating Expenses increased in 2001 due to increased trading overheads and traders' incentive compensation.
The increase in Nonoperating Income Taxes in 2001 reflects the increase in nonoperating pre-tax income.
The decrease in 2001 Interest Charges reflects the recognition in 2000 of deferred interest payments to the IRS on disputed income taxes from the disallowance of tax deductions for COLI interest for the years 1991-1998.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
---------------------------------
Year Ended December 31,
-------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING REVENUES:
Wholesale Electricity $ 990,905 $ 957,548 $ 966,882
Energy Delivery 321,721 314,410 311,019
Sales to AEP Affiliates 214,138 255,039 210,308
---------- ---------- ----------
TOTAL OPERATING REVENUES 1,526,764 1,526,997 1,488,209
---------- ---------- ----------
OPERATING EXPENSES:
Fuel 239,455 250,098 210,870
Purchased Power:
Wholesale Electricity 23,443 18,707 13,785
AEP Affiliates 233,724 238,237 265,475
Other Operation 462,707 449,115 596,861
Maintenance 151,602 127,263 219,854
Depreciation and Amortization 168,070 164,230 154,920
Taxes other Than Income Taxes 57,721 65,518 60,622
Income Taxes 38,853 54,124 524
---------- ---------- ----------
TOTAL OPERATING EXPENSES 1,375,575 1,367,292 1,522,911
---------- ---------- ----------
OPERATING INCOME (LOSS) 151,189 159,705 (34,702)
NONOPERATING INCOME 93,739 97,810 76,499
NONOPERATING EXPENSES 71,029 83,037 62,377
NONOPERATING INCOME TAXES 5,984 5,043 4,189
INTEREST CHARGES 93,923 93,647 107,263
---------- ---------- ----------
NET INCOME (LOSS) 73,992 75,788 (132,032)
PREFERRED STOCK DIVIDEND REQUIREMENTS 4,601 4,621 4,624
---------- ---------- ---------
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $ 69,391 $ 71,167 $(136,656)
========== ========== =========
Consolidated Statements of Comprehensive Income
-----------------------------------------------
Year Ended December 31,
--------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
NET INCOME (LOSS) $ 73,992 $75,788 $(132,032)
OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Interest Rate Hedge 3,835 (3,835) -
Cash Flow Power Hedge (286) - -
Minimum Pension Liability (40,201) - -
-------- ------- ---------
COMPREHENSIVE INCOME (LOSS) $ 37,340 $71,953 $(132,032)
======== ======= =========
See Notes to Financial Statements beginning on page L-1.
|
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
--------------------------------------------
Year Ended December 31,
--------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
Retained Earnings January 1 $ 74,605 $ 3,443 $ 166,389
Net Income (Loss) 73,992 75,788 (132,032)
-------- -------- ---------
148,597 79,231 34,357
-------- -------- ---------
Deductions:
Cash Dividends Declared:
Common Stock - - 26,290
Cumulative Preferred Stock:
4-1/8% Series 229 229 230
4.56% Series 66 66 66
4.12% Series 52 72 74
5.90% Series 897 897 897
6-1/4% Series 1,203 1,203 1,203
6.30% Series 834 834 834
6-7/8% Series 1,186 1,186 1,186
-------- -------- ---------
Total Cash Dividends Declared 4,467 4,487 30,780
Capital Stock Expense 134 139 134
-------- -------- ---------
Total Deductions 4,601 4,626 30,914
-------- -------- ---------
Retained Earnings December 31 $143,996 $ 74,605 $ 3,443
======== ======== =======
See Notes to Financial Statements beginning on page L-1.
|
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
---------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,768,463 $2,758,160
Transmission 971,599 957,336
Distribution 921,835 900,921
General (including nuclear fuel) 220,137 233,005
Construction Work in Progress 147,924 74,299
---------- ----------
Total Electric Utility Plant 5,029,958 4,923,721
Accumulated Depreciation and Amortization 2,568,604 2,436,972
---------- ----------
NET ELECTRIC UTILITY PLANT 2,461,354 2,486,749
---------- ----------
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR
FUEL DISPOSAL TRUST FUNDS 870,754 834,109
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 83,265 82,898
---------- ----------
OTHER PROPERTY AND INVESTMENTS 120,941 127,977
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 3,237 16,804
Advances to Affiliates 191,226 46,309
Accounts Receivable:
Customers 67,333 60,864
Affiliated Companies 122,489 31,908
Miscellaneous 30,468 25,398
Allowance for Uncollectible Accounts (578) (741)
Fuel 32,731 28,989
Materials and Supplies 95,552 91,440
Energy Trading and Derivative Contracts 68,148 108,895
Accrued Utility Revenues 6,511 2,072
Prepayments and Other 11,899 6,497
---------- ----------
TOTAL CURRENT ASSETS 629,016 418,435
---------- ----------
REGULATORY ASSETS 348,212 408,927
---------- ----------
DEFERRED CHARGES 73,649 34,967
---------- ----------
TOTAL ASSETS $4,587,191 $4,394,062
========== ==========
See Notes to Financial Statements beginning on page L-1.
|
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
December 31,
-----------
2002 2001
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 2,500,000 Shares
Outstanding - 1,400,000 Shares $ 56,584 $ 56,584
Paid-in Capital 858,560 733,216
Accumulated Other Comprehensive Income (Loss) (40,487) (3,835)
Retained Earnings 143,996 74,605
---------- ----------
Total Common Shareholder's Equity 1,018,653 860,570
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 8,101 8,736
Subject to Mandatory Redemption 64,945 64,945
Long-term Debt 1,587,062 1,312,082
---------- ----------
TOTAL CAPITALIZATION 2,678,761 2,246,333
---------- ----------
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning 620,672 600,244
Other 138,965 87,025
---------- ----------
TOTAL OTHER NONCURRENT LIABILITIES 759,637 687,269
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 30,000 340,000
Accounts Payable - General 125,048 86,766
Accounts Payable - Affiliated Companies 93,608 43,956
Taxes Accrued 71,559 69,761
Interest Accrued 21,481 20,691
Obligations Under Capital Leases 8,229 10,840
Energy Trading and Derivative Contracts 48,568 93,413
Other 92,822 76,486
---------- ----------
TOTAL CURRENT LIABILITIES 491,315 741,913
---------- ----------
DEFERRED INCOME TAXES 356,197 400,531
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 97,709 105,449
---------- ----------
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 73,885 77,592
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 32,261 42,936
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 97,426 92,039
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $4,587,191 $4,394,062
========== ==========
See Notes to Financial Statements beginning on page L-1.
|
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
-------------------------------------
Year Ended December 31,
----------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income (Loss) $ 73,992 $ 75,788 $(132,032)
Adjustments for Noncash Items:
Depreciation and Amortization 168,070 166,360 163,391
Amortization (Deferral) of Incremental Nuclear
Refueling Outage Expenses (net) (26,577) 418 5,737
Amortization of Nuclear Outage Costs 40,000 40,000 40,000
Deferred Income Taxes (16,921) (29,205) (125,179)
Deferred Investment Tax Credits (7,740) (8,324) (7,854)
Unrecovered Fuel and Purchased Power Costs 37,501 37,501 37,501
Changes in Certain Current Assets
And Liabilities:
Accounts Receivable (net) (102,283) 64,841 (25,305)
Fuel, Materials and Supplies (7,854) (19,426) 10,743
Accrued Utility Revenues (4,439) (2,072) 44,428
Accounts Payable 87,934 (60,185) 85,056
Taxes Accrued 1,798 1,345 19,446
Mark-to-Market of Energy Trading and Derivatives Contracts (9,517) (62,647) 14,830
Disputed Tax and Interest Related to COLI - - 56,856
Regulatory Asset - Trading Losses (992) 8,493 (17,914)
Regulatory Liability - Trading Gains 2,494 34,293 (7,416)
Change in Other Assets (28,233) (5,871) (68,160)
Change in Other Liabilities 21,001 (5,102) 37,309
--------- --------- ---------
Net Cash Flows From Operating Activities 228,234 236,207 131,437
--------- --------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (167,484) (91,052) (171,071)
Buyout of Nuclear Fuel Leases - (92,616) -
Other 1,759 1,074 587
--------- --------- ---------
Net Cash Flows Used For Investing Activities (165,725) (182,594) (170,484)
--------- --------- ---------
FINANCING ACTIVITIES:
Capital Contributions from Parent Company 125,000 - -
Issuance of Long-term Debt 288,732 297,656 199,220
Retirement of Cumulative Preferred Stock (424) - (314)
Retirement of Long-term Debt (340,000) (44,922) (148,000)
Change in Advances from Affiliates (net) (144,917) (299,891) 253,582
Change in Short-term Debt (net) - - (224,262)
Dividends Paid on Common Stock - - (26,290)
Dividends Paid on Cumulative Preferred Stock (4,467) (4,487) (3,368)
--------- --------- ---------
Net Cash Flows From (Used For)
Financing Activities (76,076) (51,644) 50,568
--------- --------- ---------
Net Increase (Decrease) in Cash and
Cash Equivalents (13,567) 1,969 11,521
Cash and Cash Equivalents January 1 16,804 14,835 3,314
--------- --------- ---------
Cash and Cash Equivalents December 31 $ 3,237 $16,804 $14,835
======= ======= =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $89,984,000, $92,140,000
and $82,511,000 and for income taxes was $60,523,000, $100,470,000 and
$73,254,000 in 2002, 2001 and 2000, respectively. Noncash acquisitions under
capital leases were $1,023,000 and $22,218,000 in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
|
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
-----------------------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY $1,018,653 $ 860,570
---------- ----------
PREFERRED STOCK:
$100 Par Value - Authorized 2,250,000 shares
$25 Par Value - Authorized 11,200,000 shares
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2002 (a) Year Ended December 31, December 31, 2002
------ ------------ ------------------------ -----------------
2002 2001 2000
---- ---- ----
Not Subject to Mandatory Redemption-$100 Par:
4-1/8% 106.125 20 - 3,750 55,369 5,537 5,539
4.56% 102 - - - 14,412 1,441 1,441
4.12% 102.728 6,326 - 1,375 11,230 1,123 1,756
---------- ----------
8,101 8,736
---------- ----------
Subject to Mandatory Redemption-$100 Par(b):
5.90% (c) - - - 152,000 15,200 15,200
6-1/4% (c) - - - 192,500 19,250 19,250
6.30% (c) - - - 132,450 13,245 13,245
6-7/8% (d) - - - 172,500 17,250 17,250
---------- ----------
64,945 64,945
---------- ----------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 174,245 264,141
Installment Purchase Contracts 310,336 310,239
Senior Unsecured Notes 747,027 696,144
Other Long-term Debt (e) 223,736 219,947
Junior Debentures 161,718 161,611
Less Portion Due Within One Year (30,000) (340,000)
---------- ----------
Long-term Debt Excluding Portion Due Within One Year 1,587,062 1,312,082
---------- ----------
TOTAL CAPITALIZATION $2,678,761 $2,246,333
========== ==========
(a) The cumulative preferred stock is callable at the price indicated plus
accrued dividends
(b) Sinking fund provisions require the redemption of 15,000 shares in 2003 and
67,500 shares in each of 2004, 2005, 2006 and 2007. The sinking fund
provisions of each series subject to mandatory redemption have been met by
purchase of shares in advance of these due dates. Shares previously
purchased may be applied to meet the sinking fund requirement.
(c) Commencing in 2004 and continuing through 2008 I&M may redeem, at $100 per
share, 20,000 shares of the 5.90% series, 15,000 shares of the 6-1/4%
series and 17,500 shares of the 6.30% series outstanding under sinking fund
provisions at its option and all remaining outstanding shares must be
redeemed not later than 2009. The series are callable beginning November 1,
2003 for the 5.90% series, December 1, 2003 for the 6-1/4% series and March
1, 2004 for the 6.30% series at $100 plus accrued dividends.
(d) Commencing in 2003 and continuing through the year 2007, a sinking fund
will require the redemption of 15,000 shares each year and the redemption
of the remaining shares outstanding on April 1, 2008, in each case at $100
per share. Callable at $100 per share plus accrued dividends beginning
February 1, 2003.
(e) Represents a liability for SNF disposal including interest payable to the
DOE. See Note 9.
See Notes to Financial Statements beginning on page L-1.
|
First mortgage bonds outstanding were as follows:
% Rate Due
7.60 2002 - November 1 $ - $ 50,000
7.70 2002 - December 15 - 40,000
6.10 2003 - November 1 30,000 30,000
8.50 2022 - December 15 75,000 75,000
7.35 2023 - October 1 15,000 15,000
7.20 2024 - February 1 30,000 30,000
7.50 2024 - March 1 25,000 25,000
Unamortized Discount (755) (859)
-------- --------
$174,245 $264,141
|
First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions.
Installment purchase contracts have been entered in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:
% Rate Due
City of Lawrenceburg, Indiana:
7.00 2015 - April 1 $ 25,000 $ 25,000
5.90 2019 - November 1 52,000 52,000
City of Rockport, Indiana:
(a) 2014 - August 1 - 50,000 7.60 2016 - March 1 40,000 40,000 6.55 2025 - June 1 50,000 50,000 (b) 2025 - June 1 50,000 50,000 |
4.90(c) 2025 - June 1 50,000 -
City of Sullivan, Indiana:
5.95 2009 - May 1 45,000 45,000
Unamortized Discount (1,664) (1,761)
-------- --------
$310,336 $310,239
======== ========
(a) A variable interest rate was determined weekly. The average weighted
|
interest rates were 1.5% in 2002 and 2.4% for 2001.
(b) In June 2001 an auction rate was established. Auction rates are determined
by standard procedures every 35 days. The auction rate for 2002 ranged from
1.3% to 1.7% and averaged 1.5%. The auction rate for June through December
2001 ranged from 1.55% to 2.9% and averaged 2.4%. Prior to June 25, 2001,
an adjustable interest rate was a daily, weekly, commercial paper or term
rate as designated by I&M. A weekly rate was selected which ranged from
1.9% to 4.9% in 2001 and averaged 3.3% during 2001.
(c) Rate is fixed until June 1, 2007 (term rate bonds).
The terms of the installment purchase contracts require I&M to pay amounts sufficient for the cities to pay interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain generating plants. The term rate bonds due 2025 are subject to mandatory tender for purchase on the term maturity date (June 1, 2007). Accordingly, the term rate bonds have been classified for repayment purposes in 2007 (the term end date).
Senior unsecured notes outstanding were as follows:
% Rate Due
------ ------------------
(a) 2002 - September 3 $ - $200,000
6-7/8 2004 - July 1 150,000 150,000
6.125 2006 - December 15 300,000 300,000
6.45 2008 - November 10 50,000 50,000
6.375 2012 - November 1 100,000 -
6 2032 - December 31 150,000 -
Unamortized Discount (2,973) (3,856)
-------- --------
$747,027 $696,144
======== ========
|
(a) A floating interest rate was determined quarterly. The rate on December 31, 2001 was 2.71%. The average interest rates were 2.6% in 2002 and 5.1% in 2001.
Junior debentures outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
------ -----------------
8.00 2026 - March 31 $ 40,000 $ 40,000
7.60 2038 - June 30 125,000 125,000
Unamortized Discount (3,282) (3,389)
-------- --------
Total $161,718 $161,611
======== ========
|
Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of I&M.
At December 31, 2002, future annual long-term debt payments are as follows:
Amount
------
(in thousands)
2003 $ 30,000
2004 150,000
2005 -
2006 300,000
2007 50,000
Later Years 1,095,736
----------
Total Principal Amount 1,625,736
Unamortized Discount (8,674)
----------
Total $1,617,062
==========
|
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Index to Combined Notes to Consolidated Financial Statements
The notes to I&M's consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to I&M. The combined footnotes begin on page L-1.
Combined
Footnote
Reference
---------
Significant Accounting Policies Note 1
Merger Note 4
Nuclear Plant Restart Note 5
Effects of Regulation Note 7
Customer Choice and Industry Restructuring Note 8
Commitments and Contingencies Note 9
Guarantees Note 10
Sustained Earnings Improvement Initiative Note 11
Asset Impairments and Investment Value Losses Note 13
Benefit Plans Note 14
Business Segments Note 16
Risk Management, Financial Instruments and Derivatives Note 17
Income Taxes Note 18
Supplementary Information Note 20
Leases Note 22
Lines of Credit and Sale of Receivables Note 23
Unaudited Quarterly Financial Information Note 24
Related Party Transactions Note 29
|
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Indiana Michigan Power Company:
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Indiana Michigan Power Company and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Indiana Michigan Power Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 |
KENTUCKY POWER COMPANY
KENTUCKY POWER COMPANY
Selected Financial Data
-----------------------
Year Ended December 31,
--------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $ 378,683 $ 379,025 $ 389,875 $ 358,757 $ 362,999
Operating Expenses 336,486 331,347 340,137 304,082 311,106
---------- ----------- ---------- ---------- ----------
Operating Income 42,197 47,678 49,738 54,675 51,893
Nonoperating
Items, Net 5,206 1,248 2,070 (327) (1,726)
Interest Charges 26,836 27,361 31,045 28,918 28,491
---------- ----------- ---------- ---------- ----------
Net Income $ 20,567 $ 21,565 $ 20,763 $ 25,430 $ 21,676
========== =========== ========== ========== ==========
Year Ended December 31,
--------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility
Plant $1,295,619 $1,128,415 $1,103,064 $1,079,048 $1,043,711
Accumulated
Depreciation and
Amortization 397,304 384,104 360,648 340,008 315,546
---------- ---------- ---------- ---------- ----------
Net Electric
Utility Plant $ 898,315 $744,311 $742,416 $739,040 $728,165
========== ======== ======== ======== ========
Total Assets $1,164,676 $ 999,048 $1,494,543 $ 986,123 $ 921,847
========== ========== ========== ========== ==========
Common Stock and
Paid-in Capital $ 259,200 $ 209,200 $209,200 $209,200 $199,200
Accumulated Other
Comprehensive
Income (Loss) (9,451) (1,903) - - -
Retained Earnings 48,269 48,833 57,513 67,110 71,452
---------- ---------- ---------- ---------- ----------
Total Common
Shareholder's
Equity $ 298,018 $ 256,130 $266,713 $276,310 $270,652
========== ========== ======== ======== ========
Long-term
Debt (a) $ 466,632 $ 346,093 $330,880 $365,782 $368,838
========== ========== ======== ======== ========
Obligations Under
Capital Leases(a)
$ 7,248 $ 9,583 $ 14,184 $ 15,141 $ 18,977
========== ========== ======== ======== ========
Total
Capitalization
and Liabilities $1,164,676 $ 999,048 $1,494,543 $ 986,123 $ 921,847
========== ========== ========== ========== ==========
(a) Including portion due within one year.
|
KPCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power serving 174,000 retail customers in eastern Kentucky. KPCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. KPCo also sells wholesale power to municipalities.
The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of AEP Power Pool revenues and costs.
KPCo has a unit power agreement with AEGCo, an affiliated company, which expires in 2004. The unit power agreement extends until December 31, 2009 for Rockport Plant Unit 1 and until December 7, 2002 for Rockport Plant Unit 2 if AEP's settlement restructuring agreement filed with the FERC becomes operative. The agreement provides for KPCo to purchase 15% of the total output of the two unit 2,600-mw capacity Rockport Plant. Under the unit power agreement, there is a demand charge for the right to receive the power, which is payable even it the power is not taken. The amount of the demand charge is such that when added to other amounts received by AEGCo, it will enable AEGCo to recover all its fixed expenses including a FERC-approved rate of return on common equity.
Net Income for 2002 decreased $1 million or 5%. Total Revenues were flat while increases in Operating Expenses, driven by expenses related to planned outages at the Big Sandy plant, were offset by comparable gains in net nonoperating income which benefited from decreases in trading incentive compensation.
Increase (Decrease)
Year-to-Date
-------------------
(dollars in millions)
Amount %
------ -
Wholesale Electricity* $13 6
Energy Delivery* 1 1
Sales to AEP Affiliates (14) (34)
---
Total $ - -
===
|
*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.
Revenues in 2002 were comparable to those of last year. Increased sales to retail electricity customers reflecting warmer summer weather, colder days in late 2002, and increased fuel recovery revenues were offset by lower Sales to AEP Affiliates resulting from planned outages in 2002. KPCo's decreased generation was due to scheduled maintenance resulting in lower availability in the fourth quarter.
Increase (Decrease)
Year-to-Date
-------------------
(dollars in millions)
Amount %
------ -
Fuel $(5.6) (8)
Wholesale Electricity - N.M.
Purchases from AEP Affiliates
2.8 2
Other Operation (5.4) (9)
Maintenance 12.6 56
Depreciation .7 2
Taxes Other Than
Income Taxes .4 5
Income Taxes (.4) (4)
-----
|
N.M. = Not Meaningful
Fuel expense decreased in 2002 as a result of planned fourth quarter outages at the Big Sandy plant for scheduled boiler maintenance. The 800 megawatt Unit 2, representing approximately 75% of the plant's generation capacity, was off-line from mid-September through the end of the year, thereby reducing the demand for fuel in the fourth quarter. Purchases from AEP Affiliates for 2002 increased to meet demand during the planned outages at the Big Sandy plant.
Other Operation expense decreased in 2002 due to reduced consumption of emission allowances due to the planned outage; reduced accruals for trading incentive compensation due to reduced trading activity; and improvements in transmission expense resulting from less wholesale activity and related transmission, and an increase in AEP transmission equalization credits. Under the AEP Transmission Equalization Agreement, KPCo and certain eastern region affiliates share the costs associated with the ownership of their transmission system based upon each company's peak demand and investment. A decrease in KPCo's peak demand relative to its affiliates' peak demand was the main reason for the increase in transmission equalization credits. These developments were offset in part by severance expenses related to a sustained earnings initiative (see Note 11).
Maintenance expense increased in 2002 primarily as a result of planned power plant outages. Big Sandy plant Unit 2 was down for the fourth quarter for planned boiler overhaul and electric plant maintenance. The Company experienced marginal increases in overhead line maintenance expense.
Nonoperating Income Taxes for 2002 have increased as a result of increases in pre-tax income for the year offset in part by prior-year tax return adjustments.
Nonoperating Income for 2002 decreased as a result of AEP's previously announced plan to reduce trading activity, and decreased margins on power trading activity outside of the AEP System's traditional marketing area resulting from soft market demand. Nonoperating Expenses decreased in 2002 as a result of decreases in trading incentive compensation.
KENTUCKY POWER COMPANY
Statements of Income
--------------------
Year Ended December 31,
-------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING REVENUES:
Wholesale Electricity $218,665 $205,476 $226,708
Energy Delivery 132,054 131,183 121,346
Sales to AEP Affiliates 27,964 42,366 41,821
-------- -------- --------
TOTAL OPERATING REVENUES 378,683 379,025 389,875
-------- -------- --------
OPERATING EXPENSES:
Fuel 65,043 70,635 74,638
Purchased Power:
Wholesale Electricity 29 86 1,940
AEP Affiliates 133,002 130,204 127,707
Other Operation 52,892 58,275 52,495
Maintenance 35,089 22,444 25,866
Depreciation and Amortization 33,233 32,491 31,028
Taxes Other Than Income Taxes 8,240 7,854 7,251
Income Taxes 8,958 9,358 19,212
-------- -------- --------
TOTAL OPERATING EXPENSES 336,486 331,347 340,137
-------- -------- --------
OPERATING INCOME 42,197 47,678 49,738
NONOPERATING INCOME 7,863 10,881 6,139
NONOPERATING EXPENSES 753 8,949 2,940
NONOPERATING INCOME TAXES 1,904 684 1,129
INTEREST CHARGES 26,836 27,361 31,045
-------- -------- --------
NET INCOME $ 20,567 $ 21,565 $ 20,763
======== ======== ========
Statements of Comprehensive Income
----------------------------------
Year Ended December 31,
-------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
NET INCOME $ 20,567 $21,565 $20,763
OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Interest Rate Hedge 2,225 (1,903) -
Minimum Pension Liability (9,773) - -
-------- ------- -------
COMPREHENSIVE INCOME $ 13,019 $19,662 $20,763
======== ======= =======
Statements of Retained Earnings
-------------------------------
Year Ended December 31,
-------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
RETAINED EARNINGS JANUARY 1 $48,833 $57,513 $67,110
NET INCOME 20,567 21,565 20,763
CASH DIVIDENDS DECLARED 21,131 30,245 30,360
------- ------- -------
RETAINED EARNINGS DECEMBER 31 $48,269 $48,833 $57,513
======= ======= =======
See Notes to Financial Statements beginning on page L-1.
|
KENTUCKY POWER COMPANY
Balance Sheets
--------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $ 275,121 $ 271,070
Transmission 373,639 374,116
Distribution 425,817 402,537
General 55,913 65,059
Construction Work in Progress 165,129 15,633
---------- ----------
Total Electric Utility Plant 1,295,619 1,128,415
Accumulated Depreciation and Amortization 397,304 384,104
---------- ----------
NET ELECTRIC UTILITY PLANT 898,315 744,311
---------- ----------
OTHER PROPERTY AND INVESTMENTS 6,904 6,492
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 29,871 29,477
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 2,304 1,947
Accounts Receivable:
Customers 22,044 20,036
Affiliated Companies 23,802 16,012
Miscellaneous 2,889 3,333
Allowance for Uncollectible Accounts (192) (264)
Fuel 10,817 12,060
Materials and Supplies 16,127 15,766
Accrued Utility Revenues 5,301 5,395
Accrued Tax Benefit 1,253 -
Energy Trading Contracts 24,320 33,905
Prepayments and other 2,127 1,314
---------- ----------
TOTAL CURRENT ASSETS 110,792 109,504
---------- ----------
REGULATORY ASSETS 101,976 97,692
---------- ----------
DEFERRED CHARGES 16,818 11,572
---------- ----------
TOTAL ASSETS $1,164,676 $ 999,048
========== ==========
See Notes to Financial Statements beginning on page L-1.
|
KENTUCKY POWER COMPANY
December 31,
-----------
2002 2001
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $50 Par Value:
Authorized - 2,000,000 Shares
Outstanding - 1,009,000 Shares $ 50,450 $ 50,450
Paid-in Capital 208,750 158,750
Accumulated Other Comprehensive Income (Loss) (9,451) (1,903)
Retained Earnings 48,269 48,833
---------- --------
Total Common Shareowner's Equity 298,018 256,130
Long-term Debt 391,632 176,093
Long-term Debt - Affiliated Companies 60,000 75,000
---------- --------
TOTAL CAPITALIZATION 749,650 507,223
---------- --------
OTHER NONCURRENT LIABILITIES 27,319 11,929
---------- --------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - General - 95,000
Long-term Debt Due within One Year -
Affiliated Companies 15,000 -
Advances from Affiliates 23,386 66,200
Accounts Payable:
General 46,515 23,464
Affiliated Companies 44,035 22,557
Customer Deposits 8,048 4,461
Taxes Accrued - 10,305
Interest Accrued 6,471 5,269
Energy Trading and Derivative Contracts 17,803 38,664
Other 14,322 12,882
---------- --------
TOTAL CURRENT LIABILITIES 175,580 278,802
---------- --------
DEFERRED INCOME TAXES 178,313 168,304
---------- --------
DEFERRED INVESTMENT TAX CREDITS 9,165 10,405
---------- --------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 11,488 14,917
---------- --------
REGULATORY LIABILITIES AND DEFERRED CREDITS 13,161 7,468
---------- --------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $1,164,676 $999,048
========== ========
See Notes to Financial Statements beginning on page L-1.
|
KENTUCKY POWER COMPANY
Statements of Cash Flows
------------------------
Year Ended December 31,
----------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 20,567 $ 21,565 $ 20,763
Adjustments for Noncash Items:
Depreciation and Amortization 33,233 32,491 31,034
Deferred Income Taxes 9,839 6,293 3,765
Deferred Investment Tax Credits (1,240) (1,251) (1,252)
Deferred Fuel Costs (net) 2,998 (4,707) 2,948
Mark-to-Market of Energy Trading Contracts (12,267) (1,454) (4,376)
Change in Certain Current Assets and Liabilities:
Accounts Receivable (net) (9,426) 23,694 (20,930)
Fuel, Materials and Supplies 882 (7,658) 8,386
Accrued Utility Revenues 94 1,105 7,237
Accounts Payable 44,529 (22,942) 39,883
Taxes Accrued (11,558) (1,580) 2,025
Disputed Tax and Interest Related to COLI - - 5,943
Change in Other Assets (21,491) (2,762) 62,653
Change in Other Liabilities 16,161 (9,446) (62,702)
--------- -------- ---------
Net Cash Flows From Operating Activities 72,321 33,348 95,377
--------- -------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (178,700) (37,206) (36,209)
Proceeds From Sales of Property 217 216 266
--------- -------- ---------
Net Cash Flows Used For Investing
Activities (178,483) (36,990) (35,943)
--------- -------- ---------
FINANCING ACTIVITIES:
Capital Contributions from Parent Company 50,000 - -
Issuance of Long-term Debt 274,964 75,000 69,685
Retirement of Long-term Debt (154,500) (60,000) (105,000)
Change in Short-term Debt (net) - - (39,665)
Change in Advances From Affiliates (net) (42,814) 18,564 47,636
Dividends Paid (21,131) (30,245) (30,360)
--------- -------- ---------
Net Cash Flows From (Used For)
Financing Activities 106,519 3,319 (57,704)
--------- -------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 357 (323) 1,730
Cash and Cash Equivalents January 1 1,947 2,270 540
--------- -------- ---------
Cash and Cash Equivalents December 31 $ 2,304 $ 1,947 $ 2,270
========= ======== =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $25,176,000, $27,090,000
and $28,619,000 and for income taxes was $13,040,500, $7,549,000 and $7,923,000
in 2002, 2001 and 2000, respectively. Noncash acquisitions under capital leases
were $22,021, $817,000 and $2,817,000 and in 2002, 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
|
KENTUCKY POWER COMPANY
Statements of Capitalization
----------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY $298,018 $256,130
-------- --------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds - 59,383
Senior Unsecured Notes 352,508 147,625
Notes Payable 75,000 100,000
Junior Debentures 39,124 39,085
Less Portion Due Within One Year (15,000) (95,000)
-------- - -------
Long-term Debt Excluding Portion Due Within One Year 451,632 251,093
-------- - -------
TOTAL CAPITALIZATION $749,650 $507,223
======== ========
See Notes to Financial Statements beginning on page L-1.
|
First mortgage bonds outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
6.65 2003 - May 1 $ - $ 15,000
6.70 2003 - June 1 - 15,000
6.70 2003 - July 1 - 15,000
7.90 2023 - June 1 - 14,500
Unamortized Discount - (117)
-------- --------
$ - $ 59,383
======== ========
|
First mortgage bonds were secured by a first mortgage lien on electric utility plant.
Senior unsecured notes outstanding were as follows:
% Rate Due
------ ------------------
(a) 2002 - November 19 $ - $ 70,000
6.91 2007 - October 1 48,000 48,000
6.45 2008 - November 10 30,000 30,000
5.50 2007 - July 125,000 -
4.31 2007 - November 12 80,400 -
4.37 2007 - December 12 69,564 -
Unamortized Discount (456) (375)
-------- --------
$352,508 $147,625
|
(a) A floating interest rate is determined monthly. The rate December 31, 2001 was 4.3%.
Notes payable to parent company were as follows:
% Rate Due
4.336 2003 - May 15 $15,000 $15,000
6.501 2006 - May 15 60,000 60,000
------- -------
$75,000 $75,000
|
Notes payable to banks outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
7.45 2002 - September 20 $ - $25,000
======= =======
|
Junior debentures outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
8.72 2025 - June 30 $40,000 $40,000
Unamortized Discount (876) (915)
------- -------
Total $39,124 $39,085
======= =======
|
Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of the Company.
At December 31, 2002, future annual long-term debt payments are as follows:
Amount
------
(in thousands)
2003 $ 15,000
2004 -
2005 -
2006 60,000
2007 322,964
Later Years 70,000
--------
Total Principal Amount 467,964
Unamortized Discount (1,332)
--------
Total $466,632
========
|
The notes to KPCo's financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to KPCo. The combined footnotes begin on page L-1.
Combined
Footnote
Reference
---------
Significant Accounting Policies Note 1
Merger Note 4
Rate Matters Note 6
Effects of Regulation Note 7
Commitments and Contingencies Note 9
Guarantees Note 10
Sustained Earnings Improvement Initiative Note 11
Asset Impairments and Investment Value Losses Note 13
Benefit Plans Note 14
Business Segments Note 16
Risk Management, Financial Instruments and Derivatives Note 17
Income Taxes Note 18
Leases Note 22
Lines of Credit and Sale of Receivables Note 23
Unaudited Quarterly Financial Information Note 24
Related Party Transactions Note 29
|
INDEPENDENT AUDITORS' REPORT
To the Shareholder and Board of
Directors of Kentucky Power Company:
We have audited the accompanying balance sheets and statements of capitalization of Kentucky Power Company as of December 31, 2002 and 2001, and the related statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Kentucky Power Company as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 |
OHIO POWER COMPANY
OHIO POWER COMPANY
Selected Financial Data
-----------------------
Year Ended December 31,
---------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $2,113,125 $2,098,105 $2,140,331 $1,978,826 $2,105,547
Operating Expenses 1,814,796 1,857,395 1,913,504 1,689,997 1,816,175
---------- ---------- ---------- ---------- ----------
Operating Income 298,329 240,710 226,827 288,829 289,372
Nonoperating Items,
Net 5,376 18,686 (5,004) 7,000 588
Interest Charges 83,682 93,603 119,210 83,672 80,035
---------- ---------- ---------- ---------- ----------
Income Before
Extraordinary Item 220,023 165,793 102,613 212,157 209,925
Extraordinary Loss - (18,348) (18,876) - -
---------- ---------- --------- ---------- ----------
Net Income 220,023 147,445 83,737 212,157 209,925
Preferred Stock
Dividend
Requirements 1,258 1,258 1,266 1,417 1,474
---------- ---------- ---------- ---------- ----------
Earnings Applicable
To Common Stock $ 218,765 $ 146,187 $ 82,471 $ 210,740 $ 208,451
========== ========== ========== ========== ==========
Year Ended December 31,
---------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility
Plant $5,685,826 $5,390,576 $5,577,631 $5,400,917 $5,257,841
Accumulated
Depreciation 2,566,828 2,452,571 2,764,130 2,621,711 2,461,376
---------- ---------- ---------- ---------- ----------
Net Electric Utility
Plant $3,118,998 $2,938,005 $2,813,501 $2,779,206 $2,796,465
========== ========== ========== ========== ==========
Total Assets $4,457,032 $4,394,073 $6,193,975 $4,675,159 $4,344,680
========== ========== ========== ========== ==========
Common Stock and
Paid-in Capital $783,684 $783,684 $783,684 $783,577 $783,536
Accumulated Other
Comprehensive Income
(Loss) (72,886) (196) - - -
Retained Earnings 522,316 401,297 398,086 587,424 587,500
---------- ---------- ---------- ---------- ----------
Total Common
Shareholder's Equity $1,233,114 $1,184,785 $1,181,770 $1,371,001 $1,371,036
========== ========== ========== ========== ==========
Cumulative Preferred Stock:
Not Subject to
Mandatory Redemption $ 16,648 $ 16,648 $ 16,648 $ 16,937 $ 17,370
Subject to Mandatory
Redemption (a) 8,850 8,850 8,850 8,850 11,850
---------- ---------- ---------- ---------- ----------
Total Cumulative
Preferred Stock $ 25,498 $ 25,498 $ 25,498 $ 25,787 $ 29,220
========== ========== ========== ========== ==========
Long-term Debt (a) $1,067,314 $1,203,841 $1,195,493 $1,151,511 $1,084,928
========== ========== ========== ========== ==========
Obligations Under
Capital Leases (a) $ 65,626 $ 80,666 $ 116,581 $ 136,543 $ 142,635
========== ========== ========== ========== ==========
Total Capitalization
and Liabilities $4,457,032 $4,394,073 $6,193,975 $4,675,159 $4,344,680
========== ========== ========== ========== ==========
(a) Including portion due within one year.
|
Ohio Power Company (OPCo) is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 702,000 retail customers in northwestern, east central, eastern and southern sections of Ohio. OPCo supplies electric power to the AEP Power Pool and shares the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. OPCo also sells wholesale power to municipalities and cooperatives.
The cost of the AEP Power Pool's generating capacity is allocated among Pool members based on their relative peak demands and generating reserves through the payment of capacity charges or the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of AEP Power Pool revenues and costs.
Income Before Extraordinary Item increased $54 million or 33% in 2002 mainly due to reductions in operating expenses, predominantly fuel, and interest charges.
Income Before Extraordinary Item increased $63 million or 62% in 2001 primarily due to the effect of a court decision related to a corporate owned life insurance (COLI) program recorded in 2000. In February 2001 the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including OPCo, in a suit over deductibility of interest claimed in AEP's consolidated tax returns related to COLI. In 1998 and 1999 OPCo paid the disputed taxes and interest attributable to the COLI interest deductions for taxable years 1991-98. The payments were included in Other Property and Investments pending the resolution of this matter. Net Income was also favorably impacted by the growth in and strong performance by the wholesale business. The effects of the COLI decision in 2000 and favorable wholesale business in 2001 were offset in part by the commencement of the amortization of transition regulatory assets in 2001, the effect of mild winter weather and the economic downturn.
Operating Revenues increased 1% in 2002 mainly as a result of increased residential and commercial sales due to demand caused by weather conditions. Changes in the components of Operating Revenues were:
(Dollars in Millions)
2002 2001
-----------------------------
Amount % Amount %
------ - ------ -
Retail* $ 11 2 $(66) (8)
Wholesale
Marketing 10 5 (19) (8)
Unrealized MTM 2 8 33 N.M.
Other 1 1 (4) (5)
---- ----
Total
Wholesale
Electricity* 24 2 (56) (5)
Energy
Delivery* 37 7 85 18
Sales to AEP
Affiliates (46) (9) (71)(12)
---- ----
Total $ 15 1 $(42) (2)
==== ====
|
* Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.
During the summer months, cooling degree days increased 39%. For the fall season, heating degree days increased 32%. This reflects a return to more normal weather conditions since 2001 weather was abnormally mild. Sales to AEP Affiliates decreased due to a 15% decrease in price, reflective of lower average fuel cost, while MWH sales rose slightly.
Operating Revenues decreased 2% in 2001 due to decreased sales to the AEP Power Pool. This was the result of an affiliate being able to supply more power to the Power Pool from two nuclear units that returned to service in June and December 2000.
Operating Expenses decreased 2% in 2002 mostly due to reductions in Fuel. Operating Expenses in 2001 also decreased 3%. This reduction was the result of lower Fuel and Income Taxes partially offset by amortization of transition regulatory assets.
Changes in the components of Operating Expenses were:
(dollars in millions)
2002 2001
---- ----
Amount % Amount %
------ - ------ -
Fuel $(102) (15) $(85) (11)
Wholesale
Electricity
Purchased Power 4 6 15 30
AEP Affiliates
Purchased Power 8 14 12 23
Other Operation 16 4 (4) (1)
Maintenance (6) (4) 18 15
Depreciation
and Amortization 9 4 84 54
Taxes Other Than
Income Taxes 16 10 (10) (6)
Income Taxes 12 12 (86) (46)
----- ----
Total Operating
Expenses $ (43) (2) $(56) (3)
===== ====
|
The Fuel expense decrease for 2002 reflects a reduction of 19% in average cost of fuel for generation, offset in part by a slight increase in MWH generated. The decrease in fuel costs are the result of purchasing coal at lower prices on the open market in 2002 instead of affiliated company coal.
Fuel expense decreased 11% in 2001 mainly due to a 9% decrease in net generation because of decreased sales to the AEP Power Pool caused by an affiliate's two nuclear units returning to service.
Wholesale Electricity Purchased Power expense increased in 2002. This was the result of a 11% increase of MWH sales, partially offset by a decrease in price. In 2001 the increase was due to increases in MWH purchases from third parties because of the non-availability of associated nuclear power for resale to wholesale customers and to meet internal demand.
AEP Affiliates Purchased Power expense increased in 2002 as a result of an 18% increase of MWH purchased from affiliates with a slight decrease in the average price. The increase for 2001 was also a result of increased purchases through the AEP Power Pool.
Maintenance expense increased in 2001 mainly due to boiler repairs at Amos, Cardinal, Kammer, Mitchell, Muskingum and Sporn plants, and boiler inspections at the Amos and Cardinal Plants.
In 2001, the commencement of amortization of transition regulatory assets in connection with the transition to customer choice and market-based pricing of retail electricity supply under Ohio deregulation accounted for the significant increase in Depreciation and Amortization expense.
The 2002 increase in Taxes Other Than Income Taxes is the result of increases in state excise tax created from a change in the base tax calculation. The decrease in 2001 was due to a decrease in property tax expense reflecting a reduction in rates on generation property under the Ohio Restructuring law partially offset by a new state excise tax.
Income Taxes increased in 2002 due to an increase in both federal and state tax expenses. Federal taxes increased due to higher pre-tax operating income offset in part by changes in certain book/tax timing differences accounted for on a flow-thru basis. State taxes increased predominately as a result of the State of Ohio's tax legislation revision involving utility deregulation.
Income Taxes decreased in 2001 due to an unfavorable ruling in AEP's suit against the government over interest deductions claimed relating to AEP's COLI program which was recorded in 2000 and a decrease in pre-tax book income.
Nonoperating Expenses decreased during 2002 due to reductions in variable incentive compensation expenses associated with wholesale trading.
Nonoperating Income and Nonoperating Expenses increased in 2001 as a result of an increase in the level of trading activity outside of the AEP System's traditional marketing area.
The 2002 increase in Nonoperating Income Tax Expense is a result of the favorable tax benefit from the sale of the Ohio Coal companies in 2001. This event also caused the decrease for 2001.
The 2002 decrease in Interest Charges was primarily due to a decrease in the outstanding balances of long-term debt, the refinancing of debt at favorable interest rates and a reduction in short-term interest rates.
The major reason for the decrease in Interest Charges in 2001 was the recognition in 2000 of deferred interest payments to the IRS related to COLI disallowances.
In the second quarter of 2001 an extraordinary loss of $18 million net of tax was recorded to write-off prepaid Ohio excise taxes stranded by Ohio deregulation. In 2000 the application of regulatory accounting for generation under SFAS 71 was discontinued which resulted in an after tax extraordinary loss of $19 million.
OHIO POWER COMPANY
Statements of Income
--------------------
Year Ended December 31,
-------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING REVENUES:
Wholesale Electricity $1,058,250 $1,034,026 $1,090,297
Energy Delivery 589,673 552,713 467,587
Sales to AEP Affiliates 465,202 511,366 582,447
---------- ---------- ----------
TOTAL OPERATING REVENUES 2,113,125 2,098,105 2,140,331
---------- ---------- ----------
OPERATING EXPENSES:
Fuel 584,730 686,568 771,969
Purchased Power:
Wholesale Electricity 67,385 63,441 48,657
AEP Affiliates 71,154 62,585 50,741
Other Operation 416,533 400,790 404,410
Maintenance 136,609 142,878 124,735
Depreciation and Amortization 248,557 239,982 155,944
Taxes Other Than Income Taxes 176,247 159,778 169,527
Income Taxes 113,581 101,373 187,521
---------- ---------- ----------
TOTAL OPERATING EXPENSES 1,814,796 1,857,395 1,913,504
---------- ---------- ----------
OPERATING INCOME 298,329 240,710 226,827
NONOPERATING INCOME 51,953 70,108 57,163
NONOPERATING EXPENSES 28,567 53,802 44,009
NONOPERATING INCOME TAX EXPENSE (CREDIT) 18,010 (2,380) 18,158
INTEREST CHARGES 83,682 93,603 119,210
---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 220,023 165,793 102,613
EXTRAORDINARY LOSS - DISCONTINUANCE OF
REGULATORY ACCOUNTING FOR GENERATION -
Net of tax (See Note 2) - (18,348) (18,876)
---------- ---------- ----------
NET INCOME 220,023 147,445 83,737
PREFERRED STOCK DIVIDEND REQUIREMENTS 1,258 1,258 1,266
---------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 218,765 $ 146,187 $ 82,471
========== ========== ==========
Statements of Comprehensive Income
----------------------------------
Year Ended December 31,
-----------------------------------------------
(in thousands)
2002 2001 2000
---- ---- ----
NET INCOME $220,023 $147,445 $83,737
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign Currency Exchange Rate Hedge (542) (196) -
Minimum Pension Liability (72,148) - -
-------- -------- -------
COMPREHENSIVE INCOME $147,333 $147,249 $83,737
======== ======== =======
The common stock of OPCo is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY
Statement of Retained Earnings
------------------------------
Year Ended December 31,
-----------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
Retained Earnings January 1 $401,297 $398,086 $587,424
Net Income 220,023 147,445 83,737
-------- -------- --------
621,320 545,531 671,161
-------- -------- --------
Deductions:
Cash Dividends Declared:
Common Stock 97,746 142,976 271,813
Cumulative Preferred Stock:
4.08% Series 58 58 59
4.20% Series 96 96 96
4.40% Series 139 139 139
4-1/2% Series 439 439 442
5.90% Series 428 428 428
6.02% Series 66 66 66
6.35% Series 32 32 32
-------- -------- --------
Total Dividends 99,004 144,234 273,075
-------- -------- --------
Retained Earnings December 31 $522,316 $401,297 $398,086
======== ======== ========
See Notes to Financial Statements beginning on page L-1.
|
OHIO POWER COMPANY
Balance Sheets
--------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $3,116,825 $3,007,866
Transmission 905,829 891,283
Distribution 1,114,600 1,081,122
General 260,153 245,232
Construction Work in Progress 288,419 165,073
---------- ----------
Total Electric Utility Plant 5,685,826 5,390,576
Accumulated Depreciation and Amortization 2,566,828 2,452,571
---------- ----------
NET ELECTRIC UTILITY PLANT 3,118,998 2,938,005
---------- ----------
OTHER PROPERTY AND INVESTMENTS 61,686 62,303
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 103,230 99,706
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 5,285 8,848
Accounts Receivable:
Customers 95,100 84,694
Affiliated Companies 124,244 148,563
Miscellaneous 19,281 20,409
Allowance for Uncollectible Accounts (909) (1,379)
Fuel 87,409 84,724
Materials and Supplies 85,379 88,768
Energy Trading Contracts 92,108 114,280
Prepayments and Other 12,083 20,865
---------- ----------
TOTAL CURRENT ASSETS 519,980 569,772
---------- ----------
REGULATORY ASSETS 568,641 644,625
---------- ----------
DEFERRED CHARGES 84,497 79,662
---------- ----------
TOTAL ASSETS $4,457,032 $4,394,073
========== ==========
See Notes to Financial Statements beginning on page L-1.
|
OHIO POWER COMPANY
December 31,
-----------
2002 2001
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 40,000,000 Shares
Outstanding - 27,952,473 Shares $ 321,201 $ 321,201
Paid-in Capital 462,483 462,483
Accumulated Other Comprehensive Income (Loss) (72,886) (196)
Retained Earnings 522,316 401,297
---------- ----------
Total Common Shareholder's Equity 1,233,114 1,184,785
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 16,648 16,648
Subject to Mandatory Redemption 8,850 8,850
Long-term Debt 917,649 1,203,841
---------- ----------
TOTAL CAPITALIZATION 2,176,261 2,414,124
---------- ----------
OTHER NONCURRENT LIABILITIES 227,689 130,386
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - General 89,665 -
Long-term Debt Due Within One Year - Affiliated Companies 60,000 -
Short-term Debt - Affiliated Companies 275,000 -
Advances From Affiliates 129,979 300,213
Accounts Payable - General 170,563 131,057
Accounts Payable - Affiliated Companies 145,718 176,520
Customer Deposits 12,969 5,452
Taxes Accrued 111,778 126,770
Interest Accrued 18,809 17,679
Obligations Under Capital Leases 14,360 16,405
Energy Trading Contracts 61,839 98,081
Other 80,608 90,431
---------- ----------
Total CURRENT LIABILITIES 1,171,288 962,608
---------- ----------
DEFERRED INCOME TAXES 794,387 797,889
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 18,748 21,925
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 39,702 50,459
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 28,957 16,682
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $4,457,032 $4,394,073
========== ==========
See Notes to Financial Statements beginning on page L-1.
|
OHIO POWER COMPANY
Statements of Cash Flows
------------------------
Year Ended December 31,
----------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 220,023 $ 147,445 $ 83,737
Adjustments for Noncash Items:
Depreciation, Depletion and Amortization 248,557 252,123 200,350
Deferred Income Taxes 46,010 215,833 (65,956)
Deferred Investment Tax Credits (3,177) (3,289) (3,399)
Deferred Fuel Costs (net) - - (56,869)
Extraordinary Loss 18,348 18,876
Mark to Market of Energy Trading Contracts (28,693) (59,833) (5,614)
Change in Certain Current Assets and Liabilities:
Accounts Receivable (net) 14,571 51,640 51,430
Fuel, Materials and Supplies 704 4,852 46,645
Accrued Utility Revenues 3,081 264 45,311
Accounts Payable 8,704 9,887 56,069
Customer Deposits 7,517 (34,284) 31,540
Taxes Accrued (14,992) (96,331) 60,919
Disputed Tax and Interest Related to COLI - - 110,494
Employee Benefit and Other Noncurrent Liabilities 110,298 (392,026) 145,573
Impairment Loss 1,757 - -
Change in Other Assets (2,233) 79,831 (439,448)
Change in Other Liabilities (133,154) (107,704) 359,640
--------- --------- ---------
Net Cash Flows From Operating Activities 478,973 86,756 639,298
--------- --------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (354,797) (344,571) (254,016)
Proceeds From Sales of Property and Other 6,499 16,778 6,354
Investment in Coal Companies - (32,115) -
--------- --------- ---------
Net Cash Flows Used For
Investing Activities (348,298) (359,908) (247,662)
--------- --------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt - 300,000 74,748
Change in Advances From Affiliates (net) (170,234) 392,699 (92,486)
Retirement of Cumulative Preferred Stock - - (182)
Retirement of Long-term Debt (140,000) (297,858) (30,663)
Change in Short-term Debt (net) 275,000 - (194,918)
Dividends Paid on Common Stock (97,746) (142,976) (271,813)
Dividends Paid on Cumulative Preferred Stock (1,258) (1,258) (1,262)
--------- --------- ---------
Net Cash Flows From (Used For)
Financing Activities (134,238) 250,607 (516,576)
--------- --------- ---------
Net Decrease in Cash and Cash Equivalents (3,563) (22,545) (124,940)
Cash and Cash Equivalents January 1 8,848 31,393 156,333
--------- --------- ---------
Cash and Cash Equivalents December 31 $ 5,285 $ 8,848 $31,393
======= ======= =======
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $81,041,000,
$94,747,000 and $87,120,000 and for income taxes was $105,058,000, $(22,417,000)
and $142,710,000 in 2002, 2001 and 2000, respectively. Noncash acquisitions
under capital leases were $106,000, $2,380,000 and $17,005,000 in 2002, 2001 and
2000, respectively.
See Notes to Financial Statements beginning on page L-1.
|
OHIO POWER COMPANY
Statements of Capitalization
----------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY $1,233,114 $1,184,785
---------- ----------
PREFERRED STOCK: $100 par value - authorized shares 3,762,403
$25 par value - authorized shares 4,000,000
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2002 (a) Year Ended December 31, December 31, 2002
------ ------------- --------------------------- -----------------
2002 2001 2000
---- ---- ----
Not Subject to Mandatory Redemption-$100 Par:
4.08% $103 - - - 14,595 1,460 1,460
4.20% 103.20 - - 276 22,824 2,282 2,282
4.40% 104 - - 432 31,512 3,151 3,151
4-1/2% 110 - - 2,181 97,546 9,755 9,755
---------- ----------
16,648 16,648
---------- ----------
Subject to Mandatory Redemption-$100 Par (b):
5.90% (c) $ - - - - 72,500 7,250 7,250
6.02% (d) - - - - 11,000 1,100 1,100
6.35% (d) - - - - 5,000 500 500
---------- ----------
8,850 8,850
---------- ----------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 136,633 141,544
Installment Purchase Contracts 233,340 233,235
Senior Unsecured Notes 397,341 396,962
Notes Payable to Affiliated Company 300,000 300,000
Junior Debentures - 132,100
Less Portion Due Within One Year (149,665) -
---------- ----------
Long-term Debt Excluding Portion Due Within One Year 917,649 1,203,841
---------- ----------
TOTAL CAPITALIZATION $2,176,261 $2,414,124
========== ==========
(a) The cumulative preferred stock is callable at the price indicated plus
accrued dividends.
(b) Sinking fund provisions require the redemption of 35,000 shares in 2003 and
57,500 shares in each of 2004, 2005, 2006 and 2007. The sinking fund
provisions of each series subject to mandatory redemption have been met by
purchase of shares in advance of the due dates. Shares previously purchased
may be applied to the sinking fund requirement. At the company's option,
all shares are redeemable at $100 per share plus accrued and unpaid
dividends with at least 30 days notice beginning on or after November 1,
2003 for the 5.09% series, October 1, 2003 for the 6.02% series, and April
1, 2003 for the 6.35% series.
(c) Commencing in 2004 and continuing through the year 2008, a sinking fund for
the 5.90% cumulative preferred stock will require the redemption of 22,500
shares each year and the redemption of the remaining shares outstanding on
January 1, 2009, in each case at $100 per share. Shares previously redeemed
may be applied to meet sinking fund requirements.
(d) Commencing in 2003 and continuing through 2007 sinking fund provisions will
require the redemption of 20,000 shares each year of the 6.02% series and
15,000 shares each year of the 6.35% series, in each case at $100 per
share. All remaining outstanding shares must be redeemed in 2008. Shares
previously redeemed may be applied to meet the sinking fund requirements.
See Notes to Financial Statements beginning on page L-1.
|
First mortgage bonds outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
6.75 2003 - April 1 $ 29,850 $ 29,850
6.55 2003 - October 1 27,315 27,315
6.00 2003 - November 1 12,500 12,500
6.15 2003 - December 1 20,000 20,000
(a) 2022 - February 10 - 5,000
7.75 2023 - April 1 5,000 5,000
7.375 2023 - October 1 20,250 20,250
7.10 2023 - November 1 12,000 12,000
7.30 2024 - April 1 10,000 10,000
Unamortized Discount (282) (371)
-------- --------
Total $136,633 $141,544
======== ========
|
(a) Redeemed on May 10, 2002.
First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions.
Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:
% Rate Due
Mason County, West
Virginia:
5.45% 2016 - December 1 $ 50,000 $ 50,000
Marshall County, West
Virginia:
5.45% 2014 - July 1 50,000 50,000
5.90% 2022 - April 1 35,000 35,000
6.85% 2022 - June 1 50,000 50,000
Ohio Air Quality
Development
5.15% 2026 - May 1 50,000 50,000
Unamortized Discount (1,660) (1,765)
Total $233,340 $233,235
======== ========
|
Under the terms of the installment purchase contracts, OPCo is required to pay amounts
sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.
Senior unsecured notes outstanding were as follows:
% Rate Due
------ ------------------
6.75 2004 - July 1 $100,000 $100,000
7.00 2004 - July 1 75,000 75,000
6.73 2004 - November 1 48,000 48,000
6.24 2008 - December 4 37,225 37,225
7-3/8 2038 - June 30 140,000 140,000
Unamortized Discount (2,884) (3,263)
-------- --------
Total $397,341 $396,962
======== ========
|
Notes payable to parent company were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
4.336% 2003 - May 15 $ 60,000 $ 60,000
6.501% 2006 - May 15 240,000 240,000
-------- --------
Total $300,000 $300,000
======== ========
|
Junior debentures outstanding were as follows:
% Rate Due
------ -----------------
(a) 2025 - September 30 $ - $ 85,000
(a) 2027 - March 31 - 50,000
Unamortized Discount - (2,900)
-------- --------
Total $ - $132,100
======== ========
|
(a) Redeemed on July 24, 2002
At December 31, 2002 future annual long-term debt payments are as follows:
Amount
------
(in thousands)
2003 $ 149,665
2004 223,000
2005 -
2006 240,000
2007 -
Later Years 459,475
----------
Total Principal Amount 1,072,140
Unamortized Discount 4,826
----------
Total $1,067,314
==========
|
The notes to OPCo's financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to OPCo. The combined footnotes begin on page L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Extraordinary Items and Cumulative Effect Note 2
Effects of Regulation Note 7
Customer Choice and Industry Restructuring Note 8
Commitments and Contingencies Note 9
Guarantees Note 10
Sustained Earnings Improvement Initiative Note 11
Acquisitions, Dispositions and Discontinued
Operations Note 12
Asset Impairments and Investment Value Losses Note 13
Benefit Plans Note 14
Business Segments Note 16
Risk Management, Financial Instruments
and Derivatives Note 17
Income Taxes Note 18
Supplementary Information Note 20
Leases Note 22
Lines of Credit and Sale of Receivables Note 23
Unaudited Quarterly Financial Information Note 24
Related Party Transactions Note 29
|
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Ohio Power Company:
We have audited the accompanying balance sheets and statements of capitalization of Ohio Power Company as of December 31, 2002 and 2001, and the related statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Ohio Power Company as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 |
PUBLIC SERVICE COMPANY OF OKLAHOMA
AND SUBSIDIARY
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Selected Consolidated Financial Data
------------------------------------
Year Ended December 31,
---------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $ 793,647 $957,000 $956,398 $749,390 $780,159
Operating Expenses 708,926 860,012 859,729 650,677 665,085
---------- -------- -------- -------- --------
Operating Income 84,721 96,988 96,669 98,713 115,074
Nonoperating Items,
Net (3,239) 20 8,974 946 (91)
Interest Charges 40,422 39,249 38,980 38,151 38,074
---------- -------- -------- -------- --------
Net Income 41,060 57,759 66,663 61,508 76,909
Preferred Stock Dividend
Requirements 213 213 212 212 213
Gain On Reacquired
Preferred Stock 1 - - - -
---------- -------- -------- -------- --------
Earnings Applicable to
Common Stock $ 40,848 $ 57,546 $ 66,451 $ 61,296 $ 76,696
========== ======== ======== ======== ========
December 31,
---------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $2,759,504 $2,695,099 $2,604,670 $2,459,705 $2,391,722
Accumulated Depreciation
and Amortization 1,239,855 1,184,443 1,150,253 1,114,255 1,082,081
---------- ---------- ---------- ---------- ----------
Net Electric Utility
Plant $1,519,649 $1,510,656 $1,454,417 $1,345,450 $1,309,641
========== ========== ========== ========== ==========
Total Assets $1,776,690 $1,748,911 $2,138,423 $1,524,846 $1,471,089
========== ========== ========== ========== ==========
Common Stock and Paid-in
Capital $ 337,246 $ 337,246 $ 337,246 $ 337,246 $ 337,246
Accumulated Other Comprehensive
Income (Loss) (54,473) - - - -
Retained Earnings 116,474 142,994 137,688 139,237 142,941
---------- ---------- ---------- ---------- ----------
Total Common
Shareholder's Equity $ 399,247 $ 480,240 $ 474,934 $ 476,483 $ 480,187
========== ========== ========== ========== ==========
Cumulative Preferred
Stock:
Not Subject to
Mandatory Redemption $ 5,267 $ 5,267 $ 5,267 $ 5,270 $ 5,271
========== ========== ========== ========== ==========
Preferred Securities of
Subsidiary Trust $ 75,000 $ 75,000 $ 75,000 $ 75,000 $ 75,000
========== ========== ========== ========== ==========
Long-term Debt (a) $ 545,437 $ 451,129 $ 470,822 $ 384,516 $ 384,064
========== ========== ========== ========== ==========
Total Capitalization and
Liabilities $1,776,690 $1,748,911 $2,138,423 $1,524,846 $1,471,089
========== ========== ========== ========== ==========
(a) Including portion due within one year.
|
Public Service Company of Oklahoma (PSO) is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 505,000 retail customers in eastern and southwestern Oklahoma. PSO also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives.
Wholesale power marketing activities are conducted on PSO's behalf by AEPSC. PSO, along with the other AEP electric operating subsidiaries, shares in AEP's electric power transactions with other utility systems and power marketers.
In 2002, Net Income decreased by $17 million or 29% primarily resulting from reduced wholesale margins and increased depreciation expense.
Operating revenues decreased in 2002 as a result of reduced wholesale margins, a decline in fuel recovery revenue and decreases due to the interchange cost reconstruction (ICR) adjustments (see Note 6).
Increase (Decrease)
From Previous Year
------------------
(dollars in millions)
Amount %
------ -
Wholesale Electricity* $(149.7) (23)
Energy Delivery* 13.6 5
Sales to AEP Affiliates (27.3) (74)
-------
Total Operating Revenues $(163.4) (17)
=======
|
*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.
Changes in Operating Expenses
-----------------------------
Increase (Decrease)
From Previous Year
------------------
(dollars in millions)
Amount %
------ -
Fuel $(215.3) (47)
Purchased Power:
Wholesale Electricity 23.3 96
AEP Affiliates 45.7 104
Other Operation (4.1) (3)
Maintenance 1.9 4
Depreciation and
Amortization 5.6 7
Taxes Other Than
Income Taxes 2.1 7
Income Taxes (10.3) (30)
-------- ---
Total $(151.1) (18)
======= ===
|
N.M. = Not Meaningful
The decrease in Fuel expense in 2002 was primarily due to lower market prices for natural gas and fuel oil, and deferral of underrecovered fuel costs due to the ICR adjustments through the fuel clause recovery mechanism (see Note 6) and to the amortization of previously overrecovered fuel costs.
The increase in Electricity Marketing Purchased Power expense in 2002 resulted mainly from ICR adjustments (see Note 6), partially offset by a decrease in energy prices.
The increase in the AEP Affiliates Purchased Power expense in 2002 resulted mainly from the ICR adjustments (see Note 6).
Other Operation expense decreased in 2002 primarily due to lower transmission expenses and decreased factoring expenses due to reduced revenues.
Maintenance expense increased, in 2002 largely as a result of increased expenses to repair damage to overhead lines caused by a winter storm in 2002.
Depreciation and Amortization expense increased in 2002 primarily due to the additional depreciable capitalized costs involved in repowering Northeast Station Units 1 & 2 completed in 2001.
Taxes Other Than Income Taxes increased in 2002 primarily due to the increase in ad valorem taxes.
Income Taxes decreased in 2002 primarily due to a decrease in pre-tax income.
Nonoperating Expenses increased primarily due to the write-down of certain non-utility investments in 2002.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Consolidated Statements of Income
---------------------------------
Year Ended December 31,
-----------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING REVENUES:
Wholesale Electricity $508,661 $658,352 $696,626
Energy Delivery 275,547 261,877 245,124
Sales to AEP Affiliates 9,439 36,771 14,648
-------- -------- --------
TOTAL OPERATING REVENUES 793,647 957,000 956,398
-------- -------- --------
OPERATING EXPENSES:
Fuel 246,199 461,470 402,933
Purchased Power:
Wholesale Electricity 47,507 24,187 88,088
AEP Affiliates 89,454 43,758 60,788
Other Operation 133,538 137,678 121,697
Maintenance 48,060 46,188 45,858
Depreciation and Amortization 85,896 80,245 76,418
Taxes Other Than Income Taxes 34,077 31,973 28,688
Income Taxes 24,195 34,513 35,259
-------- -------- --------
TOTAL OPERATING EXPENSES 708,926 860,012 859,729
-------- -------- --------
OPERATING INCOME 84,721 96,988 96,669
NONOPERATING INCOME 1,920 2,112 8,807
NONOPERATING EXPENSES 6,971 1,740 1,139
NONOPERATING INCOME TAX EXPENSE (CREDIT) (1,812) 352 (1,306)
INTEREST CHARGES 40,422 39,249 38,980
-------- -------- --------
NET INCOME 41,060 57,759 66,663
GAIN ON REACQUIRED PREFERRED STOCK 1 - -
LESS: PREFERRED STOCK DIVIDEND REQUIREMENTS 213 213 212
-------- -------- --------
EARNINGS APPLICABLE TO COMMON STOCK $ 40,848 $ 57,546 $ 66,451
======== ======== ========
Consolidated Statements of Comprehensive Income
-----------------------------------------------
Year Ended December 31,
-----------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
NET INCOME $ 41,060 $57,759 $66,663
OTHER COMPREHENSIVE INCOME (LOSS):
Cash Flow Power Hedges (42) - -
Minimum Pension Liability (54,431) - -
-------- ------- -------
COMPREHENSIVE INCOME (LOSS) $(13,413) $57,759 $66,663
======== ======= =======
The common stock of PSO is owned by a wholly owned subsidiary of AEP. See Notes
to Financial Statements beginning on page L-1.
|
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Consolidated Statements of Retained Earnings
--------------------------------------------
Year Ended December 31,
---------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
BEGINNING OF PERIOD $142,994 $137,688 $139,237
NET INCOME 41,060 57,759 66,663
DEDUCTIONS
Capital Stock Gains (1) - -
Cash Dividends Declared:
Common Stock 67,368 52,240 68,000
Preferred Stock 213 213 212
-------- -------- --------
BALANCE AT END OF PERIOD $116,474 $142,994 $137,688
======== ======== ========
The common stock of PSO is owned by a wholly owned subsidiary of AEP. See Notes
to Financial Statements beginning on page L-1.
|
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Consolidated Balance Sheets
---------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $1,040,520 $1,034,711
Transmission 432,846 427,110
Distribution 990,947 972,806
General 206,747 203,572
Construction Work in Progress 88,444 56,900
---------- ----------
Total Electric Utility Plant 2,759,504 2,695,099
Accumulated Depreciation and Amortization 1,239,855 1,184,443
---------- ----------
NET ELECTRIC UTILITY PLANT 1,519,649 1,510,656
---------- ----------
OTHER PROPERTY AND INVESTMENTS 5,383 41,020
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 4,481 21,354
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 16,774 5,795
Accounts Receivable:
Customers 31,687 31,144
Affiliated Companies 14,139 10,905
Allowance for Uncollectible Accounts (84) (44)
Fuel Inventory 19,973 21,559
Materials and Supplies 37,375 36,785
Under-recovered Fuel Costs 76,470 756
Energy Trading and Derivative Contracts 3,841 26,259
Prepayments and Other 2,735 2,368
---------- ----------
TOTAL CURRENT ASSETS 202,910 135,527
---------- ----------
REGULATORY ASSETS 26,150 35,064
---------- ----------
DEFERRED CHARGES 18,117 5,290
---------- ----------
TOTAL ASSETS $1,776,690 $1,748,911
========== ==========
See Notes to Financial Statements beginning on page L-1.
|
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
December 31,
-----------
2002 2001
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $15 Par Value:
Authorized Shares: 11,000,000
Issued Shares: 10,482,000
Outstanding Shares: 9,013,000 $ 157,230 $ 157,230
Paid-in Capital 180,016 180,016
Accumulated Other Comprehensive Income (Loss) (54,473) -
Retained Earnings 116,474 142,994
---------- ----------
Total Common Shareholder's Equity 399,247 480,240
---------- ----------
Cumulative Preferred Stock Not Subject
to Mandatory Redemption 5,267 5,267
PSO-Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely Junior
Subordinated Debentures of PSO 75,000 75,000
Long-term Debt 445,437 345,129
---------- ----------
TOTAL CAPITALIZATION 924,951 905,636
---------- ----------
OTHER NONCURRENT LIABILITIES 54,761 7,263
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 100,000 106,000
Advances from Affiliates 86,105 123,087
Accounts Payable - General 61,169 72,759
Accounts Payable - Affiliated Companies 78,076 40,857
Customer Deposits 21,789 21,041
Over-Recovered Fuel Costs - 9,476
Taxes Accrued 6,854 18,150
Interest Accrued 6,979 7,298
Energy Trading and Derivative Contracts 3,260 31,718
Other 24,957 12,216
---------- ----------
TOTAL CURRENT LIABILITIES 389,189 442,602
---------- ----------
DEFERRED INCOME TAXES 341,396 296,877
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 32,201 33,992
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 32,611 49,080
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 1,581 13,461
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $1,776,690 $1,748,911
========== ==========
See Notes to Financial Statements beginning on page L-1.
|
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Consolidated Statements of Cash Flows
-------------------------------------
Year Ended December 31,
---------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 41,060 $ 57,759 $ 66,663
Adjustments to Reconcile Net Income to Net Cash from Operating Activities:
Depreciation and Amortization 85,896 80,245 76,418
Deferred Income Taxes 75,659 (17,751) 25,453
Deferred Investment Tax Credits (1,791) (1,791) (1,791)
Changes in Certain Assets and Liabilities:
Accounts Receivable (net) (3,737) 21,405 (28,826)
Fuel, Materials and Supplies 996 (589) 677
Other Property and Investments (419) (2,809) 7,994
Accounts Payable 25,629 (55,319) 89,330
Taxes Accrued (11,296) 16,491 (16,821)
Fuel Recovery (85,190) 51,987 (36,798)
Transmission Coordination Agreement Settlement - - (15,063)
Changes in Other Assets 2,215 (9,120) 4,482
Changes in Other Liabilities (6,928) 9,351 (6,103)
--------- --------- ---------
Net Cash From Operating Activities 122,094 149,859 165,615
--------- --------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (89,365) (124,520) (176,851)
Proceeds from Sale of Property 963 - -
Other Items - (359) -
--------- --------- ---------
Net Cash Used For
Investing Activities (88,402) (124,879) (176,851)
--------- --------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 187,850 - 105,625
Retirement of Long-term Debt (106,000) (20,000) (20,000)
Change in Advances From Affiliates (net) (36,982) 41,967 1,951
Dividends Paid on Common Stock (67,368) (52,240) (68,000)
Dividends Paid on Cumulative Preferred Stock (213) (213) (212)
--------- --------- ---------
Net Cash From (used For)
Financing Activities (22,713) (30,486) 19,364
--------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 10,979 (5,506) 8,128
Cash and Cash Equivalents January 1 5,795 11,301 3,173
--------- --------- ---------
Cash and Cash Equivalents December 31 $ 16,774 $ 5,795 $ 11,301
========= ========= =========
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $38,620,000,
$38,250,000 and $33,732,000 and for income taxes was ($38,943,000),
$38,653,000 and $25,786,000 in 2002, 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
|
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Consolidated Statements of Capitalization
-----------------------------------------
December 31,
------------
2002 2001
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY $ 399,247 $480,240
--------- --------
PREFERRED STOCK: Cumulative $100 par value - authorized shares 700,000,
redeemable at the option of PSO upon 30 days notice.
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2002 Year Ended December 31, December 31, 2002
------ ------------ ---------------------------- -----------------
2002 2001 2000
---- ---- ----
Not Subject to Mandatory Redemption:
4.00% $105.75 6 - 25 44,600 4,460 4,460
4.24% 103.19 - - - 8,069 807 807
--------- ---------
5,267 5,267
--------- ---------
TRUST PREFERRED SECURITIES
PSO-obligated, mandatorily redeemable preferred securities of subsidiary trust
holding solely Junior Subordinated Debentures of PSO, 8.00%,
due April 30, 2037 75,000 75,000
--------- --------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 298,079 297,772
Installment Purchase Contracts 47,358 47,357
Senior Unsecured Notes 200,000 106,000
Less Portion Due Within One Year (100,000) (106,000)
--------- --------
Long-term Debt Excluding Portion Due Within One Year 445,437 345,129
--------- --------
TOTAL CAPITALIZATION $ 924,951 $905,636
========= ========
See Notes to Financial Statements beginning on page L-1.
|
First mortgage bonds outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
6.25 2003 - April 1 $ 35,000 $ 35,000
7.25 2003 - July 1 65,000 65,000
7.38 2004 - December 1 50,000 50,000
6.50 2005 - June 1 50,000 50,000
7.38 2023 - April 1 100,000 100,000
Unamortized Discount (1,921) (2,228)
-------- --------
$298,079 $297,772
|
First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions.
Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
Oklahoma Environmental
Finance Authority (OEFA):
5.90 2007 - December 1 $ 1,000 $ 1,000
Oklahoma Development
Finance Authority (ODFA):
4.875 2014 - June 1 33,700 33,700
Red River Authority
of Texas:
6.00 2020 - June 1 12,660 12,660
Unamortized Discount (2) (3)
------- -------
Total $47,358 $47,357
======= =======
|
Under the terms of the installment purchase contracts, PSO is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.
Senior unsecured notes outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
(a) 2002 - November 21 $ - $106,000
(b) 2032 - December 31 200,000 -
-------- --------
TOTAL $200,000 $106,000
======== ========
|
(a) A floating interest rate is determined monthly. The rate on December 31,
2001 was $2.775%.
(b) A fixed interest rate of 6.00% was the rate on December 31, 2002.
At December 31, 2002, future annual long-term debt payments are as follows:
Amount
------
(in thousands)
2003 $100,000
2004 50,000
2005 50,000
2006 -
2007 1,000
Later Years 346,360
--------
Total Principal Amount 547,360
Unamortized Discount (1,923)
--------
Total $545,437
========
|
See Note 25 for discussion of the Trust Preferred Securities issued by a wholly owned statutory business trust of PSO (see Note 25).
The notes to PSO's consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to PSO. The combined footnotes begin on page L-1.
Significant Accounting Policies Note 1 Merger Note 4 Rate Matters Note 6 Effects of Regulation Note 7 Customer Choice and Industry Restructuring Note 8 Commitments and Contingencies Note 9 Guarantees Note 10 Sustained Earnings Improvement Initiative Note 11 Benefit Plans Note 14 Business Segments Note 16 Risk Management, Financial Instruments and Derivatives Note 17 Income Taxes Note 18 Leases Note 22 Lines of Credit and Sale of Receivables Note 23 Unaudited Quarterly Financial Information Note 24 Trust Preferred Securities Note 25 Jointly Owned Electric Utility Plant Note 28 Related Party Transactions Note 29 |
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Public Service Company of Oklahoma:
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Public Service Company of Oklahoma and subsidiary as of December 31, 2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Public Service Company of Oklahoma and subsidiary as of December 31, 2002 and 2001, and the results of their operations and their cash flows each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 |
SOUTHWESTERN ELECTRIC POWER COMPANY
AND SUBSIDIARIES
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
------------------------------------
Year Ended December 31,
------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,084,720 $1,101,326 $1,118,274 $ 971,527 $ 952,952
Operating Expenses 942,251 955,119 989,996 824,465 802,274
---------- ---------- ---------- ---------- ----------
Operating Income 142,469 146,207 128,278 147,062 150,678
Nonoperating Items, Net (309) 741 3,851 (1,965) 2,451
Interest Charges 59,168 57,581 59,457 58,892 55,135
---------- ---------- ---------- ---------- ----------
Income Before
Extraordinary Item 82,992 89,367 72,672 86,205 97,994
Extraordinary Loss - - - (3,011) -
---------- ---------- ---------- ---------- ----------
Net Income 82,992 89,367 72,672 83,194 97,994
Preferred Stock Dividend
Requirements 229 229 229 229 705
Loss on
Reacquired Preferred
Stock - - - - (856)
---------- ---------- ---------- ---------- ----------
Earnings Applicable to
Common Stock $ 82,763 $ 89,138 $ 72,443 $ 82,965 $ 96,433
========== ======== ======== ========== ==========
December 31,
------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $3,596,174 $3,460,764 $3,319,024 $3,231,431 $3,157,911
Accumulated Depreciation
and Amortization 1,697,338 1,550,618 1,457,005 1,384,242 1,317,057
---------- ---------- ---------- ---------- ----------
Net Electric Utility
Plant $1,898,836 $1,910,146 $1,862,019 $1,847,189 $1,840,854
========== ========== ========== ========== ==========
Total Assets $2,208,675 $2,300,676 $2,658,389 $2,106,762 $2,082,258
========== ========== ========== ========== ==========
Common Stock and
Paid-in Capital $ 380,663 $ 380,663 $ 380,663 $ 380,663 $ 380,663
Accumulated Other Comprehensive
Income (Loss) (53,683) - - - -
Retained Earnings 334,789 308,915 293,989 283,546 296,581
---------- ---------- ---------- ---------- ----------
Total Common
Shareholder's Equity $ 661,769 $ 689,578 $ 674,652 $ 664,209 $ 677,244
========== ========== ========== ========== ==========
Preferred Stock $ 4,701 $ 4,701 $ 4,701 $ 4,703 $ 4,704
========== ========== ========= ========== ==========
Trust Preferred
Securities $ 110,000 $ 110,000 $ 110,000 $ 110,000 $ 110,000
========== ========== ========== ========== ==========
Long-term Debt (a) $ 693,448 $ 645,283 $ 645,963 $ 541,568 $ 587,673
========== ========== ========== ========== ==========
Total Capitalization and Liabilities $2,208,675 $2,300,676 $2,658,389 $2,106,762 $2,082,258
========== ========== ========== ========== ==========
(a) Including portion due within one year.
|
Southwestern Electric Power Company (SWEPCo) is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 437,000 retail customers in northeastern Texas, northwestern Louisiana and western Arkansas. SWEPCo also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives.
Wholesale power marketing activities are conducted on SWEPCo's behalf by AEPSC. SWEPCo, along with the other AEP electric operating subsidiaries, shares in AEP's electric power transactions with other utility systems and power marketers.
In 2002, Net Income decreased $6.4 million or 7% primarily resulting from reduced margins. In 2001, Net Income increased $16.7 million or 23% resulting primarily from the favorable impact of our sharing in AEP's power marketing activities for a full year.
Increase (Decrease)
From Previous Year
------------------
(dollars in millions)
2002 2001
---- ----
Amount % Amount %
------ - ------ -
Wholesale
Electricity* $(25) (4) $(21) (3)
Energy Delivery* 15 5 (12) (3)
Sales to AEP
Affiliates (7) (9) 16 26
---- ----
Total
Operating
Revenues $(17) (2) $(17) (2)
==== ====
|
*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.
Operating Revenues decreased 2% for 2002 primarily due to decreased fuel revenues offset in part by the addition of the Dolet Hills mining operation ($12.6 million) and the positive impact of the interchange cost reconstruction (ICR) adjustments (see Note 6).
In 2001, Operating Revenues decreased $17 million or 2% resulting from unfavorable wholesale marketing and trading conditions.
Increase (Decrease)
From Previous Year
------------------
(dollars in millions)
2002 2001
---- ----
Amount % Amount %
------ - ------ -
Fuel $(69) (15) $(41) (8)
Purchased
Power:
Wholesale
Electricity 26 143 (40) (69)
AEP
Affiliates 26 165 2 19
Other Operation 18 10 12 7
Maintenance (8) (10) - (1)
Depreciation
and
Amortization 3 3 15 14
Taxes Other
Than
Income Taxes (1) (1) 2 4
Income Taxes (8) (20) 16 60
---- ----
Total $(13) (1) $(34) (4)
==== ====
|
Fuel expense decreased in 2002 due to a reduction in MWH generated and a decrease in the cost of fuel, primarily natural gas.
Fuel expense decreased in 2001 from lower natural gas prices and a mild summer resulting in a reduction in generation.
In 2002, Purchased Power increased primarily due to the impact of ICR adjustments (see Note 6). In 2001, the decrease in Purchased Power expense was mainly due to reduced prices caused by decreased electricity demand.
The acquisition of Dolet Hills Lignite Company (Dolet Hills) in June 2001 caused Other Operation expense to increase in 2002 by $4.3 million. Other Operation expense was also impacted by the ICR adjustments (see Note 6). In 2001, Other Operation expense increased also as a result of the Dolet Hills mining operation in June 2001.
The 10% decrease in Maintenance expense in 2002 is primarily a result of higher storm and tree trimming related expenses in 2001.
The increase in Depreciation and Amortization expense in 2002 is primarily due to the addition of Dolet Hills in June 2001, which added $3.0 million of additional expense in 2002. Depreciation and Amortization expense increased in 2001 due primarily to an increase in excess earnings accruals under the Texas restructuring legislation and the acquisition of Dolet Hills mining operation.
In 2002, the decrease in Income Taxes was due to a decrease in pre-tax income. In 2001, the increase in income tax expense was primarily due to an increase in pre-tax income.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
---------------------------------
Year Ended December 31,
------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING REVENUES:
Wholesale Electricity $ 664,185 $ 689,085 $ 710,200
Energy Delivery 348,236 333,004 344,950
Sales to AEP Affiliates 72,299 79,237 63,124
---------- ---------- ----------
TOTAL OPERATING REVENUES 1,084,720 1,101,326 1,118,274
---------- ---------- ----------
OPERATING EXPENSES:
Fuel 388,334 457,613 498,805
Purchased Power:
Wholesale Electricity 44,119 18,164 58,518
AEP Affiliates 42,022 15,858 13,338
Other Operation 189,024 171,314 159,459
Maintenance 66,855 74,677 75,123
Depreciation and Amortization 122,969 119,543 104,679
Taxes Other Than Income Taxes 55,232 55,834 53,830
Income Taxes 33,696 42,116 26,244
---------- ---------- ----------
TOTAL OPERATING EXPENSES 942,251 955,119 989,996
---------- ---------- ----------
OPERATING INCOME 142,469 146,207 128,278
NONOPERATING INCOME 3,260 4,512 5,487
NONOPERATING EXPENSES 1,797 3,229 3,112
NONOPERATING INCOME TAX EXPENSE (CREDIT) 1,772 542 (1,476)
INTEREST CHARGES 59,168 57,581 59,457
---------- ---------- ----------
NET INCOME 82,992 89,367 72,672
PREFERRED STOCK DIVIDEND REQUIREMENTS 229 229 229
---------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 82,763 $ 89,138 $ 72,443
========== ========== ==========
Consolidated Statements of Comprehensive Income
-----------------------------------------------
Year Ended December 31,
-----------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
NET INCOME $82,992 $89,367 $72,672
OTHER COMPREHENSIVE INCOME (LOSS):
Cash Flow Power Hedges (48) - -
Minimum Pension Liability (53,635) - -
------- ------- -------
COMPREHENSIVE INCOME $29,309 $89,367 $72,672
======= ======= =======
The common stock of SWEPCo is owned by a wholly owned subsidiary of AEP. See
Notes to Financial Statements beginning on page L-1.
|
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
--------------------------------------------
Year Ended December 31,
----------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $308,915 $293,989 $283,546
NET INCOME 82,992 89,367 72,672
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 56,889 74,212 62,000
Preferred Stock 229 229 229
-------- -------- --------
BALANCE AT END OF PERIOD $334,789 $308,915 $293,989
======== ======== ========
The common stock of SWEPCo is owned by a wholly owned subsidiary of AEP. See
Notes to Financial Statements beginning on page L-1.
|
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
---------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $1,503,722 $1,429,356
Transmission 575,003 538,749
Distribution 1,063,564 1,042,523
General 378,130 376,016
Construction Work in Progress 75,755 74,120
---------- ----------
Total Electric Utility Plant 3,596,174 3,460,764
Accumulated Depreciation and Amortization 1,697,338 1,550,618
---------- ----------
NET ELECTRIC UTILITY PLANT 1,898,836 1,910,146
---------- ----------
OTHER PROPERTY AND INVESTMENTS 5,978 43,000
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 5,119 24,508
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 2,069 5,415
Accounts Receivable:
Customers 62,359 43,133
Affiliated Companies 19,253 12,069
Allowance for Uncollectible Accounts (2,128) (89)
Fuel Inventory 61,741 52,212
Materials and Supplies 33,539 32,527
Under-recovered Fuel Costs 2,865 8,839
Energy Trading and Derivative Contracts 4,388 30,139
Prepayments and Other 17,851 18,716
---------- ----------
TOTAL CURRENT ASSETS 201,937 202,961
---------- ----------
REGULATORY ASSETS 49,233 52,308
---------- ----------
DEFERRED CHARGES 47,572 67,753
---------- ----------
TOTAL ASSETS $2,208,675 $2,300,676
========== ==========
See Notes to Financial Statements beginning on page L-1.
|
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
December 31,
-----------
2002 2001
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $18 Par Value:
Authorized - 7,600,000 Shares
Outstanding - 7,536,640 Shares $ 135,660 $ 135,660
Paid-in Capital 245,003 245,003
Accumulated Other Comprehensive Income (Loss) (53,683) -
Retained Earnings 334,789 308,915
---------- ----------
Total Common Shareholder's Equity 661,769 689,578
Preferred Stock 4,701 4,701
SWEPCo-Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely Junior
Subordinated Debentures of SWEPCo 110,000 110,000
Long-term Debt 637,853 494,688
---------- ----------
TOTAL CAPITALIZATION 1,414,323 1,298,967
---------- ----------
OTHER NONCURRENT LIABILITIES 78,494 40,109
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 55,595 150,595
Advances from Affiliates, net 23,239 117,367
Accounts Payable - General 62,139 71,810
Accounts Payable - Affiliated Companies 58,773 37,469
Customer Deposits 20,110 19,880
Taxes Accrued 19,081 36,522
Interest Accrued 17,051 13,027
Energy Trading and Derivative Contracts 3,724 36,297
Over-recovered Fuel 17,226 5,487
Other 34,565 26,074
---------- ----------
TOTAL CURRENT LIABILITIES 311,503 514,528
---------- ----------
DEFERRED INCOME TAXES 341,064 369,781
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 44,190 48,714
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 17,295 13,127
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 1,806 15,450
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $2,208,675 $2,300,676
========== ==========
See Notes to Financial Statements beginning on page L-1.
|
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
-------------------------------------
Year Ended December 31,
--------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 82,992 $ 89,367 $ 72,672
Adjustments to Reconcile Net Income to Net Cash Flows From Operating
Activities:
Depreciation and Amortization 122,969 119,543 104,679
Deferred Income Taxes (3,134) (31,396) 14,653
Deferred Investment Tax Credits (4,524) (4,453) (4,482)
Mark-to-Market Energy Trading and Derivative Contracts (1,151) (10,695) 7,795
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (24,371) (11,447) (1,254)
Fuel, Materials and Supplies (10,541) (19,578) 22,103
Accounts Payable 11,633 (34,489) 43,962
Taxes Accrued (17,441) 25,298 (13,150)
Transmission Coordination Agreement Settlement - - (24,406)
Fuel Recovery 17,713 34,423 (38,357)
Change in Other Assets 24,257 1,323 54,414
Change in Other Liabilities 12,161 11,714 (37,001)
--------- --------- ---------
Net Cash Flows From Operating Activities 210,563 169,610 201,628
--------- --------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (111,775) (111,725) (120,671)
Purchase of Dolet Hills Mining Operations - (85,716) -
Other 1,134 (411) 446
--------- --------- ---------
Net Cash Flows Used For
Investing Activities (110,641) (197,852) (120,225)
--------- --------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 198,573 - 149,360
Redemption of Preferred Stock - - (1)
Retirement of Long-term Debt (150,595) (595) (45,595)
Change in Advances From Affiliates (net) (94,128) 106,786 (124,074)
Dividends Paid on Common Stock (56,889) (74,212) (62,000)
Dividends Paid on Cumulative Preferred Stock (229) (229) (229)
--------- --------- ---------
Net Cash Flows From (Used For)
Financing Activities (103,268) 31,750 (82,539)
--------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (3,346) 3,508 (1,136)
Cash and Cash Equivalents January 1 5,415 1,907 3,043
--------- --------- ---------
Cash and Cash Equivalents December 31 $ 2,069 $ 5,415 $ 1,907
========= ========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $49,008,000, $51,126,000
and $51,111,000 and for income taxes was $60,451,000, $49,901,000 and
$27,994,000 in 2002, 2001, and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
|
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
-----------------------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY $ 661,769 $ 689,578
---------- ----------
PREFERRED STOCK: $100 par value - authorized shares 1,860,000
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2002 Year Ended December 31, December 31, 2002
------ ------------ ---------------------------- -----------------
2002 2001 2000
---- ---- ----
Not Subject to Mandatory Redemption:
4.28% $103.90 - - - 7,386 740 740
4.65% $102.75 - - - 1,907 190 190
5.00% $109.00 - - 12 37,715 3,771 3,771
---------- ----------
4,701 4,701
---------- ----------
TRUST PREFERRED SECURITIES
SWEPCo-Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely
Junior Subordinated Debentures of SWEPCo, 7.875%,
due April 30, 2037 110,000 110,000
---------- ----------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 315,420 315,449
Installment Purchase Contracts 179,183 179,834
Senior Unsecured Notes 198,845 150,000
Less Portion Due Within One Year (55,595) (150,595)
---------- ----------
Long-term Debt Excluding Portion Due Within One Year 637,853 494,688
---------- ----------
TOTAL CAPITALIZATION $1,414,323 $1,298,967
========== ==========
See Notes to Financial Statements beginning on page L-1.
|
% Rate Due
6-5/8 2003 - February 1 $ 55,000 $ 55,000
7-3/4 2004 - June 1 40,000 40,000
6.20 2006 - November 1 5,505 5,650
6.20 2006 - November 1 1,000 1,000
7.00 2007 - September 1 90,000 90,000
7-1/4 2023 - July 1 45,000 45,000
6-7/8 2025 - October 1 80,000 80,000
Unamortized Discount (1,085) (1,201)
-------- --------
$315,420 $315,449
======== ========
|
First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions.
Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:
% Rate Due
DeSoto County:
7.60 2019 - January 1 $ 53,500 $ 53,500 Sabine: 6.10 2018 - April 1 81,700 81,700 |
Titus County:
6.90 2004 - November 1 12,290 12,290
6.00 2008 - January 1 12,620 13,070
8.20 2011 - August 1 17,125 17,125
Unamortized Premium 1,948 2,149
-------- --------
$179,183 $179,834
======== ========
|
Under the terms of the installment purchase contracts, SWEPCo is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.
Senior unsecured notes outstanding were as follows:
% Rate Due
------ ------------------
4.50 2005 - July 1 $200,000 $ -
(a) 2002 - March 1 - 150,000
Unamortized Discount (1,155) -
-------- --------
$198,845 $150,000
======== ========
|
(a)A floating interest rate is determined monthly. The rate on December 31, 2001 was 2.311%.
At December 31, 2002 future annual long-term debt payments are as follows:
Amount
------
(in thousands)
2003 $ 55,595
2004 52,885
2005 200,595
2006 6,520
2007 90,450
Later Years 287,695
--------
Total Principal Amount 693,740
Unamortized Discount (292)
--------
Total $693,448
========
|
See Note 25 for discussion of Trust Preferred Securities issued by a wholly-owned statutory business trust of SWEPCo.
The notes to SWEPCo's consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to SWEPCo. The combined footnotes begin on page L-1.
Combined
Footnote
Reference
---------
Significant Accounting Policies Note 1
Extraordinary Items and Cumulative Effect Note 2
Goodwill and Other Intangible Assets Note 3
Merger Note 4
Rate Matters Note 6
Effects of Regulation Note 7
Customer Choice and Industry Restructuring Note 8
Commitments and Contingencies Note 9
Guarantees Note 10
Sustained Earnings Improvement Initiative Note 11
Acquisitions, Dispositions and Discontinued Operations Note 12
Benefit Plans Note 14
Business Segments Note 16
Risk Management, Financial Instruments and Derivatives Note 17
Income Taxes Note 18
Leases Note 22
Lines of Credit and Sale of Receivables Note 23
Unaudited Quarterly Financial Information Note 24
Trust Preferred Securities Note 25
Jointly Owned Electric Utility Plant Note 28
Related Party Transactions Note 29
|
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Southwestern Electric Power Company:
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Southwestern Electric Power Company and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Southwestern Electric Power Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 |
COMBINED NOTES TO FINANCIAL STATEMENTS
Index to Combined Notes to Financial Statements
The notes to financial statements that follow are a combined presentation for AEP and its subsidiary registrants. The following list of footnotes shows the registrant to which they apply:
1. Significant Accounting Policies AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC, TNC
2. Extraordinary Items and AEP, APCo, CSPCo, OPCo, SWEPCo,
Cumulative Effect TCC, TNC
3. Goodwill and Other Intangible Assets AEP, SWEPCo
4. Merger AEP, I&M, KPCo, PSO, SWEPCo, TCC,
TNC
5. Nuclear Plant Restart AEP, I&M
6. Rate Matters AEP, KPCo, PSO, SWEPCo, TCC, TNC
7. Effects of Regulation AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC, TNC
8. Customer Choice and Industry AEP, APCo, CSPCo, I&M, OPCo, PSO,
Restructuring SWEPCo, TCC, TNC
9. Commitments and Contingencies AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC, TNC
10. Guarantees AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC, TNC
11. Sustained Earnings Improvement AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
Initiative OPCo, PSO, SWEPCo, TCC, TNC
12. Acquisitions, Dispositions and AEP, OPCo, SWEPCo, TCC, TNC
Discontinued Operations
13. Asset Impairments and Investment AEP, APCo, CSPCo, I&M, KPCo, OPCo,
Value Losses TCC, TNC
14. Benefit Plans AEP, APCo, CSPCo, I&M, KPCo, OPCo,
PSO, SWEPCo, TCC, TNC
15. Stock-Based Compensation AEP
16. Business Segments AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC, TNC
17. Risk Management, Financial AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
Instruments and Derivatives OPCo, PSO, SWEPCo, TCC, TNC
18. Income Taxes AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC, TNC
19. Basic and Diluted Earnings Per Share AEP
20. Supplementary Information AEP, APCo, CSPCo, I&M, OPCo
21. Power and Distribution Projects AEP
22. Leases AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC, TNC
23. Lines of Credit and Sale AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
of Receivables OPCo, PSO, SWEPCo, TCC, TNC
24. Unaudited Quarterly Financial AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
Information OPCo, PSO, SWEPCo, TCC, TNC
25. Trust Preferred Securities AEP, PSO, SWEPCo, TCC
26. Minority Interest in Finance AEP
Subsidiary
27. Equity Units AEP
28. Jointly Owned Electric Utility Plant CSPCo, PSO, SWEPCo, TCC, TNC
29. Related Party Transactions AEGCo, APCo, CSPCo, I&M, KPCo, OPCo,
PSO, SWEPCo, TCC, TNC
30. Subsequent Events (Unaudited) AEP
|
1. Significant Accounting Policies:
Business Operations - AEP's (the Company's) principal business conducted by its eleven domestic electric utility operating companies is the generation, transmission and distribution of electric power. Nine of AEP's eleven domestic electric utility operating companies, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC, are SEC registrants. AEGCo is a domestic generating company wholly-owned by AEP that is an SEC registrant. These companies are subject to regulation by the FERC under the Federal Power Act and follow the Uniform System of Accounts prescribed by FERC. They are subject to further regulation with regard to rates and other matters by state regulatory commissions.
AEP also engages in wholesale marketing and trading of electricity, natural gas and to a lesser extent, other commodities in the United States and Europe. In addition, the Company's domestic operations include non-regulated independent power and cogeneration facilities, coal mining and intra-state midstream natural gas operations in Louisiana and Texas.
International operations include supply of electricity and other non-regulated power generation projects in the United Kingdom, and to a lesser extent in Mexico, Australia, China and the Pacific Rim region. These operations are either wholly-owned or partially-owned by various AEP subsidiaries. We also maintained operations in Brazil through the fourth quarter of 2002. See Note 13 for discussion of impaired investments and assets held for sale.
The Company also operates domestic barging operations, provides various energy related services and furnishes communications related services domestically. See Note 13 for further discussion of changes in our communications related business and other business operations announced in 2002.
Rate Regulation - AEP is subject to regulation by the SEC under the PUHCA. The rates charged by the domestic utility subsidiaries are approved by the FERC and the state utility commissions. The FERC regulates wholesale electricity operations and transmission rates and the state commissions regulate retail rates. The prices charged by foreign subsidiaries located in China, Mexico and Brazil are regulated by the authorities of that country and are generally subject to price controls.
Principles of Consolidation - AEP's consolidated financial statements include AEP Co., Inc. and its wholly-owned and majority-owned subsidiaries consolidated with their wholly-owned or substantially controlled subsidiaries. The consolidated financial statements for APCo, CSPCo, I&M, PSO, SWEPCo and TCC include the registrant and its wholly-owned subsidiaries. Significant intercompany items are eliminated in consolidation. Equity investments not substantially controlled that are 50% or less owned are accounted for using the equity method with their equity earnings included in Other Income for AEP and nonoperating income for the registrant subsidiaries.
Basis of Accounting - As the owner of cost-based rate-regulated electric public utility companies, AEP Co., Inc.'s consolidated financial statements reflect the actions of regulators that result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation," regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues. Application of SFAS 71 for the generation portion of the business was discontinued as follows: in Ohio by OPCo and CSPCo in September 2000, in Virginia and West Virginia by APCo in June 2000, in Texas by TCC, TNC, and SWEPCo in September 1999 and in Arkansas by SWEPCo in September 1999. See Note 8, "Customer Choice and Industry Restructuring" for additional information.
Use of Estimates - The preparation of these financial statements in conformity with generally accepted accounting principles necessarily includes the use of estimates and assumptions by management. Actual results could differ from those estimates.
Property, Plant and Equipment - Domestic electric utility property, plant and equipment are stated at original cost of the acquirer. Property, plant and equipment of the non-regulated operations and other investments are stated at their fair market value at acquisition plus the original cost of property acquired or constructed since the acquisition, less disposals. Additions, major replacements and betterments are added to the plant accounts. For cost-based rate-regulated operations, retirements from the plant accounts and associated removal costs, net of salvage, are deducted from accumulated depreciation. The costs of labor, materials and overhead incurred to operate and maintain plant are included in operating expenses. Plants are tested for impairment as required under SFAS 144. See Note 13.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
- AFUDC is a noncash, nonoperating income item that is capitalized and recovered
through depreciation over the service life of domestic regulated electric
utility plant. It represents the estimated cost of borrowed and equity funds
used to finance construction projects. The amounts of AFUDC for 2002, 2001 and
2000 were not significant. Effective with the discontinuance of SFAS 71
regulatory accounting for domestic generating assets in Arkansas, Ohio, Texas,
Virginia, West Virginia and other non-regulated operations, interest is
capitalized during construction in accordance with SFAS 34, "Capitalization of
Interest Costs." The amounts of interest capitalized were not material in 2002,
2001, and 2000.
Depreciation, Depletion and Amortization - Depreciation of property, plant and equipment is provided on a straight-line basis over the estimated useful lives of property, other than coal-mining property, and is calculated largely through the use of composite rates by functional class as follows:
Annual Composite
Functional Class Depreciation Rates
of Property Ranges
---------------- ------------------
2002
----
Production:
Steam-Nuclear 2.5% to 3.4%
Steam-Fossil-Fired 2.6% to 4.5%
Hydroelectric- Conventional
and Pumped Storage 1.9% to 3.4%
Transmission 1.7% to 3.0%
Distribution 3.3% to 4.2%
Other 1.8% to 9.9%
Annual Composite
Functional Class Depreciation Rates
of Property Ranges
---------------- ------------------
2001
----
Production:
Steam-Nuclear 2.5% to 3.4%
Steam-Fossil-Fired 2.5% to 4.5%
Hydroelectric- Conventional
and Pumped Storage 1.9% to 3.4%
Transmission 1.7% to 3.1%
Distribution 2.7% to 4.2%
Other 1.8% to 15.0%
Annual Composite
Functional Class Depreciation Rates
of Property Ranges
---------------- ------------------
2000
----
Production:
Steam-Nuclear 2.8% to 3.4%
Steam-Fossil-Fired 2.3% to 4.5%
Hydroelectric- Conventional
and Pumped Storage 1.9% to 3.4%
Transmission 1.7% to 3.1%
Distribution 3.3% to 4.2%
Other 2.5% to 7.3%
|
The following table provides the annual composite depreciation rates generally used by the AEP registrant subsidiaries for the years 2002, 2001 and 2000 which were as follows:
Nuclear Steam Hydro Transmission Distribution General
------- ----- ----- ------------ ------------ -------
AEGCo - % 3.5% - % - % - % 2.8%
APCo - 3.4 2.9 2.2 3.3 3.1
CSPCo - 3.2 - 2.3 3.6 3.2
I&M 3.4 4.5 3.4 1.9 4.2 3.8
KPCo - 3.8 - 1.7 3.5 2.5
OPCo - 3.4 2.7 2.3 4.0 2.7
PSO - 2.7 - 2.3 3.4 6.3
SWEPCo - 3.4 - 2.7 3.6 4.7
TCC 2.5 2.6 1.9 2.3 3.5 4.0
TNC - 2.8 - 3.1 3.3 6.8
|
Depreciation, depletion and amortization of coal-mining assets is provided over each asset's estimated useful life or the estimated life of the mine, whichever is shorter, and is calculated using the straight-line method for mining structures and equipment. The units-of-production method is used to amortize coal rights and mine development costs based on estimated recoverable tonnages. These costs are included in the cost of coal charged to fuel expense for coal used by utility operations. Current average amortization rates are $0.32 per ton in 2002, $3.46 per ton in 2001 and $5.07 per ton in 2000. In 2001, an AEP subsidiary sold coal mines in Ohio and West Virginia. See Note 12, Acquisitions, Dispositions and Discontinued Operations for further discussion of the changes in our coal investments leading to the decline in amortization rates in 2002.
Cash and Cash Equivalents - Cash and cash equivalents include temporary cash investments with original maturities of three months or less.
Inventory - Except for PSO, TCC and TNC, the regulated domestic utility companies value fossil fuel inventories using a weighted average cost method. PSO, TCC and TNC, utilize the LIFO method to value fossil fuel inventories. For those domestic utilities whose generation is unregulated, inventory of coal and oil is carried at the lower of cost or market. Coal mine inventories are also carried at the lower of cost or market. Materials and supplies inventories are carried at average cost.
Non-trading gas inventory is carried at the lower of cost or market. In compliance with EITF 02-03 as described in the New Accounting Pronouncements section of Note 1, natural gas inventories held in connection with trading operations at October 25, 2002 continued to be carried at fair value until December 31, 2002, and inventory purchased from October 26 through December 31, 2002 was carried at the lower of cost or market. Effective January 1, 2003, all natural gas inventories held in connection with trading operations will be adjusted to the historical cost basis and carried at the lower of cost or market. We estimate the adjustment in January 2003 will decrease the value of natural gas inventories held in connection with trading operations by approximately $39 million. This change will be accounted for as a cumulative effect of a change in accounting principle.
Accounts Receivable - AEP Credit, Inc. factors accounts receivable for certain of the domestic utility subsidiaries and, until the first quarter of 2002, factored accounts receivable for certain non-affiliated utilities. On December 31, 2001 AEP Credit, Inc. entered into a sale of receivables agreement with a group of banks and commercial paper conduits. This transaction constitutes a sale of receivables in accordance with SFAS 140, allowing the receivables to be taken off of the company's balance sheet. See Note 23 for further details.
Foreign Currency Translation - The financial statements of subsidiaries outside the U.S. which are included in AEP's consolidated financial statements are measured using the local currency as the functional currency and translated into U.S. dollars in accordance with SFAS 52 "Foreign Currency Translation". Assets and liabilities are translated to U.S. dollars at year-end rates of exchange and revenues and expenses are translated at monthly average exchange rates throughout the year. Currency translation gain and loss adjustments are recorded in shareholders' equity as Accumulated Other Comprehensive Income (Loss). The non-cash impact of the changes in exchange rates on cash, resulting from the translation of items at different exchange rates, is shown on AEP's Consolidated Statements of Cash Flows in Effect of Exchange Rate Changes on Cash. Actual currency transaction gains and losses are recorded in income.
Deferred Fuel Costs - The cost of fuel consumed is charged to expense when the fuel is burned. Where applicable under governing state regulatory commission retail rate orders, fuel cost over or under-recoveries are deferred as regulatory liabilities or regulatory assets in accordance with SFAS 71. These deferrals generally are amortized when refunded or billed to customers in later months with the regulator's review and approval. The amount of deferred fuel costs under fuel clauses for AEP was $143 million at December 31, 2002 and $139 million at December 31, 2001. See Note 7 "Effects of Regulation".
We are protected from fuel cost changes in Kentucky for KPCo, the SPP area of Texas, Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia for APCo. Where fuel clauses have been eliminated due to the transition to market pricing, (Ohio effective January 1, 2001 and in the Texas ERCOT area effective January 1, 2002) changes in fuel costs impact earnings. In other state jurisdictions, (Indiana, Michigan and West Virginia) where fuel clauses have been frozen or suspended for a period of years, fuel cost changes also impact earnings. This is also true for certain of AEP's Independent Power Producer generating units that do not have long-term contracts for their fuel supply. See Note 6, "Rate Matters" and Note 8, "Customer Choice and Industry Restructuring" for further information about fuel recovery.
Revenue Recognition -
Regulatory Accounting - The consolidated financial statements of AEP and the financial statements of electric operating subsidiary companies with cost-based rate-regulated operations (I&M, KPCo, PSO, and a portion of APCo, OPCo, CSPCo, TCC, TNC and SWEPCo), reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period and by matching income with its passage to customers through regulated revenues in the same accounting period. Regulatory liabilities are also recorded to provide currently for refunds to customers that have not yet been made.
When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates.
Traditional Electricity Supply and Delivery Activities - Revenues are recognized on the accrual or settlement basis for normal retail and wholesale electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general, expenses are recorded when purchased electricity is received and when expenses are incurred.
Domestic Gas Pipeline and Storage Activities - Revenues are recognized from domestic gas pipeline and storage services when gas is delivered to contractual meter points or when services are provided. Transportation and storage revenues also include the accrual of earned, but unbilled and/or not yet metered gas.
Substantially all of the forward gas purchase and sale contracts, excluding wellhead purchases of natural gas, swaps and options for the domestic pipeline operations, qualify as derivative financial instruments as defined by SFAS 133. Accordingly, net gains and losses resulting from revaluation of these contacts to fair value during the period are recognized currently in the results of operations, appropriately discounted and net of applicable credit and liquidity reserves.
Energy Marketing and Trading Transactions - In 2000, 2001 and throughout the majority of 2002, AEP engaged in wholesale electricity, natural gas and other commodity marketing and trading transactions (trading activities). Trading activities involve the purchase and sale of energy under forward contracts at fixed and variable prices and the trading of financial energy contracts which includes exchange futures and options and over-the-counter options and swaps. We use the mark-to-market method of accounting for trading activities as required by EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 98-10). Under the mark-to-market method of accounting, gains and losses from settlements of forward trading contracts are recorded net in revenues. For energy contracts not yet settled, whether physical or financial, changes in fair value are recorded net in revenues as unrealized gains and losses from mark-to-market valuations. When positions are settled and gains and losses are realized, the previously recorded unrealized gains and losses from mark-to-market valuations are reversed. In October 2002, management announced plans to focus on wholesale markets around owned assets.
All of the registrant subsidiaries except AEGCo participate in AEP's wholesale marketing and trading of electricity. For I&M, KPCo, PSO and a portion of TNC and SWEPCo, when the contract settles the total gain or loss is realized in cash. Where this amount is recorded on the income statement depends on whether the contract's delivery points are within or outside of AEP's traditional marketing area. For contracts with delivery points in AEP's traditional marketing area, the total gain or loss realized in cash for sales and the cost of purchased energy are included in revenues on a net basis. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses). For contracts with delivery points outside of AEP's traditional marketing area only the difference between the accumulated unrealized net gains or losses recorded in prior periods and the cash proceeds is recognized in the income statement as nonoperating income. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate.
For APCo, CSPCo and OPCo, depending on whether the delivery point for the electricity is in AEP's traditional marketing area or not determines where the contract is reported in the income statement. Physical forward trading sale and purchase contracts with delivery points in AEP's traditional marketing area are included in revenues on a net basis. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are also included in revenues on a net basis. Physical forward sale and purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis.
The trading of energy options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in AEP's revenues until the contracts settle. When these contracts settle, the net proceeds are recorded in revenues and reverse the prior cumulative unrealized net gain or loss. APCo, CSPCo, OPCo, I&M and KPCo also have financial transactions, but record the unrealized gains and losses, as well as the net proceeds upon settlement, in nonoperating income.
The fair values of open short-term trading contracts are based on exchange prices and broker quotes. Open long-term trading contracts are marked-to-market based mainly on AEP- developed valuation models. The models are derived from internally assessed market prices with the exception of the NYMEX gas curve, where we use daily settled prices. All fair value amounts are net of appropriate valuation adjustments for items such as discounting, liquidity and credit quality. Such valuation adjustments provide for a better approximation of fair value. The use of these models to fair value open trading contracts has inherent risks relating to the underlying assumptions employed by such models. Independent controls are in place to evaluate the reasonableness of the price curve models. Significant adverse or favorable effects on future results of operations and cash flows could occur if market prices, at the time of settlement, do not correlate with AEP-developed price models.
As explained above, the effect on AEP's Consolidated Statements of Operations of marking to market open electricity trading contracts in AEP's regulated jurisdictions is deferred as regulatory assets (losses) or liabilities (gains) since these transactions are included in cost of service on a settlement basis for ratemaking purposes. Unrealized mark-to-market gains and losses from trading activities whether deferred or recognized in revenues are part of Energy Trading and Derivative Contracts assets or liabilities as appropriate.
Construction Projects for Outside Parties - Certain AEP entities engage in construction projects for outside parties that are accounted for on the percentage-of-completion method of revenue recognition. This method recognizes revenue in proportion to costs incurred compared to total estimated costs.
Debt Instrument Hedging and Related Activities - In order to mitigate the risks
of market price and interest rate fluctuations, AEP, APCo, CSPCo, I&M, KPCo and
OPCo enter into contracts to manage the exposure to unfavorable changes in the
cost of debt to be issued. These anticipatory debt instruments are entered into
in order to manage the change in interest rates between the time a debt offering
is initiated and the issuance of the debt (usually a period of 60 days). Gains
or losses from these transactions are deferred and amortized over the life of
the debt issuance with the amortization included in interest charges. There were
no such forward contracts outstanding at December 31, 2002 or 2001. See Note 17
- "Risk Management, Financial Instruments and Derivatives" for further
discussion of the accounting for risk management transactions.
Levelization of Nuclear Refueling Outage Costs - In order to match costs with regulated revenues, incremental operation and maintenance costs associated with periodic refueling outages at I&M's Cook Plant are deferred and amortized over the period beginning with the commencement of an outage and ending with the beginning of the next outage.
Maintenance Costs - Maintenance costs are expensed as incurred except where SFAS 71 requires the recordation of a regulatory asset to match the expensing of maintenance costs with their recovery in cost-based regulated revenues. See below for an explanation of costs deferred in connection with an extended outage at I&M's Cook Plant.
Amortization of Cook Plant Deferred Restart Costs - Pursuant to settlement agreements approved by the IURC and the MPSC to resolve all issues related to an extended outage of the Cook Plant, I&M deferred $200 million of incremental operation and maintenance costs during 1999. The deferred amount is being amortized to expense on a straight-line basis over five years from January 1, 1999 to December 31, 2003. I&M amortized $40 million each year 1999 through 2002 leaving $40 million as an SFAS 71 regulatory asset at December 31, 2002 on the Consolidated Balance Sheets of AEP and I&M.
Other Income and Other Expenses - Other Income includes non-operational revenue including area business development and river transportation, equity earnings of non-consolidated subsidiaries, gains on dispositions of property, interest and dividends, an allowance for equity funds used during construction (explained above) and miscellaneous income. Other Expenses includes non-operational expense including area business development and river transportation, losses on dispositions of property, miscellaneous amortization, donations and various other non-operating and miscellaneous expenses.
AEP Consolidated Other Income and Deductions
December 31,
2002 2001 2000
---- ---- ----
(in millions)
OTHER INCOME:
Equity Earnings $ 104 $ 123 $ 22
Non-operational Revenue 187 123 71
Interest and Miscellaneous
Income 25 16 2
Gain on Sale of Frontera
- 73 -
Gain on Sale of Retail
Electric Provider 129 - -
----- ----- ----
Total Other Income $ 445 $ 335 $ 95
===== ===== ====
OTHER EXPENSES:
Property Taxes and
Miscellaneous Expenses $ 142 $ 68 $ 28
Non-operational Expenses
179 56 49
Fiber Optic and
Datapult Exit Costs - 49 -
Provision for Loss - Airplane
- 14 -
----- ----- ----
Total Other Expenses $ 321 $ 187 $ 77
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Income Taxes - The AEP System follows the liability method of accounting for income taxes as prescribed by SFAS 109, "Accounting for Income Taxes." Under the liability method, deferred income taxes are provided for all temporary differences between the book cost and tax basis of assets and liabilities which will result in a future tax consequence. Where the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established in accordance with SFAS 71 to match the regulated revenues and tax expense.
Investment Tax Credits - Investment tax credits have been accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are being amortized over the life of the regulated plant investment.
Excise Taxes - AEP and its subsidiary registrants, as an agent for a state or local government, collect from customers certain excise taxes levied by the state or local government upon the customer. These taxes are not recorded as revenue or expense, but only as a pass-through billing to the customer to be remitted to the government entity. Excise tax collections and payments related to taxes imposed upon the customer are not presented in the income statement.
Debt and Preferred Stock - Gains and losses from the reacquisition of debt used to finance domestic regulated electric utility plant are generally deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment. If debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost based regulatory accounting under SFAS 71 are generally deferred and amortized over the term of the replacement debt commensurate with their recovery in rates. Gains and losses on the reacquisition of debt for operations not subject to SFAS 71 are reported as a Loss on Reacquired Debt, an extraordinary item on the Consolidated Statements of Operations of AEP and TCC. See discussion of SFAS 145 in New Accounting Pronouncements section of this note for new treatment effective in 2003.
Debt discount or premium and debt issuance expenses are deferred and amortized utilizing the effective interest rate method over the term of the related debt. The amortization expense is included in interest charges.
Where rates are regulated, redemption premiums paid to reacquire preferred stock of the domestic utility subsidiaries are included in paid-in capital and amortized to retained earnings commensurate with their recovery in rates. The excess of par value over costs of preferred stock reacquired is credited to paid-in capital and amortized to retained earnings consistent with the timing of its inclusion in rates in accordance with SFAS 71.
Goodwill and Intangible Assets - In June 2001, the FASB issued SFAS 141, Business Combinations, and SFAS 142, Goodwill and Other Intangible Assets, affecting AEP and SWEPCo.
SFAS 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001 and established new standards for the recognition of certain identifiable intangible assets, separate from goodwill. We adopted the provisions of SFAS 141 effective July 1, 2001. See Note 12 for further discussion of acquisitions initiated after June 30, 2001 and Note 3 for further discussion of our components of goodwill and intangible assets.
SFAS 142 requires that goodwill and intangible assets with finite useful lives no longer be amortized, but instead tested for impairment at least annually. SFAS 142 also requires that intangible assets with finite useful lives be amortized over their respective estimated lives to the estimated residual values. In accordance with SFAS 142, for all business combinations with an acquisition date before July 1, 2001, we amortized goodwill and intangible assets with indefinite lives through December 2001, and then ceased amortization. The goodwill associated with those business combinations with an acquisition date before July 1, 2001 was amortized on a straight-line basis generally over 40 years except for the portion of goodwill associated with gas trading and marketing activities which was amortized on a straight-line basis over 10 years. In accordance with SFAS 142, for all business combinations with an acquisition date after June 30, 2001, we have not amortized goodwill and intangible assets with indefinite lives. Intangible assets with finite lives continue to be amortized over their respective estimated lives ranging from 5 to 10 years. See Note 3 for total goodwill, accumulated amortization and the impact on operations of the adoption of SFAS 142.
In early 2002, we began testing our goodwill and intangible assets with indefinite useful lives for impairment, in accordance with SFAS 142. See Note 3 for the results of our testing and the corresponding net transitional impairment loss recorded as a Cumulative Effect of Accounting Change during 2002.
Nuclear Trust Funds - Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions have allowed us to collect through rates to fund future decommissioning and spent fuel disposal liabilities. By rules or orders, the state jurisdictional commissions (Indiana, Michigan and Texas) and the FERC established investment limitations and general risk management guidelines to protect their ratepayers' funds and to allow those funds to earn a reasonable return. In general, limitations include:
o Acceptable investments (rated investment grade or above)
o Maximum percentage invested in a specific type of investment
o Prohibition of investment in obligations of the applicable company or
its affiliates.
Trust funds are maintained for each regulatory jurisdiction and managed by investment managers, who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested in order to optimize the after-tax earnings of the Trust, giving consideration to liquidity, risk, diversification, and other prudent investment objectives.
Securities held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel are included in Other Assets at market value in accordance with SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities." Securities in the trust funds have been classified as available-for-sale due to their long-term purpose. In accordance with SFAS 71, unrealized gains and losses from securities in these trust funds are not reported in equity but result in adjustments to the liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the spent nuclear fuel disposal trust funds in accordance with their treatment in rates.
Comprehensive Income (Loss) - Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss). There were no material differences between net income and comprehensive income for AEGCo.
Components of Other Comprehensive Income (Loss) - Other comprehensive income
(loss) is included on the balance sheet in the equity section. The following
table provides the components that comprise the balance sheet amount in
Accumulated Other Comprehensive Income (Loss) for AEP.
December 31,
Components 2002 2001 2000
------------------------------------------------------------
(in millions)
Foreign Currency
Adjustments $ 4 $(113) $ (99)
Unrealized Losses
On Securities (2) - -
Unrealized Gain on
Hedged Derivatives (16) (3) -
Minimum Pension
Liability (595) (10) (4)
----- ----- -----
$(609) $(126) $(103)
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Accumulated Other Comprehensive Income (Loss) for AEP registrant subsidiaries as of December 31, 2002 and 2001 is shown in the following table. Registrant subsidiary balances for Accumulated Other Comprehensive Income (Loss) for the year ended December 31, 2000 was zero.
December 31,
Components 2002 2001
------------------------------------------------------
(in thousands)
Cash Flow Hedges:
APCo $(1,920) $ (340)
CSPCo (267) -
I&M (286) (3,835)
KPCo 322 (1,903)
OPCo (738) (196)
PSO (42) -
SWEPCo (48) -
TCC (36) -
TNC (15) -
Minimum Pension
Liability:
APCo $(70,162) $ -
CSPCo (59,090) -
I&M (40,201) -
KPCo (9,773) -
OPCo (72,148) -
PSO (54,431) -
SWEPCo (53,635) -
TCC (73,124) -
TNC (30,748) -
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Segment Reporting - The AEP System has adopted SFAS No. 131, which requires disclosure of selected financial information by business segment as viewed by the chief operating decision-maker. See Note 16, "Business Segments" for further discussion and details regarding segments.
Common Stock Options - At December 31, 2002, AEP has two stock-based employee compensation plans with outstanding stock options, which are described more fully in Note 15. AEP accounts for these plans under the recognition and measurement principles of APB Opinion No. 25, Accounting for Stock Issued to Employees and related Interpretations. No stock-based employee compensation expense is reflected in AEP's earnings, as all options granted under these plans had exercise prices equal to or above the market value of the underlying common stock on the date of grant. The following table illustrates the effect on AEP's net income (loss) and earnings (loss) per share as if AEP had applied the fair value recognition provisions of FASB Statement No. 123, "Accounting for Stock-Based Compensation", to stock-based employee compensation.
Year Ended December 31,
2002 2001 2000
---- ---- ----
(in millions
except per share data)
Net Income(Loss), as reported $ (519) $ 971 $ 267
Deduct: Total stock-based
employee compensation
expense determined
under fair value
based method for
all awards, net of
related tax effects (9) (12) (3)
------ ----- -----
Pro forma net income
(loss) $ (528) $ 959 $ 264
====== ===== =====
Earnings (Loss) per share:
Basic - as reported
$(1.57) $3.01 $0.83
====== ===== =====
Basic - pro forma $(1.59) $2.98 $0.82
====== ===== =====
Diluted - as reported
$(1.57) $3.01 $0.83
====== ===== =====
Diluted - pro forma $(1.59) $2.97 $0.82
====== ===== =====
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Earnings Per Share (EPS) - AEP calculates earnings (loss) per share in
accordance with SFAS No. 128, "Earnings Per Share" (see Note 19). Basic earnings
(loss) per common share is calculated by dividing net earnings (loss) available
to common shareholders by the weighted average number of common shares
outstanding during the period. Diluted earnings (loss) per common share is
calculated by adjusting the weighted average outstanding common shares, assuming
conversion of all potentially dilutive stock options and awards. The effects of
stock options have not been included in the fiscal 2002 diluted loss per common
share calculation as their effect would have been anti-dilutive. Basic and
diluted EPS are the same in 2002, 2001 and 2000.
AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC are wholly-owned subsidiaries of AEP and are not required to report EPS.
Reclassification - Beginning in the fourth quarter of 2002, AEP and its registrant subsidiaries elected to begin netting certain assets and liabilities related to forward physical and financial transactions. This is done in accordance with FASB Interpretation No. 39, "Offsetting of Amounts Related to Certain Contracts" and Emerging Issues Task Force Topic D-43, "Assurance That a Right of Setoff is Enforceable in a Bankruptcy under FASB Interpretation No. 39". Transactions with common counterparties have been netted at the applicable entity level, by commodity and type (physical or financial) where the legal right of offset exists. For comparability purposes, prior periods presented in this report have been netted in accordance with this policy.
Certain additional prior year financial statement items have been reclassified to conform to current year presentation. Such reclassifications had no impact on previously reported net income.
New Accounting Pronouncements
SFAS 142, "Goodwill and Other Intangible Assets", was effective for AEP on January 1, 2002. The adoption of SFAS 142 required the transition testing for impairment of all indefinite lived intangibles by the end of the first quarter 2002 and initial testing of goodwill by the end of the second quarter 2002. In the first quarter 2002, AEP completed testing the goodwill of its domestic operations and its indefinite lived intangible assets and there was no impairment. In the second quarter 2002, AEP completed initial testing for goodwill impairment of the U.K. and Australian retail electricity and supply operations. The fair values of the U.K. and Australia retail electricity and supply operations were estimated using a combination of market values based on recent market transactions and cash flow projections. As a result of that testing, AEP determined that there was a net transitional impairment loss, which is reported as a cumulative effect of a change in accounting principle. See Notes 2, 3, 12 and 13 for further discussion of the actual impairment charges and sales of impaired assets.
SFAS 142 also changed the accounting and reporting for goodwill and other intangible assets. In accordance with SFAS 142 goodwill and indefinite lived intangible assets acquired through acquisition after June 30, 2001 were not amortized. Effective January 1, 2002, amortization related to goodwill and indefinite lived intangible assets acquired before July 1, 2001 ceased. SFAS 142 requires that other intangible assets be separately identified and if they have finite lives, they must be amortized over that life. See Note 3 for amortization lives of AEP's and SWEPCo's intangible assets.
SFAS 143, "Accounting for Asset Retirement Obligations", is effective for AEP on January 1, 2003. SFAS 143 generally applies to legal obligations associated with the retirement of long-lived assets. A company is required to recognize an estimated liability for any legal obligations associated with the future retirement of its long-lived assets. The liability is measured at fair value and is capitalized as part of the related asset's capitalized cost. The increase in the capitalized cost is included in determining depreciation expense over the expected useful life of the asset. The catch-up effect of adopting SFAS 143 will be recorded as a cumulative effect of an accounting change. Additionally, because the asset retirement obligation is recorded initially at fair value, accretion expense (similar to interest) will be recognized each period as an operating expense in the statement of operations.
The regulated entities have an asset retirement obligation associated with nuclear decommissioning costs for the Cook and STP Nuclear Plants (affects I&M and TCC) and possibly other obligations. AEP expects to establish regulatory assets and liabilities that will result in no cumulative effect adjustment of adopting SFAS 143 for the regulated entities.
In addition, the regulated transmission and distribution entities have asset retirement obligations related to the final retirement of certain transmission and distribution lines. There are also underground storage tanks located at various sites throughout the AEP System and PCB's are contained in certain transformer rectifier sets at power plants. The amounts relating to these obligations cannot be determined because the entities are not able to estimate the final retirement dates for these facilities.
In January 2003, the SEC Staff concluded that SFAS 143 also precludes an entity from recording an expense for estimated costs associated with the removal or retirement of assets that result from other than legal obligations. The SEC Staff concluded that amounts that are included in accumulated depreciation related to estimated removal costs arising from other than legal obligations should be written off as part of the cumulative effect of adopting SFAS 143 unless the company is regulated under SFAS 71. Companies regulated under SFAS 71 may continue to include removal costs in depreciation rates but must quantify the removal costs included in accumulated depreciation as regulatory liabilities in footnote disclosure. The AEP registrant subsidiaries that are regulated entities have included estimated removal costs for non-legal retirement obligations in book depreciation rates.
For non-regulated entities, including certain formerly regulated generation facilities, asset retirement obligations associated with wind farms, closure costs associated with power plants in the U.K. and possibly other items will be incurred. Also the amount of removal costs embedded in accumulated depreciation is expected to result in a favorable cumulative effect adjustment to net income. However, AEP and its registrant subsidiaries have not completed their determination of the net effect of these items on first quarter 2003 results of operations upon the adoption of the provisions of this standard.
In August 2001, the FASB issued SFAS 144, "Accounting for the Impairment or Disposal of Long-lived Assets" which sets forth the accounting to recognize and measure an impairment loss. This standard replaced, SFAS 121, "Accounting for Long-lived Assets and for Long-lived Assets to be Disposed Of." AEP adopted SFAS 144 effective January 1, 2002. The adoption of SFAS 144 did not materially affect AEP's results of operations or financial conditions. See Notes 3 and 13 for discussion of impairments recognized in 2002 by AEP and its registrant subsidiaries, affected by SFAS 144.
In April 2002, the FASB issued SFAS 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections". SFAS 145 rescinds SFAS 4, "Reporting Gains and Losses from Extinguishment of Debt", effective for fiscal years beginning after May 15, 2002. SFAS 4 required gains and losses from extinguishment of debt to be aggregated and classified as an extraordinary item if material. In 2003, for financial reporting purposes AEP and TCC will reclassify extraordinary losses net of tax on TCC's reacquired debt of $2 million for 2001.
In October 2002, the Emerging Issues Task Force of the FASB reached a final consensus on Issue No. 02-3, "Recognition and Reporting of Gains and Losses on Energy Contracts under Issues No. 98-10 and 00-17" (EITF 02-3). EITF 02-3 rescinds EITF 98-10 and related interpretive guidance. Under EITF 02-3, mark-to-market accounting is precluded for energy trading contracts that are not derivatives pursuant to SFAS 133. The consensus to rescind EITF 98-10 will also eliminate any basis for recognizing physical inventories at fair value other than as provided by generally accepted accounting principles. The consensus is effective for fiscal periods beginning after December 15, 2002, and applies to all energy trading contracts entered into and inventory purchased through October 25, 2002. Effective January 1, 2003, nonderivative energy contracts are required to be accounted for on a settlement basis and inventory is required to be presented at the lower of cost or market. The effect of implementing this consensus will be reported as a cumulative effect of an accounting change. Such contracts and inventory will continue to be accounted for at fair value through December 31, 2002. Energy contracts that qualify as derivatives will continue to be accounted for at fair value under SFAS 133.
Effective January 1, 2003, EITF 02-3 requires that gains and losses on all derivatives, whether settled financially or physically, be reported in the income statement on a net basis if the derivatives are held for trading purposes. Previous guidance in EITF 98-10 permitted non-financial settled energy trading contracts to be reported either gross or net in the income statement. Prior to the third quarter of 2002, AEP and its registrant subsidiaries recorded and reported upon settlement, sales under forward trading contracts as revenues and purchases under forward trading contracts as purchased energy expenses. Effective July 1, 2002, AEP and its registrant subsidiaries reclassified such forward trading revenues and purchases on a net basis, as permitted by EITF 98-10. The reclassification of such trading activity to a net basis of reporting resulted in a substantial reduction in both revenues and purchased energy expense, but did not have any impact on financial condition, results of operations or cash flows.
Effective July 1, 2002, AEP and its registrant subsidiaries modified their valuation procedures for estimating the fair value of energy trading contracts at inception. Unrealized gain or loss at inception is recognized only when the fair value of a contract is obtained from a quoted market price in an active market or is otherwise evidenced by comparison to other observable market data. Any fair value changes subsequent to the inception of a contract, however, are recognized immediately based on the best market data available. AEP and its registrant subsidiaries now also use such procedures for determining unrealized gain or loss at inception for all derivative contracts.
In June 2002, FASB issued SFAS 146 which addresses accounting for costs associated with exit or disposal activities. This statement supersedes previous accounting guidance, principally EITF No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." Under EITF No. 94-3, a liability for an exit cost was recognized at the date of an entity's commitment to an exit plan. SFAS 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. SFAS 146 also establishes that the liability should initially be measured and recorded at fair value. The timing of recognizing future costs related to exit or disposal activities, including restructuring, as well as the amounts recognized may be affected by SFAS 146. AEP will adopt the provisions of SFAS 146 for exit or disposal activities initiated after December 31, 2002.
In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45) which requires that a liability related to issuing a guarantee be recognized, as well as additional disclosures of guarantees. This new guidance is an interpretation of SFAS Nos. 5, 57 and 107 and a rescission of FIN No. 34. The initial recognition and initial measurement provisions of FIN 45 are effective on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements of FIN 45 are effective for financial statements of interim and annual periods ending after December 15, 2002. We do not expect that the implementation of FIN 45 will materially affect results of operations, cash flows or financial condition. See guarantee details discussed in Note 10.
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure", which amends SFAS No. 123, "Accounting for Stock-Based Compensation". SFAS 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. Under the fair value based method, compensation cost for stock options is measured when options are issued. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require more prominent and more frequent (quarterly) disclosures in financial statements of the effects of stock-based compensation. SFAS 148 is effective for fiscal years ending after December 15, 2002. AEP does not currently intend to adopt the fair value based method of accounting for stock options.
In November 2002, the FASB issued an Invitation to Comment, "Accounting for Stock-Based Compensation: A Comparison of FASB Statement No. 123, Accounting for Stock-Based Compensation, and Its Related Interpretations, and IASB Proposed IFRS, Share-Based Payment." The FASB plans to make a decision in the first quarter of 2003 whether it will begin a more comprehensive reconsideration of the accounting for stock options. This may include revisiting the decision in SFAS 123 allowing companies to disclose the pro forma effects of the fair value based method rather than requiring recognition of the fair value of employee stock options as an expense.
In January 2003, the FASB issued FASB Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46) which changes the requirements for consolidation of certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This new guidance is an interpretation of Accounting Research Bulletin (ARB) No. 51, "Consolidated Financial Statements". The initial recognition and initial measurement provisions of FIN 46 for all enterprises with variable interests in variable interest entities created after January 31, 2003, shall apply the provisions of this Interpretation to those entities immediately. A public entity with variable interests in variable interest entities created before February 1, 2003 shall apply the provisions of this Interpretation no later than the beginning of the first interim or annual reporting period beginning after June 15, 2003.
If it is reasonably possible that an enterprise will consolidate or disclose information about a variable interest entity when this Interpretation becomes effective, the enterprise shall disclose the following information in all financial statements initially issued after January 31, 2003, regardless of the date on which the variable interest entity was created:
a. The nature, purpose, size, and activities of the variable interest entity
b. The enterprise's maximum exposure to loss as a result of its involvement
with the variable interest entity
AEP and its subsidiaries believe it is reasonably possible that they will be required to consolidate identified variable interest entities as a result of this new guidance. See Notes 9, 22, 23 and 26 for additional disclosures relating to the variable interest entities.
2. Extraordinary Items and Cumulative Effect:
Extraordinary Items - Extraordinary items were recorded for the discontinuance of regulatory accounting under SFAS 71 for the generation portion of the business in the Ohio, Virginia, West Virginia, Texas and Arkansas state jurisdictions. See Note 7 "Customer Choice and Industry Restructuring" for descriptions of the restructuring plans and related accounting effects. OPCo and CSPCo recognized an extraordinary loss for stranded Ohio Public Utility Excise Tax (commonly known as the Gross Receipts Tax - GRT) net of allowable Ohio coal credits during the quarter ended June 30, 2001. This loss resulted from regulatory decisions in connection with Ohio deregulation which stranded the recovery of the GRT. Effective with the liability affixing on May 1, 2001, CSPCo and OPCo recorded an extraordinary loss under SFAS 101. Both Ohio companies appealed to the Ohio Supreme Court the PUCO order on Ohio restructuring that the Ohio companies believe failed to provide for recovery for the final year of the GRT. In April 2002, the Ohio Supreme Court denied recovery of the final year of the GRT.
In October 2001, TCC reacquired $101 million of pollution control bonds in advance of their maturity. Since these pollution control bonds were used to finance unregulated generation assets, a loss of $2 million after-tax was recorded. AEP and its registrant subsidiaries had no extraordinary items in 2002.
The following table shows the components of the extraordinary items reported on AEP's Consolidated Statements of Operations:
Year Ended
December 31,
-----------
2002 2001 2000
---- ---- ----
(in millions)
Extraordinary Items:
Discontinuance of Regulatory
Accounting for Generation:
Ohio Jurisdiction (Net of Tax
of $20 million in 2001 and
$35 Million in 2000)(a) $ - $(48) $(44)
Virginia and West Virginia
Jurisdictions (Inclusive of
Tax Benefit of $8 Million)(b) - - 9
Loss on Reacquired Debt
(Net of Tax of $1 Million
in 2001)(c) - (2) -
---- ---- ----
Extraordinary Items $ - $(50) $(35)
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(a) Relates to AEP, OPCo and CSPCo.
(b) Relates to AEP and APCo.
(c) Relates to AEP and TCC.
Cumulative Effect of Accounting Change - SFAS 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized and be tested annually for impairment. The implementation of SFAS 142 resulted in a $350 million net transitional loss for our U.K. and Australian operations and is reported in AEP's Consolidated Statements of Operations as a cumulative effect of accounting change (see Note 3 for further details).
The FASB's Derivative Implementation Group (DIG) issued accounting guidance under SFAS 133 for certain derivative fuel supply contracts with volumetric optionality and derivative electricity capacity contracts. This guidance, effective in the third quarter of 2001, concluded that fuel supply contracts with volumetric optionality cannot qualify for a normal purchase or sale exclusion from mark-to-market accounting and provided guidance for determining when certain option-type contracts and forward contracts in electricity can qualify for the normal purchase or sale exclusion.
For AEP, the effect of initially adopting the DIG guidance at July 1, 2001 was a favorable earnings mark-to-market effect of $18 million, net of tax of $2 million. It was reported as a cumulative effect of an accounting change on AEP's Consolidated Statements of Operations.
3. Goodwill and Other Intangible Assets:
As described in the Significant Accounting Policies footnote, AEP adopted the provisions of SFAS 141 effective July 1, 2001. SFAS 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001 and established new standards for the recognition of certain identifiable intangible assets, separate from goodwill. Business combinations initiated after June 30, 2001 (see Note 12 for details) are accounted for utilizing SFAS 141.
SFAS 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead tested for impairment at least annually. SFAS 142 required a two-step impairment test for goodwill. The first step was to compare the carrying amount of the reporting unit's assets to the fair value of the reporting unit. If the carrying amount exceeded the fair value then the second step was required to be completed, which involves allocating the fair value of the reporting unit to each asset and liability, with the excess being implied goodwill. The impairment loss is the amount by which the recorded goodwill exceeds the implied goodwill. AEP was required to complete a "transitional" impairment test for goodwill as of the beginning of the fiscal year in which the statement was adopted. This transitional impairment test required that AEP complete step one of the goodwill impairment test within six months from the date of initial adoption, or June 30, 2002. In the first quarter 2002, AEP completed the transitional impairment test of goodwill related to domestic operations and indefinite lived intangible assets and concluded that those assets were not impaired.
In the second quarter 2002, AEP completed testing for goodwill impairment on AEP's U.K. and Australian retail electricity and supply operations. The fair values of the U.K. and Australian retail electricity and supply operations were estimated using a combination of market values based on recent market transactions and cash flow projections. As a result of this testing, AEP determined that there was a net transitional impairment loss of $350 million, which was reported in AEP's Consolidated Statements of Operations as a Cumulative Effect of Accounting Change.
SFAS 142 also requires that intangible assets with finite useful lives be amortized over their respective estimated lives to the estimated residual values. In accordance with SFAS 142, for all business combinations initiated before July 1, 2001, AEP amortized goodwill and intangible assets with indefinite lives through December 2001, and then ceased amortization. The goodwill associated with those business combinations with acquisition dates before July 1, 2001 was amortized on a straight-line basis generally over 40 years except for the portion of goodwill associated with gas trading and marketing activities, which was amortized on a straight-line basis over 10 years. Also, in accordance with SFAS 142, for all business combinations with acquisition dates after June 30, 2001, AEP has not amortized goodwill and intangible assets with indefinite lives. Intangible assets with finite lives continue to be amortized over their respective estimated lives ranging from 5 to 10 years.
New reporting requirements imposed by SFAS 142 include the disclosures shown below.
Goodwill
The changes in AEP's the carrying amount of goodwill for the twelve months ended December 31, 2002 by operating segment are:
Energy AEP
Wholesale Delivery Other Consolidated
--------- -------- ----- ------------
(in millions)
Balance January 1, 2002 $340 $37 $15 $392
Goodwill acquired 2 - - 2
Changes to Goodwill due to purchase price
adjustments 181 - - 181
Non-transitional impairment losses (173) - (12) (185)
Foreign currency exchange rate changes 6 - - 6
---- --- --- ----
Balance December 31, 2002 $356 $37 $ 3 $396
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Accumulated amortization of goodwill was approximately $22 million and $25 million at December 31, 2002 and 2001, respectively. A decrease of $3 million related principally to the non-transitional impairment of goodwill on Gas Power Systems (see Note 13a).
The transitional impairment loss related to SEEBOARD and CitiPower goodwill, which is reported as a cumulative effect of an accounting change, is excluded from the above schedule. Under SFAS 144, the assets of SEEBOARD and CitiPower, including goodwill and acquired intangible assets no longer subject to amortization, are reported as Assets of Discontinued Operations in AEP's Consolidated Balance Sheets. See Note 12 related to the sale of SEEBOARD and CitiPower.
Changes to goodwill due to purchase price adjustments of $181 million was primarily due to purchase price adjustments related to AEP's acquisition of U.K. Generation. The purchase price adjustments also include adjustments related to the acquisition of Houston Pipe Line Company, MEMCO, Nordic Trading and AEP Coal (see Note 12).
In the first quarter of 2002, AEP recognized a goodwill impairment loss of $12 million for all goodwill related to the acquisition of Gas Power Systems (see Note 13a).
In the fourth quarter of 2002, AEP prepared its annual goodwill impairment tests. The fair values of the operations were estimated using cash flow projections. There were no goodwill impairments as a result of the annual goodwill impairment tests. However, in the fourth quarter, AEP recognized goodwill impairment losses totaling $173 million related to impairment studies performed on the U.K. Generation assets ($166 million), AEP Coal ($3 million), and Nordic Trading ($4 million). These goodwill impairment studies were triggered by the SFAS 144 asset impairment losses recognized on these operations in the fourth quarter (refer to Note 13). The fair values of these operations were estimated using cash flow projections.
The following tables show the transitional disclosures to adjust AEP's reported net income (loss) and earnings (loss) per share to exclude amortization expense recognized in prior periods related to goodwill and intangible assets that are no longer being amortized.
Net Income (Loss) Year Ended December 31,
-----------------------
2002 2001 2000
---- ---- ----
(in millions)
Reported Net Income (Loss) $(519) $ 971 $267
Add back: Goodwill amortization (a) - 39 39
Add back: Amortization for intangibles with indefinite
lives under SFAS 142 (b) - 8 9
----- ------ ----
Adjusted Net Income (Loss) $(519) $1,018 $315
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Twelve Months Ended
Earnings (Loss) Per Share (Basic and Dilutive) December 31,
-------------------
2002 2001 2000
---- ---- ----
Reported Earnings (Loss) per Share $(1.57) $3.01 $0.83
Add back: Goodwill amortization (c) - 0.12 0.12
Add back: Amortization for intangibles with
indefinite lives under SFAS 142 (d) - 0.02 0.03
------ ----- -----
Adjusted Earnings (Loss) per Share $(1.57) $3.15 $0.98
====== ===== =====
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(a) This amount includes $34 million and $37 million in 2001 and 2000 related
to Seeboard and CitiPower amortization expense included in Discontinued
Operations on AEP's Consolidated Statements of Operations.
(b) The amounts shown for 2001 and 2000 relate to CitiPower amortization
expense included in Discontinued Operations on AEP's Consolidated
Statements of Operations.
(c) This amount includes $0.10 and $0.11 in 2001 and 2000 related to Seeboard
and CitiPower amortization expense included in Discontinued Operations on
AEP's Consolidated Statements of Operations.
(d) The amounts shown for 2001 and 2000 relate to CitiPower amortization
expense included in Discontinued Operations on AEP's Consolidated
Statements of Operations.
Acquired Intangible Assets
Acquired intangible assets subject to amortization are $37 million at December 31, 2002 and $33 million at December 31, 2001, net of accumulated amortization. Of those amounts, $25 million and $33 million at December 31, 2002 and 2001, relate to SWEPCo. The gross carrying amount, accumulated amortization and amortization life by major asset class are:
December 31, 2002 December 31, 2001
Gross Gross
Amortization Carrying Accumulated Carrying Accumulated
Life Amount Amortization Amount Amortization
------------ -------- ------------ ------- ------------
(in years) (in millions) (in millions)
Dolet Hills Advanced
Royalties (SWEPCo) 10 $35 $5 $35 $2
Less: Adjustment Due to
Purchase Price
Reallocation
(SWEPCo) 6 1 - -
Trade name and
Administration of
Contracts 7 2 - - -
Unpatented
Technology 10 10 - - -
--- -- --- --
Totals $41 $4 $35 $2
=== == === ==
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Amortization of intangible assets (primarily SWEPCo) was $2 million for the twelve months ended December 31, 2002. AEP's estimated aggregate amortization expense is $4 million for each year 2003 through 2008. SWEPCo's estimated aggregate amortization expense (included in AEP's estimated amount) is $3 million for each year 2003 through 2008.
AEP's acquired intangible assets no longer subject to amortization were comprised of retail and wholesale distribution licenses for CitiPower operating franchises. The licenses were being amortized on a straight-line basis over 20 and 40 years for the retail and wholesale licenses, respectively. In accordance with SFAS 144, the assets of CitiPower, including acquired intangible assets no longer subject to amortization, are reported as Assets of Discontinued Operations on one line in AEP's Consolidated Balance Sheets. See Note 12 related to the sale of CitiPower.
4. Merger:
On June 15, 2000, AEP merged with CSW so that CSW became a wholly-owned subsidiary of AEP. Under the terms of the merger agreement, approximately 127.9 million shares of AEP Common Stock were issued in exchange for all the outstanding shares of CSW Common Stock based upon an exchange ratio of 0.6 share of AEP Common Stock for each share of CSW Common Stock.
The merger was accounted for as a pooling of interests. Accordingly, AEP's consolidated financial statements give retroactive effect to the merger, with all periods presented as if AEP and CSW had always been combined. Certain reclassifications have been made to conform the historical financial statement presentation of AEP and CSW. Effective January 2003, the legal name of CSW was changed to AEP Utilities, Inc.
In connection with the merger, $10 million ($7 million after tax), $21 million ($14 million after tax) and $203 million ($180 million after tax) of non-recoverable merger costs were expensed in 2002, 2001 and 2000. Such costs included transaction and transition costs not recoverable from ratepayers. Also included in the merger costs were non-recoverable changes in control payments. Merger transaction and transition costs of $52 million recoverable from ratepayers were deferred pursuant to state regulator approved settlement agreements through December 31, 2002. The deferred merger costs are being amortized over five to eight year recovery periods, depending on the specific terms of the settlement agreements, with the amortization ($8 million, $8 million and $4 million for the years 2002, 2001 and 2000) included in depreciation and amortization expense.
The following tables show the deferred merger cost and amortization expense of the applicable subsidiary registrants:
Amortization
Merger Cost Expense for the
Deferral at Year Ended
December 31, 2002 December 31, 2002
----------------- -----------------
(in millions)
I&M $8.2 $1.7
KPCo 2.9 0.6
PSO 5.0 1.6
SWEPCo 3.9 1.1
TCC 9.1 2.6
TNC 2.7 0.8
Amortization
Merger Cost Expense for the
Deferral at Year Ended
December 31, 2001 December 31, 2001
----------------- -----------------
(in millions)
I&M $ 9.1 $1.7
KPCo 3.2 0.6
PSO 6.6 1.2
SWEPCo 5.0 1.1
TCC 11.8 2.6
TNC 3.5 0.8
Amortization
Merger Cost Expense for the
Deferral at Year Ended
December 31, 2000 December 31, 2000
----------------- -----------------
(in millions)
I&M $ 6.9 $0.7
KPCo 2.5 0.3
PSO 7.9 0.5
SWEPCo 6.1 0.5
TCC 14.4 1.3
TNC 4.2 0.4
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Merger transition costs are expected to continue to be incurred for several years after the merger and will be expensed or deferred for amortization as appropriate. As hereinafter summarized, the state settlement agreements provide for, among other things, a sharing of net merger savings with certain regulated customers over periods of up to eight years through rate reductions which began in the third quarter of 2000.
Summary of key provisions of Merger Rate Agreements:
State/Company Ratemaking Provisions
Texas - SWEPCo, TCC, TNC $221 million rate reduction over 6 years.
No base rate increases for 3 years post merger.
Indiana - I&M $67 million rate reduction over 8 years. Extension
of base rate freeze until January 1, 2005. Requires
additional annual deposits of $6 million to the
nuclear decommissioning trust fund for the
years 2001 through 2003.
Michigan - I&M Customer billing credits of approximately $14
million over 8 years. Extension of base rate freeze
until January 1, 2005.
Kentucky - KPCo Rate reductions of approximately $28 million over
8 years. No base rate increases for 3 years post
merger.
Oklahoma - PSO Rate reductions of approximately $28 million over
5 years. No base rate increase before January 1,
2003.
Arkansas - SWEPCo Rate reductions of $6 million
over 5 years.
Louisiana - SWEPCo Rate reductions to share merger savings estimated
to be $18 million over 8 years. Base rate
cap until June 2005.
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If actual merger savings are significantly less than the merger savings rate reductions required by the merger settlement agreements in the eight-year period following consummation of the merger, future results of operations, cash flows and possibly financial condition could be adversely affected.
See Note 9, "Commitments and Contingencies" for information on a court decision concerning the merger.
5. Nuclear Plant Restart:
I&M completed the restart of both units of the Cook Plant in 2000. Cook Plant is a 2,110 MW two-unit plant owned and operated by I&M under licenses granted by the NRC. I&M shut down both units of the Cook Plant, in September 1997, due to questions regarding the operability of certain safety systems that arose during a NRC architect engineer design inspection.
Settlement agreements in the Indiana and Michigan retail jurisdictions that address recovery of Cook Plant related outage costs were approved in 1999. The IURC approved a settlement agreement that resolved all matters related to the recovery of replacement energy fuel costs and all outage/restart costs and related issues during the extended outage of the Cook Plant. The MPSC approved a settlement agreement for two open Michigan power supply cost recovery reconciliation cases that resolved all issues related to the Cook Plant extended outage. The settlement agreements allowed:
o Deferral of $200 million of non-fuel nuclear operation and maintenance
(O&M) costs for amortization over five years ending December 31, 2003,
o Deferral of certain unrecovered fuel and power supply costs for
amortization over five years ending December 31, 2003,
o A freeze in base rates through December 31, 2003 and a fixed fuel
recovery charge through March 1, 2004 in the Indiana
jurisdiction,
o A freeze in base rates and fixed power supply costs recovery factors
until January 1, 2004 for the Michigan jurisdiction.
The amount of costs and deferrals charged to other operation and maintenance expenses were as follows:
Year Ended December 31,
2002 2001 2000
---- ---- ----
Costs Incurred $- $ 1 $297
Amortization of Deferrals 40 40 40
- -- - -- -- --
Charged to O&M Expense $40 $41 $337
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At December 31, 2002 and 2001, deferred O&M costs of $40 million and $80 million, respectively, remained in Regulatory Assets to be amortized through 2003. Also pursuant to the settlement agreements, accrued fuel-related revenues of $38 million were amortized as a reduction of revenues in each of 2002, 2001 and 2000. At December 31, 2002 and 2001, fuel-related revenues of $37 million and $75 million, respectively, were included in Regulatory Assets and will be amortized through December 31, 2003 for both jurisdictions.
The amortization of O&M costs and fuel-related revenues deferred under Indiana and Michigan retail jurisdictional settlement agreements will adversely affect results of operations through December 31, 2003 when the amortization period ends. The annual amortization of O&M costs and fuel-related revenue deferrals is approximately $78 million.
6. Rate Matters:
Texas Fuel - Affecting AEP, SWEPCo, TCC and TNC
Prior to the start of retail competition in ERCOT on January 1, 2002, fuel recovery for Texas utilities was a multi-step procedure. When fuel costs changed, utilities filed with the PUCT for authority to adjust fuel factors. If a utility's prior fuel factors resulted in material over-recovery or under-recovery of fuel costs, the utility would also request a refund or surcharge factor to refund or collect those amounts. While fuel factors were intended to recover fuel costs, final settlement of these amounts was subject to reconciliation and approval by the PUCT.
Fuel reconciliation proceedings determine whether fuel costs incurred during the reconciliation period were reasonable and necessary. All fuel costs incurred since the prior reconciliation date are subject to PUCT review and approval. If material amounts are determined to be unreasonable and ordered to be refunded to customers, results of operations and cash flows would be negatively impacted.
According to Texas Restructuring Legislation, fuel cost in the Texas jurisdiction after 2001 is no longer subject to PUCT review and reconciliation. During 2002, TCC and TNC filed final fuel reconciliations with the PUCT to reconcile their fuel costs through the period ending December 31, 2001. The ultimate recovery of deferred fuel balances at December 31, 2001 will be decided as part of their 2004 true-up proceedings. See discussion of TCC and TNC fuel reconciliations below.
In October 2001, the PUCT delayed the start of customer choice in the SPP area of Texas. All of SWEPCo's Texas service territory and a small portion of TNC's service territory are in SPP. SWEPCo's existing Texas fuel cost recovery procedures will continue until competition begins. SWEPCo will continue to set fuel factors and determine final fuel costs in fuel reconciliation proceedings during the SPP delay period. The PUCT has ruled that TNC fuel factors in the SPP area will be based upon the price-to-beat fuel factors offered by the retail electric provider in the ERCOT portion of TNC's service territory. TNC transferred its SPP customers to Mutual Energy SWEPCo effective December 1, 2002. TNC filed in 2002 with the PUCT to determine the most appropriate method to reconcile fuel costs in TNC's SPP area and a decision is expected by mid 2003.
Under Texas restructuring, customer choice to select a retail electric provider began January 1, 2002. Sales to customers using 1 MW or less will be at fixed base rates during a transition period from 2002 through 2006. As discussed in Note 12 "Acquisitions, Dispositions and Discontinued Operations", AEP sold its Texas retail electric providers (REP) and their retail customers in December 2002.
The former AEP subsidiaries serving as REPs for the ERCOT area filed with the PUCT in May 2002 to increase the fuel portion of their price-to-beat rate in compliance with the Texas Restructuring Legislation and the PUCT's rules. The Texas legislation provides for the adjustment of the fuel portion of the rate up to twice annually to reflect significant changes in the market price of natural gas and purchased energy used to serve retail customers using NYMEX natural gas prices. On July 15, 2002, the PUCT required further hearings to reconsider the validity of their existing rules for fuel factor adjustments. On July 24, 2002, the Texas REPs filed a petition with the District Court seeking an injunction commanding the PUCT to proceed to a final order based on the existing rules and prohibiting the PUCT from conducting a remand proceeding. The District Court issued an order on August 9, 2002 requiring the PUCT to comply with the existing rules. On August 26, 2002, the PUCT issued an order approving a 22% increase to the fuel portion of the price-to-beat rates effective immediately for both REPs. The PUCT order approving the 22% increase has been appealed by parties opposing the price-to-beat adjustment. With the sale of the REPs to Centrica in December 2002, Centrica is responsible for these appeals. Any adverse ruling from the appeal could impact TCC and TNC by requiring refunds for the time period AEP served the retail customers prior to the sale to Centrica (January 2002 to December 2002).
TCC Fuel Reconciliation - Affecting AEP and TCC
In December 2002, TCC filed with the PUCT to reconcile fuel costs and to defer its over-recovery of fuel for inclusion in the 2004 true-up proceeding. This reconciliation for the period of July 1998 through December 2001 will be the final fuel reconciliation. At December 31, 2001, the over-recovery balance for TCC was $63.5 million including interest. During the reconciliation period, TCC incurred $1.6 billion of eligible fuel and fuel-related expenses. Recommendations from intervening parties are expected in April 2003 with hearings scheduled in May 2003. A final order is expected in late 2003. An adverse ruling from the PUCT could have a material impact on future results of operations, cash flows and financial condition. Additional information regarding the 2004 true-up proceeding for TCC can be found in Note 8 "Customer Choice and Industry Restructuring".
TNC Fuel Reconciliation - Affecting AEP and TNC
In June 2002, TNC filed with the PUCT to reconcile fuel costs and to defer any unrecovered portion applicable to retail sales within its ERCOT service area for inclusion in the 2004 true-up proceeding. This reconciliation for the period of July 2000 through December 2001 will be the final fuel reconciliation for TNC's ERCOT service territory. At December 31, 2001, the under-recovery balance associated with TNC's ERCOT service area was $27.5 million including interest. During the reconciliation period, TNC incurred $293.7 million of eligible fuel costs serving both ERCOT and SPP retail customers. TNC also requested authority to surcharge its SPP customers. TNC's SPP customers will continue to be subject to fuel reconciliations until competition begins in SPP. The under-recovery balance at December 31, 2001 for TNC's service within SPP was $0.7 million including interest.
In October 2002, the filing was split into two phases for hearing purposes. The first phase examined all components of the filing except for AEP trading activities and the associated margins that flow back to customers as an offset to fuel costs consistent with the PUCT - approved Texas merger settlement. Intervenors filed testimony in the first phase recommending that up to $25 million of TNC's requested retail eligible fuel recovery be disallowed and hearings were held on October 23, 2002. TNC disputed the recommendations. On October 21, 2002, the PUCT Staff and Office of Public Utility Counsel (OPC) filed a joint Motion for Summary Decision related to the second phase issue and requested that approximately $18.5 million of TNC's retail eligible fuel recovery be disallowed without a hearing. On November 8, 2002, the administrative law judges (ALJs) in the case denied the motion. The intervenors filed testimony on October 29, 2002 in the second phase recommending that up to $34 million of TNC's requested retail eligible fuel recovery be disallowed. The intervenors recommended disallowance includes the amount sought in the October 21 Motion for Summary Decision. The total intervenor recommended retail disallowance is approximately $59 million. Hearings for the second phase were held on November 13-14, 2002. On February 3, 2003, TNC filed a motion to reopen the evidentiary record and include a decrease to retail eligible fuel costs of $1.3 million, including interest, to reflect final resettlement revenues and expenses from ERCOT for the period August through December 2001 (see discussion in Fuel and Purchased Power below). The PUCT is expected to issue a final order in this case by mid 2003. An adverse ruling from the PUCT could have a material impact on future results of operations, cash flows and financial condition.
ERCOT Over-scheduling - Affecting AEP, TCC and TNC
ERCOT began serving as a central control center for all of ERCOT at the end of July 2001 when ERCOT became a single control area. Qualified scheduling entities (QSE) schedule loads and resources for ERCOT market participants including power generation companies and retail electric providers. In August 2001, ERCOT incurred substantial costs for managing transmission in its north zone. The costs incurred by ERCOT to manage congestion are shared by all ERCOT QSEs. In late 2001, the PUCT initiated an investigation of the impact of scheduling of electric loads and resources by QSEs during August 2001. The PUCT's investigation determined that a substantial amount of the congestion charges were the result of QSEs, including AEP's QSE, scheduling more resources than required to meet their actual load requirements in the ERCOT north zone. AEP's QSE over-scheduled resources due to an error in the allocation of estimated load requirements between ERCOT congestion zones. Pursuant to the PUCT's investigation, QSEs, including AEP's QSE, agreed to a settlement that provides for the refund of payments received for adjusting resource schedules for congestion. The settlement was approved by the PUCT in November 2002. The settlement recognizes that the scheduling errors were associated with the start up of the ERCOT competitive market. AEP's QSE paid $3.2 million to ERCOT and received $1.7 million from ERCOT in congestion refunds for a net payment of $1.5 million. Payments were assigned to TNC and the refunds were allocated to TCC and TNC. TNC incurred a net cost of $2.8 million and TCC received a refund of $1.3 million. The TNC payment and TCC refund have been reflected in the final fuel reconciliation filings for each company. However, intervening parties have objected to the inclusion of the TNC payment in its final fuel reconciliation. Recommendations from intervening parties in the TCC proceeding are not expected until April 2003. An adverse ruling from the PUCT would impact future results of operations, cash flows and financial condition.
Texas Transmission Rates - Affecting AEP, TCC and TNC
On June 28, 2001, the Supreme Court of Texas ruled that the transmission pricing mechanism created by the PUCT in 1996 and used for the period January 1, 1997 through August 31, 1999 was invalid. The court upheld an appeal filed by unaffiliated Texas utilities that the PUCT exceeded its statutory authority to set such rates during that period. TCC and TNC were not parties to the case. However, the companies' transmission sales and purchases were priced using the invalid rates. It is unclear what action the PUCT will take to respond to the court's ruling. If the PUCT changes rates retroactively, the result could have a material unfavorable impact on results of operations and cash flows for TCC and TNC.
FERC Wholesale Fuel Complaints - Affecting AEP and TNC
In May 2000, certain TNC wholesale customers filed a complaint with FERC alleging that TNC had overcharged them through the fuel adjustment clause for certain purchased power costs related to 1999 unplanned outages at TNC's Oklaunion generation station. In November 2001, certain TNC wholesale customers filed an additional complaint at FERC asserting that since 1997 TNC had billed wholesale customers for not only the 1999 Oklaunion outage costs, but also certain additional costs that are not permissible under the fuel adjustment clause.
In December 2001, FERC issued an order requiring TNC to refund, with interest, amounts associated with the May 2000 complaint that were previously billed to wholesale customers. The effects of this order were recorded in 2001. In response to the November 2001 complaint, negotiations to settle the complaint and update the contracts are continuing. In March 2002, TNC recorded a provision for refund of $2.2 million before income taxes. The actual refund and final resolution of this matter could differ materially from this estimate and may have a negative impact on future results of operations, cash flows and financial condition.
FERC Transmission Rates - Affecting AEP, PSO, SWEPCo, TCC and TNC
In November 2001, FERC issued an order resulting from a remand by an appeals court of a tariff compliance filing order issued in 1998 that had been appealed by certain customers. The order required PSO, SWEPCo, TCC and TNC to submit revised open access transmission tariffs and calculate and issue refunds for overcharges from January 1, 1997. In July 2002, FERC approved a revised open access transmission tariff and refunds of $1.3 million were issued to unaffiliated entities.
Under FERC rules, the new tariffs resulted in a reallocation of previously received transmission revenues among affiliates resulting in the following income statement impact:
Increase (Decrease) Revenues
----------------------------
2001 2002 Total
(in millions)
PSO $ 2.8 $ 2.5 $ 5.3
SWEPCo 3.2 2.8 6.0
TCC (6.0) (2.8) (8.8)
TNC (2.6) (1.2) (3.8)
----- ----- -----
AEP Total $(2.6) $ 1.3 $(1.3)
===== ===== =====
|
Fuel and Purchased Power - Affecting AEP, PSO, SWEPCo, TCC and TNC
PSO has Under-Recovered Fuel Costs of $75.7 million at December 31, 2002, representing fuel and purchased power costs recorded but not yet collected from retail customers in Oklahoma. The first significant item causing the under-recovery is approximately $44 million in reallocation of purchased power costs for periods prior to January 1, 2002, as described below. The other significant item impacting the under-recovered fuel costs are natural gas price increases that were not expected when PSO set its quarterly factors during 2002. The Corporation Commission of the State of Oklahoma (OCC) is currently reviewing the reasons for the large under-recovered balance.
The AEP West electric operating companies' power is dispatched real-time on an economic basis and is later allocated among the AEP West electric operating companies using the Interchange Cost Reconstruction (ICR) system based on dispatch information from internal and external sources. ICR is designed to allocate the cost of power under the terms and conditions of the AEP West Operating Agreement. During 2002, two ICR adjustments were made. The adjustments were related to a 2002 true-up and a reallocation of years prior to 2002.
During the third quarter of 2002, AEP reallocated purchased power costs among the four AEP West electric operating companies for the periods prior to January 1, 2002 (the ICR Adjustments). The effects of the reallocation on pre-tax income were insignificant to PSO and TCC and increased pre-tax income at SWEPCo and TNC by $2.4 million and $1.9 million, respectively.
The formation of the ERCOT single control zone increased the need for data estimation and true-up which has resulted in extended true-up periods associated with allocations being performed on estimated data. ERCOT can make adjustments to companies' settlements for up to six months. A true-up process for 2002 was completed and recorded in the fourth quarter of 2002 resulting in insignificant changes in PSO's and SWEPCo's pre-tax income. TCC's pre-tax income was reduced by $3.7 million and TNC's pre-tax income was increased by $4.8 million. As ERCOT notifies TCC and TNC of further adjustments, they will be recorded.
PSO implemented new fuel rates in December 2002 following the OCC's review and approval. The new fuel factors were designed to recover estimated fuel costs for the next three months and to begin recovery of the under-recovered amount. Recovery of the under-recovered amount is expected to occur over several months and is subject to OCC review and approval.
For SWEPCo, the true-up process described above and the ICR Adjustments resulted in a net increase in fuel costs recoverable from customers of $8 million included in Regulatory Assets on AEP's and SWEPCo's Consolidated Balance Sheets. The amount is recoverable from customers pursuant to the applicable fuel recovery mechanisms and review of the state regulatory commissions in Arkansas, Louisiana and Texas.
To the extent the OCC and/or the AEP West Commissions regulating SWEPCo do not permit recovery of the revised fuel and purchased power costs, there could be an adverse effect on results of operations and cash flows.
PSO Rate Review - Affecting AEP and PSO
In February 2003, the Director of the OCC filed an application requiring PSO to file all documents necessary for a general rate review before August 1, 2003. Management is unable to predict the result of this review as the documents and data have not been assembled.
Louisiana Compliance Filing - Affecting AEP and SWEPCo
On October 15, 2002, SWEPCo filed with the Louisiana Public Service Commission (LPSC) detailed financial information typically utilized in a revenue requirement filing, including a jurisdictional cost of service. This filing was required by the LPSC as a result of their order approving the merger between AEP and CSW. The LPSC's merger order also provides that SWEPCo's base rates are capped at the present level through mid 2005. The filing indicates that SWEPCo's current rates should not be reduced. If the LPSC disagrees with our conclusion, they could order SWEPCo to file all documents for a full cost of service revenue requirement review in order to determine whether SWEPCo's capped rates should be reduced which would adversely impact results of operations and cash flows.
FERC Long-term Contracts - Affecting AEP and AEP East and AEP West companies
In September 2002, the FERC voted to hold hearings to consider requests from certain wholesale customers located in Nevada and Washington to break long-term contracts which they allege are "high-priced". At issue are long-term contracts entered during the California energy price spike in 2000 and 2001. The complaints allege that AEP sold power at unjust and unreasonable prices. The FERC delayed hearings to allow the parties to hold settlement discussions. In January 2003, the FERC settlement judge assigned to the case indicated that the parties' settlement efforts were not progressing and he recommended that the complaint be placed back on the schedule for a hearing. In February 2003, AEP and one of our customers agreed to terminate their contract with the customer withdrawing its FERC complaint.
In a similar complaint, a FERC administrative law judge (ALJ) ruled in favor of AEP and dismissed, in December 2002, a complaint filed by two Nevada utilities. In 2000 and 2001, AEP agreed to sell power to the utilities for future delivery. In late 2001, the utilities filed complaints that the prices for power supplied under those contracts should be lowered because the market for power was allegedly dysfunctional at the time such contracts were entered. The ALJ rejected the utilities' complaint, held that the markets for future delivery were not dysfunctional, and that the utilities had failed to demonstrate that the public interest required that changes be made to the contracts. The ALJ's order is preliminary and is subject to review by the FERC. The FERC will likely rule on the ALJ's order in 2003. Management is unable to predict the outcome of these proceedings or their impact on results of operations.
Environmental Surcharge Filing - Affecting AEP and KPCo
In September 2002, KPCo filed with the KPSC to revise its environmental surcharge tariff to recover the cost of emissions control equipment being installed at Big Sandy Plant. See NOx Reductions in Note 9 "Commitments and Contingencies".
The surcharge request, as filed, would increase annual revenues by approximately $21 million and must be approved by the KPSC before its inclusion in customers' bills. If the KPSC does not approve an increase in the environmental surcharge, results of operations and cash flows would be negatively impacted.
7. Effects of Regulation:
In accordance with SFAS 71 the consolidated financial statements include regulatory assets (deferred expenses) and regulatory liabilities (deferred revenues) recorded in accordance with regulatory actions in order to match expenses and revenues from cost-based rates in the same accounting period. Regulatory assets are expected to be recovered in future periods through the rate-making process and regulatory liabilities are expected to reduce future cost recoveries. Among other things, application of SFAS 71 requires that the AEP System's regulated rates be cost-based and the recovery of regulatory assets be probable. Management has reviewed all the evidence currently available and concluded that the requirements to apply SFAS 71 continue to be met for all electric operations in Indiana, Kentucky, Louisiana, Michigan, Oklahoma and Tennessee.
When the generation portion of the business in Arkansas, Ohio, Texas, Virginia and West Virginia no longer met the requirements to apply SFAS 71, net regulatory assets were written off for that portion of the business unless they were determined to be recoverable as a stranded cost through regulated distribution rates or wire charges in accordance with SFAS 101 and EITF 97-4. In the Ohio and West Virginia jurisdictions generation-related regulatory assets that are recoverable through transition rates have been transferred to the distribution portion of the business and are being amortized as they are recovered through charges to regulated distribution customers. These assets are classified as "transition regulatory assets". As discussed in Note 8, "Customer Choice and Industry Restructuring" the Virginia SCC ordered the generation-related regulatory assets in the Virginia jurisdiction to remain with the generation portion of the business. Generation-related regulatory assets in the Virginia jurisdiction are being amortized concurrent with their recovery through capped rates. These assets are also classified as "transition regulatory assets." The Texas jurisdiction generation-related regulatory assets that are eligible for recovery through securitization have been classified as "regulatory assets designated for or subject to securitization." See Note 8 "Customer Choice and Industry Restructuring" for further details.
AEP's recognized regulatory assets and liabilities are comprised of the following at:
December 31,
-----------
2002 2001
---- ----
(in millions)
Regulatory Assets:
Amounts Due From Customers
For Future Income Taxes $ 791 $ 814
Transition Regulatory Assets 743 847
Regulatory Assets
Designated for or Subject to
Securitization 336 959
Texas Wholesale Clawback (a) 262 -
Deferred Fuel Costs 143 139
Unamortized Loss on
Reacquired Debt 83 99
Cook Plant Restart Costs 40 80
DOE Decontamination and
Decommissioning
Assessment 26 31
Other 264 193
------ ------
Total Regulatory Assets $2,688 $3,162
====== ======
Regulatory Liabilities:
Deferred Investment
Tax Credits $ 455 $ 491
Texas Retail Clawback (a) 66 -
Other 419 393
------ -----
Total Regulatory Liabilities $ 940 $ 884
====== =====
|
(a) See "Texas Restructuring" section of Note 8.
The recognized regulatory assets and liabilities for the registrant subsidiaries are of two types: those earning a return and those not earning a return. Items not earning a return have their recovery period end date indicated. Regulatory assets and liabilities are comprised of the following items:
AEGCo APCo
------------------------------ ------------------------------
Recovery/ Recovery/
Refund Refund
2002 2001 Period 2002 2001 Period
---- ---- -------- ---- ---- --------
(in thousands)
Regulatory Assets:
Amounts Due From
Customers For Future
Income Taxes $209,884 $189,794 Note 1
Transition - Regulatory
Assets Virginia 39,670 46,981 Jun. 2007
Transition - Regulatory
Assets West Virginia 119,038 127,998 Jun. 2011
Deferred Fuel Costs 5,367 11,732
Unamortized Loss on
Reacquired Debt $ 4,970 $ 5,207 Note 2 9,147 10,421 Note 2
Deferred Storm Damage - 6
Other 12,447 10,451 Note 3
------- ------- -------- --------
Total Regulatory Assets $ 4,970 $ 5,207 $395,553 $397,383
======= ======= ======== ========
Regulatory Liabilities:
Deferred Investment
Tax Credits $52,943 $56,304 Note 4 $ 33,691 $ 38,328 Note 4
WV Rate Stabilization 75,601 75,601 Note 5
Amounts Due To Customers
For Future Income Taxes 16,670 22,725 Note 1
Other 72 112 Note 3
------- ------- -------- --------
Total Regulatory Liabilities $69,613 $79,029 $109,364 $114,041
======= ======= ======== ========
|
Note 1: This amount fluctuates from month to month and has no fixed
recovery/refund period.
Note 2: Unamortized loss on reacquired debt varies in its recovery period for
each registrant and ranges from one to thirty-six years recovery period across
all registrants. Note 3: Other may include items not earning a return and would
have various recovery/refund periods. Note 4: Generally amortized over the life
of the related plant assets as approved by the various state commissions. Note
5: Amortization will be determined by the WVPSC to offset market prices.
CSPCo I&M
------------------------------- -------------------------------
Recovery/ Recovery/
Refund Refund
2002 2001 Period 2002 2001 Period
---- ---- -------- ---- ---- --------
(in thousands)
Regulatory Assets:
Amounts Due From Customers
For Future Income Taxes $ 26,290 $ 28,361 Note 1 $163,928 $171,605 Note 1
Transition - Regulatory
Assets 204,961 223,830 Dec. 2008
Deferred Fuel Costs 37,501 75,002 Dec. 2003
Unamortized Loss on
Reacquired Debt 5,978 7,010 Note 2 14,994 16,255 Note 2
Cook Plant Restart Costs 40,000 80,000 Dec. 2003
Incremental Nuclear Refueling
Outage Expenses (Net) 29,572 2,995 Note 5
DOE Decontamination and
Decommissioning Assessment 23,375 27,784 Dec. 2008
Other 20,453 3,066 Note 3 38,842 35,286 Note 3
-------- -------- -------- --------
Total Regulatory Assets $257,682 $262,267 $348,212 $408,927
======== ======== ======== ========
Regulatory Liabilities:
Deferred Investment
Tax Credits $ 33,907 $ 37,176 Note 4 $ 97,709 $105,449 Note 4
Other - 31 Note 3 65,983 52,479 Note 3
-------- -------- -------- --------
Total Regulatory Liabilities $ 33,907 $ 37,207 $163,692 $157,928
======== ======== ======== ========
|
Note 1: This amount fluctuates from month to month and has no fixed recovery
period.
Note 2: Unamortized loss on reacquired debt varies in its recovery period for
each registrant and ranges from one to thirty-six years recovery period across
all registrants. Note 3: Other may include items not earning a return and would
have various recovery/refund periods. Note 4: Generally amortized over the life
of the related plant assets as approved by the various state commissions. Note
5: Amortized over the period beginning with the commencement of an outage and
ending with the beginning of the next outage.
KPCo OPCo
------------------------------ ----------------------------
Recovery/ Recovery/
Refund Refund
2002 2001 Period 2002 2001 Period
---- ---- -------- ---- ---- --------
(in thousands)
Regulatory Assets:
Amounts Due From Customers
For Future Income Taxes $ 87,261 $83,027 Note 1 $165,106 $186,740 Note 1
Transition - Regulatory
Assets 375,409 442,707 Dec. 2007
Deferred Fuel Costs - 1,542
Unamortized Loss on
Reacquired Debt 152 51 Note 2 4,899 5,502 Note 2
Other 14,563 13,072 Note 3 23,227 9,676 Note 3
-------- ------- -------- --------
Total Regulatory Assets $101,976 $97,692 $568,641 $644,625
======== ======= ======== ========
Regulatory Liabilities:
Deferred Investment
Tax Credits $ 9,165 $10,405 Note 4 $ 18,748 $ 21,925 Note 4
Other 12,152 6,551 Note 3 1,237 1,237 Note 3
-------- ------- -------- --------
Total Regulatory Liabilities $ 21,317 $16,956 $ 19,985 $ 23,162
======== ======= ======== ========
|
Note 1: This amount fluctuates from month to month and has no fixed recovery
period.
Note 2: Unamortized loss on reacquired debt varies in its recovery period for
each registrant and ranges from one to thirty-six years recovery period across
all registrants. Note 3: Other may include items not earning a return and would
have various recovery/refund periods. Note 4: Generally amortized over the life
of the related plant assets as approved by the various state commissions.
PSO SWEPCo
----------------------------- ------------------------------
Recovery/ Recovery/
Refund Refund
2002 2001 Period 2002 2001 Period
---- ---- -------- ---- ---- --------
(in thousands)
Regulatory Assets:
Amounts Due From
Customers For Future
Income Taxes $ 19,855 $ 16,532 Note 1
Deferred Fuel Costs $ 76,470 $ 756 Note 1 2,865 8,839 Note 1
Unamortized Loss on
Reacquired Debt 11,138 12,381 Note 2 17,031 20,045 Note 2
Other 15,012 22,683 Note 3 12,347 15,731 Note 3
-------- ------- -------- --------
Total Regulatory Assets $102,620 $35,820 $ 52,098 $ 61,147
======== ======= ======== ========
Regulatory Liabilities:
Deferred Investment
Tax Credits $ 32,201 $33,992 Note 4 $ 44,190 $ 48,714 Note 4
Ammounts Due To Customers
For Future Income Taxes 27,893 26,085 Note 1
Deferred Fuel Costs - 9,476 Note 1 17,226 5,487 Note 1
Other 4,391 22,444 Note 3 7,094 10,889 Note 3
-------- ------- -------- --------
Total Regulatory Liabilities $ 64,485 $91,997 $ 68,510 $ 65,090
======== ======= ======== ========
|
Note 1: This amount fluctuates from month to month and has no fixed
recovery/refund period.
Note 2: Unamortized loss on reacquired debt varies in its recovery period for
each registrant and ranges from one to thirty-six years recovery period across
all registrants. Note 3: Other may include items not earning a return and would
have various recovery/refund periods. Note 4: Generally amortized over the life
of the related plant assets as approved by the various state commissions.
TCC TNC
---------------------------- -------------------------------
Recovery/ Recovery/
Refund Refund
2002 2001 Period 2002 2001 Period
---- ---- -------- ---- ---- --------
(in thousands)
Regulatory Assets:
Amounts Due From Customers
For Future Income Taxes $162,247 $ 200,496 Note 1
Regulatory Assets -
Designated For or Subject
To Securitization 336,444 959,294 Note 5
Deferred Fuel Costs $26,680 $ 40,389 Note 5
Texas Wholesale Clawback 262,000 - Note 5
Unamortized Loss on
Reacquired Debt 8,661 11,186 Note 2 3,283 8,272 Note 2
Deferred Debt - Restructuring 13,324 - Note 2 10,134 - Note 2
DOE Decontamination and
Decommissioning Assessment 3,170 3,170 Dec. 2004
Other 9,150 11,960 Note 3 5,000 5,461 Note 3
-------- ---------- ------- --------
Total Regulatory Assets $794,996 $1,186,106 $45,097 $ 54,122
======== ========== ======= ========
Regulatory Liabilities:
Deferred Investment
Tax Credits $117,686 $ 122,892 Note 4 $21,510 $ 22,781 Note 4
Deferred Fuel Costs 69,026 52,572 Note 5
Texas Retail Clawback 51,926 - Note 5 14,328 - Note 5
Over - Recovery of
Transition Changes 20,870 - Jan. 2016
Purchased Power Conservation 9,560 - Note 1
Excess Earnings 46,111 62,852 Note 5 17,419 17,300 Note 4
Ammounts Due To Customers
For Future Income Taxes 12,280 13,591 Note 1
Other 6 6 Note 3 7,285 5,775 Note 3
-------- ---------- ------- --------
Total Regulatory Liabilities $315,185 $ 238,322 $72,822 $ 59,447
======== ========== ======= ========
|
Note 1: This amount fluctuates from month to month or year to year and has no
fixed recovery/refund period.
Note 2: Unamortized loss on reacquired debt varies in its recovery period for
each registrant and ranges from one to thirty-seven years recovery period across
all registrants. Note 3: Other may include items not earning a return and would
have various recovery/refund periods. Note 4: Generally amortized over the life
of the related plant assets as approved by the various state commissions. Note
5: Includable in TCC's and TNC's PUCT 2004 true-up proceedings. See "Texas
Restructuring" section of Note 8.
8. Customer Choice and Industry Restructuring:
Customer choice allowing retail customers to select alternative generation suppliers began on January 1, 2001 in Ohio and on January 1, 2002 in Michigan, Virginia and in the ERCOT area of Texas. Customer choice in the SPP area of Texas, also scheduled to begin on January 1, 2002, was delayed by the PUCT. AEP's subsidiaries operate in both the ERCOT and SPP areas of Texas.
Implementation of legislation enacted in Arkansas, Oklahoma and West Virginia to allow retail customers to choose their electricity supplier has been delayed or repealed. In 2001, Oklahoma delayed implementation of customer choice indefinitely. In February 2003, the Arkansas General Assembly passed legislation that repealed customer choice legislation, which is currently awaiting signature by the Govenor of Arkansas. Before West Virginia's choice plan can be effective, tax legislation must be passed to continue consistent funding for state and local governments. No further legislation has been introduced related to restructuring in West Virginia.
In general, state restructuring legislation provides for a transition from cost-based rate regulated bundled 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.
Ohio Restructuring - Affecting AEP, CSPCo and OPCo
Customer choice of electricity supplier and restructuring began on January 1, 2001, under the Ohio Act. At January 1, 2003, virtually all customers continue to receive supply service from CSPCo and OPCo with a legislatively required residential generation rate reduction of 5%. All customers continue to be served by CSPCo and OPCo for transmission and distribution services.
The Ohio Act provided for a five-year transition period to move from cost-based rates to market pricing for electric generation supply services. It granted the PUCO broad oversight responsibility for promulgation of rules for competitive retail electric generation service and approval of a transition plan for each electric utility company, changed the taxation of electric companies and addressed certain major transition issues including unbundling of rates and the recovery of stranded costs including regulatory assets and transition costs.
In 1999 CSPCo and OPCo filed transition plans. After negotiations with interested parties including the PUCO staff, the PUCO approved a stipulation agreement for CSPCo's and OPCo's transition plans. The approved plans included, among other things, recovery of generation-related regulatory assets over seven years for OPCo and over eight years for CSPCo through frozen transition rates for the first five years of the recovery period and through a wires charge for the remaining years. At December 31, 2002, the remaining amount of regulatory assets to be amortized as recovered was $375 million for OPCo and $205 million for CSPCo.
By provisions of the Ohio Act on May 1, 2001, electric distribution companies became subject to an excise tax based on KWH sold to Ohio customers. The last tax year for which Ohio electric utilities paid the excise tax based on gross receipts was May 1, 2001 through April 30, 2002. As required by law, the gross receipts tax is paid in advance of the tax year for which the utility exercises its privilege to conduct business. CSPCo and OPCo treated the tax payment as a prepaid expense and amortized it to expense during the privilege year.
The stipulation agreement also required the PUCO to consider implementation of a gross receipts tax credit rider as the parties could not reach an agreement. Following a hearing on the gross receipts tax issue, the PUCO ordered the gross receipts tax credit rider to be effective May 1, 2001 instead of May 1, 2002 as proposed by the companies. On April 3, 2002, the Ohio Supreme Court rejected the companies' arguments and affirmed the PUCO's order which established the effective date of tax credit riders in rates. This ruling had no impact on 2002 results of operations as the companies had recorded an extraordinary loss ($30 million for CSPCo and $18 million for OPCo, both amounts net of tax) in 2001.
On June 27, 2002, the Ohio Consumers' Counsel, Industrial Energy Users - Ohio and American Municipal Power - Ohio filed a complaint with the PUCO alleging that CSPCo and OPCo have violated the PUCO's orders regarding implementation of their transition plan and violated other applicable law by failing to participate in an RTO.
The complainants seek, among other relief, an order from the PUCO suspending collection of transition charges by CSPCo and OPCo until transfer of control of their transmission assets has occurred, pricing standard offer electric generation effective January 1, 2006 at the market price used by the companies in their 1999 transition plan filings to estimate transition costs and imposing a $25,000 per company forfeiture for each day AEP fails to comply with its commitment to transfer control of transmission assets to an RTO.
Due to the FERC's reversal of its previous approval of our RTO filings, CSPCo and OPCo have been delayed in the implementation of their RTO participation plans. We continue to pursue integration of CSPCo, OPCo and other AEP East companies into PJM. In this regard on December 19, 2002, the companies filed an application with PUCO for approval of the transfer of functional control over certain of their transmission facilities to PJM. Management is unable to predict the timing of FERC's final approval of RTOs, the timing of an RTO being operational or the outcome of these proceedings before the PUCO.
In October 2002, the PUCO initiated an investigation of the financial condition of Ohio's regulated public utilities. The PUCO's goal is to identify measures available to the PUCO to ensure that the regulated operations of Ohio's public utilities are not impacted by adverse financial consequences of parent or affiliate company unregulated operations and take appropriate corrective action, if necessary. The utilities and other interested parties were requested to provide comments and suggestions by November 12, 2002, with reply comments by November 22, 2002, on the type of information necessary to accomplish the stated goals, the means to gather the required information from the public utilities and potential courses of action that the PUCO could take. Management is unable to predict the outcome of the PUCO's investigation or its impact on results of operations and business practices, if any.
Virginia Restructuring - Affecting AEP and APCo
In Virginia, choice of electricity supplier for retail customers began on January 1, 2002 under its restructuring law. Presently, APCo continues to service all its previous customers under capped rates. A finding by the Virginia SCC that an effective competitive market exists would be required to end the transition period prior to its scheduled end on June 30, 2007.
The restructuring law provides an opportunity for recovery of just and reasonable net stranded generation costs. The mechanisms in the Virginia law for net stranded cost recovery are: a capping of rates until as late as July 1, 2007, and the application of a wires charge upon customers who depart the incumbent utility in favor of an alternative supplier prior to the termination of the rate cap. Capped rates are the rates in effect at July 1, 1999 if no rate change request was made by the utility. APCo did not request new rates. Virginia's restructuring law does not permit the Virginia SCC to change generation rates during the transition period except for changes in fuel costs, changes in state gross receipts taxes, or to address financial distress of the utility.
In July 2002, APCo filed with the Virginia SCC requesting an increase in fuel rates effective January 1, 2003. A public hearing was held on September 23, 2002 related to this filing. On November 8, 2002, a decision was issued in this proceeding approving an annual increase of approximately $24 million.
The Virginia restructuring law also required filings to be made that outline the functional separation of generation from transmission and distribution and a rate unbundling plan. In January 2001 APCo filed its corporate separation plan and rate unbundling plan with the Virginia SCC. The Virginia SCC approved settlement agreements that resolved most issues except the assignment of generation-related regulatory assets among functionally separated generation, transmission and distribution organizations. The Virginia SCC determined that generation-related regulatory assets and related amortization expense should be assigned to APCo's generation function. Presently, capped rates are sufficient to recover generation-related regulatory assets. Therefore, management determined that recovery of APCo's generation-related regulatory assets remains probable. APCo did not and will not collect a wires charge in 2002 or 2003, respectively. The settlement agreements and related Virginia SCC order addressed functional separation leaving decisions related to corporate separation for later consideration.
Texas Restructuring - Affecting AEP, SWEPCo, TCC and TNC
In preparation for the start of competition in Texas, CPL, SWEPCo, and WTU, the integrated electric utility companies operating in Texas, were required to make PUCT filings and legal and operational changes to their business. AEP formed new subsidiaries, Mutual Energy CPL L.P. and Mutual Energy WTU L.P., to act as retail electric providers (REP) in Texas beginning on January 1, 2002, the effective date of customer choice in Texas. The CPL and WTU names continued to be used by the registrant subsidiaries which owned the generation, transmission and distribution assets located in the ERCOT areas of Texas and WTU's entire operations in SPP throughout most of 2002. In December 2002, WTU transferred its SPP retail customers to Mutual Energy SWEPCO L.P. AEP sold the new subsidiaries that serve ERCOT retail customers to Centrica in December 2002, along with the Central Power and Light and West Texas Utilities brand names. CPL and WTU changed their names to AEP Texas Central Company (TCC) and AEP Texas North Company (TNC), respectively.
On January 1, 2002, customer choice of electricity supplier began in the ERCOT area of Texas. Customer choice has been delayed in other areas of Texas including the SPP area. All of SWEPCo's Texas service territory and a small portion of TNC's service territory are located in the SPP. TCC operates entirely in the ERCOT area of Texas.
Texas restructuring legislation, among other things:
o provides for the recovery of regulatory assets and other stranded costs
through securitization and non-bypassable wires charges;
o requires reductions in NOx and sulfur dioxide emissions;
o provides for an earnings test for each of the years 1999 through 2001 which
will reduce stranded cost recoveries or if there is no stranded cost,
provides for a refund or their use to fund certain capital expenditures;
o requires each utility to structurally unbundle into a retail electric
provider, a power generation company and a transmission and distribution
utility;
o provides for certain limits for ownership and control of generating
capacity by companies and;
o provides for a 2004 true-up proceeding to quantify and reconcile the amount
of stranded costs, final fuel balances, net regulatory assets, certain
environmental costs, accumulated excess earnings, excess of price-to-beat
revenues over market prices subject to certain conditions and limitations
(Retail clawback), and the difference between the price of power obtained
through the legislatively-mandated capacity auctions and the power costs
used in the PUCT's ECOM model for 2002 and 2003 (Wholesale clawback) and
other issues.
Under the Texas Legislation, electric utilities were required to submit a plan to structurally unbundle business activities into a retail electric provider, a power generation company and a transmission and distribution (T&D) utility. In 2000, SWEPCo, TCC and TNC filed their business separation plans with the PUCT. The PUCT approved the plans for TCC and TNC but determined that competition in the SPP areas of Texas should be delayed indefinitely and abated SWEPCo's plan.
Operations for TCC and TNC have been functionally separated consistent with the approved plans. The delivery of electricity in ERCOT continues to be the responsibility of TCC and TNC at regulated prices.
Texas Legislation provides electric utilities an opportunity to recover regulatory assets and stranded costs resulting from the unbundling of the T&D utility from the generation facilities. Stranded costs are the difference between regulatory net book value of generation assets and the market value of the assets based on one of several methodologies authorized by the Texas Legislation. Stranded costs can be refinanced through securitization (a financing structure designed to provide lower financing costs than are available through conventional financings).
In 1999, TCC filed with the PUCT to securitize $1.27 billion of its retail generation-related regulatory assets and $47 million in other qualified restructuring costs. The PUCT authorized the issuance of up to $797 million of securitization bonds ($949 million of generation-related regulatory assets and $33 million of qualified refinancing costs offset by $185 million of customer benefits for accumulated deferred income taxes). TCC issued its securitization bonds in February 2002. The annual cost of the bonds are recovered through a PUCT approved transition charge in distribution rates.
TCC included regulatory assets not approved for securitization in its request for recovery of $1.1 billion of stranded costs. The $1.1 billion request included $800 million of STP costs included in Property, Plant and Equipment-Electric Production on AEP's Consolidated Balance Sheets. These STP costs had previously been identified as excess cost over market (ECOM) by the PUCT for regulatory purposes. They were earning a lower return and being amortized on an accelerated basis for rate-making purposes.
After hearings on the issue of stranded costs, the PUCT ruled, in October 2001, that its current estimate of TCC's stranded costs was negative $615 million. TCC disagreed with the ruling (see discussion of appeal ruling below). The ruling indicated that TCC's costs were below market after securitization of regulatory assets. 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. If TCC's total stranded costs determined in the 2004 true-up are less than the amount of securitized regulatory assets, the PUCT can implement an offsetting credit to transmission and distribution rates.
The Texas Legislation allows for several alternative methods to be used to value stranded costs in the final 2004 true-up proceeding including the sale or exchange of generation assets, stock valuation or the use of an ECOM model.
TCC decided to obtain a market value of generating assets for purposes of determining stranded costs for the 2004 true-up proceeding and filed a plan of divestiture with the PUCT, in December 2002, seeking approval of a sales process for all of its generating facilities. Such sales quantify the actual stranded costs. The amount of stranded costs under this market valuation methodology will be the amount by which net book value of TCC's generating assets, including regulatory assets and liabilities that were not securitized, exceeds the market value of the generation assets as measured by the net proceeds from the sale of the assets. It is anticipated that any such sale will result in significant stranded costs for purposes of the 2004 true-up proceeding. The filing included a request for the PUCT to issue a declaratory order that TCC's 25% ownership interest in its nuclear plant, STP, can be sold to value stranded costs. Intervenors to this proceeding, including the PUCT Staff, have made filings to dismiss TCC's filing claiming that the PUCT does not have the authority to issue a declaratory order. The intervenors also argued that the proper time to address the sales process is after the plants are sold during the 2004 true-up proceeding. Since the bidding process is not expected to be completed before mid 2004, TCC requested that the 2004 true-up proceeding be scheduled after completion of the divestiture of the generating assets.
Texas Legislation also requires that electric utilities and their affiliated power generation companies (PGC) sell at auction in 2002 and 2003 at least 15% of the PGC's Texas jurisdictional installed generation capacity in order to promote competitiveness in the wholesale market through increased availability of generation and liquidity. Actual market power prices received in the state mandated auctions wil replace the PUCT's earlier estimates of those market prices used in the ECOM model to calculate the stranded cost for the 2004 true-up proceeding.
The decision to determine stranded costs using market prices, instead of using the PUCT's ECOM model estimates, enabled TCC to record a $262 million regulatory asset and related revenues which represents the quantifiable amount of stranded costs for the year 2002 related to the wholesale prices. Prior to the decision to pursue a sale of TCC's generating assets, the PUCT's ECOM estimate prohibited the recognition of the regulatory assets and revenues as there was no way to quantify stranded costs. As discussed above, a defined process is required in order to determine the amount of stranded costs related to generation facility for the 2004 true-up proceedings. TCC's plan of divestiture filed with the PUCT during December 2002 provided such a process.
When the divestiture and the 2004 true-up processing is completed, TCC will securitize stranded costs which exceed current securitized amounts. The annual costs of securitization will be recovered through a non-bypassable rate surcharge by the regulated T&D utility over the life of the securitization bonds. Any stranded costs and other true-up amounts not recovered through the sale of securitization bonds may be recovered through a separate non-bypassable competitive transition charge to T&D utility customers.
The Texas Legislation provides for an earnings test each year 1999 through 2001 and requires PUCT approval of the annual earnings test calculation.
The PUCT issued final orders for the 1999 earnings test in February 2001 and for the 2000 earnings test in September 2001. The 1999 excess earnings were none for SWEPCo, $24 million for TCC and $1 million for TNC. Excess earnings for 2000 were $1 million for SWEPCo, $23 million for TCC and $17 million for TNC. Adjustments were recorded in results of operations as the orders were received.
The PUCT issued its final order for the 2001 earnings test in December 2002. An estimate of 2001 excess earnings of $8 million for TCC, $2 million for SWEPCo and none for TNC had been recorded in 2001. Adjustments to reflect the PUCT staff's estimate of excess earnings ($2 million for SWEPCo, $0.7 million for TNC and none for TCC) were recorded prior to September 30, 2002. The PUCT's final order regarding 2001 excess earnings required only minor adjustments to prior estimates.
Due to TCC's and TNC's disagreement with the PUCT's final order for the 2000 excess earnings, the companies filed an appeal in district court in 2001 seeking judicial review of the PUCT's determination of excess earnings. The district court upheld the PUCT's order and the companies appealed that decision. A ruling on the appeal is expected in 2003.
On January 28, 2003, the TCC and TNC filed an appeal in District Court seeking judicial review of the PUCT order for the 2001 excess earnings.
The PUCT ruled that prior to the 2004 true-up proceeding, no adjustments would be made to the amount of stranded costs authorized by the PUCT to be securitized. Final stranded cost amounts and the treatment of excess earnings will be determined in the 2004 true-up proceeding. To the extent that the final 2004 true-up proceeding determines that TCC should recover additional stranded costs, the additional amount recoverable can also be securitized. The PUCT also ruled that excess earnings for the period 1999-2001 should be refunded through distribution rates to the extent of any over-mitigation of stranded costs represented by negative ECOM. In 2001 the PUCT issued an order requiring TCC to reduce distribution rates by approximately $54.8 million plus accrued interest over a five-year period beginning January 1, 2002 in order to return estimated excess earnings for 1999, 2000 and 2001. Since excess earnings amounts were expensed in 1999, 2000 and 2001, the order has no additional effect on reported net income but will reduce cash flows for the five year refund period. The amount to be refunded is recorded as a regulatory liability.
Management believes that TCC will have stranded costs in 2004. TCC has appealed the PUCT's refund of excess earnings to the Travis County District Court and, depending on the outcome of that appeal (and the final outcome of the rulemaking challenge discussed below), the PUCT may revise the treatment of excess earnings in the final calculation of the stranded cost balance. In the same appeal, TCC and certain unaffiliated parties also challenged various elements of the PUCT's order determining the estimated stranded costs of TCC, with the unaffiliated parties contending, among other things, that the entire $615 million of negative stranded costs should be refunded presently. Prior to the Court hearing on this issue, however, TCC agreed to give up its claims concerning errors in the calculation of the stranded cost estimate, while the unaffiliated parties agreed to give up claims that there should be a refund of negative stranded costs. The Travis County District Court subsequently heard oral arguments concerning the remaining issues in the appeal, but has not yet issued a decision. The PUCT's stranded cost estimate that is the subject of this appeal will be superceded by a final determination of stranded costs to be accomplished as part of the 2004 true-up proceeding.
In a separate appeal challenging the PUCT's substantive rule governing the 2004 true-up proceeding, the Texas Third Court of Appeals ruled in February 2003, that the Texas Legislation does not contemplate the refunding of negative stranded costs to customers. The Court of Appeals held that the PUCT was justified in using any negative stranded cost balance determined in the 2004 true-up proceeding only as an offset to prevent an over-recovery of stranded costs via securitization. In addition, the Court of Appeals ruled that negative stranded costs cannot be offset against other true-up balances, including final under-recovered fuel amounts. This ruling may be further appealed to the Supreme Court of Texas.
Beginning January 1, 2002, fuel costs are not subject to PUCT fuel reconciliation proceedings for TCC and TNC's ERCOT retail customers. Due to the delay of competition for SWEPCo's SPP area of Texas, SWEPCo continues to record and request recovery of fuel costs subject to Texas fuel proceedings. Final deferred fuel balances related to ERCOT customers of TCC and TNC at December 31, 2001 will be included in the 2004 true-up proceeding. If the final fuel balances or any amount incurred but not yet reconciled are not recovered, they could have a negative impact on results of operations.
Under the Texas Legislation, retail electric providers (REPs) associated with integrated utilities are required to offer residential and small commercial customers (with a peak usage of less than 1000 KW) a price-to-beat rate until January 1, 2007. In December 2001 the PUCT approved price-to-beat rates for the AEP REPs in TCC's and TNC's ERCOT area. Customers with a peak usage of more than 1000 KW are subject to market rates. The Texas Restructuring Legislation also provides that a REP associated with integrated utilities may request an adjustment of its fuel portion of the price-to-beat rate up to two times annually to reflect changes in market prices of fuel and purchased energy costs based upon changes in NYMEX gas prices.
As part of the 2004 true-up proceedings the price-to-beat rates charged by AEP REPs for 2002 and 2003 will be compared to the market rates for the same period. If market rates are lower, the excess of the price-to-beat, reduced by non- bypassable delivery charges, over the prevailing market prices must be returned to the distribution company, subject to a per customer maximum. During 2002, AEP provided for such potential liabilities at the maximum amount via a charge to revenues, and recorded a regulatory liability for TCC and TNC. These amounts were $52 million for TCC and $14 million for TNC.
West Virginia Restructuring - Affecting AEP and APCo
In 2000 the WVPSC issued an order approving an electricity restructuring plan which the WV Legislature approved by joint resolution. The joint resolution provides that the WVPSC cannot implement the plan until the legislature makes tax law changes necessary to preserve the revenues of state and local governments. Since the WV Legislature has not passed the required tax law changes, the restructuring plan has not become effective. AEP subsidiaries, APCo and WPCo, provide electric service in WV.
A Joint Stipulation approved by the WVPSC in 2000 in connection with a base rate
filing, allowed for recovery of regulatory assets including any
generation-related regulatory assets through the following provisions: o Frozen
transition rates and a wires charge of 0.5 mills per KWH.
o The retention, as a regulatory liability, on the books of a net cumulative
deferred ENEC over-recovery balance of $66 million to be used to offset
the cost of deregulation when generation is deregulated in WV.
o The retention of net merger savings prior to December 31, 2004
resulting from the merger of AEP and CSW.
o A 0.5 mills per KWH wires charge for departing customers provided
for in the WV Restructuring Plan.
Management expects that the approved Joint Stipulation provides for the recovery of existing regulatory assets and other stranded costs.
In order for customer choice to become effective in WV, the WV Legislature needed to enact additional legislation to preserve the revenues of state and local government. In the subsequent two legislative sessions, which usually end in March each year, the West Virginia Legislature has not enacted the required legislation. Due to the lack of legislative activity, the WVPSC closed two proceedings related to electricity restructuring in the summer of 2002.
The two closed proceedings related to the respective dockets intended originally to determine whether West Virginia should deregulate the generation business, and to develop the WVPSC's Deregulation Plan and related rules to implement the Plan.
Management has reviewed these two proceedings and has concluded that at this time it is not clear that APCo meets the requirements to reapply SFAS 71. Management will monitor developments to determine when it is appropriate to reapply SFAS 71 to APCo's generation business.
Arkansas Restructuring - Affecting AEP and SWEPCo
In 1999, Arkansas enacted legislation to restructure its electric utility industry.
In February 2003, the Arkansas General Assembly passed legislation that repealed customer choice legislation, which is currently awaiting signature by the Governor of Arkansas.
Discontinuance of the Application of SFAS 71 Regulatory Accounting in Arkansas,
Ohio, Texas, Virginia and West Virginia - Affecting AEP, APCo, CSPCo, OPCo,
SWEPCo, TCC and TNC
The enactment of restructuring legislation and the ability to determine transition rates, wires charges and any resultant gain or loss under restructuring legislation in Arkansas, Ohio, Texas, Virginia and West Virginia resulted in AEP and certain subsidiaries discontinuing regulatory accounting under SFAS 71 for the generation portion of their business in those states. Under the provisions of SFAS 71, regulatory assets and regulatory liabilities are recorded to reflect the economic effects of regulation by matching expenses with related regulated revenues.
The discontinuance of the application of SFAS 71 in Arkansas, Ohio, Texas, Virginia and West Virginia resulted in recognition of extraordinary gains or losses. The discontinuance of SFAS 71 can require the write-off of regulatory assets and liabilities related to the deregulated operations, unless their recovery is provided through cost-based regulated rates to be collected in a portion of operations which continues to be rate regulated. Additionally, a company must determine if any plant assets are impaired when they discontinue SFAS 71 accounting. At the time the companies discontinued SFAS 71, the analysis showed that there was no accounting impairment of generation assets.
As a result of deregulation of generation, the application of SFAS 71 for the generation portion of the business in Arkansas, Ohio, Texas, Virginia and West Virginia was discontinued. Remaining generation-related regulatory assets will be amortized as they are recovered under terms of transition plans. Management believes that substantially all generation-related regulatory assets and stranded costs will be recovered under terms of the transition plans. If future events including the 2004 true-up proceeding in Texas were to make their recovery no longer probable, the companies would write-off the portion of such regulatory assets and stranded costs deemed unrecoverable as a non-cash extraordinary charge to earnings. If any write-off of regulatory assets or stranded costs occurred, it could have a material adverse effect on future results of operations, cash flows and possibly financial condition.
Michigan Restructuring - Affecting AEP and I&M
Customer choice commenced for I&M's Michigan customers on January 1, 2002. Effective with that date the rates on I&M's Michigan customers' bills for retail electric service were unbundled to allow customers the opportunity to evaluate the cost of generation service for comparison with other offers. I&M's total rates in Michigan remain unchanged and reflect cost of service. At December 31, 2002, none of I&M's customers have elected to change suppliers and no alternative electric suppliers are registered to compete in I&M's Michigan service territory.
Management has concluded that as of December 31, 2002 the requirements to apply SFAS 71 continue to be met since I&M's rates for generation in Michigan continue to be cost-based regulated.
9. Commitments and Contingencies:
Construction and Other Commitments - Affecting AEP, AEGCo, APCo, CSPCo, I&M,
KPCo, OPCo, PSO, SWEPCo, TCC and TNC
The AEP System has substantial construction commitments to support its operations. Aggregate construction expenditures for 2003-2005 for consolidated domestic and foreign operations are estimated to be $4.7 billion.
The following table shows the estimated construction expenditures of the subsidiary registrants for 2003 - 2005:
(in millions)
AEGCo $ 70.9 APCo 1,005.7 CSPCo 418.9 I&M 601.5 KPCo 148.3 OPCo 733.4 PSO 262.3 SWEPCo 351.3 TCC 419.6 TNC 130.8 |
APCo, AEP's subsidiary which operates in Virginia and West Virginia, has been seeking regulatory approval to build a new high voltage transmission line for over a decade. Certificates have been issued by both the West Virginia Public Service Commission and the Virginia State Corporation Commission authorizing construction and operation of the line. On December 31, 2002, the U.S. Forest Service issued a final environmental impact statement and record of decision to allow the use of federal lands in the Jefferson National Forest for construction of a portion of the line. We expect additional state and federal permits to be issued in the first half of 2003. Through December 31, 2002, we had invested approximately $51 million in this effort. The line is estimated to cost $287 million including amounts spent to date with completion scheduled in 2006. If the required permits are not obtained and the line is not constructed, the $51 million investment would be written off adversely affecting future results of operations and cash flows.
Long-term contracts to acquire fuel for electric generation have been entered into for various terms, the longest of which extends to the year 2014 for the AEP System. The expiration date of the longest fuel contract is 2007 for APCo, 2005 for CSPCo, 2007 for I&M, 2005 for KPCo, 2012 for OPCo, 2014 for PSO, 2006 for SWEPCo and 2006 for TNC. The contracts provide for periodic price adjustments and contain various clauses that would release the subsidiaries from their obligations under certain force majeure conditions.
The AEP System has unit contingent contracts to supply approximately 250 MW of capacity to unaffiliated entities through December 31, 2009. The commitment is pursuant to a unit power agreement requiring the delivery of energy only if the unit capacity is available.
Power Generation Facility - Affecting AEP and OPCo
AEP has entered into agreements with Katco Funding L.P. (Katco) an unrelated unconsolidated special purpose entity. Katco has an aggregate financing commitment of $525 million and a capital structure of which 3% is equity from investors with no relationship to AEP or any of its subsidiaries and 97% is debt from a syndicate of banks. Katco was formed to develop, construct, finance and lease a power generation facility to AEP. Katco will own the power generation facility and lease it to AEP after construction is completed. The lease will be accounted for as an operating lease (see Note 22), therefore neither the facility nor the related obligations are reported on AEP's balance sheet. Payments under the operating lease are expected to commence in the first quarter of 2004. AEP will in turn sublease the facility to Dow Chemical Company (DOW), which will use the energy produced by the facility and sell excess energy. AEP has agreed to purchase the excess energy from DOW for resale. The use of Katco allows AEP to limit its risk associated with the power generation facility once the construction phase has been completed.
AEP is the construction agent for Katco, and is responsible for completing construction by December 31, 2003, subject to unforeseen events beyond AEP's control.
In the event the project is terminated before completion of construction, AEP has the option to either purchase the facility for 100% of project costs or terminate the project and make a payment to Katco for 89.9% of project costs.
The operating lease between Katco and AEP commences on the commercial operation date of the facility and continues until November 2006. The lease contains extension options subject to the approval of Katco, and if all extension options were exercised, the total term of the lease would be 30 years. AEP's lease payments to Katco are sufficient for Katco to make required debt payments and provide a return to the investors of Katco. At the end of each lease term, AEP may renew the lease at fair market value subject to Katco's approval, purchase the facility at its original construction cost, or sell the facility, on behalf of Katco, to an independent third party. If the facility is sold and the proceeds from the sale are insufficient to repay Katco, AEP may be required to make a payment to Katco for the difference between the proceeds from the sale and the obligations of Katco, up to 82% of the project's cost. AEP has guaranteed a portion of the obligations of its subsidiaries to Katco during the construction and post-construction periods.
As of December 31, 2002, project costs subject to these agreements totaled $360 million, and total costs for the completed facility are expected to be approximately $510 million. For the 30-year extended lease term, the lease rental is a variable rate obligation indexed to three-month LIBOR. Consequently as market interest rates increase, the payments under this operating lease will also increase. Annual payments of approximately $12 million represent future minimum payments during the initial term calculated using the indexed LIBOR rate (1.38% at December 31, 2002). The Power Generation Facility collateralizes the debt obligation of Katco. AEP's maximum exposure to loss as a result of its involvement with Katco is 100% during the construction phase and up to 82% once the construction is completed. Maximum loss is deemed to be remote due to the collateralization.
It is reasonably possible that AEP will consolidate Katco in the third quarter of 2003, as a result of the issuance of FASB Interpretation No. 46 "Consolidation of Variable Interest Entities" (FIN 46). Upon consolidation, AEP would record the assets, liabilities, depreciation expense, minority interest and debt interest expense. AEP would eliminate operating lease expense. The sublease to DOW would not be affected by this consolidation.
OPCo has entered into a 30-year power purchase agreement for electricity produced by an unaffiliated entity's three-unit natural gas fired plant. The plant was completed in 2002 and the agreement will terminate in 2032. Under the terms of the agreement, OPCo has the option to run the plant until December 31, 2005 taking 100% of the power generated and making monthly capacity payments. The capacity payments are fixed through December 2005 at $1.2 million per month. For the remainder of the 30-year contract term, OPCo will pay the variable costs to generate the electricity it purchases (up to 20% of the plant's capacity).
Nuclear Plants - Affecting AEP, I&M and TCC
I&M owns and operates the two-unit 2,110 MW Cook Plant under licenses granted by the NRC. TCC owns 25.2% of the two-unit 2,500 MW STP. STPNOC operates STP on behalf of the joint owners under licenses granted by the NRC. The operation of a nuclear facility involves special risks, potential liabilities, and specific regulatory and safety requirements. Should a nuclear incident occur at any nuclear power plant facility in the U.S., the resultant liability could be substantial. By agreement I&M and TCC are partially liable together with all other electric utility companies that own nuclear generating units for a nuclear power plant incident at any nuclear plant in the U.S. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, results of operations, cash flows and financial condition would be adversely affected.
Nuclear Incident Liability - Affecting AEP, I&M and TCC
The Price-Anderson Act establishes insurance protection for public liability arising from a nuclear incident at $9.5 billion and covers any incident at a licensed reactor in the U.S. Commercially available insurance provides $200 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $88 million on each licensed reactor in the U.S. payable in annual installments of $10 million. As a result, I&M could be assessed $176 million per nuclear incident payable in annual installments of $20 million. TCC could be assessed $44 million per nuclear incident payable in annual installments of $5 million as its share of a STPNOC assessment. The number of incidents for which payments could be required is not limited. Under an industry-wide program insuring workers at nuclear facilities, I&M and TCC are also obligated for assessments of up to $6.2 million and $1.6 million, respectively, for potential claims. These obligations will remain in effect until December 31, 2007.
Insurance coverage for property damage, decommissioning and decontamination at the Cook Plant and STP is carried by I&M and STPNOC in the amount of $1.8 billion each. I&M and STPNOC jointly purchase $1 billion of excess coverage for property damage, decommissioning and decontamination. Additional insurance provides coverage for extra costs resulting from a prolonged accidental outage. I&M and STPNOC utilize an industry mutual insurer for the placement of this insurance coverage. Participation in this mutual insurer requires a contingent financial obligation of up to $36 million for I&M and $3 million for TCC which is assessable if the insurer's financial resources would be inadequate to pay for losses.
The current Price-Anderson Act expired in August 2002. Its contingent financial obligations still apply to reactors licensed by the NRC as of its expiration date. It is anticipated that the Price-Anderson Act will be renewed with increased third party financial protection requirements for nuclear incidents.
SNF Disposal - Affecting AEP, I&M and TCC
Federal law provides for government responsibility for permanent SNF disposal and assesses nuclear plant owners fees for SNF disposal. A fee of one mill per KWH for fuel consumed after April 6, 1983 at Cook Plant and STP is being collected from customers and remitted to the U.S. Treasury. Fees and related interest of $224 million for fuel consumed prior to April 7, 1983 at Cook Plant have been recorded as long-term debt. I&M has not paid the government the Cook Plant related pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program. At December 31, 2002, funds collected from customers towards payment of the pre-April 1983 fee and related earnings thereon are in external funds and exceed the liability amount. TCC is not liable for any assessments for nuclear fuel consumed prior to April 7, 1983 since the STP units began operation in 1988 and 1989.
Decommissioning and Low Level Waste Accumulation Disposal - Affecting AEP, I&M and TCC
Decommissioning costs are accrued over the service lives of the Cook Plant and STP. The licenses to operate the two nuclear units at Cook Plant expire in 2014 and 2017. After expiration of the licenses, Cook Plant is expected to be decommissioned using the prompt decontamination and dismantlement (DECON) method. The estimated cost of decommissioning and low level radioactive waste accumulation disposal costs for Cook Plant ranges from $783 million to $1,481 million in 2000 nondiscounted dollars. The wide range is caused by variables in assumptions including the estimated length of time SNF may need to be stored at the plant site subsequent to ceasing operations. This, in turn, depends on future developments in the federal government's SNF disposal program. Continued delays in the federal fuel disposal program can result in increased decommissioning costs. I&M is recovering estimated Cook Plant decommissioning costs in its three rate-making jurisdictions based on at least the lower end of the range in the most recent decommissioning study at the time of the last rate proceeding. The amount recovered in rates for decommissioning the Cook Plant and deposited in the external fund was $27 million in 2002 and 2001 and $28 million in 2000.
The licenses to operate the two nuclear units at STP expire in 2027 and 2028. After expiration of the licenses, STP is expected to be decommissioned using the DECON method. TCC estimates its portion of the costs of decommissioning STP to be $289 million in 1999 nondiscounted dollars. TCC is accruing and recovering these decommissioning costs through rates based on the service life of STP at a rate of $8 million per year.
Decommissioning costs recovered from customers are deposited in external trusts. In 2002 and 2001 I&M deposited in its decommissioning trust an additional $12 million each year related to special regulatory commission approved funding for decommissioning of the Cook Plant. Trust fund earnings increase the fund assets and the recorded liability and decrease the amount needed to be recovered from ratepayers. Decommissioning costs including interest, unrealized gains and losses and expenses of the trust funds are recorded in Other Operation expense for Cook Plant. For STP, nuclear decommissioning costs are recorded in Other Operation expense, interest income of the trusts are recorded in Nonoperating Income and interest expense of the trust funds are included in Interest Charges.
On the AEP Consolidated Balance Sheets, nuclear decommissioning trust assets are included in Other Assets and a corresponding nuclear decommissioning liability is included in Other Noncurrent Liabilities. On TCC's balance sheets, the nuclear decommissioning liability of $98 million is included in Electric Utility Plant-Accumulated Depreciation and Amortization. The decommissioning liability for both nuclear plants combined totals $719 million and $699 million at December 31, 2002 and 2001, respectively.
Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M, and OPCo
Since 1999 AEPSC, APCo, CSPCo, I&M, and OPCo have been involved in litigation regarding generating plant emissions under the Clean Air Act. Federal EPA and a number of states alleged that AEP System companies and eleven unaffiliated utilities modified certain units at coal fired generating plants in violation of the Clean Air Act. Federal EPA filed complaints against AEP subsidiaries in U.S. District Court for the Southern District of Ohio. A separate lawsuit initiated by certain special interest groups was consolidated with the Federal EPA case. The alleged modification of the generating units occurred over a 20 year period.
Under the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). In 2001 the District Court ruled claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints cannot be imposed. There is no time limit on claims for injunctive relief.
Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and intends to vigorously pursue its defense.
Management is unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the Clear Air Act proceedings and unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. In the event the AEP System companies do not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates and market prices for electricity.
In December 2000 Cinergy Corp., an unaffiliated utility, which operates certain plants jointly owned by CSPCo, reached a tentative agreement with the Federal EPA and other parties to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing between the parties in an attempt to reach final settlement terms. Cinergy's settlement could impact the operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%, respectively, by CSPCo). Until a final settlement is reached, CSPCo will be unable to determine the settlement's impact on its jointly owned facilities and its results of operations and cash flows.
NOx Reductions - Affecting AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, SWEPCo and
TCC
Federal EPA issued a NOx Rule requiring substantial reductions in NOx emissions in a number of eastern states, including certain states in which the AEP System's generating plants are located. The NOx Rule has been upheld on appeal. The compliance date for the NOx Rule is May 31, 2004.
In 2000 Federal EPA also adopted a revised rule (the Section 126 Rule) granting petitions filed by certain northeastern states under the Clean Air Act. The rule imposed emissions reduction requirements comparable to the NOx Rule beginning May 1, 2003, for most of AEP's coal-fired generating units. Affected utilities, including certain AEP operating companies, petitioned the D.C. Circuit Court to review the Section 126 Rule.
After review, the D.C. Circuit Court instructed Federal EPA to justify the methods it used to allocate allowances and project growth for both the NOx Rule and the Section 126 Rule. AEP subsidiaries and other utilities requested that the D.C. Circuit Court vacate the Section 126 Rule or suspend its May 2003 compliance date. In August 2001 the D.C. Circuit Court issued an order tolling the compliance schedule until Federal EPA responded to the Court's remand. On April 30, 2002, Federal EPA announced that May 31, 2004 is the compliance date for the Section 126 Rule. Federal EPA published a notice in the Federal Register in May 2002 advising that no changes in the growth factors used to set the NOx budgets were warranted. In June 2002 AEP subsidiaries joined other utilities and industrial organizations in seeking a review of Federal EPA's action in the D.C. Circuit Court. This action is pending.
In 2000 the Texas Commission on Environmental Quality (formerly the Texas Natural Resource Conservation Commission) adopted rules requiring significant reductions in NOx emissions from utility sources, including SWEPCo and TCC. The compliance date is May 2003 for TCC and May 2005 for SWEPCo.
AEP is installing a variety of emission control technologies to reduce NOx emissions to comply with the applicable state and Federal NOx requirements. This includes selective catalytic reduction (SCR) technolocy on certain units and non-SCR technologies on a larger number of units. During 2001 SCR technology commenced operations on OPCo's Gavin Plant. Installation of SCR technology on Amos and Mountaineer plants was completed and commenced operation in May 2002. Construction of SCR technology at certain other AEP generating units continues. Non-SCR technologies have been installed and commenced operation on a number of units across the AEP System and additional units will be equipped with these technologies.
The AEP NOx compliance plan is a dynamic plan that is continually reviewed and revised as new information becomes available on the performance of installed technologies and the cost of planned technologies. Certain compliance steps may or may not be necessary as a result of this new information. Consequently, the plan has a range of possible outcomes. Our current estimates indicate that compliance with the NOx Rule, the Texas Commission on Environmental Quality rule and the Section 126 Rule could result in required capital expenditures in the range of $1.3 billion to $2 billion of which $843 million has been spent through December 31, 2002 for the AEP System. The range of cost estimate reflects the uncertainty over the need for certain SCR projects. Estimated compliance cost ranges and amounts spent by registrant subsidiaries at December 31, 2002, are as follows:
Estimated Amount Spent
Compliance Costs
---------------- ------------
(in millions)
AEGCo $30 - 198 $ 1
APCo 445 234
CSPCo 93 45
I&M 42 - 210 5
KPCo 163 135
OPCo 535 - 864 387
SWEPCo 40 24
TCC 5 5
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Since compliance costs cannot be estimated with certainty, the actual cost to comply could be significantly different than the estimates depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless any capital and operating costs of additional pollution control equipment are recovered from customers, they will have an adverse effect on results of operations, cash flows and possibly financial condition.
Merger Litigation - Affecting AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC
On January 18, 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC failed to prove that the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and sent the case back to the SEC for further review. Specifically, the court told the SEC to revisit its conclusion that the merger met PUHCA requirements that utilities be "physically interconnected" and confined to a "single area or region."
In its June 2000 approval of the merger, the SEC agreed with AEP that the companies' systems are integrated because they have transmission access rights to a single high-voltage line through Missouri and also met the PUCHA's single region requirement because it is now technically possible to centrally control the output of power plants across many states. In its ruling, the appeals court said that the SEC failed to support and explain its conclusions that the integration and single region requirements are satisfied.
Management believes that the merger meets the requirements of the PUHCA and expects the matter to be resolved favorably.
Enron Bankruptcy - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo
On October 15, 2002, certain subsidiaries of AEP filed claims against Enron and its subsidiaries in the bankruptcy proceeding filed by the Enron entities which are pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron's bankruptcy AEP had open trading contracts and trading accounts receivables and payables with Enron. In addition, on June 1, 2001, we purchased Houston Pipe Line Company (HPL) from Enron. Various HPL related contingencies and indemnities remained unsettled at the date of Enron's bankruptcy. The timing of the resolution of the claims by the Bankruptcy Court is not certain.
In connection with the 2001 acquisition of HPL, we acquired exclusive rights to use and operate the underground Bammel gas storage facility pursuant to an agreement with BAM Lease Company, a now-bankrupt subsidiary of Enron. This exclusive right to use the referenced facility is for a term of 30 years, with a renewal right for another 20 years and includes the use of the Bammel storage reservoir and the related compression, treating and delivery systems. We have engaged in preliminary discussions with Enron concerning the possible purchase of the residual interest held by Enron in the Bammel storage facility and the possible resolution of outstanding issues between AEP and Enron relating to our acquisition of its interest in the Bammel storage facility. We are unable to predict whether these discussions will lead to an agreement on these subjects. If these discussions do not lead to an agreement, there may be a dispute with Enron concerning our ability to continue utilization of the Bammel storage facility under the existing agreement.
We also entered into an agreement with BAM Lease Company which grants HPL the right to use approximately 65 billion cubic feet of cushion gas (or pad gas) required for the normal operation of the Bammel gas storage facility. The Bammel Gas Trust, which purportedly owned approximately 55 billion cubic feet of the gas, had entered into a financing arrangement in 1997 with Enron and a group of banks. These banks purported to have certain rights to the gas in certain events of default. In connection with AEP's acquisition of HPL, the banks entered into an agreement granting HPL's use of the cushion gas and released HPL from liabilities and obligations under the financing arrangement. HPL was thereafter informed by the banks of a purported default by Enron under the terms of the referenced financing arrangement. In July 2002 the banks filed a lawsuit against HPL seeking a declaratory judgment that they have a valid and enforceable security interest in this cushion gas which would permit them to cause the withdrawal of this gas from the storage facility. In September 2002 HPL filed a general denial and certain counterclaims against the banks. Management is unable to predict the outcome of this lawsuit or its impact on results of operations and cash flows.
In 2001 AEP expensed $47 million ($31 million net of tax) for our estimated loss from the Enron bankruptcy. In 2002 AEP expensed an additional $6 million for a cumulative loss of $53 million ($34 million net of tax). The amounts for certain subsidiary registrants were:
Amounts
Amounts Net of
Registrant Expensed Tax
-------- -----
(in millions)
APCo $5.3 $3.4
CSPCo 2.7 1.8
I&M 2.8 1.8
KPCo 1.1 0.7
OPCo 3.6 2.3
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The additional 2002 expense did not materially change the cumulative expense per registrant subsidiary. The amounts expensed were based on an analysis of contracts where AEP and Enron entities are counterparties, the offsetting of receivables and payables, the application of deposits from Enron entities and management's analysis of the HPL related purchase contingencies and indemnifications.
Enron has recently instituted proceedings against other energy trading counter-parties challenging the practice of utilizing offsetting receivables and payables and related collateral across various Enron entities. We believe that we have the right to utilize similar procedures in dealing with payables, receivables and collateral with Enron entities by offsetting approximately $110 million of trading payables owed to various Enron entities against trading receivables due to us. We believe we have legal defenses to any challenge that may be made to the utilization of such offsets but at this time are unable to predict the ultimate resolution of this issue.
Shareholder Lawsuits - Affecting AEP
In the fourth quarter of 2002 lawsuits alleging securities law violations and seeking class action certification were filed in federal District Court, Columbus, Ohio against AEP, certain AEP executives, and in some of the lawsuits, members of the AEP Board of Directors and certain investment banking firms. The lawsuits claim that AEP failed to disclose that alleged "round trip" trades resulted in an overstatement of revenues, that AEP failed to disclose that AEP traders falsely reported energy prices to trade publications that published gas price indices and that AEP failed to disclose that it did not have in place sufficient management controls to prevent round trip trades or false reporting of energy prices. The plaintiffs seek recovery of an unstated amount of compensatory damages, attorney fees and costs. The cases are presently pending a decision by the Court on competing motions by certain plaintiffs and groups of plaintiffs' for designation as lead plaintiff. Once the Court selects a lead plaintiff, that lead plaintiff will file an amended complaint. AEP intends to vigorously defend against these actions. Also in the fourth quarter of 2002, two shareholder derivative actions were filed in state court in Columbus, Ohio against AEP and its Board of Directors alleging a breach of fiduciary duty for failure to establish and maintain adequate internal controls over AEP's gas trading operations; and, a lawsuit was filed against AEP, certain AEP executives and AEP's ERISA Plan Administrator in federal District Court for the Southern District of New York (subsequently transferred to federal District Court in Columbus, Ohio) alleging violations of the Employee Retirement Income Security Act in the selection of AEP stock as a investment alternative and in the allocation of assets to AEP stock. These cases are in the initial pleading stage. AEP intends to vigorously defend against these actions.
California Lawsuit - Affecting AEP
In November 2002, Cruz Bustamante, Lieutenant Governor of California, filed a lawsuit in Los Angeles County, California Superior Court against forty energy companies including AEP and two publishing companies alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. This case is in the initial pleading stage. AEP intends to vigorously defend against this action.
Arbitration of Williams Claim - Affecting AEP
In October 2002, AEP filed its demand for arbitration with the American Arbitration Association to initiate formal arbitration proceedings in a dispute with the Williams Companies (Williams). The proceeding results from Williams' repudiation of its obligations to provide physical power deliveries to AEP and Williams' failure to provide the monetary security required for natural gas deliveries by AEP. Consequently, both parties claimed default and terminated all outstanding natural gas and electric power trading deals among the various Williams and AEP affiliates. Williams claimed that AEP owes approximately $130 million in connection with the termination and liquidation of all trading deals. AEP believes it has valid claims arising from Williams' actions and is seeking, in part, a determination that either no amount is due or that a lesser amount is due from AEP to Williams (which is fully reserved by AEP) and the extent of any other damages and legal or equitable relief available. Although management is unable to predict the outcome of this matter, it is not expected to have a material impact on results of operations, cash flows or financial condition.
Energy Market Investigations - Affecting AEP
In February 2002, the FERC issued an order directing its Staff to conduct a fact-finding investigation into whether any entity, including Enron, manipulated short-term prices in electric energy or natural gas markets in the West or otherwise exercised undue influence over wholesale prices in the West, for the period January 1, 2000, forward. In April 2002 AEP furnished certain information to the FERC in response to their related data request.
Pursuant to the FERC's February order, on May 8, 2002, the FERC issued further data requests, including requests for admissions, with respect to certain trading strategies engaged in by Enron and, allegedly, traders of other companies active in the wholesale electricity and ancillary services markets in the West, particularly California, during the years 2000 and 2001. This data request was issued to AEP as part of a group of over 100 entities designated by the FERC as all sellers of wholesale electricity and/or ancillary services to the California Independent System Operator and/or the California Power Exchange.
The May 8, 2002 FERC data request required senior management to conduct an investigation into our trading activities during 2000 and 2001 and to provide an affidavit as to whether we engaged in certain trading practices that the FERC characterized in the data request as being potentially manipulative. Senior management complied with the order and denied our involvement with those trading practices.
On May 21, 2002, the FERC issued a further data request with respect to this matter to us and over 100 other market participants requesting information for the years 2000 and 2001 concerning "wash", "round trip" or "sale/buy back" trading in the Western System Coordinating Council (WSCC), which involves the sale of an electricity product to another company together with a simultaneous purchase of the same product at the same price (collectively, "wash sales"). Similarly, on May 22, 2002, the FERC issued an additional data request with respect to this matter to us and other market participants requesting similar information for the same period with respect to the sale of natural gas products in the WSCC and Texas. After reviewing our records, we responded to the FERC that we did not participate in any "wash sale" transactions involving power or gas in the relevant market. We further informed the FERC that certain of our traders did engage in trades on the Intercontinental Exchange, an electronic electricity trading platform owned by a group of electricity trading companies, including us, on September 21, 2001, the day on which all brokerage commissions for trades on that exchange were donated to charities for the victims of the September 11, 2001 terrorist attacks, which do not meet the FERC criteria for a "wash sale" but do have certain characteristics in common with such sales. In response to a request from the California attorney general for a copy of AEP's responses to the FERC inquires, we provided the pertinent information.
The PUCT also issued similar data requests to AEP and other power marketers. AEP responded to such data request by the July 2, 2002 response date. The U.S. Commodity Futures Trading Commission (CFTC) issued a subpoena to us on June 17, 2002 requesting information with respect to "wash sale" trading practices. AEP responded to CFTC. In addition, the U.S. Department of Justice made a civil investigation demand to AEP and other electric generating companies concerning their investigation of the Intercontinental Exchange. AEP has completed a review of our trading activities in the United States for the last three years involving sequential trades with the same terms and counterparties. The revenue from such trading is not material to our financial statements. AEP believes that substantially all these transactions involve economic substance and risk transference and do not constitute "wash sales".
In August 2002, AEP received an informal data request from the SEC asking us to voluntarily provide documents related to "round trip" or "wash" trades. AEP has provided the requested information to the SEC.
In September 2002, AEP received a subpoena from FERC requesting information about our natural gas transactions and their potential impact on gas commodity prices in the New York City area. AEP responded to the subpoena in October 2002.
In October 2002, AEP dismissed several employees involved in natural gas marketing and trading after the Company determined that they provided inaccurate price information for use in indexes compiled and published by trade publications. AEP, subsequently, instituted measures that require all price information for use in market indexes be verified and reported through AEP's chief risk officer's organization. AEP has and will continue to provide to the FERC, the SEC and the CFTC information relating to price data given to energy industry publications.
FERC Proposed Standard Market Design - Affecting AEP System
In July 2002, the FERC issued its Standard Market Design (SMD) notice of proposed rulemaking, one of the most sweeping rulemaking proposals in its history. The proposed SMD rule seeks to standardize the structure and operation of wholesale electricity markets across the country. Key elements of FERC's proposal include standard rules and processes for all users of the electricity transmission grid, new transmission rules and policies, and the creation of certain markets to be operated by independent administrators of the grid in all regions. The FERC recently indicated that it would issue a white paper on the proposal in April 2003, in response to the numerous comments FERC received on its proposal. The FERC is expected to issue its final rule in mid to late 2003. Because the rule is not yet finalized, management cannot predict the effect of the final rule on cash flows and results of operations.
FERC Proposed Security Standards - Affecting AEP System
The FERC published for comment its proposed security standards as part of the SMD. These standards are intended to ensure all market participants have a basic security program that effectively protects the electric grid and related market activities. They require compliance by January 1, 2004. The impact of these proposed standards is far-reaching and includes significant penalties for non-compliance. These standards apply to market operations and transmission owners. For the AEP System this includes: power generation plants, transmission systems, distribution systems and related areas of business. FERC is considering new proposals to modify the scope and timetable for compliance with the standards. Unless FERC changes the scope and timing of the original proposed standards, those standards could result in significant expenditures and operational changes in a compressed time frame, and may adversely affect results of operations and cash flows if such costs are not recovered from customers.
FERC Market Power Mitigation - Affecting AEP System
A FERC order issued in November 2001 on AEP's triennial market based wholesale power rate authorization update required certain mitigation actions that AEP would need to take for sales/purchases within its control area and required AEP to post information on its website regarding its power system's status. As a result of a request for rehearing filed by AEP and other market participants, FERC issued an order delaying the effective date of the mitigation plan until after a planned technical conference on market power determination. No such conference has been held and management is unable to predict the timing of any further action by the FERC or its affect on future results of operations and cash flows.
Other - AEP and its subsidiaries are involved in a number of other legal proceedings and claims. While management is unable to predict the ultimate outcome of these matters, it is not expected that their resolution will have a material adverse effect on results of operations, cash flows or financial condition.
10. Guarantees:
In November 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45) which clarifies the accounting to recognize a liability related to issuing a guarantee, as well as additional disclosures of guarantees. This new guidance is an interpretation of SFAS 5, 57, and 107 and a rescission of FIN 34. The initial recognition and initial measurement provisions of FIN 45 is effective on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements of FIN 45 are effective for financial statements of interim or annual periods ending after December 15, 2002.
There are no liabilities recorded for all of the guarantees described below in accordance with FIN 45 as these guarantees were entered into prior to December 31, 2002. There is no collateral held in relation to these guarantees and there is no recourse to third parties in the event these guarantees are drawn.
Certain AEP subsidiaries have entered into standby letters of credit (LOC) with third parties. These LOCs cover gas and electricity trading contracts, construction contracts, insurance programs, security deposits, debt service reserves, drilling funds and credit enhancements for issued bonds. All of these LOCs were issued at a subsidiary level of AEP in the subsidiaries' ordinary course of business. TCC issued one of the LOCs for credit enhancement of issued bonds. The maximum future payments of all the LOCs are approximately $166 million with maturities ranging from January 2003 to December 2007. TCC's LOC was for $40.9 million with a maturity date of November 2003. Since AEP is the parent to all these subsidiaries, it holds all assets of the subsidiary as collateral. There is no recourse to third parties in the event these letters of credit are drawn.
The following AEP subsidiaries have entered into guarantees of third parties obligations:
CSW Energy and CSW International have guaranteed 50% of the required debt service reserve of Sweeny Cogeneration (Sweeny), an IPP of which CSW Energy is a 50% owner. The guarantee was provided in lieu of Sweeny funding the debt reserve as a part of financing. In the event that Sweeny does not make the required debt payments, CSW Energy and CSW International have a maximum future payment exposure of approximately $3.7 million, which expires June 2020.
Additionally, CSW guaranteed 50% of the required debt service reserve for Polk Power Partners, another IPP of which CSW Energy owns 50%. In the event that Polk Power does not make the required debt payments, CSW has a maximum future payment exposure of approximately $4.7 million, which expires July 2010.
In connection with reducing the cost of the lignite mining contract for its Henry W. Pirkey Power Plant, SWEPCo has agreed under certain conditions, to assume the revolving credit agreement, capital lease obligations, and term loan payments of the mining contractor. In the event the mining contractor defaults under any of these agreements, SWEPCo's total future maximum payment exposure is approximately $74 million with maturity dates ranging from April 2003 to February 2012.
As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo has agreed to provide guarantees of mine reclamation in the amount of approximately $85 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by a third party miner. At December 31, 2002 the cost to reclaim the mine is estimated to be approximately $36 million. This guarantee ends upon depletion of reserves estimated at 2035 plus 6 years to complete reclamation.
In connection with the ability for Mutual Energy CPL L.P. (former subsidiary of AEP sold to Centrica on December 23, 2002) to compete in the CPL territory and to secure transition charges, AEP provided a guarantee that AEP would pay transition charges if Mutual Energy CPL failed to meet certain obligations. At the time of sale this guarantee (matures in February 2003) was not revoked. The future maximum payment exposure is $12.2 million. In February 2003, the guarantee matured and no payments under the guarantee were required.
In connection with the ERCOT transmission congestion auction, AEP has guaranteed the obligations of Mutual Energy CPL L.P. (former subsidiary of AEP sold to Centrica on December 23, 2002) and Mutual Energy WTU L.P. (former subsidiary of AEP sold to Centrica on December 23, 2002). At the time of sale these guarantees were not revoked. The total future maximum payment exposure for both companies is approximately $0.6 million. In January 2003 these guarantees matured and no payments under the guarantees were required.
See Note 26 "Minority Interest in Finance Subsidiary" for disclosure for the guaranteed support of AEP for Caddis Partners, LLC.
AEP and all its registrant and non-registrant subsidiaries enter into several types of contracts, which would require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. At this time AEP cannot estimate the maximum potential payment for any of these indemnifications due to the uncertainty of future events. In addition, as of December 31, 2002, there are no liabilities required for any indemnifications.
AEP and its regulated and non-regulated subsidiaries lease certain equipment under a master operating lease. Under the lease agreement, the lessor is guaranteed to receive up to 87% of the unamortized balance of the equipment at the end of the lease term. If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, we have committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance. At December 31, 2002, the maximum potential loss for these lease agreements was approximately $50 million assuming the fair market value of the equipment is zero at the end of the lease term. The maximum potential loss by registrant is as follows:
Registrant Maximum Potential Loss
---------- ----------------------
(in millions)
APCo $ 0.7
CSPCo 0.8
I&M 2.0
KPCo -
OPCo 0.7
PSO 3.3
SWEPCo 3.4
TCC 6.7
TNC 2.5
Other AEP non-registrant
Subsidiaries 29.9
-----
Total $50.0
=====
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11. Sustained Earnings Improvement Initiative:
In response to difficult conditions in AEP's business, a Sustained Earnings
Improvement (SEI) initiative was undertaken company-wide in the fourth quarter
of 2002, as a cost-saving and revenue-building effort to build long-term
earnings growth. Termination benefits expense relating to 1,120 terminated
employees totaling $75.4 million pre-tax was recorded in the fourth quarter of
2002. Of this amount, AEP paid $9.5 million to these terminated employees in the
fourth quarter of 2002. The termination benefits expense was classified as
Maintenance and Other Operation expense on AEP's Consolidated Statements of
Operations and as Other Operation expense on the other registrant's statements
of operations. We determined that the termination of the employees under our SEI
initiative did not constitute a curtailment under the provisions of SFAS No. 88
"Employers' Accounting for Settlements and Curtailments of Defined Benefit
Pension Plans and for Termination Benefits".
The following table shows the staff reductions, termination benefits expense and
the remaining termination benefits expense accrual as of December 31, 2002:
Total Total
Number Total Termination
of Expense Benefits
Terminated Recorded in Accrued at
Employees 2002 12/31/02
--------- --------- -----------
(in millions) (in millions)
AEGCo - $ 0.3 $ 0.3
APCo 93 13.1 12.2
CSPCo 19 5.0 4.5
I&M 146 15.0 13.1
KPCo 16 2.6 2.5
OPCo 33 7.5 7.1
PSO 17 3.1 3.0
SWEPCo 8 3.3 3.1
TCC 37 6.0 5.5
TNC 20 2.0 1.6
Other AEP
Subsidiaries 731 17.5 13.0
----- ----- -----
Totals 1,120 $75.4 $65.9
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Approximately $48 million of severance expense associated with 701 AEP Service Corporation employees (included in the 731 figure above) was allocated among all AEP subsidiaries. AEGCo has no employees but receives allocated expenses.
In addition, certain buildings and corporate aircraft are being sold in an effort to reduce ongoing operating expenses.
12. Acquisitions, Dispositions and Discontinued Operations:
Acquisitions
SFAS 141 "Business Combinations" applies to all business combinations initiated and consummated after June 30, 2001.
2002
Acquisition of Nordic Trading
In January 2002 AEP acquired for $2.2 million and other assumed liabilities the
trading operations, including key staff, of Enron's Norway and Sweden-based
energy trading businesses (Nordic Trading). Results of operations are included
in AEP's Consolidated Statements of Operations from the date of acquisition. The
excess of cost over fair value of the net assets acquired was approximately $4.0
million which was recorded as Goodwill. Subsequently in the fourth quarter of
2002, a decision was made to exit the non-core trading business in Europe and to
close or sell Nordic Trading as discussed under the "Discontinued Operations"
section of this note.
Acquisition of USTI
In January 2002, AEP acquired 100% of the stock of United Sciences Testing, Inc.
(USTI) for $12.5 million. USTI provides equipment and services related to
automated emission monitoring of combustion gases to both AEP affiliates and
external customers. Results of operations are included in AEP's Consolidated
Statements of Operations from the date of acquisition.
2001
On June 1, 2001, AEP, through a wholly owned subsidiary, purchased Houston Pipe Line Company and Lodisco LLC for $727 million from Enron. The acquired assets include 4,200 miles of gas pipeline, a 30-year $274 million prepaid lease of a gas storage facility and certain gas marketing contracts. The purchase method of accounting was used to record the acquisition. According to APB Opinion No. 16 "Business Combinations" AEP recorded the assets acquired and liabilities assumed at their estimated fair values determined by independent appraisal or by Company's management based on information currently available and on current assumptions as to future operations. Based on a final purchase price allocation the excess of cost over fair value of the net assets acquired was approximately $153 million and is recorded as Goodwill. SFAS 142 "Goodwill and Other Intangible Assets" treats goodwill as a non-amortized, non-wasting asset effective January 1, 2002. Therefore, Goodwill was amortized for only seven months in 2001 on a straight-line basis over 30 years. The purchase method results in the assets, liabilities and earnings of the acquired operations being included in AEP's consolidated financial statements from the purchase date.
AEP also purchased the following assets or acquired the following businesses
from July 1, 2001 through December 31, 2001 for an aggregate total of $1,651
million:
o SWEPCo, an AEP subsidiary, purchased the Dolet Hills mining operations
and assumed the existing mine reclamation liabilities at its jointly
owned lignite reserves in Louisiana.
o Quaker Coal Company as part of a bankruptcy proceeding settlement. AEP
also assumed additional liabilities of approximately $58 million. The
acquisition includes property, coal reserves, mining operations and
royalty interests in Colorado, Kentucky, Ohio, Pennsylvania and West
Virginia. AEP continues to operate the mines and facilities which
employ over 800 individuals. See Note 13b "Asset Impairments and
Investment Value Losses".
o MEMCO Barge Line added 1,200 hopper barges and 30 towboats to AEP's
existing barging fleet. MEMCO's 450 employees operate the barge line.
MEMCO added major barging operations on the Mississippi and Ohio rivers
to AEP's barging operations on the Ohio and Kanawha rivers.
o U.K. Generation added 4,000 megawatts of coal-fired generation from
Fiddler's Ferry, a four-unit, 2,000-megawatt station on the River
Mersey in northwest England, approximately 200 miles from London and
Ferrybridge, a four-unit, 2,000-megawatt station on the River Aire in
northeast England, approximately 200 miles from London and related coal
stocks. See Note 13b "Asset Impairments and Investment Value Losses".
o A 20% equity interest in Caiua, a Brazilian electric operating company
which is a subsidiary of Vale. See Note 21, "Power and Distribution
Projects". AEP converted a total of $66 million on an existing loan and
accrued interest on that loan into Caiua equity. See Note 13b "Asset
Impairments and Investment Value Losses".
o Indian Mesa Wind Project consisting of 160 megawatts of wind
generation located near Fort Stockton, Texas.
o Acquired existing contracts and hired key staff from Enron's
London-based international coal trading group.
Regarding the 2002 and 2001 acquisitions, management has recorded the assets acquired and liabilities assumed at their estimated fair values in accordance with APB Opinion No. 16 and SFAS 141 as appropriate based on currently available information and on current assumptions as to future operations.
Dispositions
2002
In 2002, AEP completed a number of disposals of assets determined to be non-core:
Disposal of SEEBOARD
On June 18, 2002, AEP, through a wholly owned subsidiary, entered into an
agreement, subject to European Union (EU) approval, to sell its consolidated
subsidiary SEEBOARD, a U.K. electricity supply and distribution company. EU
approval was received July 25, 2002 and the sale was completed on July 29, 2002.
AEP received approximately $941 million in net cash from the sale, subject to a
working capital true up, and the buyer assumed SEEBOARD debt of approximately
$1.12 billion, resulting in a net loss of $345 million at June 30, 2002. In
accordance with SFAS 144 the results of operations of SEEBOARD have been
classified as Discontinued Operations for all years presented. A net loss of $22
million was classified as Discontinued Operations in the second quarter of 2002.
The remaining $323 million of the net loss has been classified as a transitional
impairment loss from the adoption of SFAS 142 (see Notes 2 and 3) and has been
reported as a Cumulative Effect of Accounting Change retroactive to January 1,
2002. A $59 million reduction of the net loss was recognized in the second half
of 2002 to reflect changes in exchange rates to closing, settlement of working
capital true-up and selling expenses. The net total loss recognized on the
disposal of SEEBOARD was $286 million. Proceeds from the sale of SEEBOARD were
used to pay down bank facilities and short-term debt.
The assets and liabilities of SEEBOARD were aggregated on AEP's Consolidated Balance Sheets as Assets of Discontinued Operations and Liabilities of Discontinued Operations as of December 31, 2001. The major classes of SEEBOARD's assets and liabilities of discontinued operations were:
December 31,
2001
-----------
(in millions)
Assets:
Current Assets $ 324
Plant,Property and Equipment, Net 1,283
Goodwill 1,129
Other Assets 96
------
Total Assets of Discontinued
Operations $2,832
Liabilities:
Current Liabilities $ 752
Long-term Debt 701
Deferred Income
Taxes 268
Other Liabilities 77
------
Total Liabilities of Discontinued
Operations $1,798
|
Disposal of CitiPower
On July 19, 2002, AEP, through a wholly owned subsidiary entered into an
agreement to sell CitiPower, a retail electricity and gas supply and
distribution subsidiary in Australia. AEP completed the sale on August 30, 2002
and received net cash of approximately $175 million and the buyer assumed
CitiPower debt of approximately $674 million. AEP recorded a net charge totaling
$125 million as of June 30, 2002. The charge included an impairment loss of $98
million on the remaining carrying value of an intangible asset related to a
distribution license for CitiPower. The remaining $27 million of net loss was
classified as a transitional goodwill impairment loss from the adoption of SFAS
142 (see Notes 2 and 3) and was recorded as a Cumulative Effect of Accounting
Change retroactive to January 1, 2002.
The loss on the sale of CitiPower increased $24 million to $149 million in the second half of 2002 based on actual closing amounts and exchange rates.
CitiPower's results of operations have been reclassified as Discontinued Operations in accordance with SFAS 144. The assets and liabilities of CitiPower have been aggregated on the December 31, 2001, AEP balance sheet as Assets of Discontinued Operations and Liabilities of Discontinued Operations. The major classes of CitiPower's assets and liabilities of discontinued operations are:
December 31, 2001
-------------------
(in millions)
Assets:
Current Assets $ 138
Plant, Property and
Equipment, Net 495
Goodwill/Intangibles 466
Other Assets 23
------
Total Assets of
Discontinued
Operations $1,122
======
Liabilities:
Current Liabilities $ 83
Long-term Debt 612
Deferred Income Taxes 55
Other Liabilities 34
----
Total Liabilities of Discontinued
Operations
$784
|
Total revenues and pretax profit (loss) of the discontinued operations of SEEBOARD and CitiPower were:
SEEBOARD
(in millions)
Revenues:
12 months ended
12/31/02 $ 694
12 months ended
12/31/01 1,451
12 months ended
12/31/00 1,596
Pretax Profit:
12 months ended
12/31/02 $ 180
12 months ended
12/31/01 104
12 months ended
12/31/00 91
CitiPower
(in millions)
Revenues:
12 months ended
12/31/02 $ 204
12 months ended
12/31/01 350
12 months ended
12/31/00 338
Pretax Profit (Loss):
12 months ended
12/31/02 $ (190)
12 months ended
12/31/01 (4)
12 months ended
12/31/00 20
|
Disposition of Texas REPs
In April 2002, AEP reached a definitive agreement, subject to regulatory approval, to sell two of its Texas retail electric providers (REPs) to Centrica, a provider of retail energy and other consumer services. PUCT regulatory approval for the sale was obtained in December 2002. On December 23, 2002 AEP sold to Centrica, the general partner interests and the limited partner interests in Mutual Energy CPL L.P. and Mutual Energy WTU L.P. for a base purchase price paid in cash at closing and certain additional payments, including a net working capital payment. Centrica paid a base purchase price of $145.5 million which was based on a fair market value per customer established by an independent appraiser and an agreed customer count. AEP recorded a net gain totaling $83.7 million in Other Income. AEP (through TCC and TNC) will provide Centrica with a power supply contract for the two REPs and back-office services related to these customers for a two-year period. In addition, AEP retained the right to share in earnings from the two REPs above a threshold amount through 2006 in the event the Texas retail market develops increased earnings opportunities. Under the Texas Legislation, REPs are subject to a clawback liability if customer change does not attain thresholds required by the legislation. AEP is responsible for a portion of such liability, if any, for the period it operated the REPs in the Texas competitive retail market (January 1, 2002 through December 23, 2002). In addition, AEP retained responsibility for regulatory obligations arising out of operations before closing. AEP's wholly-owned subsidiary Mutual Energy Service Company LLC (MESC) received an up-front payment of approximately $30 million from Centrica associated with the back-office service agreement, and MESC deferred its right to receive payment of an additional amount of approximately $9 million to secure certain contingent obligations. These prepaid service revenues were deferred on the books of MESC to be amortized over the two-year term of the back office service agreement.
2001
In March 2001, CSWE, a subsidiary company, completed the sale of Frontera, a generating plant that the FERC required to be divested in connection with the merger of AEP and CSW. The sale proceeds were $265 million and resulted in an after tax gain of $46 million.
In July 2001, AEP, through a wholly owned subsidiary, sold its 50% interest in a 120-megawatt generating plant located in Mexico. The sale resulted in an after tax gain of approximately $11 million.
In July 2001, OPCo, an AEP subsidiary, sold coal mines in Ohio and West Virginia and agreed to purchase approximately 34 million tons of coal from the purchaser of the mines through 2008. The sale is expected to have a nominal impact on the results of operations and cash flows of OPCo and AEP.
In December 2001, AEP completed the sale of its ownership interests in the Virginia and West Virginia PCS (personal communications services) Alliances for stock, resulting in an after tax gain of approximately $7 million. During 2002, due to decreasing market value of the shares, AEP reduced the value of them to zero.
2000
In December 2000, AEP, through a wholly owned subsidiary, committed to negotiate a sale of its 50% investment in Yorkshire, a U.K. electricity supply and distribution company. As a result a $43 million writedown ($30 million after tax) was recorded in the fourth quarter of 2000 to reflect the net loss from the expected sale in the first quarter of 2001. The writedown is included in Other Income on AEP's Consolidated Statements of Operations. On February 26, 2001 an agreement to sell the Company's 50% interest in Yorkshire was signed. On April 2, 2001, following the approval of the buyer's shareholders, the sale was completed without further impact on AEP's consolidated earnings.
In December 2000, CSW International, a subsidiary company sold its investment in a Chilean electric company for $67 million. A net loss on the sale of $13 million ($9 million after tax) is included in Other Income, and includes $26 million ($17 million net of tax) of losses from foreign exchange rate changes that were previously reflected in Accumulated Other Comprehensive Income. In the second quarter of 2000 AEP management determined that the then existing decline in market value of the shares was other than temporary. As a result the investment was written down by $33 million ($21 million after tax) in June 2000. The total loss from both the write down of the Chilean investment to market in the second quarter and from the sale in the fourth quarter was $46 million ($30 million net of tax).
Discontinued Operations
The operations shown below, affecting AEP, were discontinued or classified as held for sale in 2002. Results of operations of these businesses have been reclassified as shown in the following table:
SEE-BOARD CitiPower Pushan Eastex Total
--------- --------- ------ ------ -----
(in millions)
2002 Revenue $ 694 $204 $57 $ 73 $1,028
2001 Revenue 1,451 350 57 - 1,858
2000 Revenue 1,596 338 57 - 1,991
2002 Earnings (Loss)
After Tax 96 (123) (7) (156) (190)
2001 Earnings
(Loss) After Tax 88 (6) 4 - 86
2000 Earnings (Loss)
After Tax 99 17 7 (1) 122
|
13. Asset Impairments and Investment Value Losses:
In 2002 AEP recorded pre-tax impairments of assets (including goodwill) and investments totaling $1.426 billion (consisting of approximately $866.6 million related to Asset Impairments, $321.1 million related to Investment Value and Other Impairment Losses, and $238.7 million related to Discontinued Operations) that reflected downturns in energy trading markets, projected long-term decreases in electricity prices, and other factors. These impairments exclude the transitional impairment loss from adoption of SFAS142 (see Notes 2 and 3). The categories of impairments included:
2002 Pre-Tax Estimated Loss
----
(in millions)
Asset Impairments Held for Sale $ 483.1
Asset Impairments Held and Used 651.4
Investment Value Losses 291.9
----------
Total $1,426.4
========
|
a. Assets Held for Sale
In 2002, AEP (and its registrant subsidiaries, as applicable) recorded the following estimated loss on disposal of assets (including Goodwill) held for sale:
2002 Pre-Tax
Assets Estimated Loss
Held for Sale on Disposal Business Registrant
------------- ----------- -------- ----------
(in millions)
Eastex $218.7 Wholesale AEP
Pushan Power 20.0 Other AEP
-------
Total Impairment Losses
Included in Discontinued
Operations $238.7
Telecommunication - AEPC/C3 $158.5 Other AEP
Newgulf Facility 11.8 Wholesale AEP
Nordic Trading 5.3 Wholesale AEP
Excess Equipment 23.9 Wholesale AEP
Excess Real Estate 15.7 Wholesale AEP
--------
Total Included in
Asset Impairment Losses $215.2
Telecommunications - AFN $ 13.8 Other AEP
Water Heater AEP, APCo, CSPCo,
Program 3.2 Wholesale I&M, KPCo and OPCo
Gas Power Systems 12.2 Wholesale AEP
--------
Total Included in
Investment Value
and Other Impairment
Losses $ 29.2
-------
Total-All Held for Sale
Losses $483.1
======
|
Eastex
In 1998, CSW began construction of a natural gas-fired cogeneration facility
(Eastex) located near Longview, Texas and commercial operations commenced in
December 2001. In June 2002, AEP requested that the FERC allow it to modify the
FERC Merger Order and substitute Eastex as a required divestiture under the
order, due to the fact that the agreed upon market-power related divestiture of
a plant in Oklahoma was no longer feasible. The FERC approved the request at the
end of September 2002. Subsequently, in the fourth quarter of 2002 AEP solicited
bids for the sale of Eastex and several interested buyers were identified by
December 2002. A sale of assets is expected to be completed by the end of 2003
with an estimated pre-tax loss on sale of $218.7 million included in
Discontinued Operations in AEP's Consolidated Statements of Operations. The
estimated loss was based on the estimated fair value of the facility and
indicative bids by interested buyers.
Results of operations of Eastex have been reclassified as Discontinued Operations in accordance with SFAS 144 as shown in Note 12. The assets and liabilities of Eastex have been included on AEP's Consolidated Balance Sheets as held for sale. The major classes of assets and liabilities held for sale are:
2002 2001
---- ----
(in millions)
Assets:
Current Assets $15 $ -
Property, Plant and Equipment, Net - 217
Other Assets - 3
------ ------
Total Assets Held for Sale $15 $220
=== ====
Liabilities:
Current Liabilities $ 8 $ 5
Other Liabilities 4 1
----- ------
Total Liabilities Held for Sale $12 $ 6
=== ======
|
Pushan Power Plant
In the fourth quarter of 2002, AEP began active negotiations to sell its
interest in the Pushan Power Plant (Pushan) in Nanyang, China to the minority
interest partner. Negotiations are expected to be completed by the second
quarter of 2003 with an estimated pre-tax loss on disposal of $20.0 million,
based on an indicative price expression. The estimated pre-tax loss on disposal
is classified in Discontinued Operations in AEP's Consolidated Statements of
Operations.
Results of operations of Pushan have been reclassified as Discontinued Operations in accordance with SFAS 144 as discussed in Note 12. The assets and liabilities of Pushan have been classified on AEP's Consolidated Balance Sheets as held for sale. The major classes of assets and liabilities held for sale are:
2002 2001
---- ----
(in millions)
Assets:
Current Assets $ 19 $ 17
Property, Plant and Equipment, Net 132 161
----- -----
Total Assets Held for Sale $151 $178
==== ====
Liabilities:
Current Liabilities $ 28 $ 27
Long-term Debt 25 30
Other Liabilities 26 24
------ -----
Total Liabilities Held for Sale $ 79 $ 81
===== =====
|
Telecommunications
AEP had developed businesses to provide telecommunication services to businesses
and to other telecommunication companies through broadband fiber optic networks
operated in conjunction with AEP's electric transmission and distribution lines.
The businesses included AEP Communications, LLC (AEPC), C3 Communications, Inc.
(C3), and a 50% share of AFN Networks, LLC (AFN), a joint venture. Due to the
difficult economic conditions in these businesses and the overall
telecommunications industry, and other operating problems, the AEP Board
approved in December 2002 a plan to cease operations of these businesses. AEP
took steps to market the assets of the businesses to potential interested buyers
in the fourth quarter of 2002. A number of potential buyers have made offers for
the assets of C3. Potential buyers have indicated interest in the assets of AFN.
A formal offering of the assets of AEPC will begin early in 2003. The complete
sale of all telecommunication assets is expected to be completed by the end of
2003 with an estimated pre-tax impairment loss of $158.5 million (related to
AEPC and C3) classified in Asset Impairments in AEP's Consolidated Statements of
Operations and an estimated pre-tax loss in value of the investment in AFN of
$13.8 million classified in Investment Value and Other Impairment Losses in
AEP's Consolidated Statements of Operations. The estimated losses are based on
indicative bids by potential buyers.
$6 million and $182 million of Property, Plant and Equipment, net of accumulated depreciation of the telecommunication businesses have been classified on AEP's Consolidated Balance Sheets as held for sale in 2002 and 2001, respectively.
Newgulf Facility
In 1995, CSW purchased an 85 MW gas-fired peaking electrical generation facility
located near Newgulf, Texas (Newgulf). In October 2002 AEP began negotiations
with a likely buyer of the facility. A sale is now expected to be completed by
the end of 2003 with an estimated pre-tax loss on sale of $11.8 million based on
an indicative bid by the likely buyer. The estimated loss on disposal is
classified in Asset Impairments on AEP's Consolidated Statements of Operations.
Newgulf's Property, Plant and Equipment, net of accumulated depreciation, of $6
million in 2002 and $17 million in 2001 has been classified on AEP's
Consolidated Balance Sheets as held for sale.
Nordic Trading
In October 2002 AEP announced that its ongoing energy trading operations would
be centered around its generation assets. As a result, AEP took steps to exit
its coal, gas, and electricity trading activities in Europe, except for those
activities necessary to support the U.K. Generation operations. The Nordic
Trading business acquired earlier in 2002 (see Note 12) was made available for
sale to potential buyers. The estimated pre-tax loss on disposal in 2002 of $5.3
million, consisted of impairment of goodwill of $4.0 million (see Note 3) and
impairment of assets of $1.3 million. The estimated loss of $5.3 million is
included in Asset Impairments on AEP's Consolidated Statements of Operations.
Management's determination of a zero fair value was based on discussions with a
potential buyer. There are no assets and liabilities of Nordic Trading to be
classified on AEP's Consolidated Balance Sheets as held for sale.
Excess Equipment
In November 2002, as a result of a cancelled development project, AEP obtained
title to a surplus gas turbine generator. AEP has been unsuccessful in finding
potential buyers of the unit, including its own internal generation operators,
due to an over-supply of generation equipment available for sale. Sale of the
turbine is now projected before the end of 2003 with an estimated 2002 pre-tax
loss on disposal of $23.9 million, based on market prices of similar equipment.
The loss is included in Asset Impairments on AEP's Consolidated Statements of
Operations. The Other asset of $12 million in 2002 and $31 million in 2001 has
been classified on AEP's Consolidated Balance Sheets as held for sale.
Excess Real Estate
In the fourth quarter of 2002, AEP began to market an under-utilized office
building in Dallas, TX obtained through the merger with CSW. One prospective
buyer has executed an option to purchase the building. Sale of the facility is
projected by second quarter 2003 and an estimated 2002 pre-tax loss on disposal
of $15.7 million has been recorded, based on the option sale price. The
estimated loss is included in Asset Impairments on AEP's Consolidated Statements
of Operations. The Property asset of $18 million in 2002 and $36 million in 2001
has been classified on AEP's Consolidated Balance Sheets as held for sale.
Water Heater Program
AEP, APCo, CSPCo, I&M, KPCo and OPCo operated a program to lease electric water
heaters to residential and commercial customers until a decision was reached in
the fourth quarter of 2002 to discontinue the program and to offer the assets
for sale. Negotiations are underway with a qualified buyer, and sale of the
assets is projected by the end of the first quarter of 2003. AEP's estimated
2002 pre-tax loss on disposal of $3.20 million ($50 thousand for APCo, $615
thousand for CSPCo, $643 thousand for I&M, $11 thousand for KPCo, $1.757 million
for OPCo and $126 thousand for other AEP non-registrant subsidiaries) was based
on the expected contract sales price. The loss is included in Investment Value
and Other Impairment Losses on AEP's Consolidated Statements of Operations and
in Nonoperating Expenses on the statements of income of the registrant
subsidiaries. The assets and liabilities have been classified on AEP's
Consolidated Balance Sheets as held for sale. The major classes of assets held
for sale are:
2002 2001
---- ----
(in millions)
Assets:
Current Assets $ 1 $ 2
Property, Plant and Equipment, Net 38 48
---- ----
Total Assets Held for Sale $39 $50
=== ===
|
Gas Power Systems
AEP acquired in 2001 a 75% interest in a startup company seeking to develop
low-cost peaking generator sets powered by surplus jet turbine engines. The
first quarter of 2002, AEP recognized a goodwill impairment loss of $12.2
million due to technological and operating problems (See Note 3). The loss was
recorded in Investment Value and Other Impairment Losses on AEP's Consolidated
Statements of Operations. The fair values of the remaining assets and
liabilities were excluded from AEP's Consolidated Balance Sheets as held for
sale, as the impact was insignificant. AEP's remaining interest was sold in
January 2003.
b. Assets Held and Used
In 2002, AEP recorded the following impairments related to assets (including Goodwill) held and used to Asset Impairments on AEP's Consolidated Statements of Operations:
Assets Business
Held and Used 2002 Pre-Tax Loss Segment Registrant
------------- ------------------ ------- ----------
(in millions)
U.K. Generation $548.7 Wholesale AEP
AEP Coal 59.9 Wholesale AEP
Texas Plants 38.1 Wholesale AEP and TNC
Ft. Davis Wind Farm
4.7 Wholesale AEP and TNC
-------
Total - ALL
Held and Used
Losses $51.4
=====
|
U.K. Generation Plants
In December 2001, AEP acquired two coal-fired generation plants (U.K.
Generation) in the U.K. for a cash payment of $942.3 million and assumption of
certain liabilities. Subsequently and continuing through 2002, wholesale U.K.
electric power prices declined sharply as a result of domestic over-capacity and
static demand. External industry forecasts and AEP's own projections made during
the fourth quarter of 2002 indicate that this situation may extend many years
into the future. As a result, the U.K. Generation fixed asset carrying value at
year-end 2002 was substantially impaired. A December 2002 probability-weighted
discounted cash flow analysis of the fair value of our U.K. Generation indicated
a 2002 pre-tax impairment loss of $548.7 million, including a goodwill
impairment of $166.1 million as discussed in Note 3. The cash flow analysis used
a discount rate of 6% over the remaining life of the assets and reflected
assumptions for future electricity prices and plant operating costs. This
impairment loss is included in Asset Impairments on AEP's Consolidated
Statements of Operations.
AEP Coal
In October 2001, AEP acquired out of bankruptcy certain assets and assumed
certain liabilities of nineteen coal mine companies formerly known as "Quaker
Coal" and re-identified as "AEP Coal". During 2002 the coal operations suffered
a decline in forward prices and adverse mining factors that culminated in the
fourth quarter of 2002 and significantly reduced mine productivity and revenue.
Based on an extensive review of economically accessible reserves and other
factors, future mine productivity and production is expected to continue to be
below historical levels. In December 2002, a probability-weighted discounted
cash flow analysis of fair value of the mines was performed which indicated a
2002 pre-tax impairment loss of $59.9 million including a goodwill impairment of
$3.6 million as discussed in Note 3. This impairment loss is included in Asset
Impairments on AEP's Consolidated Statements of Operations.
Texas Plants
In September 2002, AEP proposed closing 16 gas-fired power plants in the ERCOT
control area of Texas (8 TNC plants and 8 TCC plants). ERCOT indicated that it
may designate some of those plants as "reliability must run" (RMR) status. In
October ERCOT designated seven RMR plants (3 TNC plants and 4 TCC plants) and
approved AEP's plan to inactivate nine other plants (5 TNC plants and 4 TCC
plants). The process of moving the plants to inactive status took approximately
two months. Employees of the plants moved to inactive status (approximately 180)
were eligible for severance and outplacement services.
As a result of the decision to inactivate TNC plants, a write-down of utility assets of approximately $34.2 million (pre-tax) was recorded in Asset Impairments expense during the third quarter 2002 on AEP's and TNC's Statements of Operations. The decision to inactivate the TCC plants resulted in a write-down of utility assets of approximately $95.6 million (pre-tax), which was deferred and recorded in Regulatory Assets during the third quarter 2002 in AEP's Consolidated Balance Sheets (in Regulatory Assets Designated For or Subject to Securitization on TCC's Consolidated Balance Sheets).
During the fourth quarter 2002, evaluations continued as to whether assets remaining at the inactivated plants, including materials, supplies and fuel oil inventories, could be utilized elsewhere within the AEP System. As a result of such evaluations, TNC recorded an additional asset impairment charge to Asset Impairments expense of $3.9 million (pre-tax) in the fourth quarter 2002. In addition TNC recorded related inventory write-downs of $2.6 million [$1.2 million in Fuel and Purchased Energy: Electricity on AEP (Fuel Expense on TNC) and $1.4 million in Maintenance and Other Operation expense on AEP (Other Operation on TNC)]. Similarly, TCC recorded an additional asset impairment write-down of $6.7 million (pre-tax), which was deferred and recorded in Regulatory Assets on AEP (in Regulatory Assets Designated For or Subject to Securitization on TCC's Consolidated Balance Sheets) in the fourth quarter 2002. TCC also recorded related inventory write-downs of $14.9 million which was deferred and recorded in Regulatory Assets on AEP (in Regulatory Assets Designated For or Subject to Securitization on TCC's Consolidated Balance Sheets) in the fourth quarter 2002.
The total Texas plant asset impairment of $38.1 million in 2002 (all related to TNC) is included in Asset Impairments on AEP's and TNC's Consolidated Statements of Operations.
RMR plants are required to ensure the reliability of the power grid, even if electricity from those plants is not required to meet market needs. ERCOT and AEP negotiated interim contracts for the seven RMR plants through December 2003, however, ERCOT has the right to terminate the plants from RMR status upon 90 days written notice.
In December 2002, TCC filed a plan of divestiture with the PUCT proposing to sell all of its power generation assets, including the eight gas-fired generating plants that were either inactivated or designated as RMR status. See Texas Restructuring section of the "Customer Choice and Industry Restructuring" Note 8 for further discussion of the divestiture plan and anticipated timeline.
Ft. Davis Wind Farm
In the 1990's, CSW developed a 6 MW facility wind energy project located on a
lease site near Ft. Davis, Texas. In the fourth quarter of 2002 AEP engineering
staff determined that operation of the facility was no longer technically
feasible and the lease of the underlying site should not be renewed. Dismantling
of the facility will be complete by the end of 2003 with an estimated 2002
pre-tax loss on abandonment of $4.7 million. The loss was recorded in Asset
Impairments on AEP's Consolidated Statements of Operations and TNC's Statements
of Operations. The facility will continue to be classified as held and used
until disposal is complete.
c. Investment Values
In 2002, AEP recorded the following declines in fair value on investments accounted for under APB 18 that were considered to be other than temporarily impaired as shown in the table below:
Investment Value
Impairment 2002 Pre-Tax Business
Loss Items Estimated Loss Segment Registrant
---------- -------------- ------- ----------
(in millions)
Grupo Rede Investment - Brazil $217.0 Other AEP
South Coast Power 63.2 Other AEP
Misc. Technology Investments 11.7 Other AEP
------
Total $291.9
|
Grupo Rede Investment
In December 2002, AEP recorded an other than temporary impairment totaling
$141.0 million ($217.0 million net of federal income tax benefit of $76.0
million) of its 44% equity investment in Vale and its 20% equity interest in
Caiua, both Brazilian electric operating companies (referred to as Grupo Rede).
This amount is included in Investment Value and Other Impairment Losses on AEP's
Consolidated Statements of Operations. As of September 30, 2002, AEP had not
recognized its cumulative equity share of operating and foreign currency
translation losses of approximately $88 million and $105 million, respectively,
due to the existence of a put option that permits AEP to require Grupo Rede to
purchase our equity at a minimum price equal to the U.S. dollar equivalent of
the original purchase price. In January 2002 AEP evaluated through an
independent credit assessment the ability of Grupo Rede to fulfill its
responsibilities under the put option and concluded that the carrying value of
the original investment was reasonable.
During 2002, there has been a continuing decline in the Brazilian power industry and the value of the local currency. Events in the fourth quarter of 2002 led us to change our view that Grupo Rede would be able to fulfill its responsibilities under the put option. These events included two downgrades of Caiua debt by Moody's, resulting in a rating of Caa1. Caiua is an intermediate holding company which owns substantially all of the utility companies in the Grupo Rede system. The downgrading of Caiua's credit ratings to a level well below investment grade casts significant doubt on the ability of Grupo Rede to honor the put option. Grupo Rede is in the process of restructuring some of its debt s, and as a condition for participating in the restructuring, during November 2002 a creditor of Grupo Rede requested that AEP agree not to exercise the put option prior to March 31, 2007. AEP agreed and in exchange received an extension of the put option from the previous end date of 2009 through 2019. Based on the factors noted above, AEP could no longer reasonably believe that our investment could be recovered, resulting in the recording of the impairment.
South Coast Power Investment
South Coast Power is a 50% owned joint venture that was formed in 1996 to build
and operate a merchant closed-cycle gas turbine generator at Shoreham, U.K..
South Coast Power is subject to the same adverse wholesale electric power rates
described for U.K. Generation above. A December 2002 projected cash flow
estimate of the fair value of the investment indicated a 2002 pre-tax other than
temporary impairment of the equity interest (which included the fair value of
supply contracts held by South Coast Power and accounted for in accordance with
SFAS 133) in the amount of $63.2 million. This loss of investment value is
included in Investment Value and Other Impairment Losses on AEP's Consolidated
Statements of Operations.
Technology Investments
AEP previously made investments totaling $11.7 million in four early-stage or
startup technologies involving pollution control and procurement. An analysis in
December 2002 of the viability of the underlying technologies and the projected
performance of the investee companies indicated that the investments were
unlikely to be recovered, and an other than temporary impairment of the entire
amount of the equity interest under APB 18 was recorded. The loss of investment
value is included in Investment Value and Other Impairment Losses on AEP's
Consolidated Statements of Operations.
14. Benefit Plans:
Pension and Other Postretirement Benefits
In the U.S. AEP sponsors two qualified pension plans and two nonqualified pension plans. Substantially all employees in the U.S. are covered by either one qualified plan or both a qualified and a nonqualified pension plan. Other postretirement benefit (OPEB) plans are sponsored by the AEP System to provide medical and death benefits for retired employees in the U.S.
AEP also has a foreign pension plan for employees of AEP Energy Services U.K. Generation Limited (Genco) in the U.K. Genco employees participate in their existing pension plan acquired as part of AEP's purchase of two generation plants in the U.K. in December 2001.
The following tables provide a reconciliation of the changes in the plans' benefit obligations and fair value of assets over the two-year period ending December 31, 2002, and a statement of the funded status as of December 31 for both years:
U.S. U.S.
Pension Plans OPEB Plans
------------- ----------
2002 2001 2002 2001
---- ---- ---- ----
(in millions)
Reconciliation of Benefit
Obligation:
Obligation at January 1 $3,292 $3,161 $ 1,645 $1,668
Service Cost 72 69 34 30
Interest Cost 241 232 114 114
Participant Contributions - - 13 8
Plan Amendments (2) - - 7 (a)
Actuarial (Gain) Loss 258 121 152 192
Divestitures - - - (287) (b)
Benefit Payments (278) (291) (81) (88)
Curtailments - - - 1
------ ------ ------- ------
Obligation at December 31 $3,583 $3,292 $ 1,877 $1,645
====== ====== ======= ======
Reconciliation of Fair Value
of Plan Assets:
Fair Value of Plan Assets at
January 1 $3,438 $3,911 $ 711 $ 704
Actual Return on Plan Assets (371) (182) (57) (31)
Company Contributions 6 - 137 118
Participant Contributions - - 13 8
Benefit Payments (278) (291) (81) (88)
------ ------ ------- ------
Fair Value of Plan Assets at
December 31 $2,795 $3,438 $ 723 $ 711
====== ====== ======= ======
Funded Status:
Funded Status at December 31 $ (788) $ 146 $(1,154) $ (934)
Unrecognized Net Transition
(Asset) Obligation (7) (15) 233 263
Unrecognized Prior-Service Cost (13) (12) 6 7
Unrecognized Actuarial
(Gain) Loss 1,020 35 896 649
------ ------ ------- ------
Prepaid Benefit (Accrued
Liability) $ 212 $ 154 $ (19) $ (15)
====== ====== ======= ======
|
(a) Related to the purchase of Houston Pipe Line Company and MEMCO Barge Line.
(b) Related to the sale of Central Ohio Coal Company, Southern Ohio Coal Company
and Windsor Coal Company.
The following table provides the amounts for prepaid benefit costs and accrued benefit liability recognized in the Consolidated Balance Sheets as of December 31 of both years. The amounts for additional minimum liability, intangible asset and Accumulated Other Comprehensive Income for 2001 and 2002 were recorded in 2002.
U.S. U.S.
Pension Plans OPEB Plans
------------- ----------
2002 2001 2002 2001
---- ---- ---- ----
(in millions)
Prepaid Benefit Costs $ 255 $ 205 $ - $ 1
Accrued Benefit Liability (44) (51) (19) (16)
Additional Minimum Liability (944) (15) N/A N/A
Intangible Asset 45 9 N/A N/A
Accumulated Other
Comprehensive Income 900 6 N/A N/A
----- ----- ---- ------
Net Asset (Liability) $ 212 $ 154 $(19) $ (15)
===== ===== ==== =====
Other Comprehensive (Income)
Expense Attributable to
Change in Additional Pension
Liability Recognition $ 894 $(4) N/A N/A
===== === ==== ======
|
N/A = Not Applicable
The value of our qualified plans' assets has decreased from $3.438 billion at December 31, 2001 to $2.795 billion at December 31, 2002. The qualified plans paid $272 million in benefits to plan participants during 2002 (nonqualified plans paid $6 million in benefits). The investment returns and declining discount rates have changed the status of our qualified plans from overfunded (plan assets in excess of projected benefit obligations) by $146 million at December 31, 2001 to an underfunded position (plan assets are less than projected benefit obligations) of $788 million at December 31, 2002. Due to the qualified plans currently being underfunded, the Company recorded a charge to Other Comprehensive Income (OCI) of $585 million, and a Deferred Income Tax Asset of $315 million, offset by a Minimum Pension Liability of $662 million and reduction to prepaid costs and intangible assets of $238 million. The charge to OCI does not affect earnings or cash flow. The OCI charge for each AEP subsidiary registrant is recorded in Minimum Pension Liability in the respective registrant's Consolidated Statements of Comprehensive Income. Also, because of the recent reductions in the funded status of our qualified plans, we expect to make cash contributions to our qualified plans of approximately $66 million in 2003 increasing to approximately $108 million per year by 2005.
The AEP System's qualified pension plans had accumulated benefit obligations in excess of plan assets of $661 million at December 31, 2002.
The AEP System's nonqualified pension plans had accumulated benefit obligations in excess of plan assets of $72 million at December 31, 2002 and $66 million at December 31, 2001. There are no assets in the nonqualified plans.
The AEP System's OPEB plans had accumulated benefit obligations in excess of plan assets of $1,154 million and $934 million at December 31, 2002 and 2001, respectively.
The Genco pension plan had $7 million and $10 million at December 31, 2002 and 2001, respectively, of accumulated benefit obligations in excess of plan assets.
The following table provides the components of AEP's net periodic benefit cost (credit) for the plans for fiscal years 2002, 2001 and 2000:
U.S. U.S.
Pension Plans OPEB Plans
------------- ----------
2002 2001 2000 2002 2001 2000
---- ---- ---- ---- ---- ----
(in millions)
Service Cost $ 72 $ 69 $ 60 $ 34 $ 30 $ 29
Interest Cost 241 232 227 114 114 106
Expected Return on Plan Assets (337) (338) (321) (62) (61) (57)
Amortization of
Transition (Asset) Obligation (9) (8) (8) 29 30 41
Amortization of Prior-service
Cost (1) - 13 - - -
Amortization of Net Actuarial
(Gain) Loss (10) (24) (39) 27 18 4
---- ----- ----- ---- ---- ----
Net Periodic Benefit Cost
(Credit) (44) (69) (68) 142 131 123
Curtailment Loss (a) - - - - 1 79
---- ----- ----- ---- ---- ----
Net Periodic Benefit
Cost (Credit) After
Curtailments $ (44) $ (69) $ (68) $142 $132 $202
===== ===== ===== ==== ==== ====
|
(a) Curtailment charges were recognized during 2000 for the shutdown of Central Ohio Coal Company, Southern Ohio Coal Company and Windsor Coal Company.
The following table provides the net periodic benefit cost (credit) for the plans by the following AEP registrant and other non-registrant subsidiaries for fiscal years 2002, 2001 and 2000:
U.S. U.S.
Pension Plans OPEB Plans
------------- ----------
2002 2001 2000 2002 2001 2000
---- ---- ---- ---- ---- ----
(in thousands)
APCo $ (9,988) $(13,645) $(14,047) $ 25,107 $ 22,810 $ 22,139
CSPCo (8,328) (10,624) (10,905) 11,494 10,328 9,643
I&M (4,206) (7,805) (8,565) 17,608 15,077 14,155
KPCo (1,406) (1,922) (2,075) 2,986 2,438 2,364
OPCo (11,360) (14,879) (15,041) 22,608 34,444 116,205
PSO (3,819) (2,480) (2,196) 8,436 6,187 4,277
SWEPCo (2,245) (3,051) (2,606) 8,371 6,399 4,152
TCC (4,786) (3,411) (2,986) 10,733 8,214 6,656
TNC (1,104) (1,644) (1,585) 4,798 3,729 2,929
Other Non-Registrant
Subsidiaries 3,657 (9,139) (7,546) 29,722 22,278 19,798
-------- -------- -------- -------- -------- --------
Total $(43,585) $(68,600) $(67,552) $141,863 $131,904 $202,318
======== ======== ======== ======== ======== ========
|
The weighted-average assumptions as of December 31, used in the measurement of AEP's benefit obligations are shown in the following tables:
U.S. U.S.
Pension Plans OPEB Plans
------------- ----------
2002 2001 2000 2002 2001 2000
---- ---- ---- ---- ---- ----
% % % % % %
Discount Rate 6.75 7.25 7.50 6.75 7.25 7.50
Expected Return on
Plan Assets 9.00 9.00 9.00 8.75 8.75 8.75
Rate of Compensation
Increase 3.7 3.7 3.2 N/A N/A N/A
|
In determining the discount rate in the calculation of future pension obligations we review the interest rates of long-term bonds that receive one of the two highest ratings given by a recognized rating agency. As a result of a decrease in this benchmark rate during 2002, we determined that a decrease in our discount rate from 7.25% at December 31, 2001 to 6.75% at December 31, 2002 was appropriate.
For OPEB measurement purposes, a 10% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2003. The rate was assumed to decrease gradually each year to a rate of 5% through 2008 and remain at that level thereafter.
Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans. A 1% change in assumed health care cost trend rates would have the following effects:
1% Increase 1% Decrease
----------- -----------
(in millions)
Effect on total service
and interest cost
components of net
periodic postretirement
health care benefit cost $ 21 $ (17)
Effect on the health care
component of the
accumulated
postretirement
benefit obligation 237 (193)
|
AEP Savings Plans
AEP sponsors various defined contribution retirement savings plans eligible to substantially all non-United Mine Workers of America (UMWA) U.S. employees. These plans include features under Section 401(k) of the Internal Revenue Code and provide for company matching contributions. Beginning in 2001, AEP's contributions to the two largest plans increased to 75 cents for every dollar of the first 6% of eligible employee compensation from the previous rate of 50 cents. The cost for contributions to these plans totaled $60.1 million in 2002, $55.6 million in 2001 and $36.8 million in 2000.
The following table provides the cost for contributions to the savings plans by the following AEP registrant and other non-registrant subsidiaries for fiscal years 2002, 2001 and 2000:
2002 2001 2000
---- ---- ----
(in thousands)
APCo $ 6,722 $7,031 $ 3,988
CSPCo 2,784 2,789 1,638
I&M 8,039 7,833 4,231
KPCo 1,043 1,016 544
OPCo 5,785 6,398 3,713
PSO 2,260 2,235 2,306
SWEPCo 2,765 2,776 2,880
TCC 3,054 3,046 3,161
TNC 1,574 1,558 1,708
Other Non-
Registrant
Subsidiaries 26,094 20,869 12,677
------- ------- ------
Total $60,120 $55,551 $36,846
======= ======= =======
|
On January 1, 2003, the two major AEP Savings Plans merged into a single plan.
Other UMWA Benefits
AEP and OPCo provide UMWA pension, health and welfare benefits for certain unionized mining employees, retirees, and their survivors who meet eligibility requirements. The benefits are administered by UMWA trustees and contributions are made to their trust funds. Contributions are expensed as paid as part of the cost of active mining operations and were not material in 2002, 2001 and 2000. In July 2001, OPCo sold certain coal mines in Ohio and West Virginia.
15. Stock-Based Compensation:
The American Electric Power System 2000 Long-Term Incentive Plan (the Plan) was approved by shareholders at AEP's annual meeting in 2000 and authorizes the use of 15,700,000 shares of AEP common stock for various types of stock-based compensation awards, including stock option awards, to key employees. The Plan was adopted in 2000.
Under the Plan, the exercise price of all stock option grants must equal or exceed the market price of AEP's common stock on the date of grant. AEP generally grants options that have a ten-year life and vest, subject to the participant's continued employment, in approximately equal 1/3 increments on January 1st following the first, second and third anniversary of the grant date.
CSW maintained a stock option plan prior to the merger with AEP in 2000. Effective with the merger, all CSW stock options outstanding were converted into AEP stock options at an exchange ratio of one CSW stock option for 0.6 of an AEP stock option. The exercise price for each CSW stock option was adjusted for the exchange ratio. Outstanding CSW stock options will continue in effect until all options are exercised, cancelled or expired. Under the CSW stock option plan, the option price was equal to the fair market value of the stock on the grant date. All CSW options fully vested upon the completion of the merger and expire 10 years after their original grant date.
A summary of AEP stock option transactions in fiscal periods 2002, 2001 and 2000 is as follows:
2002 2001 2000
---- ---- ----
Weighted Weighted Weighted
Average Average Average
Options Exercise Options Exercise Options Exercise
(in thousands) Price (in thousands) Price (in thousands) Price
Outstanding at
beginning of year 6,822 $37 6,610 $36 825 $40
Granted 2,923 $27 645 $45 6,046 $36
Exercised (600) $36 (216) $38 (26) $36
Forfeited (358) $41 (217) $37 (235) $39
----- ----- -----
Outstanding at
end of year 8,787 $34 6,822 $37 6,610 $36
===== ===== =====
Options exercisable
at end of year 2,481 $36 395 $43 588 $41
===== === ===
Weighted average Exercise price of options:
-Granted above Market Price $27 N/A N/A
-Granted at Market Price $27 $45 $36
|
The following table summarizes information about AEP stock options outstanding at December 31, 2002:
Range of Exercise Number Life in Exercise Prices Outstanding Years Price --------------------------------------------- $27.06-35.625 8,047,058 8.4 $ 32.54 40.69-49.00 739,483 7.1 44.84 --------------------------------------------- $27.06-49.00 8,786,541 8.3 $ 33.58 --------------------------------------------- |
Options Exercisable
Range of Exercise Number Weighted-Average Prices Outstanding Exercise Price $27.06-35.625 2,230,000 $35.51 40.69-49.00 251,327 43.66 --------------------------------------------- $27.06-49.00 2,481,327 $36.33 --------------------------------------------- |
If compensation expense for stock options had been determined based on the fair value at the grant date, AEP net income and earnings per share would have been the pro forma amounts shown in the following table:
-------------------------------------------------------------
2002 2001 2000
---- ---- ----
(in millions
except per share amounts)
Net (loss) income:
As reported $ (519) $ 971 $ 267
Pro forma (528) 959 264
Basic (loss) earnings per share:
As reported $(1.57) $3.01 $0.83
Pro forma (1.59) 2.98 0.82
Diluted (loss) earnings per share:
As reported $(1.57) $3.01 $0.83
Pro forma (1.59) 2.97 0.82
|
The proceeds received from exercised stock options are included in common stock and paid-in capital.
The pro forma amounts are not representative of the effects on reported net income for future years.
The fair value of each option award is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions used to estimate the fair value of AEP options granted:
2002 2001 2000
-------------------------------------------------------------
Risk Free Interest
Rate 3.53% 4.87% 5.02%
Expected Life 7 years 7 years 7 years
Expected Volatility 29.78% 28.40% 24.75%
Expected Dividend
Yield 6.15% 6.05% 6.02%
|
Weighted average fair value of options:
-Granted above
Market Price $4.58 N/A N/A
-Granted at Market Price
$4.37 $8.01 $5.50
---------------------------- ---------- ---------- ----------
|
16. Business Segments:
In 2000, AEP reported the following four business segments: Domestic Electric Utilities; Foreign Energy Delivery; Worldwide Energy Investments; and Other. With this structure, our regulated domestic utility companies were considered single, vertically-integrated units, and were reported collectively in the Domestic Electric Utilities segment.
In 2001 and 2002, we moved toward a goal of functionally and structurally separating our businesses. The ensuing realignment of our operations resulted in our current business segments, Wholesale, Energy Delivery and Other. The business activities of each of these segments are as follows:
Wholesale
o Generation of electricity for sale to retail and wholesale customers
o Gas pipeline and storage services
o Marketing and trading of electricity, gas, coal and other commodities
o Coal mining, bulk commodity barging operations and other energy
supply related businesses
Energy Delivery
o Domestic electricity transmission
o Domestic electricity distribution
Other
o Energy services
Segment results of operations for the twelve months ended December 31, 2002, 2001 and 2000 are shown below. These amounts include certain estimates and allocations where necessary.
We have used earnings before interest and income taxes (EBIT) as a measure of segment operating performance. The EBIT measure is total operating revenues net of total operating expenses and other income and deductions from income. It differs from net income in that it does not take into account interest expense, income taxes and the effect of discontinued operations, extraordinary items and the cumulative effect of a change in accounting principle. EBIT is believed to be a reasonable gauge of results of operations. By excluding interest expense and income taxes, EBIT does not give guidance regarding the demand of debt service or other interest requirements, or tax liabilities or taxation rates. The effects of interest expense and taxes on overall corporate performance can be seen in the Consolidated Statements of Operations. By excluding discontinued operations, extraordinary items, and the cumulative effect of changes in accounting principles, EBIT gives more focused guidance on segment operating performance.
Energy Reconciling AEP
Year Wholesale Delivery Other Adjustments Consolidated
---- --------- -------- ----- ----------- ------------
(in millions)
2002
Revenues from:
External unaffiliated
customers $10,988 $ 3,551 $ 16 $ - $14,555
Transactions with other
operating segments 2,314 20 46 (2,380) -
Segment EBIT 645 970 (549) - 1,066
Depreciation, depletion and
amortization expense 842 519 16 - 1,377
Total assets 22,622 11,624 248 247(a) 34,741
Investments in equity method
subsidiaries 115 - 57 - 172
Gross property additions 1,072 638 12 - 1,722
2001
Revenues from:
External unaffiliated
customers $ 9,297 $ 3,356 $ 114 $ - $12,767
Transactions with other
operating segments 2,708 20 1,155 (3,883) -
Segment EBIT 1,302 986 42 - 2,330
Depreciation, depletion and
amortization expense 597 632 14 - 1,243
Total assets 21,947 12,455 220 4,675(a) 39,297
Investments in equity method
subsidiaries 242 - 370 - 612
Gross property additions 610 844 200 - 1,654
2000
Revenues from:
External unaffiliated
customers $ 7,834 $3,174 $ 105 $ - $11,113
Transactions with other
operating segments 1,726 2 750 (2,478) -
Segment EBIT 686 1,017 89 - 1,792
Depreciation, depletion and
amortization expense 556 506 29 - 1,091
Total assets 24,172 14,876 2,625 4,960(a) 46,633
Investments in equity method
subsidiaries 140 - 296 - 436
Gross property additions 366 961 141 - 1,468
(a) Reconciling adjustments for Total Assets include Assets Held for Sale and/or
Assets of Discontinued Operations
|
Of the registrant operating company subsidiaries, all of the registrant subsidiaries except AEGCo have two business segments. The segment results for each of these subsidiaries are reported in the table below. AEGCo has one segment, a wholesale generation business. AEGCo's results of operations are reported in AEGCo's financial statements.
Twelve Months Ended Twelve Months Ended
December 31, 2002 December 31, 2001
----------------- -----------------
Segment Segment Total
Revenues EBIT Total Assets Revenues EBIT Assets
-------- ------- ------------ -------- ------- ------
(in thousands) (in thousands)
Wholesale Segment
APCo $1,220,381 $215,735 $2,586,966 $1,189,223 $164,844 $2,505,877
CSPCo 907,882 282,974 1,762,074 867,100 232,372 1,742,328
I&M 1,205,043 42,410 3,160,575 1,212,587 117,396 3,027,509
KPCo 246,629 6,568 591,655 247,842 4,935 507,516
OPCo 1,523,452 364,071 2,861,415 1,545,392 240,128 2,820,995
PSO 518,100 34,322 840,374 695,123 52,086 827,235
SWEPCo 736,484 70,547 1,082,251 768,322 82,409 1,127,331
TCC 1,135,946 395,060 3,117,447 1,265,655 303,966 2,847,743
TNC 377,387 (58,930) 376,308 387,422 7,930 371,031
Energy Delivery Segment
APCo $ 594,089 $217,360 $2,040,881 $ 595,036 $213,733 $1,976,908
CSPCo 492,278 63,071 991,166 483,219 130,503 980,060
I&M 321,721 170,342 1,426,616 314,410 111,206 1,366,553
KPCo 132,054 51,697 573,021 131,183 54,033 491,532
OPCo 589,673 71,225 1,595,617 552,713 118,261 1,573,078
PSO 275,547 69,543 936,316 261,877 79,787 921,676
SWEPCo 348,236 107,081 1,126,424 333,004 107,197 1,173,345
TCC 554,547 148,918 2,238,991 473,182 109,587 2,045,287
TNC 73,353 53,995 500,867 169,036 33,226 493,844
Registrant Subsidiaries
Company Total
APCo $1,814,470 $433,095 $4,627,847 $1,784,259 $378,577 $4,482,785
CSPCo 1,400,160 346,045 2,753,240 1,350,319 362,875 2,722,388
I&M 1,526,764 212,752 4,587,191 1,526,997 228,602 4,394,062
KPCo 378,683 58,265 1,164,676 379,025 58,968 999,048
OPCo 2,113,125 435,296 4,457,032 2,098,105 358,389 4,394,073
PSO 793,647 103,865 1,776,690 957,000 131,873 1,748,911
SWEPCo 1,084,720 177,628 2,208,675 1,101,326 189,606 2,300,676
TCC 1,690,493 543,978 5,356,438 1,738,837 413,553 4,893,030
TNC 450,740 (4,935) 877,175 556,458 41,156 864,875
|
Twelve Months Ended
December 31, 2000
-------------------
Revenues Segment EBIT Total Assets
-------- ------------ ------------
(in thousands)
Wholesale Segment
APCo $1,184,335 $154,525 $3,674,081
CSPCo 906,363 235,860 2,481,594
I&M 1,177,190 (146,297) 3,978,360
KPCo 268,529 22,379 759,228
OPCo 1,672,744 289,084 3,976,532
PSO 711,274 54,072 1,011,474
SWEPCo 773,324 27,055 1,302,611
TCC 1,291,588 273,650 3,182,202
TNC 394,860 13,910 466,539
Energy Delivery Segment
APCo $574,918 $191,560 $2,898,514
CSPCo 398,046 81,896 1,395,897
I&M 311,019 126,241 1,795,748
KPCo 121,346 49,770 735,315
OPCo 467,587 138,418 2,217,443
PSO 245,124 85,524 1,126,949
SWEPCo 344,950 129,842 1,355,778
TCC 478,814 136,069 2,285,499
TNC 176,204 50,201 620,965
Registrant Subsidiaries
Company Total
APCo $1,759,253 $346,085 $6,572,595
CSPCo 1,304,409 317,756 3,877,491
I&M 1,488,209 (20,056) 5,774,108
KPCo 389,875 72,149 1,494,543
OPCo 2,140,331 427,502 6,193,975
PSO 956,398 139,596 2,138,423
SWEPCo 1,118,274 156,897 2,658,389
TCC 1,770,402 409,719 5,467,701
TNC 571,064 64,111 1,087,504
|
17. Risk Management, Financial Instruments and Derivatives:
Risk Management
We are subject to market risks in our day to day operations. Our risk policies have been reviewed with the Board of Directors, approved by a Risk Executive Committee and are administered by the Chief Risk Officer. The Risk Executive Committee establishes risk limits, approves risk policies, assigns responsibilities regarding the oversight and management of risk and monitors risk levels. This committee receives daily, weekly, and monthly reports regarding compliance with policies, limits and procedures. The committee meets monthly and consists of the Chief Risk Officer, Chief Credit Officer, V.P. of Market Risk Oversight, and senior financial and operating managers.
The risks and related strategies that management can employ are:
Risk Description Strategy
---- ----------- --------
Price Risk Volatility in Trading and
commodity prices hedging
Interest Rate Risk Changes in
interest rates Hedging
Foreign Exchange Fluctuations in
Risk foreign currency Trading and
rates hedging
Credit Risk Non-performance Guarantees
on contracts and
with collateral
counterparties
|
We employ physical forward purchase and sale contracts, exchange futures and options, over-the-counter options, swaps, and other derivative contracts to offset price risk where appropriate. However, we engage in trading of electricity, gas and to a lesser degree other commodities and as a result we are subject to price risk. The amount of risk taken by the traders is controlled by the management of the trading operations and the Chief Risk Officer and his staff. If the risk from trading activities exceeds certain pre-determined limits, the positions are modified or hedged to reduce the risk to be within the limits unless specifically approved by the Risk Executive Committee.
AEP is exposed to risk from changes in the market prices of coal and natural gas used to generate electricity where generation is no longer regulated or where existing fuel clauses are suspended or frozen. The protection afforded by fuel clause recovery mechanisms has either been eliminated by the implementation of customer choice in Ohio (effective January 1, 2001) and in the ERCOT area of Texas (effective January 1, 2002) or frozen by a settlement agreement in Michigan, capped in Indiana and fixed (subject to future commission action) in West Virginia. To the extent all fuel supply for the generating units in these states is not under fixed price long-term contracts, AEP is subject to market price risk. AEP continues to be protected against market price changes by active fuel clauses in Arkansas, Kentucky, Louisiana, Oklahoma, Virginia and the SPP area of Texas.
We enter into currency and interest rate forward and swap transactions to hedge the currency and interest rate exposures created by commodity transactions. These transactions are marked-to-market to match the change in value in the transactions they hedge which are also marked-to-market. We employ forward contracts as cash flow hedges and swaps as cash flow or fair value hedges to mitigate changes in interest rates or fair values on Short-Term Debt and Long-term Debt when management deems it necessary. We do not hedge all interest rate risk.
We employ cash flow forward hedge contracts to lock-in prices on transactions denominated in foreign currencies where deemed necessary. International subsidiaries use currency swaps to hedge exchange rate fluctuations in debt denominated in foreign currencies. We do not hedge all foreign currency exposure.
Our open trading contracts, including structured transactions, are marked-to-market daily using the price model and price curve(s) corresponding to the instrument. Forwards, futures and swaps are generally valued by subtracting the contract price from the market price and then multiplying the difference by the contract volume and adjusting for net present value and other impacts. Significant estimates in valuing such contracts include forward price curves, volumes, seasonality, weather, and other factors.
Forwards and swaps are valued based on forward price curves which represent a series of projected prices at which transactions can be executed in the market. The forward price curve includes the market's expectations for prices of a delivered commodity at that future date. The forward price curve is developed from the market bid price, which is the highest price which traders are willing to pay for a contract, and the ask or offer price, which is the lowest price traders are willing to receive for selling a contract.
Option contracts, consisting primarily of options on forwards and spread options, are valued using models, which are variations on Black-Scholes option models. The market-related inputs are the interest rate curve, the underlying commodity forward price curve, the implied volatility curve and the implied correlation curve. Volatility and correlation prices may be quoted in the market. Significant estimates in valuing these contracts include forward price curves, volumes, and other volatilities.
Futures and options traded on exchanges (primarily oil and gas on NYMEX) are valued at the exchange price.
Electricity and gas markets in particular have primary trading hubs or delivery points/regions and less liquid secondary delivery points. In North American natural gas markets, the primary delivery points are generally traded from Henry Hub, Louisiana. The less liquid gas or power trading points may trade as a spread (based on transportation costs, constraints, etc.) from the nearest liquid trading hub. Also, some commodities trade more often and therefore are more liquid than others. For example, peak electricity is a more liquid product than off-peak electricity. Henry Hub gas trades in monthly blocks for up to 36 months and after that only trades in seasonal or calendar blocks. When this occurs, we use our best judgment to estimate the curve values. The value used will be based on various factors such as last trade price, recent price trend, product spreads, location spreads (including transportation costs), cross commodity spreads (e.g., heat rate conversion of gas to power), time spreads, cost of carry (e.g., cost of gas storage), marginal production cost, cost of new entrant capacity, and alternative fuel costs. Also, an energy commodity contract's price volatility generally increases as it approaches the delivery month. Spot price volatility (e.g., daily or hourly prices) can cause contract values to change substantially as open positions settle against spot prices. When a portion of a curve has been estimated for a period of time and market changes occur, assumptions are updated to align the curve to the market. All fair value amounts are net of adjustments for items such as credit quality of the counterparty (credit risk) and liquidity risk.
We also mark-to-market derivatives that are not trading contracts in accordance with generally accepted accounting principles. There may be unique models for these transactions, but the curves the Company inputs into the models are the same forward curves, which are described above.
We have developed independent controls to evaluate the reasonableness of our valuation models and curves. However, there are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. Therefore, there could be a significant favorable or adverse effect on future results of operations and cash flows if market prices at settlement differ from the price models and curves.
Results of Risk Management Activities
The amounts of net revenue margins (sales less purchases) in 2002, 2001, and 2000 for trading activities were:
2002 2001 2000
---- ---- ----
(in millions)
Net Revenue
Margins $53 $402 $233
|
The amounts of revenues recorded in 2002, 2001 and 2000 for the registrant subsidiaries were:
2002 2001 2000
---- ---- ----
(in thousands)
APCo $29,044 $ 52,871 $ 27,924
CSPCo 24,503 36,120 16,999
I&M 11,833 19,130 26,575
KPCo 3,801 6,150 10,704
OPCo 39,114 43,789 26,840
PSO (1,357) (7,345) 5,233
SWEPCo (4,999) 2,317 1,562
TCC (7,708) 10,500 (1,752)
TNC (1,098) 1,508 222
------- -------- --------
Total $93,133 $165,040 $114,307
======= ======== ========
|
The fair value of open trading contracts that are marked-to-market are based on management's best estimates using over-the-counter quotations and exchange prices for short-term open trading contracts, and internally developed price curves for open long-term trading contracts. The following table does not reflect derivative contracts designated as hedges or firm transmission rights contracts. As a result, the totals will not agree to the Consolidated Balance Sheets. The fair values of trading contracts at December 31 are:
2002 2001
------------------ -------------------
Fair Fair
Value Value
(in millions) (in millions)
Trading Assets
Electricity and Other
Physicals $ 846 $ 966
Financials 226 170
------ -------
Total Trading Assets $1,072 $ 1,136
====== =======
Gas
Physicals $ 105 $ 196
Financials 685 1,587
------ -------
Total Trading Assets $ 790 $ 1,783
====== =======
Trading Liabilities
Electricity and Other
Physicals $ (534) $ (760)
Financials (126) (87)
------ -------
Total Trading Liabilities $ (660) $ (847)
====== =======
Gas
Physicals $ (191) $ (38)
Financials (761) (1,586)
------ -------
Total Trading Liabilities $ (952) $(1,624)
====== =======
|
The fair values of trading contracts for the registrant subsidiaries at December 31 are:
2002 2001
----------------- -----------------
Fair Fair
Value Value
(in thousands) (in thousands)
APCo
Trading Assets
Electricity and Other
Physicals $ 168,687 $ 217,914
Financials 39,585 39,466
Trading Liabilities
Electricity and Other
Physicals $(100,045) $(164,624)
Financials (11,375) (17,055)
CSPCo
Trading Assets
Electricity and Other
Physicals $ 113,397 $ 133,425
Financials 26,611 24,206
Trading Liabilities
Electricity and Other
Physicals $ (67,244) $ (98,749)
Financials (7,647) (10,433)
|
I&M
Trading Assets
Electricity and Other
Physicals $ 121,706 $ 165,162
Financials 28,474 26,630
Trading Liabilities
Electricity and Other
Physicals $ (70,061) $(117,795)
Financials (9,258) (12,652)
2002 2001
---------------- ------------------
Fair Fair
Value Value
(in thousands) (in thousands)
KPCo
Trading Assets
Electricity and Other
Physicals $ 43,532 $ 53,651
Financials 10,216 9,732
Trading Liabilities
Electricity and Other
Physicals $ (25,815) $ (46,476)
Financials (2,935) (4,178)
OPCo
Trading Assets
Electricity and Other
Physicals $ 158,473 $ 180,989
Financials 35,304 32,997
Trading Liabilities
Electric and Other
Physicals $ (89,526) $(132,603)
Financials (10,145) (15,937)
|
PSO
Trading Assets
Electricity
Physicals $ 8,165 $ 47,613
Trading Liabilities
Electricity
Physicals $ (4,620) $ (45,179)
SWEPCo
Trading Assets
Electricity
Physicals $ 9,329 $ 54,647
Trading Liabilities
Electricity
Physicals $ (5,278) $ (51,747)
|
TCC
Trading Assets
Electricity
Physicals $ 26,752 $ 62,520
Trading Liabilities
Electricity
Physicals $ (21,136) $ (58,663)
Financials (202) -
|
TNC
Trading Assets
Electricity
Physicals $ 6,323 $ 18,567
Trading Liabilities
Electricity
Physicals $ (4,047) $ (17,652)
Financials (233) -
|
Credit Risk
AEP limits credit risk by extending unsecured credit to entities based on internal ratings. AEP uses Moody's Investor Service, Standard and Poor's and qualitative and quantitative data to independently assess the financial health of counterparties on an ongoing basis. This data, in conjunction with the ratings information, is used to determine appropriate risk parameters. AEP also requires cash deposits, letters of credit and parental/affiliate guarantees as security from counterparties depending upon credit quality in our normal course of business.
We trade electricity and gas contracts with numerous counterparties. Since our open energy trading contracts are valued based on changes in market prices of the related commodities, our exposures change daily. We believe that our credit and market exposures with any one counterparty are not material to our financial condition at December 31, 2002. At December 31, 2002, less than 7% of our exposure was below investment grade as expressed in terms of Net Mark to Market Assets. Net Mark to Market Assets represents the aggregate difference between the forward market price for the remaining term of the contract and the contractual price per counterparty. The following table approximates counterparty credit quality and exposure for AEP based on netting across AEP entities, commodities and instruments at December 31, 2002:
Futures,
Forward and
Counterparty Swap
Credit Quality Contracts Options Total
----------- ------- -----
(in millions)
AAA/Exchanges $ 26 $ 2 $ 28
AA 307 33 340
A 448 26 474
BBB 700 101 801
Below Investment
Grade 107 11 118
------- ------ ------
Total $1,588 $ 173 $1,761
====== ===== ======
|
We enter into transactions for electricity and natural gas as part of wholesale trading operations. Electricity and gas transactions are executed over-the-counter with counterparties or through brokers. Gas transactions are also executed through brokerage accounts with brokers who are registered with the U.S. Commodity Futures Trading Commission. Brokers and counterparties require cash or cash-related instruments to be deposited on these transactions as margin against open positions. The combined margin deposits at December 31, 2002 and 2001 were $109 million and $55 million. These margin accounts are restricted and therefore are not included in Cash and Cash Equivalents on the Consolidated Balance Sheets. AEP and its subsidiaries can be subject to further margin requirements should related commodity prices change.
The margin deposits at December 31, 2002 for the registrants were:
(in thousands)
APCo $1,010 CSPCo 673 I&M 727 KPCo 261 OPCo 1,400 PSO 91 SWEPCo 105 TCC 121 TNC 37 |
Financial Derivatives and Hedging
In the first quarter of 2001, AEP adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. AEP recorded a favorable transition adjustment to Accumulated Other Comprehensive Income of $27 million at January 1, 2001 in connection with the adoption of SFAS 133. Derivatives included in the transition adjustment are interest rate swaps, foreign currency swaps and commodity swaps, options and futures.
Most of the derivatives identified in the trans-ition adjustment were designated as cash flow hedges and relate to foreign operations.
Certain derivatives may be designated for accounting purposes as a hedge of either the fair value of an asset, liability, firm commitment, or a hedge of the variability of cash flows related to a variable-priced asset, liability, commitment, or forecasted trans-action. To qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be documented to include the risk management objective and strategy for use of the hedge instrument. At the inception of the hedge and on an ongoing basis, the effectiveness of the hedge is assessed to determine whether the hedge will be or is highly effective in offsetting changes in fair value or cash flows of the item being hedged. Changes in the fair value that result from the ineffectiveness of a hedge under SFAS 133 are recognized currently in earnings through mark-to-market accounting. Changes in the fair value of effective cash flow hedges are reported in Accumulated Other Comprehensive Income. Gains and losses from cash flow hedges in other comprehensive income are reclassified to earnings in the accounting periods in which the variability of cash flows of the hedged items affect earnings
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on AEP's Consolidated Balance Sheets at December 31, 2002 are:
Accumulated
Other Comprehensive
Hedging Assets Hedging Liabilities Income (Loss) After Tax
-------------- ------------------- -----------------------
(in millions)
lectricity and Gas $6 $ (8) $ (2)
nterest Rate - (13)* (12)
oreign Currency - (2) (2)
----
$(16)
|
* Includes $6 million loss recorded in an equity investment.
The following table represents the activity in Other Comprehensive Income (Loss) related to the effect of adopting SFAS 133 for derivative contracts that qualify as cash flow hedges at December 31, 2002:
(in millions)
AEP Consolidated
Beginning Balance, January 1, 2002 $ (3)
Changes in fair value (56)
Reclasses from OCI to net loss 43
-------
Accumulated OCI derivative loss, December 31, 2002 $ (16)
=======
(in thousands)
APCo
Beginning Balance, January 1, 2002 $ (340)
Effective portion of changes in fair value (1,310)
Reclasses from OCI to net income (270)
-------
Accumulated OCI derivative loss, December 31, 2002 $(1,920)
=======
CSPCo
Beginning Balance, January 1, 2002 $ -
Effective portion of changes in fair value 62
Reclasses from OCI to net income (329)
-------
Accumulated OCI derivative Loss, December 31, 2002 $ (267)
=======
I&M
Beginning Balance, January 1, 2002 $(3,835)
Effective portion of changes in fair value 34
Reclasses from OCI to net income 3,515
-------
Accumulated OCI derivative loss, December 31, 2002 $ (286)
=======
KPCo
Beginning Balance, January 1, 2002 $(1,903)
Effective portion of changes in fair value 343
Reclasses from OCI to net income 1,882
-------
Accumulated OCI derivative gain, December 31, 2002 $ 322
=======
OPCo
Beginning Balance, January 1, 2002 $ (196)
Effective portion of changes in fair value (103)
Reclasses from OCI to net income (439)
-------
Accumulated OCI derivative loss, December 31, 2002 $ (738)
=======
PSO
Beginning Balance, January 1, 2002 $ -
Effective portion of changes in fair value 2
Reclasses from OCI to net income (44)
-------
Accumulated OCI derivative loss, December 31, 2002 $ (42)
=======
SWEPCo
Beginning Balance, January 1, 2002 $ -
Effective portion of changes in fair value 1
Reclasses from OCI to net income (49)
-------
Accumulated OCI derivative loss, December 31, 2002 $ (48)
=======
TCC
Beginning Balance, January 1, 2002 $ -
Effective portion of changes in fair value 30
Reclasses from OCI to net income (66)
-------
Accumulated OCI derivative loss, December 31, 2002 $ (36)
=======
TNC
Beginning Balance, January 1, 2002 $ -
Effective portion of changes in fair value 3
Reclasses from OCI to net income (18)
-------
Accumulated OCI derivative loss, December 31, 2002 $ (15)
=======
|
Approximately $9 million of net losses from cash flow hedges in Accumulated Other Comprehensive Income (Loss) at December 31, 2002 are expected to be reclassified to net income in the next twelve months as the items being hedged settle. The actual amounts reclassified from Accumulated Other Comprehensive Income to Net Income can differ as a result of market price changes. The maximum term for which the exposure to the variability of future cash flows is being hedged is five years.
Financial Instruments
Market Valuation of Non-Derivative Financial Instrument
The book values of Cash and Cash Equivalents, Accounts Receivable, Short-term Debt and Accounts Payable approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value.
The fair values of Long-term Debt and preferred stock subject to mandatory redemption are based on quoted market prices for the same or similar issues and the current dividend or interest rates offered for instruments with similar maturities. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that we could realize in a current market exchange. The book values and fair values of significant financial instruments for AEP and its registrant subsidiaries at December 31, 2002 and 2001 are summarized in the following tables.
2002 2001
---- ----
Book Value Fair Value Book Value Fair Value
---------- ---------- ---------- ----------
(in millions) (in millions)
AEP
Long-term Debt $ 10,125 $ 10,470 $ 9,505 $ 9,542
Preferred Stock 84 77 95 93
Trust Preferred Securities 321 324 321 321
(in thousands) (in thousands)
AEGCo
Long-term Debt $ 44,802 $ 48,103 $ 44,793 $ 45,268
APCo
Long-term Debt $1,893,861 $1,953,087 $1,556,559 $1,439,531
Preferred Stock 10,860 9,774 10,860 10,860
CSPCo
Long-term Debt $ 621,626 $ 643,715 $ 791,848 $ 802,194
Preferred Stock - - 10,000 10,100
I&M
Long-term Debt $1,617,062 $1,673,363 $1,652,082 $1,672,392
Preferred Stock 64,945 58,948 64,945 62,795
KPCo
Long-term Debt $ 466,632 $ 475,455 $ 346,093 $ 350,233
OPCo
Long-term Debt $1,067,314 $1,095,197 $1,203,841 $1,227,880
Preferred Stock 8,850 7,965 8,850 8,837
PSO
Long-term Debt $ 545,437 $ 570,761 $ 451,129 $ 462,903
Trust Preferred Securities 75,000 75,900 75,000 74,730
SWEPCo
Long-term Debt $ 693,448 $ 727,085 $ 645,283 $ 656,998
Trust Preferred Securities 110,000 110,880 110,000 109,780
TCC
Long-term Debt $1,438,565 $1,522,373 $1,253,768 $1,278,644
Trust Preferred Securities 136,250 136,959 136,250 135,760
TNC
Long-term Debt $ 132,500 $ 144,060 $ 255,967 $ 266,846
|
Other Financial Instruments - Nuclear Trust Funds Recorded at Market Value - The trust investments which are classified as held for sale for decommissioning and SNF disposal, reported in Other Assets on AEP's Consolidated Balance Sheets, are recorded at market value in accordance with SFAS 115 "Accounting for Certain Investments in Debt and Equity Securities". At December 31, 2002 and 2001, the fair values of the trust investments were $969 million and $933 million, respectively, and had a cost basis of $909 million and $839 million, respectively. The change in market value in 2002, 2001, and 2000 was a net unrealized holding loss of $33 million and $11 million and a net unrealized holding gain of $6 million, respectively.
18. Income Taxes:
The details of AEP's consolidated income taxes before discontinued operations, extraordinary items, and cumulative effect as reported are as follows:
2002 2001 2000
---- ---- ----
(in millions)
Federal:
Current $ 330 $404 $ 793
Deferred (192) 60 (236)
----- ---- -----
Total 138 464 557
----- ---- -----
State:
Current 32 61 47
Deferred 30 34 (6)
----- ---- -----
Total 62 95 41
----- ---- -----
International:
Current 13 (13) 4
Deferred 1 - -
----- ---- ------
Total 14 (13) 4
----- ---- -----
Total Income Tax
as Reported
Before
Discontinued
Operations,
Extraordinary
Items and
Cumulative
Effect $ 214 $546 $ 602
===== ==== =====
|
The details of the registrant subsidiaries income taxes as reported are as
follows:
AEGCo APCo CSPCo I&M KPCo
Year Ended December 31, 2002 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $ 6,607 $ 99,140 $ 81,539 $ 66,063 $ 680
Deferred (5,028) 17,626 25,771 (19,870) 9,451
Deferred Investment Tax Credits 2 (3,229) (3,096) (7,340) (1,173)
-------- -------- -------- --------- -------
Total 1,581 113,537 104,214 38,853 8,958
-------- -------- -------- --------- -------
Charged (Credited) to
Nonoperating Income (net):
Current (173) (354) 9,442 3,435 1,583
Deferred - (849) (2,479) 2,949 388
Deferred Investment Tax Credits (3,363) (1,408) (174) (400) (67)
-------- -------- -------- --------- --------
Total (3,536) (2,611) 6,789 5,984 1,904
-------- -------- -------- --------- --------
Total Income Tax as Reported $ (1,955) $110,926 $111,003 $ 44,837 $ 10,862
======== ======== ======== ========= ========
|
OPCo PSO SWEPCo TCC TNC
Year Ended December 31, 2002 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $ 86,026 $(49,673) $ 41,354 $ 30,495 $ 109
Deferred 30,048 75,659 (3,134) 113,726 (10,652)
Deferred Investment Tax Credits (2,493) (1,791) (4,524) (5,207) (1,271)
-------- -------- -------- --------- --------
Total 113,581 24,195 33,696 139,014 (11,814)
-------- -------- -------- --------- --------
Charged (Credited) to
Nonoperating Income (net):
Current 2,732 (1,812) 1,772 3,223 1,334
Deferred 15,962 - - (71) (1,623)
Deferred Investment Tax Credits (684) - - - -
-------- -------- -------- --------- --------
Total 18,010 (1,812) 1,772 3,152 (289)
-------- -------- -------- --------- --------
Total Income Tax as Reported $131,591 $ 22,383 $ 35,468 $ 142,166 $(12,103)
======== ======== ======== ========= ========
|
AEGCo APCo CSPCo I&M KPCo
Year Ended December 31, 2001 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $ 9,126 $ 71,623 $ 88,013 $ 107,286 $ 7,726
Deferred (6,224) 27,198 14,923 (45,785) 2,812
Deferred Investment Tax Credits - (3,237) (3,899) (7,377) (1,180)
-------- -------- -------- --------- --------
Total 2,902 95,584 99,037 54,124 9,358
-------- -------- -------- --------- --------
Charged (Credited) to
Nonoperating Income (net):
Current (56) (19,165) (13,803) (10,590) (2,725)
Deferred - 21,832 17,885 16,580 3,481
Deferred Investment Tax Credits (3,414) (1,528) (159) (947) (72)
-------- -------- -------- --------- --------
Total (3,470) 1,139 3,923 5,043 684
-------- -------- -------- --------- --------
Total Income Tax as Reported $ (568) $ 96,723 $102,960 $ 59,167 $ 10,042
======== ======== ======== ========= ========
|
OPCo PSO SWEPCo TCC TNC
Year Ended December 31, 2001 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $(62,298) $ 53,030 $ 77,965 $ 190,671 $ 19,424
Deferred 166,166 (16,726) (31,396) (72,568) (11,891)
Deferred Investment Tax Credits (2,495) (1,791) (4,453) (5,207) (1,271)
-------- -------- -------- --------- --------
Total 101,373 34,513 42,116 112,896 6,262
-------- -------- -------- --------- --------
Charged (Credited) to
Nonoperating Income (net):
Current (21,600) 352 542 (398) (691)
Deferred 20,014 - - - -
Deferred Investment Tax Credits (794) - - - -
-------- -------- -------- --------- --------
Total (2,380) 352 542 (398) (691)
-------- -------- -------- --------- --------
Total Income Tax as Reported $ 98,993 $ 34,865 $ 42,658 $ 112,498 $ 5,571
======== ======== ======== ========= ========
|
AEGCo APCo CSPCo I&M KPCo
Year Ended December 31, 2000 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $ 8,746 $129,165 $120,494 $ 134,796 $ 17,878
Deferred (5,842) 3,838 (7,746) (126,748) 2,521
Deferred Investment Tax Credits - (2,947) (3,379) (7,524) (1,187)
-------- -------- -------- --------- --------
Total 2,904 130,056 109,369 524 19,212
-------- -------- -------- --------- --------
Charged (Credited) to
Nonoperating Income (net):
Current (44) 327 3,777 2,950 (50)
Deferred - 4,764 3,683 1,569 1,244
Deferred Investment Tax Credits (3,396) (1,968) (103) (330) (65)
-------- -------- -------- --------- --------
Total (3,440) 3,123 7,357 4,189 1,129
-------- -------- -------- --------- --------
Total Income Tax as Reported $ (536) $133,179 $116,726 $ 4,713 $ 20,341
======== ======== ======== ========= ========
|
OPCo PSO SWEPCo TCC TNC
Year Ended December 31, 2000 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $ 259,608 $ 11,597 $ 16,073 $ 89,403 $ 6,774
Deferred (70,263) 25,453 14,653 16,263 9,401
Deferred Investment Tax Credits (1,824) (1,791) (4,482) (5,207) (1,271)
--------- -------- -------- --------- --------
Total 187,521 35,259 26,244 100,459 14,904
--------- -------- -------- --------- --------
Charged (Credited) to
Nonoperating Income (net):
Current 15,426 (1,306) (1,476) (5,073) (222)
Deferred 4,307 - - - (1,237)
Deferred Investment Tax Credits ( 1,575) - - - -
--------- -------- -------- --------- ---------
Total 18,158 (1,306) (1,476) (5,073) (1,459)
--------- -------- -------- --------- --------
Total Income Tax as Reported $ 205,679 $ 33,953 $24,768 $ 95,386 $ 13,445
========= ======== ======= ========= ========
|
The following is a reconciliation for AEP Consolidated of the difference between the amount of federal income taxes computed by multiplying book income before federal income taxes by the statutory tax rate, and the amount of income taxes reported.
Year Ended December 31,
----------------------
2002 2001 2000
---- ---- ----
(in millions)
Net Income (Loss) $(519) $ 971 $267
Discontinued Operations (net of income tax
Of $73 million in 2002, $22 million in 2001
and $5 million in 2000) 190 (86) (122)
Extraordinary Items
(net of income tax of $20 million in 2001
and $44 million in 2000) - 50 35
Cumulative Effect of Accounting Change
(net of income tax of $2 million in 2001) 350 (18) -
Preferred Stock Dividends 11 10 11
----- ------ ----
Income Before Preferred Stock Dividends
of Subsidiaries 32 927 191
Income Taxes Before Discontinued Operations,
Extraordinary Items and Cumulative Effect 214 546 602
----- ------ ----
Pre-Tax Income $ 246 $1,473 $793
===== ====== ====
Income Taxes on Pre-Tax Income
at Statutory Rate (35%) $ 86 $ 516 $278
Increase (Decrease) in Income Taxes
Resulting from the Following Items:
Depreciation 32 48 77
Corporate Owned Life Insurance - 4 247
Investment Tax Credits (net) (35) (37) (36)
Tax Effects of International Operations 123 (12) (1)
Energy Production Credits (14) - -
Merger Transaction Costs - - 49
State Income Taxes 40 62 26
Other (18) (35) (38)
----- ------ ----
Total Income Taxes as Reported Before
Discontinued Operations, Extraordinary
Items and Cumulative Effect $ 214 $ 546 $602
===== ====== ====
Effective Income Tax Rate 87.0% 37.1% 75.9%
===== ====== ====
|
Shown below is a reconciliation for each AEP registrant subsidiary of the difference between the amount of federal income taxes computed by multiplying book income before federal income taxes by the statutory rate, and the amount of income taxes reported.
AEGCo APCo CSPCo I&M KPCo
Year Ended December 31, 2002 (in thousands)
Net Income $ 7,552 $205,492 $181,173 $ 73,992 $ 20,567
Income Taxes (1,955) 110,926 111,003 44,837 10,862
-------- -------- -------- -------- --------
Pre-Tax Income $ 5,597 $316,418 $292,176 $118,829 $ 31,429
======== ======== ======== ======== ========
Income Tax on Pre-Tax Income
at Statutory Rate (35%) $ 1,959 $110,746 $102,262 $ 41,590 $ 11,000
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 870 3,082 2,899 21,812 2,057
Corporate Owned Life Insurance - (93) 719 268 305
Nuclear Fuel Disposal Costs - - - (3,814) -
Allowance for Funds Used
During Construction (446) - - (3,453) -
Rockport Plant Unit 2 Investment
Tax Credit (748) - - - -
Removal Costs - - - - (735)
Investment Tax Credits (net) (3,361) (4,637) (3,270) (7,740) (1,240)
State Income Taxes 335 6,469 11,387 124 1,058
Other (564) (4,641) (2,994) (3,950) (1,583)
-------- -------- -------- -------- --------
Total Income Taxes as Reported $ (1,955) $110,926 $111,003 $ 44,837 $ 10,862
======== ======== ======== ======== ========
Effective Income Tax Rate N.M. 35.1% 38.0% 37.7% 34.6%
==== ===== ===== ===== =====
|
OPCo PSO SWEPCo TCC TNC
Year Ended December 31, 2002 (in thousands)
Net Income (Loss) $220,023 $ 41,060 $ 82,992 $ 275,941 $(13,677)
Income Taxes 131,591 22,383 35,468 142,166 (12,103)
-------- -------- -------- --------- --------
Pre-Tax Income (Loss) $351,614 $ 63,443 $118,460 $ 418,107 $(25,780)
======== ======== ======== ========= ========
Income Tax on Pre-Tax Income (Loss)
at Statutory Rate (35%) $123,065 $ 22,205 $ 41,461 $ 146,337 $ (9,023)
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 4,227 (583) (2,790) (295) (32)
Corporate Owned Life Insurance (84) - - - -
Investment Tax Credits (net) (3,177) (1,791) (4,524) (5,207) (1,271)
State Income Taxes 18,051 2,639 3,987 2,202 (1,577)
Other (10,491) (87) (2,666) (871) (200)
-------- -------- -------- --------- --------
Total Income Taxes as Reported $131,591 $ 22,383 $ 35,468 $ 142,166 $(12,103)
======== ======== ======== ========= ========
Effective Income Tax Rate 37.4% 35.3% 29.9% 34.0% 47.0%
===== ===== ===== ===== =====
|
AEGCo APCo CSPCo I&M KPCo
Year Ended December 31, 2001 (in thousands)
Net Income $ 7,875 $161,818 $161,876 $ 75,788 $ 21,565
Extraordinary Loss - - 30,024 - -
Income Taxes (568) 96,723 102,960 59,167 10,042
------- -------- -------- --------- --------
Pre-Tax Income $ 7,307 $258,541 $294,860 $ 134,955 $ 31,607
======= ======== ======== ========= ========
Income Tax on Pre-Tax Income
at Statutory Rate (35%) $ 2,557 $ 90,489 $103,201 $ 47,234 $ 11,062
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 230 2,977 2,757 21,224 1,581
Corporate Owned Life Insurance - 450 544 (148) 334
Nuclear Fuel Disposal Costs - - - (3,292) -
Allowance for Funds Used
During Construction (1,078) - - (1,606) -
Rockport Plant Unit 2 Investment
Tax Credit 374 - - - -
Removal Costs - - - - (420)
Investment Tax Credits (net) (3,414) (4,765) (4,058) (8,324) (1,252)
State Income Taxes 1,050 9,613 5,727 6,137 318
Other (287) (2,041) (5,211) (2,058) (1,581)
-------- -------- -------- --------- --------
Total Income Taxes as Reported $ (568) $ 96,723 $102,960 $ 59,167 $ 10,042
======== ======== ======== ========= ========
Effective Income Tax Rate N.M. 37.4% 34.9% 43.8% 31.8%
==== ===== ===== ===== =====
|
OPCo PSO SWEPCo TCC TNC
Year Ended December 31, 2001 (in thousands)
Net Income $ 147,445 $ 57,759 $ 89,367 $ 182,278 $ 12,310
Extraordinary Loss 18,348 - - 2,509 -
Income Taxes 98,993 34,865 42,658 112,498 5,571
--------- -------- -------- --------- --------
Pre-Tax Income $ 264,786 $ 92,624 $132,025 $ 297,285 $ 17,881
========= ======== ======== ========= ========
Income Tax on Pre-Tax Income
at Statutory Rate (35%) $ 92,675 $ 32,418 $ 46,209 $ 104,050 $ 6,258
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 7,972 1,127 (501) 8,477 1,463
Corporate Owned Life Insurance 1,852 - - - -
Investment Tax Credits (net) (3,289) (1,791) (4,453) (5,207) (1,271)
State Income Taxes 9,752 5,137 5,451 9,652 1,283
Other (9,969) (2,026) (4,048) (4,474) (2,162)
--------- -------- -------- --------- --------
Total Income Taxes as Reported $ 98,993 $ 34,865 $ 42,658 $ 112,498 $ 5,571
========= ======== ======== ========= ========
Effective Income Tax Rate 37.4% 37.6% 32.3% 37.8% 31.2%
==== ==== ==== ===== =====
|
AEGCo APCo CSPCo I&M KPCo
Year Ended December 31, 2000 (in thousands)
Net Income (Loss) $ 7,984 $ 73,844 $ 94,966 $(132,032) $ 20,763
Extraordinary (Gains) Loss (1,066) 39,384 - -
Income Tax Benefit - (7,872) (14,148) - -
Income Taxes (536) 133,179 116,726 4,713 20,341
------- -------- -------- --------- --------
Pre-Tax Income (Loss) $ 7,448 $198,085 $236,928 $(127,319) $ 41,104
======= ======== ======== ========= ========
Income Tax on Pre-Tax Income
(Loss) at Statutory Rate (35%) $ 2,607 $ 69,330 $ 82,925 $ (44,562) $ 14,386
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 452 7,606 10,529 20,378 1,827
Corporate Owned Life Insurance - 54,824 29,259 42,587 5,149
Nuclear Fuel Disposal Costs - - - (3,957) -
Allowance for Funds Used
During Construction (1,070) - - (2,211) -
Rockport Plant Unit 2 Investment
Tax Credit 374 - - - -
Removal Costs - (1,197) - - (420)
Investment Tax Credits (net) (3,396) (4,915) (3,482) (7,854) (1,252)
State Income Taxes 784 9,950 89 6,004 1,597
Other (287) (2,419) (2,594) (5,672) (946)
-------- -------- -------- --------- --------
Total Income Taxes as Reported $ (536) $133,179 $116,726 $ 4,713 $ 20,341
======== ======== ======== ========= ========
Effective Income Tax Rate N.M. 67.2% 49.3% N.M. 49.5%
==== ==== ==== ==== =====
|
OPCo PSO SWEPCo TCC TNC
Year Ended December 31, 2000 (in thousands)
Net Income $ 83,737 $ 66,663 $ 72,672 $ 189,567 $ 27,450
Extraordinary Loss 40,157 - - - -
Income Tax Benefit (21,281) - - - -
Income Taxes 205,679 33,953 24,768 95,386 13,445
--------- -------- -------- --------- --------
Pre-Tax Income $ 308,292 $100,616 $ 97,440 $ 284,953 $ 40,895
========= ======== ======== ========= ========
Income Tax on Pre-Tax Income
at Statutory Rate (35%) $ 107,902 $ 35,216 $ 34,104 $ 99,734 $ 14,313
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 27,577 695 (1,012) 7,556 1,204
Corporate Owned Life Insurance 84,453 - - - -
Investment Tax Credits (net) (3,398) (1,791) (4,482) (5,207) (1,271)
State Income Taxes (1,988) 3,037 1,650 2,296 -
Other (8,867) (3,204) (5,492) (8,993) (801)
--------- -------- -------- --------- --------
Total Income Taxes as Reported $ 205,679 $ 33,953 $ 24,768 $ 95,386 $ 13,445
========= ======== ======== ========= ========
Effective Income Tax Rate 66.7% 33.7% 25.4% 33.5% 32.9%
==== ==== ==== ===== ====
|
The following tables show the elements of the net deferred tax liability and the significant temporary differences for AEP Consolidated and each registrant subsidiary:
December 31, 2002 2001
-------------- ---- ----
(in millions)
Deferred Tax Assets $ 2,189 $ 1,216
Deferred Tax Liabilities (6,105) (5,716)
------- -------
Net Deferred Tax Liabilities $(3,916) $(4,500)
======= =======
Property Related Temporary Differences $(3,612) $(3,674)
Amounts Due From Customers For Future
Federal Income Taxes (360) (245)
Deferred State Income Taxes (422) (314)
Transition Regulatory Assets (234) (268)
Regulatory Assets Designated for Securitization (310) (332)
Asset Impairments and Investment Value Losses 417 -
Deferred Income Taxes on Other Comprehensive Loss 326 3
All Other (net) 279 330
------- -------
Net Deferred Tax Liabilities $(3,916) $(4,500)
======= =======
|
AEGCo APCo CSPCo I&M KPCo
December 31, 2002 (in thousands)
Deferred Tax Assets $ 73,094 $ 213,972 $ 72,990 $ 348,672 $ 36,948
Deferred Tax Liabilities (102,096) (915,773) (510,761) (704,869) (215,261)
--------- --------- --------- --------- ---------
Net Deferred Tax Liabilities $ (29,002) $(701,801) $(437,771) $(356,197) $(178,313)
========== ========= ========= ========= =========
Property Related Temporary Differences $ (74,291) $(555,824) $(331,381) $(343,587) $(127,073)
Amounts Due From Customers For
Future Federal Income Taxes 7,626 (58,246) (8,895) (38,752) (20,488)
Deferred State Income Taxes (5,119) (77,693) (23,448) (52,528) (28,722)
Transition Regulatory Assets - (28,735) (71,752) - -
Asset Impairments and Investment
Value Losses - 18 215 225 4
Deferred Income Taxes on Other
Comprehensive Loss - 38,823 31,961 21,800 5,089
Net Deferred Gain on Sale and
Leaseback-Rockport Plant Unit 2 38,866 - - 25,860 -
Accrued Nuclear Decommissioning Expense - - - 65,856 -
Deferred Fuel and Purchased Power - (1,878) (273) (13,144) 415
Deferred Cook Plant Restart Costs - - - (14,000) -
Nuclear Fuel - - - (5,153) -
All Other (net) 3,916 (18,266) (34,198) (2,774) (7,538)
--------- -------- --------- --------- ---------
Net Deferred Tax Liabilities $ (29,002) $(701,801) $(437,771) $(356,197) $(178,313)
========= ========= ========= ========= =========
|
OPCo PSO SWEPCo TCC TNC
December 31, 2002 (in thousands)
Deferred Tax Assets $ 155,334 $ 70,649 $ 82,113 $ 130,210 $ 35,970
Deferred Tax Liabilities (949,721) (412,045) (423,177) (1,391,462) (153,491)
--------- --------- --------- ----------- ---------
Net Deferred Tax Liabilities $(794,387) $(341,396) $(341,064) $(1,261,252) $(117,521)
========= ========= ========= =========== =========
Property Related Temporary Differences $(620,634) $(303,888) $(315,821) $ (709,246) $(142,034)
Amounts Due From Customers For
Future Federal Income Taxes (53,256) 9,490 (4,078) (198,595) 5,726
Deferred State Income Taxes (46,990) (57,911) (48,372) (66,333) (4,080)
Transition Regulatory Assets (131,833) - - - -
Asset Impairments and Investment
Value Losses 615 - - - 14,996
Deferred Income Taxes on Other
Comprehensive Loss 39,246 29,332 28,906 39,394 16,565
Deferred Fuel and Purchased Power 540 (28,696) 3,192 2,655 (9,933)
Regulatory Assets Designated
For Securitization - - - (310,410) -
All Other (net) 17,925 10,277 (4,891) (18,717) 1,239
--------- --------- --------- ----------- ---------
Net Deferred Tax Liabilities $(794,387) $(341,396) $(341,064) $(1,261,252) $(117,521)
========= ========= ========= =========== =========
|
AEGCo APCo CSPCo I&M KPCo
December 31, 2001 (in thousands)
Deferred Tax Assets $ 75,856 $ 162,334 $ 74,767 $ 332,225 $ 30,927
Deferred Tax Liabilities (103,831) (865,909) (518,489) (732,756) (199,231)
--------- --------- --------- --------- ---------
Net Deferred Tax Liabilities $ (27,975) $(703,575) $(443,722) $(400,531) $(168,304)
========= ========= ========= ========= =========
Property Related Temporary Differences $ (70,581) $(530,298) $(323,139) $(306,151) $(118,147)
Amounts Due From Customers For
Future Federal Income Taxes 9,292 (55,206) (9,839) (46,756) (20,215)
Deferred State Income Taxes (3,822) (56,747) (8,968) (38,015) (25,267)
Transition Regulatory Assets - (34,783) (78,298) - -
Deferred Income Taxes on Other
Comprehensive Loss - 183 - 2,065 1,025
Net Deferred Gain on Sale and
Leaseback-Rockport Plant Unit 2 40,816 - - 27,157 -
Accrued Nuclear Decommissioning Expense - - - 43,707 -
Deferred Fuel and Purchased Power - (4,106) (39) (26,270) 57
Deferred Cook Plant Restart Costs - - - (28,000) -
Nuclear Fuel - - - (16,062) -
All Other (net) (3,680) (22,618) (23,439) (12,206) (5,757)
--------- --------- --------- --------- ---------
Net Deferred Tax Liabilities $ (27,975) $(703,575) $(443,722) $(400,531) $(168,304)
========= ========= ========= ========= =========
|
OPCo PSO SWEPCo TCC TNC
December 31, 2001 (in thousands)
Deferred Tax Assets $ 135,938 $ 59,421 $ 56,189 $ 130,863 $ 22,888
Deferred Tax Liabilities (933,827) 356,298) (425,970) (1,294,658) (167,937)
--------- -------- --------- ----------- ---------
Net Deferred Tax Liabilities $(797,889) $(296,877) $(369,781) $(1,163,795) $(145,049)
========= ========= ========= =========== =========
Property Related Temporary
Differences $(595,974) $(320,900) $(362,884) $ (808,922) $(149,309)
Amounts Due From Customers For
Future Federal Income Taxes (61,130) 10,199 (6,441) (70,174) 4,757
Deferred State Income Taxes (18,440) (35,038) (48,729) (66,333) (4,079)
Transition Regulatory Assets (154,947) - - - -
Deferred Income Taxes on Other
Comprehensive Loss 106 - - - -
Deferred Fuel and Purchased Power 12 3,052 (2,778) 18,032 (11,756)
Provision for Mine Shutdown Costs 20,323 - - - -
Regulatory Assets Designated
For Securitization - - - (332,198) -
All Other (net) 12,161 45,810 51,051 95,800 15,338
--------- --------- -------- ------------ ---------
Net Deferred Tax Liabilities $(797,889) $(296,877) $(369,781) $(1,163,795) $(145,049)
========= ========= ========= =========== =========
|
We have settled with the IRS all issues from the audits of our consolidated federal income tax returns for the years prior to 1991. We have received Revenue Agent's Reports from the IRS for the years 1991 through 1996, and have filed protests contesting certain proposed adjustments. Returns for the years 1997 through 2000 are presently being audited by the IRS. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on results of operations.
COLI Litigation - On February 20, 2001, the U.S. District Court for the Southern District of Ohio ruled against AEP in its suit against the United States over deductibility of interest claimed by AEP in its consolidated federal income tax returns related to its COLI program. AEP had filed suit to resolve the IRS' assertion that interest deductions for AEP's COLI program should not be allowed. In 1998 and 1999 the Company paid the disputed taxes and interest attributable to COLI interest deductions for taxable years 1991-98 to avoid the potential assessment by the IRS of additional interest on the contested tax. The payments were included in other assets pending the resolution of this matter. As a result of the U.S. District Court's decision to deny the COLI interest deductions, net income was reduced by $319 million in 2000. The Company has filed an appeal of the U.S. District Court's decision with the U.S. Court of Appeals for the 6th Circuit.
The earnings reductions recorded in 2000 for affected registrant subsidiaries were as follows:
(in millions)
APCo $ 82
CSPCo 41
I&M 66
KPCo 8
OPCo 118
|
The Company joins in the filing of a consolidated federal income tax return with its affiliated companies in the AEP System. The allocation of the AEP System's current consolidated federal income tax to the System companies is in accordance with SEC rules under the 1935 Act. These rules permit the allocation of the benefit of current tax losses to the System companies giving rise to them in determing their current tax expense. The tax loss of the System parent company, AEP Co., Inc., is allocated to its subsidiaries with taxable income. With the exception of the loss of the parent company, the method of allocation approximates a separate return result for each company in the consolidated group.
19. Basic and Diluted Earnings Per Share:
The calculation of AEP's basic and diluted earnings (loss) per common share (EPS) is based on the amounts of Net Income (Loss) and weighted average common shares shown in the table below:
2002 2001 2000
---- ---- ----
(in millions - except
per share amounts)
Income:
Income Before Discontinued
Operations, Extraordinary
Items and Cumulative
Effect $ 21 $ 917 $ 180
Discontinued Operations (190) 86 122
------ ----- -----
Income (Loss) Before
Extraordinary Item
And Cumulative Effect (169) 1,003 302
Extraordinary Losses
(net of tax):
Discontinuance of
Regulatory Accounting
For Generation - (48) (35)
Loss on Reacquired Debt - (2) -
Cumulative Effect of
Accounting Change
(net of tax) (350) 18 -
----- ----- -----
Net Income (Loss) $(519) $ 971 $ 267
===== ====== =====
Weighted Average Shares:
Average Common
Shares Outstanding 332 322 322
Assumed Conversion of
Dilutive Stock Options
(see Note 15) - 1 -
----- ----- -----
Diluted Average Common
Shares Outstanding 332 323 322
===== ===== =====
Basic and Diluted
Earnings Per Common Share:
Income Before Discontinued
Operations, Extraordinary
Items and Cumulative
Effect $ 0.06 $2.85 $0.56
Discontinued Operations (0.57) 0.26 0.38
------ ----- -----
Income (Loss) Before
Extraordinary Item and
Cumulative Effect (0.51) 3.11 0.94
Extraordinary Losses
(net of tax):
Discontinuance of
Regulatory Accounting
For Generation - (0.15) (0.11)
Loss on Reacquired Debt - (0.01) -
Cumulative Effect
of Accounting Change
(net of tax) (1.06) 0.06 -
------ ----- -----
$(1.57) $3.01 $0.83
====== ===== =====
|
The assumed conversion of stock options does not affect net earnings (loss) for purposes of calculating diluted earnings per share. AEP's basic and diluted EPS are the same in 2002, 2001 and 2000 since the effect on weighted average common shares outstanding is minimal.
Had AEP recognized net income in fiscal 2002, incremental shares attributable to the assumed exercise of outstanding stock options would have increased diluted common shares outstanding by 398,000 shares.
Options to purchase 8.8 million, 0.7 million and 6.4 million shares of common stock were outstanding at December 31, 2002, 2001 and 2000, respectively, but were not included in the computation of diluted earnings per share because the options' exercise prices were greater than the year-end market price of the common shares and, therefore, the effect would be antidilutive.
In addition, there is no effect on diluted earnings per share related to our equity units (issued in 2002) unless the market value of AEP common stock exceeds $49.08 per share. There were no dilutive effects from equity units at December 31, 2002. If our common stock value exceeds $49.08 we would apply the treasury stock method to the equity units to calculate diluted earnings per share. This method of calculation theoretically assumes that the proceeds received as a result of the forward purchase contracts are used to repurchase outstanding shares. Also see Note 27.
20. Supplementary Information:
Year Ended December 31,
-----------------------
2002 2001 2000
---- ---- ----
(in millions)
AEP Consolidated Purchased Power -
Ohio Valley Electric Corporation
(44.2% owned by AEP System) $142 $127 $86
Cash was paid for:
Interest (net of capitalized amounts) $792 $972 $842
Income Taxes $336 $569 $449
Noncash Investing and Financing Activities:
Acquisitions under Capital Leases $ 6 $17 $118
Assumption of Liabilities Related to Acquisitions $1 $171 -
Exchange of Communication Investment for Common Stock - $5 -
|
The amounts of power purchased by the registrant subsidiaries from Ohio Valley Electric Corporation, which is 44.2% owned by the AEP System, for the years ended December 31, 2002, 2001, and 2000 were:
APCo CSPCo I&M OPCo
---- ----- --- ----
(in thousands)
Year Ended December 31, 2002 $53,386 $14,885 $23,282 $50,135
Year Ended December 31, 2001 45,542 12,626 20,723 47,757
Year Ended December 31, 2000 30,998 8,706 15,204 31,134
|
21. Power and Distribution Projects:
Power Projects
AEP owns interests of 50% or less in domestic unregulated power plants with a capacity of 1,483 MW located in Colorado, Florida and Texas. In addition to the domestic projects, AEP has equity interests in international power plants totaling 1,113 MW.
Investments in power projects that are 50% or less owned are accounted for by the equity method and reported in Investments in Power and Distribution Projects on AEP's Consolidated Balance Sheets (see "Eastex" within the Assets Held for Sale section of Note 13), except for Eastex Cogeneration which, due to its structure, is consolidated. At December 31, 2002, six domestic power projects and three international power investments are accounted for under the equity method. The six domestic projects are combined cycle gas turbines that provide steam to a host commercial customer and are considered either Qualifying Facilities (QFs) or Exempt Wholesale Generators (EWGs) under PURPA. The three international power investments are classified as Foreign Utility Companies (FUCO) under the Energy Policies Act of 1992. Two of the international investments are power projects and the other international investment is a company which owns an interest in four additional power projects. All of the power projects accounted for under the equity method have unrelated third-party partners.
Seven of the above power projects have project-level financing, which is non-recourse to AEP. AEP or AEP subsidiaries have guaranteed $58 million of domestic partnership obligations for performance under power purchase agreements and for debt service reserves in lieu of cash deposits.
Distribution Projects
AEP owns a 44% equity interest in Vale, a Brazilian electric operating company which was purchased for a total of $149 million. On December 1, 2001 AEP converted a $66 million note receivable and accrued interest into a 20% equity interest in Caiua (Brazilian electric operating company), a subsidiary of Vale. Vale and Caiua have experienced losses from operations and AEP's investment has been affected by the devaluation of the Brazilian Real. In December 2002, AEP recorded an other than temporary impairment totaling $141.1 million (after federal income tax benefit of $76 million) of its 44% equity investment in Vale and its 20% equity interest in Caiua. See "Grupo Rede Investment" within the Investment Values section of Note 13 "Asset Impairments and Investment Value Losses", for further information on the 2002 impairment of AEP's Vale and Caiua investments.
22. Leases:
Leases of property, plant and equipment are for periods up to 99 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases.
Lease rentals for both operating and capital leases are generally charged to operating expenses in accordance with rate-making treatment for regulated operations. Capital leases for non-regulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows:
AEP AEGCo APCo CSPCo I&M KPCo OPCo
Year Ended December 31, 2002 (in thousands)
Lease Payments on
Operating Leases $346,000 $76,143 $ 6,634 $ 5,209 $110,833 $ 1,597 $68,816
Amortization of Capital Leases 65,000 238 9,729 6,010 8,319 2,171 12,637
Interest on Capital Leases 14,000 19 2,240 1,717 2,221 469 4,501
-------- ------- ------- ------- -------- ------- -------
Total Lease Rental Costs $425,000 $76,400 $18,603 $12,936 $121,373 $ 4,237 $85,954
======== ======= ======= ======= ======== ======= =======
|
PSO SWEPCo TCC TNC
Year Ended December 31, 2002 (in thousands)
Lease Payments on
Operating Leases $ 4,403 $3,240 $ 7,184 $ 1,981
Amortization of Capital Leases - - - -
Interest on Capital Leases - - - -
------- ------ ------- -------
Total Lease Rental Costs $ 4,403 $3,240 $ 7,184 $ 1,981
======= ====== ======= =======
|
AEP AEGCo APCo CSPCo I&M KPCo OPCo
Year Ended December 31, 2001 (in thousands)
Lease Payments on
Operating Leases $293,000 $76,262 $ 6,142 $ 7,063 $104,574 $ 1,191 $63,913
Amortization of Capital Leases 82,000 281 12,099 7,206 17,933 2,740 14,443
Interest on Capital Leases 22,000 55 3,789 2,396 4,424 808 5,818
-------- ------- ------- ------- -------- ------- -------
Total Lease Rental Costs $397,000 $76,598 $22,030 $16,665 $126,931 $ 4,739 $84,174
======== ======= ======= ======= ======== ======= =======
|
PSO SWEPCo TCC TNC
Year Ended December 31, 2001 (in thousands)
Lease Payments on
Operating Leases $ 4,010 $ 2,277 $ 5,948 $ 1,534
Amortization of Capital Leases - - - -
Interest on Capital Leases - - - -
-------- ------- ------- -------
Total Lease Rental Costs $ 4,010 $ 2,277 $ 5,948 $ 1,534
======== ======= ======= =======
|
AEP AEGCo APCo CSPCo I&M KPCo OPCo
Year Ended December 31, 2000 (in thousands)
Lease Payments on
Operating Leases $246,000 $73,858 $ 7,128 $ 7,683 $ 81,446 $ 1,978 $51,981
Amortization of Capital Leases 118,000 281 13,900 7,776 26,341 3,931 37,280
Interest on Capital Leases 36,000 55 3,930 2,690 10,908 1,054 9,584
-------- ------- ------- ------ -------- ------- -------
Total Lease Rental Costs $400,000 $74,194 $24,958 $18,149 $118,695 $ 6,963 $98,845
======== ======= ======= ======= ======== ======= =======
|
PSO SWEPCo TCC TNC
Year Ended December 31, 2000 (in thousands)
Lease Payments on
Operating Leases $ 3,269 $ 1,401 $ 5,410 $ 1,210
Amortization of Capital Leases - - - -
Interest on Capital Leases - - - -
-------- ------- ------- -------
Total Lease Rental Costs $ 3,269 $ 1,401 $ 5,410 $ 1,210
======== ======= ======= =======
|
Property, plant and equipment under capital leases and related obligations
recorded on the Consolidated Balance Sheets are as follows:
AEP AEGCO APCo CSPCo I&M KPCo
Year Ended December 31, 2002 (in thousands)
Property, Plant and Equipment
Under Capital Leases
Production $ 40,000 $ 1,793 $ 3,368 $ 6,380 $ 5,728 $ 1,138
Distribution 15,000 - - - 14,589 -
Other:
Mining Assets and Other 687,000 - 67,395 46,791 70,140 14,258
-------- ------ ------- ------- -------- -------
Total Property, Plant
and Equipment 742,000 1,793 70,763 53,171 90,457 15,396
Accumulated Amortization 299,000 1,294 37,452 26,551 41,141 8,168
-------- ------- ------- ------- -------- ------
Net Property, Plant and
Equipment Under
Capital Leases $443,000 $ 499 $33,311 $26,620 $ 49,316 $ 7,228
======== ======= ======= ======= ======== =======
Obligations Under Capital Leases:
Noncurrent Liability $170,000 $ 301 $23,991 $21,643 $ 42,619 $ 5,093
Liability Due Within One Year 58,000 198 9,598 5,967 8,229 2,155
-------- ------- ------- ------- -------- ------
Total Obligations Under
Capital Leases $228,000 $ 499 $33,589 $27,610 $ 50,848 $ 7,248
======== ======= ======= ======= ======== =======
|
OPCo SWEPCo
Year Ended December 31, 2002 (in thousands)
Property, Plant and Equipment
Under Capital Leases
Production $ 21,360 $ -
Distribution - -
Other:
Mining Assets and Other 103,018 45,699
Total Property, Plant
and Equipment 124,378 45,699
Accumulated Amortization 63,810 45,699
Net Property, Plant and
Equipment Under
Capital Leases $ 60,568 $ -
======== =======
Obligations Under Capital Leases:
Noncurrent Liability $ 51,266 $ -
Liability Due Within One Year 14,360 -
-------- -------
Total Obligations Under
Capital Leases $ 65,626 $ -
======== =======
|
AEP AEGCo APCo CSPCo I&M KPCo OPCo
Year Ended December 31, 2001 (in thousands)
Property, Plant and Equipment
Under Capital Leases
Production $ 39,000 $ 1,983 $ 2,712 $ 6,380 $ 4,826 $ 1,138 $ 22,477
Distribution 15,000 - - - 14,593 - -
Other:
Mining Assets and Other 723,000 129 82,292 54,999 86,267 17,658 114,944
-------- ------- ------- ------- --------- ------- -------
Total Property, Plant
and Equipment 777,000 2,112 85,004 61,379 105,686 18,796 137,421
Accumulated Amortization 250,000 1,801 38,745 26,044 43,768 9,213 57,429
-------- ------- ------- ------- --------- ------- --------
Net Property, Plant and
Equipment Under
Capital Leases $527,000 $ 311 $46,259 $35,335 $ 61,918 $ 9,583 $ 79,992
======== ======= ======= ======= ========= ======= ========
Obligations Under Capital Leases:
Noncurrent Liability $219,000 $ 76 $33,928 $27,052 $ 51,093 $ 6,742 $ 64,261
Liability Due Within One Year 75,000 235 12,357 7,835 10,840 2,841 16,405
-------- ------- ------- ------- --------- ------- --------
Total Obligations Under
Capital Leases $294,000 $ 311 $46,285 $34,887 $ 61,933 $ 9,583 $ 80,666
======== ======= ======= ======= ========= ======= ========
|
Future minimum lease payments consisted of the following at December 31, 2002:
AEP AEGCo APCo CSPCo I&M KPCo OPCo
Capital (in thousands)
-------
2003 $ 70,000 $ 249 $12,483 $ 7,365 $ 10,373 $ 2,623 $ 17,363
2004 53,000 114 10,515 6,231 9,122 1,957 14,634
2005 37,000 58 6,799 5,279 6,506 1,581 11,442
2006 29,000 31 5,117 3,898 5,561 948 10,220
2007 21,000 29 2,668 2,969 4,024 788 8,694
Later Years 59,000 79 4,829 8,321 10,732 725 20,302
-------- ---------- ------- ------- --------- ------- --------
Total Future Minimum
Lease Payments 269,000 560 42,411 34,063 46,318 8,622 82,655
Less Estimated Interest Elemen 41,000 61 8,822 6,453 (4,530) 1,374 17,029
-------- ---------- ------- ------- --------- ------- --------
Estimated Present Value of
Future Minimum Lease
Payments $228,000 $ 499 $33,589 $27,610 $ 50,848 $ 7,248 $ 65,626
======== ========== ======= ======= ========= ======= ========
|
AEP AEGCo APCo CSPCo I&M KPCo OPCo
(in thousands)
Noncancellable Operating Leases
2003 $ 305,000 $ 73,854 $ 4,482 $ 4,608 $ 95,213 $ 1,031 $ 62,784
2004 271,000 73,854 3,723 5,111 81,246 865 62,837
2005 252,000 73,854 3,114 4,013 78,968 747 62,169
2006 242,000 73,854 2,742 1,630 77,741 576 62,481
2007 237,000 73,854 1,962 1,374 76,461 875 62,880
Later Years 2,462,000 1,107,810 4,384 2,670 1,117,725 1,492 180,548
---------- ---------- -------- ------- ---------- ------- --------
Total Future Minimum
Lease Payments $3,769,000 $1,477,080 $20,407 $19,406 $1,527,354 $ 5,586 $493,699
========== ========== ======= ======= ========== ======= ========
|
PSO SWEPCo TCC TNC
(in thousands)
Noncancellable Operating Leases
2003 $ 2,260 $ 912 $ 1,815 $ 448
2004 1,998 617 1,565 296
2005 1,714 433 1,388 192
2006 1,391 317 1,086 169
2007 1,256 301 603 167
Later Years - - - -
---------- ---------- ------- -------
Total Future Minimum
Lease Payments $ 8,619 $ 2,580 $ 6,457 $ 1,272
========== ========== ======= =======
|
OPCo has entered into an agreement with JMG Funding LLP (JMG) an unrelated unconsolidated special purpose entity. JMG has a capital structure of which 3% is equity from investors with no relationship to AEP or any of its subsidiaries and 97% is debt from pollution control bonds and other bonds. JMG was formed to design, construct and lease the Gavin Scrubber for the Gavin Plant to OPCo. JMG owns the Gavin Scrubber and leases it to OPCo. The lease is accounted for as an operating lease with the payment obligations included in the lease footnote. Payments under the operating lease are based on JMG's cost of financing (both debt and equity) and include an amortization component plus the cost of administration. Neither OPCo nor AEP has an ownership interest in JMG and does not guarantee JMG's debt.
At any time during the lease, OPCo has the option to purchase the Gavin Scrubber for the greater of its fair market value or adjusted acquisition cost (equal to the unamortized debt and equity of JMG) or sell the Gavin Scrubber. The initial 15-year lease term is non-cancelable. At the end of the initial term, OPCo can renew the lease, purchase the Gavin Scrubber (terms previously mentioned), or sell the Gavin Scrubber. In case of a sale at less than the adjusted acquisition cost, OPCo must pay the difference to JMG.
The use of JMG allows AEP to enter into an operating lease while keeping the tax benefits otherwise associated with a capital lease. As of December 31, 2002, unless the structure of this arrangement is changed, it is reasonably possible that AEP will consolidate JMG in the third quarter of 2003 as a result of the issuance of FIN 46. Upon consolidation, AEP would record the assets, liabilities, depreciation expense, minority interest and debt interest expense of JMG. AEP would eliminate operating lease expense. AEP's maximum exposure to loss as a result of its involvement with JMG is approximately $560 million of outstanding debt and equity of JMG as of December 31, 2002.
AEGCo and I&M entered into a sale and leaseback transaction in 1989 with
Wilmington Trust Company (Owner Trustee) an unrelated unconsolidated trustee for
Rockport Plant Unit 2 (the plant). Owner Trustee was capitalized with equity
from six owner participants with no relationship to AEP or any of its
subsidiaries and debt from a syndicate of banks and securities in a private
placement to certain institutional investors.
The gain from the sale was deferred and is being amortized over the term of the
lease, which expires in 2022. The Owner Trustee owns the plant and leases it to
AEGCo and I&M. The lease is accounted for as an operating lease with the payment
obligations included in the lease footnote. The lease term is for 33 years with
potential renewal options. At the end of the lease term, AEGCo and I&M have the
option to renew the lease or the Owner Trustee can sell the plant. AEGCo, I&M
nor AEP has ownership interest in the Owner Trustee and do not guarantee its
debt.
23. Lines of Credit and Sale of Receivables:
Lines of Credit - AEP System
The AEP System uses short-term debt, primarily commercial paper and revolving
credit facilities, to meet fluctuations in working capital requirements and
other interim capital needs. AEP has established a utility money pool and a
non-utility money pool to coordinate short-term borrowings for certain
subsidiaries. Utility money participants include AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC and TNC. AEP also incurs borrowings outside of the money
pool for other subsidiaries. As of December 31, 2002, AEP had revolving credit
facilities totaling $3.5 billion to support its commercial paper program. At
December 31, 2002, AEP had $3.2 billion outstanding in short-term borrowings of
which $1.4 billion was commercial paper supported by the revolving credit
facilities. The maximum amount of commercial paper outstanding during the year,
which had a weighted average interest rate during 2002 of 2.47%, was $3.3
billion during April 2002. On December 11, 2002, Moody's Investor Services
placed AEP's Prime-2 short-term rating for commercial paper under review for
possible downgrade. On January 24, 2003, Standard & Poor's Rating Services
placed AEP's A-2 short-term rating for commercial paper under review for
possible downgrade. On February 10, 2003, Moody's Investor Services downgraded
AEP's short-term rating for commercial paper to Prime-3 from Prime-2. As a
result, AEP's access to the commercial paper market will be limited and AEP will
use other sources of funds as necessary.
The registrant subsidiaries incurred interest expense for amounts borrowed from
the AEP money pool as follows:
2002 2001 2000
---- ---- ----
(in millions)
AEGCo $0.4 $ 0.8 $ -
APCo 4.9 9.8 -
CSPCo 3.2 5.0 1.4
I&M 0.4 13.1 0.8
KPCo 1.8 2.3 -
OPCo 6.9 14.6 9.2
PSO 5.4 6.3 7.5
SWEPCo 4.6 3.4 4.2
TCC 11.1 11.4 16.9
TNC 3.8 3.1 2.7
|
Interest income earned from amounts advanced to the AEP money pool by the registrant subsidiaries were:
2002 2001 2000
---- ---- ----
(in millions)
AEGCo $0.1 $ - $ -
APCo 2.0 1.7 -
CSPCo 1.3 0.8 1.1
I&M 2.0 1.6 9.0
KPCo - 0.1 1.8
OPCo 0.8 8.6 3.4
PSO 1.1 - -
SWEPCo 1.6 0.1 -
TCC 2.0 0.1 -
|
Outstanding short-term debt for AEP Consolidated consisted of:
December 31,
-----------
2002 2001
---- ----
(in millions)
Balance Outstanding:
Notes Payable $1,747 $1,063
Commercial paper 1,417 2,948
------ ------
Total $3,164 $4,011
====== ======
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Sale of Receivables - AEP Credit
AEP Credit entered into a sale of receivables agreement with a group of banks and commercial paper conduits. Under the sale of receivables agreement, which expires May 28, 2003, AEP Credit sells an interest in the receivables it acquires to the commercial paper conduits and banks and receives cash. This transaction constitutes a sale of receivables in accordance with SFAS 140 allowing the receivables to be taken off of AEP Credit's balance sheet and allowing AEP Credit to repay any debt obligations. AEP has no ownership interest in the commercial paper conduits and does not consolidate these entities in accordance with GAAP. We continue to service the receivables. This off-balance sheet transaction was entered into to allow AEP credit to repay its outstanding debt obligations, continue to purchase the AEP operating companies' receivables, and accelerate its cash collections.
At December 31, 2002, the sale of receivables agreement provided the banks and commercial paper conduits would purchase a maximum of $600 million of receivables from AEP Credit, of which $454 million was outstanding. As collections from receivables sold occur and are remitted, the outstanding balance for sold receivables is reduced and as new receivables are sold, the outstanding balance of sold receivables increases. All of the receivables sold represented affiliate receivables. The commitment's new term under the sale of receivables agreement will remain at $600 million until May 28, 2003. AEP Credit maintains a retained interest in the receivables sold and this interest is pledged as collateral for the collection of the receivables sold. The fair value of the retained interest is based on book value due to the short-term nature of the accounts receivables less an allowance for anticipated uncollectible accounts.
AEP Credit purchases accounts receivable through purchase agreements with affiliated companies and, until the first quarter of 2002, with non-affiliated companies. As a result of the restructuring of electric utilities in the State of Texas, the purchase agreement between AEP Credit and Reliant Energy, Incorporated was terminated as of January 25, 2002 and the purchase agreement between AEP Credit and Texas-New Mexico Power Company, the last remaining non-affiliated company, was terminated on February 7, 2002. In addition, the purchase agreements between AEP Credit and its Texas affiliates AEP Texas Central Company (formerly Central Power and Light Company) and AEP Texas North Company (formerly West Texas Utilities Company) were terminated effective March 20, 2002.
Comparative accounts receivable information for AEP Credit:
Year Ended December 31,
----------------------
2002 2001
---- ----
(in millions)
Proceeds from Sale of
Accounts Receivable $5,513 $1,134
Accounts Receivable
Retained Interest Less
Uncollectible Accounts
and Amounts Pledged as
Collateral 76 143
Deferred Revenue from
Servicing Accounts
Receivable 1 5
Loss on Sale of Accounts
Receivable 4 8
Average Variable
Discount Rate 1.92% 2.28%
Retained Interest if 10%
Adverse change in
Uncollectible Accounts 74 142
Retained Interest if 20%
Adverse change in
Uncollectible Accounts 72 140
|
Historical loss and delinquency amount for the AEP System's customer accounts receivable managed portfolio:
Face Value
Year Ended December 31,
----------------------
2002 2001
(in millions)
Customer Accounts Receivable Retained $ 466 $ 343
Miscellaneous Accounts Receivable Retained 1,394 1,365
Allowance for Uncollectible Accounts Retained (119) (69)
------ ------
Total Net Balance Sheet Accounts Receivable 1,741 1,639
Customer Accounts Receivable Securitized (Affiliate) 454 560
Customer Accounts Receivable Securitized (Non-Affiliate) - 485
------ ------
Total Accounts Receivable managed $2,195 $2,684
====== ======
Net Uncollectible Accounts Written Off 48 72
------ ------
|
Customer accounts receivable retained and securitized for the domestic electric operating companies are managed by AEP Credit. Miscellaneous account receivable have been fully retained and not securitized.
At December 31, 2002, delinquent customer accounts receivable was $30 million.
Under the factoring arrangement certain of the registrant subsidiaries (excluding AEGCo) sell without recourse certain of their customer accounts receivable and accrued utility revenue balances to AEP Credit and are charged a fee based on AEP Credit financing costs, uncollectible accounts experience for each company's receivables and administrative costs. The costs of factoring customer accounts receivable is reported as an operating expense. The amount of factored accounts receivable and accrued utility revenues for each registrant subsidiary was as follows:
2002 2001
---- ----
Company (in millions)
-------
APCo $ 67.6 $ 61.2
CSPCo 114.3 105.7
I&M 103.7 94.9
KPCo 29.5 26.2
OPCo 109.8 100.2
PSO 83.7 70.7
SWEPCo 65.2 81.6
TCC - 145.3
TNC - 35.5
|
The fees paid by the registrant subsidiaries to AEP Credit for factoring customer accounts receivable were:
Year Ended December 31,
----------------------
2002 2001 2000
---- ---- ----
(in millions)
APCo $ 4.8 $ 5.2 $ -
CSPCo 15.8 15.2 10.8
I&M 7.4 8.5 6.8
KPCo 2.7 2.7 1.9
OPCo 11.4 12.8 8.4
PSO 7.2 9.6 8.3
SWEPCo 5.4 7.4 9.2
TCC 2.2 14.7 15.7
TNC 1.4 3.8 4.0
|
24. Unaudited Quarterly Financial Information:
The unaudited quarterly financial information for AEP Consolidated follows:
2002 Quarterly Periods Ended
----------------------------
March 31 June 30 Sept. 30 Dec. 31
-------- ------- -------- -------
(In Millions - Except
Per Share Amounts)
Revenues $3,169 $3,575 $3,870 $3,941
Operating Income (Loss) 459 427 782 (405)
Income (Loss) Before
Discontinued Operations,
Extraordinary Items
and Cumulative Effect 159 158 386 (682)
Net Income (Loss) (169) 62 425 (837)
Earnings (Loss) per Share
Before Discontinued
Operations,Extraordinary
Items and Cumulative
Effect* 0.49 0.49 1.14 (2.01)
Earnings (Loss) per
Share** (0.53) 0.19 1.25 (2.47)
2001 Quarterly Periods Ended
----------------------------
March 31 June 30 Sept. 30 Dec. 31
-------- ------- -------- -------
(In Millions - Except
Per Share Amounts)
Revenues $2,910 $3,259 $3,733 $2,865
Operating Income 521 622 824 215
Income Before
Discontinued Operations,
Extraordinary Items
and Cumulative Effect 230 251 399 37
Net Income 266 232 421 52
Earnings per Share Before
Discontinued Operations,
Extraordinary Items
and Cumulative Effect*** 0.72 0.77 1.23 0.12
Earnings per Share**** 0.83 0.72 1.31 0.16
|
* Amounts for 2002 do not add to $0.06 earnings per share before Discontinued Operations, Extraordinary Items and Cumulative Effect due to rounding and the dilutive effect of shares issued in 2002.
**Amounts for 2002 do not add to $(1.57) earnings per share due to rounding.
***Amounts for 2001 do not add to $2.85 earnings per share before Discontinued Operations, Extraordinary Items and Cumulative Effect due to rounding.
****Amounts for 2001 do not add to $3.01 earnings per share due to rounding.
The unaudited quarterly financial information for each AEP registrant subsidiary follows:
Quarterly Periods Ended AEGCo APCo CSPCo I&M KPCo
(in thousands)
2002
March 31
Operating Revenues $49,875 $462,605 $314,826 $352,235 $ 99,185
Operating Income 1,767 81,554 45,548 30,363 15,484
Income Before
Extraordinary Items 1,893 55,341 33,858 11,058 10,246
Net Income 1,893 55,341 33,858 11,058 10,246
June 30
Operating Revenues $53,356 $432,015 $343,813 $369,043 $ 92,164
Operating Income 1,504 65,224 58,040 19,865 9,550
Income Before
Extraordinary Items 1,718 46,608 51,721 7,494 5,246
Net Income 1,718 46,608 51,721 7,494 5,246
September 30
Operating Revenues $55,988 $474,282 $428,437 $421,472 $100,359
Operating Income 1,436 81,365 89,033 57,004 11,119
Income Before Extraordinary Items 1,947 53,947 76,117 35,312 5,994
Net Income 1,947 53,947 76,117 35,312 5,994
December 31
Operating Revenues $54,062 $445,568 $313,084 $384,014 $ 86,975
Operating Income 1,422 73,920 27,158 43,957 6,044
Income (Loss) Before
Extraordinary Items 1,994 49,596 19,477 20,128 (919)
Net Income (Loss) 1,994 49,596 19,477 20,128 (919)
|
Quarterly Periods Ended OPCo PSO SWEPCo TCC TNC
----------------------- ---- --- ------ --- ---
(in thousands)
2002
March 31
Operating Revenues $520,652 $148,986 $222,259 $278,910 $103,626
Operating Income 83,716 8,410 22,469 55,445 11,145
Income (Loss) Before Extraordinary Items 64,051 (1,648) 8,159 24,445 3,992
Net Income (Loss) 64,051 (1,648) 8,159 24,445 3,992
June 30
Operating Revenues $521,365 $158,330 $263,074 $360,391 $104,452
Operating Income 61,046 20,201 31,988 64,319 5,547
Income Before Extraordinary Items 55,348 11,620 18,155 33,535 675
Net Income 55,348 11,620 18,155 33,535 675
September 30
Operating Revenues $566,366 $230,098 $362,423 $546,260 $152,667
Operating Income (Loss) 97,210 50,710 60,254 118,204 (308)
Income (Loss) Before Extraordinary Items 80,258 41,002 45,794 93,383 (4,193)
Net Income (Loss) 80,258 41,002 45,794 93,383 (4,193)
December 31
Operating Revenues $504,742 $256,233 $236,964 $504,932 $ 89,995
Operating Income (Loss) 56,357 5,400 27,758 155,765 (8,513)
Income (Loss) Before
Extraordinary Items 20,366 (9,914) 10,884 124,578 (14,151)
Net Income (Loss) 20,366 (9,914) 10,884 124,578 (14,151)
|
Quarterly Periods Ended AEGCo APCo CSPCo I&M KPCo
----------------------- ----- ---- ----- --- ----
(in thousands)
2001
March 31
Operating Revenues $60,507 $501,204 $327,437 $387,813 $100,681
Operating Income 1,807 88,152 51,932 52,698 12,604
Income Before Extaordinary Items 1,980 61,787 37,671 32,363 7,075
Net Income 1,980 61,787 37,671 32,363 7,075
June 30
Operating Revenues $52,217 $430,412 $333,995 $382,234 $ 89,541
Operating Income 1,882 59,362 62,894 47,340 8,364
Income Before Extrodinary Items 2,063 36,419 47,418 27,374 2,742
Net Income 2,063 36,419 21,011 27,374 2,742
September 30
Operating Revenues $57,417 $434,450 $375,691 $398,457 $ 96,197
Operating Income 1,615 60,381 76,920 44,509 12,587
Income Before Extraordinary Items 2,051 30,317 65,318 25,064 5,312
Net Income 2,051 30,317 65,318 25,064 5,312
December 31
Operating Revenues $57,407 $418,193 $313,196 $358,493 $ 92,606
Operating Income 1,673 67,091 60,431 15,158 14,123
Income (Loss) Before
Extraordinary Items 1,781 33,295 41,493 (9,013) 6,436
Net Income (Loss) 1,781 33,295 37,876 (9,013) 6,436
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Quarterly Periods Ended OPCo PSO SWEPCo TCC TNC
----------------------- ---- --- ------ --- ---
(in thousands)
2001
March 31
Operating Revenues $552,503 $225,080 $267,117 $432,910 $141,649
Operating Income 64,756 8,340 33,986 64,152 5,392
Income (Loss) Before Extraordinary Items 53,397 (1,560) 19,869 35,031 891
Net Income (Loss) 53,397 (1,560) 19,869 35,031 891
June 30
Operating Revenues $512,196 $265,360 $271,748 $470,420 $139,228
Operating Income 47,067 21,942 32,649 82,351 12,428
Income Before Extraordinary Items 32,094 11,921 17,784 52,518 6,133
Net Income 10,579 11,921 17,784 52,518 6,133
September 30
Operating Revenues $535,535 $325,373 $331,441 $527,117 $181,433
Operating Income 69,668 59,914 60,194 112,598 17,745
Income Before Extraordinary Items 51,378 51,069 46,357 83,702 14,067
Net Income 51,378 51,069 46,357 83,702 14,067
December 31
Operating Revenues $497,871 $141,187 $231,020 $308,390 $ 94,148
Operating Income (Loss) 59,219 6,792 19,378 36,630 (2,175)
Income (Loss) Before
Extraordinary Items 28,924 (3,671) 5,357 13,536 (8,781)
Net Income (Loss) 32,091 (3,671) 5,357 11,027 (8,781)
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Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect for the fourth quarter 2002 decreased $896 million from the prior year due to the impairment loss and impairment value losses of approximately $1,188 million (pre-tax) to reduce the valuation of under-performing assets. In addition to the impairments that were recorded during the fourth quarter, a change in AEP's Accumulated Other Comprehensive Income (Loss) of $585 million for pension liability had a negative effect on each registrant's Consolidated Balance Sheets.
25. Trust Preferred Securities:
The following Trust Preferred Securities issued by the wholly-owned statutory business trusts of PSO, SWEPCo and TCC were outstanding at December 31, 2002 and December 31, 2001. They are classified on AEP's, PSO's, SWEPCo's and TCC's Balance Sheets as Certain Subsidiary Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of Such Subsidiaries. The Junior Subordinated Debentures mature on April 30, 2037. TCC reacquired 490,000 trust preferred units during 2001.
Units
Issued/ Description of
Outstanding Underlying
Business Trust Security At 12/31/02 Amount at December 31, Debentures of Registrant
-------------- -------- ----------- ---------------------- ------------------------
2002 2001
(in millions)
CPL Capital I 8.00%, Series A 5,450,000 $136 $136 TCC, $141 million,
8.00%, Series A
PSO Capital I 8.00%, Series A 3,000,000 75 75 PSO, $77 million,
8.00%, Series A
SWEPCo Capital I 7.875%, Series A 4,400,000 110 110 SWEPCO, $113 million,
---------- ---- ----
7.875%, Series A
12,850,000 $321 $321
========== ==== ====
|
Each of the business trusts is treated as a subsidiary of its parent company. The only assets of the business trusts are the subordinated debentures issued by their parent company as specified above. In addition to the obligations under their subordinated debentures, each of the parent companies has also agreed to a security obligation which represents a full and unconditional guarantee of its capital trust obligation.
26. Minority Interest in Finance Subsidiary:
In August 2001, AEP formed AEP Energy Services Gas Holding Co. II, LLC (SubOne) and Caddis Partners, LLC (Caddis). SubOne is a wholly owned consolidated subsidiary of AEP that was capitalized with the assets of Houston Pipe Line Company, Louisiana Interstate Gas Company (AEP subsidiaries) and $321.4 million of AEP Energy Services Gas Holding Company (AEP Gas Holding is an AEP subsidiary and parent of SubOne) preferred stock, that is convertible into AEP common stock at market price on a dollar-for-dollar basis. Caddis was capitalized with $2 million cash and a subscription agreement that represents an unconditional obligation to fund $83 million from SubOne and $750 million from Steelhead Investors LLC ("Steelhead" - non-controlling preferred member interest). As managing member, SubOne consolidates Caddis. Steelhead is an unconsolidated special purpose entity and has a capital structure of $750 million of which 3% is equity from investors with no relationship to AEP or any of its subsidiaries and 97% is debt from a syndicate of banks. The use of Steelhead allows AEP to limit its risk associated with Houston Pipe Line Company and Louisiana Intrastate Gas Company.
Under the provisions of the Caddis formation agreements, Steelhead receives a quarterly preferred return equal to an adjusted floating reference rate (4.784% and 4.413% for the quarters ended December 31, 2002 and 2001, respectively). Caddis has the right to redeem Steelhead's interest at any time.
The $750 million invested in Caddis by Steelhead was loaned to SubOne. This intercompany loan to SubOne is due August 2006, and is supported by the natural gas pipeline assets of SubOne, a cash reserve fund of SubOne and SubOne's $321.4 million of preferred stock in AEP Gas Holding. The preferred stock is convertible into AEP common stock upon the occurrence of certain events including AEP's stock price closing below $18.75 for ten consecutive trading days. AEP can elect not to have the transaction supported by such preferred stock if SubOne were to reduce its loan with Caddis by $225 million. The credit agreement between Caddis and SubOne contains covenants that restrict certain incremental liens and indebtedness, asset sales, investments, acquisitions, and distributions. The credit agreement also contains covenants that impose minimum financial ratios. Non-performance of these covenants may result in an event of default under the credit agreement. Through December 31, 2002, we have complied with the covenants contained in the credit agreement. In addition, a default under any other agreement or instrument relating to AEP and certain subsidiaries' debt outstanding in excess of $50 million is an event of default under the credit agreement.
The initial period of Steelhead's investment in Caddis is through August 2006. At the end of the initial period, Caddis will either reset Steelhead's return rate, re-market Steelhead's interests to new investors, redeem Steelhead's interests, in whole or in part including accrued return, or liquidate Caddis in accordance with the provisions of applicable agreements.
Steelhead has certain rights as a preferred member in Caddis. Upon the occurrence of certain events including a default in the payment of the preferred return, Steelhead's rights include: forcing a liquidation of Caddis and acting as the liquidator, and requiring the conversion of the AEP Gas Holding preferred stock into AEP common stock. If Steelhead exercised its rights to force Caddis to liquidate under these conditions, then AEP would evaluate whether to refinance at that time or relinquish the assets that support the intercompany loan to Caddis. Liquidation of Caddis could negatively impact AEP's liquidity.
Caddis and SubOne are each a limited liability company, with a separate existence and identity from its members, and the assets of each are separate and legally distinct from AEP. The results of operations, cash flows and financial position of Caddis and SubOne are consolidated with AEP for financial reporting purposes. Steelhead's investment in Caddis and payments made to Steelhead from Caddis are currently reported on AEP's consolidated statements of operation and consolidated balance sheets as Minority Interest in Finance Subsidiary.
AEP's maximum exposure to loss as a result of its involvement with Steelhead is $321.4 million of preferred stock, $83 million under the subscription agreement to Caddis for any losses incurred by Caddis and the cash reserve fund balance of $34 million (as of December 31, 2002) due Caddis for default under the intercompany loan agreement. AEP can reduce its maximum exposure related to the preferred stock by a reduction of $225 million of the intercompany loan.
As of December 31, 2002, we are continuing to review the application of FIN 46 as it relates to the Steelhead transaction.
27. Equity Units
In June 2002, AEP issued 6.9 million equity units at $50 per unit and received proceeds of $345 million. Each equity unit consists of a forward purchase contract and a senior note.
The forward purchase contracts obligate the holders to purchase shares of AEP common stock on August 16, 2005. The purchase price per equity unit is $50. The number of shares to be purchased under the forward purchase contract will be determined under a formula based upon the average closing price of AEP common stock near the stock purchase date. Holders may satisfy their obligation to purchase AEP common stock under the forward purchase contracts by allowing the senior notes to be remarketed or by continuing to hold the senior notes and using other resources as consideration for the purchase of stock. If the holders elect to allow the notes to be remarketed, the proceeds from the remarketing will be used to purchase a portfolio of U.S. treasury securities that the holders will pledge to AEP in order to meet their obligations under the forward purchase contracts.
The senior notes have a principal amount of $50 each and mature on August 16, 2007. The senior notes are the collateral that secures the holders' requirement to purchase common stock under the forward purchase contracts.
AEP will make quarterly interest payments on the senior notes at the initial annual rate of 5.75%. The interest rate can be reset through a remarketing, which is initially scheduled for May 2005. AEP will make contract adjustment payments to the purchaser at the annual rate of 3.50% on the forward purchase contracts. The present value of the contract adjustment payments has been recorded as a $31 million liability in Equity Unit Senior Notes offset by a charge to Paid-in Capital. Interest payments on the senior notes are reported as interest expense. Accretion of the contract adjustment payment liability is reported as interest expense.
AEP applies the treasury stock method to the equity units to calculate diluted earnings per share. This method of calculation theoretically assumes that the proceeds received as a result of the forward purchase contract are used to repurchase outstanding shares.
28. Jointly Owned Electric Utility Plant:
CSPCo, PSO, SWEPCo, TCC and TNC have generating units that are jointly owned with unaffiliated companies. Each of the participating companies is obligated to pay its share of the costs of any such jointly owned facilities in the same proportion as its ownership interest. Each AEP registrant subsidiary's proportionate share of the operating costs associated with such facilities is included in its statements of income and the investments are reflected in its balance sheets under utility plant as follows:
Company's Share
December 31,
---------------
2002 2001
-------------------------- ---------------------------
Percent Utility Construction Utility Construction
of Plant Work Plant Work
Ownership in Service in Progress in Service in Progress
--------- ------------ ------------- ------------ ------------
(in thousands) (in thousands)
CSPCo:
W.C. Beckjord Generating Station
(Unit No. 6) 12.5 $ 15,487 $ 49 $ 14,292 $ 884
Conesville Generating Station
(Unit No. 4) 43.5 81,960 279 81,697 494
J.M. Stuart Generating Station 26.0 197,276 44,865 193,760 27,758
Wm. H. Zimmer Generating Station 25.4 705,620 14,077 704,951 2,634
Transmission (a) 61,187 2,281 61,476 91
---------- ------- ---------- -------
$1,061,530 $61,551 $1,056,176 $31,861
========== ======= ========== =======
PSO:
Oklaunion Generating Station
(Unit No. 1) 15.6 $ 83,562 $ 777 $ 82,646 $ 634
========== ======= ========== ========
SWEPCo:
Dolet Hills Generating Station
(Unit No. 1) 40.2 $ 235,366 1,313 $ 234,747 $ 675
Flint Creek Generating Station
(Unit No. 1) 50.0 91,567 1,052 83,953 213
Pirkey Generating Station
(Unit No. 1) 85.9 451,136 2,197 439,430 10,577
---------- ------- ---------- -------
$ 778,069 $ 4,562 $ 758,130 $11,465
========== ======= ========== ========
TCC:
Oklaunion Generating Station
(Unit No. 1) 7.8 $ 38,055 $ 369 $ 37,728 $ 318
South Texas Project Generating
Station (Units No. 1 and 2) 25.2 2,364,359 43,887 2,360,452 41,571
---------- ------- ---------- -------
$2,402,414 $44,256 $2,398,180 $41,889
========== ======= ========== ========
TNC:
Oklaunion Generating Station
(Unit No. 1) 54.7 $ 277,946 $ 3,650 $ 279,419 $ 1,651
========== ======= ========== =======
(a) Varying percentages of ownership.
|
The accumulated depreciation with respect to each AEP registrant subsidiary's share of jointly owned facilities is shown below:
December 31,
-----------
2002 2001
---- ----
(in thousands)
CSPCo $436,683 $410,756
PSO 49,085 35,653
SWEPCo 450,057 392,728
TCC 927,193 863,130
TNC 102,542 100,430
|
29. Related Party Transactions
AEP System Power Pool
APCo, CSPCo, I&M, KPCo and OPCo are parties to the Interconnection Agreement, dated July 6, 1951, as amended (the Interconnection Agreement), defining how they share the costs and benefits associated with their generating plants. This sharing is based upon each company's "member-load-ratio," which is calculated monthly on the basis of each company's maximum peak demand in relation to the sum of the maximum peak demands of all five companies during the preceeding 12 months. In addition, since 1995, APCo, CSPCo, I&M, KPCo and OPCo have been parties to the AEP System Interim Allowance Agreement which provides, among other things, for the transfer of SO2 Allowances associated with transactions under the Interconnection Agreement. As part of AEP's restructuring settlement agreement filed with FERC, under certain conditions CSPCo and OPCo would no longer be parties to the Interconnection Agreement and certain other modifications to its terms would also be made.
Power marketing and trading transactions (trading activities) are conducted by the AEP Power Pool and shared among the parties under the Interconnection Agreement. Trading activities involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and the trading of electricity contracts including exchange traded futures and options and over-the-counter options and swaps. The majority of these transactions represent physical forward contracts in the AEP System's traditional marketing area and are typically settled by entering into offsetting contracts.
In addition, the AEP Power Pool enters into transactions for the purchase and sale of electricity options, futures and swaps, and for the forward purchase and sale of electricity outside of the AEP System's traditional marketing area.
PSO, SWEPCo, TCC, TNC and AEP Service Corporation are parties to a Restated and Amended Operating Agreement originally dated as of January 1, 1997 (CSW Operating Agreement). The CSW Operating Agreement requires the operating companies of the west zone to maintain specified annual planning reserve margins and requires the operating companies that have capacity in excess of the required margins to make such capacity available for sale to other operating companies 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. As part of AEP's restructuring settlement agreement filed with the FERC, under certain conditions TCC and TNC would no longer be parties to the CSW Operating Agreement.
AEP's System Integration Agreement provides for the integration and coordination of AEP's east and west zone operating subsidiaries, joint dispatch of generation within the AEP System, and the distribution, between the two operating zones, of costs and benefits associated with the System's generating plants. It is designed to function as an umbrella agreement in addition to the AEP Interconnection Agreement and the CSW Operating Agreement, each of which will continue to control the distribution of costs and benefits within each zone.
The following table shows the revenues derived from sales to the Pools and direct sales to affiliates for years ended December 31, 2002, 2001 and 2000:
APCo CSPCo I&M KPCo OPCo AEGCo
Related Party Revenues (in thousands)
2002 Sales to East System Pool $106,651 $42,986 $ 197,525 $ 22,369 $397,248 $ -
Sales to West System Pool 18,300 12,107 13,036 4,717 16,265 -
Direct Sales To East Affiliates 58,213 - - - 50,599 213,071
Direct Sales To West Affiliates - - - - - -
Other 3,313 2,109 3,577 878 1,090 -
-------- ------- ---------- -------- -------- --------
Total Revenues $186,477 $57,202 $ 214,138 $ 27,964 $465,202 $213,071
======== ======= ========== ======== ======== ========
2001 Sales to East System Pool $ 91,977 $44,185 $ 239,277 $ 34,735 $431,637 $ -
Sales to West System Pool 24,892 13,971 15,596 6,117 19,797 -
Direct Sales To East Affiliates 54,777 - - - 55,450 227,338
Direct Sales To West Affiliates (3,133) (1,705) (1,905) (744) (2,590) -
Other 2,772 11,060 2,071 2,258 7,072 -
-------- ------- ---------- -------- -------- --------
Total Revenues $171,285 $67,511 $ 255,039 $ 42,366 $511,366 $227,338
======== ======= ========== ======== ======== ========
2000 Sales to East System Pool $ 81,013 $36,884 $ 200,474 $ 36,554 $502,140 $ -
Sales to West System Pool 7,697 4,095 4,614 1,829 6,356 -
Direct Sales To East Affiliates 59,106 - - - 66,487 227,983
Direct Sales To West Affiliates 4,092 2,262 2,510 972 3,421 -
Other 2,770 6,124 2,710 2,466 4,043 -
-------- ------- ---------- -------- -------- --------
Total Revenues $154,678 $49,365 $ 210,308 $ 41,821 $582,447 $227,983
======== ======= ========== ======== ======== ========
|
PSO SWEPCo TCC TNC
Related Party Revenues (in thousands)
2002 Sales to East System Pool $ - $ - $ - $ -
Sales to West System Pool 674 1,334 18,416 1,280
Direct Sales To East Affiliates 611 270 366 (23)
Direct Sales To West Affiliates 6,047 75,674 956,751 228,404
Other 2,107 (4,979) 32,911 10,764
------- ------- ---------- --------
Total Revenues $ 9,439 $72,299 $1,008,444 $240,425
======= ======= ========== ========
2001 Sales to East System Pool $ 4 $ - $ - $ -
Sales to West System Pool 3,317 8,073 19,865 322
Direct Sales To East Affiliates 2,833 3,238 3,697 1,228
Direct Sales To West Affiliates 30,668 67,930 12,617 9,350
Other (51) (4) 5,583 7,781
------- ------- ---------- --------
Total Revenues $36,771 $79,237 $ 41,762 $ 18,681
======= ======= ========== ========
2000 Sales to East System Pool $ - $ - $ - $ -
Sales to West System Pool 7,323 5,546 23,421 194
Direct Sales To East Affiliates (1,990) (3,008) (3,348) (1,116)
Direct Sales To West Affiliates 21,995 62,178 12,516 7,645
Other (12,680) (1,592) 5,163 11,931
------- ------- ---------- --------
Total Revenues $14,648 $63,124 $ 37,752 $ 18,654
======= ======= ========== ========
|
The following table shows the purchased power expense incurred from purchases from the Pools and affiliates for the years ended December 31, 2002, 2001, and 2000:
APCo CSPCo I&M KPCo OPCo
Related Party Purchases (in thousands)
2002 Purchases from East System Pool $233,677 $309,999 $ 83,918 $ 68,846 $70,338
Purchases from West System Pool 337 219 237 86 297
Direct Purchases from East Affiliates 583 387 149,569 64,070 519
Direct Purchases from West Affiliates - - - - -
-------- -------- -------- -------- -------
Total Purchases $234,597 $310,605 $233,724 $133,002 $71,154
======== ======== ======== ======== =======
2001 Purchases from East System Pool $346,582 $292,034 $ 79,030 $ 61,816 $62,350
Purchases from West System Pool 296 165 185 72 235
Direct Purchases from East Affiliates - - 159,022 68,316 -
Direct Purchases from West Affiliates - - - - -
-------- -------- -------- -------- -------
Total Purchases $346,878 $292,199 $238,237 $130,204 $62,585
======== ======== ======== ======== =======
2000 Purchases from East System Pool $355,305 $287,482 $106,644 $ 58,150 $50,339
Purchases from West System Pool 455 260 285 108 390
Direct Purchases from East Affiliates - - 158,537 69,446 -
Direct Purchases from West Affiliates 14 8 9 3 12
-------- -------- -------- -------- -------
Total Purchases $355,774 $287,750 $265,475 $127,707 $50,741
======== ======== ======== ======== =======
|
PSO SWEPCo TCC TNC
Related Party Purchases (in thousands)
2002 Purchases from East System Pool $ 343 $ - $ - $ -
Purchases from West System Pool 874 (456) 1,366 15,475
Direct Purchases from East Affiliates 29,029 17,242 8,236 2,669
Direct Purchases from West Affiliates 59,208 25,236 13,804 19,438
------- ------- ------- -------
Total Purchases $89,454 $42,022 $23,406 $37,582
======= ======= ======= =======
2001 Purchases from East System Pool $ 1,327 $ - $ - $ 4
Purchases from West System Pool 5,877 3,810 415 11,689
Direct Purchases from East Affiliates 1,951 2,352 12,657 4,614
Direct Purchases from West Affiliates 34,603 9,696 45,569 40,349
------- ------- ------- -------
Total Purchases $43,758 $15,858 $58,641 $56,656
======= ======= ======= =======
2000 Purchases from East System Pool $20,100 $ - $ - $ -
Purchases from West System Pool 5,386 4,379 1,696 18,444
Direct Purchases from East Affiliates 2,117 695 251 71
Direct Purchases from West Affiliates 33,185 8,264 30,644 39,258
------- ------- ------- -------
Total Purchases $60,788 $13,338 $32,591 $57,773
======= ======= ======= =======
|
The above summarized related party revenues and expenses are reported in their entirety, without elimination, and are presented as operating revenues affiliated and purchased power affiliated on the statements of operations of each AEP Power Pool member. Since all of the above pool members are included in AEP's consolidated results, the above summarized related party transactions are eliminated in total in AEP's consolidated revenues and expenses.
AEP System Transmission Pool
APCo, CSPCo, I&M, KPCo and OPCo are parties to the Transmission Agreement, dated April 1, 1984, as amended (the Transmission Agreement), defining how they share the costs associated with their relative ownership of the extra-high-voltage transmission system (facilities rated 345 kv and above) and certain facilities operated at lower voltages (138 kv and above). Like the Interconnection Agreement, this sharing is based upon each company's "member-load-ratio."
The following table shows the net (credits) or charges allocated among the parties to the Transmission Agreement during the years ended December 31, 2002, 2001 and 2000:
2002 2001 2000
---- ---- ----
(in thousands)
APCo $(13,400) $ (3,100) $ (3,400)
CSPCo 42,200 40,200 38,300
I&M (36,100) (41,300) (43,800)
KPCo (5,400) (4,600) (6,000)
OPCo 12,700 8,800 14,900
|
PSO, SWEPCo, TCC, TNC and AEP Service Corporation are parties to a Transmission Coordination Agreement originally dated as of January 1, 1997 (TCA). The TCA established a coordinating committee, which is charged with the responsibility of overseeing the coordinated planning of the transmission facilities of the west zone operating subsidiaries, including the performance of transmission planning studies, the interaction of such subsidiaries with independent system operators (ISO) and other regional bodies interested in transmission planning and compliance with the terms of the Open Access Transmission Tariff (OATT) filed with the FERC and the rules of the FERC relating to such tariff.
Under the TCA, the west zone operating subsidiaries have delegated to AEP Service Corporation the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. The TCA also provides for the allocation among the west zone operating subsidiaries of revenues collected for transmission and ancillary services provided under the OATT.
The following table shows the net (credits) or charges allocated among the parties to the Transmission Agreement during the years ended December 31, 2002, 2001 and 2000:
2002 2001 2000
---- ---- ----
(in thousands)
PSO $(4,200) $ (4,000) $ (3,300)
SWEPCo (5,000) (5,400) (5,900)
TCC 3,600 3,900 3,400
TNC 5,600 5,500 5,800
|
AEP's System Transmission Integration Agreement provides for the integration and coordination of the planning, operation and maintenance of the transmission facilities of AEP's east and west zone operating subsidiaries. Like the System Integration Agreement, the System Transmission Integration Agreement functions as an umbrella agreement in addition to the AEP Transmission Agreement and the Transmission Coordination Agreement. The System Transmission Integration Agreement contains two service schedules that govern:
o The allocation of transmission costs and revenues.
o The allocation of third-party transmission costs and revenues and
System dispatch costs.
The Transmission Integration Agreement anticipates that additional service schedules may be added as circumstances warrant.
Unit Power Agreements and Other
A unit power agreement between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) such amounts, as when added to amounts received by AEGCo from any other sources, will be at least sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by FERC, currently 12.16%. The I&M Power Agreement will continue in effect until the expiration of the lease term of Unit 2 of the Rockport Plant 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 in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KPCo unit power agreement expires on December 31, 2004. This unit power agreement extends until December 31, 2009 for Unit 1 and until December 7, 2022 for Unit 2 if AEP's restructuring settlement agreement filed with the FERC becomes operative.
APCo and OPCo, jointly own two power plants. The costs of operating these facilities are apportioned between the owners based on ownership interests. Each company's share of these costs is included in the appropriate expense accounts on each company's consolidated statements of income. Each company's investment in these plants is included in electric utility plant on its consolidated balance sheets.
I&M provides barging services to AEGCo, APCo and OPCo. I&M records revenues from barging services as nonoperating income. AEGCo, APCo and OPCo record costs paid to I&M for barging services as fuel expense. The amount of affiliated revenues and affiliated expenses were:
Year Ended December 31,
2002 2001 2000
---- ---- ----
Company (in millions)
I&M - revenues $34.3 $30.2 $23.5
AEGCo - expense 7.8 8.5 8.8
APCo - expense 12.8 11.5 7.8
OPCo - expense 7.9 10.2 6.9
Memco - expense 5.7 - -
AEP Energy Services 0.1 - -
|
American Electric Power Service Corporation (AEPSC) provides certain managerial and professional services to AEP System companies. The costs of the services are billed to its affiliated companies by AEPSC on a direct-charge basis, whenever possible, and on reasonable bases of proration for shared services. The billings for services are made at cost and include no compensation for the use of equity capital, which is furnished to AEPSC by AEP Co., Inc. Billings from AEPSC are capitalized or expensed depending on the nature of the services rendered. AEPSC and its billings are subject to the regulation of the SEC under the PUHCA.
30. Subsequent Events (Unaudited):
Common Stock Offering - On February 27, 2003, AEP priced its offering of 50 million shares of common stock at a public offering price of $20.95 per share. AEP has granted the underwriters an option to purchase an additional 7.5 million shares of common stock to cover overallotments. The net proceeds from the sale of these securities will be used to reduce debt and for general corporate purposes.
Senior Notes Offering - During March 2003, AEP completed an offering of 5.375% Series C Senior Notes which have a principal amount of $500 million and a maturity date of March 15, 2010. The net proceeds from the offering will be used to repay or redeem current maturities of long-term debt, a portion of our minority interest in a financing subsidiary, and for general corporate purposes.
REGISTRANTS' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, ACCOUNTING POLICIES AND OTHER MATTERS
The following is a combined presentation of management's discussion and analysis of financial condition, accounting policies and other matters for AEP and its registrant subsidiaries. Management's discussion and analysis of results of operations for AEP and each of its subsidiary registrants is presented with their financial statements earlier in this document. The following is a list of sections of management's discussion and analysis of financial condition, accounting policies and other matters and the registrant to which they apply:
Financial Condition AEP, AEGCo, APCo,
CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo,
TCC, TNC
Critical Accounting AEP, AEGCo, APCo,
Policies CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo,
TCC, TNC
Market Risks AEP, AEGCo, APCo,
CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo,
TCC, TNC
Industry Restructuring AEP, APCo, CSPCo
I&M, KPCo, OPCo,
PSO, SWEPCo, TCC,
TNC
Litigation AEP, AEGCo, APCo,
CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo,
TCC, TNC
Environmental Concerns AEP, AEGCo, APCo,
and Issues CSPCo, I&M, KPCo
OPCo, PSO,
SWEPCo, TCC, TNC
Other Matters AEP, AEGCo, APCo,
CSPCo, I&M, KPCo,
OPCo, PSO,
SWEPCo, TCC, TNC
|
Financial Condition
We measure our financial condition by the strength of the balance sheets and the liquidity provided by cash flows and earnings.
Balance sheet capitalization ratios and cash flow ratios are principal determinants of our credit quality.
Credit Ratings
The rating agencies have been conducting credit reviews of AEP and its registrant subsidiaries. The agencies are also reviewing most companies in the energy sector due to issues which impact the entire industry, not only AEP and its subsidiaries.
In February 2003, Moody's Investors Service (Moody's) completed their review of AEP and its rated subsidiaries. The results of that review were downgrades of the following ratings for unsecured debt: AEP to Baa3 from Baa2, 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 and the placement of five of the registrant subsidiaries on negative outlook. With the completion of the reviews, Moody's has placed AEP and its rated subsidiaries on stable outlook.
In February 2003, Standard & Poor's placed AEP's senior unsecured debt and commercial paper ratings on credit watch with negative implications, and did the same with the subsidiaries. S&P indicated that resolution regarding these actions would come within a short time (see additional discussion in Financing - Credit Ratings in Item 1 of Part I).
In 2002, Fitch Ratings Service downgraded both PSO and SWEPCo from A to A- for the senior unsecured notes. Fitch has AEP and its subsidiaries on stable outlook and the commercial paper rating is stable at F-2 (see additional discussion in Financing - Credit Ratings in Item 1 of Part I).
Current ratings of AEP's subsidiaries' first mortgage bonds are listed in the following table:
Company Moody's S&P Fitch ------- ------- --- ----- APCo Baa1 BBB+ A- CSPCo A3 BBB+ A I&M Baa1 BBB+ BBB+ KPCo Baa1 BBB+ BBB+ OPCo A3 BBB+ A- PSO A3 BBB+ A SWEPCO A3 BBB+ A TCC Baa1 BBB+ A TNC A3 BBB+ A |
Current short-term ratings are as follows:
Company Moody's S&P Fitch ------- ------- --- ----- AEP P-3 A-2 F-2 |
The current ratings for senior unsecured debt are listed in the following table:
Company Moody's S&P Fitch ------- ------- --- ----- AEP Baa3 BBB+ BBB+ AEP Resources* Baa3 BBB+ BBB+ APCo Baa2 BBB+ BBB+ CSPCo A3 BBB+ A- I&M Baa2 BBB+ BBB KPCo Baa2 BBB+ BBB OPCo A3 BBB+ BBB+ PSO Baa1 BBB+ A- SWEPCO Baa1 BBB+ A- TCC Baa2 BBB+ A- TNC Baa1 BBB+ A- |
* The rating is for a series of senior notes issued with a Support Agreement from AEP.
AEP's common equity to total capitalization declined to 32% in 2002 from 36% in 2001 and 37% in 2000. Total capitalization includes long-term debt due within one year, equity unit senior notes, minority interest and short-term debt. Preferred stock at 1% remained unchanged. In 2002, long-term debt including equity unit senior notes and trust preferred securities increased from 43% to 50% while Short-term Debt decreased from 17% to 14% and Minority Interest in Finance Subsidiary remained unchanged at 3%. In 2001 Long-term Debt remained unchanged while Short-term Debt decreased from 20% to 17% and Minority Interest in Finance Subsidiary increased to 3%. In 2002, 2001 and 2000, AEP did not issue any shares of common stock to meet the requirements of the Dividend Reinvestment and Direct Stock Purchase Plan and the Employee Savings Plan. Common stock was issued in 2002 for stock options exercised and under an equity offering (discussed in Financing Activity).
Liquidity, or access to cash, has become a more critical factor in determining the financial stability of a company due to volatility in wholesale power markets and the potential limitations that credit rating downgrades place on a company's ability to raise capital. Management is committed to preserving an adequate liquidity position and addressing AEP and its subsidiaries' financial needs in 2003.
As of December 31, 2002, we had an available liquidity position of $3.5 billion as illustrated in the table below:
Commercial Paper Backup
Lines of Credit $2,500* 5/03
Commercial Paper Backup
Lines of Credit 1,000 5/05
Corporate Separation
Revolving Credit 1,725 4/03
Euro Revolving Credit
Facilities 315 10/03
------
Total 5,540
Cash
Liquidity Reserve 1,000**
------
Total Credit Facilities
and Cash 6,540
Less: Commercial Paper
Outstanding
Corporate Separation 1,415
Loans 1,300
Euro Revolving
Credit Loans 305
------
Total Available Liquidity $3,520
======
|
* Contains one year term-out provision. ** Unrestricted and excludes $213 million of operational cash on hand.
AEP and its subsidiaries' goal for 2003 is to use cash from operations to fund capital expenditures, dividend payments and working capital requirements. 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.
Short-term funding comes from the parent company's commercial paper program and revolving credit facilities. Proceeds are loaned to the subsidiaries through intercompany notes. AEP and its subsidiaries also operate a non-utility and utility money pool to minimize the AEP System's external short-term funding requirements and sell accounts receivable to provide liquidity for the domestic electric subsidiaries. The commercial paper program is backed by $3.5 billion in bank facilities of which $1 billion matures in May 2005. The remaining $2.5 billion matures in May 2003 and has a one-year term-out provision at AEP's option. At December 31, 2002, approximately $1.4 billion of commercial paper was outstanding. A portion of the commercial paper balance is related to funding of debt maturities of the Ohio and Texas subsidiaries pending a permanent financing program. The Ohio and Texas subsidiaries issued $2,025 million of senior unsecured notes in February 2003 with maturity dates ranging from 2005 to 2033. The commercial paper balance outstanding decreased in early 2003 due to repayment with proceeds from these issuances.
AEP also has a $1.725 billion bank facility maturing in April 2003 that is available for debt refinancing. At December 31, 2002, $1.3 billion was outstanding under that facility. With the issuance of the permanent financing for the Ohio and Texas subsidiaries mentioned above, this facility was repaid and cancelled in February 2003.
AEP also has revolving credit facilities in place for 300 million Euros to support the wholesale business in Europe. At December 31, 2002, the majority of these facilities were drawn.
AEP also maintains a minimum $300 million cash liquidity reserve fund to support its marketing operations in the U.S. and keeps additional cash on hand as market conditions change. At December 31, 2002, AEP had $1 billion of cash available for liquidity.
On December 6, 2002, we closed a 364-day, $425 million facility and used it to partially repay the maturing interim financing for the U.K. generation plants (FFF). The facility was secured by a pledge of the shares of AEP companies in the FFF ownership chain and guaranteed by the parent company. A portion ($213 million) of the facility is due in May 2003. The remainder of the FFF interim financing was repaid using a combination of existing funds and draws against the Euro revolving credit facilities.
In total, we had approximately $6.5 billion in liquidity sources of which $3.5 billion were unused and available at December 31, 2002.
During 2002, cash flow from operations was $1.7 billion, including $21 million from Net Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect, approximately $1.3 billion from depreciation, amortization, deferred taxes, and deferred investment tax credits, approximately $1.1 billion associated with asset, investment value and other impairments, offset by additional working capital requirements of approximately $700 million. These additional working capital requirements reflect the one time impact of the discontinuance of the sale of accounts receivable for Texas companies and billing delays related to the transition to customer choice in Texas, higher margin requirements for gas trading, seasonal fuel inventory growth, and other miscellaneous items. Construction expenditures were $1.7 billion including major expenditures for emission control technology on several coal-fired generating units (see discussion in Note 9). Dividends on common stock were $793 million. Cash from operations, proceeds from the sale of SEEBOARD, CitiPower and the Texas REPs and the issuance of common stock, common equity units, 15-year notes for a wind generation project and transition funding bonds provided funds to reduce debt, fund construction and pay dividends.
During 2001, AEP's cash flow from operations was $2.8 billion, including $885 million from Net Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect and $1.4 billion from depreciation, amortization, deferred taxes and deferred investment tax credits. Capital expenditures including acquisitions were $3.9 billion and dividends on common stock were $773 million. Cash from operations less dividends on common stock financed 51% of capital expenditures.
During 2001, the proceeds of AEP's $1.25 billion global notes issuance and proceeds from the sale of a U.K. distribution company and two generating plants provided cash to purchase assets, fund construction, retire debt and pay dividends. Major construction expenditures include amounts for a wind generating facility and emission control technology on several coal-fired generating units. Asset purchases include HPL, coal mines, a barge line, a wind generating facility and two coal-fired generating plants in the U.K. These acquisitions accounted for the increase in total debt during 2001. Long-term funding arrangements for specific assets are often complex and typically not completed until after the acquisition.
The loss for 2002 resulted in a negative dividend payout ratio of 153% reflecting the losses on sale and impairments of assets. Earnings for 2001 resulted in a dividend payout ratio of 80%, a considerable improvement over the 289% payout ratio in 2000. The abnormally high ratio in 2000 was the result of the adverse impact on 2000 earnings from the Cook Plant extended outage and related restart expenditures, merger costs and the write-off related to COLI and non-regulated subsidiaries.
AEP and its subsidiaries generally use short-term borrowings to fund property acquisitions and construction until long-term funding mechanisms are arranged. Some acquisitions of existing business entities include the assumption of their outstanding debt and certain liabilities. Sources of long-term funding include issuance of AEP common stock, minority interest or long-term debt and sale-leaseback or leasing arrange-ments. The domestic electric subsidiaries generally issue short-term debt to provide for interim financing of capital expenditures that exceed internally generated funds and periodically reduce their outstanding short-term debt through issuances of long-term debt and additional capital contributions from their parent company.
AEP's revolving credit agreements include covenants that require performance of
certain actions, including maintaining specified financial ratios.
Non-performance of these covenants may result in an event of default under these
credit agreements. At December 31, 2002, AEP complied with the covenants
contained in these credit agreements. In addition, a default under any other
agreement or instrument relating to debt outstanding in excess of $50 million is
an event of default under these credit agreements. An event of default under
these credit agreements would cause all amounts outstanding thereunder to be
immediately payable.
Common Stock
In June 2002, AEP issued 16 million shares of common stock at $40.90 per share through an equity offering and received net proceeds of $634 million. Proceeds from the sale of equity units and common stock were used to pay down short-term debt and establish a cash liquidity reserve fund.
Equity Units
In June 2002, AEP issued 6.9 million equity units at $50 per unit ($345 million). See Note 27 for additional information.
Debt
In February 2002, TCC issued $797 million of securitization notes that were approved by the PUCT as part of Texas restructuring to recover generation related regulatory assets. The proceeds were used to reduce TCC's debt and equity.
In April 2002, AEP closed on a bridge loan facility consisting of a $1.125 million 364-day revolving credit facility and a $600 million 364-day term loan facility to prepare for corporate separation. At year-end, $600 million was borrowed under the term loan facility and $700 million was borrowed under the revolving credit facility. Those amounts were repaid and the facility terminated when bonds were issued by CSPCo, OPCo, TCC and TNC in February 2003.
In February 2003, CSPCo issued $250 million of unsecured senior notes due 2013 at a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a coupon of 6.60%. OPCo issued $250 million of unsecured senior notes due 2013 at a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a coupon of 6.60%. TCC issued $100 million of unsecured senior notes due 2005 at a variable rate, $150 million of unsecured senior notes due 2005 at a coupon of 3.0%, $275 million of unsecured senior notes due 2013 at a coupon of 5.50% and $275 million of unsecured senior notes due 2033 at a coupon of 6.65%. TNC issued $225 million of unsecured senior notes due 2013 at a coupon of 5.50%. The use of proceeds from the above bonds was repayment of the bridge loan facility mentioned above, repayment of short-term debt, and for general corporate purposes.
In 2002, the following issuances were completed by the subsidiaries of AEP:
------------ ---------------- ----------- ----------- -------
Principal
Amount
(in
mil-
Com-pany Type of Debt lions) Interest Due
Rate Date
------------ ---------------- ----------- ----------- -------
------------ ---------------- ----------- ----------- -------
Senior
APCo Unsecured Notes $450 4.80% 2005
------------ ---------------- ----------- ----------- -------
------------ ---------------- ----------- ----------- -------
Senior
APCo Unsecured Notes 200 4.32%* 2007
------------ ---------------- ----------- ----------- -------
------------ ---------------- ----------- ----------- -------
Installment
I&M Purchase 50 4.90% 2025
Contracts
------------ ---------------- ----------- ----------- -------
------------ ---------------- ----------- ----------- -------
Senior
I&M Unsecured Notes 150 6.0% 2032
------------ ---------------- ----------- ----------- -------
------------ ---------------- ----------- ----------- -------
Senior
I&M Unsecured Notes 100 6 3/8% 2012
------------ ---------------- ----------- ----------- -------
------------ ---------------- ----------- ----------- -------
Senior
KPCo Unsecured Notes 125 5.50% 2007
------------ ---------------- ----------- ----------- -------
------------ ---------------- ----------- ----------- -------
Senior
KPCo Unsecured Notes 80 4.32%* 2007
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Senior
KPCo Unsecured Notes 70 4.37%* 2007
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Senior
PSO Unsecured Notes 200 6.00% 2032
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Senior
SWEPCo Unsecured Notes 200 4.50% 2005
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Other Notes Payable 121 6.20%- 2017
Subsid-iaries 6.60%
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------------ ---------------- ----------- ----------- -------
Other Revolving 305 Variable 2003
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The subsidiaries also redeemed approximately $2 billion of long-term debt in 2002. See the Schedule of Long-term Debt for each registrant in sections B to K for details.
AEP uses money pools to meet the short-term borrowings for the majority of its subsidiaries In addition, AEP also funds the short-term debt requirements of other subsidiaries that are not included in the money pool. As of December 31, 2002, AEP had credit facilities totaling $3.5 billion to support its commercial paper program. At December 31, 2002, AEP had $1.4 billion outstanding in short-term borrowings subject to these credit facilities.
AEP Credit purchases, without recourse, the accounts receivable of most of the domestic utility operating companies. AEP Credit's financing for the purchase of receivables changed in December 2001. Starting December 31, 2001, AEP Credit entered into a sale of receivables agreement. The agreement allows AEP Credit to sell certain receivables and receive cash meeting the requirements of SFAS 140 for the receivables to be removed from AEP's and the subsidiaries' Balance Sheets. At December 31, 2002, AEP Credit had $454 million sold under this agreement. See Note 23 for further discussion.
Off-balance Sheet and Minority Interest Arrangements
AEP and its subsidiaries enter into off-balance sheet arrangements for various reasons ranging from accelerating cash collections, reducing operational expense to spreading risk of loss to third parties. The following identifies significant off-balance sheet arrangements:
Power Generation Facility
AEP has entered into agreements with Katco Funding L.P. (Katco), an unrelated unconsolidated special purpose entity. Katco has an aggregate financing commitment of $525 million and a capital structure of which 3% is equity from investors with no relationship to AEP or any of its subsidiaries and 97% is debt from a syndicate of banks. Katco was formed to develop, construct, finance and lease a power generation facility to AEP. Katco will own the power generation facility and lease it to AEP after construction is completed. The lease will be accounted for as an operating lease (see Note 22), therefore neither the facility nor the related obligations are reported on AEP's Consolidated Balance Sheets. Payments under the operating lease are expected to commence in the first quarter of 2004. AEP will in turn sublease the facility to Dow Chemical Company (DOW), which will use the energy produced by the facility and sell excess energy. AEP has agreed to purchase the excess energy from DOW for resale. The use of Katco allows AEP to limit its risk associated with the power generation facility once the construction phase has been completed.
AEP is the construction agent for Katco, and is responsible for completing construction by December 31, 2003, subject to unforeseen events beyond AEP's control.
In the event the project is terminated before completion of construction, AEP has the option to either purchase the facility for 100% of project costs or terminate the project and make a payment to Katco for 89.9% of project costs.
The operating lease between Katco and AEP commences on the commercial operation date of the facility and continues until November 2006. The lease contains extension options subject to the approval of Katco, and if all extension options were exercised, the total term of the lease would be 30 years. AEP's lease payments to Katco are sufficient for Katco to make required debt payments and provide a return to the investors of Katco. At the end of each lease term, AEP may renew the lease at fair market value subject to Katco's approval, purchase the facility at its original construction cost, or sell the facility, on behalf of Katco, to an independent third party. If the facility is sold and the proceeds from the sale are insufficient to repay Katco, AEP may be required to make a payment to Katco for the difference between the proceeds from the sale and the obligations of Katco, up to 82% of the project's cost. AEP has guaranteed a portion of the obligations of its subsidiaries to Katco during the construction and post-construction periods.
As of December 31, 2002, project costs subject to these agreements totaled $360 million, and total costs for the completed facility are expected to be approximately $510 million. For the 30-year extended lease term, the lease rental is a variable rate obligation indexed to three-month LIBOR. Consequently as market interest rates increase, the payments under this operating lease will also increase. Annual payments of approximately $12 million represent future minimum payments during the initial term calculated using the indexed LIBOR rate (1.38% at December 31, 2002). The Power Generation Facility collateralizes the debt obligation of Katco. AEP's maximum exposure to loss as a result of its involvement with Katco is 100% during the construction phase and up to 82% once the construction is completed. Maximum loss is deemed to be remote due to the collateralization.
It is reasonably possible that AEP will consolidate Katco in the third quarter of 2003, as a result of the issuance of FASB Interpretation No. 46 "Consolidation of Variable Interest Entities" (FIN 46). Upon consolidation, AEP would record the assets, liabilities, depreciation expense, minority interest and debt interest expense. AEP would eliminate operating lease expense. The sublease to DOW would not be affected by this consolidation.
The lease payments and the guarantee of construction commitments are included in the Other Commercial Commitments table below.
In August 2001, AEP formed AEP Energy Services Gas Holding Co. II, LLC (SubOne) and Caddis Partners, LLC (Caddis). SubOne is a wholly owned consolidated subsidiary of AEP that was capitalized with the assets of Houston Pipe Line Company, Louisiana Interstate Gas Company (AEP subsidiaries) and $321.4 million of AEP Energy Services Gas Holding Company (AEP Gas Holding is an AEP subsidiary and parent of SubOne) preferred stock, that is convertible into AEP common stock at market price on a dollar-for-dollar basis. Caddis was capitalized with $2 million cash and a subscription agreement that represents an unconditional obligation to fund $83 million from SubOne and $750 million from Steelhead Investors LLC ("Steelhead" - non-controlling preferred member interest). As managing member, SubOne consolidates Caddis. Steelhead is an unconsolidated special purpose entity and has a capital structure of $750 million of which 3% is equity from investors with no relationship to AEP or any of its subsidiaries and 97% is debt from a syndicate of banks. The use of Steelhead allows AEP to limit its risk associated with Houston Pipe Line Company and Louisiana Intrastate Gas Company.
Under the provisions of the Caddis formation agreements, Steelhead receives a quarterly preferred return equal to an adjusted floating reference rate (4.784% and 4.413% for the quarters ended December 31, 2002 and 2001, respectively). Caddis has the right to redeem Steelhead's interest at any time.
The $750 million invested in Caddis by Steelhead was loaned to SubOne. This intercompany loan to SubOne is due August 2006, and is supported by the natural gas pipeline assets of SubOne, a cash reserve fund of SubOne and SubOne's $321.4 million of preferred stock in AEP Gas Holding. The preferred stock is convertible into AEP common stock upon the occurrence of certain events including AEP's stock price closing below $18.75 for ten consecutive trading days. AEP can elect not to have the transaction supported by such preferred stock if SubOne were to reduce its loan with Caddis by $225 million. The credit agreement between Caddis and SubOne contains covenants that restrict certain incremental liens and indebtedness, asset sales, investments, acquisitions, and distributions. The credit agreement also contains covenants that impose minimum financial ratios. Non-performance of these covenants may result in an event of default under the credit agreement. Through December 31, 2002, we have complied with the covenants contained in the credit agreement. In addition, a default under any other agreement or instrument relating to AEP and certain subsidiaries' debt outstanding in excess of $50 million is an event of default under the credit agreement.
The initial period of Steelhead's investment in Caddis is through August 2006. At the end of the initial period, Caddis will either reset Steelhead's return rate, re-market Steelhead's interests to new investors, redeem Steelhead's interests, in whole or in part including accrued return, or liquidate Caddis in accordance with the provisions of applicable agreements.
Steelhead has certain rights as a preferred member in Caddis. Upon the occurrence of certain events including a default in the payment of the preferred return, Steelhead's rights include: forcing a liquidation of Caddis and acting as the liquidator, and requiring the conversion of the AEP Gas Holding preferred stock into AEP common stock. If Steelhead exercised its rights to force Caddis to liquidate under these conditions, then AEP would evaluate whether to refinance at that time or relinquish the assets that support the intercompany loan to Caddis. Liquidation of Caddis could negatively impact AEP's liquidity.
Caddis and SubOne are each a limited liability company, with a separate existence and identity from its members, and the assets of each are separate and legally distinct from AEP. The results of operations, cash flows and financial position of Caddis and SubOne are consolidated with AEP for financial reporting purposes. Steelhead's investment in Caddis and payments made to Steelhead from Caddis are currently reported on AEP's income statement and balance sheet as Minority Interest in Finance Subsidiary.
AEP's maximum exposure to loss as a result of its involvement with Steelhead is $321.4 million of preferred stock, $83 million under the subscription agreement to Caddis for any losses incurred by Caddis and the cash reserve fund balance of $34 million (as of December 31, 2002) due Caddis for default under the intercompany loan agreement. AEP can reduce its maximum exposure related to the preferred stock by a reduction of $225 million of the intercompany loan.
As of December 31, 2002, management is continuing to review the application of FIN 46 as it relates to the Steelhead transaction.
AEP Credit entered into a sale of receivables agreement with a group of banks and commercial paper conduits. Under the sale of receivables agreement, which expires May 28, 2003, AEP Credit sells an interest in the receivables it acquires to the commercial paper conduits and banks and receives cash. This transaction constitutes a sale of receivables in accordance with SFAS 140 allowing the receivables to be taken off of AEP Credit's balance sheet and allowing AEP Credit to repay any debt obligations. AEP has no ownership interest in the commercial paper conduits and does not consolidate these entities in accordance with GAAP. We continue to service the receivables. This off-balance sheet transaction was entered into to allow AEP Credit to repay its outstanding debt obligations, continue to purchase the AEP operating companies' receivables, and accelerate its cash collections.
At December 31, 2002, the sale of receivables agreement provided the banks and commercial paper conduits would purchase a maximum of $600 million of receivables from AEP Credit, of which $454 million was outstanding. As collections from receivables sold occur and are remitted, the outstanding balance for sold receivables is reduced and as new receivables are sold, the outstanding balance of sold receivables increases. All of the receivables sold represented affiliate receivables. The commitment's new term under the sale of receivables agreement will remain at $600 million until May 28, 2003. AEP Credit maintains a retained interest in the receivables sold and this interest is pledged as collateral for the collection of the receivables sold. The fair value of the retained interest is based on book value due to the short-term nature of the accounts receivables less an allowance for anticipated uncollectible accounts.
See Note 23 "Lines of Credit and Sale of Receivables" for further disclosure.
OPCo has entered into an agreement with JMG Funding LLP (JMG) an unrelated unconsolidated special purpose entity. JMG has a capital structure of which 3% is equity from investors with no relationship to AEP or any of its subsidiaries and 97% is debt from pollution control bonds and other bonds. JMG owns the Gavin Scrubber and leases it to OPCo. The lease is accounted for as an operating lease with the payment obligations included in the lease footnote. Payments under the operating lease are based on JMG's cost of financing (both debt and equity) and include an amortization component plus the cost of administration. Neither OPCo nor AEP has an ownership interest in JMG and does not guarantee JMG's debt.
At any time during the lease, OPCo has the option to purchase the Gavin Scrubber for the greater of its fair market value or adjusted acquisition cost (equal to the unamortized debt and equity of JMG) or sell the Gavin Scrubber. The initial 15-year lease term is non-cancelable. At the end of the initial term, OPCo can renew the lease, purchase the Gavin Scrubber (terms previously mentioned), or sell the Gavin Scrubber. In case of a sale at less than the adjusted acquisition cost, OPCo must pay the difference to JMG.
The use of JMG allows OPCo to enter into an operating lease while keeping the tax benefits otherwise associated with a capital lease. As of December 31, 2002, unless the structure of this arrangement is changed, it is reasonably possible that AEP and OPCo will consolidate JMG in the third quarter of 2003 as a result of the issuance of FIN 46. Upon consolidation, AEP and OPCo would record the assets, liabilities, depreciation expense, minority interest and debt interest expense of JMG. AEP and OPCo would eliminate operating lease expense. AEP's and OPCo's maximum exposure to loss as a result of their involvement with JMG is approximately $560 million of outstanding debt and equity of JMG as of December 31, 2002.
AEGCo and I&M entered into a sale and leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee) an unrelated unconsolidated trustee for Rockport Plant Unit 2 (the plant). Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors.
The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the plant and leases it to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the lease footnote. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the plant. AEGCo, I&M nor AEP has ownership interest in the Owner Trustee and do not guarantee its debt.
Summary Obligation Information
The contractual obligations of AEP and its subsidiaries include amounts reported on the Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes AEP's contractual cash obligations at December 31, 2002:
Payments Due by Period
(in millions)
Contractual Cash Obligations Less Than 1 year 2-3 years 4-5 years After 5 years Total
---------------------------- ---------------- --------- --------- ------------- -----
Long-term Debt $1,633 $1,817 $2,316 $4,354 $10,120
Short-term Debt 3,164 - - - 3,164
Equity Unit Senior Notes - - 376 - 376
Trust Preferred Securities - - - 321 321
Minority Interest In Finance
Subsidiary (a) - - 759 - 759
Preferred Stock Subject to
Mandatory Redemption - - - 84 84
Capital Lease Obligations 70 90 50 18 228
Unconditional Purchase
Obligations (b) 1,405 1,810 989 1,513 5,717
Noncancellable Operating Leases 305 523 479 2,462 3,769
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Total Contractual
Cash Obligations $6,577 $4,240 $4,969 $8,752 $24,538
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(a) The initial period of the preferred interest is through August 2006. At the
end of the initial period, the preferred rate may be reset, the preferred
member interests may be re-marketed to new investors, the preferred member
interests may be redeemed, in whole or in part including accrued return, or
the preferred member interest may be liquidated.
(b) Represents contractual obligations to purchase coal and natural gas as fuel
for electric generation along with related transportation of the fuel.
For the subsidiary registrants, please see each registrant's schedules of capitalization and long-term debt included with each registrants' financial statements in sections B through K for the timing of debt payment obligations and the lease footnote (Note 22) in section L for the timing of rent payments.
The special purpose entities (SPE), described under "Off-Balance Sheet and Minority Interest Arrangements" above, have been employed for some of the contractual cash obligations reported in the above table. The lease of Rockport Plant Unit 2 and the Gavin Scrubber, the permanent financing of HPL, and the sale of accounts receivable all use SPEs. Neither AEP nor any AEP related parties have an ownership interest in the SPE. AEP does not guarantee the debt of these entities. These SPEs are not consolidated in AEP's or the subsidiaries' financial statements in accordance with GAAP. As a result, neither the assets nor the debt of the SPE are included on AEP's Consolidated Balance Sheets. The future cash obligations payable to the SPEs are included in the above table.
In addition to the amounts disclosed in the contractual cash obligations table above, AEP and its subsidiaries make commitments in the normal course of business. These commitments include standby letters of credit, guarantees for the payment of obligation performance bonds, and other commitments. AEP's commitments outstanding at December 31, 2002 under these agreements are summarized in the table below:
Amount of Commitment Expiration Per Period
(in millions)
Other Commercial Commitments Less Than 1 year 2-3 years 4-5 years After 5 years Total
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Standby Letters of Credit (a) $ 125 $ 1 $ - $ 40 $ 166
Guarantees of the Performance
of Ooutside Parties (b) 13 17 325 137 492
Guarantess of Our Performance 1,159 2 82 9 1,252
Construction of Generating and
Transmission Facilities for
Third Parties (c) 671 83 47 67 868
Other Commercial
Commitments (d) 14 53 11 - 78
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Total Commercial Commitments $1,982 $156 $465 $253 $2,856
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(a) AEP has standby letters of credit to third parties. These letters of credit
cover gas and electricity trading contracts, various construction contracts
and credit enhancement for issued bonds. All of these letters of credit
were issued at a subsidiary level of AEP in the subsidiaries' ordinary
course of business. The maximum future payments of these letters of credit
are $166 million with maturities ranging from January 2003 to December
2007. There is no liability recorded for these letters of credit in
accordance with FIN 45. Since AEP is the parent to all these subsidiaries,
it holds all assets of the subsidiary as collateral. There is no recourse
to third parties in the event these letters of credit are drawn.
(b) These amounts are the balances drawn, not the maximum guarantee disclosed in
Note 10.
(c) As construction agent for third party owners of power plants and
transmission facilities, AEP has committed by contract terms to complete
construction by dates specified in the contracts. Should AEP default on
these obligations, financial payments could be up to 100% of contract
value (amount shown in table) or other remedies required by contract terms.
(d) Represents estimated future payments for power to be generated at facilities
under construction.
With the exceptions of SWEPCo's guarantee of an unaffiliated mine operator's obligations (payable upon their default) of $148 million at December 31, 2002, and OPCo's obligations under a power purchase agreement of $14 million each year in 2003 through 2005, the obligations in the above table are commitments of AEP and its non-registrant subsidiaries.
OPCo has entered into a 30-year power purchase agreement for electricity pro-duced by an unaffiliated entity's three-unit natural gas fired plant. The plant was completed in 2002 and the agreement will terminate in 2032. Under the terms of the agreement, OPCo has the option to run the plant until December 31, 2005 taking 100% of the power generated and making monthly capacity payments. The capacity payments are fixed through December 2005 at $1.2 million per month. For the remainder of the 30 year contract term, OPCo will pay the variable costs to generate the electricity it purchases which could be up to 20% of the plant's capacity. The estimated fixed payments are included in the Other Commercial Commitments table shown above.
Expenditures for domestic electric utility construction are estimated to be $4 billion for the next three years. Approximately 90% of those construction expenditures are expected to be financed by internally generated funds.
Construction expenditures for certain registrant subsidiaries for the next three years are:
Construction
Projected Expenditures
Construction Financed with
Expenditures Internal Funds
------------ --------------
(in millions)
APCo $1,005 70%
I&M 601 90
OPCo 733 100
SWEPCo 351 100
TCC 419 100
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APCo, AEP's subsidiary which operates in Virginia and West Virginia, has been seeking regulatory approval to build a new high voltage transmission line for over a decade. Certificates have been issued by both the WVPSC and the Virginia SCC authorizing construction and operation of the line. On December 31, 2002, the United States Forest Service issued a final environmental impact statement and record of decision to allow the use of federal lands in the Jefferson National Forest for construction of a portion of the line. APCo expects additional state and federal permits to be issued in the first half of 2003. Through December 31, 2002, APCo has invested approximately $51 million in this effort. The line is estimated to cost $287 million including amounts spent to date with completion in 2006. If the required permits are not obtained and the line is not constructed, the $51 million investment would be written off adversely affecting future results of operations and cash flows.
AEP maintains qualified defined benefit pension plans (Qualified Plans), which cover substantially all non-union and certain union associates, and unfunded excess plans to provide benefits in excess of amounts permitted to be paid under the provisions of the tax law to participants in the Qualified Plans. Additionally, AEP has entered into individual retirement agreements with certain current and retired executives that provide additional retirement benefits.
AEP's pension income for all pension plans approximated $69 million and $44 million for the years ended December 31, 2001 and December 31, 2002, respectively, and is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on the Qualified Plans' assets of 9%. In developing the expected long-term rate of return assumption, AEP evaluated input from actuaries and investment consultants, including their reviews of asset class return expectations as well as long-term inflation assumptions. Projected returns by such actuaries and consultants are based on broad equity and bond indices. AEP also considered historical returns of the investment markets as well as AEP's 10-year average return (for the period ended 2002) of 8.8%. AEP anticipates that the investment managers will continue to generate long-term returns of at least 9.0%. The expected long-term rate of return on the Qualified Plans' assets is based on an asset allocation assumption of 70% with equity managers, with an expected long-term rate of return of 10.5%, and 28% with fixed income managers, with an expected long-term rate of return of 6%, and 2% in cash and short term investments with an expected rate of return of 3%. Because of market fluctuation, the actual asset allocation as of December 31, 2002 was 67% with equity managers and 32% with fixed income managers and 1% in cash. AEP believes, however, that the long-term asset allocation on average will approximate 70% with equity managers, 28% with fixed income managers and the remaining 2% in cash. AEP regularly reviews the actual asset allocation and periodically rebalances the investments to our targeted allocation when considered appropriate. AEP continues to believe that 9.0% is a reasonable long-term rate of return on the Qualified Plans' assets, despite the recent market downturn in which the Qualified Plans' assets had a loss of 11.2% for the twelve months ended December 31, 2002. AEP will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust as necessary.
AEP bases its determination of pension expense or income on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded. As of December 31, 2002 AEP had cumulative losses of approximately $879 million which remain to be recognized in the calculation of the market-related value of assets. These unrecognized net actuarial losses result in increases in the future pension costs depending on several factors, including whether such losses at each measurement date exceed the corridor in accordance with SFAS No. 87, "Employers' Accounting for Pensions."
The discount rate that AEP utilizes for determining future pension obligations is based on a review of long-term bonds that receive one of the two highest ratings given by a recognized rating agency. The discount rate determined on this basis has decreased from 7.25% at December 31, 2001 to 6.75% at December 31, 2002. Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on the Qualified Plans' assets of 9.0%, a discount rate of 6.75% and various other assumptions, AEP estimates that the pension expense for all pension plans will approximate $2 million, $46 million and $97 million in 2003, 2004 and 2005, respectively. Future actual pension expense will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the pension plans.
Lowering the expected long-term rate of return on the Qualified Plans' assets by .5% (from 9.0% to 8.5%) would have reduced pension income for 2002 by approximately $19 million. Lowering the discount rate by 0.5% would have reduced pension income for 2002 by approximately $8 million.
The value of the Qualified Plans' assets has decreased from $3.438 billion at December 31, 2001 to $2.795 billion at December 31, 2002. The Qualified Plans paid out $272 million in benefits to plan participants during 2002 (nonqualified plans paid out $6 million in benefits). The investment returns and declining discount rates have changed the status of the Qualified Plans from overfunded (plan assets in excess of projected benefit obligations) by $146 million at December 31, 2001 to an underfunded position (plan assets are less than projected benefit obligations) of $788 million at December 31, 2002. Due to the Qualified Plans currently being underfunded, AEP recorded a charge to Other Comprehensive Income (OCI) of $585 million, and a Deferred Income Tax Asset of $315 million, offset by a Minimum Pension Liability of $662 million and a reduction to prepaid costs and intangible assets of $238 million. The charge to OCI does not affect earnings or cash flow. AEP is in full compliance with all regulations governing such plans including all Employee Retirement Income Security Act of 1974 laws. Because of the recent reductions in the funded status of the Qualified Plans, AEP expects to make cash contributions to the Qualified Plans of approximately $66 million in 2003 increasing to approximately $108 million per year by 2005.
Critical Accounting Policies
In the ordinary course of business, AEP and its registrant subsidiaries have made a number of estimates and assumptions relating to the reporting of results of operations and financial condition in the preparation of their financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ significantly from those estimates under different assumptions and conditions. They believe that the following discussion addresses the most critical accounting policies, which are those that are most important to the portrayal of the financial condition and results and require management's most difficult, subjective and complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain.
When regulatory assets are probable of recovery through regulated rates, they record them as assets on the balance sheet. They test for probability of recovery whenever new events occur, for example, issuance of a regulatory commission order or passage of new legislation. If they determine that recovery of a regulatory asset is no longer probable, they write-off that regulatory asset as a charge against earnings. A write-off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates.
Traditional Electricity Supply and Delivery Activities - Revenues are recognized on the accrual or settlement basis for normal retail and wholesale electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our statement of operations when the energy is delivered to the customer and include unbilled as well as billed amounts. In general, expenses are recorded when purchased electricity is received and when expenses are incurred.
Domestic Gas Pipeline and Storage Activities - Revenues are recognized from domestic gas pipeline and storage services when gas is delivered to contractual meter points or when services are provided. Transportation and storage revenues also include the accrual of earned, but unbilled and/or not yet metered gas.
Substantially all of the forward gas purchase and sale contracts, excluding wellhead purchases of natural gas, swaps and options for the domestic pipeline operations, qualify as derivative financial instruments as defined by SFAS 133. Accordingly, net gains and losses resulting from revaluation of these contracts to fair value during the period are recognized currently in the results of operations, appropriately discounted and net of applicable credit and liquidity reserves.
Energy Marketing and Trading Activities -In 2000, 2001 and throughout the majority of 2002, AEP engaged in broad non-regulated wholesale electricity, natural gas and other commodity marketing and trading transactions (trading activities). AEP's trading activities involved the purchase and sale of energy under forward contracts at fixed and variable prices and the buying and selling of financial energy contracts which include exchange traded futures and options and over-the-counter options and swaps. We used the mark-to-market method of accounting for trading activities as required by EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 98-10). Under the mark-to-market method of accounting, gains and losses from settlements of forward trading contracts are recorded net in revenues. For energy contracts not yet settled, whether physical or financial, changes in fair value are recorded net as revenues. Such fair value changes are referred to as unrealized gains and losses from mark-to-market valuations. When positions are settled and gains and losses are realized, the previously recorded unrealized gains and losses from mark-to-market valuations are reversed. Unrealized mark-to-market gains and losses are included in the Balance Sheets as "Energy Trading and Derivative Contracts." In October 2002, management announced plans to focus on wholesale markets where we own assets. A portion of the revenues and costs associated with AEP's wholesale electricity trading activities is allocated to TCC, SWEPCo, PSO and TNC and to members of the AEP Power Pool (APCo, CSPCo, I&M, KPCo and OPCo); however, TCC, SWEPCo, PSO and TNC are only allocated a portion of the forward transactions.
AEP's cost-based rate-regulated electric public utility companies (I&M, KPCo, PSO, and a portion of TNC and SWEPCo) defer, as regulatory liabilities (unrealized gains) or regulatory assets (unrealized losses), changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area. AEP's traditional marketing area is up to two transmission systems from the AEP service territory. For contracts which are outside of AEP's traditional marketing area, the change in fair value is included in nonoperating income on a net basis.
The majority of trading activities represent physical forward contracts that are typically settled by entering into offsetting contracts. An example of our energy trading activities is when, in January, we enter into a forward sales contract to deliver energy in July. At the end of each month until the contract settles in July, we would record any difference between the contract price and the market price as an unrealized gain or loss in revenues. In July when the contract settles, we would realize a gain or loss in cash and reverse to revenues the previously recorded cumulative unrealized gain or loss. Prior to settlement, the change in the fair value of physical forward sale and purchase contracts is included in revenues on a net basis. Upon settlement of a forward trading contract, the amount realized for a sales contract and the realized cost for a purchase contract are included on a net basis in revenues with the prior change in unrealized fair value reversed out of revenues.
For I&M, KPCo, PSO and a portion of TNC and SWEPCo, when the contract settles the total gain or loss is realized in cash and the impact on the income statement depends on whether the contract's delivery points are within or outside of AEP's traditional marketing area. For contracts with delivery points in AEP's traditional marketing area, the total gain or loss realized in cash for sales and the cost of purchased energy are included in revenues on a net basis. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses). For contracts with delivery points outside of AEP's traditional marketing area only the difference between the accumulated unrealized net gains or losses recorded in prior periods and the cash proceeds is recognized in the income statement as nonoperating income. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate.
For APCo, CSPCo and OPCo, depending on whether the delivery point for the electricity is in AEP's traditional marketing area or not determines where the contract is reported in the income statement. Physical forward trading sale and purchase contracts with delivery points in AEP's traditional marketing area are included in revenues on a net basis. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are also included in revenues on a net basis. Physical forward sale and purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis.
Continuing with the above example for AEP, APCo, CSPCo, OPCo, TCC, and a portion of TNC and SWEPCo, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy energy in July. If we do nothing else with these contracts until settlement in July and if the commodity type, volumes, delivery point, schedule and other key terms match, then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. Mark-to-market accounting for these contracts from this point forward will have no further impact on operating results but has an offsetting and equal effect on trading contract assets and liabilities. If the sale and purchase contracts do not match exactly as to commodity type, volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on revenues from recording additional changes in fair values using MTM accounting.
For AEP, the trading of energy options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in revenues until the contracts settle. When these contracts settle, we record the net proceeds in revenues and reverse to revenues the prior cumulative unrealized net gain or loss. APCo, CSPCo, I&M, KPCo and OPCo also have financial transactions, but record the unrealized gains and losses, as well as the net proceeds upon settlement, in nonoperating income.
The fair values of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based primarily on valuation models that estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by the appropriate valuation adjustments for items such as discounting, liquidity and credit quality. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due to AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. We have independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile. Unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and at the time contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices are not consistent with AEP's approach at estimating current market consensus for forward prices in the current period. This is particularly true for long-term contracts.
AEP applies MTM accounting to derivatives that are not trading contracts in accordance with generally accepted accounting principles. Derivatives are contracts whose value is derived from the market value of an underlying commodity.
Volatility in energy commodities markets affects the fair values of all of our open trading and derivative contracts exposing us to market risk and causing our results of operations to be subject to volatility. See Note 17, "Risk Management, Financial Instruments and Derivatives" for a discussion of the policies and procedures used to manage our exposure to market and other risks from trading activities.
Given the previously discussed reduction in AEP's trading activities, the impact of mark-to-market accounting on our financial statements is expected to decline in future periods.
Long-lived assets, including fixed assets and intangibles, are evaluated periodically for impairment whenever events or changes in circumstances indicate that the carrying amount of any such assets may not be recoverable. If the sum of the undiscounted cash flows is less than the carrying value, we recognize an impairment loss, measured as the amount by which the carrying value exceeds the fair value of the asset. The estimate of cash flow is based upon, among other things, certain assumptions about expected future operating performance. Our estimates of undiscounted cash flow may differ from actual cash flow due to, among other things, technological changes, economic conditions, changes to its business model or changes in its operating performance.
AEP sponsors pension and other retirement plans in various forms covering substantially all employees who meet eligibility requirements. Several statistical and other factors which attempt to anticipate future events are used in calculating the expense and liability related to the plans. These factors include assumptions about the discount rate, expected return on plan assets and rate of future compensation increases as determined by management, within certain guidelines. In addition, AEP's actuarial consultants also use subjective factors such as withdrawal and mortality rates to estimate these factors. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact to the amount of pension expense recorded.
See Note 1 to the consolidated financial statements for a discussion of significant accounting policies and new accounting pronouncements.
Market Risks
As a major power producer and marketer of wholesale electricity and natural gas, we have certain market risks inherent in our business activities. These risks include commodity price risk, interest rate risk, foreign exchange risk and credit risk. They represent the risk of loss that may impact us due to changes in the underlying market prices or rates.
Policies and procedures have been established to identify, assess, and manage market risk exposures in our day to day operations. Our risk policies have been reviewed with the Board of Directors, approved by a Risk Executive Committee and administered by a Chief Risk Officer. The Risk Executive Committee establishes risk limits, approves risk policies, assigns responsibilities regarding the oversight and management of risk and monitors risk levels. This committee receives daily, weekly, and monthly reports regarding compliance with policies, limits and procedures. The committee meets monthly and consists of the Chief Risk Officer, Chief Credit Officer, V.P. Market Risk Oversight, and senior financial and operating managers.
We use a risk measurement model which calculates Value at Risk (VaR) to measure our commodity price risk in the trading portfolio. The VaR is based on the variance - covariance method using historical prices to estimate volatilities and correlations and assuming a 95% confidence level and a one-day holding period. Based on this VaR analysis, at December 31, 2002 a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition. The following table shows the high, average, and low market risk as measured by VaR at:
2002 2001
---- ----
High Average Low High Average Low
---- ------- --- ---- ------- ---
(in millions)
AEP $24 $12 $4 $28 $14 $5
APCo 4 1 - 4 1 -
CSPCo 3 1 - 2 1 -
I&M 3 1 - 3 1 -
KPCo 1 - - 1 - -
OPCo 4 1 - 3 1 -
PSO - - - 2 1 -
SWEPCo - - - 3 1 -
TCC - - - 3 1 -
TNC - - - 1 1 -
|
After the October announcement of our strategy to reduce trading activity, the related VaRs were substantially reduced. The average AEP trading VaR for the fourth quarter 2002 was $7 million as compared to $13 million for fourth quarter 2001. In 2003 we will continue to adjust our VaR limit structure commensurate with our anticipated level of trading activity.
We also utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one year holding period. The volatilities and correlations were based on three years of weekly prices. The risk of potential loss in fair value attributable to AEP's exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $527 million at December 31, 2002 and $673 million at December 31, 2001. However, since we would not expect to liquidate our entire debt portfolio in a one year holding period, a near term change in interest rates should not materially affect results of operations or consolidated financial position.
The following table shows the potential loss in fair value as measured by VaR allocated to the AEP registrant subsidiaries based upon debt outstanding:
VaR for Registrant Subsidiaries:
December 31,
-----------
2002 2001
---- ----
(in millions)
Company
AEGCo $ 3 $5
APCo 87 100
CSPCo 33 60
I&M 85 86
KPCo 30 16
OPCo 34 59
PSO 70 17
SWEPCo 70 36
TCC 65 80
TNC 5 20
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AEGCo is not exposed to risk from changes in interest rates on short-term and long-term borrowings used to finance operations since financing costs are recovered through the unit power agreements.
AEP is exposed to risk from changes in the market prices of coal and natural gas used to generate electricity where generation is no longer regulated or where existing fuel clauses are suspended or frozen. The protection afforded by fuel clause recovery mechanisms has either been eliminated by the implementation of customer choice in Ohio (effective January 1, 2001 for CSPCo and OPCo) and in the ERCOT area of Texas (effective January 1, 2002 for TCC and TNC) or frozen by settlement agreements in Michigan and West Virginia or capped in Indiana. To the extent the fuel supply of the generating units in these states is not under fixed price long-term contracts AEP is subject to market price risk. AEP continues to be protected against market price changes by active fuel clauses in Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of Texas.
We employ physical forward purchase and sale contracts, exchange futures and options, over-the-counter options, swaps, and other derivative contracts to offset price risk where appropriate. However, we engage in trading of electricity, gas and to a lesser degree other commodities and as a result we are subject to price risk. The amount of risk taken by the traders is controlled by the management of the trading operations and the Company's Chief Risk Officer and his staff. When the risk from trading activities exceeds certain pre-determined limits, the positions are modified or hedged to reduce the risk to be within the limits unless specifically approved by the Risk Executive Committee.
We employ fair value hedges, cash flow hedges and swaps to mitigate changes in interest rates or fair values on short and long-term debt when management deems it necessary. We do not hedge all interest rate risk.
We employ cash flow forward hedge contracts to lock-in prices on certain power trading transactions denominated in foreign currencies where deemed necessary. International subsidiaries use currency swaps to hedge exchange rate fluctuations in debt denominated in foreign currencies. We do not hedge all foreign currency exposure.
Credit Risk
AEP limits credit risk by extending unsecured credit to entities based on internal ratings. In addition, AEP uses Moody's Investor Service, Standard and Poor's and qualitative and quantitative data to independently assess the financial health of counterparties on an ongoing basis. This data, in conjunction with the ratings information, is used to determine appropriate risk parameters. AEP also requires cash deposits, letters of credit and parental/affiliate guarantees as security from counterparties depending upon credit quality in our normal course of business.
We trade electricity and gas contracts with numerous counterparties. Since our open energy trading contracts are valued based on changes in market prices of the related commodities, our exposures change daily. We believe that our credit and market exposures with any one counterparty is not material to our financial condition at December 31, 2002. At December 31, 2002 approximately 7% of our exposure was below investment grade as expressed in terms of net MTM assets. Net MTM assets represents the aggregate difference between the forward market price for the remaining term of the contract and the contractual price per counterparty. As of December 31, 2002, the following table approximates counterparty credit quality and exposure for AEP based on netting across AEP entities, commodities and instruments:
Futures,
Forward and
Counterparty Swap
Credit Quality: Contracts Options Total
-------------- ------- ------- ------
(in millions)
AAA/Exchanges $ 26 $ 2 $ 28
AA 307 33 340
A 448 26 474
BBB 700 101 801
Below Investment
Grade 107 11 118
--------- ----- --------
Total $ 1,588 $173 $1,761
======= ==== ======
|
The counterparty credit quality and exposure for the registrant subsidiaries is generally consistent with that of AEP.
We enter into transactions for electricity and natural gas as part of wholesale trading operations. Electric and gas transactions are executed over the counter with counterparties or through brokers. Gas transactions are also executed through brokerage accounts with brokers who are registered with the Commodity Futures Trading Commission. Brokers and counterparties require cash or cash related instruments to be deposited on these transactions as margin against open positions. The combined margin deposits at December 31, 2002 and 2001 were $109 million and $55 million, respectively. These margin accounts are restricted and therefore are not included in Cash and Cash Equivalents on the Balance Sheets. We can be subject to further margin requirements should related commodity prices change.
We recognize the net change in the fair value of all open trading contracts, in accordance with generally accepted accounting principles and include the net change in mark-to-market amounts on a net discounted basis in revenues. The marking-to-market of open trading contracts contributed an unrealized $180 million to revenues in 2002. The mark-to-market fair values of open short-term trading contracts are based on exchange prices and broker quotes. The fair value of open long-term trading contracts are based mainly on internally developed valuation models. The gross value is present valued and reduced by appropriate valuation adjustments for counterparty credit risks and liquidity risk to arrive at fair value. The models are derived from internally assessed market prices with the exception of the NYMEX gas curve, where we use daily settled prices. Forward price curves are developed for inclusion in the model based on broker quotes and other available market data. The liquid portion of these curves are validated on a regular basis by the middle-office through the market data. Illiquid portions of the curves are validated through a review of the underlying market assumptions and variables for consistency and reasonableness. The end of the month liquidity reserve is based on the difference in price between the price curve and the bid price if we have a long position and the price curve and the ask price if we have a short position. This provides for a more accurate valuation of energy contracts.
The use of these models to fair value open trading contracts has inherent risks relating to the underlying assumptions employed by such models. Independent controls are in place to evaluate the reasonableness of the price curve models. Significant adverse or favorable effects on future results of operations and cash flows could occur if market prices, at the time of settlement, do not correlate with our interally developed price models.
The effect on the Statements of Operations of marking to market open electricity trading contracts in AEP's regulated jurisdictions, specifically I&M, KPCo, PSO and a portion of SWEPCO, is deferred as regulatory assets (losses) or liabilities (gains) since these transactions are included in cost of service on a settlement basis for ratemaking purposes. Unrealized mark-to-market gains and losses from trading are reported as assets or liabilities.
The following table shows net revenues (revenues less fuel and purchased energy expense) and their relationship to the mark-to-market revenues (the change in fair value of open trading contracts).
December 31,
-----------
2002 2001 2000
---- ---- ----
(in millions)
Revenues
(including
Mark- To-
Market
Adjustment) $14,555 $12,767 $11,113
Fuel and
Purchased
Energy
Expense 6,307 4,944 3,880
------- ------- -------
Net Revenues $ 8,248 $ 7,823 $ 7,233
======= ======= =======
Mark-to-Market
Revenues $180 $207 $187
=== ==== ====
Percentage of
Net Revenues
Represented by
Mark-to-Market
On Open
Trading Positions 2% 3% 3%
== == ==
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The following tables analyze the changes in fair values of trading assets and liabilities. The first table "Net Fair Value of Mark-to-Market Energy Trading and Derivative Contracts" shows how the net fair value of energy trading contracts was derived from the amounts included in the Consolidated Balance Sheets line item "Energy Trading and Derivative Contracts." The next table "Mark-to-Market Energy Trading and Derivative Contracts" disaggregates realized and unrealized changes in fair value; identifies changes in fair value as a result of changes in valuation methodologies; and reconciles the net fair value of energy trading contracts and related derivatives at December 31, 2001 of $448 million to December 31, 2002 of $250 million. Contracts realized/settled during the period include both sales and purchase contracts. The third table "Mark-to-Market Energy Trading and Derivative Contract Maturities" shows exposures to changes in fair values and realization periods over time for each method used to determine fair value.
Net Fair Value of Mark-to-Market Energy Trading and Derivative Contracts - AEP
December 31
----------------------
2002 2001
---- ----
(in millions)
Energy Trading and Derivative Contracts:
Current Asset $1,046 $ 2,125
Long-term Asset 824 795
Current Liability (1,147) (1,877)
Long-term Liability (484) (603)
------ -------
Net Fair Value of Energy Trading and Derivative Contracts 239 440
Non-trading related derivative liabilities 11* -
Assets held for sale (CitiPower) - 8
------ -------
Net Fair Value of Energy Trading and Derivative Contracts $ 250 $ 448
====== =======
* Excludes $6 million Loss recorded in an equity investment.
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The above net fair value of energy trading and derivative contracts includes $180 million at December 31, 2002, in unrealized mark-to-market gains that are recognized in the Consolidated Statements of Operations at December 31, 2002.
Mark-to-Market Energy Trading and Derivative Contracts - AEP
Total
-----
(in millions)
Net Fair Value of Energy Trading and Derivative Contracts
at December 31, 2001 $ 448
(Gain) Loss from Contracts Realized/Settled During the Period (182) (a)
Fair Value of New Open Contracts When Entered Into During the Period 68 (b)
Net Option Premiums Paid/(Received) (130) (c)
Change in fair value due to Methodology Changes 1 (d)
Change in Market Value of Energy Trading Contracts
Allocated to Regulated Jurisdictions (2) (e)
Changes in Market Value of Contracts 47 (f)
-----
Net Fair Value of Energy Trading and Derivative Contracts
at December 31, 2002 $ 250
=====
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Mark-to-Market Energy Trading and Derivative Contracts - Registrant Subsidiaries
APCo CSPCo I&M
---- ----- ---
Net Fair Value of Energy Trading
Contracts at December 31, 2001 $ 75,701 $48,449 $ 61,345
(Gain) Loss from Contracts
Realized/Settled During the Period (a) (19,143) (13,812) (9,611)
Change in Fair Value Due To
Methodology Changes (d) 350 228 247
Changes in Fair Market Value of Energy
Trading Contracts Allocated To
Regulated Jurisdictions (e) - - 1,502
Fair Value Of New Open Contracts
When Entered Into during The Period (b) 10,865 7,039 2,774
Net Option Premium Payments (c) (1,797) (1,208) (1,292)
Changes In Market Value Of Contracts (f) 30,876 24,421 15,896
-------- ------- --------
Net Fair Value of Energy Trading
Contracts at December 31, 2002 (g) $ 96,852 $65,117 $ 70,861
======== ======= ========
|
KPCo OPCo PSO
---- ---- ---
Net Fair Value of Energy Trading
Contracts at December 31, 2001 $12,729 $ 65,446 $ 2,434
(Gain) Loss From Contracts
Realized/Settled During Period (a) 1,153 (18,337) 6,476
Change in Fair Value Due To
Methodology Changes (d) 90 311 32
Changes In Fair Market Value Of Energy
Trading Contracts Allocated To
Regulated Jurisdiction (e) 5,136 - (5,397)
Fair Value of New Open Contracts
When Entered Into During Period (b) 1,013 18,443 -
Net Option Premium Payments (c) (464) (1,603) -
Changes In Market Value Of Contracts (f) 5,341 29,846 -
------- -------- -------
Net Fair Value of Energy Trading
Contracts at December 31, 2002 (g) $24,998 $ 94,106 $ 3,545
======= ======== =======
|
SWEPCo TCC TNC
------ --- ---
Net Fair Value of Energy Trading
Contracts at December 31, 2001 $ 2,900 $ 3,857 $ 915
(Gain) Loss From Contracts
Realized/Settled During The Period (a) 6,971 7,138 2,413
Change in Fair Value Due To
Methodology Changes (d) 36 42 12
Changes In Fair Market Value Of Energy
Trading Contracts Allocated To
Regulated jurisdiction (e) (2,485) - (336)
Fair Value Of New Open Contracts
When Entered Into During The Period (b) 428 1,919 1,627
Net Option Premium Payments (c) - - -
Changes In Market Value Of Contracts (f) (3,800) (7,542) (2,588)
------- ------- -------
Net Fair Value of Energy Trading
Contracts at December 31, 2002 (g) $ 4,050 $ 5,414 $ 2,043
======= ======= =======
|
(a) "(Gain) Loss from Contracts Realized/Settled During the Period" include
realized gains from energy trading contracts and related derivatives that
settled during 2002 that were entered into prior to 2002. (b) The "Fair Value of
New Open Contracts When Entered Into During Period" represents the fair value of
long- term contracts entered into with customers during 2002. The fair value is
calculated as of the execution of the contract. Most of the fair value comes
from longer term fixed price contracts with customers that seek to limit their
risk against fluctuating energy prices. The contract prices are valued against
market curves representative of the delivery location.
(c) Net Option Premiums Paid/(Received)" reflects the net option premiums
paid/(received) as they relate to unexercised and unexpired option contracts
that were entered into in 2002. (d) The Company changed the discount rate
applied to its trading portfolio from BBB+ Utility to LIBOR in the second
quarter which increased fair value by $10 million. In addition, the Company
changed its methodology in valuing a spread option model so as to more
accurately reflect the exercising of power transactions at optimal prices which
reduced fair value by $9 million.
(e)"Change in Market Value of Energy Trading Contracts Allocated to Regulated
Jurisdictions" relates to the net gains of those contracts that are not
reflected in the Consolidated Statements of Operations. These net gains are
recorded as regulatory liabilities for those subsidiaries that operate in
regulated jurisdictions.
(f)"Changes in Market Value of Contracts" represents the fair value change in
the trading portfolio due to market fluctuations during the current period.
Market fluctuations are attributable to various factors such as supply/demand,
weather, storage, etc.
(g)"Net Fair Value of Energy Trading Contracts" does not reflect the changes in
fair value associated with derivative contracts designated as hedges and
therefore will not agree to the net fair value of the Energy Trading and
Derivative Contracts line items on the individual registrants' balance sheets.
Mark-to-Market Energy Trading and Derivative Contract Maturities - AEP
Fair Value of Contracts at December 31, 2002
--------------------------------------------
Maturities
(in millions)
AEP Consolidated Less than In Excess Total Fair
Source of Fair Value 1 year 1-3 years 4-5 years Of 5 years Value
-------------------- ------ --------- --------- ---------- -----
Prices Actively Quoted (a) $(32) $ 69 $ - $ - $ 37
Prices Provided by Other External
Sources (b) 24 189 11 - 224
Prices Based on Models and Other
Valuation Methods (c) (84) 13 36 24 (11)
---- ---- --- --- ----
Total $(92) $271 $47 $24 $250
==== ==== === === ====
|
Mark-to-Market Energy Trading and Derivative Contract Maturities- Registrant Subsidiaries
Fair Value of Contracts at December 31, 2002
--------------------------------------------
Maturities
(in thousands)
Less than In Excess Total Fair
Source of Fair Value 1 year 1-3 years 4-5 years Of 5 years Value
-------------------- ------ --------- --------- ---------- -----
APCo
Prices Provided by Other
External Sources (b) $14,352 $43,307 $ 3,018 $ - $ 60,677
Prices Based on Models and Other
Valuation Methods (c) 11,492 9,475 8,183 7,025 36,175
------- ------- ------- ------ --------
Total $25,844 $52,782 $11,201 $7,025 $ 96,852
======= ======= ======= ====== ========
CSPCo
Prices Provided by Other
External Sources (b) $ 9,657 $29,113 $ 2,028 $ - $ 40,798
Prices Based on Models and Other
Valuation Methods (c) 7,726 6,370 5,501 4,722 24,319
------- ------- ------- ------ --------
Total $17,383 $35,483 $ 7,529 $4,722 $ 65,117
======= ======= ======= ====== ========
KPCo
Prices Provided by Other
External Sources (b) $ 3,707 $11,176 $ 779 $ - $ 15,662
Prices Based On Models and Other
Valuation Methods (c) 2,966 2,442 2,114 1,814 9,336
------- ------- ------- ------ --------
Total $ 6,673 $13,618 $ 2,893 $1,814 $ 24,998
======= ======= ======= ====== ========
I&M
Prices Provided by Other
External Sources (b) $12,105 $30,961 $ 2,171 $ - $ 45,237
Prices Based on Models and Other
Valuation Methods (c) 7,913 6,772 5,886 5,053 25,624
------- ------- ------- ------ --------
Total $20,018 $37,733 $ 8,057 $5,053 $ 70,861
======= ======= ======= ====== ========
OPCo
Prices Provided by Other
External Sources (b) $20,775 $38,622 $ 2,691 $ - $ 62,088
Prices Based on Models and Other
Valuation Methods (c) 10,003 8,453 7,298 6,264 32,018
------- ------- ------- ------ --------
Total $30,778 $47,075 $ 9,989 $6,264 $ 94,106
======= ======= ======= ====== ========
PSO
Prices Provided by Other
External Sources (b) $ 373 $1,736 $ 125 $ - $ 2,234
Prices Based on Models and Other
Valuation Methods (c) 296 390 336 289 1,311
------- ------ ------- ------- --------
Total $ 669 $2,126 $ 461 $ 289 $ 3,545
======= ====== ======= ======= ========
SWEPCo
Prices Provided by Other
External Sources (b) $ 427 $1,983 $ 141 $ - $ 2,551
Prices Based on Models and Other
Valuation Methods (c) 338 446 385 330 1,499
------- ------ ------- ------- --------
Total $ 765 $2,429 $ 526 $ 330 $ 4,050
======= ====== ======= ======= ========
TCC
Prices Provided by Other
External Sources (b) $ 1,536 $ 1,605 $ 115 $ - $ 3,256
Prices Based on Models and Other
Valuation Methods (c) 1,219 361 311 267 2,158
------- ------- -------- ------- --------
Total $ 2,755 $ 1,966 $ 426 $ 267 $ 5,414
======= ======= ======== ======= ========
TNC
Prices Provided by Other
External Sources (b) $ 201 $1,016 $ 73 $ - $ 1,290
Prices Based on Models and Other
Valuation Methods (c) 159 229 197 168 753
------- ------ -------- ------ --------
Total $ 360 $1,245 $ 270 $ 168 $ 2,043
======= ====== ======== ====== ========
|
(a)"Prices Actively Quoted" represents the Company's exchange traded futures
positions.
(b)"Prices Provided by Other External Sources" represents the
Company's positions in
natural gas, power, and coal at points where over-the-counter broker quotes
are available. Some prices from external sources are quoted as strips (one
bid/ask for Nov-Mar, Apr-Oct, etc). Such transactions have also been
included in this category.
(c)"Prices Based on Models and Other Valuation Methods" contain the following:
the value of the Company's adjustments for liquidity and counterparty credit
exposure, the value of contracts not quoted by an exchange or an
over-the-counter broker, the value of transactions
for which an internally developed price curve was developed as a result of
the long dated nature of certain transactions, and the value of certain
structured transactions.
We have investments in debt and equity securities which are held in nuclear trust funds. The trust investments and their fair value are discussed in Note 17, "Risk Management, Financial Instruments and Derivatives." Financial instruments in these trust funds have not been included in the market risk calculation for interest rates as these instruments are marked-to-market and changes in market value of these instruments are reflected in a corresponding decommissioning liability. Any differences between the trust fund assets and the ultimate liability are expected to be recovered through regulated rates from our regulated customers.
Inflation affects our cost of replacing operating and maintaining utility plant assets. The rate-making process limits recovery to the historical cost of assets, resulting in economic losses when the effects of inflation are not recovered from customers on a timely basis. However, economic gains that result from the repayment of long-term debt with inflated dollars partly offset such losses.
Industry Restructuring
Four of the eleven state retail jurisdictions (Michigan, Ohio, Texas and Virginia) in which AEP's domestic electric utility companies operate have implemented retail restructuring legislation. Three other states (Arkansas, Oklahoma and West Virginia) initially adopted retail restructuring legislation, but have since delayed the implementation of that legislation or repealed the legislation (Arkansas). In general, retail restructuring legislation provides for a transition from cost-based rate regulation of bundled electric service to customer choice and market pricing for the supply of electricity. As legislative and regulatory proceedings evolved, six AEP electric operating companies (APCo, CSPCo, OPCo, SWEPCo, TCC and TNC) have discontinued the application of SFAS 71 regulatory accounting for the generation business. AEP has not discontinued its regulatory accounting for its subsidiaries doing business in Michigan (I&M) and Oklahoma (PSO). Restructuring legislation, the status of the transition plans and the status of the electric utility companies' accounting to comply with the changes in each of our state regulatory jurisdictions affected by restructuring legislation is presented in Note 8 of the Notes to Financial Statements.
Corporate Separation
AEP and its subsidiaries have filed with the FERC and SEC seeking approval to separate their regulated and unregulated operations. The plan for corporate separation allows AEP and its subsidiaries to meet the requirements of Texas and Ohio restructuring legislation. In Texas, TCC and TNC intended to transfer the generation assets from the integrated electric operating companies (CPL and WTU) which operated in ERCOT prior to the effective date of the Texas Restructuring Legislation to unregulated generation companies. In Ohio, CSPCo and OPCo intended to transfer transmission and distribution assets from the integrated companies to two new wires companies leaving CSPCo and OPCo as generating companies. AEP and its subsidiaries proposed amendments to the power pooling agreements to remove the four Ohio and Texas generating companies. Only those operating companies that continue to exist as integrated utilities would have been included in the amended power pooling agreements, which would govern energy exchanges among members and the allocation of their off-system purchases and sales. In connection with corporate seperation, certain new interim power supply agreements have been proposed to provide power to distribution companies who will no longer own generation assets. Several state commissions, wholesale customer groups and other interested parties intervened in the FERC proceeding. Negotiated settlement agreements with the state regulatory commissions and other major intervenors were filed with the FERC in December 2001. In September 2002, the FERC conditionally approved our corporate separation plan as modified by the settlement agreements. Terms in the settlement agreements would be effective upon implementation of corporation separation. In addition, SEC approval of AEP's corporate separation plan is required for its implementation. The Arkansas Commission intervened with the SEC, which has extended the length of time needed for the SEC's review. In order to execute this separation, AEP and its subsidiaries may be required to retire various debt securities and transfer assets between legal entities.
With the changes in AEP's business strategy in response to current energy market/business conditions, management is evaluating changes to the corporate separation plans, including determining whether legal corporate separation is appropriate.
RTO Formation
FERC Order No. 2000 and many of the settlement agreements with the FERC and state regulatory commissions to approve the AEP-CSW merger required the transfer of functional control of the subsidiaries' transmission systems to RTOs.
AEP East companies initially participated in the formation of the Alliance RTO. In December 2001, the FERC reversed prior approvals and rejected the Alliance RTO's filing. Subsequently, in May 2002, AEP announced an agreement with the PJM Interconnection to pursue terms for AEP East companies to participate in PJM with final agreements to be negotiated. In July 2002, the FERC conditionally approved AEP's decision for AEP East companies to join PJM subject to certain conditions being met. The performance of these conditions are only partially under AEP's control. In December 2002, AEP East companies in Indiana, Kentucky, Ohio and Virginia filed for state regulatory commission approval of their plans to transfer functional control of their transmission assets to PJM based on statutory or regulatory requirements in those states. Those proceedings are currently pending. In February 2003, the Virginia Legislature enacted legislation that would prohibit the transfer to an RTO, until at least July 2004, which is currently awaiting signature by the Governor of Virginia.
AEP West companies are members of ERCOT or the SPP. In May 2002, FERC accepted, conditionally, filings related to a proposed consolidation of the MISO and the SPP. In that order the FERC required the AEP West companies in SPP to file reasons why they should not be required to join MISO. In August 2002, AEP, SWEPCo and TNC notified the FERC of their intent that the transmission assets in SPP would participate in MISO. AEP's SPP companies are also regulated by state public utility commissions, and the Louisiana and Arkansas commissions also filed responses to the FERC's RTO order indicating that additional analysis was required. Regulatory activities concerning various RTO issues are ongoing in Arkansas and Louisiana.
Management is unable to predict the outcome of these transmission regulatory actions and proceedings or their impact on the timing and operation of RTOs, AEP and its subsidiaries' transmission operations or future results of operations and cash flows.
FERC Proposed Standard Market Design and Security Standards
In 2002, the FERC issued its Standard Market Design (SMD) notice of proposed rulemaking seeking to standardize the structure and operation of wholesale electricity markets across the country. The FERC published for comment its proposed security standards as part of the SMD. These standards are intended to ensure all market participants have a basic security program that effectively protects the electric grid and related market activities. Because the rule is not yet finalized, management cannot predict the effect of the final rule on AEP or its subsidiaries' operations and financial results. See Note 9 for a complete discussion of these proposals.
Litigation
AEP and its subsidiaries are involved in various litigation. The details of significant litigation contingencies are disclosed in Note 9 and summarized below.
Enron Bankruptcy - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo
In 2002, certain subsidiaries of AEP filed claims in the bankruptcy proceeding of the Enron Corp. and its subsidiaries which are pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron's bankruptcy, AEP and its subsidiaries had open trading contracts and trading accounts receivables and payables with Enron and various HPL related contingencies and indemnities including issues related to the underground Bammel gas storage facility and the cushion gas (or pad gas) required for its normal operation.
In 2001, AEP expensed $47 million ($31 million net of tax) for our estimated loss from the Enron bankruptcy. In 2002 AEP expensed an additional $6 million for a cumulative loss of $53 million ($34 million net of tax). The amounts for certain subsidiary registrants were:
Amounts
Amounts Net of
Registrant Expensed Tax
-------- -----
(in millions)
APCo $5.3 $3.4
CSPCo 2.7 1.8
I&M 2.8 1.8
KPCo 1.1 0.7
OPCo 3.6 2.3
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The additional 2002 expense did not materially change the cumulative expense per registrant subsidiary. The amounts expensed were based on an analysis of contracts where AEP entities and Enron are counterparties.
Management believes that we have the right to utilize offsetting receivables and payables and related collateral across various Enron entities by offsetting approximately $110 million of trading payables owed to various Enron entities against trading receivables due to us. Management believes we have legal defenses to any challenge that may be made to the utilization of such offsets. At this time management is unable to predict the ultimate resolution of these issues or their impact on results of operations and cash flows. See Note 9 for further discussion.
COLI - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo
A decision by the U.S. District Court for the Southern District of Ohio in February 2001 that denied AEP's deduction of interest claimed on AEP's consolidated federal income tax returns related to a COLI program resulted in a $319 million reduction in AEP's Net Income for 2000.
The earnings reductions for affected registrant subsidiaries were as follows:
(in millions)
APCo $ 82
CSPCo 41
I&M 66
KPCo 8
OPCo 118
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AEP has appealed the Court's decision. See Note 18 for further discussion.
Shareholders' Litigation - Affecting AEP
In 2002, lawsuits alleging securities law violations, a breach of fiduciary duty for failure to establish and maintain adequate internal controls and violations of the Employee Retirement Income Security Act were filed against AEP, certain AEP executives, members of the AEP Board of Directors and certain investment banking firms. These cases are in the initial pleading stage. AEP intends to vigorously defend against these actions. See Note 9 for further discussion.
California Lawsuit - Affecting AEP
In 2002, the Lieutenant Governor of California filed a lawsuit in California Superior Court against forty energy companies, including AEP, and two publishing companies alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP intends to vigorously defend against this action. See Note 9 for further discussion.
FERC Wholesale Fuel Complaints - Affecting AEP and TNC
In May 2000 and November 2001, certain TNC wholesale customers filed a complaints with FERC alleging that TNC had overcharged them through the fuel adjustment clause for certain purchased power costs. The final resolution of this matter could have a negative impact on futute results of operations, cash flow and financial condition. See Note 6 for further discussion.
Merger Litigation - Affecting AEP and all Subsidiary Registrants
In January 2002, a federal court ruled that the SEC did not properly find that the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and sent the case back to the SEC for further review. Management believes that the merger meets the requirements of the PUHCA and expects the matter to be resolved favorably. See Note 9 for further discussion.
Arbitration of Williams Claim - Affecting AEP
In 2002, AEP filed its demand for arbitration with the American Arbitration Association to initiate formal arbitration proceedings in a dispute with the Williams Companies (Williams). The proceeding results from Williams' repudiation of its obligations to provide physical power deliveries to AEP and Williams' failure to provide the monetary security required for natural gas deliveries. Although management is unable to predict the outcome of this matter, it is not expected to have a material impact on results of operations, cash flows or financial condition. See Note 9 for further discussion.
Energy Market Investigations - Affecting AEP
During 2002, the FERC, the California attorney general, the PUCT, the SEC, the Department of Justice and the U.S. Commodity Futures Trading Commission (CFTC) initiated investigations into whether any entity, including Enron, manipulated short-term prices in electric energy or natural gas markets, exercised undue influence over wholesale prices or participated in fraudulent trading practices.
AEP and its subsidiaries have and will continue to provide information to the FERC, the SEC, state officials and the CFTC as required. See Note 9 for further discussion.
FERC Market Power Mitigation - Affecting the AEP System
A FERC order on our triennial market based wholesale power rate authorization update required certain mitigation actions that AEP and its subsidiaries would need to take for sales/purchases within their control area and required the posting of information on our website regarding the status of AEP's power system. As a result of a request for rehearing filed by AEP and other market participants, FERC issued an order delaying the effective date of the mitigation plan until after a planned technical conference on market power determination. No such conference has been held and management is unable to predict the timing of any further action by the FERC or its affect on future results of operations and cash flows.
Other Litigation - Affecting AEP and all Subsidiary Registrants
AEP and its subsidiaries are involved in a number of other legal proceedings and claims. While management is unable to predict the outcome of such litigation, it is not expected that the ultimate resolution of these matters will have a material adverse effect on results of operations, cash flows or financial condition.
Environmental Concerns and Issues
AEP and its subsidiaries will confront several new environmental requirements
over the next decade with the potential for substantial control costs and
premature retirement of some generating plants. These policies include:
stringent controls on sulfur dioxide (S02), nitrogen oxide (NOx) and mercury
(Hg) emissions from future regulations or laws, or an adverse decision in the
New Source Review litigation; a new Clean Water Act rule to reduce fish killed
at once-through cooled power plants; and a possible future requirement to reduce
carbon dioxide (CO2) emissions as the world endeavors to stabilize atmospheric
concentrations of greenhouse gas emissions and avert global climatic changes.
AEP and its subsidiaries' environmental policy require full compliance with all applicable legal requirements. In support of this policy, AEP and its subsidiaries invest in research through groups like the Electric Power Research Institute and directly through demonstration projects for new emission control technologies. AEP and its subsidiaries intend to continue in a leadership role to protect and preserve the environment while providing vital energy commodities and services to customers at fair prices. AEP and its subsidiaries have a proven record of efficiently producing and delivering electricity and gas while minimizing the impact on the environment. AEP and its subsidiaries have spent billions of dollars to equip many of their facilities with pollution control technologies.
Multi-pollutant control legislation has been introduced in Congress and is supported by the Bush Administration. The legislation would regulate NOx, SO2, Hg and possibly CO2 emissions from electric generating plants. AEP and its subsidiaries are advocates of comprehensive, multi-pollutant legislation so that compliance planning can be coordinated and collateral emission reductions maximized. Optimally, such legislation would establish reasonable emission reduction targets and compliance timetables based on sound science, utilize nationwide cap-and-trade programs for achieving compliance as cost-effectively as possible, protect fuel diversity and preserve the reliability of the nation's electric supply. Management is unable to predict the timing or magnitude of additional pollution control laws or regulations. If additional control technology is required on AEP System facilities and their costs are not recoverable from customers through regulated rates or market prices, those costs could adversely affect future results of operations and cash flows. The following discussions explain existing control efforts, litigation and other pending matters related to environmental issues for AEP companies.
Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M and OPCo
Since 1999 AEPSC, APCo, CSPCo, I&M, and OPCo have been involved in litigation regarding generating plant emissions under the Clean Air Act. Federal EPA, a number of states and special interest groups alleged that AEP System companies modified certain units at coal fired generating plants in violation of the Clean Air Act over a 20 year period.
Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and intends to vigorously pursue its defense. Management is unable to estimate the loss or range of loss related to the contingent liability under the Clear Air Act proceedings and unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. If the AEP System companies do not prevail, any capital and operating costs of additional pollution control equipment or any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered. See Note 9 for further discussion.
NOx Reductions - Affecting AEP, APCo, I&M, OPCo, SWEPCo and TCC
Federal EPA issued a NOx Rule and adopted a revised rule (the Section 126 Rule) requiring substantial reductions in NOx emissions in a number of eastern states, including certain states in which the AEP System's generating plants are located. The compliance date for these rules is May 31, 2004.
In 2000, the Texas Commission on Environmental Quality (formerly the Texas Natural Resource Conservation Commission) adopted rules requiring significant reductions in NOx emissions from utility sources, including TCC and SWEPCo. The compliance date is May 2003 for TCC and May 2005 for SWEPCo.
AEP and its subsidiaries are installing a variety of emission control
technologies to reduce NOx emissions to comply with the applicable state and
Federal NOx requirements including selective catalytic reduction (SCR) and
non-SCR technologies. The AEP System NOx compliance plan is a dynamic plan that
is continually reviewed and revised. Current estimates indicate that compliance
with the NOx Rule, the Texas Commission on Environmental Quality rule and the
Section 126 Rule could result in required capital expenditures in the range of
$1.3 billion to $2 billion of which $843 million has been spent through December
31, 2002 for the AEP System.
The following table shows the estimated compliance cost ranges and amounts spent by certain of AEP's registrant subsidiaries through December 31, 2002.
Estimated Amounts
Compliance Costs Spent
---------------- -------
(in millions)
Company
APCo $445 $234
I&M 42-210 5
OPCo 535-864 387
SWEPCo 40 24
TCC 5 5
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Unless any capital and operating costs of additional pollution control equipment are recovered from customers, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. See Note 9 for further discussion.
Superfund and State Remediation - Affecting AEP, APCo, CSPCo, I&M, OPCo, SWEPCo and TCC
By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically disposed of or treated in captive disposal facilities or are beneficially utilized. In addition, our generating plants and transmission and distribution facilities have used asbestos, PCBs and other hazardous and non-hazardous materials. AEP and its subsidiaries are currently incurring costs to safely dispose of these substances. Additional costs could be incurred to comply with new laws and regulations if enacted.
Superfund addresses clean-up of hazardous substances at disposal sites and authorized Federal EPA to administer the clean-up programs. As of year-end 2002 subsidiaries of AEP are named by the Federal EPA as a PRP for five sites. APCo, CSPCo, and OPCo each have one PRP site and I&M has two PRP sites. There are six additional sites for which APCo, CSPCo, I&M, KPCo, OPCo and SWEPCo have received information requests which could lead to PRP designation. HPL, OPCo, SWEPCo and TCC have also been named potentially liable at six sites under state law. Liability has been resolved for a number of sites with no significant effect on results of operations. In those instances where AEP or its subsidiaries have been named a PRP or defendant, their disposal or recycling activities were in accordance with the then-applicable laws and regulations. Unfortunately, Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories.
While the potential liability for each Superfund site must be evaluated separately, several general statements can be made regarding AEP subsidiaries' potential future liability. Disposal of materials at a particular site is often unsubstantiated and the quantity of materials deposited at a site was small and often nonhazardous. Although superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. Therefore, our present estimates do not anticipate material cleanup costs for identified sites for which AEP subsidiaries have been declared PRPs. If significant cleanup costs are attributed to AEP or its subsidiaries in the future under Superfund, results of operations, cash flows and possibly financial condition would be adversely affected unless the costs can be recovered from customers.
Global Climate Change - Affecting AEP and all Registrant Subsidiaries
At the Third Conference of the Parties to the United Nations Framework
Convention on Climate Change held in Kyoto, Japan in December 1997, more than
160 countries, including the U.S., negotiated a treaty requiring legally-binding
reductions in emissions of greenhouse gases, chiefly CO2, which many scientists
believe are contributing to global climate change. Although the U.S. signed the
Kyoto Protocol on November 12, 1998, the treaty was not submitted to the Senate
for its advice and consent by President Clinton. In March 2001, President Bush
announced his opposition to the treaty and its U.S. ratification. At the Seventh
Conference of the Parties in November 2001, the parties finalized the rules,
procedures and guidelines required to facilitate ratification of the protocol.
The protocol is expected to become effective in 2003. AEP does not support the
Kyoto Protocol but intends to work with the Bush Administration and U.S.
Congress to develop responsible public policy on this issue. Management expects
that due to President Bush's opposition to legislation mandating greenhouse gas
emissions controls, any policies developed and implemented in the near future
are likely to encourage voluntary measures to reduce, avoid or sequester such
emissions. AEP has for many years been a leader in pursuing voluntary actions to
control greenhouse gas emissions. AEP recently expanded its commitment in this
area by
joining the Chicago Climate Exchange, a pilot greenhouse gas emission reduction
and trading program, under which AEP and its subsidiaries are obligated to
reduce or offset 18 million tons of CO2 emissions during 2003-2006.
The acquisition of 4,000 MW of coal-fired generation in the United Kingdom in December 2001 exposes these assets to potential CO2 emission control obligations since the U.K has become a party to the Kyoto Protocol.
Control of Mercury Emissions
In December 2000, Federal EPA issued a regulatory determination listing the electric generating sector as a source category under the Clean Air Act for development of maximum achievable control technology standards to control emissions of hazardous air pollutants, including Hg. Federal EPA is expected to issue proposed regulations in 2003 and develop a final rule in 2004. Management cannot predict the outcome of these regulatory proceedings, or the costs to comply with any new standards adopted by Federal EPA. The costs associated with compliance could be material. However, unless any capital and operating costs of additional pollution control equipment are recovered from customers, they will have an adverse effect on future results of operations, cash flows and possibly financial condition.
Costs for Spent Nuclear Fuel and Decommissioning - Affecting AEP, I&M and TCC
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 Nuclear Waste Policy Act of 1982 established federal responsibility for the permanent off-site disposal of SNF and high-level radioactive waste. By law I&M and TCC participate in the DOE's SNF disposal program which is described in Note 9 of the Notes to Financial Statements. Since 1983 I&M has collected $303 million from customers for the disposal of nuclear fuel consumed at the Cook Plant. $117 million of these funds have been deposited in external trust funds to provide for the future disposal of SNF and $186 million has been remitted to the DOE. TCC has collected and remitted to the DOE, $53 million for the future disposal of SNF since STP began operation in the late 1980s. Under the provisions of the Nuclear Waste Policy Act, collections from customers are to provide the DOE with money to build a permanent repository for spent fuel. However, in 1996, the DOE notified the companies that it would be unable to begin accepting SNF by the January 1998 deadline required by law. To date DOE has failed to comply with the requirements of the Nuclear Waste Policy Act.
As a result of DOE's failure to make sufficient progress toward a permanent repository or otherwise assume responsibility for SNF, AEP on behalf of I&M and STPNOC on behalf of TCC and the other STP owners, along with a number of unaffiliated utilities and states, filed suit in the D.C. Circuit Court requesting, among other things, that the D.C. Circuit Court order DOE to meet its obligations under the law. The D.C. Circuit Court ordered the parties to proceed with contractual remedies but declined to order DOE to begin accepting SNF for disposal. DOE estimates its planned site for the nuclear waste will not be ready until at least 2010. In 1998, AEP and I&M filed a complaint in the U.S. Court of Federal Claims seeking damages in excess of $150 million due to the DOE's partial material breach of its unconditional contractual deadline to begin disposing of SNF generated by the Cook Plant. Similar lawsuits were filed by other utilities. In August 2000, in an appeal of related cases involving other unaffiliated utilities, the U.S. Court of Appeals for the Federal Circuit held that the delays clause of the standard contract between utilities and the DOE did not apply to DOE's complete failure to perform its contract obligations, and that the utilities' suits against DOE may continue in court. On January 17, 2003, the U.S. Court of Federal Claims ruled in favor of I&M on the issue of liability. The case continues on the issue of damages owed to I&M by the DOE. As long as the delay in the availability of a government approved storage repository for SNF continues, the cost of both temporary and permanent storage of SNF and the cost of decommissioning will continue to increase.
In January 2001, I&M and STPNOC, on behalf of STP's joint owners, joined a lawsuit against DOE, filed in November 2000 by unaffiliated utilities, related to DOE's nuclear waste fund cost recovery settlement with PECO Energy Corporation (now Exelon Generation Company, LLC). The settlement adjusted the fees Exelon was required to pay to DOE for disposal of SNF. The fee adjustment allowed Exelon to skip payments to the DOE to make up for Exelon's damages from DOE's breach of its contract obligation to dispose of SNF from commercial nuclear power plants. The companies believe the settlement was unlawful as it would force other utilities (rather than DOE) to compensate Exelon for the damages it had incurred from DOE's breach of contract. In September 2002, the U.S. Court of Appeals for the Eleventh Circuit found that DOE acted improperly by adopting the fee adjustment provision of this settlement, that the fee adjustment provisions of the settlement harmed other utilities who pay into the fund and violated the federal nuclear waste management laws and that the fee adjustment provisions of the settlement were null and void.
The cost to decommission nuclear plants is affected by both NRC regulations and the delayed SNF disposal program. Studies completed in 2000 estimate the cost to decommission the Cook Plant ranges from $783 million to $1,481 million in 2000 non-discounted dollars. External trust funds have been established with amounts collected from customers to decommission the plant. At December 31, 2002, the total decom-missioning trust fund balance for Cook Plant was $618 million which includes earnings on the trust investments. Studies completed in 1999 for STP estimate TCC's share of decommissioning cost to be $289 million in 1999 non-discounted dollars. Amounts collected from customers to decommission STP have been placed in an external trust. At December 31, 2002, the total decommission-ing trust fund for TCC's share of STP was $98 million which includes earnings on the trust investments. Estimates from the decommissioning studies could continue to escalate due to the uncertainty in the SNF disposal program and the length of time that SNF may need to be stored at the plant site. I&M and TCC will work with regulators and customers to recover the remaining estimated costs of decommissioning Cook Plant and STP. However, AEP's, I&M's and TCC's future results of operations, cash flows and possibly their financial conditions would be adversely affected if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered.
Other Environmental Concerns - Affecting AEP and all Subsidiaries
AEP and its subsidiaries are exposed to other environmental concerns which are not considered to be material or potentially material at this time. Should they become significant or should any new concerns be uncovered that are material, they could have a material adverse effect on results of operations and possibly financial condition. AEP performs environmental reviews and audits on a regular basis for the purpose of identifying, evaluating and addressing environmental concerns and issues.
Other Matters
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 depending on the nature and location of facilities AEP and its subsidiaries acquire and the terms of power sale contracts they enter. In addition, AEP and its subsidiaries have historically sold less power, and consequently earned less income, when weather conditions are milder. AEP and its subsidiaries expect that unusually mild weather in the future could diminish their results of operations and may impact their financial condition.
Sustained Earnings Improvement Initiative
In response to difficult conditions in AEP's business, a Sustained Earnings Improvement (SEI) initiative was undertaken company-wide in the fourth quarter of 2002, as a cost-saving and revenue-building effort to build long-term earnings growth. Termination benefits expense relating to 1,120 terminated employees totaling $75.4 million pre-tax was recorded in the fourth quarter of 2002. We determined that the termination of the employees under our SEI initiative did not constitute a curtailment under the provisions of SFAS No. 88 "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits". In addition, certain buildings and corporate aircraft are being sold in an effort to reduce ongoing operating expenses. See Note 11 for additional information.
Non-Core Wholesale Investments
Additional market deterioration associated with AEP's non-core wholesale investments, including AEP's U.K. operations, could have an adverse impact on AEP's future results of operations and cash flows. Significant long-term changes in external market conditions could lead to additional write-offs and potential divestitures of AEP's wholesale investments, including, but not limited to, AEP's U.K. operations.
Elk City Referendum - Affecting AEP and PSO
In October 2002, the City Commission of Elk City, Oklahoma voted to hold a referendum seeking voter approval of a $20.4 million acquisition of PSO's distribution assets within the city limits. The vote occurred in December 2002 with the referendum being defeated.
Snohomish Settlement - Affecting AEP
In February 2003, AEP and the Public Utility District No. 1 of Snohomish County,
Washington (Snohomish) agreed to terminate their long-term contract signed in
January 2001. Snohomish also agreed to withdraw its complaint before the FERC
regarding this contract.
Investments Limitations - Affecting AEP
Our investment, including guarantees of debt, in certain types of activities is limited by PUHCA. SEC authorization under PUHCA limits us to issuing and selling securities in an amount up to 100% of our average quarterly consolidated retained earnings balance for investment in EWGs and FUCOs. At December 31, 2002, AEP's investment in EWGs and FUCOs was $2.0 billion, including guarantees of debt, compared to AEP's limit of $2.8 billion.
SEC rules under PUHCA permit AEP to invest up to 15% of consolidated capitalization (such amount was $3.2 billion at December 31, 2002) in energy-related companies, including marketing and/or trading of electricity, gas and other energy commodities.
INVESTOR INQUIRIES
Investors should direct inquiries to Investor Relations using the toll free
number, 1-800-237-2667 or by writing to: Bette Jo Rozsa Managing Director of
Investor Relations American Electric Power Service Corporation 28th Floor 1
Riverside Plaza Columbus, OH 43215-2373
FORM 10-K ANNUAL REPORT
The Annual Report (Form 10-K) to the Securities and Exchange Commission will
be available in April 2003 at no cost to shareholders.
Please address requests for copies to:
R. Todd Rimmer
Director of Financial Reporting
American Electric Power Service Corporation
26th Floor
1 Riverside Plaza
Columbus, OH 43215-2373
TRANSFER AGENT AND REGISTRAR OF CUMULATIVE PREFERRED STOCK
Equiserve Trust Company, N.A.
P.O. Box 43069
Providence, RI 02940-3069
Phone Number: 1-800-328-6955
Hearing Impaired Number: TDD: 1-800-952-9245
Website: http://www.equiserve.com
EXHIBIT 21
Subsidiaries of
American Electric Power Company, Inc.
As of December 31, 2002
The voting stock of each company shown indented is owned by the company
immediately above which is not indented to the same degree. Subsidiaries not
indented are directly owned by American Electric Power Company, Inc.
Percentage
of Voting
Securities
Location of Owned By
Name of Company Incorporation Immediate Parent
--------------- ------------- ----------------
American Electric Power Company, Inc. New York
American Electric Power Service Corporation New York 100.0
AEP C&I Company, LLC Delaware 100.0
AEP Coal, Inc. Nevada 100.0
AEP Communications, Inc. Ohio 100.0
AEP Energy Services, Inc. Ohio 100.0
AEP Generating Company Ohio 100.0
AEP Desert Sky LP, LLC Delaware 100.0
AEP Desert Sky LP II, LLC Delaware 100.0
Golden Prairie Holding Company LLC Delaware 100.0
AEP Investments, Inc. Ohio 100.0
Mutual Energy L.L.C. Delaware 100.0
AEP Power Marketing, Inc. Ohio 100.0
AEP T&D Services, LLC Delaware 100.0
AEP Pro Serv, Inc. Ohio 100.0
AEP Retail Energy LLC Delaware 100.0
AEP Texas POLR, LLC Delaware 100.0
AEP Resources, Inc. Ohio 100.0
Appalachian Power Company Virginia 98.7 (a)
Cedar Coal Co. West Virginia 100.0
Central Appalachian Coal Company West Virginia 100.0
Central Coal Company West Virginia 50.0 (b)
Southern Appalachian Coal Company West Virginia 100.0
Columbus Southern Power Company Ohio 100.0
Colomet, Inc. Ohio 100.0
Conesville Coal Preparation Company Ohio 100.0
Simco Inc. Ohio 100.0
Ohio Valley Electric Corporation Ohio 4.3 (e)
Indiana-Kentucky Electric Corporation Indiana 100.0
Franklin Real Estate Company Pennsylvania 100.0
Indiana Michigan Power Company Indiana 100.0
Blackhawk Coal Company Utah 100.0
Price River Coal Company, Inc. Indiana 100.0
Kentucky Power Company Kentucky 100.0
Kingsport Power Company Virginia 100.0
Ohio Power Company Ohio 99.2 (c)
Cardinal Operating Company Ohio 50.0 (d)
Central Coal Company West Virginia 50.0 (b)
Ohio Valley Electric Corporation Ohio 39.9 (e)
Indiana-Kentucky Electric Corporation Indiana 100.0
Wheeling Power Company West Virginia 100.0
Central and South West Corporation Delaware 100.0
AEP Texas Central Company Texas 100.0 (f)
CPL Capital I Delaware 100.0 (g)
CPL Transition Funding LLC (DE) Delaware 100.0 (g)
Public Service Company of Oklahoma Oklahoma 100.0
PSO Capital I Delaware 100.0
Southwestern Electric Power Company Delaware 100.0
The Arklahoma Corporation Arkansas 47.6
SWEPCo Capital I Delaware 100.0
Southwestern Arkansas Utilities Corporation Arkansas 100.0
Dolet Hills Lignite Company, LLC Delaware 100.0
AEP Texas North Company Texas 100.0 (h)
Notes:
a. 13,499,500 shares of Common Stock, all owned by parent, have one vote each
and 177,899 shares of Preferred Stock, all owned by the public, have one
vote each.
b. Owned 50% by Appalachian Power Company and 50% by Ohio Power Company.
c. 27,952,473 shares of Common Stock, all owned by parent, have one vote each
and 238,977 shares of Preferred Stock, all owned by the public, have one
vote each.
d. Ohio Power Company owns 50% of the stock; the other 50% is owned by a
corporation not affiliated with American Electric Power Company, Inc.
e. American Electric Power Company, Inc. and Columbus Southern Power Company
own 39.9% and 4.3% of the stock, respectively, and the remaining 55.8% is
owned by unaffiliated companies.
f. Central Power and Light Company changed its name to AEP Texas Central
Company.
g. The names of CPL Capital I and CPL Transition Funding LLC (DE)were
unchanged at December 31, 2002. AEP intends to change the names of these
companies in 2003.
h. West Texas Utilities Company changed its name to AEP Texas North Company.
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Exhibit 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos. 333-46360, 333-39402, 333-66048 and 333-62278 of American Electric Power Company, Inc. on Form S-8, Post-Effective Amendment No. 1 to Registration Statement No. 333-50109 of American Electric Power Company, Inc. on Form S-8, Post-Effective Amendment No. 3 to Registration Statement No. 33-01052 of American Electric Power Company, Inc. on Form S-8, Post Effective Amendment No. 3 to Registration Statement No. 33-01734 of American Electric Power Company, Inc. on Form S-3, Post Effective Amendment No. 1 to Registration Statement No. 333-86050 of American Electric Power Company, Inc. on Form S-3 and Registration Statement No. 333-58540 of American Electric Power Company, Inc. on Form S-3, of our reports dated February 21, 2003, appearing in and incorporated by reference in this Annual Report on Form 10-K of American Electric Power Company, Inc. for the year ended December 31, 2002.
/s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio March 20, 2003 |
Exhibit 24
POWER OF ATTORNEY
AMERICAN ELECTRIC POWER COMPANY, INC.
Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2002
The undersigned directors of AMERICAN ELECTRIC POWER COMPANY, INC., a New York corporation (the "Company"), do hereby constitute and appoint E. LINN DRAPER, JR., ARMANDO A. PENA and SUSAN TOMASKY, and each of them, their attorneys-in-fact and agents, to execute for them, and in their names, and in any and all of their capacities, the Annual Report of the Company on Form 10-K, pursuant to Section 13 of the Securities Exchange Act of 1934, for the fiscal year ended December 31, 2002, and any and all amendments thereto, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform every act and thing required or necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.
IN WITNESS WHEREOF, the undersigned have signed these presents this 25th day of February, 2003.
/s/ E. R. Brooks /s/ Leonard J. Kujawa ---------------------------- ------------------------------ E. R. Brooks Leonard J. Kujawa /s/ Donald M. Carlton /s/ Richard L. Sandor ---------------------------- ------------------------------ Donald M. Carlton Richard L. Sandor /s/ John P. DesBarres /s/ Thomas V. Shockley, III ---------------------------- ------------------------------ John P. DesBarres Thomas V. Shockley, III /s/ E. Linn Draper, Jr. /s/ Donald G. Smith ---------------------------- ------------------------------ E. Linn Draper, Jr. Donald G. Smith /s/ Robert W. Fri /s/ Linda Gillespie Stuntz ---------------------------- ------------------------------ Robert W. Fri Linda Gillespie Stuntz /s/ William R. Howell /s/ Kathryn D. Sullivan ---------------------------- ------------------------------ William R. Howell Kathryn D. Sullivan /s/ Lester A. Hudson, Jr. ---------------------------- Lester A. Hudson, Jr. |
Exhibit 99(a)
Certification Pursuant to Section 1350 of Chapter 63 Of Title 18 of the United States Code
I, E. Linn Draper, Jr., the chief executive officer of
American Electric Power Company, Inc. AEP Generating Company AEP Texas Central Company AEP Texas North Company Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company
(the "Companies"), certify that (i) the Annual Reports of the Companies on Form 10-K for the year ended December 31, 2002 (the "Reports") fully comply with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Reports fairly presents, in all material respects, the financial condition and results of operations of the Companies.
/s/ E. Linn Draper, Jr. E. Linn Draper, Jr. March 20, 2003 |
Exhibit 99(b)
Certification Pursuant to Section 1350 of Chapter 63 Of Title 18 of the United States Code
I, Susan Tomasky, the chief financial officer of
American Electric Power Company, Inc. AEP Generating Company AEP Texas Central Company AEP Texas North Company Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company
(the "Companies"), certify that (i) the Annual Reports of the Companies on Form 10-K for the year ended December 31, 2002 (the "Reports") fully comply with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Reports fairly presents, in all material respects, the financial condition and results of operations of the Companies.
/s/ Susan Tomasky Susan Tomasky March 20, 2003 |