American Electric Power Company 10-K 2005
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
For the fiscal year ended December 31, 2004
For the transition period from __________ to_________
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. o
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. x
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 o
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 o 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:
Securities registered pursuant to Section 12(g) of the Act:
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
This combined Form 10-K is separately filed by AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, American Electric Power Company, Inc., Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Except for American Electric Power Company, Inc., each registrant makes no representation as to information relating to the other registrants.
You can access financial and other information at AEP’s website, including AEP’s Principles of Business Conduct (which also serves as a code of ethics applicable to Item 10 of this Form 10-K), certain committee charters and Principles of Corporate Governance. The address is www.AEP.com. AEP makes available, free of charge on its website, copies of its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC.
The following abbreviations or acronyms used in this Form 10-K are defined below:
This report made by AEP and certain of its registrant subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and each of 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:
ITEM 1. BUSINESS
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 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, 2004, the subsidiaries of AEP had a total of 19,893 employees. Because it is a holding company rather than an operating company, AEP 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 934,000 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, 2004, APCo and its wholly owned subsidiaries had 2,375 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. APCo integrated into PJM on October 1, 2004.
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 707,000 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, 2004, CSPCo had 1,150 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. CSPCo integrated into PJM on October 1, 2004.
I&M (organized in Indiana in 1925) is engaged in the generation, transmission and distribution of electric power to approximately 579,000 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, 2004, I&M had 2,634 employees. Among the principal industries served are primary metals, transportation equipment, electrical and electronic machinery, fabricated metal products, rubber and miscellaneous plastic products and chemicals and allied products. Since 1975, I&M has leased and operated the assets of the municipal system of the City of Fort Wayne, Indiana. In addition to its AEP System interconnections, I&M also is interconnected with the following unaffiliated utility companies: Central Illinois Public Service Company, CG&E, Commonwealth Edison Company, Consumers Energy Company, Illinois Power Company, Indianapolis Power & Light Company, Louisville Gas and Electric Company, Northern Indiana Public Service Company, PSI Energy Inc. and Richmond Power & Light Company. I&M integrated into PJM on October 1, 2004.
KPCo (organized in Kentucky in 1919) is engaged in the generation, transmission and distribution of electric power to approximately 175,000 retail customers in an area in eastern Kentucky, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. At December 31, 2004, KPCo had 424 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. KPCo integrated into PJM on October 1, 2004.
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 and integrated into PJM on October 1, 2004. It purchases electric power from APCo for distribution to its customers. At December 31, 2004, Kingsport Power Company had 58 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 707,000 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, 2004, OPCo had 2,177 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. OPCo integrated into PJM on October 1, 2004.
PSO (organized in Oklahoma in 1913) is engaged in the generation, transmission and distribution of electric power to approximately 509,000 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, 2004, PSO had 1,197 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. PSO is a member of SPP.
SWEPCo (organized in Delaware in 1912) is engaged in the generation, transmission and distribution of electric power to approximately 444,000 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, 2004, SWEPCo had 1,378 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. SWEPCo is a member of SPP.
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 713,000 retail customers through REPs in southern Texas, and in supplying and marketing electric power at wholesale to other electric utility companies, a municipality, rural electric cooperatives and other market participants. At December 31, 2004, TCC had 933 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 188,000 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, 2004, TNC had 415 employees. Among the principal industries served by TNC are agriculture and the manufacturing or processing of cotton seed products, oil products, precision and consumer metal products, meat products and gypsum products. 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 and integrated into PJM on October 1, 2004. It purchases electric power from OPCo for distribution to its customers. At December 31, 2004, Wheeling Power Company had 61 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, 2004, AEPSC had 6,208 employees.
General Risks Of Our Regulated Operations
Rate regulation may delay or deny full recovery of costs. (Applies to each registrant.)
Our public utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. These rates are generally regulated based on an analysis of the applicable utility’s expenses incurred in a test year. Thus, the rates a utility is allowed to charge may or may not match its expenses at any given time. While rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commission will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs.
The rates that certain of our utilities may charge their customers may be reduced. (Applies to AEP and PSO, SWEPCo and TCC, respectively.)
In February 2003, the OCC required PSO to file all documents necessary for a general rate review. In October 2003 and June 2004, PSO filed financial information and supporting testimony in response to the OCC’s requirements indicating that its annual revenues were $41 million less than costs. The OCC Staff and intervenors filed testimony regarding their recommendations of a decrease in annual existing rates between $15 and $36 million. In addition, one party recommended that $30 million of PSO’s natural gas costs not be recovered from customers because it failed to implement a procurement strategy that this party alleged would have resulted in lower natural gas costs. PSO filed rebuttal testimony in February 2005which indicated a decrease of PSO’s revenue deficiency from $41 million to $28 million, although much of that decrease includes items that would be recovered through the fuel adjustment clause rather than through base rates. Hearings are scheduled to begin in March 2005, and a final decision is not expected any earlier than the second quarter of 2005. Management is unable to predict the ultimate effect of these proceedings on PSO’s revenues, results of operations, cash flows and financial condition.
In October 2002, SWEPCo filed with the 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 its order approving the merger between AEP and Central and South West Corporation (“CSW”). The LPSC’s merger order also provides that SWEPCo’s base rates are capped at the present level through mid-2005. In April 2004, SWEPCo filed updated financial information with a test year ending December 31, 2003 as required by the LPSC. Both filings indicated that SWEPCo’s current rates should not be reduced. Subsequently, direct testimony was filed on behalf of the LPSC recommending a $15 million reduction in SWEPCo’s Louisiana jurisdictional base rates. At this time, management is unable to predict the outcome of this proceeding. If a rate reduction is ordered in the future, it would adversely impact SWEPCo’s future results of operations and cash flows.
On June 26, 2003, the City of McAllen, Texas requested that TCC provide justification showing that its transmission and distribution rates should not be reduced. Other municipalities served by TCC passed similar rate review resolutions. TCC filed the requested support for its rates based on a test year ending June 30, 2003 with all of its municipalities and the PUCT. In February 2004, eight intervening parties and the PUCT Staff filed testimony recommending reductions to TCC’s requested $67 million rate increase. The recommendations ranged from a decrease in existing rates of approximately $100 million to an increase in TCC’s current rates of approximately $27 million. The ALJs issued recommendations in November 2004, which would reduce TCC’s existing rates by $51 million to $78 million from existing levels. The PUCT will hold additional hearings on two major issues in March 2005. The PUCT is expected to issue a decision in the first half of 2005. If the PUCT orders a rate reduction, it could adversely impact TCC’s future results of operations and cash flows.
The amount that PSO seeks to recover for fuel costs is currently being reviewed. (Applies to PSO.)
In 2002, PSO experienced a $44 million under-recovery of fuel costs resulting from a reallocation among AEP’s West zone public utility subsidiaries of purchased power costs for periods prior to January 1, 2002. In September 2003, the OCC expanded the case to include a full review of PSO’s 2001 fuel and purchased power practices. PSO filed testimony in February 2004. An intervenor, the OCC Staff filed testimony and the Attorney General of Oklahoma have made filings indicating that recovery should be disallowed altogether or reduced in the range of $18 million to $9 million. These filings raised certain issues of an allocation approved under FERC. The ALJ recommended that the OCC lacks authority to examine whether PSO deviated from the FERC allocation methodology and that any such complaints should be addressed at the FERC. The OCC conducted a hearing on the jurisdictional matter in January 2005 but has not issued a decision. If the OCC determines, as a result of the review that a portion of PSO’s fuel and purchased power costs should not be recovered, there could be an adverse effect on PSO’s results of operations, cash flows and possibly financial condition.
The base rates that certain of our utilities charge are currently capped or frozen. (Applies to AEP, CSPCo, I&M, OPCo and SWEPCo.)
Base rates charged to customers in Indiana, Michigan, Louisiana and Ohio are currently either frozen or capped. To the extent our costs in these states exceed the applicable cap or frozen rate, those costs are not recoverable from customers.
Certain of our revenues and results of operations are subject to risks that are beyond our control. (Applies to each registrant.)
Unless mitigated by timely and adequate regulatory recovery, the cost of repairing damage to our utility facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events, in excess of reserves established for such repairs, may adversely impact our revenues, operating and capital expenses and results of operations.
We are exposed to nuclear generation risk. (Applies to AEP, I&M and TCC.)
Through I&M and TCC, we have interests in four nuclear generating units, which interests equal 2,740 MW, or 7% of our generation capacity. (TCC has entered an agreement to sell its interest in two nuclear generating units.) We are, therefore, also subject to the risks of nuclear generation, which include the following:
The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants such as ours. In addition, although we have no reason to anticipate a serious nuclear incident at our plants, if an incident did occur, it could harm our results of operations or financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit.
The different regional power markets in which we compete or will compete in the future have changing transmission regulatory structures, which could affect our performance in these regions. (Applies to each registrant.)
Our results are likely to be affected by differences in the market and transmission regulatory structures in various regional power markets. Problems or delays that may arise in the formation and operation of new regional transmission organizations, or “RTOs”, may restrict our ability to sell power produced by our generating capacity to certain markets if there is insufficient transmission capacity otherwise available. The rules governing the various regional power markets may also change from time to time which could affect our costs or revenues. Because it remains unclear which companies will be participating in the various regional power markets, or how RTOs will develop or what regions they will cover, we are unable to assess fully the impact that these power markets may have on our business.
AEP’s East zone public utility subsidiaries joined PJM on October 1, 2004. Two of AEP’s west zone public utility subsidiaries are members of SPP. In February 2004, FERC granted RTO status to the SPP, subject to fulfilling specified requirements. In October 2004, the FERC issued an order granting final RTO status to SPP subject to certain filings.
The Louisiana and Arkansas Commissions are concerned about the effect on retail ratepayers of utilities in Louisiana and Arkansas joining RTOs. The Commissions have ordered the utilities in those states, including us, to analyze and submit to the Commissions the costs and benefits of RTO options available to the utilities. The Louisiana Commission has also determined that certain RTO structures that contemplate legally transferring transmission assets to it are presumptively not in the public interest.
To the extent we are faced with conflicting state and Federal requirements as to our participation in RTOs, it could adversely affect our ability to operate and recover transmission costs from retail customers. Management is unable to predict the outcome of these transmission regulatory actions and proceedings or their impact on the timing and operation of RTOs, our transmission operations or future results of operations and cash flows.
The FERC may reduce the amount we may charge third parties for using our transmission facilities. (Applies to AEP and AEP’s East zone public utility subsidiaries.)
In July 2003, the FERC issued an order directing PJM and the MISO to make compliance filings for their respective OATTs to eliminate the transaction-based charges for through and out (T&O) transmission service on transactions where the energy is delivered within the proposed Midwest ISO and PJM expanded regions (Combined Footprint). The elimination of the T&O rates will reduce the transmission service revenues collected by the RTOs and thereby reduce the revenues received by transmission owners under the RTOs’ revenue distribution protocols.
AEP and several other utilities in the Combined Footprint filed a proposal for new rates to become effective December 1, 2004. In November 2004, FERC eliminated the T&O rates and replaced the rates temporarily through March 2006 with seams elimination cost adjustment (SECA) fees. AEP’s East zone public utility subsidiaries received approximately $196 million of T&O rate revenues for the twelve months ended September 30, 2004, the last twelve months prior to joining PJM. The portion of those revenues associated with transactions for which the T&O rate is being eliminated and replaced by SECA fees was $171 million. Effective April 2006, all transmission costs that would otherwise have been defrayed by T&O rates in the Combined Footprint will be subject to recovery from native load customers of AEP’s East zone public utility subsidiaries. At this time, management is unable to predict whether any resultant increase in rates applicable to AEP’s internal load will be recoverable on a timely basis from state retail customers. Unless new replacement rates compensate AEP for its lost revenues, and unless any increase in AEP’s East zone public utility subsidiaries’ transmission expenses from these new rates are fully recovered in retail rates on a timely basis, future results of operations, cash flows and financial condition will be adversely affected.
We are subject to regulation under the Public Utility Holding Company Act of 1935. (Applies to each registrant.)
Our system is subject to the jurisdiction of the SEC under PUHCA. The rules and regulations under PUHCA impose a number of restrictions on the operations of registered holding company systems. These restrictions include a requirement that the SEC approve in advance securities issuances, sales and acquisitions of utility assets, sales and acquisitions of securities of utility companies and acquisitions of other businesses. PUHCA also generally limits the operations of a registered holding company to a single integrated public utility system, plus additional energy-related businesses. PUHCA rules limit the dividends that our subsidiaries may pay from unearned surplus.
Our merger with CSW may ultimately be found to violate PUHCA. (Applies to AEP, PSO, SWEPCo, TCC and TNC.)
We acquired CSW in a merger completed on June 15, 2000. Among the more significant assets we acquired as a result of the merger were four additional domestic electric utility companies - PSO, SWEPCo, TCC and TNC. On January 18, 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC’s June 14, 2000 order approving the merger failed to properly find that the merger meets the requirements of 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’s requirement that the electric utilities be “physically interconnected” and confined to a “single area or region.” In August 2004, the SEC announced it would conduct hearings on this issue. A hearing was held January 10, 2005 before an ALJ. An initial decision is expected from the ALJ later this year. The SEC will have the opportunity to review the initial decision.
We believe that the merger meets the requirements of PUHCA and expect the matter to be resolved favorably. We can give no assurance, however, that: (i) the SEC or any applicable court review will find that the merger complies with PUHCA, or (ii) the SEC or any applicable court review will not impose material adverse conditions on us in order to find that the merger complies with PUHCA. If the merger were ultimately found to violate PUHCA, we could be required to take remedial actions or divest assets, which could harm our results of operations or financial condition.
We operate in a non-uniform and fluid regulatory environment. (Applies to each registrant.)
In most instances and in varying degrees, the rates charged by the domestic utility subsidiaries are approved by the FERC and the eleven state utility commissions. FERC regulates wholesale electricity operations and transmission rates and the state commissions regulate retail generation and distribution rates. Several of the eleven state retail jurisdictions in which our domestic electric utilities operate have enacted restructuring legislation. Restructuring legislation in Texas requires the legal separation of generation and related assets from the transmission and distribution assets of the electric utilities in that state. In Ohio, we are complying with restructuring legislation through the continued functional separation of the operations of our Ohio utility subsidiaries. As a result of restructuring legislation in Texas and Ohio, a significant portion of our domestic generation is no longer directly regulated by state utility commissions as to rates. TCC has sold some of its generation in Texas and is in the process of selling its remaining generation. Our utility operations in the remaining state retail jurisdictions that have not enacted any restructuring legislation currently plan to adhere to the vertically-integrated utility model with cost recovery through regulated rates.
Our business plan is based on the regulatory framework as described. There can be no assurance that the states that have pursued restructuring will not reverse such policies; nor can there be assurance that the states that have not enacted restructuring legislation will not do so in the future. In addition to the multiple levels of regulation at the state level in which we operate, our business is subject to extensive federal regulation. There can be no assurance that the federal legislative and regulatory initiatives (which have occurred over the past few years and which have generally facilitated competition in the energy sector) will continue or will not be reversed.
Further alteration of the regulatory landscape in which we operate will impact the effectiveness of our business plan and may, because of the continued uncertainty, harm our financial condition and results of operations.
Risks Related to Market, Economic or International Financial Volatility
Downgrades in our credit ratings could negatively affect our ability to access capital and/or to operate our power trading businesses. (Applies to each registrant other than AEGCo.)
Following the bankruptcy of Enron, the credit ratings agencies initiated a thorough review of the capital structure and the quality and stability of earnings of energy companies, including us. The agencies made ratings changes at that time. Further negative ratings actions could constrain the capital available to our industry and could limit our access to funding for our operations. Our business is capital intensive, and we are dependent upon our ability to access capital at rates and on terms we determine to be attractive. If our ability to access capital becomes significantly constrained, our interest costs will likely increase and our financial condition could be harmed and future results of operations could be adversely affected.
Moody’s has assigned an investment grade credit rating to the senior unsecured long-term debt of each registrant other than AEGCo (collectively, the “Rated Issuers”). Moody’s has further assigned an outlook of stable for each of the Rated Issuers other than AEP, which Moody’s assigned an outlook of positive in 2004. S&P has also assigned an investment grade credit rating to the senior unsecured long-term debt of each of the Rated Issuers. S&P has assigned an outlook of stable for each of the Rated Issuers. Fitch has also assigned an investment grade credit rating (with stable outlook) to the senior unsecured long-term debt of each of the Rated Issuers. Apart from Moody’s improving the outlook on AEP noted above, none of these ratings was adjusted by any rating agency during 2004.
Moody’s has assigned AEP a short-term debt rating of P-3. S&P has assigned AEP a short-term debt rating of A-2. Fitch has assigned AEP a short-term debt rating of F-2. As a result of the split rating, AEP’s access to the commercial paper market may be limited and the short-term borrowing costs of each registrant may increase (because AEP’s subsidiaries conduct short-term borrowing through AEP and on the same terms available to AEP).
If Moody’s or S&P were to downgrade the long-term rating of any of the Rated Issuers, particularly below investment grade, the borrowing costs of that Rated Issuer would increase, which would diminish its financial results. In addition, it would likely be required to pay a higher interest rate in future financings, and its potential pool of investors and funding sources could decrease.
Our power trading business relies on the investment grade ratings of our individual public utility subsidiaries’ senior unsecured long-term debt. Most of our counterparties require the creditworthiness of an investment grade entity to stand behind transactions. If those ratings were to decline below investment grade, our ability to operate our power trading business profitably would be diminished because we would likely have to deposit cash or cash-related instruments which would reduce our profits.
The underfunded condition of our retirement plans may require additional significant contributions. (Applies to each registrant.)
AEP provides defined benefit pension plans (“Pension Plans”) for the employees of our subsidiaries. In addition, AEP provides health care and life insurance benefit plans for retired employees.
Low prevailing interest rates have increased the pension plans’ liability. The combined Pension Plans’ liabilities based on service and pay to date (“Accumulated Benefit Obligation”) exceeded the value of the assets at December 31, 2004. As of December 31, 2004, the fair value of the Pension Plans assets was $3.56 billion while the Accumulated Benefit Obligation was estimated at $4.0 billion, an underfunding of approximately $450 million. For the individual pension plans that were underfunded based on the Accumulated Benefit Obligation, underfunding totaled approximately $474 million. In order to fund the qualified pension plans fully by the end of 2005, a discretionary contribution of $200 million was made in the fourth quarter of 2004 and discretionary contributions of $100 million per quarter are expected in 2005.
AEP also made contributions of $137 million to postretirement health care and life insurance benefits trust funds in 2004, and expects to contribute significant amounts in the future.
We cannot predict the future performance of the investment markets. A downturn in the investment markets could have a material negative impact on the net asset value of the plans’ trust accounts and increase the underfunding of the Pension Plans, net of benefit obligations. This may necessitate significant cash contributions to the Pension Plans. Changes in interest rates may also materially affect the pension and postretirement health care and life insurance benefit liabilities and the cash contributions needed to fund those liabilities. Changes in the laws and regulations governing the plans may increase or decrease the required contributions.
Our operating results may fluctuate on a seasonal and quarterly basis. (Applies to each registrant.)
Electric power generation 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. As a result, our overall operating results in the future may fluctuate substantially on a seasonal basis. The pattern of this fluctuation may change depending on the terms of power sale contracts that we enter into. In addition, we have historically sold less power, and consequently earned less income, when weather conditions are milder. We expect that unusually mild weather in the future could diminish our results of operations and harm our financial condition.
Changes in technology may significantly affect our business by making our power plants less competitive. (Applies to each registrant.)
A key element of our business model is that generating power at central power plants achieves economies of scale and produces power at relatively low cost. There are other technologies that produce power, most notably fuel cells, microturbines, windmills and photovoltaic (solar) cells. It is possible that advances in technology will reduce the cost of alternative methods of producing power to a level that is competitive with that of most central power station electric production. If this were to happen and if these technologies achieved economies of scale, our market share could be eroded, and the value of our power plants could be reduced. Changes in technology could also alter the channels through which retail electric customers buy power, thereby harming our financial results.
Changes in commodity prices may increase our cost of producing power or decrease the amount we receive from selling power, harming our financial performance. (Applies to each registrant.)
We are heavily exposed to changes in the price and availability of coal because most of our generating capacity is coal-fired. We have contracts of varying durations for the supply of coal for most of our existing generation capacity, but as these contracts end or otherwise not honored, we may not be able to purchase coal on terms as favorable as the current contracts.
We also own natural gas-fired facilities, which increases our exposure to the more volatile market prices of natural gas.
Changes in the cost of coal or natural gas and changes in the relationship between such costs and the market prices of power will affect our financial results. Since the prices we obtain for power may not change at the same rate as the change in coal or natural gas costs, we may be unable to pass on the changes in costs to our customers. In addition, the prices we can charge our retail customers in some jurisdictions are capped and our fuel recovery mechanisms in other states are frozen for various periods of time.
In addition, actual power prices and fuel costs will differ from those assumed in financial projections used to value our trading and marketing transactions, and those differences may be material. As a result, our financial results may be diminished in the future as those transactions are marked to market.
At times, demand for power could exceed our supply capacity. (Applies to each registrant other than TCC and TNC.)
We are currently obligated to supply power in parts of eleven states. From time to time because of unforseen circumstances the demand for power required to meet these obligations could exceed our available generation capacity. If this occurs, we would have to buy power on the market. We may not always have the ability to pass these costs on to our customers because some of the states we operate in do not allow us to increase our rates in response to increased fuel cost charges. Since these situations most often occur during periods of peak demand, it is possible that the market price for power at that time would be very high. Even if a supply shortage was brief, we could suffer substantial losses that could diminish our results of operations.
Risks Relating To State Restructuring
We have limited ability to pass our costs of production on to our customers. (Applies to each registrant.)
We are exposed to risk from changes in the market prices of coal and natural gas used to generate power where generation is no longer regulated or where existing fuel clauses are suspended or frozen. Recently, the price of coal and natural gas has increased materially. The protection afforded by retail fuel clause recovery mechanisms has been eliminated by the implementation of customer choice in Ohio and in the ERCOT area of Texas. There may be similar risks should customer choice be similarly implemented in other states. Because the risk of generating costs cannot be passed through to customers as a matter of right in Ohio and the ERCOT area of Texas, we retain these risks.
A fuel clause in West Virginia has been suspended per a settlement reached in a state restructuring proceeding. However, as restructuring has not been implemented in West Virginia, the fuel clause may be reactivated. An extension of the currently pending fuel clause in Indiana is being negotiated.
Our default service obligations in Ohio do not restrict customers from switching suppliers of power. (Applies to AEP, CSPCo and OPCo.)
Those default service customers that we serve in Ohio may choose to purchase power from alternative suppliers. Should they choose to switch from us, our sales of power may decrease. Customers originally choosing alternative suppliers may switch to our default service obligations. This may increase demand above our facilities’ available capacity. Thus, any such switching by customers could have an adverse effect on our results of operations and financial position. Conversely, to the extent the power sold to meet the default service obligations could have been sold to third parties at more favorable wholesale prices, we will have incurred potentially significant lost opportunity costs.
If CSPCo and OPCo are unable to remain functionally separated, they will need SEC approval to legally separate their assets. (Applies to CSPCo and OPCo.)
Ohio has enacted restructuring legislation in the Ohio Act. CSPCo and OPCo each currently comply with the Ohio Act as a functionally separated electric utility. The PUCO has approved the rate stabilization plan that does not contemplate legal separation at least through 2008. However, we can give no assurance that we can remain functionally separated following that. If CSPCo and OPCo are unable to remain functionally separated and we are required to legally separate, they would need SEC approval to legally separate.
Some laws and regulations governing restructuring of the wholesale generation market in Michigan and Virginia have not yet been interpreted or adopted and could harm our business, operating results and financial condition. (Applies to AEP and APCo and I&M, respectively.)
While the electric restructuring laws in Michigan and Virginia established the general framework governing the retail electric market, the laws required the utility commission in each state to issue rules and determinations implementing the laws. Some of the regulations governing the retail electric market have not yet been adopted by the utility commission in each state. These laws, when they are interpreted and when the regulations are developed and adopted, may harm our business, results of operations and financial condition. Virginia restructuring legislation was enacted in 1999 providing for retail choice of generation suppliers to be phased in over two years beginning January 1, 2002. It 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 with VSCC 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. Legislation in Virginia has been adopted which extends a cap on electricity rates until 2010.
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, 2004, none of I&M’s Michigan customers have elected to change suppliers and no alternative electric suppliers are registered to compete in I&M’s Michigan service territory.
There is uncertainty as to our recovery of deferred fuel balances and stranded costs resulting from industry restructuring in Texas. (Applies to AEP and TCC.)
In 2002, TCC filed its final fuel reconciliation with the PUCT to reconcile fuel costs to be included in its deferred over-recovery balance in the true-up proceeding described below. This reconciliation covers the period from July 1998 through December 2001. The PUCT will review an ALJ report addressing the reconciliation and will likely issue a decision in the first quarter of 2005. The over-recovery balance and the subsequent provisions for probable disallowances totaled $212 million, including interest, at December 31, 2004. The PUCT will net the final amount against recoverable amounts determined by the true-up proceeding.
Restructuring legislation in Texas required utilities with stranded costs to use market-based methods to value certain generating assets for determining stranded costs. We have elected to use the sale of assets method to determine the market value of all of the generation assets of TCC for stranded cost purposes. The amount of stranded costs under this market valuation methodology will be the amount by which the 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. TCC’s sale of its generating assets will be subject to a review in a true-up proceeding conducted by the PUCT. TCC’s recorded net regulatory asset for amounts subject to approval in the true-up proceeding, net of the deferred fuel over-recovery described above, is approximately $1.6 billion. We estimate that TCC’s true-up filing will exceed the total of its recorded net regulatory asset. Management expects that the true-up proceeding will be contentious and could possibly result in disallowances. If we are unable, after the true-up proceeding, to recover all or a portion of our stranded plant costs, generation-related net regulatory assets, wholesale capacity auction true-up regulatory assets, other restructuring true-up items and costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition.
Collection of our revenues in Texas is concentrated in a limited number of REPs. (Applies to AEP, TCC and TNC.)
Our revenues from the distribution of electricity in the ERCOT area of Texas are collected from REPs that supply the electricity we distribute to their customers. Currently, we do business with approximately forty three REPs. Adverse economic conditions, structural problems in the new Texas market or financial difficulties of one or more REPs could impair the ability of these REPs to pay for our services or could cause them to delay such payments. We depend on these REPs for timely remittance of payments. Any delay or default in payment could adversely affect the timing and receipt of our cash flows thereby have an adverse effect on our liquidity.
We may not be able to respond effectively to competition. (Applies to each registrant.)
We may not be able to respond in a timely or effective manner to the many changes in the power industry that may occur as a result of regulatory initiatives to increase competition. These regulatory initiatives may include deregulation of the electric utility industry in some markets. To the extent that competition increases, our profit margins may be negatively affected. Industry deregulation may not only continue to facilitate the current trend toward consolidation in the utility industry but may also encourage the disaggregation of other vertically integrated utilities into separate generation, transmission and distribution businesses. As a result, additional competitors in our industry may be created, and we may not be able to maintain our revenues and earnings levels or pursue our growth strategy.
While demand for power is generally increasing throughout the United States, the rate of construction and development of new, more efficient electric generation facilities may exceed increases in demand in some regional electric markets. The start-up of new facilities in the regional markets in which we have facilities could increase competition in the wholesale power market in those regions, which could harm our business, results of operations and financial condition. Also, industry restructuring in regions in which we have substantial operations could affect our operations in a manner that is difficult to predict, since the effects will depend on the form and timing of the restructuring.
Risks Related to Environmental Regulation
Our costs of compliance with environmental laws are significant, and the cost of compliance with future environmental laws could harm our cash flow and profitability. (Applies to each registrant other than TCC and TNC.)
Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and health and safety. Compliance with these legal requirements requires us to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees and permits at all of our facilities. These expenditures have been significant in the past and we expect that they will increase in the future. Costs of compliance with environmental regulations could harm our industry, our business and our results of operations and financial position, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets we operate increase. Additionally, in July 2004 attorneys general of eight states and others sued AEP and other utilities alleging that carbon dioxide emissions from power generating facilities constitute a public nuisance under federal common law. The suits seek injunctive relief in the form of specific emission reduction commitments from the defendants. While we believe the claims are without merit, the costs associated with reducing carbon dioxide emissions could harm our business and our results of operations and financial position.
We anticipate that we will incur considerable capital costs for compliance. (Applies to each registrant other than TCC and TNC.)
Most of our generating capacity is coal burning. We plan to install new emissions control equipment and may be required to upgrade existing equipment, purchase emissions allowances or reduce operations. We estimate that we will invest approximately $600 million to comply with existing federal and state regulations designed to limit nitrogen oxide (“NOx”) emissions and approximately $1.2 billion to comply with existing federal and state regulations designed to limit sulfur dioxide (“SO2”) emissions. We estimate that we will invest approximately $1.8 billion (and an additional $150 million in operation and maintenance expenses) to comply with currently proposed, but as yet unadopted, federal regulations designed to limit NOx, SO2 and mercury emissions through 2010, assuming certain contingencies. Between 2011 and 2020 we expect to incur additional costs for pollution control technology retrofits and investment of $1.6 billion. However, post-2010 capital investment estimates are quite uncertain. All of our estimates are subject to significant uncertainties about the outcome of several interrelated assumptions and variables, including timing of implementation, required levels of reductions, allocation requirements of the new rules, and our selected compliance alternatives. As a result, we cannot estimate our compliance costs with certainty. The actual costs to comply could differ significantly from the estimates. All of the costs are incremental to our current investment base and operating cost structure. These expenditures for pollution control technologies, replacement generation and associated operating costs should be recoverable from customers through regulated rates (in regulated jurisdictions) and should be recoverable through market prices (in deregulated jurisdictions). If not, those costs could adversely affect future results of operations and cash flows, and possibly financial condition.
Governmental authorities may assess penalties on us for failures to comply with environmental laws and regulations. (Applies to each registrant.)
If we fail to comply with environmental laws and regulations, even if caused by factors beyond our control, that failure may result in the assessment of civil or criminal penalties and fines against us. Recent lawsuits by the EPA and various states filed against us highlight the environmental risks faced by generating facilities, in general, and coal-fired generating facilities, in particular.
Since 1999, we have been involved in litigation regarding generating plant emissions under the Clean Air Act. Federal EPA and a number of states alleged that we and eleven unaffiliated utilities modified certain units at coal-fired generating plants in violation of the Clean Air Act. Federal EPA filed complaints against certain 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.
If these actions are resolved against us, substantial modifications of our existing coal-fired power plants would be required. In addition, we could be required to invest significantly in additional emission control equipment, accelerate the timing of capital expenditures, pay penalties and/or halt operations. Moreover, our results of operations and financial position could be reduced due to the timing of recovery of these investments and the expense of ongoing litigation.
Other parties have settled similar lawsuits. An unaffiliated utility which operates certain plants jointly owned by CSPCo reached a tentative agreement to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing and a settlement could impact the operation of certain of the jointly owned plants. Until a final settlement is reached, CSPCo will be unable to determine the settlement’s impact on its jointly owned facilities and its future results of operations and cash flows.
Risks Related to Power Trading and Wholesale Businesses
Our revenues and results of operations are subject to market risks that are beyond our control. (Applies to each registrant.)
We sell power from our generation facilities into the spot market or other competitive power markets or on a contractual basis. We also enter into contracts to purchase and sell electricity, natural gas, emission allowances and coal as part of our power marketing and energy trading operations. With respect to such transactions, we are not guaranteed any rate of return on our capital investments through mandated rates, and our revenues and results of operations are likely to depend, in large part, upon prevailing market prices for power in our regional markets and other competitive markets. These market prices may fluctuate substantially over relatively short periods of time. It is reasonable to expect that trading margins may erode as markets mature and that there may be diminished opportunities for gain should volatility decline. In addition, FERC, which has jurisdiction over wholesale power rates, as well as independent system operators that oversee some of these markets, may impose price limitations, bidding rules and other mechanisms to address some of the volatility in these markets. Fuel prices may also be volatile, and the price we can obtain for power sales may not change at the same rate as changes in fuel costs. These factors could reduce our margins and therefore diminish our revenues and results of operations.
Volatility in market prices for fuel and power may result from:
Our power trading (including coal, gas and emission allowances trading and power marketing) and risk management policies cannot eliminate the risk associated with these activities. (Applies to each registrant.)
Our power trading (including coal, gas and emission allowances trading and power marketing) activities expose us to risks of commodity price movements. We attempt to manage our exposure through enforcement of established risk limits and risk management procedures. These risk limits and risk management procedures may not work as planned and cannot eliminate the risks associated with these activities. As a result, we cannot predict the impact that our energy trading and risk management decisions may have on our business, operating results or financial position.
We routinely have open trading positions in the market, within established guidelines, resulting from the management of our trading portfolio. To the extent open trading positions exist, fluctuating commodity prices can improve or diminish our financial results and financial position.
Our power trading and risk management activities, including our power sales agreements with counterparties, rely on projections that depend heavily on judgments and assumptions by management of factors such as the future market prices and demand for power and other energy-related commodities. These factors become more difficult to predict and the calculations become less reliable the further into the future these estimates are made. Even when our policies and procedures are followed and decisions are made based on these estimates, results of operations may be diminished if the judgments and assumptions underlying those calculations prove to be wrong or inaccurate.
Our financial performance may be adversely affected if we are unable to operate our pooled electric generating facilities successfully. (Applies to each registrant.)
Our performance is highly dependent on the successful operation of our electric generating facilities. Operating electric generating facilities involves many risks, including:
A decrease or elimination of revenues from power produced by our electric generating facilities or an increase in the cost of operating the facilities would adversely affect our results of operations.
Parties with whom we have contracts may fail to perform their obligations, which could harm our results of operations. (Applies to each registrant.)
We are exposed to the risk that counterparties that owe us money or power could breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices that may exceed our contractual prices, which would cause our financial results to be diminished and we might incur losses. Although our estimates take into account the expected probability of default by a counterparty, our actual exposure to a default by a counterparty may be greater than the estimates predict.
We are contractually required to operate a power generation facility that we have agreed to lease but the energy sales market for the facility’s excess energy is over-supplied. (Applies to AEP.)
We have agreed to lease from Juniper Capital L.P. a non-regulated merchant power generation facility (“Facility”) near Plaquemine, Louisiana. We sublease the Facility to Dow. We operate the Facility for Dow. Dow uses a portion of the energy produced by the Facility and sells the excess power to us. We have agreed to sell up to all of the excess 800 MW to a third party at a price that is currently in excess of market. This agreement is now being litigated. If it is unenforceable, we will be required to find new purchasers for up to 800 MW. There can be no assurance that this power will be sold at prices that will exceed our costs to produce it. If that were the case, as a result of our obligations to Dow, we would be required to operate the Facility at a loss.
We rely on electric transmission facilities that we do not own or control. If these facilities do not provide us with adequate transmission capacity, we may not be able to deliver our wholesale electric power to the purchasers of our power. (Applies to each registrant.)
We depend on transmission facilities owned and operated by other unaffiliated power companies to deliver the power we sell at wholesale. This dependence exposes us to a variety of risks. If transmission is disrupted, or transmission capacity is inadequate, we may not be able to sell and deliver our wholesale power. If a region’s power transmission infrastructure is inadequate, our recovery of wholesale costs and profits may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure.
The FERC has issued electric transmission initiatives that require electric transmission services to be offered unbundled from commodity sales. Although these initiatives are designed to encourage wholesale market transactions for electricity and gas, access to transmission systems may in fact not be available if transmission capacity is insufficient because of physical constraints or because it is contractually unavailable. We also cannot predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets.
We do not fully hedge against price changes in commodities. (Applies to each registrant.)
We routinely enter into contracts to purchase and sell electricity, natural gas, coal and emission allowances as part of our power marketing and energy and emission allowances trading operations. In connection with these trading activities, we routinely enter into financial contracts, including futures and options, over-the counter options, financially-settled swaps and other derivative contracts. These activities expose us to risks from price movements. If the values of the financial contracts change in a manner we do not anticipate, it could harm our financial position or reduce the financial contribution of our trading operations.
We manage our exposure by establishing risk limits and entering into contracts to offset some of our positions (i.e., to hedge our exposure to demand, market effects of weather and other changes in commodity prices). However, we do not always hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility, our results of operations and financial position may be improved or diminished based upon our success in the market.
We are exposed to losses resulting from the bankruptcy of Enron Corp. (Applies to AEP, except for last paragraph, which applies to each registrant.)
In 2002, certain of our subsidiaries filed claims against Enron Corp. (“Enron”) and its subsidiaries in the Enron bankruptcy proceeding pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron’s bankruptcy, certain of our subsidiaries 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 from Enron remained unsettled at the date of Enron’s bankruptcy.
Cushion gas use agreements - In connection with the 2001 acquisition of HPL, we also entered into an agreement with BAM Lease Company, which grants HPL the exclusive right to use approximately 65 BCF of cushion gas required for the normal operation of the Bammel gas storage facility. At the time of our acquisition of HPL, Bank of America (“BOA”) and certain other banks (together with BOA, “BOA Syndicate”) and Enron entered into an agreement granting HPL the exclusive use of 65 BCF of cushion gas. Also at the time of our acquisition, Enron and the BOA Syndicate also released HPL from all prior and future liabilities and obligations in connection with the financing arrangement. After the Enron bankruptcy, HPL was informed by the BOA Syndicate of a purported default by Enron under the terms of the financing arrangement. We are currently litigating the rights to the cushion gas.
In February 2004, in connection with BOA’s dispute, Enron filed Notices of Rejection regarding the cushion gas use agreement and other incidental agreements. We have objected to Enron’s attempted rejection of these agreements. In January 2005 we sold a 98% controlling interest in HPL, including the Bammel gas storage facility. We indemnified the purchaser for damages, if any, arising from the litigation with BOA.
Commodity trading settlement disputes - In September 2003, Enron filed a complaint in the Bankruptcy Court against AEPES challenging AEP’s offsetting of receivables and payables and related collateral across various Enron entities and seeking payment of approximately $125 million plus interest in connection with gas related trading transactions. AEP has asserted its right to offset trading payables owed to various Enron entities against trading receivables due to several AEP subsidiaries. The parties are currently in non-binding court-sponsored mediation.
In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC seeking approximately $93 million plus interest in connection with a transaction for the sale and purchase of physical power among Enron, AEP and Allegheny Energy Supply, LLC during November 2001. Enron’s claim seeks to unwind the effects of the transaction. AEP believes it has several defenses to the claims in the action being brought by Enron. The parties are currently in non-binding court-sponsored mediation. Management is unable to predict the final resolution of these disputes, however the impact on results of operations, cash flows and financial condition could be material.
Potential for disruption exists if the delay of a FERC market power mitigation order is lifted. (Applies to each registrant.)
In July 2004, the FERC issued an order directing AEP and two unaffiliated utilities to file generation market power analyses within 30 days. We have presented evidence to FERC to demonstrate that we do not possess market power in geographic areas where we sell wholesale power. In a December 2004 order, FERC found that AEP passed the screens in PJM and ERCOT, but not in the SPP area. Because AEP did not pass the market share screen in SPP, FERC initiated a proceeding under Section 206 of the FPA in which AEP is rebuttably presumed to possess market power in SPP. Consequently, our revenues from sales in SPP at market based rates after March 6, 2005 will be collected subject to refund to the extent that prices are ultimately found not to be just and reasonable. In February 2005 AEP filed with the FERC revisions to its market-based rate tariffs that cap the rates of wholesale power that AEP delivers within its control area of the SPP. We are unable to predict the timing or impact of any further action by the FERC.
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, 2004 are as follows:
HOLDING COMPANY REGULATION
The provisions of PUHCA, are administered by the SEC. PUHCA regulates many aspects of a registered holding company system, such as the AEP System. PUHCA limits the operations of a registered holding company system to a single integrated public utility system and such other businesses as are incidental or necessary to the operations of the system. In addition, PUHCA governs, among other things, financings, sales or acquisitions of utility assets and intra-system transactions.
PUHCA and the rules and orders of the SEC currently require that transactions between associated companies in a registered holding company system be performed at cost, with limited exceptions. Over the years, the AEP System has developed numerous affiliated service, sales and construction relationships and, in some cases, invested significant capital and developed significant operations in reliance upon the ability to recover its full costs under these provisions.
Legislation has been introduced in numerous sessions of Congress that would repeal PUHCA, but no such legislation has passed.
On June 15, 2000, a wholly owned merger subsidiary of AEP merged with and into CSW (now known as AEP Utilities, Inc.). 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.
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.” A hearing was held January 10, 2005 before an ALJ. An initial decision is expected from the ALJ later this year. The SEC will have the opportunity to review the initial decision.
Management believes that the merger meets the requirements of PUHCA and expects the matter to be resolved favorably.
Companies within the AEP System generally use short-term debt to finance working capital needs, acquisitions and construction. The companies periodically issue long-term debt to reduce short-term debt. In recent history short-term debt has been provided by AEP’s commercial paper program and revolving credit facilities. Proceeds were made available to subsidiaries under the AEP corporate borrowing program. Throughout 2004, AEP was successful in accessing the commercial paper market. Certain public utility subsidiaries of AEP also sell accounts receivable to provide liquidity.
AEP’s revolving credit agreements (which backstop the commercial paper program) include covenants and events of default typical for this type of facility, including a maximum debt/capital test and a $50 million cross-acceleration provision. At December 31, 2004, AEP was in compliance with its debt covenants. With the exception of a voluntary bankruptcy or insolvency, any event of default has either or both a cure period or notice requirement before termination of the agreements. A voluntary bankruptcy or insolvency would be considered an immediate termination event. See Management’s Financial Discussion and Analysis of Results of Operations, included in the 2004 Annual Reports, under the heading entitled Financial Condition for additional information with respect to AEP’s credit agreements.
AEP’s subsidiaries have also utilized, and expect to continue to utilize, additional financing arrangements, such as leasing arrangements, including the leasing of utility assets and coal mining and transportation equipment and facilities.
In 2004, AEP executives met with representatives of the rating agencies to review AEP and its registrant subsidiaries’ historical and forecasted financial condition, operations and other matters.
In August 2004, Moody’s placed AEP on positive outlook. In July 2004, S&P upgraded the senior secured ratings of PSO and SWEPCo to A- from BBB. To date, S&P has not changed the ratings of AEP or any other of its rated subsidiaries. Fitch did not change the ratings of AEP or its rated subsidiaries during 2004.
The senior secured ratings on certain of AEP’s rated subsidiaries will be removed where secured debt no longer exists.
See Management’s Financial Discussion and Analysis of Results of Operations, included in the 2004 Annual Reports, under the heading entitled Financial Condition for additional information with respect to the credit ratings of the registrants other than AEGCo.
ENVIRONMENTAL AND OTHER MATTERS
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:
In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. See Management’s Financial Discussion and Analysis of Results of Operations, included in the 2004 Annual Reports, under the heading entitled Environmental Matters for information on current environmental issues.
If our expenditures for pollution control technologies, replacement generation and associated operating costs are not recoverable from customers through regulated rates (in regulated jurisdictions) or market prices (in deregulated jurisdictions), those costs could adversely affect future results of operations and cash flows, and possibly financial condition.
The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the AEP System.
See Management’s Financial Discussion and Analysis of Results of Operations under the heading entitled Environmental Matters and Note 7 to the consolidated financial statements entitled Commitments and Contingencies, included in the 2004 Annual Reports, for further information with respect to environmental matters.
Investments related to improving AEP System plants’ environmental performance and compliance with air and water quality standards during 2003 and 2004 and the current estimate for 2005 are shown below. Substantial investments in addition to the amounts set forth below are expected by the System in future years in connection with the modification and addition of facilities at generating plants for environmental quality controls in order to comply with air and water quality standards which have been or may be adopted. Future investments could be significantly greater if litigation regarding whether AEP properly installed emission control equipment on its plants is resolved against any AEP subsidiaries or emissions reduction requirements are accelerated or otherwise become more onerous. See Management’s Financial Discussion and Analysis of Results of Operations under the headings entitled Future Reduction Requirements for NOx, SO2 and Hg and Estimated Air Quality Investments; and Note 7 to the consolidated financial statements, entitled Commitments and Contingencies, included in the 2004 Annual Reports, for more information regarding this litigation and environmental expenditures in general.
Electric and Magnetic Fields
EMF are found everywhere there is electricity. Electric fields are created by the presence of electric charges. Magnetic fields are produced by the flow of those charges. This means that EMF are created by electricity flowing in transmission and distribution lines, electrical equipment, household wiring, and appliances.
A number of studies in the past several years have examined the possibility of adverse health effects from EMF. While some of the epidemiological studies have indicated some association between exposure to EMF and health effects, none has produced any conclusive evidence that EMF does or does not cause adverse health effects.
Management cannot predict the ultimate impact of the question of EMF exposure and adverse health effects. If further research shows that EMF exposure contributes to increased risk of cancer or other health problems, or if the courts conclude that EMF exposure harms individuals and that utilities are liable for damages, or if states limit the strength of magnetic fields to such a level that the current electricity delivery system must be significantly changed, then the results of operations and financial condition of AEP and its operating subsidiaries could be materially adversely affected unless these costs can be recovered from customers.
Utility operations constitute most of AEP’s business operations. Utility operations include (i) the generation, transmission and distribution of electric power to retail customers and (ii) the supplying and marketing of electric power at wholesale (through the electric generation function) to other electric utility companies, municipalities and other market participants. AEPSC, as agent for AEP’s public utility subsidiaries performs marketing, generation dispatch, fuel procurement and power-related risk management and trading activities.
AEP’s public utility subsidiaries own approximately 34,500 MW of domestic generation. See Deactivation and Disposition of Generating Facilities for a discussion of planned and completed sales of certain of AEP’s generating facilities. Pursuant to regulatory orders, the AEP public utility subsidiaries operate their generating facilities as a single interconnected and coordinated electric utility system. See Item 2 — Properties for more information regarding AEP’s generation capacity.
AEP Power Pool and CSW Operating Agreement
APCo, CSPCo, I&M, KPCo and OPCo are parties to the Interconnection Agreement, dated July 6, 1951, as amended (Interconnection Agreement), defining how they share the costs and benefits associated with their generating plants. This sharing is based upon each company’s “member-load-ratio.” The Interconnection Agreement has been approved by the FERC.
The member-load ratio is calculated monthly by dividing such company’s highest monthly peak demand for the last twelve months by the aggregate of the highest monthly peak demand for the last twelve months for all east zone operating companies. As of December 31, 2004, the member-load ratios were as follows:
Although customer choice was adopted in Ohio in 2001, CSPCo and OPCo plan to remain functionally separated through at least December 31, 2008 as authorized by their rate stabilization plan approved by the PUCO. See Management’s Financial Discussion and Analysis and Financial Condition, under the heading entitled Regulatory Matters, Ohio included in the 2004 Annual Reports and Note 6 to the consolidated financial statements, entitled Customer Choice and Industry Restructuring, included in the 2004 Annual Reports, for more information.
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, 2002, 2003 and 2004:
PSO, SWEPCo, TCC, TNC, and AEPSC are parties to a Restated and Amended Operating Agreement originally dated as of January 1, 1997 (CSW Operating Agreement), which has been approved by the FERC. The CSW Operating Agreement requires the west zone public utility subsidiaries to maintain adequate annual planning reserve margins and requires the subsidiaries that have capacity in excess of the required margins to make such capacity available for sale to other AEP west zone public utility subsidiaries as capacity commitments. Parties are compensated for energy delivered to recipients based upon the deliverer’s incremental cost plus a portion of the recipient’s savings realized by the purchaser that avoids the use of more costly alternatives. Revenues and costs arising from third party sales are shared based on the amount of energy each west zone public utility subsidiary contributes that is sold to third parties. Upon the sale of its generation assets, TCC will no longer supply generating capacity under the CSW Operating Agreement.
The following table shows the net (credits) or charges allocated among the parties under the CSW Operating Agreement during the years ended December 31, 2002, 2003 and 2004:
Power generated by or allocated or provided under the Interconnection Agreement or CSW Operating Agreement to any public utility subsidiary is primarily sold to customers (or in the case of the ERCOT area of Texas, REPs) by such public utility subsidiary at rates approved (other than in the ERCOT area of Texas) by the public utility commission in the jurisdiction of sale. In Ohio and Virginia, such rates are based on a statutory formula as those jurisdictions transition to the use of market rates for generation. See Regulation — Rates.
Under both the Interconnection Agreement and CSW Operating Agreement, power that is not needed to serve the native load of our public utility subsidiaries is sold in the wholesale market by AEPSC on behalf of those subsidiaries. See Risk Management and Trading for a discussion of the trading and marketing of such power.
AEP’s System Integration Agreement, which has been approved by the FERC, provides for the integration and coordination of AEP’s east and west zone operating subsidiaries. This includes joint dispatch of generation within the AEP System and the distribution, between the two zones, of costs and benefits associated with the transfers of power between the two zones (including sales to third parties and risk management and trading activities). It is designed to function as an umbrella agreement in addition to the Interconnection Agreement and the CSW Operating Agreement, each of which controls the distribution of costs and benefits within each zone.
Risk Management and Trading
As agent for AEP’s public utility subsidiaries, AEP sells excess power into the market and engages in power and natural gas risk management and trading activities focused in regions in which AEP traditionally operates. These activities primarily involve the purchase and sale of electricity (and to a lesser extent, natural gas) under physical forward contracts at fixed and variable prices. These contracts include physical transactions, over-the-counter swaps and exchange-traded futures and options. The majority of physical forward contracts are typically settled by entering into offsetting contracts. These transactions are executed with numerous counterparties or on exchanges. Counterparties and exchanges may require cash or cash related instruments to be deposited on these transactions as margin against open positions. As of December 31, 2004, counterparties have posted approximately $98 million in cash, cash equivalents or letters of credit with AEPSC for the benefit of AEP’s public utility subsidiaries (while, as of that date, AEP’s public utility subsidiaries had posted approximately $2 million with counterparties). Since open trading contracts are valued based on changes in market power prices, exposures change daily.
The following table shows the sources of power generated by the AEP System:
Variations in the generation of nuclear power are primarily related to refueling and maintenance outages. Variations in the generation of natural gas power are primarily related to the availability of cheaper alternatives to fulfill certain power requirements and the deactivation or sale of certain gas-fired plants owned by TCC and TNC. Price increases in one or more fuel sources relative to other fuels generally result in increased use of other fuels.
Coal and Lignite: AEP’s public utility subsidiaries procure coal and lignite under a combination of purchasing arrangements including long-term contracts, affiliate operations, short-term, and spot agreements with various producers and coal trading firms. The price for most coal fuels has increased resulting in a trend that may continue. Management has responded to increases in the price of coal by rebalancing the coal used in its generating facilities with products from different coal regions and sources of differing heat rates and sulfur content. This rebalancing is an ongoing process that is expected to continue. Management believes, but cannot provide assurances that, AEP’s public utility subsidiaries will be able to secure and transport coal and lignite of adequate quality and in adequate quantities to operate their coal and lignite-fired units. See Investments-Other for a discussion of AEP’s coal marketing and transportation operations.
The following table shows the amount of coal delivered to the AEP System during the past three years and the average delivered price of spot coal purchased by System companies:
The coal supplies at AEP System plants vary from time to time depending on various factors, including customers’ usage of electric power, space limitations, the rate of consumption at particular plants, labor issues and weather conditions which may interrupt deliveries. At December 31, 2004, the System’s coal inventory was approximately 31 days of normal usage. This estimate assumes that the total supply would be utilized through the operation of plants that use coal most efficiently.
In cases of emergency or shortage, system companies have developed programs to conserve coal supplies at their plants. Such programs have been filed and reviewed with officials of federal and state agencies and, in some cases, the relevant state regulatory agency has prescribed actions to be taken under specified circumstances by System companies, subject to the jurisdiction of such agency.
The FERC has adopted regulations relating, among other things, to the circumstances under which, in the event of fuel emergencies or shortages, it might order electric utilities to generate and transmit electric power to other regions or systems experiencing fuel shortages, and to ratemaking principles by which such electric utilities would be compensated. In addition, the federal government is authorized, under prescribed conditions, to reallocate coal and to require the transportation thereof, for the use at power plants or major fuel-burning installations experiencing fuel shortages.
Natural Gas: Through its public utility subsidiaries, AEP consumed over 94 billion cubic feet of natural gas during 2004 for generating power. A majority of the natural gas-fired power plants are connected to at least two pipelines, which allows greater access to competitive supplies and improves reliability. A portfolio of long-term, monthly and seasonal firm purchase and transportation agreements (that are entered into on a competitive basis and based on market prices) supplies natural gas requirements for each plant.
Nuclear: I&M and STPNOC have made commitments to meet their current 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 2011 and (ii) 100% of the uranium concentrate needed for STP through spring 2011. See Deactivation and Disposition of Generation Facilities for more information about TCC’s interest in STP.
For purposes of the storage of high-level radioactive waste in the form of spent nuclear fuel, I&M has completed modifications to its spent nuclear fuel storage pool. AEP anticipates that the Cook Plant has storage capacity to permit normal operations through 2012. STP has on-site storage facilities with the capability to store the spent nuclear fuel generated by the STP units over their licensed lives.
Nuclear Waste and Decommissioning
I&M, as the owner of the Cook Plant, and TCC, as a partial owner of STP, have a significant future financial commitment to dispose of spent nuclear fuel and decommission and decontaminate the plants safely. The ultimate cost of retiring the Cook Plant and STP may be materially different from estimates and funding targets as a result of the:
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 Deactivation and Disposition of Generation Facilities for more information about TCC’s interest in STP.
See Management’s Financial Discussion and Analysis of Results of Operations and Note 7 to the consolidated financial statements, entitled Commitments and Contingencies, included in the 2004 Annual Reports, for information with respect to nuclear waste and decommissioning and related litigation.
Low-Level Radioactive Waste: The LLWPA mandates that the responsibility for the disposal of low-level radioactive waste rests with the individual states. Low-level radioactive waste consists largely of ordinary refuse and other items that have come in contact with radioactive materials. Michigan and Texas do not currently have disposal sites for such waste available. AEP cannot predict when such sites may be available, but South Carolina and Utah operate low-level radioactive waste disposal sites and accept low-level radioactive waste from Michigan and Texas. AEP’s access to the South Carolina facility is currently allowed through the end of fiscal year 2008. There is currently no set date limiting AEP’s access to the Utah facility. See Deactivation and Disposition of Generation Facilities for more information about TCC’s interest in STP.
Deactivation and Disposition of Generation Facilities
Pursuant to ERCOT’s approval, AEP deactivated 16 gas-fired power plants (8 TCC plants and 8 TNC plants). Separately, TCC conducted an auction to sell all of its generation facilities in Texas to establish the market value of the assets and TCC’s stranded costs in accordance with the Texas Act. See Texas Regulatory Assets and Stranded Cost Recovery and Post-Restructuring Wires Charges. The competitive bidding process began in June 2003 after the PUCT issued a rule confirming TCC’s ability to establish the value of its generation assets and amount of stranded costs by selling the generation assets. The PUCT engaged a consultant and designated a team to monitor the auction and advise TCC on the sale of its generating assets, including requirements of the Texas Act for establishing stranded costs.
The assets had a generating capacity of 4,497 MW and included the eight deactivated gas-fired generating plants, one coal-fired plant, TCC’s interest in Oklaunion Power Station, a hydroelectric facility and TCC’s interest in STP. TCC has entered into agreements to sell its 7.8% share of Oklaunion Power Station and its 25.2% share in STP and sold the remaining generation assets in July 2004. See Notes 6 and 10 to the consolidated financial statements entitled Customer Choice and Industry Restructuring and Acquisitions, Dispositions, Discontinued Operations, Impairments, Assets Held For Sale and Assets Held and Used, included in the 2004 Annual Reports, for more information on the disposition of TCC generation facilities.
Structured Arrangements Involving Capacity, Energy, and Ancillary Services
In January 2000, OPCo and NPC, an affiliate of Buckeye, entered into an agreement relating to the construction and operation of a 510 MW gas-fired electric generating peaking facility to be owned by NPC. OPCo is entitled to 100% of the power generated by the facility, and is responsible for the fuel and other costs of the facility through 2005. After 2005, NPC and OPCo will be entitled to 80% and 20%, respectively, of the power of the facility, and both parties will generally be responsible for the fuel and other costs of the facility.
Certain Power Agreements
AEGCo: Since its formation in 1982, AEGCo’s business has consisted of the ownership and financing of its 50% interest in Unit 1 of the Rockport Plant and, since 1989, leasing of its 50% interest in Unit 2 of the Rockport Plant. The operating revenues of AEGCo are derived from the sale of capacity and energy associated with its interest in the Rockport Plant to I&M and KPCo pursuant to unit power agreements, which have been approved by the FERC.
The I&M Power Agreement provides for the sale by AEGCo to I&M of all the capacity (and the energy associated therewith) available to AEGCo at the Rockport Plant. Whether or not power is available from AEGCo, I&M is obligated 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). When added to amounts received by AEGCo from any other sources, such amounts 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 last of the lease terms of Unit 2 of the Rockport Plant has expired (currently December 2022) unless extended in specified circumstances.
Pursuant to an assignment between I&M and KPCo, and a unit power agreement between KPCo and AEGCo, AEGCo sells KPCo 30% of the capacity (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo has agreed to pay to AEGCo the 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 was extended in November 2004 for an additional 18 years and now expires in December 2022.
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%. In April 2004, AEP agreed to sell a portion of its shares in OVEC (.73% of OVEC) to Louisville Gas and Electric Company. The sale is expected to close in the first quarter of 2005. Following the sale, the aggregate equity participation of AEP and CSPCo in OVEC will be 43.47%. Until September 1, 2001, OVEC supplied from its generating capacity the power requirements of a uranium enrichment plant near Portsmouth, Ohio owned by the DOE. The sponsoring companies are now entitled to receive and obligated to 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 (ICPA), which defines the rights of the owners and sets the power participation ratio of each, will expire by its terms on March 12, 2006. An Amended and Restated ICPA has been unanimously approved and executed by the sponsoring companies and OVEC to extend the term of the ICPA for an additional 20 years to March 13, 2026. The aggregate power participation ratio of the AEP entities in the Amended and Restated ICPA is 43.47%. The AEP-affiliated owners of OVEC and the other owners are evaluating the need for environmental investments related to their ownership interests, which may be material.
Buckeye: Transmission service agreements between Buckeye, AEP and other transmission owners provide for the transmission and delivery of power generated by Buckeye at the Cardinal Station. These transmission agreements were made pursuant to the applicable open access transmission tariffs (OATT) of AEP and others. On October 1, 2004, AEP joined PJM, and the Buckeye transmission service over the AEP system was transferred under the PJM OATT. Buckeye is entitled under the Cardinal Station
Agreement to receive, and is obligated to pay for, the excess of its maximum one-hour coincident peak demand plus a 15% reserve margin over the 1,226,500 kilowatts of capacity of the generating units which Buckeye currently owns in the Cardinal Station. Such demand, which occurred on January 23, 2003, was recorded at 1,409,726 kilowatts.
ELECTRIC TRANSMISSION AND DISTRIBUTION
AEP’s public utility subsidiaries (other than AEGCo) own and operate transmission and distribution lines and other facilities to deliver electric power. See Item 2—Properties for more information regarding the transmission and distribution lines. Most of the transmission and distribution services are sold, in combination with electric power, to retail customers of AEP’s public utility subsidiaries in their service territories. These sales are made at rates established and approved by the state utility commissions of the states in which they operate, and in some instances, approved by the FERC. See Regulation—Rates. The FERC regulates and approves the rates for wholesale transmission transactions. See Regulation—FERC. As discussed below, some transmission services also are separately sold to non-affiliated companies.
AEP’s public utility subsidiaries (other than AEGCo) hold franchises or other rights to provide electric service in various municipalities and regions in their service areas. In some cases, these franchises provide the utility with the exclusive right to provide electric service. These franchises have varying provisions and expiration dates. In general, the operating companies consider their franchises to be adequate for the conduct of their business. For a discussion of competition in the sale of power, see Competition.
AEP Transmission Pool
Transmission Equalization Agreement: APCo, CSPCo, I&M, KPCo and OPCo operate their transmission lines as a single interconnected and coordinated system and are parties to the Transmission Equalization Agreement, dated April 1, 1984, as amended (TEA), defining how they share the costs and benefits associated with their relative ownership of the extra-high-voltage transmission system (facilities rated 345 KV and above) and certain facilities operated at lower voltages (138 KV and above). The TEA has been approved by the FERC. Sharing under the TEA is based upon each company’s “member-load ratio.” The member-load ratio is calculated monthly by dividing such company’s highest monthly peak demand for the last twelve months by the aggregate of the highest monthly peak demand for the last twelve months for all east zone operating companies. As of December 31, 2004, the member-load ratios were as follows:
The following table shows the net (credits) or charges allocated among the parties to the TEA during the years ended December 31, 2002, 2003 and 2004:
Transmission Coordination Agreement: PSO, SWEPCo, TCC, TNC and AEPSC are parties to the TCA. The TCA has been approved by the FERC and establishes a coordinating committee, which is charged with the responsibility of overseeing the coordinated planning of the transmission facilities of the west zone public utility subsidiaries, including the performance of transmission planning studies, the interaction of such subsidiaries with independent system operators and other regional bodies interested in transmission planning and compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such tariff.
Under the TCA, the west zone public utility subsidiaries have delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the AEP OATT on their behalf. The TCA also provides for the allocation among the west zone public utility subsidiaries of revenues collected for transmission and ancillary services provided under the AEP OATT.
The following table shows the net (credits) or charges allocated among the parties to the TCA during the years ended December 31, 2002, 2003 and 2004:
Transmission Services for Non-Affiliates: In addition to providing transmission services in connection with their own power sales, AEP’s public utility subsidiaries and other System companies also provide transmission services for non-affiliated companies. See Regional Transmission Organizations. Transmission of electric power by AEP’s public utility subsidiaries is regulated by the FERC.
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 System Transmission Integration Agreement contemplates that additional service schedules may be added as circumstances warrant.
Regional Transmission Organizations
On April 24, 1996, the FERC issued orders 888 and 889. These orders require each public utility that owns or controls interstate transmission facilities to file an open access network and point-to-point transmission tariff that offers services comparable to the utility’s own uses of its transmission system. The orders also require utilities to functionally unbundle their services, by requiring them to use their own tariffs in making off-system and third-party sales. As part of the orders, the FERC issued a pro-forma tariff that reflects the Commission’s views on the minimum non-price terms and conditions for non-discriminatory transmission service. In addition, the orders require all transmitting utilities to establish an OASIS, which electronically posts transmission information such as available capacity and prices, and require utilities to comply with Standards of Conduct that prohibit utilities’ system operators from providing non-public transmission information to the utility’s merchant energy employees. The orders also allow a utility to seek recovery of certain prudently incurred stranded costs that result from unbundled transmission service.
In December 1999, FERC issued Order 2000, which provides for the voluntary formation of RTOs, entities created to operate, plan and control utility transmission assets. Order 2000 also prescribes certain characteristics and functions of acceptable RTO proposals.
As a condition of FERC’s approval in 2000 of AEP’s merger with CSW, AEP was required 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. The AEP East Companies integrated into PJM on October 1, 2004.
SWEPCo and PSO currently intend to transfer functional control of their transmission assets to SPP subject to receipt of appropriate regulatory approvals. In February 2004, the FERC conditionally approved SPP as an RTO. In October 2004, the FERC issued an order granting RTO status to SPP subject to certain filings. The Arkansas Public Service Commission and LPSC have required filings related to SWEPCo’s transfer of functional control of transmission facilities to an RTO. The remaining west zone public utility subsidiaries (TCC and TNC) are members of ERCOT.
See Note 4 to the consolidated financial statements, entitled Rate Matters, included in the 2004 Annual Reports and Management’s Financial Discussion and Analysis of Results of Operations under the heading entitled RTO Formation for a discussion of public utility subsidiary participation in RTOs.
Regional Through and Out Rates
In July 2003, the FERC issued an order directing PJM and the MISO to make compliance filings for their respective OATTs to eliminate the transaction-based charges for through and out (T&O) transmission service on transactions where the energy is delivered within the proposed Midwest ISO and PJM expanded regions (Combined Footprint). The elimination of the T&O rates will reduce the transmission service revenues collected by the RTOs and thereby reduce the revenues received by transmission owners under the RTOs’ revenue distribution protocols.
AEP and several other utilities in the Combined Footprint filed a proposal for new rates to become effective December 1, 2004. In November 2004, FERC eliminated the T&O rates and replaced the rates temporarily through March 2006 with a seams elimination cost adjustment (SECA) fees. AEP’s East zone public utility subsidiaries received approximately $196 million of T&O rate revenues for the twelve months ended September 30, 2004, the last twelve months prior to joining PJM. The portion of those revenues associated with transactions for which the T&O rate is being eliminated and replaced by SECA fees was $171 million. Effective April 2006, all transmission costs that would otherwise be defrayed by T&O rates in the Combined Footprint will be subject to recovery from native load customers of AEP’s East zone public utility subsidiaries. At this time, management is unable to predict whether any resultant increase in rates applicable to AEP’s internal load will be recoverable on a timely basis from state retail customers. Unless new replacement rates compensate AEP for its lost revenues and any increase in AEP’s East zone public utility subsidiaries’ transmission expenses from these new rates are fully recovered in retail rates on a timely basis, future results of operations, cash flows and financial condition will be adversely affected. See Management’s Financial Discussion and Analysis of Results of Operations under the heading entitled FERC Order on Regional Through and Out Rates for more information.
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. While still regulated, retail sales in Michigan are now made at unbundled rates. See Electric Restructuring and Customer Choice Legislation and Rates. AEP’s subsidiaries are also subject to regulation by the FERC under the FPA. I&M and TCC are subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant and STP, respectively. AEP and certain of its subsidiaries are also subject to the broad regulatory provisions of PUHCA administered by the SEC.
Historically, state utility commissions have established electric service rates on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service. A utility’s cost of service generally reflects its operating expenses, including operation and maintenance expense, depreciation expense and taxes. State utility commissions periodically adjust rates pursuant to a review of (i) a utility’s revenues and expenses during a defined test period and (ii) such utility’s level of investment. Absent a legal limitation, such as a law limiting the frequency of rate changes or capping rates for a period of time as part of a transition to customer choice of generation suppliers, a state utility commission can review and change rates on its own initiative. Some states may initiate reviews at the request of a utility, customer, governmental or other representative of a group of customers. Such parties may, however, agree with one another not to request reviews of or changes to rates for a specified period of time.
The rates of AEP’s public utility subsidiaries are generally based on the cost of providing traditional bundled electric service (i.e., generation, transmission and distribution service). In Ohio, Virginia and the ERCOT area of Texas, rates are transitioning from bundled cost-based rates for electric service to unbundled cost-based rates for transmission and distribution service on the one hand, and market pricing for and/or customer choice of generation on the other. In Ohio, the PUCO has approved the rate stabilization plans filed by OPCo and CSPCo which, among other things, address retail generation service rates through December 31, 2008. In Virginia, APCO’s base rates are capped, subject to certain adjustments, at their mid-1999 levels until December 31, 2010, or sooner if the VSCC finds that a competitive market for generation exists in Virginia.
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 through a fuel adjustment clause is no longer provided for in Ohio. Fuel recovery is also limited in the ERCOT area of Texas, but because AEP sold MECPL and MEWTU, there is little impact on AEP of fuel recovery procedures related to service in ERCOT.
The following state-by-state analysis summarizes the regulatory environment of each jurisdiction in which AEP operates. Several public utility subsidiaries operate in more than one jurisdiction.
Indiana: I&M provides retail electric service in Indiana at bundled rates 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 rates were capped through December 31, 2004. Its fuel recovery rate was capped through February 29, 2004. On September 22, 2004, the IURC issued an order extending the interim fuel factor through March 2005, subject to true-up upon resolution of the (previously filed but unexecuted) corporate separation plan. The status of additional base and fuel clause rate caps, subject to certain conditions, is presently under discussion with the parties to a proposed settlement agreement relating to AEP’s corporate separation issues.
Ohio: CSPCo and OPCo each operates as a functionally separated utility and provides “default” retail electric service to customers at unbundled rates pursuant to the Ohio Act through December 31, 2005. The PUCO approved the rate stabilization plan filed by CSPCo and OPCo (which, among other things, addresses default retail generation service rates from January 1, 2006 through December 31, 2008). Retail generation rates would be determined consistent with the rate stabilization plan until December 31, 2008. CSPCo and OPCo are and will continue to provide distribution services to retail customers at rates approved by the PUCO. These rates will be frozen (with certain exceptions) from their levels as of December 31, 2005 through December 31, 2008. Transmission services will continue to be provided at rates established by the FERC. See Note 6 to the consolidated financial statements, entitled Customer Choice and Industry Restructuring, included in the 2004 Annual Reports, for more information.
Oklahoma: PSO provides retail electric service in Oklahoma at bundled rates approved by the OCC. PSO’s rates are set on a cost-of-service basis. Fuel and purchased energy costs above the amount included in base rates are recovered by applying a fuel adjustment factor to retail kilowatt-hour sales. The factor is adjusted quarterly and is based upon forecasted fuel and purchased energy costs. Over or under collections of fuel costs for prior periods are returned to or recovered from customers when new quarterly factors are established. See Note 4 to the consolidated financial statements, entitled Rate Matters, included in the 2004 Annual Reports, for information regarding current rate proceedings.
Texas: The Texas Act requires the legal separation of generation-related assets from transmission and distribution assets. TCC and TNC currently operate on a functionally separated basis. In January 2002, TCC and TNC transferred all their retail customers in the ERCOT area of Texas to MECPL, MEWTU and AEP Commercial and Industrial REP (an AEP affiliate). TNC’s retail SPP customers were ultimately transferred to Mutual Energy SWEPCo L.P. (an AEP affiliate). TCC and TNC provide retail transmission and distribution service on a cost-of-service basis at rates approved by the PUCT and wholesale transmission service under tariffs approved by the FERC consistent with PUCT rules. See Note 4 to the consolidated financial statements, entitled Rate Matters, included in the 2004 Annual Reports, for information on current rate proceedings.
In May 2003, the PUCT delayed competition in the SPP area of Texas until at least January 1, 2007. As such, SWEPCo’s Texas operations continue to operate and to be regulated as a traditional bundled utility with both base and fuel rates.
Virginia: APCo provides unbundled retail electric service in Virginia. APCo’s unbundled generation, transmission (which reflect FERC approved transmission rates) and distribution rates as well as its functional separation plan were approved by the VSCC in December 2001.
The Virginia Act, which was amended in 2004, capped APCO’s base rates at their mid-1999 levels until the end of the transition period (now December 31, 2010), or sooner if the VSCC finds that a competitive market for generation exists in Virginia. The Virginia Act permits APCo to seek two changes to its capped rates as follows: one prior to July 1, 2007, and one between July 1, 2007 and December 31, 2010. In addition, as a result of the 2004 amendments, APCo is entitled to annual rate changes to recover the incremental costs it incurs on and after July 1, 2004 for transmission and distribution reliability and compliance with state or federal environmental laws or regulations. The Virginia Act also allows adjustments to fuel rates during the transition period and continues to permit utilities to recover their actual fuel costs, the fuel component of their purchased power costs and certain capacity charges. APCo recovers its generation capacity charges through capped base rates.
West Virginia: APCo and Wheeling Power Company provide retail electric service at bundled rates approved by the WVPSC. A plan to introduce customer choice was approved by the West Virginia Legislature in its 2000 legislative session. However, implementation of that plan was placed on hold pending necessary changes to the state’s tax laws in a subsequent session. Those changes have not been made. Management currently believes that implementation of the plan is unlikely.
While West Virginia generally allows for timely recovery of fuel costs, the most recent rate proceeding for both APCo and WPCo resulted in the suspension of their operative fuel clause mechanisms (though they continue to recover a fixed level of fuel costs through 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 following table illustrates the current rate regulation status of the states in which the public utility subsidiaries of AEP operate:
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. 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 appealed that order, and the FERC issued an order delaying the effective date of the order. This was done in connection with the FERC’s adoption of a new test called supply management assessment (SMA).
In April 2004, the FERC issued two orders concerning utilities’ ability to sell wholesale electricity at market-based rates. In the first order, the FERC adopted two new interim screens for assessing potential generation market power of applicants for wholesale market based rates, and described additional analyses and mitigation measures that could be presented if an applicant does not pass one of these interim screens. These two screening tests include a “pivotal supplier” test which determines if the market load can be fully served by alternative suppliers and a “market share” test which compares the amount of surplus generation at the time of the applicant’s minimum load. In July 2004, the FERC issued an order on rehearing affirming its conclusions in the April order and directing AEP and two unaffiliated utilities to file generation market power analyses within 30 days. In the second order, the FERC initiated a rulemaking to consider whether the FERC’s current methodology for determining whether a public utility should be allowed to sell wholesale electricity at market-based rates should be modified in any way.
On August 9, 2004, as amended on September 16, 2004 and November 19, 2004, AEP submitted its generation market power screens in compliance with the FERC’s orders. The analysis focused on the three major areas in which AEP serves load and owns generation resources -- ECAR, SPP and ERCOT, and the “first tier” control areas for each of those areas.
The pivotal supplier and market share screen analyses that AEP filed demonstrated that AEP does not possess market power in any of the control areas to which it is directly connected (first-tier markets). AEP passed both screening tests in all of its “first tier” markets. In its three “home” control areas, AEP passed the pivotal supplier test. As part of PJM, AEP also passes the market share screen for the PJM destination market. AEP also passed the market share screen for ERCOT. AEP did not pass the market share screen as designed by the FERC for the SPP control area.
In a December 17, 2004 Order, FERC affirmed our conclusions that we passed both market power screen tests in all areas except SPP. Because AEP did not pass the market share screen in SPP, FERC initiated a proceeding under Section 206 of the FPA in which AEP is rebuttably presumed to possess market power in SPP. Consequently, our revenues from sales within our control area of the SPP at market based rates after March 6, 2005 will be collected subject to refund to the extent that prices are ultimately found not to be just and reasonable. In February 2005 AEP filed with the FERC revisions to its market-based rate tariffs that cap the rates of wholesale power that AEP delivers within its control area of the SPP. We are unable to predict the timing or impact of any further action by the FERC.
ELECTRIC RESTRUCTURING AND CUSTOMER CHOICE LEGISLATION
Certain states in AEP’s service area have adopted restructuring or customer choice legislation. In general, this legislation provides for a transition from bundled cost-based rate regulated electric service to unbundled cost-based rates for transmission and distribution service and market pricing for the supply of electricity with customer choice of supplier. At a minimum, this legislation allows retail customers to select alternative generation suppliers. Electric restructuring and/or customer choice began on January 1, 2001 in Ohio and on January 1, 2002 in Michigan, Virginia and the ERCOT area of Texas. Electric restructuring in the SPP area of Texas has been delayed by the PUCT until at least 2007. AEP’s public utility subsidiaries operate in both the ERCOT and SPP areas of Texas.
Implementation of legislation enacted in West Virginia to allow retail customers to choose their electricity supplier is unlikely. In order for West Virginia’s choice plan to become effective, tax legislation must be passed to preserve pre-legislation levels of funding for state and local governments. Because such legislation has not been passed and because legislation enacted in March 2003 clarified the jurisdiction of the WVPSC over electric generation facilities, management currently believes that implementation of the plan is unlikely. In February 2003, Arkansas repealed its restructuring legislation.
See Note 5 to the consolidated financial statements, entitled Effects of Regulation, included in the 2004 Annual Reports, for a discussion of the effect of restructuring and customer choice legislation on accounting procedures. See Note 6 to the consolidated financial statements entitled Customer Choice and Industry Restructuring for additional information.
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, 2004, none of I&M’s Michigan customers have elected to change suppliers and no alternative electric suppliers are registered to compete in I&M’s Michigan service territory.
The Ohio Act requires vertically integrated electric utility companies that offer competitive retail electric service in Ohio to separate their generating functions from their transmission and distribution functions. Following the market development period (which will terminate no later than December 31, 2005), retail customers will receive distribution and, where applicable, transmission service from the incumbent utility whose distribution rates will be approved by the PUCO and whose transmission rates will be approved by the FERC. CSPCo and OPCo filed a rate stabilization plan with the PUCO that, among other things, addresses default generation service rates from January 1, 2006 through December 31, 2008. See Regulation—FERC for a discussion of FERC regulation of transmission rates and Regulation—Rates—Ohio for a discussion of the impact of restructuring on distribution rates. The PUCO approved the rate stabilization plan filed by CSPCo and OPCo, with certain modifications. The Commission authorized CSPCo and OPCo to remain functionally separated through the end of that three-year period.
Signed into law in June of 1999, the Texas Act substantially amended the regulatory structure governing electric utilities in Texas in order to allow retail electric competition for all customers. Among other things, the Texas Act:
The Texas Act provides each affected utility an opportunity to recover its generation related regulatory assets and stranded costs resulting from the legal separation of the transmission and distribution utility from the generation facilities and the related introduction of retail electric competition. Regulatory assets consist of the Texas jurisdictional amount of generation-related regulatory assets and liabilities in the audited financial statements as of December 31, 1998. Stranded costs consist of the positive excess of the net regulated book value of generation assets (as of December 31, 2001) over the market value of those assets, taking specified factors into account, as ultimately determined in a PUCT true-up proceeding.
For a discussion of (i) regulatory assets and stranded costs subject to recovery by TCC and (ii) rate adjustments made after implementation of restructuring to allow recovery of certain costs by or with respect to TCC and TNC, see Texas Regulatory Asset and Stranded Cost Recovery and Post-Restructuring Wires Charges and Note 6 to the consolidated financial statements entitled Customer Choice and Industry Restructuring.
In April 2004, the Governor of Virginia signed legislation that extends the transition period for electricity restructuring, including capped rates, through December 31, 2010. The legislation provides specified cost recovery opportunities during the capped rate period, including two optional general base rate changes and an opportunity for timely recovery, through a separate rate mechanism, of certain incremental environmental and reliability costs incurred on and after July 1, 2004.
Texas Regulatory Assets And Stranded Cost Recovery And Post-Restructuring Wires Charges
TCC may recover generation-related regulatory assets and plant-related stranded costs. Regulatory assets consist of the Texas jurisdictional amount of generation-related regulatory assets and liabilities in the audited financial statements as of December 31, 1998. Plant-related stranded costs consist of the positive excess of the net regulated book value of generation assets (as of December 31, 2001) over the market value of those assets, taking specified factors into account. 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 excess cost over market (ECOM) model. Carrying costs on stranded costs are also allowed to be recovered beginning January 1, 2002.
TCC’s true-up proceedings will determine the amount and recovery of:
The PUCT adopted a rule in 2003 regarding the timing of the true-up proceedings scheduling TCC’s filing 60 days after the completion of the sale of TCC’s generation assets. Due to regulatory and contractual delays in the sale of its generating assets, TCC has not yet filed its true-up request.
TCC’s net true-up regulatory assets (liabilities) recorded at December 31, 2004 is set forth in the following table.
TCC’s net true-up regulatory assets (liabilities)
For a more complete discussion of recovery of regulatory assets and stranded costs in Texas, see Note 6 to the consolidated financial statements entitled Customer Choice and Industry Restructuring, included in the 2004 Annual Reports.
The Texas Act further permits utilities to establish a special purpose entity to issue securitization bonds for the recovery of generation-related regulatory assets and, after the true-up proceeding, the amount of plant-related stranded costs and remaining generation-related regulatory assets not previously securitized. Securitization bonds allow for regulatory assets and plant-related 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 plant-related stranded costs or generation-related regulatory assets not recovered through the sale of securitization bonds may be recovered through a separate non-bypassable competitive transition charge to transmission and distribution customers.
For a discussion of recovery of regulatory assets and stranded costs in Ohio and Virginia, see Note 6 to the consolidated financial statements entitled Customer Choice and Industry Restructuring, included in the 2004 Annual Reports.