FORM 10-K
(Mark One)
| [ X ] |
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2003 |
| [ ] |
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ______ to ______ Commission File Number 1-1097 |
Oklahoma Gas and Electric Company meets the conditions set forth in General Instruction I(1) (a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by General Instruction I(2).
OKLAHOMA GAS AND ELECTRIC COMPANY
(Exact
name of registrant as specified in its charter)
| Oklahoma (State or other jurisdiction of incorporation or organization) |
73-0382390 (I.R.S. Employer Identification No.) |
321 North Harvey
P.O. Box 321
Oklahoma City,
Oklahoma 73101-0321
(Address of principal
executive offices)
(Zip Code)
Registrant’s
telephone number, including area code: (405) 553-3000
Securities registered pursuant to Section 12(b) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes No X
As of June 30, 2003, the last business day of the registrant’s most recently completed second fiscal quarter, 40,378,745 shares of common stock, par value $2.50 per share, were outstanding, all of which were held by OGE Energy Corp.
As of January 31, 2004, 40,378,745 shares of common stock, par value $2.50 per share, were outstanding, all of which were held by OGE Energy Corp. There were no other shares of capital stock of the registrant outstanding at such date.
DOCUMENTS INCORPORATED BY REFERENCE
None
|
Part I |
Page |
| Item 1. Business | 1 |
| The Company | 1 |
| General | 2 |
| Regulation and Rates | 5 |
| Rate Activities and Proposals | 15 |
| Fuel Supply | 17 |
| Finance and Construction | 19 |
| Environmental Matters | 21 |
| Employees | 23 |
| Access to Securities and Exchange Commission Filings |
24 |
| Item 2. Properties |
25 |
| Item 3. Legal Proceedings |
26 |
| Item 4. Submission of Matters to a Vote of Security Holders | 29 |
| Executive Officers of the Registrant |
30 |
| Part II | |
| Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters |
33 |
| Item 6. Selected Financial Data |
34 |
| Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations |
35 |
| Item 7A. Quantitative and Qualitative Disclosures About Market Risk |
68 |
| Item 8. Financial Statements and Supplementary Data |
70 |
| Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
116 |
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| Item 9A. Controls and Procedures |
116 |
| Part III |
|
| Item 10. Directors and Executive Officers of the Registrant |
116 |
| Item 11. Executive Compensation |
116 |
| Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
116 |
| Item 13. Certain Relationships and Related Transactions |
116 |
| Item 14. Principal Accountant Fees and Services |
116 |
| Part IV |
|
| Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K | 117 |
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Oklahoma Gas and Electric Company (the “Company”) generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas and is subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“FERC”). The Company is a wholly-owned subsidiary of OGE Energy Corp. (“Energy Corp.”) which is an energy and energy services provider offering physical delivery and management of both electricity and natural gas in the south central United States. The Company was incorporated in 1902 under the laws of the Oklahoma Territory and is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area. The Company sold its retail gas business in 1928 and is no longer engaged in the gas distribution business. The Company’s principal executive offices are located at 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101-0321; telephone (405) 553-3000.
The Company has been and will continue to be affected by competitive changes to the utility industry. Significant changes already have occurred and additional changes are being proposed to the wholesale electric market. Although it appears unlikely in the near future that changes will occur to retail regulation in the states served by the Company due to the significant problems faced by California in its electric deregulation efforts and other factors, significant changes are possible, which could significantly change the manner in which the Company conducts its business. These developments at the federal and state levels are described in more detail below under “Regulation and Rates – State Restructuring Initiatives and National Energy Legislation.”
On October 11, 2002, the Company, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to a settlement (the “Settlement Agreement”) of the Company’s rate case. The terms of the settlement are described below in “Regulation and Rates – 2002 Settlement Agreement.”
In early 2002, Energy Corp. completed a review of its business strategy that was largely driven by the anticipated deregulation of the retail electric markets in Oklahoma and Arkansas. Due to a variety of factors, including the current efforts to repeal the Oklahoma Electric Restructuring Act of 1997 and the recent repeal of the Restructuring Law in Arkansas, Energy Corp. does not anticipate that deregulation of the electricity markets in Oklahoma or Arkansas will occur in the foreseeable future. The strategic direction of Energy Corp. has been revised to reflect these developments. As a result, Energy Corp. expects potentially slower earnings growth than associated with deregulation but with less variability of those earnings.
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Energy Corp.’s revised business strategy will utilize the diversified asset position of the Company and Energy Corp.’s wholly-owned natural gas pipeline subsidiary, Enogex Inc. and subsidiaries (“Enogex”), to provide energy products and services to customers primarily in the south central United States. Energy Corp. will focus on those products and services with limited or manageable commodity exposure. Energy Corp. intends for the Company to continue as a vertically integrated utility engaged in the generation, transmission and the distribution of electricity and to represent over time approximately 70 percent of Energy Corp.’s consolidated assets. The remainder of Energy Corp.’s consolidated assets will be in Enogex’s businesses. At December 31, 2003, the Company and Enogex represented approximately 61 percent and 35 percent, respectively, of Energy Corp.’s consolidated assets. The remaining four percent of Energy Corp.’s consolidated assets were primarily at the holding company. In addition to the incremental growth opportunities that Enogex provides, Energy Corp. believes that Enogex’s risk management capabilities, commercial skills and market information provide value to all of Energy Corp.’s businesses. Federal regulation in regard to the operations of the wholesale power market may change with the evolving policy at the FERC. In addition, Oklahoma and Arkansas legislatures and utility commissions may propose changes from time to time that could subject utilities to market risk. Accordingly, the Company is applying risk management practices to all of its operations in an effort to mitigate the potential adverse effect of any future regulatory changes. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Company Strategy” for a further discussion.
The Company furnishes retail electric service in 270 communities and their contiguous rural and suburban areas. During 2003, five other communities and three rural electric cooperatives in Oklahoma and western Arkansas purchased electricity from the Company for resale. The service area, with an estimated population of 1.9 million, covers approximately 30,000 square miles in Oklahoma and western Arkansas; including Oklahoma City, the largest city in Oklahoma, and Fort Smith, Arkansas. Of the 270 communities served, 244 are located in Oklahoma and 26 in Arkansas. Approximately 89 percent of total electric operating revenues for the year ended December 31, 2003, were derived from sales in Oklahoma and the remainder from sales in Arkansas.
The Company’s system control area peak demand as reported by the system dispatcher during 2003 was approximately 5,977 MWs on August 21, 2003. The Company’s load responsibility peak demand was approximately 5,657 MWs on August 21, 2003, resulting in a capacity margin of approximately 14.0 percent. As reflected in the table on page 3 and in the operating statistics on page 4, there were approximately 25.1 million megawatt-hour (“MWH”) sales in 2003 as compared to approximately 24.9 million in 2002 and 2001. MWH sales to the Company’s customers (“system sales”) increased approximately 1.6 percent in 2003, due to increased usage related to customer growth in the Company’s service territory partially offset by milder weather during 2003. Sales to other utilities and power marketers (“off-system sales”) decreased approximately 67.0 percent in 2003, due to the changing supply and demand needs on the Company’s generation system.
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Variations in MWH sales for the three years are reflected in the following table:
| Increase/ | Increase/ | Increase/ | ||||||
| 2003 | (Decrease) | 2002 | (Decrease) | 2001 | (Decrease) | |||
| System Sales (A) | 25.0 | 1.6% | 24.6 | 0.4% | 24.5 | (2.0)% | ||
| Off-System Sales (A) | 0.1 | (67.0)% | 0.3 | (25.0)% | 0.4 | 33.3% | ||
| Total Sales | 25.1 | 0.8% | 24.9 | --- | 24.9 | (1.6)% | ||
| (A) Sales are in millions of MWHs. | ||||||||
The Company is subject to competition in various degrees from government-owned electric systems, municipally-owned electric systems, rural electric cooperatives and, in certain respects, from other private utilities, power marketers and cogenerators. Oklahoma law forbids the granting of an exclusive franchise to a utility for providing electricity.
Besides competition from other suppliers or marketers of electricity, the Company competes with suppliers of other forms of energy. The degree of competition between suppliers may vary depending on relative costs and supplies of other forms of energy. See “Regulation and Rates – State Restructuring Initiatives and National Energy Legislation” for a discussion of the potential impact on competition from federal and state legislation.
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| Year ended December 31 (In millions) | 2003 | 2002 | 2001 | ||||||||
| ELECTRIC ENERGY | |||||||||||
| (Millions of MWH) | |||||||||||
| Generation (exclusive of station use) | 22 | .5 | 23 | .4 | 23 | .0 | |||||
| Purchased | 4 | .5 | 3 | .5 | 3 | .7 | |||||
| Total generated and purchased | 27 | .0 | 26 | .9 | 26 | .7 | |||||
| Company use, free service and losses | (1 | .9) | (2 | .0) | (1 | .8) | |||||
| Electric energy sold | 25 | .1 | 24 | .9 | 24 | .9 | |||||
| ELECTRIC ENERGY SOLD | |||||||||||
| (Millions of MWH) | |||||||||||
| Residential | 8 | .2 | 8 | .0 | 8 | .0 | |||||
| Commercial and industrial | 12 | .6 | 12 | .4 | 12 | .4 | |||||
| Public street and highway lighting | 0 | .1 | 0 | .1 | 0 | .1 | |||||
| Other sales to public authorities | 2 | .6 | 2 | .6 | 2 | .5 | |||||
| System sales for resale | 1 | .5 | 1 | .5 | 1 | .5 | |||||
| Total system sales | 25 | .0 | 24 | .6 | 24 | .5 | |||||
| Off-system sales | 0 | .1 | 0 | .3 | 0 | .4 | |||||
| Total sales | 25 | .1 | 24 | .9 | 24 | .9 | |||||
| ELECTRIC OPERATING REVENUES | |||||||||||
| (In millions) | |||||||||||
| Residential | $ | 601 | .4 | $ | 557 | .6 | $ | 578 | .9 | ||
| Commercial and industrial | 665 | .9 | 605 | .5 | 638 | .0 | |||||
| Public street and highway lighting | 11 | .1 | 10 | .4 | 10 | .9 | |||||
| Other sales to public authorities | 135 | .0 | 125 | .1 | 127 | .9 | |||||
| System sales for resale | 57 | .7 | 48 | .2 | 52 | .5 | |||||
| Provision for FERC rate refund | - | -- | - | -- | (1 | .0) | |||||
| Total system sales | 1,471 | .1 | 1,346 | .8 | 1,407 | .2 | |||||
| Off-system sales | 4 | .1 | 6 | .3 | 13 | .0 | |||||
| Total Electric Revenues | 1,475 | .2 | 1,353 | .1 | 1,420 | .2 | |||||
| Miscellaneous revenues | 41 | .9 | 34 | .9 | 36 | .6 | |||||
| Total Electric Operating Revenues | $ | 1,517 | .1 | $ | 1,388 | .0 | $ | 1,456 | .8 | ||
| ACTUAL NUMBER OF ELECTRIC CUSTOMERS | |||||||||||
| (At end of period) | |||||||||||
| Residential | 622,52 | 7 | 616,71 | 2 | 609,40 | 8 | |||||
| Commercial and industrial | 89,23 | 5 | 88,46 | 6 | 87,51 | 1 | |||||
| Public street and highway lighting | 24 | 9 | 24 | 9 | 25 | 0 | |||||
| Other sales to public authorities | 13,40 | 9 | 13,03 | 1 | 12,56 | 6 | |||||
| Sales for resale | 5 | 0 | 5 | 5 | 6 | 2 | |||||
| Total | 725,47 | 0 | 718,51 | 3 | 709,79 | 7 | |||||
| AVERAGE RESIDENTIAL CUSTOMER SALES | |||||||||||
| Average annual revenue | $ | 970.0 | 4 | $ | 907.9 | 5 | $ | 952.3 | 2 | ||
| Average annual use (kilowatt-hour (“KWH”)) | 13,20 | 2 | 13,09 | 5 | 13,13 | 1 | |||||
| Average price per KWH (cents) | $ | 7.3 | 5 | $ | 6.9 | 3 | $ | 7.2 | 5 | ||
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The Company’s retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by the Company is also regulated by the OCC and the APSC. The Company’s wholesale electric tariffs, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the Department of Energy has jurisdiction over some of the Company’s facilities and operations. For the year ended December 31, 2003, approximately 87 percent of the Company’s electric revenue was subject to the jurisdiction of the OCC, nine percent to the APSC and four percent to the FERC.
The order of the OCC authorizing the Company to reorganize into a subsidiary of Energy Corp. contains certain provisions which, among other things, ensure the OCC access to the books and records of Energy Corp. and its affiliates relating to transactions with the Company; require Energy Corp. to employ accounting and other procedures and controls to protect against subsidization of non-utility activities by the Company’s customers; and prohibit Energy Corp. from pledging Company assets or income for affiliate transactions.
2002 Settlement Agreement
On October 11, 2002, the Company, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to the Settlement Agreement of the Company’s rate case. The administrative law judge subsequently recommended approval of the Settlement Agreement and on November 22, 2002, the OCC signed a rate order containing the provisions of the Settlement Agreement. The Settlement Agreement provides for, among other items: (i) a $25.0 million annual reduction in the electric rates of the Company’s Oklahoma customers which went into effect January 6, 2003; (ii) recovery by the Company, through rate base, of the capital expenditures associated with the January 2002 ice storm; (iii) the Company to acquire electric generation (“New Generation”) of not less than 400 megawatts (“MW”) to be integrated into the Company’s generation system; and (iv) recovery by the Company, over three years, of the $5.4 million in deferred operating costs, associated with the January 2002 ice storm, through the Company’s rider for off-system sales. Previously, the Company had a 50/50 sharing mechanism in Oklahoma for any off-system sales. The Settlement Agreement provided that the first $1.8 million in annual net profits from the Company’s off-system sales will go to the Company, the next $3.6 million in annual net profits from off-system sales will go to the Company’s Oklahoma customers, and any net profits of off-system sales in excess of these amounts will be credited in each sales year with 80 percent to the Company’s Oklahoma customers and the remaining 20 percent to the Company. If any of the $5.4 million is not recovered at the end of the three years, the OCC will authorize the recovery of any remaining costs.
Pending Acquisition of Power Plant
As part of the 2002 Settlement Agreement with the OCC, the Company undertook to acquire New Generation of not less than 400 MWs. The acquisition of a 77 percent interest in the 520 MW NRG McClain Station (the “McClain Plant”) would clearly constitute an acquisition of such New Generation under the Settlement Agreement. The Company expects this New
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Generation, including the interim purchase power agreement, will provide savings, over a three-year period, in excess of $75.0 million to its Oklahoma customers. These savings will be derived from: (i) the avoidance of purchase power contracts otherwise needed; (ii) replacing an above market cogeneration contract with PowerSmith Cogeneration Project, L.P. (“PowerSmith”) when it can be terminated at the end of August 2004; and (iii) fuel savings associated with operating efficiencies of the new plant. These savings, while providing real savings to Oklahoma customers, are not expected to affect the profitability of the Company because the Company’s rates would not need to be reduced to accomplish these savings. As indicated in the Settlement Agreement, the Company is required to provide monthly reports, for a period of 36 months after the acquisition, to the OCC Staff, documenting and providing proof of savings experienced by the Company’s customers. In the event the Company is unable to demonstrate at least $75.0 million in savings to its customers during this 36-month period, the Company will have an obligation to credit its Oklahoma customers any unrealized savings below $75.0 million as determined at the end of the 36-month period, which shall be no later than December 31, 2006. PowerSmith has filed an application with the OCC seeking to compel the Company to continue purchasing power from PowerSmith’s qualified cogeneration facility under the Public Utility Regulatory Policy Act of 1978 (“PURPA”) at a price that would include an avoided capacity charge equal to the lesser of (i) the rate currently specified in the power purchase agreement between the Company and PowerSmith or (ii) the avoided cost of the McClain Plant. The Company does not believe that this matter should be heard at the OCC at this time and that the avoided cost requested by PowerSmith is too high. In the event PowerSmith is ultimately successful and the Company is required to sign a purchase power agreement, it could negatively affect the Company’s ability to achieve the targeted $75 million three-year customer savings under the existing terms of the Settlement Agreement. PowerSmith and the Company have been holding discussions to determine if mutually agreeable terms can be reached for a power contract between the companies providing for capacity payments to the PowerSmith facility.
In the event the Company did not acquire the New Generation by December 31, 2003, the Settlement Agreement requires the Company to credit $25.0 million annually (at a rate of 1/12 of $25.0 million per month for each month that the New Generation is not in place) to its Oklahoma customers beginning January 1, 2004 and continuing through December 31, 2006. However, if the Company purchases the New Generation subsequent to January 1, 2004, the credit to Oklahoma customers will terminate in the first month that the New Generation begins initial operations and any previously-credited amounts to Oklahoma customers will be deducted in the determination of the $75.0 million targeted savings.
On August 18, 2003, the Company signed an asset purchase agreement to acquire NRG McClain LLC’s 77 percent interest in the McClain Plant. The acquisition of this interest in the McClain Plant would clearly constitute an acquisition of New Generation under the Settlement Agreement. The purchase price for the interest in the McClain Plant is approximately $159.9 million, subject to adjustment for prepaid gas and property taxes. The McClain Plant includes natural gas-fired combined cycle combustion turbine units and is located near Newcastle, Oklahoma in McClain County, Oklahoma. The McClain Plant began operating in 2001. The owner of the remaining 23 percent in the McClain Plant is the Oklahoma Municipal Power Authority (“OMPA”).
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Closing is subject to customary conditions including receipt of regulatory approval by the FERC. The asset purchase agreement, as amended, provides that, unless extended, either party has the right to terminate the contract if the closing does not occur on or before March 16, 2004. Because the current owner of the McClain Plant has filed for bankruptcy protection, the acquisition also was subject to approval by the bankruptcy court. As part of the bankruptcy approval process, NRG McClain LLC’s interest in the plant was subject to an auction process and on October 28, 2003, the bankruptcy court approved the sale of NRG McClain LLC’s interest in the plant to the Company. Several parties have filed interventions at the FERC opposing the Company’s application under Section 203 of the Federal Power Act to acquire NRG McClain’s interest in the power plant or, alternatively, requesting the FERC to delay approving such acquisition. The Company believed that its application met the standards under Section 203 set forth by the FERC and that its application would be approved. On December 18, 2003, the FERC shifted its policy regarding market power issues, raised wholesale market power concerns and ordered a hearing regarding the Company’s acquisition of the McClain Plant. The FERC action did not reject the Company’s request to purchase the McClain Plant, but demonstrated that the Company must address certain issues. On January 20, 2004, the Company filed a petition for re-hearing of the FERC’s December 18, 2003 order which included new mitigation measures that were designed to allow for prompt approval of the transaction. That request is still pending before the FERC. The Company has no indication whether the FERC will accept those proposed mitigation measures. On March 2, 2004, the Company filed testimony and exhibits with the FERC administrative law judge. The testimony and exhibits indicate that, if the case proceeds to hearing, the wholesale market power issues that the FERC raised in the December 18, 2003 order may be resolved by the minimal mitigation measures.
Assuming the acquisition occurs, the Company expects to operate the plant in accordance with a joint ownership and operating agreement with the OMPA. Under this agreement, the Company would operate the facility, and the Company and the OMPA would be entitled to the net available output of the plant based on their respective ownership percentages. All fixed and variable costs, except fuel and gas transportation costs, would be shared in proportion to the respective ownership interests. Fuel and gas transportation costs would be shared based on consumption. The Company expects to utilize its portion of the output, 400 MWs, to serve its native load. As provided in the Settlement Agreement, pending approval of a request to increase base rates to recover the investment in the plant, the Company will have the right to accrue a regulatory asset, for a period not to exceed 12 months subsequent to the acquisition, consisting of the non-fuel operation and maintenance expenses, depreciation, cost of debt associated with the investment and ad valorem taxes. Upon approval by the OCC of the Company’s request, all prudently incurred costs accrued through the regulatory asset within the 12-month period will be included in the Company’s prospective cost of service.
Despite the delay at the FERC, an agreement to purchase power from the McClain Plant is enabling the Company to honor the customer savings as outlined in the Settlement Agreement. On January 8, 2004, the Company filed an application with the OCC and requested that the OCC confirm the steps that the Company has taken to comply with the Settlement Agreement will result in customer savings being delivered beginning January 1, 2004, and that no further rate reduction is necessary. Various parties have intervened opposing the Company’s request. If the OCC does not agree with the Company’s request, the Company will be required to reduce
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electric rates to its Oklahoma customers by approximately $2.1 million per month and would expect to reduce expenditures for planned electric system reliability upgrades. The OCC has scheduled a hearing on April 19, 2004 for action in this case.
Assuming that the Company acquires the McClain Plant, the Company expects to fund the acquisition with a combination of a capital contribution from Energy Corp., funded in part by Energy Corp.’s equity issuance in 2003, and the issuance of long-term debt by the Company.
2003 Rate Case
On September 15, 2003, the Company filed with the OCC a notice of intent to seek an annual increase in its rates to its Oklahoma customers of more than one percent. The notice listed the following, among others, as major issues to be addressed in its application: (i) the acquisition of New Generation in accordance with the Settlement Agreement; (ii) increased capital expenditures for efficiency improvements and reliability enhancements to ensure fuel costs are minimized; and (iii) increased pension, medical and insurance costs. On October 31, 2003, the Company filed a request with the OCC to increase its rates by approximately $91 million annually. The increase was intended to pay for its pending acquisition of a 77 percent interest in the McClain Plant, allow for investment in electric system reliability and address rising business costs. The rate plan would have reduced rates for schools and more than 80,000 small businesses and non-profit organizations. On January 15, 2004, the Company filed an application to withdraw its request for a $91 million rate increase due to the delay at FERC in receiving the necessary approvals to complete the acquisition of the McClain Plant, which was a significant part of this rate case. An order dismissing the case was issued by the OCC on January 30, 2004. On December 18, 2003, the FERC issued an order setting for hearing the Company’s proposed acquisition of the McClain Plant and on January 15, 2004, the FERC administrative law judge in charge of the hearing and the parties to the case agreed to a procedural schedule that would produce a decision on the McClain Plant acquisition no sooner than the third quarter of 2004. The Company expects to file another rate case in the near future to recover increased operating and capital expenditures.
Gas Transportation and Storage Agreement
As part of the Settlement Agreement, the Company also agreed to consider competitive bidding for gas transportation service to its natural gas-fired generation facilities pursuant to the terms set forth in the Settlement Agreement. The Company believes that in order for it to achieve maximum coal generation and ensure reliable electric service, it must have firm no-notice load following service for both gas transportation and gas storage. This type of service is required to satisfy the daily swings in customer demand placed on the Company’s system and still permit natural gas units to not impede coal energy production. The Company also believes that gas storage is an integral part of providing gas supply to the Company’s generation facilities. Accordingly, the Company evaluated its competitive bid options in light of these circumstances. The Company’s evaluation clearly demonstrates that the Enogex integrated gas system provides superior firm no-notice load following service to the Company that is not available from other companies serving the Company marketplace. On April 29, 2003, the Company filed an application with the OCC in which the Company advised the OCC that, after careful
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consideration, competitive bidding for gas transportation was rejected in favor of a new intrastate firm no-notice load following gas transportation and storage services agreement with Enogex. This seven-year agreement provides for gas transportation and storage services for each of the Company’s natural gas-fired generation facilities. During 2003, the Company paid Enogex approximately $44.7 million for gas transportation and storage services. Based upon requests for information from intervenors, the Company has requested from Enogex and Enogex has agreed to retain a “cost of service” consultant to assist in the preparation of testimony related to this case. On January 30, 2004, the OCC issued a procedural schedule for this case. A hearing is scheduled August 10-11, 2004 and an OCC order in the case is expected by the end of 2004. The Company believes the amount currently paid to Enogex for no-notice load following transportation and storage services is fair, just and reasonable. If any amounts paid by the Company are found not to be recoverable, the Company believes such amount would not be material.
Security Enhancements
On April 8, 2002, the Company filed a joint application with the OCC requesting approval for security investments and a rider to recover these costs from the ratepayers. On August 14, 2002, the Company filed testimony with the OCC outlining proposed expenditures and related actions for security enhancement and a proposed recovery rider. Attempting to make security investments at the proper level, the Company has developed a set of guidelines intended to minimize long-term or widespread outages, minimize the impact on critical national defense and related customers, maximize the ability to respond to and recover from an attack, minimize the financial impact on the Company that might be caused by an attack and accomplish these efforts with minimal impact on ratepayers. The OCC Staff retained a security expert to review the report filed by the Company. The Company currently expects that hearings will be held in early 2004.
On October 17, 2003, the OCC filed a notice of inquiry to consider the issues related to the role of the OCC and Oklahoma regulated companies in addressing the security of the electrical system infrastructure and key assets. On March 4, 2004, the OCC deliberated the notice of inquiry and directed the OCC Staff to file a rulemaking proceeding for each utility industry regarding security of the electrical system infrastructure and key assets.
Other Regulatory Actions
The Settlement Agreement, when it became effective, provided for the termination of the Acquisition Premium Credit Rider (“APC Rider”) and the Gas Transportation Adjustment Credit Rider (“GTAC Rider”).
The APC Rider was approved by the OCC in March 2000 and was implemented by the Company to reflect the completion of the recovery of the amortization premium paid by the Company when it acquired Enogex in 1986. The effect of the APC Rider was to remove approximately $10.7 million annually from the amount being recovered by the Company from its Oklahoma customers in current rates.
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In June 2001, the OCC approved a stipulation (the “Stipulation”) to the competitive bid process of the Company’s gas transportation service from Enogex. The Stipulation directed the Company to reduce its rates to its Oklahoma retail customers by approximately $2.7 million per year through the implementation of the GTAC Rider. The GTAC Rider was a credit for gas transportation cost recovery and was applicable to and became part of each Oklahoma retail rate schedule to which the Company’s automatic fuel adjustment clause applies. As discussed above, the Settlement Agreement terminated the GTAC Rider. Consequently, these charges for gas transportation provided by Enogex are now included in base rates.
The Company’s Generation Efficiency Performance Rider (“GEP Rider”) expired in June 2002. The GEP Rider was established initially in 1997 in connection with the Company’s 1996 general rate review and was intended to encourage the Company to lower its fuel costs by: (i) allowing the Company to collect one-third of the amount by which its fuel costs were below a specified percentage (96.261 percent) of the average fuel costs of certain other investor-owned utilities in the region; and (ii) disallowing the collection of one-third of the amount by which its fuel costs exceeded a specified percentage (103.739 percent) of the average fuel costs of other investor-owned utilities. In June 2000 the OCC made modifications to the GEP Rider which had the effect of reducing the amount the Company could recover under the GEP Rider by: (i) changing the Company’s peer group to include utilities with a higher coal-to-gas generation mix; (ii) reducing the amount of fuel costs that can be recovered if the Company’s costs exceed the new peer group by changing the percentage above which the Company will not be allowed to recover one-third of the fuel costs from Oklahoma customers from 103.739 percent to 101.0 percent; (iii) reducing the Company’s share of cost savings as compared to its new peer group from 33 percent to 30 percent; and (iv) limiting to $10.0 million the amount of any awards paid to the Company or penalties charged to the Company. For the period between January 1, 2002 and June 30, 2002, the Company recovered approximately $2.4 million under the GEP Rider.
State Restructuring Initiatives
Oklahoma
As previously reported, the Electric Restructuring Act of 1997 (the “1997 Act”) was initially designed to provide retail customers in Oklahoma a choice of their electric supplier by July 1, 2002. Additional implementing legislation was to be adopted by the Oklahoma Legislature to address many specific issues associated with the 1997 Act and with deregulation. In May 2000, a bill addressing the specific issues of deregulation was passed in the Oklahoma State Senate and then was defeated in the Oklahoma House of Representatives. In May 2001, the Oklahoma Legislature postponed the scheduled start date for customer choice from July 1, 2002 until at least 2003. In addition to postponing the date for customer choice, this legislation called for a nine-member task force to further study the issues surrounding deregulation. The task force includes the Governor or his designee, the Oklahoma Attorney General, the OCC Chair and several legislative leaders, among others. In the 2003 legislative session, additional legislation was introduced to repeal the 1997 Act, but the 2003 legislative session ended without any further action to repeal the 1997 Act. It is unknown at this time whether the 1997 Act will be repealed. The Company will continue to actively participate in the legislative process and expects to remain a competitive supplier of electricity. As a result of the failures of California’s attempt to
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deregulate its electricity markets, the Enron bankruptcy, and associated impacts on the industry, efforts to restructure the electricity market in Oklahoma appear at this time to be delayed indefinitely.
Arkansas
In April 1999, Arkansas passed a law (the “Restructuring Law”) calling for restructuring of the electric utility industry at the retail level. The Restructuring Law initially targeted customer choice of electricity providers by January 1, 2002. In February 2001, the Restructuring Law was amended to delay the start date of customer choice of electric providers in Arkansas until October 1, 2003, with the APSC having discretion to further delay implementation to October 1, 2005. In March 2003, the Restructuring Law was repealed. As part of the repeal legislation, electric public utilities are permitted to recover transition costs. The Company incurred approximately $2.4 million in transition costs necessary to carry out its responsibilities associated with efforts to implement retail open access. On January 20, 2004, the APSC issued an order which authorized the Company to recover approximately $1.9 million in transition costs over an 18-month period beginning February 2004.
Automatic Fuel Adjustment Clauses
Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component in the cost-of-service for ratemaking, are passed through to the Company’s customers through automatic fuel adjustment clauses, which are subject to periodic review by the OCC, the APSC and the FERC. The OCC is currently reviewing the appropriateness of gas transportation charges under the agreement between the Company and Enogex. See “Gas Transportation and Storage Agreement” for a further discussion. The Company believes the amount currently paid to Enogex for no-notice load following transportation and storage services is fair, just and reasonable. All of the storage costs and a portion of the gas transportation costs are included in either base rates or are recoverable through the Company’s automatic fuel adjustment clause. See “Regulation and Rates – Other Regulatory Actions” for a further discussion.
National Energy Legislation
In December 2003 the U.S. Senate failed to pass a comprehensive Energy Bill that had long been debated in the Senate and the House of Representatives. The bill, as it was proposed, would have been largely beneficial to the Company. It contained provisions that would have minimized the risk of future uneconomic purchased power contracts being forced on the Company under PURPA as well as providing tax incentives for investment in the electric transmission and natural gas pipeline systems. The bill also provided favorable provisions for mandatory reliability oversight by the North American Electric Reliability Council with oversight by the FERC as well as the FERC citing authority for electric transmission in disputed areas. Also positive to the Company was that the bill did not contain any provisions for mandatory levels of renewable energy which would have had the effect of raising the Company’s electric rates. Another significant provision of the Energy Bill was the repeal of the Public Utility Holding Company Act of 1935 which was of minimal impact to the Company.
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When Congress reconvened in January 2004, the debate renewed over the Energy Bill. A compromise bill has been proposed in the Senate that would keep all of the issues important to the Company intact with the exception of the tax provisions. Excluding those provisions would eliminate the incentives for investment in the electric transmission and natural gas pipeline systems. It is unknown at this time what language will be contained in the final bill or when, or if, the bill is likely to be considered again in the Senate and the House of Representatives and, when or if, the bill ultimately will be approved.
Federal law imposes numerous responsibilities and requirements on the Company. PURPA requires electric utilities, such as the Company, to purchase power generated in a manufacturing process from a qualified cogeneration facility (“QF”). Generally stated, electric utilities must purchase electric energy and production capacity made available by QF’s at a rate reflecting the cost that the purchasing utility can avoid as a result of obtaining energy and production capacity from these sources; rather than generating an equivalent amount of energy itself or purchasing the energy or capacity from other suppliers. The Company has entered into agreements with four such cogenerators. Electric utilities also must furnish electric energy to QF’s on a non-discriminatory basis at a rate that is just, reasonable and in the public interest and must provide certain types of service which may be requested by QF’s to supplement or back up those facilities’ own generation.
Although efforts to increase competition at the state level have been stalled, there have been several initiatives implemented at the federal level to increase competition in the wholesale markets for electricity. The National Energy Policy Act of 1992 (“Energy Act”), among other things, promoted the development of independent power producers (“IPP”). The Energy Act was followed by FERC Order 888 and Order 889, which facilitated third-party utilization of the transmission grid for sales of wholesale power. The Energy Act, Orders 888 and 889, and other FERC policies and initiatives have significantly increased competition in the wholesale power market. Utilities, including the Company, have increased their own in-house wholesale marketing efforts and the number of entities with whom they historically traded. Moreover, power marketers became an increasingly important presence in the industry, however, their importance has declined following the bankruptcy of Enron and the financial troubles of other significant power marketers. These entities typically arbitrage wholesale price differentials by buying power produced by others in one market and selling it in another. IPP’s also are becoming a more significant sector of the electric utility industry. In both Oklahoma and Arkansas, significant additions of new power plants have been announced and, in some cases completed, almost all of it from IPP’s.
Notwithstanding these developments in the wholesale power market, the FERC recognized that impediments remained to the achievement of fully competitive wholesale markets including: (i) engineering and economic inefficiencies inherent in the current operation and expansion of the transmission grid; and (ii) continuing opportunities for transmission owners (primarily electric utilities) to discriminate in the operation of their transmission facilities in favor of their own or affiliated power marketing activities. In the past, the FERC only encouraged utilities to join and place their transmission systems under the operational control of independent system operators (“ISO”). On December 20, 1999, the FERC issued Order 2000, its final rule on regional transmission organizations (“RTO”). Order 2000 is intended to have the
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effect of turning the nation’s transmission facilities into independently operated “common carriers” that offer comparable service to all would-be-users. Although adopting a voluntary approach towards RTO formation, the FERC stressed that Order 2000 does not preclude it from requiring RTO participation. Order 2000 set out a timetable for every jurisdictional utility (including the Company) to either join in an RTO filing, or, alternatively, to submit a filing describing its efforts to join an RTO, the reasons for not participating in an RTO proposal and any obstacles to participation, and its plans for further work toward participation.
The Company is a member of the Southwest Power Pool (“SPP”), the regional reliability organization for all or parts of Oklahoma, Arkansas, Kansas, Louisiana, New Mexico, Mississippi, Missouri and Texas. The Company participated with the SPP in the development of regional transmission tariffs and executed an Agency Agreement with the SPP to facilitate interstate transmission operations within this region in 1998. In October 2000, the SPP filed its application with the FERC to become an RTO. In July 2001, the FERC determined that the SPP did not have adequate scope and configuration to be granted RTO status. The SPP was encouraged to explore the possibility of joining an RTO to be formed in the southeastern region of the United States and then to explore the feasibility of becoming a part of the recently approved RTO being established by the Midwest Independent System Operator (“MISO”). The SPP and MISO entered negotiations during the late summer of 2001 to combine the SPP and MISO and to form a new regional transmission entity that would combine the MISO and SPP organizations, capture certain synergies that would be available from the combined organization, and allow member companies in the SPP certain options with respect to membership in the combined organization. However, for a variety of reasons, MISO and SPP terminated their proposed combination in March 2003. The Company remained a member of the SPP while the MISO/SPP combination was pending, and the Company participated with the SPP and other SPP members to evaluate the next steps necessary for compliance with the FERC’s Order 2000. In the meantime, the SPP continued to offer open access transmission service in the SPP region under the SPP Open Access Transmission Tariff. On October 15, 2003, the SPP filed an application with the FERC seeking authority to form an RTO. On February 10, 2004, the FERC conditionally approved the SPP’s application. The SPP must meet certain conditions before it may commence operations as an RTO. Termination of the proposed MISO/SPP combination and recent conditional approval of the SPP RTO application are not expected to significantly impact the Company’s financial results.
In October 2001, the FERC issued a Notice of Proposed Rulemaking proposing to adopt new standards of conduct rules applicable to all jurisdictional electric and natural gas transmission providers. The proposed rules would replace the current rules governing the electric transmission and wholesale electric functions of electric utilities and the rules governing natural gas transportation and wholesale gas supply functions. The proposed rules would expand the definition of “affiliate” and further limit communications between transmission functions and supply functions, and could materially increase operating costs of market participants, including the Company and Enogex. In April 2002, the FERC Staff issued a reaction paper, generally rejecting the comments of parties opposed to the proposed rules. On November 25, 2003, the FERC issued its new rules regulating the relationship between electric and gas transmission providers and those entities’ merchant personnel and energy affiliates. The FERC’s final rule requires all transmission providers to be in full compliance with the new rules by June 1, 2004.
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On February 9, 2004, the Company submitted a plan and schedule to take the necessary actions to be in compliance with these new rules and expects that its initial costs to comply with the final rule will not exceed $0.5 million in 2004. The final rule is currently before the FERC on rehearing. Any changes to the final rule on rehearing could affect the anticipated compliance costs.
In July 2002, the FERC issued a Notice of Proposed Rulemaking on Standard Market Design Rulemaking for regulated utilities. If implemented as proposed, the rulemaking will substantially change how wholesale electric markets operate throughout the United States. The proposed rulemaking expands the FERC’s intent to unbundle transmission operations from integrated utilities and ensure robust competition in wholesale markets. The proposed rule contemplates that all wholesale and retail customers will take transmission service under a single network transmission service tariff. The rule also contemplates the implementation of a bid-based system for buying and selling energy in wholesale markets. RTOs or Independent Transmission Providers will administer the market. RTOs will also be responsible for regional plans that identify opportunities to construct new transmission, generation or demand side programs to reduce transmission constraints and meet regional energy requirements. Finally, the rule envisions the development of Regional Market Monitors responsible for ensuring the individual participants do not exercise unlawful market power. On April 28, 2003, the FERC issued a White Paper, “Wholesale Market Platform”, in which the FERC indicated that it will change the proposed rule as reflected in the White Paper and following additional regional technical conferences. The FERC committed in the White Paper to work with interested parties including state commissions to find solutions that will recognize regional differences within regions subject to the FERC’s jurisdiction. Thus far, the FERC has held conferences in Boston, Omaha, Wilmington, Tallahassee, Phoenix, New York and San Francisco.
In October 2003, the FERC issued new rules governing corporate “money pools,” which include jurisdictional public utility or pipeline subsidiaries of nonregulated parent companies. The rules require documentation of transactions within such money pools and notification to the FERC if the common equity ratio of the utility falls below 30 percent.
The FERC requires all utilities authorized to sell power at market-based rates to file updated market power analyses every three years. In December 2003, the Company filed its updated market power analysis with the FERC.
Regulatory Assets and Liabilities
The Company, as a regulated utility, is subject to the accounting principles prescribed by the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 provides that certain costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management’s expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.
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The Company initially records certain costs: (i) that are probable of future recovery as a deferred charge until such time as the cost is approved by a regulatory authority, then the cost is reclassified as a regulatory asset; and (ii) that are probable of future liability as a deferred credit until such time as the amount is approved by a regulatory authority, then the amount is reclassified as a regulatory liability.
At December 31, 2003 and 2002, the Company had regulatory assets of approximately $94.2 million and $111.1 million, respectively, and regulatory liabilities of approximately $148.7 million and $109.3 million, respectively. Approximately 45 percent of the regulatory assets and liabilities are allocated to the Company’s electric generation assets and approximately 55 percent of the regulatory assets and liabilities are allocated to the Company’s electric transmission and distribution assets.
As discussed previously, legislation was enacted in Oklahoma and Arkansas that was to restructure the electric utility industry in those states. The Arkansas legislation was repealed and implementation of the Oklahoma restructuring legislation has been delayed and seems unlikely to proceed during the near future. Yet, if and when implemented this legislation would deregulate the Company’s electric generation assets and cause the Company to discontinue the use of SFAS No. 71, with respect to its related regulatory balances. This may result in either full recovery of generation-related regulatory assets (net of related regulatory liabilities) or a non-cash, pre-tax write-off as an extraordinary charge, depending on the transition mechanisms developed by the legislature for the recovery of all or a portion of these net regulatory assets.
The previously enacted Oklahoma and Arkansas legislation would not affect the Company’s electric transmission and distribution assets and the Company believes that the continued use of SFAS No. 71 with respect to the related regulatory balances is appropriate. However, if utility regulators in Oklahoma and Arkansas were to adopt regulatory methodologies in the future that are not based on the cost-of-service, the continued use of SFAS No. 71 with respect to the regulatory balances related to the electric transmission and distribution assets may no longer be appropriate. Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, management believes that its regulatory assets, including those related to generation, are probable of future recovery.
Summary
The Energy Act, the actions of the FERC, the restructuring legislation in Oklahoma and other factors are intended to increase competition in the electric industry. The Company has taken steps in the past and intends to take appropriate steps in the future to remain a competitive supplier of electricity. While the Company is supportive of competition, it believes that all electric suppliers must be required to compete on a fair and equitable basis and the Company is advocating this position vigorously.
In 2002, the Company concluded its Oklahoma rate review proceeding before the OCC. This rate review was initiated in September 2001 by the OCC Staff and was concluded by order
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of the OCC on November 20, 2002. Under the rate review, the Company, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to a Settlement Agreement which stipulated