UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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, 2002
OR
[ ] 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: 1-12579
OGE Energy Corp.
(Exact name of registrant as specified in its charter)
Oklahoma
73-1481638
(State or other jurisdiction
of
(I.R.S. Employer
incorporation or organization)
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:
Title of each class
Name of each exchange on which registered
Common Stock
New York Stock Exchange and Pacific Stock Exchange
Rights to Purchase Series A Preferred Stock
New York Stock Exchange and Pacific Stock Exchange
Securities registered pursuant to Section 12(g) 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 filed (as defined in Rule 12b-2 of the
Act). Yes X
No
As of June 28, 2002, the last business day of the
registrant's most recently completed second fiscal quarter, the aggregate market
value of shares of common stock held by non-affiliates was $1,776,961,521 based
on the number of shares held by non-affiliates (77,732,350) and the reported
closing market price of the common stock on the New York Stock Exchange on such
date of $22.86.
As of February 28, 2003, 78,720,459 shares of
common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
The Proxy Statement for the Company's 2003 annual meeting of stockholders is incorporated by reference into Part III of this Form 10-K.
OGE ENERGY CORP.
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2002
TABLE OF CONTENTS
Part I Page
Item 1. Business.............................................................................. 1
The Company........................................................................... 1
Electric Operations................................................................... 3
General........................................................................... 3
Regulation and Rates.............................................................. 6
Rate Activities and Proposals..................................................... 16
Fuel Supply....................................................................... 17
Natural Gas Pipeline Operations - Enogex.............................................. 19
Finance and Construction.............................................................. 29
Environmental Matters................................................................. 31
Employees............................................................................. 35
Access to Securities and Exchange Commission Filings.................................. 35
Item 2. Properties............................................................................ 36
Item 3. Legal Proceedings..................................................................... 37
Item 4. Submission of Matters to a Vote of Security Holders................................... 45
Executive Officers of the Registrant................................................ 46
Part II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters............................................................................. 49
Item 6. Selected Financial Data............................................................... 51
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations............................................................... 52
Item 7A. Quantitative and Qualitative Disclosures About Market Risk............................ 89
Item 8. Financial Statements and Supplementary Data........................................... 92
Item 9. Changes In and Disagreements with Accountants on Accounting and
Financial Disclosure................................................................ 149
i
TABLE OF CONTENTS (Continued)
Part III
Item 10. Directors and Executive Officers of the Registrant.................................... 150
Item 11. Executive Compensation................................................................ 150
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters......................................................... 150
Item 13. Certain Relationships and Related Transactions........................................ 150
Item 14. Controls and Procedures............................................................... 151
Part IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K....................... 152
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PART I
Item 1. Business.
THE COMPANY
OGE Energy Corp. (collectively with its subsidiaries, the “Company”) 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 conducts these activities through two business segments, the Electric Utility and the Natural Gas Pipeline segments.
The Electric Utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through Oklahoma Gas and Electric Company (“OG&E”) and are subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“FERC”). OG&E 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. OG&E sold its retail gas business in 1928 and is no longer engaged in the gas distribution business.
OG&E 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 OG&E 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 OG&E 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, OG&E, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to a settlement of OG&E’s rate case. The terms of the settlement are described below in “Regulation and Rates - Recent Regulatory Matters.”
The Natural Gas Pipeline segment is conducted through Enogex Inc. and its subsidiaries (“Enogex”) and consists of three related businesses: (i) the transportation and storage of natural gas, (ii) the gathering and processing of natural gas, and (iii) the marketing and trading of natural gas (collectively, the “pipeline businesses”). The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are located in the major gas producing basins of Oklahoma. Through a 75 percent interest in the NOARK Pipeline System Limited Partnership (“NOARK”), Enogex also owns a controlling interest in and operates the Ozark Gas Transmission System (“Ozark”), a FERC regulated interstate pipeline that extends from southeast Oklahoma through Arkansas to southeast Missouri. Enogex’s marketing and trading activities include corporate price risk management and other optimization services. Enogex was previously engaged in the exploration and production of natural gas, however, this portion of Enogex’s business, along with interests in certain gas gathering and processing assets in Texas
1
were sold in 2002 and 2003 and are reported in the Consolidated Financial Statements as discontinued operations.
The Company was incorporated in August 1995 in the State of Oklahoma and its executive offices are located at 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101-0321; telephone (405) 553-3000.
Company Strategy
In early 2002, the Company 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, the Company does not anticipate that deregulation of the electricity markets in Oklahoma or Arkansas will occur in the foreseeable future. The strategic direction of the Company has been revised to reflect these developments. As a result, the Company expects potentially slower earnings growth than associated with deregulation but with less variability of those earnings.
The Company’s business strategy will utilize the diversified asset position of OG&E and Enogex to provide energy products and services to customers primarily in the south central United States. The Company will focus on those products and services with limited or manageable commodity exposure. The Company intends for OG&E to continue as an integrated utility engaged in the generation and the distribution of electricity and to represent over time approximately 70 percent of the Company’s consolidated assets. The remainder of the Company’s assets will be in Enogex’s pipeline businesses. In addition to the incremental growth opportunities that Enogex provides, the Company believes that Enogex’s risk management capabilities, commercial skills and market information provide value to all of the Company’s businesses. Federal regulation in regard to the operations of the wholesale power market may change with the proposed Standard Market Design initiative at the FERC. In addition, Oklahoma and Arkansas legislatures and utility commissions may propose changes from time to time that could subject the 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.
In the near term, OG&E plans on increasing its investment and growing earnings largely through the acquisition of a merchant power plant. As part of the OCC’s rate order on November 20, 2002, OG&E is seeking to purchase an electric power plant with at least 400 megawatts (“MW”) of generating capacity and to include the cost of such plant in its rate base. Given the surplus power in the region, the Company believes there is a continuing opportunity to purchase existing power plants at prices below the cost to build. This should enable OG&E to generate electricity for its customers at prices below those being paid by OG&E under existing qualified cogeneration and small power production producers’ contracts (“QF contracts”). Unless extended by OG&E, many of these QF contracts will expire over the next one to five years. Accordingly, OG&E will continue to explore opportunities to purchase power plants in order to serve its native load. OG&E anticipates filing with appropriate regulatory agencies to increase base rates to recover its investment in any power plant acquired and expects that customers
2
should realize overall lower rates through fuel savings due to the increased efficiency of these new plants and lower capital costs than those associated with the expiring QF contracts.
Enogex initiated a program in 2002 to improve its financial performance. As a part of this performance improvement program, Enogex has sold approximately $103.8 million in assets, reduced debt by 17 percent, reduced its number of employees by 12 percent and reorganized its operations. In addition to improving its earnings, Enogex will continue to take actions to reduce its exposure to commodity prices by, among other things, mitigating its exposure to keep whole processing arrangements and reducing earnings volatility. While the Company believes substantial progress has been achieved, substantial opportunities remain. Enogex expects to continue reviewing its work processes, rationalizing assets, renegotiating contracts to improve pricing on existing volumes and reducing costs to further improve its financial return in addition to pursuing opportunities for organic growth.
In 2003, in addition to these ongoing efforts, a major upgrade of the information systems is expected to be substantially completed. The Company believes these upgrades will be a major step towards obtaining the data required for it to optimize its system, provide improved customer service and enable management to more accurately determine the earnings potential of the unregulated pipeline system. The Company does not anticipate significantly increasing its investment in Enogex in accordance with the goal of targeting its pipeline businesses at 30 percent of the Company’s consolidated assets.
ELECTRIC OPERATIONS - OG&E
General
The Electric Utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E. OG&E furnishes retail electric service in 270 communities and their contiguous rural and suburban areas. During 2002, seven other communities and two rural electric cooperatives in Oklahoma and western Arkansas purchased electricity from OG&E for resale. The service area, with an estimated population of 1.7 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 279 communities served, 252 are located in Oklahoma and 27 in Arkansas. Approximately 90 percent of total electric operating revenues for the year ended December 31, 2002, were derived from sales in Oklahoma and the remainder from sales in Arkansas.
OG&E’s system control area peak demand as reported by the system dispatcher during 2002 was approximately 5,696 MW’s on August 23, 2002. OG&E’s load responsibility peak demand was approximately 5,427 MW’s on August 23, 2002, resulting in a capacity margin of approximately 18.9 percent. As reflected in the table on page 4 and in the operating statistics on page 5, total megawatt-hour (“MWH”) sales remained flat in 2002 as compared to a decrease of approximately 1.6 percent in 2001 and an increase of approximately 6.3 percent in 2000. MWH sales to OG&E’s customers (“system sales”) increased approximately 0.4 percent in 2002, due to favorable weather in the third quarter of 2002. Sales to other utilities and power marketers
3
(“off-system sales”) decreased approximately 25.0 percent in 2002 compared to an increase of approximately 33.3 percent in 2001 and a decrease of approximately 25.0 percent in 2000.
Variations in MWH sales for the three years are reflected in the following table:
(Millions of MWH)
Increase/ Increase/ Increase/
2002 (Decrease) 2001 (Decrease) 2000 (Decrease)
=============================================================================================
System Sales 24.6 0.4% 24.5 (2.0)% 25.0 6.4%
Off-System Sales 0.3 (25.0)% 0.4 33.3% 0.3 (25.0)%
------ ------ ------
Total Sales 24.9 --- 24.9 (1.6)% 25.3 6.3%
====== ====== ======
OG&E 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, OG&E 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.
4
OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS
Year ended December 31 (In millions) 2002 2001 2000
=========================================================================================================
ELECTRIC ENERGY
(Millions of MWH)
Generation (exclusive of station use)....................... 23.4 23.0 23.3
Purchased................................................... 3.5 3.7 3.7
----------- ----------- -----------
Total generated and purchased........................... 26.9 26.7 27.0
Company use, free service and losses........................ (2.0) (1.8) (1.7)
----------- ----------- -----------
Electric energy sold.................................... 24.9 24.9 25.3
=========== =========== ===========
ELECTRIC ENERGY SOLD
(Millions of MWH)
Residential................................................. 8.0 8.0 8.0
Commercial and industrial................................... 12.4 12.4 12.7
Public street and highway lighting.......................... 0.1 0.1 0.1
Other sales to public authorities........................... 2.6 2.5 2.4
System sales for resale..................................... 1.5 1.5 1.8
----------- ----------- -----------
Total system sales...................................... 24.6 24.5 25.0
Off-system sales............................................ 0.3 0.4 0.3
----------- ----------- -----------
Total sales............................................. 24.9 24.9 25.3
=========== =========== ===========
ELECTRIC OPERATING REVENUES
(In millions)
Residential................................................. $ 557.6 $ 578.9 $ 575.7
Commercial and industrial................................... 605.5 638.0 643.6
Public street and highway lighting.......................... 10.4 10.9 10.3
Other sales to public authorities........................... 125.1 127.9 124.2
System sales for resale..................................... 48.2 52.5 58.1
Provision for FERC rate refund.............................. --- (1.0) ---
----------- ----------- -----------
Total system sales...................................... 1,346.8 1,407.2 1,411.9
Off-system sales............................................ 6.3 13.0 12.9
----------- ----------- -----------
Total Electric Revenues................................. 1,353.1 1,420.2 1,424.8
Miscellaneous revenues...................................... 34.9 36.6 28.8
----------- ----------- -----------
Total Electric Operating Revenues....................... $ 1,388.0 $ 1,456.8 $ 1,453.6
=========== =========== ===========
ACTUAL NUMBER OF ELECTRIC CUSTOMERS
(At end of period)
Residential................................................. 616,712 609,408 603,826
Commercial and industrial................................... 88,466 87,511 86,659
Public street and highway lighting.......................... 249 250 250
Other sales to public authorities........................... 13,031 12,566 11,615
Sales for resale............................................ 55 62 52
----------- ----------- -----------
Total................................................... 718,513 709,797 702,402
=========== =========== ===========
AVERAGE RESIDENTIAL CUSTOMER SALES
Average annual revenue...................................... $ 907.95 $ 952.32 $ 957.54
Average annual use (KWH).................................... 13,095 13,131 13,264
Average price per KWH (cents)............................... $ 6.93 $ 7.25 $ 7.22
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Regulation and Rates
OG&E’s retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by OG&E is also regulated by the OCC and the APSC. OG&E’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 OG&E’s facilities and operations.
The order of the OCC authorizing OG&E to reorganize into a subsidiary of the Company contains certain provisions which, among other things, ensure the OCC access to the books and records of the Company and its affiliates relating to transactions with OG&E; require the Company to employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E’s customers; and prohibit the Company from pledging OG&E assets or income for affiliate transactions.
For the year ended December 31, 2002, approximately 88 percent of OG&E’s electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and four percent to the FERC.
Recent Regulatory Matters
In September 2001, the director of the OCC public utility division filed an application with the OCC to review the rates of OG&E. In the filing, the OCC Staff requested that OG&E submit information for a test year ending September 30, 2001. On December 14, 2001, OG&E, citing the need for investment in security and system reliability, filed a notice with the OCC of its intent to seek an increase in OG&E’s electric rates. On January 28, 2002, OG&E filed testimony with the OCC supporting OG&E’s request for a $22.0 million annual rate increase with approximately $10.3 million related to investments for security and approximately $11.7 million attributable to investments in increased system reliability and increased utility operating costs. Over the past 16 years, OG&E has had several rate reductions that have totaled more than $142.0 million annually.
Attempting to make security investments at the proper level, OG&E 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 OG&E that might be caused by an attack and accomplish these efforts with minimal impact on ratepayers. Initially, approximately $10.3 million of the January 28, 2002 rate increase requested by OG&E was to invest in increased security. As described below, OG&E subsequently withdrew its request for the $10.3 million related to security.
The additional $11.7 million of the original $22.0 million request was for investment in increased system reliability and for increased utility operating costs. OG&E had added new generation capacity to meet growing customer demand and had determined that it needed to increase expenditures for distribution system reliability following a series of record-breaking storms, including a 1995 windstorm in the Oklahoma City area affecting 175,000 customers,
6
1999 tornadoes affecting about 150,000 customers and disrupting service at a power plant, July 2000 thunderstorms affecting 110,000 customers, a Christmas 2000 ice storm affecting 140,000 customers, Memorial Day 2001 storms leaving 143,000 customers without power and at least two other storms affecting at least 100,000 customers each.
As part of its filing, OG&E sought approval to offer several new rate program choices to customers. One such pilot program involves flat billing. This option would set a customer’s bill at a fixed dollar amount and would not change throughout the year regardless of the amount of power consumed. The bill amount would then be adjusted in the following year based on the previous year’s usage and other factors. Another proposed rate program, a Green Power option, would involve OG&E contracting with wind generators to purchase a quantity of wind-generated power, then offering that power to customers. The rate would reflect the higher cost of wind-generated power.
On January 30, 2002, a significant ice storm hit OG&E’s service territory and inflicted major damage to the transmission and distribution infrastructure requiring total expenditures for repairs of approximately $92.0 million. On April 8, 2002, OG&E announced it would withdraw the $10.3 million increased security portion of its January request. Simultaneously with that announcement, OG&E filed a Joint Application with the Staff of the OCC for separate consideration of costs related to increased security requirements. Thereafter, on August 14, 2002, OG&E filed a report outlining proposed expenditures and related actions for security enhancement. OG&E is working with the OCC Staff under this separate filing to determine the appropriate dollar amount for security upgrades and recovery mechanisms. The OCC Staff has indicated its intent to retain a security expert to review the report filed by OG&E.
On July 1, 2002, OG&E filed direct testimony in support of recovery for the approximately $92.0 million in damages caused by the January 2002 ice storm. OG&E requested approximately a $14.5 million annual increase in revenue requirement. The request included recovery of, and return on, approximately $86.6 million of capital expenditures related to the ice storm and recovery, over three years, of approximately $5.4 million of deferred operating costs. Recovery of costs associated with the January 2002 ice storm is included in the Joint Stipulation and Settlement Agreement discussed below.
On October 11, 2002, OG&E, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to a settlement (the “Settlement Agreement”) of OG&E’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 OG&E’s Oklahoma customers which begins with the first regular billing cycle occurring 41 days after the issuance of the OCC order approving the Settlement Agreement; (ii) recovery by OG&E, through rate base, of the capital expenditures associated with the January 2002 ice storm; (iii) recovery by OG&E, over three years, of the $5.4 million in deferred operating costs, associated with the January 2002 ice storm, through OG&E’s rider for off-system sales; (iv) OG&E to acquire electric generating capacity (“New Generation”) of not less than 400 MW’s to be integrated into OG&E’s generation system. Key portions of the Settlement Agreement are described below.
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I. Rate Reduction to Oklahoma Customers
The Settlement Agreement stipulated that OG&E would file tariffs, designed to reflect an annual reduction of $25.0 million in OG&E’s Oklahoma jurisdictional operating revenue. The $25.0 million annual reduction began on January 6, 2003.
II. Recovery of Storm Damages
The Settlement Agreement stipulated that OG&E would be allowed to earn a return, through base rates, on the capital expenditures related to the January 2002 ice storm. The Settlement Agreement also stipulated that OG&E would be allowed recovery of $5.4 million of deferred operating costs related to the January 2002 ice storm. The recovery of the $5.4 million in operating costs will be recovered over a three-year period through OG&E’s rider for off-system sales. Currently, OG&E has 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 OG&E’s off-system sales will go to OG&E, the next $3.6 million in annual net profits from off-system sales will go to OG&E’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 OG&E’s Oklahoma customers and the remaining 20 percent to OG&E. 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.
III. New Generation
OG&E intends to take steps to purchase electric generating facilities of not less than 400 MW’s to be integrated into OG&E’s generation system. OG&E will have the right to accrue a regulatory asset, for a period not to exceed 12 months subsequent to the acquisition and initial operation of the New Generation, consisting of the non-fuel operation and maintenance expenses, depreciation, cost of debt associated with the capital investment and ad valorem taxes related to the New Generation. In addition to the accrual of the regulatory asset, OG&E must file an application with the OCC for the inclusion of the New Generation into OG&E’s rate base, as part of a general rate review, no later than 12 months following the acquisition and initial operation of the New Generation. Upon approval by the OCC of the application, all prudently incurred costs accrued through the regulatory asset within the 12 month period will be included in OG&E’s prospective cost of service. The period for recovery of the regulatory asset will be determined by the OCC. OG&E expects this New Generation will provide savings, over a three-year period, in excess of $75.0 million to OG&E’s Oklahoma customers. These savings will be derived from: (i) the avoidance of purchase power contracts otherwise needed; (ii) replacing an above market cogeneration contract when it can be terminated at the end of August 2004; and (iii) fuel savings associated with operating efficiencies of a new plant. These savings, while providing real savings to OG&E’s Oklahoma customers, should have no effect on the profitability of OG&E.
As indicated above, OG&E’s decision with respect to the purchase of the New Generation will be subject to a review by the OCC as a part of a general rate case for the purpose of determining the level of just and reasonable costs associated with the New Generation to be included in OG&E’s rate base. The OCC’s review is expected to include, but not be limited to, an analysis and review of the alternatives to purchasing the New Generation, the amount paid for
8
such New Generation and the level of capacity purchases. OG&E will provide monthly reports, for a period of 36 months, to the OCC Staff, documenting and providing proof of savings experienced by OG&E’s customers. In determining the 36-month savings, OG&E will be required to include in its reports: (1) the avoidance of purchased capacity otherwise required to meet Southwest Power Pool (“SPP”) capacity margin requirements; (2) credits to customers accruing by virtue of cogeneration contract terminations; and (3) the fuel savings associated with the operating efficiencies of OG&E’s generating facilities including the New Generation compared to the fuel efficiencies of OG&E’s generation facilities in operation during the test year related to the Settlement Agreement. The operating costs associated with the New Generation will be deducted from the sum of the three items discussed above to determine the ultimate amount of savings. In determining the 36-month savings, OG&E will not include savings to its customers, which occur as the result of scheduled reductions in ongoing cogeneration contract payments. In the event OG&E is unable to demonstrate at least $75.0 million in savings to its customers during this 36-month period, OG&E will have an obligation to credit its 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.
In the event OG&E does not acquire the New Generation by December 31, 2003, OG&E will be required 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 OG&E purchases the New Generation subsequent to January 2004, the credit to Oklahoma customers will terminate in the first month that the New Generation begins initial operations and any credited amount to Oklahoma customers will be included in the determination of the $75.0 million targeted savings.
IV. Rate Design
As part of the Settlement Agreement, OG&E agreed to withdraw its request for a Coal Utilization Performance Rider (“CUP Rider”) and a Transmission Investment Recovery Rider (“TIR Rider”). The CUP Rider would have rewarded OG&E based on its performance in the utilization of its coal generation facilities. The greater the coal plant utilization, the greater the benefits received by OG&E’s customers. OG&E’s coal plants are among the nations most efficient and the energy produced by those plants displaces higher cost energy. The CUP Rider would have provided additional incentive for OG&E by encouraging OG&E to aggressively pursue even greater efficiencies from these best-in-class plants. Additional CUP Rider incentives would have commenced at 72 percent coal utilization and increased as percentages rose above the 72 percent threshold level. The TIR Rider would have been applicable to investments necessary for increased transmission service and interconnect costs not funded by a new transmission customer (such as an independent power producer (“IPP”)) or for investment to improve available transfer capability as defined and approved by the regional transmission organizations (“RTOs”). OG&E agreed not to seek implementation of a CUP Rider or a TIR Rider or other similar riders in OG&E’s next general rate proceeding or during the 36-month benefit period of the New Generation. However, in the event federal regulation of the interstate transmission grid results in a new rate design which increases costs to OG&E’s Oklahoma customers, OG&E will not be precluded from requesting a TIR Rider.
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V. Gas Transportation Service
In a 1997 Order, the OCC approved a stipulation wherein OG&E agreed to initiate a competitive bidding process for gas transportation service to its natural gas plants.
OG&E’s current gas transportation service contract with Enogex for OG&E’s current natural gas generation facilities has a primary term ending in April 2004 and provides for an annual payment to Enogex of approximately $32.3 million. As part of the Settlement Agreement, OG&E agreed to consider competitive bidding as an option when analyzing the extension or renewal of OG&E’s gas transportation service contract with Enogex prior to April 2004. OG&E further agreed to consider competitive bidding as an option for all natural gas transportation services and gas supply acquisition practices to all new generation facilities built, purchased or placed into service after October 9, 2002. If OG&E chooses not to utilize competitive bidding to obtain all natural gas transportation services to its current generation facilities, after April 2004, or to any new generation facilities, OG&E must then provide the OCC Staff and the office of the Oklahoma Attorney General all data and information upon which the decision was based.
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 OG&E to reflect the completion of the recovery of the amortization premium paid by OG&E 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 OG&E from its Oklahoma customers in current rates.
In June 2001, the OCC approved a stipulation (the “Stipulation”) to the competitive bid process of OG&E’s gas transportation service from Enogex. The Stipulation directed OG&E 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 OG&E’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.
OG&E’s Generation Efficiency Performance Rider (“GEP Rider”) expired in June 2002. The GEP Rider was established initially in 1997 in connection with OG&E’s 1996 general rate review and was intended to encourage OG&E to lower its fuel costs by: (i) allowing OG&E 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
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2000 the OCC made modifications to the GEP Rider which had the effect of reducing the amount OG&E could recover under the GEP Rider by: (i) changing OG&E’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 OG&E’s costs exceed the new peer group by changing the percentage above which OG&E 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 OG&E’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 OG&E or penalties charged to OG&E. For the period between January 1, 2002 and June 30, 2002, OG&E 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 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 passed Senate Bill 440 (“SB 440”), which 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, SB 440 calls 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 current legislative session, Senate Bill 383 has been recently introduced to repeal the 1997 Act. It is unknown at this time whether the bill will be passed into law. 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 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, like the 1997 Act, would have significantly affected OG&E’s future operations. OG&E’s electric service area includes parts of western Arkansas, including Fort Smith. 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.
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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 OG&E’s customers through automatic fuel adjustment clauses, which are subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC also have authority to review the appropriateness of gas transportation charges or other fees OG&E pays to Enogex. See “Regulation and Rates – Other Regulatory Actions” for a further discussion.
National Energy Legislation
Federal law imposes numerous responsibilities and requirements on OG&E. The Public Utility Regulatory Policy Act of 1978 requires electric utilities, such as OG&E, 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. OG&E 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 and 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 IPP’s. 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 OG&E, have increased their own in–house wholesale marketing efforts and the number of entities with whom they historically traded. Moreover, power marketers are an increasingly important presence in the industry. 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, 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,
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its final rule on RTO’s. Order 2000 is intended to have the 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 OG&E) 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.
OG&E is a member of the SPP, the regional reliability organization for Oklahoma, Arkansas, Kansas, Louisiana, Missouri and part of Texas. OG&E 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 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 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 control areas of MISO and SPP, 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. The officers of MISO and of SPP, under the direction of their respective Boards of Directors developed documentation to effect the merger of SPP and MISO into a new organization, and the transaction was approved by the SPP Board of Directors. On February 7, 2003, OG&E executed a Conditional MISO Membership Application to join the resulting company as a Transmission Owner, subject to certain conditions being either met or waived. On the same date, OG&E executed the Conditional Withdrawal Agreement with the SPP. The Conditional Withdrawal Agreement would have had the effect of terminating OG&E’s membership in the SPP, except for regional reliability purposes, at such time as the MISO - SPP combination received all necessary regulatory approvals, the required number of SPP member companies executed the Conditional Membership Application to join MISO, and the SPP and MISO merger transaction were closed. OG&E filed with the APSC a cost/benefit analysis to demonstrate that OG&E's joining the MISO/SPP combination would have been in the public interest.
One of the conditions to the SPP and MISO merger transaction was that two-thirds of the load served by transmission owners within the SPP were to execute the Conditional Membership Application and to execute the Conditional Withdrawal Agreement with the SPP. During March 2003 it became apparent to the SPP Board of Directors that the Conditional Membership Applications would not be executed by transmission owners representing two-thirds of the load in the SPP. At its meeting on March 12, 2003, the SPP Board of Directors directed the President of SPP to open discussion with the MISO Board of Directors concerning termination of the proposed MISO/SPP combination. On March 20, 2003, MISO and SPP announced that their respective Boards had voted to terminate their merger because the conditions required to close the transaction would not be met in the foreseeable future. OG&E has remained a member of the
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SPP while the MISO/SPP combination was pending, and OG&E will continue to be a member of the SPP as the SPP, other SPP members and OG&E evaluate the next steps necessary for compliance with the FERC's Order 2000. In the meantime, the SPP will continue to offer open access transmission service in the SPP region under the SPP Open Access Transmission Tariff. Termination of the proposed MISO/SPP combination and OG&E's continued membership in the SPP are not expected to significantly impact the Company's consolidated 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 OG&E and Enogex. In April 2002, the FERC staff issued a reaction paper, generally rejecting the comments of parties opposed to the proposed rules. Final rules have been delayed while the FERC pursues development of its Standard Market Design Rulemaking.
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 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 rule contemplates that all wholesale and retail customers will be on 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. The FERC recently extended the comment period, but anticipates that the final rules will be in place in 2003 and the contemplated market changes will take place in 2003 and 2004.
On August 1, 2002, the FERC issued a Notice of Proposed Rulemaking proposing to adopt new rules governing corporate “money pools,” which include jurisdictional public utility or pipeline subsidiaries of nonregulated parent companies. The proposed rules would require documentation of transactions within such money pools, a proprietary capital account of the jurisdictional utility of 30 percent, and would require the nonregulated parent company to have an investment grade rating. Several parties have filed comments on the proposed rule. No final rule has been issued.
Regulatory Assets and Liabilities
OG&E, 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
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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.
OG&E initially records 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.
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 OG&E’s electric generation assets and cause the Company to discontinue the use of SFAS No. 71, with respect to its related regulatory assets. 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 of up to approximately $28.7 million, 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 OG&E’s electric transmission and distribution assets and the Company believes that the continued use of SFAS No. 71 with respect to the related regulatory assets 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 assets related to the electric transmission and distribution assets may no longer be appropriate. The Company has approximately $35.2 million of regulatory assets related to transmission and distribution assets. 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. OG&E has taken steps in the past and intends to take appropriate steps in the future to remain a competitive supplier of electricity. While OG&E is supportive of competition, it believes that all electric suppliers must be required to compete on a fair and equitable basis and OG&E is advocating this position vigorously.
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Rate Activities and Proposals
In 2002, OG&E 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 of the OCC on November 20, 2002. Under the rate review, OG&E, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to a Settlement Agreement which stipulated that OG&E would file tariffs, designed to reflect an annual reduction of $25.0 million in OG&E’s Oklahoma jurisdictional operating revenue. The $25.0 million annual reduction began on January 6, 2003.
Other elements of importance addressed in the Settlement Agreement stressed the importance of acquiring New Generation to meet growing customer electricity demands for 2004 and beyond; a modification of the sharing ratio of off-system sales, and the recognition of the reduction of cogeneration costs in OG&E’s retail rates in the years 2003 and beyond.
OG&E also received OCC approval in the Settlement Agreement for several new customer programs and rate options, as well as modifications to existing rate structures. The Guaranteed Flat Bill (“GFB”) option for residential and small general service accounts will allow qualifying customers the opportunity to purchase their electricity needs at a set price for an entire year. Budget-minded customers that desire a fixed monthly bill will benefit from the GFB option. A second tariff rate option approved in the Settlement Agreement is an offering to provide a “renewable energy” resource to OG&E’s Oklahoma retail customers. This renewable energy resource is a wind power purchase program and will be available as a voluntary option to all of OG&E’s Oklahoma retail customers. Oklahoma’s availability of wind resources makes the renewable wind power option a possible choice in meeting the renewable energy needs of our conservation-minded customers. A third new rate offering available to commercial and industrial customers is levelized demand billing. This program will be beneficial for medium to large size customers with seasonally consistent demand levels who wish to reduce the variability of their monthly electric bills. The levelized demand offering is not for every customer, but many customers will benefit from this program. The last new program being offered to OG&E’s commercial and industrial customers and approved by the OCC is a new voluntary load curtailment program. This program will provide customers with the opportunity to curtail on a voluntary basis when OG&E’s system conditions merit curtailment action. Customers that curtail their usage will receive payment for their curtailment response. This voluntary curtailment program seeks customers that can curtail on most curtailment event days, but may not be able to curtail every time that a curtailment event is required.
The previously discussed new rate options coupled with OG&E’s existing rate choices provide many tariff options for OG&E’s Oklahoma retail customers. OG&E’s rate choice flexibility, reduction in cogeneration rates, acquisition of additional generation resources, and overall low costs of production and deliverability are expected to provide valuable benefits for our customers for many years to come. OG&E began implementation of the new rate options during the first billing cycle in January 2003. Since many of these options are voluntary, customers may choose these options anytime after the January 2003 start date. The revenue impacts associated with these options are indeterminate since customers may choose to remain on existing rate options instead of volunteering for the new rate option choices. There is
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no overall material impact associated with these new rate options, but minimal revenue variations may occur based upon changes in customer’s usage characteristics if they choose these new programs.
Fuel Supply
During 2002, approximately 72 percent of the OG&E-generated energy was produced by coal units and 28 percent by natural gas units. Of the 5,696 total MW capability reflected in the table on page 36, approximately 3,160 MW’s or 55 percent are from natural gas generation and approximately 2,535 MW’s or 45 percent are from coal generation. Though OG&E has a higher installed capability of generation from natural gas units of 55 percent, it has been more economical to generate electricity for our customers using lower priced coal. With Oklahoma’s readily accessible supply of natural gas, OG&E was at one time 100 percent reliant upon natural gas as its fuel source for electric generation. In the early 1970‘s, OG&E turned to coal as a fuel source after natural gas was declared to be in limited supply and after enactment of the Fuel Use Act, which essentially prohibited any new electric generation fueled by natural gas. A slight decline in the percentage of coal generation in future years is expected to result from increased usage of natural gas generation required to meet growing energy needs. Over the last five years, the average cost of fuel used, by type, per million British thermal unit (“MMBtu”) was as follows:
2002 2001 2000 1999 1998
- ---------------------------------------------------------------------------------------------------
Coal............................ $ 0.93 $ 0.81 $ 0.87 $ 0.85 $ 0.85
Natural Gas..................... $ 3.78 $ 4.91 $ 4.93 $ 3.14 $ 2.83
Weighted Average................ $ 1.77 $ 1.97 $ 1.96 $ 1.54 $ 1.48
A portion of the fuel cost is included in base rates and differs for each jurisdiction. The portion of these costs that is not included in base rates is recovered through automatic fuel adjustment clauses. See "Regulation and Rates - Automatic Fuel Adjustment Clauses."
Coal
All of OG&E's coal units, with an aggregate capability of approximately 2,535 MW's, are designed to burn low sulfur western coal. OG&E purchases coal primarily under long-term contracts. During 2002, OG&E purchased approximately 10.7 million tons of coal from the following Wyoming suppliers: Kennecott Energy Company, Arco Coal Company, Peabody Coal Sales Company and Triton Coal Company. The combination of all coal has a weighted average sulfur content of less than 0.24 percent and can be burned in these units under existing federal, state and local environmental standards (maximum of 1.2 lbs. of sulfur dioxide per MMBtu) without the addition of sulfur dioxide removal systems. Based upon the average sulfur content, OG&E's units have an approximate emission rate of 0.504 lbs. of sulfur dioxide per MMBtu. In anticipation of the more strict provisions of Phase II of The Clean Air Act, which began in the year 2000, OG&E had contracts in place to allow for a supply of very low sulfur coal from suppliers in the Powder River Basin to meet the new sulfur dioxide standards.
OG&E has continued its efforts to maximize the utilization of its coal units at both the Sooner and Muskogee generating plants. See "Environmental Matters" for a discussion of an
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environmental proposal that, if implemented as proposed, could inhibit OG&E's ability to use coal as its primary boiler fuel.
Natural Gas
OG&E utilized a request for bid to acquire approximately 90 percent of its projected annual natural gas requirements for 2003. These contracts are tied to various gas price market indices and most will expire in April 2004. The remaining gas requirements of OG&E will be secured through monthly and day-to-day purchases as required.
In 1993, OG&E began utilizing a natural gas storage facility that allows OG&E to optimize the use of its generation assets.
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NATURAL GAS PIPELINE OPERATIONS - ENOGEX
The Natural Gas Pipeline segment is conducted through Enogex and consists of three related businesses: (i) the transportation and storage of natural gas, (ii) the gathering and processing of natural gas, and (iii) the marketing and trading of natural gas (collectively, the “pipeline businesses”). The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are located in the major gas producing basins of Oklahoma. Enogex and its subsidiaries operate approximately 9,300 miles of gas gathering and transportation pipelines. Additionally, through a 75 percent interest in NOARK, Enogex also owns a controlling interest in and operates Ozark, a FERC regulated interstate pipeline that extends from southeast Oklahoma through Arkansas to southeast Missouri. Enogex’s marketing and trading activities include corporate price risk management and other optimization services. Enogex was previously engaged in the exploration and production of natural gas, however, this portion of Enogex’s business, along with interests in certain gas gathering and processing assets in Texas were sold in 2002 and 2003 and are reported in the Consolidated Financial Statements as discontinued operations.
The pipeline and storage assets of Enogex provide OG&E strategic access to natural gas supplies, and flexible and reliable delivery terms that are required to fuel OG&E's gas-fired generators. The natural gas generation peaking units require the ability to quickly change their status, to meet both the peak and off-peak demands of the retail load particularly when coal units have an unscheduled outage. The Enogex pipeline assets access major wellhead supply sources primarily located across Oklahoma and Arkansas, and the Enogex storage assets provide the ability to regulate the receipt and delivery of natural gas to match the instantaneous needs of these generation units.
Gas units contribute their highest value when they have the capability to provide "load following" service to the customer. While the physical characteristics of gas units are known to provide quick start-up and on-line functionality, and while their ability to efficiently provide varying levels of electric generation relative to other forms of generation is further acknowledged, their ultimate effectiveness is contingent upon having access to an integrated pipeline and storage system that can respond in a short term fashion to meet its corresponding fluctuating operational fuel requirements. The combination of these assets is critical to OG&E's ability to provide reliable generation service at reasonable prices to the consumer.
Not only is Enogex providing service to its own generation affiliate, but the same assets provide firm and interruptible services to a significant portion of the other gas-fired generation and numerous other loads in the State of Oklahoma, as well as certain such requirements in the adjoining States of Texas and Arkansas. Enogex understands the needs of generators, and more importantly has the appropriately sized pipelines, compression and storage assets necessary to meet their requirements.
Through Enogex's gathering and processing assets, Enogex aggregates gas supplies not only for its own markets but also, for those markets accessible via its numerous intrastate and interstate pipeline connections. It aggressively pursues new supplies from wells drilled by producers primarily in the prolific Anadarko and Arkoma basins. The system capacity, due to its large diameter pipelines and its natural gas processing plants, is capable of adapting to the
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varying pressure and quality requirements of the mid-continent production. Enogex is able to provide low-pressure service to extend the production life of older wells as well as meeting the high-pressure requirements of new exploration.
The activities described above, while central to Enogex's operations, are not its only businesses. The transmission capabilities and "on and off-system" markets of the pipeline assets provide other business opportunities. An equally important and valuable feature of Enogex and its assets is the ability of Enogex to use its pipeline system and storage assets as a "market hub". There are 60 major pipeline connections with 15 other intrastate and interstate pipeline companies providing access to markets in the western United States, the mid-west, northeast, and Gulf Coast in addition to Oklahoma and adjoining states. Therefore, regardless of the ever varying relationship between supply and market, both in volume and location, Enogex's assets sit in the geographic center of the United States, with sufficient capacity to provide cross-haul transportation and storage services to a variety of utility and industrial customers that need to access mid-continent supply for their own needs, or to suppliers from other regions seeking to provide gas to on-system markets which Enogex serves.
The marketing and trading businesses are an important element in realizing the full value from the pipeline and storage assets and in providing products and services that support the market hub strategy. The marketing and trading business offers the Company real–time and longer–term price discovery and capacity valuation for energy commodities (power, natural gas, and associated natural gas liquids) associated with the Company's assets. It is also instrumental in providing increased liquidity for these energy commodities, by focusing on developing supplies and markets that can access the Enogex systems either directly or via interconnections with intrastate and interstate pipelines. The marketing and trading businesses also provide the Company the capability of providing risk management services to its customers.
The Company intends to continue to build upon the foundation of services and products, which these assets can provide. In addition, the Company expects to realize incremental profit, by improving its ability to aggregate gas and to optimize its position based upon the information available from its operations and the marketplace.
Recent Actions
During 2002, Enogex evaluated, redesigned and reorganized its internal work processes in order to achieve cost reductions and revenue enhancements within its businesses. Enogex is beginning to see the positive results of these efforts and expects continued improvement during 2003. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Forward-Looking Statements.”
After a review of Enogex’s assets on the basis of their strategic value and other factors, the Company sold all of its exploration and production assets and its interest in Belvan Corp., Belvan Limited Partnership and Todd Ranch Limited Partnership (“Belvan”) in 2002 and its interest in the NuStar Joint Venture (“NuStar”) in February 2003. These dispositions have been reported as discontinued operations for the years ended December 31, 2002, 2001 and 2000 in the Consolidated Financial Statements.
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On August 2, 2002, Ozark entered into an Agreement of Sale and Purchase with CenterPoint Energy Gas Transmission Co. to sell approximately 29 miles of transmission lines of the Ozark pipeline located in Pittsburg and Latimer counties in Oklahoma. On November 18, 2002, the Company received FERC approval for the closing, which occurred on January 6, 2003.
On January 23, 2003, Enogex entered into an Agreement of Sale and Purchase with Benedum Gas Partners, L.P. to sell all of its interest in NuStar. The effective date of the sale was January 1, 2003 and the closing occurred on February 18, 2003.
In October 2002, the Emerging Issues Task Force (“EITF”) reached a consensus on certain issues covered in EITF No. 02-3, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” One consensus of EITF 02-3 requires that all mark-to-market gains and losses, whether realized or unrealized, on financial derivative contracts as defined in SFAS No. 133 be shown net in the Income Statement for financial statements issued for periods beginning after December 15, 2002, with reclassification required for prior periods presented. The Company has adopted this consensus effective January 1, 2003 and the application of this consensus did not have a material impact on its consolidated financial position or results of operations as this consensus supports the Company’s historical presentation of financial derivative contracts.
In October 2002, the EITF reached a consensus to rescind EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities”, as amended effective for fiscal periods beginning after December 15, 2002. Effective October 25, 2002, all new contracts and physical inventories that would have been accounted for under EITF 98-10 are no longer marked to market through earnings unless the contracts meet the definition of derivative under SFAS No. 133. Application of the consensus for energy contracts and inventory that existed on or before October 25, 2002 that remain in effect at the date this consensus is initially applied will be recognized as a cumulative effect of a change in accounting principle in accordance with Accounting Principles Board Opinion No. 20, “Accounting Changes.” As a result, only energy contracts that meet the definition of a derivative in SFAS No. 133 will be carried at fair value. The Company has adopted this consensus effective January 1, 2003 resulting in an approximate $5.9 million after tax loss. The loss, which will be accounted for as a cumulative effect of a change in accounting principle, is primarily related to natural gas held in storage for trading purposes.
During the fourth quarter of 2002, Enogex recognized a pre-tax impairment loss of approximately $48.3 million. The impairment loss related to natural gas processing and compression assets. The impairments resulted from plans to dispose of these assets at prices below the carrying amount. The fair value of these assets was determined based on third-party evaluations, prices for similar assets, historical data and projected cash flows. See Note 4 of Notes to Consolidated Financial Statements for a further discussion.
FERC Section 311 Rate Case
In December 2001, Enogex made its filing at the FERC under Section 311 of the Natural Gas Policy Act to establish rates and a default processing fee and to address various other issues,
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for the combined Enogex and Transok pipeline systems effective January 1, 2002. Effective January 1, 2002, these systems began operating as a single Enogex pipeline system. The FERC Staff, Enogex and the active intervening parties have conducted settlement discussions. Enogex has negotiated a settlement of the case with the interveners. A Stipulation and Agreement of Settlement and related documents were filed with the FERC on March 5, 2003 to resolve all issues in dispute in Docket No. PR02-10-000. Comments are due March 25, 2003 and reply comments will be due April 4, 2003. The proposed settlement includes a fee for processing to bring gas gathered behind processing plants to pipeline gas quality Btu standards (processing fee) and a monthly low flow meter charge of $200 (offset in any month by the transportation revenues generated by gas through the meter). If the settlement is approved, Enogex will have no refund obligation. The outcome of this rate case will not have an adverse effect on the Company’s consolidated financial position or results of operations as any default processing fee billed through February 2003 has been fully reserved on the Company’s books. The Company expects to be charging a default processing fee this year and to recognize such fees in the Income Statement.
Transportation and Storage
General. One of Enogex’s primary lines of business is the transportation of natural gas, with current throughput of approximately 1.5 billion cubic feet per day ("Bcfd"). Enogex delivers natural gas to most interstate and intrastate pipelines and end-users connected to its systems from the Arkoma basin of eastern Oklahoma and Arkansas, the Anadarko basin of western Oklahoma and the Panhandle of west Texas. At December 31, 2002, Enogex was connected to 15 other major pipelines at approximately 60 pipeline interconnect points. These interconnections include Panhandle Eastern Pipe Line, Southern Star Central Gas Pipeline (formerly Williams Central), Natural Gas Pipeline Company of America, Oneok Gas Transmission, Northern Natural Gas Company, ANR Pipeline, Western Farmers Electric Cooperative and CenterPoint Energy Gas Transmission Co., as well as connections via Enogex’s Ozark system to Texas Eastern and Mississippi River Transmission. Further, Enogex is connected to various end-users including much of the natural gas generation facilities in Oklahoma. At December 31, 2002, the net property, plant and equipment balance for Enogex's transportation and storage business was approximately $764.2 million.
Enogex owns two storage facilities in Oklahoma, the Greasy Creek Facility and the Stuart Storage Facility. The Greasy Creek Facility has a working capacity of approximately 18 billion cubic feet (“Bcf”) with a maximum daily deliverability of 450 million cubic feet per day (“MMcfd”) and similar injection capability. Enogex offers both firm and interruptible storage services to third parties, under Section 311 of the Natural Gas Policy Act ("NGPA"), under terms and conditions specified in its Statement of Conditions for Gas Storage and at market-based rates to be negotiated with each customer. During 2002, Enogex expensed approximately $4.0 million for gas losses associated with the Greasy Creek storage field. While gas losses are normally associated with the operation of a natural gas storage field, this amount exceeds normal allowances. Enogex is currently analyzing the field and is taking actions to mitigate future losses.
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Enogex also recently purchased the Stuart Storage Facility from Central Oklahoma Oil and Gas Corp. (“COOG”). The Stuart Storage Facility has a working capacity of approximately 13 Bcf. The Stuart Storage Facility is used exclusively to support Enogex’s intrastate transportation and storage services for OG&E. See "Item 3. Legal Proceedings" for a discussion of the pending litigation associated with the purchase of the Stuart Storage Facility.
Enogex offers both firm and interruptible transportation services to customers with a majority of transportation revenues derived from firm contracts. Enogex offers interruptible service to customers when capacity is available.
Effective January 1, 2002, the Enogex and Transok L.L.C. (and its subsidiaries) (“Transok”) pipeline systems have been merged to simplify for both Enogex and its customers the administration and operation of maintaining two separate pipelines. Enogex provides firm intrastate transportation services to OG&E as well as Public Service Company of Oklahoma (“PSO”), the second largest electric utility in Oklahoma, serving the Tulsa market. In July 1999, Enogex acquired Transok. Transok maintained a sole-supplier relationship with PSO until 1998, when Oklahoma Natural Gas began supplying gas to three of the PSO generating stations pursuant to a competitive bid process put in place by the OCC. Notwithstanding the loss of the sole-supplier status, Enogex remains as the primary supplier to PSO. Enogex continues to provide gas transmission delivery services to all of PSO’s gas-fueled electric generation units in Oklahoma under a firm intrastate transportation contract. The current PSO contract, which expires January 1, 2005, and the OG&E contract, which expires April 30, 2004, provide for a monthly demand charge plus a variable transportation rate. In addition, Enogex provides transportation services via the leased Palo Duro pipeline system to Houston Pipe Line Company (“HPC”), an affiliate of PSO, for gas delivery service to certain HPC generating stations in the Texas panhandle. The lease for the Palo Duro pipeline terminates on June 30, 2003 unless Enogex exercises its option to renew the lease for an additional five year period. Enogex continues to evaluate the option to renew the lease but has not made any decision in that regard. During 2002, 2001 and 2000, Enogex’s revenues from the contracts with OG&E, PSO and HPC were approximately $53.9 million, $54.9 million and $54.5 million, respectively.
Relationship with OG&E. From its inception, Enogex has been the exclusive transporter of natural gas to OG&E electric power generating stations. Although Enogex is not directly regulated by the OCC, OG&E’s rates are subject to OCC jurisdiction. The OCC issued an order on November 20, 2002 which contained a provision, among other things, that OG&E would consider competitive bidding as an option in obtaining gas transportation service for its natural gas generating facilities when Enogex’s current contract expires in April 2004. The amount collected from OG&E by Enogex under the current contract was approximately $33.6 million, $36.3 million and $37.4 million, respectively, during 2002, 2001 and 2000, respectively.
Competition. Enogex’s pipeline and storage assets compete with interstate and other intrastate pipeline and storage facilities in the transportation and storage of natural gas. The principal elements of competition are rates, terms of services and flexibility and reliability of service.
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Natural gas competes with other forms of energy available to Enogex’s customers and end-users, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability or price of natural gas or other forms of energy as well as weather and other factors affect the demand for natural gas on the Enogex system.
Regulation. The rates charged by Enogex for transporting natural gas on behalf of an interstate natural gas pipeline company or a local distribution company served by an interstate natural gas pipeline company are subject to the jurisdiction of the FERC under Section 311 of the NGPA. Rates to provide such service must be "fair and equitable" under the NGPA and are subject to review and approval by the FERC at least once every three years. This rate review may involve an administrative-type trial and an administrative appellate review. By offering interruptible Section 311 transportation, the regulatory burden on Enogex is not appreciably increased, but does give Enogex the opportunity to utilize any unused capacity on an interruptible basis in interstate commerce and thus increase its transportation revenues. See "FERC Section 311 Case” for a discussion of Enogex’s current Section 311 case. As noted above, Ozark as an interstate pipeline is regulated by the FERC under The Natural Gas Act of 1938, as amended (the "Natural Gas Act").
The Company, through Enogex, owns a 75 percent interest in Ozark. Ozark transports natural gas in interstate commerce. As a result, it qualifies as a "natural gas company" under the Natural Gas Act, and is subject to the regulatory jurisdiction of the FERC. Under the Natural Gas Act, the FERC has jurisdiction to review and authorize the proposed construction of facilities for the transportation of natural gas in interstate commerce, the rendition of service through interstate facilities, the rates charged for such service, and the abandonment of such facilities or of services.
The Natural Gas Act requires that the rates charged, and the terms and conditions of service observed, by interstate pipelines be "just and reasonable", and not unduly discriminatory or preferential. All rates and terms and conditions of service proposed by an interstate pipeline must be filed with the FERC, and the FERC has jurisdiction under the Natural Gas Act to determine whether proposed rates or terms and conditions meet the statutory standards. The Act confers upon the FERC authority to determine a jurisdictional pipeline's rates, charges and terms and conditions of service, to establish depreciation rates and to prescribe uniform systems of accounts.
The rates charged by Enogex for transporting natural gas for OG&E and other shippers within Oklahoma are not subject to FERC regulation because they are intrastate transactions. With respect to state regulation, the rates charged by Enogex for any intrastate transportation service have not been subject to direct state regulation by the OCC, which is the state agency responsible for setting rates of public utilities within Oklahoma. Even though the intrastate pipeline business of Enogex is not directly regulated by the OCC, the OCC, the Arkansas Commission and the FERC (all of which approve various electric rates of OG&E) have the authority to examine the appropriateness of any transportation charges or other fees paid by OG&E to Enogex which OG&E seeks to recover from its ratepayers in its cost-of-service for electric service. See "Relationship with OG&E" below for a discussion of competitive bidding for OG&E's service.
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Enogex's pipeline operations are subject to various Oklahoma safety and environmental and non-discriminatory transportation requirements.
Gathering and Processing
General. Natural gas gathering operations are conducted through Enogex Gas Gathering L.L.C., and gas processing operations are conducted through Enogex Products Corporation (“Products”). The streams of processable natural gas gathered from wells and other sources are gathered through Enogex’s gas gathering systems to processing plants for the extraction of natural gas liquids. Products is one of the largest gas processors in the state of Oklahoma, owning 10 gas processing plants (of which seven are currently being operated) with an inlet capacity of over one Bcfd. During 2002, Products had ownership interests in two other gas processing plants related to NuStar, which were sold in February 2003. In 2002, it produced approximately eight million gross barrels of natural gas liquids. Products has been active since 1968 in the processing of natural gas and marketing of natural gas liquids. Products natural gas processing plant operations consist of the extraction and sale of natural gas liquids. The products extracted include condensate, marketable ethane, condensate, marketable ethane, propane, butanes and natural gasoline mix. The residue gas remaining after the liquid products have been extracted consists primarily of ethane and methane. At December 31, 2002, the net property, plant and equipment balance for Enogex's gathering and processing business was approximately $352.3 million.
Approximately 21 percent of the commercial grade propane processed at Products' plants is sold on the local market. The other natural gas liquids produced by Products are delivered into pipeline facilities of Koch Hydrocarbon and transported to Conway, Kansas and Mont Belvieu, Texas, where they are sold under contract or on the spot market. Ethane, which may be optionally produced at all of Products' plants except one, is sold in the spot market under a contract with Equistar Chemicals LP.
During 2002, Enogex took steps to decrease the volatility of its earnings stream by reducing its exposure to keep whole processing arrangements. Keep whole processing arrangements generally require a processor of natural gas to keep its shippers whole on a Btu basis and, thereby replacing the Btu value of the liquids with natural gas at market prices. Therefore, if natural gas prices increase and liquids prices do not increase by a corresponding amount, processing margins are negatively affected. In order to minimize the negative impact on processing margins, ethane and propane are rejected whenever possible. Exposure to keep whole processing arrangements was reduced through contract renegotiations and changes in the standards of service provided by Enogex under the FERC Section 311 filing discussed previously that provides for a processing fee in the event the fractionation spreads are negative. As a result of these actions, exposure to keep whole processing arrangements (without the processing fee provision) has been reduced to approximately 21 percent of total inlet volumes projected in 2003. The remaining 2003 projected inlet volumes are approximately 39 percent keep whole with the processing fee, 31 percent liquids and nine percent fixed fee. In addition, the Company actively monitors current and future prices for opportunities to hedge the processing margin. Enogex has executed physical and financial hedges by selling liquids forward as well as hedging the fractionation spread of various liquids' components. As of
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March 19, 2003, Enogex had hedged approximately 38 percent of its projected equity liquid volumes attributable to percentage of liquids agreements and approximately 10 percent of its projected keep whole processing volumes.
After a review of Enogex’s assets on the basis of their strategic value and other factors, the Company sold all of its interest in Belvan in 2002 and its interest in NuStar in February 2003. These dispositions have been reported as discontinued operations for the years ended December 31, 2002, 2001 and 2000 in the Consolidated Financial Statements. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Discontinued Operations” for a further discussion.
Competition. In processing and marketing natural gas liquids, Products competes against virtually all other gas processors producing and selling natural gas liquids. Competition for natural gas supply is based on efficiency and reliability of operations, reputation, availability of gathering and transportation to markets and pricing arrangements offered by the gatherer/processor. Products believes it will be able to continue to compete against such companies.
With respect to the profitability of the natural gas liquids industry generally, as the price of natural gas liquids fall without a corresponding decrease in the price of natural gas, it may become uneconomical to extract certain natural gas liquids. As explained under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”, this factor had a significant adverse impact on the results of Enogex during 2001. In addition to the commodity pricing impact that affects the entire industry, the profitability of Products is also largely affected by the volume of natural gas processed at its plants which is highly dependent upon the volume of natural gas gathered by the Enogex pipeline systems. Generally, if the volume of natural gas gathered increases, then the volume of liquids extracted by Products should also increase.
Marketing and Trading
Enogex’s commodity sales and services related to natural gas and electric power are conducted by Enogex primarily through its subsidiary, OGE Energy Resources, Inc. (“OERI”).
Natural Gas. OERI is engaged in the business of gas marketing. OERI's agreements with Enogex provide for OERI to provide marketing services for all natural gas volumes purchased by the pipeline at the wellhead from producers or otherwise. As a service to the producers on the Enogex system, Enogex may agree to purchase the gas at the wellhead in conjunction with gathering their gas for transportation to other markets.
OERI also purchases and sells natural gas pursuant to contracts with Enogex and Products relating to Enogex’s pipeline gathering, processing and storage assets. OERI marketed the natural gas produced by Enogex Exploration Corporation (“Exploration”) (prior to the sale of Exploration’s assets). In 2000, OERI purchased gas for OG&E. However, this was discontinued in 2001 and 2002. At December 31, 2002, the net property, plant and equipment balance for Enogex's marketing and trading business was approximately $3.5 million.
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OERI focuses on serving customers along the natural gas value chain, from producers to end-users, by purchasing natural gas from suppliers both on and off the Enogex and Ozark pipeline systems and reselling to pipelines, local distribution companies and end-users, including the electric generation sector.
The geographic scope of marketing efforts has been focused largely in the mid-continent area of the United States. These markets are natural extensions of OERI’s business on the Enogex system. OERI contracts for Enogex pipeline capacity to access multiple interconnections with the interstate pipeline system that moves natural gas from the production basins in the south central United States to the major consumption areas in Chicago, New York and other north central and mid Atlantic regions of the United States.
OERI participates in both long-term markets and short-term “spot” markets for natural gas. Although OERI continues to increase its focus on long-term sales, short-term sales of natural gas will continue to play a critical role in the overall strategy because they provide an important source of market intelligence as well as an important portfolio balancing function. In 2002, OERI bought and sold approximately 2.2 Bcfd of natural gas, of which approximately 25 percent moved on the Enogex pipeline system.
OERI’s risk management skills afford its customers the opportunity to tailor the risk profile and composition of their natural gas portfolio. The Company follows a policy of hedging price risk on gas purchases or sales contracts entered into by the marketing group by buying and selling natural gas futures contracts on the New York Mercantile Exchange futures exchange and other derivatives in the over-the-counter market, subject to a $2.5 million annual trading loss limit in accordance with corporate policies.
Electricity. OERI participates actively as a wholesale purchaser and reseller in the physical wholesale power markets of the mid-continent region. It has a fully-staffed 24-hour power desk that continually monitors the physical marketplace seeking to capture arbitrage opportunities by matching market participants with power surpluses to those market participants with power needs, primarily on an hourly or daily basis. OERI no longer participates in any speculative electricity trading activities. The expertise of OERI’s power desk in managing customer requirements and the complexities of the transmission grid provide OERI the opportunity to extract value from the daily marketplace. As the physical power broker for OG&E, OERI assists in the sale to and purchase from the physical power markets as required to meet the needs of OG&E. In accordance with applicable FERC affiliate rules, since March 2000, virtually all of OG&E’s surplus power sales activity has been performed by OERI who sold approximately 2,500 MW’s per day in 2002.
Competition. Marketing and Trading competes with major integrated oil companies, major interstate and intrastate pipelines, national and local natural gas brokers, marketers and distributors for natural gas supplies and in marketing and trading natural gas. Competition for natural gas supplies is based primarily on reputation, the availability of gathering and transportation to high-demand markets and the ability to obtain a satisfactory price for the producer's natural gas. Competition for sales to customers is based primarily upon reliability, services offered and price of delivered natural gas.
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For the year ended December 31, 2002, approximately 78 percent of OERI’s service volumes were with electric utilities, local gas distribution companies, pipelines and producers. The remaining 22 percent of service volumes were to marketers, municipals, cooperatives and industrials. As of December 31, 2002, approximately 79.5 percent of the exposure was to companies having investment grade ratings with Standard & Poor’s Ratings Services ("Standard & Poor's") and approximately 0.5 percent having less than investment grade ratings. The remaining 20 percent of OERI’s exposure is with privately held companies, municipals or cooperative that were not rated by Standard & Poor’s. These non-rated companies have satisfied our internal credit analyses and policies.
Exploration and Production
After a review of Enogex’s assets on the basis of their strategic value and other factors, the Company sold all of its exploration and production assets in 2002. These dispositions have been reported as discontinued operations for the years ended December 31, 2002, 2001 and 2000 in the Consolidated Financial Statements. The exploration and production activities were conducted through Exploration, which was formed in 1988 primarily to engage in the development and production of oil and natural gas. Exploration focused its early drilling activity in the Antrim Devonian shale trend in the state of Michigan and in recent years had concentrated on drilling opportunities in Oklahoma. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations–Results of Operations–Discontinued Operations” for a further discussion.
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FINANCE AND CONSTRUCTION
Capital requirements and future contractual obligations estimated for 2003 through 2006 and beyond are as follows:
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Actual 2006 and
(In millions) 2002 2003 2004 2005 Beyond
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OG&E capital expenditures including AFUDC......... $ 198.7 (A) $ 149.0 (B) $ 142.0 $ 142.0 N/A
Enogex capital expenditures and acquisitions (C).. 20.0 39.0 35.0 28.0 N/A
Other Operations capital expenditures............. 15.8 8.0 8.0 8.0 N/A
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Total capital expenditures.................. 234.5 196.0 185.0 178.0 N/A
Maturities of long-term debt...................... 115.0 20.8 52.8 146.1 $1,303.2
Retirement of long-term debt...................... 25.0 10.0 (D) N/A N/A N/A
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Total capital requirements.................. 374.5 226.8 237.8 324.1 1,303.2
Operating lease obligations
OG&E railcars.................................. 5.4 5.4 5.4 5.4 46.9
Enogex noncancellable operating leases......... 4.3 4.3 3.6 3.5 5.2
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Total operating lease obligations........... 9.7 9.7 9.0 8.9 52.1
Unconditional purchase obligations
OG&E cogeneration capacity payments............ 192.1 164.7 152.7 87.7 173.6
OG&E other purchased power capacity payments... 10.7 14.6 N/A N/A N/A
OG&E fuel minimum purchase commitments......... 164.1 152.2 145.6 147.2 565.4
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Total unconditional purchase obligations.... 366.9 331.5 298.3 234.9 739.0
Total capital requirements, operating lease
obligations and unconditional purchase
obligations..................................... 751.1 568.0 545.1 567.9 2,094.3
Amounts recoverable through automatic fuel
adjustment clause (E)........................... (370.8) (334.9) (303.7) (240.3) (785.9)
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Total, net.................................. $ 380.3 $ 233.1 $ 241.4 $ 327.6 $1,308.4
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(A) Includes approximately $86.6 million from the January 2002 ice storm.
(B) Amounts do not include the acquisition of New Generation.
(C) Amounts exclude discontinued operations capital expenditures.
(D) Reflects amounts that have been called to date for redemption in 2003.
(E) Includes expected recoveries of costs incurred for OG&E's railcar operating lease obligations
and OG&E's unconditional purchase obligations.
N/A - not applicable
Variances in the actual cost of fuel used in electric generation (which includes the operating lease obligations for OG&E’s railcar leases shown above) and certain purchased power costs, as compared to the fuel component included