10-K 1 oge10k123103.htm 10K 12/31/2003

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, 2003

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
(State or other jurisdiction of
incorporation or organization)

73-1481638
(I.R.S. Employer
Identification No.)

321 North Harvey
P.O. Box 321
Oklahoma City, Oklahoma 73101-0321
(Address of principal executive offices)
(Zip Code)
Registrant’s telephone number, including area code: (405) 553-3000

Securities registered pursuant to Section 12(b) of the Act:

	Title of each class		Name of each exchange on which registered
	Common Stock Rights to Purchase Series A Preferred Stock		New York Stock Exchange and Pacific Stock Exchange 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 filer (as defined in Rule 12b-2 of the Act). Yes X No

As of June 30, 2003, 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 $1,704,295,645 based on the number of shares held by non-affiliates (79,751,785) and the reported closing market price of the common stock on the New York Stock Exchange on such date of $21.37.

As of January 31, 2004, 87,469,884 shares of common stock, par value $0.01 per share, were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

The Proxy Statement for the Company’s 2004 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, 2003

Part I	Page
Item 1. Business	1
The Company	1
Electric Operations - OG&E	2
General	2
Regulation and Rates	5
Rate Activities and Proposals	15
Fuel Supply	16
Natural Gas Pipeline Operations - Enogex	18
Finance and Construction	28
Environmental Matters	30
Employees	33
Access to Securities and Exchange Commission Filings	33
Item 2. Properties	34
Item 3. Legal Proceedings	35
Item 4. Submission of Matters to a Vote of Security Holders	42
Executive Officers of the Registrant	43
Part II
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters	46
Item 6. Selected Financial Data	48
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	50
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	105
Item 8. Financial Statements and Supplementary Data	108
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	175

TABLE OF CONTENTS (Continued)

Item 9A. Controls and Procedures	175
Part III
Item 10. Directors and Executive Officers of the Registrant	176
Item 11. Executive Compensation	176
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	177
Item 13. Certain Relationships and Related Transactions	177
Item 14. Principal Accountant Fees and Services	177
Part IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K	178

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 (the “Settlement Agreement”) of OG&E’s rate case. The terms of the settlement are described below in “Regulation and Rates – 2002 Settlement Agreement.”

The operations of the Natural Gas Pipeline segment are conducted through Enogex Inc. and its subsidiaries (“Enogex”) and consist 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, “Enogex’s businesses”). Enogex’s focus is to utilize its gathering, processing, transportation and storage capacity to execute physical, financial and service transactions to capture revenues across different commodities, locations or time periods. 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 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 in the first quarter of 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 principal 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 revised 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 a vertically integrated utility engaged in the generation, transmission 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 consolidated assets will be in Enogex’s businesses. At December 31, 2003, OG&E and Enogex represented approximately 61 percent and 35 percent, respectively, of the Company’s consolidated assets. The remaining four percent of the Company’s consolidated assets were primarily at the holding company. 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 evolving policy at the FERC. In addition, Oklahoma and Arkansas legislatures and utility commissions may propose changes from time to time that could subject utilities to market risk. Accordingly, the Company is applying risk management practices to all of its operations in an effort to mitigate the potential adverse effect of any future regulatory changes. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Company Strategy” for a further discussion.

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 2003, five other communities and three rural electric cooperatives in Oklahoma and western Arkansas purchased electricity from OG&E for resale. The service area, with an estimated population of 1.9 million, covers approximately 30,000 square miles in Oklahoma and western Arkansas; including Oklahoma City, the largest city in Oklahoma, and Fort Smith, Arkansas. Of the 270 communities served, 244 are located in Oklahoma and 26 in Arkansas. Approximately 89 percent of total electric operating revenues for the year ended December 31, 2003, were derived from sales in Oklahoma and the remainder from sales in Arkansas.

OG&E’s system control area peak demand as reported by the system dispatcher during 2003 was approximately 5,977 MWs on August 21, 2003. OG&E’s load responsibility peak demand was approximately 5,657 MWs on August 21, 2003, resulting in a capacity margin of approximately 14.0 percent. As reflected in the table below and in the operating statistics on page 4, there were approximately 25.1 million megawatt-hour (“MWH”) sales in 2003 as compared to approximately 24.9 million in 2002 and 2001. MWH sales to OG&E’s customers (“system sales”) increased approximately 1.6 percent in 2003, due to increased usage related to customer growth in OG&E’s service territory partially offset by milder weather during 2003. Sales to other utilities and power marketers (“off-system sales”) decreased approximately 67.0 percent in 2003, due to the changing supply and demand needs on OG&E’s generation system.

Variations in MWH sales for the three years are reflected in the following table:


	2003	Increase/ (Decrease)	2002	Increase/ (Decrease)	2001	Increase/ (Decrease)
System Sales (A) Off-System Sales (A)	25.0 0.1	1.6% (67.0)%	24.6 0.3	0.4% (25.0)%	24.5 0.4	(2.0)% 33.3%
Total Sales	25.1	0.8%	24.9	---	24.9	(1.6)%
(A) Sales are in million of MWHs.

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.

OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS

Year ended December 31 (In millions)		2003			2002			2001

ELECTRIC ENERGY
(Millions of MWH)
Generation (exclusive of station use)		22	.5		23	.4		23	.0
Purchased		4	.5		3	.5		3	.7

Total generated and purchased		27	.0		26	.9		26	.7
Company use, free service and losses		(1	.9)		(2	.0)		(1	.8)

Electric energy sold		25	.1		24	.9		24	.9

ELECTRIC ENERGY SOLD
(Millions of MWH)
Residential		8	.2		8	.0		8	.0
Commercial and industrial		12	.6		12	.4		12	.4
Public street and highway lighting		0	.1		0	.1		0	.1
Other sales to public authorities		2	.6		2	.6		2	.5
System sales for resale		1	.5		1	.5		1	.5

Total system sales		25	.0		24	.6		24	.5
Off-system sales		0	.1		0	.3		0	.4

Total sales		25	.1		24	.9		24	.9

ELECTRIC OPERATING REVENUES
(In millions)
Residential	$	601	.4	$	557	.6	$	578	.9
Commercial and industrial		665	.9		605	.5		638	.0
Public street and highway lighting		11	.1		10	.4		10	.9
Other sales to public authorities		135	.0		125	.1		127	.9
System sales for resale		57	.7		48	.2		52	.5
Provision for FERC rate refund		-	--		-	--		(1	.0)

Total system sales		1,471	.1		1,346	.8		1,407	.2
Off-system sales		4	.1		6	.3		13	.0

Total Electric Revenues		1,475	.2		1,353	.1		1,420	.2
Miscellaneous revenues		41	.9		34	.9		36	.6

Total Electric Operating Revenues	$	1,517	.1	$	1,388	.0	$	1,456	.8

ACTUAL NUMBER OF ELECTRIC CUSTOMERS
(At end of period)
Residential		622,52	7		616,71	2		609,40	8
Commercial and industrial		89,23	5		88,46	6		87,51	1
Public street and highway lighting		24	9		24	9		25	0
Other sales to public authorities		13,40	9		13,03	1		12,56	6
Sales for resale		5	0		5	5		6	2

Total		725,47	0		718,51	3		709,79	7

AVERAGE RESIDENTIAL CUSTOMER SALES
Average annual revenue	$	970.0	4	$	907.9	5	$	952.3	2
Average annual use (kilowatt-hour (“KWH”))		13,20	2		13,09	5		13,13	1
Average price per KWH (cents)	$	7.3	5	$	6.9	3	$	7.2	5

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. For the year ended December 31, 2003, approximately 87 percent of OG&E’s electric revenue was subject to the jurisdiction of the OCC, nine percent to the APSC and four percent to the FERC.

The order of the OCC authorizing 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.

2002 Settlement Agreement

On October 11, 2002, OG&E, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to 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 went into effect January 6, 2003; (ii) recovery by OG&E, through rate base, of the capital expenditures associated with the January 2002 ice storm; (iii) OG&E to acquire electric generation (“New Generation”) of not less than 400 megawatts (“MW”) to be integrated into OG&E’s generation system; and (iv) 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. Previously, OG&E had a 50/50 sharing mechanism in Oklahoma for any off-system sales. The Settlement Agreement provided that the first $1.8 million in annual net profits from 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.

Pending Acquisition of Power Plant

As part of the 2002 Settlement Agreement with the OCC, OG&E undertook to acquire New Generation of not less than 400 MWs. The acquisition of a 77 percent interest in the 520 MW NRG McClain Station (the “McClain Plant”) would clearly constitute an acquisition of such New Generation under the Settlement Agreement. OG&E expects this New Generation, including the interim purchase power agreement, will provide savings, over a three-year period, in excess of $75.0 million to its Oklahoma customers. These savings will be derived from: (i)

the avoidance of purchase power contracts otherwise needed; (ii) replacing an above market cogeneration contract with PowerSmith Cogeneration Project, L.P. (“PowerSmith”) when it can be terminated at the end of August 2004; and (iii) fuel savings associated with operating efficiencies of the new plant. These savings, while providing real savings to Oklahoma customers, are not expected to affect the profitability of OG&E because OG&E’s rates would not need to be reduced to accomplish these savings. As indicated in the Settlement Agreement, OG&E is required to provide monthly reports, for a period of 36 months after the acquisition, to the OCC Staff, documenting and providing proof of savings experienced by OG&E’s customers. 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 Oklahoma customers any unrealized savings below $75.0 million as determined at the end of the 36-month period, which shall be no later than December 31, 2006. PowerSmith has filed an application with the OCC seeking to compel OG&E to continue purchasing power from PowerSmith’s qualified cogeneration facility under the Public Utility Regulatory Policy Act of 1978 (“PURPA”) at a price that would include an avoided capacity charge equal to the lesser of (i) the rate currently specified in the power purchase agreement between OG&E and PowerSmith or (ii) the avoided cost of the McClain Plant. OG&E does not believe that this matter should be heard at the OCC at this time and that the avoided cost requested by PowerSmith is too high. In the event PowerSmith is ultimately successful and OG&E is required to sign a purchase power agreement, it could negatively affect OG&E’s ability to achieve the targeted $75 million three-year customer savings under the existing terms of the Settlement Agreement. PowerSmith and OG&E have been holding discussions to determine if mutually agreeable terms can be reached for a power contract between the companies providing for capacity payments to the PowerSmith facility.

In the event OG&E did not acquire the New Generation by December 31, 2003, the Settlement Agreement requires OG&E 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 1, 2004, the credit to Oklahoma customers will terminate in the first month that the New Generation begins initial operations and any previously-credited amounts to Oklahoma customers will be deducted in the determination of the $75.0 million targeted savings.

On August 18, 2003, OG&E signed an asset purchase agreement to acquire NRG McClain LLC’s 77 percent interest in the McClain Plant. The acquisition of this interest in the McClain Plant would clearly constitute an acquisition of New Generation under the Settlement Agreement. The purchase price for the interest in the McClain Plant is approximately $159.9 million, subject to adjustment for prepaid gas and property taxes. The McClain Plant includes natural gas-fired combined cycle combustion turbine units and is located near Newcastle, Oklahoma in McClain County, Oklahoma. The McClain Plant began operating in 2001. The owner of the remaining 23 percent in the McClain Plant is the Oklahoma Municipal Power Authority (“OMPA”).

Because the current owner of the McClain Plant has filed for bankruptcy protection, the acquisition also was subject to approval by the bankruptcy court. As part of the bankruptcy approval process, NRG McClain LLC’s interest in the plant was subject to an auction process and on October 28, 2003, the bankruptcy court approved the sale of NRG McClain LLC’s interest in the plant to OG&E. Several parties have filed interventions at the FERC opposing OG&E’s application under Section 203 of the Federal Power Act to acquire NRG McClain’s interest in the power plant or, alternatively, requesting the FERC to delay approving such acquisition. OG&E believed that its application met the standards under Section 203 set forth by the FERC and that its application would be approved. On December 18, 2003, the FERC shifted its policy regarding market power issues, raised wholesale market power concerns and ordered a hearing regarding OG&E’s acquisition of the McClain Plant. The FERC action did not reject OG&E’s request to purchase the McClain Plant, but demonstrated that OG&E must address certain issues. On January 20, 2004, OG&E filed a petition for re-hearing of the FERC’s December 18, 2003 order which included new mitigation measures that were designed to allow for prompt approval of the transaction. That request is still pending before the FERC. OG&E has no indication whether the FERC will accept those proposed mitigation measures. On March 2, 2004, OG&E filed testimony and exhibits with the FERC administrative law judge. The testimony and exhibits indicate that, if the case proceeds to hearing, the wholesale market power issues that the FERC raised in the December 18, 2003 order may be resolved by the minimal mitigation measures.

Assuming the acquisition occurs, OG&E expects to operate the plant in accordance with a joint ownership and operating agreement with the OMPA. Under this agreement, OG&E would operate the facility, and OG&E and the OMPA would be entitled to the net available output of the plant based on their respective ownership percentages. All fixed and variable costs, except fuel and gas transportation costs, would be shared in proportion to the respective ownership interests. Fuel and gas transportation costs would be shared based on consumption. OG&E expects to utilize its portion of the output, 400 MWs, to serve its native load. As provided in the Settlement Agreement pending approval of a request to increase base rates to recover the investment in the plant, OG&E will have the right to accrue a regulatory asset, for a period not to exceed 12 months subsequent to the acquisition, consisting of the non-fuel operation and maintenance expenses, depreciation, cost of debt associated with the investment and ad valorem taxes. Upon approval by the OCC of OG&E’s request, 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.

Despite the delay at the FERC, an agreement to purchase power from the McClain Plant is enabling OG&E to honor the customer savings as outlined in the Settlement Agreement. On January 8, 2004, OG&E filed an application with the OCC and requested that the OCC confirm the steps that OG&E has taken to comply with the Settlement Agreement will result in customer savings being delivered beginning January 1, 2004, and that no further rate reduction is necessary. Various parties have intervened opposing OG&E’s request. If the OCC does not agree with OG&E’s request, OG&E will be required to reduce electric rates to its Oklahoma customers by approximately $2.1 million per month and would expect to reduce expenditures for planned electric system reliability upgrades. The OCC has scheduled a hearing on April 19, 2004 for action in this case.

Assuming that OG&E acquires the McClain Plant, OG&E expects to fund the acquisition with a combination of a capital contribution from the Company, funded in part by the Company’s equity issuance in 2003, and the issuance of long-term debt by OG&E.

2003 Rate Case

On September 15, 2003, OG&E filed with the OCC a notice of intent to seek an annual increase in its rates to its Oklahoma customers of more than one percent. The notice listed the following, among others, as major issues to be addressed in its application: (i) the acquisition of New Generation in accordance with the Settlement Agreement; (ii) increased capital expenditures for efficiency improvements and reliability enhancements to ensure fuel costs are minimized; and (iii) increased pension, medical and insurance costs. On October 31, 2003, OG&E filed a request with the OCC to increase its rates by approximately $91 million annually. The increase was intended to pay for its pending acquisition of a 77 percent interest in the McClain Plant, allow for investment in electric system reliability and address rising business costs. The rate plan would have reduced rates for schools and more than 80,000 small businesses and non-profit organizations. On January 15, 2004, OG&E filed an application to withdraw its request for a $91 million rate increase due to the delay at FERC in receiving the necessary approvals to complete the acquisition of the McClain Plant, which was a significant part of this rate case. An order dismissing the case was issued by the OCC on January 30, 2004. On December 18, 2003, the FERC issued an order setting for hearing OG&E’s proposed acquisition of the McClain Plant and on January 15, 2004, the FERC administrative law judge in charge of the hearing and the parties to the case agreed to a procedural schedule that would produce a decision on the McClain Plant acquisition no sooner than the third quarter of 2004. OG&E expects to file another rate case in the near future to recover increased operating and capital expenditures.

Gas Transportation and Storage Agreement

As part of the Settlement Agreement, OG&E also agreed to consider competitive bidding for gas transportation service to its natural gas-fired generation facilities pursuant to the terms set forth in the Settlement Agreement. OG&E believes that in order for it to achieve maximum coal generation and ensure reliable electric service, it must have firm no-notice load following service for both gas transportation and gas storage. This type of service is required to satisfy the daily swings in customer demand placed on OG&E’s system and still permit natural gas units to not impede coal energy production. OG&E also believes that gas storage is an integral part of providing gas supply to OG&E’s generation facilities. Accordingly, OG&E evaluated its competitive bid options in light of these circumstances. OG&E’s evaluation clearly demonstrates that the Enogex integrated gas system provides superior firm no-notice load following service to OG&E that is not available from other companies serving the OG&E marketplace. On April 29, 2003, OG&E filed an application with the OCC in which OG&E advised the OCC that, after careful consideration, competitive bidding for gas transportation was rejected in favor of a new intrastate firm no-notice load following gas transportation and storage services agreement with Enogex. This seven-year agreement provides for gas transportation and storage services for each of OG&E’s natural gas-fired generation facilities. During 2003, OG&E paid Enogex approximately $44.7 million for gas transportation and storage services. Based

upon requests for information from intervenors, OG&E has requested from Enogex and Enogex has agreed to retain a “cost of service” consultant to assist in the preparation of testimony related to this case. On January 30, 2004, the OCC issued a procedural schedule for this case. A hearing is scheduled August 10-11, 2004 and an OCC order in the case is expected by the end of 2004. OG&E believes the amount currently paid to Enogex for no-notice load following transportation and storage services is fair, just and reasonable. If any amounts paid by OG&E are found not to be recoverable, OG&E believes such amount would not be material.

Security Enhancements

On April 8, 2002, OG&E filed a joint application with the OCC requesting approval for security investments and a rider to recover these costs from the ratepayers. On August 14, 2002, OG&E filed testimony with the OCC outlining proposed expenditures and related actions for security enhancement and a proposed recovery rider. Attempting to make security investments at the proper level, 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. The OCC Staff retained a security expert to review the report filed by OG&E. OG&E currently expects that hearings will be held in early 2004.

On October 17, 2003, the OCC filed a notice of inquiry to consider the issues related to the role of the OCC and Oklahoma regulated companies in addressing the security of the electrical system infrastructure and key assets. On March 4, 2004, the OCC deliberated the notice of inquiry and directed the OCC Staff to file a rulemaking proceeding for each utility industry regarding security of the electrical system infrastructure and key assets.

Other Regulatory Actions

The Settlement Agreement, when it became effective, provided for the termination of the Acquisition Premium Credit Rider (“APC Rider”) and the Gas Transportation Adjustment Credit Rider (“GTAC Rider”).

The APC Rider was approved by the OCC in March 2000 and was implemented by 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 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 initially designed to provide retail customers in Oklahoma a choice of their electric supplier by July 1, 2002. Additional implementing legislation was to be adopted by the Oklahoma Legislature to address many specific issues associated with the 1997 Act and with deregulation. In May 2000, a bill addressing the specific issues of deregulation was passed in the Oklahoma State Senate and then was defeated in the Oklahoma House of Representatives. In May 2001, the Oklahoma Legislature postponed the scheduled start date for customer choice from July 1, 2002 until at least 2003. In addition to postponing the date for customer choice, this legislation called for a nine-member task force to further study the issues surrounding deregulation. The task force includes the Governor or his designee, the Oklahoma Attorney General, the OCC Chair and several legislative leaders, among others. In the 2003 legislative session, additional legislation was introduced to repeal the 1997 Act, but the 2003 legislative session ended without any further action to repeal the 1997 Act. It is unknown at this time whether the 1997 Act will be repealed. The Company will continue to actively participate in the legislative process and expects to remain a competitive supplier of electricity. As a result of the failures of California’s attempt to deregulate its electricity markets, the Enron bankruptcy, and associated impacts on the industry, efforts to restructure the electricity market in Oklahoma appear at this time to be delayed indefinitely.

Arkansas

In April 1999, Arkansas passed a law (the “Restructuring Law”) calling for restructuring of the electric utility industry at the retail level. The Restructuring Law initially targeted customer choice of electricity providers by January 1, 2002. In February 2001, the Restructuring Law was amended to delay the start date of customer choice of electric providers in Arkansas until October 1, 2003, with the APSC having discretion to further delay implementation to October 1, 2005. In March 2003, the Restructuring Law was repealed. As part of the repeal legislation, electric public utilities are permitted to recover transition costs. OG&E incurred approximately $2.4 million in transition costs necessary to carry out its responsibilities associated with efforts to implement retail open access. On January 20, 2004, the APSC issued an order which authorized OG&E to recover approximately $1.9 million in transition costs over an 18-month period beginning February 2004.

Automatic Fuel Adjustment Clauses

Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component in the cost-of-service for ratemaking, are passed through to 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 is currently reviewing the appropriateness of gas transportation charges under the agreement between OG&E and Enogex. See “Gas Transportation and Storage Agreement” for a further discussion. OG&E believes the amount currently paid to Enogex for transportation and storage services is fair, just and reasonable. All of the storage costs and a portion of the gas transportation costs are included in either base rates or are recoverable through OG&E’s automatic fuel adjustment clause. See “Regulation and Rates – Other Regulatory Actions” for a further discussion.

National Energy Legislation

In December 2003 the U.S. Senate failed to pass a comprehensive Energy Bill that had long been debated in the Senate and the House of Representatives. The bill, as it was proposed, would have been largely beneficial to the Company. It contained provisions that would have minimized the risk of future uneconomic purchased power contracts being forced on the Company under the PURPA as well as providing tax incentives for investment in the electric transmission and natural gas pipeline systems. The bill also provided favorable provisions for mandatory reliability oversight by the North American Electric Reliability Council with oversight by the FERC as well as the FERC citing authority for electric transmission in disputed areas. Also positive to the Company was that the bill did not contain any provisions for mandatory levels of renewable energy which would have had the effect of raising the Company’s electric rates. Another significant provision of the Energy Bill was the repeal of the Public Utility Holding Company Act of 1935 which was of minimal impact to the Company.

When Congress reconvened in January 2004, the debate renewed over the Energy Bill. A compromise bill has been proposed in the Senate that would keep all of the issues important to the Company intact with the exception of the tax provisions. Excluding those provisions would eliminate the incentives for investment in the electric transmission and natural gas pipeline

systems. It is unknown at this time what language will be contained in the final bill or when, or if, the bill is likely to be considered again in the Senate and the House of Representatives and, when or if, the bill ultimately will be approved.

Federal law imposes numerous responsibilities and requirements on OG&E. PURPA 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, reasonable and in the public interest and must provide certain types of service which may be requested by QF’s to supplement or back up those facilities’ own generation.

Although efforts to increase competition at the state level have been stalled, there have been several initiatives implemented at the federal level to increase competition in the wholesale markets for electricity. The National Energy Policy Act of 1992 (“Energy Act”), among other things, promoted the development of independent power producers (“IPP”). The Energy Act was followed by FERC Order 888 and Order 889, which facilitated third-party utilization of the transmission grid for sales of wholesale power. The Energy Act, Orders 888 and 889, and other FERC policies and initiatives have significantly increased competition in the wholesale power market. Utilities, including OG&E, have increased their own in-house wholesale marketing efforts and the number of entities with whom they historically traded. Moreover, power marketers became an increasingly important presence in the industry, however, their importance has declined following the bankruptcy of Enron and the financial troubles of other significant power marketers. These entities typically arbitrage wholesale price differentials by buying power produced by others in one market and selling it in another. IPP’s also are becoming a more significant sector of the electric utility industry. In both Oklahoma and Arkansas, significant additions of new power plants have been announced and, in some cases completed, almost all of it from IPP’s.

Notwithstanding these developments in the wholesale power market, the FERC recognized that impediments remained to the achievement of fully competitive wholesale markets including: (i) engineering and economic inefficiencies inherent in the current operation and expansion of the transmission grid; and (ii) continuing opportunities for transmission owners (primarily electric utilities) to discriminate in the operation of their transmission facilities in favor of their own or affiliated power marketing activities. In the past, the FERC only encouraged utilities to join and place their transmission systems under the operational control of independent system operators (“ISO”). On December 20, 1999, the FERC issued Order 2000, its final rule on regional transmission organizations (“RTO”). Order 2000 is intended to have the 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 Southwest Power Pool (“SPP”), the regional reliability organization for all or parts of Oklahoma, Arkansas, Kansas, Louisiana, New Mexico, Mississippi, Missouri and 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 1998. In October 2000, the SPP filed its application with the FERC to become an RTO. In July 2001, the FERC determined that the SPP did not have adequate scope and configuration to be granted RTO status. The SPP was encouraged to explore the possibility of joining an RTO to be formed in the southeastern region of the United States and then to explore the feasibility of becoming a part of the recently approved RTO being established by the Midwest Independent System Operator (“MISO”). The SPP and MISO entered negotiations during the late summer of 2001 to combine the SPP and MISO and to form a new regional transmission entity that would combine the MISO and SPP organizations, capture certain synergies that would be available from the combined organization, and allow member companies in the SPP certain options with respect to membership in the combined organization. However, for a variety of reasons, MISO and SPP terminated their proposed combination in March 2003. OG&E remained a member of the SPP while the MISO/SPP combination was pending, and OG&E participated with the SPP and other SPP members to evaluate the next steps necessary for compliance with the FERC’s Order 2000. In the meantime, the SPP continued to offer open access transmission service in the SPP region under the SPP Open Access Transmission Tariff. On October 15, 2003, the SPP filed an application with the FERC seeking authority to form an RTO. On February 10, 2004, the FERC conditionally approved the SPP’s application. The SPP must meet certain conditions before it may commence operations as an RTO. Termination of the proposed MISO/SPP combination and recent conditional approval of the SPP RTO application are not expected to significantly impact the Company’s 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. On November 25, 2003, the FERC issued its new rules regulating the relationship between electric and gas transmission providers and those entities’ merchant personnel and energy affiliates. The FERC’s final rule requires all transmission providers to be in full compliance with the new rules by June 1, 2004. In February 2004, OG&E and Enogex submitted plans and schedules to take the necessary actions to be in compliance with these new rules and expect that their initial costs to comply with the final rule will not exceed $1.6 million in 2004. The final rule is currently before the FERC on rehearing. Any changes to the final rule on rehearing could affect the anticipated compliance costs.

In July 2002, the FERC issued a Notice of Proposed Rulemaking on Standard Market Design Rulemaking for regulated utilities. If implemented as proposed, the rulemaking will substantially change how wholesale electric markets operate throughout the United States. The proposed rulemaking expands the FERC’s intent to unbundle transmission operations from integrated utilities and ensure robust competition in wholesale markets. The proposed rule contemplates that all wholesale and retail customers will take transmission service under a single network transmission service tariff. The rule also contemplates the implementation of a bid-based system for buying and selling energy in wholesale markets. RTOs or Independent Transmission Providers will administer the market. RTOs will also be responsible for regional plans that identify opportunities to construct new transmission, generation or demand side programs to reduce transmission constraints and meet regional energy requirements. Finally, the rule envisions the development of Regional Market Monitors responsible for ensuring the individual participants do not exercise unlawful market power. On April 28, 2003, the FERC issued a White Paper, “Wholesale Market Platform”, in which the FERC indicated that it will change the proposed rule as reflected in the White Paper and following additional regional technical conferences. The FERC committed in the White Paper to work with interested parties including state commissions to find solutions that will recognize regional differences within regions subject to the FERC’s jurisdiction. Thus far, the FERC has held conferences in Boston, Omaha, Wilmington, Tallahassee, Phoenix, New York and San Francisco.

In October 2003, the FERC issued new rules governing corporate “money pools,” which include jurisdictional public utility or pipeline subsidiaries of nonregulated parent companies. The rules require documentation of transactions within such money pools and notification to the FERC if the common equity ratio of the utility falls below 30 percent.

The FERC requires all utilities authorized to sell power at market-based rates to file updated market power analyses every three years. In December 2003, OG&E filed its updated market power analysis with the FERC.

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 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 certain costs: (i) that are probable of future recovery as a deferred charge until such time as the cost is approved by a regulatory authority, then the cost is reclassified as a regulatory asset; and (ii) that are probable of future liability as a deferred credit until such time as the amount is approved by a regulatory authority, then the amount is reclassified as a regulatory liability.

At December 31, 2003 and 2002, OG&E had regulatory assets of approximately $94.2 million and $111.1 million, respectively, and regulatory liabilities of approximately $148.7 million and $109.3 million, respectively. Approximately 45 percent of the regulatory assets and liabilities are allocated to OG&E’s electric generation assets and approximately 55 percent of the regulatory assets and liabilities are allocated to OG&E’s electric transmission and distribution assets.

As discussed previously, legislation was enacted in Oklahoma and Arkansas that was to restructure the electric utility industry in those states. The Arkansas legislation was repealed and implementation of the Oklahoma restructuring legislation has been delayed and seems unlikely to proceed during the near future. Yet, if and when implemented this legislation would deregulate OG&E’s electric generation assets and cause the Company to discontinue the use of SFAS No. 71, with respect to its related regulatory balances. This may result in either full recovery of generation-related regulatory assets (net of related regulatory liabilities) or a non-cash, pre-tax write-off as an extraordinary charge, depending on the transition mechanisms developed by the legislature for the recovery of all or a portion of these net regulatory assets.

The previously enacted Oklahoma and Arkansas legislation would not affect 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 balances is appropriate. However, if utility regulators in Oklahoma and Arkansas were to adopt regulatory methodologies in the future that are not based on the cost-of-service, the continued use of SFAS No. 71 with respect to the regulatory balances related to the electric transmission and distribution assets may no longer be appropriate. Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, management believes that its regulatory assets, including those related to generation, are probable of future recovery.

Summary

The Energy Act, the actions of the FERC, the restructuring legislation in Oklahoma and other factors are intended to increase competition in the electric industry. 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.

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. The Settlement Agreement addressed the importance of OG&E acquiring New Generation. See “Regulation and Rates — Pending Acquisition of Power Plant” for the

issues facing OG&E in its acquisition of the McClain Plant in accordance with the Settlement Agreement.

Other elements of importance addressed in the Settlement Agreement included 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 allows 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 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 is 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 is 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 provides 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 in future years since customers may choose to remain on existing rate options instead of volunteering for the new rate option choices. There was no overall material impact in 2003 associated with these new rate options, but minimal revenue variations may occur in the future based upon changes in customers’ usage characteristics if they choose these new programs.

Fuel Supply

During 2003, approximately 77 percent of the OG&E-generated energy was produced by coal units and 23 percent by natural gas units. Of the 5,660 total MW capability reflected in the

table under Item 2. Properties, approximately 3,125 MWs or 55 percent are from natural gas generation and approximately 2,535 MWs 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. 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:

		2003			2002			2001			2000			1999

Coal	$	0.9	3	$	0.9	3	$	0.8	1	$	0.8	7	$	0.8	5
Natural Gas	$	6.4	6	$	3.7	8	$	4.9	1	$	4.9	3	$	3.1	4
Weighted Average	$	2.2	7	$	1.7	7	$	1.9	7	$	1.9	6	$	1.5	4

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 MWs, are designed to burn low sulfur western coal. OG&E purchases coal primarily under long-term contracts expiring in 2010 and 2011. During 2003, OG&E purchased approximately 9.7 million tons of coal from the following Wyoming suppliers: Kennecott Energy Company, Arch Coal Inc., 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 well within the limitations of the provisions of Phase II of The Clean Air Act.

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 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 (“RFB”) to acquire approximately 42 percent of its projected annual natural gas requirements through approximately April 2004. These contracts are tied to various gas price market indices and most will expire in April 2004. A significant portion of future gas requirements of OG&E will be secured through a new multi-year RFB that was issued in February 2004 with deliveries to begin in April 2004. Additional gas requirements of OG&E will be met with 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.

NATURAL GAS PIPELINE OPERATIONS - ENOGEX

The operations of the Natural Gas Pipeline segment are conducted through Enogex and consist 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. Enogex’s focus is to utilize its gathering, processing, transportation and storage capacity to execute physical, financial and service transactions to capture revenues across different commodities, locations, or time periods. 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 8,000 miles of intrastate gas gathering and transportation pipelines. Additionally, through a 75 percent interest in NOARK, Enogex also owns a controlling interest in and operates Ozark, an approximately 931 mile FERC regulated interstate pipeline that extends from southeast Oklahoma through Arkansas to southeast Missouri. 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 in the first quarter of 2003 and are reported in the Consolidated Financial Statements as discontinued operations.

The transportation, storage and gathering 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 natural gas-fired generation facilities. 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 gathering assets access major wellhead supply sources primarily located across Oklahoma and Arkansas, and the integrated transportation and storage assets provide the ability to regulate the receipt and delivery of natural gas to match the instantaneous needs of these generation units.

Natural gas-fired generation units contribute their highest value when they have the capability to provide “load following” service to the customer. While the physical characteristics of natural 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 a generator’s ability to provide reliable generation service at reasonable prices to the consumer.

Not only is Enogex providing service to OG&E, but Enogex’s same assets provide firm and interruptible services to a significant portion of the other natural gas-fired generation loads in the State of Oklahoma and numerous other generation loads in the adjoining States of Texas and Arkansas. Enogex understands the needs of generators, and more importantly has the appropriately-sized pipelines, compression and integrated storage assets necessary to meet their requirements.

Through Enogex’s gathering and processing assets, Enogex aggregates gas supplies for both its own markets, and 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 Anadarko and Arkoma basins. Oklahoma ranks third in the nation in natural gas production. The system capacity, due to its large diameter gathering pipelines and its natural gas processing plants, is capable of adapting to the varying pressure and quality requirements of 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. Enogex is also able to remove natural gas liquids from the wellhead gas streams, by processing the gas, which would otherwise prevent such gas from meeting the British thermal unit (“Btu”) and quality specifications of the downstream marketplace and therefore could not be produced.

The activities described above, while central to Enogex’s operations, are not its only businesses. The transportation capabilities and “on and off-system” markets of the pipeline assets provide other business opportunities. This 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”. At December 31, 2003, excluding the pipeline connection between its intrastate pipeline and the Ozark pipeline, Enogex was connected to 15 other major pipelines at approximately 60 pipeline interconnect points 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 constantly varying relationship between supply and demand, both in volume and location, Enogex’s assets sit in a key geographic region 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.

Enogex’s marketing and trading business is an important element in realizing the full value of its transportation and storage assets and in providing products and services that support the market hub concept. The marketing and trading business offers the Company real-time and longer-term price discovery and valuation of energy commodities (natural gas and associated natural gas liquids) associated with the Company’s assets. The marketing and trading business also is 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 business also provides 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 that these assets can provide. In addition, the Company expects to generate additional margins by improving its ability to aggregate gas, maximize the operational capabilities of its assets and utilize commercial information available from the marketplace.

Recent Actions

Beginning in 2002, Enogex evaluated, redesigned and reorganized its internal work processes and senior management structure in order to achieve cost reductions, revenue enhancements and strategic leadership within its businesses.

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, 2003, 2002 and 2001 in the Consolidated Financial Statements.

In addition to these ongoing efforts, in 2003 Enogex began a major upgrade of its information systems that is expected to be substantially completed by the end of 2004. The Company believes that these upgrades will be a major step towards obtaining the data required to allow it to capture available economic opportunities on its assets, provide improved customer service and enable management to more accurately determine the earnings potential of its various assets and service offerings.

Other efforts at Enogex during 2003 included improvements to its two storage fields. The repair project at the Wetumka Storage Facility (formerly known as Greasy Creek) was designed to mitigate any potential gas migration, and the remediation program at the Stuart Storage Facility (once completed) is intended to prevent water encroachment in the field. During 2003, approximately $0.5 million was spent and expensed on the Wetumka Storage Facility project and approximately $2.4 million in capital expenditures was spent on the Stuart Storage Facility project; the Company expects no material future expenditures at the Wetumka Storage Facility and expenditures of less than $1.5 million for the Stuart Storage Facility.

During the fourth quarter of 2002, the Company recognized a pre-tax impairment loss of approximately $48.3 million which related to Enogex natural gas processing and compression assets. In the fourth quarter of 2003, as a result of an ongoing initiative to improve asset utilization, the Company concluded that certain idle Enogex natural gas compression assets may no longer be required to meet the Company’s future business needs. As a result, the Company recognized a pre-tax impairment loss of approximately $9.2 million related to these natural gas 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. The carrying amount of these assets held for sale was approximately $11.9 million at December 31, 2003. The Company is actively marketing these assets and has developed a plan to sell these assets within one year.

On August 2, 2002, Ozark, in which an Enogex subsidiary owns a 75 percent interest, 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 for approximately $10.0 million. On November 18, 2002, the Company received FERC approval for the closing, which occurred on January 6, 2003. The Company recorded approximately a $5.3 million pre-tax gain and approximately $1.1 million in minority interest expense in the first quarter of 2003 related to the sale of these assets.

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

for the combined Enogex and Transok L.L.C. pipeline systems. By order dated May 9, 2003, the FERC accepted the stipulation and settlement agreement and entered its order modifying Enogex’s Statement of Operating Conditions (“SOC”). The FERC Order required Enogex to modify its SOC to eliminate the priority for scheduling and curtailment purposes for interruptible dedicated gas customers. In June 2003, Apache Corporation (“Apache”) and the Oklahoma Independent Petroleum Association (“OIPA”) sought rehearing as to the elimination of the priority for dedicated gas. The FERC issued a tolling order on July 9, 2003, and by order dated January 30, 2004, the FERC denied the Apache and OIPA requests for rehearing and affirmed its May 9 order. The time for judicial appeal of the January 30, 2004 order has not yet expired. The settlement included a fee to be assessed under certain market conditions to process customer gas gathered behind processing plants so that it meets pipeline gas quality Btu standards and can be redelivered to interstate pipelines (default processing fee). The default processing fee, which decreases the volatility of its earnings stream by reducing its exposure to keep whole processing arrangements, is implemented in the event the fractionation spreads (the difference between the price of natural gas liquids extracted and natural gas) are negative. The settlement also approved a monthly low flow meter charge of $200 (offset in any month by the transportation revenues generated by gas through the meter). Pursuant to Enogex’s SOC, if Enogex’s annual processing gross margin on revenues exceeds a specified threshold, Enogex is required to record a default processing fee refund obligation in an amount equal to the lesser of the default processing fees and the amount of the processing margin in excess of the specified threshold. During the third and fourth quarters of 2003, the Company established approximately a $4.9 million reserve, based on projected future market conditions, to cover such refund obligations. For the year ended December 31, 2003, the Company recognized revenue, net of the $4.9 million reserve, of approximately $0.3 million for default processing fees and approximately $0.7 million of low flow meter charges. For 2004, Enogex’s forecasted processing gross margin exceeds the threshold calculated under the terms of the SOC. As a result, any default processing fees charged to customers will be recorded as deferred revenue until it becomes probable that the gross margin threshold in the SOC will not be exceeded during 2004. The accounting for default processing fees is not expected to impact full-year earnings, but could affect the timing of those earnings.

Transportation and Storage

General. One of Enogex’s primary lines of business is the transportation of natural gas, with current throughput of approximately 1.4 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, 2003, excluding the pipeline connection between its intrastate pipeline and the Ozark pipeline, Enogex was connected to 15 other major pipelines at approximately 60 pipelines 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, CenterPoint Energy Gas Transmission Co., Black Marlin Pipeline, El Paso Natural Gas Pipeline, Kansas Pipeline and Oneok WesTex Transmission L.P., 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 numerous electric generation facilities in Oklahoma that are fueled by natural gas. At December 31, 2003, the net property, plant and equipment balance for Enogex’s transportation and storage business was approximately $733.0 million.

Enogex owns two storage facilities in Oklahoma, the Wetumka Storage Facility and the Stuart Storage Facility. These storage facilities are currently being operated at a working gas level of approximately 24.5 billion cubic feet (“Bcf”) with an approximate withdrawal capability of 650 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 natural gas inventory losses associated with the Wetumka Storage Facility. While some gas losses are normally associated with the operation of a natural gas storage field, the 2002 amount exceeded acceptable levels. The Stuart Storage Facility is used to support Enogex’s intrastate transportation and storage services for OG&E. During 2003, Enogex made improvements to these two storage fields. The repair project at the Wetumka Storage Facility was designed to mitigate any potential gas migration, and the remediation program at the Stuart Storage Facility (once completed) is intended to prevent water encroachment in the field. During 2003, approximately $0.5 million was spent and expensed on the Wetumka Storage Facility project and approximately $2.4 million in capital expenditures was spent on the Stuart Storage Facility project; the Company expects no material future expenditures at the Wetumka Storage Facility and expenditures of less than $1.5 million for the Stuart Storage Facility. See “Item 3. Legal Proceedings” for a discussion of the pending litigation associated with the Stuart Storage Facility.

Enogex offers interruptible Section 311 transportation services as well as both firm and interruptible services to intrastate 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 subsidiary entities (“Transok”) merged thereby simplifying 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 the primary supplier to PSO. Enogex continues to provide gas transmission delivery services to all of PSO’s natural gas-fired 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, 2009, provide for a monthly demand charge plus variable transportation charges (including fuel). As part of the contract with OG&E, Enogex provides additional natural gas storage services for OG&E. Enogex has been providing these natural gas storage services since August 2002 when Enogex exercised its option to purchase the Stuart Storage Facility to collect on its judgment against Central Oklahoma Oil and Gas Corp. (“COOG”). 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. Enogex’s lease of the Palo Duro pipeline terminated effective June 30, 2003. On June 27, 2003, Enogex sent notice to the FERC indicating that its lease of the Palo Duro pipeline had terminated, and that Enogex would no longer be offering Section 311 service to Palo Duro shippers. Enogex has extended its lease of a small segment of gathering pipeline off of the Palo Duro system, referred to as the Northeast Lateral. The term of the lease extension of the Northeast Lateral expires February 28, 2005, and will remain in effect month to month thereafter, subject to termination by either Enogex or the lessor upon 60 days notice. Though the Palo Duro system, including the Northeast Lateral, were sold from the lessor to a third party in 2004, Enogex has not received termination notice and continues to operate under the monthly lease terms. During 2003, 2002 and 2001, Enogex’s revenues from the contracts with OG&E, PSO and HPC were approximately $63.0 million, $57.1 million and $55.1 million, respectively.

Relationship with OG&E. From its inception, Enogex has been the exclusive transporter of natural gas to OG&E’s natural gas-fired generation facilities. 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-fired generation facilities when the contract with Enogex expired. The term of the then current contract was to expire in April 2004. Subsequently, this contract was amended by an agreement dated May 1, 2003 with no-notice load following requirements and a termination date of April 30, 2009. As part of the contract with OG&E, Enogex provides additional natural gas storage services for OG&E. Enogex has been providing these natural gas storage services since August 2002 when Enogex exercised its option to purchase the Stuart Storage Facility to collect on its judgment against COOG. The amount collected from OG&E by Enogex under the current contract for transportation services was approximately $33.5 million, $33.6 million and $36.3 million, respectively, during 2003, 2002 and 2001. The amount collected from OG&E by Enogex under the current contract for storage services was approximately $11.2 million and $3.3 million, respectively, during 2003 and 2002. Enogex did not provide storage services to OG&E during 2001.

Competition. Enogex’s transportation and storage assets compete with interstate and other intrastate pipeline and storage facilities in providing transportation and storage services for natural gas. The principal elements of competition are rates, terms of services, flexibility and reliability of service.

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 most recent Section 311 case.

The Company, through Enogex, owns a 75 percent interest in Ozark. Ozark transports natural gas in interstate commerce. As a result, Ozark qualifies as a “natural gas company” under the Natural Gas Act of 1938 (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 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 Natural Gas 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 APSC 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” above for a discussion of competitive bidding for OG&E’s service.

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 natural 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 and delivered to processing plants for the extraction of natural gas liquids. During 2003, the gathering systems connected approximately 232 producing wells located primarily in the Anadarko and Arkoma basins of

Oklahoma and Arkansas represented by 103 contracts with 72 producers. The Company provides connection, measurement, treating, dehydration and compression services for various types of producing wells owned by various sized producers who are active in the region. Where the quality of natural gas received dictates that removal of natural gas liquids may be in order, such gas is aggregated via the gathering system to the inlet of one or more of the Company’s fleet of processing plants operated by Products. The resulting processed stream of natural gas is then delivered via the Enogex pipeline system to one or more delivery points into the web of transmission pipelines in the region. Products is one of the largest gas processors in the state of Oklahoma, operating six gas processing plants with a total inlet capacity of 678 MMcfd. During 2002, Products had ownership interests in two other gas processing plants related to NuStar, which were sold in February 2003. In 2003, approximately 259 million gallons of natural gas liquids were produced. Products has been active since 1968 in the processing of natural gas and extraction and marketing of natural gas liquids. The liquids extracted include 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, 2003, the net property, plant and equipment balance for Enogex’s gathering and processing business was approximately $308.4 million.

Approximately 24 percent of the commercial grade propane processed at Products’ plants is sold on the local market. The balance of propane and 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.

During 2002, Enogex initiated 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 by replacing the Btu value of the liquids extracted from the well stream 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 based upon then current market conditions. 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 default processing fee in the event the fractionation spreads (the difference between the price of natural gas liquids extracted and natural gas) are negative. As a result, in months in which commodity spreads were negative thus activating the default processing fee allowed in the SOC, the exposure to keep whole processing arrangements has been reduced. Further, when market conditions dictated, Products took active steps to reduce the amount of natural gas at the plant inlet to approximately 11 percent keep whole without the default processing fee. In addition, the Company actively monitors current and future commodity prices for opportunities to hedge its 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 discussed above, the Company sold all of its interest in Belvan in 2002 and its interest in NuStar in February 2003.

Competition. Enogex competes with gatherers of all types and sizes, including those affiliated with various producers, other major pipeline companies, as well as various independent gatherers. 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. Enogex 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 falls without a corresponding decrease in the price of natural gas, it may become uneconomical to extract certain natural gas liquids. This factor had a significant adverse impact on the results of Enogex during 2001 but as discussed above, the potential adverse impact has been materially mitigated, but not entirely eliminated. 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 and Btu content of natural gas gathered. 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 are conducted primarily through its subsidiary, OGE Energy Resources, Inc. (“OERI”).

OERI is engaged in the business of natural gas marketing. OERI’s agreements with Enogex provide for OERI to provide marketing services for all natural gas volumes purchased by Enogex 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 gathering, processing and storage assets. Prior to the sale of Enogex’s exploration assets in 2002, OERI marketed the natural gas produced by Enogex Exploration Corporation (“Exploration”). At December 31, 2003, the net property, plant and equipment balance for Enogex’s marketing and trading business was approximately $1.8 million.

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 pipeline capacity with Enogex and other pipelines to access multiple interconnections with the interstate pipeline system network 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 intermediate-term markets (less than three years) and short-term “spot” markets for natural gas. Although OERI continues to increase its focus on intermediate-term sales, short-term sales of natural gas are expected to 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 2003, OERI bought and sold approximately 1.0 Bcfd of natural gas.

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 daily and monthly trading stop loss limits of $2.5 million in accordance with corporate policies.

Competition. OERI competes in marketing and trading natural gas with major integrated oil companies, marketing affiliates of major interstate and intrastate pipelines, national and local natural gas brokers, marketers and distributors for natural gas supplies. Competition for natural gas supplies is based primarily on reputation, credit support, 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 the price of delivered natural gas.

For the year ended December 31, 2003, approximately 74 percent of OERI’s service volumes were with electric utilities, local gas distribution companies, pipelines and producers. The remaining 26 percent of service volumes were to marketers, municipals, cooperatives and industrials. At December 31, 2003, approximately 76 percent of the exposure was to companies having investment grade ratings with Standard & Poor’s Ratings Services (“Standard & Poor’s”) and approximately three percent having less than investment grade ratings. The remaining 21 percent of OERI’s exposure is with privately held companies, municipals or cooperatives that were not rated by Standard & Poor’s. OERI applies internal credit analyses and policies to these non-rated companies.

Exploration and Production

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, 2003, 2002 and 2001 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 – Enogex – Discontinued Operations” for a further discussion.

FINANCE AND CONSTRUCTION

Future Capital Requirements

Capital Requirements

The Company’s primary needs for capital are related to replacing or expanding existing facilities in OG&E’s electric utility business and replacing or expanding existing facilities at Enogex. Other capital requirements are primarily related to maturing debt, operating lease obligations, hedging activities, natural gas storage and delays in recovering unconditional fuel purchase obligations. The Company generally meets its cash needs through a combination of internally generated funds, short-term borrowings and permanent financings. See “Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations – Liquidity and Capital Requirements” for a detailed discussion of the Company’s capital requirements.

Variances in the actual cost of fuel used in electric generation (which includes the operating lease obligations for OG&E’s railcar leases) and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, are passed through to OG&E’s customers through automatic fuel adjustment clauses. Accordingly, while the cost of fuel related to operating leases and the vast majority of unconditional fuel purchase obligations of OG&E may increase capital requirements, such costs are recoverable through automatic fuel adjustment clauses and have little, if any, impact on net capital requirements and future contractual obligations. The automatic fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. See Note 18 of Notes to Consolidated Financial Statements for a further discussion.

Capital Expenditures

The Company’s current 2004 to 2006 construction program includes the purchase of New Generation as discussed below. OG&E currently has contracts with qualified cogeneration facilities and small power production producers’ (“QF contracts”) for the purchase of 540 MWs, all of which expire in the next one to five years. The Company will continue reviewing all of the supply alternatives to replace expiring QF contracts that minimize the total cost of generation to our customers. Accordingly, OG&E will continue to explore opportunities to build or buy power plants in order to serve its native load. As a result of the high volatility of current natural gas prices and the increase in natural gas prices, OG&E will also assess the feasibility of constructing additional base load coal-fired units. See “Regulation and Rates – Pending Acquisition of Power Plant” for a description of current proceedings involving a PowerSmith QF contract.

On August 18, 2003, OG&E signed an asset purchase agreement to acquire NRG McClain LLC’s 77 percent interest in the 520 MW McClain Plant. The purchase price for the interest in the McClain Plant is approximately $159.9 million, subject to adjustment for prepaid gas and property taxes. Closing is currently delayed in response to an order of the FERC. See “Regulation and Rates – Pending Acquisition of Power Plant.” If approval is received, funding

for the acquisition is to be provided by proceeds received by the Company from its equity offering in the third quarter of 2003, and a debt issuance by OG&E. To reliably meet the increased electricity needs of OG&E’s customers during the foreseeable future, OG&E will continue to invest to maintain the integrity of the delivery system. Approximately $10.5 million of the Company’s capital expenditures budgeted for 2004 are to comply with environmental laws and regulations.

Future Sources of Financing

General

Management expects that internally generated funds, funds received from the 2003 equity offering, proceeds from the sales of common stock pursuant to the Company’s Automatic Dividend Reinvestment and Stock Purchase Plan (“DRIP”) and short-term debt will be adequate over the next three years to meet other anticipated capital expenditures, operating needs, payment of dividends and maturities of long-term debt. As discussed below, the Company utilizes short-term debt to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged. The Company issued equity in the third quarter of 2003 and issued common stock pursuant to the DRIP during 2003. Later in 2004, assuming the acquisition of the McClain Plant is approved by the FERC, OG&E plans to issue debt to fund the purchase of the McClain Plant and for general corporate purposes and the Company plans to issue common stock pursuant to the DRIP during 2004.

Short-Term Debt

Short-term borrowings generally are used to meet working capital requirements. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Requirements – Future Sources of Financing” for a table showing the Company’s lines of credit in place and available cash at January 31, 2004. Short-term borrowings are expected to consist of a combination of bank borrowings and commercial paper.

The Company’s ability to access the commercial paper market could be adversely impacted by a commercial paper ratings downgrade. The lines of credit contain rating grids that require annual fees and borrowing rates to increase if the Company suffers an adverse ratings impact. The impact of additional downgrades of the Company’s rating would result in an increase in the cost of short-term borrowings of approximately five to 20 basis points, but would not result in any defaults or accelerations as a result of the rating changes. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Requirements – Future Capital Requirements” for potential financing needs upon a downgrade by Moody’s Investors Service (“Moody’s”) of Enogex’s long-term debt rating.

Unlike the Company and Enogex, OG&E must obtain regulatory approval from the FERC in order to borrow on a short-term basis. OG&E has the necessary regulatory approvals to incur up to $400 million in short-term borrowings at any one time.

Security Ratings

In January and February 2003, Standard & Poor’s and Moody’s lowered many of the credit ratings of OGE Energy Corp.’s, OG&E’s and Enogex’s debt. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Requirements – Future Capital Requirements” for a more detailed discussion of such credit rating agency actions.

Asset Sales

Also contributing to the liquidity of the Company have been numerous asset sales by Enogex. Since January 1, 2002, completed sales generated net proceeds of approximately $101.3 million. Sales proceeds generated to date have been used to reduce debt at Enogex and commercial paper at the holding company.

The Company continues to evaluate opportunities to enhance shareowner returns and achieve long-term financial objectives through acquisitions and divestitures of assets that may complement its existing portfolio. Permanent financing would be required for any such acquisitions.

ENVIRONMENTAL MATTERS

Approximately $10.5 million of the Company’s capital expenditures budgeted for 2004 are to comply with environmental laws and regulations.

The Company’s management believes that all of its operations are in substantial compliance with present federal, state and local environmental standards. It is estimated that the Company’s total expenditures for capital, operating, maintenance and other costs to preserve and enhance environmental quality will be approximately $62.3 million during 2004, compared to approximately $52.7 million utilized in 2003. The Company continues to evaluate its environmental management systems to ensure compliance with existing and proposed environmental legislation and regulations and to better position itself in a competitive market.

In 2003, several pieces of national legislation were either introduced or reintroduced after having failed to pass in 2002. These bills could have required the reduction in emissions of sulfur dioxide (“SO2”), nitrogen oxide (“NOX”), carbon dioxide (“CO2”) and mercury from the electric utility industry. Among the bills was President Bush’s “Clear Skies” proposal. While not addressing CO2, this bill would require significant reductions in SO2, NOX and mercury emissions. As in 2002, none of the proposed legislation became law; however, it is expected that numerous multi-pollutant bills will again be introduced in 2004.

As required by Title IV of the Clean Air Act Amendments of 1990 (“CAAA”), OG&E completed installation and certification of all required continuous emissions monitors at its generating stations in 1995. Since then, OG&E has submitted emissions data quarterly to the Environmental Protection Agency (“EPA”) as required by the CAAA. Beginning in 2000, OG&E became subject to more stringent SO2 emission requirements. These lower limits had no

significant financial impact due to OG&E’s earlier decision to burn low sulfur coal. In 2003, OG&E’s SO2 emissions were well below the allowable limits.

With respect to the NOX regulations of Title IV of the CAAA, OG&E committed to meeting a 0.45 lbs/MMBtu NOX emission level in 1997 on all coal-fired boilers. As a result, OG&E was eligible to exercise its option to extend the effective date of the lower emission requirements from the year 2000 until 2008. OG&E’s average NOX emissions from its coal-fired boilers for 2003 were 0.32 lbs/MMBtu. However, further reductions in NOX emissions could be required if, among other things, legislation is enacted, a study currently being conducted by the state of Oklahoma determines that such NOX emissions are contributing to regional haze and that OG&E’s facilities impact the air quality of the Tulsa or Oklahoma City metropolitan areas, or if Oklahoma fails to meet the new fine particulate standards. Any of these scenarios would require significant capital and operating expenditures.

The Oklahoma Department of Environmental Quality’s Clean Air Act Amendment Title V permitting program was approved by the EPA in March 1996. By March of 1997, OG&E had submitted all required permit applications. As of December 31, 2003, OG&E had received Title V permits for all but one of its generating stations. Since OG&E submitted all of its permit applications on time it is considered in compliance with the Title V permit program even though all permits have not been issued. Air permit fees for generating stations were approximately $0.6 million in 2003. The fees for 2004 are estimated to be approximately the same as in 2003.

Other potential air regulations have emerged that could impact OG&E. On December 15, 2003, the EPA proposed regulations to limit mercury emissions from coal-fired boilers. This rule is expected to be finalized by early 2005. Earliest compliance by OG&E would be January 2008. Depending upon the final regulations, this could result in significant capital and operating expenditures. In addition, on December 17, 2003, the EPA proposed an interstate air quality rule. This rule is intended to control SO2 and NOX from utility boilers in order to minimize the interstate transport of air pollution. In the proposed rule, the state of Oklahoma is exempt from any reductions. However this could change as the EPA has indicated its intentions to review Oklahoma’s impact on other states. If Oklahoma is included in the final rule reductions, this could lead to significant capital and operating expenditures by OG&E.

In 1997, the EPA finalized revisions to the ambient ozone and particulate standards. After a court challenge, which delayed implementation, the EPA has now begun to finalize the implementation process. Based on the most recent monitoring data, Oklahoma’s Governor in July of 2003 proposed to the EPA that the entire state be designated attainment with the ozone standard. Later in 2003 the EPA approved Oklahoma’s request. However, both Tulsa and Oklahoma City had previously entered into an “Early Action Compact” with the EPA whereby voluntary measures will be enacted to reduce ozone. In order to ensure that ozone levels remain below the standards, both cities intend to comply with the compact. Minimal impact on OG&E’s operations is expected.

The EPA also has issued regulations concerning regional haze. These regulations are intended to protect visibility in national parks and wilderness areas throughout the United States. In Oklahoma, the Wichita Mountains would be the only area covered under the

regulation. However, Oklahoma’s impact on parks in other states must also be evaluated. Sulfates and nitrate aerosols (both emitted from coal-fired boilers) can lead to the degradation of visibility. The State of Oklahoma has joined with eight other central states and has begun the process of determining what, if any, impact emission sources in Oklahoma have on national parks and wilderness areas. If an impact is determined, then significant capital expenditures could be required for both the Sooner and Muskogee generating stations.

While the United States has withdrawn its support of the Kyoto Protocol on global warming, legislation has been considered which would limit CO2 emissions. President Bush supports voluntary reductions by industry. OG&E has joined other utilities in voluntary CO2 sequestration projects through reforestation of land in the southern United States. In addition, OG&E has committed to reduce its CO2 emission rate (lbs. CO2/MWH) by up to five percent over the next 10 years. However, if legislation is passed requiring mandatory reductions this could have a tremendous impact on OG&E’s operations by requiring OG&E to significantly reduce the use of coal as a fuel source.

OG&E has sought, and will continue to seek, new pollution prevention opportunities and to evaluate the effectiveness of its waste reduction, reuse and recycling efforts. In 2003, OG&E obtained refunds of approximately $0.5 million from its recycling efforts. This figure does not include the additional savings gained through the reduction and/or avoidance of disposal costs and the reduction in material purchases due to the reuse of existing materials. Similar savings are anticipated in future years.

OG&E has submitted three applications during 2003 to renew its Oklahoma pollution discharge elimination system permits. OG&E anticipates that the renewed permits will continue to allow operational flexibility.

OG&E requested, based on the performance of a site-specific study, that the State agency responsible for the development of water quality standards adjust the in-stream copper criterion at one of its facilities. Adjustment of this criterion should allow the facility to avoid costly treatment and/or facility reconfiguration requirements. The State and the EPA have approved the new in-stream criteria for copper.

Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of any cooling water intake structure reflect the “best available technology” for minimizing environmental impacts. The EPA’s original rules on this issue were set-aside in 1977 by the Fourth Circuit U.S. Court of Appeals. In 1993, the EPA announced its plan to develop new rules in part due to a lawsuit filed by the Hudson Riverkeeper. To settle the lawsuit, the EPA signed a court-approved consent decree to develop 316(b) regulations. Final rules for existing utility sources were approved on February 16, 2004. Depending on the analysis of these final 316(b) rules, capital and/or operating costs may increase at some of OG&E’s generating facilities.

The construction and operation of pipelines, plants and other facilities for gathering, processing, treating, transporting or storing natural gas and other products may be subject to federal, state and local environmental laws and regulations, including those that can impose obligations to clean up any potential releases of hazardous substances at the locations at which

Enogex operates. In most instances, the applicable regulatory requirements relate to water and air pollution control or solid waste management measures. Appropriate governmental authorities may enforce these laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties, assessment and remediation requirements and injunctions as to future compliance. Enogex generates some materials subject to the requirements of the Federal Resource Conservation and Recovery Act and the Clean Water Act and comparable state statutes, prepares and files reports and documents pursuant to the Toxic Substance Control Act and the Emergency Planning and Community Right to Know Act and obtains permits pursuant to the Federal Clean Air Act and comparable state air statutes.

Environmental regulation can increase the cost of planning, design, initial installation and operation of Enogex’s facilities. Historically, Enogex’s total expenditures for environmental control facilities and for remediation have not been significant in relation to its results of operations or financial condition. The Company believes, however, that it is reasonably likely that the trend in environmental legislation and regulations will continue to be towards stricter standards.

Beginning in 2000, the Company began a process to evaluate, determine and report emissions from its pipeline facilities for compliance with recently promulgated maximum achievable control technology regulations. After evaluating the submitted information, the Oklahoma Department of Environmental Quality (“ODEQ”), beginning in late 2001, issued notices of violation regarding potential air permitting issues at certain of these reported facilities. Generally, the notices alleged violations relating to potential sources of various emissions, with the majority of the sources relating to glycol dehydrators. The Company has resolved all these matters and, in compliance with consent orders entered between the parties, the Company has taken action to submit or modify permits, install control equipment, modify reporting procedures and pay penalties. See “Item 3. Legal Proceedings” for a further discussion of this matter.

The Company has and will continue to evaluate the impact of its operations on the environment. As a result, contamination on Company property may be discovered from time to time.

EMPLOYEES

The Company and its subsidiaries had 2,941 employees at December 31, 2003.

ACCESS TO SECURITIES AND EXCHANGE COMMISSION FILINGS

The Company’s web site address is www.oge.com. The Company makes available, free of charge through its web site, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission under the heading “Investors”, “SEC Filings.”

Item 2. Properties.

OG&E owns and operates an interconnected electric generation, transmission and distribution system, located in Oklahoma and western Arkansas, which includes eight generating stations with an aggregate capability of approximately 5,660 MWs. The following table sets forth information with respect to OG&E’s electric generating facilities, all of which are located in Oklahoma:

						2003	Unit	Station
Station &		Year		Fuel	Unit	Capacity	Capability	Capability
Unit		Installed	Unit Design Type	Capability	Run Type	Factor (A)	(MWs)	(MWs)

Seminole	1	1971	Steam-Turbine	Gas	Base Load	23.3%	520.4
	2	1973	Steam-Turbine	Gas	Base Load	21.2%	507.6
	3	1975	Steam-Turbine	Gas/Oil	Base Load	19.6%	489.0	1,517.0

Muskogee	3	1956	Steam-Turbine	Gas	Base Load	7.2%	166.0
	4	1977	Steam-Turbine	Coal	Base Load	73.1%	500.5
	5	1978	Steam-Turbine	Coal	Base Load	87.3%	514.0
	6	1984	Steam-Turbine	Coal	Base Load	70.9%	502.0	1,682.5

Sooner	1	1979	Steam-Turbine	Coal	Base Load	82.1%	505.2
	2	1980	Steam-Turbine	Coal	Base Load	79.9%	513.8	1,019.0

Horseshoe	6	1958	Steam-Turbine	Gas/Oil	Base Load	16.9%	168.5
Lake	7	1963	Combined Cycle	Gas/Oil	Base Load	17.3%	227.5
	8	1969	Steam-Turbine	Gas	Base Load	8.0%	380.5
	9	2000	Combustion-Turbine	Gas	Peaking	2.3%(B)	45.5
	10	2000	Combustion-Turbine	Gas	Peaking	6.1%(B)	45.5	867.5

Mustang	1	1950	Steam-Turbine	Gas	Peaking	0.6%(B)	53.0
	2	1951	Steam-Turbine	Gas	Peaking	0.7%(B)	53.0
	3	1955	Steam-Turbine	Gas	Base Load	16.6%	115.5
	4	1959	Steam-Turbine	Gas	Base Load	21.9%	250.0
	5	1971	Combustion-Turbine	Gas/Jet Fuel	Peaking	0.7%(B)	31.0	502.5

Conoco	1	1991	Combustion-Turbine	Gas	Base Load	56.1%	31.5
	2	1991	Combustion-Turbine	Gas	Base Load	57.8%	31.0	62.5

Enid	1	1965	Combustion-Turbine	Gas	Peaking	--- (C)	---
	2	1965	Combustion-Turbine	Gas	Peaking	--- (C)	---
	3	1965	Combustion-Turbine	Gas	Peaking	--- (C)	---
	4	1965	Combustion-Turbine	Gas	Peaking	--- (C)	---	---

Woodward	1	1963	Combustion-Turbine	Gas	Peaking	--- (B)	9.4	9.4

Total Generating Capability (all stations)								5,660.4

	(A) 2003 Capacity Factor = 2003 Net Actual Generation / (2003 Net Maximum Capacity (Nameplate Rating in MWs) x Period Hours (8,760 Hours)).
	(B) Peaking units, which are used when additional capacity is required, are also necessary to meet the SPP reserve margins.
	(C) These units are currently inactive.

At December 31, 2003, OG&E’s transmission system included: (i) 32 substations with a total capacity of approximately 14.2 million kilo Volt-Amps (“kVA”) and approximately 3,959 structure miles of lines in Oklahoma; and (ii) two substations with a total capacity of approximately 1.5 million kVA and approximately 252 structure miles of lines in Arkansas. OG&E’s distribution system included: (i) 340 substations with a total capacity of approximately 9.3 million kVA, 22,494 structure miles of overhead lines, 1,859 miles of underground conduit and 7,565 miles of underground conductors in Oklahoma; and (ii) 36 substations with a total capacity of approximately 1.4 million kVA, 1,870 structure miles of overhead lines, 224 miles of underground conduit and 442 miles of underground conductors in Arkansas.

At December 31, 2003, Enogex and its subsidiaries owned: (i) approximately 8,000 miles of intrastate gas gathering and transportation pipelines in the states of Oklahoma and Texas; (ii) six operating natural gas processing plants with a total inlet capacity of 678 MMcfd, all located in Oklahoma; (iii) 75 percent interest in NOARK, which consists of approximately 931 miles of interstate gas gathering and transportation pipelines, located in eastern Oklahoma and Arkansas; and (iv) two natural gas storage fields in Oklahoma operating at a working gas level of approximately 24.5 Bcf with an approximate withdrawal capability of 650 MMcfd and similar injection capability.

During the three years ended December 31, 2003, the Company’s gross property, plant and equipment additions were approximately $603.6 million and gross retirements were approximately $244.1 million. These additions were provided by internally generated funds from operating cash flows, short-term borrowings and permanent financings. The additions during this three-year period amounted to approximately 10.6 percent of total property, plant and equipment at December 31, 2003.

Item 3. Legal Proceedings.

In the normal course of business, the Company is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties, environmental actions or the action of various regulatory agencies. Management consults with counsel and other appropriate experts to assess the claim. If in management’s opinion, the Company has incurred a probable loss as set forth by accounting principles generally accepted in the United States, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company’s Consolidated Financial Statements. Except as set forth below, management, after consultation with legal counsel, does not anticipate that liabilities arising out of currently pending or threatened lawsuits and claims will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.

1. The City of Enid, Oklahoma (“Enid”) through its City Council, notified OG&E of its intent to purchase OG&E’s electric distribution facilities for Enid and to terminate OG&E’s franchise to provide electricity within Enid as of June 26, 1998. On August 22, 1997, the City Council of Enid adopted Ordinance No. 97-30, which in essence granted OG&E a new 25-year franchise subject to approval of the electorate of Enid on November 18, 1997. In October 1997, 18 residents of Enid filed a lawsuit against Enid, OG&E and others in the District Court of

Garfield County, State of Oklahoma, Case No. CJ-97-829-01. Plaintiffs seek a declaration holding that (i) the Mayor of Enid and the City Council breached their fiduciary duty to the public and violated Article 10, Section 17 of the Oklahoma Constitution by allegedly “gifting” to OG&E the option the city held to acquire OG&E’s electric system when the City Council approved the new franchise by Ordinance No. 97-30; (ii) the subsequent approval of the new franchise by the electorate of the City of Enid at the November 18, 1997, franchise election cannot cure the alleged breach of fiduciary duty or the alleged constitutional violation; (iii) violations of the Oklahoma Open Meetings Act occurred and that such violations render the resolution approving Ordinance No. 97-30 invalid; (iv) OG&E’s support of the Enid Citizens’ Against the Government Takeover was improper; (v) OG&E has violated the favored nations clause of the existing franchise; and (vi) the City of Enid and OG&E have violated the competitive bidding requirements found at 11 O.S. 35-201, et seq. Plaintiffs seek money damages against the Defendants under 62 O.S. 372 and 373. Plaintiffs allege that the action of the City Council in approving the proposed franchise allowed the option to purchase OG&E’s property to be transferred to OG&E for inadequate consideration. Plaintiffs demand judgment for treble the value of the property allegedly wrongfully transferred to OG&E. On October 28, 1997, another resident filed a similar lawsuit against OG&E, Enid and the Garfield County Election Board in the District Court of Garfield County, State of Oklahoma, Case No. CJ-97-852-01. However, Case No. CJ-97-852-01 was dismissed without prejudice in December 1997. On December 8, 1997, OG&E filed a Motion to Dismiss Case No. CJ-97-829-01 for failure to state claims upon which relief may be granted. This motion is currently pending. While the Company cannot predict the precise outcome of this proceeding, the Company believes at the present time that this lawsuit is without merit and intends to vigorously defend this case.

2. United States of America ex rel., Jack J. Grynberg v. Enogex Inc., Enogex Services Corporation and OG&E. (United States District Court for the Western District of Oklahoma, Case No. CIV-97-1010-L.) United States of America ex rel., Jack J. Grynberg v. Transok Inc. et al. (United States District Court for the Eastern District of Louisiana, Case No. 97-2089; United States District Court for the Western District of Oklahoma, Case No. 97-1009M.). On June 15, 1999, the Company was served with Plaintiff’s complaint, which is a qui tam action under the False Claims Act. Plaintiff Jack J. Grynberg, as individual relator on behalf of the United States Government, alleges: (i) each of the named defendants have improperly or intentionally mismeasured gas (both volume and Btu content) purchased from federal and Indian lands which have resulted in the under-reporting and underpayment of gas royalties owed to the Federal Government; (ii) certain provisions generally found in gas purchase contracts are improper; (iii) transactions by affiliated companies are not arms-length; (iv) excess processing cost deduction; and (v) failure to account for production separated out as a result of gas processing. Grynberg seeks the following damages: (a) additional royalties which he claims should have been paid to the Federal Government, some percentage of which Grynberg, as relator, may be entitled to recover; (b) treble damages; (c) civil penalties; (d) an order requiring defendants to measure the way Grynberg contends is the better way to do so; and (e) interest, costs and attorneys’ fees.

In qui tam actions, the United States Government can intervene and take over such actions from the relator. The Department of Justice, on behalf of the United States Government, decided not to intervene in this action.

Plaintiff filed over 70 other cases naming over 300 other defendants in various Federal Courts across the country containing nearly identical allegations. The Multidistrict Litigation Panel entered its order in late 1999 transferring and consolidating for pretrial purposes approximately 76 other similar actions filed in nine other Federal Courts. The consolidated cases are now before the United States District Court for the District of Wyoming.

In October 2002, the Court granted the Department of Justice’s motion to dismiss certain of Plaintiff’s claims and issued an order dismissing Plaintiff’s valuation claims against all defendants. Various procedural motions have been filed. Discovery is proceeding on limited jurisdiction issues as ordered by the Court. The deposition of relator Grynberg began in December 2002, and continued during 2003.

The Company intends to vigorously defend this action. Since the case is in the early stages of motions and discovery, the Company is unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to the Company at this time.

3. Will Price (Price I) - On September 24, 1999, various subsidiaries of the Company were served with a class action petition filed in United States District Court, State of Kansas by Quinque Operating Company and other named plaintiffs, alleging mismeasurement of natural gas on non-federal lands. On April 10, 2003 the Court entered an order denying class certification. On May 12, 2003, Plaintiffs (now Will Price, Stixon Petroleum, Inc., Thomas F. Boles and the Cooper Clark Foundation, on behalf of themselves and other royalty interest owners) filed a motion seeking to file an amended petition and the court granted the motion on July 28, 2003. In this amended petition, OG&E and Enogex Inc. were omitted from the case. Two subsidiaries of Enogex remain as defendants. The Plaintiffs’ amended petition alleges that approximately 60 defendants, including two Enogex subsidiaries, have improperly measured natural gas. The amended petition reduces the claims to: (1) mismeasurement of volume only; (2) conspiracy, unjust enrichment and accounting; (3) a putative Plaintiffs’ class of only royalty owners; and (4) gas measured in three specific states. Discovery on class certification is proceeding.

4. Will Price (Price II) - On May 12, 2003, the Plaintiffs (same as those in Price I above) filed a new class action petition (Price II) in the District Court of Stevens County, Kansas, relating to wrongful Btu analysis against natural gas pipeline owners and operators, naming the same defendants as in the amended petition of the Price I case. Two Enogex subsidiaries were served on August 4, 2003. The Plaintiffs seek to represent a class of only royalty owners either from whom the defendants had purchased natural gas or measured natural gas since January 1, 1974 to the present. The class action petition alleges improper analysis of gas heating content. In all other respects, the Price II petition appears to be the same as the amended petition in Price I. Discovery on class certification is proceeding.

5. A Notice of Enforcement Action (“NOE”) by the Texas Natural Resource Conservation Commission (now known as the Texas Commission on Environmental Quality (“TCEQ”)) was issued to Products by letter dated July 26, 2002. The NOE relates to the operation of a sulfur recovery unit owned and operated by Belvan at its Crockett County, Texas natural gas processing facility. The TCEQ’s proposed fine was approximately $0.1 million and Products is working with the current owner of Belvan to properly respond to the TCEQ, since Products sold its interest in Belvan in March 2002. Products has requested the TCEQ to issue the NOE in the permitted entity’s name and is waiting for this correction from the TCEQ. However, Products may retain some liability to the purchaser for any penalties that Belvan might incur from the NOE. Pursuant to the Agreement of Sale and Purchase with the purchaser, Products’ liability for any penalties that Belvan might incur from the NOE should not exceed approximately $0.1 million and this amount is fully reserved on Products books.

6. In 1998, Enogex entered into a storage lease agreement (the “Agreement”) with COOG. Under the Agreement, COOG agreed to make certain enhancements to the Stuart Storage Facility to increase capacity and deliverability of the facility. In 1999 a dispute arose as to whether the natural gas deliverability for the Stuart Storage Facility was being provided by COOG and these issues were submitted to arbitration in October and November 2001. In July 2002, the Oklahoma District Court affirmed the arbitration award and entered judgment against COOG and in favor of Enogex in the amount of approximately $23.3 million (the “Judgment”).

On July 24, 2002, Enogex exercised the asset purchase option provided in the Agreement and title to the Stuart Storage Facility was transferred to Enogex on October 24, 2002, effective August 9, 2002 (the date COOG turned over operations of the facility to Enogex). As part of the Agreement, the Company agreed in 1998 to make up to a $12 million secured loan to Natural Gas Storage Corporation (“NGSC”), an affiliate of COOG (the “NGSC Loan”). Since June 2002, NGSC has failed and refused to repay the NGSC Loan. As of December 31, 2003, the amount outstanding under the NGSC Loan was approximately $8.0 million plus accrued interest.

On August 12, 2002, the Company received a petition in a legal proceeding filed by COOG and NGSC against the Company and Enogex in Texas. COOG and NGSC stated a claim for declaratory judgment asserting, among other things, that NGSC is not obligated to make payments on the NGSC Loan based on various theories and, that: (1) the Company was obligated to demand Enogex make the requisite payments to the Company; (2) the Company is liable to NGSC for failing to demand the requisite payments from Enogex, or alternatively, NGSC is entitled to a reduction in the amount it owes to the Company; (3) Enogex was and is obligated to make the payments to the Company until the indebtedness of NGSC to the Company is reduced to zero; (4) Enogex is not entitled to set off the Judgment against the lease payments that it originally owed to COOG and now owes to the Company; (5) no event of default has occurred; and (6) under the Agreement, the only remedy Enogex had or has if the Stuart Storage Facility did not perform was to seek a modification of the lease payments based upon COOG’s expert’s

analysis of the performance of the Stuart Storage Facility. COOG and NGSC have also stated claims for breach of contract relating to the same allegations in its claim for declaratory relief and include claims for attorneys’ fees.

The Company objected to being sued in Texas because the Texas Court does not have proper jurisdiction over the Company. On September 24, 2002, Enogex filed an answer in response to the allegations, asserting, among other things, that the disputed issues have already been properly determined by the Arbitration Panel and the Oklahoma Court and, therefore, this action is improper.

On February 27, 2003, Enogex sent its arbitration demand to plaintiffs (COOG and NGSC) regarding the issues between plaintiffs and Enogex in the Texas action, and Enogex named its arbitrator. On February 28, 2003, Enogex filed a motion to dismiss, or in the alternative, to abate, stay and compel arbitration in the Texas action. By Order dated June 19, 2003, the Court granted Enogex’s request for arbitration and ordered COOG/NGSC and Enogex to arbitration on all issues and claims arising under the Agreement and/or the asset purchase option, including all issues overlapping with the loan agreement and related documents. The Texas action is stayed in its entirety pending arbitration. Under the arbitration provisions in the Agreement, a final arbitration decision is to be rendered by June 30, 2004.

On July 16, 2003, the Company and Enogex served separate complaints on the individual shareholders of COOG and NGSC – Enogex Inc. v John C. Thrash, John F. Thrash and Robert R. Voorhees, Jr., Case No. CIV-03-0388-L; and OGE Energy Corp. and Enogex Inc. v John C. Thrash, John F. Thrash and Robert R. Voorhees, Jr., Case No. CIV 03-0389-L – both filed in the Western District of Oklahoma Federal Court. The Company and Enogex have each stated claims for (1) fraudulent transfer; (2) imposition of an equitable trust; and (3) breach of fiduciary duty.

The Company intends to continue to vigorously pursue its rights in conjunction with the remaining amount owed under the Judgment, plus interest, and the Company and Enogex seek to recover the amount owed under the NGSC Loan, plus interest.

7. Farmland Industries, Inc. (“Farmland”) voluntarily filed for Chapter 11 bankruptcy protection from creditors on May 31, 2002. Enogex provided gas transportation and supply services to Farmland, and is an unsecured creditor of Farmland. Enogex filed its Proof of Claim on January 7, 2003, for approximately $5.4 million. In April 2003, Enogex negotiated a settlement and received approximately $1.9 million in May 2003.

On July 31, 2003, Farmland filed its Disclosure Statement for its Reorganization Plan for approval by the bankruptcy court. According to the Disclosure Statement, Farmland proposes to pay its general unsecured creditors an amount between 60 percent and 82 percent on their pre-petition claims. As a general unsecured creditor of Farmland and pursuant to the terms of the Settlement Agreement referenced above, Enogex’s recovery under the proposed distribution would be approximately $0.8 million, which is in addition to the $1.9 million Enogex received in May 2003.

8. On October 17, 2002, the City of Jenks, Oklahoma filed a petition in state district court in Tulsa County, Oklahoma against Enogex Inc. seeking damages associated with Enogex’s alleged failure to remit a gross receipts tax to the city relating to natural gas sold to an IPP, Green Country Energy, LLC (“Green Country”) within the city limits. Based on this claim, the city alleged damages “in excess of $10,000.” The city claimed that some of Enogex’s pipelines are located within the city’s public rights of way, and therefore, based on city ordinance, any sale of natural gas by Enogex to Green Country is subject to a two percent gross receipts tax. The city made an identical claim against two other defendants, Green Country and Exelon Generation Company, LLC, (“Exelon”) as the “supplier” of natural gas to Green Country. The city also sought interest on the amount in controversy, as well as its court costs and attorneys’ fees. Additionally, the city asserted other claims against Exelon and Green Country pursuant to two other city ordinances. On December 2, 2002, Enogex and the other defendants filed answers denying plaintiff’s claims.

On May 8, 2003, the city and Green Country filed a joint motion to approve a settlement. On May 9, 2003, the court entered an order approving the settlement, whereby Green Country agreed to pay the city $3.0 million in lieu of any other taxes or fees that may be assessed by the city for the next 35 years. The claims asserted by the city against Green Country were all dismissed. The city also dismissed the claims against Exelon that were asserted against Green Country. The remaining claim asserted against Enogex and Exelon related to the gross receipts tax was not dismissed; however, Enogex’s position is that the settlement between Green Country and the city effectively resolved the gross receipts tax issue. Nonetheless, Enogex cannot guarantee that the city will not continue to pursue the gross receipts tax matter, or other similar matters, against Enogex.

9. In 2000, Enogex entered into long-term firm transportation contracts with an IPP relating to a plant to be built in Wagoner County, Oklahoma. Effective July 1, 2000, the contracts were assigned to Calpine Energy Services, L.P. (“Calpine Energy”). In February 2002, Enogex requested a prepayment from Calpine Energy due to Calpine falling below the contractual creditworthiness criteria. Calpine Energy refused to pay the full monthly demand fees and also refused to make any prepayments as requested. Enogex also made a demand on Calpine Corporation, as guarantor, relating to Calpine Energy’s failure to make the required prepayment and demand payments.

In September 2002, Calpine Energy and Calpine Corporation filed a lawsuit against Enogex in connection with this matter. After participating in a court ordered mediation on August 18, 2003, the parties reached a settlement of the pending issues on September 29, 2003. The terms of the settlement obligated Calpine Energy to make a nonrefundable payment to Enogex in the amount of $3.0 million and to maintain a prepayment. Enogex agreed to apply a credit of $1.0 million to the final two months’ demand charges under the transportation contract. On October 14, 2003, Enogex received payment of the settlement amount from Calpine Energy. As a result of this settlement, the Company recorded $2.0 million of the settlement payment as revenue in the third quarter of 2003 and this matter is now considered closed.

10. OG&E has been sued by Kaiser-Francis Oil Company in District Court, Blaine County, Oklahoma. This case has been pending for more than 10 years. Plaintiff alleges that OG&E breached the terms of numerous contracts covering approximately 60 wells by failing to

purchase gas from Plaintiff in amounts set forth in the contracts. Plaintiff seeks $20.0 million in take-or-pay damages and $1.8 million in underpayment damages. Over the objection and unsuccessful appeal by OG&E, Plaintiff has been permitted to amend its petition to include a claim based on theories of tort. Specifically, Plaintiff alleges, among other things, that OG&E intentionally and tortuously interfered with contracts by falsifying documents, sponsoring false testimony and putting forward legal defenses, which are known by OG&E to be without merit. If successful, Plaintiff believes that these theories could give Plaintiff a basis to seek punitive damages. OG&E believes that, to the extent Plaintiff were successful on the merits of its claims of OG&E’s failure to take gas, these amounts would be recoverable through its regulated electric rates. The claims related to tortuous conduct, which OG&E believes at this time are without merit, would not appear to be properly recoverable in its rates. This lawsuit has been stayed pending the outcome of an appeal that OG&E filed in a similar case brought by Kaiser-Francis in Grady County. In the Grady case, OG&E is appealing a verdict against it in the amount of approximately $8.0 million, including pre-judgment interest and attorneys’ fees. While the Company cannot predict the precise outcome of the Grady case or this lawsuit, the Company believes, based on the information known at this time, that this lawsuit will not have a material adverse effect on the Company’s consolidated financial position or results of operations.

11. Beginning in 2000, the Company began a process to evaluate, determine and report emissions from its pipeline facilities for compliance with recently promulgated maximum achievable control technology regulations. After evaluating the submitted information, the ODEQ, beginning in late 2001, issued notices of violation regarding potential air permitting issues at certain of these reported facilities. Generally, the notices alleged violations relating to potential sources to emit various emissions, with the majority of the sources relating to glycol dehydrators. As previously reported, all but two of the notices were resolved in 2001 and 2002. Enogex has worked with the ODEQ regarding the two remaining notices, the Clinton Gas Plant and the Strong City Compressor Station, as well as two additional notices relating to air permitting issues that were issued by the ODEQ in November 2002 and January 2003, respectively, relating to the Cox City Compressor Station and the Comanche Tap Gas Plant. Enogex has resolved all four of these notices and agreed to pay, in the aggregate, less than $0.1 million in settlement, which included monies for supplemental environmental projects, penalties and certain remediation efforts.

12. On July 31, 2003, representatives of Enogex met with the FERC Staff to discuss resolution of a pending matter that Enogex discovered and brought to the FERC’s attention in November 2002 relating to construction by Ozark under its blanket certificate and Enogex under Section 311 authorization. The matter disclosed to the FERC relates to minor construction in 1998 and 1999 that was performed under the reasonable belief that the facilities constituted non-jurisdictional gathering. Accordingly, pre-construction environmental clearances for the FERC-jurisdictional facilities were not obtained and the construction was not reported on blanket certificate and Section 311 construction reports. Upon review, Enogex and Ozark determined that two construction projects should have been treated as FERC-jurisdictional transmission, one under Ozark’s blanket certificate and the other pursuant to Enogex’s Section 311 authorization. Enogex and Ozark self-reported the non-compliant activities and have cooperated with the FERC’s investigation. By order issued December 19, 2003, FERC approved separate consent agreements entered into between FERC and Enogex and Ozark, respectively. Enogex paid a

civil penalty of $80,000, with the additional amount of $15,000 to be suspended if Enogex completes an outreach program informing other industry companies about procedures for obtaining pre-clearance for construction of certain facilities. Ozark paid $20,000 to the FERC to defray the Commission’s costs of investigating Ozark’s possible violation. This matter is now considered closed.

Item 4. Submission of Matters to a Vote of Security Holders.

None

Executive Officers of the Registrant.

The following persons were Executive Officers of the Registrant as of January 31, 2004:

Name	Age	Title
Steven E. Moore	57	Chairman of the Board, President and Chief Executive Officer
Al M. Strecker	60	Executive Vice President and Chief Operating Officer
Peter B. Delaney	50	Executive Vice President, Finance and Strategic Planning - OGE Energy Corp. and Chief Executive Officer - Enogex Inc.
James R. Hatfield	46	Senior Vice President and Chief Financial Officer
Jack T. Coffman	60	Senior Vice President - Power Supply - OG&E
Steven R. Gerdes	47	Vice President - Utility Operations and Shared Services
Michael G. Davis	54	Vice President - Business Systems and Services
Donald R. Rowlett	46	Vice President and Controller
Deborah S. Fleming	48	Treasurer
Gary D. Huneryager	53	Internal Audit Officer
Carla D. Brockman	44	Corporate Secretary

No family relationship exists between any of the Executive Officers of the Registrant. Messrs. Moore, Strecker, Hatfield, Gerdes, Davis, Rowlett and Huneryager, Ms. Fleming and Ms. Brockman are also officers of OG&E. Each Officer is to hold office until the Board of Directors meeting following the next Annual Meeting of Stockholders, currently scheduled for May 20, 2004.

The business experience of each of the Executive Officers of the Registrant for the past five years is as follows:

Name

Business Experience

Steven E. Moore	1999 - Present:	Chairman of the Board, President and Chief Executive Officer
Al M. Strecker	1999 - Present:	Executive Vice President and Chief Operating Officer
Peter B. Delaney	2002 - Present:	Executive Vice President, Finance and Strategic Planning - OGE Energy Corp. and Chief Executive Officer - Enogex Inc.
	2001 - 2002:	Principal, PD Energy Advisors (consulting firm)
	1999 - 2001:	Managing Director, UBS Warburg (investment banking firm)
James R. Hatfield	2000 - Present:	Senior Vice President and Chief Financial Officer
	1999 - 2000:	Senior Vice President, Chief Financial Officer and Treasurer
Jack T. Coffman	1999 - Present:	Senior Vice President - Power Supply - OG&E
Steven R. Gerdes	2003 - Present:	Vice President - Utility Operations and Shared Services
	1999 - 2003:	Vice President - Shared Services
Michael G. Davis	2004 - Present	Vice President - Business Systems and Services
	2002 - 2003:	Vice President - Process Management - OG&E
	1999 - 2002:	Vice President - Marketing and Customer Care - OG&E
Donald R. Rowlett	1999 - Present:	Vice President and Controller

Deborah S. Fleming	2003 - Present:	Treasurer
	2000 - 2003:	Assistant Treasurer - Williams Cos. Inc.
	1999 - 2000:	Director of Corporate Finance - Williams Cos. Inc. (energy company)
Gary D. Huneryager	2002 - Present:	Internal Audit Officer
	2001 - 2002:	Assistant Internal Audit Officer
	1999 - 2001:	Service Line Director (Business Process Outsourcing) - Arthur Andersen LLP
Carla D. Brockman	2002 - Present:	Corporate Secretary
	2002:	Assistant Corporate Secretary
	1999 - 2002:	Client Manager - Strategic Planning

PART II

Item 5. Market for Registrant’s Common Equity and Related
Stockholder Matters.

The Company’s Common Stock is listed for trading on the New York and Pacific Stock Exchanges under the ticker symbol “OGE.” Quotes may be obtained in daily newspapers where the common stock is listed as “OGE Engy” in the New York Stock Exchange listing table. The following table gives information with respect to price ranges, as reported in The Wall Street Journal as New York Stock Exchange Composite Transactions, and dividends paid for the periods shown.


		Dividend					Price
2002		Paid			High			Low

First Quarter	$	0.332	5	$	24.1	2	$	21.2	8
Second Quarter		0.332	5		24.2	4		21.8	2
Third Quarter		0.332	5		23.2	9		16.1	3
Fourth Quarter		0.332	5		18.3	4		13.7	0


		Dividend					Price
2003		Paid			High			Low

First Quarter	$	0.332	5	$	19.3	7	$	15.9	9
Second Quarter		0.332	5		22.2	5		17.3	6
Third Quarter		0.332	5		22.7	5		19.5	0
Fourth Quarter		0.332	5		24.3	4		21.9	6


		Dividend				Price
2004		Paid		High			Low

First Quarter (through January 31)	$	0.332	5	24.5	0		23.0	3

The number of record holders of the Company’s Common Stock at January 31, 2004, was 31,932. The book value of the Company’s Common Stock at January 31, 2004, was $13.81.

Dividend Restrictions

Before the Company can pay any dividends on its common stock, the holders of any of its preferred stock that may be outstanding are entitled to receive their dividends at the respective rates as may be provided for the shares of their series. Currently, there are no shares of preferred stock of the Company outstanding. In addition, the Company may not, except in limited circumstances, declare or pay dividends on its common stock if it has deferred payment of interest on the junior subordinated debentures that were issued in connection with the trust originated preferred securities issued and sold by its subsidiary trust, OGE Energy Capital Trust I. Because the Company is a holding company and conducts all of its operations through

its subsidiaries, the Company’s cash flow and ability to pay dividends will be dependent on the earnings and cash flows of its subsidiaries and the distribution or other payment of those earnings to the Company in the form of dividends, or in the form of repayments of loans or advances to it. The Company expects to derive principally all of the funds required by it to enable it to pay dividends on its common stock from dividends paid by OG&E, on OG&E’s common stock. The Company’s ability to receive dividends on OG&E’s common stock is subject to the prior rights of the holders of any OG&E preferred stock that may be outstanding and the covenants of OG&E’s certificate of incorporation and its debt instruments limiting the ability of OG&E to pay dividends.

Under OG&E’s certificate of incorporation, if any shares of its preferred stock are outstanding, dividends (other than dividends payable in common stock), distributions or acquisitions of OG&E common stock:

may not exceed 50 percent of net income for a prior 12-month period, after deducting dividends on any preferred stock during the period, if the sum of the capital represented by the common stock, premiums on capital stock (restricted to premiums on common stock only by SEC orders), and surplus accounts is less than 20 percent of capitalization;
may not exceed 75 percent of net income for such 12-month period, as adjusted if this capitalization ratio is 20 percent or more, but less than 25 percent; and
if this capitalization ratio exceeds 25 percent, dividends, distributions or acquisitions may not reduce the ratio to less than 25 percent except to the extent permitted by the provisions described in the above two bullet points.

Currently, no shares of OG&E preferred stock are outstanding and no portion of the retained earnings of OG&E is presently restricted by this provision. OG&E’s certificate of incorporation further provides that no dividend may be declared or paid on the OG&E common stock until all amounts required to be paid or set aside for any sinking fund for the redemption or purchase of OG&E cumulative preferred stock, par value $25 per share, have been paid or set aside.

Item 6. Selected Financial Data.

HISTORICAL DATA

		2003			2002			2001			2000			1999

SELECTED FINANCIAL DATA
(In millions, except per share data)

Operating revenues	$	3,779	.0	$	3,023	.9	$	3,064	.4	$	3,184	.4	$	2,106	.7
Cost of goods sold		2,846	.0		2,120	.3		2,185	.6		2,275	.3		1,260	.5

Gross margin on revenues		933	.0		903	.6		878	.8		909	.1		846	.2
Other operating expenses		626	.1		667	.9		607	.9		574	.5		521	.4

Operating income		306	.9		235	.7		270	.9		334	.6		324	.8
Other income		8	.1		3	.7		3	.1		4	.2		2	.7
Other expense		9	.0		4	.7		4	.2		3	.6		2	.7
Net interest expense		96	.7		109	.1		123	.0		129	.4		97	.5
Income tax expense		73	.7		44	.6		52	.9		72	.0		87	.3

Income from continuing
operations		135	.6		81	.0		93	.9		133	.8		140	.0
Income (loss) from discontinued
operations, net of tax		(0	.4)		9	.8		6	.7		13	.2		11	.3
Cumulative effect on prior years
of change in accounting
principle, net of tax of $3.4		(5	.4)		--			--			--			--

Net income	$	129	.8	$	90	.8	$	100	.6	$	147	.0	$	151	.3

Basic earnings (loss) per average
common share
Income from continuing
operations	$	1.6	6	$	1.0	4	$	1.2	0	$	1.7	2	$	1.8	0
Income from discontinued
operations, net of tax		--	-		0.1	2		0.0	9		0.1	7		0.1	4
Loss from cumulative effect of
accounting change, net of tax		(0.0	7)		--	-		--	-		--	-		--	-

Net income	$	1.5	9	$	1.1	6	$	1.2	9	$	1.8	9	$	1.9	4

Diluted earnings (loss) per average
common share
Income from continuing
operations	$	1.6	5	$	1.0	4	$	1.2	0	$	1.7	2	$	1.8	0
Income from discontinued
operations, net of tax		--	-		0.1	2		0.0	9		0.1	7		0.1	4
Loss from cumulative effect of
accounting change, net of tax		(0.0	7)		--	-		--	-		--	-		--	-

Net income	$	1.5	8	$	1.1	6	$	1.2	9	$	1.8	9	$	1.9	4

Dividends declared per share	$	1.3	3	$	1.3	3	$	1.3	3	$	1.3	3	$	1.3	3

HISTORICAL DATA (Continued)

		2003			2002			2001			2000			1999

SELECTED FINANCIAL DATA
(In millions, except per share data)
Long-term debt	$	1,436	.1	$	1,501	.9	$	1,526	.3	$	1,648	.5	$	1,140	.5
Total assets	$	4,584	.7	$	4,264	.9	$	4,118	.0	$	4,444	.6	$	4,043	.0
CAPITALIZATION RATIOS (A)
Stockholders’ equity		45.56	%		39.58	%		40.54	%		39.23	%		47.20	%
Long-term debt		54.44	%		60.42	%		59.46	%		60.77	%		52.80	%
RATIO OF EARNINGS TO
FIXED CHARGES (B)
Ratio of earnings to fixed charges		3.0	6		2.0	8		2.1	0		2.4	5		3.1	2

(A)

Capitalization ratios = [Stockholders’ equity / (Stockholders’ equity + Long-term debt)] and [Long-term debt / (Stockholders’ equity + Long-term debt)].

(B)

For purposes of computing the ratio of earnings to fixed charges, (1) earnings consist of income from continuing operations plus fixed charges, federal and state income taxes, deferred income taxes and investment tax credits (net); and (2) fixed charges consist of interest on long-term debt, related amortization, interest on short-term borrowings and a calculated portion of rents considered to be interest.

Item 7. Management’s Discussion and Analysis of Financial Condition and
and Results of Operations.

Introduction

The operations of the Natural Gas Pipeline segment are conducted through Enogex Inc. and its subsidiaries (“Enogex”) and consist 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, “Enogex’s businesses”). Enogex’s focus is to utilize its gathering, processing, transportation and storage capacity to execute physical, financial and service transactions to capture revenues across different commodities, locations or time periods. 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, 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 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 in the first quarter of 2003 and are reported in the Consolidated Financial Statements as discontinued operations.

Company Strategy

In the near term, OG&E plans on increasing its investment and growing earnings largely through the acquisition of electric generation (“New Generation”). As discussed in more detail below, in August 2003, OG&E signed an asset purchase agreement to acquire NRG McClain LLC’s 77 percent interest in the 520 megawatt (“MW”) NRG McClain Station (the “McClain Plant”). In December 2003, the FERC delayed approval of the acquisition citing market power concerns. On January 15, 2004, the FERC administrative law judge in charge of the hearing and the parties to the case agreed to a procedural schedule that would produce a decision on the McClain Plant acquisition no sooner than the third quarter of 2004. OG&E subsequently withdrew its request before the OCC to increase its rates by approximately $91 million annually to cover the costs of the acquisition. Despite the delay at the FERC, an agreement to purchase power from the McClain Plant is enabling OG&E to honor the customer savings as outlined in the agreed settlement of OG&E’s rate case (the “Settlement Agreement”). The Company will continue to monitor the FERC’s recent shift in policy regarding market power issues around the McClain Plant acquisition to determine the practicability of future power plant purchases in addition to purchased power contracts. See “Overview – Pending Acquisition of Power Plant” for a further discussion including a potential $2.1 million per month rate reduction. OG&E also plans to increase its capital expenditures in the foreseeable future for electric system reliability upgrades which is consistent with our commitment to our Customer Savings and Reliability Plan outlined in OG&E’s rate case filed with the OCC on October 31, 2003.

OG&E currently has contracts with qualified cogeneration facilities and small power production producers’ (“QF contracts”) for the purchase of 540 MWs, all of which expire in the next one to five years. The Company will continue reviewing all of the supply alternatives to replace expiring QF contracts that minimize the total cost of generation to our customers. Accordingly, OG&E will continue to explore opportunities to build or buy power plants in order to serve its native load. As a result of the high volatility of current natural gas prices and the

increase in natural gas prices, OG&E will also assess the feasibility of constructing additional base load coal-fired units.

Enogex initiated a program in 2002 to improve its financial profile and performance. Since January 1, 2002, Enogex has sold assets and received net sales proceeds of approximately $101.3 million, reduced debt by approximately $164.9 million or 22 percent, reduced its number of employees by approximately 12 percent, reorganized its operations and restructured its senior management team. In addition to focusing on growing its earnings, Enogex managed its commodity price and earnings volatility exposures and minimized its exposure to keep whole processing arrangements. Enogex’s profitability increased significantly in 2003 due to the performance improvement plan initiated in 2002. While the Company believes substantial progress has been achieved, additional opportunities remain. Enogex continues to review its work processes, evaluate the rationalization of assets, negotiate better terms for both new contracts and replacement contracts, manage costs and pursue opportunities for organic growth, all in an effort to further improve its cash flow and net income.

Other efforts at Enogex during 2003 included improvements to its two storage fields. The repair project at the Wetumka Storage Facility (formerly known as Greasy Creek) was designed to mitigate potential gas migration, and the remediation program at the Stuart Storage Facility (once completed) is intended to prevent water encroachment in the field. During 2003, approximately $0.5 million was spent and expensed on the Wetumka Storage Facility project and approximately $2.4 million in capital expenditures was spent on the Stuart Storage Facility project; the Company expects no material future expenditures at the Wetumka Storage Facility and expenditures of less than $1.5 million for the Stuart Storage Facility.

Forward-Looking Statements

Except for the historical statements contained herein, the matters discussed in the following discussion and analysis, including the discussion in “2004 Outlook”, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate”, “believe”, “estimate”, “expect”, “intend”, “objective”, “plan”, “possible”, “potential” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit, actions of ratings agencies and their impact on capital expenditures; the Company’s ability and the ability of its subsidiaries to obtain financing on favorable terms; prices of electricity, natural gas and natural gas liquids, each on a stand-alone basis and in relation to each other; business conditions in the energy industry; competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company; unusual

weather; state and federal legislative and regulatory decisions and initiatives; changes in accounting standards, rules or guidelines; creditworthiness of suppliers, customers, and other contractual parties; completion of the pending acquisition of a power plant; an adverse decision by the OCC requiring OG&E to reduce its rates and the other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission.

Overview

General

The following discussion and analysis presents factors which affected the Company’s consolidated results of operations for the years ended December 31, 2003, 2002 and 2001 and the Company’s consolidated financial position at December 31, 2003 and 2002. The following information should be read in conjunction with the Consolidated Financial Statements and Notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.

Enogex previously was engaged in the exploration and production of natural gas (the “E&P business”). Since January 1, 2002, Enogex has sold all of its E&P business along with certain gas gathering and processing assets that were owned by Enogex through its interest in the NuStar Joint Venture (“NuStar”) and its interest in Belvan Corp., Belvan Limited Partnership and Todd Ranch Limited Partnership (“Belvan”). As required by accounting principles generally accepted in the United States, these dispositions have been reported as discontinued operations for the years ended December 31, 2003, 2002 and 2001 in the Consolidated Financial Statements.

Operating Results

2003 compared to 2002. The Company reported net income of approximately $129.8 million, or $1.58 per diluted share, and $90.8 million, or $1.16 per diluted share, for the years ended December 31, 2003 and 2002, respectively. The increase in net income during 2003 as compared to 2002 was primarily due to lower impairment charges and higher gross margin on revenues (“gross margin”) in all of Enogex’s businesses and lower interest expenses at the holding company. These increases were partially offset by lower earnings at OG&E. The Company’s results of operations for the years ended December 31, 2003 and 2002 include a loss of approximately $0.4 million, or $0.00 per diluted share, and income of approximately $9.8 million, or $0.12 per diluted share, respectively, from the discontinued operations discussed above. See “Results of Operations – Enogex – Discontinued Operations” below for a further discussion.

OG&E reported net income of approximately $115.4 million, or $1.41 per diluted share, and $126.1 million, or $1.61 per diluted share, for the years ended December 31, 2003 and 2002, respectively. The decrease in net income during 2003 as compared to 2002 was primarily attributable to lower electric rates as a result of the $25 million electric rate reduction that went into effect in Oklahoma on January 6, 2003, weaker weather-related demand and higher

operating and maintenance expenses partially offset by customer growth in OG&E’s service territory.

Enogex’s operations, including discontinued operations, reported net income of approximately $26.9 million, or $0.33 per diluted share, for the year ended December 31, 2003 as compared to a net loss of approximately $21.7 million, or $0.28 per diluted share, for the year ended December 31, 2002. This improvement during 2003 as compared to 2002 was primarily attributable to lower impairment charges and higher gross margins in all of Enogex’s businesses from, among other things, improved management of pipeline system fuel, increased levels of firm transportation revenues, improved processing results and the negotiation of both new contracts and replacement contracts at better terms that resulted in increases in gathering fees and reductions in the purchase price of gas. Also contributing to Enogex’s improvement were gains from asset sales, lower net interest expense and lower operating and maintenance expenses.

As stated above, Enogex’s E&P business, its interest in NuStar and its interest in Belvan have been reported as discontinued operations for the years ended December 31, 2003, 2002 and 2001 in the Consolidated Financial Statements as these assets have been sold. The Company’s results of operations for the years ended December 31, 2003 and 2002 include a loss of approximately $0.4 million, or $0.00 per diluted share, and income of approximately $9.8 million, or $0.12 per diluted share, respectively, from the discontinued operations discussed above. This decrease was attributable to the sale of Enogex’s E&P business, NuStar and Belvan during 2002 and in the first quarter of 2003, higher income tax expense due to tax credits from Enogex’s E&P business not being realized as a result of a tax accounting method change and recording an additional charge related to the sale of NuStar during the third quarter of 2003. See “Results of Operations – Enogex – Discontinued Operations” below for a further discussion.

The results of the holding company reflect a loss of $0.16 per diluted share and a loss of $0.17 per diluted share for the years ended December 31, 2003 and 2002, respectively. The improvement is primarily due to lower interest charges and a higher income tax benefit partially offset by higher other miscellaneous expenses.

2002 compared to 2001. The Company reported net income of approximately $90.8 million, or $1.16 per share, and $100.6 million, or $1.29 per share, for the years ended December 31, 2002 and 2001, respectively. The decrease in net income during 2002 as compared to 2001 was primarily due to impairment losses of $0.39 per share in the fourth quarter of 2002 for Enogex and the Company. Excluding impairment charges, the Company’s earnings in 2002 would have been $1.55 per share compared to $1.34 per share in 2001, when the Company reported a $0.05 per share impairment charge. The Company’s results of operations for the years ended December 31, 2002 and 2001 include income of approximately $9.8 million, or $0.12 per share, and income of approximately $6.7 million, or $0.09 per share, respectively, from the discontinued operations discussed above. See “Results of Operations – Enogex – Discontinued Operations” below for a further discussion.

OG&E reported net income of approximately $126.1 million, or $1.61 per share, and $121.2 million, or $1.55 per share, for the years ended December 31, 2002 and 2001, respectively. The increase in net income during 2002 as compared to 2001 is primarily

attributable to lower operating and maintenance expenses, lower interest expenses and increased growth in OG&E’s service territory partially offset by lower levels of natural gas transportation cost recovered, lower recoveries of fuel costs from Arkansas customers, loss of revenue resulting from the January 2002 ice storm, lower sales to other utilities and power marketers (“off-system sales”), milder weather and higher depreciation expense.

Enogex’s operations, including discontinued operations, reported a net loss of approximately $21.7 million, or $0.28 per share, and a loss of $5.0 million, or $0.06 per share, for the years ended December 31, 2002 and 2001, respectively. The reduced earnings during 2002 as compared to 2001 were primarily attributable to impairment losses of $0.38 per share in the fourth quarter of 2002 related to the disposition of natural gas processing plants and compression assets that were no longer needed in Enogex’s business. Absent impairment charges in 2002 and 2001 and including discontinued operations, Enogex would have earned $0.10 per share in 2002 compared with a loss of $0.01 per share in 2001. This improvement was primarily from the transportation and storage business as a result of additional firm revenues from new long-term contracts to merchant electric generation facilities and increased storage revenues. Additionally, better fuel recoveries and lower interest expense contributed to the improvement and were only partially offset by lower volumes in gathering and processing.

As stated above, Enogex’s E&P business, its interest in NuStar and its interest in Belvan have been reported as discontinued operations for the years ended December 31, 2003, 2002 and 2001 in the Consolidated Financial Statements as these assets have been sold. The Company’s results of operations for the years ended December 31, 2002 and 2001 include income of approximately $9.8 million, or $0.12 per share, and income of approximately $6.7 million, or $0.09 per share, respectively. The increase was primarily related to a higher gross margin on natural gas liquids sales, an impairment charge recorded in 2001 for Belvan, net gains on the sale of certain of these assets in 2002, lower depreciation expense and lower operating and maintenance expenses partially offset by a lower gross margin on natural gas sales. See “Results of Operations – Enogex – Discontinued Operations” below for a further discussion.

The results of the holding company reflect a loss of $0.17 per share and a loss of $0.20 per share for the years ended December 31, 2002 and 2001, respectively. The reduced loss was primarily attributable to lower interest expenses partially offset by a lower income tax benefit and an impairment loss in the fourth quarter of 2002 related to the Company’s aircraft.

2002 Settlement Agreement

$5.4 million in deferred operating costs, associated with the January 2002 ice storm, through OG&E’s rider for off-system sales. Previously, OG&E had a 50/50 sharing mechanism in Oklahoma for any off-system sales. The Settlement Agreement provided that the first $1.8 million in annual net profits from 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.

Pending Acquisition of Power Plant

As part of the 2002 Settlement Agreement with the OCC, OG&E undertook to acquire New Generation of not less than 400 MWs. The acquisition of a 77 percent interest in the McClain Plant would clearly constitute an acquisition of such New Generation under the Settlement Agreement. OG&E expects this New Generation, including the interim purchase power agreement, will provide savings, over a three-year period, in excess of $75.0 million to its Oklahoma customers. These savings will be derived from: (i) the avoidance of purchase power contracts otherwise needed; (ii) replacing an above market cogeneration contract with PowerSmith Cogeneration Project, L.P. (“PowerSmith”) when it can be terminated at the end of August 2004; and (iii) fuel savings associated with operating efficiencies of the new plant. These savings, while providing real savings to Oklahoma customers, are not expected to affect the profitability of OG&E because OG&E’s rates would not need to be reduced to accomplish these savings. As indicated in the Settlement Agreement, OG&E is required to provide monthly reports, for a period of 36 months after the acquisition, to the OCC Staff, documenting and providing proof of savings experienced by OG&E’s customers. 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 Oklahoma customers any unrealized savings below $75.0 million as determined at the end of the 36-month period, which shall be no later than December 31, 2006. PowerSmith has filed an application with the OCC seeking to compel OG&E to continue purchasing power from PowerSmith’s qualified cogeneration facility under the Public Utility Regulatory Policy Act of 1978 (“PURPA”) at a price that would include an avoided capacity charge equal to the lesser of (i) the rate currently specified in the power purchase agreement between OG&E and PowerSmith or (ii) the avoided cost of the McClain Plant. OG&E does not believe that this matter should be heard at the OCC at this time and that the avoided cost requested by PowerSmith is too high. In the event PowerSmith is ultimately successful and OG&E is required to sign a purchase power agreement, it could negatively affect OG&E’s ability to achieve the targeted $75 million three-year customer savings under the existing terms of the Settlement Agreement. PowerSmith and OG&E have been holding discussions to determine if mutually agreeable terms can be reached for a power contract between the companies providing for capacity payments to the PowerSmith facility.

customers will terminate in the first month that the New Generation begins initial operations and any previously-credited amounts to Oklahoma customers will be deducted in the determination of the $75.0 million targeted savings.

Closing is subject to customary conditions including receipt of regulatory approval by the FERC. The asset purchase agreement, as amended, provides that, unless extended, either party has the right to terminate the contract if the closing does not occur on or before March 16, 2004. Because the current owner of the McClain Plant has filed for bankruptcy protection, the acquisition also was subject to approval by the bankruptcy court. As part of the bankruptcy approval process, NRG McClain LLC’s interest in the plant was subject to an auction process and on October 28, 2003, the bankruptcy court approved the sale of NRG McClain LLC’s interest in the plant to OG&E. Several parties have filed interventions at the FERC opposing OG&E’s application under Section 203 of the Federal Power Act to acquire NRG McClain’s interest in the power plant or, alternatively, requesting the FERC to delay approving such acquisition. OG&E believed that its application met the standards under Section 203 set forth by the FERC and that its application would be approved. On December 18, 2003, the FERC shifted its policy regarding market power issues, raised wholesale market power concerns and ordered a hearing regarding OG&E’s acquisition of the McClain Plant. The FERC action did not reject OG&E’s request to purchase the McClain Plant, but demonstrated that OG&E must address certain issues. On January 20, 2004, OG&E filed a petition for re-hearing of the FERC’s December 18, 2003 order which included new mitigation measures that were designed to allow for prompt approval of the transaction. That request is still pending before the FERC. OG&E has no indication whether the FERC will accept those proposed mitigation measures. On March 2, 2004, OG&E filed testimony and exhibits with the FERC administrative law judge. The testimony and exhibits indicate that, if the case proceeds to hearing, the wholesale market power issues that the FERC raised in the December 18, 2003 order may be resolved by the minimal mitigation measures.

recover the investment in the plant, OG&E will have the right to accrue a regulatory asset, for a period not to exceed 12 months subsequent to the acquisition, consisting of the non-fuel operation and maintenance expenses, depreciation, cost of debt associated with the investment and ad valorem taxes. Upon approval by the OCC of OG&E’s request, 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.

2003 Rate Case

Gas Transportation and Storage Agreement

Security Enhancements

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 “Electric Competition; Regulation.”

Asset Disposals

Enogex sold its interest in NuStar for approximately $37.0 million in February 2003. The Company recognized approximately a $1.4 million after tax gain related to the sale of these assets in the first quarter of 2003. The final accounting for the NuStar sale was completed in the third quarter of 2003 which resulted in an additional charge of approximately $0.2 million after tax which was recorded in the third quarter of 2003. The final accounting is subject to approval by all parties to the sale of the joint venture interest. These items are recorded in Income from Discontinued Operations in the accompanying Consolidated Statements of Income. These assets were part of the Natural Gas Pipeline segment.

Enogex sold approximately 29 miles of transmission lines of the Ozark pipeline, in which an Enogex subsidiary owns a 75 percent interest, located in Pittsburg and Latimer counties in Oklahoma for approximately $10.0 million in January 2003. The Company recognized approximately a $5.3 million pre-tax gain and approximately $1.1 million in minority interest expense in the first quarter of 2003 related to the sale of these assets, which is recorded in Other Income and Other Expense, respectively, in the accompanying Consolidated Statements of Income. These assets were part of the Natural Gas Pipeline segment.

The Company sold its aircraft for approximately $5.8 million in August 2003. The Company recognized approximately a $0.1 million pre-tax loss related to the sale of the aircraft, which is recorded in Other Expense in the accompanying Consolidated Statements of Income. The aircraft was part of Other Operations.

2004 Outlook

General

The Company currently expects that consolidated earnings in 2004 will be between $1.40 and $1.50 per share, excluding any regulatory action that might affect the electric rates at OG&E. The Company expects improved performance from Enogex while at OG&E, financial performance will depend to a large extent on regulatory considerations. The 2004 outlook includes expected net income of between $113 million and $117 million at OG&E and between $27 million and $31 million at Enogex, while the holding company will likely post a net loss of approximately $16 million. During 2004, the Company expects cash flow from operations of between $300 million and $310 million. In 2004, OG&E plans to increase capital expenditures for electric system reliability upgrades. The Company has assumed approximately 88.0 million

average common shares outstanding for 2004 which includes issuing approximately 2.0 million additional shares (approximately $50.0 million of common stock) through the Company’s Automatic Dividend Reinvestment and Stock Purchase Plan (“DRIP”) in the second half of 2004. Additionally, funding for the Company’s pension plan is expected to be approximately $56.0 million in 2004. In addition to issuing long-term debt to support the acquisition of New Generation, the Company also anticipates calling $200 million of 8.375 percent trust preferred securities at the holding company and replacing them with long-term debt. The replacement of the trust preferred securities will be dependent upon the interest rate environment, access to the capital markets and regulatory and other considerations. The 2004 outlook also includes approximately $6.2 million of additional interest expense at the holding company for unamortized debt expense associated with calling the trust preferred securities. Expected 2004 net income assumes a 38.7 percent effective tax rate.

OG&E

During 2004, OG&E anticipates slightly higher revenue than in 2003 based on sales growth of slightly less than two percent, normal weather and no change in base rates. Overall operating expenses are expected to grow at a rate of approximately 2.8 percent. OG&E also assumes lower short-term interest costs for 2004 and OG&E expects to increase capital expenditures to over $200 million for electric system reliability upgrades. Key factors affecting OG&E’s 2004 net income will be the result of pending regulatory proceedings, weather, OG&E’s ability to control operating and maintenance expenses and customer growth. If the OCC does not agree that OG&E is delivering the customer savings as outlined in the Settlement Agreement, OG&E may be required to credit to its Oklahoma customers approximately $2.1 million per month for each month that the New Generation is not in place. OG&E has significant seasonality in its earnings. OG&E typically shows minimal earnings or slight losses in the first and fourth quarters with a majority of earnings in the third quarter due to the seasonal nature of air conditioning demand.

Enogex

Enogex manages its operations along three related businesses: transportation and storage; gathering and processing; and marketing and trading. In 2004, these businesses are expected to produce a gross margin of approximately $244 million, down from $253 million in 2003. The Company expects approximately 51 percent of Enogex’s gross margin during 2004 to be generated from its transportation and storage business as compared to 55 percent in 2003. Approximately 74 percent of these gross margins are under firm contracts. Revenues in transportation and storage are primarily from gas transportation contracts with utilities in Oklahoma and Arkansas and independent power producers (“IPP”) in Oklahoma. Revenues in the transportation and storage business are expected to decrease due to lower recovery of prior under recovered fuel as the Company has lowered its fuel rate on the system partially offset by the full year impact of a storage contract. The Company expects its gathering and processing business to contribute approximately 41 percent of Enogex’s gross margin in 2004 as compared to 36 percent in 2003. Revenues in gathering and processing are expected to increase in 2004 primarily due to continued efforts to increase margins from renegotiation of expiring contracts and reduced fuel expense offset by lower forecasted processing margins. Volumes are expected

to remain flat from 2003. The Company has forecasted natural gas prices of approximately $4.50 per million British thermal unit (“MMBtu”), $0.51 per gallon average natural gas liquids prices and 200 new well connects in its gathering and processing business. The Company expects its marketing and trading business to contribute approximately eight percent of Enogex’s gross margin in 2004 as compared to nine percent in 2003. Revenues in marketing and trading are expected to decrease in 2004 primarily due to a lack of the 2003 change in accounting principle discussed in “Accounting Pronouncements” partially offset by increased natural gas marketed volumes. Enogex also expects operating expenses to be flat in 2004 as increased operating expenses are offset by the impairment charge of $9.2 million that was recorded in 2003. Enogex also expects lower interest expense due to lower levels of long-term debt. Key factors affecting Enogex’s 2004 net income will be gathering and processing volumes on the system, natural gas and natural gas liquids prices, commodity prices and the level of system fuel costs.

Enogex expects to continue to evaluate the strategic fit and financial performance of its assets in an effort to ensure a proper economic allocation of resources. The magnitude and timing of any impairment or gain on the disposition of assets that may be identified as not being strategic have not been determined.

Dividend Policy

The Company’s dividend policy is determined by the Board of Directors and is based on numerous factors, including management’s estimation of the long-term earnings power of its businesses. The target payout ratio for the Company is to pay out as dividends approximately 75 percent of its earnings on an annual basis. The target payout ratio has been determined after consideration of numerous factors, including the largely retail composition of our shareholder base, our financial position, our growth targets, the composition of our assets and investment opportunities. While the dividend payout ratio is expected to exceed the target payout ratio in 2004, management after considering estimates of future earnings and numerous other factors, expects at this time that it will continue to recommend to the Board of Directors a continuance of the current dividend rate.

Results of Operations

										Percent Change From Prior Year
(In millions, except per share data)		2003			2002			2001		2003		2002

Operating income	$	306.	9	$	235.	7	$	270.	9	30.	2	(13.	0)
Net income	$	129.	8	$	90.	8	$	100.	6	43.	0	(9.	7)
Basic average common shares outstanding		81.	8		78.	1		77.	9	4.	7	0.	3
Diluted average common shares outstanding		82.	1		78.	2		77.	9	5.	0	0.	4
Basic earnings per average common share	$	1.5	9	$	1.1	6	$	1.2	9	37.	1	(10.	1)
Diluted earnings per average common share	$	1.5	8	$	1.1	6	$	1.2	9	36.	2	(10.	1)
Dividends declared per share	$	1.3	3	$	1.3	3	$	1.3	3	--	-	--	-

In reviewing its consolidated operating results, the Company believes that it is appropriate to focus on operating income as reported in its Consolidated Statements of Income as operating income indicates the ongoing profitability of the Company excluding unusual or infrequent items, the cost of capital and income taxes. Included in 2003 and 2002 operating

income are pre-tax impairment charges of approximately $10.2 million and $50.1 million, respectively. These impairments, primarily for Enogex natural gas processing and compression assets that were no longer needed in Enogex’s business, were made in accordance with accounting principles generally accepted in the United States. Operating income was approximately $306.9 million, $235.7 million and $270.9 million in 2003, 2002 and 2001, respectively. These amounts exclude the results of Enogex’s E&P business, NuStar and Belvan, which as explained above, were sold in 2002 and in the first quarter of 2003 and which are reported as discontinued operations. See “Enogex – Discontinued Operations” below for a further discussion.

Operating Income (Loss) by Business Segment

(In millions)		2003			2002			2001

OG&E (Electric Utility)	$	216.	2	$	239.	1	$	236.	6
Enogex (Natural Gas Pipeline) (A)		91.	2 (B)		(3.	0) (B)		34.	4
Other Operations (C)		(0.	5)		(0.	4)		(0.	1)

Consolidated operating income	$	306	.9	$	235	.7	$	270	.9

(A) Excludes discontinued operations.
(B) After recording pre-tax impairment charges of approximately $9.2 million and $48.3 million in 2003 and 2002, respectively.
(C) Other Operations primarily includes unallocated corporate expenses.

The following operating income analysis by business segment includes intercompany transactions that are eliminated in the Consolidated Financial Statements.

OG&E

(In millions)		2003			2002			2001

Operating revenues	$	1,517	.1	$	1,388	.0	$	1,456	.8
Fuel		544	.5		435	.8		485	.8
Purchased power		292	.9		260	.0		280	.7

Gross margin on revenues		679	.7		692	.2		690	.3
Other operating expenses		463	.5		453	.1		453	.7

Operating income	$	216	.2	$	239	.1	$	236	.6

System sales - MWH (A)		25	.0		24	.6		24	.5
Off-system sales - MWH		0	.1		0	.3		0	.4

Total sales - MWH		25	.1		24	.9		24	.9

(A) Megawatt-hour

2003 compared to 2002. OG&E’s operating income decreased approximately $22.9 million or 9.6 percent in 2003 as compared to 2002. The decrease in operating income was primarily attributable to lower electric rates as a result of the $25 million electric rate reduction that went into effect in Oklahoma on January 6, 2003, weaker weather-related demand, lower off-system sales and higher operating and maintenance expenses partially offset by customer growth in OG&E’s service territory.

Gross margin, which is operating revenues less cost of goods sold, was approximately $679.7 million in 2003 as compared to approximately $692.2 million in 2002, a decrease of approximately $12.5 million or 1.8 percent. The gross margin primarily decreased due to lower electric rates as a result of the $25 million electric rate reduction that went into effect in Oklahoma on January 6, 2003 (approximately $24.8 million). Gross margin also was reduced by approximately $2.0 million due to weaker weather-related demand. Lower off-system sales decreased the gross margin by approximately $1.9 million as off-system sales can vary based upon the supply and demand needs on OG&E’s generation system. Partially offsetting these decreases in gross margin was an increase of approximately $17.5 million due to customer growth in OG&E’s service territory.

Cost of goods sold for OG&E consists of fuel used in electric generation and purchased power. Fuel expense increased approximately $108.7 million or 24.9 percent in 2003 as compared to 2002 primarily due to a 29.4 percent increase in the average cost of fuel per kilowatt-hour (“Kwh”). OG&E’s electric generating capability is fairly evenly divided between coal and natural gas and provides for flexibility to use either fuel to the best economic advantage for OG&E and its customers. In 2003, OG&E’s fuel mix was 77 percent coal and 23 percent natural gas. 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 with lower priced coal. Purchased power costs increased approximately $32.9 million or 12.7 percent in 2003 as compared to 2002. The increase was primarily due to approximately a 28.2 percent increase in the volume of energy purchased primarily due to economic purchases.

Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, are passed through to OG&E’s customers through automatic fuel adjustment clauses. While the regulatory mechanisms for recovering fuel costs differ in Oklahoma and Arkansas, in both states the costs are passed through to customers and are intended to provide neither an ultimate benefit nor detriment to OG&E. The automatic fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC have authority to review the appropriateness of gas transportation charges or other fees OG&E pays to Enogex. See Note 18 of Notes to Consolidated Financial Statements.

Other operating expenses, consisting of operating and maintenance expense, depreciation expense and taxes other than income, increased approximately $10.4 million or 2.3 percent in 2003 as compared to 2002. OG&E’s operating and maintenance expense increased approximately $11.9 million or 4.2 percent in 2003 as compared to 2002. The increase was primarily due to approximately a $10.7 million increase in pension and benefit expenses in 2003 as compared to 2002, due to the general upward trend in these costs. Also contributing to the increase in operating and maintenance expenses was the recognition of approximately $5.4 million for costs incurred during the first quarter of 2002 in connection with the severe January 2002 ice storm being reported as a regulatory asset. These 2002 expenditures, incurred by field service personnel, would normally have been charged to maintenance expenses in 2002. The increased operating and maintenance expenses were partially offset by a decrease in bad debt expense of approximately $3.5 million due to improved collection efforts.

Depreciation expense decreased approximately $1.3 million or 1.1 percent in 2003 as compared to 2002 due to a change made in the depreciation rate of production plant in 2003 as required by the Settlement Agreement.

2002 compared to 2001. OG&E’s operating income increased approximately $2.5 million or 1.1 percent in 2002 as compared to 2001. The increase in operating income was primarily attributable to a slightly higher gross margin due to growth in electric usage in OG&E’s service territory and lower operating and maintenance expenses partially offset by lower levels of natural gas transportation cost recovered, lower recoveries of fuel costs from Arkansas customers, loss of revenue resulting from the January 2002 ice storm, lower off-system sales and milder weather.

Gross margin was approximately $692.2 million in 2002 as compared to approximately $690.3 million in 2001, an increase of approximately $1.9 million or 0.3 percent. Growth in the number of customers in OG&E’s service territory and the resulting increase in electric sales of approximately 2.9 percent increased the gross margin by approximately $20.1 million. The increase was offset by lower recoveries of fuel costs from Arkansas customers through that state’s automatic fuel adjustment clause of approximately $5.9 million. In Arkansas, recovery of fuel costs is subject to a bandwidth mechanism. If fuel costs are within the bandwidth range, recoveries are not adjusted on a monthly basis; rather they are reset annually on April 1. Gross margin also was reduced by approximately $4.0 million due to milder weather. Lower recoveries under the Generation Efficiency Performance Rider (“GEP Rider”), which terminated in June 2002, decreased the gross margin by approximately $3.6 million in 2002. Additionally, lower levels of natural gas transportation cost that OG&E was allowed to recover from its customers as a result of the Acquisition Premium Credit Rider (“APC Rider”) and the Gas Transportation Adjustment Credit Rider (“GTAC Rider”) decreased the gross margin by approximately $2.1 million. See Note 18 of Notes to Consolidated Financial Statements for a further discussion of these riders. Although total expenditures from the January 2002 ice storm of approximately $92.0 million, which have been capitalized or deferred, did not impact operating results, the related loss of revenue due to interruption of service to our customers resulted in a decrease in the gross margin of approximately $1.5 million in 2002. Reduced amounts of off-system sales decreased the gross margin by approximately $1.1 million as off-system sales can vary based upon the supply and demand needs on OG&E’s generation system.

Fuel expense decreased approximately $50.0 million or 10.3 percent in 2002 as compared to 2001 primarily due to an 11.1 percent decrease in the average cost of fuel per Kwh. In 2002, OG&E’s fuel mix was 72 percent coal and 28 percent natural gas. Purchased power costs decreased approximately $20.7 million or 7.4 percent in 2002 as compared to 2001. This decrease was primarily due to approximately a 4.6 percent decrease in the volume of energy purchased and a 2.6 percent decrease in the cost of purchased energy per Kwh.

Other operating expenses decreased approximately $0.6 million or 0.1 percent in 2002 as compared to 2001. OG&E’s operating and maintenance expense decreased approximately $4.4 million or 1.5 percent in 2002 as compared to 2001. This decrease was primarily due to a decrease of approximately $11.5 million in bad debt expense, a decrease of approximately $1.8 million in materials and supplies expense and a decrease of approximately $1.0 million in

contract labor costs. Higher than normal bills driven by high natural gas prices early in 2001, along with customer cut-off moratoriums imposed during high temperature periods during the summer of 2001 contributed to significantly increased uncollectibles in 2001. The decrease in contract labor costs was due to higher contract labor costs incurred in 2001 due to the use of contractors to supplement OG&E’s own crews to restore power after a major ice storm at the beginning of 2001 and a major wind storm in the early summer of 2001. The decreased operating and maintenance expenses were partially offset by an increase in employee pension and benefit costs of approximately $9.9 million. Pension expense increased primarily due to lower than forecasted returns on assets in the pension trust and the effect of lower discount rates used to measure the accumulated pension benefit obligation. The general upward trend in medical costs also contributed to the increase in employee benefit costs.

Depreciation expense increased approximately $3.3 million or 2.8 percent in 2002 as compared to 2001 due to a higher level of depreciable plant. Taxes other than income increased approximately $0.5 million or 1.1 percent in 2002 as compared to 2001 due to higher ad valorem taxes.

Enogex – Continuing Operations

(Dollars in millions)		2003			2002			2001

Operating revenues	$	2,327.	8	$	1,684.	0	$	1,649.	8
Gas and electricity purchased for resale		2,019.	1		1,402.	1		1,318.	4
Natural gas purchases - other		55.	4		70.	5		142.	9

Gross margin on revenues		253.	3		211.	4		188.	5
Impairment of assets		9.	2		48.	3		--	-
Other operating expenses		152.	9		166.	1		154.	1

Operating income (loss)	$	91.	2	$	(3.	0)	$	34.	4

New well connects		23	2		16	6		27	9

Gathered volumes - MMBtu/d (A)		1,01	2		1,05	6		1,27	8
Incremental transportation volumes - MMBtu/d		44	0		48	6		42	7

Total throughput volumes - MMBtu/d		1,45	2		1,54	2		1,70	5

Natural gas processed - Mmcf/d (B)		41	4		45	5		64	1

Natural gas liquids produced (keep whole) - million gallons		12	5		19	7		31	4
Natural gas liquids produced (POL and fixed-fee) - million gallons		13	4		15	4		19	6

Total natural gas liquids produced - million gallons		25	9		35	1		51	0

Average sales price per gallon	$	0.59	5	$	0.40	6	$	0.45	7
Natural gas marketed - Bbtu (C)		374,29	6		409,87	9		280,66	0
Average sales price per MMBtu	$	5.20	8	$	3.23	6	$	4.40	3

(A) Million British thermal units per day. (B) Million cubic feet per day. (C) Billion British thermal units. N/A - Not applicable.

2003 compared to 2002. Enogex’s operating income in 2003 increased approximately $94.2 million as compared to 2002. The increase was primarily attributable to lower impairment charges and higher gross margins in all of Enogex’s businesses, from among other things, improved management of pipeline system fuel, increased levels of firm transportation revenues, improved processing results and the negotiation of both new contracts and replacement contracts at better terms that resulted in increases in gathering fees and reductions in the purchase price of gas. Also contributing to Enogex’s improvement were lower operating and maintenance expenses. Enogex sold its E&P business and its interest in Belvan during 2002 and Enogex sold its interest in NuStar during the first quarter of 2003; accordingly, these are reported as discontinued operations for the years ended December 31, 2003, 2002 and 2001 in the Consolidated Financial Statements. See “Enogex – Discontinued Operations” below for a further discussion.

Transportation and storage contributed approximately $138.1 million of Enogex’s gross margin in 2003 as compared to approximately $120.8 million in 2002, an increase of approximately $17.3 million or 14.3 percent. Gross margins benefited from increased storage revenues of approximately $8.8 million in 2003 as compared to 2002. The increased storage revenues were mainly due to new demand fees from the contract with OG&E related to the purchase of the Stuart Storage Facility in August 2002 and increased demand fees from both third parties and Enogex’s marketing and trading business. Also contributing to the increase in gross margin was improved management of pipeline system fuel which, when coupled with higher natural gas prices, accelerated the authorized recovery of pipeline system fuel expense of approximately $10.5 million. The authorized recovery of pipeline system fuel was the result of

Enogex under recovering fuel in prior periods. Also contributing to the increase in gross margin were increased levels of firm transportation revenues of approximately $5.5 million as a result of the Calpine Energy settlement and an increase in related demand fees recognized in 2003. These increases were partially offset by approximately a $4.1 million decrease in gross margin due to a revenue allocation related to bundled contracts from Enogex’s transportation and storage business to Enogex’s gathering and processing business to more accurately reflect the performance of our businesses, approximately $1.2 million higher electric compression costs and approximately a $1.1 million imbalance collectibility reserve.

Gathering and processing contributed approximately $91.3 million of Enogex’s gross margin in 2003 as compared to approximately $73.0 million in 2002, an increase of approximately $18.3 million or 25.1 percent. Gathering gross margins increased approximately $9.8 million in 2003 as compared to 2002 primarily due to a $4.1 million revenue allocation related to bundled contracts from Enogex’s transportation and storage business to Enogex’s gathering and processing business to more accurately reflect the performance of our businesses and the negotiation of both new contracts and replacement contracts at better terms that resulted in increases in gathering fees and reductions in the purchase price of gas. Also, there was an increase in the number of well connects in 2003 as compared to 2002. Processing gross margins increased approximately $8.5 million in 2003 as compared to 2002. This increase was primarily due to wider commodity spreads between natural gas and natural gas liquids and better management and dispatch of the plants. However, processing volumes were lower as a result of economic dispatching of the network of processing plants based upon market conditions.

Marketing and trading contributed approximately $23.9 million of Enogex’s gross margin in 2003 as compared to approximately $17.6 million in 2002, an increase of approximately $6.3 million or 35.8 percent. The increase was primarily due to Enogex recording a $9.0 million pre-tax loss as a cumulative effect of a change in accounting principle in the first quarter of 2003 rather than this loss being included in operating and maintenance expense. The cumula

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549

OR

Securities registered pursuant to Section 12(g) of the Act: None

OGE ENERGY CORP.

FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2003

TABLE OF CONTENTS

TABLE OF CONTENTS (Continued)

PART I

Item 1. Business.

THE COMPANY

Company Strategy

ELECTRIC OPERATIONS - OG&E

General

OKLAHOMA GAS AND ELECTRIC COMPANY CERTAIN OPERATING STATISTICS

Regulation and Rates

Rate Activities and Proposals

Fuel Supply

NATURAL GAS PIPELINE OPERATIONS - ENOGEX

FINANCE AND CONSTRUCTION

Future Capital Requirements

Future Sources of Financing

ENVIRONMENTAL MATTERS

EMPLOYEES

ACCESS TO SECURITIES AND EXCHANGE COMMISSION FILINGS

Item 2. Properties.

Item 3. Legal Proceedings.

Executive Officers of the Registrant.

PART II

Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters.

Dividend Restrictions

Item 6. Selected Financial Data.

HISTORICAL DATA

HISTORICAL DATA (Continued)

Item 7. Management’s Discussion and Analysis of Financial Condition and and Results of Operations.

Introduction

Company Strategy

Forward-Looking Statements

Overview

2004 Outlook

Results of Operations

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS

Item 5. Market for Registrant’s Common Equity and Related
Stockholder Matters.

Item 7. Management’s Discussion and Analysis of Financial Condition and
and Results of Operations.