10-K 1 oge10k123104.htm 10-K 12/31/2004

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, 2004

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, 2004, 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 $2,224,093,097 based on the number of shares held by non-affiliates (87,322,069) and the reported closing market price of the common stock on the New York Stock Exchange on such date of $25.47.

As of January 31, 2005, 89,979,541 shares of common stock, par value $0.01 per share, were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

The Proxy Statement for the Company’s 2005 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, 2004

Part I	Page
Item 1. Business	1
The Company	1
Electric Operations - OG&E	3
General	3
Regulation and Rates	6
Rate Activities and Proposals	7
Fuel Supply	9
Natural Gas Pipeline Operations - Enogex	11
Finance and Construction	21
Environmental Matters	22
Employees	23
Access to Securities and Exchange Commission Filings	23
Item 2. Properties	24
Item 3. Legal Proceedings	26
Item 4. Submission of Matters to a Vote of Security Holders	32
Executive Officers of the Registrant	33
Part II
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities	36
Item 6. Selected Financial Data	39
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	86
Item 8. Financial Statements and Supplementary Data	89
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	168

TABLE OF CONTENTS (Continued)

Item 9A. Controls and Procedures	168
Item 9B. Other Information	172
Part III
Item 10. Directors and Executive Officers of the Registrant	172
Item 11. Executive Compensation	172
Item 12. Security Ownership of Certain Beneficial Owners and Management	176
Item 13. Certain Relationships and Related Transactions	176
Item 14. Principal Accounting Fees and Services	176
Part IV
Item 15. Exhibits and Financial Statement Schedules	177
Signature	186

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 primarily 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 in Note 18 of Notes to Consolidated Financial Statements.

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 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 margins 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 Ozark Gas Transmission, L.L.C. (“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, was 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, the Company recognized that immediate deregulation of the retail electric markets in Oklahoma and Arkansas was very unlikely and revised its business strategy. In the summer of 2004, the Company again reviewed its business strategy in light of significant changing market and regulatory trends such as the over supply of electric generation, the evolution of electric transmission markets and rules, the natural gas supply forecast, the sustained increase of natural gas commodity prices and the anticipated emergence of liquefied natural gas. The Company concluded that its existing business strategy of utilizing a diversified asset position was the proper course.

The Company’s vision is to be a regional energy company focused on its regulated utility business and natural gas pipeline business that is recognized for operational excellence and financial performance. The Company intends to maintain the majority of its assets in the regulated utility business complemented by its natural gas pipeline business. The Company’s long-term financial goals include earnings growth of four to five percent on a normalized basis, a dividend payout ratio below 75 percent and an A- credit rating. OG&E has embarked on a Customer Savings and Reliability Plan that provides for increased investment at the utility to (i) improve reliability to meet load growth; (ii) replace aging infrastructure; and (iii) deploy newer technology to improve operational and environmental performance. Capacity payment savings from reduced cogeneration payments and fuel savings from the acquisition of a 77 percent interest in the 520 megawatt (“MW”) NRG McClain Station (the “McClain Plant”) will be utilized to mitigate the price increases associated with these investments.

At Enogex, the Company plans to continue to implement improvements to enhance long-term financial performance of its mid-continent assets through more efficient operations and effective commercial management of the assets. In addition, Enogex is seeking to diversify its gathering, processing and transportation businesses principally by expanding into other geographic areas that are complementary with the Company’s strategic capabilities. Enogex’s marketing business, which concentrates principally on origination of physical sales of natural gas, has expanded into the Gulf Coast, Rocky Mountain and East Coast markets.

The Company’s business strategy is to continue maintaining the diversified asset position of OG&E and Enogex so as to provide competitive 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 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, 2004, OG&E and Enogex represented approximately 63 percent and 36 percent,

respectively, of the Company’s consolidated assets. The remaining one 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 many of the risk management practices, commercial skills and market information available from Enogex provide value to all of the Company’s businesses subject to the evolving federal regulations of the FERC in regard to the operations of the wholesale power market. 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 – Executive Overview” 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 269 communities and their contiguous rural and suburban areas. During 2004, seven other communities and five 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, the second largest city in that state. Of the 269 communities that OG&E serves, 243 are located in Oklahoma and 26 in Arkansas. OG&E derived approximately 89 percent of its total electric operating revenues for the year ended December 31, 2004 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 2004 was approximately 5,823 MWs on August 3, 2004. OG&E’s load responsibility peak demand was approximately 5,460 MWs on August 3, 2004, resulting in a capacity margin of approximately 22.3 percent. As reflected in the table below and in the operating statistics on page 5, there were approximately 24.8 million megawatt-hour (“MWH”) sales in 2004 as compared to approximately 25.1 million in 2003 and 24.9 million in 2002. MWH sales to OG&E’s customers (“system sales”) decreased approximately 0.1 percent in 2004 primarily due to milder weather during 2004. Sales to other utilities and power marketers (“off-system sales”) remained flat in 2004. Variances in off-system sales are due in large part to the changing supply and demand needs on OG&E’s generation system and the market for off-system sales.

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

	2004	Increase/ (Decrease)	2003	Increase/ (Decrease)	2002	Increase/ (Decrease)
System Sales (A) Off-System Sales (A)	24.7 0.1	(0.1)% ---%	25.0 0.1	1.6% (67.0)%	24.6 0.3	0.4% (25.0)%
Total Sales	24.8	(0.1)%	25.1	0.8%	24.9	---%
(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 Note 18 of Notes to Consolidated Financial Statements 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)		2004			2003			2002

ELECTRIC ENERGY
(Millions of MWH)
Generation (exclusive of station use)		22	.6		22	.5		23	.4
Purchased		4	.2		4	.5		3	.5

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

Electric energy sold		24	.8		25	.1		24	.9

ELECTRIC ENERGY SOLD
(Millions of MWH)
Residential		7	.9		8	.2		8	.0
Commercial		5	.7		5	.8		5	.8
Industrial		7	.0		6	.8		6	.6
Public authorities		2	.7		2	.7		2	.7
Sales for resale		1	.4		1	.5		1	.5

System sales		24	.7		25	.0		24	.6
Off-system sales		0	.1		0	.1		0	.3

Total sales		24	.8		25	.1		24	.9

ELECTRIC OPERATING REVENUES
(In millions)
Residential	$	611	.4	$	601	.4	$	557	.6
Commercial		389	.9		372	.5		346	.9
Industrial		326	.7		293	.4		258	.6
Public authorities		158	.5		146	.1		135	.5
Sales for resale		57	.0		57	.7		48	.2
Provision for refund on gas transportation and storage case		(6	.9)		-	--		-	--
Other		40	.7		41	.9		34	.9

System sales revenues		1,577	.3		1,513	.0		1,381	.7
Off-system sales revenues		0	.8		4	.1		6	.3

Total Electric Operating Revenues	$	1,578	.1	$	1,517	.1	$	1,388	.0

ACTUAL NUMBER OF ELECTRIC CUSTOMERS
(At end of period)
Residential		630,73	6		622,52	7		616,71	2
Commercial		80,78	6		80,26	5		79,76	8
Industrial		9,42	0		8,97	0		8,69	8
Public authorities		14,02	2		13,65	8		13,28	0
Sales for resale		4	4		5	0		5	5

Total		735,00	8		725,47	0		718,51	3

AVERAGE RESIDENTIAL CUSTOMER SALES
Average annual revenue	$	975.0	8	$	970.0	4	$	907.9	5
Average annual use (kilowatt-hour (“KWH”))		12,63	0		13,20	2		13,09	5
Average price per KWH (cents)	$	7.7	2	$	7.3	5	$	6.9	3

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, 2004, 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 OCC issued an order in 1996 authorizing OG&E to reorganize into a subsidiary of the Company. The order required that, among other things, (i) the Company permit the OCC access to the books and records of the Company and its affiliates relating to transactions with OG&E; (ii) the Company employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E’s customers; and (iii) the Company refrain from pledging OG&E assets or income for affiliate transactions.

Regulatory Matters and Plant Acquisition

In November 2002, the OCC issued an order containing provisions of an agreed-upon settlement of OG&E’s rate case. The terms of this settlement included, among other things, a $25.0 million annual reduction in electric rates and a requirement for OG&E to acquire 400 MWs of electric generation. The rate reduction went into effect January 6, 2003 and the acquisition of a 77 percent interest in the 520 MW McClain Plant was completed on July 9, 2004. The McClain Plant, located near Newcastle, Oklahoma, is a combined cycle unit consisting of two natural-gas fired combustion turbine generators combined with a steam turbine generator. The owner of the remaining 23 percent interest in the McClain Plant is the Oklahoma Municipal Power Authority. OG&E operates the plant. The purchase price was approximately $160.0 million. OG&E temporarily funded the McClain Plant acquisition with short-term borrowings from the Company. On August 4, 2004, OG&E issued $140.0 million of long-term debt to replace these short-term borrowings. Also, on August 9, 2004, the Company made a capital contribution to OG&E of approximately $153.0 million. For additional information regarding the McClain Plant acquisition and related regulatory matters, see Note 18 of Notes to Consolidated Financial Statements.

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 actual or anticipated 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 actual or anticipated 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. Excluding

recoverable take or pay gas charges, the McClain Plant operating and maintenance expenses, depreciation, ad valorem taxes and interest on debt, regulatory assets are being amortized and reflected in rates charged to customers over periods of up to 20 years.

OG&E records certain actual or anticipated costs and obligations as regulatory assets or liabilities if it is probable, based on regulatory orders or other available evidence, that the cost or obligation will be included in amounts allowable for recovery or refund in future rates.

At December 31, 2004 and 2003, OG&E had regulatory assets of approximately $137.3 million and $94.2 million, respectively, and regulatory liabilities of approximately $130.1 million and $149.7 million, respectively.

As discussed in Note 18 of Notes to Consolidated Financial Statements, 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 could deregulate OG&E’s electric generation assets and cause OG&E 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 OG&E 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.

See Note 18 of Notes to Consolidated Financial Statements for a discussion of certain regulatory matters including the gas transportation and storage contract between OG&E and Enogex, security enhancements and national energy legislation.

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. OG&E received OCC approval in the settlement of its rate case (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 could 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 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 or 2004 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. In 2004, over 90 percent of the GFB pilot customers renewed for a second year under the program. The pilot program has received favorable reviews and OG&E is currently considering a filing with the OCC for permanent rate status in the second quarter of 2005.

Fuel Supply

During 2004, approximately 70 percent of the OG&E-generated energy was produced by coal units and 30 percent by natural gas units. Of the 6,141 total MW capability reflected in the table under Item 2. Properties, approximately 3,601 MWs, or 59 percent, are from natural gas generation and approximately 2,540 MWs, or 41 percent, are from coal generation. Though OG&E has a higher installed capability of generation from natural gas units, 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 weighted average cost of fuel used, by type, per million British thermal unit (“MMBtu”) was as follows:

		2004			2003			2002			2001			2000

Coal	$	1.0	0	$	0.9	3	$	0.9	3	$	0.8	1	$	0.8	7
Natural Gas	$	6.5	7	$	6.4	6	$	3.7	8	$	4.9	1	$	4.9	3
Weighted Average	$	2.6	9	$	2.2	7	$	1.7	7	$	1.9	7	$	1.9	6

The increase in the weighted average cost of fuel in 2004 as compared to 2003 was primarily due to increased natural gas prices and a higher amount of natural gas burned in 2004 while the increase in the weighted average cost of fuel in 2003 as compared to 2002 was primarily due to increased natural gas prices in 2003 partially offset by a lower amount of natural gas burned in 2003. The decrease in the weighted average cost of fuel in 2002 as compared to 2001 was primarily due to lower natural gas prices in 2002 partially offset by a higher amount of natural gas burned in 2002. A portion of these fuel costs is included in the base rates to customers and differs for each jurisdiction. The portion of these fuel costs that is not included in the base rates is recovered through OG&E’s regulatorily approved automatic fuel adjustment clauses. See Note 1 of Notes to Consolidated Financial Statements. OG&E currently has pending before the OCC an application to recover the costs of gas transportation and storage services provided to it by Enogex pursuant to the contract between OG&E and Enogex. An adverse decision by the OCC could result in OG&E having to refund previously collected amounts. See Note 18 of Notes to Consolidated Financial Statements for a further discussion of this matter.

Coal

All of OG&E’s coal units, with an aggregate capability of approximately 2,540 MWs, are designed to burn low sulfur western coal. OG&E purchases coal primarily under long-term contracts expiring in 2010 and 2011. During 2004, OG&E purchased approximately 9.4 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 0.25 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 coal units have an approximate emission rate of 0.504 lbs. of sulfur dioxide per MMBtu, well within the limitations of the provisions of the Clean Air Act.

OG&E has continued its efforts to maximize the utilization of its coal units at both its Sooner and Muskogee generating plants. See “Environmental Laws and Regulations” in Note 17 of Notes to Consolidated Financial Statements 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

In April 2004, OG&E utilized a request for bid (“RFB”) to acquire approximately 56 percent and 26 percent of its projected annual natural gas requirements for 2005 and 2006, respectively. All of these contracts are tied to various gas price market indices and most will expire in December 2006. Additional natural gas supply for the summer of 2005 will be secured through a new RFB issued in the first quarter of 2005. OG&E will meet additional natural gas requirements with monthly and daily purchases as required.

In 1993, OG&E began utilizing a natural gas storage facility that allowed OG&E to maximize the value of its generation assets, which storage services are now provided by Enogex as part of Enogex’s gas transportation and storage contract with OG&E.

Wind

During 2003, OG&E contracted with FPL Energy for 50 MWs of electricity generated at a wind farm near Woodward, Oklahoma. After more than one year of marketing wind power to OG&E’s residential and business customers, almost 9,000 have subscribed for all or part of their electricity usage. Since OG&E last requested bids to determine the cost of adding wind to its system, natural gas prices have continued to rise and federal renewable energy tax credits have been extended. OG&E is exploring adding another 80 MWs of wind-generated electricity to its system and, in December 2004, OG&E issued a request for proposals from companies who produce electricity from wind. OG&E expects to use the proposal responses to conduct a thorough analysis of how adding more wind will affect customers today and in the future. A decision is expected during the first or second quarter of 2005.

NATURAL GAS PIPELINE OPERATIONS – ENOGEX

Overview

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 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 margins 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 8,200 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 a 931 mile gas gathering and interstate transmission pipeline system of which 734 miles is comprised of a FERC regulated interstate pipeline, Ozark, 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, was sold in 2002 and in the first quarter of 2003 and are reported in the Consolidated Financial Statements as discontinued operations.

Strategy

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 (i.e., the ability of the generation unit to regulate generation to respond to and meet the instantaneous changes in customer demand). 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 Oklahoma and other generation loads in 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 its 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 second in the nation in onshore natural gas production and ranks second in the nation as a natural gas exporting state. 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, through its processing plants, is also able to remove natural gas liquids from the wellhead gas streams, which is necessary for such gas to meet quality specifications of the downstream marketplace.

The activities described above, while central to Enogex’s operations, are not its only businesses. The transportation capabilities and 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, 2004, Enogex was connected to 15 other major pipelines at approximately 65 pipeline interconnect points providing access to markets in the western United States, the Midwest, 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 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 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 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 business also provides the Company the capability to provide 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. As a part of this process, Enogex implemented a number of steps intended to maximize the value of its assets.

Dispositions

Exploration and Production; Processing. Enogex 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, 2004, 2003 and 2002 in the Consolidated Financial Statements.

Processing and Compression Assets. During the fourth quarter of 2002, the Company recognized a pre-tax impairment loss of approximately $48.3 million in the Natural Gas Pipeline segment related to Enogex natural gas processing and compression assets. In the fourth quarter of 2003, the Company recognized a pre-tax impairment loss of approximately $9.2 million related to these natural gas compression assets. See Note 6 of Notes to Consolidated Financial Statements for a more detailed discussion of these impairments.

During the year ended December 31, 2004, the Company sold certain of its compression and processing assets for approximately $5.0 million and recognized an after tax gain of approximately $1.8 million related to the sale of these assets. The carrying amount of the remaining assets (that were the subject of the impairment charges in the fourth quarters of 2002 and 2003) was approximately $2.6 million and $11.9 million at December 31, 2004 and 2003, respectively. As discussed below, for any remaining assets that were the subject of the impairment charges in the fourth quarters of 2002 and 2003, the Company has either contributed the assets to the joint venture or reclassified these assets from held for sale to held and used as of December 31, 2004.

During the third quarter of 2004, Enogex entered into a joint venture arrangement with a third party and contributed certain of its natural gas compression assets (with a carrying amount of approximately $3.9 million) to the joint venture. The objective of the joint venture is to derive value from the assets by renting the natural gas compressors. Enogex Compression Company, LLC (“Enogex Compression”) was created to act as the participating entity in the joint venture. Enogex Compression holds a majority ownership in the joint venture, although the actual ownership percentages may fluctuate based on the relative capital contributions of Enogex Compression and the third party member. The third party acts as the manager and conducts the daily operations of the joint venture. These assets are part of the Natural Gas Pipeline segment.

During the third quarter of 2004, the Company reclassified an asset from assets held for sale to assets held and used. This asset had a carrying amount of approximately $0.8 million at the time the asset was reclassified. In October 2004, the Company reclassified a large electric driven compressor that was previously classified as assets held for sale to assets held and used.

This compressor had a carrying amount of approximately $1.2 million at September 30, 2004. In December 2004, the Company reclassified several compressors and processing plants that were previously classified as assets held for sale to assets held and used. These assets had a carrying amount of approximately $1.6 million at December 31, 2004. See Note 6 of Notes to Consolidated Financial Statements for a more detailed discussion of these reclassifications.

Transportation and Storage. During September 2004, Enogex received notification from a customer that a transportation agreement involving four of Enogex’s non-contiguous pipeline asset segments located in West Texas and used to serve the customer’s power plants would be terminated effective December 31, 2004. In response to this notification, the Company recognized, during the third quarter of 2004, a pre-tax impairment loss of approximately $8.6 million in the Natural Gas Pipeline segment related to Enogex natural gas pipeline assets that were used to provide service to this customer. In December 2004, the Company received notification that all of this customers’ plants in West Texas had shut down and service is no longer required. The Company is currently evaluating other commercial opportunities for these assets as well as contacting other parties that may be interested in acquiring any of these assets. See Note 6 of Notes to Consolidated Financial Statements for a more detailed discussion of this impairment.

In January 2003, Ozark recognized a gain of approximately $5.3 million and approximately $1.1 million in minority interest expense related to the sale of approximately 29 miles of transmission lines of its pipeline.

Capital Expenditures; Improvement Projects.

In 2003, Enogex began a major upgrade of its information systems that is expected to be substantially completed during the second and third quarters of 2005. Enogex 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 better determine the earnings potential of its various assets and service offerings.

During 2004, Enogex made improvements to the Stuart Storage Facility which reduced water encroachment in the field. During 2004, approximately $1.9 million in capital expenditures was spent on this project. Enogex does not expect any material future expenditures on this water encroachment project.

In December 2002, Enogex entered into an agreement with Colorado Interstate Gas Company regarding reservation of firm capacity on an interstate gas pipeline that was initially proposed to be in service by August 31, 2005 (the “Cheyenne Plains Pipeline”). Under the final transportation agreement, OGE Energy Resources, Inc. (“OERI”) reserved 60,000 decatherms/day (“Dth/day”) of capacity on the pipeline for 10 years and two months. Such reservation provides OERI access to significant additional natural gas supplies in the Rocky Mountain production basins. The Cheyenne Plains Pipeline, which began full service in February 2005, provides interstate gas transportation services in Wyoming, Colorado and Kansas with a capacity of 560,000 Dth/day. OERI pays a demand fee of approximately $7.5 million annually for this capacity.

Transportation and Storage

General. One of Enogex’s primary lines of business is the transportation of natural gas, with current throughput of approximately 1.5 trillion British thermal units (“Btu”) per day. 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, 2004, Enogex was connected to 15 other major pipelines at approximately 65 pipeline interconnect points. These interconnections include Panhandle Eastern Pipe Line, Southern Star Central Gas Pipeline (formerly Williams Central), Natural Gas Pipeline Company of America, Oneok Gas Transmission, Northern Natural Gas Company, ANR Pipeline, Western Farmers Electric Cooperative, 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, 2004, the net property, plant and equipment balance for Enogex’s transportation and storage business was approximately $714.7 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 23 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 Operating Conditions (“SOC”) for gas storage and at market-based rates to be negotiated with each customer. Both facilities are used to support Enogex’s intrastate transportation and storage services for OG&E. See “Item 3. Legal Proceedings” for a discussion of the legal matters 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, Transok L.L.C. and its subsidiary entities (“Transok”), which Enogex had acquired in 1999, merged into Enogex thereby simplifying for both Enogex and its customers the administration and operation of maintaining two separate pipelines. Enogex provides firm intrastate transportation and storage services to several customers and Enogex’s major customers are OG&E as well as Public Service Company of Oklahoma (“PSO”), the second largest electric utility in Oklahoma, serving the Tulsa market. Enogex provides 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 has been extended to January 1, 2006, 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 natural gas storage services since August 2002 when

Enogex acquired the Stuart Storage Facility from Central Oklahoma Oil and Gas Corp. (“COOG”). During 2004, 2003 and 2002, Enogex’s revenues from its firm intrastate transportation and storage contracts were approximately $95.6 million, $92.2 million and $79.5 million, respectively.

Relationship with OG&E. From its inception, Enogex has been the transporter of natural gas to OG&E’s natural gas-fired generation facilities. 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 for gas transportation service to 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. Following a consideration of competitive bidding by OG&E as required by the prior order from the OCC, the contract with Enogex 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 beyond the level and flexibility that was provided previously. Enogex has been providing natural gas storage services since August 2002 when Enogex acquired the Stuart Storage Facility from COOG. The amount collected from OG&E by Enogex under the current contract for transportation services was approximately $34.3 million, $33.5 million and $33.6 million, respectively, during 2004, 2003 and 2002. The amount collected from OG&E by Enogex under the current contract for storage services was approximately $15.3 million, $11.2 million and $3.3 million, respectively, during 2004, 2003 and 2002. OG&E currently has pending before the OCC an application to recover the costs of gas transportation and storage services provided to it by Enogex pursuant to the contract between OG&E and Enogex. An adverse decision by the OCC could result in OG&E having to refund previously collected amounts. See Note 18 of Notes to Consolidated Financial Statements for a further discussion of this matter.

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, but will not necessarily, involve an administrative-type hearing before the FERC Staff panel 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.

In December 2001, Enogex made its triennial rate filing at the FERC under Section 311 of the NGPA. Enogex also proposed a default processing fee and addressed various other issues for the combined Enogex and Transok L.L.C. pipeline systems. In May 2003, the FERC accepted a stipulation and settlement agreement and entered an order modifying Enogex’s SOC with respect to priority dedicated gas.

On September 1, 2004, Enogex made a filing at the FERC to revise the SOC approved in the 2001 case, to permit, among other things, the unbundling, effective October 1, 2004, of its previously bundled gathering and transportation services. On September 30, 2004, Enogex made its triennial filing to establish rates for Section 311 service, reflecting the unbundling of the transportation and gathering services.

Numerous parties intervened in the SOC and Section 311 dockets and some parties protested one or both of the filings. The proceedings are currently in the discovery phase. A technical conference was held on January 13, 2005. For additional information regarding this matter, see Note 18 of Notes to Consolidated Financial Statements.

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 Note

18 of Notes to Consolidated Financial Statements for a discussion of OG&E’s application to the OCC to approve amounts currently being charged to OG&E by Enogex for gas transportation and storage services.

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. (“Gathering”), 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 2004, Gathering connected 277 new producing wells, located in the Anadarko and Arkoma basins of Oklahoma and Arkansas, to its gathering systems. 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 Oklahoma, operating six natural gas processing plants with a total inlet capacity of 708 MMcfd. During 2002, Products had ownership interests in two other gas processing plants related to NuStar, which were sold in February 2003. 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. In 2004, approximately 279 million gallons of natural gas liquids were sold. Enogex continues to lease a small segment of gathering pipeline off of the Palo Duro pipeline system, referred to as the Northeast Lateral. This lease expires February 28, 2005, and, Enogex does not expect to renew the lease. At December 31, 2004, the net property, plant and equipment balance for Enogex’s gathering and processing business was approximately $301.0 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 these keep-whole processing arrangements was reduced through contract renegotiations and changes in the SOC provided by Enogex under the 2001 FERC Section 311 filing discussed previously. The SOC provides for a default processing fee in the event the natural gas liquids revenue less the associated fuel and shrinkage costs is 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, Enogex took active steps to reduce the amount of natural gas at the plant inlet to approximately 22 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 uses forward physical sales and financial hedges to capture these spreads.

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, access to markets and pricing. Enogex believes it will be able to continue to compete effectively.

With respect to the profitability of the natural gas processing industry generally, if the price of natural gas liquids falls without a corresponding decrease in the cost of natural gas, it may become uneconomical to extract certain natural gas liquids. This factor has had a significant adverse impact on the results of Enogex in the past, 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 natural gas liquids extracted by Products should also increase.

Marketing

General. Enogex’s commodity sales and services related to natural gas are conducted primarily through its subsidiary, OERI.

OERI is engaged in the business of natural gas marketing. OERI provides marketing services to Enogex for natural gas volumes purchased at the wellhead from customers. 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. At December 31, 2004, the net property, plant and equipment balance for Enogex’s marketing business was approximately $0.7 million.

OERI focuses on serving customers along the natural gas value chain, from producers to end-users, by purchasing natural gas from suppliers 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 primarily 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. Also, Enogex’s marketing business has expanded into the Gulf Coast, Rocky Mountain and East Coast markets to diversify its business.

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 2004, OERI’s average daily sales volumes grew from approximately 1.3 Bcf in 2003 to 1.8 Bcf 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 natural gas with major integrated oil companies, marketing affiliates of major interstate and intrastate pipelines, national and local natural gas brokers and 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, 2004, approximately 61.7 percent of OERI’s service volumes were with electric utilities, local gas distribution companies, pipelines and producers. The remaining 38.3 percent of service volumes were to marketers, municipals, cooperatives and industrials. At December 31, 2004, approximately 80.6 percent of the payment exposure was to companies having investment grade ratings with Standard & Poor’s Ratings Services (“Standard & Poor’s”) and approximately 0.3 percent having less than investment grade ratings. The

remaining 19.1 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 operations have been reported as discontinued operations in the Consolidated Financial Statements. The exploration and production activities were conducted through Enogex Exploration Corporation, which was formed in 1988 primarily to engage in the development and production of oil and natural gas. Exploration focused its drilling activity in Michigan and 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 (including technology) at Enogex. Other working 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 (through a combination of bank borrowings and commercial paper) and permanent financings. See “Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations – Liquidity and Capital Requirements” for a discussion of the Company’s capital requirements.

Capital Expenditures

The Company’s current 2005 to 2007 construction program includes continued investment in system and transmission upgrades that is part of the Company’s Customer Savings and Reliability Plan. OG&E has approximately 430 MWs of contracts with qualified cogeneration facilities and small power production producers’ (“QF contracts”) that will expire at the end of 2007, unless extended by OG&E. In addition, effective September 1, 2004, OG&E entered into a new 15-year power sales agreement for 120 MWs with PowerSmith Cogeneration Project, L.P. (“PowerSmith”). OG&E will continue reviewing all of the supply alternatives to these expiring QF contracts that minimize the total cost of generation to its customers, including exercising its options (if applicable) to extend these QF contracts at pre-determined rates. 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 “Item 7. Management’s Discussion and Analysis of Financial

Conditions and Results of Operations – Liquidity and Capital Requirements” for a discussion of the Company’s capital expenditures.

Pension and Postretirement Benefit Plans

During 2004 and 2003, the Company made contributions of approximately $69.0 million and $50.0 million, respectively, to ensure that the pension plan maintains an adequate funded status. During 2005, the Company plans to contribute approximately $37.4 million to the pension plan. See “Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations – Liquidity and Capital Requirements” for a discussion of the Company’s pension and postretirement benefit plans.

Future Sources of Financing

Management expects that internally generated funds, proceeds from the sales of common stock pursuant to the Company’s Automatic Dividend Reinvestment and Stock Purchase Plan and long and short-term debt will be adequate over the next three years to meet anticipated capital expenditures, operating needs, payment of dividends and maturities of long-term debt. As discussed below, the Company utilizes short-term borrowings (through a combination of bank borrowings and commercial paper) to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged.

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, 2005. At January 31, 2005, the Company’s short-term borrowings consisted of commercial paper.

ENVIRONMENTAL MATTERS

Approximately $7.0 million of the Company’s capital expenditures budgeted for 2005 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 $57.8 million during 2005, as compared to approximately $57.1 million in 2004. 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. See Note 17 of Notes to Consolidated Financial Statements for a discussion of environmental matters, including the impact of existing and proposed environmental legislation and regulations.

EMPLOYEES

The Company and its subsidiaries had 3,012 employees at December 31, 2004.

ACCESS TO SECURITIES AND EXCHANGE COMMISSION FILINGS

The Company’s web site address is www.oge.com. Through the Company’s web site under the heading “Investors”, “SEC Filings,” the Company makes available, free of charge, 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.

Item 2. Properties.

OG&E owns and operates an interconnected electric generation, transmission and distribution system, located in Oklahoma and western Arkansas, which includes nine generating stations with an aggregate capability of approximately 6,141 MWs. The following table sets forth information with respect to OG&E’s electric generating facilities, all of which are located in Oklahoma:

						2004	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	25.5%	506.0
	1GT	1971	Combustion-Turbine	Gas	Peaking	0.01%(B)	15.4
	2	1973	Steam-Turbine	Gas	Base Load	28.1%	507.6
	3	1975	Steam-Turbine	Gas/Oil	Base Load	25.4%	516.8	1,545.8

Muskogee	3	1956	Steam-Turbine	Gas	Base Load	6.6%	166.0
	4	1977	Steam-Turbine	Coal	Base Load	77.0%	500.5
	5	1978	Steam-Turbine	Coal	Base Load	70.4%	521.6
	6	1984	Steam-Turbine	Coal	Base Load	63.4%	499.0	1,687.1

Sooner	1	1979	Steam-Turbine	Coal	Base Load	80.8%	505.2
	2	1980	Steam-Turbine	Coal	Base Load	64.8%	513.8	1,019.0

Horseshoe	6	1958	Steam-Turbine	Gas/Oil	Base Load	17.8%	168.5
Lake	7	1963	Combined Cycle	Gas/Oil	Base Load	17.4%	234.0
	8	1969	Steam-Turbine	Gas	Base Load	7.8%	380.5
	9	2000	Combustion-Turbine	Gas	Peaking	9.1% (B)	45.5
	10	2000	Combustion-Turbine	Gas	Peaking	9.1% (B)	45.5	874.0

Mustang	1	1950	Steam-Turbine	Gas	Peaking	0.6% (B)	53.0
	2	1951	Steam-Turbine	Gas	Peaking	0.6% (B)	53.0
	3	1955	Steam-Turbine	Gas	Base Load	19.0%	117.5
	4	1959	Steam-Turbine	Gas	Base Load	17.6%	250.0
	5	1971	Combustion-Turbine	Gas/Jet Fuel	Peaking	0.6% (B)	60.0	533.5

Conoco	1	1991	Combustion-Turbine	Gas	Base Load	66.5%	31.5
	2	1991	Combustion-Turbine	Gas	Base Load	69.8%	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	0.1% (B)	12.0	12.0

McClain (D)	1	2001	Combined Cycle	Gas	Base Load	59.8%	406.8	406.8

Total Generating Capability (all stations)								6,140.7

	(A) 2004 Capacity Factor = 2004 Net Actual Generation / (2004 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 Southwest Power Pool reserve margins.
	(C) These units are currently inactive.
	(D) OG&E owns a 77 percent interest in the 520 MW McClain Plant.

At December 31, 2004, OG&E’s transmission system included: (i) 27 substations with a total capacity of approximately 7.2 million kilo Volt-Amps (“kVA”) and approximately 3,969 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) 339 substations with a total capacity of approximately 9.9 million kVA, 22,567 structure miles of overhead lines, 1,941 miles of underground conduit and 7,868 miles of underground conductors in Oklahoma; and (ii) 33 substations with a total capacity of approximately 1.5 million kVA, 1,889 structure miles of overhead lines, 239 miles of underground conduit and 459 miles of underground conductors in Arkansas.

At December 31, 2004, Enogex and its subsidiaries owned: (i) approximately 8,200 miles of intrastate gas gathering and transportation pipelines in Oklahoma and Texas; (ii) a 75 percent interest in NOARK, which consists of 931 miles of interstate gas gathering and transportation pipelines, located in eastern Oklahoma and Arkansas; (iii) two natural gas storage fields in Oklahoma operating at a working gas level of approximately 23 Bcf with an approximate withdrawal capability of 650 MMcfd and similar injection capability; and (iv) six operating natural gas processing plants with a total inlet capacity of 708 MMcfd, all located in Oklahoma. The following table sets forth information with respect to Enogex’s natural gas processing plants:

Processing Plant	Year Installed	Type of Plant	Fuel Capability	2004 Inlet Volumes (MMcfd)	2004 Inlet Capacity (MMcfd)
Calumet	1969	Lean Oil	Gas	110	250
Cox City	1994	Cryogenic Refrigeration	Gas	139	150
Harrah	1994	Cryogenic Refrigeration	Gas	23	38
Thomas	1981	Cryogenic Refrigeration	Gas	78	150
Canute	1996	Cryogenic Refrigeration	Gas	55	60
Wetumka	1983	Cryogenic Refrigeration	Gas	32	60
				437	708

During the three years ended December 31, 2004, the Company’s gross property, plant and equipment additions were approximately $839.9 million and gross retirements were approximately $250.0 million. These additions were provided by internally generated funds from operating cash flows, short-term borrowings (through a combination of bank borrowings and commercial paper) and permanent financings. The additions during this three-year period amounted to approximately 13.8 percent of total property, plant and equipment at December 31, 2004.

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 and in Notes 17 and 18 of Notes to Consolidated Financial Statements, management, after consultation with legal counsel, does not anticipate that liabilities arising out of currently pending or threatened lawsuits, claims and contingencies 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 sought 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 sought money damages against the Defendants under 62 O.S. 372 and 373. Plaintiffs alleged 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 demanded 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 and no action has been taken on this motion for seven years. 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 jurisdictional issues as ordered by the Court. A hearing on the defendants’ motions to dismiss for lack of subject matter jurisdiction, including public disclosure, original source and voluntary disclosure requirements is set for March 17 – 18, 2005.

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. A hearing on class certification issues is set for April 1, 2005.

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. A hearing on class certification issues is set for April 1, 2005.

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 Enogex Products Corporation, a subsidiary of Enogex, 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. Products sold its interest in Belvan in March 2002. The TCEQ’s proposed fine was approximately $0.1 million. Products has requested the TCEQ to issue the NOE in the permitted entity’s name and is waiting for this correction from the TCEQ. Pursuant to the Agreement of Sale and Purchase with the purchaser, Products’ may retain some liability for penalties that Belvan might incur from the NOE not to exceed approximately $0.1 million. 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”). NGSC failed and refused to repay the NGSC Loan.

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. In 2002, Enogex responded 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.

By order dated June 19, 2003, the Texas Court granted Enogex’s request for arbitration and ordered COOG, NGSC and Enogex to arbitration. The parties participated in the Oklahoma County arbitration in May 2004 and the arbitration panel rendered a decision in the Company’s favor for approximately $5.0 million related to the outstanding NGSC Loan on July 15, 2004 and this judgment is final.

In 2003, the Company and Enogex brought separate complaints against 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 each stated claims for (1) fraudulent transfer; (2) imposition of an equitable trust; and (3) breach of fiduciary duty. A jury trial was held from October 12 – 26, 2004. The case was submitted to the jury on October 25, 2004 and the jury ruled in favor of the Company and Enogex for approximately $6.6 million.

The individual defendants have filed a motion for new trial, which is currently pending before the Court. Also in the Texas case, on October 4, 2004, the plaintiffs filed a first amended petition seeking: (i) declaratory judgment based on collusion to impair collateral; (ii) gross negligence; and (iii) declaratory judgment and confirmation of certain aspects of the arbitration award. The plaintiffs have added a request for punitive damages. A motion to strike the amended petition or alternatively refer any remaining issues to arbitration under the parties’ agreement has been filed by Enogex and the Company. The plaintiffs filed a motion to dismiss Enogex from the suit which the court granted by order dated January 26, 2005. Enogex has objected to this ruling and has requested reconsideration of the court’s ruling to properly reserve the previous rulings in this matter. A determination relating to the jurisdiction by the Texas court of the Company is pending before the court.

The Company intends to continue to vigorously pursue its rights in conjunction with the remaining amounts owed under the judgments, plus interest.

7. Farmland Industries, Inc. (“Farmland”) voluntarily filed for Chapter 11 bankruptcy protection from creditors in 2002. Enogex provided gas transportation and supply services to Farmland, and was an unsecured creditor of Farmland. Enogex filed its proof of claim in 2003 for approximately $5.4 million. In April 2003, Enogex negotiated a settlement and received the agreed settlement amount of approximately $2.7 million during 2003 and 2004.

In addition, Farmland filed a dismissal of its preference claim it had asserted against Enogex. On July 8, 2004, Enogex received a distribution check from Farmland for approximately $0.5 million. The remainder of the settlement amount (approximately $0.3 million) was paid on July 30, 2004. These amounts are included in the $2.7 million discussed above. This case is now closed.

8. 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. This lawsuit was 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, the plaintiff alleged that OG&E breached the terms of several gas purchase contracts in amounts set forth in the contracts. In 2001, the district court rendered a verdict against OG&E in the amount of approximately $8.0 million, including pre-judgment interest and attorneys’ fees. OG&E filed an appeal and on May 18, 2004, the Court of Appeals issued an opinion reversing the judgment and remanding for a new trial. The appellate court found that the trial court committed reversible error in rejecting a portion of OG&E’s

interpretation of the commercial well provisions of the gas purchase contracts, and in failing to recognize issues of fact for the jury relating to OG&E’s contention regarding the correct initial reserve estimate on one of the natural gas wells, the Thiel No 1-9. In addition, the appellate court made rulings favorable to OG&E relating to the statutory measure of damages, the effect of line pressure adjustment provisions in the contracts, and the admission of certain hearsay evidence. The appellate court made rulings favorable to Kaiser-Francis relating to the effect of royalty payment obligations on the amount of damages, the effect of the amount of reserves owned by Kaiser-Francis in the wells on OG&E’s gas purchase obligation, the propriety of the award of prejudgment interest, and OG&E’s liability for the payment of gross production taxes pertaining to the damages awarded. The appellate court returned an issue relating to the alleged effect of Kaiser-Francis’s failure to make gas available for consideration by the trial court. Finally, the appellate court denied Kaiser-Francis’s request for appeal-related attorney’s fees and costs. On July 6, 2004, the Court of Appeals denied Kaiser-Francis’s motion for rehearing. Both parties filed petitions for certiorari with the Oklahoma Supreme Court for the review of those portions of the appellate court’s opinion unfavorable to each. The Oklahoma Supreme Court denied both parties’ petitions for certiorari on January 10, 2005. Once the mandate issues from the Oklahoma Supreme Court, this case will be sent back to the District Court of Grady County for further proceedings consistent with the decision of the Court of Appeals. In the Blaine County case, once the mandate issues from the Oklahoma Supreme Court in the Grady County appeal, the parties will have 30 days to notify the trial judge in the District Court of Blaine County that the appeal is over. At that time, the trial judge is likely to lift the stay that has been in effect since June 3, 2002. OG&E believes that, to the extent Plaintiff were successful on the merits of its claims of OG&E’s failure to take gas in either the Blaine County case or Grady County case, 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 recoverable in its electric rates.

9. National Steel Corporation (“National Steel”) voluntarily filed for Chapter 11 bankruptcy protection from creditors in 2002. OERI provided gas supply services to National Steel and was an unsecured creditor of National Steel. OERI filed its proof of claim on August 14, 2002 for approximately $0.9 million. This amount was originally fully reserved on OERI’s books; however, the receivable was subsequently determined to be uncollectible by OERI, and the reserved amount was reduced to zero. In March 2004, National Steel filed an adversary proceeding in the pending bankruptcy against OERI seeking the refund and return of payments made by National Steel to OERI during the 90 days preceding its bankruptcy filing totaling approximately $2.7 million. A settlement of the pending bankruptcy issues was reached in October 2004 between the parties wherein OERI agreed to not pursue its claim in the bankruptcy (approximately a $12,000 claim based on the filed bankruptcy plan) in exchange for National Steel dismissing the pending preference claim. The Company now considers this case to be closed.

10. OG&E vs. Terra Tech, LLC, District Court of Oklahoma County, State of Oklahoma. Case No. CJ-2004-149. OG&E filed suit against Terra Tech, LLC (“Terra Tech”) alleging that Terra Tech fraudulently, and in breach of contract, submitted invoices for work not performed and materials not used. Terra Tech filed an answer containing a counterclaim against OG&E. Defendant Terra Tech contends that OG&E’s actions constituted a breach of oral

contract and failure to pay for work performed in an amount in excess of $10,000. Defendant Terra Tech also seeks attorney fees. OG&E believes that recovery on the counterclaim by Terra Tech, if any, would be less than OG&E’s recovery against Terra Tech. Discovery has been served on the defendant and there have been no scheduling deadlines or trial date yet.

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 February 25, 2005:

Name	Age	Title
Steven E. Moore	58	Chairman of the Board, President and Chief Executive Officer
Peter B. Delaney	51	Executive Vice President and Chief Operating Officer
James R. Hatfield	47	Senior Vice President and Chief Financial Officer
Jack T. Coffman	61	Senior Vice President - Power Supply - OG&E
Steven R. Gerdes	48	Vice President - Utility Operations - OG&E
Melvin H. Perkins, Jr.	56	Vice President - Transmission - OG&E
Michael G. Davis	55	Vice President - Business Process
Donald R. Rowlett	47	Vice President and Controller
Deborah S. Fleming	49	Treasurer
Gary D. Huneryager	54	Internal Audit Officer
Carla D. Brockman	45	Corporate Secretary
Danny P. Harris	49	Vice President and Chief Operating Officer - Enogex Inc.
Jerry A. Peace	42	Chief Risk and Compliance Officer

No family relationship exists between any of the Executive Officers of the Registrant. Messrs. Moore, Delaney, Hatfield, Davis, Rowlett, Huneryager and Peace, 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 19, 2005.

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

Name

Business Experience

Donald R. Rowlett

2000 - Present:

Vice President and Controller

Deborah S. Fleming	2003 - Present:	Treasurer
	2000 - 2003:	Assistant Treasurer - Williams Cos. Inc.
	2000:	Director of Corporate Finance - Williams Cos. Inc. (energy company)
Gary D. Huneryager	2002 - Present:	Internal Audit Officer
	2001 - 2002:	Assistant Internal Audit Officer
	2000 - 2001:	Service Line Director (Business Process Outsourcing) - Arthur Andersen LLP
Carla D. Brockman	2002 - Present:	Corporate Secretary
	2002:	Assistant Corporate Secretary
	2000 - 2002:	Client Manager - Strategic Planning
Danny P. Harris	2001 - Present:	Vice President and Chief Operating Officer - Enogex Inc.
	2000 - 2001:	Director, Strategic Development - Enogex Inc.
	2000:	Manager, System Control - Enogex Inc.
Jerry A. Peace	2004 - Present:	Chief Risk and Compliance Officer
	2002 - 2004:	Chief Risk Officer
	2001 - 2002:	Director, Options Trading - Enogex Inc.
	2000 - 2001:	Director, Structured Services - Enogex Inc.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities.

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
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	$	0.332	5	$	26.7	0	$	23.0	3
Second Quarter		0.332	5		26.8	0		22.8	5
Third Quarter		0.332	5		26.4	8		24.1	0
Fourth Quarter		0.332	5		26.9	5		25.1	7


		Dividend					Price
2005		Paid			High			Low

First Quarter (through January 31)	$	0.332	5	$	26.6	7	$	25.1	5

The number of record holders of the Company’s Common Stock at January 31, 2005, was 30,965. The book value of the Company’s Common Stock at January 31, 2005, was $14.35.

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. 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, and from Enogex, on Enogex’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.

Issuer Purchases of Equity Securities

Except as noted below, the shares indicated below represent shares of Company common stock purchased on the open market by the trustee for the Company’s Stock Ownership and Retirement Savings Plan and reflect shares purchased with employee contributions as well as the portion attributable to the Company’s matching contributions.

Period	Total Number of Shares Purchased	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plan	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan
1/1/04 - 1/31/04	105,900	$ 24.06	N/A	N/A
2/1/04 - 2/29/04	16,400	$ 24.56	N/A	N/A
3/1/04 - 3/31/04	16,900	$ 26.01	N/A	N/A
4/1/04 - 4/30/04	138,900	$ 24.55	N/A	N/A
5/1/04 - 5/31/04	16,600	$ 24.24	N/A	N/A
6/1/04 - 6/30/04*	51,144	$ 24.39	N/A	N/A
7/1/04 - 7/31/04	90,000	$ 24.50	N/A	N/A
8/1/04 - 8/31/04	34,800	$ 24.77	N/A	N/A
9/1/04 - 9/30/04	26,700	$ 25.57	N/A	N/A
10/1/04 - 10/31/04	80,600	$ 25.47	N/A	N/A
11/1/04 - 11/30/04	54,800	$ 25.99	N/A	N/A
12/1/04 - 12/31/04	57,600	$ 26.26	N/A	N/A

* This month reflects the following transactions: (i) the surrender to the Company of 7,244 shares of common stock at an average price of $25.14 per share to satisfy tax withholding obligations in connection with the vesting of restricted stock issued to employees; and (ii) the purchase of 43,900 shares of common stock at an average price of $24.27 per share relating to the Company’s Stock Ownership and Retirement Savings Plan.
N/A - not applicable

Item 6. Selected Financial Data.

HISTORICAL DATA

		2004			2003			2002			2001			2000

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

Operating revenues	$	4,926	.6	$	3,779	.0	$	3,023	.9	$	3,064	.4	$	3,184	.4
Cost of goods sold		3,962	.7		2,846	.0		2,120	.3		2,185	.6		2,275	.3

Gross margin on revenues		963	.9		933	.0		903	.6		878	.8		909	.1
Other operating expenses		646	.4		626	.1		667	.9		607	.9		574	.5

Operating income		317	.5		306	.9		235	.7		270	.9		334	.6
Other income		12	.1		8	.1		3	.7		3	.1		4	.2
Other expense		5	.5		9	.0		4	.7		4	.2		3	.6
Net interest expense		90	.9		96	.7		109	.1		123	.0		129	.4
Income tax expense		80	.2		73	.7		44	.6		52	.9		72	.0

Income from continuing operations		153	.0		135	.6		81	.0		93	.9		133	.8
Income (loss) from discontinued
operations, net of tax		0	.5		(0	.4)		9	.8		6	.7		13	.2
Cumulative effect on prior years
of change in accounting principle,
net of tax of $3.4		-	--		(5	.4)		-	--		-	--		-	--

Net income	$	153	.5	$	129	.8	$	90	.8	$	100	.6	$	147	.0

Basic earnings (loss) per average
common share
Income from continuing operations	$	1.7	3	$	1.6	6	$	1.0	4	$	1.2	0	$	1.7	2
Income from discontinued
operations, net of tax		0.0	1		--	-		0.1	2		0.0	9		0.1	7
Loss from cumulative effect of
accounting change, net of tax		--	-		(0.0	7)		--	-		--	-		--	-

Net income	$	1.7	4	$	1.5	9	$	1.1	6	$	1.2	9	$	1.8	9

Diluted earnings (loss) per average
common share
Income from continuing operations	$	1.7	2	$	1.6	5	$	1.0	4	$	1.2	0	$	1.7	2
Income from discontinued
operations, net of tax		0.0	1		--	-		0.1	2		0.0	9		0.1	7
Loss from cumulative effect of
accounting change, net of tax		--	-		(0.0	7)		--	-		--	-		--	-

Net income	$	1.7	3	$	1.5	8	$	1.1	6	$	1.2	9	$	1.8	9

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

HISTORICAL DATA (Continued)

		2004			2003			2002			2001			2000

SELECTED FINANCIAL DATA
(In millions, except per share data)
Long-term debt	$	1,424	.1	$	1,436	.1	$	1,501	.9	$	1,526	.3	$	1,648	.5
Total assets	$	4,870	.3	$	4,584	.7	$	4,264	.9	$	4,118	.0	$	4,444	.6
CAPITALIZATION RATIOS (A)
Stockholders’ equity		47.44	%		45.56	%		39.58	%		40.54	%		39.23	%
Long-term debt		52.56	%		54.44	%		60.42	%		59.46	%		60.77	%
RATIO OF EARNINGS TO
FIXED CHARGES (B)
Ratio of earnings to fixed charges		3.2	9		3.0	6		2.0	8		2.1	0		2.4	5

(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 pre-tax income from continuing operations plus fixed charges, less allowance for borrowed funds used during construction and minority interest expense; 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
Results of Operations.

Introduction

Executive Overview

natural gas. The Company concluded that its existing business strategy of utilizing a diversified asset position was the proper course.

During 2004, the Company had several significant accomplishments including the completion of the acquisition of a 77 percent interest in the 520 megawatt (“MW”) NRG McClain Station (the “McClain Plant”) in July 2004, the completion of two revolving credit agreements totaling $550 million for the Company and OG&E in October 2004, improved financial performance at Enogex, improved financial flexibility associated with the reduction of the long-term debt balance at Enogex, such that Enogex began to contribute to funding the Company’s dividend which has been funded solely by OG&E in the past. Looking at 2005, OG&E expects to file a rate case during the second quarter of 2005 to recover, among other things, its investment in, and the operating expenses of, the McClain Plant and expects new approved rates to be in effect by January 2006. Also, during 2005, OG&E will work to advance its Customer Savings and Reliability Plan which provides for increased investment at the utility to improve reliability and meet load growth, replace infrastructure equipment and deploy newer technology that improves operational and environmental performance. Capacity payment savings from reduced cogeneration payments and fuel savings from the McClain Plant will be utilized to mitigate the price increases associated with these investments. For additional information regarding the McClain Plant acquisition and related regulatory matters, see Note 18 of Notes to Consolidated Financial Statements. During 2005, the Company will also be focused on controlling and managing operating and maintenance expenses and will continue to analyze the cost structure of the Company’s businesses ensuring consistency with the Company’s business model. At Enogex during 2005, the Company will focus on enhancing its financial position and the operations of its mid-continent assets as well as seeking to expand into other geographic areas outside of the mid-continent area. Overall, the Company has a strong commitment to train and retain talented personnel so that both the Company and its employees are successful in improving the financial and operating performance of the Company.

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 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, 2004, OG&E and Enogex represented approximately 63 percent and 36 percent, respectively, of the Company’s consolidated assets. The remaining one 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 many of the risk management practices, commercial skills and market information available from Enogex provide value to all of the Company’s businesses subject to the evolving federal regulations of the FERC in regard to the operations of the wholesale power market. 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.

OG&E has approximately 430 MWs of contracts with qualified cogeneration facilities and small power production producers’ (“QF contracts”) that will expire at the end of 2007, unless extended by OG&E. In addition, effective September 1, 2004, OG&E entered into a new 15-year power sales agreement for 120 MWs with PowerSmith Cogeneration Project, L.P. (“PowerSmith”). OG&E will continue reviewing all of the supply alternatives to these expiring QF contracts that minimize the total cost of generation to its customers, including exercising its options (if applicable) to extend these QF contracts at pre-determined rates. 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 completed significant sales transactions which have generated net sales proceeds of approximately $106.3 million, reduced debt by approximately $226.8 million or 30.6 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 and 2004 due to the performance improvement plan initiated in 2002 as well as an overall favorable business environment coupled with higher commodity prices. 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.

In addition, Enogex is seeking to diversify its gathering, processing and transportation businesses principally by expanding into other geographic areas that are complementary with the Company’s strategic capabilities. Enogex’s marketing business, which concentrates principally

on origination of physical sales of natural gas, has expanded into the Gulf Coast, Rocky Mountain and East Coast markets.

In addition to these ongoing efforts, in 2003 Enogex began a major upgrade of its information systems that is expected to be substantially completed during the second and third quarters of 2005. Enogex 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 better determine the earnings potential of its various assets and service offerings.

Forward-Looking Statements

Except for the historical statements contained herein, the matters discussed in the following discussion and analysis, including the discussion in “2005 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 rating 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; federal or state legislation and regulatory decisions (the proceeding currently pending before the OCC related to OG&E’s recovery of the costs billed to it by Enogex for gas transportation and storage services) and initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the Company’s markets; environmental laws and regulations that may impact the Company’s operations; changes in accounting standards, rules or guidelines; creditworthiness of suppliers, customers and other contractual parties; the higher degree of risk associated with the Company’s nonregulated business compared with the Company’s regulated utility business; and other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission.

Overview

Summary of Operating Results

2004 compared to 2003. The Company reported net income of approximately $153.5 million, or $1.73 per diluted share, as compared to approximately $129.8 million, or $1.58 per

diluted share, for the years ended December 31, 2004 and 2003, respectively. The increase in net income during 2004 as compared to 2003 was primarily due to:

higher gross margins on revenues (“gross margin”) in Enogex’s gathering and processing business primarily due to an overall favorable business environment coupled with higher commodity prices;

gains from asset sales; and

lower net interest expense.

These increases to net income were partially offset by:

lower gross margins at OG&E due to cooler weather in its service territory; and

higher operating expenses.

OG&E reported net income of approximately $107.6 million, or $1.22 per diluted share of the Company’s common stock, as compared to approximately $115.4 million, or $1.41 per diluted share, for the years ended December 31, 2004 and 2003, respectively. The decrease in net income at OG&E during 2004 as compared to 2003 is described in more detail below.

Enogex’s operations, including discontinued operations, reported net income of approximately $60.7 million, or $0.69 per diluted share of the Company’s common stock, as compared to approximately $26.9 million, or $0.33 per diluted share, for the years ended December 31, 2004 and 2003, respectively. The increase in net income at Enogex during 2004 as compared to 2003 is described in more detail below.

The results of the holding company reflect a loss of approximately $0.18 per diluted share and $0.16 per diluted share, respectively, for the years ended December 31, 2004 and 2003. The increased loss is primarily due to an increase in net interest expense due to a write off of approximately $5.9 million of unamortized debt issuance costs for the trust preferred securities which were redeemed at par on October 15, 2004, partially offset by an increase in other income.

The Company’s results of operations for the years ended December 31, 2004 and 2003, respectively, include income of approximately $0.5 million, or $0.01 per diluted share, and a loss of approximately $0.4 million, or less than $0.01 per diluted share, from the discontinued operations discussed below. See “Results of Operations – Enogex – Discontinued Operations” for a further discussion.

Earnings per share in 2004 as compared to 2003 were affected by a higher amount of common stock outstanding from the Company’s equity issuance in August 2003 and the issuance of common stock in 2003 and 2004 pursuant to the Company’s Automatic Dividend Reinvestment and Stock Purchase Plan (“DRIP/DSPP”).

2003 compared to 2002. The Company reported net income of approximately $129.8 million, or $1.58 per diluted share, as compared to approximately $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 at Enogex;

higher gross margins in all of Enogex’s businesses;

growth in OG&E’s service territory; and

lower interest expenses at the holding company.

These increases to net income were partially offset by:

lower gross margins at OG&E due to lower electric rates as a result of the $25 million electric reduction that went into effect in Oklahoma on January 6, 2003.

OG&E reported net income of approximately $115.4 million, or $1.41 per diluted share, as compared to approximately $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 is described in more detail below.

Enogex’s operations, including discontinued operations, reported net income of approximately $26.9 million, or $0.33 per diluted share, as compared to a net loss of approximately $21.7 million, or $0.28 per diluted share, for the years ended December 31, 2003 and 2002, respectively. This improvement during 2003 as compared to 2002 is described in more detail below.

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

The Company’s results of operations for the years ended December 31, 2003 and 2002, respectively, include a loss of approximately $0.4 million, or less than $0.01 per diluted share, and income of approximately $9.8 million, or $0.12 per diluted share, from the discontinued operations discussed below. See “Results of Operations – Enogex – Discontinued Operations” for a further discussion.

Regulatory Matters and Plant Acquisition

borrowings from the Company. On August 4, 2004, OG&E issued $140.0 million of long-term debt to replace these short-term borrowings. Also, on August 9, 2004, the Company made a capital contribution to OG&E of approximately $153.0 million. For additional information regarding the McClain Plant acquisition and related regulatory matters, see Note 18 of Notes to Consolidated Financial Statements.

2005 Outlook

For 2005, the Company’s earnings guidance is $137 million to $147 million of net income, or $1.50 to $1.60 per share, assuming approximately 90.5 million average diluted shares outstanding. The 2005 outlook includes earnings guidance of $106 million to $110 million, or $1.17 to $1.22 per share, at OG&E and $39 million to $43 million, or $0.43 to $0.48 per share, at Enogex, while earnings guidance at the holding company is a loss between $6 million and $8 million, or $0.07 to $0.09 per share. During 2005, the Company expects cash flow from operations of between $323 million and $332 million. In 2005, OG&E plans to increase capital expenditures for electric system reliability upgrades. Additionally, funding for the Company’s pension plan is expected to be approximately $37.4 million in 2005. Expected 2005 net income assumes a 38.7 percent effective tax rate.

For 2005, OG&E earnings guidance is $106 million to $110 million, or $1.17 to $1.22 per share. OG&E assumes that margin growth approximating one to two percent will be more than offset by increased operating expenses and higher interest costs associated with the acquisition of the McClain Plant and capital expenditures for investment in OG&E’s generation, transmission and distribution system. OG&E expects to increase capital expenditures to approximately $248 million for electric system expansion and reliability upgrades in 2005. Key factors affecting OG&E’s 2005 net income will be the result of pending regulatory proceedings, weather, OG&E’s ability to control operating and maintenance expenses and customer growth. 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. The earnings guidance further assumes no change in base rates and normal weather. OG&E expects to file a rate case during the second quarter of 2005 to recover, among other things, its investment in, and the operating expenses of, the McClain Plant and expects new approved rates to be in effect by January 2006. The earnings guidance also assumes a recovery of the costs associated with the Enogex natural gas transportation and storage services at a level consistent with a recent recommendation by the administrative law judge overseeing this proceeding. On October 22, 2004, the administrative law judge overseeing the proceeding recommended approximately $41.9 million annual demand fee recovery with OG&E refunding to its customers any amounts collected in excess of this amount. If this recommendation is ultimately accepted, OG&E believes its refund obligation would be approximately $6.9 million at December 31, 2004, which the Company does not believe is material in light of previously established reserves. An OCC order in this case is expected in the first quarter of 2005. There can be no guarantee that the OCC will approve the $41.9 million annual demand fee recovery recommended by the administrative law judge. See Note 18 of Notes to Consolidated Financial Statements for a further discussion of this matter.

For 2005, Enogex earnings guidance is $39 million to $43 million, or $0.43 to $0.48 per share. Enogex manages its operations along three related businesses: transportation and storage;

gathering and processing; and marketing. In 2005, these businesses are assumed to produce a gross margin of approximately $269 million, down from $301 million in 2004. The Company expects approximately 46 percent of Enogex’s gross margin during 2005 to be generated from its transportation and storage business as compared to 46 percent in 2004. Approximately 88 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 the completion in 2004 of the over recovery of prior year’s under recovered fuel. The Company expects its gathering and processing business to contribute approximately 48 percent of Enogex’s gross margin in 2005 as compared to 46 percent in 2004. Revenues in gathering and processing are expected to increase in 2005 primarily due to continued efforts to increase margins from the negotiation of both new contracts and replacement contracts. Volumes are expected to remain flat from 2004. The Company has assumed lower commodity spreads of $1.53 per Million British thermal unit (“MMBtu”) in 2005 as compared to $2.45 per MMBtu in 2004 and has assumed lower average natural gas liquids prices of $0.71 per gallon in 2005 as compared to $0.72 per gallon in 2004. The Company also assumes 242 new well connects in its gathering and processing business in 2005. While operating improvements allowed Enogex to capture significant value in a favorable commodity environment, the commodity and well connect assumptions budgeted for 2005 reflect commodity prices that are not as robust as those experienced in 2004. The Company expects its marketing business to contribute approximately six percent of Enogex’s gross margin in 2005 as compared to eight percent in 2004. Gross margins in marketing are expected to decrease in 2005 primarily due to 2004 gross margins being above expectations and its anticipated loss of approximately $3.0 million due to its position on the Cheyenne Plains Pipeline as explained in Note 17 of Notes to Consolidated Financial Statements. Enogex also expects approximately $5.1 million in lower operating expenses in 2005 due to not having an $8.6 million impairment charge that was recorded in the third quarter of 2004. In addition, Enogex also expects approximately $1.2 million in lower net interest expense from the retirement of long-term debt in 2004 and 2005. Key factors affecting Enogex’s 2005 net income will be new well connections, natural gas and natural gas liquids prices and operating costs. Enogex expects to continue to evaluate the strategic fit and financial performance of each of its assets in an effort to ensure a proper economic allocation of resources. The magnitude and timing of any potential impairment or gain on the disposition of any assets have not been determined or included in the 2005 earnings guidance.

For 2005, earnings guidance at the holding company, which primarily has interest expense but no operating revenue, is a loss between $6 million and $8 million, or $0.07 to $0.09 per share. The decrease in the loss as compared to 2004 is primarily due to lower interest expenses associated with the redemption of $200 million of trust preferred securities on October 15, 2004.

Dividend Policy

The Company’s dividend policy is reviewed by the Board of Directors at least annually 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 normalized 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 2005, 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

The following discussion and analysis presents factors which affected the Company’s consolidated results of operations for the years ended December 31, 2004, 2003 and 2002 and the Company’s consolidated financial position at December 31, 2004 and 2003. 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, 2004, 2003 and 2002 in the Consolidated Financial Statements.


(In millions, except per share data)		2004			2003			2002

Operating income	$	317.	5	$	306.	9	$	235.	7
Net income	$	153.	5	$	129.	8	$	90.	8
Basic average common shares outstanding		88.	0		81.	8		78.	1
Diluted average common shares outstanding		88.	5		82.	1		78.	2
Basic earnings per average common share	$	1.7	4	$	1.5	9	$	1.1	6
Diluted earnings per average common share	$	1.7	3	$	1.5	8	$	1.1	6
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 2004, 2003 and 2002 operating income are pre-tax impairment charges of approximately $7.8 million, $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 (Loss) by Business Segment

(In millions)		2004			2003			2002

OG&E (Electric Utility)	$	192.	0	$	216.	2	$	239.	1
Enogex (Natural Gas Pipeline) (A)		126.	6 (B)		91.	2 (B)		(3.	0) (B)
Other Operations (C)		(1.	1)		(0.	5)		(0.	4)

Consolidated operating income	$	317	.5	$	306	.9	$	235	.7

(A) Excludes discontinued operations. See “Enogex - Discontinued Operations” for a further discussion.
(B) After recording pre-tax impairment charges of approximately $7.8 million, $9.2 million and $48.3 million 2004, 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

(Dollars in millions)	2004			2003			2002
Operating revenues	$	1,578	.1	$	1,517	.1	$	1,388	.0
Fuel		645	.4		544	.5		435	.8
Purchased power		269	.1		292	.9		260	.0

Gross margin on revenues		663	.6		679	.7		692	.2
Other operating and maintenance		301	.9		294	.8		282	.9
Depreciation		122	.7		121	.8		123	.1
Taxes other than income		47	.0		46	.9		47	.1

Operating income	$	192	.0	$	216	.2	$	239	.1

Operating revenues by classification Residential	$	611	.4	$	601	.4	$	557	.6
Commercial		389	.9		372	.5		346	.9
Industrial		326	.7		293	.4		258	.6
Public authorities		158	.5		146	.1		135	.5
Sales for resale		57	.0		57	.7		48	.2
Provision for refund on gas transportation and storage case		(6	.9)		-	--		-	--
Other		40	.7		41	.9		34	.9

System sales revenues		1,577	.3		1,513	.0		1,381	.7
Off-system sales revenues		0	.8		4	.1		6	.3

Total operating revenues	$	1,578	.1	$	1,517	.1	$	1,388	.0

MWH (A) sales by classification (in millions) Residential		7	.9		8	.2		8	.0
Commercial		5	.7		5	.8		5	.8
Industrial		7	.0		6	.8		6	.6
Public authorities		2	.7		2	.7		2	.7
Sales for resale		1	.4		1	.5		1	.5

System sales		24	.7		25	.0		24	.6
Off-system sales		0	.1		0	.1		0	.3

Total sales		24	.8		25	.1		24	.9

Number of customers		735,0	08		725,4	70		718,5	13

Average cost of energy per KWH (B) - cents Fuel		2.8	87		2.4	54		1.8	97
Fuel and purchased power		3.4	36		3.1	28		2.6	14

Degree days (C) Heating
Actual		3,1	14		3,4	88		3,7	53
Normal		3,6	50		3,6	31		3,6	34
Cooling
Actual		1,8	39		1,8	98		1,8	47
Normal		1,9	11		1,9	11		1,9	11

(A)

Megawatt-hour.

(B)

Kilowatt-hour.

(C)

Degree days are calculated as follows: The high and low degrees of a particular day are added together and then averaged. If the calculated average is above 65 degrees, then the difference between the calculated average and 65 is expressed as cooling degree days, with each degree of difference equaling one cooling degree day. If the calculated average is below 65 degrees, then the difference between the calculated average and 65 is expressed as heating degree days, with each degree of difference equaling one heating degree day. The daily calculations are then totaled for the particular reporting period.

2004 compared to 2003. OG&E’s operating income decreased approximately $24.2 million or 11.2 percent in 2004 as compared to 2003. The decrease in operating income was primarily attributable to:

lower gross margins due to cooler weather in OG&E’s service territory;

lower margins related to sales to wholesale customers;

the timing of fuel recoveries; and

higher operating expenses.

These decreases in operating income were partially offset by:

growth in OG&E’s service territory.

Gross margin, which is operating revenues less cost of goods sold, was approximately $663.6 million in 2004 as compared to approximately $679.7 million in 2003, a decrease of approximately $16.1 million or 2.4 percent. The gross margin decreased primarily due to:

cooler weather in OG&E’s service territory which reduced the gross margin by approximately $15.7 million;

lower margins related to sales to wholesale customers primarily resulting from reduced sales of power under a new wholesale contract with an existing customer which reduced the gross margin by approximately $3.2 million; and

the timing of fuel recoveries which decreased the gross margin by approximately $1.7 million.

These decreases in gross margin were partially offset by:

growth in OG&E’s service territory which increased the gross margin by approximately $4.9 million.

Cost of goods sold for OG&E consists of fuel used in electric generation and purchased power. Fuel expense was approximately $645.4 million in 2004 as compared to approximately $544.5 million in 2003, an increase of approximately $100.9 million or 18.5 percent. The increase was primarily due to an increase in the average cost of fuel per kwh, primarily due to higher natural gas prices despite lower mwh sales. 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 2004, OG&E’s fuel mix was 70 percent coal and 30 percent natural gas as compared to 77 percent coal and 23 percent natural gas in 2003. Though OG&E has a higher installed capability of generation from natural gas units of 59 percent, it has been more economical to generate electricity for our customers with lower priced coal. Purchased power costs were approximately $269.1 million in 2004 as compared to approximately $292.9 million in 2003, a decrease of approximately $23.8 million or 8.1 percent. The decrease was primarily due to OG&E’s acquisition of the McClain Plant in July 2004 and the termination of power purchase contracts in December 2003 and August 2004.

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, Arkansas and the FERC, in each jurisdiction 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 for a discussion of current proceedings at the OCC regarding OG&E’s gas transportation and storage contract with Enogex.

Other operating and maintenance expenses were approximately $301.9 million in 2004 as compared to approximately $294.8 million in 2003, an increase of approximately $7.1 million or 2.4 percent. The increase in other operating and maintenance expenses was primarily due to:

increased outside services expense of approximately $17.9 million, primarily due to higher expenses for infrastructure projects in the fourth quarter of 2004, many of which were postponed from earlier in 2004;

increased materials and supplies expense of approximately $1.8 million; and

increased liability insurance expense of approximately $0.9 million due to increased insurance premiums.

These increases in other operating and maintenance expenses were partially offset by:

lower salaries and wages expense of approximately $6.8 million and lower pension and benefit expense of approximately $6.6 million primarily due to more projects on which the costs are capitalized and are not being expensed currently.

Depreciation expense was approximately $122.7 million in 2004 as compared to approximately $121.8 million in 2003, an increase of approximately $0.9 million or 0.7 percent, primarily due to a higher level of depreciable plant. Also, another factor affecting 2004 results was an overall increase of approximately $3.8 million in the reserves related to litigation.

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 sales to other utilities and power marketers (“off-system sales”); and

higher other operating and maintenance expenses.

These decreases in operating income were partially offset by:

growth in OG&E’s service territory.

Gross margin 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 decreased primarily 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, which reduced the gross margin by approximately $24.8 million;

weaker weather-related demand which reduced the gross margin by approximately $2.0 million; and

lower off-system sales which reduced 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 and the market for off-system sales.

These decreases in gross margin were partially offset by:

growth in OG&E’s service territory which increased the gross margin by approximately $17.5 million.

Fuel expense was approximately $544.5 million in 2003 as compared to approximately $435.8 million in 2002, an increase of approximately $108.7 million or 24.9 percent. The increase was due to a 29.4 percent increase in the average cost of fuel per kwh, primarily due to higher natural gas prices and higher mwh sales. 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. Purchased power costs were approximately $292.9 million in 2003 as compared to approximately $260.0 million in 2002, an increase of approximately $32.9 million or 12.7 percent. The increase was primarily due to approximately a 28.2 percent increase in the volume of energy purchased primarily due to economic purchases.

Other operating and maintenance expenses were approximately $294.8 million in 2003 as compared to approximately $282.9 million in 2002, an increase of approximately $11.9 million or 4.2 percent. The increase in other operating and maintenance expenses was primarily due to:

higher pension and benefit expenses of approximately $10.7 million due to the general upward trend in these costs; and

costs of approximately $5.4 million incurred during the first quarter of 2002 in connection with the severe January 2002 ice storm being reported as a regulatory asset as these 2002 expenditures, incurred by field service personnel, would normally have been charged to maintenance expenses in 2002.

These increases in other operating and maintenance expenses were partially offset by:

lower uncollectibles expense of approximately $3.5 million due to improved collection efforts.

Depreciation expense was approximately $121.8 million in 2003 as compared to approximately $123.1 million in 2002, a decrease of approximately $1.3 million or 1.1 percent, primarily due to a change made in the depreciation rate of production plant in 2003 as required by the settlement of OG&E’s rate case in November 2002 (the “Settlement Agreement”).

Enogex – Continuing Operations

(Dollars in millions)		2004			2003			2002

Operating revenues	$	3,443.	9	$	2,327.	8	$	1,684.	0
Gas and electricity purchased for resale (A)		3,054.	3		2,019.	1		1,402.	1
Natural gas purchases - other		88.	6		55.	4		70.	5

Gross margin on revenues		301.	0		253.	3		211.	4
Other operating and maintenance		101.	5		91.	2		101.	1
Depreciation		47.	6		44.	2		49.	3
Impairment of assets		7.	8		9.	2		48.	3
Taxes other than income		17.	5		17.	5		15.	7

Operating income (loss)	$	126.	6	$	91.	2	$	(3.	0)

New well connects		27	7		23	2		16	6

Gathered volumes - TBtu/d (B)		1.0	1		0.9	9		1.0	6
Incremental transportation volumes - TBtu/d		0.5	1		0.4	4		0.4	9

Total throughput volumes - TBtu/d		1.5	2		1.4	3		1.5	5

Natural gas processed - Mmcf/d (C)		50	2		41	4		45	5

Natural gas liquids sold (keep whole) - million gallons		26	3		20	7		28	5
Natural gas liquids sold (POL and fixed-fee) - million gallons		1	6		1	8		2	2

Total natural gas liquids sold - million gallons		27	9		22	5		30	7

Average sales price per gallon	$	0.72	0	$	0.59	5	$	0.40	6

(A) OGE Energy Resources, Inc. (“OERI”) exited the power marketing business during the first quarter of 2004. (B) Trillion British thermal units per day. (C) Million cubic feet per day.

2004 compared to 2003. Enogex’s operating income in 2004 increased approximately $35.4 million or 38.8 percent as compared to 2003. The increase in operating income was primarily attributable to higher gross margins in Enogex’s gathering and processing business primarily due to an overall favorable business environment coupled with higher commodity prices and revenue improvements generated from the negotiation of both new contracts and replacement contracts at better terms. These increases were partially offset by higher operating expenses.

Enogex sold its interest in NuStar during the first quarter of 2003; accordingly this is reported as discontinued operations for the years ended December 31, 2004, 2003 and 2002 in the Consolidated Financial Statements. See “Enogex – Discontinued Operations” for a further discussion.

Transportation and storage contributed approximately $137.4 million of Enogex’s gross margin in 2004 as compared to approximately $138.1 million in 2003, a decrease of approximately $0.7 million or 0.5 percent. The gross margin decreased primarily due to:

certain contractual revenues recorded in transportation and storage in 2003 being recorded in gathering and processing in 2004 which reduced the gross margin by approximately $12.7 million;

mark-to-market timing losses on natural gas storage inventory which reduced the gross margin by approximately $3.7 million;

the Calpine Energy Services, L.P. (“Calpine Energy”) settlement in 2003 which resulted in a one-time increase of approximately $2.0 million to the gross margin in 2003;

the net change between fuel retained and fuel consumed which decreased the gross margin by approximately $1.7 million; and

third party pipeline imbalances which decreased the gross margin by approximately $1.0 million.

These decreases in the transportation and storage gross margin were partially offset by:

higher purchases and sales activity due to Enogex being more active in the marketplace which increased the gross margin by approximately $6.6 million;

higher interruptible revenues and higher crosshaul revenues due to an increase in interruptible contract volumes and increased crosshaul margins and volumes which increased the gross margin by approximately $6.3 million;

higher transportation and storage revenues in 2004 primarily due to the additional demand fees and overrun charges from the transportation and storage contract with OG&E, which was effective May 2003, which increased the gross margin by approximately $4.9 million; and

an amended intercompany natural gas purchase contract which increased the gross margin by approximately $2.5 million.

Gathering and processing contributed approximately $139.8 million of Enogex’s gross margin in 2004 as compared to approximately $91.3 million in 2003, an increase of approximately $48.5 million or 53.1 percent. Gathering gross margins increased approximately $27.5 million in 2004 as compared to 2003 primarily due to:

the change in 2004 discussed above of recording certain contractual revenues in gathering and processing rather than in transportation and storage, which increased the gross margin by approximately $12.7 million;

revenue improvements generated from an overall favorable business environment coupled with higher commodity prices and the negotiation of both new contracts and replacement contracts at better terms; and

an increase in the number of well connects and the volumes of natural gas gathered.

Processing gross margins increased approximately $21.0 million in 2004 as compared to 2003 primarily due to:

increased keep-whole, percent of liquids and condensate margins due to favorable commodity prices and higher keep-whole volumes which increased the gross margin by approximately $21.9 million; and

an expense reallocation of compressor fuel (from processing in 2003 to transportation and storage in 2004) which increased the gross margin by approximately $1.3 million.

Marketing contributed approximately $23.8 million of Enogex’s gross margin in 2004 as compared to approximately $23.9 million in 2003, a decrease of approximately $0.1 million or 0.4 percent. The gross margin decreased primarily due to:

lower gains from the sale of natural gas in storage in 2004 of approximately $12.1 million primarily due to Enogex recording approximately 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 recording this loss as a reduction of the gross margin. The cumulative effect of a change in accounting principle was the result of accounting for certain energy contracts and natural gas in storage at the lower of cost or market rather than on a mark-to-market basis (see Note 2 of Notes to Consolidated Financial Statements for a further discussion);

mark-to-market timing losses on natural gas storage inventory due to different pricing environments during 2004 as compared to 2003 which reduced the gross margin by approximately $2.2 million; and

exiting the power marketing business in 2004 which reduced the gross margin by approximately $1.1 million.

These decreases in the marketing gross margin were partially offset by:

new business activity in the marketing portfolio which increased the gross margin by approximately $12.2 million; and

lower demand fees expense for storage services due to establishing new rates for the new storage season which began April 1 which increased the gross margin by approximately $3.4 million.

Enogex’s other operating and maintenance expenses were approximately $101.5 million in 2004 as compared to approximately $91.2 million in 2003, an increase of approximately $10.3 million or 11.3 percent. The increase in other operating and maintenance expenses was primarily due to:

higher payroll, benefit and pension expenses of approximately $4.1 million due to hiring new employees, payment of overtime and salary increases;

higher outside service costs of approximately $2.4 million related to work performed to maintain the integrity and safety of Enogex’s pipeline;

higher materials and supplies expense of approximately $2.3 million for repairs and maintenance of systems; and

higher uncollectibles expense of approximately $1.4 million due to miscellaneous accounts receivable items becoming over 180 days old.

Depreciation expense was approximately $47.6 million in 2004 as compared to approximately $44.2 million in 2003, an increase of approximately $3.4 million or 7.7 percent. The increase was primarily due to a higher level of depreciable plant as the implementation of an information system was completed during the second quarter of 2004 in addition to accelerated depreciation recorded during the fourth quarter of 2004 related to the impairment involving four of Enogex’s non-contiguous pipeline asset segments.

Impairment of assets was approximately $7.8 million in 2004 as compared to approximately $9.2 million in 2003, a decrease of approximately $1.4 million or 15.2 percent. During September 2004, Enogex received notification from a customer that a transportation agreement involving four of Enogex’s non-contiguous pipeline asset segments located in West Texas and used to serve the customer’s power plants would be terminated effective December 31, 2004. In connection with the preparation of the third quarter 2004 financial statements, Enogex performed an evaluation on these assets and concluded that an impairment charge needed to be recorded. The primary reason for this determination was that these four pipeline asset segments were originally built for the specific purpose of providing gas transmission service to this customers’ four power plants that have been or are in the process of being shut down, and, as a result, other alternative commercial uses for these facilities are considered unlikely. Also, in 2004, the Company reclassified several compressors and processing plants that were previously classified as assets held for sale to assets held and used. This decision was based on the fact these assets are no longer being marketed and the Company believes the value of the future benefit of holding these assets exceeds the current fair market value. As a result, in accordance with Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long–Lived Assets,” the Company determined the fair value of these assets based on a third party valuation of the assets and, as a result, the Company recorded a net gain of approximately $0.8 million during 2004 related to reclassifying these assets from assets held for sale to assets held and used, which was recorded as a credit to Impairment of Assets on the Consolidated Statements of Income. During 2003, an evaluation of the horsepower of compression needed to meet the operational requirements of the Company’s gathering and transmission system was performed based on the then current market conditions. The review identified compressor equipment that could be removed from the system and a pre-tax impairment loss of approximately $9.2 million was recorded in the fourth quarter of 2003 to recognize the difference between the carrying value of these units and their fair value expected to be realized in a disposal. The impairment recorded in the fourth quarter of 2003 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.

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

OR