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

FORM 10-Q

(Mark One)

[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2004

[ ]	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)

405-553-3000
(Registrant’s telephone number, including area code)

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 whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).
Yes X No

As of April 30, 2004, 87,621,312 shares of common stock, par value $0.01 per share, were outstanding.

OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2004

Part I - FINANCIAL INFORMATION	Page
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Balance Sheets	1
Condensed Consolidated Statements of Operations	3
Condensed Consolidated Statements of Cash Flows	4
Notes to Condensed Consolidated Financial Statements	5
Item 2. Management’s Discussion and Analysis of Financial Condition
and Results of Operations	32
Item 3. Quantitative and Qualitative Disclosures About Market Risk	56
Item 4. Controls and Procedures	57
Part II - OTHER INFORMATION
Item 1. Legal Proceedings	58
Item 6. Exhibits and Reports on Form 8-K	58
Signature	60

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

(In millions)	March 31, 2004			December 31, 2003
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	149	.6	$	245	.6
Accounts receivable, less reserve of $3.3 and $4.2, respectively		317	.4		350	.2
Accrued unbilled revenues		37	.4		38	.0
Fuel inventories		64	.9		163	.3
Materials and supplies, at average cost		48	.7		45	.1
Price risk management		87	.0		61	.3
Gas imbalance		72	.7		70	.0
Accumulated deferred tax assets		9	.9		9	.4
Fuel clause under recoveries		0	.4		4	.0
Other		8	.0		21	.5

Total current assets		796	.0		1,008	.4


OTHER PROPERTY AND INVESTMENTS, at cost		38	.3		34	.7


PROPERTY, PLANT AND EQUIPMENT
In service		5,633	.7		5,596	.3
Construction work in progress		64	.5		56	.7
Other		12	.9		15	.0

Total property, plant and equipment		5,711	.1		5,668	.0
Less accumulated depreciation		2,389	.6		2,358	.5

Net property, plant and equipment		3,321	.5		3,309	.5


DEFERRED CHARGES AND OTHER ASSETS
Recoverable take or pay gas charges		32	.5		32	.5
Income taxes recoverable from customers, net		31	.4		31	.6
Intangible asset - unamortized prior service cost		40	.2		40	.2
Prepaid benefit obligation		47	.7		55	.7
Price risk management		25	.4		13	.5
Other		58	.9		58	.6

Total deferred charges and other assets		236	.1		232	.1


TOTAL ASSETS	$	4,391	.9	$	4,584	.7

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.

OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)
(Unaudited)

(In millions)	March 31, 2004			December 31, 2003
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Short-term debt	$	-	--	$	202	.5
Accounts payable		286	.5		280	.2
Dividends payable		29	.1		29	.1
Customers’ deposits		41	.6		41	.6
Accrued taxes		7	.5		18	.7
Accrued interest		23	.7		30	.7
Accrued interest - unconsolidated affiliate		3	.5		3	.5
Tax collections payable		7	.4		7	.9
Accrued vacation		17	.9		17	.2
Long-term debt due within one year		63	.1		52	.1
Non-recourse debt of joint venture		1	.2		1	.2
Price risk management		76	.1		46	.9
Gas imbalance		28	.1		22	.5
Fuel clause over recoveries		32	.8		32	.4
Other		32	.5		41	.2

Total current liabilities		651	.0		827	.7

LONG-TERM DEBT
Long-term debt		1,174	.3		1,189	.7
Non-recourse debt of joint venture		40	.2		40	.2
Long-term debt - unconsolidated affiliate		206	.2		206	.2

Total long-term debt		1,420	.7		1,436	.1

DEFERRED CREDITS AND OTHER LIABILITIES
Accrued pension and benefit obligations		171	.4		167	.4
Accumulated deferred income taxes		748	.3		747	.3
Accumulated deferred investment tax credits		40	.7		42	.0
Accrued removal obligations, net		120	.1		116	.3
Price risk management		8	.7		4	.5
Provision for payments of take or pay gas		32	.5		32	.5
Other		11	.7		9	.3

Total deferred credits and other liabilities		1,133	.4		1,119	.3

STOCKHOLDERS’ EQUITY
Common stockholders’ equity		640	.7		636	.1
Retained earnings		604	.9		623	.9
Accumulated other comprehensive loss, net of tax		(58	.8)		(58	.4)

Total stockholders’ equity		1,186	.8		1,201	.6


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	4,391	.9	$	4,584	.7

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.

OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

	Three Months Ended March 31,
(In millions, except per share data)		2004			2003

OPERATING REVENUES
Electric Utility operating revenues	$	304	.3	$	332	.6
Natural Gas Pipeline operating revenues		737	.4		717	.6

Total operating revenues		1,041	.7		1,050	.2
COST OF GOODS SOLD
Electric Utility cost of goods sold		171	.4		203	.9
Natural Gas Pipeline cost of goods sold		683	.5		664	.5

Total cost of goods sold		854	.9		868	.4

Gross margin on revenues		186	.8		181	.8
Other operation and maintenance		91	.1		90	.3
Depreciation		46	.0		46	.6
Taxes other than income		18	.7		17	.2

OPERATING INCOME		31	.0		27	.7

OTHER INCOME (EXPENSE)
Other income		2	.8		6	.1
Other expense		(1	.5)		(2	.9)

Net other income		1	.3		3	.2

INTEREST INCOME (EXPENSE)
Interest income		0	.4		0	.2
Interest on long-term debt		(18	.2)		(19	.0)
Interest on trust preferred securities		-	--		(4	.3)
Interest expense - unconsolidated affiliate		(4	.3)		-	--
Allowance for borrowed funds used during construction		0	.1		0	.2
Interest on short-term debt and other interest charges		(1	.1)		(1	.8)

Net interest expense		(23	.1)		(24	.7)

INCOME FROM CONTINUING OPERATIONS BEFORE TAXES		9	.2		6	.2
INCOME TAX EXPENSE (BENEFIT)		(0	.6)		1	.9

INCOME FROM CONTINUING OPERATIONS BEFORE
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE		9	.8		4	.3
DISCONTINUED OPERATIONS (NOTE 5)
Income from discontinued operations		0	.7		2	.2
Income tax expense		0	.3		0	.9

Income from discontinued operations		0	.4		1	.3

INCOME BEFORE CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE		10	.2		5	.6
CUMULATIVE EFFECT ON PRIOR YEARS OF CHANGE
IN ACCOUNTING PRINCIPLE, net of tax of $3.7		-	--		(5	.9)

NET INCOME (LOSS)	$	10	.2	$	(0	.3)

BASIC AVERAGE COMMON SHARES OUTSTANDING		87	.5		78	.7
DILUTED AVERAGE COMMON SHARES OUTSTANDING		88	.1		78	.9
BASIC AND DILUTED EARNINGS (LOSS) PER AVERAGE
COMMON SHARE
Income from continuing operations	$	0.1	1	$	0.0	5
Income from discontinued operations, net of tax		0.0	1		0.0	2
Loss from cumulative effect of accounting change, net of tax		--	-		(0.0	7)

NET INCOME	$	0.1	2	$	--	-

DIVIDENDS DECLARED PER SHARE	$	0.332	5	$	0.332	5

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.

OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended March 31,
(In millions)		2004			2003


CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	10	.2	$	(0	.3)
Adjustments to reconcile net income (loss) to net cash provided from
operating activities
Income from discontinued operations		(0	.4)		(1	.3)
Cumulative effect of change in accounting principle		-	--		5	.9
Depreciation		46	.0		46	.6
Deferred income taxes and investment tax credits, net		(0	.5)		(0	.5)
Gain on sale of assets		(1	.4)		(5	.7)
Price risk management assets		(29	.8)		(27	.2)
Price risk management liabilities		33	.2		23	.0
Other assets		3	.4		8	.2
Other liabilities		5	.9		0	.3
Change in certain current assets and liabilities
Accounts receivable, net		32	.8		(72	.2)
Accrued unbilled revenues		0	.6		(4	.3)
Fuel, materials and supplies inventories		94	.8		25	.5
Gas imbalance asset		(2	.7)		37	.2
Fuel clause under recoveries		3	.6		(34	.1)
Other current assets		4	.9		3	.5
Accounts payable		6	.3		118	.5
Customers’ deposits		-	--		1	.0
Accrued taxes		(11	.2)		(6	.3)
Accrued interest		(7	.0)		(7	.5)
Fuel clause over recoveries		0	.4		-	--
Gas imbalance liability		5	.6		(13	.5)
Other current liabilities		(2	.2)		1	.2

Net Cash Provided from Operating Activities		192	.5		98	.0

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(53	.4)		(44	.9)
Proceeds from sale of assets		3	.0		9	.9
Other investing activities		0	.6		(0	.4)

Net Cash Used in Investing Activities		(49	.8)		(35	.4)

CASH FLOWS FROM FINANCING ACTIVITIES
Retirement of long-term debt		(12	.0)		-	--
Decrease in short-term debt, net		(202	.5)		(102	.0)
Premium on issuance of common stock		4	.5		4	.2
Distribution to minority interest		-	--		(2	.5)
Dividends paid on common stock		(29	.1)		(23	.9)

Net Cash Used in Financing Activities		(239	.1)		(124	.2)

DISCONTINUED OPERATIONS
Net cash used in operating activities		-	--		(0	.5)
Net cash provided from investing activities		0	.4		38	.5

Net Cash Provided from Discontinued Operations		0	.4		38	.0

NET DECREASE IN CASH AND CASH EQUIVALENTS		(96	.0)		(23	.6)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		245	.6		44	.4

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	149	.6	$	20	.8

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.

OGE ENERGY CORP.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1. Summary of Significant Accounting Policies

Organization

OGE Energy Corp. (collectively, with its subsidiaries, the “Company”) is an energy and energy services provider offering physical delivery and management of both electricity and natural gas in the south central United States. The Company conducts these activities through two business segments, the Electric Utility and the Natural Gas Pipeline segments. All intercompany transactions have been eliminated in consolidation.

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 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.

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 revenues across different commodities, locations or time periods. The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are located in the major gas producing basins of Oklahoma. Through a 75 percent interest in the NOARK Pipeline System Limited Partnership, Enogex also owns a controlling interest in and operates the Ozark Gas Transmission System (“Ozark”), a FERC regulated interstate pipeline that extends from southeast Oklahoma through Arkansas to southeast Missouri. Enogex sold its interests in certain gas gathering and processing assets in Texas in the first quarter of 2003 which is reported in the Condensed Consolidated Financial Statements as discontinued operations.

The Company allocates operating costs to its affiliates based on several factors. Operating costs directly related to specific affiliates are assigned to those affiliates. Where more than one affiliate benefits from certain expenditures, the costs are shared between those affiliates receiving the benefits. Operating costs incurred for the benefit of all affiliates are allocated among the affiliates, based primarily upon head-count, occupancy, usage or the “Distragas” method. The Distragas method is a three-factor formula that uses an equal weighting of payroll, operating income and assets. The Company believes this method provides a reasonable basis for allocating common expenses.

Basis of Presentation

The Condensed Consolidated Financial Statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the disclosures are adequate to prevent the information presented from being misleading.

In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of the Company at March 31, 2004 and December 31, 2003, the results of its operations for the three months ended March 31, 2004 and 2003, and the results of its cash flows for the three months ended March 31, 2004 and 2003, have been included and are of a normal recurring nature.

Due to seasonal fluctuations and other factors, the operating results for the three months ended March 31, 2004 are not necessarily indicative of the results that may be expected for the year ending December 31, 2004 or for any future period. The Condensed Consolidated Financial Statements and Notes thereto should be read in conjunction with the audited Consolidated Financial Statements and Notes thereto included in the Company’s Form 10-K for the year ended December 31, 2003.

Accounting Records

The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC. Additionally, OG&E, as a regulated utility, is subject to the accounting principles prescribed by the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 provides that certain costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management’s expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. Excluding recoverable take or pay gas charges, regulatory assets are being amortized and reflected in rates charged to customers over periods of up to 20 years.

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

The following table is a summary of OG&E’s regulatory assets and liabilities at:

(In millions)	March 31, 2004			December 31, 2003
Regulatory Assets
Recoverable take or pay gas charges	$	32	.5	$	32	.5
Income taxes recoverable from customers, net		31	.4		31	.6
Unamortized loss on reacquired debt		21	.8		22	.1
PowerSmith capacity payments		3	.1		-	--
January 2002 ice storm		1	.8		3	.6
Fuel clause under recoveries		0	.4		4	.0
Miscellaneous		0	.2		0	.4

Total Regulatory Assets	$	91	.2	$	94	.2

Regulatory Liabilities
Accrued removal obligations, net	$	120	.1	$	116	.3
Fuel clause over recoveries		39	.2		32	.4
Estimated refund on FERC fuel		1	.0		1	.0

Total Regulatory Liabilities	$	160	.3	$	149	.7

Recoverable take or pay gas charges represent outstanding prepayments of gas related to a reserve for litigation that OG&E is currently involved in which OG&E expects full recovery through its regulatory approved fuel adjustment clause.

Income taxes recoverable from customers represent income tax benefits previously used to reduce OG&E’s revenues. These amounts are being recovered in rates as the temporary differences that generated the income tax benefit turn around. The provisions of SFAS No. 71 allowed the Company to treat these amounts as regulatory assets and liabilities and they are being amortized over the estimated remaining life of the assets to which they relate. The income tax related regulatory assets and liabilities are netted on the Company’s Condensed Consolidated Balance Sheets in the line item, “Income Taxes Recoverable from Customers, Net.”

PowerSmith Cogeneration Project, L.P. (“PowerSmith”) capacity payments relate to customer savings of approximately $1.0 million per month that began in January 2004 to reflect the expiration of the PowerSmith contract in August 2004. These customer savings relate to the period from September to December 2004.

Fuel clause under recoveries are generated from under recoveries from OG&E’s customers when OG&E’s cost of fuel exceeds the amount billed to its customers. Fuel clause over recoveries are generated from over recoveries from OG&E’s customers when the amount billed to its customers exceeds OG&E’s cost of fuel. The Company’s fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers’ bills. As a result, OG&E under recovers fuel cost in periods of rising prices above the baseline charge for fuel and over recovers fuel cost when prices decline below the baseline charge for fuel. Provisions in the fuel clauses allow the Company to amortize under or over recovery.

Accrued removal obligations represent asset retirement costs previously recovered from ratepayers for other than legal obligations. In accordance with SFAS No. 143, “Accounting for

Asset Retirement Obligations,” the Company was required to reclassify its accrued removal obligations, which had previously been recorded as a liability in Accumulated Depreciation, to a regulatory liability.

Management continuously monitors the future recoverability of regulatory assets. When in management’s judgment future recovery becomes impaired, the amount of the regulatory asset is reduced or written off, as appropriate. If the Company were required to discontinue the application of SFAS No. 71 for some or all of its operations, it could result in writing off the related regulatory assets; the financial effects of which could be significant.

Income Taxes

The Company files consolidated income tax returns. Income taxes are allocated to each affiliate based on its separate taxable income or loss. Federal investment tax credits on electric utility property have been deferred and are being amortized to income over the life of the related property. Amortization of the federal investment tax credits was approximately $1.3 million for each of the three months ended March 31, 2004 and 2003 and is recorded as an income tax benefit in the Condensed Consolidated Statements of Operations. During the three months ended March 31, 2004, the Company recorded Oklahoma investment tax credits of approximately $3.7 million which is recorded as an income tax benefit in the Condensed Consolidated Statements of Operations.

The Company follows the provisions of SFAS No. 109, “Accounting for Income Taxes,” which uses an asset and liability approach to accounting for income taxes. Under SFAS No. 109, deferred tax assets or liabilities are computed based on the difference between the financial statement and income tax bases of assets and liabilities using the enacted marginal tax rate. Deferred income tax expenses or benefits are based on the changes in the asset or liability from period to period.

Stock-Based Compensation

Pursuant to the provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” the Company has elected to continue using the intrinsic value method of accounting for its stock-based employee compensation plans in accordance with Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees.” Accordingly, the Company has not recognized compensation expense for its stock-based awards to employees.

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure – an amendment of FASB Statement No. 123.” SFAS No. 148 amended the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The following table reflects pro forma net income (loss) and income (loss) per average common share had the Company elected to adopt the fair value based method of SFAS No. 123:

	Three Months Ended March 31,
(In millions, except per share data)		2004			2003

Net income (loss), as reported	$	10	.2	$	(0	.3)
Add:
Stock-based employee compensation expense included
in reported net income (loss), net of related tax effects		-	--		-	--
Deduct:
Stock-based employee compensation expense determined
under fair value based method for all awards,
net of related tax effects		0	.3		0	.4

Pro forma net income (loss)	$	9	.9	$	(0	.7)

Income (loss) per average common share
Basic and diluted - as reported	$	0.	12	$	-	--
Basic and diluted - pro forma	$	0.	11	$	(0.	01)

Reclassifications

Certain prior year amounts have been reclassified on the Condensed Consolidated Financial Statements to conform to the 2004 presentation.

2. Accounting Pronouncements

In October 2002, the Emerging Issues Task Force (“EITF”) reached a consensus on certain issues covered in EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.” One consensus of EITF 02-3 was to rescind EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” as amended, effective for fiscal periods beginning after December 15, 2002. Effective October 25, 2002, all new contracts and physical inventories that would have been accounted for under EITF 98-10 were no longer marked to market through earnings unless the contracts met the definition of a derivative under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. Application of the consensus for energy contracts and inventory that existed on or before October 25, 2002 that remain in effect at the date this consensus was initially applied were recognized as a cumulative effect of a change in accounting principle in accordance with APB Opinion No. 20, “Accounting Changes.” As a result, only energy contracts that meet the definition of a derivative in SFAS No. 133 are carried at fair value. The Company adopted this consensus effective January 1, 2003 resulting in approximately a $9.6 million pre-tax loss ($5.9 million after tax). The loss, which was accounted for as a cumulative effect of a change in accounting principle during the first quarter of 2003, was primarily related to natural gas held in storage for trading purposes. This natural gas held in storage was sold during the first quarter of 2003 resulting in an increase in the gross margin on revenues (“gross margin”) in excess of the cumulative effect loss described above.

In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin No. 51.” Interpretation No. 46 requires the consolidation of entities in which an enterprise absorbs a majority of the entity’s expected losses, receives a majority of the entity’s expected residual returns, or both, as a result of ownership, contractual or other financial interests in the entity. Currently, entities are generally consolidated by an enterprise when it has a controlling financial interest through ownership of a majority voting interest in the entity.

In October 2003, the FASB issued Interpretation No. 46-6, “Effective Date of FASB Interpretation No. 46, Consolidation of Variable Interest Entities,” in which the FASB agreed to defer, for public companies, the required effective dates to implement Interpretation No. 46 for interests held in a variable interest entity (“VIE”) or potential VIE that was created before February 1, 2003. For calendar year-end public companies, the deferral effectively moved the required effective date from the third quarter to the fourth quarter of 2003.

As a result of Interpretation No. 46-6, a public entity need not apply the provisions of Interpretation No. 46 to an interest held in a VIE or potential VIE until the end of the first interim or annual period ending after December 15, 2003, if the VIE was created before February 1, 2003 and the public entity has not issued financial statements reporting that VIE in accordance with Interpretation No. 46, other than in the disclosures required by Interpretation No. 46. Interpretation No. 46 may be applied prospectively with a cumulative-effect adjustment as of the date on which it is first applied or by restating previously issued financial statements for one or more years with a cumulative-effect adjustment as of the beginning of the first year restated. The Company adopted this new interpretation effective December 31, 2003 resulting in approximately a $0.8 million pre-tax gain ($0.5 million after tax). The adoption of this new interpretation resulted in the deconsolidation of the trust preferred securities of OGE Energy Capital Trust I, a wholly-owned financing trust of the Company, and the consolidation of Energy Insurance Bermuda Ltd. (“EIB”) Mutual Business Program No. 19 (“MBP 19”).

EIB is incorporated in Bermuda under the Companies Act of 1981, as amended. The Company began participating in EIB through MBP 19 on November 15, 1998. The Company is the sole participant in MBP 19. The Company has issued an $8.0 million standby letter of credit to MBP 19 for the benefit of insuring parts of the Company’s property and liability insurance programs. MBP 19 was established to provide $15.0 million worth of property and liability insurance for the Company. The $8.0 million letter of credit was issued to provide protection for MBP 19 in case of large insurance claim losses. At December 31, 2003, there were no drawings against this letter of credit. Since a letter of credit was issued, the total equity investment at risk of MBP 19 was not sufficient to permit it to finance its activities without additional subordinated financial support from other parties. Therefore, MBP 19 was considered a VIE as defined in Interpretation No. 46 and the Company is the primary beneficiary which resulted in the consolidation of MBP 19 into the Company’s Consolidated Financial Statements for the year ended December 31, 2003. Effective January 1, 2004, the reinsurer of the MBP 19 program agreed to remove the guarantee requirement which will enable the Company to terminate the standby letter of credit previously provided. However, the reinsurer added a ratings trigger requirement in the revised agreement such that if the commercial paper rating of the Company is lowered by two grades, MBP 19 may be surcharged an additional premium, which may result in

an additional premium to the Company. Since the guarantee requirement was removed, the total equity investment at risk of MBP 19 is sufficient to permit it to finance its activities without additional subordinated financial support from other parties. Therefore, MBP 19 is not considered a VIE as defined in Interpretation No. 46 which resulted in the deconsolidation of MBP 19 during the first quarter of 2004.

3. Price Risk Management Assets and Liabilities

Non-Trading Activities

The Company periodically utilizes derivative contracts to manage the exposure of its assets to unfavorable changes in commodity prices, as well as to reduce exposure to adverse interest rate fluctuations. During the three months ended March 31, 2004 and 2003, the Company’s use of non-trading price risk management instruments involved the use of commodity price and interest rate swap agreements. These agreements involve the exchange of fixed price or rate payments in exchange for floating price or rate payments over the life of the instrument without an exchange of the underlying principal amount.

In accordance with SFAS No. 133, the Company recognizes all of its derivative instruments as Price Risk Management assets or liabilities in the Balance Sheet at fair value with such amounts classified as current or long-term based on their anticipated settlement. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation. For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item attributable to the hedged risk are recognized in the same line item associated with the hedged item in current earnings during the period of the change in fair values. For derivatives that are designated and qualify as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of Accumulated Other Comprehensive Income and recognized into earnings in the same period during which the hedged transaction affects earnings. The ineffective portion of a derivative’s change in fair value is recognized currently in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and hedged item during the period of hedge designation. Forecasted transactions designated as the hedged item in a cash flow hedge are regularly evaluated to assess whether they continue to be probable of occurring. If the forecasted transactions are no longer probable of occurring, hedge accounting will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings. Any amounts recorded in Accumulated Other Comprehensive Income will remain in other comprehensive income until such time the forecasted transaction is deemed probable not to occur. The Company’s interest rate swap agreements have been designated as fair value hedges and qualified for the shortcut method prescribed by SFAS No. 133. Under the shortcut method, the Company assumes that the hedged item’s change in fair value is exactly as much as the derivative’s change in fair value.

At March 31, 2004 and December 31, 2003, the Company had outstanding cash flow hedges, and approximately a $0.9 million after tax gain was included in Accumulated Other Comprehensive Loss.

Trading Activities

The Company, through its subsidiary, OGE Energy Resources, Inc. (“OERI”), engages in energy trading activities primarily related to the purchase and sale of natural gas. Contracts utilized in these activities generally include forward swap contracts as well as over-the-counter and exchange traded futures and options. Energy trading activities are accounted for in accordance with SFAS No. 133 and EITF 02-3. Under the guidance provided by SFAS No. 133, financial instruments that qualify as derivatives are reflected at fair value with the resulting unrealized gains and losses recorded as Price Risk Management assets or liabilities in the Condensed Consolidated Balance Sheets, classified as current or long-term based on their anticipated settlement. Unrealized gains and losses from changes in the market value of open contracts are included in Natural Gas Pipeline Operating Revenues in the Condensed Consolidated Statements of Operations. Energy trading contracts resulting in delivery of a commodity that meet the requirements of EITF Issue No. 99-19, “Reporting Revenues Gross as a Principal or Net as an Agent,” are included as sales or purchases in the Condensed Consolidated Statements of Operations depending on whether the contract relates to the sale or purchase of the commodity.

4. Accumulated Other Comprehensive Loss

The components of total comprehensive income (loss) for the three months ended March 31, 2004 and 2003, respectively, are as follows:

	Three Months Ended March 31,
(In millions)		2004			2003

Net income (loss)	$	10	.2	$	(0	.3)
Other comprehensive income (loss), net of tax:
Deferred hedging gains		-	--		0	.2
Reversal of unrealized gains on available-for-sale securities		(0	.4)		-	--

Total comprehensive income (loss)	$	9	.8	$	(0	.1)

Effective January 1, 2004, MBP 19 was deconsolidated in the Condensed Consolidated Financial Statements which resulted in a reversal of the unrealized gains on available-for-sale securities recorded at December 31, 2003. See Note 2 for a further discussion of the accounting for MBP 19.

The components of accumulated other comprehensive loss at March 31, 2004 and December 31, 2003 are as follows:

(In millions)	March 31, 2004			December 31, 2003
Minimum pension liability adjustment, net of tax	$	(59	.7)	$	(59	.7)
Deferred hedging gains, net of tax		0	.9		0	.9
Unrealized gains on available-for-sale securities, net of tax		-	--		0	.4

Total accumulated other comprehensive loss	$	(58	.8)	$	(58	.4)

Accumulated other comprehensive loss at both March 31, 2004 and December 31, 2003 included approximately a $59.7 million after tax loss ($97.4 million pre-tax) related to a minimum pension liability adjustment based on a review of the funded status of the pension plan by the Company’s actuarial consultants as of December 31, 2003. Any increases or decreases in the minimum pension liability will be reflected in Other Comprehensive Income or Loss in the fourth quarter.

5. Enogex – Discontinued Operations

Enogex sold its interests in the NuStar Joint Venture (“NuStar”) for approximately $37.0 million in February 2003. The Company recognized approximately a $1.4 million after tax gain related to the sale of these assets in the first quarter of 2003. The final accounting for the NuStar sale was completed in the third quarter of 2003 which resulted in an additional charge of approximately $0.2 million after tax which was recorded in the third quarter of 2003. The final accounting is subject to approval by all parties to the sale of the joint venture interest. During the first quarter of 2004, the Company recognized approximately $0.4 million after tax from funds received related to an overpayment for natural gas purchases in a prior period.

The Condensed Consolidated Financial Statements of the Company reflect NuStar, which was part of the Natural Gas Pipeline segment, as discontinued operations. Accordingly, revenues, costs and expenses and cash flows of NuStar have been excluded from the respective captions in the Condensed Consolidated Financial Statements and have been reported as “Income from Discontinued Operations” and “Net Cash Provided from Discontinued Operations.” There were no outstanding balances related to NuStar on the Condensed Consolidated Balance Sheets. Summarized financial information for the discontinued operations is as follows:

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS DATA

	Three Months Ended March 31,
(In millions)		2004			2003

Operating revenues from discontinued operations	$	0	.7	$	7	.8

Income from discontinued operations before taxes		0	.7		2	.2

6. Asset Disposals

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

7. Impairment of 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 which related to Enogex natural gas processing and compression assets. In the fourth quarter of 2003, as a result of an ongoing initiative to improve asset utilization in the Natural Gas Pipeline segment, the Company concluded that certain idle Enogex natural gas compression assets may no longer be required to meet the Company’s future business needs. As a result, the Company recognized a pre-tax impairment loss of approximately $9.2 million related to these natural gas compression assets. The impairments resulted from plans to dispose of these assets at prices below the carrying amount. The fair value of these assets was determined based on third-party evaluations, prices for similar assets, historical data and projected cash flows. During the first quarter of 2004, the Company sold certain of the compression and processing assets for approximately $2.7 million. The Company recognized approximately a $0.7 million after tax gain related to the sale of these assets. The carrying amount of the remaining assets held for sale was approximately $9.2 million and $11.9 million at March 31, 2004 and December 31, 2003, respectively. During April 2004, the Company sold certain of the compression and processing assets for approximately $0.1 million. The Company will recognize an after tax gain related to the sale of these assets of less than $0.1 million in April 2004. The Company continues to actively market these assets and plans to sell or otherwise dispose of these assets by the end of 2004.

8. Supplemental Cash Flow Information

The following table discloses information about investing and financing activities that affect recognized assets and liabilities but which do not result in cash receipts or payments.

	Three Months Ended March 31,
(In millions)		2004			2003

NON-CASH INVESTING AND FINANCING ACTIVITIES

Change in fair value of long-term debt due to interest rate swaps	$	7	.8	$	0	.2
Issuance of common stock		-	--		2	.8

9. Common Stock

For the three months ended March 31, 2004, there were 239,124 shares of new common stock issued pursuant to the Stock Incentive Plan, which related to exercised stock options.

10. Earnings Per Share

Outstanding shares for purposes of basic and diluted earnings per average common share were calculated as follows:

	Three Months Ended March 31,
(In millions)		2004		2003

Average Common Shares Outstanding
Basic average common shares outstanding		87	.5	78	.7
Effect of dilutive securities:
Employee stock options and unvested stock grants		0	.2	0	.2
Contingently issuable shares (performance units)		0	.4	-	--

Diluted average common shares outstanding		88	.1	78	.9

For the three months ended March 31, 2004 and 2003, respectively, approximately 0.7 million shares and 2.3 million shares related to outstanding employee stock options were not included in the calculation of diluted earnings per average common share because the effect of including those shares is anti-dilutive as the exercise price of the stock options exceeded the average common stock market price during the respective period.

11. Long-Term Debt

At March 31, 2004, the Company is in compliance with all of its debt agreements.

OG&E has four series of long-term debt with optional redemption provisions which allow the holders to request repayment of the long-term debt at various dates prior to the maturity. The debt series which are redeemable at the option of the holder during the next 12 months are as follows:

SERIES		DATE DUE		AMOUNT

6.500 %		Senior Notes, Series Due July 15, 2017	$	125	.0
Variable %		Garfield Industrial Authority, January 1, 2025		47	.0
Variable %		Muskogee Industrial Authority, January 1, 2025		32	.4
Variable %		Muskogee Industrial Authority, June 1, 2027		56	.0

	Tot	al	$	260	.4

The 6.500 percent Senior Notes (“Senior Notes”) will be repayable on July 15, 2004, at the option of the holders, at 100 percent of the principal amount, together with accrued and unpaid interest to July 15, 2004. In order for a Senior Note to be repaid, the Company must receive at the principal corporate trust office of the Senior Note Trustee during the period from and including May 15, 2004 to and including the close of business on June 15, 2004, a Senior Note with the form entitled “Option to Elect Repayment” on these Senior Notes or other documentation with this information. The repayment option may be exercised by the holder of a Senior Note for less than the entire principal amount of the Senior Note, provided the principal amount is in denominations of $1,000. If the Senior Note holders were to exercise the put options prior to the maturity date, the Company has sufficient liquidity but may choose to

refinance these obligations in the capital markets. Such refinancing may incur higher annual interest charges. At the present time, the Company does not believe a majority of the Senior Notes will be submitted for repayment in this interest rate environment.

All of the variable rate industrial authority bonds (“Bonds”) are subject to tender at the option of the holders, at 100 percent of the principal amount, together with accrued and unpaid interest to the date of purchase. The bond holders, on any business day, can request repayment of the Bond by delivering an irrevocable notice to the tender agent stating the principal amount of the Bond, payment instructions for the purchase price and the business day the Bond is to be purchased. The repayment option may only be exercised by the holder of a Bond for the entire principal amount. A third party remarketing agent for the Bonds will attempt to remarket any Bonds tendered for purchase. If the remarketing agent is unable to remarket any such Bonds, the Company is obligated to repurchase such unremarketed Bonds. The Company has sufficient liquidity to meet these obligations.

Interest Rate Swap Agreements

At March 31, 2004 and December 31, 2003, the Company had three outstanding interest rate swap agreements: (i) OG&E entered into an interest rate swap agreement, effective March 30, 2001, to convert $110.0 million of 7.30 percent fixed rate debt due October 15, 2025, to a variable rate based on the three month London InterBank Offering Rate (“LIBOR”) and (ii) Enogex entered into two separate interest rate swap agreements, effective July 15, 2002 and October 24, 2002, to convert $100.0 million of 8.125 percent fixed rate debt due January 15, 2010, to a variable rate based on the six month LIBOR. The objective of these interest rate swaps was to achieve a lower cost of debt and to raise the percentage of total corporate long-term floating rate debt to reflect a level more in line with industry standards. These interest rate swaps qualified as fair value hedges under SFAS No. 133 and met all of the requirements for a determination that there was no ineffective portion as allowed by the shortcut method under SFAS No. 133.

At March 31, 2004 and December 31, 2003, the fair values pursuant to the interest rate swaps were approximately $15.4 million and $7.6 million, respectively, and are classified as Deferred Charges and Other Assets – Price Risk Management in the Condensed Consolidated Balance Sheets. A corresponding net increase of approximately $15.4 million and $7.6 million was reflected in Long-Term Debt at March 31, 2004 and December 31, 2003, respectively, as these fair value hedges were effective at March 31, 2004 and December 31, 2003.

12. Short-Term Debt

The short-term debt balance was approximately $202.5 million at December 31, 2003 primarily due to the planned acquisition of the McClain Plant discussed in Notes 15 and 16. There was no short-term debt outstanding at March 31, 2004. Due to a delay in the completion of the McClain Plant acquisition, the Company used short-term investments and proceeds received from the sale of natural gas inventory by Enogex during the first quarter of 2004 to reduce the outstanding commercial paper balance.

The following table shows the Company’s lines of credit in place and available cash at March 31, 2004. Short-term borrowings are expected to consist of a combination of bank borrowings and commercial paper.

Lines of Credit and Available Cash (In millions)
Entity	Amount Available	Amount Outstanding	Maturity
OGE Energy Corp. (A) OG&E OGE Energy Corp. (A)	$ 15.0 100.0 300.0	$ --- --- ---	April 6, 2004 June 26, 2004 December 9, 2004
Cash	415.0 149.6	--- N/A	N/A
Total	$ 564.6	$ ---
(A) The lines of credit at OGE Energy Corp. are used to back up the Company’s commercial paper borrowings. There was no short-term debt outstanding at March 31, 2004. In April 2004, the Company renewed its $15.0 million credit facility, shown in the table above, which matures April 6, 2005.

The Company’s ability to access the commercial paper market could be adversely impacted by a commercial paper ratings downgrade. The lines of credit contain rating grids that require annual fees and borrowing rates to increase if the Company suffers an adverse ratings impact. The impact of additional downgrades of the Company’s rating would result in an increase in the cost of short-term borrowings of approximately five to 20 basis points, but would not result in any defaults or accelerations as a result of the rating changes.

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

13. Retirement Plans and Postretirement Benefit Plans

In December 2003, the FASB issued SFAS No. 132 (Revised), “Employer’s Disclosures about Pension and Postretirement Benefits, an amendment of FASB Statements No. 87, 88 and 106,” which revised employers’ disclosures about pension plans and other postretirement benefits. This Statement requires additional disclosures to those in the original SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” for defined benefit pension plans and other defined benefit postretirement plans which include disclosures describing the components of net periodic benefit cost recognized during interim periods.

A detail of net periodic benefit cost included in the Condensed Consolidated Financial Statements is as follows:

Net Periodic Benefit Cost


	Pension Plan						Postretirement Benefit Plans
	Three Months Ended March 31,						Three Months Ended March 31,
(In millions)		2004			2003			2004			2003

Service cost	$	4	.2	$	3	.6	$	0	.8	$	0	.9
Interest cost		7	.4		7	.1		2	.8		3	.0
Return on plan assets		(7	.9)		(6	.6)		(1	.4)		(1	.3)
Amortization of transition obligation		-	--		-	--		0	.7		0	.7
Amortization of net (gain) loss		3	.0		2	.5		1	.2		1	.4
Amortization of unrecognized prior service cost		1	.6		1	.3		0	.5		0	.5

Net periodic benefit cost	$	8	.3	$	7	.9	$	4	.6	$	5	.2

Pension Plan Funding

The Company previously disclosed in its Form 10-K for the year ended December 31, 2003 that it expected to contribute approximately $56.0 million to the pension plan in 2004. The Company presently anticipates contributing an additional $13.0 million to the pension plan during 2004, for a total contribution of approximately $69.0 million in 2004. After the benefit liability was remeasured as of January 1, 2004, the Company decided to make the additional contribution to ensure the pension plan maintains an adequate funded status. The Company plans to make contributions to the pension plan during the second and third quarters of 2004. In April 2004, the Company funded approximately $23.0 million to the pension plan. The expected contributions to the pension plan, anticipated to be in the form of cash, are discretionary contributions and are not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974.

Medicare Prescription Drug, Improvement and Modernization Act of 2003

On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Act”). The Act expanded Medicare to include, for the first time, coverage for prescription drugs. The Company sponsors retiree medical programs for certain of its locations and the Company expects that this legislation will eventually reduce the Company’s costs for some of these programs.

At this point, the Company’s investigation into its response to the legislation is preliminary, as we await guidance from various governmental and regulatory agencies concerning the requirements that must be met to obtain these cost reductions as well as the manner in which such savings should be measured. Based on this preliminary analysis, it appears that some of the Company’s retiree medical plans will need to be changed in order to qualify for beneficial treatment under the Act, while other plans can continue unchanged.

Because of various uncertainties related to the Company’s response to this legislation and the appropriate accounting methodology for this event, the Company has elected to defer financial recognition of this legislation until the FASB issues final accounting guidance. When issued, that final guidance could require the Company to change previously reported information. This deferral election is permitted under FASB Staff Position FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” Management has not yet determined what the impact of this accounting guidance will be on its consolidated financial position or results of operations.

14. Report of Business Segments

The Company’s Electric Utility operations are conducted through OG&E, a regulated utility engaged in the generation, transmission, distribution and sale of electric energy. The Company’s Natural Gas Pipeline operations are conducted through Enogex. Enogex is engaged in the transportation and storage of natural gas, the gathering and processing of natural gas and the marketing of natural gas. Other Operations for the three months ended March 31, 2003 primarily includes unallocated corporate expenses, interest expense on commercial paper and the trust preferred securities. As a result of the adoption of FASB Interpretation No. 46 on December 31, 2003, this resulted in the deconsolidation of the trust preferred securities and the consolidation of MBP 19 for the year ended December 31, 2003 in the Company’s Condensed Consolidated Financial Statements. However, MBP 19 was deconsolidated during the first quarter of 2004 due to the removal of the guarantee requirement by the reinsurer. See Note 2 for a further discussion of the accounting for MBP 19. Therefore, Other Operations for the three months ended March 31, 2004 primarily includes unallocated corporate expenses, interest expense to unconsolidated affiliate and interest expense on commercial paper. Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations. The following tables are a summary of the results of the Company’s business segments for the three months ended March 31, 2004 and 2003.


Three Months Ended March 31, 2004	Electric Utility			Natural Gas Pipeline (A)			Other Operations			Intersegment			Total
(In millions)
Operating revenues	$	304	.3	$	749	.2	$	-	--	$	(11	.8)	$	1,041	.7
Fuel		108	.0		-	--		-	--		(11	.8)		96	.2
Purchased power		75	.2		-	--		-	--		-	--		75	.2
Gas and electricity purchased for resale		-	--		666	.1		-	--		-	--		666	.1
Natural gas purchases - other		-	--		17	.4		-	--		-	--		17	.4

Cost of goods sold		183	.2		683	.5		-	--		(11	.8)		854	.9
Gross margin on revenues		121	.1		65	.7		-	--		-	--		186	.8

Other operation and maintenance		71	.5		23	.3		(3	.7)		-	--		91	.1
Depreciation		31	.9		11	.5		2	.6		-	--		46	.0
Taxes other than income		12	.7		4	.9		1	.1		-	--		18	.7

Operating income		5	.0		26	.0		-	--		-	--		31	.0

Other income		0	.4		1	.4		1	.0		-	--		2	.8
Other expense		(0	.5)		(0	.3)		(0	.7)		-	--		(1	.5)
Interest income		0	.2		0	.1		0	.3		(0	.2)		0	.4
Interest expense		(9	.7)		(9	.3)		(4	.7)		0	.2		(23	.5)
Income tax expense (benefit)		(4	.6)		5	.5		(1	.5)		-	--		(0	.6)

Income (loss) from continuing operations		-	--		12	.4		(2	.6)		-	--		9	.8

Income from discontinued operations		-	--		0	.4		-	--		-	--		0	.4

Net income (loss)	$	-	--	$	12	.8	$	(2	.6)	$	-	--	$	10	.2

(A) Natural Gas Pipeline’s operations consist of three related businesses: Transportation and Storage, Gathering and Processing and Marketing. The following table is supplemental Natural Gas Pipeline information.

Three Months Ended March 31, 2004	Transportation and Storage			Gathering and Processing			Marketing			Eliminations			Total
(In millions)
Operating revenues	$	83	.6	$	133	.3	$	667	.2	$	(134	.9)	$	749	.2
Operating income (loss)	$	14	.5	$	12	.2	$	(0	.7)	$	-	--	$	26	.0


Three Months Ended March 31, 2003	Electric Utility			Natural Gas Pipeline (A)			Other Operations			Intersegment			Total
(In millions)
Operating revenues	$	332	.6	$	739	.6	$	-	--	$	(22	.0)	$	1,050	.2
Fuel		141	.2		-	--		-	--		(10	.0)		131	.2
Purchased power		72	.7		-	--		-	--		-	--		72	.7
Gas and electricity purchased for resale		-	--		657	.0		-	--		(12	.0)		645	.0
Natural gas purchases - other		-	--		19	.5		-	--		-	--		19	.5

Cost of goods sold		213	.9		676	.5		-	--		(22	.0)		868	.4
Gross margin on revenues		118	.7		63	.1		-	--		-	--		181	.8

Other operation and maintenance		72	.0		22	.4		(4	.1)		-	--		90	.3
Depreciation		32	.6		11	.2		2	.8		-	--		46	.6
Taxes other than income		12	.0		4	.3		0	.9		-	--		17	.2

Operating income		2	.1		25	.2		0	.4		-	--		27	.7

Other income		0	.3		5	.7		0	.1		-	--		6	.1
Other expense		(0	.7)		(1	.7)		(0	.5)		-	--		(2	.9)
Interest income		-	--		0	.3		4	.8		(4	.9)		0	.2
Interest expense		(9	.9)		(10	.1)		(9	.8)		4	.9		(24	.9)
Income tax expense (benefit)		(4	.9)		9	.3		(2	.5)		-	--		1	.9

Income (loss) from continuing operations
before cumulative effect of change in
accounting principle		(3	.3)		10	.1		(2	.5)		-	--		4	.3

Income from discontinued operations		-	--		1	.3		-	--		-	--		1	.3

Income (loss) before cumulative effect of
change in accounting principle		(3	.3)		11	.4		(2	.5)		-	--		5	.6
Cumulative effect on prior years of
change in accounting principle, net of tax		-	--		(5	.9)		-	--		-	--		(5	.9)

Net income (loss)	$	(3	.3)	$	5	.5	$	(2	.5)	$	-	--	$	(0	.3)

(A) Natural Gas Pipeline’s operations consist of three related businesses: Transportation and Storage, Gathering and Processing and Marketing. The following table is supplemental Natural Gas Pipeline information.

Three Months Ended March 31, 2003	Transportation and Storage			Gathering and Processing			Marketing			Eliminations			Total
(In millions)
Operating revenues	$	69	.0	$	141	.5	$	646	.6	$	(117	.5)	$	739	.6
Operating income	$	8	.7	$	6	.5	$	10	.0	$	-	--	$	25	.2

15. Commitments and Contingencies

Except as set forth below and in Note 16, the circumstances set forth in Note 17 to the Company’s Consolidated Financial Statements included in the Company’s Form 10-K for the year ended December 31, 2003, appropriately represent, in all material respects, the current status of any material commitments and contingent liabilities.

Agreement with Colorado Interstate Gas Company

In December 2002, Enogex entered into an agreement with Colorado Interstate Gas Company (“CIG”) regarding reservation of firm capacity on a proposed interstate gas pipeline (the “Cheyenne Plains Pipeline”). If completed, the Cheyenne Plains Pipeline would provide interstate gas transportation services in the states of Wyoming, Colorado and Kansas with a capacity of 560,000 decatherms/day (“Dth/day”). Under this agreement, Enogex bid to reserve 60,000 Dth/day of capacity on the proposed pipeline for 10 years and two months. Such reservation would result in Enogex having access to significant additional natural gas supplies in the Rocky Mountain production basins. The FERC has issued an order granting certificate to the Cheyenne Plains Pipeline project and CIG is now targeting an in-service date within the first quarter of 2005.

National Steel Corporation

National Steel Corporation (“National Steel”) voluntarily filed for Chapter 11 bankruptcy protection from creditors on March 6, 2002. OERI provided gas supply services to National Steel and is an unsecured creditor of National Steel. OERI filed its proof of claim on August 14, 2002 in the amount of 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. OERI intends to vigorously defend this action. Other than OERI’s $0.9 million claim that was originally reserved, no further reserve is believed to be appropriate at this time.

Pending Acquisition of Power Plant

On August 18, 2003, OG&E signed an asset purchase agreement to acquire NRG McClain LLC’s 77 percent interest in the 520 megawatt (“MW”) NRG McClain Station (the “McClain Plant”). Closing has been delayed pending receipt of FERC approval. The acquisition of this interest in the McClain Plant would clearly constitute an acquisition of electric generation under the agreed-upon settlement of OG&E’s rate case (the “Settlement Agreement”). The purchase price for the interest in the McClain Plant is approximately $159.9 million, subject to adjustment for prepaid gas and property taxes. See Note 16 for a further description of this matter and a description of current proceedings involving a PowerSmith contract.

Sooner Power Plant Coal Dust Explosion

On February 16, 2004, there was a coal dust explosion at OG&E’s Sooner Power Plant which caused structural and electrical damage to the coal train unloading system. The generation capacity of the Sooner Plant facility was not impacted by this incident. The estimated costs to repair the damage are approximately $3.0 million to $4.0 million, of which a majority is expected to be capitalized in 2004. The coal train unloading system resumed unloading coal trains at the end of the first quarter of 2004. The Company is insured for this loss through MBP 19 which is a self-funded insurance program.

Other

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 Condensed 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. This assessment of currently pending or threatened lawsuits is subject to change.

16. Rate Matters and Regulation

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.

Recent Regulatory Matters

2002 Settlement Agreement

OG&E’s rider for sales to other utilities and power marketers (“off-system sales”). Previously, OG&E had a 50/50 sharing mechanism in Oklahoma for any off-system sales. The Settlement Agreement provided that the first $1.8 million in annual net profits from OG&E’s off-system sales will go to OG&E, the next $3.6 million in annual net profits from off-system sales will go to OG&E’s Oklahoma customers, and any net profits of off-system sales in excess of these amounts will be credited in each sales year with 80 percent to OG&E’s Oklahoma customers and the remaining 20 percent to OG&E. If any of the $5.4 million is not recovered at the end of the three years, the OCC will authorize the recovery of any remaining costs.

OCC Order Confirming Savings

The Settlement Agreement requires that, if OG&E did not acquire the New Generation by December 31, 2003, OG&E must credit $25.0 million annually (at a rate of 1/12 of $25.0 million per month for each month that the New Generation is not in place) to its Oklahoma customers beginning January 1, 2004 and continuing through December 31, 2006. As discussed in more detail below, in August 2003 OG&E signed an agreement to purchase a 77 percent interest in the McClain Plant, but due to a delay at the FERC, the acquisition has not yet been completed. In the interim, OG&E has entered into a power purchase agreement with the McClain Plant, which expires December 31, 2004, that is delivering the savings guaranteed to OG&E’s customers. OG&E requested that the OCC confirm that the steps it has taken, including the power purchase agreement, were satisfying the customer savings obligation under the Settlement Agreement and that OG&E would not be required to begin crediting its customers. On April 28, 2004, the OCC issued an order confirming that OG&E was delivering savings to its customers as required under the Settlement Agreement. The order removed any uncertainty over whether OG&E had to reduce its rates, effective January 1, 2004, while it awaits action by the FERC on its application to purchase the McClain Plant.

FERC Section 311 Rate Case

In December 2001, Enogex made its filing at the FERC under Section 311 of the Natural Gas Policy Act to establish rates and a default processing fee and to address various other issues for the combined Enogex and Transok L.L.C. pipeline systems. In May 2003, the FERC accepted the stipulation and settlement agreement and entered an order modifying Enogex’s Statement of Operating Conditions (“SOC”). The settlement included a fee to be assessed under certain market conditions to process customer gas gathered behind processing plants so that it meets the heating value standards of natural gas transmission pipelines (“default processing fee”). This default processing fee, which reduces Enogex’s exposure to keep whole processing arrangements, is implemented in the event the difference between the price of natural gas liquids extracted and natural gas is negative. The settlement also approved a monthly low flow meter charge of $200 (offset in any month by the transportation revenues generated by gas through the meter). Pursuant to Enogex’s SOC, if Enogex’s annual processing gross margin exceeds a specified threshold, Enogex is required to record a default processing fee refund obligation in an amount equal to the lesser of the default processing fees or the amount of the processing margin in excess of the specified threshold.

During the third and fourth quarters of 2003, the Company established approximately a $4.9 million reserve to cover such refund obligations. During April 2004, the Company refunded its default processing fee refund obligation under the SOC to the applicable customers. There were no default processing fees billed to customers during the first quarter of 2004 as compared to approximately $1.8 million during the first quarter of 2003. For the three months ended March 31, 2004 and 2003, the Company recognized revenue of approximately $0.1 million of low flow meter charges. Based on the forecasted processing gross margin for 2004, any default processing fees charged to customers will be recorded as deferred revenue until it becomes probable that the 2004 gross margin threshold in the SOC will not be exceeded. The accounting for default processing fees is not expected to impact full-year earnings, but could affect the timing of those earnings.

Pending Regulatory Matters

Currently, OG&E has one significant matter pending at the FERC relating to the FERC’s review of market power issues and mitigation measures involved in the McClain Plant acquisition. OG&E also has three significant matters pending at the OCC: (i) a motion by PowerSmith seeking to compel OG&E to continue purchasing power from a qualified cogeneration facility; (ii) a review of the process completed by OG&E in its selection of gas transportation and storage services to meet its system operating needs and (iii) security investments on OG&E’s system. These matters, as well as several other pending matters, are discussed below.

Pending Acquisition of Power Plant

As part of the 2002 Settlement Agreement with the OCC, OG&E undertook to acquire New Generation of not less than 400 MWs. The acquisition of a 77 percent interest in the McClain Plant would clearly constitute an acquisition of such New Generation under the Settlement Agreement. OG&E expects this New Generation, including the interim power purchase agreement, will provide savings, over a three-year period, in excess of $75.0 million to its Oklahoma customers. These savings were to be derived from: (i) the avoidance of purchase power contracts otherwise needed; (ii) replacing an above market cogeneration contract with PowerSmith when it can be terminated at the end of August 2004; and (iii) fuel savings associated with operating efficiencies of the new plant. In the event OG&E is unable to demonstrate at least $75.0 million in savings to its customers during this 36-month period, OG&E will have an obligation to credit its Oklahoma customers any unrealized savings below $75.0 million as determined at the end of the 36-month period, which shall be no later than December 31, 2006. PowerSmith has filed an application with the OCC seeking to compel OG&E to continue purchasing power from PowerSmith’s qualified cogeneration facility under the Public Utility Regulatory Policy Act of 1978 at a price that would include an avoided capacity charge equal to the lesser of (i) the rate currently specified in the power purchase agreement between OG&E and PowerSmith or (ii) the avoided cost of the McClain Plant. On March 29, 2004, OG&E and PowerSmith reached a tentative, 15-year power sales agreement under which OG&E will continue to purchase electric power from PowerSmith. The terms of the agreement are being finalized and will be subject to approval by the OCC. In conjunction with OG&E’s agreement with PowerSmith, PowerSmith is in the process of completing a long-

term steam sales agreement with Dayton Tire. On April 15, 2004, OG&E and PowerSmith provided an update to the OCC regarding completion of the contract and the OCC scheduled a hearing for May 11, 2004 in this case. OG&E’s ability to meet its guarantee of customer savings of at least $75 million over three years is not expected to be materially affected by this new agreement to purchase electric power from PowerSmith.

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

Closing is subject to customary conditions including receipt of regulatory approval by the FERC. The asset purchase agreement, as amended, provides that, unless extended, either party has the right to terminate the contract if the closing does not occur on or before May 21, 2004. Because the current owner of the McClain Plant has filed for bankruptcy protection, the acquisition also was subject to approval by the bankruptcy court. As part of the bankruptcy approval process, NRG McClain LLC’s interest in the plant was subject to an auction process and on October 28, 2003, the bankruptcy court approved the sale of NRG McClain LLC’s interest in the plant to OG&E. Several parties have filed interventions at the FERC opposing OG&E’s application under Section 203 of the Federal Power Act to acquire NRG McClain’s interest in the power plant or, alternatively, requesting the FERC to delay approving such acquisition. OG&E believed that its application met the standards under Section 203 set forth by the FERC and that its application would be approved. On December 18, 2003, the FERC shifted its policy regarding market power issues, raised wholesale market power concerns and ordered a hearing regarding OG&E’s acquisition of the McClain Plant. The FERC action did not reject OG&E’s request to purchase the McClain Plant, but ordered that OG&E must address certain issues in an administrative hearing. On January 15, 2004, the FERC administrative law judge in charge of the hearing and the parties to the case agreed to a procedural schedule that would produce a decision on the McClain Plant acquisition no sooner than the third quarter of 2004. On January 20, 2004, OG&E filed a petition for re-hearing of the FERC’s December 18, 2003 order which included new mitigation measures that were designed to allow for prompt approval of the transaction. That request is still pending before the FERC. OG&E has no indication whether the FERC will accept those proposed mitigation measures. On March 2, 2004, OG&E filed testimony and exhibits with the FERC administrative law judge. The testimony and exhibits indicate that, if the case proceeds to hearing, the wholesale market power issues that the FERC raised in the December 18, 2003 order may be resolved by the proposed mitigation measures. OG&E also filed on March 8, 2004, in the proceeding before the FERC administrative law judge an offer of settlement proposing additional mitigation measures at an aggregate cost of approximately $18.5 million and, despite opposition from certain intervenors, requested the administrative law judge to certify the offer as a contested settlement. Following a denial of OG&E’s request, OG&E asked the administrative law judge to reconsider his decision or,

alternatively, to grant OG&E an interlocutory appeal to the FERC of his decision. The FERC administrative law judge denied OG&E’s requests and OG&E is appealing his decision to the FERC. Absent FERC granting OG&E’s January 20 motion for reconsideration or its most recent appeal, the matter is scheduled for hearing before the FERC administrative law judge on August 3, 2004.

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

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

Gas Transportation and Storage Agreement

As part of the Settlement Agreement, OG&E also agreed to consider competitive bidding for gas transportation service to its natural gas-fired generation facilities pursuant to the terms set forth in the Settlement Agreement. OG&E believes that in order for it to achieve maximum coal generation and ensure reliable electric service, it must have firm no-notice load following service for both gas transportation and gas storage. This type of service is required to satisfy the daily swings in customer demand placed on OG&E’s system and still permit natural gas units to not impede coal energy production. OG&E also believes that gas storage is an integral part of providing gas supply to OG&E’s generation facilities. Accordingly, OG&E evaluated its competitive bid options in light of these circumstances. OG&E’s evaluation clearly demonstrates that the Enogex integrated gas system provides superior firm no-notice load following service to OG&E that is not available from other companies serving the OG&E marketplace. On April 29, 2003, OG&E filed an application with the OCC in which OG&E advised the OCC that, after careful consideration, competitive bidding for gas transportation was rejected in favor of a new intrastate firm no-notice load following gas transportation and storage services agreement with Enogex. This seven-year agreement provides for gas transportation and storage services for each of OG&E’s natural gas-fired generation facilities. During the three months ended March 31, 2004 and 2003, OG&E paid Enogex approximately $11.8 million and $10.0 million, respectively, for gas transportation and storage services. Based upon requests for information from intervenors, OG&E has requested from Enogex and Enogex retained a “cost of service”

consultant to assist in the preparation of testimony related to this case. On January 30, 2004, the OCC issued a procedural schedule for this case. On March 31, 2004, OG&E filed testimony and exhibits with the OCC, which completes the initial documentation required to be filed in this case. A hearing is scheduled August 10-11, 2004 and an OCC order in the case is expected by the end of 2004. OG&E believes the amount currently paid to Enogex for no-notice load following transportation and storage services is fair, just and reasonable. If any amounts paid by OG&E are found not to be recoverable, OG&E believes such amount would not be material.

Security Enhancements

On April 8, 2002, OG&E filed a joint application with the OCC requesting approval for security investments and a rider to recover these costs from the ratepayers. On August 14, 2002, OG&E filed testimony with the OCC outlining proposed expenditures and related actions for security enhancement and a proposed recovery rider. Attempting to make security investments at the proper level, OG&E has developed a set of guidelines intended to minimize long-term or widespread outages, minimize the impact on critical national defense and related customers, maximize the ability to respond to and recover from an attack, minimize the financial impact on OG&E that might be caused by an attack and accomplish these efforts with minimal impact on ratepayers. The OCC Staff retained a security expert to review the report filed by OG&E. OG&E currently expects that hearings will be held in mid-2004.

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

Southwest Power Pool

OG&E is a member of the Southwest Power Pool (“SPP”), the regional reliability organization for all or parts of Oklahoma, Arkansas, Kansas, Louisiana, New Mexico, Mississippi, Missouri and Texas. OG&E participated with the SPP in the development of regional transmission tariffs and executed an Agency Agreement with the SPP to facilitate interstate transmission operations within this region in 1998. In October 2003, the SPP filed an application with the FERC seeking authority to form an RTO. On February 10, 2004, the FERC conditionally approved the SPP’s application. The SPP must meet certain conditions before it may commence operations as an RTO. On April 27, 2004, the SPP Board of Directors took actions to meet the conditions to satisfy the FERC requirement for formal approval of the RTO. The SPP compliance filing at the FERC was made on May 3, 2004. It is not known at this time whether the FERC will grant RTO status to the SPP.

FERC Standards of Conduct

In October 2001, the FERC issued a Notice of Proposed Rulemaking proposing to adopt new standards of conduct rules applicable to all jurisdictional electric and natural gas transmission providers. The proposed rules would replace the current rules governing the

electric transmission and wholesale electric functions of electric utilities and the rules governing natural gas transportation and wholesale gas supply functions. The proposed rules would expand the definition of “affiliate” and further limit communications between transmission functions and supply functions, and could materially increase operating costs of market participants, including OG&E and Enogex. In April 2002, the FERC Staff issued a reaction paper, generally rejecting the comments of parties opposed to the proposed rules. On November 25, 2003, the FERC issued its new rules regulating the relationship between electric and gas transmission providers and those entities’ merchant personnel and energy affiliates. The FERC’s final rule requires all transmission providers to be in full compliance with the new rules by June 1, 2004. In February 2004, OG&E and Enogex submitted plans and schedules to take the necessary actions to be in compliance with these new rules and expect that their initial costs to comply with the final rule will not exceed $1.6 million in 2004. On April 16, 2004, the FERC issued an order on rehearing in which the FERC largely rejected requests to revise its November 25 final rule. However, the FERC did extend the compliance date until September 2004 and did clarify certain aspects of the rule. The impact of those clarifications on compliance costs is not known at this time.

Market-Based Rate Authority

On April 14, 2004, the FERC issued (1) interim requirements for FERC jurisdictional electric utilities who have been granted authority to make wholesale sales at market-based rates, and (2) an order initiating a new rulemaking on future market-based rates authorizations. The interim method for analyzing generation market power requires two assessments – whether the utility is a pivotal supplier based on a control area’s annual peak demand and whether the utility exceeds certain market share thresholds on a seasonal basis. If an applicant is determined to have generation market power, the applicant must propose a market power mitigation plan. The new interim assessment methods are applicable to all pending initial market-based rate applications and triennial reviews pending the rulemaking described below. The triennial reviews of OG&E and OERI are currently pending before the FERC. In the rulemaking proceeding, the FERC is seeking comments on the adequacy of the FERC’s current analysis of market-based rate filings, including the adequacy of the new “interim” assessment of generation market power. The Company is reviewing the new requirements to determine what, if any, impact the new requirements will have on the wholesale market-based rate authority of OG&E and OERI.

Department of Energy Blackout Report

On April 6, 2004, the U.S. Department of Energy issued its final report regarding the August 14, 2003 electric blackout in the eastern United States, which did not affect OG&E’s electric system. The report recommends a number of specific changes to current statutes, rules or practices in order to improve the reliability of the infrastructure used to transmit electric power. The recommendations include the establishment of mandatory reliability standards and financial penalties for noncompliance. On April 14, 2004, the FERC issued a policy statement requiring electric utilities, including OG&E, to submit a report on vegetation management practices and indicating the FERC’s intent to make North American Electric Reliability Council reliability standards mandatory. OG&E is reviewing the final report and the FERC policy statement. Implementation of the blackout report recommendations and the FERC policy

statement could increase future transmission costs, but the extent of the increased costs is not known at this time.

Redbud Tariff Filing

On March 5, 2004, Redbud Energy LP (“Redbud”) filed a rate schedule with the FERC in Docket No. ER04-622-000 under which Redbud proposed to charge OG&E a rate for transmission service Redbud alleges it provides to OG&E over certain facilities that Redbud constructed to connect its generation facility to the OG&E transmission grid. Redbud claims that the facilities cost approximately $19.3 million, and seeks to recover this amount from OG&E over a 60-month period. Also on March 5, 2004, Redbud filed an application with the FERC in Docket No. EG04-38-000 asking the FERC to rule that Redbud can charge OG&E this fee for transmission service and remain an exempt wholesale generator under Section 32 of the Public Utility Holding Company Act of 1935. OG&E opposed Redbud’s filings in the two dockets on the grounds that Redbud is not entitled to impose such a transmission rate, and that the imposition of such a rate is inconsistent with Redbud’s status as an exempt wholesale generator. On May 4, 2004, the FERC issued an order rejecting Redbud’s proposed rate schedule. At this time, OG&E does not know whether Redbud intends to challenge the FERC’s May 4, 2004 order.

State Restructuring Initiatives

Oklahoma

As previously reported, the Oklahoma legislature originally adopted the Electric Restructuring Act of 1997 (the “1997 Act”) to provide retail customers in Oklahoma with a choice of their electric supplier. The scheduled start date for customer choice has been indefinitely postponed. In the 2003 legislative session, attempts to repeal the 1997 Act were initiated, but the session ended without repeal of the 1997 Act. It is unknown at this time whether the 1997 Act will be repealed.

Arkansas

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

17. Fair Value of Financial Instruments

The following information is provided regarding the estimated fair value of the Company’s financial instruments, including derivative contracts related to the Company’s price risk management activities, which have significantly changed since December 31, 2003.

	March 31, 2004						December 31, 2003
		Carrying			Fair			Carrying			Fair
(In millions)		Amount			Value			Amount			Value

Price Risk Management Assets
Energy Trading Contracts	$	97	.0	$	97	.0	$	67	.2	$	67	.2
Interest Rate Swaps		15	.4		15	.4		7	.6		7	.6
Price Risk Management Liabilities
Energy Trading Contracts	$	84	.8	$	84	.8	$	51	.4	$	51	.4

The carrying value of the financial instruments on the Condensed Consolidated Balance Sheets not otherwise discussed above approximates fair value except for long-term debt which is valued at the carrying amount. The valuation of the Company’s interest rate swaps and energy trading contracts was determined primarily based on quoted market prices. However, in certain instances where market quotes are not available, other valuation techniques or models are used to estimate market values. The valuation of instruments also considers the credit risk of the counterparties and the potential impact of liquidating the position in an orderly manner over a reasonable period of time.

Item 2. Management’s Discussion and Analysis of Financial Condition
and Results of Operations.

Introduction

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.

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 (collectively, “Enogex’s businesses”). Enogex’s focus is to utilize its gathering, processing, transportation and storage capacity to execute physical, financial and service transactions to capture revenues across different commodities, locations or time periods. The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are located in the major gas producing basins of Oklahoma. Through a 75 percent interest in the NOARK Pipeline System Limited Partnership, Enogex also owns a controlling interest in and operates the Ozark Gas Transmission System (“Ozark”), a FERC regulated interstate pipeline that extends from southeast Oklahoma through Arkansas to southeast Missouri. Enogex sold its interests in certain gas gathering and processing assets in Texas in the first quarter of 2003 which is reported in the Condensed Consolidated Financial Statements as discontinued operations.

Forward-Looking Statements

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

timing of the entry of additional competition in the markets served by the Company; unusual weather; state and federal legislative and regulatory decisions and initiatives; changes in accounting standards, rules or guidelines; creditworthiness of suppliers, customers, and other contractual parties; completion of the pending acquisition of a power plant; and the other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission including Exhibit 99.01 to the Company’s Form 10-K for the year ended December 31, 2003.

Overview

General

The following discussion and analysis presents factors which affected the Company’s consolidated results of operations for the three months ended March 31, 2004 as compared to the same period in 2003 and the Company’s consolidated financial position at March 31, 2004. The following information should be read in conjunction with the Condensed Consolidated Financial Statements and Notes thereto and the Company’s Form 10-K for the year ended December 31, 2003. Known trends and contingencies of a material nature are discussed to the extent considered relevant.

In the first quarter of 2003, Enogex sold its interests in certain gas gathering and processing assets that were owned by Enogex through its interest in the NuStar Joint Venture (“NuStar”). As required by accounting principles generally accepted in the United States, these dispositions have been reported as discontinued operations for the three months ended March 31, 2004 and 2003 in the Condensed Consolidated Financial Statements.

Operating Results

The Company reported net income of approximately $10.2 million, or $0.12 per share, as compared to a net loss of approximately $0.3 million, or less than $0.01 per share, for the three months ended March 31, 2004 and 2003, respectively. The increase in net income during the three months ended March 31, 2004 as compared to the same period in 2003 was primarily due to higher gross margin on revenues (“gross margin”) in Enogex’s transportation and storage business and Enogex’s gathering and processing business, lower income tax expense at Enogex, lower interest expenses at the holding company and improved earnings at OG&E. These increases to net income were partially offset by a lower gross margin in Enogex’s marketing business and higher operating expenses at Enogex. The Company’s results of operations for the three months ended March 31, 2004 and 2003 include income of approximately $0.4 million, or $0.01 per share, and $1.3 million, or $0.02 per share, from the discontinued operations discussed above. See “Results of Operations – Enogex – Discontinued Operations” below for a further discussion.

OG&E reported break-even results for the three months ended March 31, 2004 as compared to a net loss of approximately $3.3 million, or $0.04 per share, for the three months ended March 31, 2003. The improvement in earnings during the three months ended March 31, 2004 as compared to the same period in 2003 was primarily attributable to higher gross margins from growth in OG&E’s service territory and additional fuel recoveries from its customers

partially offset by warmer than normal weather as heating degree days were 14 percent below the first quarter of 2003. Also contributing to OG&E’s improvement were lower net interest expense and Oklahoma investment tax credits of approximately $1.7 million during the three months ended March 31, 2004.

Enogex’s operations, including discontinued operations, reported net income of approximately $12.8 million, or $0.15 per share, and $5.5 million, or $0.07 per share, for the three months ended March 31, 2004 and 2003, respectively. This improvement during the three months ended March 31, 2004 as compared to the same period in 2003 was primarily attributable to higher gross margins in Enogex’s transportation and storage business and Enogex’s gathering and processing business from, among other things, increased levels of transportation and storage revenues, revenue improvements generated from the negotiation of both new contracts and replacement contracts at better terms that resulted in increases in gathering fees and reductions in the purchase price of gas in addition to the revenue impact from increased natural gas gathering volumes. These increases were partially offset by a lower gross margin in Enogex’s marketing business and higher operating expenses. Also contributing to Enogex’s improvement were lower net interest expense and lower income tax expense from Oklahoma investment tax credits of approximately $2.0 million during the three months ended March 31, 2004.

As stated above, Enogex’s interest in NuStar has been reported as discontinued operations for the three months ended March 31, 2004 and 2003 in the Condensed Consolidated Financial Statements as these assets have been sold. The Company’s results of operations for the three months ended March 31, 2004 and 2003 include income of approximately $0.4 million, or $0.01 per share, and $1.3 million, or $0.02 per share, from the discontinued operations discussed above. This decrease was attributable to the sale of NuStar in the first quarter of 2003 partially offset from funds received related to an overpayment of natural gas purchases in a prior period. See “Results of Operations – Enogex – Discontinued Operations” below for a further discussion.

During the three months ended March 31, 2004, Enogex had a total of approximately $3.8 million in net income relating to various non-recurring items. The Oklahoma investment tax credit provided a positive earnings contribution of approximately $2.0 million and additional fuel recoveries provided a positive earnings contribution of approximately $1.1 million. In addition, Enogex had a gain on the sale of compressors of approximately $0.7 million and income from discontinued operations contributed approximately $0.4 million. These increases were partially offset by approximately a $0.4 million decrease in other miscellaneous items. During the three months ended March 31, 2003, Enogex had a total of approximately $2.4 million in net income relating to various non-recurring items. The gain on the sale of a portion of the Ozark pipeline provided a positive earnings contribution of approximately $2.4 million and income from discontinued operations provided a positive earnings contribution of approximately $1.3 million. In addition, Enogex had a prior period adjustment which provided a positive earnings contribution of approximately $1.1 million and other miscellaneous items contributed approximately $0.2 million. These increases were partially offset by a decrease in fuel recoveries of approximately $0.9 million and an income tax adjustment of approximately $1.7 million.

The results of the holding company reflect a loss of $0.03 per share for each of the three months ended March 31, 2004 and 2003.

2002 Settlement Agreement

On October 11, 2002, OG&E, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to settle OG&E’s rate case. The administrative law judge subsequently recommended approval of the agreed-upon settlement (the “Settlement Agreement”) and on November 22, 2002, the OCC signed a rate order containing the provisions of the Settlement Agreement. The Settlement Agreement provides for, among other items: (i) a $25.0 million annual reduction in the electric rates of OG&E’s Oklahoma customers which went into effect January 6, 2003; (ii) recovery by OG&E, through rate base, of the capital expenditures associated with the January 2002 ice storm; (iii) OG&E to acquire electric generation of not less than 400 megawatts (“MW”) (“New Generation”) to be integrated into OG&E’s generation system; and (iv) recovery by OG&E, over three years, of the $5.4 million in deferred operating costs, associated with the January 2002 ice storm, through OG&E’s rider for sales to other utilities and power marketers (“off-system sales”). Previously, OG&E had a 50/50 sharing mechanism in Oklahoma for any off-system sales. The Settlement Agreement provided that the first $1.8 million in annual net profits from OG&E’s off-system sales will go to OG&E, the next $3.6 million in annual net profits from off-system sales will go to OG&E’s Oklahoma customers, and any net profits of off-system sales in excess of these amounts will be credited in each sales year with 80 percent to OG&E’s Oklahoma customers and the remaining 20 percent to OG&E. If any of the $5.4 million is not recovered at the end of the three years, the OCC will authorize the recovery of any remaining costs.

Pending Acquisition of Power Plant

As part of the 2002 Settlement Agreement with the OCC, OG&E undertook to acquire New Generation of not less than 400 MWs. The acquisition of a 77 percent interest in the 520 MW NRG McClain Station (the “McClain Plant”) would clearly constitute an acquisition of such New Generation under the Settlement Agreement. OG&E expects this New Generation, including the interim power purchase agreement, will provide savings, over a three-year period, in excess of $75.0 million to its Oklahoma customers. These savings were to be derived from: (i) the avoidance of purchase power contracts otherwise needed; (ii) replacing an above market cogeneration contract with PowerSmith when it can be terminated at the end of August 2004; and (iii) fuel savings associated with operating efficiencies of the new plant. In the event OG&E is unable to demonstrate at least $75.0 million in savings to its customers during this 36-month period, OG&E will have an obligation to credit its Oklahoma customers any unrealized savings below $75.0 million as determined at the end of the 36-month period, which shall be no later than December 31, 2006. PowerSmith has filed an application with the OCC seeking to compel OG&E to continue purchasing power from PowerSmith’s qualified cogeneration facility under the Public Utility Regulatory Policy Act of 1978 at a price that would include an avoided capacity charge equal to the lesser of (i) the rate currently specified in the power purchase agreement between OG&E and PowerSmith or (ii) the avoided cost of the McClain Plant. On March 29, 2004, OG&E and PowerSmith reached a tentative, 15-year power sales agreement under which OG&E will continue to purchase electric power from PowerSmith. The terms of

the agreement are being finalized and will be subject to approval by the OCC. In conjunction with OG&E’s agreement with PowerSmith, PowerSmith is in the process of completing a long-term steam sales agreement with Dayton Tire. On April 15, 2004, OG&E and PowerSmith provided an update to the OCC regarding completion of the contract and the OCC scheduled a hearing for May 11, 2004 in this case. OG&E’s ability to meet its guarantee of customer savings of at least $75 million over three years is not expected to be materially affected by this new agreement to purchase electric power from PowerSmith.

In the event OG&E did not acquire the New Generation by December 31, 2003, the Settlement Agreement requires OG&E to credit $25.0 million annually (at a rate of 1/12 of $25.0 million per month for each month that the New Generation is not in place) to its Oklahoma customers beginning January 1, 2004 and continuing through December 31, 2006. However, if OG&E purchases the New Generation subsequent to January 1, 2004, the credit to Oklahoma customers will terminate in the first month that the New Generation begins initial operations and any previously-credited amounts to Oklahoma customers will be deducted in the determination of the $75.0 million targeted savings.

order which included new mitigation measures that were designed to allow for prompt approval of the transaction. That request is still pending before the FERC. OG&E has no indication whether the FERC will accept those proposed mitigation measures. On March 2, 2004, OG&E filed testimony and exhibits with the FERC administrative law judge. The testimony and exhibits indicate that, if the case proceeds to hearing, the wholesale market power issues that the FERC raised in the December 18, 2003 order may be resolved by the proposed mitigation measures. OG&E also filed on March 8, 2004, in the proceeding before the FERC administrative law judge an offer of settlement proposing additional mitigation measures at an aggregate cost of approximately $18.5 million and, despite opposition from certain intervenors, requested the administrative law judge to certify the offer as a contested settlement. Following a denial of OG&E’s request, OG&E asked the administrative law judge to reconsider his decision or, alternatively, to grant OG&E an interlocutory appeal to the FERC of his decision. The FERC administrative law judge denied OG&E’s requests and OG&E is appealing his decision to the FERC. Absent FERC granting OG&E’s January 20 motion for reconsideration or its most recent appeal, the matter is scheduled for hearing before the FERC administrative law judge on August 3, 2004.

Despite the delay at the FERC, an agreement to purchase power from the McClain Plant is enabling OG&E to honor the customer savings as outlined in the Settlement Agreement. On April 28, 2004, the OCC confirmed the steps that OG&E has taken to comply with the Settlement Agreement, including the power purchase agreement with the McClain Plant, were resulting in customer savings being delivered beginning January 1, 2004, and that no further rate reduction is necessary.

Outlook

The Company currently expects that consolidated earnings in 2004 will be between $1.60 and $1.70 per share, which includes the positive impact of non-recurring items during the first quarter of 2004. The 2004 outlook includes expected net income of between $120 million and $124 million at OG&E and between $34 million and $38 million at Enogex, while the holding company will likely post a net loss of approximately $13 million to $14 million. OG&E’s 2004 earnings expectations have been increased primarily due to an increase in gross margins driven by approximately $6.0 million of additional fuel recoveries from its customers as well as a reduction in operating and maintenance expenses of approximately $4.9 million primarily due to a decrease in projected pension expense. Enogex’s 2004 earnings expectations have been increased primarily due to non-recurring items of approximately $5.0 million primarily in Enogex’s transportation and storage business in addition to continued business improvements of approximately $2.0 million primarily in Enogex’s gathering and processing business. The holding company’s 2004 earnings expectations have been increased primarily due to lower than forecasted commercial paper levels. The Company has assumed approximately 88.2 million average common shares outstanding for 2004, reflecting the full year impact of the Company’s August 2003 equity issuance and the issuance of approximately 2.0 million additional shares (approximately $50.0 million of common stock) through the Company’s Automatic Dividend Reinvestment and Stock Purchase Plan (“DRIP”) in the second half of 2004. Additionally, funding for the Company’s pension plan is expected to be approximately $69.0 million in 2004. The Company expects to fund the pension plan during the second and third quarters of 2004. In April 2004, the Company funded approximately $23.0 million to the pension plan. In addition to issuing long-term debt to support the acquisition of New Generation, the Company also anticipates calling $200 million of 8.375 percent trust preferred securities at the holding company and replacing them with a combination of long-term and short-term debt. The replacement of the trust preferred securities will be dependent upon the interest rate environment, access to the capital markets and regulatory and other considerations. The 2004 outlook also includes approximately $6.2 million of additional interest expense at the holding company for unamortized debt expense associated with calling the trust preferred securities. Expected 2004 net income assumes a 38.7 percent effective tax rate.

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 impairment or gain on the disposition of assets that may be identified as not being strategic have not been determined.

Results of Operations

	Three Months Ended March 31,
(In millions, except per share data)		2004			2003

Operating income	$	31	.0	$	27	.7
Net income (loss)	$	10	.2	$	(0	.3)
Basic average common shares outstanding		87	.5		78	.7
Diluted average common shares outstanding		88	.1		78	.9
Basic and diluted earnings per average common share	$	0.1	2	$	-	--
Dividends declared per share	$	0.332	5	$	0.332	5

In reviewing its consolidated operating results, the Company believes that it is appropriate to focus on operating income as reported in its Condensed Consolidated Statements of Operations as operating income indicates the ongoing profitability of the Company excluding unusual or infrequent items, the cost of capital and income taxes. Operating income was approximately $31.0 million and $27.7 million for the three months ended March 31, 2004 and 2003, respectively. These amounts exclude the results of NuStar, which as explained above, was sold in the first quarter of 2003 and which is reported as discontinued operations. See “Enogex – Discontinued Operations” below for a further discussion.

Operating Income by Business Segment

	Three Months Ended March 31,
(In millions)		2004			2003

OG&E (Electric Utility)	$	5	.0	$	2	.1
Enogex (Natural Gas Pipeline) (A)		26	.0		25	.2
Other Operations (B)		-	--		0	.4

Consolidated operating income	$	31	.0	$	27	.7

(A) Excludes discontinued operations.
(B) Other Operations primarily includes unallocated corporate expenses.

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

OG&E	Three Months Ended March 31,
(Dollars in millions)		2004			2003

Operating revenues	$	304	.3	$	332	.6
Fuel		108	.0		141	.2
Purchased power		75	.2		72	.7

Gross margin on revenues		121	.1		118	.7
Other operating expenses		116	.1		116	.6

Operating income	$	5	.0	$	2	.1

Operating revenues by classification
Residential	$	125	.0	$	127	.9
Commercial		69	.1		77	.4
Industrial		64	.9		69	.4
Public authorities		28	.9		32	.7
Sales for resale		12	.6		13	.4
Other		3	.7		10	.2

System sales revenues		304	.2		331	.0
Off-system sales revenues		0	.1		1	.6

Total operating revenues	$	304	.3	$	332	.6

MWH (A) sales by classification (in millions)
Residential		1	.9		2	.0
Commercial		1	.3		1	.3
Industrial		1	.7		1	.6
Public authorities		0	.6		0	.6
Sales for resale		0	.3		0	.4

System sales		5	.8		5	.9
Off-system sales		-	--		-	--

Total sales		5	.8		5	.9

Number of customers		728,3	23		720,7	01

Average cost of energy per KWH (B) - cents
Fuel		2.1	72		2.7	47
Fuel and purchased power		2.9	62		3.4	52

Degree days (C)
Heating
Actual		1,7	85		2,0	86
Normal		1,9	82		1,9	63
Cooling
Actual			18			3
Normal			8			8


(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.

OG&E’s operating income for the three months ended March 31, 2004 increased approximately $2.9 million as compared to the same period in 2003. The increase in operating income was primarily attributable to higher gross margins from growth in OG&E’s service territory and additional fuel recoveries from its customers partially offset by warmer than normal weather.

Gross margin, which is operating revenues less cost of goods sold, was approximately $121.1 million for the three months ended March 31, 2004 as compared to approximately $118.7 million during the same period in 2003, an increase of approximately $2.4 million or 2.0 percent. The gross margin increased approximately $4.0 million due to growth in OG&E’s service territory and additional fuel recoveries from its customers of approximately $1.0 million partially offset by a decrease of approximately $2.6 million due to warmer than normal weather as heating degree days were 14 percent below the first quarter of 2003.

Cost of goods sold for OG&E consists of fuel used in electric generation and purchased power. Fuel expense was approximately $108.0 million for the three months ended March 31, 2004 as compared to approximately $141.2 million during the same period in 2003, a decrease of approximately $33.2 million or 23.5 percent. The decrease was primarily due to OG&E optimizing its lower cost fuel in storage. Purchased power costs were approximately $75.2 million for the three months ended March 31, 2004 as compared to approximately $72.7 million during the same period in 2003, an increase of approximately $2.5 million or 3.4 percent. The increase was primarily due to a 14.4 percent increase in the volume of energy purchased primarily due to economic purchases.

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

Other operating expenses, consisting of operating and maintenance expense, depreciation expense and taxes other than income, were approximately $116.1 million for the three months ended March 31, 2004 as compared to approximately $116.6 million during the same period in 2003, a decrease of approximately $0.5 million or 0.4 percent. Operating and maintenance expense decreased approximately $0.5 million or 0.7 percent for the three months ended March 31, 2004 as compared to the same period in 2003. This decrease was primarily due to a decrease of approximately $0.8 million in materials and supplies expense, a decrease of approximately $0.6 million in outside services, a decrease of approximately $0.3 million in overhead allocations by the Company, a decrease of approximately $0.2 million in property insurance costs and a decrease of approximately $0.6 million in miscellaneous other items. These decreases in operating and maintenance expense were partially offset by an increase of approximately $1.4 million in bad debt expense and an increase of approximately $0.6 million in pension expense. Depreciation expense decreased approximately $0.7 million or 2.1 percent for the three months ended March 31, 2004 as compared to the same period in 2003 primarily due to a change in the depreciation rates for OG&E’s power plants. Taxes other than income increased approximately

$0.7 million or 5.8 percent for the three months ended March 31, 2004 as compared to the same period in 2003 primarily due to approximately a $0.4 million increase in payroll taxes and approximately a $0.3 million increase in ad valorem taxes.

Enogex – Continuing Operations

	Three Months Ended March 31,
(Dollars in millions)		2004			2003

Operating revenues	$	749	.2	$	739	.6
Gas and electricity purchased for resale		666	.1		657	.0
Natural gas purchases - other		17	.4		19	.5

Gross margin on revenues		65	.7		63	.1
Other operating expenses		39	.7		37	.9

Operating income	$	26	.0	$	25	.2

New well connects		4	9		3	4

Gathered volumes - TBtu/d (A)		1.0	4		0.9	8
Incremental transportation volumes - TBtu/d		0.4	2		0.4	8

Total throughput volumes -TBtu/d		1.4	6		1.4	6

Natural gas processed - Mmcf/d (B)		47	3		46	3

Natural gas liquids produced (keep whole) - million gallons			4			4
Natural gas liquids produced (POL and fixed-fee) - million gallons		5	3		4	9

Total natural gas liquids produced - million gallons		5	7		5	3

Average sales price per gallon	$	0.65	9	$	0.64	0

(A) Trillion British thermal units per day.
(B) Million cubic feet per day.

Enogex’s operating income for the three months ended March 31, 2004 increased approximately $0.8 million or 3.2 percent as compared to the same period in 2003. The increase was primarily attributable to higher gross margins in Enogex’s transportation and storage business and Enogex’s gathering and processing business from, among other things, increased levels of transportation and storage revenues, revenue improvements generated from the negotiation of both new contracts and replacement contracts at better terms that resulted in increases in gathering fees and reductions in the purchase price of gas in addition to the revenue impact from increased natural gas gathering volumes. These increases were partially offset by a lower gross margin in Enogex’s marketing business and higher operating expenses. Enogex sold its interest in NuStar during the first quarter of 2003; accordingly this is reported as discontinued operations for the three months ended March 31, 2004 and 2003 in the Condensed Consolidated Financial Statements. See “Enogex – Discontinued Operations” below for a further discussion.

Transportation and storage contributed approximately $30.5 million of Enogex’s gross margin for the three months ended March 31, 2004 as compared to approximately $27.7 million during the same period in 2003, an increase of approximately $2.8 million or 10.1 percent. Gross margins increased from higher storage revenues of approximately $1.2 million for the three months ended March 31, 2004 as compared to the same period in 2003. The increased storage revenues were mainly due to increased demand fees from the storage contract with OG&E, which was effective May 2003, and increased demand fees from Enogex’s marketing business partially offset by decreased demand fees from third parties. Gross margin also benefited from higher firm and non-firm revenues and higher pipeline imbalance recovery of approximately $1.0 million. Gross margins also increased by approximately $0.6 million due to the negotiation of both new contracts and replacement contracts at better terms that resulted in increases in gathering fees and reductions in the purchase price of gas. Also contributing to the

increase in gross margin were increased transportation revenues of approximately $0.5 million for the three months ended March 31, 2004 due to increased demand fees from the transportation contract with OG&E, which was effective May 2003. These increases were partially offset by approximately a $1.1 million decrease in the gross margin due to recording natural gas storage inventory at the lower of cost of market during the three months ended March 31, 2004 as this natural gas storage inventory was previously classified as Property, Plant and Equipment and was reclassified to Fuel Inventories on the Condensed Consolidated Balance Sheets at December 31, 2003.

Gathering and processing contributed approximately $32.4 million of Enogex’s gross margin for the three months ended March 31, 2004 as compared to approximately $22.1 million during the same period in 2003, an increase of approximately $10.3 million or 46.6 percent. Gathering gross margins increased approximately $9.7 million for the three months ended March 31, 2004 as compared to the same period in 2003 primarily due to an overall favorable business environment, revenue improvements generated from the negotiation of both new contracts and replacement contracts at better terms that resulted in increases in gathering fees and reductions in the purchase price of gas and the revenue impact from increased natural gas gathering volumes. Processing gross margins increased approximately $0.6 million for the three months ended March 31, 2004 as compared to the same period in 2003. The increase was primarily due to an expense reallocation for field compressor fuel recorded in processing in 2003 and in gathering in 2004 partially offset by default processing fees recorded during the three months ended March 31, 2003.

Marketing contributed approximately $2.8 million of Enogex’s gross margin for the three months ended March 31, 2004 as compared to approximately $13.3 million during the same period in 2003, a decrease of approximately $10.5 million or 78.9 percent. Gross margin included gains from the sale of natural gas in storage of approximately $2.1 million and $10.2 million, respectively, during the three months ended March 31, 2004 and 2003. The decrease in the gains of the sale of natural gas in storage was primarily due to Enogex recording a $9.0 million pre-tax loss as a cumulative effect of a change in accounting principle in the first quarter of 2003 rather than this loss being included 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 Condensed Consolidated Financial Statements for a further discussion. Also contributing to the decrease was approximately a $0.8 million increase in demand fees for storage services paid to Enogex’s transportation and storage business and third parties.

Other operating expenses, consisting of operating and maintenance expense, depreciation expense and taxes other than income, for Enogex were approximately $39.7 million for the three months ended March 31, 2004 as compared to approximately $37.9 million during the same period in 2003, an increase of approximately $1.8 million or 4.7 percent. Operating and maintenance expenses were approximately $23.3 million for the three months ended March 31, 2004 as compared to approximately $22.4 million during the same period in 2003, an increase of approximately $0.9 million or 4.0 percent. The increase was primarily due to approximately a $0.5 million increase in payroll, benefit and pension expenses, higher materials and supplies expense of approximately $0.3 million and higher outside service costs of

approximately $0.3 million. These increases were partially offset by approximately $0.2 million of lower lease payments from the dissolution of a lease in the third quarter of 2003. Depreciation expense was approximately $11.5 million for the three months ended March 31, 2004 as compared to approximately $11.2 million during the same period in 2003, an increase of approximately $0.3 million or 2.7 percent. The increase was primarily due to a higher level of depreciable plant. Taxes other than income were approximately $4.9 million for the three months ended March 31, 2004 as compared to approximately $4.3 million during the same period in 2003, an increase of approximately $0.6 million or 14.0 percent. The increase was primarily due to approximately a $0.3 million increase in ad valorem taxes and approximately a $0.2 million increase in payroll taxes.

Consolidated Other Income and Expense, Interest Expense and Income Tax Expense

Other income includes, among other things, contract work performed by OG&E, non-operating rental income, gain on the sale of assets, profit on the retirement of fixed assets, minority interest income and miscellaneous non-operating income. Other income was approximately $2.8 million for the three months ended March 31, 2004 as compared to approximately $6.1 million during the same period in 2003, a decrease of approximately $3.3 million or 54.1 percent. The decrease was primarily due to the recognition, in the first quarter of 2003, of a pre-tax gain of approximately $5.3 million related to the sale of approximately 29 miles of transmission lines of the Ozark pipeline in January 2003. This decrease was partially offset by approximately a $1.2 million increase from gains on the sale of certain of Enogex’s compression and processing assets in the first quarter of 2004 and approximately a $0.8 million increase due to an increase in the assets associated with the deferred compensation plan and retirement restoration plan.

Other expense includes, among other things, expenses from loss on the sale of assets, loss on retirement of fixed assets, minority interest expense, miscellaneous charitable donations, expenditures for certain civic, political and related activities and miscellaneous deductions. Other expense was approximately $1.5 million for the three months ended March 31, 2004 as compared to approximately $2.9 million during the same period in 2003, a decrease of approximately $1.4 million or 48.3 percent. This decrease was primarily due to the recognition, in the first quarter of 2003, of approximately $1.1 million in minority interest expense related to the gain from the sale of approximately 29 miles of transmission lines of the Ozark pipeline in January 2003 that was attributable to the minority interest.

Net interest expense includes interest income, interest expense and other interest charges. Net interest expense was approximately $23.1 million for the three months ended March 31, 2004 as compared to approximately $24.7 million during the same period in 2003, a decrease of approximately $1.6 million or 6.5 percent. This decrease was primarily due to approximately a $0.8 million decrease related to lower interest expense accruals during the three months ended March 31, 2004 as compared to the same period in 2003 due to a reduction in long-term debt and lower interest rates and approximately a $0.7 million decrease in interest expense due to a lower average commercial paper balance for the three months ended March 31, 2004 as compared to the same period in 2003.

Income tax benefit was approximately $0.6 million for the three months ended March 31, 2004 as compared to income tax expense of approximately $1.9 million during the same period in 2003, a decrease in income tax expense of approximately $2.5 million. The decrease was primarily due to lower pre-tax income for Enogex partially offset by a lower pre-tax loss for OG&E. In addition, approximately $3.7 million of Oklahoma investment tax credits were recorded during the three months ended March 31, 2004. Amortization of the federal investment tax credits was approximately $1.3 million for each of the three months ended March 31, 2004 and 2003.

Enogex – Discontinued Operations

Enogex sold its interests in NuStar for approximately $37.0 million in February 2003. The Company recognized approximately a $1.4 million after tax gain related to the sale of these assets in the first quarter of 2003. The final accounting for the NuStar sale was completed in the third quarter of 2003 which resulted in an additional charge of approximately $0.2 million after tax which was recorded in the third quarter of 2003. The final accounting is subject to approval by all parties to the sale of the joint venture interest. During the first quarter of 2004, the Company recognized approximately $0.4 million after tax from funds received related to an overpayment for natural gas purchases in a prior period.

As a result of this sale transaction, Enogex’s interest in NuStar, which was part of the Natural Gas Pipeline segment, has been reported as discontinued operations for the three months ended March 31, 2004 and 2003 in the Condensed Consolidated Financial Statements. Results for the discontinued operations are summarized and discussed below.

	Three Months Ended March 31,
(In millions)		2004			2003

Operating revenues	$	0	.7	$	7	.8
Gas purchased for resale		-	--		5	.9
Natural gas purchases - other		-	--		0	.6

Gross margin on revenues		0	.7		1	.3
Other operating expenses		-	--		1	.4

Operating income (loss)		0	.7		(0	.1)

Other income		-	--		2	.4
Net interest expense		-	--		0	.1
Income tax expense		0	.3		0	.9

Net income	$	0	.4	$	1	.3

The decreases were all attributable to the fact that following the sale of NuStar in February 2003, no operations of NuStar are reflected in the Condensed Consolidated Financial Statements except for approximately $0.7 million received during the first quarter of 2004 related to an overpayment of natural gas purchases in a prior period.

Financial Condition

The balance of Cash and Cash Equivalents was approximately $149.6 million and $245.6 million at March 31, 2004 and December 31, 2003, respectively, a decrease of approximately $96.0 million or 39.1 percent. The decrease was primarily due to an increase in short-term investments at December 31, 2003 in anticipation of the planned acquisition of the McClain Plant. Due to a delay in the completion of the McClain Plant acquisition, the Company used short-term investments and proceeds received from the sale of natural gas inventory at Enogex during the first quarter of 2004 to reduce the outstanding commercial paper balance.

The balance of Accounts Receivable was approximately $317.4 million and $350.2 million at March 31, 2004 and December 31, 2003, respectively, a decrease of approximately $32.8 million or 9.4 percent. The decrease was primarily due to a decrease in OG&E’s billings to its customers reflecting lower fuel costs in March 2004 as compared to December 2003 and warmer than normal weather.

The balance of Fuel Inventories was approximately $64.9 million and $163.3 million at March 31, 2004 and December 31, 2003, respectively, a decrease of approximately $98.4 million or 60.3 percent. The decrease was primarily due to inventory sales at Enogex during the first quarter of 2004, a decrease in natural gas inventory primarily due to it being advantageous for the Company to use the lower priced fuel in inventory rather than purchasing higher priced natural gas during the first quarter of 2004 and a decrease in coal inventories due to the coal train unloading system at the Sooner Plant being out of service for most of the first quarter of 2004.

The balance of current Price Risk Management assets was approximately $87.0 million and $61.3 million at March 31, 2004 and December 31, 2003, respectively, an increase of approximately $25.7 million or 41.9 percent. The increase was due to an increase in park and loan transactions and natural gas storage withdrawals associated with OGE Energy Resources, Inc.’s (“OERI”) activities during the three months ended March 31, 2004. This increase is offset by an increase in current Price Risk Management liabilities.

The balance of Short-Term Debt was approximately $202.5 million at December 31, 2003 primarily due to the planned acquisition of the McClain Plant. There was no short-term debt outstanding at March 31, 2004. Due to a delay in the completion of the McClain Plant acquisition, the Company used short-term investments and proceeds received from the sale of natural gas inventory by Enogex during the first quarter of 2004 to reduce the outstanding commercial paper balance.

The balance of current Price Risk Management liabilities was approximately $76.1 million and $46.9 million at March 31, 2004 and December 31, 2003, respectively, an increase of approximately $29.2 million or 62.3 percent. The increase was due to an increase in park and loan transactions and natural gas storage withdrawals associated with OERI’s activities during the three months ended March 31, 2004. This increase was partially offset by an increase in current Price Risk Management assets.

Off-Balance Sheet Arrangements

Off-balance sheet arrangements include any transactions, agreements or other contractual arrangements to which an unconsolidated entity is a party and under which the Company has: (i) any obligation under a guarantee contract having specific characteristics as defined in Financial Accounting Standards Board (“FASB”) Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”; (ii) a retained or contingent interest in assets transferred to an unconsolidated entity or similar arrangement that serves as credit, liquidity or market risk support to such entity for such assets; (iii) any obligation, including a contingent obligation, under a contract that would be accounted for as a derivative instrument but is indexed to the Company’s own stock and is classified in stockholders’ equity in the Company’s consolidated balance sheet; or (iv) any obligation, including a contingent obligation, arising out of a variable interest as defined in FASB Interpretation No. 46, “Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin No. 51” in an unconsolidated entity that is held by, and material to, the Company, where such entity provides financing, liquidity, market risk or credit risk support to, or engages in leasing, hedging or research and development services with, the Company. Except as set forth below, there have been no significant changes in the Company’s off-balance sheet arrangements reported in the Company’s Form 10-K for the year ended December 31, 2003.

Energy Insurance Bermuda Ltd. Mutual Business Program No. 19

Energy Insurance Bermuda Ltd. (“EIB”) is incorporated in Bermuda under the Companies Act of 1981, as amended. The Company began participating in EIB through Mutual Business Program No. 19 (“MBP 19”) on November 15, 1998. The Company is the sole participant in MBP 19. The Company has issued an $8.0 million standby letter of credit to MBP 19 for the benefit of insuring parts of the Company’s property and liability insurance programs. MBP 19 was established to provide $15.0 million worth of property and liability insurance for the Company. The $8.0 million letter of credit was issued to provide protection for MBP 19 in case of large insurance claim losses. At December 31, 2003, there were no drawings against this letter of credit. Since a letter of credit was issued, the total equity investment at risk of MBP 19 was not sufficient to permit it to finance its activities without additional subordinated financial support from other parties. Therefore, MBP 19 was considered a VIE as defined in Interpretation No. 46 and the Company is the primary beneficiary which resulted in the consolidation of MBP 19 into the Company’s Consolidated Financial Statements for the year ended December 31, 2003. Effective January 1, 2004, the reinsurer of the MBP 19 program agreed to remove the guarantee requirement which will enable the Company to terminate the standby letter of credit previously provided. However, the reinsurer added a ratings trigger requirement in the revised agreement such that if the commercial paper rating of the Company is lowered by two grades, MBP 19 may be surcharged an additional premium, which may result in an additional premium to the Company. Since the guarantee requirement was removed, the total equity investment at risk of MBP 19 is sufficient to permit it to finance its activities without additional subordinated financial support from other parties. Therefore, MBP 19 is not considered a VIE as defined in Interpretation No. 46 which resulted in the deconsolidation of MBP 19 during the first quarter of 2004.

Liquidity and Capital Requirements

The Company’s primary needs for capital are related to replacing or expanding existing facilities in OG&E’s electric utility business and replacing or expanding existing facilities at Enogex. Other capital requirements are primarily related to maturing debt, operating lease obligations, hedging activities, natural gas storage and delays in recovering unconditional fuel purchase obligations. The Company generally meets its cash needs through a combination of internally generated funds, short-term borrowings and permanent financings.

Interest Rate Swap Agreements

At March 31, 2004 and December 31, 2003, the Company had three outstanding interest rate swap agreements: (i) OG&E entered into an interest rate swap agreement, effective March 30, 2001, to convert $110.0 million of 7.30 percent fixed rate debt due October 15, 2025, to a variable rate based on the three month London InterBank Offering Rate (“LIBOR”) and (ii) Enogex entered into two separate interest rate swap agreements, effective July 15, 2002 and October 24, 2002, to convert $100.0 million of 8.125 percent fixed rate debt due January 15, 2010, to a variable rate based on the six month LIBOR. The objective of these interest rate swaps was to achieve a lower cost of debt and to raise the percentage of total corporate long-term floating rate debt to reflect a level more in line with industry standards. These interest rate swaps qualified as fair value hedges under Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and met all of the requirements for a determination that there was no ineffective portion as allowed by the shortcut method under SFAS No. 133.

Future Capital Requirements

Capital Expenditures

The Company’s current 2004 to 2006 construction program includes the purchase of New Generation as discussed below. OG&E currently has contracts with qualified cogeneration facilities and small power production producers’ (“QF contracts”) for the purchase of 540 MWs, all of which expire in the next one to five years, although as discussed above, OG&E recently tentatively agreed to a new 15-year agreement with one of the QFs. The Company will continue reviewing all of the supply alternatives to these expiring QF contracts that minimize the total cost of generation to our customers, including exercising our 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 Note 16 of Notes to Condensed Consolidated Financial Statements for a description of current proceedings involving a PowerSmith QF contract.

On August 18, 2003, OG&E signed an asset purchase agreement to acquire NRG McClain LLC’s 77 percent interest in the McClain Plant. Closing has been delayed pending receipt of FERC approval. The purchase price for the interest in the McClain Plant is approximately $159.9 million, subject to adjustment for prepaid gas and property taxes. See “Overview – Pending Acquisition of Power Plant.” If approval is received, OG&E expects to fund the acquisition with a combination of a capital contribution from the Company, funded in part by the Company’s equity issuance in August 2003, and the issuance of long-term debt by OG&E. To reliably meet the increased electricity needs of OG&E’s customers during the foreseeable future, OG&E will continue to invest to maintain the integrity of the delivery system. Approximately $10.5 million of the Company’s capital expenditures budgeted for 2004 are to comply with environmental laws and regulations.

Pension and Postretirement Benefit Plans

Future Sources of Financing

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

Short-Term Debt

Short-term borrowings generally are used to meet working capital requirements. The short-term debt balance was approximately $202.5 million at December 31, 2003 primarily due to the planned acquisition of the McClain Plant. There was no short-term debt outstanding at March 31, 2004. Due to a delay in the completion of the McClain Plant acquisition, the Company used short-term investments and proceeds received from the sale of natural gas inventory by Enogex during the first quarter of 2004 to reduce the outstanding commercial paper balance.

Lines of Credit and Available Cash (In millions)
Entity	Amount Available	Amount Outstanding	Maturity
OGE Energy Corp. (A) OG&E OGE Energy Corp. (A)	$ 15.0 100.0 300.0	$ --- --- ---	April 6, 2004 June 26, 2004 December 9, 2004
Cash	415.0 149.6	--- N/A	N/A
Total	$ 564.6	$ ---
(A) The lines of credit at OGE Energy Corp. are used to back up the Company’s commercial paper borrowings. There was no short-term debt outstanding at March 31, 2004. In April 2004, the Company renewed its $15.0 million credit facility, shown in the table above, which matures April 6, 2005.

Asset Sales

Also contributing to the liquidity of the Company have been numerous asset sales by Enogex. Since January 1, 2002, completed sales generated net proceeds of approximately $104.2 million. Sales proceeds generated to date have been used to reduce debt at Enogex and commercial paper at the holding company.

The Company continues to evaluate opportunities to enhance shareowner returns and achieve long-term financial objectives through acquisitions and divestitures of assets that may

complement its existing portfolio. Permanent financing would be required for any such acquisitions.

Critical Accounting Policies and Estimates

The Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements contain information that is pertinent to Management’s Discussion and Analysis. In preparing the Condensed Consolidated Financial Statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material effect on the Company’s Condensed Consolidated Financial Statements particularly as they relate to pension expense and impairment estimates. However, the Company believes it has taken reasonable but conservative positions, where assumptions and estimates are used, in order to minimize the negative financial impact to the Company that could result if actual results vary from the assumptions and estimates. In management’s opinion, the areas of the Company where the most significant judgment is exercised is in the valuation of pension plan assumptions, impairment estimates, contingency reserves, accrued removal obligations, regulatory assets and liabilities, unbilled revenue for OG&E, the allowance for uncollectible accounts receivable, the valuation of energy purchase and sale contracts and natural gas storage inventory and fair value and cash flow hedging policies. The selection, application and disclosure of these critical accounting estimates have been discussed with the Company’s audit committee and are discussed in detail in Management’s Discussion and Analysis of Financial Condition and Results of Operations in the Company’s Form 10-K for the year ended December 31, 2003.

Accounting Pronouncements

See Note 2 of Notes to Condensed Consolidated Financial Statements for a discussion of recent accounting pronouncements.

Electric Competition; Regulation

OG&E and Enogex have been and will continue to be affected by competitive changes to the utility and energy industries. 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 16 of Notes to Condensed Consolidated Financial Statements and in the Company’s Form 10-K for the year ended December 31, 2003.

Gas Transportation and Storage Agreement

Security Enhancements

inquiry and directed the OCC Staff to file a rulemaking proceeding for each utility industry regarding security of the utility system infrastructure and key assets.

Commitments and Contingencies

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 Condensed Consolidated Financial Statements. Except as set forth below, in Note 15 of Notes to Condensed Consolidated Financial Statements and in Note 17 to the Company’s Consolidated Financial Statements included in the Company’s Form 10-K for the year ended December 31, 2003, 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. This assessment of currently pending or threatened lawsuits is subject to change.

Agreement with Colorado Interstate Gas Company

National Steel Corporation

vigorously defend this action. Other than OERI’s $0.9 million claim that was originally reserved, no further reserve is believed to be appropriate at this time.

Pending Acquisition of Power Plant

On August 18, 2003, OG&E signed an asset purchase agreement to acquire NRG McClain LLC’s 77 percent interest in the McClain Plant. Closing has been delayed pending receipt of FERC approval. The acquisition of this interest in the McClain Plant would clearly constitute an acquisition of New Generation under the Settlement Agreement. The purchase price for the interest in the McClain Plant is approximately $159.9 million, subject to adjustment for prepaid gas and property taxes. See “Overview - Pending Acquisition of Power Plant” above and Note 16 of Notes to Condensed Consolidated Financial Statements for a further description of this matter and a description current proceedings involving a PowerSmith QF contract.

Sooner Power Plant Coal Dust Explosion

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Risk Management

The risk management process established by the Company is designed to measure both quantitative and qualitative risks in its businesses. A corporate risk management department, under the direction of a corporate risk oversight management committee, has been established to review these risks on a regular basis. The Company is exposed to market risk in its normal course of business, including changes in certain commodity prices and interest rates. The Company also engages in price risk management activities for both trading and non-trading purposes.

To manage the volatility relating to these exposures, the Company enters into various derivative transactions pursuant to the Company’s policies on hedging practices. Derivative positions are monitored using techniques such as mark-to-market valuation, value-at-risk and sensitivity analysis.

Interest Rate Risk

The Company’s exposure to changes in interest rates relates primarily to long-term debt obligations and commercial paper. The Company manages its interest rate exposure by limiting its variable rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. The Company may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

The Company’s exposure to interest rate risk for changes in interest rates has not significantly changed since December 31, 2003. See Notes 11 and 12 of Notes to Condensed Consolidated Financial Statements for a discussion of the Company’s long-term and short-term debt activity.

Commodity Price Risk

The market risks inherent in the Company’s market risk sensitive instruments, positions and anticipated commodity transactions are the potential losses in value arising from adverse changes in the commodity prices to which the Company is exposed. These market risks are broken into trading, which includes transactions that are voluntarily entered into to capture subsequent changes in commodity prices, and non-trading, which result from the exposure some of the Company’s assets have to commodity prices.

The trading activities are conducted throughout the year subject to daily and monthly trading stop loss limits of $2.5 million. The daily loss exposure from trading activities is measured primarily using value at risk as well as other quantitative risk measurement techniques and is limited to $1.5 million. These limits are designed to mitigate the possibility of trading activities having a material adverse effect on the Company’s operating income.

The prices of natural gas, natural gas liquids and natural gas liquids processing spreads are subject to fluctuations resulting from changes in supply and demand. The changes in these prices have a direct effect on the operating income received by the Company as compensation for operating some of its assets. To partially reduce non-trading commodity price risk incurred in the Company’s normal course of business caused by these market fluctuations, the Company may hedge, through the utilization of derivatives, the effects these market fluctuations have on the operating income received by the Company as compensation for operating these assets. Because the commodities covered by these derivatives are substantially the same commodities that the Company buys and sells in the physical market, no special studies other than monitoring the degree of correlation between the derivative and cash markets are deemed necessary.

A sensitivity analysis has been prepared to estimate the trading and non-trading commodity price exposure to the market risk of the Company’s natural gas and natural gas liquids commodity positions. The Company’s daily net commodity position consists of natural gas inventories, commodity purchase and sales contracts, financial and commodity derivative instruments and anticipated natural gas processing spreads and fuel recoveries. The fair value of such position is a summation of the fair values calculated for each commodity by valuing each net position at quoted market prices. Market risk is estimated as the potential loss in fair value resulting from a hypothetical 10 percent adverse change in such prices over the next 12 months. The results of this analysis, which may differ from actual results, are as follows as of March 31, 2004.

(In millions)	Trading			Non-Trading
Commodity market risk, net	$	0	.1	$	5	.4

Item 4. Controls and Procedures.

The Company maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of the Company’s management, including the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), of the effectiveness of the Company’s disclosure controls and procedures, the CEO and CFO have concluded that the Company’s disclosure controls and procedures are effective.

No change in the Company’s internal control over financial reporting has occurred during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

Reference is made to Part I, Item 3 of the Company’s Form 10-K for the year ended December 31, 2003 for a description of certain legal proceedings presently pending. Except as set forth below, there are no new significant cases to report against the Company or its subsidiaries and there have been no material changes in the previously reported proceedings.

National Steel Corporation

Item 6. Exhibits and Reports on Form 8-K.

(a) Exhibits

	Exhibit No.		Description
	2.01		Amendment No. 6 to Asset Purchase Agreement, dated as of March 12, 2004 by and between OG&E and NRG McClain LLC.
	2.02		Amendment No. 7 to Asset Purchase Agreement, dated as of April 15, 2004 by and between OG&E and NRG McClain LLC.
	10.01		Fourth Amendment to Loan Agreement, dated April 6, 2004 between OGE Energy Corp. and Bank of Oklahoma, N.A.
	31.01		Certifications Pursuant to Rule 13a-15(e)/15d-15(e) As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32.01		Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(b) Reports on Form 8-K

The Company filed a Current Report on Form 8-K on January 16, 2004 to report that OG&E withdrew its request for a $91 million rate increase.

The Company filed a Current Report on Form 8-K on January 28, 2004 to report its consolidated results of operations and financial condition for the fourth quarter and year ended December 31, 2003.

The Company filed a Current Report on Form 8-K on March 29, 2004 to report the retirement of the Executive Vice President and Chief Operating Officer of the Company.

The Company filed a Current Report on Form 8-K on March 30, 2004 to report that OG&E and Smith Cogeneration have reached a tentative power sales agreement.

The Company filed a Current Report on Form 8-K on April 28, 2004 to report that the Oklahoma Corporation Commission issued an order confirming that OG&E was delivering savings to its customers as required under the Settlement Agreement.

The Company filed a Current Report on Form 8-K on May 3, 2004 to provide additional information related to fees paid to Ernst & Young LLP for the year ended December 31, 2003.

The Company filed a Current Report on Form 8-K on May 5, 2004 to report its consolidated results of operations and financial condition for the first quarter ended March 31, 2004.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	OGE ENERGY CORP. (Registrant)
	By	/s/ Donald R. Rowlett
		Donald R. Rowlett Vice President and Controller (On behalf of the registrant and in his capacity as Chief Accounting Officer)

May 7, 2004

Exhibit 2.01

AMENDMENT NO. 6 TO ASSET PURCHASE AGREEMENT

THIS AMENDMENT NO. 6 TO ASSET PURCHASE AGREEMENT (this “Amendment”), dated as of March 12, 2004, is made by NRG McCLAIN LLC, a Delaware limited liability company (“Seller”), and OKLAHOMA GAS AND ELECTRIC COMPANY, an Oklahoma corporation (“Buyer”).

RECITALS

A. Seller and Buyer entered into a Asset Purchase Agreement, dated as of August 18, 2003, as amended by Amendments No. 1, 2, 3, 4 and 5 thereto (as so amended, the “Agreement”; capitalized terms used but not defined in this Amendment have the meanings ascribed to such terms in the Agreement).

B. Seller is the debtor and debtor in possession in Case No. 03-15205(PCB) (the “Case”) under Chapter 11 of the United States Bankruptcy Code currently pending in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court”), which Case is being jointly administered with several other affiliated Chapter 11 cases under Case No. 03-13204(PCB).

C. Seller and Buyer wish to amend the Agreement to revise the optional termination date provided for in the Agreement.

NOW, THEREFORE, in consideration of the premises and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree to amend the Agreement as follows:

ARTICLE I
Amendment to Agreement

SECTION 1.1 Amendment of Section 12.1. Clauses (b) and (c) of Section 12.1 of the Agreement are hereby amended and restated to read as follows:

“(b) Buyer, if the Closing has not occurred on or before April 15, 2004 and the failure to consummate the Asset Purchase on or before such date did not result from the failure by Buyer to fulfill any undertaking or commitment provided for herein that is required to be fulfilled prior to the Closing;

(c) Seller, if the Closing has not occurred on or before April 15, 2004 and the failure to consummate the Asset Purchase on or before such date did not result from the failure by Seller to fulfill any undertaking or commitment provided for herein that is required to be fulfilled prior to the Closing;”.

ARTICLE II
Miscellaneous

SECTION 2.1 References to the Agreement. (a) Each reference in the Agreement to “this Agreement,” “hereunder,” “herein” or words of like import shall mean and be a reference to the Agreement as amended and affected hereby.

(b) Each reference in the other Transaction Documents to the Agreement shall mean and be a reference to the Agreement, as amended and affected hereby.

SECTION 2.2. Effectiveness. This Amendment shall become effective upon the satisfaction, or waiver in writing by Seller and Buyer, of the following conditions:

(a) Each of Seller and Buyer shall have executed this Amendment; and

(b) WestLB AG, as Agent (the “Agent”) for the Lenders parties to that Omnibus Restructuring and Consent Agreement dated as of August 18, 2003 (the “ORCA”), by and among Seller, the Agent, the Lenders and the affiliates of Seller parties thereto, shall have executed a copy of this Amendment for the limited purpose of evidencing its consent to this Amendment in accordance with the provisions of the ORCA.

SECTION 2.3 Ratification. Each of Buyer and Seller acknowledges and ratifies the Agreement and the other Transaction Documents, as amended and affected hereby, and agrees and acknowledges that all the terms thereof as amended and affected hereby, (a) are hereby brought forward for the benefit of the parties thereto, and (b) shall remain in full force and effect.

SECTION 2.4 Governing Law. This Amendment shall be governed by and construed in accordance with the laws of the State of New York without giving effect to any choice or conflict of law provision or rule (whether of the State of New York or any other jurisdiction) that would cause the application of the laws of any jurisdiction other than the State of New York, except to the extent preempted by federal bankruptcy laws.

SECTION 2.5 Headings and Definitions. The Section and Article headings contained in this Amendment are inserted for convenience of reference only and shall not affect the meaning or interpretation of this Amendment. All references to Sections or Articles contained herein mean Sections or Articles of this Amendment unless otherwise stated. All defined terms and phrases herein are equally applicable to both the singular and plural forms of such terms.

SECTION 2.6 Counterparts. This Amendment may be executed in one or more counterparts, all of which shall be considered one and the same agreement, and shall become effective when one or more counterparts have been signed by each of the parties and delivered to the other parties.

SECTION 2.7 Electronic Signatures.

(a) Notwithstanding the Electronic Signatures in Global and National Commerce Act (15 U.S.C. Sec. 7001 et seq.), the Uniform Electronic Transactions Act, or any other Law relating to or enabling the creation, execution, delivery, or recordation of any contract or

signature by electronic means, and notwithstanding any course of conduct engaged in by the Parties, no Party shall be deemed to have executed this Amendment unless and until such Party shall have executed this Amendment on paper by a handwritten original signature or any other symbol executed or adopted by a Party with current intention to authenticate this Amendment.

(b) Delivery of a copy of this Amendment bearing an original signature by facsimile transmission (whether directly from one facsimile device to another by means of a dial-up connection or whether mediated by the worldwide web), by electronic mail in “portable document format” (“.pdf”) form, or by any other electronic means intended to preserve the original graphic and pictorial appearance of a document, or by combination of such means, shall have the same effect as physical delivery of the paper document bearing the original signature. “Originally signed” or “original signature” means or refers to a signature that has not been mechanically or electronically reproduced.

IN WITNESS WHEREOF, each party hereto has caused this Amendment to be duly executed by its authorized officer or representative as of the date first written above.

[Signature pages follow]

	NRG McCLAIN LLC, a Delaware limited liability company
	By:	/s/ George P. Schaefer
	Name:	George P. Schaefer
	Title:	Treasurer

	OKLAHOMA GAS AND ELECTRIC COMPANY, an Oklahoma corporation
	By:	/s/ James R. Hatfield
	Name:	James R. Hatfield
	Title:	Senior Vice President and Chief
		Financial Officer

Consented to in accordance with the provisions of
the ORCA as of the date first written above.

WESTLB AG, NEW YORK BRANCH
As Agent

By:	/s/ Michael G. Pantelogianis
Name:	Michael G. Pantelogianis
Title:	Associate Director

By:	/s/ Jared Brenner
Name:	Jared Brenner
Title:	Director

Exhibit 2.02

AMENDMENT NO. 7 TO ASSET PURCHASE AGREEMENT

THIS AMENDMENT NO. 7 TO ASSET PURCHASE AGREEMENT (this “Amendment”), dated as of April 15, 2004, is made by NRG McCLAIN LLC, a Delaware limited liability company (“Seller”), and OKLAHOMA GAS AND ELECTRIC COMPANY, an Oklahoma corporation (“Buyer”).

RECITALS

A. Seller and Buyer entered into an Asset Purchase Agreement, dated as of August 18, 2003, as amended heretofore (as so amended, the “Agreement”; capitalized terms used but not defined in this Amendment have the meanings ascribed to such terms in the Agreement).

C. Seller and Buyer wish to amend the Agreement to revise the optional termination date provided for in the Agreement.

ARTICLE I
Amendment to Agreement

SECTION 1.1 Amendment of Section 12.1. Clauses (b) and (c) of Section 12.1 of the Agreement are hereby amended and restated to read as follows:

“(b) Buyer, if the Closing has not occurred on or before May 21, 2004 and the failure to consummate the Asset Purchase on or before such date did not result from the failure by Buyer to fulfill any undertaking or commitment provided for herein that is required to be fulfilled prior to the Closing;

(c) Seller, if the Closing has not occurred on or before May 21, 2004 and the failure to consummate the Asset Purchase on or before such date did not result from the failure by Seller to fulfill any undertaking or commitment provided for herein that is required to be fulfilled prior to the Closing;”.

ARTICLE II
Miscellaneous

SECTION 2.1 References to the Agreement. (a) Each reference in the Agreement to “this Agreement,” “hereunder,” “herein” or words of like import shall mean and be a reference to the Agreement as amended and affected hereby.

(b) Each reference in the other Transaction Documents to the Agreement shall mean and be a reference to the Agreement, as amended and affected hereby.

SECTION 2.2. Effectiveness. This Amendment shall become effective upon the satisfaction, or waiver in writing by Seller and Buyer, of the following conditions:

(a) Each of Seller and Buyer shall have executed this Amendment; and

SECTION 2.7 Electronic Signatures.

IN WITNESS WHEREOF, each party hereto has caused this Amendment to be duly executed by its authorized officer or representative as of the date first written above.

[Signature pages follow]

	NRG McCLAIN LLC, a Delaware limited liability company
	By:	/s/ George P. Schaefer
	Name:	George P. Schaefer
	Title:	Treasurer

	OKLAHOMA GAS AND ELECTRIC COMPANY, an Oklahoma corporation
	By:	/s/ James R. Hatfield
	Name:	James R. Hatfield
	Title:	Senior Vice President and Chief
		Financial Officer

Consented to in accordance with the provisions of
the ORCA as of the date first written above.

WESTLB AG, NEW YORK BRANCH
As Agent

By:	/s/ Jared Brenner
Name:	Jared Brenner
Title:	Executive Director

By:	/s/ Ben Wagner
Name:	Ben Wagner
Title:	Manager - Global Specialized Finance

Exhibit 10.01

FOURTH AMENDMENT TO LOAN AGREEMENT

This Fourth Amendment to Loan Agreement (the “Fourth Amendment”) is made effective as of April 6, 2004, by and among OGE Energy Corp., an Oklahoma corporation (“Borrower”), and Bank of Oklahoma, N.A., a national banking association (“Lender”).

R E C I T A L S:

A. Borrower and the Lender previously entered into a Loan Agreement dated April 6, 2001, a First Amendment to Loan Agreement dated June 29, 2001, a Second Amendment dated April 6, 2002, and a Third Amendment dated April 6, 2003 (collectively, the “Loan Agreement”), which governs an extension of credit to the Borrower in the maximum principal amount of $15,000,000.00.

B. The Borrower and the Lender desire to amend the Loan Agreement as hereafter described.

NOW, THEREFORE, in consideration of the mutual covenants and agreements herein contained, the parties hereto agree as follows:

The definition of “Termination Date” is amended to mean April 6, 2005.

The definition of “364-Day Facility” is amended to mean the Credit Agreement dated as of December 11, 2003, between Borrower and Bank One, N.A., as administrative agent, Wachovia Bank, National Association, as syndication agent and Commerzbank AG, Citibank, N.A. and the Bank of New York as co-documentation agents.

The definition of “Note” is amended to mean the renewal promissory note in the form attached to this Fourth Amendment to Loan Agreement as Exhibit “A”, which will be executed and delivered by the Borrower to evidence the $15,000,000 extension of credit.

The definition of “Pricing Grid” means the pricing grid attached hereto as Exhibit “B”.

2. Representations, Warranties and Agreements. In order to induce the Lender to enter into this Fourth Amendment, the Borrower represents and warrants to the Lender as follows:

(a) Authorization and Enforceability. This Fourth Amendment and any other documents to be executed and delivered by Borrower in connection therewith, when executed and delivered in accordance with the terms hereof, are and shall be the legal, valid and binding obligation of Borrower and enforceable in accordance with their respective terms. The making and performance of this Fourth Amendment and the execution and delivery of the various instruments associated therewith have been duly authorized by the Borrower, and neither the execution nor delivery of this Fourth Amendment or the other instruments contemplated hereby, nor fulfillment of or compliance with their respective terms and provisions, requires any consent, approval or other action by, or any notice to or filing with, any governmental agency or tribunal, or

will conflict with, or result in a breach of the terms, conditions or provisions of, or constitute a default under, or result in the creation of any lien upon any of the properties or assets of Borrower pursuant to its organizational documents or any other agreement, instrument or law to which Borrower is subject.

(b) Adoption of Representation and Warranties. The Borrower hereby represents and warrants to the Lender that all of the representations and warranties contained in the 364-Day Facility are true and correct in all material respects as of the effective date of this Fourth Amendment, and all such representations and warranties are incorporated herein by reference.

(c) Other Agreements. Except as expressly amended by this Fourth Amendment and, to the extent contained in Section 6 of the 364-Day Facility, as provided in the 364-Day Facility, Borrower hereby adopts and remakes to the Lender all of its respective agreements and covenants contained in the Loan Agreement and/or in the other Loan Documents, effective as of the effective date of this Fourth Amendment, and all such agreements and covenants are incorporated herein by reference.

3. Costs, Fees and Expenses. The Borrower agrees to pay to the Lender all reasonable costs and expenses, including reasonable attorneys’ fees, incurred by the Lender in connection with the preparation, execution and delivery of this Fourth Amendment.

4. Adoption of Loan Agreement. The Borrower expressly agrees to be bound by and comply with all terms and provisions of the Loan Agreement, as amended. Except as modified herein, the terms and conditions of the Loan Agreement shall remain unchanged, and the Loan Agreement shall continue in full force and effect in accordance with its terms. The Borrower further represents to the Lender that, as of the effective date of this Fourth Amendment, Borrower has no defenses, setoffs or counterclaims of any kind or nature against the Lender with respect to the Loan Agreement of any of the obligations thereunder or any action previously taken or not taken by the Lender with respect thereto.

IN WITNESS WHEREOF, the parties have executed this Fourth Amendment on the 6th day of April 2004.

BORROWER:		OGE ENERGY CORP., an Oklahoma corporation
	By:	/s/ Deborah S. Fleming
		Name: Deborah S. Fleming Title: Treasurer
BANK:		BANK OF OKLAHOMA, N.A., a national banking association
	By:	/s/ Laura Christofferson
		Name: Laura Christofferson Title: Senior Vice President

EXHIBIT “A”

REVOLVING NOTE

$15,000,000

April 6, 2004

FOR VALUE RECEIVED, the undersigned, OGE Energy Corp., an Oklahoma corporation (the “Borrower”), HEREBY PROMISES TO PAY to the order of Bank of Oklahoma, N.A. (the “Bank”), at its Principal Office located at 201 Robert S. Kerr Blvd., Oklahoma City, Oklahoma, in lawful money of the United States and in immediately available funds, the principal amount of $15,000,000.00, or the aggregate unpaid principal amount of all revolving loans made to the Borrower by the Bank pursuant to the Loan Agreement and outstanding on the Termination Date, whichever is less, and to pay interest from the date of this Revolving Note at the time and at a rate per annum described in the Loan Agreement.

This Revolving Note is the Note referred to in, and is entitled to the benefits of, the Loan Agreement, dated as of April 6, 2004, between the Borrower and the Bank (the “Loan Agreement”). Terms used herein which are defined in the Loan Agreement shall have their defined meanings when used herein. The Loan Agreement, among other things, contains provisions for acceleration of the maturity of this Revolving Note upon the happening of certain stated events.

This Revolving Note shall be governed by the laws of the State of Oklahoma, provided that, as to the maximum rate of interest which may be charged or collected, if the laws applicable to the Bank permit it to charge or collect a higher rate than the laws of the State of Oklahoma, then such laws applicable to the Bank shall apply to the Bank under this Revolving Note.

			OGE ENERGY CORP., an Oklahoma corporation
		By:	/s/ Deborah S. Fleming
			Name: Deborah S. Fleming Title: Treasurer

EXHIBIT “B”

PRICING GRID

Pricing is based on senior unsecured debt ratings of Borrower, as detailed below. The Borrower has the option of locking in the LIBOR rate for 30, 60 or 90 days.

Less Than 50% Usage		Greater Than 50% Usage

Debt Rating (S&P/Moody’s)	Applicable Margin For LIBOR Loans	Non-Use Fee	Applicable Margin For LIBOR Loans	Non-Use Fee
> A+ / A1	85.0	10.0	110.0	12.5
> A / A2	90.0	10.0	115.0	12.5
> BBB+ / Baa1	100.0	12.5	125.0	15.0
> BBB / Baa2	110.0	12.5	135.0	15.0
> BBB- / Baa3	130.0	25.0	155.0	30.0
< BBB- / Baa3	150.0	25.0	175.0	30.0

“Moody’s Rating” means, at any time, the rating issued by Moody’s and then in effect with respect to the Borrower’s senior unsecured long-term debt securities without third-party credit enhancement.

“S&P Rating” means, at any time, the rating issued by S&P and then in effect with respect to the Borrower’s senior unsecured long-term debt securities without third-party credit enhancement.

The Applicable Margin and Non-Use Fee Rate shall be determined in accordance with the foregoing table based on the then-current Moody’s and S&P Ratings. The credit rating in effect on any date for the purposes of this Schedule is that in effect at the close of business on such date. If at any time the Borrower has no Moody’s Rating or no S&P Rating, Level VI status shall exist.

If the Borrower is split-rated and the ratings differential is one level, the higher rating will apply. If the Borrower is split-rated and the ratings differential is two levels or more, the intermediate rating at the midpoint will apply. If there is no midpoint, the higher of the two intermediate ratings will apply.

Exhibit 31.01

CERTIFICATIONS

I, Steven E. Moore, certify that:

1. I have reviewed this quarterly report on Form 10-Q of OGE Energy Corp.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2004

/s/ Steven E. Moore
      Steven E. Moore
      Chairman of the Board, President and
         Chief Executive Officer

Exhibit 31.01

CERTIFICATIONS

I, James R. Hatfield, certify that:

1. I have reviewed this quarterly report on Form 10-Q of OGE Energy Corp.;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2004

/s/ James R. Hatfield
      James R. Hatfield
      Senior Vice President and
        Chief Financial Officer

Exhibit 32.01

Certification Pursuant to 18 U.S.C. Section 1350
As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of OGE Energy Corp. (the “Company”) on Form 10-Q for the period ended March 31, 2004, as filed with the Securities and Exchange Commission (the “Report”), each of the undersigned does hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

May 7, 2004

	/s/ Steven E. Moore
	Steven E. Moore Chairman of the Board, President and Chief Executive Officer
	/s/ James R. Hatfield
	James R. Hatfield Senior Vice President and Chief Financial Officer

OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2004

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

OGE ENERGY CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

OGE ENERGY CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Continued) (Unaudited)

OGE ENERGY CORP. CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

OGE ENERGY CORP. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

OGE ENERGY CORP. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

1. Summary of Significant Accounting Policies

Organization

Basis of Presentation

Accounting Records

Income Taxes

Stock-Based Compensation

Reclassifications

2. Accounting Pronouncements

3. Price Risk Management Assets and Liabilities

4. Accumulated Other Comprehensive Loss

5. Enogex – Discontinued Operations

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS DATA

6. Asset Disposals

7. Impairment of Assets

8. Supplemental Cash Flow Information

9. Common Stock

10. Earnings Per Share

11. Long-Term Debt

12. Short-Term Debt

13. Retirement Plans and Postretirement Benefit Plans

14. Report of Business Segments

15. Commitments and Contingencies

16. Rate Matters and Regulation

Recent Regulatory Matters

Pending Regulatory Matters

17. Fair Value of Financial Instruments

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Introduction

Forward-Looking Statements

Overview

Outlook

Results of Operations

Financial Condition

Off-Balance Sheet Arrangements

Liquidity and Capital Requirements

Future Capital Requirements

Future Sources of Financing

Critical Accounting Policies and Estimates

Accounting Pronouncements

Electric Competition; Regulation

Commitments and Contingencies

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Item 4. Controls and Procedures.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

Item 6. Exhibits and Reports on Form 8-K.

(a) Exhibits

(b) Reports on Form 8-K

SIGNATURE

AMENDMENT NO. 6 TO ASSET PURCHASE AGREEMENT

RECITALS

ARTICLE I Amendment to Agreement

ARTICLE II Miscellaneous

AMENDMENT NO. 7 TO ASSET PURCHASE AGREEMENT

RECITALS

ARTICLE I Amendment to Agreement

ARTICLE II Miscellaneous

FOURTH AMENDMENT TO LOAN AGREEMENT

EXHIBIT “A”

REVOLVING NOTE

EXHIBIT “B”

PRICING GRID

Exhibit 31.01

Exhibit 31.01

CERTIFICATIONS

OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)
(Unaudited)

OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

OGE ENERGY CORP.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Item 2. Management’s Discussion and Analysis of Financial Condition
and Results of Operations.

ARTICLE I
Amendment to Agreement

ARTICLE II
Miscellaneous

ARTICLE I
Amendment to Agreement

ARTICLE II
Miscellaneous