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OGE Energy Corp. 1st quarter 10-Q

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, 2005

[ ]	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 March 31, 2005, 90,195,109 shares of common stock, par value $0.01 per share, were outstanding.

OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2005

Part I - FINANCIAL INFORMATION	Page
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Balance Sheets	1
Condensed Consolidated Statements of Income	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	33
Item 3. Quantitative and Qualitative Disclosures About Market Risk	50
Item 4. Controls and Procedures	51
Part II - OTHER INFORMATION
Item 1. Legal Proceedings	53
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities	55
Item 6. Exhibits	55
Signature	56

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

(In millions)	March 31, 2005			December 31, 2004
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	20	.3	$	26	.4
Accounts receivable, less reserve of $3.7 and $4.5, respectively		416	.8		487	.9
Accrued unbilled revenues		48	.0		45	.5
Fuel inventories		53	.7		89	.0
Materials and supplies, at average cost		53	.8		53	.2
Price risk management		207	.0		118	.6
Gas imbalances		126	.9		100	.1
Accumulated deferred tax assets		14	.5		13	.7
Fuel clause under recoveries		29	.7		54	.3
Recoverable take or pay gas charges		13	.4		17	.0
Other		8	.9		13	.5

Total current assets		993	.0		1,019	.2


OTHER PROPERTY AND INVESTMENTS, at cost		32	.0		31	.4


PROPERTY, PLANT AND EQUIPMENT
In service		6,011	.3		5,957	.6
Construction work in progress		120	.3		110	.5
Other		5	.5		5	.8

Total property, plant and equipment		6,137	.1		6,073	.9
Less accumulated depreciation		2,525	.8		2,492	.9

Net property, plant and equipment		3,611	.3		3,581	.0


DEFERRED CHARGES AND OTHER ASSETS
Income taxes recoverable from customers, net		30	.7		30	.9
Intangible asset - unamortized prior service cost		38	.0		38	.0
Prepaid benefit obligation		84	.1		92	.7
Price risk management		20	.8		19	.6
Other		62	.1		57	.5

Total deferred charges and other assets		235	.7		238	.7


TOTAL ASSETS	$	4,872	.0	$	4,870	.3

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, 2005			December 31, 2004
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Short-term debt	$	154	.0	$	125	.0
Accounts payable		428	.1		476	.2
Dividends payable		30	.0		29	.9
Customers’ deposits		49	.2		48	.3
Accrued taxes		2	.0		14	.1
Accrued interest		26	.1		33	.2
Tax collections payable		7	.4		7	.2
Accrued vacation		18	.7		17	.9
Long-term debt due within one year		12	.1		35	.1
Non-recourse debt of joint venture		1	.2		1	.2
Price risk management		180	.1		102	.9
Gas imbalances		16	.2		22	.8
Provision for payments of take or pay gas		17	.4		21	.0
Other		36	.6		40	.6

Total current liabilities		979	.1		975	.4


LONG-TERM DEBT
Long-term debt		1,378	.2		1,385	.1
Non-recourse debt of joint venture		39	.0		39	.0

Total long-term debt		1,417	.2		1,424	.1


DEFERRED CREDITS AND OTHER LIABILITIES
Accrued pension and benefit obligations		200	.9		197	.0
Accumulated deferred income taxes		814	.9		802	.0
Accumulated deferred investment tax credits		35	.6		36	.8
Accrued removal obligations, net		121	.8		122	.2
Price risk management		20	.4		6	.6
Asset retirement obligation		1	.1		1	.1
Other		16	.4		19	.5

Total deferred credits and other liabilities		1,211	.1		1,185	.2


STOCKHOLDERS’ EQUITY
Common stockholders’ equity		706	.2		700	.8
Retained earnings		635	.1		659	.8
Accumulated other comprehensive loss, net of tax		(76	.7)		(75	.0)

Total stockholders’ equity		1,264	.6		1,285	.6


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	4,872	.0	$	4,870	.3

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

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

	Three Months Ended March 31,
(In millions, except per share data)		2005			2004

OPERATING REVENUES
Electric Utility operating revenues	$	301	.0	$	304	.3
Natural Gas Pipeline operating revenues		979	.8		737	.4

Total operating revenues		1,280	.8		1,041	.7
COST OF GOODS SOLD
Electric Utility cost of goods sold		163	.1		171	.4
Natural Gas Pipeline cost of goods sold		927	.6		683	.5

Total cost of goods sold		1,090	.7		854	.9

Gross margin on revenues		190	.1		186	.8
Other operation and maintenance		98	.9		91	.1
Depreciation		46	.6		46	.0
Taxes other than income		18	.6		18	.7

OPERATING INCOME		26	.0		31	.0

OTHER INCOME (EXPENSE)
Other income		1	.7		2	.8
Other expense		(2	.0)		(1	.5)

Net other income (expense)		(0	.3)		1	.3

INTEREST INCOME (EXPENSE)
Interest income		2	.0		0	.4
Interest on long-term debt		(20	.2)		(18	.2)
Interest expense - unconsolidated affiliate		-	--		(4	.3)
Allowance for borrowed funds used during construction		0	.6		0	.1
Interest on short-term debt and other interest charges		(1	.6)		(1	.1)

Net interest expense		(19	.2)		(23	.1)

INCOME FROM CONTINUING OPERATIONS BEFORE TAXES		6	.5		9	.2
INCOME TAX EXPENSE (BENEFIT)		1	.2		(0	.6)

INCOME FROM CONTINUING OPERATIONS		5	.3		9	.8
DISCONTINUED OPERATIONS
Income from discontinued operations		-	--		0	.7
Income tax expense		-	--		0	.3

Income from discontinued operations		-	--		0	.4

NET INCOME	$	5	.3	$	10	.2

BASIC AVERAGE COMMON SHARES OUTSTANDING		90	.0		87	.5
DILUTED AVERAGE COMMON SHARES OUTSTANDING		90	.5		88	.1
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE
Income from continuing operations	$	0.0	6	$	0.1	1
Income from discontinued operations, net of tax		--	-		0.0	1

NET INCOME	$	0.0	6	$	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)		2005			2004


CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	5	.3	$	10	.2
Adjustments to reconcile net income to net cash provided from
operating activities
Income from discontinued operations		-	--		(0	.4)
Depreciation		46	.6		46	.0
Deferred income taxes and investment tax credits, net		12	.3		(0	.5)
Gain on sale of assets		(0	.2)		(1	.4)
Price risk management assets		(95	.8)		(29	.8)
Price risk management liabilities		88	.5		33	.2
Other assets		4	.4		3	.4
Other liabilities		(4	.0)		5	.9
Change in certain current assets and liabilities
Accounts receivable, net		71	.1		32	.8
Accrued unbilled revenues		(2	.5)		0	.6
Fuel, materials and supplies inventories		34	.7		94	.8
Gas imbalance asset		(26	.8)		(2	.7)
Fuel clause under recoveries		24	.6		3	.6
Other current assets		8	.2		4	.9
Accounts payable		(48	.1)		6	.3
Customers’ deposits		0	.9		-	--
Accrued taxes		(12	.1)		(11	.2)
Accrued interest		(7	.1)		(7	.0)
Fuel clause over recoveries		-	--		0	.4
Gas imbalance liability		(6	.6)		5	.6
Other current liabilities		(6	.6)		(2	.2)

Net Cash Provided from Operating Activities		86	.8		192	.5

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(74	.8)		(53	.4)
Proceeds from sale of assets		0	.4		3	.0
Other investing activities		-	--		0	.6

Net Cash Used in Investing Activities		(74	.4)		(49	.8)

CASH FLOWS FROM FINANCING ACTIVITIES
Retirement of long-term debt		(23	.0)		(12	.0)
Increase (decrease) in short-term debt, net		29	.0		(202	.5)
Premium on issuance of common stock		5	.4		4	.5
Dividends paid on common stock		(29	.9)		(29	.1)

Net Cash Used in Financing Activities		(18	.5)		(239	.1)

DISCONTINUED OPERATIONS
Net cash provided from investing activities		-	--		0	.4

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

NET DECREASE IN CASH AND CASH EQUIVALENTS		(6	.1)		(96	.0)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		26	.4		245	.6

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	20	.3	$	149	.6

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 primarily in the south central United States. The Company conducts these activities through two business segments, the Electric Utility and the Natural Gas Pipeline segments. 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 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. The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are located in the major gas producing basins of Oklahoma. Through a 75 percent interest in the NOARK Pipeline System Limited Partnership (“NOARK”), Enogex also owns a controlling interest in and operates Ozark Gas Transmission, L.L.C. (“Ozark”), a FERC regulated interstate pipeline that extends from southeast Oklahoma through Arkansas to southeast Missouri. Enogex also holds a majority interest in Enerven Compression Services, LLC, a joint venture focused on the rental of natural gas compression assets. Enogex’s participating entity in the joint venture, Enogex Compression Company, LLC, has been consolidated in the Company’s financial statements with a minority interest recorded.

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, 2005 and December 31, 2004, the results of its operations for the three months ended March 31, 2005 and 2004, and the results of its cash flows for the three months ended March 31, 2005 and 2004, 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, 2005 are not necessarily indicative of the results that may be expected for the year ending December 31, 2005 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, 2004.

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 actual or anticipated costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management’s expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. Excluding recoverable take or pay gas charges and the McClain Plant expenses (operating and maintenance expenses, depreciation, ad valorem taxes and interest on debt) in the table on the following page, regulatory assets are being amortized and reflected in rates charged to customers over periods of up to 30 years.

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

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

(In millions)	March 31, 2005			December 31, 2004
Regulatory Assets
Income taxes recoverable from customers, net	$	30	.7	$	30	.9
Fuel clause under recoveries		29	.7		54	.3
Unamortized loss on reacquired debt		20	.7		21	.0
McClain Plant expenses		17	.8		11	.0
Recoverable take or pay gas charges		13	.4		17	.0
Arkansas transition costs		0	.4		0	.7
January 2002 ice storm		-	--		1	.8
Miscellaneous		0	.2		0	.6

Total Regulatory Assets	$	112	.9	$	137	.3


Regulatory Liabilities
Accrued removal obligations, net	$	121	.8	$	122	.2
Estimated refund on gas transportation and storage case		7	.9		6	.9
Estimated refund on FERC fuel		1	.0		1	.0

Total Regulatory Liabilities	$	130	.7	$	130	.1

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 OG&E 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.”

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. OG&E’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 are intended to allow OG&E to amortize under or over recovery. OG&E expects to recover the fuel clause under recoveries during 2005.

Unamortized loss on reacquired debt is comprised of unamortized debt issuance costs and call premiums related to the early retirement of OG&E’s long-term debt. These amounts are being recovered over the term of the long-term debt which replaced the previous long-term debt.

As a result of the completion of the acquisition of a 77 percent interest in the 520 megawatt (“MW”) NRG McClain Station (the “McClain Plant”) on July 9, 2004, and consistent with the 2002 agreed-upon settlement of OG&E’s rate case (the “Settlement Agreement”) with the OCC, OG&E has the right to accrue a regulatory asset, for a period not to exceed 12 months subsequent to the completion of the acquisition and the operation of the McClain Plant,

consisting of the non-fuel operation and maintenance expenses, depreciation, cost of debt associated with the investment and ad valorem taxes. All prudently incurred costs accrued through the regulatory asset within the 12-month period would be included in OG&E’s prospective cost of service and would be recovered over a period to be determined by the OCC.

Recoverable take or pay gas charges represent OG&E’s estimate of the maximum amount that it could be obligated to pay under certain take-or-pay contracts. OG&E believes that it is entitled to recover any such amounts from its customers through its regulatorily approved automatic fuel adjustment clauses or other regulatory mechanisms.

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.

On November 22, 2002, the OCC signed a rate order containing the provisions of the Settlement Agreement. The Settlement Agreement provides for, among other things, 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 from 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. During the three months ended March 31, 2005, OG&E recovered approximately $1.8 million in annual net profits from off-system sales. Including this amount, OG&E has recovered a total of $5.4 million related to the regulatory asset since December 31, 2002, which is in accordance with the Settlement Agreement. In April 2005, OG&E expects to begin crediting annual net profits from off-system sales to OG&E’s Oklahoma customers up to $3.6 million and any annual net profits from off-system sales in excess of this amount will be shared between OG&E’s Oklahoma customers and OG&E in accordance with the Settlement Agreement.

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,” OG&E was required to reclassify its accrued removal obligations, which had previously been recorded as a liability in Accumulated Depreciation, to a regulatory liability.

Also, as part of the Settlement Agreement, OG&E agreed to consider competitive bidding as a basis to select its provider for gas transportation service to its natural gas-fired generation facilities pursuant to the terms set forth in the Settlement Agreement. The prescribed bidding

process detailed in the Settlement Agreement provided that separate transportation services be bid for each generation facility. OG&E believes that, in order for it to achieve maximum coal generation, to deliver the lowest cost energy to its customers and to ensure reliable electric service, it must have integrated, firm no-notice load following service for both gas transportation and gas storage. On April 29, 2003, as required by the Settlement Agreement, 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 integrated, firm no-notice load following gas transportation and storage services agreement with Enogex. On October 22, 2004, the administrative law judge (“ALJ”) overseeing the proceeding recommended approximately $41.9 million annual demand fee recovery with OG&E refunding to its customers any demand fees collected in excess of this amount. If this recommendation is ultimately accepted, OG&E believes its refund obligation would be approximately $7.9 million at March 31, 2005, which the Company does not believe is material in light of previously established reserves. See Note 13 for a further discussion.

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 month periods ended March 31, 2005 and 2004 and is recorded as an income tax benefit in the Condensed Consolidated Statements of Income.

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.

OG&E has an Oklahoma investment tax credit (“ITC”) carryover of approximately $3.3 million. These ITC carryover amounts will begin expiring in the year 2017. OG&E believes that, based on current projections, these ITC carryover amounts will be fully utilized in 2005.

American Jobs Creation Act of 2004

On October 22, 2004, President Bush signed into law the American Jobs Creation Act of 2004 (the “Jobs Creation Act”). The Jobs Creation Act amended and added a significant number of provisions to the Internal Revenue Code and these changes affect virtually all taxpayers. The

Jobs Creation Act includes a provision that entitles all U.S. manufacturers with qualified manufacturing activities to a “Deduction Related to Production Activities” (“DRPA”). Certain activities of the Company, including the generation of electricity and the processing of natural gas, are included in the list of qualifying manufacturing activities for purposes of the DRPA. Thus, the Company believes that the DRPA could impact the Company’s future effective income tax rate.

Beginning in 2005, the DRPA equals three percent of the lesser of: (a) taxable income derived from a qualified production activity; or (b) overall taxable income for the taxable year. However, the deduction for a taxable year is limited to 50 percent of the Form W-2 wages paid by a taxpayer during the taxable year in which the deduction is claimed. The deduction percentage increases to six percent in 2007. In 2010, when the deduction is fully phased-in, the deduction rate will be nine percent.

Because OG&E is an integrated electric utility and Enogex is an integrated natural gas transportation company, both will be required to allocate income and expenses to their “qualified production activity.” The U.S. Treasury Department issued guidance related to the DRPA in January 2005 and this guidance provides rules for determining taxable income when a portion of a taxpayer’s income is derived from a qualified production activity. The FASB has determined that the DRPA will be classified as a “special deduction” for purposes of computing income tax expense which will have the effect of reducing the Company’s overall effective tax rate to the extent the Company can claim a deduction. For 2005, the Company currently estimates that the income tax benefit will be between approximately $0.4 million and $0.8 million for OG&E and between approximately $0.4 million and $0.8 million for Enogex Products Corporation (a wholly-owned subsidiary of Enogex).

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. Also, see Note 2 for a discussion of a recent accounting pronouncement, which replaces SFAS No. 123, that the Company will adopt effective January 1, 2006.

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 and income 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)		2005			2004


Net income, as reported	$	5	.3	$	10	.2

Add:
Stock-based employee compensation expense included
in reported net income, 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	.2		0	.3


Pro forma net income	$	5	.1	$	9	.9


Income per average common share
Basic and diluted - as reported	$	0.	06	$	0.	12
Basic and diluted - pro forma	$	0.	06	$	0.	11

2. Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123 (Revised), “Share-Based Payment,” which replaces SFAS No. 123 and supersedes APB Opinion No. 25. This statement applies to all share-based payment transactions in which an entity acquires goods or services by issuing (or offering to issue) its shares, share options or other equity instruments (except for equity instruments held by an employee share ownership plan) or by incurring liabilities to an employee or other supplier (a) in amounts based, at least in part, on the price of the entity’s shares or other equity instruments or (b) that require or may require settlement by issuing the entity’s equity shares or other equity instruments. This statement applies to all awards granted after the required effective date and to awards modified, repurchased or cancelled after that date. The cumulative effect of initially applying this statement, if any, is recognized as of the required effective date. This statement requires a public entity to measure and recognize the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with limited exceptions). The grant-date fair value of employee share options and similar instruments will be estimated using option-pricing models adjusted for the unique characteristics of those instruments. If an equity award is modified after the grant date, incremental compensation cost will be recognized in an amount equal to the excess of the fair value of the modified award over the fair value of the original award immediately before the modification. As of the required effective date, all public entities that used the fair-value based method for either recognition or disclosure under SFAS No. 123 will apply this statement using a modified version of prospective application. Under that transition method, compensation cost is recognized on or after the required effective date for the portion of outstanding awards for which the requisite service has not yet been rendered, based on the grant-date fair value of those awards calculated under SFAS No. 123 for either recognition or pro forma disclosures. For periods prior to the required effective date, those entities may elect to apply a modified version of retrospective application under which financial statements for prior periods are adjusted on a

basis consistent with the pro forma disclosures required for those periods by SFAS No. 123. Adoption of SFAS No. 123(R) is required for public entities as of the beginning of the first fiscal year beginning after June 15, 2005. The Company will adopt this new standard effective January 1, 2006. Management has not yet determined what the impact of this new standard will be on its consolidated financial position or results of operations.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” in which an entity is required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event if the liability’s fair value can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred. Uncertainty surrounding the timing and method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. However, in some cases, there is insufficient information to estimate the fair value of an asset retirement obligation. In these cases, the liability should be initially recognized in the period in which sufficient information is available for an entity to make a reasonable estimate of the liability’s fair value. This interpretation is effective no later than the end of fiscal years ending after December 15, 2005. The Company will adopt this new interpretation effective December 31, 2005. Retrospective application for interim financial information is permitted but not required. This interpretation will require both recognition of a cumulative change in accounting principle and disclosure of the liability on a pro forma basis for transition purposes. Management has not yet determined what the impact of this new interpretation will be on its consolidated financial position or results of operations.

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, 2005 and 2004, 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, “Accounting for Derivative Instruments and Hedging Activities,” as amended, the Company recognizes all of its derivative instruments as Price Risk Management assets or liabilities in the Condensed Consolidated Balance Sheets 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 is recognized in current earnings on the same line item as the gain or loss recorded for the change in the fair value of the hedged item. 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. As a matter of policy, all non-trading hedged items (except for interest rate swap agreements) and the derivatives used for cash flow hedges must be identical with respect to time and location and must be in compliance with SFAS No. 133. 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 and any amounts recorded in Accumulated Other Comprehensive Income will be recognized directly in earnings.

The Company’s interest rate swap agreements have been designated as fair value hedges under SFAS No. 133. The fair value hedges 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. See Note 8 for a description of the Company’s interest rate swap agreements.

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 Emerging Issues Task Force (“EITF”) 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.” In accordance with 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 Income. 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 Income 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 for the three months ended March 31, 2005 and 2004, respectively, are as follows:

	Three Months Ended March 31,
(In millions)		2005			2004

Net income	$	5	.3	$	10	.2
Other comprehensive income (loss), net of tax:
Deferred hedging losses, net of tax		(1	.8)		-	--
Amortization of cash flow hedge, net of tax		0	.1		-	--
Reversal of unrealized gains on available-for-sale securities		-	--		(0	.4)

Total comprehensive income	$	3	.6	$	9	.8

The components of accumulated other comprehensive loss at March 31, 2005 and December 31, 2004 are as follows:

(In millions)	March 31, 2005			December 31, 2004
Minimum pension liability adjustment, net of tax	$	(72	.7)	$	(72	.7)
Deferred hedging gains (losses), net of tax		(1	.6)		0	.2
Settlement and amortization of cash flow hedge, net of tax		(2	.4)		(2	.5)

Total accumulated other comprehensive loss	$	(76	.7)	$	(75	.0)

Accumulated other comprehensive loss at both March 31, 2005 and December 31, 2004 included an after tax loss of approximately $72.7 million ($118.6 million pre-tax) related to a minimum pension liability adjustment based on a review of the funded status of the Company’s pension plan by the Company’s actuarial consultants as of December 31, 2004. Any increases or decreases in the minimum pension liability will be reflected in Other Comprehensive Income or Loss in the fourth quarter.

5. 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)		2005			2004

NON-CASH INVESTING AND FINANCING ACTIVITIES
Change in fair value of long-term debt due to interest rate swaps	$	(6	.8)	$	7	.8

6. Common Stock

For the three months ended March 31, 2005, there were 231,668 shares of new common stock issued pursuant to the Company’s Stock Incentive Plan, related to exercised stock options.

7. 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)		2005		2004

Average Common Shares Outstanding
Basic average common shares outstanding		90	.0	87	.5
Effect of dilutive securities:
Employee stock options and unvested stock grants		0	.1	0	.2
Contingently issuable shares (performance units)		0	.4	0	.4

Diluted average common shares outstanding		90	.5	88	.1

For the three months ended March 31, 2005 and 2004, respectively, approximately 0.3 million shares and 0.7 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.

8. Long-Term Debt

At March 31, 2005, the Company is in compliance with all of its debt agreements.

Long-Term Debt with Optional Redemption Provisions

OG&E has three series of variable rate industrial authority bonds (the “Bonds”) with optional redemption provisions that allow the holders to request repayment of the Bonds at various dates prior to the maturity. The Bonds, which are redeemable at the option of the holder during the next 12 months, are as follows:

SERIES		DATE DUE		AMOUNT

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 (redeemable during next 12 months)	$	135	.4

All of these Bonds are subject to redemption 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 principal amount. A third party remarketing agent for the Bonds will attempt to remarket any Bonds tendered for purchase. Since the original issuance of these series of Bonds in 1995 and 1997, the remarketing agent has successfully remarketed all tendered bonds. 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

Fair Value Hedges

At March 31, 2005, the Company had three outstanding interest rate swap agreements that qualified as fair value hedges: (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 a total of $200.0 million ($100.0 million for each interest rate swap agreement) of 8.125 percent fixed rate debt due January 15, 2010, to a variable rate based on the six month LIBOR in arrears. 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.

On April 1, 2005, Enogex terminated its interest rate swap agreements and received approximately $0.2 million related to this transaction. Since inception of the Enogex interest rate swap agreements, the Company has received approximately $32.5 million related to these agreements and the effective interest rate until maturity will be approximately 7.67 percent on this long-term debt.

At March 31, 2005 and December 31, 2004, the fair values pursuant to OG&E’s interest rate swap were approximately $2.0 million and $3.9 million, respectively, and the fair value hedge was classified as Deferred Charges and Other Assets – Price Risk Management in the Condensed Consolidated Balance Sheets. A corresponding net increase of approximately $2.0 million and $3.9 million was reflected in Long-Term Debt at March 31, 2005 and December 31, 2004, respectively, as this fair value hedge was effective at March 31, 2005 and December 31, 2004.

At March 31, 2005, Enogex’s interest rate swaps were classified as Deferred Credits and Other Liabilities – Price Risk Management of approximately $0.9 million in the Condensed Consolidated Balance Sheet. A corresponding net decrease of approximately $0.9 million was reflected in Long-Term Debt at March 31, 2005 as these fair value hedges were effective at March 31, 2005. At December 31, 2004, the fair values pursuant to Enogex’s interest rate swaps were approximately $4.0 million and the fair value hedges were classified as Deferred Charges and Other Assets – Price Risk Management in the Condensed Consolidated Balance Sheet. A corresponding net increase of approximately $4.0 million was reflected in Long-Term Debt at December 31, 2004 as these fair value hedges were effective at December 31, 2004.

9. Short-Term Debt

The short-term debt balance was approximately $154.0 million and $125.0 million at March 31, 2005 and December 31, 2004, respectively. The following table shows the Company’s lines of credit in place, commercial paper outstanding and available cash at March 31, 2005. At March 31, 2005, the Company’s short-term borrowings consisted of borrowings on its revolving credit agreement and commercial paper.

Lines of Credit, Commercial Paper and Available Cash (In millions)
Entity	Amount Available	Amount Outstanding	Maturity
OGE Energy Corp. OG&E (B) OGE Energy Corp. (D)	$ 15.0 100.0 450.0	$ --- --- 154.0	April 6, 2005 (A) October 20, 2009 (C) October 20, 2009 (C)
	565.0	154.0
Cash	20.3	N/A	N/A
Total	$ 585.3	$ 154.0
(A) In April 2005, the Company renewed its $15.0 million credit facility, shown in the table above, which matures April 6, 2006.
(B) No borrowings were outstanding at March 31, 2005 under this line of credit; however, $0.2 million of this line of credit supports a letter of credit.
(C) Each of the new credit facilities has a five-year term with two options to extend the term for one year.
(D) This bank facility is available to back up a maximum of $300.0 million of the Company’s commercial paper borrowings and can be used as a letter of credit facility. At March 31, 2005, the Company had approximately $85.0 million in outstanding borrowings under this line of credit and approximately $69.0 million in commercial paper borrowings.

The Company’s and OG&E’s ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade. Their respective back-up lines of credit contain rating grids that cause annual fees and borrowing rates to increase if they suffer an adverse ratings impact. The impact of any future downgrades would result in an increase in the cost of short-term borrowings 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 for a two-year period beginning January 1, 2005 and ending December 31, 2006.

10. 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 the disclosure requirements applicable to employers’ pension plans and other postretirement benefit plans. This Statement requires additional disclosures for defined benefit pension plans and other defined benefit postretirement plans, including disclosures describing the components of net periodic benefit cost recognized during interim periods.

The details of net periodic benefit cost of the pension plan (including the restoration of retirement income plan) and the postretirement benefit plans included in the Condensed Consolidated Financial Statements are as follows:

Net Periodic Benefit Cost


	Pension Plan and Restoration of Retirement Income Plan						Postretirement Benefit Plans
	Three Months Ended March 31,						Three Months Ended March 31,
(In millions)		2005			2004			2005			2004

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

Net periodic benefit cost	$	9	.1	$	8	.3	$	4	.5	$	4	.6

Pension Plan Funding

The Company previously disclosed in its Form 10-K for the year ended December 31, 2004 that it expected to contribute approximately $37.4 million to the pension plan in 2005. The Company presently anticipates reducing this amount by approximately $5.4 million during 2005, for a total contribution of approximately $32.0 million in 2005, which represents the Company’s 2004 pension expense. The Company plans to make contributions to the pension plan during the second and third quarters of 2005. In April 2005, the Company funded approximately $10.7 million to the pension plan. The remaining expected contributions to the pension plan in 2005, 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 “Medicare Act”). The Medicare Act expanded Medicare to include, for the first time, coverage for prescription drugs. In May 2004, the FASB issued FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” FAS 106-2 provided guidance on the accounting for the effects of the Medicare Act for employers that sponsor postretirement heath care plans that provide prescription drug benefits. FAS 106-2 also required those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Medicare Act. The Company adopted this new standard effective July 1, 2004 with retroactive application to the date of the Medicare Act’s enactment. Management expects that the accumulated plan benefit obligation (“APBO”) for the Company’s postretirement medical plan will be reduced by approximately $13.3 million as a

result of savings to the Company’s postretirement medical plan resulting from the Medicare Act, which will reduce the Company’s costs for its postretirement medical plan by approximately $2.5 million annually. The $2.5 million in annual savings is comprised of a reduction of approximately $1.5 million from amortization of the $13.3 million gain due to the reduction of the APBO, a reduction in the interest cost on the APBO of approximately $0.8 million and a reduction in the service cost due to the subsidy of approximately $0.2 million.

11. 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, 2005 primarily includes unallocated corporate expenses, interest expense on commercial paper and interest expense on long-term debt. 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 summarize the results of the Company’s business segments for the three months ended March 31, 2005 and 2004.


Three Months Ended March 31, 2005	Electric Utility			Natural Gas Pipeline (A)			Other Operations			Intersegment			Total
(In millions)
Operating revenues	$	301	.0	$	1,000	.8	$	-	--	$	(21	.0)	$	1,280	.8
Cost of goods sold		175	.0		937	.6		-	--		(21	.9)		1,090	.7

Gross margin on revenues		126	.0		63	.2		-	--		0	.9		190	.1
Other operation and maintenance		77	.4		24	.6		(3	.1)		-	--		98	.9
Depreciation		33	.1		11	.6		1	.9		-	--		46	.6
Taxes other than income		12	.7		4	.8		1	.1		-	--		18	.6

Operating income		2	.8		22	.2		0	.1		0	.9		26	.0

Other income		0	.7		-	--		1	.0		-	--		1	.7
Other expense		(0	.5)		(0	.4)		(1	.1)		-	--		(2	.0)
Interest income		1	.6		0	.6		0	.3		(0	.5)		2	.0
Interest expense		(9	.7)		(9	.1)		(2	.9)		0	.5		(21	.2)
Income tax expense (benefit)		(3	.4)		5	.2		(0	.9)		0	.3		1	.2

Net income (loss)	$	(1	.7)	$	8	.1	$	(1	.7)	$	0	.6	$	5	.3

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


Three Months Ended March 31, 2005	Transportation and Storage			Gathering and Processing			Marketing (B)			Eliminations			Total
(In millions)
Operating revenues	$	69	.7	$	152	.8	$	903	.7	$	(125	.4)	$	1,000	.8
Operating income (loss)	$	12	.8	$	13	.4	$	(4	.0)	$	-	--	$	22	.2

(B) In March 2005, Enogex corrected its procedure for accounting for park and loan transactions during 2004 that resulted from an incorrect change in an accounting procedure implemented during 2004. The incorrect procedure affected the timing of recognition of revenue and income from park and loan transactions and resulted in a temporary overstatement of operating revenues without the associated expense until the transaction was completed and the expense recognized. As a result of this correction, Enogex recorded a pre-tax charge of approximately $7.7 million as a reduction in Operating Revenues in the Condensed Consolidated Statement of Income and a corresponding $7.7 million decrease in Current Price Risk Management Assets in the Condensed Consolidated Balance Sheet during the three months ended March 31, 2005.


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
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


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

12. Commitments and Contingencies

Except as set forth below and in Note 13, 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, 2004, appropriately represent, in all material respects, the current status of any material commitments and contingent liabilities.

Natural Gas Storage Facility Agreement with Central Oklahoma Oil and Gas Corp.

As reported in Note 17 to the Company’s Consolidated Financial Statements in the Company’s Form 10-K for the year ended December 31, 2004, OGE Energy Corp., Enogex, Central Oklahoma Oil and Gas Corp. (“COOG”), Natural Gas Storage Corporation (“NGSC”) and individual shareholders of COOG and NGSC have been involved in legal proceedings relating to a gas storage agreement and associated agreements. In the actions pending against the individuals in the U.S. District Court for Western District of Oklahoma, the jury, on October 25, 2004, ruled in favor of the Company and Enogex for approximately $6.6 million. The individual defendants filed a motion for new trial. On March 23, 2005, the court entered an order: (i) denying the defendants’ motion for new trial; (ii) denying the defendants’ motion to stay; and (iii) granting the motion of OGE Energy Corp. and Enogex to allow registration of judgments in the U.S. District Court for the Southern District of Texas. On April 20, 2005, the defendants filed an appeal in the Tenth Circuit Court of Appeals.

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

Natural Gas Measurement Case

As reported in Note 17 to the Company’s Consolidated Financial Statements in the Company’s Form 10-K for the year ended December 31, 2004, the Company has been involved in legal proceedings filed by Jack J. Grynberg in federal courts related to natural gas measurement. Various procedural motions have been filed and discovery is proceeding on limited jurisdictional issues. A hearing on the defendants’ motions to dismiss for lack of subject matter jurisdiction, including public disclosure, original source and voluntary disclosure requirements was held March 17 – 18, 2005. The court indicated that a ruling would be made regarding these motions by the end of April 2005; however, no ruling has been issued to date.

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

Recent Enogex Litigation

On March 8, 2005, Enogex was served with a putative class action filed by G.M. Oil Properties, Inc. in the District Court of Comanche County, Oklahoma. The petition alleges that Enogex exercises a monopoly power with respect to its gathering facilities within the state of

Oklahoma. The petition further alleges that, due to the alleged monopoly power, Enogex has caused damage to the plaintiff and other small gas producers and marketers.

The Company intends to vigorously defend this action. At the present time, the Company believes the case is without merit and is filing a motion to dismiss for failure to state a claim.

Agreement with Colorado Interstate Gas Company

OERI and Cheyenne Plains Gas Pipeline Company, L.L.C. are parties to a firm transportation services agreement dated April 14, 2004. The Cheyenne Plains Pipeline provides interstate gas transportation services in Wyoming, Colorado and Kansas with a capacity of 560,000 decatherms/day (“Dth/day”). OERI reserved 60,000 Dth/day of firm capacity on the Cheyenne Plains Pipeline for 10 years. Such reservation provides OERI access to significant additional natural gas supplies in the Rocky Mountain production basins. OERI pays a demand fee of approximately $7.5 million annually for this capacity. The Cheyenne Plains Pipeline was initially proposed to be in service by August 31, 2005 but was able to begin full service in February 2005. OERI expects a loss of approximately $5.0 million in 2005 related to its Cheyenne Plains’ position as a result of unfavorable market conditions for the capacity primarily due to the earlier than expected in-service date for the project and the associated lack of upstream gas supply and pipeline infrastructure to deliver gas to the Cheyenne hub for 2005. OERI incurred a loss of approximately $1.0 million during the first quarter of 2005 related to its Cheyenne Plains’ position.

Environmental Laws and Regulations

OG&E

Air

On January 24, 2005, national legislation was introduced in Congress that, if passed, could require a significant reduction in emissions of sulfur dioxide (“SO2”), nitrogen oxide (“NOX”) and mercury from the electric utility industry. The legislation, introduced in Senate Bill 131, is commonly referred to as the Clear Skies Act of 2005. The bill failed to pass the U.S. Senate Committee on Environment and Public Works on March 9, 2005. The future status of the bill is not known at this time. In addition, on April 6, 2005, the Omnibus Mercury Emissions Reduction Act was introduced which, if passed, would require significant reductions in mercury, SO2, NOX and carbon dioxide (“CO2”) by 2010. The future status of the bill is not known at this time.

On March 10, 2005, the Environmental Protection Agency (“EPA”) published the Clean Air Interstate Rule (“CAIR”). This rule is intended to control SO2 and NOX emissions from utility boilers in order to minimize the interstate transport of air pollution. The state of Oklahoma is not listed as one of the states affected by the rule. However, states not subject to

the CAIR must demonstrate to the EPA that their emissions do not significantly impact the air quality in downwind states. If a state cannot make this demonstration it then becomes subject to the CAIR. If Oklahoma becomes subject to the CAIR, OG&E could have significant additional capital and operating expenditures.

Also in March 2005, the EPA issued a Clean Air Mercury Rule to limit mercury emissions from coal-fired boilers. Earliest compliance by OG&E would be 2008. The rule uses a cap and trade program to reduce mercury emissions in two phases. OG&E expects that phase one of this rule will have minimal impact on its operations. However, OG&E expects that phase two will require significant mercury reductions and substantial capital and operating costs. Litigation has been initiated by several parties in this matter, so the ultimate impact of this rule is not known at this time.

The Oklahoma Department of Environmental Quality’s Clean Air Act Amendment Title V permitting program was approved by the EPA in March 1996. By March of 1997, OG&E had submitted all required permit applications. The Title V permit application for the McClain Plant had been filed in a timely manner by the previous owner prior to the acquisition of the McClain Plant by OG&E. As of December 31, 2004, OG&E had received Title V permits for all of its generating stations, with the exception of the McClain Plant. OG&E expects to receive the McClain Plant permit by mid-2005. Because these permits require renewal every five years, OG&E has begun the renewal process for some of its generating stations. Air permit fees for generating stations were approximately $0.6 million in 2004. The fees for 2005 are estimated to be approximately the same as in 2004.

Water

OG&E has one Oklahoma Pollutant Discharge Elimination System permit renewal pending. OG&E expects that this permit will be issued during the second or third quarter of 2005. OG&E expects that this permit, when finally issued, will continue to be reasonable in its requirements, allow operational flexibility and provide reductions in operating costs.

Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of any cooling water intake structure reflect the “best available technology” for minimizing environmental impacts. EPA Section 316(b) rules for existing facilities became effective July 23, 2004. OG&E has acquired the services of a consultant to assist in the development of “Proposal for Information Collection” documents for four applicable facilities. These documents will be submitted to the state regulatory agency for review and approval during the second or third quarter of 2005. Depending on the ultimate analysis and recommendation(s) of the 316(b) rules, capital and/or operating costs may increase at some of OG&E’s generating facilities.

Other

generally accepted in the United States, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company’s Consolidated Financial Statements. Except as otherwise stated above, in Notes 17 and 18 of Notes to Consolidated Financial Statements in the Company’s Form 10-K for the year ended December 31, 2004, in Item 3 of that report, in Note 13 below or in Item 1 of Part II of this report, 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.

13. Rate Matters and Regulation

Except as set forth below, the circumstances set forth in Note 18 to the Company’s Consolidated Financial Statements included in the Company’s Form 10-K for the year ended December 31, 2004, appropriately represent, in all material respects, the current status of any regulatory matters.

Regulatory Matters

2002 Settlement Agreement

On November 22, 2002, the OCC signed a rate order containing the provisions of a Settlement Agreement of OG&E’s rate case. 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 MWs (“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 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 from 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. During the three months ended March 31, 2005, OG&E recovered approximately $1.8 million in annual net profits from off-system sales. Including this amount, OG&E has recovered a total of $5.4 million related to the regulatory asset since December 31, 2002, which is in accordance with the Settlement Agreement. In April 2005, OG&E expects to begin crediting annual net profits from off-system sales to OG&E’s Oklahoma customers up to $3.6 million and any annual net profits from off-system sales in excess of this amount will be shared between OG&E’s Oklahoma customers and OG&E in accordance with the Settlement Agreement.

Recent Acquisition of Power Plant

On July 9, 2004, OG&E completed the acquisition of NRG McClain LLC’s 77 percent interest in the McClain Plant. This transaction was intended to satisfy the requirement in the Settlement Agreement to acquire New Generation. 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 interest in the McClain Plant is the Oklahoma Municipal Power Authority (“OMPA”).

The closing of the purchase of the McClain Plant was subject to approval from the FERC. On July 2, 2004, the FERC authorized OG&E to acquire the McClain Plant. The FERC’s approval was based on an offer of settlement in which OG&E proposed, among other things, to install certain new transmission facilities and to hire an independent market monitor to oversee OG&E’s activity for a limited period. Two other parties, InterGen Services, Inc. and AES Shady Point (“AES”), opposed OG&E’s offer of settlement and filed competing settlement offers. In the July 2, 2004 order, the FERC: (i) approved OG&E’s offer of settlement subject to conditions; (ii) rejected the competing offers of settlement; and (iii) approved OG&E’s acquisition of the McClain Plant. As part of the July 2, 2004 order, OG&E agreed to undertake the following mitigation measures: (i) install a transformer at one of its facilities at a cost of approximately $9.3 million which was completed in the fourth quarter of 2004; (ii) provide a 600 MW bridge into its control area from the Redbud Energy LP (“Redbud”) plant; and (iii) hire an independent market monitor to oversee OG&E’s activity in its control area. The market monitoring plan is designed to detect any anticompetitive conduct by OG&E from operation of its generation resources or its transmission system. The market monitoring function is performed daily and periodic reviews are also performed. To date, the independent market monitor has filed two reports, one on October 13, 2004 covering the period from July 10, 2004 to September 30, 2004, and one on January 14, 2005 covering the period from October 1, 2004 to December 31, 2004. The report covering the period from January 1, 2005 to March 31, 2005 has not been filed to date. Based on an analysis of transmission congestion data on OG&E’s system, along with data on purchases and sales, generation dispatch data and power flows on OG&E’s tie lines, the market monitor concluded that OG&E did not act in an anticompetitive manner through either dispatch of its generation or operation of its transmission system. Additionally, OG&E’s operations under the ongoing mitigation measures that require OG&E to make available transmission capability available to the Redbud power plant for access to the OG&E system were analyzed. Based on this analysis, the market monitor concluded that OG&E has complied with this requirement. Further, in the review of the disposition of requests for transmission service, the independent market monitor detected no problems with access to OG&E’s transmission system. OG&E expects to complete the installation and implementation of these measures by June 2005. One party has filed a request for rehearing of the FERC’s July 2, 2004 order. On April 18, 2005, the FERC issued an order denying the party’s request for rehearing. This party has 60 days to file a petition for review with the FERC.

On April 4, 2005, OG&E filed with the OCC a notice of intent informing the OCC that OG&E plans to file an application for a rate increase on or about May 20, 2005 to recover, among other things, its investment in, and the operating expenses of, the McClain Plant. In the notice of intent, OG&E proposes that new rates go into effect upon issuance of an order by the

OCC no later than 180 days from the date of filing of the application. The proposed effective date of the rate change is the first billing cycle in December 2005. As provided in the Settlement Agreement, until OG&E seeks and obtains approval of a request to increase base rates to recover, among other things, 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 completion of the acquisition and the operation of the McClain Plant, consisting of the non-fuel operation and maintenance expenses, depreciation, cost of debt associated with the investment and ad valorem taxes. If the OCC were to approve OG&E’s request, all prudently incurred costs accrued through the regulatory asset within the 12-month period (which amount was approximately $17.8 million at March 31, 2005) would be included in OG&E’s prospective cost of service and would be recovered over a period to be determined by the OCC.

OG&E expects the addition of the McClain Plant, including the effects of an interim power purchase agreement OG&E had with NRG McClain LLC while OG&E was awaiting regulatory approval to complete the acquisition, will provide savings, over a three-year period, in excess of $75.0 million to its Oklahoma customers. In the event OG&E is unable to demonstrate at least $75.0 million in savings to its customers during this 36-month period, OG&E will be required to credit its Oklahoma customers any unrealized savings below $75.0 million as determined at the end of the 36-month period ending December 31, 2006. At this time, OG&E believes that it will be able to demonstrate at least $75.0 million in savings during this period.

Enogex FERC Section 311 2001 Rate Case

Pursuant to a settlement accepted by the FERC in May 2003 to resolve Enogex’s 2001 Section 311 rate case, Enogex assessed a fee under certain market conditions for processing customer gas gathered behind processing plants so that it met the heating value standards of natural gas transmission pipelines (“default processing fee”). Pursuant to Enogex’s Statement of Operating Conditions (“SOC”) that was effective through September 30, 2004, if Enogex’s annual processing gross margin on revenues (“gross margin”) exceeded a specified threshold, Enogex was 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. In June 2004, Enogex billed default processing fees of approximately $0.2 million, which was recorded as deferred revenue. Based on the processing gross margin for 2004, these default processing fees billed to customers were recorded as deferred revenue and were refunded or credited to customers by April 30, 2005.

Enogex FERC Section 311 2004 Rate Cases and related FERC dockets

On September 1, 2004, Enogex made a filing at the FERC to revise its previously approved SOC to permit, among other things, the unbundling, effective October 1, 2004, of its previously bundled gathering and transportation services. Under the unbundling plan, the FERC will regulate Enogex’s Section 311 transportation and any regulation of gathering will be pursuant to Oklahoma statute. Several parties challenged various aspects of the SOC changes and the filing is currently under review at the FERC.

On September 30, 2004, Enogex made its required triennial filing at the FERC to update Enogex’s Section 311 maximum transportation rate. Certain parties challenged aspects of the rate filing. In addition, on September 29, 2004, Enogex filed an updated fuel factor with the FERC for the last quarter of 2004. One party protested the fourth quarter 2004 fuel filing. On November 15, 2004, Enogex filed an updated fuel factor for fuel year 2005 (calendar year 2005). This is an annual filing made by Enogex to establish the fixed fuel percentage for natural gas shipped on the Enogex Section 311 system for the upcoming year. One intervenor has challenged the annual fuel factor filing.

The FERC Staff served, and Enogex answered, numerous data requests concerning the revised SOC, the rate filing and the fuel filings. An initial technical conference in the three dockets was held on January 13, 2005. At the conference, the parties agreed to brief one aspect of the Enogex filing and ask the FERC for policy guidance on that issue and also seek an extension of time in which to attempt to settle the rate case. Enogex and nearly all of the intervening parties filed a joint unopposed motion for an extension of time on January 25, 2005. The FERC has extended the time for action on these dockets by at least 90 days. The FERC has not yet acted on the request for policy guidance. Enogex, intervenors and the FERC Staff held a second technical and settlement conference on March 30, 2005. The parties continue to engage in settlement discussions.

Pending Regulatory Matters

Currently, OG&E has one significant matter pending at the OCC which is a review of the process completed by OG&E in its selection of gas transportation and storage services to meet its system operating needs. This matter, as well as several other matters pending before the OCC and the FERC, is discussed below.

Gas Transportation and Storage Agreement

As part of the Settlement Agreement, OG&E also agreed to consider competitive bidding as a basis to select its provider for gas transportation service to its natural gas-fired generation facilities pursuant to the terms set forth in the Settlement Agreement. The prescribed bidding process detailed in the Settlement Agreement provided that separate transportation services be bid for each generation facility. OG&E believes that, in order for it to achieve maximum coal generation, to deliver the lowest cost energy to its customers and to ensure reliable electric service, it must have integrated, firm no-notice load following service for both gas transportation and gas storage. This type of service is required to permit natural gas units to satisfy the daily swings in customer demand placed on OG&E’s system and not impede coal energy production. Accordingly, OG&E evaluated its competitive bid options in light of these circumstances. The study determined that the required integrated service is not available in the marketplace from parties other than Enogex. The study also indicated that non-integrated service would result in higher costs to customers. OG&E’s evaluation clearly demonstrates that the Enogex integrated gas system provides superior integrated, 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, as required by the Settlement Agreement, 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 integrated, 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. OG&E will pay Enogex annual demand fees of approximately $46.8 million for the right to transport specified maximum daily quantities (“MDQ”) and maximum hourly quantities (“MHQ”) of gas at various minimum gas delivery pressures depending on the operational needs of the individual generating facility. In addition, OG&E supplies system fuel in-kind for its pro-rata share of actual fuel and loss and unaccounted for gas on the transportation system. To the extent OG&E transports gas in quantities in excess of the prescribed MDQs or MHQs, it pays an overrun service charge. During the three months ended March 31, 2005 and 2004, OG&E paid Enogex approximately $11.9 million and $11.8 million, respectively, for gas transportation and storage services.

Based upon requests for information from intervenors, OG&E requested from Enogex and Enogex retained a “cost of service” consultant to assist in the preparation of testimony related to this case. On March 31, 2004, OG&E filed testimony and exhibits with the OCC, which completed the initial documentation required to be filed in this case. On July 12, 2004, several parties filed responsive testimony reflecting various positions on the issues related to this case. In particular, the testimony of the OCC Staff recommended that OG&E be entitled to recover the $46.8 million annual demand fee requested, which results in no refund, and also recommended that OG&E provide at its next general rate review the results of an open competitive bidding process or a comprehensive market study. If OG&E does not provide such open bidding or market study, the OCC Staff recommendation would cap recovery at approximately $40 million at OG&E’s next general rate review. The recommendations in the testimony of the Attorney General’s office and the Oklahoma Industrial Energy Consumers would cap recovery at approximately $35 million and $31 million, respectively, with the difference between what OG&E has been collecting through its automatic fuel adjustment clause and these recommended amounts being refunded to customers.

OG&E filed rebuttal testimony on August 16, 2004 in this case. Hearings in this case before an ALJ occurred from September 16-22, 2004. On October 22, 2004, the ALJ overseeing the proceeding recommended approximately $41.9 million annual demand fee recovery with OG&E refunding to its customers any demand fees collected in excess of this amount. If this recommendation is ultimately accepted, OG&E believes its refund obligation would be approximately $7.9 million at March 31, 2005, which the Company does not believe is material in light of previously established reserves. OG&E believes the amount currently paid to Enogex for integrated, firm no-notice load following transportation and storage services is fair, just and reasonable. OG&E and other parties to the proceeding appealed the ALJ’s recommendation on November 1, 2004 and a hearing in this case was held before the OCC on December 7, 2004. The OCC took the case under advisement and an OCC order in the case is now expected in the second quarter of 2005. There can be no guarantee that the OCC will approve the $41.9 million annual demand fee recovery recommended by the ALJ.

Competitive Bidding and Prudence Reviews for Electric Utility Providers

On March 10, 2005, the OCC filed Cause No. PUD 200500129 regarding “Inquiry of the Oklahoma Corporation Commission into Guidelines for Establishing Rules for Competitive Bidding and Prudence Reviews for Electric Utility Providers.” As an electric utility provider, any such guidelines that were adopted would likely impact OG&E. An initial technical conference was held on April 11, 2005 and another technical conference was held on April 27, 2005. Also, a hearing is scheduled for June 6, 2005 and OCC deliberations are expected to occur subsequent to June 6, 2005. At this time, OG&E cannot determine the impact of this ruling on its operations.

Review of OG&E’s Fuel Adjustment Clause for Calendar Year 2003

On March 18, 2005, the OCC Staff filed Cause No. PUD 200500140 regarding “Application of the Public Utility Division Director for Public Hearing to Review and Monitor OG&E’s Fuel Adjustment Clause for Calendar Year 2003.” The Company expects the OCC to issue a procedural schedule during the second quarter of 2005.

Southwest Power Pool

The regional state committee, which is comprised of commissioners of the applicable state regulatory commissions, finished its process of formulating a methodology for funding transmission expansion in the Southwest Power Pool (“SPP”) control area by allocating costs of transmission expansion to the SPP members who benefit. The SPP Board of Directors adopted this plan and filed it at the FERC on February 28, 2005, Docket No. ER05-652. The FERC conditionally accepted the plan on April 21, 2005 with an effective date of May 5, 2005. Also, the SPP is in the process of developing a process, required by the FERC, to create an imbalance energy market which will require cash settlements for over or under generation. Each SPP member will be responsible for monitoring its generation in its control area on an hourly basis and periodically submitting this information to the SPP, who will then provide settlement statements to each of the SPP members. The implementation date of the imbalance energy market requirements, which was initially planned to be effective October 1, 2005, has been suspended. The SPP Board of Directors voted on April 26, 2005 to make the implementation effective no later than March 1, 2006.

Market-Based Rate Authority

On December 22, 2003, OG&E and OERI filed a triennial market power update based on the supply margin assessment test. On April 14, 2004, the FERC issued: (1) interim requirements for the 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 fails to pass either assessment, the FERC will presume that the utility can exercise generation market power and will initiate an investigation into the scope of the applicant’s

market power. The FERC will allow a utility to rebut that presumption through the submission of additional information. If an applicant is found 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. On May 13, 2004, the FERC directed all utilities with pending three year market-based reviews to revise the generation market power portion of their three year review to address the two interim tests described above. 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. OG&E and OERI submitted a compliance filing to the FERC on February 7, 2005 which shows the impact of the new requirements on OG&E and OERI. In the compliance filing, OG&E and OERI passed the pivotal supplier screen but failed to pass the market share screen. OG&E and OERI provided an explanation as to why its failure of the market share screen should not be viewed as an indication that they can exercise generation market power. One party, Redbud, protested the OG&E and OERI filing and proposed that the FERC require OG&E to adopt an economic dispatch program as a means to mitigate OG&E’s and OERI’s generation market power. On March 15, 2005, OG&E and OERI responded to Redbud’s protest. In that response OG&E and OERI reiterated that the information they initially filed demonstrates that they cannot exercise market power and that Redbud’s proposal is beyond the scope of the proceeding. Another party, AES, has requested intervention in this case in protest. OG&E and OERI do not know when the FERC will act on the filing or what action the FERC will take.

State Legislative Initiatives

Oklahoma

In the 2005 legislative session, House Bills 1910 and 1386 were introduced. House Bill 1910 proposes that electric utilities: (i) be granted the certainty of knowing that costs of transmission upgrades assigned by a regional transmission organization will be recoverable, as will the costs for a pre-approved plan to handle state and federally mandated environmental upgrades; and (ii) be able to seek pre-approval for generation construction projects. Currently, utilities make investments and then seek approval from the OCC to include the investment in rates charged to customers. House Bill 1910 would eliminate much of the uncertainty surrounding the investments described above by knowing in advance that the investment had been determined to be “used and useful” which would ensure the utility recovery of its investment in future rates. House Bill 1386 proposes that utilities be able to continue to serve and expand, if so desired, in service territories in which they currently serve but which a municipality annexes. Currently, there is some legal uncertainty as to whether utilities can expand in an area described above. House Bill 1386 would remove that uncertainty. The future status of these bills is not known at this time.

Arkansas

In April 1999, Arkansas passed 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.

14. 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, 2004.

	March 31, 2005						December 31, 2004
		Carrying			Fair			Carrying			Fair
(In millions)		Amount			Value			Amount			Value

Price Risk Management Assets
Energy Trading Contracts	$	225	.8	$	225	.8	$	130	.3	$	130	.3
Interest Rate Swaps		2	.0		2	.0		7	.9		7	.9
Price Risk Management Liabilities
Energy Trading Contracts	$	199	.6	$	199	.6	$	109	.5	$	109	.5
Interest Rate Swaps		0	.9		0	.9		-	--		-	--
Long-Term Debt
Enogex Notes	$	486	.0	$	513	.5	$	514	.1	$	556	.3

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. The fair value of the Company’s long-term debt is based on quoted market prices and management’s estimate of current rates available for similar issues with similar maturities.

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

Introduction

The operations of the Natural Gas Pipeline segment are conducted through Enogex Inc. and its subsidiaries (“Enogex”) and consist of three related businesses: (i) the transportation and storage of natural gas, (ii) the gathering and processing of natural gas and (iii) the marketing of natural gas. Enogex’s focus is to utilize its gathering, processing, transportation and storage capacity to execute physical, financial and service transactions to capture margins across different commodities, locations or time periods. The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are located in the major gas producing basins of Oklahoma. Through a 75 percent interest in the NOARK Pipeline System Limited Partnership (“NOARK”), Enogex also owns a controlling interest in and operates Ozark Gas Transmission, L.L.C. (“Ozark”), a FERC regulated interstate pipeline that extends from southeast Oklahoma through Arkansas to southeast Missouri.

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”, “project” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit, actions of rating agencies and their impact on capital expenditures; the Company’s ability and the ability of its subsidiaries to obtain financing on favorable terms; prices of electricity, natural gas and natural gas liquids, each on a stand-alone basis and in relation to each other; business conditions in the energy industry; competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company; unusual weather; federal or state legislation and regulatory decisions (including the proceeding currently

pending before the OCC related to OG&E’s recovery of the costs billed to it by Enogex for gas transportation and storage services) and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition enters the Company’s market; environmental laws and regulations that may impact the Company’s operations; changes in accounting standards, rules or guidelines; creditworthiness of suppliers, customers and other contractual parties; the higher degree of risk associated with the Company’s nonregulated business compared with the Company’s regulated utility business; and other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission including Exhibit 99.01 to the Company’s Form 10-K for the year ended December 31, 2004.

Overview

Summary of Operating Results

The Company reported net income of approximately $5.3 million, or $0.06 per share, as compared to approximately $10.2 million, or $0.12 per share, for the three months ended March 31, 2005 and 2004, respectively. The decrease in net income for the three months ended March 31, 2005 as compared to the same period in 2004 was primarily due to:

OG&E reporting a net loss of approximately $1.7 million, or $0.02 per share of the Company’s common stock, for the three months ended March 31, 2005, as compared to break-even results for the three months ended March 31, 2004; and

Enogex’s operations, including discontinued operations, reporting net income of approximately $8.1 million, or $0.09 per share of the Company’s common stock, as compared to approximately $12.8 million, or $0.15 per share, for the three months ended March 31, 2005 and 2004, respectively.

These decreases to net income as compared to the prior period were partially offset by:

lower net interest expense of approximately $1.8 million at the holding company resulting in a net loss of approximately $0.01 per share for the three months ended March 31, 2005 as compared to a net loss of approximately $0.03 per share during the same period in 2004.

Earnings per share for the three months ended March 31, 2005 as compared to the same period in 2004 were affected by a higher amount of common stock outstanding from the issuance of common stock in 2004 pursuant to the Company’s Automatic Dividend Reinvestment and Stock Purchase Plan (“DRIP/DSPP”).

Outlook

The Company previously disclosed in its Form 10-K for the year ended December 31, 2004 that its earnings guidance was $137 million to $147 million of net income, or $1.50 to $1.60 per share. The Company has increased its 2005 earnings guidance to $149 million to $158 million of net income, or $1.65 to $1.75 per share, assuming approximately 90.5 million average diluted shares outstanding. The change in earnings guidance is due to the increase in projected

earnings at Enogex. The outlook for OG&E and the holding company remains unchanged (see “Outlook” in the Company’s Form 10-K for the year ended December 31, 2004 for a description of the underlying assumptions related to the earnings guidance for OG&E and the holding company). The 2005 outlook includes earnings guidance of $106 million to $110 million, or $1.17 to $1.22 per share, at OG&E and $49 million to $56 million, or $0.54 to $0.62 per share, at Enogex, while earnings guidance at the holding company is a loss between $6 million and $8 million, or $0.07 to $0.09 per share. During 2005, the Company expects cash flow from operations of between $333 million and $345 million. Additionally, funding for the Company’s pension plan is expected to be approximately $32.0 million in 2005. The Company expects to fund the pension plan during the second and third quarters of 2005. In April 2005, the Company funded approximately $10.7 million to the pension plan. Expected 2005 net income assumes a 38.7 percent effective tax rate.

For 2005, Enogex’s earnings guidance has been increased from $39 million to $43 million, or $0.43 to $0.48 per share, to $49 million to $56 million, or $0.54 to $0.62 per share. Enogex manages its operations along three related businesses: transportation and storage; gathering and processing; and marketing. In 2005, these businesses are assumed to produce a gross margin on revenues (“gross margin”) between $286 million and $297 million, down from $301 million in 2004. The Company expects approximately 45 percent of Enogex’s gross margin during 2005 to be generated from its transportation and storage business. Revenues in transportation and storage are primarily from gas transportation contracts with utilities in Oklahoma and Arkansas and independent power producers in Oklahoma. The Company expects its gathering and processing business to contribute approximately 52 percent of Enogex’s gross margin in 2005. Revenues in gathering and processing are expected to increase from the original 2005 earnings guidance due to higher forecasted commodity spreads. The Company has raised its 2005 commodity spread projections from $1.53 per Million British thermal unit (“MMBtu”) to an expected average spread for 2005 of between $2.02 and $2.56 per MMBtu. Average natural gas liquids price projections have also increased from $0.71 per gallon to between $0.82 and $0.89 per gallon in 2005. The Company still assumes 242 new well connects in its gathering and processing business in 2005. While operating improvements allowed Enogex to capture significant value in a favorable commodity environment, the commodity and well connect assumptions budgeted for 2005 reflect commodity prices that are not as robust as those experienced in 2004. The Company expects its marketing business to contribute approximately three percent of Enogex’s gross margin in 2005. Gross margins in marketing are expected to decrease in 2005 primarily due to 2004 gross margins being above expectations, its anticipated loss of approximately $5.0 million due to its position on the Cheyenne Plains Pipeline (see Note 12 of Notes to Condensed Consolidated Financial Statements) and the correction to the accounting procedure for park and loan transactions (see Note 11 of Notes to Condensed Consolidated Financial Statements). Enogex continues to expect lower operating expenses of approximately $5.1 million in 2005 due to not having an $8.6 million impairment charge that was recorded in the third quarter of 2004. Key factors affecting Enogex’s projected 2005 net income will be gathered volumes, natural gas and natural gas liquids prices and operating costs. Enogex expects to continue to evaluate the strategic fit and financial performance of each of its assets in an effort to ensure a proper economic allocation of resources. The magnitude and timing of any potential impairment or gain on the disposition of any assets have not been determined nor included in the 2005 earnings guidance.

Results of Operations

The following discussion and analysis presents factors which affected the Company’s consolidated results of operations for the three months ended March 31, 2005 as compared to the same period in 2004 and the Company’s consolidated financial position at March 31, 2005. The following information should be read in conjunction with the Condensed Consolidated Financial Statements and Notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.

	Three Months Ended March 31,
(In millions, except per share data)		2005			2004

Operating income	$	26	.0	$	31	.0
Net income	$	5	.3	$	10	.2
Basic average common shares outstanding		90	.0		87	.5
Diluted average common shares outstanding		90	.5		88	.1
Basic and diluted earnings per average common share	$	0.0	6	$	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 Income as operating income indicates the ongoing profitability of the Company excluding unusual or infrequent items, the cost of capital and income taxes.

Operating Income by Business Segment

	Three Months Ended March 31,
(In millions)		2005			2004

OG&E (Electric Utility)	$	2	.8	$	5	.0
Enogex (Natural Gas Pipeline)		22	.2		26	.0
Other Operations (A)		1	.0		-	--

Consolidated operating income	$	26	.0	$	31	.0

(A) Other Operations primarily includes unallocated corporate expenses and consolidating eliminations.

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)		2005			2004

Operating revenues	$	301	.0	$	304	.3
Cost of goods sold		175	.0		183	.2

Gross margin on revenues		126	.0		121	.1
Other operation and maintenance		77	.4		71	.5
Depreciation		33	.1		31	.9
Taxes other than income		12	.7		12	.7

Operating income	$	2	.8	$	5	.0

Operating revenues by classification
Residential	$	114	.2	$	125	.0
Commercial		70	.2		69	.1
Industrial		65	.7		64	.9
Public authorities		29	.1		28	.9
Sales for resale		13	.1		12	.6
Provision for refund on gas transportation and storage case		(1	.0)		-	--
Other		9	.3		3	.7

System sales revenues		300	.6		304	.2
Off-system sales revenues		0	.4		0	.1

Total operating revenues	$	301	.0	$	304	.3

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

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

Total sales		5	.8		5	.8

Number of customers		734,8	20		728,3	23

Average cost of energy per KWH (B) - cents
Fuel		2.4	03		2.1	72
Fuel and purchased power		2.8	13		2.9	62

Degree days (C)
Heating
Actual		1,6	65		1,7	85
Normal		1,9	63		1,9	82
Cooling
Actual			1			18
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, 2005 decreased approximately $2.2 million or 44.0 percent as compared to the same period in 2004. The decrease in operating income was primarily attributable to:

higher operation and maintenance expense; and

higher depreciation expense.

These decreases in operating income were partially offset by:

higher gross margins.

Gross margin, which is operating revenues less cost of goods sold, was approximately $126.0 million for the three months ended March 31, 2005 as compared to approximately $121.1 million during the same period in 2004, an increase of approximately $4.9 million or 4.0 percent. The gross margin increased primarily due to:

growth in OG&E’s service territory which increased the gross margin by approximately $3.8 million; and

the seasonal over collection of revenues related to the cogeneration credit rider, implemented January 1, 2005, as the rider is based on an equal monthly amount of kwh usage as compared to actual kwh usage, which increased the gross margin by approximately $3.1 million.

These increases in gross margin were partially offset by:

milder weather in OG&E’s service territory which reduced the gross margin by approximately $1.7 million; and

the provision for refund associated with OG&E’s gas transportation and storage case which reduced the gross margin by approximately $1.0 million.

Cost of goods sold for OG&E consists of fuel used in electric generation and purchased power. Fuel expense was approximately $132.3 million for the three months ended March 31, 2005 as compared to approximately $108.0 million during the same period in 2004, an increase of approximately $24.3 million or 22.5 percent. The increase was primarily due to an increase in the average cost of fuel per kwh, primarily due to higher average natural gas prices. Purchased power costs were approximately $42.7 million for the three months ended March 31, 2005 as compared to approximately $75.2 million during the same period in 2004, a decrease of approximately $32.5 million or 43.2 percent. The decrease was primarily due to OG&E’s acquisition of a 77 percent interest in the 520 megawatt (“MW”) NRG McClain Station (the “McClain Plant”) in July 2004, the termination of a power purchase contract in August 2004 which was replaced with a new contract in September 2004 and the scheduled decrease in cogeneration capacity payments for another power purchase contract, which decreases became effective in January 2005.

Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking,

are passed through to OG&E’s customers through automatic fuel adjustment clauses. While the regulatory mechanisms for recovering fuel costs differ in Oklahoma, Arkansas and the FERC, in each jurisdiction the costs are passed through to customers and are intended to provide neither an ultimate benefit nor detriment to OG&E. The automatic fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC have authority to review the appropriateness of gas transportation charges or other fees OG&E pays to Enogex. See Note 13 of Notes to Condensed Consolidated Financial Statements for a discussion of current proceedings at the OCC regarding OG&E’s gas transportation and storage contract with Enogex and a review of OG&E’s automatic fuel adjustment clause for 2003.

Other operating and maintenance expenses were approximately $77.4 million for the three months ended March 31, 2005 as compared to approximately $71.5 million during the same period in 2004, an increase of approximately $5.9 million or 8.3 percent. The increase in other operating and maintenance expenses was primarily due to:

higher salaries and wages expense of approximately $2.8 million, higher employee expenses of approximately $0.6 million and higher pension and benefit expense of approximately $0.4 million, primarily due to more capitalized costs during the first quarter of 2004 and increased salary and wage rates; and

higher outside services expense of approximately $2.5 million and higher materials and supplies expense of approximately $2.0 million, primarily due to higher expenses for infrastructure projects in the first quarter of 2005 as spending OG&E had to reduce its rates, effective January 1, 2004.

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

lower allocations from the holding company of approximately $3.6 million primarily due to lower miscellaneous corporate expenses.

Depreciation expense was approximately $33.1 million for the three months ended March 31, 2005 as compared to approximately $31.9 million during the same period in 2004, an increase of approximately $1.2 million or 3.8 percent, primarily due to a higher level of depreciable plant.

Enogex – Continuing Operations

	Three Months Ended March 31,
(Dollars in millions)		2005			2004

Operating revenues	$	1,000	.8	$	749	.2
Cost of goods sold		937	.6		683	.5

Gross margin on revenues		63	.2		65	.7
Other operation and maintenance		24	.6		23	.3
Depreciation		11	.6		11	.5
Taxes other than income		4	.8		4	.9

Operating income	$	22	.2	$	26	.0

New well connects		5	3		6	3

Gathered volumes - TBtu/d (A)		1.0	0		1.0	1
Incremental transportation volumes - TBtu/d		0.4	8		0.4	1

Total throughput volumes -TBtu/d		1.4	8		1.4	2

Natural gas processed - Mmcf/d (B)		50	0		47	3

Natural gas liquids sold (keep-whole) - million gallons		7	8		5	3
Natural gas liquids sold (POL and fixed-fee) - million gallons			4			4

Total natural gas liquids sold - million gallons		8	2		5	7

Average sales price per gallon	$	0.74	6	$	0.65	9

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

Enogex’s operating income for the three months ended March 31, 2005 decreased approximately $3.8 million or 14.6 percent as compared to the same period in 2004. The decrease in operating income was primarily attributable to lower gross margins of approximately $4.4 million in Enogex’s marketing business and of approximately $0.6 million in Enogex’s transportation and storage business which was only partially offset by increased gross margins of approximately $2.5 million in Enogex’s gathering and processing business.

Transportation and storage contributed approximately $29.9 million of Enogex’s gross margin for the three months ended March 31, 2005 as compared to approximately $30.5 million during the same period in 2004, a decrease of approximately $0.6 million or 2.0 percent. The gross margin decreased primarily due to:

increased fuel expenses due to higher natural gas prices and fuel usage which reduced the gross margin by approximately $2.1 million; and

a reduction in retained fuel sales on the Ozark transmission system which reduced the gross margin by approximately $1.5 million.

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

higher purchases and sales activity of natural gas due to Enogex being more active in the market place which increased the gross margin by approximately $2.1 million; and

increased crosshaul prices and volumes partially offset by higher electric rates which increased the gross margin by approximately $0.8 million.

Gathering and processing contributed approximately $34.9 million of Enogex’s gross margin for the three months ended March 31, 2005 as compared to approximately $32.4 million during the same period in 2004, an increase of approximately $2.5 million or 7.7 percent. Gathering gross margins increased approximately $0.5 million for the three months ended March 31, 2005 as compared to the same period in 2004. The gathering gross margin increased primarily due to:

contractual fuel gains primarily due to higher natural gas prices which increased the gross margin by approximately $1.3 million; and

higher natural gas compression fees primarily due to an increase in low pressure gathering volumes (subject to compression fees) which increased the gross margin by approximately $0.5 million.

These increases in the gathering gross margin were partially offset by:

lower margins on natural gas sales which reduced the gross margin by approximately $0.9 million; and

higher electric compression costs which reduced the gross margin by approximately $0.4 million.

Processing gross margins increased approximately $2.0 million for the three months ended March 31, 2005 as compared to the same period in 2004 primarily due to:

increased condensate margins primarily due to higher condensate prices which increased the gross margin by approximately $1.2 million; and

increased keep-whole margins primarily due to higher keep-whole volumes which increased the gross margin by approximately $1.1 million.

Marketing reduced Enogex’s gross margin by approximately $1.6 million for the three months ended March 31, 2005 as compared to a contribution of approximately $2.8 million during the same period in 2004, a decrease of approximately $4.4 million. The gross margin decreased primarily due to:

a correction to the accounting procedure for park and loan transactions in 2004 which reduced the gross margin by approximately $7.7 million (see Note 11 of Notes to Condensed Consolidated Financial Statements); and

mark-to-market timing losses on natural gas storage inventory due to different pricing environments during 2005 as compared to 2004 which reduced the gross margin by approximately $0.8 million.

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

gains recorded on natural gas previously in storage inventory, which was subject to a lower of cost or market adjustment in 2004, which increased the gross margin by approximately $3.1 million; and

lower demand fees paid for storage services due to establishing new rates for the new storage season which began April 1, 2004 which increased the gross margin by approximately $1.1 million.

Enogex’s other operating and maintenance expenses were approximately $24.6 million for the three months ended March 31, 2005 as compared to approximately $23.3 million during the same period in 2004, an increase of approximately $1.3 million or 5.6 percent. The increase in other operating and maintenance expenses was primarily due to:

higher outside services costs of approximately $0.9 million related to maintaining the integrity and safety of Enogex’s pipeline and an inventory management study; and

higher materials and supplies expense of approximately $0.6 million for repairs and maintenance of systems.

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

lower allocations from the holding company of approximately $0.6 million due to lower miscellaneous corporate expenses.

During the three months ended March 31, 2005, Enogex had a decrease in net income of approximately $4.7 million relating to a correction to the accounting procedure for park and loan transactions in 2004, which the Company does not consider to be reflective of the ongoing profitability of Enogex’s business. During the three months ended March 31, 2004, Enogex had an increase in net income of approximately $4.2 million relating to various items that the Company does not consider to be reflective of the ongoing profitability of Enogex’s business. These increases in net income include:

an Oklahoma investment tax credit of approximately $2.0 million;

an imbalance settlement with a customer of approximately $1.6 million;

a gain on the sale of Enogex compression and processing assets of approximately $0.7 million; and

income from discontinued operations of approximately $0.4 million.

These increases to net income were partially offset by:

under recovered fuel of approximately $0.5 million.

Consolidated Other Income and Expense, Net 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, minority interest income and miscellaneous non-operating income. Other income was approximately $1.7 million for the three months ended March 31, 2005 as compared to approximately $2.8 million during the same period in 2004, a decrease of approximately $1.1 million or 39.3 percent. The decrease in other income was

primarily due to a realized gain of approximately $1.2 million on the sale of certain of Enogex’s compression and processing assets during the first quarter of 2004.

Other expense includes, among other things, expenses from the losses on the sale of assets, minority interest expense, miscellaneous charitable donations, expenditures for certain civic, political and related activities and miscellaneous deductions. Other expense was approximately $2.0 million for the three months ended March 31, 2005 as compared to approximately $1.5 million during the same period in 2004, an increase of approximately $0.5 million or 33.3 percent. The increase in other expense was primarily due to:

an increase in the liability associated with the deferred compensation plan and the restoration of retirement income plan of approximately $0.2 million; and

income tax penalties assessed related to prior periods of approximately $0.2 million.

Net interest expense includes interest income, interest expense and other interest charges. Net interest expense was approximately $19.2 million for the three months ended March 31, 2005 as compared to approximately $23.1 million during the same period in 2004, a decrease of approximately $3.9 million or 16.9 percent. The decrease in net interest expense was primarily due to:

a net reduction in interest expense of approximately $3.9 million due to the reduction of long-term debt outstanding;

an increase in interest income of approximately $1.8 million due to the interest portion of an income tax refund related to prior periods; and

a reduction in interest expense of approximately $0.5 million due to an increase in the allowance for borrowed funds used during construction.

These decreases in net interest expense were partially offset by:

an increase in interest expense of approximately $1.8 million due to an increase in variable interest rates associated with the Company’s interest rate swap agreements and variable rate industrial authority bonds.

Income tax expense was approximately $1.2 million for the three months ended March 31, 2005 as compared to an income tax benefit of approximately $0.6 million during the same period in 2004, an increase in income tax expense of approximately $1.8 million. The increase in income tax expense was primarily due to:

a decrease in Oklahoma state tax credits of approximately $3.3 million during the first quarter of 2005 as compared to the same period in 2004.

This increase in income tax expense was partially offset by:

lower pre-tax income for the Company.

Financial Condition

The balance of Accounts Receivable was approximately $416.8 million and $487.9 million at March 31, 2005 and December 31, 2004, respectively, a decrease of approximately $71.1 million or 14.6 percent. The decrease was primarily due to a decrease in OG&E’s billings to its customers reflecting milder weather in March 2005 as compared to December 2004 and lower natural gas prices and volumes associated with Enogex’s activities in the first quarter of 2005.

The balance of Fuel Inventories was approximately $53.7 million and $89.0 million at March 31, 2005 and December 31, 2004, respectively, a decrease of approximately $35.3 million or 39.7 percent. The decrease was primarily due to inventory sales at Enogex during the first quarter of 2005.

The balance of current Price Risk Management assets was approximately $207.0 million and $118.6 million at March 31, 2005 and December 31, 2004, respectively, an increase of approximately $88.4 million or 74.5 percent. The increase was primarily due to higher volumes associated with park and loan transactions and related financial contracts associated with OGE Energy Resources, Inc.’s (“OERI”) activities during the first quarter of 2005.

The balance of the Gas Imbalance asset was approximately $126.9 million and $100.1 million at March 31, 2005 and December 31, 2004, respectively, an increase of approximately $26.8 million or 26.8 percent. The Gas Imbalance asset is comprised of planned or managed imbalances related to Enogex’s marketing business, referred to as park and loan transactions, and pipeline and natural gas liquids imbalances, which are operational imbalances. Park and loan transactions were approximately $114.4 million and $76.0 million at March 31, 2005 and December 31, 2004, respectively, an increase of approximately $38.4 million or 50.5 percent. The increase was due to an increase in park and loan transactions during the three months ended March 31, 2005 resulting from economic opportunities in the marketplace.

The balance of Fuel Clause Under Recoveries was approximately $29.7 million and $54.3 million at March 31, 2005 and December 31, 2004, respectively, a decrease of approximately $24.6 million or 45.3 percent. The decrease in fuel clause under recoveries was due to the amount billed to OG&E’s customers during the three months ended March 31, 2005 exceeding OG&E’s cost of fuel. OG&E’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 are intended to allow OG&E to amortize under or over recovery. OG&E expects to recover the fuel clause under recoveries during 2005.

The balance of Short-Term Debt was approximately $154.0 million and $125.0 million at March 31, 2005 and December 31, 2004, respectively, an increase of approximately $29.0 million or 23.2 percent. The increase was primarily due to the daily operational needs of the Company.

The balance of Accounts Payable was approximately $428.1 million and $476.2 million at March 31, 2005 and December 31, 2004, respectively, a decrease of approximately $48.1 million or 10.1 percent. The decrease was primarily due to lower natural gas prices and volumes associated with Enogex’s activities in the first quarter of 2005.

The balance of current Price Risk Management liabilities was approximately $180.1 million and $102.9 million at March 31, 2005 and December 31, 2004, respectively, an increase of approximately $77.2 million or 75.0 percent. The increase was primarily due to higher volumes associated with park and loan transactions and related financial contracts associated with OERI’s activities during the first quarter of 2005.

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, 2004.

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”) in November 1998. The Company terminated the MBP 19 program during the second quarter of 2005, with an effective date of January 31, 2005, and recorded a reduction in operating and maintenance expense of approximately $0.6 million related to this transaction.

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 (including technology) at Enogex. Other working capital requirements are primarily related to

maturing debt, operating lease obligations, hedging activities, natural gas storage and delays in recovering unconditional fuel purchase obligations. The Company generally meets its cash needs through a combination of internally generated funds, short-term borrowings (through a combination of bank borrowings and commercial paper) and permanent financings.

Interest Rate Swap Agreements

Fair Value Hedges

At March 31, 2005, the Company had three outstanding interest rate swap agreements that qualified as fair value hedges: (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 a total of $200.0 million ($100.0 million for each interest rate swap agreement) of 8.125 percent fixed rate debt due January 15, 2010, to a variable rate based on the six month LIBOR in arrears. 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 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 2005 to 2007 construction program includes continued investment in distribution, generation and transmission systems that is part of the Company’s Customer Savings and Reliability Plan. OG&E has approximately 430 MWs of contracts with qualified cogeneration facilities and small power production producers’ (“QF contracts”) that will expire at the end of 2007, unless extended by OG&E. In addition, effective September 1, 2004, OG&E entered into a new 15-year power sales agreement for 120 MWs with PowerSmith Cogeneration Project, L.P. OG&E will continue reviewing all of the supply alternatives to these expiring QF contracts that minimize the total cost of generation to its customers, including exercising its options (if applicable) to extend these QF contracts at pre-determined rates. Accordingly, OG&E will continue to explore opportunities to build or buy power plants in order to serve its native load. As a result of the high volatility of current natural gas prices and the increase in natural gas prices, OG&E will also assess the feasibility of constructing additional base load coal-fired units. Approximately $7.0 million of the Company’s capital expenditures budgeted for 2005 are to comply with environmental laws and regulations.

Pension and Postretirement Benefit Plans

The Company previously disclosed in its Form 10-K for the year ended December 31, 2004 that it expected to contribute approximately $37.4 million to the pension plan in 2005. The Company presently anticipates reducing this amount by approximately $5.4 million during 2005, for a total contribution of approximately $32.0 million in 2005 which represents the Company’s 2004 pension expense. The Company plans to make contributions to the pension plan during the second and third quarters of 2005. In April 2005, the Company funded approximately $10.7 million to the pension plan. The remaining expected contributions to the pension plan in 2005, 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.

Future Sources of Financing

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

Short-Term Debt

The following table shows the Company’s lines of credit in place, commercial paper outstanding and available cash at March 31, 2005. At March 31, 2005, the Company’s short-

term borrowings consisted of borrowings on its revolving credit agreement and commercial paper.

Lines of Credit, Commercial Paper and Available Cash (In millions)
Entity	Amount Available	Amount Outstanding	Maturity
OGE Energy Corp. OG&E (B) OGE Energy Corp. (D)	$ 15.0 100.0 450.0	$ --- --- 154.0	April 6, 2005 (A) October 20, 2009 (C) October 20, 2009 (C)
	565.0	154.0
Cash	20.3	N/A	N/A
Total	$ 585.3	$ 154.0
(A) In April 2005, the Company renewed its $15.0 million credit facility, shown in the table above, which matures April 6, 2006.
(B) No borrowings were outstanding at March 31, 2005 under this line of credit; however, $0.2 million of this line of credit supports a letter of credit.
(C) Each of the new credit facilities has a five-year term with two options to extend the term for one year.
(D) This bank facility is available to back up a maximum of $300.0 million of the Company’s commercial paper borrowings and can be used as a letter of credit facility. At March 31, 2005, the Company had approximately $85.0 million in outstanding borrowings under this line of credit and approximately $69.0 million in commercial paper borrowings.

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 contingent 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 affect 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, 2004.

Accounting Pronouncements

See Note 2 of Notes to Condensed Consolidated Financial Statements for a discussion of recent accounting pronouncements that are applicable to the Company.

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 Notes 12 and 13 of Notes to Condensed Consolidated Financial Statements in this Form 10-Q and in the Company’s Form 10-K for the year ended December 31, 2004. OG&E currently has one important matter pending before the OCC. See Note 13 of Notes to Condensed Consolidated Financial Statements for a further discussion.

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 disclosed otherwise in this report or in the Company’s Form 10-K for the year ended December 31, 2004, 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. See Notes 12 and 13 of Notes to Condensed Consolidated Financial Statements and Item 1 of Part II in this Form 10-Q and Notes 17 and 18 to the Company’s Consolidated Financial Statements included in the Company’s Form 10-K for the year ended December 31, 2004 for a discussion of the Company’s commitments and contingencies.

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 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 and other forward transactions pursuant to the Company’s policies on hedging practices. These 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 short-term debt, interest rate swap agreements 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 utilizes 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, 2004. On April 1, 2005, Enogex terminated its interest rate swap agreements and received approximately $0.2 million related to this transaction. Since inception of the Enogex interest rate swap agreements, the Company has received approximately $32.5 million related to these agreements and the effective interest rate until maturity will be approximately 7.67 percent on this long-term debt. See Notes 8 and 9 of Notes to Condensed Consolidated Financial Statements in this Form 10-Q 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 can be classified as trading, which includes transactions that are entered into voluntarily to capture subsequent changes in commodity prices, or non-trading, which includes 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, subject to a $1.5 million limit, as well as other quantitative risk measurement techniques. 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 hedges, through the utilization of derivatives and other forward transactions, 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 hedges 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.

Sensitivity analyses have been prepared to estimate the Company’s exposure to the market risk of the Company’s natural gas and natural gas liquids commodity positions. These analyses are done for both trading and non-trading activities. 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 value of trading positions is a summation of the fair values calculated for each commodity by valuing each net position at quoted market prices. Because quoted market prices are not available for all of the Company’s non-trading positions, the value of non-trading positions is a summation of the forecasted values calculated for each commodity based upon internally generated forecast 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 these analyses, which may differ from actual results, are as follows as of March 31, 2005.

(In millions)	Trading			Non-Trading

Commodity market risk, net	$	1	.1	$	8	.1

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.

As reported in Note 11 of Notes to Condensed Consolidated Financial Statements included in this report, the Company, in the first quarter of 2005, corrected its procedure for accounting for park and loan transactions in 2004 that resulted from an incorrect change in accounting procedure which was implemented during 2004. The incorrect procedure affected the timing of recognition of revenue and income from park and loan transactions and resulted in the temporary overstatement of operating revenues without the associated expense until the transaction was completed and the expense recognized. As a result of this correction, Enogex recorded a pre-tax charge of approximately $7.7 million as a reduction in Operating Revenues in the Condensed Consolidated Statement of Income and a corresponding $7.7 million decrease in Current Price Risk Management Assets in the Condensed Consolidated Balance Sheet during the three months ended March 31, 2005.

The Company concluded that the prior improper change in accounting for park and loan transactions was not a material weakness in its internal controls and that the subsequent correction was not a material change to its internal controls.

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, 2004 for a description of certain legal proceedings presently pending. Except as set forth below and in Notes 12 and 13 of Notes to Condensed Consolidated Financial Statements in this Form 10-Q, 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.

1. As reported in Part I, Item 3 (Legal Proceedings) of the Company’s Form 10-K for the year ended December 31, 2004, the Company has been involved in legal proceedings filed by Jack J. Grynberg in federal courts related to natural gas measurement. Various procedural motions have been filed and discovery is proceeding on limited jurisdictional issues. A hearing on the defendants’ motions to dismiss for lack of subject matter jurisdiction, including public disclosure, original source and voluntary disclosure requirements was held March 17 – 18, 2005. The court indicated that a ruling would be made regarding these motions by the end of April 2005; however, no ruling has been issued to date.

2. As reported in Part I, Item 3 (Legal Proceedings) of the Company’s Form 10-K for the year ended December 31, 2004, OGE Energy Corp., Enogex, Central Oklahoma Oil and Gas Corp. (“COOG”), Natural Gas Storage Corporation (“NGSC”) and individual shareholders of COOG and NGSC have been involved in legal proceedings relating to a gas storage agreement and associated agreements. In the actions pending against the individuals in the U.S. District Court for Western District of Oklahoma, the jury, on October 25, 2004, ruled in favor of the Company and Enogex for approximately $6.6 million. The individual defendants filed a motion for new trial. On March 23, 2005, the court entered an order: (i) denying the defendants’ motion for new trial; (ii) denying the defendants’ motion to stay; and (iii) granting the motion of OGE Energy Corp. and Enogex to allow registration of judgments in the U.S. District Court for the Southern District of Texas. On April 20, 2005, the defendants filed an appeal in the Tenth Circuit Court of Appeals.

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

3. OG&E has been sued by Kaiser-Francis Oil Company in District Court, Blaine County, Oklahoma. This case has been pending for more than 10 years. Plaintiff alleges that OG&E breached the terms of numerous contracts covering approximately 60 wells by failing to purchase gas from Plaintiff in amounts set forth in the contracts. Plaintiff seeks $25.0 million in take-or-pay damages and $1.8 million in underpayment damages. Over the objection and

unsuccessful appeal by OG&E, Plaintiff has been permitted to amend its petition to include a claim based on theories of tort. Specifically, Plaintiff alleges, among other things, that OG&E intentionally and tortuously interfered with contracts by falsifying documents, sponsoring false testimony and putting forward legal defenses, which are known by OG&E to be without merit. If successful, Plaintiff believes that these theories could give Plaintiff a basis to seek punitive damages. This lawsuit was stayed pending the outcome of an appeal that OG&E filed in a similar case brought by Kaiser-Francis in Grady County.

In the Grady case, the plaintiff alleged that OG&E breached the terms of several gas purchase contracts in amounts set forth in the contracts. In 2001, the district court rendered a verdict against OG&E in the amount of approximately $8.0 million, including pre-judgment interest and attorneys’ fees. OG&E filed an appeal and on May 18, 2004, the Court of Appeals issued an opinion reversing the judgment and remanding for a new trial. The appellate court found that the trial court committed reversible error in rejecting a portion of OG&E’s interpretation of the commercial well provisions of the gas purchase contracts, and in failing to recognize issues of fact for the jury relating to OG&E’s contention regarding the correct initial reserve estimate on one of the natural gas wells, the Thiel No 1-9. In addition, the appellate court made rulings favorable to OG&E relating to the statutory measure of damages, the effect of line pressure adjustment provisions in the contracts, and the admission of certain hearsay evidence. The appellate court made rulings favorable to Kaiser-Francis relating to the effect of royalty payment obligations on the amount of damages, the effect of the amount of reserves owned by Kaiser-Francis in the wells on OG&E’s gas purchase obligation, the propriety of the award of prejudgment interest, and OG&E’s liability for the payment of gross production taxes pertaining to the damages awarded. The appellate court returned an issue relating to the alleged effect of Kaiser-Francis’s failure to make gas available for consideration by the trial court. Finally, the appellate court denied Kaiser-Francis’s request for appeal-related attorney’s fees and costs. On July 6, 2004, the Court of Appeals denied Kaiser-Francis’s motion for rehearing. Both parties filed petitions for certiorari with the Oklahoma Supreme Court for the review of those portions of the appellate court’s opinion unfavorable to each. The Oklahoma Supreme Court denied both parties’ petitions for certiorari on January 10, 2005. Mandate was issued by the Oklahoma Supreme Court on February 4, 2005. Since then, the Blaine County case has been set for trial beginning January 17, 2006. The Grady County case has been set for trial beginning October 17, 2005. Additionally, Kaiser-Francis has filed a motion in the Grady County case asking for leave to file a fourth amended petition, the purpose of which is to include a claim based on the same theories of tort as alleged in the Blaine County case. OG&E will be opposing that motion, which is set for hearing May 19, 2005.

OG&E believes that, to the extent Plaintiff were successful on the merits of its claims of OG&E’s failure to take gas in either the Blaine County case or Grady County case, these amounts would be recoverable through its regulated electric rates. The claims related to tortuous conduct, which OG&E believes at this time are without merit, would not appear to be recoverable in its electric rates.

4. On March 8, 2005, Enogex was served with a putative class action filed by G.M. Oil Properties, Inc. in the District Court of Comanche County, Oklahoma. The petition alleges that Enogex exercises a monopoly power with respect to its gathering facilities within the state of

Oklahoma. The petition further alleges that, due to the alleged monopoly power, Enogex has caused damage to the plaintiff and other small gas producers and marketers.

The Company intends to vigorously defend this action. At the present time, the Company believes the case is without merit and is filing a motion to dismiss for failure to state a claim.

Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities.

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


Period	Total Number of Shares Purchased	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plan	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan

1/1/05 - 1/31/05	77,500	$25.84	N/A	N/A
2/1/05 - 2/28/05	65,000	$25.90	N/A	N/A
3/1/05 - 3/31/05	26,100	$26.69	N/A	N/A

N/A - not applicable

Item 6. Exhibits.

Exhibit No.		Description
10.01		Fifth Amendment to Loan Agreement, dated April 6, 2005 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.

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 4, 2005

Exhibit 10.01

FIFTH AMENDMENT TO LOAN AGREEMENT

This Fifth Amendment to Loan Agreement (the “Fifth Amendment”) is made effective as of April 6, 2005, by and among OGE Energy Corp., an Oklahoma corporation (the “Borrower”), and Bank of Oklahoma, N.A., a national banking association (the “Lender”).

RECITALS:

A. The 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, a Third Amendment dated April 6, 2003, and a Fourth Amendment dated April 6, 2004 (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, 2006.

The definition of “364-Day Facility” is amended to mean the unsecured Credit Agreement dated as of October 20, 2004, between the Borrower and Wachovia Bank, N.A., as administrative agent and JP Morgan Chase Bank as syndication agent.

The definition of “Note” is amended to mean the renewal promissory note in the form attached to this Fifth 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 Fifth Amendment, the Borrower represents and warrants to the Lender as follows:

(a) Authorization and Enforceability. This Fifth 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 Fifth 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 Fifth 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 Fifth Amendment, and all such representations and warranties are incorporated herein by reference.

(c) Other Agreements. Except as expressly amended by this Fifth Amendment, Borrower hereby adopts and remakes to the Lender all of its respective agreements and covenants contained in the Loan Agreement effective as of the effective date of this Fifth 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 Fifth 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 Fifth 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 Fifth Amendment on the 6th day of April 2005.


BORROWER:		OGE ENERGY CORP., an Oklahoma
		corporation

	By:	/s/ Deborah S. Fleming
		Name: Deborah S. Fleming
		Title: Treasurer


BANK:		BANK OF OKLAHOMA, N.A.

	By:	/s/ Laura Christofferson
		Name: Laura Christofferson
		Title: Senior Vice President

EXHIBIT “A”

REVOLVING NOTE

$15,000,000

April 6, 2005

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, 2005, 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 long-term debt ratings of Borrower by the Moody’s Rating, Fitch Rating and S&P Rating. In the event of split ratings and (a) two ratings are equal and higher than the third, the higher rating will apply, (b) two ratings are equal but lower than the third, the lower rating shall apply, (c) no ratings are equal, the intermediate rating will apply.


Tier	Debt Rating Utilization Fee**		Facility Fee*	LIBOR Margin	Prime Rate Loans

1	> A1/A+ /A+	0.10%	0.08%	0.22%	0%

2	> A2/A/A	0.10%	0.08%	0.27%	0%

3	> A3/A-/A-	0.125%	0.10%	0.325%	0%

4	> Baa1/BBB+/BBB+	0.125%	0.125%	0.375%	0%

5	> Baa2/BBB/BBB	0.125%	0.15%	0.60%	0%

6	> Baa3//BBB-/BBB-	0.125%	0.175%	0.825%	0%

7	< Baa3//BBB-/BBB-	0.25%	0.25%	1.25%	0%

	* Irrespective of usage.
	** If usage > 50%

“Moody’s Rating” means, at any time, the rating issued by Moody’s Investor Service, Inc., 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 Standard and Poor’s Rating Services, a division of The McGraw Hill Companies, Inc., and then in effect with respect to the Borrower’s senior unsecured long-term debt securities without third-party credit enhancement.

“Fitch Rating” means, at any time, the rating issued by Fitch Ratings, 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 Rating, Fitch Rating and S&P Rating. 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 VII status shall exist.

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)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) 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) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) 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

d) 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 4, 2005

/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 4, 2005

/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, 2005, 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 4, 2005

	/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, 2005

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 INCOME (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

Fair Value Hedges

9. Short-Term Debt

10. Retirement Plans and Postretirement Benefit Plans

11. Report of Business Segments

12. Commitments and Contingencies

Air

Water

13. Rate Matters and Regulation

Regulatory Matters

Pending Regulatory Matters

14. 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

Fair Value Hedges

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 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities.

Item 6. Exhibits.

SIGNATURE

FIFTH AMENDMENT TO LOAN AGREEMENT

EXHIBIT “A”

REVOLVING NOTE

EXHIBIT “B”

PRICING GRID

CERTIFICATIONS

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 INCOME
(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.