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 June 30, 2004

[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to

Commission File Number: 1-12579

OGE ENERGY CORP.
(Exact name of registrant as specified in its charter)

Oklahoma
(State or other jurisdiction of
incorporation or organization)

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

321 North Harvey
P.O. Box 321
Oklahoma City, Oklahoma 73101-0321
(Address of principal executive offices)
(Zip Code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No

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

As of July 31, 2004, 87,626,912 shares of common stock, par value $0.01 per share, were outstanding.

OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2004

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	35
Item 3. Quantitative and Qualitative Disclosures About Market Risk	63
Item 4. Controls and Procedures	64
Part II - OTHER INFORMATION
Item 1. Legal Proceedings	65
Item 4. Submission of Matters to a Vote of Security Holders	66
Item 6. Exhibits and Reports on Form 8-K	66
Signature	69

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

(In millions)	June 30, 2004			December 31, 2003

ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	44	.7	$	245	.6
Accounts receivable, less reserve of $3.2 and $4.2, respectively		390	.2		350	.2
Accrued unbilled revenues		66	.2		38	.0
Fuel inventories		116	.4		163	.3
Materials and supplies, at average cost		48	.3		45	.1
Price risk management		73	.4		61	.3
Gas imbalance		37	.1		70	.0
Accumulated deferred tax assets		9	.7		9	.4
Fuel clause under recoveries		9	.3		4	.0
Other		4	.9		21	.5

Total current assets		800	.2		1,008	.4

OTHER PROPERTY AND INVESTMENTS, at cost		36	.4		34	.7

PROPERTY, PLANT AND EQUIPMENT
In service		5,662	.3		5,596	.3
Construction work in progress		90	.3		56	.7
Other		12	.6		15	.0

Total property, plant and equipment		5,765	.2		5,668	.0
Less accumulated depreciation		2,417	.8		2,358	.5

Net property, plant and equipment		3,347	.4		3,309	.5

DEFERRED CHARGES AND OTHER ASSETS
Recoverable take or pay gas charges		32	.5		32	.5
Income taxes recoverable from customers, net		31	.2		31	.6
Intangible asset - unamortized prior service cost		40	.2		40	.2
Prepaid benefit obligation		85	.7		55	.7
Price risk management		20	.4		13	.5
Other		62	.1		58	.6

Total deferred charges and other assets		272	.1		232	.1

TOTAL ASSETS	$	4,456	.1	$	4,584	.7

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

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

(In millions)	June 30, 2004			December 31, 2003

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Short-term debt	$	-	--	$	202	.5
Accounts payable		343	.0		280	.2
Dividends payable		29	.1		29	.1
Customers’ deposits		44	.0		41	.6
Accrued taxes		41	.8		18	.7
Accrued interest		30	.8		30	.7
Accrued interest - unconsolidated affiliate		3	.5		3	.5
Tax collections payable		10	.0		7	.9
Accrued vacation		18	.1		17	.2
Long-term debt due within one year		68	.3		52	.1
Non-recourse debt of joint venture		1	.2		1	.2
Price risk management		70	.2		46	.9
Gas imbalance		30	.7		22	.5
Fuel clause over recoveries		-	--		32	.4
Other		28	.4		41	.2

Total current liabilities		719	.1		827	.7

LONG-TERM DEBT
Long-term debt		1,148	.5		1,189	.7
Non-recourse debt of joint venture		39	.6		40	.2
Long-term debt - unconsolidated affiliate		206	.2		206	.2

Total long-term debt		1,394	.3		1,436	.1

DEFERRED CREDITS AND OTHER LIABILITIES
Accrued pension and benefit obligations		172	.0		167	.4
Accumulated deferred income taxes		748	.8		747	.3
Accumulated deferred investment tax credits		39	.4		42	.0
Accrued removal obligations, net		122	.5		116	.3
Price risk management		16	.5		4	.5
Provision for payments of take or pay gas		32	.5		32	.5
Other		14	.2		9	.3

Total deferred credits and other liabilities		1,145	.9		1,119	.3

STOCKHOLDERS’ EQUITY
Common stockholders’ equity		641	.0		636	.1
Retained earnings		614	.8		623	.9
Accumulated other comprehensive loss, net of tax		(59	.0)		(58	.4)

Total stockholders’ equity		1,196	.8		1,201	.6

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	4,456	.1	$	4,584	.7

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 June 30,						Six Months Ended June 30,
(In millions, except per share data)	2004			2003			2004			2003

OPERATING REVENUES
Electric Utility operating revenues	$	411	.5	$	357	.9	$	715	.8	$	690	.5
Natural Gas Pipeline operating revenues		743	.9		494	.7		1,481	.3		1,212	.2

Total operating revenues		1,155	.4		852	.6		2,197	.1		1,902	.7
COST OF GOODS SOLD
Electric Utility cost of goods sold		230	.9		175	.8		402	.3		379	.7
Natural Gas Pipeline cost of goods sold		688	.0		446	.2		1,371	.5		1,110	.6

Total cost of goods sold		918	.9		622	.0		1,773	.8		1,490	.3

Gross margin on revenues		236	.5		230	.6		423	.3		412	.4
Other operation and maintenance		93	.1		93	.1		184	.2		183	.4
Depreciation		44	.2		43	.0		90	.2		89	.6
Impairment of assets		-	--		1	.0		-	--		1	.0
Taxes other than income		17	.0		16	.9		35	.7		34	.1

OPERATING INCOME		82	.2		76	.6		113	.2		104	.3

OTHER INCOME (EXPENSE)
Other income		2	.9		0	.6		5	.7		6	.7
Other expense		(1	.5)		(0	.6)		(3	.0)		(3	.6)

Net other income		1	.4		-	--		2	.7		3	.1

INTEREST INCOME (EXPENSE)
Interest income		0	.5		0	.1		0	.9		0	.3
Interest on long-term debt		(18	.9)		(19	.2)		(37	.1)		(38	.2)
Interest on trust preferred securities		-	--		(4	.3)		-	--		(8	.6)
Interest expense - unconsolidated affiliate		(4	.3)		-	--		(8	.6)		-	--
Allowance for borrowed funds used during construction		0	.2		0	.1		0	.3		0	.4
Interest on short-term debt and other interest charges		(1	.0)		(1	.7)		(2	.1)		(3	.5)

Net interest expense		(23	.5)		(25	.0)		(46	.6)		(49	.6)

INCOME FROM CONTINUING OPERATIONS BEFORE
TAXES		60	.1		51	.6		69	.3		57	.8
INCOME TAX EXPENSE		21	.1		19	.4		20	.5		21	.3

INCOME FROM CONTINUING OPERATIONS BEFORE
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE		39	.0		32	.2		48	.8		36	.5
DISCONTINUED OPERATIONS (NOTE 5)
Income from discontinued operations		-	--		-	--		0	.7		2	.2
Income tax expense		-	--		-	--		0	.3		0	.9

Income from discontinued operations		-	--		-	--		0	.4		1	.3

INCOME BEFORE CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE		39	.0		32	.2		49	.2		37	.8
CUMULATIVE EFFECT ON PRIOR YEARS OF CHANGE
IN ACCOUNTING PRINCIPLE, net of tax of $3.7		-	--		-	--		-	--		(5	.9)

NET INCOME	$	39	.0	$	32	.2	$	49	.2	$	31	.9

BASIC AVERAGE COMMON SHARES OUTSTANDING		87	.6		79	.2		87	.6		78	.9
DILUTED AVERAGE COMMON SHARES OUTSTANDING		88	.2		79	.4		88	.1		79	.2
BASIC AND DILUTED EARNINGS (LOSS) PER AVERAGE
COMMON SHARE
Income from continuing operations	$	0.	44	$	0.	41	$	0.	55	$	0.	46
Income from discontinued operations, net of tax		-	--		-	--		0.	01		0.	01
Loss from cumulative effect of accounting change, net of tax		-	--		-	--		-	--		(0.	07)

NET INCOME	$	0.	44	$	0.	41	$	0.	56	$	0.	40

DIVIDENDS DECLARED PER SHARE	$	0.33	25	$	0.33	25	$	0.66	50	$	0.66	50

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

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

	Six Months Ended June 30,
(In millions)	2004			2003

CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	49	.2	$	31	.9
Adjustments to reconcile net income to net cash provided from
operating activities
Income from discontinued operations		(0	.4)		(1	.3)
Cumulative effect of change in accounting principle		-	--		5	.9
Depreciation		90	.2		89	.6
Impairment of assets		-	--		1	.0
Deferred income taxes and investment tax credits, net		(0	.5)		(3	.1)
Gain on sale of assets		(3	.1)		(5	.7)
Price risk management assets		(23	.7)		(39	.0)
Price risk management liabilities		33	.2		33	.2
Other assets		(35	.1)		18	.2
Other liabilities		8	.2		1	.8
Change in certain current assets and liabilities
Accounts receivable, net		(40	.1)		5	.5
Accrued unbilled revenues		(28	.2)		(36	.6)
Fuel, materials and supplies inventories		43	.7		(28	.3)
Gas imbalance asset		32	.9		(2	.3)
Fuel clause under recoveries		(5	.3)		(23	.6)
Other current assets		8	.0		5	.7
Accounts payable		63	.0		7	.8
Customers’ deposits		2	.4		1	.7
Accrued taxes		23	.2		23	.5
Accrued interest		-	--		(0	.5)
Gas imbalance liability		8	.2		4	.2
Fuel clause over recoveries		(32	.4)		-	--
Other current liabilities		(3	.6)		4	.7

Net Cash Provided from Operating Activities		189	.8		94	.3

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(122	.5)		(91	.8)
Proceeds from sale of assets		5	.5		9	.9
Other investing activities		0	.7		(0	.4)

Net Cash Used in Investing Activities		(116	.3)		(82	.3)

CASH FLOWS FROM FINANCING ACTIVITIES
Retirement of long-term debt		(19	.0)		(19	.0)
Decrease in short-term debt, net		(202	.5)		(17	.9)
Premium on issuance of common stock		4	.9		15	.4
Distribution to minority interest		-	--		(2	.5)
Dividends paid on common stock		(58	.2)		(47	.8)

Net Cash Used in Financing Activities		(274	.8)		(71	.8)

DISCONTINUED OPERATIONS
Net cash provided from (used in) operating activities		0	.4		(0	.6)
Net cash provided from investing activities		-	--		38	.5

Net Cash Provided from Discontinued Operations		0	.4		37	.9

NET DECREASE IN CASH AND CASH EQUIVALENTS		(200	.9)		(21	.9)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		245	.6		44	.4

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	44	.7	$	22	.5

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

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

1. Summary of Significant Accounting Policies

Organization

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

The Electric Utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through Oklahoma Gas and Electric Company (“OG&E”) and are subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“FERC”). OG&E 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. Enogex’s focus is to utilize its gathering, processing, transportation and storage capacity to execute physical, financial and service transactions to capture revenues across different commodities, locations or time periods. The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are located in the major gas producing basins of Oklahoma. Through a 75 percent interest in the NOARK Pipeline System Limited Partnership, Enogex also owns a controlling interest in and operates the Ozark Gas Transmission System (“Ozark”), a FERC regulated interstate pipeline that extends from southeast Oklahoma through Arkansas to southeast Missouri. Enogex sold its interests in certain gas gathering and processing assets in Texas in the first quarter of 2003, which is reported in the Condensed Consolidated Financial Statements as discontinued operations.

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

Basis of Presentation

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

In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of the Company at June 30, 2004 and December 31, 2003, the results of its operations for the three and six months ended June 30, 2004 and 2003, and the results of its cash flows for the six months ended June 30, 2004 and 2003, have been included and are of a normal recurring nature.

Due to seasonal fluctuations and other factors, the operating results for the three and six months ended June 30, 2004 are not necessarily indicative of the results that may be expected for the year ending December 31, 2004 or for any future period. The Condensed Consolidated Financial Statements and Notes thereto should be read in conjunction with the audited Consolidated Financial Statements and Notes thereto included in the Company’s Form 10-K for the year ended December 31, 2003.

Accounting Records

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

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

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

(In millions)	June 30, 2004			December 31, 2003
Regulatory Assets
Recoverable take or pay gas charges	$	32	.5	$	32	.5
Income taxes recoverable from customers, net		31	.2		31	.6
Unamortized loss on reacquired debt		21	.5		22	.1
Fuel clause under recoveries		9	.3		4	.0
PowerSmith capacity payments		6	.1		-	--
January 2002 ice storm		1	.8		3	.6
Miscellaneous		0	.9		0	.4

Total Regulatory Assets	$	103	.3	$	94	.2

Regulatory Liabilities
Accrued removal obligations, net	$	122	.5	$	116	.3
Fuel clause over recoveries		6	.4		32	.4
Estimated refund on FERC fuel		1	.0		1	.0

Total Regulatory Liabilities	$	129	.9	$	149	.7

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

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

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

PowerSmith Cogeneration Project, L.P. (“PowerSmith”) capacity payments relate to customer savings of approximately $1.0 million per month that began in January 2004 to reflect the expiration of the PowerSmith contract in August 2004. These customer savings relate to the period from January to August 2004. This regulatory asset will be recovered from customers from September to December 2004 pursuant to filed tariffs.

Accrued removal obligations represent asset retirement costs previously recovered from ratepayers for other than legal obligations. In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations,” the Company was required to reclassify its accrued removal obligations, which had previously been recorded as a liability in Accumulated Depreciation, to a regulatory liability.

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

Income Taxes

The Company files consolidated income tax returns. Income taxes are allocated to each affiliate based on its separate taxable income or loss. Federal investment tax credits on electric utility property have been deferred and are being amortized to income over the life of the related property. Amortization of the federal investment tax credits was approximately $1.3 million for each of the three months ended June 30, 2004 and 2003 and was approximately $2.6 million for each of the six months ended June 30, 2004 and 2003 and are recorded as income tax benefits in the Condensed Consolidated Statements of Income. During the three and six months ended June 30, 2004, respectively, the Company recorded Oklahoma state tax credits of approximately $0.5 million and $4.2 million which are recorded as income tax benefits 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.

Stock-Based Compensation

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

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure – an amendment of FASB Statement No. 123.” SFAS No. 148 amended the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The

following table reflects pro forma net income and income per average common share had the Company elected to adopt the fair value based method of SFAS No. 123:

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions, except per share data)	2004			2003			2004			2003
Net income, as reported	$	39	.0	$	32	.2	$	49	.2	$	31	.9
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	.3		0	.4		0	.7		0	.7

Pro forma net income	$	38	.7	$	31	.8	$	48	.5	$	31	.2

Income per average common share
Basic and diluted - as reported	$	0.4	4	$	0.4	1	$	0.5	6	$	0.4	0
Basic - pro forma	$	0.4	4	$	0.4	0	$	0.5	5	$	0.4	0
Diluted - pro forma	$	0.4	4	$	0.4	0	$	0.5	5	$	0.3	9

Reclassifications

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

2. Accounting Pronouncements

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

accounted for as a cumulative effect of a change in accounting principle during the first quarter of 2003, was primarily related to natural gas held in storage for trading purposes. This natural gas held in storage was sold during the first quarter of 2003 resulting in an increase in the gross margin on revenues (“gross margin”) in excess of the cumulative effect loss described above.

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 and six months ended June 30, 2004 and 2003, the Company’s use of non-trading price risk management instruments involved the use of commodity price and interest rate swap agreements. These agreements involve the exchange of fixed price or rate payments in exchange for floating price or rate payments over the life of the instrument without an exchange of the underlying principal amount.

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

the forecasted transaction, and, as a result, no ineffectiveness is expected. See Notes 4 and 11 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 EITF 02-3. 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 and six months ended June 30, 2004 and 2003, respectively, are as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2004			2003			2004			2003
Net income	$	39	.0	$	32	.2	$	49	.2	$	31	.9
Other comprehensive loss, net of tax:
Deferred hedging losses		(0	.2)		(0	.5)		(0	.2)		(0	.3)
Reversal of unrealized gains on available-for-sale securities		-	--		-	--		(0	.4)		-	--

Total comprehensive income	$	38	.8	$	31	.7	$	48	.6	$	31	.6

The components of accumulated other comprehensive loss at June 30, 2004 and December 31, 2003 are as follows:

(In millions)	June 30, 2004			December 31, 2003
Minimum pension liability adjustment, net of tax	$	(59	.7)	$	(59	.7)
Deferred hedging gains, net of tax		0	.7		0	.9
Unrealized gains on available-for-sale securities, net of tax		-	--		0	.4

Total accumulated other comprehensive loss	$	(59	.0)	$	(58	.4)

Accumulated other comprehensive loss at both June 30, 2004 and December 31, 2003 included approximately a $59.7 million after tax loss ($97.4 million pre-tax) related to a minimum pension liability adjustment based on a review of the funded status of the Company’s

pension plan by the Company’s actuarial consultants as of December 31, 2003. Any increases or decreases in the minimum pension liability will be reflected in Other Comprehensive Income or Loss in the fourth quarter.

During the second quarter of 2004, the Company entered into three separate interest rate swap agreements, effective April 16, 2004, April 21, 2004 and May 17, 2004, respectively, to hedge approximately $20.0 million, $30.0 million and $20.0 million, respectively, of future interest payments of long-term debt expected to be issued later this year related to the planned redemption of $200.0 million of 8.375 percent trust preferred securities of OGE Energy Capital Trust I, a wholly-owned financing trust of the Company. These interest rate swap agreements mature on October 15, 2014. The objective of these interest rate swaps was to protect against the volatility of interest rates affecting future interest payments. These interest rate swaps qualified as cash flow hedges under SFAS No. 133 and met all of the requirements for a determination that there was no ineffective portion as allowed by the hypothetical derivative method under SFAS No. 133.

At June 30, 2004, the fair values for these interest rate swaps was approximately $0.2 million and are classified as Current Assets – Price Risk Management in the Condensed Consolidated Balance Sheets. A corresponding net increase of approximately $0.2 million was reflected in Accumulated Other Comprehensive Income at June 30, 2004 as these cash flow hedges were effective at June 30, 2004.

During July 2004, the Company entered into an interest rate swap agreement, effective July 16, 2004, to hedge approximately $10.0 million of future interest payments of long-term debt expected to be issued later this year related to the planned redemption of $200.0 million of 8.375 percent trust preferred securities of OGE Energy Capital Trust I. This interest rate swap agreement matures on October 15, 2014. The objective of this interest rate swap was to protect against the volatility of interest rates affecting future interest payments. This interest rate swap qualified as a cash flow hedge under SFAS No. 133 and met all of the requirements for a determination that there was no ineffective portion as allowed by the hypothetical derivative method under SFAS No. 133.

5. Enogex – Discontinued Operations

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

The Condensed Consolidated Financial Statements of the Company reflect NuStar, which was part of the Natural Gas Pipeline segment, as discontinued operations. Accordingly, revenues, costs and expenses and cash flows of NuStar have been excluded from the respective captions in the Condensed Consolidated Financial Statements and have been reported as “Income

from Discontinued Operations” and “Net Cash Provided from Discontinued Operations.” There were no outstanding balances related to NuStar on the Condensed Consolidated Balance Sheets. Summarized financial information for the discontinued operations is as follows:

CONDENSED CONSOLIDATED STATEMENTS OF INCOME DATA

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)		2004		2003		2004			2003

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

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

6. Asset Disposals

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

OG&E sold land near its principal executive offices for approximately $0.9 million in the second quarter of 2004. OG&E recognized approximately a $0.3 million pre-tax gain related to the sale of this asset, which is recorded in Other Income in the Condensed Consolidated Statements of Income. This asset was part of the Electric Utility segment.

7. Impairment of Assets

During the fourth quarter of 2002, the Company recognized a pre-tax impairment loss of approximately $48.3 million in the Natural Gas Pipeline segment which related to Enogex natural gas processing and compression assets. In the fourth quarter of 2003, as a result of an ongoing initiative to improve asset utilization in the Natural Gas Pipeline segment, the Company concluded that certain idle Enogex natural gas compression assets may no longer be required to meet the Company’s future business needs. As a result, the Company recognized a pre-tax impairment loss of approximately $9.2 million related to these natural gas compression assets. The impairments resulted from plans to dispose of these assets at prices below the carrying amount. The fair value of these assets was determined based on third-party evaluations, prices for similar assets, historical data and projected cash flows. During the three months ended June 30, 2004, the Company sold certain of its compression and processing assets for approximately $1.9 million and recognized approximately a $1.0 million after tax gain related to the sale of these assets. During the six months ended June 30, 2004, the Company sold certain of its compression and processing assets for approximately $4.7 million and recognized approximately a $1.7 million after tax gain related to the sale of these assets. The carrying amount of the remaining assets held for sale was approximately $8.3 million and $11.9 million at June 30, 2004 and December 31, 2003, respectively. The Company continues to actively market these assets and plans to sell or otherwise dispose of these assets by the end of 2004.

As previously reported, the Company recognized an impairment loss related to certain idle Enogex natural gas compression assets in 2002. The Company has developed a plan relating to the disposition of those assets and during the third quarter of 2004, the Company entered into a joint venture arrangement with a third party and contributed some of its impaired compression assets (with a carrying amount of approximately $4.3 million) to the joint venture. The carrying amount of $4.3 million is part of the $8.3 million carrying amount of the remaining assets held for sale at June 30, 2004 discussed above. The near term objective of the joint venture is to derive value from the assets by renting the natural gas compressors, while the long term objective is to sell such assets or the joint venture. The Company has created a wholly-owned limited liability company to act as the participating entity in the joint venture. This limited liability company is expected to hold a majority ownership in the joint venture, although the actual ownership percentages may fluctuate based on the relative capital contributions of the Company and the third party member. The third party will act as the manager and maintain the daily operations of the joint venture. These assets were part of the Natural Gas Pipeline segment.

During the second quarter of 2003, the Company recognized a pre-tax impairment loss of $1.0 million in Other Operations related to the Company’s aircraft. The impairment resulted from plans to dispose of the aircraft at a price below the carrying amount. The fair value of the aircraft was determined based on a third-party evaluation. The closing on the sale was completed in August 2003 and the Company recognized approximately a $0.1 million pre-tax loss related to the sale of the aircraft in the third quarter of 2003. The aircraft was part of Other Operations.

8. Supplemental Cash Flow Information

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

	Six Months Ended June 30,
(In millions)		2004			2003

NON-CASH INVESTING AND FINANCING ACTIVITIES
Change in fair value of long-term debt due to interest rate swaps	$	(6	.0)	$	7	.2
Issuance of common stock		-	--		5	.7

9. Common Stock

For the three and six months ended June 30, 2004, respectively, there were 18,100 shares of new common stock and 257,224 shares of new common stock issued pursuant to the Company’s Stock Incentive Plan, which related to exercised stock options.

10. Earnings Per Share

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

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2004		2003		2004		2003
Average Common Shares Outstanding
Basic average common shares outstanding	87	.6	79	.2	87	.6	78	.9
Effect of dilutive securities:
Employee stock options and unvested stock grants	0	.3	0	.1	0	.2	0	.2
Contingently issuable shares (performance units)	0	.3	0	.1	0	.3	0	.1

Diluted average common shares outstanding	88	.2	79	.4	88	.1	79	.2

For the three and six months ended June 30, 2004, approximately 0.7 million shares each 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. For the three and six months ended June 30, 2003, respectively, approximately 1.9 million shares and 2.1 million shares related to outstanding employee stock options were not included in the calculation of diluted earnings per average common share because the effect of including those shares is anti-dilutive as the exercise price of the stock options exceeded the average common stock market price during the respective period.

11. Long-Term Debt

At June 30, 2004, the Company is in compliance with all of its debt agreements.

Long-Term Debt with Optional Redemption Provisions

OG&E’s 6.500 percent Senior Notes (“Senior Notes”) were repayable on July 15, 2004, at the option of the holders, at 100 percent of the principal amount, together with accrued and unpaid interest to July 15, 2004. Only holders who submitted requests for repayment between May 15, 2004 and June 15, 2004 were entitled to such repayments. OG&E and the Senior Note Trustee received no such requests for repayment of the Senior Notes.

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

Early Retirement of Long-Term Debt

In 1998, Enogex issued a note of approximately $5.7 million payable to an unaffiliated former partial interest owner of the NOARK Pipeline System Limited Partnership, a subsidiary of Enogex Arkansas Pipeline Corporation, which is a wholly-owned subsidiary of Enogex. The note had a maturity date of July 1, 2020 and an interest rate of 7.00 percent. Principal and interest payments of approximately $0.8 million were due annually beginning July 1, 2004. On July 1, 2004, Enogex made the initial $0.8 million payment. On July 14, 2004, Enogex made a payment of approximately $7.8 million to repay the outstanding note balance and satisfy its remaining obligations related to this note. Enogex expects to record a pre-tax gain of approximately $0.1 million in the third quarter of 2004 related to this transaction.

Interest Rate Swap Agreements

Fair Value Hedges

At June 30, 2004 and December 31, 2003, the Company had three outstanding interest rate swap agreements: (i) OG&E entered into an interest rate swap agreement, effective March 30, 2001, to convert $110.0 million of 7.30 percent fixed rate debt due October 15, 2025, to a variable rate based on the three month London InterBank Offering Rate (“LIBOR”) and (ii) Enogex entered into two separate interest rate swap agreements, effective July 15, 2002 and October 24, 2002, to convert $100.0 million of 8.125 percent fixed rate debt due January 15, 2010, to a variable rate based on the six month LIBOR 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.

At June 30, 2004 and December 31, 2003, the fair values pursuant to OG&E’s interest rate swap were approximately $2.7 million and $4.0 million, respectively, and are classified as Deferred Charges and Other Assets – Price Risk Management in the Condensed Consolidated Balance Sheets. A corresponding net increase of approximately $2.7 million and $4.0 million was reflected in Long-Term Debt at June 30, 2004 and December 31, 2003, respectively, as this fair value hedge was effective at June 30, 2004 and December 31, 2003.

At June 30, 2004, the fair values pursuant to Enogex’s interest rate swaps were approximately $1.3 million and are classified as Deferred Credits and Other Liabilities – Price Risk Management in the Condensed Consolidated Balance Sheets. A corresponding net decrease of approximately $1.3 million was reflected in Long-Term Debt at June 30, 2004 as these fair value hedges were effective at June 30, 2004. At December 31, 2003, the fair values pursuant to Enogex’s interest rate swaps were approximately $3.6 million and are classified as Deferred Charges and Other Assets – Price Risk Management in the Condensed Consolidated Balance Sheets. A corresponding net increase of approximately $3.6 million was reflected in Long-Term Debt at December 31, 2003 as these fair value hedges were effective at December 31, 2003.

Cash Flow Hedges

12. Short-Term Debt

The short-term debt balance was approximately $202.5 million at December 31, 2003 primarily due to the planned acquisition of the McClain Plant discussed in Note 16. There was no short-term debt outstanding at June 30, 2004. Due to a delay in the completion of the McClain Plant acquisition, the Company used short-term investments and proceeds received from the sale of natural gas inventory by Enogex during the six months ended June 30, 2004 to reduce the outstanding commercial paper balance.

The following table shows the Company’s lines of credit in place and available cash at June 30, 2004. Short-term borrowings are expected to consist of a combination of bank borrowings and commercial paper.

Lines of Credit and Available Cash (In millions)
Entity	Amount Available			Amount Outstanding			Maturity
OGE Energy Corp. (A)	$	15	.0	$	-	--	April 6, 2005
OG&E		100	.0		-	--	December 9, 2004
OGE Energy Corp. (A)		300	.0		-	--	December 9, 2004
		415	.0		-	--
Cash		44	.7		N	/A	N/A

Total	$	459	.7	$	-	--

(A) The lines of credit at OGE Energy Corp. are used to back up the Company’s commercial paper borrowings. There was no short-term debt outstanding at June 30, 2004. In April 2004, the Company renewed its $15.0 million credit facility, shown in the table above, which matures April 6, 2005. Also, in June 2004, OG&E extended the maturity date of its $100.0 million credit facility, shown in the table above, to December 9, 2004.

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

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

13. Retirement Plans and Postretirement Benefit Plans

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

A detail of the net periodic benefit cost related to the Company’s pension plan and postretirement benefit plans included in the Condensed Consolidated Financial Statements is as follows:

Net Periodic Benefit Cost


	Pension Plan
	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)		2004			2003			2004			2003

Service cost	$	4	.2	$	4	.0	$	8	.4	$	7	.6
Interest cost		7	.4		7	.5		14	.8		14	.6
Return on plan assets		(7	.9)		(5	.5)		(15	.8)		(12	.1)
Amortization of net loss		3	.0		4	.1		6	.0		6	.6
Amortization of unrecognized prior service cost		1	.6		1	.6		3	.2		2	.9

Net periodic benefit cost	$	8	.3	$	11	.7	$	16	.6	$	19	.6

	Postretirement Benefit Plans
	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)		2004			2003			2004			2003

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

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

Pension Plan Funding

The Company previously disclosed in its Form 10-K for the year ended December 31, 2003 that it expected to contribute approximately $56.0 million to its pension plan in 2004. The Company presently anticipates contributing an additional $13.0 million to its pension plan during 2004, for a total contribution of approximately $69.0 million in 2004. After the benefit liability was remeasured as of January 1, 2004, the Company decided to make the additional contribution to ensure the pension plan maintains an adequate funded status. The Company funded approximately $46.0 million to its pension plan during the second quarter of 2004 and also expects to make contributions in the third quarter of 2004. The expected contributions to the pension plan, anticipated to be in the form of cash, are discretionary contributions and are not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974.

Medicare Prescription Drug, Improvement and Modernization Act of 2003

On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Act”). The Act expanded Medicare to include,

for the first time, coverage for prescription drugs. Due to various uncertainties related to the Company’s response to this legislation in relation to its postretirement medical plan and the appropriate accounting methodology for this event, the Company elected to defer financial recognition of this legislation until the FASB issued final accounting guidance. This deferral election was permitted under FASB Staff Position No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” 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,” which supersedes FAS 106-1. FAS 106-2 provides guidance on the accounting for the effects of the Act for employers that sponsor postretirement heath care plans that provide prescription drug benefits. FAS 106-2 also requires those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Act. For employers who elected to defer financial recognition, FAS 106-2 provides two alternative methods of adoption which include a retroactive application to the date of the Act’s enactment or a prospective application as of the date of adoption. For employers who elected not to defer financial recognition, FAS 106-2 requires these employers to recognize a cumulative effect of a change in accounting principle in accordance with APB Opinion No. 20. Adoption of FAS 106-2 is required for financial statements issued for periods beginning after June 15, 2004. The Company will adopt this new standard effective July 1, 2004 with retroactive application to the date of the Act’s enactment. Management expects that the savings to the Company’s postretirement medical plan resulting from the Act will reduce the Company’s costs for its postretirement medical plan by approximately $2.5 million annually.

14. Report of Business Segments

The Company’s Electric Utility operations are conducted through OG&E, a regulated utility engaged in the generation, transmission, distribution and sale of electric energy. The Company’s Natural Gas Pipeline operations are conducted through Enogex. Enogex is engaged in the transportation and storage of natural gas, the gathering and processing of natural gas and the marketing of natural gas. For the three and six months ended June 30, 2003, Other Operations primarily includes unallocated corporate expenses, interest expense on the trust preferred securities and interest expense on commercial paper. As a result of the adoption of FASB Interpretation No. 46, “Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin No. 51,” on December 31, 2003, and the resulting deconsolidation of the trust preferred securities, Other Operations for the three and six months ended June 30, 2004 primarily includes unallocated corporate expenses, interest expense to unconsolidated affiliate and interest expense on commercial paper. Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations. The following tables are a summary of the results of the Company’s business segments for the three and six months ended June 30, 2004 and 2003.


Three Months Ended June 30, 2004	Electric Utility			Natural Gas Pipeline (A)			Other Operations			Intersegment			Total

(In millions)
Operating revenues	$	411	.5	$	775	.5	$	-	--	$	(31	.6)	$	1,155	.4
Fuel		162	.8		-	--		-	--		(12	.3)		150	.5
Purchased power		80	.4		-	--		-	--		-	--		80	.4
Gas and electricity purchased for resale		-	--		682	.7		-	--		(19	.3)		663	.4
Natural gas purchases - other		-	--		24	.6		-	--		-	--		24	.6

Cost of goods sold		243	.2		707	.3		-	--		(31	.6)		918	.9
Gross margin on revenues		168	.3		68	.2		-	--		-	--		236	.5

Other operation and maintenance		71	.5		25	.1		(3	.5)		-	--		93	.1
Depreciation		30	.3		11	.4		2	.5		-	--		44	.2
Taxes other than income		11	.8		4	.4		0	.8		-	--		17	.0

Operating income		54	.7		27	.3		0	.2		-	--		82	.2

Other income		0	.9		1	.8		0	.2		-	--		2	.9
Other expense		(0	.7)		-	--		(0	.8)		-	--		(1	.5)
Interest income		-	--		0	.4		0	.5		(0	.4)		0	.5
Interest expense		(9	.6)		(10	.1)		(4	.7)		0	.4		(24	.0)
Income tax expense (benefit)		14	.9		7	.9		(1	.7)		-	--		21	.1

Net income (loss)	$	30	.4	$	11	.5	$	(2	.9)	$	-	--	$	39	.0

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


Three Months Ended June 30, 2004	Transportation and Storage			Gathering and Processing			Marketing			Eliminations			Total
(In millions)
Operating revenues	$	86	.5	$	124	.6	$	687	.9	$	(123	.5)	$	775	.5
Operating income (loss)	$	17	.1	$	10	.3	$	(0	.1)	$	-	--	$	27	.3


Three Months Ended June 30, 2003	Electric Utility			Natural Gas Pipeline (A)			Other Operations			Intersegment			Total
(In millions)
Operating revenues	$	357	.9	$	513	.2	$	-	--	$	(18	.5)	$	852	.6
Fuel		125	.6		-	--		-	--		(11	.1)		114	.5
Purchased power		61	.3		-	--		-	--		-	--		61	.3
Gas and electricity purchased for resale		-	--		439	.3		-	--		(7	.4)		431	.9
Natural gas purchases - other		-	--		14	.3		-	--		-	--		14	.3

Cost of goods sold		186	.9		453	.6		-	--		(18	.5)		622	.0
Gross margin on revenues		171	.0		59	.6		-	--		-	--		230	.6

Other operation and maintenance		74	.9		22	.4		(4	.2)		-	--		93	.1
Depreciation		29	.1		11	.1		2	.8		-	--		43	.0
Impairment of assets		-	--		-	--		1	.0		-	--		1	.0
Taxes other than income		11	.7		4	.5		0	.7		-	--		16	.9

Operating income (loss)		55	.3		21	.6		(0	.3)		-	--		76	.6

Other income		0	.4		-	--		0	.2		-	--		0	.6
Other expense		(0	.6)		0	.2		(0	.2)		-	--		(0	.6)
Interest income		-	--		0	.4		5	.0		(5	.3)		0	.1
Interest expense		(10	.2)		(10	.1)		(10	.1)		5	.3		(25	.1)
Income tax expense (benefit)		17	.0		4	.4		(2	.0)		-	--		19	.4

Net income (loss)	$	27	.9	$	7	.7	$	(3	.4)	$	-	--	$	32	.2


Three Months Ended June 30, 2003	Transportation and Storage			Gathering and Processing			Marketing			Eliminations			Total
(In millions)
Operating revenues	$	53	.7	$	134	.1	$	431	.6	$	(106	.2)	$	513	.2
Operating income	$	19	.2	$	1	.7	$	0	.7	$	-	--	$	21	.6


Six Months Ended June 30, 2004	Electric Utility			Natural Gas Pipeline (A)			Other Operations			Intersegment			Total
(In millions)
Operating revenues	$	715	.8	$	1,524	.7	$	-	--	$	(43	.4)	$	2,197	.1
Fuel		270	.8		-	--		-	--		(24	.1)		246	.7
Purchased power		155	.6		-	--		-	--		-	--		155	.6
Gas and electricity purchased for resale		-	--		1,348	.8		-	--		(19	.3)		1,329	.5
Natural gas purchases - other		-	--		42	.0		-	--		-	--		42	.0

Cost of goods sold		426	.4		1,390	.8		-	--		(43	.4)		1,773	.8
Gross margin on revenues		289	.4		133	.9		-	--		-	--		423	.3

Other operation and maintenance		143	.0		48	.4		(7	.2)		-	--		184	.2
Depreciation		62	.2		22	.9		5	.1		-	--		90	.2
Taxes other than income		24	.5		9	.3		1	.9		-	--		35	.7

Operating income		59	.7		53	.3		0	.2		-	--		113	.2

Other income		1	.3		3	.2		1	.2		-	--		5	.7
Other expense		(1	.2)		(0	.3)		(1	.5)		-	--		(3	.0)
Interest income		0	.2		0	.5		0	.7		(0	.5)		0	.9
Interest expense		(19	.3)		(19	.4)		(9	.3)		0	.5		(47	.5)
Income tax expense (benefit)		10	.3		13	.4		(3	.2)		-	--		20	.5

Income (loss) from continuing operations		30	.4		23	.9		(5	.5)		-	--		48	.8

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

Net income (loss)	$	30	.4	$	24	.3	$	(5	.5)	$	-	--	$	49	.2

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


Six Months Ended June 30, 2004	Transportation and Storage			Gathering and Processing			Marketing			Eliminations			Total
(In millions)
Operating revenues	$	170	.1	$	257	.9	$	1,355	.1	$	(258	.4)	$	1,524	.7
Operating income (loss)	$	31	.6	$	22	.5	$	(0	.8)	$	-	--	$	53	.3


Six Months Ended June 30, 2003	Electric Utility			Natural Gas Pipeline (A)			Other Operations			Intersegment			Total
(In millions)
Operating revenues	$	690	.5	$	1,252	.8	$	-	--	$	(40	.6)	$	1,902	.7
Fuel		266	.9		-	--		-	--		(21	.2)		245	.7
Purchased power		134	.0		-	--		-	--		-	--		134	.0
Gas and electricity purchased for resale		-	--		1,096	.2		-	--		(19	.4)		1,076	.8
Natural gas purchases - other		-	--		33	.8		-	--		-	--		33	.8

Cost of goods sold		400	.9		1,130	.0		-	--		(40	.6)		1,490	.3
Gross margin on revenues		289	.6		122	.8		-	--		-	--		412	.4

Other operation and maintenance		146	.8		44	.8		(8	.2)		-	--		183	.4
Depreciation		61	.7		22	.3		5	.6		-	--		89	.6
Impairment of assets		-	--		-	--		1	.0		-	--		1	.0
Taxes other than income		23	.7		8	.8		1	.6		-	--		34	.1

Operating income		57	.4		46	.9		-	--		-	--		104	.3

Other income		0	.7		5	.8		0	.2		-	--		6	.7
Other expense		(1	.4)		(1	.5)		(0	.7)		-	--		(3	.6)
Interest income		-	--		0	.6		9	.8		(10	.1)		0	.3
Interest expense		(20	.0)		(20	.3)		(19	.7)		10	.1		(49	.9)
Income tax expense (benefit)		12	.1		13	.7		(4	.5)		-	--		21	.3

Income (loss) from continuing operations		24	.6		17	.8		(5	.9)		-	--		36	.5

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

Income (loss) before cumulative effect of change in accounting principle		24	.6		19	.1		(5	.9)		-	--		37	.8
Cumulative effect on prior years of change in accounting principle, net of tax		-	--		(5	.9)		-	--		-	--		(5	.9)

Net income (loss)	$	24	.6	$	13	.2	$	(5	.9)	$	-	--	$	31	.9


Six Months Ended June 30, 2003	Transportation and Storage			Gathering and Processing			Marketing			Eliminations			Total
(In millions)
Operating revenues	$	122	.7	$	275	.6	$	1,078	.2	$	(223	.7)	$	1,252	.8
Operating income	$	27	.9	$	8	.3	$	10	.7	$	-	--	$	46	.9

15. Commitments and Contingencies

Except as set forth below and in Note 16, the circumstances set forth in Note 17 to the Company’s Consolidated Financial Statements included in the Company’s Form 10-K for the year ended December 31, 2003 and in Note 15 to the Company’s Condensed Consolidated Financial Statements included in the Company’s Form 10-Q for the quarter ended March 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, 2003, Enogex, Central Oklahoma Oil and Gas Corp. and Natural Gas Storage Corporation have been involved in legal proceedings relating to a gas storage agreement and associated agreements. The parties participated in the arbitration in May 2004 and the arbitration panel rendered a decision in the Company’s favor for approximately $5.0 million on July 15, 2004. The Company plans to institute proceedings with the District Court of Oklahoma County to have the arbitration award confirmed and entered as a judgment of the Court. For additional information regarding this dispute, see Note 17 of Notes to Consolidated Financial Statements in the Company’s Form 10-K for the year ended December 31, 2003.

Farmland Industries

As earlier reported, Farmland Industries, Inc. (“Farmland”) voluntarily filed for Chapter 11 bankruptcy protection from creditors on May 31, 2002. Enogex filed its proof of claim on January 7, 2003 for approximately $5.4 million. In April 2003, Enogex negotiated a settlement and received approximately $1.9 million in May 2003. As a general unsecured creditor of Farmland and pursuant to the terms of the settlement agreement referenced above, Enogex is entitled to an additional payment of approximately $0.8 million.

Enogex received a letter from Farmland dated May 17, 2004, wherein Farmland sought the refund and return of payments made by Farmland to Enogex during the 90 days preceding Farmland’s bankruptcy filing, totaling approximately $4.7 million. Enogex responded to Farmland’s letter on June 17, 2004, and on July 19, 2004, Farmland filed a dismissal of its preference claim against Enogex. On July 8, 2004, Enogex received a distribution check from Farmland for approximately $0.5 million. The remainder of the settlement amount (approximately $0.3 million) is expected to be paid in the near future.

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 Condensed Consolidated Financial Statements. Management, after consultation with legal counsel, does not anticipate that liabilities arising out of currently pending or threatened lawsuits, claims and contingencies will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows. This assessment of currently pending or threatened lawsuits is subject to change.

16. Rate Matters and Regulation

OG&E’s retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by OG&E is also regulated by the OCC and the APSC. OG&E’s wholesale electric tariffs, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the Department of Energy has jurisdiction over some of OG&E’s facilities and operations.

Recent Regulatory Matters

2002 Settlement Agreement

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

OCC Order Confirming Savings

520 MW NRG McClain Station (the “McClain Plant”), but due to a delay at the FERC, the acquisition was not completed by December 31, 2003. In the interim, OG&E entered into a power purchase agreement with the McClain Plant that delivered the savings guaranteed to OG&E’s customers. OG&E requested that the OCC confirm that the steps it has taken, including the power purchase agreement, were satisfying the customer savings obligation under the Settlement Agreement and that OG&E would not be required to begin crediting its customers. On April 28, 2004, the OCC issued an order confirming that OG&E was delivering savings to its customers as required under the Settlement Agreement. The order removed any uncertainty over whether OG&E had to reduce its rates, effective January 1, 2004, while it awaited action by the FERC on its application to purchase the McClain Plant. A party to the OCC proceeding has appealed the OCC’s order to the Oklahoma Supreme Court. OG&E currently believes that the appeal is without merit.

Recent Acquisition of Power Plant

As part of the 2002 Settlement Agreement with the OCC, OG&E undertook to acquire New Generation of not less than 400 MWs. The acquisition of a 77 percent interest in the McClain Plant on July 9, 2004, as discussed below in more detail, constitutes an acquisition of such New Generation. OG&E expects this New Generation, 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. These savings will be derived from: (i) the avoidance of purchase power contracts otherwise needed; (ii) replacing an above market cogeneration contract with PowerSmith when it can be terminated at the end of August 2004 with a more economic contract with PowerSmith; and (iii) fuel savings associated with operating efficiencies of the new plant. These savings, while providing real savings to Oklahoma customers, are not expected to affect OG&E’s profitability because its rates are not expected to be reduced to accomplish these savings. 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, which shall be no later than December 31, 2006.

On August 18, 2003, OG&E signed an asset purchase agreement to acquire NRG McClain LLC’s 77 percent interest in the McClain Plant. The McClain Plant includes natural gas-fired combined cycle combustion turbine units and is located near Newcastle, Oklahoma in McClain County, Oklahoma. The McClain Plant began operating in 2001. The owner of the remaining 23 percent in the McClain Plant is the Oklahoma Municipal Power Authority (“OMPA”).

OG&E completed the acquisition of the McClain Plant on July 9, 2004. The purchase price for the interest in the McClain Plant was approximately $160.0 million. The closing was subject to customary conditions including receipt of certain regulatory approvals. Because NRG McClain LLC had filed for bankruptcy protection, the acquisition was subject to approval by the bankruptcy court. As part of the bankruptcy approval process, NRG McClain LLC’s interest in the plant was subject to an auction process and on October 28, 2003, the bankruptcy court approved the sale of NRG McClain LLC’s interest in the plant to OG&E.

The final approval OG&E had been waiting for was the 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 OG&E filed in a proceeding on March 8, 2004. Under the offer of settlement, 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, 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. Requests for rehearing of the FERC’s July 2, 2004 order were due on or before August 2, 2004. One such rehearing request was filed. The outcome of that request for rehearing cannot be determined at this time.

With the acquisition complete, OG&E will operate the plant in accordance with a joint ownership and operating agreement with the OMPA. Under this agreement, OG&E will operate the facility, and OG&E and the OMPA will be entitled to the net available output of the plant based on their respective ownership percentages. All fixed and variable costs, except fuel and gas transportation costs, will be shared in proportion to the respective ownership interests. Fuel and gas transportation costs will be paid in accordance with each individual owner’s respective transportation contract and consumption. OG&E expects to utilize its portion of the output, 400 MWs, to serve its native load. As a result, OG&E expects to file with the OCC a request to increase its rates to its Oklahoma customers to recover, among other things, its investment in, and the operating expenses of, the McClain Plant no later than 12 months following the acquisition and initial operation of New Generation. The timing of such request is uncertain. 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 acquisition, 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 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 funded the McClain Plant acquisition with short-term borrowings from the Company. OG&E expects to issue long-term debt to permanently finance the McClain Plant acquisition. Also, the Company expects to make a capital contribution to OG&E of approximately $153.0 million in August.

FERC Section 311 Rate Case

In December 2001, Enogex made its filing at the FERC under Section 311 of the Natural Gas Policy Act to establish rates and a default processing fee and to address various other issues for the combined Enogex and Transok L.L.C. pipeline systems. In May 2003, the FERC accepted the stipulation and settlement agreement and entered an order modifying Enogex’s Statement of Operating Conditions (“SOC”). The settlement included a fee to be assessed under certain market conditions to process customer gas gathered behind processing plants so that it meets the heating value standards of natural gas transmission pipelines (“default processing fee”). This default processing fee, which reduces Enogex’s exposure to keep whole processing

arrangements, is implemented in the event the natural gas liquids revenue less the associated fuel and shrinkage costs is negative. The settlement also approved a monthly low flow meter charge of $200 (offset in any month by the transportation revenues generated by gas through the meter). Pursuant to Enogex’s SOC, if Enogex’s annual processing gross margin exceeds a specified threshold, Enogex is required to record a default processing fee refund obligation in an amount equal to the lesser of the default processing fees or the amount of the processing margin in excess of the specified threshold.

During the third and fourth quarters of 2003, the Company established approximately a $4.9 million reserve to cover such refund obligations. During April 2004, the Company refunded its default processing fee refund obligation under the SOC to the applicable customers. There were no default processing fees billed to customers for the three and six months ended June 30, 2004. For the three and six months ended June 30, 2003, the Company billed default processing fees of approximately $6.6 million and $8.4 million, respectively. Based on the forecasted processing gross margin for 2004, any default processing fees charged to customers will be recorded as deferred revenue until it becomes probable that the 2004 gross margin threshold in the SOC will not be exceeded. The accounting for default processing fees is not expected to impact full-year earnings, but could affect the timing of those earnings. Also, during the three months ended June 30, 2004 and 2003, respectively, the Company recognized revenue of approximately $0.1 million and $0.3 million of low flow meter charges. During the six months ended June 30, 2004 and 2003, respectively, the Company recognized revenue of approximately $0.3 million and $0.5 million of low flow meter charges.

Pending Regulatory Matters

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

Contract with PowerSmith

PowerSmith has filed an application with the OCC seeking to compel OG&E to continue purchasing power from PowerSmith’s qualified cogeneration facility under the Public Utility Regulatory Policy Act of 1978 at a price that would include an avoided capacity charge equal to the lesser of (i) the rate currently specified in the power purchase agreement between OG&E and PowerSmith or (ii) the avoided cost of the McClain Plant. On June 7, 2004, OG&E and PowerSmith signed a 15-year power sales agreement under which OG&E will contract to purchase electric power from PowerSmith. The terms of the agreement are subject to approval by the OCC. A condition to the power sales agreement becoming effective is PowerSmith completing a long-term steam sales agreement with Dayton Tire, which PowerSmith appears to be in the process of doing. A hearing on OG&E and PowerSmith’s request for OCC approval of the contract was initially scheduled to begin on July 8 before an administrative law judge but has been delayed until August 3. The parties have agreed that the August 3 hearing on the contract

will dispose of the application filed by PowerSmith that is described above. OG&E’s ability to meet its guarantee of customer savings of at least $75 million over three years is not expected to be materially affected by this new agreement to purchase electric power from PowerSmith.

Gas Transportation and Storage Agreement

As part of the Settlement Agreement, OG&E also agreed to consider competitive bidding for gas transportation service to its natural gas-fired generation facilities pursuant to the terms set forth in the Settlement Agreement. The prescribed bidding process detailed in the Settlement Agreement provided that each generation facility bid separately for the services required. OG&E believes that in order for it to achieve maximum coal generation, which delivers the lowest cost energy to its customers, and 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 satisfy the daily swings in customer demand placed on OG&E’s system and still permit natural gas units to not impede coal energy production. OG&E also believes that gas storage is an integral part of providing gas supply to OG&E’s generation facilities. Accordingly, OG&E evaluated its competitive bid options in light of these circumstances. OG&E’s evaluation clearly demonstrates that the Enogex integrated gas system provides superior 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, 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 at an annual cost of approximately $46.8 million. During the three months ended June 30, 2004 and 2003, OG&E paid Enogex approximately $12.3 million and $11.2 million, respectively, for gas transportation and storage services. During the six months ended June 30, 2004 and 2003, OG&E paid Enogex approximately $24.1 million and $21.2 million, respectively, for gas transportation and storage services. Based upon requests for information from intervenors, OG&E has requested from Enogex and Enogex retained a “cost of service” consultant to assist in the preparation of testimony related to this case. On January 30, 2004, the OCC issued a procedural schedule for this case. On March 31, 2004, OG&E filed testimony and exhibits with the OCC, which completes the initial documentation required to be filed in this case. 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 requested, which results in no refund, and also recommends OG&E to 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 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 $30 million, respectively, with the difference between what OG&E has been collecting through its fuel adjustment clause and these recommended amounts being refunded to customers. OG&E expects to file rebuttal testimony in August 2004 in this case. Hearings in this case currently are scheduled for September 16, 17 and 20, 2004 and an OCC order in the case is expected by the end of 2004. OG&E believes the amount currently

paid to Enogex for integrated, firm no-notice load following transportation and storage services is fair, just and reasonable. If any amounts paid by OG&E are found not to be recoverable, OG&E believes such amount would not be material.

Security Enhancements

On April 8, 2002, OG&E filed a joint application with the OCC requesting approval for security investments and a rider to recover these costs from the ratepayers. On August 14, 2002, OG&E filed testimony with the OCC outlining proposed expenditures and related actions for security enhancement and a proposed recovery rider. Attempting to make security investments at the proper level, OG&E has developed a set of guidelines intended to minimize long-term or widespread outages, minimize the impact on critical national defense and related customers, maximize the ability to respond to and recover from an attack, minimize the financial impact on OG&E that might be caused by an attack and accomplish these efforts with minimal impact on ratepayers. The OCC Staff retained a security expert to review the report filed by OG&E. All responsive testimony in this case is required to be filed by August 13, 2004 and OG&E may file rebuttal testimony in September 2004 in this case if necessary. Hearings in this case currently are scheduled for November 9-11, 2004 and an OCC order in the case is expected in early 2005.

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

FERC Standards of Conduct

On November 25, 2003, the FERC issued new rules regulating the relationships between electric and natural gas transmission providers, as defined in the rules, and those entities’ merchant personnel and energy affiliates. The new rules will replace the existing rules governing these relationships. The new rules expand the definition of “affiliate” and further limit communications between transmission providers and those entities’ merchant personnel and energy affiliates, and, as the new rules continue to evolve, could materially increase the operating costs of market participants, including OG&E and Enogex.

In February 2004, OG&E and Enogex submitted plans and schedules to the FERC which detail the necessary actions to be in compliance with these new rules and expected that their initial costs to comply with the final rules would not exceed $1.6 million in 2004. On April 16, 2004, the FERC issued an order on rehearing in which the FERC largely rejected requests to revise its November 25 final rule. However, the FERC did extend the compliance date until September 1, 2004 and did clarify certain aspects of the rule. Based upon the progress made to date, OG&E and Enogex now anticipate that the initial costs to comply with the final rules will not exceed $1.0 million in 2004.

Market-Based Rate Authority

On April 14, 2004, the FERC issued (1) interim requirements for FERC jurisdictional electric utilities who have been granted authority to make wholesale sales at market-based rates, and (2) an order initiating a new rulemaking on future market-based rates authorizations. The interim method for analyzing generation market power requires two assessments - whether the utility is a pivotal supplier based on a control area’s annual peak demand and whether the utility exceeds certain market share thresholds on a seasonal basis. If an applicant is determined to have generation market power, the applicant must propose a market power mitigation plan. The new interim assessment methods are applicable to all pending initial market-based rate applications and triennial reviews pending the rulemaking described below. The triennial reviews of OG&E and OERI are currently pending before the FERC. In the rulemaking proceeding, the FERC is seeking comments on the adequacy of the FERC’s current analysis of market-based rate filings, including the adequacy of the new “interim” assessment of generation market power. The Company is reviewing the new requirements to determine what, if any, impact the new requirements will have on the wholesale market-based rate authority of OG&E and OERI. The Company must submit a compliance filing to the FERC by February 7, 2005 which shows the impact of the new requirements on OG&E and OERI.

Department of Energy Blackout Report

On April 6, 2004, the U.S. Department of Energy issued its final report regarding the August 14, 2003 electric blackout in the eastern United States, which did not have an adverse affect on OG&E’s electric system. The report recommends a number of specific changes to current statutes, rules or practices in order to improve the reliability of the infrastructure used to transmit electric power. The recommendations include the establishment of mandatory reliability standards and financial penalties for noncompliance. On April 14, 2004, the FERC issued a policy statement requiring electric utilities, including OG&E, to submit a report on vegetation management practices and indicating the FERC’s intent to make North American Electric Reliability Council reliability standards mandatory. On June 17, 2004, OG&E filed its report on vegetation management practices with the FERC. Implementation of the blackout report recommendations and the FERC policy statement could increase future transmission costs, but the extent of the increased costs is not known at this time.

Redbud Tariff Filing

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

imposition of such a rate is inconsistent with Redbud’s status as an exempt wholesale generator. On May 4, 2004, the FERC issued an order rejecting Redbud’s proposed rate schedule. Redbud has since asked the FERC to rehear and reverse its May 4 order rejecting Redbud’s filing. At this time, OG&E does not know when the FERC will rule on Redbud’s request for rehearing.

State Legislative Initiatives

Oklahoma

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

In the 2004 legislative session, legislation was enacted requiring a study to determine the feasibility of providing investor-owned utilities an incentive to enter into purchase power agreements in Oklahoma by allowing the utilities to earn a return on purchased power. This study is scheduled to begin in the third quarter of 2004 and the study committee is required to file a final report with its findings in January 2005.

Arkansas

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

In the 2003 legislative session, legislation was enacted requiring a study relating to the restructuring of the electric utility industry at the industrial level to provide customer choice of electricity providers for large customers. This study is currently underway and the APSC is required to file a final report with its findings no later than September 30, 2004 to the General Assembly of Arkansas.

17. Fair Value of Financial Instruments

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

	June 30, 2004						December 31, 2003
(In millions)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Price Risk Management Assets
Energy Trading Contracts	$	91	.1	$	91	.1	$	67	.2	$	67	.2
Interest Rate Swaps		2	.7		2	.7		7	.6		7	.6
Price Risk Management Liabilities
Energy Trading Contracts	$	85	.4	$	85	.4	$	51	.4	$	51	.4
Interest Rate Swaps		1	.3		1	.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.

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

Forward-Looking Statements

Except for the historical statements contained herein, the matters discussed in the following discussion and analysis, including the discussion in “Outlook”, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate”, “believe”, “estimate”, “expect”, “intend”, “objective”, “plan”, “possible”, “potential” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit, actions of 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; state and federal legislative initiatives and regulatory decisions; changes in accounting standards, rules or guidelines; creditworthiness of suppliers, customers, and other contractual parties; 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, 2003.

Overview

General

The following discussion and analysis presents factors which affected the Company’s consolidated results of operations for the three and six months ended June 30, 2004 as compared to the same period in 2003 and the Company’s consolidated financial position at June 30, 2004. The following information should be read in conjunction with the Condensed Consolidated Financial Statements and Notes thereto and the Company’s Form 10-K for the year ended December 31, 2003. Known trends and contingencies of a material nature are discussed to the extent considered relevant.

In the first quarter of 2003, Enogex sold its interests in certain gas gathering and processing assets that were owned by Enogex through its interest in the NuStar Joint Venture (“NuStar”). As required by accounting principles generally accepted in the United States, these dispositions have been reported as discontinued operations for the three and six months ended June 30, 2004 and 2003 in the Condensed Consolidated Financial Statements.

Operating Results

The Company reported net income of approximately $39.0 million, or $0.44 per share, as compared to approximately $32.2 million, or $0.41 per share, for the three months ended June 30, 2004 and 2003, respectively. The Company reported net income of approximately $49.2 million, or $0.56 per share, as compared to approximately $31.9 million, or $0.40 per share, for the six months ended June 30, 2004 and 2003, respectively. The increase in net income during the three months ended June 30, 2004 as compared to the same period in 2003 was primarily due to higher gross margin on revenues (“gross margin”) in Enogex’s gathering and processing business and Enogex’s marketing business, lower interest expenses at the holding company and lower income tax expense at OG&E. These increases to net income were partially offset by a lower gross margin in Enogex’s transportation and storage business and higher operating expenses and income tax expense at Enogex. Also affecting earnings per share for the three months ended June 30, 2004 was a higher amount of common stock outstanding from the Company’s equity issuance in August 2003 and the issuance of common stock in 2003 pursuant to the Company’s Automatic Dividend Reinvestment and Stock Purchase Plan (“DRIP”). The increase in net income during the six months ended June 30, 2004 as compared to the same period in 2003 was primarily due to higher gross margins in Enogex’s gathering and processing business and Enogex’s transportation and storage business, lower interest expenses at the holding company and lower operating expenses and income tax expense at OG&E. Also contributing to

the increase in net income was a loss recorded during the first quarter of 2003 related to a cumulative effect of a change in accounting principle. These increases to net income were partially offset by a lower gross margin in Enogex’s marketing business and higher operating expenses at Enogex. The Company’s results of operations for the six months ended June 30, 2004 and 2003, respectively, include income of approximately $0.4 million, or $0.01 per share, and $1.3 million, or $0.01 per share, from the discontinued operations discussed above. See “Results of Operations – Enogex – Discontinued Operations” below for a further discussion. Also affecting earnings per share for the six months ended June 30, 2004 was a higher amount of common stock outstanding from the Company’s equity issuance in August 2003 and the issuance of common stock in 2003 pursuant to the Company’s DRIP.

OG&E reported net income of approximately $30.4 million, or $0.34 per share of the Company’s common stock, as compared to approximately $27.9 million, or $0.35 per share, for the three months ended June 30, 2004 and 2003, respectively. OG&E reported net income of approximately $30.4 million, or $0.35 per share, as compared to approximately $24.6 million, or $0.31 per share, for the six months ended June 30, 2004 and 2003, respectively. The improvement in earnings at OG&E during the three months ended June 30, 2004 as compared to the same period in 2003 was primarily attributable to lower operating expenses and income tax expense partially offset by lower gross margins from the timing of fuel recoveries and lower sales to wholesale customers partially offset by warmer than normal weather and growth in OG&E’s service territory. The decrease in earnings per share for the three months ended June 30, 2004 as compared to the same period in 2003 reflects a higher amount of common stock outstanding from the Company’s equity issuance in August 2003 and the issuance of common stock in 2003 pursuant to the Company’s DRIP. The improvement in earnings at OG&E during the six months ended June 30, 2004 as compared to the same period in 2003 was primarily attributable to lower operating expenses and income tax expense partially offset by lower gross margins from the timing of fuel recoveries, lower sales to wholesale customers and milder than normal weather partially offset by growth in OG&E’s service territory.

Enogex’s operations, including discontinued operations, reported net income of approximately $11.5 million, or $0.13 per share of the Company’s common stock, as compared to approximately $7.7 million, or $0.10 per share, for the three months ended June 30, 2004 and 2003, respectively. Enogex’s operations, including discontinued operations, reported net income of approximately $24.3 million, or $0.28 per share, as compared to approximately $13.2 million, or $0.17 per share, for the six months ended June 30, 2004 and 2003, respectively. The improvement in earnings at Enogex during the three months ended June 30, 2004 as compared to the same period in 2003 was primarily attributable to higher gross margins in Enogex’s gathering and processing business and Enogex’s marketing business from, among other things, revenue improvements generated from the negotiation of both new contracts and replacement contracts at better terms that resulted in increases in gathering fees and reductions in the purchase price of gas and an overall favorable business environment. These increases were partially offset by a lower gross margin in Enogex’s transportation and storage business and higher operating expenses and income tax expense. The improvement in earnings at Enogex during the six months ended June 30, 2004 as compared to the same period in 2003 was primarily attributable to higher gross margins in Enogex’s gathering and processing business and Enogex’s transportation and storage business from, among other things, increased levels of transportation

and storage revenues, revenue improvements generated from the negotiation of both new contracts and replacement contracts at better terms that resulted in increases in gathering fees and reductions in the purchase price of gas and an overall favorable business environment. Also contributing to the increase in net income was a loss recorded during the first quarter of 2003 related to a cumulative effect of a change in accounting principle. These increases were partially offset by a lower gross margin in Enogex’s marketing business and higher operating expenses.

As stated above, Enogex’s interest in NuStar has been reported as discontinued operations for the three and six months ended June 30, 2004 and 2003 in the Condensed Consolidated Financial Statements as these assets have been sold. There were no results of operations from discontinued operations for the three months ended June 30, 2004 and 2003. The Company’s results of operations for the six months ended June 30, 2004 and 2003, respectively, include income of approximately $0.4 million, or $0.01 per share, and $1.3 million, or $0.01 per share, from the discontinued operations discussed above. This decrease was attributable to the sale of NuStar in the first quarter of 2003, partially offset by funds received in the first quarter of 2004 related to an overpayment of natural gas purchases in a prior period. See “Results of Operations – Enogex – Discontinued Operations” below for a further discussion.

During the three months ended June 30, 2004, Enogex had approximately $2.6 million in net income relating to various non-recurring items. Authorized recovery of previously under recovered fuel provided a positive earnings contribution of approximately $1.6 million and Enogex had a gain on the sale of compression and processing assets of approximately $1.0 million. During the three months ended June 30, 2003, Enogex had approximately $3.2 million in net income from the authorized recovery of previously under recovered fuel.

During the six months ended June 30, 2004, Enogex had approximately $6.6 million in net income relating to various non-recurring items. Authorized recovery of previously under recovered fuel provided a positive earnings contribution of approximately $2.8 million and the Oklahoma investment tax credit provided a positive earnings contribution of approximately $2.0 million. In addition, Enogex had a gain on the sale of compression and processing assets of approximately $1.7 million and income from discontinued operations contributed approximately $0.4 million. These increases were partially offset by approximately $0.3 million due to other miscellaneous items. During the six months ended June 30, 2003, Enogex had approximately $4.6 million in net income relating to various non-recurring items. The gain on the sale of assets provided a positive earnings contribution of approximately $2.7 million and authorized recovery of previously under recovered fuel provided a positive earnings contribution of approximately $2.3 million. Income from discontinued operations provided a positive earnings contribution of approximately $1.3 million. These increases were partially offset by an income tax adjustment of approximately $1.7 million.

The results of the holding company reflect a loss of approximately $0.03 per share and $0.07 per share for the three and six months ended June 30, 2004, respectively, as compared to losses of approximately $0.04 per share and $0.08 per share for the three and six months ended June 30, 2003, respectively, primarily due to lower interest expenses.

2002 Settlement Agreement

On October 11, 2002, OG&E, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to settle OG&E’s rate case. The administrative law judge subsequently recommended approval of the agreed-upon settlement (the “Settlement Agreement”) and on November 22, 2002, the OCC signed a rate order containing the provisions of the Settlement Agreement. The Settlement Agreement provides for, among other items: (i) a $25.0 million annual reduction in the electric rates of OG&E’s Oklahoma customers which went into effect January 6, 2003; (ii) recovery by OG&E, through rate base, of the capital expenditures associated with the January 2002 ice storm; (iii) OG&E to acquire electric generation of not less than 400 megawatts (“MW”) (“New Generation”) to be integrated into OG&E’s generation system; and (iv) recovery by OG&E, over three years, of the $5.4 million in deferred operating costs, associated with the January 2002 ice storm, through OG&E’s rider for sales to other utilities and power marketers (“off-system sales”). Previously, OG&E had a 50/50 sharing mechanism in Oklahoma for any off-system sales. The Settlement Agreement provided that the first $1.8 million in annual net profits from OG&E’s off-system sales will go to OG&E, the next $3.6 million in annual net profits from off-system sales will go to OG&E’s Oklahoma customers, and any net profits of off-system sales in excess of these amounts will be credited in each sales year with 80 percent to OG&E’s Oklahoma customers and the remaining 20 percent to OG&E. If any of the $5.4 million is not recovered at the end of the three years, the OCC will authorize the recovery of any remaining costs. During the first quarter of 2004, OG&E received approximately $1.8 million in annual net profits from OG&E’s off-system sales in accordance with the Settlement Agreement.

OCC Order Confirming Savings

The Settlement Agreement requires that, if OG&E did not acquire the New Generation by December 31, 2003, OG&E must credit $25.0 million annually (at a rate of 1/12 of $25.0 million per month for each month that the New Generation is not in place) to its Oklahoma customers beginning January 1, 2004 and continuing through December 31, 2006. As discussed in more detail below, in August 2003 OG&E signed an agreement to purchase a 77 percent interest in the 520 MW NRG McClain Station (the “McClain Plant”), but due to a delay at the FERC, the acquisition was not completed by December 31, 2003. In the interim, OG&E entered into a power purchase agreement with the McClain Plant that delivered the savings guaranteed to OG&E’s customers. OG&E requested that the OCC confirm that the steps it has taken, including the power purchase agreement, were satisfying the customer savings obligation under the Settlement Agreement and that OG&E would not be required to begin crediting its customers. On April 28, 2004, the OCC issued an order confirming that OG&E was delivering savings to its customers as required under the Settlement Agreement. The order removed any uncertainty over whether OG&E had to reduce its rates, effective January 1, 2004, while it awaited action by the FERC on its application to purchase the McClain Plant. A party to the OCC proceeding has appealed the OCC’s order to the Oklahoma Supreme Court. OG&E currently believes that the appeal is without merit.

Recent Acquisition of Power Plant

Outlook

The Company currently expects that consolidated earnings in 2004 will be between $1.60 and $1.70 per share, which includes the positive impact of non-recurring items during the first six months of 2004, normal weather and no change in OG&E’s electric rates. The 2004 outlook is based on continued improvement in financial performance at OG&E and Enogex, with net income of between $120 million and $124 million at OG&E and net income of between $34 million and $38 million at Enogex. The 2004 outlook also is based on a projected loss for the holding company of approximately $13 million to $14 million, and assumes approximately 88.4 million average diluted shares outstanding for 2004.

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.

Results of Operations

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions, except per share data)	2004			2003			2004			2003
Operating income	$	82	.2	$	76	.6	$	113	.2	$	104	.3
Net income	$	39	.0	$	32	.2	$	49	.2	$	31	.9
Basic average common shares outstanding		87	.6		79	.2		87	.6		78	.9
Diluted average common shares outstanding		88	.2		79	.4		88	.1		79	.2
Basic and diluted earnings per average common share	$	0.4	4	$	0.4	1	$	0.5	6	$	0.4	0
Dividends declared per share	$	0.332	5	$	0.332	5	$	0.665	0	$	0.665	0

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 was approximately $82.2 million and $76.6 million for the three months ended June 30, 2004 and 2003, respectively. Operating income was approximately $113.2 million and $104.3 million for the six months ended June 30, 2004 and 2003, respectively. These amounts exclude the results of NuStar, which as explained above, was sold in the first quarter of 2003 and which is reported as discontinued operations. See “Enogex – Discontinued Operations” below for a further discussion.

Operating Income by Business Segment

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2004			2003			2004			2003
OG&E (Electric Utility)	$	54	.7	$	55	.3	$	59	.7	$	57	.4
Enogex (Natural Gas Pipeline) (A)		27	.3		21	.6		53	.3		46	.9
Other Operations (B)		0	.2		(0	.3)		0	.2		-	--

Consolidated operating income	$	82	.2	$	76	.6	$	113	.2	$	104	.3

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

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

OG&E

	Three Months Ended June 30,						Six Months Ended June 30,
(Dollars in millions)	2004			2003			2004			2003
Operating revenues	$	411	.5	$	357	.9	$	715	.8	$	690	.5
Fuel		162	.8		125	.6		270	.8		266	.9
Purchased power		80	.4		61	.3		155	.6		134	.0

Gross margin on revenues		168	.3		171	.0		289	.4		289	.6
Other operating expenses		113	.6		115	.7		229	.7		232	.2

Operating income	$	54	.7	$	55	.3	$	59	.7	$	57	.4

Operating revenues by classification Residential	$	151	.6	$	137	.4	$	276	.6	$	265	.2
Commercial		106	.4		92	.8		175	.5		170	.2
Industrial		88	.7		68	.7		153	.6		138	.1
Public authorities		42	.2		33	.6		71	.1		66	.3
Sales for resale		13	.8		14	.7		26	.4		28	.1
Other		8	.6		9	.5		12	.3		19	.8

System sales revenues		411	.3		356	.7		715	.5		687	.7
Off-system sales revenues		0	.2		1	.2		0	.3		2	.8

Total operating revenues	$	411	.5	$	357	.9	$	715	.8	$	690	.5

MWH (A) sales by classification (in millions) Residential		1	.8		1	.7		3	.7		3	.7
Commercial		1	.4		1	.4		2	.7		2	.7
Industrial		1	.7		1	.7		3	.4		3	.3
Public authorities		0	.7		0	.6		1	.3		1	.2
Sales for resale		0	.4		0	.4		0	.7		0	.8

System sales		6	.0		5	.8		11	.8		11	.7
Off-system sales		-	--		-	--		-	--		0	.1

Total sales		6	.0		5	.8		11	.8		11	.8

Number of customers		729,6	61		721,3	04		729,6	61		721,3	04

Average cost of energy per KWH (B) - cents Fuel		3.1	21		2.2	92		2.6	57		2.5	12
Fuel and purchased power		3.7	34		2.9	24		3.3	56		3.1	84

Degree days (C) Heating
Actual		1	77		1	80		1,9	62		2,2	57
Normal		2	36		2	36		2,2	18		2,1	99
Cooling
Actual		6	22		4	75		6	40		4	78
Normal		5	47		5	47		5	55		5	55

(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 degrees days, with each degree of difference equaling one cooling degree day. If the calculated average is below 65 degrees, than 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.

Quarter ended June 30, 2004 as compared to quarter ended June 30, 2003

OG&E’s operating income for the three months ended June 30, 2004 decreased approximately $0.6 million or 1.1 percent as compared to the same period in 2003. The decrease in operating income was primarily attributable to the timing of fuel recoveries and lower sales to wholesale customers partially offset by warmer than normal weather, growth in OG&E’s service territory and lower operating expenses.

Gross margin, which is operating revenues less cost of goods sold, was approximately $168.3 million for the three months ended June 30, 2004 as compared to approximately $171.0 million during the same period in 2003, a decrease of approximately $2.7 million or 1.6 percent. The gross margin decreased approximately $3.5 million due to the timing of fuel recoveries and decreased approximately $0.9 million due to lower sales to wholesale customers primarily resulting from reduced sales of power under a new wholesale contract with an existing customer. These decreases were partially offset by an increase of approximately $1.0 million due to warmer than normal weather and an increase of approximately $0.8 million due to growth in OG&E’s service territory.

Cost of goods sold for OG&E consists of fuel used in electric generation and purchased power. Fuel expense was approximately $162.8 million for the three months ended June 30, 2004 as compared to approximately $125.6 million during the same period in 2003, an increase of approximately $37.2 million or 29.6 percent. The increase was due primarily to an increase in the average cost of fuel per kwh due to higher natural gas prices. Purchased power costs were approximately $80.4 million for the three months ended June 30, 2004 as compared to approximately $61.3 million during the same period in 2003, an increase of approximately $19.1 million or 31.2 percent. The increase was due to an increase of 43.3 percent in the volume of energy purchased primarily due to economic purchases.

Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, are passed through to OG&E’s customers through automatic fuel adjustment clauses. While the regulatory mechanisms for recovering fuel costs differ in Oklahoma, Arkansas and 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 16 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.

Other operating expenses, consisting of operating and maintenance expense, depreciation expense and taxes other than income were approximately $113.6 million for the three months ended June 30, 2004 as compared to approximately $115.7 million during the same period in 2003, a decrease of approximately $2.1 million or 1.8 percent. Operating and maintenance expense decreased approximately $3.4 million or 4.5 percent for the three months ended June 30, 2004 as compared to the same period in 2003. This decrease was primarily due to a decrease of

approximately $2.4 million in salaries and wages expense and a decrease of approximately $2.3 million in pension and benefit expense during the three months ended June 30, 2004 as compared to the same period in 2003 due to more projects on which the costs are capitalized and are not being expensed currently. Also contributing to the decrease were lower property insurance costs of approximately $0.4 million. These decreases in operating and maintenance expense were partially offset by an increase of approximately $1.1 million in outside services and an increase of approximately $0.9 million in materials and supplies expense. Depreciation expense increased approximately $1.2 million or 4.1 percent for the three months ended June 30, 2004 as compared to the same period in 2003 primarily due to a change in the depreciation rates for OG&E’s power plants.

Six months ended June 30, 2004 as compared to six months ended June 30, 2003

OG&E’s operating income for the six months ended June 30, 2004 increased approximately $2.3 million or 4.0 percent as compared to the same period in 2003. The increase in operating income was primarily attributable to growth in OG&E’s service territory and lower operating expenses partially offset by the timing of fuel recoveries, lower sales to wholesale customers and milder than normal weather.

Gross margin was approximately $289.4 million for the six months ended June 30, 2004 as compared to approximately $289.6 million during the same period in 2003, a decrease of approximately $0.2 million or 0.1 percent. The gross margin decreased approximately $2.5 million due to the timing of fuel recoveries and decreased approximately $1.5 million due to lower sales to wholesale customers primarily resulting from reduced sales of power under a new wholesale contract with an existing customer. Also contributing to the decreased gross margin was a decrease of approximately $1.1 million due to milder than normal weather. These decreases were partially offset by an increase of approximately $4.8 million due to growth in OG&E’s service territory.

Fuel expense was approximately $270.8 million for the six months ended June 30, 2004 as compared to approximately $266.9 million during the same period in 2003, an increase of approximately $3.9 million or 1.5 percent. The increase was due primarily to an increase in the average cost of fuel per kwh due to higher natural gas prices. Purchased power costs were approximately $155.6 million for the six months ended June 30, 2004 as compared to approximately $134.0 million during the same period in 2003, an increase of approximately $21.6 million or 16.1 percent. The increase was due to an increase of 28.1 percent in the volume of energy purchased primarily due to economic purchases.

Other operating expenses were approximately $229.7 million for the six months ended June 30, 2004 as compared to approximately $232.2 million during the same period in 2003, a decrease of approximately $2.5 million or 1.1 percent. Operating and maintenance expense decreased approximately $3.8 million or 2.6 percent for the six months ended June 30, 2004 as compared to the same period in 2003. This decrease was primarily due to a decrease of approximately $3.4 million in salaries and wages expense and a decrease of approximately $2.7 million in pension and benefit expense during the six months ended June 30, 2004 as compared to the same period in 2003 due to more projects on which the costs are capitalized and are not

being expensed currently. These decreases in operating and maintenance expense were partially offset by an increase of approximately $1.9 million in bad debt expense and an increase of approximately $0.8 million in outside services. Depreciation expense increased approximately $0.5 million or 0.8 percent for the six months ended June 30, 2004 as compared to the same period in 2003 primarily due to a change in the depreciation rates for OG&E’s power plants. Taxes other than income increased approximately $0.8 million or 3.4 percent for the six months ended June 30, 2004 as compared to the same period in 2003 primarily due to an increase of approximately $0.5 million in ad valorem taxes and an increase of approximately $0.4 million in payroll taxes.

Enogex – Continuing Operations

	Three Months Ended June 30,						Six Months Ended June 30,
(Dollars in millions)	2004			2003			2004			2003
Operating revenues	$	775	.5	$	513	.2	$	1,524	.7	$	1,252	.8
Gas and electricity purchased for resale		682	.7		439	.3		1,348	.8		1,096	.2
Natural gas purchases - other		24	.6		14	.3		42	.0		33	.8

Gross margin on revenues		68	.2		59	.6		133	.9		122	.8
Other operating expenses		40	.9		38	.0		80	.6		75	.9

Operating income	$	27	.3	$	21	.6	$	53	.3	$	46	.9

New well connects		5	4		6	5		11	7		11	0

Gathered volumes - TBtu/d (A)		0.9	8		1.0	0		1.0	0		0.9	9
Incremental transportation volumes - TBtu/d		0.5	4		0.4	3		0.4	7		0.4	4

Total throughput volumes - TBtu/d		1.5	2		1.4	3		1.4	7		1.4	3

Natural gas processed - Mmcf/d (B)		50	7		43	4		49	0		44	9

Natural gas liquids produced (keep whole) - million gallons		5	0		5	1		10	3		10	0
Natural gas liquids produced (POL and fixed-fee) - million gallons			4			4			8			8

Total natural gas liquids produced - million gallons		5	4		5	5		11	1		10	8

Average sales price per gallon	$	0.68	0	$	0.55	4	$	0.66	9	$	0.59	6

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

Quarter ended June 30, 2004 as compared to quarter ended June 30, 2003

Enogex’s operating income for the three months ended June 30, 2004 increased approximately $5.7 million or 26.4 percent as compared to the same period in 2003. The increase was primarily attributable to higher gross margins in Enogex’s gathering and processing business and Enogex’s marketing business from, among other things, revenue improvements generated from the negotiation of both new contracts and replacement contracts at better terms that resulted in increases in gathering fees and reductions in the purchase price of gas and an overall favorable business environment. These increases were partially offset by a lower gross margin in Enogex’s transportation and storage business and higher operating expenses. Enogex sold its interest in NuStar during the first quarter of 2003; accordingly this is reported as discontinued operations for the three months ended June 30, 2004 and 2003 in the Condensed Consolidated Financial Statements. See “Enogex – Discontinued Operations” below for a further discussion.

Transportation and storage contributed approximately $33.4 million of Enogex’s gross margin for the three months ended June 30, 2004 as compared to approximately $35.3 million during the same period in 2003, a decrease of approximately $1.9 million or 5.4 percent. Gross margins decreased approximately $3.8 million for the three months ended June 30, 2004 as compared to the same period in 2003 due to the fact that certain contractual revenues that were recorded in transportation and storage in 2003 began being recorded in gathering and processing in 2004. Gross margins also decreased approximately $1.5 million due to reduced fuel recoveries associated with under recovered fuel in prior periods. Partially offsetting these decreases in gross margin was an increase from higher storage revenues of approximately $1.1 million for the three months ended June 30, 2004 as compared to the same period in 2003. The

increased storage revenues were mainly due to additional demand fees from the storage contract with OG&E, which was effective May 2003. Gross margin also was positively impacted for the three months ended June 30, 2004 by increased crosshaul revenues of approximately $0.9 million and higher interruptible revenues of approximately $0.8 million reflecting increases in crosshaul margins and volumes and interruptible contract volumes. Gross margin also increased by approximately $0.6 million due to the negotiation of both new contracts and replacement contracts at more favorable purchase and sale terms.

Gathering and processing contributed approximately $31.4 million of Enogex’s gross margin for the three months ended June 30, 2004 as compared to approximately $21.3 million during the same period in 2003, an increase of approximately $10.1 million or 47.4 percent. Gathering gross margins increased approximately $6.4 million for the three months ended June 30, 2004 as compared to the same period in 2003, of which approximately $4.0 million reflects the change in 2004 discussed above of recording certain contractual revenues in gathering and processing rather than in transportation and storage. Gross margins also increased due to revenue improvements generated from the negotiation of both new contracts and replacement contracts at better terms that resulted in increases in gathering fees and reductions in the purchase price of gas and an overall favorable business environment. Processing gross margins increased approximately $3.7 million for the three months ended June 30, 2004 as compared to the same period in 2003. The increase reflects increased keep whole, percent of liquids and condensate margins due to favorable commodity prices and an expense reallocation due to the fact that field compressor fuel that was recorded in processing in 2003 began being recorded in gathering in 2004. These increases were partially offset by default processing fee revenue recorded during the three months ended June 30, 2003. There was no default processing fee revenue recorded during the three months ended June 30, 2004.

Marketing contributed approximately $3.4 million of Enogex’s gross margin for the three months ended June 30, 2004 as compared to approximately $3.0 million during the same period in 2003, an increase of approximately $0.4 million or 13.3 percent. The increase was primarily due to a decrease of approximately $1.6 million in demand fees expense for storage services due to establishing new rates for the new storage season which began April 1, partially offset by a decrease of approximately $1.2 million in mark-to-market gains due to lower volumes in storage during the three months ended June 30, 2004 as compared to the same period in 2003.

Other operating expenses, consisting of operating and maintenance expense, depreciation expense and taxes other than income, for Enogex were approximately $40.9 million for the three months ended June 30, 2004 as compared to approximately $38.0 million during the same period in 2003, an increase of approximately $2.9 million or 7.6 percent. Operating and maintenance expenses increased approximately $2.7 million or 12.1 percent for the three months ended June 30, 2004 as compared to the same period in 2003. The increase reflects higher allocations from the holding company of approximately $1.3 million, an increase of approximately $0.9 million in payroll, benefit and pension expenses due to hiring new employees and payment of overtime and salary increases and higher materials and supplies expense for repairs and maintenance of systems of approximately $0.5 million. Depreciation expense increased approximately $0.3 million or 2.7 percent primarily due to a higher level of depreciable plant.

Six months ended June 30, 2004 as compared to six months ended June 30, 2003

Enogex’s operating income for the six months ended June 30, 2004 increased approximately $6.4 million or 13.6 percent as compared to the same period in 2003. The increase was primarily attributable to higher gross margins in Enogex’s gathering and processing business and Enogex’s transportation and storage business from, among other things, increased levels of transportation and storage revenues, revenue improvements generated from the negotiation of both new contracts and replacement contracts at better terms that resulted in increases in gathering fees and reductions in the purchase price of gas and an overall favorable business environment. These increases were partially offset by a lower gross margin in Enogex’s marketing business and higher operating expenses. Enogex sold its interest in NuStar during the first quarter of 2003; accordingly this is reported as discontinued operations for the six months ended June 30, 2004 and 2003 in the Condensed Consolidated Financial Statements. See “Enogex – Discontinued Operations” below for a further discussion.

Transportation and storage contributed approximately $63.9 million of Enogex’s gross margin for the six months ended June 30, 2004 as compared to approximately $63.0 million during the same period in 2003, an increase of approximately $0.9 million or 1.4 percent. Gross margins increased approximately $2.7 million due to a decrease in third party imbalance expense and approximately $2.2 million from higher storage revenues for the six months ended June 30, 2004 as compared to the same period in 2003. The increased storage revenues were mainly due to additional demand fees from the storage contract with OG&E, which was effective May 2003. Gross margin increased by approximately $1.2 million due to the negotiation of both new contracts and replacement contracts at more favorable purchase and sale terms. Gross margins increased approximately $0.9 million from higher interruptible revenues due to an increase in interruptible contract volumes. Also contributing to the increase in gross margin were increased transportation revenues of approximately $0.6 million for the six months ended June 30, 2004 from additional demand fees from the transportation contract with OG&E, which was effective May 2003, and an increase of approximately $0.6 million in crosshaul revenues from increased crosshaul margins and volumes. These increases were partially offset by a decrease of approximately $5.8 million due to the fact that certain contractual revenues that were recorded in transportation and storage in 2003 began being recorded in gathering and processing in 2004. Gross margin also was adversely impacted by approximately $1.5 million due to reduced fuel recoveries associated with under recovered fuel in prior periods.

Gathering and processing contributed approximately $63.9 million of Enogex’s gross margin for the six months ended June 30, 2004 as compared to approximately $43.5 million during the same period in 2003, an increase of approximately $20.4 million or 46.9 percent. Gathering gross margins increased approximately $16.1 million for the six months ended June 30, 2004 as compared to the same period in 2003, of which approximately $7.9 million reflects the change in 2004 discussed above of recording certain contractual revenues in gathering and processing rather than in transportation and storage. Gross margins also increased due to revenue improvements generated from the negotiation of both new contracts and replacement contracts at better terms that resulted in increases in gathering fees and reductions in the purchase price of gas and an overall favorable business environment. Processing gross margins increased approximately $4.3 million for the six months ended June 30, 2004 as

compared to the same period in 2003. The increase was primarily due to increased keep whole, percent of liquids and condensate margins due to favorable commodity prices and an expense reallocation due to the fact that field compressor fuel that was recorded in processing in 2003 began being recorded in gathering in 2004. These increases were partially offset by default processing fee revenue recorded during the six months ended June 30, 2003. There was no default processing fee revenue recorded during the six months ended June 30, 2004.

Marketing contributed approximately $6.1 million of Enogex’s gross margin for the six months ended June 30, 2004 as compared to approximately $16.3 million during the same period in 2003, a decrease of approximately $10.2 million or 62.6 percent. Gross margin included gains from the sale of natural gas in storage of approximately $2.2 million and $10.2 million, respectively, during the six months ended June 30, 2004 and 2003. The decrease in the gains of the sale of natural gas in storage was primarily due to Enogex recording approximately a $9.0 million pre-tax loss as a cumulative effect of a change in accounting principle in the first quarter of 2003 rather than this loss being included as a reduction of the gross margin. The cumulative effect of a change in accounting principle was the result of accounting for certain energy contracts and natural gas in storage at the lower of cost or market rather than on a mark-to-market basis. See Note 2 of Notes to Condensed Consolidated Financial Statements for a further discussion. Also contributing to the decrease was a decrease of approximately $0.8 million in mark-to-market gains due to lower volumes in storage during the six months ended June 30, 2004 as compared to the same period in 2003, offset by a decrease of approximately $0.8 million in demand fees expense for storage services due to establishing new rates for the new storage season which began April 1.

Other operating expenses for Enogex were approximately $80.6 million for the six months ended June 30, 2004 as compared to approximately $75.9 million during the same period in 2003, an increase of approximately $4.7 million or 6.2 percent. Operating and maintenance expenses increased approximately $3.6 million or 8.0 percent for the six months ended June 30, 2004 as compared to the same period in 2003. The increase reflects higher allocations from the holding company of approximately $2.2 million, an increase of approximately $1.4 million in payroll, benefit and pension expenses due to hiring new employees and payment of overtime and salary increases, higher materials and supplies expense for repairs and maintenance of systems of approximately $0.8 million and higher outside service costs of approximately $0.3 million. These increases were partially offset by approximately $0.2 million of lower lease payments from the dissolution of a lease in the third quarter of 2003. Depreciation expense increased approximately $0.6 million or 2.7 percent for the six months ended June 30, 2004 as compared to the same period in 2003 primarily due to a higher level of depreciable plant. Taxes other than income increased approximately $0.5 million or 5.7 percent for the six months ended June 30, 2004 as compared to the same period in 2003 primarily due to an increase of approximately $0.3 million in ad valorem taxes and an increase of approximately $0.2 million in payroll taxes.

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

Other income includes, among other things, contract work performed by OG&E, non-operating rental income, gain on the sale of assets, profit on the retirement of fixed assets, minority interest income and miscellaneous non-operating income. Other income was

approximately $2.9 million for the three months ended June 30, 2004 as compared to approximately $0.6 million during the same period in 2003, an increase of approximately $2.3 million. The increase was primarily due to gains of approximately $1.6 million on the sale of certain of Enogex’s compression and processing assets and approximately $0.3 million from the sale of land near the Company’s principal executive offices during the three months ended June 30, 2004, as well as an increase of approximately $0.2 million in the assets associated with the deferred compensation plan and retirement restoration plan.

Other income was approximately $5.7 million for the six months ended June 30, 2004 as compared to approximately $6.7 million during the same period in 2003, a decrease of approximately $1.0 million or 14.9 percent. In the first quarter of 2003, the Company recognized a pre-tax gain of approximately $5.3 million related to the sale of approximately 29 miles of transmission lines of the Ozark pipeline. During the six months ended June 30, 2004, the Company realized gains of approximately $2.8 million on the sale of certain of Enogex’s compression and processing assets, approximately $1.0 million in the assets associated with the deferred compensation plan and retirement restoration plan and approximately $0.3 million from the sale of land near the Company’s principal executive offices.

Other expense includes, among other things, expenses from loss on the sale of assets, loss on retirement of fixed assets, minority interest expense, miscellaneous charitable donations, expenditures for certain civic, political and related activities and miscellaneous deductions. Other expense was approximately $1.5 million for the three months ended June 30, 2004 as compared to approximately $0.6 million during the same period in 2003, an increase of approximately $0.9 million primarily due to an increase of approximately $0.6 million in the liability associated with the deferred compensation plan and retirement restoration plan.

Other expense was approximately $3.0 million for the six months ended June 30, 2004 as compared to approximately $3.6 million during the same period in 2003, a decrease of approximately $0.6 million or 16.7 percent. This difference reflects the recognition, in the first quarter of 2003, of approximately $1.1 million in minority interest expense related to the gain from the sale of approximately 29 miles of transmission lines of the Ozark pipeline that was attributable to the minority interest, that was partially offset by an increase of approximately $0.9 million in the liability associated with the deferred compensation plan and retirement restoration plan.

Net interest expense includes interest income, interest expense and other interest charges. Net interest expense was approximately $23.5 million for the three months ended June 30, 2004 as compared to approximately $25.0 million during the same period in 2003, a decrease of approximately $1.5 million or 6.0 percent. This decrease was primarily due to a decrease of approximately $0.7 million in interest expense due to a lower average commercial paper balance for the three months ended June 30, 2004 as compared to the same period in 2003 and lower interest expense accruals (approximately $0.2 million) during the three months ended June 30, 2004 as compared to the same period in 2003 due to a reduction in long-term debt and lower interest rates.

Net interest expense was approximately $46.6 million for the six months ended June 30, 2004 as compared to approximately $49.6 million during the same period in 2003, a decrease of approximately $3.0 million or 6.0 percent. This decrease was primarily due to a decrease of approximately $1.4 million in interest expense due to a lower average commercial paper balance for the six months ended June 30, 2004 as compared to the same period in 2003 and lower interest expense accruals (approximately $1.0 million) during the six months ended June 30, 2004 as compared to the same period in 2003 due to a reduction in long-term debt and lower interest rates.

Income tax expense was approximately $21.1 million for the three months ended June 30, 2004 as compared to approximately $19.4 million during the same period in 2003, an increase of approximately $1.7 million or 8.8 percent. The increase was primarily due to higher pre-tax income for Enogex and OG&E. This increase was partially offset by a change in the timing of the recognition of book and tax permanent differences in 2004 and the recognition of additional Oklahoma state tax credits of approximately $0.5 million during the three months ended June 30, 2004. Amortization of the federal investment tax credits was approximately $1.3 million for each of the three months ended June 30, 2004 and 2003.

Income tax expense was approximately $20.5 million for the six months ended June 30, 2004 as compared to approximately $21.3 million during the same period in 2003, a decrease of approximately $0.8 million or 3.8 percent. The decrease was primarily due to the recognition of additional Oklahoma state tax credits of approximately $4.2 million during the six months ended June 30, 2004 and a change in the timing of the recognition of book and tax permanent differences in 2004 partially offset by higher pre-tax income for Enogex and OG&E. Amortization of the federal investment tax credits was approximately $2.6 million for each of the six months ended June 30, 2004 and 2003.

Enogex – Discontinued Operations

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

As a result of this sale transaction, Enogex’s interest in NuStar, which was part of the Natural Gas Pipeline segment, has been reported as discontinued operations for the three and six months ended June 30, 2004 and 2003 in the Condensed Consolidated Financial Statements. Results for the discontinued operations are summarized and discussed below.

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2004			2003			2004			2003
Operating revenues	$	-	--	$	-	--	$	0	.7	$	7	.8
Gas purchased for resale		-	--		-	--		-	--		5	.9
Natural gas purchases - other		-	--		-	--		-	--		0	.6

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

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

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

Net income	$	-	--	$	-	--	$	0	.4	$	1	.3

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

Financial Condition

The balance of Cash and Cash Equivalents was approximately $44.7 million and $245.6 million at June 30, 2004 and December 31, 2003, respectively, a decrease of approximately $200.9 million or 81.8 percent. The decrease was primarily due to an increase in short-term investments at December 31, 2003 in anticipation of the planned acquisition of the McClain Plant. Due to a delay in the completion of the McClain Plant acquisition, the Company used short-term investments and proceeds received from the sale of natural gas inventory at Enogex during the six months ended June 30, 2004 to reduce the outstanding commercial paper balance.

The balance of Accounts Receivable was approximately $390.2 million and $350.2 million at June 30, 2004 and December 31, 2003, respectively, an increase of approximately $40.0 million or 11.4 percent. The increase was primarily due to higher natural gas prices and volumes associated with Enogex’s activities in the second quarter of 2004 partially offset by a decrease in OG&E’s billings to its customers reflecting lower fuel costs in June 2004 as compared to December 2003 primarily due to an increase in the credit for previous fuel over recoveries.

The balance of Accrued Unbilled Revenues was approximately $66.2 million and $38.0 million at June 30, 2004 and December 31, 2003, respectively, an increase of approximately $28.2 million. The increase reflects higher seasonal electric rates and increased usage due to warmer weather during June 2004 as compared to December 2003.

The balance of Fuel Inventories was approximately $116.4 million and $163.3 million at June 30, 2004 and December 31, 2003, respectively, a decrease of approximately $46.9 million or 28.7 percent. The decrease was primarily due to inventory sales at Enogex during the six months ended June 30, 2004.

The balance of current Price Risk Management assets was approximately $73.4 million and $61.3 million at June 30, 2004 and December 31, 2003, respectively, an increase of approximately $12.1 million or 19.7 percent. The increase was primarily due to an increase in park and loan transactions and natural gas storage withdrawals associated with OGE Energy Resources, Inc.’s (“OERI”) activities during the six months ended June 30, 2004. This increase is offset by an increase in current Price Risk Management liabilities.

The balance of the Gas Imbalance asset was approximately $37.1 million and $70.0 million at June 30, 2004 and December 31, 2003, respectively, a decrease of approximately $32.9 million or 47.0 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 imbalances, which are operational imbalances. Park and loan transactions were approximately $24.1 million and $45.4 million at June 30, 2004 and December 31, 2003, respectively, a decrease of approximately $21.3 million or 46.9 percent. The decrease was due to the expiration of the park and loan transactions during the six months ended June 30, 2004. The Company expects to obtain and sell the majority of this gas during the third and fourth quarters of 2004. Operational imbalances were approximately $13.0 million and $24.6 million at June 30, 2004 and December 31, 2003, respectively, a decrease of approximately $11.6 million or 47.2 percent. The decrease was due to a reduction of volumes partially offset by an increase in natural gas prices.

The balance of Prepaid Benefit Obligation was approximately $85.7 million and $55.7 million at June 30, 2004 and December 31, 2003, respectively, an increase of approximately $30.0 million or 53.9 percent. The increase was primarily due to the Company funding its pension plan during the second quarter of 2004 partially offset by pension accruals being credited to the prepaid benefit obligation.

The balance of Other Current Assets was approximately $4.9 million and $21.5 million at June 30, 2004 and December 31, 2003, respectively, a decrease of approximately $16.6 million or 77.2 percent. The decrease was primarily due to prepaid insurance amortization during the six months ended June 30, 2004 in addition to the deconsolidation of Energy Insurance Bermuda Ltd. Mutual Business Program No. 19 (“MBP 19”), effective January 1, 2004, in accordance with Financial Accounting Standards Board (“FASB”) Interpretation No. 46, “Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin No. 51.”

The balance of Short-Term Debt was approximately $202.5 million at December 31, 2003 primarily due to the planned acquisition of the McClain Plant. Due to a delay in the completion of the McClain Plant acquisition, the Company used short-term investments and proceeds received from the sale of natural gas inventory by Enogex during the six months ended June 30, 2004 to reduce the outstanding commercial paper balance. There was no short-term debt outstanding at June 30, 2004.

The balance of Accounts Payable was approximately $343.0 million and $280.2 million at June 30, 2004 and December 31, 2003, respectively, an increase of approximately $62.8 million or 22.4 percent. The increase was primarily due to higher natural gas prices and volumes associated with Enogex’s activities in the second quarter of 2004.

The balance of Accrued Taxes was approximately $41.8 million and $18.7 million at June 30, 2004 and December 31, 2003, respectively, an increase of approximately $23.1 million. The increase was primarily due to the Company’s results of operations for the six months ended June 30, 2004 and the timing of income tax payments in 2004.

The balance of current Price Risk Management liabilities was approximately $70.2 million and $46.9 million at June 30, 2004 and December 31, 2003, respectively, an increase of approximately $23.3 million. The increase was primarily due to an increase in park and loan transactions and natural gas storage withdrawals associated with OERI’s activities during the six months ended June 30, 2004. This increase was partially offset by an increase in current Price Risk Management assets.

The balance of Fuel Clause Under Recoveries was approximately $9.3 million at June 30, 2004. The balance of Fuel Clause Over Recoveries (net of Fuel Clause Under Recoveries) was approximately $28.4 million at December 31, 2003. The increase in fuel clause under recoveries was due to under recoveries from OG&E’s customers as OG&E’s cost of fuel exceeded the amount billed during 2004. The cost of fuel subject to recovery through the fuel clause mechanism was approximately $2.64 per Million British thermal unit (“MMBtu”) in June 2004, and was approximately $1.21 per MMBtu in December 2003. 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 allow OG&E to amortize under or over recovery.

The balance of Other Current Liabilities was approximately $28.4 million and $41.2 million at June 30, 2004 and December 31, 2003, respectively, a decrease of approximately $12.8 million or 31.1 percent. The decrease was primarily due to incentive compensation payments partially offset by incentive compensation accruals during the six months ended June 30, 2004 in addition to the deconsolidation of MBP 19, effective January 1, 2004, in accordance with FASB Interpretation No. 46.

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 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 in an unconsolidated entity that is held by, and material to, the Company, where such entity provides financing, liquidity, market risk or credit risk support to, or engages in leasing, hedging or research and

development services with, the Company. Except as set forth below, there have been no significant changes in the Company’s off-balance sheet arrangements reported in the Company’s Form 10-K for the year ended December 31, 2003.

Heat Pump Loans

OG&E has a heat pump loan program, whereby, qualifying customers may obtain a loan from OG&E to purchase a heat pump. In October 1998, OG&E sold approximately $25.0 million of its heat pump loans in a securitization transaction through OGE Consumer Loan LLC. During the second quarter of 2004, OG&E repurchased the outstanding heat pump loan balance of approximately $0.1 million. No gain or loss was recorded in the second quarter of 2004 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 at Enogex. Other capital requirements are primarily related to maturing debt, operating lease obligations, hedging activities, natural gas storage and delays in recovering unconditional fuel purchase obligations. The Company generally meets its cash needs through a combination of internally generated funds, short-term borrowings and permanent financings.

Early Retirement of Long-Term Debt

Interest Rate Swap Agreements

Fair Value Hedges

corporate long-term floating rate debt to reflect a level more in line with industry standards. These interest rate swaps qualified as fair value hedges under Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and met all of the requirements for a determination that there was no ineffective portion as allowed by the shortcut method under SFAS No. 133.

Cash Flow Hedges

During the second quarter of 2004, the Company entered into three separate interest rate swap agreements, effective April 16, 2004, April 21, 2004 and May 17, 2004, respectively, to hedge approximately $20.0 million, $30.0 million and $20.0 million, respectively, of future interest payments of long-term debt expected to be issued later this year related to the planned redemption of $200.0 million of 8.375 percent trust preferred securities of OGE Energy Capital Trust I. These interest rate swap agreements mature on October 15, 2014. The objective of these interest rate swaps was to protect against the volatility of interest rates affecting future interest payments. These interest rate swaps qualified as cash flow hedges under SFAS No. 133 and met all of the requirements for a determination that there was no ineffective portion as allowed by the hypothetical derivative method under SFAS No. 133.

agreement matures on October 15, 2014. The objective of this interest rate swap was to protect against the volatility of interest rates affecting future interest payments. This interest rate swap qualified as a cash flow hedge under SFAS No. 133 and met all of the requirements for a determination that there was no ineffective portion as allowed by the hypothetical derivative method under SFAS No. 133.

Future Capital Requirements

Capital Expenditures

The Company’s current 2004 to 2006 construction program includes the purchase of New Generation as discussed below. In addition to the 110 MW PowerSmith contract expiring in August 2004, for which OG&E recently entered into a replacement contract with PowerSmith (subject to OCC approval), 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. OG&E will continue reviewing all of the supply alternatives to these expiring QF contracts that minimize the total cost of generation to its customers, including exercising its options (if applicable) to extend these QF contracts at pre-determined rates. Accordingly, OG&E will continue to explore opportunities to build or buy power plants in order to serve its native load. As a result of the high volatility of current natural gas prices and the increase in natural gas prices, OG&E will also assess the feasibility of constructing additional base load coal-fired units. See Note 16 of Notes to Condensed Consolidated Financial Statements for a description of current proceedings involving a PowerSmith QF contract.

On August 18, 2003, OG&E signed an asset purchase agreement to acquire NRG McClain LLC’s 77 percent interest in the McClain Plant. OG&E completed the acquisition of the McClain Plant on July 9, 2004. The purchase price for the interest in the McClain Plant was approximately $160.0 million. See “Overview – Recent Acquisition of Power Plant.” OG&E funded the acquisition with short-term borrowings from the Company. OG&E expects to issue long-term debt to permanently finance the McClain Plant acquisition. Also, the Company expects to make a capital contribution to OG&E of approximately $153.0 million in August. To reliably meet the increased electricity needs of OG&E’s customers during the foreseeable future, OG&E will continue to invest to maintain the integrity of the delivery system. Approximately $10.5 million of the Company’s capital expenditures budgeted for 2004 are to comply with environmental laws and regulations.

Pension and Postretirement Benefit Plans

and also expects to make contributions in the third quarter of 2004. The expected contributions to the pension plan, anticipated to be in the form of cash, are discretionary contributions and are not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974.

Security Ratings

The Company’s credit ratings from Moody’s Investors Service (“Moody’s”) were as follows: OGE Energy Corp.’s senior unsecured debt, Baa1; OG&E’s senior unsecured debt, A2; Enogex’s senior unsecured debt, Baa3; and OGE Energy Corp.’s short-term commercial paper rating, P-2. The outlook for OGE Energy Corp. and OG&E is stable. On June 29, 2004, Moody’s upgraded Enogex’s outlook from negative to stable based on Enogex’s improved ability to tolerate adverse commodity price environments and to avoid future losses in several areas. Moody’s further discussed that Enogex is more financially flexible as a result of reducing interest expense over the past three years, is improving returns from asset rationalization, has lower but more profitable volumes and has more favorable gas processing contract terms.

Future Sources of Financing

Management expects that internally generated funds, funds received from the 2003 equity offering, proceeds from the sales of common stock pursuant to the Company’s DRIP 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 debt to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged. The Company issued equity in the third quarter of 2003 and issued common stock pursuant to the DRIP during 2003. With the acquisition of the McClain Plant complete, OG&E plans to issue long-term debt to permanently finance the McClain Plant acquisition and the Company plans to issue common stock pursuant to the DRIP during 2004.

Short-Term Debt

Short-term borrowings generally are used to meet working capital requirements. The short-term debt balance was approximately $202.5 million at December 31, 2003 due to the planned acquisition of the McClain Plant. Due to a delay in the completion of the McClain Plant acquisition, the Company used short-term investments and proceeds received from the sale of natural gas inventory by Enogex during the six months ended June 30, 2004 to reduce the outstanding commercial paper balance. There was no short-term debt outstanding at June 30, 2004. In July 2004, the Company issued short-term debt to fund a portion of the McClain Plant acquisition, which closed July 9 and, as a result, the short-term debt balance was approximately $216.1 million at July 31, 2004.

Lines of Credit and Available Cash (In millions)
Entity	Amount Available			Amount Outstanding			Maturity
OGE Energy Corp. (A)	$	15	.0	$	-	--	April 6, 2005
OG&E		100	.0		-	--	December 9, 2004
OGE Energy Corp. (A)		300	.0		-	--	December 9, 2004
		415	.0		-	--
Cash		44	.7		N	/A	N/A

Total	$	459	.7	$	-	--

(A) The lines of credit at OGE Energy Corp. are used to back up the Company’s commercial paper borrowings. There was no short-term debt outstanding at June 30, 2004. In April 2004, the Company renewed its $15.0 million credit facility, shown in the table above, which matures April 6, 2005. Also, in June 2004, OG&E extended the maturity date of its $100.0 million credit facility, shown in the table above, to December 9, 2004.

Asset Sales

Also contributing to the liquidity of the Company have been numerous asset sales by Enogex. Since January 1, 2002, completed sales generated net proceeds of approximately $106.0 million. Sales proceeds generated to date have been used to reduce debt at Enogex and commercial paper at the holding company.

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

Critical Accounting Policies and Estimates

The Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements contain information that is pertinent to Management’s Discussion and Analysis. In preparing the Condensed Consolidated Financial Statements, management is required to make estimates and assumptions that affect the reported amounts of assets and

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

Accounting Pronouncements

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

Electric Competition; Regulation

OG&E and Enogex have been and will continue to be affected by competitive changes to the utility and energy industries. Significant changes already have occurred and additional changes are being proposed to the wholesale electric market. Although it appears unlikely in the near future that changes will occur to retail regulation in the states served by OG&E due to the significant problems faced by California in its electric deregulation efforts and other factors, significant changes are possible, which could significantly change the manner in which OG&E conducts its business. These developments at the federal and state levels are described in more detail in Note 16 of Notes to Condensed Consolidated Financial Statements and in the Company’s Form 10-K for the year ended December 31, 2003. The Company currently has three important matters pending before the OCC. See Note 16 of Notes of 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 set forth, in Notes 15 and 16 of Notes to Condensed Consolidated Financial

Statements, in Note 17 to the Company’s Consolidated Financial Statements included in the Company’s Form 10-K for the year ended December 31, 2003 and in Note 15 to the Company’s Condensed Consolidated Financial Statements included in the Company’s Form 10-Q for the quarter ended March 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.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Risk Management

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

To manage the volatility relating to these exposures, the Company enters into various derivative 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 long-term debt obligations and commercial paper. The Company manages its interest rate exposure by limiting its variable rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. The Company may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

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

Commodity Price Risk

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

The trading activities are conducted throughout the year subject to daily and monthly trading stop loss limits of $2.5 million. The daily loss exposure from trading activities is measured primarily using value at risk, 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 may hedge, 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 trading and non-trading commodity price exposure to the market risk of the Company’s natural gas and natural gas liquids commodity positions. The Company’s daily net commodity position consists of natural gas inventories, commodity purchase and sales contracts, financial and commodity derivative instruments and anticipated natural gas processing spreads and fuel recoveries. The 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 June 30, 2004.

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

Item 4. Controls and Procedures.

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

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

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

Reference is made to Part I, Item 3 of the Company’s Form 10-K for the year ended December 31, 2003 and Part II, Item 1 of the Company’s Form 10-Q for the quarter ended March 31, 2004 for a description of certain legal proceedings presently pending. Except as set forth below and in Notes 15 and 16 of Notes to Condensed Consolidated Financial Statements, 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.

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

Kaiser-Francis Oil Company

As previously reported, OG&E had been sued by Kaiser-Francis Oil Company in District Court, Grady County, Oklahoma. 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. The Court of Appeals denied Kaiser-Francis’s motion for rehearing. The parties may file

petitions for certiorari, for review by the Oklahoma Supreme Court of those portions of the appellate court’s opinion unfavorable to each. While the Company cannot predict the precise outcome of this case, the Company believes, based on the information known at this time, that this lawsuit will not have a material adverse effect on the Company’s consolidated financial position or results of operations.

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

(a) The Company’s Annual Meeting of Shareowners was held on May 20, 2004.

(b) Not applicable.

(1)

The Shareowners voted to elect the Company’s nominees for election to the Board of Directors as follows:

Luke R. Corbett – 71,802,770 votes for election and 3,934,793 votes withheld

Robert Kelley – 71,362,209 votes for election and 4,375,354 votes withheld

J.D. Williams – 63,450,951 votes for election and 12,286,612 votes withheld

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

(a) Exhibits

	Exhibit No.		Description
	2.01		Amendment No. 8 to Asset Purchase Agreement, dated as of May 15, 2004 by and between OG&E and NRG McClain LLC.
	2.02		Amendment No. 9 to Asset Purchase Agreement, dated as of June 2, 2004 by and between OG&E and NRG McClain LLC.
	2.03		Amendment No. 10 to Asset Purchase Agreement, dated as of June 17, 2004 by and between OG&E and NRG McClain LLC.
	10.01		Consulting Agreement, dated as of June 30, 2004 by and between OGE Energy Corp. and Al Strecker.
	10.02		Amendment No. 1 to Credit Agreement, dated as of June 22, 2004 by and between OG&E, Bank One, NA, Wachovia Bank, National Association, Cobank, ACB, Lasalle Bank National Association,

			U.S. Bank National Association, Union Bank of California, N.A. and Bank Hapoalim B.M.
	10.03		Amended and Restated Facility Operating Agreement for the McClain Generating Facility dated as of July 9, 2004 between OG&E and the Oklahoma Municipal Power Authority.
	10.04		Amended and Restated Ownership and Operation Agreement for the McClain Generating Facility dated as of July 9, 2004 between OG&E and the Oklahoma Municipal Power Authority.
	10.05		Operating and Maintenance Agreement for the Transmission Assets of the McClain Generating Facility dated as of August 25, 2003 between OG&E and the Oklahoma Municipal Power Authority
	31.01		Certifications Pursuant to Rule 13a-15(e)/15d-15(e) As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32.01		Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(b) Reports on Form 8-K

The Company filed a Current Report on Form 8-K on April 30, 2004 to report that the Oklahoma Corporation Commission (“OCC”) issued an order confirming that OG&E was delivering savings to its customers as required under the Settlement Agreement.

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

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

The Company filed a Current Report on Form 8-K on May 24, 2004 to report the status of negotiations between OG&E and PowerSmith relating to finalizing the tentative power sales agreement reached on March 29, 2004.

The Company filed a Current Report on Form 8-K on June 10, 2004 to report that OG&E and PowerSmith reached a power sales agreement on June 8, 2004. The terms of the agreement are subject to approval by the OCC.

The Company filed a Current Report on Form 8-K on July 9, 2004 to report that OG&E received regulatory approval from the FERC to purchase a 77 percent interest in the McClain Plant.

The Company filed a Current Report on Form 8-K on July 13, 2004 to report that OG&E completed its acquisition of the McClain Plant.

The Company filed a Current Report on Form 8-K on August 4, 2004 to report its consolidated results of operations and financial condition for the quarter ended June 30, 2004.

SIGNATURE

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

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

August 3, 2004

Exhibit 2.01

AMENDMENT NO. 8 TO ASSET PURCHASE AGREEMENT

THIS AMENDMENT NO. 8 TO ASSET PURCHASE AGREEMENT (this “Amendment”), dated as of May 15, 2004, is made by NRG McCLAIN LLC, a Delaware limited liability company (“Seller”), and OKLAHOMA GAS AND ELECTRIC COMPANY, an Oklahoma corporation (“Buyer”).

RECITALS

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

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

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

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

ARTICLE I
Amendment to Agreement

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

“(b) Buyer, if the Closing has not occurred on or before June 4, 2004 and the failure to consummate the Asset Purchase on or before such date did not result from the failure by Buyer to fulfill any undertaking or commitment provided for herein that is required to be fulfilled prior to the Closing;

(c) Seller, if the Closing has not occurred on or before June 4, 2004 and the failure to consummate the Asset Purchase on or before such date did not result from the failure by Seller to fulfill any undertaking or commitment provided for herein that is required to be fulfilled prior to the Closing;”.

ARTICLE II
Miscellaneous

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

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

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

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

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

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

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

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

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

SECTION 2.7 Electronic Signatures.

(a) Notwithstanding the Electronic Signatures in Global and National Commerce Act (15 U.S.C. Sec. 7001 et seq.), the Uniform Electronic Transactions Act, or any other Law relating to or enabling the creation, execution, delivery, or recordation of any contract or signature by electronic means, and notwithstanding any course of conduct engaged in by the Parties, no Party shall be deemed to have executed this Amendment unless and until such Party shall have executed this Amendment on paper by a handwritten original signature or any other symbol executed or adopted by a Party with current intention to authenticate this Amendment.

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

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

[Signature pages follow]

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

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

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

WESTLB AG, NEW YORK BRANCH
As Agent

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

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

Exhibit 2.02

AMENDMENT NO. 9 TO ASSET PURCHASE AGREEMENT

THIS AMENDMENT NO. 9 TO ASSET PURCHASE AGREEMENT (this “Amendment”), dated as of June 2, 2004, is made by NRG McCLAIN LLC, a Delaware limited liability company (“Seller”), and OKLAHOMA GAS AND ELECTRIC COMPANY, an Oklahoma corporation (“Buyer”).

RECITALS

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

ARTICLE I
Amendment to Agreement

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

“(b) Buyer, if the Closing has not occurred on or before June 18, 2004 and the failure to consummate the Asset Purchase on or before such date did not result from the failure by Buyer to fulfill any undertaking or commitment provided for herein that is required to be fulfilled prior to the Closing;

(c) Seller, if the Closing has not occurred on or before June 18, 2004 and the failure to consummate the Asset Purchase on or before such date did not result from the failure by Seller to fulfill any undertaking or commitment provided for herein that is required to be fulfilled prior to the Closing;”.

ARTICLE II
Miscellaneous

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

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

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

SECTION 2.7 Electronic Signatures.

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

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

[Signature pages follow]

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

	OKLAHOMA GAS AND ELECTRIC COMPANY, an Oklahoma corporation
	By:	/s/ Peter B. Delaney
	Name:	Peter B. Delaney
	Title:	Executive Vice President and
		Chief Operating Officer

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

WESTLB AG, NEW YORK BRANCH
As Agent

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

By:	/s/ Claudia Flores
Name:	Claudia Flores
Title:	Associate Director

Exhibit 2.03

AMENDMENT NO. 10 TO ASSET PURCHASE AGREEMENT

THIS AMENDMENT NO. 10 TO ASSET PURCHASE AGREEMENT (this “Amendment”), dated as of June 17, 2004, is made by NRG McCLAIN LLC, a Delaware limited liability company (“Seller”), and OKLAHOMA GAS AND ELECTRIC COMPANY, an Oklahoma corporation (“Buyer”).

RECITALS

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

ARTICLE I
Amendment to Agreement

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

“(b) Buyer, if the Closing has not occurred on or before July 9, 2004 and the failure to consummate the Asset Purchase on or before such date did not result from the failure by Buyer to fulfill any undertaking or commitment provided for herein that is required to be fulfilled prior to the Closing;

(c) Seller, if the Closing has not occurred on or before July 9, 2004 and the failure to consummate the Asset Purchase on or before such date did not result from the failure by Seller to fulfill any undertaking or commitment provided for herein that is required to be fulfilled prior to the Closing;”.

ARTICLE II
Miscellaneous

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

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

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

SECTION 2.7 Electronic Signatures.

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

[Signature pages follow]

	NRG McCLAIN LLC, a Delaware limited liability company
	By:	/s/ John Brewster
	Name:	John Brewster
	Title:	President

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

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

WESTLB AG, NEW YORK BRANCH
As Agent

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

By:	/s/ Claudia Flores
Name:	Claudia Flores
Title:	Associate Director

Exhibit 10.01

CONSULTING AGREEMENT BETWEEN
OG&E ENERGY CORP. AND AL STRECKER

1. Identification and Parties. This Consulting Agreement (“Agreement”) is entered into by and between Al Strecker (“Consultant”) and OGE Energy Corp. (the “Company”) as of June 1, 2004 (the “Effective Date”).

2. Recitals. The Company desires to retain Consultant and Consultant desires to be retained upon the terms and conditions set forth in this Agreement.

3. Term of Agreement.

3.1. This Consulting Agreement shall commence on the Effective Date.

3.2. This Agreement shall remain in effect for a one (1) year term from June 1, 2004 to May 31, 2005, unless terminated earlier pursuant to Paragraph 6 of this Agreement.

4. Services.

4.1. During the term of this Agreement, Consultant shall consult with and advise the Company or its subsidiary, Oklahoma Gas and Electric Company, on specific matters as designated from time to time by the Company’s Chief Executive Officer (“CEO”) or the Company’s Executive Vice President and Chief Operating Officer (“COO”). Consultant shall render such consulting services diligently and in the best interests of the Company and its subsidiaries and affiliates. Consultant shall report and be responsible to the COO or such other person designated in writing to Consultant by the CEO.

4.2. It is the Company’s desire that Consultant also continue to serve during the term of this Agreement as a member of the Board of Directors of the Company’s subsidiary, Enogex Inc. Notwithstanding anything in this Agreement, the Company and Consultant understand that Consultant can be removed at any time from the Board by the shareholders of Enogex Inc.

4.3. Consultant shall not be required to devote any minimum number of hours to consulting services under this Agreement nor shall Consultant be guaranteed any number of hours but, as needed, Consultant will make available his time upon reasonable notice during normal business hours to providing services hereunder.

4.4. Consultant has voluntarily sought to do business with the Company, and Consultant represents that entering into this Agreement does not conflict with, or constitute a breach of, the terms of any existing agreement or obligation to which Consultant is a party or by which Consultant is bound.

5. Compensation. In consideration for services provided pursuant to this Agreement, Consultant shall receive from the Company the following fees:

5.1. Consultant shall be paid a lump-sum “Retainer Fee” of Eighteen Thousand Five Hundred and No/100 Dollars ($18,500.00). This Retainer Fee will be paid to Consultant on or before July 31, 2004.

5.2. For consulting services performed at the request of the CEO or COO, or for services performed as a member of the Board of Directors of Enogex Inc., Consultant shall be paid at the rate of Two Hundred Thirty and No/100 Dollars ($230.00) per hour. In addition, Consultant shall be entitled to the reimbursement of the following expenses incurred in the course of performing such services: (i) long-distance telephone charges; (ii) overnight delivery service charges; and (iii) reasonable out-of-pocket travel expenses for travel to locations more than 50 miles from the Company’s headquarters at 321 N. Harvey, Oklahoma City, Oklahoma (collectively, “Permitted Expenses”). Consultant shall submit to the Company monthly invoices which show the total number of hours worked and contain a description of the work performed and Permitted Expenses.

5.3. Except for the Retainer Fee and Permitted Expenses, all monies owed to Consultant for hourly fees for consulting and Board services under this Agreement shall be paid after May 31, 2005, but in no event later than July 31, 2005.

6. Early Termination of Agreement. The Agreement and the term thereof shall end prior to May 31, 2005, on the first to occur of the following events:

6.1. The death of Consultant;

6.2. The date as of which the CEO terminates the Agreement because of the inability of Consultant to provide services under this Agreement by reason of Consultant’s total disability, as determined by the Company; or

6.3. The date as of which the CEO terminates the Agreement due to the failure of Consultant to perform his obligations under this Agreement in a manner satisfactory to the Company if such failure has continued for thirty (30) days after written notice specifying such failure has been given by the Company to Consultant; except that, if such failure is due to the misconduct, malfeasance, nonfeasance or breach of any provision of this Agreement by Consultant, the date of termination of the Agreement shall be the date written notice of such failure is given to Consultant.

In the event this Agreement is terminated prior to May 31, 2005, all obligations of the Company under Paragraph 5 shall terminate; provided, however, that any amounts to which Consultant is entitled for services rendered prior to the termination of this Agreement but not yet paid as of the termination of this Agreement shall be paid to Consultant as provided in Paragraph 5 and all Permitted Expenses to which Consultant is entitled to reimbursement through the termination of this Agreement shall be paid as provided in Section 5.

7. Non-Compete. Consultant agrees that for the time this Agreement is in effect, he will take on other clients only with the prior written approval of the COO, if such engagement would involve “Competition”. For purposes of this Agreement, “Competition” shall mean engaging in or carrying on, directly or indirectly, any enterprise, whether as an advisor, principal, agent, partner, officer, director, employee, stockholder, associate or consultant to any person, partnership, corporation or any other business entity that is principally engaged in the business of the Company or its affiliates in their market areas; provided, however, that “Competition” will not include the mere ownership of 1% or less of the outstanding securities in any enterprise and exercise of rights appurtenant thereto.

8. Confidentiality

8.1. “Confidential Information” for purposes of this Agreement shall be defined as all information, knowledge or data relating to the business of the Company or its affiliates, including, but not limited to trade secrets; marketing strategies; financial information; technological and engineering data; formulas; production plans and methods; manufacturing applications and techniques; research and development activities; preferences and identities of customers, vendors, suppliers and prospective customers; vendors and suppliers and sources of business referrals; current, prospective and ongoing business strategies, plans and techniques; computer and other programs, software, devices, methods, techniques, processes and inventions, including, but not limited to, any enhancements thereto; compilations and other materials developed by or on behalf of the Company or its affiliates (whether in written, graphic, audiovisual, electronic or other media, including computer software), which has been and/or will be subject to reasonable efforts to maintain its confidentiality, is not generally known to the public or by competitors of the Company or its affiliates, and which derives its value from remaining undisclosed. Confidential Information also includes information in the above categories of any third party affiliated, associated or doing business with the Company or its affiliates which has been disclosed to the Company or its affiliates in the course of conduct of the Company’s or affiliates’ business. Confidential Information does not include any information that is in the public domain or otherwise is or becomes publicly available (other than as a result of a wrongful act of Consultant or any agent or employee of the Company or its affiliates).

8.2. Consultant acknowledges that, Consultant has been, and may be in the future, intimately involved with and be privy to Confidential Information which is a valuable asset of the Company and its affiliates and which, if disclosed or used without authorization, would cause irreparable harm to the Company or its affiliates. Consultant acknowledges that the Confidential Information is and will remain the exclusive property of the Company and its affiliates.

8.3. Consultant agrees to hold, at all times during the term of this Agreement and after termination of this Agreement for any reason, all Confidential Information in trust for the benefit of the Company and its affiliates or any third party as described above. Consultant further agrees that he will not, during the term of this Agreement and after termination of this Agreement for any reason, use in any manner, for the benefit of any individual or entity, or divulge or convey to any other individual or entity, any Confidential Information without the Company’s prior written permission, unless required to do so by duties under this Agreement or

legal process; provided that, before making such disclosure, Consultant shall advise the Company and will cooperate fully in any legal action the Company may elect to take in order to attempt to prevent such disclosure.

8.4. Upon termination of this Agreement with the Company for any reason, or at any other time the Company demands, Consultant shall deliver promptly to the Company all Company property then in his possession.

8.5. Consultant agrees that the terms of this Paragraph 8 and the obligations hereunder shall survive termination of the Agreement. Consultant agrees to abide by the Company’s policies regarding confidentiality, conduct or ethics.

8.6. In the event of a breach by Consultant of any of the provisions of this Paragraph 8, the Company or its affiliates may, in addition to any other rights and remedies existing in their favor, apply to any court of law or equity of competent jurisdiction for specific performance and/or injunctive or other relief in order to enforce or prevent any violations of the provisions hereof.

9. General Provisions.

9.1. This Agreement constitutes the entire agreement between the Company and Consultant with respect to the performance of consulting and Board services and supersedes all prior and contemporaneous agreements, representations and understandings, oral or written, regarding such matters between the parties.

9.2. This Agreement shall be governed by and construed in accordance with the laws of the State of Oklahoma, without regard to conflicts of law principles.

9.3. Any dispute, claim or controversy of any kind whatsoever between Consultant and the Company, shall be settled by final and binding arbitration in Oklahoma City, Oklahoma, by the American Arbitration Association (the “AAA”), pursuant to the AAA’s Commercial Arbitration Rules and procedures that are then in effect. The parties to this Agreement and all who claim under them shall be conclusively bound by the determination of any arbitrator, and only have the right to have any decision or award rendered in accordance with this Paragraph entered as a judgment in a court of the State of Oklahoma or any other court of competent jurisdiction. Any claim by a party to this Agreement must be raised within six (6) months of the date of the knowledge by the party of such claim, or within the time provided by law, whichever is earlier.

9.4. The captions and paragraph numbers appearing in this Agreement are inserted for convenience and in no way define, limit, construe or describe the scope or intent of the provisions of this Agreement.

9.5. No waiver of any breach of any term or provision of this Agreement shall be construed to be, nor shall be, a waiver of any other breach of this Agreement. No waiver shall be binding unless in writing and signed by the party waiving the breach.

9.6. This Agreement has been reviewed by the parties and the parties have had an opportunity to have it reviewed by their respective attorneys. The parties have had a sufficient opportunity to consider and negotiate the contents of this Agreement.

9.7. This Agreement may be amended, modified, or supplemented only by a written agreement, executed by both parties to this Agreement.

9.8. The provisions of this Agreement are severable and, in the event that any provision hereof shall be found by any court to be unenforceable, in whole or in part, the remainder of this Agreement shall nonetheless remain enforceable and binding upon the Company and Consultant.

9.9. All notices or other communications provided for in this Agreement shall be in writing and shall be deemed to have been given if delivered by hand or by a nationally recognized overnight delivery service to the parties at the following addresses:

CONSULTANT:		COMPANY:
Al Strecker 2430 Cedar Oak Drive Edmond, Oklahoma 73013		Peter B. Delaney Executive Vice President and Chief Operating Officer OGE Energy Corp. 321 N. Harvey Oklahoma City, OK 73102

Either party wishing to change the address to which notice or other communications under this Agreement shall be sent shall give written notice of such change to the other party.

9.10. The parties hereby acknowledge and agree that (i) in performing his obligations hereunder, Consultant will be acting exclusively as an independent contractor, and (ii) they do not intend, and will not hold out or permit the assertion by any third party, that there exists any partnership, agency, joint venture, common undertaking for a profit or other relationship between the parties other than that of independent contractor.

9.11. This Agreement shall inure to the benefit of and be binding upon the Company, its successors and assigns, including, without limitation, any person, partnership, corporation or other entity which may acquire all or substantially all of the Company’s assets and business or into or with which the Company may be merged or consolidated, and upon Consultant and his personal or legal representatives, executors, administrators, successor, heirs, distributees or legatees. This Agreement may not be assigned by Consultant in whole or in part without prior written consent of the Company.

9.12. The Company may withhold from any amounts payable under this Agreement all federal, state, city or other taxes the Company is required to withhold pursuant to any law or government regulation or ruling.

9.13. For purposes of this Agreement, the term “affiliate” means with respect to the Company or any other entity, an entity that directly, or indirectly through one or more intermediaries, controls, is controlled by, or is under common control with the Company or such other entity.

IN WITNESS WHEREOF, the parties have executed this Agreement as of this 30th day of June, 2004.

CONSULTANT:		COMPANY:
By: /s/ Al Strecker Al Strecker		By: /s/ Peter B. Delaney Peter B. Delaney, Exec. VP

Exhibit 10.02

AMENDMENT NO. 1

Dated as of June 22, 2004

CREDIT AGREEMENT

Dated as of June 26, 2003

THIS AMENDMENT NO. 1 (“Amendment”) is made as of June 22, 2004 by and among Oklahoma Gas and Electric Company (the “Borrower”), the financial institutions listed on the signature pages hereof (the “Lenders”) and Bank One, NA (Main Office Chicago), as Administrative Agent (the “Agent”), under that certain Credit Agreement dated as of June 26, 2003 by and among the Borrower, the Lenders and the Agent (the “Credit Agreement”). Capitalized terms used herein and not otherwise defined herein shall have the respective meanings given to them in the Credit Agreement.

WHEREAS, the Borrower has requested that the Facility Termination Date be extended to December 9, 2004 and certain other amendments be made to the Credit Agreement as described herein;

WHEREAS, the Borrower, the Lenders party hereto and the Agent have agreed to so amend the Credit Agreement on the terms and conditions set forth herein;

NOW, THEREFORE, in consideration of the premises set forth above, the terms and conditions contained herein, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Borrowers, the Lenders party hereto and the Agent have agreed to the following amendments to the Credit Agreement.

1. Amendments to Credit Agreement. Effective as of June 22, 2004 (the “Effective Date”) but subject to the satisfaction of the conditions precedent set forth in Section 2 below,

(a) The definition of “Facility Termination Date” appearing in Article I of the Credit Agreement is amended to delete the reference to “June 24, 2004” appearing therein and insert “December 9, 2004” in lieu thereof:

(b) The definition of “SEC Reports” appearing in Article I of the Credit Agreement is amended and restated in its entirety to read as follows:

““SEC Reports” means (i) the Annual Report on Form 10-K of the Borrower for the fiscal year ended December 31, 2003, (ii) the Quarterly Report on Form 10-Q of the Borrower for the fiscal quarter ended March 31, 2004, and (iii) the Current Report on Form 8-K of the Borrower dated May 24, 2004.”

(c) Sections 5.4 and 5.5 of the Credit Agreement are amended to delete the reference to “December 31, 2002" appearing therein and insert “December 31, 2003” in lieu thereof.

2. Conditions of Effectiveness. The effectiveness of this Amendment is subject to the conditions precedent that the Agent shall have received (i) counterparts of this Amendment duly executed by the Borrower, each of the Lenders and the Agent, (ii) for the ratable account of each Lender, an amendment fee equal to 0.025% of such Lender’s Commitment, (iii) copies of resolutions or actions of any other body authorizing the execution of this Amendment by the Borrower, (iv) favorable written opinions of counsels to the Borrower, in form and substance reasonably acceptable to the Agent and its counsel, (v) such other instruments and documents as are reasonably requested by the Agent and (vi) payment and/or reimbursement of all of the fees and expenses (including attorneys’ fees and expenses) due or payable to the Agent in connection with this Amendment.

3. Representations and Warranties of the Borrower. The Borrower hereby represents and warrants as follows:

(a) This Amendment and the Credit Agreement as amended hereby constitute legal, valid and binding obligations of the Borrower and are enforceable against the Borrower in accordance with their terms.

(b) As of the date hereof and giving effect to the terms of this Amendment, (i) there exists no Default or Unmatured Default and (ii) the representations and warranties contained in Article V of the Credit Agreement, as amended hereby, are true and correct in all material respects, except for representations and warranties made with reference solely to an earlier date.

4. Reference to and Effect on the Credit Agreement.

(a) Upon the effectiveness hereof, each reference to the Credit Agreement in the Credit Agreement or any other Loan Document shall mean and be a reference to the Credit Agreement as amended hereby.

(b) Except as specifically amended above, the Credit Agreement and all other documents, instruments and agreements executed and/or delivered in connection therewith shall remain in full force and effect and are hereby ratified and confirmed.

(c) The execution, delivery and effectiveness of this Amendment shall not operate as a waiver of any right, power or remedy of the Agent or the Lenders, nor constitute a waiver of any provision of the Credit Agreement or any other documents, instruments and agreements executed and/or delivered in connection therewith.

5. Governing Law. This Amendment shall be governed by and construed in accordance with the internal laws of the State of Illinois, but giving effect to federal laws applicable to national banks.

6. Headings. Section headings in this Amendment are included herein for convenience of reference only and shall not constitute a part of this Amendment for any other purpose.

7. Counterparts. This Amendment may be executed by one or more of the parties hereto on any number of separate counterparts, and all of said counterparts taken together shall be deemed to constitute one and the same instrument.

[Signature Pages Follow]

IN WITNESS WHEREOF, this Amendment has been duly executed as of the day and year first above written.

	OKLAHOMA GAS AND ELECTRIC COMPANY, as the Borrower
	By: /s/ Deborah S. Fleming
	Name: Deborah S. Fleming Title: Treasurer

	BANK ONE, NA (MAIN OFFICE CHICAGO), as a Lender and as Agent
	By: /s/ Jane Bek Keil
	Name: Jane Bek Keil Title: Director

	WACHOVIA BANK, NATIONAL ASSOCIATION, as a Lender and as Syndication Agent
	By: /s/ Lawrence P. Sullivan
	Name: Lawrence P. Sullivan Title: Director

	COBANK, ACB, as a Lender and as Co-Documentation Agent
	By: /s/ Raymond Haley
	Name: Raymond Haley Title: Vice President

	LASALLE BANK NATIONAL ASSOCIATION, as a Lender and as Co-Documentation Agent
	By: /s/ Meghan C. Payne
	Name: Meghan C. Payne Title: First Vice President

	U.S. BANK NATIONAL ASSOCIATION, as a Lender
	By: /s/ David F. Higbee
	Name: David F. Higbee Title: Vice President

	UNION BANK OF CALIFORNIA, N.A., as a Lender
	By: /s/ Susan K. Johnson
	Name: Susan K. Johnson Title: Vice President

	BANK HAPOALIM B.M., as a Lender
	By: /s/ James P. Surless
	Name: James P. Surless Title: Vice President

	By: /s/ Laura Anne Raffa
	Name: Laura Anne Raffa Title: Executive Vice President & Corporate Manager

Exhibit 10.03

AMENDED AND RESTATED

FACILITY OPERATING AGREEMENT

for the

MCCLAIN GENERATING FACILITY

by and between

OKLAHOMA MUNICIPAL POWER AUTHORITY

and

OKLAHOMA GAS AND ELECTRIC COMPANY

dated as of July 9, 2004

		Page
ARTICLE I	DEFINITIONS	2
1.01	Definitions	2
1.02	Interpretations	4
ARTICLE II	OPERATIONS AND MAINTENANCE; PAYMENTS	4
2.01	Payments for Service	5
2.02	Settlement of Overdelivery Charges	5
2.03	Invoice or Payment Disputes or Errors	5
2.04	Interest on Late Payments	5
2.05	Audit	6
ARTICLE III	TERM OF AGREEMENT; TERMINATION	6
3.01	Term	6
3.02	Termination	6
ARTICLE IV	REPRESENTATIONS AND WARRANTIES	6
4.01	OG&E Representations	6
4.02	OMPA Representations	7
ARTICLE V	MISCELLANEOUS	8
5.01	Entire Agreement	8
5.02	Amendments	8
5.03	Captions	8
5.04	Notices	8
5.05	Severability	10
5.06	Assignment	10
5.07	No Waiver	10
5.08	Governing Law	10
5.09	No Partnership Created	10
5.10	Consequential Damages	10
5.11	Limitations Application	10
5.12	Survival	11
5.13	Interpretation	11
ARTICLE VI	DISPUTE RESOLUTION	11
6.01	Dispute Resolution; Arbitration	11
6.02	Performance During Dispute	13

Exhibit A Schedules of Duties and Responsibilities
Exhibit B Direct Costs and Direct Assessments

FACILITY OPERATING AGREEMENT

This AMENDED AND RESTATED FACILITY OPERATING AGREEMENT, dated and effective as of July 9, 2004 (this “Agreement”), is by and between the OKLAHOMA MUNICIPAL POWER AUTHORITY, a governmental agency and body politic and corporate of the State of Oklahoma (“OMPA”), and OKLAHOMA GAS AND ELECTRIC COMPANY, an Oklahoma corporation (“OG&E”).

Recitals

A. OMPA and NRG McClain, LLC, a Delaware limited liability company (“NRG McClain”), are joint owners as tenants in common of a 520 MW natural gas-fired combined cycle electric generating facility located in McClain County, Oklahoma (the “Facility”) owning a 23% and 77%, respectively, interest in the Facility (the respective ownership interests in the Facility are hereinafter referred to as “Ownership Ratio”);

B. Pursuant to the Asset Purchase Agreement dated as of August 18, 2003 by and between OG&E and NRG McClain, OG&E has agreed to purchase all of NRG McClain’s right, title and interest in the Facility (the “Power Plant Asset Purchase Agreement”) and will become the owner of NRG McClain’s right, title and interest in the Facility upon closing of the transactions contemplated by and in accordance with the Power Plant Asset Purchase Agreement (the “Power Plant Closing”);

C. Effective as of the date of the Power Plant Closing (the “Effective Date”), OMPA and OG&E own the Facility as tenants in common in accordance with the Amended and Restated Ownership and Operation Agreement (the “O&O Agreement”) to be entered into by and between OMPA and OG&E prior to the Effective Date;

D. Pursuant to the Operating and Maintenance Agreement dated as of August 25, 2003, by and between OG&E and OMPA (the “Transmission O & M Agreement”), OG&E agreed to provide operation and maintenance services with respect to the transmission assets (the “Transmission Assets”) of the Facility effective as of the Power Plant Closing;

E. Effective as of the Effective Date, OMPA and OG&E agree that OG&E will also provide operation and maintenance services as they relate to the generation assets (the “Generation Assets”) of the Facility; and

F. OMPA and OG&E agree that the operation and maintenance services to be provided by OG&E with respect to the Facility shall be exclusively regulated by (i) this Agreement as they relate to the Generation Assets, and (ii) by the Transmission O&M Agreement as they relate to the Transmission Assets.

Agreement

NOW THEREFORE, in consideration of the mutual covenants and agreements set forth in this Agreement, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

ARTICLE I

DEFINITIONS

1.01 Definitions. Terms not otherwise defined in this Agreement shall have the same meanings as set forth in the O&O Agreement. As used in this Agreement, the following terms shall have the meanings specified in this Section 1.01:

“AAA” has the meaning given to it in Section 6.01(c).

“Agreement” has the meaning given to it in the introductory paragraph hereto.

“Approved Capital Budget” means the two year Capital Budget prepared by the Operator pursuant to Section 1(f) of Exhibit A and approved by the Executive Committee pursuant to Section 1(f) of Exhibit A, as may be modified in writing in accordance with the terms of this Agreement.

“Approved Operating Budget” means the Operating Budget prepared and approved by the Executive Committee pursuant to Section 3.04 of the O&O Agreement.

“Approved Operating Plan” means the five year Operating Plan (including major maintenance and capital repairs, and recommended improvements and additions) prepared by Operator based on each Owner’s proposed schedule for dispatch of the Facility for the same period pursuant to Section 1(a) of Exhibit A and approved by the Executive Committee pursuant to Section 1(c) of Exhibit A, as maybe modified in writing in accordance with the terms of this Agreement.

“Consumables” means water treatment chemicals, reagents arid other chemicals, lubrication fluids and filters, hydraulic fluids and filters, air filters, ordinary fasteners (nuts, bolts, flails, etc., which are customarily readily available on normal commercial turns), light bulbs and fluorescent tubes, ordinary gasket materials, gloves, flashlights, batteries, disposable safety equipment and first aid supplies, replacement hand tools, solder and welding rods, all supplies for maintenance and plant cleaning materials and supplies, and all other items commonly considered to be consumables within operations of similar facilities.

“Demand” has the meaning specified in Section 6.01(c).

“Dispatch Schedule” means the schedule that shows the required generation and fuel for the relevant time period as published by Owner.

“Environmental Incident” means an environmentally-related event at a Facility that a) has a material impact on human health, welfare or the environment or has the potential to cause such an impact, b) is or has the potential to be a material breach of compliance with any environmental laws, rules or regulations, c) attracts or has the potential to attract widespread negative media attention, and/or d) represents or has the potential to represent a material adverse economic impact on Facility operations.

“Facility” means the electric generation facility located on the Site and associated natural gas, water and waste water pipelines, pumping and meter stations and electric facilities on the Owners’ side of the interconnection point, in each case, including any additions, expansions, enhancements, improvements and betterments.

“Facility Employees” means the suitable, qualified, competent and experienced personnel employed by Operator to provide Operator’s operation and maintenance services in accordance with this Agreement.

“Hazardous Waste” means waste with inherent properties, which make such waste dangerous to manage by ordinary means, including chemicals and other wastes defined as hazardous at any time during the term of this Agreement by the State of Oklahoma or by any applicable Legal Requirements.

“Legal Requirement” means all laws, statutes, codes, ordinances, Permits, orders, awards, judgments, decrees, injunctions, rules, regulations, authorizations, consents, approvals, orders, franchises, licenses, directions and requirements of all governments or governmental units, courts or arbitrators, which now or at any time hereafter may be applicable to or affect the Facility or any part thereof or any streets, alleys, passageways, sidewalks, curbs, or gutters adjoining the Facility or any part thereof or any use or condition of the Facility or any part thereof or the acquisition, construction, ownership, use or operation of the Facility or any part thereof, except those the non-compliance as to which will not have a material adverse effect on the acquisition, construction, ownership or operation of the Facility.

“LTSA” means that certain Long Term Service Agreement, dated as of December 29, 1999, by and between OG&E and General Electric International, Inc., as such agreement has been or may be amended, supplemented, restated or otherwise modified.

“OG&E” has the meaning given to it in the recitals hereto.

“O&O Agreement” has the meaning given to it in the Recitals.

“OMPA” has the meaning given to it in the recitals hereto.

“O&M Manual” means the operating manuals for the Facility provided by any construction contractor pursuant to any contract for the construction of the Facility, and the operating data, design drawings, specifications, vendor manuals, and similar materials provided by an Owner or any construction contractor to Operator with respect to the Facility.

“Permits” means all of the consents, approvals, authorizations, directions, licenses, waivers and permits issued by any federal, state or local agency or authority to an Owner or the Operator with respect to the ownership, construction, operation and maintenance of the Facility in a safe and commercially sound manner.

“Plant Expenses” means all costs and expenses associated with the services to be provided by the Operator under this Agreement (adjusted, to the extent applicable, for payments

by Owners of their Variable Operating Maintenance Share). Plant Expenses are generally divided into Direct Costs (including a mark-up of 5% of all Direct Costs) and Direct Assessments as listed on Exhibit B hereto. OMPA and OG&E agree that Direct Costs and Direct Assessments are directly related to the operation of the Facility, and that the 5% mark-up with respect to Direct Costs represents a reasonable approximation of administrative and general costs that are directly related to the operation of the Facility but not specifically traceable except with undue difficulty. OG&E and OMPA further agree that the account numbers listed on Exhibit B with respect to the Direct Costs and the Direct Assessments, respectively, reflect the current list of such accounts, but that such account numbers may change from time to time to adequately reflect all Plant Expenses to be allocated between OG&E and OMPA.

“Prudent Operating Practices” has the meaning ascribed to in the O&O Agreement.

“Rules” has the meaning specified in Section 6.01(c).

“Site” means the parcel of land described in the Special Warranty Deed set forth in Section 2.01(a)(i) of the Disclosure Schedule to the Asset Purchase Agreement, dated as of December 13, 2000, between OMPA and Duke Energy McClain, LLC, a Delaware limited liability company, pursuant to which OMPA acquired a 23.0% undivided interest in the Power Plant as a tenant in common.

1.02 Interpretations. In this Agreement, unless clear contrary intention appears: (i) the singular number includes the plural number and vice versa; (ii) reference to any Person includes such Person’s successors and assigns but, if applicable, only if such successors and assigns are permitted by this Agreement, and reference to a Person in a particular capacity excludes such Person in any other capacity; (iii) reference to any gender includes each other gender; (iv) reference to any agreement (including this Agreement), document or instrument means such agreement, document or instrument as amended or modified and in effect from time to time in accordance with the terms thereof and, if applicable, the terms hereof; (v) reference to any Article, Section, Schedule or Exhibit means such Article, Section, Schedule or Exhibit to this Agreement, and references in any Article, Section, Schedule, Exhibit or definition to any clause means such clause of such Article, Section, Schedule, Exhibit or definition; (vi) “hereunder,” “hereof,” “hereto,” “herein” and words of similar import are reference to this Agreement as a whole and not to any particular Section or other provision hereof; (vii) relative to the determination of any period of time, “from” means “from and including,” “to” means “to but excluding” and “through” means “through and including”; (viii) “including” (and with correlative meaning “include”) means including without limiting the generality of any description preceding such term; and (ix) reference to any law (including statutes and ordinances) means such law as amended, modified, codified or reenacted, in whole or in part, and in effect from time to time, including rules and regulations promulgated thereunder.

ARTICLE II

OPERATIONS AND MAINTENANCE; PAYMENTS

Operations and Maintenance Services. OMPA acknowledges and agrees that OG&E will become, as of the Effective Date, the Operator of the Facility pursuant to the Ownership and Operation Agreement. OG&E’s sole obligation pursuant to this Agreement shall be to make available to OMPA those operations and maintenance services to be provided with respect to the Facility by OG&E in accordance with Exhibit A to this Agreement and any major maintenance contracts for which OMPA is obligated to make payments pursuant to Section 2.02, including in each case, to the extent of OMPA’s Ownership Ratio, any damages or other amounts payable to such other parties thereunder. In connection therewith, OG&E shall be solely liable for all payments to be made in providing the operation and maintenance services listed on Exhibit A hereto and shall have sole responsibility for the obligations of the “Owner” under Exhibit A. For this purpose, arrangements with third parties for services that are incidental to the primary function of the Facility, e.g., an arrangement for the repair or major maintenance of the Facility, shall not be treated as a contract for the operation of the Facility, provided that the scope of any such arrangement is confined to services that are incidental; the duration of any such arrangement is limited to the period of time needed to perform such services; and the payments for such services under any such arrangement are a substantially predetermined amount (including, e.g., “cost plus”) which is not based on the revenues or profits that may be derived from the Facility.

2.01 Payments for Service. OG&E shall invoice OMPA monthly for OMPA’s Ownership Ratio of the Plant Expenses adjusted, to the extent applicable, for OG&E’s and/or OMPA’s Variable Operating Maintenance Share (as defined in the O&O Agreement).

2.02 Settlement of Overdelivery Charges. OG&E and OMPA are each parties to separate agreements for transmission of fuel to the Power Plant with a third-party provider, Oneok Transportation, LLC (“Oneok”). Pursuant to an understanding among OG&E, OMPA and Oneok, OG&E will be charged by Oneok any same day or next day overdeliveries caused by either OG&E and OMPA. OG&E and OMPA therefore agree that OG&E may invoice OMPA in accordance with Section 2.01 of this Agreement on a monthly basis for any overdelivery charges caused by OMPA.

2.03 Invoice or Payment Disputes or Errors. If either OG&E or OMPA discovers an error in the amount of any invoice or payment made pursuant to this Article II or if OMPA disputes a payment requested pursuant to this Article II, such party shall notify the other party within 60 days of discovery of such dispute or error, provided that neither party shall be entitled to correction of any such error if notice of such error is not delivered in writing to the other party within three years of the applicable invoice or payment. If OMPA disputes the amount of any invoice, it shall nevertheless pay the full amount of such invoice, subject to a right to a refund if the dispute is resolved in OMPA’s favor, and failure to pay such amount in dispute shall be deemed to be a default hereunder. Any disputes resulting from this Article II shall be settled in accordance with the provisions of Article VI.

2.04 Interest on Late Payments. Any amounts (a) disputed and subsequently found to have been correctly invoiced or owed, or (b) not timely paid in accordance with this Agreement shall accrue interest at the lesser of (i) the then effective prime rate of Citibank, N.A. plus 5%, or (ii) the highest rate permitted by applicable law, from the day on which such amounts become due and owing to the day on which such amounts and the interest thereon are paid. OMPA and OG&E intend that this Agreement shall at all times comply with applicable law now or hereafter in effect governing interest payable hereunder. If the applicable law is ever revised, repealed, or judicially interpreted so as to render usurious any amount called for under this Agreement, then all excess amounts theretofore collected shall be credited to the then applicable principal balance hereunder or be refunded, and this Agreement shall immediately be deemed to have been reformed and the amounts thereafter collected hereunder reduced, without the necessity of the execution of any new document, so as to comply with the then applicable law, but to permit the recovery of the fullest amount otherwise called for hereunder.

2.05 Audit. During ordinary business hours and upon reasonable notice to OG&E, OMPA may inspect, copy and audit OG&E’s books, records, accounts, ledgers, time cards, estimates, schedules, correspondence and other documents related to OG&E’s performance of its obligations hereunder and amounts due to OG&E hereunder; provided, however, that any audit of line item “Salaries – Incentive Pay” listed on Exhibit B hereto shall be limited to determining that any payments made by OG&E to employees at the Facility have been made consistent with payout amounts received by employees of OG&E at other power plants. OG&E agrees to keep such records for five years following their respective preparation (at which time it will be permitted to destroy such books and records in the ordinary course of business) and will furthermore keep any such books and records not previously destroyed in the ordinary course of business, for five years after the termination of this Agreement, and shall provide copies to OMPA upon request, at OMPA’s expense. OMPA’s acceptance or approval or payment of OG&E’s charges shall not operate as a waiver of OMPA’s right to audit OG&E in accordance with this Section 2.05.

ARTICLE III

TERM OF AGREEMENT; TERMINATION

3.01 Term. This Agreement shall become effective as of the Effective Date and shall remain in effect until, and shall terminate automatically without any further action by the parties hereto on the Termination Date as defined in the O&O Agreement.

3.02 Termination. Notwithstanding anything in Section 2.01 to the contrary, upon termination of this Agreement pursuant to Section 3.01, and in addition to any amounts payable by OMPA through the effective date of such termination pursuant to Article II, OG&E shall be entitled to a payment equal to OMPA’s Ownership Ratio of all ordinary and necessary costs, losses or expenses incurred by OG&E as a direct consequence of the termination, including costs for claims arising out of the termination of subcontracts and costs incurred in assisting OG&E and OMPA by preserving and protecting work in progress.

ARTICLE IV

REPRESENTATIONS AND WARRANTIES

4.01 OG&E Representations. OG&E represents and warrants to OMPA as follows:

(a) Standing. OG&E is a corporation duly formed and validly existing under the laws of the State of Oklahoma. OG&E has full corporate power and authority to execute and deliver this Agreement and to perform its obligations hereunder. OG&E is qualified, and during the term of this Agreement shall continue to be qualified, to do business in the State of Oklahoma. The execution and delivery by OG&E of this Agreement and the performance by OG&E of its obligations hereunder have been duly and validly authorized by all requisite corporate action on the part of OG&E. The execution and delivery by OG&E of this Agreement do not, and the performance by OG&E of its obligations under this Agreement will not, violate any provision of any laws, OG&E’s constitutive documents or any indenture, agreement or instrument to which OG&E is a party, or by which OG&E or its property may be bound or affected. This Agreement has been duly and validly executed and delivered by OG&E and constitutes the legal valid and binding obligation of OG&E enforceable against OG&E in accordance with its terms, except as the same may be limited by bankruptcy, insolvency, reorganization, arrangement, moratorium or other similar laws relating to or affecting the rights of creditors generally, or by general equitable principles.

(b) No Violation of Law. OG&E is not in violation of any applicable laws or any judgment entered by any federal, state or local governmental authority, which violations or judgments, individually or in the aggregate, would affect OG&E’s ability to perform its obligations under this Agreement. Neither the execution, delivery and performance by OG&E of its obligations under this Agreement, nor the consummation of the transactions contemplated hereby, will violate any authorizations, consents, exemptions, decrees, licenses, policies, interpretations, guidelines, permits, certificates, regulations, orders and approvals of and from any federal, state, county or local governmental entity of which OG&E is or upon exercise of reasonable diligence should be aware or any laws, rules, regulations or orders of any Governmental Authority.

4.02 OMPA Representations. OMPA represents and warrants to OG&E as follows:

(a) Standing. OMPA is a governmental agency and body politic and corporate of the State of Oklahoma, validly existing and in good standing under the laws of the State of Oklahoma. OMPA has full power and authority to enter into this Agreement and to perform its obligations hereunder. The execution and delivery by OMPA of this Agreement and the performance by OMPA of its obligations hereunder have been duly and validly authorized by its Board of Directors, no other action on the part of OMPA being necessary. The execution and delivery by OMPA of this Agreement do not, and the performance by OMPA of its obligations under this Agreement will not, violate any provision of any laws, Title 11, Sections 24-101 et seq. of the Oklahoma Statutes, the constitutive documents of OMPA or any indenture, agreement or instrument to which OMPA is a party, or by which OMPA’s property may be bound or

affected. This Agreement has been duly and validly executed and delivered by OMPA and constitutes the legal, valid and binding obligation of OMPA enforceable against OMPA in accordance with its terms except as the same may be limited by bankruptcy, insolvency, reorganization, arrangement, moratorium or other similar laws relating to or affecting the rights of creditors generally, or by general equitable principles

(b) No Violation of Law. OMPA is not in violation of any applicable laws or any judgment entered by any federal, state or local governmental authority, which violations or judgments, individually or in the aggregate, would affect OMPA’s ability to perform its obligations under this Agreement. Neither the execution, delivery and performance by OMPA of its obligations under this Agreement, nor the consummation of the transactions contemplated hereby, will violate any authorizations, consents, exemptions, decrees, licenses, policies, interpretations, guidelines, permits, certificates, regulations, orders and approvals of and from any federal, state, county or local governmental entity of which OMPA is or upon exercise of reasonable diligence should be aware or any laws, rules, regulations or orders of any Governmental Authority.

ARTICLE V

MISCELLANEOUS

5.01 Entire Agreement. This Agreement, the O&O Agreement, the Schedule and Exchange Agreement, the Transmission Services Agreement, the Fuel Agreement, the Market Dispatch Agreement and the Service Agreement For Power Sales Between OMPA and OG&E contain the entire understanding of the parties with respect to the subject matter hereof and thereof and supersede all prior agreements and commitments with respect thereto, including that certain Memorandum of Understanding regarding the O&O Agreement between OG&E and OMPA dated September 15, 2003. There are no oral understandings, terms or conditions and neither party has relied upon any representation, expressed or implied, not contained in this Agreement or the agreements expressly referenced herein. This Agreement may be signed in counterparts.

5.02 Amendments. No change, amendment, or modification of this Agreement shall be valid or binding upon the parties hereto unless such change, amendment, or modification shall be in writing and duly executed by the parties hereto.

5.03 Captions. The captions and subheadings contained in this Agreement are for convenience and reference only and in no way define, describe, extend, or limit the scope or intent of this Agreement or the intent of any provision contained herein.

5.04 Notices. Except as otherwise expressly provided herein, any notice, demand, offer, or other instrument required or permitted to be given pursuant to this Agreement shall be in writing, signed by the party giving such notice, demand, offer, or other instrument and shall be delivered by telecopier, hand delivery, registered or certified mail, return receipt requested, postage prepaid, or nationally recognized overnight courier to the other party at the address set forth below:

If to OMPA:
	Oklahoma Municipal Power Authority
	Street Address: 2300 East Second Street Edmond, OK 73034 Post Office Address: P.O. Box 1960 Edmond, OK 73083-1960
	Facsimile No. (405) 359-1071 Attn: General Manager

With a copy to:
	Oklahoma Municipal Power Authority
	Street Address: 2300 East Second Street Edmond, OK 73034 Post Office Address: P.O. Box 1960 Edmond, OK 73083-1960
	Facsimile No. (405) 359-1071 Attn: General Counsel

If to OG&E:
	Oklahoma Gas and Electric Company PO Box 321 Oklahoma City, Oklahoma 73101-0321 Attention: Jack T. Coffman, Senior Vice President, Power Supply Facsimile No.: (405) 553-3198

With a copy to:
	Jones Day 77 West Wacker Drive, Suite 3500 Chicago, Illinois 60601-1692 Attention: Peter D. Clarke Facsimile No.: (312) 782-8585

Each party shall have the right to change the place to which notice, demand, offer, or other instrument shall be sent or delivered by similar notice sent in like manner to the other party. The effective date of any notice, demand, offer, or other instrument issued pursuant to this Agreement shall be the date (a) of delivery, if delivered by telecopier with answer back confirmation, (b) when delivered, if hand delivered, (c) if sent by overnight courier, one business day after delivery to such courier, and (d) if sent by registered or certified mail, three business days after being deposited in U.S. mail.

5.05 Severability. The invalidity of one or more of the provisions or sections contained in this Agreement shall not affect the validity of the remaining portion of the Agreement so long as the material purposes of this Agreement can be determined and effectuated. In the event that any portion or all of this Agreement is held to be void or unenforceable, the parties agree to negotiate in good faith to reach an equitable agreement on such portion that is void or unenforceable which shall effect the intent of the parties as set forth in this Agreement. In the event that the parties do not mutually agree on what changes to make, if any, within 60 days after the such portion or all of this Agreement is held to be void or unenforceable, either party may initiate the dispute resolution procedures set forth in Article VI with respect to the obligation to negotiate in good faith.

5.06 Assignment. This Agreement shall be binding upon, shall inure to the benefit of, and may be performed by, the successors and assigns of the parties hereto. No assignment, pledge, or other transfer of this Agreement by either party shall be made without the other party’s prior written consent, nor shall it operate to release the assignor, pledgor, or transferor from any of its obligations under this Agreement.

5.07 No Waiver. Any failure of either party to enforce any of the provisions of this Agreement or to require compliance with any of its provisions at any time during the pendency of this Agreement shall in no way affect the validity of this Agreement, or any part hereof, and shall not be deemed a waiver of the right of either party thereafter to enforce any and each such provision.

5.08 Governing Law. THIS AGREEMENT SHALL BE GOVERNED BY, CONSTRUED, INTERPRETED AND ENFORCED IN ACCORDANCE WITH, THE SUBSTANTIVE LAW OF THE STATE OF OKLAHOMA WITHOUT REFERENCE TO ANY PRINCIPLES OF CONFLICTS OF LAWS THEREOF.

5.09 No Partnership Created. Nothing contained in this Agreement shall be construed as constituting a joint venture or partnership between OMPA and OG&E.

5.10 Consequential Damages. Neither party shall in any event be responsible or liable to the other party for consequential damages, including, without limitation, liability for loss of use of the Facility or existing property, loss of profits, loss of product or business interruption, however caused, except to the extent any indemnification hereunder is deemed to be consequential damages.

5.11 Limitations Application. Neither party makes any representations, covenants, warranties or guarantees, express or implied, other than those expressly set forth herein. The parties’ rights, liabilities, responsibilities and remedies with respect to the obligations to be performed under this Agreement, whether in contract or otherwise, shall be exclusively those expressly set forth in this Agreement.

5.12 Survival. The provisions of Section 2.04, Section 5.11, this Section 5.12 and Article VI shall survive the termination of this Agreement without limitation.

5.13 Interpretation. The parties intend that this Agreement shall comply with Rev. Proc. 97-13, and this Agreement shall be interpreted accordingly.

ARTICLE VI

DISPUTE RESOLUTION

6.01 Dispute Resolution; Arbitration.

(a) Any dispute or claims arising under this Agreement which cannot be resolved by the parties through negotiation by the parties’ managers shall be referred to a panel consisting of a senior executive of each party, with authority to decide or resolve the matter in dispute, for review and resolution. Such senior executives shall attempt to meet and resolve the dispute within 30 days.

(b) If the parties are unable to resolve a dispute as provided in Section 6.01, each party has the right to (i) pursue any legal and/or equitable remedies in the District Court of Oklahoma County or such other court of proper jurisdiction or (ii) seek to arbitrate the dispute using the procedures specified in Section 6.01(c); which election shall be binding upon such party with respect to the dispute at issue.

(c) If so elected by a party and the other party agrees in writing, a dispute shall be arbitrated in accordance with the following procedures:

(1) At the request of either party upon written notice to that effect to the other party (a “Demand”), the dispute shall be finally settled by binding arbitration before a panel of three arbitrators in accordance with the Commercial Arbitration Rules (the “Rules”) of the American Arbitration Association (“AAA”) then in effect, except as modified herein. The Demand must include statements of the facts and circumstances surrounding the dispute, the legal obligation breached by the other party, the amount in controversy and the requested relief accompanied by all relevant documents supporting the Demand.

(2) Unless the parties otherwise agree, arbitration shall be held in the headquarters cities of the parties alternating locations between sessions or meetings with the arbitrator(s) and beginning, for each arbitrated dispute, with the headquarters city of the party not making the Demand. The arbitration shall be governed by the United States Arbitration Act, 9 U.S.C. §§ 1 et seq.

(3) Each party shall select one arbitrator within ten days of the receipt of the Demand, or if such party to the dispute fails to make such selection within ten days from the receipt of the Demand, the AAA shall make such appointment. The two arbitrators thus appointed shall select the third arbitrator, who shall act as the chairman of the panel. If the two arbitrators fail to agree on a third arbitrator within 30 days of the selection of the second arbitrator, the AAA shall make such appointment.

(4) The award shall be in writing (stating the award and the reasons therefor) and shall be final and binding upon the parties, and shall be the sole and exclusive remedy between the parties regarding any claims, counterclaims, issues, or accountings presented to the arbitral panel. The arbitral panel shall be authorized in its discretion to grant pre-award and post-award interest at commercial rates. Judgment upon any award may be entered in any court having jurisdiction. For purposes of a pre-arbitral injunction, pre-arbitral attachment or other order in aid of arbitration proceedings, the parties hereby agree to submit to the jurisdiction of the United States federal courts located in, and the local courts of, the State of Oklahoma. Each of the parties irrevocably waives, to the fullest extent permitted by law, any objection it may now or hereafter have to the jurisdiction of such courts or the laying of the venue of any such proceeding brought in such a court and any claim that any such proceeding brought in such a court has been brought in an inconvenient forum. Each of the parties hereby consents to service of process by registered mail at its address set forth herein and agrees that its submission to jurisdiction and its consent to service of process by mail is made for the express benefit of the other party.

(5) This Agreement and the rights and obligations of the parties shall remain in full force and effect pending the award in any arbitration proceeding hereunder.

(6) Unless otherwise ordered by the arbitrators, each party shall bear its own costs and fees, including attorneys’ fees and expenses. The parties expressly agree that the arbitrators shall have no power to consider or award any form of damages barred by Section 5.10, or any other multiple or enhanced damages, whether statutory or common law.

(7) The parties, to the fullest extent permitted by law, hereby irrevocably waive and exclude any rights of application or appeal or rights to state a special case for the opinion of the courts or any other recourse to the court system other than to enforce the agreement to arbitrate pursuant to this Section 3.13(c) for attachment or other order in aid of arbitration proceedings or to enforce the award of the arbitral panel.

(8) During the pendency of any dispute, the parties shall continue to perform the obligations imposed upon them under this Agreement to the fullest extent possible, consistent with their positions in dispute.

6.02 Performance During Dispute. During the pendency of any dispute, the parties shall continue to perform the obligations imposed upon them under this Agreement to the fullest extent possible, consistent with their positions in dispute.

IN WITNESS WHEREOF, the parties have executed this Agreement as of the date first above written.

	OKLAHOMA MUNICIPAL POWER AUTHORITY
	By:	/s/ Roland Dawson Name: Roland Dawson Title: General Manager and Assistant Secretary

	OKLAHOMA GAS AND ELECTRIC COMPANY
	By:	/s/ Jack T. Coffman Name: Jack T. Coffman Title: Senior Vice President, Power Supply

EXHIBIT A
to
Facilities Operating Agreement,

Operations & Maintenance

Schedule of Duties and Responsibilities

Operator shall administer, operate and maintain the Facility in accordance with the Approved Operating Plan, the Approved Operating Budget, the Approved Capital Budget, the Dispatch Schedule, Prudent Operating Practices, all Legal Requirements, the O&M Manuals and the relevant insurance policies. Operator shall be responsible for and perform the following tasks:

1. Administrative. Plan, budget, schedule and conduct all business related to the operation and maintenance of the Facility.

(a) Operating Plan. Operator shall provide to the Executive Committee a five year Operating Plan, including budget estimates, which shall set forth all underlying assumptions (including emissions data) and implementation plans in connection with the operation and maintenance of the Facility. The Operating Plan shall include: (a) routine operational services; (b) routine repairs and maintenance for each part of the Facility; (c) information regarding the inventory and proposed procurement of equipment, spare parts, tools and, in the case of major equipment, the residual life thereof; (d) routine operational information, general operating data and other Facility data; (e) scheduled outages; (f) consumable items; (h) staffing plans (i) Operator’s environmental plan describing any actions necessary to ensure that the Facility will comply with all applicable environmental Legal Requirements; and (j) Operator’s recommendations on matters affecting the operation and maintenance of the Facility, including any relevant capital improvements, additions or other expenditures for the Year.

(b) Operating Budget. Operator shall prepare and provide to the Executive Committee a Budget Estimate in accordance with Section 3.04(b) of the O&O Agreement. Furthermore, Operator shall prepare (based on the Budget Estimate) and provide, and the Executive Committee shall approve, the Operating Budget in accordance with Section 3.04(b) of the O&O Agreement. The Operating Budget shall be itemized on a monthly GAAP basis and shall incorporate all project operating costs.

(1) Each Owner shall provide the Operator a Dispatch Schedule, including “best estimates” for capacity factor, expected load cycling duty and quality and type of fuel.

(2) Operator shall prepare the Operating Plan, the Budget Estimate and the Operating Budget based on the Dispatch Schedule and shall add proposed scheduled outage information. Any modifications to the Approved Operating

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Plan or the Approved Operating Budget required as a result of changes in the foregoing not attributable to Operator should be deemed modifications made at the Executive Committee’s request.

(3) Not later than (i) December 31, 2003, with respect to the Year in which the Effective Date occurs, and (ii) ninety (90) days prior to the beginning of each subsequent Year, Operator shall submit to the Executive Committee, for the Executive Committee’s review and approval, the proposed Operating Plan.

(4) Within thirty (30) days of the Executive Committee’s receipt of a proposed Operating Plan and the Budget Estimate, the Executive Committee shall provide comments to Operator with respect thereto and request any additions, changes or modifications thereto. Not more than ten (10) days following Operator’s receipt of the Executive Committee’s comments on the proposed Operating Plan and Budget Estimate, the Executive Committee and Operator shall meet to discuss the terms of such Operating Plan and Budget Estimate and the Executive Committee’s requested changes thereto. Operator and the Executive Committee shall use reasonable efforts to reach agreement thereon. Upon approval by the Executive Committee, such Operating Plan shall be the Approved Operating Plan and the Budget Estimate shall be the basis for the Approved Operating Budget for the applicable Year.

(d) Operating Budget Overruns/Underruns. If at any time Operator reasonably anticipates that the aggregate costs of operating and maintaining the Facility may exceed the amount set forth in the applicable Approved Operating Budget by more than 10% or be 10% below the amount set forth in the applicable Approved Operating Budget, Operator shall promptly advise the Executive Committee of such situation by Notice and propose for the Executive Committee’s approval any changes to the Approved Operating Budget which Operator considers necessary.

(e) Revisions to Operating Plan and Operating Budget. At the request of the Executive Committee, or to the extent Operator itself determines necessary or appropriate, Operator shall update the applicable Operating Plan or Operating Budget at such times as may be appropriate to reflect changes in assumptions made in their preparation. These updates shall be submitted to the Executive Committee for its approval. In addition, Operator may, at any time, provide proposed revisions to any Operating Plan or Operating Budget to the Executive Committee for consideration. Unless otherwise specified by the Executive Committee, such revisions shall become effective for purposes of this Agreement from the date of the Executive Committee’s approval thereof (if approved), and shall be applied to the first calendar month to which such revision relates following such approval or resolution.

(f) Capital Budget. In conjunction with, the preparation of the Operating Plan and Operating Budget, Operator shall determine the necessity for and cost of capital improvements. Major Capital Projects and routine annual capital improvements shall be included in the Operating Plan. A two-year Capital Budget shall be prepared and submitted to Owner by Operator at the time of submission of the Operating Plan and Operating Budget. The Executive Committee shall review and approve the two-year Capital Budget as provided herein.

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(g) Inventory. Prepare a spare parts and inventory program for approval by the Executive Committee in accordance with Section 3.03 of the O&O Agreement.

(h) Security Program. Develop and implement a security program, including provisions for third-party access to the site and Facility.

(i) Safety Procedures. Develop and maintain safety procedures, a safety manual, and an effective safety program including fire and explosion safety measures.

(j) Operating Workforce. Develop an effective and sufficient operating work force through appropriate on-going hiring, training, administration, and compensation programs in conjunction with Owners.

(k) Financial Reports. Provide detailed financial and operating reports with Approved Operating Budget comparisons.

(l) Periodic Reports. Prepare and provide periodic reports on behalf of and at the request of Owners.

(m) Information Requests. Respond in a timely manner to written requests for Facility information from Owners.

(n) Employment Insurance. Obtain and maintain such workers’ compensation, unemployment and other employee related insurance as is required by applicable state law.

(o) Maintenance Program. Develop, implement and regularly update a maintenance program that is intended to minimize life cycle maintenance costs and maximize intervals between major maintenance outages, does not invalidate equipment manufacturers’ warranties, specifications and recommendations or Prudent Operating Practices, and meets the requirements of the authorized insurance inspector.

(p) O&M Consulting. Provide such operating and maintenance consulting services to Owners as it may deem necessary or desirable. Costs of such services shall be included in the Two Year Operating Budget.

(q) Insurance. Obtain and maintain required and appropriate levels of insurance.

(r) Permits. Reasonably assist Owners in obtaining all necessary Permits in connection with the Facility.

(s) Meter Reading. Read and confirm readings of all meters associated with the Facility.

(t) Accounting Records. Provide accounting records and data to support monthly, quarterly, year-end or other reports.

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(u) Invoices. Review and approve all invoices. Obtain Owners approval for costs that exceed the Approved Operating Budget limits.

(v) Cost Ledgers. Maintain true, complete and accurate cost ledgers and accounting records in accordance with generally accepted accounting principles (“GAAP”).

(w) Notices. Provide appropriate notices to Owners in a timely manner.

(x) Revisions. Provide proposed revisions to the Operating Plan and the Operating Budget based on changes in Owners expected Dispatch Schedule for the relevant period, and fuel and/or other contracts. Items approved by Owners will be considered approved additions to the Operating Plan and the Operating Budget.

(y) Adequate Records. Maintain true, complete and accurate operating logs, records and reports necessary or required by applicable Legal Requirements and Project Agreements or beneficial for proper operation and maintenance of the Facility in accordance with Prudent Operating Practices.

(z) Manuals. Maintain drawings, instruction books and operating and maintenance manuals and procedures, and revise drawings and manuals as modifications are made. Cooperate with and assist Owners’ personnel in obtaining and maintaining required Legal Requirements.

(aa) Unrestricted Access. Provide Owners and Owners’ designees with unrestricted access to the Facility in accordance with the normal site safety and security procedures and cooperate with Owners and their designees in all Owner inspections of the Facility. Such inspections may occur on any business day without Notice at any time and shall not unreasonably interfere with personnel safety or the operation and maintenance of the Facility.

2. Operation and Maintenance.

(a) Operate and maintain the Facility in a clean, safe and efficient manner and in accordance with Prudent Operating Practices.

(b) Operate the Facility in accordance with the Approved Operating Plan and the Approved Operating Budget. If a new Operating Plan and/or a new Operating Budget is not timely approved by Owners, operate in accordance with the preceding Approved Operating Plan and/or Approved Operating Budget until a new Operating Plan and/or a new Operating Budget is approved.

(c) Operator may initiate work on a condition that constitutes a safety, environmental issue or something that could damage the plant without prior approval from the Owners. The operator shall notify the Owners as soon as practicable.

(d) Maintain all tools and instruments necessary to operate and maintain the Facility.

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(e) Purchase and inventory spare parts, materials, and supplies (including Consumables and items covered by Plant Office Expenses and Rolling Stock Expenses) as per the approved spare parts program.

(f) Schedule and perform or cause to be performed the work specified in the maintenance program in accordance with the Dispatch Schedule, the Approved Operating Plan, the Approved Operating Budget, Prudent Operating Practices, and all Legal Requirements.

(g) Perform periodic operational checks and tests of equipment in accordance with the equipment manufacturers’ specifications and recommendations, Prudent Operating Practices and all Legal Requirements, and arrange for required environmental or other required specialized equipment tests to be performed.

Maintain records of the foregoing, including: (i) a register of all equipment subject to inspection by governmental authorities; (ii) a register of all test dates and results; and (iii) a register of Facility operating performance data including operating hours and adjustments to expired hours and expired life, all measurements and records required by Permits and Project Agreements, and maintenance of Facility generating and protective equipment.

(h) Evaluate the nature and impact of any equipment failure and if the failure is major or material, promptly provide notice to Owners and review the situation with Owners and mutually agree on a reasonable remedy of the matter.

(i) Provide for necessary and desirable security services for the Facility in accordance with the security program.

(j) Provide for building, structural and yard maintenance services.

(k) Order, receive and maintain adequate inventories and supplies (parts and Consumables).

(l) Operate and maintain the Facility in such a way as to satisfy all Legal Requirements and Project Agreements, taking such samples and performing and reporting such tests as are required by all Legal Requirements and Project Agreements, and promptly provide Notice to Owner of any areas of Legal Requirements or Project Agreement conflicts, violations or unsatisfactory conditions or test results, including performing all necessary testing and reporting in accordance with Legal Requirements and Project Agreements.

(m) Develop and maintain environmental procedures and an effective environmental program. Dispose of all waste materials, including Hazardous Waste, in accordance with Legal Requirements and Owner’s waste disposal agreements.

(n) The Facility shall be operated by the Operator’s employees and the Operator shall be fully responsible for all the acts and omissions of all of its operators.

(o) Operator shall provide at least the minimum number of suitably qualified, competent and experienced personnel as may be required satisfactorily to carry out the respective parts of the services to the performance of which Operator assigns them. Owners shall review labor costs as a part of the approval process of the Operating Budget.

(p) Complete the delivery of fuel supply, including unloading and inventory as required by the Dispatch Schedule, on a day-to-day basis.

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(q) Operate to achieve the target Equivalent Availability Factor (EAF) for the plant based upon the Approved Dispatch Schedule, and advise Owners of any risks associated with fuel or dispatch issues, including any recommended curtailments.

(r) Maintain a boiler and pressure vessel repair rating of an ‘R-Stamp’.

(s) Provide recommendations to Owners to increase reliability and reduce expenses.

3. Environmental Incident Reporting and Evaluation.

The Operator shall be responsible for immediately notifying all appropriate governmental entities, the Corporate Environmental Health and Safety Department and other deemed appropriate persons in the event of an Environmental Incident. Evidence of all notifications and who was notified shall be placed in the Facility environmental files.

In addition, the Operator shall document and file all critical information regarding each such event.

The Corporate Environmental Health and Safety Department shall be responsible for filing all follow-up reports required by Environmental Law. A copy of such reports shall be placed in the Facility’s environmental files.

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EXHIBIT B
TO

FACILITIES OPERATING AGREEMENT

OPERATIONS & MAINTENANCE — ACCOUNTING MEMORANDUM

Article II Operations and Maintenance shall be further defined as follows:

Each Owner shall pay their respective Ownership Ratio of Direct Costs incurred at the Facility. These costs will include:

Salaries and wages;
Employee pensions, benefits, and payroll taxes;
Other Employee expenses;
Office equipment and other office expense;
Communication expense;
Other direct costs incurred at the power plant; and
Team Share Incentive pay paid to plant employees.

Each Owner shall pay their respective Ownership Ratio of Outside Services which will include any costs associated with the LTSA or its successor.

In addition OMPA will pay a 5% adder only with respect to Direct Costs in #1 above. The adder will not be applied to any other costs.

OMPA will also pay the following costs allocated to the Facility:

Purchase Overhead allocated based on a percentage of the Direct Costs for materials and services;
P-Card Overhead allocated based on a percentage of the Direct Costs related to P-Card purchases;
Computer Equipment Activity allocated based on number of units at location;
Information System Activity Allocation allocated based on actual number of SAP seats per location;
Power Supply Division costs allocated by Nameplate capacity or other agreed to allocation method; and
Assessments for work performed which are for the direct benefit of the Facility provided such costs can be documented as a Power Plant expense.

OMPA will not pay the following types of Assessments: A&G Distrigas, Headcount, Utility Company, or Information Systems or items of a similar nature.

Station Power will be billed at OG&E system average fuel cost for the respective month. The tariff rate will no longer apply to station power.

B-1

In the event a market develops for ancillary services, the parties will mutually negotiate an arrangement that will meet the then applicable tax requirements and tariff requirements while insuring both parties will receive the Ownership Ratio of any revenues derived from such services.

Direct Costs

GL Account Description			GL Account Number
Materials & Supplies Returns (Cr)			601000
Materials & Supplies - Sales Issues			601001
Materials & Supplies - Stock			601002
Materials & Supplies Non Stock			601100
Tools - Unassigned Stock Numbers			601200
Inventory Shrinkage			603100
Office Equip and Other Office Expense			605000
Communications Expense			607000
Utilities			608000
Salaries & Wages - Regular			620000
Salaries & Wages - Overtime			621000
Per diem			622000
Salaries & Wages - Medical/Sickness			629200
Salaries & Wages - Holiday/Vacation			629300
Salaries - Incentive Pay			629500
Temporary Help			631000
Contract Labor			633000
Employee Expenses - Meals			640000
Employee Expenses - Education/Training			640010
Employee Expenses - Other			640020
Employee Expenses - Personal Auto			640030
Employee Expenses-Communication Devi			640040
Trucking Outside			650000
Transportation Maintenance			650100
Transportation Fuel			650110
Fleet Registration Fees			650120
Computer Rentals			670001
Equipment Rentals			670002
Transportation Rentals			670003
Rents - Other			670004
Environmental Expense			676000
Health & Safety Expense			677000
Professional Dues and Subscriptions			680000
Postage			680009
Printing			680010
Miscellaneous Fees and Permits			680015
Professional Services - Legal			682000
Professional Services - Other			682010
Property Insurance			683000
Public Injuries & Damages			684000
Workers Comp Accrual			684010
Empl Pen & Ben-Pension Plan			685000

B-2

Empl Pen and Ben -Training			685003
Empl Pen and Ben - Other			685010
Empl Pen & Ben - Group Life Insurance			685016
Empl Pen & Ben - Group Medical			685017
Empl Pen & Ben- Group Dental			685019
Empl Pen & Ben- Long Term Disability			685020
Empl Pen & Ben- Retirement Savings Plan			685024
Empl Pen & Ben- Retire Saving Restoration Plan			685025
Empl Pen & Ben- Postretirement Life Insurance			685031
Empl Pen And Ben-Physicals, Eyeglass			685033
Misc Gen Exp - Corporate			689000
Misc Gen Exp - Corp Association Dues &			689001
Misc Gen Exp - Conventions/Meetings			689006
Misc Gen Exp - Other			689007
Misc Gen Exp - Power Plants Tours			689011
Taxes - Other - FICA			705020
Taxes - Other - FUTA			705030
Taxes - Other - SUTA			705040
Overhead @5% of Direct Cost

Direct Assessment

Applicable for work performed on behalf of the Facility only

GL Account Description		GL Account Number
Station Power		Separate Calculation
Outside Services including LTSA		632000
Purchasing OH Applied to Cost Center		780003
P-Card OH Applied to Cost Centers		780004
Labor OH Applied		800000
Purchasing		800003
P-Card		800004
Fully Loaded Labor Activity		800100
Fully Loaded OT Labor Activity		800110
Per Diem		800200
Contr Labor Activity		800310
Contr Equip Activity		800320
Contr Pdiem Activity		800330
Contract Labor/Temporary Labor Activity		800500
Computer Equipment at Plant		800850
Computer Equipment Activity		800851
Info System		800871
Internal Personnel Costs (Production Dept. only)		810010
Assessment Other (Production Dept. only)		810020
External Services (Production Dept. only)		810030
Materials & Supplies (Production Dept. only)		810040
Transportation Activity		865010

B-3

Exhibit 10.04

AMENDED AND RESTATED

OWNERSHIP AND OPERATION AGREEMENT

for the

MCCLAIN GENERATING FACILITY

by and between

OKLAHOMA MUNICIPAL POWER AUTHORITY

and

OKLAHOMA GAS AND ELECTRIC COMPANY

dated as of July 9, 2004

		Page
ARTICLE I	DEFINITIONS	1
1.01	Definitions	1
1.02	Interpretations	5
ARTICLE II	OWNERSHIP RATIOS	6
2.01	Ownership Ratios	6
2.02	Changes in Ratios	6
2.03	Waiver of Partition	6
2.04	Admission of New Owner	6
ARTICLE III	OPERATION AND PAYMENT OF COSTS	7
3.01	Operations of the Power Plant	7
3.02	[Intentionally omitted.]	7
3.03	Executive Committee	7
3.04	Payment of Expense: Operating Budget	11
3.05	Claims Treated as Costs of Operation	13
3.06	Books and Records	13
3.07	Fuel Supply	13
ARTICLE IV	ALLOCATION AND SCHEDULING OF NET AVAILABLE OUTPUT	13
4.01	Allocation of Net Available Output	13
4.02	Scheduling of Net Available Output	14
ARTICLE V	LIMITATION OF LIABILITY	14
5.01	Limitation of Liability	14
ARTICLE VI	DAMAGE TO POWER PLANT; END OF OPERATIONS	14
6.01	Damage to, or Condemnation of, th Power Plant	14
6.02	End of Power Plant Operations	16
6.03	Insurance	16
ARTICLE VII	TERM AND TERMINATION	16
7.01	Term	16
7.02	Termination	16
ARTICLE VIII	DEFAULT AND REMEDIES	17
8.01	Default	17
8.02	Remedies	17
ARTICLE IX	MISCELLANEOUS	18
9.01	Governing Law	18
9.02	Dispute Resolution; Arbitration	18
9.03	Force Majeure	20
9.04	Restrictions on Assignments and Transfers	20

-i-

9.05	Attorneys' Fees and Litigation Express	21
9.06	Notices	21
9.07	Waivers	23
9.08	No Reliance	23
9.09	Assumption of Risk	23
9.10	Waiver of Defenses	23
9.11	No Third-Party Beneficiaries	23
9.12	Severability	23
9.13	Independent Counsel	24
9.14	Further Assurances	24
9.15	No Partnership	24
9.16	Ancillary Services	24
9.17	Access	24
9.18	Adjustment	25
9.19	Entire Agreement	25

EXHIBITS AND SCHEDULES

Exhibit A	Amended and Restated Facility Operating Agreement
Exhibit B	Operating Procedures
Schedule 6.03	Insurance Coverages

OWNERSHIP AND OPERATION AGREEMENT

This OWNERSHIP AND OPERATION AGREEMENT, dated as of July 9, 2004 (this “Agreement”), is made and entered into by and between OKLAHOMA MUNICIPAL POWER AUTHORITY, a governmental agency and body politic and corporate of the State of Oklahoma (“OMPA”), and OKLAHOMA GAS AND ELECTRIC COMPANY, an Oklahoma corporation (“OG&E”).

Recitals

A. OMPA and NRG McClain, LLC, a Delaware limited liability company (“NRG McClain”), are joint owners as tenants in common of a natural gas-fired combined cycle electric generating facility nominally rated at 520 MW located in McClain County, Oklahoma (the “Power Plant”), and are parties to the Ownership and Operation Agreement, dated as of March 1, 2001, setting forth certain agreements with respect to the ownership and operation of the Power Plant (the “Original Agreement”).

B. Pursuant to the Asset Purchase Agreement dated as of August 18, 2003 by and between OG&E and NRG McClain, OG&E has agreed to purchase all of NRG McClain’s right, title and interest in the Power Plant (the “Power Plant Asset Purchase Agreement”) and will become the owner of NRG McClain’s right, title and interest in the Power Plant upon closing of the transactions contemplated by and in accordance with the Power Plant Asset Purchase Agreement (the “Power Plant Closing”).

C. Accordingly, OMPA and OG&E have determined to hereby amend and restate the Original Agreement to set forth their agreements with respect to the ownership and operation of the Power Plant subsequent to, effective as of and expressly conditioned upon, the Power Plant Closing.

Agreement

ARTICLE I

DEFINITIONS

1.01 Definitions. As used in this Agreement, the following terms shall have the meanings specified in this Section 1.01:

“AAA” has the meaning given to it in Section 9.02(c)(1).

“Affiliate” means any Person that directly, or indirectly through one or more intermediaries, controls or is controlled by or is under common control with the Person specified. For purposes of this definition, control of a Person means the power, direct or indirect, to direct or cause the direction of the management and policies of such Person whether by contract or

otherwise, and ownership by a Person of twenty five percent (25%) or more of the voting securities or other voting equity interests of another Person shall create a rebuttable presumption that such Person controls such other Person.

“Agreement” has the meaning given to it in the introductory paragraph hereto.

“Ancillary Services” means those services made available by virtue of the Power Plant other than the sale of Capacity, Energy, fuel and capital assets. Such services may include, but shall not be limited to, load following, reserves, storage of fuel and supply or absorption of reactive power.

“Applicable Law” means all laws, statutes, rules, regulations, ordinances and other pronouncements having the effect of law of the United States, any foreign country or any domestic or foreign state, county, city or other political subdivision or of any Governmental Authority.

“Buy-Sell Notice” has the meaning given to it in Section 3.03(i).

“Buy-Sell Procedure” has the meaning given to it in Section 3.03(i).

“Capacity” means the rated continuous ability of the Power Plant to generate Energy and Ancillary Services expressed in megawatts (MW).

“Capital Additions” means additions, improvements and betterments to the Power Plant.

“Claims” means all claims, demands, losses, liabilities and expenses, including reasonable attorney’s fees.

“Claiming Party” has the meaning given to that term in Section 9.03(a).

“Costs of Capital Additions” means those costs incurred or to be incurred to effect Capital Additions.

“Costs of Operation” means all costs attributable to the operation and maintenance of the Power Plant, including all amounts payable under the Operating & Maintenance Agreements or any successor agreement, and, without duplication, all direct administrative and general costs plus cost of repairs, renewals and replacements necessary to assure design capability and reliability or that are required by any Governmental Authority. Costs of Operation shall not include (i) payments in lieu of property Taxes, (ii) any Power Plant Fuel Costs (iii) the financing costs, fees and expenses of an Owner relating to the ownership and acquisition of its interest in the Owned Assets, (iv) Taxes based upon the net income of any

Owner or individually assessed against any Owner’s Ownership Ratio in the Owned Assets or Ownership Ratio in respect of the Net Available Output of the Power Plant or from which any Owner is exempt, and (v) Costs of Capital Additions.

“Demand” has the meaning specified in Section 9.02(c)(1).

“DEMc” means Duke Energy McClain, LLC, a Delaware limited liability company and former owner of an undivided interest in the Power Plant.

“Effective Date” has the meaning given to that term in Section 7.01.

“Elective Capital Additions” means Capital Additions that are not required (i) to operate the Power Plant in accordance with Prudent Operating Practices, (ii) to assure design capability and reliability of the Power Plant, or (iii) by any Governmental Authority or pursuant to any Applicable Law.

“Energy” means electric energy or electricity.

“Executive Committee” means the Executive Committee established pursuant to Section 3.03(a).

“Facility Operating Agreement” means the Amended and Restated Facility Operating Agreement among the Owners and the Operator, as amended from time to time. As provided in Section 3.01(b), as of the date hereof the Facility Operating Agreement shall be between OMPA and OG&E and shall be in the form of Exhibit A.

“Fuel Agreement” means the Contract for Sale and Purchase of Natural Gas dated the date hereof by and between OG&E and OMPA, as amended from time to time.

“Force Majeure” has the meaning given to it in Section 9.03(a).

“Governmental Authority” means any court, tribunal, arbitrator, authority, agency, commission, official or other instrumentality of the United States, any foreign country or any domestic or foreign state, county, city or other political subdivision or similar governing entity, other, in any case, than OMPA.

“Initiating Owner” has the meaning given to it in Section 3.03(i)(1).

“Interests” has the meaning given to it in Section 3.03(i).

“Majority of Members” means Members representing Owners holding in the aggregate more than 50% of the aggregate Ownership Ratios.

“Market Dispatch Sale Agreement” means the OG&E/OMPA Market Dispatch Sale Agreement dated the date hereof by and between OG&E and OMPA, as amended from time to time.

“Member” has the meaning given to it in Section 3.03(b).

“Net Available Output” means the net amount of Capacity available from and Energy, Ancillary Services and all other related products of the Power Plant that can be sold or purchased, produced by the Power Plant from time to time under the operating conditions then existing, including periods when some or all of the Power Plant may be inoperable, after station use.

“Net Generating Capability” means the total amount of Energy which the Power Plant is capable of generating, with due allowance being made for legal, regulatory and physical constraints then existing, less the amount used in the production thereof.

“NRG McClain” has the meaning given in the recitals to this Agreement.

“Offer Period” has the meaning given to it in Section 3.03(i)(1).

“Operating Budget” has the meaning given to it in Section 3.04(b).

“Operating & Maintenance Agreements” means, collectively, the Facility Operating Agreement and the Transmission O&M Agreement.

“Operator” has the meaning given to it in Section 3.01(b). As of the date hereof, the Operator is OG&E.

“Original Agreement” has the meaning given in the recitals to this Agreement.

“Owned Assets” means the assets comprising the Power Plant and which are owned by the Parties as tenants in common.

“Owners” means OG&E and OMPA and any other Person that acquires an interest in the Owned Assets in accordance with the terms of this Agreement.

“Ownership Ratio” has the meaning given to it in Section 2.01.

“Permitted Liens” means any Permitted Liens under the Power Plant Asset Purchase Agreement, provided, however, that clause (j) of such definition may include Liens (as defined in the Power Plant Asset Purchase Agreement), imperfections or failures of title of the types described in clauses (a) through (i) thereof without regard to any contest.

“Person” means any natural person, corporation, general partnership, limited partnership, proprietorship, limited liability company, other business organization, trust, union, association or Governmental Authority.

“Power Plant” has the meaning given to it in the recitals hereto.

“Power Plant Asset Purchase Agreement” has the meaning given to it in the recitals hereto.

“Power Plant Fuel Costs” means all costs for supply, transportation and storage of fuel used in the Power Plant.

“Prudent Operating Practices” means the practices, methods and acts (including but not limited to the generally accepted practices, methods and acts engaged in or approved by the operators of similar electric generating facilities) which at the time such practice, method or act is employed, and in the exercise of reasonable judgment in light of the facts known at such time, would be expected to accomplish the desired result in a workmanlike manner, consistent with (a) Applicable Laws and governmental requirements, and (b) reliability, safety and environmental protection. “Prudent Operating Practices” shall not require the use of the optimum practice, method or act, but only requires the use of acceptable practices, methods or acts generally accepted in the United States in performing obligations in accordance with Prudent Operating Practices.

“Receiving Owner” has the meaning given to that term in Section 3.03(i)(1).

“Resolution Deadline” has the meaning given to that term in Section 3.03(i).

“Rules” has the meaning specified in Section 9.02(c)(1).

“Schedule and Exchange Agreement” means the Schedule and Exchange Agreement dated the date hereof by and between OG&E and OMPA, as amended from time to time.

“Supermajority of Members” means Members representing Owners holding in the aggregate more than 85% of aggregate Ownership Ratios.

“Taking” means the taking of any of the Power Plant as a result of the exercise of the power of eminent domain or condemnation for public or quasi-public use or the sale or conveyance of any of the Power Plant under the threat of condemnation.

“Taxes” means all taxes, charges, fees, levies or other assessments imposed by any United States federal, state or local or foreign taxing authority, including but not limited to, income, excise, property, sales, transfer, franchise, payroll, withholding, social security or other taxes, including any interest, penalties or additions attributable thereto.

“Term” means the term of this Agreement as defined in Section 7.01.

“Termination Date” has the meaning given to it in Section 7.01.

“Transmission O&M Agreement” means the Operating and Maintenance Agreement for the Transmission Assets of the McClain Generating Facility by and between OMPA and OG&E dated as of August 25, 2003, as amended from time to time.

“Variable Operating Maintenance Share” means $2 per megawatt hours (MWh) of Energy. Except as otherwise agreed to, the Variable Operating Maintenance Share is payable by any Owner that schedules any unscheduled Energy of another Owner to such Owner with respect to such Energy.

1.02 Interpretations. In this Agreement, unless clear contrary intention appears: (i) the singular number includes the plural number and vice versa; (ii) reference to any Person includes such Person’s successors and assigns but, if applicable, only if such successors and assigns are permitted by this Agreement, and reference to a Person in a particular capacity excludes such Person in any other capacity; (iii) reference to any gender includes each other gender; (iv) reference to any agreement (including this Agreement), document or instrument means such agreement, document or instrument as amended or modified and in effect from time to time in accordance with the terms thereof and, if applicable, the terms hereof, (v) reference to any Article, Section, Schedule or Exhibit means such Article, Section, Schedule or Exhibit to this Agreement, and references in any Article, Section, Schedule, Exhibit or definition to any clause means such clause of such Article, Section, Schedule, Exhibit or definition, (vi) “hereunder,” “hereof,” “hereto,” “herein” and words of similar import are reference to this Agreement as a whole and not to any particular Section or other provision hereof; (vii) relative to the determination of any period of time, “from” means “from and including,” “to” means “to but excluding” and “through” means “through and including;” (viii) “including” (and with correlative meaning “include”) means including without limiting the generality of any

description preceding such term; and (ix) reference to any law (including statutes and ordinances) means such law as amended, modified, codified or reenacted, in whole or in part, and in effect from time to time, including rules and regulations promulgated thereunder.

ARTICLE II

OWNERSHIP RATIOS

2.01 Ownership Ratios.

(a)

The Owners own the Owned Assets as tenants in common with each owning, as of the Effective Date, undivided interests in the following percentages:

	OMPA:		23.0%
	OG&E:		77.0%

Each Owner’s undivided interest in the Owned Assets, as it may change from time to time as provided herein, is referred to herein as its “Ownership Ratio.” Ownership Ratios may be modified only as provided in Sections 2.04, 6.01(b) and 8.02(a).

(b) Owners shall have the right to schedule and receive the Net Available Output of the Power Plant in the same percentages as their Ownership Ratios, subject to the Schedule and Exchange Agreement.

2.02 Changes in Ratios. Any changes in Ownership Ratios shall be given effect as provided pursuant to the terms and conditions of this Agreement without any further act, except such regulatory approval(s) as may be required.

2.03 Waiver of Partition. The Owners expressly waive any right of partition with respect to the Owned Assets, whether by partition in kind or sale and division of the proceeds thereof, until the end of Power Plant operations as described in Section 6.02.

2.04 Admission of New Owner. No Person shall succeed to or acquire the rights provided to Owners under this Agreement unless and to the extent that (i) the assignment or transfer pursuant to which it acquired its Interests in the Power Plant is valid under the terms of this Agreement and (ii) it becomes a party to this Agreement either by execution of this Agreement or by a written agreement acceptable to a Majority of Members to be bound by all of the terms and conditions hereof. For the avoidance of doubt, OMPA hereby acknowledges as valid and consents to the assignment and transfer by NRG McClain to OG&E of NRG McClain’s interest in and rights under the Original Agreement and 77% undivided interest in the Owned Assets.

ARTICLE III

OPERATION AND PAYMENT OF COSTS

3.01 Operations of the Power Plant. The Owners collectively agree that the Power Plant, including each Owner’s respective ownership interests in the Owned Assets, shall be operated together pursuant to this Agreement as follows:

(a) All decisions in respect of operating, maintaining, administering contracts relating to improving and adding capital improvements to the Power Plant are hereby delegated to the Executive Committee established pursuant to Section 3.03(a) hereof.

(b) Unless otherwise agreed by the Executive Committee pursuant to Section 3.03(g) hereof the day to day operation and maintenance of the Power Plant will be performed by OG&E as operator (the “Operator”). The rights and duties of the Operator shall be as set forth in the Operating and Maintenance Agreements as in effect from time to time. The Owners acknowledge that DEMc as operator under a predecessor Facility Operating Agreement subcontracted certain matters relating to the major maintenance and repair of the Power Plant to General Electric International, Inc. pursuant to the LTSA that will be assigned to OG&E as of the Power Plant Closing and that OG&E is in the process of negotiating amendments to the LTSA. OMPA hereby approves an amended LTSA to the extent that such amended LTSA does provide for terms that are provided for under the Memorandum of Understanding dated as of October 26, 2003 between General Electric International, Inc. and OG&E; provided, however, that any additional changes to the LTSA shall be approved by the Executive Committee pursuant to Section 3.03(f).

3.02 [Intentionally omitted.]

3.03 Executive Committee.

(a) Establishment of Executive Committee. The Owners hereby establish the Executive Committee to carry out such functions as may be delegated to it by the Owners as set forth herein. In addition to the rights set forth in Section 3.03(d), the Executive Committee shall have the power to establish policies and procedures for the operation and maintenance of the Owned Assets review and approve operating budgets, management compensation, specifications, annual schedules, capital budgets and similar major decision matters, and generally provide such guidance and direction as is needed to operate and maintain the Owned Assets. The Operator shall report to the Executive Committee and shall be responsible for the day-to-day oversight and coordination of matters relating to the operation and maintenance of the Power Plant and such other matters as may be delegated to the Operator by the Executive Committee.

(b) Composition of Executive Committee. Each Owner shall appoint one representative to the Executive Committee (each such representative, a “Member”). Each Member shall have a single vote equal to the Ownership Ratio of the Owner that appointed such Member. Each Member on the Executive Committee shall hold office until death, resignation or removal at the pleasure of the Owner that appointed such Member to the Executive Committee. If a vacancy occurs on the Executive Committee, the Owner that appointed such vacating

Member shall appoint a successor. Each Owner may also designate an alternate who shall be authorized to act in the absence of the Executive Committee representative or representatives for whom he or she is an alternate. Each alternate shall also hold office until death, resignation or removal at the pleasure of the appointing Owner. The initial Members and alternates on the Executive Committee and their successors shall be appointed by the respective Owners by written notice to the other Owners. No Executive Committee Member or alternate shall be entitled to compensation or reimbursement of expenses from the Owners for attendance at such meetings. Owners also may vote by one or more other proxies authorized by a written appointment of proxy signed by the Owner or by an Owner’s duly authorized attorney-in-fact and delivered to the Executive Committee for inclusion in the minutes or filing with the Executive Committee’s records. In the event that any Owner ceases to be an Owner for any reason whatsoever, the Member on the Executive Committee appointed by such Owner shall immediately cease to be a Member thereof.

(c) Executive Committee Meetings. The Executive Committee shall hold regular meetings quarterly on the date established from time to time by the Executive Committee. Between regular meetings, the chairman of the Executive Committee may call special meetings upon three days’ written notice to all Members, or upon such shorter telephonic notices the chairman determines is appropriate to respond to emergency situations. The Executive Committee shall keep written minutes of its meetings. Any action which may be taken at a meeting of the Executive Committee may be taken without a meeting by individual action taken in writing by Members of the Executive Committee representing sufficient Ownership Ratios to approve such action. Participation by conference telephone where all participants can hear one another shall constitute participation in person.

(d) Powers and Duties of Executive Committee. Subject to the terms and conditions of this Agreement and the Facility Operating Agreement, the Executive Committee shall have full power and complete authority to make all decisions and manage and direct all aspects of the operation and maintenance of the Power Plant, including with respect to enforcement of any contractual rights in respect of the Power Plant, appointment of the Operator, entering into amendments or modifications to the Facility Operating Agreement and agreeing to the terms and conditions of any similar agreements with any replacement Operator. Subject to the provisions of Section 3.03(g), the Executive Committee may delegate such of its authorities and responsibilities to an Owner, or officer or employee of any Owner, or other party as the Executive Committee may elect, including, without limitation, the Operator. The Owners hereby consent to the exercise by such Persons of the powers contemplated by this Agreement and to the employment, when and if the same is deemed necessary or advisable, of such brokers, agents, accountants, attorneys and other advisors as such Persons may determine to be appropriate for the management of the Owned Assets.

(e) Powers and Duties of Chairman. The chairman of the Executive Committee shall be elected by the Executive Committee and shall be responsible for (i) providing notice of meetings to all Members, (ii) preparing an agenda for all meetings in consultation with the Operator, (iii) setting the times for approval of certain actions or decisions, which shall be not less than three days except in case of matters which in the chairman’s judgment require emergency action or decision, (iv) presiding over all meetings and directing the order of business and procedures thereof; (v) arranging for the keeping of the minutes of all

meetings and the distribution thereof to all Members and (vi) taking such other action with respect to meetings of the Executive Committee as may seem necessary or appropriate in the judgment of the chairman. The chairman of the Executive Committee may be removed and a new chairman of the Executive Committee may be appointed by the vote of a Majority of Members.

(f) Voting. Each Executive Committee Member shall vote that Owner’s entire Ownership Ratio of the Owner which appointed such Member on any matter to be decided by the Executive Committee. Except as otherwise provided in Section 3.03(g), below, decisions of the Executive Committee shall be made by the approval of a Majority of Members. Matters not disapproved by a Member of the Executive Committee within the time after submission specified in the submittal, which shall not be less than specified in this Agreement (or if no time is specified in this Agreement, then within seven (7) calendar days) shall be deemed approved by such Member. No Member shall disapprove (i) matters which were submitted to the Executive Committee pursuant to the terms of this Agreement and not disapproved within the time allowed, (ii) items found by an arbitrator pursuant to the dispute resolution provisions hereof to be or have been consistent with Prudent Operating Practices, (iii) items where costs were borne solely by another Owner or the Operator individually, or (iv) items recommended by the chairman or the Operator having a total cost to all Owners in the aggregate of less than $70,000.

(g) Supermajority Matters. The following matters when submitted to the Executive Committee shall require the approval of a Supermajority of Members:

(i) except to the extent that the then current Operating & Maintenance Agreements otherwise provide, (A) the termination of such Operating & Maintenance Agreements, (B) any material amendment to any of the Operating & Maintenance Agreements, or (C) the approval of new Operating & Maintenance Agreements or the replacement or appointment of the Operator (such approval not to be unreasonably withheld or delayed by any Owner, which approval of a proposed replacement Operator shall not be withheld by any Owner if such replacement Operator is a qualified operator of gas-fired combined cycle facilities with similar technology as the Power Plant);

(ii) Elective Capital Additions requiring a total cost to all Owners in the aggregate in excess of $10,000,000; provided, however, that approval of a Supermajority of Members will not be required with respect to any such Elective Capital Additions if (A) the Owner(s) consenting to the Elective Capital Additions agree to bear all Costs of Capital Additions with respect thereto and (B) the carrying out of such Elective Capital Additions will not unreasonably interfere with the ability of non-consenting Owner(s) to obtain its or their Ownership Ratio of Net Available Output; provided, further, that all Elective Capital Additions requiring a total cost to all Owners in the aggregate of less or equal to $10,000,000 and all other Elective Capital Additions that have been approved by a Supermajority of Members in accordance with this Section 3.03(g) shall be deemed Capital Additions for purposes of this Agreement;

(iii) a decision to settle Third Party Claims where the uninsured portion of any such claim exceeds $10,000,000;

(iv) a decision to end Power Plant operations as provided in Section 6.02; and

(v) proposals to change any of the terms of this Section 3.03(g).

(h) Notwithstanding the foregoing, for so long as OMPA is an Owner and any bonds or other securities, the interest on which is excluded from gross income for federal income tax purposes, and which were issued or are to be issued to finance or refinance the acquisition of OMPA’s undivided interest in the Power Plant, remain outstanding, no Facility Operating Agreement shall include any provision that OMPA determines, on the basis of an opinion of counsel, could adversely affect the exclusion from gross income, for federal income tax purposes, of the interest on such bonds or other securities issued or to be issued by OMPA in such financing or refinancing.

(i) Deadlock. In the event that (i) there are only two Owners (for purposes of this Section 3.03(i) a Person and all of its Affiliates shall be treated as a single Owner) or if there are more than two Owners, one Owner and its Affiliates has an Ownership Ratio of more than 50%, (ii) the Members representing such Owners disagree with respect to the resolution of any matter requiring the approval of a Supermajority of Members as provided in Section 3.03(g)(i) or Section 3.03(g)(ii) (but only if such Elective Capital Additions will benefit all Owners in proportion to their Ownership Ratios), and (iii) the respective senior management representatives of the Owners have not resolved such disagreement within thirty (30) days of a written notice from an Owner requesting such resolution (“Resolution Deadline”), then (A) the dispute resolution procedures of Section 9.02 hereof shall not apply to such disagreement (but will continue to apply with respect to any dispute concerning the application of this subsection (i) or the interpretation thereof), and (B) any Owner may, provided such Owner is not then a defaulting Owner hereunder, by written notice (“Buy-Sell Notice”) to the other Owners within 15 days after the Resolution Deadline initiate the following procedure (“Buy-Sell Procedure”) with respect to offers to buy and sell each Owner’s respective interests in the Power Plant (the “Interests”). If no Owner initiates the Buy-Sell Procedure by timely delivery of a Buy-Sell Notice, the disagreement may be resolved pursuant to the dispute resolution procedures provided in this Agreement. Notwithstanding the foregoing, in the event of the disposition by OG&E of all, or substantially all, of its ownership interests in the Power Plant, any disagreement among the Owners as to the qualification of any replacement Operator proposed in connection with such disposition shall be subject to the dispute resolution procedures set forth in Section 9.02, rather than the Buy-Sell Procedure.

(1) Within 15 days of the date of delivery of the Buy-Sell Notice, the initiating Owner (the “Initiating Owner”) shall submit to all of the other Owners (each, a “Receiving Owner”) an offer in writing which shall be an offer to purchase all of the Interests of the Receiving Owners for the price, per 1% of Ownership Ratio, set forth in the offer. Such offer shall be irrevocable for a period of 15 days from the date of submission to the Receiving Owners (“Offer Period”).

(2) Prior to the end of the Offer Period, each Receiving Owner must either (A) accept in writing the Initiating Owner’s offer, or (B) make a counteroffer (irrevocable for a period of 15 days from the date of submission thereof) to purchase all of the Interests of the

other Owners for a price per 1% of Ownership Ratio that exceeds the offered price per 1% of Ownership Ratio by at least 5% of the offered price. If a Receiving Owner makes a counteroffer pursuant to this Section 3.03(i)(2), the counteroffer shall be treated as an offer made pursuant to Section 3.03(i)(1) hereof initiating a new Offer Period, the Owner making such counteroffer shall be treated as the Initiating Owner, and the Owners receiving the counteroffer shall be treated as, and have the rights of, the Receiving Owners pursuant to this Section 3.03(i)(2) to either accept the counteroffer or make a new counteroffer.

(3) Notwithstanding the foregoing, at any time prior to the end of any Offer Period, any Receiving Owner may terminate the Buy-Sell Procedure with respect to its Interest in the Power Plant by acquiescing in writing in all respects to the position of the then Initiating Owner with respect to the matter or matters then in dispute. If as a result of such acquiescence, such matter or matters are approved by a Supermajority of Members, the Buy-Sell Procedure shall be terminated in respect of all Owners and the matter or matters in question shall be deemed to have been approved by a Supermajority of Members. If such acquiescence does not result in the approval of such matter or matters by a Supermajority of Members, the Buy-Sell Procedure shall continue but the then Initiating Owner’s offer shall not apply to the acquiescing Owner, which shall not be considered to be a Receiving Owner with respect to such offer.

(4) Failure by a Receiving Owner to accept an offer, make a conforming counteroffer or acquiesce in respect of the matter or matters then in dispute as provided herein by the end of an Offer Period shall constitute acceptance of the last conforming offer made. Within 30 days after acceptance in writing or the end of an Offer Period resulting in deemed acceptance of an offer by all of the Receiving Owners, the Owners shall enter into an asset purchase agreement with respect to the Interests being purchased which shall have customary terms and conditions mutually agreed to by the parties thereto and provided that (A) the purchase price shall be payable entirely in cash in immediately available funds as of the closing under such asset purchase agreement, (B) the Interests shall be free and clear of all liens and encumbrances (other than Permitted Liens), including, without limitation, any obligations in respect to the Capacity or Energy produced by the Power Plant, and (C) the termination of this Agreement and the Facility Operating Agreement shall be a condition precedent to the closing of such asset purchase agreement.

3.04 Payment of Expenses: Operating Budget.

(a) Except as provided in this Section 3.04(a), each Owner shall be fully and individually responsible for the timely payment of its Ownership Ratio of all Costs of Operation (adjusted, to the extent applicable, for payments by Owner’s of their Variable Operating Maintenance Share), all Costs of Capital Additions and, to the extent applicable, each Owner’s Variable Operating Maintenance Share. Furthermore, each Owner shall be fully and individually responsible for the timely payment of its Power Plant Fuel Costs in accordance with the Fuel Agreement or pursuant to agreements individually entered into by such Owner for the supply, transportation and/or storage of fuel to be used on behalf of such Owner in the Power Plant. Notwithstanding the foregoing:

(1) If the then current Operating & Maintenance Agreements provide for the direct allocation of amounts payable thereunder to one or more of the Owners, the terms of the Operating & Maintenance Agreements shall control with respect to such amounts.

(2) Except as otherwise agreed to, costs payable hereunder or under the Operating & Maintenance Agreements shall include only actual costs without markup.

(3) Each Owner shall be fully and individually responsible for the payment of its own financing costs and Taxes whether arising in connection with this Agreement, the Power Plant or otherwise.

(4) OG&E will, upon the Power Plant Closing, make necessary and appropriate transmission system upgrades and improvements when OG&E deems necessary to the transmission system to accommodate the full capacity output of the Power Plant, and OG&E agrees that none of the costs and expenses associated with such additional transmission system upgrades and improvements shall be allocated to OMPA under the Operating & Maintenance Agreements. The transmission system upgrades and improvement shall inure to the benefit of all Owners in proportion to their respective Ownership Interests, but shall at all times be the property of OG&E and be subject to being included as part of subsequent Open Access Transmission Tariff charges to third parties, including OMPA. The transmission system upgrades and improvements are expected to be completed and in service at the end of eighteen (18) months following the Power Plant Closing.

(b) On or before October 1 of each year, commencing 2004, the Operator will provide to the Executive Committee a reasonable estimate of the operating budget (the “Budget Estimate”) for the next year. On or before November 15 of each year, commencing 2004, the Executive Committee shall prepare (based on the Budget Estimate) and approve an operating budget (the “Operating Budget”) for the next calendar year. The Operating Budget for calendar year 2004 shall be prepared and approved by the Executive Committee within 30 days after execution of this Agreement. The Operating Budget shall contain the Executive Committee’s reasonable estimate of all costs and expenses incurred each month for the operation and maintenance of the Power Plant, including without limitation, estimated amounts payable under the Facility Operating Agreement, fuel costs and budgeted capital expenditures. The Executive Committee may amend the Operating Budget from time to time.

(c) Within fifteen days of receipt of an invoice therefor from the Operator, each Owner shall pay the Operator such Owner’s Ownership Ratio of the actual Costs of Operation and Costs of Capital Additions, provided, however, if such costs exceed any line item in the Operating Budget by more than 10%, no Owner shall be obligated to pay any such amount until such amount is approved by the Executive Committee by means of an amendment to the Operating Budget.

3.05 Claims Treated as Costs of Operation. Except as otherwise specifically provided herein, the Owners shall be responsible for any and all Claims of Persons who are not Owners arising from or related in any way to the Power Plant in proportion to their Ownership Ratio.

3.06 Books and Records. Operator shall keep, in conformity with all requirements of Law, proper books, records, accounts, ledgers, time cards, estimates, schedules, correspondence and other documents related to the Operator’s performance of its obligations hereunder and amounts due to the Operator under any Facility Operating Agreement. During ordinary business hours and upon reasonable notice to Operator, each Owner may inspect, copy and audit such books and records. Operator agrees to keep such books and records for five years following their respective preparation (at which time it will be permitted to destroy such books and records in the ordinary course of business) and will furthermore keep any such books and records not previously destroyed in the ordinary course of business, for five years after the termination of this Agreement, and shall provide copies thereof to each Owner upon request, at such requesting Owner’s expense. The acceptance, approval or payment by any Owner of the Operator’s charges in complying with such request shall not operate as a waiver of such Owner’s right to audit the Operator in accordance with this Section 3.06.

3.07 Fuel Supply. Each Owner is individually responsible for the supply, transfer and/or storage of fuel (including, without limitation, any imbalance services associated therewith) used or to be used in connection with operation of the Power Plant to produce Energy for the account of such Owner. Notwithstanding the previous sentence, simultaneously with the execution of this Agreement, OG&E and OMPA entered into the Fuel Agreement pursuant to which OG&E exclusively provides fuel and imbalance services to OMPA as of the effective date thereof, responsibility for which services shall automatically revert to OMPA upon termination of said Fuel Agreement.

ARTICLE IV

ALLOCATION AND SCHEDULING OF NET AVAILABLE OUTPUT

4.01 Allocation of Net Available Output.

(a) Subject to the Schedule and Exchange Agreement, scheduling procedures hereof and the availability of the Power Plant, each Owner shall be entitled to schedule and take all or any part (in accordance with Exhibit B, II, C) hereto) of its Ownership Ratio of the Net Available Output of the Power Plant.

(b) Except as otherwise agreed to, each Owner shall be solely responsible for all costs, penalties or damages caused to the Operator if an Owner fails to make available the supply, transportation and/or storage of fuel required to meet such Owner’s scheduled Net Available Output of the Power Plant, and if fuel is not actually received from other sources, such Owner shall not be entitled to the scheduled Net Available Output of the Power Plant to which it would otherwise be entitled to the extent of such unavailability.

4.02 Scheduling of Net Available Output. The Owners shall schedule their entitlement to Net Available Output in accordance with the operating procedures set forth in Exhibit B hereto.

ARTICLE V

LIMITATION OF LIABILITY

5.01 Limitation of Liability. THE EXPRESS REMEDIES AND MEASURES OF DAMAGES PROVIDED FOR IN THIS AGREEMENT SHALL BE THE SOLE AND EXCLUSIVE REMEDIES FOR AN OWNER HEREUNDER AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. IF NO REMEDY OR MEASURE OF DAMAGES IS EXPRESSLY HEREIN PROVIDED, AN OWNER MAY, SUBJECT TO THE LIMITATIONS OF THE NEXT SENTENCE HEREOF, RECOVER SUCH REMEDIES, INCLUDING DAMAGES AND FEES AND EXPENSES OF ATTORNEYS AS MAY BE AVAILABLE AT LAW OR EQUITY. NOTWITHSTANDING THE FOREGOING, HOWEVER, NO OWNER SHALL UNDER ANY CIRCUMSTANCES BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE OR EXEMPLARY DAMAGES, WHETHER BY STATUTE, IN TORT OR CONTRACT OR OTHERWISE. THE LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE MEASURE OF DAMAGES SHALL BE WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE NEGLIGENCE OF ANY OWNER. TO THE EXTENT ANY DAMAGES REQUIRED TO BE PAID HEREUNDER ARE LIQUIDATED, THE OWNERS ACKNOWLEDGE THAT THE DAMAGES ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, OTHERWISE OBTAINING AN ADEQUATE REMEDY IS INCONVENIENT AND THE LIQUIDATED DAMAGES CONSTITUTE A REASONABLE APPROXIMATION OF THE HARM OR LOSS.

ARTICLE VI

DAMAGE TO POWER PLANT; END OF OPERATIONS

6.01 Damage to, or Condemnation of, the Power Plant.

(a) In the event that the Power Plant suffers damage resulting from causes other than ordinary wear, tear or deterioration, or to the extent any Taking affects the Power Plant, to the extent that the estimated uninsured or uncompensated cost of repair as determined by the Executive Committee, or, if a Majority of Members cannot agree within a period of six (6) months from the date of damage, as determined by the arbitrator pursuant to the dispute resolution provisions hereof; is less than or equal to $10 million, and if the Executive Committee does not determine that the operations of the Power Plant shall be ended pursuant to Section 6.02, the Executive Committee shall promptly cause the Operator to submit a revised Operating Budget and shall proceed to cause the repair of the Power Plant, and each Owner shall pay as budgeted, into a separate trust account, its Ownership Ratio of the estimated uninsured or uncompensated cost thereof.

(b) If the Power Plant suffers damage or a Taking to the extent that the estimated uninsured or uncompensated cost of repair exceeds $10 million as determined in accordance with Section 6.01(a) the Executive Committee shall, or, if a Majority of Members cannot agree within six (6) months from the date of damage, the arbitrator shall, determine the estimated value of the Power Plant as and when repaired. Thereafter, each Owner which, within

a reasonable time to be determined by the Executive Committee, gives notice in writing to the other Owners of its desire that the Power Plant be repaired, shall, in the proportion that its Ownership Ratio bears to the total of the Ownership Ratio of all Owners giving such notice, pay into the separate trust account, as budgeted in a revised budget, all of the estimated uninsured or uncompensated cost of repair. If any Owner has given such a notice, the Ownership Ratio of each Owner which did not give such a notice shall, at the end of the reasonable time which was determined by the Executive Committee, be reduced to the extent determined by the following formula:

O2	=	O1	x	V - (C - I)
				V

where
V C I	= = =	Estimated value of the Power Plant as repaired Estimated cost of repair Estimated insurance or compensation proceeds, if any, inuring to the benefit of all Owners (shall not include insurance or compensation proceeds to which only individual Owners are entitled)
O1 O2	= =	Ownership Ratio prior to loss Reduced Ownership Ratio

At the same time, the amount of such reductions shall be added to the Ownership Ratio of the Owners giving such notice in the proportion that the Ownership Ratio of each bears to the total of the Ownership Ratios of all Owners giving such notice.

(c) If the Power Plant suffers damage to the extent that the estimated uninsured or uncompensated cost of repair as determined in Section 6.01(a) exceeds $10 million and no Owner gives the notice required by Section 6.01(b), the damaged Power Plant shall not be repaired. If portions of the Power Plant are still capable of economically generating electricity, then the Executive Committee shall cause the Operator to implement the procedures specified in Section 6.02 with respect to the damaged facilities only and continue to operate the remaining facilities. If no portion of the Power Plant is still capable of economically generating electricity, then the Executive Committee shall cause the Operator to end Power Plant operations pursuant to Section 6.02.

(d) In the case of repair of the Power Plant pursuant to Sections 6.01(a) or (b), all proceeds of insurance and condemnation awards shall first be applied to repair of the Power Plant, with any excess being distributed to the Owners in accordance with their Ownership Ratios.

6.02 End of Power Plant Operations. When the Power Plant can no longer be made capable, consistent with Prudent Operating Practices, of producing electricity or cannot obtain required permits, or when the Owners otherwise agree to end Power Plant operations by the

approval of a Supermajority of Members, the Executive Committee shall cause the Operator to sell for removal all salable parts of the Power Plant to the highest bidder(s). Each Owner shall bear its Ownership Ratio of all costs of termination of Power Plant operations, including the costs of decommissioning, razing all structures and disposing of the debris and meeting all requirements of Applicable Law. Each Owner shall receive its Ownership Ratio of any proceeds resulting from the liquidation by the Operator of the Power Plant pursuant to this Section 6.02 only after the payment of all costs of termination of Power Plant operations, including payment of any expenses authorized by the Executive Committee.

6.03 Insurance.

(a) The Executive Committee shall establish the types, limits and deductibles of insurance purchased for the Power Plant by OG&E on behalf of the Owners, which insurance shall at a minimum provide the coverages set forth in Schedule 6.03 hereto or as required by law.

(b) Unless otherwise agreed by the Executive Committee, all insurance shall be for the benefit of all Owners in accordance with their Ownership Ratios. In the event that any Owner acquires separate insurance covering its interest in the Power Plant, such policies shall be appropriately endorsed to provide waivers of subrogation to OG&E and all other Owners in order to prevent subrogation or the holding of OG&E or any other Owners responsible for losses.

ARTICLE VII

TERM AND TERMINATION

7.01 Term. This Agreement shall become effective, and amend and restate and supercede in its entirety the Original Agreement, upon the Power Plant Closing (the “Effective Date”). The term of this Agreement (“Term”) shall be from the Effective Date through the date of the end of Power Plant operations as provided in Section 6.02 or the date of any earlier termination of this Agreement by the mutual written agreement of the Owners (the “Termination Date”), provided that the Owners shall comply with any orders of any Governmental Authority with respect to any earlier termination and the costs of such compliance shall be borne by the Owners at that time in accordance with their Ownership Ratios.

7.02 Termination. This Agreement shall not be subject to termination by any party or Owner prior to the Termination Date except as expressly provided in Section 7.01. Each of the Owners, to the extent not prohibited by Applicable Law, waives all rights now or hereafter existing, conferred by statute, common law or otherwise to quit, terminate or surrender this Agreement, other than any rights or obligations which may have accrued to such Owner, or to which such Owner may have become subject, hereunder prior to such termination.

ARTICLE VIII

DEFAULT AND REMEDIES

8.01 Default.

(a) Upon failure of an Owner to make any payment when due, fulfill any covenant, or, except as excused by Force Majeure, perform any material obligation of an Owner herein, any other Owner may make written demand upon said Owner.

(b) If the failure of an Owner is to make a payment when due, such failure shall immediately constitute a default; provided that, for the first two times that written demand pursuant to Section 8.01(a) is made upon such Owner, such failure to make payment when due shall not constitute a default if such nonpayment is cured within 15 calendar days from the date of the demand pursuant to Section 8.01(a).

(c) If the failure of an Owner is to fulfill any covenant or to perform any other material obligation, and if such failure is not cured within 30 days from the date of such demand, it shall, at the expiration of such period, constitute a default.

(d) If an Owner in good faith disputes the existence or extent of a failure described in Section 8.01(a), it shall, within the applicable period given to it in Sections 8.01(b) or (c), nonetheless make such payment or perform such obligation under written protest directed to the Owners. Such dispute shall be resolved pursuant to the dispute resolution procedures provided for herein.

8.02 Remedies.

(a) If a default is limited to a failure of the defaulting Owner to make payments, the defaulting Owner’s Ownership Ratio of Net Available Output may, subject to rights of the then non-defaulting Owner(s) under the Market Dispatch Agreement and the Schedule and Exchange Agreement, be sold during the period of default for the benefit of the defaulting Owner (to third parties or other Owner(s)) and the proceeds applied to the amounts owed by such Owner; provided that the non-defaulting Owner(s) shall have no obligation to engage in any such sales. Payments not made when due may be advanced by the other Owner(s) and, if so advanced, shall bear interest until paid at the prime rate of Citibank, N.A. (or its successor) plus 5% or the highest lawful rate, whichever is lower. If a payment default (including accrued interest thereon) has not been brought current by the defaulting Owner by the 90th day following the original due date of such amount, then, in lieu of receiving a cash payment from the defaulting Owner therefor, any non-defaulting Owner may, to the extent permitted by Applicable Law, elect by 30 days’ prior written notice to the defaulting Owner to increase its respective Ownership Ratio (and the Ownership Ratio of the defaulting Owner shall be correspondingly reduced) according to the following formula:

	Increased Interest = SI x		A
			TV

where

means the defaulting Owner's then current Ownership Ratio;

		A		means the aggregate amount then owed by such defaulting Owner; and
		TV		means the product of such defaulting Owner's then current Ownership Ratio multiplied by the weighted average of the purchase price paid by all Owners for their respective Ownership Ratio.

If more than one Owner elects to increase its Ownership Ratio in lieu of receiving a cash payment from the defaulting Owner, the increases shall be apportioned on a pro rata basis among the prior Ownership Ratios of the electing Owners. No Owner shall be required to elect to increase its Ownership Ratio in lieu of receiving a cash payment from a defaulting Owner hereunder.

(b) If a default involves the failure of a defaulting Owner to fulfill any covenant or to perform any other material obligation, the defaulting Owner’s Ownership Ratio of Net Available Output may, subject to rights of the then non-defaulting Owner(s) under the Market Dispatch Agreement and the Schedule and Exchange Agreement, be used or sold by the non-defaulting Owner(s) as it may in its sole discretion determine during the period of such default, and the value thereof, calculated as the Variable Cost of producing the Energy actually generated from such Net Available Output, shall be credited to any actual damages incurred by the non-defaulting Owner(s) as a result of such failure or non-performance; provided that the non-defaulting Owner(s) shall have no obligation to so use or sell the defaulting Owner’s Ownership Ratio of Net Available Output.

(c) In addition to the rights granted in this Section 8.02, any non-defaulting Owner may seek injunctive relief, including specific performance, to enforce a defaulting Owner’s obligation under this Agreement; provided that all claims to recover damages or payments on account of any default hereunder shall proceed pursuant to the dispute resolution procedures provided herein.

ARTICLE IX

MISCELLANEOUS

9.01 Governing Law. THIS AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED, INTERPRETED AND ENFORCED IN ACCORDANCE WITH, THE SUBSTANTIVE LAW OF THE STATE OF OKLAHOMA WITHOUT REFERENCE TO ANY PRINCIPLES OF CONFLICTS OF LAWS THEREOF.

9.02 Dispute Resolution; Arbitration.

(a) Any dispute or claims arising under this Agreement which cannot be resolved by the parties through negotiation by the parties’ managers shall be referred to a panel

consisting of a senior executive of each party, with authority to decide or resolve the matter in dispute, for review and resolution. Such senior executives shall attempt to meet and resolve the dispute within 30 days.

(b) If the parties are unable to resolve a dispute as provided in Section 9.02(a), each party has the right to (i) pursue any legal and/or equitable remedies in the District Court of

Oklahoma County or such other court of proper jurisdiction or (ii) seek to arbitrate the dispute using the procedures specified in Section 9.02(c); which election shall be binding upon such party with respect to the dispute at issue.

(c) If so elected by a party and the other party agrees in writing, a dispute shall be arbitrated in accordance with the following procedures:

submission to jurisdiction and its consent to service of process by mail is made for the express benefit of the other party.

(5) This Agreement and the rights and obligations of the parties shall remain in full force and effect pending the award in any arbitration proceeding hereunder.

(6) Unless otherwise ordered by the arbitrators, each party shall bear its own costs and fees, including attorneys’ fees and expenses. The parties expressly agree that the arbitrators shall have no power to consider or award any form of damages barred by Section 5.01, or any other multiple or enhanced damages, whether statutory or common law.

(7) The parties, to the fullest extent permitted by law, hereby irrevocably waive and exclude any rights of application or appeal or rights to state a special case for the opinion of the courts or any other recourse to the court system other than to enforce the agreement to arbitrate pursuant to this Section 9.02(c) for attachment or other order in aid of arbitration proceedings or to enforce the award of the arbitral panel.

9.03 Force Majeure.

(a) “Force Majeure” means an event not anticipated as of the Effective Date which is not within the reasonable control of the party (or in the case of third party obligations or facilities, the third party) claiming suspension (the “Claiming Party”), and which by the exercise of due diligence the Claiming Party is unable to overcome in a commercially reasonable manner or obtain or cause to be obtained a commercially reasonable substitute performance therefor. Events of Force Majeure include, but are not restricted to: wrongful or negligent acts of the other party; acts of God; fire, civil disturbance; labor dispute or labor shortages; strikes sabotage, action or restraint by court order or Governmental Authority (so long as the Claiming Party has not applied for or assisted in the application for, and has opposed where and to the extent reasonable, such action or restraint); and inability after diligent application to obtain or maintain required permits, licenses, zoning or other required approvals from any Governmental Authority or other third-party Person whose consent is required as a condition to a party’s performance hereunder.

(b) Suspension. If a party is rendered unable by Force Majeure to carry out, in whole or in part, its obligations under this Agreement and such party gives written notice and full details of the event to the other party as soon as practicable after the occurrence of the event, then during the pendency of such Force Majeure but for no longer period, the obligations of the party affected by the event (other than the obligation to make payments then due or becoming due with respect to performance prior to the event) shall be suspended to the extent required. The party affected by the Force Majeure shall remedy the Force Majeure with all reasonable dispatch.

9.04 Restrictions on Assignments and Transfers. An Owner shall be entitled to assign or transfer all or any of its Interests in the Power Plant to any Person who becomes an Owner pursuant to Section 2.04 without restriction of any kind.

9.05 Attorneys’ Fees and Litigation Expenses. In the event any action is commenced to recover damages or enforce any rights or obligations under this Agreement, then the prevailing party in such action shall be entitled to recover its attorney fees, including the reasonable fees of in-house counsel, expert fees, and all reasonable out-of-pocket expenses incurred in enforcing the prevailing party’s rights under this Agreement, regardless of whether those fees, costs or expenses are otherwise recoverable as costs in the action, including all fees and expenses incurred in investigation and preparation of the action before it is filed and upon appeal.

9.06 Notices.

(a) Means of Notification. Unless this Agreement specifically requires otherwise, any notice, demand or request provided for in this Agreement, or served, given or made in connection with it, shall be in writing and shall be deemed properly served, given or made if delivered in person or sent by fax or sent by registered or certified mail, postage prepaid, or by a nationally recognized overnight courier service that provides a receipt of delivery, in each case, to the parties at the addresses specified below:

If to OMPA:
	Oklahoma Municipal Power Authority
	Street Address: 2300 East Second Street Edmond, OK 73034 Post Office Address: P.O. Box 1960 Edmond, OK 73083-1960
	Facsimile No. (405) 359-1071 Attn: General Manager

With a copy to:
	Oklahoma Municipal Power Authority
	Street Address: 2300 East Second Street Edmond, OK 73034 Post Office Address: P.O. Box 1960 Edmond, OK 73083-1960
	Facsimile No. (405) 359-1071 Attn: General Counsel

If to OG&E:
	Oklahoma Gas and Electric Company PO Box 321 Oklahoma City, Oklahoma 73101-0321 Attention: Jack T. Coffman, Senior Vice President, Power Supply Facsimile No.: (405) 553-3198
With a copy to:
	Jones Day 77 West Wacker Drive, Suite 3500 Chicago, Illinois 60601-1692 Attention: Peter D. Clarke Facsimile No.: (312) 782-8585

(b) Effective Time. Notice given by personal delivery, mail or overnight courier pursuant to this Section 9.06 shall be effective upon physical receipt. Notice given by fax pursuant to this Section 9.06 shall be effective as of (i) the date of confirmed delivery if delivered before 5:00 p.m. (central prevailing time) on any business day, or (ii) the next succeeding business day if confirmed delivery is after 5:00 p.m. (central prevailing time) on any business day or during any non-business day.

9.07 Waivers. Except as otherwise provided herein, no provision of this Agreement may be waived except in writing. No failure by any party to exercise, and no delay in exercising, short of the statutory period, any right, power or remedy under this Agreement shall operate as a waiver thereof. Any waiver at any time by a party of its right with respect to a default under this Agreement, or with respect to any other matter arising in connection therewith, shall not be deemed a waiver with respect to any subsequent default or matter.

9.08 No Reliance. Each party acknowledges that in entering into this Agreement, it has not relied on any statement, representation or promise of the other party or any other Person except as expressly stated in this Agreement.

9.09 Assumption of Risk. In entering into this Agreement, each of the parties assumes the risk of any mistake of fact or law, and if either or both of the parties should subsequently discover that any understanding of the facts or the law was incorrect, neither of the parties shall be entitled to, nor shall attempt to, set aside this Agreement or any portion thereof.

9.10 Waiver of Defenses. Upon the execution of this Agreement, the parties release each other from any and all claims relating to the formation and negotiation of this Agreement, including, but not limited to reformation, rescission, mistake of fact, or mistake of law. The parties further agree that they waive and will not raise in any court, administrative body or other tribunal any claim in avoidance of or defense to the enforcement of this Agreement other than the express conditions given to it in this Agreement.

9.11 No Third-Party Beneficiaries. None of the promises, rights or obligations contained in this Agreement shall inure to the benefit of any Person not a party to this Agreement; and no action may be commenced or prosecuted against any party by any third party claiming to be a third-party beneficiary of this Agreement or the transactions contemplated hereby.

9.12 Severability. If any provision of this Agreement is held to be illegal, invalid or unenforceable under any present or future law, and if the rights or obligations of any party hereto under this Agreement will not be materially and adversely affected thereby, (i) such provision will be fully severable, (ii) this Agreement shall be construed and enforced as if such illegal, invalid or unenforceable provision had never comprised a part hereof, (iii) the remaining provisions of this Agreement shall remain in full force and effect and will not be affected by the illegal, invalid or unenforceable provision or by its severance herefrom and (iv) in lieu of such illegal, invalid or unenforceable provision, there shall be added automatically as a part of this

Agreement a legal, valid and enforceable provision as similar in terms to such illegal, invalid or unenforceable provision as may be possible.

9.13 Independent Counsel. The parties acknowledge that they have been represented by independent counsel in connection with this Agreement, they fully understand the terms of this Agreement, and they voluntarily agree to those terms for the purposes of making a full compromise and settlement of the subject matter of this Agreement.

9.14 Further Assurances. Each party shall promptly and with all due diligence take all necessary action in aid of obtaining all regulatory approvals, licenses and permits necessary to carry out its obligations under this Agreement. Each party shall, from time-to-time on request, execute deeds, bills of sale and whatever other documents that may be necessary in addition to this Agreement to evidence title.

9.15 No Partnership. Nothing in this Agreement shall create a partnership, joint venture, association or a trust. The parties shall affirmatively elect not to apply the provisions of Subchapter K of the Internal Revenue Code of 1986. Each party shall severally bear its respective share of all obligations and liabilities of the Power Plant as it arises. No Party shall have a right or power to bind any other party without its written consent, except as provided in this Agreement. IN THEIR RELATIONS WITH EACH OTHER UNDER THIS AGREEMENT, THE PARTIES SHALL NOT BE CONSIDERED FIDUCIARIES OR TO HAVE ESTABLISHED A CONFIDENTIAL RELATIONSHIP, BUT RATHER SHALL BE FREE TO ACT ON AN ARM’S LENGTH BASIS IN ACCORDANCE WITH THEIR OWN RESPECTIVE SELF-INTEREST, SUBJECT, HOWEVER, TO THE OBLIGATIONS OF THE OWNERS TO ACT IN GOOD FAITH IN THEIR DEALINGS WITH EACH OTHER WITH RESPECT TO ACTIVITIES HEREUNDER. NO OWNER NOR ANY AFFILIATE OF ANY OWNER, BY REASON OF SUCH OWNER’S INTEREST IN THE POWER PLANT OR APPOINTMENT OF A REPRESENTATIVE OF SUCH OWNER AS A MEMBER OF THE EXECUTIVE COMMITTEE, SHALL BE PRECLUDED FROM ENGAGING IN ANY ACTIVITIES SIMILAR TO THOSE TO BE CONDUCTED BY THE OTHER OWNERS IN RESPECT OF THE POWER PLANT OR ANY ACTIVITIES INCIDENTAL OR RELATED THERETO IN THE UNITED STATES OF AMERICA, MEXICO, OR ANYWHERE ELSE, NOR SHALL ANY OWNER OR ANY AFFILIATE OF ANY OWNER HAVE ANY OBLIGATION, BY REASON OF SUCH OWNER’S INTEREST IN THE POWER PLANT OR APPOINTMENT OF A REPRESENTATIVE OF SUCH OWNER AS A MEMBER OF THE EXECUTIVE COMMITTEE, TO MAKE AVAILABLE TO ANY OTHER PERSON ANY OTHER OPPORTUNITY THAT SUCH OWNER OR ANY OF ITS AFFILIATES MAY HAVE TO DEVELOP, CONSTRUCT, OWN, OPERATE, MAINTAIN OR FINANCE ANY OTHER PROJECT OF ANY KIND OR NATURE, INCLUDING, WITHOUT LIMITATION, ANY POWER PLANT PROJECT.

9.16 Ancillary Services. To the extent the Power Plant is used or may be used to generate Ancillary Services or related products from time to time, the Owners shall negotiate in good faith in an attempt to agree, consistent with their respective Ownership Ratio, on an equitable allocation of the costs and benefits, to account for such Ancillary Services or related products.

9.17 Access. Each party and its designees shall have the right to go upon and into the Power Plant at any time, subject to the necessity of efficient and safe construction and operation of the Power Plant, but the Operator alone shall have possession and control of the Power Plant for and on behalf of all of the Owners.

9.18 Adjustments. For purpose of determining the responsibilities with respect to any contractual obligations between OMPA and NRG McClain under the Original Agreement outstanding as of the Power Plant Closing, OG&E and OMPA agree that in accordance with the Power Plant Purchase Agreement, OG&E will be responsible for the payment of all outstanding contractual obligations of NRG McClain owed to OMPA under the Original Agreement, if any, provided, however, that OG&E will not be liable to OMPA (and therefore NRG McClain will continue to be liable) with respect to any liabilities resulting out of the breach of, or a default under, the Original Agreement. Furthermore, all accounts payable currently owed by OMPA to NRG McClain under the Original Agreement, to the extent resulting from operation of the Power Plant prior to the Power Plant Closing, remain payable to NRG McClain. For purpose of clarification, this provision is strictly limited to contractual obligations under the Original Agreement and OG&E and OMPA agree that it does not create any obligations or liabilities of OG&E originated under the Original Agreement for claims based in tort, equity or otherwise.

9.19 Entire Agreement. This Agreement, together with the Operating & Maintenance Agreements, the Fuel Agreement, the Schedule and Exchange Agreement, the Market Dispatch Agreement and the Service Agreement For Power Sales Between OMPA and OG&E, constitute the complete and entire expression of agreements between the parties and supersede all prior and contemporaneous offers, promises, representations, negotiations, discussions, and communications, whether written or oral, including that certain Memorandum of Understanding re the subject matter of this Agreement between OMPA and OG&E dated September 15, 2003, all of which may have been made in connection with the subject matter of this Agreement, including, in each case, all schedules and exhibits thereto. Any such representations or claims are hereby disclaimed. This Agreement may be signed in counterparts.

[Remainder of page intentionally blank.]

IN WITNESS WHEREOF, the parties have executed this Agreement as of the date first above written.

		OKLAHOMA MUNICIPAL POWER AUTHORITY
		By:	/s/ Charles Lamb
			Name: Charles Lamb Title: Chair, OMPA Board of Directors
Attest:
By:	/s/ Roland Dawson
	Name: Roland Dawson Title: Assistant Secretary

		OKLAHOMA GAS AND ELECTRIC COMPANY
		By:	/s/ Jack T. Coffman
			Name: Jack T. Coffman Title: Senior Vice President, Power Supply
Attest:
By:	/s/
	Name: Title:

Exhibit A

to

Amended and Restated Ownership and Operation Agreement

Amended and Restated Facility Operating Agreement

Exhibit B

To Ownership
and Operation Agreement

Operating Procedures

I.	Scheduling and Operational Notifications Contacts:

OG&E		OMPA
Day Ahead Hourly	(405) 553-2116 (405) 553-2116	Operations Backup	(405) 340-8313 (405) 340-5047
		Ponca City Power Plant	(580) 763-8048

OMPA and OG&E will provide each other with full contact lists from time to time.

II.

Daily Dispatching Procedure

Prior to 0800 central prevailing time on the business day (Weekends and Monday deliveries will require notification by the Friday preceding the date power is taken; NERC holidays or the next day after a holiday will require notification by the first business day preceding a holiday) prior to energy delivery, OG&E shall advise OMPA (i) what OMPA’s Ownership Ratio of the Net Available Output is expected to be, (ii) whether OG&E will exercise its rights under the Schedule and Exchange Agreement and (iii) whether OG&E expects to run the Power Plant or not. If OG&E’s preliminary decision is not to run the plant, OMPA and OG&E shall agree on a preliminary dispatch cost of the plant. The preliminary dispatch cost will be calculated using an estimated gas cost, and estimated heat rate of 7,500 Btu/kwh, and an operation and maintenance cost of $2.00/MWh. OMPA shall use the mutually agreed estimated cost in making its unit commitment decisions for the day in question.

Prior to 0830 central prevailing time on the business day (Weekends and Monday deliveries will require notification by the Friday preceding the date power is taken; NERC holidays or the next day after a holiday will require notification by the first business day preceding a holiday) prior to energy delivery, OMPA shall provide OG&E with a preliminary schedule of energy requirements which will include: quantity, time and any delivery point requirements.

If OG&E decides not to dispatch the Power Plant, it will notify OMPA and its designated fuel supplier (if other than OG&E) prior to 0830 central prevailing time on the day prior to energy delivery. In such event, OG&E shall, at the request of OMPA, sell power to OMPA pursuant to the Market Dispatch Sale Agreement under the OG&E market-based rate tariff under the rates, terms and conditions agreed to thereunder.

D)	By 1130, central prevailing time on the business day prior to energy delivery, OG&E will provide OMPA with a written confirmation of OMPA’s schedule which will include: Quantity, time and anticipated delivery points.

E)	By 1130 central prevailing time on the business day prior to Energy delivery from the Power Plant, OG&E will provide OMPA and its designated fuel supplier (if other than OG&E) with a written confirmation of OMPA’s fuel nomination which will include: Quantity and time of delivery.

III.

Restart

If OG&E provides power from alternate energy sources and decides to restart the Power Plant after the dispatch notification time period:

A)	OG&E will notify OMPA and its designated fuel supplier (if other than OG&E) that it has elected to restart the Power Plant.

If energy delivery from alternate resources is in progress, OG&E will have full rights to the ramp energy (the energy produced from the time start up commences until the earlier of (1) the time that OMPA’s pro rata share of the Energy produced is equal to the replacement Energy, or (2) the time that the Power Plant reaches its then available capacity as set forth in a written notice from OG&E to OMPA and its designated fuel supplier.

OG&E will notify OMPA and its designated fuel supplier (if other than OG&E) of resource changes at the occurrence of the earlier of (1) the time that OMPA’s pro rata share of the Energy produced is equal to the replacement Energy, or (2) the time that the Power Plant reaches its then available capacity as set forth in a written notice from OG&E to OMPA and its designated fuel supplier (if other than OG&E).

IV.

Intraday Changes

A)	If the Power Plant is on-line:

Intraday changes to the schedule will be allowed provided that notification is made at least one (1) hour prior to the implementation of the schedule change. OMPA cannot request a change in schedule that will require the Power Plant to run outside prudent operating parameters, such as ramp rate and minimum operating load.

B)	If OMPA is being served from alternate energy sources and the Power Plant is not on-line;

No intraday changes will be allowed, except by mutual agreement.

OMPA can elect to market excess energy on a real time basis.

C)	If OMPA is being served from alternate energy sources and the Power Plant is on-line due to a restart:

OMPA will not be allowed to reduce the scheduled quantities or change the scheduled delivery point, except by mutual agreement.

OMPA can elect to market energy on a real time basis.

If OMPA is receiving less than its Ownership Ratio equivalent of the Power Plant’s output from an alternate source, it can request additional energy up to a total delivered energy amount equivalent to its Ownership Ratio equivalent of the Power Plant’s output.

If OMPA is receiving its Ownership Ratio equivalent of the Power Plant’s output from an alternate energy source, it can elect to purchase energy from the Power Plant at the prevailing market price provided that notification is made at least one (1) hour prior to the implementation of the schedule change.

D)	In the event that the Power Plant were to experience a transient event which results in a schedule curtailment, OG&E will notify OMPA and its designated fuel supplier (if other than OG&E) within fifteen minutes after the event occurs.

Exhibit 10.05

OPERATING AND MAINTENANCE AGREEMENT

for the

TRANSMISSION ASSETS OF THE
MCCLAIN GENERATING FACILITY

by and between

OKLAHOMA MUNICIPAL POWER AUTHORITY

and

OKLAHOMA GAS AND ELECTRIC COMPANY

dated as of August 25, 2003

		Page
ARTICLE I	OPERATIONS AND MAINTENANCE; PAYMENT	2
1.01	Operations and Maintenance Services	2
1.02	Payments for Service	2
1.03	Invoice or Payment Disputes or Errors	2
1.04	Interest on Late Payments	2
1.05	Audit	3
ARTICLE II	TERMS OF AGREEMENT; TERMINATION	3
2.01	Term	3
ARTICLE III	MISCELLANEOUS	3
3.01	Entire Agreement	3
3.02	Amendments	3
3.03	Captions	4
3.04	Notices	4
3.05	Severability	5
3.06	Assignment	5
3.07	No Waiver	5
3.08	Governing Law	6
3.09	No Partnership Created	6
3.10	Consequential Damages	6
3.11	Limitations Application	6
3.12	Interpretation	6
3.13	Dispute Resolution; Arbitration	6
3.14	Tax Covenant	8

-i-

OPERATING AND MAINTENANCE AGREEMENT

This OPERATING AND MAINTENANCE AGREEMENT, dated as of August 25, 2003 (this “Agreement”), is entered into by and between the OKLAHOMA MUNICIPAL POWER AUTHORITY, a governmental agency and body politic and corporate of the State of Oklahoma (“OMPA”), and OKLAHOMA GAS AND ELECTRIC COMPANY, an Oklahoma corporation (“OG&E”).

Recitals

B. Pursuant to the Asset Purchase Agreement dated as of August 18, 2003 by and between OG&E and NRG McClain, OG&E has agreed to purchase all of NRG McClain’s right, title and interest in the Facility (the “Asset Purchase Agreement”) and will become the owner of NRG McClain’s right, title and interest in the Facility upon closing of the transactions contemplated by and in accordance with the Asset Purchase Agreement (the “Power Plant Closing”);

D. Prior to the Effective Date, OG&E and OMPA will enter into a Facility Operating Agreement (the “Facility Operating Agreement”) pursuant to which OG&E will agree to provide operation and maintenance services with respect to the generation assets (the “Generation Assets”) of the Facility;

E. Effective as of the Effective Date, OMPA and OG&E agree that OG&E will also provide operation and maintenance services as they relate to the transmission assets (the “Transmission Assets”) of the Facility described on Exhibit A-1 and Exhibit A-2 hereto; and

F. OMPA and OG&E agree that the operation and maintenance services to be provided by OG&E with respect to the Facility shall be exclusively regulated by (i) the Facility Operating Agreement as they relate to the Generation Assets, and (ii) this Agreement as they relate to the Transmission Assets.

Agreement

ARTICLE I

OPERATIONS AND MAINTENANCE; PAYMENTS

1.01 Operations and Maintenance Services. As Operator of the Facility, OG&E hereby agrees to provide, in accordance with Prudent Operating Practices, and make available to OMPA, all necessary operating and maintenance services with respect to the Transmission Assets, including without limitation, those services to be provided pursuant to a subcontract with a third-party (an “O&M Subcontract”), if any, and any major maintenance contracts for which OMPA is obligated to make payments under this Agreement. In connection therewith, OG&E shall be solely liable for all payments to be made in providing operation and maintenance services under this Agreement or any O&M Subcontract. For purposes of this Agreement, “Prudent Operating Practices” means the practices, methods and acts (including but not limited to the generally accepted practices, methods and acts engaged in or approved by the operators of similar electric generating facilities) which at the time such practice, method or act is employed, and in the exercise of reasonable judgment in light of the facts known at such time, would be expected to accomplish the desired result in a workmanlike manner, consistent with (a) applicable laws and governmental requirements, and (b) reliability, safety and environmental protection. Prudent Operating Practices shall not require the use of the optimum practice, method or act, but only requires the use of acceptable practices, methods or acts generally accepted in the United States in performing obligations in accordance with Prudent Operating Practices.

1.02 Payments for Service. OG&E shall invoice OMPA monthly for OMPA’s Ownership Ratio of the costs of the services provided by OG&E as Operator pursuant to Section 1.01 above and for OMPA’s Ownership Ratio of the costs for any services that will be provided with respect to the Transmission Assets pursuant to a separate maintenance contract or contracts with a supplier which is unaffiliated with OG&E or OMPA.

1.03 Invoice or Payment Disputes or Errors. If either OG&E or OMPA discovers an error in the amount of any invoice or payment made pursuant to this Article I or if OMPA disputes a payment requested pursuant to this Article I, such party shall notify the other party within 60 days of discovery of such dispute or error, provided that neither party shall be entitled to correction of any such error if notice of such error is not delivered in writing to the other party within three years of the applicable invoice or payment. If OMPA disputes the amount of any invoice, it shall nevertheless pay the full amount of such invoice, subject to a right to a refund if the dispute is resolved in OMPA’s favor, and failure to pay such amount in dispute shall be deemed to be a default hereunder. Any disputes resulting from this Article I shall be settled in accordance with Section 3.14.

1.04 Interest on Late Payments. Any amounts (a) disputed and subsequently found to have been correctly invoiced or owed, or (b) not timely paid in accordance with this Agreement shall accrue interest at the lesser of (i) the then effective prime rate of Citibank, N.A. plus 2%, or (ii) the highest rate permitted by applicable law, from the day on which such amounts become due and owing to the day on which such amounts and the interest thereon are paid. OMPA and OG&E intend that this Agreement shall at all times comply with applicable law now or hereafter in effect governing interest payable hereunder. If the applicable law is ever revised, repealed, or judicially interpreted so as to render usurious any amount called for under this Agreement, then all excess amounts theretofore collected shall be credited to the then applicable principal balance hereunder or be refunded, and this Agreement shall immediately be deemed to have been reformed and the amounts thereafter collected hereunder reduced, without the necessity of the execution of any new document, so as to comply with the then applicable law, but to permit the recovery of the fullest amount otherwise called for hereunder.

1.05 Audit. During ordinary business hours and upon reasonable notice to OG&E, OMPA may inspect, copy and audit OG&E’s books, records, accounts, ledgers, time cards, estimates, schedules, correspondence and other documents related to OG&E’s performance of its obligations hereunder and amounts due to OG&E hereunder. OG&E agrees to keep such records for five years following their respective preparation (at which time it will be permitted to destroy such books and records in the ordinary course of business) and will furthermore keep any such books and records not previously destroyed in the ordinary course of business, for six years after the termination of this Agreement, and shall provide copies to OMPA upon request, at OMPA’s expense. OMPA’s acceptance or approval or payment of OG&E’s charges shall not operate as a waiver of OMPA’s right to audit OG&E in accordance with this Section 1.05.

ARTICLE II

TERM OF AGREEMENT; TERMINATION

2.01 Term. This Agreement shall become effective as of the Effective Date and shall remain in effect until the date that is one day prior to the date that is three years after such date. Unless either party delivers written notice to the other party of such party’s intent to terminate this Agreement effective as of the end of such term on or before the date that is one day after the date that is one year prior to the end of such term (such date, the “Notification Deadline Date”), then, effective as of the Notification Deadline Date, the term of this Agreement shall be extended for an additional two years beyond the end of its original term. The parties expressly waive any other notification of the Notification Deadline Date as may be provided by law.

ARTICLE III

MISCELLANEOUS

3.01 Entire Agreement. This Agreement contains the entire understanding of the parties with respect to the subject matter hereof and supersede all prior agreements and

commitments with respect thereto. There are no oral understandings, terms or conditions and neither party has relied upon any representation, expressed or implied, not contained in this Agreement. This Agreement may be signed in counterparts.

3.02 Amendments. No change, amendment, or modification of this Agreement shall be valid or binding upon the parties hereto unless such change, amendment, or modification shall be in writing and duly executed by the parties hereto.

3.03 Captions. The captions and subheadings contained in this Agreement are for convenience and reference only and in no way define, describe, extend, or limit the scope or intent of this Agreement or the intent of any provision contained herein.

3.04 Notices. Except as otherwise expressly provided herein, any notice, demand, offer, or other instrument required or permitted to be given pursuant to this Agreement shall be in writing, signed by the party giving such notice, demand, offer, or other instrument and shall be delivered by telecopier, hand delivery, registered or certified mail, return receipt requested, postage prepaid, or nationally recognized overnight courier to the other party at the address set forth below:

If to OMPA:
	Oklahoma Municipal Power Authority
	Street Address: 2300 East Second Street Edmond, OK 73034 Post Office Address: P.O. Box 1960 Edmond, OK 73083-1960
	Facsimile No. (405) 359-1071 Attn: General Manager

With a copy to:
	Oklahoma Municipal Power Authority
	Street Address: 2300 East Second Street Edmond, OK 73034 Post Office Address: P.O. Box 1960 Edmond, OK 73083-1960
	Facsimile No. (405) 359-1071 Attn: General Counsel

If to OG&E:
	Oklahoma Gas and Electric Company PO Box 321 Oklahoma City, Oklahoma 73101-0321 Attention: Jack T. Coffman Facsimile No.: (405) 553-3198
With a copy to:
	Jones Day 77 West Wacker Drive, Suite 3500 Chicago, Illinois 60601-1692 Attention: Peter D. Clarke Facsimile No.: (312) 782-8585

3.05 Severability. The invalidity of one or more of the provisions or sections contained in this Agreement shall not affect the validity of the remaining portion of the Agreement so long as the material purposes of this Agreement can be determined and effectuated. In the event that any portion or all of this Agreement is held to be void or unenforceable, the parties agree to negotiate in good faith to reach an equitable agreement on such portion that is void or unenforceable which shall effect the intent of the parties as set forth in this Agreement. In the event that the parties do not mutually agree on what changes to make, if any, within 60 days after the such portion or all of this Agreement is held to be void or

unenforceable, either party may initiate the dispute resolution procedures set forth in Article VI with respect to the obligation to negotiate in good faith.

3.06 Assignment. This Agreement shall be binding upon, shall inure to the benefit of, and may be performed by, the successors and assigns of the parties hereto. No assignment, pledge, or other transfer of this Agreement by either party shall be made without the other party’s prior written consent, nor shall it operate to release the assignor, pledgor, or transferor from any of its obligations under this Agreement.

3.07 No Waiver. Any failure of either party to enforce any of the provisions of this Agreement or to require compliance with any of its provisions at any time during the pendency of this Agreement shall in no way affect the validity of this Agreement, or any part hereof, and shall not be deemed a waiver of the right of either party thereafter to enforce any and each such provision.

3.08 Governing Law. THIS AGREEMENT SHALL BE GOVERNED BY, CONSTRUED, INTERPRETED AND ENFORCED IN ACCORDANCE WITH, THE SUBSTANTIVE LAW OF THE STATE OF OKLAHOMA WITHOUT REFERENCE TO ANY PRINCIPLES OF CONFLICTS OF LAWS THEREOF.

3.09 No Partnership Created. Nothing contained in this Agreement shall be construed as constituting a joint venture or partnership between OMPA and OG&E.

3.10 Consequential Damages. Neither party shall in any event be responsible or liable to the other party for consequential damages, including, without limitation, liability for loss of use of the Facility or existing property, loss of profits, loss of product or business interruption, however caused, except to the extent any indemnification hereunder is deemed to be consequential damages.

3.11 Limitations Application. Neither party makes any representations, covenants, warranties or guarantees, express or implied, other than those expressly set forth herein. The parties’ rights, liabilities, responsibilities and remedies with respect to the obligations to be performed under this Agreement, whether in contract or otherwise, shall be exclusively those expressly set forth in this Agreement.

3.12 Interpretation. The parties intend that this Agreement shall comply with Rev. Proc. 97-13, and this Agreement shall be interpreted accordingly.

3.13 Dispute Resolution; Arbitration.

(b) If the parties are unable to resolve a dispute as provided in Section 3.13(a), each party has the right to (i) pursue any legal and/or equitable remedies in the District Court of Oklahoma County or such other court of proper jurisdiction or (ii) seek to arbitrate the dispute using the procedures specified in Section 3.13(c); which election shall be binding upon such party with respect to the dispute at issue.

(c) If so elected by a party and the other Party agrees in writing, a dispute shall be arbitrated in accordance with the following procedures:

consents to service of process by registered mail at its address set forth herein and agrees that its submission to jurisdiction and its consent to service of process by mail is made for the express benefit of the other party.

(5) This Agreement and the rights and obligations of the parties shall remain in full force and effect pending the award in any arbitration proceeding hereunder.

(6) Unless otherwise ordered by the arbitrators, each party shall bear its own costs and fees, including attorneys’ fees and expenses. The parties expressly agree that the arbitrators shall have no power to consider or award any form of damages barred by Section 3.10, or any other multiple or enhanced damages, whether statutory or common law.

3.14 Tax Covenant. For as long as OMPA’s Ownership Ratio in the Facility is financed or refinanced with tax exempt financing, OG&E will take no action which OMPA determines, on the basis of opinion of counsel, will adversely affect the exclusion from gross income, for federal income tax purposes, of the interest on securities issued or to be issued by OMPA in such financing or refinancing.

IN WITNESS WHEREOF, the parties have executed this Agreement as of the date first above written.

	OKLAHOMA MUNICIPAL POWER AUTHORITY
	By:	/s/ Roland Dawson
	Name:	Roland Dawson
	Title:	General Manager

	OKLAHOMA GAS AND ELECTRIC COMPANY
	By:	/s/ Al Strecker
	Name:	Al Strecker
	Title:	Executive Vice President and Chief
		Operating Officer

EXHIBIT A-1

TRANSMISSION ASSETS

One line diagram

A-1

EXHIBIT A-2

TRANSMISSION ASSETS

Electrical Equipment List

Quantity		Description
2 1 2		Transformer, 18 - 142 kV, 116/154/193 MVA Transformer, 18 - 142 kV, 134/178/223 MVA Circuit Breaker, 6900A, 63kA Sym Int

A-2

Exhibit 31.01

CERTIFICATIONS

I, Steven E. Moore, certify that:

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

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

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

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

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

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

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

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

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

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

Date: August 3, 2004

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

Exhibit 31.01

CERTIFICATIONS

I, James R. Hatfield, certify that:

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

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

Date: August 3, 2004

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

Exhibit 32.01

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

In connection with the Quarterly Report of OGE Energy Corp. (the "Company") on Form 10-Q for the period ended June 30, 2004, as filed with the Securities and Exchange Commission (the "Report"), each of the undersigned does hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

August 3, 2004

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

OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2004

TABLE OF CONTENTS

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

Reclassifications

2. Accounting Pronouncements

3. Price Risk Management Assets and Liabilities

4. Accumulated Other Comprehensive Loss

5. Enogex – Discontinued Operations

6. Asset Disposals

7. Impairment of Assets

8. Supplemental Cash Flow Information

9. Common Stock

10. Earnings Per Share

11. Long-Term Debt

Fair Value Hedges

Cash Flow Hedges

12. Short-Term Debt

13. Retirement Plans and Postretirement Benefit Plans

14. Report of Business Segments

15. Commitments and Contingencies

16. Rate Matters and Regulation

Recent Regulatory Matters

Pending Regulatory Matters

17. Fair Value of Financial Instruments

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

Introduction

Forward-Looking Statements

Overview

Outlook

Results of Operations

Operating Income by Business Segment

Financial Condition

Off-Balance Sheet Arrangements

Liquidity and Capital Requirements

Fair Value Hedges

Cash Flow 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 4. Submission of Matters to a Vote of Security Holders.

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

(a) Exhibits

(b) Reports on Form 8-K

SIGNATURE

Exhibit 2.01

AMENDMENT NO. 8 TO ASSET PURCHASE AGREEMENT

RECITALS

ARTICLE I Amendment to Agreement

ARTICLE II Miscellaneous

AMENDMENT NO. 9 TO ASSET PURCHASE AGREEMENT

RECITALS

ARTICLE I Amendment to Agreement

ARTICLE II Miscellaneous

AMENDMENT NO. 10 TO ASSET PURCHASE AGREEMENT

RECITALS

ARTICLE I Amendment to Agreement

ARTICLE II Miscellaneous

CONSULTING AGREEMENT BETWEEN OG&E ENERGY CORP. AND AL STRECKER

AMENDED AND RESTATED

FACILITY OPERATING AGREEMENT

for the

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.

ARTICLE I
Amendment to Agreement

ARTICLE II
Miscellaneous

ARTICLE I
Amendment to Agreement

ARTICLE II
Miscellaneous

ARTICLE I
Amendment to Agreement

ARTICLE II
Miscellaneous

CONSULTING AGREEMENT BETWEEN
OG&E ENERGY CORP. AND AL STRECKER

EXHIBIT B
TO

To Ownership
and Operation Agreement

TRANSMISSION ASSETS OF THE
MCCLAIN GENERATING FACILITY