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, 2003

[ ]	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, 2003, 80,608,557 shares of common stock, par value $0.01 per share, were outstanding.

OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2003

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	34
Item 3. Quantitative and Qualitative Disclosures About Market Risk	67
Item 4. Controls and Procedures	69
Part II - OTHER INFORMATION
Item 1. Legal Proceedings	70
Item 4. Submission of Matters to a Vote of Security Holders	72
Item 6. Exhibits and Reports on Form 8-K	73
Signature	74

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

	June 30, 2003			December 31, 2002
	(In millions)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	22	.5	$	44	.4
Accounts receivable, net		307	.0		304	.6
Accrued unbilled revenues		64	.8		28	.2
Fuel inventories		120	.5		99	.7
Materials and supplies, at average cost		40	.6		42	.6
Price risk management		54	.7		17	.1
Pipeline imbalance		36	.6		34	.3
Accumulated deferred tax assets		10	.5		10	.9
Fuel clause under recoveries		38	.3		14	.7
Other		4	.9		10	.6
Current assets of discontinued operations		0	.1		4	.7

Total current assets		700	.5		611	.8

OTHER PROPERTY AND INVESTMENTS, at cost		28	.2		27	.2

PROPERTY, PLANT AND EQUIPMENT
In service		5,554	.9		5,469	.7
Construction work in progress		51	.2		44	.8
Other		29	.2		30	.5

Total property, plant and equipment		5,635	.3		5,545	.0
Less accumulated depreciation		2,298	.2		2,231	.4

Net property, plant and equipment		3,337	.1		3,313	.6
In service of discontinued operations		-	--		54	.2
Less accumulated depreciation		-	--		11	.4

Net property, plant and equipment of discontinued
operations		-	--		42	.8

Net property, plant and equipment		3,337	.1		3,356	.4

DEFERRED CHARGES AND OTHER ASSETS
Recoverable take or pay gas charges		32	.5		32	.5
Income taxes recoverable from customers, net		32	.4		34	.8
Intangible asset - unamortized prior service cost		42	.7		42	.7
Prepaid benefit obligation		25	.3		44	.9
Price risk management		28	.8		20	.1
Other		60	.4		80	.8
Deferred charges and other assets of discontinued operations		-	--		0	.2

Total deferred charges and other assets		222	.1		256	.0

TOTAL ASSETS	$	4,287	.9	$	4,251	.4

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

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

	June 30, 2003			December 31, 2002
	(In millions)
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term debt	$	257	.1	$	275	.0
Accounts payable		276	.8		269	.0
Dividends payable		26	.6		26	.1
Customers' deposits		34	.7		33	.0
Accrued taxes		43	.4		23	.6
Accrued interest		35	.2		35	.7
Tax collections payable		9	.6		6	.7
Accrued vacation		17	.4		16	.9
Long-term debt due within one year		31	.0		21	.0
Price risk management		45	.0		13	.9
Pipeline imbalance		13	.6		9	.4
Other		19	.5		19	.4
Current liabilities of discontinued operations		-	--		2	.0

Total current liabilities		809	.9		751	.7

LONG-TERM DEBT		1,480	.0		1,501	.9

DEFERRED CREDITS AND OTHER LIABILITIES
Accrued pension and benefit obligations		189	.5		184	.2
Accumulated deferred income taxes		617	.7		627	.0
Accumulated deferred investment tax credits		44	.6		47	.1
Accrued removal obligations, net		112	.7		109	.3
Price risk management		3	.6		0	.6
Provision for payments of take or pay gas		32	.5		32	.5
Other		5	.7		4	.1
Deferred credits and other liabilities of discontinued operations		-	--		9	.1

Total deferred credits and other liabilities		1,006	.3		1,013	.9

STOCKHOLDERS' EQUITY
Common stockholders' equity		482	.5		453	.5
Retained earnings		583	.8		604	.7
Accumulated other comprehensive loss, net of tax		(74	.6)		(74	.3)

Total stockholders' equity		991	.7		983	.9

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	4,287	.9	$	4,251	.4

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,
	2003			2002			2003			2002
	(In millions, except per share data)
OPERATING REVENUES
Electric Utility operating revenues	$	357	.9	$	352	.2	$	690	.5	$	614	.3
Natural Gas Pipeline operating revenues		494	.7		378	.6		1,212	.2		692	.3

Total operating revenues		852	.6		730	.8		1,902	.7		1,306	.6
COST OF GOODS SOLD
Electric Utility cost of goods sold		175	.8		169	.6		379	.7		309	.4
Natural Gas Pipeline cost of goods sold		446	.2		338	.4		1,110	.6		612	.4

Total cost of goods sold		622	.0		508	.0		1,490	.3		921	.8
Gross margin on revenues		230	.6		222	.8		412	.4		384	.8
Other operation and maintenance		93	.1		96	.4		183	.4		181	.5
Depreciation		43	.0		46	.0		89	.6		91	.2
Impairment of assets		1	.0		-	--		1	.0		-	--
Taxes other than income		16	.9		16	.3		34	.1		33	.0

OPERATING INCOME		76	.6		64	.1		104	.3		79	.1

OTHER INCOME (EXPENSE)
Other income		0	.6		0	.5		6	.7		0	.9
Other expense		(0	.6)		(0	.9)		(3	.6)		(1	.8)

Net other income (expense)		-	--		(0	.4)		3	.1		(0	.9)

INTEREST INCOME (EXPENSE)
Interest income		0	.1		0	.5		0	.3		1	.0
Interest on long-term debt		(19	.2)		(21	.7)		(38	.2)		(43	.8)
Interest on trust preferred securities		(4	.3)		(4	.3)		(8	.6)		(8	.6)
Allowance for borrowed funds used during construction		0	.1		0	.3		0	.4		0	.7
Interest on short-term debt and other interest charges		(1	.7)		(1	.6)		(3	.5)		(4	.1)

Net interest expense		(25	.0)		(26	.8)		(49	.6)		(54	.8)

INCOME FROM CONTINUING OPERATIONS BEFORE
TAXES		51	.6		36	.9		57	.8		23	.4
INCOME TAX EXPENSE		19	.4		11	.7		21	.3		6	.6

INCOME FROM CONTINUING OPERATIONS BEFORE
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE		32	.2		25	.2		36	.5		16	.8
DISCONTINUED OPERATIONS
Income from discontinued operations		-	--		3	.2		2	.2		4	.9
Income tax expense (benefit)		-	--		-	--		0	.9		(0	.4)

Income from discontinued operations		-	--		3	.2		1	.3		5	.3

INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE		32	.2		28	.4		37	.8		22	.1
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING FOR
ENERGY TRADING CONTRACTS, NET OF TAX OF $3.7		-	--		-	--		(5	.9)		-	--

NET INCOME	$	32	.2	$	28	.4	$	31	.9	$	22	.1

BASIC AVERAGE COMMON SHARES OUTSTANDING		79	.2		78	.0		78	.9		78	.0
DILUTED AVERAGE COMMON SHARES OUTSTANDING		79	.4		78	.0		79	.2		78	.0
BASIC EARNINGS PER AVERAGE COMMON SHARE
Income from continuing operations	$	0	.41	$	0	.32	$	0	.46	$	0	.21
Income from discontinued operations, net of tax		-	--		0	.04		0	.01		0	.07
Loss from cumulative effect of accounting change, net of tax		-	--		-	--		(0	.07)		-	--

NET INCOME	$	0	.41	$	0	.36	$	0	.40	$	0	.28

DILUTED EARNINGS PER AVERAGE COMMON SHARE
Income from continuing operations	$	0	.41	$	0	.32	$	0	.46	$	0	.21
Income from discontinued operations, net of tax		-	--		0	.04		0	.01		0	.07
Loss from cumulative effect of accounting change, net of tax		-	--		-	--		(0	.07)		-	--

NET INCOME	$	0	.41	$	0	.36	$	0	.40	$	0	.28

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,
	2003			2002
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	31	.9	$	22	.1
Adjustments to reconcile net income to net cash provided from
operating activities
Income from discontinued operations		(1	.3)		(5	.3)
Cumulative effect of change in accounting principle		5	.9		-	--
Depreciation		89	.6		91	.2
Impairment of assets		1	.0		-	--
Deferred income taxes and investment tax credits, net		(3	.1)		23	.5
Gain on sale of assets		(5	.7)		(0	.5)
Ineffectiveness of interest rate swap		-	--		0	.2
Price risk management assets		(39	.0)		8	.9
Price risk management liabilities		33	.2		5	.1
Other assets		18	.2		0	.3
Other liabilities		1	.8		2	.6
Change in certain current assets and liabilities
Accounts receivable, net		5	.5		(26	.0)
Accrued unbilled revenues		(36	.6)		(28	.6)
Fuel, materials and supplies inventories		(28	.3)		(11	.2)
Pipeline imbalance asset		(2	.3)		(12	.0)
Fuel clause under recoveries		(23	.6)		-	--
Other current assets		5	.7		3	.8
Accounts payable		7	.8		38	.6
Customers' deposits		1	.7		2	.0
Accrued taxes		23	.5		2	.9
Accrued interest		(0	.5)		(1	.0)
Fuel clause over recoveries		-	--		(14	.5)
Pipeline imbalance liability		4	.2		6	.2
Other current liabilities		4	.7		6	.9

Net Cash Provided from Operating Activities		94	.3		115	.2

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(91	.8)		(154	.3)
Proceeds from sale of assets		9	.9		0	.6
Other investing activities		(0	.4)		(0	.3)

Net Cash Used in Investing Activities		(82	.3)		(154	.0)

CASH FLOWS FROM FINANCING ACTIVITIES
Retirement of long-term debt		(19	.0)		(31	.0)
(Decrease) increase in short-term debt, net		(17	.9)		77	.2
Premium on issuance of common stock		15	.4		0	.2
Distribution to minority interest		(2	.5)		-	--
Dividends paid on common stock		(47	.8)		(51	.9)

Net Cash Used in Financing Activities		(71	.8)		(5	.5)

DISCONTINUED OPERATIONS
Net cash (used in) provided from operating activities		(0	.6)		21	.3
Net cash provided from (used in) investing activities		38	.5		(3	.4)
Net cash used in financing activities		-	--		(1	.4)

Net Cash Provided from Discontinued Operations		37	.9		16	.5

NET DECREASE IN CASH AND CASH EQUIVALENTS		(21	.9)		(27	.8)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		44	.4		37	.5

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	22	.5	$	9	.7

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 significant 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 sold its retail gas business in 1928 and is no longer engaged in the gas distribution business. OG&E is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area.

The Natural Gas Pipeline segment is conducted through Enogex Inc. and its subsidiaries (“Enogex”) and consists of three related businesses: (i) the transportation and storage of natural gas, (ii) the gathering and processing of natural gas and (iii) the marketing and trading of natural gas. 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's focus is to utilize its processing, transportation and storage capacity and execute physical, financial and service transactions to capture revenues across different commodities, locations, or time periods. Enogex was previously engaged in the exploration and production of natural gas, however, this portion of Enogex’s business, along with interests in certain gas gathering and processing assets in Texas, were sold in 2002 and in the first quarter of 2003 and are reported in the 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, 2003 and December 31, 2002, the results of its operations for the three and six months ended June 30, 2003 and 2002, and the results of its cash flows for the six months ended June 30, 2003 and 2002, 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, 2003 are not necessarily indicative of the results that may be expected for the year ending December 31, 2003 or for any future period. The accompanying 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, 2002.

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. At June 30, 2003 and December 31, 2002, regulatory assets of approximately $59.6 million and approximately $63.9 million, respectively, are being amortized and reflected in rates charged to customers over periods of up to 20 years. At June 30, 2003 and December 31, 2002, regulatory liabilities of approximately $112.7 million and approximately $109.3 million, respectively, have been reclassified from Accumulated Depreciation in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations.”

OG&E initially records 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 the Company's regulatory assets and liabilities at:

(In millions)	June 30, 2003			December 31, 2002
Regulatory Assets
Income taxes recoverable from customers, net	$	32	.4	$	34	.8
Unamortized loss on reacquired debt		22	.7		23	.3
January 2002 ice storm		3	.6		5	.4
Miscellaneous		0	.9		0	.4

Total Regulatory Assets	$	59	.6	$	63	.9

Regulatory Liabilities
Accrued removal obligations, net	$	112	.7	$	109	.3

Total Regulatory Liabilities	$	112	.7	$	109	.3

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.”

Accrued removal obligations represent asset retirement costs previously recovered from ratepayers for other than legal obligations. In accordance with SFAS No. 143, the Company was required to reclassify the accrued removal obligations, which had previously been recorded as a liability in Accumulated Depreciation, to a regulatory liability. See Note 2 for a further discussion.

Management continuously monitors the future recoverability of regulatory assets. When, in management’s judgment, future recovery becomes impaired, the amount of the regulatory asset is reduced or written off, as appropriate.

If the Company were required to discontinue the application of SFAS No. 71 for some or all of its operations, it could result in writing off the related regulatory assets and liabilities; the financial effects of which could be significant.

Use of Estimates

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. In management’s opinion, the areas of the Company where the most significant judgment is exercised are in the valuation of pension plan assumptions, impairment estimates, contingency reserves, unbilled revenue for OG&E, the allowance for uncollectible accounts receivable and the valuation of energy purchase and sale contracts and natural gas storage inventory.

Allowance for Uncollectible Accounts Receivable

For OG&E, all customer balances are written off if not collected within six months after the account is finalized. The allowance for uncollectible accounts receivable for OG&E is calculated by multiplying the last six months of electric revenue by the provision rate. The provision rate is based on a 12-month historical average of actual balances written off. To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. The allowance for uncollectible accounts receivable for Enogex is established on a case-by-case basis when the Company believes the required payment of specific amounts owed is unlikely to occur. The allowance for uncollectible accounts receivable was approximately $7.8 million and $13.6 million at June 30, 2003 and December 31, 2002, respectively.

Impairment of Assets

The Company assesses potential impairments of assets when there is evidence that events or changes in circumstances indicate that an asset’s carrying value may not be recoverable. An impairment loss is recognized when the sum of the expected future net cash flows is less than the carrying amount of the asset. The amount of any recognized impairment is based on the estimated fair value of the asset subject to impairment compared to the carrying amount of such asset.

Income Taxes

The Company files consolidated income tax returns. Income taxes are allocated to each affiliate based on its separate taxable income or loss. Investment tax credits on electric utility property have been deferred and are being amortized to income over the life of the related property.

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.

Cash and Cash Equivalents

For purposes of the condensed consolidated financial statements, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. These investments are carried at cost, which approximates fair value.

Revenue Recognition

OG&E

OG&E reads its customers’ meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers’ electricity consumption that has not been billed at the end of each month. An amount is accrued as a receivable for this unbilled revenue based on estimates of usage and prices during the period. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.

Enogex

The Company recognizes revenue from natural gas gathering and processing and transportation and storage services to third parties as services are provided. Revenue associated with natural gas liquids is recognized when the production is processed and sold. Substantially all of OGE Energy Resources, Inc.’s (“OERI”) natural gas and power marketing contracts qualify as derivatives and, therefore, are accounted for at fair value as prescribed in SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. Under fair value accounting, fixed-price forwards, swaps, options, futures and other financial instruments with third parties are recorded at estimated fair market values, net of reserves, with the corresponding market changes in fair value recognized in earnings and offsetting amounts recorded as Price Risk Management assets and liabilities in the accompanying Condensed Consolidated Balance Sheets. See Note 2 for a further discussion.

Automatic Fuel Adjustment Clauses

Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component in the cost-of-service for ratemaking, are passed through to OG&E’s customers through automatic fuel adjustment clauses, which are subject to periodic review by the OCC, the APSC and the FERC.

Fuel Inventories

OG&E

Fuel inventories for the generation of electricity consist of coal, natural gas and oil. These inventories are accounted for under the last-in, first-out (“LIFO”) cost method. The estimated replacement cost of fuel inventories was higher than the stated LIFO cost by approximately $28.9 million and $7.0 million at June 30, 2003 and December 31, 2002, respectively, based on the average cost of fuel purchased.

Enogex

Effective January 1, 2003, natural gas storage inventory used in OERI’s business activities are accounted for at the lower of cost or market in accordance with the guidance in Emerging Issues Task Force (“EITF”) Issue No. 02-3, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” which resulted in the rescission of EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” as amended. Prior to January 1, 2003, this inventory was accounted for on a fair value accounting basis utilizing a gas index that in management’s opinion approximated the current market value of natural gas in that region as of the Balance Sheet date. In order to minimize risk, OERI may enter into contracts or hedging instruments to hedge the fair value of this inventory. If these contracts qualify for hedge accounting under SFAS No. 133, the hedged portion of the inventory is recorded at fair value with an offsetting gain or loss recorded currently in earnings. The fair value of the hedging instrument is also recorded on the books of the Company as a Price Risk Management asset or liability with an offsetting gain or loss recorded in current earnings. At June 30, 2003, the Company had all natural gas inventory hedged with qualified fair value hedges under SFAS No. 133. As part of its recurring business activity, OERI injects and withdraws natural gas under the terms of storage capacity contracts; the amount of natural gas inventory was approximately $53.7 million and $32.9 million at June 30, 2003 and December 31, 2002, respectively. See Note 2 for a further discussion.

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.

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,
	2003			2002			2003			2002
	(In millions, except per share data)
Net income, as reported	$	32	.2	$	28	.4	$	31	.9	$	22	.1
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	.4		0	.3		0	.7		0	.6

Pro forma net income	$	31	.8	$	28	.1	$	31	.2	$	21	.5

Income per average common share
Basic - as reported	$	0	.41	$	0	.36	$	0	.40	$	0	.28
Basic - pro forma	$	0	.40	$	0	.36	$	0	.40	$	0	.28
Diluted - as reported	$	0	.41	$	0	.36	$	0	.40	$	0	.28
Diluted - pro forma	$	0	.40	$	0	.36	$	0	.39	$	0	.28

Reclassifications

Certain prior year amounts have been reclassified on the condensed consolidated financial statements to conform to the 2003 presentation.

2. Accounting Pronouncements

In June 2001, the FASB issued SFAS No. 143, which applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. SFAS No. 143 affects the Company’s accrued plant removal costs for generation, transmission, distribution and processing facilities and requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of the fair value can be made. If a reasonable estimate of the fair value cannot be made in the period the asset retirement obligation is incurred, the liability shall be recognized when a reasonable estimate of the fair value can be made. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes, written or oral contracts, including obligations arising under the doctrine of promissory estoppel. The recognition of an asset retirement obligation is capitalized as part of the carrying amount of

the long-lived asset. Asset retirement obligations represent future liabilities and, as a result, accretion expense is accrued on this liability until such time as the obligation is satisfied. Adoption of SFAS No. 143 is required for financial statements issued for fiscal years beginning after June 15, 2002. The Company adopted this new standard effective January 1, 2003 and the adoption of this new standard did not have a material impact on its consolidated financial position or results of operations. In connection with the adoption of SFAS No. 143, the Company assessed whether it had a legal obligation within the scope of SFAS No. 143. The Company determined that it had a legal obligation to retire certain assets. As the Company currently has no plans to retire any of these assets and the remaining life is indeterminable, an asset retirement obligation was not recognized; however, the Company will monitor these assets and record a liability when a reasonable estimate of the fair value can be made. As described below, amounts recovered from ratepayers related to estimated asset retirement obligations recorded as a liability in Accumulated Depreciation were reclassified as a regulatory liability in the first quarter of 2003.

SFAS No. 143 also requires that, if the conditions of SFAS No. 71 are met, a regulatory asset or liability should be recorded to recognize differences between asset retirement costs recorded under SFAS No. 143 and legal or other asset retirement costs recognized for ratemaking purposes. Upon adoption of SFAS No. 143, the Company was required to quantify the amount of asset retirement costs previously recovered from ratepayers for other than legal obligations and reclassify those differences as regulatory assets or liabilities. At December 31, 2002, approximately $109.3 million had been previously recovered from ratepayers and recorded as a liability in Accumulated Depreciation related to estimated asset retirement obligations. This balance was reclassified as a regulatory liability on the December 31, 2002 Condensed Consolidated Balance Sheet. At June 30, 2003, the regulatory liability for accrued removal obligations, net was approximately $112.7 million.

In July 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 addresses financial accounting and reporting for costs associated with exit and disposal activities and supersedes EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” SFAS No. 146 requires recognition of a liability for a cost associated with an exit or disposal activity when the liability is incurred, as opposed to when the entity commits to an exit plan under EITF 94-3. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Adoption of SFAS No. 146 is required for exit and disposal activities initiated after December 31, 2002. The Company adopted this new standard effective January 1, 2003 and the adoption of this new standard did not have a material impact on its consolidated financial position or results of operations.

effective January 1, 2003 and the application of this consensus did not have a material impact on its consolidated financial position or results of operations as this consensus supports the Company’s historical presentation of financial derivative contracts.

In October 2002, the EITF reached a consensus to rescind EITF 98-10 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 are no longer marked to market through earnings unless the contracts meet the definition of a derivative under SFAS No. 133. Application of the consensus for energy contracts and inventory that existed on or before October 25, 2002 that remained 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 will be carried at fair value. The Company adopted this consensus effective January 1, 2003 resulting in an approximate $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, 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 gross margin on revenues in excess of the cumulative effect loss described above.

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 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation which includes the prospective method, modified prospective method and retroactive restatement method. SFAS No. 148 also amends 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. Adoption of the annual disclosure and voluntary transition requirements of SFAS No. 148 is required for annual financial statements issued for fiscal years ending after December 15, 2002. Adoption of the interim disclosure requirements of SFAS No. 148 is required for interim periods beginning after December 15, 2002. Pursuant to the provisions of SFAS No. 123, the Company has elected to continue using the intrinsic value method of accounting for its stock-based employee compensation plans in accordance with APB 25. However, the Company has included the required disclosures under SFAS No. 148 in Note 1.

In December 2002, the FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” Interpretation No. 45 requires that at the time a company issues a guarantee, the company must recognize an initial liability for the fair value, or market value, of the obligations it assumes under that guarantee. Interpretation No. 45 is applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The Company adopted this new interpretation effective January 1, 2003 and the adoption of this new interpretation did not have a material impact on its consolidated financial position or results of operations.

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

Interpretation No. 46 applies immediately to variable interest entities created after January 31, 2003, and to variable interest entities in which an enterprise obtains an interest after that date. It applies in the first fiscal year or interim period beginning after June 15, 2003, to variable interest entities in which an enterprise holds a variable interest that it acquired before February 1, 2003. Interpretation No. 46 may be applied prospectively with a cumulative-effect adjustment as of the date on which it is first applied or by restating previously issued financial statements for one or more years with a cumulative-effect adjustment as of the beginning of the first year restated. The Company adopted this new interpretation effective July 1, 2003 and the adoption of this new interpretation is not expected to have a material impact on its consolidated financial position or results of operations.

In April 2003, the FASB issued SFAS No. 149, “Amendments of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain instruments embedded in other contracts and for hedging activities under SFAS No. 133. This statement requires that contracts with comparable characteristics be accounted for similarly. In particular, this statement clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative, clarifies when a derivative contains a financing component, amends the definition of an underlying hedged risk to conform to language used in FASB Interpretation No. 45 and amends certain other existing pronouncements. This statement, the provisions of which are to be applied prospectively, is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The Company adopted this new standard effective July 1, 2003 and the adoption of this new standard is not expected to have a material on its consolidated financial position or results of operations.

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. The requirements of this statement apply to an issuer’s classification and measurement of freestanding financial instruments, including those that comprise more than one option or forward contract. This statement does not apply to features that are embedded in a financial instrument that are not a derivative in its entirety. This statement also addresses questions about the classification of certain financial instruments that embody obligations to issue equity shares. The provisions of this statement are effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The Company adopted

this new standard effective July 1, 2003 and the adoption of this new standard is not expected to have a material impact on its consolidated financial position or results of operations.

3. Price Risk Management Assets and Liabilities

Non-Trading Activities

The Company periodically utilizes derivative contracts to manage exposure to unfavorable changes in commodity prices, as well as to reduce exposure to adverse interest rate fluctuations. During the six months ended June 30, 2003 and 2002, the Company’s use of non-trading price risk management instruments primarily involved the use of interest rate swap agreements to hedge the Company’s exposure to interest rate risk by converting a portion of the Company’s fixed rate debt to a floating rate. These agreements involve the receipt of fixed rate amounts in exchange for floating rate interest payments over the life of the agreement without an exchange of the underlying principal amount. In addition, the Company utilized certain fixed price swap instruments to hedge the price to be received for fuel authorized to be recovered from customers as well as to hedge portions of the Company’s exposure to natural gas liquids prices and natural gas storage activities.

In accordance with SFAS No. 133, the Company recognizes all of its derivative instruments as Price Risk Management assets or liabilities in the Balance Sheet at fair value with such amounts classified as current or long-term based on their anticipated settlement. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation. For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item attributable to the hedged risk are recognized in the same line item associated with the hedged item in current earnings during the period of the change in fair values. For derivatives that are designated and qualify as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of Accumulated Other Comprehensive Income and recognized into earnings in the same period during which the hedged transaction affects earnings. The ineffective portion of a derivative’s change in fair value is recognized currently in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and hedged item during the period of hedge designation. Forecasted transactions designated as the hedged item in a cash flow hedge are regularly evaluated to assess whether they continue to be probable of occurring. If the forecasted transactions are no longer probable of occurring, any gain or loss deferred in Accumulated Other Comprehensive Income is recognized currently in earnings. The Company’s interest rate swap agreements have been designated as fair value hedges and qualified for the shortcut method prescribed by SFAS No. 133. Under the shortcut method, the Company assumes that the hedged item’s change in fair value is exactly as much as the derivative’s change in fair value.

At June 30, 2003, the Company had outstanding cash flow hedges and approximately a $0.3 million after tax loss was included in Accumulated Other Comprehensive Loss. At

December 31, 2002, the Company had no outstanding cash flow hedges, and no amounts were included in Accumulated Other Comprehensive Loss related to cash flow hedges.

Trading Activities

The Company, through its subsidiary, 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. Under the guidance provided by SFAS No. 133, financial instruments that qualify as derivatives are reflected at fair value with the resulting unrealized gains and losses recorded as Price Risk Management assets or liabilities in the accompanying 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 accompanying Condensed Consolidated Statements of Income depending on whether the contract relates to the sale or purchase of the commodity. See Note 2 for a further discussion of the accounting for the Company’s energy trading activities.

4. Comprehensive Income

The components of total comprehensive income for the three and six months ended June 30, 2003 and 2002, respectively, are as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2003			2002			2003			2002
Net income	$	32	.2	$	28	.4	$	31	.9	$	22	.1

Other comprehensive loss, net of tax:
Deferred hedging losses		(0	.5)		-	--		(0	.3)		(0	.1)

Total comprehensive income	$	31	.7	$	28	.4	$	31	.6	$	22	.0

Accumulated other comprehensive loss at both June 30, 2003 and December 31, 2002 included approximately a $74.3 million after tax loss ($121.3 million pre-tax) related to a minimum pension liability adjustment. The Company’s actuarial consultants review the funded status of the pension plan at year end. Any increases or decreases in the minimum pension liability will be reflected in Other Comprehensive Income or Loss in the fourth quarter. Also included at June 30, 2003 was approximately a $0.3 million after tax loss related to outstanding cash flow hedges.

5. Discontinued Operations

On March 25, 2002, Enogex entered into an Agreement of Sale and Purchase with West Texas Gas, Inc. to sell all of its interests in Belvan Corp., Belvan Limited Partnership and Todd Ranch Limited Partnership (“Belvan”) for approximately $9.8 million. The effective date of the

sale was January 1, 2002 and the closing occurred on March 28, 2002. The Company recognized approximately a $1.6 million after tax gain related to the sale of these assets.

On August 5, 2002, Enogex entered into an Agreement of Sale and Purchase with Chesapeake Exploration Limited Partnership to sell all of its exploration and production assets located in Oklahoma, Texas, Arkansas and Mississippi for approximately $15.0 million. The effective date of the sale was July 1, 2002 and the closing occurred on September 19, 2002. The Company recognized approximately a $2.3 million after tax loss related to the sale of these assets.

On November 14, 2002, Enogex entered into an Agreement of Sale and Purchase with Quicksilver Resources, Inc. to sell all of its exploration and production assets located in Michigan for approximately $32.0 million. The effective date of the sale was July 1, 2002 and the closing occurred on December 2, 2002. The Company recognized approximately a $2.9 million after tax gain related to the sale of these assets.

During the third quarter of 2002, the Company decided to sell all of its interests in the NuStar Joint Venture (“NuStar”). On January 23, 2003, Enogex entered into an Agreement of Sale and Purchase with Benedum Gas Partners, L.P. to sell all of the interests of its subsidiary, Enogex Products Corporation, in the west Texas properties consisting of NuStar, which has operations consisting of the extraction and sale of natural gas liquids, for approximately $37.0 million. The effective date of the sale was January 1, 2003 and the closing occurred on February 18, 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 condensed consolidated financial statements of the Company have been restated to reflect Enogex’s exploration and production assets, NuStar and Belvan, all of which were part of the Natural Gas Pipeline segment, as discontinued operations. Accordingly, revenues, costs and expenses, assets, liabilities and cash flows of the exploration and production assets, NuStar and Belvan have been excluded from the respective captions in the condensed consolidated financial statements and have been reported as “Current Assets of Discontinued Operations”, “Net Property, Plant and Equipment of Discontinued Operations”, “Deferred Charges and Other Assets of Discontinued Operations”, “Current Liabilities of Discontinued Operations”, “Deferred Credits and Other Liabilities of Discontinued Operations”, “Income from Discontinued Operations” and “Net Cash Provided from Discontinued Operations.”

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)	2003			2002			2003			2002

Operating revenues from discontinued operations	$	---	$	21	.8	$	7	.8	$	41	.2

Income from discontinued operations before taxes	$	---	$	3	.2	$	2	.2	$	4	.9

CONDENSED CONSOLIDATED BALANCE SHEET DATA

(In millions)	June 30, 2003			December 31, 2002
Accounts receivable	$	0	.1	$	4	.1
Other current assets		-	--		0	.6

Total current assets of discontinued operations	$	0	.1	$	4	.7

Plant in service of discontinued operations	$	-	--	$	54	.2
Less accumulated depreciation		-	--		11	.4

Net property, plant and equipment of discontinued operations	$	-	--	$	42	.8

Total deferred charges and other assets of discontinued operations	$	-	--	$	0	.2

Accounts payable	$	-	--	$	1	.1
Accrued taxes		-	--		0	.4
Other current liabilities		-	--		0	.5

Total current liabilities of discontinued operations	$	-	--	$	2	.0

Total deferred credits and other liabilities of discontinued operations	$	-	--	$	9	.1

6. Asset Disposals

On August 2, 2002, Ozark, in which an Enogex subsidiary owns a 75 percent interest, entered into an Agreement of Sale and Purchase with CenterPoint Energy Gas Transmission Co. to sell approximately 29 miles of transmission lines of the Ozark pipeline located in Pittsburg and Latimer counties in Oklahoma for approximately $10.0 million. On November 18, 2002, the Company received FERC approval for the closing, which occurred on January 6, 2003. The Company recognized approximately a $5.3 million pre-tax gain in the first quarter of 2003 related to the sale of these assets, which is recorded in Other Income in the accompanying Condensed Consolidated Statements of Income. These assets were part of the Natural Gas Pipeline segment.

7. Impairment of Assets

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 carrying amount of the aircraft was approximately $5.8 million at June 30, 2003. The Company expects to complete the sale of the aircraft in August 2003. See Note 17 for a further discussion.

8. Supplemental Cash Flow Information

Non-cash financing activities for the six months ended June 30, 2003 and 2002 included approximately $7.2 million and $5.9 million, respectively, related to the change in fair value of the interest rate swap agreements and the corresponding change in long-term debt.

9. Common Stock

For the six months ended June 30, 2003, the Company issued 1,495,941 shares of new common stock pursuant to the Company’s Automatic Dividend Reinvestment and Stock Purchase Plan (the “Plan”). For the six months ended June 30, 2003 and 2002, respectively, there were 33,834 shares and 10,199 shares of new common stock issued pursuant to the Stock Incentive Plan, which related to exercised stock options.

S-3 Filings

On April 2, 2003, the Company filed a Form S-3 Registration Statement to register 7,000,000 shares of the Company’s common stock pursuant to the Plan. Under the terms of the Plan, the Company may accept requests for optional investments in amounts greater than $0.1 million per year and may offer a discount of up to three percent from current market prices. This program allows the Company to sell additional common stock at a lower discount than that normally incurred in a secondary equity offering. The Company issued 288,133 shares and 327,588 shares on April 30, 2003 and May 30, 2003, respectively, at a discount of 1.75 percent pursuant to the Plan. The Company issued 380,463 shares and 405,024 shares on June 30, 2003 and July 31, 2003, respectively, at a discount of 1.50 percent pursuant to the Plan.

On April 15, 2003, the Company filed a Form S-3 Registration Statement pursuant to which it may offer from time to time up to $130.0 million of unsecured debt securities or shares of the Company’s common stock.

10. Earnings Per Share

For the three and six months ended June 30, 2003, there were approximately 0.1 million shares and approximately 0.2 million shares related to outstanding employee stock options, which were included in the computation of diluted earnings per average common share. For the three and six months ended June 30, 2003, there were approximately 0.1 million shares each assumed outstanding related to contingently issuable shares pursuant to the Company's Annual Incentive Compensation Plan. For both the three and six months ended June 30, 2002, there were approximately 0.1 million shares related to outstanding employee stock options, which were included in the computation of diluted earnings per average common share.

For the three and six months ended June 30, 2003, approximately 1.9 million shares and approximately 2.1 million shares related to outstanding employee stock options were not included in the calculation of adjusted average common shares outstanding for diluted earnings per average common share because the effect of including those shares is anti-dilutive as the exercise price of the employee stock options exceeded the average market price for the common stock during the respective period. For the three and six months ended June 30, 2002, approximately 0.8 million shares and approximately 1.1 million shares related to outstanding employee stock options are not included in the calculation of adjusted average common shares outstanding for diluted earnings per average common share because the effect of including those

shares is anti-dilutive as the exercise price of the employee stock options exceeded the average market price for the common stock during the respective period.

11. Long-Term Debt

Long-Term Debt

During the three months ended June 30, 2003, approximately $9.0 million of Enogex’s long-term debt matured. In addition, on April 28, 2003, Enogex redeemed $10.0 million principal amount of 7.75 percent medium-term notes due April 24, 2023 and April 26, 2023.

Interest Rate Swap Agreements

At June 30, 2003 and December 31, 2002, 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 each of 8.125 percent fixed rate debt due January 15, 2010, to a variable rate based on the six month LIBOR.

These interest rate swaps qualified as fair value hedges under SFAS No. 133 and meet all of the requirements for a determination that there was no ineffective portion as allowed by the shortcut method under SFAS No. 133. 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.

At June 30, 2003 and December 31, 2002, the fair values pursuant to the interest rate swaps were approximately $23.1 million and $15.9 million, respectively, and are included in non-current Price Risk Management assets in the accompanying Condensed Consolidated Balance Sheets. A corresponding net increase of approximately $23.1 million and $15.9 million is reflected in Long-Term Debt at June 30, 2003 and December 31, 2002, respectively, as these fair value hedges were effective at June 30, 2003 and December 31, 2002.

S-3 Filing

On April 17, 2003, OG&E filed a Form S-3 Registration Statement pursuant to which it may offer from time to time up to $200.0 million aggregate principal amount of OG&E’s unsecured senior notes.

Security Ratings

Company may experience somewhat higher borrowing costs but does not expect the actions by Standard & Poor’s to have a significant impact on the Company’s consolidated financial position or results of operations.

On February 5, 2003, Moody’s Investors Service (“Moody’s”) lowered the credit ratings of OGE Energy Corp.’s senior unsecured debt to Baa1 from A3, OG&E’s senior unsecured debt to A2 from A1 and Enogex’s senior unsecured debt to Baa3 from Baa2. OGE Energy Corp.’s short-term commercial paper rating was unchanged at P-2. The Company may experience somewhat higher borrowing costs but does not expect the actions by Moody’s to have a significant impact on the Company’s consolidated financial position or results of operations. As a result of Enogex’s rating being lowered to Baa3, OGE Energy Corp. was required to issue a $5.0 million guarantee on Enogex’s behalf for a counterparty. At June 30, 2003, there is approximately a $1.5 million outstanding liability balance related to this guarantee.

A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

Liquidity

On April 6, 2003, the Company renewed its $15.0 million line of credit facility for an additional one-year term expiring April 6, 2004.

On June 26, 2003, OG&E renewed its $100.0 million line of credit facility for an additional one-year term expiring June 26, 2004.

12. Short-Term Debt

Consolidated short-term debt of approximately $257.1 million and $275.0 million, respectively, was outstanding at June 30, 2003 and December 31, 2002. The following table shows the Company’s lines of credit in place at June 30, 2003. Short-term borrowings will consist of a combination of bank borrowings and commercial paper.

Lines of Credit (In millions)
Entity	Amount			Maturity
OGE Energy Corp. (A)	$	200	.0	January 8, 2004
		100	.0	January 15, 2004
		15	.0	April 6, 2004
OG&E		100	.0	June 26, 2004

Total	$	415	.0

(A)

   The lines of credit at OGE Energy Corp. are used to back up the Company’s commercial paper borrowings,
    which were approximately $223.3 million at June 30, 2003. No borrowings were outstanding at June 30, 2003
    under any of the lines of credit shown above, however, $8.0 million of the $15.0 million line of credit above is
    supported by a letter of credit described in Note 14.

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

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. 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 and trading of natural gas. Enogex also has been involved in investing in the development for and production of natural gas and crude oil, which investments Enogex sold during 2002. Other Operations primarily includes unallocated corporate expenses and interest expense on commercial paper and the Trust Originated Preferred Securities. 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, 2003 and 2002.


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

(A) Beginning with the first quarter of 2002, Natural Gas Pipeline’s operations consisted of three related businesses: Transportation and Storage, Gathering and Processing and Marketing and Trading. The following table is supplemental Natural Gas Pipeline information.


Three Months Ended June 30, 2003	Transportation and Storage			Gathering and Processing			Marketing and Trading			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


Three Months Ended June 30, 2002	Electric Utility			Natural Gas Pipeline (A)			Other Operations			Intersegment			Total
(In millions)
Operating revenues	$	352	.2	$	390	.0	$	-	--	$	(11	.4)	$	730	.8
Fuel		112	.8		-	--		-	--		(8	.4)		104	.4
Purchased power		65	.2		-	--		-	--		-	--		65	.2
Gas and electricity purchased for resale		-	--		317	.8		-	--		(3	.0)		314	.8
Natural gas purchases - other		-	--		23	.6		-	--		-	--		23	.6

Cost of goods sold		78	.0		341	.4		-	--		(11	.4)		508	.0
Gross margin on revenues		174	.2		48	.6		-	--		-	--		222	.8

Other operation and maintenance		75	.5		23	.8		(2	.9)		-	--		96	.4
Depreciation		30	.3		13	.2		2	.5		-	--		46	.0
Taxes other than income		11	.6		4	.1		0	.6		-	--		16	.3

Operating income (loss)		56	.8		7	.5		(0	.2)		-	--		64	.1

Other income		0	.1		0	.4		-	--		-	--		0	.5
Other expense		(0	.9)		-	--		-	--		-	--		(0	.9)
Interest income		0	.4		0	.5		4	.8		(5	.2)		0	.5
Interest expense		(10	.1)		(12	.4)		(10	.0)		5	.2		(27	.3)
Income tax expense (benefit)		15	.5		(1	.8)		(2	.0)		-	--		11	.7

Income (loss) from continuing operations	$	30	.8	$	(2	.2)	$	(3	.4)	$	-	--	$	25	.2

Income from discontinued operations		-	--		3	.2		-	--		-	--		3	.2

Net income (loss)	$	30	.8	$	1	.0	$	(3	.4)	$	-	--	$	28	.4


Three Months Ended June 30, 2002	Transportation and Storage			Gathering and Processing			Marketing and Trading			Eliminations			Total
(In millions)
Operating revenues	$	106	.8	$	46	.5	$	318	.5	$	(81	.8)	$	390	.0
Operating income (loss)	$	9	.4	$	(1	.9)	$	-	--	$	-	--	$	7	.5


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 of change in accounting
for energy trading contracts, 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 and Trading			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


Six Months Ended June 30, 2002	Electric Utility			Natural Gas Pipeline (A)			Other Operations			Intersegment			Total
(In millions)
Operating revenues	$	614	.3	$	713	.4	$	-	--	$	(21	.1)	$	1,306	.6
Fuel		197	.8		-	--		-	--		(17	.5)		180	.3
Purchased power		129	.0		-	--		-	--		-	--		129	.0
Gas and electricity purchased for resale		-	--		574	.5		-	--		(3	.6)		570	.9
Natural gas purchases - other		-	--		41	.6		-	--		-	--		41	.6

Cost of goods sold		326	.8		616	.1		-	--		(21	.1)		921	.8
Gross margin on revenues		287	.5		97	.3		-	--		-	--		384	.8

Other operation and maintenance		140	.2		47	.7		(6	.4)		-	--		181	.5
Depreciation		61	.1		25	.2		4	.9		-	--		91	.2
Taxes other than income		23	.5		8	.1		1	.4		-	--		33	.0

Operating income		62	.7		16	.3		0	.1		-	--		79	.1

Other income		0	.3		0	.6		-	--		-	--		0	.9
Other expense		(1	.5)		(0	.2)		(0	.1)		-	--		(1	.8)
Interest income		0	.8		0	.9		9	.5		(10	.2)		1	.0
Interest expense		(19	.9)		(25	.5)		(20	.6)		10	.2		(55	.8)
Income tax expense (benefit)		13	.1		(2	.3)		(4	.2)		-	--		6	.6

Income (loss) from continuing operations	$	29	.3	$	(5	.6)	$	(6	.9)	$	-	--	$	16	.8

Income from discontinued operations		-	--		5	.3		-	--		-	--		5	.3

Net income (loss)	$	29	.3	$	(0	.3)	$	(6	.9)	$	-	--	$	22	.1


Six Months Ended June 30, 2002	Transportation and Storage			Gathering and Processing			Marketing and Trading			Eliminations			Total
(In millions)
Operating revenues	$	223	.8	$	85	.3	$	569	.2	$	(164	.9)	$	713	.4
Operating income (loss)	$	20	.1	$	(3	.9)	$	0	.1	$	-	--	$	16	.3

14. Commitments and Contingencies

Except as set forth below, the circumstances set forth in Note 15 to the Company’s consolidated financial statements included in the Company’s Form 10-K for the year ended December 31, 2002, 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.

Reference is made to paragraph 5 in Item 3. Legal Proceedings of the Company's Annual Report on From 10-K for the year ended December 31, 2002, which describes the ongoing dispute between Central Oklahoma Oil and Gas Corp. ("COOG") and the Company and Enogex. As previously reported, Enogex entered into a Storage Lease Agreement with COOG relating to the Stuart Storage Facility and the Company agreed to make up to a $12 million secured loan to Natural Gas Storage Corporation ("NGSC"), an affiliate of COOG (the "NGSC Loan"). In July 2002, judgment was entered against COOG and in favor of Enogex in the amount of approximately $23.3 million (the "Judgment"), in connection with the Storage Lease Agreement. Enogex subsequently exercised its option to acquire the Stuart Storage Facility under the Asset Purchase Option in the Storage Lease Agreement. The Company and Enogex intend to continue to vigorously pursue their rights in conjunction with the NGSC Loan.

On February 28, 2003, Enogex filed in the Texas action, a motion to dismiss, or in the alternative, to compel arbitration. NGSC and COOG filed their response and a hearing was held on March 14, 2003. By order dated June 19, 2003, the Court granted Enogex's motion to dismiss, or in the alternative, to compel arbitration and ordered Plaintiffs (COOG and NGSC) and Enogex to arbitration on all issues and claims arising under the Storage Lease Agreement and/or the Option Agreement, including all issues overlapping with the loan agreement and related documents. The Texas action is stayed in its entirety pending arbitration. Enogex intends to vigorously pursue its rights through arbitration.

On July 16, 2003, the Company and Enogex served separate complaints on the individual shareholders of COOG and NGSC - Enogex Inc. v John C. Thrash, John F. Thrash and Robert R. Voorhees, Jr., Case No. CIV_03-0388-L; and OGE Energy Corp. and Enogex Inc. v John C. Thrash, John F. Thrash and Robert R. Voorhees, Jr., Case No. CIV 03-0389-L - both filed in the Western District of Oklahoma Federal Court. The Company and Enogex have each stated claims for (1) fraudulent transfer; (2) imposition of an equitable trust; and (3) breach of fiduciary duty. Enogex seeks to recover the remaining amount owed under the Judgment, plus interest, and the Company and Enogex seek to recover amount owed under the NGSC Loan, plus interest.

Farmland Industries

Farmland Industries, Inc. (“Farmland”) voluntarily filed for Chapter 11 bankruptcy protection from creditors on May 31, 2002. Enogex provided gas transportation and supply services to Farmland, and is an unsecured creditor of Farmland. Enogex filed its Proof of Claim on January 7, 2003, for approximately $5.4 million. In April 2003, Enogex negotiated a settlement and received approximately $1.9 million in May 2003 which is approximately $0.3 million higher than the $1.6 million outstanding balance due (net of the $3.8 million reserve recorded in 2002).

petition claims. As a general unsecured creditor of Farmland and pursuant to the terms of the Settlement Agreement referenced above, Enogex’s recovery under the proposed distribution would be approximately $0.8 million, which is in addition to the $1.9 million Enogex received in May 2003.

Agreement with Colorado Interstate Gas Company

In December 2002, Enogex entered into a Precedent Agreement with Colorado Interstate Gas Company (“CIG”) regarding reservation of capacity on a proposed interstate gas pipeline (the “Cheyenne Plains Pipeline”). If completed, the Cheyenne Plains Pipeline would provide interstate gas transportation services in the states of Wyoming, Colorado and Kansas with a capacity of 560,000 decatherms/day (“Dth/day”). Under the Precedent Agreement, Enogex bid to reserve 60,000 Dth/day of capacity on the proposed pipeline. Such reservation would result in Enogex having access to significant additional natural gas supplies in the areas to be served by the proposed pipeline. Subject to regulatory and other approvals, CIG is proposing an in-service date of August 31, 2005.

On May 20, 2003, Cheyenne Plains filed its initial certificate applications with the FERC, including its proposed tariff for the pipeline, as well as certain environmental filings. On July 7, 2003, Enogex filed a motion to intervene, stating certain objections involving Cheyenne Plains’ proposed treatment of reservation fees and creditworthiness requirements.

Cheyenne Plains issued a second open season notice on July 25, 2003, wherein Cheyenne Plains proposes to expand the capacity of its pipeline facilities in connection with a separate open season being conducted by an affiliate, Wyoming Interstate Company. The second open season expires on August 14, 2003.

Guarantees

During the normal course of business, Enogex issues guarantees on behalf of its subsidiaries for the purpose of securing credit for certain business activities. These guarantees are for payment when due of amounts payable by its subsidiaries under various agreements with counterparties. At June 30, 2003, accounts payable supported by guarantees was approximately $72.9 million. Since these guarantees by Enogex represent security for payment of payables obtained in the normal course of its subsidiaries’ business activities, the Company, on a consolidated basis, does not assume any additional liability as a result of this arrangement.

OGE Energy Corp. has issued a $5.0 million guarantee on behalf of OERI and a $15.0 million guarantee on behalf of Enogex Inc. for the purpose of securing credit for certain business activities. These guarantees are for payment when due of amounts payable by OERI and Enogex Inc. under various agreements with counterparties. At June 30, 2003, accounts payable supported by guarantees was approximately $1.5 million. Since these guarantees by OGE Energy Corp. represent security for payment of payables obtained in OERI’s and Enogex Inc.’s business activities, the Company, on a consolidated basis, does not assume any additional liability as a result of this arrangement.

The Company has issued an $8.0 million standby letter of credit to an insurance company, Energy Insurance Bermuda Ltd. Mutual Business Program No. 19 ("MBP 19"), for the benefit of insuring parts of the Company's property and liability insurance programs. MBP 19 was established to provide $15 million worth of property and liability insurance for the Company. The $8.0 million letter of credit was issued to provide protection for MBP 19 in case of large insurance claim losses. At June 30, 2003, there were no drawings against this letter of credit. This letter of credit renews automatically on an annual basis.

As of June 30, 2003, in the event Moody’s or Standard & Poor’s were to lower Enogex’s senior unsecured debt rating to a below investment grade rating, Enogex would be required to post approximately $6.3 million of collateral to satisfy its obligation under its financial and physical contracts.

Storm Damage

On May 8 and May 9, 2003, the Oklahoma City area was hit by a series of tornadoes that inflicted damage to OG&E’s transmission and distribution system. The estimated storm damage costs are approximately $8.7 million of which approximately $7.9 million was capitalized and $0.8 million was expensed in the second quarter. The storm damage costs did not have a material effect on the Company’s consolidated financial position or results of operations.

Other

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

15. Rate Matters and Regulation

Regulation and Rates

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

The order of the OCC authorizing OG&E to reorganize into a subsidiary of the Company contains certain provisions which, among other things, ensure the OCC access to the books and records of the Company and its affiliates relating to transactions with OG&E; require the Company to employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E’s customers; and prohibit the Company from pledging OG&E’s assets or income for affiliate transactions.

On October 11, 2002, OG&E, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to a settlement (the “Settlement Agreement”) of OG&E’s rate case. The administrative law judge subsequently recommended approval of the Settlement Agreement and on November 22, 2002, the OCC signed a rate order containing the provisions of the Settlement Agreement. The Settlement Agreement provides for, among other items: (i) a $25.0 million annual reduction in the electric rates of OG&E’s Oklahoma customers which went into effect January 6, 2003; (ii) recovery by OG&E, through rate base, of the capital expenditures associated with the January 2002 ice storm; (iii) 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; (iv) OG&E to acquire electric generating capacity of not less than 400 megawatts (“MW”) to be integrated into OG&E’s generation system. Key portions of the Settlement Agreement are described in detail in Note 16 to the Company’s Consolidated Financial Statements included in the Company’s Form 10-K for the year ended December 31, 2002.

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. On April 29, 2003, OG&E filed an application with the OCC in which OG&E advised the OCC that after careful consideration competitive bidding for gas transportation was rejected in favor of a new intrastate firm no-notice load following gas transportation and storage services agreement with Enogex. This seven-year agreement provides for gas transportation and storage services for each of OG&E’s natural gas fired generation plants. A hearing is scheduled to be held October 27, 2003 and an OCC order in the case is expected either later in 2003 or early in 2004.

On May 12, 2003, OG&E filed with the OCC a notice of intent to seek an annual increase in its rates to its Oklahoma customers of more than one percent. The notice lists the following, among others, as major issues to be addressed in its application: (i) the acquisition of a generation facility in accordance with the Settlement Agreement; (ii) increased capital expenditures for efficiency improvements and reliability enhancements to ensure fuel costs are minimized, and (iii) increased pension, medical and insurance costs. On June 25, 2003, OG&E announced that it has delayed filing its application for this rate increase to later in 2003.

Security Enhancements

On August 14, 2002, OG&E filed a report with the OCC outlining proposed expenditures and related actions for security enhancement. 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 has retained a security expert to review the report filed by OG&E, and a hearing is expected to be held in late 2003.

Other Regulatory Actions

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

The APC Rider was approved by the OCC in March 2000 and was implemented by OG&E to reflect the completion of the recovery of the amortization premium paid by OG&E when it acquired Enogex in 1986. The effect of the APC Rider was to remove approximately $10.7 million annually from the amount being recovered by OG&E from its Oklahoma customers in current rates.

In June 2001, the OCC approved a stipulation (the “Stipulation”) to the competitive bid process of OG&E’s gas transportation service from Enogex. The Stipulation directed OG&E to reduce its rates to its Oklahoma retail customers by approximately $2.7 million per year through the implementation of the GTAC Rider. The GTAC Rider was a credit for gas transportation cost recovery and was applicable to and became part of each Oklahoma retail rate schedule to which OG&E’s automatic fuel adjustment clause applies. As discussed above, the Settlement Agreement terminated the GTAC Rider. Consequently, these charges for gas transportation provided by Enogex are now included in base rates.

OG&E’s Generation Efficiency Performance Rider (“GEP Rider”) expired in June 2002. The GEP Rider was established initially in 1997 in connection with OG&E’s 1996 general rate review and was intended to encourage OG&E to lower its fuel costs by: (i) allowing OG&E to collect one-third of the amount by which its fuel costs were below a specified percentage (96.261 percent) of the average fuel costs of certain other investor-owned utilities in the region; and (ii) disallowing the collection of one-third of the amount by which its fuel costs exceeded a specified percentage (103.739 percent) of the average fuel costs of other investor-owned utilities. In June 2000 the OCC made modifications to the GEP Rider which had the effect of reducing the amount OG&E could recover under the GEP Rider by: (i) changing OG&E’s peer group to include utilities with a higher coal-to-gas generation mix; (ii) reducing the amount of fuel costs that can be recovered if OG&E’s costs exceed the new peer group by changing the percentage above which OG&E will not be allowed to recover one-third of the fuel costs from Oklahoma customers from 103.739 percent to 101.0 percent; (iii) reducing OG&E’s share of cost savings as compared to its new peer group from 33 percent to 30 percent; and (iv) limiting to $10.0 million the amount of any awards paid to OG&E or penalties charged to OG&E.

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, effective January 1, 2002, the date that these systems began operating as a single Enogex pipeline system. The FERC Staff, Enogex and the active intervening parties held extensive settlement discussions. Enogex negotiated a settlement of the case with the interveners and, on March 5, 2003, filed a Stipulation and Agreement of Settlement and related documents with the FERC to resolve all issues in dispute in Docket No. PR02-10-000. By Order dated May 9, 2003, the FERC accepted the settlement agreement and entered its order modifying Enogex’s Statement of Operating Conditions (“SOC”). The FERC Order required Enogex to modify its SOC to eliminate the priority for scheduling and curtailment purposes for interruptible dedicated gas customers. As ordered, Enogex filed a revised SOC on May 22, 2003. By filings on June 3 and June 9, 2003, respectively, Apache Corporation and the Oklahoma Independent Petroleum Association sought rehearing as to the elimination of the priority for dedicated gas. The FERC issued a tolling order on July 9, 2003 but has not issued an order on the merits. The settlement included a fee to be assessed under certain market conditions to process customer gas gathered behind processing plants so that it meets pipeline gas quality Btu standards and can be redelivered to interstate pipelines (default processing fee). The 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). During the first six months of 2003, the Company recognized revenue of approximately $4.1 million for default processing fees and approximately $0.5 million of low flow meter charges.

State Restructuring Initiatives

Oklahoma

As previously reported, the Electric Restructuring Act of 1997 (the “1997 Act”) was designed to provide retail customers in Oklahoma a choice of their electric supplier by July 1, 2002. Additional implementing legislation was to be adopted by the Oklahoma Legislature to address many specific issues associated with the 1997 Act and with deregulation. In May 2000, a bill addressing the specific issues of deregulation was passed in the Oklahoma State Senate and then was defeated in the Oklahoma House of Representatives. In May 2001, the Oklahoma Legislature passed Senate Bill 440 (“SB 440”), which postponed the scheduled start date for customer choice from July 1, 2002 until at least 2003. In addition to postponing the date for customer choice, SB 440 calls for a nine-member task force to further study the issues surrounding deregulation. The task force includes the Governor or his designee, the Oklahoma Attorney General, the OCC Chair and several legislative leaders, among others. In the 2003 legislative session, Senate Bill 383 was introduced to repeal the 1997 Act. The 2003 legislative session ended without any further action to repeal the 1997 Act. It is unknown at this time whether the bill will be passed into law. The Company will continue to actively participate in the legislative process and expects to remain a competitive supplier of electricity. As a result of the failures of California’s attempt to deregulate its electricity markets, the Enron bankruptcy, and

associated impacts on the industry, efforts to restructure the electricity market in Oklahoma appear at this time to be delayed indefinitely.

Arkansas

In April 1999, Arkansas passed a law (the “Restructuring Law”) calling for restructuring of the electric utility industry at the retail level. The Restructuring Law initially targeted customer choice of electricity providers by January 1, 2002. In February 2001, the Restructuring Law was amended to delay the start date of customer choice of electric providers in Arkansas until October 1, 2003, with the APSC having discretion to further delay implementation to October 1, 2005. In March 2003, the Restructuring Law was repealed. As part of the repeal legislation, electric public utilities are permitted to recover transition costs. OG&E incurred approximately $2.4 million in transition costs necessary to carry out its responsibilities associated with efforts to implement retail open access. OG&E will be filing an application with the APSC in the next several months to recover these costs. The APSC will most likely schedule a hearing later in 2003.

16. 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 that have significantly changed since December 31, 2002:

	June 30, 2003						December 31, 2002
(In millions)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Price Risk Management Assets
Energy Trading Contracts	$	60	.4	$	60	.4	$	21	.4	$	21	.4
Interest Rate Swaps		23	.1		23	.1		15	.9		15	.9
Price Risk Management Liabilities
Energy Trading Contracts	$	48	.6	$	48	.6	$	14	.6	$	14	.6

The carrying value of the financial instruments on the accompanying 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.

17. Subsequent Event

On July 15, 2003, the Company entered into an Agreement of Sale and Purchase to sell the Company’s aircraft for approximately $5.8 million. The closing is expected to be completed in August 2003. 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 carrying amount of the aircraft was approximately $5.8 million at June 30, 2003. Therefore, no gain or loss will be recorded in the third quarter of 2003 related to the sale of the aircraft. The aircraft was part of Other Operations.

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

Introduction

The Natural Gas Pipeline segment is conducted through Enogex Inc. and its subsidiaries (“Enogex”) and consists of three related businesses: (i) the transportation and storage of natural gas, (ii) the gathering and processing of natural gas and (iii) the marketing and trading of natural gas (collectively, the “pipeline businesses”). 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's focus is to utilize its processing, transportation and storage capacity and execute physical, financial and service transactions to capture revenues across different commodities, locations, or time periods. Enogex was previously engaged in the exploration and production of natural gas, however, this portion of Enogex’s business, along with interests in certain gas gathering and processing assets in Texas, were sold in 2002 and in the first quarter of 2003 and are reported in the condensed consolidated financial statements as discontinued operations.

Company Strategy

In early 2002, the Company completed a review of its business strategy that was largely driven by the anticipated deregulation of the retail electric markets in Oklahoma and Arkansas. Due to a variety of factors, including efforts to repeal the Oklahoma Electric Restructuring Act of 1997 and the recent repeal of the Restructuring Law in Arkansas, the Company does not anticipate that deregulation of the electricity markets in Oklahoma or Arkansas will occur in the foreseeable future. The strategic direction of the Company has been revised to reflect these developments. As a result, the Company expects potentially slower earnings growth than associated with deregulation but with less variability of those earnings.

The Company’s business strategy will utilize the diversified asset position of OG&E and Enogex to provide energy products and services to customers primarily in the south central United States. The Company will focus on those products and services with limited or manageable commodity exposure. The Company intends for OG&E to continue as an integrated utility engaged in the generation, transmission and the distribution of electricity and to represent over time approximately 70 percent of the Company’s consolidated assets. The remainder of the Company’s assets will be in Enogex’s pipeline businesses. In addition to the incremental growth opportunities that Enogex provides, the Company believes that Enogex’s risk management capabilities, commercial skills and market information provide value to all of the Company’s businesses. Federal regulation in regard to the operations of the wholesale power market may change with the proposed Standard Market Design initiative at the FERC. In addition, Oklahoma and Arkansas legislatures and utility commissions may propose changes from time to time that could subject utilities to market risk. Accordingly, the Company is applying risk management practices to all of its operations in an effort to mitigate the potential adverse effect of any future regulatory changes.

In the near term, OG&E plans on increasing its investment and growing earnings largely through the acquisition of a merchant power plant. As part of the OCC’s rate order on November 20, 2002, OG&E is seeking to purchase an electric power plant with at least 400 megawatts (“MW”) of generating capacity and to include the cost of such plant in its rate base. OG&E anticipates filing with appropriate regulatory agencies to increase base rates to recover its investment in, and operating expenses of, any power plant acquired and expects that customers should realize overall lower rates through fuel savings due to the increased efficiency of a new plant and lower capital costs than those associated with expiring qualified cogeneration and small power production producers’ contracts (“QF contracts”) pursuant to which OG&E currently acquires a portion of the power it delivers to its customers.

The Company will continue to review all of the supply alternatives to replace expiring QF contracts that minimize the total cost of generation to our customers. Unless extended by OG&E, 540 MW's of QF contracts will expire over the next one to five years. 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 projected natural gas prices, OG&E will include the feasibility of constructing additional base load coal-fired units in its build options.

Enogex initiated a program in 2002 to improve its financial performance. As a part of this performance improvement program, Enogex has received net sales proceeds of approximately $101.3 million from asset sales, reduced debt during 2002 by approximately $128.5 million or 17 percent, reduced its number of employees by approximately 12 percent and reorganized its operations. In addition to improving its earnings, Enogex will continue to take actions to reduce its exposure to commodity prices by, among other things, mitigating its exposure to keep whole processing arrangements and reducing earnings volatility. While the Company believes substantial progress has been achieved, substantial opportunities remain. Enogex expects to continue reviewing its work processes, rationalizing assets, negotiating contracts with better terms for both new contracts and for the replacement of contracts covering

existing volumes as they expire and reducing costs to further improve its financial return in addition to pursuing opportunities for organic growth.

In 2003, in addition to these ongoing efforts, a major upgrade of the information systems is expected to be substantially completed. The Company believes that these upgrades will be a major step towards obtaining the data required for it to optimize its system, provide improved customer service and enable management to more accurately determine the earnings potential of the unregulated pipeline system.

Other efforts at Enogex during 2003 have included improvements to its two storage fields. The improvement project at Greasy Creek is intended to reduce potential gas migration, while the improvement project at the newly-acquired Stuart Storage Facility is intended to eliminate water encroachment in the field. To date, expenditures on the projects have not been material and the Company does not expect that the remaining expenditures will be material.

The Company has a goal of targeting its pipeline businesses at 30 percent of the Company’s consolidated assets.

Forward-Looking Statements

Except for the historical statements contained herein, the matters discussed in the following discussion and analysis, including the discussion in “2003 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”, “estimate”, “expect”, “objective”, “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 their impact on capital expenditures; prices of electricity, natural gas and natural gas liquids, each on a stand-alone basis and in relation to each other; business conditions in the energy industry; competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company; unusual weather; state and federal legislative and regulatory decisions and initiatives; changes in accounting standards, rules or guidelines; creditworthiness of suppliers, customers, and other contractual parties; actions by ratings agencies; and the other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission, including Exhibit 99.01 to the Company’s Form 10-K for the year ended December 31, 2002.

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, 2003 as compared to the same periods in 2002 and the Company’s consolidated financial position at June 30, 2003. 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, 2002. Known trends and contingencies of a material nature are discussed to the extent considered relevant.

Enogex previously was engaged in the exploration and production of natural gas (the “E&P business”). Since January 1, 2002, Enogex has sold all of its E&P business along with certain gas gathering and processing assets that were owned by Enogex through its interest in the NuStar Joint Venture (“NuStar”) and its interest in Belvan Corp., Belvan Limited Partnership and Todd Ranch Limited Partnership (“Belvan”). As required by accounting principles generally accepted in the United States, these dispositions have been reported as discontinued operations for the three and six months ended June 30, 2003 and 2002 in the condensed consolidated financial statements.

Operating Results

The Company reported earnings of $0.41 per share for the three months ended June 30, 2003 as compared to earnings of $0.36 per share for the same period in 2002 and earnings of $0.40 per share for the six months ended June 30, 2003 compared to earnings of $0.28 per share for the same period in 2002. The improvement in financial performance was primarily due to improved management of pipeline system fuel at Enogex, better operating performance resulting from higher gross margins on revenues (“gross margin”) in Enogex’s natural gas storage business, negotiation of both new contracts and replacements for expiring contracts at better terms that resulted in increases in gathering fees and reductions in the purchase price of gas at Enogex and lower interest expenses at the holding company partially offset by lower earnings at OG&E. As all of Enogex's discontinued operations discussed above were sold prior to the beginning of the second quarter of 2003, there were no earnings from such discontinued operations for the three months ended June 30, 2003 compared to earnings of $0.04 per share for the same period in 2002. The Company’s results for the six months ended June 30, 2003 and 2002 include a contribution of $0.01 per share and $0.07 per share, respectively, from the discontinued operations discussed above. See “Enogex — Discontinued Operations” for a further discussion.

OG&E contributed $0.35 per share for the three months ended June 30, 2003 compared to $0.40 per share for the same period in 2002. OG&E’s decrease was primarily attributable to lower electric rates due to the January 2003 rate reduction and cooler weather in OG&E’s service territory partially offset by customer growth.

Enogex’s operations, including discontinued operations, contributed $0.10 per share for the three months ended June 30, 2003 compared to $0.01 per share for the same period in 2002. Enogex’s improvement was primarily attributable to improved management of pipeline system fuel, better operating performance resulting from higher gross margins in Enogex’s natural gas storage business and the negotiation of both new contracts and replacements for expiring contracts at better terms that resulted in increases in gathering fees and reductions in the purchase price of gas.

As stated above, Enogex’s E&P business, its interest in NuStar and its interest in Belvan have been reported as discontinued operations for the three months ended June 30, 2003 and 2002 in the condensed consolidated financial statements as these assets have been sold. As all of these operations were sold prior to the beginning of the second quarter of 2003, there were no earnings from discontinued operations for the three months ended June 30, 2003 compared to earnings of $0.04 per share for the same period in 2002. See “Enogex — Discontinued Operations” for a further discussion.

The results of the holding company reflect a loss of $0.04 per share for the three months ended June 30, 2003 compared to a loss of $0.05 per share for the same period in 2002 primarily due to lower interest expenses.

OG&E contributed $0.31 per share for the six months ended June 30, 2003 compared to $0.38 per share for the same period in 2002. OG&E’s decrease was primarily attributable to lower electric rates due to the January 2003 rate reduction, cooler weather in OG&E’s service territory and higher operating and maintenance expenses partially offset by customer growth and higher recoveries of fuel cost from Arkansas customers.

Enogex’s operations, including discontinued operations, contributed $0.17 per share for the six months ended June 30, 2003 compared to $0.00 per share for the same period in 2002. Enogex’s improvement was primarily attributable to better operating performance resulting from higher gross margins in all of Enogex’s businesses, the negotiation of both new contracts and replacement of expiring contracts at better terms that resulted in increases in gathering fees and reductions in the purchase price of gas, gains from asset sales, lower net interest expense and lower operating and maintenance expenses.

As stated above, Enogex’s E&P business, its interest in NuStar and its interest in Belvan have been reported as discontinued operations for the six months ended June 30, 2003 and 2002 in the condensed consolidated financial statements as these assets have been sold. Earnings from discontinued operations were $0.01 per share for the six months ended June 30, 2003 compared to $0.07 per share for the same period in 2002. This decrease was attributable to the sale of Enogex’s E&P business, NuStar and Belvan during 2002 and in the first quarter of 2003. See “Enogex — Discontinued Operations” for a further discussion.

The results of the holding company reflect a loss of $0.08 per share for the six months ended June 30, 2003 compared to a loss of $0.10 per share for the same period in 2002 primarily due to lower interest expenses.

Regulatory Considerations

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) 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”); (iv) OG&E to acquire electric generating capacity (“New Generation”) of not less than 400 MW’s to be integrated into OG&E’s generation system.

OG&E expects that the New Generation will provide savings, over a three-year period, in excess of $75 million. If OG&E is unable to demonstrate at least $75 million in savings, OG&E will be required to credit to its Oklahoma customers any unrealized savings below $75 million. In the event OG&E does not acquire the New Generation by December 31, 2003, OG&E will be required to credit $25.0 million annually (at a rate of 1/12 of $25.0 million per month for each month that the New Generation is not in place) to its Oklahoma customers beginning January 1, 2004 and continuing through December 31, 2006. However, if OG&E purchases the New Generation subsequent to January 1, 2004, the credit to Oklahoma customers will terminate in the first month that the New Generation begins initial operations and any previously-credited amount to Oklahoma customers will be deducted in the determination of the $75.0 million targeted savings. Reference is made to Note 15 of Notes to Condensed Consolidated Financial Statements in this report and to Note 16 to the Company’s Consolidated Financial Statements included in the Company’s Form 10-K for the year ended December 31, 2002 for a further discussion of the Settlement Agreement and of other recent actions relating to OG&E’s rates.

OG&E has been and will continue to be affected by competitive changes to the utility industry. Significant changes already have occurred and additional changes are being proposed to the wholesale electric market. Although it appears unlikely in the near future that changes will occur to retail regulation in the states served by OG&E due to the significant problems faced by California in its electric deregulation efforts and other factors, significant changes are possible, which could significantly change the manner in which OG&E conducts its business. These developments at the federal and state levels are described in more detail below under “Electric Competition; Regulation.”

2003 Outlook

General

The Company previously projected 2003 earnings at $1.35 to $1.45 per share assuming, among other things, normal weather and continued customer growth in the electric utility service area and improved performance at Enogex. Due to improved performance at Enogex, the Company has revised its 2003 earnings estimate to $1.40 to $1.50 per share. The Company anticipates a contribution of approximately $112 to $118 million from OG&E, approximately $18 to $20 million from Enogex and a loss of approximately $14 million at the holding company. Enogex’s 2003 earnings expectations have been increased due to the negotiation of both new contracts and replacements for expiring contracts at better terms that resulted in increases in gathering fees and reductions in the purchase price of gas, the assistance of default processing fees and electronic simulation models to optimize processing configuration, improved management of pipeline system fuel and better utilization of field equipment.

In the Company's initial earnings projection for 2003, the Company assumed approximately 83.5 million average common shares outstanding for 2003, up from an average of approximately 78.1 million in 2002. The Company now expects approximately 82.4 million average common shares outstanding for 2003. The Company plans to issue a combination of equity and debt in 2003 to support the capital structure at OG&E for its purchase of generation and for other corporate purposes including the repayment of short-term debt. During April 2003, the Company filed two registration statements to register shares of the Company’s common stock pursuant to the Company’s Automatic Dividend Reinvestment and Stock Purchase Plan and to offer from time to time up to $130.0 million of unsecured debt securities or shares of the Company’s common stock. Also, during April 2003, OG&E filed a registration statement to offer from time to time up to $200.0 million aggregate principal amount of OG&E’s unsecured senior notes.

The Company continues to pursue the acquisition of a new power plant and hopes to sign an agreement during the third quarter of 2003.

Dividend Policy

The Company’s dividend policy is determined by the Board of Directors and is based on numerous factors, including management’s estimate of the long-term earnings power of its businesses. The target payout ratio for the Company is to pay out as dividends approximately 75 percent of its earnings on an annual basis. The target payout ratio has been determined after consideration of numerous factors, including the largely retail composition of our shareholder base, our financial position, our growth targets, the composition of our assets and investment opportunities. On an operating basis excluding impairment charges, the Company’s earnings per share for 2002 exceeded the dividend rate of $1.33 per share. While the dividend payout ratio is expected to exceed the target payout ratio in 2003, management, after considering estimates of future earnings and numerous other factors, expects at this time that it will continue to recommend to the Board of Directors a continuance of the current dividend rate.

Asset Disposals

Enogex sold its interest in NuStar for approximately $37.0 million in February 2003. The Company recognized approximately a $1.4 million after tax gain related to the sale of these assets in the first quarter of 2003, which is recorded in Income from Discontinued Operations in the accompanying Condensed Consolidated Statements of Income. These assets were part of the Natural Gas Pipeline segment.

Enogex sold approximately 29 miles of transmission lines of the Ozark pipeline, in which an Enogex subsidiary owns a 75 percent interest, located in Pittsburg and Latimer counties in Oklahoma for approximately $10.0 million in January 2003. The Company recognized approximately a $5.3 million pre-tax gain related to the sale of these assets, which is recorded in Other Income in the accompanying Condensed Consolidated Statements of Income. 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 Company expects to sell its aircraft for approximately $5.8 million in August 2003. As the proceeds are expected to equal the carrying amount of the aircraft, no gain or loss will be recorded during the third quarter of 2003 related to the sale of the aircraft. The aircraft was part of Other Operations.

Results of Operations

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions, except per share data)	2003			2002			2003			2002
Operating income	$	76	.6	$	64	.1	$	104	.3	$	79	.1
Net income	$	32	.2	$	28	.4	$	31	.9	$	22	.1
Basic average common shares outstanding		79	.2		78	.0		78	.9		78	.0
Diluted average common shares outstanding		79	.4		78	.0		79	.2		78	.0
Basic and diluted earnings per average common share	$	0.4	1	$	0.3	6	$	0.4	0	$	0.2	8
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. Operating income was approximately $76.6 million and $64.1 million for the three months ended June 30, 2003 and 2002, respectively. Operating income was approximately $104.3 million and $79.1 million for the six months ended June 30, 2003 and 2002, respectively. These amounts exclude the results of Enogex’s E&P business, NuStar and Belvan, which as explained above, were sold in 2002 and in the first quarter of 2003 and which are reported as discontinued operations. See “Enogex — Discontinued Operations” below for a further discussion.

Operating Income by Business Segment

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2003			2002			2003			2002
OG&E (Electric Utility)	$	55	.3	$	56	.8	$	57	.4	$	62	.7
Enogex (Natural Gas Pipeline) (A)		21	.6		7	.5		46	.9		16	.3
Other Operations		(0	.3)		(0	.2)		-	--		0	.1

Consolidated operating income	$	76	.6	$	64	.1	$	104	.3	$	79	.1

(A) Excludes discontinued operations.

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,
(In millions)	2003			2002			2003			2002
Operating revenues	$	357	.9	$	352	.2	$	690	.5	$	614	.3
Fuel		125	.6		112	.8		266	.9		197	.8
Purchased power		61	.3		65	.2		134	.0		129	.0

Gross margin on revenues		171	.0		174	.2		289	.6		287	.5
Other operating expenses		115	.7		117	.4		232	.2		224	.8

Operating income	$	55	.3	$	56	.8	$	57	.4	$	62	.7

System sales - MWH (A)		5	.8		6	.0		11	.7		11	.5
Off-system sales - MWH		-	--		-	--		0	.1		0	.2

Total sales - MWH		5	.8		6	.0		11	.8		11	.7

(A) Megawatt-hour

Quarter ended June 30, 2003 compared to quarter ended June 30, 2002

OG&E’s operating income for the three months ended June 30, 2003 decreased approximately $1.5 million or 2.6 percent as compared to the same period in 2002. The decrease in operating income was primarily attributable to lower electric rates due to the January 2003 rate reduction and cooler weather in OG&E’s service territory partially offset by customer growth.

The gross margin, which is operating revenues less cost of goods sold, was approximately $171.0 million for the three months ended June 30, 2003 as compared to approximately $174.2 million during the same period in 2002, a decrease of approximately $3.2 million or 1.8 percent. The gross margin decreased due to lower electric rates resulting from OG&E’s rate reduction, which went into effect on January 6, 2003 (approximately $3.4 million), cooler weather in OG&E’s service territory (approximately $4.8 million), the loss of revenue associated with various rate riders (approximately $1.2 million) and lower off-system sales (approximately $1.1 million). Partially offsetting the decrease in gross margin was an increase of approximately $4.9 million due to growth in OG&E’s service territory and an increase of approximately $2.6 million

due to higher recoveries of fuel costs from Arkansas customers through that state’s automatic fuel adjustment clause.

Cost of goods sold for OG&E consists of fuel used in electric generation and purchased power. Fuel expense was approximately $125.6 million for the three months ended June 30, 2003 as compared to approximately $112.8 million during the same period in 2002, an increase of approximately $12.8 million or 11.3 percent. The increase was due primarily to an increase in the average cost of fuel per kilowatt-hour (“kwh”) due to higher natural gas prices. Purchased power costs were approximately $61.3 million for the three months ended June 30, 2003 as compared to approximately $65.2 million during the same period in 2002, a decrease of approximately $3.9 million or 6.0 percent. The decrease is primarily due to lower capacity payments to cogeneration facilities.

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

Other operating expenses, consisting of operating and maintenance expense, depreciation expense and taxes other than income, were approximately $115.7 million for the three months ended June 30, 2003 as compared to approximately $117.4 million during the same period in 2002, a decrease of approximately $1.7 million or 1.4 percent. This decrease was primarily due to a $1.2 million decrease in depreciation expense resulting from a change in depreciation rates resulting from the Settlement Agreement. Also contributing to the decrease was approximately a $0.6 million decrease in operating and maintenance expenses primarily due to lower levels of uncollectibles expense of approximately $1.7 million and miscellaneous other items of approximately $1.9 million. These decreases were partially offset by an increase of approximately $3.0 million in pension and benefit expenses for the three months ended June 30, 2003 as compared to the same period in 2002 due to the general upward trend in these costs.

Six months ended June 30, 2003 compared to six months ended June 30, 2002

OG&E’s operating income for the six months ended June 30, 2003 decreased approximately $5.3 million or 8.5 percent as compared to the same period in 2002. The decrease in operating income was primarily attributable to lower electric rates due to the January 2003 rate reduction, cooler weather in OG&E’s service territory and higher operating and maintenance expenses partially offset by customer growth and higher recoveries of fuel cost from Arkansas customers.

The gross margin was approximately $289.6 million for the six months ended June 30, 2003 as compared to approximately $287.5 million during the same period in 2002, an increase of approximately $2.1 million or 0.7 percent. Gross margin increased for the six months ended June 30, 2003 due to growth in OG&E’s service territory (approximately $9.2 million), higher recoveries of fuel costs from Arkansas customers through that state’s automatic fuel adjustment clause (approximately $5.5 million) and the loss of revenue in January 2002, associated with the interruption of service to our customers as a result of the severe January 2002 ice storm (approximately $1.5 million). Partially offsetting the increase in gross margin was a decrease of approximately $7.6 million due to lower electric rates resulting from OG&E’s January 2003 rate reduction, a decrease of approximately $3.8 million due to cooler weather in OG&E’s service territory and a decrease of approximately $2.4 million due to the loss of revenue associated with various rate riders.

Fuel expense was approximately $266.9 million for the six months ended June 30, 2003 as compared to approximately $197.8 million during the same period in 2002, an increase of approximately $69.1 million or 34.9 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 $134.0 million for the six months ended June 30, 2003 as compared to approximately $129.0 million during the same period in 2002, an increase of approximately $5.0 million or 3.9 percent. The increase was primarily due to approximately a 14.0 percent increase in the volume of energy purchased.

Other operating expenses, consisting of operating and maintenance expense, depreciation expense and taxes other than income, were approximately $232.2 million for the six months ended June 30, 2003 as compared to approximately $224.8 million during the same period in 2002, an increase of approximately $7.4 million or 3.3 percent. The increase was primarily due to approximately a $6.6 million increase in operating and maintenance expenses. This increase was primarily due to approximately $5.4 million of costs incurred during the first quarter of 2002 in connection with the severe January 2002 ice storm being reported as a regulatory asset. These 2002 expenditures, incurred by field service personnel, would normally have been charged to maintenance expenses. Also contributing to the increase in operating and maintenance expenses was an increase of approximately $3.3 million in contract labor, primarily related to the overhaul of one of OG&E’s turbines. Pension and benefit expenses increased approximately $3.7 million for the six months ended June 30, 2003 as compared to the same period in 2002 due to the general upward trend in these costs. These increases were partially offset by lower levels of uncollectibles expense of approximately $2.9 million and lower miscellaneous operating expenses of approximately $1.8 million.

Enogex – Continuing Operations

	Three Months Ended June 30,						Six Months Ended June 30,
(Dollars in millions)	2003			2002			2003			2002
Operating revenues	$	513	.2	$	390	.0	$	1,252	.8	$	713	.4
Gas and electricity purchased for resale		439	.3		317	.8		1,096	.2		574	.5
Natural gas purchases - other		14	.3		23	.6		33	.8		41	.6

Gross margin on revenues		59	.6		48	.6		122	.8		97	.3
Other operating expenses		38	.0		41	.1		75	.9		81	.0

Operating income	$	21	.6	$	7	.5	$	46	.9	$	16	.3

Physical system supply - MMbtu/d (A)		1,51	9		1,60	0		1,56	6		1,64	8
Natural gas processed - MMcfd (B)		40	9		51	5		41	8		52	1
Natural gas liquids sold - million gallons		61	.1		86	.3		120	.1		161	.2
Average sales price per gallon	$	0.56	3	$	0.40	5	$	0.60	7	$	0.38	0
Natural gas marketed - Bbtu (C)		81,47	6		94,09	6		189,77	2		192,39	6
Average sales price per Bbtu	$	5.20	5	$	3.23	8	$	5.62	3	$	2.90	8
Power marketed - MWH		69,19	6		457,01	7		129,58	4		723,93	0
Average sales price per MWH	$	45.39	0	$	27.91	0	$	45.59	0	$	27.32	0

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

Quarter ended June 30, 2003 compared to quarter ended June 30, 2002

Enogex’s operating income for the three months ended June 30, 2003 increased approximately $14.1 million or 188.0 percent as compared to the same period in 2002. The increase was primarily attributable to improved management of pipeline system fuel, better operating performance resulting from higher gross margins in Enogex’s natural gas storage business and the negotiation of both new contracts and replacements for expiring contracts at better terms that resulted in increases in gathering fees and reductions in the purchase price of gas. Enogex sold its E&P business and its interest in Belvan during 2002 and Enogex sold its interest in NuStar during the first quarter of 2003; accordingly, these are reported as discontinued operations for the three months ended June 30, 2003 and 2002 in the condensed consolidated financial statements. See “Enogex — Discontinued Operations” below for a further discussion.

Transportation and storage contributed approximately $35.3 million of Enogex’s gross margin for the three months ended June 30, 2003 as compared to approximately $25.7 million during the same period in 2002, an increase of approximately $9.6 million or 37.4 percent. Gross margins benefited from improved management of pipeline system fuel which, when coupled with higher natural gas prices, accelerated the recovery of pipeline system fuel of approximately $5.5 million, increased levels of firm transportation revenues of approximately $1.1 million as a result of a collectibility reserve recorded in 2002 and increased storage revenues of approximately $2.9 million during the three months ended June 30, 2003 as compared to the same period in 2002. The increased storage revenues were mainly due to increased demand fees related to a storage facility acquired in August 2002 and increased demand fees from Enogex’s marketing and trading business.

Gathering and processing contributed approximately $21.3 million of Enogex’s gross margin for the three months ended June 30, 2003 as compared to approximately $17.5 million during the same period in 2002, an increase of approximately $3.8 million or 21.7 percent. Processing gross margins increased $1.0 million for the three months ended June 30, 2003 as compared to the same period in 2002 due to higher commodity prices for natural gas liquids and the assistance of the default processing fee under certain market conditions. Actual processing volumes were lower as a result of dispatching the plants based upon market conditions. Gathering gross margins increased approximately $2.8 million for the three months ended June 30, 2003 as compared to the same period in 2002 due to the negotiation of both new contracts and replacements for expiring contracts at better terms that resulted in increases in gathering fees and reductions in the purchase price of gas. Also, volumes were up due to an increase in the number of well connects for the three months ended June 30, 2003 as compared to the same period in 2002.

Marketing and trading contributed approximately $3.0 million of Enogex’s gross margin for the three months ended June 30, 2003 as compared to approximately $5.4 million during the same period in 2002, a decrease of approximately $2.4 million or 44.4 percent. Marketing gross margins decreased approximately $2.4 million primarily due to seasonal recognition of storage revenues which differ from the monthly payment of demand fees paid to obtain storage capacity from an affiliate and other third parties. Also contributing to the decrease were contract expirations and changes in accounting as required by Emerging Issues Task Force ("EITF") Issue No. 02-3, "Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities." These decreases were partially offset by higher mark-to-market gains due to the timing of natural gas injections during the three months ended June 30, 2003 as compared to the same period in 2002.

Other operating expenses, consisting of operating and maintenance expense, depreciation expense and taxes other than income, for Enogex were approximately $38.0 million for the three months ended June 30, 2003 as compared to approximately $41.1 million during the same period in 2002, a decrease of approximately $3.1 million or 7.5 percent. Operating and maintenance expenses were approximately $22.4 million for the three months ended June 30, 2003 as compared to approximately $23.8 million during the same period in 2002, a decrease of approximately $1.4 million or 5.9 percent. The decrease was primarily due to lower payroll expenses of approximately $1.2 million and lower expense allocations from the parent of approximately $0.9 million. These decreases were partially offset by higher outside service costs of approximately $0.7 million. Depreciation expense was approximately $11.1 million for the three months ended June 30, 2003 as compared to approximately $13.2 million during the same period in 2002, a decrease of approximately $2.1 million or 15.9 percent. The decrease was primarily the result of ceasing depreciation on the natural gas processing plants written down and classified as held for sale in the fourth quarter of 2002.

Six months ended June 30, 2003 compared to six months ended June 30, 2002

Enogex’s operating income for the six months ended June 30, 2003 increased approximately $30.6 million or 187.7 percent as compared to the same period in 2002. The

increase was primarily attributable to better operating performance resulting from higher gross margins in all of Enogex’s businesses, the negotiation of both new contracts and replacements of expiring contracts at better terms that resulted in increases in gathering fees and reductions in the purchase price of gas, gains from asset sales, lower net interest expense and lower operating and maintenance expenses. Enogex sold its E&P business and its interest in Belvan during 2002 and Enogex sold its interest in NuStar during the first quarter of 2003; accordingly, these are reported as discontinued operations for the six months ended June 30, 2003 and 2002 in the condensed consolidated financial statements. See “Enogex — Discontinued Operations” below for a further discussion.

Transportation and storage contributed approximately $63.0 million of Enogex’s gross margin for the six months ended June 30, 2003 as compared to approximately $51.9 million during the same period in 2002, an increase of approximately $11.1 million or 21.4 percent. Gross margins benefited from improved management of pipeline system fuel which, when coupled with higher natural gas prices, accelerated the recovery of pipeline system fuel of approximately $6.3 million and increased storage revenues of approximately $6.0 million during the six months ended June 30, 2003 as compared to the same period in 2002. The increased storage revenues were mainly due to increased demand fees related to a storage facility acquired in August 2002 and increased demand fees from Enogex’s marketing and trading business.

Gathering and processing contributed approximately $43.5 million of Enogex’s gross margin for the six months ended June 30, 2003 as compared to approximately $34.8 million during the same period in 2002, an increase of approximately $8.7 million or 25.0 percent. Processing gross margins increased $5.6 million for the six months ended June 30, 2003 as compared to the same period in 2002 due to higher commodity prices for natural gas liquids and the assistance of the default processing fee under certain market conditions. Actual processing volumes were lower as a result of dispatching the plants based upon market conditions. Gathering gross margins increased approximately $3.1 million for the six months ended June 30, 2003 as compared to the same period in 2002 due to the negotiation of both new contracts and replacements for expiring contracts at better terms that resulted in increases in gathering fees and reductions in the purchase price of gas. Also, volumes were up due to an increase in the number of well connects for the six months ended June 30, 2003 as compared to the same period in 2002.

Marketing and trading contributed approximately $16.3 million of Enogex’s gross margin for the six months ended June 30, 2003 as compared to approximately $10.6 million during the same period in 2002, an increase of approximately $5.7 million or 53.8 percent. Gross margins included approximately $10.2 million from gains on the sale of natural gas in storage during the first quarter of 2003. These gains were largely offset by Enogex recording a $9.0 million pre-tax loss, for the cumulative effect of a change in accounting principle in the first quarter of 2003 as a 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 “Accounting Pronouncements” for a further discussion. Therefore, absent the impact of the change in accounting principle, gross margins would have been approximately $7.3 million during the six months ended June 30, 2003 as compared to approximately $10.6 million during the same period in 2002. This $3.3 million decrease in the gross margin was due primarily to a $4.1 million decrease due to seasonal

recognition of storage revenues which differ from the monthly payment of demand fees paid to obtain storage capacity from an affiliate and other third parties, contract expirations and changes in accounting as required by EITF 02-3. Also contributing to the decrease was approximately a $1.5 million increase in demand fees paid to Enogex’s transportation and storage business. These decreases were only partially offset by higher mark-to-market gains of approximately $1.6 million due to the timing of natural gas injections during the six months ended June 30, 2003 as compared to the same period in 2002.

Other operating expenses, consisting of operating and maintenance expense, depreciation expense and taxes other than income, for Enogex were approximately $75.9 million for the six months ended June 30, 2003 as compared to approximately $81.0 million during the same period in 2002, a decrease of approximately $5.1 million or 6.3 percent. Operating and maintenance expenses were approximately $44.8 million for the six months ended June 30, 2003 as compared to approximately $47.7 million during the same period in 2002, a decrease of approximately $2.9 million or 6.1 percent. The decrease was primarily due to lower uncollectibles expense of approximately $0.8 million, lower payroll expenses of approximately $2.0 million and lower materials and supplies expense of approximately $1.0 million. These decreases were partially offset by higher outside service costs of approximately $1.2 million. Depreciation expense was approximately $22.3 million for the six months ended June 30, 2003 as compared to approximately $25.2 million during the same period in 2002, a decrease of approximately $2.9 million or 11.5 percent. The decrease was primarily the result of ceasing depreciation on the natural gas processing plants written down and classified as held for sale in the fourth quarter of 2002.

Enogex — Discontinued Operations

On March 25, 2002, Enogex entered into an Agreement of Sale and Purchase with West Texas Gas, Inc. to sell all of its interests in Belvan for approximately $9.8 million. The effective date of the sale was January 1, 2002 and the closing occurred on March 28, 2002. The Company recognized approximately a $1.6 million after tax gain related to the sale of these assets.

During the third quarter of 2002, the Company decided to sell all of its interests in NuStar. On January 23, 2003, Enogex entered into an Agreement of Sale and Purchase with Benedum Gas Partners, L.P. to sell all of the interests of its subsidiary, Enogex Products Corporation, in the west Texas properties consisting of NuStar, which has operations consisting of the extraction and sale of natural gas liquids, for approximately $37.0 million. The effective date of the sale was January 1, 2003 and the closing occurred on February 18, 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.

As a result of these sale transactions, Enogex’s E&P business, its interest in NuStar and its interest in Belvan, all of which were part of the Natural Gas Pipeline segment, have been reported as discontinued operations for the three and six months ended June 30, 2003 and 2002 in the condensed consolidated financial statements. Results for these discontinued operations are summarized and discussed below.

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2003			2002			2003			2002
Operating revenues	$	-	--	$	21	.8	$	7	.8	$	41	.2
Gas purchased for resale		-	--		12	.4		5	.9		24	.2
Natural gas purchases - other		-	--		1	.4		0	.6		3	.4

Gross margin on revenues		-	--		8	.0		1	.3		13	.6
Other operating expenses		-	--		4	.6		1	.4		10	.0

Operating income (loss)	$	-	--	$	3	.4	$	(0	.1)	$	3	.6

As all of these operations were sold prior to the beginning of the second quarter of 2003, there was no gross margin from discontinued operations for the three months ended June 30, 2003 compared to approximately $8.0 million for the three months ended June 30, 2002. Gross margin was approximately $1.3 million and $13.6 million for the six months ended June 30, 2003 and 2002, respectively. As all of these operations were sold prior to the beginning of the second quarter of 2003, there were no operating expenses from discontinued operations for the three months ended June 30, 2003 compared to approximately $4.6 million for the three months ended June 30, 2002. Other operating expenses were approximately $1.4 million and $10.0 million for the six months ended June 30, 2003 and 2002, respectively. The decreases in the gross margin and other operating expenses were primarily attributable to the sale of Enogex’s E&P business and Belvan during 2002 and the sale of NuStar in February 2003.

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

Other income includes, among other things, contract work performed by OG&E, non-operating rental income, gain on the sale of assets, profit on the retirement of fixed assets, minority interest income and miscellaneous non-operating income. Other income was approximately $6.7 million for the six months ended June 30, 2003 as compared to approximately $0.9 million during the same period in 2002, an increase of approximately $5.8 million. The increase was primarily due to a pre-tax gain of approximately $5.3 million related to the sale of approximately 29 miles of transmission lines of the Ozark pipeline in January 2003.

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 $3.6 million for the six months ended June 30, 2003 as compared to approximately $1.8 million during the same period in 2002, an increase of approximately $1.8 million. This increase was primarily due to an increase of approximately $1.1 million in minority interest expense related to the gain from the sale of approximately 29 miles of transmission lines of the Ozark pipeline in January 2003 that was attributable to the minority interest. Also contributing to the increase was approximately a $0.5 million increase in the liability associated with the deferred compensation plan.

Net interest expense includes interest income, interest expense and other interest charges. Net interest expense was approximately $49.6 million for the six months ended June 30, 2003 as compared to approximately $54.8 million during the same period in 2002, a decrease of approximately $5.2 million or 9.5 percent. This decrease was primarily due to a reduction in interest expense of approximately $5.0 million related to the retirement of $140.0 million of Enogex debt during 2002.

Income tax expense was approximately $19.4 million for the three months ended June 30, 2003 as compared to approximately $11.7 million during the same period in 2002, an increase of approximately $7.7 million. Income tax expense was approximately $21.3 million for the six months ended June 30, 2003 as compared to approximately $6.6 million during the same period in 2002, an increase of approximately $14.7 million. These increases were primarily from higher pre-tax income at Enogex partially offset by lower pre-tax income at OG&E during the three and six months ended June 30, 2003.

Financial Condition

The balance of Accrued Unbilled Revenues was approximately $64.8 million and $28.2 million at June 30, 2003 and December 31, 2002, respectively, an increase of approximately $36.6 million or 129.8 percent. The increase was primarily due to higher fuel costs, higher seasonal electric rates and increased usage due to warmer weather during June 2003 as compared to December 2002.

The balance of Fuel Inventories was approximately $120.5 million and $99.7 million at June 30, 2003 and December 31, 2002, respectively, an increase of approximately $20.8 million or 20.9 percent. The increase was due to more volumes injected at higher prices during June 2003 as compared to December 2002.

The balance of current Price Risk Management assets was approximately $54.7 million and $17.1 million at June 30, 2003 and December 31, 2002, respectively, an increase of approximately $37.6 million or 219.9 percent. The increase was due to significant volatility and higher natural gas prices associated with OERI’s trading activities during the first six months of 2003. This increase is partially offset by an increase in current Price Risk Management liabilities.

The balance of Fuel Clause Under Recoveries was approximately $38.3 million and $14.7 million at June 30, 2003 and December 31, 2002, respectively, an increase of approximately $23.6 million or 160.5 percent. This increase was due to under recoveries from OG&E’s customers as OG&E’s cost of fuel exceeded the amount billed during the first six months of 2003. The cost of fuel subject to recovery through the fuel clause mechanism was approximately $1.54 per million British thermal unit (“MMBtu”) in December 2002, and was approximately $2.13 per MMBtu in June 2003. The Company’s fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers’ bills. As a result the Company under recovers fuel cost in periods of rising prices and over recovers fuel cost when prices decline. Provisions in the fuel clauses allow the Company to amortize under or over recovery. The Company began amortizing the under collected amounts beginning with the April 2003 customers bills.

The balance of Prepaid Benefit Obligation was approximately $25.3 million and $44.9 million at June 30, 2003 and December 31, 2002, respectively, a decrease of approximately $19.6 million or 43.7 percent. The decrease was primarily due to pension accruals being credited to the prepaid benefit obligation.

The balance of Short-Term Debt was approximately $257.1 million and $275.0 million at June 30, 2003 and December 31, 2002, respectively, a decrease of approximately $17.9 million or 6.5 percent. The decrease was primarily due to proceeds received from the sale of Ozark and NuStar and from the sale of natural gas inventory by Enogex during the first quarter of 2003, which were used to reduce the commercial paper balance at the holding company.

The balance of Accrued Taxes was approximately $43.4 million and $23.6 million at June 30, 2003 and December 31, 2002, respectively, an increase of approximately $19.8 million or 83.9 percent. The increase was primarily due to the Company’s results of operations for the six months ended June 30, 2003 and the timing of income tax payments during 2003.

The balance of current Price Risk Management liabilities was approximately $45.0 million and $13.9 million at June 30, 2003 and December 31, 2002, respectively, an increase of approximately $31.1 million or 223.7 percent. The increase was due to significant volatility and higher natural gas prices associated with OERI’s trading activities during the first six months of 2003. This increase was offset by an increase in current Price Risk Management assets.

Liquidity and Capital Requirements

General

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 purchase obligations. The Company generally meets its cash needs through a combination of internally generated funds, short-term borrowings and permanent financings.

Interest Rate Swap Agreements

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 meet all of the requirements for a determination that there was no ineffective portion as allowed by the shortcut method under SFAS No. 133. 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.

Future Capital Requirements

The Company’s current 2003 to 2005 construction program does not include additional generation plants, however, the Company will continue to review all of the supply alternatives to replace expiring QF contracts that minimize the total cost of generation to our customers. Unless extended by OG&E, 540 MW's of QF contracts will expire over the next one to five years. 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 projected natural gas prices, OG&E will include the feasibility of constructing additional base load coal-fired units in its build options.

In accordance with the Settlement Agreement approved by the OCC on November 20, 2002, OG&E intends to purchase an electric generating plant with at least 400 MW’s of generating capacity. The Company believes that an efficient combined cycle plant can be purchased for a price less than the cost to build a new facility. 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 $4.9 million of the Company’s capital expenditures budgeted for 2003 are to comply with environmental laws and regulations.

Future financing requirements may be dependent, to varying degrees, upon numerous factors such as general economic conditions, abnormal weather, load growth, acquisitions of other businesses, actions by rating agencies, inflation, changes in environmental laws or regulations, rate increases or decreases allowed by regulatory agencies, new legislation and market entry of competing electric power generators.

Future Sources of Financing

General

Apart from the funds required to purchase at least 400 MW’s of a power plant pursuant to the Settlement Agreement, management expects that internally generated funds will be adequate over the next three years to meet other anticipated capital expenditures, operating needs, payment of dividends and maturities of long-term debt. The Company plans to issue a combination of equity and debt in 2003 to fund the purchase of the electric generating plant.

Short-Term Debt

Short-term borrowings will be used to meet working capital requirements. The following table shows the Company’s lines of credit in place at July 31, 2003. Short-term borrowings will consist of a combination of bank borrowings and commercial paper.

Lines of Credit (In millions)
Entity	Amount			Maturity
OGE Energy Corp. (A)	$	200	.0	January 8, 2004
		100	.0	January 15, 2004
		15	.0	April 6, 2004
OG&E		100	.0	June 26, 2004

Total	$	415	.0

(A)

The lines of credit at OGE Energy Corp. are used to back up the Company’s commercial paper borrowings, which were
   approximately $242.3 million at July 31, 2003. No borrowings were outstanding at July 31, 2003 under any of the
   lines of credit shown above, however, $8.0 million of the $15.0 million line of credit above is supported by a letter of credit
   described in "Commitments and Contingencies - Guarantees."

Security Ratings

On January 15, 2003, Standard & Poor’s Ratings Services (“Standard & Poor’s”) lowered the credit ratings of OGE Energy Corp.’s, OG&E’s and Enogex’s senior unsecured debt from A- to BBB+. OGE Energy Corp.’s short-term commercial paper ratings were affirmed at A-2. The outlook is now stable. Standard & Poor’s cited the relatively low-risk low-cost efficient operations of OG&E and the business and financial profile of Enogex, which has higher risk. Standard & Poor’s further cited the rationalization at Enogex has resulted in a business-risk reduction, but it is not adequate to warrant an improvement in the overall business score. The Company may experience somewhat higher borrowing costs but does not expect the actions by Standard & Poor’s to have a significant impact on the Company’s consolidated financial position or results of operations.

On February 5, 2003, Moody’s lowered the credit ratings of OGE Energy Corp.’s senior unsecured debt to Baa1 from A3, OG&E’s senior unsecured debt to A2 from A1 and Enogex’s senior unsecured debt to Baa3 from Baa2. OGE Energy Corp.’s short-term commercial paper rating was unchanged at P-2. The outlook for OGE Energy Corp. and OG&E is stable and Enogex is negative. Moody’s cited the diminished credit profile of both OG&E and Enogex with OG&E having competitive generation and stable cash flow but with regulatory risk associated with the acquisition of at least 400 MW’s of new generation and Enogex exposed to the seasonality of its gas processing business although it has reduced its keep-whole exposure. The Company may experience somewhat higher borrowing costs but does not expect the actions by Moody’s to have a significant impact on the Company’s consolidated financial position or results of operations. As a result of Enogex’s rating being lowered to Baa3, OGE Energy Corp. was required to issue a $5.0 million guarantee on Enogex’s behalf for a counterparty. At June 30, 2003, there is approximately a $1.5 million outstanding liability balance related to this guarantee. In the event one or more of the credit ratings were to fall below investment grade, Enogex may seek OGE Energy Corp. guarantees to satisfy its customers in order to avoid disruption of its marketing and trading business.

Asset Sales

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

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

Critical Accounting Policies and Estimates

The Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements included in this Form 10-Q and in the Company’s Form 10-K for the year ended December 31, 2002 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. However, the Company has taken 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 are in the valuation of pension plan assumptions, impairment estimates, contingency reserves, unbilled revenue for OG&E, the allowance for uncollectible accounts receivable and the valuation of energy purchase and sale contracts and natural gas storage inventory. The selection, application and disclosure of the following critical accounting estimates have been discussed with the Company’s audit committee.

Consolidated (including Electric Utility and Natural Gas Pipeline Segments)

Pension and other postretirement plan expenses and liabilities are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets and assumed discount rates. Actual changes in the fair market value of plan assets and differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension expense ultimately recognized. For a discussion of the pension plan rate assumptions, reference is made to Note 13 of the Notes to Consolidated Financial Statements in the Company’s Form 10-K for the year ended December 31, 2002.

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.

Electric Utility Segment

OG&E reads its customers’ meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers’ electricity consumption that has not been billed at the end of each month. Unbilled revenue is presented in Accrued Unbilled Revenues on the Condensed Consolidated Balance Sheets and in Operating Revenues on the Condensed Consolidated Statements of Income based on estimates of usage and prices during the period. At June 30, 2003 and December 31, 2002, Accrued Unbilled Revenues were approximately $64.8 million and $28.2 million, respectively. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.

All customer balances are written off if not collected within six months after the account is finalized. The allowance for uncollectible accounts receivable is calculated by multiplying the last six months of electric revenue by the provision rate. The provision rate is based on a 12-month historical average of actual balances written off. To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable on the Condensed Consolidated Balance Sheets and is included in Other Operation and Maintenance Expense on the Condensed Consolidated Statements of Income. The allowance for uncollectible accounts receivable for OG&E was approximately $2.3 million and $4.7 million at June 30, 2003 and December 31, 2002, respectively.

Natural Gas Pipeline Segment

Operating revenues for transportation, gathering and storage services for Enogex are estimated each month based on the prior month’s activity, historical seasonal fluctuations and any known adjustments. The estimates are reversed in the following month and customers are billed on actual volumes and contracted prices. Gas sales are calculated on current month nominations and contracted prices. Operating revenues associated with the production of natural gas liquids are estimated based on current month estimated production and contracted prices. These amounts are reversed in the following month and the customers are billed on actual production and contracted prices. Estimated operating revenues are reflected in Accounts Receivable on the Condensed Consolidated Balance Sheets and in Operating Revenues on the Condensed Consolidated Statements of Income.

Estimates for gas purchases are based on sales volumes and contracted purchase prices. Estimated gas purchases are included in Accounts Payable on the Condensed Consolidated Balance Sheets and in Cost of Goods Sold on the Condensed Consolidated Statements of Income.

In October 2002, the EITF reached a consensus 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 are no longer marked to market through earnings unless the contracts meet the definition of a derivative under SFAS No. 133. Contracts and physical inventories that existed at October 25, 2002 continued to be accounted for under EITF 98-10 through December 31, 2002. Effective January 1, 2003, these contracts were revalued in accordance with provisions of EITF 02-3 which rescinded EITF 98-10. The change in the value of these contracts is shown as a cumulative effect of a change in accounting principle in the accompanying Condensed Consolidated Statements of Income. Energy contracts are entered into by OGE Energy Resources, Inc. (“OERI”), the marketing subsidiary of Enogex. Corporate risk management and credit committees charged with enforcing the trading and credit policies, which include specific guidance on counterparties, procedures, credit and trading limits, monitor these activities. Marketing activities include the trading and marketing of natural gas, electricity and natural gas liquids. The vast majority of positions expire within two years, which is when the cash aspect of the transactions will be realized. In nearly all cases, independent market prices are obtained and compared to the values used for the mark-to-market valuation, and an oversight group outside of the marketing organization monitors all modeling methodologies and assumptions. The recorded value of the energy contracts may change significantly in the future as the market price for the commodity changes, but the value is still subject to the risk loss limitations provided under the Company’s risk policies. The Company utilizes a model to estimate the fair value of its energy contracts including derivatives that do not have an independent market price. At June 30, 2003, unrealized mark-to-market gains were approximately $2.0 million, which included approximately $0.2 million of unrealized mark-to-market losses that were calculated utilizing models. Energy contracts are presented in Price Risk Management assets and liabilities on the Condensed Consolidated Balance Sheets and in Operating Revenues on the Condensed Consolidated Statements of Income. See “Accounting Pronouncements” for a further discussion.

Effective January 1, 2003, natural gas storage inventory used in OERI’s business activities are accounted for at the lower of cost or market in accordance with the guidance in EITF 02-3, which resulted in the rescission of EITF 98-10. Prior to January 1, 2003, this inventory was accounted for on a fair value accounting basis utilizing a gas index that in management’s opinion approximated the current market value of natural gas in that region as of the Balance Sheet date. In order to minimize risk, OERI may enter into contracts or hedging instruments to hedge the fair value of this inventory. If these contracts qualify for hedge accounting under SFAS No. 133, the hedged portion of the inventory is recorded at fair value with an offsetting gain or loss recorded currently in earnings. The fair value of the hedging instrument is also recorded on the books of the Company as a Price Risk Management asset or liability with an offsetting gain or loss recorded in current earnings. At June 30, 2003, the Company had all natural gas inventory hedged with qualified fair value hedges under SFAS No. 133. As part of its recurring business activity, OERI injects and withdraws natural gas under the terms of storage capacity contracts; the amount of natural gas inventory was approximately $53.7 million and $32.9 million at June 30, 2003 and December 31, 2002, respectively. See “Accounting Pronouncements” for a further discussion. Natural gas storage inventory is presented in Fuel Inventories on the

Condensed Consolidated Balance Sheets and in Cost of Goods Sold on the Condensed Consolidated Statements of Income.

The allowance for uncollectible accounts receivable is established on a case-by-case basis when the Company believes the required payment of specific amounts owed is unlikely to occur. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable on the Condensed Consolidated Balance Sheets and is included in Other Operation and Maintenance Expense on the Condensed Consolidated Statements of Income. The allowance for uncollectible accounts receivable for the Natural Gas Pipeline segment was approximately $5.5 million and $8.9 million at June 30, 2003 and December 31, 2002, respectively.

Accounting Pronouncements

In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. SFAS No. 143 affects the Company’s accrued plant removal costs for generation, transmission, distribution and processing facilities and requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of the fair value can be made. If a reasonable estimate of the fair value cannot be made in the period the asset retirement obligation is incurred, the liability shall be recognized when a reasonable estimate of the fair value can be made. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes, written or oral contracts, including obligations arising under the doctrine of promissory estoppel. The recognition of an asset retirement obligation is capitalized as part of the carrying amount of the long-lived asset. Asset retirement obligations represent future liabilities and, as a result, accretion expense is accrued on this liability until such time as the obligation is satisfied. Adoption of SFAS No. 143 is required for financial statements issued for fiscal years beginning after June 15, 2002. The Company adopted this new standard effective January 1, 2003 and the adoption of this new standard did not have a material impact on its consolidated financial position or results of operations. In connection with the adoption of SFAS No. 143, the Company assessed whether it had a legal obligation within the scope of SFAS No. 143. The Company determined that it had a legal obligation to retire certain assets. As the Company currently has no plans to retire any of these assets and the remaining life is indeterminable, an asset retirement obligation was not recognized; however, the Company will monitor these assets and record a liability when a reasonable estimate of the fair value can be made. As described below, amounts recovered from ratepayers related to estimated asset retirement obligations recorded as a liability in Accumulated Depreciation were reclassified as a regulatory liability in the first quarter of 2003.

SFAS No. 143 also requires that, if the conditions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” are met, a regulatory asset or liability should be recorded to recognize differences between asset retirement costs recorded under SFAS No. 143 and legal or other asset retirement costs recognized for ratemaking purposes. Upon adoption of SFAS No.

143, the Company was required to quantify the amount of asset retirement costs previously recovered from ratepayers for other than legal obligations and reclassify those differences as regulatory assets or liabilities. At December 31, 2002, approximately $109.3 million had been previously recovered from ratepayers and recorded as a liability in Accumulated Depreciation related to estimated asset retirement obligations. This balance was reclassified as a regulatory liability on the December 31, 2002 Condensed Consolidated Balance Sheet. At June 30, 2003, the regulatory liability for accrued removal obligations, net was approximately $112.7 million.

In October 2002, the EITF reached a consensus on certain issues covered in EITF 02-3. One consensus of EITF 02-3 requires that all mark-to-market gains and losses, whether realized or unrealized, on financial derivative contracts as defined in SFAS No. 133 be shown net in the Income Statement for financial statements issued for periods beginning after December 15, 2002, with reclassification required for prior periods presented. The Company adopted this consensus effective January 1, 2003 and the application of this consensus did not have a material impact on its consolidated financial position or results of operations as this consensus supports the Company’s historical presentation of financial derivative contracts.

In October 2002, the EITF reached a consensus to rescind EITF 98-10 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 are no longer marked to market through earnings unless the contracts meet the definition of a derivative under SFAS No. 133. Application of the consensus for energy contracts and inventory that existed on or before October 25, 2002 that remained 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 Accounting Principles Board (“APB”) Opinion No. 20, “Accounting Changes.” As a result, only energy contracts that meet the definition of a derivative in SFAS No. 133 will be carried at fair value. The Company adopted this consensus effective January 1, 2003 resulting in an approximate $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, 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 gross margin on revenues in excess of the cumulative effect loss described above.

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 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation which includes the prospective method, modified prospective method and retroactive restatement method. SFAS No. 148 also amends the disclosure requirements of SFAS No. 123, “Accounting for Stock-Based Compensation,” 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. Adoption of the annual disclosure and voluntary transition requirements of SFAS No. 148 is required for annual financial statements issued for fiscal years ending after December 15, 2002. Adoption of the interim disclosure requirements of SFAS No. 148 is required for interim periods beginning after December 15, 2002. Pursuant to the provisions of SFAS No. 123, the Company has elected to continue using the intrinsic value method of accounting for its stock-based employee compensation plans in accordance with APB Opinion No. 25, “Accounting for Stock Issued to Employees.” However, the Company has included the required disclosures under SFAS No. 148 in Note 1 of Notes to Condensed Consolidated Financial Statements.

In April 2003, the FASB issued SFAS No. 149, “Amendments of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain instruments embedded in other contracts and for hedging activities under SFAS No. 133. This statement requires that contracts with comparable characteristics be accounted for similarly. In particular, this statement clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative, clarifies when a derivative contains a financing component, amends the definition of an underlying hedged risk to conform to language used in FASB Interpretation No. 45 and amends certain other existing pronouncements. This statement, the provisions of which are to be applied prospectively, is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The Company adopted this new standard effective July 1, 2003 and the adoption of this new standard is not expected to have a material impact on its consolidated financial position or results of operations.

Electric Competition; Regulation

Proposed Standard Market Design Rulemaking

In July 2002, the FERC issued a Notice of Proposed Rulemaking on Standard Market Design Rulemaking for regulated utilities. If implemented as proposed, the rulemaking will substantially change how wholesale electric markets operate throughout the United States. The proposed rulemaking expands the FERC’s intent to unbundle transmission operations from integrated utilities and ensure robust competition in wholesale markets. The proposed rule contemplates that all wholesale and retail customers will take transmission service under a single network transmission service tariff. The rule also contemplates the implementation of a bid-based system for buying and selling energy in wholesale markets. RTOs or Independent Transmission Providers will administer the market. RTOs will also be responsible for regional plans that identify opportunities to construct new transmission, generation or demand side programs to reduce transmission constraints and meet regional energy requirements. Finally, the rule envisions the development of Regional Market Monitors responsible for ensuring the individual participants do not exercise unlawful market power. On April 28, 2003, the FERC

issued a White Paper, “Wholesale Market Platform”, in which the FERC indicated that it will change the proposed rule as reflected in the White Paper and following additional regional technical conferences. The FERC committed in the White Paper to work with interested parties including state commissions to find solutions that will recognize regional differences within regions subject to the FERC’s jurisdiction. Thus far, the FERC has held conferences in Boston and Omaha.

Reference is made to Note 14 and Note 15 of Notes to Condensed Consolidated Financial Statements in this report and to “Electric Competition; Regulation” in Item 7 of the Company’s Form 10-K for the year ended December 31, 2002 for a discussion of pending regulatory actions involving OG&E or Enogex and of other initiatives to increase competition in the retail and wholesale sale of electricity.

Commitments and Contingencies

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

On July 16, 2003, the Company and Enogex served separate complaints on the individual shareholders of COOG and NGSC - Enogex Inc. v John C. Thrash, John F. Thrash and Robert R.

Voorhees, Jr., Case No. CIV_03-0388-L; and OGE Energy Corp. and Enogex Inc. v John C. Thrash, John F. Thrash and Robert R. Voorhees, Jr., Case No. CIV 03-0389-L - both filed in the Western District of Oklahoma Federal Court. The Company and Enogex have each stated claims for (1) fraudulent transfer; (2) imposition of an equitable trust; and (3) breach of fiduciary duty. Enogex seeks to recover the remaining amount owed under the Judgment, plus interest, and the Company and Enogex seek to recover amount owed under the NGSC Loan, plus interest.

Farmland Industries

On July 31, 2003, Farmland filed its Disclosure Statement for its Reorganization Plan for approval by the bankruptcy court. According to the Disclosure Statement, Farmland proposes to pay its general unsecured creditors an amount between 50 percent and 65 percent on their pre-petition claims. As a general unsecured creditor of Farmland and pursuant to the terms of the Settlement Agreement referenced above, Enogex’s recovery under the proposed distribution would be approximately $0.8 million, which is in addition to the $1.9 million Enogex received in May 2003.

Agreement with Colorado Interstate Gas Company

Cheyenne Plains issued a second open season notice on July 25, 2003, wherein Cheyenne Plains proposes to expand the capacity of its pipeline facilities in connection with a separate open

season being conducted by an affiliate, Wyoming Interstate Company. The second open season expires on August 14, 2003.

Guarantees

Storm Damage

Other

Besides the various existing contingencies herein described, the Company’s ability to fund its future operational needs and to finance its construction program could be impacted by numerous factors such as general economic conditions, abnormal weather, load growth, acquisitions of other businesses, actions by rating agencies, inflation, changes in environmental laws or regulations, rate increases or decreases allowed by regulatory agencies, new legislation and market entry of competing electric power generators.

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 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 engages in price risk management for both trading and non-trading purposes.

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

Interest Rate Risk

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

The Company’s exposure to interest rate risk for changes in interest rates has not significantly changed since December 31, 2002. See Notes 11 and 12 of Notes to Condensed Consolidated Financial Statements.

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 Company’s commodity prices.

The trading activities are conducted throughout the year subject to a daily, monthly and annual trading stop loss limit of $4.0 million. The daily loss exposure from trading activities is measured primarily using value at risk as well as other quantitative risk measurement techniques and is limited to $1.5 million. These limits are designed to mitigate the possibility of trading activities having a material adverse effect on Enogex’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. Processing spreads are the difference between the values of natural gas liquids compared to the value of an equivalent

amount of MMBtu in natural gas form. To partially reduce 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, a portion of the Company’s supply and related purchase and sale contracts, as well as any anticipated transactions (purchases and sales). Because the commodities covered by these derivatives are substantially the same commodities that the Company buys and sells in the physical market, no special studies other than monitoring the degree of correlation between the derivative and cash markets are deemed necessary.

A sensitivity analysis has been prepared to estimate the commodity price exposure to the market risk of the Company’s natural gas, natural gas liquids and electricity commodity positions. The Company’s daily net commodity position consists of natural gas inventories, commodity purchase and sales contracts, financial and commodity derivative instruments and anticipated natural gas processing spreads and fuel recoveries. The fair value of such position is a summation of the fair values calculated for each commodity by valuing each net position at quoted market prices. Market risk is estimated as the potential loss in fair value resulting from a hypothetical 10 percent adverse change in such prices over the next 12 months. The results of this analysis, which may differ from actual results, are as follows as of June 30, 2003:

(In millions)	Trading			Non-Trading
Commodity market risk, net	$	0	.1	$	4	.2

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.

Subsequent to the date of their evaluation, there have been no significant changes in the Company’s internal controls or in other factors that could significantly affect these controls.

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, 2002 and to Part II, Item 1 of the Company’s Form 10-Q for the quarter ended March 31, 2003 for a description of certain legal proceedings presently pending. 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, except as set forth below.

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

Federal Energy Regulatory Commission

On July 31, 2003, representatives of Enogex met with the FERC Staff to discuss resolution of a pending matter that Enogex discovered and brought to the FERC's attention in November 2002 relating to construction by Ozark under its blanket certificate and Enogex under Section 311 authorization. The matter disclosed to the FERC relates to minor construction in 1998 and 1999 that was performed under the reasonable belief that the facilities constituted non-jurisdictional gathering. Accordingly, pre-construction environmental clearances for the FERC-jurisdictional facilities were not obtained and the construction was not reported on blanket certificate and Section 311 construction reports. Upon review, Enogex and Ozark determined that two construction projects should have been treated as FERC-jurisdictional transmission, one under Ozark's blanket certificate and the other pursuant to Enogex's Section 311 authorization. Enogex and Ozark self-reported the non-compliant activities and have cooperated with the FERC's investigation, including providing all requested information to the FERC. The FERC has proposed Enogex pay an amount of approximately $0.1 million relating to both construction projects. Enogex and Ozark continue to work with and exchange information with the FERC Staff.

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

(a) The Company’s Annual Meeting of Shareowners was held on May 22, 2003.

(b) Not applicable.

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

Steven E. Moore — 69,502,197 votes for election and
2,667,951 votes withheld

William E. Durrett — 69,241,672 votes for election and
2,928,476 votes withheld

John D. Groendyke — 69,751,551 votes for election and
2,418,597 votes withheld

(2) The Shareowners voted for the Company’s 2003 Stock Incentive Plan as
follows:

62,544,822 votes for approval, 8,055,229 votes against and
1,570,097 votes abstained

(3) The Shareowners voted for the Company’s Annual Incentive
Compensation Plan as follows:

62,634,322 votes for approval, 7,793,840 votes against and
1,741,986 votes abstained

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

Exhibit No.		Description
10.01		Credit Agreement dated June 26, 2003 between OG&E, Bank One, NA, Wachovia Bank, National Association, Cobank, ACB and LaSalle Bank National Association.
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, 2003 to report its consolidated results of operations and financial condition for the first quarter of 2003.

The Company filed a Current Report on Form 8-K on May 6, 2003 to report additional financial data discussed in the Company’s first quarter 2003 earnings conference call.

The Company filed a Current Report on Form 8-K on June 16, 2003 to report the resignation of the Treasurer of the Company.

The Company filed a Current Report on Form 8-K on July 2, 2003 to report the Company’s decision to move OG&E’s request for a general rate change to later in 2003.

The Company filed a Current Report on Form 8-K on August 6, 2003 to report its consolidated results of operations and financial condition for the second quarter of 2003.

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 13, 2003

Exhibit 10.01

CREDIT AGREEMENT

DATED AS OF JUNE 26, 2003

AMONG

OKLAHOMA GAS AND ELECTRIC COMPANY,

THE LENDERS

AND

BANK ONE, NA
AS ADMINISTRATIVE AGENT

AND

WACHOVIA BANK, NATIONAL ASSOCIATION
AS SYNDICATION AGENT

AND

COBANK, ACB AND LASALLE BANK NATIONAL ASSOCIATION
AS CO-DOCUMENTATION AGENTS

BANC ONE CAPITAL MARKETS, INC.,
AS SOLE LEAD ARRANGER AND SOLE BOOK RUNNER

SIDLEY AUSTIN BROWN & WOOD
Bank One Plaza
10 South Dearborn Street
Chicago, Illinois 60603

TABLE OF CONTENTS
ARTICLE I	DEFINITIONS	1
ARTICLE II	THE CREDITS	12
2.1.	Commitment	12
2.2.	Required Payments; Termination	13
2.3.	Ratable Loans	13
2.4.	Types of Advances	13
2.5.	Facility Fee; Utilization Fee; Reductions in Aggregate Commitment	13
2.6.	Minimum Amount of Each Advance	14
2.7.	Optional Principal Payments	14
2.8.	Method of Selecting Types and Interest Periods for New Advances	14
2.9.	Conversion and Continuation of Outstanding Advances	14
2.10.	Changes in Interest Rate, etc.	15
2.11.	Rates Applicable After Default	15
2.12.	Method of Payment	16
2.13.	Noteless Agreement; Evidence of Indebtedness	16
2.14.	Telephonic Notices	16
2.15.	Interest Payment Dates; Interest and Fee Basis	17
2.16.	Notification of Advances, Interest Rates, Prepayments and
	Commitment Reductions; Availability or Loans	17
2.17.	Lending Installations	17
2.18.	Non-Receipt of Funds by the Agent	17
2.19.	Replacement of Lender	18
ARTICLE III	YIELD PROTECTION; TAXES	18
3.1.	Yield Protection	18
3.2.	Changes in Capital Adequacy Regulations	19
3.3.	Availability of Types of Advances	20
3.4.	Funding Indemnification	20
3.5.	Taxes	20
3.6.	Lender Statements; Survival of Indemnity	22
3.7.	Alternative Lending Installation	22
ARTICLE IV	CONDITIONS PRECEDENT	22
4.1.	Initial Advance	22
4.2.	Each Advance	23
ARTICLE V	REPRESENTATIONS AND WARRANTIES	24
5.1.	Existence and Standing	24
5.2.	Authorization and Validity	24
5.3.	No Conflict; Government Consent	24
5.4.	Financial Statements	25
5.5.	Material Adverse Change	25

5.6.	Taxes	25
5.7.	Litigation and Contingent Obligations	25
5.8.	Subsidiaries	26
5.9.	ERISA	26
5.10.	Accuracy of Information	26
5.11.	Regulation U	26
5.12.	Material Agreements	26
5.13.	Compliance With Laws	27
5.14.	Ownership of Properties	27
5.15.	Plan Assets; Prohibited Transactions	27
5.16.	Environmental Matters	27
5.17.	Investment Company Act	27
5.18.	Public Utility Holding Company Act	27
5.19.	Insurance	28
5.20.	No Default or Unmatured Default	28
5.21.	Reportable Transaction	28
ARTICLE VI	COVENANTS	28
6.1.	Financial Reporting	28
6.2.	Use of Proceeds	29
6.3.	Notice of Default	29
6.4.	Conduct of Business	29
6.5.	Taxes	29
6.6.	Insurance	30
6.7.	Compliance with Laws	30
6.8.	Maintenance of Properties	30
6.9.	Inspection; Keeping of Books and Records	30
6.10.	Merger	30
6.11.	Sale of Assets	30
6.12.	Liens	31
6.13.	Affiliates	33
6.14.	Financial Contracts	33
6.15.	Leverage Ratio	33
ARTICLE VII	DEFAULTS	33
ARTICLE VIII	ACCELERATION, WAIVERS, AMENDMENTS AND REMEDIES	35
8.1.	Acceleration	35
8.2.	Amendments	36
8.3.	Preservation of Rights	36
ARTICLE IX	GENERAL PROVISIONS	37
9.1.	Survival of Representations	37
9.2.	Governmental Regulation	37

9.3.	Headings	37
9.4.	Entire Agreement	37
9.5.	Several Obligations; Benefits of this Agreement	37
9.6.	Expenses; Indemnification	37
9.7.	Numbers of Documents	38
9.8.	Accounting	38
9.9.	Severability of Provisions	39
9.10.	Nonliability of Lenders	39
9.11.	Confidentiality	39
9.12.	Lenders Not Utilizing Plan Assets	40
9.13.	Nonreliance	40
9.14.	Disclosure	40
ARTICLE X	THE AGENT	40
10.1.	Appointment; Nature of Relationship	40
10.2.	Powers	40
10.3.	General Immunity	41
10.4.	No Responsibility for Loans, Recitals, etc.	41
10.5.	Action on Instructions of Lenders	41
10.6.	Employment of Agents and Counsel	41
10.7.	Reliance on Documents; Counsel	41
10.8.	Agent's Reimbursement and Indemnification	42
10.9.	Notice of Default	42
10.10.	Rights as a Lender	42
10.11.	Lender Credit Decision	43
10.12.	Successor Agent	43
10.13.	Agent and Arranger Fees	43
10.14.	Delegation to Affiliates	43
10.15.	Syndication Agent and Co-Documentation Agents	44
ARTICLE XI	SETOFF; RATABLE PAYMENTS	44
11.1.	Setoff	44
11.2.	Ratable Payments	44
ARTICLE XII	BENEFIT OF AGREEMENT; ASSIGNMENTS; PARTICIPATIONS	44
12.1.	Successors and Assigns; Designated Lenders	44
12.2.	Participations	46
12.3.	Assignments	47
12.4.	Dissemination of Information	49
12.5.	Tax Certifications	49
ARTICLE XIII	NOTICES	49
13.1.	Notices	49
13.2.	Change of Address	49
ARTICLE XIV	COUNTERPARTS	50

iii

ARTICLE XV	CHOICE OF LAW; CONSENT TO JURISDICTION;
	WAIVER OF JURY TRIAL	50
ARTICLE XVI	TERMINATION OF EXISTING CREDIT AGREEMENT	51

SCHEDULES

Commitment Schedule

Pricing Schedule

Schedule 1	-	Subsidiaries
Schedule 2	-	Asset Dispositions
Schedule 3	-	Liens

EXHIBITS

Exhibit A	-	Form of Borrower's Counsels' Opinions
Exhibit B	-	Form of Compliance Certificate
Exhibit C	-	Form of Assignment and Assumption Agreement
Exhibit D	-	Form of Loan/Credit Related Money Transfer Instruction
Exhibit E	-	Form of Promissory Note (if requested)
Exhibit F	-	Form of Designation Agreement

CREDIT AGREEMENT

This Agreement, dated as of June 26, 2003, is among Oklahoma Gas and Electric Company, an Oklahoma corporation, the Lenders and Bank One, NA, a national banking association having its principal office in Chicago, Illinois, as Administrative Agent and Wachovia Bank, National Association, as Syndication Agent and CoBank, ACB and LaSalle Bank National Association as Co-Documentation Agents. The parties hereto agree as follows:

ARTICLE I

DEFINITIONS

As used in this Agreement:

“Accounting Changes” is defined in Section 9.8. hereof.

“Advance” means a borrowing hereunder, (i) made by the Lenders on the same Borrowing Date, or (ii) converted or continued by the Lenders on the same date of conversion or continuation, consisting, in either case, of the aggregate amount of the several Loans of the same Type and, in the case of Eurodollar Loans, for the same Interest Period.

“Affiliate” of any Person means any other Person directly or indirectly controlling, controlled by or under common control with such Person. A Person shall be deemed to control another Person if the controlling Person owns 10% or more of any class of voting securities (or other ownership interests) of the controlled Person or possesses, directly or indirectly, the power to direct or cause the direction of the management or policies of the controlled Person, whether through ownership of stock, by contract or otherwise.

“Agent” means Bank One in its capacity as contractual representative of the Lenders pursuant to Article X, and not in its individual capacity as a Lender, as Administrative Agent, and any successor Agent appointed pursuant to Article X.

“Aggregate Commitment” means the aggregate of the Commitments of all the Lenders, as reduced from time to time pursuant to the terms hereof. The initial Aggregate Commitment is One Hundred Million and 00/100 Dollars ($100,000,000).

“Aggregate Outstanding Credit Exposure” means, at any time, the aggregate of the Outstanding Credit Exposure of all the Lenders.

“Agreement” means this Credit Agreement, as it may be amended, restated, supplemented or otherwise modified and as in effect from time to time.

“Agreement Accounting Principles” means generally accepted accounting principles applied in a manner consistent with that used in preparing the financial statements referred to in Section 5.4., as modified in accordance with Section 9.8.

“Alternate Base Rate” means, for any day, a fluctuating rate of interest per annum equal to the higher of (i) the Prime Rate for such day and (ii) the sum of the Federal Funds Effective Rate for such day and one half of one percent (0.5%) per annum.

“Applicable Fee Rate” means, with respect to the Facility Fee and the Utilization Fee at any time, the percentage rate per annum which is applicable at such time with respect to each such fee as set forth in the Pricing Schedule.

“Applicable Margin” means, with respect to Advances of any Type at any time, the percentage rate per annum which is applicable at such time with respect to Advances of such Type as set forth in the Pricing Schedule.

“Approved Fund” means any Fund that is administered or managed by (a) a Lender, (b) an Affiliate of a Lender or (c) an entity or an Affiliate of an entity that administers or manages a Lender.

“Arranger” means Banc One Capital Markets, Inc., a Delaware corporation, and its successors, in its capacity as Lead Arranger and Sole Book Runner.

“Article” means an article of this Agreement unless another document is specifically referenced.

“Authorized Officer” means any of the President, Chief Financial Officer, Treasurer, or any Vice President of the Borrower, acting singly.

“Bank One” means Bank One, NA, a national banking association having its principal office in Chicago, Illinois, in its individual capacity, and its successors.

“Borrower” means Oklahoma Gas and Electric Company, an Oklahoma corporation, and its permitted successors and assigns (including, without limitation, a debtor in possession on its behalf).

“Borrowing Date” means a date on which an Advance is made hereunder.

“Borrowing Notice” is defined in Section 2.8.

“Business Day” means (i) with respect to any borrowing, payment or rate selection of Eurodollar Advances, a day (other than a Saturday or Sunday) on which banks generally are open in Chicago, Illinois and New York, New York for the conduct of substantially all of their commercial lending activities, interbank wire transfers can be made on the Fedwire system and dealings in United States dollars are carried on in the London interbank market and (ii) for all other purposes, a day (other than a Saturday or Sunday) on which banks generally are open in Chicago, Illinois for the conduct of substantially all of their commercial lending activities and interbank wire transfers can be made on the Fedwire system.

“Capitalized Lease” of a Person means any lease of Property by such Person as lessee which would be capitalized on a balance sheet of such Person prepared in accordance with Agreement Accounting Principles.

“Capitalized Lease Obligations” of a Person means the amount of the obligations of such Person under Capitalized Leases which would be shown as a liability on a balance sheet of such Person prepared in accordance with Agreement Accounting Principles.

“Change in Control” means (i) the acquisition by any Person, or two or more Persons acting in concert, of beneficial ownership (within the meaning of Rule 13d-3 of the Securities and Exchange Commission under the Securities Exchange Act of 1934) of 30% or more of the outstanding shares of voting stock of the Parent; (ii) the Parent shall cease to own, directly or indirectly and free and clear of all Liens or other encumbrances, at least 80% of the outstanding shares of voting stock of the Borrower on a fully diluted basis; or (iii) the majority of the Board of Directors of the Parent fails to consist of Continuing Directors.

“Closing Date” means June 26, 2003.

“Code” means the Internal Revenue Code of 1986, as amended, reformed or otherwise modified from time to time, and any rule or regulation issued thereunder.

“Co-Documentation Agent” means each of CoBank, ACB and LaSalle Bank National Association, in its capacity as Co-Documentation Agent hereunder.

“Commitment” means, for each Lender, the amount set forth on the Commitment Schedule opposite such Lender’s name, as it may be modified as a result of any assignment that has become effective pursuant to Section 12.3 or as otherwise modified from time to time pursuant to the terms hereof.

“Commitment Schedule” means the Schedule identifying each Lender’s Commitment as of the Closing Date attached hereto and identified as such.

“Consolidated Indebtedness” means at any time the Indebtedness of the Borrower and its Subsidiaries calculated on a consolidated basis as of such time.

“Consolidated Net Worth” means at any time the consolidated stockholders’ equity of the Borrower and its Subsidiaries calculated on a consolidated basis in accordance with Agreement Accounting Principles.

“Consolidated Total Capitalization” means at any time the sum of Consolidated Indebtedness and Consolidated Net Worth, each calculated at such time.

“Contingent Obligation” of a Person means any agreement, undertaking or arrangement by which such Person assumes, guarantees, endorses, contingently agrees to purchase or provide funds for the payment of, or otherwise becomes or is contingently liable upon, the obligation or liability of any other Person, or agrees to maintain the net worth or working capital or other financial condition of any other Person, or otherwise assures any creditor of such other Person against loss, including, without limitation, any comfort letter, operating agreement, take-or-pay contract or the obligations of any such Person as general partner of a partnership with respect to the liabilities of the partnership.

“Continuing Director” means, with respect to any Person as of any date of determination, any member of the board of directors of such Person who (a) was a member of such board of directors on the Closing Date, or (b) was nominated for election or elected to such board of directors with the approval of a majority of the Continuing Directors who were members of such board at the time of such nomination or election.

“Controlled Group” means all members of a controlled group of corporations or other business entities and all trades or businesses (whether or not incorporated) under common control which, together with the Borrower or any of its Subsidiaries, are treated as a single employer under Section 414 of the Code.

“Conversion/Continuation Notice” is defined in Section 2.9.

“Default” means an event described in Article VII.

“Designated Lender” means, with respect to each Designating Lender, each Eligible Designee designated by such Designating Lender pursuant to Section 12.1.2.

“Designating Lender” means, with respect to each Designated Lender, the Lender that designated such Designated Lender pursuant to Section 12.1.2.

“Designation Agreement” is defined in Section 12.1.2.

“Dollar” and “$” means dollars in the lawful currency of the United States of America.

“Eligible Designee” means a special purpose corporation, partnership, limited partnership or limited liability company that is administered by the respective Designating Lender or an Affiliate of such Designating Lender and (i) is organized under the laws of the United States of America or any state thereof, (ii) is engaged primarily in making, purchasing or otherwise investing in commercial loans in the ordinary course of its business and (iii) issues (or the parent of which issues) commercial paper rated at least A-1 or the equivalent thereof by S&P or the equivalent thereof by Moody’s.

“Environmental Laws” means any and all federal, state, local and foreign statutes, laws, judicial decisions, regulations, ordinances, rules, judgments, orders, decrees, plans, injunctions, permits, concessions, grants, franchises, licenses, agreements and other governmental restrictions relating to (i) the protection of the environment, (ii) the effect of the environment on human health, (iii) emissions, discharges or releases of pollutants, contaminants, hazardous substances or wastes into surface water, ground water or land, or (iv) the manufacture, processing, distribution, use, treatment, storage, disposal, transport or handling of pollutants, contaminants, hazardous substances or wastes or the clean-up or other remediation thereof.

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended from time to time, and any rules or regulations issued thereunder.

“Eurodollar Advance” means an Advance which, except as otherwise provided in Section 2.11., bears interest at the applicable Eurodollar Rate.

“Eurodollar Base Rate” means, with respect to a Eurodollar Advance for the relevant Interest Period, the applicable British Bankers’ Association Interest Settlement Rate for deposits in Dollars appearing on Reuters Screen FRBD as of 11:00 a.m. (London time) two (2) Business Days prior to the first day of such Interest Period, and having a maturity equal to such Interest Period, provided that, (i) if Reuters Screen FRBD is not available to the Agent for any reason, the applicable Eurodollar Base Rate for the relevant Interest Period shall instead be the applicable British Bankers’ Association Interest Settlement Rate for deposits in Dollars as reported by any other generally recognized financial information service as of 11:00 a.m. (London time) two (2) Business Days prior to the first day of such Interest Period, and having a maturity equal to such Interest Period, and (ii) if no such British Bankers’ Association Interest Settlement Rate is available to the Agent, the applicable Eurodollar Base Rate for the relevant Interest Period shall instead be the rate determined by the Agent to be the rate at which Bank One or one of its affiliate banks offers to place deposits in Dollars with first class banks in the London interbank market at approximately 11:00 a.m. (London time) two (2) Business Days prior to the first day of such Interest Period, in the approximate amount of Bank One’s relevant Eurodollar Loan, and having a maturity equal to such Interest Period.

“Eurodollar Loan” means a Loan which, except as otherwise provided in Section 2.11., bears interest at the applicable Eurodollar Rate.

“Eurodollar Rate” means, with respect to a Eurodollar Advance for the relevant Interest Period, the sum of (i) the quotient of (a) the Eurodollar Base Rate applicable to such Interest Period, divided by (b) one minus the Reserve Requirement (expressed as a decimal) applicable to such Interest Period, plus (ii) the Applicable Margin.

“Excluded Taxes” means, in the case of each Lender or applicable Lending Installation and the Agent, taxes imposed on its overall net income, and franchise taxes (imposed in lieu of net income taxes) imposed on it, by (i) the jurisdiction under the laws of which such Lender or the Agent is incorporated or organized or any political combination or subdivision or taxing authority thereof or (ii) the jurisdiction in which the Agent’s or such Lender’s principal executive office or such Lender’s applicable Lending Installation is located.

“Exhibit” refers to an exhibit to this Agreement, unless another document is specifically referenced.

“Existing Credit Agreement” means that certain Credit Agreement dated as of June 27, 2002 among the Borrower, the financial institutions party thereto as lenders and agents and Bank One as administrative agent, as the same has been amended, restated, supplemented or otherwise modified from time to time.

“Facility Fee” is defined in Section 2.5.1.

“Facility Termination Date” means the earlier of (a) June 24, 2004 and (b) the date of termination in whole of the Aggregate Commitment pursuant to Section 2.5. hereof or the Commitments pursuant to Section 8.1. hereof.

“Federal Funds Effective Rate” means, for any day, an interest rate per annum equal to the weighted average of the rates on overnight Federal funds transactions with members of the

Federal Reserve System arranged by Federal funds brokers on such day, as published for such day (or, if such day is not a Business Day, for the immediately preceding Business Day) by the Federal Reserve Bank of New York, or, if such rate is not so published for any day which is a Business Day, the average of the quotations at approximately 10:00 a.m. (Chicago time) on such day on such transactions received by the Agent from three Federal funds brokers of recognized standing selected by the Agent in its sole discretion.

“FERC” means the Federal Energy Regulatory Commission, or any successor thereto.

“Floating Rate” means, for any day, a rate per annum equal to (i) the Alternate Base Rate for such day plus (ii) the Applicable Margin, in each case changing when and as the Alternate Base Rate changes.

“Floating Rate Advance” means an Advance which, except as otherwise provided in Section 2.11., bears interest at the Floating Rate.

“Floating Rate Loan” means a Loan which, except as otherwise provided in Section 2.11., bears interest at the Floating Rate.

“Fund” means any Person (other than a natural person) that is (or will be) engaged in making, purchasing, holding or otherwise investing in commercial loans and similar extensions of credit in the ordinary course of its business.

“GAAP” means generally accepted accounting principles in effect from time to time.

“Indebtedness” of a Person means, at any time, without duplication, such Person’s (i) obligations for borrowed money, (ii) obligations representing the deferred purchase price of Property or services (other than accounts payable arising in the ordinary course of such Person’s business payable on terms customary in the trade), (iii) obligations, whether or not assumed, secured by Liens or payable out of the proceeds or production from Property now or hereafter owned or acquired by such Person, (iv) obligations which are evidenced by notes, acceptances, or other instruments, (v) obligations to purchase securities or other Property arising out of or in connection with the sale of the same or substantially similar securities or Property, (vi) Capitalized Lease Obligations, (vii) Contingent Obligations then due and payable by such Person, (viii) reimbursement obligations under Letters of Credit, (ix) Off-Balance Sheet Liabilities, and (x) any other obligation for borrowed money which in accordance with Agreement Accounting Principles would be shown as a liability on the consolidated balance sheet of such Person.

“Interest Period” means, with respect to a Eurodollar Advance, a period of one, two, three or six months or such other period agreed to by the Lenders and the Borrower, commencing on a Business Day selected by the Borrower pursuant to this Agreement. Such Interest Period shall end on but exclude the day which corresponds numerically to such date one, two, three or six months or such other agreed upon period thereafter, provided, however, that if there is no such numerically corresponding day in such next, second, third or sixth succeeding month or such other succeeding period, such Interest Period shall end on the last Business Day of such next, second, third or sixth succeeding month or such other succeeding period. If an Interest Period would otherwise end on a day which is not a Business Day, such Interest Period shall end on the

next succeeding Business Day, provided, however, that if said next succeeding Business Day falls in a new calendar month, such Interest Period shall end on the immediately preceding Business Day.

“Lenders” means the lending institutions listed on the signature pages of this Agreement and their respective successors and assigns.

“Lending Installation” means, with respect to a Lender or the Agent, the office, branch, subsidiary or affiliate of such Lender or the Agent listed on the signature pages hereof or on the administrative information sheets provided to the Agent in connection herewith or on a Schedule or otherwise selected by such Lender or the Agent pursuant to Section 2.17.

“Letter of Credit” of a Person means a letter of credit or similar instrument which is issued upon the application of such Person or upon which such Person is an account party or for which such Person is in any way liable.

“Lien” means any lien (statutory or other), mortgage, pledge, hypothecation, assignment, deposit arrangement, encumbrance or preference, priority or other security agreement or preferential arrangement of any kind or nature whatsoever (including, without limitation, the interest of a vendor or lessor under any conditional sale, Capitalized Lease or other title retention agreement).

“Loan” means, with respect to a Lender, such Lender’s loan made pursuant to Article II (or any conversion or continuation thereof).

“Loan Documents” means this Agreement and all other documents, instruments, notes (including any Notes issued pursuant to Section 2.13. (if requested)) and agreements executed in connection therewith or contemplated thereby, as the same may be amended, restated or otherwise modified and in effect from time to time.

“Material Adverse Effect” means a material adverse effect on (i) the business, Property, condition (financial or otherwise), operations or results of operations of the Borrower, or the Borrower and its Subsidiaries taken as a whole, (ii) the ability of the Borrower to perform its obligations under the Loan Documents, or (iii) the validity or enforceability of any of the Loan Documents or the rights or remedies of the Agent or the Lenders thereunder.

“Material Indebtedness” means Indebtedness in an outstanding principal amount of $20,000,000 or more in the aggregate (or the equivalent thereof in any currency other than U.S. dollars).

“Material Indebtedness Agreement” means any agreement under which any Material Indebtedness was created or is governed or which provides for the incurrence of Indebtedness in an amount which would constitute Material Indebtedness (whether or not an amount of Indebtedness constituting Material Indebtedness is outstanding thereunder).

“Material Subsidiary” means any Subsidiary that would be a “significant subsidiary” as defined in Article 1, Rule 1-02 of Regulation S-X, as promulgated under the Securities Act of 1933, as amended, as such regulation is in effect on the date of this Agreement, provided,

however, a Subsidiary that would not be a “significant subsidiary” as defined in Regulation S-X will be treated as a Material Subsidiary to the extent necessary so that all Subsidiaries that are not Material Subsidiaries do not in the aggregate represent more than 25% of the consolidated total assets of the Borrower and its consolidated Subsidiaries or more than 25% of the total revenue of the Borrower and its consolidated Subsidiaries.

“Moody’s” means Moody’s Investors Service, Inc.

“Multiemployer Plan” means a multiemployer plan, as defined in Section 4001(a)(3) of ERISA, which is covered by Title IV of ERISA and to which the Borrower or any member of the Controlled Group is obligated to make contributions.

“Non-U.S. Lender” is defined in Section 3.5(iv).

“Note” is defined in Section 2.13.

“Obligations” means all Loans, advances, debts, liabilities, obligations, covenants and duties owing by the Borrower to the Agent, any Lender, the Arranger, any affiliate of the Agent, any Lender or the Arranger, or any indemnitee under the provisions of Section 9.6. or any other provisions of the Loan Documents, in each case of any kind or nature, present or future, arising under this Agreement or any other Loan Document, whether or not evidenced by any note, guaranty or other instrument, whether or not for the payment of money, whether arising by reason of an extension of credit, loan, foreign exchange risk, guaranty, indemnification, or in any other manner, whether direct or indirect (including those acquired by assignment), absolute or contingent, due or to become due, now existing or hereafter arising and however acquired. The term includes, without limitation, all interest, charges, expenses, fees, attorneys’ fees and disbursements, paralegals’ fees, and any other sum chargeable to the Borrower or any of its Subsidiaries under this Agreement or any other Loan Document.

“Off-Balance Sheet Liability” of a Person means the principal component of (i) any liability under any Sale and Leaseback Transaction which is not a Capitalized Lease, (ii) any liability under any so-called “synthetic lease” transaction entered into by such Person, or (iii) any obligation arising with respect to any other transaction which is the functional equivalent of or takes the place of borrowing but which does not constitute a liability on the balance sheets of such Person, but excluding from this clause (iii) Operating Leases and also excluding liabilities in connection with any Receivables Purchase Facility.

“Other Taxes” is defined in Section 3.5(ii).

“Outstanding Credit Exposure” means, as to any Lender, the aggregate principal amount of its Loans outstanding at such time.

“Parent” means OGE Energy Corp., an Oklahoma corporation.

“Participants” is defined in Section 12.2.1.

“Payment Date” means the last day of March, June, September and December and the Facility Termination Date.

“PBGC” means the Pension Benefit Guaranty Corporation, or any successor thereto.

“Person” means any natural person, corporation, firm, joint venture, partnership, limited liability company, association, enterprise, trust or other entity or organization, or any government or political subdivision or any agency, department or instrumentality thereof.

“Plan” means an employee pension benefit plan, excluding any Multiemployer Plan, which is covered by Title IV of ERISA or subject to the minimum funding standards under Section 412 of the Code as to which the Borrower or any member of the Controlled Group may have any liability.

“Pricing Schedule” means the Schedule identifying the Applicable Margin and Applicable Fee Rate attached hereto and identified as such.

“Prime Rate” means a rate per annum equal to the prime rate of interest announced from time to time by Bank One or its parent (which is not necessarily the lowest rate charged to any customer), changing when and as said prime rate changes.

“Property” of a Person means any and all property, whether real, personal, tangible, intangible, or mixed, of such Person, or other assets owned, leased or operated by such Person.

“Pro Rata Share” means, with respect to a Lender, a portion equal to a fraction the numerator of which is such Lender’s Commitment at such time (in each case, as adjusted from time to time in accordance with the provisions of this Agreement) and the denominator of which is the Aggregate Commitment at such time, or, if the Aggregate Commitment has been terminated, a fraction the numerator of which is such Lender’s Outstanding Credit Exposure at such time and the denominator of which is the sum of the aggregate outstanding amount of all Loans at such time.

“Purchasers” is defined in Section 12.3.1.

“Rate Management Obligations” of a Person means any and all obligations of such Person, whether absolute or contingent and howsoever and whensoever created, arising, evidenced or acquired (including all renewals, extensions and modifications thereof and substitutions therefor), under (i) any and all Rate Management Transactions, and (ii) any and all cancellations, buy backs, reversals, terminations or assignments of any Rate Management Transactions.

“Rate Management Transaction” means any transaction (including an agreement with respect thereto) now existing or hereafter entered by the Borrower which is a rate swap, basis swap, forward rate transaction, equity or equity index swap, equity or equity index option, bond option, interest rate option, foreign exchange transaction, cap transaction, floor transaction, collar transaction, forward transaction, currency swap transaction, cross-currency rate swap transaction, currency option or any other similar transaction (including any option with respect to any of these transactions) or any combination thereof, whether linked to one or more interest rates, foreign currencies, or equity prices.

“Receivables Purchase Documents” means any series of receivables purchase or sale agreements generally consistent with terms contained in comparable structured finance transactions pursuant to which the Borrower or any of its Subsidiaries, in their respective capacities as sellers or transferors of any consumer loan receivables, sell or transfer to SPVs all of their respective rights, title and interest in and to certain consumer loan receivables for further sale or transfer to other purchasers of or investors in such assets (and the other documents, instruments and agreements executed in connection therewith), as any such agreements may be amended, restated, supplemented or otherwise modified from time to time, or any replacement or substitution therefor.

“Receivables Purchase Facility” means any securitization facility made available to the Borrower or any of its Subsidiaries, pursuant to which consumer loan receivables of the Borrower or any of its Subsidiaries are transferred to one or more SPVs, and thereafter to certain investors, pursuant to the terms and conditions of the Receivables Purchase Documents.

“Regulation D” means Regulation D of the Board of Governors of the Federal Reserve System as from time to time in effect and any successor thereto or other regulation or official interpretation of said Board of Governors relating to reserve requirements applicable to member banks of the Federal Reserve System.

“Regulation U” means Regulation U of the Board of Governors of the Federal Reserve System as from time to time in effect and any successor or other regulation or official interpretation of said Board of Governors relating to the extension of credit by banks for the purpose of purchasing or carrying margin stocks applicable to member banks of the Federal Reserve System.

“Regulation X” means Regulation X of the Board of Governors of the Federal Reserve System as from time to time in effect and any successor or other regulation or official interpretation of said Board of Governors relating to the extension of credit by foreign lenders for the purpose of purchasing or carrying margin stock (as defined therein).

“Reportable Event” means a reportable event as defined in Section 4043 of ERISA and the regulations issued under such section, with respect to a Plan subject to Title IV of ERISA, excluding, however, such events as to which the PBGC has by regulation waived the requirement of Section 4043(a) of ERISA that it be notified within 30 days of the occurrence of such event, provided, however, that a failure to meet the minimum funding standard of Section 412 of the Code and of Section 302 of ERISA shall be a Reportable Event regardless of the issuance of any such waiver of the notice requirement in accordance with either Section 4043(a) of ERISA or Section 412(d) of the Code.

“Required Lenders” means Lenders in the aggregate having greater than fifty-five percent (55%) of the Aggregate Commitment or, if the Aggregate Commitment has been terminated, Lenders in the aggregate holding greater than fifty-five percent (55%) of the Aggregate Outstanding Credit Exposure.

“Reserve Requirement” means, with respect to an Interest Period, the maximum aggregate reserve requirement (including all basic, supplemental, marginal and other reserves) which is imposed under Regulation D on Eurocurrency liabilities.

“S&P” means Standard and Poor’s Ratings Services, a division of The McGraw Hill Companies, Inc.

“Sale and Leaseback Transaction” means any sale or other transfer of Property by any Person with the intent to lease such Property as lessee.

“Schedule” refers to a specific schedule to this Agreement, unless another document is specifically referenced.

“SEC Reports” means (i) the Annual Report on Form 10-K of the Borrower for the fiscal year ended December 31, 2002 and (ii) the Quarterly Report on Form 10-Q of the Borrower for the fiscal quarter ended March 31, 2003.

“Section” means a numbered section of this Agreement, unless another document is specifically referenced.

“Single Employer Plan” means a Plan maintained by the Borrower or any member of the Controlled Group for employees of the Borrower or any member of the Controlled Group.

“SPV” means any special purpose entity established for the purpose of purchasing consumer loan receivables in connection with a receivables securitization transaction permitted under the terms of this Agreement.

“Subsidiary” of a Person means (i) any corporation more than 50% of the outstanding securities having ordinary voting power of which shall at the time be owned or controlled, directly or indirectly, by such Person or by one or more of its Subsidiaries or by such Person and one or more of its Subsidiaries, or (ii) any partnership, limited liability company, association, joint venture or similar business organization more than 50% of the ownership interests having ordinary voting power of which shall at the time be so owned or controlled. Unless otherwise expressly provided, all references herein to a “Subsidiary” shall mean a Subsidiary of the Borrower.

“Substantial Portion” means, with respect to the Property of the Borrower and its Subsidiaries, Property which represents more than 10% of the consolidated assets of the Borrower and its Subsidiaries or property which is responsible for more than 10% of the consolidated net sales or of the consolidated net income of the Borrower and its Subsidiaries, in each case, as would be shown in the consolidated financial statements of the Borrower and its Subsidiaries as at the end of the four fiscal quarter period ending with the fiscal quarter immediately prior to the fiscal quarter in which such determination is made (or if financial statements have not been delivered hereunder for that fiscal quarter which ends the four fiscal quarter period, then the financial statements delivered hereunder for the quarter ending immediately prior to that quarter).

“Syndication Agent” means Wachovia Bank, National Association, in its capacity as Syndication Agent hereunder.

“Taxes” means any and all present or future taxes, duties, levies, imposts, deductions, charges or withholdings, and any and all liabilities with respect to the foregoing, but excluding Excluded Taxes and Other Taxes.

“Transferee” is defined in Section 12.4.

“Type” means, with respect to any Advance, its nature as a Floating Rate Advance or a Eurodollar Advance and with respect to any Loan, its nature as a Floating Rate Loan or a Eurodollar Loan.

“Unfunded Liabilities” means the amount (if any) by which the present value of all vested and unvested accrued benefits under each Single Employer Plan subject to Title IV of ERISA exceeds the fair market value of all such Plan’s assets allocable to such benefits, all determined as of the then most recent valuation date for such Plan for which a valuation report is available, using actuarial assumptions for funding purposes as set forth in such report.

“Unmatured Default” means an event which but for the lapse of time or the giving of notice, or both, would constitute a Default.

“Utilization Fee” is defined in Section 2.5.2.

“Wholly-Owned Subsidiary” of a Person means (i) any Subsidiary all of the outstanding voting securities of which shall at the time be owned or controlled, directly or indirectly, by such Person or one or more Wholly-Owned Subsidiaries of such Person, or by such Person and one or more Wholly-Owned Subsidiaries of such Person, or (ii) any partnership, limited liability company, association, joint venture or similar business organization 100% of the ownership interests having ordinary voting power of which shall at the time be so owned or controlled.

The foregoing definitions shall be equally applicable to both the singular and plural forms of the defined terms.

ARTICLE II

THE CREDITS

2.1. Commitment. From and including the date of this Agreement and prior to the Facility Termination Date, upon the satisfaction of the conditions precedent set forth in Section 4.1. and 4.2., as applicable, each Lender severally agrees, on the terms and conditions set forth in this Agreement, to make Loans to the Borrower from time to time in an amount not to exceed in the aggregate at any one time outstanding its Pro Rata Share of the Aggregate Commitment; provided that at no time shall the Aggregate Outstanding Credit Exposure hereunder exceed the Aggregate Commitment. Subject to the terms of this Agreement, the Borrower may borrow, repay and reborrow at any time prior to the Facility Termination Date. The commitment of each Lender to lend hereunder shall expire on the Facility Termination Date.

2.2. Required Payments; Termination. Any outstanding Advances and all other unpaid Obligations shall be paid in full by the Borrower on the Facility Termination Date. Notwithstanding the termination of this Agreement on the Facility Termination Date, until all of the Obligations (other than contingent indemnity obligations) shall have been fully paid and satisfied and all financing arrangements among the Borrower and the Lenders hereunder and under the other Loan Documents shall have been terminated, all of the rights and remedies under this Agreement and the other Loan Documents shall survive.

2.3. Ratable Loans. Each Advance hereunder shall consist of Loans made from the several Lenders ratably in proportion to the ratio that their respective Commitments bear to the Aggregate Commitment.

2.4. Types of Advances. The Advances may be Floating Rate Advances or Eurodollar Advances, or a combination thereof, selected by the Borrower in accordance with Sections 2.8. and 2.9.

2.5. Facility Fee; Utilization Fee; Reductions in Aggregate Commitment.

2.5.1. Facility Fee. The Borrower agrees to pay to the Agent for the account of each Lender a Facility Fee (the “Facility Fee”) at a per annum rate equal to the Applicable Fee Rate on such Lender’s Commitment (whether used or unused) from the date hereof to and including the Facility Termination Date, payable on each Payment Date hereafter and on the Facility Termination Date, provided that, if any Lender continues to have Loans outstanding hereunder after the termination of its Commitment (including, without limitation, during any period when Loans may be outstanding but new Loans may not be borrowed hereunder), then the Facility Fee shall continue to accrue on the aggregate principal amount of the Loans owed to such Lender until such Loans are repaid in full.

2.5.2. Utilization Fee. If the Aggregate Outstanding Credit Exposure of all the Lenders hereunder exceeds thirty-three and one-third percent (33^1/3%) of the Aggregate Commitment hereunder (which, after the Commitments have been terminated, shall be based on the Aggregate Commitment immediately prior to such termination) then in effect on such date, the Borrower will pay to the Agent for the ratable benefit of the Lenders a utilization fee (the “Utilization Fee”) at a per annum rate equal to the Applicable Fee Rate on the average daily Aggregate Outstanding Credit Exposure for the then current fiscal quarter (or portion thereof), payable quarterly in arrears on each Payment Date and on the date this Agreement is terminated in full and all Obligations hereunder have been paid in full pursuant to Section 2.2.

2.5.3. Reductions in Aggregate Commitment. The Borrower may permanently reduce the Aggregate Commitment in whole, or in part, ratably among the Lenders in integral multiples of $5,000,000, upon at least two Business Days’ written notice to the Agent, which notice shall specify the amount of any such reduction, provided, however, that the amount of the Aggregate Commitment may not be reduced below the aggregate principal amount of the outstanding Advances. All accrued facility fees shall be payable

on the effective date of any termination of the obligations of the Lenders to make Loans hereunder and on the final date upon which all Loans are repaid hereunder.

2.6. Minimum Amount of Each Advance. Each Eurodollar Advance shall be in the minimum amount of $5,000,000 (and in multiples of $1,000,000 if in excess thereof), and each Floating Rate Advance shall be in the minimum amount of $5,000,000 (and in multiples of $1,000,000 if in excess thereof), provided, however, that any Floating Rate Advance may be in the amount of the unused Aggregate Commitment.

2.7. Optional Principal Payments. The Borrower may from time to time pay, without penalty or premium, all outstanding Floating Rate Advances, or, in a minimum aggregate amount of $1,000,000 or any integral multiple of $1,000,000 in excess thereof, any portion of the outstanding Floating Rate Advances on any Business Day upon notice to the Agent by no later than 10:00 a.m. (Chicago time) on the date of such prepayment. The Borrower may from time to time pay, subject to the payment of any funding indemnification amounts required by Section 3.4. but without penalty or premium, all outstanding Eurodollar Advances, or, in a minimum aggregate amount of $1,000,000 or any integral multiple of $500,000 in excess thereof, any portion of the outstanding Eurodollar Advances upon three Business Days’ prior notice to the Agent.

2.8. Method of Selecting Types and Interest Periods for New Advances. The Borrower shall select the Type of Advance and, in the case of each Eurodollar Advance, the Interest Period applicable thereto from time to time. The Borrower shall give the Agent irrevocable notice (a “Borrowing Notice”) not later than 10:00 a.m. (Chicago time) on the Borrowing Date of each Floating Rate Advance and three Business Days before the Borrowing Date for each Eurodollar Advance, specifying:

2.8.1. the Borrowing Date, which shall be a Business Day, of such Advance,

2.8.2. the aggregate amount of such Advance,

2.8.3. the Type of Advance selected, and

2.8.4. in the case of each Eurodollar Advance, the Interest Period applicable thereto.

Not later than noon (Chicago time) on each Borrowing Date, each Lender shall make available its Loan or Loans in funds immediately available in Chicago to the Agent at its address specified pursuant to Article XIII. The Agent will promptly make the funds so received from the Lenders available to the Borrower at the Agent’s aforesaid address.

2.9. Conversion and Continuation of Outstanding Advances. Floating Rate Advances shall continue as Floating Rate Advances unless and until such Floating Rate Advances are converted into Eurodollar Advances pursuant to this Section 2.9. or are repaid in accordance with Section 2.7. Each Eurodollar Advance shall continue as a Eurodollar Advance until the end of the then applicable Interest Period therefor, at which time such Eurodollar Advance shall be automatically converted into a Floating Rate Advance unless (x) such Eurodollar Advance is or was repaid in accordance with Section 2.7. or (y) the Borrower shall have given the Agent a

Conversion/Continuation Notice (as defined below) requesting that, at the end of such Interest Period, such Eurodollar Advance continue as a Eurodollar Advance for the same or another Interest Period. Subject to the terms of Section 2.6., the Borrower may elect from time to time to convert all or any part of a Floating Rate Advance into a Eurodollar Advance. The Borrower shall give the Agent irrevocable notice (a “Conversion/Continuation Notice”) of each conversion of a Floating Rate Advance into a Eurodollar Advance or continuation of a Eurodollar Advance not later than 10:00 a.m. (Chicago time) on the third Business Day prior to the date of the requested conversion or continuation, specifying:

2.9.1. the requested date, which shall be a Business Day, of such conversion or continuation,

2.9.2. the aggregate amount and Type of the Advance which is to be converted or continued, and

2.9.3. the amount of such Advance which is to be converted into or continued as a Eurodollar Advance and the duration
of the Interest Period applicable thereto.

2.10. Changes in Interest Rate, etc. Each Floating Rate Advance shall bear interest on the outstanding principal amount thereof, for each day from and including the date such Advance is made or is automatically converted from a Eurodollar Advance into a Floating Rate Advance pursuant to Section 2.9., to but excluding the date it is paid or is converted into a Eurodollar Advance pursuant to Section 2.9. hereof, at a rate per annum equal to the Floating Rate for such day. Changes in the rate of interest on that portion of any Advance maintained as a Floating Rate Advance will take effect simultaneously with each change in the Alternate Base Rate. Each Eurodollar Advance shall bear interest on the outstanding principal amount thereof from and including the first day of the Interest Period applicable thereto to (but not including) the last day of such Interest Period at the interest rate determined by the Agent as applicable to such Eurodollar Advance based upon the Borrower’s selections under Sections 2.8. and 2.9. and otherwise in accordance with the terms hereof. No Interest Period may end after the Facility Termination Date.

2.11. Rates Applicable After Default. Notwithstanding anything to the contrary contained in Section 2.8., 2.9. or 2.10., during the continuance of a Default or Unmatured Default the Required Lenders may, at their option, by notice to the Borrower, declare that no Advance may be made as, converted into or continued as a Eurodollar Advance. During the continuance of a Default the Required Lenders may, at their option, by notice to the Borrower (which notice may be revoked at the option of the Required Lenders notwithstanding any provision of Section 8.2. requiring unanimous consent of the Lenders to changes in interest rates), declare that (i) each Eurodollar Advance shall bear interest for the remainder of the applicable Interest Period at the rate otherwise applicable to such Interest Period plus 2% per annum and (ii) each Floating Rate Advance shall bear interest at a rate per annum equal to the Floating Rate in effect from time to time plus 2% per annum, provided that, during the continuance of a Default under Section 7.6. or 7.7., the interest rates set forth in clauses (i) and (ii) above shall be applicable to all Advances without any election or action on the part of the Agent or any Lender.

2.12. Method of Payment. All payments of the Obligations hereunder shall be made, without setoff, deduction, or counterclaim, in immediately available funds to the Agent at the Agent’s address specified pursuant to Article XIII, or at any other Lending Installation of the Agent specified in writing by the Agent to the Borrower, by noon (local time) on the date when due and shall be applied ratably by the Agent among the Lenders. Each payment delivered to the Agent for the account of any Lender shall be delivered promptly by the Agent to such Lender in the same type of funds that the Agent received at its address specified pursuant to Article XIII or at any Lending Installation specified in a notice received by the Agent from such Lender. The Agent is hereby authorized to charge the account of the Borrower maintained with Bank One for each payment of principal, interest and fees as it becomes due hereunder.

2.13. Noteless Agreement; Evidence of Indebtedness. (i) Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness of the Borrower to such Lender resulting from each Loan made by such Lender from time to time, including the amounts of principal and interest payable and paid to such Lender from time to time hereunder.

(ii)

The Agent shall also maintain accounts in which it will record (a) the amount of each Loan made hereunder, the Type thereof and the Interest Period with respect thereto, (b) the amount of any principal or interest due and payable or to become due and payable from the Borrower to each Lender hereunder and (c) the amount of any sum received by the Agent hereunder from the Borrower and each Lender’s share thereof.

(iii)

The entries maintained in the accounts maintained pursuant to paragraphs (i) and (ii) above shall be prima facie evidence of the existence and amounts of the Obligations therein recorded; provided, however, that the failure of the Agent or any Lender to maintain such accounts or any error therein shall not in any manner affect the obligation of the Borrower to repay the Obligations in accordance with their terms.

(iv)

Any Lender may request that its Loans be evidenced by a promissory note in substantially the form of Exhibit E (a “Note”). In such event, the Borrower shall prepare, execute and deliver to such Lender such Note payable to the order of such Lender. Thereafter, the Loans evidenced by such Note and interest thereon shall at all times (prior to any assignment pursuant to Section 12.3.) be represented by one or more Notes payable to the order of the payee named therein, except to the extent that any such Lender subsequently returns any such Note for cancellation and requests that such Loans once again be evidenced as described in paragraphs (i) and (ii) above.

2.14. Telephonic Notices. The Borrower hereby authorizes the Lenders and the Agent to extend, convert or continue Advances, effect selections of Types of Advances and to transfer funds based on telephonic notices made by any person or persons the Agent or any Lender in good faith believes to be acting on behalf of the Borrower, it being understood that the foregoing authorization is specifically intended to allow Borrowing Notices and Conversion/Continuation Notices to be given telephonically. The Borrower agrees to deliver promptly to the Agent a

written confirmation, if such confirmation is requested by the Agent or any Lender, of each telephonic notice signed by an Authorized Officer. If the written confirmation differs in any material respect from the action taken by the Agent and the Lenders, the records of the Agent and the Lenders shall govern absent manifest error.

2.15. Interest Payment Dates; Interest and Fee Basis. Interest accrued on each Floating Rate Advance shall be payable in arrears on each Payment Date, commencing with the first such date to occur after the date hereof, on any date on which the Floating Rate Advance is prepaid, whether due to acceleration or otherwise, and at maturity. Interest accrued on that portion of the outstanding principal amount of any Floating Rate Advance converted into a Eurodollar Advance on a day other than a Payment Date shall be payable on the date of conversion. Interest accrued on each Eurodollar Advance shall be payable on the last day of its applicable Interest Period, on any date on which the Eurodollar Advance is prepaid, whether by acceleration or otherwise, and at maturity. Interest accrued on each Eurodollar Advance having an Interest Period longer than three months shall also be payable on the last day of each three-month interval during such Interest Period. Interest and fees shall be calculated for actual days elapsed on the basis of a 360-day year. Interest shall be payable for the day an Advance is made but not for the day of any payment on the amount paid if payment is received prior to noon (local time) at the place of payment. If any payment of principal of or interest on an Advance, any fees or any other amounts payable to the Agent or any Lender hereunder shall become due on a day which is not a Business Day, such payment shall be made on the next succeeding Business Day and, in the case of a principal payment, such extension of time shall be included in computing interest, fees and commissions in connection with such payment.

2.16. Notification of Advances, Interest Rates, Prepayments and Commitment Reductions; Availability or Loans. Promptly after receipt thereof, the Agent will notify each Lender of the contents of each Aggregate Commitment reduction notice, Borrowing Notice, Conversion/Continuation Notice, and repayment notice received by it hereunder. The Agent will notify the Borrower and each Lender of the interest rate applicable to each Eurodollar Advance promptly upon determination of such interest rate and will give the Borrower and each Lender prompt notice of each change in the Alternate Base Rate. Not later than 12:00 noon (Chicago time) on each Borrowing Date, each Lender shall make available its Loan or Loans in funds immediately available in Chicago to the Agent at its address specified pursuant to Article XIII. The Agent will promptly make the funds so received from the Lenders available to the Borrower at the Agent’s aforesaid address.

2.17. Lending Installations. Each Lender may book its Loans at any Lending Installation selected by such Lender and may change its Lending Installation from time to time. All terms of this Agreement shall apply to any such Lending Installation and the Loans and any Notes issued hereunder shall be deemed held by each Lender for the benefit of any such Lending Installation. Each Lender may, by written notice to the Agent and the Borrower in accordance with Article XIII, designate replacement or additional Lending Installations through which Loans will be made by it and for whose account Loan payments are to be made.

2.18. Non-Receipt of Funds by the Agent. Unless the Borrower or a Lender, as the case may be, notifies the Agent prior to the date on which it is scheduled to make payment to the Agent of (i) in the case of a Lender, the proceeds of a Loan or (ii) in the case of the Borrower, a

payment of principal, interest or fees to the Agent for the account of the Lenders, that it does not intend to make such payment, the Agent may assume that such payment has been made. The Agent may, but shall not be obligated to, make the amount of such payment available to the intended recipient in reliance upon such assumption. If such Lender or the Borrower, as the case may be, has not in fact made such payment to the Agent, the recipient of such payment shall, on demand by the Agent, repay to the Agent the amount so made available together with interest thereon in respect of each day during the period commencing on the date such amount was so made available by the Agent until the date the Agent recovers such amount at a rate per annum equal to (x) in the case of payment by a Lender, the Federal Funds Effective Rate for such day for the first three days and, thereafter, the interest rate applicable to the relevant Loan or (y) in the case of payment by the Borrower, the interest rate applicable to the relevant Loan.

2.19. Replacement of Lender. If the Borrower is required pursuant to Section 3.1., 3.2. or 3.5. to make any additional payment to any Lender or if any Lender’s obligation to make or continue, or to convert Floating Rate Advances into, Eurodollar Advances shall be suspended pursuant to Section 3.3. (any Lender so affected an “Affected Lender”), the Borrower may elect, if such amounts continue to be charged or such suspension is still effective, to replace such Affected Lender as a Lender party to this Agreement, provided that no Default or Unmatured Default shall have occurred and be continuing at the time of such replacement, and provided further that, concurrently with such replacement, (i) another bank or other entity which is reasonably satisfactory to the Borrower and the Agent shall agree, as of such date, to purchase for cash the Loans due to the Affected Lender pursuant to an assignment substantially in the form of Exhibit C and to become a Lender for all purposes under this Agreement and to assume all obligations of the Affected Lender to be terminated as of such date and to comply with the requirements of Section 12.3. applicable to assignments, and (ii) the Borrower shall pay to such Affected Lender in same day funds on the day of such replacement (A) all interest, fees and other amounts then accrued but unpaid to such Affected Lender by the Borrower hereunder to and including the date of termination, including without limitation payments due to such Affected Lender under Sections 3.1., 3.2. and 3.5., and (B) an amount, if any, equal to the payment which would have been due to such Lender on the day of such replacement under Section 3.4. had the Loans of such Affected Lender been prepaid on such date rather than sold to the replacement Lender, in each case to the extent not paid by the purchasing lender.

ARTICLE III

YIELD PROTECTION; TAXES

3.1. Yield Protection. If, on or after the date of this Agreement, the adoption of any law or any governmental or quasi-governmental rule, regulation, policy, guideline or directive (whether or not having the force of law), or any change in any such law, rule, regulation, policy, guideline or directive or in the interpretation or administration thereof by any governmental or quasi-governmental authority, central bank or comparable agency charged with the interpretation or administration thereof, or compliance by any Lender or applicable Lending Installation with any request or directive (whether or not having the force of law) of any such authority, central bank or comparable agency:

3.1.1. subjects any Lender or any applicable Lending Installation to any Taxes, or changes the basis of taxation of payments (other than with respect to Excluded Taxes) to any Lender in respect of its Eurodollar Loans, or

3.1.2. imposes or increases or deems applicable any reserve, assessment, insurance charge, special deposit or similar requirement against assets of, deposits with or for the account of, or credit extended by, any Lender or any applicable Lending Installation (other than reserves and assessments taken into account in determining the interest rate applicable to Eurodollar Advances), or

3.1.3. imposes any other condition the result of which is to increase the cost to any Lender or any applicable Lending Installation of making, funding or maintaining its Commitment or Eurodollar Loans or reduces any amount receivable by any Lender or any applicable Lending Installation in connection with its Commitment or Eurodollar Loans, or requires any Lender or any applicable Lending Installation to make any payment calculated by reference to the amount of Commitment or Eurodollar Loans held or interest received by it, by an amount deemed material by such Lender,

and the result of any of the foregoing is to increase the cost to such Lender or applicable Lending Installation of making or maintaining its Eurodollar Loans or Commitment or to reduce the return received by such Lender or applicable Lending Installation in connection with such Eurodollar Loans or Commitment, then, within 15 days of demand, accompanied by the written statement required by Section 3.6., by such Lender, the Borrower shall pay such Lender such additional amount or amounts as will compensate such Lender for such increased cost or reduction in amount received.

3.2. Changes in Capital Adequacy Regulations. If a Lender determines the amount of capital required or expected to be maintained by such Lender, any Lending Installation of such Lender or any corporation controlling such Lender is increased as a result of a Change, then, within 15 days of demand, accompanied by the written statement required by Section 3.6., by such Lender, the Borrower shall pay such Lender the amount necessary to compensate for any shortfall in the rate of return on the portion of such increased capital which such Lender determines is attributable to this Agreement, its Loans or its Commitment to make Loans hereunder (after taking into account such Lender’s policies as to capital adequacy). “Change” means (i) any change after the date of this Agreement in the Risk-Based Capital Guidelines or (ii) any adoption of, or change in, or change in the interpretation or administration of any other law, governmental or quasi-governmental rule, regulation, policy, guideline, interpretation, or directive (whether or not having the force of law) after the date of this Agreement which affects the amount of capital required or expected to be maintained by any Lender or any Lending Installation or any corporation controlling any Lender. “Risk-Based Capital Guidelines” means (i) the risk-based capital guidelines in effect in the United States on the date of this Agreement, including transition rules, and (ii) the corresponding capital regulations promulgated by regulatory authorities outside the United States implementing the July 1988 report of the Basle Committee on Banking Regulation and Supervisory Practices Entitled “International Convergence of Capital Measurements and Capital Standards,” including transition rules, and any amendments to such regulations adopted prior to the date of this Agreement.

3.3. Availability of Types of Advances. If any Lender determines that maintenance of its Eurodollar Loans at a suitable Lending Installation would violate any applicable law, rule, regulation, or directive, whether or not having the force of law, or if the Required Lenders determine that (i) deposits of a type and maturity appropriate to match fund Eurodollar Advances are not available or (ii) the interest rate applicable to Eurodollar Advances does not accurately reflect the cost of making or maintaining Eurodollar Advances, then the Agent shall suspend the availability of Eurodollar Advances and require any affected Eurodollar Advances to be repaid or converted to Floating Rate Advances on the respective last days of the then current Interest Periods with respect to such Loans or within such earlier period as required by law, subject to the payment of any funding indemnification amounts required by Section 3.4.

3.4. Funding Indemnification. If any payment of a Eurodollar Advance occurs on a date which is not the last day of the applicable Interest Period, whether because of acceleration, prepayment or otherwise, or a Eurodollar Advance is not made on the date specified by the Borrower for any reason other than default by the Lenders, or a Eurodollar Advance is not prepaid on the date specified by the Borrower for any reason, the Borrower will indemnify each Lender for any loss or cost incurred by it resulting therefrom, including, without limitation, any loss or cost in liquidating or employing deposits acquired to fund or maintain such Eurodollar Advance.

3.5. Taxes. (i) All payments by the Borrower to or for the account of any Lender or the Agent hereunder or under any Note shall be made free and clear of and without deduction for any and all Taxes. If the Borrower shall be required by law to deduct any Taxes from or in respect of any sum payable hereunder to any Lender or the Agent, (a) the sum payable shall be increased as necessary so that after making all required deductions (including deductions applicable to additional sums payable under this Section 3.5.) such Lender or the Agent (as the case may be) receives an amount equal to the sum it would have received had no such deductions been made, (b) the Borrower shall make such deductions, (c) the Borrower shall pay the full amount deducted to the relevant authority in accordance with applicable law and (d) the Borrower shall furnish to the Agent the original copy of a receipt evidencing payment thereof or, if a receipt cannot be obtained with reasonable efforts, such other evidence of payment as is reasonably acceptable to the Agent, in each case within 30 days after such payment is made.

(ii)

In addition, the Borrower shall pay any present or future stamp or documentary taxes and any other excise or property taxes, charges or similar levies which arise from any payment made hereunder or under any Note or from the execution or delivery of, or otherwise with respect to, this Agreement or any Note (“Other Taxes”).

(iii)

The Borrower shall indemnify the Agent and each Lender for the full amount of Taxes or Other Taxes (including, without limitation, any Taxes or Other Taxes imposed on amounts payable under this Section 3.5.) paid by the Agent or such Lender as a result of its Commitment, any Loans made by it hereunder, or otherwise in connection with its participation in this Agreement and any liability (including penalties, interest and expenses) arising therefrom or with respect thereto. Payments due under this indemnification shall be made within 30 days of the date the Agent or such Lender makes demand therefor pursuant to Section 3.6.

(iv)

Each Lender that is not incorporated under the laws of the United States of America or a state thereof (each a “Non-U.S. Lender”) agrees that it will, not more than ten Business Days after the date on which it becomes a party to this Agreement (but in any event before a payment is due to it hereunder), (i) deliver to each of the Borrower and the Agent two duly completed copies of United States Internal Revenue Service Form W-8BEN or W-8ECI, certifying in either case that such Lender is entitled to receive payments under this Agreement without deduction or withholding of any United States federal income taxes, or (ii) in the case of a Non-U.S. Lender that is fiscally transparent, deliver to the Agent a United States Internal Revenue Form W-8IMY together with the applicable accompanying forms, W-8 or W-9, as the case may be, and certify that it is entitled to an exemption from United States withholding tax. Each Non-U.S. Lender further undertakes to deliver to each of the Borrower and the Agent (x) renewals or additional copies of such form (or any successor form) on or before the date that such form expires or becomes obsolete, and (y) after the occurrence of any event requiring a change in the most recent forms so delivered by it, such additional forms or amendments thereto as may be reasonably requested by the Borrower or the Agent. All forms or amendments described in the preceding sentence shall certify that such Lender is entitled to receive payments under this Agreement without deduction or withholding of any United States federal income taxes, unless an event (including without limitation any change in treaty, law or regulation) has occurred prior to the date on which any such delivery would otherwise be required which renders all such forms inapplicable or which would prevent such Lender from duly completing and delivering any such form or amendment with respect to it and such Lender advises the Borrower and the Agent that it is not capable of receiving payments without any deduction or withholding of United States federal income tax.

(v)

For any period during which a Non-U.S. Lender has failed to provide the Borrower with an appropriate form pursuant to clause (iv) above (unless such failure is due to a change in treaty, law or regulation, or any change in the interpretation or administration thereof by any governmental authority, occurring subsequent to the date on which a form originally was required to be provided), such Non-U.S. Lender shall not be entitled to gross up or indemnification under this Section 3.5. with respect to Taxes imposed by the United States; provided that, should a Non-U.S. Lender which is otherwise exempt from or subject to a reduced rate of withholding tax become subject to Taxes because of its failure to deliver a form required under clause (iv) above, the Borrower shall take such steps as such Non-U.S. Lender shall reasonably request to assist such Non-U.S. Lender to recover such Taxes.

(vi)

Any Lender that is entitled to an exemption from or reduction of withholding tax with respect to payments under this Agreement or any Note pursuant to the law of any relevant jurisdiction or any treaty shall deliver to the Borrower (with a copy to the Agent), at the time or times prescribed by applicable law, such properly completed and executed documentation prescribed by applicable law as will permit such payments to be made without withholding or at a reduced rate.

(vii)

If the U.S. Internal Revenue Service or any other governmental authority of the United States or any other country or any political subdivision thereof asserts a claim that the Agent or the Borrower did not properly withhold tax from amounts paid to or for the account of any Lender (because the appropriate form was not delivered or properly completed, because such Lender failed to notify the Agent of a change in circumstances which rendered its exemption from withholding ineffective, or for any other reason), such Lender shall indemnify the Agent and the Borrower fully for all amounts paid, directly or indirectly, by the Agent or the Borrower, as the case may be, as tax, withholding therefor, or otherwise, including penalties and interest, and including taxes imposed by any jurisdiction on amounts payable to the Agent or the Borrower, as the case may be, under this subsection, together with all costs and expenses related thereto (including attorneys fees and time charges of attorneys for the Agent or the Borrower, as the case may be, which attorneys may be employees of the Agent or the Borrower, as the case may be). The obligations of the Lenders under this Section 3.5. (vii) shall survive the payment of the Obligations and termination of this Agreement.

3.6. Lender Statements; Survival of Indemnity. Each Lender shall deliver a written statement of such Lender to the Borrower (with a copy to the Agent) as to the amount due, if any, under Section 3.1., 3.2., 3.4. or 3.5. Such written statement shall set forth in reasonable detail the calculations upon which such Lender determined such amount and shall be final, conclusive and binding on the Borrower in the absence of manifest error. Determination of amounts payable under such Sections in connection with a Eurodollar Loan shall be calculated as though each Lender funded its Eurodollar Loan through the purchase of a deposit of the type and maturity corresponding to the deposit used as a reference in determining the Eurodollar Rate applicable to such Loan, whether in fact that is the case or not. Unless otherwise provided herein, the amount specified in the written statement of any Lender shall be payable on demand after receipt by the Borrower of such written statement. The obligations of the Borrower under Sections 3.1., 3.2., 3.4. and 3.5. shall survive payment of the Obligations and termination of this Agreement.

3.7. Alternative Lending Installation. To the extent reasonably possible, each Lender shall designate an alternate Lending Installation with respect to its Eurodollar Loans to reduce any liability of the Borrower to such Lender under Sections 3.1., 3.2. and 3.5. or to avoid the unavailability of Eurodollar Advances under Section 3.3., so long as such designation is not, in the judgment of such Lender, reasonably disadvantageous to such Lender. A Lender’s designation of an alternative Lending Installation shall not affect the Borrower’s rights under Section 2.19. to replace a Lender.

ARTICLE IV

CONDITIONS PRECEDENT

4.1. Initial Advance. The Lenders shall not be required to make the initial Advance hereunder unless the following conditions precedent have been satisfied and the Borrower has furnished to the Agent with sufficient copies for the Lenders:

4.1.1 Copies of the articles or certificate of incorporation of the Borrower, together with all amendments, and a certificate of good standing, each certified by the appropriate governmental officer in its jurisdiction of incorporation.

4.1.2 Copies, certified by the Secretary or Assistant Secretary of the Borrower, of its by-laws and of its Board of Directors’ resolutions and of resolutions or actions of any other body authorizing the execution of the Loan Documents to which the Borrower is a party.

4.1.3 An incumbency certificate, executed by the Secretary or Assistant Secretary of the Borrower, which shall identify by name and title and bear the signatures of the Authorized Officers and any other officers of the Borrower authorized to sign the Loan Documents to which the Borrower is a party, upon which certificate the Agent and the Lenders shall be entitled to rely until informed of any change in writing by the Borrower.

4.1.4 A certificate, signed by the chief financial officer of the Borrower, stating that on the Closing Date no Default or Unmatured Default has occurred and is continuing.

4.1.5 A written opinion of the Borrower’s counsels, in form and substance satisfactory to the Agent and addressed to the Lenders, in substantially the form of Exhibit A.

4.1.6 Any Notes requested by a Lender pursuant to Section 2.13 payable to the order of each such requesting Lender.

4.1.7 Written money transfer instructions, in substantially the form of Exhibit D, addressed to the Agent and signed by an Authorized Officer, together with such other related money transfer authorizations as the Agent may have reasonably requested.

4.1.8 The Agent shall have determined that there is an absence of any material adverse change or disruption in primary or secondary loan syndication markets, financial markets or in capital markets generally that would likely impair syndication of the Loans hereunder.

4.1.9 Evidence satisfactory to the Agent that the Existing Credit Agreement has been, or shall simultaneously on the Closing Date be, terminated (except for those provisions that expressly survive the termination thereof) and all loans outstanding and other amounts owed to the lenders or agents thereunder shall have been, or simultaneously with the initial Advance hereunder will be, paid in full.

4.1.10 Such other documents as any Lender or its counsel may have reasonably requested.

4.2. Each Advance. The Lenders shall not be required to make any Advance (including the initial Advance hereunder) unless on the applicable Borrowing Date:

4.2.1 There exists no Default or Unmatured Default.

4.2.2 The representations and warranties contained in Article V are true and correct as of such Borrowing Date except to the extent any such representation or warranty is stated to relate solely to an earlier date, in which case such representation or warranty shall have been true and correct on and as of such earlier date.

4.2.3 The aggregate amount of short-term debt of the Borrower, after taking into account the requested Advances, will not exceed the maximum amount of short-term debt permitted under all rules, regulations and orders of FERC applicable to the Borrower and its Subsidiaries.

4.2.4 All legal matters incident to the making of such Advance shall be satisfactory to the Lenders and their counsel.

Each Borrowing Notice with respect to each such Advance shall constitute a representation and warranty by the Borrower that the conditions contained in Sections 4.2.1, 4.2.2 and 4.2.3 have been satisfied. Any Lender may require a duly completed compliance certificate in substantially the form of Exhibit B as a condition to making an Advance.

ARTICLE V

REPRESENTATIONS AND WARRANTIES

The Borrower represents and warrants to the Lenders that:

5.1. Existence and Standing. Each of the Borrower and its Subsidiaries is a corporation, partnership (in the case of Subsidiaries only) or limited liability company duly and properly incorporated or organized, as the case may be, validly existing and (to the extent such concept applies to such entity) in good standing under the laws of its jurisdiction of incorporation or organization and has all requisite authority to conduct its business in each jurisdiction in which its business is conducted, except where the failure to be in good standing could not reasonably be expected to have a Material Adverse Effect.

5.2. Authorization and Validity. The Borrower has the power and authority and legal right to execute and deliver the Loan Documents and to perform its obligations thereunder. The execution and delivery by the Borrower of the Loan Documents and the performance of its obligations thereunder have been duly authorized by proper corporate proceedings, and the Loan Documents to which the Borrower is a party constitute legal, valid and binding obligations of the Borrower enforceable against the Borrower in accordance with their terms, except as enforceability may be limited by bankruptcy, insolvency or similar laws affecting the enforcement of creditors’ rights generally.

5.3. No Conflict; Government Consent. Neither the execution and delivery by the Borrower of the Loan Documents, nor the consummation of the transactions therein contemplated, nor compliance with the provisions thereof will violate (i) any law, rule, regulation, order, writ, judgment, injunction, decree or award binding on the Borrower or any of its Subsidiaries or (ii) the Borrower’s or any Subsidiary’s articles or certificate of incorporation, partnership agreement, certificate of partnership, articles or certificate of organization, by-laws, or operating or other management agreement, as the case may be, or (iii) the provisions of any

indenture, instrument or agreement to which the Borrower or any of its Subsidiaries is a party or is subject, or by which it, or its Property, is bound, or conflict with or constitute a default thereunder, or result in, or require, the creation or imposition of any Lien in, of or on the Property of the Borrower or a Subsidiary pursuant to the terms of any such indenture, instrument or agreement, except for any such violations which, individually and in the aggregate, could not reasonably be expected to have a Material Adverse Effect. Except as described in the next succeeding sentences, no order, consent, adjudication, approval, license, authorization, or validation of, or filing, recording or registration with, or exemption by, or other action in respect of any governmental or public body or authority, or any subdivision thereof, which has not been obtained by the Borrower or any of its Subsidiaries, is required to be obtained by the Borrower or any of its Subsidiaries in connection with the execution and delivery of the Loan Documents, the borrowings under this Agreement, the payment and performance by the Borrower of the Obligations or the legality, validity, binding effect or enforceability of any of the Loan Documents. FERC has issued its order authorizing the incurrence by the Borrower of short-term debt in the aggregate principal amount not exceeding $400,000,000 outstanding at any one time, subject to the condition that, among other things, all such short-term debt shall be incurred on or before December 31, 2004 and shall mature no later than December 31, 2005. Additional authorization of FERC will be necessary in order for the Borrower to obtain any Advances under this Agreement after December 31, 2004 or to have outstanding more than $400,000,000 in principal amount of short-term debt (including Loans under this Agreement).

5.4. Financial Statements. The December 31, 2002 consolidated financial statements of the Borrower and its Subsidiaries heretofore delivered to the Lenders were prepared in accordance with generally accepted accounting principles in effect on the date such statements were prepared and fairly present the consolidated financial condition and operations of the Borrower and its Subsidiaries at such date and the consolidated results of their operations for the period then ended.

5.5. Material Adverse Change. Since December 31, 2002, except as disclosed in the SEC Reports, there has been no change in the business, Property, condition (financial or otherwise) or results of operations of the Borrower and its Subsidiaries which could reasonably be expected to have a Material Adverse Effect.

5.6. Taxes. The Borrower and its Subsidiaries have filed all United States federal tax returns and all other tax returns which are required to be filed and have paid all taxes due pursuant to said returns or pursuant to any assessment received by the Borrower or any of its Subsidiaries, except in respect of such taxes, if any, which are not in the aggregate material or as are being contested in good faith and as to which adequate reserves have been provided in accordance with GAAP and as to which no Lien exists (except as permitted by Section 6.12.1). The United States income tax returns of the Borrower and its Subsidiaries have been audited by the Internal Revenue Service through the fiscal year ended December 31, 1998. The charges, accruals and reserves on the books of the Borrower and its Subsidiaries in respect of any taxes or other governmental charges are adequate.

5.7. Litigation and Contingent Obligations. Except as disclosed in the SEC Reports, there is no litigation, arbitration, governmental investigation, proceeding or inquiry pending or, to the knowledge of any of their officers, threatened against or affecting the Borrower or any of

its Subsidiaries which could reasonably be expected to have a Material Adverse Effect or which seeks to prevent, enjoin or delay the making of any Loans. Except as disclosed in the SEC Reports, other than any liability incident to any litigation, arbitration or proceeding which could not reasonably be expected to have a Material Adverse Effect, the Borrower has no material contingent obligations not provided for or disclosed in the financial statements referred to in Section 5.4.

5.8. Subsidiaries. Schedule 1 contains an accurate list of all Subsidiaries of the Borrower as of the date of this Agreement, setting forth their respective jurisdictions of organization and the percentage of their respective capital stock or other ownership interests owned by the Borrower or other Subsidiaries. All of the issued and outstanding shares of capital stock or other ownership interests of such Subsidiaries have been (to the extent such concepts are relevant with respect to such ownership interests) duly authorized and issued and are fully paid and non-assessable.

5.9. ERISA. The Unfunded Liabilities of all Single Employer Plans could not in the aggregate reasonably be expected to have a Material Adverse Effect. Neither the Borrower nor any other member of the Controlled Group has incurred, or is reasonably expected to incur, pursuant to Section 4201 of ERISA, any withdrawal liability to Multiemployer Plans in excess of $20,000,000 in the aggregate that has not been satisfied. Each Plan complies in all material respects with all applicable requirements of law and regulations, except for noncompliance that, in the aggregate, would not have a Material Adverse Effect. No Reportable Event has occurred with respect to any Plan, other than those that, in aggregate, would not have a Material Adverse Effect. Neither the Borrower nor any other member of the Controlled Group has withdrawn from any Multiemployer Plan within the meaning of Title IV of ERISA or initiated steps to do so, and, to the knowledge of the Borrower, no steps have been taken to reorganize or terminate, within the meaning of Title IV of ERISA, any Multiemployer Plan.

5.10. Accuracy of Information. The information, exhibits or reports furnished by the Borrower to the Agent or to any Lender in connection with the negotiation of, or compliance with, the Loan Documents, taken as a whole, do not contain any material misstatement of fact or omit to state a material fact or any fact necessary to make the statements contained therein not misleading.

5.11. Regulation U. Neither the Borrower nor any of its Subsidiaries is engaged principally, or as one of its important activities, in the business of extending credit for the purpose, whether immediate, incidental or ultimate of buying or carrying margin stock (as defined in Regulation U), and after applying the proceeds of each Advance, margin stock (as so defined) constitutes less than 25% of the value of those assets of the Borrower and its Subsidiaries which are subject to any limitation on sale, pledge, or other restriction hereunder.

5.12. Material Agreements. Neither the Borrower nor any Subsidiary is a party to any agreement or instrument or subject to any charter or other corporate restriction which could reasonably be expected to have a Material Adverse Effect. Neither the Borrower nor any Subsidiary is in default in the performance, observance or fulfillment of any of the obligations, covenants or conditions contained in (i) any agreement to which it is a party, which default could

reasonably be expected to have a Material Adverse Effect or (ii) any Material Indebtedness Agreement.

5.13. Compliance With Laws. The Borrower and its Subsidiaries have complied with all applicable statutes, rules, regulations, orders and restrictions of any domestic or foreign government or any instrumentality or agency thereof having jurisdiction over the conduct of their respective businesses or the ownership of their respective Property except for any failure to comply with any of the foregoing which could not reasonably be expected to have a Material Adverse Effect.

5.14. Ownership of Properties. Except (i) for assets disposed of in the ordinary course of business since March 31, 2003, (ii) as described in SEC Reports and (iii) as set forth on Schedule 2, on the date of this Agreement, the Borrower and its Subsidiaries have good title, free of all Liens other than those permitted by Section 6.12, to all of the assets reflected in the Borrower’s consolidated balance sheet as of March 31, 2003, as owned by the Borrower and its Subsidiaries.

5.15. Plan Assets; Prohibited Transactions. The Borrower is not an entity deemed to hold “plan assets” within the meaning of 29 C.F.R. § 2510.3-101 of an employee benefit plan (as defined in Section 3(3) of ERISA) which is subject to Title I of ERISA or any plan (within the meaning of Section 4975 of the Code), and assuming the accuracy of the representations and warranties made in Section 9.12 and in any assignment made pursuant to Section 12.3.3, neither the execution of this Agreement nor the making of Loans hereunder gives rise to a prohibited transaction within the meaning of Section 406 of ERISA or Section 4975 of the Code.

5.16. Environmental Matters. In the ordinary course of its business, the officers of the Borrower consider the effect of Environmental Laws on the business of the Borrower and its Subsidiaries, in the course of which they identify and evaluate potential risks and liabilities accruing to the Borrower due to Environmental Laws. On the basis of this consideration, the Borrower has concluded that, except as disclosed in the SEC Reports, Environmental Laws cannot reasonably be expected to have a Material Adverse Effect. Except as disclosed in the SEC Reports, neither the Borrower nor any Subsidiary has received any notice to the effect that its operations are not in material compliance with any of the requirements of applicable Environmental Laws or are the subject of any federal or state investigation evaluating whether any remedial action is needed to respond to a release of any toxic or hazardous waste or substance into the environment, which non-compliance or remedial action could reasonably be expected to have a Material Adverse Effect.

5.17. Investment Company Act. Neither the Borrower nor any Subsidiary is an “investment company” or a company “controlled” by an “investment company”, within the meaning of the Investment Company Act of 1940, as amended.

5.18. Public Utility Holding Company Act. The Borrower is a “public utility company” and a “subsidiary company” of the Parent, which is a “holding company”, as such terms are defined in the Public Utility Holding Company Act of 1935, as amended (the “1935 Act”), and such “holding company” and the Borrower are currently exempt from the provisions of the 1935 Act (except Section 9 thereof).

5.19. Insurance. The Borrower maintains, and has caused each Subsidiary to maintain, with financially sound and reputable insurance companies insurance on all their Property in such amounts, subject to such deductibles and self-insurance retentions and covering such risks as is consistent with sound business practice of similarly situated companies.

5.20. No Default or Unmatured Default. No Default or Unmatured Default has occurred and is continuing.

5.21. Reportable Transaction. The Borrower does not intend to treat the Advances and related transactions as being a “reportable transaction” (within the meaning of Treasury Regulation Section 1.6011-4). In the event the Borrower determines to take any action inconsistent with such intention, it will promptly notify the Agent thereof.

ARTICLE VI

COVENANTS

During the term of this Agreement, unless the Required Lenders shall otherwise consent in writing:

6.1. Financial Reporting. The Borrower will maintain, for itself and each Subsidiary, a system of accounting established and administered in accordance with generally accepted accounting principles, and furnish to the Lenders:

6.1.1 Within 90 days after the close of each of its fiscal years, financial statements prepared in accordance with GAAP on a consolidated and consolidating basis for itself and its Subsidiaries, including balance sheets as of the end of such period, statements of income and statements of cash flows, accompanied by (a) an audit report, unqualified as to scope, of a nationally recognized firm of independent public accountants or other independent public accountants reasonably acceptable to the Required Lenders; (b) any management letter prepared by said accountants, and (c) a certificate of said accountants that, in the course of their examination necessary for their certification of the foregoing, they have obtained no knowledge of any Default or Unmatured Default, or if, in the opinion of such accountants, any Default or Unmatured Default shall exist, stating the nature and status thereof.

6.1.2 Within 45 days after the close of the first three quarterly periods of each of its fiscal years, for itself and its Subsidiaries, consolidated and consolidating unaudited balance sheets as at the close of each such period and consolidated and consolidating statements of income and a statement of cash flows for the period from the beginning of such fiscal year to the end of such quarter, all certified by its chief financial officer or treasurer.

6.1.3 Together with the financial statements required under Sections 6.1(i) and (ii), a compliance certificate in substantially the form of Exhibit B signed by its chief financial officer or treasurer showing the calculations necessary to determine compliance with this Agreement and stating that no Default or Unmatured Default exists, or if any Default or Unmatured Default exists, stating the nature and status thereof.

6.1.4 Within 270 days after the close of each fiscal year of the Borrower, a copy of the actuarial report showing the Unfunded Liabilities of each Single Employer Plan as of the valuation date occurring in such fiscal year, certified by an actuary enrolled under ERISA.

6.1.5 As soon as possible and in any event within 10 days after the Borrower knows that any Reportable Event has occurred with respect to any Plan that could reasonably be expected to have a Material Adverse Effect, a statement, signed by the chief financial officer of the Borrower, describing said Reportable Event and the action which the Borrower proposes to take with respect thereto.

6.1.6 As soon as possible and in any event within 10 days after receipt by the Borrower, a copy of (a) any notice or claim to the effect that the Borrower or any of its Subsidiaries is or may be liable to any Person as a result of the release by the Borrower, any of its Subsidiaries, or any other Person of any toxic or hazardous waste or substance into the environment, and (b) any notice alleging any violation of any federal, state or local environmental, health or safety law or regulation by the Borrower or any of its Subsidiaries, which, in either case, could reasonably be expected to have a Material Adverse Effect.

6.1.7 Promptly upon the filing thereof, copies of all registration statements and annual, quarterly, monthly or other regular reports which the Borrower or any of its Subsidiaries files with the Securities and Exchange Commission.

6.1.8 Such other information (including non-financial information) as the Agent or any Lender may from time to time reasonably request.

6.2. Use of Proceeds. The Borrower will, and will cause each Subsidiary to, use the proceeds of the Advances for general corporate purposes, including without limitation commercial paper liquidity support. The Borrower shall use the proceeds of the Advances in compliance with all applicable legal and regulatory requirements and any such use shall not result in a violation of any such requirements, including, without limitation, Regulation U and X, the Securities Act of 1933, as amended, and the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder.

6.3. Notice of Default. The Borrower will, and will cause each Subsidiary to, give prompt notice in writing to the Lenders of the occurrence of any Default or Unmatured Default and of any other development, financial or otherwise, which could reasonably be expected to have a Material Adverse Effect.

6.4. Conduct of Business. The Borrower will, and will cause each Subsidiary to, be primarily engaged in energy-related businesses and/or other businesses as are ancillary thereto.

6.5. Taxes. The Borrower will, and will cause each Subsidiary to, timely file complete and correct United States federal and applicable foreign, state and local tax returns required by law and pay when due all taxes, assessments and governmental charges and levies upon it or its income, profits or Property, except those which are not in the aggregate material or which are

being contested in good faith by appropriate proceedings and with respect to which adequate reserves have been set aside in accordance with GAAP.

6.6. Insurance. The Borrower will, and will cause each Subsidiary to, maintain with financially sound and reputable insurance companies insurance on all their Property in such amounts, subject to such deductibles and self-insurance retentions, and covering such risks as is consistent with sound business practice, and the Borrower will furnish to any Lender upon request full information as to the insurance carried.

6.7. Compliance with Laws. The Borrower will, and will cause each Subsidiary to, comply with all laws, rules, regulations, orders, writs, judgments, injunctions, decrees or awards to which it may be subject including, without limitation, all Environmental Laws, except where failure to so comply could not reasonably be expected to result in a Material Adverse Effect.

6.8. Maintenance of Properties. Subject to Section 6.11., the Borrower will, and will cause each Subsidiary to, do all things necessary to maintain, preserve, protect and keep its Property used in the operation of its business in good repair, working order and condition, and make all necessary and proper repairs, renewals and replacements so that its business carried on in connection therewith may be properly conducted at all times.

6.9. Inspection; Keeping of Books and Records. The Borrower will, and will cause each Subsidiary to, permit the Agent and the Lenders, by their respective representatives and agents, to inspect any of the Property, books and financial records of the Borrower and each Subsidiary, to examine and make copies of the books of accounts and other financial records of the Borrower and each Subsidiary, and to discuss the affairs, finances and accounts of the Borrower and each Subsidiary with, and to be advised as to the same by, their respective officers at such reasonable times and intervals as the Agent or any Lender may designate. The Borrower shall keep and maintain, and cause each of its Subsidiaries to keep and maintain, in all material respects, proper books of record and account in which entries in conformity with GAAP shall be made of all dealings and transactions in relation to their respective businesses and activities. If a Default has occurred and is continuing, the Borrower, upon the Agent’s request, shall turn over copies of any such records to the Agent or its representatives.

6.10. Merger. The Borrower will not, nor will it permit any Subsidiary to, merge or consolidate with or into any other Person, except that a Subsidiary may merge into the Borrower or a Wholly-Owned Subsidiary.

6.11. Sale of Assets. The Borrower will not, nor will it permit any Subsidiary to, lease, sell or otherwise dispose of its Property to any other Person, except:

6.11.1 Sales of inventory in the ordinary course of business.

6.11.2 A disposition of assets by a Subsidiary to the Borrower or another Subsidiary or by the Borrower to a Subsidiary.

6.11.3 A disposition of obsolete property, property no longer used in business or other assets in the ordinary course of business of the Borrower or any Subsidiary.

6.11.4 A disposition of assets for an aggregate purchase price of up to $50,000,000 pursuant to, and in accordance with, Receivables Purchase Facilities.

6.11.5 Leases, sales or other dispositions of its Property that, together with all other Property of the Borrower and its Subsidiaries previously leased, sold or disposed of (other than dispositions otherwise permitted by this Section 6.11) as permitted by this Section during the twelve-month period ending with the month in which any such lease, sale or other disposition occurs, do not constitute a Substantial Portion of the Property of the Borrower and its Subsidiaries.

6.12. Liens. The Borrower will not, nor will it permit any Subsidiary to, create, incur, or suffer to exist any Lien in, of or on the Property of the Borrower or any of its Subsidiaries, except:

6.12.1 Liens for taxes, assessments or governmental charges or levies on its Property if the same shall not at the time be delinquent or thereafter can be paid without penalty, or are being contested in good faith and by appropriate proceedings and for which adequate reserves in accordance with GAAP shall have been set aside on its books.

6.12.2 Liens imposed by law, such as carriers’, warehousemen’s and mechanics’ liens and other similar liens arising in the ordinary course of business which secure payment of obligations not more than 60 days past due or which are being contested in good faith by appropriate proceedings and for which adequate reserves in accordance with GAAP shall have been set aside on its books.

6.12.3 Liens arising out of pledges or deposits under worker’s compensation laws, unemployment insurance, old age pensions, or other social security or retirement benefits, or similar legislation.

6.12.4 Liens existing on the date hereof and described in Schedule 3.

6.12.5 Deposits securing liability to insurance carriers under insurance or self-insurance arrangements.

6.12.6 Deposits to secure the performance of bids, trade contracts (other than for borrowed money), leases, statutory obligations, surety and appeal bonds, performance bonds and other obligations of a like nature incurred in the ordinary course of business.

6.12.7 Easements, reservations, rights-of-way, restrictions, survey exceptions and other similar encumbrances as to real property of the Borrower and its Subsidiaries which customarily exist on properties of corporations engaged in similar activities and similarly situated and which do not materially interfere with the conduct of the business of the Borrower or such Subsidiary conducted at the property subject thereto.

6.12.8 Liens existing on property or assets at the time of acquisition thereof by the Borrower or a Subsidiary, provided that (i) such Liens existed at the time of such acquisition and were not created in anticipation thereof, and (ii) any such Lien does not

encumber any other property or assets (other than additions thereto and property in replacement or substitution thereof).

6.12.9 Liens existing on property or assets of a Person which becomes a Subsidiary of the Borrower; provided that (i) such Liens existed at the time such Person became a Subsidiary and were not created in anticipation thereof, and (ii) any such Lien does not encumber any other property or assets (other than additions thereto and property in replacement or substitution thereof).

6.12.10 Liens arising by reason of any judgment, decree or order of any court or other governmental authority, if appropriate legal proceedings are being diligently prosecuted and shall not have been finally terminated or the period within which such proceedings may be initiated shall not have expired, in an aggregate amount not to exceed $20,000,000 at any time outstanding.

6.12.11 Leases and subleases of real property owned or leased by the Borrower or any Subsidiary not interfering with the ordinary conduct of the business of the Borrower and the Subsidiaries.

6.12.12 Liens securing Indebtedness (including Capitalized Lease Obligations) of the Borrower and its Subsidiaries incurred to finance the acquisition, repair, construction, development or improvement of fixed or capital assets; provided that (i) such Liens shall be created substantially simultaneously with or within 18 months of the acquisition or completion of repair, construction, development or improvement of such fixed or capital assets and (ii) such Liens do not encumber any property other than the property financed by such Indebtedness (other than additions thereto and property in replacement or substitution thereof).

6.12.13 Liens in favor of the United States of America or any state thereof, or any department, agency or instrumentality or political subdivision of the United States of America or any state thereof, or for the benefit of holders of securities issued by any such entity, to secure any Indebtedness incurred for the purpose of financing all or any part of the purchase price of the cost of the repair, construction, development or improvement of any fixed or capital assets; provided that such Liens do not encumber any property other than the property financed by such Indebtedness (other than additions thereto and property in replacement or substitution thereof).

6.12.14 Liens securing Indebtedness of the Borrower to a Subsidiary or of a Subsidiary to the Borrower or another Subsidiary.

6.12.15 Liens arising in connection with a Receivables Purchase Facility.

6.12.16 Renewals, extensions and replacements of the Liens permitted under Sections 6.12.4, 6.12.8, 6.12.9, 6.12.12 and 6.12.13 above; provided that no such Lien shall as a result thereof cover any additional assets (other than additions thereto and property in replacement or substitution thereof).

6.12.17 Liens not described in Sections 6.12.1 through 6.12.16, inclusive, securing Indebtedness of the Borrower (other than Indebtedness of the Borrower owed to any Subsidiary) and/or securing Indebtedness of the Borrower’s Subsidiaries (other than Indebtedness of any Subsidiary owed to the Borrower or any other Subsidiary), in an aggregate outstanding amount not to exceed ten percent (10%) of the consolidated assets of the Borrower and its Subsidiaries at the time of such incurrence.

6.13. Affiliates. The Borrower will not, and will not permit any Subsidiary to, enter into any transaction (including, without limitation, the purchase or sale of any Property or service) with, or make any payment or transfer to, any Affiliate (other than the Borrower and its Subsidiaries) except in the ordinary course of business and pursuant to the reasonable requirements of the Borrower’s or such Subsidiary’s business and upon fair and reasonable terms no less favorable to the Borrower or such Subsidiary than the Borrower or such Subsidiary would obtain in a comparable arms-length transaction.

6.14. Financial Contracts. The Borrower will not, nor will it permit any Subsidiary to, enter into or remain liable upon any Rate Management Transactions except for those entered into in the ordinary course of business for bona fide hedging purposes and not for speculative purposes.

6.15. Leverage Ratio. The Borrower will not permit the ratio, determined as of the end of each of its fiscal quarters, of (i) Consolidated Indebtedness to (ii) Consolidated Total Capitalization to be greater than 0.65 to 1.0.

ARTICLE VII

DEFAULTS

The occurrence of any one or more of the following events shall constitute a Default:

7.1. Any representation or warranty made or deemed made by or on behalf of the Borrower or any of its Subsidiaries to the Lenders or the Agent under or in connection with this Agreement, any Loan, or any certificate or information delivered in connection with this Agreement or any other Loan Document shall be materially false on the date as of which made.

7.2. Nonpayment of principal of any Loan when due, or nonpayment of interest upon any Loan or of any fee or other obligations under any of the Loan Documents within five days after the same becomes due.

7.3. The breach by the Borrower of any of the terms or provisions of Section 6.2., 6.10., 6.11., 6.12., 6.13., 6.14. or 6.15.

7.4. The breach by the Borrower (other than a breach which constitutes a Default under another Section of this Article VII) of any of the terms or provisions of this Agreement which is not remedied within five days after written notice from the Agent or any Lender.

7.5. Failure of the Borrower or any of its Subsidiaries to pay when due any Material Indebtedness; or the default by the Borrower or any of its Subsidiaries in the performance

(beyond the applicable grace period with respect thereto, if any) of any term, provision or condition contained in any Material Indebtedness Agreement, or any other event shall occur or condition exist, the effect of which default, event or condition is to cause, or to permit the holder(s) of such Material Indebtedness or the lender(s) under any Material Indebtedness Agreement to cause, such Material Indebtedness to become due prior to its stated maturity or any commitment to lend under any Material Indebtedness Agreement to be terminated prior to its stated expiration date; or any Material Indebtedness of the Borrower or any of its Subsidiaries shall be declared to be due and payable or required to be prepaid or repurchased (other than by a regularly scheduled payment) prior to the stated maturity thereof; or the Borrower or any of its Subsidiaries shall not pay, or admit in writing its inability to pay, its debts generally as they become due.

7.6. The Borrower or any of its Material Subsidiaries shall (i) have an order for relief entered with respect to it under the Federal bankruptcy laws as now or hereafter in effect, (ii) make an assignment for the benefit of creditors, (iii) apply for, seek, consent to, or acquiesce in, the appointment of a receiver, custodian, trustee, examiner, liquidator or similar official for it or any Substantial Portion of its Property, (iv) institute any proceeding seeking an order for relief under the Federal bankruptcy laws as now or hereafter in effect or seeking to adjudicate it a bankrupt or insolvent, or seeking dissolution, winding up, liquidation, reorganization, arrangement, adjustment or composition of it or its debts under any law relating to bankruptcy, insolvency or reorganization or relief of debtors or fail to file an answer or other pleading denying the material allegations of any such proceeding filed against it, (v) take any corporate or partnership action to authorize or effect any of the foregoing actions set forth in this Section 7.6. or (vi) fail to contest in good faith any appointment or proceeding described in Section 7.7.

7.7. Without the application, approval or consent of the Borrower or any of its Material Subsidiaries, a receiver, trustee, examiner, liquidator or similar official shall be appointed for the Borrower or any of its Material Subsidiaries or any Substantial Portion of its Property, or a proceeding described in Section 7.6. (iv) shall be instituted against the Borrower or any of its Material Subsidiaries and such appointment continues undischarged or such proceeding continues undismissed or unstayed for a period of 60 consecutive days.

7.8. Any court, government or governmental agency shall condemn, seize or otherwise appropriate, or take custody or control of, all or any portion of the Property of the Borrower and its Subsidiaries which, when taken together with all other Property of the Borrower and its Subsidiaries so condemned, seized, appropriated, or taken custody or control of, during the twelve-month period ending with the month in which any such action occurs, constitutes a Substantial Portion.

7.9. The Borrower or any of its Subsidiaries shall fail within 45 days to pay, bond or otherwise discharge one or more (i) judgments or orders for the payment of money in excess of $20,000,000 (or the equivalent thereof in currencies other than U.S. Dollars) in the aggregate, or (ii) nonmonetary judgments or orders which, individually or in the aggregate, could reasonably be expected to have a Material Adverse Effect, which judgment(s), in any such case, is/are not stayed on appeal or otherwise being appropriately contested in good faith and with respect to which adequate reserves have been set aside on its books in accordance with GAAP.

7.10. The Unfunded Liabilities of all Single Employer Plans could in the aggregate reasonably be expected to result in a Material Adverse Effect or any Reportable Event shall occur in connection with any Plan that could reasonably be expected to have a Material Adverse Effect.

7.11. Nonpayment by the Borrower or any Subsidiary of any Rate Management Obligation, in an outstanding principal amount of $20,000,000 or more, when due or the breach (beyond the applicable grace period with respect thereto, if any) by the Borrower or any Subsidiary of any term, provision or condition contained in any Rate Management Transaction, whether or not any Lender or Affiliate of a Lender is a party thereto.

7.12. Any Change in Control shall occur.

7.13. The Borrower or any other member of the Controlled Group shall have been notified by the sponsor of a Multiemployer Plan that it has incurred, pursuant to Section 4201 of ERISA, withdrawal liability to such Multiemployer Plan in an amount which, when aggregated with all other amounts required to be paid to Multiemployer Plans by the Borrower or any other member of the Controlled Group as withdrawal liability (determined as of the date of such notification), exceeds $20,000,000 or requires payments exceeding $5,000,000 per annum.

7.14. The Borrower or any other member of the Controlled Group shall have been notified by the sponsor of a Multiemployer Plan that such Multiemployer Plan is in reorganization or is being terminated, within the meaning of Title IV of ERISA, if as a result of such reorganization or termination the aggregate annual contributions of the Borrower and the other members of the Controlled Group (taken as a whole) to all Multiemployer Plans which are then in reorganization or being terminated have been or will be increased, in the aggregate, over the amounts contributed to such Multiemployer Plans for the respective plan years of such Multiemployer Plans immediately preceding the plan year in which the reorganization or termination occurs by an amount exceeding $20,000,000.

7.15. The Borrower or any of its Subsidiaries shall (i) be the subject of any proceeding or investigation pertaining to the release by the Borrower, any of its Subsidiaries or any other Person of any toxic or hazardous waste or substance into the environment, or (ii) violate any Environmental Law, which, in the case of an event described in clause (i) or clause (ii), has resulted in a judgment or order of liability against the Borrower or any of its Subsidiaries in an amount in excess of $20,000,000, which liability is not paid, bonded or otherwise discharged within 45 days or which is not stayed on appeal and being appropriately contested in good faith.

7.16. Any Loan Document shall fail to remain in full force or effect or any action shall be taken by the Borrower, the Parent or any subsidiary of the Parent to discontinue or to assert the invalidity or unenforceability of any Loan Document.

ARTICLE VIII

ACCELERATION, WAIVERS, AMENDMENTS AND REMEDIES

8.1. Acceleration. If any Default described in Section 7.6. or 7.7. occurs with respect to the Borrower, the obligations of the Lenders to make Loans hereunder shall automatically

terminate and the Obligations shall immediately become due and payable without any election or action on the part of the Agent or any Lender. If any other Default occurs, the Required Lenders (or the Agent with the consent of the Required Lenders) may terminate or suspend the obligations of the Lenders to make Loans hereunder, or declare the Obligations to be due and payable, or both, whereupon the Obligations shall become immediately due and payable, without presentment, demand, protest or notice of any kind, all of which the Borrower hereby expressly waives.

If, after acceleration of the maturity of the Obligations or termination of the obligations of the Lenders to make Loans hereunder as a result of any Default (other than any Default as described in Section 7.6. or 7.7. with respect to the Borrower) and before any judgment or decree for the payment of the Obligations due shall have been obtained or entered, the Required Lenders (in their sole discretion) shall so direct, the Agent shall, by notice to the Borrower, rescind and annul such acceleration and/or termination.

8.2. Amendments. Subject to the provisions of this Section 8.2., the Required Lenders (or the Agent with the consent in writing of the Required Lenders) and the Borrower may enter into agreements supplemental hereto for the purpose of adding or modifying any provisions to the Loan Documents or changing in any manner the rights of the Lenders or the Borrower hereunder or waiving any Default hereunder; provided, however, that no such supplemental agreement shall, without the consent of all of the Lenders:

8.2.1 Extend the final maturity of any Loan or postpone any regularly scheduled payment of principal of any Loan or forgive all or any portion of the principal amount thereof, or reduce the rate or extend the time of payment of interest or fees thereon (other than a waiver of the application of the default rate of interest pursuant to Section 2.11. hereof).

8.2.2 Reduce the percentage specified in the definition of Required Lenders or any other percentage of Lenders specified to be the applicable percentage in this Agreement to act on specified matters or amend the definition of “Pro Rata Share”.

8.2.3 Extend the Facility Termination Date, or reduce the amount or extend the payment date for, the mandatory payments required under Section 2.2., or increase the amount of the Commitment of any Lender hereunder, or permit the Borrower to assign its rights or obligations under this Agreement.

8.2.4 Amend this Section 8.2.

No amendment of any provision of this Agreement relating to the Agent shall be effective without the written consent of the Agent. The Agent may waive payment of the fee required under Section 12.3.2 without obtaining the consent of any other party to this Agreement.

8.3. Preservation of Rights. No delay or omission of the Lenders or the Agent to exercise any right under the Loan Documents shall impair such right or be construed to be a waiver of any Default or an acquiescence therein, and the making of a Loan notwithstanding the

existence of a Default or the inability of the Borrower to satisfy the conditions precedent to such Loan shall not constitute any waiver or acquiescence. Any single or partial exercise of any such right shall not preclude other or further exercise thereof or the exercise of any other right, and no waiver, amendment or other variation of the terms, conditions or provisions of the Loan Documents whatsoever shall be valid unless in writing signed by the Lenders required pursuant to Section 8.2., and then only to the extent in such writing specifically set forth. All remedies contained in the Loan Documents or by law afforded shall be cumulative and all shall be available to the Agent and the Lenders until the Obligations have been paid in full.

ARTICLE IX

GENERAL PROVISIONS

9.1. Survival of Representations. All representations and warranties of the Borrower contained in this Agreement shall survive the making of the Loans herein contemplated.

9.2. Governmental Regulation. Anything contained in this Agreement to thecontrary notwithstanding, no Lender shall be obligated to extend credit to the Borrower in violation of any limitation or prohibition provided by any applicable statute or regulation.

9.3. Headings. Section headings in the Loan Documents are for convenience of reference only, and shall not govern the interpretation of any of the provisions of the Loan Documents.

9.4. Entire Agreement. The Loan Documents embody the entire agreement and understanding among the Borrower, the Agent and the Lenders and supersede all prior agreements and understandings among the Borrower, the Agent and the Lenders relating to the subject matter thereof other than those contained in the fee letter described in Section 10.13. which shall survive and remain in full force and effect during the term of this Agreement.

9.5. Several Obligations; Benefits of this Agreement. The respective obligations of the Lenders hereunder are several and not joint and no Lender shall be the partner or agent of any other (except to the extent to which the Agent is authorized to act as such). The failure of any Lender to perform any of its obligations hereunder shall not relieve any other Lender from any of its obligations hereunder. This Agreement shall not be construed so as to confer any right or benefit upon any Person other than the parties to this Agreement and their respective successors and assigns, provided, however, that the parties hereto expressly agree that the Arranger shall enjoy the benefits of the provisions of Sections 9.6., 9.10. and 10.11. to the extent specifically set forth therein and shall have the right to enforce such provisions on its own behalf and in its own name to the same extent as if it were a party to this Agreement.

9.6. Expenses; Indemnification. (i) The Borrower shall reimburse the Agent and the Arranger for any costs, internal charges and out-of-pocket expenses (including attorneys’ and paralegals’ fees and time charges of attorneys for the Agent, which attorneys may be employees of the Agent and expenses of and fees for other advisors and professionals engaged by the Agent or the Arranger) paid or incurred by the Agent or the Arranger in connection with the investigation, preparation, negotiation, documentation, execution, delivery, syndication,

distribution (including, without limitation, via the internet), review, amendment, modification and administration of the Loan Documents. The Borrower also agrees to reimburse the Agent, the Syndication Agent, the Co-Documentation Agents, the Arranger and the Lenders for any costs, internal charges and out-of-pocket expenses (including attorneys’ and paralegals’ fees and time charges and expenses of attorneys and paralegals for the Agent, the Syndication Agent, the Co-Documentation Agents, the Arranger and the Lenders, which attorneys and paralegals may be employees of the Agent, the Syndication Agent, the Co-Documentation Agents, the Arranger or the Lenders) paid or incurred by the Agent, the Syndication Agent, the Arranger or any Lender in connection with the collection and enforcement of the Loan Documents.

(ii)

The Borrower hereby further agrees to indemnify the Agent, the Syndication Agent, the Co-Documentation Agents, the Arranger, each Lender, their respective affiliates, and each of their directors, officers and employees against all losses, claims, damages, penalties, judgments, liabilities and expenses (including, without limitation, all expenses of litigation or preparation therefore whether or not the Agent, the Syndication Agent, the Co-Documentation Agents, the Arranger, any Lender or any affiliate is a party thereto, and all reasonable attorneys’ and paralegals’ fees, reasonable time charges and reasonable expenses of attorneys and paralegals of the party seeking indemnification, which attorneys and paralegals may or may not be employees of such party seeking indemnification) which any of them may pay or incur arising out of or relating to this Agreement, the other Loan Documents, the transactions contemplated hereby or the direct or indirect application or proposed application of the proceeds of any Loan hereunder except to the extent that they have resulted from the gross negligence or willful misconduct of the party seeking indemnification. The obligations of the Borrower under this Section 9.6. shall survive the termination of this Agreement.

9.7. Numbers of Documents. All statements, notices, closing documents, and requests hereunder shall be furnished to the Agent with sufficient counterparts so that the Agent may furnish one to each of the Lenders, to the extent that the Agent deems necessary.

9.8. Accounting. Except as provided to the contrary herein, all accounting terms used in the calculation of any financial covenant or test shall be interpreted and all accounting determinations hereunder in the calculation of any financial covenant or test shall be made in accordance with Agreement Accounting Principles. If any changes in generally accepted accounting principles are hereafter required or permitted and are adopted by the Borrower or any of its Subsidiaries with the agreement of its independent certified public accountants and such changes result in a change in the method of calculation of any of the financial covenants, tests, restrictions or standards herein or in the related definitions or terms used therein (“Accounting Changes”), the parties hereto agree, at the Borrower’s request, to enter into negotiations, in good faith, in order to amend such provisions in a credit neutral manner so as to reflect equitably such changes with the desired result that the criteria for evaluating the Borrower’s and its Subsidiaries’ financial condition shall be the same after such changes as if such changes had not been made; provided, however, until such provisions are amended in a manner reasonably satisfactory to the Agent and the Required Lenders, no Accounting Change shall be given effect in such calculations. In the event such amendment is entered into, all references in this Agreement to Agreement Accounting Principles shall mean generally accepted accounting principles as of the

date of such amendment. Notwithstanding the foregoing, all financial statements to be delivered by the Borrower pursuant to Section 6.1. shall be prepared in accordance with generally accepted accounting principles in effect at such time.

9.9. Severability of Provisions. Any provision in any Loan Document that is held to be inoperative, unenforceable, or invalid in any jurisdiction shall, as to that jurisdiction, be inoperative, unenforceable, or invalid without affecting the remaining provisions in that jurisdiction or the operation, enforceability, or validity of that provision in any other jurisdiction, and to this end the provisions of all Loan Documents are declared to be severable.

9.10. Nonliability of Lenders. The relationship between the Borrower on the one hand and the Lenders and the Agent on the other hand shall be solely that of borrower and lender. Neither the Agent, the Arranger nor any Lender shall have any fiduciary responsibilities to the Borrower. Neither the Agent, the Arranger nor any Lender undertakes any responsibility to the Borrower to review or inform the Borrower of any matter in connection with any phase of the Borrower’s business or operations. The Borrower agrees that neither the Agent, the Arranger nor any Lender shall have liability to the Borrower (whether sounding in tort, contract or otherwise) for losses suffered by the Borrower in connection with, arising out of, or in any way related to, the transactions contemplated and the relationship established by the Loan Documents, or any act, omission or event occurring in connection therewith, unless it is determined in a final non-appealable judgment by a court of competent jurisdiction that such losses resulted from the gross negligence or willful misconduct of the party from which recovery is sought. Neither the Agent, the Arranger nor any Lender shall have any liability with respect to, and the Borrower hereby waives, releases and agrees not to sue for, any special, indirect, consequential or punitive damages suffered by the Borrower in connection with, arising out of, or in any way related to the Loan Documents or the transactions contemplated thereby.

9.11. Confidentiality. Each Lender agrees to hold any confidential information which it may receive from the Borrower pursuant to this Agreement in confidence, except for disclosure (i) to its Affiliates and to other Lenders and their respective Affiliates, for use solely in connection with the transactions contemplated hereby, (ii) to legal counsel, accountants, and other professional advisors to such Lender or to a Transferee, in each case which have been informed as to the confidential nature of such information, (iii) to regulatory officials having jurisdiction over it, (iv) to any Person as required by law, regulation, or legal process, (v) to any Person in connection with any legal proceeding to which such Lender is a party, (vi) to such Lender’s direct or indirect contractual counterparties in swap agreements or to legal counsel, accountants and other professional advisors to such counterparties, in each case which have been informed as to the confidential nature of such information, (vii) permitted by Section 12.4. and (viii) to rating agencies if requested or required by such agencies in connection with a rating relating to the Advances hereunder. Notwithstanding anything herein to the contrary, confidential information shall not include, and each Lender (and each employee, representative or other agent of any Lender) may disclose to any and all Persons, without limitation of any kind, the “tax treatment” and “tax structure” (in each case, within the meaning of Treasury Regulation Section 1.6011-4) of the transactions contemplated hereby and all materials of any kind (including opinions or other tax analyses) that are or have been provided to such Lender relating to such tax treatment or tax structure; provided that with respect to any document or similar item that in either case contains information concerning such tax treatment or tax structure of the

transactions contemplated hereby as well as other information, this sentence shall only apply to such portions of the document or similar item that relate to such tax treatment or tax structure.

9.12. Lenders Not Utilizing Plan Assets. Each Lender and Designated Lender represents and warrants that none of the consideration used by such Lender or Designated Lender to make its Loans constitutes for any purpose of ERISA or Section 4975 of the Code assets of any “plan” as defined in Section 3(3) of ERISA or Section 4975 of the Code and the rights and interests of such Lender or Designated Lender in and under the Loan Documents shall not constitute such “plan assets” under ERISA.

9.13. Nonreliance. Each Lender hereby represents that it is not relying on or looking to any margin stock (as defined in Regulation U of the Board of Governors of the Federal Reserve System) for the repayment of the Loans provided for herein.

9.14. Disclosure. The Borrower and each Lender hereby acknowledge and agree that Bank One and/or its Affiliates from time to time may hold investments in, make other loans to or have other relationships with the Borrower and its Affiliates.

ARTICLE X

THE AGENT

10.1. Appointment; Nature of Relationship. Bank One, NA is hereby appointed by each of the Lenders as its contractual representative (herein referred to as the “Agent”) hereunder and under each other Loan Document, and each of the Lenders irrevocably authorizes the Agent to act as the contractual representative of such Lender with the rights and duties expressly set forth herein and in the other Loan Documents. The Agent agrees to act as such contractual representative upon the express conditions contained in this Article X. Notwithstanding the use of the defined term “Agent,” it is expressly understood and agreed that the Agent shall not have any fiduciary responsibilities to any Lender by reason of this Agreement or any other Loan Document and that the Agent is merely acting as the contractual representative of the Lenders with only those duties as are expressly set forth in this Agreement and the other Loan Documents. In its capacity as the Lenders’ contractual representative, the Agent (i) does not hereby assume any fiduciary duties to any of the Lenders, (ii) is a “representative” of the Lenders within the meaning of the term “secured party” as defined in the Illinois Uniform Commercial Code and (iii) is acting as an independent contractor, the rights and duties of which are limited to those expressly set forth in this Agreement and the other Loan Documents. Each of the Lenders hereby agrees to assert no claim against the Agent on any agency theory or any other theory of liability for breach of fiduciary duty, all of which claims each Lender hereby waives.

10.2. Powers. The Agent shall have and may exercise such powers under the Loan Documents as are specifically delegated to the Agent by the terms of each thereof, together with such powers as are reasonably incidental thereto. The Agent shall have no implied duties to the Lenders, or any obligation to the Lenders to take any action thereunder except any action specifically provided by the Loan Documents to be taken by the Agent.

10.3. General Immunity. Neither the Agent nor any of its directors, officers, agents or employees shall be liable to the Borrower, the Lenders or any Lender for any action taken or omitted to be taken by it or them hereunder or under any other Loan Document or in connection herewith or therewith except to the extent such action or inaction is determined in a final non-appealable judgment by a court of competent jurisdiction to have arisen from the gross negligence or willful misconduct of such Person.

10.4. No Responsibility for Loans, Recitals, etc. Neither the Agent nor any of its directors, officers, agents or employees shall be responsible for or have any duty to ascertain, inquire into, or verify (a) any statement, warranty or representation made in connection with any Loan Document or any borrowing hereunder; (b) the performance or observance of any of the covenants or agreements of any obligor under any Loan Document, including, without limitation, any agreement by an obligor to furnish information directly to each Lender; (c) the satisfaction of any condition specified in Article IV, except receipt of items required to be delivered solely to the Agent; (d) the existence or possible existence of any Default or Unmatured Default; (e) the validity, enforceability, effectiveness, sufficiency or genuineness of any Loan Document or any other instrument or writing furnished in connection therewith; (f) the value, sufficiency, creation, perfection or priority of any Lien in any collateral security; or (g) the financial condition of the Borrower or any guarantor of any of the Obligations or of any of the Borrower’s or any such guarantor’s respective Subsidiaries. The Agent shall have no duty to disclose to the Lenders information that is not required to be furnished by the Borrower to the Agent at such time, but is voluntarily furnished by the Borrower to the Agent (either in its capacity as Agent or in its individual capacity).

10.5. Action on Instructions of Lenders. The Agent shall in all cases be fully protected in acting, or in refraining from acting, hereunder and under any other Loan Document in accordance with written instructions signed by the Required Lenders, and such instructions and any action taken or failure to act pursuant thereto shall be binding on all of the Lenders. The Lenders hereby acknowledge that the Agent shall be under no duty to take any discretionary action permitted to be taken by it pursuant to the provisions of this Agreement or any other Loan Document unless it shall be requested in writing to do so by the Required Lenders. The Agent shall be fully justified in failing or refusing to take any action hereunder and under any other Loan Document unless it shall first be indemnified to its satisfaction by the Lenders pro rata against any and all liability, cost and expense that it may incur by reason of taking or continuing to take any such action.

10.6. Employment of Agents and Counsel. The Agent may execute any of its duties as Agent hereunder and under any other Loan Document by or through employees, agents, and attorneys-in-fact and shall not be answerable to the Lenders, except as to money or securities received by it or its authorized agents, for the default or misconduct of any such agents or attorneys-in-fact selected by it with reasonable care. The Agent shall be entitled to advice of counsel concerning the contractual arrangement between the Agent and the Lenders and all matters pertaining to the Agent’s duties hereunder and under any other Loan Document.

10.7. Reliance on Documents; Counsel. The Agent shall be entitled to rely upon any Note, notice, consent, certificate, affidavit, letter, telegram, statement, paper or document believed by it to be genuine and correct and to have been signed or sent by the proper person or

persons, and, in respect to legal matters, upon the opinion of counsel selected by the Agent, which counsel may be employees of the Agent.

10.8. Agent’s Reimbursement and Indemnification. The Lenders agree to reimburse and indemnify the Agent, the Syndication Agent and the Co-Documentation Agents ratably in proportion to the Lenders’ Pro Rata Shares of the Aggregate Commitment (or, if the Aggregate Commitment has been terminated, of the Outstanding Credit Exposure) (i) for any amounts not reimbursed by the Borrower for which the Agent, the Syndication Agent or either Co-Documentation Agent is entitled to reimbursement by the Borrower under the Loan Documents, (ii) for any other expenses incurred by the Agent, the Syndication Agent, or either Co-Documentation Agent on behalf of the Lenders, in connection with the preparation, execution, delivery, administration and enforcement of the Loan Documents (including, without limitation, for any expenses incurred by the Agent or the Syndication Agent in connection with any dispute between the Agent or the Syndication Agent and any Lender or between two or more of the Lenders) and (iii) for any liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind and nature whatsoever which may be imposed on, incurred by or asserted against the Agent, the Syndication Agent, or either Co-Documentation Agent in any way relating to or arising out of the Loan Documents or any other document delivered in connection therewith or the transactions contemplated thereby (including, without limitation, for any such amounts incurred by or asserted against the Agent, the Syndication Agent, or either Co-Documentation Agent in connection with any dispute between the Agent, the Syndication Agent, the Co-Documentation Agents and any Lender or between two or more of the Lenders), or the enforcement of any of the terms of the Loan Documents or of any such other documents, provided that (i) no Lender shall be liable for any of the foregoing to the extent any of the foregoing is found in a final non-appealable judgment by a court of competent jurisdiction to have resulted from the gross negligence or willful misconduct of the party seeking indemnification and (ii) any indemnification required pursuant to Section 3.5.(vii) shall, notwithstanding the provisions of this Section 10.8., be paid by the relevant Lender in accordance with the provisions thereof. The obligations of the Lenders under this Section 10.8. shall survive payment of the Obligations and termination of this Agreement.

10.9. Notice of Default. The Agent shall not be deemed to have knowledge or notice of the occurrence of any Default or Unmatured Default hereunder unless the Agent has received written notice from a Lender or the Borrower referring to this Agreement describing such Default or Unmatured Default and stating that such notice is a “notice of default”. In the event that the Agent receives such a notice, the Agent shall give prompt notice thereof to the Lenders.

10.10. Rights as a Lender. In the event the Agent is a Lender, the Agent shall have the same rights and powers hereunder and under any other Loan Document with respect to its Commitment and its Loans as any Lender and may exercise the same as though it were not the Agent, and the term “Lender” or “Lenders” shall, at any time when the Agent is a Lender, unless the context otherwise indicates, include the Agent in its individual capacity. The Agent and its Affiliates may accept deposits from, lend money to, and generally engage in any kind of trust, debt, equity or other transaction, in addition to those contemplated by this Agreement or any other Loan Document, with the Borrower or any of its Subsidiaries in which the Borrower or such Subsidiary is not restricted hereby from engaging with any other Person. The Agent, in its individual capacity, is not obligated to remain a Lender.

10.11. Lender Credit Decision. Each Lender acknowledges that it has, independently and without reliance upon the Agent, the Arranger or any other Lender and based on the financial statements prepared by the Borrower and such other documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement and the other Loan Documents. Each Lender also acknowledges that it will, independently and without reliance upon the Agent, the Arranger or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under this Agreement and the other Loan Documents.

10.12. Successor Agent. The Agent may resign at any time by giving written notice thereof to the Lenders and the Borrower, such resignation to be effective upon the appointment of a successor Agent or, if no successor Agent has been appointed, forty-five days after the retiring Agent gives notice of its intention to resign. The Agent may be removed at any time with or without cause by written notice received by the Agent from the Required Lenders, such removal to be effective on the date specified by the Required Lenders. Upon any such resignation or removal, the Required Lenders shall have the right to appoint, on behalf of the Borrower and the Lenders, a successor Agent. If no successor Agent shall have been so appointed by the Required Lenders within thirty days after the resigning Agent’s giving notice of its intention to resign, then the resigning Agent may appoint, on behalf of the Borrower and the Lenders, a successor Agent. Notwithstanding the previous sentence, the Agent may at any time without the consent of the Borrower or any Lender, appoint any of its Affiliates which is a commercial bank as a successor Agent hereunder. If the Agent has resigned or been removed and no successor Agent has been appointed, the Lenders may perform all the duties of the Agent hereunder and the Borrower shall make all payments in respect of the Obligations to the applicable Lender and for all other purposes shall deal directly with the Lenders. No successor Agent shall be deemed to be appointed hereunder until such successor Agent has accepted the appointment. Any such successor Agent shall be a commercial bank having capital and retained earnings of at least $100,000,000. Upon the acceptance of any appointment as Agent hereunder by a successor Agent, such successor Agent shall thereupon succeed to and become vested with all the rights, powers, privileges and duties of the resigning or removed Agent. Upon the effectiveness of the resignation or removal of the Agent, the resigning or removed Agent shall be discharged from its duties and obligations hereunder and under the Loan Documents. After the effectiveness of the resignation or removal of an Agent, the provisions of this Article X shall continue in effect for the benefit of such Agent in respect of any actions taken or omitted to be taken by it while it was acting as the Agent hereunder and under the other Loan Documents. In the event that there is a successor to the Agent by merger, or the Agent assigns its duties and obligations to an Affiliate pursuant to this Section 10.12., then the term “Prime Rate” as used in this Agreement shall mean the prime rate, base rate or other analogous rate of the new Agent.

10.13. Agent and Arranger Fees. The Borrower agrees to pay to the Agent and the Arranger, for their respective accounts, the fees agreed to by the Borrower, the Agent and the Arranger pursuant to that certain letter agreement dated May 14, 2003, or as otherwise agreed from time to time.

10.14. Delegation to Affiliates. The Borrower and the Lenders agree that the Agent may delegate any of its duties under this Agreement to any of its Affiliates. Any such Affiliate (and such Affiliate’s directors, officers, agents and employees) which performs duties in connection

with this Agreement shall be entitled to the same benefits of the indemnification, waiver and other protective provisions to which the Agent is entitled under Articles IX and X.

10.15. Syndication Agent and Co-Documentation Agents. None of the Syndication Agent and the Co-Documentation Agents shall have any obligation, liability, responsibility or duty under this Agreement other than those applicable to all Lenders. Without limiting the foregoing, none of the Syndication Agent and the Co-Documentation Agents shall have or be deemed to have a fiduciary relationship with any Lender. Each Lender hereby makes the same acknowledgements with respect to the Syndication Agent and the Co-Documentation Agents as it makes with respect to the Agent in Section 10.11.

ARTICLE XI

SETOFF; RATABLE PAYMENTS

11.1. Setoff. In addition to, and without limitation of, any rights of the Lenders under applicable law, if the Borrower becomes insolvent, however evidenced, or any Default occurs, any and all deposits (including all account balances, whether provisional or final and whether or not collected or available) and any other Indebtedness at any time held or owing by any Lender or any Affiliate of any Lender to or for the credit or account of the Borrower may be offset and applied toward the payment of the Obligations owing to such Lender, whether or not the Obligations, or any part thereof, shall then be due.

11.2. Ratable Payments. If any Lender, whether by setoff or otherwise, has payment made to it upon its Loans (other than payments received pursuant to Section 3.1., 3.2., 3.4. or 3.5.) in a greater proportion than that received by any other Lender, such Lender agrees, promptly upon demand, to purchase a portion of the Loans held by the other Lenders so that after such purchase each Lender will hold its ratable proportion of Loans. If any Lender, whether in connection with setoff or amounts which might be subject to setoff or otherwise, receives collateral or other protection for its Obligations or such amounts which may be subject to setoff, such Lender agrees, promptly upon demand, to take such action necessary such that all Lenders share in the benefits of such collateral ratably in proportion to their Loans. In case any such payment is disturbed by legal process, or otherwise, appropriate further adjustments shall be made.

ARTICLE XII

BENEFIT OF AGREEMENT; ASSIGNMENTS; PARTICIPATIONS

12.1. Successors and Assigns; Designated Lenders.

12.1.1 Successors and Assigns. The terms and provisions of the Loan Documents shall be binding upon and inure to the benefit of the Borrower, the Agent and the Lenders and their respective successors and assigns permitted hereby, except that (i) the Borrower shall not have the right to assign its rights or obligations under the Loan Documents without the prior written consent of each Lender, (ii) any assignment by any Lender must be made in compliance with Section 12.3., and (iii) any transfer by

participation must be made in compliance with Section 12.2. Any attempted assignment or transfer by any party not made in compliance with this Section 12.1. shall be null and void, unless such attempted assignment or transfer is treated as a participation in accordance with Section 12.3.2. The parties to this Agreement acknowledge that clause (ii) of this Section 12.1. relates only to absolute assignments and this Section 12.1. does not prohibit assignments creating security interests, including, without limitation, (x) any pledge or assignment by any Lender of all or any portion of its rights under this Agreement and any Note to a Federal Reserve Bank, (y) in the case of a Lender which is a Fund, any pledge or assignment of all or any portion of its rights under this Agreement and any Note to its trustee in support of its obligations to its trustee or (z) any pledge or assignment by any Lender of all or any portion of its rights under this Agreement and any Note to direct or indirect contractual counterparties in swap agreements relating to the Loans; provided, however, that no such pledge or assignment creating a security interest shall release the transferor Lender from its obligations hereunder unless and until the parties thereto have complied with the provisions of Section 12.3. The Agent may treat the Person which made any Loan or which holds any Note as the owner thereof for all purposes hereof unless and until such Person complies with Section 12.3.; provided, however, that the Agent may in its discretion (but shall not be required to) follow instructions from the Person which made any Loan or which holds any Note to direct payments relating to such Loan or Note to another Person. Any assignee of the rights to any Loan or any Note agrees by acceptance of such assignment to be bound by all the terms and provisions of the Loan Documents. Any request, authority or consent of any Person, who at the time of making such request or giving such authority or consent is the owner of the rights to any Loan (whether or not a Note has been issued in evidence thereof), shall be conclusive and binding on any subsequent holder or assignee of the rights to such Loan.

12.1.2 Designated Lenders.

(i)

Subject to the terms and conditions set forth in this Section 12.1.2, any Lender may from time to time elect to designate an Eligible Designee to provide all or any part of the Loans to be made by such Lender pursuant to this Agreement; provided that the designation of an Eligible Designee by any Lender for purposes of this Section 12.1.2 shall be subject to the approval of the Agent (which consent shall not be unreasonably withheld or delayed). Upon the execution by the parties to each such designation of an agreement in the form of Exhibit F hereto (a “Designation Agreement”) and the acceptance thereof by the Agent, the Eligible Designee shall become a Designated Lender for purposes of this Agreement. The Designating Lender shall thereafter have the right to permit the Designated Lender to provide all or a portion of the Loans to be made by the Designating Lender pursuant to the terms of this Agreement and the making of the Loans or portion thereof shall satisfy the obligations of the Designating Lender to the same extent, and as if, such Loan was made by the Designating Lender. As to any Loan made by it, each Designated Lender shall have all the rights a Lender making such Loan would have under this Agreement and otherwise; provided, (x) that all voting rights

under this Agreement shall be exercised solely by the Designating Lender, (y) each Designating Lender shall remain solely responsible to the other parties hereto for its obligations under this Agreement, including the obligations of a Lender in respect of Loans made by its Designated Lender and (z) no Designated Lender shall be entitled to reimbursement under Article III hereof for any amount which would exceed the amount that would have been payable by the Borrower to the Lender from which the Designated Lender obtained any interests hereunder. No additional Notes shall be required with respect to Loans provided by a Designated Lender; provided, however, to the extent any Designated Lender shall advance funds, the Designating Lender shall be deemed to hold the Notes in its possession as an agent for such Designated Lender to the extent of the Loan funded by such Designated Lender. Such Designating Lender shall act as administrative agent for its Designated Lender and give and receive notices and communications hereunder. Any payments for the account of any Designated Lender shall be paid to its Designating Lender as administrative agent for such Designated Lender and neither the Borrower nor the Agent shall be responsible for any Designating Lender’s application of such payments. In addition, any Designated Lender may (1) with notice to, but without the consent of the Borrower or the Agent, assign all or portions of its interests in any Loans to its Designating Lender or to any financial institution consented to by the Agent providing liquidity and/or credit facilities to or for the account of such Designated Lender and (2) subject to advising any such Person that such information is to be treated as confidential in accordance with Section 9.11., disclose on a confidential basis any non-public information relating to its Loans to any rating agency, commercial paper dealer or provider of any guarantee, surety or credit or liquidity enhancement to such Designated Lender.

(ii)

Each party to this Agreement hereby agrees that it shall not institute against, or join any other Person in instituting against, any Designated Lender any bankruptcy, reorganization, arrangement, insolvency or liquidation proceeding or other proceedings under any federal or state bankruptcy or similar law for one year and a day after the payment in full of all outstanding senior indebtedness of any Designated Lender; provided that the Designating Lender for each Designated Lender hereby agrees to indemnify, save and hold harmless each other party hereto for any loss, cost, damage and expense arising out of its inability to institute any such proceeding against such Designated Lender. This Section 12.1.2(ii) shall survive the termination of this Agreement.

12.2. Participations.

12.2.1 Permitted Participants; Effect. Any Lender may, in the ordinary course of its business and in accordance with applicable law, at any time sell to one or more banks or other entities (“Participants”) participating interests in any Loan owing to such Lender, any Note held by such Lender, any Commitment of such Lender or any other interest of

such Lender under the Loan Documents. In the event of any such sale by a Lender of participating interests to a Participant, such Lender’s obligations under the Loan Documents shall remain unchanged, such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations, such Lender shall remain the owner of its Loans and the holder of any Note issued to it in evidence thereof for all purposes under the Loan Documents, all amounts payable by the Borrower under this Agreement shall be determined as if such Lender had not sold such participating interests, and the Borrower and the Agent shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under the Loan Documents.

12.2.2 Voting Rights. Each Lender shall retain the sole right to approve, without the consent of any Participant, any amendment, modification or waiver of any provision of the Loan Documents other than any amendment, modification or waiver with respect to any Loan or Commitment in which such Participant has an interest which would require consent of all of the Lenders pursuant to the terms of Section 8.2.

12.2.3 Benefit of Certain Provisions. The Borrower agrees that each Participant shall be deemed to have the right of setoff provided in Section 11.1. in respect of its participating interest in amounts owing under the Loan Documents to the same extent as if the amount of its participating interest were owing directly to it as a Lender under the Loan Documents, provided that each Lender shall retain the right of setoff provided in Section 11.1. with respect to the amount of participating interests sold to each Participant. The Lenders agree to share with each Participant, and each Participant, by exercising the right of setoff provided in Section 11.1., agrees to share with each Lender, any amount received pursuant to the exercise of its right of setoff, such amounts to be shared in accordance with Section 11.2. as if each Participant were a Lender. The Borrower further agrees that each Participant shall be entitled to the benefits of Sections 3.1., 3.2., 3.4. and 3.5. to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to Section 12.3., provided that (i) a Participant shall not be entitled to receive any greater payment under Section 3.1., 3.2. or 3.5. than the Lender who sold the participating interest to such Participant would have received had it retained such interest for its own account, unless the sale of such interest to such Participant is made with the prior written consent of the Borrower, and (ii) any Participant not incorporated under the laws of the United States of America or any State thereof agrees to comply with the provisions of Section 3.5. to the same extent as if it were a Lender.

12.3. Assignments.

12.3.1 Permitted Assignments. Any Lender may at any time assign to one or more banks or other entities (“Purchasers”) all or any part of its rights and obligations under the Loan Documents. Such assignment shall be substantially in the form of Exhibit C or in such other form as may be agreed to by the parties thereto. Each such assignment with respect to a Purchaser which is not a Lender or an Affiliate of a Lender or an Approved Fund shall either be in an amount equal to the entire applicable Commitment and Loans of the assigning Lender or (unless each of the Borrower and the Agent otherwise consents) be in an aggregate amount not less than $2,500,000. The amount of

the assignment shall be based on the Commitment or outstanding Loans (if the Commitment has been terminated) subject to the assignment, determined as of the date of such assignment or as of the “Trade Date,” if the “Trade Date” is specified in the assignment.

12.3.2 Consents. The consent of the Borrower shall be required prior to an assignment becoming effective unless the Purchaser is a Lender, an Affiliate of a Lender or an Approved Fund, provided that the consent of the Borrower shall not be required if (i) a Default has occurred and is continuing or (ii) if such assignment is in connection with the physical settlement of any Lender’s obligations to direct or indirect contractual counterparties in swap agreements relating to the Loans; provided, that the assignment without the Borrower’s consent pursuant to clause (ii) shall not increase the Borrower’s liability under Section 3.5. The consent of the Agent shall be required prior to an assignment becoming effective unless the Purchaser is a Lender, an Affiliate of a Lender or an Approved Fund. Any consent required under this Section 12.3.2 shall not be unreasonably withheld or delayed.

12.3.3 Effect; Effective Date. Upon (i) delivery to the Agent of an assignment, together with any consents required by Sections 12.3.1 and 12.3.2, and (ii) payment of a $3,500 fee to the Agent for processing such assignment (unless such fee is waived by the Agent), such assignment shall become effective on the effective date specified in such assignment. The assignment shall contain a representation and warranty by the Purchaser to the effect that none of the funds, money, assets or other consideration used to make the purchase and assumption of the Commitment and Loans under the applicable assignment agreement constitutes “plan assets” as defined under ERISA and that the rights, benefits and interests of the Purchaser in and under the Loan Documents will not be “plan assets” under ERISA. On and after the effective date of such assignment, such Purchaser shall for all purposes be a Lender party to this Agreement and any other Loan Document executed by or on behalf of the Lenders and shall have all the rights, benefits and obligations of a Lender under the Loan Documents, to the same extent as if it were an original party thereto, and the transferor Lender shall be released with respect to the Commitment and Loans assigned to such Purchaser without any further consent or action by the Borrower, the Lenders or the Agent. In the case of an assignment covering all of the assigning Lender’s rights, benefits and obligations under this Agreement, such Lender shall cease to be a Lender hereunder but shall continue to be entitled to the benefits of, and subject to, those provisions of this Agreement and the other Loan Documents which survive payment of the Obligations and termination of the Loan Documents. Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this Section 12.3. shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with Section 12.2. Upon the consummation of any assignment to a Purchaser pursuant to this Section 12.3.3, the transferor Lender, the Agent and the Borrower shall, if the transferor Lender or the Purchaser desires that its Loans be evidenced by Notes, make appropriate arrangements so that, upon cancellation and surrender to the Borrower of the Notes (if any) held by the transferor Lender, new Notes or, as appropriate, replacement Notes are issued to such transferor Lender, if applicable, and new Notes or, as appropriate,

replacement Notes, are issued to such Purchaser, in each case in principal amounts reflecting their respective Commitments, as adjusted pursuant to such assignment.

12.3.4 Register. The Agent, acting solely for this purpose as an agent of the Borrower (and the Borrower hereby designates the Agent to act in such capacity), shall maintain at one of its offices in Chicago, Illinois a copy of each Assignment and Assumption delivered to it and a register for the recordation of the names and addresses of the Lenders, and the Commitments of, and principal amounts of the Loans owing to, each Lender pursuant to the terms hereof from time to time (the “Register”). The entries in the Register shall be conclusive, and the Borrower, the Agent and the Lenders may treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. The Register shall be available for inspection by the Borrower and any Lender, at any reasonable time and from time to time upon reasonable prior notice.

12.4. Dissemination of Information. The Borrower authorizes each Lender to disclose to any Participant or Purchaser or any other Person acquiring an interest in the Loan Documents by operation of law (each a “Transferee”) and any prospective Transferee any and all information in such Lender’s possession concerning the creditworthiness of the Borrower and its Subsidiaries; provided that each Transferee and prospective Transferee agrees to be bound by Section 9.11. of this Agreement.

12.5. Tax Certifications. If any interest in any Loan Document is transferred to any Transferee which is not incorporated under the laws of the United States or any State thereof, the transferor Lender shall cause such Transferee, concurrently with the effectiveness of such transfer, to comply with the provisions of Section 3.5.(iv).

ARTICLE XIII

NOTICES

13.1. Notices. Except as otherwise permitted by Section 2.14. with respect to borrowing notices, all notices, requests and other communications to any party hereunder shall be in writing (including electronic transmission, facsimile transmission or similar writing) and shall be given to such party: (x) in the case of the Borrower, the Lenders or the Agent, at its address or facsimile number set forth on the signature pages hereof or, (y) in the case of any party, at such other address or facsimile number as such party may hereafter specify for the purpose by notice to the Agent and the Borrower in accordance with the provisions of this Section 13.1. Each such notice, request or other communication shall be effective (i) if given by facsimile transmission, when transmitted to the facsimile number specified in this Section and confirmation of receipt is received, (ii) if given by mail, 72 hours after such communication is deposited in the mails with first class postage prepaid, addressed as aforesaid, or (iii) if given by any other means, when delivered (or, in the case of electronic transmission, received) at the address specified in this Section; provided that notices to the Agent under Article II shall not be effective until received.

13.2. Change of Address. The Borrower, the Agent and any Lender may each change the address for service of notice upon it by a notice in writing to the other parties hereto.

ARTICLE XIV

COUNTERPARTS

This Agreement may be executed in any number of counterparts, all of which taken together shall constitute one agreement, and any of the parties hereto may execute this Agreement by signing any such counterpart. This Agreement shall be effective when it has been executed by the Borrower, the Agent and the Lenders and each party has notified the Agent by facsimile transmission or telephone that it has taken such action.

ARTICLE XV

CHOICE OF LAW; CONSENT TO JURISDICTION; WAIVER OF JURY TRIAL

15.1 CHOICE OF LAW. THE LOAN DOCUMENTS (OTHER THAN THOSE CONTAINING A CONTRARY EXPRESS CHOICE OF LAW PROVISION) SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE INTERNAL LAWS (INCLUDING, WITHOUT LIMITATION, 735 ILCS SECTION 105/5-1 ET SEQ, BUT OTHERWISE WITHOUT REGARD TO THE CONFLICT OF LAWS PROVISIONS) OF THE STATE OF ILLINOIS, BUT GIVING EFFECT TO FEDERAL LAWS APPLICABLE TO NATIONAL BANKS.

15.2 CONSENT TO JURISDICTION. THE BORROWER, THE AGENT AND EACH LENDER HEREBY IRREVOCABLY SUBMITS TO THE NON-EXCLUSIVE JURISDICTION OF ANY UNITED STATES FEDERAL OR ILLINOIS STATE COURT SITTING IN CHICAGO, ILLINOIS IN ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO ANY LOAN DOCUMENTS AND THE BORROWER, THE AGENT AND EACH LENDER HEREBY IRREVOCABLY AGREES THAT ALL CLAIMS IN RESPECT OF SUCH ACTION OR PROCEEDING MAY BE HEARD AND DETERMINED IN ANY SUCH COURT AND IRREVOCABLY WAIVES ANY OBJECTION IT MAY NOW OR HEREAFTER HAVE AS TO THE VENUE OF ANY SUCH SUIT, ACTION OR PROCEEDING BROUGHT IN SUCH A COURT OR THAT SUCH COURT IS AN INCONVENIENT FORUM. NOTHING HEREIN SHALL LIMIT THE RIGHT OF THE AGENT OR ANY LENDER TO BRING PROCEEDINGS AGAINST THE BORROWER IN THE COURTS OF ANY OTHER JURISDICTION. ANY JUDICIAL PROCEEDING BY THE BORROWER AGAINST THE AGENT OR ANY LENDER INVOLVING, DIRECTLY OR INDIRECTLY, ANY MATTER IN ANY WAY ARISING OUT OF, RELATED TO, OR CONNECTED WITH ANY LOAN DOCUMENT SHALL BE BROUGHT ONLY IN A COURT IN CHICAGO, ILLINOIS.

15.3 WAIVER OF JURY TRIAL. THE BORROWER, THE AGENT AND EACH LENDER HEREBY WAIVE TRIAL BY JURY IN ANY JUDICIAL PROCEEDING INVOLVING, DIRECTLY OR INDIRECTLY, ANY MATTER (WHETHER SOUNDING IN TORT, CONTRACT OR OTHERWISE) IN ANY WAY ARISING OUT OF, RELATED TO, OR CONNECTED WITH ANY LOAN DOCUMENT OR THE RELATIONSHIP ESTABLISHED THEREUNDER.

ARTICLE XVI

TERMINATION OF EXISTING CREDIT AGREEMENT

The Borrower and the Lenders party to the Existing Credit Agreement agree that, upon (i) the execution and delivery of this Agreement by each of the parties hereto and (ii) satisfaction (or waiver by the Borrower, the Lenders and the Agent) of the conditions precedent set forth in Section 4.1, the Existing Credit Agreement shall be deemed terminated and cancelled and all commitments to lend thereunder shall be deemed to have been reduced to zero and terminated permanently. Furthermore, on or prior to the date immediately preceding the Closing Date, any and all accrued and unpaid interest and fees due and payable thereunder shall have been paid.

[Signature Pages Follow]

IN WITNESS WHEREOF, the Borrower, the Lenders and the Agent have executed this Agreement as of the date first above written.

	OKLAHOMA GAS AND ELECTRIC COMPANY
	By:	/s/ Eric B. Weekes
	Title:	Treasurer
		321 N. Harvey Oklahoma City, OK 73102

	Attention:	Eric B. Weekes
		Telephone: (405) 553-3581 FAX: (405) 553-3625

	BANK ONE, NA, Individually and as Agent
	By:	/s/ Madeline Pember
	Title:	Director
		1 Bank One Plaza Chicago, Illinois 60670
	Attention:	Jane A. Bek
		Telephone: (312) 732-3422 FAX: (312) 732-5435