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 September 30, 2004

OR

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

Commission File Number: 1-1097

Oklahoma Gas and Electric Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format permitted by General Instruction H(2).

OKLAHOMA GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)

Oklahoma
(State or other jurisdiction of
incorporation or organization)

73-0382390
(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 No X

As of October 31, 2004, 40,378,745 shares of common stock, par value $2.50 per share, were outstanding.

OKLAHOMA GAS AND ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2004

Part I - FINANCIAL INFORMATION	Page

Item 1. Financial Statements (Unaudited)
Condensed Balance Sheets	1
Condensed Statements of Income	3
Condensed Statements of Cash Flows	4
Notes to Condensed Financial Statements	5

Item 2. Management’s Discussion and Analysis of Financial Condition
and Results of Operations	26

Item 3. Quantitative and Qualitative Disclosures About Market Risk	41

Item 4. Controls and Procedures	41

Part II - OTHER INFORMATION

Item 1. Legal Proceedings	42

Item 6. Exhibits	42

Signature	43

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)

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

ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	-	--	$	4	.0
Accounts receivable - customers, less reserve of $2.7 and $2.6, respectively		143	.8		123	.1
Accounts receivable - other		11	.8		9	.9
Advances to parent		48	.1		51	.8
Accrued unbilled revenues		67	.8		38	.0
Fuel inventories, at LIFO cost		52	.9		60	.0
Materials and supplies, at average cost		46	.3		41	.4
Accumulated deferred tax assets		7	.0		6	.8
Fuel clause under recoveries		48	.9		4	.0
Other		1	.1		6	.2

Total current assets		427	.7		345	.2


OTHER PROPERTY AND INVESTMENTS, at cost		4	.9		5	.6


PROPERTY, PLANT AND EQUIPMENT
In service		4,461	.2		4,210	.8
Construction work in progress		99	.1		44	.6
Other		1	.0		1	.0

Total property, plant and equipment		4,561	.3		4,256	.4
Less accumulated depreciation		2,063	.7		2,006	.0

Net property, plant and equipment		2,497	.6		2,250	.4


DEFERRED CHARGES AND OTHER ASSETS
Recoverable take or pay gas charges		32	.5		32	.5
Income taxes recoverable from customers, net		31	.0		31	.6
Intangible asset - unamortized prior service cost		35	.7		35	.7
Prepaid benefit obligation		73	.4		37	.5
Price risk management		4	.1		4	.0
Other		40	.3		32	.7

Total deferred charges and other assets		217	.0		174	.0


TOTAL ASSETS	$	3,147	.2	$	2,775	.2

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

OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED BALANCE SHEETS (Continued)
(Unaudited)

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

LIABILITIES AND STOCKHOLDER’S EQUITY
CURRENT LIABILITIES
Short-term debt	$	-	--	$	50	.0
Accounts payable - affiliates		102	.1		40	.9
Accounts payable - other		55	.8		57	.7
Customers’ deposits		43	.6		35	.8
Accrued taxes		31	.0		20	.6
Accrued interest		15	.5		12	.8
Tax collections payable		9	.8		7	.9
Accrued vacation		11	.7		11	.6
Gas imbalance		0	.8		-	--
Fuel clause over recoveries		-	--		32	.4
Other		20	.0		15	.3

Total current liabilities		290	.3		285	.0


LONG-TERM DEBT		847	.3		707	.2


DEFERRED CREDITS AND OTHER LIABILITIES
Accrued pension and benefit obligations		140	.5		134	.8
Accumulated deferred income taxes		559	.2		535	.9
Accumulated deferred investment tax credits		38	.1		42	.0
Accrued removal obligations, net		122	.1		116	.3
Provision for payments of take or pay gas		32	.5		32	.5
Asset retirement obligation		1	.1		-	--
Other		-	--		1	.6

Total deferred credits and other liabilities		893	.5		863	.1


STOCKHOLDER’S EQUITY
Common stockholder’s equity		665	.4		512	.4
Retained earnings		504	.1		460	.9
Accumulated other comprehensive loss, net of tax		(53	.4)		(53	.4)

Total stockholder’s equity		1,116	.1		919	.9


TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	3,147	.2	$	2,775	.2

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

OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)

	Three Months Ended September 30,		Nine Months Ended September 30,
(In millions)	2004	2003	2004	2003

OPERATING REVENUES	$	535	.9	$	540	.3	$	1,251	.7	$	1,230	.9

COST OF GOODS SOLD*		280	.9		266	.1		707	.3		667	.0

Gross margin on revenues		255	.0		274	.2		544	.4		563	.9
Other operation and maintenance		65	.7		71	.5		208	.7		218	.3
Depreciation		30	.2		29	.9		92	.4		91	.7
Taxes other than income		11	.7		12	.0		36	.2		35	.7

OPERATING INCOME		147	.4		160	.8		207	.1		218	.2


OTHER INCOME (EXPENSE)
Other income		3	.5		-	--		4	.8		0	.5
Other expense		(0	.1)		(0	.9)		(1	.3)		(2	.1)

Net other income (expense)		3	.4		(0	.9)		3	.5		(1	.6)


INTEREST INCOME (EXPENSE)
Interest income		0	.2		0	.4		0	.4		0	.5
Interest on long-term debt		(9	.3)		(9	.1)		(27	.4)		(27	.8)
Allowance for borrowed funds used during construction		0	.9		0	.1		1	.2		0	.5
Interest on short-term debt and other interest charges		(0	.5)		(0	.9)		(2	.0)		(2	.7)

Net interest expense		(8	.7)		(9	.5)		(27	.8)		(29	.5)


INCOME BEFORE TAXES		142	.1		150	.4		182	.8		187	.1

INCOME TAX EXPENSE		50	.8		55	.3		61	.1		67	.4


NET INCOME	$	91	.3	$	95	.1	$	121	.7	$	119	.7


* Before intercompany eliminations.

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

OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)

	Nine Months Ended September 30,
(In millions)	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	121	.7	$	119	.7
Adjustments to reconcile net income to net cash provided from
operating activities
Depreciation		92	.4		91	.7
Deferred income taxes and investment tax credits, net		20	.4		79	.0
Gain on sale of assets		(3	.0)		-	--
Other assets		(40	.8)		(17	.3)
Other liabilities		(0	.3)		3	.8
Change in certain current assets and liabilities
Accounts receivable - customers, net		(20	.7)		(89	.2)
Accounts receivable - other, net		(1	.9)		0	.6
Accrued unbilled revenues		(29	.8)		(30	.7)
Fuel, materials and supplies inventories		2	.2		4	.0
Fuel clause under recoveries		(44	.9)		(6	.6)
Other current assets		5	.3		4	.2
Accounts payable		(1	.9)		(1	.1)
Accounts payable - affiliates		69	.8		110	.8
Customers’ deposits		7	.9		1	.3
Accrued taxes		10	.4		9	.5
Accrued interest		2	.7		1	.4
Gas imbalance liability		0	.8		-	--
Fuel clause over recoveries		(32	.4)		-	--
Other current liabilities		6	.7		8	.9

Net Cash Provided from Operating Activities		164	.6		290	.0


CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(329	.8)		(114	.4)
Proceeds from sale of assets		3	.1		-	--

Net Cash Used in Investing Activities		(326	.7)		(114	.4)


CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		138	.6		-	--
Increase (decrease) in short-term debt, net		106	.6		(92	.0)
Dividends paid on common stock		(87	.1)		(78	.6)

Net Cash Provided from (Used in) Financing Activities		158	.1		(170	.6)


NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(4	.0)		5	.0
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		4	.0		0	.3

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	-	--	$	5	.3

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

OKLAHOMA GAS AND ELECTRIC COMPANY
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

1. Summary of Significant Accounting Policies

Organization

Oklahoma Gas and Electric Company (the “Company”) generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas and its operations are subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“FERC”). The Company is a wholly-owned subsidiary of OGE Energy Corp. (“Energy Corp.”), 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 was incorporated in 1902 under the laws of the Oklahoma Territory and is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area. The Company sold its retail gas business in 1928 and is no longer engaged in the gas distribution business.

Basis of Presentation

The Condensed 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 financial position of the Company at September 30, 2004 and December 31, 2003, the results of its operations for the three and nine months ended September 30, 2004 and 2003, and the results of its cash flows for the nine months ended September 30, 2004 and 2003, have been included and are of a normal recurring nature.

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

Accounting Records

The accounting records of the Company are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC.

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

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

The following table is a summary of the Company’s regulatory assets and liabilities at:

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

Regulatory Assets
Fuel clause under recoveries	$	48	.9	$	4	.0
Recoverable take or pay gas charges		32	.5		32	.5
Income taxes recoverable from customers, net		31	.0		31	.6
Unamortized loss on reacquired debt		21	.3		22	.1
Cogeneration capacity payments		6	.6		-	--
McClain Plant operating and maintenance expenses		4	.1		-	--
January 2002 ice storm		1	.8		3	.6
Miscellaneous		0	.7		0	.4

Total Regulatory Assets	$	146	.9	$	94	.2


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

Total Regulatory Liabilities	$	129	.5	$	149	.7

Fuel clause under recoveries are generated from under recoveries from the Company’s customers when the Company’s cost of fuel exceeds the amount billed to its customers. Fuel clause over recoveries are generated from over recoveries from the Company’s customers when the amount billed to its customers exceeds the Company’s cost of fuel. The Company’s fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers’ bills. As a result, the Company under recovers fuel cost in periods of rising prices above the baseline

charge for fuel and over recovers fuel cost when prices decline below the baseline charge for fuel. Provisions in the fuel clauses allow the Company to amortize under or over recovery.

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

Income taxes recoverable from customers represent income tax benefits previously used to reduce the Company’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 Balance Sheets in the line item, “Income Taxes Recoverable from Customers, Net.”

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

Cogeneration capacity payments relate to customer savings of approximately $1.0 million per month that began in January 2004 to reflect the expiration of the PowerSmith Cogeneration Project, L.P. (“PowerSmith”) contract in August 2004. These customer savings relate to the period from January to August 2004. The Company started recovering this regulatory asset beginning in September and the remaining balance of approximately $6.6 million will be recovered in the fourth quarter pursuant to filed tariffs.

As a result of the McClain Plant acquisition (further discussed in Note 11) completed on July 9, 2004, the Company has the right to accrue a regulatory asset, for a period not to exceed 12 months subsequent to the acquisition and operation of the McClain Plant, consisting of the non-fuel operation and maintenance expenses, depreciation, cost of debt associated with the investment and ad valorem taxes. All prudently incurred costs accrued through the regulatory asset within the 12-month period would be included in the Company’s prospective cost of service and would be recovered over a period to be determined by the OCC.

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

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

Income Taxes

The Company is a member of an affiliated group that files consolidated income tax returns. Income taxes are allocated to each company in the affiliated group based on its separate taxable income or loss. Federal investment tax credits on electric utility property have been deferred and are being amortized to income over the life of the related property. Amortization of the federal investment tax credits was approximately $1.3 million for each of the three month periods ended September 30, 2004 and 2003 and was approximately $3.9 million for each of the nine month periods ended September 30, 2004 and 2003 and are recorded as income tax benefits in the Condensed Statements of Income. During the nine months ended September 30, 2004, the Company recorded Oklahoma state tax credits of approximately $2.2 million, which are recorded as income tax benefits in the Condensed Statements of Income.

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

Related Party Transactions

Energy Corp. allocated operating costs to the Company of approximately $20.3 million and $21.0 million during the three months ended September 30, 2004 and 2003, respectively, and allocated approximately $65.2 million and $63.4 million during the nine months ended September 30, 2004 and 2003, respectively. Energy Corp. allocates operating costs to its affiliates based on several factors. Operating costs directly related to specific affiliates are assigned to those affiliates. When 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.

During the three months ended September 30, 2004 and 2003, the Company paid its affiliate Enogex Inc. and subsidiaries (“Enogex”) approximately $8.6 million and $8.5 million, respectively, for transporting gas to the Company’s natural gas-fired generating facilities. During the nine months ended September 30, 2004 and 2003, the Company paid Enogex approximately $25.6 million and $25.0 million, respectively, for transporting gas to the Company’s natural gas-fired generating facilities. During the three months ended September 30, 2004 and 2003, the Company paid Enogex approximately $5.0 million and $3.3 million, respectively, for natural gas storage services. During the nine months ended September 30, 2004 and 2003, the Company paid Enogex approximately $12.1 million and $8.0 million, respectively, for natural gas storage services. During the three months ended September 30, 2004 and 2003, the Company also recorded natural gas purchases from Enogex of approximately $14.2 million and $1.8 million, respectively. During the nine months ended September 30, 2004 and 2003, the Company

recorded natural gas purchases from Enogex of approximately $33.5 million and $20.8 million, respectively. Approximately $3.8 million was recorded at September 30, 2004 and is included in Accounts Payable – Affiliates in the Condensed Balance Sheets for these activities. There were no amounts recorded for these activities at December 31, 2003.

During the three months ended September 30, 2004, the Company recorded interest income of approximately $0.1 million from Energy Corp. for advances made by the Company. The Company made no advances to Energy Corp. for the three months ended September 30, 2003. During the nine months ended September 30, 2004, the Company recorded interest income of approximately $0.2 million from Energy Corp. for advances made by the Company to Energy Corp. The Company made no advances to Energy Corp. for the nine months ended September 30, 2003.

During the three months ended September 30, 2004 and 2003, the Company recorded interest expense of approximately $0.4 million and $0.3 million, respectively, to Energy Corp. for advances made by Energy Corp. to the Company. During the nine months ended September 30, 2004 and 2003, the Company recorded interest expense of approximately $0.5 million and $1.1 million, respectively, to Energy Corp. for advances made by Energy Corp. to the Company. The interest rate charged on advances to the Company from Energy Corp. approximates Energy Corp.’s commercial paper rate.

During the three months ended September 30, 2004 and 2003, the Company paid approximately $29.1 million and $26.3 million, respectively, in dividends to Energy Corp. During the nine months ended September 30, 2004 and 2003, the Company paid approximately $87.1 million and $78.6 million, respectively, in dividends to Energy Corp.

Reclassifications

Certain prior year amounts have been reclassified on the Condensed Financial Statements to conform to the 2004 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. The scope of SFAS No. 143 includes the Company’s accrued plant removal costs for generation, transmission and distribution assets. SFAS No. 143 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. Asset 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. 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 (except as discussed below) 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. During the third quarter of 2004, the Company determined that it had a legal obligation within the scope of SFAS No. 143 to retire certain assets related to the expiration of a power supply contract in June 2006. The Company recorded an asset retirement obligation of approximately $1.1 million at September 30, 2004 and plans to amortize this amount for 21 months beginning October 1, 2004.

3. Price Risk Management Assets and Liabilities

The Company periodically utilizes derivative contracts to reduce exposure to adverse interest rate fluctuations. During the three and nine months ended September 30, 2004 and 2003, the Company’s use of price risk management instruments involved the use of an interest rate swap agreement. This agreement involved the exchange of fixed price or rate payments in exchange for floating price or rate payments over the life of the instrument without an exchange of the underlying principal amount.

In accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, the Company recognizes all of its derivative instruments as Price Risk Management assets or liabilities in the Condensed Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation. For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative instrument is recognized in current earnings on the same line item as the gain or loss recorded for the change in the fair value of the hedged item. For derivatives that are designated and qualify as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of Accumulated Other Comprehensive Income and recognized into earnings in the same period during which the hedged transaction affects earnings. The ineffective portion of a derivative’s change in fair value is recognized currently in earnings. As a matter of policy, all hedged items and the derivatives used for cash flow hedges must be identical with respect to time and location and must be in compliance with SFAS No. 133. Forecasted transactions designated as the hedged item in a cash flow hedge are regularly evaluated to assess whether they continue to be probable of occurring. If the forecasted transactions are no longer probable of occurring, hedge accounting will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings. Any amounts recorded in Accumulated Other Comprehensive Income will remain in other comprehensive income until such time as the forecasted transaction is deemed probable not to occur.

The Company’s interest rate swap agreement has been designated as a fair value hedge 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. See Note 7 for a description of the Company’s interest rate swap agreement.

4. Accumulated Other Comprehensive Loss

There were no items of other comprehensive income for the three and nine months ended September 30, 2004 and 2003. Accumulated other comprehensive loss at both September 30, 2004 and December 31, 2003 is comprised of approximately a $53.4 million after tax loss ($87.1 million pre-tax) related to a minimum pension liability adjustment based on a review of the funded status of Energy Corp.’s pension plan by Energy Corp.’s actuarial consultants as of December 31, 2003. Any increases or decreases in the minimum pension liability will be reflected in Other Comprehensive Income or Loss in the fourth quarter.

5. Asset Disposals

In September 2004, the Company sold its interests in its natural gas producing properties for approximately $3.1 million. These interests had a carrying value of approximately $0.1 million and the Company recognized a gain of approximately $3.0 million, which is recorded in Other Income in the Condensed Statements of Income.

6. Supplemental Cash Flow Information

Non-cash financing activities for the nine months ended September 30, 2004 and 2003 included approximately a $0.1 million increase and approximately a $0.9 million decrease, respectively, related to the change in fair value of long-term debt due to an interest rate swap agreement.

7. Long-Term Debt

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

Long-Term Debt with Optional Redemption Provisions

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

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


SERIES	DATE DUE		AMOUNT

Variable %	Garfield Industrial Authority, January 1, 2025	$	47	.0
Variable %	Muskogee Industrial Authority, January 1, 2025		32	.4
Variable %	Muskogee Industrial Authority, June 1, 2027		56	.0

Total (redeemable during next 12 months)		$	135	.4

All of these Bonds are subject to redemption at the option of the holders, at 100 percent of the principal amount, together with accrued and unpaid interest to the date of purchase. The bond holders, on any business day, can request repayment of the Bond by delivering an irrevocable notice to the tender agent stating the principal amount of the Bond, payment instructions for the purchase price and the business day the Bond is to be purchased. The repayment option may only be exercised by the holder of a Bond for the principal amount. A third party remarketing agent for the Bonds will attempt to remarket any Bonds tendered for purchase. Since the original issuance of these series of Bonds in 1995 and 1997, the remarketing agent has successfully remarketed all tendered bonds. If the remarketing agent is unable to remarket any such Bonds, the Company is obligated to repurchase such unremarketed Bonds. The Company has sufficient liquidity to meet these obligations.

Interest Rate Swap Agreement

Fair Value Hedge

At September 30, 2004 and December 31, 2003, the Company had one outstanding interest rate swap agreement that qualified as a fair value hedge 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. The objective of this interest rate swap 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. This interest rate swap qualified as a fair value hedge under SFAS No. 133 and met all of the requirements for a determination that there was no ineffective portion as allowed by the shortcut method under SFAS No. 133.

At September 30, 2004 and December 31, 2003, the fair values pursuant to the interest rate swap were approximately $4.1 million and $4.0 million, respectively, and the hedge was classified as Deferred Charges and Other Assets – Price Risk Management in the Condensed Balance Sheets. A corresponding net increase of approximately $4.1 million and $4.0 million was reflected in Long-Term Debt at September 30, 2004 and December 31, 2003, respectively, as this fair value hedge was effective at September 30, 2004 and December 31, 2003.

8. Short-Term Debt

In December 2003, the Company issued commercial paper in anticipation of the planned acquisition of the McClain Plant by the end of 2003 and the short-term debt balance was approximately $50.0 million at December 31, 2003. Due to a delay in the completion of the McClain Plant acquisition, the Company transferred these funds to Energy Corp. for investment and at December 31, 2003, the Company had approximately $51.8 million in outstanding

advances to Energy Corp. Due to the delay in the completion of the McClain Plant acquisition, Energy Corp. repaid the outstanding advances and the Company used these funds to repay the outstanding commercial paper balance during the first quarter of 2004. At September 30, 2004, the Company had approximately $48.1 million in outstanding advances to Energy Corp.

The following table shows Energy Corp.’s and the Company’s lines of credit in place and available cash at September 30, 2004. Energy Corp.’s short-term borrowings could include a combination of bank borrowings and commercial paper.

Lines of Credit and Available Cash (In millions)

Entity	Amount Available		Amount Outstanding		Maturity

Energy Corp.		$ 15.0		$ ---	April 6, 2005
The Company (A)		100.0		---	December 9, 2004
Energy Corp. (A)		300.0		---	December 9, 2004

		415.0		---
Cash		28.1		N/A	N/A

Total		$ 443.1		$ ---

(A) These lines of credit are used to back up Energy Corp.’s commercial paper borrowings, which were approximately $10.2 million at September 30, 2004.

On October 20, 2004, Energy Corp. and the Company entered into revolving credit agreements totaling $550 million. These agreements, which include two separate credit facilities, one for Energy Corp. in an amount up to $450 million and one for the Company in an amount up to $100 million, replaced Energy Corp.’s and the Company’s current credit facilities in the table above that were to expire on December 9, 2004. Each of the new credit facilities has a five-year term with two options to extend the term for one year. For the Company’s credit facility, the Company filed an application to issue securities with the OCC in September 2004 and received approval of this transaction in October 2004.

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

The Company must obtain regulatory approval from the FERC in order to borrow on a short-term basis. The Company has the necessary regulatory approvals to incur up to $400 million in short-term borrowings at any one time. In October 2004, the Company filed an application with the FERC to request a two-year renewal of its current regulatory approval to incur up to $400 million in short-term borrowings at any one time. The Company’s current short-term borrowing authorization expires December 31, 2004.

9. Retirement Plans and Postretirement Benefit Plans

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

The details of net periodic benefit cost related to Energy Corp.’s pension plan and postretirement benefit plans included in the Condensed Financial Statements is as follows:

Net Periodic Benefit Cost


	Pension Plan
	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)		2004			2003			2004			2003

Service cost	$	2	.8	$	2	.5	$	8	.4	$	7	.7
Interest cost		6	.1		6	.1		18	.3		18	.4
Return on plan assets		(6	.4)		(5	.0)		(19	.1)		(14	.9)
Amortization of net loss		2	.5		2	.8		7	.3		8	.2
Amortization of unrecognized prior service cost		1	.3		1	.3		3	.9		3	.8

Net periodic benefit cost	$	6	.3	$	7	.7	$	18	.8	$	23	.2


	Postretirement Benefit Plans
	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)		2004			2003			2004			2003

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

Net periodic benefit cost	$	3	.7	$	3	.4	$	11	.2	$	10	.1

Pension Plan Funding

approximately $54.5 million was allocated to the Company. The contributions to the pension plan, in the form of cash, were discretionary contributions and were not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974.

Medicare Prescription Drug, Improvement and Modernization Act of 2003

On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Medicare Act”). The Medicare Act expanded Medicare to include, for the first time, coverage for prescription drugs. Due to various uncertainties related to Energy Corp.’s response to this legislation in relation to its postretirement medical plan and the appropriate accounting methodology for this event, Energy Corp. elected to defer financial recognition of this legislation until the FASB issued final accounting guidance. This deferral election was permitted under FASB Staff Position No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” In May 2004, the FASB issued FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” FAS 106-2 provides guidance on the accounting for the effects of the Medicare Act for employers that sponsor postretirement heath care plans that provide prescription drug benefits. FAS 106-2 also requires those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Medicare Act. For employers who elected to defer financial recognition, FAS 106-2 provides two alternative methods of adoption which include a retroactive application to the date of the Medicare Act’s enactment or a prospective application as of the date of adoption. For employers who elected not to defer financial recognition, FAS 106-2 requires these employers to recognize a cumulative effect of a change in accounting principle in accordance with Accounting Principles Board Opinion No. 20, “Accounting Changes.” Adoption of FAS 106-2 is required for financial statements issued for periods beginning after June 15, 2004. Energy Corp. adopted this new standard effective July 1, 2004 with retroactive application to the date of the Medicare Act’s enactment. Management expects that the accumulated plan benefit obligation (“APBO”) for Energy Corp.’s postretirement medical plan will be reduced by approximately $13.3 million as a result of savings to Energy Corp.’s postretirement medical plan resulting from the Medicare Act, which will reduce Energy Corp.’s costs for its postretirement medical plan by approximately $2.5 million annually, of which approximately $2.1 million is allocated to the Company. The $2.1 million in annual savings is comprised of a reduction of approximately $1.2 million from amortization of the $13.3 million gain due to the reduction of the APBO, a reduction in the interest cost on the APBO of approximately $0.7 million and a reduction in the service cost due to the subsidy of approximately $0.2 million.

10. Commitments and Contingencies

Except as set forth in Note 11, the circumstances set forth in Note 11 to the Company’s Financial Statements included in the Company’s Form 10-K for the year ended December 31, 2003 and in Note 9 to the Company’s Condensed Financial Statements included in the Company’s Form 10-Q for the quarters ended March 31, 2004 and June 30, 2004,

appropriately represent, in all material respects, the current status of any material commitments and contingent liabilities.

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

11. Rate Matters and Regulation

The Company’s retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by the Company is also regulated by the OCC and the APSC. The Company’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 the Company’s facilities and operations.

Recent Regulatory Matters

2002 Settlement Agreement

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

in annual net profits from off-system sales, gave approximately $3.6 million in annual net profits from off-system sales to its Oklahoma customers and currently, the net profits from off-system sales have exceeded the $5.4 million and are being shared with 80 percent to the Company’s Oklahoma customers and the remaining 20 percent to the Company.

OCC Order Confirming Savings

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

Recent Acquisition of Power Plant

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

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

The final approval the Company had been waiting for was the approval from the FERC. On July 2, 2004, the FERC authorized the Company to acquire the McClain Plant. The FERC’s approval was based on an offer of settlement the Company filed in a proceeding on

March 8, 2004. Under the offer of settlement, the Company proposed, among other things, to install certain new transmission facilities and to hire an independent market monitor to oversee the Company’s activity for a limited period. Two other parties, InterGen Services, Inc. and AES Shady Point, opposed the Company’s offer of settlement and filed competing settlement offers. In the July 2, 2004 order, the FERC: (i) approved the Company’s offer of settlement subject to conditions; (ii) rejected the competing offers of settlement; and (iii) approved the Company’s acquisition of the McClain Plant. As part of the July 2, 2004 order, the Company agreed to undertake the following mitigation measures: (i) install transformers at two of its facilities at a cost of approximately $18.5 million; (ii) upgrade one transmission line in the Company’s local service territory; (iii) hire an independent market monitor to oversee the Company’s activity in its control area; and (iv) provide a 600 MW bridge into its control area from the Redbud plant. On October 13, 2004, the independent market monitor filed its first report with the FERC. The market monitoring plan is designed to detect any anticompetitive conduct by the Company from operation of its generation resources or its transmission system. The market monitoring function is performed daily and periodic reviews are also performed with any findings reported to the FERC. The purpose of this first report is to provide an account of monitoring activities and significant events on the Company’s system during the period from July 10, 2004 to September 30, 2004. During this period, transmission congestion data on the Company’s system, along with data on purchases and sales, generation dispatch data and power flows on the Company’s tie lines were analyzed. The market monitor concluded that the Company did not act in an anticompetitive manner through either dispatch of its generation or operation of its transmission system. Additionally, the Company’s operations under the ongoing mitigation measures that require the Company to make available transmission capability available to the Redbud power plant for access to the Company system were analyzed. Based on this analysis, the market monitor concluded that the Company has complied with this requirement. The Company expects to complete the installation and implementation of these measures by June 2005. One party has filed a request for rehearing of the FERC’s July 2, 2004 order. The outcome of that request for rehearing cannot be determined at this time.

The Company is operating the plant in accordance with a joint ownership and operating agreement with the OMPA. Under this agreement, the Company operates the facility, and the Company and the OMPA are entitled to the net available output of the plant based on their respective ownership percentages. All fixed and variable costs, except fuel and gas transportation costs, are shared in proportion to the respective ownership interests. Fuel and gas transportation costs are paid in accordance with each individual owner’s respective transportation contract and consumption. The Company expects to utilize its portion of the output, 400 MWs, to serve its native load. As a result, the Company expects to file with the OCC a request to increase its rates to its Oklahoma customers to recover, among other things, its investment in, and the operating expenses of, the McClain Plant no later than July 8, 2005. The Company expects to file a rate case by mid-year 2005 using 2004 as a test year with new approved rates expected to be in effect by the first quarter of 2006. As provided in the Settlement Agreement, until the Company seeks and obtains approval of a request to increase base rates to recover, among other things, the investment in the plant, the Company will have the right to accrue a regulatory asset, for a period not to exceed 12 months subsequent to the acquisition and operation of the McClain Plant, consisting of the non-fuel operation and maintenance expenses, depreciation, cost of debt associated with the investment and ad valorem taxes. If the OCC were

to approve the Company’s request, all prudently incurred costs accrued through the regulatory asset within the 12-month period would be included in the Company’s prospective cost of service and would be recovered over a period to be determined by the OCC.

The Company temporarily funded the McClain Plant acquisition with short-term borrowings from Energy Corp. On August 4, 2004, the Company issued $140.0 million of long-term debt to replace these short-term borrowings. Also, on August 9, 2004, Energy Corp. made a capital contribution to the Company of approximately $153.0 million.

The Company expects the acquisition of the McClain Plant, including the effects of an interim power purchase agreement the Company had with NRG McClain LLC while the Company was awaiting regulatory approval to complete the acquisition, will provide savings, over a three-year period, in excess of $75.0 million to its Oklahoma customers. These savings will be derived from: (i) the avoidance of purchase power contracts otherwise needed; (ii) an above market cogeneration contract with PowerSmith when it terminated at the end of August 2004; and (iii) fuel savings associated with operating efficiencies of the new plant. These savings, while providing real savings to Oklahoma customers, are not expected to affect the Company’s profitability because its rates are not expected to be reduced to accomplish these savings. In the event the Company is unable to demonstrate at least $75.0 million in savings to its customers during this 36-month period, the Company will be required to credit its Oklahoma customers any unrealized savings below $75.0 million as determined at the end of the 36-month period ending December 31, 2006. At this time, the Company believes that it will be able to demonstrate at least $75.0 million in savings during this period.

Contract with PowerSmith

In September 2003, PowerSmith filed an application with the OCC seeking to compel the Company to continue purchasing power from PowerSmith’s qualified cogeneration facility under the Public Utility Regulatory Policy Act of 1978 at a price that would include an avoided capacity charge equal to the avoided cost of the McClain Plant. On June 7, 2004, the Company and PowerSmith signed a 15-year power sales agreement under which the Company would contract to purchase electric power from PowerSmith. On August 27, 2004, the new 15-year power sales agreement was approved by the OCC and became effective September 1, 2004. The Company’s ability to meet its guarantee of customer savings of at least $75 million over three years is not expected to be materially affected by this new agreement to purchase electric power from PowerSmith.

Pending Regulatory Matters

Currently, the Company has two significant matters pending at the OCC: (i) a review of the process completed by the Company in its selection of gas transportation and storage services to meet its system operating needs; and (ii) security investments on the Company’s system. These matters, as well as several other pending matters, are discussed below.

Gas Transportation and Storage Agreement

As part of the Settlement Agreement, the Company also agreed to consider competitive bidding for gas transportation service to its natural gas-fired generation facilities pursuant to the terms set forth in the Settlement Agreement. The prescribed bidding process detailed in the Settlement Agreement provided that each generation facility bid separately for the services required. The Company believes that in order for it to achieve maximum coal generation, which delivers the lowest cost energy to its customers, and ensure reliable electric service, it must have integrated, firm no-notice load following service for both gas transportation and gas storage. This type of service is required to satisfy the daily swings in customer demand placed on the Company’s system and still permit natural gas units to not impede coal energy production. The Company also believes that gas storage is an integral part of providing gas supply to the Company’s generation facilities. Accordingly, the Company evaluated its competitive bid options in light of these circumstances. The Company’s evaluation clearly demonstrates that the Enogex integrated gas system provides superior integrated, firm no-notice load following service to the Company that is not available from other companies serving the Company marketplace. On April 29, 2003, as required by the Settlement Agreement, the Company filed an application with the OCC in which the Company advised the OCC that, after careful consideration, competitive bidding for gas transportation was rejected in favor of a new intrastate integrated, firm no-notice load following gas transportation and storage services agreement with Enogex. This seven-year agreement provides for gas transportation and storage services for each of the Company’s natural gas-fired generation facilities at an annual cost of approximately $46.8 million. During the three months ended September 30, 2004 and 2003, the Company paid Enogex approximately $13.6 million and $11.8 million, respectively, for gas transportation and storage services. During the nine months ended September 30, 2004 and 2003, the Company paid Enogex approximately $37.7 million and $33.0 million, respectively, for gas transportation and storage services. Based upon requests for information from intervenors, the Company requested from Enogex and Enogex retained a “cost of service” consultant to assist in the preparation of testimony related to this case. On January 30, 2004, the OCC issued a procedural schedule for this case. On March 31, 2004, the Company filed testimony and exhibits with the OCC, which completed the initial documentation required to be filed in this case. On July 12, 2004, several parties filed responsive testimony reflecting various positions on the issues related to this case. In particular, the testimony of the OCC Staff recommended that the Company be entitled to recover the $46.8 million requested, which results in no refund, and also recommended that the Company provide at its next general rate review the results of an open competitive bidding process or a comprehensive market study. If the Company does not provide such open bidding or market study, the OCC Staff recommendation would cap recovery at approximately $40 million at the Company’s next general rate review. The recommendations in the testimony of the Attorney General’s office and the Oklahoma Industrial Energy Consumers (“OIEC”) would cap recovery at approximately $35 million and $30 million, respectively, with the difference between what the Company has been collecting through its automatic fuel adjustment clause and these recommended amounts being refunded to customers. On July 26, 2004, the OCC issued a new procedural schedule. The Company filed rebuttal testimony on August 16, 2004 in this case. Hearings in this case before an administrative law judge occurred from September 16-22, 2004. On October 22, 2004, the administrative law judge overseeing the proceeding recommended approximately $41.9 million annual recovery with the Company refunding to its customers any

amounts collected in excess of this amount. If this recommendation is ultimately accepted, the Company believes its refund obligation would be approximately $6.1 million, which the Company does not believe is material in light of previously established reserves. The Company believes the amount currently paid to Enogex for integrated, firm no-notice load following transportation and storage services is fair, just and reasonable. The Company appealed the administrative law judge’s recommendation on November 1 and a hearing in this case is currently scheduled for November 19. An OCC order in the case is expected by the end of 2004.

Security Enhancements

On April 8, 2002, the Company filed a joint application with the OCC requesting approval for security investments and a rider to recover these costs from the ratepayers. On August 14, 2002, the Company filed testimony with the OCC outlining proposed expenditures and related actions for security enhancement and a proposed recovery rider. Attempting to make security investments at the proper level, the Company 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 the Company that might be caused by an attack and accomplish these efforts with minimal impact on ratepayers. The OCC Staff retained a security expert to review the report filed by the Company. On July 13, 2004, the security expert filed testimony that recommended: (i) $19.0 million in capital expenditures and $2.5 million annually in operating and maintenance expenses are justified to enhance the security of the Company’s infrastructure; and (ii) a security rider should be authorized to recover costs as these projects are completed. On August 4, 2004, the Company filed responsive testimony that quantified the minimal customer impact and revised its request for security investments so that it was consistent with the OCC Staff’s recommendations. On August 13, 2004, the only intervening party, the OIEC, filed a statement of position which supported the OCC Staff’s recommendations. On October 28, 2004, all parties signed a joint stipulation that contains the OCC Staff’s recommendations and authorizes a $5 million annual recovery from the Company’s customers for security enhancement. The hearing in this case is currently scheduled for November 9-11, 2004 and an OCC order in the case is expected in early 2005.

On October 17, 2003, the OCC filed a notice of inquiry to consider the issues related to the role of the OCC and Oklahoma regulated companies in addressing the security of the utility system infrastructure and key assets. On March 4, 2004, the OCC deliberated the notice of inquiry and directed the OCC Staff to file a rulemaking proceeding for each utility industry regarding security of the utility system infrastructure and key assets. On August 27, 2004, the OCC Staff filed a Notice of Proposed Rulemaking. The first technical conference was held on September 23, 2004 and written comments were filed by all the parties on October 1, 2004. A second technical conference was held on October 21, 2004 and a hearing is currently scheduled for December 3, 2004.

Cogeneration Credit Rider

On September 17, 2004, the Company filed an application and testimony with the OCC requesting a cogeneration credit rider. The requested rider would reduce charges to customers

because of decreasing cogeneration payments made by the Company beginning January 2005. The cogeneration credit rider is necessary as amounts recovered from customers in base rates include historically higher cogeneration payments. The Company’s current cogeneration credit rider expires December 31, 2004. On October 29, 2004, the OCC Staff and other parties filed responsive testimony. Hearings in this case are scheduled from November 15-17, 2004. An OCC order is expected by the end of 2004 regarding the new cogeneration credit rider.

Southwest Power Pool

The Company is a member of the Southwest Power Pool (“SPP”), the regional reliability organization for all or parts of Oklahoma, Arkansas, Kansas, Louisiana, New Mexico, Mississippi, Missouri and Texas. The Company participated with the SPP in the development of regional transmission tariffs and executed an Agency Agreement with the SPP to facilitate interstate transmission operations within this region in 1998. In October 2003, the SPP filed an application with the FERC seeking authority to form a regional transmission organization (“RTO”). On February 10, 2004, the FERC conditionally approved the SPP’s application. The SPP must meet certain conditions before it may commence operations as an RTO. On April 27, 2004, the SPP Board of Directors took actions to meet the conditions to satisfy the FERC requirement for formal approval of the RTO. The SPP compliance filing at the FERC was made on May 3, 2004. In response to a subsequent FERC order on July 2, 2004, the SPP made a compliance filing on August 6, 2004 stating that all requirements had been met to achieve RTO status. In a FERC order dated October 1, 2004, the FERC accepted the SPP’s compliance filing and the SPP was granted RTO status, subject to the SPP submitting a further compliance filing, within 30 days. On November 1, 2004, the SPP made a compliance filing as required under the October 1 FERC order. Also, on November 1, the SPP filed a request for rehearing of the FERC’s October 1 order.

FERC Standards of Conduct

On November 25, 2003, the FERC issued new rules regulating the relationships between electric and natural gas transmission providers, as defined in the rules, and those entities’ merchant personnel and energy affiliates. The new rules will replace the existing rules governing these relationships. The new rules expand the definition of “affiliate” and further limit communications between transmission providers and those entities’ merchant personnel and energy affiliates.

In February 2004, the Company and Enogex submitted plans and schedules to the FERC which detail the necessary actions to be in compliance with these new rules and expected that their initial costs to comply with the final rules would not exceed $1.6 million in 2004. On April 16, 2004 and August 2, 2004, the FERC issued orders on rehearing in which the FERC largely rejected requests to revise its November 25 final rule. However, the FERC did extend the compliance date until September 22, 2004 and did clarify certain aspects of the rule. The Company and Enogex believe that they have taken the necessary actions to comply with the new rules and estimate that the initial costs of compliance incurred in the first nine months of 2004 were less than $0.5 million and the recurring cost of compliance in future years is expected to be immaterial to Energy Corp.

Department of Energy Blackout Report

On April 6, 2004, the U.S. Department of Energy issued its final report regarding the August 14, 2003 electric blackout in the eastern United States, which did not have an adverse affect on the Company’s electric system. The report recommends a number of specific changes to current statutes, rules or practices in order to improve the reliability of the infrastructure used to transmit electric power. The recommendations include the establishment of mandatory reliability standards and financial penalties for noncompliance. On April 14, 2004, the FERC issued a policy statement requiring electric utilities, including the Company, to submit a report on vegetation management practices and indicating the FERC’s intent to make North American Electric Reliability Council reliability standards mandatory. On June 17, 2004, the Company filed its report on vegetation management practices with the FERC. During 2004, the Company has spent less than $0.2 million related to the implementation of blackout report recommendations. Implementation of the blackout report recommendations and the FERC policy statement could increase future transmission costs, but the extent of the increased costs is not known at this time.

Redbud Tariff Filing

On March 5, 2004, Redbud Energy LP (“Redbud”) filed a rate schedule with the FERC in Docket No. ER04-622-000 under which Redbud proposed to charge the Company a rate for transmission service Redbud alleges it provides to the Company over certain facilities that Redbud constructed to connect its generation facility to the Company transmission grid. Redbud claims that the facilities cost approximately $19.3 million, and seeks to recover this amount from the Company over a 60-month period. Also on March 5, 2004, Redbud filed an application with the FERC in Docket No. EG04-38-000 asking the FERC to rule that Redbud can charge the Company this fee for transmission service and remain an exempt wholesale generator under Section 32 of the Public Utility Holding Company Act of 1935. The Company opposed Redbud’s filings in the two dockets on the grounds that Redbud is not entitled to impose such a transmission rate, and that the imposition of such a rate is inconsistent with Redbud’s status as an exempt wholesale generator. On May 4, 2004, the FERC issued an order rejecting Redbud’s proposed rate schedule. Redbud has since asked the FERC to rehear and reverse its May 4 order rejecting Redbud’s filing. At this time, the Company does not know when the FERC will rule on Redbud’s request for rehearing. On November 1, 2004, the FERC issued an order denying Redbud’s request for rehearing. Redbud has 60 days to file a petition for review with the FERC.

State Legislative Initiatives

Oklahoma

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

In the 2004 legislative session, legislation was enacted requiring a study to determine the feasibility of providing investor-owned utilities an incentive to enter into purchase power agreements in Oklahoma by allowing the utilities to earn a return on purchased power. The study committee held its first meeting in late August and will continue holding two meetings a month through November. At the conclusion of the meetings, a final report with any recommendations will be filed with the legislature in January 2005.

Arkansas

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

In the 2003 legislative session, legislation was enacted requiring a study relating to the restructuring of the electric utility industry at the industrial level to provide customer choice of electricity providers for large customers. A roundtable discussion regarding the study was held on July 22, 2004 and comments were filed on August 20, 2004. The APSC released the report on September 30, 2004 and the Insurance and Commerce Committee heard the issue on October 20, 2004. The commissioners concluded that circumstances in the current electric generation market have not changed sufficiently since adoption of Act 204 (The Electric Utility Regulatory Reform Act of 2003) to be able to structure a large user access program that would produce economic benefits for large users while also ensuring no cost-shifting or net cost increases to remaining customers. The commissioners also concluded that there are no clear economic benefits, and more likely economic harm, that would result from moving forward with the large user access program concept at this time.

12. Fair Value of Financial Instruments

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

	September 30, 2004						December 31, 2003
(In millions)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Price Risk Management Assets
Interest Rate Swaps	$	4	.1	$	4	.1	$	4	.0	$	4	.0
Long-Term Debt
Senior Notes	$	711	.9	$	766	.3	$	571	.8	$	611	.8

The carrying value of the financial instruments on the Condensed 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 swap was determined primarily based on quoted market prices. The fair value of the Company’s long-term debt is based on quoted market prices.

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

Introduction

Forward-Looking Statements

Except for the historical statements contained herein, the matters discussed in the following discussion and analysis, including the discussion in “Outlook”, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate”, “believe”, “estimate”, “expect”, “intend”, “objective”, “plan”, “possible”, “potential” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit, actions of rating agencies and their impact on capital expenditures; the Company’s and Energy Corp.’s ability to obtain financing on favorable terms; prices of electricity and natural gas; business conditions in the energy industry; competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company; unusual weather; federal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the Company’s markets; changes in accounting standards, rules or guidelines; creditworthiness of suppliers, customers and other contractual parties; and other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission, including Exhibit 99.01 to the Company’s Form 10-K for the year ended December 31, 2003.

Overview

General

The following discussion and analysis presents factors which affected the Company’s results of operations for the three and nine months ended September 30, 2004 as compared to the same period in 2003 and the Company’s financial position at September 30, 2004. The following information should be read in conjunction with the Condensed Financial Statements and Notes

thereto and the Company’s Form 10-K for the year ended December 31, 2003. Known trends and contingencies of a material nature are discussed to the extent considered relevant.

Summary of Operating Results

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

The Company reported net income of approximately $91.3 million as compared to approximately $95.1 million for the three months ended September 30, 2004 and 2003, respectively. The decrease in net income during the three months ended September 30, 2004 as compared to the same period in 2003 was primarily attributable to lower gross margins on revenues (“gross margin”) due to cooler weather in the Company’s service territory partially offset by a gain from the sale of assets, lower operating expenses, lower interest expenses and lower income tax expense.

Nine months ended September 30, 2004 as compared to nine months ended September 30, 2003

The Company reported net income of approximately $121.7 million as compared to approximately $119.7 million for the nine months ended September 30, 2004 and 2003, respectively. The increase in net income during the nine months ended September 30, 2004 as compared to the same period in 2003 was primarily attributable to a gain from the sale of assets, lower operating expenses, lower interest expenses and lower income tax expense partially offset by lower gross margins due to cooler weather in the Company’s service territory.

Regulatory Matters and Plant Acquisition

In November 2002, the OCC issued an order containing provisions of an agreed-upon settlement of the Company’s rate case. The terms of this settlement included, among other things, a $25.0 million annual reduction in electric rates and a requirement for the Company to acquire 400 megawatts (“MW”) of electric generation. On July 9, 2004, the Company completed its acquisition of a 77 percent interest in the 520 MW McClain Plant. The purchase price was approximately $160.0 million. The Company temporarily funded the McClain Plant acquisition with short-term borrowings from Energy Corp. On August 4, 2004, the Company issued $140.0 million of long-term debt to replace these short-term borrowings. For additional information regarding the McClain Plant acquisition and related regulatory matters, see Note 11 of Notes to Condensed Financial Statements.

Outlook

For 2004, Energy Corp. expects consolidated earnings to be near $1.60 per share. This estimate recognizes the impact of mild summer weather at the Company which had cooling degree days 14 percent below normal during the third quarter. The mild third quarter weather, as compared to normal, negatively impacted the Company’s revenues by approximately $20 million. The Company’s earnings range is now expected to be between $111 million and $115 million.

For 2005, Energy Corp.’s earnings guidance is $136 million to $145 million of net income, or $1.50 to $1.60 per share, assuming approximately 90.4 million average diluted shares outstanding. The Company’s contribution to consolidated earnings is projected to be $108 million to $112 million. The Company assumes that margin growth approximating two percent will be more than offset by increased operating expenses and higher interest costs associated with the acquisition of the McClain Plant and capital expenditures for investment in the Company’s generation, transmission and distribution system. The guidance further assumes no change in base rates and normal weather. The Company expects to file a rate case by mid-year 2005 to recover, among other things, its investment in, and the operating expenses of, the McClain Plant and expects new approved rates to be in effect by the first quarter of 2006. The earnings guidance also assumes a recovery of the costs associated with the Enogex natural gas transportation and storage services at a level consistent with a recent recommendation by the administrative law judge overseeing this proceeding. On October 22, 2004, the administrative law judge overseeing the proceeding recommended $41.9 million annual recovery with the Company refunding to its customers any amounts collected in excess of this amount. If this recommendation ultimately is accepted, the Company believes its refund obligation would be approximately $6.1 million, which Energy Corp. does not believe is material in light of previously established reserves. An OCC order in this case is expected by the end of 2004.

Results of Operations

	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2004			2003			2004			2003
Operating income	$	147	.4	$	160	.8	$	207	.1	$	218	.2
Net income		91	.3		95	.1		121	.7		119	.7

In reviewing its operating results, the Company believes that it is appropriate to focus on operating income as reported in its Condensed Statements of Income as operating income indicates the ongoing profitability of the Company excluding unusual or infrequent items, the cost of capital and income taxes. Operating income was approximately $147.4 million and $160.8 million for the three months ended September 30, 2004 and 2003, respectively. Operating income was approximately $207.1 million and $218.2 million for the nine months ended September 30, 2004 and 2003, respectively.

	Three Months Ended September 30,						Nine Months Ended September 30,
(Dollars in millions)	2004			2003			2004			2003
Operating revenues	$	535	.9	$	540	.3	$	1,251	.7	$	1,230	.9
Fuel		220	.1		181	.9		490	.9		448	.8
Purchased power		60	.8		84	.2		216	.4		218	.2

Gross margin on revenues		255	.0		274	.2		544	.4		563	.9
Other operation and maintenance		65	.7		71	.5		208	.7		218	.3
Depreciation		30	.2		29	.9		92	.4		91	.7
Taxes other than income		11	.7		12	.0		36	.2		35	.7

Operating income	$	147	.4	$	160	.8	$	207	.1	$	218	.2

Operating revenues by classification Residential	$	218	.7	$	243	.2	$	495	.3	$	508	.5
Commercial		134	.2		131	.4		309	.7		301	.6
Industrial		100	.4		86	.8		254	.0		224	.9
Public authorities		53	.3		49	.1		124	.4		115	.4
Sales for resale		17	.9		17	.5		44	.3		45	.6
Other		11	.2		11	.4		23	.5		31	.2

System sales revenues		535	.7		539	.4		1,251	.2		1,227	.2
Off-system sales revenues		0	.2		0	.9		0	.5		3	.7

Total operating revenues	$	535	.9	$	540	.3	$	1,251	.7	$	1,230	.9

MWH (A) sales by classification (in millions) Residential		2	.6		3	.0		6	.3		6	.6
Commercial		1	.7		1	.7		4	.4		4	.5
Industrial		1	.8		1	.7		5	.2		5	.0
Public authorities		0	.7		0	.8		2	.0		2	.0
Sales for resale		0	.4		0	.4		1	.1		1	.2

System sales		7	.2		7	.6		19	.0		19	.3
Off-system sales		-	--		-	--		-	--		0	.1

Total sales		7	.2		7	.6		19	.0		19	.4

Number of customers		733,2	43		724,5	49		733,2	43		724,5	49

Average cost of energy per KWH (B) - cents Fuel		3.2	44		2.7	59		2.8	91		2.6	07
Fuel and purchased power		3.6	35		3.2	93		3.4	62		3.2	27

Degree days (C) Heating
Actual		-	--			22		1,9	62		2,2	79
Normal			29			29		2,2	47		2,2	28
Cooling
Actual		1,1	20		1,3	25		1,7	60		1,8	03
Normal		1,2	95		1,2	95		1,8	50		1,8	50

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

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

The Company’s operating income for the three months ended September 30, 2004 decreased approximately $13.4 million or 8.3 percent as compared to the same period in 2003. The decrease in operating income was primarily attributable to cooler weather in the Company’s service territory and lower margins related to sales to wholesale customers. These decreases were partially offset by growth in the Company’s service territory, the timing of fuel recoveries and lower operating expenses.

Gross margin, which is operating revenues less cost of goods sold, was approximately $255.0 million for the three months ended September 30, 2004 as compared to approximately $274.2 million during the same period in 2003, a decrease of approximately $19.2 million or 7.0 percent. The gross margin decreased approximately $21.9 million due to cooler weather in the Company’s service territory and approximately $1.1 million due to lower margins related to sales to wholesale customers primarily resulting from reduced sales of power under a new wholesale contract with an existing customer. These decreases were partially offset by an increase of approximately $2.2 million due to growth in the Company’s service territory and an increase of approximately $1.9 million due to the timing of fuel recoveries.

Cost of goods sold for the Company consists of fuel used in electric generation and purchased power. Fuel expense was approximately $220.1 million for the three months ended September 30, 2004 as compared to approximately $181.9 million during the same period in 2003, an increase of approximately $38.2 million or 21.0 percent. The increase was due to an increase in the average cost of fuel per kwh, primarily due to higher natural gas prices, despite lower mwh sales. Purchased power costs were approximately $60.8 million for the three months ended September 30, 2004 as compared to approximately $84.2 million during the same period in 2003, a decrease of approximately $23.4 million or 27.8 percent. The decrease was primarily due to the Company’s acquisition of the McClain Plant in July 2004, lower volumes of purchased power and the termination of a power purchase contract in December 2003.

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 the Company’s customers through automatic fuel adjustment clauses. While the regulatory mechanisms for recovering fuel costs differ in Oklahoma, Arkansas and the FERC, in each jurisdiction the costs are passed through to customers and are intended to provide neither an ultimate benefit nor detriment to the Company. 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 the Company pays to Enogex. See Note 11 of Notes to Condensed Financial Statements for a discussion of current proceedings at the OCC regarding the Company’s gas transportation and storage contract with Enogex.

Operating and maintenance expenses decreased approximately $5.8 million or 8.1 percent for the three months ended September 30, 2004 as compared to the same period in 2003. This decrease was primarily due to a decrease of approximately $3.8 million in pension and benefit expense and a decrease of approximately $1.7 million in salaries and wages expense during the

three months ended September 30, 2004 as compared to the same period in 2003 due to more projects on which the costs are capitalized and are not being expensed currently. A contributing factor to the overall decrease in operating and maintenance expense was that a number of the Company’s employees provided assistance for hurricane restoration efforts in the southeastern United States and, as a result, were not available for Company projects. Also contributing to the decrease was a decrease of approximately $2.0 million in corporate allocations due to over allocations during the first six months of 2004. These decreases in operating and maintenance expense were partially offset by an increase of approximately $3.3 million in outside services expense primarily due to Southwest Power Pool (“SPP”) membership fees. Depreciation expense increased approximately $0.3 million or 1.0 percent for the three months ended September 30, 2004 as compared to the same period in 2003 primarily due to a higher level of depreciable plant. Taxes other than income decreased approximately $0.3 million or 2.5 percent for the three months ended September 30, 2004 as compared to the same period in 2003 primarily due to a decrease of approximately $0.2 million in ad valorem taxes.

Nine months ended September 30, 2004 as compared to nine months ended September 30, 2003

The Company’s operating income for the nine months ended September 30, 2004 decreased approximately $11.1 million or 5.1 percent as compared to the same period in 2003. The decrease in operating income was primarily attributable to cooler weather in the Company’s service territory, lower margins related to sales to wholesale customers and the timing of fuel recoveries. These decreases were partially offset by growth in the Company’s service territory and lower operating expenses.

Gross margin was approximately $544.4 million for the nine months ended September 30, 2004 as compared to approximately $563.9 million during the same period in 2003, a decrease of approximately $19.5 million or 3.5 percent. The gross margin decreased approximately $23.5 million due to cooler weather in the Company’s service territory, approximately $2.6 million due to lower margins related to sales to wholesale customers primarily resulting from reduced sales of power under a new wholesale contract with an existing customer and approximately $0.6 million due to the timing of fuel recoveries. These decreases were partially offset by an increase of approximately $7.5 million due to growth in the Company’s service territory.

Fuel expense was approximately $490.9 million for the nine months ended September 30, 2004 as compared to approximately $448.8 million during the same period in 2003, an increase of approximately $42.1 million or 9.4 percent. The increase was due to an increase in the average cost of fuel per kwh, primarily due to higher natural gas prices, despite lower mwh sales. Purchased power costs were approximately $216.4 million for the nine months ended September 30, 2004 as compared to approximately $218.2 million during the same period in 2003, a decrease of approximately $1.8 million or 0.8 percent. The decrease was primarily due to the Company’s acquisition of the McClain Plant in July 2004 and the termination of a power purchase contract in December 2003.

Operating and maintenance expenses decreased approximately $9.6 million or 4.4 percent for the nine months ended September 30, 2004 as compared to the same period in 2003. This decrease was primarily due to a decrease of approximately $6.5 million in pension and benefit expense and a decrease of approximately $5.1 million in salaries and wages expense during the nine months ended September 30, 2004 as compared to the same period in 2003 due to more projects on which the costs are capitalized and are not being expensed currently. A contributing factor to the overall decrease in operating and maintenance expense was that a number of the Company’s employees provided assistance for hurricane restoration efforts in the southeastern United States and, as a result, were not available for Company projects. Also contributing to the decrease was a decrease of approximately $2.1 million in corporate allocations primarily due to a decrease in depreciation expense allocated to the Company by Energy Corp. related to one of Energy Corp.’s systems being fully depreciated in 2003 and a decrease of approximately $0.6 million in property insurance costs. These decreases in operating and maintenance expense were partially offset by an increase of approximately $4.1 million in outside services expense primarily due to SPP membership fees and approximately $2.2 million in bad debt expense. Depreciation expense increased approximately $0.7 million or 0.8 percent for the nine months ended September 30, 2004 as compared to the same period in 2003 primarily due to a higher level of depreciable plant. Taxes other than income increased approximately $0.5 million or 1.4 percent for the nine months ended September 30, 2004 as compared to the same period in 2003 primarily due to an increase of approximately $0.4 million in ad valorem taxes.

Other Income and Expense, Interest Expense and Income Tax Expense

Other income includes, among other things, contract work performed by the Company, non-operating rental income, gain on the sale of assets and miscellaneous non-operating income. Other income was approximately $3.5 million for the three months ended September 30, 2004. There were no other income items for the three months ended September 30, 2003. The increase was primarily due to gains of approximately $3.0 million from the sale of the Company’s interest in its natural gas producing properties and approximately $0.6 million from the repurchase of outstanding heat pump loans.

Other income was approximately $4.8 million for the nine months ended September 30, 2004 as compared to approximately $0.5 million during the same period in 2003, an increase of approximately $4.3 million. The increase was primarily due to gains of approximately $3.0 million from the sale of the Company’s interests in its natural gas producing properties, approximately $0.6 million from the repurchase of outstanding heat pump loans and approximately $0.3 million from the sale of land near the Company’s principal executive offices.

Other expense includes, among other things, expenses from the losses on the sale of assets, miscellaneous charitable donations, expenditures for certain civic, political and related activities and miscellaneous deductions. Other expense was approximately $0.1 million for the three months ended September 30, 2004 as compared to approximately $0.9 million during the same period in 2003, a decrease of approximately $0.8 million or 88.9 percent. The decrease was primarily due to a decrease of approximately $0.5 million related to an increase in the allowance for funds used during construction.

Other expense was approximately $1.3 million for the nine months ended September 30, 2004 as compared to approximately $2.1 million during the same period in 2003, a decrease of approximately $0.8 million or 38.1 percent. The decrease was primarily due to a decrease of approximately $0.6 million related to an increase in the allowance for funds used during construction.

Net interest expense includes interest income, interest expense and other interest charges. Net interest expense was approximately $8.7 million for the three months ended September 30, 2004 as compared to approximately $9.5 million during the same period in 2003, a decrease of approximately $0.8 million or 8.4 percent. This decrease was primarily due to an increase in the allowance for borrowed funds used during construction (approximately $0.8 million) during the three months ended September 30, 2004 as compared to the same period in 2003.

Net interest expense was approximately $27.8 million for the nine months ended September 30, 2004 as compared to approximately $29.5 million during the same period in 2003, a decrease of approximately $1.7 million or 5.8 percent. This decrease was primarily due to an increase in the allowance for borrowed funds used during construction (approximately $0.7 million), lower interest expense to Energy Corp. (approximately $0.7 million) due to the Company having lower average borrowings outstanding from Energy Corp. and lower interest expense accruals (approximately $0.3 million) during the nine months ended September 30, 2004 as compared to the same period in 2003 due to lower interest rates.

Income tax expense was approximately $50.8 million for the three months ended September 30, 2004 as compared to $55.3 million during the same period in 2003, a decrease of approximately $4.5 million or 8.1 percent. The decrease was primarily due to lower pre-tax income for the Company and a change in the timing of the recognition of book and tax permanent differences in 2004. Amortization of the federal investment tax credits was approximately $1.3 million for each of the three month periods ended September 30, 2004 and 2003.

Income tax expense was approximately $61.1 million for the nine months ended September 30, 2004 as compared to $67.4 million during the same period in 2003, a decrease of approximately $6.3 million or 9.3 percent. The decrease was primarily due to lower pre-tax income for the Company, the recognition of additional Oklahoma state tax credits of approximately $2.2 million during the nine months ended September 30, 2004 and a change in the timing of the recognition of book and tax permanent differences in 2004. Amortization of the federal investment tax credits was approximately $3.9 million for each of the nine month periods ended September 30, 2004 and 2003.

Financial Condition

The balance of Accounts Receivable – Customers was approximately $143.8 million and $123.1 million at September 30, 2004 and December 31, 2003, respectively, an increase of approximately $20.7 million or 16.8 percent. The increase was primarily due to an increase in the Company’s billings to its customers reflecting higher fuel costs and increased usage due to warmer weather during September 2004 as compared to December 2003.

The balance of Accrued Unbilled Revenues was approximately $67.8 million and $38.0 million at September 30, 2004 and December 31, 2003, respectively, an increase of approximately $29.8 million or 78.4 percent. The increase reflects higher seasonal electric rates and increased usage due to warmer weather during September 2004 as compared to December 2003.

The balance of Fuel Clause Under Recoveries was approximately $48.9 million at September 30, 2004. The balance of Fuel Clause Over Recoveries (net of Fuel Clause Under Recoveries) was approximately $28.4 million at December 31, 2003. The increase in fuel clause under recoveries was due to under recoveries from the Company’s customers as the Company’s cost of fuel exceeded the amount billed during 2004. The cost of fuel subject to recovery through the fuel clause mechanism was approximately $2.41 per Million British thermal unit (“MMBtu”) in September 2004, and was approximately $1.21 per MMBtu in December 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 above the baseline charge for fuel and over recovers fuel cost when prices decline below the baseline charge for fuel. Provisions in the fuel clauses allow the Company to amortize under or over recovery.

The balance of Prepaid Benefit Obligation was approximately $73.4 million and $37.5 million at September 30, 2004 and December 31, 2003, respectively, an increase of approximately $35.9 million or 95.7 percent. The increase was primarily due to Energy Corp. funding its pension plan during the second and third quarters of 2004 partially offset by pension accruals being credited to the prepaid benefit obligation.

The balance of Short-Term Debt was approximately $50.0 million at December 31, 2003 primarily due to the planned acquisition of the McClain Plant by the end of 2003. In December 2003, the Company issued commercial paper in anticipation of the planned acquisition of the McClain Plant. Due to a delay in the completion of the McClain Plant acquisition, the Company transferred these funds to Energy Corp. for investment during the fourth quarter of 2003. Due to a delay in the completion of the McClain Plant acquisition, Energy Corp. repaid the outstanding advances and the Company used these funds to repay the outstanding commercial paper balance during the first quarter of 2004. At September 30, 2004, there was no short-term debt outstanding.

The balance of Accounts Payable – Affiliates was approximately $102.1 million and $40.9 million at September 30, 2004 and December 31, 2003, respectively, an increase of approximately $61.2 million. The increase was primarily due to the funding of Energy Corp.’s pension plan, dividend payments to Energy Corp. and a net increase due to income tax accruals and payments during the nine months ended September 30, 2004.

The balance of Accrued Taxes was approximately $31.0 million and $20.6 million at September 30, 2004 and December 31, 2003, respectively, an increase of approximately $10.4 million or 50.5 percent. The increase was primarily due to the Company’s results of operations for the nine months ended September 30, 2004 and the timing of income tax payments in 2004.

The balance of Long-Term Debt was approximately $847.3 million and $707.2 million at September 30, 2004 and December 31, 2003, respectively, an increase of approximately $140.1 million or 19.8 percent. The increase was primarily due to the issuance of $140.0 million of long-term debt in August 2004 by the Company to replace the short-term borrowings initially issued to finance the McClain Plant acquisition.

Off-Balance Sheet Arrangements

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

Heat Pump Loans

The Company had a heat pump loan program whereby, qualifying customers could obtain a loan from the Company to purchase a heat pump. In November 1999, the Company sold approximately $12.7 million of its heat pump loans in a securitization transaction through OGE Consumer Loan II LLC. In October 2004, the Company repurchased the outstanding heat pump loan balance of approximately $1.1 million. The Company expects to record a loss of less than $0.1 million in the fourth quarter of 2004 related to this transaction.

Liquidity and Capital Requirements

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

Interest Rate Swap Agreement

Fair Value Hedge

At September 30, 2004 and December 31, 2003, the Company had one outstanding interest rate swap agreement that qualified as a fair value hedge 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. The objective of this interest rate swap 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. This interest rate swap qualified as a fair value hedge under Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and met all of the requirements for a determination that there was no ineffective portion as allowed by the shortcut method under SFAS No. 133.

Future Capital Requirements

Capital Expenditures

The Company’s current 2004 to 2006 construction program includes the purchase of New Generation as discussed below. The Company has approximately 430 MWs of contracts with qualified cogeneration facilities and small power production producers’ (“QF contracts”) that will expire at the end of 2007, unless extended by the Company. In addition, effective September 1, 2004, the Company entered into a new 15-year power sales agreement with PowerSmith Cogeneration Project, L.P. (“PowerSmith”). The Company will continue reviewing all of the supply alternatives to these expiring QF contracts that minimize the total cost of generation to its customers, including exercising its options (if applicable) to extend these QF contracts at pre-determined rates. Accordingly, the Company will continue to explore opportunities to build or buy power plants in order to serve its native load. As a result of the high volatility of current natural gas prices and the increase in natural gas prices, the Company will also assess the feasibility of constructing additional base load coal-fired units. See Note 11 of Notes to Condensed Financial Statements for a description of the new PowerSmith QF contract.

The Company completed the acquisition of NRG McClain LLC’s 77 percent interest in the McClain Plant on July 9, 2004. The purchase price for the interest in the McClain Plant was approximately $160.0 million. See “Overview – Regulatory Matters and Plant Acquisition.” The Company temporarily funded the acquisition with short-term borrowings from Energy Corp. On August 4, 2004, the Company issued $140.0 million of long-term debt to replace these short-

term borrowings. Also, on August 9, 2004, Energy Corp. made a capital contribution to the Company of approximately $153.0 million. To reliably meet the increased electricity needs of the Company’s customers during the foreseeable future, the Company will continue to invest to maintain the integrity of the delivery system. Approximately $5.8 million of the Company’s capital expenditures budgeted for 2004 are to comply with environmental laws and regulations.

Pension and Postretirement Benefit Plans

Energy Corp. previously disclosed in its Form 10-K for the year ended December 31, 2003 that it expected to contribute approximately $56.0 million to its pension plan in 2004, of which approximately $43.5 million is the Company’s portion. After the benefit liability was remeasured as of January 1, 2004, Energy Corp. decided to make an additional contribution of $13.0 million (for a total anticipated contribution of $69.0 million in 2004) to ensure the pension plan maintains an adequate funded status. Energy Corp. funded this $69.0 million contribution to its pension plan during the second and third quarters of 2004, of which approximately $54.5 million was allocated to the Company. The contributions to the pension plan, in the form of cash, were discretionary contributions and were not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974.

Future Sources of Financing

Management expects that internally generated funds, funds received from Energy Corp. (from Energy Corp.’s 2003 equity offering and proceeds from the sales of its common stock pursuant to Energy Corp.’s Automatic Dividend Reinvestment and Stock Purchase Plan) and long and short-term debt will be adequate over the next three years to meet anticipated capital expenditures, operating needs, payment of dividends and maturities of long-term debt. As discussed below, the Company utilizes short-term borrowings from Energy Corp. to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged. With the acquisition of the McClain Plant complete, the Company issued long-term debt to permanently finance the McClain Plant acquisition in August 2004.

Short-Term Debt

Short-term borrowings from Energy Corp. generally are used to meet working capital requirements. In December 2003, the Company issued commercial paper in anticipation of the planned acquisition of the McClain Plant by the end of 2003 and the short-term debt balance was approximately $50.0 million at December 31, 2003. Due to a delay in the completion of the McClain Plant acquisition, the Company transferred these funds to Energy Corp. for investment and at December 31, 2003, the Company had approximately $51.8 million in outstanding advances to Energy Corp. Due to a delay in the completion of the McClain Plant acquisition, Energy Corp. repaid the outstanding advances and the Company used these funds to repay the outstanding commercial paper balance during the first quarter of 2004. At September 30, 2004, the Company had approximately $48.1 million in outstanding advances to Energy Corp. In July 2004, Energy Corp. issued short-term debt and loaned the proceeds to the Company to fund a

portion of the McClain Plant acquisition, which closed July 9 and, as a result, advances from Energy Corp. were approximately $296.8 million at July 31, 2004. On August 4, 2004, the Company issued $140.0 million of long-term debt to replace these short-term borrowings.

The following table shows Energy Corp.’s and the Company’s lines of credit in place at September 30, 2004. Energy Corp.’s short-term borrowings could include a combination of bank borrowings and commercial paper.

Lines of Credit and Available Cash (In millions)

Entity	Amount Available		Amount Outstanding		Maturity

Energy Corp.		$ 15.0		$ ---	April 6, 2005
The Company (A)		100.0		---	December 9, 2004
Energy Corp. (A)		300.0		---	December 9, 2004

		415.0		---
Cash		28.1		N/A	N/A

Total		$ 443.1		$ ---

(A) These lines of credit are used to back up Energy Corp.’s commercial paper borrowings, which were approximately $10.2 million at September 30, 2004.

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

existing portfolio and divestitures of idle or under performing assets. Permanent financing may be required for any such acquisitions.

Critical Accounting Policies and Estimates

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

Accounting Pronouncements

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

Electric Competition; Regulation

The Company 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 the Company 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 the Company conducts its business. These developments at the federal and state levels are described in more detail in Note 11 of Notes to Condensed Financial Statements in this Form 10-Q and in the Company’s Form 10-K for the year ended December 31, 2003. The Company currently has two important matters pending before the OCC. See Note 11 of Notes of Condensed Financial Statements for a further discussion.

Commitments and Contingencies

In the normal course of business, the Company is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties, environmental actions or the action of various regulatory agencies. Management consults with counsel and other appropriate experts to assess the claim. If in management’s opinion, the Company has incurred a probable loss as set forth by accounting principles generally accepted in the United States, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company’s Condensed Financial Statements. Except as set forth in Notes 10 and 11 of Notes to Condensed Financial Statements in this Form 10-Q, in Note 11 to the Company’s Financial Statements included in the Company’s Form 10-K for the year ended December 31, 2003 and in Note 9 to the Company’s Condensed Financial Statements included in the Company’s Form 10-Q for the quarters ended March 31, 2004 and June 30, 2004, management, after consultation with legal counsel, does not anticipate that liabilities arising out of currently pending or threatened lawsuits, claims and contingencies will have a material adverse effect on the Company’s financial position, results of operations or cash flows. This assessment of currently pending or threatened lawsuits is subject to change.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Under the reduced disclosure format permitted by General Instruction H(2)(c) of Form 10-Q, the information otherwise required by Item 3 has been omitted.

Item 4. Controls and Procedures.

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

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

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

Reference is made to Part I, Item 3 of the Company’s Form 10-K for the year ended December 31, 2003 and Part II, Item 1 of the Company’s Form 10-Q for the quarters ended March 31, 2004 and June 30, 2004 for a description of certain legal proceedings presently pending. Except as set forth in Notes 10 and 11 of Notes to Condensed Financial Statements in this Form 10-Q, there are no new significant cases to report against the Company and there have been no material changes in the previously reported proceedings.

Item 6. Exhibits.

Exhibit No.

Description

31.01

Certifications Pursuant to Rule 13a-15(e)/15d-15(e) As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.01

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

SIGNATURE

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

	OKLAHOMA GAS AND ELECTRIC COMPANY (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)

November 4, 2004

Exhibit 31.01

CERTIFICATIONS

I, Steven E. Moore, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Oklahoma Gas and Electric Company;

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

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

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

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

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

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

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

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

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

Date: November 4, 2004

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

Exhibit 31.01

CERTIFICATIONS

1. I have reviewed this quarterly report on Form 10-Q of Oklahoma Gas and Electric Company;

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

Date: November 4, 2004

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

Exhibit 32.01

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

In connection with the Quarterly Report of Oklahoma Gas and Electric Company (the “Company”) on Form 10-Q for the period ended September 30, 2004, as filed with the Securities and Exchange Commission (the “Report”), each of the undersigned does hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

November 4, 2004

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

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

FORM 10-Q

OR

OKLAHOMA GAS AND ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2004

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

OKLAHOMA GAS AND ELECTRIC COMPANY CONDENSED BALANCE SHEETS (Continued) (Unaudited)

OKLAHOMA GAS AND ELECTRIC COMPANY CONDENSED STATEMENTS OF INCOME (Unaudited)

OKLAHOMA GAS AND ELECTRIC COMPANY CONDENSED STATEMENTS OF CASH FLOWS (Unaudited)

OKLAHOMA GAS AND ELECTRIC COMPANYNOTES TO CONDENSED FINANCIAL STATEMENTS (Unaudited)

1. Summary of Significant Accounting Policies

Organization

Basis of Presentation

Accounting Records

Income Taxes

Related Party Transactions

Reclassifications

2. Accounting Pronouncements

3. Price Risk Management Assets and Liabilities

4. Accumulated Other Comprehensive Loss

5. Asset Disposals

6. Supplemental Cash Flow Information

7. Long-Term Debt

Fair Value Hedge

8. Short-Term Debt

9. Retirement Plans and Postretirement Benefit Plans

10. Commitments and Contingencies

11. Rate Matters and Regulation

Recent Regulatory Matters

Pending Regulatory Matters

12. Fair Value of Financial Instruments

Introduction

Forward-Looking Statements

Overview

Outlook

Results of Operations

Financial Condition

Off-Balance Sheet Arrangements

Liquidity and Capital Requirements

Fair Value Hedge

Future Capital Requirements

Future Sources of Financing

Critical Accounting Policies and Estimates

Accounting Pronouncements

Electric Competition; Regulation

Commitments and Contingencies

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Item 4. Controls and Procedures.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

Item 6. Exhibits.

SIGNATURE

CERTIFICATIONS

Exhibit 31.01

CERTIFICATIONS

Exhibit 32.01

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

OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED BALANCE SHEETS (Continued)
(Unaudited)

OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)

OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)

OKLAHOMA GAS AND ELECTRIC COMPANY
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

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