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

FORM 10-Q

(Mark One)

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

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 April 30, 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 MARCH 31, 2004

Part I - FINANCIAL INFORMATION	Page

Item 1. Financial Statements (Unaudited)
Condensed Balance Sheets	1
Condensed Statements of Operations	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	23

Item 3. Quantitative and Qualitative Disclosures About Market Risk	38

Item 4. Controls and Procedures	38

Part II - OTHER INFORMATION

Item 1. Legal Proceedings	39

Item 6. Exhibits and Reports on Form 8-K	39

Signature	41

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)

		March 31,			December 31,
(In millions)		2004			2003


ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	4	.0	$	4	.0
Accounts receivable - customers, less reserve of $1.9 and $2.6, respectively		90	.0		123	.1
Accounts receivable - other		8	.6		9	.9
Advances to parent		13	.4		51	.8
Accrued unbilled revenues		37	.4		38	.0
Fuel inventories, at LIFO cost		45	.0		60	.0
Materials and supplies, at average cost		44	.3		41	.4
Accumulated deferred tax assets		6	.3		6	.8
Fuel clause under recoveries		0	.4		4	.0
Other		5	.9		6	.2

Total current assets		255	.3		345	.2


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


PROPERTY, PLANT AND EQUIPMENT
In service		4,242	.3		4,210	.8
Construction work in progress		48	.5		44	.6
Other		1	.0		1	.0

Total property, plant and equipment		4,291	.8		4,256	.4
Less accumulated depreciation		2,024	.2		2,006	.0

Net property, plant and equipment		2,267	.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	.4		31	.6
Intangible asset - unamortized prior service cost		35	.7		35	.7
Prepaid benefit obligation		31	.3		37	.5
Price risk management		5	.9		4	.0
Other		33	.7		32	.7

Total deferred charges and other assets		170	.5		174	.0


TOTAL ASSETS	$	2,698	.8	$	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)

		March 31,			December 31,
(In millions)		2004			2003


LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Short-term debt	$	-	--	$	50	.0
Accounts payable - affiliates		44	.5		40	.9
Accounts payable - other		60	.3		57	.7
Customers’ deposits		37	.5		35	.8
Accrued taxes		11	.1		20	.6
Accrued interest		14	.1		12	.8
Tax collections payable		7	.3		7	.9
Accrued vacation		12	.0		11	.6
Fuel clause over recoveries		32	.8		32	.4
Other		16	.5		15	.3

Total current liabilities		236	.1		285	.0


LONG-TERM DEBT		709	.2		707	.2


DEFERRED CREDITS AND OTHER LIABILITIES
Accrued pension and benefit obligations		136	.3		134	.8
Accumulated deferred income taxes		533	.1		535	.9
Accumulated deferred investment tax credits		40	.7		42	.0
Accrued removal obligations, net		120	.1		116	.3
Provision for payments of take or pay gas		32	.5		32	.5
Other		-	--		1	.6

Total deferred credits and other liabilities		862	.7		863	.1


STOCKHOLDERS’ EQUITY
Common stockholders’ equity		512	.4		512	.4
Retained earnings		431	.8		460	.9
Accumulated other comprehensive loss, net of tax		(53	.4)		(53	.4)

Total stockholders’ equity		890	.8		919	.9


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	2,698	.8	$	2,775	.2

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

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


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


OPERATING REVENUES	$	304	.3	$	332	.6

COST OF GOODS SOLD		183	.2		213	.9

Gross margin on revenues		121	.1		118	.7
Other operation and maintenance		71	.5		72	.0
Depreciation		31	.9		32	.6
Taxes other than income		12	.7		12	.0

OPERATING INCOME		5	.0		2	.1


OTHER INCOME (EXPENSE)
Other income		0	.4		0	.3
Other expense		(0	.5)		(0	.7)

Net other expense		(0	.1)		(0	.4)


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

Net interest expense		(9	.5)		(9	.9)


LOSS BEFORE TAXES		(4	.6)		(8	.2)

INCOME TAX BENEFIT		(4	.6)		(4	.9)


NET LOSS	$	-	--	$	(3	.3)

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

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


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


CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	-	--	$	(3	.3)
Adjustments to reconcile net loss to net cash provided from
operating activities
Depreciation		31	.9		32	.6
Deferred income taxes and investment tax credits, net		(3	.2)		0	.7
Other assets		3	.5		5	.1
Other liabilities		(0	.9)		2	.3
Change in certain current assets and liabilities
Accounts receivable - customers, net		33	.1		8	.3
Accounts receivable - other		1	.3		(1	.0)
Accrued unbilled revenues		0	.6		(4	.3)
Fuel, materials and supplies inventories		12	.1		3	.5
Fuel clause under recoveries		3	.6		(34	.1)
Other current assets		0	.5		0	.5
Accounts payable		2	.6		27	.1
Accounts payable - affiliates		3	.6		30	.4
Customers’ deposits		1	.7		1	.0
Accrued taxes		(9	.5)		(9	.1)
Accrued interest		1	.3		1	.5
Fuel clause over recoveries		0	.4		-	--
Other current liabilities		1	.0		3	.2

Net Cash Provided from Operating Activities		83	.6		64	.4


CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(43	.1)		(36	.6)

Net Cash Used in Investing Activities		(43	.1)		(36	.6)


CASH FLOWS FROM FINANCING ACTIVITIES
Decrease in short-term debt, net		(11	.6)		(2	.0)
Dividends paid on common stock		(28	.9)		(26	.1)

Net Cash Used in Financing Activities		(40	.5)		(28	.1)


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

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	4	.0	$	-	--

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.”) which is an energy and energy services provider offering physical delivery and management of both electricity and natural gas in the south central United States. The Company 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 March 31, 2004 and December 31, 2003, the results of its operations for the three months ended March 31, 2004 and 2003, and the results of its cash flows for the three months ended March 31, 2004 and 2003, have been included and are of a normal recurring nature.

Due to seasonal fluctuations and other factors, the operating results for the three months ended March 31, 2004 are not necessarily indicative of the results that may be expected for the year ending December 31, 2004 or for any future period. The Condensed 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, 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:

		March 31,			December 31,
(In millions)		2004			2003

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

Total Regulatory Assets	$	91	.2	$	94	.2


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

Total Regulatory Liabilities	$	160	.3	$	149	.7

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

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

Fuel clause under recoveries are generated from under recoveries from 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.

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 months ended March 31, 2004 and 2003 and is recorded as an income tax benefit in the Condensed Statements of Operations. During the three months ended March 31, 2004, the Company recorded Oklahoma investment tax credits of approximately $1.7 million which is recorded as an income tax benefit in the Condensed Statements of Operations.

The Company follows the provisions of SFAS No. 109, “Accounting for Income Taxes,” which uses an asset and liability approach to accounting for income taxes. Under SFAS No. 109, deferred tax assets or liabilities are computed based on the difference between the financial

statement and income tax bases of assets and liabilities using the enacted marginal tax rate. Deferred income tax expenses or benefits are based on the changes in the asset or liability from period to period.

Fair Value of Financial Instruments

The carrying value of the financial instruments on the Condensed Balance Sheets not otherwise discussed in these notes approximates fair value except for long-term debt which is valued at the carrying amount.

Related Party Transactions

Energy Corp. allocated operating costs to the Company of approximately $22.0 million and $21.0 million during the three months ended March 31, 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. Where more than one affiliate benefits from certain expenditures, the costs are shared between those affiliates receiving the benefits. Operating costs incurred for the benefit of all affiliates are allocated among the affiliates, based primarily upon head-count, occupancy, usage or the “Distragas” method. The Distragas method is a three-factor formula that uses an equal weighting of payroll, operating income and assets. The Company believes this method provides a reasonable basis for allocating common expenses.

During the three months ended March 31, 2004 and 2003, the Company paid its affiliate, Enogex Inc. and its subsidiaries (“Enogex”), approximately $8.5 million and $8.1 million, respectively, for transporting gas to the Company’s natural gas-fired generating facilities. During the three months ended March 31, 2004 and 2003, the Company paid Enogex approximately $3.3 million and $1.9 million, respectively, for natural gas storage services. During the three months ended March 31, 2004 and 2003, the Company also recorded natural gas purchases from Enogex of approximately $0.1 million and $11.8 million, respectively. Approximately $0.1 million was recorded at March 31, 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 March 31, 2004, the Company recorded interest income of approximately $0.1 million from Energy Corp. for advances made by the Company to Energy Corp. The Company made no advances to Energy Corp. for the three months ended March 31, 2003.

During the three months ended March 31, 2003, the Company recorded interest expense of approximately $0.3 million to Energy Corp. for advances made by Energy Corp. to the Company. Energy Corp. made no advances to the Company for the three months ended March 31, 2004. The interest rate charged on advances to the Company from Energy Corp. approximates Energy Corp.’s commercial paper rate.

During the three months ended March 31, 2004 and 2003, the Company paid approximately $28.9 million and $26.1 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 January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin No. 51.” Interpretation No. 46 requires the consolidation of entities in which an enterprise absorbs a majority of the entity’s expected losses, receives a majority of the entity’s expected residual returns, or both, as a result of ownership, contractual or other financial interests in the entity. Currently, entities are generally consolidated by an enterprise when it has a controlling financial interest through ownership of a majority voting interest in the entity.

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

As a result of Interpretation No. 46-6, a public entity need not apply the provisions of Interpretation No. 46 to an interest held in a VIE or potential VIE until the end of the first interim or annual period ending after December 15, 2003, if the VIE was created before February 1, 2003 and the public entity has not issued financial statements reporting that VIE in accordance with Interpretation No. 46, other than in the disclosures required by Interpretation No. 46. Interpretation No. 46 may be applied prospectively with a cumulative-effect adjustment as of the date on which it is first applied or by restating previously issued financial statements for one or more years with a cumulative-effect adjustment as of the beginning of the first year restated. The Company adopted this new interpretation effective December 31, 2003 and the adoption of this new interpretation did not have a material impact on its financial position or results of operations.

3. Price Risk Management Assets and Liabilities

The Company periodically utilizes derivative contracts to reduce exposure to adverse interest rate fluctuations. During the three months ended March 31, 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 Balance Sheet at fair value with such amounts classified as current or long-term based on their anticipated settlement. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation. For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item attributable to the hedged risk are recognized in the same line item associated with the hedged item in current earnings during the period of the change in fair values. For derivatives that are designated and qualify as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of Accumulated Other Comprehensive Income and recognized into earnings in the same period during which the hedged transaction affects earnings. The ineffective portion of a derivative’s change in fair value is recognized currently in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and hedged item during the period of hedge designation. Forecasted transactions designated as the hedged item in a cash flow hedge are regularly evaluated to assess whether they continue to be probable of occurring. If the forecasted transactions are no longer probable of occurring, hedge accounting will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings. Any amounts recorded in Accumulated Other Comprehensive Income will remain in other comprehensive income until such time the forecasted transaction is deemed probable not to occur. The Company’s interest rate swap 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.

4. Accumulated Other Comprehensive Loss

There were no items of other comprehensive income for the three months ended March 31, 2004 and 2003. Accumulated other comprehensive loss at both March 31, 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 the 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. Supplemental Cash Flow Information

Non-cash financing activities for the three months ended March 31, 2004 and 2003, included approximately a $1.9 million increase and a $0.2 million increase, respectively, related to the change in the fair value of long-term debt due to an interest rate swap agreement.

6. Long-Term Debt

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

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


SERIES	DATE DUE		AMOUNT

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

Total		$	260	.4

The 6.500 percent Senior Notes (“Senior Notes”) will be repayable on July 15, 2004, at the option of the holders, at 100 percent of the principal amount, together with accrued and unpaid interest to July 15, 2004. In order for a Senior Note to be repaid, the Company must receive at the principal corporate trust office of the Senior Note Trustee during the period from and including May 15, 2004 to and including the close of business on June 15, 2004, a Senior Note with the form entitled “Option to Elect Repayment” on these Senior Notes or other documentation with this information. The repayment option may be exercised by the holder of a Senior Note for less than the entire principal amount of the Senior Note, provided the principal amount is in denominations of $1,000. If the Senior Note holders were to exercise the put options prior to the maturity date, the Company has sufficient liquidity but may choose to refinance these obligations in the capital markets. Such refinancing may incur higher annual interest charges. At the present time, the Company does not believe a majority of the Senior Notes will be submitted for repayment in this interest rate environment.

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

Interest Rate Swap Agreement

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 March 31, 2004 and December 31, 2003, the fair values pursuant to the interest rate swap were approximately $5.9 million and $4.0 million, respectively, and are classified as Deferred Charges and Other Assets – Price Risk Management in the Condensed Balance Sheets. A corresponding net increase of approximately $5.9 million and $4.0 million was reflected in Long-Term Debt at March 31, 2004 and December 31, 2003, respectively, as these fair value hedges were effective at March 31, 2004 and December 31, 2003.

7. Short-Term Debt

The short-term debt balance was approximately $50.0 million at December 31, 2003 primarily due to the planned acquisition of the McClain Plant discussed in Notes 9 and 10. There was no short-term debt outstanding at March 31, 2004. The decrease was primarily due to commercial paper issued in December 2003 by the Company in anticipation of the planned acquisition of the McClain Plant. Due to a delay in the completion of the McClain Plant acquisition, the Company repaid the outstanding commercial paper balance during the first quarter of 2004. At March 31, 2004 and December 31, 2003, respectively, the Company had approximately $13.4 million and $51.8 million in short-term debt from Energy Corp. outstanding.

As indicated below, the Company has in place a $100 million line of credit with a bank. The following table shows Energy Corp.’s and the Company’s lines of credit in place and available cash at March 31, 2004. Energy Corp.’s short-term borrowings are expected to consist of a combination of bank borrowings and commercial paper.

Lines of Credit and Available Cash (In millions)

Entity	Amount Available		Amount Outstanding		Maturity

Energy Corp. (A)		$ 15.0		$ ---	April 6, 2004
The Company		100.0		---	June 26, 2004
Energy Corp. (A)		300.0		---	December 9, 2004

		415.0		---
Cash		149.6		N/A	N/A

Total		$ 564.6		$ ---

(A) The lines of credit at Energy Corp. are used to back up its commercial paper borrowings. There was no short-term debt outstanding at March 31, 2004. In April 2004, Energy Corp. renewed its $15.0 million credit facility, shown in the table above, which matures April 6, 2005.

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.

8. Retirement Plans and Postretirement Benefit Plans

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

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

Net Periodic Benefit Cost



							Postretirement
	Pension Plan						Benefit Plans

	Three Months Ended						Three Months Ended
	March 31,						March 31,

(In millions)		2004			2003			2004			2003

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

Net periodic benefit cost	$	6	.3	$	6	.2	$	3	.7	$	4	.3

Pension Plan Funding

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 the pension plan in 2004, of which approximately $43.5 million is the Company’s portion. Energy Corp. presently anticipates contributing an additional $13.0 million to the pension plan during 2004, for a total contribution of approximately $69.0 million in 2004. After the benefit liability was remeasured as of January 1, 2004, Energy Corp. decided to make the additional contribution to ensure the pension plan maintains an adequate funded status. During 2004, Energy Corp. plans to make contributions to the pension plan during the second and third quarters of 2004. In April 2004, Energy Corp. funded approximately $23.0 million to the pension plan, of which approximately

$18.2 million was allocated to the Company. The expected contributions to the pension plan, anticipated to be in the form of cash, are discretionary contributions and are not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974.

Medicare Prescription Drug, Improvement and Modernization Act of 2003

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

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

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

9. Commitments and Contingencies

Except as set forth below and in Note 10, 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, appropriately represent, in all material respects, the current status of any material commitments and contingent liabilities.

Pending 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 520 megawatt (“MW”) NRG McClain Station (the “McClain Plant”). Closing has been delayed pending receipt of FERC approval. The acquisition of this interest in the McClain Plant would clearly constitute an acquisition of electric generation under the agreed-upon settlement of the Company’s rate case (the “Settlement Agreement”). The purchase price for the interest in the McClain Plant is approximately $159.9 million, subject to

adjustment for prepaid gas and property taxes. See Note 10 for a further description of this matter and a description of current proceedings involving a PowerSmith contract.

Sooner Power Plant Coal Dust Explosion

On February 16, 2004, there was a coal dust explosion at the Company’s Sooner Power Plant which caused structural and electrical damage to the coal train unloading system. The generation capacity of the Sooner Plant facility was not impacted by this incident. The estimated costs to repair the damage are approximately $3.0 million to $4.0 million, of which a majority is expected to be capitalized in 2004. The coal train unloading system resumed unloading coal trains at the end of the first quarter of 2004. Energy Corp. is insured for this loss through Energy Insurance Bermuda Ltd. Mutual Business Program No. 19 which is a self-funded insurance program.

Other

In the normal course of business, the Company is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties, environmental actions or the action of various regulatory agencies. Management consults with counsel and other appropriate experts to assess the claim. If in management’s opinion, the Company has incurred a probable loss as set forth by accounting principles generally accepted in the United States, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company’s Condensed 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.

10. 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

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 MWs (“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.

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 McClain Plant, but due to a delay at the FERC, the acquisition has not yet been completed. In the interim, the Company has entered into a power purchase agreement with the McClain Plant, which expires December 31, 2004, that is delivering the savings guaranteed to the Company’s customers. The Company requested that the OCC confirm that the steps it has taken, including the power purchase agreement, were satisfying the customer savings obligation under the Settlement Agreement and that 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 Company had to reduce its rates, effective January 1, 2004, while it awaits action by the FERC on its application to purchase the McClain Plant.

Pending Regulatory Matters

Currently, the Company has one significant matter pending at the FERC relating to the FERC’s review of market power issues and mitigation measures involved in the McClain Plant acquisition. The Company also has three significant matters pending at the OCC: (i) a motion by PowerSmith seeking to compel the Company to continue purchasing power from a qualified cogeneration facility; (ii) 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 (iii) security

investments on the Company’s system. These matters, as well as several other pending matters, are discussed below.

Pending Acquisition of Power Plant

As part of the 2002 Settlement Agreement with the OCC, the Company undertook to acquire New Generation of not less than 400 MWs. The acquisition of a 77 percent interest in the McClain Plant would clearly constitute an acquisition of such New Generation under the Settlement Agreement. The Company expects this New Generation, including the interim power purchase agreement, will provide savings, over a three-year period, in excess of $75.0 million to its Oklahoma customers. These savings were to be derived from: (i) the avoidance of purchase power contracts otherwise needed; (ii) replacing an above market cogeneration contract with PowerSmith when it can be terminated at the end of August 2004; and (iii) fuel savings associated with operating efficiencies of the new plant. In the event the Company is unable to demonstrate at least $75.0 million in savings to its customers during this 36-month period, the Company will have an obligation to credit its Oklahoma customers any unrealized savings below $75.0 million as determined at the end of the 36-month period, which shall be no later than December 31, 2006. PowerSmith has filed an application with the OCC seeking to compel 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 lesser of (i) the rate currently specified in the power purchase agreement between the Company and PowerSmith or (ii) the avoided cost of the McClain Plant. On March 29, 2004, the Company and PowerSmith reached a tentative, 15-year power sales agreement under which the Company will continue to purchase electric power from PowerSmith. The terms of the agreement are being finalized and will be subject to approval by the OCC. In conjunction with the Company’s agreement with PowerSmith, PowerSmith is in the process of completing a long-term steam sales agreement with Dayton Tire. On April 15, 2004, the Company and PowerSmith provided an update to the OCC regarding completion of the contract and the OCC scheduled a hearing for May 11, 2004 in this case. 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.

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 interest in the McClain Plant would clearly constitute an acquisition of New Generation under the Settlement Agreement. The purchase price for the interest in the McClain Plant is approximately $159.9 million, subject to adjustment for prepaid gas and property taxes. The McClain Plant includes natural gas-fired combined cycle combustion turbine units and is located near Newcastle, Oklahoma in McClain County, Oklahoma. The McClain Plant began operating in 2001. The owner of the remaining 23 percent in the McClain Plant is the Oklahoma Municipal Power Authority (“OMPA”).

Because the current owner of the McClain Plant has filed for bankruptcy protection, the acquisition also was subject to approval by the bankruptcy court. As part of the bankruptcy approval process, NRG McClain LLC’s interest in the plant was subject to an auction process and on October 28, 2003, the bankruptcy court approved the sale of NRG McClain LLC’s interest in the plant to the Company. Several parties have filed interventions at the FERC opposing the Company’s application under Section 203 of the Federal Power Act to acquire NRG McClain’s interest in the power plant or, alternatively, requesting the FERC to delay approving such acquisition. The Company believed that its application met the standards under Section 203 set forth by the FERC and that its application would be approved. On December 18, 2003, the FERC shifted its policy regarding market power issues, raised wholesale market power concerns and ordered a hearing regarding the Company’s acquisition of the McClain Plant. The FERC action did not reject the Company’s request to purchase the McClain Plant, but ordered that the Company must address certain issues in an administrative hearing. On January 15, 2004, the FERC administrative law judge in charge of the hearing and the parties to the case agreed to a procedural schedule that would produce a decision on the McClain Plant acquisition no sooner than the third quarter of 2004. On January 20, 2004, the Company filed a petition for re-hearing of the FERC’s December 18, 2003 order which included new mitigation measures that were designed to allow for prompt approval of the transaction. That request is still pending before the FERC. The Company has no indication whether the FERC will accept those proposed mitigation measures. On March 2, 2004, the Company filed testimony and exhibits with the FERC administrative law judge. The testimony and exhibits indicate that, if the case proceeds to hearing, the wholesale market power issues that the FERC raised in the December 18, 2003 order may be resolved by the proposed mitigation measures. The Company also filed on March 8, 2004, in the proceeding before the FERC administrative law judge an offer of settlement proposing additional mitigation measures at an aggregate cost of approximately $18.5 million and, despite opposition from certain intervenors, requested the administrative law judge to certify the offer as a contested settlement. Following a denial of the Company’s request, the Company asked the administrative law judge to reconsider his decision or, alternatively, to grant the Company an interlocutory appeal to the FERC of his decision. The FERC administrative law judge denied the Company’s requests and the Company is appealing his decision to the FERC. Absent FERC granting the Company’s January 20 motion for reconsideration or its most recent appeal, the matter is scheduled for hearing before the FERC administrative law judge on August 3, 2004.

Assuming the acquisition occurs, the Company expects to operate the plant in accordance with a joint ownership and operating agreement with the OMPA. Under this agreement, the Company would operate the facility, and the Company and the OMPA would be entitled to the net available output of the plant based on their respective ownership percentages. All fixed and variable costs, except fuel and gas transportation costs, would be shared in proportion to the respective ownership interests. Fuel and gas transportation costs would be shared based on consumption. The Company expects to utilize its portion of the output, 400 MWs, to serve its native load. As provided in the Settlement Agreement, pending approval of a request to increase base rates to recover the investment in the plant, the Company will have the right to accrue a regulatory asset, for a period not to exceed 12 months subsequent to the acquisition, consisting of the non-fuel operation and maintenance expenses, depreciation, cost of debt associated with the

investment and ad valorem taxes. Upon approval by the OCC of the Company’s request, all prudently incurred costs accrued through the regulatory asset within the 12-month period will be included in the Company’s prospective cost of service.

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

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 Company believes that in order for it to achieve maximum coal generation and ensure reliable electric service, it must have firm no-notice load following service for both gas transportation and gas storage. This type of service is required to satisfy the daily swings in customer demand placed on 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 firm no-notice load following service to the Company that is not available from other companies serving the Company marketplace. On April 29, 2003, 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 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. During the three months ended March 31, 2004 and 2003, the Company paid Enogex approximately $11.8 million and $10.0 million, respectively, for gas transportation and storage services. Based upon requests for information from intervenors, the Company has requested from Enogex and Enogex retained a “cost of service” consultant to assist in the preparation of testimony related to this case. On January 30, 2004, the OCC issued a procedural schedule for this case. On March 31, 2004, the Company filed testimony and exhibits with the OCC, which completes the initial documentation required to be filed in this case. A hearing is scheduled August 10-11, 2004 and an OCC order in the case is expected by the end of 2004. The Company believes the amount currently paid to Enogex for no-notice load following transportation and storage services is fair, just and reasonable. If any amounts paid by the Company are found not to be recoverable, the Company believes such amount would not be material.

Security Enhancements

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. The Company currently expects that hearings will be held in mid-2004.

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

Southwest Power Pool

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 an RTO. On February 10, 2004, the FERC conditionally approved the SPP’s application. The SPP must meet certain conditions before it may commence operations as an RTO. On April 27, 2004, the SPP Board of Directors took actions to meet the conditions to satisfy the FERC requirement for formal approval of the RTO. The SPP compliance filing at the FERC was made on May 3, 2004. It is not known at this time whether the FERC will grant RTO status to the SPP.

FERC Standards of Conduct

In October 2001, the FERC issued a Notice of Proposed Rulemaking proposing to adopt new standards of conduct rules applicable to all jurisdictional electric and natural gas transmission providers. The proposed rules would replace the current rules governing the electric transmission and wholesale electric functions of electric utilities and the rules governing natural gas transportation and wholesale gas supply functions. The proposed rules would expand the definition of “affiliate” and further limit communications between transmission functions and supply functions, and could materially increase operating costs of market participants, including the Company and Enogex. In April 2002, the FERC Staff issued a reaction paper, generally rejecting the comments of parties opposed to the proposed rules. On November 25, 2003, the FERC issued its new rules regulating the relationship between electric and gas transmission providers and those entities’ merchant personnel and energy affiliates. The FERC’s final rule requires all transmission providers to be in full compliance with the new rules by June 1, 2004. In February 2004, the Company and Enogex submitted plans and schedules to take the necessary actions to be in compliance with these new rules and expect that their initial costs to comply with

the final rule will not exceed $1.6 million in 2004. On April 16, 2004, the FERC issued an order on rehearing in which the FERC largely rejected requests to revise its November 25 final rule. However, the FERC did extend the compliance date until September 2004 and did clarify certain aspects of the rule. The impact of those clarifications on compliance costs is not known at this time.

Market-Based Rate Authority

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

Department of Energy Blackout Report

On April 6, 2004, the U.S. Department of Energy issued its final report regarding the August 14, 2003 electric blackout in the eastern United States, which did not affect 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. The Company is reviewing the final report and the FERC policy statement. Implementation of the blackout report recommendations and the FERC policy statement could increase future transmission costs, but the extent of the increased costs is not known at this time.

Redbud Tariff Filing

On March 5, 2004, Redbud Energy LP (“Redbud”) filed a rate schedule with the FERC in Docket No. ER04-622-000 under which Redbud proposed to charge 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. At this time, the Company does not know whether Redbud intends to challenge the FERC’s May 4, 2004 order.

State Restructuring Initiatives

Oklahoma

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

Arkansas

In April 1999, Arkansas passed a law (the “Restructuring Law”) calling for restructuring of the electric utility industry at the retail level. The Restructuring Law, which had initially targeted customer choice of electricity providers by January 1, 2002, was repealed in March 2003 before it was implemented. As part of the repeal legislation, electric public utilities were permitted to recover transition costs. 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.

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 ratings agencies and their impact on capital expenditures; Energy Corp.’s ability and the ability of its subsidiaries to obtain financing on favorable terms; prices of electricity; business conditions in the energy industry; competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company; unusual weather; state and federal legislative and regulatory decisions and initiatives; changes in accounting standards, rules or guidelines; creditworthiness of suppliers, customers, and other contractual parties; completion of the pending acquisition of a power plant; and the other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission, including Exhibit 99.01 to the Company’s Form 10-K for the year ended December 31, 2003.

Overview

General

The following discussion and analysis presents factors which affected the Company’s results of operations for the three months ended March 31, 2004 as compared to the same period in 2003 and the Company’s financial position at March 31, 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.

Operating Results

The Company reported break-even results for the three months ended March 31, 2004 as compared to a net loss of approximately $3.3 million for the three months ended March 31, 2003. The improvement in earnings during the three months ended March 31, 2004 as compared to the same period in 2003 was primarily attributable to higher gross margins from growth in the Company’s service territory and additional fuel recoveries from its customers partially offset by warmer than normal weather as heating degree days were 14 percent below the first quarter of 2003. Also contributing to the Company’s improvement were lower net interest expense and Oklahoma investment tax credits of approximately $1.7 million during the three months ended March 31, 2004.

2002 Settlement Agreement

On October 11, 2002, the Company, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to settle the Company’s rate case. The administrative law judge subsequently recommended approval of the agreed-upon settlement (the “Settlement Agreement”) and on November 22, 2002, the OCC signed a rate order containing the provisions of the Settlement Agreement. The Settlement Agreement provides for, among other items: (i) a $25.0 million annual reduction in the electric rates of 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.

Pending Acquisition of Power Plant

As part of the 2002 Settlement Agreement with the OCC, the Company undertook to acquire New Generation of not less than 400 MWs. The acquisition of a 77 percent interest in the 520 MW NRG McClain Station (the “McClain Plant”) would clearly constitute an acquisition of such New Generation under the Settlement Agreement. The Company expects this New Generation, including the interim power purchase agreement, will provide savings, over a three-year period, in excess of $75.0 million to its Oklahoma customers. These savings were to be derived from: (i) the avoidance of purchase power contracts otherwise needed; (ii) replacing an above market cogeneration contract with PowerSmith when it can be terminated at the end of

August 2004; and (iii) fuel savings associated with operating efficiencies of the new plant. In the event the Company is unable to demonstrate at least $75.0 million in savings to its customers during this 36-month period, the Company will have an obligation to credit its Oklahoma customers any unrealized savings below $75.0 million as determined at the end of the 36-month period, which shall be no later than December 31, 2006. PowerSmith has filed an application with the OCC seeking to compel 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 lesser of (i) the rate currently specified in the power purchase agreement between the Company and PowerSmith or (ii) the avoided cost of the McClain Plant. On March 29, 2004, the Company and PowerSmith reached a tentative, 15-year power sales agreement under which the Company will continue to purchase electric power from PowerSmith. The terms of the agreement are being finalized and will be subject to approval by the OCC. In conjunction with the Company’s agreement with PowerSmith, PowerSmith is in the process of completing a long-term steam sales agreement with Dayton Tire. On April 15, 2004, the Company and PowerSmith provided an update to the OCC regarding completion of the contract and the OCC scheduled a hearing for May 11, 2004 in this case. 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.

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

Closing is subject to customary conditions including receipt of regulatory approval by the FERC. The asset purchase agreement, as amended, provides that, unless extended, either party has the right to terminate the contract if the closing does not occur on or before May 21, 2004. Because the current owner of the McClain Plant has filed for bankruptcy protection, the acquisition also was subject to approval by the bankruptcy court. As part of the bankruptcy approval process, NRG McClain LLC’s interest in the plant was subject to an auction process

and on October 28, 2003, the bankruptcy court approved the sale of NRG McClain LLC’s interest in the plant to the Company. Several parties have filed interventions at the FERC opposing the Company’s application under Section 203 of the Federal Power Act to acquire NRG McClain’s interest in the power plant or, alternatively, requesting the FERC to delay approving such acquisition. The Company believed that its application met the standards under Section 203 set forth by the FERC and that its application would be approved. On December 18, 2003, the FERC shifted its policy regarding market power issues, raised wholesale market power concerns and ordered a hearing regarding the Company’s acquisition of the McClain Plant. The FERC action did not reject the Company’s request to purchase the McClain Plant, but ordered that the Company must address certain issues in an administrative hearing. On January 15, 2004, the FERC administrative law judge in charge of the hearing and the parties to the case agreed to a procedural schedule that would produce a decision on the McClain Plant acquisition no sooner than the third quarter of 2004. On January 20, 2004, the Company filed a petition for re-hearing of the FERC’s December 18, 2003 order which included new mitigation measures that were designed to allow for prompt approval of the transaction. That request is still pending before the FERC. The Company has no indication whether the FERC will accept those proposed mitigation measures. On March 2, 2004, the Company filed testimony and exhibits with the FERC administrative law judge. The testimony and exhibits indicate that, if the case proceeds to hearing, the wholesale market power issues that the FERC raised in the December 18, 2003 order may be resolved by the proposed mitigation measures. The Company also filed on March 8, 2004, in the proceeding before the FERC administrative law judge an offer of settlement proposing additional mitigation measures at an aggregate cost of approximately $18.5 million and, despite opposition from certain intervenors, requested the administrative law judge to certify the offer as a contested settlement. Following a denial of the Company’s request, the Company asked the administrative law judge to reconsider his decision or, alternatively, to grant the Company an interlocutory appeal to the FERC of his decision. The FERC administrative law judge denied the Company’s requests and the Company is appealing his decision to the FERC. Absent FERC granting the Company’s January 20 motion for reconsideration or its most recent appeal, the matter is scheduled for hearing before the FERC administrative law judge on August 3, 2004.

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

Outlook

Energy Corp. currently expects that consolidated earnings in 2004 will be between $1.60 and $1.70 per share. The 2004 outlook includes expected net income of between $120 million and $124 million for the Company. The Company’s 2004 earnings expectations have been increased primarily due to an increase in gross margins driven by approximately $6.0 million of additional fuel recoveries from its customers as well as a reduction in operating and maintenance expenses of approximately $4.9 million primarily due to a decrease in projected pension expense. Additionally, funding for Energy Corp.’s pension plan is expected to be approximately $69.0 million in 2004, of which approximately $54.5 million is the Company’s portion. Energy Corp. expects to fund the pension plan during the second and third quarters of 2004. In April 2004, Energy Corp. funded approximately $23.0 million to the pension plan, of which approximately $18.2 million was allocated to the Company.

Results of Operations


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

Operating income	$	5.0	$	2.1
Net loss	$	---	$	(3.3)

In reviewing its operating results, the Company believes that it is appropriate to focus on operating income as reported in its Condensed Statements of Operations as operating income indicates the ongoing profitability of the Company excluding unusual or infrequent items, the cost of capital and income taxes. Operating income was approximately $5.0 million and $2.1 million for the three months ended March 31, 2004 and 2003, respectively.


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

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

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

Operating income	$	5	.0	$	2	.1

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

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

Total operating revenues	$	304	.3	$	332	.6

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

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

Total sales		5	.8		5	.9

Number of customers		728,3	23		720,7	01

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

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

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

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

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

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

Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, are passed through to the Company’s customers through automatic fuel adjustment clauses. While the regulatory mechanisms for recovering fuel costs differ in Oklahoma and Arkansas, in both states the costs are passed through to customers and are intended to provide neither an ultimate benefit nor detriment to 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.

Other operating expenses, consisting of operating and maintenance expense, depreciation expense and taxes other than income, were approximately $116.1 million for the three months ended March 31, 2004 as compared to approximately $116.6 million during the same period in 2003, a decrease of approximately $0.5 million or 0.4 percent. Operating and maintenance expense decreased approximately $0.5 million or 0.7 percent for the three months ended March 31, 2004 as compared to the same period in 2003. This decrease was primarily due to a decrease of approximately $0.8 million in materials and supplies expense, a decrease of approximately $0.6 million in outside services, a decrease of approximately $0.3 million in overhead allocations by Energy Corp., a decrease of approximately $0.2 million in property insurance costs and a decrease of approximately $0.6 million in miscellaneous other items. These decreases in

operating and maintenance expense were partially offset by an increase of approximately $1.4 million in bad debt expense and an increase of approximately $0.6 million in pension expense. Depreciation expense decreased approximately $0.7 million or 2.1 percent for the three months ended March 31, 2004 as compared to the same period in 2003 primarily due to a change in the depreciation rates for the Company’s power plants. Taxes other than income increased approximately $0.7 million or 5.8 percent for the three months ended March 31, 2004 as compared to the same period in 2003 primarily due to approximately a $0.4 million increase in payroll taxes and approximately a $0.3 million increase in ad valorem taxes.

Net Interest Expense

Net interest expense includes interest income, interest expense and other interest charges. Net interest expense was approximately $9.5 million for the three months ended March 31, 2004 as compared to approximately $9.9 million during the same period in 2003, a decrease of approximately $0.4 million or 4.0 percent. This decrease was primarily due to approximately a $0.2 million decrease related to lower interest expense accruals during the three months ended March 31, 2004 as compared to the same period in 2003 due to lower interest rates.

Income Tax Benefit

Income tax benefit was approximately $4.6 million for the three months ended March 31, 2004 as compared to $4.9 million during the same period in 2003, a decrease of approximately $0.3 million or 6.1 percent. The decrease was primarily due to a lower pre-tax loss for the Company. In addition, approximately $1.7 million of Oklahoma investment tax credits were recorded during the three months ended March 31, 2004. Amortization of the federal investment tax credits was approximately $1.3 million for each of the three months ended March 31, 2004 and 2003.

Financial Condition

The balance of Accounts Receivable – Customers was approximately $90.0 million and $123.1 million at March 31, 2004 and December 31, 2003, respectively, a decrease of approximately $33.1 million or 26.9 percent. The decrease was primarily due to a decrease in the Company’s billings to its customers reflecting lower fuel costs in March 2004 as compared to December 2003 and warmer than normal weather.

The balance of Advances to Parent was approximately $13.4 million and $51.8 million at March 31, 2004 and December 31, 2003, respectively, a decrease of approximately $38.4 million or 74.1 percent. The decrease was primarily due to commercial paper issued in December 2003 by the Company 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. during the first quarter of 2004.

The balance of Fuel Inventories was approximately $45.0 million and $60.0 million at March 31, 2004 and December 31, 2003, respectively, a decrease of approximately $15.0 million

or 25.0 percent. The decrease was primarily due to a decrease in natural gas inventory primarily due to it being advantageous for the Company to use the lower priced fuel in inventory rather than purchasing higher priced natural gas during the first quarter of 2004. Also contributing to the decrease was a decrease in coal inventories due to the coal train unloading system at the Sooner Plant being out of service for most of the first quarter of 2004.

The balance of Short-Term Debt was approximately $50.0 million at December 31, 2003. There was no short-term debt outstanding at March 31, 2004. The decrease was primarily due to commercial paper issued in December 2003 by the Company in anticipation of the planned acquisition of the McClain Plant. Due to a delay in the completion of the McClain Plant acquisition, the Company repaid the outstanding commercial paper balance during the first quarter of 2004.

Off-Balance Sheet Arrangements

Off-balance sheet arrangements include any transactions, agreements or other contractual arrangements to which an unconsolidated entity is a party and under which the Company has: (i) any obligation under a guarantee contract having specific characteristics as defined in Financial Accounting Standards Board (“FASB”) Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”; (ii) a retained or contingent interest in assets transferred to an unconsolidated entity or similar arrangement that serves as credit, liquidity or market risk support to such entity for such assets; (iii) any obligation, including a contingent obligation, under a contract that would be accounted for as a derivative instrument but is indexed to the Company’s own stock and is classified in stockholders’ equity in the Company’s 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. 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.

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 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 Agreements

At March 31, 2004 and December 31, 2003, the Company had one outstanding interest rate swap agreement effective March 30, 2001, to convert $110.0 million of 7.30 percent fixed rate debt due October 15, 2025, to a variable rate based on the three month London InterBank Offering Rate. 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 currently has contracts with qualified cogeneration facilities and small power production producers’ (“QF contracts”) for the purchase of 540 MWs, all of which expire in the next one to five years, although as discussed above, the Company recently tentatively agreed to a new 15-year agreement with one of the QFs. The Company will continue reviewing all of the supply alternatives to these expiring QF contracts that minimize the total cost of generation to our customers, including exercising our options (if applicable) to extend these QF contracts at pre-determined rates. Accordingly, 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 10 of Notes to Condensed Financial Statements for a description of current proceedings involving a PowerSmith QF contract.

On August 18, 2003, the Company signed an asset purchase agreement to acquire NRG McClain LLC’s 77 percent interest in the McClain Plant. Closing has been delayed pending receipt of FERC approval. The purchase price for the interest in the McClain Plant is approximately $159.9 million, subject to adjustment for prepaid gas and property taxes. See “Overview – Pending Acquisition of Power Plant.” If approval is received, the Company expects to fund the acquisition with a combination of a capital contribution from Energy Corp. funded in part by Energy Corp.’s equity issuance in August 2003, and the issuance of long-term debt by the Company. 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 the pension plan in 2004, of which approximately $43.5 million is the Company’s portion. Energy Corp. presently anticipates contributing an additional $13.0 million to the pension plan during 2004, for a total contribution of approximately $69.0 million in 2004. After the benefit liability was remeasured as of January 1, 2004, Energy Corp. decided to make the additional contribution to ensure the pension plan maintains an adequate funded status. Energy Corp. plans to make contributions to the pension plan during the second and third quarters of 2004. In April 2004, Energy Corp. funded approximately $23.0 million to the pension plan, of which approximately $18.2 million was allocated to the Company. The expected contributions to the pension plan, anticipated to be in the form of cash, are discretionary contributions and are not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974.

Future Sources of Financing

Other than in connection with the purchase of the McClain Plant, 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 short-term debt will be adequate over the next three years to meet other anticipated capital expenditures, operating needs, payment of dividends and maturities of long-term debt. As discussed below, the Company utilizes short-term borrowings from Energy Corp. to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged. Later in 2004, assuming the acquisition of the McClain Plant is approved by the FERC, the Company plans to issue debt to fund the purchase of the McClain Plant and for general corporate purposes.

Short-Term Debt

Short-term borrowings from Energy Corp. generally are used to meet working capital requirements. As indicated below, the Company also has in place a $100 million line of credit with a bank. The short-term debt balance was approximately $50.0 million at December 31, 2003 primarily due to the planned acquisition of the McClain Plant. There was no short-term debt outstanding at March 31, 2004. The decrease was primarily due to commercial paper issued in December 2003 by the Company in anticipation of the planned acquisition of the McClain Plant. Due to a delay in the completion of the McClain Plant acquisition, the Company repaid the outstanding commercial paper balance during the first quarter of 2004.

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

Lines of Credit and Available Cash (In millions)

Entity	Amount Available		Amount Outstanding		Maturity

Energy Corp. (A)		$ 15.0		$ ---	April 6, 2004
The Company		100.0		---	June 26, 2004
Energy Corp. (A)		300.0		---	December 9, 2004

		415.0		---
Cash		149.6		N/A	N/A

Total		$ 564.6		$ ---

(A) The lines of credit at Energy Corp. are used to back up its commercial paper borrowings. There was no short-term debt outstanding at March 31, 2004. In April 2004, Energy Corp. renewed its $15.0 million credit facility, shown in the table above, which matures April 6, 2005.

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

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

Critical Accounting Policies and Estimates

The Condensed 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 effect 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 10 of Notes to Condensed Financial Statements and in the Company’s Form 10-K for the year ended December 31, 2003.

Gas Transportation and Storage Agreement

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

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. The Company currently expects that hearings will be held in mid-2004.

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 below, in Note 9 of Notes to Condensed Financial Statements and in Note 11 to the Company’s Financial Statements included in the Company’s Form 10-K for the year ended December 31, 2003, management, after consultation with legal counsel, does not anticipate that liabilities arising out of currently pending or threatened lawsuits, claims and contingencies will have a material adverse effect on the Company’s financial position, results of operations or cash flows. This assessment of currently pending or threatened lawsuits is subject to change.

Pending 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. Closing has been delayed pending receipt of FERC approval. The acquisition of this interest in the McClain Plant would clearly constitute an acquisition of New Generation under the Settlement Agreement. The purchase price for the interest in the McClain Plant is approximately $159.9 million, subject to adjustment for prepaid gas and property taxes. See “Overview - Pending Acquisition of Power Plant” above and Note 10 of Notes to Condensed Financial Statements for a further description of this matter and a description of current proceedings involving a PowerSmith QF contract.

Sooner Power Plant Coal Dust Explosion

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 for a description of certain legal proceedings presently pending. 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 and Reports on Form 8-K.

(a)	Exhibits

	Exhibit No.	Description

	2.01	Amendment No. 6 to Asset Purchase Agreement, dated as of March 12, 2004 by and between the Company and NRG McClain LLC. (Filed as Exhibit 2.01 to Energy Corp.’s Form 10-Q for the quarter ended March 31, 2004 (File 1-12579) and incorporated by reference herein)

	2.02	Amendment No. 7 to Asset Purchase Agreement, dated as of April 15, 2004 by and between the Company and NRG McClain LLC. (Filed as Exhibit 2.02 to Energy Corp.’s Form 10-Q for the quarter ended March 31, 2004 (File 1-12579) and incorporated by reference herein)

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

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

(b)	Reports on Form 8-K

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

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

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

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

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

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

SIGNATURE

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

	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)

May 7, 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: May 7, 2004

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

Exhibit 31.01

CERTIFICATIONS

I, James R. Hatfield, certify that:

1. I have reviewed this quarterly report on Form 10-Q of 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: May 7, 2004

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

Exhibit 32.01

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

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

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

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

May 7, 2004

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

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

FORM 10-Q

OR

OKLAHOMA GAS AND ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2004

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

1. Summary of Significant Accounting Policies

Organization

Basis of Presentation

Accounting Records

Income Taxes

Fair Value of Financial Instruments

Related Party Transactions

Reclassifications

2. Accounting Pronouncements

3. Price Risk Management Assets and Liabilities

4. Accumulated Other Comprehensive Loss

5. Supplemental Cash Flow Information

6. Long-Term Debt

7. Short-Term Debt

8. Retirement Plans and Postretirement Benefit Plans

9. Commitments and Contingencies

10. Rate Matters and Regulation

Recent Regulatory Matters

Pending Regulatory Matters

Introduction

Forward-Looking Statements

Overview

Outlook

Results of Operations

Financial Condition

Off-Balance Sheet Arrangements

Liquidity and Capital Requirements

Future Capital Requirements

Future Sources of Financing

Critical Accounting Policies and Estimates

Accounting Pronouncements

Electric Competition; Regulation

Commitments and Contingencies

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Item 4. Controls and Procedures.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

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

SIGNATURE

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

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