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

FORM 10-Q

(Mark One)

[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2005

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 March 31, 2005, 40,378,745 shares of common stock, par value $2.50 per share, were outstanding, all of which were held by OGE Energy Corp. There were no other shares of capital stock of the registrant outstanding at such date.

OKLAHOMA GAS AND ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2005

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	26

Item 3. Quantitative and Qualitative Disclosures About Market Risk	37

Item 4. Controls and Procedures	37

Part II - OTHER INFORMATION

Item 1. Legal Proceedings	38

Item 6. Exhibits	39

Signature	40

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)

		March 31,			December 31,
(In millions)		2005			2004


ASSETS
CURRENT ASSETS
Accounts receivable - customers, less reserve of $2.0 and $2.7, respectively	$	76	.0	$	91	.7
Accounts receivable - other, net		11	.4		13	.7
Advances to parent		-	--		26	.5
Accrued unbilled revenues		48	.0		45	.5
Fuel inventories, at LIFO cost		35	.9		42	.2
Materials and supplies, at average cost		51	.1		50	.3
Accumulated deferred tax assets		8	.8		9	.0
Fuel clause under recoveries		29	.7		54	.3
Recoverable take or pay gas charges		13	.4		17	.0
Other		4	.9		6	.0

Total current assets		279	.2		356	.2


OTHER PROPERTY AND INVESTMENTS, at cost		4	.8		4	.8


PROPERTY, PLANT AND EQUIPMENT
In service		4,585	.4		4,539	.0
Construction work in progress		102	.3		94	.4
Other		1	.0		1	.0

Total property, plant and equipment		4,688	.7		4,634	.4
Less accumulated depreciation		2,107	.1		2,085	.8

Net property, plant and equipment		2,581	.6		2,548	.6


DEFERRED CHARGES AND OTHER ASSETS
Income taxes recoverable from customers, net		30	.7		30	.9
Intangible asset - unamortized prior service cost		31	.8		31	.8
Prepaid benefit obligation		60	.5		67	.2
Price risk management		2	.0		3	.9
Other		45	.7		40	.8

Total deferred charges and other assets		170	.7		174	.6


TOTAL ASSETS	$	3,036	.3	$	3,084	.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)		2005			2004


LIABILITIES AND STOCKHOLDER’S EQUITY
CURRENT LIABILITIES
Accounts payable - affiliates	$	28	.3	$	45	.4
Accounts payable - other		86	.3		93	.0
Advances from parent		2	.1		-	--
Customers’ deposits		46	.4		45	.6
Accrued taxes		12	.2		20	.4
Accrued interest		15	.7		16	.4
Tax collections payable		7	.1		7	.1
Accrued vacation		12	.0		11	.6
Price risk management		-	--		0	.1
Gas imbalances		-	--		0	.1
Provision for payments of take or pay gas		17	.4		21	.0
Other		17	.3		21	.4

Total current liabilities		244	.8		282	.1


LONG-TERM DEBT		845	.3		847	.2


DEFERRED CREDITS AND OTHER LIABILITIES
Accrued pension and benefit obligations		157	.0		155	.5
Accumulated deferred income taxes		578	.8		570	.4
Accumulated deferred investment tax credits		35	.6		36	.8
Accrued removal obligations, net		121	.8		122	.2
Asset retirement obligation		1	.1		1	.1
Other		6	.2		6	.5

Total deferred credits and other liabilities		900	.5		892	.5


STOCKHOLDER’S EQUITY
Common stockholder’s equity		665	.5		665	.5
Retained earnings		444	.3		461	.0
Accumulated other comprehensive loss, net of tax		(64	.1)		(64	.1)

Total stockholder’s equity		1,045	.7		1,062	.4


TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	3,036	.3	$	3,084	.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)		2005			2004


OPERATING REVENUES	$	301	.0	$	304	.3

COST OF GOODS SOLD*		175	.0		183	.2

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

OPERATING INCOME		2	.8		5	.0


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

Net other income (expense)		0	.2		(0	.1)


INTEREST INCOME (EXPENSE)
Interest income		1	.6		0	.2
Interest on long-term debt		(9	.7)		(9	.1)
Allowance for borrowed funds used during construction		0	.6		0	.1
Interest on short-term debt and other interest charges		(0	.6)		(0	.7)

Net interest expense		(8	.1)		(9	.5)


LOSS BEFORE TAXES		(5	.1)		(4	.6)

INCOME TAX BENEFIT		(3	.4)		(4	.6)


NET LOSS	$	(1	.7)	$	-	--


* Before intercompany eliminations.

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

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


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


CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(1	.7)	$	-	--
Adjustments to reconcile net loss to net cash provided from
operating activities
Depreciation		33	.1		31	.9
Deferred income taxes and investment tax credits, net		7	.7		(3	.2)
Gain on sale of assets		(0	.2)		-	--
Price risk management liabilities		(0	.1)		-	--
Other assets		2	.7		3	.5
Other liabilities		(2	.4)		(0	.9)
Change in certain current assets and liabilities
Accounts receivable - customers, net		15	.7		33	.1
Accounts receivable - other, net		2	.3		1	.3
Accrued unbilled revenues		(2	.5)		0	.6
Fuel, materials and supplies inventories		5	.5		12	.1
Fuel clause under recoveries		24	.6		3	.6
Other current assets		4	.6		0	.5
Accounts payable		(6	.7)		2	.6
Accounts payable - affiliates		(3	.1)		3	.6
Customers’ deposits		0	.8		1	.7
Accrued taxes		(8	.2)		(9	.5)
Accrued interest		(0	.7)		1	.3
Gas imbalance liability		(0	.1)		-	--
Fuel clause over recoveries		-	--		0	.4
Other current liabilities		(7	.4)		1	.0

Net Cash Provided from Operating Activities		63	.9		83	.6


CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(63	.8)		(43	.1)
Proceeds from sale of assets		0	.3		-	--

Net Cash Used in Investing Activities		(63	.5)		(43	.1)


CASH FLOWS FROM FINANCING ACTIVITIES
Increase (decrease) in short-term debt, net		28	.6		(11	.6)
Dividends paid on common stock		(29	.0)		(28	.9)

Net Cash Used in Financing Activities		(0	.4)		(40	.5)


NET INCREASE IN CASH AND CASH EQUIVALENTS		-	--		-	--
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		-	--		4	.0

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 is 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 primarily 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, 2005 and December 31, 2004, the results of its operations for the three months ended March 31, 2005 and 2004, and the results of its cash flows for the three months ended March 31, 2005 and 2004, have been included and are of a normal recurring nature.

Due to seasonal fluctuations and other factors, the operating results for the three months ended March 31, 2005 are not necessarily indicative of the results that may be expected for the year ending December 31, 2005 or for any future period. The Condensed 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, 2004.

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

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

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

		March 31,			December 31,
(In millions)		2005			2004

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

Total Regulatory Assets	$	112	.9	$	137	.3


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

Total Regulatory Liabilities	$	130	.7	$	130	.1

Income taxes recoverable from customers represent income tax benefits previously used to reduce 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.”

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 are intended to allow the Company to amortize under or over recovery. The Company expects to recover the fuel clause under recoveries during 2005.

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

As a result of the completion of the acquisition of a 77 percent interest in the 520 megawatt (“MW”) NRG McClain Station (the “McClain Plant”) on July 9, 2004, and consistent with the 2002 agreed-upon settlement of the Company’s rate case (the “Settlement Agreement”) with the OCC, the Company has the right to accrue a regulatory asset, for a period not to exceed 12 months subsequent to the completion of the acquisition and the operation of the McClain Plant, consisting of the non-fuel operation and maintenance expenses, depreciation, cost of debt associated with the investment and ad valorem taxes. All prudently incurred costs accrued through the regulatory asset within the 12-month period would be included in the Company’s prospective cost of service and would be recovered over a period to be determined by the OCC.

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

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

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

Accrued removal obligations represent asset retirement costs previously recovered from ratepayers for other than legal obligations. In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations,” 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.

Also, as part of the Settlement Agreement, the Company agreed to consider competitive bidding as a basis to select its provider for gas transportation service to its natural gas-fired generation facilities pursuant to the terms set forth in the Settlement Agreement. The prescribed bidding process detailed in the Settlement Agreement provided that separate transportation services be bid for each generation facility. The Company believes that, in order for it to achieve maximum coal generation, to deliver the lowest cost energy to its customers and to ensure reliable electric service, it must have integrated, firm no-notice load following service for both gas transportation and gas storage. On April 29, 2003, as required by the Settlement Agreement, the Company filed an application with the OCC in which the Company advised the OCC that, after careful consideration, competitive bidding for gas transportation was rejected in favor of a new intrastate integrated, firm no-notice load following gas transportation and storage services agreement with its affiliate, Enogex Inc. and subsidiaries (“Enogex”). On October 22, 2004, the administrative law judge (“ALJ”) overseeing the proceeding recommended approximately $41.9 million annual demand fee recovery with the Company refunding to its customers any demand fees collected in excess of this amount. If this recommendation is ultimately accepted, the Company believes its refund obligation would be approximately $7.9 million at March 31, 2005, which the Company does not believe is material in light of previously established reserves. See Note 10 for a further discussion.

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

Income Taxes

The Company is a member of an affiliated group that files consolidated income tax returns. Income taxes are allocated to each company in the affiliated group based on its separate taxable income or loss. Federal investment tax credits on electric utility property have been deferred and are being amortized to income over the life of the related property. Amortization of the federal investment tax credits was approximately $1.3 million for each of the three month periods ended March 31, 2005 and 2004 and 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.

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

American Jobs Creation Act of 2004

On October 22, 2004, President Bush signed into law the American Jobs Creation Act of 2004 (the “Jobs Creation Act”). The Jobs Creation Act amended and added a significant number of provisions to the Internal Revenue Code and these changes affect virtually all taxpayers. The Jobs Creation Act includes a provision that entitles all U.S. manufacturers with qualified manufacturing activities to a “Deduction Related to Production Activities” (“DRPA”). Certain activities of the Company, including the generation of electricity, is included in the list of qualifying manufacturing activities for purposes of the DRPA. Thus, the Company believes that the DRPA could impact the Company’s future effective income tax rate.

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

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

Related Party Transactions

Energy Corp. allocated operating costs to the Company of approximately $21.4 million and $22.0 million during the three months ended March 31, 2005 and 2004, 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, 2005 and 2004, the Company paid Enogex approximately $8.7 million and $8.5 million, respectively, for transporting gas to the Company’s natural gas-fired generating facilities. During the three months ended March 31, 2005 and 2004, the Company paid Enogex approximately $3.2 million and $3.3 million, respectively, for natural gas storage services. During the three months ended March 31, 2005 and 2004, the Company also recorded natural gas purchases from Enogex of approximately $10.0 million and $0.1 million, respectively. Approximately $6.5 million and $8.4 million were recorded at March 31, 2005 and December 31, 2004, respectively, and are included in Accounts Payable – Affiliates in the Condensed Balance Sheets for these activities. See Note 10 for a discussion of the gas transportation and storage contract between the Company and Enogex.

The Company recorded interest income from Energy Corp. for advances made by the Company to Energy Corp. of approximately $0.1 million for each of the three month periods ended March 31, 2005 and 2004.

During the three months ended March 31, 2005, the Company recorded interest expense of approximately $0.1 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, 2005 and 2004, the Company paid approximately $29.0 million and $28.9 million, respectively, in dividends to Energy Corp.

2. Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123 (Revised), “Share-Based Payment,” which replaces SFAS No. 123, “Accounting for Stock-Based Compensation” and supersedes Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.” This statement applies to all share-based payment transactions in which an entity acquires goods or services by issuing (or offering to issue) its shares, share options or other equity instruments (except for equity instruments held by an employee share ownership plan) or by incurring liabilities to an employee or other supplier (a) in amounts based, at least in part, on the price of the entity’s shares or other equity instruments or (b) that require or may require settlement by issuing the entity’s equity shares or other equity instruments. This statement applies to all awards granted after the required effective date and to awards modified, repurchased or cancelled after that date. The cumulative effect of initially applying this statement, if any, is recognized as of the required effective date. This statement requires a public entity to measure and recognize the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with limited exceptions). The grant-date fair value of employee share options and similar instruments will be estimated using option-pricing models adjusted for the unique characteristics of those instruments. If an equity award is modified after the grant date, incremental compensation cost will be recognized in an amount equal to the excess of the fair value of the modified award over the fair value of the original award immediately before the modification. As of the required effective date, all public entities that used the fair-value based method for either recognition or disclosure under SFAS No. 123 will apply this statement using a modified version of prospective application. Under that transition method, compensation cost is recognized on or after the required effective date for the portion of outstanding awards for which the requisite service has not yet been rendered, based on the grant-date fair value of those awards calculated under SFAS No. 123 for either recognition or pro forma disclosures. For periods prior to the required effective date, those entities may elect to apply a modified version of retrospective application under which financial statements for prior periods are adjusted on a basis consistent with the pro forma disclosures required for those periods by SFAS No. 123. Adoption of SFAS No. 123(R) is required for public entities as of the beginning of the first fiscal year beginning after June 15, 2005. The Company will adopt this new standard effective January 1, 2006. Management has not yet determined what the impact of this new standard will be on its financial position or results of operations.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” in which an entity is required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event if the liability’s fair value can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred. Uncertainty surrounding the timing and method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. However, in some cases, there is insufficient information to estimate the fair value of an asset retirement obligation.

In these cases, the liability should be initially recognized in the period in which sufficient information is available for an entity to make a reasonable estimate of the liability’s fair value. This interpretation is effective no later than the end of fiscal years ending after December 15, 2005. The Company will adopt this new interpretation effective December 31, 2005. Retrospective application for interim financial information is permitted but not required. This interpretation will require both recognition of a cumulative change in accounting principle and disclosure of the liability on a pro forma basis for transition purposes. Management has not yet determined what the impact of this new interpretation will be on its 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, 2005 and 2004, the Company’s use of price risk management instruments involved the use of an interest rate swap agreement. This agreement involves the exchange of fixed price or rate payments in exchange for floating price or rate payments over the life of the instrument without an exchange of the underlying principal amount.

In accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, the Company recognizes all of its derivative instruments as Price Risk Management assets or liabilities in the Condensed Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation. For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative instrument is recognized in current earnings on the same line item as the gain or loss recorded for the change in the fair value of the hedged item. For derivatives that are designated and qualify as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of Accumulated Other Comprehensive Income and recognized into earnings in the same period during which the hedged transaction affects earnings. The ineffective portion of a derivative’s change in fair value is recognized currently in earnings. As a matter of policy, all non-trading hedged items (except for interest rate swap agreements) and the derivatives used for cash flow hedges must be identical with respect to time and location and must be in compliance with SFAS No. 133. Forecasted transactions designated as the hedged item in a cash flow hedge are regularly evaluated to assess whether they continue to be probable of occurring. If the forecasted transactions are no longer probable of occurring, hedge accounting will cease on a prospective basis and all future changes in the fair value of the derivative and any amounts recorded in Accumulated Other Comprehensive Income will be recognized directly in earnings.

The Company’s interest rate swap agreement has been designated as a fair value hedge under SFAS No. 133. The fair value hedge qualified for the shortcut method prescribed by SFAS No. 133. Under the shortcut method, the Company assumes that the hedged item’s change in fair value is exactly as much as the derivative’s change in fair value. See Note 6 for a description of the Company’s interest rate swap agreement.

4. Accumulated Other Comprehensive Loss

There were no items of other comprehensive income for the three months ended March 31, 2005 and 2004. Accumulated other comprehensive loss at both March 31, 2005 and December 31, 2004 included an after tax loss ($104.6 million pre-tax and $64.1 million after tax) related to a minimum pension liability adjustment based on a review of the funded status of Energy Corp.’s pension plan by Energy Corp.’s actuarial consultants as of December 31, 2004. Any increases or decreases in the minimum pension liability will be reflected in Other Comprehensive Income or Loss in the fourth quarter.

5. Supplemental Cash Flow Information

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

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

NON-CASH INVESTING AND FINANCING ACTIVITIES
Change in fair value of long-term debt due to interest rate swap	$	(1	.9)	$	1	.9

6. Long-Term Debt

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

Long-Term Debt with Optional Redemption Provisions

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

SERIES		DATE DUE		AMOUNT

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

	Tot	al (redeemable during next 12 months)	$	135	.4

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

agent has successfully remarketed all tendered bonds. If the remarketing agent is unable to remarket any such Bonds, the Company is obligated to repurchase such unremarketed Bonds. The Company has sufficient liquidity to meet these obligations.

Interest Rate Swap Agreement

Fair Value Hedge

At March 31, 2005 and December 31, 2004, the Company had one outstanding interest rate swap agreement that qualified as a fair value hedge effective March 30, 2001, to convert $110.0 million of 7.30 percent fixed rate debt due October 15, 2025, to a variable rate based on the three month London InterBank Offering Rate. The objective of this interest rate swap was to achieve a lower cost of debt and to raise the percentage of total corporate long-term floating rate debt to reflect a level more in line with industry standards. This interest rate swap qualified as a fair value hedge under SFAS No. 133 and met all of the requirements for a determination that there was no ineffective portion as allowed by the shortcut method under SFAS No. 133.

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

7. Short-Term Debt

At March 31, 2005, the Company had approximately $2.1 million in outstanding advances from Energy Corp. At December 31, 2004, the Company had approximately $26.5 million in outstanding advances to Energy Corp. and no commercial paper outstanding. The following table shows Energy Corp.’s and the Company’s lines of credit in place, commercial paper outstanding and available cash at March 31, 2005. At March 31, 2005, Energy Corp.’s short-term borrowings consisted of borrowings on its revolving credit agreement and commercial paper.

Lines of Credit, Commercial Paper and Available Cash (In millions)

Entity	Amount Available		Amount Outstanding		Maturity

Energy Corp.		$ 15.0		$ ---	April 6, 2005 (A)
The Company (B)		100.0		---	October 20, 2009 (C)
Energy Corp. (D)		450.0		154.0	October 20, 2009 (C)

		565.0		154.0
Cash		---		N/A	N/A

Total		$ 565.0		$ 154.0

(A) In April 2005, Energy Corp. renewed its $15.0 million credit facility, shown in the table above, which matures April 6, 2006.
(B) No borrowings were outstanding at March 31, 2005 under this line of credit; however, $0.2 million of this line of credit supports a letter of credit.
(C) Each of the new credit facilities has a five-year term with two options to extend the term for one year.
(D) This bank facility is available to back up a maximum of $300.0 million of Energy Corp.’s commercial paper borrowings and can be used as a letter of credit facility. At March 31, 2005, Energy Corp. had approximately $85.0 million in outstanding borrowings under this line of credit and approximately $69.0 million in commercial paper borrowings.

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

Unlike Energy Corp. and Enogex, 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 for a two-year period beginning January 1, 2005 and ending December 31, 2006.

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

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

Net Periodic Benefit Cost



	Pension Plan and
	Restoration of						Postretirement
	Retirement Income Plan						Benefit Plans

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

(In millions)		2005			2004			2005			2004

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

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

Pension Plan Funding

Energy Corp. previously disclosed in its Form 10-K for the year ended December 31, 2004 that it expected to contribute approximately $37.4 million to the pension plan in 2005, of which approximately $29.0 million was expected to be allocated to the Company. Energy Corp. presently anticipates reducing this amount by approximately $5.4 million during 2005, for a total contribution of approximately $32.0 million in 2005, which represents Energy Corp.’s 2004 pension expense, of which approximately $24.8 million is expected to be allocated to the Company. Energy Corp. plans to make contributions to the pension plan during the second and third quarters of 2005. In April 2005, Energy Corp. funded approximately $10.7 million to the pension plan, of which approximately $8.3 million was allocated to the Company. The remaining expected contributions to the pension plan in 2005, anticipated to be in the form of cash, are discretionary contributions and are not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974.

Medicare Prescription Drug, Improvement and Modernization Act of 2003

On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Medicare Act”). The Medicare Act expanded Medicare to include, for the first time, coverage for prescription drugs. In May 2004, the FASB issued FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” FAS 106-2 provided guidance on the accounting for the effects of the Medicare Act for employers that sponsor postretirement heath care plans that provide prescription drug benefits. FAS 106-2 also required those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Medicare Act. Energy Corp. adopted this new standard effective July 1, 2004 with retroactive application to the date of the Medicare Act’s enactment. Management expects that the accumulated plan benefit obligation (“APBO”) for Energy Corp.’s postretirement medical plan will be reduced by approximately $13.3 million as a result of savings to Energy

Corp.’s postretirement medical plan resulting from the Medicare Act, which will reduce Energy Corp.’s costs for its postretirement medical plan by approximately $2.5 million annually, of which approximately $2.1 million is expected to be allocated to the Company. The $2.1 million in annual savings is comprised of a reduction of approximately $1.2 million from amortization of the $13.3 million gain due to the reduction of the APBO, a reduction in the interest cost on the APBO of approximately $0.7 million and a reduction in the service cost due to the subsidy of approximately $0.2 million.

9. Commitments and Contingencies

Except as set forth below and in Note 10, the circumstances set forth in Note 12 to the Company’s Condensed Financial Statements included in the Company’s Form 10-K for the year ended December 31, 2004, appropriately represent, in all material respects, the current status of any material commitments and contingent liabilities.

Natural Gas Measurement Case

As reported in Note 12 to the Company’s Financial Statements in the Company’s Form 10-K for the year ended December 31, 2004, the Company has been involved in legal proceedings filed by Jack J. Grynberg in federal courts relating to natural gas measurement. Various procedural motions have been filed and discovery is proceeding on limited jurisdictional issues. A hearing on the defendants’ motions to dismiss for lack of subject matter jurisdiction, including public disclosure, original source and voluntary disclosure requirements was held March 17 – 18, 2005. The court indicated that a ruling would be made regarding these motions by the end of April 2005; however, no ruling has been issued to date.

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

Environmental Laws and Regulations

Air

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

On March 10, 2005, the Environmental Protection Agency (“EPA”) published the Clean Air Interstate Rule (“CAIR”). This rule is intended to control SO2 and NOX emissions from utility boilers in order to minimize the interstate transport of air pollution. The state of Oklahoma is not listed as one of the states affected by the rule. However, states not subject to the CAIR must demonstrate to the EPA that their emissions do not significantly impact the air quality in downwind states. If a state cannot make this demonstration it then becomes subject to the CAIR. If Oklahoma becomes subject to the CAIR, the Company could have significant additional capital and operating expenditures.

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

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

Water

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

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

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 Financial Statements. Except as otherwise stated above, in Notes 12 and 13 of Notes to Financial Statements in the Company’s Form 10-K for the year ended December 31, 2004, in Item 3 of that report, in Note 10 below or in Item 1 of Part II of this report, management, after consultation with legal counsel, does not anticipate that liabilities arising out of currently pending or threatened lawsuits, claims and contingencies will have a material adverse effect on the Company’s 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

Except as set forth below, the circumstances set forth in Note 13 to the Company’s Financial Statements included in the Company’s Form 10-K for the year ended December 31, 2004, appropriately represent, in all material respects, the current status of any regulatory matters.

Regulatory Matters

2002 Settlement Agreement

On November 22, 2002, the OCC signed a rate order containing the provisions of a Settlement Agreement of the Company’s rate case. The Settlement Agreement provides for, among other items: (i) a $25.0 million annual reduction in the electric rates of the Company’s Oklahoma customers which went into effect January 6, 2003; (ii) recovery by the Company, through rate base, of the capital expenditures associated with the January 2002 ice storm; (iii) the Company to acquire electric generation of not less than 400 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 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 from 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. During the three months ended March 31, 2005, the Company recovered approximately $1.8 million in annual net profits from off-system sales. Including this amount, the Company has recovered a total of $5.4 million related to the regulatory asset since December 31, 2002, which is in accordance with the Settlement

Agreement. In April 2005, the Company expects to begin crediting annual net profits from off-system sales to the Company’s Oklahoma customers up to $3.6 million and any annual net profits from off-system sales in excess of this amount will be shared between the Company’s Oklahoma customers and the Company in accordance with the Settlement Agreement.

Recent Acquisition of Power Plant

On July 9, 2004, the Company completed the acquisition of NRG McClain LLC’s 77 percent interest in the McClain Plant. This transaction was intended to satisfy the requirement in the Settlement Agreement to acquire New Generation. The McClain Plant includes natural gas-fired combined cycle combustion turbine units and is located near Newcastle, Oklahoma in McClain County, Oklahoma. The McClain Plant began operating in 2001. The owner of the remaining 23 percent interest in the McClain Plant is the Oklahoma Municipal Power Authority (“OMPA”).

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

measures by June 2005. One party has filed a request for rehearing of the FERC’s July 2, 2004 order. On April 18, 2005, the FERC issued an order denying the party’s request for rehearing. This party has 60 days to file a petition for review with the FERC.

On April 4, 2005, the Company filed with the OCC a notice of intent informing the OCC that the Company plans to file an application for a rate increase on or about May 20, 2005 to recover, among other things, its investment in, and the operating expenses of, the McClain Plant. In the notice of intent, the Company proposes that new rates go into effect upon issuance of an order by the OCC no later than 180 days from the date of filing of the application. The proposed effective date of the rate change is the first billing cycle in December 2005. As provided in the Settlement Agreement, until the Company seeks and obtains approval of a request to increase base rates to recover, among other things, the investment in the plant, the Company will have the right to accrue a regulatory asset, for a period not to exceed 12 months subsequent to the completion of the acquisition and the operation of the McClain Plant, consisting of the non-fuel operation and maintenance expenses, depreciation, cost of debt associated with the investment and ad valorem taxes. If the OCC were to approve the Company’s request, all prudently incurred costs accrued through the regulatory asset within the 12-month period (which amount was approximately $17.8 million at March 31, 2005) would be included in the Company’s prospective cost of service and would be recovered over a period to be determined by the OCC.

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

Pending Regulatory Matters

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

Gas Transportation and Storage Agreement

As part of the Settlement Agreement, the Company also agreed to consider competitive bidding as a basis to select its provider for gas transportation service to its natural gas-fired generation facilities pursuant to the terms set forth in the Settlement Agreement. The prescribed bidding process detailed in the Settlement Agreement provided that separate transportation services be bid for each generation facility. The Company believes that, in order for it to achieve maximum coal generation, to deliver the lowest cost energy to its customers and to ensure

reliable electric service, it must have integrated, firm no-notice load following service for both gas transportation and gas storage. This type of service is required to permit natural gas units to satisfy the daily swings in customer demand placed on the Company’s system and not impede coal energy production. Accordingly, the Company evaluated its competitive bid options in light of these circumstances. The study determined that the required integrated service is not available in the marketplace from parties other than Enogex. The study also indicated that non-integrated service would result in higher costs to customers. The Company’s evaluation clearly demonstrates that the Enogex integrated gas system provides superior integrated, firm no-notice load following service to the Company that is not available from other companies serving the Company marketplace.

On April 29, 2003, as required by the Settlement Agreement, the Company filed an application with the OCC in which the Company advised the OCC that, after careful consideration, competitive bidding for gas transportation was rejected in favor of a new intrastate integrated, firm no-notice load following gas transportation and storage services agreement with Enogex. This seven-year agreement provides for gas transportation and storage services for each of the Company’s natural gas-fired generation facilities. The Company will pay Enogex annual demand fees of approximately $46.8 million for the right to transport specified maximum daily quantities (“MDQ”) and maximum hourly quantities (“MHQ”) of gas at various minimum gas delivery pressures depending on the operational needs of the individual generating facility. In addition, the Company supplies system fuel in-kind for its pro-rata share of actual fuel and loss and unaccounted for gas on the transportation system. To the extent the Company transports gas in quantities in excess of the prescribed MDQs or MHQs, it pays an overrun service charge. During the three months ended March 31, 2005 and 2004, the Company paid Enogex approximately $11.9 million and $11.8 million, respectively, for gas transportation and storage services.

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

The Company filed rebuttal testimony on August 16, 2004 in this case. Hearings in this case before an ALJ occurred from September 16-22, 2004. On October 22, 2004, the ALJ

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

Competitive Bidding and Prudence Reviews for Electric Utility Providers

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

Review of the Company’s Fuel Adjustment Clause for Calendar Year 2003

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

Southwest Power Pool

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

suspended. The SPP Board of Directors voted on April 26, 2005 to make the implementation effective no later than March 1, 2006.

Market-Based Rate Authority

On December 22, 2003, the Company and its affiliate, OGE Energy Resources, Inc. (“OERI”) filed a triennial market power update based on the supply margin assessment test. On April 14, 2004, the FERC issued: (1) interim requirements for the FERC jurisdictional electric utilities who have been granted authority to make wholesale sales at market-based rates; and (2) an order initiating a new rulemaking on future market-based rates authorizations. The interim method for analyzing generation market power requires two assessments – whether the utility is a pivotal supplier based on a control area’s annual peak demand and whether the utility exceeds certain market share thresholds on a seasonal basis. If an applicant fails to pass either assessment, the FERC will presume that the utility can exercise generation market power and will initiate an investigation into the scope of the applicant’s market power. The FERC will allow a utility to rebut that presumption through the submission of additional information. If an applicant is found to have generation market power, the applicant must propose a market power mitigation plan. The new interim assessment methods are applicable to all pending initial market-based rate applications and triennial reviews pending the rulemaking described below. On May 13, 2004, the FERC directed all utilities with pending three year market-based reviews to revise the generation market power portion of their three year review to address the two interim tests described above. In the rulemaking proceeding, the FERC is seeking comments on the adequacy of the FERC’s current analysis of market-based rate filings, including the adequacy of the new “interim” assessment of generation market power. The Company and OERI submitted a compliance filing to the FERC on February 7, 2005 which shows the impact of the new requirements on the Company and OERI. In the compliance filing, the Company and OERI passed the pivotal supplier screen but failed to pass the market share screen. The Company and OERI provided an explanation as to why its failure of the market share screen should not be viewed as an indication that they can exercise generation market power. One party, Redbud, protested the Company and OERI filing and proposed that the FERC require the Company to adopt an economic dispatch program as a means to mitigate the Company’s and OERI’s generation market power. On March 15, 2005, the Company and OERI responded to Redbud’s protest. In that response the Company and OERI reiterated that the information they initially filed demonstrates that they cannot exercise market power and that Redbud’s proposal is beyond the scope of the proceeding. Another party, AES, has requested intervention in this case in protest. The Company and OERI do not know when the FERC will act on the filing or what action the FERC will take.

State Legislative Initiatives

Oklahoma

In the 2005 legislative session, House Bills 1910 and 1386 were introduced. House Bill 1910 proposes that electric utilities: (i) be granted the certainty of knowing that costs of transmission upgrades assigned by a regional transmission organization will be recoverable, as

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

Arkansas

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

11. Fair Value of Financial Instruments

The following information is provided regarding the estimated fair value of the Company’s financial instruments, including derivative contracts related to the Company’s price risk management activities, which have significantly changed since December 31, 2004.

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

Price Risk Management Assets
Interest Rate Swap	$	2	.0	$	2	.0	$	3	.9	$	3	.9

The carrying value of the financial instruments on the Condensed Balance Sheets not otherwise discussed above approximates fair value except for long-term debt which is valued at the carrying amount. The valuation of the Company’s interest rate swap was determined primarily based on quoted market prices. The fair value of the Company’s long-term debt is based on quoted market prices.

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

Introduction

Forward-Looking Statements

Except for the historical statements contained herein, the matters discussed in the following discussion and analysis, including the discussion in “Outlook”, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate”, “believe”, “estimate”, “expect”, “intend”, “objective”, “plan”, “possible”, “potential”, “project” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit, actions of rating agencies and their impact on capital expenditures; the Company’s and Energy Corp.’s ability to obtain financing on favorable terms; prices of electricity and natural gas; business conditions in the energy industry; competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company; unusual weather; federal or state legislation and regulatory decisions (including the proceeding currently pending before the OCC related to the Company’s recovery of the costs billed to it by its affiliate, Enogex Inc. and subsidiaries (“Enogex”) for gas transportation and storage services) and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition enters the Company’s markets; environmental laws and regulations that may impact the Company’s operations; changes in accounting standards, rules or guidelines; creditworthiness of suppliers, customers and other contractual parties; and other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission including Exhibit 99.01 to the Company’s Form 10-K for the year ended December 31, 2004.

Overview

Summary of Operating Results

The Company reported a net loss of approximately $1.7 million for the three months ended March 31, 2005, as compared to break-even results for the three months ended March 31, 2004.

Outlook

Energy Corp. previously disclosed in its Form 10-K for the year ended December 31, 2004 that its earnings guidance was $137 million to $147 million of net income, or $1.50 to $1.60 per share. Energy Corp. has increased its 2005 earnings guidance to $149 million to $158 million, or $1.65 to $1.75 per share, assuming approximately 90.5 million average diluted shares outstanding. The change in earnings guidance is due to the increase in projected earnings at Enogex. The outlook for the Company remains unchanged (see “Outlook” in the Company’s Form 10-K for the year ended December 31, 2004 for a description of the underlying assumptions related to the earnings guidance for the Company). The 2005 outlook includes earnings guidance of $106 million to $110 million for the Company. Additionally, funding for Energy Corp.’s pension plan is expected to be approximately $32.0 million in 2005, of which approximately $24.8 million is expected to be allocated to the Company. Energy Corp. expects to fund the pension plan during the second and third quarters of 2005. In April 2005, Energy Corp. funded approximately $10.7 million to the pension plan, of which approximately $8.3 million was allocated to the Company. Expected 2005 net income assumes a 38.7 percent effective tax rate.

Results of Operations

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


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

Operating income	$	2.8	$	5.0
Net loss	$	(1.7)	$	---

In reviewing its operating results, the Company believes that it is appropriate to focus on operating income as reported in its Condensed Statements of Operations as operating income indicates the ongoing profitability of the Company excluding unusual or infrequent items, the cost of capital and income taxes.


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

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

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

Operating income	$	2	.8	$	5	.0

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

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

Total operating revenues	$	301	.0	$	304	.3

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

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

Total sales		5	.8		5	.8

Number of customers		734,8	20		728,3	23

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

Degree days (C)
Heating
Actual		1,6	65		1,7	85
Normal		1,9	63		1,9	82
Cooling
Actual			1			18
Normal			8			8

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

The Company’s operating income for the three months ended March 31, 2005 decreased approximately $2.2 million or 44.0 percent as compared to the same period in 2004. The decrease in operating income was primarily attributable to:

higher operation and maintenance expense; and

higher depreciation expense.

These decreases in operating income were partially offset by:

higher gross margin on revenues (“gross margin”).

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

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

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

These increases in gross margin were partially offset by:

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

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

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

Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, are passed through to the Company’s customers through automatic fuel adjustment clauses. While the regulatory mechanisms for recovering fuel costs differ in Oklahoma, Arkansas and the FERC, in each jurisdiction the costs are passed through to customers and are intended to provide neither an ultimate benefit nor detriment to the Company. The automatic fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC have authority to review the appropriateness of gas transportation charges or other fees the Company pays to Enogex. See Note 10 of Notes to Condensed Financial Statements for a discussion of current proceedings at the OCC regarding the Company’s gas transportation and storage contract with Enogex and a review of the Company’s automatic fuel adjustment clause for 2003.

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

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

higher outside services expense of approximately $2.5 million and higher materials and supplies expense of approximately $2.0 million, primarily due to higher expenses for infrastructure projects in the first quarter of 2005 as spending on infrastructure projects in the first quarter of 2004 was postponed as the Company awaited an OCC order regarding whether the Company had to reduce its rates, effective January 1, 2004.

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

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

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

Other Income, Net Interest Expense and Income Tax Expense

Other income includes, among other things, contract work performed by the Company, non-operating rental income, gain on the sale of assets and miscellaneous non-operating income. Other income was approximately $0.7 million for the three months ended March 31, 2005 as compared to approximately $0.4 million during the same period in 2004, an increase of

approximately $0.3 million or 75.0 percent. The increase in other income was primarily due to a gain of approximately $0.2 million during the first quarter of 2005 from the sale of miscellaneous assets.

Net interest expense includes interest income, interest expense and other interest charges. Net interest expense was approximately $8.1 million for the three months ended March 31, 2005 as compared to approximately $9.5 million during the same period in 2004, a decrease of approximately $1.4 million or 14.7 percent. This decrease in net interest expense was primarily due to:

an increase in interest income of approximately $1.4 million due to the interest portion of an income tax refund related to prior periods; and

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

These decreases in net interest expense were partially offset by:

an increase in interest expense of approximately $0.7 million due to an increase in variable interest rates associated with the Company’s interest rate swap agreement and variable rate industrial authority bonds.

Income tax benefit was approximately $3.4 million for the three months ended March 31, 2005 as compared to approximately $4.6 million during the same period in 2004, a decrease of approximately $1.2 million or 26.1 percent. The decrease in income tax benefit was primarily due to:

a decrease in Oklahoma state tax credits of approximately $1.4 million during the first quarter of 2005 as compared to the same period in 2004.

This decrease in income tax benefit was partially offset by:

a higher pre-tax loss for the Company.

Financial Condition

The balance of Accounts Receivable – Customers was approximately $76.0 million and $91.7 million at March 31, 2005 and December 31, 2004, respectively, a decrease of approximately $15.7 million or 17.1 percent. The decrease was primarily due to a decrease in the Company’s billings to its customers reflecting milder weather in March 2005 as compared to December 2004.

The balance of Advances to Parent was approximately $26.5 million at December 31, 2004. There were no outstanding advances to Energy Corp. at March 31, 2005. The decrease was primarily due to payments for ad valorem taxes and bond interest.

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

The balance of Accounts Payable – Affiliates was approximately $28.3 million and $45.4 million at March 31, 2005 and December 31, 2004, respectively, a decrease of approximately $17.1 million or 37.7 percent. The decrease was primarily due to a decrease in the dividend declared in March 2005 as compared to December 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 stockholder’s equity in the Company’s balance sheet; or (iv) any obligation, including a contingent obligation, arising out of a variable interest as defined in FASB Interpretation No. 46, “Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin No. 51,” in an unconsolidated entity that is held by, and material to, the Company, where such entity provides financing, liquidity, market risk or credit risk support to, or engages in leasing, hedging or research and development services with, the Company. There have been no significant changes in the Company’s off-balance sheet arrangements reported in the Company’s Form 10-K for the year ended December 31, 2004.

Liquidity and Capital Requirements

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

Interest Rate Swap Agreement

Fair Value Hedge

At March 31, 2005 and December 31, 2004, the Company had one outstanding interest rate swap agreement that qualified as a fair value hedge effective March 30, 2001, to convert $110.0 million of 7.30 percent fixed rate debt due October 15, 2025, to a variable rate based on the three month London InterBank Offering Rate. The objective of this interest rate swap was to achieve a lower cost of debt and to raise the percentage of total corporate long-term floating rate debt to reflect a level more in line with industry standards. This interest rate swap qualified as a fair value hedge under SFAS No. 133, “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 2005 to 2007 construction program includes continued investment in distribution, generation and transmission systems that is part of the Company’s Customer Savings and Reliability Plan. The Company has approximately 430 MWs of contracts with qualified cogeneration facilities and small power production producers’ (“QF contracts”) that will expire at the end of 2007, unless extended by the Company. In addition, effective September 1, 2004, the Company entered into a new 15-year power sales agreement for 120 MWs with PowerSmith Cogeneration Project, L.P. The Company will continue reviewing all of the supply alternatives to these expiring QF contracts that minimize the total cost of generation to its customers, including exercising its options (if applicable) to extend these QF contracts at pre-determined rates. Accordingly, the Company will continue to explore opportunities to build or buy power plants in order to serve its native load. As a result of the high volatility of current natural gas prices and the increase in natural gas prices, the Company will also assess the feasibility of constructing additional base load coal-fired units. Approximately $5.3 million of the Company’s capital expenditures budgeted for 2005 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, 2004 that it expected to contribute approximately $37.4 million to the pension

plan in 2005, of which approximately $29.0 million was expected to be allocated to the Company. Energy Corp. presently anticipates reducing this amount by approximately $5.4 million during 2005, for a total contribution of approximately $32.0 million in 2005, which represents Energy Corp.’s 2004 pension expense, of which approximately $24.8 million is expected to be allocated to the Company. Energy Corp. plans to make contributions to the pension plan during the second and third quarters of 2005. In April 2005, Energy Corp. funded approximately $10.7 million to the pension plan, of which approximately $8.3 million was allocated to the Company. The remaining expected contributions to the pension plan in 2005, anticipated to be in the form of cash, are discretionary contributions and are not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974.

Future Sources of Financing

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

Short-Term Debt

The following table shows Energy Corp.’s and the Company’s lines of credit in place, commercial paper outstanding and available cash at March 31, 2005. At March 31, 2005, Energy Corp.’s short-term borrowings consisted of borrowings on its revolving credit agreement and commercial paper.

Lines of Credit, Commercial Paper and Available Cash (In millions)

Entity	Amount Available		Amount Outstanding		Maturity

Energy Corp.		$ 15.0		$ ---	April 6, 2005 (A)
The Company (B)		100.0		---	October 20, 2009 (C)
Energy Corp. (D)		450.0		154.0	October 20, 2009 (C)

		565.0		154.0
Cash		---		N/A	N/A

Total		$ 565.0		$ 154.0

(A) In April 2005, Energy Corp. renewed its $15.0 million credit facility, shown in the table above, which matures April 6, 2006.
(B) No borrowings were outstanding at March 31, 2005 under this line of credit; however, $0.2 million of this line of credit supports a letter of credit.
(C) Each of the new credit facilities has a five-year term with two options to extend the term for one year.
(D) This bank facility is available to back up a maximum of $300.0 million of Energy Corp.’s commercial paper borrowings and can be used as a letter of credit facility. At March 31, 2005, Energy Corp. had approximately $85.0 million in outstanding borrowings under this line of credit and approximately $69.0 million in commercial paper borrowings.

Critical Accounting Policies and Estimates

The Condensed 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 contingent liabilities at the date of the Condensed Financial Statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material affect on the Company’s Condensed Financial Statements

particularly as they relate to pension expense. However, the Company believes it has taken reasonable but conservative positions, where assumptions and estimates are used, in order to minimize the negative financial impact to the Company that could result if actual results vary from the assumptions and estimates. In management’s opinion, the areas of the Company where the most significant judgment is exercised is in the valuation of pension plan assumptions, contingency reserves, accrued removal obligations, regulatory assets and liabilities, unbilled revenue, the allowance for uncollectible accounts receivable and fair value hedging policies. The selection, application and disclosure of these critical accounting estimates have been discussed with Energy Corp.’s audit committee and are discussed in detail in Management’s Discussion and Analysis of Financial Condition and Results of Operations in the Company’s Form 10-K for the year ended December 31, 2004.

Accounting Pronouncements

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

Electric Competition; Regulation

The Company has been and will continue to be affected by competitive changes to the utility and energy industries. Significant changes already have occurred and additional changes are being proposed to the wholesale electric market. Although it appears unlikely in the near future that changes will occur to retail regulation in the states served by 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 Notes 9 and 10 of Notes to Condensed Financial Statements in this Form 10-Q and in the Company’s Form 10-K for the year ended December 31, 2004. The Company currently has one important matter pending before the OCC. See Note 10 of Notes to Condensed Financial Statements for a further discussion.

Commitments and Contingencies

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

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

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, 2004 for a description of certain legal proceedings presently pending. Except as set forth below and in Notes 9 and 10 of Notes to Condensed Financial Statements in this Form 10-Q, there are no new significant cases to report against the Company or its subsidiaries and there have been no material changes in the previously reported proceedings.

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

2. The Company has been sued by Kaiser-Francis Oil Company in District Court, Blaine County, Oklahoma. This case has been pending for more than 10 years. Plaintiff alleges that the Company breached the terms of numerous contracts covering approximately 60 wells by failing to purchase gas from Plaintiff in amounts set forth in the contracts. Plaintiff seeks $25.0 million in take-or-pay damages and $1.8 million in underpayment damages. Over the objection and unsuccessful appeal by the Company, Plaintiff has been permitted to amend its petition to include a claim based on theories of tort. Specifically, Plaintiff alleges, among other things, that the Company intentionally and tortuously interfered with contracts by falsifying documents, sponsoring false testimony and putting forward legal defenses, which are known by the Company to be without merit. If successful, Plaintiff believes that these theories could give Plaintiff a basis to seek punitive damages. This lawsuit was stayed pending the outcome of an appeal that the Company filed in a similar case brought by Kaiser-Francis in Grady County.

In the Grady case, the plaintiff alleged that the Company breached the terms of several gas purchase contracts in amounts set forth in the contracts. In 2001, the district court rendered a verdict against the Company in the amount of approximately $8.0 million, including pre-judgment interest and attorneys’ fees. The Company filed an appeal and on May 18, 2004, the Court of Appeals issued an opinion reversing the judgment and remanding for a new trial. The appellate court found that the trial court committed reversible error in rejecting a portion of the Company’s interpretation of the commercial well provisions of the gas purchase contracts, and in failing to recognize issues of fact for the jury relating to the Company’s contention regarding the

correct initial reserve estimate on one of the natural gas wells, the Thiel No 1-9. In addition, the appellate court made rulings favorable to the Company relating to the statutory measure of damages, the effect of line pressure adjustment provisions in the contracts, and the admission of certain hearsay evidence. The appellate court made rulings favorable to Kaiser-Francis relating to the effect of royalty payment obligations on the amount of damages, the effect of the amount of reserves owned by Kaiser-Francis in the wells on the Company’s gas purchase obligation, the propriety of the award of prejudgment interest, and the Company’s liability for the payment of gross production taxes pertaining to the damages awarded. The appellate court returned an issue relating to the alleged effect of Kaiser-Francis’s failure to make gas available for consideration by the trial court. Finally, the appellate court denied Kaiser-Francis’s request for appeal-related attorney’s fees and costs. On July 6, 2004, the Court of Appeals denied Kaiser-Francis’s motion for rehearing. Both parties filed petitions for certiorari with the Oklahoma Supreme Court for the review of those portions of the appellate court’s opinion unfavorable to each. The Oklahoma Supreme Court denied both parties’ petitions for certiorari on January 10, 2005. Mandate was issued by the Oklahoma Supreme Court on February 4, 2005. Since then, the Blaine County case has been set for trial beginning January 17, 2006. The Grady County case has been set for trial beginning October 17, 2005. Additionally, Kaiser-Francis has filed a motion in the Grady County case asking for leave to file a fourth amended petition, the purpose of which is to include a claim based on the same theories of tort as alleged in the Blaine County case. The Company will be opposing that motion, which is set for hearing May 19, 2005.

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

Item 6. Exhibits.
	Exhibit No.	Description

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

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

SIGNATURE

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

	OKLAHOMA GAS AND ELECTRIC COMPANY (Registrant)
	By	/s/ Donald R. Rowlett
		Donald R. Rowlett Vice President and Controller (On behalf of the registrant and in his capacity as Chief Accounting Officer)

May 4, 2005

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)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

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

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

Date: May 4, 2005

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

Exhibit 31.01

CERTIFICATIONS

I, James R. Hatfield, certify that:

1. I have reviewed this quarterly report on Form 10-Q of 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 4, 2005

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

Exhibit 32.01

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

In connection with the Quarterly Report of Oklahoma Gas and Electric Company (the “Company”) on Form 10-Q for the period ended March 31, 2005, as filed with the Securities and Exchange Commission (the “Report”), each of the undersigned does hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

May 4, 2005

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

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

FORM 10-Q

OR

OKLAHOMA GAS AND ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2005

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

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

1. Summary of Significant Accounting Policies

Organization

Basis of Presentation

Accounting Records

Income Taxes

Related Party Transactions

2. Accounting Pronouncements

3. Price Risk Management Assets and Liabilities

4. Accumulated Other Comprehensive Loss

5. Supplemental Cash Flow Information

6. Long-Term Debt

Fair Value Hedge

7. Short-Term Debt

8. Retirement Plans and Postretirement Benefit Plans

Net Periodic Benefit Cost

9. Commitments and Contingencies

Air

Water

10. Rate Matters and Regulation

Regulatory Matters

Pending Regulatory Matters

11. Fair Value of Financial Instruments

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

Introduction

Forward-Looking Statements

Overview

Outlook

Results of Operations

Financial Condition

Off-Balance Sheet Arrangements

Liquidity and Capital Requirements

Fair Value Hedge

Future Capital Requirements

Future Sources of Financing

Critical Accounting Policies and Estimates

Accounting Pronouncements

Electric Competition; Regulation

Commitments and Contingencies

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Item 4. Controls and Procedures.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

SIGNATURE

CERTIFICATIONS

CERTIFICATIONS

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

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

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

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